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(410) 767-8004 CASENO8707IISTAFDIRECTTESTDLV&AW November 20, 1996 Daniel P. Gahagan Executive Secretary Public Service Commission of Maryland 6 St. Paul Street Baltimore, Maryland 21202-6806 Re: Case No. 8707, Phase II Dear Mr. Gahagan: Enclosed for filing in Case No. 8707, Phase II, are the original and two (2) copies of the Direct Testimony of David L. Valcarenghi and Aurora Watson of the Public Service Commission Staff. Copies of Staff's Direct Testimony have been provided to the Hearing Examiner conducting this proceeding and to all parties of record. Very truly yours, James R. Scheltema Assistant Staff Counsel JRS/rt Enclosures cc: Teresa M. Bay, Hearing Examiner All Parties of Record BEFORE THE PUBLIC SERVICE COMMISSION OF MARYLAND IN THE MATTER OF THE APPLICATION OF CHESAPEAKE UTILITIES CORPORATION FOR AUTHORITY TO REVISE ITS RATES AND CHARGES FOR GAS SERVICE ) ) ) ) CASE NO. 8707 PHASE II DIRECT TESTIMONY OF AURORA D. WATSON ON BEHALF OF THE STAFF OF THE PUBLIC SERVICE COMMISSION OF MARYLAND NOVEMBER 20, 1996 TABLE OF CONTENTS I. INTRODUCTION AND SUMMARY 1 II. NEW RATE CLASSES 4 III. CUSTOMER CLASS COST ALLOCATION 4 IV. RATE IMPACTS 15 V. NEGOTIATED CONTRACT RATES 16 VI. SHARING OF INTERRUPTIBLE AND CAPACITY RELEASE MARGINS 18 VII. TARIFF MODIFICATIONS 19 VIII. RATE DESIGN 20 IX. CONCLUSION 21 CASE NO. 8707 DIRECT TESTIMONY OF AURORA D. WATSON ON BEHALF OF THE PUBLIC SERVICE COMMISSION STAFF I. Introduction and Summary Q. Please state your name, occupation and business address. A. My name is Aurora D. Watson. I am a regulatory economist with the Maryland Public Service Commission in the Division of Rate Research and Economics. My business address is 6 St. Paul Street, Baltimore, Maryland 21202. Q. Please describe your professional background. A. From 1979 to 1991, I was employed by the Federal Energy Regulatory Commission as a public utilities specialist. I conducted various investigations involving natural gas producers and pipeline companies and testified in rate proceedings, particularly in the area of cost classification, cost allocation and rate design. In 1991, I joined WestGas, the former gas subsidiary of Public Service Company of Colorado, as a financial analyst. In this capacity, I was responsible for all tariff matters including regulatory filings with the State of Colorado and the FERC. I also prepared regulatory impact analyses for the company during the transition into an Order 636 era. 4 In 1993, I was employed by the Colorado Public Utilities Commission as a financial analyst to conduct investigations of various state regulated utilities and brief the Commission on my conclusions. I joined the Maryland Public Service Commission Staff in April 1996. Q. What is your educational background? A. I have a Bachelor of Science degree in Chemistry from the American University in Washington, D.C. I have received supplementary training/education from the FERC, NARUC, AGA, FEBA (Federal Energy Bar Association), RMNGA (Rocky Mountain Natural Gas Association), the USEPA and graduate course work at the American University, the Colorado School of Mines and the University of Denver. Q. What is the purpose of your testimony today? A. I am submitting testimony today to address certain cost allocation and tariff issues. I will discuss: 1) the classification and allocation of costs associated with distribution facilities, 2) margin-sharing, 3) negotiated contract rates for firm service, 4) Chesapeake's proposed new rate classes, 5) the need to use a gradual approach to phase in rate increases on customer classes, and 6) rate design. Q. What are your conclusions and recommendations? A. My conclusions are as follows: (1) Chesapeake's proposed rate class segmentation reflects certain characteristics of the respective customer groups such as size and usage patterns; 5 (2) The classification and allocation of costs for distribution mains needs to be reconfigured. An allocation of mains to demand and commodity is appropriate; (3) Chesapeake's use of the minimum system (MIN) approach to cost allocation is inappropriate because the data used can be easily manipulated to arrive at allocation factors ranging from 16% to more than 100% of the actual investment in mains; (4) The classification and allocation of costs for services needs to be reconfigured. Services are largely customer-related and should therefore be allocated on the number of customers; (5) The ratio for margin sharing related to interruptible service and capacity release should remain at 90/10 (ratepayers/company); (6) The NCR tariff offering negotiated contract rates for firm service is inappropriate prior to unbundling. Negotiated contracts should continue to be considered by the Commission individually in the form of special contracts -- not through a blanket authorization; and (7) The rate design used by Chesapeake in this case should be approved. II. New Rate Classes Q. Please comment on Chesapeake's proposals to establish new rate classes. 6 A. To design rates, it is first necessary to separate the company's customers into rate classes. The rate class segmentation is dependent upon the characteristics of the customers and the company's ratemaking goals. Examples of ratemaking goals include economic efficiency, fairness, competitiveness and reflection of cost incurrence. In this proceeding, Chesapeake proposes to redefine its rate classes according to certain characteristics, principal among which is customer size. Q. Are you opposed to Chesapeake's proposed class segmentation? A. No. It appears that Chesapeake has redefined its rate classes in accordance with the characteristics of its customer population including size, customer type, load factor and alternate fuel capability. III. Customer Class Cost Allocation Q. Would you please describe the processes of cost classification, cost allocation, and rate design? A. First, overall costs are functionalized into categories such as production, storage, and transmission or distribution. Next, these functionalized costs are classified as demand or capacity-related, commodity or energy-related, and customer-related for the purpose of cost allocation and rate design. Demand or capacity-related costs are associated with the peak usage of a system and do not vary directly with the number of customers or their annual usage. Commodity costs are those that vary in proportion to a customer's volumetric 7 consumption. Customer costs are those that vary directly with the number of customers served. It is important to note that there is no one scientifically correct method of cost allocation. The process by which just and reasonable rates are produced is generally more judgment than math. The allocation methodology provides the cost of service for each customer class. The goal of cost allocation is well described in the following quote: The steps which comprise the cost classification and allocation process are designed to identify the nature, characteristics and behavior of system costs, and to identify the classes of service or customers that are deemed responsible for the incurrence of such system costs. [AGA Gas Rate Fundamentals, 3rd Ed.(1978) p.235] Costs are thus allocated to the customer classes using factors, such as units of service, that reflect the identifying characteristics of cost incurrence. Rate design is a creative process that translates these allocated costs into unit charges in a manner that is judged to achieve certain ratemaking goals while recovering the required revenue from each customer class. Defining customer class must therefore precede the rate design process. 8 Q. What cost classification and cost allocation issues do you wish to address specifically? A. I wish to address the treatment of distribution mains and services for the purposes of cost classification and cost allocation. Q. How does Chesapeake treat distribution mains and services for purposes of cost classification and cost allocation? A. Chesapeake assigns the fixed costs of mains and services to demand- related and customer-related classifications using a minimum distribution system methodology. As described by Mr. Johnson (at lines 23-24 on page 5 of his direct testimony), the allocation employed for the customer-related portion of mains and services is "based on the number of customers in each class of service rather than the maximum demand imposed during the peak day by each class." Q. Please describe the minimum distribution system concept. A. As the NARUC Gas Distribution Rate Design Manual (June 1989) states at page 22: The minimum size main theory assumes that there is a minimum size main necessary to connect the customer to the system and thus affords the customer an opportunity to take service if he so desires. Under the minimum size main theory, all distribution mains are priced out at the historic unit cost of the smallest main installed in the system, and assigned as customer costs. The remaining book cost of distribution mains is assigned to demand. 9 Q. Is this the procedure used by Chesapeake's witness Johnson? A. No. Chesapeake uses its own variant of the approach described above. First, Mr. Johnson performs his analysis using an "inflated" unit cost to determine the customer-related costs of a minimum system. An inflation factor is applied to express costs of different vintage pipes in today's dollars. Second, Mr. Johnson performs his analysis on the basis of 1 1/4 inch pipe -- not the smallest main installed in the system. Third, Mr. Johnson develops a "trended installed cost" ratio (comparing the 1 1/4" pipe to the average for all distribution main) to derive the percentage of distribution main being classified as customer-related. Q. Please describe Mr. Johnson's application of the MIN methodology to Chesapeake's distribution system. A. According to Mr. Johnson's testimony at line 5, page 6, the minimum system for mains was based on a 1 1/4" steel main. He states that "this main was selected because it is the smallest size main shown on the company's records as having significant installed footage." (Page 6, lines 6-7). According to Mr. Johnson, the cost of the 1 1/4" main is 41.80% per foot of the average cost per foot for all distribution mains. Mr. Johnson concludes therefore that 41.80% of the distribution main costs should be classified as customer-related. (Page 6, lines 9-10). Q. Do you agree with Mr. Johnson's use of the minimum distribution system methodology for the allocation of mains and services to demandrelated and customer-related classifications? 10 A. No, I do not. According to Mr. Johnson's direct testimony (page 5, lines 18-24), the minimum distribution system methodology recognizes "that there is conceptually, a minimum size system of distribution mains and services in order to connect each customer to the transmission system or source of supply which is required regardless of the volume of gas required by that customer." He further states that this minimum system "is a function of the expanse of the service territory and concentration of customers" and should therefore be allocated on the basis of "the number of customers in each class of service, rather than the maximum demand imposed during the peak day by each class." I question Mr. Johnson's supposition that his minimum size methodology reflects the concentration or density of customers. To quote Bonbright: It [the minimum-sized distribution system] makes no allowance for the density factor (customers per linear mile or per square mile). Indeed, if the Company's entire service area stays fixed, an increase in number of customers does not necessarily betoken any increase whatever in the costs of a minimum-sized distribution system. (James C. Bonbright, Principles of Public Utility Rates, 84n.3(1961) p. 348) I do not believe that a customer-related classification clearly reflects the cost causation of distribution mains. While the minimum system methodology is an approach which has been used in Maryland and elsewhere, it is a controversial and imperfect approach. It is imperfect because no real distribution system would be built with only 1 1/4” mains, or any other minimum size of pipe. In addition, the number of customers bears a weak relationship to costs of mains. A distribution system is sized to carry the system’s peak load. A better approach would employ a noncoincident peak (NCP) allocator which would more 11 accurately reflect that costs are incurred to meet the peak load of all customer classes using the system. However, even if the minimum system were deemed to be the appropriate method in this case, the data employed to derive Chesapeake’s minimum system is problematic and, as I will show, unreliable on its face. For this reason alone, Chesapeake’s application of the minimum system methodology must be rejected. Q. A. What is the effect of Chesapeake's methodology? In my opinion, the use of the minimum distribution system over allocates cost to residential and small commercial customers who comprise 96.77% of Chesapeake's customers. (See Exhibit JRT-2). This 96.77% is made up of 7,965 residential (of which 1,731 are non-heat) and 1,053 general service customers. Under the MIN methodology, large volume and industrial customers receive a smaller allocation of costs. Schedule 1.1 of Exhibit RSJ-2 -- "Allocation", shows the shifting of cost responsibility away from the Medium Volume, Large Volume, High Load Factor and contract Demand customers that would result from allocating more costs on the basis of number of customers. While these customer classes combined comprise 31.26% of the design-day demand or peak load, they comprise only 2.60% of the total number of customers. Q. What allocation methods have been ordered in other Maryland cases? A. In Case No. 8119, involving Washington Gas Light, the Company demonstrated an "almost exact correlation" between the number of customers 12 and the length of the distribution mains. Based on this showing, the Commission deemed it appropriate to recognize the correlation by classifying a portion of the costs of distribution mains as customer costs and allocating that portion on a number of customers basis. In Case No. 8070, involving Baltimore Gas and Electric Company, the non-coincident peak (NCP) method was accepted and the minimum size method was rejected. The NCP method was recognized as reflecting the actual design and operation of the distribution mains system, and further, that mains must be capable of delivering the maximum amount demanded whether or not that demand is coincident with the system peak demand. The minimum size method was rejected for its “many deficiencies.” Q. Do you agree with Mr. Johnson's use of the 1 1/4" pipe as the basis for his minimum system? A. There are a variety of sizes that could be chosen as the basis of a minimum system. The choice to use the 1 1/4" steel main is at best a judgment call. With Chesapeake’s proposed MIN methodology, much depends on how "significant installed footage" is defined. Chesapeake's Response to Maryland People's Counsel Data Request No. 25 [Exhibit ADW-1] shows the pipe mix Chesapeake uses in serving its customers. While the 1 1/4” steel main comprises 12,212 feet of the system, there is 12,244 feet of 1 1/2” steel main which would appear to meet the company's criterion. If 12,244 feet of 1 1/2” pipe is considered significant, then basing the minimum system on 1 1/2" main at an inflated unit cost of $1.92 per foot (versus the inflated unit cost of $5.07 per foot 13 for the 1 1/4" main) would reduce the amount of costs assigned by Chesapeake as customer-related by more than one million dollars. Q. Have you provided an exhibit to show how Chesapeake's data produces unpredictable and unreliable results? A. Yes, I have. Exhibit No. ADW-2, shows the results of my analysis. In this analysis I mirrored Mr. Johnson's MIN methodology by using the inflated unit cost of the pipe, but substituted various other pipes represented in Exhibit ADW-1. Using 3/4" steel pipe, the inflated unit cost is $9.53/foot giving a system investment of $10,141,854, which is 78.6% of the total to be assigned as customer-related. If 2" steel pipe is used, the inflated unit cost is $9.95/foot, yielding a ratio which would assign 82.1% as customer-related costs. It is important to note that, as Exhibit ADW-2 shows, the inflated unit cost of 3/4" steel pipe is $9.53/ft. while the 1 1/2" steel pipe is only $1.92/ft., implying that the smaller diameter pipe costs nearly 5 times more than the larger diameter pipe. Further, the 1 1/4" plastic pipe is shown to cost $17.82/ft. as compared to the 2" plastic pipe at a cost of $8.18/ft., or more than twice as much. If the 1 1/2" steel pipe were employed to arrive at a minimum system using Mr. Johnson’s methodology, it would result in 15.84% as customer-related costs. Using the 1 1/4" plastic pipe would result in 147% as customer-related costs. It appears that Mr. Johnson sized his minimum system so that it would yield what he believed to be a "reasonable result". Clearly, a methodology which relies on such problematic data is suspect and should be rejected. Q. What methodology would you prefer? 14 A. As I said earlier, a more appropriate allocator for mains would be the noncoincident peak (NCP). Ideally, I would recommend a result similar to the Commission's decision in Case No. 8070 which rejected the MIN methodology because of its deficiencies in favor of the noncoincident peak methodology. Distribution mains are used to provide gas service for different classes of customers. The costs of these mains are common costs to all customers. It is therefore appropriate to look at how the costs are incurred and how the facilities are used. The NCP approach gives a better match of cost with cost responsibility than the problematic MIN system because it recognizes that mains were originally installed and sized to meet NCP's, and that all gas used at the time of NCP contributes to that peak. Therefore, the benefits that customers derive from a functioning distribution system are more related to NCP than to a minimum system. NCP replicates how the system is actually used. It accepts peak as an allocation method -- the system will be allocated on peak demand. However, the allocation used will be the peaks for each customer class whenever that peak is (which may or may not be coincident to other customer class peaks). The NCP method ensures that even the non-heating customers are assigned their fair share based on their noncoincident peak usage. Q. Are you recommending an NCP allocation methodology for the Company? 15 A. No, I am not. Unfortunately, the required NCP data is not available for Chesapeake’s customers and I do not think the time and expense that would be needed to obtain customer class noncoincident peaks is warranted. Q. Do you have an alternative method you wish to propose? A. Yes. As an alternative to NCP, I am recommending adoption of a 50/50 split of mains between demand and commodity. A proper allocation of distribution mains should reflect the actual design and operation of the distribution mains system. While a second best to the noncoincident peak method, my proposed cost allocation methodology reflects usage at times other than the coincident peak, as does the NCP allocator. Further, my methodology reflects the fact that the system of mains is planned and justified upon both the energy and peak requirements of customers. The distribution mains are sized to meet anticipated peak loads. Yet clearly, these same facilities are available to provide gas service to customers year round, irrespective of peak demand. The system capacity is used both for meeting peak demands and for providing service at times other than during peak periods. To reflect both the annual deliveries and the peak usage for which the facilities are built and used, I have allocated the costs of distribution mains on a 50% commodity and 50% demand basis. As a practical matter, this ensures that mains costs are apportioned to customers classes whether their peak demand falls in the coldest month or at some other time of the year. Q. What allocators did you use in your proposed methodology? 16 A. For this allocation, I used Chesapeake's annual sales allocator and its design day allocator, respectively. Half of the mains costs were assigned as demand-related costs and allocated on the basis of Chesapeake's design day demand. The remaining half were assigned as commodity and allocated on the basis of annual sales deliveries. Q. Why did you choose a 50/50 allocation of costs to demand and commodity? A. My methodology presents a balance between the pure peak and the pure volumetric cost responsibility approaches. A pure peak responsibility method would assign 100% of the fixed costs as demand or capacity-related costs and allocate such costs among customer classes according to their non-coincident peak demand. A pure volumetric approach would treat 100% of the fixed costs as commodity or energy-related costs to be allocated among customer classes on the basis of annual deliveries. (High load factor and non-weather sensitive customer classes will bear a greater proportion of the costs on an annual basis than on a peak basis.) Q. How did you treat services? A. With respect to services, I have assigned costs as being predominantly customer-related and allocated them to classes based on the number of customers. Services includes the investment made for the connection to the customer, which is a service line cost. It is therefore recognized in the assignment of services to the customer-related classification. 17 Q. Your Exhibit ADW- 3, shows costs allocated by your recommended methodology to the current customer classes. Please explain. A. My Exhibit ADW-3 is for illustrative purposes only. Staff did not have the information necessary to provide an analysis using the proposed customer classes. Because Staff accepts the new customer classes (with the exception of NCR) as proposed, Chesapeake should apply my methodology to their proposed new classes. IV. RATE IMPACTS Q. What concerns do you have with respect to the rate impact on customers as a result of Chesapeake’s proposal? A. Chesapeake's cost of service studies demonstrate that certain gas customer classes have been providing returns which are substantially greater than the system average. (Exhibit TJS-1, Schedule 1.0, Page 1). Even as modified for a more appropriate allocation of distribution mains and services, Chesapeake's cost allocation produces class costs of service which differ markedly from current revenue by customer class. To equalize class rates of return, some significant changes in class revenue requirements will be necessary. However, such a movement in class revenue requirements should proceed gradually and moderately in order to prevent or lessen any potential for rate shock. Thus, I believe that the change in class revenue requirements should take place in two steps, half on the effective date of the order in this case and the remaining half, one year from 18 that date. This would be practically achieved by using 1/2 the revenue allocation results for increases and using 1/2 the revenue allocation results for any decreases in the first year. The remaining increases and decreases from the allocation results would then be applied in the second year. V. Negotiated Contract Rates Q. What is the proposed Rate Schedule "NCR"? A. Rate Schedule "NCR" is a negotiated contract rate service that Chesapeake is proposing to offer on a voluntary basis. NCR service will be available to any customer who has economically competitive alternatives to its full or partial service requirements that "it is likely to select if the Company does not provide a negotiated contract rate", and the price to the customer "will provide net revenues above the incremental costs to provide" this NCR service. The contract term for NCR service is fixed at one year or more. NCR service is a firm service which Chesapeake believes will be elected by some of its large customers. Q. Will the NCR rate schedule be open to all customers? A. No, it will not. According to a letter from Chesapeake's counsel dated October 3, 1996, NCR service will only replace service from alternate fuels other than gas service at this time. (Exhibit ADW- 4) This action is according to agreement among the parties. Q. What is your recommendation with respect to Negotiated Contract Rate Service? 19 A. With respect to the gas sales part of Negotiated Contract Rate service, clearly any negotiated gas sales needs to be addressed in the context of unbundled services and the development of gas on gas competition. Chesapeake should not be able to offer negotiated sales rates prior to unbundling except to the extent that special contracts are currently allowed subject to the consent of the Public Service Commission. To the extent that the Company wishes to, it can bring individual contracts to the Commission for approval. In order to protect customers from discriminatory treatment, the Commission should retain the authority to approve or reject individual special contract rates. This is especially true where the Company may otherwise have an opportunity to bind customers with contracts, and possibly shift costs to captive customers, in advance of competitors being able to offer choices to them through unbundling tariffs (and the availability of open access on the Eastern Shore supplying pipeline). VI. Sharing of Interruptible and Capacity Release Margins Q. What changes is Chesapeake proposing with respect to the sharing of interruptible margins? A. Chesapeake is proposing to change the formula for sharing interruptible margins from the current 90/10 to 80/20. Currently, firm customers are credited 90% of the interruptible margin through the PGA. On page 11, line 17 of his direct testimony, Mr. Schuh asserts that "there is considerable risk associated with achieving a particular level of interruptible margins. With open access 20 there will be competitive pressures to reduce margins." He argues therefore that if the Company receives a higher percentage of the margin, the Company will have greater incentive to "market its services aggressively and take steps to attract customers". (Page 12, lines 1-2). Q. Do you agree? A. No, I do not. The 10% that the Company receives is essentially a sales commission. The Company is acting on behalf of the firm customers to maximize the return to firm customers. The return should be maximized for the firm customer since it is the firm customer that is entirely at risk for the cost of providing interruptible service. Columbia Maryland's margin sharing split is 92% to firm customers, 8% to Columbia. (See p. 193 of 80 MDPSC, Order No. 68462, Case No. 8157, order issued June 9, 1989). Washington Gas Light changed from a 90/10 sharing to 92/8 in Case No. 8191 (but 90/10 was retained for their sales to PEPCO). There is no reason for Chesapeake to receive a larger share of these margins. If anything, the trend of comparable sharing arrangements in Maryland would indicate a change to 92/8. If interruptible sales were to vanish completely, all else equal, the Company's earnings from a ratemaking perspective would be unaffected, while firm customers would lose the PGA credit. Q. Chesapeake is proposing an 80/20 margin sharing mechanism for capacity release. Do you agree? A. No. Again, the Company is acting on behalf of the firm customers who bear the cost of this capacity and the risk of under-utilization. (With respect to 21 the sharing mechanism for capacity release of other Maryland LDCs, WGL has no incentive, BGE has 90/10 and CGMD has 90/10.) VII. Tariff Modifications Q. Are you proposing any modifications to Chesapeake’s new tariff pages? A. Yes. I am proposing that language be added to the “Availability” section of Rate Schedule “IS” to ensure that alternate fuel equipment has to be in operating condition. VIII. Rate Design Q. Do you have any comments with respect to Chesapeake’s proposed rate design? A. Yes. I support Chesapeake’s rate design in general. I believe the declining block rates used by Chesapeake are still appropriate as they reflect the difference in sub-class rates of return for the heating and non-heating customers and the under-recovery of customer-related costs in the customer charge. However, I would suggest that the Company's proposed customer charge increase be incremental with one half imposed currently and the remainder of the increase imposed in the following year. 22 IX. CONCLUSION Q. Please summarize your recommendations. A. In conclusion, I am recommending: 1) that Chesapeake's proposed rate class segmentation and rate design be accepted; 2) that the minimum system be rejected as a methodology in this case in favor of a demand/commodity treatment of mains and a customer-related treatment of services; 3) that the ratios for margin sharing related to interruptible service and to capacity release remain 90/10 (ratepayers/company); 4) that the changes in total revenue requirement for each class and in the customer charge be phased in two steps; and, 5) that the NCR rate schedule be rejected in favor of Commission review of individual special contracts. Q. Does this conclude your testimony? A. Yes, it does. 23