Be Hydro 2006 IEP/L TAP Hearing

Be HYDRO UNDERTAKING

HEARING DATE:

November 23, 2006

TRANSCRIPT REFERENCE:

Volume 8, Page 1083, Line 6

REQUESTOR:CECBC

QUESTION

Please file the business case for Revelstoke Unit 5 that includes an analysis of thebenefits listed by counsel for CECBC at Volume 8 of the Transcript, Page 1080,lines 12-18.

RESPONSE

Attached is a redacted version of the most recent business case for RevelstokeUnit 5, dated August 2006. It does not include the trade-related benefits describedby counsel for CECBC at Volume 8 of the Transcript, Page 1080, lines 12-18.

P> ,,~

Business Case

Revelstoke Unit 5Regulatory Completion and Definition Phase -2

Issued By:

Date:

Generation Project Delivery Group

August 2006

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1E;~tioncd1·d D'EfrnJt.~0',r1Phas;9 2

T.ABLE OF CONTEEXEC UTIVE SUM MARY 3

1.0 BAC KGROU ND 9

1.1 STRATEGIC VALUE AND OPPORTUNITY 91.2 CURRENT STATUS 9

2.0 PROJ ECT DESCRIPTION 9

3.0 PROJ ECT JUSTIFICATION 10

4.0 PROJ ECT COSTS 11

5.0 RELATED ENERGY BENEFITS 13

5.1 ESTIMATION OF ENERGY BENEFITS 13

6.0 ECONOMIC ANALYSIS AND IMPACT ON BCTC 14

6.1 ECONOMIC ANALYSIS 146.2 IMPACT ON BCTC 15

7.0 ALTERNATIVE RESOURCES 15

8.0 SOCIAL/ENVIRONMENTAL EVALUATION 16

8.1 SOCiAL 168.2 ENViRONMENTAL 17

9.0 PROJ ECT UNCERTAINTY 17

10.0 REGULATORY COMPLETION STRATEGy 18

11.0 RISK MANAGEM ENT 20

12.0 RECOM MENDATION 21

13.0 PROJ ECT SCH EDULE 21

APPENDIX A - DISCUSSION OF REVELSTOKE UNIT 5 ENERGY RELATED (SYSTEM)BEN EFITS 23

APPENDIX B - TOTAL CONSTRUCTION COST (P90 LOADED) 29

APPENDIX C - PUBLIC CONSULTATION AND FIRST NATION ISSUES THAT REQUIREMITIGA TION 30

APPENDIX D - KEY GENERATOR AND TURBINE CONTRACT TERMS AND CONDITIONS ...... 31

APPENDIX E - ECONOMIC ANALYSIS 33

u

The BC Hydro system is approaching a tight dependable capacity load/resource balance and ashortfall could jeopardize BC Hydro's ability to meet customer peak load requirements. Given its lowcost, its relatively short lead time, its low and manageable impacts, and its operating flexibility, BCHydro considers Revelstoke Unit 5 to be its best alternative to meet capacity needs. Given theuncertainties around the amount and timing of new dependable capacity from F2006 Call EPAs, DSM

and load growth, it is prudent to proceed with Revelstoke Unit 5 for its earliest in-servicedate.

The Project

Revelstoke Generating Station is located downstream of Mica Generating Station and the Kinbasketstorage reservoir. Revelstoke was originally designed to be a six unit, -3000 MW plant but when itwas originally constructed only four generating units were installed. Therefore, the opportunity existsto install additional cost effective capacity at Revelstoke with minimal environmental impacts.Revelstoke Unit 5 would provide 480 MW of very long term (50+ years) dependable capacity. Thefinal 6th unit could be installed at some time in the future.

The Need for the Project

The load-resource balance analysis in Figure 1 shows a need for additional capacity in F2013 basedon the 2006 mid load forecast after adjustment for BC Hydro's full DSM targets. This is also basedon an assumed attrition of 23% of the dependable capacity obtained from the F2006 Call. However, ifa few of the larger F2006 Call projects do not meet their in-service date, if DSM projects do notdeliver the planned capacity savings or if peak requirements increase, additional capacity could berequired by F2011. Revelstoke Unit 5 also provides a source of dependable capacity in the event thatall six units of Burrard are not available or not cost-effective.

Figure 1: Dependable Capacity Load Resource Balance· 2006 Load Forecast with DSM

17,000

16,000

i::' 15,000'ijtilIi 14,000u~il~"'-"c~'"o

Fiscal Year

M'"'''''' Existing__ Heritage Thermalr:==J Alcan •r:==J2007__ Downstream

r:==J Resourcec=:J F2006 Cac=:J Reveistokem2009

Mid DSM

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Project Costs

and D,sfin:,fticr1 Ph,a:se' 2 I;....

Currently, the best estimate, based on known scope, for REV5 is between $300 and $350 million(loaded) for an October 2011 in-service. This pricing is based on a detailed re-estimation includingan independent review of the estimate and a specific study related to forecasted non-residentialconstruction sector escalation/inflation by an independent economist. If BC Hydro is able to achievean in-service date of October 2010, we should be able to save at least $30 million.

Additional Project Benefits

As well as providing 480 MW of dependable capacity, Revelstoke Unit 5 would provide the followingyear-round system operating benefits:

• On average, 140 GWh/yr energy because REV 5 will be more efficient than older Revelstokeunits and will be preferentially loaded.

• Revelstoke Unit 5 would enable energy efficiency gains primarily on BC Hydro's ColumbiaRiver plants in the order of 40 to 86 GWh/y by reducing a small amount of spill and byenhancing the balance of water and import capability during spring freshet as well as systemflexibility during the winter and summer.

• Revelstoke Unit 5 will create overall system shaping benefits when there are relatively highmargins between peak and light load prices, particularly in the summer. The shaping benefitvalue is expected to vary from year to year over the life of the Revelstoke Unit 5 project.

Comparison to Alternatives

The 2006 IEP identified Revelstoke Unit 5 as the least cost of the dependable capacity supply optionsavailable to BC Hydro. This was reconfirmed in the August 2006 amendments to the IEP Long TermAcquisition Plan (August 2006 LTAP). Table 1 is the resource option unit cost of capacity summaryfrom the August 2006 LTAP. This table compares the current estimate of the UCC for RevelstokeUnit 5 to other dependable capacity options.

Corresponding to $270 million to $350 million as spent capital cost range, the UCC for RevelstokeUnit 5 range is $37 to $45/kW-yr ($2006) based on a 6 percent real discount rate. However, this isreduced to $6 to $14/kW-yr ($2006) when energy gain and system shaping benefits are included. Incalculating these benefits, the energy gain benefit at the Revelstoke generating station was updatedbased on a levelized price 1. System benefits and shaping benefits are influenced by pricedifferentials, rather than absolute prices. The annual system benefits were estimated at $3 millionand the shaping benefits have been valued at $3 million per year, which are at the lower end of theexpected range.

Based on input from BCTC, the cost of transmission upgrades at Ashton Creek are included as a costassociated with Revelstoke Unit 5. The cost of this upgrade is $4 million (loaded). However, BCTChas confirmed that transmission reinforcement from the Interior to Lower Mainland is not required todeliver Revelstoke Unit 5 capacity in the winter peak2

.

I Be Hydro's March 2006 "Scenario price forecast was used to calculate the benefit. The levelizedrrice is $65/MWh for the 50 year term in 2011.- Revelstoke G5 Integration Study (Report No. SPA 2006-104, July 2006)

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The costs for other options have not been updated since the 2006 IEP was originally issued and theyare based on conceptual or generic studies which suggests they are subject to significant uncertainty.Other resources, such as SCGT, which would require eleven 47 MW simple cycle gas turbines toreplace Revelstoke Unit 5, would face potential significant stakeholder and regulatory issues. Aswell, the future cost of resources such as the Canadian Entitlement to the Downstream benefits (CE)depends on commodity prices that will change over time.

Table 1 Resource Option UCC Summarya

Option Dependable UCC@6%Capacity (MW) ($/kW per year)

Revelstoke Unit 5b 480 6-14

CEc up to 500 10Burrard 6 Units 910 26e

Mica Unit 5 450 31f

SCGTd 47 MW per unit 108Pumped Storage d up to 500 102

a) The UCC is calculated as the PV of costs divided by the PV of the dependablecapacity benefits.

b) For Revelstoke Unit 5 only the PV of costs is net of energy related benefits.c) The UCC of the CE (Canadian Downstream Benefits Entitlement) is based on the

opportunity cost of capacity from the 2005 ROR. The opportunity cost of capacity inthe future is unknown. Any energy that would be required to supplement the capacitywould have to be purchased at on-peak market prices.

d) UCCs for SCGT and pumped storage include fixed costs only. These UCCs couldincrease or decrease depending on how the plant's variable cost of energy (i.e., fuel orenergy for pumping) compares to the on-peak value of energy.

e) The cost for Burrard is based on six units providing 910 MW of capacity in F2014. Thisis the incremental cost over and above the cost of using Burrard to provide voltagestability only. The impacts of energy dispatch from Burrard have not been included inthis analysis.

f) The UCC for Mica Unit 5 does not include system benefits.

Overview of Development Stages

Current Stage -Initial InvestigationsSince the Board approved $2.7 million in April 2005, BC Hydro has been conducting stakeholderengagement, First Nations engagement, preliminary engineering and developing equipmentspecifications. As well, CPCN and Environmental Assessment applications are being prepared.

Next Stage - Regulatory Completion and Definition Phase 2BC Hydro will be filing CPCN and EA applications, executing major equipment contracts andcommencing model testing of the turbine. This work is intended to provide the Board the informationnecessary to make a final Go/No Go decision on the project in Sept 2008 or earlier.

Final Stage - Execution

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After final Board approval, final equipment orders will be confirmed with the selected manufacturersand on-site construction and commissioning tests will be conducted.

Project Schedule and Decision Milestones

BaseSchedule ISOof October

2011

EarliestPossible ISOof October,

2010

Decision Points and/or Milestones

Key schedule and decision points are shown below. The greatest uncertainty in the schedule lies inthe first twenty months and relate to the time needed for regulatory completion, and reaching anagreement with First Nations.

Expenditure

Definition PhasePart 1 ($2.7 M)

Regulatory Completion phase started May 2005

September2006

October 2008

January 2007September

2007September

2008September

2008

May 2005

Sept 2005

May 2006

August 2006

September September2006 2006

September September2006 2006

September September2006 2006

September September2006 2006

October 2007

September2006

January 2007September

2007September

2007September

2007

civil construction contract(s) November November2007 2008

Commence construction on site June 2008 June 2009

Revelstoke Unit 5 ready for commercial October 2010 October 2011operation.

Award

Regulatory processes complete

Proceed with supply and installation ofturbine and generator

Turbine model testing completed

First Nation's agreement in principle complete

Conversation with the BOD

Re-commenced the BCEAA process

Update with the BODSeek Approval for remaining Definition PhaseFunding from BOD

File Supplemental Environmental Report

Execute Turbine and Generator contract withtermination provisions

Commence preliminary engineering design

Proceed with turbine design and model workcomponent of equipment contract.CPCN Preparation Substantially Completepending input from IEP Hearing and review ofupdated detailed analysis.File CPCN

Implementation(Balance $)

Definition PhasePart 2 ($12.5 M)

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Status of Current Activities and Next Steps

1 Regulatory Completion

Several licensing and regulatory approvals are required, including:

• BC Environmental Assessment (BCEM) process leading to a Project Approval Certificate;• The Federal environmental process which will be harmonized through referral under the

BCEM process;• An addendum to the Columbia River Water Use Plan (WUP) to identify any changed

operational and monitoring impacts of the fifth unit. The Columbia River WUP consideredonly four units at Revelstoke;

• First Nation consultation with the objective of negotiating a Benefits Agreement; and,• Certificate of Public Convenience and Necessity (CPCN) from the BC Utilities Commission.

2 - Stakeholder Engagement

On June 14, 2006 our team met with project stakeholders, First Nations, regulators, local cityrepresentatives, and local area residents. At that meeting, a consensus agreement was concludedaround draft mitigation and compensation for the project. This agreement will strongly influence theenvironmental and BCUC processes. Several of the stakeholders noted their concern that the "taxes-in-lieu" grants have not been adjusted for many years. This concern has been passed on togovernment through a separate briefing note. Also, concerns were raised from the city of Goldenrepresentatives that the region as a whole has not received a "fair share" of the benefits generated byhydroelectric facilities in the region. Based on the consensus around the draft mitigation andcompensation, we were able to submit an Addendum to the Columbia Water Use Plan to theComptroller of Water Rights, and we hope to file our Environmental Impact Assessment with the BCEnvironmental Assessment Office in early September 2006. A summary of the impacts identified andthe mitigation measures proposed is shown in Appendix 0

3 - First Nations

First Nations consultation continues on the project. At the discussions around the draft mitigation andcompensation discussed at the June 14, 2006 Core Committee meeting, the Okanagan NationAlliance representative endorsed the draft recommendations without reservation, whilerepresentatives for the Shuswap Nation Tribal Council and the Ktunaxa Nation Council both acceptedthe draft recommendations with minor reservations.

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4 - Turbine and Generator Contract

We are currently negotiating with Voith/Siemens a contract for the supply and installation of theturbine and generator. The first phase of the work includes the turbine design and model testing andwill be completed by September 2007. The remainder of the work will be included in phase 2 and willoccur after project implementation is approved. To ensure that we secure the price andmanufacturing schedule for Revelstoke 5, the entire contract is scheduled to be executed in earlySeptember 2006. The contract is currently estimated at approximately $69 million plus escalationprovisions. To mitigate our risk associated with a possible delay or termination of the contract, we arecompleting a rigorous legal and business review of the contract to limit our financial exposure in theevent of a delay, and enable BC Hydro to terminate the contract after the model test if projectimplementation is not approved (See Appendix D).

5 - Transmission

A number of studies were completed by BCTC related to the transmission requirements needed toreliably deliver the project in the winter at the time of peak customer demand. Generation Operationshas interpreted these studies and determined that there is no requirement, from a system reliabilityperspective, to install a third bus in the power plant. However, Revelstoke 5 does increase the MostSevere Single Contingency (MSSC) in the BC Hydro system to 1500 MW and as a result, BC Hydrowould have a larger reliance on neighbouring control areas for reserves. BCTC has also confirmedthat two transmission projects will be needed to deliver Revelstoke Unit 5; a capacitor bank at AshtonCreek substation and reconfiguration of Nicola substation. BCTC has confirmed the Ashton Creekwork is linked with Revelstoke 5, whereas the reconfiguration of Nicola is something they need to dofor other reasons and should not be linked to Revelstoke 5. These projects are to be implemented byBCTC and are triggered through the Network Integrated Transmission Service (NITS) application.Funding for the projects will rest with BCTC. In the Revelstoke 5 business case, these costs areidentified as BC Hydro costs not funded by the project but included in the comparisons with othercapacity options. BCTC has confirmed that transmission reinforcement from the interior to the LowerMainland, 5L83, is not required to deliver the capacity in the winter peak3

.

Recommendation:

Revelstoke Unit 5 is the preferred alternative available to meet BC Hydro's generation supplyreliability requirements by F2011. The addition of Revelstoke Unit 5 would address the uncertaintiesassociated with the timing of new dependable capacity from EPAs, DSM deliverability and loadgrowth. Its costs have been thoroughly reviewed compared to other capacity options and its lead timerequirements are well understood. In addition, Revelstoke Unit 5 provides system energy benefitsand energy shaping benefits and could reduce the reliance on Burrard.

It is recommended that BC Hydro proceed with Revelstoke Unit 5 for its earliest in-service date ofOctober 2010 (Fiscal 2011). but allow for an October 2011 in-service date. Therefore, it isrecommended that the $12.5 million funding required to complete the Definition phase be approved inorder to continue to target an October 2010 in-service date, while allowing for an Oct 2011 in-servicedate.

3 An alternative approach was used in the evaluation of F2006 Call projects. This assignedincremental transmission costs to projects outside the load centre. This may raise some concern thatthe UCC of REV5 is understated compared to imports or dependable capacity projects in the loadcentre.

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1.0 Background

tH1·d De,fin;;tfon Phl3se 2

1.1 Strategic Value and Opportunity

Revelstoke Generating Station started operation in 1984 and consists of four generating units with acombined capacity of 1980 MW with room to accommodate two additional 500 MW units. It is locateddownstream of Mica Generating Station and combined with the flexibility afforded by KinbasketReservoir, Revelstoke provides significant value by helping to meet the demand for electricity and bysupporting Powerex's trading activities. The 5th unit would provide 480 MW of additional dependablecapacity to meet the winter peak demand requirements of BC Hydro's customers as well as additionalsystem energy benefits and energy shaping benefits.

1.2 Current Status

The Action Plan of BC Hydro's 2004 Integrated Electricity Plan (IEP) recommended that, given theinherent uncertainty in advancing new supply, work proceed to preserve the unit's earliest in-servicedate. In May 2005, approval was given to commence the Definition Phase of Revelstoke Unit 5 withfunding of $2.7 million (loaded).

The 2006 IEP has confirmed that Revelstoke Unit 5 is BC Hydro's least cost capacity resource optionAt its earliest in-service date of F2011 or F2012 it will supply 480 MW of dependable capacity whichwill provide a buffer to the uncertainties behind the load forecast, actual dependable capacity realizedfrom 2006 and 2007 IPP Call, achievement of the Power Smart capacity reductions, and the relianceon the additional 3 units at Burrard.

Currently approval is being sought for $12.5 million (loaded) to fund the project to September 2007and complete the Definition Phase of the project. Regulatory approvals for the project includecompleting the BC Environmental Assessment Approval including Federal CEAA approval throughreferral, a review and changes if necessary to the Columbia Water Use Plan, and a BCUCCertification of Public Convenience and Necessity (CPCN). The current status of these approvalsprocesses is discussed in section 10.0.

2.0 Project Description

The Revelstoke Unit 5 Project includes adding the following equipment to the existing Revelstokegenerating station:

• An exposed steel penstock of 7.9 m diameter, consisting of a 75 m long straight sectionsupported by four ring girdles and an expansion joint;

• A vertical shaft Francis turbine of approximately 7.0 m diameter, with a maximum dischargecapability of approximately 400 m3/s;

• An umbrella type generator, air cooled, with a rated capacity of approximately 500 MW;• A generator transformer 16 kV/500 kV and SF6 switchgear located in the powerhouse; and,• Additional ancillary mechanical and electrical equipment for the generator and switchgear.

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3.0 Project Justification

Figure 1 is the dependable capacity load resource balance included in the amended 2006 IEP LongTerm Acquisition Plan submitted to the BCUC in August 2006. Existing/committed resources arecompared to the 2006 Peak Demand Forecast after reductions from BC Hydro's full DSM (PowerSmart) targets. Existing and committed resources include the expected contribution of dependablecapacity from the F2006 and F2007 Call for private resources, 913 MW available from Burrard untilF2014, 147 MW under the Alcan energy purchase agreement and 90 MW from Resource Smart unitupgrades at 8M Shrum. The load resource balance accounts for capacity reserve requirements of14% of dependable supply less 400MW from the market.4 As of F2011, 14 percent of supply isapproximately 1800MW.

Figure 1: Dependable Capacity Load Resource Balance ·2006 Load Forecast with DSM

17,000

16,000

~ 15,000'0~ 14,000u_::5 ~ 13,000.. ~'t:l~ 12,000c..,Cl 11,000

10,000

9,000 * ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ ~ w ~ & ~~~~~~~~~~~~~~~~~~~~~

Fiscal Year(year ending March 31 )

'-'- .. _._'-' "ZOO€Loaci'Forecast Range after fllil Dsrvl targets'c=:::J Existing Purchase Contracts_ Heritage Thermalc:::::lAlcan ' Firm Energyc:::::l2007 Call_ Downstream Benefits

"_" ,..:.in,t:!..~q~r:gE~~ning re~~~,_~_, '_____'_"

·,·······'·'·iiiiiiiiiiFier1tageHyciroeTectric' ,- ..- .." .".",...,,"'"c:::::l Resource Smartc:::::l F2006 Callc:::::l Revelstoke Capacity Additioni::.i:i:iI2009 Call- - 2006 Mid Load Forecast after full DSM targets'

The shortfall in dependable capacity within the operating time horizon (first three years) is being metby relying on the Downstream Benefits (DSBs). While DSBs of up to 500 MW are assumed to beavailable, BC Hydro does not rely on them in the longer term to defer incremental capacity additions.

The load-resource balance shows a need for additional capacity in F20 13 based on the March 2006load forecast after adjustment for BC Hydro's full DSM targets. This is also based on an assumedattrition of 23% of the dependable capacity obtained from the F2006 Call. However, if a few of thelarger F2006 Call projects do not meet their in-service date, if DSM projects do not deliver theplanned capacity savings or if peak requirements increase, additional capacity could be required byF2011.

4 The "dip" in the peak demand load forecast in F2015 is due in part to a reduction in capacityreserves when Burrard is removed from the existing supply since reserves are a percentage ofsupply.

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Revelstoke Unit 5, at its earliest in-service date of F2011 or F2012, will supply 480 MW ofdependable capacity and provides a buffer to the uncertainties surrounding the load forecast anddependable capacity resources5

. Revelstoke Unit 5 also provides a source of dependable capacityin the event that all six units of Burrard are not available or not cost-effective.

Section 6 of this business case provides an update of the Revelstoke Unit 5 unit cost compared toavailable alternative resources and concludes that Revelstoke Unit 5 remains BC Hydro's lowest costcapacity resource.

4.0 Project Costs

The current capital cost estimate for Revelstoke Unit 5 is in the range of $270 to $350 million dollars(as spent). This pricing is based on a detailed re-estimate of the capital cost completed in July 2006.This updated cost estimate was then reviewed and verified by an independent, external professionalestimator. Finally, a specific study was completed related to forecasted non~residential constructionsector escalation by an independent economist. Input from both external reviews was thenincorporated into the revised estimate.The updated P50 and P90 cost estimates for the two in-service dates are as provided in Table 2.

Table 2 Ca pital Cost Estimates for Revelstoke Unit 5Cost

In-Service Date P50 / P90 (millions)

Oct/2010 P50 $270Oct/2010 P90 $300

Oct/2011 P50 $300Oct/2011 P90 $350

Notes:I. P50 costs include a 10% contingency. P90 costs include a 20% contingency.

The inflation rates in the capital cost estimate, as recommended as part of the independent externalreview, are provided in Table 3.

Table 3 Escalation Rates used in Cost Estimate

A Inflation rates2006 2007 20088% 8% 7%

20096%

20105%

20114%

20123%

breakdown of the October 2011 in-service date P90 cost estimate (as spent dollars) is provided inTable 4. Table 5 summarizes the annual costs associated with Revelstoke Unit 5 and estimates offuture sustaining capital expenditures quoted in $2006.

5 The dependable capacity is slightly lower than the unit's rated capacity of 500 MW because it isdefined to be the capacity sustainable over a prolonged winter peak period across a range of waterconditions.

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and Definiticd1 Ph:?sJ,;! 2 :2

. --.- . -- ... ,...- ..- .... - -. ------. -- ..... -- .... -- -----. -- --- .. --- ....---JULY 2006 P90 % OF TOTAL

DESCRIPTION LOADED LOADED COSTS(Smillions) 2006

..

Management and Engineering 36 10Construction 153 44Operations, administration, and regulatory approvals 15 4Definition Phase 1 to May/06 3 1Definition Phase 2 to Sept/07 13 3Escalation (above CPI) 72 21Contingency 58 17Total 350 100

Table 5: Revelstoke Unit 5 Project Annual Costs

Cost of Energy

Operation & Maintenance

General & Administration

Taxes and Grants

Sustaining Capital

$1.8 M/yr$0.7 M/yr

$0.2 M/yr

none

$0.3 M/yr

$1.0 M$11.2 M$16.7 M$16.7 M

Water Rentals - Capacity based on rated 500 MWWater Rentals - Energy based on 140 GWh/yr at Revelstoke

Incremental maintenance (no incremental operating cost)

Incremental G&A

Capacity Grant

at 20 yrs in-serviceat 30 yrs in-service (protection, governor, exciter)at 40 yrs in-service (transformer, generator core & poles)at 50 yrs in-service (turbine, SF6 bus)

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5.0 Related Energy Benefits

In addition to its 480 MW of dependable capacity benefit, Revelstoke Unit 5 would provide thefollowing energy-related benefits.

An energy gain at Revelstoke G.S: This is expected to average 140 GWh/yr. It would result frompreferentially loading the new unit since it will be more hydraulically efficient than the existing fourunits. As well, Unit 5 would reduce the likelihood of spill at Revelstoke.

Energy gains on the entire system: This is achieved by reducing a small amount of spill on theColumbia and Pend'Oreille Rivers and by enhancing the balance of water and system flexibility duringthe winter and summer. For example, Revelstoke Unit 5 would allow more water to be released fromKinbasket to Arrow, which would increase the head at Arrow Lakes Hydro resulting in increasedenergy output at that plant. Without a 5th generating unit, the equivalent operation would cause spill atRevelstoke.

Energy shaping benefits: Revelstoke 5 would allow the Revelstoke G.S. to generate moreelectricity during the highest value time periods and less electricity during the lower value timeperiods. This allows improved daily load factoring, and weekly and seasonal shaping. In addition,during the spring freshet, Revelstoke Unit 5 would enable the plant to draft the small RevelstokeReservoir lower during heavy load hours so as to improve the import capability during light loadhours. The value of the shaping operation is influenced by the differential in market prices betweenlight load hours and peak load hours. Shaping benefits is expected to be the most volatile from yearto year of these three categories of system benefits.

In addition Revelstoke Unit 5 would provide ancillary services which would include additionaloperating reserves and additional rotational energy. The latter would facilitate importing anadditional 50 MW during periods when imports would otherwise be constrained by the lack ofrotational energy. The economic value of these ancillary services benefits has not been quantified.

5.1 Estimation of Energy Benefits

The primary factors affecting the amount of annual energy-related benefits expected from Revelstokeunit 5 are (1) average market price conditions, (2) the profile of high to low prices, and (3) BC Hydro'ssupply/demand balance.

Appendix A provides a detailed discussion of the detailed system simulation studies conducted inApril 2005 to estimate the energy related benefits. The value of the 140 GWh/y energy gain benefit atthe Revelstoke generating station is a function of average market price conditions. This has beenupdated based on the March 2006 "Scenario Average" price forecast which indicates that thelevelized price of electricity over the 50 year project life of Revelstoke unit 5 is $65/MWh. This resultsin an updated annual benefit of $9 million.

Based on evaluating the benefits of Revelstoke unit 5 under unfavourable market conditions, theestimates of system energy benefits and energy shaping benefits are conservatively estimated at $6million/year6.

6 Four scenarios were developed to determine a range of expected system benefits attributable toRevelstoke 5. These scenarios combined favourable/unfavourable market price characteristics withannual energy surplus/no surplus conditions. The total of system energy benefits plus shapingbenefits fanged from $5 to $24 million ($2004).

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6.0 Economic Analysis and Impact on BerG6.1 Economic Analysis

The economic analysis for Revelstoke Unit 5 is presented in the following table. This is based on theP50 cost estimate with an October 2011 in-service date which is $300 million (loaded). The tableshows the economic cost of the project in several ways: as a levelized unit cost of capacity ($/kW-yr),levelized annual cost ($M/yr) and 50 year present value (PV $M). The table provides separately thecost of Revelstoke 5 and the system benefits of Revelstoke Unit 5, and then derives its net cost (i.e.cost less benefit). Further details of the discounted cashflow analysis are contained in Appendix Ecorresponding to the P50 and P90 (October 2011) cost estimates.

Table 6: Revelstoke Unit 5 Unit Cost of Dependable Capacity

Levehzed UnitDependable Present Value of

Capacity Costs Unit Cost UnitLOADED COST: $300 MillionDIRECT UNINFLATED: $240 Million

Capacity Cost - Cash BasisCapital (construction) 34.2 $/KW-yr 187,962 PV$MCost of Energy: Capacity only 3.8 $/KW-yr 20,718 PV$MO&M 0.4 $/KW-yr 2,398 PV$MG&A 0.0 $/KW-yr 0 PV$MTaxes and Grants 0.6 $/KW-yr 3,210 PV$MSustaining Capital 0.6 $/KW-yr 3,382 PV$MTransmission 0.8 $/KW-yr 4,147 PV$MTotal Capacity Costs 40 $/KW-yr 221,817 PV$M

Benefits:Energy Gain at Revelstoke 140 GWh ave @ $66/MW (19) $/KW-yr (103,004) PV$MSystem Gain: 86 GWh ave @ $66/MWh (6) $/KW-yr (34,335) PV$MTime Shifting/Shaping (6) $/KW-yr (34,335) PV$MTotal Benefits (31) $/KW-yr (171,673) PV$M

Net Cost of Capacity 9 $/KW-yr 50,145 PV$M

Based on the project costs listed in section 4.0, the unit cost of dependable capacity is $40/kW-yr. Asdiscussed above, a conservative estimate of system energy related benefits has been assumed andancillary services benefits have not been quantified. The $15 million/year for system benefitsequates to $31/kW-yr which reduces the net cost of capacity to $9/kW-yr. The $270 million (loaded)P50 cost estimate based on an October 2010 in-service date results in a net cost of capacity of$6/kW-yr. The $350 million (loaded) P90 based on an October 2011 in-service results in a net cost ofcapacity of $14/kW-yr. In Section 7 this result is compared to the cost of alternative dependablecapacity resources identified in the 2006 IEP.

6.2 Impact on screBased on input from BCTC, the cost of transmission upgrades at Ashton Creek are included as a costassociated with Revelstoke Unit 5. The cost of this upgrade is $4 million (loaded). However, BCTChas confirmed that transmission reinforcement from the Interior to Lower Mainland is not required todeliver Revelstoke Unit 5 capacity in the winter peak 7

.

The upgrade at Ashton Creek substation is the addition of a mechanically switched capacitor (MSC).The MSC will allow high power transfers from the region, free up reactive reserves at Revelstoke, andprovide voltage security. The new MSC, estimated to cost $3.4 million (2006$ or $4 million loaded) isincluded in the economic analysis. As indicated in Table 6, this transmission capital and operatingcost equates to 0.8$/kW-yr.

There will likely be impacts to the amount of point-to-point (PTP) charges incurred by Powerex versusnetwork integration transmission (NITS) charges incurred by BC Hydro. When Powerex usesRevelstoke Unit 5 for marketing, it will pay a PTP charge to BCTC. However, since theinterconnection costs associated with REV5 would not significantly increase BCTC's cost of service,those PTP charges will ultimately reduce the NITS charge to BC Hydro. The end result is that BCHydro does not pay additional transmission costs. The PTP charges and offsetting reduction in NITScharges have not been included in the economic analysis of Revelstoke Unit 5 shown in Table 2.

7.0Table 7 summarises the unit cost of alternative capacity resources identified in the 2006 IEP. Theunit cost for Revelstoke Unit 5. The costs for other options have not been updated since the 2006IEP was originally issued. Mica Unit 5 is the next lowest cost new capacity resource that Be Hydrocould develop. However, at this time Mica Unit 5 is not a viable alternative to Revelstoke Unit 5 sinceMica Unit 5 earliest in-service is at least F2013. The cost for Mica unit 5 includes the regionaltransmission upgrades required to interconnect that project to the main grid but has not adjusted forthe energy related benefits it is expected to provide. That energy benefit has been estimated at 50GWh/y compared to the 140 GWh/y for Revelstoke unit 5.

Table 7 Resource Option UCC Summary8

Option Dependable UCC@6%Capacity (MW) ($/kW per year)

Revelstoke Unit 5b 480 6-14

CEe up to 500 10Burrard 6 Units 910 2611

Mica Unit 5 450 31

SCGTd 47 MW per unit 108Pumped Storage d up to 500 102

the PV of the

the PV of costs is net of energy related benefits.Downstream Benefits is based on the

from the 2006 IEP. The opportunity cost of in the

a) The uee is calculated as the PV of costs dividedbenefits.

b) For Revelstoke Unit 5c) The uec of the CE

cost of

Revelstoke G5 No. SPA 2006-1

g,u,s:fn:ls,ss Ca,se' R',e'\'!G:200f"

and O"ef[rdtt()'n Pfi2fse 2.

future is unknown. Any energy that would be required to supplement the capacitywould have to be purchased at on-peak market prices.

d) UCCs for SCGT and pumped storage include fixed costs only. These UCCs couldincrease or decrease depending on how the plant's variable cost of energy (i.e., fuel orenergy for pumping) compares to the on-peak value of energy.

e) The cost for Burrard is based on six units providing 910 MW of capacity in F2014. Thisis the incremental cost over and above the cost of using Burrard to provide voltagestability only. The impacts of energy dispatch from Burrard have not been included inthis analysis.

The costs for other options are based on conceptual or generic studies which suggests they aresubject to significant uncertainty. Other resources, such as SCGT, which would require eleven 47MW simple cycle gas turbines to replace Revelstoke Unit 5, would face potential significantstakeholder and regulatory issues. As well, the future cost of resources such as the CanadianEntitlement to the Downstream benefits (CE) depends on commodity prices that will change overtime.

It is not recommended that the capacity associated with the Canadian Entitlement to the DownstreamBenefits (CE) be used to defer or replace REV5. In effect, BC Hydro (via Powerex) would reservemarket capacity, likely for the 4 winter months and then pay market electricity price when thatcapacity supply is called on. Delivery would be via the firm transmission to the BC Border which BPAis required to provide the CEo Reservation charges are currently estimated at $US3/kW-month forthis winter which mayor may not be indicative of reservation charges by F2011. Relying on the CEcapacity would require BC Hydro to purchase energy at peak market prices. As well, the CEcapacity is expected to be an important contingency resource for BC Hydro even with REV5 in place.

Not withstanding that SCGTs or pump storage added in the future to meet peak demandrequirements would likely be developed by the private sector, to date the majority of contracts withindependent power producers (IPP's) have been for projects which predominantly provide energywith limited dependable capacity. Existing contracts provide 7000 GWh of energy but only 700 MWof dependable capacity of which 240 MW is the gas-fired Island Cogeneration project. For planningpurposes the 4,200 GWh of energy being targeted from the current F2006 is assumed to contribute600 MW of dependable capacity. If BC Hydro were to add energy-rich projects to ensure adequatepeak capacity supply the result would be a substantial oversupply of energy relative to domesticenergy requirements. BC Hydro would need to recover the cost of that energy via sales into thewholesale electricity market.

8.0 Social/Environ

8.1 Social

Evaluation

The scope of work for the regulatory completion phase of the project includes a comprehensive FirstNations consultation to identify their interests in the project. There are three First Nations withinterests in the region.

The scope of work also includes a public consultation process to identify and quantify other socialimpacts. Based on pervious work some social benefits have been identified including:• Employment during the project estimated at 300 worker-years. Indirect and induced local benefits

would add 90-100 worker-years.• The project will direct $250klyear increase in grants-in-Iieu to the Regional District.

• The project will increase the water rentals payable to the Provincial Government by an estimated$2 million/year.

8.2 Environmental

The regulatory completion scope of work includes an environmental assessment under the BCEnvironmental Assessment Act leading to a Project Approval certificate. Also the Columbia WaterUse Plan Consultative Committee will be reconvened to review the impact of the fifth unit atRevelstoke on the outcomes and measures contained in the draft Columbia WUP. This will contributeto build ina and maintaininq public support.

Based on previous work on the project and the WUP, some environmental impacts have beenidentified including:.. Reservoir levels will remain unchanged. Reservoir fluctuations within the range will change... Tailwater water levels and river flow velocity will increase. This could cause erosion of the

riverbanks. Costs associated with mitigating this impact have been provided for in the project costestimate.

.. Aquatic live, entrainment of fish could increase. Fish habitat, particularly downstream of thepowerhouse will be affected. Mitigation and compensation of these impacts will be dealt withthrough the EA process. An estimate of mitigation and compensation cost associated with theseimpacts has been provided for in the project cost estimate.

.. Impacts during construction will be dealt with through an Environmental Management plan.Impacts will for the most part be contained within the existing powerhouse.

9

uncertainties have been analysed as to their impact on the unit cost of capacity for5. The results have also been summarized in Figure 3.

.. Construction Capital - the range is shown from the P50 $300 million (October 2011) to the P90$350 million (October 2011) cost estimate. This is indicative of the risks associated with higherthan expected equipment and labour costs and higher costs due to the regulatory completionoutcomes.

.. In-service date - Capital cost of approximately $30M can be realized if REV 5 is in-service by October 2010.

.. The energy related benefits of Revelstoke Unit 5 are varied from $14 million/vear towith $15 million/year as the base case.

.. Discount rate - a real discount rate of 8% is shown as well as a lower real discount rate of4.6%. The base case discount rate is 5.88% which to BC Hvdro's nominal WACC of8%.

g:,U$1ni3SS Ca,;3'1;9 r:,iE;,\.'~:f,!s:,t:;;;.kf:t2006

Con: ;';;:J"';:d [Jieffrl'ft!:o,ti Pti:Z,,'S!=: 2

Figure 3: REV Unit Capacity Cost Sensitivities

REVS Unit Capacity Cost Sensitivities

t Reference Unit ~l!Capacity Cost $9/kw-yrl;. ,..,:

Capital Cost

In-Service Date Oct 2010 Ocl2011(basel

$33M /yr

$15M/yr

I Energy Related Benefits I IJ $14M/yr

base t' 6%

Real Discount Rate 5% I I 18%

I. .;~,_.~ .~~ ~_.~ __ •........>-.. __ ~~ __~ __~ ~_~_~ __~~ __ • _ ••......-.-. ~L_. ~._ .. L . ~_~_------'_~

-40 -30 -20 -10 0 10 20 30

$/kW-yr

10.0 Regulatory Completion Strategy

The Environmental Assessment, Water Use Planning and First Nations processes all requireconsultation. The EA process is required by regulation and follows a defined time line. The WUPprocess is voluntary and has no defined time lines, as would be the case for a review of the ColumbiaWUP for the impacts on measures and monitoring of a five unit plant. The First Nations consultationalso has no process time lines. The objectives and outcome of the consultative processes differ. Theapproach to consultation is to meet the objectives of each process but timed around the structuredtime lines of the BCEAA process.

Provincial Regulation under the BC Environmental Assessment Act (BCEAA)

To re-commence the EA process, the EAO issued BC Hydro an order under Section 11 of the Act inMay 2006. After the order is issued, BC Hydro has 12 months to submit supplemental andconsolidated information. The scope of the supplemental and consolidated information was identifiedprior to the issuance of the Section 11 order.

8·ltslness C~IS{2/Rf2\/e!.stC>~<.i22006

s:·n·cI D·effn-rtfc::'-n Pt.lase: 2

Columbia Water Use Plan and Water License

Consensus was reached on the Columbia WUP in July 2004 and the draft WUP and consultativereport were submitted to the Comptroller of Water Rights in 2005. The Comptroller had beenexpecting to direct BC Hydro to adopt the WUP by late 2005 or early in 2006. This date has sincebeen revised to September 2006, at the earliest. This WUP, which is for four units at Revelstoke, willbe the base line to measure the incremental operational impacts of the fifth unit. The ColumbiaConsultative Committee expressed interest in reviewing the incremental impacts of the fifth unit onthe measures and monitoring provisions included in the draft Columbia WUP. In terms of time lines,the WUP process is unstructured and open-ended.

The only work with respect to the water license would be to issue a "leave to commence" the workonce the EA certificate is approved. Land and Water BC confirmed that any loss of rights afforded toBC Hydro by the Water license with respect to Unit 5 would be eligible for WUP remissions. Thiswould include the impact of minimum flow that is provided in the WUP, estimated to be $1.5million/year.

First Nations

Two First Nations were included in the 1994 EA consultation. Since then, the Okanagan Nation hasclaimed interest in the region. Three nations will be involved in the BCEAA process and the ColumbiaWUP review as stakeholders. In addition BC Hydro will enter consultations with the three nations withthe view to negotiating a benefits agreement relating to the fifth unit. Like the WUP process, in termsof time lines, this is an unstructured and open-ended process.

BCUC Certification of Public Convenience and Necessity

The Revelstoke project was licensed as a six-unit facility in 1978 prior to the enactment of the BCUtilities Act. The facility therefore is deemed to have a Certificate of Public Convenience andNecessity (CPCN) and extensions of such facilities do not require a CPCN. However, in the2005/2006 Revenue Requirements process, BC Hydro proposed that it would apply for a CPCN forRevelstoke Unit 5, which was accepted by the Commission. The project plan has the CPCNapplication process commencing at some point between October 2006 and January 2007, afterstakeholder engagement is complete.

Federal Regulation under the Canadian Environmental Assessment Act (CEAA)

Federal approvals of the project will be integrated with the BCEAA process. The Department ofFisheries and Oceans will be the lead federal agency. They will be a referral agency through theBCEAA process. Federal authorization will follow very shortly after the EA certificate is approved bythe minister.

Business Case R.eve!stoke Unit 5August 2006

Completion and Definition Phase 2 20

11.0 Risk Management

Risk mitigation will be achieved through utilising standard BC Hydro contracting strategy and policy,construction strategy and plans, as well as appropriate risk management systems, such as safety andenvironment management plans. Appendix C outlines the mitigation plan for the Public Consultationand First Nations. Appendix D summarizes key points in the generator and turbine contract.

The economic evaluation of these risks is included in table 4.

Table 6. Risk Identification and Mitigation StrategyI I Description of Risk I Mitigation Strategy I Probability I Impact

Capital - cost exceedscurrent estimate

•

•

•

••

Project off-ramp after regulatorycompletionProject off-ramp before majorequipment commitmentUse of contingency andescalation allowancesFirm price contractsLiquidated damages

Low ProbabilityLow Impact since projectis below cost of nextlowest cost resourceoptions.

Low ProbabilityMedium Impact sincePerf. Guarantees/LD maynot fully cover BCH costsLow ProbabilityMedium ImpactLow ProbabilityMed Impact since themarket is dictating ahigher level of owner risk •Low Probability 1

1Low ImpactLow ProbabilityMedium Impact

Performance guaranteeLiquidated damagesExternal oversight

Schedule guaranteesSchedule review prior to awardUse of Standard BC HydroContracts

•

I •I •l-I

ii

Schedule

Performance - units do no •meet the current expected •output

Contractor Credit -Default of counterpartySafety - Multiplecontractors on site

Contracting strategy

ProjectDevelopment

ProjectImplementation

• Credit review prior to award I• Adequate security• Safety policy I• Terms and conditions of contract I• Site safety management per

WCB'eQu;'emenls ~~I• Engagement with the re- I Low Probability

convened Consultative I Medium ImpactCommittee I I

:. Adherence to EA process ! High Probability 'I

• Consensus on M&C with ! High Impact ,stakeholders I Both relate to schedule I

i risk i• Submission of supporting I High Probability

information on REV5 with i High Impactamended IEP LTAP : Both relate to risk that

• On-going consultation with ! BCUC does not approvei. .•_'- .---.i ....__BC!::'.Q......_ .._._.__ . ----.l!he projec!_.. ..... j

..._." ..""----,~--."--~_._"-,_._-

2Revelstoke Unit 5 is the preferred alternative available to meet BC Hydro's generation supply

requirements by F2011. The addition of Revelstoke Unit 5 would address the uncertaintiesassociated with the timing of new dependable capacity from EPAs, DSM deliverability and loadgrowth. Its costs have been thoroughly reviewed compared to other capacity options and its lead timerequirements are well understood. In addition, Revelstoke Unit 5 provides system energy benefitsand energy shaping benefits and could reduce the reliance on Burrard.

It is recommended that BC Hydro proceed with Revelstoke Unit 5 for its earliest in-service date ofOctober 2010 (Fiscal 2011). but allow for an October 2011 in-service date. Therefore, it isrecommended that the $12.5 million funding required to complete the Definition phase be approved inorder to continue to target an October 2010 in-service date, while allowing for an Oct 2011 in-servicedate.

1 u

Key dates and decision points are summarized below.

Regulatory Completion phase started

Conversation with the BOD

Re-commenced the SCEM process

Update with the BODSeek Approval for remaininq Definition Phase Fundinq fromBODFile Supplemental Environmental ReportExecute Turbine and Generator contract with termination

2006

2006 September 2006

September 2006 September 2006

2006 2006

2006 September 2006

2006 September 2006

2007 2007

2007 2007

2007 2008

2007 2008

October 2007 October 2008

November 2007 November 2008

June 2008 June 2009

October 2010 October 2011

Earliest Possible Base Schedule ISDISD of October, 2010 of October 2011

May 2005

May 2005

Sept 2005

2006

from

for commercial operation.

and review of detailed

Turbine model _

First Nation's agreement in

Decision Points and/or Milestones

Revelstoke Unit 5

and installation of turbine and

civil construction

Commence construction on site

CommenceProceed with turbine

contract.

The Qreatest in the schedule is in the work and relates to the

identified as

S,L;,:sln(~ss Ca.S:f3 R,IZi"~,ie"ts:to,1<:'G2006

a.nd D·sff:nf::rc-n Pha:se 2

• Longer than planned time to reach a benefits agreement with First nations, currently identified asSeptember 2007 or September 2008.

• Longer than planned time required to negotiate a turbine supply contract.

2005 Revelstoke Unit 5 Business Case)

System Optimization of Revelstoke Unit 5 Benefits

Generation, Integrated Operations and Risk Management provided the estimated system value ofshaping/time shifting and energy gains associated with Revelstoke Unit 5. The primary tool utilized isthe Generalized Optimization Model (GOM), which is a medium-term system optimization model. GOMwas used to value operating regimes for Water Use Planning for the Peace and Columbia system. Themodel takes as inputs the available resources and their operating characteristics (e.g. operatingconstraints, unit efficiency curves, etc.) and the domestic load for a given year. In addition, the marketprice of electricity is another input, which is used to determine whether it is more economical to store orto draft specific reservoirs to meet load requirements and trade in the spot market The GOM modelseeks to maximize the value of BC Hydro resources, subject to operating constraints (i.e. restrictions onplant and reservoir operation, limits on export and import capabilities from the US and the Albertamarkets, etc.). Its simulation module includes detailed modeling of the hydraulic system and enforcingthe operating the physical limits.

GOM optimizes the operation of the five major plants in the BC Hydro system (GM Shurm, PeaceCanyon, Mica, Revelstoke, Arrow Lakes Hydro) as weI! as import and export energy markets to meetthe residual load served by these projects. For each year, results from the HYSIM model (a long termsystem optimization model) are used to establish initial conditions, end of year target elevations, as wellas a general monthly operation for each project. The system is then optimized on a shorter time-step,subject to operating restrictions. The total monthly energy production from GM Shurm and Mica werealso limited in terms of their deviation from the HYSIM results. A more detailed list ofassumptions:

.. Water Years: uses 10 years streamflow from 1 October 64 to 30 September 73, which contains wetand dry water years as weI! as some dry and wet sequences

.. The load and resources are based on 2008/09 load and resource balance for scenario 1 and 2, andbased on 2015/16 load and resource balance for scenario 3 and 4.

.. For scenarios with a winter and summer peak, BC Hydro Sept 2004 gas and electricityforecast for Alberta and US with a relatively high margin between light load hours and heavyload hours. For scenarios with a winter peak only, BC Hydro July 2001 gas and electricity priceforecast for Alberta and US.

• Estimated hourly market. .• The market by water year to reflect the imaact due to varvina stream flow

conditions at BC and.. The initial forebay and ending elevations were set to match those derived bv the HYSIM results for

the corresponding water years... The monthly total energy production from the GM Shrum and the Mica alants were restricted to

deviate by no more than a certain from those derived.. The average inflows for the studies were set to the inflows used in the HYSIM model.

Within each inflows are assumed to be constant for the Peace River svstem. while theColumbia River used inflows.

.. Williston Reservoir within the WUP variable minimum elevation constraint.

.. Peace River meets the ice-controlled with a controlled flow durina the ice-controlled and flow increase for 4 hours within the .

.. All scenarios assume a 5000 cfs minimum flow at Revelstoke that was of the draft ColumbiaWater Use Plan. The of the minimum flow decreases the of Revelstoke Unit5.

Busi;ness CaS~3" Rfi:·\/\:,istct{tE;2006

d,.., .. '" -h 2.an: 1,..lelH"Hti.O'rl r:'ij'iaS~!? .', 24

• Although expired, the existing Non-Treaty Storage Agreement (NTSA) is assumed. However, thesame level non-treaty storage activity is maintained for with and without Revelstoke Unit 5 cases.As a result, if a new NTSA is implemented, the benefits attributable to Revelstoke Unit 5 would behigher.

• Same amount of Burrard energy is maintained for Scenarios 1 and 2 for with and withoutRevelstoke Unit 5. Same amount of Burrard energy is maintained for Scenarios 3 and 4 for withand without Revelstoke Unit 5.

Revelstoke Unit 5 System Benefits

Revelstoke Unit 5 does not affect the amount of water available for generation, but it does make moreefficient and effective utilization of that water. With Unit 5, there will be an additional 500 MW ofcapability to operate during higher value periods, and less energy will be generated in lower valueperiods. The following chart shows the simulated impact of Revelstoke Unit 5 on the way Revelstokeoperates.

Chart B1. Annual Duration Curve for Revelstoke

Revelstoke Generation Frequency Curve 4 Units

5 Units

2500

2000

..2~ 1500~c.2iU~ 1000Q)~

500 'I'-"'-'--"-~--"---'---'''''''--------'-~~--, ,

; :

,~

o Io 0.1 0.2 0,3 0.4 0.5 0.6 0.7 0.8 o.g

Frequency (%of Time)

During low valued times of the year, Revelstoke typically operates at minimum and is represented bythe left end of the chart. Because of the assumption of a new 5000 cfs minimum flow at Revelstoke,there will be limited opportunity to shift energy out of these periods and therefore there is little impact inoperations for approximately 20% of the time. It should be noted that the 5000 cfs minimum flow asrecommended under the draft Columbia Water Use Plan will reduce the benefit of Revelstoke Unit 5 byapproximately $1.5 M/yr. That benefit has not been included in this business case, but will berecoverable by remissions of water rental fees.

From approximately 40% to 60% of the time, energy generation is reduced with Revelstoke Unit 5, andthat water is used during higher value periods. From 60% to 100% of the time, generation fromRevelstoke is significantly higher with Unit 5. The increase in generation is due to the reduction ofgeneration from a lower valued period and also from the energy gain, described below.

Business Cas.e:F~,\D'\/e:,rs,tc-ke20'.06

,,~nct De,finftic>tl Phcl'SS~ 2 A:':J

The following chart is an extract from one GOM simulation showing Revelstoke operation with andwithout Revelstoke Unit 5 over a 7 day period in the winter. The chart shows that with Revelstoke Unit5, the plant is able to shape the energy to better meet the morning and evening peaks, and less energyis generated during the shoulder periods.

Chart B2. Simulated Operation of Revelstoke Over Seven Days

Comparison of Revelstoke GenerationGeneration (MW)

4 Units

5 Units

--rr--r\---n---n--I \--n- f \--n---~-

;:....o~

~~

~~

Dale ~

]II

In\-~-T-rT-'--'r1\1I. 111 II ~i II I

"'-~'--'-Q-A""---f-\ - -Ii !

.1·.',·······"···'1·. _i .•••\.~'-·i" ,.~".".", 1.......... I.'

t ' \...i , ,-----'- ,- .-:- ,----,\-J.J.'1 .' '. \' !s ,'j _ '" l I" I'· I . \ !

, . l U -, 1

~~'"~

~~

~o~

§oN~

500 ,--,

\000

2500

2000

1500

Due to improvements in generator design, Unit 5 will be more efficient than the other 4 units installed 20years ago. Its more efficient design means that Unit 5 will be preferentially loaded and hence will allowthe Revelstoke plant to generate additional energy using the same amount of water. The efficiencycurve from the existing unit and the potential new design is used, shown in Chart B3. The new turbinedesign provides a gradual gain in efficiency starting at 280 MW. The gain is roughly 2% at 410 MW,3.5% at 450 MW and almost 5% at SOD MW. Because a 5% gain is potentially too optimistic, thestudies for the business case assumed a maximum efficiency gain of 4.5% at 500 MW. If confirmed,Unit 5 would be designated as a first loaded and last unloaded unit because of the gain in turbineefficiency across the most likely zone of operation. In addition, the water saved due to efficiency gain inlow priced periods can be used to increase generation during higher priced periods.

B.:usin/2SS Cas.\& R~J'\/e,rS'tc'l<~;;2006

c~nd D:£-ffr'"'i,rtfcn Pha,:,sc 2 '/";''':....,'...

Chart 3B: Gain in Turbine Efficiency of Revelstoke Unit 5 vs Existing Units.__.------_.~~-_ ..._,_._--_.__._-_._~---~~<._---_._..-._',~_._--',-'--,..,'--~...._--~~ ...,----'--REV UNIT 5 TURBINE EFFICIENCY GAIN

6.00

600500400300

MW

200100

------ ~~~~_. ._ ---- ~ 5__. ..._.__ . ...00._________ ~ _._ ._._. .__.._. .__. ... .__ • ..L 4:50----·-

- ·-.-~-=·_~:_~:---.--I-:J

··-··--··-··-1- .-.,,------. --"..~'.,-".

!o

2.00

5.00

4.00

1.00

0.00

z~ 3.00~•

Another source of system benefit from Revelstoke Unit 5 is that it allows better balanced operation ofKinbasket Reservoir and Arrow Reservoir. Revelstoke Unit 5 will allow more water to be released fromKinbasket to Arrow, which increases the head at Arrow Lakes Hydro and increases energy output.Without a 5th generating unit, the equivalent operation would cause spill at Revelstoke.

Chart B4. Schematic of the Mica - Arrow System

MICA(MeA)

NI

L:

I,

REVELS TOKE(REV)

I NI

REVn"'H;~ (4)

"---.-.J...----)

MICA· ARROW SYSTEM

~,......i ~1$ ...... 1' t;.l. {SIOo~!

N"'R~: ( ....II.>!'....,.~•• c.,.,..(O\-...r}t.j

tlf"Jif't .....t. ... """.MlOOlIt I '"1(~,

(2)

8oG:

'"1....-.r t.'~"'W ',,-,, ,,,,,tUM_f; f

";'" \';'.ftrn<'iIot"''ll PI"''"'',,''''fW'\; I:

mI fht~ t",i'W~ ~)\tI. ... ,_, "''''1<'<1)", !' ,..~..,"f", I

llOG11\}~=,.:;:,·,"~~~~~~'7;,",WH'lI:r;. .. ('}roft'l) t.p"''''' ..Yt. "'''>.i''''ll ....''11 I

1) ..... ~ (» .,. , fQ\I'It)(!;l1li()._ ..Jl F....'I' .. '''.'''''l ...·.<11

!.I.. ,...... 1.

Hcvi... ""__ c~......v",,"~'" .''' ....... _ "" !........}

t~~ ......;I"~~ fj

--_·_-.J~--iWHAT$HAN LAKE RESERVOiR:' 1\ w'.'AA\l.t;Kir1.Af{n~l,.N... "::.'Anp~?N[l

~ ~"1 r-~ I "---!-~7L-.... /": • >--l. l----? , • r~"L~~-l_J""

l".x;, !.,tCP~)~ T -T- \i.~r....' WALH£R,',1 HA..•...Jl I 1·~N~.'!'t':c'" ~ CI.:.cH.\H~.(: HAROMAN~,., 'ClJl ......t.:lt ' (WHN)

COt.UMtlIA t LWHATSHAN '---- I RIVER ,~

(WGS) WGS 'I WHN,.V> ..... "f~! ...r..NI (1) I Nt (1.~ I ~f.~ ••Hr,I.1,.,.

R'~ * -L-.'" '--=1KEENLEYSIDE l ARROW L.A-,ES "'ESERVOIR !

(ARROW) " r-. 1 r.l ~ '(HLK) .• '.A '"

"...•.p.O'-'.··..-l·~ '-r' -.'" 'xCI J\jA!i.t, I, ~~~

, ,_ .._ ....1.......-----/I COI..Ut.1E.HA, 11'IVLR

Scenarios

The additional flexibility provided by Revelstoke Unit 5 is extremely valuable for load following andcapturing market value. The additional unit would increase the shaping capability of the entire BC Hydrosystem for maximizing market value and meeting domestic firm peak load. Four scenarios weredesigned to estimate the benefit of Revelstoke Unit 5.

Scenario 1 - Supply Surplus and Favourable Market Conditions

The load and resource balance is based on 2008-09 operating year. There is a market for energy inthe Pacific Northwest during winter and in California during summer. The seasonal market price has apeak in winter and a peak in summer, as well as profitable price margins between seasons andbetween peak load hours and light load hours. BC Hydro/Powerex has surplus capability and energy tosell in both winter and summer when water conditions are above dry and has the capability to imoort inlower priced hours and seasons, and resell at higher priced hours and seasons.

Scenario 2 - Supply Balance and Unfavourable Market Conditions

The resources are the same as in Scenario 1, but the load is 2000 GWh higher to reduce the surpluscapability on the system. BC Hydro/Powerex has lower amounts of surplus capability and energy to sellin both winter and summer when water conditions are above dry and has the capability to import inlower priced hours and seasons, and resell at higher priced hours and seasons. However in Scenario2, California has surplus resources. The seasonal market price has a peak during the winter but not insummer. The price margin between peak load hours and light load hours is less profitable. The lowmarket price margin in summer limits the value of a shaping resource.

Scenario 3 - Supply Balance and Favourable Market Conditions

The load and resource balance is based on the 2004 IEP base case with the 2016-17 as the operatingyear. The seasonal market price has a peak in winter and in summer, as well as profitable pricemargins between seasons and between peak load hours and light load hours. In the previous twoscenarios, the additional unit is used primarily for maximizing trade benefits and is not quite required formeeting the domestic peak load. However in Scenario 3, Revelstoke 5 is required to meet BCHdomestic peak. When Revelstoke 5 is removed, heavy imports are required to meet the domesticwinter peak load. The system is relying on the spot market to meet domestic firm load. The reduction in

_ also significantly reduces the capability to import in lower priced hours and seasonsand to resell at hioher oriced hours and seasons.

The load and resource balance is the same as in Scenario 3. The seasonal market.in winter. Revelstoke 5 is to meet BCH domestic When Revelstoke 5 isimports are required to meet the domestic winter load. Because of the lower market

it is less to on the market to meet domestic firm load in Scenario 4 than in Scenario3. The reduction in also reduces the caoabilitv to imoort in lowerhours and seasons and to resell at hioher oriced hours and seasons.

and Discussion

that anyone scenario will last for the entire life of Revelstoke 5, it is reasonable toscenarios will occur at some time in the life of the In order to be

value (Scenario 2) and a lower is as the system

While it issuppose that all

a lowerbenefit in the Reference

8,us~ness C,a.s.c;R~~;~\/i2'[,St.C0',:e ,8J"i,dCH:~ffnlt~crl Ph,ase 220G6

Table B1. Range in System Benefit

Scenario 1 Scenario 2(Reference Case) • Scenario 3 Scenario 4

RevelstokeUnit 5ahead of DomesticNeed

RevelstokeUnit 5used to meetDomesticNeed

EnergySupply1 DemandBalance

EnergySurplus(2008/09)

EnergyBalance(2008/09)

EnergyBalance(2015/16)

EnergyBalance(2015/16)

MarketPrice Characteristics

• Summer andwinter peak

• Higher marginbetween peakand LLH prices

• Winterpeak • Summerand • Winter peakonly winter peak only

• Lowermargin • Highermargin • Lowermarginbetweenpeak , betweenpeak betweenpeakand LLH prices ; and LLH prices and LLH prices

Average SystemBenefit-OriginalTurbine Efficiency $31 M/yr $13 M/yr $18 M/yr -$12 M/yr

No separate study was conducted for Scenario 4 with the reduced turbine efficiency curve. The resulthas been estimated by reducing the Scenario 3 result by approximately 30%.

For Scenarios 3 and 4 in which Revelstoke Unit 5 is need to meet domestic load requirements, itsbenefit as shown in Table B1 is derived by removing it from the system and calculating the cost ofimports required to meet domestic winter peak load and the lost opportunity cost from system shaping.The values in Table B1 do not include any replacement capacity costs that may be required, such asreserving DSBs.

Generally, the following comments can be made about the system benefits from Revelstoke Unit 5:• more value if market prices contain both a summer and winter peak, and as price margins increase

between seasons and peak load hours and light load hours• shaping value dependent on transmission availability, in particular BC to US intertie availability

during HLH• more value if the system has surplus energy and capacity• value from energy gains fairly consistent across market and supply/demand scenarios• value from time shifting are twofold - (1) generate more during high value periods and (2) as a

result of (1), reservoir is drafted lower and can then import more during low priced periods

B-t.Jsrness CaS(3 R,e·\f'i;,'·!.St:':::Y{'320'06-

cH';.d D,s:·ftn:iti',:;·t1 PI1as.:,e 2 29

Appendix B - Total Construction Cost (P90 loaded)JULY 2006 % OF TOTAL

DESCRIPTION P90 LOADED LOADED($millions) COSTS 2006

PROJECT MANAGEMENT AND SUPPORT 2 0.6%DESIGN AND ENGINEERING 11 3.2%CONSTRUCTION MANAGEMENT & SERVICES 13 3.7%PROCUREMENT 1 0.3%QUALITY ASSURANCE 2 0.6%COMMISSIONING & STAFF TRAINING 4 1.2%

SUB TOTAL (Management and Engineering) 33 9.5%

S&I CIVIL & PENSTOCK WORK 24 6.9%S&I TURBINE AND GENERATOR CIW BONUS 94 27.1%S&I ANCIL MECHANICAL AND ELECTRICAL 33 9.5%CHC MANAGEMENT COST 2 0.6%

SUB TOTAL (Construction) 153 44.1%

FACILITY OPERATIONS 1 0.3%INSURANCE 2 0.6%ADDITIONAL REQUIREMENTS 1 0.3%BUSINESS DEVELOPMENT & LEGAL 1 0.3%EXTENDED REGULATORY TO SUMMER 2008 6 1.7%MITIGATION AND COMPENSATION (INCLUDING WATERRIGHTS) 4 1.2%

SUB TOTAL (Other Costs) 15 4.4%

DEFINITION PHASE TO SUMMER 2006 3 .9%F07/08 EXTENDED DEFINITION PHASE TO 09/2007 13 3.7%

SUB TOTAL (Definition phase) 16 4.6%

ESCALATION (Over and Above CPI) 72 20.7%

P90 CONTINGENCy1 58 16.6%

P-90 ESTIMATE 347 100.0%

The $347 M (loaded) estimate does not include possible costs for the following items:• Bus Interconnection (the proposed additional bus at Revelstoke G.S.)

• Seismic stability associated with 731 block

• Further construction cost increasesThe corresponding P50 estimate is $300 million (loaded).Note that the $9,358.1 k Sub-total for the Definition Phase has been updated to $12,500 k correspondingto a P50 total of $300 M.

8:u:srrll?SS Cz~s'e R>3:\/tS:'fStc·k0

20.0.6citl··d Deffnltion Fh·a:s.E.~2

Appendix C - Public Consultation and First Nation Issuesthat require mitigation

ISSUE DRAFT RECOMMENDATIONEnvironment:Entrainment To be addressed in BC Hydro Fish Entrainment StrateQYOther Fish Water Use Plan monitoring studies to be adjusted to include winter

sampling and additional strandingVegetation Water Use Plan monitoring studies adjusted to include relocation of

some veQetation proiects, and to assess impact of diurnal fluctuationWildlife Habitat Water Use Plan monitoring studies adjusted to include relocation of

some habitat projects, and to assess impact on migratory birdsErosion Upstream bank protection for golf course and downstream

protection/enhancement of habitatSocial:EmploymentlTraining Subsidize training program (carpentry) to ensure availability. Follow

CHC agreement for construction labourAccommodations Block reserve local hotels and motelsTraffic Repair Westside Road to as Qood a condition as pre-proiectAdmin Support Include proiect coordination role for proiectRecreation/NaviQation Include Revelstoke boat ramp in Water Use PlanArchaeoloQY Advance completion of inventory study in the drawdown zoneFirst Nations:Archaeology Water Use Plan adiusted to include protection of sites

B-ustnsss Cc;,S:',?f-t1(?;\:i<:2;;'2,:(;f<,;2{J,ugust 2006

c:nd D,&fir:l'!i',::;"fl F':1~"~:z.s'92 ~

Appendix 0 - Key Generator and Turbine Contract Tenllsand Conditions

Note: As of 9 August 2006, we are still in the process of negotiating a final contract with Voith Siemens.Therefore, some of the key contract terms are still under negotiation and subject to change.

Nature of Contract: The contract is for a turbine and generator unit for Revelstoke 5. As is commonpractice, the contract provides for the design and construction of a physical scalemodel (1:19) of the turbine. This model is then tested at an independent laboratoryto ensure performance. If the performance of the model falls below contractualcommitments, liquidated damages are assessed. If the performance is significantlybelow contractual commitments, termination of the contract may be warranted.

Once the model is satisfactorily tested, and upon an affirmative notice from BCHydro to proceed further, the full scale turbine (the "prototype") and generator aredesigned, fabricated and installed.

Turbine/Generator: 512 MW, Francis Turbine and 532 MVA Umbrella Generator. The turbine consistsof a spiral case, stay vanes, wicket gates, runner, draft tube, bearings and a verticalshaft for coupling to the generator. The generator consists of a rotor, stator,bearings, and brushgear.

Contractor: Voith Siemens Hydro Power Generation Inc. (Canadian subsidiary)

Contract Stages: Stage 1: Turbine model development and testing, and design of spiral case anddraft tube.Stage 2: Prototype turbine and generator design, supply and installation.

Price:

Schedule:

Security:

As per BC Hydro standard tender documents, escalation formula based onCanadian indices for inflation, labour, materials and copper (as applicable). [Note:Still under negotiation]

Further written authorization from BC Hydro required to start Stage 2.

[Note: Original schedule was for an Oct/20 10 in-service date. Be Hydro hasnegotiated additional schedule flexibility including an option for an Oct/2011 in-service date]

0- II ~ oc:ro iii' 3' OJ OJD

52:;::;: ..., :3 £:,...,I =OJ OJ OJ 0.OJ .......... ::l (0 OJ'< -,0- .. 0 ..... ro .....0 ::l 1ir (/)roc (/) (/) ., 0.;; 0

-+0

P50 Estimate October 2011 In-Service

Rated 0 0 0 0 0 0 250 500 5000 0 0 0 0 0 240 480 480

187,962 34 4,544 28,346 26,165 65.190 76,964 38.77020,718 0 20,718 3.8 905 1,810 1,810

105 210 210 ..Annual Costs andBenefits are Uniformin $2006

0 2,656 0.5 5 260 3,072 10end of 50 yearprojecl life(except sustainingcapital which averages$9M every 10th year)

P90 Estimate October 2011 In-Service

Oct-11

MW 5,722 0 0 0 0 0 0 250 500 500MW 5,494 0 0 0 0 0 0 240 480 480

Capital $k 213,565 39 4,616 30,543 34,095 71,626 83.406 48,712of Energy: Capacity Water 20,718 3,8 905 1.810 1,810

OpHratingO&M 2006 2,398 0.4 105 210 210G&A $k 0 0,0

faxes and Grants 2006 3,210 0,6 140 281 281 Ii'

Sustaining Capitat $k 2006 3,382 0,6 Annual Costs andBenefits are Uniform

Ashton Creek 250 MVAR in $2006Capital 2006 to end of 50 yearO&M 2006 project life

(except sustainingcapital which averages

Related Benefils: $9M every 1mh year)Value of $/MWh less waler rentals ot $5,069/MWh

Energy Gain at 140 GWh ave $k 2006 (19)System Gain: 86 GWI, ave $k 2006Time Shifting/Shaping