BRITISH COL UMBIA UTILITIES COM MISSION ORDER NUMBER G -162-06 SIXTH FLOOR, 900 HOWE STREET, BOX 250 TELEPHONE: (604) 660-4700 VANCOUVER, B.C. V6Z 2N3 CANADA BC TOLL FREE: 1-800-663-1385 web site: http://www.bcuc.com FACSIMILE: (604) 660-1102 IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 and FortisBC Inc. 2006 Annual Review, 2007 Revenue Requirements and Negotiated Settlement Process BEFORE: L.F. Kelsey, Commissioner L.A. Zaozirny, Commissioner December 19, 2006 O R D E R WHEREAS: A. Commission Order No. G-58-06 approved for FortisBC Inc. (“FortisBC” or “Company”) a Performance Based Regulation Settlement for the years 2007 to 2009 (the “PBR Settlement”). The PBR Settlement requires FortisBC to hold an Annual Review, Workshop and Negotiated Settlement Process (“NSP”) each November with a goal of achieving firm rates by December 1 st for the following year; and B. The Annual Review compares the Company’s actual performance for the recently completed year to the approved targets for the Performance Standards and to determine whether the Company is entitled to an incentive payment. The Revenue Requirements Workshop is to focus on future test periods and the NSP is to establish rates for the following year; and C. One of the issues in the PBR Settlement was for FortisBC to continue to record Construction Work in Progress (“CWIP”) subject to Allowance for Funds Used During Construction (“AFUDC”) in rate base with a reduction to revenue requirements by the amount of the AFUDC for 2006. Beginning in 2007, FortisBC is to include only CWIP not subject to AFUDC in rate base and calculate interest expense and cost of equity only on Plant in Service and other costs approved for rate base treatment; and D. By letter dated September 8, 2006, the Company proposed a regulatory timetable for the filing of its 2007 Preliminary Revenue Requirements along with an Annual Review and 2007 Revenue Requirements Workshop followed by a NSP; and E. By Order No. G-118-06, the Commission established a Regulatory Timetable for the 2006 Annual Review and a 2007 Revenue Requirements Workshop on November 9 followed by an NSP on November 10, 2006; and …/2
BRITISH COLUMBIA UTILITIES COMMISSION ORDER NUMBER G-162-06 2 F. On September 29, 2006, FortisBC filed its Preliminary Revenue Requirements which sought a 2.9 percent (revised in the November 1, 2006 Update to a 2.1 percent) general rate increase effective January 1, 2007 and proposed to delay the removal of CWIP subject to AFUDC from rate base as required by the PBR Settlement until such time that the change becomes revenue neutral or appropriate in the context of the relevant revenue requirements application. FortisBC forecasts that removing CWIP subject to AFUDC from rate base in 2007 and the associated reduction to revenue requirements would increase rates by a further 2.1 percent. In the responses to information requests (BCUC IR 3.1 and 3.2), FortisBC was unable to estimate what year the removal of CWIP subject to AFUDC could occur or the threshold percentage rate increase that represented rate shock; and G. A proposed Settlement Agreement, which included a delay in the removal of CWIP subject to AFUDC from rate base for 2007 only to allow for further study, was agreed to by FortisBC and some Intervenors, with the participation of Commission staff; and H. Letters of support to the proposed Settlement Agreement were received from the British Columbia Old Age Pensioners’ Organization et. al (“BCOAPO”) and from FortisBC; and I. In its letter of comment, the Interior Municipal Electrical Utilities (“IMEU”) stated that it is in agreement with all parts of the proposed Settlement Agreement except for the proposed treatment of CWIP and AFUDC. The IMEU sees no reason to deviate from the treatment CWIP and AFUDC treatment established in the PBR Settlement. The IMEU also expects that the FortisBC general rate increase for 2007 will be less than 2 percent when the British Columbia Hydro and Power Authority final rates are flowed through. The IMEU estimates that future FortisBC rate increases will be in the range of 4 to 5 percent therefore 2007 is the optimal time to absorb the rate impact of the CWIP and AFUDC treatment change without rate shock; and J. In view of the IMEU submission, FortisBC, BCOAPO and the IMEU advised the Commission that they would support a severing of the treatment of CWIP and AFUDC from the proposed Settlement Agreement for a separate determination by the Commission. No letters of comment were received from registered intervenors who did not participate in the Settlement process; and K. The Commission has reviewed the proposed Settlement Agreement, the comments and submissions related thereto and considers that approval, in part, is warranted. NOW THEREFORE the Commission orders as follows: 1. The Commission approves the Settlement Agreement attached as Appendix 1 to this Order except for the proposed delay in the removal of CWIP subject to AFUDC from rate base. 2. The proposed delay in the removal of CWIP subject to AFUDC from rate base will be examined separately and the Commission requires an expedited review of this issue. The Commission requires that FortisBC file written submissions on the proposed delay in the removal of CWIP subject to AFUDC from rate base by Friday, January 5, 2007. The IMEU and other intervenors are to file their comments by Friday, January 12, 2007. FortisBC is to file its reply by Wednesday, January 17, 2007. Following a review of those submissions, the Commission will make a determination on the proposed delay in the removal of CWIP subject to AFUDC from rate base. …/3
3 3. The 2007 revenue requirement impact, if any, of the Commission determination on the proposed delay in the removal of CWIP subject to AFUDC from rate base is to be effective from January 1, 2007 and is to be recovered in 2007 rates on a prospective basis. 4. The Commission will accept, subject to timely filing, amended Electric Tariff Rate Schedules in accordance with the terms of this Order. DATED at the City of Vancouver, in the Province of British Columbia, this 20 Attachment Orders/G-162-06_FortisBC_NSP-2006AnnRvw-2007RR BRITISH COLUMBIA UTILITIES COMMISSION ORDER NUMBER G-162-06 th day of December 2006. BY ORDER Original signed by: L.F. Kelsey Commissioner
WILLIAM 5. GRANT TRANSITION ADVISOR, REGULATORY AFFAIRS & PLANNING bilI.grant@bcuc.com web site: http:llwww.bcuc.com VIA E-MML Dear Participants and Registered Intervenors: Re: FortisBC Inc. (""FrtisBC ") Negotiated Settlement Agreement 2007 Revenue Requirements Enclosed with this letter is the Negotiated Settlement Agreement for FortisBC's 2007 Revenue Requirements Application. Letters of C o m e n t from the Participants in the negotiated settlement process are enclosed with this settlement package which is now public and is being submitted to the Gomission and all Intek-enors. Prior to consideration by the Commission, Intervenors who did not participate in the settlement negotiations are requested to provide to the Comission their comments on the settlement package by Tuesday, December 12, 2006. Thereafter, the Commission will consider the settlement package. A public hearing may not be required unless there is significant opposition to the proposed settlement. Enclosures cc: Mr. Don Debienne Vice President Generation and Regulatory Affairs FortisBC Inc. PFiFBC-Annual 06-07RR/NSP/Negot1ated Settlement Release APPENDIX 1 to Order No. G-162-06 Page 1 of 11 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) 660-1 102 Log No. 16036 December 5.2006 Yours truly, i William J. Grant
APPENDIX 1 to Order No. G-162-06 Page 2 of 11 CONFIDENTIAL FortisBC Inc. 2007 Revenue Requirements Negotiated Settlement Agreement Introduction FortisBC Inc. (“FortisBC” or the “Company”) filed its Preliminary 2007 Revenue Requirements on September 29, 2006, in accordance with the terms of a Negotiated Settlement Agreement dated May 23, 2006 (the “NSA”) in regard to a Multi-Year Performance Based Regulation Plan (“PBR Plan”) approved by way of British Columbia Utilities Commission (the “Commission”) Order No. G-58-06. The Application requested a general rate increase of 2.9 percent effective January 1, 2007, based on the stand-alone operations of FortisBC. It also demonstrated that no rate impact would result from the addition of Princeton Light & Power Company, Limited. (“PLP”) operations if merged effective January 1, 2007. The impact of the proposed PLP merger was provided for information only in the Application. The acquisition of PLP by FortisBC is the subject of a separate application currently before the Commission. Following the submission of Information Requests by the Commission and Registered Intervenors and filing of responses, the Company filed an update to the 2007 Revenue Requirements Application on November 1, 2006 (the “Update”), incorporating financial results and forecasts as of September 30, 2006, and final Performance Standards for the period October 1, 2005 to September 30, 2006. The Update reflected a general rate increase of 2.1 percent, effective January 1, 2007, subject to changes that may result from the Commission’s decision on FortisBC’s 2007-2008 Capital Expenditure Plan application and the determination of 2007 Return on Equity arising from the Automatic Adjustment Mechanism. The 2006 Annual Review and 2007 Revenue Requirements Workshop was held in Kelowna, B.C. on November 9, 2006. FortisBC and a group of Intervenors participated in a Negotiated Settlement Process on November 10, 2006, and reached a Settlement Agreement, which is described in this document. FortisBC’s report on operating savings resulting from its capital projects is attached as Appendix A. The parties agree that this report meets FortisBC’s commitments arising from the 2006 Annual Review but should not be interpreted as being acceptance by the Intervenors on the substance of the report. The Parties to the Settlement Agreement are: ♦ FortisBC Inc.; ♦ The British Columbia Old Age Pensioners Association et al.; and ♦ The Interior Municipal Electricity Utilities. The Parties were assisted in reaching a Settlement Agreement by Commission staff. The Parties’ letters of support and comments with regard to the Settlement Agreement are attached as Appendix B.
APPENDIX 1 to Order No. G-162-06 Page 3 of 11 Settlement Agreement The Parties accept the 2007 Revenue Requirements Application, including the Update, as filed, subject to the following: Performance Standards and Incentive Sharing The Parties accept that FortisBC has generally met its Performance Targets in 2006 and have met the test set out in the NSA and is therefore eligible for its share of the financial incentive. In particular, significant progress has been made with regard to Customer Service measures, which had been of concern to stakeholders. Performance Targets for Generator Forced Outage and System Average Interruption Frequency Index were not met. The Parties wish to emphasize the importance of system reliability but accepted that the Company’s performance with regard to those measures was not the result of negligence of the Company, and that the remedy proposed with regard to the Corra Linn Unit 1 fire protection system was acceptable. The Parties accept the Company’s proposal to exclude the effect of the ongoing Lower Bonnington Unit 2 outage from the calculation of the Generator Forced Outage results in 2007. The Parties recognize that the 2007 Target for SAIFI, which is determined by a three-year rolling average, will decline as a result of outages during 2006 on the BCTC system and at DG Bell Terminal Station. It is recognized that these outages were unusual in nature, and the Company will strive for improvement in the performance of SAIFI reliability in 2007. The Parties agree to the Company’s proposal to retain the 2007 targets for Residential Extension Completion Time and Residential Construction Quote Times at 75%. The targets if calculated using the three-year rolling average would have been 72% and 73% respectively. Demand Side Management The Company will provide the load profile of various weather-sensitive DSM measures to demonstrate the impact on demand (kVA) and to confirm the valuation of avoided demand charges under Rate Schedule 3808. Class Action Law Suit The costs of this action will be held in a non Rate Base deferral account attracting FortisBC’s short term interest rate of 5.96% for 2007 and adjusted annually thereafter to reflect the test year forecast short term rate. Disposition of the account will be the subject of a future application which may involve a prudency review.
APPENDIX 1 to Order No. G-162-06 Page 4 of 11 Construction Work in Progress and AFUDC The Company’s proposal to continue its current practice of including CWIP in Rate Base and reducing Revenue Requirements by the amount of AFUDC is accepted for 2007 only. FortisBC will work with BCUC staff and stakeholders to understand any issues and future rate impacts, if any, arising out of the implementation of the new treatment of CWIP and AFUDC that is set out in the 2006 NSA and will report at the 2007 Annual Review. Final Revenue Requirements and General Rate Increase The Update reflected a general rate increase of 2.1 percent, effective January 1, 2007, subject to changes that may result from the Commission’s decision on FortisBC’s 2007-2008 Capital Expenditure Plan application and the determination of 2007 Return on Equity arising from the Automatic Adjustment Mechanism. In addition, the final rate increases for BC Hydro and BCTC will be incorporated into FortisBC’s Final 2007 Revenue Requirements provided the respective Negotiated Settlements are approved by the Commission on or before November 30, 2006. FortisBC’s 2007 rates will include the new 2007 rates for BC Hydro, BCTC and Independent Power Producers whose rates are tied to BC Hydro’s, in addition to the BC Hydro rate refund in respect of 2006 power purchase expense. If the BC Hydro and BCTC final rates are not known by November 30, 2006, these costs will be deferred for flow-through treatment in 2008.
APPENDIX 1 to Order No. G-162-06 Page 5 of 11 APPENDIX A Pursuant to Commission Order No. G-58-06 Appendix 1, subsection 2.2 Capital Expenditures Operating Savings Implementation of the capital plan can affect operating costs in a number of areas both positively and negatively: examples are lower power supply costs as a result of line loss reductions, maintenance cost increases from incremental plant in service and a reduction in costs as old plant is removed from service. Line loss reductions resulting from the capital program are built into the power supply forecast directly. Transmission and Distribution: Typically, savings associated with capital plan expenditures can be attributed to plant removed from service. This is usually offset with new plant put into service that requires ongoing new maintenance. In 2006, one distribution substation (Wynndel) was decommissioned as planned. It resulted in no operating savings as no maintenance was planned nor budgeted on the substation in the 2006 base year. However, there were O&M savings that began prior to 2006 and will continue into the future. As part of the capital plan a number of power transformers have been replaced, and although new, will still require preventive maintenance and to a lesser extent corrective maintenance. A number of projects will be implemented over the next two years that will indeed increase operating costs. For example, the greenfield projects (example: Kettle Valley Distribution Source) recently approved and submitted by way of CPCNs are forecast to increase annual maintenance costs from $15,000 – $25,000 per project. Incremental substation equipment such as transformers, switches, circuit breakers and current limiting reactors added in 2006 will require ongoing maintenance not currently included in the O&M formula. As well customer growth has increased distribution plant in service by approximately 80 kms or 1.5% and the associated annual O&M costs are also assumed to be absorbed within the current O&M formula. Page 4
APPENDIX 1 to Order No. G-162-06 Page 6 of 11 APPENDIX A Transmission maintenance for the most part appears in the form of capital refurbishments associated with the condition assessment program, and as such, improvements to the plant are reflected in reductions to future capital requirements and not operating expenses. In summary, the Capital Expenditure Plan is adding plant and the associated incremental maintenance at a rate that outpaces the rate at which old plant is being salvaged. The resulting increase in operating cost is being absorbed by the Company in productivity improvements to meet the current O&M formula and associated built in 2% productivity factor. Generation: Included in each Upgrade and Life Extension project is an O&M savings of $100,000 for the year of implementation and the year immediately following as a result of avoided annual maintenance inspections. The savings were included for the 2006 Revenue Requirements Application and associated Negotiated Settlement Agreement and subsequently achieved. General Plant: General Plant includes three projects of note with regard to O&M savings; the separation of SAP support from FortisAlberta predicts an annual decrease in O&M of approximately $200,000, the vehicle lease to ownership predicts a $282,000 annual savings, both of which were included for in the 2006 Revenue Requirements Application and associated Negotiated Settlement Agreement and subsequently achieved. The AM/FM project predicts an increase of approximately $150,000 / year in O&M expense. Summary: Operating and maintenance (“O&M”) expense is calculated by a formula as directed by the 2006 Negotiated Settlement Agreement. The NSA includes a 2% PIF for 2007 which equates to approximately $800,000 of O&M reduction. Although there is a 2% CPI inflator, market conditions and current labour wage escalation are greater than the current CPI. This PIF was intended to not only recognize operating savings as a result of capital expenditures, but also other operating efficiencies. Page 5
Table A 2006 Savings Capital Project Application (included in Base O&M) Transmission & Distribution 1 Creston Distribution Upgrade: 2006 CEP 20 2 Kettle Valley Distribution Source: 2005 CPCN 3 Nk’Mip Distribution Source: 2005 CPCN 4 Big White Supply: 2006 CPCN 5 Ellison Distribution Source: 2006 CPCN Generation 6 Lower Bonnington Unit 1 ULE 2005 CEP 100 7 Lower Bonnington Unit 3 ULE 2006 CEP 100 General Plant 8 AM/FM: 2006 CPCN 9 Vehicle Lease Buy-out: 2005/2006 CEP 280 10 Business Software Solution 2006 CEP 200 Page 6 APPENDIX 1 to Order No. G-162-06 Page 7 of 11 APPENDIX A 2007 Future Savings Years Comments Savings 20 20 Wynndel Substation Salvage <20>. Growth-related <20> Growth-related <20> Growth-related <15> Growth-related 0 Avoided maintenance in year of life extension and year following 100 0 Avoided maintenance in year of life extension and year following <150> <150> Future operating cost increase 280 280 200 200
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