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Exhibit 10.8

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT

TRANSMISSION CONTROL AGREEMENT

Among
The Independent System Operator
and
Transmission Owners

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TABLE OF CONTENTS

Section

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  Page

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1.   DEFINITIONS   2
2.
 
PARTICIPATION IN THIS AGREEMENT
 
2
3.
 
EFFECTIVE DATE, TERM AND WITHDRAWAL
 
4
4.
 
TRANSFER OF OPERATIONAL CONTROL
 
7
5.
 
INDEPENDENT SYSTEM OPERATOR
 
13
6.
 
PARTICIPATING TRANSMISSION OWNERS
 
15
7.
 
SYSTEM OPERATION AND MAINTENANCE
 
17
8.
 
CRITICAL PROTECTIVE SYSTEMS THAT SUPPORT ISO CONTROLLED GRID OPERATIONS
 
17
9.
 
SYSTEM EMERGENCIES
 
18
10.
 
ISOL CONTROLLED GRID ACCESS AND INTERCONNECTION
 
19
11.
 
EXPANSION OF TRANSMISSION FACILITIES
 
21
12.
 
USE AND ADMINISTRATION OF THE ISO CONTROLLED GRID
 
21
13.
 
EXISTING AGREEMENTS
 
21
14.
 
MAINTENANCE STANDARDS
 
21
15.
 
DISPUTE RESOLUTION
 
23
16.
 
BILLING AND PAYMENT
 
23
17.
 
RECORDS AND INFORMATION SHARING
 
23
18.
 
GRANTING RIGHTS-OF-ACCESS TO FACILITIES
 
25
19.
 
[INTENTIONALLY LEFT BLANK]
 
25
20.
 
TRAINING
 
26
21.
 
OTHER SUPPORT SYSTEMS REQUIREMENTS
 
26
22.
 
LIABILITY
 
26
23.
 
UNCONTROLLABLE FORCES
 
27
24.
 
ASSIGNMENTS AND CONVEYANCES
 
27
25.
 
ISO ENFORCEMENT
 
28
26.
 
MISCELLANEOUS
 
28
27.
 
SIGNATURE PAGE CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
 
32
28.
 
SIGNATURE PAGE PACIFIC GAS AND ELECTRIC COMPANY
 
33
29.
 
SIGNATURE PAGE SAN DIEGO GAS & ELECTRIC COMPANY
 
34
30.
 
SIGNATURE PAGE SOUTHERN CALIFORNIA EDISON COMPANY
 
35          

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31.
 
SIGNATURE PAGE CITY OF VERNON
 
36
32.
 
SIGNATURE PAGE CITY OF ANAHEIM
 
37
33.
 
SIGNATURE PAGE CITY OF AZUSA
 
38
34.
 
SIGNATURE PAGE CITY OF BANNING
 
39
35.
 
SIGNATURE PAGE CITY OF RIVERSIDE
 
40
36.
 
SIGNATURE PAGE OF TRANS-ELECT NTD PATH 15, LLC
 
41
37.
 
SIGNATURE PAGE OF WESTERN AREA POWER ADMINISTRATION, SIERRA NEVADA REGION
 
42

APPENDICES A—Facilities and Entitlements         PG&E Appendix A and Supplement
        Edison Appendix A and Supplement         SDG&E Appendix A and Supplement
        Vernon Appendix A         Anaheim Appendix A         Azusa Appendix A  
      Banning Appendix A         Riverside Appendix A         Trans-Elect NTD
Path 15, LLC Appendix A         Western Area Power Administration, Sierra Nevada
Region Appendix A    
APPENDICES B—Encumbrances
 
      PG&E Appendix B         Edison Appendix B         SDG&E Appendix B        
Vernon Appendix B         Anaheim Appendix B         Azusa Appendix B        
Riverside 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
 
 

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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.

        (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 367, 368, 375, 376 and 379 enacted as part of AB
1890 which contain assurances and schedules with respect to recovery of
transition costs.

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        (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

          iii.  Southern California Edison Company.

        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;

        (ii)   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 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;

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        (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.

        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;

          iii.  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

           v.  the applicant is capable of performing its obligations under this
Agreement.

        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.

        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

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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
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.

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.

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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. In addition, Western Area Power Administration ("Western") may be
required to withdraw as a Participating TO pursuant to Section 26.14.1.

        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 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.

3.4   Withdrawal Due to Adverse Tax Action.

        3.4.1    Right to Withdraw Due To Adverse Tax Action.    Subject to
Sections 3.4.2 through 3.4.4, in the event an Adverse Tax Action Determination
identifies an Impending Adverse Tax Action or an Actual Adverse Tax Action, a
Tax Exempt Participating TO may exercise its right to Withdraw for Tax Reasons.
The right to Withdraw for Tax Reasons, in accordance with the provisions of this
Section 3.4, shall not be subject to any approval by the ISO, the FERC or any
other Party.

        3.4.2    Adverse Tax Action Determination.    

        3.4.2.1    A Tax Exempt Participating TO shall provide to all other
Parties written notice of an Adverse Tax Action Determination and a copy of the
Tax Exempt Participating TO's (or its joint action agency's) nationally
recognized bond counsel's opinion or an IRS determination supporting such
Adverse Tax Action Determination. Such written notice shall be provided promptly
under the circumstances, but in no event more than 15 working days from the date
of receipt of such documents.

        3.4.2.2    The Adverse Tax Action Determination shall include (i) the
actual or projected date of the Actual Adverse Tax Action and (ii) a description
of the transmission lines, associated facilities or Entitlements that were
financed in whole or in part with proceeds of the Tax Exempt Debt that is the
subject of such Adverse Tax Action Determination. A Tax Exempt Participating TO
shall promptly notify all other Parties in writing in the event the actual or
projected date of the Actual Adverse Tax Action changes. The Tax Exempt
Participating TO's determination of the actual or projected date of the Actual
Adverse Tax Action shall be binding upon all Parties.

        3.4.2.3    Any transmission lines, associated facilities or Entitlements
of the Tax Exempt Participating TO not identified in both the Adverse Tax Action
Determination and the written notice of Withdrawal for Tax Reasons shall remain
under the ISO's Operational Control.

        3.4.3    Withdrawal Due to Impending Adverse Tax Action.    A Tax Exempt
Participating TO may Withdraw for Tax Reasons prior to an Actual Adverse Tax
Action if such Tax Exempt Participating TO provides prior written notice of its
Withdrawal for Tax Reasons to all other Parties as required in Sections
3.4.3(i) through 3.4.3(iv).

            i.  In the event the date of the Adverse Tax Action Determination is
seven months or more from the projected date of the Actual Adverse Tax Action,
then a Tax Exempt Participating TO that exercises its right to Withdraw for Tax
Reasons shall provide prior written notice of its

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Withdrawal for Tax Reasons to all other Parties at least six months in advance
of the projected date of the Actual Adverse Tax Action.

           ii.  In the event the date of the Adverse Tax Action Determination is
less than seven months but more than two months from the projected date of the
Actual Adverse Tax Action, then a Tax Exempt Participating TO that exercises its
right to Withdraw for Tax Reasons shall provide prior written notice of its
Withdrawal for Tax Reasons to all other Parties at least 30 days in advance of
the projected date of the Actual Adverse Tax Action.

          iii.  In the event the date of the Adverse Tax Action Determination is
between two months and one month from the projected date of the Actual Adverse
Tax Action, then a Tax Exempt Participating TO that exercises its right to
Withdraw for Tax Reasons shall provide prior written notice of its Withdrawal
for Tax Reasons to all other Parties at least 15 days in advance of the
projected date of the Actual Adverse Tax Action.

          iv.  In the event the date of the Adverse Tax Action Determination is
less than one month from the projected date of the Actual Adverse Tax Action,
then a Tax Exempt Participating TO shall have up to 15 days following the date
of the Adverse Tax Action Determination to exercise its right to Withdraw for
Tax Reasons, and if so exercised shall provide no later than one day thereafter
written notice of its Withdrawal for Tax Reasons to all other Parties.

           v.  With respect to Sections 3.4.3(i) through 3.4.3(iii), upon
receipt by the ISO of a notice to Withdraw for Tax Reasons, the ISO shall
promptly begin working with the applicable Tax Exempt Participating TO to
relinquish the ISO's Operational Control over the affected transmission lines,
associated facilities or Entitlements to such Tax Exempt Participating TO,
provided that such Operational Control must be relinquished by the ISO no later
than five days prior to the projected date of the Actual Adverse Tax Action.
With respect to Section 3.4.3(iv), (1) if the notice of Withdrawal for Tax
Reasons is received by the ISO at least six days prior to the projected date of
the Actual Adverse Tax Action, Operational Control over the affected
transmission lines, associated facilities or Entitlements must be relinquished
by the ISO to such Tax Exempt Participating TO no later than five days prior to
the projected date of the Actual Adverse Tax Action, or (2) if the notice of
Withdrawal for Tax Reasons is received by the ISO any time after six days prior
to the projected date of the Actual Adverse Tax Action, the ISO shall on the
next day relinquish Operational Control over the affected transmission lines,
associated facilities or Entitlements to such Tax Exempt Participating TO.

        3.4.4    Withdrawal Due to Actual Adverse Tax Action.    In addition to
the foregoing, upon the occurrence of an Actual Adverse Tax Action, the affected
Tax Exempt Participating TO may immediately Withdraw for Tax Reasons. The Tax
Exempt Participating TO shall have up to 15 days from the date of the Adverse
Tax Action Determination with respect to an Actual Adverse Tax Action to
exercise its right to Withdraw for Tax Reasons. If the Tax Exempt Participating
TO determines to exercise its right to Withdraw for Tax Reasons, upon receipt of
the notice of Withdrawal for Tax Reasons, the ISO shall immediately relinquish
Operational Control over the affected transmission lines, associated facilities
or Entitlements to such Tax Exempt Participating TO.

        3.4.5    Alternate Date To Relinquish Operational
Control.    Notwithstanding anything to the contrary in this Section 3.4, the
ISO and a Tax Exempt Participating TO who has provided a notice of Withdrawal
for Tax Reasons may mutually agree in writing to an alternate date that the ISO
shall relinquish Operational Control over the affected transmission lines,
associated facilities or Entitlements to such Tax Exempt Participating TO. If
the ISO or a Tax Exempt Participating TO who has provided a notice of Withdrawal
for Tax Reasons desires an alternate date from the date provided in Sections
3.4.3(i) through 3.4.3(v)(1) for the ISO to relinquish Operational Control over
the affected transmission lines, associated facilities or Entitlements to such
Tax Exempt Participating TO, such party promptly shall give written notice to
the other, and each agrees to negotiate in good faith, for a reasonable

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period of time, to determine whether or not they can reach mutual agreement for
such an alternate date; provided, however, such good faith negotiations are not
required to be conducted during the five days preceding the date provided in
Sections 3.4.3(i) through 3.4.3(v)(1) for the ISO to relinquish Operational
Control over the affected transmission lines, associated facilities or
Entitlements.

        3.4.6    Procedures to Relinquish Operational Control.    The ISO shall
implement a procedure jointly developed by all Parties to relinquish Operational
Control over the affected transmission lines, associated facilities, or
Entitlements as provided in this Section 3.4.

        3.4.7    Right to Rescind Notice of Withdrawal for Tax Reasons.    At
any time up to two days prior to the ISO's relinquishment to the Tax Exempt
Participating TO of Operational Control over the affected transmission lines,
associated facilities or Entitlements, a Tax Exempt Participating TO may rescind
its notice of Withdrawal for Tax Reasons by providing written notice thereof to
all other Parties, and such notice shall be effective upon receipt by the ISO.

        3.4.8    Amendment of Agreement.    Following the relinquishment by the
ISO of Operational Control of facilities, recognizing Entitlements of a
non-public utility in accordance with this Section 3.4, the ISO promptly shall
prepare the necessary changes to this Agreement and to the ISO Tariff (if any),
make a filing with FERC pursuant to Section 205 of the FPA, and take whatever
other regulatory action, if any, that is required to properly reflect the
Withdrawal for Tax Reasons.

        3.4.9    Provision of Information by ISO.    To assist Tax Exempt
Participating TOs in identifying at the earliest opportunity Impending Adverse
Tax Actions or Actual Adverse Tax Actions, the ISO promptly shall provide to
Participating TOs any non-confidential information regarding any ISO plans,
actions or operating protocols that the ISO believes might adversely affect the
tax-exempt status of any Tax Exempt Debt issued by, or for the benefit of, a Tax
Exempt Participating TO.

        3.4.10    Publication of Notices.    The ISO shall inform the public
through WEnet or the ISO internet website of all notices received under this
Section 3.4.

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, except that Western shall only be required to place under the
ISO's Operational Control the transmission lines and associated facilities that
it owns or to which it has Entitlements as set forth in Appendix A (Western).
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 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

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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:

            i.  directly assignable radial lines and associated facilities
interconnecting generation (other than those facilities which may be 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 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 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.

          iii.  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.

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        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 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:

            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.

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        4.2.3    Updates.    In order to keep the ISO Register current, each
Participating TO shall submit an ISO Register change for each addition or
removal of a transmission line or associated facility or Entitlement from the
ISO's Operational Control or any change in a transmission line or associated
facility's ownership, rating or the identity of the responsible Participating
TO. The ISO shall review each ISO Register change for accuracy and to assure
that all requirements of this Agreement have been met. If the ISO determines
that a submitted ISO Register change is accurate and meets all the requirements
of this Agreement, the ISO will modify the ISO Register to incorporate such
change by the end of the next Business Day. The ISO may determine that an ISO
Register change cannot be implemented due to (a) lack of clarity or necessary
information, or (b) conflict between the revised rating and applicable
contractual, regulatory or legal requirements including operating
considerations, or other conflict with the terms of this Agreement. In such
event, the ISO promptly will communicate to the Participating TO the reason that
the ISO cannot implement the ISO Register change and will work with the
Participating TO in an attempt to resolve promptly the concerns leading to the
ISO's refusal to implement an ISO Register change. The ISO consent required with
respect to a sale, assignment, release, transfer or other disposition of
transmission lines, associated facilities or Entitlements as provided in
Section 4.4 hereof shall not be withheld by the ISO as a result of an ISO
determination that an ISO Register change cannot be implemented pursuant to this
Section 4.2.3.

        4.2.4    Publication.    The ISO shall make the ISO Register information
for a given Participating TO available to that same Participating TO on WEnet or
a secure ISO-maintained internet website. The ISO will provide a copy of the ISO
Register information to other entities that can demonstrate a legitimate need
for the information in accordance with screening procedures posted on the ISO
Home Page and filed with FERC.

        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 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

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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.

        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, which consent shall
not be unreasonably withheld, 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.

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:

            i.  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

          iii.  subject to any contrary order of FERC, pending the resolution of
the procedures referenced in Section 4.5.1.

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        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 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 WEnet 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 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.

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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 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, 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
the ISO internet website.

        5.1.5    Applicable Reliability Criteria.    The ISO shall, in
consultation with Participating TOs and other Market Participants, 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

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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 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.

        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.

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        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 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 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 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.

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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
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 to an 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.

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.

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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.

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. CRITICAL PROTECTIVE SYSTEMS THAT SUPPORT ISO CONTROLLED GRID OPERATIONS

8.1.  Remedial Action Systems, Under Frequency Load Shedding, Under Voltage Load
Shedding.

        Each Participating TO shall coordinate its Critical Protective Systems
with the ISO, other Transmission Owners, and Generators to ensure that its
Remedial Action Schemes ("RAS"), Under Frequency Load Shedding ("UFLS"), and
Under Voltage Load Shedding ("UVLS") schemes function on a coordinated and
complementary basis in accordance with WSCC/NERC planning, reliability, and
protection policies and standards. Participating TOs that are parties to
contracts affecting RAS, UFLS, and UVLS schemes shall make reasonable efforts to
amend those contracts in order to permit the RAS, UFLS, and UVLS schemes to be
operated in accordance with WSCC/NERC planning, reliability, and protection
policies and standards and the ISO Tariff.

        Each Participating TO, in conjunction with the ISO, shall identify,
describe, and provide to the ISO the functionality of all RAS for electric
systems operating at 200 kV nominal voltage or higher and any other lower
voltage lines that the ISO and Participating TO determine to be critical to the
reliability of the ISO Controlled Grid. Each Participating TO shall provide to
the ISO a description of the functionality of UFLS and UVLS schemes that protect
the security and reliability of transmission facilities on the ISO Controlled
Grid.

        Each Participating TO shall maintain the design, functionality, and
settings of its existing RAS, UFLS, and UVLS schemes. New or existing schemes
that are functionally modified must be in accordance with WSCC/NERC planning,
reliability, and protection policies and standards. Each Participating TO shall
notify the ISO in advance of all RAS, UFLS, and UVLS schemes functionality

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and setting changes that affect transmission facilities on the ISO Controlled
Grid. Each Participating TO shall not disable or take clearances on RAS or UVLS
schemes without the approval of the ISO through the Maintenance Outage and
Forced Outage coordination process in accordance with the ISO Tariff. Clearances
on UFLS may be taken without approval depending upon the armed load disabled as
agreed to between the Participating TO and ISO and incorporated in the Operating
Procedures.

        The requirements of this Section 8.1 shall apply only to the
transmission facilities that are part of the ISO Controlled Grid.

8.2.  Protective Relay Systems.

        Each Participating TO shall provide to the ISO protective relay system
functional information necessary to perform system planning and operating
analysis, and to operate transmission facilities on the ISO Controlled Grid in
compliance with WSCC/NERC planning, reliability and protection policies and
standards.

        The requirements of this Section 8.2 shall apply only to the
transmission facilities that are part of the ISO Controlled Grid.

8.3   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.

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.

        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.

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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 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 ISO
Tariff and the TO Tariff as applicable, provided that the terms of the ISO
Tariff shall govern to the extent there is any inconsistency between the ISO
Tariff and the TO Tariff, and must comply with all of their 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. Interconnections Responsibilities.

        10.3.1    Applicability.    The provisions of this Section 10.3 shall
apply only to those facilities over which a Participating TO has legal authority
to effectuate proposed interconnections to the ISO Controlled Grid. Where a
Participating TO does not have the legal authority to compel interconnection,
the Participating TO's obligations with respect to interconnections shall be as
set forth in its Commission approved TO Tariff which shall contain an obligation
for the Participating TO, at a minimum, to submit or assist in the submission
of, expansion and/or interconnection requests from third parties to the
appropriate bodies of a project pursuant to the individual project agreements to
the full extent allowed by such agreements and the applicable laws and
regulations.

        10.3.2    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.

        10.3.3    Review of Participating TO Technical
Standards.    Participating TOs shall provide the ISO with copies of their
technical standards for Interconnection developed pursuant to Section 10.3.2 of
this Agreement and all amendments so that the ISO can satisfy itself as 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. Any differences in Interconnection
standards shall be addressed through negotiations and dispute resolution
proceedings, as set forth in the ISO Tariff, between the ISO and the
Participating TO.

        10.3.4    Notice.    A list of the Interconnection standards and
procedures developed by each Participating TO pursuant to Section 10.3.2,
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.

        10.3.5    Interconnection.    Each Participating TO and the ISO shall
process Interconnection requests in accordance with the ISO Tariff and the TO
Tariff as applicable, provided that the terms of the ISO Tariff shall govern to
the extent there is any inconsistency between the ISO Tariff and the TO Tariff.
Any differences in the procedures for interconnection contained in the ISO
Tariff and the TO Tariff shall be addressed through negotiations and dispute
resolution procedures, as set forth in the ISO Tariff, between the ISO and the
Participating TO.

        10.3.6    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.

        10.3.7    Collection of Payments.    The Participating TO shall collect
all payments owed under any System Impact Study Agreement, Facility Study
Agreement or other agreement entered into pursuant to this Section 10.3 or the
provisions of the ISO Tariff and its TO Tariff as applicable relating to
Interconnection.

        10.3.8    On-Site Inspections.    The ISO may at its own expense
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.

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10.4 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 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.

14. MAINTENANCE STANDARDS

14.1. ISO Determination of Standards.

        The ISO shall adopt, in consultation with the Participating TOs through
the Maintenance Coordination Committee, standards for the maintenance,
inspection, repair, and replacement of transmission facilities under its
Operational Control in accordance with Appendix C. These standards,

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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.

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.

        14.3.3    Availability Measure Target.    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, shall modify these standards and
incentives as necessary.

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.

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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 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 specified by the ISO.

        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;

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           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.

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
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 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.

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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 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.

19. [INTENTIONALLY LEFT BLANK]

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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.

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 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
contract or loss of goodwill) resulting from physical damage to property for
which a party may be liable under Section 22.1.

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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 party 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 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 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.

27

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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 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, materials, data, or information ("Data") provided to it by any
other Party that reflects or contains: (a) Data treated as confidential or
commercially sensitive under the confidentiality provisions of Section 20.3 of
the ISO Tariff; (b) critical energy infrastructure information, as defined in
Section 388.113(c)(1) of the FERC's regulations (c) technical information and
materials that constitute valuable, confidential, and proprietary information,
know-how, and trade secrets belonging to a Party, including, but not limited to,
information relating to drawings, maps, reports, specifications and records
and/or software, data, computer models, and related documentation; or (d) Data
that was previously public information but that was removed from public access
in accordance with FERC's policy statement issued on October 11, 2001 in Docket
No. PL02-1-000 in response to the September 11, 2001 terrorist attacks. In order
to be subject to the confidentiality protections of this Section 26.3, Data
provided by a Party to the ISO after January 1, 2005 which is to be accorded
confidential treatment, as set forth above, shall be marked as "Confidential
Data." Such a marking requirement, however, shall not be applicable to the Data
provided by a Party to the ISO prior to January 1, 2005 so long as the Data
qualifies for confidential treatment hereunder. Notwithstanding the foregoing,
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 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).

28

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        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 Party 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 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 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.

29

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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,
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.

26.14 Consistency with Federal Laws and Regulations

        26.14.1    No Violation of Law.    Nothing in this Agreement shall
compel any Party to: (1) violate any federal statute or regulation; or (2) in
the case of a federal agency, to exceed its statutory authority, as defined by
any applicable federal statute, or regulation or order lawfully promulgated
thereunder. No Party shall incur any liability by failing to comply with a
provision of this Agreement that is inapplicable to it by reason of being
inconsistent with any federal statute, or regulation or order lawfully
promulgated thereunder; provided, however, that such Party shall use its best
efforts to comply with this Agreement to the extent that applicable federal
laws, and regulations and orders lawfully promulgated thereunder, permit it to
do so.

        If Western issues or revises any federal regulation or order with the
intent or effect of limiting, impairing, or excusing any obligation of Western
under this Agreement, then unless Western's action was expressly directed by
Congress, any Party, by giving thirty days' advance written notice to the other
Parties, may require Western to withdraw from this Agreement, notwithstanding
any other notice period in Section 3.3.1. If such notice is given, the ISO and
Western promptly shall meet to develop arrangements needed to comply with
Western's obligation under Section 3.3.3 concerning non-impairment of ISO
Operational Control responsibilities.

30

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        26.14.2    Federal Entity Indemnity.    No provision of this Agreement
shall require any Participating TO to give an indemnity to Western or for
Western to give an indemnity to any Participating TO. If any provision of this
Agreement requiring Western to give an indemnity to the ISO or the ISO to impose
a sanction on Western is unenforceable against a federal entity, the affected
Party shall submit to the Secretary of Energy or other appropriate Departmental
Secretary a report of any circumstances that would, but for this provision, have
rendered a federal entity liable to indemnify any person or incur a sanction and
may request the Secretary of Energy or other appropriate Departmental Secretary
to take such steps as are necessary to give effect to any provisions of this
Agreement that are not enforceable against the federal entity.

        26.14.3    Recovery for Unenforceable Indemnity.    To the extent that a
Party suffers any loss as a result of being unable to enforce any indemnity as a
result of such enforcement being in violation of Section 26.14.2, it shall be
entitled to seek recovery of such loss through its TO Tariff or through the ISO
Tariff, as applicable.

31

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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 14th day of December, 2004 and thereby incorporates the
following Appendices in this Agreement:

Appendices A

Appendices B

Appendix C

Appendix D

Appendices E

Appendix F

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
151 Blue Ravine Road
Folsom, California 95630
 
 
by:
 
/s/  MARCI L. EDWARDS      

--------------------------------------------------------------------------------

Marcie L. Edwards
Interim Chief Executive Officer
 
 

32

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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 20th day
of December 2004 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 AND ELECTRIC COMPANY
77 Beale Street
San Francisco, California 94105
 
 
by:
 
/s/  JEFFREY BUTLER      

--------------------------------------------------------------------------------

Jeffrey Butler
Senior Vice President, Transmission & Distribution
 
 

33

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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 22nd day
of December, 2004 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
8330 Century Park Court
San Diego, California 92123
 
 
by:
 
/s/  JAMES AVERY      

--------------------------------------------------------------------------------

James Avery
Senior Vice President of San Diego Gas & Electric
 
 

On September 7, 2004, the California Independent System Operator Corporation
("ISO") filed with the Federal Energy Regulatory Commission ("FERC") certain
proposed revisions and additions to the Transmission Control Agreement and
Appendices thereto (the "TCA Revisions"), and to the ISO Tariff (Dockets Nos.
EL04-133-000; ER04-1198-000). San Diego Gas & Electric Company ("SDG&E")
protested, in a filing made with the Commission on September 28, 2004
("Protest"), a number of the TCA Revisions and the ISO Tariff revisions proposed
by the ISO. On November 5, 2004, FERC issued a decision regarding the proposed
revisions to the TCA and the ISO Tariff ("Order"). On December 6, 2004, the ISO
made a compliance filing with respect to the Order ("Compliance Filing"). The
ISO now proposes to file additional revisions to the TCA to reflect the addition
of the City of Pasadena as a Participating Transmission Owner in the ISO.
SDG&E's execution of the TCA is without any prejudice to or waiver of any
argument or position taken by SDG&E in its Protest. SDG&E's execution of the TCA
is not intended to accede to any provision or portion of the Order, the TCA
revisions, the Compliance Filing or the associated ISO Tariff revisions. SDG&E
is hereby reserving all of its rights with respect to the Order, the TCA
Revisions, and the associated ISO Tariff revisions, including but not limited to
all of the issues concerning the TCA (including any and all Appendices thereto)
filed by the ISO on September 7, 2004, the membership of the Western Area Power
Administration, Sierra Nevada Region ("WAPA") in the ISO, and the issues
associated with WAPA's rights in and revenues associated with the Path 15
transmission upgrade.

34

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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 22nd day
of December 2004 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:
 
/s/  RICHARD M. ROSENBLUM      

--------------------------------------------------------------------------------

Richard M. Rosenblum
Senior Vice President, Transmission & Distribution
 
 

On September 7, 2004, the California Independent System Operator Corporation
("ISO") filed with the Federal Energy Regulatory Commission ("FERC") certain
proposed revisions and additions to the Transmission Control Agreement and
Appendices thereto ("TCA Revisions"), and to the ISO Tariff (Dockets Nos.
EL04-133-000; ER04-1198-000). Southern California Edison Company ("Edison")
protested, in a filing made with the Commission on September 28, 2004
("Protest"), a number of the TCA Revisions and the ISO Tariff revisions proposed
by the ISO. On November 5, 2004, FERC issued a decision regarding the proposed
revisions to the TCA and the ISO Tariff ("Order"). On December 6, 2004, Edison
filed a request for rehearing and clarification of the Commission's Order
("Rehearing Petition"), and the ISO made a compliance filing with respect to the
Order ("Compliance Filing"). The ISO now proposes to file additional revisions
to the TCA to reflect the addition of the City of Pasadena as a Participating
Transmission Owner in the ISO. Edison's execution of the TCA is without any
prejudice to or waiver of any argument or position taken by Edison in its
Protest or in its Rehearing Petition. Edison's execution of the TCA is not
intended to and does not accede to any provision or portion of the Order, the
TCA Revisions, the Compliance Filing or the associated ISO Tariff revisions.
Edison is hereby reserving all of its rights with respect to the Order, the TCA
Revisions, and the associated ISO Tariff revisions, including but not limited
to, any and all of the issues concerning the TCA (including any and all
Appendices thereto) filed by the ISO on September 7, 2004, the membership of the
Western Area Power Administration, Sierra Nevada Region ("WAPA") in the ISO, and
the issues associated with WAPA's rights in and revenues associated with the
Path 15 transmission upgrade.

35

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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:
 
/s/  LEONIS C. MALBURG      

--------------------------------------------------------------------------------

LEONIS C. MALBURG, Mayor
ATTEST:
 
 
 
 
/s/  BRUCE V. MALKENHORST          

--------------------------------------------------------------------------------

BRUCE V. MALKENHORST, City Clerk
 
 
 
 
APPROVED AS TO FORM:
 
 
 
 
/s/  EDUARDO OLIVO          

--------------------------------------------------------------------------------

EDUARDO OLIVO, City Attorney
 
 
 
 

36

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32. SIGNATURE PAGE

CITY OF ANAHEIM

        CITY OF ANAHEIM 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 (Anaheim)

Appendix B (Anaheim)

Appendix C

Appendix D

Appendix F

 
 
CITY OF ANAHEIM
 
 
By:
 
    

--------------------------------------------------------------------------------

Marcie L. Edwards
Public Utilities General Manager
ATTEST:
 
 
 
 
    

--------------------------------------------------------------------------------

 
 
 
 
APPROVED AS TO FORM:
 
 
 
 
    

--------------------------------------------------------------------------------

 
 
 
 

37

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33. SIGNATURE PAGE

CITY OF AZUSA

        CITY OF AZUSA 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 (Azusa)

        Appendix B (Azusa)

        Appendix C

        Appendix D

        Appendix F

 
 
CITY OF AZUSA
 
 
By:
 
         

--------------------------------------------------------------------------------

        Cristina C. Madrid
Mayor

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34. SIGNATURE PAGE

CITY OF BANNING

        CITY OF BANNING 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 (Banning)

        Appendix C

        Appendix D

        Appendix F

 
 
CITY OF BANNING
 
 
By:
 
         

--------------------------------------------------------------------------------

        John Hunt
Mayor ATTEST:        

--------------------------------------------------------------------------------

 
 
 
 
APPROVED AS TO FORM:
 
 
 
 

--------------------------------------------------------------------------------

 
 
 
 

39

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35. SIGNATURE PAGE

CITY OF RIVERSIDE

        CITY OF RIVERSIDE 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 (Riverside)

        Appendix B (Riverside)

        Appendix C

        Appendix D

        Appendix F

 
 
 
 
CITY OF RIVERSIDE
3900 Main Street, 4th Floor
Riverside, California 92522
 
 
By:
 
         

--------------------------------------------------------------------------------

        George A. Caravalho, City Manager ATTEST:        

--------------------------------------------------------------------------------

 
 
 
  City Clerk        
APPROVED AS TO FORM:
 
 
 
 

--------------------------------------------------------------------------------

 
 
 
  Supervising Deputy City Attorney        

40

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36. SIGNATURE PAGE

TRANS-ELECT NTD PATH 15, LLC

        TRANS-ELECT NTD PATH 15, LLC has caused this Transmission Control
Agreement to be executed by its duly authorized representative on this 21st day
of December 2004 and thereby incorporates the following Appendices in this
Agreement:

    Appendix A (Trans-Elect)
 
 
Appendix C
 
 
Appendix D
 
 
Appendix F
 
 
Trans-Elect NTD Path 15, LLC
1850 Centennial Park Drive
Suite 480
Reston, VA 20191

    By:             ROBERT D. DICKERSON        

--------------------------------------------------------------------------------

        Robert D. Dickerson
Executive Vice President

41

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37. SIGNATURE PAGE

WESTERN AREA POWER ADMINISTRATION, SIERRA NEVADA REGION

        WESTERN AREA POWER ADMINISTRATION, SIERRA NEVADA REGION has caused this
Transmission Control Agreement to be executed by its duly authorized
representative on this 23rd day of December, 2004 and thereby incorporates the
following Appendices in this Agreement:

    Appendix A (Western)
 
 
Appendix C
 
 
Appendix D
 
 
Appendix F
 
 
Western Area Power Administration, Sierra Nevada Region
Sierra Nevada Region
114 Parkshore Drive
Folsom, CA 95630-4710

 
 
By:
 
                    /s/  JAMES D. KESELBURG      

--------------------------------------------------------------------------------

James D. Keselburg
Regional Manager

42

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37. SIGNATURE PAGE

CITY OF PASADENA

        CITY OF PASADENA has caused this Transmission Control Agreement to be
executed by its duly authorized representative on this 20th day of December,
2004 and thereby incorporates the following Appendices in this Agreement:

    Appendix A (Pasadena)    
 
 
Appendix C (Pasadena)
 
 
 
 
Appendix D
 
 
 
 
Appendix F
 
 
 
 
City of Pasadena Water and Power Department
150 S. Los Robles, Suite 200
Pasadena, CA 91101
By:
 
CYNTHIA J. KURZ
 
     

--------------------------------------------------------------------------------

        Cynthia J. Kurtz
City Manager    
 
 
 
 
ATTEST:
 
 
 
 
JANE L. RODRIGUEZ        

--------------------------------------------------------------------------------

        Jane L. Rodriguez, CMC
City Clerk

43

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TRANSMISSION CONTROL AGREEMENT

APPENDIX A

Facilities and Entitlements

(The Diagrams of Transmission Lines and Associated
Facilities Placed Under the Control of the ISO
were submitted by the ISO on behalf of the Transmission Owners
on March 31, 1997—any modifications are
attached as follows)

44

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Modification of Appendix A1

Diagrams of Transmission Lines and Associated
Facilities Placed Under the Control of the ISO

(submitted by the ISO on behalf of Pacific Gas and Electric Company
Transmission Owner)

        The diagrams of transmission lines and associated facilities placed
under the control of the ISO submitted by the ISO on behalf of PG&E on March 31,
1997 are amended as follows.

        Item 1: Port of Oakland 115 kV Facilities

        Operation Control of the transmission facilities, shown on operating
diagram, East Bay Region (East Bay Division), Sheet No. 1, serving the Port of
Oakland and Davis 115 kV (USN) is not to be transferred to the ISO. These are
special facilities funded by and connected solely to a customer's substation and
their operation is not necessary for control by the ISO pursuant to the
specifications of Section 4.1.1 of the TCA.

        As of the date of execution of the TCA, the California ISO and PG&E are
discussing further modifications to the diagrams of transmission lines and
facilities placed under the control of the ISO. A new version of the diagrams is
to be filed with FERC prior to April 1, 1998. This subsequent version of the
diagrams will reflect all modifications (including those described herein).

45

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APPENDIX A2

List of Entitlements Being Placed under ISO Operational Control

(Includes only those where PG&E is a service rights-holder)

Ref. #

--------------------------------------------------------------------------------

  Entities

--------------------------------------------------------------------------------

  Contract / Rate
Schedule #

--------------------------------------------------------------------------------

  Nature of
Contract

--------------------------------------------------------------------------------

  Termination

--------------------------------------------------------------------------------

  Comments

--------------------------------------------------------------------------------

1.   Pacific Power & Light, SCE, SDG&E   Transmission Use Agreement—PP&L Rate
Schedule with FERC   Transmission   Upon 40 years beginning approx. 1968    
2.
 
SCE, SDG&E
 
California Power Pool—PG&E Rate Schedule FERC No. 27
 
Power pool
 
Terminated
 
5/6/97
3.
 
SCE, SDG&E
 
Calif. Companies Pacific Intertie Agreement—PG&E Rate Schedule FERC No. 38
 
Transmission
 
4/1/2007
 
Both entitlement and encumbrance.
4.
 
SCE, Montana Power, Nevada Power, Sierra Pacific
 
WSCC Unscheduled Flow Mitigation Plan—PG&E Rate Schedule FERC No. 183
 
Operation of control facilities to mitigate loop flows
 
Evergreen, or on notice
 
No transmission services provided, but classify as an entitlement since loop
flow is reduced or an encumbrance if PG&E is asked to cut.
5.
 
TANC
 
Coordinated Operations Agreement—PG&E Rate Schedule FERC No. 146
 
Interconnection, scheduling, transmission
 
1/1/2043
 
Both entitlement and encumbrance.
6.
 
WAPA
 
EHV Transmission Agreement—Contract No. 2947A—PG&E Rate Schedule FERC No. 35
 
Transmission
 
1/1/2005, but service to continue for a period and at charges to be agreed
subject to FERC acceptance.
 
Both entitlement and encumbrance.
7.
 
Various—See Attachment A
 
Western Systems Power Pool Agreement—WSPP Rate Schedule FERC No. 1
 
Power sales, transmission
 
Upon WSPP expiration
 
Both entitlement and encumbrance.
8.
 
Vernon (City of)
 
Transmission Service Exchange Agreement—PG&E Rate Schedule FERC No. 148
 
Transmission
 
7/31/2007, or by extension to 12/15/2042
 
Both entitlement and encumbrance. PG&E swap of DC Line rights for service on
COTP

46

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Supplement To PG&E's Appendix A

Notices Pursuant to Section 4.1.5

        Pursuant to the Transmission Control Agreement Section 4.1.5 (iii), the
transmission system(1) Pacific Gas and Electric Company (PG&E) is placing under
the California Independent System Operator's Operational Control will meet the
Applicable Reliability Criteria in 1998,(2) except (1) for the transmission
facilities comprising Path 15, which do not meet the Western Systems
Coordinating Council's (WSCC) Reliability Criteria for Transmission Planning
with a simultaneous outage of the Los Banos-Gates and Los Banos-Midway 500 kV
lines (for south-to-north power flow exceeding 2500 MW on Path 15),(3) and
(2) with respect to potential problems identified in PG&E's annual assessment of
its reliability performance in accordance with Applicable Reliability Criteria,
performed with participation from the ISO and other stakeholders; as a result of
this process, PG&E has been developing solutions to mitigate the identified
potential problems and submitting them to the ISO for approval.

        Pursuant to Section 4.1.5(i), PG&E does not believe that transfer of
Operational Control is inconsistent with any of its franchise or right of way
agreements to the extent that ISO Operational Control is implemented as part of
PG&E utility service pursuant to AB 1890. However, PG&E can't warrant that these
right of way or franchise agreements will provide necessary authority for ISO
entry or physical use of such rights apart from PG&E's rights pursuant to its
physical ownership and operation of transmission facilities.

--------------------------------------------------------------------------------

(1)Including upgrades and operational plans for the transmission lines and
associated facilities.

(2)Based upon PG&E(1)s substation and system load forecasts for study year 1998,
historically typical generation dispatch and the Applicable Reliability
Criteria, including the current applicable WSCC Reliability Criteria for
Transmission Planning issued in March 1997, the PG&E Local Reliability as stated
in the 1997 PG&E Transmission Planning Handbook Criteria (submitted to the
California ISO Transmission Planning, in writing, on October 20, 1997), and the
NERC Reliability Performance Criteria in effect at the time PG&E was assessing
its system (as of June 1, 1997). PG&E may not meet the WSCC(1)s Disturbance
Performance level (0)D(1) (e.g. outage of three or more circuits on a
right-of-way, an entire substation or an entire generating plant including
switchyard), where the risk of such an outage occurring is considered very small
and the costs of upgrades very high.

(3)The ISO will operate Path 15 so as to maintain system reliability. In
accepting this notice from PG&E, the ISO agrees to work with PG&E and the WSCC
to achieve a resolution respecting the WSCC long-term path rating limit for Path
15, consistent with WSCC requirements. Pending any revision to the WSCC
long-term path rating limit for Path 15, the ISO will continue to operate Path
15 at the existing WSCC long-term path rating limit unless, in the judgment of
the ISO:

        (a)   the operating limit must be reduced on a short-term (e.g.,
seasonal) basis to maintain system reliability, taking into account factors such
as the WSCC guidelines, determination of credible outages and the Operating
Capability Study Group (OCSG) study process; or

        (b)   the operating limit must be reduced on a real-time basis to
maintain system reliability.

        In determining whether the operating limit of Path 15 must be changed to
maintain system reliability, the ISO shall, to the extent possible, work with
the WSCC and the PTOs to reach consensus as to any new interim operating limit.

47

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT No. 104   Original Sheet
No. 104

       

       

       

TRANSMISSION CONTROL AGREEMENT

APPENDIX B

Encumbrances

      

      

      

       

       

       

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002   Effective: January 1, 2003

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 105

PG&E APPENDIX B

List of Encumbrances on Lines and Facilities, and Entitlements Being Placed
under ISO Operational Control (per TCA Appendix A1 & A2)1

(Includes only those where PG&E is a service provider)

Abbreviations Used:   CDWR   = California Department of Water Resources     SCE
  = Southern California Edison Company     SDG&E   = San Diego Gas & Electric
Company     SMUD   = Sacramento Municipal Utility District     TANC   =
Transmission Agency of Northern California     WAPA   = Western Area Power
Administration

Ref. #

--------------------------------------------------------------------------------

  Entities

--------------------------------------------------------------------------------

  Contract/Rate
Schedule #

--------------------------------------------------------------------------------

  Nature of
Contract

--------------------------------------------------------------------------------

  Termination

--------------------------------------------------------------------------------

  Comments

--------------------------------------------------------------------------------

1.   Bay Area Rapid Transit   Service Agreement Nos. 42 and 43 to FERC Electric
Tariff, First Revised Volume No. 12   Network Integration Transmission Service
Agreement and Network Operating Agreement — OAT   10/1/2016    

--------------------------------------------------------------------------------

2.   CDWR   Comprehensive Agreement — PG&E Rate Schedule FERC No.77  
Interconnection and transmission   12/31/2014   Transmission Related Losses

--------------------------------------------------------------------------------

3.   CDWR   Etiwanda Power Plant Generation Exchange — PG&E Rate Schedule FERC
No. 169   Power exchanges   Evergreen, or on 5 years notice    

--------------------------------------------------------------------------------

--------------------------------------------------------------------------------

1/The treatment of current rights, including scheduling priorities, relating to
the listed Encumbrances are set forth in the operating instructions submitted by
the PTO in accordance with the ISO Tariff and the TCA.

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002
 
Effective: January 1, 2003

--------------------------------------------------------------------------------

Ref. #

--------------------------------------------------------------------------------

  Entities

--------------------------------------------------------------------------------

  Contract/Rate
Schedule #

--------------------------------------------------------------------------------

  Nature of
Contract

--------------------------------------------------------------------------------

  Termination

--------------------------------------------------------------------------------

  Comments

--------------------------------------------------------------------------------

4.   CDWR   Extra High Voltage Transmission — PG&E Rate Schedule FERC No. 36  
Transmission   1/1/2005    

--------------------------------------------------------------------------------

5.   Dynegy Power Services   Control Area Transmission Agreement — PG&E Rate
Schedule FERC No. 224   Transmission and various other services   Terminated
12/31/01. PG&E filing of FERC termination pending submittal of a filing to FERC.
   

--------------------------------------------------------------------------------

6.   DOE Laboratories, WAPA   PG&E/WAPA/DOE-SF 10/30/98 Settlement Agreement —
PG&E Rate Schedule FERC No. 147   Transmission Service   3/31/2009    

--------------------------------------------------------------------------------

7.   Lawrence Livermore National Laboratory, WAPA   PG&E/WAPA/DOE -SF Settlement
Agreement — PG&E Rate Schedule FERC No. 147   Standby Transmission Service  
3/31/2009    

--------------------------------------------------------------------------------

8.   Midway-Sunset Co-Generation   Cogeneration Project Special Facilities —
PG&E Rate Schedule FERC No. 182   Interconnection, transmission   1/1/2017    

--------------------------------------------------------------------------------

9.   Minnesota Methane   Service Agreement No. 1, under FERC Electric Tariff,
First Revised Volume No. 12   Firm Point-to-Point Transmission Service — OAT  
10/1/2016   Effective 10/1/96

--------------------------------------------------------------------------------

10.   Modesto Irrigation District   Interconnection Agreement — PG&E Rate
Schedule FERC No.116   Interconnection, transmission, power sales   4/1/2008  
Power sales are coordination sales — voluntary spot sales

--------------------------------------------------------------------------------

11.   NCPA, CSC, CDWR   Castle Rock-Lakeville CoTenancy Agreement — PG&E Rate
Schedule FERC No. 139   Transmission facilities maintenance   Evergreen, or 1
year notice after 1/1/2015    

--------------------------------------------------------------------------------

                     

--------------------------------------------------------------------------------

12.   Path 15 Operating Instructions Settlement — Various, see FERC Docket No.
ER99-1770-001   Exhibit B-1 to this Appendix B to the TCA   Implements
curtailment priorities consistent with various Existing Transmission Contracts.
Establishes Path 15 Facilitator role for PG&E.   3/31/2003    

--------------------------------------------------------------------------------

13.   Power Exchange   Control Area Transmission Service Agreement — PG&E Rate
Schedule FERC No. 186   Transmission and various other services   3/1/2000, or
may extend if Destec does    

--------------------------------------------------------------------------------

14.   Puget Sound Power & Light   Capacity and Energy Exchange — PG&E Rate
Schedule FERC No. 140   Power exchanges   Terminates in 2007 per 5 year advance
written notice received from Puget in 2002.    

--------------------------------------------------------------------------------

15.   San Francisco (City and County of)   Interconnection Agreement — PG&E Rate
Schedule FERC No. 114   Interconnection, transmission and supplemental power
sales   7/1/2015   Power sales are Firm Partial Requirements

--------------------------------------------------------------------------------

16.   Santa Clara (City of)   Mokelumne Settlement and Grizzly Development
Agreement — PG&E Service Agreement No. 20 under FERC Electric Tariff Sixth
Revised Volume No. 5   Transmission, power sale   1/1/2034    

--------------------------------------------------------------------------------

17.   SCE, SDG&E   Calif. Companies Pacific Intertie Agreement — PG&E Rate
Schedule FERC No. 38   Transmission service   7/31/2007   Both entitlement and
encumbrance.

--------------------------------------------------------------------------------

18.   SCE, Montana Power, Nevada Power, Sierra Pacific   WSCC Unscheduled Flow
Mitigation Plan — PG&E Rate Schedule FERC No. 221   Operation of control
facilities to mitigate loop flows   Evergreen, or on notice   No transmission
services provided, but classify as an entitlement since loop flow is reduced or
an encumbrance if we are asked to cut.

--------------------------------------------------------------------------------

                     

--------------------------------------------------------------------------------

19.   Shelter Cove   Interconnection Agreement- PG&E Rate Schedule FERC No. 198
  Distribution   6/30/2006   Effective 8/15/96

--------------------------------------------------------------------------------

20.   Sierra Pacific   Interconnection Agreement — PG&E Rate Schedule FERC No.
72   Interconnection and support services   Evergreen, or 3 years notice    

--------------------------------------------------------------------------------

21.   SMUD   Interconnection Agreement — PG&E Rate Schedule FERC No. 136  
Interconnection and transmission services   12/31/2009    

--------------------------------------------------------------------------------

22.   SMUD   EHV Transmission Agreement — PG&E Rate Schedule FERC No. 37  
Transmission   1/1/2005    

--------------------------------------------------------------------------------

23.   SMUD   Camp Far West Transmission Agreement — PG&E Rate Schedule FERC No.
91   Transmission   No notice of termination filed with FERC    

--------------------------------------------------------------------------------

24.   SMUD   Slab Creek Transmission Agreement — PG&E Rate Schedule FERC No. 88
  Transmission   No notice of termination filed with FERC    

--------------------------------------------------------------------------------

25.   (TANC) and other COTP Participants   Coordinated Operations Agreement —
PG&E Rate Schedule FERC No. 146   Transmission system coordination, curtailment
sharing, rights allocation, scheduling.   1/1/2043, or earlier if other
agreements terminate   Establishes relationship of the COTP to the Control Area
Operator.

--------------------------------------------------------------------------------

26.   (TANC) and other COTP Participants   COTP Interconnection Rate Schedule —
PG&E Rate Schedule FERC No. 144   Interconnection   Upon termination of COTP    

--------------------------------------------------------------------------------

                     

--------------------------------------------------------------------------------

27.
 
TANC
 
Midway Transmission Service / South of Tesla Principles — PG&E Rate Schedule
FERC No. 143
 
Transmission, curtailment priority mitigation,* replacement power
 
Same as the COTP Interim Participation Agreement, subject to exception
 
 

--------------------------------------------------------------------------------

28.   Turlock Irrigation District   Interconnection Agreement — PG&E Rate
Schedule FERC No. 213   Interconnection, transmission, power sales   4/1/2008,
subject to exception   Power Sales are Firm Obligation Sales (Partial
Requirements); Contract Firm (Firm Sale requested by TID); and Coordination
Sales —Voluntary Spot Sales

--------------------------------------------------------------------------------

29.   Vernon (City of)   Transmission Service Exchange Agreement — PG&E Rate
Schedule FERC No. 148   Transmission service   7/31/2007, or by extension to
12/15/2042   Both entitlement and encumbrance. PG&E swap of DC Line rights for
Vernon's COTP rights

--------------------------------------------------------------------------------

30.   WAPA   San Luis Unit — Contract No. 2207A — PG&E Rate Schedule FERC No. 79
  Transmission   4/1/2016    

--------------------------------------------------------------------------------

31.   WAPA, SCE & SDG&E   EHV Transmission Agreement — Contract No. 2947A — PG&E
Rate Schedule FERC No.35   Transmission rights, exchange and coordination, and
transmission service   1/1/2005, unless extended by agreement of the parties.  
Both entitlement and encumbrance.

--------------------------------------------------------------------------------

32.   WAPA   Sale, Interchange and Transmission — Contract No. 2948A — PG&E Rate
Schedule FERC No. 79   Integration, interconnection, transmission and power
sales and exchanges   1/1/2005    

--------------------------------------------------------------------------------

--------------------------------------------------------------------------------

*  Includes use of PG&E's DC Intertie or PDCI for prespecified mitigation of
curtailments over Path 15.

--------------------------------------------------------------------------------

33.   WAPA   Wintu Pumping Plant — Contract No. 2979A — PG&E Rate Schedule FERC
No. 79   Transmission   Concurrent with Contract No. 2948A expiration of
1/1/2005        

--------------------------------------------------------------------------------

    34.   WAPA   Delta Pumping Plant — Contract No. DE-AC65-80WP59000 — PG&E
Rate Schedule FERC No. 63   Transmission   Concurrent with Contract No. 2948A
expiration of 1/1/2005, or 3 years notice        

--------------------------------------------------------------------------------

    35.   WAPA   Healdsburg, Lompoc & Ukiah — Contract No. DE-MS65-83WP59055 —
PG&E Rate Schedule FERC No. 81   Transmission   Concurrent with Contract No.
2948A expiration of 1/1/2005, or 4 years notice        

--------------------------------------------------------------------------------

    36.   WAPA   Sonoma County Water Agency — Contract No. 88-SAO-40002 — PG&E
Rate Schedule FERC No. 126   Transmission   6/30/94, or concurrent with Contract
2948A expiration of 1/1/2005, or 4 years notice        

--------------------------------------------------------------------------------

    37.   WAPA   New Melones — Contract No. 8-07-20-P0004 — PG&E Rate Schedule
FERC No. 60   Transmission   6/1/2032   Per WAPA, commercial operation date for
New Melones was 6/1/82    

--------------------------------------------------------------------------------

    38.   WAPA   Trinity County PUD & Lewiston Power Plant — Contract No.
93-SAO-18008, Supplement No. 42 — PG&E Rate Schedule FERC No. 79   Transmission
  1/1/2005        

--------------------------------------------------------------------------------

   

Lien Mortgage

        The lien of the First and Refunding Mortgage dated December 1, 1920
between PG&E and BNY Western Trust Company, as trustee, as amended and
supplemented and in effect on the date hereof (the "PG&E Mortgage"). The
transfer of Operational Control to the ISO pursuant to this Agreement shall in
no event be deemed to be a lien or charge on the PG&E Property which would be
prior to the lien of the PG&E Mortgage; however, no consent of the trustee under
the PG&E Mortgage is required to consummate the transfer of Operational Control
to the ISO pursuant to this Agreement.

--------------------------------------------------------------------------------

--------------------------------------------------------------------------------

EXHIBIT B-1
(TO PG&E APPENDIX B)
Path 15 Operating Instructions
For Existing Encumbrances Across the Path 15 Interface
April 1, 2003, Revision 1

Introduction

        As contemplated by the ISO Tariff, and as directed by the Federal Energy
Regulatory Commission in its orders on Amendments 3 and 7 to the ISO Tariff,
which were filed by the ISO, Pacific Gas and Electric Company (PG&E) has worked
with the parties with whom it has existing contracts for transmission service
over Path 15 (ETC Parties), in order to develop these Operating Instructions,
which, pursuant to sections 2.4.3.1, 2.4.4.4.1, and 2.4.4.4.3 of the ISO Tariff,
are to be followed by the ISO in operating this constrained Path. The
constraints on Path 15 have been known by all transmission users for many years
and have not been alleviated by the creation or operation of the ISO. The
Operating Instructions which follow are intended to preserve each ETC Party's
pre-existing contract rights1 to transmission service over Path 15 and PG&E's
use of that transmission path. These Operating Instructions will remain in place
until PG&E submits replacement instructions to the ISO. PG&E will not submit
revised operating instructions to become effective prior to January 1, 2005,
except as necessary due to a materially revised ISO market design or to reflect
a material change in ETC rights. All parties reserve all rights to argue for the
implementation of different Operating Instructions and priorities for Path 15
consistent with their ETC contract rights, in the event PG&E submits any revised
Operating Instructions. Further, any party may oppose any modification of these
Operating Instructions that materially affects the rights of such party as set
forth herein. Any Party that believes these Operating Instructions should be
revised may at any time present the suggested revision to PG&E for its
consideration.

--------------------------------------------------------------------------------

1/These operating instructions apply only to unexpired contract rights. Expired
contracts will be removed from these instructions at the time of any revision or
update. The inclusion of an expired contract in these instructions pending a
revision in which the expired contract rights are removed does not confer any
extension of such contract.

--------------------------------------------------------------------------------

Purpose and Objectives

        These Path 15 Operating Instructions provide direction to the ISO
regarding the management of congestion on Path 15 during the ISO's Day Ahead,
Hour Ahead and Real Time markets. The objective of these instructions is to
assure, on an ongoing basis, the efficient use each day of available Path 15
transfer capability while maintaining the transmission rights and priorities on
Path 15 that were in existence as of the ISO Operations Date. These instructions
also clarify individual and joint responsibilities between the ISO as the
Control Area Operator and PG&E as the Path 15 Existing Transmission Contract
(ETC) Facilitator.1

        These instructions are to be adhered to except when the ISO determines
that system reliability requires that other steps be taken. The ISO is solely
responsible for continued system reliability and must unilaterally take all
steps necessary to preserve the system in times of emergency.

--------------------------------------------------------------------------------

1/Specific operating instructions have been provided to the ISO by PG&E in other
documents for each of the Existing Contracts for which it is the Responsible
Participating Transmission Owner on Path 15. In the contract specific
instructions, information is provided on the maximum MW of transmission service
available over the path; the quality of transmission service; daily, hourly and
real time scheduling rights and responsibilities; curtailment procedures; points
of receipt and points of delivery and effective and termination dates of the
contract. This set of additional instructions will clarify how the relative
transmission rights and priorities of the parties should be managed and
administered during times of congestion and possible curtailment on Path 15.

Path 15 Existing Transmission Contract Facilitator (ETC Facilitator)

        PG&E will serve in the capacity of ETC Facilitator to assist the ISO and
to provide necessary guidance to the ISO in the administration of Path 15 ETC
rights. The ETC Facilitator shall:

1.Provide to the ISO, for each hour of the Trading Day, the total amount of
megawatts that should be reserved for use by the ETC Parties.2/Such amounts
shall be provided generally by 8:30 a.m. of each weekday prior to the start of a
Trading Day for the Day-Ahead Market, and generally by 4:30 p.m. of the weekday
prior to the start of a Trading Day for the Hour-Ahead Market.3 Any revisions to
the amount of megawatts reserved for use by the ETC Parties after these times
shall be as provided in ISO operating procedures (currently M-423).

--------------------------------------------------------------------------------

2/The ETC Facilitator's specification of the megawatt reservation amount does
not limit, in any way, ETC Parties' ability to exercise their rights, including
making schedule changes in real time.

3/PG&E and most of the ETC Parties pre-schedule Monday through Friday only. PG&E
generally provides its ETC reservation for Sunday and Monday by
close-of-business on Friday and to the extent practicable, encourages ETC
Parties to provide pre-schedules in time to meet the ISO's Day-Ahead market
deadline.

--------------------------------------------------------------------------------

2.Facilitate all Path 15 schedules from ETC Parties, including those ETC Parties
for which the ETC Facilitator is not the Scheduling Coordinator (SC), unless
otherwise agreed by PG&E and the ETC Party.1

3.Schedule all SC to SC transfers2 that utilize ETC rights across Path 15,
unless otherwise agreed by PG&E and the ETC Party.

4.Inform ETC Parties, affected SCs, and the ISO, pursuant to these Operating
Instructions, when an ETC Party's scheduled usage of Path 15 is reduced and the
amount of such reduction.

5.In performing these tasks, ensure that all transmission rights and priorities
on Path 15 that were in existence as of the ISO Operations Date are maintained
and protected.

--------------------------------------------------------------------------------

1/PG&E may make arrangements with an ETC party to permit that party to self
schedule its Path 15 rights. Any such arrangements will preserve the purpose and
objectives of these Operating Instructions.

2/Currently, Southern California Edison Company (Edison) schedules its SC-SC
transfers for its Existing Contracts directly with the ISO. Upon mutual
agreement by Edison and PG&E, PG&E may become a party to these SC-SC transfers
across Path 15.

Day-Ahead Market Congestion Management

        Prior to the start of the ISO Day-Ahead process, the ETC Facilitator
will provide the ISO with an hourly reservation for ETC schedules utilizing Path
15. The ISO will determine the hourly amount of the Path 15 operating limit
available for New Firm Uses3 for use in its Congestion Management Process4 by
subtracting the ETC megawatt reservation amount from the operating limit for
Path 15 for each hour. After the deadline for receiving Day-Ahead Preferred
Schedules, the ISO performs its Congestion Management Process and determines the
Usage Charges, if any, for each hour of congestion on Path 15. ETC Parties whose
schedules over Path 15 are submitted to the ISO by the ETC Facilitator will not
be assessed Usage Charges associated with their Path 15 schedules by the ETC
Facilitator.

--------------------------------------------------------------------------------

3/Regulatory Must Take and Regulatory Must Run resources that contribute to the
"imputed use" of Path 15 are treated as New Firm Uses for this purpose. The
"imputed use" is the expected power flow resulting from the load, interchange,
and resource schedules of all SCs.

4/The ISO's Congestion Management Process uses Adjustment Bids to reduce the
amount of New Firm Use, if necessary, so that such use does not exceed the
amount of the Path 15 operating limit less the ETC reservation megawatt amount.

Hour-Ahead Market Congestion Management

        Because scheduling timelines in ETC Parties' contracts (including third
party contracts using ETC Party rights) differ from the ISO's scheduling
timeline, some pre-schedules from such parties are likely to be scheduled in the
Hour-Ahead Market. The ETC Facilitator's ETC megawatt reservation amount
submitted in the Day-Ahead Market is intended to provide sufficient reservation
to accommodate the schedules submitted in the Hour-Ahead Market. After the close
of the Hour-Ahead Preferred Market, the ISO performs its Congestion Management
Process and determines the Usage Charges, if any, for such hour on Path 15. ETC
Parties whose schedules over Path 15 are submitted to the ISO by the ETC
Facilitator will not be assessed Usage Charges associated with their Path 15
schedules by the ETC Facilitator.

--------------------------------------------------------------------------------

Real Time Curtailment Priorities

        Any and all ETC Parties' rights (including third party contracts using
ETC Party rights) to change schedules after the close of the ISO's Hour-Ahead
market will continue to be honored. In the event of curtailments on Path 15
South-to-North in real time, the ETC Facilitator will determine the appropriate
order and magnitude of curtailments given the circumstances that occur in real
time and the terms and provisions of the ETCs. This determination will be made
consistent with the following table "Path 15 South-to-North Real-Time
Curtailment Priorities", a copy of which is Attachment A, which is incorporated
into and made a part of these Path 15 Operating Instructions by this reference.

        In Attachment A, the relative priorities of the various ETC Parties'
transmission service rights across Path 15 in real-time are identified by
grouping the various rights into separate blocks and ordering the blocks by
their relative priority. Attachment A addresses only Path 15 South to North
real-time curtailment priorities. The Path 15 North-to-South real-time
curtailment priorities will be addressed in a separate and distinct set of
Operating Instructions and will be separately submitted to the ISO after review
by the Path 15 ETC Parties.

--------------------------------------------------------------------------------

ATTACHMENT A

EXHIBIT B-1
(TO PG&E APPENDIX B)

Path 15 Real-Time South-to-North Curtailment Priorities1/

Priority Group

  ETC/Priority Holder

  South-to-North

--------------------------------------------------------------------------------

12   CDWR EHV Agreement3
SCE CCPIA encumbered rights
SDG&E CCPIA encumbered rights
PG&E must-take encumbrances
CDWR Comprehensive Agreement   300 MW
320 MW
0
4
810 MW

--------------------------------------------------------------------------------

2   TANC SOTP5   300 MW

--------------------------------------------------------------------------------

3   TID IA (Reserve rights)   32 MW

--------------------------------------------------------------------------------

46   PG&E SOTP
SCE CCPIA unencumbered rights/
SDG&E CCPIA unencumbered rights/   500 MW
347 MW
109 MW

--------------------------------------------------------------------------------

5   New ETC Requests7/   unspecified     Other "As Available"    

--------------------------------------------------------------------------------

1/This table may change from time to time as existing contracts are terminated,
or the rights under those contracts change (e.g., termination of a QF contract).

2/Curtailments within Priority Group 1 are based on each party's contract right
or entitlement amount.

3/CDWR has both EHV and Comprehensive Agreement rights. When curtailments are
required, CDWR's EHV schedules are curtailed beginning at the then-current
maximum operating limit of the path (as it may increase or decrease from time to
time).

4/The Priority Group 1 capacity available to PG&E south-to-north in real time is
the capacity remaining after CDWR's EHV and SCE/SDG&E's CCPIA Existing Contract
schedules (as may be curtailed) are subtracted from the amount of available
capacity. This remaining capacity is available for CDWR's Comprehensive
Agreement schedules and PG&E's must-take encumbrances. PG&E's must-take
encumbrances rights correspond to the amount of Path 15 south-to-north transfer
capability historically available for PG&E must-take generation in ZP26,
including but not limited to the generation of PG&E's Diablo Canyon Nuclear
Power Plant, minus PG&E load in ZP26. As used in this footnote, "PG&E's
must-take encumbrances" means an amount of transmission transfer capability that
is reserved for ISO New Firm Uses across Path 15 south-to-north that is the
lesser of PG&E's must-take encumbrances rights defined above or the IOU imputed
use of Path 15. The IOU imputed use of Path 15 is the expected power flow
resulting from the load, interchange and resource schedules of PG&E, SCE and
SDG&E across Path 15. CDWR's Comprehensive Agreement schedules are curtailed,
pro rata with the Priority Group 1 capacity available to PG&E, beginning at the
then-current maximum operating limit of the path (as it may increase or decrease
from time to time).

5/TANC's 300 MW is firm bi-directional service using the Points of Receipt and
Delivery set forth in section 2.4 of the SOTP and in accordance with the
Curtailment Priorities set forth in section 3.2 of the SOTP. PG&E supports these
transfer capabilities by implementing mitigation measures when necessary, to the
extent such measures are available, up to a total of 200 MW south-to-north and
700 MW north-to-south. These mitigation measures consist of switching PG&E's
scheduled transmission service from the AC Lines to the DC Line.

6/Priority Group 4 is available for ISO use for New Firm Uses.

7/"New ETC Requests" includes any requested service by an ETC in excess of the
rights set forth in this table for Priority Groups 1-4, provided that this
footnote shall not apply to arrangements between or among PG&E and one or more
ETC Parties for future capacity upgrades, if such parties agree, or an existing
contractual commitment provides otherwise.

--------------------------------------------------------------------------------

ATTACHMENT 1

CALIFORNIA ISO PATH 15 ATC DETERMINATION METHODOLOGY

Note: This document is intended to explain the procedures for calculation and
allocation of Available Transfer Capacity (ATC) over Path 15 pursuant to the
Federal Energy Regulatory Commission's May 22, 2002 order in Docket
ER99-1770-001 (99 FERC ¶ 61,212). It should not be interpreted in any way to
modify Exhibit B-1 of the Transmission Control Agreement.

California ISO calculation of Path 15 ATC in the Day Ahead and Hour Ahead
Markets (largely described in Exhibit B-1):

1.The ISO calculates the Operating Transfer Capability (OTC) for Path 15 and
calculates the Existing Contract (ETC) rights of the Edison ETC rights holders.

2.By 8:30 a.m. of each week day prior to the start of the Trading Day PG&E
submits to the ISO the ETC capacity to be reserved in the Day Ahead Market, and
by 4:30 p.m. of each week day prior to the start of the Trading Day PG&E may
submit a revised ETC reservation amount to the ISO for the ETC capacity to be
reserved in the Hour Ahead Market. Any revisions to the amount of megawatts
reserved for use by the ETC Parties after these times shall be as provided in
ISO operating procedures (currently M-423). (The amount reserved by PG&E in the
Day-Ahead Market is based on pre-scheduled amounts submitted by the
PG&E-facilitated ETC rights holders to PG&E by 8:15 a.m. or on the previous
day's schedules and PG&E's view of the capacity that will be used by such ETC
rights holders, with an additional amount of margin to ensure that sufficient
capacity is available to the PG&E-facilitated ETC rights holders that wish to
modify their pre-scheduled use of their capacity in the Hour-Ahead and real time
scheduling processes. PG&E can but does not ordinarily provide updates in
advance of the Hour Ahead Market.)

3.The ISO subtracts the capacity reserved for the PG&E-facilitated and Edison
ETC rights holders over Path 15 from the Path 15 OTC to determine the ATC
available for New Firm Uses (NFU).

        Allocation of ATC on Path 15 in real-time, i.e. calculate ETC available
rights and curtailments based on applicable priorities (largely described in
Exhibit B-1 and Attachment A to Exhibit B-1):

1.Path 15 OTC: Confirm Path 15 South-to-North OTC and adjust for Unscheduled
Flows.

2.Priority Group 1 ETCs: Retrieve all actual schedules by ETC Parties in
Priority Group 1 (as set forth in Attachment A to Exhibit B-1) from all SCs
scheduling on behalf of such parties over Path 15.

3.PG&E Must Take Encumbrance and IOU Imputed Use: Retrieve amounts for PG&E
Must-Take Encumbrance (which is available for NFU, but needed to assess certain
parties' ETC rights) and the IOU Imputed Use—formerly PX Imputed Use—(as set
forth in footnote 4 of Attachment A to Exhibit B-1). Adjust, if necessary, for
known changes in generation amounts from amounts forecast in Day Ahead Markets.

4.Capability Available to Lower Priority ETCs: Subtract from the Path 15 OTC the
amounts for Priority Group1 ETCs actual net south-to-north scheduled amounts (2
above) and for each hour the lesser of PG&E's Must Take Encumbrance or the IOU
Imputed Use (3 above). This is the amount of transmission capacity available for
lower priority ETCs (as set forth in Attachment A to Exhibit B-1).

5.ATC Available for NFU: All ATC not used by ETC Parties is available for NFU
(this includes any amount remaining after subtracting from the Path 15 OTC the
Priority Group 1-3 ETCs actual scheduled amounts as they are adjusted for any
real-time curtailments). Thus the lesser of the PG&E Must Take Encumbrance or
the IOU Imputed Use has priority over Priority 2-3 ETCs, but shares the
available OTC with Priority 1 ETCs actually scheduled amounts.

--------------------------------------------------------------------------------

Thus, in real time, NFU access to transmission capacity over Path 15 has two
levels of priority:

•First, as the capacity represented by the lesser of the PG&E Must Take
Encumbrance or the IOU Imputed Use amount, which has priority over lower
priority ETCs and may use the unscheduled rights of Priority 1 ETC rights
holders, and

Second, as any capacity that remains after subtracting from OTC the actual
schedules for Priority 1-3 ETCs and the NFU amount above.

        However, operationally the ISO does not allocate particular NFU
schedules to a particular priority but rather treats all NFU schedules as a
single block. The following example illustrates how this occurs:

        Assume that OTC over Path 15 is 2,500 MW in a given hour and that there
is no Unscheduled Flow. Assume that there are 800 MW of Priority 1 ETC actual
schedules, 1,000 MW of PG&E Must Take Encumbrance, 200 MW of lower priority ETC
actual schedules, and 1,500 MW of NFU. This NFU amount, as described above, uses
the 1,000 MW of PG&E Must Take Encumbrance and the amount of capability
remaining after accommodating the lower priority ETC schedules. Assume that Path
15 is derated to 2,000 MW. In this example, no ETC curtailment is indicated,
thus the ISO must take actions to reduce the flow. The ISO would use Adjustment
Bids and Supplemental Energy bids in the BEEP stack to attempt to accommodate
the transactions without curtailing any of the NFU schedules. Assume that after
bids in the BEEP stack are exhausted, 1,200 MW of NFU remain on Path 15 and
curtailments are required (this occurrence is rare). If feasible within the time
available to manage the Path derating, the 1,200 MW of NFU would be curtailed on
a pro-rata basis to result in NFU of 1,000 MW. Assume that Path 15 is further
derated to 1,000 MW and that all bids in the BEEP stack remain exhausted. If
feasible within the time available to manage the Path derating, the 1,000 MW of
NFU (the amount that is using the priority rights equal to the amount of the
PG&E Must Take Encumbrance) would be curtailed on a pro-rata basis to result in
NFU of 200 MW and the lower priority ETC schedules would be curtailed to 0 MW.
Note: Priority 1 ETC rights are determined on the basis of the Path 15 OTC, and
only curtailed if the Priority 1 ETC rights holder's schedule exceeds its
contract right or entitlement amount.

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TRANSMISSION CONTROL AGREEMENT

APPENDIX C

ISO MAINTENANCE STANDARDS

1.     DEFINITIONS(1)

        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(IMS) 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(IMS) 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(IMS) condition for a period that exceeds
the period specified in the Scheduled Outage request, in which case a Forced
Outage(IMS) 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.

        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".

--------------------------------------------------------------------------------

(1)A term followed by the supercript "(IMS)" denotes a term which has a special,
unique definition in this Appendix.

48

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        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

--------------------------------------------------------------------------------

  Range of Nominal Voltage

--------------------------------------------------------------------------------

69 kV   < 70 kV 115 kV   110 - 161 kV 230 kV   200 - 230 kV 345 kV   280 - 345
kV 500 kV   500 kV HVDC   HVDC

2.     INTRODUCTION

        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).

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;

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•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 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.

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

50

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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 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(IMS) 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(IMS) duration has been capped at
72 hours so that excessively long Forced Outages(IMS) do not skew the data as to
detract from the meaningfulness and interpretation of the control charts for
accumulated Forced Outage(IMS) duration. This is not to say that an excessively
long Forced Outage(IMS) is not a concern. Rather, such Forced Outages(IMS)
should be investigated to assess the reasons for their extended duration.

        The performance monitoring system requires use of separate control
charts for each Voltage Class and PTO. Existing Forced Outage(IMS) 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(IMS) 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(IMS) frequency for all Transmission Line
Circuits;

•The annual average accumulated Forced Outage(IMS) duration for those
Transmission Line Circuits which experience Forced Outages(IMS); and

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•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 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(IMS) 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.

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.

52

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        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(IMS) 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
Outage(IMS) 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, 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.

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(IMS) 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(IMS) data through December 31 of each year. Separate Forced Outage(IMS)
frequency and accumulated Forced Outage(IMS) 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 data for the calendar year in question.

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Forced Outage(IMS) Frequency:

        The Forced Outage(IMS) frequency (fik) of the ith Transmission Line
Circuit shall equal the total number of Forced Outages(IMS) that occurred on the
ith 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(IMS), then these should be counted as two
Forced Outages(IMS). Multiple Forced Outages(IMS) 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(IMS) 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(IMS) data for that
Transmission Line Circuit shall be handled the same as those for any other
Transmission Line Circuit.

Accumulated Forced Outage(IMS) Duration:

        The accumulated Forced Outage(IMS) duration in minutes shall be
calculated as follows for each of the Transmission Line Circuits having a Forced
Outage(IMS) frequency (fik) greater than zero for the calendar year k:

    fik     dik = S oijk         j = 1    

where

dik = accumulated duration of Forced Outages(IMS) (total number of Forced
Outage(IMS) minutes) for the ith Transmission Line Circuit having a Forced
Outage(IMS) frequency (fik) greater than zero for the calendar year k.

fik =  Forced Outage(IMS) frequency as defined above for calendar year k.

oijk = duration in minutes of the jth Forced Outage(IMS) which occurred during
the kth calendar year for the ith Transmission Line Circuit. See Notes 1 and 2.

        The durations of extended Forced Outages(IMS) shall be capped as
described in Section 4.2.2. "Capping of Forced Outage(IMS) 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(IMS) 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(IMS) data reporting
scheme, and that they provide an appropriate gauge of performance.

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4.2.2.    Capping of Forced Outage(IMS) 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(IMS) 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 Outages(IMS) which: 1) were caused by events outside the PTO's system
including those Outages which originate in other TO systems, other electric
utility 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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CHART [g88844.jpg]

Figure 4.3.1 Sample Control Chart

•Index 1: Annual Average Forced Outage(IMS) Frequency for All Transmission Line
Circuits.

•Index 2: Annual Average Accumulated Forced Outage(IMS) Duration for those
Transmission Line Circuits with Forced Outages(IMS).

•Index 3: Annual Proportion of Transmission Line Circuits with No Forced
Outages(IMS).

        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(IMS), the limits
are based on standard control chart techniques for binomial proportion data. For
the other two 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.

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        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 Class and PTO as described below utilizing the Availability
Measures discussed in Section 4.2.

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Annual Average Forced Outage(IMS) Frequency for All Transmission Line Circuits
(Index 1):

Fvc,k = 1

--------------------------------------------------------------------------------

Nk Nk
S    fik
i = 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(IMS) 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.
fik =
frequency of Forced Outages(IMS) for the ith Transmission Line Circuit as
calculated in accordance with Section 4.2.1 for calendar year k.

Annual Average Accumulated Forced Outage(IMS) Duration for those Transmission
Line Circuits with Forced Outages(IMS) (Index 2):

Dvc,k
=
1

--------------------------------------------------------------------------------

No,k
No,k
S    dik
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(IMS) for all Transmission Line Circuits within a Voltage Class which
experienced Forced Outages(IMS) during the calendar year k.
No,k =
number of Transmission Line Circuits in the Voltage Class for which the Forced
Outage(IMS) frequency Availability Measure (fik) 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(IMS) for the ith Transmission Line
Circuit having a Forced Outage(IMS) frequency Availability Measure (fik) 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(IMS)
(Index 3):

Pvc,k = Nk - No,k

--------------------------------------------------------------------------------

Nk    

where

Pvc,k = index for the proportion of Transmission Line Circuits for the Voltage
Class with no Forced Outages(IMS) 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(IMS) frequency Availability Measure (fik) 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.

58

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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(IMS) Frequency for All Transmission Line Circuits, Annual
Average Accumulated Forced Outage(IMS) Duration for Transmission Line Circuits
with Forced Outages(IMS), and Annual Proportion of Transmission Line Circuits
with No Forced Outages(IMS)) 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(IMS) 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(IMS) 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 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(IMS) Frequency

    Y    Nk   Y     CLfvc = S  S fik / ( S    Nk)         k-1 i-1   k=1    

where

CLfvc = center control line value for the Forced Outage(IMS) 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 Outage(IMS) Duration for those Transmission
Line Circuits with Forced Outages(IMS)

    Y    No,k   Y     CLdvc = S  S dik / ( S    No,k)         k-1 i-1   k=1    

59

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where

CLdvc = center control line value for accumulated Forced Outage(IMS) 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 (fik) was greater than zero.

CL for Annual Proportion of Transmission Line Circuits with No Forced
Outages(IMS)

    Y     CLPvc = S    (Nk - No,k)
k=1        

--------------------------------------------------------------------------------

Y     
S  Nk
k=1        

where

CLPvc = center control line value for the proportion of Transmission Line
Circuits in the Voltage Class with no Forced Outages(IMS) 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 Voltage Classes Containing Four
or More Transmission Line Circuits with Forced Outages(IMS) 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 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(IMS) 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.

60

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        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 × 15 = 150 Forced Outage(IMS) durations
available for bootstrap sampling. Place these 150 Forced Outage(IMS) 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 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(IMS) 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 251st 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(IMS) 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(IMS) 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.

61

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        For the general case, let M = the number of accumulated Forced
Outage(IMS) durations (or Forced Outage(IMS) 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 kth year are determined using the normal approximation to the
binomial distribution. The formulas are:

        UCL = CLPvc + 3SPvc,k             LCL = CLPvc - 3SPvc,k

        UWL and LWL are calculated by replacing the "3" above with a "2".

        and

GRAPHIC [g74894.jpg]

where

SPvc,k = standard deviation for the annual proportion of Transmission Line
Circuits in the Voltage Class with no Forced Outages(IMS) for each (kth) 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.

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 - P1))/ n

        UWL = (X1+ (P2 - P1)/(P3 - P1))/ n

        LWL = (X1+ (P2 - P1)/(P3 - P1))/ n

        LCL = (X1+ (P2 - P1)/(P3 - P1))/ n

        Where

62

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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 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 P1 = 0.74 and is closest to the 99.75 percentile
value and represents the 99 percentile then P1 = 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 P1 = 0.74 and represents the 99th percentile for the case
where 78 lines didn't have any outages then X1 = 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.

•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.

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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 UWL or LWL 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 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

64

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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

        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.

65

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Table 4.3.1 Performance Indications Provided by Control Chart Tests

 
   
   
  Performance Status Indicated
by Test Results

--------------------------------------------------------------------------------

 
  Test

--------------------------------------------------------------------------------

Control Chart
Type

--------------------------------------------------------------------------------

  Number

--------------------------------------------------------------------------------

  Results

--------------------------------------------------------------------------------

  Improvement

--------------------------------------------------------------------------------

  Degradation

--------------------------------------------------------------------------------

Annual
Average
Forced
Outage(IMS)
Frequency   1

2

3

4
    value is above the UCL
value is below the LCL when LCL>0
v1 or more consecutive values above the CL
v2 or more consecutive values below the CL
2 out of 3 values above the UWL
2 out of 3 values below the LWL
6 consecutive values increasing
6 consecutive values decreasing  
4

4

4

4   4

4

4

4
 
Annual
Average
Accumulated
Forced
Outage
Duration
 
1

2

3

4
 
 
value is above the UCL
value is below the LCL when LCL>0
v1 or more consecutive values above the CL
v2 or more consecutive values below the CL
2 out of 3 values above the UWL
2 out of 3 values below the LWL
6 consecutive values increasing
6 consecutive values decreasing
 

4

4

4

4
 
4

4

4

4
 
Annual
Proportion
of
Transmission
Line Circuits
with No
Forced
Outages
 
1

2

3

4
 
 
value is above the UCL
value is below the LCL when LCL>0
v1 or more consecutive values above the CL
v2 or more consecutive values below the CL
2 out of 3 values above the UWL
2 out of 3 values below the LWL
6 consecutively increasing values
6 consecutively decreasing values
 
4

4

4

4
 
 

4

4

4

4

4.4. Outage(IMS) 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(IMS) 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.

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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

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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•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 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.

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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.

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.

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        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 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 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.

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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.

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)

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b)    Station Maintenance

•Circuit Breakers

•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 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.

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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.

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.

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CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 181

       

       

       

TRANSMISSION CONTROL AGREEMENT

APPENDIX D

Master Definitions Supplement

      

      

      

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002   Effective: January 1, 2003

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Actual Adverse Tax Action
 
A plan, tariff provision, operating protocol, action, order, regulation or law
issued, adopted, implemented, approved, made effective, taken or enacted by the
ISO, the FERC, the IRS or the United States Congress, as applicable, that likely
adversely affects the tax- exempt status of any Tax Exempt Debt issued by, or
for the benefit of, a Tax Exempt Participating TO or that, with the passage of
time, likely would adversely affect the tax-exempt status of any Tax Exempt Debt
issued by, or for the benefit of, a Tax Exempt Participating TO if the affected
facilities were to remain under the Operational Control of the ISO; provided,
however, no Actual Adverse Tax Action shall result with respect to a Tax Exempt
Participating TO that initiates such a plan, tariff provision, operating
protocol, action, order, regulation or law; provided further, however, that the
immediately preceding proviso shall not include private letter ruling requests
or related actions; provided further, that no Actual Adverse Tax Action shall
result in connection with Local Furnishing Bonds if the adverse effect on the
tax-exempt status of the Local Furnishing Bonds reasonably could be avoided by
application of the procedures set forth in Section 4.1.2 or in Section 2.3.2 and
Appendix B.
Adverse Tax Action Determination
 
A determination by a Tax Exempt Participating TO, as supported by (i) an opinion
of its (or its joint action agency's) nationally recognized bond counsel, or
(ii) the IRS (e.g., through a private letter ruling received by a Tax Exempt
Participating TO or its joint action agency), that an Impending Adverse Tax
Action or an Actual Adverse Tax Action has occurred.
AGC (Automatic Generation Control)
 
Generation equipment that automatically responds to signals 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 Criteria
 
The reliability standards established by NERC, WSCC, and 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 Outage
 
A Maintenance Outage which has been approved by the ISO through the ISO Outage
Coordination Office.      

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Available Transfer Capacity
 
For a given transmission path, the capacity rating in MW of the path established
consistent with ISO and WSCC transmission capacity rating guidelines, less any
reserved uses applicable to the path.
Black Start
 
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.
Business Day
 
Monday through Friday, excluding federal holidays and the day after Thanksgiving
Day.
Congestion
 
A condition that occurs when there is insufficient Available Transfer Capacity
to implement all Preferred Schedules simultaneously. "Congested" shall be
construed accordingly.
Congestion Management
 
The alleviation of Congestion in accordance with applicable ISO Protocols and
Good Utility Practice.
Control Area
 
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 system(s); ii) maintain scheduled interchange with
other Control Areas, within the limits of Good Utility Practice; iii) maintain
the 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.
CPUC
 
The California Public Utilities Commission, or its successor.
Critical Protective System
 
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.
Day-Ahead Market
 
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.
Demand
 
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=1MW, etc.      

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Eligible Customer
 
(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 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 System)
 
A computer control system used by electric utility dispatchers to 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 Operations Date.
End-Use Customer or End-User
 
A purchaser of electric power who purchases such power to satisfy a Load
directly connected to the ISO Controlled Grid or to a Distribution System and
who does not resell the power.
Energy
 
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.
Entitlements
 
The right of a Participating TO obtained through contract or other means to use
another entity's transmission facilities for the transmission of Energy.
Existing Contracts
 
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 Participating TO for the cost of a Facility Study.      

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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.
FERC
 
The Federal Energy Regulatory Commission or its successor.
FIITC (Firm Import Interconnection Transmission Capacity)
 
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.
Forced Outage
 
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.
FPA
 
Parts II and III of the Federal Power Act, 16 U.S.C. § 824 et seq., as they may
be amended from time to time.
Generating Unit
 
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 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.      

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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.
Impending Adverse Tax Action
 
A proposed plan, tariff, operating protocol, action, order, regulation or law
that, if issued, adopted, implemented, approved, made effective, taken or
enacted by the ISO, the FERC, the IRS or the United States Congress, as
applicable, likely would adversely affect the tax-exempt status of any Tax
Exempt Debt issued by, or for the benefit of, a Tax Exempt Participating TO if
the affected facilities were to remain under the Operational Control of the ISO;
provided, however, that with respect to a proposed federal law, such proposed
law must first have been approved by (i) one of the houses of the United States
Congress and (ii) at least one committee or subcommittee of the other house of
the United States Congress; provided further, however, no Impending Adverse Tax
Action shall result with respect to a Tax Exempt Participating TO that initiates
such a plan, tariff provision, operating protocol, action, order, regulation or
law; provided further, however, that the immediately preceding proviso shall not
include private letter ruling requests or related actions; provided further,
that no Impending Adverse Tax Action shall result in connection with Local
Furnishing Bonds if the adverse effect on the tax-exempt status of the Local
Furnishing Bonds reasonably could be avoided by application of the procedures
set forth in Section 4.1.2 or in Section 2.3.2 and Appendix B.
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, 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.
Interconnection Agreement
 
A contract between a party requesting interconnection and the Participating TO
that owns the transmission facility with which the requesting party wishes to
interconnect.

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IRS   The United States Department of Treasury, Internal Revenue Service, or any
successor thereto.
ISO (Independent System Operator)
 
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.
ISO ADR Procedures
 
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.
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 Committee
 
A committee appointed by the ISO Governing Board pursuant 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 Office
 
The office established by the ISO to coordinate Maintenance 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 Tariff, dated March 31,
1997, as it may be modified from time to time.
Load
 
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.
Local Furnishing Bond
 
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).      

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Local Furnishing Participating TO
 
Any Tax-Exempt Participating TO that owns facilities financed by Local
Furnishing Bonds.
Local Regulatory Authority
 
The state or local governmental authority responsible for the regulation or
oversight of a utility.
Local Reliability Criteria
 
Reliability criteria established at the ISO Operations Date, unique to the
transmission systems of each of the Participating TOs.
Maintenance Outage
 
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, transmission, or distribution of Energy
or Ancillary Services into, out of, or through the ISO Controlled Grid.
Monthly Peak Load
 
The 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 of the ISO
Tariff.
Non-Participating Generator
 
A Generator that is not a Participating Generator.
Non-Participating TO
 
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 for use.      

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Operational Control
 
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 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 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 System)
 
The ISO computer control system used to monitor the real time performance of the
various elements of the ISO Controlled Grid, control Generation, and perform
operational power flow studies.      

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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 transmission addition or upgrade in accordance
with Section 3.2 of the ISO Tariff.
RAS (Remedial Action Schemes)
 
Protective systems that typically utilize a combination of 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 Generation
 
Hydro Spill Generation and Generation which is required to run 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 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 Transmission Group)
 
A voluntary organization approved by FERC and composed of 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 Control and Data Acquisition)
 
A computer system that allows an electric system operator to 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.      

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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.
Self-Sufficiency or Self-Sufficient
 
A Participating TO for which the sum of its Dependable 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 TO
 
A Participating TO that is the beneficiary of outstanding Tax-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 Agreement)
 
The agreement between the ISO and Participating TOs 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.      

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UDC (Utility Distribution Company)
 
An entity that owns a Distribution System for the delivery of 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, 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 Network)
 
An electronic network that facilitates communications and data 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 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.
Withdraw for Tax Reasons or Withdrawal for Tax Reasons
 
In accordance with Section 3.4 of this Agreement, withdrawal from this
Agreement, or withdrawal from the ISO's Operational Control of all or any
portion of the transmission lines, associated facilities or Entitlements that
were financed in whole or in part with proceeds of the Tax Exempt Debt that is
the subject of an Impending Adverse Tax Action or an Actual Adverse Tax Action.
WSCC (Western System Coordinating Council)
 
The Western Systems Coordinating Council or its successor.

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TRANSMISSION CONTROL AGREEMENT

APPENDIX E

Nuclear Protocols

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DIABLO CANYON NUCLEAR POWER PLANT
UNITS 1 & 2

REQUIREMENTS FOR OFFSITE
POWER SUPPLY OPERABILITY
REVISION 1

DCPP 1&2 REQUIREMENTS FOR OFFSITE POWER SUPPLY OPERABILITY

OVERVIEW

        The DCPP Operating License and Technical Specifications require two
physically independent sources (not necessarily on separate right of way)
designed and located so as to minimize to the extent practical the likelihood of
their simultaneous failure under operating and postulated accident and
environmental conditions. A switchyard common to both sources is acceptable.
Each of these sources shall be designed to be available in sufficient time
following a loss of all DCPP onsite alternating current power supplies and the
other offsite electric power circuit. One of these sources shall be designed to
be available within a few seconds following a loss-of-coolant accident. For
DCPP, the sources available within seconds are the 230 kV grid interface and the
second source is the 525 kV grid interface.

        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 (safety
related and non-safety related) are transferred to the 230 kV grid. In addition
DCPP has a delayed transfer capability to the 525 kV grid. 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 either source of 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 either source 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 voltages (at the DCPP
switchyards) must stay within the range of 207 kV to 240 kV and 525 kV to 545 kV
under post accident operating conditions. During normal operation, the 230 kV
voltage must maintain above 207 kV such that when DCPP transfers its load from
the onsite source to the offsite source the voltage does not decrease below 207
kV. During normal operation, the 230 kV voltage at DCPP 230 kV switchyard should
meet the 230 kV voltage requirements identified in PG&E Operating Instruction
O-23. Otherwise, that offsite power source may be considered Inoperable. Since a
design basis accident can result in a unit trip, it is imperative that the trip
does not impair the operability of the offsite power system. Therefore,
following a trip of a DCPP unit (i.e., the unit breakers open) and assuming the
other DCPP unit was already shutdown, the DCPP switchyard voltage must recover
to and be maintained at or above 207 kV within 16 seconds following the unit
trip. If this condition cannot be met, then the offsite power source is
considered Inoperable, and action must be taken to shut down the operating DCPP
unit(s). In addition, the 500 kV 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

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degraded grid conditions are recognized, assessed and immediately communicated
to the DCPP operating staff for Operability determination.

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 as
necessary. 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 the ISO,
PG&E and the DCPP operating staff for operability determination. Changes in the
operation of the transmission network that conflict with these requirements
requires prior approval by PG&E.

1.Three transmission lines into the 500 kV DCPP switchyard and two lines into
the 230 kV DCPP switchyard are normally in service. Any change that alters the
performance capabilities of either offsite source at the applicable switchyard
requires prior approval by PG&E (DCPP) and the ISO.

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 230 kV systems, 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 kV and 230 kV offsite
power source should be capable of providing 130 MVA (i.e. dual unit orderly
shutdown) to Diablo Canyon for normal operation, safe shutdown, and design basis
accident mitigation.

3.The minimum grid voltage at DCPP 230 kV switchyard shall be maintained at or
above 230 kV for normal operation with all Los Padres 230 kV elements (See list
below) in service. In the event of a system disturbance or line outage that can
cause the DCPP voltage to dip below 230 kV, including the trip of a DCPP unit,
the grid voltage shall recover to 207 kV or above within 16 seconds.

Los Padres Area Major 230 kV Elements

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  Major 500 kV Elements

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DCPP—Mesa Line   DCPP-Gates Line Morro Bay—Mesa Line   DCPP-Midway Line #1 & #2
Line Morro May—DCPP Line Morro Bay—Templeton Line Morro Bay—Midway Line #1 or #2
Line Morro Bay—Gates Line #2 Line Largest Los Padres area generator other than
DCPP DCPP 230 kV capacitor banks Mesa 115 kV capacitor banks

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 230 kV and 500 kV switchyards shall be
maintained at or below 240 kV and 545 kV, respectively, unless required to
preserve transmission network integrity.

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6.The 500 kV system shall be maintained between 525 kV and 545 kV. Operation of
DCPP is limited between 24.375 kV and 26.25 kV (i.e. 0.975 p.u. and 1.05 p.u.).

        PG&E, in coordination with the ISO, shall perform and update system
studies based on changing grid conditions (load growth, etc.) to identify
critical conditions that could render the DCPP 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 that 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 both PG&E (Transmission Planning, Electric System Operations and
DCPP) and the ISO. 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 both PG&E
(Transmission Planning, Electric System Operations and DCPP) and the ISO.

        System studies shall consider the interconnections between PG&E, and
other utilities in the Western Electricity Coordinating Council (WECC) region.

7.In the event of a complete loss of the DCPP offsite power supply (i.e. both
the 230 kV and 500 kV grid interfaces) both the ISO and PG&E shall establish the
following restoration priorities:

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.

8.Grid frequency shall be maintained at 60 Hertz (nominal). The following
operations are initiated for low system frequency conditions:

a)At 59.65 Hz, E19 & E20 interruptible customers are tripped.

b)PG&E complies with the WECC Coordinated Off-Nominal Frequency Load Shedding
and Restoration Plan.

9.Patrol and inspection of PG&E transmission lines shall be performed in
accordance with the current CAISO approved PG&E Overhead Electrical Transmission
Line Maintenance Practice.

10.Line insulators between the plant and switchyard shall be washed by PG&E on
an appropriate wash cycle during the wash season in accordance with the current
CAISO approved PG&E Overhead Electrical Transmission Line Maintenance Practice
to reduce line outages that may result from flashovers due to possible
accumulated contamination.

11.Maintenance, testing and calibration of DCPP switchyard equipment and
protective relays shall be performed in accordance with the current CAISO
approved PG&E Electrical Station Maintenance Practice.

12.PG&E (DCPP) maintains a safety analysis for DCPP (Section 8.0, Electric Power
of DCPP 1&2 Final Safety Analysis Update Report (FSAR)). PG&E (DCPP) is required
by 10CFR50.71(e) to submit to the NRC periodic updates to the FSAR. The
requirements contained in this Appendix E are documented in the FSAR. Any
changes to these requirements, or the Bulk Power Transmission System Reliability
criteria used as a basis for compliance with a requirement, shall be transmitted
by both the ISO and PG&E (Transmission operator) to PG&E (DCPP) for prior
approval.

        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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SONGS 2&3 REQUIREMENTS FOR OFFSITE
POWER SUPPLY OPERABILITY

Revised September 2, 2002

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 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.

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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.

1.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 158 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

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 kV. (References 10, 11, 18)

6.The normal operating voltage of the SONGS switchyard shall be maintained at
230 kV. 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 GCC Operating
Procedure: SONGS Voltage (Current revision).

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Based on these nomograms and SONGS offline unit's status, if the Grid Control
Center or ISO determines that the operating point is outside the applicable
derated 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 critical transmission lines/grid conditions:

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
SONGS- Serrano & SONGS - Chino 230 kV Lines

Critical Line(s) Out in SDG&E Territory

Hassayampa-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

Critical Grid Conditions:
SCE/SDG&E Tie Separation at SONGS:

SCE/SDG&E Tie Open, Unit 3 On-Line (Unit 2 Off-Line)
SCE/SDG&E Tie Open, Unit 2 On-Line (Unit 3 Off-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.

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(References 1, 2, 19, 21)

System studies shall consider the interconnections between SCE, SDG&E, and other
utilities in the Western Electricity Coordinating Council (WECC). (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.

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. SCE and SDG&E
comply with the WECC Coordinated Off-Nominal Frequency Load Shedding and
Restoration Plan.

Note:System separation between SCE and SDG&E at the SONGS bus tie on low grid
frequency mentioned in the previous version of the TCA is being removed from
SONGS by mid-2002. Increased load shedding schemes by SDG&E have been
implemented which preclude the need for system separation at SONGS bus ties on
low frequency.

(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.Patrol and inspection of SCE and SDG&E transmission lines shall be performed
in accordance with the current ISO approved Overhead Electric Transmission Line
Maintenance Practice or as required by the NRC plant-operating license,
whichever requirement is more stringent. These patrols and inspections are to
ensure that the physical and electrical integrity of transmission system
components are maintained. (Reference 7)

81

--------------------------------------------------------------------------------

12.Line insulators on lines which carry power from the plant to the grid shall
be washed as required by the NRC plant-operating license or on an appropriate
wash cycle in accordance with the current ISO approved Overhead Electric
Transmission Line Maintenance Practice, whichever requirement is more stringent.
The purpose and frequency of which is proven to prevent line outages that may
result from flashovers due to accumulated contamination. (Reference 7)

13.Maintenance, testing and calibration of SCE and SDG&E station equipment and
protective relays shall be performed in accordance with the current ISO approved
Electrical Station Maintenance Practice or as required by the NRC plant
operating license, whichever requirement is more stringent. (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.

82

--------------------------------------------------------------------------------

REFERENCES

1)SONGS 2&3 Operating License and Technical Specifications, Section 3.8,
Electrical Power Systems

2)10CFR50 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 Plan Revision 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)ANSI/IEEE 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-SO23-120, SONGS Design Basis Document, 6.9KV, 4.16KV and 480V Electrical
Systems

14)90051, SONGS Station Blackout Analyses

15)NUMARC 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 3"

18)System Operating Bulletin 17 Appendix, System Voltage Control for San Onofre
Nuclear Generating Station (Current approved revision)

19)GCC Operating Procedure: SONGS Voltage (Current approved revision)

20)System Operating Bulletin 113, San Onofre 220 kV System Separation (Current
approved revision)

21)Regulatory Guide 1.93, Availability of Electric Power Sources

23)SCE Division Order 60.20, Storage Batteries (Current approved revision)

26)System Operating Bulletin 1-A, Thermal Station Start-up and Power System
Restoration (Current approved revision)

27)System Operating Bulletin 254, Emergency Orders—San Onofre Nuclear Generating
Station 220 kV (Current approved revision)

28)SDG&E Control Procedure 1150, Capacity & Energy Emergencies—SDG&E
System            Emergencies (Current approved revision)

83

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 225

       

       

       

TRANSMISSION CONTROL AGREEMENT

APPENDIX F

NOTICES

      

      

      

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002   Effective: January 1, 2003

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 226

NOTICES

California Independent System Operator

Name of Primary    
Representative:
 
Deborah A. Le Vine

--------------------------------------------------------------------------------

Title:
 
Director of Contracts

--------------------------------------------------------------------------------

Address:
 
151 Blue Ravine Road

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Folsom, California 95630

--------------------------------------------------------------------------------

Email Address:
 
dlevine@caiso.com

--------------------------------------------------------------------------------

Phone:
 
(916) 351-2144

--------------------------------------------------------------------------------

Fax No:
 
(916) 351-2487

--------------------------------------------------------------------------------

Name of Alternative
 
 
Representative:
 
Randy Abernathy

--------------------------------------------------------------------------------

Title:
 
Vice President of Market Services

--------------------------------------------------------------------------------

Address:
 
151 Blue Ravine Road

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Folsom, California 95630

--------------------------------------------------------------------------------

Email Address:
 
rabernathy@caiso.com

--------------------------------------------------------------------------------

Phone:
 
(916) 351-4435

--------------------------------------------------------------------------------

Fax No:
 
(916) 351-2350

--------------------------------------------------------------------------------

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002
 
Effective: January 1, 2003

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   First Revised Sheet No. 227
Superseding Original Sheet No. 227

Pacific Gas and Electric Company

Name of Primary    
Representative:
 
Rod Maslowski

--------------------------------------------------------------------------------

Title:
 
Director, Electric System Operations

--------------------------------------------------------------------------------

Address:
 
77 Beale Street, Room 1526

--------------------------------------------------------------------------------

City/State/Zip Code:
 
San Francisco, CA 94105

--------------------------------------------------------------------------------

Email Address:
 
RJM8@pge.com

--------------------------------------------------------------------------------

Phone:
 
415-973-1218

--------------------------------------------------------------------------------

Fax No:
 
415-973-3341

--------------------------------------------------------------------------------

Name of Alternative
 
 
Representative:
 
Steve Metague

--------------------------------------------------------------------------------

Title:
 
Director, Electric Transmission Rates

--------------------------------------------------------------------------------

Address:
 
77 Beale Street, Room 1339

--------------------------------------------------------------------------------

City/State/Zip Code:
 
San Francisco, CA 94105

--------------------------------------------------------------------------------

Email Address:
 
SJMd@pge.com

--------------------------------------------------------------------------------

Phone:
 
415 973-6545

--------------------------------------------------------------------------------

Fax No:
 
415 973-9174

--------------------------------------------------------------------------------

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: September 7, 2004
 
Effective: Upon notice after November 1, 2004

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 228

San Diego Gas & Electric Company

Name of Primary    
Representative:
 
Geoff Gaebe

--------------------------------------------------------------------------------

Title:
 
Director—Electrical Engineering

--------------------------------------------------------------------------------

Address:
 
8316 Century Park Court

--------------------------------------------------------------------------------

City/State/Zip Code:
 
San Diego, CA 92123

--------------------------------------------------------------------------------

Email Address:
 
ggaebe@semprautilities.com

--------------------------------------------------------------------------------

Phone:
 
858-654-1636

--------------------------------------------------------------------------------

Fax No:
 
858-654-1692

--------------------------------------------------------------------------------

Name of Alternative
 
 
Representative:
 
Ali Yari

--------------------------------------------------------------------------------

Title:
 
Manager Grid Operation Services

--------------------------------------------------------------------------------

Address:
 
9060 Friars Road

--------------------------------------------------------------------------------

City/State/Zip Code:
 
San Diego, CA 92108

--------------------------------------------------------------------------------

Email Address:
 
yari@semprautilities.com

--------------------------------------------------------------------------------

Phone:
 
619-725-8639

--------------------------------------------------------------------------------

Fax No:
 
619-683-3291

--------------------------------------------------------------------------------

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002   Effective: January 1, 2003

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 229

Southern California Edison Company

Name of Primary    
Representative:
 
Richard M. Rosenblum

--------------------------------------------------------------------------------

Title:
 
Senior Vice President, Transmission & Distribution

--------------------------------------------------------------------------------

Address:
 
2244 Walnut Grove Ave., GO4

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Rosemead, California 91770

--------------------------------------------------------------------------------

Email Address:
 
Richard.Rosenblum@SCE.com

--------------------------------------------------------------------------------

Phone:
 
(626) 302-2123

--------------------------------------------------------------------------------

Fax No:
 
(626) 302-2781

--------------------------------------------------------------------------------

Name of Alternative
 
 
Representative:
 
John R. Fielder

--------------------------------------------------------------------------------

Title:
 
Senior Vice President, Regulatory Policy & Affairs

--------------------------------------------------------------------------------

Address:
 
2244 Walnut Grove Ave., GO4

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Rosemead, California 91770

--------------------------------------------------------------------------------

Email Address:
 
John.Fielder@SCE.com

--------------------------------------------------------------------------------

Phone:
 
(626) 302-3440

--------------------------------------------------------------------------------

Fax No:
 
(626) 302-2970

--------------------------------------------------------------------------------

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002
 
Effective: January 1, 2003

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 230

City of Vernon

Name of Primary    
Representative:
 
Bruce V. Malkenhorst

--------------------------------------------------------------------------------

Title:
 
City Administrator

--------------------------------------------------------------------------------

Address:
 
4305 Santa Fe Avenue

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Vernon, California 90058

--------------------------------------------------------------------------------

Email Address:
 
bmalkenhorst@ci.vernon.ca.us

--------------------------------------------------------------------------------

Phone:
 
(323) 583-8811 extension 266

--------------------------------------------------------------------------------

Fax No:
 
(323) 581-7924

--------------------------------------------------------------------------------

Name of Alternative
 
 
Representative:
 
Kenneth J. DeDario

--------------------------------------------------------------------------------

Title:
 
Director of Utilities

--------------------------------------------------------------------------------

Address:
 
4305 Santa Fe Avenue

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Vernon, California 90058

--------------------------------------------------------------------------------

Email Address:
 
kdedario@ci.vernon.ca.us

--------------------------------------------------------------------------------

Phone:
 
(323) 583-8811 extension 211

--------------------------------------------------------------------------------

Fax No:
 
(323) 826-1425

--------------------------------------------------------------------------------

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002
 
Effective: January 1, 2003

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 231

City of Anaheim

Name of Primary    
Representative:
 
Sheryll A. Schroeder

--------------------------------------------------------------------------------

Title:
 
City Clerk

--------------------------------------------------------------------------------

Address:
 
200 S. Anaheim Blvd.

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Anaheim, California 92805

--------------------------------------------------------------------------------

Email Address:
 
sschroeder@anaheim.net

--------------------------------------------------------------------------------

Phone:
 
(714) 765-5645

--------------------------------------------------------------------------------

Fax No:
 
(714) 765-4105

--------------------------------------------------------------------------------

Name of Alternative
 
 
Representative:
 
Marcie L. Edwards

--------------------------------------------------------------------------------

Title:
 
Public Utilities General Manager

--------------------------------------------------------------------------------

Address:
 
201 S. Anaheim Blvd., Suite 1101

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Anaheim, California 92805

--------------------------------------------------------------------------------

Email Address:
 
medwards@anaheim.net

--------------------------------------------------------------------------------

Phone:
 
(714) 765-5173

--------------------------------------------------------------------------------

Fax No:
 
(714) 765-4138

--------------------------------------------------------------------------------

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002
 
Effective: January 1, 2003

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 232

City of Azusa

Name of Primary    
Representative:
 
Joseph Hsu

--------------------------------------------------------------------------------

Title:
 
Director of Utilities

--------------------------------------------------------------------------------

Address:
 
729 N. Azusa Avenue

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Azusa, CA 91702

--------------------------------------------------------------------------------

Email Address:
 
jhsu@ci.azusa.ca.us

--------------------------------------------------------------------------------

Phone:
 
(626) 812-5171

--------------------------------------------------------------------------------

Fax No:
 
(626) 334-3163

--------------------------------------------------------------------------------

Name of Alternative
 
 
Representative:
 
Bob Tang

--------------------------------------------------------------------------------

Title:
 
Assistant Director of Resource Management

--------------------------------------------------------------------------------

Address:
 
729 N. Azusa Avenue

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Azusa, CA 91702

--------------------------------------------------------------------------------

Email Address:
 
btang@ci.azusa.ca.us

--------------------------------------------------------------------------------

Phone:
 
(626) 812-5214

--------------------------------------------------------------------------------

Fax No:
 
(626) 334-3163

--------------------------------------------------------------------------------

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002
 
Effective: January 1, 2003

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 233

City of Banning

Name of Primary    
Representative:
 
Paul Toor

--------------------------------------------------------------------------------

Title:
 
Public Works Director

--------------------------------------------------------------------------------

Address:
 
99 East Ramsey Street

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Banning, California 92220

--------------------------------------------------------------------------------

Email Address:
 
ptoor@ci.banning.ca.us

--------------------------------------------------------------------------------

Phone:
 
(909) 922-3130

--------------------------------------------------------------------------------

Fax No:
 
(909) 922-3141

--------------------------------------------------------------------------------

Name of Alternative
 
 
Representative:
 
Fred Mason

--------------------------------------------------------------------------------

Title:
 
Power Resource Specialist

--------------------------------------------------------------------------------

Address:
 
176 East Lincoln Street

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Banning, California 92220

--------------------------------------------------------------------------------

Email Address:
 
fmason@ci.banning.ca.us

--------------------------------------------------------------------------------

Phone:
 
(909) 922-3265

--------------------------------------------------------------------------------

Fax No:
 
(909) 849-1550

--------------------------------------------------------------------------------

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002
 
Effective: January 1, 2003

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 234

City of Riverside

Name of Primary    
Representative:
 
Thomas P. Evans

--------------------------------------------------------------------------------

Title:
 
Public Utilities Director

--------------------------------------------------------------------------------

Address:
 
3900 Main Street

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Riverside, CA 92522

--------------------------------------------------------------------------------

Email Address:
 
tevans@ci.riverside.ca.us

--------------------------------------------------------------------------------

Phone:
 
(909) 826-5502

--------------------------------------------------------------------------------

Fax No:
 
(909) 369-0548

--------------------------------------------------------------------------------

Name of Alternative
 
 
Representative:
 
Gary L. Nolff

--------------------------------------------------------------------------------

Title:
 
Power Contracts/Projects Manager

--------------------------------------------------------------------------------

Address:
 
2911 Adams Street

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Riverside, CA 92504

--------------------------------------------------------------------------------

Email Address:
 
gnolff@pac.state.ca.us

--------------------------------------------------------------------------------

Phone:
 
(909) 351-6313

--------------------------------------------------------------------------------

Fax No:
 
(909) 351-6328

--------------------------------------------------------------------------------

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002
 
Effective: January 1, 2003

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 235

Trans-Elect NTD Path 15, LLC

Name of Primary    
Representative:
 
Robert L. Mitchell

--------------------------------------------------------------------------------

Title:
 
President

--------------------------------------------------------------------------------

Address:
 
1850 Centennial Park Drive, Suite 480

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Reston, VA 20191

--------------------------------------------------------------------------------

Email Address:
 
RLMitchell@trans-elect.com

--------------------------------------------------------------------------------

Phone:
 
(703) 563-4362

--------------------------------------------------------------------------------

Fax No:
 
(703) 563-4330

--------------------------------------------------------------------------------

Name of Alternative
 
 
Representative:
 
Perry Cole

--------------------------------------------------------------------------------

Title:
 
Vice President

--------------------------------------------------------------------------------

Address:
 
3420 N. Hillcrest

--------------------------------------------------------------------------------

City/State/Zip Code:
 
Butte, Montana 59701

--------------------------------------------------------------------------------

Email Address:
 
PCole@trans-elect.com

--------------------------------------------------------------------------------

Phone:
 
(406) 782-1907

--------------------------------------------------------------------------------

Fax No:
 
(406) 782-0036

--------------------------------------------------------------------------------

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: August 15, 2003
 
Effective: Upon notice after January 1, 2004

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 236

Western Area Power Administration, Sierra Nevada Region

Name of Primary    
Representative:
 
James D. Keselburg
Title:
 
Regional Manager
Address:
 
114 Parkshore Drive
City/State/Zip Code:
 
Folsom, CA 95630-4710
Email Address:
 
keselbrg@wapa.gov
Phone:
 
(916) 353-4418
Fax No:
 
(916) 985-1930
Name of Alternative
 
 
Representative:
 
Thomas R. Boyko
Title:
 
Power Marketing Manager
Address:
 
114 Parkshore Drive
City/State/Zip Code:
 
Folsom, CA 95630-4710
Email Address:
 
Boyko@wapa.gov
Phone:
 
(916) 353-4421
Fax No:
 
(916) 985-1931

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: September 7, 2004
 
Effective: Upon notice after November 1, 2004

--------------------------------------------------------------------------------

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
FERC ELECTRIC TARIFF NO. 7
SECOND REPLACEMENT TRANSMISSION CONTROL AGREEMENT   Original Sheet No. 237

City of Pasadena

Name of Primary    
Representative:
 
Ms. Phyllis E. Currie
Title:
 
General Manager
 
 
City of Pasadena Water and Power Department
Address:
 
150 S. Los Robles, Suite 200
City/State/Zip Code:
 
Pasadena, CA 91101
Email Address:
 
pcurrie@cityofpasadena.net
Phone:
 
(626) 744-4425
Fax No:
 
(626) 744-4470
Name of Alternative
 
 
Representative:
 
Mr. Steven K. Endo
Title:
 
Resource Planning Manager
 
 
City of Pasadena Water and Power Department
Address:
 
150 S. Los Robles, Suite 200
City/State/Zip Code:
 
Pasadena, CA 91101
Email Address:
 
sendo@cityofpasadena.net
Phone:
 
(626) 744-6246
Fax No:
 
(626) 744-6432

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: December 23, 2004
 
Effective: January 1, 2005

--------------------------------------------------------------------------------

QuickLinks

Exhibit 10.8

TRANSMISSION CONTROL AGREEMENT Among The Independent System Operator and
Transmission Owners
TRANSMISSION CONTROL AGREEMENT Among The Independent System Operator and
Transmission Owners
27. SIGNATURE PAGE CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
TRANSMISSION CONTROL AGREEMENT
Modification of Appendix A1
APPENDIX A2 List of Entitlements Being Placed under ISO Operational Control
Supplement To PG&E's Appendix A Notices Pursuant to Section 4.1.5
TRANSMISSION CONTROL AGREEMENT APPENDIX B Encumbrances
PG&E APPENDIX B
List of Encumbrances on Lines and Facilities, and Entitlements Being Placed
under ISO Operational Control (per TCA Appendix A1 & A2)1
EXHIBIT B-1 (TO PG&E APPENDIX B) Path 15 Operating Instructions For Existing
Encumbrances Across the Path 15 Interface April 1, 2003, Revision 1
EXHIBIT B-1 (TO PG&E APPENDIX B)
ATTACHMENT 1
CALIFORNIA ISO PATH 15 ATC DETERMINATION METHODOLOGY
TRANSMISSION CONTROL AGREEMENT APPENDIX D Master Definitions Supplement
TRANSMISSION CONTROL AGREEMENT APPENDIX E Nuclear Protocols
DIABLO CANYON NUCLEAR POWER PLANT UNITS 1 & 2 REQUIREMENTS FOR OFFSITE POWER
SUPPLY OPERABILITY REVISION 1
TRANSMISSION CONTROL AGREEMENT APPENDIX F NOTICES