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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    
    

 
TABLE OF CONTENTS  

	Section
 
	 	 
	 	Page

	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
	 	 	 	 	 

i

 

	

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	
 	

 

ii

  

 
 

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. 

1

 

        (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; 

2

 

        (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 

3

 

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. 

4

   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 

5

 

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 

6

 

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 

7

 

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. 

8

 

        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. 

9

   
        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 

10

 

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. 

11

 

        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. 

12

 

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 

13

 

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. 

14

   
        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. 

15

 

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. 

16

 

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 

17

 

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, 

21

 

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. 

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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). 

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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

 

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

 

        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

  

 
 

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

 
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

 
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

 
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

 
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

 
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

   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

38

 
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

 
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

 
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

 
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

 
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

  

 
 

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

 
 
 

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

 
 
 

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

 
 
 

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. 

   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

 

        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; 

49

 

	•
	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

 

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 

51

 

	•
	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

   
        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. 

53

 

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. 

54

 

 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: 

55

 

  

 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. 

56

 

        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. 

57

   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

 

 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

 

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

 

        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

   
        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 

  

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

 

	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. 

63

 

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

 

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

   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. 

66

 

 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 

67

 

	•
	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. 

68

 

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. 

69

   
        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. 

70

 

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) 

71

 

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. 

72

 

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. 

73

	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

	

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.
	 	 	 

	

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.
	 	 	 

	

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.
	 	 	 

	

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.
	 	 	 

	

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.

	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).
	 	 	 

	

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.
	 	 	 

	

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.
	 	 	 

	

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.
	 	 	 

	

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.
	 	 	 

	

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.

  

 
 

TRANSMISSION CONTROL AGREEMENT    
    
    APPENDIX E    
    
    Nuclear Protocols    
    

74

 
 
 

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 

75

 

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
 
	 	Major 500 kV Elements
 

	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. 

76

 
	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.

77

   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. 

78

 

 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). 

79

 

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. 

80

 

(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 NOTICESQuickLinks
 -- Click here to rapidly navigate through this document
  

 
 

Exhibit 10.9    
    

 
 

OPERATING AGREEMENT
  Between    

STATE OF CALIFORNIA

DEPARTMENT OF WATER RESOURCES 

And 

PACIFIC GAS AND ELECTRIC COMPANY 

THIS
AGREEMENT HAS BEEN FILED WITH AND APPROVED BY THE CALIFORNIA PUBLIC UTILITIES COMMISSION ("COMMISSION") FOR USE BETWEEN THE STATE OF CALIFORNIA DEPARTMENT OF WATER RESOURCES ("DWR") AND PACIFIC
GAS AND ELECTRIC COMPANY ("UTILITY"). 

Original
Execution Date: April 17, 2003 

Amended
Execution Date: November 12, 2004(1) 

Date
of Commission Approval: January 3, 2005 

Effective
Date: December 22, 2004 

	(1)
	Pursuant
to D.04-10-020. 

1

 
 
 

(This page was intentionally left blank.)    
    

2

 
 
 

OPERATING AGREEMENT    
    

        This OPERATING AGREEMENT (this "Agreement") is between the State of California Department of Water Resources
("DWR"), acting solely under the authority and powers granted by AB1X, codified as Sections 80000 through 80270 of the Water Code, and not under its powers and responsibilities with
respect to the State Water Resources Development System, and Pacific Gas and Electric Company, a California corporation ("Utility"). DWR and Utility are sometimes collectively referred to herein as
the "Parties" and individually referred to as a "Party." Unless otherwise noted, all capitalized terms shall have the meanings set forth in Article I of this Agreement. 

 
 

R E C I T A L S    
    

        WHEREAS, under the Act, DWR has entered into a number of long-term power purchase agreements for the purpose of providing the net short requirements
to the retail ratepayers of the State's electrical corporations, including Utility; and 

        WHEREAS,
the Contract Allocation Order of the Commission provides that such long-term power purchase agreements are to be operationally allocated among the State's electrical
corporations, including Utility, solely for the purpose of causing the State's electrical corporations to perform certain specified functions on behalf of DWR, as DWR's limited agent, including
dispatching, scheduling, billing and settlements functions, and to sell surplus energy, all as such functions relate to those certain power purchase agreements that are operationally allocated to each
electrical corporation under the Contract Allocation Order; and 

        WHEREAS,
DWR wishes to provide for the performance of such functions under the Allocated Contracts by Utility on behalf of DWR in accordance with such long-term power
purchase agreements as provided in this Agreement; and 

        WHEREAS,
consistent with the Contract Allocation Order, DWR will retain legal and financial obligations, together with ongoing responsibility for any other functions not explicitly
provided in this Agreement to be performed by Utility, with respect to each of the Allocated Contracts and it is the intent of DWR and the Utility that the provisions of this Agreement will not
constitute an "assignment" of the Allocated Contracts or Interim Contracts to Utility. 

        WHEREAS,
consistent with the Interim Contract Order of the Commission, DWR expects to enter into certain Interim Contracts prior to January 1, 2003 and DWR wishes to provide for
the administration of such Interim Contracts by Utility. 

        NOW, THEREFORE, in consideration of the mutual obligations of the Parties, the Parties agree as follows: 

 
 

ARTICLE I
  DEFINITIONS    
    

        Section 1.01.    Definitions.    The following terms shall have the respective meanings in this Agreement: 

        The
following terms, when used herein (and in the attachments hereto) with initial capitalization, shall have the meaning specified in this Section 1.01. Certain additional terms
are defined in the attachments hereto. The singular shall include the plural and the masculine shall include the feminine and neuter, and vice versa.
"Includes" or "including" shall mean "including without limitation." References to a section or attachment shall mean a section or attachment of this Agreement, as the case may be, unless the context
requires otherwise, and reference to a given agreement or instrument shall be a reference to that agreement or instrument as modified, amended, supplemented or restated through the date as of which
such reference is made (except as otherwise specifically provided herein). 

3

 

Unless
the context otherwise requires, references to Applicable Laws or Applicable Tariffs shall be deemed references to such laws or tariffs as they may be amended, replaced or restated from time to
time. References to the time of day shall be deemed references to such time as measured by prevailing Pacific Time. 

        "Act" means Chapter 4 of Statutes of 2001 (Assembly Bill 1 of the First 2001-02 Extraordinary Session) of the State of
California, as amended. 

        "Agreement", means this Operating Agreement, together with all attached Schedules, Exhibits and Attachments, as such may be amended from
time to time as evidenced by a written amendment executed by the Parties. 

        "Allocated Contracts" means the long-term power purchase agreements operationally allocated to Utility under the Contract
Allocation Order, without legal and financial assignment of such agreements to Utility, as provided in Schedule 1 attached hereto. 

        "Allocated Power" means all power and energy, including the use of such power or energy as ancillary services, delivered or to be
delivered under the Contracts. 

        "Applicable Commission Orders" means such rules, regulations, decisions, opinions or orders as the Commission may lawfully issue or
promulgate from time to time, which relate to the subject matter of this Agreement. 

        "Applicable Law" means the Act, Applicable Commission Orders and any other applicable statute, constitutional provision, rule, regulation,
ordinance, order, decision or code of a Governmental Authority. 

        "Applicable Tariffs" means Utility's tariffs, including all rules, rates, schedules and preliminary statements, governing electric energy
service to Utility's customers in its service territory, as filed with and approved by the Commission and, if applicable, the Federal Energy Regulatory Commission. 

        "Assign(s)" shall have the meaning set forth in Section 14.01. 

        "Bonds" shall have the meaning set forth in the Rate Agreement. 

        "Bond Charges" shall have the meaning set forth in the Rate Agreement. 

        "Business Day" means the regular Monday through Friday weekdays that are customary working days, excluding holidays, as established by
Applicable Tariffs. 

        "Commission" means the California Public Utilities Commission. 

        "Confidential Information" shall have the meaning set forth in Section 11.01(c). 

        "Contracts" means the Allocated Contracts and the Interim Contracts. 

        "Contract Allocation Order" means Decision 02-09-053 of the Commission, issued on September 19, 2002, as
such Decision may be modified, revised, amended, supplemented or superseded from time to time by the Commission. 

        "DWR Power" shall have the same meaning set forth in the Servicing Arrangement with such amendments to incorporate the Settlement
Principles for Remittances and Surplus Revenues as provided in Exhibit C of this Agreement. 

        "DWR Revenues" means those amounts required to be remitted to DWR by Utility in accordance with this Agreement and as further provided in
the Servicing Arrangement. 

        "Effective Date" means the effective date in accordance with Section 14.13, as such date is set forth on the cover page hereof. 

4

 

        "Fund" means the Department of Water Resources Electric Power Fund established by Section 80200 of the California Water Code. 

        "Good Utility Practice" means 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 does not require the
optimum practice, method, or act to the exclusion of all others, but rather is intended to include acceptable practices, methods, or acts generally accepted in the Western Electric Coordinating
Council region. 

        "Governmental Authority" means any nation or government, any state or other political subdivision thereof, and any entity exercising
executive, legislative, judicial, regulatory or administrative functions of or pertaining to a government, including the Commission. 

        "Governmental Program" means any program or directive established by Applicable Law which directly or indirectly affects the rights or
obligations of the Parties under this Agreement and which obligates or authorizes DWR to make payments or give credits to customers or other third parties under such programs or directives. 

        "ISO" means the California Independent System Operator Corporation. 

        "Interim Contract Order" means Decision 02-08-071 of the Commission, issued on August 22, 2002, as such
Decision may be amended or supplemented from time to time by the Commission. 

        "Interim Contracts" mean the power purchase or exchange arrangements between DWR and various Suppliers entered into by DWR at the request
of Utility and consistent with the Interim Contract Order, as listed in Schedule 2 attached hereto. 

        "Order" means Decision 02-12-069 of the Commission, issued on December 19, 2002 as such decision may be
amended or supplemented from time to time by the Commission. 

        "Power Charges" shall have the meaning set forth in the Rate Agreement. 

        "Priority Long Term Power Contract" shall have the meaning set forth in the Rate Agreement. 

        "Rate Agreement" means the Rate Agreement between DWR and the Commission adopted by the Commission on February 21, 2002 in Decision
02-02-051. 

        "Remittance" means a payment by Utility to DWR or its Assign(s) in accordance with the Servicing Arrangement. 

        "Servicing Arrangement" means the Servicing Order as specified in Commission Decision 02-12-072, dated
December 19, 2002, as may be modified from time to time. 

        "Supplier" means those certain third parties who are supplying power pursuant to the Contracts. 

        "Term" means term provided in Section 2.05 hereof. 

        "URG" means utility-retained generation, including without limitation Utility's portfolio of generation resources and power purchase
agreements prior to or after the Effective Date by Utility. 

        Section 1.02.    Undefined Terms.    Capitalized terms not otherwise defined in Section 1.01 herein
shall have the meanings set forth in the Act or the Servicing Arrangement. 

5

 
 
 

ARTICLE II
  OPERATIONAL ALLOCATION OF POWER PURCHASE AGREEMENTS;
  MANAGEMENT OF THE CONTRACTS; ALLOCATED POWER; TERM    
    

        Section 2.01.    Operational Allocation and Management of Power Purchase Agreements.    On behalf of DWR, as
its limited agent, Utility will perform certain day-to-day scheduling and dispatch functions, billing and settlements and surplus energy sales and certain other tasks with
respect to the Allocated Contracts and each Interim Contract, as more fully set forth in this Agreement. 

        As
further provided in Contract Administration and Performance Test Monitoring Protocols set forth in Exhibit E, DWR will continue to monitor and audit the Supplier performance
under the Contracts. Upon development of a mutually agreeable plan, Utility will monitor the performance of Suppliers, as further provided in Exhibit E, subject, however, to DWR's right but not
the obligation to audit and monitor all functions contemplated to be performed by Utility, all as further provided in this Agreement. 

        Section 2.02.    Standard of Contract Management.    

	(a)
	Utility
agrees to perform the functions specified in this Agreement relating to the Allocated Contracts and prior to novation, and Interim Contracts in a commercially reasonable
manner, exercising Good Utility Practice, and in a fashion reasonably designed to serve the overall best interests of retail electric customers. Utility shall provide to DWR such information
specifically provided in Exhibit F hereto to facilitate DWR's verification of Utility's compliance with this Section 2.02.

	(b)
	To
the extent requested by Utility, DWR shall provide evidence in Commission proceedings describing Utility's and DWR's performance, rights and obligations under this Agreement.

	(c)
	DWR
acknowledges the Commission's exclusive authority over whether the Utility has managed Allocated Power available under the Contracts in a just and reasonable manner and DWR and
Utility agree that none of the provisions of this Agreement shall be interpreted to reduce, diminish, or otherwise limit the scope of any Commission authority or to give DWR any authority over such
matters. In addition, the Parties acknowledge that DWR is not subject to the Commission's jurisdiction, and the Parties agree that none of the provisions of this Agreement, including
Section 13.04 herein, shall be interpreted to subject DWR to the Commission's jurisdiction or authority.

	(d)
	The
Utility acknowledges DWR's separate and independent right to evaluate and enforce Utility's commercial performance under this Agreement.

	(e)
	Utility
agrees to provide any information not otherwise required herein that is reasonably necessary to allow DWR to exercise its rights in subsection (d) above, provided that
all such information shall be used solely for the purposes of exercising such rights. 

        Section 2.03.    Good Faith.    Each Party hereby covenants that it shall perform its actions, obligations and
duties in connection with this Agreement in good faith. 

        Section 2.04.    DWR Power.    During the term of this Agreement, the electric power and energy, including but
not limited to capacity, and output, or any of them from the Contracts delivered to retail end-use customers in Utility's service area shall constitute DWR Power for all purposes of the
Servicing Arrangement. Utility shall arrange for transmission service to accommodate surplus sales to the extent that transmission service is available and cost effective, all as further provided in
Exhibit A. 

        Section 2.05.    Term.    

	(a)
	The
Term of this Agreement shall commence on the Effective Date and shall terminate on the earlier of (a) the termination of the Servicing Arrangement, or (b) the
termination of this Agreement by DWR upon ninety days' written notice to Utility, or (c) upon consultation with 

6

 

the
Commission, the termination of the Agreement by DWR upon reasonable written notice to Utility no shorter than 30 days, or (d) pursuant to Article VII hereof, the termination
of this Agreement by a non-defaulting Party after an Event of Default. In addition, this Agreement will terminate as to each Contract that terminates in accordance with its terms. DWR
agrees to notify Utility as to the termination of each Contract as provided in Section 5.01(e) hereof. 

	(b)
	If
an event occurs which has the effect of materially altering and materially adversely impacting the economic position of the Parties or either of them under this Agreement, then the
affected Party may, by written notice, request that the Commission approve amendments to this Agreement or other arrangements incidental to this Agreement as necessary to preserve or restore the
economic position under this Agreement held by the affected Party immediately prior to such event. Such notice shall describe the event and shall include reasonable particulars as to the manner and
extent to which the economic position of the Party giving notice has been adversely affected. 

 
 

ARTICLE III
  LIMITED AGENCY / NO ASSIGNMENT    
    

        Section 3.01.    Limited Agency.    Utility is hereby appointed as DWR's agent for the limited purposes set
forth in this Agreement. Utility shall not be deemed to be acting, and shall not hold itself out, as agent for DWR for any purpose other than those described in this Agreement. Utility's duties and
obligations shall be limited to those duties and obligations that are specified in this Agreement. 

        Section 3.02.    No Assignment.    DWR shall remain legally and financially responsible for performance under
each of the Contracts and shall retain liability to the counterparty for any failure of Utility to perform the functions referred to in this Agreement on behalf of DWR as its limited agent, under such
Contracts in accordance with the terms thereof. It is the intent of DWR and Utility that the provisions of this Agreement shall not constitute or result in an "assignment" of the Allocated Contracts
in any respect. 

 
 

ARTICLE IV
  LIMITED DUTIES OF UTILITY    
    

        Section 4.01.    Limited Duties of Utility as to the Contracts.    During the Term of this Agreement, Utility
shall: 

	(a)
	On
behalf of DWR, as its limited agent, perform the day-to-day scheduling and dispatch functions, including day-ahead, hour-ahead and
real time trading, scheduling transactions with all involved parties, under the Allocated Contracts, perform billing and settlements functions and obtain relevant information for these functions such
as transmission availability and others, with respect to the Allocated Contracts set forth in Schedule 1 hereto, all as more specifically provided in the Operating Protocols attached hereto as
Exhibit A;

	(b)
	On
behalf of DWR, as its limited agent, enter into transactions for the purchase (or sale, as the case may be) of gas, gas transmission services, gas storage services and financial
hedges, and perform the operational and administrative responsibilities for such purchases under gas tolling provisions under the Allocated Contracts, including the review of fuel plans and
consideration of alternative fuel supply, all as more specifically provided in the Fuel Management Protocols attached hereto as Exhibit B;

	(c)
	On
behalf of DWR, as its limited agent, perform all necessary billing and settlement functions under the Allocated Contracts in accordance with the terms of the applicable Allocated
Contracts. In addition, perform all necessary billing and settlement functions related to DWR Revenues and remit DWR Revenues to DWR, consistent with the Settlement Principles for 

7

 

Remittances
and Surplus Revenues attached hereto as Exhibit C and the Servicing Arrangement; 

	(d)
	Assume
financial responsibility for the ISO charges listed on Exhibit D attached hereto;

	(e)
	On
behalf of DWR, as its limited agent, upon development of a mutually agreeable plan, monitor the performance of Suppliers under the Allocated Contracts and undertake the
administration of the Allocated Contracts, as more specifically provided in the Contract Administration and Performance Monitoring Protocols attached hereto as Exhibit E;

	(f)
	Provide
to DWR the necessary information required by DWR as more specifically provided in the DWR Data Requirements From Utility attached hereto as Exhibit F to facilitate
DWR's continued performance of financial obligations related to Allocated Contracts and to facilitate DWR's verification, audit and monitoring related to the Allocated Contracts and reporting
requirements set forth in Applicable Laws or agreements;

	(g)
	At
all times in performing its obligations under this Agreement (i) comply with the provisions of each of the Allocated Contracts, (ii) follow Good Utility Practice, and
(iii) comply with all Applicable Laws and Applicable Commission Orders;

	(h)
	Appoint
a primary and secondary contact person, as set forth in Schedule 2 hereto, to coordinate the responsibilities listed in this Section 4.01; and

	(i)
	On
behalf of DWR, as its limited agent, make surplus energy sales as more specifically provided in this Agreement; and

	(j)
	Prior
to novation of the Interim Contracts by Utility in accordance with the terms of each such Interim Contract, comply with the provisions listed in paragraphs (a) through
(i) of this Section 4.01, in each case substituting the defined term Interim Contract(s) for the term Allocated Contract(s). 

Provided,
however, in the event that DWR fails to provide or provides inaccurate information which results in Utility's non-compliance with its obligations under this Agreement, the
resulting non-compliance by Utility shall not constitute an Event of Default under Section 7.01 hereof. 

        Section 4.02.    Dispatch or Sale of Allocated Power.    Subject to any existing or new ISO tariff provisions
that may affect the dispatch of such Contracts, Allocated Power from all Contracts shall be dispatched or sold, as the case may be, by Utility pursuant to the Operating Protocols attached hereto as
Exhibit A. 

        Section 4.03.    DWR Revenues.    DWR Revenues shall be accounted and remitted to DWR consistent with the
principles provided in the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C and the provisions of the Servicing Arrangement. Unless otherwise specifically
provided in this Agreement, Utility will not be required at any time to advance or pay any of its own funds in the fulfillment of its responsibilities under this Agreement. 

        Section 4.04.    Ownership of Allocated Power.    Notwithstanding any other provision herein, and in accordance
with the Act and Section 80110 of the California Water Code, Utility and DWR agree that DWR shall retain title to all Allocated Power, including DWR Power. In accordance with the Act and
Section 80104 of the California Water Code, upon the delivery of Allocated Power to Utility's customers, those customers shall be deemed to have purchased that power from DWR, and payment for
such sale shall be a direct obligation of such customer to DWR. In addition, Utility and DWR agree that DWR shall retain title to any surplus Allocated Power sold by Utility as limited agent to DWR as
provided in this Agreement. 

8

 

 
 

ARTICLE V
  DUTIES OF DWR    
    

        Section 5.01.    Duties of DWR.    Consistent with the Contract Allocation Order, during the Term of this
Agreement, DWR shall: 

	(a)
	Remain
legally and financially responsible under each of the Contracts and cooperate with Utility in the transition from DWR to Utility the performance of the functions provided in
this Agreement;

	(b)
	Assume
legal and financial responsibilities and enter into or facilitate Utility's entering into transactions as DWR's limited agent, for the purchase (or sale, as the case may be) of
gas, gas transmission services, gas storage services and financial hedges, and timely consent to or approve the Utility's performance of the operational and administrative responsibilities for such
purchases under gas tolling provisions under the Allocated Contracts, including the review of fuel plans and consideration of alternative fuel supply, all as more specifically provided in the Fuel
Management Protocols attached hereto as Exhibit B;

	(c)
	Pay
invoices to the Suppliers and perform all necessary verification, audit and monitoring of the billing and settlement functions to be performed on DWR's behalf, as its limited
agent, by Utility relating to the Contracts and prior to novation, the Interim Contracts. In addition, perform all necessary verification, audit and monitoring of the billing and settlement functions
to be performed on DWR's behalf, as its limited agent, by Utility related to DWR Revenues, consistent with the principles set forth in the Settlement Principles for Remittances and Surplus Revenues
attached hereto as Exhibit C;

	(d)
	Until
such time as a mutually agreed upon plan may be entered into with Utility and approved by the Commission, and no earlier than January 1, 2004, continue to monitor the
performance of Suppliers and conduct certain contract administration duties under the Allocated Contracts, all as more specifically provided in the Contract Administration and Performance Monitoring
Protocols attached hereto as Exhibit E. In addition, continue to perform all other administrative functions related to Contracts not explicitly provided in this Agreement to be performed by
Utility on behalf of DWR, as its limited agent;

	(e)
	Upon
the termination of any Contract, submit in writing to Utility appropriate Schedules and Attachments to Exhibit A amended to reflect the termination of any Contract. Such
amended Schedules and Attachments shall become effective only upon the effective date of the termination of such Contract. Provided, however, rights or obligations of the Parties that arise or relate
to Utility's performance of its duties under this Agreement in respect of any terminated Contract shall survive until the expiration of any such right or obligation; and

	(f)
	Appoint
a primary and secondary contact person, as set forth in Schedule 3 hereto, to coordinate the responsibilities listed in this Section 5.01. 

 
 

ARTICLE VI
  SPECIAL CONTRACT TERMS    
    

        Section 6.01.    Special Contract Terms.    In addition to the obligations set forth in this Agreement, Utility
agrees to comply with the terms and provisions applicable to the Interim Contracts as set forth in Schedule 2 hereto. 

9

 
 
 

ARTICLE VII
  EVENTS OF DEFAULT    
    

        Section 7.01.    Events of Default.    The following events shall constitute "Events of Default" under this
Agreement: 

	(a)
	any
material failure by a Party to pay any amount due and payable under this Agreement that continues unremedied for five (5) Business Days after the earlier of the day the
defaulting Party receives written notice thereof from the non-defaulting Party; or

	(b)
	any
material failure by Utility to schedule and dispatch Contracts, consistent with the principles set forth in Exhibit A; or

	(c)
	any
failure (except as provided in (a) or (b)) by a Party to duly observe or perform in any material respect any other covenant or agreement of such Party set forth in this
Agreement, which failure continues unremedied for a period of 15 calendar days after written notice of such failure has been given to such Party by the non-defaulting Party; or

	(d)
	any
material representation or warranty made by a Party shall prove to be false, misleading or incorrect in any material respect as of the date made; or

	(e)
	an
Event of Default (as defined under the Servicing Arrangement) shall have occurred and is continuing under the Servicing Arrangement. 

        Section 7.02.    Consequences of Utility Event of Default.    Upon any Event of Default by Utility, DWR may, in
addition to exercising any other remedies available under this Agreement or under Applicable Law, (i) terminate this Agreement in whole or in part; and (ii) apply in an appropriate forum
for sequestration and payment to DWR or its Assign(s) of DWR Revenues or for specific performance of the functions related to the Contracts to be performed by Utility on behalf of DWR, as its limited
agent, as provided in this Agreement. 

        Section 7.03.    Consequences of DWR Event of Default.    Upon an Event of Default by DWR (other than an Event
of Default under 7.01(a)), Utility shall request that the Commission terminate this Agreement in whole or in part, Section 2.05 notwithstanding. 

        Section 7.04.    Remedies.    Subject to Article XIII of this Agreement, upon any Event of Default, the
non-defaulting Party may exercise any other legal or equitable right or remedy that may be available to it under applicable law or under this Agreement. 

        Section 7.05.    Remedies Cumulative.    Except as otherwise provided in this Agreement, all rights of
termination, cancellation, or other remedies in this Agreement are cumulative. Use of any remedy shall not preclude any other remedy available under this Agreement. 

        Section 7.06.    Waivers.    None of the provisions of this Agreement shall be considered waived by either
Party unless the Party against whom such waiver is claimed gives such waiver in writing. The failure of either Party to insist in any one or more instances upon strict performance of any of the
provisions of this Agreement or to take advantage of any of its rights hereunder shall not be construed as a waiver of any such provisions or the relinquishment of any such rights for the future, but
the same shall continue and remain in full force and effect. Waiver by either Party of any default by the other Party shall not be deemed a waiver of any other default. 

 
 

ARTICLE VIII
  PAYMENT OF FEES AND CHARGES    
    

        Section 8.01.    Utility Fees and Charges.    As noted in the Contract Allocation Order, the details of the
amount and recovery of administrative costs to Utility associated with the Contracts are expected to be considered in another Commission proceeding. As such, the Parties agree that the administrative 

10

 

costs
to Utility will be recovered pursuant to such Commission proceeding. Utility shall enter the cost of such fees and charges in its Purchased Electric Commodity Account, or its successor or
another account designated by the Commission on a current basis, for recovery in retail rates subject to subsequent Commission review. 

 
 

ARTICLE IX
  REPRESENTATIONS AND WARRANTIES    
    

        Section 9.01.    Representations and Warranties.    

	(a)
	Each
person executing this Agreement for the respective Parties expressly represents and warrants that he or she has authority to bind the Party on whose behalf he or she has executed
this Agreement.

	(b)
	Each
Party represents and warrants that it has the full power and authority to execute and deliver this Agreement and to perform its terms, that execution, delivery and performance of
this Agreement have been duly authorized by all necessary corporate or other action by such Party, and that this Agreement constitutes such Party's legal, valid and binding obligation, enforceable
against such Party in accordance with its terms.

	(c)
	DWR
represents and warrants that all necessary and appropriate notices, inducements, undertakings, approvals, and consents have been obtained from each Supplier to the Contract
allocated to Utility in order for Utility to undertake its duties set forth in this Agreement in a timely and appropriate fashion. 

 
 

ARTICLE X
  LIMITATIONS ON LIABILITY    
    

        Section 10.01.    Consequential Damages.    In no event will either Party be liable to the other Party for any
indirect, special, exemplary, incidental, punitive, or consequential damages under any theory. Nothing in this Section 10.01 shall limit either Party's rights as provided in Article VII
above. 

        Section 10.02.    Limited Obligations of DWR.    Any amounts payable by DWR under this Agreement shall be
payable solely from moneys on deposit in the Department of Water Resources Electric Power Fund established pursuant to Section 80200 of the California Water Code (the "Fund"). 

        Section 10.03.    Sources of Payment; No Debt of State.    DWR's obligation to make payments hereunder shall be
limited solely to the Fund and shall be payable as an operating expense of the Fund solely from Power Charges subject and subordinate to each Priority Long Term Power Contract in accordance with the
priorities and limitations established with respect to the Fund's operating expenses in any indenture providing for the issuance of Bonds and in the Rate Agreement and in the Priority Long Term Power
Contracts. Any liability of DWR arising in connection with this Agreement or any claim based thereon or with respect thereto, including, but not limited to, any payment arising as the result of any
breach or Event of Default under this Agreement, and any other payment obligation or liability of or judgment against DWR hereunder, shall be satisfied solely from the Fund. NEITHER THE FULL FAITH AND
CREDIT NOR THE TAXING POWER OF THE STATE OF CALIFORNIA ARE OR MAY BE PLEDGED FOR ANY PAYMENT UNDER THIS AGREEMENT. Revenues and assets of the State Water Resources Development System, and Bond Charges
under the Rate Agreement, shall not be liable for or available to make any payments or satisfy any obligation arising under this Agreement. If moneys on deposit in the Fund are insufficient to pay all
amounts payable by DWR under this Agreement, or if DWR has reason to believe such funds may become insufficient to pay all amounts payable by DWR under this Agreement, DWR shall diligently pursue an
increase to its revenue requirements as permitted under the Act from the appropriate Governmental Authority as soon as practicable. To the extent DWR's obligations are "administrative costs," they
will require annual appropriation by the legislature. 

11

 

        Section 10.04.    Cap on Liability.    In no event will Utility be liable to DWR for damages under this
Agreement, including indemnification obligations, whether in contract, warranty, tort (including negligence), strict liability or otherwise (referred to as "Damages" for purposes of this Section), in
an amount in excess of: 1) on an annual calendar year basis, $5 million plus ten percent of Damages in excess of $5 million and 2) for the entire term of this Agreement,
$50 million in total payments of
Damages to DWR. For example, if Damages for an event are $100 million, Utility's total liability for this event would be $14.5 million ($5 million plus10% of $95 million)
and that would be the full extent of Utility's liability for such Damages. All Damages associated with an event will apply only to the annual limit in the first year in which Damages for that event
were assessed. For example, if Damages for an event were paid as follows: $15 million in year 1 and $10 million in year 2, the Utility would pay DWR $7 million ($5 million
plus10% of $10 million for year 1 and 10% of $10 million for year 2). In this example, the $1 million paid to DWR in year 2 (10% of $10 million) does not count against the
year 2 $5 million calendar year threshold. DWR hereby releases Utility from any liability for Damages in excess of the limitations on liability set forth in this Section 10.04, provided
however, that this limitation on Utility liability shall not apply to the extent the liability is a result of Utility's gross negligence or willful misconduct. 

 
 

ARTICLE XI
  CONFIDENTIALITY    
    

        Section 11.01.    Proprietary Information.    

	(a)
	Nothing
in this Agreement shall affect Utility's obligations to observe any Applicable Law prohibiting the disclosure of Confidential Information regarding its customers.

	(b)
	Nothing
in this Agreement, and in particular nothing in Sections 11.01(e)(x) through 11.01(e)(z) of this Agreement, shall affect the rights of the Commission to obtain from
Utility, pursuant to Applicable Law, information requested by the Commission, including Confidential Information provided by DWR to Utility. Applicable Law, and not this Agreement, will govern what
information the Commission may disclose to third parties, subject to any confidentiality agreement between DWR and the Commission.

	(c)
	The
Parties acknowledge that each Party may acquire information and material that is the other Party's confidential, proprietary or trade secret information. As used herein,
"Confidential Information" means any and all technical, commercial, financial and customer information disclosed by one Party to the other (or obtained from one Party's inspection of the other Party's
records or documents), including any patents, patent applications, copyrights, trade secrets and proprietary information, techniques, sketches, drawings, maps, reports, specifications, designs,
records, data, models, inventions, know-how, processes, apparati, equipment, algorithms, software programs, software source documents, object code, source code, and information related to
the current, future and proposed products and services of each of the Parties, and includes, without limitation, the Parties' respective information concerning research, experimental work,
development, design details and specifications, engineering, financial information, procurement requirements, purchasing, manufacturing, business forecasts, sales and merchandising, and marketing
plans and information. In all cases, Confidential Information includes proprietary or confidential information of any third party disclosing such information to either Party in the course of such
third party's business or relationship with such Party. Utility's Confidential Information also includes any and all lists of customers, and any and all information about customers, both individually
and aggregated, including but not limited to customers' names, street addresses of customer residences and/or facilities, email addresses, identification numbers, Utility account numbers and
passwords, payment histories, energy usage, rate schedule history, allocation of energy uses among customer residences and/or facilities, and usage of DWR Power. All Confidential Information 

12

 

disclosed
by the disclosing Party ("Discloser") will be considered Confidential Information by the receiving Party ("Recipient") if identified as confidential and received from Discloser. 

	(d)
	Each
Party agrees to take all steps reasonably necessary to hold in trust and confidence the other Party's Confidential Information. Without limiting the generality of the immediately
preceding sentence, each Party agrees (i) to hold the other Party's Confidential Information in strict confidence, not to disclose it to third parties or to use it in any way, commercially or
otherwise, other than as permitted under this Agreement; and (ii) to limit the disclosure of the Confidential Information to those of its employees, agents or directly related subcontractors
with a need to know who have been advised of the confidential nature thereof and who have acknowledged their express obligation to maintain such confidentiality. DWR shall not disclose Confidential
Information to employees, agents or subcontractors that are in any respect responsible for power marketing or trading activities associated with the State Water Resources Development System.

	(e)
	The
foregoing two paragraphs will not apply to any item of Confidential Information if: (i) it has been published or is otherwise readily available to the public other than by
a breach of this Agreement; (ii) it has been rightfully received by Recipient from a third party without breach of confidentiality obligations of such third party and outside the context of the
provision of services under this Agreement; (iii) it has been independently developed by Recipient personnel having no access to the Confidential Information; (iv) it was known to
Recipient prior to its first receipt from Discloser, or (v) it has been summarized, processed and incorporated for incorporation into reports, discussions, statements or any other further work
product. In addition, Recipient may disclose Confidential Information if and to the extent required by law or a Governmental Authority, provided that (x) Recipient shall give Discloser a
reasonable opportunity to review and object to the disclosure of such Confidential Information, (y) Discloser may seek a protective order or confidential treatment of such Confidential
Information, and (z) Recipient shall make commercially reasonable efforts to cooperate with Discloser in seeking such protective order or confidential treatment. Discloser shall pay Recipient
its reasonable costs of cooperating. 

        Section 11.02.    No License.    Nothing contained in this Agreement shall be construed as granting to a Party
a license, either express or implied, under any patent, copyright, trademark, service mark, trade dress or other intellectual property right, or to any Confidential Information now or hereafter owned,
obtained, controlled by, or which is or may be licensable by, the other Party. 

        Section 11.03.    Survival of Provisions.    The provisions of this Article XI shall survive the
termination of this Agreement. 

 
 

ARTICLE XII
  RECORDS AND AUDIT RIGHTS    
    

        Section 12.01.    Records.    Utility shall maintain accurate records and accounts relating to the Contracts in
sufficient detail to permit DWR to audit and monitor the functions to be performed by Utility on behalf of DWR, as its limited agent, under this Agreement. In addition, Utility shall maintain accurate
records and accounts relating to DWR Revenues to be remitted by Utility to DWR, consistent with the Settlement Principles for Remittances and Surplus Revenues set forth in Exhibit C hereto.
Utility shall provide to DWR and its Assign(s) access to such records. Access shall be afforded without charge, upon reasonable request made pursuant to Section 12.02. Access shall be afforded
only during Business Hours and in such a manner so as not to interfere unreasonably with Utility's normal operations. Utility shall not treat DWR Revenues as income or assets of Utility or any
affiliate for any tax, financial reporting or regulatory purposes, and the financial books or records of Utility and affiliates shall be maintained in a manner consistent with the absolute ownership
of DWR Revenues by 

13

 

DWR
and Utility's holding of DWR Revenues in trust for DWR (whether or not held together with other monies). 

        Section 12.02.    Audit Rights.    

	(a)
	Upon
30 calendar days' prior written notice, DWR may request an audit, conducted by DWR or its agents (at DWR's expense), of Utility's records and procedures, which shall be limited
to records and procedures containing information bearing upon Utility's performance of its obligations under this Agreement. The audit shall be conducted during Business Hours without interference
with Utility's normal operations, and in compliance with Utility's security procedures.

	(b)
	As
provided in the Act, the State of California Bureau of State Audits (the "Bureau") shall conduct a financial and performance audit of DWR's implementation of Division 27
(commencing with Section 80000) of the California Water Code, and the Bureau shall issue a final report on or before March 31, 2003. In addition, as provided in Section 8546.7 of
the California Government Code, Utility agrees that, pursuant to this Section 12.02, DWR or the State of California Department of General Services, the Bureau, or their designated
representative ("DWR's Agent") shall have the right to review and to copy (at DWR's expense) any non-confidential records and supporting documentation pertaining to the performance of this
Agreement and to conduct an on-site review of any Confidential Information pursuant to Section 12.03 hereof. Utility agrees to maintain such records for such possible audit for
three years after final Remittance to DWR. Utility agrees to allow such auditor(s) access to such records during Business Hours and to allow interviews of any employees who might reasonably have
information related to such records. Further, Utility agrees to include a similar right for DWR or DWR's Agent to audit records and interview staff in any contract between Utility and a subcontractor
directly related to performance of this Agreement. 

        Section 12.03.    Confidentiality.    Materials reviewed by either Party or its agents in the course of an
audit may contain Confidential Information subject to Article XI above. The use of all materials provided to
DWR or Utility or their agents, as the case may be pursuant to this Article XII, shall comply with the provisions in Article XI and shall be limited to use in conjunction with the
conduct of the audit and preparation of a report for appropriate distribution of the results of the audit consistent with Applicable Law. 

        Section 12.04.    Annual Certifications.    At least annually, and in no event later than the tenth Business
Day after the end of the calendar year, Utility shall deliver to DWR a certificate of an authorized representative certifying that to the best of such representative's knowledge, after a review of
Utility performance under this Agreement, Utility has fulfilled its obligations under this Agreement in all material respects and is in compliance herewith in all material respects. 

        Section 12.05.    Additional Applicable Laws.    Each Party shall make an effort to promptly notify the other
Party in writing to the extent such Party becomes aware of any new Applicable Laws or changes (or proposed changes) in Applicable Tariffs hereafter enacted, adopted or promulgated that may have a
material adverse effect on either Party's ability to perform its duties under this Agreement. A Party's failure to so notify the other Party pursuant to this Section 12.05 will not constitute a
material breach of this Agreement, and will not give rise to any right to terminate this Agreement or cause either Party to incur any liability to the other Party or any third party. 

        Section 12.06.    Other Information.    Upon the reasonable request of DWR or its Assign(s), Utility shall
provide to DWR or its Assign(s) any public financial information in respect of Utility applicable to services provided by Utility under this Agreement, to the extent such information is reasonably
available to Utility, which (i) is reasonably necessary and permitted by Applicable Law to monitor the performance by Utility hereunder, or (ii) otherwise relates to the exercise of
DWR's rights or the 

14

 

discharge
of DWR's duties under this Agreement or any Applicable Law. In particular, but without limiting the foregoing, Utility shall provide to DWR any such information that is necessary or useful
to calculate DWR's revenue requirements (as described in Sections 80110 and 80134 of the California Water Code). 

        Section 12.07.    Data and Information Retention.    All data and information associated with the provision and
receipt of services pursuant to this Agreement shall be maintained for the greater of (a) the retention time required by Applicable Law or Applicable Tariffs for maintaining such information,
or (b) three (3) years. 

 
 

ARTICLE XIII
  DISPUTE RESOLUTION    
    

        Section 13.01.    Dispute Resolution.    Should any dispute arise between the Parties or should any dispute
between the Parties arise from the exercise of either Party's audit rights contained in Section 12.02 hereof, the Parties shall remit any undisputed amounts and agree to enter into good faith
negotiations as soon as practicable to resolve such disputes within (10) Business Days so as to resolve such disputes, as appropriate, within the timeframes provided under this Agreement, or as
soon as possible thereafter. For any disputed Remittances, if such resolution cannot be made before the remittance date, Utility shall remit the undisputed portion to DWR. In addition, the disputed
portion of the Remittances shall be deposited into an escrow account held by a qualified, independent escrow holder. Upon resolution of such disputes, the Party that escrowed the disputed amount shall
reimburse the other Party from the escrow account as necessary. 

        Section 13.02.    ISO Settlements Disputes.    Utility shall review, validate and verify all ISO
charges/credits contained on all ISO settlement statements, including any charges/credits resulting from functions related to the Contracts to be performed by Utility as provided in this Agreement.
Utility shall inform DWR of any discrepancies and shall dispute any such discrepancies with the ISO in accordance with the ISO's tariff and protocols. Except as provided in Section 13.03, if
any ISO charge type settlement amount appearing on a Preliminary or Final Settlement Statement (as defined in the ISO tariff) resulting or relating to the Utility's performance of functions related to
the Contracts under this Agreement is in dispute, it shall be the responsibility of Utility, on behalf of DWR, as its limited agent, to seek resolution of said dispute through the ISO dispute
resolution process as provided in the ISO's tariff. 

        For
disputes affecting Utility's Remittances to DWR, including disputes on ISO charges to non-DWR parties that would affect Remittances to DWR, Utility shall provide to DWR:
a) notification of submission of the dispute through the ISO dispute resolution process, identifying, among other items, the dispute type, quantity, price and allocation; b) a copy of
the submitted dispute and all supporting data; and c) a copy of all ensuing documentation resulting from the ongoing dispute resolution process. Utility shall track and validate all disputed
ISO charges involving any financial responsibility of DWR. 

        Section 13.03.    Supplier Invoice Disputes.    DWR shall continue to be responsible for all dispute resolution
relating to Supplier invoices. In addition, except as specifically provided in Exhibit E of this Agreement, all other contract administration functions shall remain DWR's responsibility. 

        Section 13.04.    Good-Faith Negotiations.    Should any dispute arise between the Parties relating
to this Agreement, the Parties shall undertake good-faith negotiations to resolve such dispute. If the Parties are unable to resolve such dispute through good-faith
negotiations, either Party may submit a detailed written summary of the dispute to the other Party. Upon such written presentation, each Party shall designate an executive with authority to resolve
the matter in dispute. If the Parties are unable to resolve such dispute within 30 days from the date that a detailed summary of such dispute is presented in writing to the other Party, and the
dispute relates solely to Utility's conduct, performance, acts 

15

 

and/or
omissions (and not to DWR's conduct performance, acts and/or omissions), then DWR may, at its sole discretion, present the dispute to the Commission for resolution, in accordance with
Applicable Law. All other disputes shall be brought in a court of competent jurisdiction or a forum mutually acceptable to the Parties in accordance with Applicable Law. Nothing herein shall preclude
either Party from challenging the decision or action which such Party deems may adversely affect its interests in any appropriate forum of the Party's choosing. 

        Section 13.05.    Costs.    Each Party shall bear its own respective costs and attorney fees in connection with
respect to any dispute resolution process undertaken by it pursuant to this Article. Provided, however, DWR shall reimburse Utility all reasonably incurred costs, including, but not limited to,
in-house and retained attorneys, consultants, witnesses, and arbitration costs, arising from or pertaining to all disputes relating to ISO charges/credits contained on all ISO settlement
statements resulting from the operational, dispatch and administrative functions related to the Contracts performed by Utility on behalf of DWR, as its limited agent, pursuant to the standards set
forth in Section 2.02 herein and consistent with the provisions of the ISO tariff, as may be amended from time to time, including disputes on ISO charges to non-DWR parties that
would affect Remittances to DWR. These costs shall be recorded and invoiced in the manner set forth in Section 8.01 hereof. 

 
 

ARTICLE XIV
  MISCELLANEOUS    
    

        Section 14.01.    Assignment    

	(a)
	Except
as provided in paragraphs (b) (c), (d) and (e) below, neither Party shall assign or otherwise dispose of this Agreement, its right, title or interest
herein or any part hereof to any entity, without the prior written consent of the other Party. No assignment of this Agreement shall relieve the assigning Party of any of its obligations under this
Agreement until such obligations have been assumed by the assignee. When duly assigned in accordance with this Section 14.01(a) and when accepted by the assignee, this Agreement shall be
binding upon and shall inure to the benefit of the assignee. Any assignment in violation of this Section 14.01 (a) shall be void.

	(b)
	Utility
acknowledges and agrees that DWR may assign or pledge its rights to receive performance hereunder to a trustee or another party ("Assign(s)") in order to secure DWR's
obligations under its bonds (as that term is defined in the Act), and any such Assign shall be a third party beneficiary of this Agreement; provided, however, that this authority to assign or pledge
rights to receive performance hereunder shall in no event extend to any person or entity that sells power or other goods or services to DWR.

	(c)
	Any
person (i) into which Utility may be merged or consolidated, (ii) which may result from any merger or consolidation to which Utility shall be a party or
(iii) which may succeed to the properties and assets of Utility substantially as a whole, which person in any of the foregoing cases executes an agreement of assumption to perform every
obligation of Utility hereunder, shall be the successor to Utility under this Agreement without further act on the part of any of the Parties to this Agreement; provided, however, that Utility shall
have delivered to DWR and its Assign(s) an opinion of counsel reasonably acceptable to DWR stating that such consolidation, merger or succession and such agreement of assumption complies with this
Section 13.01(c) and that all of Utility's obligations hereunder have been validly assumed and are binding on any such successor or assign.

	(d)
	Notwithstanding
anything to the contrary herein, DWR's rights and obligations hereunder shall be transferred, without any action or consent of either Party hereto, to any entity
created by the State legislature which is required under Applicable Law to assume the rights and obligations of DWR under Division 27 of the California Water Code. 

16

 

	(e)
	Notwithstanding
anything to the contrary herein, Utility's rights and obligations under this Agreement may be assigned to the reorganized debtor under a plan of reorganization
approved by the Bankruptcy Court for Utility without any action or consent of either Party hereto. 

        Section 14.02.    Force Majeure.    Neither Party shall be liable for any delay or failure in performance of
any part of this Agreement (including the obligation to remit money at the times specified herein) from any cause beyond its reasonable control, including but not limited to, unusually severe weather,
flood, fire, lightning, epidemic, quarantine restriction, war, sabotage, act of a public enemy, earthquake, insurrection, riot, civil disturbance, strike, restraint by court order or Government
Authority, or any combination of these causes, which by the exercise of due diligence and foresight such Party could not reasonably have been expected to avoid and which by the exercise of due
diligence is unable to overcome. 

        Section 14.03.    Severability.    In the event that any one or more of the provisions of this Agreement shall
for any reason be held to be unenforceable in any respect under applicable law, such unenforceability shall not affect any other provision of this Agreement, but this Agreement shall be construed as
if such unenforceable provision or provisions had never been contained herein. 

        Section 14.04.    Survival of Payment Obligations.    Upon termination of this Agreement, each Party shall
remain liable to the other Party for all amounts owing under this Agreement. Utility shall continue to collect and remit, pursuant to the terms of the Servicing Arrangement and the principles provided
in the Settlement Principles for Remittances and Surplus Revenues provided in Exhibit C hereto and any DWR Charges billed to customers or any DWR Surplus Energy Sales Revenues attributable to
sales entered into before the effective date of termination of the Servicing Arrangement. 

        Section 14.05.    Third-Party Beneficiaries.    The provisions of this Agreement are exclusively for the
benefit of the Parties and any permitted assignee of either Party and there are no third party beneficiaries under this Agreement. 

        Section 14.06.    Governing Law.    This Agreement shall be interpreted, governed and construed under the laws
of the State of California without regard to choice of law provisions. 

        Section 14.07.    Multiple Counterparts.    This Agreement may be executed in multiple counterparts, each of
which shall be an original. 

        Section 14.08.    Section Headings.    Section and paragraph headings appearing in this Agreement are inserted
for convenience only and shall not be construed as interpretations of text. 

        Section 14.09.    Amendments.    No amendment, modification, or supplement to this Agreement shall be effective
unless it is in writing and signed by the authorized representatives of both Parties and approved as required, and by reference incorporates this Agreement and identifies the specific portions that
are amended, modified, or supplemented or indicates that the material is new. No oral understanding or agreement not incorporated in this Agreement is binding on either of the Parties. 

        Section 14.10.    Amendment Upon Changed Circumstances.    The Parties acknowledge that compliance with any
Commission decision, legislative action or other governmental action (whether issued before or after the Effective Date of this Agreement) affecting the operation of this Agreement, including but not
limited to (i) dissolution of the ISO, (ii) changes in the ISO market structure, (iii) a decision regarding direct access currently pending before the Commission, (iv) the
establishment of other Governmental Programs, or (v) a modification to the Contract Allocation Agreement may require that amendment(s) be made to this Agreement. The Parties therefore agree
that if either Party reasonably determines that such a decision or action would materially affect the services to be provided hereunder or the reasonable costs thereof, then upon the issuance of such
decision or the approval of such action (unless and until it is stayed), the Parties will negotiate the amendment(s) to this 

17

 

Agreement
that is (or are) appropriate in order to effectuate the required changes in services to be provided or the reimbursement thereof. If the Parties are unable to reach agreement on such
amendments within 60 days after the issuance of such decision or approval of such action, either Party may, in the exercise of its sole discretion, submit the disagreement to the Commission for
proposed resolution. Nothing herein shall preclude either Party from challenging the decision or action which such Party deems may adversely affect its interests in any appropriate forum of the
Party's choosing. 

        The
Parties agree that, if the rating agencies request changes to this Agreement which the Parties reasonably determine are necessary and appropriate, the Parties will negotiate in good
faith, but will be under no obligation to reach agreement or to ask the Commission to amend this Agreement to accommodate the rating agency requests and will cooperate in obtaining any required
approvals of the Commission or other entities for such amendments. 

        Section 14.11    Indemnification.    

	(a)
	Indemnification of DWR.    Utility (the "Indemnitor") shall at all times protect, indemnify, defend and hold harmless DWR,
and its elected officials, appointed officers, employees, representatives, agents and contractors (each, an "Indemnified Party" or an "Indemnitee") from and against (and pay the full amount of) any
and all claims (whether in tort, contract or otherwise), demands, expenses (including, without limitation, in-house and retained attorneys' fees) and liabilities for losses, damage, injury
and liability of every kind and nature and however caused, and taxes (of any kind and by whomsoever imposed), to third parties arising from or in connection with (or alleged to arise from in
connection with): (1) any failure by Utility to perform its material obligations under this Agreement; (2) any material representation or warranty made by Utility shall prove to be
false, misleading or incorrect in any material respect as of the date made; (3) the gross negligence or willful misconduct of Utility or any of its officers, directors, employees, agents,
representatives, subcontractors or assignees in connection with this Agreement; and (4) any violation of or failure by Utility or Indemnitor to comply with any Applicable Commission Orders or
Applicable Law; provided, however, that the foregoing indemnifications and protections shall not extend to any losses arising from gross negligence or willful misconduct of any Indemnified Party.

	(b)
	Obligation of Utility.    Consistent with the Contract Allocation Order, Utility shall not, in acting as limited agent of DWR
hereunder be required to perform any obligations of any Supplier under any Allocated Contract or to make any payments on behalf of such Supplier or as the result of the failure of such Supplier to
perform under any Allocated Contract.

	(c)
	Indemnification of Utility.    To the extent permitted by law, DWR ("Indemnitor") shall at all times protect, indemnify,
defend and hold harmless Utility, and its officers, employees, representatives, agents and contractors (each, an "Indemnified Party" or "Indemnitee"), from and against (and pay the full amount of) any
and all claims (whether in tort, contract or otherwise), demands, expenses (including, without limitation, in-house and retained attorneys' fees) and liabilities for losses, damage, injury
and liability of every kind and nature and however caused, and taxes (of any kind and by whomsoever imposed), to third parties arising from or in connection with (or alleged to arise from on in
connection with): (1) any failure by DWR to perform its material obligations under this Agreement or any Allocated Contract and, prior to novation, any Interim Contract; (2) any
material representation or warranty made by DWR shall prove to be false, misleading or incorrect in any material respect as of the date made; (3) the gross negligence or willful misconduct of
the DWR or any of its officers, directors or employees, agents, representatives, subcontractors or assignees in connection with this Agreement; (4) any action claiming Utility failed to perform
any Supplier's obligations under a Contract; and (5) any violation of or failure by DWR or Indemnitor to comply with any Applicable Law; and provided, however, that the foregoing 

18

 

indemnifications
and protections shall not extend to any losses arising from the gross negligence or willful misconduct of any Indemnified Party. 

	(d)
	Indemnification Procedures.    Indemnitee shall promptly give notice to Indemnitor of any claim or action to which it seeks
indemnification from Indemnitor. Indemnitor shall defend any such claim or action brought against it, and may also defend such claim or action on behalf of the Indemnitee (with counsel reasonably
satisfactory to Indemnitor) unless there is any actual or potential conflict between Indemnitor and Indemnitee with respect to such claim or action. If there is any actual or potential conflict
between Indemnitor and Indemnitee with respect to such claim or action, Indemnitee shall have the opportunity to assume (at Indemnitor's expense) defense of any claim or action brought against
Indemnitee by a third party; however, failure by Indemnitee to request defense of such claim or action by the Indemnitor shall not affect Indemnitee's right to indemnity under this
Section 14.11. In any action or claim involving Indemnitee, Indemnitor shall not settle or compromise any claim without the prior written consent of Indemnitee. 

        Section 14.12.    Notices and Demands.    (a) Except as otherwise provided under this Agreement, all
notices, demands, or requests pertaining to this Agreement shall be in writing and shall be deemed to have been given (i) on the date delivered in person, (ii) on the date when sent by
facsimile (with receipt
confirmed by telephone by the intended recipient or his or her authorized representative) or electronic transmission (with receipt confirmed telephonically or electronically by the intended recipient
or his or her authorized representative) or by special messenger, or (iii) 72 hours following delivery to a United States post office when sent by certified or registered United States
mail postage prepaid, and addressed as set forth below: 

	Utility:
	Pacific
Gas and Electric Company

245 Market Street, Room 1267

San Francisco, CA 94105-1814

	Attn:
	Roy
Kuga

Lead Director of Gas and Electric Supply

Telephone: (415) 973-3806

Facsimile: (415) 973-0585

Email: rmk4@pge.com

	DWR:
	State
of California

The Resources Agency

Department of Water Resources

California Energy Resources Scheduling Division

3310 El Camino Avenue, Suite 120

Sacramento, California 95821

	Attn:
	Peter
S. Garris

Deputy Director

Telephone: (916) 574-2733

Facsimile: (916) 574-0301

Email: pgarris@water.ca.gov

	(a)
	Each
Party shall be entitled to specify as its proper address any other address in the United States, or specify any change to the above information, upon written notice to the other
Party complying with this Section 14.12.

	(b)
	Each
Party shall designate on Attachment A the person(s) to be contacted with respect to specific operational matters. Each Party shall be entitled to specify any change to such
person(s) upon written notice to the other Party complying with this Section 14.12. 

19

 

        Section 14.13.    Approval.    This Agreement shall be effective upon the execution by both Parties and
approval of such executed agreement by the Commission. Except as expressly provided otherwise herein, neither Party may commence performance hereunder until such date. Any delay in the commencement of
performance hereunder as a consequence of waiting for such approval(s) shall not be a breach or default under this Agreement. 

        Section 14.14.    Government Code and Public Contract Code Inapplicable.    DWR has determined, pursuant to
Section 80014(b) of the California Water Code, that application of certain provisions of the Government Code and Public Contract Code applicable to State contracts, including but not limited to
advertising and competitive bidding requirements and prompt payment requirements, would be detrimental to accomplishing the purposes of Division 27 (commencing with Section 80000) of the
California Water Code and that such provisions and requirements are therefore not applicable to or incorporated in this Agreement. 

        Section 14.15.    Annual Review.    The provisions of the Exhibits are subject to annual review by DWR and
Utility to ensure their relevance and usefulness. In the event that the Parties mutually agree that certain provisions of the Exhibits should be amended or supplemented, an amendment to the Exhibit
should be executed and Utility shall submit to the Commission for approval. 

        Section 14.16    Other Operating Agreement.    It is DWR's intent to have a consistent operating agreement with
all three investor-owned utilities (IOUs). Should DWR reach an operating agreement with another IOU relating to the subject matter of this Agreement, that in Utility's judgment is more favorable on
the whole than this Agreement, Utility shall have the right to receive the same terms and conditions as such other IOU. This provision specifically does not allow Utility to select particular portions
or provisions of such other IOU's operating agreement. In addition, if Utility elects to be subject to such other IOU's operating agreement's terms and conditions, Utility shall be subject to such
other IOU's operating agreement with only such modifications agreed to by DWR as necessary to address operating differences between that other IOU and Utility. Utility shall exercise the foregoing
right within 60 days following Commission approval of such other operating agreement. 

        IN
WITNESS WHEREOF, the Parties have executed this Agreement on the date or dates indicated below, to be effective as of the Effective Date. 

	CALIFORNIA STATE DEPARTMENT OF WATER RESOURCES, acting solely under the authority and powers granted by AB1X, codified as Sections 80000 through 80270 of the Water Code, and not under its powers and responsibilities with
respect to the State Water Resources Development System	 	PACIFIC GAS & ELECTRIC COMPANY, a California corporation
	

By:	
 	

/s/  VIJU PATEL      
	
 	

By:	
 	

/s/  ROY M. KUGA      

	Name:	 	Viju Patel	 	Name:	 	Roy M. Kuga
	Title:	 	Executive Manager	 	Title:	 	Vice President, Gas & Electric Supply
	Date:	 	11/12/04	 	Date:	 	11-12-04

20

  

 
 

Schedule 1    

 
 

ALLOCATED CONTRACTS    
    

 
 

Schedule 2    

 
 

INTERIM CONTRACTS    
    

 
 

Schedule 3    

 
 

REPRESENTATIVES AND CONTACTS    
    

21

 
 

DWR/PG&E EXHIBIT A
  
    OPERATING PROTOCOLS    
    

 
 
 

EXHIBIT A
  
    OPERATING PROTOCOLS    
    

        Pursuant to Section 4.01 of this Agreement, on behalf of DWR as its limited agent, Utility shall perform the day-to-day scheduling
and dispatch functions, including day-ahead, hour-ahead and real-time trading, scheduling of transactions with all involved parties, making surplus energy sales and
obtaining relevant information for these functions such as transmission availability and others, with respect to the Allocated Contracts set forth in Schedule 1 to the Agreement, and, prior to
novation, the Interim Contracts set forth in Schedule 2, all as more specifically provided below and in compliance with the provisions of each of the Contracts: 

	I.
	Resource Commitment and Dispatch.    Utility agrees to use good faith efforts to dispatch Allocated Contracts, and, prior to
novation, Interim Contracts, based on the principle of "least cost dispatch" to retail customers, consistent with the Contract Allocation Order and other Applicable Commission Orders. Utility shall
undertake these least cost dispatch functions both of the Contracts and its URG so as to minimize the cost of service to retail customers based on circumstances known or that reasonably could have
been known by Utility at the time dispatch decisions are made. DWR shall have no role in enforcement or review of Utility least cost dispatch under this Agreement and all issues of Utility compliance
with least cost dispatch shall be within the sole review of the Commission.

	A.
	Annual, Quarterly and Weekly Load and Resource Assessment Studies.    Utility shall provide to DWR copies of its annual and
quarterly load and resource assessment studies. Provided that Utility submits substantially the same information to the Commission, copies of the Commission submission will be simultaneously sent to
DWR to satisfy requirements of this section. In addition, Utility will provide a weekly commitment and dispatch plan for informational purposes to DWR in the same form that such plan is used
internally.

	B.
	Scheduling Protocols.

	1.
	DWR
is responsible for notifying the counter-party to each of the Allocated Contracts that scheduling under the Allocated Contracts will be performed by Utility before the first day
that schedules are due to be submitted by Utility. DWR is responsible for notifying Utility of any changes to the Allocated Contracts that it has negotiated, including changes to the scheduling terms.
DWR agrees to provide such notice as soon as possible following the negotiation of any changed provisions and in any case prior to the time that any changed provisions become effective. 

To
the extent that any of the Interim Contracts are amended or modified by DWR or Utility, including changes to the scheduling terms, DWR and Utility agree to provide such notice to the other Party as
soon as possible following the negotiation of any changed provisions and in any case prior to the time that any such changed provisions become effective. 

	2.
	Utility
agrees to schedule Contracts in accordance with their terms and in accordance with the requirements of the Control Area operator or operators with whom the Contract must be
scheduled to provide for power delivery.

	II.
	ISO Ancillary Service (AS) Market.    Among the Contracts are resources that are or may be qualified to be bid into the ISO's
Ancillary Services ("AS") market or that Utility may use in its self-provision of AS. Utility is authorized to develop protocols and procedures for the use of DWR resources for AS. Utility
shall, upon DWR's request, provide to DWR such information concerning Utility's intended use of DWR resources for AS as DWR may reasonably request for planning and revenue requirement purposes. 

1

 
	III.
	Surplus Energy Sales and Energy Exchanges

	A.
	Over-generation.    If the ISO announces an over-generation situation Utility will back down resources
in accordance with the ISO tariff and Good Utility Practice. In order to reduce the need for physical curtailment in over-generation situations, DWR and Utility shall develop pay for
curtailment protocols and procedures that will enable Utility to instruct a must-take resource not to deliver energy under specified conditions. The costs and charges associated with
mitigation of an over-generation situation shall be allocated among the Parties on a pro-rata basis consistent with the surplus sales allocation principles set forth in
Exhibit C.

	B.
	Energy Exchange Arrangements.    Existing non-DWR/CERS exchanges and those that might be transacted
post-2002, will be considered URG exchanges. The accounting of energy necessary to support energy exchanges is addressed in Exhibit C.

	C.
	Surplus Energy Sales Arrangement.    Utility shall on a monthly basis prepare a sales plan addressing all surplus sales,
including without limitation sales to manage over-generation, contemplated by the Utility for review by DWR. Such plan shall address sales of power from the combined portfolio of URG
resources and Contracts, which will be administered by Utility on its own behalf and acting as DWR's limited agent. As specified in Section 2.02 of the Agreement, Utility shall pursue surplus
sales in a fashion reasonably designed to serve the overall best interests of retail electric customers based on information known or could have been known by Utility at the time. Utility agrees to
include sufficient details in the sales plans to allow DWR to satisfy its financial management and reporting requirements. To the extent there is surplus power uncommitted to a forward energy surplus
sales transaction, Utility shall be required to bid such surplus energy in the day-ahead, hour-ahead or real-time market. Utility shall arrange for transmission
service to accommodate surplus sales to the extent that transmission service is available and cost effective. The costs of transmission service, ISO charges and the costs of firm transmission rights
associated with such surplus energy sales transactions shall be treated in accordance with the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C.

	IV.
	Outage Coordination and Determination of Resource Availability of Contracts.    Utility shall communicate with the Scheduling
Coordinator of each Contract to coordinate, approve, document and report planned Contract outages. For those Contracts where resource availability affects capacity payments, Utility will use good
faith efforts to verify supplier actual resource availability, and keep records of resource availability as reported by Supplier. In addition, Utility shall document all outages (forced and planned)
and notices of outages of DWR contract resources and provide such documents to DWR within five (5) business days after the end of each calendar month. Interim Contracts Utility and DWR agree
that the Attachments and data requirements associated with this Agreement will be updated as needed to incorporate the addition of new Interim Contracts entered into after the execution date of this
Agreement. 

2

 
 

DWR/PG&E EXHIBIT B
  
    FUEL MANAGEMENT PROTOCOLS    
    

 
 
 

EXHIBIT B
  FUEL MANAGEMENT PROTOCOLS    
    

        Certain of the Contracts listed on Schedule 1 of this Agreement provide DWR the option of either (i) letting the Supplier provide the necessary
natural gas for its generating units at an index-based price or agreed upon fixed price or (ii) DWR procuring the gas supply and causing such supply to be delivered to the Supplier under a
tolling arrangement ("Fuel Option"). Certain of the Contracts with Fuel Option provide that DWR can decide on a monthly basis whether to procure the gas and others provide that the decision be made
annually or semi-annually when DWR reviews the Supplier's proposed fuel plan. 

        The
purpose of this Exhibit B is to describe the relationship which will exist between DWR and Utility and the specific responsibilities of each as they all relate to managing the
natural gas provisions of the Contracts which include Fuel Options. Specifically, this Exhibit B will address responsibilities for the following activities: (i) determining types and
lengths of gas contracts, (ii) nominating deliveries, (iii) contracting for gas transportation and storage, (iv) managing imbalances, (v) reviewing, authorizing and making
payment of gas invoices and (vi) determining and implementing hedge strategies, as appropriate. 

	I.
	Operating Relationship Between DWR and Utility

While
DWR will retain legal and financial responsibility for gas and related services, Utility shall, as a limited agent acting for DWR, perform the administrative and operational activities, as
further specified below, required to ensure adequate gas is supplied to Suppliers' generating units, consistent with the tolling provisions included in the Contracts. The intent of this relationship
is to provide Utility sufficient flexibility and authority to execute normal day-to-day activities associated with managing the fuel provisions of tolling Contracts and
procurement of natural gas and related services, as a limited agent acting on behalf of DWR without direct involvement by DWR but in a manner consistent with Utility Gas Supply Plans which have been
reviewed and approved by DWR and the Commission. 

	II.
	Fuel Activities

Consistent
with the terms of the Contracts with Fuel Options, Utility shall have administrative and operational authority to act, as a limited agent, for fuel supply related activities, consistent
with the following goals and guidelines whenever Utility has recommended, and DWR has reviewed and approved such recommendation that gas for a Contract with Fuel Option be caused to be supplied by
Utility from a list of approved providers. 

	1.
	Utility
shall use reasonable commercial efforts to secure delivery of gas in a reliable manner and consistent with gas requirements for producing scheduled energy.

	2.
	Utility
shall develop a portfolio of gas supply for the Contracts that contain Fuel Options and where Utility is to supply gas, acting as limited agent on behalf of DWR, consistent
with the approved Utility Gas Supply Plans. Such portfolio should be diversified in terms of price mechanism, period of performance, and gas suppliers.

	3.
	Utility
shall develop a portfolio of supply which is reasonably priced relative to the market and in accordance with an approved Utility Gas Supply Plan.

 

	III.
	Review of Supplier Fuel Plans

In
accordance with the terms of each of the Contracts with Fuel Options, Utility, acting as a limited agent on behalf of DWR, shall review each fuel plan prepared and submitted by the Supplier, and
forwarded to the Utility by DWR, and determine whether to recommend (i) approval of the Supplier Fuel Plan and authorization for the Supplier to provide gas to its generating unit(s), or
(ii) procurement and management of gas supplies to the generating unit(s) by Utility. Utility, acting as a limited agent on behalf of DWR, shall advise DWR and the 

1

 

Commission
on a timely basis of its recommendation regarding responsibility for supplying natural gas. DWR shall, on a timely basis, review Utility's recommendation and either approve or identify
requested changes. Once approved, Utility shall advise the Supplier in accordance with the time requirements included in the appropriate Contract with Fuel Option. In addition, for any Supplier Fuel
Plans which have been implemented and are operative as of the Effective Date, and where DWR has previously elected to be responsible for gas supply, Utility may advise DWR that it would rather have
Supplier provide the gas as of the Effective Date. DWR shall coordinate with Utility and Supplier to revise such Supplier Fuel Plans, to the extent possible, prior to the Effective Date. 

	IV.
	Fuel Procurement Strategies

Under
the Contracts with Fuel Option, upon Utility's recommendation, and DWR's review and approval of such recommendation, Utility will be responsible for procuring the natural gas fuel from a list of
approved gas providers. Utility shall, acting as the limited agent of DWR, have administrative and operational responsibility for determining its gas procurement strategies, including but not limited
to (i) types of contracts, (ii) length of contracts, (iii) pricing terms, (iv) use of storage, (v) types of gas transportation, (vi) delivery point(s),
(vii) whether and how to obtain gas price forecasts, (viii) if and what risk management tools are to be used, and (ix) how to maintain current market intelligence. 

Utility
shall consolidate these strategies and submit them to DWR and the Commission as a "Utility Gas Supply Plan" by April 17, 2003 and, thereafter on a semi-annual basis during
the Term. Utility may also provide a copy of such Gas Supply Plan to DWR in advance of the filing with the Commission so as to be able to indicate DWR's approval of such plan. Utility shall indicate
in its Advice Letter filing to the Commission whether DWR has approved such plan as appropriate. DWR shall also formally notify the Commission when it has approved such plan. 

DWR
and the Commission will review and approve the Utility Gas Supply Plans. In the event of conflicting guidance between the Commission and DWR regarding various aspects of the Gas Supply Plan they
respectively approve or reject, where DWR only approves a subset of what the Commission approves, then Utility shall operate within the sphere of DWR's approval. If, however, the Commission explicitly
rejects portions of the Gas Supply Plan that DWR would authorize, then Utility must operate within the limitations of the Commission's decision. After a reasonable period of time operating within the
framework of the Gas Supply Plans and the Commission's and DWR's respective approval and/or rejection of various pieces of the Gas Supply Plan, the Parties agree to meet and confer to determine
whether the approval process may need to be revised in some manner, and Utility shall submit to Commission any such proposed revisions. Once approved, Utility may act within such Utility Gas Supply
Plan without further DWR involvement, except as provided below. 

	V.
	Gas Purchasing

Utility
and DWR shall jointly determine a list of approved gas providers who can be used to supply gas under the Contracts with Fuel Options. Master agreements intended to cover normal
day-to-day volumes will then be executed with such approved providers. While DWR will be the executing party under all DWR gas contracts, such agreements shall specifically
authorize Utility to act for and on behalf of DWR, as a limited agent, in negotiating specific prices, quantities and delivery periods for specific purchases under such master agreements; provided
however, on the earliest practicable date after the execution of this Agreement, DWR agrees to provide to Utility in writing and in advance of such negotiations any limits, including without
limitation any terms, that may be required by DWR. If Utility determines it would be beneficial to enter into any DWR gas contract which exceeds 3 months or have a total value exceeding
$10 million, it shall negotiate such agreement(s) and submit them to DWR for advance approval and execution. 

2

 
	VI.
	Gas Transportation

Utility
shall have responsibility for recommending to DWR which pipelines should transport gas if Utility, acting as limited agent on behalf of DWR is to supply gas under a Contract with Fuel Option.
Following approval of or revision of Utility Gas Supply Plan, Utility shall negotiate firm and/or interruptible agreements with such pipelines, consistent with the Utility Gas Supply Plan and submit
them to DWR for execution. While DWR will be the executing party, such agreements with pipelines shall specifically authorize Utility to act for and on behalf of DWR in nominating gas deliveries,
making imbalance trades and managing gas volumes transported under such agreements provided, however, on the earliest practicable date after the execution of this Agreement, DWR agrees to provide to
Utility in writing and in advance of such negotiations any limits, including without limitation any terms, that may be required by DWR. 

	VII.
	Gas Scheduling

If
permitted under the Contracts, the Utility shall have full administrative and operational responsibility for scheduling gas deliveries, whether to a specific generating plant or to storage for all
gas contracts entered into by DWR or by Utility on DWR's behalf pursuant to this Exhibit B. This function includes use of interstate and intrastate gas pipeline provider websites, confirming
via telephone, and all other activities required to move gas from the designated delivery point, as determined by the Utility, to its destination, as determined by the Utility. 

	VIII.
	Storage Capacity, Injections and Withdrawals

Utility
shall have responsibility for devising plans for gas storage, if Utility, acting as limited agent on behalf of DWR, is to supply gas under Contracts with Fuel Option from a list of approved
providers. Following approval of the Utility Gas Supply Plans, Utility shall negotiate firm and/or interruptible agreements with such storage service providers and submit them to DWR for execution.
While DWR will be the executing party with DWR remaining the principal under such contracts, such agreements with storage service providers shall specifically authorize Utility to act for and on
behalf of DWR in nominating gas injections and withdrawals under such agreements; provided, however, on the earliest practicable date after the execution of this Agreement, DWR agrees to provide to
Utility in writing and in advance of such negotiations any limits, including without limitation any terms, that may be required by DWR. 

	IX.
	Managing Gas Delivery/Usage Imbalances

For
gas that it purchases and transports on behalf of DWR, Utility shall have full administrative and operational responsibility for monitoring and managing the daily status of gas usage vs. gas
deliveries (i.e. gas imbalances). In addition, to the extent that gas transportation providers issue operational flow orders or require adjustments in scheduled gas deliveries due to system
constraints, Utility, acting as limited agent on behalf of DWR, shall be responsible for compliance with such orders. Utility shall also be responsible for any penalties imposed by gas transportation
providers for imbalances caused by Utility, due to its failure to exercise prudent gas management practices. 

	X.
	Invoice Review, Approval and Payment

For
natural gas, pipeline transportation and storage services it purchases in accordance with this Exhibit B, Utility, acting as limited agent on behalf of DWR, shall have responsibility for
receiving invoices from gas, transportation and storage suppliers, reviewing them for accuracy, approving/rejecting invoices for payment and forwarding to DWR for payment; provided, however, on the
earliest practicable date after the execution of this Agreement, DWR agrees to cause Utility to be authorized to receive such information from Suppliers. Utility shall provide DWR sufficient
documentation to verify payment of the invoices. 

3

 
	XI.
	Forecasting

Utility
shall be responsible for all gas price, demand and supply forecasts which Utility believes are consistent with any accepted gas supply responsibilities. 

	XII.
	Risk Management

Utility
shall develop and include in its Gas Supply Plans, plans for the hedging of DWR Fuel Supply costs. Final decisions relating to the use or non-use of financial tools such as
futures, options and swaps to hedge future gas price exposure on any gas volumes not hedged by Utility under the Utility Gas Supply Plans shall be made and implemented by DWR. Any such contracts
executed by DWR on a "portfolio basis" should be utility-specific. 

	XIII.
	Market Intelligence

Any
and all efforts to obtain, analyze and utilize market intelligence for decision-making purposes shall be the responsibility of Utility. 

	XIV.
	Payment of Gas Costs

For
natural gas, pipeline transportation, financial hedges and storage services that are purchased and provided by a Supplier under an approved Fuel Supply Plan, DWR shall pay such gas related costs
as part of the invoice for commodity, product, or services submitted by the Supplier. For natural gas, pipeline transportation and storage services provided under DWR contracts and administered by
Utility on behalf of DWR, DWR shall pay invoices after they have been reviewed and approved for payment by Utility. 

	XV.
	Allocation of Existing DWR Gas Contracts

DWR
has entered into gas supply, transportation and storage contracts as provided in Attachment 1 to this Exhibit B that have expiration dates after the Effective Date of this Agreement. The
administrative and operational control of the contracts listed on Attachment 1 to this Exhibit B will become the responsibility of Utility. This shall include (i) scheduling gas
transportation, (ii) confirming gas deliveries, (iii) nominating gas withdrawals from and injections into storage, if applicable, (iv) and reviewing and approving invoices for
payment. When approved, invoices shall be transmitted to DWR for payment within 10 days of receipt of invoice from the gas supplier, gas storage or gas transportation provider. 

	XVI.
	Pre-existing Financial Hedge Instruments

If
DWR has entered into any financial hedge transactions that will remain operable after the Effective Date of this Agreement, DWR shall retain full administrative and operational control over such
transactions. 

4

 
 

DWR/PG&E EXHIBIT C
  
    SETTLEMENT PRINCIPLES
  FOR REMITTANCES AND
  SURPLUS REVENUES    
    

 
 
 

EXHIBIT C
  SETTLEMENT PRINCIPLES FOR REMITTANCES AND SURPLUS REVENUES    
    

        This Exhibit C outlines the principles by which Utility will calculate revenues associated with surplus energy sales and DWR energy delivered to retail
customers. This Exhibit C also addresses the information that Utility will provide to DWR to support DWR payment of Contract invoices, and invoices from natural gas supplier(s) for fuel
provided to service DWR Contracts where tolling options have been implemented. 

        This
Exhibit C works in conjunction with the applicable Servicing Arrangement with Utility for purposes of determining the remittance amounts by Utility, which serves as DWR's
billing and collection agent. 

        In
accordance with the Contract Allocation Order(1), this Exhibit C provides that: 

	(1)
	Contract
Allocation Order is CPUC Decision (D.) 02-09-053.

	•
	Revenues
will be allocated for both surplus sales and retail customer deliveries

	•
	Revenues
will be allocated pro rata, based on dispatched quantities of energy

	•
	The
principle of balancing least cost economic dispatch while maintaining reliability is reinforced through these revenue allocation protocols.

	•
	Surplus
sales quantities will be calculated as the difference between Utility's Energy Delivery Obligations (EDO) and the combination of energy from URG and energy
dispatched from the Contracts. 

        Where
Utility's Energy Delivery Obligations is defined as: (1) Utility's retail load(2) which includes distribution losses, (2) all pump-back loads,
(3) energy exchange transactions between Utility and counter parties, (4) wholesale obligations, existing as of January 1, 2003, and (5) transmission losses. 

	(2)
	PG&E
retail load obligations per CPUC May 2002 Service Order (D.02-05-048) includes Western Area Power Administration (WAPA) load, although this load is not retail load. 

        The
principles herein, together with the applicable methods and calculations contained in the Servicing Arrangement, form a substantive component of the accounting protocols
required to implement the Contract Allocation Order. This Exhibit should also be read in conjunction with Exhibit F ("Data Requirements"). 

        Exhibit F
may periodically be modified to include all data that DWR will require to verify the remittances of revenues as remittance or implementation protocols change. Utility
and DWR agree to modify Exhibit F to include or exclude information reasonably determined by DWR to allow DWR to verify Net DWR Retail Supply and the surplus remittances. 

Utility Remittance to DWR  

Utility
shall remit to DWR an Energy Payment for the delivery of Contract energy to Utility retail customers (including the delivery or Contract energy to WAPA) and a separate payment for DWR's share
of Surplus Energy Sales Revenues. The principles for the remittances to DWR of Surplus Energy Sales Revenue and Energy Payment are contained in Sections A and B of this Exhibit C, respectively.
The details for determination of the remittances to DWR by Utility are contained in the Servicing Arrangement. 

1

 

 A.    Utility Remittance to DWR of Revenue from Surplus Energy Sales  

Surplus Energy and Revenues

Surplus
energy exists when dispatched supply from Utility portfolio and DWR Contracts exceeds Utility's Energy Delivery Obligations. When such a condition exists, the revenues from the sale of surplus
energy shall be shared between Utility and DWR. Surplus sale revenues can occur either through a forward market sale or a delivery of the excess energy into the ISO real time market. In addition to
the sharing of surplus energy revenues, the quantity of any surplus energy shall likewise be shared between Utility and DWR, and used in the determination of the Hourly Percentage Factor described in
Section I.(B). 

Surplus
energy sales revenues shall be placed by Utility into a separate account (Surplus Sales Fund) to be held in trust and shall be disbursed by Utility to DWR in accordance with the
pro-rata allocation principles in Exhibit C and consistent with the provisions of Attachment J of the Servicing Arrangement. For surplus energy sales to third parties, Utility shall
apply reasonable credit risk management criteria that is consistent with industry accepted credit standards. 

Surplus Energy Quantity

The
Surplus Energy quantity shall be determined by subtracting Utility's Energy Delivery Obligations from the sum of dispatched URG energy and dispatched DWR Supply. URG energy shall include
dispatched energy from URG, new Utility contracts and Utility market purchases plus adjustments for Ancillary Services and ISO Instructed Energy as described under "Definitions and Adjustments." DWR
Supply shall include dispatched energy from DWR must take and dispatchable contracts plus adjustments described below. 

DWR
Surplus Energy quantity shall be the product of Surplus Energy quantity multiplied by the DWR Surplus Energy Percentage. Utility Surplus Energy quantity shall be the remaining portion of Surplus
Energy. Both Utility and DWR Surplus Energy quantities shall be applied to the respective Party's energy supply quantities for determination of the Hourly Percentage Factor described in
Section (B). 

Surplus Energy Sales Revenues

Surplus
Energy Sales Revenues shall be shared between Utility and DWR in the same manner as Surplus Energy. 

Forward Market Sale

DWR
share of revenues from a forward market sale of surplus energy shall be the product of the net revenue multiplied by the DWR Surplus Energy Percentage. Utility share of these revenues shall be net
revenue less DWR share of net revenues. Revenues from a forward market sale shall not be distributed to the Parties until after Utility receives the revenues from the sales and pays
sale-related charges. Shared revenues from forward market sales shall be net of transmission costs and broker fees. 

ISO Real Time Market Sales

Revenues
from delivery of surplus energy to the ISO real time market shall be determined from the product of positive load or supply deviation multiplied by the ISO real time market price. These
revenues will be netted against any ISO charges related to the load deviation, including a negative ISO price. Load deviation is determined by subtracting the Utility metered load from the Final Hour
Ahead Load Schedule, however only positive quantities, where schedule exceeds meter, reflect surplus conditions for revenue sharing. Supply deviation is determined by subtracting the Final Hour Ahead 

2

 

Supply
Schedule (adjusted by real time instructions) from metered supply, however, only positive quantities, where meter exceeds the adjusted schedule, reflect surplus conditions for revenue sharing. 

DWR
share of revenues from delivery of surplus energy to ISO real time market shall be the product of the net revenues multiplied by the DWR Surplus Energy Percentage. Utility share of these net
revenues shall be the net revenue less DWR share of net revenues. Revenues from delivery of surplus energy to the ISO real-time market shall not be distributed to the Parties until after
the Utility received payment for final monthly invoice from the ISO for the month in which the surplus energy was delivered. 

Over-generation Periods

During
periods of over-generation condition as announced by the ISO, surplus sales may be made at very low, zero or even negative prices. In such conditions, the surplus sale revenue
calculations as described above still hold. However it is recognized that the sales may result in little or no revenue. Sales could even be done at a cost to the seller. That seller could be Utility
or the ISO selling in an "out-of-market" condition. During these conditions, ISO-related charges assigned to Utility for such sales (e.g.—ISO selling
out-of-market) are included in the surplus sales revenue as a cost. During over-generation conditions there may be no market in which to sell surplus energy. In
that event, or in expectation of that event, Utility shall declare that no valid market exists for surplus energy and shall begin curtailing must-take resources in accordance with
Utility's procedures for mitigating over-generation conditions. Such mitigation measures shall be consistent with good utility practice, specifically hydroelectric facilities at spill or
near-spill conditions and nuclear facilities scheduled by Utility are the last resources to be reduced in power output. 

Over-generation
for purposes of this Exhibit C is defined as the condition in which total supply exceeds total loads in the ISO control area. 

Revenues
or costs from delivery of surplus energy to the ISO real time market under an over-generation condition shall not be distributed to the Parties until after Utility receives
payment for final monthly invoice from the ISO for the month in which the surplus energy was delivered. 

Calculation of Surplus Energy Percentage

DWR
Surplus Energy Percentage shall be equal to the pro rata share of DWR Supply to the sum of Utility Supply and DWR Supply, expressed as follows: 

DWR Surplus Energy Percentage = DWR Supply / (Utility Supply + DWR Supply)

Where:

DWR
Supply is total energy dispatched from DWR Contracts with adjustments for transmission losses, Ancillary Services and ISO Instructed Energy transactions described below. 

Utility
Supply is total energy dispatched from URG, new Utility contracts and Utility market purchases with adjustments for transmission losses, existing wholesale obligations, WAPA load, Ancillary
Services and ISO Instructed Energy, exchange transactions, all pumping loads, and ISO Uninstructed Energy as described below. 

3

 

 B.    Definitions and Adjustments  

Certain
energy and capacity transactions, which may be conducted by Utility in its normal course of business, may affect the Utility and DWR Supply quantities used in pro rata calculations. 

Exchanges are transactions where energy is delivered to a third party in one period and a similar, but not necessarily equal, amount of energy is
returned by third party in a different period. For the purposes of pro rata share calculation, exchanges use and supplement energy from the Utility Supply. 

Forward Sales are transactions where energy is sold in a forward market to balance supply with demand. In general, for the purposes of remittance
determination, forward sales are made using energy from the joint Utility/DWR portfolio. 

Ancillary Services are transactions where capacity from certain qualifying resources is sold to ISO for ancillary services rather than being used as
energy to serve retail load. Resources from both Utility portfolio and DWR Contracts may qualify for use as ancillary services. Since the capacity used for ancillary services does not serve retail
energy load, ancillary service capacity is not considered as a joint Utility/DWR portfolio transaction for the purpose of remittance determination. If Utility or DWR Contract resource capacity is used
for ancillary services, the capacity quantity will not be included in the supply quantity of the owning party for the purpose of pro rata share calculations, and owning party will retain all the
revenues from the ancillary services as well as all associated transaction costs and ISO charges. 

ISO Instructed Energy is a transaction where certain qualifying resources are able to sell energy from unused capacity to the ISO in the real time
market. The energy delivered from these resources is directed by the ISO in real time to balance supply and load imbalances on the grid. Either Utility portfolio or DWR Contracts may contain resources
that have ability to provide instructed energy to ISO. Since instructed energy is resource specific and does not directly serve the retail load of any utility, instructed energy is not considered as a
joint Utility/DWR portfolio transaction for the purpose of remittance determination. If Utility or DWR Contract resources are dispatched as instructed energy, the energy quantity will not be included
in the supply quantity of the owning party for the purpose of pro rata share calculations, and owning party will retain all the revenues from the instructed energy as well as all associated
transaction costs and ISO charges. 

ISO Uninstructed Energy is a transaction where energy is delivered or received from the ISO grid in the real time based on the actual consumption of
retail load and actual deliveries of supply resources. 

Uninstructed Retail Load Deviations

Uninstructed
Load Deviations are the difference between scheduled load and metered load. If retail load deviations are positive (schedule exceeds meter), it is considered that any excess supply (less
any positive uninstructed supply deviation) was dispatched from the joint Utility/DWR portfolio in excess of quantity needed to serve retail load, and that the ISO credit for the excess supply should
be shared pro rata as described above. If retail load deviations are negative (meter exceed schedule), to the extent deviations are not compensated by a positive uninstructed supply deviation, it is
considered that Utility had to procure additional supply from ISO real time market. The negative load deviation quantity procured from ISO real time market is considered a Utility market purchase and
the quantity will be included in Utility Supply for pro rata share calculation purposes. 

4

 

Uninstructed Supply Deviations

Uninstructed
Supply Deviations are the difference between scheduled supply and metered supply plus an ISO allocation for transmission losses. If Utility's net supply deviations(2) are positive (meter
exceeds schedule), to the extent not needed to compensate a negative uninstructed retail load deviation, it is considered that excess supply was a Utility market sale and will not be included in
Utility Supply for pro rate calculation purposes. If Utility's net supply deviations are negative (schedule exceeds meter), to the extent not balanced by a positive uninstructed retail load deviation,
it is considered that Utility had to procure additional supply from the ISO real time market. The negative supply deviation quantity procured from the ISO real time market is considered a Utility
market purchase and the quantity will be included in Utility Supply for pro rata share calculation purposes. 

	(2)
	Net
positive and negative deviations of all supply resources. 

Transmission Losses

Transmission
loss is defined as Energy that is lost due to the process of transmitting energy from supply source to load. Therefore, supply resources from DWR Contracts and Utility Supply have
distinct and identifiable quantity of transmission losses. Utility and DWR Supply should be net of transmission losses because of energy that is delivered to retail customers (i.e. load) equals
quantity of supply less losses. 

 C.    Utility Remittance to DWR for Sales of DWR Energy to Utility Retail Customers—Energy Payment  

Utility
shall remit to DWR its Energy Payments according to the terms of each Utility's respective Servicing Arrangement. 

The
DWR Energy Payment is billed by each utility to customers in accordance with the terms of each applicable Utility Servicing Arrangement. The DWR Energy Payment is billed kWhs served by Net DWR
Supply at the applicable CPUC approved DWR rate. Net DWR Supply is total DWR Supply less DWR share of surplus energy. The DWR Energy Payment is allocated based on the percentage of energy supplied by
DWR to Utility, which is the "Hourly Percentage Factor" multiplied by the retail load of each customer. The Hourly Percentage Factor is determined by calculating the percentage of net energy supplied
by DWR to Utility to serve retail load, as expressed below: 

Hourly Percentage Factor = Net DWR Supply / (Net Utility Supply + Net DWR Supply)

Where:

Net
DWR Supply is DWR Supply quantity used for the determination of DWR Surplus Energy Percentage less DWR share of surplus energy quantity, which is determined by the product of surplus energy
multiplied by DWR Surplus Energy Percentage. 

Net
Utility Supply is Utility Supply quantity used for the determination of DWR Surplus Energy Percentage less Utility share of surplus energy quantity, which is total surplus energy less the DWR
share of surplus energy quantity. 

In
the Event of any conflict between the formulas and procedures in this Exhibit C and the formulas and procedures in Utility's Servicing Arrangement, those contained in Utility's Servicing
Arrangement shall govern. 

5

 

	II.
	Bilateral Settlement

Under
the Contract Allocation Order DWR remains financially obligated for the Contracts. DWR will continue to pay suppliers and this requires DWR to apply appropriate procedures and controls to ensure
that payments are made accurately and in a timely manner. Information supporting Contract settlements will be provided by Utility, and additional information may also be required to address contract
performance issues (such as availability and other items as discussed in Exhibit E) and to allow DWR to settle disputes in an appropriate manner. 

DWR
requires sufficient information to support payment requests so that it can meet the accountability requirements of the State Controller's Office and the State Auditor, and simultaneously comply
with the applicable statutes concerning disbursement of public monies. The Utility shall reconcile schedules with suppliers invoice. DWR shall make the associated payments to suppliers after
performing its verification, and Utility will provide the data as required in Exhibit F to allow it to perform these duties in a timely manner as set forth herein. 

DWR
shall continue to perform validation of settlement data and invoices and pay Contract costs directly to the suppliers upon validation of invoices. 

	III.
	Fuel Cost Verification and Settlement

Exhibit B
provides a detailed discussion concerning Utility's responsibility for fuel management. DWR will continue to pay fuel suppliers and others involved in providing fuel management
services for the delivery of fuel for those DWR Contracts where the Fuel Option has been elected. Consistent with the above, Utility will perform settlements activities to reconcile quantities and
associated charges, and DWR will perform verification, audit and monitoring to support its disbursement of funds. Utility will comply with the requirements contained in Exhibit F to provide DWR
with the necessary information to apply appropriate procedures and controls to ensure that fuel payments and payments for fuel management services are made accurately and in a timely manner and to
allow DWR to settle disputes in an appropriate manner. 

6

 
 

DWR/PG&E EXHIBIT D
  
    ISO SCHEDULING COORDINATOR CHARGES    
    

 
 
 

EXHIBIT D
  ISO SCHEDULING COORDINATOR CHARGES    
    

        The financial obligation for ISO charges incurred as of the Effective Date will be allocated to the Utility, unless otherwise extended under the existing and any
future Applicable Commission Orders. Unless specifically provided in Exhibit C hereto, all ISO charges incurred after the Effective Date attributable to load and resources shall be the
responsibility of Utility. 

        Utility
agrees that any refunds, reruns or credits through the ISO attributable to costs incurred by DWR for trade dates beginning Hour Ending 2200, January 17, 2001 up to the
Effective Date, which are separate from ISO charges subject to Commission Decision No. 02-05-048, shall belong to DWR and Utility shall take all necessary action to
remit such refunds or credits to DWR within reasonable time. In addition, DWR shall be responsible for any ISO charges incurred during this period pursuant to the existing letter agreement between the
Parties. Utility shall invoice DWR for such ISO charges within a reasonable period of time and DWR shall pay Utility for such ISO charges within 10 days of receipt of such invoice. Without
making any assurances as to Commission action, DWR agrees to take appropriate action to ensure that such refunds or credits are applied consistent with DWR's Revenue Requirement cost allocation method
for the same trade dates. 

        DWR
agrees that any refunds, reruns, or credits through the ISO attributable to ISO charges invoiced to DWR under the November 7, 2001 order of the Federal Energy Regulatory
Commission and subsequent orders but which are further subject to Commission Decision No.02-05-048, which directs Utility to directly reimburse DWR for such
ISO charges incurred starting Hour Ending 2200, January 17, 2001 up to the Effective Date, shall belong to Utility and DWR shall take all necessary action to remit such refunds or credits
directly to Utility within reasonable time. 

1

 
 

DWR/PG&E EXHIBIT E
  
    CONTRACT MANAGEMENT AND
  ADMINISTRATION PROTOCOLS    
    

 
 
 

EXHIBIT E
  CONTRACT MANAGEMENT AND ADMINISTRATION PROTOCOLS    
    

        DWR will retain all contract management, administration and monitoring responsibilities for the Contracts, including due diligence, performance testing, contract
performance assessment, formal correspondence and notifications with Suppliers, exercise of contract options, contract interpretation and dispute resolution, and financial reporting. In the event
Utility and DWR agree in the future to transition the Due Diligence and Performance Test Monitoring functions set forth in this Exhibit E from DWR to the Utility, the Parties will first develop
a mutually acceptable plan of performance, a transition schedule, and a transition plan for transfer of such functions from DWR to the Utility for review and approval by the Commission.. Upon
agreement of the Parties to an acceptable plan and completion of the transition period, the agreed upon functions will transfer from DWR to the Utility ("the Transition Date"). 

	I.
	Due-Diligence

The
Due Diligence function assesses the progress of permitting, construction and performance capability of new generating facilities under to the Contracts. Due Diligence includes
(i) monitoring activities associated with the development, construction, and performance of new generating facilities; (ii) identification and tracking of key projects milestones
including permitting, equipment procurement, construction, commissioning, and performance testing; (iii) coordination with permitting agencies and
the Suppliers, review of project documents, physical inspections, and witnessing of acceptance tests, (iv) verification that the new facilities can perform in a manner that is consistent with
the obligations under the appropriate Contract and (v) review and approval of commercial operation dates and documentation. 

	II.
	Performance Test Monitoring

A.
Annual Performance Tests 

Annual
Performance Tests verify ongoing compliance with the Contracts and establish plants capacities and efficiencies that are used to calculate contract payments, either for capacity or energy.
Annual Performance Test responsibilities generally consist of (i) verification of testing procedures, (ii) witness of performance tests, (iii) review of test results and test
reports for compliance with Contract terms and conditions, and (iv) identification of contract non-compliance for dispute resolution with the Supplier. Prior to the Transition Date,
the Utility will cooperate and assist DWR with scheduling of upcoming Annual Performance Tests, and the Utility may have its staff witness such testing. 

B.
Scheduled Performance Tests 

Prior
to the Transition Date, on occasion, DWR may request that Utility schedule a peaking or dispatchable generating facility for testing (to assure that such generation facility is available
according to the terms of the contract between such generation facility and DWR). The utility will cooperate and shall coordinate with the DWR on a mutually acceptable date for performance of the
test. On the date agreed upon, the Utility shall schedule the specified facility or unit for operation to test the availability, reliability, and performance of the scheduled unit. 

C.
Test Procedures and Protocols 

Prior
to January 1, 2003, Utility shall meet with DWR staff to review, discuss, and verify test procedures and protocols developed by DWR. 

1

 

	III.
	Contract Performance Assessments

DWR
shall continue to perform an after-the-fact review ("Performance Assessment") of each Contract on a periodic basis. The purpose of the Performance Assessment is to assess,
analyze, and document the overall performance of each contract Supplier, assure that the Supplier is satisfying the terms and conditions of their respective contract(s), and identify potential issues,
disputes, and other matters that may require corrective action by either Utility or DWR as part of contract administration. 

	IV.
	Other Administrative Matters

A.
Correspondence with Suppliers 

Utility
and DWR agree to copy each other on all written correspondence and written notifications sent to or received from a Supplier of an Allocated Contract or Interim Contract related to the
activities described in this Exhibit E. The Parties agree to provide additional information as requested related to verification and support of the activities described in this
Exhibit E. 

B.
Reports 

Results
of the activities described in this Exhibit E will be documented by DWR in written reports ("Reports") and shall be discussed periodically between DWR and the Utility. Such Reports may
include, but are not limited to, summary of test results, status of projects, recommendations for operational changes, procedural changes, dispute resolution, and results of Performance Assessments. 

Such
Reports, documentation, or other material developed by either Party shall be shared and reviewed with the other Party on a timely basis. 

2

 
 

DWR/PG&E EXHIBIT F
  
    DWR DATA REQUIREMENTS FROM UTILITY    
    

 
 
 

EXHIBIT F
  DWR DATA REQUIREMENTS FROM UTILITY    
    

        To effectively fulfill its legal and financial responsibilities, DWR requires access to standard and reliable information on a timely basis. Post transition, DWR
remains statutorily and contractually obligated to collect, account for, and remit funds for the power it provides to the IOU's retail customers. More specifically, post transition, DWR must have
readily available access to information that is currently available in-house due to DWR's operational responsibilities. The primary source of this information post transition will be the
three utilities. 

        The
information being requested is required to: 

	•
	Verify,
audit, monitor and authorize payment for bilateral invoices for allocated DWR contracts;

	•
	Manage
disputes between DWR and the bilateral counterparties;

	•
	Verify,
audit, monitor and authorize payment for fuel procured by the utilities relating to DWR allocated contracts;

	•
	Verify,
audit, monitor, collect and IOU remittances relating to repayment of Energy Supplied and Bond Funds;

	•
	Forecast,
manage and monitor DWR monetary requirements and associated accounts;

	•
	Ongoing
reporting responsibilities under AB1X, the rate agreement and bond indenture;

	•
	Audit
and monitor long-term contract performance and associated risks prior to contract assignment or novation. 

        The
table below contains a brief description of the information to be provided by Utility, the frequency for which Utility shall provide such information to DWR, and the effective date
for when Utility shall provide such information to DWR. 

1

 

        The
following table outlines DWR data requirements relating to general contract/trade information: 

	Contract/Trade
	 	 
	 	 
	 	 

	Requirement
 
	 	Description
	 	Freq
	 	Effective
	 	Delivery

Method

	Surplus Energy Sales Plan	 	Monthly utility's surplus energy sales plan updated weekly. Sales plan will outline all surplus sales contemplated by the utility, including but not limited to balance of month, weekly balance of week and other short-term
sales.	 	Monthly plan, updated weekly	 	1/1/2003	 	Email/Fax—Standard Form TBD
	

Surplus Energy Sales	
 	

Contract/Deal information relating to the forward sale of DWR surplus energy. This would include but is not limited to Counter party, Term (Start/End Date), Hourly Contract Volumes, Hourly Price, Location, any fee information, etc.	
 	

When executed	
 	

All surplus forward sales entered into after 1/1/2003	
 	

Email/Fax—Standard Form TBD

2

 

        The
following table outlines DWR data requirements relating to long-term contract schedule information and associated bilateral invoices: 

	Schedule/Bilateral Invoice
	 	 
	 	 
	 	 

	Requirement
 
	 	Description
	 	Freq
	 	Effective
	 	Delivery

Method

	Final Schedule Volumes, Long Term Contracts	 	For all long-term contracts allocated to the utilities and any surplus energy sales, the detailed hourly final schedule volumes and pricing information by contract by counterparty, by day.	 	T+1 (Daily)	 	1/2/2003	 	Secure Electronic—

Format TBD
	

 	
 	

Final schedule volumes are defined as the final volume for the hour at the completion of the real-time market. These volumes represent the hour ahead scheduled volumes adjusted to include any real-time market adjustments by the ISO. Absent any real
time adjustments, this data will be the same as Final Hour Ahead Schedule.	
 	

 	
 	

 	
 	

 
	

 	
 	

File should include, but is not limited to; Utility identifier, file type identifier (i.e. final, HA), SC identifier, counterparty identifier, contract identifier, schedule type identifier (i.e. sale), delivery location, date, volume scheduled by
hour, price per hour.	
 	

 	
 	

 	
 	

 
	

Hour Ahead Schedule Volumes, Long Term Contracts	
 	

For all long-term contracts allocated to the utilities and any surplus energy sales, the detailed hour ahead final schedule volumes and pricing information by contract, by counterparty, by day.	
 	

T+1 (Daily)	
 	

1/2/2003	
 	

Secure Electronic—

Format TBD
	 	 	 	 	 	 	 	 	 

3

 

	

 	
 	

Format and data elements of the file provided should be identical to what was specified above in Final Schedule volumes.	
 	

 	
 	

 	
 	

 
	

 	
 	

(Note: This cannot be the ISO Hour Ahead Final Schedule template as this file does not provide transactional level details but consolidates/collapses information based on certain ISO rules.)	
 	

 	
 	

 	
 	

 
	

Reconciled Monthly bilateral invoices	
 	

Monthly invoice and supporting documentation for bilateral contracts relating to DWR long-term contracts, reviewed and approved by utility for payment by DWR to the counterparty.	
 	

Monthly—5 business days prior to payment due date	
 	

Feb 03	
 	

TBD

4

 

        In
the event of a bilateral invoice dispute with the counterparty, DWR may also request from the utility the additional schedule information. This information would be in the same format
as outlined in the table above. As mentioned above, DWR is requesting transactional level information and not the associated ISO template files due to the consolidation/collapsing of schedules with
the template files. Schedule information required would include: 

	•
	Hour
Ahead Preferred Schedule Volumes

	•
	Day
Ahead Final Schedule Volumes

	•
	Day
Ahead Adjusted Schedule Volumes

	•
	Day
Ahead Revised Preferred Schedule Volumes

	•
	Day
Ahead Preferred Schedule Volumes 

5

 

        The
following table outlines DWR data requirements relating to the verification of fuel costs. It assumes DWR will retain legal and financial responsibility for gas and related services
while the utility will perform administrative and operational responsibilities as outlined in Exhibit B. 

	Fuel Costs
	 	 
	 	 
	 	 

	Requirement
 
	 	Description
	 	Freq
	 	Effective
	 	Delivery

Method

	Generator fuel plan proposal	 	Proposal and supporting analysis on whether or not to accept or reject of generator fuel plan.	 	Based on individual contracts	 	Jan-03	 	TBD
	

Utility Fuel Procurement Plan	
 	

Utility will provide a bi-annual fuel procurement plan for utility supplied fuel.	
 	

Bi-Annual	
 	

Jan-03	
 	

TBD
	

Tolling agreement Settlement Report	
 	

Monthly report on each DWR tolling agreement that includes but is not limited to: tolling contract identifier, who provided the gas (generator/utility) and daily quantity of gas supplied.	
 	

Monthly	
 	

Feb-03	
 	

Electronic Format TBD
	

Reconciled Monthly Gas Invoice	
 	

Suppliers monthly invoice and supporting documentation for fuel procurement relating to DWR tolling agreements, reviewed and approved by Utility for payment by DWR to the supplier.	
 	

Monthly—5-business days prior to payment due date	
 	

Feb-03	
 	

Electronic—Format TBD
	

Gas Transportation Contract Information	
 	

Details relating to the Utility negotiated firm and/or interruptible transportation agreements for DWR review and authorization.	
 	

When executed	
 	

All contracts effective after 1/1/2003	
 	

E-mail/Fax Standard Form TBD
	

Gas Storage Contract Information	
 	

Details relating to the Utility/negotiated firm and/or interruptible storage agreements for DWR review and authorization.	
 	

When executed	
 	

All contracts effective after 1/1/03	
 	

E-mail/Fax Standard Form TBD
	

Reconciled Monthly gas transportation invoices	
 	

Suppliers monthly invoice and supporting documentation for natural gas transportation costs relating to DWR tolling agreements, reviewed and approved by utility for payment by DWR to the supplier.	
 	

Monthly—5-business days prior to payment due date	
 	

Feb-03	
 	

Electronic—Format TBD
	 	 	 	 	 	 	 	 	 

6

 

	

Reconciled Monthly gas storage invoices	
 	

Supplier's monthly invoice and supporting documentation for storage relating to DWR tolling agreements, reviewed and approved by utility for payment by DWR to the supplier.	
 	

Monthly—5-business days prior to payment due date	
 	

Feb-03	
 	

Electronic—Format TBD

7

 

        The
following table outlines additional DWR data relating to utility revenue remittance: 

	Utility Revenue Remittance
	 	 
	 	 
	 	 

	Requirement
 
	 	Description
	 	Freq
	 	Effective
	 	Delivery

Method

	Utility ISO Preliminary Settlement and Supporting Files	 	The complete Utility preliminary settlement statement and supporting files in original ISO template format.	 	T + 38 business days	 	Ongoing	 	Secure Electronic-ISO Template Direct from ISO
	

Utility Final ISO Settlement Statement and Supporting Files	
 	

The complete Utility final ISO settlement statement and supporting files in ISO original template format. This information also required for remittance calculation purposes.	
 	

T + 45 business days	
 	

Ongoing	
 	

Secure Electronic-ISO Template Direct from ISO
	

Scheduled Retail Load by hour	
 	

Utilities estimated retail load information by hour, by day used for the preliminary remittance.	
 	

T + 1	
 	

1/1/2003	
 	

TBD
	

Hourly aggregate final schedule of Utility's resource portfolio	
 	

Utilities total hourly scheduled volumes for the entire Utilities portfolio. This is an aggregate total for the day, by hour and represents the total volume supplied by the utility.	
 	

T+1 (Daily)	
 	

1/2/2003	
 	

TBD
	

Wholesale Obligation Volumes	
 	

Utilities total hourly scheduled volumes for pre-existing wholesale commitments in aggregate by the hour for each day.	
 	

T+1 (Daily)	
 	

1/2/03	
 	

TBD
	

Hourly Distribution Loss Factor	
 	

Utility DLF % by hour	
 	

When changes required	
 	

1/1/2003	
 	

TBD
	

Estimated DWR remittance %	
 	

Utility estimated remittance percentage.	
 	

When changes required	
 	

1/1/2003	
 	

TBD
	

Energy Sales billed (kWh)*	
 	

Monthly kWh billed by Utility to end users	
 	

Monthly	
 	

Ongoing	
 	

Standard DWR Form/File (TBD)
	

DWR Power Charge volumes*	
 	

Monthly kWh billed by Utility to end users	
 	

Monthly	
 	

Ongoing	
 	

Standard DWR Form/File (TBD)
	 	 	 	 	 	 	 	 	 

8

 

	

DWR Power Charge billed to Customer*	
 	

Monthly dollar amount of DWR Power Charge being billed to customer including identification of dates billed.	
 	

Monthly	
 	

Ongoing	
 	

Standard DWR Form/File
	

DWR Power Charge Remitted to DWR*	
 	

Daily dollar amount being remitted by Utility to DWR for the DWR Power Charge collected from customers including identification of dates billed.	
 	

Daily	
 	

Ongoing	
 	

Standard DWR Form/File (TBD)

	*
	This
information is already provided pursuant to the Servicing Arrangement, and supports the daily remittance calculation for each month and subsequent true-ups. The
Servicing Arrangement will be modified as necessary to conform to this Operating Agreement. 

        As
various Commission proceedings are finalized DWR will also require specific data related to Bond Charge remittances and to Direct Access exit fees. The specific nature and format of
this data will be agreed with between the utilities and DWR. 

9

 

        The
following table outlines DWR data requirements relating to resource information: 

	Resource Information
	 	 
	 	 
	 	 

	Requirement
 
	 	Description
	 	Freq
	 	Effective
	 	Delivery

Method

	Load and Resource Assessment Studies	 	Copies of Utilities annual and quarter load and resource assessment studies as provided to the PUC.	 	Annually and quarterly	 	Jan-03	 	TBD
	

Update Description of Resources	
 	

Updated description of URG resources.	
 	

Annually or when significant changes	
 	

Jan 1, 04	
 	

TBD
	

Unit Commitment Studies	
 	

As provided to the PUC.	
 	

Weekly	
 	

Jan-03	
 	

TBD
	

DWR Non-Dispatched Resources Report	
 	

Report of Resources that were economic to run, but were not dispatched.	
 	

Ad hoc	
 	

1/1/03	
 	

TBD
	

DWR Resource Unavailability Form	
 	

Utility notification to DWR for resources within an allocated contracts becoming unavailable, or scheduled to become unavailable.	
 	

As outlined in operating agreement	
 	

1/1/2003	
 	

Standard DWR Form—Email/Fax
	

 	
 	

Note: This information could be provided directly from the generator to DWR and would therefore not be required from Utility.	
 	

 	
 	

 	
 	

 

        Upon
the reasonable request of DWR, Utility will provide to DWR any information in respect of Utility that is applicable to the rights and obligations of the Parties under this Agreement
or any material information that is reasonably necessary for DWR to monitor and manage their risks and perform their fiduciary responsibilities. Upon the reasonable request of Utility, DWR will
provide to
Utility any information in respect of DWR that is applicable to the rights and obligations of the Parties under this Agreement or any material information that is reasonably necessary for Utility to
operationally administer Contracts under this Agreement. 

        For
the information identified above, or any additional information identified through the term of this Agreement, standard submission formats will be used or be developed by DWR for use
by each of the investor-owned utilities, including Utility. In the cases where the information requirements result in a large volume of data (e.g., schedule information), DWR will use or develop
standard detailed file definitions for use by all of the investor-owned utilities, including Utility. Data will be submitted to DWR by Utility through a secure electronic communication medium, unless
other medium is reasonably requested by DWR. 

        As
a result of the relative short implementation timeframes, it is anticipated an interim delivery protocol (e.g., comma delimited file via email, compact diskettes) will be
utilized until the final data 

10

 

transmission
media are in place. DWR shall work jointly with Utility to ensure the required data is available by January 1, 2003. 

        In
the event that DWR incurs additional costs, including but not limited to penalties, interest or other such costs, due to Utility's failure to timely provide the data set forth in this
Exhibit F, any such direct cost increase invoiced or assessed to DWR shall be borne by Utility. 

        The
provisions of this Exhibit are subject to annual review by DWR and Utility to ensure that data reporting remains relevant and useful. 

11

QuickLinks

Exhibit 10.9

OPERATING AGREEMENT Between

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OPERATING AGREEMENT

R E C I T A L S

ARTICLE I DEFINITIONS

ARTICLE II OPERATIONAL ALLOCATION OF POWER PURCHASE AGREEMENTS; MANAGEMENT OF THE CONTRACTS; ALLOCATED POWER; TERM

ARTICLE III LIMITED AGENCY / NO ASSIGNMENT

ARTICLE IV LIMITED DUTIES OF UTILITY

ARTICLE V DUTIES OF DWR

ARTICLE VI SPECIAL CONTRACT TERMS

ARTICLE VII EVENTS OF DEFAULT

ARTICLE VIII PAYMENT OF FEES AND CHARGES

ARTICLE IX REPRESENTATIONS AND WARRANTIES

ARTICLE X LIMITATIONS ON LIABILITY

ARTICLE XI CONFIDENTIALITY

ARTICLE XII RECORDS AND AUDIT RIGHTS

ARTICLE XIII DISPUTE RESOLUTION

ARTICLE XIV MISCELLANEOUS

Schedule 1

ALLOCATED CONTRACTS

Schedule 2

INTERIM CONTRACTS

Schedule 3

REPRESENTATIVES AND CONTACTS

DWR/PG&E EXHIBIT A OPERATING PROTOCOLS

EXHIBIT A OPERATING PROTOCOLS

DWR/PG&E EXHIBIT B FUEL MANAGEMENT PROTOCOLS

EXHIBIT B FUEL MANAGEMENT PROTOCOLS

DWR/PG&E EXHIBIT C SETTLEMENT PRINCIPLES FOR REMITTANCES AND SURPLUS REVENUES

EXHIBIT C SETTLEMENT PRINCIPLES FOR REMITTANCES AND SURPLUS REVENUES

DWR/PG&E EXHIBIT D ISO SCHEDULING COORDINATOR CHARGES

EXHIBIT D ISO SCHEDULING COORDINATOR CHARGES

DWR/PG&E EXHIBIT E CONTRACT MANAGEMENT AND ADMINISTRATION PROTOCOLS

EXHIBIT E CONTRACT MANAGEMENT AND ADMINISTRATION PROTOCOLS

DWR/PG&E EXHIBIT F DWR DATA REQUIREMENTS FROM UTILITY

EXHIBIT F DWR DATA REQUIREMENTS FROM UTILITY

Source: [{"source": "alea-institute/alea-institute/kl3m-data-edgar-agreements/train-00078-of-00352.parquet"}, [{"source": "alea-institute/alea-institute/kl3m-data-edgar-agreements/train-00078-of-00352.parquet"}]]