BRITISH COL UMBIA UTILITIES COM MISSION
SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C. V6Z 2N3 CANADA web site: http://www.bcuc.com IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473
and FortisBC Inc. 2007 Annual Review, 2008 Revenue Requirements and Negotiated Settlement Process
BEFORE: L.A. O’Hara, Commissioner December 4, 2007 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, 2008 and potentially 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 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 conducted to establish rates for the following year; and
C. By Order No. G-117-07 dated September 21, 2007, the Commission established a Regulatory Timetable for the 2007 Annual Review and a 2008 Revenue Requirements Workshop on November 8, 2007 in Kelowna, BC, followed by an NSP on November 9, 2007; and
D. On October 1, 2007, FortisBC filed its Preliminary 2008 Revenue Requirements, which sought a 4.0 percent general rate increase effective January 1, 2008; and
E. On November 1, 2007, Fortis BC filed an update to the 2008 Revenue Requirements Application (“Update”), which incorporated financial results and forecasts as of September 30, 2007, including financial Performance Standards for the period October 1, 2006 to September 30, 2007, and sought a lower general rate increase of 3.4 percent, effective January 1, 2008; and
F. As a result of the 2007 Annual Review on November 8, 2007 and 2008 Revenue Requirements Settlement discussions on November 9, 2007, a Settlement Agreement was proposed and agreed to by FortisBC and some Intervenors, with the participation of Commission Staff. The proposed Settlement Agreement, which results in a general rate increase of 2.9 percent effective January 1, 2008, was circulated to the participants and registered Intervenors on November 23, 2007; and
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ORDER NUMBER G -147-07 TELEPHONE: (604) 660-4700 BC TOLL FREE: 1-800-663-1385 FACSIMILE: (604) 660-1102
BRITISH COLUMBIA UTILITIES COMMISSION
ORDER NUMBER G-147-07 2
G. The proposed Settlement Agreement includes a 4.9 basis point yield spread between 10 year and 30 year Canada bonds in forecasting FortisBC’s 2008 allowed rate of return on common equity (“ROE”) under the Commission’s automatic adjustment mechanism. By Letter No. L-93-07, dated November 22, 2007, the Commission established the 2008 ROE for the low-risk benchmark utility of 8.62 percent that is based on an average yield spread of 4.9 basis points between 10 year and 30 Canada bonds. Accordingly, FortisBC confirmed that the ROE incorporated into the Settlement Agreement is in accordance with FortisBC’s 2008 allowed ROE; and
H. Letters of support to the proposed Settlement Agreement were received from Buryl Goodman and Alan Wait. A wording modification to the proposed Settlement Agreement with regard to income tax was suggested by the British Columbia Old Age Pensioners’ Organization et al. (“BCOAPO”). The modified Settlement Agreement (“the Modified Settlement Agreement”) was agreed to by BCOAPO, the Interior Municipal Electrical Utilities and FortisBC; and
I. In its letter of comment dated November 22, 2007, Horizon Technologies Inc. (“Horizon”) submits that it does not support the proposed Negotiated Settlement Agreement (“NSA”) and raised concerns with respect to (1) FortisBC Cost of Service Study and Rate Design Application (“RDA”), (2) Demand Side Management (“DSM”), and (3) 2007 BC Energy Plan. Horizon requests more description to the scope of the Rate Design Application to support FortisBC’s original budget of $600,000 and expresses concern that the revised $400,000 budget per the proposed Settlement Agreement may result in a smaller scope for the RDA. Horizon submits that the projected 2008 DSM savings level should be increased to 23.9 GWh or higher from 19.5 GWh set out in the proposed Settlement Agreement. Finally, Horizon requires that FortisBC will consider the 2007 BC Energy Plan in all its 2008 projects and applications; and
J. In response to Horizon’s submission, on November 23, 2007, FortisBC first states that it understands Horizon to be a company based outside its service territory that sells energy efficiency related consulting services. FortisBC then submits that the letter by Horizon should not be given any weight when considering the approval of the NSA and comments as follows:
• The issues of scope, participation and recommendations relating to the FortisBC RDA should be addressed in a rate design proceeding and not the 2008 Revenue Requirements and NSA.
• FortisBC considers the planned DSM savings, which were also reviewed by the DSM Committee, are appropriate and does not support the recommendation set out in Horizon’s letter.
• Negotiating a specific standard and scope of consideration of the Energy Plan for all future regulatory applications is inappropriate and would go beyond the scope of FortisBC’s 2008 Revenue Requirements Application and the NSA; and
K. By the due date of November 29, 2007, no comments were received from any Registered Intervenors who had not participated in the Settlement negotiation; and
L. The Commission has reviewed the proposed Settlement Agreement, the modification as shown on page 24 of Appendix A, comments and submissions related thereto and considers that approval is warranted.
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BRITISH COLUMBIA UTILITIES COMMISSION
ORDER NUMBER G-147-07 3
NOW THEREFORE the Commission orders as follows: 1. The Commission approves the Modified Settlement Agreement attached as Appendix A to this Order, and the Terms of Settlement along with supporting schedules showing the effect of changes arising from the Negotiated Settlement.
2. The Commission considers that changes submitted by Horizon with regard to the RDA and the BC Energy Plan are beyond the scope of this Revenue Requirements proceeding and are not approved.
3. 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 4 th day of December 2007. BY ORDER Original signed by: L.A. O’Hara Commissioner Attachment
Order/G-147-07_FortisBC 2008RR Negotiated Settlement
APPENDIX A to Order No. G-147-07 Page 1 of 40
FortisBC Inc. 2008 Revenue Requirements Negotiated Settlement Agreement Introduction FortisBC Inc. (“FortisBC” or the “Company”) filed its Preliminary 2008 Revenue Requirements on October 1, 2007, in accordance with the terms of 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 reflected a general rate increase of 4.0 percent effective January 1, 2008. Following the submission of Information Requests by the Commission and Registered Intervenors and filing of responses, the Company filed an update to the 2008 Revenue Requirements Application on November 1, 2007 (the “Update”), incorporating financial results and forecasts as of September 30, 2007, and final Performance Standards for the period October 1, 2006 to September 30, 2007. The Update reflected a general rate increase of 3.4 percent, effective January 1, 2008, subject to the determination of 2008 Return on Equity arising from the Automatic Adjustment Mechanism and the outcome of a Negotiated Settlement Process (“NSP”).
The 2007 Annual Review and 2008 Revenue Requirements Workshop was held in Kelowna, BC on November 8, 2007. FortisBC and a group of Intervenors participated in a NSP on November 9, 2007, and reached a Settlement Agreement, which is described in this document. The Settlement Agreement results in a general rate increase of 2.9% effective January 1, 2008. Summary Revenue Requirements Schedules, which also reflect the final 2008 Return on Equity are attached as Appendix A.
The following Parties participated in the NSP: Participant Party W.J. Grant British Columbia Utilities Commission P. Nakoneshny British Columbia Utilities Commission D. Chong British Columbia Utilities Commission D. Flintoff British Columbia Utilities Commission J. Yang British Columbia Utilities Commission T. Andreychuk The Interior Municipal Electricity Utilities, The City of Penticton V. Kumar The Interior Municipal Electricity Utilities, The City of Grand Forks R. Leslie The Interior Municipal Electricity Utilities, Nelson Hydro C. McNeely The Interior Municipal Electricity Utilities, The City of Kelowna K. Ostraat The Interior Municipal Electricity Utilities, The District of Summerland
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CONFIDENTIAL APPENDIX A to Order No. G-147-07 Page 2 of 40
CONFIDENTIAL APPENDIX A S. Khan The British Columbia Old Age Pensioners to Order No. G-147-07 Page 3 of 40 Organization et al. B. Goodman and E. Goodman FortisBC Ratepayers A. Wait FortisBC Ratepayer L. Bertsch Horizon Technologies D. Bennett FortisBC Inc. J. Martin FortisBC Inc. M. Mulcahy FortisBC Inc. D. Swanson FortisBC Inc. Settlement Agreement The Parties accept the 2008 Revenue Requirements Application, including the Update, as filed, subject to the following:
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FortisBC Inc. 2007 Annual Review and 2008 Revenue Requirements Negotiated Settlement Agreement
ISSUES ISSUE DESCRIPTION RESOLUTION REFERENCE Tab 3 – Revenue Requirements Water Fees: (Sec. Water fees have been presented as a tax Water fee will be classified as part of power Exhibit B-2, Q10.1 3.4.2) Cost since 2005. supply costs. Classification
Income Tax: (Sec. On October 30, 2007 the Canadian The expected federal corporate income tax Updated Exhibit B-1, 3.4.3) Expected government announced a further 1.0% reduction will be included in 2008 revenue Tab 3, p. 16 Reduction in Federal reduction in the corporate income tax requirements. If it is not enacted, the Corporate Income Tax rate, effective January 1, 2008. If difference is subject to Z-factor treatment. Rate in 2008 enacted, the federal rate will be reduced to 19.5% from 20.5% for 2008.
Cost of Equity: (Sec. FortisBC was predicting an inverse yield Will be set through automatic adjustment Updated Exhibit B-1, 3.5.2) curve for calculation of Benchmark ROE. mechanism. For current estimates, use a 4.9 Tab 3, p. 17; Actual yield spread between 10 and 30 basis point spread between 10 and 30 year Exhibit B-2, BCUC IR year bonds in October 2007 was 4.9 basis government bonds. Q20.1, points, which will be used for setting the 2008 ROE benchmark rate.
Deferred Charges: Income tax impact for deferred charges FortisBC will adjust the 2007 income tax Exhibit B-2, BCUC (Sec. 3.8.2) Deferred should be 34.12% in 2007, rather than rate applicable to deferred charges to Q11.3.2; tax rate for 2007 33% as shown in Table 3.8.2. 34.12%. BCOAPO Q3.1 FortisBC Cost of FortisBC forecast $600,000, before tax, For budget purposes, the forecast will be Updated Exhibit B-1, Service and Rate for its Cost of Service Analysis and Rate reduced to $400,000, before tax. Tab 3, p. 30 Design Application Design Application. (2008) (Sec. 3.8.2)
APPENDIX A to Order No. G-147-07 Page 4 of 40 CONFIDENTIAL
ISSUES ISSUE DESCRIPTION Revenue Protection: Further detailed activity of the Revenue Budget accepted. FortisBC will continue to (Sec. 3.8.2) Protection cost of $260,000 in 2008 provide detail on the Revenue Protection would be desirable. program annually, in accordance with Order G-58-06. Hydro Electric Supply In the February 14, 2006 Update, This cost will be expensed as per the Study – Recovery as a FortisBC described this project as “Small Uniform System of Accounts as it does not deferred charge (Sec. Hydro Reconnaissance Study” and lead to a capital project that is placed in 3.8.2) “recorded as a preliminary investigation, service. The $21,000 of study costs will be pending determination of feasibility”. expensed in 2007. FortisBC proposes to amortize the costs during 2008.
Related-Party Disclosure of related party transaction will Exhibit B-2, BCUC Transactions be a standard item for future revenue Q65.3 requirements applications.
Contingent Liabilities: FortisBC proposes to submit an FortisBC will apply for cost recovery if they (Sec. 3.10) Forest Fire application in regard to costs of litigation occur. near Vaseux Lake and not covered under the Company’s pending claims insurance coverage, if necessary. Tab 5 – Load and Customer Forecast Residential and Accept the Residential and General Service General Service forecasts. Forecast Wholesale Load FortisBC’s 2008 Wholesale Load Adjust Wholesale Load forecast for 2008 Forecast forecast (Tab 5, Appendix A) is 891 upwards to 904 GWh. GWh.
APPENDIX A to Order No. G-147-07 Page 5 of 40 CONFIDENTIAL RESOLUTION REFERENCE Updated Exhibit B-1, Tab 3, pp. 33-35; Exhibit B-2, BCUC Q15.4 Updated Exhibit B-1, Tab 4, p. 32; Exhibit B-2, BCUC Q15.7
Updated Exhibit B-1, p. 39; Exhibit B-2, BCUC Q19.1, p.52 Updated Exhibit B-1 Tab 5, pp. 5-6; Exhibit B-2 BCUC Q29.0 to Q32.0 Exhibit B-1, Tab 5, pp. 12 and 17; B-2, BCUC Q34.2 and 34.3
ISSUES ISSUE DESCRIPTION Subsequent Events: FortisBC filed in confidence its forecast 1. A deferral account will be established to (Sec. 3.9) Industrial of 2008 load, revenue and power Load Forecast purchases resulting from closures and/or Uncertainty: reduced operations of three of its largest CANPAR, Pope & industrial customers. Talbot, and Weyerhaeuser 2. The Company will use forecasts per the
3. The net loss due to default of payments in 2008 is also recorded in the new deferral account.
System Loss: (Sec. 5.3) FortisBC incorporated a gross system A system loss factor of 9.1% will be used for Exhibit B-1, Tab 5, p. loss factor of 9.4% in the 2007 updated the 2008 load forecast, based on the average 13 and 2008 load forecasts. The four-year of the four-year and three-year system losses average is 9.4% and the three-year meant to reflect the newer systems resulting average is 8.8%. in a declining trend of system loss. This is a negotiated position between the Parties.
Power Factor FortisBC’s Tariff requires customers to During 2008 FortisBC is to investigate a Exhibit B-2, BCUC Surcharges for large maintain a power factor of not less than power factor penalty (Power Factor<0.95) in Q4.1, pp. 6-7, distribution and 90 percent lagging. The benefits of a accordance with BC Hydro Electric Tariff Q4.2, p. 7, transmission higher power factor may include: Supplement No. 5 Q4.3, pp.7-8, customers. • Lower line losses (currently 9.4%); Q35.1 - Q35.2, pp. 113-• Reduction in peak demand and 115, energy requirements; and Q42.1, pp.124-125 • Reduction of power purchase expense
APPENDIX A to Order No. G-147-07 Page 6 of 40 CONFIDENTIAL RESOLUTION REFERENCE Exhibit B-1, Tab 3, pp. capture the incremental costs and 33-35; incremental revenue for load variance Exhibit B-2, BCUC from the 2008 Forecast for CANPAR, Q16.0, Q17.0; Pope & Talbot, and Weyerhaeuser, Exhibit B-1-2, Tab 3, which will flow through to rates in 2009. pp. 38-39 November 7, 2007 confidential filing with reduced load expectations, power purchases and revenue in 2008.
ISSUES ISSUE DESCRIPTION Tab 7 – Capital Expenditures Preliminary FortisBC proposes to purchase property The purchase of the land is not approved at Investigative Projects: adjacent to its Duck Lake Substation in this time. FortisBC may bring forward this (Sec. 7.2.8) Duck Lake order to secure access and provide for item at a future time when a near term or Substation Property possible future expansion of the medium term need is established. substation. Preliminary FortisBC proposes to capitalize the Accept budget forecast for 2008 for the Investigative Projects: removal of danger trees killed by the pine purposes of this negotiation. FortisBC is to (Sec. 7.2.8) Pine Beetle beetle as additional right of way provide detailed analysis at the next annual Kill – Hazard Trees reclamation expenditures. review of the extent of the hazard and the future costs. FortisBC and the Participants hold differing views on the treatment of removal costs for Pine Beetle Kill. The Parties agree that the 2008 removal costs will be recorded in a rate-base deferral account, amortized over 10 Q28.1A, p.31 years, without prejudice to the treatment of future expenditures.
Preliminary As the issue of dissimilar metals causing Will be addressed in a CPCN application. Updated Exhibit B-1, Investigative Projects: high contact resistance between copper Tab 7, p.17; (Sec. 7.2.8) Conductor and aluminum is well known, FortisBC is Exhibit B-2, Q56.2, p. Replacement (Burn- to propose corrective action to address 160 Off) this issue. FortisBC is to identify the estimated cost of replacing the hot line tap after a failure.
APPENDIX A to Order No. G-147-07 Page 7 of 40 CONFIDENTIAL RESOLUTION REFERENCE Updated Exhibit B-1, Tab 7, p. 17; and attached report; Exhibit B-2, BCUC Q7.2 & Q51.3 Updated Exhibit B-1, Tab 7, pp. 17-18; and attached report; Exhibit B-2, BCUC Q7.4, p.14; Q27.5.1, p.91, Q27.5.2, p.91, Q27.5.3, p.92, Q41.1, p.123; Exhibit B-2, Appendix
ISSUES ISSUE DESCRIPTION Demand Side Most DSM materials were filed after the FortisBC commits to filing DSM results for Management: (Sec. November 1 Update so IRs on DSM were previous year and previous six months 7.2.7) limited. The DSM material should come before or with the Annual Review materials, in with the other materials. including the incentive calculations and the other reports discussed at page 15 of (updated) Tab 7.
Capital Expenditure Accepted as filed Updated Exhibit B-1, Operating Savings Tab 7 Appendix 1 Report
Tab 8 – 2007 Performance Standards Injury Severity Rate The 2007 Injury Severity Rate Target The Parties agree to retain the 2007 target of (“ISR”) Target was not met. If calculated using the 17.53 for Injury Severity Rate in 2008. three-year rolling average, the 2008 Target would be 21.62. The Company will provide as part of the 2008 Annual Review/2009 Revenue Requirements a substantive report outlining the Company’s safety program including its efforts to manage the injury severity rate.
2007 Incentive Sharing The Parties accept that FortisBC has generally met its performance targets in 2007 and has met the test set out in the NSA and is therefore eligible for its share of the financial incentive.
APPENDIX A to Order No. G-147-07 Page 8 of 40 CONFIDENTIAL RESOLUTION REFERENCE Updated Exhibit B-1, Tab 7, p.15; Exhibit B-2 BCUC Q55.1; Other DSM material filed on October 11; IRs sent out on Oct 12.
Exhibit B-1-3, Errata, Tab 8 p.4A; Exhibit B-2, BCUC Q61.0 to Q61.1 p.166; Q61.3 p. 167, Q62.1.1 to Q62.1.2 pp. 167-168, Q61.3 p. 167, Q62.2 p. 168, Appendix A62.1.1; Appendix A62.2.
ISSUES ISSUE DESCRIPTION BC Energy Plan FortisBC will continue to consider the BC Energy Plan in its 2008 projects and applications. For example, the BC Energy Plan is a relevant factor in the rate design studies and application, the development of DSM programs, and future energy supply plans.
APPENDIX A to Order No. G-147-07 Page 9 of 40 CONFIDENTIAL RESOLUTION REFERENCE
APPENDIX A to Order No. G-147-07 Page 10 of 40
Appendix A
2008 Revenue Requirements Negotiated Settlement Agreement
Financial Schedules FortisBC Inc.
2008 Revenue Requirements Financial Schedules – Negotiated Settlement REVENUE REQUIREMENTS OVERVIEW
2008 Revenue Requirements November 1 Increase or Settlement Update (Decrease) Agreement ($000s)
1 Sales Volume (GW.h) 2 Rate Base 3 Return on Rate Base 4 5 REVENUE DEFICIENCY 6 7 POWER SUPPLY 8 Power Purchases 9 Water Fees 10 11 OPERATING 12 O&M Expense 13 Capitalized Overhead 14 Wheeling 15 Other Income 16 17 TAXES 18 Property Taxes 19 Income Taxes 20 21 FINANCING 22 Cost of Debt 23 Cost of Equity 24 Depreciation and Amortization 25 AFUDC 26 27 28 Prior Year Incentive True Up 29 Flow Through Adjustments 30 AFUDC / CWIP shortfall 31 ROE Sharing Incentives 32 33 34 TOTAL REVENUE REQUIREMENT 37 39 Interest on Non Rate Base Deferral Account 40 ADJUSTED REVENUE REQUIREMENT 41 Less: REVENUE AT APPROVED RATES 42 REVENUE DEFICIENCY for Rate Setting 43 44 RATE INCREASE November 16, 2007 FortisBC Inc.
APPENDIX A to Order No. G-147-07 Page 11 of 40
3,166 (79) 3 ,087 823,434 (587) 8 22,847 7.54% 7.47% 70,840 (3,437) 6 7,403 7,858 - 7 ,858 78,698 (3,437) 7 5,261 45,310 - 4 5,310 (9,062) - (9,062) 3,622 - 3 ,622 (5,030) - (5,030) 34,840 - 3 4,840 11,176 - 1 1,176 4,403 (414) 3 ,989 15,579 (414) 1 5,165 31,784 (22) 3 1,762 30,269 (581) 2 9,688 34,373 (17) 3 4,356 - - - 96,426 (620) 9 5,806 22 - 2 2 (42) - (42) 895 - 8 95 (2,159) - (2,159) (1,284) - (1,284) 224,259 (4,471) 2 19,788 27 - 2 7 224,286 (4,471) 2 19,815 216,829 (3,135) 2 13,694 7,457 (1,336) 6 ,121 3.4% 2.9% Page 1
2008 Revenue Requirements Financial Schedules – Negotiated Settlement SCHEDULE 1 – UTILITY RATE BASE
1 Plant in Service, January 1 2 Net Additions 3 Plant in Service, December 31 4 5 6 Construction Work in Progress 7 Less: CWIP subject to AFUDC (Note 1) 8 Plant Held for Future Use 9 Plant Acquisition Adjustment 10 Deferred and Preliminary Charges 11 Less non-rate base deferral accounts 12 13 14 Less: 15 Accumulated Depreciation 16 and Amortization 17 Contributions in Aid of Construction 18 19 20 Depreciated Rate Base 21 22 Prior Year Depreciated Utility Rate Base 23 24 Mean Depreciated Utility Rate Base 25 26 Allowance for Working Capital 27 Adjustment for Capital Additions 28 29 Mid-Year Utility Rate Base 30 31 Note 1. In 2007, the BCUC issued Commission Order No. G-20-07 which instructed 32 FortisBC to remove Construction Work in Progress subject to AFUDC from 33 rate base and to remove AFUDC from Revenue Requirements effective 34 January 1, 2007. 35 36 Note 2. 2006 Closing balance of rate base items has been restated to include the 37 effects of the rate base previously held by PLP. November 16, 2007 FortisBC Inc.
APPENDIX A to Order No. G-147-07 Page 12 of 40
Actual Forecast Forecast 2006 2007 2008 (Note 2) ($000s) 820,437 943,920 1,075,766 123,483 131,846 1 08,640 943,920 1,075,766 1,184,406 33,208 47,897 6 6,300 (41,090) ( 59,513) - - - 11,912 11,912 1 1,912 18,563 13,921 1 6,062 (895) 1,007,603 1,107,511 1,219,167 226,508 249,139 2 75,031 68,188 75,950 8 0,694 294,696 325,089 3 55,725 712,907 782,422 8 63,441 631,231 712,907 7 82,422 672,069 747,664 8 22,932 7,511 7,269 7 ,188 (4,806) (10,818) ( 7,273) 674,773 744,115 8 22,847 Page 2
2008 Revenue Requirements Financial Schedules – Negotiated Settlement Table I – A – Utility Plant in Service (2008)
December 31 Line Account Hydraulic Production Plant 1 330 Land Rights 120 2 331 Structures and Improvements 11,412 3 332 Reservoirs, Dams & Waterways 20,436 4 333 Water Wheels, Turbines and Gen. 59,908 5 334 Accessory Equipment 22,283 6 335 Other Power Plant Equipment 38,132 7 336 Roads, Railroads and Bridges 1,053 8 153,344 9 Transmission Plant 10 350 Land Rights 7,079 11 350.1 Land Rights - Clearing 4,364 12 353 Station Equipment 160,319 13 355 Poles Towers & Fixtures 65,109 14 356 Conductors and Devices 64,993 15 359 Roads and Trails 817 16 302,682 17 Distribution Plant 18 360 Land Rights 1,449 19 360.1 Land Rights - Clearing 4,153 20 362 Station Equipment 106,113 21 364 Poles Towers & Fixtures 105,121 22 365 Conductors and Devices 175,091 23 368 Line Transformers 78,344 24 369 Services 7,292 25 370 Meters 13,225 26 371 Installation on Customers' Premises 938 27 373 Street Lighting and Signal System 5,691 28 497,418 29 General Plant 30 389 Land 4,642 31 390 Structures-Frame & Iron 337 32 390.1 Structures-Masonry 22,971 33 391 Office Furniture & Equipment 5,224 34 391.1 Computer Equipment 45,054 35 392 Transportation Equipment 18,449 36 394 Tools and Work Equipment 9,876 37 397 Communication Structures and Equipment 15,769 38 122,322 39 40 101 Plant in Service 1,075,766 41 107.1 Plant under construction not subject 42 to AFUDC 6,807 43 107.2 Plant under construction 44 subject to AFUDC 41,090 45 114 Utility Plant Acquisition Adjustment 11,912 46 105 Plant held for future use - 47 48 105 Utility Plant per Balance Sheet 1,135,575 November 16, 2007 FortisBC Inc.
APPENDIX A to Order No. G-147-07 Page 13 of 40
December 31 2007 Additions Retirements 2008 (000s) - - 120 666 (84) 11,994 1,541 ( 80) 21,897 274 (73) 60,110 274 22,557 274 38,407 - 1,053 3,030 (237) 156,138 - - 7,079 4,364 35,637 (1,779) 194,177 13,956 (966) 78,100 13,956 (1,183) 77,767 - - 817 63,549 (3,928) 362,303 - - 1,449 4,153 2,191 - 108,305 7,495 ( 80) 112,536 12,646 ( 80) 187,657 5,398 83,743 - - 7,292 615 - 13,840 - - 938 - - 5,691 28,346 (160) 525,603 3,764 - 8,406 - - 337 1,312 - 24,283 187 - 5,411 6,411 - 51,465 2,461 - 20,910 650 - 10,526 3,687 (432) 19,024 18,472 (432) 140,361 113,397 (4,757) 1,184,406 6,787 59,513 11,912 - 1,262,618 Page 3
2008 Revenue Requirements Financial Schedules – Negotiated Settlement Table I – A – 1 – Additions to Plant in Service (2008)
CWIP Dec. 31, 2007 Hydraulic Production 1 P1 Generator & Plant Cooling System Upgrade 22 2 P1U3 Upgrade & Life Extension - 3 P2 Old Unit Repower - 4 P3U1 Upgrade & Life Extension 3,258 5 P3U1 Headgate Rebuild - 6 P3U3 Upgrade & Life Extension 3,500 7 P3U3 Headgate Rebuild 327 8 P3 Plant Completion 545 9 P3 H/G Hoist, Control, Wire Rope Upg 1 0 P4U1 Upgrade & Life Extension 533 1 1 P1 Misc Upgrades - 1 2 P2 Misc Upgrades 1 3 P3 Misc Upgrades - 1 4 P4 Misc Upgrades - 1 5 8,185 Transmission Plant 1 6 Okanagan Transmission Reinforcement 4,235 1 7 Big White 138 KV Line & Substation 4,474 1 8 Ellison Distribution Source 2,103 1 9 Naramata Rehabilitation 2,647 2 0 Black Mountain Distribution Source 1,249 2 1 Hollywood/Mission Cap Increase - 2 2 Kettle Valley 13,737 2 3 Transmission Line Sustaining - 2 4 Station Sustaining - 2 5 Castlegar Sub Cap 2,250 2 6 Crawford Bay Cap Inc - 2 7 Capitalized Inventory & Transformers 6,787 2 8 Coffee Creek Capacitor 69Kv - 2 9 Kaslo Capacitor 25Kv - 3 0 18 L Breaker @ Waneta - 3 1 37,482 Distribution Plant 3 2 Customer New Connects - 3 3 Distribution Sustaining - 3 4 Mckinley Lnd Cap Upgrade 9 3 5 HOL1-OKM1 Tie-KLO Rd 10 3 6 SEX4 Regulator 10 3 7 Duck Lake Substation - 3 8 Lee2-Hol5 Tie Add N.O 10 3 9 GLE2 Spall/Springfield UG - 4 0 PRI04 Capacity Upgrade 84 4 1 OKF03 Capacity Upgrade 84 4 2 VAL01 Capacity Upgrade 10 4 3 217 General Plant 4 4 Communications and Automation 119 4 5 Protection and Communications Rehabilitation - 4 6 Vehicles - 4 7 Metering - 4 8 Information Systems 1,894 4 9 Telecommunications - 5 0 Buildings - 5 1 Furniture & Fixtures - 5 2 Tools & Equipment - 5 3 2,013 5 4 TOTAL 47,897 November 16, 2007 FortisBC Inc.
APPENDIX A to Order No. G-147-07 Page 14 of 40
CWIP Additions to Expenditures Dec 31, 2008 Plant in Service ($000s) 370 392 - - 2,266 2,266 - 4,062 7,320 - 54 54 - 6,460 9,960 - 270 - 597 616 1,161 - 669 669 382 915 - 290 - 290 290 - 290 338 - 338 454 - 454 16,521 21,675 3,030 13,978 18,213 - 7,295 - 11,769 11,937 - 14,040 2,458 5,105 - 8,459 9,708 - 4,812 4,812 - 5,570 19,307 5,588 - 5,588 4,709 - 4,709 5,340 7,590 10 10 6,787 - - - - - 1,800 1,800 71,956 44,625 64,813 15,954 15,954 11,265 11,265 350 359 339 349 150 160 - - 409 419 50 50 798 882 291 375 887 897 30,493 - 30,710 1,902 2,021 1,491 1,491 2,461 2,461 136 136 4,517 6,411 175 175 1,312 1,312 187 187 650 650 12,831 - 14,844 131,800 66,300 113,397 Page 4
2008 Revenue Requirements Financial Schedules – Negotiated Settlement Table 1 – B – Deferred Charges and Credits (2007) Balance at Dec. 31, 2006 Demand Side Management 1 Demand Side Management Additions 17,882 2 Tax Impact (12,064) 3 PLP Energy Management 190 4 6,008 5 Deferred Regulatory Expense 6 Deferred Revenue - Incentive Adjustment ( 2,524) 7 Provision for True-up for 2006 Incentive 34 8 2005 Revenue Requirements 529 9 Tax Impact ( 152) 10 2006 Revenue Requirements 160 11 Tax Impact ( 53) 12 2007 Revenue Requirements 29 13 Tax Impact ( 9) 14 2007 BC Hydro Rate Design - 15 Tax Impact - 16 2008 Revenue Requirements - 17 Tax Impact - 18 Terasen Gas ROE Application ( 3) 19 Tax Impact 6 20 ( 1,983) 21 22 Preliminary and Investigative Charges 1,814 23 24 Other Deferred Charges and Credits 25 Trail Office Lease Costs 203 26 Trail Office Rental to SD#20 ( 564) 27 Prepaid Pension Costs 5,732 28 Tax Impact (164) 29 Post Retirement Benefits (1,329) 30 Tax Impact 441 31 Renegotiation of Canal Plant Agreement 412 32 Tax Impact ( 59) 33 2005 System Development Plan 494 34 Tax Impact ( 25) 35 2008 System Development Plan Update - 36 Tax Impact - 37 Automated Meter Reading Feasibility Study - 38 Tax Impact - 39 2005 Resource Plan 91 40 Tax Impact ( 10) 41 2008 Resource Plan Update - 42 Tax Impact - 43 Hydro Electric Supply Study 21 44 Tax Impact ( 7) 45 Renew BCH Power Purchase Agreement 3 46 Tax Impact ( 1) 47 Discount Forfeit Defense (note 1) 48 Tax Impact (note 1) 49 Revenue Protection 590 50 Tax Impact (194) 51 Big White Supply Project 3,342 52 Tax Impact - 53 Innovative Clean Energy Fund Levy Implementation - 54 Tax Impact 55 PLP Transition costs 74 56 Tax Impact ( 24) 57 PLP Potential Substation 36 58 PLP Settlement Costs 63 59 PLP Computer Software 132 60 PLP Deferred Pension Credit ( 93) 61 PLP Deferred Rate Stabilization Account ( 75) 62 Other Deferred Charges and Credits - 63 9,089 64 Deferred Debt Issue Costs 65 Series E 10 66 Series F 142 67 Series G 127 68 Series H 121 69 Series I 213 70 Series J 196 71 Series 04-1 1,717 72 Tax Impact ( 36) 73 Series 05-1 1,199 74 Tax Impact (166) 75 Series 07-1 - 76 Tax Impact - 77 3,524 78 79 TOTAL DEFERRED CHARGES 18,453 80 Note 1: 81 Per the 2007 NSA regarding the Discount Forfeit defence costs, the 2007 opening Deferred Charges balance has been reduced by the of $110K 82 ($164K before tax); 2007 Additions and Transfers were reduced by $28k ($42K before tax) and 2007 closing Deferred Charges balance was 83 reduced by $138k ($206K before tax); and Interest of $10k on the average balance was included in 2007 rates. November 16, 2007 FortisBC Inc.
APPENDIX A to Order No. G-147-07 Additions and Amortized to Balance at Page 15 of 40 Transfers Other Accounts Amortization Dec. 31, 2007 ($000s) 2,473 ( 1,227) 19,128 ( 844) (12,908) ( 77) 113 1,629 - (1,304) 6,333 ( 1,306) 2,524 ( 1,306) ( 12) 22 (176) 353 - 51 ( 101) ( 53) 107 - 18 ( 35) 7 - 36 ( 2) - (11) 17 - 17 (6) - (6) 30 - 30 (10) - (10) 3 - ( 6) - ( 1,270) 2,512 (164) ( 905) 141 ( 1,874) - 81 ( 12) 191 ( 34) - (598) 535 - 6,267 ( 183) ( 347) ( 2,230) ( 3,559) 761 1,202 ( 412) - - 59 - (165) 330 - 9 (16) 250 250 (85) ( 85) 100 100 (34) ( 34) 11 ( 30) 72 ( 4) 3 (11) 350 350 (119) ( 119) ( 21) - 7 - - 3 - (1) - - 165 (590) 165 (56) 194 ( 56) ( 3,342) - - - - - 25 25 ( 9) ( 9) ( 74) - 24 - ( 11) 25 ( 16) 47 ( 23) 109 12 ( 81) - (75) - - - ( 3,879) ( 84) (982) 4,145 ( 3) 7 ( 13) 129 (9) 118 ( 14) 107 ( 13) 200 ( 65) 131 ( 215) 1,502 ( 20) 4 (52) ( 42) 1,157 ( 84) 6 (244) 1,300 - 1,300 (89) - (89) 1,107 - (363) 4,267 ( 2,272) 554 (2,813) 13,921 Page 5
2008 Revenue Requirements Financial Schedules – Negotiated Settlement Table 1 – B – Deferred Charges and Credits (2008) Balance at Dec. 31, 2007 Demand Side Management 1 Demand Side Management Additions 19,128 2 Tax Impact ( 12,908) 3 PLP Energy Management 113 4 6,333 5 Deferred Regulatory Expense 6 Provision for True-up for 2006 Incentive 22 7 Deferred Revenue - Incentive Adjustment ( 1,306) 8 2005 Revenue Requirements 353 9 Tax Impact (101) 10 2006 Revenue Requirements 107 11 Tax Impact ( 35) 12 2007 Revenue Requirements 36 13 Tax Impact ( 11) 14 2008 Revenue Requirements 30 15 Tax Impact ( 10) 16 2008 Cost of Service and Rate Design - 17 Tax Impact - 18 2009 Revenue Requirements - 19 Tax Impact - 20 2007 BC Hydro Rate Design 17 21 Tax Impact ( 6) 22 ( 905) 23 24 Preliminary and Investigative Charges 81 25 26 Other Deferred Charges and Credits 27 Trail Office Lease Costs 191 28 Trail Office Rental to SD#20 ( 598) 29 Prepaid Pension Costs 6,267 30 Tax Impact (347) 31 Post Retirement Benefits (3,559) 32 Tax Impact 1,202 33 2005 System Development Plan 330 34 Tax Impact ( 16) 35 2008 System Development Plan Update 250 36 Tax Impact ( 85) 37 Automated Meter Reading Feasibility Study 100 38 Tax Impact ( 34) 39 2005 Resource Plan 72 40 Tax Impact ( 11) 41 2008 Resource Plan Update 350 42 Tax Impact (119) 43 Hydro Electric Supply Study - 44 Tax Impact - 45 Renew BCH Power Purchase Agreement 3 46 Tax Impact ( 1) 47 Discount Forfeit Defense (note 1) 206 48 Tax Impact (note 1) ( 68) 49 Revenue Protection 165 50 Tax Impact ( 56) 51 Big White Supply Project - 52 Tax Impact - 53 Innovative Clean Energy Fund Levy Implementation 25 54 Tax Impact ( 9) 55 PLP Potential Substation 25 56 PLP Settlement Costs 47 57 PLP Computer Software 109 58 PLP Deferred Pension Credit ( 81) 59 PLP Deferred Rate Stabilization Account ( 75) 60 ROW Reclamation (Pine Beetle Kill) - 61 Tax Impact - 62 Industrial Load Forecast Variance - 63 Tax Impact - 64 Other Deferred Charges and Credits - 65 4,283 66 Deferred Debt Issue Costs 67 Series E 7 68 Series F 129 69 Series G 118 70 Series H 107 71 Series I 200 72 Series J 131 73 Series 04-1 1,502 74 Tax Impact ( 52) 75 Series 05-1 1,157 76 Tax Impact (244) 77 Series 07-1 1,300 78 Tax Impact ( 89) 79 4,267 80 81 TOTAL DEFERRED CHARGES 14,059 82 83 Note 1: 2007 opening Deferred Charges balance has been increased by the Discount Forfeit defence costs of $138K ($206K before tax). November 16, 2007 FortisBC Inc.
APPENDIX A to Order No. G-147-07 Additions and Amortized to Balance at Page 16 of 40 Transfers Other Accounts Amortization Dec. 31, 2008 ($000s) 2,355 (2,055) 19,428 ( 742) 668 (12,982) ( 77) 36 1,613 - (1,464) 6,482 ( 22) - 1,306 - ( 176) 177 51 (50) ( 53) 53 18 (18) (36) - 11 - - 30 - ( 10) 400 400 (126) ( 126) 50 - 50 ( 16) - ( 16) (17) - 6 - 308 1,284 ( 197) 491 310 ( 60) - 331 ( 12) 179 ( 39) - (637) 1,155 - 7,422 ( 364) ( 711) (2,230) (5,789) 702 1,904 ( 165) 165 9 ( 7) 125 375 ( 39) (124) (100) - 32 ( 2) (30) 42 3 ( 8) ( 88) 263 30 (89) - - - - 197 - 200 ( 62) 1 (62) ( 206) - 68 - 260 ( 165) 260 ( 82) 56 (82) - - - - - - (25) - 9 - (11) 14 (16) 31 ( 23) 86 12 ( 69) 75 - 2,500 - 2,500 (788) - (788) - - - - - - - - - 1,306 ( 39) ( 478) 5,072 ( 3) 4 ( 13) 116 ( 9) 110 ( 14) 93 ( 13) 187 ( 65) 66 ( 215) 1,288 ( 20) 7 (65) ( 42) 1,115 ( 84) 9 (319) ( 33) 1,267 ( 89) 2 (175) ( 193) - ( 388) 3,686 3,344 1,185 (2,527) 16,062 Page 6
2008 Revenue Requirements Financial Schedules – Negotiated Settlement SCHEDULE 2 – EARNED RETURN 1 SALES VOLUME (GW.h) 2 3 ELECTRICITY SALES REVENUE 4 5 EXPENSES 6 Power Purchases 7 Water Fees 8 Wheeling 9 Net O&M Expense 10 Property Tax 11 Depreciation and Amortization 12 Other Income 13 AFUDC 14 Incentive Adjustments 15 UTILITY INCOME BEFORE TAX 16 Less: 17 INCOME TAXES 18 19 EARNED RETURN 20 RETURN ON RATE BASE 21 Utility Rate Base 22 Return on Rate Base November 16, 2007 FortisBC Inc.
APPENDIX A to Order No. G-147-07 Page 17 of 40 Actual Forecast Forecast 2006 2007 2008 ($000s) 2 03,362 210,452 219,815 3 ,040 3,096 3,087 203,362 210,452 219,815 6 7,576 66,938 67,403 8 ,371 7,904 7,858 3 ,840 3,471 3,622 3 2,337 33,796 36,248 1 0,275 10,637 11,176 2 6,746 30,932 34,356 (5,153) ( 5,273) (5,030) (2,360) - - 2 ,431 ( 1,206) (1,284) 5 9,299 63,253 65,466 6,504 6,069 3,989 52,795 57,185 61,477 674,773 744,115 822,847 7.82% 7.68% 7.47% Page 7
2008 Revenue Requirements Financial Schedules – Negotiated Settlement Table 2 – A – 1 – Sales by Customer Class
Actual Forecast Forecast 2006 2007 2008 (GWh)
1 Residential 2 General Service 3 Industrial 4 Wholesale 5 Lighting 6 Irrigation 7 Total Sales 8 Losses and Company Use 9 Gross Load Table 2 – A – 2 – Sales Revenue by Customer Class
10 Residential 11 General Service 12 Industrial 13 Wholesale 14 Lighting and Irrigation 16 Total 17 18 * Forecast at 2007 approved rates Table 2 – A – 3 – Customers at Year-End 19 Residential 20 General Service 21 Wholesale 22 Industrial 23 Lighting & Irrigation 24 Total 25 26 * 2007 Customers include 3,212 acquired from PLP November 16, 2007 FortisBC Inc.
APPENDIX A to Order No. G-147-07 Page 18 of 40
1,091 1,155 1,193 598 637 686 344 362 240 948 878 904 16 13 13 43 51 51 3,040 3,096 3,087 365 321 309 3,405 3,417 3,396 Actual Forecast Forecast 2006 2007 2008 * ($000s)
87,446 92,626 96,014 46,844 49,888 54,293 18,871 20,692 15,182 46,299 42,922 43,779 3,902 4,324 4,426 203,362 210,452 213,694 Actual Forecast Forecast 2006 2007 2008 89,181 93,515 96,022 10,285 11,116 11,471 8 7 7 37 40 36 2,902 3,227 3,227 102,413 107,905 110,763 Page 8
2008 Revenue Requirements Financial Schedules – Negotiated Settlement Table 2 – B – Power Purchase Expense
1 FortisBC 2 DSM 3 Power Purchases (net of surplus sales) 4 Total System Load (before DSM savings) 5 Less DSM 6 Total System Load (including DSM savings) 7 Expense - Energy 8 Expense - Capacity 9 Upgrade Life Extension credits and other adjustments (229) 1 0 Total Power Purchase Expense November 16, 2007 FortisBC Inc.
APPENDIX A to Order No. G-147-07 Page 19 of 40
Actual Forecast Forecast 2006 2007 2008 GW.h 1 ,506 1,498 1,572 4 5 11 1 ,899 1,919 1,824 3 ,409 3,422 3,407 (4) ( 5) ( 11) 3 ,405 3,417 3,396 ($000s) 5 6,264 56,439 55,317 1 1,541 12,321 13,717 ( 1,822) ( 524) 6 7,576 66,938 67,403 Page 9
2008 Revenue Requirements Financial Schedules – Negotiated Settlement SCHEDULE 3 – INCOME TAX EXPENSE
Actual Forecast Forecast 2006 2007 2008 ($000s)
1 UTILITY INCOME BEFORE TAX 2 Deduct: 3 Interest on Non Rate Base Deferral Account 4 Interest Expense 5 6 ACCOUNTING INCOME 7 8 Adjustments to Accounting Income 9 to arrive at Taxable Income 10 11 Deductions 12 Capital Cost Allowance 13 Capitalized Overhead 14 AFUDC 15 Additions to Deferred Charges for Tax Purposes 2,325 16 Incentive & Revenue Deferrals 17 Financing Fees 18 All Other (net effect) 19 20 21 Additions 22 Amortization of Deferred Charges 23 Depreciation 24 25 26 TAXABLE INCOME 27 28 Tax Rate 29 30 Taxes Payable 31 Prior Years' Overprovisions/(Underprovisions) 32 Deferred Charges Tax Effect 33 Large Corporations Tax 34 Allowance for tax audit 35 36 REGULATORY TAX PROVISION November 16, 2007 FortisBC Inc.
APPENDIX A to Order No. G-147-07 Page 20 of 40
59,299 63,253 65,466 - 10 27 26,112 28,813 31,762 33,187 34,430 33,678 30,730 38,119 44,421 8,382 8,836 9,062 2,360 - - - - - 1,206 1,284 - 933 933 (1,180) (875) 281 42,617 48,219 55,981 2,221 2,813 2,527 24,525 28,119 31,829 26,746 30,932 34,356 17,315 17,143 12,052 34.12% 34.12% 31.50% 5,908 5,849 3,796 (302) 31 - 898 189 193 - - - - - -6,504 6,069 3,989 Page 10
2008 Revenue Requirements Financial Schedules – Negotiated Settlement SCHEDULE 4 – COMMON SHARE EQUITY
Actual Forecast Forecast 2006 2007 2008 ($000s)
1 Share Capital 2 Retained Earnings 3 4 COMMON EQUITY - OPENING BALANCE 5 6 Less: Common Dividends 7 8 Add: Net Income Share Adjustment 9 Shares Issued 10 11 COMMON EQUITY - CLOSING BALANCE 12 13 SIMPLE AVERAGE 14 15 Adjustment for Shares Issued 16 Deemed Equity Adjustment 17 18 COMMON EQUITY - AVERAGE November 16, 2007 FortisBC Inc.
APPENDIX A to Order No. G-147-07 Page 21 of 40
128,000 148,000 168,000 144,724 143,329 159,899 272,724 291,329 327,899 (10,200) (11,800) (13,400) 26,683 28,370 29,688 (17,878) 20,000 20,000 20,000 291,329 327,899 364,187 282,027 309,614 346,043 (13,573) (7,397) (4,110) - (4,571) (12,794) 268,454 297,646 329,139 Page 11
2008 Revenue Requirements Financial Schedules – Negotiated Settlement SCHEDULE 5 – RETURN ON CAPITAL
Actual Forecast Forecast 2006 2007 2008 ($000s)
1 Secured and Senior Unsecured Debt 2 Proportion 3 Embedded Cost 4 Cost Component 5 Return 6 7 Short Term Debt 8 Proportion 9 Embedded Cost 10 Cost Component 11 Return (including fees) 12 13 14 Common Equity 15 Proportion 16 Embedded Cost 17 Cost Component 18 Return 19 20 TOTAL CAPITALIZATION 21 RATE BASE 22 23 Earned Return 24 25 RETURN ON CAPITAL 26 RETURN ON RATE BASE November 16, 2007 FortisBC Inc.
APPENDIX A to Order No. G-147-07 Page 22 of 40
385,968 437,718 489,468 57.20% 58.82% 59.48% 6.49% 6.42% 6.36% 3.71% 3.78% 3.78% 25,062 28,111 31,126 20,352 8,752 4,240 3.02% 1.18% 0.52% 5.16% 8.02% 15.00% 0.16% 0.09% 0.08% 1,050 702 636 268,454 297,646 329,139 39.78% 40.00% 40.00% 9.94% 9.53% 9.02% 3.95% 3.81% 3.61% 26,683 28,370 29,688 674,774 744,116 822,847 674,774 744,116 822,847 52,795 57,183 61,450 7.82% 7.68% 7.47% 7.82% 7.68% 7.47% Page 12
2008 Revenue Requirements Financial Schedules – Negotiated Settlement FORECAST RETURN ON CAPITAL
1 Bond Yield per: 2 10 year Government of Canada Bond Yield 3 Premium from 30 Year Bond Yield 4 5 Forecast 30 Year Bond Yield 6 Add/Subtract 25% of yield under 5.25% 7 Adjusted Yield 8 Premium for Low Risk Utilities 9 BCUC Benchmark Forecast 1 0 Rounded Benchmark ROE 1 1 FortisBC Risk Premium 1 2 FortisBC Allowed ROE 1 3 1 4 Rate Base 1 5 Equity Ratio 1 6 Allowed ROE 1 7 Net Earnings November 16, 2007 FortisBC Inc.
APPENDIX A to Order No. G-147-07 Page 23 of 40
Approved Forecast 2007 2008 4 .150 4.500 0.069 0.049 4.219 4.549 0.258 0.175 4.477 4.724 3.895 3.895 8.372 8.619 8.370 8.620 0.400 0.400 8 .770 9.020 822,847 40% 9.02% 29,688 Page 13
The British Columbia Public Interest Advocacy Centre 208–1090 West Pender Street Vancouver, BC V6E 2N7 Tel: (604) 687-3063 Fax: (604) 682-7896 email: bcpiac@bcpiac.com http://www.bcpiac.com Via email November 22, 2007 Erica Hamilton Commission Secretary BC UTILITIES COMMISSION Sixth Floor - 900 Howe Street Vancouver, BC V6Z 2N3
Re: FortisBC Inc. –2008 Revenue Requirements Negotiated Settlement Agreement BCOAPO et al. approves the 2008 Revenue Requirements Negotiated Settlement Agreement dated November 19, 2006, subject to the following wording change in Issue #2 - "Income Tax" under Tab 3 (page 3 of the final NSA) that has been agreed to by BCUC staff, FortisBC and BCOAPO et al.:
"The expected federal corporate income tax reduction will be included in 2008 revenue requirements. If it is not enacted, the difference is subject to Z-factor treatment. will be captured in a deferral account and flowed through to 2009 revenue requirements”.
We would like to thank Commission staff and the parties for their efforts in reaching the NSA Yours truly, BC PUBLIC INTEREST ADVOCACY CENTRE Original in file signed by Sarah Y. Khan Barrister & Solicitor
SYK/ar
C:\Documents and Settings\jeyang\Local Settings\Temporary Internet Files\OLK13\HamiltonNSAletNov 22 07 (2).doc
Sarah Khan 687-4134 Patricia MacDonald 687-3017 James L. Quail 687-3034 Ros Salvador 488-1315 Leigha Worth 687-3044 Barristers & Solicitors Eugene Kung Articled Student APPENDIX A to Order No. G-147-07 Page 24 of 40
APPENDIX A to Order No. G-147-07 Page 25 of 40
APPENDIX A to Order No. G-147-07 Page 26 of 40
I.M.E.U. Interior Municipal Electrical Utilities Cities of Kelowna, Penticton, Grand Forks, District of Summerland, Nelson Hydro
November 22, 2007 Via Email William J. Grant Transition Advisor British Columbia Utilities Commission Sixth Floor, 900 Howe Street, Box 250 Vancouver BC V6Z 2N3
Dear Mr. Grant: Re: FortisBC Negotiated Settlement 2008 Revenue Requirements Application
The IMEU is in receipt of your letter dated November 19, 2007 requesting acceptance of the Negotiated Settlement Agreement (NSA) for the FortisBC 2008 Revenue Requirements Application.
We understand that a wording change in the section of the NSA discussing Income Tax has been agreed upon between BCOAPO, FortisBC and BCUC Staff. We have been in contact with Sarah Khan and are also in agreement with that change. We further confirm that the IMEU accepts the remainder of the NSA as attached to your November 19 letter.
If you have any questions or concerns, please contact the undersigned at (250) 352-8212, or by e-mail at rleslie@nelson.ca
Respectfully submitted,
_________________________ Russell Leslie, P.Eng Chairman, IMEU
cc: IMEU group Participants
Page 1 of 1 APPENDIX A to Order No. G-147-07 Page 27 of 40
Yang, Jeffrey BCUC:EX From: Al Wait [alwait@telus.net] Sent: Wednesday, November 21, 2007 4:38 PM To: Yang, Jeffrey BCUC:EX Subject: FortisBC 2008 NSP
Mr. Yang: I wish to confirm that I am in agreement with the FortisBC Negotiated Settlement for 2008 recently completed in Kelowna.
Alan Wait
2007-11-23
APPENDIX A to Order No. G-147-07 Page 28 of 40
Fortis BC 2008 Revenue Requirements Application Response to Negotiated Settlement Agreement
By: Ludo Bertsch, Horizon Technologies Inc. Date: Nov 22, 2007 BCUC Project Number: 3698478
Background Ludo Bertsch, participant in the Negotiated Settlement Process (NSP), has received support from a number of companies and individuals including:
- Alternergy Systems - Andrew Illingworth - Avalon Alliance - BC Sustainable Energy Association – Okanagan chapter - Best Western Inn Kelowna - Coast Energy Management Collaborative - Complete Home Energy Ltd. - Dan Huang - David Smith, member of the Canadian Institute of Planners and Planning Institute of BC; Planning Director, Peachland, BC - Delta Geothermal Limited - Dr Gord Lovegrove, P.Eng, UBC Okanagan - Dunlop Renewable Energy Ltd. - Eco Wise Water Systems Ltd. - Energy Solutions for Vancouver Island - Erin Radomske, Biology Department, Okanagan College - Gail Hourigan - Geoff Hann, P. Eng - GeoTility Systems Corp. - Greig Crockett, retired lawyer - Horizon Technologies Inc. - Intelligent Database Solutions Inc. - IPS Integrated Power Systems - J LeCavalier & Associates Inc. - Jenergy Technologies - Kelowna Kasugai Sister City Association - Komatsu Japanese Market - Naramata Conservation - Okanagan Environmental Industry Alliance - Okanagan Sustain Homes - Quantum Wind Power Corp. Ludo Bertsch, Horizon Technologies Ref: 2007.FortisBCRDA.NSPResponse.010.doc Page 1 of 11
APPENDIX A to Order No. G-147-07 Page 29 of 40
- Rob Dahl, teacher, Springvalley Middle School - Robert J. Dantzer, P. Eng - S2 Innovative Products Group Ltd. - S. Wright Logistics, Management, Consulting - Swiss Solar Tech - Terra Firm Inc. - Terra Geothermal Corp. - Tigress Ventures - The Wellness Spa - Wendy Wright - Windterra Systems Inc. We do not support the Negotiated Settlement Agreement as described in the document labeled “FortisBC Inc. 2008 Revenue Requirement Negotiated Settlement Agreement”. Our suggested changes and supporting reasons are described below:
NSP Issues 1.0 FortisBC Cost of Service and Rate Design Application (2008) (Sec. 3.8.2) Issue Description: “FortisBC forecast $600,000, before tax, for its Cost of Service Analysis and Rate Design Application” Resolution: “For budget purposes, the forecast will be reduced to $400,000, before tax” Our submission: Add more description to the scope of the Rate Design Application for the budget of $600,000, include general tariffs for customers to sell power back to FortisBC, include budget line items (e.g. “Stakeholder Consultation”), and have meaningful engagement of stakeholders before submitting applications, such as the Rate Design application and the Advanced Meter Infrastructure CPCN.
The BCUC Order in response to Time-of-Use rates for FortisBC states: “FortisBC is directed to file a Rate Design application on or before September 1, 2008. The Rate Design application should include a proposal for Time-of-Use rates that will apply to all customers within the merged PLP/FortisBC service area.” 1 The FortisBC update of November 1, 2007 provided a cost estimate for the Cost of Service and Rate Design Application (RDA) at $600,000 2 with specific 1 BCUC Order G-115-07, Sept. 21, 2007 2 FortisBC 2008 RRA Exhibit B-1-2, Tab 3, Section 3.8.2 vi, Page 30 Ludo Bertsch, Horizon Technologies Ref: 2007.FortisBCRDA.NSPResponse.010.doc Page 2 of 11
APPENDIX A to Order No. G-147-07 Page 30 of 40
line item costs. No further description of the scope of the RDA was included with the cost estimate.
Without such a description, there is a wide range of options that the RDA could cover and correspondingly a wide range of costs. For example, here are several of those options:
1. FortisBC’s RDA might only cover the Time-of-Use rates. 2. On the other hand, FortisBC’s RDA could cover similar topics as those in BC Hydro’s 2007 RDA, which “sets the foundation for BC Hydro’s future rate design proposals” 3 . 3. Yet another option for FortisBC’s RDA is to implement new rates such as allowing customers which generate their own electricity (e.g. solar panels) to sell power back to FortisBC at prescribed rates. These rates help support the government’s commitment to the 2007 Energy Plan released Feb 27, 2007 and the recently introduced Greenhouse Gas Reduction Targets Act (Bill 44).
For example, BC Hydro has had a net metering program since 2004 4 where 5.4 c/kWh is paid for excess electricity from a customer for installations up to 50kW. BC Hydro is presently proposing a “Standing Offer Program” 5 in which approx 5 c/kWh to 10 c/kWh is paid for larger customers.
Ontario Hydro has a “Renewable Energy Standard Offer Program” 6 established in 2006 modeled on the best practice in European countries where small hydro and wind are paid 11 c/kWh and solar energy are paid 42 c/kWh.
Without a further clarifying description of the scope for the Rate Design Application, we submit that is not possible to gauge whether or not the stated budget is suitable.
The resolution of the NSP agreement to reduce the budget to $400,000 7 is also evidence of the need for this description. Without the RDA scope description, a reduction in the budget may result in a smaller scope of the RDA. Similarly, there may be more support from Intervenors and the BCUC for a larger budget if a wider scope for the RDA is presented.
3 BC Hydro 2007 RDA Exhibit B-1, page 3 4 BC Hydro Electric Tariff, Schedule 1289, March 10, 2004 5 BC Hydro Standing Offer Program Rates, Revised July 5, 2007 6 Ontario Hydro Renewable Energy Standard Offer Program 7 FortisBC RRA NSP, “FortisBC Cost of Service and Rate Design Application” issue Ludo Bertsch, Horizon Technologies Ref: 2007.FortisBCRDA.NSPResponse.010.doc Page 3 of 11
APPENDIX A to Order No. G-147-07 Page 31 of 40
The specific line items for the reduced budget of $400,000 are not provided, so it is not clear where the reductions are expected to be made. In particular, it is not clear if the “Stakeholder Consultation” budget of $50,000 8 of the original will be reduced for this new budget estimate.
An indication of the challenges of a rate design application for FortisBC and the anticipated response from the BCUC are demonstrated in the 2007 Rate Design Application by BC Hydro. BCUC’s response to BC Hydro’s application also demonstrates the Commission Panel’s support of not only substantial stakeholder engagement, but also early engagement.
The Commission Panel made overall comments on BC Hydro’s RDA in its latest decision in a section called “Views of the Commission Panel on the Application and Determination” 9 : “The Commission Panel is struck by the limited scope of the matters on which BC Hydro chose to engage with its stakeholders, and the minimal engagement with them in the process of developing the RDA, particularly since its last RDA was filed in 1991 – sixteen years ago. Given the amount of strategic and policy direction BC Hydro has received in the intervening years by way of direction from the Commission, and from its Shareholder, the Province, by way of the 2002 and 2007 Energy Plans, and in point of fact from the public pronouncements of its own executive, as highlighted in Sections 1 and 2 of this Decision, the Commission Panel finds BC Hydro’s response disappointing.” 10 “. . . clearly illustrates that it did not engage with its stakeholders to any meaningful degree on the fundamental role that rates, and their structure, can, and should, play in the achievement of the strategic agenda that has been set for it.” 11 “It is clear that Intervenors were not provided the opportunity to participate in meaningful dialogue as to the ‘issues and proposals to be addressed in the F2008 RDA’ but rather were informed as to what BC Hydro had decided was going to be brought forward, and given limited opportunity to comment on a narrow range of issues and options of a non-strategic nature. Given that, the Intervenors have been left with no choice but to put their agendas for constructive change before this Commission Panel.” 12 8 FortisBC 2008 RRA Exhibit B-1-2, Tab 3, Section 3.8.2 vi, Page 30 9 BC Hydro 2007 Rate Design Application, BCUC Decision Phase 1, October 26, 2007, section 2.7 10 BC Hydro 2007 Rate Design Application, BCUC Decision Phase 1, October 26, 2007, pg 56 11 BC Hydro 2007 Rate Design Application, BCUC Decision Phase 1, October 26, 2007, pg 56 12 BC Hydro 2007 Rate Design Application, BCUC Decision Phase 1, October 26, 2007, pg 57 Ludo Bertsch, Horizon Technologies Ref: 2007.FortisBCRDA.NSPResponse.010.doc Page 4 of 11
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“The Commission Panel contrasts the Stakeholder consultations BC Hydro conducted in order to inform the 2007 RDA, with those it conducted in support of its 2006 IEP/LTAP proceedings before this Commission. In finding that BC Hydro had appropriately engaged its stakeholders in those matters (IEP/LTAP Decision, May 11, 2007, p. 31) the Commission had before it a 286 page document entitled ‘First Nations and Stakeholder Report (ibid p. 27). In this proceeding, BC Hydro filed a 20 page ‘Stakeholder Engagement Summary’ fully 40 percent of which is concerned with the relatively small and unique E-Plus customer subset.” 13 “The Commission Panel also observes that a sense of urgency appears to be missing in the 2007 RDA, which contradicts with the message to be found in the external communications of the BC Hydro Executive. BC Hydro’s assertion that it has conducted significant rate design work over the past three years (Opening Statement, Exhibit B-24) is at odds with the absence of innovative proposals in the 2007 RDA.” 14 Further indications of the need for stakeholder engagement are demonstrated in BC Hydro’s proposed changes to its Large General Service Rates in the same RDA 15 : “The evidence before the Commission Panel is that BC Hydro’s stakeholder engagement process consisted of two workshop meetings at which only two options (one of which retained a declining block structure) were presented to customers, and that part of BC Hydro’s proposed mitigation was an offer of participation in its Power Smart programs, which were programs already in existence.
The Commission Panel finds that BC Hydro’s proposed restructuring of its Large General Service class was ill-conceived and poorly executed. The proposal is denied.” 16 “The Commission Panel is also concerned that while it heard statements from BC Hydro that further structural changes to the Large General Service cannot be undertaken until after its proposed phasein period, it did not receive any indication of what those changes may look like, and as a result the Commission Panel cannot be sure that where BC Hydro’s proposal takes the class would be a logical place to start further structural changes. In the Commission Panel’s view the stakeholder engagement should start with the long view rather than vice versa.” 17 13 BC Hydro 2007 Rate Design Application, BCUC Decision Phase 1, October 26, 2007, pg 58 14 BC Hydro 2007 Rate Design Application, BCUC Decision Phase 1, October 26, 2007, pg 58 15 BC Hydro 2007 Rate Design Application, BCUC Decision Phase 1, October 26, 2007, section 4.4 16 BC Hydro 2007 Rate Design Application, BCUC Decision Phase 1, October 26, 2007, pg 162 17 BC Hydro 2007 Rate Design Application, BCUC Decision Phase 1, October 26, 2007, pg 162 Ludo Bertsch, Horizon Technologies Ref: 2007.FortisBCRDA.NSPResponse.010.doc Page 5 of 11
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“Accordingly, BC Hydro is directed to commence meaningful stakeholder engagement with its Large General Service customers to develop, and file with the Commission an application for a rate structure or structures that encourage conservation without unduly benefiting or harming any of its customers in that class.” 18 In summary, we submit that: a) FortisBC should provide more description to the scope of the Rate Design Application to support its original budget of $600,000.
b) If FortisBC changes its budget from $600,000, that new budget should indicate the amounts for specific line items, including “Stakeholder Consultation”.
c) FortisBC should include general tariffs for customers to sell power back to FortisBC in its upcoming RDA application.
d) FortisBC should have meaningful engagement of stakeholders before submitting applications, such as the Rate Design Application and the Advanced Meter Infrastructure CPCN.
2.0 Demand Side Management (Sec. 7.2.7) Issue Description: Set 2008 DSM projection at 19.5 GWh Resolution: Maintain 2008 DSM projection at 19.5 GWh Our submission: Increase DSM projection to 23.9 GWh or higher
The DSM expenditure projections were developed as part of the 2007-2008 Capital Expenditure Plan released on July 26, 2006 notes the following projections:
Total Savings (GWh) – July 26, 2006: 2006 20.5 18 BC Hydro 2007 Rate Design Application, BCUC Decision Phase 1, October 26, 2007, pg 163 19 FortisBC 2007-2008 Capital Expenditure Plan, July 26, 2006 Ludo Bertsch, Horizon Technologies
19 . The July 26, 2006 plan
2007 2008 21.8 19.5 Ref: 2007.FortisBCRDA.NSPResponse.010.doc Page 6 of 11
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The actual energy savings to year-end is now projected to be 28.5 GWh which is 31 percent higher resulting in the following table:
Total Savings (GWh) – (from 2008 RRA Update): 2006 20.5 In the FortisBC 2007 RRA, the DSM Energy savings years (2002 – 2005) were noted and are added to create the table below:
Total Savings (GWh) – (from 2007 RRA & 2008 RRA Update): 2002 2003 2004 16.3 18.5 21.7 There is a clear trend toward increasing savings. There is appropriately a 75% increase from 2002 to 2007.
The FortisBC RRA proposal to set the 2008 estimate to 19.5 GWh puts it below the 2004 level, even though all years since 2004 have been above that level.
One method to analyze the trend is to use a three year moving average similar to the FortisBC safety and health metrics average results would be:
3 Year Moving Average - Total Savings (GWh): 2005 2006 2007 2008 18.8 21.0 21.6 23.9 This gives an indication to the trend of the DSM savings, on top of which other parameters may adjust the trend accordingly. For example, the 2007 BC Energy Plan 23 clearly places an emphasis on DSM which would tend to further increase the 2008 levels (see next item for further discussion on the new BC Energy Plan).
It is not unusual for FortisBC to update its Capital Expenditure Plan according to the latest information - in the November 1, 2007 submission FortisBC
20 FortisBC 2008 RRA Exhibit B-2, BCUC IR#1, A53.1.3 21 FortisBC 2007 RRA BCUC IR#1, A35.1 22 FortisBC 2008 RRA, Exhibit B-1, Tab 8, Section 8.1.1 23 FortisBC 2008 RRA, Exhibit B-2, Horizon IR#1, A14.1, 2007 BC Energy Plan Ludo Bertsch, Horizon Technologies Ref: 2007.FortisBCRDA.NSPResponse.010.doc Page 7 of 11
20 ,
2007 2008 28.5 19.5 21 over the previous
2005 2006 2007 2008 22.7 20.5 28.5 19.5
22 . The three year moving
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updated 15 capital projects 24 , but did not update the DSM plan. In summary, we submit that: The projected 2008 DSM Savings level should be at least 23.9 GWh.
3.0 2007 BC Energy Plan Issue Description: - nil -Resolution: “Fortis will continue to consider the BC Energy Plan in its 2008 projects and applications.” Our submission: “Fortis will consider the 2007 BC Energy Plan in all its 2008 projects and applications.”
The 2008 FortisBC RRA’s application date was 7 months after the 2007 BC Energy Plan, which was released on February 27, 2007 25 . The new Energy Plan determined that utilities should explore new rate structures that encourage energy efficiency and conservation, and should pursue cost effective and competitive demand side management 26 . In response to Horizon’s IR#1, FortisBC stated that “It will take some time to consider the fifty-five policy items, firstly to determine which are relevant to FortisBC, secondly to determine how best to proceed and thirdly to complete due process.” “The Company” . . . .”will incorporate the relevant elements of the Energy Plan policy action items into the next DSM business plan”. 27 FortisBC has not committed to a firm timeframe for consideration of the new Energy Plan policy items other than consideration in the next DSM business plan. Without such timeframe, FortisBC could effectively avoid such consideration by taking an extraordinary length of time.
In addition, we submit that FortisBC has already had ample time to consider the new BC Energy Plan - other utilities have already considered the new BC Energy Plan in their applications as the examples below indicate.
24 FortisBC 2008 RRA, Exhibit B-1-2, Tab 7, Appendix 1 25 FortisBC 2008 RRA, Exhibit B-2, Horizon IR#1, A14.1, 2007 BC Energy Plan 26 FortisBC 2008 RRA, Exhibit B-2, Horizon IR#1, A14.1, 2007 BC Energy Plan, Policy Actions #3 and #4 27 FortisBC 2008 RRA, Exhibit B-2, Horizon IR#1, A1.1 Ludo Bertsch, Horizon Technologies Ref: 2007.FortisBCRDA.NSPResponse.010.doc Page 8 of 11
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For example, BC Hydro considered the new plan after only 16 days in their March 15, 2007, Rate Design Application. In the section “Context for the 2007 Rate Design Application” 28 BC Hydro states: “On February 27, 2007, the Provincial Government released its 2007 Energy Plan (‘The BC Energy Plan: A Vision for Clean Energy Leadership’). The new Energy Plan sets out a large number of policy actions that place emphasis on energy conservation, energy efficiency and clean energy, and sets the direction to make British Columbia electricity self sufficient by 2016. An energy conservation target of meeting 50% of incremental resource needs through demand reduction by 2020 is established. With specific reference to utility rates, Policy Action 4 addresses the use of pricing structures as a demand side management tool to either discourage consumption overall, or shift demand to less costly periods. In particular:
‘all utilities are encouraged to explore, develop and propose to the Commission additional innovative rate designs that encourage efficiency, conservation and the development of clean or renewable energy’.
In this policy context BC Hydro’s 2007 Rate Design Application sets the foundation for BC Hydro’s future rate design proposals that will address the opportunities to use rate structures to contribute to the implementation of the government’s 2007 Energy Plan. As noted in the section below BC Hydro is currently developing a long term rate strategy that will be informed by the 2007 Energy Plan and that will set the course for future rate changes and new rates that are designed to promote energy conservation and load management.” 29 Another example of an utility responding to the new BC Energy Plan is Terasen Gas. In its “System Extension and Customer Connection Policy Review” 30 with the BCUC, submitted on July 31, 2007, the new BC Energy Plan was prominent.
Terasen Gas in its introduction states: “These changes will promote the responsible use of natural gas as a method to achieve energy efficiency and optimal use of resources within the broader energy market, which the Companies believe is consistent with the objectives of the 2007 BC Energy Plan – A Vision for Clean Energy Leadership (the “Energy Plan”) released by the
28 BC Hydro 2007 Rate Design Application, Exhibit B-1, March 15, 2007, section 1.2 29 BC Hydro 2007 Rate Design Application, Exhibit B-1, March 15, 2007, pages 2-3 30 Terasen Gas System Extension & Customer Connection Policy Review, July 31, 2007 Ludo Bertsch, Horizon Technologies Ref: 2007.FortisBCRDA.NSPResponse.010.doc Page 9 of 11
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Ministry of Energy, Mines and Petroleum Resources in the spring of 2007.” 31 “The Companies believe that as a result of the current economic climate, and specifically the release of the BC Energy Plan, the connection and attachment policies should help meet societal and governmental policy and objectives, including promoting energy efficiency and conservation and also encourage the optimal consumer energy mix.
The Energy Plan is ‘a made in BC solution to the common global challenge of ensuring a secure, reliable supply of affordable energy in an environmentally responsible way’ 32 . The document outlines 55 policy actions to help BC achieve this goal. The Terasen Utilities are supportive of the Energy Plan and believe that all energy utilities can and should play an integral role in helping BC meet and exceed the goals as set out in the Energy Plan.
The Terasen Utilities see a number of policy actions for which achievement of their objectives will be dependent on changes in the approach to customer connection and attachment activities for both gas and electric utilities:
• Policy Action #2, states ‘Ensure a coordinated approach to conservation and efficiency is actively pursued in British Columbia’ 33 . This action further states that ‘some programs, such as targeting household space and water heating, may not be justified on the basis of either electricity savings or gas savings alone. However, a coordinated effort may be cost-effective’. • Policy Action #3 ‘Encourage[s] utilities to pursue cost effective and competitive demand side management opportunities’. The action further states that ‘Energy efficiency is a critical piece of all BC utility resource plans’ 34 . • Policy Action # 4 ‘Explore with B.C. utilities new rate structures that encourage energy efficiency and conservation’. The action further states that utilities are encouraged to ‘explore, develop and propose to the Commission additional innovative rate designs that encourage efficiency [and include] tariffs focused on promoting energy efficient new construction…’ 35 . 31 Terasen Gas System Extension & Customer Connection Policy Review, July 31, 2007, Exhibit B-1, pg 1 32 FortisBC 2008 RRA, Exhibit B-2, Horizon IR#1, A14.1, 2007 BC Energy Plan, page 2 33 FortisBC 2008 RRA, Exhibit B-2, Horizon IR#1, A14.1, 2007 BC Energy Plan, page 1 34 FortisBC 2008 RRA, Exhibit B-2, Horizon IR#1, A14.1, 2007 BC Energy Plan, page 3 35 FortisBC 2008 RRA, Exhibit B-2, Horizon IR#1, A14.1, 2007 BC Energy Plan, page 4 Ludo Bertsch, Horizon Technologies Ref: 2007.FortisBCRDA.NSPResponse.010.doc Page 10 of 11
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• Policy Action # 24 states, ‘A policy action of The BC Energy Plan is to review the BC Utilities Commission’s role in considering social, environmental and economic costs and benefits as a part of its regulatory framework’ 36 . The Companies believe that the changes requested in this Application are consistent with these Energy Plan policy actions.” 37 We submit that 8 months after the new Energy Plan release FortisBC should be required to consider the BC Energy Plan in all its projects and applications. Without the use of the word “all” (as per the NSP agreement resolution), FortisBC could choose not to consider the Energy Plan for essentially all its projects, and only consider the occasional project. By using the word “all” (as per our submission) FortisBC would still be able to decide on a project-by-project basis which, if any, policy actions are relevant to each particular project, but would be required at least to determine such relevancy.
It is also important to note that the new BC Energy Plan (e.g. 2007) is focus of this item and not the previous Energy Plan (e.g. 2002) - hence the addition of “2007” in our submission to clarify.
Our submission removes the words “continue to” as we submit that FortisBC has not given any evidence that it has considered the 2007 BC Energy Plan in this application.
Therefore, we submit that the statement in the NSP regarding the Energy Plan should changed to:
“Fortis will consider the 2007 BC Energy Plan in all its 2008 projects and applications.”
36 FortisBC 2008 RRA, Exhibit B-2, Horizon IR#1, A14.1, 2007 BC Energy Plan, page 6 37 Terasen Gas System Extension & Customer Connection Policy Review, July 31, 2007, Exhibit B-1, pages 3-4
Ludo Bertsch, Horizon Technologies
Ref: 2007.FortisBCRDA.NSPResponse.010.doc Page 11 of 11
APPENDIX A to Order No. G-147-07
November 23, 2007 Ms. Erica M. Hamilton Commission Secretary BC Utilities Commission Sixth Floor, 900 Howe Street, Box 250 Vancouver, BC V6Z 2N3
Dear Ms. Hamilton: Re: FortisBC Inc. 2008 Revenue Requirements Negotiated Settlement Agreement
FortisBC Inc. (“FortisBC” or “the Company”) approves the 2008 Revenue Requirements Negotiated Settlement Agreement (“NSA”) dated November 19, 2007, including the following wording change with regard to Income Tax requested by BCOAPO:
“The expected federal corporate income tax reduction will be included in 2008 revenue requirements. If it is not enacted, the difference is subject to Z-factor treatment. will be captured in a deferral account and flowed through to 2009 revenue requirements.”
FortisBC would like to thank the Parties and Commission Staff for their efforts in reaching this Agreement and appreciates the letters of support for the NSA.
The Company considers it necessary to comment on a letter received on November 22, 2007 from Horizon Technologies Inc. (“Horizon”), which FortisBC understands is a company based outside of FortisBC’s service territory that sells energy efficiency related consulting services. The Company respectfully submits that the letter, which does not support the NSA, should not be given any weight when considering the approval of the NSA. The Horizon letter raised three concerns with respect to (1) FortisBC Cost of Service Study and Rate Design Application, (2) Demand Side Management and (3) 2007 BC Energy Plan. FortisBC comments are as follows:
(1) FortisBC Cost of Service Study and Rate Design (“RDA”) The issues of scope, participation and recommendations relating to the FortisBC RDA are matters that should be addressed in the RDA and not the 2008 Revenue Requirements and NSA. Furthermore the determination of budgeted costs for the RDA is only meant to be an estimate of the revenue requirements impact of the process and not a definition or limitation of the scope of the FortisBC RDA. Finally,
David Bennett FortisBC Inc. Page 39 of 40 Vice President, Regulatory Affairs Department Regulatory Affairs & General Counsel 1290 Esplanade Box 130 Trail BC V1R 4L4 Fax: 1 866 605 9431 regulatory@fortisbc.com www.fortisbc.com
FortisBC Negotiated Settlement Agreement November 23, 2007 the adequacy of BC Hydro’s RDA is arguably not relevant to FortisBC’s RDA and certainly not relevant to FortisBC’s Revenue Requirements Application and NSA.
(2) Demand Side Management The Demand Side Management (“DSM”) program was addressed and approved in the 2007 and 2008 Capital Expenditure Plan application. The Company will file another Capital Expenditure Plan in 2008. The planned savings set out in the 2008 FortisBC Revenue Requirement Application were reviewed by the DSM Committee and are appropriate. FortisBC does not support the recommendation set out in the letter by Horizon.
(3) 2007 BC Energy Plan (“the Energy Plan”) FortisBC continues to support the 2007 BC Energy Plan and will continue to consider the Energy Plan in its 2008 projects and applications as appropriately stated in the NSA. Negotiating a specific standard and scope of consideration of the Energy Plan for all future regulatory applications is inappropriate and would go beyond the scope of FortisBC’s 2008 Revenue Requirements Application and this NSA.
Sincerely,
David Bennett Vice President, Regulatory Affairs & General Counsel
cc Parties to the NSA
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