CAARS Hemlock Valley Electrical Services Ltd. Decision October 17, 1990 1 1.0 INTRODUCTION This Decision is made following a public hearing on September 24 and 25, 1990 at the British Columbia Utilities Commission ("the Commission") Hearing Room in Vancouver, B.C.. Hemlock Valley Electrical Services Ltd. ("HVES" or "the Company") is a public utility operating under Certificates of Public Convenience and Necessity issued by the Commission and is regulated under the provisions of the Utilities Commission Act ("the Act"). The Company applied pursuant to Sections 67(2) and 106(1) of the Act to increase its filed Electric Tariff Rate Schedule by 7.32ยข/kW.h, (84.6%). The reasons given were to permit the recovery of British Columbia Hydro and Power Authority's recently approved rate increases, forecast operating costs and a return on rate base. As HVES is an extremely small utility, the Commission first attempted to resolve potential issues among the interested parties without the necessity for a formal public hearing, in order to avoid the cost involved. A Committee of Commissioners was struck to review the problems associated with the utility. Two meetings were held with representatives of the Company and its customers. In addition Commission staff were directed to review the electrical system and accounting records and report their findings. Following these reviews and recognizing the substance and tenor of the parties' positions and views, a decision was taken by the Commission to set the Application down for hearing. The Rate Application is based on a forecast test period of one year commencing May 1, 1990, corresponding with the currently approved fiscal year. The Company sought rate relief effective June 1, 1990. The Commission, by Order No. G-51-90, approved an interim increase of 3.70#/kW.h effective with consumption on and after July 1, 1990. The effective date provided for notice to the customers. The interim increases deferred any consideration of return on rate base to the public hearing.
2 The Order also required HVES to inform each customer of the Application, the approved interim increase, and the effect on average annual billings. Response to the Customer Notice was both prompt and vocal. Commission Order No. G-58-90 set down the hearing and required the utility to send all customers a Notice of Public Hearing by direct mail. Intervenors in the hearing included the Hemlock Valley Ratepayers' Association ("HVRA") and Strata Council NW 1282. A number of the letters received by the Commission expressed the desire by the customers of the utility to have B.C. Hydro acquire and operate the electrical distribution system at Hemlock Valley. In his opening statement, the Chairman advised the participants that the Commission had previously reviewed this matter and that the proposal would not form part of this hearing. The Chairman was, however, able to advise participants that the government is considering the question of British Columbia Hydro and Power Authority's ("B.C. Hydro") obligation to serve remote communities like Hemlock Valley. 2.0 BACKGROUND HVES is a subsidiary of Hemlock Valley Resorts Inc. ("Resorts"). The original parent company, Hemlock Valley Recreations Limited ("Recreations"), owned and leased land in Hemlock Valley for development and provided facilities for year-round recreational use. Recreations went into receivership in 1984 and in 1987 its assets, including the utility company shares, were sold to Resorts. Resorts is now wholly-owned by Mr. Joseph Peters, the President and sole director of HVES. In 1980 a public hearing was held to issue a Certificate of Public Convenience and Necessity and to set rates for the utility. In 1983 a public hearing was held to set a new tariff schedule for the Company. The Company did not make any further revenue requirements applications until the current Application.
3 3.0 INTERVENORS 3.1 Hemlock Valley Ratepayers' Association The Hemlock Valley Ratepayers' Association played a significant intervention role in the hearing. Although not represented by legal counsel, the Association presented three panels which were coordinated by Mr. Tim Pollock and Mr. Barry Cavens. Ten members of the HVRA submitted written evidence prior to the hearing. The areas canvassed under direct and cross-examination are as follows: Mr. Tim Pollock, President of HVRA, provided information on the history of the utility's rates and earnings and took issue with a number of statements in the Application. Mr. Rick Mazur gave evidence regarding telephone and snow removal costs as being "unrealistic and misleading." Mr. Peter Maharajh disputed the power consumption data used by HVES and certain administration fees. Mr. Frank L. Gruen commented on excessive costs, accounting and billing practices and questioned the arbitrary allocation of costs. Mr. William Mackie denied the necessity for snow removal from the transformers and suggested that proper marking of transformers would suffice. Mr. Barry Cavens covered a number of areas including billing problems, safety concerns, and opportunities to reduce peak demand. Mr. Kevin O,Donnell objected to the inclusion of estimated hearing costs as utility expenses in the Application and the lack of budget process on accounting principles. Mr. Jim Young, in his written testimony, covered the requirements of developers in providing services in property sales. Ms. Jean Tsuyuki opposed the rate base component in the Application on the basis that the utility systems were fully paid for by the developers. Mr. Darrell Kippin disputed the Application for repairs and maintenance.
4 The foregoing individual submissions by members of the Hemlock Valley Ratepayers' Association were further supported by a series of panels as follows: - rate base - operations and maintenance, administration - operations and maintenance, technical - safety - social implications - cost of purchased power 3.2 Strata Council NW 1282 Mr. R.W. Dowler made a representation on the Council's concern regarding inequities in rate design due to the fact that electricity rates do not recognize the Council's ownership of high voltage switch-gear, transformers and the lower voltage distribution and meters. The Commission can understand Mr. Dowler's position, and has some sympathy for it. However, it appears that when the condominium developer made the decision to invest in switch-gear and transformers it was made without assuring the availability of a tariff for service at primary voltage, and that has never materialized. The Commission is of the opinion that the utility still cannot economically justify the sophistication of a more elaborate rate structure at this time. The Commission can only encourage the Strata Council to continue its discussions with the Company regarding a viable solution, recognizing that, under the circumstances, this may take some time. 4.0 RATE BASE 4.1 Determination of Rate Base Mr. Sanderson, Counsel for the Company, presented legal argument for the consideration of a return on the appraised value of assets based on Section 65(4)(b) of the Act. In this regard, he discussed the minority judgement of Mr. Justice Locke in the Supreme Court of Canada case of B.C. Electric
5 Railway Co. Ltd. v. Public Utilities Commission of B.C. et.al., to argue that the Commission had no option but to recognize a return on rate base. The Company's calculation of rate base for the period May 1, 1990 to April 30, 1991 was $366,511 (excluding diesel operations). In the 1980 Decision, the Commission made a determination of rate base. After various adjustments, it arrived at a figure of $590,626. It is interesting to note that in Exhibit 7 of that proceeding, Commission staff raised the question of customer contributions toward the cost of the electrical distribution system included in the sale price of lots. The Company's response was to provide calculations indicating a contribution of $85,000. The Commission subsequently increased this to $126,500 on the grounds that the calculation should apply to 253 lots, not 170 as the Company proposed. Hence, the $590,626 finding for rate base included a deduction for customer contributions which was tested by cross-examination considered relevant at that time. During the course of the current hearing, several references were made to the Commission's 1983 Decision alleging that the rate base was removed or eliminated. Careful examination of the 1983 Decision and the circumstances surrounding it leads the Division of the Commission hearing this Application to a different conclusion. It is clear that in the 1983 Decision the inter-dependency of electric and other services with the resort enterprise at Hemlock Valley was fully understood. It is also clear that the Commission felt some consternation about the 7.69% negative return on rate base flowing from the 1980 Decision. It was also apprehensive that the continued existence of Hemlock Valley as a going concern was being "...materially affected by the downturn in the provincial economy." Moreover, it was looking at the changeover from diesel generators to a tie-line with B.C. Hydro. The change in source of power was unquestionably correct in the long-term, but it imposed an annual amortization
6 cost of $99,840.18 for the years immediately ahead. That addition of nearly $100,000 per year materially distorted the profit and loss statement. In the circumstances, the Commission, in its 1983 Decision, chose to ignore return on rate base as an appropriate means of fixing fair and reasonable rates, and chose instead a pragmatic break-even approach between revenue and expenses. It also added a small allowance for contingencies. Management of the utility was evidently prepared to accept this approach. However, the Commission did not make a finding on rate base; it neither accepted, rejected, nor amended the Company's evidence on the subject. This Division of the Commission considers that the 1983 Decision was a practical decision to tide the enterprise at Hemlock Valley over a particularly difficult period. Sooner or later, however, longer-term prospects must be faced squarely. The tie-line has been amortized over five years. Evidence (Exhibits 14 through 21) clearly indicate that recovery of plant expenditures was anticipated through utility rates. Therefore the Commission believes that a return to more traditional rate-maklng practice is justified. It was proposed to the Commission by the intervenors at the hearing that rate base should not be recognized. The cornerstone of rate base is appraised value of utility property, which is usually taken to be original cost of plant. The Commission cannot, by a stroke of the pen, eliminate the appraised value of the property; to do so would be confiscation of property. Reductions to rate base occur through the subtraction of items such as accumulated depreciation, and customer contributions. Considerable evidence was submitted regarding statements of disclosure for land sales. It soon became evident that there had been not one prospectus for the development, but several. Those applying after December 1979 had wording which quite clearly stated that costs of constructing electric utility plant, covered initially by the developer, would be recovered by charges to the utility customers. Any subsequent additions to utility plant would, in any event, go into the appraised value of property. In the 1980 Decision, an argument was made that customers contributed to the cost of the electric utility through their lot
sales prices and adjustments were
7 made in the amount of $126,500. Since that date, the weight of evidence does not support the Commission making further such deductions in respect of lot sales. It is noted, also, that the major proportion of rate base components were in place by 1980 (T 15). The Commission notes that the Company's computation of rate base includes depreciation accumulated from year to year irrespective of whether or not there was cash flow to support it. This is what accounts primarily for the drop in rate base from 1980 to 1990/91 for essentially the same plant. However, the Company did not choose to come before the Commission for rate amendment since 1983, and the Commission does not propose to make any adjustment for prior cash flow problems. The Commission has considered alternative calculations for rate base and concludes that no material difference results from any refinements which might be made. Therefore, the Commission accepts the Company's evidence, and finds the rate base to be $366,511 for the test period. 4.2 Capital Structure The Company currently has no viable capital structure of its own. Its financing has been by way of loans from the parent company. The Applicant proposes a deemed 50/50% debt/equity ratio in this Application. It is a frequent practice of regulatory tribunals to use a notional capital structure. While 50% equity is much higher than would be usual for utilities in general, the higher proportion of equity in this case can be considered as reasonable, bearing in mind the relative risks in the case of the Company. 4.3 Return on Rate Base The Company has proposed a return of 13% on the debt component, and 15% on the equity component of the rate base. Standing alone, these figures certainly fall within a reasonable range in today's market. Nevertheless, the Commission considers it essential to consider the particular circumstances of the Company in this Decision. While it is true that risky investments
typically
8 command higher returns, that position considers primarily the potential investors' point of view in placing funds at the utility's disposal. From the existing shareholders' point of view, the realization of an allowable rate of return depends upon the ability of management to run an efficient organization, and for external factors to favourably affect the prosperity of the Company. Bearing in mind the inter-relationship of the resort and utility elements at Hemlock, and the current circumstances of the utility, the Commission cannot accept a return on equity for rate-making purposes of 15%. For the foregoing reasons, the Commission believes that a 13% return on debt, and a 13% return on equity is both just and reasonable within the spirit of Sections 65(3)and 65(4) of the Act, which state: "(3) It is a question of fact, of which the commission is the sole judge, whether a rate is unjust or unreasonable, or whether, in any case, there is undue discrimination, preference, prejudice or disadvantage in respect of a rate or service, or whether a service is offered or furnished under substantially similar circumstances and conditions." "(4) In this section a rate is "unjust" or "unreasonable" if the rate is (a) more than a fair and reasonable charge for service of the nature and quality furnished by the utility, (b) insufficient to yield a fair and reasonable compensation for the service rendered by the utility, or a fair and reasonable return on the appraised value of its property, or (c) unjust and unreasonable for any other reason." 5.0 COST OF SERVICE The efficient operation of a utility requires proper budgeting and planning. In budgeting for projected operating costs the Company needs to have a clear understanding of the duties to be performed, the personnel required and the number of person-hours likely to be involved. There is evidence that the management consultant employed by the Company made useful suggestions in this regard to the Company owner (T 157). In administering a budget it is
9 important that costs be allocated and recorded as they are incurred. In preparing an application for a rate change it is essential that the Company be able to show that all costs of materials, services and employee hours have been allocated properly. It is important to have available documentation to support all projected cost estimates. Mindful of the foregoing, the Commission, in its analysis of the cost of service, was frustrated by the general lack of adequate documentation and conventional budgeting and planning procedures. 5.1 Purchased Power A major part of the cost of service is the cost of acquiring electricity from B.C. Hydro. Mr. D.G. Hildebrand, a consultant for the Company, prepared financial calculations estimating the test year consumption and cost (T 52). In estimating unit cost he used the cost of purchased electricity for a reported period, the 11 months ending April 30, 1989. The total for that year was shown as $1 10,159 in the Annual Report filed by the Company with the Commission (Exhibit 11). This represented 2,111,400 kilowatt hours at an average unit cost of 5.217ยข/kW.h. This unit cost was adjusted to incorporate approved rate increases of 3% (November 15, 1989) and 1.5% (April 1, 1990) to B.C. Hydro rates resulting in a unit cost of purchased electricity of 5.454ยข/kW.h for the test year (T 54-57). In response to his request to HVES for a projection of electricity purchased for the test year beginning May 1, 1990, Ms. Erna Dudley, a consulting accountant for the Company, provided an estimated figure of 2,300,000 kW.h. From this he deducted an allowance of 11% for line losses to arrive at a test year billed
10 consumption estimate of 2,047,000 kW.h at a cost of $125,454. Dividing the latter by the estimated consumption provided a value of 6.13ยข/kW.h. These calculations are shown in Exhibit 7. This process is necessary because the resort operation is not metered. A spokesperson for the intervenors, Mr. T. Pollock, disagreed with these estimates. Based on information he acquired from B.C. Hydro concerning sales to the Company over the past two years, he concluded that in 1988/89 the demand averaged 561 kVA and electricity delivered totalled 2,233,800 kW.h. In 1989/90 comparable figures were an average demand of 477 kVA and 1,877,000 kW.h delivered (Exhibit 13D). He used an arithmetic monthly average for each of the two years to arrive at an estimate of average demand and total consumption for the test year. He applied B.C. Hydro Rate Schedule 1211, to arrive at a total cost of energy acquired. An allowance for the same 11% line loss used by the Company resulted in a calculated unit cost of 5.38ยข/kW.h (T 304-307). Copies of actual invoices received by the Company for purchased power were not available at the hearing to confirm any of the foregoing. The Company undertook to obtain this information and file it with the Commission at a later date (T 151). Subsequent to the hearing, Counsel for the Company filed documents to substantiate the cost of purchased electricity in the year 1988/89. Working papers of Ms. Dudley, the Company accountant, showed that the total cost for that year for power purchased of 2,203,200 kW.h was in fact $100,984.44, rather that the amount of $110,159.16 stated in the Application. The reason for the discrepancy was explained and reconciled. The revised figure on the purchased cost of electricity was provided by the Company to Mr. D. Hildebrand, who then recalculated the cost of electricity for the test year. His calculation now estimates the purchased electricity cost in the test year to be 5.38ยข per kW.h, rather than the 6.13ยข per kW.h shown in
11 Exhibit 7. This revised estimate is exactly equal to the estimate calculated by the intervenors in Exhibit 13D. The Company now accepts that there is no dispute between the Company and the intervenors on the estimated cost of electricity to be recovered from revenues in the test year. The Application estimated that 2,300,000 kW.h of electricity would be purchased from B.C. Hydro in the test year. Allowing for an 11 percent line loss the consumption estimate is 2,047,000 kW.h. The Commission accepts this estimated consumption which, at 5.38ยข per kW.h, generates a revenue requirement of $110,129. Evidence was adduced that the winter of 1988/89 was the coldest since the resort commenced operation (T 310) resulting in an unusually high domestic heating load. The Company did not disagree but stated that, due to the severe winter, power was frequently interrupted. This reduced tie-line power available to the ski operation as evidenced by the fact that $16,000 in diesel fuel was consumed in operating the standby diesel generator (T 328). Mr. Pollock also stated that the 1989/90 season was unusual in that there was insufficient snow to support regular ski operation until after Christmas. This resulted in below normal electrical demand and consumption (T 311). 5.2 Operating Costs Another component of the cost of service is the expense incurred in the operation of the utility. Table 3A of the Application provides a breakdown of the estimated costs for the test year. These costs can be grouped under three general headings: (a)Administrative Costs $68,300 (including wages and benefits, office services and overhead expenses) (b) Repairs, Maintenance and Vehicle Costs 31,000 (c) Snow Removal 18,000 TOTAL AMOUNT APPLIED FOR $117,300
12 5.2.1 Administrative Costs It has not been the practice of the Company to prepare operating and maintenance budgets (T 366). Time sheets were available for only a limited number of employees (T 33 and 38). No evidence in the form of historical cost analyses was presented by the Company in support of the Application. Generally, the estimated administrative costs were based on judgement by the Company's accountant. This task was complicated by the fact that the parent company operates a resort and two other utility services using the same personnel. The Commission acknowledges the efficiency in having one staff to administer the operation of a multiple set of activities; however, this does not obviate the necessity for accurate allocation of common costs to discrete accounting records. Several intervenors took strong exception to the Company estimates. Mr. F. Gruen and Mr. R. Mazur, intervenors with financial backgrounds, testified that the service could be performed at much less cost. Mr. Gruen stated that his research has shown that for under $14,500 annually the following billing and accounting services could be provided off-premises (T 230-231): Billing service including computer processing, pre-printed forms, envelopes, postage, monthly mailing of invoices and quarterly mailing of statements. Maintenance of accounts receivable. Maintenance of accounts payable. Maintenance of General Ledger and Financial Statements. Maintenance of Trust Account. In support of his opinion he filed a letter from a professional accountant (Exhibit 13E), which is attached as Appendix A to this Decision.
13 As indicated in Section 5.2, the Application requested administrative costs of $68,300. While the Company provided evidence regarding the method used to arrive at the various components of the administrative costs, the Application was not supported by actual historic cost records. In addition, the delineation of some of the costs was new and had not appeared in Annual Reports to the Commission. The Commission has some difficulty in assessing the value of cost estimates based largely on judgement without supporting documentation. However, the Commission accepts that, even in an integrated operating environment, a distinct utility has certain basic requirements for accounting processes, clerical support and general costs. Accordingly, on the basis of all of the evidence. the Commission determines that $43,000 would be a far and reasonable amount to cover the costs of administration, accounting and office services for the test year. This is calculated as follows: - $15,000 to cover the cost of what might be called the manipulative processes done mostly by computer. These would include calculating customer accounts from meter readings, preparing and mailing electricity bills, keeping ledger accounts and preparing financial statements. - $20,000 to pay the allocated portion of wages and benefits for the persons involved in meter reading, coding accounts receivable and payable, bank transactions, collecting bills, dealing with customers, filing and other office functions. - $5,000 allowance for bad debts, insurance, property taxes, business licenses and other costs. - $3,000 as a one-time charge for setting up procedures, computer programs and budget preparation to organize the administration services appropriately, and other contingencies. The Commission directs the Company to prepare and file with the Commission an operating budget at the beginning of each fiscal year.
14 5.2.2 Operating Improvements There are actions the Company can take to reduce its operating costs. For example, meter readings and customer billing could be done on a bi-monthly basis during the lower demand season from May 1 through October. The Company has a wide fluctuation in cash flow between the summer and winter seasons. Some of the problems associated with shortages of working capital could be alleviated by offering the customer some payment options. For instance, the customer could be given the opportunity to pay on a budget plan in twelve equal monthly payments. The final payment would be adjusted in accordance with actual meter readings. Another option would be to accept pre-payments with a discount from those customers willing to authorize payments directly from a personal bank account. Any one or a combination of these options could provide an accumulation of working capital in the off-season and would shorten the time lag in collecting customers' bills. Incentives such as these are used commonly by other electric utilities. The Commission suggests that the Company seek competitive quotations for routine maintenance work with the objective of setting up appropriate blanket orders. A job order system could then be utilized against pre-agreed charge-out rates. This type of system would allow for the use of dedicated services both for routine and emergency maintenance situations. 5.2.3 Maintenance and Vehicle Cost The Company forecast the cost of repair and maintenance at $25,000 for the test year. This figure resulted from a stated actual cost of $35,000 in 1989/90 less $10,000 for the incorrect allocation of sewer pump charges. It must be emphasized that this forecast is considerably higher than expenditures reported in previous years in Annual Reports filed with the Commission. While the Company's forecast was essentially not disputed in detail by intervenors, the evidence in the hearing clearly indicated the serious concern of the
Company's customers regarding safety and maintenance procedures, and their desire to see necessary work carried out.
15 The Company filed in evidence a report from Aard Wolf Electric (Exhibit 6) listing outstanding maintenance work it felt was required to restore the distribution system to acceptable standards. The Company electrician, at the time, agreed with the proposal and suggested that the work be done on a priority basis (Exhibit 26). He estimated the cost of priority items at $30,000 plus materials with a further $45,000 for other proposed work. The Company intends to have this work done as time and personnel permit (T 356). The Commission is concerned that the utility system be maintained in a manner that assures an adequate, safe and dependable service. The Commission needs to be advised that the priority maintenance items listed in Exhibits 6 and 26 are carried out in the near future. The Company has undertaken to have items 1 through 5 listed on Exhibit 6 completed first (T 350-351). The Commission therefore directs that the Company provide the Commission with a time schedule for the completion of the work, as well as specific advice when the work is completed. In addition, the Company is directed to file a copy of its preventative maintenance program by November 1, 1990 (T 115). In reviewing Exhibit 6, the Commission considers that some of the items should be considered as capital expenditures inasmuch as they will improve or extend the life of the system. Optional work for system separation for ease of maintenance should be considered as capital cost. In light of the foregoing, the Commission concludes that an amount of $20,000 is a fair and reasonable allowance for repair and maintenance costs for the test year. 5.2.4 Snow Removal The Company requested approval of an $18,000 expense item for the cost of removal of snow from electrical transformers housings and connection pits. It presented evidence that an amount of $17,593 had been expended the previous year in removing snow from transformers because some had suffered damage
16 or failure and many had to be cleared to isolate the problem. Snow had not been removed from transformers in previous years. The Commission finds that proper maintenance and proper marking to prevent damage from snow-clearing machinery will preclude the necessity for regular snow removal. Proper protection and marking of all installations subject to risk of damage, including electrical, propane tanks and fire hydrants, should be considered mandatory. The Commission concludes that the request for an $18,000 annual expense for snow removal is unnecessary. 5.3 Hearing Costs Mr. K. O'Donnell, in his intervention, expressed the concern of many ratepayers that the Company's hearing expenses should not be borne by them. In particular he pointed to fees attributed to questions of law, e.g. rate base. Because the process is in the interest of the ratepayers, it is the normal practice of regulatory tribunals to allow applicants to recover reasonable costs. These can include both the Applicant's costs and those of the tribunal. Section 133 of the Act precludes the funding of intervenors. In this case, the Company estimated its Application costs at $30,000. Subsequent to the hearing, the Company advised Commission staff that its actual costs were in the order of $43,000. The Commission notes this increase and has decided to increase the Application estimate by $5,000. The Commission anticipates that Application costs for any future hearings will be substantially less, inasmuch as the Applicant is more familiar with the process, and special legal and consulting fees should not be required. 6.0 UTILITY MANAGEMENT AND QUALITY OF SERVICE Every public utility is required to provide suitable service to its customers without undue discrimination or delay. This requires that the utility operate
and maintain its property and equipment in a condition to supply safe and efficient service. In a small utility with limited revenue, where the employees
17 have other non-utility related duties, it is incumbent upon management to provide the supervision that ensures this quality of service. In the circumstances of HVES, the same personnel are involved in a number of different business activities, all with the same basic objective---the successful operation of a mountain resort. While HVES provides a distinct electrical service to its customers, it differs significantly from other utilities in that the service is but one of several activities owned and managed by Hemlock Valley Resorts. This dependent arrangement contributes to the "credibility gap" that permeated the submissions of intervenors. There is no question that the customers experienced a sense of frustration in their dealings with the owner on matters involving invoicing, information requests, and concerns regarding the safety and reliability of the system. Evidence of this general syndrome surfaced in relation to discussions regarding Exhibit 6, a report dated March 9, 1990 by Aard Wolf Electric. The report refers to difficulties encountered due to "poor work standards and designs", and recommended work on a list of five deficiencies that should be done on a priority basis. The report states, "These five items should be done as soon as possible for safety reasons and ease in finding any future problems should they arise." In T 346-348, Mr. Peters could not assure Commission Counsel that the foregoing had been corrected. In addition, Mr. Peters was less than certain regarding the qualifications of his former electrician and the requirements for the job (T 350). Further, Commissioner Page's discussion with Mr. Peters (T 355-357) regarding water infiltrating electric service entrances, a matter raised by Mr. Cavens, revealed the same lack of urgency by the utility in relation to matters of safety. Intrinsic in this Application for revenue requirements is the request that HVES be treated, under regulation, like other utilities. Accordingly, the Commission suggests that this expectation be complemented by the requirement that the
18 utility be managed like other utilities. In this sense, HVES must operate efficiently to provide its customers with safe and reliable services (T 359). Suggestions have been made in earlier sections of this Decision which can not only improve safety and reliability but also address customer concerns. In a discussion relating to bad debts (T 363-364), Mr. Peters stated: "So what we've done now is, and speaking of a social problem, we do have a social problem up there, because everybody in this room is familiar with me or whoever else is on the hill, and they want to make sure the hill is running right and the skiing is right. This is really secondary to their main interests. They did not buy these places up on the hill to pay electrical bills, they bought them to go skiing. That was their main concern." In acknowledging the necessity to manage bad debts because of the impact on all ratepayers, Mr. Peters stated (T 364): "It's going to be run as a business and we're going to have to do it." The foregoing comments must be related to the somewhat unique situation in which both the utility, the ratepayers and the other services on the mountain find themselves. Hemlock Valley is a resort area and, as such, does not have the permanent population base to support the resources of the community in a conventional way. As Mr. Sanderson put it (T 379): "...And indeed, just because of the surrounding unfortunate circumstances of the resort, this utility is unlike, 1 think, any other that you're called upon to deal with." The need to address the appropriate focus in Hemlock Valley was echoed by Mr. Cavens (T 423-424): "...I think you've seen before you in the last couple of days, you've seen ten individuals from the Rate Payers' Association. Our association comprises about 202 people. It was mentioned in our opening statement. And I would like to see this focus taken away
19 from the electric utility, moved into doing something productive for the mountain. This exercise has tended to drive us apart, and 1 would like to see those energies now focus on doing something productive for our investments, Hemlock Valley's investments, and the recreational potential of Hemlock Valley." During the course of the hearing, the Commission was impressed with the sincerity, variety and degree of expertise shown by the witnesses for the principal intervenor, The Hemlock Valley Ratepayers' Association. It is suggested to the Company that consideration might well be given to drawing on this pool of talent. The Commission strongly recommends that a "Utility Consultation Committee" be established by HVES, with members from the utility and representative ratepayers. Quarterly information meetings should serve to improve communications in the interest of the common goals of all the participants on the mountain 7.0 DECISION SUMMARY 7.1 Revenue Requirement Section 44 of the Utilities Commission act requires that: "Every public utility shall maintain its property and equipment in a condition to enable it to furnish, and it shall furnish, a service to the public that the Commission considers is in all respects adequate, safe, efficient,just and reasonable." It is the duty of the Commission to see that this is done. It is also the duty of the Commission to ensure that the utility has sufficient revenue to enable it to perform these functions. However, it must always be satisfied that the level of funding provided for is within the Company's ability to use efficaciously. On the basis of the evidence presented, the Commission has set a revenue requirement to satisfactorily meet the above objectives (refer to attached schedules).
20 7.2 Rate Adjustment Phase-ln As mentioned in Section 1.0, the Application contemplated a rate increase of 84.6% in the test year. The adjustments to the cost of service in this Decision have mitigated some of the potential rate shock. The Commission considers that a return on rate base should be allowed, however, it believes that the ratepayers should be protected from the full impact initially. In arriving at this conclusion, the Commission has recognized that there was a hiatus of some seven years between Applications. In addition, the future economics and the viability of the mountain are at stake. Accordingly, the Commission orders that the rate base costs be phased-in over three years. The Commission requires the utility to file amended rate schedules incorporating an increase of 1.51ยข per kW.h over permanent rates effective July 1, 1990, and for further increases of 1.51ยข per kW.h and 0.75ยข per kW.h effective May 1, 1991 and May 1, 1992, respectively. DATED at the City of Vancouver, in the Province of British Columbia, this of October, 1990.
IN THE MATTER OF the Utilities Commission Act S.B.C. 1980, c. 60, as amended and IN THE MATTER OF a Rate Application by Hemlock Valley Electrical Services Ltd. DECISION October 17, 1990 Before: J.G. McIntyre, Chairman H.J. Page, Commissioner K.L. Hall, Commissioner
APPEARANCES C.W. SANDERSON Hemlock Valley Electrical Services Ltd. B. CORNISH T. POLLOCK Hemlock Valley Ratepayers' Association B. CAVENS W. DOWLER Strata Council 1282 ! COMMISSION COUNSEL G.A. Fulton COMMISSION STAFF B. McKinlay N.C.J. Smith COURT REPORTERS/ Allwest Reporting Ltd. HEARING OFFICER (i)
TABLE OF CONTENTS APPEARANCES LIST OF EXHIBITS 1.0 INTRODUCTION 2.0 BACKGROUND 3.0 INTERVENORS 3.1 Hemlock Valley Ratepayers' Association 3.2 Strata Council NW1282 4.0 RATE BASE 4.1 Determination of Rate Base 4.2 Capital Structure 4.3 Return on Rate Base 5.0 COST OF SERVICE 5.1 Purchased Power 5.2 Operating Costs 5.2.1 Administrative Costs 5.2.2 Operating Improvements 5.2.3 Maintenance and Vehicle Cost 5.2.4 Snow Removal 5.3 Hearing Costs 6.0 UTILITY MANAGEMENT AND QUALITY OF SERVICE 7.0 DECISION SUMMARY 7.1 Revenue Requirement 7.2 Rate Adjustment Phase-ln Order No. G-77-90 Schedule 1 Utility Rate Base Schedule 2 Utility Income and Return Schedule 3 Income Taxes Schedule 4 Return on Capital Table of Adjustments Appendix A Exhibit 13E - Thomas R. Friedrich, C.G.A. letter dated September 6, 1990 re: Hemlock Valley Electrical Services Ltd. Billing QuotePage No. (i) (ii) 1 2 3 3 4 4 4 7 7 8 9 11 12 14 14 15 16 16 19 19 20
LIST OF EXHIBITS (cont'd) Prospectus of Hemlock Valley Recreations Ltd., Subdivision 6, dated 5th December, 1979 Prospectus of Hemlock Valley Recreations Ltd., Subdivision 1, dated 29th November, 1976 Prospectus of Hemlock Valley Recreations Ltd., Subdivision 2 and 3, dated 20th April, 1978 Prospectus of Hemlock Valley Recreations Ltd., Subdivision 4, dated 28th February, 1978 Prospectus of Hemlock Valley Recreations Ltd., Subdivision 4A, dated 17th April, 1983 Prospectus of Hemlock Valley Recreations Ltd., Subdivision 5, dated 17th October, 1979 Prospectus of Hemlock Valley Recreations Ltd., Subdivision 7, dated 13th January, 1981 Prospectus of Strata Council dated 12th January, 1979 Certificate of Indefeasible Title for T.J.W. and R.F. Pollock Ski Hemlock (the Zermatt) Ski Hemlock (Winter) Hemlock (Hemlock Valley Recreations Limited) See Hemlock (Individuals Opportunities) Hemlock (Activities About at the New Hemlock) Ski Hemlock (Lot Plan Lay-Out) Commission Order No. G-36-87 Review of Aard Wolf Electric Proposal Letter from Mr. Dowler to British Columbia Utilities Commission, September 10, 1990 Letters from Interested Parties (iii)Exhibit No. ! 14 15 16 17 18 19 20 21 22 23A 23B 23C 23D 23E 24 25 26 27 28
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