B R I T I S H C O L U M B I A U T IL I T I E S C O M M I S S I O N
O R D E R N U M B ER G-85-97 IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 and An Application by BC Gas Utility Ltd. for Approval of a Performance Based Rate Plan to Determine Revenue Requirements for the Years 1998 - 2002 BEFORE: L.R. Barr, Deputy Chair ) and Acting Chair ) July 23, 1997 K.L. Hall, Commissioner ) P.G. Bradley, Commissioner ) O R D E R WHEREAS: A. On February 5, 1997 BC Gas Utility Ltd. ("BC Gas") filed with the Commission its Performance Based Rate Plan and Revenue Requirements Application 1998 - 2002 (the "Application") for approval to set rates for the years ending December 31, 1998 through 2002; and
B. The Commission reviewed the Application and issued Order No. G-13-97 setting down a Pre-Hearing Conference to commence on February 28, 1997. Following the Pre-Hearing Conference, the Commission issued Order No.ÊG-24-97, which included a Regulatory Agenda and Timetable, setting a second Pre-Hearing Conference for AprilÊ24, 1997 and a public hearing, if required, to commence JuneÊ3, 1997. On AprilÊ24, 1997 the Commission, by Order No.ÊG-47-97, amended the dates set out in the Regulatory Timetable and revised the public hearing date to JuneÊ23, 1997; and
C. Commission Order No.ÊG-68-97 cancelled the public hearing scheduled for JuneÊ23, 1997 and allowed for a rescheduling by way of a future Commission Order; and
D. The Alternative Dispute Resolution ("ADR") process commenced on JuneÊ2, 1997 and, on JuneÊ26, 1997, BCÊGas, ADR participants and Commission staff agreed to a proposed settlement agreement; and
E. On JulyÊ10, 1997 the proposed settlement agreement was circulated to all Registered Intervenors and the Commission Panel. No comments were received; and
B R I T I S H C O L U M B I A U T I L IT IE S C O M M I S S I ON
2 F. The Commission has reviewed the proposed settlement agreement and sets out its views in the Reasons for Decision issued concurrently with this Order.
NOW THEREFORE the Commission orders as follows: 1. The Commission accepts the terms of the proposed settlement agreement as revised by its Consolidated Settlement Document and issues its Reasons for Decision.
2. BCÊGas will comply with all the terms contained in the Consolidated Settlement Document accompanying the Reasons for Decision.
3. BCÊGas is to inform all customers of the effect on rates of this Decision. 4. The public hearing into the application is not required and is therefore cancelled. DATED at the City of Vancouver, in the Province of British Columbia, this ÊÊÊÊÊÊÊ25thÊÊÊÊÊÊÊÊÊday of July, 1997. Attachment
O R D ER N U M B E R G-85-97
BY ORDER Original signed by: Lorna R. Barr Deputy Chair and Acting Chair
a IN THE MATTER OF BC Gas Utility Ltd. REVENUE REQUIREMENTS APPLICATION 1998 - 2002 Reasons for Decision July 23, 1997 BEFORE: Lorna R. Barr, Deputy Chair and Acting Chair Ken L. Hall, Commissioner Paul G. Bradley, Commissioner
TABLE OF CONTENTS REASONS FOR DECISION COMMISSION ORDER No. G-85-97 CONSOLIDATED SETTLEMENT DOCUMENT APPENDIX A - ILLUSTRATIVE RATE IMPACTS APPENDIX B - COMMISSION STAFF LETTER OF JULY 15, 1997
1 REASONS FOR DECISION Introduction BC Gas Utility Ltd. ("BC Gas") filed an application dated February 5, 1997 (the ÒApplicationÓ) with the British Columbia Utilities Commission (the ÒCommissionÓ, "BCUC") to establish the method for determining its revenue requirements and for approval to set rates for the five years ending DecemberÊ31,Ê1998 to 2002.
On February 10, 1997, the Commission issued Order G-13-97 setting a pre-hearing conference to commence FebruaryÊ28, 1997. Following the pre-hearing conference, the Commission issued Order No.ÊG-24-97 which included a regulatory timetable, setting a second pre-hearing conference for AprilÊ24,Ê1997 and a public hearing, if required, to commence JuneÊ3, 1997. Subsequent to the second pre-hearing conference the Commission issued Order No.ÊG-47-97 setting down a revised regulatory timetable which provided for, among other matters, rescheduling the public hearing to June 23, 1997. The timetable also provided for public workshops regarding the Application; a process for filing information requests by parties and responses by BCÊGas; and an Alternative Dispute Resolution process ("ADR") to negotiate a settlement of issues related to the Application. BCÊGas conducted public workshops on March 10, 11 and April 16, 1997. Information requests were filed and an additional 3 volumes of information responses and other data were provided by BCÊGas.
The negotiation sessions commenced on June 2, 1997 and continued on various dates through to JuneÊ26,Ê1997 when a negotiated settlement was reached between BC Gas and the parties to the negotiation. The three year proposed settlement agreement was circulated to the ADR participants. Endorsements of the proposed settlement agreement by all of the ADR participants were received at the Commission by July 10, 1997. Subsequently, the proposed settlement agreement was circulated to all registered intervenors for comments by July 18, 1997 and no comments were received. The Commission panel for this proceeding also received a copy of the proposed settlement agreement and letters of endorsement.
2 The impact of the applied-for rates and the proposed settlement agreement on customer costs for natural gas service (gross margin) is as follows:
1998 1999 2000 2001 2002 Rate Impact as a % of Gross Margin applied for in original application (May 5, 1997 revision) 6.40 3.40 2.70 1.90 1.60 Rate Impact as a % of Gross Margin (proposed settlement agreement) 1.85 2.00 2.00 N/A N/A The Commission notes that the participants expect that the gross margin rate impact on the CompanyÕs firm sales customers will be further reduced as a result of amortization of Gas Cost Reconciliation Account balances.
The Commission Panel has now reviewed the proposed settlement agreement as well as the letters of endorsement and comment from the ADR participants and has concluded that it should accept the settlement. Many of the elements within the proposed settlement agreement do not require special comment. However, the Commission did wish to express its views on several key issues that it noted in arriving at its decision and these Reasons for Decision provide those views.
Table 1 sets out key comparisons between the proposed settlement agreement and the Application as revised on May 5, 1997 by BC Gas.
3 Table 1 Key Aspects of proposed Settlement Agreement Proposed BC Gas Settlement Application Agreement Term 5 years 3 years Productivity 1998 - 1% 1998 - 2% 1999 - 1% 1999 - 2% 2000 - 1% 2000 - 3% Capital Structure 35% 33% Capitalization of 1998 - 10.27% 1998 - 20% Overhead 1999 - 10.27% 1999 - 20% 2000 - 10.27% 2000 - 16% The Commission has also created a new document called the Consolidated Settlement Document which incorporates editorial changes as proposed by BC Gas, and one other change as follows. In the subsection entitled "DSM Achievement Incentive" paragraph 6 originally read "The Company will apply to the Commission for funding of new programs where required". The Commission has changed this wording to "The Company will apply to the Commission for program changes where required". The Commission made the change as it concluded that the proposed wording may have arguably fettered the Commission in its discretion as provided for in the B.C. Utilities Commission Act.
Commission Comments on Key Issues: Term BC Gas applied for a five year term while the parties to the agreement agreed to a term of three years. The Commission considers a three year term is appropriate. It provides a long enough period to allow incentives to perform and at the same time balances the risks and other concerns with respect to changes that could occur over an extended period of time. The Commission is aware of some five year settlements which have been implemented for pipelines, but the Commission is of the view that the number of variables of change that can occur for a Local Distribution Company ("LDC") make it more appropriate to look at shorter terms. Pipelines typically have a limited number of shippers and more discrete cost projections.
4 Operating and Maintenance Costs ("O&M") The formula used to develop O&M costs has been previously utilized in the settlements with respect to BCÊGas and West Kootenay Power. From this experience, the Commission is satisfied that the methodology of adjusting a base cost for the growth in customers, productivity and inflation has provided appropriate targets for developing incentives. Attached to the Consolidated Settlement Document is a letter from Commission staff dated July 15, 1997 (Appendix B) which provides three examples of how productivity from capital projects will be eligible for inclusion within the O&M productivity targets.
Demand Side Management ("DSM") The DSM Achievement Incentive represents the second time the Commission has endorsed a mechanism to pursue cost effective DSM resources. However, it is still a new feature in the regulatory environment and very little knowledge has yet been accumulated as to its success or failure. The Inland/Industrial group, in their letter of acceptance of the settlement, pointed out that "the settlement agreement should explain that the DSM programs and incentives are to be accounted for within the rate classes to which they relate." In the Commission's view, this is adequately covered in the settlement agreement, paragraph 9 in the subsection entitled "DSM Achievement Incentive".
Capital Efficiency Mechanism This is the first significant capital efficiency mechanism that the Commission has approved. It is designed to provide an incentive for the utility to improve its costs of installing mains, services, meters and "other" plant. The range of incentive has been narrowed and the amount of the efficiency adjustment reduced from that originally filed in the Application. Due to the innovative nature of this particular mechanism, the Commission will be closely monitoring both the operation and results flowing from the use of the mechanism.
Overhead Capitalization The Commission is in agreement with the move to reduce the capitalization of overheads from 22.5% to 16% over the three year period. The change is directionally correct in that a mature utility such as BC Gas should be lowering its overhead charges as capital projects are reduced as a proportion of total expenditures, and the customers that are benefiting from the capital projects are paying for them in an accelerated manner. The Commission also believes that, in undertaking and achieving the changes in overheads capitalization, the reductions should not lead to significant rate impacts.
5 Annual Review and Quality of Service The Commission endorses the provision for an annual review. This allows the Commission to discharge its responsibility to maintain oversight of the utility and establish rates for each year. The Commission views the inclusion of service quality indicators as an important component of any incentive rate scheme. Such indicators ensure a utility will appropriately balance its obligation to provide safe, secure, high quality and non-discriminatory service to customers at the lowest rates possible while also providing an opportunity for shareholders to earn a fair return on their investment.
DATED at the City of Vancouver, in the Province of British Columbia this 25th day of July, 1997. ___________ O riginal s ig n e d b y: _ ______________ Lorna R. Barr, Deputy Chair and Acting Chair ___________O riginal s ig n e d b y: _ ______________ Ken L. Hall Commissioner ___________ O riginal s ig n e d b y: _ ______________ Paul G. Bradley Commissioner
1 CONSOLIDATED SETTLEMENT DOCUMENT BC GAS UTILITY LTD. 1998 - 2000 REVENUE REQUIREMENTS
Background BCÊGas Utility Ltd. (ÒBCÊGas") filed an application dated February 5, 1997 (the ÒApplicationÓ) with the British Columbia Utilities Commission (the ÒCommissionÓ, "BCUC") to establish the method for determining its revenue requirements for the years 1998 to 2002.
On February 10, 1997, the Commission issued Order G-13-97 setting a pre-hearing conference to commence FebruaryÊ28, 1997. Following the pre-hearing conference, the Commission issued Order No.ÊG-24-97 which included a regulatory agenda and timetable, setting a second pre-hearing conference for AprilÊ24, 1997 and a public hearing, if required, to commence JuneÊ3, 1997. Subsequent to the second pre-hearing conference the Commission issued Order No.ÊG-47-97 setting down a revised regulatory agenda and timetable rescheduling the public hearing to June 23, 1997. The regulatory agenda included public workshops regarding the Application; a process for filing information requests by parties and responses by BCÊGas; and an Alternative Dispute Resolution process ("ADR") to negotiate settlement of issues related to the Application. BCÊGas conducted public workshops on March 10, 11 and April 16. Information requests were filed and an additional 3 volumes of information responses and other data were provided by BCÊGas.
The negotiation sessions commenced on June 2, 1997 and continued on various dates through to JuneÊ26, 1997. Parties represented during the settlement negotiations were BCÊGas; Consumers Association of Canada (B.C.), B.C. Old Age PensionersÕ Organization, Council of Senior CitizenÕs Organizations of B.C., Federated Anti-Poverty Groups of B.C., Senior CitizenÕs Association of B.C., West End SeniorÕs Network, and the End Legislative Poverty & TenantÕs Right Coalition, represented by the British Columbia Public Interest Advocacy Centre; Lower Mainland Large Volume Gas Users Association; R.T.ÊOÕCallaghan & Associates (not available for the final two negotiating sessions); Fording Coal Ltd.; Association for the Advancement of Sustainable Energy Policy; Cominco Ltd., Weyerhaeuser Canada Ltd. and Celgar Pulp Company; and British Columbia Utilities Commission Staff.
Multi-Year Settlement This document sets out the terms of a three year settlement reached during the negotiations for setting the revenue requirements and rates of BCÊGas. The margin and rate impacts arising from the settlement are summarized on the schedules in Appendix A. The impacts are estimates and are based on several assumptions (subject to vary in the manner as discussed below). These are subject to change each year and relate to factors including:
a) the rate of return on common f) short and long term debt interest rates equity b) revenues g) rate base additions c) customer additions h) effect of capital efficiency mechanism d) taxes i) capital projects approved under applications for Certificate e) inflation of Public Convenience and Necessity (CPCNÕs)
2 The estimated gross margin impacts resulting from the settlement, as set out in Appendix A, are: 1998 Core Non-Core Rate Impact as a % of Gross Margin 1.85 Based on the underlying assumptions, the gross margin rate impact on Core market customers are expected to be further reduced to about 0% in each year as a result of amortization of GCRA balances.
The settlement is the culmination of negotiations among parties who have many diverse interests. The settlement represents numerous compromises among the parties and consists of a settlement package from which no part can be severed. The issues resolved in the settlement negotiations are numerous and complex. Taken as a whole, the settlement represents a balance of interests and an overall consensus among the participating parties.
Term The parties have agreed to a term of 3 years, namely the calendar years 1998, 1999 and 2000 (the ÒTermÓ).
Productivity Productivity shall be 2% in 1998, 2% in 1999 and 3% in 2000. References to ÒProductivityÓ in this document are references to those productivities except where stated otherwise.
Inflation Several elements of the revenue requirement determination methodology are dependent on an inflation rate forecast. The forecast rate of inflation to be applied will be the consumer price index forecast for British Columbia.
The BCÊGas proposal utilizing the forecasts for the next calendar year B.C. CPI by the Toronto-Dominion Bank, the Royal Bank of Canada, B.C. Ministry of Finance and the Conference Board of Canada (produced July to September) is accepted (hereinafter referred to as Òforecast B.C. CPIÓ).
References to ÒInflationÓ in this document are references to this forecast of B.C. CPI except where stated otherwise.
Capital Structure The common equity thickness for BCÊGas will remain at 33%. In respect to its preference shares which are redeemable in 1999 and 2000, BCÊGas will redeem such preference shares and replace the same with long term debt as redemption occurs.
Rate Of Return On Common Equity
1999 2000 Core Non-Core Core Non-Core 1.85 2.00 2.00 2.00 2.00
3 The rate of return on common equity for BCÊGas will be reset annually in accordance with the CommissionÕs automatic rate of return adjustment mechanism.
Gas Costs ¥ The gas costs of BCÊGas will be set in the manner currently approved by the Commission and customer rates will be adjusted in accordance with the currently approved gas cost allocation methodology.
¥ The Gas Cost Reconciliation Account will continue in the manner as approved by the Commission.
¥ The current Off System Incentive Plan will expire November 1, 1997. The parties agree to enter into discussions to determine the form of a successor gas cost incentive plan both for the short term and the long term. Any subsequent plan will be reviewed by interested parties before being submitted to the Commission for approval.
Revenues ¥ Both core market and non-core market revenues will be forecast each year in accordance with the methodologies employed by BCÊGas and will be reviewed at the Annual Review before being submitted.
¥ The methodology for forecasting residential and commercial sales is established but industrial sales forecasts will be reviewed annually.
¥ The Rate Stabilization Adjustment Mechanism (ÒRSAMÓ) will continue in the manner as approved by the Commission.
¥ Customer Additions will be forecast for each year of the Term, in accordance with the methodology employed by BCÊGas and approved by the Commission.
Operating & Maintenance Costs (ÒO&MÓ) The O & M levels for each year of the Term will be determined in accordance with the following formula:
[Base Cost x (1 + Growth in Customers - Productivity) x (1 + Inflation)] + Cost of Defined Required Incremental Activities
Where: Base Cost means: for 1998 this will be $142,760,000. e.g., 1998 O&M level base cost $142,760,000 x (1 + 2.10% - 2.00%) x 1.01 = $144,334,000 allowed O&M for 1998 excluding DRIA
4 for calculating the allowed O&M level for each subsequent year, the previous year's allowed O&M adjusted for projected actual customers will be the revised base to which customer growth, productivity and inflation will be added.
e.g., 1999 O&M level $144,334,000 x 1998 Projected Actual Customers 1998 Forecast Customers
= revised base x formula = 1999 allowed O&M excl. DRIA Growth in the forecast percentage growth in the average number of Customers means: customers for the year over the previous year. 1998 Projected The estimate of actual average customers during 1998 at Actual Customers: the November 1998 workshop 1998 Forecast The forecast of average customers during 1998 Customers: at the November 1997 workshop. In the event BCÊGas files an application for a revenue requirement increase in 2001, the Base Cost O&M level to be reflected in rates for 2001, before any increase for inflation and growth in customers, will be that arising from 2000, subject to exogenous factors and DRIA.
Productivity and Retail Markets Downstream of the Meter (RMDM) One instrument that the Company may use to achieve the targeted productivity gains is shedding, altering or reducing utility activities pursuant to the CommissionÕs policy on RMDM.
BCÊGas will be entitled to capture the benefits of improved efficiencies, reduced costs, or other financial savings achieved through RMDM, for the duration of the test period. Adjustments in utility rates during the test period arising from RMDM will be limited to reflecting the reduction of services that had been previously included in customersÕ bundled utility services. For further clarity the following hypothetical example distinguishes between improved efficiencies eligible for productivity and reduced services not eligible for productivity
Example: BCÊGas determines that outsourcing customer billing will reduce the cost of this function from $1.00/per customer to $0.79 and the third party will charge customers directly. The efficient gain of $0.21 is eligible for productivity but the rates will be rebased to reflect the $0.79 now paid directly to the third party.
O&M Productivity and Capital Projects Improved efficiencies, reduced costs, or other financial savings achieved by BCÊGas as a result of capital projects approved by the Commission pursuant to applications for Certificates of Public Convenience and Necessity may also be used by BCÊGas to achieve the targeted O&M productivity levels.
5 DEMAND SIDE MANAGEMENT AND INCENTIVES The Demand Side Management expenditure levels are forecast to remain constant over the Term, namely $1.624 million per year as a DRIA.
DSM Achievement Incentive The following DSM Achievement Incentive is to be implemented. It is designed to encourage BCÊGas to pursue cost effective demand side management resources.
1. Only energy efficiency programs are included in the mechanism. 2. A threshold level of 75% of the annual forecast gas savings must be achieved before any incentive is earned.
3. Calculation of incentive payments for gas savings greater than the threshold will be based on the net TRC benefits.
4. Recognizing that incremental energy savings become progressively more difficult to achieve, incentive payments will be earned according to the following schedule:
% of Annual Forecast Before Tax Earnings as % of GJ Savings_ ____TRC Net Benefits____ 75% up to 100% 3% 100% and above 5% 5. DSM results (both positive and negative) from programs developed within the Utility but which at some point are moved outside the utility will be included in the DSM calculation where those program results are tracked by the Utility. This is consistent with the CompanyÕs goal of maximizing customer value in offering cost effective, competitive DSM services.
6. In order to maximize DSM efficiencies, BCÊGas will be allowed to reallocate resources to modify existing programs, discontinue programs and develop new programs as the Company considers necessary. The Company will apply to the Commission for program changes where required.
7. A protocol for measuring DSM savings and TRC benefits needs to be established with the Commission and interested parties prior to the incentive mechanism taking effect.
8. The status of all DSM programs will be reviewed on a semi-annual basis with one of the reviews timed to coincide with the Annual Review of Service Quality Indicators.
9. The incentive mechanism will operate through the RSAM. The DSM Achievement Incentive operates outside of the Earnings Sharing Mechanism.
DSM Achievement Incentive Sample Calculations Three cases are provided below representing the range of possible incentive payments for BCÊGas achieving a minimum of 75% of forecast DSM gas savings.
6 Case A Assuming: 75% of forecast gas savings achieved total TRC net benefits = $2,581,000
Incentive = 3% of TRC net benefits (before tax) = $77,430 Case B Assuming: 100% of forecast gas savings achieved total TRC net benefits = $3,848,000
Incentive = 5% of TRC net benefits (before tax) = $192,400 Case C Assuming: 110% of forecast gas savings achieved total TRC net benefits = $4,350,000
Incentive = 5% of TRC net benefits (before tax) = $217,500 Restructuring Deferral Account A deferral account to record the costs incurred by BCÊGas in restructuring its work force to achieve enhanced productivity is to be created and is to be effective upon the approval by the Commission of this settlement. The costs recorded in this deferral account will be recovered in customer rates. The deferral account will not exceed $3 million.
The amortization of this deferral account for restructuring costs will be no greater than $1 million for each year of the Term.
New Revenue Opportunities The parties recognize that BCÊGas should not be dis-incented from seeking legitimate new revenue opportunities which would serve to reduce future revenue deficiencies. To the extent such opportunities arise, but require expenditures greater than those arising from the formula, such revenues and expenditures will be addressed during the Annual Review each year.
Capital Expenditures Capital expenditures for each year of the Term are established by class and by formula for certain of the classes. The classes are:
1. Mains - Recurring 5. System Improvements/Reinforcements 2. Services - Recurring 6. All Other Plant 3. Gas Measurement 7. Special Projects and CPCNÕs 4. Transmission Plant
Formulae for determining the expected capital expenditures for each year have been established for classes 1, 2, 3, 4, 5 and 6 as follows:
7 Note: the operation of the formulae for each class is shown for 1998 and 1999 and applies similarly to year 2000.
1. Mains - Recurring: 1998 Allowed Unit Cost = Base Unit Cost x (1+ Inflation - Productivity) 1998 Allowed Cost = 1998 Allowed Unit Cost x Service Additions x 21.6 metres of main per Service Addition
Where: Base Unit cost = $25.03/metre main Service Additions = 95.1% of forecast Customer Additions
1999 Allowed Unit Cost = 1998 Allowed Unit Cost x (1+ Inflation - Productivity) 1999 Allowed Cost = 1999 Allowed Unit Cost x Service Additions x 21.6 metres of main per Service Addition
2. Services: 1998 Allowed Unit Cost = Base Unit cost x (1 + Inflation - Productivity) 1998 Allowed Cost = 1998 Allowed Unit Cost x Service Additions Where: Base Unit cost = $884/Service Addition Service Additions = 95.1% of forecast Customer Additions
1999 Allowed Unit Cost = 1998 Allowed Unit Cost x (1+ Inflation - Productivity) 1999 Allowed Cost = 1999 Allowed Unit Cost x Service Additions 3. Meters: 1998 Allowed Unit Cost = Base Unit cost x (1 + Inflation - Productivity) 1998 Allowed Cost = 1998 Allowed Unit Cost x (Customer Additions + Meters Recalled)
Where: Base Unit cost = $242/meter Customer Additions = forecast Customer Additions Meters Recalled = forecast of meters to be Recalled
1999 Allowed Unit Cost = 1998 Allowed Unit Cost x (1+ Inflation - Productivity) 1999 Allowed Cost = 1999 Allowed Unit Cost x (Customer Additions + Meters Recalled)
4. Transmission Plant: 1998 Allowed Unit Cost = Base Unit cost x (1 + Inflation - Productivity) 1998 Allowed Cost = 1998 Allowed Unit Cost x Transmission System Forecast Peak Day Throughput
8 Where: Base Unit cost = $439.50/103m3 Transmission System Forecast Peak Day Throughput = forecast Transmission System Forecast Peak Day Throughput productivity = 1%
1999 Allowed Unit Cost = 1998 Allowed Unit Cost x (1+ Inflation - Productivity) 1999 Allowed Cost = 1999 Allowed Unit Cost x Transmission System Forecast Peak Day Throughput
5. System Improvements/Reinforcements: 1998 Allowed Unit Cost = Base Unit Cost x (1 + Inflation - Productivity) 1998 Allowed Cost = 1998 Allowed Unit Cost x Customers End of Year ("EOY") Where: Base Unit cost = $6.52/customer EOY Customer EOY = forecast end of year total customers productivity = 1%
1999 Allowed Unit Cost = 1998 Allowed Unit Cost x (1+ Inflation - Productivity) 1999 Allowed Cost = 1999 Allowed Unit Cost x Customers EOY 6. All Other Plant: The Allowed Costs for All Other Plant for each year of the Term will be set with an aggregate base level of $29,317,000 adjusted for Inflation each year less Productivity.
1998 Allowed Cost = $29,317,000 x (1+ Inflation - Productivity) 1999 Allowed Cost = 1998 Allowed Cost x (1+ Inflation - Productivity) BCÊGas has divided its capital expenditures into 4 categories. They are: A. Mains, Meters and Services B. System Integrity and Reliability C. All Other Plant D. CPCNÕs and Special Projects
9 The costs related to each category will be identified by the accounts prescribed by the BCUC Code of Accounts and the CompanyÕs sub-accounts as follows:
BCUC BC Gas Account Sub-Account (1) Category A
Distribution Plant - Service Installations Distribution Plant - Meter and Regulator Installations Distribution Plant - New Mains Distribution Plant - Main Installations General Distribution Plant - Meters
Category B LNG 440 - xxx Transmission Plant 449 xxx Distribution Plant - Main Corrosion Control 460 - 653 TS (3) Distribution Plant - System Improvements 469 657/659 Distribution Plant - Gate and Regulator 475 671 Stations 475 Distribution Plant - Telemetry 477 672 TS (3) 477 Category C All other BCUC Capital accounts and BC Gas sub-accounts
Category D N/A N/A (1) xxx includes all BC Gas sub-accounts in the BCUC account (2) Account 473-62X- Distribution Plant Renewals and Alteration (3) TS refers to charges from Technical Services to these Accounts
Special Projects and CPCNÕs Special Projects and Certificate of Public Convenience and Necessity ("CPCN") projects are capital projects which BCÊGas foresees as being required within the Term, but have not been developed sufficiently (certain of such projects were identified and described in the Application, they include: Southern Crossing, Automated Meter Reading, Single Vendor System, Interior LNG Satellite Facility, Customer Information Systems, Coastal Facilities, SCADA, muster stations), or projects which are not foreseen but could be required, such as the relocation of an urban transmission pipeline. Such projects are subject to approval by the Commission through applications for Certificates of Public Convenience and Necessity. To the extent such applications are approved and the capital projects undertaken, the capital project will form part of the rate base of BCÊGas in the year following the year in which the capital project is completed. BCÊGas will be entitled to accrue AFUDC on the expenditures associated with the capital project until the capital project is part of rate base.
473 xxx excl. 62X (2) 474 xxx 475 640 475 649 478 xxx
10 BCÊGas will be entitled to include the prudently incurred total capital expenditures and AFUDC in rate base at the commencement of the year following completion of the capital project.
Capital Efficiency Mechanism BCÊGas should be incented to employ capital more efficiently. A capital efficiency mechanism will operate as set out below. The categories in respect of which the mechanism will operate are categories A and C as described above.
To the extent the actual unit costs for a year vary from the Allowed Unit Costs for Category A, this difference is to be multiplied by the actual number of units (e.g. in the case of Mains - Recurring it would be actual metres of main installed for the year). This amount, together with the difference between the actual and allowed capital expenditures for that year in Category C, will form the basis for an efficiency adjustment to the utility rate base. This adjustment will be an aggregate dollar sum (the ÒCapital Efficiency AdjustmentÓ) which will be added or subtracted from the utility rate base. This mechanism will operate similarly in the case of positive and negative variances in unit costs.
The Capital Efficiency Incentive Adjustment to rate base will be phased out over three years. More specifically, in the immediately following year 66.7% of this variance will be an adjustment to the utility rate base and 33.3% in the subsequent year. This phasing will apply to each year of the Term so that the effect of variances in the second and third year of the Term will continue beyond the Term, e.g., phasing of the year 2000 variances will occur through the year 2002. For examples of the effect of the Capital Efficiency Mechanism, see CasesÊA1, B1, C1 and D1 in the response to ItemÊ6 of Information Request No.Ê1 of the Inland Industrial Group (VolumeÊ2, TabÊE6).
Depreciation and Amortization Expense The depreciation rates for BCÊGas currently approved by the Commission will continue. BCÊGas has indicated that it intends to file a depreciation study. The Commission will consider the study and any changes arising upon receipt and consideration of the study and the recommendation for changes in rates, if any, applied for by the Company.
Deferral Accounts The following deferral accounts are to be continued or created: ¥ Continuation of the debt interest deferral accounts. ¥ Continuation of the NGV conversion grants deferral account for 1998 - 2000 to be amortized over three years. ¥ Revenue requirement hearing costs to be amortized over three years. ¥ DSM expenditures for 1998 - 2000 to be amortized over three years. ¥ IRP costs for 1998 - 2000 to be amortized over three years. ¥ Deferral of property tax expense variances from forecast and amortized in the following year. 1996/1997 credits amortized as per Appendix A. ¥ BC Hydro DRIA - amortization as per Appendix A. ¥ DSM DRIA - amortization as per Appendix A. ¥ Continuation of Coastal Facilities relocation costs deferral account.
11 ¥ April 29, 1997 application for Phase 2 of BC 21 Power Smart costs - $303,000. ¥ Continuation of RSAM and GCRA accounts as described above. ¥ Deferral of restructuring costs as described above. Further details of the deferral accounts are found in Appendix A. Overhead Capitalization Pursuant to a term of the 1996 and 1997 Negotiated Settlement, BCÊGas filed a study on its overheads capitalization policy. The study recommended a significant reduction in the capitalization ratio. The impact of this study was to reduce overhead capitalization from 22.5% to 10.27% as shown in Volume 1, Section C, Tab 9-02 Revised (line 20) of the Application.
The BCÊGas study and proposal is accepted, however, the capitalization ratios will be limited to 20%, 20%, and 16% for the years 1998, 1999 and 2000 respectively based on total Gross O&M excluding DRIA. The Company may apply for additional reductions in overheads capitalized in subsequent revenue requirement filings.
Taxes Changes in taxes and similar costs will continue to be flowed through to customers with variances recorded in deferral accounts and amortized in rates in the following year.
The methodology for determination of the level of taxes for each year of the Term will be determined in the manner as specified in the Application, Volume 1, Section C Tabs 10 and 13 as revised.
Other Cost of Service Categories All other categories of the cost of service not specifically referred to above will be determined in the manner as specified in the Application, Volume 1 as revised.
Exogenous Factors During the Term, the BCÊGas cost of service will be adjusted for exogenous factors (positive or negative) which are beyond the full control of the utility including: judicial, legislative or administrative changes, orders and directions; changes in generally accepted accounting principles and rules, catastrophic events, bypass or other similar events imposed on BCÊGas which are not reflected in the rates of BCÊGas.
Earnings Sharing Mechanism BCÊGas will share equally with its customers earnings variances (positive or negative) between the authorized level of earnings as determined annually under this settlement and the actual earnings of the utility net of specific incentive programs; namely, the capital efficiency mechanism, the gas supply incentive plan and the DSM Achievement Incentive all of which will be considered to be non-utility income for the purposes of calculating the earnings of the utility.
12 The operation of the Earnings Sharing Mechanism is illustrated in Volume 1, Section C, Tab 15 of the Application.
Annual Reviews and Rate Adjustments BCÊGas will conduct an Annual Review of the operation of the settlement and rate adjustments prior to January 1 of each year of the Term with the Commission, its staff and interested parties. The Annual Review is a "proceeding" for purposes of participant cost awards. This process will provide the Commission and all interested parties an opportunity to remain informed about the activities of the Company. The Annual Review will attempt to obtain consensus on issues which must be decided by the Commission in advance of each fiscal year for the matters related to setting the rates for each year of the Term.
At the annual workshop to be held in November of each of the years 1998 through 1999, BCÊGas will present projections for the year that is ending and forecasts for the next year. The projections for the year that is ending will include:
¥ projected utility volumes and revenues ¥ projected utility expenses ¥ projected year-end plant balances and other rate base information ¥ projected deferral account balances and amortization ¥ projected year-end customers and other cost driver information ¥ projected utility earnings. Forecasts for the next year will include: ¥ forecast customer growth ¥ forecasts of cost drivers, such as peak day throughput ¥ forecast Inflation ¥ forecast utility volumes and revenues ¥ forecast utility expenses (revised allowed costs) ¥ forecast utility capital expenditures (revised allowed costs) ¥ forecast plant balances, deferral account balances and amortization to be included in rates. Cost drivers for the next year will be updated to reflect the forecasts relating to the year. Cost drivers for the next year will also be updated for projected variances between actual customer growth in the past year and the customer growth that had been forecast for that year.
Opening plant balances and other rate base items for the next year will be adjusted to reflect projected variances which are not included in the capital efficiency mechanism discussed above.
Service quality results will also be reviewed at the Annual Review. BCÊGas proposes to commence its workshops in November of 1997. At that workshop forecasts for 1998 will be presented, together with the projected number of customers as of January 1, 1998 and projected plant balances and other rate base information as of January 1, 1998. Cost drivers for 1998 will be updated to reflect the forecasts for 1998. Rates for 1998 will be set by the Commission based on
13 the projected opening rate base for 1998 and the forecasts for 1998 as agreed upon by the participants or as subsequently determined by the Commission.
Prior to each annual workshop, BCÊGas will provide interested parties and the Commission advance information regarding the projections and forecasts to be presented by BCÊGas at the workshop. This should be done 3 weeks prior to the workshop to allow parties to submit information requests and receive responses prior to the workshops.
In regard to projected year-end earnings, projected year end capital unit costs related to capital incentives presented for rate-making purposes in the November workshop BCÊGas will provide an update in April or May once actual results have been determined and adjustments will be made at the following year end. Incentives will be trued up to the actual results at that time.
Service Quality Indicators Principle: Maintenance of existing high levels of service quality is an important feature of this Settlement. However, it is recognized that variance in these statistics may occur due to random events or events beyond the full control of BCÊGas.
Process: ¥ Service Quality Indicators will be reviewed at the Annual Review in November of each year. ¥ Participants will be given an opportunity to argue whether a deviation from the benchmark for any of the Service Quality Indicators is significant enough to establish that service quality is deteriorating generally or in specific areas.
¥ For those concerns which are not resolved at the review, participants will retain the option to make submissions to the Commission that it should limit the payments which BCÊGas might otherwise earn from the financial incentives in this Settlement.
Service Quality Indicators: 1. Response time to emergency calls1. 2. Response time for answering service centre calls by a person. 3. Leaks per kilometre of distribution mains due to system deterioration. 4. Transmission system annual reportable incidents. 5. Number of third party distribution system damage incidents per 1000 housing starts2.
1 Applies to Coastal region only. Data for 1994 and 1995 not available. Measure for Interior region will be determined at a later date. 2 Data for 1994 is not available. Initial benchmark will be set using 2 years of data.
14 Annual Evaluation: ¥ Unless otherwise indicated, benchmarks will be calculated as the rolling average of the three years prior to the most current year; performance indicators will be calculated as the rolling average of the most current year plus the past two years.
¥ Each performance indicator will be evaluated on its own merits and a material deviation from the benchmark for any single performance indicator is sufficient basis to argue service quality deterioration and the need to limit payments to BCÊGas.
¥ Each performance indicator will be given equal weight. ¥ The onus of establishing that a benchmark has been met or why it is reasonable that it was not met rests with the utility.
¥ Interested parties should have access to the service quality evaluation prior to the Annual Review. ¥ Any party may argue that the benchmarks need to be modified
Appendix A 1998 - 2002 Revenue Requirements Settlement Illustrative Rate Impacts Summary
BC GAS UTILITY LTD. APPENDIX A SUMMARY 1998-2000 SETTLEMENT FOR THE YEARS 1998 TO 2000 ILLUSTRATIVE RATE IMPACTS ($000) SUMMARY
1998-2000 Particulars Volume 1 (Rev.) Difference Settlement (1) (2) (3) (4) 1998 Rate Base $ 1,581,623 $ (12,734) $ 1,568,889
Revenue Requirement $ 24,448 $ (17,552) $ 6,896 % Gross Margin Increase 6.37% -4.57% 1.80% Gross Margin (incl. Increase) $ 408,468 $ (17,552) $ 390,916
Operation and Maintenance Gross O&M excl. BC Hydro Costs $ 136,057 $ (2,273) $ 133,784 O&M Expense (Net) $ 133,335 $ (16,244) $ 117,091
Plant Additions - Capital Expenditures $ 93,474 $ (8,782) $ 84,692 - Overheads Capitalized 15,075 13,792 28,867 - All Other (WIP etc.) 2,445 0 2,445 Total $ 110,994 $ 5,010 $ 116,004
1999 Rate Base $ 1,635,694 $ (4,125) $ 1,631,569
Revenue Requirement $ 14,278 $ (6,570) $ 7,708 % Gross Margin Increase 3.44% -1.50% 1.94% Gross Margin (incl. Increase) $ 429,512 $ (24,421) $ 405,091
Operation and Maintenance Gross O&M excl. BC Hydro Costs $ 139,981 $ (4,638) $ 135,343 O&M Expense (Net) $ 137,133 $ (18,696) $ 118,437
Plant Additions - Capital Expenditures $ 95,829 $ (9,241) $ 86,588 - Overheads Capitalized 15,510 13,693 29,203 - All Other (WIP etc.) 8,420 0 8,420 Total $ 119,759 $ 4,452 $ 124,211
2000 Rate Base $ 1,703,373 $ (16,436) $ 1,686,937
Revenue Requirement $ 11,984 $ (3,961) $ 8,023 % Gross Margin Increase 2.73% -0.79% 1.94% Gross Margin (incl. Increase) $ 450,229 $ (28,891) $ 421,338
Operation and Maintenance Gross O&M excl. BC Hydro Costs $ 144,106 $ (8,468) $ 135,638 O&M Expense (Net) $ 141,126 $ (16,581) $ 124,545
Plant Additions - Capital Expenditures $ 135,013 $ (47,670) $ 87,343 - Overheads Capitalized 15,967 7,446 23,413 - All Other(WIP etc.) 140 0 140 Total $ 151,120 $ (40,224) $ 110,896
BC GAS UTILITY LTD. SUMMARY OF RATE INCREASE REQUIRED APPENDIX A FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1999 1998 - 2000 SETTLEMENT ($000) ILLUSTRATIVE RATE IMPACTS PAGE 01-01 1998 1999 --- Captive --- --- Captive --- Core Non-Core Non-Captive Total Core Non-Core Non Captive Total (1) (2) (3) (4) (5) (6) (7) (8) (9) RATE INCREASE REQUIRED Gas Sales and Transportation Revenue, At Prior Year's Rates $721,248 $33,574 $15,139 $769,961 $742,055 $33,520 $15,108 $790,683 Add - Other Revenue Related to Burrard Thermal / Centra BC (PCEC) 0 336 8,806 9,142 0 336 8,888 9,224 Total Revenue 721,248 33,910 23,945 779,103 742,055 33,856 23,996 799,907
Less - Cost of Gas (376,727) (6,192) (12,164) (395,083) (383,994) (6,366) (12,164)(402,524) Gross Margin $344,521 $27,718 $11,781 $384,020 $358,061 $27,490 $11,832 $397,383 ======== ======= ======= ====== ======= ======= ======= ======= Revenue Deficiency-Volume 1 (Rev) $22,628 $1,820 $0 $24,448 $13,260 $1,018 $0 $14,278 Difference (16,245) (1,307) 0 (17,552) (6,102) (468) 0 (6,570)
Revenue Deficiency - 1998-2000 Settlement 6,383 513 0 6,896 7,158 550 0 7,708 Refund of Deferred Gas Cost Credits (GCRA) 0 0 0 0 0 0 0 0 $6,383 $513 $0 $6,896 $7,158 $550 $0 $7,708 ======== ======= ======= ====== ======= ======= ======= =======
Rate Increase as a % of Gross Margin 1.85% 1.85% 0.00% 1.80% 2.00% 2.00% 0.00% 1.94% ======== ======= ======= ====== ======= ======= ======= =======
Rate Increase as a % of Total Revenue 0.88% 1.51% 0.00% 0.89% 0.96% 1.62% 0. 00% 0.96% ======== ======= ======= ====== ======= ======= ======= =======
. ILLUSTRATIVE RATE IMPACTS PAGE 01-01.1 2000 ----- Captive ----Particulars Core Non-Core Non-Captive Total (1) (2) (3) (4) (5) RATE INCREASE REQUIRED Gas Sales and Transportation Revenue, At Prior Year's Rates $765,421 $34,282 $15,082 $814,785
Add - Other Revenue Related to Burrard Thermal / Centra BC (PCEC) 0 336 8,885 9,221
Total Revenue 765,421 34,618 23,967 824,006 Less - Cost of Gas (392,051) (6,476) (12,164) (410,691) Gross Margin $373,370 $28,142 $11,803 $413,315 ======== ======= ======= ========
Revenue Deficiency - Volume 1 (Rev.) $11,144 $840 $0 $11,984 Difference (3,683) (278) 0 (3,961)
Revenue Deficiency - 1998-2000 Settlement 7,461 562 0 8,023 Refund of Deferred Gas Cost Credits (GCRA) 0 0 0 0 $7,461 $562 $0 $8,023 ======== ======= ======= =======
Rate Increase as a % of Gross Margin 2.00% 2.00% 0.00% 1.94% ======== ======= ======= ========
Rate Increase as a % of Total Revenue 0.97% 1.62% 0.00% 0,97% ======== ======= ======= ========
. ILLUSTRATIVE RATE IMPACTS PAGE 02-01
1998 1999 2000 Present Revised 1998 Revised 1999 Revised Description Rates Adj Rates Rates Adj Rates Rates Adj Rates (1) (2) (3) (4) (5) (6) (7) (8) (9) (10)
Plant in Service, Beginning $1,842,973 $0 $1,842,973 $1,949,177 $0 $1,949,177 $2,063,288 $0 $2,063,288 Additions 116,004 0 116,004 124 211 0 124 211 110 896 0 110,896 Disposals (9,800) 0 (9,800) (10,100) 0 (10,100) (10,400) 0 (10,400)
Plant in Service, Ending 1,949,177 0 1,949,177 2,063,288 0 2,063,288 2,163,784 0 2,163,784 Add - Intangible Plant 967 0 967 967 0 967 967 0 967
1,950,144 0 1,950,144 2,064,255 0 2,064,255 2,164,751 0 2,164,751 Contributions In Aid of Construction (73,964) 0 (73,964) (87,518) 0 (87,518) (102,314) 0 (102,314) Less - Accumulated Depreciation (314,089) 0 (314,089) (357,976) 0 (357,976) (405,567) 0 (405,567)
Net Plant in Service, Ending $1,562,091 $0 $1,562,091 $1,618,761 $0 $1,618,761 $1,656,870 $0 $1,656,870 ========== === ========== ========== == =========== ========= == =========
Net Plant in Service, Beginning $1,508,239 $0 $1,508,239 $1,562,091 $0 $1,562,091 $1,618,761 $0 $1,618,761 ========== === ========== ========== == =========== ========= == =========
Net Plant in Service, Mid-Year $1,535,165 $0 $1,535,165 $1,590,426 $0 $1,590,426 $1,637,816 $0 $1,637,816 Adjustment to 13-Month Average 0 0 0 0 0 0 0 0 Construction Advances (3,114) 0 (3,114) (2,336) 0 (2,336) (1,557) 0 (1,557) Work in Progress, No AFUDC 4,048 0 4,048 4 333 0 4,333 3,833 0 3,833 Unamortized Deferred Charges (7,215) 0 (7,215) (1 384) 0 (1,384) 4,167 0 4,167 Cash Working Capital 10,024 71 10,095 10,401(106) 10,295 10,881 40 10,921 Other Working Capital 29,910 0 29,910 30,235 0 30,235 31,757 0 31,757
Utility Rate Base $1,568,818 $71 $1,568,889 $1,631,675(106) $1,631,569 $1,686,897 40 $1,686,937 ========== === ========== ========== == =========== ========= == =========
. ILLUSTRATIVE RATE IMPACTS PAGE 02-02 UTILITY INCOME AND EARNED RETURN FOR THE YEARS ENDED DECEMBER 31, 1998, 1999 AND 2000 ($000) 1998 1999 2000 -Revised Rates- -Revised Rates- -Revised Rates- Present Revised 1998 Revised 1999 Revised Particulars Rates Revenue Total Rates Revenue Total Rates Revenue Total (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) ENERGY VOLUMES (TJ) Sales 158,624 0 158,624 161,357 0 161,357 164,379 0 164,379
Transportation 80,626 0 80,626 79,741 0 79,741 80,616 0 80,616 239,250 0 239,250 241,098 0 241,098 244,995 0 244,995 ======= ===== ======= ======= ===== ======= ======= ===== ======= Average Rate per GJ Sales $4.680 $4.720 $4.731 $4.776 $4.788 $4.833 Transportation $0.343 $0.348 $0.342 $0.348 $0.345 $0.351 Average $3.218 $3.247 $3.280 $3.311 $3.326 $3.358 UTILITY REVENUE Sales - Present Rates $742,344 $0 $742,344 $763,426 $0 $763,426 $786,984 $0 $786,984 - Increase 0 6,436 6,436 0 7,220 7,220 0 7,526 7,526 Transportation - Present Rates 27,617 0 27,617 27,257 0 27,257 27,801 0 27,801 - Increase 0 460 460 0 489 489 0 502 502 Total 769,961 6,896 776,857 790,683 7,708 798,391 814,785 8,023 822,808 ======= ===== ======= ======= ===== ======= ======= ===== ======= Cost of Gas Sold (Including Gas Lost) 395,083 0 395,083 402,524 0 402,524 410,691 0 410,691 Gross Margin 374,878 6,896 381,774 388,159 7,708 395,867 404,094 8,023 412,117 Restructuring Costs Amort. 555 0 555 555 0 555 555 0 555 Operation and Maintenance 117,091 0 117,091 118,437 0 118,437 124,545 0 124,545 Vehicle and FIS Leases 2,269 0 2,269 2,309 0 2,309 2,346 0 2,346 Property and Sundry Taxes 31,210 0 31,210 32,227 (1) 32,226 34,577 0 34,577 Depreciation and Amortization54,904 0 54,904 58,799 0 58,799 61,801 0 61,801 Other Operating Revenue (14,169) 0 (14,169) (14,399) 0 (14,399) (14,545) 0 (14,545) 191,860 0 191,860 197,928 (1) 197,927 209,279 0 209,279 Utility Income Before Taxes 183,018 6,896 189,914 190,231 7,709 197,940 194,815 8,023 202,838 Income Taxes 49,878 3,072 52,950 53,054 3,429 56,483 53,693 3,562 57,255 EARNED RETURN $133,140 3,824 $136,964 $137,177 4,280 $141,457 $141,122 $4,461 $145,583 UTILITY RATE BASE $1,568,818 $71 $1,568,889 $1,631,675 ($106) 1,631,569 1,686,897 $40 1,686,937 RATE OF RETURN ON UTILITY RATE BASE 8.49% 8.73% 8.41% 8.67% 8.37% 8.63%
. ILLUSTRATIVE RATE IMPACTS PAGE 02-03 INCOME TAXES / REVENUE DEFICIENCY FOR THE YEARS ENDED DECEMBER 31, 1998, 1999 AND 2000 ($000) 1998 1999 2000 -Revised Rates- -Revised Rates- -Revised Rates- Present Revised 1998 Revised 1999 Revised Particulars Rates Revenue Total Rates Revenue Total Rates Revenue Total (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) CALCULATION OF INCOME TAXES Earned Return $133 140 $3,824 $136,964 $137,177 $4,280 $141,457 $141,122 $4,461 $145,583 Deduct -Interest on Debt (73,711) 5 (73,706) (77,441) (4) (77,445) (84,252) (17) (84,269) Add- Non-Tax Ded. Expense (Net) 4,435 0 4,435 5,317 0 5,317 4,315 0 4,315 Accounting Income After Tax 63,864 3,829 67,693 65,053 4,276 69,329 61,185 4,444 65,629 Add (Deduct) - Timing Differences (9,757) 0 (9,757) (7,309) 0 (7,309) (2,875) 0 (2,875) Add - Large Corporation Tax 2,440 (76) 2,364 2,508 (86) 2,422 2,597 (90) 2,507
Taxable Income After Tax $56,547 $3,753 $60,300 $60,252 $4,190 $64,442 $60,907 $4,354 $65,261 ======= ===== ====== ====== ===== ====== ====== ===== ======
Income Tax Rate(Current Tax) 45.620% 45.620% 45.620% 45.620% 45.620% 45.620% 45.620% 45.620% 45.620% 1 - Current Income Tax Rate 54.380% 54.380% 54.380% 54.380% 54.380% 54.380% 54.380% 54.380% 54.380%
Taxable Income (L10 : L14) $103,985 $6,901 $110,886 $110,798 $7,705 $118,503 $112,003 $8,006 $120,009 ======= ===== ======= ======= ===== ======= ======= ===== ======= Income Tax-Current (L18xL13)$47,438 $3,148 $50,586 $50,546 $3,515 $54,061 $51,096 $3,652 $54,748 - Large Corporation Tax 2,440 (76) 2,364 2,508 (86) 2,422 2,597 (90) 2,507 Total $49,878 $3,072 $52,950 $53,054 $3,429 $56,483 $53,693 $3,562 $57,255 ======= ===== ======= ======= ===== ======= ======= ===== ======= REVENUE DEFICIENCY Earned Return $3,824 $136,964 $4,280 $141,457 $4,461 $145,583 Add - Income Taxes 3,072 52,950 3,429 56,483 3,562 57,255 Deduct - Utility Income Before Taxes, Present Rates 0 (183,018) 0 (190,231) 0(194,815) Corporate Capital Tax 0 0 (1) (1) 0 0 Deficiency After Corporate Capital Tax $6,896 $6,896 $7,708 $7,708 $8,023 $8,023 ===== ===== ===== ===== ===== =====
RETURN ON CAPITAL ILLUSTRATIVE RATE IMPACTS FOR THE YEARS ENDED DECEMBER 31, 1998, 1999 AND 2000 PAGE 02-04 ($000) Average ---- Capitalization ---- Embedded Cost Earned Particulars Reference Amount % Cost Component Return 1998 PRESENT RATES Long-Term Debt $692,562 44.15% 9.420X 4.16X Unfunded Debt 211,701 13.49% 4.000% 0.54% Preference Shares 146,845 9.36% 6.995% 0.65% Common Equity 517,710 33.00% 9.515% 3.14% $1,568,818 100.00% 8.49% 1998 REVISED RATES Long-Term Debt $692,562 44.14% 9.420% 4.16% $65,239 Unfunded Debt $211,701 Adjustment, Revised Rates 48 211,749 13.50% 4.000% 0.54% 8,470 Preference Shares 146,845 9.36% 6.995% 0.65% 10,272 Common Equity 517,733 33.00% 10.250% 3.38% 53,068 $1,568,889 100.00% 8.73% $137,049 1999 AT 1998 RATES Long-Term Debt $734 940 45.04% 9.288% 4.18% Unfunded Debt 229,546 14.07% 4.000% 0.56% Preference Shares 128,736 7.89% 6.946% 0.55% Common Equity 538,453 33.00% 9.455% 3.12% $1,631,675 100.00% 8.41% 1999 REVISED RATES Long-Term Debt $734,940 45.05% 9.288% 4.18% $68,261 Unfunded Debt $229,546 Adjustment, Revised Rates (71) 229,475 14.06% 4.000% 0.56% 9,179 Preference Shares 128,736 7.89% 6.946% 0.55% 8,942 Common Equity 538,418 33.00% 10.250% 3.38% 55,188 $1,631,569 100.00% 8.67% $141,570
2000 AT 1999 RATES Long-Term Debt $828,322 49.10% 9.016% 4.43% Unfunded Debt 239 399 14.19% 4.000% 0 57% Preference Shares 62 500 3.71% 6.631% 0 25% Common Equity 556,676 33.00% 9.455% 3.12% $1,686,897 100.00% 8.37% 2000 REVISED RATES Long-Term Debt $828,322 49.11% 9.016% 4.43% $74,682 Unfunded Debt $239,399 Adjustment, Revised Rates 27 239,426 14.19% 4.000% 0.57% 9,577 Preference Shares 62,500 3.70% 6.631% 0.25% 4,144 Common Equity 556,689 33.00% 10.250% 3.38% 57,061 $1,686,937 100.00% 8.63% $145,464
ILLUSTRATIVE RATE IMPACTS PAGE 03-04 BC GAS UTILITY LTD TARGET COSTS - CAPITAL EXPENDITURE SUMMARY FOR THE YEARS ENDING DECEMBER 31, 1998 TO 2000 ($000)
Target Costs Particulars Base Cost 1998 1999 2000 (1) (2) (3) (4) (5)
SUMMARY - TOTAL COST CATEGORY: A: MAINS, SERVICES & METERS $35,204 $36,246 $37,652 $38,445 B: SYSTEM INTEGRITY AND RELIABILITY 18,545 18,805 18,948 18,850
C: ALL OTHER PLANT 29,317 29,641 29,988 30,048 TOTAL - CATEGORIES A, B & C 83,066 84,692 86,588 87,343 D: SPECIAL PROJECTS 2300 0 0 0 0 8400 0 0 0 0 MISC. 0 0 0 0
TOTAL CAPITAL EXPENDITURES 83,066 84,692 86,588 87,343 TOTAL PER 1998-2002 VOL. 1, PAGE 03-04 (REV) 89,908 93,474 95,829 135,013 INCREASE (DECREASE) ($6,842) ($8,782) ($9,241) ($47,670) TOTAL CAPITAL EXPENDITURES - REAL ($1997) $83,066 $83,853 $84,882 $84,774
CAPITAL EXPENDITURE/PLANT ADDITIONS SUMMARY 1998 - 2000 SETTLEMENT BC GAS UTILITY LTD. ILLUSTRATIVE RATE IMPACTS ($000) PAGE 03-05
Target Costs Particulars Base Cost 1998 1999 2000 (1) (2) (3) (4) (5)
CAPITAL EXPENDITURES A: MAINS, SERVICES & METERS $35,204 $36,246 $37,652 $38,445
B: SYSTEM INTEGRITY AND RELIABILITY 18,545 18,805 18,948 18,850
C: ALL OTHER PLANT 29,317 29,641 29,988 30,048 D: SPECIAL PROJECTS 0 0 0 0 TOTAL CAPITAL EXPENDITURES 83,066 84,692 86,588 87,343
WORK IN PROGRESS Add - Opening WIP 16,100 15,205 8,380 Less - Closing WIP (15,205) (8,380) (9,770)
Add - AFUDC 1,550 1,595 1,530 Add - O'H Capitalized 28,867 29,203 23,413 SUBTOTAL - PLANT ADDITIONS 116,004 124,211 110,896 Add - 1996 and 1997 CPCN's 6,618 . TOTAL PLANT ADDITIONS 122,622 124,211 110,896
TOTAL PER 1998 - 2002 VOL. 1, PAGE 03-05 (REV.) 117,612 119,759 151,120 INCREASE (DECREASE) $5,010 $4,452 ($40,224)
1998 - 2000 SETTLEMENT 1998 PAGE 03-11.1
UNAMORTIZED DEFERRED CHARGES AND AMORTIZATION FOR THE YEAR ENDED DECEMBER 31, 1998 ($000)
Forecast Amortization Mid-Year Balance Gross Less- Net ------------- Balance Average Particulars Account 12/31/97 Additions Taxes Additions Expense Other 12/31/98 1998 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) Deferred Interest #179-008 $0 $0 $0 $0 $0 $0 $0 $0
Market Rebate Incentive - Water Heater Grants #179-052 402 0 0 0 (100) 0 302 352 - Commercial & Multi-Family #179-013 103 0 0 0 (55) 0 48 75
NGV Conversion Grants #179-018 20 0 0 0 (20) 0 0 10 NGV Conversion Grants 1996-1997 1,534 0 0 0 (527) 0 1,007 1,271 NGV Conversion Grants 1998-2002 0 1,500 (668) 832 0 0 832 416
Local Gas Development #179-053 2,908 0 (90) (90) (564) 0 2,254 2,581 Fraser Valley Gas Exploration #179-092 457 0 0 0 (91) 0 366 411 Revenue Req. Hearing-1998-2002 179-141 133 0 0 0 (44) 0 89 111
Demand Side Management G-69-93 179-063 45 0 0 0 (33) 0 12 28 Demand Side Management 1996-97 327 0 0 0 (110) 0 217 272 Demand Side Management 1998-2002 0 1,585 (705) 880 0 0 880 440
Integrated Resource Plan G-69-93 179-064 133 0 0 0 (77) 0 56 94 Integrated Resource Plan G-60-94 147 0 0 0 (49) 0 98 123 Integrated Resource Plan 1996-97 108 0 0 0 (36) 0 72 90 Integrated Resource Plan 1998-2002 0 100 (45) 55 0 0 55 28
Residential Thermostat Program #179-109 30 0 0 0 (11) 0 19 24 Property Tax Deferral #179-062 (890) 0 0 0 0 0 (890) (890) Westar Receivable #179-069 134 0 0 0 (27) 0 107 121
UNAMORTIZED DEFERRED CHARGES AND AMORTIZATION 1998 FOR THE YEAR ENDED DECEMBER 31, 1998 PAGE 03-11.2 ($000)
Forecast Amortization Mid-Year Balance Gross Less- Net ------------- Balance Average Particulars Account 12/31/97 Additions Taxes Additions Expense Other 12/31/98 1998 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10)
G.C.R.A. #179-088 (13,500) 0 0 0 0 4,500 (9,000) (11,250) G.C.R.A. Interest #179-188 0 0 0 0 0 0 0 0
Offsystem Sales Coord. Center 179-120 23 0 0 0 (10) 0 13 18 Revelstoke Propane Cost #279-024 293 0 0 0 0 (293) 0 147 B.C. Hydro DRIA #179-144 (823) 0 0 0 0 0 (823) (823) DSM DRIA #179-142 (489) 0 0 0 0 0 (489) (489)
Recovery of Non-Utility Service #279-063 (98) 0 0 0 98 0 0 (49) RSAM #179-089 (7,500) 0 0 0 0 2,500 (5,000) (6,250)
NGV B.C. Transit Grants #179-105 461 0 0 0 (159) 0 302 382 BC21 Power Smart Program #179-119 444 0 0 0 (222) 0 222 333 BC21 Power Smart Phase 2 168 0 0 0 (34) 0 134 151
Coastal Facilities (#C-6-95) - Relocation 2,387 1,049 (467) 582 (686) 0 2,283 2,335 - Lochburn NBV Amortization 1,108 0 0 0 (369) 0 739 924 - Fraser Valley NBV Amortization 878 0 0 0 (176) 0 702 790
Organizational Restructuring #179-132 480 0 0 0 (96) 0 384 432 Non-Core Margin Deferral #179-135 214 0 0 0 0 (214) 0 107
Main Extension Hearing Costs #179-138 18 0 0 0 (18) 0 0 9 1995 IRP Participant A~ards #179-140 7 0 0 0 (7) 0 0 4 Gain on Sale of Kamloops Property 279-001 (193) 0 0 0 193 0 0 (97)
Restructuring Costs 0 3,000 (1,335) 1,665 (555) 0 1,110 555 Total Deferred Charges for Rate Base ($10,531) $7,234 ($3,310) 3,924 ($3,785) $6,493 ($3,899) ($7,215) ======= ===== ===== ===== ===== ===== ======= =====
UNAMORTIZED DEFERRED CHARGES AND AMORTIZATION 1998 - 2000 SETTLEMENT FOR THE YEAR ENDED DECEMBER 31, 1999 1999 ($000) PAGE 03-11.3
Forecast Amortization Mid-Year Balance Gross Less- Net ------------- Balance Average Particulars Account 12/31/98 Additions Taxes Additions Expense Other 12/31/99 1999 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10)
Deferred Interest #179-008 $0 $0 $0 $0 $0 $0 $0 $0 Market Rebate Incentive - Water Heater Grants #179-052 302 0 0 0 (100) 0 202 252 - Commercial & Multi-Family 179-013 48 0 0 0 (48) 0 0 24
NGV Conversion Grants #179-018 0 0 0 0 0 0 0 0 NGV Conversion Grants 1996-1997 1,007 0 0 0 (527) 0 480 743 NGV Conversion Grants 1998-2002 832 1,500 (668) 832 (277) 0 1,387 1,109
Local Gas Development #179-053 2,254 0 (81) (81) (544) 0 1,629 1,942 Fraser Valley Gas Exploration 179-092 366 0 0 0 (91) 0 275 320 Revenue Req. Hearing-1998-2002 179-141 89 0 0 0 (44) 0 45 67
Demand Side Management G-69-93 179-063 12 0 0 0 (12) 0 0 6 Demand Side Management 1996-97 217 0 0 0 (109) 0 108 163 Demand Side Management 1998-2002 880 1,585 (705) 880 (293) 0 1,467 1,174
Integrated Resource Plan G-69-93 179-064 56 0 0 0 (56) 0 0 28 Integrated Resource Plan #G-60-94 98 0 0 0 (49) 0 49 73 Integrated Resource Plan 1996-97 72 0 0 0 (36) 0 36 54 Integrated Resource Plan 1998-2002 55 100 (45) 55 (18) 0 92 74
Residential Thermostat Program #179-109 19 0 0 0 (11) 0 8 14 Property Tax Deferral #179-062 (890) 0 0 0 0 429 (461) (676) Westar Receivable #179-069 107 0 0 0 (26) 0 81 93
UNAMORTIZED DEFERRED CHARGES AND AMORTIZATION 1998 - 2000 SETTLEMENT FOR THE YEAR ENDED DECEMBER 31, 1999 1999 ($000) PAGE 03-11.4
Forecast Amortization Mid-Year Balance Gross Less- Net ------------- Balance Average Particulars Account 12/31/98 Additions Taxes Additions Expense Other 12/31/99 1999 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10)
G.C.R.A. #179-088 (9,000) 0 0 0 0 4,500 (4,500) (6,750) G.C.R.A. Interest #179-188 0 0 0 0 0 0 0 0
Offsystem Sales Coor. Center #179-120 13 0 0 0 (13) 0 0 7 Revelstoke Propane Cost #279-024 0 0 0 0 0 0 0 0 B.C. Hydro DRIA #179-144 (823) 0 0 0 0 0 (823) (823) DSM DRIA #179-142 (489) 0 0 0 0 0 (489) (489)
Recovery of Non-Utility Service 279-063 0 0 0 0 0 0 0 0 RSAM #179-089 (5,000) 0 0 0 0 2,500 (2,500) (3,750)
NGV B.C. Transit Grants #179-105 302 0 0 0 (159) 0 143 223 BC21 Power Smart Program #179-119 222 0 0 0 (222) 0 0 111 BC21 Power Smart Phase 2 134 0 0 0 (34) 0 100 117
Coastal Facilities (#C-6-95) - Relocation 2,283 1,049 (467) 582 (802) 0 2,063 2,173 - Lochburn NBV Amortization 739 0 0 0 (369) 0 370 555 - Fraser Valley NBV Amortization 702 0 0 0 (176) 0 526 614
Organizational Restructuring #179-132 384 0 0 0 (96) 0 288 336 Non-Core Margin Deferral #179-135 0 0 0 0 0 0 0 0
Main Extension Hearing Costs #179-138 0 0 0 0 0 0 0 0 1995 IRP Participant Awards #179-140 0 0 0 0 0 0 0 0 Gain on Sale of Kamloops Property #279-001 0 0 0 0 0 0 0 0
Restructuring Costs 1,110 0 0 0 (555) 0 555 833 Total Deferred Charges for Rate Base ($3,899) $4,234 ($1,966) 2,268 ($4,667) $7,429 $1,131 ($1,384) ====== ====== ====== ===== ====== ====== ====== ======
UNAMORTIZED DEFERRED CHARGES AND AMORTIZATION 1998 - 2000 SETTLEMENT FOR THE YEAR ENDED DECEMBER 31, 2000 2000 ($000) PAGE 03-11.5
Forecast Amortization Mid-Year Balance Gross Less- Net ------------- Balance Average Particulars Account 12/31/99 Additions Taxes Additions Expense Other 12/31/00 2000 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10)
Deferred Interest #179-008 $0 $0 $0 $0 $0 $0 $0 $0 Market Rebate Incentive - Water Heater Grants #179-052 202 0 0 0 (100) 0 102 152 - Commercial & Multi-Family 179-013 0 0 0 0 (42) 0 (42) (21)
NGV Conversion Grants #179-018 0 0 0 0 0 0 0 0 NGV Conversion Grants 1996-1997 480 0 0 0 (480) 0 0 240 NGV Conversion Grants 1998-2002 1,387 1,500 (668) 832 (555) 0 1,664 1,526
Local Gas Development #179-053 1,629 0 (73) (73) (520) 0 1,036 1,332 Fraser Valley Gas Exploration 179-092 275 0 0 0 (91) 0 184 230
Revenue Req. Hearing-1998-2002 179-141 45 0 0 0 (45) 0 0 23 Demand Side Management G-69-93 179-063 0 0 0 0 0 0 0 0 Demand Side Management 1996-97 108 0 0 0 (108) 0 0 54 Demand Side Management 1998-2002 1,467 1,585 (705) 880 (587) 0 1,760 1,613
Integrated Resource Plan G-69-93 179-064 0 0 0 0 0 0 0 0 Integrated Resource Plan #G-60-94 49 0 0 0 (49) 0 0 25 Integrated Resource Plan 1996-97 36 0 0 0 (36) 0 0 18 Integrated Resource Plan 1998-2002 92 100 (45) 55 (37) 0 110 100
Residential Thermostat Program #179-109 8 0 0 0 (8) 0 0 4 Property Tax Deferral #179-062 (461) 0 0 0 0 461 0 (231) Westar Receivable #179-069 81 0 0 0 (27) 0 54 68
UNAMORTIZED DEFERRED CHARGES AND AMORTIZATION 1998 - 2000 SETTLEMENT FOR THE YEAR ENDED DECEMBER 31, 2000 2000 ($000) PAGE 03-11.6
Forecast Amortization Mid-Year Balance Gross Less- Net ------------- Balance Average Particulars Account 12/31/99 Additions Taxes Additions Expense Other 12/31/009 2000 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10)
G.C.R.A. #179-088 (4,500) 0 0 0 0 4,500 0 (2,250) G.C.R.A. Interest #179-188 0 0 0 0 0 0 0 0
Offsystem Sales Coor. Center #179-120 0 0 0 0 0 0 0 0 Revelstoke Propane Cost #279-024 0 0 0 0 0 0 0 0 B.C. Hydro DRIA #179-144 (823) 0 0 0 823 0 0 (412) DSM DRIA #179-142 (489) 0 0 0 489 0 0 (245)
Recovery of Non-Utility Service 279-063 0 0 0 0 0 0 0 0 RSAM #179-089 (2,500) 0 0 0 0 2,500 0 (1,250)
NGV B.C. Transit Grants #179-105 143 0 0 0 (143) 0 0 71 BC21 Power Smart Program #179-119 0 0 0 0 0 0 0 0 BC21 Power Smart Phase 2 100 0 0 0 (34) 0 66 83
Coastal Facilities (#C-6-95) - Relocation 2,063 1,049 (467) 582 (918) 0 1,727 1,895 - Lochburn NBV Amortization 370 0 0 0 (370) 0 0 185 - Fraser Valley NBV Amortization 526 0 0 0 (176) 0 350 438
Organizational Restructuring #179-132 288 0 0 0 (96) 0 192 240 Non-Core Margin Deferral #179-135 0 0 0 0 0 0 0 0
Main Extension Hearing Costs #179-138 0 0 0 0 0 0 0 0 1995 IRP Participant Awards #179-140 0 0 0 0 0 0 0 0 Gain on Sale of Kamloops Property #279-001 0 0 0 0 0 0 0 0
Restructuring Costs 555 0 0 0 (555) 0 555 278 Total Deferred Charges for Rate Base ($1,131) $4,234 ($1,958) 2,276 ($3,665) $7,461 $7,203 ($4,167) ====== ====== ====== ===== ====== ====== ====== ======
OPERATING & MAINTENANCE EXPENSE ILLUSTRATIVE RATE IMPACTS ($000) PAGE 09-02 Target Costs Particulars 1998 1999 2000 (1) (2) (3) (4) Cost Drivers / Escalators Average No. of Customers 734,710 750,609 767,317 Growth % 2.10% 2.16% 2.23% Productivity Improvement Factor (PIF) 2.00% 2.00% 3.00% Inflation (CPI) 1.00% 1.00% 1.00% O&M (Gross) O&M $133,784 $135 343 $135,638 BC Hydro Service Agreement 10,550 10 673 10,696 Total 144,334 146,016 146,334 DRIA's - DSM / IRP 1,624 1,624 1,624 - Other - - - 1,624 1,624 1,624 Total Gross O&M 145,958 147,640 147,958
O'H Capitalized 20.00% 20.00% 16.00% O&M 28,867 29,203 23,413 BC Hydro Senvice Agreement DRIA's - DSM / IRP - - - - Other - - -Total O'H Capitalized 28,867 29,203 23,413 Total Per 1998 - 2002 Vol. 1, Page 09-02 (Rev) 15,075 15,510 15,967 Difference 13,792 13,693 7,446 O&M Expense (Net) O&M 115,467 116,813 122,921 DRIA's - DSM/IRP 1,624 1,624 1,624 - Other - - -Total O&M Expense $117,091 $118,437 $124,545 Total per 1998-2002 Vol.1, Page 09-02 (Rev.) $133,335 $137,133 $141,126 Difference ($16,244) ($18,696) ($16,581)
Appendix B Commission Staff letter of July 15, 1997
APPENDIX B Page 1 of 2 a SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C. CANADA V6Z 2N3 WILLIAM J. GRANT TELEPHONE: (604) 660-4700 EXECUTIVE DIRECTOR, BC TOLL FREE: 1-800-663-1385 REGULATORY AFFAIRS & PLANNING FACSIMILE: (604) 660-1102 VIA FACSIMILE July 15, 1997 Mr. Jim Quail The British Columbia Public Interest Advocacy Centre 815 - 815 West Hastings Street Vancouver, B.C. V6C 1B4 Dear Jim: Re: BC Gas Utility Ltd. Revenue Requirements Application Thank you for your two letters of July 10, 1997 indicating your consent to the terms of the proposed settlement document along with the letter recording your interpretation of two of the provisions of the proposed settlement of this matter. With respect to O&M productivity gains from capital projects the settlement document records the method for recognizing productivity at page 5. During our discussions of this matter we explored several examples including the Southern Crossing Project and the construction of a new operations building in the Lower Mainland. In the case of the Southern Crossing Project the approval and construction of the pipeline would come into rate base the year following its completion. A number of impacts would be felt including funding of the rate base addition, changes to Westcoast or other upstream transportation suppliers, new gas supply options at hopefully more efficient prices, and the potential of third party revenues from the use of spare capacity in the pipeline. None of these components would affect the O&M productivity levels unless BCÊGas were also able to obtain a direct O&M productivity improvement from the existence of this new capital edition. If that were to occur it would be available to assist BCÊGas in meeting its O&M productivity targets during the remaining term of the three year agreement. The completion of a new operations centre in the Lower Mainland is probably a better example of where some real O&M productivity might occur. In this case, BC Gas may seek approval and then build the new operations centre allowing it to sell parts of the Boundary/Lougheed property and relocate personnel from a number of leased premises. Presumably, there would also be some down sizing of space requirements at the downtown office. The effect would be that the new capital costs would flow into rate base the year following their completion and the proceeds of the sale of the Boundary/Lougheed property would reduce rate base. These changes would not affect the O&M productivity levels but the Company will likely obtain a number of efficiencies resulting from the more efficient housing of employees, the avoidance of travel, and such matters as the updating of equipment. These benefits are all available to assist the Company in meeting its O&M productivity targets for whatever remaining period exists in the three year settlement. . . ./2
APPENDIX B Page 2 of 2 2 A third potentially significant CPCN could be the completion of a new customer information system allowing consolidated billing and other links to the financial and work order systems within BC Gas. As with the other projects the capital costs related to the new system would come into rate base in the year following completion. At the same time the Unisys system would be retired from rate base and the billing contract with B.C. Hydro would be terminated. These changes would not effect the O&M productivity targets, but the existence of the new customer information systems would likely have a profound impact on BCÊGas operations, allowing improved information and efficiencies in numerous O&M areas of the Company. All of these O&M benefits would assist the Company in meeting the O&M targets for the remaining period of the three year settlement. I hope this assists by providing an assessment of three of the more significant capital projects which may come to realization late in the three year settlement horizon. Yours truly, Original signed by: W.J. Grant WJG/lm cc: Mr. D.M. Masuhara, Vice President Legal and Regulatory Affairs BC Gas Utility Ltd. Mr. David Bursey, Bull, Housser & Tupper Mr. Chris Weafer, Owen Bird Ms. Carol Reardon, Heenan Blaikie Mr. Dave Newlands, Fording Coal, c/o Pacific Western Energy Products and Services Inc Mr. R. OÕCallaghan, RT O'Callaghan & Associates Inc BCG/98-2002PBR/NS Pkge/PIAC O&M Queries