Exhibit B1-10 Mar2904 List of Errata and Chapter 2B …...Notes1. Added Chapter 2A - Evidentiary...

81 - 10

Schedule C. List of Errata

Title Remove Insert NoteVolume I , Summary Original , page i Revision 1, pages i and i-Table of ContentsVolume I, Chapter 2 Original, page 2-49 Revision 1 , page 2-49Volume I, Chapter 2 Original. page 2- Revision 1 . page 2-Volume I, Chapter 4 Original , page 4- Revision 1. page 4-Volume I , Chapter 6 Original, page 6- Revision 1 , page 6-Volume I, Chapter 6 Original. page 6- Revision 1 , page 6-Volume I, Chapter 7 Original, page 7- Revision 1, page 7-Volume I , Chapter 11 Revision 1, page 11- Revision 2, page 11-

Volume II, Appendix I Original, page 8 Revision 1 , page 8Volume II, Appendix I Original, page 9 Revision 1, page 9

BCUC IR #1. Original , page 1 Revision 1, page 1

BCUe IR #1. Original , page 1 Revision 1, page 1

BeUC IR #1. Original , page Revision 1, page 1

BCUe IR #1. Original, page 4 Revision 1, page 4BCUC IR #1. 18. Original, schedule 18- Revision 1 , schedule 18-BCUC IR #1. 75. Original, Schedule 75-6-16, first page Revision 1 , Schedule 75- 16, first page

Notes1. Added Chapter 2A - Evidentiary Update Consolidated Revenue Requirements and Financial Schedules and

Chapter 2B - BC Hydro Deferral AccountsCorrected Distribution Expansion and Improvements for F1994; corrected Deferred Power Smart for F1995 to F1998.Corrected upper limit of free rider range from 12% to 22% as per IPPBC IR #1.24.Corrected Interior YTD Actual CAIDI from 2.92 to 2.76 as per PRRD IR #1. 13.

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5. Corrected misalignment of headings column as per SIERRA IR #1.24.6. Line 21 , corrected as " cost of conserved energy" as per SIERRA IR #1.7. Corrected Distribution OMA for F2003 Actual8. Corrected description of Figure 7-3 in line 7; corrected range labels on x-axis of Figure 7-9. Corrected fiscal year reference in line 22.10. Corrected classification of Aboriginal Relations charge as per BCUC IR #1.20. 3 and BCOAPO IR #1.47.0(b).11. Corrected classification of Aboriginal Relations charge as per BCUC IR #1.20. 3 and BCOAPO IR #1. 56.0(c).12. Corrected assignment of $1. 9m under Regional Facilities for F2001 from G&A, Coastal Region to Operations,

Coastal Region.

13. Corrected values for NTSA and Other Net Exchanges for F2003 and F2004.14. Reclassification of ARD expenditures ($5.0m) from SS&I to "Other15. Reclassification of ARD expenditures ($5.0m) from SS&I to "Other".16. Headcount mix restated as per BCUC IR #2. 184.

Volume 1. Summary Table of Contents

CHAPTER 1. ApPLICATION OVERVIEWIntroduction...

."'''''''''''..''''''.'' ....... ................... .....

..................................................................... 1-Context of Application.. ......... ..... ...............................................................................,............... 1-Summary of Revenue Requirement ...................... .................................................................. 1-

Overview of BC Hydro Organizational Structure..................................................................... 1-Conclusion...................... ......... .....

....... ....... ............ ................. .........

.,.,."",,,,,,,,,,,,.,,,,,,,,,,,,,,.,, 1-6 Names , Titles and Addresses of Contacts for this Application ...............................................

CHAPTER 2. CONSOLIDATED REVENUE REQUIREMENTS AND FUNCTIONAL SCHEDULESIntroduction........... ............ ........... ..... ......

....... .................... .............

........................................... 2-Pro Forma Consolidated Statements ....................................................................."................ 2-Discussion of Financial Forecasts ....

..... ...... ..... .............. ........

.................................................. 2-BC Hydro Deferral Accounts..... ....... ............ ................................. ......................................... 2-Reconcilation of Consolidated and Functional Costs .............................................................Definition of Financial Schedules .......... ...............

.... ....... .......

...................................... ...... ..... 2-

Allocation of Corporate Costs...... .................. ..... ............................. ........................................ 2-

CHAPTER 2A. EVIDENTIARY UPDATE CONSOLIDATED REVENUE REQUIREMENTS ANDFUNCTIONAL SCHEDULES

Introduction. .... .......... ....... ...........

........ ......... .......

.......................................... .................. ........ 2A-Pro Forma Consolidated Statements .......... ..... .............................. ................ .......... ............... 2A-Discussion of Financial Forecasts .................

..... ................ ............................. .....

..... .............. 2A-

CHAPTER 2B. Bc HYDRO DEFERRAL ACCOUNTSIntroduction...... ..... ........,.. ...... .....,...... ............. ....... ......

.... .... ...... ........ .........

.......... ... ........ ..... ... 2B-

Heritage Payment Obligation Deferral Account ...................................................................... 2A-3 Non-Heritage Deferral Account ..,................. ..................... ..... ............................ .......... ...... ..... 2A-

Trade Income Deferral Account ........................................... ......................... ................ ....... 2A-BCTC Transition Deferral Accunt .......

..... ........... ........ :...... ............ """"'" ..". ...........

............. 2A-6

CHAPTER 3. BC HYDRO CORPORATE FUNCTIONSIntroduction......................... ,.",."",,,,,,,,,,,.,,,,,,,,,., ............................................,......................... 3-1Budget Procss........................... .............................................................................................. 3-3Financial and Risk Management

"""''''''.'''''''''''''''''''''''''''''''''''''''''''''''''''''''.''.''''''.... ... ..... .....

3-6Safety....... ................ .......

...... ............ ...... ...........,

..................................... .......,......................... 3-9Environmental Responsibilty .....

;.. ......... ......... .... ...........

............ ..........,.................................. 3-Pricing of Exernal Products and Service ........................................................................ 3-15Corporate Exective Ofce

........ ....... ....,.. ........ ............. ......

.........,............................. ............. 3-16Corporate Resources........ ...........

.................. ...........

................................................... ........... 3-

Finance............................. ................. """""".'''''''''''''''''''''''''''''''''''''''''''.''''''''''''''''''''''''''.'' 3-

1 0 Sustainability .......................

;....................................................

............................................. 3-49

11 Distribution Corporate Function.......... ......... ......................

.... ............... ........... .....

................... 3-

12 Other Corporate Costs.. .........

..............,............. ........ ....... ................ ................... ......

........ ..... 3-

BC Hydro 2004/05 and 2005/06 Revenue Requirement Application

(Revision 1, March 29 , 2004)

BC hydro nw,

Adjustments to Corporate Costs ........................ ..................................................................... 3-Summary of Corporate Cost Component of BC Hydro s Revenue Requirement ...................

CHAPTER 4. ENERGY SUPPLY COSTS1. Introduction................... ........................................ ................... .................... ........ ............ .......... 4-2. Power Smart..... ...................................................................... ......................................... .......... 4-3. Energy Purchase Agreements.............

"""""""""""""""'"''

.................................................. 4-4. Gas Transportation and (non-BCTC) Domestic Transmission ...............................................5. Heritage Payment Obligation ........ .................................... ............... ......... .............................. 4-6. Market Purchases................. .....

..... ........... ... .................. ....... .................................... .......

...... 4-7. Selected Expenditures Not Reflected in the Test Periods ...................................................... 4-8. Electricity Planning Context......... ....... ......

..... .................................................. ..... ...............

.... 4-

BC Hydro 2004/05 and 2005/06 Revenue Requirement Application, i-(Revision 1, March 29, 2004)

BChgdroSCHEDULE A-

Domestic Cost Of EnergyFor the Years Ended March 31

($ milions)

F2003 F2004 F200S F2006Acal Forest Plan Plan Schee. Reference Chapter

Domestic cost of energ:Water rentals $258 $246 $265 $281 D1- Gen (HC) Ch5Independent Power Proucer andlong-term purchase commitents 290 378 378 397 En. Supply Cost Ch4

Market eleccit purchases 249 105 D1- Gen (HC) Ch5Net Purchases frm Powerex D1- Gen (HC) Ch5Natural gas for thermal generation 1 D1- Gen (HC) Ch5Domestic cost of energ - Non-integrated Areas Dist &NIA Ch7Domestic transmission 01- Gen (HC) Ch5Gas trnspoation En.Supply Cost Ch4Cost of market" Transmission Ch6Oter 01- Gen (HC) Ch5Total Domestic cost of energy $708 $824 $808

I CF2003 F20M F200S F2006Actual Forest Plan Plan

Domestic energ:

GW.h'Water rentals 47,665 759 46, 130 46,293Independent Power Proucers andlongter purchase commitents 950 598 003

Market eleccit purchases 896 930 316 506Net Purchases frm Powerex 113Thermal generatin 251 242 258 194Non-integrated Areas 107 105Exchange net 605 179 560 660

53, 55,079 55,969 55,761Less: Line loss and system use 689) (5,325) (5,422) (5,57)Net sales to Powerex 623 260 700Domestic sales volumes 677 131 287

$/MW'hWater rentls $ 5.413 5.496 $ 5.745 070Independent Powr Prouce andlongerm purcse comitents 58.586 60. 57.2 56.690

Market elecit puse 60. 50.507 45.337 36.521Net Purcse frm Powerex 44.924Natul gas for thrmal geneti 111. 115.702 108.527 123.711Domestic co of enrg - Nonntegted Ars 145.833 132. 130.841 142.857

Total weghted avege cost $ 14.545 $ 19.214 $16.718 $ 16.289

1. Thi in fied trrt co of appximatel $10 mRlIo re to th BypssTranspo Agrement be Tersen and BC Hydro.

2. Does co of ene trnsissin wh Inudes co managent 3. Reles to tol co dived by sale volume.

BC Hydro 2004/05 and 2005/06 Revenue Requirement Application2 -

(Revision 1 , March 29, 20Q4)

BC hydroSCHEDULE 04

Resource Usage - Transmission($ milions)

F2006Une F200 F200S Plan

Acal Fort Plan BC Hydro BCTCOpeations, Maintenance and Administration Expenses by Resources

LabourDirec 17. 23. 28. 28.Indire 11. 11.4

Materils 4.4 4.4BC Hydro Servce

Engineering 12. 13. 14. 14.Reid Sece 63. 73. 69. 69.BC Hydro Corpate Direc ChargesOter BC Hydro Bilings

Exerl SerABS' 10. 10. 10.Oter 16. 31.4 29. 28.

Buildings & EquipmentVehicesCorate Alloon 28. 22. 15. 16.Less: Capitlized Oveea (5. (5. (5. (5.Less: Recveres

Interal (6. (6. (6. (5.Exemal - -1

T ota! OMA Exenes

--

Operaions, Maintenance and Administration Expenses by Category

Dire 123. 142. 154. 151.Suppo 20. 35. 25. 24.Corate Alloctions 28. 227 15. 16.Less: Capitlized Overhead (5. (5. (5. (5.Les: Recveres

- --

Tot OMA Exses

--

Capit ExnditresSutaining 99. 143. 155. 104. 43.Grwt 68. 53. 89. 162.0CIATotal Capitl Exditure

HeadcntM&P 100 171 181 181IBEWOPEIUTot Headcnt 316

. Interal chrges fr the Shared Se organiztion that wa ourc to AB In fisc 20 have be clif as ABS cotsfor fi 203 eve though the ouourcng did, not ocr unt fica 20.

F20 Indud $11.1 miRion reng to retrctrig co.

BC Hydro 2004/05 and 2005/06 Revenue R quirement Application

2 - 85(Revision 1 , March 29, 20Q4)

BC hydroPower Smart

The costs associated with Power Smart programs before and since F2002 are summarized

in Table 4-2. This table summarizes the Power Smart cost expensed for each of the periods

identified; the Power Smart deferred capital expenditures are detailed in chapter 8,

section 1.

Table 4.2. Power Smart Costs

($ millons)OMAAmortization of Power Smart before F2002Amortization of Power Smart from F2002Amortization subtotalFinance chargesAllowed ROETotal

F2005$22.

13.17.- $31.

$62.

F2006$22.4

8.428.- $36.

$69.

F2003$12.

23.4

- $24.

$46.

F2004$19.

18.

$24.

$51.

1. Power Smart Before F2002

BC Hydro initiated a significant Power Smart program in 1989. As of the end of F2001 , it

yielded energy savings of 2,459 GWh/year at a portolio total resource cost (TRC) of 3.

cents/kWh and a portolio utilty cost of 2.0 cents/kWh. The amortization of BC Hydro

costs amounts to $13.3 milion and $8.3 millon for F2005 and F2006, respectively. This

amount is decreasing rapidly each year as the initial programs are fully amortized.

2. Power Smart Since F2002

In F2001 , BC Hydro forecasted that approximately 10,000 GWh of new electricity supply

was required to meet the projected increase in load over the following 10-year period.

BC Hydro assessed the achievable potential for incremental electricity savings from Power

Smart, drawing on the 1993-1994 Conservation Potential Review (CPR). The CPR was an

in-depth analysis of where, how and at what cost electricity consumption in BC could be

reduced through energy effciency and behavioural changes. The CPR indicated that there

was about 6,000 GWhlyr of electcity savings potentially achievable between 1990 and

2010 at a cost of less than 6 centslkWh (cost of conserved energy). As noted above, the

Power Smart programs initiated before F2002 achieved an estimated 2,459 GWh/year of

electricity savings. Therefore, approximately 3,500 GWhlyr of the CPR's estimated

I c


4 - 5

(Revision 1, March 29, 2004)

BC hydroTable 6-1. Total Transmission Revenue Requirement Summary

($ millons) F2005 F2006Plan Plan

Operations , Maintenance & AdministrationSystem Operations $44. $45.Asset Management & Maintenance 106.4 106.General & Administration 18. 17.

I cBC Hydro Corporate Allocation 15.4 16.

BC Hydro Rights Management, Properties , and AssetI cRetirement Obligation

Total Operations , Maintenance & Administration $189. $190.

Cost of MarketAsset Related ExpenseFinance Charge 131. 141.Depreciation & Amortization 151. 159.4Grants & Taxes 89. 90.Allowed Return 123. 129.Total Cost $685. $718.

Less Non-WTS Revenues and RecoveriesNon-WTS Revenues:

Generation Related Transmission Assets (43. (43.Substation Distribution Asset Management (69. (70.4)Aquila General Wheeling Agreement (3. (3.

Secondary Revenues (4. (5.(120. (123.

Cost Recoveries:

Generation Dispatch Services (1. (1.

Distribution Dispatch Services (2;6) (2.

Control Centre Leases (1.4)Other Recoveries (1.4) (1.4)

(6. (5.

Total Non-WTS Revenues and Recoveries $(127. $(128.

Total Transmission Revenue Requirement $558. $590.

F2005 reflects Phase 1 of BC Hydro and BCTC's relationship. During Phase 1, BC Hydro

has retained BCTC to administer the WTS tariff and BCTC has been given the responsibilty

for planning, operating, and maintaining the transmission system. All costs associated with

providing transmission service , including those related to BCTC , are paid by BC Hydro.

BC Hydro is seeking to recover the net amount of these costs of $558.4 millon (Table 6-1).


6 -

(Revision 1 , March 29 , 2004)

BC hydroGross Operating and Maintenance Expenditures

Table 6-2 shows transmission operations , maintenance , and administration expenses for

F2003 to F2006. These are comprised of:

system operations expenses;

asset management and maintenance;

general and administration expenses; and

BC Hydro rights management , properties , and asset retirement obligations.

Table 6-2. Operations, Maintenance, and Administration Costs Summary

($ milions) F2004Forecast

F2006Plan

Transmission System OperationAsset Management and MaintenanceGeneral and AdministrationBC Hydro Rights Management, Properties , andAsset Retirement ObligationBC Hydro Corporate AllocationTotal CostDeduct: Cost RecoveriesTotal per Financial StatementsNotes:1. F2003 Costs are not available in the same categories as subsequent years due to accounting

and restructuring changes that occurred post-F2003.

F2003Actual(Note 1)

$37.103.27.

$158.

22.$194.

(6.$188.

F2005 Plan

$44.106.4

18.

15.4$189.

(6.182.

$45.106.

17.

I c

16.$190.

(5. 1 )

$185.

The increase in Operations , Maintenance , and Administration costs from F2003 to F2004 is

explained in Table 6-

Table 6-3. Reconcilation of Operations, Mtce, and Admin Costs, F2003 to F2004

F2003 Actual

Accounting ChangesOne-time BCTC establishment costAdditional operating costsEx-plan forest fire repair costEx-plan maintenance costEx-plan cyberspace security reviewCorporate Allocation ReductionIntra-SBU bud et transfers

F2004 Forecast

($ millons)$158.

14.11.0.4

5.40.4

(5.(0.

$188.


6 - 9

(Revision 1 , March 29 , 2004)

BC hydro7. 1. Overview of Asset Health

Asset health is a direct driver of operating, maintenance , and capital expenditures. The

distribution network asset health is generally good , meaning that in the near term it is

able to continue to provide the service that it was designed for. The major caveat is that

an increasing proportion of the facilities is at or approaching end of life, which means

increasing maintenance efforts and expenditures wil be required.

Figure 7-3 shows an age profile for poles , one of the major asset categories, for F2003. I

Distribution Pole Age Profile400,

fA 350

'0 300,

- 250,

200

.Q 150,

:: 100,

Z 50 000

19 to 28 29 to 38 39 to 48 ::48

Pole Age (Years)

Figure 7-3. Distribution Pole Age Profile

The age profile of distribution poles is considered typical for other asset categories. The

average life expectancy for poles is 40 years. As noted in Figure 7-3, 15% of poles are

older than the average life expectancy, and with an additional 20% reaching that

threshold within 10 years , a disproportionately high number of poles is nearing the end

of their expected lives. Age is a major factor influencing asset health and this age profile

indicates that additional sustaining investments (maintenance or replacement) wil be

necessary to manage asset failures and equipment-related outages.

BC Hydro conducts an annual assessment of the conditon of its distribution assets. The

following is a summary of the current condition of the assets, as well as BC Hydro

response to asset condition.


7 -(Revision 1 , March 29, 2004)

BC hydroFuture capital spending requirements are identified within the operating plans presented in

chapters 3 to 9. Table 11-2 identifies the forecast capital additions by expenditure category

for F2004 to F2006.

Table 11-2. Capital Expenditure Forecast, F2004 to F2006

Expenditure Category F2004 F2005 F2006($ milions) Total Total Total

Generation Hydro $95 $22 $117 $96 $13 $109 $123 $12 $135

Generation Thermal 193 196

Transmission - Lines

Substations 125 150 203

Distribution 118 193 123 207 130 216

ComputersLand & Buildings

Surveys & Investigations (inclAboriginal Negotiations)VehiclesPower Smart 116 116 105 105

OtherBCTC (Note

Gross Expenditures $425 $344 $769 $429 $392 $821 $394 $595 $989

CIA - Specific

CIA - Recurring -42 -41 -45

Net Expenditures incl BCTC $422 $299 $722 $425 $346 $771 $390 $545 $935(Note 3)

I C2

I C2

Notes:1. S = Sustaining Capital Expenditures; G = Growth Capital Expenditures2. Includes expenditures on BCTC-owned assets only.3. BCTC Capital Expenditures are consolidated for F2004 and F2005 only (see section 3. , page

21 ).

4. Some columns do not total due to rounding.

This remainder of this chapter includes lists of historical (since F1994), in;.progress

planned capital projects, by line of business or service organization , with capital cost greater

than $2 milion. Descriptions are provided for projects with capital cost greater than

$5 millon.

As discussed in chapter 6, BCTC has responsibilty for planning and justifying capital

projects relating to BC Hydro s transmission assets. As a result, historical , in-progress , and

planned capital expenditures relating to transmission assets are identified in chapter 6. .


11 - 2

(Revision 2 , February 20 , 2004)

. .

Resource SupplyCost of NaturalGas

Greenhouse GasEmissions

CustomerElectricity TariffRates

Note: application of the cost of new supply to the energy savings byregion is beyond the scope of this analysis (note: the only exceptionis a few specific programs in the residential sector that targetresidents on Vancouver Island). In addition , for the purpose ofconservatism , capacity savings were not estimated or valued in thisanalysis , thus making the analysis conservative.

Some of the programs in the residential sector include the conversionof electric appliances to natural gas appliances. The kWh savingsare converted to GJ and then multiplied by the forecast resourcesupply cost of natural gas. This figure is then multiplied by therelative efficiency rating of the energy effcient equipment.

Source: BC Hydro s Long Run Natural Gas Price Forecast (January2003).

Each GWh of electricity that Power Smart saves is assumed toeliminate the production of electricity from new sources. It isassumed that these new sources of electricity would generate 360tonnes of green house gases per GWh. Each tonne of green housegases is valued at $3 per tonne (i.e. $1 080 per GWh saved). For thepurpose of conservatism , the green house gas valuation of $3 pertonne is assumed to be constant in all 20 years (i.e. 0% inflation isassumed).

Source: Green house gas emissions and values estimated by BCHydro s Green House Gas Staff (J. Duffy and 1. Ferguson), May2003.

, Outlned below is a summary of the tariff rates that were assumed inthe analysis (note: this rate is used to compute the customerselectricity savings as well as BC Hydro s forgone revenues):

Residential Sector: the analysis assumes the trailing step(1101) tariff of 5.77 cents per kWh.

Source: BC Hydro Rates Department

, "

Electricity Service Residential (1101) - Zone I"

CommerciaVGovemment Sector: the analysis assumes ablended tariff of 5.34 cents per kWh based upon the weightedaverage consumption of General 35 KW and over and UnderGeneral 35 KW customers in fiscal 2002103.

Source: BC Hydro , Power Smart Business Systems Group (H.Bains), May 2003.

Industrial Sector: the analysis assumes a blended tariff of

Page 8Power Smart 10 Year Plan: 2002/03 through 2011/12(Revision 1 , March 29 , 2004)

Discount Rate

Li ne Losses

Free Riders, FreeDrivers andMonitoring &Verification

61 cents per kWh. This is based upon the followingassumptions: 85% of the industrial sectors ' electricityconsumption is at the 1821 tariff of 3. 30 cents per kWh and15% of the industrial sectors ' electricity consumption is at theblended tariff of 5.34 cents per kWh for thecommercial/government sector (Le. 3.61 cents per kWh is theweighted average).

I c

Source: The 1821 tariff is based upon a billing analysis of theindustrial sector s accounts within the 1821 tariff. The 85%/15%allocation of the energy savings within the industrial sector is basedupon Power Smart's estimate of the achievable energy savings in theindustrial sector giving consideration to the Conservation PotentialReview s achievable energy savings targets.

A nominal discount rate of 8% is used to discount the streams ofbenefits , costs and energy savings back to fiscal 2002/03. Thisincludes the estimated inflation of 2.0% per year.

Source: Discount rate provided by BC Hydro s Controller s DivisionMay 2003.

For the purpose of calculating TRC and utility cost , line losses wereused to gross-up the energy savings at the customers ' meters toreflect the actual electricity generation savings that BC Hydro willrealize. The following line losses were applied to each sector:

Residential Sector: line losses of 7%.Commercial/Government Sector: line losses of 7%.Industrial Sector: line losses of 3.6%. This is based upon thefollowing assumptions: 85% of the industrial sectorselectricity consumption is at the 1821 tariff with line losses of3% and 15% of the industrial sectors ' electricity consumptionis at the 12xx tariffs with line losses of 7% (Le. 3.6% is theweighted average). .

Source: BC Hydro s Resource Planning and Load ForecastingDivisions , May 2003. The 85%/15% allocation of the energy savingswithin the industrial sector is based upon Power Smart's estimate ofthe achievable energy savings in the industrial sector givingconsideration to the Conservation Potential Review s achievableenergy savings targets.

The programs in each sector have individual assumptions for freeriders , free drivers and Monitoring and Verification (M&V). A freerider is defined as someone who participates in the Power Smartprogram and receives the incentive/rebate but would have undertakenthe energy effcient project without the incentive/rebate. Theassumption for free riders range from 3% to 22% for individual

Power Smart 10 Year Plan: 2002/03 through 2011/12

(Revision 1 , March 29 , 2004)Page 9

British Columbia Utilities ComissionInformation Request No. 1. 3 Dated: 23 January 2004British Columbia Hydro & Power AuthorityRes nse issued 20 Februa 2004British Columbia Hydro & Power Authority Revenue Requirements

licatlon 2004/05 and 2005/06

Page

Reference: Volume 1, p. 1-15, Cost Drivers

Please provide a cost summary of requirements needed to maintain thereliability of the system.

RESPONSE:

Table 1 shows the overall OMA and capital expenditures, by function required tomaintain the reliability of the system.

Table 1 Ex enditures Re uired to Maintain Reliabil of the S tem($ milions) F1994 F2003 F2004 F2005 F2006

Actual Actual YEF Plan PlanEstimated

DistributionI cOMA 61.4 71. 70. 77.4 77.

ital 39.4 50. 62. 63. 67.I cSub-Total 100. 122. 133.4 141. 144.

GenerationOMA 53. 49. 48. 53.4 53.

ital 53. 95. 98. 101. 125.Sub-Total 106. 145.4 146.4 154. 178.

TransmissionOMA 99. 84. 100. 105. 105.

ital 30. 88. 120. 98. 90.Sub-Total 129. 172. 220. 203. 195.

Total OMA 214. 210. 219. 235;9 236.Total Ca ital 123. 234.4 281. 262. 282.

I cTotal OMA and Ca ital 337. 440. 500. 498. 518.4

Notes:While the above OMA and capital expenditures do impact reliabilty, they mayalso impact other drivers e.g., safety.The OMA costs consist of direct maintenance spending only.The F1994 OMA costs for distribution, transmission and generation areestimated.

(Revision 1 , March 29, 2004)

British Columbia Utilities CommissionInformation Request No. 1. 10 Dated: 23 January 2004British Columbia Hydro & Power AuthorityRes nse issued 20 Februa 2004British Columbia Hydro & Powe Authority Revenue Requirements

lication 2004/05 and 2005/06

Page

Reference: Application, Volume I, Chapter 2, Consolidated RevenueRequirements and Financial Schedules

10 Page 2- , Table 2-13: What projects have been abandoned or studiescapitalized over F2003 and F2004, and which are forecast over F2005and F2006?

RESPONSE:

The abandoned projects and studies capitalized over F2003 to forecast F2006 arelisted in the table below.

Sunuar of SSI Projec Expenditre for F2003 to F2006(in millons)

Exenditure CapitalizedPrie Name Brief Prie Desption I F2003 I F20 I F2005 I F20

Site Studies, Aboriainal Neaotiaton & Settemnt Proec and Other Deferr Projec cots capitlizDam Safetv Defciem- Investioatons

WAC Benett Dam Proiec 01Ruskin Dam 01Couitam Dam 01

Huah Kelevsde Eartfill Dam 01Ruskin Dam - Stave Falls Dam - Decien InvetiaationlaJoie Dam Shotcrte & Seismic Resstance

John Hart Dam - Deciencv InveoationSeton Dam - Deciencv Invesaations (Po Canal, Soilwav)Huah Keenlevsde Dam - Remiation OotionsSoillwav Gate Ooeration Afer Sesmic EveMica Dam - Roo & Seismic Caoaci, SlooStthcoa Dam - Deciencv InveaationPeace Canvo - Sesmic StbiltvStrathcoa - Embankment Dam and Po Outet WOIReve1stoke - Sesmc Pernc and Oter Mica - Perforanc Asment (Embankmt Dam)GM Shrum - WAC Bennett Fine Miaration 01Stthcoa - PM and Soillwv Caoacitv. Camobel R. SvtemClowom - Seismic StabilitvSeon - Sesmc Stabiltv of Dam & CanalAbereldie Dam Soillwv & Rive Bank Stbilit

Soilimachee - Stct StbilitHuoh Keelevsde - Safet Huah Kelevse - Reliabilit of Discara Faclites

Totl Dam Saety Deienc InvtiatAbrlninal NAot all Seemnt Prec Capitliz Abinal Negotitin and Sent cots 7.2Ot Deerr Pmlec Costs C..itllzedAS strt-u - defer RFI Co of AS tr stng, 10.

leg, an ot ad seceasated wi th lron. Thdeer tron co will beam on a stgh-line bas th intial ter of th aal

Tot co caIt 20.8 8.5

Abanon Proec Wind 10MW wind farm or on VI

Tesng of 20 MW wa teog Wave Ener th we co of VI.

Wave EnvTesng of 4 MW wa tecnoog Van Isand.

Wind Eneav WlndEnv - En FutreWind SIe Idticaon - Wind Eny

Wind Enomv DeelootTotal wre-ow of abandone Proec 2.8

I c

I c

Note 1: Abginal negotiation, litigation and seem co are capitalize and amozed over 10 yers pursant to BCC Order Numb G-3-2.


British Columbia Utilities CommissionInformation Request No. 1. 20 Dated: 23 January 2004British Columbia Hydro & Powe AuthorityRes nse Issued 20 Februa 200British Columbia Hydro & Powe Autority Revenue Requirements

lication 2004/05 and 2005/06

Page

Reference: Application, Volume I, Chapter 2, Consolidated RevenueRequirements and Financial Schedules

20 Page 2-49 , Schedule A- , Line 33: Receipt of Non-Treaty Storage inF2003 (Exchange net) appears to drive Market purchases and Purchasesfrom Powerex. Please explain.

RESPONSE:

The item labelled "Exchange net" in Chapter 2, Page 2-49, Schedule A-9 andChapter 4, Page 4-18, Table 4-7 includes net energy deliveries under the Non-Treaty Storage Agreement (NTSA), the Canal Plant Agreement, the KeenleysideEntitlement Agreement and several shorter-term Treaty Operating Agreements.The table below shows the NTSA component of Exchange net:

Fiscal NTSA Other Net Exchanges Total Net Exchanges

F2003 (65) (1,540) (1,605)I cF2004 (301) (878) (1,179)

F2005 515 560F2006 499 161 660

There is no direct relationship between the NTSA component of Exchange Net andeither "Market electricity purchases" (energy purchased from Powerex that isneeded to economically serve domestic load) or "Net Purchases from Powerex(energy purchased by Powerex for the purpose of electricity trade).

The NTSA, which is attched in its entirety to BC Hydro s response to BCUC IR #13, provides significant benefits of additional stream flow regulation to both

BC Hydro and the Bonnevile Power Administration (BP A) through the co- operative use of reservoir storage (primarily at Mica) and generation at Mica,Revelstoke and Keenleyside and' at the eleven projects downstream in the UnitedStates.

Under the NTSA, use of non-treaty reservoir storage at Mica is shared equally byBC Hydro and BPA. BC Hydro is obligated to send electricity to BPA when:. BP A releases water from their account resulting in increasedgel1eration at '

Canadian projects; or. BC Hydro stores water into its account, causing a reduction in generation at

downstream projects in the United States.

Similarly, BPA is obligated to send energy to BC Hydro when:. BC Hydro releases water from its account resulting in increased generation at

downstream projects in the United States; or. BP A stores water into its account, causing a reduction in generation at

Canadian projects.


British Columbia Utilities Commission PageInformation Request No. 1. 10 Dated: 23 January 2004British Columbia Hydro & Power AuthorityRes nse issued 20 Februa 200British Columbia Hydro & Power Authority Revenue Requirements

lication 2004/05 and 2005106

Operating Costs and Headcount - Organizational View

F2001 Actual F2002 Ac'ual F2003 Actual F2004 Forecast F2005 Plan F2006 PlanORGANIZA nON $Millons Headcount $Mlllons Headcount $Miliona Headcount $Millions Headcount $Mlliion. Headcount $M lIions HeadcountPeace Region 13. 13. 12, 13. 100 14, 100 14. 101

Columbia Region 19. 149 18, 149 18. 142 19. 143 23. 142 24, 140

Coastal Region 47. 246 55. 291 48. 284 40. 228 39. 224 40, 224Total Regions 80. 490 87. 539 79. 520 73.4 471 77, 466 78, 465

Engineering Services (1. 242 12. 232 Ifj! \1 r TiJ liE!

Resource Management 20.Business IntegrationOperations & Energy PurchasingDam SafetySustainabilty/Aborlginal RelationsAboriginal RelationsStrategic ProjectsStrategic Asset ManagementBusiness DevelopmentSubtotal 21. 89. 22. 81. 140.

Controller s OffceHuman ResourcesOther 11. 15. 11. 11.Total line of Business Support 13. 107 144 15. 100 23. 127 21.1 116 20. 110

Total BC Hydro GenerationOperating Costs 113. 928 131, 996 119. 760 126. 756 125.4 735 126. 727

RESOURCE MANAGEMENT 15. 20. 13.

OPERATIONS & ENERGY PURCHASESOperations and Maintenance

Reat Time OperationsOperations PlanningHydrology

General and AdministrationEnvironmental Program 0.4Infoon ation Technology

Total Oparatlng Co... 13. 12. 13.

ENGINEERING SERVICES (1. 242 232BUSINESS INTEGRATIONSTRATEGIC PROJECTSSTRATEGIC ASSET MANAGEMENT

BUSINESS DEVELOPMENT and ASSET MANAGEMENTGeneral and Administration

Planning Generating Sy.tenml

REGIO FACIlIES(O)

Pe Ra NIA 2.3 NIA NIA 0.5 0.5Co Ragn NIA NIA NIACo Reg 19. NIA NIA 10. NIA 6.2

SU (0) 29.2 NIA 15.2 NIA 17. NIA 8.2 6.2

Maien (M)

Regio NIA 7.2 NIA NIA 10. 10. 11.Co Reio 14. NIA NIA NIA 11. 107 106 15. 105Co Regio 28. NIA 28. NIA 22. NIA 23.2 131 22. 131 23. 136

S-(M) 510 NIA 44. NIA 41. NIA 45. 315 486 314 49. 319Gen an Admlnlpsa Regio NIA NIA 2.0 NIA 2.2 2.6Cobia Reio NIA NIA NIA 7.2Co Reg NIA 17. NIA 15. NIA 11. 10. 10.

SU Ge an Ad- NIA 27. NIA 21. NIA 20. 21. 20.

Tot Op Co 60. 67. ' 79. 73. 471 776 76.

(Revision March 2004)

Capital expenditure SummaryFor the Years ended March 31(in millons)

F1994 F1995 F1996 F1997 F1998 F1999 F2000 F2001 F2002 F2003Gross Capital Expenditures Total

Electric SystemGeneration - Hydro

:::::::::::::: ::::::::::::::::

146Generation. Thermal::::::::::::::::6::::::::::::::::76.::Transmission 117 131 ::::::::::::: :88:::::::::::::::: 68:: 156Subtotal 164 185 134 117 115 155 208 166 243

:::::::: :::: : :::::::

::::i2 2::: 384

Distributionansion and Improvements 198 178 182 164 148 142 140 146 154 ::::::::::::: :49:::::::::::::: 1 1::: 170Total Electc System 362 363 316 281 263 297 348 312 397 :.:.:.:.:.:.231:. :.:.: .:.:.: . 554

GeneralComputers

::::::::::::: ::::::::::::::::::$:::

Land & Buildings

//:::Ut::::::::jj/:tSurveys & InvestigationsTools & EquipmentVehicles

::::::::::::::

(:::::::::::::::::Q::Other

::::::::::::::

::::::::::::::::::Q::SubsidiariesUnder (over) applied overhead (2) (2) (4) (1)

Total General 100 134

::::::::::::~~~::::::::::::::::::

142

Subtotal Capitl expenditres 430 412 364 328 319 387 412 531 :::::::.:.: :361:::::.:.:.::: .32Q.: 696

Deferr Power Smart

::::::::::::::::::::::::: :::::::::

Total GrQSs Capitl and DSM expendIture 471 397 351 325 392 413 ::::.:::::. :367..:.:::::.:::. :3-4:. 741

Less COntributions in Aid

""""'" "'"

(16)

"""'" """"

Speifc

""" """ ,.,...

(17)

.." .......... .., ...... ... ""'" "" ....

(38

..,.,.............,.'

(45Recurrng

.............. """"""""""'" ,.......,. '-""" ......"""" """ ......,

Total CIA (56) (51) (51) (48) (47) (39) (41) (44) (54)

""'" -...... ... ....

(62)

"""" """" .........".......... ....""""" """ ...."""""""'" -,.."""" """"'"

Totl Net Capital and DSM expenditures 428 420 303 278 353 408 369 491 :.:.:. :.:. :.367:.:.: ':.: .:.:. 314.: 679

Notes:1. Figures restated to reflect presentation In F2003.

(Revision1, March 29, 2004) Schedule 18-3-

I c

I c

FIELD SERVICES

The monthly Field Services Management Report is the key document for identifying variances at the Key Business Unit(KBU) level. The report contains the recovery statements for each KBU along with performance against both financial andnon.financial targets. This report is reviewed monthly at the Field Services management committee meetings. At that time,any variances In performance and associated corrective actions are discussed. In turn, each KBU manager would discusstheir individual recovery statements with their own management teams and take corrective actions as necessary. Inaddition, the monthly management report Is updated with a current annual forecast In order to identify trends against plan.The Field Services performance targets and actual results for F2003 and year-to-cate December actual results for F2004 areprovided in the following tables.

Summary of Performance KPI as March 31, 2003

Performance Interior LMVl/Statlons LMVllDlstrlbution LMVlfTrans & Veg CBUKPl' YTD YTD YTD YTD YTD YTD YTD YTD YTD YTD

Actual Target Actual Target Actual Target Actual Target Actual Target# of Disablin urles/edicl Aids

% of Total Planned Work Com leted - Stations 98% 98% 102% 98%

% of Prventative Maintenance Work Com leted - Stations 99% 100% 100% 100%

% of Planned Work Com leted. Distribution

% of Annual Ins ecions Com leted 92% 92%% of Annual Corrtive Maintenance Com leted 94% 92%% of Scheduled Ve etation Maintenance Com leted. Distribution 100% 95%% of Scheduled Ve etation Maintenance Com leted. Transmission 104% 95%Preventable Outa

I C

CAIDI 2.48

IBEW Labour Utiliztion 69. 69. 69. 69. 70. 69. 79. 69. 85. 80.Vehicle Utiliztion 50. 50. 46. 50. 59. 50. 47. 50.Total Cha eable Hours 484. 365.

Schedule 75-


Revenue Requirement Application

2004/05 and 2005/06

BC hydro

Volume

Chapter 2B.

BC Hydro Deferral Accounts

BC hydroTable of Contents

INTRODUCTION........................ ....... ......... .............. ................................................... 28-

HERITAGE PAYMENT OBLIGATION DEFERRAL ACCOUNT.................................... 28-

NON-HERITAGE DEFERRAL ACCOUNT ....................................................................... 28-

TRADE INCOME DEFERRAL ACCOUNT ........................................................................ 28-

8eTe TRANSITION DEFERRAL ACCOUNT .................................................. 28-


2B - ii

BC hydroIntroduction

As noted in chapter 1 , BC Hydro applies in this application for Commission approval of four

new deferral accounts, being the "Heritage Payment Obligation Deferral Account", (HDA),

the "Trade Income Deferral Account" , and the "BCTC Transition Deferral Account". In

addition , BC Hydro is applying for a deferral account similar to the HDA for components that

do not fall within the Heritage Payment Obligation , the "Non-Heritage Deferral Account". This

section elaborates on these proposed deferral accounts.


2B -

BC hydroHeritage Payment Obligation Deferral Account

Section 7 of HSD #2 requires the Commission to allow BC Hydro to establish deferral

account mechanisms for the purpose of recording differences between the forecasts of the

Heritage Payment Obligation and Trade Income used to establish rates , and the actual

after-the-fact Heritage Payment Obligation and Trade Income.

Regarding the Heritage Payment Obligation Deferral Account (HDA), BC Hydro proposes

that it record variances between the following components of the Heritage Payment

Obligation , as defined in schedule A to appendix A of HSD #2:

1. cost of energy (all costs in (a)(i), except those arising from changes in customer load);

2. variable costs related to thermal generation (part of (a)(ii));

3. unplanned major maintenance expenditures greater than $1 milion related to single

event equipment or infrastructure failure or weather related events (part of (a)(ii));

4. any incremental annual impact where the sum of depreciation and finance charges is

greater than $1 milion caused by unplanned major capital expenditures related to single

event equipment or infrastructure failure or weather related events (part of (a)(ii));

5. amortization of unplanned deferred capital costs pursuant to BCUC Order G-53-02 (part

of (a)(iv)); and

6. net revenues from surplus hydro electricity sales (all costs in (b)(ii)).

Each of the foregoing is proposed to be included in the' HDA because they are components

that are largely out of BC Hydro s control. Note that "variable costs related to thermal

generation" refers to maintenance and operating costs arising primarily from the operation of

Burrard Generating Station. Variations to planned operations of Burrard are driven by the

same factors that make cost of energy so volatile, which is why BC Hydro proposes to

include it in the HDA. Unplanned, single-event capital related costs (Le. depreciation and

finance charges) or maintenance expenditures arising from weather or equipment failure are

included in the HDA as an alternative to building contingencies into the revenue

requirement. Revenues from the sale of surplus hydro electricity sales are forecast as zero

for the period of this Application. Not including them in the HDA would mean that ratepayers

would not get the benefi of any such revenues that did arise.


2B-

BC hydroNon-Heritage Deferral Account

The components of the HDA, as now proposed , result from BC Hydro s conviction that it

should assume financial responsibilty for all controllable risks but create deferral accounts

for non-controllable risks. This logic applies equally to non-heritage payment obligations.

Accordingly BC Hydro is applying for a similar deferral account (the Non-Heritage Deferral

Account (NHDA)) for the following additional components. The basis for this application is

the same as under the HDA, that is, components that are non-controllable by BC Hydro. As

with the HDA, these amounts are variances in actual revenues or costs compared to the

amounts forecast. These components are:

1. cost of Energy - all non-HPO energy costs except those arising from changes in

customer load;

2. significant unplanned major maintenance expenditures greater than $1 milion related to

single event equipment or infrastrcture failure;

3. any incremental annual impact where the sum of depreciation and finance charges is

greater than $1 millon caused by significant unplanned major capital expenditures

related to single event equipment or infrastrcture failure , or weather related events;

4. significant unplanned storm restoration response expenditures. A Storm event includes

extraordinary weather or other events that trigger the activation of a Provincial Regional

Emergency Operation Centre or the Provincial Emergency Co-ordination Centre; and

5. Founding Partner Benefits and any CIS Credits under the ABS Contract.

The amounts transferred to the NHDA for components 1 and 4 could be either charges or

credits. For components 2 and 3 there wil only be charges and for component 5 there wil

only be credits.

BC Hydro is applying for balances in all the deferral accounts to attract an interest charge or

credit at BC Hydro s average borrowing cost.

BC Hydro proposes that no cap or limit be set on the HDA or NHDA, but that instead they be

cleared through an adjustment to BC Hydro s revenue requirement, upon application , and in

light of balances that may have accrued in other BC Hydro deferral accunts and

BC Hydro s overall financial situation. BC Hydro also proposes that by June 30 of each


2B-

BC hydroyear, commencing in 2005, that it publicly report to the Commission the variances for the

previous fiscal year in the components of the HDA and the NHDA, and their balances.

BC Hydro 2004/05 and 2005106 Revenue Requirement Application

2B-

BC hydroTrade Income Deferral Account

Regarding the Trade Income Deferral Account, BC Hydro proposes that it be used to record

differences between forecast and actual Trade Income, as that expression is defined in

HSD #2. In this way any losses on the year or any extaordinary windfalls that would cause

Powerex audited net income to exceed $200 millon dollars would not be carried forward to

future periods , consistent with the govemment's response to the Heritage

Recommendations. As with the Heritage Payment Obligation Deferral Account, the Trade

Income Deferral Accunt would be cleared through an adjustment to BC Hydro s revenue

requirement, upon application , and each year BC Hydro would publicly report to the

Commission the variance for the previous fiscal period in Trade Income, and the balance of

the Trade Income Deferral Account.


2B -

As summarily described above and as elaborated on in chapter 6, BCTC wil be providing

wholesale transmission services on behalf of BC Hydro and under BC Hydro s existing tariffs

until April 1 , 2005 (phase 1). At that time it expects to begin providing WTS on its own

behalf under its new tariffs, and on behalf of BC Hydro under BC Hydro s new tariffs (phase

2). This application assumes that the total net cost to BC Hydro of providing and purchasing

WTS services in phase 2 wil be the same as the total net cost of providing those services in

phase 1 , and that in consequence BC Hydro s transmission revenue requirement for F2006

wil remain as it is presented in this application, and that no further adjustment to BC Hydro

rates wil be required other than as applied for in this application. That assumption wil not

be tested until BCTC applies for and receives Commission approval for its first independent

revenue requirement for F2006. In consequence BC Hydro applies in this application for

approval to record any variances between its current forecast of net WTS costs in F2006

and its adjusted forecast of its net WTS costs in F2006 based on the outcome of BCTC'

revenue requirement proceeding, and for approval to carr that adjustment forward to

subsequent rate periods.

BC hgdroBCTC Transition Deferral Account


2B -

Exhibit B1-10 Mar2904 List of Errata and Chapter 2B …...Notes1. Added Chapter 2A - Evidentiary...

Documents

Transcript of Exhibit B1-10 Mar2904 List of Errata and Chapter 2B …...Notes1. Added Chapter 2A - Evidentiary...