Minutes
Ratesetting Working Group
September 17-18, 1996

Note: all handouts made available electronically will be posted on the Working Group's Web site.

Interpretation of Existing Tariffs subteam, 9/17:

To allow additional preparation prior to discussion, this subteam meeting was postponed to October 9.

Analysis subteam, 9/17:

Status of Analysis of Unbundling the Distribution Function into Component Services:

SDG&E's analysis has revealed the availability of a meter reading cost model, which performs optimization based on the set of addresses comprising SDG&E's customer base, and is exploring the quantification of incremental costs through changing the set of input addresses and re-running the model. A user manual exists for the model, and SDG&E will report on the extent of description of algorithms, any proprietary concerns about the model's availability, etc. Parties requested the ability to run sensitivity analyses, and pointed out the need to comply with rules adopted following “AB 475”; some examples of sensitivity analyses were discussed by the group, and parties are invited to send questions to SDG&E (David Croyle) for tests of modeling, e.g., “breaking” the model, determining the extent of variation of results on various dimensions. SDG&E anticipates reporting illustrative/ hypothetical output results, because this is easier than creating illustrative inputs due to the model being more data intensive than first expected. Edison clarified that it should not be presumed to agree with SDG&E's assumptions.

Proposed Mapping between Rate Components and Unbundled Utility Functions:

Dan Pease summarized PG&E's approach. For Schedule E-1 (residential), baseline is assigned between distribution and generation (CTC) such that the amount in distribution would result in a 15% differential after CTC is no longer in rates, with the remainder of the current baseline differential being reflected in CTC rates. PG&E sees nothing in AB 1890 that conflicts with residual setting of CTC rate components. Illustrative rates are based on current rates and revenue allocation. The allocation of revenue requirement by function is illustrative (e.g., does not reflect the actual proposed allocation of common costs between functions; this is the case for all three utilities). For Schedule E-20 (large industrial), (1) transmission rate components are calculated as an equal percentage of current demand charges, with demand charges being used to collect transmission revenues because this is a capacity cost, (2) the same approach is used for distribution rates, except that the customer charge is collected 100% in distribution rates, and (3) residual generation demand charges are all credited to CTC, with energy charges being a combination of Power Exchange and CTC revenues.

Robert Hansen reviewed excerpts of SDG&E's July 15 filing. SDG&E is considering freezing CTC rates as of 6/10/96, leaving latitude to change other UDC rate components. SDG&E does not feel that AB 1890 requires SDG&E to maintain current rate “distortions” that now exist in other rate components.

John Dalessi summarized Edison's approach. Edison assumes that a CPUC rate design will be used for both transmission and distribution after FERC determines the transmission revenue requirement. Edison is considering whether to determine the Power Exchange price on recorded basis rather than a forecasted basis. For distribution rates, it appears that marginal cost revenues may exceed the revenue requirement, in contrast to the relationship for total revenues where revenue requirement significantly exceeds marginal cost revenues.

Full Working Group, 9/18:

1. Review of Agenda, Minutes, and Other Announcements: Regarding the Sept. 13 letter from SDG&E and other parties to Commissioner Duque, concerning the Ratesetting Working Group report on Track 2 issues, Edison expressed concern that they were described as a consensus of some parties, and stated that it expects parties to the RWG to conduct themselves according to established rules and discuss views openly; Edison is concerned that the working group is endangered if discussion occurs outside the process. Some parties expressed a desire to respond to the Sept. 13 letter.

2. Outcome of PBR Prehearing Conference, Identification of RWG Tasks: Comments will be filed Oct. 7 concerning the effects of AB 1890. A workshop will be held the week of Oct. 21, with prefiled comments on 10/18, followed by a prehearing conference. An ALJ Ruling is to be issued with details; if it is not issued prior to the next RWG meeting, Jim Price will discuss needs for RWG action with ALJ Wetzell.

3. Presentations by Utilities on Preparation for 11/15 Filings:

• SDG&E stated that AB 1890's implications are not all clear, and asked if we should postpone the 11/15 filings until AB 1890 can be clarified.
• PG&E identified the issues for its 11/15 filing in the presentation it prepared for the 7/25-26 meetings:
  • Allocate All Shared Costs Based on the Results of an Efforts Study
  • Unbundle the Cost of Capital
  • Explain How to Coordinate the Various Traditional and Restructuring Rate Cases
  • Describe How to Unbundle the Existing Balancing Accounts and Assign their 12-31-97 Balances
  • Describe the Creation/Elimination of New/Obsolete Balancing Accounts
  • Define the Starting Points for the Generation and Distribution Performance-based Ratemaking Mechanisms
  • Unbundle Ancillary Services and UDC Procurement by January 1, 1998
  • Describe How Various Rate Design Issues Will be Resolved
  • Discuss the Detail to be Provided on Customers' Bills
  PG&E reports that shared costs amount to about $388 million, about 5% of revenue requirement. PG&E is examining organizational implications on shared costs as unbundling occurs, such as what would be required if functions were done by separate companies as opposed by 3 business units (generation, transmission, and distribution). Ancillary services and UDC procurement involve a variety of issues to be developed.
• Edison proposes 5 Track 1 items: Generation, Transmission, Distribution, CTC, and Public Goods. One difference between PG&E's and SCE's proposals is the distinction voltage level between transmission and distribution; another difference is that Edison is using the CPUC revenue allocation for transmission, while PG&E is using FERC's 12CP allocation. SCE is using an avoided cost approach for separating generation, and will net transmission out of T&D. Both PG&E and SCE are setting CTC on a residual basis. SCE is freezing tariff charges. The Alternate proposed PBR decision for Edison eliminates ERAM in 1997. Edison is still considering Power Exchange/ CTC accounting mechanisms.

4. Need for Consistency Among Filings: PG&E and SCE are using a separation of revenue requirement for the "Big 5" items (Generation, Transmission, Distribution, CTC, and Public Goods); PG&E and Edison see different rules as applying to the "Big 5" items, and these differences were explored. Their revenue requirement separation differs from the "managerial accounting" approach recommended by SDG&E for distribution services, even when "average attributable costs" are used. The Total Service Long Run Incremental Cost (TSLRIC) approach used in telecommunications also differs from these methods. The voltage level used to distinguish transmission vs. distribution also differs between PG&E and SCE, but no need was seen to discuss this in detail in RWG.