Orders

ROBERT J. PELLATT COMMISSION SECRETARY Commission.Secretary@bcuc.com web site: http://www.bcuc.com

Log No. 1482 VIA FACSIMILE/EMAIL January 14, 2003 Mr. Geoff Higgins Manager, Regulatory Affairs Centra Gas British Columbia Inc. 1675 Douglas Street P.O. Box 3777 Victoria, B.C. V8W 3V3 Dear Mr. Higgins: Re: Centra Gas British Columbia Inc. Approval of 1999 to 2001 Actual Revenue Requirements and Revenue Deficiencies ______________and 2003 to 2005 Forecast Revenue Requirements____________ Enclosed is Commission Order No. G-2-03 approving the Negotiated Settlement issued on December 24, 2002 with respect to the above noted Applications.

Yours truly, Original signed by: Robert J. Pellatt cms Enclosure cc: Registered Intervenors/Interested Parties Via Facsimile/Email CG/2003-05RR/NSP Settlement Approved

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C. CANADA V6Z 2N3 TELEPHONE: (604) 660-4700 BC TOLL FREE: 1-800-663-1385 FACSIMILE: (604) 660-1102

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 ER N U M B E R G-2-03 TELEPHONE: (604) 660-4700 SIXTH FLOOR, 900 HOWE STREET, BOX 250 BC TOLL FREE: 1-800-663-1385 VANCOUVER, B.C. V6Z 2N3 CANADA FACSIMILE: (604) 660-1102 web site: http://www.bcuc.com IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 and the Special Direction to the British Columbia Utilities Commission by the Lieutenant Governor in Council through Order in Council No. 1510, dated December 13, 1995 and An Application by Centra Gas British Columbia Inc. for Approval of 1999 to 2001 Actual Revenue Deficiencies and 2003 to 2005 Forecast Revenue Requirements BEFORE: P. Ostergaard, Chair ) P.G. Bradley, Commissioner ) January 9, 2003 K.L. Hall, Commissioner ) O R D E R WHEREAS: A. On July 31, 2002, Centra Gas British Columbia Inc. (“Centra Gas”) applied, pursuant to Section 23 of the Utilities Commission Act (“the Act”) and the Special Direction (Order in Council 1510, 1995), for approval of its 1999 to 2001 actual revenue deficiencies and its forecast 2003 to 2005 revenue requirements for its Vancouver Island and Sunshine Coast service areas. Centra Gas proposed that the Application be reviewed through a Negotiated Settlement Process; and

B. By Order No. G-76-02 the Commission determined that the Application should proceed to a Negotiated Settlement Process and established a regulatory timetable; and

C. On November 25 and 26, 2002, a Settlement Conference was held in Victoria, B.C. Representatives from the Commission staff, British Columbia Hydro and Power Authority (“B.C. Hydro”), the Vancouver Island Gas Joint Venture (“VIGJV”), the British Columbia Public Interest Advocacy Centre (“BCPIAC”), Calpine Island Cogeneration, the Ministry of Energy and Mines and the Vancouver Island Public Sector Natural Gas Consumers Group (“Public Sector Consumers”) attended, all of whom participated in settlement discussions; and

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B R I T IS H C O L U M B I A U T I L I T I E S C O M M I S S I O N

2 D. A Negotiated Settlement was reached among the participants and circulated to all Registered Intervenors, Interested Parties and the Commission on December 24, 2002; and

E. The Commission received letters on the Negotiated Settlement from Centra Gas, BCPIAC, B.C. Hydro, the Public Sector Consumers and the VIGJV; and

F. The Commission has reviewed the Negotiated Settlement for Centra Gas’ 1999 to 2001 Actual Revenue Deficiencies and the 2003 to 2005 Forecast Revenue Requirements and finds that it should be approved.

NOW THEREFORE the Commission approves for Centra Gas the Negotiated Settlement as issued on December 24, 2002 and attached as Appendix A to this Order.

DATED at the City of Vancouver, in the Province of British Columbia, this 14 th day of January 2003. BY ORDER Original signed by: Peter Ostergaard Chair Attachment

Order/CGBC-2003/05 RR Neg.Sttmt

O R D E R N U M B E R G-2-03

APPENDIX A to Order No. G-2-03 Page 1 of 34 WILLIAM J. GRANT SIXTH FLOOR, 900 HOWE STREET, BOX 250 EXECUTIVE DIRECTOR, VANCOUVER, B.C. CANADA V6Z 2N3 REGULATORY AFFAIRS & PLANNING TELEPHONE: (604) 660-4700 bill.grant@bcuc.com BC TOLL FREE: 1-800-663-1385 web site: http://www.bcuc.com FACSIMILE: (604) 660-1102 Log No. 1482 C O N F I D E N T I A L VIA FACSIMILE December 19, 2002 Dear Participants: Re: Centra Gas British Columbia Inc. (“Centra Gas”) Negotiated Settlement Approval of 1999 to 2001 Actual Revenue Requirements and Revenue Deficiencies ______________and 2003 to 2005 Forecast Revenue Requirements____________ Enclosed is the Negotiated Settlement Agreement on the Centra Gas Application for Approval of 1999 to 2001 Actual Revenue Deficiencies and 2003 to 2005 Forecast Revenue Requirements. Thank you for your edits to the draft Settlement document which have been incorporated in this final Agreement. It was evident from the responses received from some of the participants on December 16, 2002 that further edits were required. Those edits have now been incorporated in this document and are shown in a black-lined version for your reference. Centra Gas has updated the supporting schedules to the Negotiated Settlement Agreement and has included a written explanation. Please review the Negotiated Settlement Agreement and provide your written correspondence confirming your acceptance of this settlement by Monday, December 23, 2002. On Tuesday, December 24, 2002, the Negotiated Settlement Agreement and letters of comment from the participants will be made public and forwarded to the Commission for its review. Prior to consideration by the Commission, intervenors who did not participate in the settlement negotiations will be requested to provide to the Commission their comments on the settlement package by January 6, 2003. Thereafter, the Commission will consider the settlement package. A public hearing may not be required unless there is significant opposition to the proposed settlement. Yours truly,

W.J. Grant WJG/cms Attachments cc: Mr. Geoffrey Higgins Manager, Regulatory Affairs Centra Gas British Columbia Inc.

APPENDIX A to Order No. G-2-03 Page 2 of 34 C O N F I D E N T I A L

IN THE MATTER OF the Utilities Commission Act, RSBC 1996, c. 473, Section 23 - and -IN THE MATTER OF the Special Direction to the British Columbia Utilities Commission issued by the Lieutenant Governor in Council through Order in Council 1510, dated December 13, 1995 - and -IN THE MATTER OF an Application by Centra Gas British Columbia Inc. for approval of its 1999, 2000 and 2001 Actual Revenue Requirements and Revenue Deficiencies, and 2003, 2004 and 2005 Forecast Revenue Requirements NEGOTIATED SETTLEMENT On July 31, 2002, Centra Gas British Columbia Inc. (“Centra Gas” or the “Company”) filed a Revenue Requirements Application (the “Application”) with the British Columbia Utilities Commission (the “Commission”). The Application was for approval of Centra Gas’ actual revenue requirements and revenue deficiencies for 1999 through 2001, and forecast revenue requirements for the test period 2003 through 2005. The Application was Phase one of a two phase process to establish future test period costs (Phase 1) and an appropriate rate design for customers of Centra Gas, effective January 1, 2003 (Phase 2). Commission Order No. G-71-02 established a workshop and pre-hearing conference for both the Phase 1 and Phase 2 Applications, which was held in Nanaimo, B.C. on October 22, 2002. The pre-hearing conference provided a forum for review of the Applications, determination of issues to be resolved, establishment of the regulatory agenda and timetable to review the Applications, and determination of whether or not to proceed with a negotiated settlement. At the pre-hearing conference, no party opposed the request by Centra Gas to proceed to a negotiated settlement process. The Commission issued Order No. G-76-02 establishing a Negotiated Settlement Process, and set out the Regulatory Agenda pertaining to the Application. The timetable for the Applications included Information Requests (“IR’s”) to be issued by Commission staff and Intervenors by Friday, November 1, and Wednesday November 6, 2002 respectively. Responses from Centra Gas to the IR’s were due to the Commission and Intervenors by November 18, 2002. Negotiations were to be held in Victoria commencing on Monday, November 25, 2002 for the Phase 1 Application, and Tuesday, December 3, 2002 for the Phase 2 Application. The Commission Staff issued IR’s pertaining to both the Phase 1 and Phase 2 Applications in writing on November 1, 2002. In addition to these, Centra Gas also received information requests from British Columbia Hydro and Power Authority (“B.C. Hydro”) on October 28, 2002 (BCH 1), and November 6, 2002 (BCH 2 and BCH 3), the Vancouver Island Gas Joint Venture (“VIGJV”) on November 6, 2002 (JV 1) and November 14, 2002 (JV 2), the Consumers Association of Canada (B.C.) et al (“CAC BC”) on October 30, 2002 (PIAC 1) and November 6, 2002 (PIAC 2), the Ministry of Energy & Mines (“MEM”) on October 28 (MEM 1), November 5, 2002 (MEM 2) and November 6, 2002 (MEM 3 and MEM 4), OK Industries (OK 1) on October 31, 2002, and Willis Energy Services (“Willis”) on behalf of the Vancouver Island

APPENDIX A to Order No. G-2-03 Page 3 of 34 3 Public Sector Natural Gas Consumers Group (Camosum College, Victoria School District, University of Victoria and the Sooke School District) (Willis 1) on November 6, 2002. Centra Gas responded to BCH 1 on November 1, 2002 and all of the other IR’s on November 18, 2002. A settlement conference was held in Victoria on November 25 and 26, 2002. In attendance were Commission Staff, the VIGJV, CAC BC, B.C. Hydro, MEM, Willis, Camosun College, Victoria School District, Calpine Canada, and Centra Gas, all of whom participated in the settlement discussions. The following is the negotiated settlement arrived at between Centra Gas and the parties attending the settlement conference as shown on the Negotiated Settlement schedules attached to and forming part of this Agreement. This settlement was achieved with the participation of the Commission Staff. 1. Items At-Risk for Centra On BCUC IR 1-6.2, Centra interprets the Special Direction as meaning “the BCUC will continue to approve variations (as they have since 1995), in other words ‘true-up to actual’ between forecast test year cost of service and actual costs (other than O&M) unless reasonable evidence exists to conclude variations not be approved.” The items that will continue to be fixed (and not trued-up) will be gross OM&A, equity component, and rate of return on common equity. 2. Revenue Forecast The load forecasts in the Application indicate residential energy sales of 4,057,547 GJ for 2003, 4,227,538 GJ for 2004 and 4,405,574 GJ for 2005. Forecast energy sales for commercial customers from 2003 to 2005 are 7,114,422 GJ, 7,196,997 GJ and 7,280,358 GJ respectively. The underlying assumptions in the forecasts were based on the expected total customer additions of approximately 3,000 each year during the forecast period, resulting in an average use per customer of 59.4 to 59.5 GJ/year for residential customers, and 836.0 to 836.9 GJ/year for the various commercial classes. Centra Gas provided further information to support the assumptions and supporting information that includes the predicted new home attachments, its conversion rate, Centra Gas’ current market share and its “on main” potential. Based on the supporting information, it is reasonable to accept that the overall customer additions have stabilized at approximately 3,000 customers per year. The forecast use rates are also acceptable against the historical usage trend. Variances in revenue as a result of the differences between the actual and forecast sales will flow to the RDDA. The forecast sales volumes will be ‘trued-up’ to actual. 3. Cost of Gas and Gas Cost Variance Account (“GCVA”) In the period 2003 to 2004, the forward curve of natural gas commodity costs for April 1, 2002 was used and inflation was applied to forecast 2005. Based on the gas contracting plan, hedging programs, and the provincial Royalty credits, Centra Gas’ cost of gas is effectively hedged out by October for the following year. The anticipated effect on gas costs for 2002/03 is in the range of +/- one percent as a result of the 2002/03 Price Management program. The April 1, 2002 forward curve is accepted. The differences between actual and forecast gas costs on a royalty adjusted basis will flow to the GCVA.

APPENDIX A to Order No. G-2-03 Page 4 of 34 4 The establishment of the GCVA is consistent with other gas distribution utilities in the Province and is accepted effective January 1, 2003. The balance of the GCVA will be provided and reviewed with the Company’s quarterly reports to the Commission to be used for determining future customer rates. The account will serve to hold and recover/refund the differences between actual and forecast cost of gas of the core market over a shorter timeframe than if the variance flowed directly to the RDDA. 4. Gross OM&A Gross Operating, Maintenance and Administrative (OM&A) expense is to be reduced from filed amounts of $32,972,352, $34,878,353, and $35,228,397 in 2003, 2004, and 2005 respectively (including the adjustments to fired hours, pension expense, and head office lease costs) to $31,700,000 in 2003, $32,500,000 in 2004, and $32,600,000 in 2005. The above amounts exclude the expense related to stock option grants, pending the outcome of the BC Gas Utility Ltd. hearing into the appropriate treatment of stock options (among other things). If the cost of stock options is accepted as part of the revenue requirements of BC Gas Utility Ltd., the cost of the stock options of Centra Gas will be added back to the above agreed OM&A amounts. Included in the amounts agreed to above for Gross OM&A are Employee Pension expense and Insurance expense. Employee Pension expense is forecast to be $2,536,911, $2,720,781, and $2,720,541 in 2003, 2004 and 2005 respectively. To the extent actual Pension expenses are different from forecast, the variance will be recorded in a deferral account, to be amortized in the same period as incurred. Insurance costs, as included in the settlement amounts above are $634,713, $646,137, and $659,060 in 2003, 2004 and 2005 respectively. To the extent actual Insurance costs are different from forecast, the variance will be recorded in a deferral account, to be amortized in the same period as incurred. Pension costs attributable to rate payers is to include pensionable amounts for Executive salaries and short term bonuses, which is consistent with past practice for Centra Gas (BCUC IR 1-1.1 of the 2000-02 revenue requirement application). With the purchase by BC Gas, Centra Gas will continue to explore synergies. If further cost reduction opportunities are found, these would be reflected in the re-basing of costs in a future revenue requirements application. Centra Gas receives Customer Information services from Enlogix. Centra Gas agrees to provide a report by June 30, 2003 on the financial assessment of continuing with Enlogix compared to moving to CustomerWorks, or other customer information service providers. Centra Gas is proposing to purchase Greenhouse Gas Credits of $153,800 per year commencing 2003, and is recording these costs in the Gas Supply department, which is fully allocated to Cost of Gas (BCUC IR 1-4.11). This cost of gas item will not be spent unless legally required. 5. Depreciation and Gannett Fleming Study On page 8.2 of the Application Centra Gas is proposing a change to the calculation of depreciation expense in accordance with a study by Gannet Fleming in Tab 22B of the Application. The study proposes that annual depreciation expense increase by $89,200 starting in 2003. The proposed changes are acceptable.

APPENDIX A to Order No. G-2-03 Page 5 of 34 5 6. Plant Additions The actual plant additions for 1999 to 2001 in transmission, distribution and general plant were reviewed and the explanations of variance were acceptable. In Tab 8 of the Application Centra Gas characterizes significant additions as expenditures that are about one percent of rate base or $4 million. Centra Gas intends to apply for a Certificate of Public Convenience and Necessity (“CPCN”) if a project exceeds one percent of rate base or $4 million; however, the Commission may designate that projects with an expected cost of less than one percent of rate base also require a CPCN. The annual review will consider material changes to the approved capital forecast that Centra Gas or customers believe are important. System Betterment Expenditures – (Transmission and Distribution) System Betterment Expenditures 2003 2004 2005 Transmission Compressor Stations $ 845,000 $ 845,000 $ 820,000 Regulating Meter $ 115,000 $ 200,000 $ 90,000 Stations Pipelines $1,215,000 $1,165,000 $1,165,000 Distribution Services, Meters & $ 120,000 $ 120,000 $ 120,000 Regs Mains $ 346,000 $ 306,000 $ 306,000 Total $2,641,000 $2,636,000 $2,501,000 The proposed expenditure levels are accepted for the three years, however Centra Gas remains at risk for the prudency of the costs. The System Betterment Expenditures are forecast to be $2,641,000, $2,636,000 and $2,501,000 for the periods 2003 to 2005 inclusive. The largest expenditures, over $800,000 in each year are described as follows: • In 2003 the relocation of the high pressure transmission mainline that crosses the Coquitlam Dam requires a $1,000,000 expenditure. A second item, an upgrade to units #1 and #2 at V1 Coquitlam compressors allows for the installation of dry gas seals on the rotating shaft. It is estimated to cost $825,000. • An expenditure of $1,000,000 in 2004 allows for the lowering of the high-pressure transmission line between Parksville and Nanaimo that crosses the Englishman River. This is a preventative measure to ensure safety and reliability of the pipeline that may be exposed by river erosion. • In 2005 directional drilling of the Haslam River will require an outlay of $1,000,000. This action will protect the high pressure transmission mainline between Nanaimo and Ladysmith from river erosion. Compressor upgrades account for a further expenditure of $800,000. The Greater Vancouver Regional District emission reduction targets necessitate emission upgrades to units #1 and #2 compressors at the Coquitlam station. General Plant additions for 2003 to 2005 are about $1.3 million per year as shown on page 10.24, Table 10.7 of the Application and are accepted as filed.

APPENDIX A to Order No. G-2-03 Page 6 of 34 6 7. Deferred Charges and Amortization Centra Gas recorded the costs of preliminary survey and investigation costs in non-rate base, interest bearing deferral accounts commencing with a request for service from B.C. Hydro in 1997. The referenced deferral accounts are shown on Schedule 39 of Tab 19 in the Application and include: T-Service for ICP $ 423,551 Woodfibre Compressor V2 $ 276,035 Mainland Looping $ 183,964 Second Marine Crossing $ 691,956 Port Alberni Looping $ 479,790 * Total $2,055,296 * This is the amount net of B.C. Hydro/ATCO recoveries of $131,589 shown in response to BCH 2-2.7.1, p. 5. In respect to this total ($2,055,296) Centra Gas will charge $1,568,411 to capital overheads in 2002, and then allocate to Account 465. For rate design purposes, Centra Gas will assign $300,000 as a direct assignment to B.C. Hydro and $1,268,411 to HPTS Transmission Mains Account 465 for allocation to all shippers on the Centra HPTS (including the Centra Distribution System) on the same basis as the revenue requirements for the balance of Account 465. The balance ($486,885) will be written off (net of any income taxes thereon) as a shareholder cost in 2002 and not as adjusted cost of service. In future, Centra Gas will provide, at no charge, preliminary assessments only for large capital projects required to serve new loads for potential or existing customers. If detailed project costs and design details are required, Centra Gas will obtain a signed commitment from the customer that Centra Gas will be reimbursed for costs incurred should the project not proceed. In future revenue requirements applications, Centra Gas will include a continuity of non-rate base deferral accounts, segregated from rate base deferral accounts, as part of the Application Schedules. 8. BC Capital Tax Audit and Appeal Costs In Tab 18 of the Application and BCUC IR 1-15.0, Centra describes the BC Capital Tax assessment of $6.2 million and its appeal. Centra Gas requests recovery in cost of service for any re-assessed capital taxes including interest and penalties and any legal or other costs incurred to defend its position.

APPENDIX A to Order No. G-2-03 Page 7 of 34 7 In BCH IR 2-2.20.2 Centra Gas states “In the event it is determined that Centra is liable for all or some portion of the reassessment, Centra will assess the appropriate treatment and, either apply for an interest bearing deferral account, to be amortized over 5 years, which is the same period over which the tax assessment occurred, or roll the amount directly into the RDDA”. Parties support Centra Gas’ efforts to appeal this issue. The prudency of the costs incurred and the assessed taxes, interest and penalties will be reviewed by the parties when the appeal is finalized along with a determination of the method of recovery. 9. Pension Charges See Item 4. 10. Capital Structure and Financing Costs It is agreed that for a Utility of Centra Gas’ size and circumstance, an average level of 35 percent common equity is appropriate. Centra Gas has maintained a 65 percent debt/35 percent equity capital structure since its inception and this structure is considered appropriate. Return on Common Equity The use of the automatic adjustment mechanism is appropriate for Centra Gas in the setting of its allowed equity rate of return commencing in 2003. A risk premium over the benchmark utility rate of return on common equity of fifty (50) basis points is appropriate for Centra Gas. Centra Gas will re-assess its basis point premium in its next revenue requirement application. Short-term Debt Centra Gas has proposed a short-term debt cost of 30 day Bankers Acceptances (BA’s) plus 80 basis points, which is accepted. Long-term Debt When Centra Gas’ long-term debt is due for renewal, it will apply to the Commission for approval of the new financing arrangement and the cost, as required under the Utilities Commission Act. 11. Actual 1999 to 2001 Revenue Deficiencies Centra Gas has shown the actual 1999 to 2001 revenue deficiencies in Tab 19, Schedule 2 of the Application. The allowed gross OM&A for 1999 to 2001 was set by settlement agreements with 2000 and 2001 allowing adjustments for customer growth and Customer Information System costs (“CIS”) as shown in BCUC IR 1-18.1. The actual 1999 to 2001 revenue deficiencies were reviewed and are accepted. 12. RDDA In BCUC IR 1-6.1 to 6.8 Centra Gas shows the recording of Annual Revenue Deficiencies and Surpluses in the Revenue Deficiency Deferral Account (“RDDA”) and the financing of those deficiencies. Centra Gas’ responses on the recording of activity in the RDDA

APPENDIX A to Order No. G-2-03 Page 8 of 34 8 appear to be consistent with the Special Direction. The financing of the RDDA through Class A preferred shares or Class B debt is described in BCUC IR 1-6.2 and 1-6.6.1. The net after tax cost of Class B instruments is identified as 5.08 percent compared to a Class A dividend cost of 5.65 percent. Therefore, with Centra Gas becoming taxable in 2003, the RDDA financing should be cheaper with Class B debt. For 2002 onward, Centra Gas should finance the RDDA by Class B instruments if the net after tax cost, including loss carry forwards from 2002, results in a lower financing cost than Class A instruments. Centra Gas will ensure that the least cost financing of the RDDA is included in adjusted cost of service. 13. Overhead Capitalization Centra Gas describes its overhead capitalization policy on page 9.23 of the Application. On Tab 19 Schedule 112 the gross O&M before capitalization is shown on line 16 with the capitalized gross O&M on line 17. For the years 2003 to 2005 the overhead capitalization percentage is 16.43 percent, 15.88 percent and 16.18 percent respectively. These overhead percentages are accepted. Centra Gas will continue to apply its overhead capitalization policy in the determination of OM&A capitalized, and will request Commission approval of each year’s OM&A capitalization commencing with the amount for 2004 according to past practice. 14. BC Gas Wheeling Charge There is no issue regarding the BC Gas Wheeling Charges to Centra as described in BCUC IR 1-5.1 to 1-5.2.2. 15. Re-Amortization of Repayable Loans On page 11.1 of the Application, Centra Gas describes that a $75 million federal/provincial refundable contribution was partly amortized as a reduction to the cost of service and the RDDA, totaling about $8.7 million. The amortization occurred because the contribution was not expected to be refundable but, in response to JV 1-14, Centra Gas describes that the expectation has changed and repayments to government will likely commence in 2012, subject to the ability of Centra Gas to obtain non-government debt financing on reasonable, BCUC approved commercial terms. Centra Gas is proposing to reverse the amortization by a charge against the annual surplus, which will vary with the amount of annual surplus. Centra’s proposal is accepted. 16. Annual Review In BCUC IR 1-6.7 Centra Gas proposes that it hold an annual meeting with Intervenors and Commission staff in November of each year in preparation for rate setting for the following year. The annual meeting will review Centra Gas’ performance that year and its proposed activities in the upcoming year. In addition, Centra proposes to provide quarterly reports to Commission staff and Intervenors to review competitive prices and determine if core customer sales rates should change. Intervenors may comment to the Commission on the quarterly reports but the Commission would not normally initiate quarterly meetings unless it determines that such a meeting is desirable. The parties accept this proposal. 17. Insurance Costs Centra Gas will report on the market survey of insurance costs for 2004 and 2005 at the November 2003 Annual Review.