1.	Overview and Policy
Witness:  Jim Price

This exhibit presents the recommendations of the Commission’s Office of Ratepayer Advocates (ORA) in response to the March 9, 1998, revised testimony of Pacific Gas and Electric Company (PG&E), San Diego Gas and Electric Company (SDG&E), and Southern California Edison Company (Edison) regarding their applications (A.97-11-004, A.97-11-011, and A.97-12-012) for the adoption of credits for revenue cycle services provided by energy service providers (ESPs).  On February 27, 1998, ORA distributed its Phase 1 testimony discussing the context in which these credits are being considered, recommending a general framework for these credits, and addressing how variations in cost of service should be analyzed.  This exhibit in Phase 2 of this proceeding now recommends specific credit amounts, ratemaking and accounting procedures related to these credits, and a mechanism for future changes to the adopted credits.  This chapter provides an overview of ORA’s recommendations and establishes the policy principles that guide these recommendations.  Chapter 2 then presents recommendations for specific details of revenue cycle credits to be available beginning January 1, 1999.
Consistent with the Commission’s policies established by D.96-10-074 and 97-05-039, ORA recommends pricing revenue cycle services on an incremental cost basis, with specific credits being addressed in Chapter 2.  An overarching policy recommendation is that the Commission should seek consistency in the ratemaking methodologies between utilities whenever possible.  Although differences in ratemaking treatment have been accepted in the past on issues that exist for all utilities, the impact of newly opened competition throughout California means that the impact of ratemaking issues for each utility is no longer limited to its service area, and that consistency among utilities with respect to rules and protocols for ratemaking is much more important than in the past, even though the tariffed rates themselves reflect differences between the utilities’ own operating costs.
A.	Background
ORA’s Phase 1 testimony described the development of unbundled revenue cycle services, and detailed how Decisions (D.) 95-12-063, 96-10-074, and 97-05-039 have progressively defined the Commission’s inclusion of competition for revenue cycle services as an integral part of electric industry restructuring.  Decisions in the Direct Access portion of the electric restructuring proceeding (e.g., D.97-10-087) have defined additional rules for how revenue cycle services will be provided, and the 1997 proceeding regarding separation of major rate components (A.96-12-009 et al, resulting in D.97-08-056) established pertinent Commission policies for rate unbundling.
The Commission's concern for the relationship between the unbundling of revenue cycle functions and the provision of Direct Access opportunities to residential and small business customers is well founded.  The unbundling of these functions is necessary, not only to facilitate the offering of competitive options to all customers, but also to insure equal opportunities for new ESPs to compete with the Utility Distribution Companies (UDC) for retail sales.  Beyond the ratesetting efficiencies anticipated, the unbundling of these functions from distribution operations is an essential factor in the effectiveness of Direct Access as a market alternative to regulatory command and control.
ORA sees many opportunities for innovative service to customers through unbundled revenue cycle functions, and asked the Commission in December 20, 1996, (12/20/96) comments, in R.94-04-031/ I.94-04-032 concerning revenue cycle unbundling, to ensure that electric industry restructuring includes all actions that are necessary to achieve the Commission’s stated goal of offering competitive options to all customer classes, one of which is to unbundle customer service functions, including billing, metering, customer information, and collections – which had become known as “revenue cycle” activities.  D.97-05-039 subsequently adopted rules allowing the competitive performance of these activities, similar to those recommended by ORA.  ORA’s remaining comments of 12/20/96 remain as valid guidance for setting rate credits for these activities.
Unbundling customer service functions and providing equitable rate credits is necessary not only to facilitate the offering of competitive options to all customer classes, but also to ensure equal opportunities for new marketers to compete with the UDC for retail sales.  Unbundling billing allows marketers to distinguish their services in the marketplace, enables realistic customer choice by allowing customers to receive a single bill and make a single payment, regardless of their generation supplier, and ensures that customers of marketers who do their own billing will not be forced to pay the UDC to prepare bills that do not need to be prepared.  Unbundling customer service functions can also allow marketers to devise methods of delivering these services that save costs relative to conventional utility service.  For example, a marketer could cause a meter to be installed that can be read remotely (regardless of separate decisions as to who installs and controls the meter), have the meter read twice per month, and receive payments through automatic electronic transfers, thereby achieving cost savings by reducing cash “floats” and uncollectibles.  Beyond marketing opportunities, allowing competing suppliers to influence metering decisions can allow them to add advanced energy control services to their market offerings.
B.	Recommended Policy Framework
The Commission concluded in D.96-10-074 that while these revenue cycle 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, beyond simply which entity provides the service, is that cost causation is a key to cost allocation.  For example, while estimating and allocating future metering costs is a prominent current issue in restructuring, 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 the marketing of generation, and appropriately, metering has been unbundled as a function that can be performed by competitive ESPs as they market generation.  Although retail metering is carried out by the UDC business unit in the restructured utility, it should be seen as a competitive activity, not as a monopoly function.  Services that can become competitive (i.e., are not natural monopolies) should be treated as merchant functions, instead of as part of the UDC’s Wires Company function.  (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 within the UDC.)
Pursuant to D.97-05-039, which resulted from parties’ 12/20/96 comments and subsequent additional rounds of comments, the UDC’s costs of providing competitive services will be credited on retail customers’ payment responsibility to the Wires Company, and charged to customers by whichever ESP provides the service to the customer.  This rate design structure is easily implemented during Assembly Bill (AB) 1890’s rate freeze because the CPUC must avoid double-charging for costs that are necessarily provided by ESPs and no longer provided by the UDC.  However, as the market matures, this functional separation should be enforced by assigning the UDC’s revenue cycle costs to its competitive merchant function instead of its competitive Wires Company function.
An important implication of viewing competitive activities in this way is in the allocation of common costs (administrative and general expenses, etc.).  In their proposals for rate unbundling in A.96-12-009 et al, the utilities proposed to allocate none of the residual common costs (after direct and indirect cost assignments) to generation, invoking incremental costing principles.  This would, of course, raise the loading of common costs on the distribution and other regulated functions.  The residual common costs amounted to about 5% of total electric costs.  ORA disagreed that the regulated share of residual common costs should be increased because of the event of unbundling, and in D.97-08-056 the Commission adopted ORA’s recommended allocation principle of allocating common costs to competitive functions.  Similarly to the principle that if the generation function needs the capital and O&M that were allocated to it in the past, then such capital and O&M should continue to be needed by the generation function after its unbundling, ideally any residual common costs not needed by the UDC as a Wires Company (including those allocable to its merchant functions) after revenue cycle unbundling can in principle be shed through rental agreements or through other means.  In any case, once competitive market conditions develop, the unbundled allocation of residual common costs to the distribution Wires Company function should not include those that would otherwise be allocable to competitive functions.  The achievement of a fully competitive status for revenue cycle functions (and ability to allocate residual common costs) is limited for 1999 because of the UDC’s default provider status, as noted in ORA’s Phase 1 testimony, but the UDC’s default provider role should decrease over time.
In order to ensure that a set of appropriate credits can be determined to initiate this type of unbundling by January 1999, D.97-05-039 and testimony in Phase 1 of this proceeding have identified a specific list of activities for initial cost analysis.  ORA’s Phase 1 testimony identified changes in the market structure, as it matures, that may add to this list.  Additional activities must be undertaken by a competing ESP although they do not necessarily avoid costs by the UDC, at least in the short term.  For example, customer information is a cost that each ESP (including the UDC’s merchant function) incurs, even though a customer’s original supplier cannot avoid this cost when the customer changes suppliers (since it remains a UDC customer for monopoly services).  Costs of interacting with the Power Exchange and Independent System Operator may vary with the number of customers that an ESP supplies, although it seems unlikely that the UDC’s cost of this function will change until markets are well developed.  However, the billing process includes collections (i.e., the “uncollectibles” portion of calculating a UDC’s rates), between the steps of asking for payment and accounting for its receipt;  not only is the process used (and hence the success of collection) under the control of the ESP, but limiting the UDC’s bill collection to gas instead of combined service limits the UDC’s exposure to uncollectibles.  Other examples could be cited, but it should be clear without enumerating all examples that care should be used in reaching a conclusion that a particular activity cannot be avoided.
C.	Incremental Pricing Principles
D.96-10-074 asked for the parties’ estimates of revenue cycle costs, including incremental cost of the hourly meter, a methodology to estimate potential cost credited to the hourly meter, and the allocation of common costs with installation of a single meter.  D.97-05-039 again directed cost studies to be submitted, resulting in the applications in this proceeding.  What is necessary in these studies is to have the customers’ rates properly unbundled, to reflect the full spectrum of the customer service components.  By expressing a meter cost, for example, as a reduction to the UDC’s rates similarly to the PX price to the customer, the customer can choose a different supplier for the energy or for the meter.
ORA’s 12/20/96 comments in response to D.96-10-074 advanced a policy framework for unbundling and ratesetting, described the use of incremental cost based rates to represent the net avoided costs associated with revenue cycle services, and examined benchmarks from material previously presented or used by the utilities concerning customer service functions, as guidance in judging the reasonableness of cost estimates that were submitted concurrently by other parties.  Although D.96-10-074 and D.97-05-039 requested cost studies to establish a basis for further action on revenue cycle unbundling, the Commission did not issue specific directions on the type of incremental cost (i.e., net avoided cost) study.  The Commission has used various forms of incremental costs for different purposes;  for example, the summation of marginal costs from various components is used to allocate the revenue requirement to customer classes.  Incremental cost is the change in costs associated with a change in the quantity produced, but for the electric utility industry, the increment of quantity varies depending on the costs that are being examined.  In the gas industry, long run marginal costs are the costs associated with a change in demand over a given time horizon, typically over ten years;  these marginal costs are also used for allocation purposes.  In the context of competitive revenue cycle services, “incremental” should refer to cost variations relative to the number of customers, not to the presence of competition or of some number of competing suppliers.  ORA’s 12/20/96 comments used cost estimates that already exist from various sources as benchmarks for evaluating cost estimates submitted by other parties.
Access to competitively priced inputs does not necessarily imply that the incremental costs of metering services which use those inputs are the same for all providers of metering service;  this limits the Commission’s ability to determine bounds for the UDCs’ pricing of competitive services, at this time, to the setting of regulated rates.  The incremental costs are the same for all firms only under the restrictive conditions of a perfectly competitive market at equilibrium.  As described in ORA’s 12/20/96 comments, the four conditions of perfect competition are:
1.	The products are identical across sellers.
2.	Each buyer or seller is sufficiently small relative to the market that he or she cannot influence the product price.
3.	All resources are complete mobile.
4.	Consumers, firms, and resource owners have perfect knowledge of economic and technological data.
The assumption of  access to competitively priced inputs can be interpreted as satisfying condition 3:  mobility of  resources.  The specification for incremental costs for a given set of functions and features is consistent with condition 1 (identical products).  However, it is unlikely that condition 4 (perfect knowledge) will be satisfied since technology is currently in a state of flux.  Firms will learn and adopt new technologies at different rates, although it is anticipated that the new technology will result in declining costs.
However, even if the Commission were to assume the restrictive conditions of a perfectly competitive market, a result of the marginal cost being the same for all firms which produce at the market clearing price would require information on the industry’s supply and demand functions.  Even if the Commission were to assume that incremental cost is the same across firms, using a less restrictive model of contestable markets, it is not clear at present whether the cost information available for the existing providers (the UDCs) form a valid proxy for a market supply function.  Incremental cost data is readily available for only one point on the UDCs’ cost functions, i.e., the incremental cost for their current level of demand, and the increment of demand underlying the cost studies may differ from firm to firm.  In addition, as it relates to customers’ response to the newly competitive energy market, information is not available regarding customers’ demand, the other essential element in determining the market equilibrium price.  Although prices should reflect cost of service, failing to include all pertinent costs and thus setting prices for the existing providers (the UDCs) too low may prevent competitive markets from forming.  This would prevent the Commission from gathering the information needed to address the issues described above.  Thus, while incremental cost is the appropriate guideline for setting credits for revenue cycle services, the Commission should be cautious before imposing limitations when setting the initial credit level, and ensure that the adopted credits are adequate to allow competitive markets to form and thereby reveal broader information about market prices.
D.	The Commission’s Tradition of Marginal Cost Pricing
The Commission has sometimes used marginal cost and incremental cost interchangeably, and therefore a review of its marginal cost methodologies is useful when commencing a review of incremental costs.  The Commission’s recent decisions on costing methodologies have explained (see, e.g., D.96-04-050, pp. 17-24) that it has relied on marginal cost principles to simulate the pricing structure and has distinguished three principal cost components in providing utility services to their customers:  (1) the cost of providing energy, (2) the cost of meeting a customer’s demand, and (3) the cost of providing customers with access to the utility system.  In order to develop their marginal customer costs, the utilities have normally presented detailed data including costs associated with metering and billing functions.  Within metering functions, meter facility investment costs are presented separately for various customer classes in their rate case filings.  The utilities present the cost of a meter based on typical customer characteristics, for instance, a residential customer or an agriculture customer.  The three California electric utilities’ customer cost determinations can be summarized as follows:
PG&E (A.94-12-005):  PG&E’s marginal customer costs reflect recurring and one-time services.  Recurring services include supervision, billing, accounting, meter-reading, customer contracts & orders, mailing customer bills, collection expenses, customer access equipment maintenance, and miscellaneous customer account expenses.  In addition, existing customer access equipment must be replaced from time to time.  Connecting a new customer to PG&E’s system is a one-time service.  (PG&E 1996 Test Year, Marginal Costs, p. 7-5)
SCE (A.93-12-025):  SCE’s marginal customer cost is separated into two major categories:  (1) the investment-related costs associated with hooking up a new customer; and (2) the expense-related costs associated with installation, customer accounting and billing.  (Exh. SCE-25, Pricing Proposal, pp. 17-18)  Customer account expenses include the following activities:  meter reading, postage, credit, local offices, customer accounting, phone center, domestic write-off, non-domestic write-off, phone bill, LIRA, and others.
SDG&E (A. 91-11-024):  SDG&E’s marginal customer costs are composed of the investment cost of providing access or hooking up the new customer and the cost of adding and maintaining a new customer account, or the customer accounting and collection costs.  (Cost of Service Report, pp. 1-14 to 1-15)  Customer accounting, collection, and other customer service and O&M costs include customer payments, postage, meter reading, customer services, instructional expenses, selling expenses, credit management, collections, billing, and book keeping expenses.  (Rate Window filing, Marginal cost report workpapers, July 1995, p. 064)
The contrasts between the utilities’ marginal customer cost approaches include two methods for determining the cost of meters:  (1) rental and (2) new customer hookup approaches.  The rental approach computes the incremental cost of access equipment and annualizes it using a real economic carrying charge (RECC).  The rental approach implies that the customer pays an annual (or monthly) rental payment for using the customer access facility.  Lately, the Commission has moved toward using a new customer hookup approach, which distinguishes between existing and new customers (e.g., D.96-04-050, p. 63).  Instead of assigning a rental charge to all customers, the new hookup method treats the utility’s incremental cost of installing a new meter or replacing an existing meter as the lump sum cost of the new meter, which is assigned to each class on the basis of the number of new customers and estimated replacements.  This meter cost can also be regarded as the cost that the utility will avoid if the new meter is installed by another market entrant.
E.	Issues for Future Resolution
To properly unbundle rates, the Commission has stated that it would apply the telecommunication model:
“We envision three major stages in completing product or rate unbundling for electric services, which will address both rate unbundling and rate design.  This approach is similar to that used to unbundle the basic network functions for telecommunications.  The first stage is to identify the components of electric services.  The second stage is to establish costing methodologies and perform cost studies for each service, and the third stage is to price the component services.”  (D.96-03-022, p. 35)
As ORA has similarly recommended in its 12/20/96 comments, in A.96-12-009 et al, and in Phase 1 of this proceeding, methodologies from the telecommunications industry should be explored in order to separate monopoly versus competitive functions of the UDC as the electric industry is restructured, including analysis of unbundled functions as a series of “building blocks” that, in total, comprise utility service.  Although crediting approaches are a practical way in this proceeding to expeditiously functionalize the utilities’ revenue requirements in the context of AB 1890’s rate freeze, the result includes a “distribution” function that would more properly be described as a 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 methodologies used in telecommunications to functionalize utility service among non-competitive, semi-competitive, and fully competitive functions.
Even before the telecommunications model can be applied, ORA anticipates that the cost data for these services will need to be reexamined over time as the Commission and the parties gain more experience in the new market’s operation.  In addition, technological changes will also lead to cost changes associated with these services.  The unit costs of metering and billing filed by the utilities in their rate cases and in this proceeding vary, even for homogeneous sets of customers such as residential, and future analyses may allow greater consistency.  As in the supply of generation services, suppliers of revenue cycle services will now be subject to competitive pressures from the market in order to reduce service costs to the customers.  However, the unit cost data presented in this proceeding has been described by the utilities as representing their current operations, i.e., as consistent with the data that has been used to form part of their revenue requirement.  Therefore, these data can be reasonable for use as the basis for credits reflecting costs that are avoided when customers choose a supplier other than the utility.  (ORA’s recommended methodology does modify the utilities’ proposed calculations, as discussed in Chapter 2.)  Once additional competitive cost information is available, the Commission may choose to use the options offered in the market as a benchmark in determining the utility’s future credits.
Update procedures resulting from this proceeding should first recognize that many assumptions have been necessary in conducting the cost analyses that are being reviewed, including but not limited to market penetration level, mix of customers choosing direct access and unbundled revenue cycle services, and characteristics of new energy marketers.  After adopting credits applicable for 1999 in this proceeding, a significant effort should be anticipated to update credits that would be effective for the year 2000, based on market experience through mid-1999.  Subsequently, annual reviews should be conducted as recommended by SDG&E, with the scope of effort to be guided also by the Commission’s goal of applying its experience with telecommunications industry restructuring to the context of electric industry restructuring.
2.	
Recommended Revenue Cycle Credits
Witness:  Jim Price

This chapter presents ORA’s recommendations for specific details of revenue cycle credits to be available beginning January 1, 1999, following the policies recommended in the previous chapter.  Table 2-A contains the values recommended by ORA for revenue cycle unbundling credits to be implemented on January 1, 1999.
The credits recommended in this chapter correspond to those recommended in ORA’s Phase 1 testimony, and are discussed in sections organized in the same manner.  Segments within credit categories are as recommended in ORA’s Phase 1 testimony, except that (1) the analysis of credits for Full Consolidated ESP Billing will be presented on May 11, 1998, (after the April 15 filing of additional utility testimony) as discussed in ALJ Malcolm’s March 30 ruling and at the hearing of April 1, and (2) analysis since ORA’s Phase 1 testimony has resulted in Meter Ownership credit segments for new construction and for purchase of existing meters in-place being unnecessary if ORA’s recommendations for the method of calculation and implementation are adopted.  (If ORA’s recommendations regarding these situations are not adopted, the additional segments would be required.  For purchase of existing meters in-place, the difference in meter ownership credit would be the amount subtracted as offsets in PG&E’s and SCE’s proposals.)
The credit segments in Table 2-A consist of rate schedule, commodity (electric-only versus combined gas/ electric), geographic zones, and (in the case of PG&E) existing meter reading technology.  As recommended in ORA’s Phase 1 testimony, a customer whose ESP has contracted with the UDC (or otherwise arranged) to provide revenue cycle services for gas should be treated as electric-only for purposes of this proceeding.  Where credits are based on the customer’s rate schedule, they should be based on the applicable schedule for the month for which service is rendered, rather than on the rate schedule on a past date.  Thus, if a customer changes from a non-time-of-use (TOU) schedule to a TOU schedule, the TOU schedule’s credits should apply.
The utilities’ exhibits contain detailed descriptions of the activities involved in revenue cycle functions, and of their proposed calculations.  These descriptions are not repeated here, and instead are summarized where it is useful to contrast them or to differ with their findings.  In many instances, ORA finds that SDG&E’s approach to its “net avoided cost” analysis best reflects the incremental cost approach endorsed by ORA, and ORA recommends the adoption of SDG&E’s methodology in a number of areas.  In particular, SDG&E’s analysis includes the critical step of identifying all UDC activities that could be avoided at 100% market penetration by ESPs before reaching conclusions that only a limited set of activities can be avoided at a low market penetration.  As demonstrated in SDG&E’s testimony, this step of analysis allows methods to be identified by which a UDC’s resources can be redeployed into other activities, rather than allowing a premature conclusion to be reached that its resources are sunk costs.
A.	Summary of Recommendations
For meter reading and meter data management, SDG&E’s methodology for calculating incremental cost should be adopted, except that costs such as vehicle use and hours of miscellaneous activities should be treated as labor cost loaders rather than averaged costs, and that costs of customer inquiries identified by SCE should be added to SDG&E’s credit methodology.  In addition, the geographic basis for credits should be simplified to consist of standard versus high-cost areas rather than five zones.
Meter services can be approximated by a labor cost analysis such as that used by SCE, but meter installation costs (and possibly additional meter maintenance costs) identified by SDG&E should be included in the calculation of credits.
For meter ownership, SDG&E’s annualized capital cost methodology should be adopted.  Costs for processing returned meters, which PG&E and SCE subtract from the value of returned meters, should instead be treated as a cost of meter installation for service to bundled customers, and credited in meter services.
For billing and payment services, SDG&E’s methodology should be adopted.
B.	Meter Reading & Meter Data Management
PG&E, SCE, and SDG&E all compute meter reading costs using analyses of the time required for their workers to read meters in the field, obtain access to the meters (e.g., by walking between customer premises), and perform related activities.  However, SDG&E’s methodology includes a more comprehensive accounting of meter reading activities, which shows that only part of a meter reader’s day can actually be spent in the field, and that the costs of additional hours of its staff (and related equipment use) must also be included in the labor costs.  ORA disagrees with the aspects of SDG&E’s analysis in which it averages the cost of these additional hours and costs of equipment use among customers rather than among what it calls the meter readers’ “productive” hours, and with SDG&E’s conclusion that supervision costs are only “semi-variable”.  That is, regarding SDG&E’s averaging of costs beyond meter readers’ reading and access time, the additional costs should be treated as “loaders” on the “productive” hours’ costs, since reductions in the hours that meter readers spend in the field would enable the additional costs to also be reduced.  If more hours of field time were reduced than the reduction in the number of accounts (for example, by disproportionately reducing the number of meters to be read in low-density areas), costs of “non-productive” hours and of equipment use, per account, should be expected to decrease.  Although this treatment results in a different level of credit in each segment than was proposed by SDG&E, ORA’s recommendation regarding this issue does not change the total revenue represented by the credits.  Pending the issuance of data requests to SCE to enable a company-specific value to be computed for these “loaders”, ORA has used SDG&E’s values for SCE.
SDG&E has treated supervision costs as “semi-variable” rather than “variable” because it assumes that one of its ten supervisor’s time is not avoidable until 10% market penetration is achieved.  However, its assumption that the market penetration level is 10% instead of a lower value, before one supervisor can be redeployed for other activities, implies that all ten of its supervisors are now fully occupied such that any growth in the number of customers in its service area would require the addition of an eleventh supervisor, and SDG&E has not demonstrated that this is the case.  SDG&E has also not demonstrated that as a supervisor’s required time is reduced below full-time, redeployment of its fractional workload to other activities could not occur.  If a utility that is larger than SDG&E employs more than ten meter-reading supervisors, redeployment of a supervisor could occur at a lower market penetration level than the 10% used by SDG&E.  As noted in ORA’s Phase 1 testimony, the actual level of market penetration is difficult to estimate until some actual experience in the new revenue cycle service markets is available.  Therefore, ORA recommends treating meter-reading supervision time as a variable cost.
A further adjustment to SDG&E’s methodology is the addition of customer inquiry costs, as have been identified in the meter reading credits proposed by SCE.  These costs are required for activities such as researching meter history and resolving questions of possibly misread meters.  Due to the relatively small cost of this activity on a per-customer basis, ORA recommends that SCE’s value should simply be used for this credit component, with refinements examined in future update proceedings.  Instead of identifying this cost as part of the meter reading credit, SDG&E has included all customer inquiry costs in its billing and payments credit, so ORA has subtracted the value of SCE’s customer inquiry cost from SDG&E’s billing and payments credit while adding it to the meter reading credit.
A controversial issue identified in parties’ Phase 1 testimony is segmentation based on geographic cost variations.  The utilities express concerns that rates will not accurately reflect cost of service unless geographic de-averaging occurs, while some intervenors express concerns about the basis for distinguishing cost variations and about differing ratemaking treatment between revenue cycle credits and other rates (which are not geographic).  ORA is not fundamentally opposed to reflecting variations in cost of service if they can be analyzed meaningfully, but acknowledges the intervenors’ concerns as well.  As this issue relates to revenue cycle services, ORA is particularly concerned that ESPs who wish to offer revenue cycle services should not be discouraged from serving high cost areas, by receiving only averaged credits.
The utilities have approached their analysis of this issue in different ways.  SDG&E defines geographic zones using ranges of access times between premises (under 30 seconds, 30 to 60 seconds, 60 to 120 seconds, 120 to 180 seconds, and over 180 seconds), with the result that over 90% of its customers are in zone 1.  In contrast, SCE defines geographic zones using a percentage distribution, with 10% of customers each in zones 1 and 5, 20% each in zones 2 and 4, and the remaining 40% in zone 3.  PG&E uses only three zones.  Creating geographic distinctions for meter reading costs would be more meaningful if all utilities were to use a consistent definition.  In addition, ORA is not convinced that identifying low cost zones would be an effective way of combating the possibility of “cherry-picking” that appears to be a significant motivation for the utilities’ proposal of geographic zones, since high density groups of customers occur even within lower-density zip codes and could be identified by other marketing techniques.  While ORA supports the use of zip code as an understandable way to define zones, a single zip code can contain premises ranging from apartments and shopping malls to country homes and ranches.  Therefore, ORA recommends creating a single high-cost zone in this proceeding, containing approximately 10% of a UDC’s customers;  ORA’s recommended meter reading credits, where the zones proposed by the utilities are to be combined, are calculated using weighted average calculations for the zones that were proposed by the utilities.  This recommendation is not meant to preclude further differentiation among geographic areas in future proceedings.
PG&E’s, SCE’s, and SDG&E’s proposals all focus on meter reading costs.  Experience in the new competitive market will allow incremental costs of meter data management activities to be included in this analysis as well as meter reading costs.  ORA has not included these costs in this exhibit because both the UDCs and ESPs will be using new business systems for these activities, and incremental costs of the new systems may be difficult to determine..
C.	Meter Services
The credit category of “meter services” encompasses installation, replacement, and maintenance.  SCE’s methodology is a succinct summary of the costs of these activities, and therefore forms an understandable basis for computing this credit, with modifications as discussed below.  SDG&E’s methodology is more complex in its calculation of similar costs, but is sufficiently compatible with ORA’s recommendations that ORA has used SDG&E’s values without modification.  SDG&E’s analysis identifies the cost category of meter installation, which is not apparent in SCE’s analysis.  Instead, PG&E and SCE have placed similar costs as a cost to ESPs and customers for its required return of old meters, in calculating the meter ownership credit.  PG&E’s and SCE’s treatment is inconsistent with the incremental cost approach recommended by ORA:  meter installation is inherently part of meter services under the utilities’ Direct Access tariffs, and these costs are incurred by the utility because the meters are in use by their bundled customers, not because the utilities’ old meters are returned by a new service provider.  Therefore, ORA has removed these costs from the meter ownership cost calculation and placed them in the meter services credit as a cost of bundled service that is avoided when a competing ESP offers revenue cycle services.
D.	Meter Ownership
SDG&E’s methodology treats meter ownership cost as an annualized capital cost.  This is a simple, understandable approach to this credit category, which parallels methodologies that have been used for marginal customer costs, and ORA recommends its use.
In contrast, SCE’s and PG&E’s proposed methodologies assert that certain costs of returning old meters to the utility should be subtracted from the value of the returned meters.  ORA shares SDG&E’s view that these are overall costs of electric industry restructuring, and are not correctly associated with meter ownership credits.  SCE’s and PG&E’s proposal to subtract these costs from the value of returned meters led ORA to propose an option in Phase 1 for customers or ESPs to buy the old meters in place rather than essentially pay to return them.  SDG&E’s methodology makes a separate segment for in-place purchase of existing meters unnecessary, and therefore it does not appear in the credits recommended by ORA.  However, if SCE’s or PG&E’s method were used, the adopted methodology should ensure that the salvage value for retired meters would always remain positive (or at worst, zero) for customers or ESPs who are willing to take over ownership of their existing meters in-place, and that the UDC is expected to utilize meters that are required to be returned and that are returned in usable condition.  If the salvage value for returned meters is determined by a UDC to be zero (or even approach zero) at a future date, there should be no reason for the UDC to insist that the old meters need to be returned, and its then-existing meter stock should simply be turned over to customers in exchange for its estimated salvage value.  Even before this time is reached, however, allowing customers to purchase their existing meters would promote the goal expressed in D.97-05-039 of minimizing barriers to competition by ensuring that meters can be easily used by other energy suppliers.
ORA’s Phase 1 recommendation to create separate credit segments for new vs. existing construction was addressed during April 1 cross-examination of PG&E’s and SCE’s rebuttal testimony, which stated essentially that conditions for handling this cost difference should be implemented in the new line extension rules to take effect in July 1998, pursuant to D.97-12-098.  PG&E witness Levin explained (Tr. 24) his view of how, procedurally, the resolution of this issue in this proceeding can flow through to the line extension rules without requiring a credit to be added to other tariffs.  SCE witness Fellows addressed how developers’ costs and allowances can be computed to ensure consistent treatment of direct access customers and bundled service customers (Tr. 42 - 46), and stated that (1) the Commission should establish the line extension rules such that if an ESP installs the meter and the allowance exceeds the developer's costs, the UDC should write a check (or similar action) for what its cost of installing the meter would have been, and (2) the calculation of net revenue will be the same regardless of whether the UDC or the ESP performs the metering services.  The intent of the line extension provisions described by SCE would help to ensure equitable treatment among customers, but instead of including the cost of the new meter installation as part of the developer’s cost and assuming that a new customer will select bundled revenue cycle services from the UDC, the Commission should look toward a future time when the UDC's merchant functions are separate from its Wires Company functions for ratemaking purposes, as discussed in Chapter 1.  Therefore, metering costs should be excluded from both the developer's costs and the net revenues that are used to compute allowances.  This would then make the need for a separate revenue cycle services credit for new construction into a moot issue for purposes of setting credits in Phase 2.
E.	Billing and Payments
Billing credits reflect the cost of bill presentation, payment processing, collections, credit, uncollectibles, and customer inquiries.  Bill processing costs would also apply to “full ESP consolidated billing”, but the utilities’ analyses presented to date address only “partial ESP consolidated billing”, so these costs have not been addressed.  (The utilities will file cost analyses of full ESP consolidated billing on April 15, with ORA and intervenor testimony due May 11.  ORA’s recommendations concerning full ESP consolidated billing will thus be addressed in a future exhibit.)
As stated in the introduction to this chapter, SDG&E’s methodology implements the important principle of identifying all UDC activities that could be avoided at 100% market penetration by ESPs before reaching conclusions that only a limited set of activities can be avoided at a low market penetration, thereby allowing methods to be identified by which a UDC’s resources can be redeployed into other activities, rather than allowing a premature conclusion to be reached that its resources are sunk costs.  In addition, SDG&E’s methodology recognizes (and ORA agrees) that offsetting costs that are subtracted from revenue cycle credits should not include (1) costs that are recovered through service fees, (2) “set up” or infrastructure costs, and (3) costs that are more directly relevant to the ESP than to the customer.  Therefore, ORA accepts SDG&E’s methodology for purposes of this proceeding.  (Refinements may be identified in future update proceedings.)  In computing the billing and payments credits recommended in Table 2-A for SCE, ORA has removed the offsetting costs (of which there are several) that SCE and PG&E have proposed to subtract from the credit, because they are contrary to the criteria recommended by SDG&E and ORA.  The volume of workpapers required to present the utilities’ proposed credits for billing and payments demonstrates the complexity of the required analysis, with the result that ORA’s review of the utilities’ proposals is ongoing.  Further examination of testimony in this proceeding (e.g., in hearings) may reveal that SDG&E’s analysis is more comprehensive than SCE’s and that additional adjustments should be made to SCE’s proposed credits for billing and payments, based on the principles recommended in this exhibit, in areas such as payment processing, collections, and customer inquiries.

Table 2-A
Recommended Credits for Revenue Cycle Services
Category and Segment	PG&E	SCE	SDG&E	
Meter Reading & Meter Data Management				
Rate Schedules:  <20 kW, non-TOU				
Commodity:  Electric-only				
Standard areas		$0.49	$0.49	
High-cost areas		$0.73	$1.12	
Commodity:  Combined electric/ gas				
Standard areas		n/a	$0.08	
High-cost areas		n/a	$0.08	
Rate Schedules:  20 - 500 kW, non-TOU				
Commodity:  Electric-only				
Standard areas		$0.64	$0.48	
High-cost areas		$0.88	$1.11	
Commodity:  Combined electric/ gas				
Standard areas		n/a	$0.08	
High-cost areas		n/a	$0.08	
Rate Schedules:  >500 kW (TOU)				
Commodity:  Electric-only				
Standard areas		$4.44	$0.90	
High-cost areas		$4.69	$1.60	
Commodity:  Combined electric/ gas				
Standard areas		n/a	$0.24	
High-cost areas		n/a	$0.24	
Rate Schedules:  Other TOU				
Commodity:  Electric-only				
Standard areas		$1.66	$0.89	
High-cost areas		$1.91	$1.60	
Commodity:  Combined electric/ gas				
Standard areas		n/a	$0.24	
High-cost areas		n/a	$0.24	

Table 2-A (continued)
Recommended Credits for Revenue Cycle Services
Category and Segment	PG&E	SCE	SDG&E	
Meter Services				
Rate Schedules:  <20 kW, non-TOU		$0.09	$0.082	
Rate Schedules:  20 - 500 kW, non-TOU		$0.17	$0.082	
Rate Schedules:  >500 kW (TOU)		$3.48	$0.155	
Rate Schedules:  Other TOU		$0.88	$0.082	
				
Meter Ownership				
Rate Schedules:  Residential, non-TOU		$0.12	$0.13	
Rate Schedules:  <20 kW commercial, non-TOU		$0.12	$1.04	
Rate Schedules:  20 - 500 kW, non-TOU		$0.41	$1.25	
Rate Schedules:  >500 kW (TOU)		$6.68	$3.40	
Rate Schedules:  Other TOU		$1.64	$0.38	
				
Partial Consolidated ESP Billing				
Rate Schedules:  Residential				
Electric-only		$0.544	$1.40	
Combined electric/ gas		n/a	$0.18	
Rate Schedules:  <20 kW, commercial				
Electric-only		$0.544	$1.59	
Combined electric/ gas		n/a	$0.18	
Rate Schedules:  20 - 500 kW				
Electric-only		$0.836	$1.59	
Combined electric/ gas		n/a	$0.18	
Rate Schedules:  >500 kW				
Electric-only		$8.083	$1.59	
Combined electric/ gas		n/a	$0.18	

PHASE 2 TESTIMONY ON UNBUNDLING
REVENUE CYCLE COMPONENTS
FOR ELECTRIC INDUSTRY RESTRUCTURING

OFFICE OF RATEPAYER ADVOCATES

TABLE OF CONTENTS

1. Overview and Policy	
A. Background	
B. Recommended Policy Framework	
C. Incremental Pricing Principles	
D. The Commission’s Tradition of Marginal Cost Pricing	
E. Issues for Future Resolution	
2. Recommended Revenue Cycle Credits	
A. Summary of Recommendations	
B. Meter Reading & Meter Data Management	
C. Meter Services	
D. Meter Ownership	
E. Billing and Payments