Exhibit A

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

Pacific Gas and Electric Company, 
 San Diego Gas & Electric Company,	Docket Nos. EC96-19-___
 and Southern California Edison Company	and ER96-1663-___

AMENDMENT NO. 3

SUBMITTED ON
February 25, 1998

Eligible Regulatory Must-Take and Eligible 
Regulatory Must-Run Issues

A.	The Amendments Are Necessary to Preserve Existing Transmission Priorities for Certain Eligible Regulatory Must-Take and Eligible Regulatory Must-Run Generation 
The ISO proposes several amendments to the ISO Tariff, including the ISO Protocols, to preserve after the ISO Operations Date the priority that certain Eligible Regulatory Must-Take Generation and Eligible Regulatory Must-Run Generation (collectively, “RMT/RMR Generation”) currently enjoy in access to Available Transfer Capacity on Congested Inter-Zonal Interfaces.
The ISO Control Area includes, inter alia, certain transmission facilities that were constructed for the sole purpose of, or in close relationship with, adding nuclear, hydro-electric, and Qualifying Facility (“QF”) generating facilities, as well as executing power purchase contracts with minimum Energy take requirements (i.e., those facilities and contracts termed Eligible Regulatory Must-Take Generation and Eligible Regulatory Must-Run Generation under the ISO Tariff).  Of these transmission facilities, some represent Congested Inter-Zonal Interfaces.  
The ISO Tariff does not explicitly describe these relationships, nor does it explicitly set forth any transmission priority for RMT/RMR Generation.  Prior to the Commission’s October 30 order, however, the ISO Tariff included language that some Participating Transmission Owners were apparently relying on to preserve existing transmission priorities for RMT/RMR Generation.  This provision, formerly ISO Tariff Section 2.4.2.2, was removed because it was related to the Overgeneration procedures rejected by the Commission.  It stated as follows:
The ISO shall give priority to Regulatory Must-Take Generation and Regulatory Must-Run Generation scheduled in the relevant Scheduling Coordinator's Preferred Schedule in evaluating the Preferred Day-Ahead Schedules and Preferred Hour-Ahead Schedules and preparing its Suggested Adjusted Day-Ahead Schedules for the Trading Day over all Generation other than that which is determined by the ISO to be needed for System Reliability.

Other than by way of the reference in Section 2.4.2.2 to Suggested Adjusted Schedules (which Schedules, in any event, are not binding on Scheduling Coordinators), the ISO Tariff and ISO Protocols do not anywhere state that RMT/RMR Generation should be treated with the highest priority (together with Reliability Must-Run Generation), in terms of access to Available Transfer Capacity on Congested Inter-Zonal Interfaces.  At least one Participating Transmission Owner, however, stated adamantly that it had always considered the priority of such Generation to be protected.
This Amendment No. 3 will clarify the stakeholders’ intent that RMT/RMR Generation be afforded the same priority enjoyed prior to the ISO Operations Date, consistent with existing operating arrangements.
This priority afforded to RMT/RMR Generation will be accomplished by the Scheduling Coordinator flagging the resource as either Eligible Regulatory Must-Take Generation, Eligible Regulatory Must-Run Generation, or Reliability Must-Run Generation, and submitting an Adjustment Bid with an assigned value, as specified in the proposed changes to the ISO Schedules and Bids and Scheduling Protocols.  These Adjustment Bids, in combination with the flag, will assure that the ISO’s Congestion Management algorithm will not curtail RMT/RMR Generation and Reliability Must-Run Generation until all other uses (both new firm uses and Existing Contract rights) of transmission have been curtailed as follows:
•	First, economic resources and trades, which have been allocated new firm use transmission service, that submitted Adjustment Bids within the normal range will be curtailed. 
•	Second, schedules that do not have Adjustment Bids and are not RMT/RMR Generation or Reliability Must-Run Generation, which have been allocated new firm use transmission service, will be curtailed (to zero if necessary on a pro-rata basis). 
•	Third, any Existing Contract uses (if and to the extent necessary) will be curtailed. 
•	Finally, curtailments of RMT/RMR Generation or Reliability Must-Run Generation, which have been allocated new firm use transmission service, will be implemented on a pro-rata basis unless otherwise required in instructions received from Participating Transmission Owners. 
All new firm uses of ISO transmission service, whether for RMT/RMR Generation, Reliability Must-Run Generation, other "price-takers", or economic users of transmission will be assessed Usage Charges associated with the use of Congested Inter-Zonal Interfaces.  In those instances involving non-economic curtailment (pro-rata) of new firm uses of ISO transmission service, Scheduling Coordinators will be liable for default Usage Charges in accordance with Section 7.3.1.3 of the ISO Tariff.
B.	The Amendments Reflect the Board’s Understanding of a Fundamental Precept of the California Restructuring

The proposed amendments are a result of discussions between the ISO and several Market Participants relating to the treatment of RMT/RMR Generation.  As noted above, these discussions were initiated as the result of the ISO’s deletion of Overgeneration provisions from the ISO Tariff when it made its compliance posting December 23 on its “Home Page”.  PG&E objected to the deletion, asserting that a fundamental precept of the California restructuring was preservation of the ability of utilities to produce Energy from all RMT/RMR Generation.  In PG&E’s instance, it was concerned over the potential for its Diablo Canyon nuclear unit to be unable to generate if there were insufficient PX Demand south of Path 15.
This issue, which is part of a wider debate which has been running in California for several years, within and beyond the context of restructuring California’s electricity markets, was discussed in an executive session of the ISO Governing Board (“Board”) on January 21, 1998 and, the night preceding, at the meeting of the Grid Operations and Reliability Committee of the Board.  Following a lengthy discussion in executive session, the Board directed staff not to re-instate Section 2.4.2.2 of the ISO Tariff, as described above, because this provision does not address the concern expressed by PG&E.  The Board did, however, conclude that it was the intent of the stakeholders in the restructuring process that RMT/RMR Generation continue to enjoy protection from curtailment in the event of Congestion.  
Subsequent to the January 21st Board meeting, PG&E issued its “final” operating instructions to the ISO for Path 15.  Based on those instructions, ISO management determined that it could not follow PG&E’s instructions in all respects.  In a special teleconference meeting January 29, the Executive Committee directed management to seek FERC approval to vary from PG&E’s instructions to the extent necessary to work within software constraints until changes to software could be made (see discussion infra).  The third consideration of these issues was in a special teleconference meeting on February 11, when the Board confirmed its earlier findings and rejected PG&E’s assertion that RMT/RMR Generation should be exempt from Usage Charges.
Accordingly, the Board directed ISO staff to promptly file proposed amendments to the ISO Tariff, including the ISO Protocols, to preserve the same transmission priority as currently provided to such resources by the relevant Participating Transmission Owner.  While the debate at the Board meeting centered on PG&E’s Diablo Canyon nuclear plant and QFs, the Board’s decision to maintain existing transmission priorities in Congestion Management applied to RMT/RMR Generation generally.
The proposed amendments are significant to the ISO and all other stakeholders that will participate in California's electricity markets.  As indicated above, PG&E raised the concern that the operation of its Diablo Canyon generating facility (a two-unit, 2160 MW nuclear power plant), and certain QFs in its service territory, could be affected as the result of the constrained transmission path that exists between these resources and PG&E's San Francisco load center.  This transmission path is referred to as "Path 15" and has been the subject of several Commission proceedings among the various Market Participants.
In expressing its concern, PG&E noted that ISO Tariff Section 2.4.2.2 was one of the few provisions in the ISO Tariff which preserved for its existing Regulatory Must-Take resources the priority which PG&E stated it was entitled to receive in the ISO's Congestion Management processes as a fundamental premise for the California restructuring “bargain”.  Today, the operation of these resources is closely linked to the Available Transfer Capacity of Path 15 -- as has been the case since PG&E's construction of Diablo Canyon.  In those instances when scheduled uses have exceeded the transfer capability of Path 15 (predominantly in the south-to-north direction), curtailments have been issued by PG&E in its dual role as Control Area operator and transmission service provider.  Curtailments of firm transmission service have sometimes occurred on Path 15.
Recently, the Western Systems Coordinating Council (“WSCC”) has adopted more stringent criteria which have adversely affected the operational transfer capability of several transmission paths, including Path 15.  Owing to these more stringent criteria, PG&E has limited south-to-north transfers over Path 15 on what PG&E describes as an “interim” basis.  The ISO has no information as to when this limitation will end, nor does it have any reason to believe that the limitation will be permanently lifted on or after the ISO Operations Date.  As such, the matter of Path 15 curtailments will continue to be of significant importance for the foreseeable future, and a matter for which the ISO will need to be fully apprised, and capable of responding to, in accordance with provisions explicitly stated in the ISO Tariff, including the ISO Protocols.
The ISO is obligated to accept PG&E’s instructions for operation of Path 15, including several levels of priority for the curtailment of transmission service prior to the curtailment of Diablo Canyon and certain QF contracts, which instructions involve both Existing Contracts usage and usage to serve native load.  As noted earlier, a copy of those instructions is attached hereto as Exhibit C.
C.	Effect of Tariff Amendment on Other Market Participants
When the ISO management assessed options to implement the Board’s directive to preserve existing priorities, it found two alternatives.  The one chosen by the Board, as described above, makes RMT/RMR Generation a new (and higher) priority of "price-takers" than all other users of Converted Rights (together with Reliability Must Run Generation). 
This approach was chosen over the only other alternative identified -- to treat RMT/RMR Generation as the equivalent of an Existing Contract.  That would have required a reservation of the maximum amount of transfer capacity for such resources over constrained paths and virtually eliminated many Existing Contract rights.  It also would have exempted RMT/RMR Generation from Usage Charges.  As noted above, PG&E proposed that option, which was expressly rejected by the Board in the February 11 teleconference.  The approach chosen ensures the greater use of the constrained path.
The ISO notes that, under the new market structure, in most cases Diablo Canyon and other RMT/RMR Generation would be able to serve PX Demand south of Path 15, requiring no action by the ISO.  This will mean that Existing Contract rights holders who historically have been cut to allow for the flow of Diablo Canyon power will have their Schedules honored, but arguably to the detriment of new firm users.  In other words, a Scheduling Coordinator who takes some of PG&E’s Load previously served by Diablo Canyon would use Converted Rights to deliver resources to that Load.  That Scheduling Coordinator will have a lower priority than Existing Contract rights holders if its resources are south of Path 15, even though, had PG&E continued to serve that Load with Diablo Canyon Energy, PG&E’s priority would have been higher than the priority of Existing Contracts.  The ISO notes this outcome for the Commission’s information, but stresses that this approach is the preferable one of the only two the ISO could identify to accommodate PG&E’s instructions and the original stakeholder intent.  
Accordingly, the following Sections of the ISO Tariff, the Schedule and Bids Protocol and the Scheduling Protocol are revised as follows.
ISO TARIFF AMENDMENTS
7.2.2.5	provide protection, from curtailment in the event of Congestion, for certain Reliability Must-Run Generation, Eligible Regulatory Must-Take Generation, Eligible Regulatory Must-Run Generation, and those Existing Rights and Non-Converted Rights that enjoyed such protection prior to the ISO Operations Date, in accordance with the Schedule and Bids Protocol and the Scheduling Protocol;
7.2.4.1	Uses of Adjustment Bids by the ISO.
7.2.4.1.1	The ISO shall use the Adjustment Bids, in both the Day-Ahead Market and the Hour-Ahead Market, to schedule Inter-Zonal Interface capacity to those Scheduling Coordinators which value it the most and to reflect the Scheduling Coordinators’ implicit values for Inter-Zonal Interface capacity.  The ISO will also use Adjustment Bids to protect, from curtailment in the event of Congestion, certain scheduled uses of Congested Inter-Zonal Interfaces, as provided in the Schedule and Bids Protocol and the Scheduling Protocol, including Eligible Regulatory Must-Run Generation, Eligible Regulatory Must-Take Generation, Reliability Must-Run Generation and those uses associated with Existing Rights and Non-Converted Rights that enjoyed such protection prior to the ISO Operations Date.

SCHEDULE AND BIDS PROTOCOL (SBP) AMENDMENTS
SBP 2.1.1	Generation Section of a Balanced Schedule and Adjustment Bid Data
The Generation section of a Balanced Schedule will include the following information for each Generating Unit: 
(a)	SC’s ID code;
(b)	type of market (Day-Ahead or Hour-Ahead) and Trading Day;
(c)	name of Generating Unit scheduled;
(d)	type of Schedule:  Preferred or Revised (refer to the SP for details);
(e)	priority type, if applicable, to the Settlement Period (use OTHER if scheduling the use of Existing Contract rights):
i.	Reliability Must-Run Generation (RLB_MUST_RUN);
ii.	Eligible Regulatory Must-Take Generation (MUST_TAKE);
iii.	Eligible Regulatory Must-Run Generation (REG_MUST_RUN);
iv.	none (OTHER)
(f)	contract reference number for Reliability Must-Run Generation, Eligible Regulatory Must-Take Generation, Eligible Regulatory Must-Run Generation or Existing Contract (or set of interdependent Existing Contracts);
(g)	Congestion Management flag – “Yes” indicates that any Adjustment Bid submitted under item (k) below should be used;
(h)	publish Adjustment Bid flag, which will not be functional on the ISO Operations Date.  In the future, “Yes” will indicate that the SC wishes the ISO to publish its Adjustment Bids; 
(i)	Generating Unit ramp rate in MW/minute;
(j)	hourly scheduled Generating Unit output in MWh (the ISO will multiply these values by the hourly Generation Meter Multipliers), including any zero values, for each Settlement Period of the Trading Day (in the case of a Day-Ahead Schedule) and for the relevant Settlement Period (in the case of an Hour-Ahead Schedule); and
(k)	the MW and $/MWh values for each Generating Unit for which an Adjustment Bid is being submitted consistent with SBP 4.
SBP 2.1.2	Demand Section of a Balanced Schedule and Adjustment Bid Data
The Demand section of a Balanced Schedule will include the following information for each Demand location: 
(a)	SC’s ID Code;
(b)	type of market (Day-Ahead or Hour-Ahead) and Trading Day;
(c)	Demand ID – Demand location (which must be the name of a Demand Zone, Load group or bus);
(d)	type of Schedule:  Preferred or Revised (refer to the SP for details);
(e)	contract reference number for Existing Contracts (or set of interdependent Existing Contracts);
(f)	Congestion Management flag – “Yes” indicates that any Adjustment Bid submitted for a Dispatchable Load under item (i) below should be used;
(g)	publish Adjustment Bid flag, which will not be functional on the ISO Operations Date.  In the future, “Yes” will indicate that the SC wishes the ISO to publish its Adjustment Bids;
(h)	hourly scheduled MWh, including any zero values, for each Settlement Period of the Trading Day (in the case of a Day-Ahead Schedule) and for the relevant Settlement Period (in the case of an Hour-Ahead Schedule); and 
(i)	the MW and $/MWh values for each Dispatchable Load for which an Adjustment Bid is being submitted consistent with SBP 4.
SBP 2.1.3	External Import/Export Section of a Balanced Schedule and Adjustment Bid Data
The external import/export section of a Balanced Schedule will include the following information for each import or export:
(a)	SC’s ID code;
(b)	type of market (Day-Ahead or Hour-Ahead) and Trading Day;
(c)	Scheduling Point (the name);
(d)	type of Schedule:  Preferred or Revised (refer to the SP for details);
(e)	interchange ID (the name of the selling entity, the buying entity, and a numeric identifier);
(f)	Energy type – firm (FIRM), non-firm (NFRM) or Wheeling (WHEEL);
(g)	dynamic schedule flag – “Yes” indicates the SC will be dynamically scheduling the external import at the Scheduling Point;
(h)	external Control Area ID;
(i)	priority type, if applicable, to the Settlement Period (use other if scheduling the use of Existing Contract rights):
i.	Reliability Must-Run Generation (RLB_MUST_RUN);
ii.	Eligible Regulatory Must-Take Generation (MUST_TAKE);
iii.	Eligible Regulatory Must-Run Generation (REG_MUST_RUN);
iv.	none (Other) [Cannot be Other if contract type is ENGY]
(j)	contract reference number for Reliability Must-Run Generation, Eligible Regulatory Must-Take Generation, Eligible Regulatory Must-Run Generation or Existing Contract (or set of interdependent Existing Contracts);
(k)	contract type – transmission (TRNS), Energy (ENGY) or both (TR_EN);
(l)	Schedule ID (NERC ID number);
(m)	Congestion Management flag - “Yes” indicates that any Adjustment Bid submitted for an external import/export in item (r) below should be used;
(o)	publish Adjustment Bid flag, which will not be functional on the ISO Operations Date.  In the future, “Yes” will indicate that the SC wishes the ISO to publish its Adjustment Bids;
(p)	complete WSCC tag;
(q)	hourly scheduled external imports/exports in MWh (the ISO will multiply these values by the hourly Generation Meter Multipliers), including any zero values, for each Settlement Period of the Trading Day (in the case of a Day-Ahead Schedule) and for the relevant Settlement Period (in the case of an Hour-Ahead Schedule) and with external imports into the ISO Controlled Grid reported as negative quantities and external exports from the ISO Controlled Grid reported as positive quantities; and 
(r)	the MW and $/MWh values for each external import/export for which an Adjustment Bid is being submitted consistent with SBP 4.
SBP 2.1.4	Inter-Scheduling Coordinator Trades (“Internal Imports/Exports”) Section of a Balanced Schedule 
In the event of an Inter-Scheduling Coordinator Trade, the SCs who are parties to that trade must agree on a Zone in which the trade will be deemed to take place (“Trading Zone”) and notify the ISO accordingly.  If the SCs which are parties to the trade cannot agree on a Trading Zone, the ISO will designate one.  The purpose of designating a Trading Zone is to provide for the allocation of Usage Charges which may arise in connection with the trade.  Any two SCs can only have one Inter-Scheduling Coordinator Trade between them in each Trading Zone.  The Inter-Scheduling Coordinator Trades section of a Schedule will include the following information for each Inter-Scheduling Coordinator Trade:
(a)	SC’s ID code; 
(b)	type of market (Day-Ahead or Hour-Ahead) and Trading Day; 
(c)	trading SC (buyer or seller); 
(d)	type of Schedule:  Preferred or Revised (refer to the SP for details); 
(e)	contract reference number for Existing Contract (or set of interdependent Existing Contracts);
(f)	hourly scheduled MWh for each Settlement Period of the Trading Day that uses the Existing Contract indicated in (e) above (which values should be less than or equal to the values indicated in (i) below); 
(g)	Trading Zone; 
(h)	Schedule type – Energy (ENGY); and 
(i)	hourly scheduled MWh, including any zero values, for each Settlement Period of the Trading Day (in the case of a Day-Ahead Schedule) and for the relevant Settlement Period (in the case of an Hour-Ahead Schedule), with internal imports into the SC reported as negative quantities and internal exports from the SC reported as positive quantities.
SBP 2.2.1	Stage One Validation
During stage one validation, each incoming Schedule will be validated to verify proper content, format and syntax.  The ISO will check that the SC had not exceeded its Security Amount and verify that the SC is certified in accordance with the ISO Tariff.  The ISO will further verify that the SC has inputted valid Generating Unit and Demand location identification.  Scheduled Reliability Must-Run Generation, Eligible Regulatory Must-Take Generation and Eligible Regulatory Must-Run Generation will be verified against the contract reference numbers in the ISO’s Scheduling Coordinator database.  A technical validation will be performed verifying that a scheduled Generating Unit’s output is not beyond it’s declared capacity and/or operating limits.  If there is an error found during stage one validation, the SC will be notified immediately through WEnet.  The SC can then look at the notification messages to review the detailed list of errors, make changes, and resubmit the Schedule if it is still within the timing requirements of the SP.  The SC is also notified of successful validation via WEnet.
SBP 3.4	Validation of Existing Contract Schedules
Each Schedule submitted to the ISO by a SC representing a rights holder to an Existing Contract must include a valid contract reference number in accordance with SBP 3.3.  If the Schedule includes an Inter-Scheduling Coordinator Trade, only one of the SCs should submit a contract reference number.  If a match of the Schedule’s contract reference number is found in the ISO’s database and the Schedule is consistent with the instructions submitted previously by the Responsible PTO, the Schedule will be implemented in accordance with the instructions.  If a match of the Schedule’s contract reference number cannot be found in the ISO’s database,  or if both SCs, or neither SC, which is a party to an Inter-Scheduling Coordinator Trade submits a contract reference number, the ISO will contact the SC and indicate the nature of the problem.  The ISO will assist the SC, within reason, in resolving the problem so that the SC is able to submit the Schedule successfully as soon as possible within the timing requirements of the SP.  If the SC uses a contract reference number for which the Responsible PTO has not reserved transmission capacity on a particular path, the scheduled use will be treated as new firm uses with a $0/MWh Adjustment Bid.
SBP 4.6	Use of Adjustment Bids to Establish Priorities
In addition to being used to establish the value each Scheduling Coordinator places on the use of Congested Inter-Zonal Interfaces, Adjustment Bids are also used by the ISO to establish priorities associated with transmission service under Existing Contracts and priorities associated with certain Reliability Must-Run Generation, Eligible Regulatory Must-Take Generation and Eligible Regulatory Must-Run Generation that enjoyed such priorities prior to the ISO Operations Date.  To accomplish this, certain Adjustment Bids and ranges of Adjustment Bids have been reserved for use in establishing relative priorities.  Any Adjustment Bid (other than an Adjustment Bid related to Existing Contracts, Reliability Must-Run Generation, Eligible Regulatory Must-Take Generation or Eligible Regulatory Must-Run Generation) which exceeds the default Usage Charge, will be treated as if the Adjustment Bid was equal to the default Usage Charge (see description below regarding the Congestion Management software treatment of an implicitly assigned negative value for default Usage Charge).  The values and ranges for Adjustment Bids to be submitted by Scheduling Coordinators or Adjustment Bids implicitly assigned by the Congestion Management software for these various purposes are as follows:
Adjustment Bid
Value/Range
$/MWh	

Use	
2,000	Adjustment Bid value implicitly assigned by the Congestion Management software to Inter-Scheduling Coordinator Trade exports with a valid contract reference number for the amount of the Inter-Scheduling Coordinator Trade equal to or less than the MW amount specified in the Existing Contract.  Usage Charges are not calculated for these scheduled uses, except for any quantity of Energy scheduled in excess of the MW amount specified in the Existing Contract which is treated as a new firm use of ISO transmission service which the Congestion Management software values at the Adjustment Bid price of 1.4 x default Usage Charge.
	
1,900 to 2,000	Adjustment Bid range available for Demand and external export schedules using Existing Contract rights with a valid contract reference number.  Usage Charges are not calculated for these scheduled uses except for quantities of Energy scheduled in excess of the MW amount specified in the Existing Contract which is treated as a new firm use of ISO transmission service and values the additional transmission service at the Adjustment Bid price within this range.
	
1.4 x default
Usage Charge	Adjustment Bid value implicitly assigned by the Congestion Management software to Inter-Scheduling Coordinator Trade exports using new firm uses of ISO transmission service.  Usage Charges are calculated for these scheduled uses.
	
default Usage Charge	Adjustment Bid value implicitly assigned by the Congestion Management software for Demand and external export schedules of new firm uses when no Adjustment Bid is provided (i.e., a “price-taker”) or to extend the lower megawatt end of the Adjustment Bid to zero megawatts.  This is also the Adjustment Bid value used by the Congestion Management software to extend the upper megawatt end of a Generator’s Adjustment Bid to the Generator’s physical maximum limit (for external import schedules, and for external export schedules, the upper megawatt end of the Adjustment Bid is treated as the “physical” maximum limit and, as such, is not extended).  Usage Charges are calculated for these scheduled uses.
	
0.01 to < default
Usage Charge	Adjustment Bid range available for scheduling new firm uses of ISO transmission service bid as potential "price-makers."  Usage Charges are calculated for these scheduled uses.  This is the “normal” economic range for Adjustment Bids.
	
0.001 to < 0.01	Adjustment Bid range available for scheduling the use conditional firm Existing Contract rights.  Although available for Existing Contract use, this range is not protected from Usage Charges since the charges would be calculated in fractions of dollars (e.g., 100 MW at $0.01/MWh produces a $1.00 charge).  A contract reference number is not used for scheduling use of conditional firm Existing Contract rights.
	
0	Adjustment Bid value available for scheduling either new firm uses of ISO transmission service or uses of Existing Contract rights and expressing a zero dollar value for adjustments.  This is the Adjustment Bid value implicitly assigned by the Congestion Management software for a Generator or external import that is specified with a priority type or contract reference number that cannot be verified in the ISO's scheduling system and submitted with a negative Adjustment Bid outside of the range reserved for Existing Contracts (i.e., -$1,900 to -$2,000), Eligible Regulatory Must-Run, Eligible Regulatory Must-Take, and Reliability Must-Run (i.e., -$10,000).
	
- default Usage
Charge	Adjustment Bid value implicitly assigned by the Congestion Management software for Generation and external import schedules of new firm uses when no Adjustment Bid is provided (i.e., a “price-taker”) or to extend the lower megawatt end of a Generator’s Adjustment Bid to the Generator’s physical minimum limit.  This is also the Adjustment Bid value used by the Congestion Management software to extend the lower megawatt end of an external import’s Adjustment Bid to zero megawatts.  If a Scheduling Coordinator is relying partially on Existing Contract rights for an external import or Generator schedule bid and wishes to be a “price-taker” for the balance not covered by those rights, it should explicitly submit this value as its Adjustment Bid for the balance.
	
-1.4 x default
Usage Charge	Adjustment Bid value implicitly assigned by the Congestion Management software to Inter-Scheduling Coordinator Trade imports using new firm uses of ISO transmission service.  Usage Charges are calculated for these scheduled uses.
	
-1,900 to -2,000	Adjustment Bid range available for scheduling Generation and external imports using Existing Contract rights with a valid contract reference number.  Usage Charges are not calculated for these scheduled uses.  An Adjustment Bid, for an Existing Contract use, submitted with a price for the first (or single) segment outside of this range will be treated by the Congestion Management software as a zero value bid.
	
-2,000	Adjustment Bid value implicitly assigned by the Congestion Management software to Inter-Scheduling Coordinator Trade imports with a valid contract reference number for the amount of the Inter-Scheduling Coordinator Trade equal to or less than the MW amount specified in the Existing Contract.  Usage Charges are not calculated for these scheduled uses except for any quantity of Energy scheduled in excess of the MW amount specified in the Existing Contract which is treated as a new firm use of ISO transmission service which the Congestion Management software values at the Adjustment Bid price of -1.4 x default Usage Charge.
	
-10,000	Adjustment Bid value available for scheduling priority types of Reliability Must-Run Generation, Eligible Regulatory Must-Take Generation and Eligible Regulatory Must-Run Generation only.  Usage Charges are calculated for these scheduled uses.  An Adjustment Bid, for a priority type use, submitted with a price for the first (or single) segment less than this value will be treated by the Congestion Management software as a zero value bid (e.g., an Adjustment Bid of 
-$9,998/MWh will be treated as a zero value bid).

SCHEDULING PROTOCOL (SP) AMENDMENTS
SP 7.2.2	Prioritization of Transmission Uses
The following rules are designed to enable the ISO to honor Existing Contracts in accordance with Sections 2.4.3 and 2.4.4 of the ISO Tariff, except as may be limited by the operation of SP 7.4.  Regardless of the success of the application of such rules, it is intended that the rights under Existing Contracts will be honored as contemplated by the ISO Tariff except as may be limited by the operation of SP 7.4.  In each of the categories described in SP 7.2.1, the terms and conditions of service may differ among transmission contracts.  These differences will be described by each Responsible PTO in the instructions submitted to the ISO in advance of the scheduling process in accordance with the SBP.  In addition, Generation, Inter-Scheduling Coordinator Trade imports or external imports in one Zone must be matched by an equal magnitude of Demand, Inter-Scheduling Coordinator Trade exports or external exports in an adjacent Zone (see SP 7.2.3 for a summary of allowable linkages).  Scheduling and curtailment priorities associated with each category will be defined by SCs through the use of Adjustment Bids submitted as part of their Schedules as described in the following (see the SBP for a more general description of the use of Adjustment Bids to not only establish priorities within Existing Contracts, but also to establish priorities for Reliability Must-Run Generation , Eligible Regulatory Must-Take Generation and Eligible Regulatory Must-Run Generation):
(a)	Transmission capacity for Schedules will be made available to holders of firm Existing Rights and firm Non-Converted Rights in accordance with this SP and the terms and conditions of their Existing Contracts.  In the event that the firm uses of these rights must be curtailed, they will be curtailed on the basis of “high priced Adjustment Bids”.  So as not to be curtailed before any other scheduled use of Congested Inter-Zonal Interface capacity, these high priced Adjustment Bids must fall within a range to be specified by the ISO (for example, a difference of +$1,900/ MWh to +$2,000/ MWh for Demand or external exports and a difference of -$ 1,900/ MWh to 
-$ 2,000/ MWh for Generation or external imports).  This range will be reserved strictly for use in association with the prioritization of firm Existing Rights and firm Non-Converted Rights to use available Inter-Zonal Interface transmission capacity.  These high priced Adjustment Bids are only for the ISO’s use, in the context of Congestion Management, in recognizing the various levels of priority that may exist among the scheduled uses of firm transmission service.  These high priced Adjustment Bids will not affect any other rights under Existing Contracts.  To the extent that the MW amount exceeds the MW amount specified in the Existing Contract, the excess scheduled amount will be treated as a new firm use of ISO transmission services as described in (b) below.  Note that, in some instances, for a particular Inter-Zonal Interface, there may be multiple SCs submitting Schedules under several different Existing Contracts on behalf of several Existing Contract rights holders.  In these circumstances, and to the extent the rights holders desire to coordinate the prioritization of their firm uses of the Inter-Zonal Interface (i.e., attribute high priced Adjustment Bids, within the specified range, to each Schedule), their SCs will make the arrangements among themselves ahead of the ISO’s scheduling process.  In the absence of an Adjustment Bid, the ISO will treat the scheduled use of transmission service as a “price-taker” of ISO transmission service subject to Usage Charges.
(b)	ISO transmission service (i.e., “new firm uses”) will be priced in accordance with the ISO Tariff.  Usage Charges associated with the ISO’s Congestion Management procedures, as described in SP 10, will be based on Adjustment Bids which do not fall within either of the ranges specified in (a) above or (c) below.  In the absence of an Adjustment Bid, the ISO will treat the scheduled “new firm use” of ISO transmission service as a price taker paying the Usage Charge established by the highest valued use of transmission capacity between the relevant Zones.
(c)	Transmission capacity will be made available to holders of conditional firm Existing Rights and conditional firm Non-Converted Rights in a manner similar to that done prior to the ISO Operations Date; that is, allocated, as available, based on the agreed priority.  The levels of priority will be expressed in the Schedules in terms of “near zero priced Adjustment Bids”.  Adjustment Bids with the lowest near zero price will be treated with the lowest priority.  These near zero priced Adjustment Bids must fall within a range to be specified by the ISO (for example, a difference of $0.001/MWh to $0.01/MWh for Demand or external exports and -$0.001/MWh to -$0.01/MWh for Generation or external imports).  This range will be reserved strictly for use in association with the prioritization of conditional firm Existing Rights and conditional firm Non-Converted Rights to use available Inter-Zonal Interface transmission capacity.  These near-zero priced Adjustment Bids are only for the ISO’s use, in the context of Congestion Management, in recognizing the various levels of priority that may exist among the scheduled uses of conditional firm transmission service.  These near-zero priced Adjustment Bids are not intended to affect any other rights under Existing Contracts, nor are they intended to subordinate the ISO’s scheduling of firm uses. To the extent that the MW amount exceeds the MW amount specified in the Existing Contract, the excess scheduled amount will be treated as a new firm use of ISO transmission services as described in (b) above.  Note that, in some instances, for a particular Inter-Zonal Interface, there may be multiple SCs submitting Schedules under several different Existing Contracts on behalf of several Existing Contract rights holders.  In these circumstances, and to the extent the rights holders desire to coordinate the prioritization of their conditional firm uses of the Inter-Zonal Interface (i.e., attribute near-zero priced Adjustment Bids, within the specified range, to each Schedule), their SCs will make the arrangements among themselves ahead of the ISO’s scheduling process.  In the absence of an Adjustment Bid, the ISO will treat the scheduled use of  transmission service as  a “price-taker” of ISO transmission services subject to Usage Charges.
(d)	Transmission capacity will be made available to holders of non-firm Existing Rights and non-firm Non-Converted Rights in a manner similar to that done prior to the ISO Operations Date; that is, treated as the lowest valued use of available transmission capacity.  Non-firm uses of transmission capacity under Existing Contracts will be indicated in Schedules submitted by SCs as $0.00/MWh Adjustment Bids.
SP 7.2.3	Allowable Existing Contract Linkages
As indicated in SP 7.2.2, Generation, Inter-Scheduling Coordinator Trade imports or external imports in one Zone must be matched by an equal magnitude of Demand, Inter-Scheduling Coordinator Trade exports or external exports in the same Zone or in an adjacent Zone.  The table below summarizes the allowable linkages.
Generation	Demand	
Generation	External Export	
Generation	Inter-SC Trade Export	
External Import	Demand	
External Import	External Export	
External Import	Inter-SC Trade Export	
Inter-SC Trade Export	Demand	
Inter-SC Trade Export	External Export	
Inter-SC Trade Export	Inter-SC Trade Export	
SP 7.3.4	Allocation of Inter-Zonal Interface 
In the ISO’s Congestion Management analysis of the Day-Ahead Market, for each Inter-Zonal Interface:
(a)	if all scheduled uses of transmission service fit within the adjusted total transfer capability, all are accepted (in other words, there is no congestion);
(b)	if all scheduled uses of transmission service do not fit within the adjusted total transfer capability, scheduled uses of non-firm Existing Rights and non-firm Non-Converted Rights will be curtailed, pro rata, to the extent necessary.  If the remaining scheduled uses of transmission service still do not fit within the adjusted total transfer capability, uses of conditional firm Existing Rights and conditional firm Non-Converted Rights will be curtailed (based upon the levels of priority expressed in the Schedules in terms of near zero priced Adjustment Bids as described in SP 7.2.2 (c)) to the extent necessary;
(c)	if Congestion still exists after curtailing all non-firm and conditional firm uses of transmission service under Existing Contracts, the remaining transmission capacity (that is not already reserved as firm Existing Rights and firm Non-Converted Rights) is priced based upon Adjustment Bids.  To the extent there are insufficient Adjustment Bids to fully mitigate the remaining Congestion, the default Usage Charge will apply and the ISO will curtail ISO transmission service (in other words, new firm uses), pro rata, to the extent necessary; 
(d)	if Congestion still exists after curtailing ISO new firm uses, scheduled uses of firm Existing Rights and firm Non-Converted Rights are then curtailed (based upon the priorities expressed in the Schedules in terms of high priced Adjustment Bids as described in SP 7.2.2 (a)) to the extent necessary; and
(e)	if Congestion still exists after curtailing scheduled uses of firm Existing Rights and firm Non-Converted Rights, Reliability Must-Run Generation, Eligible Regulatory Must-Take Generation and Eligible Regulatory Must-Run Generation will be curtailed on a pro-rata basis (with due regard to Reliability Must-Run Generation).
SP 10.2	Congestion Management Process
(a)	Inter-Zonal Congestion Management will involve adjusting Schedules to remove potential violations of Inter-Zonal Interface constraints, minimizing the redispatch cost, as determined by the submitted Adjustment Bids that accompany the submitted Schedules.  See the SBP for a general description of the use of Adjustment Bids to establish priorities.
(b)	Inter-Zonal Congestion Management will not involve arranging or modifying trades between SCs.  Each SC’s portfolio will be kept in balance (i.e., its Generation plus external imports, as adjusted for Transmission Losses, and Inter-Scheduling Coordinator Trades (whether purchases or sales) will still match its Demand plus external exports) after the adjustments.  Market Participants will have the opportunity to trade with one another and to revise their Schedules during the first Congestion Management iteration in the Day-Ahead Market, and between the Day-Ahead Market and Hour-Ahead Market.
(c)	Inter-Zonal Congestion Management will also not involve the optimization of SC portfolios within Zones (where such apparently non-optimal Schedules are submitted by SCs).  Adjustments to individual SC portfolios within a Zone will be either incremental (i.e., an increase in Generation and external imports and a decrease in Demand and external exports) or decremental (i.e., a decrease in Generation and external imports and an increase in Demand and external exports), but not both.

(d)	If Adjustment Bids are exhausted before Congestion is eliminated, the remaining Schedules will be adjusted pro rata except for those uses of transmission service under Existing Contracts, which are curtailed in accordance with SP 7.3 and SP 7.4.

Exhibit B
Notice Suitable for Publication in the Federal Register
Pacific Gas and Electric Company, 
 San Diego Gas & Electric Company,	Docket Nos. EC96-19-___
 and Southern California Edison Company	and ER96-1663-___

NOTICE OF FILING
Take notice that on February 25, 1998, the California Independent System Operator Corporation (“ISO”) filed for Commission acceptance in this docket, pursuant to Section 205 of the Federal Power Act, an application to amend the ISO Tariff, including the ISO Protocols, and a motion for waiver of the 60-day notice requirement.  The ISO requests that the proposed amendments be made effective as of the ISO Operations Date.

The ISO states that the proposed amendments, which would preserve, after the ISO Operations Date, the priority that certain Eligible Regulatory Must-Take Generation and Eligible Regulatory Must-Run Generation currently enjoy in access to Available Transfer Capacity on Congested Inter-Zonal Interfaces, are necessary for the initial operations of the ISO.

Any person desiring to be heard or to protest said filing should file a petition to intervene or protest with the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C.  20426, in accordance with 18 C.F.R. §§ 385.212 and 385.207.  All such petitions or protests should be filed on or before _________.  Protests will be considered by the Commission in determining the appropriate action to be take, but will not serve to make Protestants parties to the proceeding.  Any person wishing to become a party must file a petition to intervene.  Copies of this application are on file with the Commission and available for public inspection.

Exhibit C
PG&E’s Instructions

Date: 		February 4, 1998

Memo To: 	California Independent System Operator (ISO)

From: 	Pacific Gas & Electric Company

Subject: 	Operating Instructions for Existing Encumbrances Across the Path 15 Interface 

These instructions direct the ISO on the allocation of transfer capability on Path 15 for use as a component in the ISO’s Day Ahead, Hour Ahead and Real Time scheduling process, and for implementation of curtailments.  The object of these instructions is to ensure that the availability of transmission transfer capability and transmission service for Existing Contracts and other encumbrances, including use for Regulatory Must-Take Generation, is neither diminished nor enhanced due purely to the new operational practices and uses of the ISO Controlled Grid under ISO Operational Control.  Specific operating instructions are 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.  Schedules for these Existing Contracts submitted to the ISO by PG&E, as Scheduling Coordinator, will reflect the best information known to PG&E of the line conditions at the time of submission. 

PG&E will utilize its encumbered DC Line Entitlements in order to allow it to meet its obligations for transmission service using Path 15, including its obligations to TANC and CDWR as well as others.

As of December 19, 1997, the available operating transfer capability of Path 15 is 3000 MW.  Another element that affects the MW of available scheduling capability is unscheduled flow.  Unscheduled flow does not reduce the transfer capability of the Path 15 but restricts the available scheduling capability (the level of transmission service that can be provided) of Path 15.  The combination of available transfer capability and unscheduled flow produces the available scheduling capability for any given hour.  

Under most operating conditions north-to-south available scheduling capability is ample to satisfy the scheduled transmission service requirements of all the current rightsholders.  Operating conditions do occur in the south-to-north direction, which require the curtailment of allocated available scheduling capability.  The curtailment procedures provided herein maintain the same scheduling and curtailment priority rights that have been and are in effect today.  PG&E operates this path dynamically.  It accepts all preschedules and takes necessary actions in real-time to mitigate possible curtailments.  The curtailments today are all performed in real time in order to provide the maximum level of service to all path users. 

The highest priority to schedule and transmit energy in both the north-to-south and south-to-north directions on an hourly basis daily on Path 15 is PG&E’s Regulatory Must-Take Generation--Net of the Local Area Load served by PG&E south of Path 15.  The ISO should exclude these highest priority schedules from its congestion management process just as other Existing Contracts schedules are excluded.  Once this priority is met the remaining available scheduling capability on Path 15 is available for other existing rightsholders and ISO usage.

There are varying levels of priority for transmission service utilization on Path 15.  Within equal priority levels curtailments are shared pro-rata.

Priority Group	Existing Contract/Priority Holder	North-to-South MW	South-to-North MW	
1st 	PG&E’s Must Take Generation, Net of PG&E Load, South of Path 15	0
	Variable	
2nd	CDWR’s EHV Agreement
SCE’s & SDG&E’s CCPIA,	300
1150	300
776	
3rd 	CDWR Comprehensive Agreement 	1278	810	
4th	TANC SOTP
PG&E SOTP	300
500	300
500	
5th 	SMUD TRS
TID Reserved Rights	400
32	400
32	
6th	Other Encumbrances	376	88	
7th	CDWR Flexibility	N/A	468/279	

Once all these existing priority obligations are satisfied, the remaining transmission capability is available for new firm or non-firm uses. 

The attached Excel worksheet allocates, tabulates and numerically details the Path 15 transmission service allocation process.  Additionally, the worksheets include calculations that show the effect reductions in COB transfer capabilities have on CDWR’s, SCE’s and SDG&E’s scheduling and transfer capabilities at COB and Path 15.  The specific cells on the spreadsheet that require input of information to reflect the current scheduling and transfer capability for all Rights Holders are boxed.  The worksheet lists all data at maximum scheduling availability (contract entitlement).  Actual transmission scheduling practices in the Day Ahead, Hour Ahead and Real Time markets may vary significantly from the values used in the worksheet.  

PG&E will submit to the ISO updated operating instructions and spreadsheets as situations and circumstances dictate.