Before the Public Utilities Commission of the State of California s38

ALJ/CMW/tcg DRAFT 1 5/14/01

Decision ______

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Application of Southern California Edison Company Application 00-11-038 (E 3338-E) for Authority to Institute a Rate (Filed November 16, 2000) Stabilization Plan with a Rate Increase and End of Rate Freeze Tariffs.

Emergency Application of Pacific Gas and Electric Application 00-11-056 Company to Adopt a Rate Stabilization Plan. (Filed November 22, 2000) (U 39 E)

Petition of THE UTILITY REFORM NETWORK for Application 00-10-028 Modification of Resolution E-3527. (Filed October 17, 2000)

(See Appendix A for List of Appearances.)

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TABLE OF CONTENTS

Title Page

INTERIM OPINION REGARDING RATE DESIGN…………………………….. 2 I. Summary...... 2 II. Background...... 3 III. Rate Design Principles and Goals...... 6 A. Equity...... 7 B. Conservation...... 9 IV. Revenue Requirement Increase...... 11 V. Revenue Allocation...... 16 A. Revenue Allocation Methodology...... 17 B. Revenue Requirement Shortfalls...... 22 1. Usage Under 130% of Baseline...... 22 2. CARE and Medical Baseline Exemption...... 26 3. Direct Access Customers...... 29 C. Amortization of Rate Increase as of March 27, 2001...... 29 VI. Preliminary Matters in Rate Design...... 32 A. Rate Freeze Constraints...... 32 B. Agricultural Definition...... 34 C. Bill Limiters...... 36 VII. Residential Rate Design...... 37 A. PG&E’s E-7 and E-8 Schedules...... 38 VIII. Nonresidential Rate Design...... 39 A. Tiering...... 39 B. Non-TOU Schedules...... 41 C. Time of Use...... 42 D. “Super Peak” Rate...... 43 E. County of Los Angeles’ Proposal to Cap Rates for Essential Customers...... 44 F. Agricultural...... 44 G. Master Meter Customers...... 45 H. Streetlight and Traffic Light Schedules...... 46 I. CIPA’s Credit for Interruptible Customers...... 47

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TABLE OF CONTENTS (Cont'd)

Title Page

IX. Other Issues...... 47 A. Tracking and Posting Data...... 47 B. Expedited Installation of RTP Metering Systems...... 49 C. 10% Rate Discount Associated with Rate Reduction Bonds...... 51 D. Bill Display...... 52 E. Bill Insert...... 53 F. Customer Education...... 54 G. Payments to CDWR ………………………………………………………..56 X. Next Steps...... 57 XI. Issuance of the Proposed Decision...... 58 INTERIM ORDER……………………………………………………………………. 75

Appendix A – List of Appearances Appendix B – Pacific Gas and Electric Proposed Rates Appendix C – Southern California Edison Proposed Rates Appendix D – Summary of Public Participation Hearings

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INTERIM OPINION REGARDING RATE DESIGN

I. Summary This decision adopts a rate design for the three-cent per kilowatt-hour (kWh) rate increase authorized for Southern California Edison Company (Edison) and Pacific Gas and Electric Company (PG&E) in Decision (D.) 01-03-082. That surcharge was adopted on March 27, 2001 to provide the utilities with additional revenues on a going-forward basis in order for those utilities to comply with their statutory duty to provide adequate electric service to their customers. Pursuant to Assembly Bill (AB) 1X, residential use below 130% of baseline is exempt from this increase. In addition, we exempt all customers who qualify for the California Alternative Rates for Energy (CARE) and Medical Baseline programs from paying the surcharge.1 In today’s decision, we address the steps for allocating the rate increase to customer classes. First, we determine the revenue requirement, which is the starting point for revenue allocation and rate design. We then allocate the revenue increase among the customer groups. Finally, we design rates within the customer groups to collect the revenue requirement. We allocate revenue and design rates in a manner that is consistent with our overall goals of conservation and equity. The rate design we adopt allows rates to be effective as of June 1, 2001. One important goal of this rate design is to provide both customers and this Commission the market information and technical tools (RTP metering systems) to actively respond to the wholesale market costs California Department of Water Resources (CDWR) could face this summer. We also set in place a framework that allows us to make midcourse corrections this summer.

1 We also increased the eligibility criteria for the electric customers participating in the CARE program from 150% to 175% of the federal poverty guideline. Additional CARE issues are being addressed in Application (A.) 00-11-009 et al.

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II. Background While we adopted a rate increase effective on the date D.01-03-082 was issued, we did not adopt a specific residential tiering approach in the absence of an overall rate- design proposal and sufficient record evidence to so act. Conceptually, we agreed that it is time to adopt a tiered approach for those customer classes that do not have rates structured on a time-of-use (TOU) basis. This approach sends the proper price and usage signals. Electric bills should be tiered to promote conservation, i.e., those who use more electricity pay higher prices for the excess use. Residential customers whose usage is below 130% of baseline are now statutorily exempt from rate increases that were not in effect as of January 5, 2001. The assigned Commissioner issued a concurrent Assigned Commissioner Ruling (ACR) setting forth an illustrative tiered rate design, inviting comment, and scheduling a prehearing conference (PHC) to establish dates for briefings and hearings.2 On April 2, 2001, the assigned Commissioner and assigned Administrative Law Judge (ALJ) convened a PHC. The assigned Commissioner stated that the Commission would pursue an intensive and expedited schedule in order to adopt and implement by June 1, 2001 a rate design to collect the three cents per kWh increase approved by the Commission in D.01-03-082. The following day, April 3, the Commission’s Energy Division held a workshop to finalize rate design templates and develop a master data request for the utilities. Parties also discussed a procedural schedule to present the Commission. On April 5, Edison and PG&E each filed a report on their billing system capabilities, and on April 6, all interested parties filed comments on the rate design goals the Commission should pursue, billing system structural issues, and procedural schedule. On April 11, 2001, the assigned Commissioner issued a ruling finding that, after review of the April 6 comments, the Commission needed a more extensive evidentiary record to design new rates. The April 11 ruling directed parties to serve their rate design

2 San Diego Gas & Electric Company (SDG&E) was included in the illustrative rate design included in the March 26 ACR and also participated in the PHC. Pursuant to the ACR issued on April 11, issues related to SDG&E rate increases and rate design are being addressed in A.00-10- 045 et al.

- 3 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT proposals as testimony on April 13, followed by hearings to commence on April 16. The Energy Division held a workshop on April 12 to provide parties more information regarding the rate design proposed by Governor Davis. The parties listed in the accompanying footnote served testimony on April 13, 2001.3 The Commission held hearings beginning on April 16 and concluding on April 26. Expert witnesses Peter A. Bradford, George J. Sterzinger, and Severin Bornstein, also appeared before the Commission at hearing on April 24 and 25 to offer testimony evaluating how effectively the proposed rate design proposals meet our rate design. The Commission also held Public Participation Hearings (PPHs) throughout Edison’s and PG&E’s service territories to allow customers to directly address the Commission. The PPHs were held in the following locations on the dates and times indicated:

Monday, May 7: 12 noon Santa Monica 7:00 p.m. Rosemead

Tuesday, May 8:2:00 p.m. Fresno 7:00 p.m. Visalia

Wednesday, May 9: 2:00 p.m. Fullerton 7:00 p.m. San Bernadino

Thursday, May 10: 12 noon Sacramento 7:00 p.m. Oakland

3 On April 13, 2001, the following parties submitted testimony: Aglet Consumer Alliance (Aglet), Agricultural Energy Consumers Association (AECA), Alliance for Retail Markets (ARM), California City-County Street Light Association (CAL-SLA), California Energy Commission (CEC), California Farm Bureau Federation (CFBF), California Independent Petroleum Association (CIPA), California Industrial Users (CIU), California Large Energy Consumers Association/California Manufacturers & Technology Association (CLECA/CMTA), California League of Food Processors (CLFP), County of Los Angeles (LA County), Energy Producers and Users Coalition (EPUC), Enron Energy Services, Inc. (Enron), The United States Department of the Navy and All Other Federal Executive Agencies (FEA), Kinder Morgan Energy Partners (KM), Leprino Foods Company (Leprino), Office of Ratepayer Advocates, California Public Utilities Commission (ORA), Pacific Gas and Electric Company (PG&E), Southern California Edison (SCE), The Utility Reform Network (TURN), Western Manufactured Housing Communities Association (WMA). These parties together with parties filing briefs and comments to the proposed and alternate decision are designated active parties to this proceeding.

Friday May 11: 3:00 p.m. San Jose

Edison and PG&E informed all customers of the locations and times by a special mailing. At the PPHs, the Commission heard statements from numerous concerned citizens. In Appendix D, we include a summary of the major issues addressed at the PPHs. This appendix was prepared by the ALJs presiding at these PPHs. After the conclusion of hearings on April 26, 2001, the parties filed briefs. The proposed decision was issued for comment on May 9, 2001. The parties filed and served comments on the proposed decision on May 10, 2001 and presented Final Oral Argument to the Commission on May 11, 2001.

III. Rate Design Principles and Goals In the ACR issued on March 26, the following principles were set forth as a framework in designing the illustrative rate proposal: - Base-rate differences among customer classes should be adjusted to reduce the disparity in prices paid for energy (on a per kilowatt hour basis) to ensure fairness in the prices paid for all energy purchased for California; - For all customers, electric bills should be tiered to the amount of electricity used in order to promote conservation – the more you use, the more you pay for that extra electricity above a certain threshold of use; and - For commercial customers with time-of-use (TOU) or other advanced meters, rates should be tiered to promote the greatest amount of conservation possible during summer peak hours.

After considering interested parties views4 on the rate design goals the Commission should pursue, President Lynch issued an ACR on April 11 that provided parties flexibility in constructing their own rate design proposals and established a hearing process to examine the proposals. As will appear from the discussion below, the original framework has been extensively modified in response to the submissions of parties.

4 At the April 2 PHC and in comments on April 6, 2001.

We provided each witness an opportunity to address the rate design goals of equity and conservation as set forth in the March 26 ACR. In addition, as explained above, we invited three expert witnesses to offer testimony that evaluated how effectively each rate design proposals met these goals.

A. Equity The goal of equity is essentially one of fairness, viewed in a broad context. Cost responsibility should be considered but only as one of the measurement criteria, and only when we have the reliable data to use in our analysis. In this proceeding, we will consider the unusual nature and large dollar amount of the surcharge increase, as well. Parties generally agree that we do not have the cost of service data necessary to consider cost-based equity5 here. There are two reasons for this. First, we do not have accurate information concerning the nature and extent of the costs relating to power purchases to date by CDWR on behalf of the utilities and their customers.6 These purchases are the primary basis of the three-cent surcharge authorized in D.01-03-082 and being allocated here. Second, the wholesale power market has been dysfunctional for approximately a year, such that costs are not the basis of the prices being charged. As PG&E states, “There is no basis for assuming that peak demands drive investment decisions in the current wholesale market.”7 We agree with TURN that we should consider fairness in the broadest sense, viewing it as a social or policy construct far more than it is a matter of economics.8 The view that fairness encompasses social and political questions is shared by Peter Bradford, 5 In defining equity as a rate design goal, several parties equated it solely with economic efficiency, stating customers should pay a rate that is in direct relationship to the marginal cost of serving them. Edison defines equity as charging various classes of customers based on the costs of providing service to them. Farm Bureau witness Illingworth noted her agreement with Edison’s definition, stating revenue allocation should be based on the future costs to serve the loads of each class. 19 RT 2404.

6 In a May 2, 2001 letter to President Lynch, CDWR provided a revenue requirement figure of $9.2 billion but not the details necessary for rate design.

7 PG&E brief at 15.

8 Florio, TURN, 22 RT 2962.

- 6 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT one of three outside experts invited by the Commission. Bradford cites to Professor James Bonbright’s rate design principles, the sixth of which is: fairness of the specific rates and the apportionment of total costs of service among the existing customers.9 Further, Bradford states he would consider ability to pay as a measurement criteria in looking at equity as a rate design goal. In recognizing the extraordinary burden we must allocate, we are convinced of the need to allocate this burden on an equal basis, in a manner that protects vulnerable customers and ensures no individual customers experience extreme hardship. The basis on which we allocate this increase should be understandable to all customers and appear reasonable to most customers. Following Bonbright’s first principle, our rate design should have the related practical attributes of simplicity, understandability, public acceptability, and feasibility of application. We are certainly conscious of the economic impact our decision will have on all sectors of California life – residential, retail and service businesses, agriculture, public services, and manufacturing and processing firms. We intend to design rates that provide price signals to which customers can respond, and thereby reduce the amount of the increase they will see on their bills. We will ensure that customers receive the public information and energy efficiency tools necessary to manage their energy usage in a manner that reduces their overall bill. We are also cognizant of individual customer impact as a principle to be considered in designing equitable rates. As CIU states, “a second prong of the equity test is that no customer should receive very harsh impacts relative to others.”10 ORA addresses this issue through its bill limiter proposal. CIPA believes that the equity goal will be met through (1) protection of low-income customers under the CARE customer exemption, (2) the Governor’s proposal that agricultural rates be capped, and (3) the Legislature’s exemption of residential usage up to 130% of baseline. 9 Bradford, Energy Division, 23 RT 3001-2. Bradford states that the eight rate design principles laid down by James Bonbright, the preeminent utility economist of the mid-20th century, have held up well over time and should be considered by the Commission here.

10 CIU brief at 4.

At this time, we do not intend to pursue the goal of reducing the disparity in prices paid for energy among customer classes. We do not have sufficient data to undertake this fundamental structural review now. We intend to revisit this goal in future proceedings.

B. Conservation Conserving electricity means reducing the amount of electric power needed to serve customers. This is a fundamental rate design goal of this proceeding. The record demonstrates that power purchased in the wholesale market for all hours by CDWR and the Independent System Operator (ISO) to serve the customers of PG&E and Edison is prohibitively expensive, as we discuss more fully below. The March 26 ACR also cited our goal of promoting the greatest amount of conservation possible during summer peak hours. The record reflects that summer peak is the time PG&E and Edison have the largest net short position and are therefore projecting a need for the most purchases from CDWR and the ISO to meet anticipated customer needs. We expected to have detailed information from CDWR, broken out by month and time of day, on the amount of power it had under contract, the prices it would be paying, and the amount of power it anticipated buying on the spot market. This information would allow us to determine the value of conserving energy in specific peak periods. Unfortunately, we have not yet received that information. Several parties testified that they expect CDWR will have to purchase significant power on the spot market this summer. Our record provides information showing futures contracts for this summer being quoted at $200-$800/MW. As Dr. Borenstein testified, all energy purchased this summer will be expensive and power purchased in peak periods will be even more expensive. The Governor’s 20/20 program is designed to reward customers who reduce their overall electric consumption by 20% this summer. This incentive, combined with customer education, energy efficiency programs, and the price signal that higher rates will send customers, are effective tools to promote conservation. A reduction in total

- 8 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT energy consumption will help protect Californians from blackouts and reduce the total financing needed by the state to purchase electricity. To maximize the value of conserving energy at times of peak demand, we can strengthen the price signal we send customers for periods when demand is highest. We have some ability to do this now by increasing rates at peak periods for those customers on time-of-use (TOU) schedules. Without having CDWR’s specific cost and supply information we are using our institutional judgement based on our expertise and experience to set the price premium for peak usage. This is also the basis for our determination that the traditional peak period of 6-8 hours accurately captures the specific peak time periods we need to address. Both of these findings may be modified when the CDWR provides us with more and better information. We will address the issue of reliability through promoting our conservation goals and using interruptible programs that we are addressing in Rulemaking (R.) 00-10- 002. We recognize that certain types of customers place an extremely high value on reliability and expect that these customers will be particularly receptive to peak reduction programs. The Legislature authorized $35 million in AB 1X 29 for the CEC to install RTP metering systems on all commercial customers of PG&E and Edison with connected loads of 200 kW and above. When CEC completes this installation and the CDWR provides specific projections, the Commission will be better able to specifically target and provide more effective price signals. Consistent with our principles of equity and conservation, we adopt a revenue allocation and rate design that achieve the following objectives: (1) reduce the need for procuring power and therefore reduce the amount of money California is paying wholesale generators for electric power; (2) allocate the unreasonable costs of this generation in a fair and understandable manner to all customers, recognizing the adverse economic impact our decision will have on all sectors of California life; (3) protect the most vulnerable customers; (4) ensure no individual customers experience extreme

- 9 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT hardship; and (5) provide customers the necessary tools to manage their energy usage and reduce their energy bills.

IV. Revenue Requirement Increase Determining the revenue requirement increase is the first step in allocating revenue and designing rates. Determining the exact price increase to be implemented for each nonexempt rate schedule offered by the Edison and PG&E first requires calculating the incremental revenue each utility must collect. In a typical rate case, we would determine the per kWh increase for each rate schedule as the ultimate product of allocating a known increase in costs or revenue requirement. Here, however, the unprecedented current circumstances described in our earlier decisions, D.01-01-018 and D.01-03-082, preclude us from knowing actual cost increases or revenue requirement. We do not know the costs of wholesale power being purchased to serve electric customers, in part because the CDWR has not yet established its revenue requirements. Nevertheless, we must expeditiously determine a revenue requirement and implement the surcharge.11 The surcharge revenues are subject to refund, as provided in D.01-03-082, should the anticipated costs not materialize. The incremental revenue requirement created by the surcharge authorized in D.01- 03-082 is a function of the sales to which the revenue requirement increase applies. The sales forecasts used by both Edison and PG&E were prepared solely by the respective utilities. Due to the extremely compressed schedule for this proceeding, these forecasts were not thoroughly reviewed by the other parties, as would be the normal course in a proceeding implementing a rate case of this magnitude. Due to the lack of review, Aglet requests that we limit the use of these forecasts to the rate increase at issue in this proceeding. We agree. In addition to the usual uncertainty present in any forecast, the time available has not allowed the utilities even to account for known or predictable future events.12 Consequently, we must acknowledge that these forecasts, while the best evidence available, should only be used for the limited purposes of this proceeding.

11 TURN states that the term “incremental revenue amount used for surcharge allocation” is more illustrative of the actual process involved here.

Having concluded above that we will use the sales forecasts provided by the utilities, we must determine whether the rate design is applicable to both the 1¢/kWh increased authorized in D.01-01-018 and the 3¢/kWh increase authorized in D.01-03-082. In addition, we must determine whether the sales to which the surcharge is applied for purposes of determining the incremental revenue requirement properly include sales exempt from paying the surcharge. In D.01-01-018, we authorized PG&E and Edison to impose for 90 days an Emergency Procurement Surcharge (EPS) of 1¢/kWh for all applicable sales of electricity. We directed PG&E and Edison to implement the increase as adopted; that is, add a 1¢/kWh surcharge to all applicable sales. In D.01-03-082, Ordering Paragraph 6, we made the EPS permanent and, in Ordering Paragraph 1, we authorized an additional surcharge of 3¢/kWh. For the latter surcharge, however, we declined to adopt a similar across-the-boards approach and instead undertook this process to consider rate design proposals tailored to encourage conservation by allocating more of the surcharge to higher volume users’ “tiered rates.” Some parties have advocated that we include the revenues to be collected from the EPS in this rate design effort. Specifically, those parties would calculate the incremental revenue requirement by multiplying forecasted sales by 4¢/kWh, rather than 3¢/kWh. Aglet stated that the rate design adopted in this phase should be applied to the full four-cent increase because considering only the three-cent increase would tend to obscure the “full impact of the heroic rate increases customers will bear.” CLECA/CMTA argued that while the Commission did not have the opportunity to evaluate revenue allocation and rate design for the one-cent surcharge when it was adopted, the Commission should use this phase for that purpose.

12 For example, neither PG&E nor SCE modified their respective sales forecasts to include any reduction in sales as a result of the customers’ conservation efforts, or for increased numbers of CARE-eligible customers due to the increased income standards adopted in D.01-01-018. While such modifications would typically be included in a thorough sales forecast, such modifications would greatly exceed the time available and the scope of this proceeding. We endorse the assigned ALJ’s determination excluding SCE’s attempt to include a proposal to re-instate the Electric Revenue Adjustment Mechanism (ERAM) from the record of this case.

The Commission adopted the one-cent surcharge on January 4, 2001, which applies to all sales except to customers eligible for the CARE program. On February 1, 2001, the California Legislature enacted and the Governor signed AB1X, which created another exemption. Among other things, AB1X prohibits increases to rates effective on January 5, 2001, applicable to residential usage below 130% of baseline usage. Because the Legislature adopted the 130% exemption after we adopted the 1¢ surcharge, the 130% exemption does not apply to the one-cent surcharge. Stated another way, usage below 130% is not exempt from the 1¢ surcharge. Such usage is, however, exempt from the 3¢ surcharge. Thus, the two surcharges are subject to different exemptions. While there may be some administrative ease in folding the two surcharges into one, the differing exemptions preclude this seeming simplification. Moreover, in D.01-03-082, we clearly identified the 3¢/kWh as subject to a new rate design approach. The EPS is already reflected in the rates that are used as the starting point for the rate design being considered in this proceeding. Therefore, the revenue allocation and rate design we discuss here applies to the three-cent increase. Edison calculates the incremental revenue to be recovered by multiplying 3¢/kWh times total forecasted system-wide sales for 2001 of 83.78 billion kWh. This results in an annual revenue increase of $2.513 billion. Similarly, PG&E applies 3¢/kWh increase to all forecasted sales for 2001. PG&E determined that its annual incremental revenue requirement is $2.46 billion. Because we agree that the revenue requirement increase should apply only to the 3¢/kWh adopted in D.01-03-082 and because we agree that we will use the utilities’ sales forecasts for our determinations in this decision only, these revenue requirement increases are an accurate estimate of what is required. Most parties apply the surcharge amount to all forecasted sales, including those sales that are exempt from paying it. In this way, the revenue requirement is determined based on an average of 3¢/kWh, recognizing that some kWh sales will carry no surcharge and others will carry a substantially higher surcharge. Aglet agrees that under usual circumstances exempting certain sales from cost recovery responsibilities would yield a shortfall that other customers would have to make

- 12 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT up. Aglet contends that in this unusual proceeding there is no legal or policy requirement to recover revenues that the utility would have achieved if there were no exempt sales. Because the surcharge is not based on quantified costs, there is no absolute need to collect that revenue. TURN agrees that all usage that is exempt from paying the surcharge should similarly be exempt from determining the revenue requirement. TURN contends that the first step in a proper methodology for allocating the rate increase to residential customers is to exclude the protected usage, as determined by the Commission and the Legislature. In adopting the three-cent surcharge in D.01-03-082, we did not specifically address this issue in the context of calculating a revenue requirement. We simply applied the rate increase “to all power costs incurred after the effective date of this decision.” There is no way of knowing actual procurement costs at this point in time. However, we have clearly stated that CDWR is to receive the full amount the utilities collect from all customers for each kWh of power provided by CDWR. It is reasonable to base the revenue requirement on applying the surcharge to forecast system-wide sales. Therefore, while we reiterate our commitment to ensuring that the exempt sales do not pay the surcharge, for purposes of determining the overall revenue requirement, all sales should be included.

V. Revenue Allocation Having determined the revenue requirement amount each utility is authorized to collect for itself and CDWR under the 3¢/kWh surcharge, the next step is to establish a rate structure that will enable Edison and PG&E to collect this revenue from its customers. The two principal issues concerning revenue allocation are: (1) the method used to apportion the revenue increase among customer classes; and (2) the treatment of the shortfall which results from exempting residential usage up to 130% of baseline consumption from any increase. It is equally important to realize what we are not doing. While the incremental revenue created by the surcharge is material when compared to the total revenue of the utilities, in this proceeding, the Commission is not setting aside all previous revenue

- 13 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT allocation and rate design. The allocation and rate design issues addressed in this decision are limited to allocation and design of the revenues to be collected pursuant to the surcharge. The underlying rate structure of the utilities will not change. Consequently, in this decision we affect only a fraction, albeit a significant fraction, of the charges imposed on customers. For residential customers, by Legislative order, we exempt approximately half of all sales. The scope of this proceeding does not include a complete revamping of all charges, just this surcharge.

A. Revenue Allocation Methodology Traditionally, revenue allocation has reflected cost causation. For the last several years, the Commission has allocated revenue based on the fact that the costs of providing service vary with the amount and duration of energy consumption, and with the facilities used to provide service. The Commission also found that it cost a utility more to deliver a kWh of energy during periods of peak demand than during non-peak periods. The fundamental facts underlying such ratemaking have changed. We have a dysfunctional wholesale energy market that has resulted in unconscionable, unlawful wholesale prices, which have increased by staggering proportions since the summer of 2000. These prices bear no relationship to any actual costs incurred in production. In fact, Califonria has experienced Stage 2 and 3 emergencies and rolling outages during off-peak times. While we acknowledge that the fundamental ratemaking facts have changed, we underscore the fact that the basic costs of production, other than fuel, have not changed. Simply put, the outrageously priced wholesale energy that causes us to take the extraordinary step of imposing this rate surcharge is being produced at the same plants upon which we based our traditional cost allocation procedures. In that respect, the fundamental facts of energy production have not changed. What has changed is that California is beset by wholesale sellers intent upon maximizing revenue without limit, and federal regulators refusing to impose any limitations. The price of wholesale energy is no longer a function of cost of production but rather a function of what price can be extracted from a market subject to manipulation.

Further compounding our dilemma is the fact that CDWR has not yet presented us with cost forecasts for the supply contracts CDWR is negotiating. Absent this data, we must look to other methodology to allocate the revenue to be collected from among the customer classes. Parties have proposed several methods for allocating revenue from the surcharge. We describe these briefly below. Historic Generation Cost Allocation – this methodology allocates the incremental revenue requirement based on the percent of generation revenues contributed by each customer group prior to adoption of the 3¢/kWh surcharge. Prior to making the allocation, the revenues must be adjusted to remove the effects of the Rate Reduction Bonds transaction and nonfirm service credits to interruptible customers. On Peak Energy Use/Top 100 hours – these two methods allocate costs based on the customer group’s share of either summer on peak energy use or 100 hours of highest system demand. 1999 Power Exchange (PX) Generation Charges – this method allocates revenue requirement by each customer group’s contribution to 1999 PX costs Equal cents per kWh – this method divides the revenue among the customer classes based on the total number of kWhs each class is forecast to consume during calendar year 2001. Our task here is to devise a rational basis for choosing one alternative revenue allocation methodology over another in a market setting that defies rationality. The record demonstrates that (1) the traditional rules of cost causation are no longer reflected in wholesale energy prices, and (2) there is no reason to believe that any of the suggested alternatives will be better at predicting cost causation in this market. All but one of the suggested alternatives ignore the simple fact that the price of wholesale energy is completely divorced from cost. The PX prices at least use recent historical data to attempt to predict what prices will be prevalent this year. These prices, however, ignore the CDWR purchases, for good reason, as those prices are not available, as well as the other factors specific to this summer such as drought conditions in the Northwest which will seriously curtail the availability of hydro generation.

Recent price experience, however, suggests that all kWhs will be valuable. In this volatile and dysfunctional market, we cannot predict which kWhs will be more valuable than others. For example, California has experienced blackouts in an off-peak season, at an off-peak time of day. Several actions could further enhance the value of off-peak energy. Customers currently on TOU schedules may engage in more aggressive load shifting, such that off-peak loads increase, decreasing the differential between off- and on-peak. In addition, it is possible that the drought in the Northwest may give us opportunities to run California fossil-fuel-fired generation at night and allow us to sell power to the Northwest. These, and many other possibilities and unanticipated events, all unpredictable in the volatile energy market, could impact the value of energy at particular times. We recognize that we cannot devise an optimum solution. In choosing among these proposals, at least two parties referred us to the works of preeminent ratemaking expert James C. Bonbright. Mr. Bonbright’s teaching provide us comfort but, unfortunately, little concrete guidance:

[R]ate structure problems are far more complex than problems of a fair return even though the latter are by no means elementary; and they are even less amenable to solution by reference to definite principles or rules or rate making. In part, the complexity is due to the mass of technical detail, including the technology of metering, involved in the design and administration of workable rate schedules for different types of utility enterprises. In part it is due to the inability of the rate maker to predict the effect of changes in rates on demand for the services and hence on costs of supply – due, in short, to ignorance of demand functions and cost functions. But in part – and this is the most serious theoretical difficulty – it is due to the necessity, faced alike by public utility managements and by regulating agencies, of taking into account numerous conflicting standards for fairness and functional efficiency in the choice of rate structure. . . . [B]y way of illustration, we may note the conflict between the desirable attribute of simplicity and the otherwise desirable attribute of close conformity to the principle of service at cost. Here, as with other clashes among various desiderata of rate-making policy, the wise choice must be that of a wise compromise; and in reaching this compromise, the practical

rate expert would look in vain to any general theory of public utility rates, at least in its present stage of development, for a scientific method of reaching the optimum solution. Bonbright, James C., Principles of Public Utility Rates, p. 288-9 (1961).

Allocating the revenue requirement to customer classes based on the proportion of 2001 forecast total kWh sales to the class drew support from PG&E, ORA, TURN, and Aglet.13 These parties chose the methodology for equity considerations and also because the methodology best reflects the surcharge’s primary purpose: to provide funds for CDWR to purchase electricity in the wholesale market at a time when those costs are expected to be higher in all hours of the year as compared to the costs incurred during the same period in previous years.14 The surcharge is in place to provide the additional funds necessary to provide for customers’ energy consumption and we have previously determined that generation costs associated specifically with energy consumption are properly recovered using an equal cents per kilowatt hour methodology.15 There is little cost data available on the wholesale purchase costs that will be necessary for this summer and the rest of 2001. The dysfunctional wholesale market has created a unique crisis of unknown duration for California electric customers. No class of customers believes that it is responsible for these price increases, and thus no class of customers wants to pay for increased wholesale electric costs. ORA equates the rate surcharge to a tax to pay for a disaster or emergency – in this case, the electricity crisis. Applying the surcharge as broadly as possible is the fairest way to apportion the noncost-based price premium being extracted by wholesale

13 These parties arrived at this conclusion by eliminating other possibilities. For example, the data upon which the generation cost allocation methodology is based are stale and obviously inapplicable to current costs. The peak hours proposals similarly suffer from a lack of confidence that the past peak/non peak distinctions are valid forecasts for the future. While closest in time to current markets, the PX price proposal fails to account for known changes in the market.

14 Marcus, TURN, 24 RT 3293; Brubaker, FEA, 19 RT 2504; McCann, CIPA/WMA, 22 RT 2873.

15 D.00-06-034, issued June 8, 2000, slip op. at 66.

generators and should help our choice of apportionment gain the widest public acceptance. An equal cents per kilowatt-hour is the most equitable revenue allocation methodology as well as the methodology most appropriate to apportioning energy purchase costs to all future energy consumption. This allocation methodology is also simple, understandable, and consistent with our approach for the one cent surcharge adopted in D.01-01-018. Therefore, we find that the revenue requirement associated with the 3¢/kWh surcharge adopted in D.01-03-082 should be allocated among the customer classes16 based on the proportional number of kWhs each class is forecast to consume during calendar year 2001.

B. Revenue Requirement Shortfalls Having completed the allocation of revenue across the customer classes, we must now address the revenue shortfalls resulting from exemptions to the surcharge. Because the exempt sales will not be contributing the revenue requirement assigned to them via the allocation process, this revenue requirement must be re-allocated to other sales.

1. Usage Under 130% of Baseline In AB X, the Legislature added section 80110 to the Water Code, effective February 1, 2001:

In no case shall the commission increase the electricity charges in effect on the date that the act that adds this section becomes effective for residential customers for existing baseline quantities or usage by those customers of up to 130 percent of existing baseline quantities, until such time as the department has recovered the costs of power it has procured for the electrical corporation’s retail end use customers as provided in this division.

16 SCE’s customer classes are: Residential, Small and Medium Commercial, Large Power, Agriculture and Plumbing, and Street and Area Lighting. PG&E’s customer groups are: Residential, Small Light and Power, Medium Light and Power, E-19 and E-20, Streetlights, Standby, and Agriculture.

This section exempts 130% of “baseline” usage. Baseline usage is defined in § 739(a). That section requires the Commission to establish a quantity of gas and electricity that is necessary to supply a “significant portion of the reasonable energy needs of the average residential customer.” This “baseline quantity” is defined to be between 50 and 60% of average residential consumption, with allowances for seasonal and climatic variations, in § 739(d)(1). The Commission is further directed to require the utilities to file residential rate schedules that provide for the baseline quantity to be the first or lowest block in a increasing block rate structure. In addition, the Commission is directed to “establish an appropriate gradual difference between the rates for the respective blocks of usage.” § 739(c)(1). In 1976, the Commission determined the initial baseline quantities in D.86087, 80 CPUC 182. Subsequent revisions and updates to the baseline quantities and applicable rates have been done in the utilities’ general rate cases. The currently applicable baseline quantities and rates are set out in PG&E’s residential tariff schedules and in Section H.3. of the Edison Preliminary Statement. Taken together, new Water Code § 80110 and Pub. Util. Code § 739, exempt a significant share of each utility’s residential sales. This exemption protects residential consumers under baseline and protects the class as a whole by providing a measure of protection to at least some portion of their service. This statutory exemption raises the issue of how this shortfall should be recovered and from other customers. The shortfall is significant: In Edison’s territory, 64% of residential sales are exempt, and 62% are exempt in PG&E’s territory. As ORA states, there are three proposals for allocating this shortfall. The first option is to recover the shortfall within residential rates. The second is to reallocate to all eligible sales, and the third is to allocate the increase to all nonresidential sales. TURN proposes that the revenue requirement be re-allocated to all non- exempt sales. TURN reasons that (1) the plain language of § 80110 is silent on the issue, and (2) the Legislature knows how to and has prohibited cost shifting when it so desires. Because cost shifting is not prohibited, the Commission should re-allocate the revenue

- 19 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT requirement to all non-exempt sales. TURN also offered Exhibit 98 that is an informal analysis from a rate design expert to Senator Bowen, Chair of the Energy, Utilities, and Communications Committee. Exhibit 98 evaluates setting the exemption at 125% versus 150% of baseline, and compares the resulting subsidies of residential customers by nonresidential customers. Inherent in this analysis is the assumption that the shortfall would be allocated to nonresidential customers. Based on Exhibit 98, TURN concludes that the Legislature was well aware of the cost-shifting implications of this exemption. TURN also notes that such a re-allocation would be consistent with treatment of the CARE subsidy. Aglet also recommends allocation of the shortfall to all customer classes. Aglet argues that: (1) allocation only to residential usage would yield unreasonably high rates in higher tiers, (2) such severe rate changes would be contrary to Bonbright’s principles regard stable rates, (3) revenue shortfalls caused by legislative mandates are more like taxes than costs caused by any particular customer class, and (4) allocation to all customer classes would be consistent with allocation of CARE discount costs. All other parties17 addressing this issue propose to re-allocate the revenue requirement to all residential sales that are not included within the exemption. PG&E states that the Commission’s usual practice is, where cost re-allocation is required, to keep such costs with the customer class. PG&E points out that revenue shortfall created by baseline rates is re-allocated solely within the residential class. Edison adds that the Governor in his rate design proposal uses this re-allocation methodology. Under the re-allocation method supported by most of the parties, the residential customer group would be allocated significantly more of the revenue requirement, and see a significantly greater rate increase. Exhibit 111 shows the following comparison of the rate increase that would result from the competing re-allocation methods for two groups of Edison customers: Non-exempt All Non- Residential only Exempt

17 ORA took no position on this issue.

Residential 22% 9% Large Power 36% 43% The residential customers would also see significantly greater changes in prices for higher tier usage. For example, PG&E’s E-1 General Residential rate schedule would show the following increases under the two alternatives: Allocated to Allocated to Non-ExemptAll Non- Residential only Exempt

Tier 1 (0 – 100%)18 11.419 12.520 Tier 2 (100 – 130%) 13.0 14.32 Tier 3 (130 – 200%) 19.5 16.66 Tier 4 (Over 200%) 28.9 20.30 One of the criteria for desirable rate structure advocated by Professor Bonbright is that the rates are stable, with a minimum of “unexpected changes seriously adverse to existing customers.”21 The price increase that a customer would see should the customer’s usage move from Tier 2 to Tier 3 spikes dramatically under the “only non- exempt residential” methodology, but is more gradual (although still high) under the other methodology. Guided once again by Professor Bonbright’s directive to make wise choices, we find that re-allocating the revenue requirement associated with sales that are exempt from paying the surcharge solely to the narrow range of remaining residential sales is too severe. The cost of this legislatively-mandated exemption should be broadly assessed across all customer groups. We find that the revenue requirement shortfall caused by applying the 3¢/kWh surcharge approved in D.01-03-082 to sales to residential customers

18 Percentage of baseline usage.

19 Exhibit 116 PG&E Rate Design Testimony.

20 Exhibit 111 ORA Testimony. ORA’s rates are slightly different from PG&E’s apparently because PG&E accounted for rate reduction bonds and the 1¢ surcharge and ORA did not.

21 Bonbright, supra, p. 291.

below 130% of baseline shall be re-allocated to all sales other than residential sales below 130% of baseline. Therefore, we adopt the TURN and Aglet method of capturing the revenue shortfall. This method spreads the shortfall to all eligible consumption, including residential sales greater than 130% of baseline. We treat the shortfall in the same way we allocate CARE shortfalls, as a subsidy. The amount is spread to all eligible customer classes on an equal cents per kWh basis.

2. CARE and Medical Baseline Exemption We also find that the revenue requirement shortfall caused by exempting CARE customers from the 3¢/kWh surcharge approved in D.01-03-082 shall be re- allocated to all sales other than sales subject to the CARE program and residential customers with usage of or less than 130% of baseline. In D.89-09-044, the Commission implemented modifications to its Low- Income Rate Assistance (LIRA) program that provided a 15% discount to low-income customers, and created a LIRA surcharge to recover the amounts necessary to fund the program. Re Investigation on the Commission’s own Motion to Comply with Senate Bill 987 and Realign Residential Rates, Including Baseline Rates, of California Energy Utilities, (1989) 32 CPUC 2d 406, 419. The decision exempted several customer groups from paying the LIRA surcharge primarily due to contractual obligations of the utility, the potential for double-paying, or statutory requirements. In addition, the decision exempted streetlighting:

Street lighting shall also be exempt because such service is ultimately paid for by taxpayers, who will already contribute to the LIRA program as ratepayers. 32 CPUC2d at 416.

The LIRA program was subsequently renamed CARE in § 739.1. Cal- SLA relies on this decision, and others, for the proposition that “street light customers are not to be burdened with revenue allocated from the CARE discount.” PG&E disagrees, contending that the previous Commission decision applied to allocating the cost of the discount for low-income service. At issue in this proceeding, in contrast, is allocating the revenue requirement for an overall surcharge.

We agree with PG&E. Whatever may have been the validity of the 1989 justification to exclude street lighting from its fair share of this program, that justification is not applicable here. This allocation is not a revenue requirement necessary to fund the low-income discount program, from which street lighting continues to be exempt, but rather a general surcharge covering procurement of electricity. It should be allocated as broadly as possible to achieve our goal of equity. The purpose of the medical baseline allowance is to protect those customers with medical conditions that require the use of electricity to protect their health and well being. Current Commission-approved tariffs provide qualifying customers with a medical baseline quantity of approximately 16.5 kWh per day above the standard baseline allowance. Medical baseline allowances are required by § 739(b)(1).22 We also adopt an exemption of the rate increase for this customer class. The utilities’ data show that PG&E has approximately 40,044 customers on a medical baseline allowance and Edison has 12,222, for a total of 52,266. Approximately 35% of these customers are in the CARE program and would be exempt from these charges. Because of the extraordinary size of the rate increase, it is reasonable to mitigate the impact to the remaining customers on medical baseline who are among the most vulnerable customer classes. This exemption will be allocated using the same methodology as the CARE exemption. The utilities should reflect the exemption of medical baseline customers in the tariffs they file pursuant to this order. While no party objects to the medical baseline exemption, it was not discussed at hearing. Therefore, Edison states in its comments and at FOA that it has not included this exemption in its billing system modifications for June 1, 2001. Edison states it can make the billing system changes by August 31, 2001. PG&E states it will be able to implement this exemption into its billing system by June 1 and has already begun expedited work on this relatively limited systems change. Edison should notify all its medical baseline customers by certified letter prior to June 1, 2001 that they are eligible

22 Medical baseline allowances are addressed in PG&E’s Rule 19 and Edison’s Preliminary Statement Part H.

for this exemption and will be given a refund of the surcharges on their September 2001 bills.

3. Direct Access Customers In this decision, we must consider whether direct access customers should be required to pay any of the rate increase. Direct access customers should be exempt from the surcharge as direct access customers are purchasing their own power and are not relying on the utilities. Furthermore, direct access customers do not contribute to the net short that the CDWR is procuring on behalf of the utilities. The surcharge adopted in D.01-03-082 is intended to provide payment for power purchases and delivery to utility customers. Neither the utilities nor the CDWR procure power for direct access customers. Instead, by definition, direct access customers receive their energy from their Energy Service Provider (ESP). It would be inequitable for direct access customers to pay for both their own cost of procurement and the procurement costs of bundled customers. We do not refer to direct access customers in D.01-03-082 and this surcharge should not apply to direct access customers.

C. Amortization of Rate Increase as of March 27, 2001 We issued D.01-03-082 on March 27, 2001, and stated that the rate increase became effective as of that date. That decision also obligates Edison and PG&E to collect and remit to CDWR a generation-related rate including the 3 cent/kWh surcharge. Today’s decision determines the specific rate allocation and design of the surcharge for collection beginning June 1 for PG&E, and June 3 for Edison. During the intervening time, March 27 to the date Edison and PG&E begin applying the surcharge, the rate increase was effective, but not yet collected. PG&E and Edison therefore seek to collect the revenue shortfall from this time period over some period in the future. Aglet and TURN contend that the rule against retroactive ratemaking prohibits collection of these amounts, because no balancing or memorandum account has yet been

- 24 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT established to authorize such collection.23 This point is irrelevant. Section 728 requires the Commission to determine the rate “to be thereafter observed and in force.” The right to recover the revenues equivalent to the three-cent surcharge was established by D.01- 03-082 and affected only electricity delivered from the effective date of that decision forward. Similarly, the precise charges to be collected from customers to recover those revenues will be effective prospectively after the date of today’s decision. We see nothing retroactive here that could possibly violate § 728. TURN’s argument assumes, without citation, that creation of a balancing or memorandum account is the only method whereby the Commission can allow a utility to collect sums at a later date. This is simply not so. At most, what § 728 requires is that there be a prospective authorization to recover the revenues.24 While the Commission often accomplishes this result through balancing or memorandum accounts, that method is not required by § 728.25 Accordingly, we see no possible violation of any prohibition against retroactive ratemaking here. In its comments on the PD and AD, TURN continues its argument that what we are doing here is inconsistent with past Commission precedent. However, in D.99-11-

23 Balancing accounts have been established in D.01-03-082, but for the purpose of recording revenues received from the authorized rate increases.

24 We do not address here the question of whether the three-cent surcharge would be subject to the legal restrictions on retroactive ratemaking. (See Southern California Edison Co. v. Public Utilities Commission (1978) 20 Cal.3d 813, where the court discussed the scope of the prohibition.) Rather, we point out that even if the restrictions of § 728 do apply to this situation, there would not be any violation.

25 In this regard, we stress the importance of the fact that D.01-03-082 made the three-cent surcharge effective immediately. Sometimes the Commission may authorize the creation of a balancing or memorandum account in a decision, but make it clear in the authorizing decision that this account will not become effective until the filing or approval of the required tariff. In that situation, the Commission’s practice is to allow recovery only of those costs incurred after the effective date of the balancing or memorandum account. Here, in contrast, the Commission neither required the creation of a balancing or memorandum account nor the filing of tariffs in order to make the three-cent surcharge effective. As noted above, the three-cent surcharge was effective immediately, although the precise method by which the rates would be spread among the various customer classes had not yet been established.

057, 26 we stated that following the usual practices in creating memorandum accounts is not the sine qua non for avoiding retroactive ratemaking problems. Thus, for example, while it is often our practice to make memorandum accounts effective from and after filing or approval of a specific tariff sheet, D.99-11-057 emphasized that memorandum accounts could become effective before such date without causing retroactive ratemaking problems so long as the effective date of the memorandum account was on or after the date of a sufficient Commission authorization of the related rate increase. As pointed out above, and as Aglet’s comments note and then apparently refuse to recognize, D.01-03- 082 expressly stated, at page 3: “We adopt this increase effective today.” We find neither TURN’s nor Aglet’s comments persuasive. Therefore, we determine that the revenue associated with applying the 3¢/kWh surcharge to all non-exempt energy sales from March 27, 2001, to the day utilities begin collecting the surcharge should be added to each utility’s revenue requirement. We will authorize the utilities to amortize the unrecovered amount over 12 months, as PG&E proposes. TURN agrees that should the Commission reject its retroactive ratemaking argument, discussed above, then a 12-month amortization period is reasonable. From a standpoint of equity, a three-month summer amortization would undoubtedly cause undue stress on summer rates, which will already be very high. The three-month surcharge also places a severe hardship upon summer intensive industries, especially the agricultural industry, which did not contribute significantly to the shortfall.

VI. Preliminary Matters in Rate Design In developing these methodologies for the rate increase, we have focused on promoting equity and encouraging conservation. We have designed rates for Edison and PG&E customers that will meet CDWR’s revenue requirements, while promoting conservation to keep the cost of CDWR-procured power down. Despite a number of attempts on the part of the Commission, we were unable to craft this decision with the benefit of detailed cost estimates from CDWR, and therefore, in many instances we have

26 This decision was reversed on other grounds in Southern California Edison Co. v. Public Utilities Commission (2000) 85 Cal.App.4th 1086.

- 26 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT resorted to utilizing historical information to set peak periods. This decision will advance the equity and conservation goals for this proceeding, but lacks the fine-tuning that could have been possible if CDWR had supported our ratemaking needs.

A. Rate Freeze Constraints As a preliminary matter, we address the question of whether the continuing rate freeze precludes us from requiring certain customers who are not currently on time-of-use schedules to shift to such schedules. Many parties assume, without much explanation, that such a mandatory shift is barred by the rate freeze. A few specifically cite to the provisions of Pub. Util. Code §§ 367 and 368. As we explain below, we conclude that the continuation of the rate freeze does not preclude us from responding to the current energy emergency by requiring certain customers to shift to time-of-use meters, thereby shifting use away from periods of peak demand. This approach achieves our goals of conservation and equity. Such a shift away from periods of peak demand can be expected to both help avoid blackouts and decrease the total cost of procuring electricity. Section 367 deals with the utilities’ recovery of certain uneconomic or transition costs. The rate freeze is mentioned in two portions of § 367. Section 367(a) provides for recovery of such uneconomic/transition costs “consistent with not increasing rates for any rate schedule, contract, or tariff option above the levels in effect on June 10, 1996.” Similarly, § 367(e)(2) states that “[i]ndividual customers shall not experience rate increases as a result of the allocation of transition costs.” Section 368 deals with the utilities’ cost recovery plans for the recovery of uneconomic costs. More specifically, § 368 sets certain conditions on the Commission’s approval of transition cost recovery plans. In that regard, § 368(a) provides that the rate levels required in the cost recovery plan “for each customer class, rate schedule, contract, or tariff option shall remain in effect until the earlier of March 31, 2002, or the date on which the commission-authorized costs for utility generation-related assets and obligations have been fully recovered.”

Thus, under § 368, the rate freeze is a required condition of the plan for recovery of transition costs. Similarly, under § 367, the recovery of transition costs is not allowed to result in a rate increase. In short, these provisions are designed to control the recovery of transition costs. We do not view them as a limitation on our authority to respond to the current energy crisis (which was not foreseen at the time those sections were enacted) by requiring certain customers to use TOU meters, thereby shifting load away from periods of peak demand. (Similarly, in D.01-01-018, we concluded that the rate freeze was not a limitation on our authority to grant emergency, interim rate relief.) We will also require the utilities to establish certain tracking accounts to further ensure that our requirement that certain customers shift to TOU schedules does not violate the principle that only the frozen rates are available for transition cost recovery. More specifically, each utility shall track the actual billings of all customers who are required to shift to time-of-use schedules by today’s order. Each utility shall also track what these customers would have been billed if they had remained on their former schedules. If comparison of these two figures shows that there has been any net increase in billings as a result of requiring these customers to shift to time-of-use schedules, we will require that this net increase in revenues be devoted only to those purposes to which we have previously dedicated the once-cent and three-cent surcharges. In this way, if there is a net increase in revenues as a result of shifting these customers to time-of-use schedules, it will not be available for transition cost recovery. In short, nothing in this decision alters Ordering Paragraph 9 of D.01-03-082, in which we concluded that the rate freeze has not ended for either PG&E or Edison under AB 1890. Rather, we conclude that, even while the rate freeze continues under AB 1890, we may require customers to shift to time-of-use schedules to encourage those customers to shift-load off-peak and thereby ameliorate the current energy emergency, so long as any resulting increase in revenues cannot be used to recover transition costs.

B. Agricultural Definition Several parties, including the California League of Food Processors, the Farm Bureau, and the Wine Institute, urge us to adopt the recommendation of § 740.11 (added

- 28 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT by SB 5X) and change the definition of customers eligible to be served under agricultural tariffs to include agricultural commodity processing customers. Section 740.11 provides, in relevant part:

In recognition of the fact that agricultural and water supplier customers necessarily have high electricity usage during peak summer demand periods, the Legislature strongly urges the commission to consider providing the option to all agricultural commodity processing customers to be included in the definition of customers eligible to be served under agricultural tariffs, consistent with its other constitutional and statutory objectives, and to the extent it does not result in cost shifting to other customer classes.

We acknowledge the uniqueness of California’s agriculture industry, and their heavy dependence upon summer on-peak usage. However, we will not expand the definition of the agricultural class at this time. The potential of migration for industrial customers tied to the agricultural industry deserves further exploration. We decline to make this change at this time, for the reason that our record is insufficient to conclude that such a change will not result in cost shifting. We do not believe the Wine Institute’s recommendation -- that we adopt this expanded category, along with a requirement that the utilities track the revenue changes resulting from customers moving to agricultural tariffs, in order to keep revenue shortfalls within each customer class and to prevent cost shifting to other classes - would sufficiently satisfy the terms of the statute. Moreover, making such a change would also require that we craft a definition of “agricultural commodity food processors.” While we have received some suggestions on how to do this, we would need to explore further on the record the ramifications of different alternatives. PG&E and Edison maintain that it is not feasible to adopt the proposed customer migration before summer’s end. Customers who qualify for the rate migration need to be identified and the difference in usage from other industrial customers understood. We will further examine this proposal to determine its feasibility and

- 29 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT explicitly specify the type of customer eligible to migrate, and examine the impact of cost shifting upon other customer groups before adopting this measure.

C. Bill Limiters ORA proposes using bill limiters to protect energy consumers from large increases. Some parties have suggested special schedules to protect their unique industries. In the short term, we prefer bill limiters to address the concerns of a particular group while the effects of migration are considered. Customers who currently reside within the industrial rate schedules should be protected by bill limiters, which can help limit the hardship created by equal cents per kWh surcharge. We believe that bill limiters are preferable to the creation of new schedules to reflect the diverse needs of customers. It is not feasible for Edison and PG&E to change the rate schedules to reflect the special constraints of each industry before June 1. Therefore, in order to mitigate rate shocks, we adopt the use of bill limiters of 300% for all rate classes other than agriculture and 250% for the agricultural class, relative to the class average rate. These bill limiters will serve as adequate protection from unique circumstances resulting in extraordinary bill impacts and can serve as a more general aid to all consumers in the way they mitigate rate increases. We acknowledge that implementing bill limiters for all customers may result in a revenue shortfall. We expect this shortfall to be small since bill limiters cap bills of "outlying" customers, i.e., those with extremely high bills. However, the utilities should be able to recover these shortfalls from all customers, except those we exempt from the rate increase, i.e., CARE, residential sales below 130% of baseline, and medical baseline customers. We have questions on our record regarding what bill limiter mechanism would best meet our objectives.. Therefore, we direct PG&E and Edison to propose a mechanism by advice letter within five days of the effective date of this decision that can be fully implemented by July 1, 2001.

VII. Residential Rate Design In the interest of promoting conservation, the March 26 ACR proposed a tiered rate structure. As we have discussed, our discretion in setting the tiers is framed by AB1X1, which requires that residential consumption up to 130% of baseline is not to see a rate increase. We adopt a five-tier rate design with incremental block tiers. We use a methodology similar to the one proposed by Aglet. Tier 1 captures usage up to the baseline amount and Tier 2 represents usage from 100 percent of baseline to 130 percent of baseline. Tier 3 reflects usage from 130 percent of baseline to 200 percent, tier 4 captures usage from 200 percent of baseline to 300 percent, and tier 5 captures usage in excess of 300 percent of baseline. Tiers 1 and 2 shall not see a rate increase. The increase between tier 3 to tier 4 is set at a rate that is double the increase from tier 2 to tier 3. The Tier 5 rate is set to be sufficient to cover the residual revenue requirement for the class. The components of the rate increase in the tiers 3 through 5 include the residential class allocation, and the residential class’ share of the shortfalls due to CARE, medical baseline allowances, and the 130% exemption. Increasing block tiers is most equitable from a revenue allocation standpoint. Prices for the residential customers who are the heaviest users will be higher than moderate users. This approach is more equitable than increasing rates for all levels of usage by the same amount. Consumers who use less place less strain on the grid and are rewarded with a lower rate for their usage. The tiered rate structure we adopt today is consistent with our goal to encourage conservation through higher rates above threshold usage. CLECA/CMTA expressed concern that the exemption would dilute the conservation signal, because many customers would not see an increase on their bill. While we recognize this concern, the exemption AB1X1 is clear.

A. PG&E’s E-7 and E-8 Schedules

The E-8 seasonal schedule for residential consumers was implemented well before the rate freeze and was locked in when the freeze took effect. Schedule E-8 energy charges do not adequately represent the costs of serving schedule E-8 customers as compared to the costs of serving schedule E-1 customers; the rates in E-8 are too low. Because the residential core electric rates have not been adjusted since 1993, schedule E- 1 customers pay higher rates to subsidize those customers on E-8. Schedule E-8 summer rates are 10 percent lower than schedule E-1 summer rates and schedule E-8's low winter seasonal rate is approximately 45 percent less than the schedule E-1 Tier 2 rate. This sends the wrong price signal to E-8 residential customers with heavy heating loads by encouraging them to increase their winter peak loads. Schedule E-8 fails to meet the Commission’s conservation objectives of equity and conservation. Conservation is essential during the upcoming months. Very few customers on E-8 schedules consume less than 130% of baseline during any month of the year. These large users must be given the appropriate incentive to conserve and must face the same rates as E-1 customers. To avoid the unintended consequence of large residential customers being able to avoid large portions of the intended surcharge for usage in excess of 200% or 300% of baseline, we should adopt a common set of tiered surcharge prices for the residential customer class.

VIII. Nonresidential Rate Design

A. Tiering Parties generally agreed that nonresidential use should not be tiered. Nonresidential classes, both commercial and industrial, capture a diverse body of energy users. We agree that tiering classes heterogeneous in size is inequitable and does not send the appropriate conservation signal. Parties who proposed tiered nonresidential rates, such as TURN and the Farm Bureau did so to conform to the specifications of the March 26 ACR. TURN proposes an extremely low first tier, where the majority of usage would be captured in the second tier.

It is essential that all nonresidential consumers, without regard of size conserve, since all usage contributes to the amount procured by the CDWR. The record provides us with no basis to assume that customers who use more energy are necessarily inefficient. Tiering would punish larger consumers to the benefit of smaller consumers within that class, without regard to their efficiency. As Mr. Sterzinger noted, tiering is not required to provide conservation incentives. We stress that a conservation signal must be sent to encourage all customers, regardless of size, to conserve during this summer’s supply shortage. At this point, we determine that a rate increase of 3 cents provides the appropriate conservation incentive and discourages biases based upon the size of a business. One alternative to tiering discussed in the hearing is special rates by SIC classification. Identification by SIC classifications do not solve the problems associated with tiering because they predict neither energy efficiency nor usage. Tiering based on SIC classification data available is not likely to be equitable, nor would it provide a meaningful conservation signal. There is neither appropriate time nor sufficient information to create specialized rates during this proceeding. Further, neither utility has the SIC classifications of their consumers and would require significant billing system changes before implementation. We reject tiering on the basis of industry codes at this time. We intend to further investigate the idea of industry-specific rates. We are open to further investigate whether more specialized SIC classifications could help us develop a more equitable rate structure. We direct the utilities to collect SIC classification data from their customers in an effort to understand whether a more detailed system of rate design by SIC classification should be available in future rate design proceedings. Another tiering alternative discussed for nonresidential consumers is creating tiers based upon the customer’s historic usage. This approach seeks to remove some of the unfairness in nonresidential tiering, but this indexing ultimately may present several problems. Possible problems arising from tiering by usage history include potential

- 33 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT gaming of meters, punishment for seasonal variation, and the tiering would be difficult to implement for new or expanding businesses. In essence, selecting a baseline based upon prior year consumption punishes companies for expansion, regardless of their level of efficiency. We do not seek to penalize efficient business growth. The record does not support tiering by usage history, therefore, we reject it. A tiering based upon baseline rates also would reward inefficient users compared to efficient users. Those most able to conserve are those customers who have not invested in energy efficient equipment. Those who remain efficient would see little benefit. We reject tiering for TOU customers for the same reasons that we reject tiering for nonresidential, non-time of use customers. Time-of-use signals are more precise and encourage conservation at the appropriate times relative to the signals sent by tiering. Additionally, neither Edison nor PG&E can implement tiering for TOU customers on their billing systems by June 1.

B. Non-TOU Schedules As discussed above, tiering for non-TOU schedules is rejected. Smaller amounts of usage are not necessarily more efficient. We agree with parties such as TURN and PG&E that conservation signals need to be sent to all customers, not just those customers who would fall into the second tier. We adopt the methodology proposed by ORA for nonresidential, non-TOU design. For small and large commercial customers with seasonal designation, 70% of revenue requirement is allocated to the summer period and 30% to the winter period. This approach is reasonable and consistent with our goals because it balances the year-round need for conservation, with a stronger conservation signal during the peak summer months. This methodology reconciles differing proposals. Parties such as Kinder Morgan suggest spreading the rate increase to summer consumption only. We reject this proposition because of the need to encourage conservation at all hours, not just during the summer. As established this past winter, rolling blackouts can occur in any season, at

- 34 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT any hour of the day. We encourage conservation at all times, and without adequate data from CDWR, we cannot advocate limiting price signals to one period only. There will be no rate caps allotted to this customer class, however, the we will adopt bill limiters of 300% of class usage, as discussed above. These bill limiters protect customers who may be disproportionately impacted by the rate increase. For larger customers with declining block schedules, such as GS-2 and PA-2 for Edison, the existing declining block structure shall be corrected to be an increasing block structure. Eliminating the declining block rate structure improves conservation incentives to this group of customers and adheres to our goal to discourage and reward customers for lower amounts of usage. We also agree with ORA that large customers should be shifted to TOU schedules in order to send improved price signals and spur additional conservation. Pursuant to ABIX 29, RTP metering systems will be installed for all customers over 200 kW. These meters will enable customers to participate in RTP pricing programs. If these customers do not chose to use their RTP metering systems in this manner, the meters can also be used to track usage by TOU period. Therefore, as customers on non-TOU schedules receive these meters, they should be immediately switched to the appropriate TOU schedule.

C. Time of Use Parties proposed three primary proposals for time-of-use rate design. The first, promoted by Edison, ORA and the Street Light Association, proposes an all hour increase. The second, proposed by EPUC and CIPA, places the bulk of the increase on summer on peak hours. The third, supported by TURN and CLECA, spreads the rate increase over all hours, with the largest increase during summer on-peak hours. A simple all-hour rate increase does meet some of our rate design goals, yet we find that it does not sufficiently promote conservation during the hours of peak demand when the electric system is most stressed. We reject the proposals that put the vast majority of the revenue requirement burden on summer on-peak consumption. Existing TOU rates are already heavily

- 35 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT weighted to the summer on-peak period. We agree with TURN that peak conservation is of key importance, but extremely high peak period prices could be counterproductive. There is a significant risk of endangering revenue recovery by too much shifting off peak, because many customers will shift their load to avoid paying the highest rates. We adopt the approach proposed by TURN and CLECA. This approach combines spreads the rate increases over all hours, yet the more of the increase falls upon summer on-peak usage. The differential between on- and off-peak usage is increased, but customers within this class will not be exposed to excessive on-peak prices.27 In addition, rate limiters shall be in effect to ensure that that customers shall not suffer undue price shocks.

D. “Super Peak” Rate The California League of Food Processors proposes a three-hour super on-peak period for the food processing industry. The on-peak price proposed would be twice as high as the on-peak price for other members of their class during the traditional six-hour peak. The proposal offers off-peak rates during the remainder of the peak period. We reject this proposal. This structure is designed to allow food processors to avoid the higher rates. The proposal would not be revenue neutral, as food processors would simply avoid the super-on-peak prices.28 One of the main goals of this rate design proceeding is to collect the revenue requirement and we are not willing to adopt proposals that would jeopardize this objective.

27 We have corrected the rate tables for PG&E’s Schedule E-20 and Edison’s Schedule TOU-8 to properly reflect the rate differential between customers served at secondary, primary, and transmission levels.

28 Yates, CLFP, Tr. 2435.

E. County of Los Angeles’ Proposal to Cap Rates for Essential Customers We reject the County of Los Angeles’ proposal to mitigate the impact the rate of increase on essential government facilities. The cap proposed would apply to facilities that have a limited ability to reduce consumption. The impact of a rate increase is a concern shared by every customer group in this proceeding. Other than statutory mandates, we oppose preferential treatment for any customer class and will not establish a methodology to discern which group should be awarded special treatment. In the interest of both conservation and equity, local government agencies will be exposed to the same price signals as other customer groups.

F. Agricultural Agriculture depends heavily on summer on-peak usage and a limited ability to load shift. Despite the special needs of this group, every eligible customer group contributing to the net short must assist in the conservation efforts of the state. Agricultural customers will be sent appropriate conservation signals and receive a fair share of the burden of increased rates. The Governor’s rate increase proposal, advocated by the Farm Bureau, proposal limits agricultural increases to 5% for TOU rates and 15% for non-TOU rates. We agree with the direction provided by the Governor’s proposal, but will take additional steps to protect this class. We are sensitive to the needs of this customer class, especially in a drought year. We will cap agricultural rate increases at 30% for both TOU and non- TOU customers. The shortfall from the 30% cap is to be spread over all eligible customer classes, including streetlights and residential consumers above 130% of baseline. In order to send an improved price signal and promote conservation, all agricultural customers with demand over 200 kW that are not on a TOU schedule should be switched when they are provided an interval meter. This is consistent with our treatment of non-TOU commercial and industrial customers.

We provide additional protection to agriculture customers by adopting a bill limiter of 250% on energy charges. Both the cap and the bill limiters will protect agricultural customers who are disproportionately affected by the rate increases in this unique year. In taking these actions, we both address the acute energy problems faced by agriculture customers and their unique risk for economic hardships from the combination of rate increases and drought and balance this risk with equity and conservation considerations.

G. Master Meter Customers Master meter customers are required to revise their billing systems to address the rate increase. While they are engaged in that process, these customers must also comply with AB1X1, which exempts customers using less than 130% of baseline from the surcharge, and Pub. Util. Code § 739.5, which requires master meter customers to charge their park residents approximately the same rate they would have been charged if they took service directly from the utility. We reject WMA’s proposals to exempt master meter customers from any surcharge in the near future and to phase in a surcharge over a year. All eligible customer classes must share the burden of a rate increase. If WMA receives an exemption or an extension, park owners who quickly fix their billing systems could receive a windfall, since they would be exempt from the surcharge but would be charging it to the customers. It is inequitable to allow the master metered customers to reap the financial benefits of the sub-metering transaction without bearing the responsibility that comes with that transaction, i.e., the payment of the CDWR procurement cost. We accept the proposal of WMA in its May 10, 2001 comments that all master-meter MHP customers be given until July 17, 2001 to implement tiered rates. This approach is reasonable because it allows master meter customers an equal amount of time as the utilities to implement billing system changes.

H. Streetlight and Traffic Light Schedules

We allocate a rate increase to the streetlight and outdoor lighting schedules on equal cents per kilowatt-hour basis. TURN proposes an alternative rate tiering method for streetlights, based on the type of lamp rather than the size of lamp or size of customer. The goal of TURN’s rate design is to encourage the replacement of the more inefficient lighting technologies. We encourage the replacement of inefficient lighting technologies; however, we believe the rate increase itself will prompt cities and counties who employ streetlights to invest in the more efficient bulbs, and any conservation-minded tariff rate schedules would be unnecessary. We also adopt an equal cents per kilowatt-hour design for traffic signals. We find tiering for traffic signals, such as the proposal by TURN, adds more complexity, but little value. We agree that cities and counties using traffic signals should join the conservation effort and switch to more efficient technologies. However, the summer initiative energy efficiency program (adopted in D.00-07-017) already provides communities with significant funding for investment in Light Emitting Display (LED) technology. In addition, these technologies were cost-effective, even before any rate increase, and providing a price break through a tiered rate design to encourage their deployment should not be necessary.

I. CIPA’s Credit for Interruptible Customers The California Independent Petroleum Association (CIPA) proposes that interruptible customers be exempted from a substantial portion of any surcharge, “as an investment in helping customers reduce their on-peak electrical demand.” Ex. 86, p. 7. We reject this proposal of a rate surcharge credit. Interruptible customers receive lower rates for energy in return for curtailing (interrupting) usage when called upon to do so to provide grid relief. The presence of the three-cent system wide surcharge will not change their interruptible status, or their obligation to comply with the tariff. Interruptible customers already receive a substantial pricing incentive that recognizes their interruptible status. According to § 743.1(b), “In no event shall the level of the pricing incentive for interruptible or curtailable service be altered from the levels in effect on June 10, 1996, until March 31, 2002.” CIPA proposes altering the calculation of the credit for these customers. Such alterations are currently prohibited by statute. As the calculation of the credit remains unchanged, an additional rebate or “surcharge discount” will not be given to each interruptible customer. The same credits will apply: customers whose credits are calculated by a percentage method will increase by an absolute amount. Customers with dollar credits will not increase as the same calculations for credits will apply.

IX. Other Issues

A. Tracking and Posting Data Informing customers of their rate group’s usage pattern with comparison information from the previous year will provide some assessment of the success of conservation efforts. In addition, as pricing information becomes available, such information will enable customers, particularly those on TOU schedules, to make decisions about when to consume energy. Data collection this summer is essential both for analysis in future rate proceedings and to raise consumer awareness about the challenges California faces in the months ahead. We direct the utilities to post customer

- 40 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT load profiles on their website, with weekly updates. We consider this feedback to customers to be critical to the success of the conservation efforts underway in this state. We therefore direct PG&E and Edison to post dynamic load profile information for all rate groups for which such information is available on their websites. Pricing information should also be posted as it becomes available. We also direct the utilities to post the day-ahead ISO price for electricity daily. Consumers will take heed at the magnitude of the wholesale market prices, and it will serve as a tool to understanding generation pricing. Current price data from the ISO will raise consumer awareness of the unjust and unreasonable wholesale market costs for electricity. Moreover, we direct these utilities, as part of their overall customer service function, to provide such other information on their websites as may be useful to customers in controlling their energy usage and bills. We appreciate their efforts to date to inform and educate their customers, and we know that they will continue. We also direct our staff to work with the utilities to maximize the potential for information sharing and customer assistance offered by the website. PG&E and Edison have explained that they can provide such information. For each rate group, Edison can post on its website the monthly load pattern and level for this summer and, for comparison purposes, last summer. In addition, load level and patterns of usage for each customer class will be available for June, July, and August. Edison will average the daily load profile by hours over either a week or a month and will present some text analyzing and explaining the significance of the information in an effort to be helpful to consumers. Edison also promises to display pricing information by time of use when it becomes available. PG&E states that it provides dynamic load profile information with daily updates of the hourly consumption profiles for the statistically representative customer served under sixteen separate rate schedules. PG&E cautions that while a comparison of this year’s load profile with last year’s may provide some feedback on the success of conservation efforts, it maintains that this data is not sufficient to determine individual price responses, and that the comparisons should be controlled for weather related effects.

ORA generally supports the idea of providing more information to customers about the market prices for electricity. Better-informed customers will be more likely to adjust their consumption to avoid high price times, and to make conservation investments. ORA recommends that the Commission maintain its own website, rather than relying solely on the utilities. We agree and intend to use our website for these purposes, as time and resources become available.

B. Expedited Installation of RTP Metering Systems Current metering capabilities place significant limitations on rate design. Customers that are able to reduce or shift their load in response to hourly price fluctuations would benefit from a real time pricing model. We find that real time pricing has tremendous potential for reducing the overall costs of supplying energy. Such pricing will enable to customers to control their bills by shifting load to lower cost times. Reducing peak load will lead to more efficient use of our available generation resources. We intend to promptly develop a detailed real time pricing rate structure to capture these benefits for California consumers. The Legislature has appropriated funding for real time metering systems. AB29X provides $35 million dollars for the installation of RTP metering systems for all bundled service customers with greater than 200 kW in peak load. Timely installation of the meters authorized by the Legislature is critical to the success of our plan. Installation of the meters will also assist in implementing our TOU rate design discussed above. Two things need to happen, however, before real time pricing can become a reality in California – meters and information. The CEC intends to begin the meter deployment process during this summer and complete it by this fall. The CEC also states that extending the meters to the next size range, 100 – 200 kW, creates another 22,000 end-users requiring meters, approximately doubling the population that is being addressed by the AB29X monies. It is possible for this next set of end-users to have advanced metering systems installed by early 2002 if additional funds are authorized by the Legislature, if end-users can be mandated to make self-provision of such meters a

- 42 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT condition of service, or if the Commission decides to authorize utilities expenditures with a workable cost recovery mechanism. We will closely monitor the CEC’s progress, and commit to providing any necessary assistance to ensure timely installation of the meters. The CEC maintains that it is working with the utilities and the ISO to meet the price information requirement. We direct our staff to cooperate and assist in these efforts.

C. 10% Rate Discount Associated with Rate Reduction Bonds Pursuant to § 368(a), PG&E’s and Edison’s residential and certain small commercial customers currently receive a 10% reduction to their electricity rates. This rate reduction is financed by rate reduction bonds (RRB) issued pursuant to § 840-847, and orders of this Commission. The 10% rate reduction applies through the end of the transition period established in § 368(a), i.e., through March 31, 2002, with the repayment obligation extending for another six years. The Legislature intended that the 10% RRB-financed rate reduction would be followed by additional rate reductions at the end of the transition period, yielding a cumulative reduction of 20% by April 1, 2002. § 330(a). TURN proposes that the 10% reduction continue despite the expiration of the RRB-produced financing. TURN reasons that the Legislature’s prohibition on rate increases in AB1X preclude this Commission from ending the 10% rate reduction because an end to the 10% reduction would effectively be an additional rate increase for residential and small commercial customers. Edison opposes this and PG&E states that this proposal is premature. At this time, we will make no determinations as to any ratemaking ramifications of the expiration of the 10% rate reduction in this decision. We need not reach the issue of how the expiration of the 10% rate reduction might interact with the prohibition on residential rate increases for up to 130% baseline because implementing the end of the 10% reduction will require further Commission action. At that time, the Commission will be better informed about the ramifications of TURN’s proposal. One related calculation issue, however, does require our determination. Edison raises the question of whether the 10% reduction should be applied to the pre-existing rates, i.e., prior to both the 1¢/kWh and 3¢/kWh, or should be applied after the surcharges are added to rates. Because the bonds that finance the rate reduction were sized to the pre-existing rates, Edison concludes that the 10% reduction should apply only to the pre- existing rates.

The amount financed by the bonds did not provide for these surcharges. Consequently, we are constrained to limiting the 10% reduction to rates in effect prior to the surcharges. In applying the 10% rate reduction for residential customers and certain commercial customers, PG&E and Edison shall apply the rate reduction to rates in effect prior to the surcharges.

D. Bill Display We provide direction with respect to how PG&E and Edison should format the new rate design on the customer bill. Our intent is to adopt a format which accurately and effectively conveys to customers our stated fundamental rate design goal of promoting conservation to reduce the amount of electricity needed to serve customers. The customer bill format must communicate the direct correlation between electricity supply, price, usage, and consumption patterns in order to promote price-responsive behavior. We intend that the bill format communicate easily understood price signals, and deliver the message that by managing their electricity usage, customers can assume a significant measure of control over the impacts of the rate increase and reduce their overall bill. We believe consumers are most likely to respond to these price signals when the bill provides sufficient detail allowing consumers to clearly identify and understand the differential pricing structures based on usage levels. In order to accurately portray the new rate design, whereby customers who use more electricity pay higher rates, each differential rate category or tier will identify its respective applicability to usage. On residential customer bills, the new rates will be incorporated through the five designated tiered usage levels: Baseline, 101% to 130%, 131% to 200%, 201% to 300% and over 300%. TOU customer bills will categorize the new rates under off-peak, mid-peak and on-peak classifications, as applicable. Likewise, commercial non-TOU customer bills will reflect the rate increase within the appropriate commodity component or block structure. Any bill reference to total energy charges will include the total cost of all energy consumption during the billing period, not merely baseline usage or some other minimum level of usage.

PG&E proposes to characterize the rate increase as a “Baseline Surcharge.” This is inaccurate and would cause customer confusion. Therefore, we do not adopt this recommendation. We recognize that customers may experience confusion as to why their electric rates are increasing while the rate freeze and legislated 10% rate reduction is still in effect. We have no objection to the utilities characterizing the rate increase as a “energy surcharge” provided the bill format complies with our objective to communicate easily understood price signals. The utilities should also include definition of the surcharge designation on the bill and a line item showing the total of energy surcharges authorized by D.01-01-018 and D.01-03-082.

E. Bill Insert The customer bill does not provide sufficient space to accommodate comprehensive information about the rate increase. Electric customers should receive information describing the need for the rate increase and the tiered rate structure adopted by the Commission. The bill insert should inform customers that if their usage falls completely within Tier 1 and Tier 2, they will not see a rate increase. Customers should be aware that the rate increase will not apply to

- 46 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT medical baseline, CARE or Direct Access customers. The bill insert should briefly describe the CARE and medical baseline programs, and provide information on how to apply. And finally, the bill insert should make customers aware that their diligent, consistent conservation efforts will reduce the both the impacts of the rate increase and the chance of blackouts due to inadequate electricity supply. A brief description of the California 20/20 Rebate Program adopted in Resolution E-3733 on May 3, 2001 should also be included. We will direct PG&E and Edison to submit a bill insert to the Commission’s Public Advisor for review and approval by May 18, 2001. The utilities may coincide the bill insert we order today with the release of any planned bill inserts related to implementation of the 20/20 Program and should include the bill insert information on their internet websites.

F. Customer Education The rate design we adopt here delivers a price increase to electric customers of PG&E and Edison that is larger than any they have experienced. We need to provide customers the information and tools they need to be able to respond to these prices by (1) lowering their energy use through participation in energy efficiency programs, (2) understanding the savings available through the Governor’s 20/20 program, (3) ensuring low income families understand the assistance available to them, and (4) offering commercial and business customers the opportunity to manage their energy bills through participation in a real time pricing program. On May 3, 2001, the Commission in D.01-05-033 took action to address issues related to the rapid deployment of additional funding for low-income assistance programs during the energy crisis. The Commission’s energy efficiency and conservation programs include low-income assistance programs for rate assistance under our California Alternate Rates for Energy (CARE) program, and energy efficiency services under the Low Income Energy Efficiency (LIEE) program. Funding for these programs

- 47 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT was substantially augmented with the passage of SB1X 5 and AB1X 29, both passed by the Legislature on April 5, 2001 and signed by the Governor on April 11, 200129. The Commission also administers a program for customer education about the changes occurring in the electric industry, and how those changes would affect them. This program includes the activities of the Electric Education Trust (EET) utilizing the services of community-based organizations (CBOs), and the education of small businesses under the auspices of the Commission’s Consumer Services Division (CSD). A draft decision by Administrative Law Judge John Wong, mailed April 24, 2001 for consideration at the May 24, 2001 conference, changes the focus of these customer education efforts to adjust for the energy crisis. Instead of focusing on direct access, these educational efforts should be broadened to include messages about conserving electricity, eligibility for the CARE program, and the exemption of certain customer classes from the recently adopted three-cent per kWh surcharge. We can facilitate further customer education by coordinating with other state agencies who are also involved in energy issues. The Department of Consumer Affairs is organizing a major marketing campaign to promote energy conservation titled “Flex Your Power” that will provide customers savings tips and promote the savings available under the Governor’s 20/20 program. Further, the California Energy Commission under its AB1X 29 funding for real time pricing meters should have funds available to address the extensive customer education that Dr. Borenstein testified will be needed to gain customer acceptance of real time pricing programs.

G. Payments to CDWR Today’s order sets schedule-specific rates for each customer class. Previous Commission orders require the utilities to unbundle, on each customer’s bill, the various non-generation related charges. Accordingly, it is now possible for Edison and PG&E to

29 SB1X 5 and AB1X 29, collectively, also appropriate an additional $140 million to the Department of Community Services and Development (DCSD) to augment its state low-income energy assistance programs, including weatherization services.

- 48 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT specifically state, on each customer’s bill, the customer’s energy charges (including the 3 cent surcharge and its amortization). We will order them to do so. 30 In D.01-03-081, we implemented an immediate methodology under which the utilities segregate and hold in trust certain sums for CDWR. However, we also stated that a “more precise method for remitting funds to DWR should be arrived at as soon as practicable.” But implementation of this more precise methodology had to await the availability of tariff schedule-specific generation-related or energy rates. As explained above, these schedule-specific energy charges are now available. Accordingly, we will order the utilities, concurrent with the implementation of today’s rate design and recovery of those sums from customers, to switch to this more precise methodology of segregating, holding in trust, and remitting funds to CDWR. The method for calculating the number of CDWR-supplied kilowatt hours under this more precise methodology is spelled out in D.01-03-081. By implementing this more precise methodology, concurrent with collection of the 3 cent surcharge, we provide for the utilities to remit the surcharge (including amortization amounts) to CDWR, based on the number of CDWR-supplied kilowatt hours, once they have collected the money from customers. 31

X. Next Steps As discussed above, we are interested in implementing a real time pricing (RTP) program as soon as the technical impediments can be resolved. The technical impediments are (1) any delays the CEC experiences in implementing its $35 million SB1X 5 authorized program to install interval meters for all customers of PG&E, Edison, and SDG&E who have a connected load of 200kW or greater; (2) delays caused by the time necessary for PG&E and Edison to make the necessary changes to their billing systems; and (3) posting of real time prices by the ISO for the day ahead or spot market. 30 We note that the sample bills provided by both PG&E and Edison in this proceeding meet this requirement

31 We take this opportunity to re-affirm, notwithstanding any inartful language apparently to the contrary that may be contained elsewhere in this decision, that, pursuant to AB 1X, CDWR does not sell electricity to utilities at wholesale, but rather sells it to retail end use customers. Under today’s decision, monies that the utilities collect from customers as agent for CDWR are based on the amount of CDWR-power supplied to those customers and the rates we authorize today.

The proposals presented by CEC and Dr. Borenstein at hearings were general in nature, did not include specific details necessary for implementation, and were based on the premise that the technical impediments listed above posed an effective barrier to implementing actual programs by June 1, 2001. The proposal presented by Enron contained more specific information and addressed the lack of ISO posted price information by using Dow Jones electricity price indices as its marginal price signal. We will proceed expeditiously to develop and adopt a voluntary RTP that will be available to customers when their interval meters are installed. We will direct Energy Division to work closely with PG&E and Edison on their billing system constraints and the manual billing procedures that can be done for customers until the system changes are complete. Our RTP process will begin with a workshop facilitated by Energy Division on May 21, 2001 and we anticipate adopting a final program later this summer. We are convinced that a comprehensive review of PG&E’s and Edison’s rate schedules and rate design should be undertaken when the Commission and interested parties have sufficient data and the time and resources necessary to thoroughly review the issues. We plan to embark on this process soon so that a comprehensive, rigorous review of rate design will be undertaken in early 2002. We recognize that we may need to quickly make a mid-course correction this summer and modify the rate design within each customer class to provide more pronounced peak period price signals, and possibly collect a higher energy surcharge, if CDWR provides information on its energy purchases that require this action. If we determine that a mid-course correction is needed, we will afford notice and provide all parties the opportunity to be heard on an expedited schedule.

XI. Issuance of the Proposed Decision The proposed decision was issued on May 9, 2001. Parties filed and served comments on the proposed decision on May 10 and appeared for final oral argument (FOA) before a quorum of the Commission on May 11. Public Utilities Code Section 311(d) generally requires, in matters that have gone to hearing, a 30-day period between

- 50 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT service of an assigned Commissioner’s or ALJ’s proposed decision and the Commission’s issuance of the decision. However, Section 311(d) provides that that period may be reduced or waived by the Commission “in an unforeseen emergency or upon the stipulation of all parties to the proceeding or as otherwise provided by law.” Although not expressly stated in Section 311(d), the 30-day period provides an opportunity for parties to comment on the proposed decision. In this proceeding, we are considering the rate design to apply to the three-cent surcharge adopted in D.01-03-082. One of the stated goals of this rate design is to encourage conservation to help Californians avoid, to the extent possible, rolling blackouts during the summer months. Given the fact that the Independent System Operator (ISO) has identified over 30 days32 in which it predicts rolling blackouts to occur and the State of Emergency called by Governor Davis on January 17, 2001, we believe that this constitutes an unforeseen emergency for these purposes. Such blackouts threaten to severely impair public health and safety. Accordingly, we will reduce the 30-day advance publication period of Section 311(d) to five days, and will allow parties to file and serve written comments on May 10, followed by final oral argument on May 11 and Commission consideration of the decision on May 14. Based on the public participation hearings, parties’ comments on the proposed decision and the final oral argument, we have made changes throughout.

32 See, e.g., CAISO Summer Assessment prepared on March 22, 2001 that identifies resource deficiencies for June through September ranging from 600 MW to nearly 3,700 MW. This report can be accessed on the ISO’s website: http://www.caiso.com.

Findings of Fact 1. To the extent possible, we will design rates to promote our fundamental goals of equity and conservation in this proceeding. 2. The goal of equity is one of fairness, viewed in a broad context and encompasses both social and political questions. 3. We do not have the necessary data to consider cost-based equity at this time, because the wholesale market is dysfunctional and costs are not the basis of prices being charged. In addition, we do not have accurate information regarding the nature and extent of costs relating to power purchases to date by CDWR. 4. We recognize the economic impact our revenue allocation and rate design decision will have on all sectors of California. We intend to design rates that provide price signals to which customers can respond and thereby reduce the amount of the increase they will see on their bills. 5. We do not have sufficient data to pursue reducing the disparity in prices paid for energy among customer classes, but intend to revisit this goal in future proceedings. 6. Conserving electricity means reducing the amount of electric power needed to serve customers. A reduction in total energy consumption will help protect Californians from blackouts and reduce the total financing needed by the state to purchase electricity. 7. We intend to promote the greatest amount of conservation during summer peak hours. Summer peak is the time PG&E and Edison have the largest net short position and are therefore projecting a need for the most purchases from CDWR and the ISO to meet anticipated customer needs. 8. Power purchased in the wholesale market all hours by CDWR and the Independent System Operator (ISO) to serve the customers of PG&E and Edison is prohibitively expensive. Once CDWR provides us with information, broken out by month and time of day, on the amount of power it had under contract, the prices it would be paying, and the amount of power it anticipated buying on the spot market, we should be able to determine the value of conserving energy in specific peak periods. However, at this time, the record

- 52 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT demonstrates that all energy purchased this summer will be expensive and power purchased in peak periods will be even more expensive. 9. To maximize the value of conserving energy at peak times, we can strengthen the price signal we send customers for periods when prices are highest. We have some ability to do this now by increasing rates at peak periods for those customers on time-of- use (TOU) schedules. 10. The Governor’s 20/20 program is designed to reward customers who reduce their overall electric consumption by 20% this summer. This incentive, along with customer education, energy efficiency programs, and the price signal that higher rates will send customers, are effective tools to promote conservation. 11. We recognize business customers generally place an extremely high value on reliability and expect that these customers will be particularly receptive to peak reduction programs and the interruptible programs adopted in R.00-10-002. 12. The Legislature authorized $35 million in SB 5X for the CEC to install interval meters on all commercial customers of PG&E and Edison with connected loads of 200 MW and above. When CEC completes this installation and the CDWR provides specific projections, the Commission will be better able to specifically target and provide more effective price signals. 13. The incremental revenue requirement created by the surcharge authorized in D.01- 03-082 is a function of the sales to which the revenue requirement increase applies. 14. The sales forecasts, while the best evidence available, should only be used for the limited purposes of calculating the revenue requirement to be applied in this proceeding. 15. The Commission adopted the one-cent surcharge on January 4, 2001, which applies to all sales except to customers eligible for the CARE program. 16. AB1X prohibits increases to rates, effective as of January 5, 2001, applicable to residential usage below 130% of baseline usage. Usage below 130% is not exempt from the one-cent surcharge. Usage below 130% of baseline usage is exempt from the three- cent surcharge.

17. The EPS is already reflected in the rates that are used as the starting point for the rate design being considered in this proceeding. 18. The revenue allocation and rate design discussed in this decision applies to the three-cent increase adopted in D.01-03-082. 19. Edison calculates the incremental revenue to be recovered by multiplying 3¢/kWh times its total forecasted system-wide sales for 2001 of 83.78 billion kWh. This results in an annual revenue increase of $2.513 billion. 20. PG&E applies 3¢/kWh increase to all its forecasted sales for 2001, which results in an annual incremental revenue requirement of $ 2.46 billion. 21. There is no way of knowing actual procurement costs at this point in time. CDWR has established its revenue requirements of $9.2 billion for procuring power but the Commission has not had an opportunity to analyze this forecast for purposes of the allocation and rate design matters addressed in this proceeding. 22. We have clearly stated that CDWR is to receive the full amount the utilities collect from all customers for each kWh of power provided by CDWR. 23. The two principal issues concerning revenue allocation are: (1) the method used to apportion the revenue increase among customer classes; and (2) the treatment of the shortfall which results from exempting residential usage up to 130% of baseline consumption from any increase. 24. The allocation and rate design issues addressed in this decision are limited to allocation and design of the revenues to be collected pursuant to the surcharge. The underlying rate structure of the utilities will not change. 25. The fundamental facts underlying traditional cost-based revenue allocation have changed. The dysfunctional wholesale energy market has resulted in unconscionable, unlawful wholesale prices, which have increased by staggering proportions since the summer of 2000. These prices bear no relationship to any actual costs incurred in production. The outrageously priced wholesale energy that causes us to take the extraordinary step of imposing this rate surcharge is being produced at the same plants

- 54 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT upon which we based our traditional cost allocation procedures. The price of wholesale energy is no longer a function of cost of production but rather a function of what price that can be extracted from a market subject to manipulation. 26. Absent data from CDWR regarding cost forecasts, we have nothing upon which we might be able to determine a cost-based revenue requirement, or to do revenue allocation guided by cost causation. 27. Recent price experience suggests that all kWhs will be valuable. In this volatile and dysfunctional market, we cannot predict which kWhs at what particular time periods will be more valuable than others. 28. The surcharge is in place to provide the additional funds necessary to provide for customers’ energy consumption and we have previously determined that generation costs associated specifically with energy consumption are properly recovered using an equal cents per kilowatt hour methodology. 29. Because we have used total forecast sales to this class, and all other classes, upon which to allocate the revenue requirement associated with the 3¢/kWh surcharge, the share allocated to residential sales that are exempt from paying the surcharge must be re- allocated to other sales. 30. Re-allocating the revenue requirement associated with sales that are exempt from paying the surcharge solely to the narrow range of remaining residential sales is too severe. The cost of this legislatively-mandated exemption should be broadly assessed across all customer groups. 31. The revenue requirement caused by exempting CARE customers should be allocated to all other customer classes, including streetlighting. 32. Funding for the CARE program is not at issue in allocating the CARE surcharge shortfall. 33. Because of the extraordinary size of the rate increase, it is reasonable to exempt customers who have usage above 130% of baseline due to medical conditions. The

- 55 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT protection we afford these vulnerable customers has a similar equitable basis to our CARE customer exemption. 34. Direct access customers do not contribute to the net short that the CDWR is procuring on behalf of PG&E’s and Edison’s customers. 35. It would be inequitable for direct access customers to pay for both their own cost of procurement and the procurement costs of bundled customers. 36. The right to recover the revenues equivalent to the three-cent surcharge was established by D.01-03-082 and affected only electricity delivered from the effective date of that decision forward. 37. A 12-month amortization period for the collection of the revenue associated with applying the three-cent surcharge to all sales from March 27, 2001 to the day utilities begin collecting the surcharge it will have less of an impact on already high rates than a shorter amortization period, and it will not disadvantage summer intensive industries such as agriculture. 38. Shifting customers to time-of-use metered schedules helps us achieve our goal of conservation as it shifts use away from periods of peak demand. 39. We can ensure that customers shifted to TOU schedules do not contribute any additional revenue toward transition cost recovery by requiring the utilities to establish tracking accounts for these customers and if there is any net increase in billings as a result of requiring these customers to shift to TOU schedules, applying these increased revenues only to those purposes to which we have previously dedicated the one-cent and three-cent surcharges. 40. We do not have sufficient information to craft a definition of “agricultural commodity food processors” or to determine that no cost shifting to other classes would occur if these customers were allowed to migrate to the agricultural tariffs, as provided under Pub. Util. Code § 740.11.

41. Bill limiters are an effective short-term means to address the concerns of unique industry groups requesting to migrate to special schedules and to mitigate rate shock on individual customers. 42. We expect the revenue shortfall from implementing bill limiters to be small and it is addressable by the utilities reflecting in their compliance advice letters an allocation of the expected shortfall and then establishing balancing accounts to track the over- or undercollection. 43. Increasing block tiers is most equitable form of revenue allocation because prices for the residential customers who are the heaviest users will be higher than moderate users, which is consistent with our goal to encourage conservation through higher rates above threshold usage. 44. It is reasonable to adopt a 5 tier-rate design with incremental block tiers with the following tiers: a. Tier 1 Up to the baseline amount b. Tier 2 From 100 – 130% of baseline c. Tier 3 From 130 – 200% of baseline d. Tier 4 From 200 – 300% of baseline e. Tier 5 In excess of 300% of baseline 45. Setting the tiered charges separatel6y for each residential rate schedule would create undesirable incentives for customers to switch rate schedules, and inequitable differences between the surcharge amounts paid by different customers with the same usage levels but served on different schedules. 46. It is reasonable to set the surcharge rates for usage in Tiers 3, 4, and 5 for the residential class as a whole, based on the combined tiered billing determinants for each utilities’ entire residential rate class. 47. Because the residential core electric rates have not been adjusted since 1993, schedule E-1 customers pay higher rates to subsidize schedule those customers on the E-8 tariff. This sends the wrong price signal to residential customers with heavy heating loads by encouraging them to increase their winter peak loads.

48. Schedule E-8 fails to meet the Commission’s conservation objectives of equity and conservation. 49. It is reasonable to adopt TURN’s proposal to close this schedule to new customers. 50. Tiering rate classes comprised of customers with substantially dissimilar usage volumes is inequitable and inconsistent with our conservation goal. 51. All nonresidential consumers, without regard of usage volume, must conserve, since all usage contributes to the amount that must be purchased by the CDWR. 52. The record does not support the finding that customers with greater usage volume are necessarily inefficient. 53. Tiering the nonresidential class would impose disproportionate impacts on larger volume usage consumers without regard to their efficiency. 54. A uniformly applied rate increase of 3¢/kWh to the nonresidential class provides the appropriate conservation incentive and discourages unfounded biases based upon usage volume. 55. Rates based on SIC classification do not predict energy efficiency or usage, and neither PG&E nor Edison has the SIC classifications of their consumers. 56. PG&E and Edison should collect SIC classification data from their customers in an effort to understand whether a more detailed system of rate design by SIC classification should be available in future rate design proceedings. 57. Tiering nonresidential rates by the customer’s historic usage could lead to gaming of meters, result in punishment for seasonal variation, and such tiering would be difficult to implement for new or expanding businesses. 58. Tiering nonresidential rate schedules by baseline usage would reward inefficient users. 59. Tiering TOU rate schedules should be rejected because time-of-use signals are more precise and encourage conservation at the appropriate times relative to the signals sent by tiering, and neither Edison nor PG&E can implement tiered TOU rates by June 1.

60. ORA’s proposal for nonresidential, non-TOU rate design for small and large commercial customers is reasonable and consistent with our goals because it balances the year-round need for conservation, with a stronger conservation signal during the peak summer months. 70% of revenue requirement will be allocated to the summer period and 30% to the winter period. 61. We encourage conservation at all time periods. Without adequate date from CDWR showing which period is more valuable than another, we cannot support limiting price signals to one period only. 62. No rate caps should be allotted to the non-TOU nonresidential customer class, other than the bill limiters of 300% of class usage. 63. Customers with declining block schedules, such as GS-2 and PA-2 for Edison, should be corrected to be an increasing block structure to improve conservation incentives. 64. A simple all-hour rate increase does not sufficiently promote conservation during the hours of peak demand. 65. Placing the vast majority of the revenue requirement burden on summer on-peak consumption may result in too much shifting off-peak. 66. The revenue requirement should be spread over all hours, but more of the increase should fall on summer on-peak usage. Although the differential between on- and off- peak usage is increased, on-peak prices are not excessive. 67. We reject the proposed 3-hour super on-peak period for the food processing industry because it would not be revenue neutral. 68. We reject the County of Los Angeles’ proposal to limit the impact the rate of increase on essential government facilities because we oppose preferential treatment for any customer class. 69. Agricultural customers depend heavily on summer on-peak usage and have a limited ability to load shift.

70. Agricultural customers are disproportionately affected by the rate increases in this year due to the unique combination of the energy emergency and drought. 71. To mitigate the effects of the rate increase on agricultural customers, it is reasonable to cap agricultural rate increases at 30% for both time-of-use and non-time-of- use customers, with the resulting revenue shortfall to be spread over all eligible customer classes, including streetlights and residential consumers above 130% of baseline. 72. A bill limiter of 250% on energy charges for agricultural customers will assist individual customers within this class in managing their bills. 73. Master meter customers should revise their billing systems to incorporate this surcharge, and to comply with Water Code § 80110 and Pub. Util. Code § 739.5, by July 17, 2001. 74. It is inequitable to allow the master metered customers to reap the financial benefits of the sub-metering transaction without bearing the responsibility that comes with that transaction, i.e., the payment of the surcharge. 75. The surcharge revenue requirement is allocated to the streetlight, outdoor lighting schedules, and traffic signal schedules on equal cents per kilowatt-hour basis. 76. It is not necessary at this time to adopt TURN’s tiering method for streetlights (based on the type of lamp rather than the size of lamp or size of customer) because the rate increase itself will prompt cities and counties who employ streetlights to invest in the more efficient bulbs. 77. Interruptible customers should not be exempted from the surcharge, as CIPA proposes. Interruptible customers already receive a substantial pricing incentive, which cannot be altered until March 31, 2002, pursuant to § 743.1(b). 78. Customers must receive as much information as possible about their usage pattern and pricing information in order to make intelligent decisions about energy consumption. 79. Data collection this summer is essential both for analysis in future rate proceedings and to raise consumer awareness about the challenges California faces in the months ahead.

80. Commission staff will work with the utilities to maximize the potential for information sharing and customer assistance offered by the website. 81. Real time pricing has tremendous potential for reducing the overall costs of supplying energy because such pricing will enable to customers to control their bills by shifting load to lower cost times, and will also reduce peak load. 82. Real time pricing meters are critical to implementing real time pricing. 83. The Legislature has appropriated $35 million dollars for the installation of real time pricing metering systems for all bundled service customers with greater than 200 kW in peak load by a program administered by the CEC. 84. We will closely monitor the CEC’s progress in installing the meters, and commit to providing any necessary assistance to ensure timely installation of the meters. Our staff will cooperate and assist the CEC in these efforts. 85. We will limit the 10% RRB-financed reduction to rates in effect prior to implementation of the 1¢/kWh and 3¢/kWh surcharges. 86. The customer bill format must communicate the direct correlation between electricity supply, price, usage, and consumption patterns in order to promote price- responsive behavior. 87. Customers need to be informed about the rate increase and how they will be impacted. 88. Consumers are most likely to respond to price signals when the bill provides sufficient detail allowing consumers to clearly identify and understand the differential pricing structures. 89. The customer bill does not provide sufficient space to accommodate comprehensive information about the rate increase. Electric customers should receive information describing the need for the rate increase and the tiered rate structure adopted by the Commission. 90. We will proceed expeditiously to develop and adopt a voluntary RTP that will be available to customers when their interval meters are installed, and we direct Energy

Division to work closely with PG&E and Edison on their billing system constraints and the manual billing procedures that can be done for customers until the system changes are complete. 91. Energy Division will facilitate a workshop on May 21, 2001 on real time pricing issues, and we anticipate adopting a final program later this summer. It is reasonable that this workshop be used to develop a master data request and format for data collection. We intend that the data request be finalized and issued no later than June 8 and to refine our approach to rate design in early July. 92. We intend to comprehensively and rigorously review of PG&E’s and Edison’s rate schedules and rate design in early 2002. 93. The proposed decision was issued on May 9, 2001. Parties filed and served comments on the proposed decision on May 10 and appeared for final oral argument before a quorum of the Commission on May 11. 94. Although not expressly stated in Section 311(d), the 30-day period provides an opportunity for parties to comment on the proposed decision. 95. One of the stated goals of the rate design options considered in this decision is to encourage conservation to help Californians avoid, to the extent possible, rolling blackouts during the summer months. 96. The ISO has predicted more than 30 days of rolling blackouts of electricity supply over the upcoming summer. 97. Electricity supply blackouts can severely impair public health and safety. 98. On January 17, 2001, Governor Davis declared a State of Emergency due to the energy shortage in California.

Conclusions of Law 1. Water Code § 80110 exempts all residential usage below 130% of baseline from any increase in electricity charges after February 1, 2001.

2. It is reasonable to allocate this extraordinary surcharge on an equal cents per kWh basis, in a manner that protects vulnerable customers and ensures no individual customers experience extreme hardship. 3. It is reasonable to adopt a revenue allocation and rate design that achieve the following objectives: (1) reduce the need for procuring power and therefore reduce the amount of money California is paying wholesale generators for electric power; (2) allocate the unreasonable costs of this generation in a fair and understandable manner to all customers, recognizing the adverse economic impact our decision will have on all sectors of California life; (3) protect the most vulnerable customers; (4) ensure no individual customers experience extreme hardship; and (5) provide customers the necessary tools to manage their energy usage and reduce their energy bills. 4. An equal cents per kilowatt-hour is the most equitable revenue allocation methodology as well as the methodology most appropriate to apportioning energy purchase costs to all future energy consumption. This allocation methodology is also simple, understandable, and consistent with our approach for the one cent surcharge adopted in D.01-01-018. 5. Because we agree that the revenue requirement increase should apply only to the 3¢/kWh adopted in D.01-03-082 and because we agree that we will use the utilities’ sales forecasts for our determinations in this decision only, these revenue requirement increases are reasonable. 6. It is reasonable to base the revenue requirement on applying the surcharge to forecast system-wide sales. 7. It is reasonable that the revenue requirement shortfall caused by applying the 3¢/kWh surcharge approved in D.01-03-082 to sales to residential customers below 130% of baseline should be re-allocated to all sales other than residential sales below 130% of baseline. 8. It is reasonable to allocate the revenue requirement shortfall from exempting CARE customers to all other customer classes, including streetlighting. This allocation is not a revenue requirement necessary to fund the low-income discount

- 63 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT program, from which street lighting continues to be exempt, but rather a general surcharge covering procurement of electricity. It should be allocated as broadly as possible to achieve our goals of equity and conservation. 9. We should exempt from the surcharge all customers who have usage above 130% due to medical conditions. The utilities should reflect the exemption of medical baseline customers in the tariffs they file pursuant to this order. 10. We should allocate the revenue shortfall from this exemption in the same manner as we allocate the CARE shortfall. 11. The revenue associated with applying the three-cent/kWh surcharge to all non- exempt energy sales from March 27, 2001 to the day utilities begin collecting the surcharge should be added to each utility’s revenue requirement and amortized over a 12- month period. 12. The surcharge adopted in D.01-03-082 should not apply to direct access customers because they are not relying on CDWR or the utilities to obtain their power. 13. We should require certain customers to shift to TOU schedules in order to better address the current energy emergency. 14. Requiring customers to shift to TOU schedules is not precluded by the continuing rate freeze because no additional revenues will be applied toward transition cost recovery. 15. Our record is insufficient to conclude that there will be no cost shifting if we expand the definition of the agricultural class to include agricultural commodity processing customers. Therefore, pursuant to Pub. Util. Code § 740.11, we do not expand the definition of the agricultural class. 16. It is reasonable to adopt the use of bill limiters of 300% for all rate classes other than agriculture and 250% for the agricultural class, relative to the class average rate. A lower limiter for the agricultural class is reasonable due to the higher than normal water pumping requirements forecast for this summer. 17. CIPA’s proposed alteration of the interruptible customer credit calculation is prohibited by § 743.1(b) because it would alter the level of the pricing incentive for

- 64 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT interruptible or curtailable service be altered from the levels in effect on June 10, 1996 prior to March 31, 2002. 18. Pursuant to § 368(a), PG&E’s and Edison’s residential and certain small commercial customers currently receive a 10% reduction to their electricity rates, financed by rate reduction bonds issued pursuant to § 840-847, and orders of this Commission. The 10% rate reduction applies through the end of the transition period established in § 368(a), i.e., through March 31, 2002. 19. We need not and should not determine any ratemaking ramifications of the expiration of the 10% RRB-financed rate reduction in this decision. 20. By implementing the more precise methodology for remitting funds to CDWR concurrent with collection of the 3 cent surcharge, we provide for the utilities to remit to CDWR the surcharge (including amortization amounts) on the electricity supplied by DWR after they have collected the money from customers. 21. Section 311(d) generally requires, in matters that have gone to hearing, a 30-day period between service of an assigned Commissioner’s or ALJ’s proposed decision and the Commission’s issuance of the decision. That section also provides that that period may be reduced or waived by the Commission “in an unforeseen emergency or upon the stipulation of all parties to the proceeding or as otherwise provided by law.” 22. Based on the fact that the ISO has identified over 30 days in which it predicts rolling blackouts to occur and the State of Emergency called by Governor Davis on January 17, 2001, we conclude that an unforeseen emergency as provided in § 311(d) exists for purposes of adopting this decision. 23. Consistent with the conclusion that an unforeseen emergency exists, we have the authority to reduce the 30-day advance publication period of § 311(d) to five days, and to allow parties to file and serve written comments on May 10, followed by final oral argument on May 11 and Commission consideration of the decision on May 14. 24. This order should be effective today in order to allow the adopted rate design to be implemented expeditiously.

INTERIM ORDER

IT IS ORDERED that: 1. Within seven days of the effective date of this decision, Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (Edison) shall file compliance advice letters with complete tariffs to implement the rate design changes adopted herein. PG&E’s advice letter shall become effective on June 1, 2001 subject to Energy Division determining that it is compliant with this Order. Edison’s advice letter shall become effective on June 3, 2001 subject to Energy Division determining that it is compliant with this Order. PG&E and Edison shall include with their advice letters detailed and complete workpapers showing the revenue allocation and rate design calculations underlying the new rates for each rate schedule. On the same day that they file their advice letters, PG&E and Edison shall serve electronic copies of the workpapers on Energy Division and all active parties in this phase of the proceeding. Specifically, PG&E and Edison shall comply with the following: a) The revenue allocation and rate design applies to the 3 cents/kilowatt- hour (kWh) surcharge adopted in Decision (D.) 01-03-082. b) The incremental revenue requirement associated with the 3 cent/kWh surcharge adopted in D.01-03-082 shall be based on applying the surcharge to forecast system-wide sales including sales to direct access customers. The annual system-wide sales forecasts are 81,991 Gigawatt-hours (GWh) for PG&E, and 83,780 GWh for Edison. The annual incremental revenue requirements are $2.46 Billion for PG&E, and $2.513 Billion for Edison. The incremental revenue requirement shall be allocated only to bundled service customers. The rates attached to this Order reflect revenue allocation and rate design including direct access customers. Thus, in workpapers supporting their advice letters, PG&E and Edison shall show the level of direct access sales removed from the sales forecast in developing the revenue allocation, rate design, and resulting rates.” c) The incremental revenue requirement associated with the 3¢/kWh surcharge adopted in D.01-03-082 shall be allocated among the customer classes based on the proportional number of bundled service kilowatt-hours (kWhs) each class is forecast to consume during calendar year 2001 (i.e., equal cents per kWh allocation). d) CARE customers, residential usage below 130% of baseline, and non- CARE medical baseline customers are exempt from any revenue allocation

- 66 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT associated with the 3 cent/kWh surcharge authorized by D.01-03-082. The rates attached to this decision do not reflect the exemption of non-CARE medical baseline customers. Thus, in workpapers supporting their advice letters, PG&E and Edison shall show the sales associated with non-CARE medical baseline customers, and how the rates were adjusted to reflect exemption of these customers from the surcharge. e) The revenue resulting from applying the 3¢/kWh surcharge approved in D.01-03-082 to forecast sales to bundled service residential customers below 130% of baseline, CARE customers, and non-CARE medical baseline customers shall be re-allocated on an equal cents per kWh basis to all bundled service sales other than (1) residential sales below 130% of baseline, (2) sales to CARE customers, and 3) sales to non-CARE medical baseline customers. f) PG&E and Edison shall reflect in the rates an allocation of shortfalls resulting from the application of the bill limiters adopted herein (bill limiter shortfalls). The rates attached to this decision do not reflect an allocation of bill limiter shortfalls. Thus, in workpapers supporting their advice letters, PG&E and Edison shall show how they developed the amount ($) of the bill limiter shortfalls and how these shortfalls are reflected in the revenue allocation, rate design, and rates within each rate schedule. The bill limiter shortfalls shall be allocated on an equal cents per kWh basis to all bundled service sales other than 1) sales to CARE customers, 2) sales to non-CARE medical baseline customers, and 3) residential sales below 130% of baseline. g) Edison and PG&E shall reflect a 5 tier-rate residential rate design with incremental block tiers with the following tiers: a. Tier 1 Up to the baseline amount b. Tier 2 From 100 – 130% of baseline c. Tier 3 From 130 – 200% of baseline d. Tier 4 From 200 – 300% of baseline e. Tier 5 In excess of 300% of baseline. f. The surcharge rates for usage in Tiers 3, 4, and 5 should be set for the residential class as a whole, based on the combined tiered billing determinants for the entire residential rate class. h) The surcharge rates for usage in Tiers 3, 4, and 5 shall be set for PG&E’s residential class as a whole, based on the combined tiered billing determinants for each utilities’ entire residential rate class. i) For small and large commercial customers with seasonal designation, 70% of revenue requirement shall be allocated to the summer period and 30% to the winter period.

j) Non-TOU nonresidential customer class and the residential class shall have a bill limiter of 300% of class usage. k) All customers with declining block schedules shall be corrected to be an increasing block structure. l) Agricultural rate increases shall be limited to 30% for both time-of-use and non-time-of-use customers, with the resulting revenue shortfall to be spread over all eligible customer classes, including streetlights and residential consumers above 130% of baseline. m) Agriculture rates shall also be subject to a bill limiter of 250% on energy charges. n) The surcharge revenue requirement shall be allocated to the streetlight and outdoor lighting schedules on equal cents per kilowatt-hour basis. o) An equal cents per kilowatt-hour design for traffic signals shall be reflected in the tariffs. p) The 10% RRB-financed reduction to rates shall apply to rates in effect prior to implementation of the 1¢/kWh and 3¢/kWh surcharges. q) The bill format shall incorporate D.01-03-082’s rate increase through the applicable baseline tiers, mid-, off-, or on-peak classifications, or other appropriate usage-based component. r) The bill format shall label the surcharge as “energy surcharge” or “energy procurement surcharge” and should provide the customer a separate line item of total energy surcharges. s) The bill format shall provide the customer a line item or items for energy charges, separate from all non-energy charges.

2. PG&E and Edison shall amortize the revenue associated with applying the 3¢/kWh surcharge to all non-exempt energy sales from March 27, 2001, to the day utilities begin collecting the surcharge over a 12-month period beginning with the date the utilities begin collecting the surcharge. 3. PG&E and Edison shall collect SIC classification data from their customers in an effort to understand whether a more detailed system of rate design by SIC classification should be available in future rate design proceedings. 4. Master meter customers shall revise their billing systems to incorporate this surcharge, and to comply with Water Code § 80110 and Pub. Util. Code § 739.5, by July 17, 2001. 5. We direct PG&E and Edison to post on their respective websites: (1) dynamic load profile information for all rate groups for which such information is available, (2) pricing information, as it becomes available, (3) day-ahead ISO price for electricity daily, and (4) such other information as may be useful to customers in controlling their energy usage and bills. We direct our staff to work with the utilities to maximize the potential for information sharing and customer assistance offered by the website. 6. PG&E and Edison shall prepare bill inserts notifying customers of the need for the rate increase, tiered rate structure, usage levels not impacted, customer exemptions, the need for conservation and information about the CARE, medical baseline and California 20/20 Rebate programs. The bill insert will be submitted to the Public Advisor for review and approval by May 18 and when approved posted on each utility’s website. 7. Concurrent with their implementation of today’s rate design and recovery of those sums from customers, PG&E and Edison shall switch to the more precise methodology of segregating, holding in trust, and remitting funds to CDWR described in D.01-03-081. The method for calculating the number of CDWR-supplied kilowatt hours under this more precise methodology is spelled out in the text of D.01-03-081. 8. We shall proceed expeditiously to develop and adopt a voluntary RTP that will be available to customers when their RTP metering systems are installed, and we direct Energy Division to work closely with PG&E and Edison on their billing system

- 69 - A.00-11-038 et al. ALJ/CMW/tcg DRAFT constraints and the manual billing procedures that can be done for customers until the system changes are complete. 9. Energy Division shall facilitate a workshop on May 21, 2001 on real time pricing issues and to develop a master data request. 10. The master data request shall be finalized and issued by June 8, 2001. 11. Within 15 days of the effective date of this Order, PG&E and Edison shall file an advice letter to implement bill limiters by July 1, 2001. PG&E’s and Edison’s advice letters shall be effective on July 1, 2001 subject to Energy Division determining that the bill limiter mechanisms addressed in these advice letters are consistent with the objectives set forth in this decision. In their advice letters, PG&E shall establish a balancing account to track the actual bill limiter shortfalls required pursuant to Ordering Paragraph 1. Balances in these accounts will be reviewed in PG&E’s and Edison’s next respective electric rate design proceedings. PG&E and Edison shall consult with ORA and Energy Division in preparing their advice letters.

12. No later than June 1, 2001, Edison shall notify its non-CARE medical baseline customers that they are exempt from the surcharge approved in D.01-03-082. Edison’s notice shall also indicate that its non-CARE medical baseline customers shall receive a credit on their September 2001 bills for any payments they made related to the surcharge while Edison was making the necessary billing modifications to reflect their exemption from the surcharge. This order is effective today. Dated ______, at San Francisco, California.

- 71 - APPENDIX A

LIST OF APPEARANCES ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

************ APPEARANCES ************ Michael Aguirre Attorney At Law Gerald Lahr AGUIRRE & MEYER ABAG POWER 1060 8TH AVENUE, SUITE 300 101 8TH STREET SAN DIEGO CA 92101 OAKLAND CA 94607 (619) 235-8636 (510) 464-7908 [email protected] [email protected] For: RATEPAYERS/UCAN For: ASSOCIATION OF BAY AREA GOVERNMENTS (ABAG)

Carrie H. Allen Katherine S. Poole AKIN, GUMP, STRAUSS, HAUER & FELD, LLP ADAMS BROADWELL JOSEPH & CARDOZO 1333 NEW HAMPSHIRE AVENUE, N.W. 651 GATEWAY BLVD., SUITE 900 WASHINGTON DC 20036 SOUTH SAN FRANCISCO CA 94080 (202) 887-4444 (650) 589-1660 [email protected] [email protected] For: CE Generation For: The Coalition of California Utility Employees Michael Alcantar Attorney At Law Marc D. Joseph ALCANTAR & KAHL LLP Attorney At Law 1300 SW 5TH AVENUE., SUITE 1750 ADAMS BROADWELL JOSEPH & CARDOZO PORTLAND OR 97201 651 GATEWAY BOULEVARD, SUITE 900 (503) 402-9900 SOUTH SAN FRANCISCO CA 94080 [email protected] (650) 589-1660 For: Cogeneration Association of California [email protected] For: The Coalition of California Utility Employees Evelyn Kahl Attorney At Law William P. Adams ALCANTAR & KAHL, LLP ADAMS ELECTRICAL SAFETY CONSULTING 120 MONTGOMERY STREET, SUITE 2200 716 BRETT AVENUE SAN FRANCISCO CA 94104 ROHNERT PARK CA 94928-4012 (415) 421-4143 (707) 795-7549 [email protected] For: SELF For: Energy Producers & Users Coalition Aaron Thomas AES NEWENERGY, INC. Edward G. Poole 350 S. GRAND AVENUE, SUITE 2950 Attorney At Law LOS ANGELES CA 90071 ANDERSON & POOLE (213) 996-6136 601 CALIFORNIA STREET, SUITE 1300 [email protected] SAN FRANCISCO CA 94108 For: New Energy Ventures, Inc. (415) 956-6413 [email protected] For: California Independent Petroleum Association and Sun-Maid James Weil Growers of California AGLET CONSUMER ALLIANCE PO BOX 1599 Daniel W. Douglass FORESTHILL CA 95631 Attorney At Law (530) 367-3300 ARTER & HADDEN LLP [email protected] 5959 TOPANGA CANYON BLVD., STE 244 For: AGLET CONSUMER ALLIANCE WOODLAND HILLS CA 91367 (818) 596-2201 [email protected] For: ALLIANCE OF RETAIL MARKETS and WESTERN POWER - 1 - ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

TRADING FORUM

Barbara R. Barkovich Robert Pernell BARKOVICH AND YAP, INC. CALIFORNIA ENERGY COMMISSION 32 EUCALYPTUS LANE 1516 9TH STREET SAN RAFAEL CA 94901 SACRAMENTO CA 95829 (415) 457-5537 (916) 654-5036 [email protected] [email protected] For: California Large Energy Consumers Association (CLECA) For: CALIFORNIA ENERGY COMMISSION (CEC)

Reed V. Schmidt Karen Norene Mills BARTLE WELLS ASSOCIATES Attorney At Law 1889 ALCATRAZ AVENUE CALIFORNIA FARM BUREAU FEDERATION BERKELEY CA 94703 2300 RIVER PLAZA DRIVE (510) 653-3399 SACRAMENTO CA 95833 [email protected] (916) 561-5655 For: California City County Streetlight Association (CAL-SLA) [email protected] For: California Farm Bureau Federation

Marco Gomez Attorney At Law Ronald Liebert BAY AREA RAPID TRANSIT DISTRICT Attorney At Law 800 MADISON STREET, 5TH FLOOR CALIFORNIA FARM BUREAU FEDERATION OAKLAND CA 94607 2300 RIVER PLAZA DRIVE (510) 464-6058 SACRAMENTO CA 95833 [email protected] (916) 561-5657 For: Bay Area Rapid Transit District [email protected] For: California Farm Bureau Federation

Roger Berliner BERLINER, CANDON & JIMISON Ed Yates 1225 19TH STREET, N.W., SUITE 800 CALIFORNIA LEAGUE OF FOOD PROCESSORS WASHINGTON DC 20036 980 NINTH STREET, SUITE 230 (202) 955-6067 SACRAMENTO CA 95814 [email protected] (916) 444-9260 For: Internal Services Department of Los Angeles County (LACISD) [email protected] For: California League of Food Processors

A Brubaker BRUBAKER & ASSOCIATES, INC. Lisa G. Urick 1215 FERN RIDGE PARKWAY, SUITE 208 Attorney At Law ST. LOUIS MO 63141 CALIFORNIA POWER EXCHANGE CORPORATION (314) 275-7007 200 S. LOS ROBLES AVENUE, SUITE 400 [email protected] PASADENA CA 91101-2482 (626) 537-3328 For: Brubaker & Associates, Inc. [email protected] For: CALIFORNIA POWER EXCHANGE Jonathan M. Weisgall V.P. Legislative & Regulatory Affairs CALENERGY COMPANY, INC. Tom Smegal 1200 NEW HAMPSHIRE AVE., NW, SUITE 300 CALIFORNIA WATER SERVICE WASHINGTON DC 20036 1720 NORTH FIRST STREET - 2 - ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

(202) 828-1378 SAN JOSE CA 95112 [email protected] (408) 367-8235 [email protected] Fernando De Leon For: California Water Association Attorney At Law CALIFORNIA ENERGY COMMISSION 1516 9TH STREET, MS-14 SACRAMENTO CA 95814-5512 (916) 654-4873 [email protected] For: CALIFORNIA ENERGY COMMISSION

Jennifer Chamberlin Howard Choy CHEVRON ENERGY SOLUTIONS Energy Management Division Manager 345 CALIFORNIA ST., 32ND FLOOR COUNTY OF LOS ANGELES SAN FRANCISCO CA 94104 INTERNAL SERVICES DEPARTMENT (415) 733-4661 1100 NORTHEASTERN AVENUE [email protected] LOS ANGELES CA 90063 (323) 881-3939 For: Chevron Energy Solutions [email protected] For: COUNTY OF LOS ANGELES Theresa Mueller Deputy City Attorney CITY AND COUNTY OF SAN FRANCISCO Patrick Mcguire 1 DR. CARLTON B. GOODLETT PLACE TOM BEACH SAN FRANCISCO CA 94102 CROSSBORDER ENERGY (415) 554-4640 2560 NINTH STREET, SUITE 316 [email protected] BERKELEY CA 94710 (510) 649-9790 For: City & County of San Francisco [email protected] For: Watson Cogeneration Company Bill Mc Callum CITY OF FRESNO 5607 W. JENSEN AVENUE Tom Beach FRESNO CA 93607 CROSSBORDER ENERGY (559) 498-1728 2560 NINTH ST., SUITE 316 [email protected] BERKELEY CA 94710 (510) 649-9790 For: CITY OF FRESNO [email protected] For: Watson Cogeneration Company Frederick Ortlieb Deputy City Attorney CITY OF SAN DIEGO Treg Tremont 1200 THIRD AVENUE, 11TH FLOOR Attorney At Law SAN DIEGO CA 92101 DAVIS WRIGHT TREMAINE (619) 236-6220 ONE EMBARCADERO CENTER, SUITE 600 [email protected] SAN FRANCISCO CA 94111-3834 (415) 276-6500 For: CITY OF SAN DIEGO [email protected] For: Costco Wholesale Corporation John Tooker City Manager CITY OF YUCAIPA Lindsey How-Downing 34272 YUCAIPA BLVD. Attorney At Law

- 3 - ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

YUCAIPA CA 92399 DAVIS WRIGHT TREMAINE LLP (909) 797-2489 ONE EMBARCADERO CENTER, STE 600 SAN FRANCISCO CA 94111-3834 Bill Powers (415) 276-6500 CONGRESS OF CALIFORNIA SENIORS [email protected] 1228 N STREET, SUITE 29 For: CALPINE CORPORATION SACRAMENTO CA 95814 (916) 442-4474 [email protected] Edward W. O'Neill For: CONGRESS OF CALIFORNIA SENIORS Attorney At Law DAVIS WRIGHT TREMAINE, LLP ONE EMBARCADERO CENTER, STE 600 SAN FRANCISCO CA 94111-3834 (415) 276-6500 [email protected] For: El Paso Natural Gas Company

Howard Owens HOYT MINKOFF CONSUMER FEDERATION OF CALIFORNIA 1228 N STREET, SUITE 29 SACRAMENTO CA 95814 (916) 554-7621 [email protected] For: CONSUMER FEDERATION OF CALIFORNIA

Norman J. Furuta Douglas K. Kerner Attorney At Law Attorney At Law DEPARTMENT OF THE NAVY ELLISON, SCHNEIDER & HARRIS 900 COMMODORE DRIVE, BLDG. 107 2015 H STREET SAN BRUNO CA 94066-5006 SACRAMENTO CA 95814 (650) 244-2100 (916) 447-2166 [email protected] [email protected] For: Federal Executive Agencies For: Independent Energy Producers Association

Dan L. Carroll Diane Fellman Attorney At Law Attorney At Law DOWNEY BRAND SEYMOUR & ROHWER, LLP ENERGY LAW GROUP LLP 555 CAPITOL MALL, 10TH FLOOR 1999 HARRISON STREET, SUITE 2700 SACRAMENTO CA 95814 OAKLAND CA 94612-3572 (916) 441-0131 (510) 874-4301 [email protected] [email protected] For: CALIFORNIA INDUSTRIAL USERS For: PacificCrockett Energy, Inc.

Colin L. Pearce Andrew J. Skaff DUANE MORRIS & HECKSCHER Attorney At Law 100 SPEAR STREET, SUITE 1500 ENERGY LAW GROUP, LLP SAN FRANCISCO CA 94105 1999 HARRISON STREET, 27TH FLOOR (415) 371-2200 OAKLAND CA 94612 (510) 874-4330 - 4 - ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

[email protected] [email protected] For: Sacramento Municipal Utility District (SMUD) For: New York Mercantile Exchange/Dynegy, Inc.

Thomas M. Berliner Carolyn Kehrein Attorneys At Law ENERGY MANAGEMENT SERVICES DUANE MORRIS & HECKSCHER 1505 DUNLAP COURT 100 SPEAR STREET, SUITE 1500 DIXON CA 95620-4208 SAN FRANCISCO CA 94105 (707) 678-9586 (415) 371-2200 [email protected] [email protected] For: Energy Users Forum For: Sacramento Municipal Utility District

Patrick Mcdonnell Lynn M. Haug ENSERCH ENERGY SERVICES ANDY BROWN SUITE 290 Attorney At Law 711 GRAND AVENUE ELLISON & SCHNEIDER SAN RAFAEL CA 94901 2015 H STREET [email protected] SACRAMENTO CA 95814-3109 For: Enserch Energy Services (916) 447-2166 [email protected] For: East Bay Municipal Utility District (EBMUD)

Nancy Ryan Andrew B. Brown ENVIRONMENTAL DEFENSE Attorney At Law 5655 COLLEGE AVENUE ELLISON, SCHNEIDER & HARRIS OAKLAND CA 94618 2015 H STREET (510) 658-8008 SACRAMENTO CA 95814 (916) 447-2166 [email protected] For: Environmental Defense [email protected] For: CALIFORNIA DEPARTMENT OF GENERAL SERVICES (DGS)

James D. Squeri Kelly R. Tilton Attorney At Law Attorney At Law GOODIN MACBRIDE SQUERI RITCHIE & DAY LLP GRUENEICH RESOURCE ADVOCATES 505 SANSOME STREET, SUITE 900 582 MARKET STREET, SUITE 1020 SAN FRANCISCO CA 94111 SAN FRANCISCO CA 94104 (415) 392-7900 (415) 834-2300 [email protected] [email protected] For: California Retailers Association For: University of California/California State University

Jeanne M. Bennett Morten Henrik Greidung Attorney At Law HAFSLUND ENERGY TRADING, LLC GOODIN MACBRIDE SQUERI RITCHIE & DAY LLP 101 ELLIOT AVE., SUITE 510 505 SANSOME STREET, SUITE 900 SEATTLE WA 98119 SAN FRANCISCO CA 94111 (206) 436-0640 (415) 392-7900 [email protected] [email protected] For: HAFSLUND ENERGY TRADING, LLC For: Alliance for Retail Markets and Enron Corporation

James Hodges

Michael B. Day 4720 BRAND WAY Attorney At Law SACRAMENTO CA 95819 GOODIN MACBRIDE SQUERI RITCHIE & DAY LLP (916) 451-7011 505 SANSOME STREET, SUITE 900 [email protected] SAN FRANCISCO CA 94111-3133 For: TELACU and Maravilla Foundation (415) 392-7900 [email protected] For: ENRON ENERGY SERVICES, INC., ENRON NORTH Jan Smutny-Jones AMERICA Association INDEPENDENT ENERGY PRODUCERS Richard H. Counihan 1112 I STREET, STE. 380 GREENMOUNTAIN.COM SACRAMENTO CA 95814-2896 50 CALIFORNIA STREET, SUITE 1500 (916) 448-9499 SAN FRANCISCO CA 94111 [email protected] (415) 439-5310 [email protected] William B. Marcus For: GREEN MOUNTAIN ENERGY RESOURCES JBS ENERGY, INC. 311 D STREET, SUITE A WEST SACRAMENTO CA 95605 David L. Marshall (916) 372-0534 GREGG INDUSTRIES, INC. [email protected] 10460 HICKSON STREET For: TURN (EXPERT WITNESS) EL MONTE CA 91731 (626) 575-7664 [email protected] Norman A. Pedersen For: Gregg Industries, Inc. Esquire JONES DAY REAVES & POGUE 555 WEST FIFTH STREET, SUITE 4600 Irene K. Moosen LOS ANGELES CA 90013-1025 KELLY TILTON (213) 243-2810 GRUENEICH RESOURCE ADVOCATES [email protected] 582 MARKET STREET, SUITE 1020 For: Commonwealth Energy Corporation and Automated Power SAN FRANCISCO CA 94104-5305 Exchange Inc. & Frito Lay, Inc. (415) 834-2300 [email protected] For: Sonoma County Water Agency Bill Bishop JR. WOOD, INC. PO BOX 545 ATWATER CA 95301 (209) 358-5643 [email protected] For: Jr. Wood, Inc. and Manufacturers Council of the Central Valley (MCCV)

Kathleen Kiernan-Harrington William H. Booth JAMES WEIL Attorney At Law SUITE 200 LAW OFFICES OF WILLIAM H. BOOTH 720 MARKET STREET 1500 NEWELL AVENUE, 5TH FLOOR SAN FRANCISCO CA 94102 WALNUT CREEK CA 94596 (415) 781-5348 (925) 296-2460 [email protected] [email protected] For: GOLDEN GATE RESTAURANT ASSOCIATION For: California Large Energy Consumers Assn.

Daniel L. Rial Christopher A. Hilen KINDER MORGAN ENERGY PARTNERS Attorney At Law 1100 TOWN & COUNTRY ROAD LEBOEUF LAMB GREENE & MACRAE LLP ORANGE CA 92868 ONE EMBARCADERO CENTER, SUITE 400 (714) 560-4854 SAN FRANCISCO CA 94111 [email protected] (415) 951-1141 For: Kinder Morgan Energy Partners, SFPP, L.P., CALNEV [email protected] For: RELIANT ENERGY POWER GENERATION, INC.

Ron Knecht 1465 MARLBAROUGH AVENUE John W. Leslie LOS ALTOS CA 94024-5742 Attorney At Law (650) 968-0115 LUCE FORWARD HAMILTON & SCRIPPS, LLP [email protected] 600 WEST BROADWAY, SUITE 2600 SAN DIEGO CA 92101-3391 For: SELF (619) 699-2536 Thomas S. Knox [email protected] Attorney At Law For: SHELL ENERGY SERVICES, LLC KNOX, LEMMON & ANAPOCSKY, LLP ONE CAPITOL MALL, SUITE 700 SACRAMENTO CA 95814 Steven Moss (916) 498-9911 M.CUBED [email protected] 673 KANSAS STREET SAN FRANCISCO CA 94107 For: Leprino Foods (415) 643-9578 Susan E. Brown [email protected] Attorney At Law For: WESTERN MOBILHOME PARK ASSOCIATION LATINO ISSUES FORUM 785 MARKET STREET, 3RD FLOOR SAN FRANCISCO CA 94103-2003 David Huard (415) 284-7224 RANDALL KEEN [email protected] MANATT, PHELPS & PHILLIPS 11355 W. OLYMPIC BLVD For: LATINO ISSUES FORUM LOS ANGELES CA 90064 (310) 312-4247 C. Susie Berlin [email protected] Attorney At Law For: CALIFORNIA HEALTHCARE ASSOCIATION LAW OFFICES OF BARRY F. MC CARTHY 2105 HAMILTON AVENUE, SUITE 140 SAN JOSE CA 95125 Matthew V. Brady (408) 558-0950 Attorney At Law [email protected] MATTHEW V. BRADY & ASSOCIATES 300 CAPITOL MALL, SUITE 1100 For: NORTHERN CALIFORNIA POWER AGENCY SACRAMENTO CA 95814 (916) 442-5600 [email protected] For: Shasta Hydroelectric, Inc.

David J. Byers Scott T. Steffen Attorney At Law Attorney At Law MCCRACKEN, BYERS & HAESLOOP MODESTO IRRIGATION DISTRICT 840 MALCOLM ROAD, SUITE 100 1231 ELEVENTH STREET BURLINGAME CA 94010 MODESTO CA 95354 (650) 259-5979 (209) 526-7387 - 7 - ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

[email protected] [email protected] For: California City County Streetlight Association (CAL-SLA) For: MODESTO IRRIGATION DISTRICT (MID)

Terry J. Houlihan Diane E. Pritchard Attorney At Law Attorney At Law MCCUTCHEN DOYLE BROWN & ENERSEN LLP MORRISON & FOERSTER, LLP 3 EMBARCADERO CENTER, 18TH FLOOR 425 MARKET STREET SAN FRANCISCO CA 94111 SAN FRANCISCO CA 94105-2482 (415) 393-2022 (415) 268-7000 [email protected] [email protected] For: RELIANT ENERGY POWER GENERATION, INC. For: E&J Gallo Winery, The Wine Institute and the Agricultural Energy Consumers Association.

Patricia R. Williams Peter Hanschen MERVYN'S CALIFORNIA Attorney At Law 22301 FOOTHILL BOULEVARD MORRISON & FOERSTER, LLP HAYWARD CA 94541 425 MARKET STREET (510) 727-5905 SAN FRANCISCO CA 94105 [email protected] (415) 268-7214 For: Mervyn's/Target Stores Division of Dayton Hudson Corporation [email protected] For: Agricultural Energy Consumers Assn.

Jeffrey H. Goldfien Assistant City Attorney Sara Steck Myers MEYERS, NAVE, RIBACK, SILVER & WILSON Attorney At Law 777 DAVIS STREET, SUITE 300 122 28TH AVENUE SAN LEANDRO CA 94577 SAN FRANCISCO CA 94121 (510) 351-4300 (415) 387-1904 [email protected] [email protected] For: City of San Leandro For: CENTER FOR ENERGY EFFICIENCY AND RENEWABLE TECHOLOGIES (CEERT)

Christopher W. Reardon Richard Roos-Collins MFRS COUNCIL OF THE CENTRAL VALLEY Attorney At Law PO BOX 1564 NATURAL HERITAGE INSTITUTE MODESTO CA 95353 2140 SHATTUCK AVENUE, SUITE 500 (209) 523-0886 BERKELEY CA 94704-1222 [email protected] (510) 644-2900 For: Manufacturers Council of the Central Valley (MCCV) [email protected] For: California Hydropower Reform Coalition

Kevin R. Mcspadden Attorney At Law Janie Mollon MILBANK TWEED HADLEY & MCCLOY Manager Regulatory Affairs 601 SOUTH FIGUEROA, 30TH FLOOR NEW WEST ENERGY LOS ANGELES CA 90017 PO BOX 61868 (213) 892-4563 PHOENIX AZ 85082-1868 [email protected] (602) 629-7758 For: MILBANK, TWEED, HADLEY & MC CLOY [email protected] For: NEW WEST ENERGY

Jose E. Guzman, Jr. Don Schoenbeck Attorney At Law RCS CONSULTING, INC.

NOSSAMAN GUTHNER KNOX & ELLIOTT LLP 900 WASHINGTON STREET, SUITE 1000 50 CALIFORNIA STREET, 34TH FLOOR VANCOUVER WA 98660 SAN FRANCISCO CA 94111-4799 (360) 737-3877 (415) 398-3600 [email protected] [email protected] For: Coalinga Cogenerator For: Cargill Corporation

James Ross Christine Ferrari RCS CONSULTING, INC. Depurty City Attorney 500 CHESTERFIELD CENTER, SUITE 320 OFFICE OF THE CITY ATTORNEY CHESTERFIELD MO 63017 CITY HALL ROOM 234 (636) 530-9544 1 DR. CARLTON B. GOODLETT PLACE [email protected] SAN FRANCISCO CA 94102-4682 For: Midway Sunset Cogeneration (415) 554-4634 [email protected] Steven Greenberg Joseph M. Malkin REALENERGY Attorney At Law 300 CAPITOL MALL, SUITE 300 ORRICK, HERRINGTON & SUTCLIFFE LLP SACRAMENTO CA 95814 400 SANSOME STREET (916) 325-2500 SAN FRANCISCO CA 94111-3143 [email protected] (415) 773-5505 For: RealEnergy [email protected] For: THE AES CORPORATION Keith Sappenfield RELIANT ENERGY RETAIL, INC. PO BOX 1409 William H. Edwards HOUSTON TX 77251-1409 KELLY M. MORTON, JAMES L. LOPES (713) 207-5570 PACIFIC GAS AND ELECTRIC CO. [email protected] 77 BEALE STREET For: Reliant Energy Retail, Inc. PO BOX 7442, RM 3115-B30A SAN FRANCISCO CA 94120-7442 (415) 973-2768 Randy Britt [email protected] ROBINSONS-MAY For: PG&E 6160 LAUREL CANYON BLVD. NORTH HOLLYWOOD CA 91606 Peter Ouborg (818) 509-4777 Attorney At Law [email protected] PACIFIC GAS AND ELECTRIC COMPANY For: Robinsons-May PO BOX 770000 SAN FRANCISCO CA 94177 (415) 973-2286 Arlin Orchard [email protected] Attorney At Law For: Pacific Gas and Electric Company SACRAMENTO MUNICIPAL UTILITY DISTRICT PO BOX 15830, MAIL STOP-B406 SACRAMENTO CA 95852-1830 Patrick J. Power (916) 732-5830 Attorney At Law [email protected] 1300 CLAY STREET, SUITE 600 For: Sacramento Municipal Utility District OAKLAND CA 94612 (510) 446-7742 [email protected] Dana S. Appling For: City of Long Beach; Universal Studios Inc. General Counsel SACRAMENTO MUNICIPAL UTILITY DISTRICT LEGAL DEPARTMENT MSB406 - 9 - ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

PO BOX 15830 SACRAMENTO CA 95852-1830 (916) 732-6126

Phillip J. Muller Beth A. Fox SCD ENERGY SOLUTIONS Attorney At Law 436 NOVA ALBION WAY SOUTHERN CALIFORNIA EDISON COMPANY SAN RAFAEL CA 94903 2244 WALNUT GROVE AVENUE (415) 479-1710 ROSEMEAD CA 91770 [email protected] (626) 302-6897 For: Southern Company Energy Marketing [email protected] For: SOUTHERN CALIFORNIA EDISON COMPANY (SCE)

Jeffrey M. Parrott LYNN G. VAN WAGENEN James P. Shotwell Attorney At Law Attorney At Law SEMPRA ENERGY SOUTHERN CALIFORNIA EDISON COMPANY 101 ASH STREET 2244 WALNUT GROVE AVE., ROOM 337 SAN DIEGO CA 92101-3017 ROSEMEAD CA 91770-0001 (619) 699-5063 (626) 302-4531 [email protected] [email protected] For: San Diego Gas & Electric Company For: SOUTHERN CALIFORNIA EDISON COMPANY (SCE)

Judy Young James C. Paine Attorney At Law Attorney At Law SEMPRA ENERGY STOEL RIVES LLP 555 W. 5TH STREET, M.L.G.T. 14E7 900 S.W. FIFTH AVENUE, STE 2600 LOS ANGELES CA 90013 PORTLAND OR 97204-1268 (213) 244-2955 (503) 294-9246 [email protected] [email protected] For: Southern California Gas Company For: PacifiCorp

James Bushee Keith W. Melville SUTHERLAND, ASBILL & BRENNAN DAVID R. CLARK 1275 PENNSYLVANIA AVENUE Attorney At Law WASHINGTON DC 20004 SEMPRA ENERGY (202) 383-0100 101 ASH STREET [email protected] SAN DIEGO CA 92101-3017 For: CALIFORNIA MANUFACTURERS ASSOCIATION (CMA) (619) 699-5039 [email protected] For: San Diego Gas & Electric Company Keith Mc Crea Attorney At Law SUTHERLAND, ASBILL & BRENNAN LLC Andrew Chau 1275 PENNSYLVANIA AVENUE, N.W. Attorney At Law WASHINGTON DC 20004-2415 SHELL ENERGY SERVICES COMPANY, L.L.C. (202) 383-0705 1221 LAMAR STREET, SUITE 1000 [email protected] HOUSTON TX 77010 For: CALIFORNIA MANUFACTURERS & TECHNOLOGY ASSN. (713) 241-8939 [email protected]

Justin D. Bradley SILICON VALLEY MANUFACTURING GROUP - 10 - ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

226 AIRPORT PARKWAY, SUITE 190 Gene L. Waas SAN JOSE CA 95110 THE CALIFORNIA POWER EXCHANGE (408) 501-7852 1000 SOUTH FREMONT BUILDING A9 WEST [email protected] ALHAMBRA CA 91803 (626) 537-3326 For: Silicon Valley Manufacturing Group [email protected] For: The California Power Exchange

Chris Witteman Bernardo R. Garcia THE GREENLINING INSTITUTE UTILITY WORKERS UNION OF AMERICA,AFL-CIO 785 MARKET STREET, 3RD FLOOR PO BOX 5198 SAN FRANCISCO CA 94103-2003 OCEANSIDE CA 92052-5198 (415) 284-7202 (949) 369-9936 [email protected] [email protected] For: THE GREENLINING INSTITUTE For: Utility Workers Union of America, AFL-CIO

Denis George Jerry Bloom Energy Manager MARGARET ROSTKER (EMAIL: THE KROGER COMPANY ROSTKMA@LAWHITE 1014 VINE STREET Attorney At Law CINCINNATI OH 45202 WHITE & CASE (513) 762-4538 TWO EMBARCADERO CENTER, SUITE 650 [email protected] SAN FRANCISCO CA 94111 For: The Kroger Company (415) 544-1104 [email protected] For: California Cogeneration Council Peter Bray THE NEW POWER COMPANY 101 CALIFORNIA STREET, SUITE 1950 Jason J. Zeller SAN FRANCISCO CA 94111 Legal Division (415) 782-7810 RM. 5002 [email protected] 505 VAN NESS AVE For: The New Power Company San Francisco CA 94102 (415) 703-4673 [email protected] Matthew Freedman For: Office of Ratepayer Advocates Attorney At Law THE UTILITY REFORM NETWORK 711 VAN NESS AVENUE, SUITE 350 ********** STATE EMPLOYEE *********** SAN FRANCISCO CA 94102 (415) 929-8876 Truman L. Burns [email protected] Office of Ratepayer Advocates For: The Utility Reform Network (TURN) RM. 4209 505 VAN NESS AVE San Francisco CA 94102 Robert Finkelstein (415) 703-2932 Attorney At Law [email protected] THE UTILITY REFORM NETWORK For: OFFICE OF RATEPAYER ADVOCATES 711 VAN NESS AVENUE, SUITE 350 SAN FRANCISCO CA 94102 (415) 929-8876 X-301 Michael W. Neville [email protected] Attorney At Law

For: The Utility Reform Network (TURN) CALIFORNIA ATTORNEY GENERAL'S OFFICE 455 GOLDEN GATE AVENUE, SUITE 11000 SAN FRANCISCO CA 94102-7004 Michael Shames (415) 703-5523 Attorney At Law [email protected] UTILITY CONSUMERS' ACTION NETWORK For: CALIFORNIA RESOURCES AGENCY 1717 KETTNER BLVD., SUITE 105 SAN DIEGO CA 92101-2532 (619) 696-6966 Jennifer Tachera [email protected] Attorney At Law For: Utility Consumers' Action Network (UCAN) CALIFORNIA ENERGY COMMISSION 1516 NINTH STREET, MS-14 SACRAMENTO CA 95814-5504 (916) 654-3870 [email protected]

Lorenzo Kristov Robert Miyashiro CALIFORNIA ENERGY COMMISSION DEPT. OF FINANCE 1516 9TH ST., MS-22 STATE CAPITOL, RM 1145 SACRAMENTO CA 95814 SACRAMENTO CA 95814 (916) 654-4773 (916) 445-8610 [email protected] [email protected] For: California Energy Commission For: DEPT. OF FINANCE (DOF)

Monica Schwebs Christopher Danforth Attorney At Law Office of Ratepayer Advocates CALIFORNIA ENERGY COMMISSION RM. 4101 1516 NINTH STREET, MS-14 505 VAN NESS AVE SACRAMENTO CA 95814-5512 San Francisco CA 94102 (916) 654-5207 (415) 703-1481 [email protected] [email protected] For: Office of Ratepayer Advocates Ruben Tavares Electricity Analysis Office CALIFORNIA ENERGY COMMISSION Joseph R. DeUlloa 1516 9TH STREET, MS 20 Administrative Law Judge Division SACRAMENTO CA 95814 RM. 5105 (916) 654-5171 505 VAN NESS AVE [email protected] San Francisco CA 94102 (415) 703-3124 For: California Energy Commission [email protected]

Roderick A. Campbell Pamela Durgin Office Of Governmental Affairs Energy Division CALIFORNIA PUBLIC UTILITIES COMMISSION RM. 4-A 770 L STREET, STE 1050 505 VAN NESS AVE SACRAMENTO CA 95814 San Francisco CA 94102 (916) 327-1418 (415) 703-1124 [email protected] [email protected]

Sean F. Casey Robert T. Feraru Office of Ratepayer Advocates Public Advisor Office RM. 4205 RM. 5303

505 VAN NESS AVE 505 VAN NESS AVE San Francisco CA 94102 San Francisco CA 94102 (415) 703-1667 (415) 703-2074 [email protected] [email protected] For: Office of Ratepayer Advocates For: Public Advisor's Office

Jim O'Brien Faline Fua DEPARTMENT OF WATER RESOURCES Energy Division 1416 9TH STREET, ROOM 1118 AREA 4-A SACRAMENTO CA 94236 505 VAN NESS AVE (916) 653-8816 San Francisco CA 94102 [email protected] (415) 703-2481 For: Department of Water Resources [email protected]

Julie Halligan Donald J. Lafrenz Executive Division Energy Division RM. 5215 AREA 4-A 505 VAN NESS AVE 505 VAN NESS AVE San Francisco CA 94102 San Francisco CA 94102 (415) 703-3491 (415) 703-1063 [email protected] [email protected] For: Energy Division Audra Hartmann Legal Division Steve Linsey 770 L STREET, SUITE 1050 Office of Ratepayer Advocates Sacramento CA 95814 RM. 4101 (916) 327-1417 505 VAN NESS AVE [email protected] San Francisco CA 94102 (415) 703-1341 Kayode Kajopaiye [email protected] Energy Division For: Office of Ratepayer Advocates AREA 4-A 505 VAN NESS AVE San Francisco CA 94102 Jeanette Lo (415) 703-2557 Energy Division [email protected] AREA 4-A 505 VAN NESS AVE For: Energy Division San Francisco CA 94102 (415) 703-1825 Dexter E. Khoury Office of Ratepayer Advocates [email protected] RM. 4205 For: Energy Division 505 VAN NESS AVE San Francisco CA 94102 Kim Malcolm (415) 703-1200 Executive Division [email protected] RM. 5115 505 VAN NESS AVE For: Office of Ratepayer Advocates San Francisco CA 94102 (415) 703-1926 Robert Kinosian [email protected] Office of Ratepayer Advocates RM. 4209 Anne W. Premo 505 VAN NESS AVE Energy Division San Francisco CA 94102 AREA 4-A

(415) 703-1500 505 VAN NESS AVE [email protected] San Francisco CA 94102 (415) 703-1247 For: Office of Ratepayer Advocates [email protected] For: CPUC ENERGY DIVISION Laura L. Krannawitter Executive Division RM. 5210 Steve Roscow 505 VAN NESS AVE Energy Division San Francisco CA 94102 AREA 4-A (415) 703-2538 505 VAN NESS AVE [email protected] San Francisco CA 94102 (415) 703-1189 [email protected]

Steven C Ross Rosalina White Office of Ratepayer Advocates Public Advisor Office RM. 4102 RM. 5303 505 VAN NESS AVE 505 VAN NESS AVE San Francisco CA 94102 San Francisco CA 94102 (415) 703-2140 (415) 703-2074 [email protected] [email protected]

Randy Chinn John S. Wong SENATE ENERGY COMMITTEE Administrative Law Judge Division ROMM 408 RM. 5019 STATE CAPITOL 505 VAN NESS AVE SACRAMENTO CA 95814 San Francisco CA 94102 [email protected] (415) 703-3130 [email protected] Linda Serizawa Executive Division ********* INFORMATION ONLY ********** RM. 5119 505 VAN NESS AVE Tom O'Neill San Francisco CA 94102 Vice President (415) 703-1383 ABN AMRO INCORPORATED [email protected] EQUITY RESEARCH ONE CALIFORNIA STREET, SUITE 200 SAN FRANCISCO CA 94111 Maria E. Stevens (415) 983-2901 Executive Division RM. 500 [email protected] 320 WEST 4TH STREET SUITE 500 Los Angeles CA 90013 David Marcus (213) 576-7012 ADAMS BROADWELL & JOSEPH [email protected] PO BOX 1287 BERKELEY CA 94701-1287 (510) 528-0728 Zenaida G. Tapawan-Conway Energy Division [email protected] AREA 4-A For: Coalition of California Utility Employees 505 VAN NESS AVE San Francisco CA 94102 (415) 703-2624 Ira Schoenholtz

[email protected] President AMERICAN ASSN OF BUSINESS PERSONS W/DIS 2 WOODHOLLOW Maria Vanko IRVINE CA 92604-3229 Energy Division (949) 559-1516 AREA 4-A For: American Association of Business Persons with Disabilities 505 VAN NESS AVE San Francisco CA 94102 (415) 703-2818 Edward G. Poole [email protected] Attorney At Law For: Energy Division ANDERSON & POOLE 601 CALIFORNIA STREET, SUITE 1300 Christine M. Walwyn SAN FRANCISCO CA 94108 Administrative Law Judge Division (415) 956-6413 RM. 5101 [email protected] 505 VAN NESS AVE For: INDEPENDENT OIL PRODUCERS AGENCY (IOPA) San Francisco CA 94102 (415) 703-2301 [email protected]

Robert E. Anderson J. A. Savage APS ENERGY SERVICES CALIFORNIA ENERGY MARKETS 1500 FIRST AVENUE 3006 SHEFFIELD AVENUE ROCHESTER MN 55906 OAKLAND CA 94602-1545 (507) 289-0800 (510) 534-9109 [email protected] [email protected] For: APS ENERGY SERVICES For: California Energy Markets

Ed Cazalet Lulu Weinzimer AUTOMATED POWER EXCHANGE, INC. CALIFORNIA ENERGY MARKETS 5201 GREAT AMERICA PARKWAY 9 ROSCOE STREET SANTA CLARA CA 95054 SAN FRANCISCO CA 94110-5921 (408) 517-2900 (415) 824-3222 [email protected] [email protected] For: Automated Power Exchange, Inc. William Dombrowski CALIFORNIA RETAILERS ASSOCIATION Scott Blaising 980 9TH STREET, SUITE 2100 Attorney At Law SACRAMENTO CA 95814-2741 8980 MOONEY ROAD (916) 443-1975 ELK GROVE CA 95624 (916) 682-9702 Alexandre B. Makler [email protected] CALPINE CORPORATION 6700 KOLL CENTER PARKWAY, SUITE 200 PLEASANTON CA 94566 Paul A. Harris (925) 600-2081 BRIDGE NEWS 44 MONTGOMERY, SUITE 2410 [email protected] SAN FRANCISCO CA 94104 For: CALPINE CORPORATION (415) 835-7641 [email protected] Susannah Churchill For: BRIDGE NEWS Energy Advocate

CALPIRG Mona Patel 926 J ST. 523 BROWN & WOOD LLP SACRAMENTO CA 95814 555 CALIFORNIA STREET, 50TH FLOOR (916) 448-4516 SAN FRANCISCO CA 94104 [email protected] (415) 772-1265 For: CALPIRG [email protected] Douglas L. Anderson Stephen Layman Vice President And General Counsel CALIFORNIA ENERGY COMMISSION, EIAD CE GENERATION, L.L.C. 1516 9TH STREET, MS-20 302 SOUTH 36TH STREET, SUITE 400 SACRAMENTO CA 95814 OMAHA NE 68131 (916) 654-4845 [email protected] J. Patrick Tang JOHN A. RUSSO/BARBARA J. PARKER Deputy City Attorney Derk Pippin CITY OF OAKLAND CALIFORNIA ENERGY MARKETS ONE FRANK OGAWA PLAZA 6TH FLOOR 9 ROSCOE STREET OAKLAND CA 94612 SAN FRANCISCO CA 94110-5921 (510) 238-6523 (415) 824-3222 [email protected] [email protected] For: CALIFORNIA ENERGY MARKETS (CEM)

John A. Barthrop Gregory T. Blue General Counsel Manager, State Regulatory Affairs COMMONWEALTH ENERGY CORP. DYNEGY, INC. 15991 RED HILL AVENUE, NO. 201 5976 W. LAS POSITAS BLVD., STE. 200 TUSTIN CA 92780 PLEASANTON CA 94588 (714) 258-0470 (925) 469-2355 [email protected] [email protected] For: Commonwealth Energy Corp. For: Dynegy, Inc.

Joseph A. Young Angela Oh EAST BAY MUNICIPAL UTILITY DISTRICT Advisor 375 ELEVENTH STREET, ROOM MS 205 COMMUNITY TECHNOLOGY POLICY COUNCIL OAKLAND CA 94607 PMB 7000-639 (510) 287-0147 REDONDO BEACH CA 90277 [email protected] June M. Skillman Wendy Illingworth COMPLETE ENERGY SERVICES, INC. ECONOMIC INSIGHTS 650 E. PARKRIDGE AVENUE, UNIT 110 320 FEATHER LANE CORONA CA 92879 SANTA CRUZ CA 95060 (909) 280-9411 (831) 427-2163 [email protected] [email protected] Maria Crispi Jon S. Silva 22 SOUTH PARK, ROOM 320 Government Affairs Associate SAN FRANCISCO CA 94107 EDISON SOURCE (415) 882-1663 955 OVERLAND COURT SAN DIMAS CA 91773 Carl K. Oshiro (909) 450-6035 Attorney At Law

CSBRT/CSBA [email protected] 100 FIRST STREET, SUITE 2540 SAN FRANCISCO CA 94105 Susan A. Huse (415) 927-0158 Research Analyst [email protected] EES CONSULTING, INC. For: CALIFORNIA SMALL BUSINESS ASSOCIATION AND 12011 BEL-RED ROAD, SUITE 200 CALIFORNIA SMALL BUSINESS ROUNDTABLE BELLEVUE WA 98005-2471 (425) 452-9200 Nicole A. Tutt [email protected] DUANE MORRIS & HECKSCHER 100 SPEAR STREET, SUITE 1500 Jeffrey D. Harris SAN FRANCISCO CA 94105 Attorney At Law (415) 371-2200 ELLISON & SCHNEIDER [email protected] 2015 H STREET SACRAMENTO CA 95814-3105 Joseph M. Paul (916) 447-2166 DYNEGY MARKETING & TRADE [email protected] 5976 WEST LAS POSITAS BLVD., STE. 200 For: Sacramento Municipal Utility District PLEASANTON CA 94588 (925) 469-2314 [email protected] Gary B. Ackerman FOOTHILL SERVICES, INC. 340 AUGUST CIRCLE MENLO PARK CA 94025 [email protected] For: Western Power Trading Forum

Robert D. Schasel Karen Lindh FRITO-LAY, INC. LINDH & ASSOCIATES 7701 LEGACY DRIVE (4C-101) 7909 WALERGA ROAD, ROOM 112, PMB 119 PLANO TX 75024-4099 ANTELOPE CA 95843 (972) 334-7000 (916) 729-1562 [email protected] [email protected] For: California Manufacturers Assn. H. Bradley Donovan Senior Vice President GEORGE WEISS ASSOCIATES, INC. Richard J. Mccann 660 MADISON AVENUE, 16TH FLOOR M.CUBED NEW YORK NY 10021-8405 2655 PORTAGE BAY, SUITE 3 (212) 415-4567 DAVIS CA 95616 [email protected] (530) 757-6363 [email protected] Douglas E. Davie HENWOOD ENERGY SERVICES, INC. Candace A. Younger 2710 GATEWAY OAKS DRIVE, STE. 300 NORTH MANATT, PHELPS & PHILLIPS, LLP SACRAMENTO CA 95833 11355 WEST OLYMPIC BOULEVARD (916) 569-0985 LOS ANGELES CA 90064 [email protected] (310) 312-4000 [email protected] Jeffrey D. Schlichting HMH RESOURCES, INC. Randall W. Keen 100 LARKSPUR LANDING, SUITE 213 MANATT, PHELPS & PHILLIPS, LLP

LARKSPUR CA 94939 11355 WEST OLYMPIC BLVD. (415) 289-4080 LOS ANGELES CA 90064 [email protected] (310) 312-4000 [email protected] Joelle Ogg JOHN & HENGERER Linda R. Beck 1200 17TH STREET, NW, STE 600 MCDONOUGH, HOLLAND & ALLEN WASHINGTON DC 20036 1999 HARRISON STREET, STE 1300 (202) 429-8812 OAKLAND CA 94612 [email protected] (510) 839-9104 For: City of Paso Robles Joaquin Herrera L. A. COUNTY PUBLIC WORKS Christopher J. Mayer TRAFFIC AND LIGHTING DIVISION MODESTO IRRIGATION DISTRICT PO BOX 1460 PO BOX 4060 ALHAMBRA CA 91802-1460 MODESTO CA 95352-4060 [email protected] (209) 526-7430 [email protected] Ralph Smith For: MODESTO IRRIGATION DISTRICT (MID) LARKIN & ASSOCIATES, INC. 15728 FARMINGTON ROAD LIVONIA MI 48154 Robert B. Weisenmiller (734) 522-3420 MRW & ASSOCIATES [email protected] 1999 HARRISON STREET, SUITE 1440 For: Larkin & Associates, Inc. OAKLAND CA 94612-3517 (510) 834-1999 [email protected] For: MRW & Associaes

Gary Herbert Bruce Bowen MSDW Mailcode B10a ONE TOWER BRIDGE, 11TH FLOOR PACIFIC GAS AND ELECTRIC COMPANY WEST CONSHOHOCKEN PA 19428 PO BOX 770000 (610) 940-4524 SAN FRANCISCO CA 94177 [email protected] [email protected]

Melanie Gillette Dan Pease NAVIGANT CONSULTING INC PACIFIC GAS AND ELECTRIC COMPANY 3100 ZINFANDEL DRIVE, SUITE 600 MAILCODE B10B RANCHO CARDOVA CA 95670 PO BOX 70000 (916) 852-1300 SAN FRANCISCO CA 94177 [email protected] [email protected]

Kay Davoodi Ed Lucha NAVY RATE INTERVENTION OFFICE PACIFIC GAS AND ELECTRIC COMPANY WASHINGTON NAVY YARD MAIL CODE: B9A 1314 HARWOOD STREET SE PO BOX 770000 WASHINGTON NAVY YARD DC 20374-5018 SAN FRANCISCO CA 94177 (202) 685-0130 (415) 973-3872 [email protected] [email protected] For: Navy Rate Intervention Janice Frazier-Hampton

PACIFIC GAS AND ELECTRIC COMPANY Martin Mattes MAIL CODE B9A Attorney At Law PO BOX 770000 NOSSAMAN GUTHNER KNOX & ELLIOTT, LLP SAN FRANCISCO CA 94177 50 CALIFORNIA STREET, 34TH FLOOR (415) 973-2254 SAN FRANCISCO CA 94111-4799 [email protected] (415) 438-7273 [email protected] Joe Migocki PACIFIC GAS AND ELECTRIC COMPANY Eve Mitchell 77 BEALE STREET, MAIL CODE B9A OAKLAND TRIBUNE SAN FRANCISCO CA 94105-1890 401 13TH ST. (415) 973-1332 OAKLAND CA 94612 [email protected] (510) 208-6474 [email protected] Niels Kjellund PACIFIC GAS AND ELECTRIC COMPANY Jonathan Jacobs MAIL CODE 859A PA CONSULTING GROUP PO BOX 770000 75 NOVA DRIVE SAN FRANCISCO CA 94177 PIEDMONT CA 94610-1037 [email protected] (510) 654-9495 [email protected] Roger J. Peters For: PA CONSULTING GROUP PACIFIC GAS AND ELECTRIC COMPANY MAIL CODE B30A PO BOX 7442 Gail L. Slocum SAN FRANCISCO CA 94120 Attorney At Law [email protected] PACIFIC GAS AND ELECTRIC CO. 77 BEALE ST. RM 3143 SAN FRANCISCO CA 94105 (415) 973-6583 [email protected]

Ron Helgens Michael Bazeley PACIFIC GAS AND ELECTRIC COMPANY SAN JOSE MERCURY NEWS MAIL CODE B9A 111 ELLIS STREET, 3RD FLOOR PO BOX 770000 SAN FRANCISCO CA 94102 SAN FRANCISCO CA 94177 (415) 434-1018 (415) 973-7524 [email protected] [email protected] James E. Hay Roxanne Piccillo SEMPRA ENERGY PACIFIC GAS AND ELECTRIC COMPANY 101 ASH STREET - H.Q. 14B MAILCODE B10B SAN DIEGO CA 92101-3017 PO BOX 70000 (619) 696-2141 SAN FRANCISCO CA 94177 [email protected] [email protected] For: Sempra

George A. Perrault Kimberly Freeman 1813 FAYMONT AVENUE SEMPRA ENERGY MANHATTAN BEACH CA 90266 601 VAN NESS AVENUE, SUITE 2060 (310) 379-0901 SAN FRANCISCO CA 94102 [email protected] (415) 202-9983 [email protected] Henry Moore

PETERSON RISK CONSULTING, LLC Leslie Katz 4/1 1 MARKET STREET, SUITE 1300 Regional Vp-Regulatory Affairs SAN FRANCISCO CA 94105 SEMPRA ENERGY (415) 393-0588 601 VAN NESS AVENUE, SUITE 2060 [email protected] SAN FRANCISCO CA 94102 (415) 202-9986 Jean Pierre Batmale [email protected] REALENERGY For: sempra 1900 AVENUE OF THE STARS, 755 LOS ANGELES CA 90067 Lynn G. Van Wagenen (310) 203-2976 Regulatory Affairs Project Manager [email protected] SEMPRA ENERGY 101 ASH STREET, ROOM 10A SAN DIEGO CA 92101 Carrie Peyton (619) 696-4055 SACRAMENTO BEE PO BOX 15779 [email protected] SACRAMENTO CA 95852 For: Sempra Energy (916) 321-1086 [email protected] G. Darryl Reed SIDLEY & AUSTIN 10 S. DEARBORN Tim Haines CHICAGO IL 60603 SACRAMENTO MUNICIPAL UTILITY DISTRICT (312) 853-7766 PO BOX 15830 SACRAMENTO CA 95852-1830 [email protected] (916) 732-6342 For: SIDLEY & AUSTIN [email protected] For: Sacramento Municipal Utility District Bruce Foster Regulatory Affairs SOUTHERN CALIFORNIA EDISON COMPANY 601 VAN NESS AVENUE, SUITE 2040 SAN FRANCISCO CA 94102 (415) 775-1856 [email protected]

Frank J. Cooley Bill C. Wells SOUTHERN CALIFORNIA EDISON COMPANY Lt. Col. 2244 WALNUT GROVE AVENUE TYNDALL AFB ROSEMEAD CA 91770 139 BARNES DRIVE, SUITE 1 (626) 302-3115 TYNDALL AFB FL 32403-5319 [email protected] (850) 283-6347 For: SOUTHERN CALIFORNIA EDISON COMPANY (SCE) [email protected] For: AIR FORCE LEGAL SERVICES AGENCY

Peter S. Goeddel SOUTHERN CALIFORNIA EDISON COMPANY Sam Wise PO BOX 800 4045 PALOS VERDES DR. NORTH 2244 WALNUT GROVE AVENUE, SUITE 321 ROLLING HILLS ESTATES CA 90274 ROSEMEAD CA 91770 (310) 377-1577 (626) 302-3104 For: SOUTHERN CALIFORNIA EDISON

Stephen E. Pickett RONALD L. OLSON - 20 - ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

Attorney At Law SOUTHERN CALIFORNIA EDISON COMPANY 2244 WALNUT GROVE AVENUE ROSEMEAD CA 91770 (626) 302-1903 [email protected]

Charles C. Read Attorney At Law STEPTOE & JOHNSON, LLP 1330 CONNECTICUT AVENUE, N.W. WASHINGTON DC 20036 (202) 429-6244 [email protected]

Peter Fox-Penner, Ph.D. THE BRATTLE GROUP 1133 20TH STREET NW, SUITE 800 WASHINGTON DC 20036 (202) 955-5050 [email protected]

Tony Wetzel THERMO ECOTEK CORPORATION 1100 MELODY LANE, SUITE 206 ROSEVILLE CA 95678 (916) 773-2940 [email protected] For: THERMO ECOTEK CORPORATION

Fred Wesley Monier TURLOCK IRRIGATION DISTRICT PO BOX 949 333 EAST CANAL DRIVE TURLOCK CA 95381-0949 (209) 883-8321 [email protected]

(END OF APPENDIX A)

APPENDIX B

PACIFIC GAS AND ELECTRIC PROPOSED RATES ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

Billing Determinants Current Total Current Revenue New Total New Rates Customer Group (kWh) Rate ($/kWh) Revenue Increase Revenue $/kWh

E-1 Energy Smr Tier 1 6,743,661,372 $0.12589 $848,959,530 Tier 2 4,786,100,707 $0.14321 $685,417,482 Winter Tier 1 7,085,095,391 $0.12589 $891,942,659 Tier 2 4,752,592,916 $0.14321 $680,618,831

0% to 100% Baseline Tier 1 13,828,756,763 $0.12589 $1,740,902,189 $1,740,902,189 $0.12589 100% to 130% Baseline Tier 2 2,533,865,376 $0.14321 $362,874,860 $362,874,860 $0.14321 130% to 200% Baseline Tier 3 3,686,054,464 $0.14321 $527,879,860 $105,575,972 $633,455,832 $0.17185 200% to 300% Baseline Tier 4 2,098,985,131 $0.14321 $300,595,661 $120,238,264 $420,833,925 $0.20049 Over 300% Baseline Tier 5 1,219,788,651 $0.14321 $174,685,933 $190,428,430 $365,114,363 $0.29933

Discounts, Credits & Nonalloc. Revenue ($3,398,220,915) ($291,282,413)

Total 23,367,450,386 kWh $2,815,656,090 $416,242,666 $3,231,898,756

EL-1 Energy Smr Tier 1 728,352,160 $0.09812 $71,465,914 $71,465,914 $0.09812 Tier 2 260,969,916 $0.11284 $29,447,845 $29,447,845 $0.11284 Winter Tier 1 693,690,541 $0.09812 $68,064,916 $68,064,916 $0.09812 Tier 2 239,382,784 $0.11284 $27,011,953 $27,011,953 $0.11284

0% to 100% Baseline Tier 1 1,422,042,701 $0 100% to 200% Baseline Tier 2 400,083,059 $0 n/a Tier 3 - $0 200% to 300% Baseline Tier 4 74,567,902 $0 Over 300% Baseline Tier 5 25,701,739 $0

Discounts, Credits & Nonalloc. Revenue ($27,870,617) ($27,870,617)

Total 1,922,395,400 kWh $168,120,011 $0 $168,120,011

E-7 Energy Smr On Peak 85,099,696 $0.32524 $27,677,825 $10,211,963 $37,889,788 $0.44524 Off Peak 481,411,229 $0.09515 $45,806,278 $18,819,249 $64,625,527 $0.13424 Wtr Part Peak 94,181,097 $0.12636 $11,900,723 $4,709,055 $16,609,778 $0.17636 Off Peak 538,319,039 $0.09851 $53,029,808 $21,043,879 $74,073,688 $0.13760

Smr Tier 1 Credit 228,479,417 ($0.01559) ($3,561,537) ($9,139,177) ($12,700,714) ($0.05559) Smr Tier 2 Credit 61,170,261 $0.00000 $0 ($2,446,810) ($2,446,810) ($0.04000) Wtr Tier 1 Credit 277,608,105 ($0.01559) ($4,327,355) ($11,104,324) ($15,431,679) ($0.05559) Wtr Tier 2 Credit 68,295,591 $0.00000 $0 ($2,731,824) ($2,731,824) ($0.04000)

0% to 100% Baseline Tier 1 506,087,522 100% to 130% Baseline Tier 2 129,465,853 130% to 200% Baseline Tier 3 229,081,544 200% to 300% Baseline Tier 4 184,012,818 Over 300% Baseline Tier 5 150,363,324 Discounts, Credits & Nonalloc. Revenue ($8,301,108) ($8,301,108) Total 1,199,011,059 kWh $122,224,635 $29,362,011 $151,586,646

EL-7 Energy Smr On Peak 1,140,406 $0.31524 $359,502 $359,502 $0.31524 Off Peak 5,395,901 $0.08515 $459,461 $459,461 $0.08515 Wtr On Peak 1,141,183 $0.11636 $132,788 $132,788 $0.11636 Off Peak 6,168,357 $0.08851 $545,961 $545,961 $0.08851

Smr Tier 1 Credit 3,649,646 ($0.01732) ($63,212) ($63,212) ($0.01732) Wtr Tier 1 Credit 4,401,935 ($0.01732) ($76,242) ($76,242) ($0.01732)

0% to 100% Baseline Tier 1 8,050,526 100% to 200% Baseline Tier 2 1,560,538 n/a Tier 3 - 200% to 300% Baseline Tier 4 2,713,368 Over 300% Baseline Tier 5 1,521,415

Discounts, Credits & Nonalloc. Revenue ($95,859) ($95,859)

Total 13,845,847 kWh $1,262,400 $0 $1,262,400 $1,262,400

E-8 Energy Smr 1,108,352,630 $0.13017 $144,274,262 $144,274,262 $0.13017 ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

APPENDIX C

SOUTHERN CALIFORNIA EDISON PROPOSED RATES ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

Revenue New Total 2001 Sales Current Total Total Revenue Increase Revenue Rate Group Forecast Rate ($MM) ($MM) ($MM) New Rate

Residential NON-CARE Energy Charges - ¢/kWh Baseline 11,799.1 13.01 $1,534.9 $1,534.9 13.01 130 % of Baseline 2,372.5 15.16 $359.6 $359.6 15.16 130% - 200% of BL 3,615.3 15.16 $548.0 $65.5 $613.5 16.97 200% - 300% of BL 2392.4 15.16 $362.6 $108.5 $471.1 19.69 Over 300% of BL 2,082.5 15.16 $315.6 $189.3 $504.9 24.25 Fixed Charges Single Family Basic Charge - $/month 21,027,996 1.00 $21.0 $21.0 Multi. Family Basic Charge - $/month 18,782,674 0.76 $14.3 $14.3 Total NON-CARE 22,261.8 14.18 $3,156.1 $363.3 $3,519.4 15.81

CARE Energy Charges - ¢/kWh Baseline 1,837.9 10.14 $186.4 $186.4 10.14 130 % of Baseline 278.5 11.97 $33.3 $33.3 11.97 130% - 200% of BL 331.0 11.97 $39.6 $39.6 11.97 Over 200% of BL 209.1 11.97 $25.0 $25.0 11.97 Fixed Charges Single Family Basic Charge - $/month 3,160,669 0.85 $2.7 $2.7 Multi. Family Basic Charge - $/month 2,823,180 0.65 $1.8 $1.8 Total CARE 2,656.5 10.87 $288.9 $0.0 $288.9 10.87

Total Residential 24,918.4 13.83 $3,445.0 $363.3 $3,808.3 15.28

Small & Med. Commercial GS-1 Energy Charges - ¢/kWh Summer 1,767.7 12.76 $225.6 $155.7 $381.2 21.57 Winter 3,184.2 12.76 $406.3 $66.7 $473.0 14.86 Fixed Charges Customer Charge - $/month 5,127,373 14.60 $74.9 $74.9 Total GS-1 4,952.0 14.27 $706.7 $222.4 $929.1 18.76

TC-1 Energy Charges - ¢/kWh Energy 186.2 7.49 $13.9 $8.4 $22.3 11.98 Fixed Charges Customer Charge - $/month 156,930 10.65 $1.7 $1.7 Total TC-1 186.2 8.38 $15.6 $8.4 $24.0 12.88

GS-2 Energy Charges - ¢/kWh 1st Tier 19,565.6 8.69 $1,700.6 $587.0 $2,287.6 11.69 2nd Tier 4,902.5 5.39 $264.3 $511.8 $776.1 15.83 Fixed Charges Customer Charge - $/month 1,413,115 60.30 $85.2 $85.2 Facility-Related - $/kW 80,039 5.40 $432.2 $432.2 Time-Related - $/kW 27,521 7.75 $213.3 $213.3 Total GS-2 24,468.1 11.02 $2,695.6 $1,098.8 $3,794.4 15.51

TOU-GS-2 (Option B) Energy Charges - ¢/kWh Summer - On Peak 44.3 15.90 $7.0 $6.5 $13.5 30.54 Mid Peak 69.4 7.61 $5.3 $3.1 $8.4 12.10 Off-Peak 142.1 5.27 $7.5 $5.0 $12.4 8.76 Winter - Mid Peak 201.5 8.81 $17.8 $9.0 $26.8 13.30 Off-Peak 308.1 5.27 $16.2 $10.8 $27.0 8.76 Fixed Charges Customer Charge - $/month 27,723 79.25 $2.2 $2.2 Facility-Related - $/kW 2,737 5.40 $14.8 $14.8 Time-Related (On Peak) - $/kW 777 16.40 $12.7 $12.7 Time-Related (Mid Peak) - $/kW 884 2.45 $2.2 $2.2 Total TOUGS-2B 765.4 11.20 $85.7 $34.4 $120.1 15.69

Total Small & Med. Commercial 30,371.5 11.54 $3,503.7 $1,363.9 $4,867.6 16.03 ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

Large Power TOU-8-Sec Current Structure Summer - On Peak 716.5 10.49 $75.1 $76.6 $151.7 21.17 Mid Peak 949.3 6.99 $66.3 $42.6 $109.0 11.48 Off-Peak 1,433.7 4.81 $69.0 $50.0 $119.0 8.30 Winter - Mid Peak 2,785.3 8.34 $232.2 $125.1 $357.3 12.83 Off-Peak 3,005.7 4.93 $148.0 $104.9 $252.9 8.42 Fixed Charges Customer Charge - $/month 29,937 298.65 $8.9 $8.9 Facility-Related - $/kW 22,038 6.40 $141.0 $141.0 Time-Related (On Peak) - $/kW 7,213 17.55 $126.6 $126.6 Time-Related (Mid Peak) - $/kW 7,458 2.80 $20.9 $20.9 Total TOU-8-Sec 8,890.5 9.99 $888.1 $399.2 $1,287.3 14.48

TOU-8-Pri (Includes special contracts sales) Energy Charges - ¢/kWh Summer - On Peak 542.1 10.42 $56.5 $65.6 $122.1 22.52 Mid Peak 768.4 6.85 $52.6 $34.5 $87.1 11.34 Off-Peak 1,324.0 4.76 $63.0 $46.2 $109.2 8.25 Winter - Mid Peak 2,189.1 8.07 $176.7 $98.3 $275.0 12.56 Off-Peak 2,799.9 4.87 $136.5 $97.7 $234.2 8.36 Fixed Charges Customer Charge - $/month 10,438 299.00 $3.1 $3.1 Facility-Related - $/kW 15,833 6.60 $104.5 $104.5 Time-Related (On Peak) - $/kW 5,107 17.95 $91.7 $91.7 Time-Related (Mid Peak) - $/kW 5,404 2.70 $14.6 $14.6 Total TOU-8-Pri 7,623.3 9.17 $699.1 $342.3 $1,041.5 13.66

TOU-8-Sub (Includes special contracts sales) Energy Charges - ¢/kWh Summer - On Peak 481.2 8.40 $40.4 $70.6 $111.0 23.07 Mid Peak 752.9 6.05 $45.6 $33.8 $79.4 10.54 Off-Peak 1,540.0 4.76 $73.2 $53.8 $127.0 8.25 Winter - Mid Peak 2,196.8 7.09 $155.8 $98.7 $254.5 11.58 Off-Peak 3,360.2 4.87 $163.7 $117.3 $281.0 8.36 Fixed Charges Customer Charge - $/month 2,226 349.45 $0.8 $0.8 Facility-Related - $/kW 13,879 0.65 $9.0 $9.0 Time-Related (On Peak) - $/kW 3,621 16.15 $58.5 $58.5 Time-Related (Mid Peak) - $/kW 4,118 2.45 $10.1 $10.1 Total TOU-8-Sub 8,331.1 6.69 $557.1 $374.1 $931.2 11.18

Total Large Power 24,844.9 8.63 $2,144.3 $1,115.7 $3,260.0 13.12 ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

Agriculture & Pumping PA-1 Energy Charges - ¢/kWh 679.4 10.17 $69.1 $28.2 $97.3 14.33 Fixed Charges Customer Charge - $/month 277,602 17.65 $4.9 $4.9 Connected Load - $/HP 9,795 2.05 $20.1 $20.1 Total PA-1 679.4 13.85 $94.1 $28.2 $122.3 18.00

PA-2 Energy Charges - ¢/kWh 1st Tier 452.4 9.12 $41.3 $4.5 $45.8 10.12 2nd Tier 257.0 6.09 $15.7 $15.9 $31.6 12.30 Fixed Charges Customer Charge - $/month 24,243 30.35 $0.7 $0.7 Facility-Related - $/kW 2,220 2.25 $5.0 $5.0 Time-Related - $/kW 754 7.40 $5.6 $5.6 Total PA-2 709.4 9.62 68.2 $20.5 $88.7 12.51

AG-TOU (Option B) Energy Charges - ¢/kWh Summer - On Peak 104.7 12.23 $12.8 $8.4 $21.2 20.27 Mid Peak 138.7 8.26 $11.5 $3.8 $15.3 11.03 Off-Peak 209.5 4.95 $10.4 $3.7 $14.1 6.72 Winter - Mid Peak 317.5 9.50 $30.2 $8.8 $39.0 12.27 Off-Peak 342.6 4.95 $17.0 $6.1 $23.0 6.72 Fixed Charges Customer Charge - $/month 44,002 42.80 $1.9 $1.9 Facility-Related - $/kW 3,487 2.85 $9.9 $9.9 Time-Related (On Peak) - $/kW 1,016 9.00 $9.1 $9.1 Total AG-TOU (Option B) 1,112.9 9.23 $102.7 $30.8 $133.5 12.00

TOU-PA-5 Energy Charges - ¢/kWh Summer - On Peak 43.0 8.95 $3.8 $4.4 $8.2 19.11 Mid Peak 61.0 6.14 $3.7 $1.5 $5.2 8.58 Off-Peak 105.1 5.28 $5.6 $1.5 $7.1 6.72 Winter - Mid Peak 177.7 7.02 $12.5 $4.3 $16.8 9.46 Off-Peak 227.4 5.92 $13.5 $3.3 $16.7 7.36 Fixed Charges Customer Charge - $/month 13,465 40.70 $0.5 $0.5 Facility-Related - $/kW 1,946 2.85 $5.5 $5.5 Time-Related (On Peak) - $/kW 521 9.00 $4.7 $4.7 Total TOU-PA-5 614.1 8.12 $49.9 $15.0 $64.8 10.56

Total Agriculture & Pumping 3,115.9 10.11 $314.9 $94.5 $409.4 13.14

Street and Area Lighting Street Light Summary Energy Charges - ¢/kWh AllNight Service 529.2 6.04 $32.0 $23.8 $55.7 10.53 Mid Night Service 0.1 6.37 $0.0 $0.0 $0.0 10.86 Fixed Charges Customer Charge - $/month 117,906 $/month-variable $2.3 $2.3 Estimated # of Lamps 694,921 $/lamp-variable $43.9 $43.9 Total Street Light 529.3 14.77 $78.2 $23.8 $101.9 19.26

TOTAL SYSTEM 83,780.0 11.32 $9,486.0 $2,961.2 $12,447.2 14.86 ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028

APPENDIX D Page 1

Public Participation Hearings Summary

A wide range of views were expressed at the PPHs by approximately 450 speakers. Customers ranged from individual residential customers to chambers of commerce, other business organizations, social service agencies, activists for various philosophies, and advocates for all forms of electricity generation and conservation. For residential customers, the biggest concerns were over their ability to cope with the rising rates, and the impact on their families’ budgets. They also pointed out the difficulty of achieving usage within baseline levels. Many questioned how baseline levels were set, indicating that they were never able to get close to baseline usage, irrespective of how much they felt they conserved. They also felt that the baseline levels were outdated and should not be used as a benchmark for spreading the surcharge. Some also believed that the CARE discount should be increased. Many residential customers also felt that assigning more of the rate increase to commercial and industrial customers would not effectively shield them from it because these businesses would simply raise prices for their products. Members of the clergy and representative of social service organizations expressed great concern for both the impacts on the poor and their own ability to provide for them. The impacts of rolling blackouts in extremely warm climate areas as well as rate increases were of concern. Representatives of handicapped persons, particularly those that must rely on intensive electricity using products such as life support APPENDIX D Page 2 ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028 devices, electric battery chargers for wheelchairs, as well as in home care persons suggested that such customers should be exempt from the increase. Small business owners decried the imposition of a substantial portion of the rate increase on their businesses. These business owners cautioned against imposing a heavy burden on business because they now have narrow margins, which could be eliminated by this increase. They also predicted that overall prices would increase, and California would no longer be able to successfully compete in the global economy. Agricultural interests were very concerned with both pricing issues and the impacts of rolling blackouts. Representatives of cold storage facilities indicted that prolonged outages could lead to food spoilage on a massive scale. Some suggested that if sufficient advance knowledge of outages was available, they could move stock to another facility to avoid the blackout. This was particularly a problem in the Edison territory where customers are not yet aware of their outage block numbers. Growers themselves complained bitterly about the impact that higher rates would have on their pumping and other costs, driving up their cost of production. As one grower said, expenses are set locally but prices we get are set globally. If their costs rise sufficiently they may not be able to market their crops. Many came not to speak about the rate changes themselves, but to express dismay or anger at the energy crises and question how the Commission and the legislature could have let such a debacle occur. Some APPENDIX D Page 3 offered their own theories of how various interests had created the crisis but most were just frustrated with such a huge crises that they felt powerless to deal with. They advised the Commission and Governor to courageously lead the state, to ************ SERVICE LIST *********** Last Update on 04-MAY-2001 by: SMJ A0011038 LIST A0011056/A0010028 investigate manipulation of energy prices, and to take strong steps to bring California power plants back under regulatory control. Speakers were also incensed with the short notice they received of the PPHs, some less than 48 hours. Greater frustration was expressed that their comments would not be considered by the Commission or affect the ultimate decision. Finally there were current and former employees of PG&E and Edison who discussed both personal impacts from the loss of their stock values and upset at the demise of two utilities that had previously been so well run.

(END OF APPENDIX D)