Title: Unscaled
Author: Jim Price

REBUTTAL TESTIMONY ON UNBUNDLING OF
MAJOR RATE COMPONENTS
FOR ELECTRIC INDUSTRY RESTRUCTURING

OFFICE OF RATEPAYER ADVOCATES

I.	Introduction
Witness:  Jim Price

This exhibit presents the recommendations of the Commission’s Office of Ratepayer Advocates (ORA) is response to intervenor testimony filed on February 29, 1997, concerning 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 (Edison).  This exhibit addresses three issues:
.	The conceptual basis for unbundling, as addressed by Agricultural Energy Consumers Association (AECA), California Energy Commission (CEC), California Large Energy Consumers Association (CLECA), The Utility Reform Network (TURN), and Utility Consumer Action Network (UCAN).
.	Assignment of generation and distribution costs to rate components, as addressed by California Association of Cogenerators/ Energy Producers and Users Coalition (CAC/ EPUC), California Industrial Users (CIU), CLECA, and Department of Defense (DOD).
.	Provision of direct access within mobile home parks, as addressed by Western Mobilehome Association (WMA) and California Mobilehome Resource and Action Association (CMRAA).
II.	
Conceptual Basis For Unbundling
Witness:  Jim Price

In somewhat varying forms, AECA (Moss, p. 3), CEC (Jaske, pp. 14-17), CLECA (Yap, p. 10), TURN (Marcus, pp. 1-10), and UCAN (Woychik) recommend separating the utilities’ customer service functions from their Wires Company functions for purposes of cost allocation and rate design.  ORA’s February 28 testimony (p. 4) also made this distinction, by reference to its December 20, 1996, comments on revenue cycle unbundling, and further recommended that the Commission should undertake a more comprehensive separation of non-competitive, semi-competitive, and fully competitive functions within the electric industry, as the Commission has done in telecommunications.  ORA’s February 28 testimony simply noted that the utilities’ cost allocations produce a category that would be better called “UDC” functions than “distribution”, but ORA has no objection to adopting a more refined approach as recommended by these intervenors.  While ORA’s December 20 comments specifically addresses revenue cycle unbundling, 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 require the unbundled functions to be subject to competition.  The conceptual frameworks embodied in CEC, CLECA, TURN, and UCAN recommendations do not necessarily form a near-term basis for the longer-term examination of unbundling that ORA has recommended, but reiterating ORA’s previous comments below helps to provide that foundation.  ORA does not comment on the specific cost allocations recommended by the intervenors, but will explore this in hearings and briefing.
CLECA’s testimony (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.  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.
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 in a distinctive utility function:  a customer access-related component.
One guiding principle in allocating these costs among the major utility functions, beyond simply which entity provides the service, is that cost causation is a key to cost allocation.  For example, estimating and allocating future metering costs are clearly among the prominent current issues in restructuring.  However, no changes are occurring in the provision of distribution system capacity that are causing needs for new metering.  Similarly, while changes in transmission service are occurring (open access in interstate commerce under FERC Rule 888, and an increased Federal regulatory role as generation is unbundled), these changes do not require different metering than is in place today.  Profound changes are occurring in generation markets and it is these changes that have additional needs for metering.  Thus, the incremental metering needs are due to changes in generation, and would more appropriately be assigned to this function than to transmission or a pure distribution function.
To assist in discussing cost allocation among utility functions, a set of terms needs to be defined.  Whereas discussions of electric industry restructuring have commonly used terms like GenCo, TransCo, LineCo, and Wires Company, it is necessary here to distinguish between natural monopoly and competitive functions of the UDC.  ORA has used “Wires Company” to refer to the monopoly functions of the UDC, and coined the term “ServiceCo” to refer to its competitive functions.  (This proposed distinction is not meant to necessarily 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.  ORA’s use of the term ServiceCo is similar to that often attached to “ESP”, and ORA uses these terms somewhat interchangeably herein;  a difference is that ORA uses ServiceCo as a cost allocation concept, similar to a business unit, whereas ESP describes a market function.  Both perform marketing functions including but not limited to metering, meter reading, billing, and customer information.
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 could 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.
An important implication of viewing competitive activities in this way is in the allocation of common costs (administrative and general expenses, etc.).  Chart 1 in ORA’s December 20 comments depicted the relationship of common costs to functional activities, in the context of the FERC system of accounts.  Details of common cost allocation have been examined in ORA’s February 28 testimony as well as in intervenor testimony.
III.	
Assignment Of Generation And Distribution Costs
To Rate Components
Witness:  Jim Price

CAC/ EPUC (Ross, pp. 22-25), CIU (Chalfant, pp. 19-22), CLECA (Yap, pp. 5, 33, 35), and DOD (Brubaker, pp. 23-24), and to some extent CEC (Jaske, pp. 4-5) emphasize setting specific functionalized rate components in rate design, whereas for separation between generation and distribution revenues, ORA’s February 28 testimony (p. 24) supported PG&E’s approach of crediting revenue proportionally.  (ORA recommended that specific unbundled rates must be established for transmission and non-bypassable charges.)  Reasons stated for ORA’s recommendations on this issue included avoidance of unnecessary re-litigation of rate design issues that have been very time confusing over the course of many years of general rate cases (GRCs), 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.  The fact that most utility rates (even those with TOU demand charges) currently collect a portion of “coincident” capacity costs through energy charges can be seen by subtracting EPMC-scaled marginal energy costs from the existing total on-peak energy charges.  To the extent that specific unbundled rates for generation and distribution can be established while preserving existing rate design principles and avoiding unnecessary re-litigation of rate design issues from previous GRCs, ORA does not object.  One way to accomplish this would be to subtract 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.  A more complex alternative would be to subtract adopted marginal energy costs as well as transmission rates and non-bypassable charges from total rates, divide the remainder proportionally between generation and distribution, and recombine the marginal energy cost into generation rates.
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 demand (TOU) 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.  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.  Coincident demand is not a factor in calculating customers’ bills, except on real time pricing schedules.  Given the existence of alternative proxies for coincident demand, the question is which one is a better proxy.  Having reviewed DRA’s testimony on this issue in previous GRCs, Edison proposed in its Test Year 1995 GRC to not increase its TOU demand charges on a relative basis.
ORA’s conclusion that average load, instead of billing demand, is a better proxy for coincident demand can be seen in the following tables, using load research data available to ORA from Edison’s 1995 GRC.  This analysis is pursued through the statistical technique of multiple regression, in which coincident demand on parts of the utility system is the dependent variable and on-peak TOU billing demand and average on-peak load are the independent variables.  The analysis can be structured with load data directly or loads scaled to customers’ maximum demand (to verify that correlations between the variables and a common factor of customer size have not biased the results), with several customer classes, and with demands at different parts of the transmission and distribution system.  For simplicity, the regressions presented here are chosen to illustrate that the results are robust for these variations.
The first table examines Edison’s TOU-8 customers, at each voltage level, and presents results for both the direct use of load data and loads that have been scaled to each customer’s maximum demand.  Because the variables have similar units (kW), the regression coefficients would be zero when an independent variable is unrelated to the dependent variable, after removing any influence of the other independent variable, and about 1.0 when an independent variable is closely related to the dependent variable.  The results show that billing demand is at best a poor proxy for coincident demand, while average load is closely related.  (Coefficients for average load in this table, as well as succeeding ones, can exceed 1.0 because customers’ demands at the time of system peaks generally exceed their average on-peak load.)  Using scaled demands to control for customer size does not alter the general results of the analysis.
Relationship to System Coincident Demand for Schedule TOU-8
| | Unscaled | | | Scaled |
| TOU-8 Secondary | TOU-8 Primary | TOU-8 Subtransmission | TOU-8 Secondary | TOU-8 Primary | TOU-8 Subtransmission
Regression Coefficient:  On-Peak Billing Demand | -0.007 | -0.148 | 0.116 | 0.180 | -0.068 | -0.021
Regression Coefficient:  On-Peak Average Load | 1.054 | 1.201 | 0.930 | 0.856 | 1.092 | 1.039
R-squared | 0.963 | 0.976 | 0.985 | 0.701 | 0.860 | 0.958
No. of data points | 2142 | 816 | 151 | 2142 | 816 | 151

For other Edison customers, ORA has used the load data directly (not scaled to customers’ maximum demands), but presents results for multiple customer groups and for contributions to transmission and distribution system loads as well as generation-level system loads.  The weighting factors applied to customers’ hourly loads in the load research data are the Peak Capacity Allocation Factors (PCAF) derived by DRA as part of the area load analysis that was adopted in Edison’s 1995 GRC for revenue allocation and real time pricing.  For completeness, these tables present results for Schedules GS-2 and PA-2, which have non-TOU demand charges;  the analysis uses TOU demands that were obtained from the load research data in the same way as demands were determined for customers that do have TOU billing demands.  Except for Schedule TOU-GS, ORA’s conclusion that coincident demand is more related to average load (i.e., energy usage) than to billing demand is apparent for all customer groups and for all levels of the utility system.  For Schedule TOU-GS, the sample size is relatively small, and the overall conclusiveness of the regression results (as measured by R-squared) is weaker than for other customer classes.
Relationship to System Coincident Demand for Other Schedules
| GS-2 | TOU-GS | PA-2 | AG-TOU | TOU-PA-5
Regression Coefficient:  On-Peak Billing Demand | 0.005 | 0.872 | -0.201 | -0.178 | -0.095
Regression Coefficient:  On-Peak Average Load | 1.043 | -0.227 | 1.115 | 1.223 | 1.251
R-squared | 0.983 | 0.689 | 0.714 | 0.964 | 0.900
No. of data points | 575 | 38 | 77 | 114 | 31

Relationship to Transmission Peak Demand for Other Schedules
| GS-2 | TOU-GS | PA-2 | AG-TOU | TOU-PA-5
Regression Coefficient:  On-Peak Billing Demand | 0.071 | 0.812 | -0.235 | -0.095 | -0.052
Regression Coefficient:  On-Peak Average Load | 0.947 | -0.211 | 1.221 | 1.072 | 1.117
R-squared | 0.990 | 0.694 | 0.797 | 0.972 | 0.939
No. of data points | 575 | 38 | 77 | 114 | 31

Relationship to Distribution Peak Demand for Other Schedules
| GS-2 | TOU-GS | PA-2 | AG-TOU | TOU-PA-5
Regression Coefficient:  On-Peak Billing Demand | 0.113 | 0.806 | -0.231 | -0.138 | -0.032
Regression Coefficient:  On-Peak Average Load | 0.908 | -0.225 | 1.220 | 1.145 | 1.141
R-squared | 0.990 | 0.703 | 0.802 | 0.976 | 0.942
No. of data points | 575 | 38 | 77 | 114 | 31

Based on these results, combined with the other reasons discussed in ORA’s February 28 testimony, recommendations to transfer collection of distribution capacity costs to TOU demand charges should be rejected.
IV.	
Provision Of Direct Access Within Mobile Home Parks
Witness:  Anthony Mazy

Testimony concerning the provision of direct access within mobile home parks has been submitted by WMA and CMRAA, as well as ORA.
WMA cites a lack of “consensus”, but that characterization is misguided.  In reality, it is WMA alone that is disturbed by the prospect of Direct Access for its tenants, and this is part of the absence of unanimity required for “consensus” in this matter.  The “joint proposal” repeatedly cited by WMA as “progress” was but a workshop draft that CMRAA subsequently declined to adopt.  CMRAA now insists, as does ORA, that submetered mobilehome park residents enjoy the opportunity to participate in the restructured electric services industry, in so much as economically realistic opportunities present themselves.  WMA seeks to restrict the opportunities available to submetered tenants solely because it might be inconvenient to the submetered system operator.  If this is a “reasonable and practical” basis on which to decide whether some residents of the state should enjoy Direct Access, we might as well refer the opportunity of Direct Access for the rest of the state’s residents to the opinion of UDCs as to its reasonableness, practicality, and convenience.  There is no “reasonable and practical” compromise between equal footing and existence as second-class citizens.
There is no reason to deny submetered mobilehome park tenants the opportunity to participate in Direct Access.  Here, “opportunity” is the key word.  Submetered mobilehome park residents should not be left in any more-favored nor less-favored position than any other resident of the state, but they must be allowed to exercise their opportunities as they find them.  Such opportunities should be enjoyed by these people, according to their own standards of values, as any other resident of this state enjoys, with the same responsibility for the weighing of respective costs and benefits, and the same responsibility for leaving others unharmed by those decisions.  
No one appears to share WMA’s extreme view of limiting Direct Access to submetered tenants.  No utility has formally denied the right of submetered tenants to seek Direct Access (although one has indicated its preference for having its obligations spelled out for it by the Commission).  No one (other than, possibly, WMA) finds fault with the existing discount method for resolving cost and revenue separations between the UDC and the operators of submetered systems—and at least one utility reiterated the relevance of that method in its own filings.  No one disagrees that submetered tenants must be responsible for any additional costs they impose on their landlords—subject, of course, to the same standards of “reasonable” costs that UDCs are held to with their customers.
WMA’s proposals for supplementary cost-recovery neglect both the practical history of applicable rate proceedings (in which even the “reasonable costs” historically incurred by mobilehome parks routinely exceed the “reasonable cost” avoided by the utility for these services) as well as current restructuring proceedings regarding the relationship between CTC collection and the rate freeze.  The Commission should disregard any suggestion to reopen such proceedings for the benefit of WMA.
ORA endorses CMRAA’s Comments without exception.  ORA’s only effort to amplify upon CMRAA’s Comments would be to emphasize again the legislative intent of P.U. Code Section 739.5, that all of the state’s citizens receive electric service on the same terms.  In today’s case, this means monopoly UDC distribution services under regulated rates, metering and billing services from competitive sources under regulated allowable costs, and energy from competitive sources at competitive prices.  This concept is simple and straightforward, beyond any party’s effort’s to make it appear complicated.