EX-10.8 7 a2150586zex-10_8.htm EXHIBIT 10.8
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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

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

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.

(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;

(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

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.

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

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

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

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.

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.

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

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.

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.

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

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.

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.

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.

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

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.

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.

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.

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,

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.

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;

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.

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]

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.

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.

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).

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.

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.

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.

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

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

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.

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 22^nd 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.

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

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:

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

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:

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, 4^th Floor Riverside, California 92522
	By:

		George A. Caravalho, City Manager
ATTEST:

City Clerk
APPROVED AS TO FORM:

Supervising Deputy City Attorney

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

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

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

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)

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).

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

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.

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 Priorities^1/

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 Requests^7/	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.

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;

•: 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

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

•: 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.

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.

Forced Outage^(IMS) Frequency:

The Forced Outage^(IMS) frequency (f_ik) of the i^th Transmission Line Circuit shall equal the total number of Forced Outages^(IMS) that occurred on the i^th 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 (f_ik) greater than zero for the calendar year k:

		f_ik
d_ik	=	S o_ijk
		j = 1

where

d_ik: = accumulated duration of Forced Outages^(IMS) (total number of Forced Outage^(IMS) minutes) for the i^th Transmission Line Circuit having a Forced Outage^(IMS) frequency (f_ik) greater than zero for the calendar year k.
f_ik: = Forced Outage^(IMS) frequency as defined above for calendar year k.
o_ijk: = duration in minutes of the j^th Forced Outage^(IMS) which occurred during the k^th calendar year for the i^th 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.

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:

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.

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.

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

F_vc,k

N_k

N_k
S f_ik
i = 1

where

F_vc,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.
N_k =	number of Transmission Line Circuits in Voltage Class in calendar year k. See Note 2, Section 4.2.1.
f_ik =	frequency of Forced Outages^(IMS) for the i^th 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):

D_vc,k

N_o,k

N_o,k
S d_ik
i = 1

where

D_vc,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.
N_o,k =	number of Transmission Line Circuits in the Voltage Class for which the Forced Outage^(IMS) frequency Availability Measure (f_ik) as calculated in accordance with Section 4.2.1 is greater than zero for the calendar year k. See Note 2, Section 4.2.1.
d_ik =	accumulated duration of Forced Outages^(IMS) for the i^th Transmission Line Circuit having a Forced Outage^(IMS) frequency Availability Measure (f_ik) 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):

P_vc,k

N_k - N_o,k

N_k

where

P_vc,k =	index for the proportion of Transmission Line Circuits for the Voltage Class with no Forced Outages^(IMS) for the calendar year k.
N_k =	number of Transmission Line Circuits in Voltage Class for calendar year k. See Note 2, Section 4.2.1.
N_o,k =	number of Transmission Line Circuits in the Voltage Class for which the Forced Outage^(IMS) frequency Availability Measure (f_ik) as calculated in accordance with Section 4.2.1 is greater than zero for the calendar year k. See Note 2, Section 4.2.1.

4.3.2. Development of Limits for Performance Control Charts

The CL, UCL, LCL, UWL and LWL for the three control charts (Annual Average Forced Outage^(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 N_k		Y
CL_fvc	=	S S f_ik	/ (	S N_k)
		k-1 i-1		k=1

where

CL_fvc =	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 N_o,k		Y
CL_dvc	=	S S d_ik	/ (	S N_o,k)
		k-1 i-1		k=1

where

CL_dvc =

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 (f_ik) was greater than zero.

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

		Y
CL_Pvc	=	S (N_k - N_o,k) k=1
		Y S N_k k=1

where

CL_Pvc =

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.

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.

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 k^th year are determined using the normal approximation to the binomial distribution. The formulas are:

UCL = CL_Pvc + 3S_Pvc,k LCL = CL_Pvc - 3S_Pvc,k

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

and

where

S_Pvc,k: = standard deviation for the annual proportion of Transmission Line Circuits in the Voltage Class with no Forced Outages^(IMS) for each (k^th) 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

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 99^th 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.

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

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.

Table 4.3.1 Performance Indications Provided by Control Chart Tests

			Performance Status Indicated by Test Results
	Test
Control Chart Type	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.

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

•: 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.

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.

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.

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)

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.

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.

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

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

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.

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.

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.

The SONGS switchyard is made up of the SCE switchyard and the SDG&E switchyard. Unless specifically stated otherwise, SONGS switchyard requirements contained in this document apply to both the SCE switchyard and the SDG&E switchyard.

SPECIFIC REQUIREMENTS

Note 1:		This section identifies the operational requirements for the SONGS offsite power supply. These requirements are part of the SONGS design basis and licensing basis. Failure to meet these requirements may render the offsite power supply Inoperable, thus requiring the operating SONGS unit(s) to shutdown. Failure to meet these requirements must be immediately communicated to SCE and the SONGS Control Room for operability determination. Changes in the operation of the transmission network that conflict with these requirements require prior approval by SCE.
Note 2:		Specific requirements, procedures, operating bulletins, division orders, and analysis that support or provide the basis for the specific operational requirements may be revised periodically subject to prior approval of the affected parties.

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).

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.

(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)

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.

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)

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

Original Sheet No. 225

TRANSMISSION CONTROL AGREEMENT

APPENDIX F

NOTICES

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002

Effective: January 1, 2003

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

Original Sheet No. 226

NOTICES

California Independent System Operator

Name of Primary
Representative:		Deborah A. Le Vine
Title:		Director of Contracts
Address:		151 Blue Ravine Road
City/State/Zip Code:		Folsom, California 95630
Email Address:		dlevine@caiso.com
Phone:		(916) 351-2144
Fax No:		(916) 351-2487
Name of Alternative
Representative:		Randy Abernathy
Title:		Vice President of Market Services
Address:		151 Blue Ravine Road
City/State/Zip Code:		Folsom, California 95630
Email Address:		rabernathy@caiso.com
Phone:		(916) 351-4435
Fax No:		(916) 351-2350

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002

Effective: January 1, 2003

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

First Revised Sheet No. 227
Superseding Original Sheet No. 227

Pacific Gas and Electric Company

Name of Primary
Representative:		Rod Maslowski
Title:		Director, Electric System Operations
Address:		77 Beale Street, Room 1526
City/State/Zip Code:		San Francisco, CA 94105
Email Address:		RJM8@pge.com
Phone:		415-973-1218
Fax No:		415-973-3341
Name of Alternative
Representative:		Steve Metague
Title:		Director, Electric Transmission Rates
Address:		77 Beale Street, Room 1339
City/State/Zip Code:		San Francisco, CA 94105
Email Address:		SJMd@pge.com
Phone:		415 973-6545
Fax No:		415 973-9174

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: September 7, 2004

Effective: Upon notice after November 1, 2004

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

Original Sheet No. 228

San Diego Gas & Electric Company

Name of Primary
Representative:		Geoff Gaebe
Title:		Director—Electrical Engineering
Address:		8316 Century Park Court
City/State/Zip Code:		San Diego, CA 92123
Email Address:		ggaebe@semprautilities.com
Phone:		858-654-1636
Fax No:		858-654-1692
Name of Alternative
Representative:		Ali Yari
Title:		Manager Grid Operation Services
Address:		9060 Friars Road
City/State/Zip Code:		San Diego, CA 92108
Email Address:		yari@semprautilities.com
Phone:		619-725-8639
Fax No:		619-683-3291

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002

Effective: January 1, 2003

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

Original Sheet No. 229

Southern California Edison Company

Name of Primary
Representative:		Richard M. Rosenblum
Title:		Senior Vice President, Transmission & Distribution
Address:		2244 Walnut Grove Ave., GO4
City/State/Zip Code:		Rosemead, California 91770
Email Address:		Richard.Rosenblum@SCE.com
Phone:		(626) 302-2123
Fax No:		(626) 302-2781
Name of Alternative
Representative:		John R. Fielder
Title:		Senior Vice President, Regulatory Policy & Affairs
Address:		2244 Walnut Grove Ave., GO4
City/State/Zip Code:		Rosemead, California 91770
Email Address:		John.Fielder@SCE.com
Phone:		(626) 302-3440
Fax No:		(626) 302-2970

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002

Effective: January 1, 2003

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

Original Sheet No. 230

City of Vernon

Name of Primary
Representative:		Bruce V. Malkenhorst
Title:		City Administrator
Address:		4305 Santa Fe Avenue
City/State/Zip Code:		Vernon, California 90058
Email Address:		bmalkenhorst@ci.vernon.ca.us
Phone:		(323) 583-8811 extension 266
Fax No:		(323) 581-7924
Name of Alternative
Representative:		Kenneth J. DeDario
Title:		Director of Utilities
Address:		4305 Santa Fe Avenue
City/State/Zip Code:		Vernon, California 90058
Email Address:		kdedario@ci.vernon.ca.us
Phone:		(323) 583-8811 extension 211
Fax No:		(323) 826-1425

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002

Effective: January 1, 2003

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

Original Sheet No. 231

City of Anaheim

Name of Primary
Representative:		Sheryll A. Schroeder
Title:		City Clerk
Address:		200 S. Anaheim Blvd.
City/State/Zip Code:		Anaheim, California 92805
Email Address:		sschroeder@anaheim.net
Phone:		(714) 765-5645
Fax No:		(714) 765-4105
Name of Alternative
Representative:		Marcie L. Edwards
Title:		Public Utilities General Manager
Address:		201 S. Anaheim Blvd., Suite 1101
City/State/Zip Code:		Anaheim, California 92805
Email Address:		medwards@anaheim.net
Phone:		(714) 765-5173
Fax No:		(714) 765-4138

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002

Effective: January 1, 2003

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

Original Sheet No. 232

City of Azusa

Name of Primary
Representative:		Joseph Hsu
Title:		Director of Utilities
Address:		729 N. Azusa Avenue
City/State/Zip Code:		Azusa, CA 91702
Email Address:		jhsu@ci.azusa.ca.us
Phone:		(626) 812-5171
Fax No:		(626) 334-3163
Name of Alternative
Representative:		Bob Tang
Title:		Assistant Director of Resource Management
Address:		729 N. Azusa Avenue
City/State/Zip Code:		Azusa, CA 91702
Email Address:		btang@ci.azusa.ca.us
Phone:		(626) 812-5214
Fax No:		(626) 334-3163

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002

Effective: January 1, 2003

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

Original Sheet No. 233

City of Banning

Name of Primary
Representative:		Paul Toor
Title:		Public Works Director
Address:		99 East Ramsey Street
City/State/Zip Code:		Banning, California 92220
Email Address:		ptoor@ci.banning.ca.us
Phone:		(909) 922-3130
Fax No:		(909) 922-3141
Name of Alternative
Representative:		Fred Mason
Title:		Power Resource Specialist
Address:		176 East Lincoln Street
City/State/Zip Code:		Banning, California 92220
Email Address:		fmason@ci.banning.ca.us
Phone:		(909) 922-3265
Fax No:		(909) 849-1550

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002

Effective: January 1, 2003

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

Original Sheet No. 234

City of Riverside

Name of Primary
Representative:		Thomas P. Evans
Title:		Public Utilities Director
Address:		3900 Main Street
City/State/Zip Code:		Riverside, CA 92522
Email Address:		tevans@ci.riverside.ca.us
Phone:		(909) 826-5502
Fax No:		(909) 369-0548
Name of Alternative
Representative:		Gary L. Nolff
Title:		Power Contracts/Projects Manager
Address:		2911 Adams Street
City/State/Zip Code:		Riverside, CA 92504
Email Address:		gnolff@pac.state.ca.us
Phone:		(909) 351-6313
Fax No:		(909) 351-6328

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: November 25, 2002

Effective: January 1, 2003

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

Original Sheet No. 235

Trans-Elect NTD Path 15, LLC

Name of Primary
Representative:		Robert L. Mitchell
Title:		President
Address:		1850 Centennial Park Drive, Suite 480
City/State/Zip Code:		Reston, VA 20191
Email Address:		RLMitchell@trans-elect.com
Phone:		(703) 563-4362
Fax No:		(703) 563-4330
Name of Alternative
Representative:		Perry Cole
Title:		Vice President
Address:		3420 N. Hillcrest
City/State/Zip Code:		Butte, Montana 59701
Email Address:		PCole@trans-elect.com
Phone:		(406) 782-1907
Fax No:		(406) 782-0036

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: August 15, 2003

Effective: Upon notice after January 1, 2004

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

Original Sheet No. 236

Western Area Power Administration, Sierra Nevada Region

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

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: September 7, 2004

Effective: Upon notice after November 1, 2004

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

Original Sheet No. 237

City of Pasadena

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

Issued by: Anthony Ivancovich, Senior Regulatory Counsel
Issued on: December 23, 2004

Effective: January 1, 2005

QuickLinks

Exhibit 10.8

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