Resolution No. 76721
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RESOLUTION NO. 7672
A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF
VERNON APPROVING A PARTIAL SETTLEMENT IN FERC
DOCKET NO. EL01-14-000 BY APPROVING AND AUTHORIZING
THE EXECUTION OF A TRANSMISSION CONTROL AGREEMENT
AMONG THE INDEPENDENT SYSTEM OPERATOR AND
TRANSMISSION OWNERS
WHEREAS, the City of Vernon (hereinafter "Vernon"), pursuant
to its notice to the Independent System Operator Corporation
(hereinafter "ISO") of June 30, 2000 electing to become a Participating
Transmission Owner (hereinafter "PTO"), has been negotiating with ISO
,the contracts necessary to achieve PTO status; and
WHEREAS, Vernon and ISO had reached an impasse in the
negotiations relating to the Transmission Control Agreement
(hereinafter "TCA"); and
WHEREAS, in an attempt to meet the deadline of January 1,
2001, Vernon filed a complaint before the Federal Energy Regulatory
Commission (hereinafter "FERC") asking the FERC to compel the ISO Board
of Governors to approve the TCA in a timely fashion so that Vernon
could become a PTO on January 1, 2001; and
WHEREAS, the ISO Board of Governors on November 30, 2000,
approved the execution of a TCA with Vernon pursuant to Vernon's
agreement to accept certain modifications therein; and
WHEREAS, the staff of Vernon have recommended to the City
Council that it accept the partial settlement offered by ISO subject to
the issues reserved for FERC approval in the letter dated December 5,
2000 from Bruce V. Malkenhorst to ISO.
NOW, THEREFORE, BE IT RESOLVED BY THE CITY COUNCIL OF THE
CITY OF VERNON AS FOLLOWS:
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Fjl
SECTION 1: The City Council of the City of Vernon hereby
finds and determines that the recitals contained hereinabove are true
land correct.
SECTION 2: The City Council of the City of Vernon hereby
approves the partial settlement in FERC Docket No. ELO1-14-000 and
approves the Transmission Control Agreement among the ISO and
Transmission Owners, a copy of which has been presented to the City
Council concurrently with this resolution, and the City Council hereby
orders said Agreement to be received and filed by the City Clerk.
SECTION 3: The City Council of the City of Vernon hereby
authorizes the Mayor and the City Clerk to execute the TCA for, and on
behalf of, the City of Vernon.
SECTION 4: The City Council of the .City of Vernon hereby
directs the City Clerk, or his designee, to transmit the executed TCA
to the ISO in a timely fashion so that ISO can make a filing of the TCA
on or before December 8, 2000.
SECTION 5: The City Clerk of the City of Vernon shall
certify to the passage of this resolution, and thereupon and thereafter
the same shall be in full force and effect.
APPROVED AND ADOPTED this 5th day of December, 2000.
ATTEST:
400,
BRUCE V. MALKENHORST, City Clerk
LEONIS C. MALBJRG, Mayor
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STATE OF CALIFORNIA )
) ss
COUNTY OF LOS:ANGELES )
I, BRUCE V. MALKENHORST, City Clerk of the City of Vernon, do
hereby certify that the foregoing Resolution, being Resolution No.
7672, was duly adopted by the City Council of the City of Vernon at a
regular meeting of the City Council duly held on Tuesday, December 5,
2000, and thereafter was duly signed by the Mayor of the City of
Vernon.
(SEAL)
BRUCE V. MALKENHORST, City Clerk
- 3 -
SUPPORTING
DOCUMENTS
CITY COUNCIL
LEONIS C. MALBURG
Mayor
THOMAS A. YBARRA
Mayor Pro-Tem
WM. 'BILL" DAVIS
Councilman
H. "LARRY" GONZALES
Councilman
W. MICHAEL MCCORMICK
Councilman
BRUCE V. MALKENHORST
City Administrator / City Clerk
FAX (323) 581-7924
CITY HALL
4305 SANTA FE AVENUE, VERNON, CALIFORNIA 90058
TELEPHONE (323) 583-8811
December 6, 2000
Ms. Deborah A. Le Vine
Director of Contracts and Compliance
California Independent System Operator
151 Blue RavineRoad
Folsom, California 95630
Dear Ms. Le Vine:
EDUARDO OLIVO
City Attorney
FAX: (562) 927--8722
KEVIN WILSON
Director of Community Services & Water
FAX: (323) 588-2761
KENNETH J. DeDARIO
Director of Municipal Utilities
FAX: (323) 583--1983
DAVE TELFORD
Fire Chief
FAX: (323) 581-1385
BRUCE W. OLSON
Police Chief
FAX: (323) 583-5236
Last night the City Council approved the Transmission Control Agreement
("TCA") pursuant to Resolution No. 7672. As requested, enclosed are
ten fully executed signature pages of the TCA provided to the City of
Vernon under your letter to Jorge C. Somoano on December 1, 2000. Also
enclosed is a copy of page F-5 of Appendix F and Resolution No. 7672.
It was the City Council's understanding from your letter dated December
1, 2000 that the California Independent System Operator will file the
approved TCA with the FERC on or before December 8, 2000.
Please let me know if your need any further verification of Vernon's
approval. You can reach me at (323) 583-8811 ext. 266 and please note
that the City Clerk's business office is closed on Friday.
Very truly yours,
loria Or co
Chief Deputy City Clerk
Encs.
ca Kenneth J. De Dario
Jorge C. Somoano
David B. Brearley
Transmission Control Agreement
Page 63
31. SIGNATURE PAGE
CITY OF VERNON
CITY OF VERNON has caused this Transmission Control Agreement to
be executed by its duly authorized representative on this
fifth
day of
December , 2000 and thereby incorporates the following Appendices in this
Agreement:
Appendix A (Vernon)
Appendix B (Vernon)
Appendix C
Appendix D
Appendix E
Appendix F
ATTEST:
y
BRUCE V. MALKENHORST, City Clerk
APPROVED AS TO FORM:
ZI -� -1-A- 41�- /'1-r<i
EDUARDO OLIVO, City Attorney
CITY OF VERNON
ISO REV 02.1200
City of Vernon
Name of Primary
Representative:
Title:
Address:
City/State/Zip Code:
Email Address:
Phone:
Fax No:
Name of Alternative
Representative:
Title:
Address:
City/State/Zip Code:
Email Address:
Phone:
Fax No:
TRANSMISSION CONTROL AGREEMENT
APPENDIX F
Bruce V. Malkenhorst
City Administrator
City of Vernon
4305 Santa Fe Avenue
Vernon,.California 90058
(323) 583-8811, Extension 266
(323) 581-7924
Kenneth J. DeDario
Director of Utilities
City of Vernon
4305 Santa Fe Avenue
Vernon, California 90058
(323) 583-8811, Extension 211
(323) 583-1983
F-5
12/06/00 WED 09:36 FAX 213 583 1983 CITY OF VERNON Utilities 121001
OFFICE OF THE CITY ,ADMINISTRATOR/CITY CLERK
INTER -OFFICE MEMORANDUM
DATE: December 6, 2000
TO: Kenneth DeDari Director of Utilities
FROM: Gloria J. Or Chief Deputy City Clerk
RE: Resolution No. 7672
Pursuant to your request hereto attached is a signed copy of
Resolution No. 7672 and a signed copy of page 63 of the Transmission
Control Agreement.
Please advise me on how you wish me to handle the signature pages.
Thank you,
Cc:' Jorge Somoano
CITY COUNCIL
11
LEONIS C. MALBURG
Mayor
THOMAS A. YBARRA
Mayor Pro-Tem
WM. 'BILL" DAVIS
Councilman
H. "LARRY" GONZALES
Councilman
W. MICHAEL MCCORMICK
Councilman
BRUCE V. MALKENHORST
City Administrator / City Clerk
FAX (323) 581-7924
CITY HALL
4305 SANTA FE AVENUE, VERNON, CALIFORNIA 90058
TELEPHONE (323) 583-8811
December 6, 2000
Ms. Deborah A. Le Vine
Director of Contracts and Compliance
California Independent System Operator
151 Blue Ravine Road
Folsom, California 95630
Dear Ms. Le Vine:
EDUARDO OLIVO
City Attorney
FAX: (562) 927-8722
KEVIN WILSON
Director of Community Services & Water
FAX: (323) 588-2761
KENNETH J. DeDARIO
Director of Municipal Utilities
FAX: (323) 583--1983
DAVE TELFORD
Fire Chief
FAX: (323) 581-1385
BRUCE W. OLSON
Police Chief
FAX: (323) 583-5236
Last night the City Council approved the Transmission Control Agreement
("TCA") pursuant to Resolution No. 7672. As requested, enclosed are
ten fully executed signature pages of the TCA provided to the City of
Vernon under your letter to Jorge C. Somoano on December 1, 2000. Also
enclosed is a copy of page F-5 of Appendix F and Resolution No. 7672.
It was the City Council's understanding from your letter dated December
1, 2000 that the California Independent System Operator will file the
approved TCA with the FERC on or before December 8, 2000.
Please let me know if your need any further verification of Vernon's
approval. You can reach me at (323) 583-8811 ext. 266 and please note
that the City Clerk's business office is closed on Friday.
Very truly yours,
loria Or co
Chief Deputy City Clerk
Encs.
c: Kenneth J. DeDario
Jorge C. Somoano
David B. Brearley
r
Transmission Control Agreement '
Page 63
31. SIGNATURE PAGE
CITY OF VERNON
CITY OF VERNON has caused this Transmission Control Agreement to
be executed by its duly authorized representative on this fifth day of
December , 2000 and thereby incorporates the following Appendices in this
Agreement:
Appendix A (Vernon)
Appendix B (Vernon)
Appendix C
Appendix D
Appendix E
Appendix F
CITY OF VERNON
By: �JSC.QLBUG�,May`®r�.
O
ATTEST: /
n /
v
BRUCE V. MALKEWORST, City Clerk
APPROVED AS TO FORM:
EDUARDO OLIVO, City Attorney
ISO REV 02.1200
Transmission Control Agreement
Page 63
31. SIGNATURE PAGE
CITY OF VERNON
CITY OF VERNON has caused this Transmission Control Agreement to
be executed by its duly authorized representative on this fifth day of
December , 20 00 and thereby incorporates the following Appendices in this
Agreement:,
Appendix A (Vernon)
Appendix B (Vernon)
Appendix C
Appendix D
Appendix E
Appendix F
ATTEST:
BRUCE V. MALKENHORST, City Clerk
APPROVED AS TO FORM:
Z�
EDUARDO OLIVO, City Attorney
CITY OF VERNON
By:
&E-ONIS C. MALB RG, May r
ISO REV 02.1200
Transmission Control Agreement
Page 63
31. SIGNATURE PAGE
CITY OF VERNON
CITY OF VERNON has caused this Transmission Control Agreement to
be executed by its duly authorized representative on this fifth day of
December , 20o0 and thereby incorporates the following Appendices in this
Agreement:
Appendix A (Vernon)
Appendix B (Vernon)
Appendix C
Appendix D
Appendix E
Appendix F
CITY OF VERNON
By:
NIS C. MALIkYRG, Mayor
ATTEST:
y
BRUCE V. MALKENHORST, City Clerk
APPROVED AS TO FORM:
EDUARDO OLIVO, City Attorney
ISO REV 02.1200
Transmission Control Agreement
Page 63
31. SIGNATURE PAGE
CITY OF VERNON
CITY OF VERNON has caused this Transmission Control Agreement to
be executed by its duly authorized representative on this fifth day of
December , 20 00 and thereby incorporates the following Appendices in this
Agreement:
Appendix A (Vernon)
Appendix B (Vernon)
Appendix C
Appendix D
Appendix E
Appendix F
ATTEST:
BRUCE V. MALKENHORST, City Clerk
APPROVED AS TO FORM:
EDUARDO OLIVO, City Attorney
CITY OF VERNON
By
NIS C. MALBORG, Mayor
ISO REV 02.1200
Transmission Control Agreement
Page 63
31. SIGNATURE PAGE
CITY OF VERNON
CITY OF VERNON has caused this Transmission Control Agreement to
be executed by its duly authorized representative on this
fifth
day of
December , 20 00 and thereby incorporates the following Appendices in this
Agreement:
Appendix A (Vernon)
Appendix B (Vernon)
Appendix C
Appendix D
Appendix E
Appendix F
CITY OF VERNON
L NIS C. MALBU . Mayor
ATTEST:
v
BRUCE V. MALKENHORST, City Clerk
APPROVED AS TO FORM:
EDUARDO OLIVO, City Attorney
ISO REV 02.1200
Transmission Control Agreement
Page 63
31. SIGNATURE PAGE
CITY OF VERNON
CITY OF VERNON has caused this Transmission Control Agreement to
be executed by its duly authorized representative on this fifth day of
December , 20oo and thereby incorporates the following Appendices in this
Agreement:
Appendix A (Vernon)
Appendix B (Vernon)
Appendix C
Appendix D
Appendix E
Appendix F
CITY OF VERNON
By:
UONIS C. MALBU G, Mayo
ATTEST:
BRUCE V. MALKENHORST, City Clerk
APPROVED AS TO FORM:
Z21-
EDUARDO OLIVO, City Attorney
ISO REV 02.1200
Transmission Control Agreement
Page 63
31. SIGNATURE PAGE
CITY OF VERNON
CITY OF VERNON has caused this Transmission Control Agreement to
be executed by its duly authorized representative on this fifth day of
December , 20 00 and thereby incorporates the following Appendices in this
Agreement:
Appendix A (Vernon)
Appendix B (Vernon)
Appendix C
Appendix D
Appendix E
Appendix F
CITY OF VERNON
By: � i
EONIS C. MAL RG, Mayo
ATTEST:
BRACE V. MALKENHORST, City Clerk
APPROVED AS TO FORM:
ccti
EDUARDO OLIVO, City Attorney
ISO REV 02.1200
Transmission Control Agreement
Page 63
31. SIGNATURE PAGE
CITY OF VERNON
CITY OF VERNON has caused this Transmission Control Agreement to
be executed by its duly authorized representative on this fifth day of
December , 2p oo and thereby incorporates the following Appendices in this
Agreement:
Appendix A (Vernon)
Appendix B (Vernon)
Appendix C
Appendix D
Appendix E
Appendix F
CITY OF VERNON
1
By:
E0NIS C. MALB RG, May
ATTEST:
BRUCE V. MALKENHORST, City Clerk
APPROVED AS TO FORM:
EDUARDO OLIVO, City Attorney
ISO REV 02.1200
Transmission Control Agreement
Page 63
31. SIGNATURE PAGE
CITY OF VERNON
CITY OF VERNON has caused this Transmission Control Agreement to
be executed by its duly authorized representative on this fifth day of
December , 20 00 and thereby incorporates the following Appendices in this
Agreement:
Appendix A (Vernon)
Appendix B (Vernon)
Appendix C
Appendix D
Appendix E
Appendix F
CITY OF VERNON
By:
LEOWS.MAL- RG, M or
ATTEST:
z/.x-
BRUCE V. MALKENHORST, City Clerk
APPROVED AS TO FORM:
EDUARDO OL1VO, City Attorney
ISO REV 02.1200
Transmission Control Agreement
Page 63
31. SIGNATURE PAGE
CITY OF VERNON
CITY OF VERNON has caused this Transmission Control Agreement to
be executed by its duly authorized representative on this fifth day of
December , 20 00 and thereby incorporates the following Appendices in this
Agreement:
Appendix A (Vernon)
Appendix B (Vernon)
Appendix C
Appendix D
Appendix E
Appendix F
CITY OF VERNON
By:-�
EONIS C. MALBU G, Mayor
ATTEST:
BRUCE V. MALKENHORST, City Clerk
APPROVED AS TO FORM:
_
---- c�ittir c.Ly
EDUARDO OLIVO, City Attorney
ISO REV 02.1200
CITY COUNCIL
LEONIS C. MALBURG
Mayor
THOMAS A. YBARRA
Mayor Pro-Tem
WM. "BILL" DAVIS
Councilman
H. "LARRY" GONZALES
Councilman
W. MICHAEL MCCORMICK
Councilman
BRUCE V. MALKENHORST
City Administrator / City Clerk
FAX (323) 581-7924
CITY HALL
4305 SANTA FE AVENUE, VERNON, CALIFORNIA 90058
TELEPHONE (323) 583-8811
EDUARDO OLIVO
City Attorney
FAX: (562) 927-8722
KEVIN WILSON
Director of Community Services & Water
FAX: (323) 588-2761
KENNETH J. DeDARIO
Director of Municipal Utilities
FAX: (323) 583-1983
DAVE TELFORD
Fire Chief
FAX: (323) 581-1385
BRUCE W. OLSON
Police Chief
FAX: (323) 583-5236
December 5, 2000
BY FACSIMILE AND AIR COURIER
Ms. Deborah A. Levine
Director of Contracts & Compliance
California Independent System Operator Corporation
151 Blue Ravine Road
Folsom, California 95630
Fax No. (916) 351-2144
Dear Ms. Le Vine:
We have received your letter of December 1, 2000 and the attached draft
Transmission Control Agreement ("TCA"). Your letter requests a response by 5:00 pm
today. Regrettably, Vernon was again provided with materials to which Vernon must
quickly respond, on a Friday, a day of the week on which Vernon is closed. Moreover,
Vernon's City Council meeting begins tonight at 5:00 pm.
Given the time constraints, Vernon proposes to proceed as follows. I and other
Vernon officials and representatives will recommend to the City Council that it approve
the draft TCA for execution with the following conditions.
First, Vernon agrees with the ISO that the issues that Vernon has raised as to
binding arbitration should be reserved for resolution by the Commission. Let me know
how the ISO would propose to formalize this reservation with respect to the TCA..
Ms. Deborah A. Le Vine
December 5, 2000
Page 2
Second, Vernon has significant concerns about the newly proposed ISO changes
to Section 16 of the TCA, and Vernon asks that the issues regarding that provision be
reserved as well. It appears to Vernon that these changes relating to refund liability are
not sufficiently defined, as they would relate to Vernon's receipt of Vernon's
Transmission Revenue Requirement and the ISO obligation when proposing
jurisdictional transmission rates to the FERC. Moreover, such a refund commitment does
not seem appropriate for imposition at the last minute in the TCA on a "take it or leave it
basis". Furthermore, the imposition of an additional obligation on Vernon to
automatically amend its TO Tariff without the exercise of Vernon's discretion is also
clearly inappropriate in the TCA. The concepts involved have broad ramifications and
perhaps should be advanced by the ISO in another docket.. Vernon will, address this
matter in a motion for leave to answer and answer to the ISO's answer and supplement to
answer to Vernon's complaint.
Third, Pacific Gas and Electric Company's made a contention in the pleading that,
under a technical reading of the ISO tariff and the TCA, Vernon's rights on the Mead-
Adelanto and Mead Phoenix lines, and on COTP, are not "Entitlements", but ownership
interests. This challenge places in doubt the definition agreed to by both the ISO and
Vernon. It seems to Vernon that throughout the negotiations the ISOand Vernon have
essentially agreed to deem Vernon's transmission rights on those lines to be
"Entitlements" and that this is the best and least complicated approach to handling the
matter. Vernon will assert that the Commission should adopt such approach'in Vernon's
motion.
Inasmuch as Vernon's City Council will probably not have completed its
consideration of the TCA until approximately 6:30 p.m. tonight, Vernon will not be able
to report to you until that time as to Vernon's approval of the execution of the :TCA.
However, I commit to have Jorge C. Somoano, Assistant Director of Resource
Management report to you right away. Let me know how to reach you or others at the
ISO at that time of evening.
We will await hearing from the ISO' as to the other matters, such as UDC and
Meter Service agreements, and FTRs, mentioned in your letter. As you know, there are
still questions about the need for a UDC and/or a Meter Service agreement, and, if they
are needed, how to implement them, but we hope that nothing concerning them will delay
Vernon's PTO status.
Please contact us regarding the reservation of issues for Commission resolution,
or regarding any other questions or concerns you may have.
Ms. Deborah A. Le Vine
December 5, 2000
Page 3
Vernon appreciates all efforts to move quickly on this matter, and looks forward
to becoming a PTO effective January 1, 2000.
Very truly yours,
Bruce V. Malkenhorst
City Administrator/City Clerk
c: Terry M. Winter, President and CEO of IS
Kenneth J. DeDario, Director of Utilities
Jorge C. Somoano, Assistant Director of Resource Management
Eduardo Olivo, City Attorney
David B. Brearley, Special Consultant .
Channing D. Strother, Jr.
TRANSMISSION CONTROL AGREEMENT
Among
The Independent System Operator
.and
Transmission Owners
Transmission Control Agreement
Original Sheet No. i
TABLE OF CONTENTS
Section Paae
1. DEFINITIONS............................................................................................................. 3
2. PARTICIPATION IN THIS AGREEMENT .................... ...... 3
.........................................
3. EFFECTIVE DATE, TERM AND WITHDRAWAL........................................................ 9
4. TRANSFER OF OPERATIONAL CONTROL............................................................ 10
5. INDEPENDENT SYSTEM OPERATOR.................................................................... 21
6. PARTICIPATING TRANSMISSION OWNERS......................................................... 26
7. SYSTEM OPERATION AND MAINTENANCE.......................................................... 30
8. AUXILIARY EQUIPMENT AND ISO CONTROLLED GRID CRITICAL
PROTECTIVE SYSTEMS....................................................................................... 31
9. SYSTEM EMERGENCIES .....................
10'. ISO CONTROLLED GRID ACCESS AND INTERCONNECTION ........................... 34
11. EXPANSION OF TRANSMISSION FACILITIES ....................
12. USE AND ADMINISTRATION OF THE ISO CONTROLLED GRID ........................ 39
13. EXISTING AGREEMENTS..................................................................................... 40
14. MAINTENANCE STANDARDS............................................................................... 41
15. DISPUTE RESOLUTION........................................................................................ 43
16. BILLING AND PAYMENT...................................................................................... 43
17. RECORDS AND INFORMATION SHARING ..................
18. GRANTING RIGHTS -OF -ACCESS TO FACILITIES ............................................... 47
19. ISO GRID OPERATIONS COMMITTEE................................................................. 49
20. TRAINING............................................................................................................... 49
21. OTHER SUPPORT SYSTEMS REQUIREMENTS ................................................. 50
ISO Rev. 02.1200
Transmission Control Agreement
Original Sheet No. ii
\ 22. LIABILITY................................................................................................................ 50
23. UNCONTROLLABLE FORCES........................................................................... 52
24. ASSIGNMENTS AND CONVEYANCES ................. ...... 53
...........................................
25. ISO ENFORCEMENT............................................................................................. 53
26. MISCELLANEOUS ........................................... .. 53
......................................................
27. SIGNATURE PAGE CALIFORNIA INDEPENDENT SYSTEM
OPERATOR CORPORATION............................................................................ 59
28. SIGNATURE PAGE PACIFIC GAS AND ELECTRIC COMPANY .......................... 60
29. SIGNATURE PAGE SAN DIEGO GAS & ELECTRIC COMPANY .......................... 61
30. SIGNATURE PAGE SOUTHERN CALIFORNIA EDISON COMPANY ................... 62
APPENDICES A - Facilities and Entitlements
PG&E Appendix A and Supplement
SDG&E Appendix A and Supplement
Edison Appendix A and Supplement
APPENDICES B - Encumbrances
PG&E Appendix B
SDG&E Appendix B
Edison Appendix B
APPENDIX C - ISO Maintenance Standards
APPENDIX D - Master Definitions Supplement
APPENDICES E - Nuclear Protocols
Diablo Canyon Appendix E
SONGS Appendix E
APPENDIX F - NOTICES
ISO Rev. 02.1200
Transmission Control Agreement
Page 1
TRANSMISSION CONTROL AGREEMENT
Among
The Independent System Operator
and
Transmission Owners
The Parties to this Transmission Control Agreement ("Agreement") first dated as
of , are
(1) The California Independent System Operator Corporation, a California
nonprofit public benefit Corporation (the "Independent System Operator" or "ISO" which
expression includes its permitted successors); and
(2) Entities owning or holding Entitlements to transmission lines and
associated facilities who subscribe to this Agreement ("Transmission Owners" or "TOs",
which expression includes their permitted successors and assigns).
This Agreement is made with reference to the following facts:
(i) The Legislature of the State of California enacted Assembly Bill 1890 ("AB
1890") that addressed the restructuring of the California electric industry in order to
increase competition in the provision of electricity.
(ii) AB 1890 provides the means for transforming the regulatory framework of
California's electric industry in ways to meet the objectives of the law
(iii) In order to create a new market structure, AB 1890 establishes an
Independent System Operator ("ISO") with centralized control of a state-wide
transmission grid charged with ensuring the efficient use and reliable operation of the
transmission system.
ISO Rev. 02.1200
Transmission Control Agreement
Page 2
(iv) AB 1890 states that it is the intention of the California Legislature that
California transmission owners commit control of their transmission facilities to the ISO
with the assurances provided in the law that the financial interests of such TOs will be
protected.
(v) Each TO: (1) owns, operates, and maintains transmission lines and
associated facilities, and/or (2) has Entitlements to use certain transmission lines and
associated facilities, with responsibilities attached thereto.
(vi) Each TO, upon satisfying the criteria for becoming a Participating TO
under Section 2.2 of this Agreement, will transfer to the ISO Operational Control of
certain transmission lines and associated facilities which are to be incorporated by the
ISO into the ISO Controlled Grid for the purpose of allowing them to be controlled as
part of an integrated Control Area.
(vii) Each Participating TO will continue to own and maintain its transmission
lines and associated facilities, if any, and will retain its Entitlements, if any, and
associated responsibilities.
(viii) The ISO intends to provide to each Participating TO access to the ISO
Controlled Grid while exercising its Operational Control for the benefit of all Market
Participants by providing non-discriminatory transmission access, Congestion
Management, grid security, and Control Area services.
(ix) Pacific Gas and Electric Company ("PG&E"), San Diego Gas & Electric
Company ("SDG&E"), and Southern California Edison Company ("Edison") (each a
Participating TO) are entering into this agreement transferring Operational Control of
their transmission facilities in reliance upon California Public Utilities Code Sections
ISO Rev. 02.1200
Transmission Control Agreement
Page 3
367, 368, 375, 376 and 379 enacted as part of AB 1890 which contain assurances and
schedules with respect to recovery of transition costs.
(x) The Parties desire to enter into this Agreement in order to establish the
terms and conditions under which TOs will become Participating TOs and how the ISO
and each Participating TO will discharge their respective duties and responsibilities.
In consideration of the above and the covenants and mutual agreements set forth
herein, and intending to be legally bound, the Parties agree as follows:
1. DEFINITIONS.
Capitalized terms in this Agreement have the meaning set out in the Master
Definitions Supplement set out in Appendix D. No subsequent amendment to the
Master Definitions Supplement shall affect the interpretation of this Agreement unless
made pursuant to Section 26.11.
2. PARTICIPATION IN THIS AGREEMENT
2.1. Transmission Owners:
2.1.1 Initial Transmission Owners.
The following entities are subscribing to this Agreement as of the date
hereof for the purpose of applying to become Participating TOs in accordance with
Section 2.2:
i. Pacific Gas and Electric Company;
ii. San Diego Gas & Electric Company; and
Southern California Edison Company.
ISO Rev. 02.1200
Transmission Control Agreement
Page 4
2.1.2 Right to Become a Party.
After this Agreement takes effect, any other owner of or holder of
Entitlements to transmission lines and facilities connected to the ISO Controlled Grid
may apply to the ISO under Section 2.2 to become a Participating TO and become a
Party to this Agreement.
2.2. Applications for Participating TO Status; Eligibility Criteria.
2.2.1 Application Procedures. All applications under this Section 2.2
shall be made in accordance with the procedures adopted by the ISO from time to time
and shall be accompanied by:
(i) a description of the transmission lines and associated facilities
that the applicant intends to place under the ISO's Operational Control;
in relation to any such transmission lines and associated facilities
that the applicant does not own, a copy of each document setting out the applicant's
Entitlements to such lines and facilities;
(iii) a statement of any Encumbrances to which any of the
transmission lines and associated facilities to be placed under the ISO's Operational
Control are subject, together with any documents creating such Encumbrances and any
dispatch protocols to give effect to them, as the ISO may require;
(iv) a statement that the applicant intends to place under the ISO's
Operational Control all of the transmission lines and associated facilities referred to in
Section 4.1 that it owns or, subject to the treatment of Existing Contracts under Sections
2.4.3 and 2.4.4 of the ISO Tariff, to which it has Entitlements and its reasons for
believing that certain lines and facilities do not form part of the applicant's transmission
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network pursuant to Sections 4.1.1.i and 4.1.1.ii;
(v) a statement of any Local Reliability Criteria to be included as part
of the Applicable Reliability Criteria;
(vi) a description of the applicant's current maintenance practices;
(vii) a list of any temporary waivers that the applicant wishes the ISO
to grant under Section 5.1.6 and the period for which it requires them;
(viii) a copy of the applicant's proposed TO Tariff, if any, must be filed;
(ix) address and contact names to which notices under this
Agreement may be sent pursuant to Section 26.1;
(x) any other information that the ISO may reasonably require in
order to evaluate the applicant's ability to comply with its obligations as a Participating
TO; and
(xi) details of the applicant's Settlement Account.
2.2.2 Notice of Application. The ISO shall require the applicant to
deliver to each existing Participating TO a copy of each application under this Section
2.2 and each amendment, together with all supporting documentation and to provide the
public with reasonable details of its application and each amendment through WEnet or
the ISO internet website. The ISO shall not grant an application for Participating TO
status until it has given each other Party and the public sixty (60) days to comment on
the original application and thirty (30) days to comment on each amendment
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2.2.3 Determination of Eligibility. Subject. to Section 2.2.4, the ISO
shall permit a Party who has submitted an application under this Section 2.2 to become
a Participating TO if, after considering all comments received from other Parties and
third parties, the ISO determines that:
i. the applicant's transmission lines and associated facilities that are
to be placed under the ISO's Operational Control can be incorporated into the ISO
Controlled Grid without any material adverse impact on its reliability;
ii. incorporating such transmission lines and associated facilities into
the ISO Controlled Grid will not put the ISO in breach of Applicable Reliability Criteria
and its obligations as a member of WSCC;
objections by the ISO under Section 4.1.3 shall have been
withdrawn or determined by the ISO Governing Board to be invalid;
iv. all applicable regulatory approvals of the applicant's TO Tariff
have been obtained; and
Agreement.
V. the applicant is capable of performing its obligations under this
Objections under Section 4.1.3 relating solely to a portion of a TO's
Facilities shall not prevent the TO from becoming a Participating TO while the
objections are being resolved.
2.2.4 Challenges to Eligibility. The ISO shall permit a Party to
become a Participating TO pending the outcome of ISO ADR Procedures challenging
whether or not the applicant satisfies the criteria set out in Section 2.2.3 if the ISO
determines that the applicant satisfies those criteria unless otherwise ordered by FERC
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2.2.5 Becoming a Participating TO. A Party whose application under
this Section 2.2 has been accepted shall become a Participating TO with effect from the
date when its TO Tariff takes effect, either as a result of acceptance by FERC or by
action of a Local Regulatory Authority, whichever is appropriate. The TO Tariff of each
Participating TO shall be posted on WEnet or the ISO internet website.
2.2.6 Procedures and Charges. The ISO shall adopt fair and non-
discriminatory procedures for processing applications under this Section 2.2. The ISO
shall publish its procedures for processing applications under this Section 2.2 on WEnet
or on the ISO internet website and shall furnish a copy of such procedures to FERC.
Applicants shall pay all costs incurred by the ISO in processing their applications. The
ISO will furnish applicants, upon request, an itemized bill for the costs of processing
their application.
2.3. Tax Exempt Debt.
2.3.1 Municipal Tax -Exempt TOs. In the event a Municipal Tax -
Exempt TO executes this Agreement in reliance upon this Section 2.3, it shall provide
written notice thereof to the ISO. Notwithstanding any other provision to the contrary
herein, except for this Section 2.3, no other provisions of this Agreement shall become
effective with respect to a Municipal Tax -Exempt TO until such Municipal Tax -Exempt
TO's nationally recognized bond counsel renders an opinion, generally of the type
regarded as unqualified in the bond market, that participation in the ISO Controlled Grid
in accordance with this Agreement will not adversely affect the tax-exempt status of any
Municipal Tax -Exempt Debt issued by, or for the benefit of, the Municipal Tax -Exempt
TO. A Municipal Tax -Exempt TO shall promptly seek, in good faith, to obtain such
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unqualified opinion from its bond counsel at the earliest opportunity. Upon receipt of
such unqualified opinion, a Municipal Tax -Exempt TO shall provide a copy of the
opinion to the ISO and all other provisions of this Agreement shall become effective with
respect to such Municipal Tax -Exempt TO as of the date thereof. If the Municipal Tax -
Exempt TO is unable to provide to the ISO such unqualified opinion within one year of
the execution of this Agreement by the Municipal Tax -Exempt TO, without further act,
deed or notice this Agreement shall be deemed to be void ab initio with respect to such
Municipal Tax -Exempt TO.
2.3.2 Acceptable Encumbrances. A Transmission Owner that has
issued Local Furnishing Bonds may become a Participating TO under Section 2.2 even
though covenants or restrictions applicable to the Transmission Owner's Local
Furnishing Bonds require the ISO's Operational Control to be exercised subject to
Encumbrances, provided that such Encumbrances do not materially impair the ISO's
ability to meet its obligations under the ISO Tariff or the Transmission. Owner's ability to
comply with the TO Tariff.
2.3.3 Savings Clause. Nothing in this Agreement shall compel any
Participating TO or Municipal Tax -Exempt TO which has issued Tax -Exempt Debt to
violate restrictions applicable to transmission facilities financed with Tax -Exempt Debt or
contractual restrictions and covenants regarding use of transmission facilities existing
as of December 20, 1995.
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3. EFFECTIVE DATE, TERM AND WITHDRAWAL
3.1. Effective Date.
This Agreement shall become effective as of the latest of:
i. the date that it is signed by the ISO and the Transmission Owners
referred to in Section 2.1.1;
ii. the date the CPUC or its delegate declares to be the start date for
direct access pursuant to CPUC Decision 97-12-131; and
iii. the date when this Agreement is accepted for filing and made
effective by the FERC.
3.2. Term.
This Agreement shall remain in full force and effect until terminated:
(1) by operation of law or (2) the withdrawal of all Participating TOs pursuant to
Section 3.3 or Section 4.4.1.
3.3. Withdrawal
3.3.1 Notice. Subject to Section 3.3.3, any Participating TO may
withdraw from this Agreement on two years' prior written notice to the other Parties.
3.3.2 Sale. Subject to Section 3.3.3, any Participating TO may
withdraw from this Agreement if that Participating TO sells or otherwise disposes of all
of the transmission facilities and Entitlements that the Participating TO placed under the
ISO's Operational Control, subject to the requirements of Section 4.4.
3.3.3 Conditions of Withdrawal. Any withdrawal from this Agreement
pursuant to Section 3.3.1 or Section 3.3.2 shall be contingent upon the withdrawing
party obtaining any necessary regulatory approvals for such withdrawal. The
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withdrawing Participating TO shall make a good faith effort to ensure that its withdrawal
does not unduly impair the ISO's ability to meet its Operational Control responsibilities
as to the facilities remaining within the ISO Controlled Grid.
3.3.4 Publication of Withdrawal Notices. The ISO shall inform the
public through WEnet or the ISO internet website of all notices received under this
Section 3.3.
4. TRANSFER OF OPERATIONAL CONTROL
4.1. TO Facilities and Rights Provided to the ISO.
4.1.1 ISO Controlled Grid. Subject to Section 4.1.2 and the treatment
of Existing Contracts under Sections 2.4.3 and 2.4.4 of the ISO Tariff and subject to the
applicable interconnection, integration, exchange, operating, joint ownership and joint
participation agreements, each Participating TO shall place under the ISO's Operational
Control the transmission lines and associated facilities forming part of the transmission
network that it owns or to which it has Entitlements. The Initial Transmission Owners
identified in Section 2.1.1 shall be deemed to have placed such transmission lines and
associated facilities under the ISO's Operational Control as of the date the CPUC or its
delegate declares to be the start date for direct access pursuant to CPUC Decisions 97-
12-131 and 98-01-053. Any transmission lines or associated facilities that the ISO
determines not to be necessary to fulfill the ISO's responsibilities under the ISO Tariff in
accordance with Section 4.1.3 of this Agreement shall not be treated as part of a
Participating TO's network for the purposes of this Section 4.1. The ISO shall recognize
the rights and obligations of owners of jointly -owned facilities which are placed under
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the ISO's Operational Control by one or more but not all of the joint owners. The ISO
shall, in exercise of operational control transferred to it, ensure that the operating
obligations, as specified by the Participating TO pursuant to Section 6.4.2 of this
Agreement, for the contracts referenced in Appendix B are performed. Any other terms
of such contracts shall not be the responsibility of the ISO. The following transmission
lines and associated facilities are also deemed not to form part of a Participating TO's
transmission network:
directly assignable radial lines and associated facilities
interconnecting generation (other than those facilities which may identified from time
to time interconnecting ISO Controlled Grid Critical Protective Systems or Generators
contracted to provide Black Start or Voltage Support) and
ii. lines and associated facilities classified as "local distribution
facilities in accordance with FERC's applicable technical and functional test and other
facilities excluded consistent with FERC established criteria for determining facilities
subject to ISO Operational Control.
4.1.2 Transfer of Facilities by Local Furnishing Participating TOs.
This Section 4.1.2 is applicable only to the enlargement of transmission capacity by
Local Furnishing Participating TOs. The ISO shall not require a Local Furnishing
Participating TO to enlarge its transmission capacity except pursuant to an order under
Section 211 of the FPA directing the Local Furnishing Participating TO to enlarge its
transmission capacity as necessary to provide transmission service as determined
pursuant to Section 3.2.9 of the ISO Tariff. If an application under Section 211 of the
FPA is filed by an eligible entity (or the ISO acting as its agent), the Local Furnishing
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Participating TO shall thereafter, within 10 days of receiving a copy of the Section 211
application, waive its right to a request for service under Section 213(a) of the FPA and
to the issuance of a proposed order under Section 212(c) of the FPA. Upon receipt of a
final order from FERC under Section 211 of the FPA that is no longer subject to
rehearing or appeal, such Local Furnishing Participating TO shall enlarge its
transmission capacity to comply with that FERC order and shall transfer to the ISO
Operational Control over its expanded transmission facilities in accordance with this
Section 4.
4.1.3 Refusal of Facilities. The ISO may refuse to exercise
Operational Control over certain of an applicant's transmission lines, associated
facilities or Entitlements if it determines during the processing of an application under
Section 2.2 that any one or more of the following conditions exist:
i. The transmission lines, associated facilities or Entitlements do not
meet or do not permit the ISO to meet the Applicable Reliability Criteria and the
applicant fails to give the ISO a written undertaking to take all good faith actions
necessary to ensure that those transmission lines, facilities or Entitlements, as the case
may be, meet the Applicable Reliability Criteria within a reasonable period from the date
of the applicant's application under Section 2.2 as determined by the ISO
ii. The transmission lines, associated facilities or Entitlements are
subject to Encumbrances that unduly impair the ISO's ability to exercise its Operational
Control over them in accordance with the ISO Tariff and the applicant fails to give the
ISO a written undertaking to negotiate in good faith to the extent permitted by the
applicable contract the removal of the Encumbrances identified by the ISO which
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preclude it from using unused capacity on the relevant transmission lines. If the
applicant provides such written undertaking but is unable to negotiate the removal of
such Encumbrances to the extent required by the ISO, the ADR Procedure shall be
used to resolve any disputes between the ISO and the applicant. For this purpose,
Non -Participating TOs may utilize ISO ADR procedures on a voluntary basis.
The transmission lines, associated facilities and Entitlements are
located in a Control Area outside of California, are operated under the direction of
another Control Area or independent system operator, and cannot be integrated into the
ISO Controlled Grid due to technical considerations.
If the ISO refuses to accept any of an applicant's transmission lines,
facilities or Entitlements, then that applicant shall have the right to notify the ISO within
a reasonable period from being notified of such refusal that it will not proceed with its
application under Section 2.2.
4.1.4 Facilities Initially Placed Under the ISO's Operational Control.
The transmission lines, associated facilities and Entitlements which each Participating
TO places under the ISO's Operational Control on the date that this Agreement takes
effect with respect to it shall be identified in Appendix A.
4.1.5 Warranties. Each Participating TO warrants that as of the date
on which it becomes a Participating TO pursuant to Section 2.2.5:
i. the transmission lines and associated facilities that it is placing
under the ISO's Operational Control and the Entitlements that it is making available for
the ISO's use are correctly identified in Appendix A (as amended in accordance with
this Agreement); that the Participating TO has all of the necessary rights and authority
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to place such transmission lines and associated facilities under the ISO's Operational
Control subject to the terms and conditions of all agreements governing the use of such
transmission lines and associated facilities; and that the Participating TO has the
necessary rights and authority to, transfer the use of such Entitlements to the ISO
subject to the terms and conditions of all agreements governing the use of such
Entitlements;
ii. the transmission lines and associated facilities that it is placing
under the ISO's Operational Control are not subject to any Encumbrances except as
disclosed in Appendix B (as amended in accordance with this Agreement);
iii. the transmission lines and associated facilities that it is placing
under the ISO's Operational Control meet the Applicable Reliability Criteria (ARC) for
the relevant Participating TO except as disclosed in writing to the ISO. As to the Local
Reliability Criteria component of ARC, each Participating TO has provided the ISO with
such information required to identify such Participating TO's Local Reliability Criteria.
4.2. The ISO Register.
4.2.1 Register of Facilities Subject to ISO Operational Control. The
ISO shall maintain a register (the "ISO Register") of all transmission lines, associated
facilities and Entitlements that are for the time being subject to the ISO's Operational
Control. The ISO Register shall also indicate those facilities over which the ISO has
asserted temporary control pursuant to Section 4.5.2 and whether or not the ISO has
commenced proceedings under Section 203 of the FPA in relation to them.
4.2.2 Contents. The ISO Register shall disclose in relation to each
transmission line and associated facility subject to the ISO's Operational Control:
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i. the identity of the Participating TO responsible for its operation
and maintenance and its owner(s) (if other than the Participating TO);
ii. the date on which the ISO assumed Operational Control over it
and, in the case of transmission lines and associated facilities over which it has
asserted temporary Operational Control, the date on which it relinquished Operational
Control over it;
iii. the date of any change in the identity of the Participating TO
responsible for its operation and maintenance or in the identity of its owner; and
iv. its applicable ratings.
4.2.3 Updates. The ISO Register shall be updated by the end of the
next business day to reflect each addition or removal of a facility or entitlement from the
ISO's Operational Control or any change in a facility's ownership, rating or the identity of
the responsible Participating TO.
4.2.4 Publication. The ISO shall make the ISO Register available to
the public on WEnet or the ISO internet website.
4.2.5 Duty to Maintain Records. The ISO shall maintain the ISO
Register in a form that conveniently shows the entities responsible for operating,
maintaining and controlling the transmission lines and associated facilities forming part
of the ISO Controlled Grid at any time and the periods during which they were so
responsible.
4.3. Rights and Responsibilities of Participating TOs.
Each Participating TO shall retain its benefits of ownership and its rights
and responsibilities in relation to the transmission lines and associated facilities placed
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under the ISO's Operational Control except as otherwise provided in this Agreement.
Participating TOs shall be responsible for operating and maintaining those lines and
facilities in accordance with this Agreement, the Applicable Reliability Criteria, the
Operating Procedures and other criteria, ISO Protocols, procedures and directions of
the ISO issued or given in accordance with this Agreement. Rights and responsibilities
that have not been transferred to the ISO as operating obligations under Section 4.1.1
of this Agreement remain with the Participating TO. This Agreement shall have no
effect on the remedies for breach or non-performance available to parties to existing
interconnection, integration, exchange, operating joint ownership and joint participation
agreements.
4.4. Sale or Disposal of Transmission Facilities or Entitlements.
4.4.1 Sale or Disposition.
4.4.1.1 No Participating TO shall sell or otherwise dispose of any lines or
associated facilities forming part of the ISO Controlled Grid without the ISO's prior
written consent, which consent shall not be unreasonably withheld.
4.4.1.2 As a condition to the sale or other disposition of any lines or
associated facilities forming part of the ISO Controlled Grid to an entity that is not a
Participating TO, the Participating TO shall require the transferee to assume in writing
all of the Participating TO's obligations under this Agreement (but without necessarily
requiring it to become a Participating TO for the purposes of the ISO Tariff or a TO
Tariff).
4.4.1.3 Any subsequent sale or other disposition by a transferee referred
to in Section 4.4.1.2 shall be subject to this Section 4.4.1.
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4.4.1.4 A transferee referred to in Section 4.4.1.2 that does not become a
Participating TO shall have the same rights and responsibilities regarding withdrawal
that a Participating TO has under Sections 3.3.1 and 3.3.3.
4.4.2 Entitlements. No Participating TO shall sell, assign, release, or
transfer any Entitlements that have been placed under the ISO's Operational Control
without the ISO's prior written consent, provided that such written consent is not
required for such release or transfer to another Participating TO who is not in any
material respect in breach of its obligations under this Agreement and who has not
given notice of its intention to withdraw from this Agreement.
4.4.3 Encumbrances. No Participating TO shall create any new
Encumbrance or (except as permitted by Sections 2.4.3 and 2.4.4 of the ISO Tariff)
extend the term of an existing Encumbrance over any lines or associated facilities
forming part of its transmission network (as determined in accordance with Section
4.1.1) without the ISO's prior written consent. The ISO shall give its consent to the
creation or extension of an Encumbrance within thirty (30) days after receiving a written
request for its consent disclosing in reasonable detail the nature of and reasons for the
proposed change unless the ISO reasonably determines that the change is inconsistent
with the Participating TO's obligations under the ISO Tariff or the TO Tariff or that the
change may materially impair the ISO's ability to exercise Operational Control over the
relevant lines or facilities or may reduce the reliability of the ISO Controlled Grid.
Exercise of rights under an Existing Contract shall not be deemed to create a new
Encumbrance for the purposes of this Section 4.4.3.
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4.5. Procedure for Designating ISO Controlled Grid Facilities.
4.5.1 Additional Facilities. If the ISO determines that it requires
Operational Control over additional transmission lines and associated facilities not then
constituting part of the ISO Controlled Grid in order to fulfill its responsibilities in relation
to the ISO Controlled Grid then the ISO shall apply to FERC pursuant to Section 203 of
the Federal Power Act, and shall make all other regulatory filings necessary to obtain
approval for such change of control and shall serve a copy of all such applications on
the affected Participating TO and the owner of such lines and facilities (if other than the
Participating TO). In the event that a Party invokes the dispute resolution provisions
identified in Section 15 with respect to the transfer of Operational Control over a facility,
such facility shall not be transferred while the dispute resolution process is pending
except pursuant to Section 4.5.2.
4.5.2 Temporary Operational Control. The ISO may exercise
temporary Operational Control over any transmission lines or associated facilities of a
Participating TO (including lines and facilities to which the Participating TO has
sufficient Entitlement to permit the ISO to exercise Operational Control over them) that
do not then form part of the ISO Controlled Grid:
in order to prevent or remedy an imminent System Emergency;
ii. on reasonable notice, for a period not exceeding ninety (90) days,
in order to determine whether exercising Operational Control over the relevant lines and
facilities will assist the ISO to meet Applicable Reliability Criteria or to fulfill its Control
Area responsibilities under the ISO Tariff; or
subject to any contrary order of FERC, pending the resolution of
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the procedures referenced in Section 4.5.1.
4.5.3 Return of Control of Facilities. Control of facilities over which
the ISO has assumed temporary operational control will be returned to the appropriate
Participating TO when the conditions set forth in Section 4.5.2 no longer require the ISO
to assume such temporary control.
4.5.4 Transmission Expansion Projects. Any transmission
expansion projects carried out pursuant to Section 3.2 of the ISO Tariff shall be subject
to the ISO's Operational Control from the date that it goes into service or after such
period as the ISO deems to be reasonably necessary for the ISO to integrate the project
into the ISO Controlled Grid.
4.6. TOs Control Centers.
4.6.1 ISO's Right to Occupy Participating TOs Control Centers.
From the ISO Operations Date until the date when, in the reasonable opinion of the
ISO, the ISO Control Center is established in accordance with Section 2.3.1.1 of the
ISO Tariff, each Participating TO shall allow the ISO access to and such rights to
occupy the Participating TO's existing control centers as the ISO reasonably requires
for the purposes of exercising Operational Control of the ISO Controlled Grid.
4.6.2 Confidentiality. The parties to this Agreement shall implement
Section 4.6.1 in conformity with the confidentiality requirements of Section 26.3.
4.7. Termination of ISO's Operational Control.
4.7.1 Release from ISO's Operational Control. Subject to Section
4.7.2, the ISO may relinquish its Operational Control over any transmission lines and
associated facilities constituting part of the ISO Controlled Grid if, after consulting the
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Participating TOs owning or having Entitlements to them, the ISO determines that it no
longer requires to exercise Operational Control over them in order to meet its Control
Area responsibilities and they constitute:
i. directly assignable radial lines and associated facilities
interconnecting Generation (other than lines and facilities interconnecting ISO
Controlled Grid Critical Protective Systems or Generators contracted to provide Black
Start or Voltage Support);
ii. lines and associated facilities which, by reason of changes in the
configuration of the ISO Controlled Grid, should be classified as "local distribution"
facilities in accordance with FERC's applicable technical and functional test, or should
otherwise be excluded from the facilities subject to ISO Operational Control consistent
with FERC established criteria; or
iii. lines and associated facilities which are to be retired from service
in accordance with Good Utility Practice.
4.7.2 Procedures. Before relinquishing Operational Control over any
transmission lines or associated facilities pursuant to section 4.7.1, the ISO shall inform
the public through W Enet and the ISO internet website of its intention to do so and of
the basis for its determination pursuant to Section 4.7.1. The ISO shall give interested
parties not less than 45 days within which to submit written objections to the proposed
removal of such lines or facilities from the ISO's Operational Control. If the ISO cannot
resolve any timely objections to the satisfaction of the objecting parties and the
Participating TOs owning or having Entitlements to the lines and facilities, such parties,
Participating TOs, or the ISO may refer any disputes for resolution pursuant to the ISO
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ADR Procedures in Section 13 of the ISO Tariff. Alternatively, the ISO may apply to
FERC for its approval of the ISO's proposal.
4.7.3 Duty to Update ISO Register. The ISO shall promptly record
any change in Operational Control pursuant to this Section 4.7 in the ISO Register in
accordance with Section 4.2.3.
5. INDEPENDENT SYSTEM OPERATOR
5.1. Control Area Operator.
5.1.1 Membership of WSCC and RTGs. The ISO shall be the
designated Control Area operator for the ISO Controlled Grid and shall be a member of
the WSCC and the relevant Regional Transmission Groups (RTGs) in that capacity. No
Party shall take any position before the WSCC or an RTG that is inconsistent with a
binding decision reached through the dispute resolution process referenced in Section
15, provided that the scope of the decision was no greater than the issues set forth in
the statement of claims published by the ISO pursuant to Section 13.2.2 of the ISO
Tariff.
5.1.2 Operational Control. The ISO shall exercise Operational Control
over the ISO Controlled Grid for the purpose of:
i. providing a framework for the efficient transmission of electricity
across the ISO Controlled Grid in accordance with the ISO Tariff;
ii. securing compliance with all Applicable Reliability Criteria;
iii. scheduling transactions for Market Participants to provide open
and non-discriminatory access to the ISO Controlled Grid in accordance with the ISO
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Tariff;
iv. relieving Congestion; and
V. to the extent provided in this Agreement, assisting Market
Participants to comply with other operating criteria, contractual obligations and legal
requirements binding on them.
5.1.3 Duty of Care. The ISO shall have the exclusive right and
responsibility to exercise Operational Control over the ISO Controlled Grid, subject to
and in accordance with Applicable Reliability Criteria and the operating criteria
established by the NRC operating licenses for nuclear generating units as provided in
Appendix E pursuant to Section 6.4.2. The ISO shall take proper care to ensure the
safety of personnel and the general public. It shall act in accordance with Good Utility
Practice, applicable law, Existing Contracts, the ISO Tariff and the Operating
Procedures. The ISO shall not direct a Participating TO to take any action which would
require a Participating TO to operate its transmission facilities in excess of their
applicable rating as established or modified from time to time by the Participating TO
pursuant to Section 6.4 except in a System Emergency where such a direction is
consistent with Applicable Reliability Criteria.
5.1.4 Operating Procedures. The ISO shall, in consultation with the
Participating TOs and other Market Participants through the ISO Grid Operations
Committee promulgate Operating Procedures governing its exercise of Operational
Control over the ISO Controlled Grid in accordance with this Agreement. The ISO shall
provide copies of the Operating Procedures and all amendments, revisions and updates
to the Participating TOs and shall make them available to the public through WEnet or
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the ISO internet website.
5.1.5 Applicable Reliability Criteria. The ISO shall, in consultation
with Participating TOs and other Market Participants through the ISO Grid Operations
Committee, develop and promulgate Applicable Reliability Criteria for the ISO
Controlled Grid, which shall be in compliance with the reliability standards promulgated
by NERC, WSCC, Local Reliability Criteria and NRC grid criteria related to operating
licenses for nuclear generating units. The ISO shall provide copies of the Applicable
Reliability Criteria and all amendments, revisions and updates to the Participating TOs
and shall make them available to the public through WEnet or the ISO internet website.
5.1.6 Waivers. The ISO may grant to any Participating TO whose
transmission facilities do not meet the Applicable Reliability Criteria when it becomes a
party to this Agreement such waivers from the Applicable Reliability Criteria as the
Participating TO reasonably requires to prevent it from being in breach of this
Agreement while it brings its transmission facilities into full compliance. Such waivers
shall be effective for such period as the ISO shall determine. A Participating TO who
has been granted a waiver made under this Section 5.1.6 shall bring its transmission
facilities into compliance with the Applicable Reliability Criteria before the expiration of
the relevant waivers and in any event as soon as reasonably practical.
5.1.7 Operational Protocols. In exercising Operational Control over
the ISO Controlled Grid, the ISO shall comply with the operational protocols to be
provided in accordance with Section 6.4.2, as they may be amended from time to time
to take account of the removal and relaxation of any Encumbrances to which the ISO
Controlled Grid is subject. Participating TOs whose transmission lines and associated
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facilities are subject to Encumbrances shall make all reasonable efforts to remove or
relax those Encumbrances in order to permit the operational protocols to be amended in
such manner as the ISO may reasonably require, to the extent permitted by Existing
Contracts and applicable interconnection, integration, exchange, operating, joint
ownership and joint participation agreements
5.1.8 System Emergencies. In the event of a System Emergency, the
ISO shall have the authority and responsibility to take all actions necessary and shall
direct the restoration of the ISO Controlled Grid to service following any interruption
associated with a System Emergency. The ISO shall also have the authority and
responsibility, consistent with Section 4 and Section 9, to act to prevent System
Emergencies. Actions and directions by the ISO pursuant to this Section 5.1.8 shall be
consistent with Section 5.1.3, Duty of Care.
5.1.9 Reporting Criteria. The ISO shall comply with the reporting
requirements of the WSCC, NERC, NRC and regulatory bodies having jurisdiction over
it. Participating TOs shall provide the ISO with information that the ISO may require to
meet this obligation.
5.2. Monitoring.
5.2.1 System Requirements. The ISO shall establish reasonable
metering, monitoring, and data collection standards and requirements for the ISO
Controlled Grid, consistent with WSCC and NERC standards.
5.2.2 System Conditions. The ISO shall monitor and observe real
time system conditions throughout the ISO Controlled Grid, as well as key facilities in
other areas of the WSCC region.
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5.2.3 Power Management System. The ISO shall install a
computerized Power Management System (PMS) to monitor transmission facilities in
the ISO Controlled Grid. A Participating TO may at its own expense and for its own
internal management purposes install a read only PMS workstation that will provide the
Participating TO with the same displays the ISO uses to monitor the Participating TO's
transmission facilitates.
5.2.4 Data. Unless otherwise mutually agreed, the ISO shall obtain real
time monitoring data for the facilities listed in the ISO Register from the Participating
TOs through transfers to the ISO of data available from the Energy Management
Systems (EMS) of the Participating TOs.
5.3. Coordination Role.
The ISO shall perform a WSCC security coordinator function as
designated by the WSCC. As such, the ISO shall have all necessary powers as
described in this Agreement in relation to Participating TOs to meet the applicable
NERC and WSCC requirements for security coordinators. The ISO shall assume this
responsibility concurrent with the commencement of ISO Operational Control.
5.4. Public Information.
5.4.1 WEnet. The ISO shall develop a public information board
(' WEnet" or ISO internet website) for the ISO Controlled Grid in accordance with the
provisions in Section 6 of the ISO Tariff.
5.4.2 Access to ISO Information. The ISO shall permit the general
public to inspect and copy other information in its possession, other than information to
be kept confidential under Section 26.3, provided that the costs of providing documents
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for inspection, including any copying costs, shall be borne by the requester.
5.5. Costs
The ISO shall not implement any reliability requirements, operating
requirements or performance standards that would impose increased costs on a
Participating TO without giving due consideration to whether the benefits of such
requirements or standards are sufficient to justify such increased costs. In any
proceeding concerning the cost recovery by a Participating TO of capital and operation
and maintenance costs incurred to comply with ISO -imposed reliability requirements,
operating requirements, or performance standards, the ISO shall, at the request of the
Participating TO, provide specific information regarding the nature of, and need for, the
ISO -imposed requirements or standards to enable the Participating TO to use this
information in support of cost recovery through rates and tariffs.
6. PARTICIPATING TRANSMISSION OWNERS
6.1. Physical Operation of Facilities.
6.1.1 Operation. Each Participating TO shall have the exclusive right
and responsibility to operate and maintain its transmission facilities and associated
switch gear and auxiliary equipment (including facilities that it operates under
Entitlements).
6.1.2 ISO Operating Orders. Each Participating TO shall operate its
transmission facilities in compliance with ISO Protocols, the Operating Procedures
(including emergency procedures in the event of communications failure) and ISO's
operating orders unless the health or safety of personnel or the general public would be
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endangered. Proper implementation of an ISO operating order by a Participating TO
shall be deemed prudent. In the event an ISO order would risk damage to facilities, and
if time permits, a Participating TO shall inform the ISO of any such risk and seek
confirmation of the relevant ISO order.
6.1.3 Duty of Care. In operating and maintaining its transmission
facilities, each Participating TO shall take proper care to ensure the safety of personnel
and the general public. It shall act in accordance with Good Utility Practice, applicable
law, ISO Protocols, the Operating Procedures and the Applicable Reliability Criteria.
6.1.4 Outages. Each Participating TO shall obtain approval from the
ISO before taking out of service and returning to service any facility identified pursuant
to Section 4.2.1 in the ISO Register, except in cases involving immediate hazard to the
safety of personnel and the general public or imminent damage to facilities where there
is not time to contact the ISO. The Participating TO shall promptly notify the ISO of
such situations.
6.1.5 Return to Service. After a System Emergency or Forced
Outage, the Participating TO shall restore to service the transmission facilities under the
ISO's Operational Control as soon as possible and in the priority order determined by
the ISO. The ISO's Operating Procedures shall give priority to restoring offsite power to
nuclear generating units, in accordance with criteria specified by the Participating TOs
under the design basis and licensing requirements of the NRC licenses applicable to
such nuclear units and any other Regulatory Must -Run Generation whose operation is
critical for the protection of wildlife and the environment.
6.1.6 Written Report. Within a reasonable time, the Participating TO
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shall provide the ISO with a written report, consistent with Section 17, describing the
circumstances and the reasons for any Forced Outage, including outages under
Section 6.1.4.
6.2. Transmission Service.
6.2.1 Compliance with Tariffs. Participating TOs shall allow access to
their transmission facilities (including any that are not for the time being under the ISO's
Operational Control) only on the terms of the ISO Tariff and the TO Tariff.
6.2.2 Release of Scheduling Rights. When required by the ISO, a
Participating TO shall release all of its scheduling rights over the transmission lines and
associated facilities that are part of the ISO Controlled Grid to the extent such rights are
established through Existing Contracts among or between Participating TOs, as
provided in the ISO Tariff.
6.3. Other Responsibilities.
Each Participating TO shall inspect, maintain, repair, replace and maintain
the rating and technical performance of its facilities under the ISO's Operational Control
in accordance with the Applicable Reliability Criteria (subject to any waivers granted
pursuant to Section 5.1.6) and the performance standards established under
Section 14.
6.4. Technical Information and Protocols.
6.4.1 Information to be Provided. Each Participating TO shall provide
to the ISO prior to the effective date of this Agreement, and in a format acceptable to
the ISO:
i. Technical specifications for any facilities under the ISO's
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Operational Control, as the ISO may require;
ii. The applicable ratings of all transmission lines and associated
facilities listed in Appendix A; and
iii. A copy of each document creating an Entitlement or
Encumbrance.
The Participating TO shall promptly notify the ISO in writing or mutually
acceptable electronic format of any subsequent changes in such technical
specifications, ratings, Entitlements or Encumbrances.
6.4.2 Protocols for Encumbered Facilities. A Party that is placing a
transmission line or associated facility (including an Entitlement) that is subject town
Encumbrance under the Operational Control of the ISO shall develop protocols for its
operation which shall: (1) reflect the rights the Party has in such facility, and (2) give
effect to any Encumbrance on such facility. Such protocols shall be delivered to the
ISO for review not less than ninety (90) days prior to the date on which the ISO is
expected to assume Operational Control of any such facility. The ISO shall review each
protocol and shall cooperate with the relevant Party to assure that operations pursuant
to the protocol are feasible and that the protocol is consistent with the applicable rights
and Encumbrances. To the extent such protocol is required to be filed at FERC, the
relevant Transmission Owner shall file such protocol not less than sixty (60) days prior
to the date on which the ISO is expected to assume Operational Control of the relevant
facility. Protocols to implement the operating criteria established by the NRC operating
licenses for nuclear generating units are provided in Appendix E.
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6.5. EMS/SCADA System.
Each Participating TO shall operate and maintain its EMS/SCADA
systems and shall allow the ISO access to the Participating TO's data from such
systems relating to the facilities under the ISO's Operational Control. The ISO, at its
own cost, may, if it considers it necessary for the purpose of carrying out its
responsibilities under this Agreement, acquire, install and maintain additional monitoring
equipment on any Participating TO's property.
6.6. Single Point Of Contact.
Each Participating TO shall provide the ISO with an appropriate single
point of contact for the coordination of operations under this Agreement.
7. SYSTEM OPERATION AND MAINTENANCE
7.1. Scheduled Maintenance.
The Parties shall forecast and coordinate Maintenance Outage plans in
accordance with Section 2.3.3 of the ISO Tariff.
7.2. Exercise of Contractual Rights.
In order to facilitate Maintenance Outage coordination of the ISO
Controlled Grid by the ISO, each Participating TO shall, to the extent that the
Participating TO has contractual rights to do so: (1) coordinate Maintenance Outages
with Non -Participating Generators; and (2) exercise its contractual rights to require
maintenance by Non -Participating Generators in each case in such manner as the ISO
approves or requests. The requirements of this Section 7.2 shall not apply to any
Non -Participating Generator with a rated capability of less than 50 MW.
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7.3. Unscheduled Maintenance.
7.3.1 Notification. A Participating TO shall notify the ISO of any faults
on the ISO Controlled Grid or any actual or anticipated Forced Outages as soon as it
becomes aware of them, in accordance with Section 2.3.3 of the ISO Tariff.
7.3.2 Returns to Service. The Participating TO shall take all steps
necessary, consistent with Good Utility Practice and in accordance with the ISO Tariff
and ISO Protocols, to prevent Forced Outages and to return to operation, as soon as
possible, any facility under the ISO's Operational Control that is the subject of a Forced
Outage.
8. AUXILIARY EQUIPMENT AND ISO CONTROLLED GRID CRITICAL
PROTECTIVE SYSTEMS
8.1. Designations of Auxiliary Equipment and Critical Protective Systems.
8.1.1 System Security. The ISO shall exercise Operational Control
over all facilities and sites with protective relay systems and Remedial Action Schemes
that the ISO determines may have a direct impact on the ability of the ISO to maintain
system security. These will be designated as ISO Controlled Grid Critical Protective
Systems. Participating TOs shall coordinate with the ISO, Generators and UDCs to
ensure that ISO Controlled Grid Critical Protective Systems, including relay systems,
are installed and maintained in order to function on a coordinated and complementary
basis with Participating TO's, Generator's and UDC's protective systems.
8.1.2 Remedial Action Schemes. The ISO shall exercise Operational
Control over Remedial Action Schemes that are designated as ISO Controlled Grid
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Critical Protective Systems. Participating TOs who are parties to contracts affecting
Remedial Action Schemes shall make all reasonable efforts to amend those contracts in
order to permit the relevant Remedial Action Scheme to be operated in such manner as
the ISO may reasonably require.
8.1.3 Identification. The ISO, in conjunction with each Participating
TO shall identify and designate all ISO Controlled Grid Critical Protective Systems
operating in relation to its transmission facilities. The ISO may change the designation
of facilities and sites as ISO Controlled Grid Critical Protective Systems from time to
time.
8.2. Operation and Maintenance of Auxiliary Equipment and Critical
Protective Systems.
8.2.1 Operation and Maintenance. The system operation and
maintenance coordination functions, including ISO Maintenance Outage authorization
requirements set forth in the ISO Tariff, shall apply to auxiliary equipment associated
with the facilities identified in the ISO Register.
8.2.2 Settings and Functionality. Each Participating TO shall
maintain the settings or functionality of ISO Controlled Grid Critical Protective Systems
and shall not change or disable such settings or functionality without the prior written
agreement of the ISO.
8.2.3 Protective Relay Systems. Each Participating TO shall continue
to install, modify, maintain, repair and replace protective relay systems on all of the
facilities identified in Appendix A, in accordance with sound engineering judgment,
WSCC and NERC criteria and Good Utility Practice.
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8.2.4 Non -ISO Controlled Grid Critical Protective Systems. Each
Participating TO may alter the settings and functionality of protective relay systems and
Remedial Action Schemes that have not been designated as ISO Controlled Grid
Critical Protective Systems without the consent of the ISO, provided that such changes
do not reduce the normal or emergency rating of a facility identified in the ISO Register.
If the facility rating will be reduced, the Participating TO shall obtain approval of the ISO
prior to making such changes. In addition, the Participating TO shall promptly report to
the ISO any facility rating increases that result from any changes to its protective relay,
settings or Remedial Action Schemes.
8.2.5 Consistency. The ISO shall develop in consultation with
Participating TOs a consistent approach to protective system design and philosophy
throughout the ISO Controlled Grid to the extent that it is practical and cost effective
9. SYSTEM EMERGENCIES
9.1. ISO Management of Emergencies.
The ISO shall manage a System Emergency pursuant to the provisions of
Section 2.3.2 of the ISO Tariff. The ISO may carry out unannounced tests of System
Emergency procedures pursuant to the ISO Tariff.
9.2. Management of Emergencies by Participating TOs.
9.2.1 ISO Orders. In the event of a System Emergency, the
Participating TOs shall comply with all directions from the ISO regarding the
management and alleviation of the System Emergency unless such compliance would
impair the health or safety of personnel or the general public.
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9.2.2 Communication. During a System Emergency, the ISO and
Participating TOs shall communicate through their respective control centers, in
accordance with the Operating Procedures.
9.3. System Emergency Reports: TO Obligations.
9.3.1 Records. Pursuant to Section 17, each Participating TO shall
maintain appropriate records pertaining to a System Emergency.
9.3.2 Review. Each Participating TO shall cooperate with the ISO in
the preparation of an Outage review pursuant to Section 2.3 of the ISO Tariff and
Section 17 of this Agreement.
9.4. Sanctions.
In the event of a major Outage that affects at least 10 percent of the
customers of an entity providing local distribution service, the ISO may order a
Participating TO to pay appropriate sanctions, as filed with and approved by FERC in
accordance with Section 12.3, if the ISO finds that the operation and maintenance
practices of the Participating TO, with respect to its transmission lines and associated
facilities that it has placed under the ISO's Operational Control, prolonged the response
time or was responsible for the Outage.
10. ISO CONTROLLED GRID ACCESS AND INTERCONNECTION
10.1. ISO Controlled Grid Access and Services.
10.1.1 Access. The ISO shall respond to requests from the Participating
TOs and other Market Participants for access to the ISO Controlled Grid. All
Participating TOs who have Eligible Customers connected to their transmission or
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distribution facilities that do not form part of the ISO Controlled Grid shall ensure open
and non-discriminatory access to those facilities for those Eligible Customers through
the implementation of an open access tariff, provided that a Participating TO shall only
be required to ensure open access to those facilities for End -Use Customers to the
extent it is required by applicable law to do so or pursuant to a voluntary offer to do so.
10.2. Interconnection.
10.2.1 Obligation to Interconnect. The Parties shall be obligated to
allow interconnection to the ISO Controlled Grid in a non-discriminatory manner, subject
to the conditions specified in this Section 10 and the applicable legal requirements.
10.2.2 Standards. All Interconnections shall be designed and built in
accordance with Good Utility Practice, all Applicable Reliability Criteria, and applicable
statutes and regulations.
10.2.3 System Upgrades. A Participating TO shall be entitled to require
a entity requesting Interconnection to pay for all necessary system reliability upgrades
on its side of the Interconnection and on the ISO Controlled Grid, as well as for all
required studies, inspection and testing, to the extent permitted by FERC policy. The
entity requesting Interconnection shall be required to execute an Interconnection
Agreement in accordance with the TO Tariff and must comply with all of its provisions,
including provisions related to creditworthiness and payment for Facility Studies.
10.2.4 A Local Furnishing Participating TO shall not be obligated to
construct or expand interconnection facilities or system upgrades unless and until the
conditions. stated in Section 4.1.2 hereof have been satisfied.
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10.3. Participating TO Responsibilities - Interconnections.
10.3.1 Technical Standards. Each Participating TO shall develop
technical standards for the design, construction, inspection, and testing applicable to
proposed Interconnections of Load and/or Generation Unit and apparatus to that part of
the ISO Controlled Grid Facilities owned by the Participating TO. Such standards shall
be consistent with Applicable Reliability Criteria and shall be developed in consultation
with the ISO. The Participating TO shall periodically review and revise its criteria to
ensure compliance with Applicable Reliability Criteria.
10.3.2 Notice. A list of the Interconnection standards and procedures
developed by each Participating TO pursuant to Section 10.3.1, including any revisions,
shall be made available to the public through the information board (e.g. WEnet or ISO
internet website). In addition, the posting will provide information on how to obtain the
Interconnection standards and procedures. The Participating TO shall provide these
standards to any party, upon request.
10.3.3 Requests for Interconnection. Each Participating TO shall
accept requests for new or modified Interconnections to the ISO Controlled Grid, and
shall process such requests in a timely, non-discriminatory manner in accordance with
its tariffs and procedures. In this regard, the Participating TO shall:
i. collect all relevant data required to process the request;
ii. coordinate the processing of the Interconnection requests with the
ISO, including collecting and submitting to the ISO all information necessary for the ISO
to assess the Interconnection request;
iii. enter into system impact or Facilities Study Agreements in
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accordance with the applicable TO Tariff with the entity requesting Interconnection, in
order to perform the studies necessary to assess the impact of the Interconnection on
the ISO Controlled Grid and identify the facilities and any necessary reinforcements of
the ISO Controlled Grid, including any alternative reinforcement options identified by the
party requesting the Interconnection, that are required for the Interconnection;
iv. enter into agreements governing the operation of the requested
Interconnection and agreements for construction, where applicable;
V. explain available study and timing options to the entity requesting
Interconnection;
vi. provide a detailed estimate of the costs to be paid by the party
requesting Interconnection and a statement of the proposed method of allocating the
cost of any required system upgrades between that party and any other beneficiaries;
and
vii. provide to the entity requesting Interconnection all ISO comments,
including any additional ISO -imposed requirements.
10.3.4 Coordination of Interconnection Requests. To ensure that all
Interconnection requests are processed in a non-discriminatory manner, the
Participating TO shall develop, periodically review, and revise procedures for
coordinating Interconnection requests consistent with Section 5.2 of the TO Tariff. Such
procedures will specify: (1) the timing for processing requests of differing complexity;
and (2) the sequencing of coordinating activities with the ISO. In addition, the
Participating TO shall coordinate the operational aspects of such Interconnection with
the ISO.
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10.3.5 Acceptance of Interconnection Facilities. The Participating TO
shall perform all necessary site inspections, review all relevant equipment tests, and
ensure that all necessary agreements have been fully executed prior to accepting
Interconnection facilities for operation.
10.3.6 Collection of Payments. The Participating TO shall collect all
payments owed under any Facility Study Agreement or other agreement entered into
pursuant to this Section 10.3 or the provisions of its TO Tariff relating to Interconnection.
10.4. ISO Responsibilities - Interconnections.
10.4.1 Review of Participating TO Technical Standards. Participating
TOs shall provide the ISO with copies of their technical standards for Interconnection
developed pursuant to Section 10.3.1 of this Agreement and all amendments so that the
ISO can satisfy itselfas to their compliance with the Applicable Reliability Criteria. The
ISO shall develop consistent Interconnection standards across the ISO Controlled Grid,
to the extent possible given the circumstances of each Participating TO, in consultation
with Participating TOs through the ISO Grid Operations Committee
10.4.2 Coordination with Participating TOs. The ISO shall coordinate
with each Participating TO in processing Interconnection requests. In that regard, the
ISO shall (1) review each Participating TO's current procedures for coordinating
Interconnection requests made in accordance with Section 10.3.4, (2) review individual
Interconnection requests and all related Participating TO studies, and (3) forward any
comments or additional requirements to the Participating TO for transmittal to the entity
requesting Interconnection.
10.4.3 On -Site Inspections. The ISO may at its own expense
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accompany a Participating TO during on -site inspections and tests of Interconnections
or, by pre -arrangement, may itself inspect Interconnections or perform its own additional
inspections and tests.
10.5. Joint Responsibilities.
The Parties shall share with the ISO relevant information about
Interconnection requests and coordinate their activities to ensure that all Interconnection
requests are processed in a timely, non-discriminatory fashion and that all
Interconnections meet the operational and reliability criteria applicable to the ISO
Controlled Grid. Subject to Section 26.3 of this Agreement, the ISO shall pass on such
information to any Parties who require it to carry out their responsibilities under this
Agreement.
11. EXPANSION OF TRANSMISSION FACILITIES
The provisions of Section 3.2 of the ISO Tariff will apply to any expansion
or reinforcement of the ISO Controlled Grid affecting the transmission facilities of the
Participating TOs placed under the Operational Control of the ISO.
12. USE AND ADMINISTRATION OF THE ISO CONTROLLED GRID
12.1. Use of the ISO Controlled Grid.
Except as provided in Section 13, use of the ISO Controlled Grid by the
Participating TOs and other Market Participants shall be in accordance with the rates,
terms, and conditions established in the ISO Tariff and the Participating TO's Tariff.
Pursuant to Section 2.1.2 of the ISO Tariff transmission service shall be provided only to
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direct access and wholesale customers eligible under state and federal law.
12.2. Administration.
Each Participating TO transfers authority to the ISO to administer the terms and
conditions for access to the ISO Controlled Grid and to collect, among other things,
Congestion Management revenues, and Wheeling -Through and Wheeling -Out
revenues.
12.3. Incentives and Penalty Revenues.
The ISO, in consultation with the Participating TOs, shall develop standards and
a mechanism for paying to and collecting from Participating TOs incentives and
penalties that may be assessed by the ISO. Such standards and mechanism shall be
filed with FERC and shall become effective upon acceptance by FERC.
13. EXISTING AGREEMENTS
The provisions of Sections 2.4.3 and 2.4.4 of the ISO Tariff will apply to
the treatment of transmission facilities of a Participating TO under the Operational
Control of the ISO which are subject to transmission service rights under Existing
Contracts. In addition, the ISO will honor the operating obligations as specified by the
Participating TO, pursuant to Section 6.4.2 of this Agreement, including any provision of
interconnection, integration, exchange, operating, joint ownership and joint participation
agreements, when operating the ISO Controlled Grid.
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14. MAINTENANCE STANDARDS
14.1. ISO Determination of Standards.
The ISO shall adopt, in consultation with the Participating TOs through the
ISO Grid Operations Committee, standards for the maintenance, inspection, repair, and
replacement of transmission facilities under its Operational Control in accordance with
Appendix C. These standards, which shall be performance -based or prescriptive or
both, will provide for high quality, safe, and reliable service and shall take into account
costs, local geography and weather, the Applicable Reliability Criteria, national electric
industry practice, sound engineering judgment and experience.
a
14.2. Existing Standards.
Until such time as the ISO adopts standards pursuant to Section 14.1, the
ISO shall measure the performance of Participating TOs in relation to the maintenance,
inspection, repair and replacement of transmission facilities by their existing standards.
Each Participating TO shall provide the ISO with such information as the ISO shall
require to identify such Participating TO's existing maintenance standards and measure
its performance against the relevant standards.
14.3. Availability Formula.
14.3.1 Availability Measure. The ISO performance -based standards
shall be based on the availability measures described in Section 4 of Appendix C of this
Agreement.
14.3.2 Excluded Events. Scheduled Approved Maintenance Outages
and certain Forced Outages will be excluded pursuant to Section 4.2.3 of Appendix C of
this Agreement from the calculation of the availability measure.
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14.3.3 Availability Measure Target. Under the oversight of the ISO
Grid Operations Committee, the Maintenance Coordination Committee and each
Participating TO shall jointly develop for the Participating TO an availability measure
target, which may be defined by a range. The target will be based on prior Participating
TO performance developed in accordance with Section 4 of Appendix C of this
Agreement and national benchmarks.
14.3.4 Calculation of Availability Measure. The availability measure
shall be calculated annually by the Participating TO and reported to the ISO for
evaluation of the Participating TO's compliance with the availability measure target.
This calculation will determine the availability measure in accordance with Section 4 of
Appendix C of this Agreement.
14.3.5 Compliance with Availability Measure Target. The ISO and
the Participating TO may track the availability measure on a more frequent basis (e.g.,
quarterly, monthly), but the annual calculation shall be the sole basis for determining the
Participating TO's compliance with its availability measure target.
14.3.6 Public Record. The Participating TO's annual availability
measure calculation and the associated availability measure data shall be made
available to the public.
14.4. Revisions to Standards.
The ISO shall periodically review with the Participating TOs the standards
and incentives implemented pursuant to this Section 14 and, through the Maintenance
Coordination Committee process, under the oversight of the ISO Grid Operations
Committee, shall modify these standards and incentives as necessary.
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14.5. Incentives and Penalties.
The ISO shall, subject to regulatory approval, develop incentive programs
which reward or impose sanctions on Participating TOs by reference to their availability
measure and the extent to which the availability performance imposes demonstrable
costs or results in demonstrable benefits for Market Participants.
15. DISPUTE RESOLUTION
In the event any dispute regarding the terms and conditions of this Agreement is
not settled, the Parties shall follow the ISO ADR Procedure set forth in Section 13 of the
ISO Tariff. The specific references in this Agreement to alternative dispute resolution
procedures shall not be interpreted to limit the Parties' rights and obligations to invoke
dispute resolution procedures pursuant to this Section-15.
16. BILLING AND PAYMENT
16.1 Application of ISO Tariff
The ISO and Participating TOs shall comply with the billing and payment
provisions set forth in Section 11 of the ISO Tariff.
16.2 Refund Obligation
Each Participating TO, whether or not it is subject to the rate jurisdiction of the
FERC under Section 205 and Section 206 of the Federal Power Act, shall make all
refunds, adjustments to its Transmission Revenue Requirement, and adjustments to its
TO Tariff and do all other things required of a Participating TO to implement any FERC
order related to the ISO Tariff, including any FERC order that requires the ISO to make
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payment adjustments or pay refunds to, or receive prior period overpayments from, any
Participating TO. All such refunds and adjustments shall be made, and all other actions
taken, in accordance with the ISO Tariff, unless the applicable FERC order requires
otherwise.
17. RECORDS AND INFORMATION SHARING
17.1. Records Relevant to Operation of ISO Controlled Grid.
The ISO shall keep such records as may be necessary for the efficient
operation of the ISO Controlled Grid and shall make appropriate records available to a
Participating TO, upon request. The ISO shall maintain for not less than five (5) years:
(1) a record of its operating orders and (2) a record of the contents of, and changes to,
the ISO Register.
17.2., Participating TO Records and Information Sharing.
17.2.1 Existing Standards. Each Participating TO shall provide to the
ISO in a format and at the time to be established by the ISO in coordination with the
Participating TO, the Participating TO's standards for inspection, maintenance, repair,
and replacement of its facilities under the ISO's Operational Control in effect as of the
date it executes this, Agreement.
17.2.2 Records. Each Participating TO shall provide and maintain
current data, records, and drawings describing the physical and electrical properties of
the facilities under the ISO's Operational Control and shall maintain records of all
inspections, maintenance, replacement, and repairs performed on such facilities, which
records shall be shared with the ISO under reasonable guidelines and procedures to be
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specified by the ISO, after consultation with the ISO Grid Operations Committee.
17.2.3 Required Reports. Pursuant to this Agreement and the
provisions of the ISO Tariff, each Participating TO shall provide to the ISO timely
information, notices, or reports regarding matters of mutual concern, including:
i. System Emergencies, Forced Outages and other incidents
affecting the ISO Controlled Grid;
ii. Maintenance Outage requests, including yearly forecasts required
by Section 2.3.3.5 of the ISO Tariff;
iii. System Planning Studies, including studies prepared in
connection with Interconnections or any transmission facility enhancement or
expansion; and
iv. Compliance with the inspection, maintenance, repair, and
replacement standards established under Section 14.
17.2.4 Other Reports. The ISO may, upon reasonable notice to the
Participating TO, request that the Participating TO provide the ISO with such
information or reports necessary for the operation of the ISO Controlled Grid. The
Participating TO shall make all such information or reports available to the ISO within a
reasonable time and in a form to be specified by the ISO.
17.2.5 Other Market Participant Information. At the request of the
ISO, a Participating TO shall provide the ISO with non -confidential information obtained
by the Participating TO from other Market Participants pursuant to contracts between
the Participating TO and such other Market Participants. Such requests shall be limited
to information that is reasonably necessary for the operation of the ISO Controlled Grid.
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17.3. ISO System Studies and Operating Procedures.
17.3.1 System Studies and Grid Stability Analyses. The ISO, in
coordination with Participating TOs, shall perform system operating studies or grid
stability analyses to evaluate forecasted changes in grid conditions that could affect its
ability to ensure compliance with the Applicable Reliability Criteria. The results and
reports from such studies shall be exchanged between the ISO and the Participating
TOs. Study results and conclusions shall generally be assessed annually, and shall be
updated as necessary, based on changing grid and local area conditions.
17.3.2 Grid Conditions Affecting Regulations, Permits and
Licenses. The ISO shall promulgate and maintain Operating Procedures to ensure that
impaired or potentially degraded grid conditions are assessed and immediately
communicated to the Participating TOs for operability determinations required by
applicable regulations, permits or licenses, such as NRC operating licenses for nuclear
generating units.
17.4. Significant Incident.
17.4.1 Risk of Significant Incident. Any Party shall timely notify all
other Parties if it becomes aware of the risk of significant incident, including extreme
temperatures, storms, floods, fires, earthquakes, earth slides, sabotage, civil unrest,
equipment outage limitations, etc., that affect the ISO Controlled Grid. The Parties shall
provide information that the reporting Party reasonably deems appropriate and
necessary for the other Parties to prepare for the occurrence, in accordance with Good
Utility Practice.
17.4.2 Occurrence of Significant Incident. Any Party shall timely
ISO Rev. 02.1200
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notify all other Parties if it becomes aware that a significant incident affecting the ISO
Controlled Grid has occurred. Subsequent to notification, each Party shall make
available to the ISO all relevant data related to the occurrence of the significant incident.
Such data shall be sufficient to accommodate any reporting or analysis necessary for
the Parties to meet their obligations under this Agreement.
17.5. Review of Information and Record -Related Policies.
The ISO Grid Operations Committee shall review the requirements of this
Section 17 annually and shall, consistent with reliability and regulatory needs, seek to
standardize reasonable record keeping, reporting, and information sharing
requirements.
18. GRANTING RIGHTS -OF -ACCESS TO FACILITIES
18.1. Equipment Installation.
In order to meet its obligations under this Agreement, a Party that owns,
rents, or leases equipment (the equipment owner) may require installation of such
equipment on property owned by another Party (the property owner), provided that the
property is being used for an electric utility purpose and that the property owner shall
not be required to do so if it would thereby be prevented from performing its own
obligations or exercising its rights under this Agreement.
18.1.1 Free Access. The property owner shall grant to the equipment
owner free of charge reasonable installation rights and rights of access to accommodate
equipment inspection, repair, upgrading, or removal for the purposes of this Agreement,
subject to the property owner's reasonable safety, operational, and future expansion
ISO Rev. 02.1200
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needs.
18.1.2 Notice. The equipment owner (whether ISO or Participating TO)
shall provide reasonable notice to the property owner when requesting access for site
assessment, coordinating equipment installation, or other relevant purposes.
18.1.3 Removal of Installed Equipment. Following reasonable notice,
the equipment owner shall be required, at its own expense, to remove or relocate
equipment, at the request of the property owner, provided that the equipment owner
shall not be required to do so if it would thereby be prevented from performing its
obligations or exercising its rights under this Agreement.
18.1.4 Costs. The equipment owner shall repair at its own expense any
property damage it causes in exercising its rights and shall reimburse the property
owner for any other costs that it is required to incur to accommodate the equipment
owner's exercise of its rights under this Section 18.1.
18.2. Rights to Assets.
The Parties shall not interfere with each other's assets, without prior
agreement.
18.3. Inspection of Facilities.
In order to meet their respective obligations under this Agreement, any
Party may view or inspect facilities owned by another Party. Provided that reasonable
notice is given, a Party shall not unreasonably deny access to relevant facilities for
viewing or inspection by the requesting Party.
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19. ISO GRID OPERATIONS COMMITTEE
The Parties shall coordinate activities relating to ISO Controlled Grid practices
and procedures using the ISO Grid Operations Committee process provided for in
Article IV, Section 4 of the ISO Bylaws.
20. TRAINING
20.1. Staffing and Training to Meet Obligations.
Each Party shall make its own arrangements for the engagement of all
staff and labor necessary to perform its obligations hereunder and for their payment.
Each Party shall employ (or cause to be employed) only persons who are appropriately
qualified, skilled, and experienced in their respective trades or occupations. ISO
employees and contractors shall abide by the ISO Code of Conduct contained in the
ISO Bylaws and approved by FERC.
20.2. Technical Training.
The ISO and the Participating TOs shall respond to reasonable requests
for support and provide relevant technical training to each other's employees to support
the safe, reliable, and efficient operation of the ISO Controlled Grid and to comply with
any NERC or WSCC operator certification or training requirements. Examples of such
technical training include, but are not limited to: (1) the theory or operation of new or
modified equipment (e.g., control systems, remedial action schemes, protective relays);
(2) computer and applicator programs; and (3) ISO (or Participating TO) requirements.
The Parties shall enter into agreements regarding the timing, term, locations, and cost
allocation for the training.
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21. OTHER SUPPORT SYSTEMS REQUIREMENTS
21.1. Related Systems.
The Parties shall each own, maintain, and operate equipment, other than
those facilities described in the ISO Register, which is necessary to meet their specific
obligations under this Agreement.
21.2. Lease or Rental of Equipment by the ISO.
Under certain circumstances, it may be prudent for the ISO to lease or
rent equipment owned by a Participating TO, (e.g., EMS/SCADA, metering, telemetry,
and communications systems), instead of installing its own equipment. In such case,
the ISO and the Participating TO shall mutually determine whether the ISO shall lease
or rent the Participating TO's equipment. The ISO and the Participating TO shall enter
into a written agreement specifying all the terms and conditions governing the lease or
rental, including its term, equipment specifications, maintenance, availability, liability,
interference mitigation, and payment terms.
22. LIABILITY
22.1. Liability for Damages.
Except as provided for in Section 13.3.14 of the ISO Tariff and subject to
Section 22.4 no Party to this Agreement shall be liable to any other Party for any losses,
damages, claims, liability, costs or expenses (including legal expenses) arising from the
performance or non-performance of its obligations under this Agreement except to the
extent that its negligent performance of this Agreement (including intentional breach)
results directly in physical damage to property owned, operated by or under the
ISO Rev. 02.1200
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operational control of any of the other Parties or in the death or injury of any person.
22.2. Exclusion of Certain Types of Loss.
No Party shall be liable to any other party under any circumstances
whatsoever for any consequential or indirect financial loss (including but not limited to
loss of profit, loss of earnings or revenue, loss of use, loss of contractor loss of
goodwill) resulting from physical damage to property for which a parry may be liable
under Section 22.1.
22.3. ISO's Insurance.
The ISO shall maintain insurance policies covering part or all of its liability
under this Agreement with such insurance companies and containing such policy limits
and deductible amounts as shall be determined by the ISO Governing Board from time
to time. The ISO shall provide all Participating TOs with details of all insurance policies
maintained by it pursuant to this Section 22 and shall have them named as additional
insureds to the extent of their insurable interest.
22.4. Participating TOs Indemnity.
Each Participating TO shall indemnify the ISO and hold it harmless
against all losses, damages, claims, liability, costs or expenses (including legal
expenses) arising from third party claims due to any act or omission of that Participating
TO except to the extent that they result from intentional wrongdoing or negligence on
the part of the ISO or of its officers, directors or employees. The ISO shall give written
notice of any third parry claims against which it is entitled to be indemnified under this
Section to the Participating TOs concerned promptly after becoming aware of them.
The Participating TOs who have acknowledged their obligation to provide a full
ISO Rev. 02.1200
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Page 52
indemnity shall be entitled to control any litigation in relation to such third party claims
(including settlement and other negotiations) and the ISO shall, subject to its right to be
indemnified against any resulting costs, cooperate fully with the Participating TOs in
defense of such claims.
23. UNCONTROLLABLE FORCES
23.1. Occurrences of Uncontrollable Forces.
An Uncontrollable Force means any act of God, labor disturbance, act of
the public enemy, war, insurrection, riot, fire, storm or flood, earthquake, explosion, any
curtailment, order, regulation, or restriction imposed by governmental, military or lawfully
established civilian authorities or any other cause beyond a Party's reasonable control
and without such Party's fault or negligence. No Party will be considered in default as
to any obligation under this Agreement if prevented from fulfilling the obligation due to
the occurrence of an Uncontrollable Force.
23.2. Obligations in the Event of an Uncontrollable Force.
In the event of the occurrence of an Uncontrollable Force, which prevents
a Party from performing any of its obligations under this Agreement, such Party shall:
(1) immediately notify the other Parties of such Uncontrollable Force with such notice to
be confirmed in writing as soon as reasonably practicable; (2) not be entitled to suspend
performance of its obligations under this Agreement to any greater extent or for any
longer duration than is required by the Uncontrollable Force; (3) use its best efforts to
mitigate the effects of such Uncontrollable Force, remedy its inability to perform, and
resume full performance of its obligations hereunder; (4) keep the other Parties
ISO Rev. 02.1200
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apprised of such efforts on a continual basis; and (5) provide written notice of the
resumption of performance hereunder. Notwithstanding any of the foregoing, the
settlement of any strike, lockout, or labor dispute constituting an Uncontrollable Force
shall be within the sole discretion of the Party to this Agreement involved in such strike,
lockout, or labor dispute and the requirement that a Party must use its best efforts to
remedy the cause of the Uncontrollable Force and/or mitigate its effects and resume full
performance hereunder shall not apply to strikes, lockouts, or labor disputes.
24. ASSIGNMENTS AND CONVEYANCES
No Party may assign its rights or transfer its obligations under this
Agreement except, in the case of a Participating TO, pursuant to Section 4.4.1.
25. ISO ENFORCEMENT
In addition to its other rights and remedies under this Agreement, the ISO may if
it sees fit initiate regulatory proceedings seeking the imposition of sanctions against any
Participating TO who commits a material breach of its obligations under this Agreement.
26. MISCELLANEOUS
26.1. Notices.
Any notice, demand, or request in accordance with this Agreement, unless
otherwise provided in this Agreement, shall be in writing and shall be deemed properly
served, given, or made: (1) upon delivery if delivered in person; (2) five (5) days after
deposit in the mail, if sent by first class United States mail, postage prepaid; (3) upon
ISO Rev. 02.1200
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receipt of confirmation by return electronic facsimile if sent by facsimile; or (4) upon
delivery if delivered by prepaid commercial courier service. Any Party may at any time,
by notice to the other Parties, change the designation or address of the person specified
to receive notice on its behalf in Appendix F. Such changes to Appendix F shall not
constitute an amendment to this Agreement. Any notice of a routine character in
connection with service under this Agreement or in connection with the operation of
facilities shall be given in such a manner as the Parties may determine from time to
time, unless otherwise provided in this Agreement.
26.2. Non -Waiver.
Any waiver at any time by any Party of its rights with respect to any default
under this Agreement, or with respect to any other matter arising in connection with this
Agreement, shall not constitute or be deemed a waiver with respect to any subsequent
default or other matter arising in connection with this Agreement. Any delay short of the
statutory period of limitations in asserting or enforcing any right shall not constitute or be
deemed a waiver.
26.3. Confidentiality.
26.3.1 ISO. The ISO shall maintain the confidentiality of all of the
documents, data, and information provided to it by any other Parry that are treated as
confidential or commercially sensitive under the confidentiality provisions of the ISO
Tariff; provided, however, that the ISO shall not keep confidential: (1) information that is
explicitly subject to data exchange through WEnet or the ISO internet website pursuant
to Section 6 of the ISO Tariff; (2) information that the ISO or the Party providing the
information is required to disclose pursuant to this Agreement, the ISO Tariff, or
ISO Rev. 02.1200
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applicable regulatory requirements (provided that the ISO shall comply with any
applicable limits on such disclosure); or (3) the information becomes available to the
public on a non -confidential basis (other than as a result of the ISO's breach of this
Agreement).
26.3.2 Other Parties. No Party shall have a right hereunder to receive
from the ISO or to review any documents, data or other information of another Party to
the extent such documents, data or information are required to be kept confidential in
accordance with Section 26.3.1 above, provided, however, that a Party may receive and
review any composite documents, data, and other information that may be developed
based upon such confidential documents, data, or information, if the composite
document does not disclose any individual Party's confidential data or information.
26.3.3 Disclosure. Notwithstanding anything in this Section 26.3 to the
contrary, if the ISO is required by applicable laws or regulations, or in the course of
administrative or judicial proceedings, to disclose information that is otherwise required
to be maintained in confidence pursuant to this Section 26.3, the ISO may disclose such
information; provided, however, that as soon as the ISO learns of the disclosure
requirement and prior to making such disclosure, the ISO shall notify the affected Party
or Parties of the requirement and the terms thereof. The affected Parry or Parties may,
at their sole discretion and own costs, direct any challenge to or defense against the
disclosure requirement and the ISO shall cooperate with such affected Party or Parties
to the maximum extent practicable to minimize the disclosure of the information
consistent with applicable law. The ISO shall cooperate with the affected Parties to
obtain proprietary or confidential treatment of confidential information by the person to
ISO Rev. 02.1200
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Page 56
whom such information is disclosed prior to any such disclosure.
26.4. Third Party Beneficiaries.
The Parties do not intend to create rights in, or to grant remedies to, any
third party as a beneficiary of this Agreement or of any duty, covenant, obligation, or
undertaking established hereunder.
26.5. Relationship of the Parties.
The covenants, obligations, rights, and liabilities of the Parties under this
Agreement are intended to be several and not joint or collective, and nothing contained
herein shall ever be construed to create an association, joint venture, trust, or
partnership, or to impose a trust or partnership covenant, obligation, or liability on, or
with regard to, any of the Parties. Each Party shall be individually responsible for its
own covenants, obligations, and liabilities under this Agreement. No Party or group of
Parties shall be under the control of or shall be deemed to control any other Party or
Parties. No Party shall be the agent of or have the right or power to bind any other
Party without its written consent, except as expressly provided for in this Agreement.
26.6. Titles.
The captions and headings in this Agreement are inserted solely to
facilitate reference and shall have no bearing upon the interpretation of any of the terms
and conditions of this Agreement.
26.7. Severability.
If any term, covenant, or condition of this Agreement or the application or
effect of any such term, covenant, or condition is held invalid as to any person, entity, or
circumstance, or is determined to be unjust, unreasonable, unlawful, imprudent, or
ISO Rev. 02.1200
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otherwise not in the public interest by any court or government agency of competent
jurisdiction, then such term, covenant, or condition shall remain in force and effect to the
maximum extent permitted by law, and all other terms, covenants, and conditions of this
Agreement and their application shall not be affected thereby, but shall remain in force
and effect and the parties shall be relieved of their obligations only to the extent
necessary to eliminate such regulatory or other determination unless a court or
governmental agency of competent jurisdiction holds that such provisions are not
separable from all other provisions of this Agreement.
26.8. Preservation of Obligations.
Upon termination of this Agreement, all unsatisfied obligations of each
Party shall be preserved until satisfied.
26.9. Governing Law.
This Agreement shall be interpreted, governed by and construed under
the laws of the State of California, without regard to the principles of conflict of laws
thereof, or the laws of the United States, as applicable, as if executed and to be
performed wholly within the State of California.
26.10. Construction of Agreement.
Ambiguities or uncertainties in the wording of this Agreement shall not be
construed for or against any Party, but shall be construed in a manner that most
accurately reflects the purpose of this Agreement and the nature of the rights and
obligations of the Parties with respect to the matter being construed.
26.11. Amendment.
This Agreement may be modified: (1) by mutual agreement of the Parties,
ISO Rev. 02.1200
Transmission Control Agreement
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subject to approval by FERC; (2) through the ISO ADR Procedure set forth in Section
13 of the ISO Tariff; or (3) upon issuance of an order by FERC.
26.12. Appendices Incorporated.
The several appendices to this Agreement, as may be revised from time to
time, are attached to this Agreement and are incorporated by reference as if herein fully
set forth.
26.13. Counterparts.
This Agreement may be executed in one or more counterparts, which may
be executed at different times. Each counterpart, which shall include applicable
individual Appendices A, B, C, D and E shall constitute an original but all such
counterparts together shall constitute one and the same instrument.
ISO Rev. 02.1200
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27. SIGNATURE PAGE
CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
California Independent System Operator Corporation has caused this
Transmission Control Agreement to be executed by its duly authorized representative
on this day of , 20 and thereby incorporates the
following Appendices in this Agreement:
Appendices A (PG&E, SDG&E and Edison)
Appendices B (PG&E, SDG&E and Edison)
Appendix C
Appendix D
Appendices E
Appendix F
CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
151 Blue Ravine Road
Folsom, California 95630
by:
Terry M. Winter
President and Chief Executive Officer
ISO REV 02.1200
Transmission Control Agreement
Page 60
28. SIGNATURE PAGE
PACIFIC GAS AND ELECTRIC COMPANY
Pacific Gas and Electric Company has caused this Transmission
Control Agreement to be executed by its duly authorized representative on this
day of , 20 and thereby incorporates the
following Appendices in this Agreement:
Appendix A (PG&E)
Appendix B (PG&E)
Appendix C
Appendix D
Appendix E (Diablo Canyon)
Appendix F
PACIFIC GAS & ELECTRIC COMPANY
77 Beale Street
San Francisco, California 94105
by:
James K. Randolph
Senior Vice President and General Manager
ISO REV 02.1200
Transmission Control Agreement
Page 61
29. SIGNATURE PAGE
SAN DIEGO GAS & ELECTRIC COMPANY
San Diego Gas & Electric Company has caused this Transmission
Control Agreement to be executed by its duly authorized representative on this
day of , 20 and thereby incorporates the
following Appendices in this Agreement:
Appendix A (SDG&E)
Appendix B (SDG&E)
Appendix C
Appendix D
Appendix E (SONGS)
Appendix F
SAN DIEGO GAS & ELECTRIC COMPANY
101 Ash Street
San Diego, California 92101
by:
Debra L. Reed
President of San Diego Gas & Electric
ISO REV 02.1200
Transmission Control Agreement
Page 62
30. SIGNATURE PAGE
SOUTHERN CALIFORNIA EDISON COMPANY
Southern California Edison Company has caused this Transmission
Control Agreement to be executed by its duly authorized representative on this
day of , 20 and thereby incorporates the
following Appendices in this Agreement:
Appendix A (Edison)
Appendix B (Edison)
Appendix C
Appendix D
Appendix E (SONGS)
Appendix F
SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue
Rosemead, California 91770
by:
R. M. Rosenwood
Senior Vice President, Transmission & Distribution
ISO REV 02.1200
Transmission Control Agreement
Page 63
31. SIGNATURE PAGE
CITY OF VERNON
CITY OF VERNON has caused this Transmission Control Agreement to
be executed by its duly authorized representative on this day of
,20 and thereby incorporates the following Appendices in this
Agreement:
Appendix A (Vernon)
Appendix B (Vernon) .
Appendix C
Appendix D
Appendix E
Appendix F
CITY OF VERNON
By:
LEONIS C. MALBURG, Mayor
ATTEST:
BRUCE V. MALKENHORST, City Clerk
APPROVED AS TO FORM:
EDUARDO OLIVO, City Attorney
ISO REV 02.1200
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d d
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
ISO MAINTENANCE STANDARDS
1. DEFINITIONS'
Availability - A measure of time a Transmission Facility under ISO Operational Control is
capable of providing service, whether or not it actually is in service.
Availability Measures - The frequency and accumulated duration of Forced Outages(ms' for each
of the Transmission Line Circuits within a Voltage Class for a given calendar year.
Availability Measure Targets- The Availability performance goals established by the ISO.
Forced Outage(IMs) - A Forced Outage(ms) occurs when a Transmission Facility is in an
Outage(IMs) condition regardless of duration and: (1) there is no Scheduled Outage request in
effect with respect to that period; or (2) the Transmission Facility is in an Outage (Ms) condition
for a period that exceeds the period specified in the Scheduled Outage request, in which case a
Forced Outage(ms) is deemed to exist for the balance of the period, unless the PTO requests and
is granted an extension to the approved Scheduled Outage request.
ISO Maintenance Guidelines - Criteria presented herein which are to be followed by each PTO in
preparing its PTO Maintenance Practices.
ISO Maintenance Standards - Those maintenance standards which result from the combination
of each PTO's Maintenance Practices and their respective Availability Measures.
Maintenance - Maintenance as used herein, unless otherwise noted, encompasses inspection,
assessment, maintenance, repair and replacement activities.
' A term followed by the supercript "(IMS) denotes a term which has a special, unique definition in this
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
Maintenance Coordination Committee - A committee responsible for recommending to the ISO
modifications to and implementation of the ISO Maintenance Standards. The committee shall be
organized and operate in accordance with Section 7.0 of this document.
Outage(Ims) - Any interruption of the flow of power in a Transmission Line Circuit between any
terminals under ISO Operational Control.
PTO - A Participating Transmission Owner as defined in Appendix D of the Transmission
Control Agreement.
PTO Maintenance Practices - A description of methods used by a PTO for the Maintenance of
each substantial type of Transmission Facility or component in its system which is under the
Operational Control of the ISO. The PTO Maintenance Practices are to be prepared in
accordance with the ISO Maintenance Guidelines.
Scheduled Outage - The removal from service of a Transmission Facility under ISO Operational
Control to perform work on specific components in accordance with the requirements of the
Transmission Control Agreement.
Section 348 Criteria - The criteria for maintenance standards established by Section 348 of the
California Public Utilities Code, as in effect from time to time, to "provide for high quality, safe
and reliable service", taking into consideration "cost, local geography and weather, applicable
codes, national electric industry practices, sound engineering judgment, and experience".
Appendix.
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TRANSMISSION CONTROL AGREEMENT
APPENDIX C
Stations - Facilities under the Operational Control of the ISO for purposes such as line
termination, voltage transformation, voltage conversion, stabilization, or switching.
Transmission Facilities - All equipment and components transferred to the ISO for Operational
Control, pursuant to the Transmission Control Agreement, such as overhead and underground
transmission lines, Stations, and system protection equipment.
Transmission Line Circuit - The continuous set of transmission conductors located primarily
outside of a Station, and apparatus terminating at interrupting devices which would be isolated
from the transmission system following a fault on such equipment.
Voltage Class - The voltage to which operating, performance, and maintenance characteristics
are referenced. Voltage Classes are defined as follows:
Voltage Class
69 kV
115 kV
230 kV
345 kV
500 kV
HVDC
2. INTRODUCTION
Range of Nominal Voltage
5 70 kV
110 - 161 kV
200 - 230 kV
280 - 345 kV
500 kV
HVDC
These standards were prepared by the ISO through a lengthy consensus building effort involving
a diverse group of stakeholders (i.e., the ISO Maintenance Standards task force).
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TRANSMISSION CONTROL AGREEMENT
APPENDIX C
2.1. Objective
The Maintenance of Transmission Facilities has several objectives:
• Ensuring that the safety and Availability performance levels inherent to the Transmission
Facilities are achieved,
• Restoring the safety and Availability to the levels inherent to the Transmission Facilities
when degradation has occurred,
• Gathering information that can be of use as the basis for identifying improvements to those
Transmission Facilities whose Availability performance is inadequate,
• Gathering information that can be used as the basis for optimizing and forecasting
Maintenance for Transmission Facilities,
• Extending the useful life of the Transmission Facilities while maintaining their inherent
levels of Availability, and
• Achieving the aforementioned objectives at a minimum total cost for Maintenance and
Outages.
The ISO Maintenance Standards address the following topics:
• Transmission Facilities Covered by the ISO Maintenance Standards;
• Availability Measures ;
• Availability Measure Targets;
• ISO Maintenance Guidelines for PTO Maintenance practices;
• Qualifications of Maintenance Personnel;
• Maintenance Record Keeping and Reporting;
• Establishment of a Maintenance Coordination Committee;
• Process for the Revision of the ISO Maintenance Standards;
• Incentives and Penalties for PTO Availability Performance;
• Compliance with Laws and Regulations; and
• Dispute Resolution.
For certain aspects of Maintenance, these Standards delineate specific requirements and
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TRANSMISSION CONTROL AGREEMENT
APPENDIX C
responsibilities (e.g., requirements for PTO inspection and Maintenance records), for others they
provide guidelines (e.g., contents of PTO Maintenance Practices documents), and for others they
describe processes (e.g., review process for PTO Maintenance Practices documents) to be enacted
to achieve the desired results.
Flexibility in establishing ISO Maintenance Standards is implicit in the goal of optimizing
Maintenance across a system characterized by diverse environmental and climatic conditions,
terrain, equipment, and design practices. To provide for flexibility while ensuring the
reasonableness of each PTO's approach to Maintenance, the ISO Maintenance Standards are
founded on two basic precepts: 1) the effectiveness of each PTO's Maintenance will be gauged
through an Availability performance monitoring system, and 2) the adequacy of each PTO's
Maintenance Practices will be assessed through ISO review. Each PTO's Maintenance Practices
will serve as the ISO's Maintenance Standards for the Transmission Facilities covered therein.
The PTO Maintenance Practices ensure a reasonable level of Maintenance during the short term
while Availability is used to monitor long term performance.
It is the belief of the ISO Maintenance Standards task force that it is impractical for the ISO to
develop and/or impose on .the PTO's a single uniform set of detailed descriptions of practices
delineating condition or time -based schedules for various Maintenance activities that account for
the myriad equipment, operating conditions, and environmental conditions within the ISO grid.
For this reason, the ISO Maintenance Standards provide ISO Maintenance Guidelines to be
followed by each PTO in preparing PTO Maintenance Practices for its Transmission Facilities.
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TRANSMISSION CONTROL AGREEMENT
APPENDIX C
2.2. Availability
ISO grid reliability is a function of the Availability of Transmission Facilities owned and
operated by its PTO's. The key to the effectiveness of the ISO Maintenance Standards is the
establishment of a consistent measure of Transmission Facility Availability (Availability
Measures) and the initial setting of the Availability Measure Targets as well as periodic revisions
of those targets. By measuring Availability the ISO is able to monitor the effectiveness of
Maintenance. While the ISO is concerned with grid reliability, reliability is a function of a
complex set of variables including the accessibility of alternative load paths, speed and
sophistication of protective equipment, and the Availability of Transmission Line Circuits, and
therefore is indirectly related to Maintenance. Thus, Availability will be the principal determinant
of each PTO's performance under the ISO Maintenance Standards.
When using Availability as a gauge of Maintenance adequacy, several things must be kept in
mind to avoid misinterpreting performance. The most important consideration is that across the
ISO grid, the vast majority of all Forced Outages(IMS) are due to random/chance events that cannot
be controlled by Maintenance. It is important to recognize that only a small percentage of all
Forced Outages(IMS) can be controlled through Maintenance (i.e. activities that do not change the
basic configuration of Transmission Facilities). This principle assumes the PTO is performing a
reasonable level of Maintenance consistent with Good Utility Practice. If an unreasonably low
level of Maintenance is performed for a sufficient period of time, Availability will decline.
However, if a level of Maintenance is being performed, consistent with Good Utility Practice,
increasing Maintenance activities by a significant order will not result in a corresponding
increase in Availability. Thus, while Maintenance is important to ensuring Availability, drastic
increases in Maintenance will not lead to substantial improvements in Transmission Facility
Availability and associated grid reliability.
A variety of techniques can be used to monitor performance, however techniques that do not
account for random variations in processes have severe limitations in that they may yield
inconsistent and/or erroneous assessments of performance. To account for random/chance
C-5
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
variations while enabling monitoring for shifts and trends in performance, control charts have
been widely accepted as an effective means for monitoring performance. Control charts are
statistically -based graphs which illustrate both an expected range of performance for a particular
process based on historical data, and discrete measures of recent performance. The relative
positions of these discrete measures of recent performance and their relationship to the expected
range of performance are used to gauge the adequacy of performance. Availability is affected by
several factors only one of which is Maintenance. In fact, for most Transmission Line Circuits
only a small fraction of Forced Outages(IMs) can be attributed to phenomenon that could be
controlled or avoided through Maintenance. Many more Forced Outages(MIS) are attributable to
random/chance events than Maintenance -related items. Therefore, while monitoring Availability
as a gauge of Maintenance adequacy is useful for evaluating long term trends, care must be taken
to avoid reading too much into the correlation of Availability to Maintenance since so many
additional variables also impact Availability.
The fundamental performance measures selected as the basis for developing an Availability
performance monitoring system are the annual accumulated duration and frequency of certain
types of Outages for each Transmission Line Circuit under the ISO's Operational Control. To
enhance the Availability performance monitoring system's use as a gauge of Maintenance
adequacy, it was necessary to exclude certain Outage(IMs) types from the determination of the
performance measures. Those excluded Outages are:
• Scheduled Outages;
• Outages caused by events originating outside the PTO's system; and
• Outages demonstrated to have been caused by earthquakes.
Additionally, the Forced Outage(ms) duration has been capped at 72 hours so that excessively
long Forced Outages"), do not skew the data as to detract from the meaningfulness and
interpretation of the control charts for accumulated Forced Outage(ms) duration. This is not to
say that an excessively long Forced Outage(ms) is not a concern. Rather, such Forced
Outages(M) should be investigated to assess the reasons for their extended duration.
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TRANSMISSION CONTROL AGREEMENT
APPENDIX C
The performance monitoring system requires use of separate control charts for each Voltage
Class and PTO. Existing Forced Outage(ms) data contains significant differences in the
Availability performance between Voltage Classes and between PTOs. These differences may be
attributable to factors such as the uniqueness of operating environments, Transmission Facility
designs, and PTO operating policies. However, regardless of the cause of the differences, review
of the Forced Outage(ms) data makes it eminently apparent that the performance differences are
such that no single set of control chart parameters for a particular Voltage Class could be applied
to all PTOs.
Three types of control charts will be constructed to provide a complete representation of
historical Availability performance, and to provide a benchmark against which future
performance can be gauged. The three types of control charts for each PTO and Voltage Class
are:
• The annual average Forced Outage(ms) frequency for all Transmission Line Circuits;
• The annual average accumulated Forced Outage(ms) duration for those Transmission Line
Circuits which experience Forced Outages(MS); and
• The annual proportion of Transmission Line Circuits that experienced no Forced
Outages(IMs)
These three control charts will assist the ISO and PTO's in assessing the performance of Voltage
Classes over time. To accommodate this process on a cumulative basis data are made available
to the ISO by each PTO at the beginning of a new year to assess the performance of the past
years.
2.3. ISO Maintenance Guidelines
Two specific requirements regarding Maintenance documentation have been incorporated into
the ISO Maintenance Standards. First, these standards require that each PTO develop and submit
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TRANSMISSION CONTROL AGREEMENT
APPENDIX C
a description of its Maintenance practices (PTO Maintenance Practices) to the ISO. Second,
these standards require that each PTO maintain Maintenance records and make those records
available to the ISO in order to demonstrate compliance with each element of its PTO
Maintenance Practices.
To outline the fundamental requirements for, and to promote consistency in the PTO
Maintenance Practices, these standards provide guidelines for the preparation and maintenance of
the PTO Maintenance Practices. These ISO Maintenance Guidelines provide for flexibility in
approach to Maintenance, but also require the description of certain specific Maintenance
practices. The guidelines require that the PTO's provide descriptions of the various Maintenance
activities, schedules and condition triggers for performing the Maintenance, and samples of any
checklists, forms, or reports used for Maintenance activities.
2.4. Data Standards
To facilitate processing of Outage'NS) data for the Availability performance monitoring system,
and to enable consistent and equitable interpretation of PTO Maintenance records by the ISO,
these standards address the need for data recording and reporting. The ISO and PTO's have
committed to developing standardized formats for transmitting Outage(IMs) data to the ISO for the
Availability performance monitoring system. These standard formats are to be finalized within
the first 60 days of 1998. Additionally, the ISO and PTO's have agreed to develop and
implement a standard Maintenance reporting system by the end of the third year of operation of
the ISO. This system will provide for consistent gathering of information that can be used as the
basis for optimizing and forecasting maintenance of Transmission Facilities. The development
of such a Maintenance reporting system is consistent with fostering the spirit of cooperation
among the ISO and the PTO's as it may eventually aid in the resolution of performance
problems, and provide the basis for research on an ISO grid -wide basis to identify opportunities
to enhance Transmission Facility Maintenance.
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TRANSMISSION CONTROL AGREEMENT
APPENDIX C
2.5. Applicability of Incentives and Penalties
Cooperation and collaboration among the PTOs responsible for ensuring the Availability of the
Transmission Facilities comprising the ISO grid are needed to ensure the most reliable grid
possible. Therefore, the ISO Maintenance Standards task force believes that a formal program of
incentives and penalties tied purely to PTO Maintenance may hinder needed cooperation among
PTOs. As a result, the ISO Maintenance Standards task force recommends that no such program
be instituted initially by the ISO.
Further, the task force recognizes the need for the ISO to enforce reasonable Maintenance to
ensure Availability in the case that: 1) a PTO exhibits degradation in Availability performance
due to Maintenance, 2) a PTO does not comply with its PTO Maintenance Practices, or 3) a PTO
is grossly or willfully negligent with regards to Maintenance. Therefore, it is the position of the
ISO Maintenance Standards task force that it is reasonable for the ISO to establish penalties for
such conditions. In the absence of a formal program of incentives and penalties, the task force
acknowledges the ISO's right to pursue sanctions for cause on a case by case basis.
Availability is a useful and tractable means for monitoring performance, however, the electric
utility industry as a whole has little experience in using Availability to gauge the adequacy of
Maintenance. Further, because the industry in general has not carefully managed historical
Outage(ms) data to the degree that is necessary to make them useful for performance monitoring,
there are varying limitations with regards to the accessibility and reliability of Outagel ''s) data
among PTOs. Also, the impact on Availability when a new entity, namely the ISO, assumes
Operational Control of the grid is unknown. Thus, it is the position of the ISO Maintenance
Standards task force that the Availability performance monitoring system will be implemented
and used to gauge Availability performance beginning on the ISO Operations Date. However,
the system needs to be used and updated during a five year phase in period to be considered for
use in a program of incentives and penalties for Availability performance.
Availability is a function of several variables including Transmission Facility Maintenance,
C-9
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
capital improvements, and improvements in restoration practices. If a PTO is exercising a
reasonable level of Maintenance, yet the Availability performance of a Voltage Class or
individual Transmission Line Circuit is inadequate for the purposes of the ISO grid, then capital
improvements or improvements in restoration practices may lead to greater Availability
improvements than increased Maintenance. Therefore, assessing incentives and penalties on the
basis of Availability as influenced by all of these variables may be a reasonable approach for
influencing PTO's to improve the Availability of their Transmission Facilities where such
improvements can be justified.
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TRANSMISSION CONTROL AGREEMENT
APPENDIX C
3. TRANSMISSION FACILITIES COVERED BY THE ISO MAINTENANCE
STANDARDS
All Transmission Facilities transferred to the ISO, pursuant to the Transmission Control
Agreement, shall be maintained in accordance with the ISO Maintenance Standards.
4. AVAILABILITY STANDARD
4.1. Introduction
The ISO shall monitor and measure each PTO's Availability for the Transmission Line Circuits
under ISO Operational Control. The ISO shall use an Availability measurement system which
consists of two primary components: 1) measures of the annual performance of each Voltage
Class based on the performance of each of the Transmission Line Circuits comprising the
Voltage Class, i.e. the Availability Measures; and 2) a set of threshold performance criteria for
each Voltage Class, i.e. Availability Measure Targets. The Availability Measure Targets will be
used to gauge the adequacy of the PTO's annual performance for each Voltage Class. Each PTO
shall make an annual report to the ISO within 90 days from the end of each calendar year that
describes its compliance with the Availability Measure Targets. In its report to the ISO,
supporting data based on Outage(HAS) records shall be included, justifying the Availability
Measures reported for each Voltage Class.
4.2. Availability Measures
4.2.1. Calculation of Availability Measures for Individual Transmission Line
Circuits
The calculation of the Availability Measures will be performed utilizing Outage('" data through
December 31 of each year. Separate Forced Outage(ms) frequency and accumulated Forced
Outage'ms) duration Availability Measures shall be calculated as follows for each Transmission
Line Circuit under ISO Operational Control within each Voltage Class. The calculations shall be
performed annually for each of the Transmission Line Circuits utilizing all appropriate Outage
C-11
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
data for the calendar year in question.
Forced Outage(ms) Freguenc
The Forced Outage(ms) frequency (fk) of the ith Transmission Line Circuit shall equal the total
number of Forced Outages(MS) that occurred on the it" Transmission Line Circuit during the
calendar year k. See Notes 1 and 2.
NOTES:
1. Multiple momentary Forced Outages(IMS) on the same Transmission Line Circuit in the span of a single
minute shall be treated as a single Forced Outage(IMS) with a duration of one minute. When the
operation of a Transmission Line Circuit is restored following a Forced Outage(IMS) and the
Transmission Line Circuit remains operational for a period exceeding one minute, i.e. 61 seconds or
more, followed by another Forced Outage(lms) , then these should be counted as two Forced
Outages('ms)Multiple Forced Outages(lms) occurring as a result of a single event should be handled as
multiple Forced Outages(IMS) only if subsequent operation of the Transmission Line Circuit between
events exceeds one minute. Otherwise they shall be considered one continuous Forced Outage(IMS)
2. If a Transmission Line Circuit, e.g. a new Transmission Line Circuit, is only in service for a portion of a
year, the Forced Outage(lms) frequency and accumulated duration data shall be treated as if the
Transmission Line Circuit had been in service for the entire year, i.e. the Outage('ms) data for that
Transmission Line Circuit shall be handled the same as those for any other Transmission Line Circuit.
Accumulated Forced Outage(lms) Duration:
The accumulated Forced Outage(lms) duration in minutes shall be calculated as follows
for each of the Transmission Line Circuits having a Forced Outage(IMS) frequency (ik)
greater than zero for the calendar year k:
fik
d ik = 1 Oi,k
J=1
where
dik = accumulated duration of Forced Outages(lms) (total number of Forced
Outage(IMS) minutes) for the ith Transmission Line Circuit having a Forced
Outage(Ims) frequency (fk) greater than zero for the calendar year k.
Jlk = Forced Outage(lms) frequency as defined above for calendar year k.
Oi k = duration in minutes of the jth Forced Outage(IMS) which occurred during
the kt" calendar year for the ith Transmission Line Circuit. See Notes1
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TRANSMISSION CONTROL AGREEMENT
APPENDIX C
and 2.
The durations of extended Forced Outages(IMS) shall be capped as described in Section
4.2.2. "Capping of Forced Outage('Ms) Duration" for the purposes of calculating the
Availability Measures . In addition, certain types of events/Outages shall be excluded
from the calculations of the Availability Measures as described in Section 4.2.3
"Excluded Events".
If a PTO makes changes to its Transmission Line Circuit identification, configuration, or
Outage(lms) data reporting schemes, the PTO shall notify the ISO at the time of the
change. In its annual report to the ISO the PTO shall provide recommendations
regarding how the Availability Measures and Availability Measure Targets should be
modified to ensure they remain consistent with the modified Transmission Line Circuit
identification or Outage(lms) data reporting scheme, and that they provide an appropriate
gauge of performance.
4.2.2. Capping of Forced Outage('Ms) Durations
The durations of individual Forced Outages(IMs) which exceed 72 hours (4320 minutes)
shall each be capped at 4320 minutes for the purpose of calculating the accumulated
Forced Outage("Ms) duration.
4.2.3. Excluded Events
The following types of events/Outages shall be excluded from the calculation of the
Availability Measures and the Availability Measure Targets:
• Scheduled Outages which are scheduled, reviewed and approved by the ISO in
accordance with the Transmission Control Agreement, and
• Forced Outa es(IMs) which: 1) were caused by events outside the PTO's system
including those Outages which originate in other TO systems, other electric utility
C-13
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
systems, or customer equipment, and 2) those Forced Outages(IMS) which can be
demonstrated to have been caused by earthquakes.
4.3. Targets for Availability Performance
The Availability Measure Targets described herein shall be phased in over a period of
five years beginning on the ISO Operations Date. The adequacy of each PTO's
Availability performance shall. be monitored through the use of charts on which are
plotted indices reflecting annual Availability performance. These charts, called control
charts as shown in Figure 4.3.1, are defined by a horizontal axis with a scale of years
and a vertical axis with a scale describing the expected range of magnitudes of the
index in question. Annual performance indices shall be plotted on these charts and a
series of tests may then be performed to assess the stability of annual performance,
shifts in performance and longer term performance trends.
Control charts for each of the following indices shall be developed and utilized to
monitor Availability performance for each Voltage Class within each PTO's system:
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APPENDIX C
Annual performance Index
--------------
98 99 00 01 02 03 04 05 06 07
Year
UCL
UWL
CL
LWL
LCL
Figure 4.3.1 Sample Control Chart
• Index 1: Annual Average Forced Outage(l""s) Frequency for All Transmission
Line Circuits.
• Index 2: Annual Average Accumulated Forced Outage(l""s) Duration for those
Transmission Line Circuits with Forced Outages(I""s)
• Index 3: Annual Proportion of Transmission Line Circuits with No Forced
Outages(I""s)
The control charts incorporate a center line (CL), upper and lower control limits (UCL
and LCL, respectively), and upper and lower warning limits (UWL and LWL,
respectively). The CL represents the average annual historical performance for a
period prior to the current year. The UCL and LCL define a range of expected
performance extending above and below the CL. For the annual proportion of
Transmission Line Circuits with no Forced Outages(""s), the limits are based on
standard control chart techniques for binomial proportion data. For the other two
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APPENDIX C
indices, bootstrap resampling techniques are used to determine empirical UCL and LCL
at 99.75% and 0.25% percentile values, respectively, for means from the historical
data. The bootstrap procedure is described in Section 4.3.2. Similarly, the UWL and
LWL define a range of performance intending to cover the percentiles from 2.5% to
97.5%. The bootstrap algorithm is also used to determine these values. Thus, the UCL
and LCL will contain about 99.5% of resampling means from the Voltage Class of
interest. UWL and LWL will contain about 95% of the resampling means. These limits
coincide with the usual choices for control charts when the means are approximately
normal. Bootstrap estimation procedures are used here since the sampling means do
not follow the Normal distribution model. The bootstrap estimation procedures ensure
consistent control chart limits by using a starting base number("seed") for it's random
number generator. Accuracy or reduced variances in the control chart limits are
attained by using the average control chart limits generated from applying ten
repetitions or cycles of the bootstrap sampling method. Collectively, the CL, UCL, LCL,
UWL and LWL provide reference values for use in evaluating performance as
described in Section 4.3.3.
For the special case where there is a Voltage Class with only one Transmission Line
Circuit, individual and moving range control charts should be used for Index 1 and 2.
The method used herein for calculating Index 3 is not applicable for those Voltage
Classes containing less than six Transmission Line Circuits. Maintenance procedures
recommended by the MCC and approved by the ISO Governing Board will be used by
the PTOs to calculate Index 1, 2, or 3 where the methods provided herein do not
apply.More information on the individual and moving range control charts can be found
in the user manuals of the statistical software recommended by the MCC and approved
by the ISO Governing Board for use in creating the control charts .
4.3.1. Calculations of Annual Availability Performance Indices for
Individual Voltage Classes
Separate annual Availability performance indices shall be calculated for each Voltage
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APPENDIX C
Class and PTO as described below utilizing the Availability Measures discussed in
Section 4.2,
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APPENDIX C
Annual Average Forced Outage(lms) Frequency for All Transmission Line Circuits (Index 1):
1 Nk
Fv c , k = N E .f ik
k e=1
where
Fvc,k = frequency index for the Voltage Class, vc, (units = Forced Outages(IMS)
/Transmission. Line Circuit). The frequency index equals the average (mean)
number of Forced Outages(lms) for all Transmission Line Circuits within a
Voltage Class for the calendar year k.
Nk number of Transmission Line Circuits in Voltage Class in calendar year k.
See Note 2, Section 4.2.1.
fk = frequency of Forced Outages('ms) for the ith Transmission Line Circuit as
calculated in accordance with Section 4.2.1 for calendar year k.
Averaae Accumulated Forced Outaae(lms) Duration for those T
1 Na,k
Dvc,k = N dik
o,k i=1
where
Dvc,k = duration index for the Voltage Class (units = minutes/Transmission Line
Circuit). The duration index equals the average accumulated duration of
Forced Outages(lms) for all Transmission Line Circuits within a Voltage Class
which experienced Forced Outages(lms) during the calendar year k.
No,k = number of Transmission Line Circuits in the Voltage Class for which the
Forced Outagg(lms) frequency Availability Measure (ik) as calculated in
accordance with Section 4.2.1 is greater than zero for the calendar year k.
See Note 2, Section 4.2.1.
dik = accumulated duration of Forced Outages("Ms) for the ith Transmission Line
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APPENDIX C
Circuit having a Forced Outage(lms) frequency Availability Measure (tk)
greater than zero for calendar year k as calculated in accordance with
Section 4.2.1.
Annual Proportion of Transmission Line Circuits with No Forced Outages(f) (Index 3):
Nk — Nv,k
Plc,k = N
k
where
P,c,k = index for the proportion of Transmission Line Circuits for the Voltage Class
with no Forced Outages(lms) for the calendar year k.
Nk = number of Transmission Line Circuits in Voltage Class for calendar year k.
See Note 2, Section 4.2.1.
No,k = number of Transmission Line Circuits in the Voltage Class for which the
Forced Outage(lms) frequency Availability Measure (ik) as calculated in
accordance with Section 4.2.1 is greater than zero for the calendar year k.
See Note 2, Section 4.2.1.
4.3.2. Development of Limits for Performance Control Charts
The CL, UCL, LCL, UWL and LWL for the three control charts (Annual Average Forced
Outage(lms) Frequency for All Transmission Line Circuits, Annual Average Accumulated
Forced Outage(lms) Duration for Transmission Line Circuits with Forced Outages(Ims),
and Annual Proportion of Transmission Line Circuits with No Forced Outages(lms)) on
which the annual Availability performance indices are to be plotted shall be calculated
as described below. The CL, UCL, LCL, UWL and LWL for each of the three control
charts shall be determined using continuously recorded Outage(ms) data for the ten year
period immediately preceding the ISO Operations Date, or immediately preceding the
date a TO becomes a PTO. In the event that a PTO does not have reliable,
continuously recorded Outage("Ms) data for this 10 year period, the PTO may determine
the control chart limits using data for a shorter period. However, if data for a shorter
period are to be used, the PTO shall prepare a brief report to the ISO providing
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APPENDIX C
reasonable justification for this modification. This report shall be submitted -to the ISO
prior to February 1, 1998, or within 30 days after a TO becomes a PTO. The ISO shall
periodically review the control chart limits and appropriately modify them when
necessary in accordance with Section 8.0, "Revision of ISO Maintenance Standards," of
this document.
4.3.2.1. CLs
The calculation of the CLs for each of the three control charts is similar to the
calculation of the annual Availability performance indices described in Section 4.3.1
except that the period for which data are to be included in the calculations is expanded
from a single calendar year to the ten years, unless a shorter period is justified by the
PTO, for the period immediately preceding the ISO Operations Date, or immediately
preceding the date a TO becomes a PTO. To account for this change a count of
Transmission Line Circuit years is included in the equations as shown below to enable
derivation of CLs which represent average performance during a multi -year period.
CL for Annual Transmission Line Circuit Forced Outage(lms) Frequency
Y Nk Y
CLf,C- YEf,k/(ENk)
k=1 i=1 k=1
where
C41C = center control line value for the Forced Outage(lMs) frequencies for each of
the Transmission Line Circuits in the Voltage Class for Y years prior to the
ISO Operations Date, or the date a TO becomes a PTO.
Y = number of years prior to the ISO Operations Date (or the date a TO becomes
a PTO) for which the PTO has reliable, continuously recorded Outage(IMs)
data. Y=10 is preferred.
CL for Annual Accumulated Forced utaae(lms) Duration for those Transmission Line
Circuits with Forced Outages
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APPENDIX C
where
CLd„, =
Y Nok Y
CLd, = j 1 d. / (Y No,k )
k=1 i=1 k=1
center control line value for accumulated Forced Outage('ms) duration for
each of the Transmission Line Circuits in the Voltage Class for Y years prior
to the ISO Operations Date (or the date a TO becomes a PTO) in which the
Forced Outage(IMS) frequency (f k) was greater than zero.
CL for Annual Proportion of Transmission Line Circuits with No Forced Outages(IMS)
Y
Y(Nk —Nok)
CLP,,C — k=1Y
E Nk
k=1
where
CLP,,, = center control line value for the proportion of Transmission Line Circuits in the
Voltage Class with no Forced Outages(lms) for Y years prior to the ISO
Operations Date, or the date a TO becomes a PTO.
4.3.2.2. UCLs, LCLs, UWLs and LWLs
UCLs, LCLs, UWLs and LWLs for Index 1 and 2 for Voltaae Classes Containin
Four or More Transmission Line Circuits with Forced Outages""I for Five or More
Years
The UCLs , UWLs, LWLs, and LCLs for the control charts for each Voltage Class
containing four or more Transmission Line Circuits with Forced Outages(IMS) shall be
determined by bootstrap resampling methods as follows: The available historical data
for Index 1 and 2 will each be entered into columns. A "seed" is then selected prior to
beginning the sampling process. The ISO assigns a number for the "seed" prior to
each years development of the control charts. The "seed" allows the user to start the
sampling in the same place and get the same results provided the data order hasn't
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APPENDIX C
changed. For Index 1, sampling with replacement will occur for the median number of
lines per year in a Voltage Class for the time period being evaluated. A sample, the
size of which is the median number of all Transmission Line Circuits for the period
being evaluated, is taken from the column of actual frequency values for all
Transmission Line Circuits. A mean is calculated from this sample and the resulting
number will be stored in a separate column. This process, will be repeated 10,000
times in order to create a column of sampling means from the historical data base. The
column of sampling means is then ordered from the smallest to largest means. From
this column percentiles are determined for a UCL( 99.75), a LCL( 0.25) a UWL(97.5),
and a LWL(2.5). Thus, for one cycle, the limits are determined by resampling from the
historical data base, calculating statistics of interest, in this case means, and then
estimating appropriate limits from the resampling means. Ten cycles of this same
process are necessary to get 10 values each of UCLs, LCLs, UWLs, and LWLs. The
average for the ten values of each limit is taken to provide the UCL, LCL, UWL, and
LWL values used in analyzing annual performance. The procedure is repeated for
Index 2 forming means for the median number of lines with Forced Outages(""S) in this
Voltage Class for the time period being evaluated. See Bootstrapping - A
Nonparametric Approach to Statistical Inference (1993) by Christopher Z. Mooney
and. Robert D. Duval, Sage Publications with ISBN 0-8039-5381-X, and An
Introduction to the Bootstrap (1993) by Bradley Efron and Robert J. Tibshirani,
Chapman and Hall Publishing with ISBN 0-412-04231-2 for further information.
Consider an example to illustrate how the Bootstrap procedure works for one cycle of
the ten required. Assume that a Voltage Class has approximately 20 Transmission
Line Circuits per year with a history of ten years. Furthermore, assume that about 15
Transmission Line Circuits per year experience Forced Outages. Therefore, there are
10 x 15 = 150 Forced Outage(lms) durations available for bootstrap sampling. Place
these 150 Forced Outage(lms) durations in a column, say "outdur'... in a specified order
. The order is automatically provided in the bootstrap algorithm developed by the ISO
and made available to the PTO. The bootstrap algorithm will sample 15 rows from
"outdur" with replacement. That is, any row may, by chance, be sampled more than
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APPENDIX C
once. From these 15 values determine the sample mean and place this in another
column, say "boot". Repeat this sampling process 10,000 times adding the new means
to "boot". The column "boot" now has 10,000 means from samples of size 15 from the
original Forced Outage(lms) duration data for this Voltage Class. The next step is to
locate the appropriate percentiles from these means for use in determining the control
chart limits for one cycle. This is accomplished by ordering the column "boot" from
smallest to largest mean and restoring these ordered means in "boot". The percentiles
which are needed are 99.75% (UCL), 97.50% (UWL), 2.50% (LWL) and 0.25% (LCL).
These are easily estimated from the sorted means by finding the associated rows in the
column "boot". For example, LWL will be estimated as the average of the 250th and
251 st rows in column "boot". Likewise the other limits will be determined. Of course,
the CL is the actual mean average for 15 lines over the ten years using the formulas in
Section 4.3.2.1. This example is for one cycle. Nine more cycles of this process will
establish the more accurate control and warning limits necessary to evaluate a PTO's
annual performance.
UCLs, LCLs, UWLs and LWLs for Index 1 and 2 for All Other Voltage Classes
When data for less than four Transmission Line Circuits with Forced Outages(IMS) are
available per year in a Voltage Class for fewer than five years, an exhaustive
enumeration of all possible selections with replacement may need to be performed.
This is because the number of possible samples for bootstrap resampling will be less
than the aforementioned 10,000 resampling frequency used for Voltage Classes
containing four or more Transmission Line Circuits with Forced Outages(lms) for five or
more years. For example, if a Voltage Class has only two Transmission Line Circuits
per year for five years, the data base will consist of 2*5 = 10 accumulated Forced
Outage(lms) durations assuming both Transmission Line Circuits experience a Forced
Outage(IMS) or more per year. Resampling two values from the column of 10 yields only
10**2 = 100 possible means. Thus, bootstrap resampling of 10,000 would over -sample
the original data 10,000/100 = 100 times.
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APPENDIX C
For the general case, let M = the number of accumulated Forced Outage('Ms) durations
(or Forced Outage(lms) frequencies) from the historical data base. If n is the median
number of Transmission Line Circuits per year, there are M""n = U possible
enumerated means for this Voltage Class. The procedure to determine the appropriate
limits for a Voltage Class is to order the column containing U enumerated means from
smallest to largest means. Then, the UCL, LCL, UWL, and LWL are determined from
this vector as described above (i.e. at the 99.75, 0.25, 97. 5 and 2. 5 percentiles,
respectively).
UCLs, LCLs, UWLs and LWLs for Index 3 When Number of Lines is > 125
According to standard procedures for proportion control charts for voltage classes
where. the median number of lines in service is greater than 125 for any given year, the
upper and lower control chart limits (UCL, LCL, UWL, and LWL) for the a year are
determined using the normal approximation to the binomial distribution. The formulas
are:
UCL = CLP, + 3SP,k LCL = CLP, - 3SPvc,k
UWL and LWL are calculated by replacing the "3" above with a "2".
and
S Pvc,k = VCL, (1 — CLP,c) / N k
where
SPvc,k = standard deviation for the annual proportion of Transmission Line Circuits in
the Voltage Class with no Forced Outages(lms) for each (0) year of the Y
years prior to the ISO Operations Date, or the date a TO becomes a PTO. If
LCL or LWL is less than zero, they should be set to zero by default.
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APPENDIX C
UCLs, LCLs, UWLs and LWLs for Index 3 when Number of Lines is less than or
equal to 125 and greater than or equal to six.
The UCLs, LCLs, UWLs, and LWLs for the control charts for each voltage class shall
be based on exact binomial probabilities for those voltage classes having equal to or
more than six but less than or equal to 125 median transmission lines per year.
A customized macro and a statistical software package approved by the ISO creates
the proportion control charts. The macro determines the control limits and use of the
exact binomial or the normal approximation to the binomial for computing the
control chart limits. This macro ensures the UCL and LCL contains about 99.5% and
the UWL and LWL contains about 95% of the binomial distribution. The percentile
values of the UCL, UWL, LWL, and LCL are respectively 99.75%, 97.5%, 2.5%, and
0.25%.
The UCL, UWL, LWL, and LCL are calculated using the following formulas:
UCL = (X1+ (P2 - P1)/(P3 - Pj) )/ n
UWL = (X1+ (P2 - P1)/(P3 - P1) )/ n
LWL = (X1+ (P2 - Pl)/(P3 - Pj) )/ n
LCL = (X1+ (P2 - P1)/(P3 - P1) )/ n
Where
P2 = A cumulative binomial probability equal to the 0.9975, 0.9750, 0.025, and
0.0025 values used respectively in the UCL, UWL, LWL, and LCL above
formulas(i.e. P2 = 0.9975 in the UCL formula and =0.025 in the LWL
formula)
P1 = A cumulative binomial probability that if not representing the percentile
value is representing the percentile value that is less than and closest to
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APPENDIX C
the 99.75, 97.50, 2.5, and 0.25 percentile values used respectively in the
UCL, UWL, LWL, and LCL formulas(e.g. if P, = 0.74 and is closest to the
99.75 percentile value and represents the 99 percentile then P, = 0.74
should be used in the UCL formula).
P3 = A cumulative binomial probability that if not representing the percentile
value is representing the percentile value that is greater than and closest to
the 99.75, 97.50, 2.5, and 0.25 percentile values used respectively in the
UCL, UWL, LWL, and LCL formulas(e.g. if P3 = 0.82 and is closest to the
99.75 percentile value and represents the 99.85 percentile then P3 = 0.82
should be used in the UCL formula).
X1 = The number of lines with no outages associated with the P1 cumulative
binomial probability values used respectively in the UCL, UWL, LWL, and
LCL formulas.(e.g. If P, = 0.74 and represents the 99th percentile for the
case where 78 lines didn't have any outages then Xi = 78 should be used
in the UCL formula).
n = The median number of lines that are in service in a given year. This
number remains the same in each of the UCL, UWL, LWL, and LCL
formulas
More information on the calculations of the proportion control chart limits is in the
current ISO Transmission Facility Availability Performance Monitoring System
Handbook.
4.3.3. Evaluation of Availability Performance
The control charts shall be reviewed annually in order to evaluate Availability
performance. The annual performance evaluation shall consist of an examination of
each of the control charts to determine if one or more of the following four tests indicate
a change in performance. The four tests have been selected to enable identification of
exceptional performance in an individual year, shifts in longer term performance, and
trends in longer term performance.
Tests
• Test 1: The index value for the current year falls outside the UCL or LCL.
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APPENDIX C
• Test 2: At least v1 consecutive annual index values fall above the CL or v2
consecutive annual index values fall below the CL. The actual values of v1 and v2
will be output from the bootstrap resampling procedures. The choices for v1 and v2
are designed to keep the probability of these events less than one percent.
Table 1. Values of v1 and v2 for Percentiles of the CL in Specified Ranges
Percentile
v1
v2
35 - 39
10
5
40
10
6
41 - 43
9
6
44 - 46
8
6
47-48
8
7
49 - 51
7
7
52-53
7
8
54 - 56
6
8
57 - 59
6
9
60
6
10
61 - 65
5
10
Thus, for example, if for a particular Voltage Class the percentile of the
historical CL is 55%, this says that the CL is located at the 55 percentile of all
bootstrap means in the "boot" column. From Table 1, v1=6, and v2=8.
• Test 3: At least two out of three consecutive annual index values fall outside the
UW L or LW L on the same side of the CL.
• Test 4: Six or more values are consecutively increasing or consecutively
decreasing.
Therefore, Test 1 is designed to detect a short term change or jump in the average
level. Tests 2 and 4 are looking for long term changes. Test 2 will detect a shift up in
averages or a shift to a,lower level. Test 4 is designed to detect either a trend of
continuous increase in the average values or continuous decrease. Test 3 is designed
to assess changes in performance during an intermediate period of three years. If Test
3 is satisfied, the evidence is of a decline (or increase) in Availability over a three year
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APPENDIX C
period. Together the four tests allow the ISO to monitor the availability performance of
a Voltage Class for a PTO.
If none of these tests indicates that a change has occurred, performance shall be
considered to be stable and consistent with past performance. If one or more of these
tests indicates a change then Availability performance shall be considered as having
improved or degraded relative to the performance defined by the control chart. Table
4.3.1 provides a summary of the performance indications provided by the tests. The
control chart limits may be updated annually if the last year's Availability performance
indices did not trigger any of the four tests. If none of the four tests are triggered, the
new limits will be constructed including the last year's data.
The control chart limits may be modified each year to reflect the number of
Transmission Line Circuits in service during that year if necessary. However, it is
suggested that unless the number of lines changes by more than 30% from the
previous year, the use of the median number of lines should continue. Consider an
example. Suppose after the control chart has been prepared for a Voltage Class, next
year's data arrive with the number of lines 30% higher than the median used in the
past. New limits will be generated in order to assess the Availability performance for
that year.
For the special case where only one Transmission Line Circuit has a Forced Outage(IMS)
in a Voltage Class during a year, the assessment process for Index 2 is as follows. If
Index 2 for this Transmission Line Circuit does not trigger any of the four tests, no
further action is necessary. If, however, one or more of the tests are triggered, then
limits for this Transmission Line Circuit for that year should be recalculated based on
the historical data for this Transmission Line Circuit alone using an individual and
moving range control chart. The only test warranted here is Test 1. More information
on the individual and moving range control charts can be found in the user manuals of
the statistical software approved by the ISO for use in creating the control charts
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APPENDIX C
If the ISO deems that the Availability Measure Targets should be modified, they shall be
modified in accordance with Section 8.0, "Revision of ISO Maintenance Standards," of
this document.
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
Table 4.3.1 Performance Indications Provided by Control Chart Tests
Control Chart
Tye
Test
Performance Status Indicated
by Test Results
Number
Results
Improvement
Degradation
1
value is above the UCL
✓
value is below the LCL when LCL>0
✓
Annual
Average
2
v1 or more consecutive values above the CL
✓
v2 or more consecutive values below the CL
✓
Forced
Outage(IMS)
3
2 out of 3 values above the UWL
✓
2 out of 3 values below the LWL
✓
Frequency
4
6 consecutive values increasing
✓
6 consecutive values decreasing
Annual
Average
Accumulated
Forced
Outage
1
value is above the UCL
value is below the LCL when LCL>0
✓
2
v1 or more consecutive values above the CL
v2 or more consecutive values below the CL
✓
3
2 out of 3 values above the UWL
✓
2 out of 3 values below the LWL
✓
Duration
4
6 consecutive values increasing
✓
6 consecutive values decreasing
✓
Annual
Proportion
1
value is above the UCL
✓
value is below the LCL when LCL>0
✓
Of
Transmission
.Line Circuits
with No
Forced
Outages
2
v1 or more consecutive values above the CL
✓
v2 or more consecutive values below the CL
✓
3
2 out of 3 values above the UWL
✓
2 out of 3 values below the LWL
✓
4
6 consecutively increasing values
6 consecutively decreasing values
✓
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APPENDIX C
4.4. Outage(lms) Data Reporting
All Outages which interrupt the flow of power on PTO Transmission Facilities under the
ISO's Operational Control shall be reported by the PTO to the ISO. Outage(IMS) reports
shall include the date, start time, end time, affected Transmission Facility, and the
probable cause of the Outage('ms) if known.
5. ISO MAINTENANCE GUIDELINES AND PTO MAINTENANCE PRACTICES
5.1. Introduction
The ISO with due consideration for the recommendations of the Maintenance
Coordination Committee shall establish, revise as needed, and maintain guidelines for
Transmission Facilities Maintenance as described in Section 5.2 of this document.
These ISO Maintenance Guidelines shall be followed by each PTO in preparing a
written description of, and updating as necessary, its PTO Maintenance Practices which
may be performance -based, time -based, or both, as may be appropriate for each
Transmission facility under the ISO's Operational Control. The PTO Maintenance
Practices will provide for consideration of the criteria referenced in Section 14.1 of the
TCA, including technological innovations and facility importance.
5.2. ISO Maintenance Guidelines for Preparation of PTO Maintenance
Practices
5.2.1. Transmission Line Maintenance
The PTO's Maintenance Practices shall, at a minimum, address the following
transmission line Maintenance activities:
a) Patrol/inspection
• Routine
• Detailed
• Emergency
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APPENDIX C
b) Vegetation Management/Right-of-Way. Maintenance
As may be appropriate for the specific facilities and equipment under the ISO's
Operational Control, the PTO's Maintenance Practices shall further detail Maintenance
activities for various attributes of the transmission lines including, but not limited to:
• Structures: wood pole, lattice steel, tubular steel, and concrete pole
• Guys/Anchors
• Foundations
• Insulators
• Conductor and Shield Wire
• Conductor and Shield Wire Clearances
• Hardware and Fittings
• Disconnects/Pole-top Switches
• Encroachments/Unauthorized Attachments
• Underground Transmission Components
5.2.2. Station Maintenance
The PTO's Maintenance Practices shall, at -a minimum, address the Maintenance of the
following equipment and attributes of Stations:
• Circuit Breakers
• Insulators/Bushings/Arrestors
• Transformers
• Regulator
• Disconnect Switches
• Metering
• Battery Systems
• Reactive Devices
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APPENDIX C
• Relaying
• Communication Facilities
• Station Auxiliary Equipment
• Direct Current Transmission Components
• Structures/Foundations
As may be appropriate for the specific equipment in and configurations of the PTO's
Stations under the ISO's Operational Control, the PTO's Maintenance Practices shall
further detail various Maintenance activities for the attributes and potential conditions of
the Stations including, but not limited to:
• Visual Inspection of/for: fences and grounds, vegetation, clearances, tracking,
abnormal heating, cracks/chips, noise, leaks, blown fuses, and bulging of
equipment cases
• Oil Containment
• Insulation Mediums
• Equipment Contacts
• Mechanical Timing
• Contamination Control
• Testing and Calibration
• Cooling Systems
• Measuring Devices
• Lubrication and Overhaul of Moving Parts
5.2.3. Descriptions of PTO Maintenance Practices
Each PTO's Maintenance Practices shall include a schedule for any time -based
Maintenance activities and a description of conditions that will initiate any performance -
based activities. The PTO's Maintenance Practices shall describe the Maintenance
methods for each substantial type of component and shall provide any checklists/report
forms which may be required for the activity. Where appropriate, the PTO's
■
C-33
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
Maintenance Practices shall provide criteria to be used to assess the condition of a
Transmission Facility or component. Where appropriate, the PTO's Maintenance
Practices shall specify condition assessment criteria and the requisite response to each
condition as may be appropriate for each specific type of component or feature of the
Transmission Facilities.
5.3. Review and Adoption of PTO Maintenance Practices
5.3.1. Initial Adoption of PTO Maintenance. Practices
5.3.1.1. Submittal of Information by the Prospective PTOs to the
ISO
Each prospective PTO shall provide the ISO with information concerning its PTO
Maintenance Practices pursuant to Section 5.2 of this Appendix C. This information
shall be prepared so as to be easily interpreted by the ISO and shall provide sufficient
detail to assess the adequacy and reasonableness of the PTO Maintenance Practices,
using the criteria referenced in Section 14.1 of the Transmission Control Agreement.
5.3.1.2. Review of the PTO Maintenance Practices by the ISO
The ISO shall review the information provided pursuant to Section 5.3.1.1 of this
Appendix C and may provide to a PTO a recommendation for an amendment to the
PTO Maintenance Practices in question by means of a notice delivered in accordance
with Section 26.1 of the Transmission Control Agreement. The disposition of any such
recommendation shall be in accordance with Section 5.3.3 of this Appendix C. To the
extent there are no recommendations, the PTO Maintenance Practices will be adopted
by the ISO, pursuant to California Public Utilities Code Section 348, as the PTO
Maintenance Practices for that PTO.
Any agreement, in respect of PTO Maintenance Practices, reached between the ISO
and a prospective PTO prior to the ISO Operations Date shall be adopted by the ISO
for purposes of this Section 5.3.1.
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TRANSMISSION CONTROL AGREEMENT
APPENDIX C
5.3.2. Proposals for Amendments to the PTO Maintenance Practices
5.3.2.1. Amendments Proposed by the ISO
The ISO shall periodically review each PTO's Maintenance Practices having regard to
the ISO Maintenance Standards, as amended and revised from time to time pursuant to
Sections 7 and 8 of this Appendix C. Following such a review, and after considering the
Section 348 Criteria, the ISO may recommend an amendment of PTO Maintenance
Practices, by means of a notice delivered in accordance with Section 26.1 of the
Transmission Control Agreement. The disposition of any such recommendation shall
be in accordance with 5.3.3 of this Appendix C. Except as provided in Section 5.3.3.4
of this Appendix, the effective date shall be no earlier than 30 days from the date of
such notice.
5.3.2.2. Amendments Proposed by a PTO
A PTO may provide to the ISO its own recommendation for an amendment to its PTO
Maintenance Practices, by means of a notice delivered in accordance with Section 26.1
of the Transmission Control Agreement. The disposition of any such recommendation
shall be in accordance with Section 5.3.3 of this Appendix C. The effective date shall be
no earlier than 30 days from the date of such notice.
5.3.3. Disposition of Recommendations
5.3.3.1. If the ISO or a PTO makes a recommendation to amend the PTO
Maintenance Practices of a PTO, as contemplated in Sections 5.3.1 or 5.3.2 of this
Appendix C, the other Party shall have 30 days to provide a notice to the
recommending party, pursuant to Section 26.1 of the Transmission Control Agreement,
that it does not agree with the recommended amendment. If it fails to provide such
notice of disagreement, the recommended amendment shall be deemed adopted by
the ISO, pursuant to California Public Utilities Code Section 348, as the PTO
Maintenance Practices for that PTO, effective as of the date specified in the notice of
the recommended amendment, which date shall be no earlier than 30 days from the
date of issuance of such notice of amendment.
C-35
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
5.3.3.2. If a PTO makes a recommendation to amend its PTO Maintenance
Practices, and if the ISO provides notice within the 30 days specified in the first
paragraph of this Section 5.3.3, pursuant to Section 26.1 of the Transmission Control
Agreement, that the ISO, having regard for the Section 348 Criteria, does not agree
with the recommended amendment, the PTO and the ISO shall make good faith efforts
to reach a resolution relating to the recommended amendment. If, after such efforts,
the PTO and the ISO cannot reach a resolution, the pre-existing PTO Maintenance
Practices shall be retained. Either Party may, however, seek further redress through
appropriate processes, including the Maintenance Coordination Committee, the ISO
Governing Board, and/or the dispute resolution mechanism specified in Section 15 of
the Transmission Control Agreement. Following the conclusion of the redress
processes, the PTO's Maintenance Practices, as altered, if at all, by these processes,
shall be deemed adopted by the ISO, pursuant to California Public Utilities Code
Section 348, as the PTO Maintenance Practices for that PTO.
5.3.3.3. If the ISO makes a recommendation to amend the PTO Maintenance
Practices of a PTO, the PTO Maintenance Practices, as amended pursuant to the ISO
recommendation, shall be deemed adopted by the ISO, pursuant to California Public
Utilities Code Section 348, as the PTO Maintenance Practices for that PTO, effective as
of the date specified by the ISO in its notice of recommended amendment. If the PTO
gives notice of a disagreement within the 30 days specified in the first paragraph of this
Section 5.3.3,'the PTO and the ISO shall make good faith efforts to reach a resolution
relating to the recommended amendment. If a resolution is not reached, either Party
may seek further redress through appropriate processes, including the Maintenance
Coordination Committee, the ISO Governing Board, and/or the dispute resolution
mechanism specified in Section 15 of the Transmission Control Agreement. The PTO
may also request, during the initial attempts at resolution and at any stage of the
redress processes, a deferral of the ISO recommended amendment, and the ISO shall
not unreasonably withhold its consent to such a request, having regard to the Section
348 Criteria. Following the conclusion of the redress processes, the PTO's
Maintenance Practices, as altered, if at all, by these processes, shall be deemed
C-36
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
adopted by the ISO, pursuant to California Public Utilities Code Section 348, as the
PTO Maintenance Practices for that PTO.
5.3.3.4. If the ISO determines in its judgment, after considering the Section 348 Criteria, that
prompt action is required to avoid a substantial risk to safety or reliability, it may direct a PTO to
implement certain temporary maintenance activities in a period of less than 30 days, by issuing
an advisory to the PTO to that effect, by way of a notice delivered in accordance with Section
26.1 of the Transmission Control Agreement. Any such maintenance practice advisories shall
specify why implementation solely under Section 5.3.3.3 is not sufficient to avoid a substantial
risk to safety or reliability including, where a substantial risk is not imminent or clearly
imminent, why prompt action is nevertheless required. If time permits, the ISO shall consult
with the relevant PTO before issuing a maintenance practice advisory. Upon receiving such an
advisory, a PTO shall implement the temporary maintenance activities in question, as of the date
specified by the ISO in its advisory, unless the PTO provides a notice to the ISO, in accordance
with Section 26.1 of the Transmission Control Agreement, that the PTO is unable to implement
the temporary maintenance activities as specified. Even if the PTO provides such a notice, the
PTO shall use its best efforts to implement the temporary maintenance activities as fully as
possible. All such maintenance practice advisories shall cease to have effect in 90 days after
issuance or such earlier period as the ISO provides in its notice. Renewal or extension of such
temporary maintenance requirements beyond 90 days shall require a
C-37
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
recommendation process pursuant to Section 5.3.3.2 or Section 5.3.3.3 of this Appendix.
5.3.3.5. Nothing in this Transmission Control Agreement shall be construed to limit the
ISO's authority under Public Utilities Code Section 348 to adopt inspection, maintenance, repair,
and replacement standards for the transmission facilities under ISO control.
5.4. Qualifications of Personnel
All Maintenance of Transmission Facilities under the ISO's Operational Control shall be
performed by persons who, by reason of training, experience and instruction, are
qualified to perform the task.
6. MAINTENANCE RECORD KEEPING AND REPORTING
The four elements of the ISO's requirements for Maintenance record keeping and
reporting are as follows:
a) The PTO will maintain records of its Maintenance activities, as set forth in Section
6.1.
b) The PTO will provide certain Maintenance records to the ISO, as set forth in Section
6.2.
c) The PTO will allow the ISO to visit Transmission Facilities, as set forth in Section
6.3.
d) The PTO will make records for Maintenance activities available to the ISO, as set
forth in Section 6.4.
In addition, the Maintenance Coordination Committee shall annually review the
requirements of this section of the ISO Maintenance Standards and shall seek to
standardize reasonable record keeping, reporting and information -sharing requirements
sufficient to support ISO regulatory reporting needs.
C-38
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
6.1. The PTO Will Maintain Records of its Maintenance Activities
The PTO shall maintain records demonstrating compliance with each element of the
PTO Maintenance Practices. The PTO's Maintenance records shall be maintained for
five years, or for one year after specific corrective Maintenance activities identified by
the PTO are completed, whichever is longer.
Each PTO's inspection records shall, at a minimum, identify the inspector, the
Transmission Facility inspected, the inspection date(s), the findings of the inspection,
recommended Maintenance activities, and the priority of the Maintenance
recommendations.
Each PTO's Maintenance records shall, at a minimum, identify the person responsible
for performing the Maintenance, the date of the Maintenance, the Transmission Facility
maintained, and a description of the Maintenance that was performed.
6.2. The PTO Will Provide Certain Maintenance Records to the ISO
By the end of the third year of operation of the ISO, the ISO and PTO's shall develop
and implement a standard Maintenance reporting system based on the
recommendations of the Maintenance Coordination Committee. Until the standard
Maintenance reporting system is implemented, the PTO shall provide the ISO, on an
annual basis, records for substantial Maintenance as limited by the following list:
a) Transmission Line Maintenance
• Patrol/Inspection
• Vegetation Management/Right-of-way Maintenance
• Structures: Wood pole, lattice steel, tubular steel, concrete pole
• Insulators (Contamination Control)
b) Station Maintenance
• Circuit Breakers
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
• Transformers
• Insulators/Bushings/Arrestors (Contamination Control)
• Regulators
• Relaying
If the PTO maintains records in a manner that includes additional information, such
records may be submitted in that manner.
6.3. The PTO Will Allow the ISO to Visit Transmission Facilities
The ISO may visit Transmission Facilities in accordance with Section 18.3 of the
Transmission Control Agreement.
6.4. The PTO Will Make Records for Maintenance Activities Available to
the ISO
The PTO shall make all Maintenance records for a Voltage Class available to the ISO
upon the request of the ISO if the annual evaluation of performance per Section 4.3.3
demonstrates degradation in the PTO's Availability performance. Upon identification of
degradation, the PTO's reporting of Maintenance data to the ISO shall continue until a
subsequent year's annual performance returns to a non -degraded level.
If a review of available records by the ISO indicates inconsistencies from the PTO
Maintenance Practices relating to a specific activity, then the ISO may request that the
PTO provide further documentation and explanation related to. those Maintenance
activities.
7. MAINTENANCE COORDINATION COMMITTEE
7.1. Maintenance Coordination Committee Functions
The ISO shall seek to establish and then appropriately convene a Maintenance
C-40
TRANSMISSION CONTROL AGREEMENT
APPENDIX C
Coordination Committee for the purposes of periodically conveying information, seeking
input from other PTOs and, interested stakeholders regarding ISO Maintenance
Standards as well as making recommendations with respect to proposed amendments
and revisions of the ISO Maintenance Standards.
7.2. Consensus
Although the role of the Maintenance Coordination Committee is advisory in nature, the
ISO will strive to achieve a consensus among committee members, and promulgate
practices, standards and protocols consistent with relevant laws and regulations.
8. REVISION OF ISO MAINTENANCE STANDARDS
The ISO, PTO's, or any interested stakeholder may submit proposals to amend or
revise the ISO Maintenance Standards. Any change proposal shall be submitted to the
Maintenance Coordination Committee for consideration in accordance with Section 7.0,
"Maintenance Coordination Committee," of this document. Recommendations for
revisions of the ISO Maintenance Standards shall be submitted by the Maintenance
Coordination Committee to the ISO for approval.
9. INCENTIVES AND PENALTIES
Any incentives and penalties relating to this Appendix shall be established in
accordance with the Transmission Control Agreement, the ISO Tariff and. ISO Protocols
after consultation between the PTO and the ISO, and approval by the FERC. No
incentives, penalties or sanctions may be imposed relating to this Appendix unless a
Schedule providing for such incentives, penalties or sanctions has first been filed with
and made effective by the FERC. Nothing in this Appendix shall be construed as
waiving the rights of the PTO to oppose or protest any incentive, penalty or sanction
proposed by the ISO to the FERC or the specific imposition by the ISO of any FERC-
approved penalty on the PTO.
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TRANSMISSION CONTROL AGREEMENT
APPENDIX C
10. COMPLIANCE WITH OTHER REGULATIONS/LAWS
Each PTO shall maintain its Transmission Facilities that are under the Operational
Control of the ISO in accordance with Good Utility Practice, sound engineering
judgment, the guidelines as outlined in the Transmission Control Agreement, and all
other applicable protocols, laws, and regulations, in order to achieve the Availability
Measure Targets set by the ISO.
10.1 SAFETY
It is of paramount importance that the PTO ensure the safety of personnel, and the
public in performing these Maintenance duties and that the ISO operate the system in a
manner which is compatible with the priority of ensuring safety. The PTO shall ensure
the safety of personnel and the public in accordance with jurisdictional agency
regulations and ensure the reliability of the system in accordance with CAISO
Maintenance Standards. In the event there is conflict between the safety and reliability,
the jurisdictional agency regulations for safety shall take precedence.
11. DISPUTE RESOLUTION
Any disputes between the ISO and PTO regarding issues related to the Maintenance,
and Availability of Transmission Facilities under the Operational Control of the ISO shall
be resolved in accordance with the Section 15 of the Transmission Control Agreement.
C-42
TRANSMISSION CONTROL AGREEMENT I
APPENDIX D
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
Master Definitions Supplement
D-1
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
AGC (Automatic Generation equipment that automatically responds to signals
Generation Control)
from the ISO's EMS control in real time to control the power
output of electric generators within a prescribed area in response
to a change in system frequency, tieline loading, or the relation
of these to each other, so as to maintain the target system
frequency and/or the established interchange with other areas
within the predetermined limits.
Ancillary Services Regulation, Spinning Reserve, Non -Spinning Reserve,
Replacement Reserve, Voltage Support and Black Start together
with such other interconnected operation services as the ISO
may develop in cooperation with Market Participants to support
the transmission of Energy from Generation resources to Loads
while maintaining reliable operation of the ISO Controlled Grid
in accordance with Good Utility Practice.
Applicable Reliability The reliability standards established by NERC, WSCC, and
Criteria
Local Reliability Criteria as amended from time to time,
including any requirements of the NRC.
Applicants Pacific Gas and Electric Company, San Diego Gas & Electric
Company, and Southern California Edison Company and any
others as applicable.
Approved Maintenance A Maintenance Outage which has been approved by the ISO
Outage
through the ISO Outage Coordination Office.
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
Available Transfer Capacity For a given transmission path, the capacity rating in MW of the
Black Start
Business Day
Congestion
Congestion Management
Control Area
path established consistent with ISO and WSCC transmission
capacity rating guidelines, less any reserved uses applicable to
the path.
The procedure by which a Generating Unit self -starts without an
external source of electricity thereby restoring power to the ISO
Controlled Grid following system or local area blackouts.
A day on which banks are open to conduct general banking
business in California.
A condition that occurs when there is insufficient Available
Transfer Capacity to implement all Preferred Schedules
simultaneously. "Congested" shall be construed accordingly
The alleviation of Congestion in accordance with applicable
ISO Protocols and Good Utility Practice.
An electric power system (or combination of electric power
systems) to which a common AGC scheme is applied in order
to: i) match, at all times, the power output of the Generating
Units within the electric power system(s), plus the Energy
purchased from entities outside the electric power system(s),
minus Energy sold to entities outside the electric power system,
with the Demand within the electric power systern(s); ii)
maintain scheduled interchange with other Control Areas,
within the limits of Good Utility Practice; iii) maintain the
D-2
CPUC
Critical Protective System
Day -Ahead Market
Demand
Eligible Customer
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
frequency of the electric power system(s) within reasonable
limits in accordance with Good Utility Practice; and iv) provide
sufficient generating capacity to maintain operating reserves in
accordance with Good Utility Practice.
The California Public Utilities Commission, or its
successor.
Facilities and sites with protective relay systems and Remedial
Action Schemes that the ISO determines may have a direct
impact on the ability of the ISO to maintain system security and
over which the ISO exercises Operational Control.
The forward market for Energy and Ancillary Services to be
supplied during the Settlement Periods of a particular Trading
Day that is conducted by the ISO, the PX and other Scheduling
Coordinators and which closes with the ISO's acceptance of the
Final Day -Ahead Schedule.
The rate at which Energy is delivered to Loads and Scheduling
Points by Generation, transmission or distribution facilities. It
is the product of voltage and the in -phase component of
alternating current measured in units of watts or standard
multiples thereof, e.g., 1,000W=1kW, 1,000kW=IMW, etc.
(i) any utility (including Participating TOs, Market Participants
and any power marketer), Federal power marketing agency, or
any person generating Energy for sale or resale; Energy sold or
D-3
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
produced by such entity may be Energy produced in the United
States, Canada or Mexico; however, such entity is not eligible
for transmission service that would be prohibited by Section
212(h)(2) of the Federal Power Act; and (ii) any retail customer
taking unbundled transmission service pursuant to a state retail
access program or pursuant to a voluntary offer of unbundled
retail transmission service by the Participating TO.
EMS (Energy Management A computer control system used by electric utility dispatchers to
System)
monitor the real time performance of the various elements of an
electric system and to control Generation and transmission
facilities.
Encumbrance A legal restriction or covenant binding on a Participating TO
that affects the operation of any transmission lines or associated
facilities and which the ISO needs to take into account in
exercising Operational Control over such transmission lines or
associated facilities if the Participating TO is not to risk
incurring significant liability. Encumbrances shall include
Existing Contracts and may include: (1) other legal restrictions
or covenants meeting the definition of Encumbrance and arising
under other arrangements entered into before the ISO
Operations Date, if any; and (2) legal restrictions or covenants
meeting the definition of Encumbrance and arising under a
contract or other arrangement entered into after the ISO
1
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
Operations Date.
End -Use Customer or End- A purchaser of electric power who purchases such power to
User
satisfy a Load directly connected to the ISO Controlled Grid or
to a Distribution System and who does not resell the power.
Energy
Entitlements
Existing Contracts
The electrical energy produced, flowing or supplied by
generation, transmission or distribution facilities, being the
integral with respect to time of the instantaneous power,
measured in units of watt-hours or standard multiples thereof,
e.g., 1,000 Wh=1kWh, 1,000 kWh=1MWh, etc.
The" right of a Participating TO obtained through contract or
other means to use another entity's transmission facilities for the
transmission of Energy.
The contracts which grant transmission service rights in
existence on the ISO Operations Date (including any contracts
entered into pursuant to such contracts) as may be amended in
accordance with their terms or by agreement between the parties
thereto from time to time.
Existing Rights Those transmission service rights defined in Section 2.4.4.1.1 of
the ISO Tariff.
Facilities Study Agreement An agreement between a Participating TO and either a Market
Participant, Project Sponsor, or identified principal beneficiaries
pursuant to which the Market Participants, Project Sponsor, and
identified principal beneficiaries agree to reimburse the
D-5
Facility Study
FERC
FIITC (Firm Import
Interconnection
Transmission Capacity)
Forced Outage
FPA
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
Participating TO for the cost of a Facility Study.
An engineering study conducted by a Participating TO to
determine required modifications to the Participating TO's
transmission system, including the cost and scheduled
completion date for such modifications that will be required to
provide needed services.
The Federal Energy Regulatory Commission or its successor.
The amount of firm transmission capacity in MW associated
with transmission facilities owned by a Participating TO or
contracted to the Participating TO under an Existing Contract,
which allows Generating Units that are not directly
interconnected with that Participating TO's transmission or
distribution system to deliver Energy to that Participating TO.
For each month of the Self -Sufficiency Test Period, FIITC shall
include the maximum amount of requirements and bundled
power sale capacity purchased by the Participating TO from the
transmission owner to which it is physically interconnected
during the hour in which the Monthly Peak Load of the
Participating TO occurs.
An Outage for which sufficient notice cannot be given to allow
the Outage to be factored into the Day -Ahead Market or Hour -
Ahead Market scheduling processes.
Parts II and III of the Federal Power Act, 16 U.S.C. § 824 et
�1
Generating Unit
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
seq., as they may be amended from time to time.
An individual electric generator and its associated plant and
apparatus whose electrical output is capable of being separately
identified and metered or a Physical Scheduling Plant that, in
either case, is:
(a) located within the ISO Control Area;
(b) connected to the ISO Controlled Grid, either directly or
via interconnected transmission, or distribution
facilities; and
(c) that is capable of producing and delivering net Energy
(Energy in excess of a generating station's internal
power requirements).
Generation Energy delivered from a Generating Unit.
Generator The seller of Energy or Ancillary Services produced by a
Generating Unit.
Good Utility Practice Any of the practices, methods, and acts engaged in or approved
by a significant portion of the electric utility industry during the
relevant time period, or any of the practices, methods, and acts
which, in the exercise of reasonable judgment in light of the
facts known at the time the decision was made, could have been
expected to accomplish the desired result at a reasonable cost
consistent with good business practices, reliability, safety, and
expedition. Good Utility Practice is not intended to be any one
D-7
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
of a number of the optimum practices, methods, or acts to the
exclusion of all others, but rather to be acceptable practices,
methods, or acts generally accepted in the region.
Hour -Ahead Market The forward market for Energy and Ancillary Services to be
supplied during a particular Settlement Period that is conducted
by the ISO, the PX and other Scheduling Coordinators which
opens after the ISO's acceptance of the Final Day -Ahead
Schedule for the Trading Day in which the Settlement Period
falls and closes with the ISO's acceptance of the Final Hour -
Ahead Schedule.
Hydro Spill Generation Hydro -electric Generation in existence prior to the ISO
Operations Date that: i) has no storage capacity and that, if
backed down, would spill; ii) has exceeded its storage capacity
and is spilling even though the generators are at full output, or
iii) has inadequate storage capacity to prevent loss of hydro-
electric Energy either immediately or during the forecast period,
if hydro -electric Generation is reduced; iv) has increased
regulated water output to avoid an impending spill.
Interconnection Transmission facilities, other than additions or replacements to
existing facilities that: i) connect one system to another system
where the facilities emerge from one and only one substation of
the two systems and are functionally separate from the ISO
Controlled Grid facilities such that the facilities are, or can be,
M.,
Interconnection Agreement
ISO (Independent System
Operator)
ISO ADR Procedures
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
operated and planned as a single facility; or ii) are identified as
radial transmission lines pursuant to contract; or iii) produce
Generation at a single point on the ISO Controlled Grid;
provided that such interconnection does not include facilities
that, if not owned by the Participating TO, would result in a
reduction in the ISO's Operational Control of the Participating
TO's portion of the ISO Controlled Grid.
A contract between a party requesting interconnection and the
Participating TO that owns the transmission facility with which
the requesting party wishes to interconnect.
The California Independent System Operator Corporation, a
state chartered, nonprofit corporation that controls the
transmission facilities of all Participating TOs and dispatches
certain Generating Units and Loads.
The procedures for resolution of disputes or differences set out
in Section 13 of the ISO Tariff, as amended from time to time.
ISO Code of Conduct For employees, the code of conduct for officers, employees and
substantially full-time consultants and contractors of the ISO as
set out in Exhibit A to the ISO bylaws; for Governors, the code
of conduct for governors of the ISO as set out in Exhibit B to
the ISO bylaws.
ISO Control Center The Control Center established, pursuant to Section 2.3.1.1 of
the ISO Tariff.
I1 •
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
ISO Controlled Grid The system of transmission lines and associated facilities of the
Participating TOs that have been placed under the ISO's
Operational Control.
ISO Governing Board The Board of Governors established to govern the affairs of the
ISO.
ISO Grid Operations A committee appointed by the ISO Governing Board pursuant
Committee
to Article IV, Section 4 of the ISO bylaws to advise on additions
and revisions to its rules and protocols, tariffs, reliability and
operating standards and other technical matters.
ISO Operations Date The date on which the ISO first assumes Operational Control of
the ISO Controlled Grid.
ISO Outage Coordination The office established by the ISO to coordinate Maintenance
Office
Outages in accordance with Section 2.3.3 of the ISO Tariff.
ISO Protocols The rules, protocols, procedures and standards promulgated by
the ISO (as amended from time to time) to be complied with by
the ISO Scheduling Coordinators, Participating TOs and all
other Market Participants in relation to the operation of the ISO
Controlled Grid and the participation in the markets for Energy
and Ancillary Services in accordance with the ISO Tariff.
ISO Register The register of all the transmission lines, associated facilities
and other necessary components that are at the relevant time
being subject to the ISO's Operational Control.
ISO Tariff The California Independent System Operator. Agreement and
D-10
Load
Local Furnishing Bond
Local Furnishing
Participating TO
Local Regulatory Authority
Local Reliability Criteria
Maintenance Outage
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
Tariff, dated March 31, 1997, as it may be modified from time
to time.
An end -use device of an End -Use Customer that consumes
power. Load should not be confused with Demand, which is the
measure of power that a Load receives or requires.
Tax-exempt bonds utilized to finance facilities for the local
furnishing of electric energy, as described in section 142(f) of
the Internal Revenue Code, 26 U.S.C. § 142(f).
Any Tax -Exempt Participating TO that owns facilities financed
by Local Furnishing Bonds.
The state or local governmental authority responsible for the
regulation or oversight of a utility.
Reliability criteria established at the ISO Operations Date,
unique to the transmission systems of each of the Participating
TOs.
A period of time during which an Operator takes its facilities
out of service for the purposes of carrying out routine planned
maintenance, or for the purposes of new construction work or
for work on de -energized and live transmission facilities (e.g.,
relay maintenance or insulator washing) and associated
equipment.
Market Participant An entity, including a Scheduling Coordinator, who participates
in the Energy marketplace through the buying, selling,
D-11
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
transmission, or distribution of Energy or Ancillary Services
into, out of, or through the ISO Controlled Grid.
Monthly Peak Load IThe maximum hourly Demand on a Participating TO's
transmission system for a calendar month, multiplied by the
Operating Reserve Multiplier.
Municipal Tax Exempt Debt An obligation the interest on which is excluded from gross
income for federal tax purposes pursuant to Section 103(a) of
the Internal Revenue Code of 1986 or the corresponding
provisions of prior law without regard to the identity of the
holder thereof. Municipal Tax Exempt Debt does not include
Local Furnishing Bonds.
Municipal Tax Exempt TO A Transmission Owner that has issued Municipal Tax Exempt
Debt with respect to any transmission facilities, or rights
associated therewith, that it would be required to place under
the ISO's Operational Control pursuant to the Transmission
Control Agreement if it were a Participating TO.
NERC The North American Electric Reliability Council or its
successor.
Nomogram A set of operating or scheduling rules which are used to ensure
that simultaneous operating limits are respected, in order to
meet NERC and WSCC operating criteria.
Non -Converted Rights Those transmission service rights as defined in Section 2.4.4.2.1
D-12
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
Non -Participating
Generator
Non -Participating TO
of the ISO Tariff.
A Generator that is not a Participating Generator.
A TO that is not a party to the TCA or for the purposes of
Sections 2.4.3 and 2.4.4 of the ISO Tariff the holder of
transmission service rights under an Existing Contract that is
not a Participating TO.
NRC The Nuclear Regulatory Commission or its successor.
Operating Procedures Procedures governing the operation of the ISO Controlled Grid
as the ISO may from time to time develop, and/or procedures
that Participating TOs currently employ which the ISO adopts
Operational Control
for use.
The rights of the ISO under the Transmission Control
Agreement and the ISO Tariff to direct Participating TOs how
to operate their transmission lines and facilities and other
electric plant affecting the reliability of those lines and facilities
for the purpose of affording comparable non-discriminatory
transmission access and meeting Applicable Reliability Criteria.
Operator The operator of facilities comprised in the ISO Controlled Grid
or Reliability Must -Run Units.
Outage Disconnection or separation, planned or forced, of one or more
elements of an electric system.
Participating Generator A Generator or other seller of Energy or Ancillary Services
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TRANSMISSION CONTROL AGREEMENT
APPENDIX D
through a Scheduling Coordinator over the ISO Controlled Grid
and which has undertaken to be bound by the terms of the ISO
Tariff.
Participating TO A party to the TCA whose application under Section 2.2 of the
TCA has been accepted and who has placed its transmission
assets and Entitlements under the ISO's Operational Control in
accordance with the TCA.
Physical Scheduling Plant A group of two or more related Generating Units, each of which
is individually capable of producing Energy, but which either by
physical necessity or operational design must be operated as if
they were a single Generating Unit and any Generating Unit or
Units containing related multiple generating components which
meet one or more of the following criteria: i) multiple
generating components are related by a common flow of fuel
which cannot be interrupted without a substantial loss of
efficiency of the combined output of all components; ii) the
Energy production from one component necessarily causes
Energy production from other components; iii) the operational
arrangement of related multiple generating components
determines the overall physical efficiency of the combined
output of all components; iv) the level of coordination required
to schedule individual generating components would cause the
ISO to incur scheduling costs far in excess of the benefits of
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TRANSMISSION CONTROL AGREEMENT
APPENDIX D
having scheduled such individual components separately; or v)
metered output is available only for the combined output of
related multiple generating components and separate generating
component metering is either impractical or economically
inefficient.
PMS (Power Management The ISO computer control system used to monitor the real time
System)
performance of the various elements of the ISO Controlled
Grid, control Generation, and perform operational power flow
studies.
Preferred Schedule The initial Schedule produced by a Scheduling Coordinator that
represents its preferred mix of Generation to meet its Demand.
For each Generator, the Schedule will include the quantity of
output, details of any Adjustment Bids, and the location of the
Generator. For each Load, the Schedule will include the
quantity of consumption, details of any Adjustment Bids, and
the location of the Load. The Schedule will also specify
quantities and location of trades between the Scheduling
Coordinator and all other Scheduling Coordinators. The
Preferred Schedule will be balanced with respect to Generation,
Transmission Losses, Load and trades between Scheduling
Coordinators.
Project Sponsor A Market Participant or group of Market Participants or a
Participating TO that proposes the construction of a
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TRANSMISSION CONTROL AGREEMENT
APPENDIX D
transmission addition or upgrade in accordance with Section 3.2
of the ISO Tariff.
RAS (Remedial Action Protective systems that typically utilize a combination of
Schemes
conventional protective relays, computer -based processors, and
telecommunications to accomplish rapid, automated response to
unplanned power system events. Also, details of RAS logic and
any special requirements for arming of RAS schemes, or
changes in RAS programming, that may be required.
Regulatory Must -Run Hydro Spill Generation and Generation which is required to run
Generation
by applicable Federal or California laws, regulations, or other
governing jurisdictional authority. Such requirements include
but are not limited to hydrological flow requirements,
environmental requirements, such as minimum fish releases,
fish pulse releases and water quality requirements, irrigation and
water supply requirements, or the requirements of solid waste
Generation, or other Generation contracts specified or
designated by the jurisdictional regulatory authority as it existed
on December 20, 1995, or as revised by Federal or California
law or Local Regulatory Authority.
Reliability Criteria Pre -established criteria that are to be followed in order to
maintain desired performance of the ISO Controlled Grid under
contingency or steady state conditions.
Reliability Must -Run Unit A Generating Unit which is the subject of the contract between
TRANSMISSION CONTROL AGREEMENT
APPENDIX D
the Generator and the ISO under which, in return for certain
payments, the ISO is entitled to call upon the owner to run the
unit when required by the ISO for the purposes of the reliable
operation of the ISO Controlled Grid.
RTG (Regional A voluntary organization approved by FERC and composed of
Transmission Group)
transmission owners, transmission users, and other entities,
organized to efficiently coordinate the planning, expansion and
use of transmission on a regional and inter -regional basis.
SCADA (Supervisory A computer system that allows an electric system operator to
Control and Data
Ac( uisition) remotely monitor and control elements of an electric system.
Scheduling Coordinator An entity certified by the ISO for the purposes of undertaking
the functions specified in Section 2.2.6 of the ISO Tariff.
Scheduling Point A location at which the ISO Controlled Grid is connected, by a
group of transmission paths for which a physical, non -
simultaneous transmission capacity rating has been established
for Congestion Management, to transmission facilities that are
outside the ISO's Operational Control., A Scheduling Point
typically is physically located at an "outside" boundary of the
ISO Controlled Grid (e.g., at the point of interconnection
between a Control Area utility and the ISO Controlled Grid).
For most practical purposes, a Scheduling Point can be
considered to be a Zone that is outside the ISO's Controlled
Grid.
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TRANSMISSION CONTROL AGREEMENT
APPENDIX D
Self -Sufficiency or Self- A Participating TO for which the sum of its Dependable
Sufficient
Generation and its FIITC is greater than or equal to its Monthly
Peak Load.
Settlement Account An account held at a bank situated in California, designated by a
Scheduling Coordinator or a Participating TO pursuant to the
Scheduling Coordinator's SC Agreement or in the case of a
Participating TO, Section 2.2.1 of the TCA, to which the ISO
shall pay amounts owing to the Scheduling Coordinator or the
Participating TO under the ISO Tariff.
System Emergency Conditions beyond the normal control of the ISO that affect the
ability of the ISO Control Area to function normally including
any abnormal system condition which requires immediate
manual or automatic action to prevent loss of Load, equipment
damage, or tripping of system elements which might result in
cascading outages or to restore system operation to meet the
minimum operating reliability criteria.
System Planning Studies Reports summarizing studies performed to assess the adequacy
of the ISO Controlled Grid as regards conformance to
Reliability Criteria.
System Reliability A measure of an electric system's ability to deliver
uninterrupted service at the proper voltage and frequency.
Tax Exempt Debt Municipal Tax Exempt Debt or Local Furnishing Bonds.
Tax Exempt Participating A Participating TO that is the beneficiary of outstanding Tax -
TO
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TRANSMISSION CONTROL AGREEMENT
APPENDIX D
Exempt Debt issued to finance any electric facilities, or rights
associated therewith, which are part of an integrated system
including transmission facilities the Operational Control of
which is transferred to the ISO pursuant to the TCA.
TCA (Transmission Control The agreement between the ISO and Participating TOs
Agreement)
establishing the terms and conditions under which TOs will
become Participating TOs and how the ISO and each
Participating TO will discharge their respective duties and
responsibilities, as may be modified from time to time.
TO (Transmission Owner) An entity owning transmission facilities or having firm
contractual rights to use transmission facilities.
TO Tariff A tariff setting out a Participating TO's rates and charges for
transmission access to the ISO Controlled Grid and whose other
terms and conditions are the same as those contained in the
document referred to as the Transmission Owners Tariff
approved by FERC as it may be amended from time to time.
UDC (Utility Distribution An entity that owns a Distribution System for the delivery of
Company)
Energy to and from the ISO Controlled Grid, and that provides
regulated retail electric service to Eligible Customers, as well as
regulated procurement service to those End -Use Customers who
are not yet eligible for direct access, or who choose not to
arrange services through another retailer..
Uncontrollable Force Any act of God, labor disturbance, act of the public enemy, war,
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TRANSMISSION CONTROL AGREEMENT
APPENDIX D
insurrection, riot, fire, storm or flood, earthquake, explosion,
breakage, or accident to machinery or equipment, any
curtailment, order, regulation or restriction imposed by
governmental military or lawfully established civilian
authorities or any other cause beyond a Party's reasonable
control and without such Party's fault or negligence.
Voltage Support Services provided by Generating Units or other equipment such
as shunt capacitors, static var compensators, or synchronous
condensers that are required to maintain established grid voltage
criteria. This service is required under normal or system
emergency conditions.
WEnet (Western Energy An electronic network that facilitates communications and data
Network
exchange among the ISO, Market Participants and the public in
relation to the status and operation of the ISO Controlled Grid.
Wheeling Out Except for Existing Rights and Non -Converted Rights exercised
under an Existing Contract in accordance with Sections 2.4.3
and 2.4.4, the use of the ISO Controlled Grid for the
transmission of Energy from a Generating Unit located within
the ISO Controlled Grid to serve a Load located outside the
transmission and distribution system of a Participating TO.
Wheeling Through Except for Existing Rights and Non -Converted Rights exercised
under an Existing Contract in accordance with Sections 2.4.3
and 2.4.4, the use of the ISO Controlled Grid for the
■
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TRANSMISSION CONTROL AGREEMENT
APPENDIX D
transmission of Energy from a Generating Unit located outside
the ISO Controlled Grid to serve a Load located outside the
transmission and distribution system of a Participating TO.
WSCC (Western System The Western Systems Coordinating Council or its successor.
Coordinating Council)
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TRANSMISSION CONTROL AGREEMENT
APPENDIX E
Nuclear Protocols
TRANSMISSION CONTROL AGREEMENT
APPENDIX E
DIABLO CANYON NUCLEAR POWER PLANT
UNITS 1 & 2
REQUIREMENTS FOR OFFSITE
POWER SUPPLY OPERABILITY
REVISION 1
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APPENDIX E
DCPP 1&2 REQUIREMENTS FOR OFFSITE POWER SUPPLY OPERABILITY
OVERVIEW
During normal operation, each DCPP unit's electrical loads are supplied from the unit's
main onsite electrical generator. If the generator is not available, either due to unit
shutdown or other reason, the loads are transferred to an alternative source. The preferred
immediate alternate source of electrical power for DCPP electric loads (safety -related and
nonsafety-related) is the offsite power supply or 230kV grid In addition DCPP has a
delayed 500 kV source. The offsite power source is sometimes referred to as the preferred
power supply in the regulatory documents.
The basic requirement for the offsite power supply is that it provides sufficient capacity and
capability for safe shutdown and design basis accident mitigation. When this condition is
met, the offsite power supply is considered Operable with respect to the DCPP Operating
License and Technical Specifications. It is a necessary condition of the Operating License
that the offsite power supply be Operable at all times. If the offsite power system is
declared Inoperable, action must be taken to shut down an on-line DCPP units(s) and, for
an off-line unit, to suspend activities as required by the DCPP Operating License and
Technical Specifications. DCPP must also perform additional diesel testing. The offsite
power system is considered Inoperable if it is degraded to the point that it does not have the
capability to effect safe shutdown and to mitigate the effects of an accident at DCPP. This
level of degradation can be caused by an unstable offsite power system, or any condition
which renders the offsite power unavailable for safe shutdown and emergency purposes.
In specific terms, the offsite power supply voltage (at the DCPP switchyard) must stay
within the range of 207 kV to 240kV under post accident operating conditions During
normal operation the voltage must be held enough above 207kV so that when DCPP
transfers it's load from the onsite source to the offsite source the voltage does not decrease
below 207kV. For normal operation with all lines in service the voltage must be above
211kV. During normal operation, the voltage should be above 218kV. Otherwise the
offsite power supply is considered Inoperable. Since a design basis accident can result in a
unit trip, it is imperative that the trip not impair the operability of the offsite power system.
Therefore, following a trip of a DCPP unit (i.e., the unit breakers open), the DCPP
switchyard voltage must recover to and be maintained at or above 207 kV within 16
seconds following the trip. If this condition cannot be met, then the offsite power supply in
the pre trip condition is considered Inoperable, and action must be taken to shut down the
operating DCPP unit(s). In addition, the 500 and 230 kV grid must remain stable if both
DCPP units trip.
System Operating procedures and programs shall be in place to ensure that various system
operating conditions (generating unit outages, line outages, system loads, spinning reserve,
etc.), including multiple contingency events, are evaluated and understood, such that
impaired or potentially degraded grid conditions are recognized, assessed and immediately
communicated to the DCPP operating staff for Operability determination.
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APPENDIX E
SPECIFIC REQUIREMENTS
Note: This section identifies the operational requirements for the DCPP offsite power
supply. These requirements are part of the DCPP design basis and licensing basis and
include PG&E System Operating Instruction 0-23 as revised from time to time. Failure to
meet these requirements may render the offsite power supply Inoperable, thus requiring the
operating DCPP unit(s) to shutdown. Failure to meet these requirements must be
immediately communicated to PG&E and the DCPP operating staff for operability
determination. Changes in the operation of the transmission network that conflict with
these requirements require prior approval by PG&E.
1. Three transmission lines into the 500 kV switchyard and two lines into the 230 kV
DCPP switchyard are normally in service. Any increase or decrease in the number of
lines into the DCPP switchyard requires prior approval by PG&E.
No line may be removed from service at anytime without prior notification to the DCPP
Operations Department. At least two independent sources of power, the 500 kV and
the 230kV system between the transmission network (grid) and DCPP switchyards shall
be available at all times. PG&E System Operating Procedure, 0-23, Operating
Instructions for Reliable Transmission Service for Diablo Canyon, provides specific
requirements to determine operability of these sources.
2. With both Diablo Canyon units off-line, the DCPP 500 and 230kV offsite power source
should be capable of providing 105MW and 78 MVAR to Diablo Canyon for normal
operation, safe shutdown, and design basis accident mitigation.
3. The minimum grid voltage at DCPP switchyard shall be maintained at or above 218kV
for normal operation with all lines in service. In the event of a system disturbance or
line outage that can cause the voltage to dip below 218kV, including the trip of a DCPP
unit, the grid voltage shall recover to 207kV or above within 16 seconds.
4. Planning and operating reliability criteria shall result in plans for the following events
without loss of grid stability or availability:
a) The loss of two DCPP units.
b) The loss of any generating unit on the PG&E grid.
c) The loss of any major transmission circuit or intertie on the PG&E grid.
d) The loss of any large load or block of load on the PG&E grid.
5. The maximum grid voltage at the DCPP switchyard shall be maintained at or below
240kV. (References 10, 11)
6. The normal operating voltage of the DCPP switchyard shall be maintained at 230 kV.
The DCPP switchyard voltage shall not exceed 240kV unless required to preserve
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TRANSMISSION CONTROL AGREEMENT
APPENDIX E
transmission network integrity.
7. The 500 kV system shall be maintained between 510kV and 550kV. Operation of
DCPP is limited between .97 p.u. and 1.05 p.u. Requests to operate above 1.01 p.u.
shall be analyzed prior to implementation to assure viability of the 500kV and 230kV
after a DCPP unit trip. If two of three.500 kV lines are out of service, spinning reserve
must be available that is equal to the total of DCPP generation.
System studies shall be performed and updated based on changing grid conditions (load
growth, etc.) to identify critical conditions that could render offsite power supply
Inoperable. The offsite power system is considered Inoperable if it is degraded to the point
that it does not have the capability to effect safe shutdown and to mitigate the effects of an
accident at DCPP. This level of degradation can be caused by an unstable offsite power
system, or any condition which renders the offsite power supply unavailable for safe
shutdown and emergency purposes. Procedures and programs shall be in effect to ensure
that the DCPP operating staff is immediately notified of such conditions. Grid conditions
that are more severe with respect to DCPP switchyard voltages or otherwise unanalyzed,
render the offsite power supply Inoperable. DCPP operating staff shall be immediately
notified of such conditions. Auditable records of system study results shall be maintained.
Study results, including revisions and updates, shall be transmitted via letter to PG&E.
Study results and conclusions shall be assessed at least annually and updated, if needed,
based on changing grid conditions. Results of the annual assessments shall be transmitted
via letter to PG&E.
System studies shall consider the interconnections between PG&E, and other utilities in the
Western States Coordinating Council (WSCC) region.
8. In the event of loss of the DCPP offsite power supply:
Note: With regard to Station Blackout(SB 0) DCPP 1 &2 are 4 hour coping plants. The
regulatory requirement is that DCPP be able to withstand a loss of all AC power (loss
of offsite power plus loss of both Emergency Diesel Generators) for 4 hours.
Therefore, at least one transmission line into the DCPP switchyard should be restored
within 4 hours to prevent possible core damage.
a) Highest possible priority shall be given to restoring power to the DCPP
switchyards.
b) Should incoming lines to the DCPP switchyards be damaged, highest priority
shall be assigned to repair and restoration of at least one line into the DCPP
switchyards.
c) Repair crews engaging in power restoration activities for DCPP shall be given
the highest priority for manpower, equipment, and materials.
d) Formal programs and procedures shall be in place to effect items a), b), and c)
above.
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APPENDIX E
9. Grid frequency shall be maintained at 60 Hertz (nominal). The following operations
are initiated for low system frequency conditions:
a) At 59.75 Hz, A- 18 interruptible customers are tripped.
b) At 59. 1 Hz, PG&E system load shedding is initiated. Two 5% blocks (10%) of
load is tripped at this frequency and at 0.2 Hz decrements until 50% of load has
been tripped (10 5% blocks).
c) At 58.2 Hz the north and south 500 kV intertie lines are tripped to separate the
PG&E system from SCE and the Northwest systems.
d) Thermal plants are equipped with 3 setpoint underfrequency relays that would
cause underfrequency tripping to protect the turbines and generators from being
damaged. The set points are:
58 Hz with 3-minute time delay
57 Hz with 1-minute time delay
55 Hz with 0.5 seconds time delay
e),Hydro generators are tripped last at 54.0 Hz with, 1-minute time delay.
10. PG&E Bulk Power Transmission System Reliability Criteria as described in the DCPP
Updated Final Safety Analysis Report shall be maintained. Changes to the reliability
criteria that could adversely impact grid reliability and availability as defined in this
specification require prior approval of PG&E.
11. PG&E transmission lines shall be patrolled annually to ensure that the physical and
electrical integrity of transmission system components is maintained.
12. Line insulators, pole hardware terminals; and tower hardware terminal within the first
three miles from the Diablo switchyard shall be washed and inspected at least three
times a year to reduce line outages that may result from flashovers due to possible
accumulated contamination.
13. Preventive maintenance, testing and calibration of DCPP switchyard circuit breakers
and protective relays shall be performed as follows:
PG&E: 230kV & 500kV circuit breakers are inspected every 2 years and overhauled
every 8 years. Transmission line relays are tested every 36 months.
Preventive maintenance and testing of DCPP switchyard batteries shall be performed
per IEEE 450-1972. Preventive maintenance and testing of DCPP switchyard battery
chargers and DC system components shall be performed every 3 months.
14. Updates to applicable portions of Section 8.0, Electric Power of DCPP 1&2 Updated
Final Analysis Report (UFSAR) shall be provided annually. These updates will be used
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TRANSMISSION CONTROL AGREEMENT
APPENDIX E
by PG&E to prepare a UFSAR change submittal to the NRC. DCPP is required by
1OCFR50.71(e) to submit to the NRC periodic updates to the UFSAR.
These Specific Requirements mirror existing operating protocols, equipment, regional and
national reliability organization standards and are subject to modification as necessary
when new standards, equipment or protocols are adopted or updated.
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TRANSMISSION CONTROL AGREEMENT
APPENDIX E
SONGS 2&3 REQUIREMENTS FOR OFFSITE
POWER SUPPLY OPERABILITY
Revised January 5,1998
OVERVIEW
The preferred source of electrical power for SONGS electrical loads (safety -related and
nonsafety-related) is the offsite power supply or 230 kV grid. The offsite power supply is
sometimes referred to as the preferred power supply in the regulatory documents.
The basic requirement for the offsite power supply is that it provides sufficient capacity and
capability to safely shut down the reactor and to mitigate certain specified accident scenarios.
When this condition is met, the offsite power supply is considered Operable with respect to the
SONGS Operating License and Technical Specifications. It is a necessary condition of the
Operating License that the offsite power supply be Operable at all times. If the offsite power
system is declared Inoperable, action must be taken to shut down an online SONGS unit(s) and,
for an offline unit, to suspend activities as required by the SONGS Operating License and
Technical Specifications. The offsite power system is considered Inoperable if it is degraded to
the point that it does not have the capability to supply electrical loads needed to safely shut down
the reactor and to mitigate the effects of an accident at SONGS. This level of degradation can be
caused by an unstable offsite power system, or any condition which renders the offsite power
unavailable to safely shutdown the units or to supply emergency electrical loads.
In specific terms, the offsite power supply voltage (at the SONGS switchyard) must stay within
the range of 218 kV to 238 kV under all normal and plant accident (i.e. emergency shutdown or
trip) conditions. Otherwise the offsite power supply is considered Inoperable. Since accident
scenarios for which the plant is designed can result in a unit trip, it is imperative that the trip not
impair the operability of the offsite power system. Therefore, following a trip of a SONGS unit
(i.e., the unit breakers open), the SONGS switchyard voltage must recover to and be maintained
at or above 218 kV within 2.5 seconds following the trip. If this condition cannot be met, then
the offsite power supply is considered Inoperable, and action must be taken to shut down the
operating SONGS unit(s). Even though these requirements apply at all times, this condition is
primarily of concern when one SONGS unit is online and the other unit offline. If both SONGS
units are online and one unit trips (due to an accident or otherwise), the non -tripped unit will
provide local voltage support to the SONGS switchyard, and 230 kV system voltage will remain
within the required range. In cases where one SONGS unit is online and one unit offline, the
offsite power supply must be sufficiently robust to survive a trip of the online unit and meet the
SONGS voltage requirements in the post -trip condition. A dual unit trip is not the limiting
condition since a plant accident is not postulated simultaneous with a dual unit trip.
System Operating procedures and programs shall be in place to ensure that various system
operating conditions (generating unit outages, line outages, system loads, spinning reserve, etc.),
including multiple contingency events, are evaluated and understood, such that impaired or
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TRANSMISSION CONTROL AGREEMENT
APPENDIX E
potentially degraded grid conditions are recognized, assessed and communicated to the SONGS
Control Room for Operability determination.
The SONGS switchyard is made up of the SCE switchyard and the SDG&E switchyard. Unless
specifically stated otherwise, SONGS switchyard requirements contained in this document apply
to both the SCE switchyard and the SDG&E switchyard.
SPECIFIC REQUIREMENTS
Note 1: This section identifies the operational requirements for the SONGS offsite power supply. These
requirements are part of the SONGS design basis and licensing basis. Failure to meet these
requirements may render the offsite power supply Inoperable, thus requiring the operating
SONGS unit(s) to shutdown. Failure to meet these requirements must be immediately
communicated to SCE and the SONGS Control Room for operability determination. Changes in
the operation of the transmission network that conflict with these requirements require prior
approval by SCE.
Note 2: Specific requirements, procedures, operating bulletins, division orders, and analysis that support or
provide the basis for the specific operational requirements may be revised periodically subject to
prior approval of the affected parties.
Nine transmission lines into the SONGS switchyard are normally in service. Any
increase or decrease in the number of lines into the SONGS switchyard requires prior
approval of SCE. (Reference 7)
No line may be removed from service for greater than 30 days without prior notification
to SCE. At least two independent transmission lines (one from SCE and one from
SDG&E) between the transmission network (grid) and SONGS switchyard shall be in
service at all times. (References 1, 2, 3, 4, 7, 8)
2. With both San Onofre units off-line, the SONGS offsite power source shall be capable of
providing 152 MW and 96 MVAR to San Onofre for normal operation and for shutting
down the units during plant Design Basis Accident (DBA) conditions. (References 9, 10)
3. The minimum grid voltage at the SONGS switchyard shall be maintained at or above
218 kV. In the event of a system disturbance that can cause the voltage to dip below
218 kV, including the trip of a SONGS unit, the grid voltage shall recover to 218 kV or
above within 2.5 seconds. (References 9, 10, 12, 13, 18)
4. The following initiating events shall not result in the loss of grid stability or availability:
a. The loss of a San Onofre Unit (with the other unit already offline), or
b. The loss of any generating unit on the SCE and SDG&E grids, or
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TRANSMISSION CONTROL AGREEMENT
APPENDIX E
C. The loss of any major transmission circuit or intertie on the SCE and SDG&E
grids, or
d. The loss of any large load or block of load (e.g., due to a bus section outage) on
the SCE and SDG&E grids.
(References 2, 3, 4, 8)
5. The maximum grid voltage at the SONGS switchyard shall be maintained at or below
238 W. (References 10, 11, 18)
6. The normal operating voltage of the SONGS switchyard shall be maintained at 230 W.
The SONGS switchyard voltage shall not exceed 232 kV unless required to preserve
transmission network integrity. (References 10, 11, 18)
7. The limiting conditions for SONGS offsite power source operability are defined as
follows:
1. One SONGS unit is off- line, and
2. One of the critical line (s) outages occurs (see list of the lines below), and
3. VAR flows north and south of SONGS are above the threshold levels for the existing
combined SCE and SDG&E import level as defined by the referenced nomograms in
the ECC Operating Procedure : SONGS Voltage, dated December 9, 1997.
Based on these nomograms and SONGS offline unit's mode status if the ECC, Grid Control
Center (GCC), or ISO determines that the operating point is outside the applicable derated
import nomogram line, they shall notify SONGS immediately that a particular transmission
line is out of service, and the critical system conditions are sufficient to cause SONGS off site
power source to be considered INOPERABLE; i.e., unable. to support SONGS voltage at 218
kV if the remaining unit trips. SONGS Control Room will declare the offsite source
inoperable (in anticipation of losing the second SONGS unit) and will declare the time period
within which the on-line unit will have to initiate shutdown if conditions are not corrected.
The time period will be within 1 to 24 hours, based on the SONGS plant and equipment
conditions.
List of the critical transmission lines:
Critical Line(s) Out In SCE Territory
Palo Verde Devers 500 kV Line
Ellis- Johanna & Ellis -Santiago 230 kV Lines
Lugo -Serrano & Mira Loma -Serrano 500 kV Lines
Lugo- Mira Loma 2&3 500 kV Lines
Two Midway Vincent 500 kV Lines
TRANSMISSION CONTROL AGREEMENT
APPENDIX E
SONGS- Serrano & SONGS - Chino 230 kV Lines
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TRANSMISSION CONTROL AGREEMENT
APPENDIX E
Critical Line(s) Out in SDG&E Territory
Palo Verde- N. Gila 500 kV Line
N. Gila- Imperial Valley 500 kV Line
Imperial Valley- Miguel 500 kV Line
Imperial Valley- Miguel 500 kV Line & Imperial Valley- LaRosita 230 kV Line
SONGS -San Luis Rey 230 kV Tap & SONGS - Mission 230 kV Line
Systems studies shall be performed and updated based on changing grid conditions (load
growth, etc.) to identify critical conditions, such as the above cases, that could render the
offsite power supply Inoperable. The offsite power system is considered Inoperable if it
is degraded to the point that it does not have the capability to provide electrical support to
safe shutdown loads and to mitigate the effects of an accident at SONGS. This level of
degradation can be caused by an unstable offsite power system, or any condition which
renders the offsite power supply unavailable for safe shutdown and emergency purposes.
The following actions are required:
a. Procedures and programs shall be in effect to ensure that the SONGS Control
Room is immediately notified of such conditions.
b. Grid conditions that are more severe with respect to SONGS switchyard voltage,
or are otherwise unanalyzed, render the offsite power supply Inoperable. The
SONGS Control Room shall be immediately notified of such conditions.
C. Auditable records of current system studies shall be made available to SCE as
needed to demonstrate compliance with regulatory requirements. Study results,
including revisions and updates, shall be formally transmitted to SCE.
d. Study results and conclusions shall be assessed at least annually and updated, if
needed, based on changing grid conditions. Results of the annual assessments
shall be formally transmitted to SCE.
(References 1, 2, 19, 21)
System studies shall consider the interconnections between SCE, SDG&E, and other
utilities in the Western Systems Coordinating Council (WSCC) region. (Reference 7)
8. In the event of loss of the SONGS offsite power supply:
Note: SONGS 2 and 3 are required by NRC regulations to be able to safely cope with a loss of all AC power
(Station Blackout) for a maximum of four hours. The four hour coping duration is based on the
expectation that at least one source of AC power (offsite transmission line or onsite diesel generator)
will be restored to the blacked -out unit within the four hours to ensure the proper functioning of
systems required for plant safety.
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TRANSMISSION CONTROL AGREEMENT
APPENDIX E
a. Highest possible priority shall be given to restoring power to the SONGS
switchyard. Procedures and training should consider several potential methods of
transmitting power from black -start capable units to the SONGS switchyard.
This includes such items as nearby gas turbine generators, portable generators,
hydro generators, and black -start fossil power plants. (References 15, 26, 28)
b. Should incoming lines to the SONGS switchyard be damaged, highest priority
shall be assigned to repair and restoration of at least one line into the SONGS
switchyard.
C. Repair crews engaging in power restoration activities for SONGS shall be given
the highest priority for manpower, equipment, and materials.
d. Formal programs and procedures shall be in place to effect items a, b, and c
above.
(References 14, 15, 16, 17, 26, 27)
9. Grid frequency shall be maintained at 60 Hertz (nominal). A trip of one SONGS unit
shall not cause the grid frequency to dip below 59.7 Hertz. The following operations are
initiated for low system frequency conditions:
a. At 59.3 Hertz, SCE system load shedding program is initiated.
b. At 58.2 Hertz, automatic separation of the SCE system from the SDG&E system is
initiated at the SONGS switchyard when either San Onofre unit is pre -selected to
separate with the SDG&E system.
C. At 58.0 Hertz, manual separation of the SCE system from the SDG&E system is
initiated at the SONGS switchyard when either San Onofre unit is pre -selected to
separate with the SDG&E system.
d. At 57.0 Hertz, automatic separation of the SCE system from the SDG&E system
is initiated at the SONGS switchyard when no San Onofre unit is selected to
separate with the SDG&E system.
e. At 56.8 Hertz, manual separation of the SCE system from the SDG&E system is
initiated at the SONGS switchyard when no San Onofre unit is selected to
separate with the SDG&E system.
Note: The above separation setpoints are provided for information only. SCE and SDG&E are
currently reviewing the 57 Hz separation setpoint. This setpoint may be changed to ensure that
system separation occurs prior to a trip of the nuclear unit(s), which also occurs at approximately 57
Hz. SCE will inform the ISO of any changes to the system separation setpoint.
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TRANSMISSION CONTROL AGREEMENT
APPENDIX E
(References 7, 20)
10. SCE and SDG&E Bulk Power Transmission System Reliability Criteria as described in
the SONGS 2&3 Updated Final Safety Analysis Report shall be maintained. It is
recognized that the SCE and SDG&E Bulk Power Transmission System Reliability
Criteria as described in the SONGS 2&3 Updated Final Safety Analysis Report may be
revised from time to time. In the event the reliability criteria are revised, a system
assessment and/or study (as described under specification 7) shall be performed to
determine if the revised reliability criteria adversely impact grid reliability and
availability as defined in this specification. Results of the assessment and/or study
together with a copy of the revised reliability criteria shall be provided to SCE. Changes
in grid operation based on the revised criteria and associated studies shall not be
implemented without prior approval of SCE. (Reference 7)
11. SCE and SDG&E transmission lines shall be patrolled annually to ensure that the
physical and electrical integrity of transmission system components is maintained.
(References 7, 22)
12. Line insulators, pole hardware terminals, and tower hardware terminals within the first
three miles from the San Onofre switchyard shall be inspected annually and washed at
least two times a year to reduce line outages that may result from flashovers due to
possible accumulated contamination. (References 7, 22)
13. Preventive maintenance, testing and calibration of SONGS switchyard circuit breakers
and protective relays shall be performed as follows:
SCE: 230 kV circuit breakers are overhauled every 300 normal operations or 25
kickouts. Response time/trip testing is performed annually. Transmission line relays are
tested biannually. (References 7, 24, 25)
SDG&E: 230 kV circuit breakers are overhauled every five years. Trip testing is
performed annually. Transmission line relays are tested biannually. (Reference 7)
14. Preventive maintenance and testing of SONGS switchyard batteries shall be performed
per IEEE 450-1972. Preventive maintenance and testing of SONGS switchyard battery
chargers and DC system components shall be performed routinely. (Reference 7, 23)
15. Updates to applicable portions of Section 8.0, Electric Power of the SONGS 2 & 3
Updated Final Safety Analysis Report (UFSAR) shall be provided annually. These
updates will be used by SCE to prepare a UFSAR change submittal to the NRC. SONGS
is required by 10CFR50.71(e) to submit to the NRC periodic updates to the UFSAR.
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TRANSMISSION CONTROL AGREEMENT
APPENDIX E
REFERENCES
1) SONGS 2&3 Operating License and Technical Specifications, Section 3.8, Electrical Power
Systems
2) IOCFR50 Appendix A, General Design Criterion 17 (GDC-17), Electrical Power Systems
3) NUREG 75/087, Standard Review Plan Revision 1, Section 8.2, Offsite Power System
4) NUREG 0800, Standard Review PlanRevision 2, Section 8.2, Offsite Power System
5) NUREG 0800, Standard Review Plan Revision 2, Branch Technical Position ICSB-11 (PSB),
Stability of Offsite Power Systems
6) NUREG 0712, SONGS 2&3 Safety Evaluation Report, Section 8.0, Electric Power Systems
7) SONGS 2 & 3 Updated Final Safety Analysis Report, Section 8.0, Electric Power
8) ANSMEEE Std. 765-1983 Preferred Power Supply for Nuclear Power Generating Stations
9) SONGS Design Calculation E4C-082, System Dynamic Voltages During Design Basis Accident
10) SONGS Design Calculation E4C-090, Auxiliary System Voltage Regulation
11) SONGS Design Calculation E4C-092, Short Circuit Studies
12) SONGS Design Calculation E4C-098, 4 kV Swgr Protective Relay Setting
13) DBD-S023-120, SONGS Design Basis Document, 6.9KV, 4.16KV and.480V Electrical Systems
14) 90051, SONGS Station Blackout Analyses
15) NUIVIARC 87-00 Guidelines and Technical Bases for NUMARC Initiatives Addressing Station
Blackout at Light Water Reactors
16) Letter from M. 0. Medford (SCE) to the Document Control Desk (NRC), dated April 17, 1989,
Subject: "Response to 10 CFR 50.63, 'Loss of all Alternating Current Power,' San Onofre
Nuclear Generating Station Units 1, 2 and 3"
17) Letter from F. R. Nandy (SCE) to the Document Control Desk (NRC), dated May 1, 1990,
Subject: "Supplemental Response to 10 CFR 50.63, 'Loss of All Alternating Current Power,'
Station Blackout (TAC No. 68599/600), San Onofre Nuclear Generating Station Units 1, 2, and
Y
18) System Operating Bulletin 17 Appendix, System Voltage Control for San Onofre Nuclear
Generating Station (Rev. January, 1998)
19) ECC Operating Procedure: Songs Voltage (Rev. 12/09/1997)
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TRANSMISSION CONTROL AGREEMENT
APPENDIX E
20) System Operating Bulletin 113, San Onofre 220 kV System Separation (Rev. April 15, 1995)
21) Regulatory Guide 1.93, Availability of Electric Power Sources
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TRANSMISSION CONTROL AGREEMENT
APPENDIX E
22) SCE Division Order 40.35, Transmission Line Routine Patrol, .Inspection, Scheduling, and
Record Keeping (Rev. 10/87)
23) SCE Division Order 60.20, Storage Batteries (Rev. 3/82)
24) SCE Division Order 50.10, Predictive Maintenance Circuit Breakers and Switches (Rev. 6/96)
25) SCE Division Order 50.20, Relay and Equipment Tests (Rev. 3/94)
26) System Operating Bulletin 1-A, Thermal Station Start-up and Power System Restoration (Rev.
12/97)
27) System Operating Bulletin 254, Emergency Orders —San Onofre Nuclear Generating Station 220
kV (Rev. March 18, 1996)
28) SDG&E Control Procedure 1150, Capacity & Energy Emergencies - SDG&E System
Emergencies ( Rev. 12/97)
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TRANSMISSION CONTROL AGREEMENT
APPENDIX F
TRANSMISSION CONTROL AGREEMENT
APPENDIX F
NOTICES
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TRANSMISSION CONTROL AGREEMENT
APPENDIX F
NOTICES
California Independent System Operator
Name of Primary
Representative:
Title:
Address:
City/State/Zip Code:
Email Address:
Phone:
Fax No:
Name of Alternative
Representative:
Title:
Address:
City/State/Zip Code:
Email Address:
Phone:
Fax No:
F-1
TRANSMISSION CONTROL AGREEMENT
APPENDIX F
Pacific Gas and Electric Company
Name of Primary
Representative:
Title:
Address:
City/State/Zip Code:
Email Address:
Phone:
Fax No:
Name of Alternative
Representative:
Title:
Address:
City/State/Zip Code:
Email Address:
Phone:
Fax No:
F-2
TRANSMISSION CONTROL AGREEMENT
APPENDIX F
San Diego Gas & Electric Company
Name of Primary
Representative:
Title:
Address:
City/State/Zip Code:
Email Address:
Phone:
Fax No:
Name of Alternative
Representative:
Title:
Address:
City/State/Zip Code:
Email Address:
Phone:
Fax No:
F-3
TRANSMISSION CONTROL AGREEMENT
APPENDIX F
Southern California Edison Company
Name of Primary
Representative:
Title:
Address:
City/State/Zip Code:
Email Address:
Phone:
Fax No:
Name of Alternative
Representative:
Title:
Address:
City/State/Zip Code:
Email Address:
Phone:
Fax No:
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TRANSMISSION CONTROL AGREEMENT
APPENDIX F
City of Vernon
Name of Primary
Representative: Bruce V. Malkenhorst
Title: City Administrator
City of Vernon
Address: 4305 Santa Fe Avenue
City/State/Zip Code: Vernon,. California 90.058
Email Address:
Phone: (323) 583-8811 Extension 266
Fax No: (323) 581-7924
Name of Alternative
Representative:
Kenneth J. DeDario
Title:
Director of Utilities
City of Vernon
Address:
4305 Santa Fe Avenue
City/State/Zip Code:
Vernon, California 90058
Email Address:
Phone:
(323) 583-8811, Extension 211
Fax No:
(323) 583-1983
F-5