1 Pacific Northern Gas Ltd. Revenue Requirements Decision April 24, 1992 CAARS 1.0 INTRODUCTION Pacific Northern Gas Ltd. ("PNG", "the Company", "the Applicant"), is a subsidiary of Westcoast Energy Inc. ("Westcoast") and is a member company of the Westcoast Utilities Group. This group consists of the Applicant as well as the Centra Gas companies who, on a combined basis, provide natural gas service to approximately 500,000 customers in British Columbia, Alberta, Manitoba and Ontario. Each company has its own president who in turn reports to the president of the Gas Utilities Division. British Columbia is served by both Centra Gas (Vancouver Island, Sunshine Coast, Port Alice and Fort St. John) as well as the Applicant on the north coast. The Applicant's system begins at Summit Lake near Prince George, where it interconnects with Westcoast's pipeline system, and terminates 350 miles west at the deep water ports of Kitimat and Prince Rupert. The Applicant's system is primarily an industrial gas transmission system serving large industrial customers of which Ocelot Chemicals Inc. ("Ocelot") is the dominant customer, consuming approximately 63 percent of the annual volume. Currently, residential customers comprise approximately 5 percent of PNG's load, while commercial, small industrial and natural gas vehicle customers comprise approximately 9 percent by volume. On a revenue basis Ocelot represents approximately 46 percent and other large industrials represent approximately 19 percent. The Company has a two-tier common equity structure. The non-voting Class A stock is publicly traded. The Class B voting shares are held in their entirety by Westcoast. The Applicant's last rate case, encompassing the 1991 fiscal year, was held in Prince Rupert, B.C. on March 18 to 22, 1991 inclusive, with the Decision rendered on April 23, 1991. That Decision approved, amongst other matters, a return on common equity of 14 percent within a range of 13.75 percent to 14.25 percent. The common equity component represented 30.72 percent of the forecast capital structure. In November of 1991, the Company held discussions with its large industrial customers to determine whether or not it would be feasible to negotiate a settlement of its 1992 Revenue Requirement and avoid a hearing. The Applicant proposed that if the revenue credit resulting from the previously approved 5 percent and 3 percent residential and commercial increases could be retained by the Company as opposed to refunded to the large industrial customers and additional revenue could be received from Ocelot, the Company would not seek further rate relief. Simultaneously, the Applicant filed with the Commission an Application for interim and permanent relief of 4.09 percent on total revenue which requested that no action be taken until the Company had completed the negotiations with these customers. These customers together represent 86 percent of the volume of gas sold by the Applicant.
2 2 On December 17, 1991 the Applicant advised the Commission staff that a consensus had not been reached and, accordingly, it requested that the Application filed on December 1, 1991, proceed.
By Order No. G-7-92 the Commission granted interim relief of 2.86 percent on total revenue effective January 1, 1992 subject to refund with interest depending on the findings of the public hearing. The Applicant applied for the opportunity to earn a return on common equity of 14.75 percent, but the Commission has limited the interim relief to the 14 percent level awarded in the last revenue requirements decision.
The hearing commenced in Prince Rupert, B.C. on February 24, 1992 and concluded on February 27, 1992. The hearing generally convened at 9:00 a.m. and concluded at 4:30 p.m. with the exception of February 27 wherein the hearing commenced at 8:30 a.m. and concluded at 8:00 p.m.
Prior to the hearing, Commission counsel wrote to all municipalities in the service area to ensure they were informed of the Application and to ascertain whether or not they would appear. Mayor Lester of Prince Rupert, in company with Mr. Smith, City Administrator for the City of Prince Rupert, attended and gave evidence.
Mayor Lester did not object to a utility, such as PNG, earning a reasonable return on its common equity but felt the Application was directed solely to the revenue side of its operations:
"We want to emphasize that we have no knowledge that this company does not operate efficiently. But we think that the Commission should concern itself with the issue of the Company's expenditure controls and practices when considering this Application. Of course, if expenditures were to be reduced, revenue requirements could also be reduced." (T. 539) The Applicant for its part provided copies of the Application to the municipalities and its large industrial customers.
Commission staff in reviewing this Application retained the services of Pevecz Consulting Services with regard to capital additions and operating and maintenance programs; Sinclair Consulting with regard to sales and weather normalization; Clifford and Associates with regard to compensations;
3 3 and Dr. W.R. Waters with regard to rate of return. The material provided by Mr. R.I. Clifford and Associates and Dr. Waters became evidence in the proceeding.
4 4 2.0 APPLICATION Pursuant to Sections 64 and 102 of the Utilities Commission Act ("the Act"), on December 1, 1991 PNG submitted an Application (Exhibit 1) for an interim refundable rate increase effective January 1, 1992 to be confirmed after a public hearing. Exhibit 2, the Direct Testimony of the Company witnesses, was received December 20, 1991 with Exhibit 3, the Direct Testimony of the Rate of Return witness being received on December 24, 1991.
The Commission would encourage the Applicant, especially when it is seeking interim relief, to file a complete Application in the first instance as this significantly reduces the processing time and costs. In this case a complete Application would consist of Exhibits 1, 2 and 3 at a minimum. With regard to the Application in general, the Commission was concerned with the lack of supporting detail initially furnished and, accordingly, brought these concerns to the attention of the Applicant by letter dated January 17, 1992 (Appendix 1).
Significant additional information was provided by the Applicant in Exhibits 4 and 5 received on February 5 and 10, 1992 respectively. The response to the industrial groups' request for additional information is contained in Exhibit 6 and was received February 18, 1992. This information request of the Applicant was made by letter dated February 7, 1992.
The Applicant is seeking a revenue increase of $1.933 million for the forecast year ending December 31, 1992. This revenue deficiency represents an increase of 4.09 percent on total revenue or 6.05 percent on the Applicant's average gross margin.
The Applicant, in support of the revenue deficiency claim, states generally that the increase is required due to capital expenditures of $7.4 million, an overall decrease in gas deliveries of 1.3 percent, repairs necessitated by flooding, a 5 percent general wage increase and the requested increase in the return on common equity. Initially the return sought was 14.75 percent which was later revised to a range of 14.50 to 14.75 percent.
The above claim was subsequently adjusted to reflect capital expenditures of $8.469 million, a reduction in the non-union wage increases to 3.5 percent and certain other adjustments resulting in the Applicant seeking relief of $1.829 million as shown in revised Exhibit 32.
5 5 In addition to the above, the Applicant is requesting a continuation of:
(i) the interim suspension of the collection of deferred income taxes; (ii) the recording in a deferred account of unaccounted for gas volumes outside of the range of 0.25 percent to 0.75 percent of total deliveries;
(iii) a deferral account to record extraordinary repairs resulting from the corrosion repair and maintenance program; and
(iv) a continuation of the short-term interest deferral account.
6 6 3.0 ISSUES 3.1 Rate Base 3.1.1 Plant Additions In the original Application, the plant additions were forecast to be $7.428 million with a list describing the expenditure and the expected cost of each item. The Commission considered that the mere recitation of tables of expenditures without further explanatory discussion as to the necessity of significant items fell far short of providing the level of comfort needed for approval. The Commission did not wish to direct PNG in how to make its case but communicated its concerns to the Applicant in a letter dated January 17, 1992 and suggested that additional supporting material be generated which would explain each major expenditure in a more comprehensive manner. PNG provided a detailed explanation of the need for each proposed addition in excess of $10,000 in Exhibit 4, which was filed with the Commission on February 5, 1992.
The detailed explanations filed by PNG were reviewed by Commission staff and Pevecz Consulting Services who were retained to examine the capital additions and operating and maintenance programs. Following this, the Applicant and registered intervenors were advised by letter dated February 14, 1992 that Commission staff was satisfied with the explanations from an engineering perspective and no further information was requested, nor would suggestions be made in that regard at the hearing to adjust or modify the program. The letter left open the question of accounting treatment of these costs.
The additions increased to $8.469 million on the revised Exhibit 32 to reflect replacements required due to an unexpected earth slide ($516,000) and additions started in 1991 but not completed until 1992 ($643,000). These increases were offset by a reduction of $146,000 due to a revised estimate on the cost of increasing the horsepower on a compressor turbine.
The industrial intervenors were looking to PNG to show signs of restraint on its capital additions (T. 871). They questioned PNG's estimates of the projected costs and whether alternative measures were considered. The Applicant confirmed that the upgrade to the Terrace shop of $110,300 could be delayed one year, a fixed span rigid bridge worth $40,000 could be purchased instead of an $81,000 Bailey bridge and the rented turbine storage facility could be improved for
7 7 $25,000 or $30,000 instead of the $72,000 it would cost to erect a building. Quotations were received for two personal computers at $15,400 instead of the budgeted $18,500 (T. 88, 95, 168 and 210).
The Commission Panel questioned the revision to the computer budget to determine if the possibility of decline was likely in the other capital additions. PNG stated that cost estimates of major capital work is based on past experience in that area and is not comparable to estimates and quotes on computer purchases (T. 210-211).
In their final argument, the industrial intervenors felt there was a need to have sufficient detail in the Application to assess whether these projects were needed. They suggested that PNG provide some narrative on projects that are above a certain level rather than just a single line item of explanation (T. 873). The industrial intervenors suggested that PNG could have come before the Commission with a general plant addition application to allow assessment of the need for the projects in advance of the rate hearing. In their view, the rate hearing would address the cost of the additions (T. 874).
The Commission agrees that a complete application is necessary and communicated its concerns to the Applicant by letter. The suggestion of a general plant addition application in advance of a rate hearing could be an issue for discussion and evidence at a future hearing, rather than only occurring in final argument. The intervenors are invited to raise the proposal at that time to allow the parties an opportunity to respond.
The Commission accepts the evidence elicited by the intervenors and, accordingly, has reduced the forecast plant additions by $151,300 representing the deferral of the Terrace shop upgrade and the purchase of a fixed span rigid bridge. The Commission concurs with the Applicant's position with regard to the turbine storage facility on owned property rather than expending considerable funds on unsuitable rental property.
Similar to the discussion in Section 3.4.1 the inflation component in plant additions has been reduced from 4 percent to 2.5 percent to reflect the most recent inflation escalation forecast.
8 8 3.1.2 Overhead Allocation In the April 23, 1991 Decision, an amount of $300,000 was disallowed from the test year capitalized overhead. A difference of opinion evidently existed between Commission staff and the Company in respect of this amount, Staff being of the view that a permanent adjustment should have been made to the 1991 plant in service additions to reflect the general reduction (T. 768). The Company took the view that the Decision referred to a particular group of expenditures proposed early in the year, but that as the year progressed, a different series of expenditures was justified, and proceeded to book them (T. 470). There is no evidence on the record to indicate that this was other than an honest difference of understanding. The Commission concurs that the 1991 general disallowance of capitalized overhead was not a permanent reduction.
The examination of this item raised a further question in the matter of capitalization of overhead with particular reference to studies of proposed capital expansion projects. Questioning of Mr. Weaver disclosed that it is the Company's practice to capitalize the cost of studies on abandoned projects as an unallocated construction cost (T. 471). The Commission notes that the Uniform System of Accounts prescribed for gas utilities and the recent Commission Order No. G-11-92 to PNG on this subject are quite explicit. The text pertaining to Account No. 172 -Preliminary Survey and Investigation Charges, states:
"If the work is abandoned the charge shall be to Account No. 329, 'Other Income Deductions', and if the amount is material, to Account No. 332, 'Extraordinary Deductions'." To capitalize the cost of studies concerning projects which do not proceed would be improperly inflating the Rate Base. Effective immediately, the Company is instructed to bring its accounting practices into conformity with the Uniform System of Accounts.
Mr. Weaver went on to state: "Our entire engineering department costs are allocated as a construction overhead." (T. 471) This policy also causes serious concerns to the Commission. It is difficult to imagine, particularly with the level of activity currently going on in connection with large-scale rehabilitation of corroded transmission pipelines, that the engineering department has no part in the operations of the
9 9 Company. Accordingly, the Company is directed to review the allocation of engineering costs for overhead purposes, and report to the Commission by June 30, 1992. The review should, among other things, indicate what adjustments, if any, would be appropriate to the account balances to give effect to revised accounting policies.
3.1.3 Deferred Charges - Extraordinary Repairs PNG has had the misfortune of having unusual corrosion problems due to disbonding of the original pipe wrapping, allowing moisture from corrosive soils to attack the metal under the coating in such a way that the pipeline's cathodic protection system is not effective. Evidence was given that this is not a unique problem to PNG and similar situations have occurred in other pipelines of the same vintage (T. 74). The subject was addressed in the 1991 hearing at which time the decision was made to treat expenditures for repairs as deferred expenses because their size would distort the test year's operating expense.
Further discussion in the current hearing identified the sections of pipe with the highest incidence of problems to be in the Telkwa Pass area, where it has been necessary to loop a six mile section (T. 79). The 8-inch pipeline between Terrace and Prince Rupert has yet to be examined and repaired. The matter was well canvassed in cross-examination of the Company witnesses as to the necessity of the rehabilitation. Mr. Weaver testified that replacements of pipe sections constituting plant units would be retired and recapitalized, with the remainder being treated as maintenance expense.
The recording of the corrosion repairs was considered in both the 1991 and 1992 Rate Hearings. In the 1991 hearing the Applicant projected corrosion repairs as a maintenance expense with an estimated value of $647,000. The Commission accepted the estimate but in the 1991 Decision directed that the costs be treated as abnormal and amortized over ten years. The actual costs for the 1991 corrosion repairs have risen to $940,000 and the Company is requesting that the deferral account be increased to reflect the actual costs.
In PNG's 1991 income tax return, the additional cost of $293,000 ($940,000-$647,000) was deducted as expense and thereby improved the net income of the shareholders (T. 151). PNG filed Exhibit 28 to explain the impact on cost of service of the additional costs. If the actual cost had been known in 1991, the deferral account would have been increased by $293,000. However,
10 10 this additional expense was deducted for income tax purposes in 1991, which results in future amortization of this amount being considered as a non-tax deductible expense.
The Commission agrees that the actual cost of $940,000 should be recorded since the expenditures were shown to be prudent. However, the Commission does not accept that the shareholders should receive the tax savings in 1991 with the customers bearing the tax consequences in future years. For regulatory purposes, the Company is instructed to record the additional cost of $293,000 as a 1992 deferral item which will provide the customers a benefit in the tax calculation for 1992. This approach is consistent with the deferral accounts established for overhead and repairs that are capitalized for regulatory purposes but expensed for income tax purposes. The difference between the forecast and the actual amount is recorded in these deferral accounts. If the actual corrosion repair costs for 1992 differ from the budgeted amount of $584,000 the variance will be reflected as a 1993 addition. The Commission is to be advised of the actual 1992 costs when they are known.
3.1.4 Propane/Air Plant In the May 1985 hearing, based on the testimony from the regional inspector of the Ministry of Labour, Gas Safety Branch, and an on-site inspection by the Commission panel members of the existing propane/air plant, the Commission concluded that the existing plant was unsafe and required extensive modification and upgrading to render it satisfactory for continued operation. The existing plant was undersized for the requirements of Prince Rupert and its location was undesirable for safety reasons. The Commission considered that having Prince Rupert at the end of a single pipeline traversing remote and rugged terrain, made mandatory the provision of an alternative or standby source of fuel for emergencies. An important additional financial benefit of the proposed new plant was its ability to peak shave load and allow PNG to reduce its capacity nomination with Westcoast. Accordingly, by Order No. C-2-85 dated June 6, 1985 the Commission issued a Certificate of Public Convenience and Necessity for the construction, operation and maintenance of a new propane/air plant.
The new plant is located on property that is leased from the Canadian National Railway. The lease was recently renewed for a period of five years effective January 1, 1991. The annual lease costs increased at that time from $4,560 to $8,400 per year. PNG also subleases property from ICG Propane Inc. ("ICG") on which PNG's storage tanks are located. The annual lease rate
11 11 from 1981 to 1992 was $1,800 but ICG has indicated that the annual rate will be increasing to $18,000 effective January 1, 1992.
The Commission is concerned with the increase in the rates and notes that PNG made a long-term investment in plant without obtaining a long-term lease. The Company is directed to review its options of controlling the lease cost and possibly obtaining alternative arrangements, inclusive of expropriation, if appropriate and report to the Commission by September 1, 1992.
3.1.5 Mid-Year Net Plant in Service The Applicant stated that plant additions are normally placed into service from approximately mid-May through to the end of September but a mid-year average value is used when calculating the net plant in service (T. 160-161). The industrial intervenors considered that these additions are occurring between the middle to the late part of the year, which results in a mid-year average overstating the net plant in service for the year. The intervenors would prefer that PNG used a weighted average calculation for determining the net plant in service to avoid an overstatement of the rate base (T. 876).
PNG replied that the time of year when plant additions are placed into service does not consider the capital expenditures made on these items prior to that date. The Company does not earn an allowance for funds used during construction ("AFUDC") on all capital expenditures.
The Commission considers using the mid-year average is a reasonable representation of the timing of expenditures on capital additions for PNG at this time. However, a change to another approach such as a weighted average calculation could be more appropriate in representing the "used and useful" nature of new plants if PNG has significantly large projects coming on stream. More evidence is required in support of this method before consideration could be given to its adoption. 3.1.6 Hearing Costs PNG filed this Application with the expected 1992 hearing costs being amortized over two years, which is consistent with the Commission's direction for the recovery of the 1991 hearing costs (T. 41). The most recent estimate of hearing costs includes $77,000 for PNG and $80,000 for the Commission. The Commission costs exclusive of consultants, legal and court reporters was approximately $5,000.
12 12 The allocation of those costs between the customers and the shareholders was a subject of discussion in the 1991 and 1992 Revenue Requirement Hearings. In the final argument, the industrial intervenors questioned the obligation of the customers to pay for the costs of defending such items as rate of return, which in their view is for the shareholder's benefit (T. 890-891).
The Commission believes that due to the circumstances of this hearing it is appropriate to disallow 30 percent of PNG's costs. The Commission directs that the hearing costs from this proceeding be recovered in the current year.
3.2 Sales & Revenue 3.2.1 Residential, Commercial and Small Industrial The above classes of customers represent approximately 36 percent of the revenue forecast by the Applicant to be received in 1992.
In reviewing the forecast for these groups consideration was given to the weather data being used as well as the method used to determine the use per customer per degree day of temperature sensitive load.
With regard to the degree day data, this material is collected for Prince Rupert, Terrace, Smithers and Prince George with the western cities data being given a weighting of 1/3 each with the remaining communities dividing the remaining third. The weighted distribution is based upon customer location. The Applicant develops the degree days for each location by assigning a weight of 50 percent to each of the 5 and 25-year averages provided by Environment Canada. The heat sensitive portion of the load is determined by deducting consumption for the month with the lowest number of degree days from the monthly consumption during the year.
If and when the heat sensitive load becomes a more significant factor in the sales mix, consideration must be given to a more sophisticated procedure. However, at this time additional expenditures could not be supported to achieve a higher level of accuracy.
13 13 3.2.2 Large Industrial PNG requests a forecast of the natural gas requirements from each of its large industrial customers each fall. The Company is seeking estimates of; the monthly firm and interruptible gas requirements for the remainder of the current year and the following calendar year, the annual firm and interruptible gas requirements for the following four years and the firm gas nomination for the next five years. The customers have been cooperative in providing information to PNG (Exhibit 4, Tab 1, pages 50-53). The monthly forecast or an annual projection provided by the customer was used by PNG to determine the sales volumes for the test year. The Applicant also considered the historical consumption of the customer and current circumstances in estimating the sales volumes (Exhibit 2, Tab 1, pages 5 and 6).
PNG considers that the sales forecasts included in the Application are reasonable with an equal chance of being over or under the actual volumes for 1992 (T. 24). The forecast includes Ocelot running at almost full capacity for the year, with the exception of the three week scheduled shutdown. The forecast volumes for Skeena Cellulose Inc. ("Skeena"), Eurocan Pulp and Paper Co. ("Eurocan"), and Alcan Smelters and Chemicals Ltd. ("Alcan") are close to the high end but there still is the possibility of additional volumes (T. 27).
The sales forecasts for Ocelot include the equivalent of 31 days of shutdowns representing 21 days for the planned shutdown, 5 days for unplanned shutdowns by Ocelot and 5 days when PNG will be unable to deliver gas due to repairs on the system or winter curtailments (T. 811 and 274).
The 1992 test year projects that total industrial sales will be 29,787 TJ while the actual 1991 volumes were 30,733 TJ (Exhibit 5, Tab 1, page 21). The variance of approximately 1,000 TJ is due to increased interruptible sales made in 1991. The industrial customers were active participants in the hearing and stated that they worked closely with PNG in developing the forecasts and do not challenge them (T. 864). The Commission accepts the forecasted firm sales. Interruptible sales are discussed in Section 3.2.3.
The Commission was very pleased to have representation at the hearing from the Company's largest industrial customer. Mr. Jeffery Tyson, Manager of Gas Supply and Regulatory Affairs for Ocelot Industries Ltd. was present throughout the hearing, and took the stand as a witness for
14 14 Ocelot. Mr. Tyson's testimony puts on the record information and a perspective which is valuable to the Commission.
3.2.3 Large Industrial Interruptible Gas Deferral Account In the 1991 Revenue Requirements Hearing the Company requested a deferral account which would have accrued the variations between the actual and forecast levels of industrial interruptible sales revenue. PNG was concerned about its upcoming negotiations with the industrial customers on value of service interruptible rates and the resulting effect on revenue. The Commission considered that the account would not be required until, at the earliest, after the Company filed new rate structures on July 1, 1991, at which time the Commission was to receive submissions. No submissions were received and no further action was taken by the Commission.
The request for a deferral account was not included in the 1992 Rate Application but the issue was raised by Commission staff. The 1991 interruptible sales that were projected for Skeena, Eurocan, Alcan and British Columbia Hydro and Power Authority ("B.C. Hydro") were approximately 1,076,000 GJ; however, the actual results were about 2,394,000 GJ. The Commission recognizes that the forecasted 1992 test year interruptible volumes for these customers have increased to approximately 1,622,000 GJ as shown in Exhibit 5, Tab 1, page 21 due to higher customer forecasts in 1992 and the actual 1991 sales, but the Applicant stated that additional volumes could be sold to these customers.
An interruptible gas deferral account would capture the additional revenue if sales to these customers were higher than projected. However, to be fair, the deferral account would also have to record the revenue short falls if interruptible sales were less than projected. On balance, the Commission believes that a deferral account is not appropriate at this time for sales to these customers since it would remove the management responsibility of forecasting and could become a potential disincentive. The Commission accepts the projected interruptible sales volumes to these customers for 1992.
The projected 1991 interruptible sales to Ocelot were approximately 2,326,000 GJ due to a reduction in the forecasted operating level of the methanol/ammonia plant to 59 MMcf per day from 62 MMcf per day and the inclusion of a three-week planned shutdown in the year. The actual volumes were about 4,365,000 GJ in 1991 resulting from the shutdown only lasting seven
15 15 days and the daily deliveries increasing to 60 to 61 MMcf per day in the second quarter of 1991 (Exhibit 5, Tab 1, page 21 and Exhibit 2, Tab 1, page 8).
The 1992 interruptible sales to Ocelot are forecast to be 4,045,643 GJ (Exhibit 5, Tab 1, page 21). The deliveries to Ocelot are allocated to the firm volumes first before they are billed at interruptible rates (T. 20). During the shutdown period, Ocelot is required to pay 80 percent of its firm margin even though it is receiving no gas, so a deficiency results. When the plant resumes operation the volumes in excess of the 80 percent level are applied against the deficiency (T. 279). The net effect at the end of the year is a reduction in the interruptible sales (T. 280).
Rather than using the expected Ocelot shutdown in the calculation of sales, Commission staff suggested that a ten-year moving average of the actual planned shutdowns could be used and the expected volumes could be adjusted accordingly. Another alternative would be to impute a shutdown of one and one-half weeks into any year based on a three-week planned shutdown being expected every second year (T. 270-272). PNG prefers to rely on Ocelot's prediction of their planned shutdown in the test year (T. 273).
Ocelot does not oppose new growth on the PNG system if it adds integrity to the system and pays a fair rate. The Ocelot witness expressed a concern about the possibility of interruptible sales being made to other customers at a rate that is only slightly higher than Ocelot's interruptible rate. Ocelot considers that there is a balance in its very high firm rate and very low interruptible rate and views its rate as a blend of the firm and interruptible rate (T. 781-784).
In final argument, Ocelot acknowledged that their concerns over sales to other customers cannot fetter the Commission or anybody else in any way with regard to other contracts which PNG may enter into before a rate design study is done (T. 867-870).
The Commission recognizes that PNG benefitted from the actual 1991 Ocelot shutdown only lasting seven days rather than the predicted three weeks. A deferral account would have retained the additional revenue for the customers and would have reduced the effect of a shutdown being included in the test year. The Commission accepts the 1992 interruptible sales forecast for Ocelot including a three-week shutdown.
16 16 3.2.4 Other Interest of $17,000 received for a linebreak settlement outstanding since 1987 was recorded as income by PNG in 1991. The intervenors suggested that the interest should have been offset against the linebreak cost in the deferral accounts. The Applicant agreed with the proposal and made the corresponding adjustment.
Various deferral accounts had been established to record the difference between the actual and the projected values. The Company was capitalizing repairs for regulatory purposes but expensing them for tax purposes with an expected tax saving reflected in the 1991 Application. A deferral account was established for the difference between the actual tax savings and the 1991 Decision amounts. At the end of 1991, the account had a credit balance of $36,000 (Exhibit 4, Tab 1, page 114).
A similar account was established for overheads that are capitalized for regulatory purposes but expensed for tax purposes. The balance in the account is a credit of $94,000 (Exhibit 4, Tab 1, page 115).
A deferral account was established to record the difference between the actual short-term interest rate and the rate of 9.9 percent per annum which was used in the 1991 Decision. A credit balance of $40,400 has been recorded in the account (Exhibit 4, Tab 1, page 116).
The Commission directs that the deferral accounts for repairs, overhead and interest rate, should be maintained and accrue interest subject to a future Order of the Commission. 3.3 Gas Purchases 3.3.1 Gas Supply Gas supply costs represent approximately 50 percent of the total costs of the Company. PNG arranges its gas supply through the efforts of Messrs. Dyce, Hough and Donohue (T. 339). To assist in the gas supply management, PNG has retained on a trial basis, the services of Canadian Hydrocarbons Marketing Inc. ("CHMI"). PNG decided to increase its demand nomination with Westcoast from 727.5 103m3 to 759.3 103m3 effective November 1, 1992 and relied on
CHMI's position in the queue to obtain the additional capacity. 17
17 In 1991, over 62 percent of all deliveries were for sales service but in 1992 this component will decline to approximately 27 percent with a corresponding increase in transportation service. According to the 1991/92 contract demand nomination, all large industrial customers will be receiving transportation service in 1992 which has PNG concerned over the Company's loss of flexibility in controlling its gas supply (Exhibit 4, Tab 1, page 66 and Exhibit 2, Tab 1, page 11). If a transportation service customer does not use its capacity on the Westcoast system, PNG is unable, at this time, to access that capacity for sales to other customers which can result in unused capacity on the PNG system. However, additional interruptible volumes, in excess of the valley gas available from the sales service customers, can be obtained through the purchase of interruptible gas from CanWest Gas Supply Inc. ("CanWest") or other suppliers (T. 313-316 and 338-339).
Prior to November 1, 1991 PNG was purchasing all of its firm gas requirements indirectly from CanWest in a contract expiring in 2002. The Company used the option of obtaining 25 percent of its core market requirements from other sources effective November 1, 1991. PNG entered into gas supply contracts on November 1, 1991 with Ocelot Energy Inc., Encor Energy Corporation Inc., Czar Resources Ltd. and CHMI for the supply of 25 percent of the core market requirements. The contracts are for 15 years except for CHMI which ends March 1, 1992.
The gas supply costs in the Application are based on the rates in effect prior to November 1, 1991. PNG received Commission approval by Order No. G-9-92 to continue recording changes in gas supply prices in a deferral account until March 1, 1992 and to record the interim changes in the Westcoast tolls effective January 1, 1992. PNG requested an extension to this deadline and filed the actual gas supply costs on April 2, 1992. This matter will be dealt with by a separate Order of the Commission. 3.3.2 Unaccounted for Gas PNG is requesting continuation of the treatment for unaccounted for gas as directed in the 1986 Decision. In that Decision, PNG was directed that if fluctuations occur in the gas account outside the range of 0.2 percent loss to 0.7 percent loss, the Applicant will apply for an accounting order for the treatment of unusual fluctuations prior to closing its accounts for the fiscal year. The practice has been satisfactory in the past and the Commission determines that it should be continued.
18 3.4 Operating Cost An analysis of the revised Exhibit 32, Schedule 2 indicates that for the 1992 test year the O&M wages and benefits have increased by 12.62 percent over the 1991 Decision level while the O&M "all other" increased by 22.15 percent. The Applicant filed Exhibit 22 to show the projected O&M expenses for 1992 of $7,250,000 excluding inflation and the salary and wage increases. The majority of the increase over the normal 1991 level was due to additional personnel, staff changes from part-time to full-time, additional pipeline patrols, right-of-way clearing and extraordinary repairs (unrelated to corrosion) (T. 508-517).
The O&M wages and benefits per GJ sold have increased from 11 cents in normalized 1990 to 13 cents in normalized 1991 and to 15 cents in test year 1992 (Exhibit 4, Tab 1, page 14). The O&M "all other" has fluctuated from 7 cents per GJ to 6 cents then returning to 7 cents per GJ over the same time period. On a per customer basis, the total O&M costs were $431 in normalized 1991 and are projected to rise by 5.82 percent to $456 in test year 1992 (Exhibit 4, Tab 1, page 18).
The Commission considers that the 1992 levels have been supported by the Applicant, except in the areas that have been adjusted, but the Company must strive for greater efficiency in the future through the size of its operations and its joint participation with the Westcoast group of companies.
3.4.1 Inflation The Applicant initially included an inflation rate of 4 percent over 1991 levels for the projected O&M costs in 1992 (Volume 1, Tab 15, page 4) with a 1 percent change being equal to $13,000 for materials and supplies and $13,000 for outside services. Testimony was received from two expert witnesses regarding their projections of inflation for 1992. Ms. McShane (the Applicant's witness) expects that inflation will be 3 percent for 1992 while the Federal Government's forecast is for a rate of 2.2 percent (T. 521-522). Dr. Waters (Commission staff witness) estimates the inflation rate to be in the range of 2.5 to 3 percent for 1992 (T. 670). The Commission considers on the basis of the information provided, that an inflation provision of 4 percent is excessive and accordingly reduces the O&M expenses by $39,000 to reflect a rate of 2.5 percent.
19 The Applicant used the Consumer Price Index ("CPI") as its basis for estimating inflation (T. 140-148). The witnesses could not provide a more appropriate measure of inflation than CPI. The Commission, in these circumstances, accepts the use of this index as a proxy for inflation on its O&M (T. 213-214 and 838-839).
3.4.2 Maintenance Costs The pipeline maintenance costs, account 865, are shown as $234,000 for the 1992 test year while the actual 1991 costs were $109,000 and the 1991 test year projected $107,000 (Volume 5, Tab 2, Appendix page 24). Based on this comparison and the Applicant's pre-filed evidence which indicated that the routine expenses in this account are only $92,173 (Exhibit 4, Tab 1, page 83) Commission staff questioned whether the difference of approximately $142,000 should be amortized rather than expensed in one year. The Applicant considers that even though these other expenses are non-routine, they are not extraordinary and should not be reclassified to a deferral account for amortization (T. 490-493). The Commission accepts the Applicant's view regarding these maintenance costs and no adjustment will be made.
3.4.3 Donations The Applicant has included in the 1992 test year a provision for donations of $33,000 within its service area. Mr. Dyce justified the expenditure with the view that the benefits are shared by the communities and the employees of the Company. PNG considers that donations assist a gas marketing program, which may result in more customers, greater revenue and stable rates (T. 129-132). The Commission believes that donations are a normal business expense which provides benefits to the customers and the shareholders, and accordingly the cost has been reduced by 50 percent in the Schedules to reflect an equal sharing.
3.4.4 Wages and Salaries The Applicant stated that the wage increase for unionized staff was set at 5 percent following a negotiated settlement (T. 116-117). The compensation package for executive management, amongst other matters, includes three components: an incentive program (payment for achieving goals agreed to between the executive and the Company), a merit aspect and a share option program (T. 737 and 841-842). The merit component was initially set at 5 percent for the year
20 20 but was reduced to 3.5 percent (Exhibit 7, Attachment No. 5). The overall budget for incentive payments in 1992 is in the range of $50,000 to $60,000 (T. 738).
The Commission staff, after receiving the pre-filed evidence presented by the Applicant, had a review of the Executive and General Salaries, Wages and Benefits undertaken by The Clifford Group Ltd. which was filed as Exhibit 11. The study concluded as follows:
"In general, we find that PNG is, for the most part, the follower in average salaries for executives, managers and other non-union personnel in a national comparison and leads in average hourly wage rates for unionized employees by comparison to other utility companies in British Columbia. However, this is offset by a lesser level of benefits and may be driven by competition for skills in the Northwest of British Columbia." 3 .5 . Other Issues 3.5.1 Reassessment on Compressor Equipment and Customer Contributions In 1985 PNG received a reassessment notice from Revenue Canada for the years from 1981 to 1985 which reclassified the compressor station equipment from Class 8 for gas transmission purposes to Class 2 for gas distribution (T. 758). There was a resulting decrease in the capital cost allowance rate from 20 percent per year to 6 percent per year. This reassessment also considered customer contributions to be income.
PNG appealed the reassessment through two levels of court and obtained a decision which upheld the reclassification on the compressors and rejected treating customer contributions as income. During the appeal process the Company remitted income taxes assuming the reassessment was correct but continued to claim capital cost allowance at the higher rate of 20 percent. By remitting tax instalments in excess of the amount owing, Revenue Canada considered that current taxes were overpaid which resulted in interest owing to PNG on these overpayments (T. 756-758).
The result of the reassessments and the court decisions received as of November 26, 1991 required additional income tax payments of approximately $2,911,000 for the years from 1980 to 1985 plus interest on the deficient payments of $1,072,000. Interest owing to PNG on the current overpayments was approximately $267,000. (Exhibit 4, Tab 1, pages 107 and 108).
21 21 The Company collected deferred income taxes in its rates until 1986 when at the request of Ocelot, PNG applied for a change to flow-through tax accounting. PNG recorded income tax expense using the 6 percent capital cost allowance rate beginning in 1987 coincident with the change to flow-through (T. 754). All of the additional payments resulting from the reassessment, including the interest components, have been recorded in the deferred taxes payable account (T. 154). The customers are not liable for the additional tax payments of $2,911,000 due to the prior contribution to deferred taxes.
PNG is requesting recovery of a net amount of approximately $626,000 which is comprised primarily of the interest on the deficient payments less interest on the overpayments. The Company is requesting the amount be set up in a rate base deferral account and amortized over five years.
The Commission concurs with the initial interpretation of the Applicant in the classification of the compressor equipment under Class 8 due to the operating pressures of the system. However, Revenue Canada Taxation adopted a different interpretation which was supported by the courts. Accordingly, adjustments were required. The Commission rejects the request to set up a rate base deferral account and amortize the balance since the costs more properly relate to deferred taxes. As a result, no entry will be made to reclassify the balance currently recorded in deferred taxes payable.
22 22 4.0 RATE OF RETURN ON COMMON EQUITY 4.1 Introduction As a result of the 1991 Revenue Requirements Decision, the Commission granted PNG the opportunity to earn a rate of return of 14.0 percent, within a range of 13.75 percent to 14.25 percent on a common equity component of approximately 31 percent of the capital structure. In 1991 PNG's actual return on common equity was approximately 14.7 percent on a common equity component of 31 percent of the capital structure.
In its current Application, PNG has requested a rate of return of 14.50 to 14.75 percent on a projected common equity component of 33 percent of the capital structure. This request is supported by the evidence of Ms. Kathleen McShane, an expert witness retained by the Company, whose recommendation was based on an assessment of the business and financial risks faced by the utility.
In addition to the evidence provided by the Applicant, the Commission also received evidence from Dr. William Waters, an expert witness retained by Commission staff to provide a second view as to the appropriate rate of return on common equity for PNG. As a result of his assessment of the risks and financing issues facing PNG, Dr. Waters concluded that a fair rate of return for the utility would be within a range of 12.5 to 13.125 percent on the same common equity component, namely 33 percent.
4.2 Riskiness of PNG - Company Position Ms. McShane stated that PNG faces four key business risks. These are: (i) cost forecasting risks; (ii) market/demand risks; (iii) physical and gas supply risks; and (iv) regulatory risks. Cost forecasting risks relate to a potential shortfall in allowed return resulting from unanticipated increases in debt costs, capital expenditures, and operating and maintenance expenditures. Last year PNG's actual capital structure contained approximately $20.5 million of short-term debt
23 23 (17 percent of its capital structure) at an estimated cost of 9.9 percent. Issuance of $15 million of long-term debt in late 1991 allowed the Company to reduce its reliance on short-term debt to $7.4 million or 6 percent of its capital structure for 1992 at an estimated cost of 7.6 percent. In order to avoid the effects of volatility associated with short-term rates, PNG has applied to retain the deferral account authorized by the Commission last year. Continuation of the deferral account will eliminate the forecasting risk associated with short-term debt.
Market/demand risks relate to potential deviations from expected revenue which result from weather, cyclical volatility associated with industrial sales, highly concentrated industrial volumes, price competition with other fuels and gas-on-gas competition. For PNG, the primary market/demand risk results from the abnormally high concentration of sales (approximately 90 percent) to a small number of industrial customers who face cyclical markets. In fact, Ocelot is expected to take 63 percent of PNG's entire volumes through a combination of firm and interruptible sales and service.
Ms. McShane testified that the market/demand risks are reduced by the minimum bill provisions associated with all PNG's large industrial customers, and in the case of Ocelot, by the existence of government guarantees associated with firm service volumes.
Nonetheless, Ms. McShane testified that if sales to large industrial customers were reduced to minimum bill levels, the Company would be exposed to a potential 7.7 percent shortfall in allowed return (Exhibit 3, page III-5), assuming no offsetting rate increases to other classes of customers.
In written testimony, Mr. Dyce suggested that this income exposure was greater than in 1991 and reflected the elimination of the incentive gas rate to Ocelot and considerably higher interruptible deliveries to the remaining three large industrial customers (Exhibit 2, Tab 1, page 7). Based on Exhibit 23, Mr. Dyce stated that if PNG were to lose all sales to Ocelot in excess of minimum load factor deliveries, the margin on remaining sales and transportation volumes would need to be increased $0.123 per gigajoule if PNG were to be kept whole and have the opportunity to earn its allowed rate of return. Further, if the entire Ocelot load were lost, the margin on remaining sales and transportations volumes would need to rise $1.26 per gigajoule if the revenue requirement were to be met. Mr. Dyce indicated that the spread between gas and other energy forms was sufficiently large that he expected residential and commercial customers could be retained by the Company even in the face of that sharp an increase, but that the Company would lose the other large industrial customers and 75 to 80 percent of the small industrial accounts (T. 418-424).
24 24 However, sufficient margin would exist in the residential and commercial categories for the Applicant to have the opportunity to earn its full return.
Ms. McShane testified that PNG faces relatively high physical risks due to the difficult nature of the terrain covered by the line. In addition, PNG's recent diversification of its gas supply has increased the possibility of deliverability failure due to reduced access to pooled supplies through CanWest.
Finally, Ms. McShane stated that the regulatory risks faced by the Company are minimal. In addition to business risks, PNG is also exposed to financial risks associated with the Company's capital structure. Ms. McShane testified that a decline in PNG's overall debt component and concomitant increase in the equity component of the capital structure has led to a slight decline in PNG's financial risk, as measured by capital structure, since the last rate application (Exhibit 3, pages III-8). In fact, she stated that PNG's capital structure, adjusted to exclude deferred taxes, is similar to that of the average Canadian utility. In addition, the projected interest coverage ratio for 1992, assuming a rate of return on common equity of 14.75 percent, was estimated at 2.28 times, an increase from the most recent projection for 1991 of 2.13 times. However, as this is still somewhat lower than the achieved average utility interest coverage ratio of 2.5 times, Ms. McShane concludes that PNG bears somewhat more financial risk than other Canadian utilities.
As a result of these risks, Ms. McShane estimates that PNG's cost of equity capital is higher than that of the average high grade Canadian utility. Using a discounted cash flow approach to estimate the implicit costs of capital for high grade utilities and for utilities similar in risk to PNG, she determines that the investors' required rate of return on equity capital is approximately 100 basis points greater for PNG than for high grade, low risk Canadian utilities. In response to cross-examination, Ms. McShane stated that at least 75 basis points of this differential could be attributed to the difference in business risk of which the major component was the market/demand risk (T. 637).
25 25 4.2.1 Position of Staff Witness Dr. Waters stated that the basic risk faced by PNG's investors was that the Company would be unable to generate sufficient operating income to meet all its obligations, including a fair rate of return on equity capital. This would occur if:
(i) rates were set at a level insufficient to cover all costs including a fair return on capital;
(ii) actual costs exceeded those forecast or revenues were less than those assumed in setting rates; or
(iii) PNG became unable to set tolls at a level sufficient to recover costs, including a fair rate of return on equity, suggesting a permanent impairment in PNG's ability to cover its costs (Exhibit 10, page 16).
Dr. Waters testified that the regulatory regime in British Columbia resulted in significant offsets to the first two sources of risk discussed above. Responsiveness to economic conditions, use of a forward test year and the introduction of deferral accounts to relieve investors of the effects of unanticipated outlays reduced the risk faced by investors (Exhibit 10, pages 16-18). These risks were further reduced by the existence of business interruption insurance which protects the Company from the effects of a prolonged physical interruption in deliveries; minimum bill provisions associated with large industrial customers; and government guarantees associated with Ocelot's firm contract demand.
With respect to a permanent impairment in PNG's ability to set rates sufficient to cover costs, Dr. Waters stated that the most likely course of such impairment, i.e. the loss of the Ocelot load was remote since, for all practical purposes, there were no alternative uses for the Ocelot plants. Dr. Waters suggested that this meant that as long as revenues associated with Ocelot's production exceeded variable costs, the plant would take gas.
Nonetheless, Dr. Waters agreed with Ms. McShane that PNG's risks warranted a premium above the rate of return required by investors in low risk Canadian utilities. Based on evidence contained in his risk premium test, he concludes that PNG's cost of equity capital is 60-80 basis points greater than that of an average high grade utility.
26 26 4.2.2 Position of Industrial Intervenors In cross-examination, Counsel for the Industrial Intervenors suggested that as Ocelot was required to take all firm volumes before receiving interruptible volumes, PNG's income exposure was not as significant as had been suggested by Company witnesses (T. 21). Although Mr. Dyce did not agree with this suggestion, he stated that it was unlikely that Ocelot would take less than its firm commitments (T. 20). Further, Mr. Dyce characterized the increased risk associated with increased interruptible volumes as prudent risk (T. 23).
With respect to increased risks associated with the unbundling of the gas sales agreement with Westcoast, Counsel argued that the loss of flexibility was offset by a decrease in PNG's responsibility to supply customers and to pay Westcoast demand charges in cases of force majeure (T. 883-884).
4.3 Return on Equity ("ROE") 4.3.1 Position of Applicant Ms. McShane estimated the Company's required ROE using three standard tests to determine the appropriate cost of equity capital. These were:
(i) the Comparable Earnings test which measures the return on book equity achieved by low risk industrials over the selected time period;
(ii) the Discounted Cash Flow ("DCF") test which estimates the prospective rate of return on market valued common equity for low risk industrials using a dividend yield plus growth model; and
(iii) the Risk Premium test which estimates the necessary premium over and above the risk free interest rate, as measured by long-term government bonds, which must be paid by the utility to attract investors.
The first two methods calculate ROE by reference to a selected group of non-regulated companies judged to be of similar risk to utilities while the third method relies on estimates of the premium
27 27 equity capital commands over debt capital in the capital market as a whole, adjusted to reflect the particular risk characteristics of utilities.
Ms. McShane's sample consisted of 28 industrial companies chosen on the basis of volatility of earnings and market prices to be of similar risk to high grade low risk utilities. To test this assumption, Ms. McShane used a discounted cash flow analysis to estimate the implicit cost of attracting capital for her group of sample companies and for low risk, high grade utilities. Based on data covering the period 1983-1990, Ms. McShane determined that the implicit cost of capital for her sample of low risk industrials was approximately 25 basis points greater than for average high grade utilities. When combined with the previously estimated 100 basis point differential between PNG and high grade utilities, this suggests that the cost of capital for PNG should be approximately 75 basis points greater than the cost estimated for low risk industrials.
In cross-examination, Ms. McShane stated that her estimate of the differential between the implicit cost of capital for her sample and for low risk, high grade utilities has varied depending on the choice of time period used to measure the differential and was at one time as great as 80 basis points (T. 616). Further, Ms. McShane testified that inclusion of 1991 data to measure the implicit cost of capital changed the direction of the cost of capital differential between high grade utilities and low risk industrials, suggesting that the cost of capital for PNG should be approximately 125 basis points greater than the cost for low risk industrials. Ms. McShane stated that she considered the 1991 data anomalous and therefore had "somewhat of a problem with including the 1991 values" in her estimate (T. 617).
Using the Comparable Earnings test, Ms. McShane estimated the average return for the period 1983 to 1991 for low risk industrials to be 13.6 percent, based on an estimated return for 1991 of 8.8 percent. In cross-examination, Ms. McShane stated that the data compiled by the Institutional Brokers Estimate System upon which the 1991 number was based had, in the past, been more optimistic than the actual numbers proved to be (T. 565). However, she rejected the estimate of earnings for 1991 compiled by Dr. Waters (Exhibit 10A), which suggested that the average return for 1991 on the industrial sample would be 7.0 percent since she stated that the extrapolation method used could lead to an underestimation of fourth quarter earnings (T. 568). However, she agreed that if Exhibit 10A were correct, her estimate of the earnings of low risk industrials would decline by approximately 20 basis points (T. 570).
28 28 With respect to the comparability of the period 1983 to 1991 to the test year, Ms. McShane acknowledged that the manufacturing sector in Canada was undergoing a significant restructuring (T. 577) and that it might be as many as three years before the return on equity for low risk industrials reached the 13.6 percent level she had estimated (T. 574). However, she maintained that the test results were still valid for 1992 (T. 582).
In her direct evidence, Ms. McShane testified that she had placed little reliance on the results of the DCF test due to the current low level of dividend yields (Exhibit 3, page I-3) and instead relied on the results of two versions of the risk premium test to determine the cost to the utility of attracting capital. Using one version of the test, Ms. McShane estimated that the required rate of return for average common stocks was approximately 450 basis points greater than the return on long-term government of Canada bonds. After assessing the riskiness of high grade utilities versus the market as a whole, Ms. McShane concluded that "a downward adjustment to the four and a half percent market risk premium of approximately 25 to 30 percent is appropriate for higher grade utilities or a risk premium of 3.25 percent." (Exhibit 3, page IV-30).
In making this assessment, Ms. McShane relied on three measures of risk: betas, standard deviation of the TSE Electric/Gas Utility Index and a comparison of the achieved returns on the sub-index to the TSE 300 as a whole. Ms. McShane stated that if she had relied solely on betas and the standard deviation, her estimated risk premium for high grade utilities would have been about 100 basis points lower than it was. The witness disputed suggestions that the achieved returns on the sub-index were anomalous since they indicated that lower risk utilities earned a higher return than higher risk industrials (Exhibit 10, page 50) and therefore should not be used (T. 628).
With regard to the other version of the test, Ms. McShane disagreed with the suggestion that her data (Exhibit 3, Schedule 17) indicated that the current market risk premium for high grade utilities was approximately 2.0 percent. Instead she noted that investor expectations with respect to bond yields were unmet during the latter part of the 1980's and first two years of the 1990's so that actual risk premiums were likely lower than investors' expected risk premiums.
Based on the two methods, and assuming a rate of return on long-term government bonds of 9.25 to 9.5 percent, Ms. McShane concluded that the appropriate rate of return for low risk, high grade utilities was 12.75 to 13.0 percent.
29 29 The results of the three tests were then adjusted to reflect the particular circumstances of PNG. In addition, since both the DCF and Risk Premium tests measure return on a market rather than a book basis, the initial results were grossed up to provide financing flexibility for the utility which is assumed to occur when the utility has a market to book ratio of 115 percent. For both the DCF and Risk Premium tests this required an add-on of approximately 120 to 130 basis points. Based on the three tests, the required ROE for the utility is as follows:
Comparable Earnings 14.4 percent DCF 14.2 percent Risk Premium 15.0 percent As a result, Ms. McShane recommended a rate of return on common equity for PNG of 14.5-14.75 percent for the 1992 test year.
4.3.2 Position of Staff Witness Dr. Waters estimated the Company's required ROE using only the Discounted Cash Flow and Risk Premium methods. He rejected the use of the Comparable Earnings method since he had concerns that:
(i) "the concept of comparable earnings does not necessarily have any relationship with the concept of a fair return"; and
(ii) "the measurement of comparable earnings (based on accounting data) provides results which are difficult to compare meaningfully across companies and across time" (Exhibit 10, page 57).
In undertaking the DCF test, Dr. Waters relied on three, partially overlapping samples of low risk Canadian industrials and used data over the period 1981 to 1991 to calculate the investor's required rate of return using dividend yields and growth rates. Based on these studies, the witness concluded that the required rate of return for low risk industrials would be no higher than 11 percent. Since elsewhere in his evidence, Dr. Waters had determined that PNG was of substantially similar risk to the low risk industrials (Exhibit 10, page 47), no adjustment was made to the initial estimate to reflect special circumstances relevant to PNG. However, Dr. Waters
30 30 did suggest that the estimate should be increased by 50 basis points as a margin of safety or allowance for flotation costs (Exhibit 10, page 4).
Dr. Waters also undertook to estimate the required risk premium for the Canadian equity market as a whole, his sample of low risk industrials and for low risk, high grade utilities. Using historical data from a variety of sources, he concluded that the gross risk premium required by equity investors was 450 to 570 basis points. However, this premium was adjusted downward by 100 basis points to reflect a purchasing power risk premium which the witness maintained was included in long-term Government of Canada bond yields.
Based on three measures of share price volatility and two measures of per share earnings volatility, Dr. Waters determined that his sample of low risk industrials had approximately two-thirds of the risk of the equity market as a whole while low risk, high grade utilities were only one-half as risky as the market. As a result, the witness estimated that the appropriate ROE for PNG would be 240 to 320 basis points above the long-term government bond rate of 9.375 or 11.8 to 12.6 percent. As with the DCF test, Dr. Waters added 50 basis points to his estimate to cover flotation costs.
Having regard to the results of both of these tests, Dr. Waters stated that a fair rate of return on equity for PNG would be in the order of 12.5 to 13.125 percent.
4.3.3 Position of Industrial Intervenors In final argument, Counsel for the Industrial Intervenors disagreed with the estimates of the yield on long-term government bonds put forward by both expert witnesses. Counsel suggested that for the estimated average long-term government bond yield of 9.375 percent to be reached, rates would have to rise significantly from current rates, which from the beginning of the year to the time of the hearing had fluctuated between 8.65 and 9.1 percent (T. 882), with the consensus forecast for 10-year government bonds forecasting a rate of 8.1 percent in three months and 8.2 percent in 12 months. The 30-year rate can be approximated by adding 60 basis points to their estimates.
31 31 5.0 MISCELLANEOUS 5.1 British Columbia Government's Budget Changes Subsequent to the completion of the hearing, the Province of British Columbia issued a new budget. The Company informed the Commission on March 31, 1992 that the budget changes would require an increase to PNG's 1992 revenue requirement of $453,000. The Company intends to make a separate Application to the Commission for the recovery of these costs and accordingly no provision is made in this Decision for these costs.
32 32 6.0 COMMISSION DECISION 6.1 Capital Structure In 1991, approximately 17 percent of PNG's capital structure was financed through short-term debt. This reliance on short-term debt had the potential to expose the Company to significant levels of risk from which its shareholders are normally exempt. After consideration of the evidence presented in the 1991 Revenue Requirements Hearing, the Commission ordered PNG to establish a short-term interest rate deferral account into which deviations from forecasted short-term interest rate costs would be accrued. This then insulates the Company from fluctuations in short-term interest rates.
In late 1991, PNG issued $15 million of long-term debt which reduced substantially the Company's reliance on short-term debt albeit at a higher cost. Nonetheless, the Commission believes there remain significant advantages to insulating the Company from this source of risk. Therefore, the Commission orders PNG to retain a short-term interest rate deferral account into which deviations from forecasted short-term interest rate costs will be accrued. For the purpose of this account, the short-term rate to be used is 7.6 percent.
6.2 Rate of Return on Equity In setting the appropriate rate of return on common equity to be allowed PNG, the Commission has kept in mind two of the primary requirements which it is obligated to meet in determining the cost of capital. The first is that the allowed rate of return on equity should reflect the risk inherent in PNG's operations. The second is that the return on equity should be sufficient to allow the Company to obtain necessary capital additions at reasonable cost.
Based on the evidence presented directly and through the course of the hearing, the Commission concurs with both Ms. McShane and Dr. Waters that the business risks associated with PNG are greater than those associated with average high grade utilities. Further, the Commission agrees with Ms. McShane that the primary business risk is that associated with the high concentration of sales to a small number of industrial customers and in particular to Ocelot (T. 637). Nonetheless, the Commission believes that the impact of these risks is subject to a number of significant mitigating offsets including minimum take provisions associated with firm contract demand by large industrial customers, government guarantees associated with firm sales and transportation
33 33 volumes to Ocelot, business interruption insurance and a significant market margin available in its other classes of service primarily residential and commercial. In addition, the form of regulation of the Company assists PNG to insulate itself against risk through the use of deferral accounts and pass-throughs for unanticipated and uncontrollable changes in cost.
However, the Commission is not convinced that the burden of the higher risk associated with PNG is borne primarily by the Company's shareholders. Based on Exhibit 23, it appears to the Commission that there is substantial room for a loss of margin from one customer, even of the size of Ocelot, to be made up through increased rates to other customers. To the extent that the risk imposed by the highly concentrated industrial sales may be borne by the residential and commercial customers rather than the shareholders, this reduces the risk to PNG considerably.
With respect to the Company's ability to attract capital, the fact that short-term debt is currently less costly than long-term debt, suggests that customers are benefiting from holding a portion of the capital structure in short-term debt instruments rather than attempting to refinance with long-term debt. However, given the volatile and frequently unpredictable nature of interest rate changes, the Commission wishes to insure that it sets a rate of return on equity that will be sufficient to allow the Company to issue long-term debt should that course of action become desirable. Thus, in determining the appropriate rate of return on common equity, the Commission has, amongst other factors, assessed the impact on the times interest coverage ratio.
Based on this evidence as discussed in the preceding sections, the Commission finds that the appropriate rate of return on equity for PNG in this proceeding is approximately 13.25 percent, within a range of 12.75 to 13.5 percent. 6.3 Summary of Adjustments Having considered all of the issues discussed and the adjustments as set out in the Decision Schedules, the Commission considers that the 2.86 percent interim increase on total revenue approved by Commission Order No. G-7-92 effective January 1, 1992 requires a downward adjustment. Based on a return on common equity of 13.25 percent, the Commission finds that PNG requires an annual revenue requirement of approximately $48 million. A net annual revenue increase of approximately $450,000 or 0.95 percent is required. PNG is to refund, to its customers, the excess between the interim rate and that approved inclusive of interest. PNG is to incorporate the above revenue requirements in the new rate schedules on a timely basis for the
34 34 effective date of January 1, 1992. A reconciliation of the implementation of the new rate schedules should also be provided.
Consistent with the direction contained in the 1991 Revenue Requirements Decision, PNG is directed to file, in the absence of a rate application, annual forecasts to the Commission, in the manner described on page 28 of that Decision.
1 35 DATED at the City of Vancouver, in the Province of British Columbia, this day of April,(handwritten) 1992.
____________________________________ J.D.V. Newlands, Deputy Chairman ____________________________________ N. Martin, Commissioner ____________________________________ H.J. Page, Commissioner BEFORE: J.D.V. Newlands, Deputy Chairman N. Martin, Commissioner H.J. Page, Commissioner
2
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 Pacific Northern Gas Ltd.
DECISION April 3, 1992
BEFORE: J.D.V. Newlands, Deputy Chairman N. Martin, Commissioner H.J. Page, Commissioner
TABLE OF CONTENTS APPEARANCES LIST OF EXHIBITS 1.0 INTRODUCTION 2.0 APPLICATION 3.0 ISSUES 3.1 Rate Base 3.1.1 Plant Additions 3.1.2 Overhead Allocation 3.1.3 Deferred Charges - Extraordinary Repairs 3.1.4 Propane/Air Plant 3.1.5 Mid-Year Net Plant in Service 3.1.6 Hearing Costs 3.2 Sales & Revenue 3.2.1 Residential, Commercial and Small Industrial 3.2.2 Large Industrial 3.2.3 Large Industrial Interruptible Gas Deferral Account 3.2.4 Other 3.3 Gas Purchases 3.3.1 Gas Supply 3.3.2 Unaccounted for Gas 3.4 Operating Cost 3.4.1 Inflation 3.4.2 Maintenance Costs 3.4.3 Donations 3.4.4 Wages and Salaries 3.5. Other Issues 3.5.1 Reassessment on Compressor Equipment and Customer Contributions 4.0 RATE OF RETURN ON COMMON EQUITY 4.1 Introduction 4.2 Riskiness of PNG - Company Position 4.2.1 Position of Staff Witness 4.2.2 Position of Industrial Intervenors 4.3 Return on Equity ("ROE") 4.3.1 Position of Applicant 4.3.2 Position of Staff Witness 4.3.3 Position of Industrial Intervenors 5.0 MISCELLANEOUS 5.1 British Columbia Government's Budget Changes
Page No. (i) (ii) 1 4 6 6 6 8 9 10 11 11 12 12 13 14 16 16 16 17 18 18 19 19 19 20 20 22 22 22 25 26 26 26 29 30 31 31
TABLE OF CONTENTS (Cont'd) Page No. 6.0 COMMISSION DECISION 32 6.1 Capital Structure 32 6.2 Rate of Return on Equity 32 6.3 Summary of Adjustments 33 Commission Order No. G-32-92 APPENDIX 1 SCHEDULES 1 to 5
APPEARANCES D.L. RICE J. LUTES D. BURSEY J. TYSON MAYOR P.J. LESTER WILLIAM SMITH __________________________________________________________________________ COMMISSION STAFF S.S. Wong P.W. Nakoneshny D.W. Emes ALLWEST COURT REPORTERS LTD. (i)
Commission Counsel Counsel for Pacific Northern Gas Ltd. Counsel for Ocelot Industries Ltd. Eurocan Pulp and Paper Co. Alcan Smelters and Chemicals Ltd. Skeena Cellulose Inc. Ocelot Industries Ltd. City of Prince Rupert Manager, Rates and Finance - Petroleum Senior Financial Analyst - Petroleum Senior Planner Court Reporters & Hearing Officer
LIST OF EXHIBITS Pacific Northern Gas Ltd. Application, Volume 1 Adjustment to Exhibit 1 Direct Testimony of Company Witnesses, Volume 2 Direct Testimony of Rate of Return Witness, Volume 3 Response to BCUC Staff Information Request No. 1, Volume 4 Response to BCUC Staff Information Request No. 2, Volume 5 Response to the Large Industrial Customers' Information Request No. 1, Volume 6 Pacific Northern Gas Ltd. Table of Miscellaneous Adjustments to the 1992 Test Year Pacific Northern Gas Ltd. Executive Summary BCUC Hearing Order No. G-7-92 dated January 8, 1992 Direct Evidence of Dr. Waters dated February 7, 1992 Two-Page "Interim Earnings" for Ms. K.C. McShane's Sample as of February 25, 1992 Growth Rate of Individual Companies Report of The Clifford Group Ltd. dated February 19, 1992 Pacific Northern Gas Ltd. System Map Excerpt - Application for 1992 Tolls Panel 2, Cost of Service, J.H. Podmore Return on Common Equity 1982-1991 Letter dated February 12, 1992 to Commission re: Compensation of Management Response of Dr. Waters to Information Request of Pacific Northern Gas Ltd. Letter dated December 12, 1991 from Commission to Pacific Northern Gas Ltd. and Attachments Graph and Table Prepared by Commission Staff
Exhibit No. 1 1A 2 3 4 5 6 7 8 9 10 10A 10B 11 12 13 14 15 16 17 18
3 Extract - Page 5 from 1991 Pacific Northern Gas Ltd. Revenue Requirement Hearing Decision Letter of September 6, 1991 from Pacific Northern Gas Ltd. to Commission with Order No. G-11-92 Schedule re: Labour Costs Between O&M and Capital Schedules - Operation and Maintenance Schedule 2B and Operating and Maintenance Expense Impact of Loss In Margin from Gas Deliveries to Ocelot Letter dated February 14, 1992 Article by Bruce Cheadle from February 18, 1992 Report on Business in the Globe and Mail Excerpts from Consensus ECON Schedule re: Flow-Through Tax Accounting Schedule re: Labour Rate Increases Schedule re: Manpower Letter of February 20, 1992 Schedules - Utility Rate Base, Utility Income and Return, Income Taxes, Common Equity, Return on Capital, Continuity of Deferred Charges for the Year 1992, Continuity of Deferred Charges for the Year 1991 (3)
19 20 21 22 23 24 25 26 28 29 30 31 revised 32