1.0 INTRODUCTION Pacific Northern Gas Ltd. ("PNG", "the Company", "the Applicant", "the Utility") is a British Columbia natural gas utility which is controlled by Westcoast Energy Inc. ("Westcoast", "WEI"). The Company has a two-tier common equity structure: the non-voting Class!A shares are publicly traded and the Class!B voting shares are 100% owned by Westcoast. The Company's Class!A Preferred Shares also trade publicly.
The PNG system, operating in three divisions, serves approximately 30,000 customers in northern British Columbia. The PNG-West Division serves communities west of Prince George extending as far as the Pacific Coast deep water ports of Kitimat and Prince Rupert. This division is primarily an industrial gas transmission system serving large industrial customers of which Methanex Corporation ("Methanex") is the dominant customer. PNG's wholly owned subsidiary, Pacific Northern Gas (N.E.) Ltd. ("PNG[N.E.]"), operates the other two divisions, namely, the Dawson Creek Division and the Tumbler Ridge Division. The Peace River Transmission Co. transports gas from the WEI interconnect to the PNG distribution system at Dawson Creek which serves approximately 5,000 customers. There are no large industrial accounts in the Dawson Creek service area. In the Tumbler Ridge area, local gas wells provide raw gas which is processed, transported, and distributed by PNG to 1,300 customers in the District of Tumbler Ridge. There are two large industrial customers, Quintette Coal Ltd. ("Quintette") and Sceptre Resources Ltd. ("Sceptre"). The service areas for each of the divisions is shown on the map opposite.
1.1 Background The 1994 and 1995 revenue requirements for all three PNG divisions were approved by the Commission based on negotiated settlements through an Alternate Dispute Resolution ("ADR") process involving PNG, its major industrial customers and the Commission staff. The last PNG revenue requirements hearing , encompassing the 1992 test year was for the former PNG system now known as the PNG-West Division; it was held in Prince Rupert in February, 1992. In the 1992 Decision the Commission approved, among other matters, a rate of return on common equity of 13.25% on a common equity component of approximately 33%. After a generic public hearing in 1994 involving BC!Gas!Utility!Ltd., PNG and West!Kootenay!Power!Ltd., the Commission adopted an adjustment mechanism to determine the appropriate annual rate of return on common equity for each utility.
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2 On November!29, 1995, PNG and PNG(N.E.) made application to amend their rate schedules in the three divisions effective January!1, 1996 ("the Application", Exhibit!1). The utilities sought approval on an interim basis under Section!106 of the Utilities Commission Act ("the Act") and on a permanent basis under Section!64 of the Act. By Order No.!G-117-95 (Exhibit!2), the Commission approved for PNG and PNG(N.E.) the proposed interim rate changes effective January!1, 1996 subject to refund with interest. The Commission scheduled a public hearing into the Application to commence on April!1, 1996 at a location to be determined after discussions with the Utility and intervenors. The Application is discussed in more detail in Chapter!2.0 of this Decision.
Based on input of participants in a pre-hearing conference held on January!31, 1996, the Commission issued Order No.!G-12-96 (Exhibit!2) on February!1, 1996 which designated the PNG(N.E.) portion of the Application for review by the ADR process and rescheduled the public hearing into the PNG-West Division to commence on April!9, 1996 in Vancouver. As a result of subsequent revisions to the Application (Exhibits!1A and!1B) by the Applicants, involving similar requests and changes for all three divisions, the Commission by Order No.!G-24-96 (Exhibit!2) dated March!8, 1996 canceled the PNG(N.E.) ADR and ordered a review of issues for all three divisions to occur in the April!9, 1996 public hearing.
Prior to the public hearing, the Applicants filed numerous supplemental applications for Commission approval (Exhibits!5 to!15). Since these applications had potential impact on the revenue requirements, the Commission directed that they also be dealt with in the public hearing.
The public hearing commenced on April 9, 1996 at the Commission's hearing room in Vancouver, B.C. and concluded with oral argument by counsel for the Applicant and Methanex on April!12, 1996.
1.2 Preliminary Matters On March 4, 1996, PNG applied for approval of a pilot program to test a Heating Insurance Plan ("HIP") in Terrace and Dawson Creek (Exhibit!12). This application was referred to the hearing. At the beginning of the hearing, counsel for the heating contractors in the PNG service areas submitted that there was insufficient time for his clients to study the plan and obtain additional information from PNG. Counsel therefore applied for a postponement of the portion of the hearing which was scheduled to deal with the HIP
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3 (T:!9). The Commission accepted the request and issued Order No.!G-33-96 which scheduled a hearing for June!3,!1996 to review the HIP. Subsequently, on May!8, 1996, PNG withdrew its HIP application and advised that it will file a new application following a generic review of non-regulated business activities by the Commission, expected to occur later in 1996.
2.0 THE APPLICATION The Application is a three-part document consisting of independent applications for the three PNG divisions, namely: PNG-West Division, PNG(N.E.)-Dawson Creek Division and Tumbler Ridge Division. The Application reflects rate impacts resulting from changes in the revenue requirement, changes in the cost of gas and from implementation of the December!15, 1995 Rate Design Decision. The total 1996 revenue requirement deficiency for PNG-West was forecast to be $3.96!million or approximately 7.7% and for Dawson Creek the projected deficiency was $157,000 or 3.2%. For Tumbler Ridge a revenue surplus of $41,000 or 2.3% was projected.
2.1 Supplementary Applications As well as the revenue requirement application filed on November 29, 1995, PNG filed a number of supplementary applications requesting Commission approval for various matters. The following summary lists these supplementary applications by filing date and hearing exhibit number and gives a brief description of each:
1. October 31, 1995 (Exhibit!6); various deferral accounts to: • recover losses resulting from the Skeena Cellulose Inc. ("Skeena") strike in 1995; • correct an error by the Company in the 1995 rate case resulting from a missed 27th pay period;
• recover increases in the Federal Capital tax; and • recover reassessments due to provincial sales tax audits. 3
4 2. November!2, 1995 (Exhibit!5); a revision to the depreciation rates for PNG-West from the current composite depreciation rate of 2.47% to one of 2.91%.
3. December 20, 1995 (Exhibit!14); an adjustment to the rates which were determined in the 1995 Rate Design Decision for two Tumbler Ridge industrial customers, Sceptre Resources and Quintette Mines.
4. December 20, 1995 (Exhibit!8); a revision to the existing NGV Conversion Loan program to increase the conversion loan from $1,600 to $3,500 per vehicle.
5. December 21, 1995 (Exhibit!15); introduction of bi-monthly billing for Dawson Creek and Tumbler Ridge.
6. January!30, 1996 (Exhibit!9); a deferral account to reverse a CCA calculation error of $521,000 which the Company made in its 1995 Revenue Requirement forecast.
7. February 19, 1996 (Exhibit!11); a proposal for a 1996 Off-System Sales Incentive Program. 8. February 21, 1996 for PNG-West (Exhibit!10) and March 5, 1996 for PNG(N.E.) (Exhibit!10A); applications to pass-through 1995 Income Tax due to disallowance by Revenue Canada of the deduction for Overheads capitalized.
9. March 4, 1996 (Exhibit!12); a request to institute a pilot program for a Heating Insurance Plan. 10. April 2, 1996 (Exhibit!13); a request to dispose of a 1995 Gas Supply Cost Deferral Account. 2.2 Forecasts and Updates Prior to, and during the hearing, the Utility filed the following updates to its Revenue Requirements Application:
• PNG-West dated February 13, 1996 (Exhibit!1A); • PNG(N.E.)-Dawson Creek and Tumbler dated February 29, 1996 (Exhibit!1B); • PNG-West dated April 2, 1996 (Exhibit!1C); and • PNG-West dated April 9, 1996 for miscellaneous information (Exhibit!1E). 4
5 PNG-West revised its revenue deficiency to $4.8!million or 9.6% of gross revenue (Exhibit!1A) and later lowered the deficiency to $4.4!million (Exhibit!1C). The revenue changes for Dawson Creek and Tumbler Ridge remain relatively the same due to offsetting factors in the updates (Exhibit!1B).
3.0 RATE BASE FOR PNG-WEST 3.1 Plant Additions The Utility has forecast plant additions of approximately $11.5!million in 1996 which compare with approved additions of $14.8 million and actual additions of $13.9!million in 1995 (Exhibit!1E). The plant additions forecast for 1996 appear to be reasonable and few concerns were raised in the hearing, except for concerns about the government-funded Infrastructure Works Program and the Utility's Customer Information System. These are discussed in turn below.
3.1.1 Mains Extensions - Infrastructure Works Program PNG has forecast mains additions costing $3.56 million due to expected contributions of $2.7!million from the Federal and Provincial sponsored Infrastructure Works Program, a program which provides government funding to subsidize a utility's costs so that service may be extended to otherwise uneconomic areas (Exhibit!4, Tab!3, p.!23). These additions will connect 560!new residential accounts. The filings of the Utility demonstrate that the program, under the current Mains Extension Test, has a negligible impact on the revenue requirement in 1996. However, if the proposed mains extensions were tested under the criteria of the February, 1996 generic Decision of the Commission on Utility System Extension Tests, they might require additional contributions which would not be available through the Infrastructure Works Program (T:!216). PNG requested that work under this program be grandfathered and that the new tests not be applied. Methanex on the other hand argued that the infrastructure program should be denied until PNG could justify the project under the criteria set out in the new directives of the Generic Mains Extension Decision (T:!618).
The Commission notes that the Utility has pursued this project and submitted applications for funding before the Mains Extension Decision was issued. The Utility should not be expected to stand still or to apply for funding subject to uncertainty of future possibly more
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6 stringent tests. Therefore, finding that it is reasonable, the Commission approves the use of the existing tests to determine project viability prior to the filing and acceptance by the Commission of a revised Mains Extension Test for PNG.
3.1.2 Customer Information System ("CIS") PNG plans to replace the existing Wang computer system in 1996 and 1997 with a new client/server CIS package (Exhibit!1, Tab!1, p.!16) which would cost $206,400 for the hardware and $308,600 for the software. In response to information requests, the Utility amended the forecast by removing all of the above costs for 1996 except for $72,000 required for ongoing system planning (T:!463) and stated that implementation of the new system is now expected to occur in 1998 (Exhibit!4, Tab!1, p.!33). Methanex was concerned about paying for a CIS system intended for the benefit of residential and commercial customers which, as PNG agreed, would not benefit large industrial customers (T:!435).
The project received close scrutiny during the hearing in view of the risk factors, uncertainty and significant costs involved. Current information shows that PNG will be a user of a new WEI system which is designed to cater to the six WEI local distribution utilities. (Westcoast owns the Centra Gas group of companies which operates natural gas utilities in B.C. serving Vancouver Island and the Sunshine Coast via its own undersea natural gas pipeline, as well as Fort St.!John. Port Alice and the resort village of Whistler are operated as propane gas systems by Centra.) WEI has selected a package developed by SCT Utility Systems, Inc. ("SCT") which has a forecast five year system average annual cost of $8.48 per customer (Exhibit!4, Tab!6, Item!9.0, pp.!9 and!11 of Drill Down Report).
The current CIS cost/customer in PNG is approximately $4.25 (T:!466) and PNG has obtained an independent cost quotation of $17 per customer as the high-end benchmark for a new system designed to meet PNG's needs based on a preliminary quotation from OrCom Systems Inc. (Exhibit!4, Tab!3, p.!24). It was also revealed that the CIS investment was to proceed under the assumption that it would be owned by a non-regulated company which would sell CIS services to the six WEI subsidiary utilities at a market based price-to-quality ratio. PNG's system requirements are only a small fraction of some of the larger affiliated utilities; the system is designed to handle 3!million customers while PNG has only about 30,000 customers (T:!434). PNG stated that it has not made any purchase commitment to the proposed system at this time (T:!430), although it continues to participate with WEI in the development of the SCT solution (T:!431).
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7 The Commission is extremely concerned about the risk factors and the apparently involuntary involvement of PNG in a large system which may significantly increase the risk of successful implementation for a small utility with more limited requirements. The Commission directs PNG, as proposed by counsel for the Applicant (T:!582), that prior to PNG's commitment to implementation of any CIS project, PNG must apply for Commission approval and justify the need for the system and the appropriateness of the related costs. All aspects of the CIS project, including other options and financial risks to customers will be reviewed for prudency.
3.2 Depreciation PNG engaged the consulting firm of Stone & Webster to conduct a Depreciation Study (Exhibit!5). The study, completed in 1995, concluded that the current composite depreciation rate of 2.47% should be increased to 2.91% based on a detailed review of individual rates. PNG proposed that the new rates be retroactively implemented effective January 1, 1995 and that the impact be offset by drawing down the deferred income tax account which has a current balance of $14.9 million. Counsel for Methanex argued that the pipeline rehabilitation program should have substantially increased the remaining life of the plant in service but the Applicant responded that the impact of rehabilitation had already been taken into account in the study.
The Company proposed to draw down the deferred income tax account to mitigate certain of the extraordinary items such as depreciation rates. Under questioning, Methanex agreed to this proposal since it would lower current rates(T:!628). However, the Commission notes that the Utility has reached the cross-over point with respect to depreciation and capital cost allowance provisions if the proposed depreciation rates are approved (T:!457). The Commission believes that under these circumstances and in the interests of a gradual change to rates to avoid any rate shock effects, a phase-in of these new rates would be appropriate.
Therefore, the Commission accepts the study result that the composite depreciation rate should be 2.91%, but rejects the proposed offset. The new depreciation rates are to be implemented by phasing in 50% of the $860,000 increase (Exhibit 4, Tab 1, p.!35) in the cost of service in 1996 and 100% of the amount in subsequent years. The proposal to have an effective date of 1995 is rejected on the basis of retroactivity. The Commission also approves the recovery of the costs of approximately $40,000 relating to the Depreciation Study which are to be amortized in full in 1996.
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8 3.3 Gas Utility Uniform System of Accounts The Gas Utility Uniform System of Accounts is prescribed by the Commission for all gas utilities under its jurisdiction. It classifies their costs under the specified accounts so that the Commission and others can compare like costs between utilities under the same account numbers or categories of revenues and costs. PNG has adopted Account!487, which is prescribed for Equipment on Customers' Premises, for Computer Equipment (T:!471). Although the Uniform System of Accounts may require updates, utilities should not unilaterally change the descriptions of these accounts to suit certain purposes without first consulting with the Commission. Computer equipment for example is more properly classified as Office Equipment under Account 483.
PNG is directed to review all costs and their account allocations to ensure that they are properly classified under the Uniform System of Accounts.
3.4 Overhead Capitalized In view of the recent Revenue Canada position on the treatment of capitalized overhead for tax purposes and in view of the BC!Gas Utility Ltd. request to expense more costs which were previously charged as overhead, counsel for Methanex suggested that PNG should do a construction overhead study in 1997 to determine if the overhead capitalization policy is still appropriate (T:!616). PNG stated that the Company has no plan to change its overhead capitalization policy (T:!424). The Commission is not persuaded that there is sufficient need for an overhead capitalization study at this time since the Utility continues to follow approved past practice on a consistent basis.
3.5 Cash Working Capital In its update to its revenue requirements filing (Exhibit!1C), PNG proposed to increase the cash working capital by $472,000 over the original Application due to changes in the lead/lag days of certain revenue and expenses. Counsel for Methanex argued that a proof should be provided to support such changes (T:!613). In the absence of such a proof, the Commission is only prepared to allow 50% of the increase for 1996. PNG in its next rate application should provide adequate support in the form of a lead/lag study including the impact of provincial sales tax on cash working capital.
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9 3.6 Request for 1995 Deferral Accounts and Other Recoveries PNG applied for Commission approval to recover six categories of 1995 costs as described below in sections!3.6.1 to 3.6.6. For the costs described in section 3.6.1 to 3.6.4 and 3.6.6, namely: loss of margin due to the Skeena strike; additional pay period in 1995; federal large corporations capital tax; provincial sales tax audit; and income tax pass-through on non-deductible overheads; PNG requested amortization through various deferral accounts (Exhibits!6 and!10). In addition, the Utility also applied for recovery of costs as described in section!3.6.5 resulting from a CCA calculation error (Exhibit!9).
In 1995, the Utility did not achieve the forecast revenue targets due to a strike in the Skeena pulp mill and lower than normal delivery to most other customers. The Utility's results in 1995, if adjusted to include recovery of all costs described in section!3.6, would show a return on common equity of 11.192% and a normalized return of 11.918% (Exhibit!1E). If these requested costs were absorbed in 1995 and not recovered, the Utility would have earned a 1995 return on common equity of 8.14% (Exhibit!20A) or a normalized return of approximately 8.87% (T:!509). Each of these deferral account requests is discussed below.
3.6.1 Loss of Margin due to Skeena Strike Since 1985, PNG has experienced three industrial stoppages due to labour disputes: 36!days at Skeena in 1992 for a 353.7!TJ loss; 42!days at Eurocan in 1992 for a 218.2!TJ loss; and, the 1995 Skeena strike which lasted 109!days and resulted in a 819.9!TJ loss of gas delivery (Exhibit!4, Tab!1, p.!50). Despite the two strikes in 1992, PNG managed to earn an actual return on common equity of 12.66% and a normalized return of 13.84%, as compared to the allowed return of 13.25% (Exhibit!4, Tab!1, p.!5). PNG did not apply to the Commission for any relief. The 1995 strike, when combined with other unfavourable events during the year, had a more severe impact.
The net margin loss of $579,883 is calculated on the basis of the 1995 loss of gas delivery above the minimum 80% of contract demand billed (Exhibit!4, Tab!1, p.!52). PNG's reasons for recovery (Exhibit!6) are that it:
• forecasts its gas requirements assuming normal deliveries and without making a downward adjustment to estimate prospective strike activity;
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10 • will not be earning its allowed return on common equity in 1995 due primarily to the Skeena work stoppage; and
• has on previous occasions voluntarily written off deferral accounts when it had earnings in excess of its allowed return.
The Commission recognizes that the Utility has not traditionally made provision for any losses due to strikes in its sales forecast (T:!49) and that the length of the Skeena strike would not reasonably have been anticipated in late 1994. However, it would appear reasonable for the Utility in its forecasting procedure to inquire about the status of labour contracts at major industrial customers' plants and the possibility of strikes as much as other events effecting consumption, such as planned maintenance shutdowns, and to make appropriate forecast sales adjustments. Although PNG in the past has written off deferred accounts as a result of its own or the Commission staff's initiatives, the Utility must carry some burden of responsibility for its own forecast. The Commission recognizes the unprecedented length of the 1995 Skeena strike, but finds that PNG should absorb some of the strike loss in this instance, as a result of its failure to ascertain, and make some provision for, the probability of labour disruption and plant shutdown at one of its major industrial customers.
The Commission considers that provision for lost sales in the order of 20% of the actual loss might have been reasonable. It therefore directs that PNG absorb this share of the lost revenue. The remaining after-tax deferral of $258,000 shall be recovered during 1996 as set out in section!3.6.7. If PNG wishes to insulate itself from future strike losses, it can come forward with a strike adjustment mechanism proposal on a prospective basis which may be similar to that of the BC!Gas Inland Division.
3.6.2 Additional Pay Period PNG's normal practice is to pay its employees' annual salaries over 26 bi-weekly pay periods which cover 364!days. It does not accrue for the extra day each year. As a result every eleventh year, as in 1995, a 27th pay period occurs. PNG submitted that this extra pay period was not included in its 1995 forecast. The impact on a net of tax basis for PNG-West is approximately $79,000 (Exhibit!20A), for Dawson Creek it is $16,237 (Exhibit!1B, Tab!1, p.!7[a]), and for Tumbler Ridge it is $7,693 (Exhibit!1B, Tab!1, p.!4[a]).
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11 The Commission has difficulty understanding why the Utility does not follow conventional accounting practice and make the proper accruals. It is also difficult to understand why the Utility's forecast is not based on the annual salaries payable to the employees, but is rather based on what is to be paid during the period. It should be noted that only one eleventh of the requested amount is related to 1995, and the remaining balance is applicable to prior years. In fact, as PNG(N.E.) was acquired from Northwestern Utilities Limited in 1993, it is not certain whether personnel in PNG(N.E.) are aware of the prior owners' accounting practice and are making a valid claim. In view of the circumstances applicable to this request and in view of the insignificant amounts accruable to 1995, the Commission does not approve the requested recovery. Furthermore, the Utility is directed to review its accounting policies and budgeting practices and ensure future adherence to sound accrual principles.
3.6.3 Federal Large Corporations Capital Tax The above tax was increased by 0.025%, or $33,000, in early 1995 but PNG did not request recovery of this pass-through item until October 31, 1995. While the Commission approves the recovery on the grounds that this amount is normally allowable for pass-through under Section 67(4) of the Act, it is concerned about the time lag in the Utility's request for recovery and expects more timely applications in future.
3.6.4 Provincial Sales Tax Audit The Utility's application states that the audit was for tax assessed on purchases (Exhibit!6, p.!3). However, evidence at the hearing disclosed that PNG also included recovery of tax not applied on sales (Exhibit!4, Tab!3, p.!37). The Company applied for similar recovery for Dawson Creek and Tumbler Ridge in February, 1996 (Exhibit!1B).
The total cost requested for recovery is approximately $22,000 on a before tax basis covering a period between October 1989 and May 1995 (Exhibit!4, Tab!6, p.!32). In addition, there is already a tax assessment of over $35,000 directly charged to fixed assets, so that the total amount of tax assessments in the Application is $57,000 for PNG-West, including penalties and interest. There are three categories of tax assessments involved here: the amount pertaining to asset purchases; the amount for O&M purchases covering the period prior to 1995; and, the amount covering only the five months of 1995. Moreover, certain of these costs are penalties and interest charges. In the Commission's view, the responsibility rests with the Utility to interpret and apply the sales tax correctly; particularly in the case of the
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12 amount applied on sales which is not treated as part of the cost of service, but is collected by the Utility and paid directly to the Province (T:!475-478). The Commission will not approve recovery of these assessments in the customer rates. Again, concerning PNG(N.E.), as in the case of the extra pay period discussed earlier, it appears that over half of the tax reassessment was related to purchases by the Utility's prior owner, Northwestern Utilities Limited. PNG may wish to pursue recovery with the prior owner.
With respect to the Utility's practice of directly charging the reassessed PST to prior year purchases in the plant assets, the Commission accepts that such corrections should be made to reflect the proper taxes paid in relation to those plant assets which continue to provide useful service.
3.6.5 CCA Calculation Error The application filed on January 30, 1996 (Exhibit!9) requests recovery of costs pertaining to a spreadsheet calculation error related to the amount of Capital Cost Allowance included in PNG's 1995 rate application. The Utility proposes to offset the after-tax effect of the error, in the amount of $232,000, by drawing down the deferred income tax balance.
The Commission disagrees with the Utility's submission that if the error is not corrected, the provisions for depreciation and CCA as reflected in the deferred income tax would be out of balance. The CCA provision in the test year is only a forecast which should be corrected to reflect the actual calculations like other costs in rate base (T:!481).
However, the Commission is aware that if this error had occurred under the previous deferred income tax accounting method used by PNG, there would have been no impact on the revenue requirement (T:!579). The Commission notes that customers have received some benefit from the voluntary switch by PNG to flow-through income tax accounting.
While the Commission expects utilities to make every effort to ensure that errors do not occur, in the circumstances of this particular case, the Commission will allow the recovery of this cost by way of a rider as discussed in section!3.6.7.
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13 3.6.6 Income Tax Pass-through on Overhead Capitalized PNG applied, under Section!67(4) of the Act, to pass-through the net after tax cost of $862,000 relating to the overhead capitalized in 1995 which had been considered as deductible for income tax purposes (Exhibit!10). A subsequent settlement with Revenue Canada reversed PNG's ability to claim this deduction starting in the 1995 taxation year (Exhibit!4, Tab!1, p.!83). This item alone accounts for $1.55 million of PNG's 1996 revenue deficiency.
The Commission approves the requested recovery but it will be passed-through as discussed further in section!3.6.7.
3.6.7 Method of Recovery In allowing the recovery of some of the above costs, the Commission also notes that in 1995, PNG did not incur certain O&M costs which had been provided for in the 1995 customer rates. In response to questions by counsel for Methanex with respect to the reduction of right-of-way clearing costs, PNG agreed that: "Ultimately the clearing would have to be done." (T:!126) and explained the reason certain maintenance activities were not done was: "...that we were not generating the revenues to enable us to do some of this maintenance work." (T:!127).
Since the Utility has been allowed to re-generate much of the lost revenue in 1995 by virtue of the Commission's approvals as discussed above, it is unreasonable for the Utility to keep the unexpended maintenance costs which will be charged to customers in future. In order to neutralize this inequality, the Commission believes that PNG must return a portion of those unexpended costs which relate to lower than budgeted operating and maintenance activities. Accordingly, the full amount of the savings related to the right-of-way clearing and half of the savings related to other maintenance items (Exhibit!4, Tab!1, p.!6[a]) should be offset with the allowed recoveries. The following table summarizes the calculation of the offsetting amounts (in thousands of dollars):
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14 Normalized Item To be Refunded Right-of-way clearing not carried out 219 219 General operations lower than normal 200 100 Lower than expected maintenance due to washout 87 43 Lower than expected compressor maintenance costs 100 50 Total $412 Total after tax (Total x .555) $229
Of the $1,540,000 requested for recovery (Exhibit!20A), the Commission approves $1,385,000 less the above $229,000. The net amount of $1,156,000 plus the deficiency carried forward with respect to industrial customers take-or-pay contract provisions in the amount of $264,000 (see section!5.1) for a total value of $1,420,000 (approximately $2,559,000 on a gross-up basis), should be recovered as a rider in 1996 similar to that of the Purchased Gas Deferral Account (section!7.1) but allocated on the margin of each rate class. Interest accruals should be made to these accounts each month on the remaining balances.
With the above adjustments and with the exclusion of costs pertaining to years prior to 1995, PNG should have earned in 1995 an actual return on common equity of 10.60% and a normalized return of approximately 11.33%. These results are shown in tabular form in Appendix!A.
3.7 Pipeline Cost Deferral Account Pre-approval of a deferral account is requested to enable PNG to recover its costs, including loss of earnings and insurance deductibles should pipeline damage occur in 1996. The request is due to a postponement of two pipeline replacement projects with a total cost of $3!million originally scheduled for 1996 (Exhibit!1, Evidence, p.!6). The one year delay is intended to reduce the impact on the revenue deficiency for PNG-West in 1996. The potential costs are $250,000 of insurance deductibles for each occurrence plus any unspecified earning loss (T:!322). PNG stated:
"The likelihood of this occurring, again, is very remote, or we would not have deferred it to 1997 ... in the past ... when we did have this type of occurrence we were always able to bring it before the Commission, and I think in all cases received Commission approval to defer the cost." (T:!323).
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15 The Commission finds that pre-approval of a pipeline cost deferral account for the unlikely event of a failure is not necessary at this time. Should any such incident occur, PNG can apply to the Commission for relief.
3.8 Stress Corrosion Cracking Investigation In its original application dated November 29, 1995, the Utility proposed a 1996 deferred expenditure of $63,000 for a stress corrosion cracking ("SCC") investigation as a portion of the pipeline rehabilitation costs. Subsequently, this was amended to $200,000 for 1996. This amendment does not affect the 1996 revenue requirement as the Company proposes to defer to 1997 an offsetting amount intended for "small inch lateral rehabilitation in 1996". The Company stated at the hearing that the $200,000 was required to fund a $40,000 study to determine what areas, if any, of the Company's pipeline right-of-way are susceptible to SCC as well as providing funds for a SCC field investigation program (T:!402). However, the Company agreed that its plans for this investigation program were preliminary and could only be finalized after receipt of the study. The study had not been completed at the time of the hearing.
The Commission is aware that the National Energy Board is involved in a highly publicized investigation into SCC in connection with the facilities of TransCanada Pipeline Ltd. It is possible that this investigation could determine that the particular conditions necessary for SCC are not likely or even possible on the PNG system. However, considering that the preliminary study on SCC susceptibility has already been undertaken by PNG and at a relatively low cost, the Commission is prepared to approve these limited costs. Before incurring any further expenditures, it would be prudent to await the results of the NEB investigation.
The Commission approves the expenditure of $40,000 for an SCC study with this amount to be amortized in full in 1996. Any further expenditures for SCC will require an application to the Commission which must be able to demonstrate a clear need based on the results of the PNG study and the current NEB SCC investigation.
3.9 Other Deferral Charges and Amortization A significant amount of effort was made to verify the status of deferral accounts in the Application, primarily due to variances between forecast and actual additions and amortization, and some changes between interest bearing and rate base deferral accounts. 15
16 The Commission believes that the main purpose of the deferral accounts is to smooth out the effect of rate changes in a way which is neutral to customers and the Utility in that it does not create a cost or benefit to either party (T:!492). The Commission directs that in future, PNG should amortize the full amounts approved in the test year in order to preserve neutrality between the Utility and customers, unless the particular deferred account's actual balance is less than the forecast amortization amount. For example, if the actual balance is $50,000, but the approved amortization in the year is $100,000, PNG should amortize only $50,000.
3.10 NGV Conversion Loan PNG filed an application on December 20, 1995 to increase the Natural Gas for Vehicle conversion loan from $1,600 up to $3,500 (Exhibit!8), to reach the same level available to other gas equipment installations. The Commission approves this Application. However, it is noted that the related tariff sheet (Original Sheet!35) allows the loan for up to three years at a fixed interest rate of 1% above the prime bank rate at the time the agreement is executed. The Commission is concerned that this financing rate may be below the actual costs of the loan program and may be subsidized by other customers. PNG is therefore directed to review this potential discrepancy and provide the Commission with justification of the interest charge on all financing assistance provided to customers, in a report to be filed by June!30,!1996.
4.0 RATE BASE FOR PNG(N.E.) DIVISIONS In general, the rate base changes in the Dawson Creek and Tumbler Ridge Divisions are considered reasonable by the Commission except for the following:
• Retirement and working capital - the Utility did not quantify the retirement provisions or working capital calculations in support of the Application (Exhibit!4, Tab 5, pp.!2 and!15). The Commission directs that each division must, in future, provide sufficient supporting schedules for its rate applications.
• Request for 1995 deferral accounts - the requests with regard to the Sales Tax audit as well as the extra pay period, as discussed in sections!3.6.2 and!3.6.4, are denied.
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17 • Income tax on overhead capitalized - the income tax impact on the 1995 undeductible overhead costs for Dawson Creek is allowed and is to be recovered by means of a rider in 1996 consistent with the treatment of this item for PNG-West.
5.0 SALES VOLUME AND REVENUE – PNG-WEST 5.1 Deficiency Carried Forward Under their sales agreements with PNG, the industrial customers are obligated to pay for a minimum monthly volume of service equal to 80% of the monthly contract demand. The deficiency volume is the amount the minimum monthly volume exceeds the actual volume of firm transportation service provided by PNG in a month. The customer is entitled to transport deficiency volumes at no additional charge within the subsequent five contract years (Exhibit!4, Tab!4, pp.!1-3). In 1995, PNG had in excess of 1!PJ in deficiency volumes carried forward to 1996 worth $575,221 in revenue. After the deduction for variable costs of $98,812 which is considered as a prepayment in 1995, the value pertaining to the deficiency volume to be delivered in 1996 with no contribution to PNG's margin is $476,409 before tax (Exhibit!4, Tab!6, p.!33).
The Commission agrees that the minimum take-or-pay revenue was forecast in the 1995 test year and should be taken into income when it was received in the same year. However, the delivery of the deficiency volumes with no margins would distort the normal revenue requirement of the Utility in a test year. The Commission believes that the test year sales volumes should attach their normal margin and the value relating to the deficiency volumes should be recovered in a rider during 1996. This sum has been included in the calculations of section!3.6.7. This cost treatment will ensure that customer rates reflect the appropriate cost of service and proper price signal, as the rates would not have embedded within them, at the beginning of the following period, an expired cost. If a portion of this forecast deficiency volume is not delivered in 1996, future rate applications should treat this particular portion as normal volume with associated revenue margin requiring no new rider.
Having the minimum take-or-pay provision in the industrial sales contracts, the Utility is able to secure most of its forecast industrial revenues. Moreover, in the PNG system any deficiency volume carried forward is also covered by an additional revenue requirement
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18 in the following test year. The Commission will consider this risk-reducing benefit in the future determination of the appropriate return on common equity for PNG.
5.2 Sales Forecast 5.2.1 Residential Sales PNG forecast 112.4 GJ usage per customer in the test year (Exhibit!4, Tab!1, p.!39). However, more updated 1995 data have shown an increase in normalized use in 1995 (Exhibit!30) and this change should be recognized in the 1996 forecast. On the basis of the updated material the Commission considers a forecast use per customer of 113.0!GJ in 1996 to be more reasonable. An increase of 11!TJ or $35,000 in gross margin is added to the test year forecast for residential sales.
5.2.2 Other Sales The Commission accepts the 1996 PNG-West sales forecast for all other sales. 5.2.3 1996 Methanex Margin Deferral Account In its Application, PNG requests a deferral account to record the loss in gross margin net of variable costs that would result if Methanex takes less than 100% of its firm deliveries. PNG believes there is significant uncertainty concerning Methanex's planned operational levels during 1996, but stated that if demand/commodity rates were approved by the Commission, PNG would withdraw the application for the deferral account (Exhibit!1, Tab!Application, p.!7). At page!53 of the PNG 1995 Rate Design Decision the Commission stated:
"The Commission approves in principle the change to a demand/commodity rate structure and directs PNG to negotiate with its large industrial customers to determine the form of amendments to the service contracts which will implement the change. The Commission expects the proposed amendments to be completed and presented to the Commission for review not later than May!31, 1996."
PNG stated during cross-examination that its primary concern is the reliability of a boiler in the Methanex plant and potential for delay from an extended shutdown for its replacement (T:!151). The Utility agreed with counsel for Methanex that the establishment of the requested deferral account would remove virtually all the forecast risks associated
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19 with the Methanex volumes which account for two thirds of PNG's throughput (T:!153). Methanex gave evidence that there was already provision for down time in its consumption forecast and that in 1995 necessary repairs were performed to ensure that the boiler could operate until the planned October 1996 shutdown. Methanex also testified that it has more confidence in its 1996 forecast throughput delivery than it had in 1995 (T:!542 and 543).
After careful consideration of the above evidence, the Commission has determined that the requested deferral account is not required. In particular, the demand/commodity proposal, if forthcoming and approved by the Commission, may eliminate most of PNG's concerns even in the event of a Methanex boiler breakdown. The general issue of risk is discussed further under Return on Common Equity in section 10.4
6.0 SALES VOLUME AND REVENUE - PNG(N.E.) 6.1 Sales Forecast The Commission accepts the sales forecast for all customer classes in the two divisions with the exception of the forecast for the single large commercial customer in Dawson Creek. In 1995, this customer experienced operating problems and consumed 32,174!GJ (Exhibit!4, Tab!5, p.!16). PNG in its original application assumed the customer would resume the optimization of its wood fuel system and use only 11,500!GJ in 1996. The latest forecast, as provided in Exhibit!29, shows that the customer will likely consume 22,579!GJ in 1996. The Commission therefore makes a sales adjustment to reflect the updated forecast of 11,000!GJ or $9,000 in margin to the large commercial sales forecast in the Dawson Creek Division.
6.2 Bi-Monthly Billing While PNG-West has historically been on bi-monthly billing, the other two divisions have not. The Company now proposes to standardize its billing practice by implementing bi-monthly billing in all three divisions. This change has no impact on the revenue requirement for the Tumbler Ridge Division but PNG estimates the annual revenue requirement for Dawson Creek will be reduced by $3,000 (Exhibit!4, Tab!5, p.!18). The Commission recognizes the positive impacts listed by the Utility in its application for bi-
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20 monthly billing in the two divisions (Exhibit!15) and approves the billing method as proposed. 7.0 GAS SUPPLY AND PURCHASES 7.1 Gas Supply Cost Deferral Account PNG applied on April!2, 1996 (Exhibit!13) to dispose of the credit balance accrued in 1995 in the gas supply cost deferral account, through a gas supply credit rider on rates effective January!1 to December!31, 1996. With respect to 1995 activities, the account recorded the difference between forecast and actual gas supply costs, any variances between the forecast and actual disposition of the 1994 gas supply cost deferral account balance and the net revenue from off-system gas sales. The account, including interest, had a credit balance of over $2.5!million at the end of 1995. PNG applied its usual gas supply cost allocation methodology to the balance and calculated a credit rider for each class. The riders for 1996 range from $.014/GJ for transportation customers to $0.569/GJ for commercial firm sales customers. The Commission approves the proposed allocation and riders .
The total amount of gas that PNG purchased in 1995 exceeded deliveries (including company use gas) by 52,096!GJ. The corresponding number for 1994 was 62,444!GJ. PNG explained that this gas had been purchased by PNG and at year end was in an imbalance account between the Westcoast pipeline and the PNG pipeline (T:!266). When PNG receives this gas from the Westcoast system in the future, firm sales customers will be credited with the gas at no cost. Although the imbalance information does not correlate exactly with PNG's annual Gas Supply Cost Deferral Account filings, the evidence shows a balance with Westcoast in PNG's favour of 296,317!GJ at the end of 1995 (Exhibit!28).
The Commission believes that PNG should be able to draw this imbalance down in 1996. PNG is directed to include a reconciliation of actual purchase and delivery quantities, including pipeline to pipeline imbalances as well as company use, when it reports actual supply costs for 1996.
7.2 Gas Supply Management The Application included $100,000 of charges for Westcoast Gas Services Inc.!(“WGSI”) in projected gas costs for 1996. PNG has contracted with WGSI for supply management
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21 services for several years and for 1996 entered into a new arrangement which includes price risk management services and which reduces payments to WGSI by about $5,000!per year!(T:!85). The issues for the Commission are whether it would be more cost-effective for PNG staff to handle more supply management activities and whether the supply management services which cannot be provided efficiently by PNG staff could be obtained at lower cost if PNG tendered for them on a competitive basis. The evidence adduced on these issues is summarized below.
Methanex argued that the Commission should not accept the requested increase in gas supply management costs for 1996. Instead it should approve costs which are based on those for 1995 plus an inflation adjustment (T:!604).
PNG now has a Manager of Gas Supply & Special Projects, as well as a Manager of Integrated Resource Planning who is involved with longer term supply planning. A Coordinator of Gas Supply & Special Projects has also been hired at an incremental cost reported to be less than $50,000!per year!(T:!95). PNG’s Gas Supply & Special Projects group is active in several areas, both utility and non-utility, including the off-system sales of valley gas which mitigate gas costs for firm sales customers. At the same time, PNG acknowledged that staff could carry out all the functions that WGSI provides, except for price risk management and access to comprehensive information about current gas markets (T:!334 and 335). PNG can pick and choose among the services that WGSI offers, but was unable to identify how much these two essential services would cost as a separate package. PNG’s policy witness stated that the Company will look internally and externally to source the supply management services that are required, in order to obtain the services at minimum cost (T:!336 and 337).
Notwithstanding that WGSI is an affiliated company, PNG did not tender the 1996 service contract largely because it had an established relationship with WGSI and was satisfied that WGSI was capable of providing a comprehensive suite of services (T:!86 and 87). Since, for the most part, WGSI only deals with the 15% of firm supply for the PNG-West Division (T:!333), PNG questioned whether other supply management companies would be interested in bidding on this relatively small amount of business.
The Commission recognizes that gas supply and supply management have become increasingly complex. At the same time, PNG has significantly increased its gas supply administrative staff and it is reasonable to expect that outside purchased services should show a corresponding decrease. Also, there may be some amount of overlap between
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22 WGSI and PNG staff, especially with regard to daily supply management activities. When PNG needs to contract for services, competitive tendering would ensure the cost of these services is minimized.
Actual supply management fees are included in the Gas Supply Cost Deferral Account. When PNG files actual gas costs, it will be expected to justify the level of in-house and purchased supply management services that it used. In addition, the Commission directs that any purchased services costs for 1997 be validated through a competitive tendering process which specifies the actual services to be provided and prices them separately.
7.3 Off-System Sales Incentive Program On February 19, 1996, PNG filed a letter (Exhibit!11) requesting approval of an Off-System Sales Incentive Program ("OSIP") for 1996 for the PNG-West Division. PNG sells its valley gas (gas which it has available under firm supply contracts but which is not needed by firm sales customers) to on-system interruptible sales customers. Since 1994, PNG has also sold valley gas that is surplus to on-system needs, in the off-system market and has used the net revenue from these sales to reduce the gas costs of its firm sales customers. Net revenue totaled $400,000 in 1995 (T:!314). PNG intends to manage these sales more actively in 1996, and internal administration costs are expected to increase from $5,000 in 1995 to $10,000 in 1996 (T:!97).
Under the OSIP proposal, PNG and firm sales customers would share the net revenue from off-system sales that is in excess of a benchmark amount. (PNG would also share in shortfalls in revenue below the benchmark.) PNG modeled its OSIP proposal after a similar BC Gas program for 1996 and 1997 that formed part of the Negotiated Settlement of the BC!Gas 1996-98 Revenue Requirements Application and which was approved by Order No.!G-98-95. The BC!Gas program was recognized as interim in nature, considering the limited experience to date with off-system sales and the evolving nature of gas commodity markets.
PNG identified the objectives of its OSIP as follows: • to maximize recovery of gas supply demand charges paid by core market customers; • to encourage and reward new, significant, activities by PNG; and • to maintain the current levels of supply security and ensure that gas costs are not adversely affected.
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23 The proposed benchmark for 1996 of $277,000 was based on off-system sales activity in 1995 adjusted for a long-term supply contract and increased interruptible sales to Skeena Cellulose Inc., both of which are expected to reduce the amount of valley gas that PNG has available to sell off-system in 1996. The benchmark would be further adjusted if other on-system industrial sales in 1996 differ significantly from 1995 quantities. The average net revenue in 1995 of $0.176/GJ would be applied to calculate the benchmark for 1996, without any adjustment for actual 1996 off-system prices (T:!326).
Methanex did not oppose OSIP in principle, but felt that it should not be implemented unless the Commission revisits its December 15, 1995, PNG and PNG(N.E.) Rate Design Decision with respect to the $0.42/GJ imputed value of service for on-system interruptible sales of valley gas. Methanex's concerns appear to relate to PNG's practice of selling gas off-system at market prices, while pricing on-system interruptible sales at its variable cost of gas. Although rate design is not the subject of the current proceeding, it can be noted that Commission Orders No.!G-26-96 and!G-37-96 have approved a reconsideration of the 1995 Rate Design Decision with regard to the quantity and value of interruptible deliveries to Methanex.
In general, the Commission supports incentive mechanisms and market-based forms of regulation where they are appropriate and serve to align the interests of the affected parties, but it has serious reservations about the timing and other aspects of PNG's filed OSIP proposal. The BC!Gas program was recognized as interim, even though that utility had three years of off-system experience on which to base its benchmark. PNG has had only one full year of off-system experience, and its proposed benchmark mechanism does not include an adjustment for actual market prices in 1996. Moreover, OSIP only addresses the sale of valley gas, while PNG acknowledges that the objective of its Gas Supply group is to minimize overall gas costs for its firm sales customers (T:!198 and 199). Therefore, at this time PNG's OSIP Application is denied. The Commission is prepared to consider a future application.
7.4 Compressor Fuel Gas The actual compressor fuel use by the Utility has declined from 3.24% in 1993 to 2.8% in 1995 (Exhibit!4A). PNG forecast 3.0% in 1996. Evidence shows that there may be offsetting factors with respect to fuel usage as the Company has added more looping to the system which tends to lower fuel use, but at the same time the compressors have been upgraded
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24 to add more horsepower which would use more fuel (T:!124). However, the declining trend in fuel gas consumption would support a 2.8% compressor fuel usage for 1996 as being reasonable. An adjustment of 72!TJ or $100,000 (72,000 x $1.382 - Exhibit!4, Tab!3, p.!66) fuel reduction is made to the 1996 Revenue Requirement.
8.0 OPERATING AND MAINTENANCE EXPENSES – PNG-WEST 8.1 Forecast Prior Period Costs Not Expensed Due to lower sales deliveries in 1995 to industrial customers than forecast, PNG made significant cutbacks in O&M costs (Exhibit!1E, Tab!2, p.!1, Line!24). Actual 1995 results show O&M reductions of $918,000. The Company, in the normalization of its 1995 results, calculated an amount of $1.071!million as abnormal cost reductions in 1995 (Exhibit!4, Tab!1, p.!6[a]). In performing the normalization process in the past, the Utility generally adjusted the sales impact due to weather and unusual events but rarely adjusted the O&M costs. The Commission has made adjustments, described in section!3.6.7, to reflect the impact of certain reduced 1995 maintenance costs which may have to be incurred in future.
8.2 Forecast Cost Escalation The forecast 1996 O&M costs show an increase of 5.52% over the 1995 normalized results (Exhibit!1E). Other evidence shows that in 1994 the Utility forecast increases of 3% to labour costs and 2% to purchases; similar forecasts for 1995 show increases of 2.3% in labour costs and 2.4% for purchases; in particular, a 2.9% increase was forecast for non-union employees (Exhibit!26). A 2% escalation factor is built into the 1996 forecast with no offsetting productivity adjustments (Exhibit!4, Tab 1, p.!7). In the meantime, the Consumer Price Index increased 0.23% in 1994 and 1.75% in 1995. It is apparent the Utility has built in a substantial allowance for price level changes, notwithstanding reduced O&M levels due to the 1994 and 1995 ADR settlements, yet the forecast total O&M continues to increase at a rate much higher than forecast inflation. The number of employees has also grown from 107 in 1993 to 119 in 1996 (Exhibit!4, Tab!1, pp.!2 and!4). The Commission is concerned with the continuing pattern of increases in PNG's O&M costs in the light of increased competition, down-sizing and restructuring in the utility industry elsewhere. Furthermore, in 1995, facing lower sales throughput, PNG chose to reduce maintenance activities rather than payroll and administrative costs. The Commission believes PNG should be reducing its payroll and administrative costs within the O&M budget and makes
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25 a reduction of $50,000 in the allowed 1996 O&M costs exclusive of other adjustments discussed in this chapter of the Decision.
8.3 Executive Bonuses In 1995, PNG executives were paid $64,300 in bonuses (Exhibit!4, Tab!1, p.!91). Since the Utility was unable to achieve its targeted return on common equity, the Commission assumes that the 1995 bonus was paid on the basis of individual non-financial goals. For 1996, PNG included $92,250 for the payment of bonuses (Exhibit!4, Tab!5, p.!15); at the same time, it was not able to identify the financial goals for the executives. The Commission believes the shareholders should pay that portion of the bonuses relating to the financial goals since they are the principal beneficiary; conversely if the financial goals are not achieved, and the bonuses are not paid, the unpaid bonuses helps protect the shareholder return in a poor year. PNG agreed that the shareholders should be allocated some of the bonuses and that between 30 to 50% of the 1996 bonuses would be allocated to financial goal achievements (T:!316 and!317). Therefore, the Commission reduces the allowance for executive bonuses attributed to rate payers by $30,000 to $62,250.
The Company also indicated that steps have been taken to develop performance indicators and trend analysis to ensure cost effectiveness and efficiency in the Utility (Exhibit 1, Tab Evidence, p.!7). PNG is directed to file a report on this matter for review by the Commission no later than September!1,!1996.
8.4 Director Fees Director fees have increased sharply from $67,000 in 1995 to $93,000 in 1996 (Exhibit!4, Tab!3, p.!57). The Company, in its 1995 Annual Report to the Shareholders (Exhibit!16, p.!31), made reference to moving to compliance with the Toronto Stock Exchange Guidelines, one of which relates to "...reducing the size of the Board with a view to improving effectiveness." (T:!354). Consistent with previously approved levels of expenditure, and in anticipation of the Utility’s move towards alignment with TSE guidelines and reduction in the number of Board Members, the Commission reduces the allowance for Director fees by $23,000 to $70,000 .
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26 8.5 WEI Services PNG has a service agreement with it's parent company WEI, which provides a number of services to the Utility in the areas of administration, pipeline and compressor operations (Exhibit!1, Tab!2, pp.!38-57).
While PNG has over the last few years been taking over some of the services such as the administration of property taxes and land, the WEI service fee continues to escalate, particularly since 1994. The annual fees increased 12.8% in 1995 and are proposed to increase by 8.1% in 1996 (Exhibit!4, Tab!1, pp.!70-73). PNG went through the same exercise as in previous hearings, detailing and justifying the WEI services by comparing costs with the alternative of direct employment of PNG staff to perform similar services in-house. Neither a cost allocation study of the WEI services nor a third party quotation has been provided to support the cost effectiveness of the fees negotiated between PNG and WEI each year. This is a recurring issue which PNG has still not adequately addressed.
The Company cited savings of over $400,000 with respect to the risk management (i.e., insurance) and gas control functions (T:!53) compared with provision of similar services by PNG itself. However, the Company has not justified these fees compared with independent third party quotations which the Commission believes may be available from the marketplace.
The Commission recognizes the ongoing need for services such as those proved by WEI to PNG, but without third party justification or knowledge of the WEI cost allocation methodology, it is difficult for the Commission to accurately assess the value of these services and to rationalize the magnitude of the increases in light of the one to two percent inflation of recent years.
At a minimum, the Commission will expect PNG to provide a more rigorous analysis of the WEI cost allocation in future revenue requirements applications. Until such further evidence is provided, the Commission will limit increases to be consistent with general forecast price level changes. Based on a 2% annual inflation rate from 1994 to 1996, the WEI service fees are reduced by $55,000, to $321,000. (This reduction is to be allocated $41,000 to O&M and $14,000 to overhead based on an overhead capitalization rate of 25%).
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27 8.6 Donations The Commission in the last PNG Decision (p.!19, April!3, 1992 Decision) determined that donations should be shared equally between shareholders and customers. In the 1996 application, PNG has included the full provision of $35,000 (T:!502) without comment as to cost sharing. While the Commission is willing to consider changes in methodologies and cost treatments, the Applicant is required to identify the changes and provide evidence and justification to support such changes. In accordance with the 1992 Decision, the donation cost is reduced by $18,000.
8.7 Property and Franchise Taxes The Commission accepts the removal of franchise fees from the revenue requirement as the fees are to be collected directly from the applicable customers similar to the Provincial sales tax treatment.
PNG has made provision for regular property tax in 1996 (Exhibit!1, Tab!2, p.!59). Since the assessed property tax is not easily predictable and is eligible for pass-through under Section!67(4) of the Act, the Company agreed that a deferral account could be set up to record the variance between forecast and actual property taxes on a prospective basis (T:!503). The 1995 actual is therefore adopted as the 1996 forecast, and $72,000 is removed for revenue requirement purposes.
9.0 O&M EXPENSES – PNG(N.E.) The forecast increase in general O&M expenses of $133,000 for 1996 in Dawson Creek results in an increase of over 33% above 1995 levels (Exhibit!1B, Tab!2, p.!1, Line!24). While the Commission recognizes that this is a mature system which may require more maintenance, it was noted during cross-examination that the Utility in fact deferred certain maintenance costs in pipeline and mains operations from 1995 to 1996 (T:!499-501). In addition, some of the cost estimates such as connection fees in 1996 do not bear a direct relationship to the actual 1995 costs incurred. The Commission is concerned about the magnitude of the proposed O&M cost increase which does not appear to reflect past trends and experiences of the Utility. Therefore, the Dawson Creek O&M expenses in the general classification are reduced by $33,000, with the resulting increase limited to $100,000 for 1996. The Commission approves the Tumbler Ridge O&M costs for 1996 as reasonable.
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28 10.0 CAPITAL STRUCTURE 10.1 Common Equity Component In its Decision on Return on Common Equity dated June!10, 1994, the Commission stated: "The Commission accepts the capital structure put forward by PNG in its application as constituting a reasonable basis on which to determine rates." The Commission in the Decision also noted: "Dr.!Waters (an expert witness on behalf of the intervenors) indicated that he found the applied for capital structure reasonable...." (p.!34). The PNG capital structure in that hearing was based on an actual component of approximately 35%.
In the current Application, PNG projected a 1996 common equity component of 35.86% and Methanex questioned why PNG would not use a fixed component of 35% (Exhibit!4, Tab!3, p.!61). The Commission agrees with the Applicant's argument that it is difficult to tailor the dividend payments or equity issues to maintain the equity component at exactly 35% (T:!635 and!636). The Commission determines that, for rate making purposes, a variation within 1% from the approved common equity ratio is not unreasonable, and PNG should strive to maintain its 35% equity component within that range.
10.2 Redemption of Preferred Shares Methanex suggested that some $5!million preferred shares in PNG should be redeemed and replaced with lower-cost debt (Exhibit!4, Tab!3, pp.!62 and!63). Although the preferred dividends are not included in the interest coverage calculation, thus improving the interest coverage ratio, the cost of preferred shares is more than that of other debt due to the effect of the tax gross-up. Overall, the Commission believes that redemption of these preferred shares which are only 3.5% of the capital structure will result in only marginal impact on customer costs. Therefore the Commission concurs with the Applicant that it is reasonable to maintain the preferred shares in the capital structure (T:!634 and!635).
10.3 Short-Term Interest Rate The Commission believes that the revised forecast annual short-term debt rate of 5.55% (Exhibit!48) is reasonable and should be adopted for all divisions of PNG in 1996.
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29 10.4 Return on Common Equity PNG has appropriately incorporated the approved return on common equity of 11.75% for all divisions in this Application as pre-determined by a Commission approved mechanism.
However, the Commission notes the increased number of deferral account requests contained in this Application compared to previous years, each of which serves to limit the risk to the Utility. In some cases, the Commission has chosen not to allow certain of these deferral accounts. If the Company is uncomfortable with its present level of risk, in future it may be more appropriate for it to consider risk reduction alternatives such as the decoupling of its sales forecasts. Should the risk of PNG be significantly reduced, the risk premium on ROE should equally be reduced and the capital structure may need to be re-examined.
11.0 OTHER 11.1 Tumbler Ridge Rate Design The Tumbler Ridge cost of service can be considered to have three industrial customers; Quintette, Sceptre-Murray and Sceptre-Thunder Creek. The costs for these customers are a major part of the total cost of service, consequently an incorrect allocation adversely affects the results. Although Table!15 in the PNG Rate Design Decision (December 15, 1995) showed Sceptre Resources as one customer, the Applicant has confirmed that for rate design purposes, it is better to divide Sceptre Resources into Sceptre-Murray and Sceptre-Thunder components to more accurately reflect the cost of service of these customers (T:!344).
The original computer model underpinning the 1995 rate design study failed to correctly accounted for Sceptre's cost responsibility for the distribution lateral to the Sceptre-Thunder Creek well. Since Sceptre-Thunder is the only customer served off the distribution lateral, the cost of service study should have directly assigned the distribution cost of 17!kilometers of three inch plastic pipe to this customer. PNG subsequently submitted a new application (Exhibit!14, dated December!20, 1995) that implemented a direct allocation of the distribution capacity costs ($45,595) to Sceptre-Thunder.
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30 As a result of this application, the cost of service allocated to small commercial customers and Quintette has been reduced and the cost of service allocated to Sceptre has increased. The residential customer class is not affected by the cost reallocation as no distribution capacity costs are assigned to this customer category.
In a letter to the Commission (Exhibit!3C), Sceptre Resources stated: "Sceptre supports the proposed changes for Thunder Creek on the understanding that the economic impact will be positive towards Sceptre, which is important given Thunder Creek continues to be a money losing operation because of poor production results."
During the hearing this was explained further to clarify that Sceptre supported the change as long as its combined rates did not increase as a result (T: 359). This is the case.
The Commission accepts that the division of Sceptre Resources into Sceptre-Thunder and Sceptre-Murray will better assign costs for rate design purposes and that distribution costs of $45,595 should be directly assigned to Sceptre-Thunder.
As described under "Commission Determination" on page 49 of the PNG 1995 Rate Design Decision (December 15, 1995), the Commission directs that a 10% increase on a gross revenue basis be applied to the rates for residential and small commercial customers effective January 1, 1996. However, the increase is to be reallocated to Sceptre-Thunder and Quintette so as to achieve as close as is practicable an equal R/C ratio for each industrial. The result of these adjustments is shown in Appendix!B.
11.2 Non-Regulated Businesses Counsel for Methanex referred (T:!178 and!179) to pp.!3 and 4 of PNG's 1995 Annual Report to Shareholders (Exhibit!16) in which PNG stated it would create new services and business including financial services, energy and energy equipment supply and management, as well as new opportunities in engineering and consulting services. PNG stated that these new opportunities were essential to PNG's success in the future. While the Company provided assurance that the utility side of the corporation would be compensated for services provided to the non-regulated businesses (T:!184), the Commission is concerned about the potential cross-subsidy by the Utility customers or potential market dominance of such non-regulated businesses supported by the Utility. The focus of PNG management away from the traditional utility activities may be detrimental to the essential services to
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31 customers unless such activities are clearly severed from the utility operations. Even in a scenario where no business opportunities outside the Utility are identified, there is a risk that rate payers will be paying for the research efforts of utility staff to find such opportunities. This issue will be explored further in future Commission proceedings.
11.3 Hearing Costs In its Application, PNG provided for hearing costs of $146,000 for PNG-West, $35,000 for Dawson Creek and $10,000 for Tumbler Ridge. The total hearing costs incurred for all three divisions are approximately $65,000: $44,000 for PNG's costs and $21,000 for the Commission's costs. The significant savings from forecast are primarily a result of reduced travel costs and fewer hearing days.
The Commission will allow full recovery of the hearing costs incurred. These costs of approximately $65,000 are to be allocated to each division on a basis proportional to the number of customers as follows: 75% to PNG-West, 20% to Dawson Creek and 5% to Tumbler Ridge.
However, the Commission notes that the Application failed to provide sufficient support or explanation in some key areas. This deficiency apparently resulted in a significantly greater number of information requests from both intervenors and Commission staff than is usual (Exhibit!4). The Commission has made comments in the relevant sections of this Decision but expects every utility to provide complete information with its applications.
The Commission accepts the forecast beginning balances in the hearing cost deferral account relating to the 1995 Rate Design hearing and an amortization period of five years for the purpose of setting 1996 rates. However, the final amounts and amortization period remain subject to approval by the Commission in its Decision following the conclusion of the PNG Rate Design Reconsideration hearing scheduled to commence on May!31,!1996.
12.0 THE DECISION On the basis of the evidence presented and the issues examined during the proceeding, the Commission has made a number of adjustments throughout this Decision to the revenue requirements applied for by PNG. The adjustments and approved revenue requirements are identified in the Decision Schedules attached to this Decision. For all three PNG
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32 divisions, the revenue requirements approved by this Decision are less than the interim revenue requirements as previously approved by Commission Order No.!G-117-95.
The approved revenue requirement for PNG-West is $52.603 million. This results in a revenue requirement increase of approximately $3.193 million or 6.46% over 1995 rates. The increase is mainly comprised of $1.6 million due to additional income tax on overhead capitalized, $0.6 million due to reduced Methanex gas deliveries and approximately $1 million due to additional depreciation expenses. For Dawson Creek, the approved revenue requirement is $4.824!million with a revenue increase of $41,000 or 0.86% which is caused by an increase in projected 1996 maintenance costs. For Tumbler Ridge, the approved revenue requirement is $1.655 million resulting in a revenue reduction of $70,000 or 4.06%.
The final retail rates to be paid by PNG's customers will be determined after the implementation of the riders approved in this Decision along with any rate design and cost of gas changes.
The difference between the interim rates and the approved rates shall be refunded to customers with appropriate interest. PNG is to comply with all the directions contained in this Decision and file, on a timely basis, new tariff schedules with an effective date of January!1, 1996. A reconciliation of the implementation of the new rate schedules and riders should also be provided.
DATED at the City of Vancouver, in the Province of British Columbia, this !!!!!!!!! day of May, 1996.
Lorna R. Barr Chair of the Division
F.C. Leighton, P.Eng. Commissioner
33 G-51-96 IN THE MATTER OF the Utilities Commission Act, S.B.C. 1980, c. 60, as amended
and An Application by Pacific Northern Gas Ltd. and Pacific Northern Gas (N.E.) Ltd. for 1996 Revenue Requirements and Interim and Permanent Rate Changes
BEFORE: L.R. Barr, Deputy Chairperson; and) F.C. Leighton, Commissioner ) May 29, 1996 O R D E R WHEREAS: A. On November!29, 1995 Pacific Northern Gas Ltd. - West Division (“PNG”) and Pacific Northern Gas (N.E.) Ltd. - Dawson Creek and Tumbler Ridge Divisions [“PNG(N.E.)”] applied to the Commission, pursuant to Sections!64 and 106 of the Utilities Commission Act, for approval to amend its Gas Tariff Rate Schedules on an interim and permanent basis effective January 1, 1996 (“the Application”); and
B. The Commission issued Order No.!G-117-95 which approved for PNG and PNG(N.E.) interim rate changes effective January!1, 1996, and set down a public hearing into the Application; and
C. Following a pre-hearing conference, the Commission issued Order No.!G-12-96 setting the review of the Dawson Creek and Tumbler Ridge sections of the Application to be dealt with by the Alternate Dispute Resolution!(“ADR”) process and the PNG section of the Application by a public hearing; and
D. PNG and PNG(N.E.) filed updates to the Application on February 16 and March!1, 1996 respectively. The update to the PNG(N.E.) sections of the Application contained new requests and changes similar to those contained in that of PNG; and
E. As a result of formal changes to PNG's Application, the Commission canceled the ADR process as directed in Order No.!G-12-96 and by Order No.!G-24-96 set the hearing to commence on April!9, 1996 to examine issues pertaining to PNG and PNG(N.E.); and
F. The Commission has considered the Application and evidence adduced therein, all as set forth in the Decision issued concurrently with this Order.
NOW THEREFORE the Commission hereby orders PNG and PNG(N.E.) as follows: 1. The Rate Base and Revenue Requirements for the year ending December!31, 1996 are as set out in the Schedules contained in the Decision.
34 2. The interim rates, approved by Order No.!G-117-95, are considered to be excessive and are required to be partially refunded with appropriate interest to customers from January!1, 1996 to the date upon which the new Gas Tariff Rate Schedules will come into effect.
3. PNG and PNG(N.E.) will comply with the several directions incorporated in the Commission Decision.
DATED at the City of Vancouver, in the Province of British Columbia, this !!!!!!!!!!!!!!!!!!!!day of May, 1996.
BY ORDER
Lorna R. Barr Deputy Chairperson
35 APPENDIX A Page 1 of 1
PACIFIC NORTHERN GAS LTD. Summary of 1995 Deferral Adjustments After Tax ($000)
A. 1995 Deferrals Requested Allowed Disallowed Items: re: 1995 Federal Large Corporation Capital Tax $ 33 $ 33 $ – BCSS Tax Reassessment (1/6 for 1995) 12 0 2 Extra Pay Period (1/11 for 1995) 79 0 7 Overheads Capitalized 862 862 – Skeena Strike (20% disallowed) 322 258 64 CCA Calculation Error 232 232 – Reduction in net income $ 1,540 $ 1,385 $ 73 Maintenance costs (412 x .555) 229 Total 1995 Disallowed: $ 302
B. Effect of Adjustments Disallowed Common Equity re: 1995 Per Schedule 4 (Exhibit 1E) $ 48,374 Mid-year effect of income reduction (151) Adjusted common equity $ 48,223
Return on Common Equity Per Schedule 5 (Exhibit 1E (11.192% of $48,374) $ 5,414 Less: reduction in net income 302 Adjusted return on common equity $ 5,112
Rate of return on common equity (i.e., $5,112 ÷ $48,223) 10.60% Normalization Adjustment [Exhibit 1E, T5, P1 (11.918 - 11.192)] .73% Normalized return on common equity 11.33%
36 APPENDIX B Page 1 OF 1
Pacific Northern Gas (N.E.) Ltd.
Tumbler Ridge Division - New Application Determination of Revenue/Cost Ratios 1995 Budget, Excluding the Cost of Gas Customer Allocated Existing Rev/Cost Increase Res, Comm 10% Costs Revenue Ratio Revenue Revised Rev/Cost Change Revenue Ratio ($) ($) ($) ($)
Residential 530,371 392,530 0.74 61,984 454,514 0.86 Small Commercial 178,573 155,722 0.87 27,538 183,260 1.03 Quintette 227,066 351,907 1.55 -81,750 270,157 1.19 Sceptre Thunder 69,826 91,178 1.31 -7,772 83,406 1.19 Sceptre Murray 106,502 119,995 1.13 0 119,995 1.13 . Total 1,112,338 1,111,332 0 1,111,332
NOTES: 1. Allocated Costs and Existing Revenue from Exhibit 4, BCUC IR p. 89(b). 2. Allocation of costs adjusted as per Exhibit 4, Tumbler Ridge IR Response No. 1, p. 11 and BCUC IR Response No. 8, p. 89. 3. Residential and Commercial increases allocated to Quintette and Sceptre so as to give the same R/C ratio for each Industrial. 4. Distribution costs of $45,595 allocated directly to Sceptre Thunder per Dec 20, 1995 Application. 5. Existing revenue for Sceptre split based on Exhibit 4, BCUC IR p. 89(f).
37 APPENDIX C Page 1 OF 1 APPEARANCES
G.A. FULTON Commission Counsel J. LUTES Pacific Northern Gas Ltd. Pacific Northern Gas (N.E.) Ltd. D. BURSEY Methanex Corporation A.W. CARPENTER Gas Contractors J. POWELL Skeena Cellulose Inc.
WITNESS PANELS PNG PANEL #1: Policy, gas supply, tariff and toll matters R.G. DYCE President and Chief Executive Officer C.P. DONOHUE Manager of Regulatory Affairs; P.T. MIDGLEY Manager of Integrated Resource Planning J.N. OOSTERBAAN Manager of Gas Supply & Special Projects.
PNG Panel #2: Rate base and cost of service matters T.W. WEAVER Comptroller; W.R. HOUGH Vice President of Engineering and Operations M.W. EPP Manager of Operations.
Methanex Panel: R. BRITTON Vice President, North American Operations J. TYSON Manger of Gas Supply and Regulatory Affairs L. GUENTHER Consultant for LSM Consulting
38 APPENDIX D LIST OF EXHIBITS Exhibit __No._
Pacific Northern Gas Ltd., 1996 Revenue Requirement Application, dated November 1995 1 Amendments to the Pacific Northern Gas Ltd., 1996 Revenue Requirement, dated February 13, 1996 1A Amendments to the Pacific Northern Gas Ltd., 1996 Revenue Requirement, dated February 29, 1996 1B Amendments to the Pacific Northern Gas Ltd., 1996 Revenue Requirement, dated April 2, 1996 1C Pacific Northern Gas Ltd., Summary of 1996 Revenue Deficiency Causation Factors Revised as of April 2, 1996 1D Pacific Northern Gas Ltd., Schedules 1 through 5 revised 1E
B.C. Utilities Commission Orders: No. G-12-96 dated February 1, 1996 Public Hearing/ADR; No.!G-24-96 dated March 8, 1996 Cancellation of PNG(N.E.) ADR; and No.!G-117-95 dated December 21, 1995 Interim Rates Changes 2 Affidavit of Notice of Publication 3 Bull, Housser & Tupper letter to B.C. Utilities Commission, dated January 8, 1996 3A
British Columbia Public Interest Advocacy Centre letter to B.C. Utilities Commission, dated April 3, 1996 3B Sceptre Resources Ltd. letter to Pacific Northern Gas Ltd., dated April 8, 1996 3C
Pacific Northern Gas Ltd. Responses to B.C. Utilities Commission Staff Information Requests: No. 1 dated January 3, 1996; No. 2 dated January 10, 1996; No. 3 dated February 28, 1996; No. 4 dated March 13, 1996; Responses to Methanex Corporation Information Requests dated February 13 and March 7, 1996; and Response to B.C. Public Interest Advocacy Centre Information Request dated February 17, 1996 4
Pacific Northern Gas Ltd., Corrected Tables 2-3, Analysis of Company Use Gas 4A Stone & Webster Management Consultants, Inc., Depreciation Study, dated September 26, 1995 5 Pacific Northern Gas Ltd. letter to B.C. Utilities Commission, dated October 31, 1995 6 Amended Table dated January 3, 1996 showing 1995 recalculation of Loss of Margin Resulting from Skeena Cellulose Work Stoppage 7 Pacific Northern Gas Ltd. letter to B.C. Utilities Commission, dated December 20, 1995 8 Pacific Northern Gas Ltd. letter to B.C. Utilities Commission, dated January 30, 1996 9 Pacific Northern Gas Ltd. letter to B.C. Utilities Commission, dated February 21, 1996 10 Pacific Northern Gas (N.E.) Ltd. letter to B.C. Utilities Commission, dated March 5, 1996 10A Pacific Northern Gas Ltd., 1996 Off-System Sales Incentive Program Application, dated February 19, 1996 11
39 Pacific Northern Gas Ltd., Pilot Program for a Heating Insurance Plan Application, dated March 4, 1996 12
Pacific Northern Gas Ltd., Disposition of 1995 Gas Supply Cost Deferral Account Balance Application, dated April 2, 1996 13
Pacific Northern Gas (N.E.) Ltd. Tumbler Ridge Division, 1996 Rate Design Application dated December 20, 1996 14
Pacific Northern Gas (N.E.) Ltd. letter to B.C. Utilities Commission, dated December 21, 1995 15
Pacific Northern Gas Ltd., 1995 Annual Report to Shareholders 16 List of Gas Contractors Opposed to the Hearing Insurance Program, dated April 4, 1996 17
Copies of letters to B.C. Utilities Commission from gas contractors opposing the Heating Insurance Program 17A
Further letters per Exhibit 17A 17B K.C. Minifie of Kitimat, B.C. letter to B.C. Utilities Commission, stamp received April 10, 1996 17C
Lawson Lundell Lawson & McIntosh letter to B.C. Utilities Commission, dated April 4, 1996 18
Pacific Northern Gas Ltd., System and Service Area Locations Map 19 Pacific Northern Gas Ltd., System Line Map 19A Pacific Northern Gas Ltd., Summary of Deferrals and the Impact of 1995 Earnings 20
Pacific Northern Gas Ltd., Revised Schedule Income Effect of 1995 20A Pacific Northern Gas Ltd., Projected Revenue Deficiencies 1997 to 2000 21 Pacific Northern Gas Ltd., Development of 1994 Base for Residential Forecast 22
Pacific Northern Gas Ltd. letter to B.C. Utilities Commission, dated July 31, 1995 23
Pacific Northern Gas Ltd., p. 75 - Non-consolidated Balance Sheets, dated March 12, 1996 of Response to Methanex Corporation Information Request No. 3 24
Pacific Northern Gas Ltd., Volume 1, PNG Tab 2, p. 9, Actual and Projected Gas Deliveries to Small Industrial Customers 25
Excerpts from Pacific Northern Gas Ltd., Revenue Requirement Applications, 1995 Volume 1, Evidence, p. 21 and 1994 Volume 2, Tab 4, pp. 5 and 6 26
Pacific Northern Gas Ltd., Consolidated Operating Margin, 1997 to 2000 27 Pacific Northern Gas Ltd., Recorded PNG/Westcoast Energy Pipeline to Pipeline Imbalances 28
40 Pacific Northern Gas (N.E.) Ltd., Dawson Creek Board Plant, 1996 Gas Requirements Projection 29
Pacific Northern Gas Ltd., Residential Forecast Graph of Trend Line 30 Pacific Northern Gas (N.E.) Ltd., Revision to p. 40 of B.C. Utilities Commission Staff Information Request No. 4, dated March 13, 1996 31
Pacific Northern Gas Ltd., Revised Summary of Integrated Resource Planning Project Deferrals 1996, dated April, 1996 32
Pacific Northern Gas Ltd., Transmission Plant Account 462 - Utility Plant In Service at December 1994 33
Pacific Northern Gas Ltd., NGV Earned Return, Schedule 2E 34 Pacific Northern Gas Ltd. letter to OrCom Systems 35 Pacific Northern Gas Ltd., Request for Proposal, dated July 1995 36 Canadian Institute of Chartered Accountants, Exposure Draft 37 Pacific Northern Gas Ltd., Continuity of Deferred Charges, Budget 1994 38 B.C. Utilities Commission Order No. G-53-94 39 Pacific Northern Gas Ltd., Revised p. 15 dated April 11, 1996 to Response to B.C. Utilities Commission Staff Information Request No. 1, dated January 3, 1996 40
Pacific Northern Gas Ltd., Sales of Unused Firm Gas Supply 1995 41 Pacific Northern Gas Ltd., Volume 1, PNG Tab 4, p. 1, Common Equity Schedule 4 42
Pacific Northern Gas Ltd., Common Equity as at December 31, 1992, Schedule 4 43
BC Gas Utility Ltd., "Cash Working Capital, Lag Time in Payment of Expenses" for the Years Ended December 31, 1996, 1997, 1998 44
Evidence of Methanex Corporation 45 Curriculum Vitae of Mr. J. Tyson 46A Curriculum Vitae of Mr. R. Britton 46B Curriculum Vitae of Mr. L. Guenther 46C Methanex Corporation, revision dated April 11, 1996 to the Response to Pacific Northern Gas Ltd. Information Request No. 1, dated April 3, 1996 47
Pacific Northern Gas Ltd., System Development Costs, dated January 1, 1996 48
41 EXECUTIVE SUMMARY Introduction On November 29, 1995, PNG and PNG(N.E.) made application to amend their rate schedules in the three divisions effective January 1, 1996 ("the Application"). The Application is a three-part document consisting of independent applications for the three PNG Divisions, namely: PNG-West Division, PNG(N.E.)-Dawson Creek and Tumbler Ridge Divisions. The Application reflects rate impacts resulting from changes in the revenue requirement, changes in the cost of gas and from implementation of the December!15, 1995 Rate Design Decision. The total 1996 revenue requirement deficiency for PNG-West was forecast to be $3.96!million or approximately 7.7%; for Dawson Creek the projected deficiency was $157,000 or 3.2%. For Tumbler Ridge a revenue surplus of $41,000 or 2.3% was projected. Prior to, and during the hearing, the Utility also filed further updates to its Application which initially revised the PNG-West revenue deficiency to $4.8!million or 9.6% of gross revenue and later lowered the deficiency to $4.4!million.
The utilities sought approval on an interim basis under Section!106 of the Utilities Commission Act and on a permanent basis under Section!64 of the Act. By Order No.!G-117-95 the Commission approved for PNG and PNG(N.E.) its proposed interim rate changes effective January 1, 1996 subject to refund with interest. A public hearing commenced on April 9, 1996 at the Commission's hearing room in Vancouver, B.C. and concluded with oral argument by counsel for the Applicant and Methanex on April!12, 1996. The Commission's findings on key issues is discussed in the balance of this executive summary.
Plant Additions The Utility has forecast plant additions of approximately $11.5 million in 1996 which compare with approved additions of $14.8 million and actual additions of $13.9 million in 1995 (Exhibit!1E). The Commission accepts the Company's forecast.
Depreciation The Commission accepts the study result that the composite depreciation rate should be 2.91%, but rejects the proposed offset of depreciation rate increases with deferred income tax. The new depreciation rates are to be implemented by phasing in 50% of the $860,000
42 increase in the cost of service in 1996 and 100% of the amount in subsequent years. The Commission also approves the recovery of the costs of approximately $40,000 relating to the Depreciation Study which are to be amortized in full in 1996.
Cash Working Capital In the absence of a lead/lag study, the Commission is only prepared to allow 50% of the proposed increase of $472,000 for 1996. PNG in its next rate application should provide adequate support in the form of a lead/lag study including the impact of provincial sales tax on cash working capital.
Request for 1995 Deferral Accounts and Other Recoveries PNG applied for Commission approval to recover certain 1995 costs. The Utility's results in 1995, if adjusted to include recovery of all of these costs, would show a return on common equity of 11.192% and a normalized return of 11.918%. If these requested costs were absorbed in 1995 and not recovered, the Utility would have earned a 1995 return on common equity of 8.14% or a normalized return of approximately 8.87%.
Of the $1,540,000 requested for recovery, the Commission approves a total of $1,156,000 to be recovered as a rider in 1996 allocated on the margin of each rate class. With adjustments and the exclusion of costs pertaining to years prior to 1995, PNG should have earned in 1995 an actual return on common equity of 10.60% and a normalized return of approximately 11.33%.
Stress Corrosion Cracking Investigation The Commission approves the expenditure of $40,000 for a stress corrosion cracking study with this amount to be amortized in full in 1996. Any further expenditures will require an application to the Commission which must be able to demonstrate a clear need based on the results of the PNG study and the current NEB investigations of stress corrosion problems on federally regulated gas transmission systems.
Other Deferral Charges and Amortization The Commission directs that PNG in future should amortize the full amounts approved in the test year in order to preserve neutrality between the Utility and customers, unless the particular deferred account's actual balance is less than the forecast amortization
43 amount. For example, if the actual balance is $50,000, but the approved amortization in the year is $100,000, PNG should amortize only $50,000.
NGV Conversion Loan The Commission approves the Application to increase the Natural Gas for Vehicle conversion loan from $1,600 up to $3,500. However, PNG is directed to provide the Commission with justification of the interest charge on all financing assistance provided to customers, in a report to be filed by June!30,!1996.
Sales Volume And Revenue The Commission believes that the test year sales volumes should attach their normal margin and the after-tax value of $264,000 relating to the deficiency volumes should be recovered in a rider during 1996.
For PNG-West, the Commission considers a forecast use per residential customer of 113.0!GJ in 1996 to be appropriate and an increase of 11!TJ or $35,000 in gross margin is added to the test year forecast. For Dawson Creek, the Commission makes a sales adjustment of 11,000!GJ or $9,000 in margin to the large commercial sales forecast. Otherwise, all sales forecasts in the Application are accepted.
Gas Supply Matters The Commission approves the proposed allocation and riders for disposition of the credit balance contained in the gas cost deferral account at the end of 1995. PNG is directed to include a reconciliation of actual purchase and delivery quantities, including pipeline to pipeline imbalances as well as company use, when it reports actual supply costs for 1996.
The Commission denies PNG's application for an off-system sales incentive program. The Commission is prepared to consider a future application.
A reduction of 72!TJ or $100,000 for compressor fuel cost is made to the 1996 Revenue Requirement.
44 OPERATING AND MAINTENANCE EXPENSES Forecast Prior Period Costs Not Expensed Due to lower sales deliveries in 1995 to industrial customers than forecast, PNG made significant cutbacks in O&M costs. The Commission has made appropriate adjustments to reflect the impact of certain reduced 1995 maintenance costs which may have to be incurred in future.
Forecast Cost Escalation The Commission is concerned with the continuing pattern of increases in PNG's O&M costs in the light of increased competition, down-sizing and restructuring in the utility industry elsewhere. The Commission believes PNG should be reducing its payroll and administrative costs within the O&M budget and makes a reduction of $50,000 in the allowed 1996 O&M costs for PNG-West exclusive of other adjustments.
The Dawson Creek O&M expenses in the general classification are reduced by $33,000 , with the resulting increase limited to $100,000 for 1996. The Commission approves the Tumbler Ridge O&M costs for 1996 as reasonable.
Executive Bonuses The Commission reduces the allowance for executive bonuses attributed to rate payers by $30,000 to $62,250. The Company indicated that steps have been taken to develop performance indicators and trend analysis to ensure cost effectiveness and efficiency in PNG. PNG is directed to file a report on this matter for review by the Commission no later than September!1,!1996.
Director Fees Consistent with previously approved levels of expenditure, and in anticipation of the Utility’s move towards alignment with TSE guidelines and reduction in the number of Board Members, the Commission reduces the allowance for Director fees by $23,000 to $70,000 .
45 WEI Services The Commission recognizes the ongoing need for services such as those proved by WEI to PNG, but without third party justification or knowledge of the WEI cost allocation methodology, it is difficult for the Commission to accurately assess the value of these services and to rationalize the magnitude of the increases in light of the one to two percent inflation of recent years. At a minimum, the Commission will expect PNG to provide a more rigorous analysis of the WEI cost allocation in future revenue requirements applications. Until such further evidence is provided, the Commission will limit increases to be consistent with general forecast price level changes. Based on a 2% annual inflation rate from 1994 to 1996, the WEI service fees are reduced by $55,000, to $321,000. (This reduction is to be allocated $41,000 to O&M and $14,000 to overhead based on an overhead capitalization rate of 25%.)
Donations In accordance with the 1992 Decision, the donation cost is reduced by $18,000. Property and Franchise Taxes The Commission accepts the removal of franchise fees from the revenue requirement as the fees are to be collected directly from the applicable customers similar to the Provincial sales tax treatment. The 1995 actual is therefore adopted as the 1996 forecast, and $72,000 is removed for revenue requirement purposes.
CAPITAL STRUCTURE Common Equity Component
The Commission determines that, for rate making purposes, a variation within one percent from the approved common equity ratio is not unreasonable, and PNG should strive to maintain its 35% equity component within that range.
Redemption of Preferred Shares The Commission concurs with the Applicant that it is reasonable to maintain the preferred shares in the capital structure.
Short-Term Interest Rate The Commission believes that the revised forecast annual short-term debt rate of 5.55% is reasonable and should be adopted for all divisions of PNG in 1996.
Return on Common Equity PNG has appropriately incorporated the approved return on common equity of 11.75% for all divisions in this Application as pre-determined by a Commission approved mechanism.
However, the Commission notes the increased number of deferral account requests contained in this application compared to previous years, each of which serves to limit the risk to the Utility. In some cases, the Commission has chosen not to allow certain of these deferral accounts. In future, the Company may wish to reduce its risk further through alternatives such as decoupling of its sales forecasts. This could lead to a re-examination of the risk premium on ROE and the capital structure.
46 OTHER Tumbler Ridge Rate Design The Commission accepts that the division of Sceptre Resources into Sceptre-Thunder and Sceptre-Murray will better assign costs for rate design purposes and that distribution costs of $45,595 should be directly assigned to Sceptre-Thunder.
Non-Regulated Businesses The focus of PNG management away from the traditional utility activities may be detrimental to the essential services to customers unless such activities are clearly severed from the utility operations. Even in a scenario where no business opportunities outside the Utility are identified, there is a risk that rate payers will be paying for the research efforts of utility staff to find such opportunities. This issue will be explored further in future Commission proceedings.
47 Hearing Costs The Commission will allow full recovery of the hearing costs incurred. These costs of approximately $65,000 are to be allocated to each division on a basis proportional to the number of customers as follows: 75% to PNG-West, 20% to Dawson Creek and 5% to Tumbler Ridge.
SUMMARY On the basis of the evidence presented and the issues examined during the proceeding, the Commission has made a number of adjustments throughout this Decision to the revenue requirements applied for by PNG. For all three PNG Divisions, the revenue requirements approved by this Decision are less than the interim revenue requirements as previously approved by Commission Order No.!G-117-95.
The approved revenue requirement for PNG-West is $52.603 million. This results in a revenue requirement increase of approximately $3.193 million or 6.46% over 1995 rates. The increase is mainly comprised of $1.6 million due to additional income tax on overhead capitalized, $0.6 million due to reduced Methanex gas deliveries and approximately $1 million due to additional depreciation expenses. For Dawson Creek, the approved revenue requirement is $4.824!million with a revenue increase of $41,000 or 0.86% which is caused by an increase in projected 1996 maintenance costs. For Tumbler Ridge, the approved revenue requirement is $1.655 million resulting in a revenue reduction of $70,000 or 4.06%.
The final retail rates to be paid by PNG's customers will be determined after the implementation of the riders approved in this Decision along with any rate design and cost of gas changes.
The difference between the interim rates and the approved rates shall be refunded to customers with appropriate interest. PNG is to comply with all the directions contained in this Decision and file, on a timely basis, new tariff schedules with an effective date of January!1, 1996. A reconciliation of the implementation of the new rate schedules and riders should also be provided.
48 TABLE OF CONTENTS Page No. EXECUTIVE SUMMARY 1.0 INTRODUCTION 1 1.1 Background 1 1.2 Preliminary Matters 2 2.0 THE APPLICATION 3 2.1 Supplementary Applications 3 2.2 Forecasts and Updates 4 3.0 RATE BASE FOR PNG-WEST 5 3.1 Plant Additions 5 3.1.1 Mains Extensions - Infrastructure Works Program 5 3.1.2 Customer Information System ("CIS") 6 3.2 Depreciation 7 3.3 Gas Utility Uniform System of Accounts 8 3.4 Overhead Capitalized 8 3.5 Cash Working Capital 8 3.6 Request for 1995 Deferral Accounts and Other Recoveries 9 3.6.1 Loss of Margin due to Skeena Strike 9 3.6.2 Additional Pay Period 10 3.6.3 Federal Large Corporations Capital Tax 11 3.6.4 Provincial Sales Tax Audit 11 3.6.5 CCA Calculation Error 12 3.6.6 Income Tax Pass-through on Overhead Capitalized 13 3.6.7 Method of Recovery 13 3.7 Pipeline Cost Deferral Account 14 3.8 Stress Corrosion Cracking Investigation 15 3.9 Other Deferral Charges and Amortization 15 3.10 NGV Conversion Loan 16 4.0 RATE BASE FOR PNG(N.E.) DIVISIONS 16 5.0 SALES VOLUME AND REVENUE – PNG-WEST 17 5.1 Deficiency Carried Forward 17 5.2 Sales Forecast 18 5.2.1 Residential Sales 18 5.2.2 Other Sales 18 5.2.3 1996 Methanex Margin Deferral Account 18 6.0 SALES VOLUME AND REVENUE - PNG(N.E.) 19 6.1 Sales Forecast 19 6.2 Bi-Monthly Billing 19 7.0 GAS SUPPLY AND PURCHASES 20 7.1 Gas Supply Cost Deferral Account 20 7.2 Gas Supply Management 20 7.3 Off-System Sales Incentive Program 22 7.4 Compressor Fuel Gas 23 8.0 OPERATING AND MAINTENANCE EXPENSES – PNG-WEST 24 8.1 Forecast Prior Period Costs Not Expensed 24 8.2 Forecast Cost Escalation 24 8.3 Executive Bonuses 25 8.4 Director Fees 25 8.5 WEI Services 26 8.6 Donations 27 8.7 Property and Franchise Taxes 27 9.0 O&M EXPENSES – PNG(N.E.) 27
49 10.0 CAPITAL STRUCTURE 28 10.1 Common Equity Component 28 10.2 Redemption of Preferred Shares 28 10.3 Short-Term Interest Rate 28 10.4 Return on Common Equity 29 11.0 OTHER 29 11.1 Tumbler Ridge Rate Design 29 11.2 Non-Regulated Businesses 30 11.3 Hearing Costs 31 12.0 THE DECISION 31 COMMISSION ORDER NO. G-51-96 DECISION SCHEDULES APPENDIX A - Summary of 1995 Deferral Adjustments APPENDIX B - Tumbler Ridge Rate Design Revenue To Cost Ratios APPENDIX C - Appearances APPENDIX D - List of Exhibits