Before the Public Utilities Commission of the State of California

Application of PACIFIC GAS AND ELECTRIC COMPANY To Edentify Separate Components of Electric Services Industry and Rates, Effective January 1, 1998.
                (Electric)            (U 39 E)

A.96-12-009

Application of SAN DIEGO GAS AND ELECTRIC COMPANY (U 902-M) For authority to Unbundle Rates and Products. | A.96-12-011
In the Matter Of The Application Of SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) Proposing The Functional Separation Of Cost Components For Energy, Transmission and Ancillary Services, Distribution, Public Benefit Programs and Nuclear Decommissioning, To Be Effective January 1, 1998 In Conformance with D.95-12-036 As Modified by D.96-01-009, the June 21, 1996 Ruling of Assigned Commission Duque, Decision 96-10-074, and Assembly Bill 1890. | A.96-12-019

CONCURENT OPENING BRIEF OF THE
OFFICE OF RATEPAYER ADVOCATES

CATHERINE A. JOHNSON
Staff Counsel

Attorney for the Office of Ratepayer Advocates

California Public Utilities Commission
505 Van Ness Ave.
San Francisco, CA 94102
Phone: (415) 703-1385
April 30, 1997	Fax: (415) 703-4432

Table of Contents

TABLE OF AUTHORITIES
I. Introduction	
II. Scope and Objectives of Proceeding	
A. Principles for Unbundling Should Promote Effective Competition	
B. The Adopted Level of Unbundling Should Allow Industry Structure to Evolve	
III. Separation of Revenue Requirement	
A. Comments Common to All Applicants	
1. Functional Unbundling Should Not Be Confused With Cost Recovery.	
2. Balancing Account Treatment Should Be Consistent With the Electric Restructuring Policy Against Creating Competitive Advantages For The Utilities.	
3. Franchise Fees And Uncollectibles Should Be Allocated Between Generation And Non-generation Functions.	
4. The Commission Should Reject the Utilities’ Recommendation to Allocate All Common (Residual) Costs to the Distribution Function.	
a) The Commission Correctly Has Rejected the “Incremental Cost” or “Residual Cost” Approach in Allocating Embedded Revenue Requirement Between Utilities’ Regulated and Competitive (Non-regulated) Businesses.	
b) The Companies Should Not Be Permitted To Increase The Cost Of Transmission And Distribution By Loading Those Regulated Functions With The Share Of Current Common Costs That Would Reasonably Be Allocated To Generation.	
c) Common Costs Should Not Be Confused With Fixed Costs.  Common Costs Need To Be Allocated Across Functions To Establish The Revenue Requirements For Transmission And Distribution At The Moment Of Unbundling, But They Are Not Unchangeable In The Face Of Reuced Scope.	
5. The Utilities’ Residual Approach to Separate Transmission Revenue From Distribution Revenue (or Rate) Should Be Rejected.	
B. PG&E	
1. PG&E’s Transition Revenue Account Should Be Rejected	
C. SCE	
1. Existing Generation-related Balancing Accounts Should Be Eliminated As Soon As Appropriate.	
D. SDG&E	
1. SDG&E’s Proposal To Allocate Production (Generation) O&M Costs To The Non-Generation Functions Is To Ask The Regulated Business To Subsidize Its Competitive Business And Should Be Rejected.	
2. SDG&E’s Distribution Revenue Requirement Is Overstated.	
IV. Revenue Allocation and Rate Design	
A. Comments Common to All Applicants	
1. Revenue Allocation	
a) ORA supports SCE’s Proposed Revenue Allocation Methodology for Transmission and Distribution	
b) Revenue Allocation for Public Purpose Programs, California Alternate Rates for Energy (CARE) and Nuclear Decommissioning/ Incremental Cost Incentive Price (ICIP) Should Consider Both CPUC Precedents and Functional Activity	
2. Functionalized Components of Rate Design Should Maintain Existing CPUC Polices	
3. Rate Design for Competition Transition Charge, Direct Access and Virtual Direct Access Should Promote the Commission’s Restructuring Goals and Result in Appropriate Price Signals	
4. Settlement Protocols Are Critical to Market Functioning and Accurate Cost Allocations	
5. ORA Supports PG&E and SDG&E’s Proposals for Baseline and CARE Rates	
6. Implementation of the AB 1890 Rate Reduction Should Promote Options for Small Customers	
7. Non-Firm Rate Programs Require Further Discussion	
8. Line Extension Rules Should Rely on Current Rules Until Changed in the Line Extension OIR	
B. PG&E	
C. SCE	
1. Real Time Pricing Must Be Continued During Restructuring and RTP and Flexible Pricing Options Can Be Adapted to the New Industry Structure	
2. Implementation of Rate Reduction Bonds Should Promote Customer Choice	
3. SCE’s Base Rate vs. ECAC Seasonal Rate Adjustment Should Be Adjusted to the New Industry Structure	
D. SDG&E	
1. SDG&E’s CTC Cost Allocation May Require Further Consideration	
2. SDG&E’s Implementation of Rate Reduction Bonds Is Contrary to Commission Policy	
V. Master Meter Issues	
VI. Bill Format	
A. Comments Common to All Applicants	
1. Rate Reduction Bond Credit Proposals Are Acceptable	
2. Power Exchange Energy Prices Must Be Shown On Bills	
3. Other Information Should Also Be Provided	
B. PG&E	
C. SDG&E	
D. SCE	
APPENDIX A
CERTIFICATE OF SERVICE

Before the Public Utilities Commission of the State of California

Application of PACIFIC GAS AND ELECTRIC COMPANY To Edentify Separate Components of Electric Services Industry and Rates, Effective January 1, 1998.
                (Electric)            (U 39 E)

A.96-12-009

Application of SAN DIEGO GAS AND ELECTRIC COMPANY (U 902-M) For authority to Unbundle Rates and Products. | A.96-12-011
In the Matter Of The Application Of SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) Proposing The Functional Separation Of Cost Components For Energy, Transmission and Ancillary Services, Distribution, Public Benefit Programs and Nuclear Decommissioning, To Be Effective January 1, 1998 In Conformance with D.95-12-036 As Modified by D.96-01-009, the June 21, 1996 Ruling of Assigned Commission Duque, Decision 96-10-074, and Assembly Bill 1890. | A.96-12-019

CONCURENT OPENING BRIEF OF THE
OFFICE OF RATEPAYER ADVOCATES

The Office of Ratepayer Advocates (ORA) of the California Public Utilities Commission (Commission) pursuant to the Commission’s Rules of Practice and Procedure and the briefing schedule adopted by the Administrative Law Judge respectfully submits its Concurrent Opening Brief on the unbundling of major rate components for electric industry restructuring.
I.	Introduction 
This opening brief summarizes the recommendations of the Commission’s Office of Ratepayer Advocates (ORA) in response to the December 6, 1996, Ratesetting applications of Pacific Gas and Electric Company (PG&E), San Diego Gas and Electric Company (SDG&E), and Southern California Edison Company (SCE) (Collectively, “Applicants”).
ORA’s testimony addresses overall principles for functional separation of revenue requirements, allocation of functionalized revenues among customer classes, and rate design and related issues. The utilities have described their revenue allocation and rate design calculations as illustrative for example, SCE states that it plans to submit its final 1998 rates in late 1997 by Advice Filing following resolution of more basic issues in the appropriate proceedings. (Ex. 12, p. 3) Similarly, ORA has responded to the utilities’ filings on a policy level on several issues, and plans to analyze and comment on the utilities’ detailed calculations when such calculations are presented during the later tariff phase of this proceeding, as identified in the Commission’s “Roadmap II” Decision 96-12-088.
II.	Scope and Objectives of Proceeding
The Commission’s policy decision on electric industry restructuring endorses unbundling traditional utility services into generation, transmission, and distribution functions. (D.95-12-063, mimeo, p. 84.) Additionally, the Commission provides its view that (1) generation is an activity remitted to a competitive market in which utility and nonutility entrants and participants will vie for customer allegiance; (2) transmission retains the attributes of a natural monopoly and will be consolidated, from an operational perspective, in the Independent System Operator (ISO), and (3) distribution is a natural monopoly with respect to serving those customers who do not opt for self-generation or construct transmission and distribution facilities to serve their consumption.,  (D.96-01-009, mimeo, pp. 93-94.) It is in response to these policy directions that the three utilities filed their unbundling proposals in this proceeding to separate the “embedded revenue requirement”  among certain functions for ratemaking purposes. (Ex. 41, p. 2.) The most significant aspect of the separation of embedded revenues is that these three functions face a different degree of competition. 
Separating the revenue requirement into functional rate components may be viewed as a series of three tasks:
1.	The total revenue requirement is allocated to functions. This includes both direct assignments of costs to specific functions, and allocation of shared or common costs among functions.
2.	Each function's revenue requirement is allocated to customer classes.
3.	Rates are designed to recover the revenue requirement assigned to the class. In some cases, rate design also includes the specification of rules and protocols for the implementation of rates. (Ex. 41, pp.1-2.)
ORA’s overarching policy recommendation is that, whenever possible, the Commission should seek consistency among the utilities in the ratemaking methodologies involved in accomplishing the above tasks. Some direct cost allocations and some rate design issues may be affected by utility-specific ratemaking structures. However, the Commission should seek uniformity in applying cost allocation principles to determine direct cost allocation, the allocation of common costs, revenue allocation, generic rate design issues, and most aspects of the billing and settlement processes. Differences in ratemaking treatment have been acceptable in the past even on issues that exist for all utilities. With statewide competition, however, the impact of ratemaking issues for each utility will no longer be limited to its service area. Consistency among utilities with respect to rules and protocols for ratemaking (but not necessarily the tariffed rates themselves) will be much more important than in the past. (Ex. 41, p. 2.)
A.	Principles for Unbundling Should Promote Effective Competition
To unbundle the total revenue requirement, the Commission should apply accepted cost allocation principles. First, direct cost assignment should be maximized (Ex. 12, Appendix C, p.7; Ex. 1, p. 2A-3, Ex. 53, p. 1.). Second, cost assignment should avoid subsidizing the utility’s competitive business at the expense of its regulated business. (Ex. 53, p. 1.) Therefore, the Commission should reject the utilities’ attempt to allocate generation-related costs to non-generation or distribution functions. These points are discussed further in Section III, below.
In addition, the Commission can find guidance for unbundling the electric utilities’ revenue requirements in its established policies for other industries, particularly telecommunications. PG&E has attempted to use certain telecommunications pricing principles, known as total service long run incremental cost (TSLRIC), to support its proposal. However, there is an important difference between telecommunications and the initial years of electric industry restructuring. As the three applicants acknowledge, the purpose of the functional unbundling filings before the Commission is to unbundle the “embedded revenue requirement” among certain functions that are being separated for ratemaking purposes as part of electric industry restructuring. That is, in this proceeding the Commission is unbundling an embedded revenue requirement among functions, whereas the Commission was not constrained by a revenue requirement cap in the telecommunications industry. In determining the allocation of embedded revenue requirement between regulated and competitive businesses, the Commission directs the utilities to apply a fully allocated cost methodology and rejects an incremental cost or residual cost approach. (D.89-10-031, mimeo, pp. 205-207.) Consequently, the utilities’ proposals to use the incremental or residual cost approach here should be rejected as inconsistent with Commission policy. This issue is discussed further in Section III below.
It should be noted that PG&E’s reference to TSLRIC principles fails to reflect the history of the telecommunications unbundling proceeding (R.93-04-003/I.93-04-002). Although the Commission has agreed that in TSLRIC studies, the cost studies themselves should not include overhead or common costs, the Commission has intended to address how common costs should be reflected in rates. In fact, part of Principle 5 states: “Recognition of such [overhead] costs will be treated as a pricing issue”. (D.95-12-016, mimeo Appendix C, p.4.) Further, in D.96-08-021 (mimeo, p. 21), the Commission stated: “we will allow parties to litigate in the hearings the extent to which shared family costs should be included in price floors.” Thus, for the telecommunications industry , the Commission has taken a two step approach to setting prices, (a) the review of cost studies to identify directly attributable costs and (b) litigation for common costs. PG&E has only focused on the cost study portion. 
PG&E cites the costing principles adopted in the Commission’s proceeding on unbundling telecommunications services in its justification for allocating residual shared cost to transmission and distribution (T&D), but is selective in its citation.  It cites two costing principles adopted in D.95-12-016: these are Principle 2, which states that the basic principle of cost causation is that only those costs that are caused by a cost object in the long run should be directly attributable to that cost object; and Principle 5, which states that TSLRIC studies of individual services shall exclude overheads that are not demonstrated to be caused by the cost object. (PG&E Ex. 1, App.2A, pp. 8-9) 
Lastly, even based on PG&E’s selective interpretation of telecommunications costing principles (that cost studies of individual services should exclude overheads that are not caused by the cost object), common cost should not be allocated to T&D either, because overhead costs are not caused by T&D any more than they are caused by generation.
Consequently, the unbundling proposals in this proceeding don't have a direct link with TSLRIC principles. The result of applying TSLRIC at this time, in the manner proposed by PG&E, is potentially anti-competitive because it reduces the administrative and general (A&G) expenses associated with PG&E’s generation services. (Ex. 41, p. 2) Firms that are considering entering new markets, such as California’s new generation market, will decide to undertake their new business functions based on an analysis of the risks of making such investments, including the long-term implications of expanding their business operations, and including increases in common costs. Such firms would commonly have several alternative new ventures that they might enter into, will often have a fixed amount of investment capability for entering those lines of work, and will only enter the generation business if they see opportunities for achieving an internal rate of return comparable to their other lines of business. For a new competitor in the generation market, shareholders will be totally at risk, with no regulatory assurances about revenue collection or ability to compete as a monopoly in any of its markets. Regulated utilities don’t have that kind of exposure. (13 RT 1699-1701, 1718-1721) CLECA/ CMA’s witness provided similar testimony, and observed that although a competitive business looks at incremental costs when deciding whether to enter markets, and would periodically discount to incremental cost in order to gain market share, it would not stay in business in a market if it could only charge incremental cost. (15 RT 1844) 
Methodologies from the telecommunications industry are worthy of exploring in the longer term as the electric industry is restructured. This includes analyzing unbundled functions as a series of “building blocks” that, in total, comprise utility service. Crediting approaches are a practical way to functionalize the utilities’ revenue requirements expeditiously in this proceeding. However, in the context of Assembly Bill (AB) 1890’s rate freeze, the result includes a “distribution” function that would more properly be described as a “Utility Distribution Company” (UDC) function because it includes a wide variety of activities, instead of just being a Wires Company. AB 1890’s rate freeze transition period provides ample opportunity to apply the rigorous TSLRIC methodology to functionalize utility service among non-competitive, semi-competitive, and fully competitive functions.
B.	The Adopted Level of Unbundling Should Allow Industry Structure to Evolve
In somewhat varying forms, several intervenors (AECA, Ex. 46, p. 3; CEC, Ex. 55, pp. 14-17; CLECA, Ex. 73, p. 10; TURN/UCAN, Ex. 63, pp. 1-10 and Ex. 49) recommend separating the utilities’ customer service functions from their Wires Company functions in the near term for purposes of cost allocation and rate design, similar to ORA’s recommendations (discussed above) to accomplish this over the course of the transition period. ORA’s Exhibit 41 simply noted that the utilities’ cost allocations would produce a category in this proceeding that would be better called “UDC” functions than “distribution”, but ORA has no objection to adopting a more refined approach in the near term, as recommended by these intervenors.  Noting that the intervenor testimony on separation of customer service functions (a) generally brings up broader needs for a ratesetting structure that can avoid cross-subsidization between utility functions, and (b) does not necessarily require the unbundled functions to be subject to competition, ORA’s Exhibit 42 reiterated points made earlier in its December 20, 1996, comments on revenue cycle unbundling to form a near-term basis for the longer-term examination of unbundling that ORA has recommended.
CLECA’s testimony (Ex. 73, p. 10) attributes the basis for this aspect of its recommended cost allocation to CPUC Decision 96-10-074.  D.96-10-074 raises questions similar to ones listed in an Assigned Commissioner’s Ruling (ACR) issued May 8, 1996, by Commissioner Duque (among other events in the CPUC’s electric restructuring proceedings), which stated:
“In order for this Commission to set distribution rates, utilities’ current costs must be unbundled or disaggregated into several components and allocated to each of the three functional areas of generation, transmission, and distribution. Because the accounting definitions vary across utilities and some accounts include costs for more than one functional area, the first step in unbundling costs requires the functional identification of each cost category and account. This identification allows the completion of the next step of assigning these costs to one of the three functional areas of generation, transmission, and distribution. This process will develop rules to assign all activities to one of the three functional areas. How should the Commission identify the functional nature of current activities to achieve an effective unbundling which can respond to an evolving interpretation of FERC’s definition of transmission service?”,
and
“The vertically integrated utility undertakes many activities which have no unique relationship to any of the three functional areas [generation, transmission or distribution]. As the most prominent example, the utility undertakes administrative and general activities with substantial fixed and variable costs to manage its operations. Other examples include customer service and support, meter reading and billing as well as regulatory activities.”
Noting the ACR’s recognition that these costs do not fit neatly into any of the broader unbundling categories and consequent request for the parties to consider the most appropriate way to allocate these costs across the three functional areas, D.96-10-074 observes that instead, some parties have proposed including some of these non-unique charges as distribution costs. (Mimeo, p. 9.) D.96-10-074 agrees with the distinctions suggested by Commissioner Duque and expresses concern that the approach taken by some parties may have skewed the debate. (Ibid.)
ORA agrees with the Commission that while these costs need to be allocated among functions as electric industry restructuring proceeds, they do not fit neatly in either the generation, transmission, or distribution functions. In fact, in the ratemaking processes of marginal cost analysis, revenue allocation, and rate design, the Commission has always included the revenue cycle costs as a distinctive utility function:  a customer access-related component. ORA’s Exhibit 42 concludes that if allocations must be made simply between generation, transmission, and distribution, incremental needs for customer services expenses are related to the generation function and therefore should be assigned to it.  Recognizing a separate customer service function will allow the Commission to be more accurate, though, in its cost assignments, and to begin to differentiate the costs of competitive services.
Whereas discussions of electric industry restructuring have commonly used terms like GenCo, TransCo, LineCo, and Wires Company, Exhibit 42 distinguishes between natural monopoly and competitive functions of the UDC by using the term “Wires Company” to refer to the monopoly functions of the UDC, and coining the term “ServiceCo” to refer to its competitive functions. (This proposed distinction is not meant necessarily to separate yet another business unit at this time, but rather to establish a basis for cost allocation.) Services that are not part of the Wires business can become competitive (i.e., are not natural monopolies) and should be assigned to the ServiceCo function, instead of the UDC’s Wires Company function.
If revenue cycle unbundling is approved, for example by adoption of ALJ Weissman’s proposed decision of February 14, 1997, the UDC’s costs of providing competitive services should be credited on retail customers’ payment responsibility to the Wires Company, and charged to customers by whichever ServiceCo provides the service to the customer; this would be considered in a later phase of this proceeding. This rate design structure would be appropriate because the CPUC must avoid double-charging for costs that are necessarily provided by ESPs and no longer provided by the UDC. (Ex. 42, p. 4.)
An initial basis for distinguishing revenue assignments between ServiceCo and the Wires Company can be found in the testimony of TURN/UCAN’s witness Marcus (Ex. 63) and CLECA/CMA’s witness Yap (Ex. 73, Table 1, and Ex. 75). In particular, TURN identifies components of revenue requirement, such as marketing, that should be removed from rates, because they correspond to activities that can be taken over by competitors, or made subject to refund. (For example, Ex. 63, TURN/ Marcus, e.g., p. 10) If the Commission finds it needs additional clarity in revenue assignments beyond that provided in these exhibits, ORA recommends that further input can be obtained during the tariff phase of this proceeding.
III.	Separation of Revenue Requirement
A.	Comments Common to All Applicants
1.	Functional Unbundling Should Not Be Confused With Cost Recovery.
The utilities generally claim that they attributed costs to the segments in a very detailed manner such that direct cost assignment could be maximized and the use of allocation could be minimized. (Ex. 12, Appendix C, p.7; Ex. 1, p. 2A-3.) On the surface, this can appear to follow the cost allocation principle that cost should be directly assigned whenever possible. However, the utilities also apply an over-riding principle, namely guaranteed cost recovery, which derails the allocation process. As a result, some of the generation costs are assigned to the non-generation or distribution function.  For instance, SCE called for establishment of a Miscellaneous Adjustment Mechanism (MAM) to recover many of its generation-related costs, such as SONGS 1 shutdown O&M, hydro pumped storage, etc., through the non-PBR component of the distribution rates. (Ex. 12, SCE/Letizia, pp.21-22.) SDG&E decided to follow suit and requested recovery of a total of $14,258,000 through its proposed MAM balancing account. (6 RT 848.) SDG&E’s witness testified that the company had not sought transition cost recovery for these MAM account costs in the CTC proceeding and noted that the only way to assure full recovery of such costs is to functionalize such costs as “distribution-related” instead of generation-related. (6 RT 848.) A PG&E witness expressed the same notion:
“Q: Am I correct in summing up your position on this to say that with respect to certain costs, whether or not they are functionally related to generation, the Commission ought to include them in a revenue adjustment proceeding account or some sort of collection account and allow PG&E to recover them through non-generation rates so as to ensure their recovery or to make more likely their recovery?
A:  That’s correct, for the purposes of continuing the commitment that was made at the time that mechanism was established.”  (5 RT 594.)
As ORA has stated, when a cost can be assigned to a function by direct assignment, then that cost should  be allocated accordingly. (Ex. 53, p. 1.) CLECA/CMA appropriately point out that though the CPUC authorized recovery of these generation-related costs, it does not guarantee recovery of them. (Ex.73, p. 12.) The utilities have presented no evidence to demonstrate that the generation costs they have assigned to the distribution function are different from the other generation costs which are assigned to the generation function and which will be recovered through PX or CTC rates. When given an example of SDG&E’s setting up a MAM for its SONGS 2&3, SDG&E’s witness, Swanson, admitted that he is not aware that the authorization for full recovery of that cost for SONGS 2&3 is any different from past Commission authorizations for any other component of SDG&E’s generation assets.  (7 RT, 895-896.)  Mr. Swanson also suggested that these MAM account costs can be treated as CTC if the Commission rejects its MAM proposal. (6 RT 850.) ORA agrees with CLECA and other intervenors that the costs included in the MAM also should be functionalized in the rates associated with that function (Ex. 73, p. 11) rather than assigning them totally to the distribution (or non-generation) function. The details of ORA’s recommendation for SCE’s MAM accounts are described in Table 1 (Appendix A), in the following section, and in Section C. 
ORA also notes that the Commission has established a workshop and comment process to evaluate how to streamline the utilities’ existing balancing accounts, including energy cost adjustment clause (ECAC) and energy revenue adjustment mechanism (ERAM).  ORA urges the Commission to coordinate the treatment of balancing accounts in this unbundling proceeding with the outcome of the Electric Tariff Streamlining workshop. By early May, the Energy Division will issue a report providing its recommendations to the Commission on balancing account issues. In the tariff workshops scheduled by the Roadmap II decision (D.96-12-088) for July, the parties should address how the Energy Division’s report impacts the balancing accounts evaluated in the unbundling proceeding.
2.	Balancing Account Treatment Should Be Consistent With the Electric Restructuring Policy Against Creating Competitive Advantages For The Utilities.
Balancing account treatment for future costs associated with generation should be limited for because other generation providers are not likely to have the same protection.  For instance, SCE’s witness, Letizia, agrees that a generation-related catastrophic events memorandum account (CEMA) would provide a competitive advantage to SCE in comparison to other market generation providers, and SCE’s CEMA account will exclude generation after January 1, 1998. (6 RT 787.) ORA recommends that the same policy be applied to PG&E and SDG&E to prevent them from obtaining a competitive advantage in the generation market. Additionally, ORA believes that the same reasoning applies to hazardous substance clean-up & litigation cost (HSCLC). PG&E proposes to retain the portion of CEMA and HSCLS for distribution and transmission facilities, and recommends the remaining part associated with generation be recovered by PX or CTC. (Ex. 1, p. 2-31.) In conclusion, ORA recommends that the utilities not be allowed generation-related CEMA and HSCLC balancing account protection for costs incurred after December 31 1997.
3.	Franchise Fees And Uncollectibles Should Be Allocated Between Generation And Non-generation Functions.
PG&E proposes to allocate the Franchise Fees and Uncollectibles (FF&U) among the functions. (Ex. 17, workpapers, pp.2-13, 2-14, lines 22&23.) SCE and SDG&E allocate all of FF&U to the non-generation section. (Ex. 8, SDG&E p. II-2.) ORA supports PG&E’s proposal. (Ex. 53, p. 1.)
PG&E’s proposal and ORA’s recommendation to allocate the uncollectible expenses between generation and non-generation is consistent with Commission policy. In D.96-09-092 the Commission adopted an allocation of the uncollectibles between generation and non-generation based on the ratio of total other generation and non-generation expenses. (D.96-09-092, ordering para. A.1.f.) To allocate all of the uncollectibles to the non-generation function as proposed by SCE and SDG&E would unfairly subsidize the utility’s competitive business at the expense of its regulated business. (Ex. 53, ORA/Tan, p.1.) This same reason applies to the franchise fees.
Mrs. Tan testified for ORA that at the present time the electric utilities still own generation plants, and the franchise fee is supposed to reflect a fraction of the total sales; hence, it should be allocated between generation and non-generation in this cost separation process. (ORA/Tan, Transcript Vol. 12, pp.1561-1562.) SCE and SDG&E have presented no reason why they should be treated differently from PG&E, which recognizes that some franchise fees should be allocated to the generation sector. 
In addition, as previously discussed in section II.A, this unbundling process is to allocate embedded revenue requirement among the functions. The embedded revenue requirement associated with FF&U was developed based on pre-restructuring utility services which include combined revenues for generation, transmission and distribution. This is evidenced by the fact that all of the three applicants use prior GRC revenue requirements to perform the cost separation. (Ex.1, p. 2-37, and p.2-44; Ex.12, Appendix C, p.1; Ex.8, p. II-1.)
4.	The Commission Should Reject the Utilities’ Recommendation to Allocate All Common (Residual) Costs to the Distribution Function.
a)	The Commission Correctly Has Rejected the “Incremental Cost” or “Residual Cost” Approach in Allocating Embedded Revenue Requirement Between Utilities’ Regulated and Competitive (Non-regulated) Businesses.
In this unbundling proceeding, the utilities have generally suggested the use of an “incremental cost” approach which would not assign any “common” (see Ex. 12, Appendix C, p. 13.) or “residual” (see Ex. 1, p. 2-9) costs to the generation function (competitive business). PG&E’s witness further concludes that the traditional fully-allocated (fully-distributed) cost method has no basis in economic theory and should not be used in managerial decision-making. (Ex.1, pp. 2A-2 & 3.) However, as noted earlier, this process is to unbundle embedded revenue requirement, and the Commission has determined that fully-allocated cost methodology is the appropriate one to allocate embedded cost between regulated and competitive businesses. In Alternative Regulatory Frameworks for Local Exchange Carriers (D.89-10-031, 33 CPUC2d 43) the Commission explains its endorsement of Federal Communications Commission’s (FCC) fully allocated cost methodology:
“DRA and several other parties urge adoption of a cost allocation methodology for services excluded from the basic sharing calculation which uses fully allocated embedded costs based on the FCC’s Part 64 rules; other suggestions range from use of incremental costs to use of stand alone costs….We conclude that use of fully allocated costs, which pass a share of company overheads to the competitive services, is a fair allocation of costs.” (Section VII. B.i. – Cost Allocation for Below-the -Line Services, mimeo, pp. 205-207. Emphasis added.)
In adopting the fully allocated cost methodology, FCC explained its acceptance of the comments made by the Department of Justice (DOJ). The following quotation from DOJ appears in that decision: 
“there is no sound economic reason to require all residual costs to be born by the regulated sector of the business; that allocation of residual costs is necessary to compensate for inevitable errors in the assignment of incremental costs; and that allocation of overhead is consistent with normal business practice.” (FCC Docket No.86-111, Separation of costs of regulated telephone service from costs of nonregulated activities, Report and Order, p.55, section 105, p.57, section 110.)
As DOJ argued, there is no sound economic reason to require all residual costs to be borne by the regulated sector of the business. The Commission should retain its adopted fully-allocated cost approach and reject the utilities’ incremental approach for assigning all residual or common costs to the regulated business.
b)	
The Companies Should Not Be Permitted To Increase The Cost Of Transmission And Distribution By Loading Those Regulated Functions With The Share Of Current Common Costs That Would Reasonably Be Allocated To Generation.
As pointed out in Exhibit 41, page 11, line 22, each company has used a variation on the theme that common costs are fixed and therefore all of current common costs should be allocated for recovery in transmission and /or distribution rates: “SCE states that costs that are ‘fixed with respect to divestiture’ should not be allocated to generation. SDG&E states that costs that ‘will continue to be incurred by SDG&E regardless of the number of competitive power plants SDG&E operates’ should not be allocated to generation. PG&E states that ‘because PG&E will divest or spin off at least 50 percent of its fossil generation, and may divest or spin off other non-nuclear generation, PG&E allocates zero residual shared cost to generation.” The companies ignore the availability of the market and CTC recovery to collect the equivalent of generation’s share of common resources, and they ignore the capability to reduce common costs the way any non-regulated competitor would in the face of reduced need for those resources.
Exhibit 41, page 12, line 10, also points out that if the companies are permitted to load generation’s reasonable share of current common costs on transmission and distribution, to the extent that a company retains generation in the regulated operating company or in an affiliate, the recovery of all common costs in transmission and distribution gives the company an advantage over competitors who would have to incur the cost of those common resources.
Exhibit 41, page 12, line 17 points out moreover that, whereas a customer buying bundled service from the company would pay for common costs roughly independently of how they are allocated among functions, a customer buying energy from a competitor would pay for common-cost resources once in energy payments and again in transmission and/or distribution rates if generation’s share is loaded on only transmission and distribution.
c)	Common Costs Should Not Be Confused With Fixed Costs.  Common Costs Need To Be Allocated Across Functions To Establish The Revenue Requirements For Transmission And Distribution At The Moment Of Unbundling, But They Are Not Unchangeable In The Face Of Reduced Scope.
SCE first defines common costs as having “no direct or causal relationship to a segment or group of segments….” (Ex. 12, Appendix C, pp.10-11) This is consistent with ORA’s testimony, which states, “…the components of accounts for A&G and for common and general plant that are shared among the functions, but not allocable by direct assignment or by indirect causation,…” (Ex. 41, p. 11.) Thus, common, i.e., residual shared, costs are common to the functions at some moment in time. SCE states, however, that its common costs are defined as such “because they do not vary with changes in operating expenses, employees, revenues…” (Ex. 12, p. 10.) In other words, by SCE’s definition, its common costs are also fixed.
SCE also refers to fixed costs that do not vary upon divestiture. (Ex. 12, Appendix C, pp. 12-13.) SCE indicates that Commissioner Duque acknowledged fixed and variable A&G. (Ibid.) However, in this discussion, SCE switches to the word “common” as though it were synonymous with “fixed”. (Id., p. 13, line 10.) As ORA Witness Clemons testified, fixed cost is a time-horizon concept: for the purpose of a particular analysis, costs are defined as fixed that will not be considered changeable  within the time horizon chosen for the analysis. (12 RT 1585.) SCE “refers to costs which will not vary upon divestiture as ‘fixed with respect to divestiture’…” (Id., p. 12.) In other words, SCE simply asserts for the purpose of its testimony that its time horizon does not allow for changes in common costs upon divestiture. The fact that SCE elects to call certain costs fixed for the current proceeding does not make these costs unchangeable. 
5.	The Utilities’ Residual Approach to Separate Transmission Revenue From Distribution Revenue (or Rate) Should Be Rejected.
The three utilities filed their transmission revenue requirements with FERC on March 31, 1997. In their unbundling applications the three utilities requested that they be allowed to adjust their distribution revenue requirement to make up the difference between FERC’s adopted transmission revenue and their proposed transmission revenue. PG&E stated that their total transmission and distribution revenue should not change due to unbundling or cost separation. (Ex. 3, p. PRP-1) SCE proposed that its distribution PBR rate be determined through a rate credit approach (a rate credit would reflect the FERC adopted transmission revenue requirement converted to a rate). (Ex. 12, p.21.)
ORA agrees with CIU (Ex.40,p. 9), CFB (Ex. 60, CFB/Ilingworth, p.10), and CLECA/CMA (Ex. 73 p. 8) that the utilities’ residual approach to separating transmission from the distribution revenue requirement should be rejected. The utilities claim that they made great efforts to identify facilities and associated costs to the proper functions: generation, transmission and distribution. SCE explained that FERC would evaluate the reasonableness of the transmission revenue requirement. (Ex. 12, p. 19.) If FERC found certain requested transmission projects unreasonable and disallowed the associated revenue, those transmission projects would not become distribution projects. Therefore, it is unreasonable to ask the distribution function to absorb the difference between the utilities’ requests and the FERC authorized transmission revenues. ORA supports CIU’s recommendation that each utility’s 1998 distribution revenue requirement be established by subtracting the proposed transmission revenue requirement from the total non-generation revenue requirement. 
B.	PG&E
1.	PG&E’s Transition Revenue Account Should Be Rejected
PG&E proposes to establish a Transition Revenue Account (TRA) to collect its transmission and distribution revenues. The TRA is functionally equivalent to the ERAM account which is a sales adjustment mechanism. (5 RT 589.) As mentioned above, the Commission has a separate process for evaluating the ECAC and ERAM mechanisms and other balancing account issues. In that process, the Commission inquired whether PG&E and SDG&E’s ERAM for non-generation revenues should be eliminated since the Commission has already eliminated ERAM for SCE’s non-generation functions. If the Commission decided that ERAM should be eliminated for the non-generation functions, PG&E’s proposed TRA also should be rejected, consistent with that decision. SDG&E already proposes to eliminate ERAM and not to replace it with any other sales adjustment mechanism. (6 RT. 864.)
C.	SCE
1.	Existing Generation-related Balancing Accounts Should Be Eliminated As Soon As Appropriate.
ORA already addressed in section III.A.1.that existing balancing account balances should be appropriately allocated among the functions based on the identification of the costs and their associated functions. In addition, the Commission should minimize existing generation-related balancing accounts to conform with the policy that generation is moving toward competition. The Commission can do this by (1) eliminating the balancing accounts as soon as the pre January 1, 1998 costs are addressed and disposed of, and (2) accelerating the recovery of the balancing accounts if possible.
For instance, SCE has a nuclear unit incentive procedure (NUIP) account. SCE’s witness, Letizia, testified that the NUIP was eliminated for SONGS 2&3 in April 1996, while NUIP would continue for Palo Verde to be recovered through the CTC. She further explained that the relevant dollars in existing NUIP balancing account was for performance for SONGS 2&3 in 1995 and for Palo Verde in 1996. (6 RT 787-788.) When NUIP becomes inactive after these reward/penalty dollars are resolved in the 1996 and 1997 ECAC reasonableness proceedings, this account should be eliminated then.
SCE states that its Yuma-Axis account was allocated between SCE and its customers by using a CPUC jurisdictional rate base offset of $14.8 million for a period of 12.5 years. (Ex. 7, p.25.) CFB, CLECA/CMA and TURN/UCAN recommend that this gain should be assigned to the generation function. (Ex. 60, p. 14; Ex. 73, p. 11; Ex. 63, p. 51.) ORA supports the recommendation. SCE argued that if this is credited to the CTC, the credit will cease after December 31, 2001. (Ex. 7, SCE/Letizia, p.25.) Since generation assets are qualified for accelerated cost recovery due to the electric restructuring policy, there is no reason why the generation-related balancing accounts cannot be allowed the same treatment.  SCE’s witness states that SCE has no problem with  the Commission deciding to accelerate the gains on Yuma-Axis sale. (6 RT 789.)
ORA’s recommendations for allocation of the revenues proposed by SCE in its MAM account are presented in Table 1 (Appendix A), and are based on the recommendations of TURN/UCAN (Ex. 63, pp. 48-51), CFB (Ex. 60, pp. 14-17), and CLECA (Ex. 73, pp. 11-14), which are also summarized in Table 1. In most instances, it is the rationale presented by TURN/UCAN that ORA finds the most convincing. Exceptions are (a) Non-Utility Affiliate Credits, where ORA agrees with CLECA/CMA that these activities are ones associated with the UDC as a distribution utility rather than with competitive generation markets or FERC-regulated transmission, (b) Catastrophic Event-Related Cost Recovery, where ORA agrees with CFBF and CLECA/CMA that such events can affect any area of a utility’s operations, and (c) items on which TURN/UCAN apparently made no recommendation.
D.	SDG&E
1.	SDG&E’s Proposal To Allocate Production (Generation) O&M Costs To The Non-Generation Functions Is To Ask The Regulated Business To Subsidize Its Competitive Business And Should Be Rejected.
The policy decision identifies “cross-subsidy” to be one of the Commission’s concerns as the electric industry is going through the restructuring process. The decision explains:
“utilities can exploit their regulated markets to obtain leverage in the competitive markets in two ways: they can shift revenues properly attributable to their regulated services to their competitive services, or they can shift costs properly attributable to their competitive services to their regulated services. In both cases, such improper shifting effectively subsidizes the utilities’ unregulated services with monopoly profits from its regulated services to the detriment of both monopoly ratepayers and competitors.” (D.96-01-009, p.102.) 
SDG&E’s proposal to allocate $3.5 million of its production (generation) O&M expenses to the non-generation sector shifts the costs that is properly attributable to their competitive services to their regulated services. This is exactly the cross-subsidy behavior  that the Commission wants to prevent as addressed above. SDG&E merely stated that these production costs relate to system control and load dispatching, and would remain with SDG&E in the competitive generation marketplace. (Ex. 8, p. II-2.) This is not a sufficient justification.  Moreover, ORA pointed out that SDG&E asserted that it had no plan to divest its generation facilities and it continued to operate as a vertically integrated utility. (Ex. 41, ORA/Tan, p.8.) Therefore, these expenses should properly stay with the generation function. 
2.	SDG&E’s Distribution Revenue Requirement Is Overstated.
The ALJ’s ruling on January 31, 1997 provided resolution on certain issues, one being:
“Consistent with Commissioner Duque’s ruling on May 8, 1996, we will be examining the functions related to the costs contained within a broader category to determine whether or not they have been assigned to the appropriate area. For instance, each utility will be required to demonstrate that the costs assigned to a broad area such as Distribution are appropriately derived from distribution-related functions. It is not sufficient to suggest that a category such as Distribution can be determined on a residual basis. Each dollar must be related to and reasonable in light of a category of activity or expense that is clearly a part of the broader functional area….” (ALJ’s Ruling On Schedule, Scope, and Other Procedure Matters of the Unbundling, on Jan. 31, 1997, emphasis added.)
In its testimony, SDG&E states that it separated the 1993 GRC adopted base rate revenue by account-level to develop the transmission and distribution (T&D) revenues. Then, the T&D revenue was escalated to 1996 T&D base rate revenue by using the Performance-Based Ratemaking (PBR) Base Rate Mechanism increments for O&M costs, capital- related costs and other items. (Ex. 8, p. II-1.) SDG&E’s proposed T&D revenue requirement fails to meet the aforementioned ALJ ruling requirement that each dollar must be related to a functional area and reasonable. The following observations illustrate the shortcomings of SDG&E’s approach:
•	SDG&E allocates 100% of the FF&U to the T&D as addressed in section III A.
•	SDG&E allocates some generation O&M expenses to the T&D functions as discussed in section III.D.1.
•	SDG&E did not present any evidence to show that it is appropriate to escalate the 1993 adopted expenses by applying the base rate PBR mechanism since the mechanism was designed based on a combined company basis. (6 RT 860.) 
•	SDG&E did not demonstrate that its developed 1996 T&D expenses are reasonable. It did not compare the expenses with the actual expenditures, and the record showed that SDG&E’s distribution O&M expenditure, which was included in its non-generation revenue requirement, highly exceeded the recorded expenditure. (6 RT.861-862.)
•	By applying the ratio of the 1993 T&D revenue and the total base rate revenue to the 1996 adopted base revenue resulting in a much smaller T&D revenue requirement than what SDG&E proposed. (6 RT 857-859.)
In summary, SDG&E’s approach is convoluted and should be rejected. The Commission can unbundle SDG&E’s revenue requirements, based on 1996 rate levels by simply applying fundamental cost separation methods directly on a more recent basis. Thus, the Commission should adjust SDG&E’s distribution revenues downward by reflecting the costs to be based on the 1996 actual expenditures. To the extent that there is uncertainty in the recalculation of SDG&E’s unbundled revenues in this manner, the Commission can adopt this more straight-forward approach on a policy level and direct SDG&E to submit detailed calculations with its tariff filings.
IV.	Revenue Allocation and Rate Design
A.	Comments Common to All Applicants
Once the utilities’ functionalized revenue requirements have been determined, revenue allocation methodologies must be determined for allocating each functional revenue requirement to customer classes, followed by determination of rate design methodologies for assigning the total revenues billed to customers for their use of specific quantities of consumption to each function’s revenue allocation to customer classes.
The three utilities use somewhat different sources for their sales and the resulting revenue forecasts, and the source of cost of service estimates used for revenue allocation and rate design differ as well.  However, because AB 1890 (section 368(a)) limits total rates effective on January 1, 1998, to those shown on June 10, 1996, tariffs (as modified by a reduction of at least 10 percent under section 368(a) of AB 1890), and the pertinent portions of SDG&E’s and SCE’s 1998 revenue levels are primarily determined through their existing PBR mechanisms, the impact of this variation in the sources of the utilities’ sales and revenue forecasts, and cost of service estimates, is limited. (Ex. 41, p. 15.)
Pursuant to AB 1890, the utilities generally propose to keep the total unit charges (customer, demand, and energy charges) as currently adopted, except for crediting customers’ bills for the rate reduction to be received by residential and small commercial customers. Thus, instead of the usual issues considered in general rate cases (GRC) concerning adjustment of these total unit charges, the rate design issues to be considered in this proceeding pertain to the functionalization of these charges, and to specific rate options. (Ex. 41, p.22.)
1.	Revenue Allocation
a)	ORA supports SCE’s Proposed Revenue Allocation Methodology for Transmission and Distribution
Each utility allocates its transmission and distribution revenue requirements using a full equal percent of marginal cost (EPMC) methodology, although a difference occurs between SCE’s methodology versus PG&E’s and SDG&E’s methodologies. For PG&E and SDG&E, each customer class’s proposed share of the functionalized system revenue requirement is the transmission, or distribution and customer, marginal cost revenue for the customer class divided by the system total transmission, or distribution and customer, marginal cost revenue. SCE’s proposed transmission revenue allocation is proportional to its transmission marginal cost revenue, but its proposed distribution revenue allocation methodology is analogous to its methodology for determining its distribution functional revenue requirement: the transmission and distribution revenues are allocated on a combined basis, then the transmission revenue allocation is subtracted to determine the distribution revenue requirement. (Ex. 41, pp. 15-16.)
Use of an EPMC revenue allocation for transmission and distribution is consistent with the CPUC’s adopted revenue allocation methodologies and with rates in effect on June 10, 1996 (the date established as a reference point by AB 1890). A difference from the application of the adopted methodologies is due to the future regulatory approach, in which FERC will be the final authority in setting unbundled transmission rates, and this is the origin of the difference between SCE’s versus PG&E’s and SDG&E’s approach to revenue allocation for the distribution function. By combining the marginal cost components in an initial allocation of transmission and distribution revenues, SCE’s proposal maintains the most consistency with the Commission’s past decisions, which apply the EPMC methodology on a total revenue basis (“EPMC on total”) instead of a functional revenue basis. In the Long Run Marginal Cost proceeding for natural gas cost allocation, the Commission rejected application of the EPMC methodology on a functional basis because it recognized that “EPMC by function” is simply equivalent to an embedded cost allocation.  For the same reason, SCE’s approach to allocating transmission and distribution revenues should be used for all three utilities in this proceeding.(Ex. 41, pp. 16-17.)
Although CLECA/ CMA’s rebuttal testimony (Ex. 72, p. 2-4) challenges ORA’s endorsement of SCE’s proposal, its argument amounts to a proposition that embedded cost ratemaking would be more appropriate in an unbundled environment, and cross-examination at (15 RT 1841-1842) confirmed that CLECA/ CMA’s witness did use a single factor to separately allocate each component of revenue requirement. The proposed stipulation on transmission revenue allocation and rate design recognizes that this treatment is equivalent to embedded cost ratemaking (Ex. 81, p. 6), and was signed by CLECA. Although ORA recommends that even greater functionalization should be pursued after the year 2001, and that this will replace “EPMC on total” with an alternative incremental cost approach, this should be pursued on a comprehensive basis when it occurs. (Ex. 41, pp. 16-17.) There would simply be no purpose served by changing from the current EPMC revenue allocation to embedded cost ratemaking, only to change again to an incremental cost approach.
b)	Revenue Allocation for Public Purpose Programs, California Alternate Rates for Energy (CARE) and Nuclear Decommissioning/ Incremental Cost Incentive Price (ICIP) Should Consider Both CPUC Precedents and Functional Activity
The Commission’s policy decision on electric restructuring (D.95-12-063) and AB 1890 identify certain types of costs as receiving different ratemaking treatment from other generation, transmission, and distribution costs. Low income credits (California Alternate Rates for Energy, or CARE) have been previously established with a separate equal cents/kWh revenue allocation. In D.95-12-063 (mimeo, p. 166), the Commission stated its policy preference for recovering these low-income assistance costs as a surcharge, applicable to direct access customers as well as bundled UDC customers, on electricity use separate from other public goods charges, in order to provide a clear funding source for low-income programs which will not be mingled with funds collected for other purposes. D.95-12-063 (mimeo, p. 146) proposes the establishment of a non-bypassable Public Goods Charge (PGC) on retail sales to fund public purpose programs (PPP), e.g., public goods RD&D and energy efficiency activities, which are not currently separated from other revenues for the purpose of revenue allocation. AB 1890’s section 379 establishes nuclear decommissioning as a separate non-bypassable charge, and sections 367 and 368 require recovery of above-market incremental cost incentive price (ICIP) costs from all customers on a non-bypassable basis. (Ex. 41, pp. 17-18.)
The most recent adopted decision addressing the issue of whether to allocate these costs on an equal cents per kWh basis or in general proportion to a marginal cost-based revenue allocation for electric utilities is D.96-04-050 (mimeo, pp. 76 - 83) in SCE’s Test Year 1995 GRC. Based on the rationale presented in D.96-04-050, ORA concludes that PPP revenues should be allocated for all utilities using the SAP methodology proposed by PG&E. (Ex. 41, pp. 17-18.) ORA would consider using a more program-specific approach once the details of program spending become available after January 1, 1998, but for now there is too much uncertainty about how PPP programs will be conducted after electric restructuring occurs, including who the program beneficiaries will be.
However, nuclear decommissioning and ICIP costs are related to the continuing utility function of energy production, and this factor alters the balance of the issues considered in D.96-04-050. Nuclear decommissioning costs have been incurred because the utilities have sought to reduce their energy production costs by using nuclear power, while ICIP is an on-going incentive for the utilities to reduce their energy production costs; thus, the intent of both of these activities has been to the benefit of customers who use relatively large amounts of energy. (12 RT 1608-1610.) Therefore, nuclear decommissioning and ICIP costs should be allocated for all utilities using the equal cents per kWh methodology proposed by SDG&E and SCE. (Ex. 41, pp. 17-18.)
Direct access and bypass should pay the same amount for the non-bypassable charges as bundled UDC customers. For rates that are determined using the SAP methodology, this could be accomplished by calculating these charges for each customer class as if all customers were served on bundled rates. (Ex. 41, pp. 17-18.)
2.	Functionalized Components of Rate Design Should Maintain Existing CPUC Polices
ORA is a party to and fully supports a stipulation on transmission revenue allocation and rate design, which was submitted to the Commission on March 19, 1997. ORA disagrees with several other aspects of the utilities’ rate design proposals, however, as discussed below.
SDG&E and SCE propose to calculate specific breakdowns of each total unit charge into functional components, and to rely to a great extent on demand charges (in addition to customer charges) for collection of distribution costs, rather than a combination of demand and energy charges. However, PG&E proposes that the Commission should not adopt “functionalized rates” at this time. (Ex. 1, pp.4-3 and 4-10.)
The degree of reliance placed on demand charges by SDG&E and SCE is also contrary to testimony presented by DRA (ORA’s predecessor) in several preceding GRCs. In those proceedings DRA demonstrated that traditional demand charges are not an ideal method for recovery of marginal costs that are attributed to system peak demands, as are 90% of SCE’s transmission costs for rate design purposes, 80% of SDG&E’s transmission costs, and a significant share of distribution costs for each of these utilities. The area load analyses adopted by the Commission for use in PG&E’s and SCE’s revenue allocations (and in rate design for PG&E) show that reflecting the loads that drive investments in new transmission and distribution capacity is even more complex than was demonstrated by DRA. Moreover, in many cases, targets for rate design have often not been clearly defined in Commission decisions on a functional basis, but instead have made tradeoffs among parties’ positions and have been subject to caps on increases in rate components. Thus, functional unbundling of all rate design components in this proceeding could be a difficult task. Because of the rate freeze, the practical effect of unbundling rate components, to the extent proposed by SDG&E and SCE, on customers’ total rates or bills is negligible. However, when rate designs of the post-rate freeze period are considered, it would be undesirable to have a starting point for the unbundled rate components that does not reflect the past decade of deliberation in the Commission’s rate design proceedings. (Ex. 41, pp. 22-24.)
A further concern about allowing distribution rates to include demand charges that amount to a high percentage of the existing demand charges is that when targets have been discussed in Commission decisions, they have considered EPMC levels that used a system-wide EPMC multiplier, while revenue requirements that will now be recognized as CTC have made up part of the escalation on EPMC targets over marginal costs. Because of the role of CTC revenues in making up the EPMC targets for demand charges, it would be appropriate to assign a portion of the existing demand charges to the generation function. (Ex. 41, pp. 22-24.)
PG&E’s rate design proposal reduces these problems by proportionally crediting total revenues among functions rather than functionally unbundling all rate components. Thus, ORA has endorsed the fundamental principle of PG&E’s proposal for all three utilities for assigning expected revenues, within each customer class, between the distribution and generation functions; other considerations require setting specific rate calculations for other unbundled components. Assignment of specific rate components for transmission, PPP, CARE, nuclear decommissioning, and ICIP, as required for billing purposes, does not alter the benefit of minimizing unnecessary controversy by proportionally crediting the remaining revenues between distribution and generation, because these two functions make up a large majority of overall revenue requirements. (Ex. 41, pp. 22-24)
Several intervenors (CAC/EPUC/ Ross, Ex. 57, pp. 22-25;  CEC/ Jaske, Ex. 55, pp. 4-5;  CIU/ Chalfant, Ex. 40, pp. 19-22;  CLECA/CMA/ Yap, Ex. 73, pp. 5, 33, 35; and DOD/ Brubaker, Ex. 45, pp. 23-24) emphasize setting specific functionalized rate components in rate design, but their recommendations do not fundamentally conflict with the reasons for ORA’s recommendations on this issue, including avoidance of unnecessary re-litigation of rate design issues that have been very time consuming over the course of many years of general rate cases, a need to preserve existing rate design principles due to AB 1890’s limitations on rate changes during a transition period to industry restructuring, the role of uneconomic generation costs in EPMC mark-up of the existing demand charges, and past analyses that demonstrate that demand charges are not an appropriate method for recovering costs of service that are attributed to system peak demands.  ORA does not object to unbundling specific rates for generation and distribution while preserving existing rate design principles and avoiding unnecessary re-litigation of rate design issues from previous GRCs.  This could be accomplished by (a) subtracting transmission rates and non-bypassable charges (however they are determined) from total rates, and dividing the remainder (a large majority of total rates) proportionally between generation and distribution to determine specific functionalized rate components, or (b) subtracting adopted marginal energy costs as well as transmission rates and non-bypassable charges from total rates, dividing the remainder proportionally between generation and distribution, and recombining the marginal energy cost into generation rates. (Ex. 42, pp. 5-6.)
However, CLECA proposes reliance on demand charges to an extent that has been controversial in a number of GRCs, without citing a basis in past decisions for its recommendations. ORA does not dispute that customer costs and “noncoincident” capacity costs (as they have been established on utility-specific bases) are appropriately reflected in customer charges and maximum demand charges, but has repeatedly presented analyses demonstrating that energy use is statistically superior to time-of-use (TOU) demand charges for reflecting the incurrence of “coincident” capacity costs (i.e., capacity costs that are attributed to contributions to the combined peak loads of multiple customers of various portions of the utility system). The key principle here is that capacity costs are indeed caused by “coincident” loads, but that traditional TOU demand charges do not measure coincident loads: instead, traditional TOU demand charges measure customers’ maximum demands over a somewhat broad set of hours that includes times when utility system loads are low as well as the times when system loads are high. Coincident demand is not a factor in calculating customers’ bills, except on real time pricing schedules.  An alternative measurement of load is average load by TOU period, which is determined by TOU energy use divided by hours in the TOU period. Given the existence of alternative proxies for coincident demand, the question is which one is a better proxy. Several tables are presented in ORA’s rebuttal testimony, representing analyses of coincident demands at different levels of the utility system, different customer classes, and different analytical formulations, demonstrating robust results supporting ORA’s conclusion that average load, instead of billing demand, is a better proxy for coincident demand. (Ex. 42, pp. 6-9.)
Based on these results, combined with the other reasons discussed in ORA’s Exhibit 41 (pp. 22-24), recommendations to transfer collection of distribution capacity costs to TOU demand charges should be rejected.
3.	Rate Design for Competition Transition Charge, Direct Access and Virtual Direct Access Should Promote the Commission’s Restructuring Goals and Result in Appropriate Price Signals
At the most fundamental level, ORA agrees with some of the principles proposed by the utilities for calculation of CTC charges:  all three utilities propose that (a) generation revenue requirements and rate components (other than nuclear decommissioning and ICIP) should be determined residually from the total bundled rates in effect on June 10, 1996, minus the other unbundled rates, (b) PX costs should be subtracted from the total generation rates to determine CTC charges, and (c) a Direct Access customer’s bill should be the total bill under the customer’s applicable full-service (bundled) rate schedule, subtracting the UDC’s cost of energy from the PX. The utilities propose that the cost of energy from the PX would be a class average cost of energy for customers without hourly meters.
The utilities extend these principles to conclude that the calculation of CTC should occur on an hourly basis, using customer-specific hourly loads, for customers with hourly meters, to ensure that total unit charges equal the unit charges in effect as of June 10, 1996. ORA recommends that this specific implementation of these principles as proposed by the utilities should not be adopted. The utilities believe this residual CTC determination will ensure that no real time pricing (RTP) customers are subject to bill increases due to RTP metering or CTC recovery (using their interpretation of sections 367(e)(1) and 368(b) of AB 1890), and that calculating the CTC in this manner will allow customers who are on a TOU tariff or who are eligible for a TOU tariff the opportunity to capture the benefit of shifting usage from one time of use period to another. The result of the utilities’ proposals is that Virtual Direct Access as envisioned by D.95-12-063 would be impossible, because customers would be charged the same rate in each hour of a TOU period.  The utilities’ proposals do not address how the Commission can achieve the goal of providing customers with market-driven price signals during the transition period, which it clearly stated at several places in the Policy decision (D.95-12-063), including Findings of Fact 17 and 18:
17.	The revelation of the real-time price of electricity coupled with a rate alternative that allows the customer who is able to respond intelligently will produce savings for any customer who is able to shift demand from peak to off-peak hours and will produce a collective benefit, in that demand will be redistributed away from the current peaks. Future generation demands will be forestalled even as existing investments in generation are made more productive
18.	Transparent, reliable price signals will be very important to foster a competitive market during the transition period because customers and suppliers will develop sophistication over time and alternative resources for price information will develop over time.
In order to achieve the Commission’s goals such as transparent, reliable price signals even during the transition period, ORA recommends calculating the CTC charge as a rolling average for each TOU period in the customer’s billing period, based on a CTC rate calculated for the customer’s otherwise-applicable tariff (which in turn would be based on a rolling average PX cost and schedule-specific load profile), instead of the hourly CTC calculation proposed by the utilities. The rolling average CTC rate should be based on the loads of all customers subject to the same otherwise-applicable tariff, whether or not hourly meters are installed on their premises. By applying a uniform CTC rate calculation to all customers subject to each otherwise-applicable tariff, ORA’s recommendation satisfies CPUC Code section 367(e)(1), which provides that transition costs shall be allocated to the various classes of customers, rate schedules, contract rates, and tariff options including self-generation deferral, interruptible and standby rate options in substantially the same proportion as similar costs are recovered as of June 10, 1996, and section 368(b), which provides that transition costs should result in no cost shifting among customer classes, rate schedules, contract, or tariff options. Section 368(b) also requires that customers of the electrical corporation who become eligible to purchase electricity from suppliers other than the electrical corporation pay the same unbundled component charges, other than energy, a bundled service customer pays, and ORA’s recommendation is also consistent with this requirement because (1) differences in cost between customers who remain on UDC tariffs are due to their choice between a rate structure that existed on 6/10/96 and a Virtual Direct Access tariff offered by the UDC, combined with the Virtual Direct Access customers’ cost of service in terms of hourly use of energy, charged at Power Exchange prices, and (2) differences in cost between customers who choose the UDC’s Virtual Direct Access tariff and customers who receive hourly prices from a Direct Access supplier are due to that supplier’s own energy cost compared to the UDC’s energy cost.  Beyond satisfying sections 367(e)(1) and 368(b), ORA’s recommendation promotes rate offerings in compliance with section 378 of AB 1890, which the utilities have not addressed. Section 378 states:
“The commission shall authorize new optional rate schedules and tariffs, including new service offerings, that accurately reflect the loads, locations, conditions of service, cost of service, and market opportunities of customer classes and subclasses.”
In addition to overlooking the Commission’s clearly stated goal of transparent, market-driven electric prices and AB 1890’s clear call for optional rates that accurately reflect customers’ loads, cost of service, and market opportunities, the utilities’ arguments overlook the fact that essentially all customer classes of all three utilities have already had TOU tariffs available for several years, without requiring hourly meters (TOU meters are simpler), and that offering simple TOU options does not require electric industry restructuring. ORA’s recommendation (as stated above) maintains the existing TOU options, for customers who choose to have the protection of AB 1890’s rate freeze, by structuring them using monthly average PX and CTC rates, regardless of whether hourly meters have been installed at customers’ sites. ORA’s recommendation then creates rate options that use the same average CTC charges as the rate schedules that are left subject to the rate freeze, but are structured to reflect hourly variations in PX prices. The same CTC charge can also appear in the tariffs applicable to direct access customers, and thereby make direct access and Virtual Direct Access into meaningful rate options that customers can voluntarily select.
Beyond being unnecessary for compliance with AB 1890, calculation of CTC on an hourly basis, as proposed by the utilities, can also lead to unintended results, as seen through two simple examples. ORA’s Exhibit 41 (pp. 26-27) demonstrated that under the utilities’ proposals, variations in market prices can result in a lower hourly cost to the ESP’s customer in a high cost hour than in a more typical hour, which is contrary to well-founded ratemaking and is reason to reject the utilities’ method of calculation. Southern Energy further demonstrated that the utilities’ proposals can provide customers with incentives to operate less efficiently, through an example of a direct access customer who has a contract with an energy supplier for its full requirements at a fixed generation price;  the customer’s total cost (generation, CTC, transmission, distribution and public purpose program) is highest when the PX price is lowest, leaving the customer with the incentive under the utilities’ hourly pricing proposal to schedule its energy use during the period when the demand for electricity (reflected in the PX price) is the highest. In contrast, ORA’s recommended methodology for calculating CTC charges accurately reflects the high cost market conditions, as demonstrated in Exhibit 41 (p. 26). 
ORA notes that the utilities express concerns such as that stated in SDG&E’s Exhibit 8 (p. V-6), that customers for whom hourly metering is in place should not be allowed to choose between hourly and monthly average PX prices, in order to prevent “gaming” of these prices. This concern is essentially the same that occurs whenever customers have a choice between multiple rate options (e.g., TOU rates with a seasonal differential, versus non-TOU rates), and the utilities have adequately addressed this concern with rules that limit tariff switching. Electric restructuring should be used explicitly to increase the options available for customer choice, such as virtual direct access, instead of limiting such rate options due to concerns about “gaming”.
Regarding other related issues, SCE proposes that a single PX price should be used to determine the UDC’s PX cost for each hour, without attempting to infer differences in different customer classes’ requirements for purchases in the day-ahead, hour-ahead, and real time energy imbalance markets (as adjusted for administrative cost, settlements, ancillary services, and congestion fees), unless it becomes apparent that differences between these classes’ mix of purchases become apparent. Due to the complexity of implementing billing and settlement systems, ORA agrees that the simplification of using a weighted average of these prices is appropriate for the initial implementation of restructuring, but asks the Commission to monitor these differences.
4.	Settlement Protocols Are Critical to Market Functioning and Accurate Cost Allocations
Settlement protocols comprise the process by which financial responsibility for the results of the electric system’s operations is assigned among market participants, and their establishment is a critical area for the implementation of electric industry restructuring. (Ex. 41, p. 31.) For example, SCE’s December 20, 1996, Ratesetting testimony identifies the following critical path steps are necessary to develop its 1998 final rates and tariffs (Ex. 12, p. 32):
•	FERC authorization of SCE’s 1998 transmission revenue requirement and decision regarding FERC/CPUC jurisdiction over unbundled retail transmission rate design;
•	Commission decision regarding SCE’s cost separation proposals filed in the Generation PBR and appended to Exhibit SCE­1 of this Application; 
•	Establishment of ISO settlement protocols;
•	Establishment of protocols governing provision of ancillary services;
•	Issuance of Rate Reduction Bonds; and
•	Establishment of ISO interruption criteria for nonfirm customers.
Whereas SCE’s list of critical path steps referred to the establishment of ISO settlement protocols, the responsibility for settlements is not only the ISO’s, but is likely to involve the UDCs as well. ORA agrees with the general approach offered by SCE, and has offered refinements to provide consistency with the ISO’s practices and to avoid cost-shifting between customer classes, particularly the following: (1) distribution loss factors should be determined prior to the operation of the PX’s day-ahead market, and should not be changed after the day-ahead bids are submitted, so scheduling coordinators can self-provide losses as they can do in the ISO’s scheduling protocols, and (2) real time, stratified load data should be utilized for customers whose settlements are based on load profiles, in order to avoid cost-shifting between customer classes to the greatest extent possible. (Ex. 41, pp. 32-37 and 39-41.)
During the ISO’s settlement process, losses that are not self-provided or purchased from another scheduling coordinator are settled using the hourly rate for imbalance energy and differences between estimated, and actual losses are considered to be bought or sold by the ISO and recovered through its administrative charge. Similar to the ISO’s true-up protocol for differences between anticipated and actual transmission losses, loss factors that were set prior to operation of day-ahead markets should not be subject to revision in determining final UDC-level settlements, and the difference in distribution losses should be considered to be purchased or sold by the UDC as a function of its distribution operations, which would be resolved by adding or subtracting from the UDC’s PX charges. A memorandum account or balancing account is more appropriate for capturing such apparent differences over time, instead of re-billing customers for past usage after the final UDC settlement. (Ex. 41, p. 36.)
Currently adopted distribution loss factors by TOU period could be used initially during 1998, but UDCs should propose procedures to ensure adequate accuracy of distribution loss factors under varying system conditions. CLECA/ CMA have proposed a formula that would allow more accurate distribution loss factors to be calculated, and ORA supports use of a formula like that proposed by CLECA/ CMA, for the reasons explained by CLECA/ CMA. (CLECA/ CMA, Ex. 73, pp. 22-24) SCE’s witness Jazayeri stated during cross-examination (11 RT 1452) that SCE envisions that there would be a set of tariffs approved by the Commission for loss factors. ORA agrees with establishing a set of Direct Access tariffs that includes loss factors, and believes a formula such as that proposed by CLECA/ CMA, and a process for implementing it, can be incorporated in such a tariff. The Ratesetting Working Group and the tariff workshop called for by the Roadmap II decision (D.96-12-088), used as an integrated process, would be a workable approach for developing these tariffs.
After system operations for a given hour have occurred, calculation of hourly loads for customers without hourly meters (including corrections for missing and anomalous load research data) can be completed within several days after the last meters have been read. Whether or not load profiling is allowed for direct access customers, many bundled UDC customers will need to be served using load profiling simply because hourly meters cannot be installed for all customers by 1998. As shown by both ORA’s and SCE’s testimony, the impacts of revised UDC load profile calculations during the settlement process can affect multiple customer classes as well as non-UDC customers. A major concern in the settlement process will be to minimize errors in load profiling since such errors cannot easily be separated from loss estimating error, meter error, error due to theft, etc. As a result, all such errors will be lumped together and will be spread to all customers in the settlement process. This means that all customers (even metered customers served by other ESPs) will have a stake in the issue of errors due to load profiling as well as other factors. (Ex. 41, pp. 32-37 and 39-41.)
Actual real time metered load data should be incorporated in the settlement process, through statistical sampling for load profiled customers, once such data are available, to ensure that settlements are as similar as possible to those that would occur if hourly metering were in place for each customer. This need is illustrated in Figures 1 through 4 of Exhibit 41, which show the hourly load shapes for SCE’s residential and GS-1 customer classes on “extremely hot” summer weekdays versus mild summer weekdays (as defined for purposes of SCE’s real time pricing Schedules RTP-2, RTP-3, RTP-2-GS, and RTP-3-GS). Night-time loads for these customer classes are similar regardless of the day-time temperatures, but their day-time loads are very weather-dependent. Use of the same load forecast for all summer weekdays would force small customers to be allocated potentially significant costs for imbalance energy from the ISO, while scaling a predetermined load shape to expected daily sales would over-attribute night-time loads and under-attribute day-time loads, again leading to potentially significant costs to small customers for imbalance energy.(Ex. 41, p. 35.)
A stratified statistical sampling technique, using multiple profiles as opposed to a single profile representing a large, diverse customer class (such as residential), should be used to minimize the “standard error” of the estimate (“error”) for a given group of customers. Multiple load profiles would be based upon stratifying a large group of customers into smaller, more homogeneous, groups in terms of the actual load shapes of the customers within each group. Such stratification would lower the overall “error” for the large group since the sum of the stratified standard errors would tend to be less than the standard error of the estimate for a single profile. Up to a point, the greater the stratification that exists, the lower will be the sum of the errors. In addition to reducing errors, such profiles will reveal variation in the data from one year to the next, and the real time sampling will help to improve the UDC’s predicted bid into the PX, helping to minimize errors in the final settlement. (Ex. 41, pp. 32-37 and 39-41.) Stratification within customer classes can also reveal pertinent differences among customers’ load patterns, as demonstrated by ORA’s cross-examination of Edison’s Witness Jazayeri. (Ex. 48 and 11 RT 1453-1461.)
The utilities have existing load research samples that can be used for this purpose, although there is no reason why other metering agents should not also be allowed to contribute to enlarging the available pool of load research data if they comply with comparable standards of statistical validity, thus reducing errors further without adding to costs that must be recovered from ratepayers as a whole.(Ex. 41, p. 35.)
5.	ORA Supports PG&E and SDG&E’s Proposals for Baseline and CARE Rates
All three utilities propose maintaining the existing baseline/ non-baseline rate differential during the term of the rate freeze, and ORA agrees with this proposal. PG&E and SDG&E propose reflecting a baseline to non-baseline rate differential in both distribution and CTC rates, so that the rate structure after CTC is removed from the UDC’s rates would continue to reflect the baseline rate structure. In contrast, SCE proposes that for Domestic rate schedules, the baseline/ non-baseline rate differential will be reflected exclusively in the CTC during the term of the rate freeze. SCE’s approach does not appear to plan for a post-rate freeze rate structure concerning baseline rates. ORA recommends applying PG&E’s and SDG&E’s proposal to all three utilities. (Ex. 41, p. 28.)
6.	Implementation of the AB 1890 Rate Reduction Should Promote Options for Small Customers
AB 1890 requires no less than a 10% reduction in average rates for residential and small commercial classes of customers, effective January 1, 1998. The costs of this reduction are to be financed through a rate reduction bond, and recovered through the same customer classes over a period of years.  This is not the only principle for rate design affecting these customer classes, however: the Commission has repeatedly endorsed the offering of TOU rates to all customer classes, to reflect cost-causation principles that have been adopted for all capacity costs, and customers who choose TOU rates should not be precluded from being eligible for AB 1890’s revenue reduction. SCE proposes to offer the rate reduction to all customers in its domestic and GS-1 rate groups, and PG&E proposes including all residential schedules and commercial Schedules A-1, A-6, A-10, and E-19 voluntary, with both utilities including a variety of TOU and non-TOU schedules.  Both SCE’s and PG&E’s proposals appear to correspond to ORA’s recommendations, except for more detailed, utility-specific issues that are addressed in section IV.C below. However, SDG&E’s proposals for tariff eligibility do not comply with the Commission’s policies in this area, and are discussed further in section IV.D below. (Ex. 41, pp. 19-20.)
While issues concerning eligibility for the rate reduction bonds are utility-specific, issues concerning crediting and bond recovery affect all three utilities. SDG&E and SCE proposed in their December 6, 1996, applications to implement the 10% rate reduction to their residential and small commercial classes in the form of a credit to the total bill before taxes and surcharges, contingent on issuance of rate reduction bonds; PG&E’s February 14, 1997, supplement also adopted this treatment.  Funding for SDG&E’s principal, transaction costs and interest associated with the rate reduction bonds will be provided through a cents per kWh surcharge applied to bills of customers receiving the bill credit (i.e., the residential and small commercial classes), based on annual bond revenue requirement divided by forecasted sales. SCE proposes separate bond repayment charges for residential and GS-1 customers, to reflect the absolute differences in rate reductions between the two rate groups. SCE’s proposal is more equitable and should be applied to PG&E and SDG&E as well. The Commission may wish to consider establishing a tracking/ balancing account to monitor over/under collections. The filings to be considered later in 1997 for establishment of the rate reduction bonds may be the best forum for addressing this concern, since full information will then be available. (Ex. 41, p. 21.)
Discussions in the Ratesetting Working Group indicate that no utility has proposed that the AB 1890 rate reduction would result in discounting the PX price that competing suppliers would need to match in order to serve small customers, i.e., the rate reduction bonds would only influence the collection of CTC. The Commission should ensure that this intent is reflected in its adoption of unbundled rates. (Ex. 41, p. 21.)
7.	Non-Firm Rate Programs Require Further Discussion
The adaptation of the utilities’ existing non-firm rate programs to the post-restructuring environment has been the subject of discussions in both the Ratesetting Working Group and the Western Power Exchange (WEPEX) Operational Rules and Protocols definition team. Discussions in the Ratesetting Working Group were suspended pending the WEPEX discussion, but ORA expects these discussions to resume after the March 1997 WEPEX Phase 2 filing, in preparation for the utilities’ June 1997 CPUC tariff filings. The text resulting from the WEPEX team’s discussion elaborates on the summary discussion in the current draft of the WEPEX Phase 2 filing, and can guide the parties in that process. SCE will probably need to modify its non-firm tariffs to reflect its interaction with the ISO’s operating criteria when the ISO assumes responsibility for the scheduling of power flows and operation of the high voltage transmission grid. The WEPEX Phase 2 filing identifies the need in general for the ISO to test its newly instituted operational protocols (draft ISO Tariff, section 2.3.2.5), and the goal of such testing should be considered to be consistent with the pre-emergency curtailment provisions contained in PG&E’s existing non-firm tariffs. (Ex. 41, pp. 28-29.) SCE’s witness acknowledged its need to further develop the operating criteria for its non-firm program, and recommended that these discussions should involve both the Ratesetting Working Group and those involved in the WEPEX process (11 RT 1462-1463); ORA agrees that both groups should be involved.
ORA agrees with PG&E’s and SCE’s proposal to reflect the interruptible credit exclusively in CTC during the term of the rate freeze. (Ex. 41, p. 29.)
8.	Line Extension Rules Should Rely on Current Rules Until Changed in the Line Extension OIR
Current line extension rules base electric line extension allowances on expected future revenues generated by a new line extension in order to compensate the utility for its initial investment. In a restructured environment, the generation and transmission components of utility revenues will no longer be relevant to the calculation of the applicable “base annual revenues”. This will lead to a reduction in line extension allowances under the existing formulas, and is a logical consequence of electric industry restructuring. ORA agrees with PG&E and SDG&E that the line extension OIR is the appropriate forum for detailed examination of these issues, but recommends that if these issues are not resolved in that forum, the consequence of reduced line extension allowances should be accepted by leaving the current rules unchanged until the pertinent studies can be completed. (Ex. 41, p. 29.)
B.	PG&E
PG&E’s proposal regarding functionalization of rate components has been structured primarily by limitations that it will face in its billing system during 1998, and PG&E asserts that unbundling (even to a limited extent such as that recommended by ORA) will take time to implement. However, PPP, CARE, nuclear decommissioning, ICIP, and CTC will be non-bypassable rates for most customers and, FERC may prefer transmission rates to be stated as specific rate components. Because of AB 1890’s requirement (section 368(b)) for customers of all generation suppliers to be charged the same rates except for energy, all utilities’ billing systems (including PG&E’s) should be expected to charge uniform rates as soon as possible for the non-bypassable components to both bundled and direct access customers. (Ex. 41, pp. 24-25.)
C.	SCE
1.	Real Time Pricing Must Be Continued During Restructuring and RTP and Flexible Pricing Options Can Be Adapted to the New Industry Structure
An exception to SCE’s general approach to calculating hourly CTC rates occurs for its existing real time pricing and flexible pricing options.  On the real time pricing options, methodologies are currently in place for calculating variable total effective rates, and when the PX price is subtracted and ESPs’ alternative energy charges are added, the result reflects market conditions in a manner acceptable to ORA. SCE also proposes (Exhibit 12, pp. 54-55) that customers taking service under some special rate contracts or options will have a lower CTC than that reflected in the otherwise applicable tariff, consistent with PU Code Section 368, which requires setting rates for contracts or tariff options at levels equal to those in effect as of June 10, 1996.
SCE further proposes (Ex. 7, pp. 63-64) that its flexible pricing options, including its real time pricing options can be conformed to the new industry structure and continue to be available to its customers.  ORA agrees, but urges that the cost-based rate structures and financial protections for ratepayers adopted when the flexible pricing options were approved by D.96-08-025 must not be weakened.  In particular, ORA is concerned that implementation of D.96-08-025 included the closure of all of SCE’s real time pricing schedules upon operation of the Power Exchange.  Although D.96-08-025 premised such effects on the fact that changes in design of real time pricing schedules would occur under industry restructuring and concern that these rates might represent contracts for differences, the Commission has not indicated in any decision that it intends to eliminate real time pricing.  No concern regarding contracts for differences has arisen in this proceeding, but the proposed stipulation on transmission pricing (Ex. 81) recommends real time pricing rates to be effective in 1998 and later years.  Indeed, its electric restructuring policy decision (D.96-12-063) emphasizes real time pricing repeatedly as central to its goals.  ORA presumes that the Commission will be issuing a ruling establishing dates and other details for the tariff phase of this proceeding, and that ruling should direct SCE to include the continuation of real time pricing after Power Exchange operations commence, in its June 1997 tariff filings.
2.	Implementation of Rate Reduction Bonds Should Promote Customer Choice
SCE proposes that if a customer becomes ineligible for schedules that have received the rate reduction, they should be excused from repaying the rate reduction bonds. ORA is concerned that other ratepayers would be required to repay the rate reduction benefit received by the customer who has been required to switch to an ineligible customer class, and recommends instead that (1) customers who are eligible for the AB 1890 rate reduction on January 1, 1998, should be allowed to continue service on an eligible rate schedule until the rate reduction bonds have been repaid, and (2) if customers choose to switch to a rate schedule that is ineligible for the rate reduction, they should be required to repay the rate reduction benefits that they have received. (Ex. 41, pp. 20-21.)
3.	SCE’s Base Rate vs. ECAC Seasonal Rate Adjustment Should Be Adjusted to the New Industry Structure
In recent years, SCE has incorporated an adjustment in its residential ECAC rates that offsets the amount of its annual revenue collection that is reflected in non-residential customers’ demand charges, which vary by season. (Presumably, part of this differential in generation rates will translate to a difference in future CTC charges.) Even though the combined rates for domestic customers have been considered acceptable under past ratemaking practices, maintaining much lower distribution rates in summer than in winter currently introduces serious price distortions that, for some market developments, then become unwarranted hurdles or subsidies to competitors. This distortion also may present problems in the future, when CTC revenues are reduced, since some customers will obtain generation from alternative providers, who will not have similar protections against seasonal revenue variations. Since the ECAC rate component will no longer be part of SCE’s ratemaking process, SCE should be required to justify any proposed continuation of this adjustment, in its June 1997 tariff filing. (Ex. 41, p. 30.)
D.	SDG&E
1.	SDG&E’s CTC Cost Allocation May Require Further Consideration
In addition to the requirements of section 368 (a), as discussed in section IV.A.3 of this brief, section 397 of AB 1890 allows SDG&E to adjust its rates reflecting a fuel price index mechanism, and SDG&E proposed a Rate Cap Mechanism in September 1996 to implement section 397. (Ex. 8, pp. I-2 to I-3.) Like PG&E and SCE, SDG&E proposes to use a residual approach to determine its CTC charges in order to meet the 6/10/96 rate freeze constraint.  However, details of how SDG&E would implement section 397 for CTC cost allocation purposes were not presented until its rebuttal testimony. (Ex. 10.) Due to the limited opportunity for other parties to respond to its proposal, the Commission should allow other parties to offer alternative proposals in the tariff implementation phase of this proceeding.
2.	SDG&E’s Implementation of Rate Reduction Bonds Is Contrary to Commission Policy
SDG&E proposes that its rate class “Schedule A” should constitute its definition of the small commercial class. SDG&E proposes that customers whose demand is less than 20 kW be allowed to switch to Schedule A, so that they can be qualified for rate reduction as mandated by AB1890. In addition, SDG&E proposes that customers, who are offered the rate reduction, not be allowed to switch to other rate schedules before the rate reduction bond recovery is completed. ORA is concerned because SDG&E has separately proposed, in Advice Letter 991-E, to close the time of use (TOU) schedules in its residential and small commercial customer classes; its testimony in this proceeding does not justify its proposal to close these rate schedules in the context of the competitive electricity markets of the future. In addition, SDG&E currently allows all commercial and industrial customers to take service on its Schedule AL-TOU, and if there are any customers with demands under 20 kW on Schedule AL-TOU, requiring them to switch to Schedule A would violate AB 1890’s rate freeze and rate reduction requirements. With respect to the recovery of the rate reduction bonds, SDG&E has not addressed the feasibility of offering customers an option to pay back the benefits they have received through AB 1890’s rate reduction if they wish to switch to other rate schedules. (Ex. 41, pp. 19-22.)
SDG&E’s closure of TOU options to residential and small commercial customers is contrary to the Commission’s Policy decision (D. 95-12-063) on electric restructuring, which emphasizes allowing customers opportunities to respond to variations in the cost of providing electricity over time, as well as to the long history of CPUC decisions that have established TOU options for California’s ratepayers. This closure of TOU options, combined with its proposed rate structure for CTC revenues, is also contrary to the assertions made by SDG&E as to the intended availability of rate options that the Commission relied upon in approving Resolution E-3483 (p. 2): in response to UCAN’s protest of Advice Letter 991-E, which cited the important role that TOU tariffs can play in the transition to the newly restructured electric industry and asked for the tariff closure to be referred to an electric restructuring workshop or working group, SDG&E acknowledged that the “Commission’s vision is hourly rates.” SDG&E then had the opportunity to file replacement tariffs in this proceeding, but instead Witness Hansen testified as follows:
Q.	Does SDG&E have a different or other response to the Commission's interest in a real time price for electricity?
A.	Well, our proposal is that CTCs will be recovered in a way that causes no bill impacts for the duration of the transition period. But after the transition period, I think our proposal allows the Commission's objectives of hourly prices of PX prices to be more closely reflected in bills. So for the duration of the PX -- excuse me -- for the duration of the CTC recovery period, I think the prices will not be changed as the Commission may have desired in some of their opinions that I have seen.
Q.	What time-of-use options is SDG&E proposing to offer to residential and small commercial customers who want to switch to such a rate option after 1-1-98?
A.	Schedule AL-TOU is optionally available to all small commercial customers. And residential customers will have an option available prior to 1-1-98 to switch to a TOU rate option. But after that period that rate option will be closed to new requests for that option.
Q.	You referred in your answer to Schedule AL-TOU. If a customer opted to use that Schedule AL-TOU, would the customer be able to participate in the 10 percent rate reduction program for small customers that was described in AB 1890?
A.	No, not in our proposal.  We are proposing that the rate reduction be only applicable to Schedule A. (8 RT 1133-1134)
That is, SDG&E has stated no intent to offer either TOU rates or hourly rates to residential customers, or small commercial customers who want to participate in the rate reduction bond program mandated by AB 1890, beyond its response to UCAN on which the Commission relied in approving Resolution E-3483. Because SDG&E has not been forthcoming in complying with the intent on which its closure of TOU rates to new customers was approved in Resolution E-3483, ORA recommends that SDG&E’s Schedules DR-VTOU, D-SMF, DR-TOU, DR-TOU-2, and A-TOU, or replacements for them, should be reopened to new customers. An option should also be available to any customers on Schedule AL-TOU as of 12/31/97, with demands under 20 kW, to remain on its rates but be eligible for AB 1890’s rate reduction of at least 10%. SDG&E customers who have received the rate reduction, and later meet the eligibility requirements of a tariff that is not eligible for the rate reduction, should be allowed to switch schedules by repaying the rate reduction benefits that they have received, rather than being prohibited from switching schedules, for the reasons discussed in sections IV.A.6 and IV.C.2 of this brief. (Ex. 41, pp. 19-22.)
V.	Master Meter Issues
ORA supports the testimony of California Mobile Home Resources and Action Association in Exhibit 52, for the reasons stated therein. 
VI.	Bill Format
A.	Comments Common to All Applicants
With the addition of certain subcategories, and the requirement for SDG&E to show the current price of its PX purchases, both as discussed below, ORA recommends adopting PG&E’s and SDG&E’s proposals for the bill formats to be used beginning January 1, 1998. ORA recommends in addition that customers with hourly meters that are read by the UDC should also be able to receive their hourly loads from the UDC (ORA, Ex. 41, p. 38), and the utilities’ responses to cross-examination on this issue indicate their willingness to comply with this recommendation to ORA’s satisfaction (1 RT 25, 110, 138.) 
For the longer term, ORA urges the Commission to establish fuller disclosure requirements now, rather than deferring that issue. Rather than waiting to determine further disclosure requirements, ORA believes that the National Association of Regulatory Utility Commissioners (NARUC) resolution and the TURN/UCAN testimony provide a good basis for adopting fuller disclosure requirements now. This recommendation is discussed at length in Section 3, below.
1.	Rate Reduction Bond Credit Proposals Are Acceptable
In PG&E’s February 14 Supplemental Testimony, PG&E noted that SCE and SDG&E had proposed certain bill credit mechanisms in their cost separation applications, and that the ALJ’s January 31 Ruling required all applicants to propose a means for reflecting this credit. In response, PG&E joined SCE and SDG&E in proposing to implement the reduction to eligible customers by reducing their bill (before taxes) by no less than 10 percent, and to account for the bill credit as reduced CTC collection. The credit will be applied to a direct access customer’s otherwise-applicable schedule (OAS) bill before being reduced by the PX cost. This ensures the amount of the discount remains unaffected by a customer’s choice of direct access. (PG&E, Ex. 2, p. 4-7) ORA endorses these proposals as described by PG&E.
Other issues concerning the rate reduction bond credit exist but pertain to rate design, and thus are addressed in Sections IV.A.6 and IV.D.
2.	Power Exchange Energy Prices Must Be Shown On Bills
As Farm Bureau’s witness Illingworth observes, stating information about the PX price on individual customer bills is essential for customers to evaluate competing bids from alternative energy providers. (Ex. 60, p. 9) This should be required on all customers bills. (ORA, Ex. 41, p. 38)
3.	Other Information Should Also Be Provided
Additional issues have been identified in the testimony of intervenors, notably TURN/ UCAN.
First, regarding the bill format to be used beginning January 1, 1998, ORA’s testimony recommends adopting PG&E and SDG&E’s proposals. (Ex. 41, p. 38.) After considering William B. Marcus’ testimony, submitted on behalf of  TURN/UCAN, ORA agrees that certain additional subcategories would be desirable. Mr. Marcus says PG&E’s proposal for bill itemization is “a good starting point,” and goes on to propose additional details which should appear on the bill. (Ex. 63, p. 19.) 
Mr. Marcus recommends the “Distribution Charge” proposed by PG&E as an item on the bill should be broken into at least two sub-components; “wires,” and various marketing functions. (Ibid.) He also proposes that PG&E’s proposed “CTC and Other Charges” category should be broken into subcategories such as: uneconomic nuclear generation; uneconomic fossil fuel generation; uneconomic purchased power contracts and “other”. (Ibid.) With those additions, TURN/UCAN find the level of disclosure in PG&E’s proposal to be satisfactory at the outset. (Ex. 63, p. 20.) ORA agrees that the additional categories would be beneficial and supports the recommendation.
Next, the Commission  should direct periodically to provide information on resource mix and the environmental characteristics of electricity purchases. NARUC adopted “Resolution in Support of Customer ‘Right-to-Know’ and Product Labeling Standards for the Retail Marketing of Electricity.” (Ex. 68.) The policy statement was adopted as Resolution No. 17 at the November 1996 NARUC convention and urges states to require disclosure as follows:
“Resolved, That NARUC urges states adopting retail direct access programs to include enforceable standards of disclosure and labeling that would allow retail customers easily to compare the price, price variability, resource mix, and environmental characteristics of their electricity purchases.”
ORA believes the level of disclosure which NARUC is supporting is desirable. Further, if other states adopted the level of disclosure recommended by NARUC, California’s electricity consumers should be equally well informed. 
TURN/UCAN also recommends that the PX and all other generation suppliers be required periodically to provide information to their customers on the sources of their generation (nuclear, coal, etc.) and its emission profile for nitrogen oxides, sulfur oxides, particulate matter under 10 microns and carbon dioxide. (Ex. 63, p. 20.) This recommendation for more extensive information is consistent with  NARUC Resolution No. 17. TURN/UCAN recommends beginning data  collection on January 1, 1998 and providing the first six months of collected data within eight or nine months. (14 RT 1804.) ORA believes that TURN/UCAN’s proposed approach to providing this additional information is reasonable, permits adequate lead time and should be adopted. ORA recommends requiring disclosure consistent with the NARUC resolution and the TURN/UCAN testimony to be provided in bill inserts two times each year and upon request.
B.	PG&E
PG&E says its current bill is full, but that it will complete a new bill process in 1997 which will provide room for more information. (Ex. 1, p.4-13 to 4-14.) PG&E expects to present more information as required by customers. (Id. p. 4-14.)
C.	SDG&E
SDG&E proposes to offer customers the option of a simplified or a more detailed bill. These proposed options offer less and more information respectively, than PG&E’s proposal. ORA has agreed with this proposal, but recommends that the PX price must be added to SDG&E’s simplified bill format (ORA, Ex. 41, pp. 37 - 38).
D.	SCE
SCE did not propose an expanded bill format in this proceeding. Rather, it proposed to provide the bare minimum required by AB 1890 and to conduct research starting in mid 1998 and determine whether to do anything further. (1 RT 106.) SCE claims it would have difficulty providing additional information by January 1, 1998. (1 RT 103.) However, there is no apparent reason why it would be more burdensome for SCE to provide expanded information than for the other utilities. PG&E and SDG&E apparently anticipate complying with the forthcoming decision on this issue by January 1, 1998, and SCE should be held to the same standard. SCE also expressed reservations about accepting the recommendations of intervenors in this proceeding as representative of the desires of their clients, even 
declining to accept the results of a  member survey that CAL-SLA suggested it could conduct. (1 RT 107.) CAL-SLA’s witness Schmidt confirmed that his testimony was in fact based on its customers’ desires. (2 RT 162.)

Respectfully submitted,

—————————————
Catherine A. Johnson
Staff Counsel

Attorney for the Office of Ratepayer Advocates

California Public Utilities Commission
505 Van Ness Ave.
San Francisco, CA 94102
Phone: (415) 703-1385
April 30, 1997	Fax: (415) 703-4432