Docket Clerk
California Public Utilities Commission
505 Van Ness Avenue
San Francisco, California 94102
RE: R.94-04-031/I.94-04-032
Dear Docket Clerk:
Enclosed for filing with the Commission are the original and five copies of the COMMENTS OF SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) ON METERING AND BILLING STRATEGIES IDENTIFIED IN D.96-10-074 in the above-referenced proceeding.
We request that a copy of this document be file-stamped and returned for our records. A self-addressed, stamped envelope is enclosed for your convenience.
Your courtesy in this matter is appreciated.
Very truly yours,
James M. Lehrer Senior Counsel
JML:JGM:DOCUMENT.01
Enclosures
cc: All Parties of Record
(U 338-E)
| Order Instituting Rulemaking on the Commission's Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulation | )))) |
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| Order Instituting Investigation on the Commission's Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulation | ))))) |
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ANN P. COHN
JAMES M. LEHRER
Attorneys for
SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue
Post Office Box 800
Rosemead, California 91770
Telephone: (818) 302-3252
Facsimile: (818) 302-1935
Dated: December 20, 1996
With the issuance of the Commission's December 20, 1995 restructuring decision and the signing of AB 1890 on September 23, 1996, California's electric industry embarked on a new era. The public policy issues surrounding metering and billing services now being debated go the heart of the role and responsibilities of public utilities in this new era.
In response to the Commission's October 25, 1996 order, Edison presents its vision of the utility distribution company (UDC) in a restructured industry and a proposal for metering and billing that promotes fair competition, choice for all customers and a timely transition to direct access. Edison envisions the UDC's role as:
Edison's proposal has three key elements:
| 1. Assuring the prompt availability of Direct Access to all customers by installing hourly meters on a systemwide basis. |
Accurate hourly metering is essential to Direct Access and to the ability of customers to change their energy consumption in response to variations in electricity prices. The only practical and cost-effective way that hourly metering can be provided to all consumersparticularly residential and small business customersis through systemwide deployment of automated meter reading (AMR) technology. Edison's AMR proposal is consistent with the current rate freeze and the rate reduction objectives of the Legislature and Commission.
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2. Reaffirming the right of all energy providers, including the UDC, to meter and bill their respective customers for the services they provide. |
Fundamental to the commercial viability of any business is the ability to measure, bill and collect payments for the services it provides customers. Neither the UDC nor any other market participant should be forced to rely on others to measure the services it provides to its customers or to bill and collect for those services.
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3. Enhancing customer choice by providing open access to the generation market through common carrier metering and billing services. |
Edison will make its metering and billing capabilities available to market participants on a regulated, open access, nondiscriminatory basis. Market participants can thus obtain the benefits of Edison's economies of scale and scope.
Edison's proposal achieves the three primary objectives for metering and billing set forth by the Commission on its October 25, 1996 order:
California Public Utilities Code 368(b) 12
D.96-10-074, issued October 25, 1996 passim
| Order Instituting Rulemaking on the Commission's Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulation | )))) |
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| Order Instituting Investigation on the Commission's Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulation | ))))) |
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Southern California Edison Company (Edison) submits these comments in response to the California Public Utilities Commission's (Commission) Decision issued October 25, 1996,/ which requested comments on, and incremental cost estimates for, "alternative strategies for metering and billing under Direct Access, particularly when hourly meters are installed."/
In its Decision, the Commission stated the following objectives for metering and billing in the restructured electric industry:
Edison strongly supports all these objectives. They are fully consistent with Edison's vision of the utility distribution company (UDC) in a restructured electric industry: facilitating prompt availability of Direct Access and effective competition in the generation market; providing safe and reliable electric distribution service, as an equalaccess common carrier; and promoting important public policy goals including consumer protection, energy efficiency, and assistance to lowincome customers.
In these comments, Edison offers a comprehensive proposal for metering and billing that promotes the Commission's objectives. Edison's proposal facilitates Direct Access for all customers as soon as possible by offering a systemwide, nondiscriminatory approach to a competitive marketplace. Indeed, systemwide hourly metering, offered under Edison's proposal, is the only practical way to accomplish the Commission's objective of prompt availability of Direct Access for all customers. Alternative proposals that seek to selectively "unbundle" metering and billing would actually impede most customers' access to the retail energy market and impair customer choice and effective competition in the marketplace.
Section I of these comments presents Edison's proposal for
metering and billing under Direct Access, explains how that proposal
promotes the Commission's objectives, and demonstrates how alternative
proposals for selective "unbundling" would frustrate
the Commission's objectives. Sections II and III discuss
Edison's metering and billing proposal in more detail, including
the issues identified in the Commission's October 25 Decision.
Sections IV and V present cost estimates and comments on
certain specific issues as ordered in the October 25 Decision.
Edison's proposal has three key elements:
The Commission made clear in its October 25 Decision that the appropriate strategy for metering and billing is to be considered as a means to achieve effective competition and customer choice in the generation market, not an end in itself./ This makes overwhelming economic sense. The cost of metering and billing is a relatively small fraction of the $65 monthly bill of Edison's typical residential customer. Moreover, these costs vary widely from customer to customer within each rate class, and few if any of these costs would be avoided if third parties began to meter and bill for their services separately from the UDC. The Commission's focus is appropriately on reducing generation cost through effective competition in that market, and on using metering and billing as a means to enhance that competition.
Hourly Metering is Essential for Direct Access
The Commission's October 25 Decision correctly focuses on the fact that hourly metering is essential for Direct Access. Hourly metering is necessary to accomplish the goals of restructuring, including the "triple benefits" of sending the right price signals to customers:
With hourly metering, all residential and small business customers will be able to have "virtual" Direct Access which will enable them to choose among time-varying rates for electricity, as well as the option of obtaining actual Direct Access.
Systemwide AMR Is The Only Way To Provide Direct Access To All Customers
The Commission has requested the parties to address in these comments on the best way to achieve installation of hourly meters for Direct Access. The only practical way that hourly metering can be made broadly available to residential and small business customers is through the systemwide deployment of automated meter reading (AMR) technology, as we explain in Section II below. The cost of installing hourly meters on a piecemeal, individual basis is simply prohibitive for these customer groups.
The economies of scale and scope available through systemwide AMR, and the savings from elimination of manual meter reading, allow deployment at minimal net cost to customers. Moreover, without AMR deployment, substantial costs would be incurred to install hourly meters on an individual basis for customers choosing Direct Access. With AMR, all customers can receive hourly meters, at a far lower unit cost, and without significant additional total cost.
Systemwide AMR Promotes Customer Choice
Systemwide hourly metering capability also will enhance competition in the generation market by offering customers the greatest flexibility in switching electricity suppliers. Absent systemwide AMR deployment, generation suppliers may attempt to use metering to "lock in" customers by making it difficult or expensive to switch suppliers. AMR thus increases customer choice and the ability to compare and change power providers.
Edison's Competitive AMR Vendor Selection
Edison has announced a pilot project to install a fixed network automated meter reading capability for 20,00050,000 meters. The supplier was selected through an eighteenmonth competitive bidding process involving over 70 vendors and six different technology options. The technology used in the pilot project can be retrofitted or incorporated into meters manufactured by various providers such as General Electric or ABB. Assuming satisfactory experience with the pilot project, Edison is prepared to install an AMR network throughout its service territory over a four-year period./ Edison's analysis of systemwide AMR deployment is set forth in Section II below.
Fundamental to the operation of any business is the ability to measure the commodity or service sold to its customers and to bill for and collect the charges for those services. This is not unique to the UDC. It is a right and responsibility of all businesses, including all market participants in the restructured electric industry. As the Commission noted in its October 25 Decision, "[i]n retail business, seldom does one firm trust another to record and process its pointofsale transactions while few firms, if any, will allow a competitor to record and bill such transactions."/ Just as the grocery store would not permit its competitor to operate the cash register in the checkout line, or the gasoline service station would not permit a competitor to operate the gas pump for its customers, neither the UDC nor any other market participant should be required to rely on others to measure the distribution services it provides to its customers, or to bill and collect for those services./ The Commission and AB 1890 have explicitly recognized the fundamental obligation of the UDC to bill and collect its CTC charges./ As the Commission's October 25 Decision recognizes, permitting the UDC and other energy service providers (ESPs) to "meter and bill independently . . . allows customer choice and allows a level playing field for all buyers and sellers."/
Moreover, the UDC must continue to meter for distribution service in order to accomplish the complex settlement process required by Direct Access. As explained in Section II below, the UDC metering function provides an unbiased metering point essential for accurate PX/ISO clearing among generators, intermediary retail suppliers and customers. Customers and all market participants will benefit from the UDC's role in ensuring accurate metering.
Of course, ESPs would be free to meter and bill for the services they provide. Customers or ESPs can install their own metering equipment, provided the equipment is installed on the load side of the UDC meter and does not interfere with UDC metering functions. ESPs also can bill their customers separately for generation or send a consolidated bill including UDC charges, as explained in Section III below. Alternatively, ESPs can rely on metering and billing services provided by the UDC on a common carrier basis (as discussed in Section I.A.3 below).
ESPs can establish an exclusive billing relationship with their customers without preventing the UDC from billing for itself. An ESP with retail customers can bill those customers for all their electric service (including UDC service) by becoming the UDC's "customer of record," i.e., the party financially responsible for the UDC service. Each of the ESP's customers will have a service address for delivery of distribution services (a UDC meter)/ but will no longer be a direct customer of the UDC. The UDC will deliver the service to the designated UDC meter and will send a bill to the ESP for distribution, CTC and other UDC charges. If the ESP has many customers, the UDC can send the ESP one bill (with itemized billing information for each service address), and the ESP can then send individual bills to each of its customers for all of their electric service, including the UDC charges./
This customer of record option exists today, and, in the future can be extended to provide ESPs access to their customers. It will give those suppliers the opportunity to develop relationships with their customers through the billing process, including related customer inquiries and other communications, without duplicating a UDC bill. It will thereby enhance Direct Access opportunities for residential and small business customers, as the Commission has emphasized.
The UDC, as a regulated entity, has special responsibilities, both to consumers and to the market as a whole./ Since the regulated UDC will perform metering and billing functions for its own commercial purposes, it can and should make its metering and billing capabilities available to market participants on a regulated, open access, nondiscriminatory basis. ESPs can obtain the benefits of the UDC's economies of scale and scope in these activities. For example, Edison will provide hourly usage data from its AMR system to market participants at tariffed rates.
Of course, ESPs are not required to avail themselves of these UDC capabilities. They are free to perform billing and metering functions for the services they provide if they so choose.
The Commission explained the concept of "level playing field" in its October 25 Decision:
By level playing field, we mean not only that parties have comparable access to the generation market through metering and billing but also that such access implies fairness to all stakeholders which avoids cost shifting where, for example, lower costs to one group do not mean stranded costs borne by another./
Some parties have advanced "unbundling" proposals that would deny the UDC and its customers this level playing field. Under these proposals, the UDC would be denied the right to meter and bill for the services it provides to its own customers and be forced to give average "cost credits" enabling others to "cherrypick" lowcost customers. Although proponents describe such proposals as "competition," these proposals do not involve true competition at all. Rather, they involve a regime of artificial regulatory "cost credits," established in litigated proceedings, that would cause widespread costshifting, as explained below.
Edison's customers are presently divided into a small number of rate classes. In each rate class, all customers are served on the same tariff. However, the customers within a particular class are not homogeneous and, in reality, impose different costs on the utility. These cost differences are not reflected in different prices charged to different consumers in each rate class. Instead, costs for all customers in a rate class are averaged and they are all charged under a common rate. This type of cost averaging can be sustained when a service is provided by a regulated monopoly. However, when a regulated service is characterized by cost averaging, opening it up to "competition" will lead to serious problems. Competitors will target those customers who have belowaverage costs for the class and leave the UDC with those customers with aboveaverage costs. This cherrypicking will lead to rate increases for the customers that remain./ Moreover, competitors may be induced to make wasteful expenditures on metering and billing merely to induce uneconomic bypass by customers who are now effectively subsidizing other customers in their class.
Consider the following hypothetical example, illustrated in Figure I1 above. Meter reading costs vary widely according to geographic area and other factors. Suppose some meters can be read for 40 cents a month and others for $1.20 a month, with a system average cost for that service of 80 cents. Unbundling proponents seek to have the Commission require that the lower cost customers, whose meters they would like to read at a cost of 40 cents, be given the average credit of 80 cents on their bills, enabling the ESPs to make a profit of up to 40 cents./ Through this adverse selection the UDC would be left with an obligation to serve only the higher cost customers. The average costs to serve the remaining UDC customers would increase. To recover these costs, the UDC would need to increase its rates for these remaining customers. Thus, the real impact of these unbundling proposals would be to undermine the rate freeze, cause unacceptable cost-shifting, and impose differential rates for distribution services among customers, all contrary to Commission policy and AB 1890./
Cost-shifting raises important social policy issues: Cherrypicking lowercost customers could leave highercost areas disenfranchised from the restructured market; unbundling credit and collections could "redline" entire communities.
Aside from the serious legal impediments and policy objections to such proposals, they would require protracted litigation over disputed cost estimates for various services. Such litigation would not be a one-time burden, because costs would have to be recalculated as markets or technology change. The lessons of the BRPU experience and QF Standard Offer pricing where the Commission set prices by proxy methods which reached 20 cents/kWh and $200/kW-year amply demonstrate the hazards of setting artificial prices through the regulatory process.
In sum, the last thing unbundling proponents want is real competition, in which all market participants would be free to meet their competitors' prices. Rather, they are seeking to exploit the cost averaging inherent in current rate designs at the expense of higher cost customers and the UDC which must serve those customers.
In addition to the costshifting described above, current "unbundling" proposals would seriously impede Direct Access in at least three ways.
First , hourly meters would be installed, if at all, only on a piecemeal basis. Systemwide deployment would not occur. Residential and small business customers would be denied Direct Access opportunities because of the high cost of installing hourly meters on a piecemeal basis.
Second, barriers to competition in the generation market would arise from switching costs imposed by metering requirements of different generation suppliers. Suppliers might attempt to "lock in" customers with metering arrangements that would make it expensive to switch to a lower cost generation provider.
Third, the piecemeal introduction of hourly meters by unregulated, competing entities would frustrate the Commission's longterm strategy of developing standardized communications protocols for metering. Competing suppliers would have an incentive to create a technological barrier to their current customers choosing another supplier.
The integrity of metering and billing in a competitive generation market depends on a complex settlement process that would be jeopardized by fragmenting the metering function as unbundling proponents are attempting to do.
Metering electricity is fundamentally different from measuring the consumption of other products. In an electric power network, a particular supplier's electrons cannot be physically identified as they go to the supplier's customers. All of the electricity that goes through the network must somehow get assigned to customers and suppliers; what customers consume in the aggregate must add up to what suppliers supply in the aggregate, less distribution and other losses. Errors in the metering of one customer's consumption will affect what other customers are charged and what each supplier is obligated to supply or pay for any shortfall. Thus, accurate metering is critical for matching direct access customers with their suppliers, identifying system imbalances and settling up for the costs of the imbalances. Attempts to "unbundle" metering would require expensive and complex audit and enforcement procedures to monitor meter operators not subject to UDC regulation. Even if such procedures were in place, they are unlikely to be fully effective, and serious problems with metering and billing accuracy would occur.
Moreover, the market for electricity has an unusual feature that
makes accurate metering particularly important. Both the customer
and ESPs have an interest in underreporting consumption,
because the electricity supplied by any given seller cannot be
traced to a particular customer. The UDC, on the other hand,
has a strong interest in the proper allocation of imbalances in
the system from any underreporting. Thus, leaving the metering
responsibility to the ad hoc process of unbundling risks
serious disruption of the settlements process and severe (and
unacceptable) prejudice to the regulated UDC.
In this Section, Edison describes the AMR system in more detail, summarizes the process by which Edison evaluated alternative AMR technologies and vendors, and identifies the key benefits of the system.
The major components of the AMR system are illustrated below in Figure II1. The majority of Edison's existing meters will be replaced or retrofitted with a device known as an RMM (Radio Meter Module). The RMM is a simple, lowcost device that can transmit its identification number and energy consumption, either total or hourly, to a PTC (Pole Top Collector). Typically, the PTC is installed on street lights, power poles, or other convenient locations.
The PTC processes data collected from the nearby RMMs and communicates
that data upstream to a WAC unit (Wide-Area Control unit). The
WACs will be located in typical radio locations such as
on existing towers, the tops of tall buildings,
or other suitable locations. The WACs will receive information
from the PTCs and communicate that information to the UDC's data
center. This communication link can occur via any of the
utility's existing communications capabilities, including microwave,
fiber, or telephone, using TCP/IP as the communications protocol.
The UDC data center can then
format, convert and upload the information into a usage database
where it can be made available to all market participants with
authorized access.
In early 1995, Edison began a formal process to identify and evaluate alternative AMR technologies. We first established a set of evaluation criteria that included technology availability, suitability for large scale deployment, cost, hourly measurement capability, two-way communications capability, and adaptability to evolving business needs. We then issued a Request for Proposal to some 70 suppliers. In response, we received proposals from more than a dozen vendors. A multidisciplinary team was formed to evaluate these proposals, and it selected five supplier bids for more indepth review and analysis.
In the final analysis, only the fixed network radio frequency AMR technology met all of the evaluation criteria. Edison entered into discussions with the suppliers of this technology and ultimately selected Itron, Inc. to conduct a pilot project involving 20,000 - 50,000 meters. The effort to install the AMR technology on these meters is now underway and is expected to be complete by mid1997. If the pilot project is successful, Edison expects to be in a position to proceed with full-scale deployment of AMR technology throughout its service area by the end of 1997.
Systemwide deployment of AMR provides substantial consumer benefits, achieves the Commission's stated objectives with respect to metering in a Direct Access environment, and is consistent with Edison's vision of the role of the UDC in the restructured electric industry. Furthermore, as described in Section IV, systemwide AMR deployment is substantially more cost effective than piecemeal installation of hourly meters.
The vast majority of Edison's smaller customers are metered with simple kWh consumption meters which are read manually once a month. As a result, these customers are charged a uniform cost per kilowatt-hour even though the hourly cost of producing electricity varies. Unless these customers obtain hourly meters they will not gain the ability to respond to real-time price signals. This ability to respond to price signals is one of the most essential and fundamental features of a competitive generation market, particularly for residential and small commercial customers.
The issue of price signals is at the heart of the debate over how best to bring the benefits of restructuring to small consumers, and it is on this point that Edison has a significant difference of opinion with the marketers and others who have been urging the Commission to unbundle distribution services. These parties claim that, in order for residential and small business customers to achieve the benefits of restructuring, the Commission must create opportunities for marketers to profit from this customer group.
The marketers' argument focuses entirely on their goal of finding profitable opportunities for themselves. It entirely overlooks the benefits of enabling these customers to respond to hourly price signals. While both are features of the competitive electricity marketplace, Edison believes that system-wide hourly metering is paramount. Most customers, particularly residential and small commercial customers, stand to benefit most from access to hourly price signals. President Conlon, in his comments at the October 10 forum on direct access, expressed such a view:
Well, it is a subject very near and dear, because I -- all through this I just envisioned that the customer would be able to cut his bill more, from how he uses electricity, [and how] . . . he manages his load to low-cost periods, than [I] ever thought he would get from choice./
In that same forum, Commissioner Fessler made the following statements:
And one of the root causes was . . . a pricing system that is indifferent to price signals, and we have a commodity that is very time-price sensitive . . .
Any scheme that encourages customers who continue to be indifferent to the underlying economics of the cost of generation is the wrong scheme insofar as I can see. . . .
[U]nless we allow customers to benefit by responding to price signals, we are not creating the right atmosphere for the consumption of electricity in this state./
Systemwide installation of AMR will enable all consumers to take advantage of the savings opportunities associated with hourly price signals.
Edison's proposal promotes entry of ESPs into the market. Generation providers that want to enter the market without incurring the significant scale sensitive costs of metering can do so, while those who perceive economic benefit in specialty metering and therefore want to install specialized systems can do so as well. Ease of market entry is particularly important to attracting suppliers capable of delivering the benefits of competition to all market segments, especially residential and small commercial customers.
Without systemwide AMR, consumers electing direct access may have to pay for new meters each time they wish to switch between generation providers. Although this cost may be embedded in service charges, or other pricing schemes, it is a real cost that must be recovered from consumers for suppliers to remain in business. This is tantamount to requiring consumers to purchase a new phone each time they switch their long distance company. Such a situation could erect a significant barrier to the ability of customers to switch readily between suppliers, potentially dampening competition in generation markets. Systemwide installation of AMR solves this problem by providing all consumers with hourly interval metering capability as a part of their distribution services.
Regardless of the metering strategy ultimately adopted, the UDC will deliver power and handle customer turn on and turn off requests, complaint processing, system planning, load analysis, capacitor control, capacity management and settlements. Each of these functions will operate more effectively under AMR.
Edison's proposal for systemwide installation of AMR creates material operational and reliability benefits, including, among other things, the ability to:
Edison's AMR system enables multiple provider access to a single meter at the database level. Any market participant can access the AMR data base through standardized communications protocols. These standardized protocols also enable meter suppliers to develop advanced meters for customers that are compatible with the AMR network. Customers can select the type of meter that Edison provides or install their own meter on the load side of Edison's meter.
Edison's AMR system can be configured to provide twoway communications with systems inside the customer's premises through either cable, hybrid fiber coaxial cable, or a radio frequency modem, as shown in Figure II-2./ Those internal systems can be simply informational in nature, such as displaying consumption patterns and billing information, or they can affect control of energy usage based upon metering data and rate structure knowledge.
Efficient settlement of the commercial transactions occurring among market participants is essential to the proper functioning of the new competitive electricity market. In the new market structure, customers or their agents will need to forecast demand one day in advance, with an opportunity to adjust that forecast one hour in advance. These forecasts represent financially binding commercial transactions. In order to determine final settlements, information is required about the hourly prices and quantities of scheduled energy and imbalance energy for each market participant. Without hourly meters, the determination of these settlements would be a cumbersome, complex process. Edison provided the Commission with a detailed description of these issues and their complexity in its December 6th filing./
The figure below illustrates the process for allocating imbalance responsibility among market participants. Meters D1 and D2 are RealTime Meters (RTMs) recording the usage of two direct access customers represented by the scheduling coordinator SC1. Direct access customers D3 and D4 utilize load profiles in estimating their hourly usage and are represented by the scheduling coordinator SC2. Metering points U1 and U2 represent UDC customers utilizing RTM and load profile estimates, respectively. Point M is the interface point between the ISO and the UDC.
In this example, the scheduled load at the customers' meters is 200 MW. Assuming system losses of 20 MW, the total load scheduled at the ISO/UDC interface will be 220 MW. After reading or estimating the actual hourly load at the customers' meters, it is found that a total of 220 MW was actually consumed. The 20 MW difference will be settled with individual scheduling coordinators. If during this hour 250 MW is delivered at point M then there is an imbalance of 30 MW, which is due to various factors, including the use of inherently imprecise load profiles. Since there is no way to divide these imbalances between the several factors potentially causing them or to identify whether they result from the UDC or direct access transactions, detailed settlement protocols must be developed to assign cost responsibility.
Furthermore, final settlements cannot occur until the end of a
complete metering cycle. As illustrated in the figure below,
this cycle can last up to 50 days after the day of delivery.
The entire settlement process is simplified and made more efficient with AMR. AMR will provide more accurate usage measurement for all customers, eliminating load profile errors and reducing meter reading errors. Furthermore, meters can be read on a real time basis, eliminating the need to wait for the monthly metering cycle to end before settlements can be finalized.
The cost to retrofit or replace 3.6 million existing meters and install the associated radio network is estimated at approximately $360 million over a fouryear period. The cost savings generated over a 15year period from the reduction of monthly manual meter reading, and other operational efficiencies, are estimated to offset most of this cost. Edison proposes to recover the remaining cost (i.e., AMR net cost) from our customers in recognition of the added value customers receive from AMR./ Such treatment is consistent with our recently adopted nongeneration PBR, because Edison is significantly expanding the scope of its responsibilities by providing hourly metering for all our customers./
Accordingly, Edison proposes to establish a memorandum account to accrue AMR-related revenue requirement, net of any cost savings, until the change in scope can be reflected in rates when the nongeneration PBR is truedup in 2002. As a part of the PBR trueup, the undepreciated portion of the AMR investment and the balance in the memorandum account would be included in rates, along with a reduction in authorized O&M expenses reflecting AMR cost savings. Edison estimates that it will accrue net costs of approximately $100 million in this account between 1998 and 2001. There would be no rate impact from systemwide AMR deployment during the rate freeze period, and at most a modest rate impact of approximately 25¢ to 50¢ per month for the average customer, which would not take place until after the rate freeze period.
Edison recognizes that other regulatory models could be used to recover the cost of AMR installation. One alternative would be a model under which Edison would be allowed to charge competitive prices for AMR services (i.e., hourly metering and related data services). Under this approach, the cost of the added functionality provided by AMR would be recovered only from those customers that chose to avail themselves of these AMR services. Monthly meter reading would be a regulated, tariffed service available to customers as a default service with costs recovered through existing nongeneration PBR rates. AMR services would be entirely competitive.
Edison does not recommend this
alternative cost recovery model because it treats hourly metering
as a competitive value-added service and is not consistent with
Commission's goal of making direct access available to all consumers.
In addition, it involves the piecemeal installation of meters
which, because of the absence of economies of scale, unnecessarily
increases the cost of providing hourly meters. These higher costs
would be a significant barrier to direct access, especially for
small, or economically disadvantaged customers. Edison therefore
recommends the establishment of a memorandum account, as described
above, since it results in all consumers, regardless of volume
of usage or financial capability, having a level playing field
and an equal capability to reap the benefits of competition.
Like decisions on metering, decisions on billing will play a key role in shaping the restructured electric industry. Decisions regarding billing have the potential to ease the transition to the competitive market or to create unnecessary confusion and distrust of the system. Edison's proposal for billing and related services fully supports the Commission's objectives of facilitating prompt availability of Direct Access for all customers, protecting the integrity of the metering and billing process, and facilitating access to the generation market.
Edison proposes to make available three billing options:
This range of choices offers significant benefits to both consumers and ESPs. These benefits, and the details of each of these options, are described in Sections III.C and D, below.
The Commission recognized that billing includes numerous functions, and different parties may view the scope of those functions differently. In response to the Commission's request in its October 25 Decision, Edison offers the following detailed definition of "billing" as that term is used in these comments.
In the context of Edison's current operations, "billing" comprises four general functions:
These and other activities Edison performs under the general rubric
of "billing" are illustrated in the following figure.
| Figure III-1 |
The overall billing, customer service, credit, and payment functions are neither organizationally nor economically separable. For example, many activities performed by our credit organization rely on information generated from the billing organization. Some of that information must be received in a timely manner in order to generate late notices. Similarly, Edison's customer service organization, which handles customers' billing inquiries and operates Edison's phone centers, depends on the customer database within its billing system to process extensions and payment arrangements. For example, during an unexpected electrical outage affecting a certain area, Edison's integrated billing system can localize the electrical problem through trouble reports placed by customers to the phone center and respond to and resolve the problem promptly. With separate phone centers resulting from piecemeal unbundling of billing, unexpected electrical outages would require coordination of activities among several different and separate entities (e.g., ESP, UDC, etc.) to resolve the outage, leading to unnecessary delays, confusion, and distrust of the system.
In short, the billing and related systems work together in an integrated billing system to support the provision of electric service to Edison's customers. The interdependencies of those functions are illustrated in Figure III2.
Selectively unbundling some of these functions would diminish
the overall effectiveness and efficiency provided by the integrated
billing services, resulting in increased costs and undesirable
impacts on consumers. Edison's billing proposal preserves the
benefits inherent in our current billing system, while also enhancing
direct access opportunities for consumers by allowing ESPs, through
choice of billing options, to establish their own relationships
with consumers.
Edison proposes to make choice in billing available by giving direct access customers the following options:
The UDC will send a bill to the customer that reflects only UDC charges (i.e., T&D, CTC, Public Benefit Charge, etc.). The ESP will send another, separate bill to the customer for only ESP charges (i.e., generation, etc.). This option is illustrated in the following figure.
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This option will allow both the UDC and the ESP to bill the customer independently from one another, as is the case when two or more services -- such as cable TV and telephone -- are provided to one customer.
Because Edison is a regulated entity committed to facilitating the transition to a competitive electric market, we will make our billing services available to ESPs should ESPs choose to utilize Edison's capabilities. The process would start with the ESP sending a bill summary to the UDC enumerating the ESP's charges for each of its customers. The ESP's charges would be reflected in consolidated bills generated and sent by the UDC to all of the ESP's customers. The consolidated bills would include both ESP and UDC charges. Upon receipt of the consolidated bill, the ESP's customers would remit payment to the UDC. The UDC then would remit the ESP's portion of the customers' payments to the ESP. The following figure illustrates the steps involved in Billing Option 2.
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Under Billing Option 2, the UDC would perform all customer billing and related services, including handling customer inquiries, processing payments, and collecting credit, and would provide those services to ESP customers at tariffed rates. Under this option, ESPs can enter the market without having to incur the significant capital investment associated with billing. This option lowers barriers to entry and promotes effective competition in the generation supplier (i.e., ESP) market.
Under this option, the ESP would become the UDC's customer of record. The ESP would bill customers directly for both ESP charges (i.e., generation, etc.) and UDC charges (i.e., CTC, T&D, Public Benefit programs, etc.).
In the example illustrated in the figure below, the UDC sends
a bill summary to the ESP that includes detailed billing information
for UDC charges for each of the ESP's customers. Then, the ESP
sends its customers consolidated bills with both the ESP's and
the UDC's charges. The ESP would be required to "flow through"
to its customers all of the UDC's charges exactly as stated in
the bill summary. Upon receipt of the consolidated bills, the
customers would remit payment. The Commission would need to establish
a procedure for handling those payments in order to comply with
AB 1890, the concerns of the rating agencies in regard to
issuance of the Rate Reduction Bonds, and local government concerns
related to franchise fees. The cost of such compliance would
appropriately be borne by the ESPs./
In order to become the UDC customer of record, the ESP will be required to: (1) assume financial responsibility for payment of the UDC's charges; (2) meet UDC creditworthiness standards;/ (3) satisfy consumer protection and education requirements proposed by the Commission or other agencies; and (4) meet all other Commission requirements (such as requirements for bill inserts). In order to ensure collection of CTC and rate reduction bond charges as required by AB 1890, special arrangements must be developed for security of payment./
To protect consumers and Edison, we propose that the Commission establish procedures to ensure that customers are informed by their ESPs, and the ESPs receive their customers' written permission, before assuming or changing their "customer of record" status. The UDC must retain the right to resume service upon a customer's written notification that they no longer wish to be served by their ESP. Also, the UDC's charges must be clearly presented to the customer in a standardized billing format. Such "anti-slamming" procedures are appropriate to protect the public interest and limit fraud.
For Billing Options 2 and 3, the UDC must also have the right to refuse to make its consolidated bill available for the inclusion of material which the UDC views as harmful to its reputation or to consumers' interests. Similarly, for Billing Option 3, the UDC must have the right to refuse to join in a consolidated ESP bill which contains such material.
Lastly, Edison suggests that, to comply with the Commission's stated goal of encouraging informed customer choices, the PX cost of power be prominently displayed on residential and small commercial customers' bills. This requirement will help reduce consumer confusion and will enhance consumers' ability to make informed choices about their electricity suppliers.
Edison suggests that Commission-adopted registration or licensing requirements are ways in which these criteria may be uniformly applied and enforced, while at the same time, promoting a competitive electric generation market./
Edison's proposal facilitates ESPs' entry into the generation market. As discussed with regard to Billing Option 2, ESPs may rely on the UDC to provide billing services (although they may choose not to) and enter the market without having to incur the significant capital investment associated with billing. Edison's integrated billing system has large economies of scope and scale, which ESPs can take advantage of under regulated, common carrier rates.
Retaining Edison's integrated billing system would allow consumers
to continue to receive a high level of responsive service and
would eliminate the need for a further layer of communication
and coordination among the ESPs, the UDC, consumers and possibly
other entities, both in dealing with individual service problems
or more widespread concerns such as outages due to storms, fires,
or other causes. The Commission recently undertook a comprehensive
investigation of PG&E's response to customers during severe
storms, in a proceeding in which all of the state's electrical
utilities were respondents. Clearly, the efficiency and effectiveness
of response to consumers' concerns is high on the Commission's
priority list, as it should be. That priority should be considered
in the context of any proposal to selectively unbundle billing
services.
The Commission has requested that Edison provide estimates of certain cost information and methodologies with respect to three different metering strategies:
In particular, the Commission has asked for:
a) With respect to meters:
b) With respect to bills:
In Section B, Edison provides a brief overview of cost principles and definitions, to establish the context for the information presented. In Sections C through E, Edison presents estimates of the relevant incremental costs, a discussion of cost credits, and an allocation of costs to generation, transmission and distribution functions.
The major conclusions that Edison draws are as follows:
This section will discuss the definitions appropriate to the issues raised by the Commission.
Marginal cost is the cost of adding one customer or one unit of demand for a service. Incremental cost is the difference in cost caused by a change or increment in the level of service, usually, but not always, divided by the size of the increment. Many concepts used in economics go by the name of incremental cost. These concepts differ by the degree to which inputs are variable, the size and content of increment, including, for a multiproduct firm, the number of service levels varied. Reference to any incremental cost must include a discussion of these latter features.
Some types of incremental cost are used so often that they have specific names. Among these are LongRun Marginal Cost (LRMC), ShortRun Marginal Cost (SRMC), and LongRun Incremental Cost (LRIC). LongRun Marginal Cost is an incremental cost where all the inputs are variable, hence the term "Long Run," and the increment is an infinitesimal change in a single service, holding the levels of any other services and various production inputs (e.g., capital) constant. SRMC differs from LRMC in that some or all of the inputs are fixed; there are many SRMCs, each differing by the degree to which inputs are held constant. For LRIC, the increment can be a large change in the quantity of a service provided, up to and including, the perunit change in cost due to dropping the production of a service completely.
Common costs are costs that are incurred by a firm to supply a group of two or more goods and services. If one product within the group is no longer supplied by the firm, the common costs will still be incurred to produce the remaining products within the group. Such common costs can be assigned to a group of products, but not meaningfully allocated to individual products within the group. For example, a company that provides tax and estate planning services may use one computer. The computer's cost is common to both services. Two companies, one of which provides only tax service, and the other only estate planning service, would each require its own computer. Their total costs would exceed that of one firm's providing both services.
In single product firms with increasing marginal cost operating in a price taking environment, e.g., in a competitive market or under a binding price cap, price will equal marginal cost, and a firm's revenue will cover its costs. In single product firms having economies of scale, a price equal to LRIC will typically be efficient and will cover costs. However, in multiproduct firms where there are economies of scope and, therefore, common costs, pricing at marginal cost or LRIC, which do not include common costs, will fail to cover costs.
Avoided cost is another incremental cost concept. Avoided cost is the change in cost when there is a reduction in the level of a service. Generally, it is taken to refer to a cost savings that is realized when another entity performs some of the functions previously provided by the firm. To make it a useful concept, the size and content of the decrement must be determined. In the case of metering, for example, the change in cost from losing 1000 contiguous customers differs from the change in cost from losing 1000 customers that are spread throughout Edison's service area.
There is an asymmetry between the incremental cost to add a customer and the avoided cost (which would be the basis for a cost credit) of not serving an existing customer. That is, it is not possible to add metering for a customer without adding certain capital costs, for example, the meter. On the other hand, when an existing customer no longer receives services, many common capital and O&M costs, which were previously incurred or continue to be incurred as part of the obligation to serve, cannot be avoided, such as the time spent walking past the location of a meter that is no longer read.
Pricing or giving bill credits based on anything other than customerspecific avoided cost can lead to substantial unfairness and other problems. It can induce inefficient entry if the price or credit is an average rather than a customer specific avoided cost. Customers of an electric utility are grouped into rate groups that are not entirely homogeneous. Consider a situation where avoided cost is calculated by dropping a random 5% of a group of customers; call this the average avoided cost. Systemwide, some customers would have avoided costs that are lower than the average avoided cost and some would have costs that are higher. If a cost credit is calculated on the basis of such an average avoided cost, it will induce new firms to enter and target the customers whose actual cost to serve is below the average avoided cost. The new firms need not be more efficient than the incumbent firm, all they need to do is provide service for no more than the average avoided cost. Such entry shifts costs from the customers in the group who go to the new provider or retailer to the customers remaining with the incumbent./ A correctly calculated cost credit requires almost a customerbycustomer computation, or at least a computation based on the costs of the specific group of customers lost to a retailer. Such a computation cannot be done in advance of identifying the customers who would leave. These avoided costs will be different from those established in today's rate classes. Moreover, it would result in complex and lengthy litigation.
The Commission has requested cost information for individual and systemwide installation of meters under three strategies and for billing services. This section identifies Edison's estimates of the incremental costs that market participants would incur to provide metering and billing services under the three strategies, and describes the costs that Edison would avoid when market participants provide these services under each of the three strategies.
There is a wide range of possible meters that could be installed by Edison or third parties in the three strategies, from the AMR units Edison proposes to install, which can transfer a day's worth of hourly readings by radio frequency transmitters, to units that communicate over telephone lines by modem and store a month's data. Significant scale economies are inherent in installation costs and in the operating and maintenance costs associated with different deployments of meters. Installing meters on a piecemeal basis will fail to capture the scale economies in installation of all the meters in a geographic area. In view of the range of technologies, Edison can only give approximations of the cost of systems other than the one it proposes.
Strategy 1: In the first strategy, Edison would retain its existing meters and presumably continue to read them each month. Third parties could, on an individual basis, install new hourly meters, which retain hourly usage information and communicate to a central location via telephone. There will be additional costs for installing new meters and for duplicate operation and maintenance of the system. Edison estimates that the cost of such meters would require a monthly charge of $25-45 per month./ Because Edison will continue to read its existing meters, there will be no offsetting cost savings. As the Commission has recognized, there will be additional costs in reconciling data among metering organizations.
Strategy 2: In this strategy, third parties could install new hourly meters on an individual basis, and replace Edison's existing meters. The additional costs would be from $20 to $35 per customer-month./ Edison might realize some savings from reselling used meters, and from not installing meters for some new customers. However, the meter-reading costs would remain virtually the same.
Strategy 3: This strategy initially would deploy AMR technology by adding RMM units to 85% of the meters in our service territory (3.6 million meters). The incremental cost would be about $1.50 to $1.75 per customer-month. This is a gross cost, which does not include offsetting O&M cost savings.
The following table summarizes the incremental metering costs of the three strategies. The individual installations represent minimum metering functionality, since they only provide hourly metering capability for customers choosing direct access.
| Figure IV-1 |
Billing and related services consist of a variety of processes which are "delivered" through one or more service organizations. Edison defines billing broadly in this section to include handling billing inquiries, credit and overdue processing, extensions and arrangements, disconnections and field collections, in addition to bill, overdue notice and remittance processing. Many of these processes require close coordination. For example, a customer's call to the telephone center or visit to a local office with a complaint about a high bill could result in a request for a meter reread and/or test, an arrangement to extend payment, or information about DSM programs. Similarly, a field service representative may disconnect service or may accept a late payment directly from the customer. Edison's computer systems maintaining customer information are used by many service organizations, and assist greatly in assuring the close coordination required to provide effective customer service.
In addition, many of the costs Edison incurs are fixed in nature. For example, the same computer program can send 3.5 million bills or 4.0 million bills. Training materials developed for telephone center employees can be just as effectively used for teaching 300 employees as for 600.
This process interdependency among different service organizations and the fixed nature of many costs make it difficult to separate the cost of billing into discrete percustomer values. We can identify costs incurred in telephone centers, local offices (and recently, third party authorized payment agencies), meter reading, field services, credit and customer accounting, but developing incremental and avoided costs on a customerspecific, servicespecific basis is far more difficult. The difficulty does not arise from inadequate accounting details, but from the existence of substantial shared and common costs, as well as sunk costs that will not vary with the number of bills issued. Other costs are fixed, so that the percustomer cost declines or increases as the number of customers grows or falls. Eventually, these complex issues must be addressed by the Commission, if it seeks to unbundle billing services or to provide cost credits. At this time, we cannot give a more detailed response, without a more precise description of the specific types of billing services that the Commission would intend third parties to provide.
If a third party were to provide its own billing services, its incremental costs would vary widely, depending on which specific billing and related services the third party would perform, and the comprehensiveness of the services provided. For example, Edison provides 24hour multilingual access to customer service representatives via a toll free 800 number and staffs its telephone centers based on a 45second queuetime standard. Clearly, a third party could undercut Edison's billing costs by offering a lower quality product no multilingual access, less than 24hour service, a 90second queue than the Commission has required of UDCs in the past.
If Edison continues to provide billing and related services to its UDC customers, and third parties send their own bills, the incremental cost incurred by the third party could vary tremendously depending on precisely what services it offers. In view of the substantial common costs, Edison cannot estimate its incremental cost, although its system average (not avoided) cost is about $3.00/customermonth. The key fact is that there would be virtually no cost savings to Edison and for UDC customers, since Edison would continue to provide its existing range of billing and related services to its UDC customers.
If the Commission were to require Edison to allow third parties to provide billing services, the incremental cost to the third party would again depend upon precisely what services the third party provides. Since Edison would no longer be sending a bill, and perhaps would not be performing some related services, it may have some cost savings. However, these savings would be very small due to the fixed costs associated with many of these services and the interdependencies among the service organizations: there would be cost increases caused by the loss of cost savings previously achieved by the interdependencies. Edison's cost savings would be limited to perhaps only the cost of postage and the paper on which bills are printed. For example, the cost of software development for Edison's billing system is largely fixed, and would not vary if the number of customers it bills were to drop from 4.0 million to 3.0 million.
A simple example of how interdependencies reduce avoided costs
is in Edison's telephone center. Edison has about 600 representatives
and receives about 10 million calls per year. About seven
percent of this call volume is related to service outages, with
billing and related service requests largely comprising the remaining
volume. If Edison were to unbundle billing and create a separate
telephone center just for outage calls (assuming that third parties
would have their own billing centers), these multiple billing
centers would require more than 600 representatives in total
and costs would be higher. Figure IV2 shows call volume
on August 10, 1996, a day when there were widespread service
interruptions due to an outage of the Pacific Intertie, compared
to September 3, 1996 (the day after the Labor Day holiday)
which was the telephone center peak day.
Since there are relatively few outage calls on the systempeak day, a telephone center designed for just billing and related services would need to be nearly as large as the existing telephone center. However, a telephone center designed for just outage response would need to be much more than seven percent of the existing telephone center, in order to handle the occasional peak volume outage days. The avoided cost, if Edison were to eliminate all billing activities completely (which would be unlikely), would be the current telephone center costs less the separate costs of an outage response telephone center, which would be much less than 93% (100% of the call volume less 7%, the average outage call volume) of the cost of the existing telephone center.
The Commission has asked for the source of cost credits, if any, and has asked Edison to outline a methodology which defines "precisely the data necessary to estimate this cost credit and a specific policy to allocate any stranded cost across stakeholders . . . ." The cost credit comes into play if "another party offers a billing or metering choice not now available from the utility." If the Commission were to order UDCs to provide a cost credit to third parties providing metering and billing services, which Edison believes is inappropriate and would oppose, the cost credit should be determined based on the specific costs that the third party allows the UDC to avoid. Developing the cost credit based on the UDC's average cost or its LRIC of providing metering and billing would certainly overstate the avoided costs, allowing third parties to "cherry pick" the cost credit, resulting in cost shifting to the UDC's remaining metering and billing customer. For the reasons described in the previous section, we expect that the costs actually avoided would be very small.
Avoided costs should be determined through a comprehensive and detailed review of the specific processes that Edison currently performs in providing systemwide metering and billing services. Such a review would clearly identify the process changes and associated cost changes that would result from third parties' performing specified services. The process review should identify both cost savings and increases from accommodating third party providers./ The process review would entail the following steps:
Although these steps are relatively easy to describe, their practical application is likely to be both difficult and contentious. Common costs will vary as the scope of Edison's activities change, although the degree of such variation will be difficult to determine. Fixed costs will not vary over a moderate range of customers, but will vary as the scale of operations changes substantially. A firm providing billing services to a few hundred customers might very well use a personal computer, rather than a mainframe computer, because its small size makes a mainframe computer impractical.
The avoided metering costs are likely to be quite small, since Edison will necessarily retain a separate metering function. Edison might save some costs associated with reading meters and would save the cost of installing meters for new customers. Today, meter readers walk about 38,000 miles each month. Even if some customers chose to install third party meters read via telephone, Edison's meter readers would still need to walk 38,000 miles each month, since the third party meters would be scattered along their routes. There may be some fractional amount of time saved by not having to pause to make a meter read; this savings might be offset by the administrative cost of continually updating records to determine which meters are to be read and which are not read. Moreover, Edison will incur additional costs relating to the fact that it must accept and audit data from other parties. The cost savings of not installing new meters raises further complications traditionally, the Commission has avoided creating separate rates for new and old customers, due to the administrative and equity issues that would arise.
Avoided billing costs would be at most little more than the price of postage stamps and envelopes. We are not able to develop precise estimates of avoided billing costs at this time for two primary reasons. First, the costs which are avoidable depend critically on which of our billing functions are transferred to competitive enterprises. Second, the common cost nature of many of our customer service activities has not been explicitly quantified. Moreover, the absence of interdependencies process might add substantial costs, overwhelming any savings.
The October 25 Decision requests a description of "a specific policy to allocate any stranded cost across stakeholders including ratepayers, employees, and shareholders."
If the Commission unbundles metering and billing services as a separate line item on our tariffs, and allows customers to either take or not take these services, the result will be unrecoverable costs for the UDC, including employee severance and reasonable retraining costs./ If the Commission allows third parties to replace Edison meters or billing equipment on either an individual or systemwide basis, which Edison would oppose, then assets which are currently "used and useful" are no longer used. To the extent the UDC is unable to sell those assets to recover its net book value, then there will be stranded investments.
Unrecoverable and stranded investment costs should be borne by ratepayers. Edison's current provision of metering and billing services is reasonable, and the costs of such services were comprehensively reviewed in our most recent GRC. If the Commission takes actions which impair Edison's ability to recover the costs of these services (including the assets which provide these services) in rates, equity and basic legal principles require fair compensation for its shareholders.
The Commission has requested Edison to propose an allocation of incremental billing and metering costs to generation, transmission, and distribution functions. As discussed above, Edison proposes that it continue to provide metering and billing services to all of its customers. Under this approach, 100% of the billing and metering costs should be allocated to the UDCs, and recovered in UDC rates.
Edison does not now meter and bill separately for distribution,
generation, and transmission service. A customer receives one
bill based on the metered consumption at the point of consumption.
It is these metering and billing costs that are now reflected
in rates. Any effort to allocate these costs to generation, transmission,
and UDC functions would be arbitrary and therefore meaningless.
Providing separate billing and metering for generation and transmission
service in the future is likely to create additional metering
costs that the customer will ultimately pay. However, such additional
metering and billing costs are not presently reflected in Edison's
billing and metering costs. Accordingly, none of Edison's current
billing and metering costs is properly allocated to the generation
and/or transmission functions. More generally, Edison does not
believe that efforts to "allocate" its metering and
billing costs to generation, transmission, and UDC functions is
a meaningful exercise. These are costs that are presently reflected
in retail rates and will continue to be incurred by all customers
who rely on the UDC for metering and billing.
The Commission ordered the parties to comment on the following seven issues: meter ownership; access to data from a single meter; installation of meters; competition in metering and billing; meter costs; bill consolidation and billing costs; and technological issues. The first four are discussed below, while the last three have been discussed earlier in the text./
The October 25 Decision states "either the customer, generation provider, distribution utility, or another party could own the meter." The Commission then identified the following factors that will impact this decision: the obligation to provide accurate data and maintain the meter, the impact on per unit meter cost, data collection costs, and customer choice in meter type.
Inaccuracy in metering could lead to significant problems in the competitive market for two principal reasons. First, the meter is the only method by which to measure energy services because energy is intangible. Unlike overnight packages, electricity cannot be traced and recovered. Second, inaccuracies could lead to improper settlements. Edison will be purchasing power from the Power Exchange and distributing it to customers. If customer meter reads are understated, the amount of power purchased from the Power Exchange will be greater than the amount of power that would appear to have been delivered to customers. This difference or "loss" must be allocated to an entity, either the customer, the generation provider, the UDC, or a combination of these entities. Regardless of how this loss is allocated, the party that underreports usage will be able to get a "free ride" from others. For example, if a customer owns the meter and underreports usage, the loss generated by that underreporting will be spread to other entities. This result exists even if the generation provider that sells into the Power Exchange owns the meter. Sales by these generation providers are measured as the energy is delivered into the system, not when energy is delivered to the customer.
In short, the UDC has an incentive to measure usage correctly at the customer level because this is the point the UDC's revenue is determined./ In addition, as a regulated entity, the UDC can easily be supervised for inaccuracy, and has much to lose if it engages in unfair practices, unlike the less regulated customers and generation providers.
UDC ownership also minimizes per unit costs and data collection costs. UDCs can obtain larger quantity discounts on meter purchases than customers and generation providers. In addition, UDCs can better control data collection costs because UDCs have an incentive to purchase compatible meters for all customers. Since customers and generation providers will not be incurring the data collection costs for all customers, they do not have the same incentive to purchase meters that are compatible with those of other customers.
The Commission has identified one potential drawback to "an exclusive franchise" in metering -- customer choice of meter type. In recognition of this drawback, Edison proposes that customers be free to install their own meters behind Edison's and be able to choose the meter Edison installs for them.
Finally, Edison's proposal ensures fairness to all stakeholders by allowing any service provider to own and install its own meter behind Edison's.
The Commission noted that the owner and another permitted party could access data from a single meter; however, such multiple access could lead to "problems of data confidentiality, transactions security, and cost allocation." October 25 Decision at 10. Edison discusses the cost allocation issues in Chapter IV, and the transactions security issues (i.e., fraud) in Section V.A. above.
Although widespread access to information is necessary for an efficient market, data confidentiality concerns should govern the dissemination of market information. Usage information should be disseminated on an aggregated basis such that the usage of a particular customer cannot be determined. Usage information for particular customers should be disseminated only to the UDC, the schedule coordinator, the customer's ESP, and the customer; others should receive the information only with express customer consent.
Contrary to the Commission's assumption, confidentiality concerns do not occur to the "same extent" whether the direct access provider or the UDC controls the meter. The direct access provider will not be subject to the same regulatory supervision as will Edison, and thus cannot easily be policed. In addition, the direct access provider may have an incentive to withhold relevant information from competing ESPs. Edison's proposal of systemwide installation collects accurate information for all customers. This information will be a valuable asset for all market participants.
The Commission has presented two options for installation -- systemwide or individual installation. As discussed more fully in Section II, systemwide installation offers universal Direct Access and economies of scale in both installation and operation of the metering and data transfer system. It also lessens the need for a costly verification and inspection program. Edison has also addressed the downside of system-wide installation -- the limits on customer choice -- by providing mechanisms through which customers can have choice in meter type.
The Commission has asked the parties to describe the economic conditions for competition, specifically the economies of scale and scope and the conditions for open entry in these markets. The Commission then asked the parties to comment on whether the Commission should set "incremental costbased rates" if the parties concluded that the market was "contestable" in the sense that entry could drive prices to incremental cost.
Incremental cost based rates should not be set because such rates are a relic of the old regulatory regime, and because markets for metering and billing are not theoretically "competitive" or "contestable."
A competitive market can exist when firms have pricing flexibility and there are no barriers to entry or exit./ No party has proposed true "competition" where every entity, including Edison, may set prices and compete for customers without an obligation to serve. As discussed above, the "competition" proposed by other parties involves Edison having a barrier to exit (i.e., the obligation to serve) and establishing an average "avoided cost" for a service against which other firms can cherrypick lowcost customers. This form of regulation will only lead to costshifting. Firms will seek only those customers for whom the average imputed "avoided cost" credit is arbitrarily set above the actual avoided cost for the specific customer being served. The remaining customers with costs above the average imputed "avoided cost" credit will remain with Edison.
To avoid costshifting and cherry-picking, the Commission would have to determine precise avoided costbased rates for several sets of customers in which the difference between the lowest cost customer and highest cost customer within each set is negligible. Such a process in theory would involve hundreds of different rates that would vary based upon geography, UDC customer density, customer type, customer demographics, credit record, and other traits. In practice, however, such a process certainly would fail. Edison cannot estimate with any certainty the costs that will be "avoided" with the loss of a specific customer or a small set of homogenous customers. Costs such as customer service inquiries and data collection likely will remain after the "loss" of a customer and certain costs will increase if other firms could meter and bill. For example, Edison will have to continue to read meters for most customers, would have to implement a process for verifying the accuracy of other meters, and would have to create mechanisms to interact with other firms.
The costshifting resulting from these incorrect rates will jeopardize several aspects of restructuring. If low cost customers were "cherry-picked" from the UDC, the UDC's average costs per customer would rise. Such increased costs would put pressure on rates, and thus would compromise the rate freeze as well as the prohibition on cost shifting contained in AB 1890.
Such anachronistic regulation also would compromise the new vision of regulation set by the Commission and the Legislature. A regulatory regime in which Edison litigates its rates before the Commission in costly and contentious proceedings is a thing of the past. Regulation is moving forward based on Performance Based Ratemaking. PBR captures the benefits of competition by providing Edison an incentive to be efficient.
Establishing average imputed costbased rates also sends the wrong price signal for competitive entry. The average rate is a result of combining lower and higher cost customers within a group. The new firms are not competing against the UDC's cost to serve the lower cost customers, but against the artificial price established through regulations that impose a common price for each rate class composed of heterogeneous customers with different cost characteristics. This will result in inefficient expenditures on metering.
For these reasons, the Commission should not set average "incremental costbased rates" for metering and billing by customer class. In any event, in order to be responsive to the Commission, Edison discusses the economies of scale and scope and the conditions for open entry in metering and billing.
Conventional meter reading is a scale-intensive activity in which cost per read is driven primarily by density. Cost is principally based on the number of meters that can be read in one day. Cost-effectiveness will decrease if the meter reader has to travel further between meters and has to spend more time at the meter. If two people walked the same street reading meters, they would spend roughly the same amount of time walking as would one person who read all of the meters. In addition, with two meter companies there would be increased costs in scheduling and creating optimal routes, as well as other additional overhead.
AMR also has economies of scale and scope. Because of the large and expensive infrastructure associated with radio based AMR, average costs decline with additional customers.
As discussed above, the billing function involves four inseparable processes -- preparing bills, processing payments, handling customer inquiries and credit. These functions require the creation of an integrated billing, payment processing, customer response and credit/collection system that operates from the same database. Once this system is created, it can serve additional customers for relatively small cost, creating economies of scale.
In addition, this system requires the interaction of all four billing processes and metering, creating economies of scope both within billing and between billing and metering. Metering and each of the four billing processes operate from the same computer and interact constantly, creating significant economies of scope.
Because of the substantial fixed cost of a systemwide network, there is little likelihood that the market will support two AMR systems. The economics of AMR depends largely upon high penetration because of the economies of scale and scope, which reduces the possibility of competitive entry after one entity has implemented a system. To the extent there is any entry, there likely would be large competing networks with significant overcapacity. Thus, the radio based AMR market will tend toward a natural monopoly.
Potential entry into the billing market is practically difficult
because of the significant economies of scope. The customer service
interdependencies are such that the functions in which there is
potential for competitive entry cannot be partitioned from the
remaining functions. In other words, there is no practical method
of "unbundling" billing without creating customer confusion
and increased costs. In addition, such unbundling would lead
to the cost shifting and cherry picking described above because
it would require the estimation of an average "avoided cost"
for a billing function. In light of these complexities and the
very small potential upside, Edison reiterates that the Commission
should remain within the PBR regime and not revert back to the
cost based regulatory framework in billing.
In these comments, we have shared with the Commission and the other parties our best thinking on how to move quickly, effectively, and fairly toward competition in energy supply through the implementation of direct access for all customers. We strongly believe the underlying principles of our proposal -- in which the UDC will be a regulated, equal access provider of distribution services -- meet the Commission's objectives. Our proposal:
The Commission has made it clear that hourly metering is essential for direct access. Systemwide deployment of AMR is the only practical way to make hourly metering broadly available to residential and small business customers. Edison's proposal increases customer choice and assures customers of the ability to compare and change power providers as easily as possible.
Having presented our proposal in broad outline, Edison looks forward to working with the Commission and other stakeholders to resolve the details of implementation.
Respectfully submitted,
ANN P. COHN
JAMES M. LEHRER
| By: | James M. Lehrer Senior Counsel |
Attorneys for
SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770
Telephone: (818) 302-3252
Facsimile: (818) 302-1935
Dated: December 20, 1996