Title: I
Author: OA2000
Last saved by: Juralynne B. Mosley
Company: California Public Utilities Commission

RESTRUCTURING STATUS		updated 07/15/99

07/15/99

State of California	Public Utilities Commission
		San Francisco
M E M O R A N D U M
		www.cpuc.ca.gov

Date:	July 7, 1999 

To:	Commissioners

From :	Douglas Long/Gurbux Kahlon
	Electric Restructure Coordinators

Subject :	Status of Electric Restructuring Matters, and Upcoming Milestones, 
		for Commissioner Reports Discussion

	Attached to this cover memo is a status report on electric restructuring activity since the Commission Meeting held on June 24^th  , including upcoming events and filings. Details from prior reports are available on the web site.,

	In our continuing effort to provide more information to the public, this report will be placed on the Commission's Web site following the Commission conference at: 
http://www.cpuc.ca.gov/electric_restructuring/status/status_index.shtml.  

cc:	W. Franklin
	P. Arth
	L. Carew
	P. Clanon
	W. Meyer
             ERT

I.	Ratesetting	3
A.	Revenue Adjustment Proceeding (RAP) (A.98-07-003, et. al.)	3
B.	Annual Transition Cost Proceedings (ATCP - A.98-09-003, et. al.)	3
C.	Performance-Based Ratemaking (PBR)	4
D.	Unbundling Revenue Cycle Services (D. 98-09-070):	4
E.	Post-Transition Period Ratemaking Applications (A.99-01-016, et. al.).	4
F. 	SDG&E Application to End the Rate Freeze (A.99-02-029)	5
II.	Transition Costs	5
A.	CTC and Restructuring Implementation Costs:  A. 96-08-001 et. al.	5
B.	Qualifying Facilities (QF) Issues	5
III.	Divestiture Proceedings	5
A.	SDG&E Sec. 851 “Divestiture” Application 97-12-039	5
B.	PG&E, Sec, 851 "Divestiture" Application 98-01-008	6
C.	Southern California Edison, Power plant Divestiture A. 96-11-046	6
IV.	Market Valuation:  PG&E A.98-05-022, Edison A.98-05-014	6
V.	Distributed Generation and Distribution Competition Rulemaking (R.98-12-015)	7
VI.	Direct Access	7
A.	Introduction:	7
B.	Utility Fees for Direct Access:	8
C.	Tariffs and Service Agreements for Direct Access (D.97-10-087)	8
D.	Meter and Data Communication Standards (D.97-12-048 and D.98-12-080)	9
E.	Retail Settlements and Information Flow (D.97-12-090 and D.98-11-044)	9
F.	Load Profiling (D.97-10-086 and D.98-12-065)	10
VII. FERC‑Related Issues	10
A.	ISO Files Ancillary Services Redesign Plan	10
B.	 Potential Settlement Reached in PG&E Transmission Owner Tariff Rate Case	11
C.	New PG&E Transmission Owner Tariff Rate Case	11
D.	FERC Considers Market-Based Rate Applications Filed by New Owners 	11
E.	 PX Files Tariff Amendments and Block-Forward Proposal	11
F.	RMR Settlement Filed at FERC in ER98-441-000, et al.	11
G.	The ISO Files Amendment 16 to its Tariff	12
H.	ISO submits agreement with PG&E on operating procedures and curtailment priorities for Path 15…...……   …12
    I.	The PX files Tariff Amendment  No. 11 …………………………………………………………………………...12
    J.	The ISO fils Tariff Amendment No. 17 …………………………………………………………………………....12
    K.	The ISO files its proposed Tariff Amendment No. 18………………………………………………………..….…13
    L.	The ISO files its proposed Tariff Amendment No. 19…………………………………………………………...…13
    M.	Recent FERC Decisions……………………………………………………………………………………………..13
VIII. Public Purpose Programs	17
A.	Energy Efficiency and Demand Side Management	17
B.	Governing Board For Low-Income Programs (LIGB)	17
IX .  CEQA Issues Related to Divestiture of Fossil Generation	18
X.	Reliability	18
XI.	Consumer Education/Protection	19
A.	The Commission’s Outreach Plan	20
B.	The Electric Education Trust	20
C.	Consumer Protection	20

I.	Ratesetting
A.	Revenue Adjustment Proceeding (RAP) (A.98-07-003, et. al.)

Pursuant to D.99-06-058 in PG&E’s, SDG&E’s and SCE’s first annual RAP proceedings, the utilities will file their 1999 RAP applications in August.  The purpose of the RAP is to consolidate the revenue requirement adjustment associated with each utility's various proceedings and ratemaking mechanisms, verify the "headroom" to be transferred to the transition cost balancing account, streamline and eliminate unnecessary balancing accounts, and consider general rate design and revenue allocation issues.

Among the issues D.99-06-058 resolved in the 1998 RAP proceedings were:

•	Allocating the costs of implementing electric restructuring (“Section 376 costs”) on an EPMC basis and in the same manner as transition costs are currently being collected
•	Allocating transmission and distribution, public purpose, nuclear decommissioning costs , and various memorandum and balancing accounts between customer classes
•	Eliminating various memorandum and balancing accounts that are no longer needed
•	Requiring the utilities to include in their 1999 RAP applications modfications to the  PX credit to include certain procurement costs related to purchasing energy from the Power Exchange. 
•	Continuing the allocation of PX start-up costs to all customers
•	Changing the “Post-Real Time” settlement costs of the Power Exchange.

D.99-06-058 also requires SDG&E to file an application later in 1999 to propose revenue allocation and rate design changes.
B.	Annual Transition Cost Proceedings (ATCP - A.98-09-003, et. al.)

•	On September 1,1998,  PG&E, SCE and SDG&E filed their first applications in their annual transition cost proceedings.  The purpose of the ATCP is to 1) review entries to the must-run and non-must-run memorandum accounts to ensure that excess revenues are properly credited to the TCBA, 2) adjust accelerated depreciation and account for the results of divestiture proceedings in the TCBA; 3) adjust the TCBA for generation capital additions and QF contract buyouts, and 4) review the reasonableness of costs and revenues from the ISO and PX, employee related transition costs, purchased power, and QF contract administration. 
•	On May 7, 1999, the final workshop report on the interaction of the rate reduction bond (RRB) proceeds with the transition cost balancing account (TCBA) was published as required by Assigned Commissioners' Ruling dated December 16, 1998.
•	Proposed decision is currently scheduled  for  November 15^th.  Final decision is expected on December 16^th. 

C.	Performance-Based Ratemaking (PBR)

On May 18, 1999, the ALJ in PG&E’s PBR proceeding, A.98-11-023, issued a ruling which changed the schedule for some key dates in the schedule.  ORA’s testimony is due July 19^th, other intervenors’ testimony is due August 9^th, and rebuttal testimony is due August 23rd.   Hearings are to begin on September 8^th.  

On May 13, 1999, the Commission issued its decision, D.99-05-030, concerning the design of the new SDG&E electric distribution and gas base rate PBR.  On May 24, 1999, SDG&E filed an advice letter to implement the new PBR.  That advice letter is under review.

In the SCE PBR Midterm Review, A.99-03-020, workshops were held on June 15^th through the 17^th, to discuss the reports and studies provided by SCE in its application, and to formulate recommendations to the Commission. The Energy Division will issue a workshop report on July 16, 1999. A decision is expected before the end of the year.

D.	Unbundling Revenue Cycle Services (D. 98-09-070):

     Decision 99-06-063 was issued.  This decision disposes of applications for rehearing of D.98-09-070, which relate to unbundling revenue cycle services.  The rehearing applications, filed by Commonwealth Energy Corporation and jointly by Enron Corp. and New Energy Ventures, LLC, focus on the billing credits based on short-run avoided costs and the surcharge fees for recovery of incremental costs of unbundling revenue cycle services.  D.99-06-063 grants a limited rehearing to modify D.98-09-070, and  denies the applications for rehearing of D.98-09-070, as modified.

E.	Post-Transition Period Ratemaking Applications (A.99-01-016, et. al.).

On January 15, 1999, PG&E, SCE and SDG&E filed the applications which propose methods of identifying the end of the transition period and establishing ratemaking mechanisms for the subsequent period.  Assigned ALJs Malcolm and Minkin held a prehearing conference on February 18 and Commissioner Duque issued a scoping memo on March 11.  The proceeding will address how to end the rate freeze for various stomer groups, and ratemaking matters such as balancing account treatment for power cost recovery.  The scope of the proceeding will also include broad rate design matters which are integral to ending the rate freeze and the development of post-transition ratemaking.  The Commission will consider the mechanics of ending the rate freeze in Phase 1 and Post-Transition Rate Regulation in Phase 2.  The schedule is as follows:

Phase 1
July 5	ALJs' Proposed Decision
August 5	Final Decision

Phase 2
July 2	ORA Testimony
July 30  	Intervenor Testimony
August 11	Rebuttal Testimony
August 23	Hearings Begin
Sept 25 	Opening Briefs
December 14 	ALJs' PD
January 14, 2000 	Final Decision

F. 	SDG&E Application to End the Rate Freeze (A.99-02-029)

On February 19, SDG&E filed A.99-02-029 proposing to end the rate freeze for its customers effective July 1, 1999.  By a Ruling dated March 1, assigned ALJs Malcolm and Minkin consolidated SDG&E's application with the post-transition period ratemaking applications.  At the March 12th prehearing conference, parties were encouraged to meet to resolve the issues on an interim basis. Parties filed a settlement on April 15^th.  In D.99-05-051 the Commission approved the settlement with conditions.  The settlement may be retroactively modified following the consideration of related issues in Phase 1 of the consolidated post-transition period ratemaking proceeding.

II.	Transition Costs
A.	CTC and Restructuring Implementation Costs:  A. 96-08-001 et. al.
Transition costs are generation asset related uneconomic costs that utilities will have an opportunity to recover through the Competition Transition Charge (CTC).  The transition cost proceeding (A.96-08-001 et. al.) has addressed most transition cost and CTC terms and conditions issues in two phases and 5 decisions

Recent Activity

A.98-05-004, et. al: The Commission adopted Decision 99-05-031 at the May 13 meeting.  This decision approves settlements on issues in SDG&E’s A.98-05-006 and PG&E’s A98.95-004 relating to restructuring implementation costs to which PU Code Section 376 applies.  On May 18, 1999 SCE, et.al., filed a joint motion for adoption of settlement in A.98.95-015 addressing SCE’s restructuring implementation cost.

B.	Qualifying Facilities (QF) Issues
For the most up-to-date information, check the Energy Division QF Web Site at: www.cpuc.ca.gov/divisions/energy/QF_issues/qf_main_page.htm/

III.	Divestiture Proceedings  
A.	SDG&E Sec. 851 “Divestiture” Application 97-12-039

SDG&E filed its divestiture application on December 19, 1997 to divest all of its fossil plants, its 20% interest in SONGS nuclear power plant as well as all of its long term power purchase contracts.  On February 18, 1999, the Commission approved (D. 99-02-073) the sale of the Encina power plant and 17 combustines by SDG&E to a consortium comprised of Dynergy Power Corporation and NRG Energy Inc.   Encina and the combustion turbines had a combined net book value as of December 31, 1997 of $94.8 million.  The sale price was $ 356 million. 

 D. 99-03-015 issued on March 4, 1999, approved the sale and donation of the South Bay Power plant to the San Diego Unified Port District.  Under the agreement, the Port District will pay $110 million for the plant to SDG&E and SDG&E will provide the Port District with a charitable donation of the main plant site land, the LNG Parcel, the Transmission parcel and the value of the South Bay plant facilities which exceeds $110 million.  The Port District has leased the plant to Duke Energy for operation.  
B.	PG&E, Sec, 851 "Divestiture" Application 98-01-008 
•	D. 99-04-026 issued on April 1, 1999 approved the sale of PG&E’s second batch of plants. Southern Energy purchased  the Potrero and the Delta plants for $801 million.  The net book value of these plants was $318.394 million.  Calpine purchased the Sonoma County Geysers and the Lake County Geysers power plants for a total of $ 212.8 million.  The combined net book value of these plants was $272.73 million. 
•	Earlier, PG&E (A. 96-11-020; D. 97-12-107)  had sold a total of 2645 MW of capacity (Morrow Bay -1002 MW,  Moss Landing -1478 MW and Oakland Power Plant-165 MW) to  Duke Power Services for $501 million.  The net book value of these plants was $390 million. 

C.	Southern California Edison, Power plant Divestiture A. 96-11-046
Edison offered all of its 12 oil/gas fired power plants for sale through an open auction process approved by the CPUC.  10 of these plants were sold in November of 1997.  The sale was approved by the CPUC on  December 16, 1997 (D. 97-12-106). The two remaining units - Long Beach and Ormond Beach power plants were sold earlier this year. The total capacity of all 12 of these plants was 9562 MW.  The first 10 plants sold for a total of $ 1.115 billion which was 2.65 times the net book value of those plants. Long Beach (530 MW) plant was sold to NRG Energy and Destec Energy for $29.9 million. Ormond Beach was purchased by Houston industries for $40 million.  The   net book value for this plant was $125 million. 

IV.	Market Valuation:  PG&E A.98-05-022, Edison A.98-05-014

This proceeding addresses, among other things, the following: 

•	Principles necessary to market value utilities' retained generation assets for purposes of calculating uneconomic costs
•	Alternatives to appraisal as a means for establishing fair market value for retained generation assets
•	Need for a date certain by which utilities must identify the assets they plan to retain, sell, transfer or dispose of, in order to meet the statutory requirement that market valuation be completed by 12/31/01

Proposed Decision on June 24th Agenda (CA-3) establishes that; 1) Edison will sell all of the land it retained at its recently divested power plants; 2) market values Edison's fossil-generation materials and supplies (M&S) and fossil-generation fuels (other than fuel oil) at their December 31, 1997 book value; and 3) defers the market valuation of Edison's fuel oil inventories and related land and facilities until either the ISO makes a determination if fuel oil capability is needed for system reliability or January 31, 2000, whichever occurs first. 

V.	Distributed Generation and Distribution Competition Rulemaking (R.98-12-015)

This rulemaking (OIR) was initiated on December 17, 1998 to consider whether the Commission should pursue further reforms in the structure and regulatory framework governing electricity distribution services. This effort is being undertaken as a collaborative effort among the Commission, the California Energy Commission (CEC) and the Electricity Oversight Board (EOB). The goal of this process is to identify the range of issues on distributed generation (DG) and distribution competition, and their interrelationships; and to explore whether a focused analysis of distributed generation or a more comprehensive consideration of distribution competition issues would be more beneficial.

Over 61 parties submitted opening comments on March 17, 1999, to respond to a series of questions and provide views on whether to undertake a more focused consideration of the utility distribution company’s (UDC) role in DG, or a broader look at the overall future role of the UDC. Reply comments from over 37 parties were filed on May 17, 1999.  

A joint agency full panel hearing (FPH) was held on June 1, 1999.  The FPH further explored the interrelationships among issues raised in the parties’ comments and elicited discussions on the procedural steps that can be undertaken to address various issues. Nine parties submitted additional written comments on the FPH questions on June 4, 1999.

A proposal is expected during the summer of 1999, which will reflect the coordinated efforts of all three agencies in cooperation with the Legislature, and will outline the specific steps and process which will be followed in addressing the issues and considering proposed changes in regulatory policies and rules.
VI.	Direct Access

A.	Introduction:  

The Commission’s basic approach to implementation of the direct access market for electricity has been to direct parties to form “working groups” for the purpose of developing any required new rules, tariffs, and business practices in a consensus-oriented atmosphere.  The Energy Division is responsible for organizing and overseeing the operation of these groups, and ensuring that they function in a fair and productive manner.  The working groups formed thus far are listed below, and the remainder of this section provides an update on the activities of each group:

1.	Tariffs and Service Agreements for Direct Access
2.	Meter and Data Communication Standards
3.	Retail Settlements and Information Flow
4.	Load Profiling

Activity Since Last Update

B.	Utility Fees for Direct Access:

On February 5^th, 1999 an Assigned Commissioner Ruling (ACR) was issued directing the utilities to file applications addressing the cost of providing discretionary and non-discretionary direct access services authorized by D.97-10-087.  The applications were filed June 17^th, 1999.

Ongoing Direct Access Implementation Activity

Direct Access Implementation Activity Reports were filed by PG&E, Edison, and SDG&E.  These reports are filed on the 15th of every month.  Check the following URL for electronic copies:  
http://www.cpuc.ca.gov/divisions/energy/Direct_Access/direct_main_page.htm

C.	Tariffs and Service Agreements for Direct Access (D.97-10-087)

Status of Proceeding

Most discussion related to the Direct Access tariffs and service agreements takes place in the monthly meetings of the “Rule 22 Tariff Review Group”, held at PG&E on the first Wednesday of every month.

Participants at the monthly meetings have decided to form a number of “sub-groups” to resolve specific issues between meetings.  These groups operate under the umbrella of a group called the “Operations Coordinating Committee” (OCC).  The sub-groups are listed below.
1.	DASR Consistency/ Account Maintenance
2.	Meter Specific Services
3.	Billing Business Rules
4.	Meter Usage Data
5.	Service Delivery Point Identifier (SDP)  Implementation Group
6.	MDMA and VEE Issues (MAVI)

The OCC meets at PG&E on the first Tuesday of the month, and provides a report to the Rule 22 Tariff Review Group when that group meets the next day.

Monthly meeting notes for both the Rule 22 and OCC groups, and other documentation, may be obtained at the website: http://162.15.5.2/wk-group/

D.	Meter and Data Communication Standards (D.97-12-048 and D.98-12-080)

Status of Proceeding

The Permanent Standards Working Group (PSWG) was established by the Meter and Data Communication Standards (D.97-12-048).  Parties met together as the “Permanent Standards Working Group” (PSWG) and submitted their report in July.  On December 17, 1998, the Commission issued D.98-12-080, which addressed the recommendations made in the PSWG report.

Meter Worker Certification:  Decision 99-03-063 denied an Application for Rehearing of D.98-12-080 filed by PG&E and SDG&E.  The Application related to the meter worker certification process adopted in D.98-12-080.  Instead, the Commission modified Decision 98-12-080 to order all parties to answer two questions regarding the Commission’s adopted certification program.  Parties made these filings on April 6^th.  A Commission decision or ruling on these filings is pending.

Meter Services:  On February 26^th, Commissioner Duque issued a Coordinating Commissioner Ruling (CCR) requesting comments on issues pertaining to the provision of competitive metering services in the restructured electric industry.  Opening Comments were filed April 13^th, and Reply Comments on April 27^th.  Commission action is pending.

Ongoing Activity

The Energy Division’s “Meter Service Provider Certification Unit” has been reviewing applications and provisionally certifying MSPs to install meters for ESPs in the UDC service territories.  A list of certified MSPs may be obtained from the Commission’s website: http://www.cpuc.ca.gov/electric_restructuring/msp_registration/msp_index.htm

D.98-12-080 directed the Energy Division to develop the appropriate forms, procedures, and criteria for accepting and reviewing Direct Access meter type self-certification forms provided by meter manufacturers, and for posting the complying meter types on the Commission’s web site.  The Energy Division made the forms available on March 19, 1999, and requested an extension on final implementation of the website, to August 1, 1999.  

E.	Retail Settlements and Information Flow (D.97-12-090 and D.98-11-044)

Status of Proceeding

The Retail Settlements and Information Flow (RSIF) decision established three working groups to address certain issues regarding the information flows that will be required for the new electric market structure to function.  Final reports have now been issued by all three groups:  the “Universal Node Identifier” Working Group, the “Distribution Loss Factor” Working Group, and the “Data Quality and Integrity Working Group”.  These reports may be found at the URLs below:

| Working Group | Web address for Report | Addressed by CPUC Decision?
1. | Universal Node Identifier | http://162.15.5.2/wk-group/dai/uni/ | D.98-11-044
2. | Distribution Loss Factor | http://162.15.5.2/wk-group/dai/dlf/ | Pending
3. | Data Quality and Integrity Working Group | http://162.15.5.2/wk-group/dai/dqi/ | Pending

F.	Load Profiling (D.97-10-086 and D.98-12-065)

Status of Proceeding

The Commission’s Load Profiling Decision ordered the Energy Division to hold a number of workshops and issue reports with recommended policy changes or refinements. 

Documents related to the load profiling workshops may be obtained at:
http://162.15.5.2/wk-group/dai/lp/

VII.	FERC‑Related Issues

A.	ISO Files Ancillary Services Redesign Plan

On March 1, 1999, the ISO filed Tariff Amendment No. 14, its Ancillary Services Redesign Plan.  The primary elements of Ancillary Services redesign are: (1) implementation of a “rational buyer” strategy to minimize the cost or procuring Ancillary Services; (2) elimination of incentives to ignore ISO dispatch orders for real time energy; (3) automation of dispatch orders for real time energy; (4) separate pricing for Regulation Up and Regulation Down; (5) development of a Participating Load Agreement to implement demand side bidding; and (6) implementation of InterSC trades of Ancillary Services.  Two other Ancillary Services redesign elements were filed as part of Amendment No.1 3 and accepted by FERC: (7) billing Ancillary Services by metered demand rather than scheduled demand; and (8) withholding payment for uninstructed deviations from Ancillary Services capacity.  In addition, Amendment 14 contains other tariff changes not related to Ancillary Services redesign, including: (9) new requirements for units providing regulation; (10) a provision for payments for Ancillary Services dispatched under certain RMR contracts; and (11) a clarification of the Market Surveillance Committee’s role.
B.	 Potential Settlement Reached in PG&E Transmission Owner Tariff Rate Case

On April 14, 1999, PG&E filed a proposed settlement in its transmission owner tariff rate case.  The CPUC filed comments in support of the settlement.

C.	New PG&E Transmission Owner Tariff Rate Case

On March 30, 1999, PG&E filed a new Transmission Owner Tariff Rate Case ER99-2326-000.  PG&E is requesting a $20 million increase in its Retail Revenue Requirement from the proposed settlement in the current ratecase ER98-2351-000.  The CPUC filed a Notice of Intervention and Protest on April 19, 1999.  

D.	FERC Considers Market-Based Rate Applications Filed by New Owners and Operators of Divested Utility Plants

Several owners of divested units have recently requested market-based rates for energy and capacity for units divested by utilities.  Applicants include: Duke Energy South Bay, Docket No. ER99-1175; Southern Energy California ER99-1841; Southern Energy Potrero ER99-1833; Southern Energy Delta ER99-1842.  In addition, the new owners of most of SDG&E’s divested units recently received market-based rate authority from FERC, Cabrillo Power I, et al, 86 FERC ¶ 61,180 (1999); Docket Nos. ER99-1115 and ER99-1116.
E.	 PX Files Tariff Amendments

The PX has filed several recent tariff amendments.  On January 8, 1999, the PX tendered for filing Amendment No. 8, to its Operating Agreement and Tariff (PX Tariff) and the accompanying PX Settlement and Billing Protocol (PSABP).  Amendment No. 8 proposes discrete changes to implement a December 11, 1998, filing by the California Independent System Operator (ISO) relating to the treatment of "TO Debits" for derated Hour-Ahead transmission capacity.  Docket No. ER99-1229-000

On January 13, 1999, the PX provided notice of a temporary, experimental deviation from the Hour-Ahead timeline contained in the PX’s FERC-authorized tariff in order to test the efficiency benefits of a "Day-Of market" timeline for a three-month period commencing January 17, 1999. Docket No. ER99-1262-000.

On February 19, 1999, the PX, tendered for filing Amendment No. 9 to the PX Tariff, which establishes a PX "Bookout" option under which offsetting transactions at common delivery points located outside of the California Independent System Operator (ISO) grid will be matched and reported as net schedules of imports into or exports from the ISO grid. Docket No. ER99-1883-000.

F.	RMR Settlement adopted at FERC in ER98-441-000, et al.

On May 28, 1999, FERC approved the proposed settlement originally filed on April 2, 1999 in the Reliability Must-Run (RMR) Cases at FERC.  The settlement achieves a uniform set of terms and conditions, which provide the ISO with RMR service from each of the previously designated facilities including energy and ancillary services. Revenue requirement settlements were also reached with each of the RMR owners.   In comparison to the as-filed rates for fixed costs, the settlement represents a rate reduction of approximately $120 million annually until December 31, 2001. Pursuant to the settlement, RMR owners will not recover 100 percent of their fixed cost revenue requirements in up-front payments from the ISO.  In the interim, nearly all owners have agreed to accept 50 percent of their full fixed cost revenue requirement pending final resolution through litigation.   The settlement also preserves the ISO’s ability to request changes to the terms and conditions after October 1, 1999, if the market experience during the coming summer peak season exhibits market distortions due to the settlement. 

G.	The ISO Files Amendment 16 to its Tariff
The ISO filed its proposed Tariff Amendment 16 to extend its current formula for its Grid Manaement Charge to the period from July 1, 1999 to December 31, 2000, subject to the outcome of an investigation in the same proceeding and subject to FERC’s determination on the ISO’s GMC filing to become effective on January 1, 2001. FERC Docket Nos. ER99-2730-000; EL99-67-000
H.	ISO submits its agreement with PG&E on operating procedures and curtailment priorities for Path 15.
On April 19, 1999 the ISO submitted its revision to the Transmission Control Agreement with PG&E which consisted of operating instructions and curtailment priorities for Path 15.  These revisions are being reviewed by FERC in this proceeding.  FERC Docket No. ER99-1770-000

I.	The PX files Tariff Amendment No. 11
On June 4, 1999, the PX filed its proposed Tariff Amendment No. 11 to modify its tariff and protocols to reflect changes made by the ISO in its Amendment No. 14 which was adopted by FERC.  Amendment 14 effected a substantial redesign of the ISO’s Ancillary Services Market.  FERC Docket No. ER99-3148-000

J.	The ISO files Tariff Amendment No. 17
On June17, 1999,  The ISO filed its proposed  Amendment No. 17 whhich includes proposed changes related to the pro forma Participating Load Agreement submitted with the amendment.  In addition, it includes; (1) changes to clarify the ISO’s Outage Corrdination Protocol; (2) change to expand the criteria establsied by the ISO Tariff; (3) changes to the ISO’s Grid Management Charge Formula to remove a separate telecommunications charge; (4) changes to the ISO Tariff and the Grid Management Charge to add recovery mechanisms for Western Systems Coordinating Council (WSCC) fines related to outages and other problems; (5) changes to the allocation of the Regulation energy Payment Adjustment (REPA) under the ISO Tariff; (6) changes to the ISO Payment Calndar; and (7) changes to the ISO’s Dispatch Protocol to conform a provision of the protocol to the ISOs actual practices.  FERC Docket No. ER99-3289-000.
K.	The ISO files its proposed Tariff Amendment No. 18
On June 18, 1999, the ISO filed a proposed Tariff Amendment No. 18 to address flaws in the current market rules for managing Intra-zonal congestion in real-time.  FERC Docket No. ER99-3301-000.

L.	The ISO files its proposed Tariff Amendment No. 19
On June 23, 1999, the ISO filed its proposed Tariff Amendment No. 19 which would modify the ISO’s New Generator Interconnection Policy which sets forth the obligations and responsibilities of Generating Units requesting interconnection to the ISO Controlled Grid and the procedures and requirements for processing such interconnection requests.  FERC Docket No. ER99-3339-000.
M.	Recent FERC Decisions

1.	FERC Denies Geysers Power Company LLC (Geysers) application for recertification as a qualifying facility

In its July 2, 1999, Order, FERC denied Geysers request for recertificiation of its 63 MW Sonoma County facilities as a qualifying facility (QF).  Geysers applied for QF status prior to purchase from PG&E It also sought confirmation that acquisition of the Sonoma facilities would not affect the QF status of another 72 MW small power production facility owned by its affiliate and located one mil of the Sonoma County facility.  FERC denied the application finding it did not meet statutory requirements.  In addition, it found that  the combination of the Sonoma Facility and the affiliated facility exceeded the 80 MW limit under PURPA.  88 FERC 61,015

2.	FERC Accepts SDG&E’s amended unbundled retail tramnsmission rates to allow pass through of Reliability Must Run (RMR) costs to retail customers.

FERC’s July 2, 1999 Order  accepts for filing, without suspension or hearing SDG&E’s amended retail transmission rates in its Transmission Owner tariff to allow passthrough to TO tariff customers costs of RMR services.  In so ordering, FERC denied the CPUC’s request to reallocate a fair portion of those costs to SDG&E’s wholesale customers.  The CPUC’s protest stated that it was unreasonable and discriminatory to assess all RMR costs to retail transmission customers.  FERC found that since SDG&E agreed in principle to such an allocation but did not yet have a wholesale transmission customer to which it would apply, there was nothing upon which to rule.  FERC noted that the allocation issue should be addressed by each of the utilities when they file to collect these costs from customers.  88 FERC 61,017.
  
3.	FERC Denies Duke Application for Rehearing Regarding Acquisition Adjustment

In an Order dated March 3, 1999, FERC denied Duke’s Request for Rehearing request for rehearing of FERC’s prior order (Duke Energy Moss Landing LLC, et al., 83 FERC ¶ 61,318 (1998)) which summarily dismissed Duke’s proposed acquisition adjustment and found the proposed rates to be rate changes rather than initial rates.  Duke had proposed to increase its cost-based rates by an amount which reflected the amount over book value that it paid PG&E for three plants.  FERC once again rejected the proposed acquisition adjustment.  Duke Energy Moss Landing LLC, et al., 86 FERC ¶ 61,227 (1999); Docket No. ER98-2668-003 et al.

4.	FERC Addresses Alturas Interconnection Issues

In an Order dated February 26, 1999, FERC broadly addressed issues related to the Alturas Interconnection.   In the order, FERC accepted for filing, nominally suspended, and set for hearing the Operating and Scheduling Agreement (Scheduling Agreement) among Bonneville Power Administration (Bonneville), PacifiCorp, and Sierra Pacific Power Company (Sierra Pacific) (collectively, the Alturas Participants) that was submitted in Docket No. ER99-945-000.  In addition, on its own motion, FERC set for investigation pursuant to section 206 of the Federal Power Act (FPA) the Alturas Intertie Project Interconnection and Operation and Maintenance Agreement (Interconnection Agreement) (Docket No. EL99-38-000), which it had previously accepted for filing in Docket No. ER99-28-000.   FERC consolidates Docket Nos. ER99-28-000, ER99-945- 000, and EL99-38-000, and directed that the hearing in the consolidated proceedings be held in abeyance pending settlement judge procedures.  FERC also addressed requests for rehearing and clarification filed in Docket No. ER99-28-001.  Sierra Pacific Power Company, 86 FERC ¶ 61,198 (1999); Docket Nos. ER99-28-000 et al.

5.	FERC Accepts PX Amendment No. 7

In an Order dated March 1, 1999, FERC accepted PX Amendment No. 7, which provides for the addition of a fourth member to the PX’s Market Monitoring Committee.  California Power Exchange Corp., 86 FERC ¶ 61,211 (1999); Docket No. ER99-1079-000.

6.	FERC Sets Duke Affiliate Abuse Issues for Hearing

In an Order dated February 25, 1999, FERC issued an order pertaining to potential affiliate abuse arising from sales by Duke Energy Moss Landing and Duke Energy Oakland—which are both RMR units—to Duke marketing affiliates.  FERC agreed that the marketing contracts raised the possibility of affiliate abuse and set for further proceedings the issue whether there is a need for special affiliate abuse rules given the interplay between Duke’s market-based sales margins and the rates under the RMR agreement.   FERC established trial-type evidentiary hearing procedures with respect to prior affiliate sales, and set a paper hearing to consider whether additional transaction or reporting rules are needed to prevent affiliate abuses.  Duke Energy Moss Landing, 86 FERC ¶ 61,187; Docket Nos. ER99-1127-000 et al.

7.	FERC Accepts PX Amendment 6 for Filing and Sets Hearing and Settlement Procedures

In an Order dated February 11, 1999, FERC accepted PX Amendment No. 6 for filing, and set hearing and settlement procedures.  Amendment No. 6 includes numerous amendments to the PX Tariff, its Settlement and Billing Protocol (PSABP), its PX Communications Protocol (PCP), and its Scheduling and Control Protocol (PSCP).  The PX stated that the proposed changes will better accommodate the flow- through and billing of charges from the California Independent System Operator Corporation (ISO), will allow the issuance of settlement statements via secure electronic interface with the PX's Internet website, and will implement additional computer software enhancements.  In addition, the PX proposed several additional changes to clarify and clean-up the PX Tariff and Protocols.   Various intervenors objected to numerous provisions as drafted, including the PX's proposed revisions to the settlements calendar; the allocation of certain ancillary services costs; and the proposal to charge PX Sellers PX Administrative Charges.  In addition, the intervenors stated that many of the proposed provisions require further clarification or revisions.  Thus FERC set the case for hearing and encouraged the parties to settle prior to hearing.  California Power Exchange Corp., 86 FERC ¶ 61,145 (1999); Docket No. ER99-933-000

8.	FERC Accepts ISO Amendment No. 13 as Modified

In an Order dated February 9, 1999, FERC accepted ISO Amendment No. 13 as modified.  On December 11, 1998, the ISO filed Tariff Amendment No. 13, containing numerous amendments to the ISO Tariff.  The most significant changes include:  (1) a proposal to withhold the Ancillary Service payments to generators that commit to provide Ancillary Services and then fail to honor that commitment by generating in other markets (referred to herein as "uninstructed deviations"; (2) a proposal to bill Ancillary Services on the basis of metered load rather than on scheduled deliveries; (3) a proposal to eliminate an inconsistency between the congestion charges assessed when a Scheduling Coordinator schedules transmission across a constrained path and the related billing credit that Scheduling Coordinator receives if its transaction is actually curtailed due to an unexpected outage; (4) a proposal to allow generators in the ISO Control Area to submit negative Supplemental Energy bids during Overgeneration conditions; and (5) a proposal to amend the Tariff to clarify that settlement of Replacement Reserve charges on a zonal or system-wide basis will be based on the ISO's procurement of Replacement Reserves in the Day-Ahead market.

FERC approved the filing in its entirety, except FERC approved allocation of replacement reserve costs retroactively back to start-up.  The ISO has been allocating Ancillary Services cost zonally when it procures Ancillary Services zonally, but had been concerned that language in the ISO tariff prohibited this practice.  This modification was proposed by PG&E and SMUD, and affirms that the Ancillary Services billing for the past year is acceptable and need not be recalculated.  It thus keeps the costs of Ancillary Services procured for the southern zone when the ISO was procuring zonally in the southern zone, and avoids reallocating the costs on a system-wide basis.

One of the items in Amendment 13 was to institute billing of Ancillary Services based on metered demand rather than scheduled demand.  This change was made to eliminate an incentive to underschedule load, which under the prior procedure enabled buyers to avoid paying for some Ancillary Services necessary to support their load.  The FERC order notes that the ISO expects the software changes necessary to implement this change to be operational in early March.  The ISO will post a notice of the implementation seven days in advance of the implementation date.  California Independent System Operator Corp., 85 FERC 61,122 (1998); Docket No. ER99-896-000.

9.	FERC Denies Oversight Board’s Rehearing Request Regarding Jurisdictional Issues

In an order dated February 4, 1999, FERC denied the Oversight Board's request for rehearing of FERC's November 24, 1998 order ("November Order").  The November order reaffirmed FERC's prior conclusion that a permanent role for the Oversight Board in the appointments, governance, or operations of the ISO and PX, or appellate review of ISO Board decisions, as that role has been reflected in the ISO Bylaws, conflicts with FERC’s jurisdiction under the Federal Power Act and undermines the independence of the ISO and PX Governing Boards.  In addition, FERC directed the ISO to seat Eric Woychik as a Governing Board member immediately.

In the February 4 order FERC stated that “although [it] is sensitive to the stake which the Oversight Board and state public officials have in the success of the ISO and the PX, especially given their unique origin in state legislation . . . Our reasons for denying rehearing stem from a need for this Commission to protect its clear jurisdiction consistent with the broad public interest, including protection of the citizens of California and surrounding states.”  FERC reiterated that under Order 888, states may continue to exercise historical regulatory authority over utility activities, but concluded once again that “the ISO and PX Bylaws are flawed because they provide a role for an agency of the State of  California that goes beyond traditional state areas of oversight, that infringes on our jurisdictional mandate under the FPA, and that undermines the independence of the ISO and PX Governing Boards with respect to transmission in interstate commerce or wholesale sales in interstate commerce.”  California Power Exchange Corp., 86 FERC ¶ 61,114 (1999);  Docket Nos. EC96-19-046 et al.

10.	FERC Permits Extension of BEEP Price Cap but Rejects Specific ISO Proposal

In an Order dated January 27, 1999, FERC rejected the specifics of the ISO’s proposal to extend the real time energy (“BEEP”) price cap, but granted the ISO discretion to impose a purchase price cap on real time energy purchases at the level the ISO deemed appropriate.  FERC also ordered the ISO to explain its future plans regarding the BEEP cap in its March 1 Ancillary Services redesign filing.   The ISO had proposed to raise the BEEP cap to $2,500/MW on October 1, 1999 regardless of market developments in the interim.  California Independent System Operator Corporation, 86 FERC ¶ 61,059 (1999); Docket N0. ER99-826-000.

In an Order dated January 27, 1999, FERC rejected the specifics of the ISO’s proposal to extend the real time energy (“BEEP”) price cap, but granted the ISO discretion to impose a purchase price cap on real time energy purchases at the level the ISO deemed appropriate.  FERC also ordered the ISO to explain its future plans regarding the BEEP cap in its March 1 Ancillary Services redesign filing.   The ISO had proposed to raise the BEEP cap to $2,500/MW on October 1, 1999 regardless of market developments in the interim.  California Independent System Operator Corporation, 86 FERC ¶ 61,059 (1999); Docket N0. ER99-826-000.

VIII.	  Public Purpose Programs
A.	Energy Efficiency and Demand Side Management 

There are two outstanding proceedings concerning Energy Efficiency and Demand Side Management programs.  A proposed decision in R.98-07-037 is anticipated in early July 1999.  This decision will address certain threshold policy issues the utilities will use to formulate their 9/1/99 program applications for Program Year 2000 and 2001.  On July 7, 1999 at 1:30, a Pre-Hearing Conference is set for the utilities’ Annual Earning Assessment Proceeding (AEAP), covering accomplishments for years 1994 and 1997, 1998, and to address policy and procedural issues for future program years 1999 through 2001, including Low Income Weatherization Programs. (A.99-05-002;  A.99-05-005;  A.99-05-007;  A.99-05-008)

Low-income Programs

On May 17, 1999, PG&E, on behalf of itself, Edison, SDG&E, and SoCal Gas, filed a joint proposal for standardizing the treatment of administrative costs for the CARE and LIEE programs.  Comments on the Joint Proposal are due by June 30, 1999.  Responses are due July 12, 1999.  On June 1, 1999, LIGB submitted its recommendations on standardized utility reporting guidelines for the CARE and LIEE programs.  Applications from the utilities to competitively bid out their program year 2000 LIEE programs are due July 1, 1999.  

Workshop on the Structure and Operating Procedures of LIGB and CBEE

Energy Division convened the workshop on April 12 and 13, 1999.  The draft Workshop Report was distributed for public comment on May 26, 1999.  Comments on the draft report were due June 11, 1999.  The final Workshop Report will be filed on June 30, 1999
For information on the Board’s current activities and background, see the CBEE website at http://www.cbee.org.
B.	Governing Board For Low-Income Programs (LIGB)

For information on the Board’s current activities and background, see the LIGB’s website at http://www.ligb.org

See the Commission’s Daily Calendar for CBEE and LIGB meeting dates and information at  http://www.cpuc.ca.gov/calendars/current/table_of_contents.htm
under Public Meetings and Workshops.
IX . 	CEQA Issues Related to Divestiture of Fossil Generation

These issues relate to the application of the California Environmental Quality Act (CEQA) to the fossil-fueled generation plants being divested by the utilities as part of electric restructuring.  Environmental assessments of the sale of the plants under CEQA were accomplished in 1997.  The Energy Division completed an Environmental Impact Report EIR on PG&E’s second divestiture application (A.98-01-008) in November 1998.  The Commission voted to adopt the Final EIR at its business meeting on November 19, 1998, and subsequently approved the sale of the plants to Southern Energy in April 1999.  

The Division released a Draft Mitigated Negative Declaration for public comment in October 1998 which analyzed SDG&E’s divestiture application (A.97-12-039).  The comment period closed on November 12, 1998.  A Final Mitigated Negative Declaration was released on November 23, 1998 and was adopted at the Commission business meeting on December 3, 1998. 

With the exception of Sierra Pacific Power Company, there are currently no pending applications before the Commission with respect to divestiture of fossil electric generation assets.  There is some potential for additional applications to be filed by investor-owned utilities in 1999 seeking approval for the further divestiture, transfer, or retention of electric generation assets.  These potential future applications may involve assets associated both with coal-fired plants and with hydroelectric facilities.  Assets associated with coal-fired generation would presumably follow a procedural path similar to the process applied to the previous fossil-fueled generation asset divestitures by the Commission  Regarding hydroelectric generation assets, it  is unclear at this time what the exact procedural path for any potential future hydroelectric divestiture, transfer, or retention would be due to a number of factors, including heightened legislative interest in the issue, the need to balance federal and state interests (among others), and the impact of the re-licensing process for hydroelectric assets at the Federal Energy Regulatory Commission.

Recent Activity 
See http://www.cpuc.ca.gov/environ.html, or http://www.pgedivest.com/ or http://www.scedivest.com/ or http://www.sdgedivest.com for more information.

X.	Reliability 

The project includes reviewing and analyzing outage data, utility inspections and maintenance (including tree trimming), work on interstate issues, and work on the distributed generation OIR.  An example of remaining work for AB 1890 includes pursuing an interstate compact for reliability.
 	
Inspections/Maintenance
•	Completed draft of generic oversight plan for GO 165 (Inspection Cycles for Electric Distribution Facilities); out for comment to CSD Utility Safety Branch.
•	Summarizing whether each major electric utility has satisfied the reporting requirements in GO 165.
•	In process of performing GO 165 audits in various PG&E divisions.
Outage Reports
•	Confirm that detailed outage data supports reports the utilities submitted.
•	Investigate why certain circuits seem to repeatedly perform poorly within the utilities’ service territory.
•	Evaluate whether utility internal planning for maintenance budgeting is based on, or considers, outage data.
Interstate Compact
•	Western Interconnection Coordination Forum is working on a proposal for western autonomy, for completion early in 1999.  This effort together with a western reliability bill being drafted by western regulators (CREPC) is aimed at influencing legislation proposed by the North American Electricity Reliability Council (NERC) to be applicable nationwide. 
Emergency Notification and Response 
•	Standards- ALJ Malcolm held a second PHC pursuant to D.98-07-097 in the prehearing conference on June 2 and scheduled hearings to begin October 4 following unsuccessful efforts by the active parties to negotiate a electric emergency response standards rulemaking on January 7..  The ALJ held a settlement.  
•	Notification--Staff is coordinating with OES, CEC, and utilities to develop and implement a statewide beeper system for use in energy emergencies.  Energy Division staff established an emergency notification phone number, voicemailbox, and pagers.  Staff has informed utilities about this system, and is in the process of coordinating with the Utility Safety Branch on how to combine it now with Safety’s existing notification system.
Undergrounding
•	Staff has worked with the Department of Health Services (DHS) on a request to develop cost and reliability information about EMF hazards and underground versus overhead power lines.  Staff involvement currently on hold.  However, Staff is working on drafting an OIR to initiate a statewide undergrounding program evaluation to assess whether the existing program, which was first authorized in the 1970’s, should be expanded, ended, or otherwise modified or improved.

XI.	Consumer Education/Protection

The utilities’ customer education program mandated by AB1890 and approved by the Commission in D.97-08-064 concluded on May 31, 1998. A Near-Term Education Plan  implemented by the Commission’s Consumer Services Division began on September 15, 1998. The Electric Education Call Center continues to serve residential and small business customers in 11 languages, with further language support available when necessary, providing customer service operators to answer questions and forward printed materials. Consumers may also access the consumer education website at www.knowledgeispower.org.

English/Consumers	800-253-0500
English/Businesses		800-789-0550
Spanish			800-365-0550
Chinese/Mandarin		800-940-3883
Chinese/Cantonese		800-957-8558
Vietnamese			800-474-5335	
Hmong			800-462-3749
Lao				800-442-2489	
Cambodian			800-465-6543
Japanese			800-210-7933
Tagalog			800-683-8448	
Korean			800-930-9559	
Thai				800-462-1244	
TDD				800-933-3119

Knowledge is Power website   The Knowledge is Power website may be accessed at: http://www.knowledgeispower.org/.  The website is another resource for consumers to learn more about how the coming changes to the electric industry will affect their energy choices. Help topics provides answers to consumers’ frequently asked questions and invites consumers to e-mail questions for an e-mail response.  Links to the CPUC and the CEC website are also provided.

A.	The Commission’s Outreach Plan
The Commission’s own Outreach Plan builds upon the Commission’s unique resources and expertise to assist and educate consumers about the changes taking place in the electric industry.  

Throughout 1999, the Commission is participating in Town Hall meetings and briefings in legislative districts statewide. These activities are designed to assist legislators in providing their constituencies with information about electric industry restructuring. 
B.	The Electric Education Trust
D.97-08-064 directed the EET to work with community-based organizations to focus its educational efforts on customer groups and communities where understanding of the changes to the electric industry is low.  The Commission authorized a total of $13 million to the EET.

C.	Consumer Protection 

Pursuant to Senate Bill 477, the Commission adopted rules to protect consumers from unfair or abusive marketing practices by electric service providers (ESP). Among other things, an ESP offering service to small commercial or residential customers must be registered by the Commission. Interim standards for ESP registration were established by D.98-03-072, and final standards were adopted by  D.99-05-034. There are currently 33 registered ESPs with active status.