Puc Docket No
PUC DOCKET NO. 22344
GENERIC ISSUES ASSOCIATED WITH § PUBLIC UTILITY COMMISSION
APPLICATIONS FOR APPROVAL OF §
UNBUNDLED COST OF SERVICE §
RATES PURSUANT TO PURA § 39.201 § OF TEXAS
AND PUBLIC UTILITY COMMISSION §
SUBSTANTIVE RULE 25.344 §
DIRECT TESTIMONY
AND EXHIBITS
OF
ELAINE SAUNDERS
ON BEHALF OF
THE TEXAS RETAILERS ASSOCIATION
INCLUDING CERTAIN HOSPITALS
LOCATED IN THE SERVICE
TERRITORIES OF RELIANT ENERGY
AND CENTRAL POWER & LIGHT
October 16, 2000
Page 3 of 15
TABLE OF CONTENTS
CLASS CLASSIFICATION/RATE DESIGN 1
I. Introduction 1
II. Class Classification 3
III. Distribution Rate Design 7
IV. Transmission Rates 11
V. Standby Transmission and Distribution Rates 11
VI. Exceptions to Standard Classifications 11
EXHIBITS
Elaine Saunders Resume EHS-1
Load Research Data EHS-2
PUC DOCKET NO. 22344
GENERIC ISSUES ASSOCIATED WITH § PUBLIC UTILITY COMMISSION
APPLICATIONS FOR APPROVAL OF §
UNBUNDLED COST OF SERVICE §
RATES PURSUANT TO PURA § 39.201 § OF TEXAS
AND PUBLIC UTILITY COMMISSION §
SUBSTANTIVE RULE 25.344 §
CLASS CLASSIFICATION/RATE DESIGN
Saunders Direct 1 October 16, 2000
Direct Testimony of Elaine Saunders
I. Introduction
Q. Please state your name and business address.
A. My name is Elaine Saunders, and I work at LaCapra Associates, 333 Washington Street, Boston, Massachusetts 02108. LaCapra Associates is a consulting firm specializing in industry restructuring, energy planning, market analysis and regulatory policy. For more than 20 years, LaCapra Associates has served a broad range of organizations involved with energy markets, including public and private utilities, energy producers and traders, financial institutions and investors, consumers, regulatory agencies and public policy organizations.
Q. What are you qualifications?
A. I have worked at LaCapra Associates since January 1994, first as a senior analyst, and now as a consultant. I have worked for a variety of utility and non-utility clients in the areas of electric utility cost of service, rate design, industry restructuring and rate unbundling. Prior to this, I was the manager of rates at Boston Edison Company. My resume is attached as Exhibit ES-1.
Q. On whose behalf are you testifying?
A. I am testifying in Docket Number 22344 on behalf of the Texas Retailers Association (“TRA”) and certain hospitals including Methodist Health Care System, HCA – the Healthcare Company, Thermal Energy Cooperative, St. Luke’s Episcopal Hospital, Tenet Health System, CHRISTUS - St. Joseph’s Hospital, Texas Children’s Hospital, The Institute for Rehabilitation, and Research and Valley Baptist Medical Center (hereinafter “THA”). The members of this group are retail customers of three utilities: Reliant Energy HL&P (“Reliant”); Central Power and Light Company (“CP&L”); and TXU Electric Company (“TXU”). Together, this group of commercial customers is a significant stakeholder in the Texas electric industry restructuring proceedings.
Q. What is the purpose of your testimony?
A. In Order Number 17 of these proceedings, the Public Utility Commission of Texas (“the Commission”) determined that a uniform customer classification and rate design (“CC/RD”) scheme is appropriate for the purposes of standardized transmission and distribution (“T&D”) rates. Regarding customer classification, the Commission will identify approximately six classes of customers for standardized use by all utilities, although exceptions to these standards are permissible if supported by factual evidence. The Commission will also hear evidence on a standardized rate structure for each class that is reflective of the costs to serve.
The purpose of my testimony is to give my opinion as to the most appropriate class classification and cost-driven rate design, in particular for the commercial class customers listed above. My comments in this testimony will relate to the general service rates of three utilities, Reliant, CP&L and TXU. I will not address the lighting and residential classes, both of which differ substantially from the general service classes and from each other in cost-causation and load shape. Thus, of the six classes targeted by the Commission, two must be set aside for residential and lighting classes, leaving approximately four for general service customers.
Q. Please summarize your testimony.
A. In this testimony, I will address the following issues in turn:
Customer classification - Standardized classes should be based on voltage level as the primary determinant of cost-causation. The classes recommended in the September 8, 2000 non-unanimous agreement signed by some of the parties is a good start, but the Commission needs to defer the determination of exceptions until the appropriate information is available.
Distribution rate design – Distribution rates should be demand-charge based as far as practicable, and include customer charges designed to collect metering, billing and customer costs;
Transmission rate design – Transmission rates should reflect cost-causation to the greatest extent possible, and updates to transmission rates should be subject to traditional regulation;
T&D Standby rates – I do not think that an additional rate class for standby customers is warranted; and
Exceptions to the standard classifications and rate designs – The Commission should allow exceptions if there has been a demonstration of significant adverse bill impacts. Similarly, exceptions should also be allowed if the resulting rates would compromise customers’ ability to participate fully in the competitive market and benefit from restructuring.
II. Class Classification
Q. What are the major cost-based factors in the delineation of rate classes for T&D rates?
A. Traditionally, class boundaries have been based on cost-causative characteristics such as voltage level, load shape, load factor, seasonality, and end-use. For T&D rates, the most important of these characteristics is voltage level, since there are significant differences in the cost to serve each voltage level. For instance, customers at the primary level should not have to pay for secondary lines and line transformers, and customers at the transmission should not have to pay for non-customer related distribution equipment.
Additionally, losses vary with voltage level and, since the allocation factors used in a typical allocated cost of service study are adjusted for losses, the resulting class revenue requirements will be more accurate.
The other cost-causative characteristics noted above are less relevant in pricing T&D delivery services than in pricing generation services. This is because the cost of generation varies considerably with time, while the relationship of time-dependence and T&D cost causation is less pronounced.
Q. Please explain what you mean by “time-dependence”.
A. The cost of generation typically rises and falls with the loads on the system. The hours with the highest loads (e.g. summer during the day) have the highest costs. In the unregulated market for generation services, the cost differentials are likely to by very large. As an extreme example, the prices posted by the New England Independent System Operator, a clearing-house for energy sold in New England, have reached as high as $6 per kilowatt-hour in some hours.
Transmission facilities are generally sized to meet the peak loads on the system. For this reason, transmission costs are generally allocated to classes on a peak-intensive method, such as “12 CP” or “summer 4-CP”.
On the other hand, distribution substation equipment is designed to meet the area loads, and the time that the peak is reached varies from substation to substation. For instance, a substation serving primarily residential loads would reach peak loads in the early evening, whereas a substation serving predominately commercial businesses would peak in the mid-afternoon. For this reason, substation costs are typically allocated to classes based on class peak.
Further down the line, distribution is sized to meet the maximum expected loads of individual customers when the peak occurs. For instance, line transformers are sized to meet the loads of a few residences, or a medium-sized business.
As time-dependence decreases down stream from the transmission system, there is also less and less diversity.
Q. Please explain what you mean by diversity.
A. In general, diversity is the ratio of the peak load of a group of customers to the sum of the individual peaks. At the substation level serving a large number of customers, there is diversity, since customers (even customer with similar load shapes) peak at different times. But as noted above, further down the line, distribution equipment is sized for smaller groups of customers, and so there less diversity.
Q. Are there other factors (i.e. other than being cost-based) that should be considered?
A. Yes. Utilities have traditionally installed the least expensive watt-hour meters at the connection point for small customers, more costly kW-demand meters for medium to large customers, and even more expensive kVA-demand meters and/or time-of-use meters for its largest customers. While the accuracy and fairness of electricity rates is improved with the more sophisticated metering, it is cost-prohibitive to install them everywhere. Thus, utilities traditionally have developed meter standards primarily based on customer size.
Even though Texas is entering a new world with electric industry restructuring, distribution and transmission rates will continue to be regulated through the traditional methods. At this time, I do not see a reason for a massive change-out of the current meter stock for the Texas distribution utilities. They should continue forward with their current metering practices. This issue will be addressed when the Commission considers the requirements of Section 39.107 of PURA prior to January 1, 2004, when metering for commercial and industrial customers will be provided on a competitive basis.
Q. Please summarize the class classification recommendation for general service customers that has been placed before the Commission.
A. Several parties in these proceedings entered into a non-unanimous Agreement (“NUA”) on September 8, 2000 recommending four general service classes as follows: Secondary customers with demands less than 10 kW, secondary customers with demands greater than 10 kW, primary voltage customer, and transmission customers. The recommendation also included two exceptions. First, the delineation in the secondary classes would be at 5 kW for Entergy Gulf States Utilities and Texas-New Mexico Power Company; and second, the delineation would be at 10 kVA for Reliant.
Reliant was not a signatory to the NUA. Reliant believes it is premature to develop standard classes without knowing how much headroom there will be between the T&D rates and the price-to-beat rates. Reliant explained in its response to the NUA that, without meaningful headroom, there would be no real choices available to such customers.
Q. Do you support the NUA on class classification?
A. I agree that the recommendation is a reasonable starting point, given the Commission’s determination that there should be four general service classes. As noted above, I believe that the service voltage level is the most important cost-causative determinant for delineating classes for T&D rate classes. Also, the delineation at 10 kW was recommended since most utilities install demand meters at this point.
However, I agree with Reliant that it is premature to “cast in concrete” the classes at this time. I agree with Reliant’s reasoning, that competition may be constrained if there is insufficient opportunity for customer to participate in the competitive market. I will explain this more fully in the last section of this testimony.
Q. Along these same lines, Reliant proposed separate classes for customers with demands in excess of 1,000 kVA (Commercial Service Classes I and II). Do you believe this is warranted?
A. No. Reliant proposed to split the classes at this point to coincide with the eligibility for price-to-beat (“PTB”) rates. While I agree with Reliant that class classification should not result in inequitable opportunities for different customers to participate in the competitive market, I do not agree that this requires a split at 1,000 kVA. The Company can simply code the individual customer accounts as eligible or ineligible for PTB. The Commission has determined that class classification should be based on cost, not administrative factors.
III. Distribution Rate Design
Q. Please explain how distribution rates should be designed.
A. Distribution rates should have a combination of customer charges and demand charges, if the appropriate metering is in place.
Q. Please explain how customer charges should be designed.
A. Ideally, customer charges should be designed to recover distribution costs that do not vary with usage. For general service customers, these are metering and customer costs. In the Commission’s December 16, 1999 General Instructions, the Texas utilities are required to functionalize the metering and customer costs included in the specific accounts of the utility as customer-related. In its order in this proceeding, the Commission should find that customer charges be developed from the appropriately functionalized costs in the individual UCOS proceedings.
Q. In addition to the customer charges, several of the utilities have proposed including the minimum demand block as a fixed charge in their initial UCOS filings. For instance, in its Commercial Service Class I Rate, Reliant has proposed a fixed charge of $4,199 for the first 850 kVA, and the demand charges applies to the excess kVA. Do you agree with this as a design feature?
A. In this case, Reliant has tied the minimum demand charge to the availability of the rate. As notes above, I do not agree that such a split is necessary. However, if the Commission finds in Reliant’s favor, then utilities should be allowed to continue this practice. By having a minimum demand charge in the rate, ineligible customers will be deterred from taking service under this rate, and so will facilitate rate administration.
Q. Do you support the use of demand charges?
A. Yes. As far as practical, the remaining distribution charges (i.e. excluding fixed metering and customer services) should be based on demand. This is because distribution equipment is designed to meet the maximum loads that customers are expected to place on them. Energy charges should be permitted only if there are metering constraints.
Q. How should the billing demand for general service rates be determined?
A. As I explained above, distribution equipment is designed to serve a combination of local area peaks and individual customer maximum demands. For this reason, I think that the relevant determination of demand is the customer peak.
However, individual customer loads can vary from month to month and season to season, and so I believe that a ratcheted demand is appropriate for general service customers.
Q. Please explain what you mean by a ratcheted demand.
A. A ratcheted demand is typically is the maximum of the current month’s demand, but not less than a pre-defined percentage of the maximum demand for the entire year.