seven mile generating station … mile generating station installation of the fourth generating unit...

SEVEN MILE GENERATING STATION INSTALLATION OF THE FOURTH GENERATING UNIT

EXECUTIVE SUMMARY

Background and Overview

The Seven Mile hydroelectric generation station is located on the Pend dlOreille River in southeastern British Columbia near Trail, 18 km downstream of Seattle City Light's Boundary Project and 9 km upstream of Cominco's Waneta Project. The Seven Mile Dam and Power plant came into service in 1979 and consist of a concrete gravity dam, a spillway, and a 4-bay powerhouse. Three generating units with a total nameplate capacity of 607.5 MW were initially installed. The installation of Unit 4 will complete the project and increase the capacity by approximately 210 MW and produce an average of 302 GWh of e!ectricity per year.

In January 2001 Minister has issued an exemption to the CPCN and directed BCH to proceed with the project for an in-service date of the spring 2004.

The Seven Mile Unit 4 project was approved by the BCH board at their January 22, 2001 meeting for an in-service date of March 1, 2004 and a CAR of $89.1 million. Expenditures to the end of May 2001 against the CAR are $10 million and the commitments are $46.8 million.

Since the approval by the BOD in January, to overhead rates charged to the project have changed and an opportunity to advance the in-service date has been explored.

The opportunity to advance the in-service date by teii months has been explored wiin GE Canada, the supplier of the generating units under the Strategic Partne~ship with BCH. Confirmed prices have been agreed with GE to accelerate work that will enable the project to enter service 10 months earlier, by 30 April 2003, at a cost to the project of $6.2 million. Other contract work in the project has been or can be scheduled to meet the accelerated in-service. Commitments have been made to preserve the early in- service date.

Analysis

Overhead Adjustment

The Power Supply SBU overhead rate has increased from 3 percent in fiscal 2001 to 6 percent in fiscal 2002. The increase is as a result of a change in overhead allocation methodologies adopted by BC Hydro and adjustment to eliminate an under-absorbed balance from the previous year. This results in a CAR request of $2.1 million.

Advanced In-Service Date

Based on the June 21, 2001 electricity price forecast, the expected incremental benefits of the generation due to the ten-month earlier in-service date are estimated at $1 4.6

million (nominal dollars) yielding an increment one year blc ratio of the acceleration of about 2.3 and a one year SVA of $5.5 million.

A review of the risks associate with the acceleration were carried out. 0 Cost, the risk of cost overruns on the acceleration costs are low as the prices from

GE have been submitted under contract as a part of the supply contract for the generating unit. On the project as a whole, the other major contract, the civil works under Contract SM 73, has been awarded on a firm price basis to meet the advanced in-service date. These two contracts represent 65% of the direct project cost along with the work completed to date. The remaining contracts would be bid on the bases of the advanced in-service dates. The project contingency has been held at $4.6 million. Delay, the risk of a delay to the accelerated in-service date has been mitigated by a close examination of the schedule by both GE and BCH to ensure it is realistic and by a shared commitment, under the Strategic Partnering agreement by both parties, to meet their critical schedule dates in the agreed advanced schedule. GE will be using the various tools available under their well proven "GE Six Sigma" initiative and the whole project will be impiemented using the IS0 9001 process. All the supply contracts will have provisions for BCH to direct acceleration should a contractor fall behind his work schedule and threaten the project's critical path in-service dates. Also, a one month contingency has been provided in the project schedule as a further provision to mitigate delay risks. Benefits, there is a risk that when the project enters service that the benefits will differ from those assumed at this time for the economic evaluation. They could differ on two counts, low market wholesale price for electricity or low inflows for the first 10 months of service. A risk assessment was carried out to using the estimated energy, capacity and ancillary services values for different inflow sequences to examine the risk due to low inflows. The studies indicate the for six years out of seven the benefits of the project will exceed a PV of the acceleration cost. For the market prices risk, a price above about $29/MWh for the ten month period would be sufficient to recover the GE advancement cost.

Based on the attractive economics of the acceleration and low and manageable risks it Is recommended that the in-service date be revised to April 30, 2003 and the CAR #94846 be revised accordingly.

Summary and Recommendation

CAR Revision 4 was approved by the Board in January 2001.

The table below summaries the changes requested to the CAR resulting from the overhead rate increase and the advanced in-service date costs.

CAR Rev 5

Direct $

OH

IDC

Acceleration I Car Rev 4 OH

77.5

2.5

9.1

2.1

5.9

0..3

(0.6)

83.4

4.9

8.5

It Is recommended that the CAR # 94846 be increased by $7.7 million to a total of $96.8 million.

I

Business Case approved by:

Total

In-Service

D. A. Harrison Senior VP, and CFO

Submitted by:

89.1

1 /Marl2004

A. Gillies Senior VP, Power Supply

Recommended by:

2.1

1 /Marl2004

M. Costello President and CEO

5.6

30lAprl2003

96.8

30lAprl2003

aferrei2

D. A. Harrison Senior VP, and

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A. Gillies

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M. Costello President and

BC Hvdro Power and Authority Power Supplv - Resource Manaaemenf

Business Development

Calculation Information Sheet

Project Project No.

Requested By Completed By

Delivery Date Filepafh

Task

Seven Mile Unit 4

Peter Northcott Andrew GH Newell

June 15,2001 C:\Windows\TEMP\[SevenMileU4-Benefit-l SJunOl .xls]Summary - Vary Generation

Re-calculate benefit associated with accelerating construction of unit 4 using updated BC Price Forecast - 15JunOl.

Notes

aferrei2

Peter Northcott Andrew GH Newell

PLY - - Discount Rate:

Inflation:

Annual = I 4.70% Monthly = 0.77% (blue numbers are calculaled)

Notes:

Notes:

Year

2000 2001 2002

1. Source: SNMU41-Accelerated.xls - assumed that CalCUlatiOns were in Nominal CAD.

Page 2 of 6

Annual Inflation (?o

1.700 1.900

CumulaUve

I=,": 100.0% 101.7% 103.6%

2003 1 2.000 2004 1 2.000

105.7% 107.8%

Notes: 1. &me: Corporate.

Capibl C a t (Nominal CAD):

Ancillary Service Revenue (Real 2000 CAD):

Revenue 157,794 15.061 21,418

7 n 139,362 47,969 57,157 52.164

12 191.931 Notes: 1. Source: VOE Report, DAR.

Genontion by TOD (GWhI:

1. Source: WKC.

Facton for Scaling Generatlon based on Precipitatlon: . . .

1. Source: WKC

LLH Inflow Variation 40%: 40 yr return period 50%: 12 yr return period 60°k 7 vr return narind

, . . - . - . . - . . - - , ..- , ... ..- , I." "." "."

Page 3 of 6

Jan 0.0 0.0 0 0

Feb 0.0 0.0 n n

130%: 5 yr return period 140%: 12 yr return period 150% 25 yr return period 164%: 60 yr return period

Selected

Mar 0.0 0.0 n n

Notes:

0.0 0.0 0.0 0.0 0.0

Apr 0.0 0.0 n I

0.0 0.0 0.0 0.0 0.0

May 0.0 0.1 n A

0.0 0.0 0.0 0.0 0.0

Jun 0.0 0.1 n 7

1.9 2.3 2.7 3.1 1 .O

Jul 0.0 0.0 n i

1.3 1.3 1.3 1.3 1 .O

Aug 0.0 0.0 n n

1.3 1.3 1.4 1.4 1 .O

Sep-Dec 0.0 0.0 n n

2.0 2.4 2.8 3.3 1.0

0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0

Price of BC Elecblclty (Nornlnrl CAD):

. . - .- - . 1. Source: 3lMayOl price forecast. AGHN.

Assurnptlanr:

1. Capital cost payments and revenues ocarr at the end of the month for NPV calculations.

Prlco Factor:

I lnflowVarlaHon I HLH I LLH ]

Page 4 of 6

IAE!El

BC HYDRO POWFR AND AUTHORlTY E MAN- -

P F-STIMATION OF NET BFNFFIT OF ACCEl FRATING CONSTRUCTION

C:\Wndows\TEMP\ISevenMileU4-Benefit-l5JunOl .xls]Surnmary - Vary Generation Date Printed: 25Jun-01

Notes: - -

1. NPV as of April I, 2001. 2. Totals have been rounded to the nearest hundred-thousand dollars. &rrL,r c6 f l 3. Capital cost calculations for the March 1,2004 in-service show expenditures beyond this in-service date. 7

F

aferrei2

&rrL,r c6 f l 7

aferrei2

&rrL,r c6 f l 7 F

C:\Windows\TEMP\[SevenMileU4-Benefit-15JunOl .xlspurnmary - Vary Generation Date Printed: 25Jun-01

Notes: 1. NPV as of April 1,2001. 2. Totals have been rounded to the nearest hundred-thousand dollars. 3. Capital cost calculations for the March I, 2004 in-service show expenditures beyond this in-service date. 4. Electricity prices have been approximated for the range of high inflow and low inflow conditions provided in the drop-down list.

The approximated prices reflect the assumption that higher prices occur in low hydro years and lower prices occur in high hydro years.

% lncreaselDecrease in Inflow from Mean with Estimated Return Period* = lM)%:2yrreturnperiod 1 - Changing expected inflow will increase or decrease generation and energy revenue of Unit 4 accordingly.

Seven Mile Unit 4 Initiative Assessment

CAR #94846

Resource Management November 2000

BC Hydro Power Supply Initiative Assessment and Scoring: Seven Mile Unit 4 Proiect

Executive Summary

The Seven Mile hydroelectric generation station is located on the Pend d'oreille River in southeastern British Columbia near Trail, 18 km downstream of Seattle City Light's Boundary Project and 9 krn upstream of Cominco's Waneta Project. The Seven Mile Dam and Power plant came into service in 1979 and consist of a concrete gravity dam, a spillway, and a 4-bay powerhouse. Three generating units with a total nameplate capacity of 607.5 MW were initially installed. The installation of Unit 4 will complete the project and increase the capacity by approximately 2 10 MW and produce an average of 302 GWh of electricity per year.

The 1994 Integrated Resource Plan (Electricity Plan) identified the installation of Unit 4 at the Seven Mile Generating Station as a prefened option to meet future domestic electrical need and recommended, through the Columbia Basin Development team, that the in-service date of 2000 be preserved. This included the application for an Energy Project Certificate (EPC). The 1995 Integrated Electricity Plan recommended continuing the licensing for the project for an in-service date of 2000.

The 1999 IEP Update concluded that no major resource acquisitions will be required by BC Hydro prior to 2006 to meet reliability planning criteria for domestic load. The IEP identifies the Seven Mile Unit 4 project will be needed to meet capacity reliability criteria in 201 1. The IEP also examined the option of advancing the Seven Mile Unit 4 project to its earliest in-service date of 36 months after receiving funding approval - March 2003. This examination identified that there may be an opportunity to advance Seven Mile Unit 4 construction ahead of domestic need to serve opportunities in electricity trade markets.

The SVA of Seven Mile 'u'nit 4, at its earliest in-service date cuiieiliiy March 2004, is $34 million over 50 years. Break-even is achieved approximately 19 years after in-service. The project provides the following additional benefits: - with an amage long-run cost of $29/MWh, the project provides a supply of electricity that

is less expensive, in the long-run, than a combined cycle gas turbine; 0 Enables retention of the Project Approval Certificate; - provides direct employment in the order of 250 person years and offset employment

through the GE Strategic Partnering Agreement of 360 person years of employment; and 0 provides green energy credits by reducing the use of gas fired electricity sources.

The Value Based Management score for this project is 60.

From a Provincial perspective, the SVA is $63 million.

BC Hydro Power Supply Initiative Assessment and Scoring: Seven Mile Unit 4 Project

TABLE OF CONTENTS

.................................................................................. .................................. . 1 Project Summary : 1

..................................................................................................................................... 1.1 Background 1

1.2 Opportunity ..................................................................................................................................... 2

............................................................................ . 2 Identification and Analysis of Alternatives 2

............................................................................................................................................ 2.1 Analysis 2 2.1.1 Key Assumptions ................................................................................................................................... 2

2.2 Summary of Results ....................................................................................................................... -3

3 . Risk ..................................... . . .............. .................................................................. 4

. 4 Recommendation .................................................................................................................... 7

............................................................................................................................ . 5 Project plan 7

6 . Deliverables ......................................................................................................................... 7

........................................................................................... 7 . Initiative assessment and scoring 8

............................................................................................................. 7.1 Summary of VBM Results 8

7.2 Strategic Alignment and Impact ................................................................................................... 9

.......................................................................................................................................... 7.3 Benefits 12 ................................................................................................................................. 7.3.1 Financial Benefits 12

................................................................................................................. 7.3.2 Additional BenefitsIImpacts 13

7.4 Projecthitiative Costs ................................................................................................................. 15

...................................................................................................... 7.5 Implementation Risk Factors 16

Appendices:

Appendix I: Detailed Assumptions Appendix 11: Results of Financial Analysis


I

1. PROJECT SUMMARY

The Seven Mile hydroelectric generating station is located on the Pend d'oreille River in southeastern British Columbia. The facility is situated 18 km downstream of Seattle City Light's Boundary Project and 9 krn upstream of Cominco's Waneta Project. The Seven Mile Dam and Power Plant came into service in 1979 and consists of a concrete gravity dam, a spillway and a 4- bay powerhouse. Three generating units with a total nameplate capacity of 607.5 MW were initially installed. The fourth bay remains empty. The power plant was designed as a four unit 8 10 MW facility, which would be in hydraulic balance with the ultimate six-unit development at the upstream Boundary plant. Unit 4 would increase the installed capacity by approximately 210 MW and enable the facility to produce average incremental energy of 302 GWh per year. No additional transmission facilities would be required between Seven Mile and Kelly Lake/Nicola to accommodate Unit 4.

The Seven Mile Unit 4 project was initiated as a result of the findings of the 1994 Integrated Resource Plan (IRP). The 1994 Integrated Resource Plan (Electricity Plan) identified the installation of Unit 4 at the Seven Mile Generating Station as a preferred option to meet future domestic electrical need and recommended, through the Columbia Basin Development team, that the in-service date of 2003104 be preserved. This included the application for an Energy Project Certificate (EPC).

Key events since the 1994 IRP include: Energy Project Certificate Appiication submitted, December 1994 The 1995 Integrated Electricity Plan recommended continuing the licensing for the project for an in-service date of 2000. BC Hydro's Board of Directors approved capital funding kr the project, February 1995. Completed the "Mitigation and Compensation Plan for the Installation and Operation of Unit 4 at the Seven Mile Generating Station", March 1996 Project Approval Certificate approved by the Province, 25 April 1996 Application for a Certificate of Public Convenience and Necessity (CPCN) made in, September 1995 Authorization under the Fisheries Act ganted December 1996 Application for a CPCN withdrawn December 1998 Water License issued allowing diversion of water for Unit 4, December 1998 The BCH Board endorses management's recommendation to "discuss with the Province options for advancing the project for a 2002 in-service date and that these discussions be expedited to preserve the 2002 in-service date", 13 September 1999. The 1999 IEP Update concluded that no major resource acquisitions will be required by BC Hydro prior to 2006 to meet reliability planning criteria for domestic load. The IEP identifies the Seven Mile Unit 4 project could be needed to meet capacity reliability

Page 1


1

criteria in 201 1. The IEP also examined the option of advancing the Seven Mile Unit 4 project to its earliest in-service date of October 2002.

There may be an opportunity to advance Seven Mile Unit 4 construction ahead of domestic need to serve opportunities in electricity trade markets.

2. IDENTIFICATION AND ANALYSIS OF ALTERNATIVES

Two alternatives have been considered to address electricity trade market opportunities:

1. Install Unit 4 Now: This alternative represents installing generating unit 4 with the earliest possible in-service date: March 2004 or 36 months after receiving approval.

2. Install Unit 4 Later: This alternative represents installing generating unit 4 for an in- service date of October 20 11.

, 2.1 .I Key Assumptions

The key assumptions used in the analysis include':

- 1 he anaiysis assumes a base case in-service date of March 2004.

c The analysis incorporates the September 2000 nominal electricity price forecast. o The analysis is conducted in nominal dollars using a nominal discount rate of 8.7% with

an amuai-lhflation rate of 2.0% applied to capital, OMA and water rentals. 0 The total direct capital cost, including inflation, used in the analysis of the project is

$76.8million. This excludes interest during construction (IDC), overhead, and monies previously spent.

+ The analysis excludes previous direct spending of $6,498 million for assessment and licensing. The loaded value of this spending is $8,391 million (loaded for overhead and IDC).

+ The generation forecast is based on the historical 45-year in-flow conditions for Seven Mile, adjusted to reflect current operating constraints.

+ The turbine will be purchased and installed by GE Canada under the terms of the Strategic Partnering Agreement.

Detailed assumptions are located in Appendix I.

Page 2

BC Hydro Power Supply Initiative Assessment and Scorina: Seven Mile Unit 4 Proiect

The two alternatives have in-service dates. Because of the significant impact on timing of costs and benefits, the results are presented for both alternatives to the end of the economic life; both alternatives assume a 50-year economic life2.

Table 2.1 indicates that proceeding with an in-service date of March 2003 is the most economic long-run of the alternatives presented.

Table 2.1 Summary of the Alternatives

10 Years of Benefit End of Life I 10 Years of Benefit End of Life

PV Project Benefits $47,286 $102,098 1 $20,050 $53,272

PV SVA3 (Nominal) $8,020 $33,676

PV Proiect Cost 63.812 68.423 1 45.078 47,679

($10,885) $5,593

.I I

NPV (Nominal) ($16,526) $33,675 1 ($25,029) $ 5,593

In addition to the financial benefits, other benefits include:

Benefit Cost Ratio 0.74 1.48

The implementation of the project will provide 250 person-years of employment. Under the Turbine Partnering Agreement with GE for the purchase of the generating unit the industrial offset agreement would provide a , further 360 person-years of employment through a $30 million industrial offset. The project supports the realization of the intent and objectives of the GE Partnering agreement. The forward electricity price curve is based on the long-run cost of combined cycle gas turbine (CCGT) located in the lower mainland. The analysis values electricity delivered to the lower mainland. Therefore, a project that has a long-run benefit-cost ratio greater than 1.0 is a more attractive long-run investment option than a CCGT located in the lower

0.44 1.07

Both alternatives presented discount results to 2000/01. 3 ~ h e analysis does not include dividend impacts.

-

Page 3 01/01/08


mainland. Seven Mile Unit 4 has a long-run benefit cost ratio of 1.48, it is therefore considered an economic long-run source of electricity supply.

Further, the project includes costs that are likely to be incurred irrespective of the decision to proceed. These costs are;

0 Plant Reliability: There is an imminent requirement to replace the switch-gear at the existing units at Seven Mile. As part of the Unit 4 project, the switch-gear on Unit 3 will be replaced to be compatible with the new switch gear to be provided on unit 4. If Unit 4 is not installed, funding will be requested to replace the switch-gear on Units 1 and 2. The cost of replacing switch-gear on Units 1 and 2 or Units 3 and 4 is $4.6 million. Overhead Costs: The project includes an allowance for $2.4 million of overhead. These overhead costs are likely to be incurred whether the project proceeds or not. - Other costs: The project includes cost allowances for "other" work such as corporate administration, M&C, Power Facilities, public consultation etc. These costs, totaling $1.6 million would likely be incurred through other initiatives such as water use planning.

If the project does not proceed, the following costs will be incurred:

Strategic Partnering Agreement: If the project does not proceed, GE through the Strategic Partnering Agreement could seek damages due to failure to meet the expectations of the agreement, this could expose BCH to a penalty estimated at $3.3 million. These costs have been included in the delay option. Write-down: Approximately $8.3 million has been spent to date. If the project does not proceed, monies spent to date will be written-off. These costs have been included in the deiay option.

3. RISK --

The following risks have been given consideration as they relate to pursuing an in-service date of 2002103 :

Construction Cost: The construction cost estimate.is considered conservative for the following reasons:

1. Cost Estimate: The cost estimate consists of approximately $30 million (direct dollars) of work to be completed by GE Canada with $37 million (direct dollars) of work to be completed by others. The cost estimate was reviewed in November 2000 and the prices from GE Canada are under the Strategic Partnering Agreement are confirmed.

Political Issues: The project is attractive from a Provincial perspective, and the risk that rate payers could be adversely impacted is considered to be low.

Page 4 01/01/08


Option Values: Option evaluation has not been explicitly considered because the appropriate tools and skills are not readily available.

Foreign Exchange Exposure: Foreign currency exchange rates are not considered to be a project risk. Rather, foreign exchange exposure managed on a portfolio basis by the treasury group.

Transmission Risk: The cost of incremental transmission capital is included in the economic analysis.

Project Approvals: Project approvals are subject to cancellation if the work is not substantially started within five years of its date of issue. The Project Approval Certificate was issued on 25 April 1996. The Federal Department of Fisheries, Habitat Compensation Agreement requires that the civil works associated with the project commence within five years from the date of the agreement (Agreement date 22 March 1996). The Federal DFO Authorization requires that the construction of the civil works begin within five years of the date of the authorization (2 December 1996). If the project does not proceed prior to March 2001 then these approvals could lapse or require extension.

Sensitivity Analysis: The project is sensitive to changes in market prices and water conditions. - - - Accordingly, the following cases have been analyzed:

1. High market prices resulting in an increase in average prices of approximately 6%4. 2. Low market prices resulting in a reduction in average prices of approximately 6%. 3. High water conditions resulting in an increase in energy and a decrease in prices. 4. Low water conditions resulting in a reduction in energy and an increase in price.

4 High and low market prices are based on the high-low range of the long-run marginal cost of gas as provided by Confer in February 1999.

High and low water conditions represent a 1 &I 10 ten year event. The high and low water conditions have resulted in price impacts consistent with those described in the previous footnote.

Results are presented to the end of economic life.

Table 2.2 Summary of Sensitivity Analysis6

Nominal ($000)

Page 5 01/01/08

.C

SVA to economic life B/C Ratio to economic life

Annual HLH GWh Annual LLH GWh

Low Market

Price Case 'i

'" . - >

$26,030 1.37

200 102

Base Case In-Service.

2003104 ', ' . - ,d*

$33,675 1.48

200 102

High Water

' High . Market

. Price Case z

$41,322 1.59

200 102

Low Water

Conditions a* _ I- Case ,&$

$86,460 2.25

347 163

Conditions ,.pp -.< &, - A

, :,*,*~C&se -. - ;:

$17,592 1.25

13 1 70


7 ~ h e analysis does not include dividend impacts.

i

Assumptions for each sensitivity are located in Appendix I.

In addition, the following impacts have been considered:

C02 Offset: construction of Seven Mile Unit 4 avoids an estimated 170,000 tonneslyear of C02 which would be produced by other competitive sources of generation. The cost to offset the C02 is estimated $10 and $90 per tonne. At $10ltonne this results in an additional annual savings of $1.7 million.

(61% NIA

+6 % Nl A

Average Price Change Impact on Water Rentals

Also, a sensitivity analysis has been conducted using a discount rate of 12% nominal. This represents a rate risk adjusted for market price volatility. The results are provided in table 2.3.

NIA N/A

Table 2.3 Summary of the Alternatives Using a Discount Rate of 12% Nominal

(16) % +66%

+26 % (34)%

PV SVA7 (Nominal) ($3,893) $3,483 r-

Benefit Cost Ratio 0.64 '1.05 1 02 8 0.62

($17,732) ($13,316)

PV Project Benefits $37,974 $64,808 PV Project Cost 59,010 6 1,325 NPV (Nominal) ($2 1,036) $3,483

Page 6 01/01/08

$9,664 $22,539 34,819 35,855

$25,155 ($13,316)


I

4. RECOMMENDATION

The SVA of Seven ~ i l e Unit 4, at its earliest in-service date currently March 2004, is $34 million over 50 years. Break-even is achieved approximately 19 years after in-service. The project provides the following additional benefits:

a with an average long-run cost of $29/MWh, the project provides a supply of electricity that is less expensive, in the long-run, than a combined cycle gas turbine;

a Enables retention of the Project Approval Certificate; a provides direct employment in the order of 250 person years and offset employment

through the GE Strategic Partnering Agreement of 360 person years of employment; and a provides green energy credits by reducing the use of gas fired electricity sources.

The Value Based Management score for this project is 60.

From a Provincial perspective , the SVA is $66 million.

5. PROJECT PLAN

The project plan is documented in report number MEP392, titled: the "Columbia Basin Development, Seven Mile Unit 4 Implementation Phase Project Plan".

6. DELIVERABLES - The deliverables include:

Unit 4 installed and operational 36 months after funding approval. a Job creation which will be measured and recorded in accordance with the Industrial

Benefits Program agreement. .

Page 7 01/01/08


7. INITIATIVE ASSESSMENT AND SCORING

7.1 SUMMARY OF VBM RESULTS

Figure 2.1 Summary of VBM Scores

STRATEGIC IMPACTS (0 - 25) Secure the Base

Efficiency & Productivity Effective Governance Public Support

Build a Strong & Capable Organization Enhance Customer Focus

Service Excellence Value Added Solutions

Grow the Business Market Development Strategic Businesses & Markets

Total Score for Strategic Irn~acts 11

ADDITIONAL BENEFITS (0 - 20) Environmental Impacts 7 LegaYRegulatory Adherence 0 Public Support 2 Employee or Union Issues 5 Aboriginal Relations 2 PublicEmployee Safety & Health 0 CornrnunitylEmployment Impacts

El 10

Total Score for Additional Benefits 20

I FINANCIAL BENEFITS (0 - 25)

PV of SVA to 10 Years $8.1 million PV of SVA to end of Life: $33.7 million

INITIATIVE COSTS (0 - 15)

PV of Costs to end of Life: $68.4 million 0

IMPLEMENTATION RISKS

Time to Implement Complexity Assumptions Past Performance Technology/Methodology Mitigation Strategy 48%

Total Score for Implementation Risks

I Total VBM Score for the Seven Mile Unit 4 Project I

Other Evaluation Measures

Corporate NPV (5 16,525) $33,676 Corporate BIC Ratio. 0.74 1.48 Unit Cost of Generation $29.18 Provincial NPV $62,771 Provincial B/C Ratio 1.92

Page 8 0 1/0 1/08


7.2 STRATEGIC ALIGNMENT AND IMPACT

Efficiency & Productivity Support competitive pricing

( Y W I Y: orovides new e n e r ~ v s u ~ ~ l v 1

Oprimize commercial availability I Y: ~rovides new caoacitv I Develop operating plans to maximize total margin I N I Develop investment plans for new plants I N I fn~esr/divest/maintain assets commercially I N I Garher customer, market and competitor intelligence I N I - I

Oprrmrze operating and resource data rncludrng the role of each plant I N I Effective Governance & Public Support

Enhance ~oodwd l and consent to operate I N I - 1

Balance multiple objectives I N I . - I

Manage issues (i. e. Sinkhole) I N L,nderstand constraints and impacts (ex . Dam Safety, WUPs) N I Develop and maintain Gov't and community relationshrps I Yes: supports Government initiative Seekstakeholder input I N

Service Excellence x. b

Delrver on promises 1 N Blrrld a siraiegic relaiionshi~ with Powerex N

Development of leadership Improved communication and information

Development of competencies Improved relationship Establishment of collaborative management

Alignment of the worL$orce Fostering diversiv Encoura~ement o f flexibilitv

N N N N N N N N

Value-Added

COLU&~IO strengIhen operafmg relat~onshp w ~ f h Powerex -

Manage . W C S and T&D relationshrps Define/develop relationshrps wrth M&CS and T&D

Create new product and service ideas N Enhance Power Supply 's capabilities N tinderstand customer needs and market requirements N Parrner with direct customers N L'nderstand core ca~abililies N

N N N

Market Development Creote new product and service ideas Enhance Power Supply's capabilities L'nderstand customer needs and market requirements

Partner with direct customers L'nderstand core caoabilities

Y: increase in fleet capacity t---"---l I I

New Strategic Businesses & Markets 9) ,

Develop targeted energy-related solutions I N Burld/mvest/drvest to caprtal~ze on new opportunrtres N Parmer with direct customers I N I

Page 9 0 110 1/08

- . . . ..

Ensurefit wrth Power Supply's strengths and strategrc drrectron

Scanjor oppor1imrfres en fry / ex11

. . N N


Slrategic Objectives ~ & p A EG " PS " Org A CS " GTB "

Strongly supports tho objective

Is mica1 to this objedivs as it

panaina le m S8UI KBU

Financial Efficiency and Productivity (E&P) Score: 6 Notes: Provides low cost supply of new energy and capacity.

Effective Governance (EG) Score: 5 Notes: Facilitates government initiative.

Build and Maintain Public Support (PS) Score: 0 Notes: No significant impacts on this objective.

Build a Strong and Capable Organization (ORG) Score: 0 Notes: No significant impacts on this objective.

Lead the Market - Enhance Customer Service (CS) Score: 0 Motes: No significant impacts on this objective.

Lead the Market - Grow the Business (GTB) Score: 0 - Notes: No significant impacts on this objective.

Is ckiIiC11 10 Ihls objeslive or n penainr

10 all of BCH

Page 10 01/01/08


, Following is a summary of impacts the Seven Mile Unit 4 project has on the Corporate performance measures.

SVA Yes This projects increase generation capability from Seven Mile and provides an SVA of $34 million.

COMNCustomer before specific capital COMA/Customer including specific capital

Public Opinion - Overall Impressions Total Generation Index

Environmental Performance Index

N No known impacts on this measure

N The impact on this measure is not planned, however, the project does increase the amount of total capital spent per customer.

N No known impacts on this measure.

Y The project increases generation capability by 185 MW at full plant load.

Y Displaces thermal generation and provides green house eas credits.

Customer Satisfaction N No known impacts on this measure. Customer Profitability from a N No known impacts on this measure. corporate perspective Service performance & reliability N No known impacts on this measure. Value-added sohtions N No known impacts on this measure.

SVA from Grow the Business N No known impacts on this measure. Ventures -s

Commodity Risk Exposure Ratio N No known impacts on this measure.

Strategic IT Coverage N No known im~acts on this measure.

Organizational Climate Safety Leadership Effectiveness

N , No known impacts on this measure. N No known impacts on this measure. N No known impacts on this measure.

Page I I 01/01/08


7.3 BENEFITS

7.3.1 Financial Benefits

PV of SVA: $34 million over the economic life of the project Score: 20 Notes: Refer to Appendix I1 for details on SVA calculations.

Summary of Scoring:

Summary of Financial Results In Service April 2004

Corporate SVA Score

The score assigned for SVA earned within 10 years.

SVA t Negative $1 Milfion 1 $2.5 1 $5 Million

Score assigned ~ O ~ V A earned over the life of the project:

Page I2 01/01/08

$25 Million

18 Million

16 Score

$50 Million

20

-

0

$1 Million

1

SVA

Score

$2.5 Million

1.5

Negative

0

4

$10 Million

3

$5 Million

2

Million 8

$25 Million

4

12

$50 Million

5


i

7.3.2 Additional Benefitsllmpacts

Score: 7 Notes: Mitigates the need to develop gas fired generation; provides green house credits.

Score: 0 Notes: No known legal/regulatory issues prevented or caused.

Score: 2 Notes: ThfTommunity of Trail may be interested in the construction of this project due to

potentially significant regional employment impacts.

Employee or

m rn v v

Nepabw general NepabYe general employee mteml n

P o ~ g e n c r a I PO+&#. general P- ponenl employe. mtsre.tl employee interenis employ.. mbrnt is

low. bu1mong.r ~enerally low to wy hqh. * l idnwd. . m t e r t held 4 a few d e r a t e , but high andlor a rnalorRyvM* OfOUP ammg swersl group rmong key group

Score: 5 Notes: Strongly held interests across KBUs and SBUs. Interested groups include Power

Supply Engineering, Resource Management, Power Facilities, Transmission & Distribution, Corporate Environment and PowerEx.

Page 13 01/01/08

BC Hydro Power Supply Initiative Assessment and Scoring: Seven Mile Unit 4 Proiect

Score: 2 Notes: The Columbia Hydro Constructors have specific clauses for aboriginal training and

employment. Further, the local aboriginal group has been consulted on the project.

PublicErnployee Safety

T-7 r-7 r - 7 v W-T

PI.VIIII low Pr.9.m nigh P r t ~ e n 6 modcrate to probaUii of moderate probabilh of moderate h g h probability of high

impacl events imp& aenb, or l w probably of hmh

impad wech

Score: 0 Notes: No known impacts.

Premnb minor job Prwems m ~ l ~ job Revme moderat. to lar *l a man numer b u n a MA wmbn hgh job bu n a large

of m m m u d r 01 sornmwhs. w "Ymbwof minor job lo0. n r

hrg. ""mbef Of commYnh.s

w m m

Score: 10 Notes: Creaks 250 worker years of employment with an additional 360 person years of off-

set employment through the GE Partnering Agreement.

Page 14 01/01/08


Score: 0 Notes: Present value of generation capital (including overheads) using a 2.0% net escalation

and an 8.7% discount rate is $59.6 million. Present value of transmission capital is estimated at $8.8 million. Present value of all project costs is $68.4 million.

Page 15 01/01/08


Time to implement (What is the total elapsed time of the initiative, ffom commitment to full deployment?) Time to Implement

7 v 3' 7

Score: -5 Notes: Upon receiving funding approval, the project has a 36 month construction period.

Complexity (Describe any specific dependencies and linkages between this and a) other initiatives, b) other SBUs or KBUs, or c) external organizations.)

Complexity

Score: 0 Notes: Although this project uses external parties to supply and install the unit, one of the

major suppliers, GE, is a preferred supplier selected by the Board of Directors.

Past Performa~ce (Does BC Hydro have past experience implementing similar initiatives? I f so, would you characterize past results as being successfill or unsuccessfil? Explain.)

Past Performance /I T-* 7

f Y

Score: 0 Notes: BC Hydro has successful experience in installing generating equipment. .

Page 16 01/01/08


Technology/Methodology (Does this initiative rely upon any technology or methodology that is new to BCH, the Utilities industry, or new in general? Describe)

Score: 0 Notes: The project does not call for new technology

Assumptions (Describe any market or regulatory assumptions that the business case is based upon.)

Score: -4 Notes: The project returns are dependent upon market prices.

Implementation Risk Mitigation Strategy (Is there a risk mitigation plan in place ? If so, attach.)

Mitigation Strategy

Score: 48r Notes: The significant implementation risks are project management oriented. These risks

are addressed in the project plan.

Page 17 01/01/08


APPEND!X I

Detailed Assumptions



I Following are the key assumptions used in the analysis of the project.

Economic & Financial Indicators

The economic indicators used in the of each alternative are:

1 Weighted Average Cost of Capital

asset net book value) 0.3% 1 Water Rental Rate ($/MWh) 4.84 Overhead Allocation Rate (charged against capital as a % of spending) 2.0%

Net Inflation De-esclation 2.0% Corporation Capital Tax Rate (Charged to

Generaticn Related Assumptions

(Nominal) 8.7%

To recognize that electricity generated closer to the Lower Mainland is worth more than

- - - electricity generated outside the Lower Mainland, generation forecasts are regionalized.

Incremental transmission costs (CIFT) from Kelly LakeNicola to the Lower Mainland is based - - - on an annual average cost of $4.1 per kW of capacity.

Appendix I Page I

01/01/08


Energy Impact Assumptions

The generation forecast is based on the historical 45 year in-flow conditions for Seven Mile, adjusted to reflect current operating constraints. The assumptions used to estimate energy impacts include:

1) Basin Description: - United States Basin: All but about 25 miles of the Pend Oreille River (US Spelling ... spelled Pend d'oreille in Canada; pronounced "Ponderay" in both Countries) are located in the US.

c Storage Reservoirs: There are 3 major storage reservoirs on the Pend Oreille and its tributaries (Flathead, Clark Fork, Bitterroot, Priest). Hungry Horse, owned by the US Bureau of Reclamation and directed by BPA, has over 3 MAF of active storage and provides multi-year storage operations. The Ken project, owned and controlled by the Montana Power Company, controls the level of Flathead Lake, has about 1 MAF of active storage and is operated over an annual cycle. The Albeni Falls project, owned by the Army Corps of Engineers and directed by BPA, controls the level of Lake Pend Oreille, has about 1 MAF of active storage and is operated over an annual cycle. - Storage Control: Operation of the Pend Oreille storage projects is coordinated with other Columbia basin operations through the Pacific Northwest Coordination Agreement (PNCA). BCH is not a member to this agreement, and has no input into basin storage operation. Unlike the Columbia Treaty Storage, the downstream agency (i.e. BCH) does not provide any compensation to the upstream parties for power-related streamflow improvements, and essentially takes the flow as provided by the US operation.

c Fish Operations: Over the last decade, fish related constraints have been imposed on aii reservoirs on the river. This has significantly reduced the effectiveness of the storage for power operations at both US and BCH project sites. Boundary-Dam: The Boundary project is located immediately upstream of 7 Mile. The project was expanded in 1985, and now has a discharge capacity of about 50 kcfs. Its forebay provides sufficient storage for its owner, Seattle City Light, to aggressively load factor the project. Generally this involves directing the available daily energy into 15 Heavy load Hours (HLH) up to the project discharge limit, with the residual water spread evenly over the remaining Light Load Hours (LLH). During the freshet period there is usually enough water coming down the rivkr to run Boundary at full load around the clock. As a result, no blocking is assumed in May, June and July. There is no minimum flow requirement for Boundary. 7 Mile: The current discharge limit for 7 Mile is about 39 kcfs. The addition of the 4" unit would increase this to about 52 kcfs, about the same as the Boundary limit. Since Boundary typically releases more water during HLH than 7 Mile (and Waneta downstream) can currently handle, the 7 Mile forebay is normally drawn down in advance of the high Boundary flows, to re-regulate the daily flows and reduce the spill at 7 Mile and Waneta.

Appendix I Page 2

01/01/08


Waneta: This project is owned by Cominco, but its operation is directed by BCH. Under the terms of the 1972 Canal Plant Agreement, Cominco is provided with a constant annual entitlement to capacity and energy, and BCH retains the actual output from the project. The current discharge capability at Waneta (with 1 out of 4 units upgraded) is about 26.6 kcfs - approximately half that of Boundary. When the project is hl ly upgraded the discharge capacity is expected to be about 3 1.6 kcfs. An expansion project is also being considered (but is unlikely?) that could potentially bring Waneta into hydraulic balance with a 4-unit 7 Mile.

2) Strearnflow Modeling: * Monthly Flow Records: Power studies were completed using three different streamflow

records: the 1993 AOP flows (1940-1985), the 1996 BPA Rate Case flows (1928-1 978), and the Feb 1998 BPA 'Best Estimate' (1928-1978). The latter two records include all anticipated fish constraints, and therefore provide a range for the more realistic basin operations. The 1998 BPA flow estimate is presumed to be the more accurate, however, becaiise it was developed more recently. To the extent that dditiona!, uiianticipated constraints may be imposed upon upstream reservoirs, both increases or decreases in 7 Mile 4 generation estimates could be anticipated. As supported by the range of streamflow records studied, however, additional constraints tend to reduce total generation from the 7-Mile project while increasing the incremental output associated with the 4'h unit. Daily Flows: Daily flow estimates were synthesized from the monthly flow estimates, using an auto-correlation procedure originally developed by Kelvin Ketchum.

2) Power Studies: Modei Details: The simulation model is a fortran modei deveioped by Herbert Louie and Wun Kin Cheng. It simulates the operation of Boundary, 7 Mile and Waneta on a twice- daily time step. The definition of HLH is variable, and was set equal to 15 hours for all studies. Boundary Operation: The daily inflows into Boundary were regulated into a maximized 15 hourELH block and a residual, 9 hour LLH block. No distinction was made between days of the week (no weekend modeling is provided). 100% unit availability assumed for all plants (i.e. no forced or planned maintenance is directly modeled). 7 Mile Re-regulation: The model simulates the 7 Mile forebay which is used to re- regulate the flows to minimize spill at the lowest discharge BCH project (i.e. Waneta). In actual practice, BCH attempts to maximize generation value, which can differ from maximizing generation. When HLH / LLH differentials are high enough to justify the operation, BCH does incur avoidable at Waneta to generate additional HLH energy at 7 Mile. This additional value (of deliberate spill when economically driven) is captured outside the model studies. mote: Recent water licence amendments may preclude this operation during some portions of the year. Further interpretation of the amendment should be investigated.] Waneta Configuration: Since the model operates 7 Mile to minimize spill at Waneta, the assumed discharge capability at Waneta affects the estimation of the benefits from 7 Mile Unit 4. It was assumed that all 4 Waneta Upgrades were installed. No Waneta Expansion was modeled.

Appendix I Page 3

01/01/08

BC Hydro Power Supply Initiative Assessment and Scorinq: Seven Mile Unit 4 Proiect

Operating Constraints: All current forebay, tailwater and generation characteristics were reflected in model studies. Turbine efficiencies for 7 Mile were obtained from the 1981 - 1984 efficiency test studies for the existing units and from bid document for the 4th unit. 4th Unit Generation: Model studies were completed for both 3-unit and 4-unit installations at 7 Mile. HLH and LLH generation totals were obtained for each study, for all 50 water years provided in the 1928 - 1978 BPA Rate Case strearnflow record. Average generation estimates were computed for each month, for both HLH and LLH. Generation benefits from the unit addition were estimated by taking the differences between the 7 Mile generation estimates. Dispatchability Premiums: Supplementary power studies were completed with 1 hour, 2 hour, 3 hour (etc.) ... and 15 hour definitions for HLHs. By taking the differences between these studies, a daily HLH profile of the project's generation potential was developed. By multiplying this hourly generation profile by an assumed hourly price profile, monthly dispatchability premiums were defined for both the existing and the expanded project. These premiums estimate the aciciitionai vaiue that can be accessed by the additional 200 MW of capacity provided by the 4th unit, through shifting lower value HLH energy, into higher value HLHs.

- - -

Revenue Related Assumptions - - -

Revenues have been valued using the Value of Energy valuation methodology. The price forecast used to value electricty is as of September 2000.

Other Cost Assumptions

OMA: facility OMA is estimated at $279k per year. The incremental OMA is due to additional maintenance requirements associated with having another generating unit. - Municipal Taxes: taxes and grants have been estimated by the corporate group and are approximately $190k per year.

Water Rentals: water rentals are based on incremental energy produced at $4.84/MWh

Capacity Fees: capacity charges are basid on incremental capacity of 185MW at $3.453/MW.

Project Cash Flows

Direct 300 7,963 28,030 30,965 463 Loaded 310 8,334 29,705 33,227 503

Appendix I Page 4

01/01/08

BC Hydro Power Supply Initiative Assessment and Scorinq: Seven Mile Unit 4 Proiect

Appendix I Page 5

0 I/O//O8


Investment schedule

Total costs invested upon completion are anticipated at:

Assumptions for 201 1 In-Service:

Assumptions for this alternative are the same as for the 2004 in-service date, adjusted for timing. Except:

1) the project cost estimate included in the economic evaluation increases by $8 million to reflect the re-licensing and re-study costs. The direct project costs in the 201 1 analysis are:

2) the monies spent to date are written-off over five years:

3) contract penalty costs are assumed to be $3.3 million and incurred in 2000/01 should the project be de@ed.

Appendix I Page 6

01/01/08


Assumptions for Sensitivity Analysis

VOE HLH Revenues VOE HLH Revenua VOE Dispatchability & Raeme Premiums Dispatchability & Reserve Premiums as a % of Revenues .J /

April May June July August September October November December January February

Total Annual Incremental

Heavy Lnad Light Load GW.h GW.h

Generatio EEi! VOE Levelized Base Case Price VOE Levelized Smsitiity Price

Price Change: 5.71%

VOE HLH Revenua VOE HLH Revenues VOE Dispatchability & Reserve Premiums Dispatchability & Reserve Premiums as a % of Revenus Generation:

Heavy Load Light Load CW.h GW.h

April IMay June July August September October November December January February March Total Annual Incr -EEl remental Generatio

VOE Levelized Base Case Rice IVOE Levelized Sensitivity Price

l ~ r i c e Change: -15.71%

VOE HLH Revenua VOE HLH Revenuer VOE Dispatchability & Reserve Premiums Dispatchability & Reserve Premiums as a %of Revenua -2

Heavy Load Light Lond GW.h GW.h

April May June July August September October November Decemba January February March Total Annual lncremenul Gneration

I VOE Levelired Base Case Price VOE Levelired Lnsitibity Rice -7 I Price Change: -5.71%

Heavy Load Light Load GW.h CW.h

April

June July August September OC* November December January February March Total Annual Incremental Gneration

VOE Levelired Base Case Rice IVOE Levelized Sensitivity Price E q lmCe change: 25.71%

Appendix 1 Page 7

01/01/08


APPENDIX ll

Results of Financial Analysis


Seven Mile Financial Evaluation Key Assumptions

Enterthe Alternative Case # t o be Reviewed i n th is Spreadsheet:

In-Service March 2004 1

Case # In-Service March 2004 0 High Market Prlce Case 1 Low Market Price Case 2 High Hydro -Low Price Case 3 Low Hydro - High Price Case 4

Economic Assumptions

Annual rate of N a Inflation k De-escalation: Rwenue Annual rate of Net Inflation & De-escalation: Cost of Annual rate of Net Inflation & De-escalation: OMA Annual rate of Net Inflation & Deacalation. Capital

Consmction begins in Fiscal Yeaf Ending March In-Servicc Month ( April is I. March is I t ) in-Service Year: Fiscal Year Ending March: Economic Life of Asset First Year of Benefiu End of Useful Life: Fiscal Year ~nd ing March: Discount Rae: Real

Discount Rate: Nominal

USS Exchange Rate

Benefit Related Assumptions

VOE HLH Annualized RwmueBenetiu: REAL f VOE LLH Annualized Rcvenue Benetlu: REAL f VOE Annualized Dispatchability Premium: REAL S Dispatchability Premiums as a % of e l d c i t y rwenua

Change in Base Case Lcvelircd Price Per MWh

Generation impacts fo; the Forward Price C ~ W C : - Heavy Load Net H L H Light Load Net L L H

GW.h Regional GW.h Regional

April

May - June -

July

wfi Itember

xtober November December January February March Total Annual incmnentrl Gncrr t io

Peak Loss Adjustment Factor

Project Cost Assumptiool

Water Capacity Fee Water Rmtal Rate W h

Facility OMA Taxa & Granu Annual Proxy used in VOE for Corporation Capital Taxa Incrementai Annual OMA Expmdinrra Overhead charged IO capital Available Capacity ClFT Cosu m LM: Transmission Capital Rate on Capacity Revmue G~ant. Taxa in Lieu and Property Tax Rate Corporation Capital Tax Combined tax rate Capilal financed through debt (for CCT)

IM) 102 104 106 108

Generat~on Cap~tal Cash Flows Real 5 75,8581 01 3001 7,9071 27,6201 30.2661 4491 01 01 01 01 0

79,196 7.782 1,835 8.068 28,783 32,239 189

Conu~but~ons ~n atd (CIA) I 01 01 01 O l 01 01 01 01 01 01 0

~ V O E HLH Revenues Is6.611. VOE HLH Revenues VOE Dispatchability & Reserve Premiums Dispatchability & Reserve Premiums as a % of Revenues 12.459.

Generation: Heavy Load Light Load GW.h GW.h

April

May June July August September October November December January February March Total Annual Incremental Gnera t io 200 102

VOE Levelized Base Casc Price VOE ~evelizcd knsitivity Price -1

l ~ r i c e Chanp: 0 . W

Heavy Load Light Load GW.h GW.h

"Y August September October November December

January Fcbwry March Total Annual Incremental Generatio 200 102

VOE Levelized Base Case Pricc VOE Lwelized sensitivity price -1

r" Price Change: 5.71%

VOE HLH Revenues VOE HLH Revenues VOE Dispatchability & RerervePremiums Dispatchability & Reserve Premiums as a % o f Revenues 7 769.

I Generation: Heavy Load Light Load

GW.h GW.h

April

May Junc July August September October November December January February

-ch \I Annual Incremental Gacra t io 347 163

Price Change: -15.71%

Seven Mile Financial Evaluation

VOE HLH Revenues VOE HLH Revenues VOE Dispatchability & Reserve Premiums Dispatchability & Reserve Premiums as a % o f Rwenues 12.58%

Key Assumptions

In-Service March


April

May Junc July August September October November December January Febmary March T o n 1 Annud Incrcmmtal Generation 102

VOE Lwelized Basc Case Price VOE Lwcl izd Sensitivity Pricc

Price Change: -5.71%

Low Hydro Sensitivity Caw: Y( - ~ V O E HLH Revenues I S,Y

I VOE HLH Rwenues VOE Dispatchability & Reserve Premiums Dispatchability & Reserve Premiums as a % of Revenues 18.00

I Generation: . H u v y Load t ight Load GW.h GW.h

April May Junc July August September October November December January February March Total Annual lncrcmcntal Generation 131 70

VOE Lwelized Basc Casc Pricc VOE Levelized Sensitivity Pncc

Price Change: 25.71%


?Curve: Nominal InService March 2004

CORPORATE PERSPECTIVE End of

Summary 5 Yean of 10 Yean 20 Yean Economic of RUUIU Benefits of Benefits of Benefits Life

07/01 12/13 7.223 2053 PV of SVA 53,116 58.020 517.712 D3.676

PV of Proiect Costt 158.453 558.453 $58.453 558.453

I PV of Project Operating Costs S31.830.49 52,797.71 52,735.35 52404 Annualized Unit Cost of Incremental Generation 519.1 8 120 7

Price Curve: Real

PROVINCML PERSPECnVE (excludes dividends) End of

Economic Life

2 0 9 Present Value of Corporate Benefits - 5102.098 58.973.84

S29.095 12.557.29 Present Value of Wata Rentals And Taxes - Present Value of Provincial Benefits $131.194 511,531.13 . -~ -

PV o i Project Costs: Overheads 51.169 51.169 51.169 51.169 PV of Project Cosu: Transmissio 52. 172 %,I90 16.619 58.80 1 PV of Benefits $25.886 547,286 574.470 5102.098 NPV Discounted CF BcncfiUCost Ratio 0.42 0.74 1.12 1.48

Present Value of All Capital 568,423 16,013.93

Net Present Value (to the Province) - 162,771 55.5 17.20

Benefit Cost Ratio 1.92

I PV of SVA 56.168 51 1.602 119.081 S28.520 51.966.41 Present Value of Corporate Benefits I S2.055 5141.69 - 595.875 S6.610.32 Present Value of Wata Rentals And Taxes

PV of Project Cosu 557.232 157,232 557.31 557,232 53,945.97 Present Value of Provinsid Benefits 597.930 56.752.01

CORPORATE PERSPECTIVE End o i

S Yern of 10 Years 20 Y n n Economic Summary of Results Benefits ofklencfio of Benefits Life

07/08 12/13 22/23 2053

PROVINCIAL PERSPECTIVE (excluder dividends) End of

Economic Life

2053

I PV of Project Operating Costs 532, 716.1 1 52.255 69 PV of Project Operating C o w 52.754.07 S 189.89 Annualized Unit Cost of Incremental Generation S22.85 Annualized Unit Con of lncremenul Generation 516.01

PV of Project Costs: Overheads 51.145 51.145 5 l.l45 51.145 578.92 PV of Project Cow: Trnnsmissio 52,129 14,121 16.601 58,978 5619.02 PV of Benefits 525,126 545.659 571,217 595,875 56.610.32 NPV (S35.379) (516,837) 56.239 528,520 S1.%6.41

Discounted CP BenefiVCost b t i o 0.42 0 73 1.10 1.41

Present Value of All Capid 467.354 54,643.91

Net Present Value (to the Province) - 530,575 St. 108 09


SVA Calculation Revenues: Adjusted for the Annual Rate o f Inflation Water Capacity Fee: Adjusted for inflation Variable Water Rentals: Adjusted for inflation Tares &Grants: Adjusted for inflation Site OMA: adjusted for inflation

less Ecanomic depreciation less annual salvage (removal cost) accrual Corporation Capital Taxes add CIA amonization Net Operating profit less Capital charge

SVA

Discount Rae Discounted SVA Cumula~ive discounlcd SVA

Opening Net B m k Value Additions less accumulated depreciation Nct bmk value less contributions in aid add accum. CIA amonization l a s salvage liability Net total inverted capital Capital charge (cost o f capital x prior y r ncl)

Cash Flow Calculation Revenues Water Capacity Fee Adjusted for inflation Variable Water Renals. Adjusled for inflation T u a &Grants. Adjusted for inflation Site OMA: adjusted for inflation I a s Capital expenditures Corporation Capital Taxes less salvage/(ren~oval cost) plus contributions in aid Net Cash Flow

Discount Rate Discminted cash flow Cumulative discounted c u h flow

BeneliI/CosI Ratio (disc.)

..-- Seven Mile Financial Evaluation

CORPORATE PERSPECTIVE

EII~ or 5 Years o r I 0 Vcars of 20 Years o f Econon~ic

& n t s Benclils & m i l s Wcsults to the end or Fiscal Year 07/08 12/13 22/23 2055 PV or SVA 53.1 16 58,020 117.722 $33.676

_P__-_s___

PV of Projecl Costs ' 558.453 158.453 158.453 $58.453 PV or Project Costs: Overheads $1,169 11.169 11.169 $1.169 PV of Projecl Costs: Tr rnm~iss ion 12.172 14,190 16.649 18.8OI

. - . NPV

D~SCOIIII~C~ C F BeneliUCost R b 42 074 112 148

'ROVINCIAL PERSPECTIVE (excludes dividends) End o f

Economic Life

2055 resent Value o f Corporate Bcnefiu 102,098 resent Value o f Water Rentals And Taxes 129.095 resent Value o f Pmvincial Benefits 1131,194

resent Value of A l l Capital 168.423

et Present Value (to the Province) 562,771 P

cnelit Cost Ralio 1 02

DRAFT minal Dollars

. -

Seven Mile Financial Evaluation -

DRAFT Nominal Dollars

SVA Calculation Revenuu: Adjusted Tor the Annual Rate o f Inflation Water Cnpeily Fee. Adjusted for inflalion Variable Water Rentals: Adjusted for inflalion Taxu &Grants Adjusted for inflation Site OMA: adjusted for inflation

less Economic depreciation less annual salvage (rcn~ovsl cost) accrual Corporalion Capital Taxu add CIA antonization Net Operaling profit less Capital charge

Discount Rate Discounted SVA Cuntulalivc discou~tted SVA

Openins Net Bmk Value Additions l u s accumulaad depreciation Net book value less contributions in aid add acwm. CIA amonizadon Iws salvage l iabi l i~y Net Iota1 invcstcd capital Capttsl charge (cost o f capital x prior yr net)

Cash f l ow Calculaliou Rcvenuu Water Capacity Fee Adjusled for inllation Variable Waler Rentals: Adjusled for inflalion T u u &Grants: Adjusted for inflalion Sile OMA: rdjuskd for inflalion less Capital wcpendituru Corporation Capilal Taxu less salvagd(ren~oval cost) plus contributions in aid NCI cash n o w

Discount Rale Discounted cash flow Cumulative discounted cash flow

BenefiUCost Ratio (disc.)

. - Seven Mile Financial Evaluation DEAFT

Nominal Dollars

SVA Calculation Revenues. Adjusted for the Annual Rate o f Inflation Water Capacity Fee: Adjusted for inflation Variable Water Rentals: Adjusted for inflation T u a &Grants: Adjusted for inflation Site OMA: adjusted for inflation

less Economic deprecialion less annual salvage (removal cost) accn~al Corporation Capital Taxer add CIA a~nonilr l ion Net Operating profit less Capital char~e

SVA

Discount Rate Discounted SVA Cu~uulat ivc Jisrountrd SVA

Opening Net Bmk Value Additions less accumulated depreciation N a book value l u s conuiburions i n aid add accum. CIA amonilolion I c u snlvagc liability Net total invested capital Capital charge (cost o f capital x prior yr net)

Cash Flow Calculation Revenues Waar Capacity Fee: Adjusted for inflation Variable Water Rentals: Adjusted for inflation Taxu &Grants: Adjusted for inflation Site OMA: adjusted for inflation less Capital expenditures Corporation Capital T u c r less salvagd(removal cost) plus contributions i n aid Nel Cash Flow

D i s m n t Rate Discounted cuh flow Cumulative discounted cash l low

BcneBUCosI Ralio (disc.)

-- Seven Mile Financial Evaluation DKAFT

Nominal Dollars

SVA Calculation Revenues: Adjusled for llte Annual Ralc of Inflation Water Capacity Fee: Adjusled for inflation Variable Water Rentals: Ad justd for inflalion Tax= &Grants Adjusted for inflation Site OMA: adjusted for inflalion Iws Econon~ic dcprcciaion I s s annual salvage (removal cost) accrual Corporation Capttal Taxa add CIA amortization Net Operating profit less Capital charge

SVA

Discount Rate Diswunled SVA Curnulalive discouuted SVA

Opening Net B w k Value Additions less accumulated depreciation Ncl book value less conlribulions in aid add rccum CIA amortimion less salvage liability Net total invested capital Capiul charge (cost o f captlal x prior yr net)

Cash Flow Calculation Revenues Water Capacity Fee: Adjusted for inflation Variable Water Rentals: Adjusted for inflation Taxes &Grants: Adjusted for inflation Site OhIA. adjusted for inflation less Capital expenditures Corporation Capital Taxes less salva~c/(rcnioval cost) plus cnntributions in aid Net Cash Flow

Diswunt Rate Discounled cmh flow Cu~nulative discounted cash flow

BeueWCosl Ratio (disc.)

.-- Seven Mile Financial Evaluation

- DRAFT

Real D o l l a r s

- -.

Contributions i n aid (CIA)

l ~ e s u l l s l a Ihe eud of F i r 4 Year 07/08 12/13 22/23 2055 I 2055

0 0 0 0 0 0 0 0 0 0 0 0

Ii.".;;".A. .. . - .. . ...- ~ . ... ~. - ~

56,168 51 1.602 519,084 528.520 - - - I Proenl Value of Corporate Benefits 95.875

$29.962 Present Value of Water Rentals And Taxes

CORPORATE PERSPECTIVE End or

S Years or I 0 Years or 20 Years o f Econon~ic kns f i t s knc f i t r Ucrtefils Lire

IPV of ~ r o j c c t ~ o r t s $57.232 557.232 557.232 $57.232 lpresent Value or Provincial Bellefits $125.837

PROVINCIAL PERSPECTIVE (excludes dividends) End or

Econonlic ire

I PVo f ProjeclCostr: Overheads $1,145 51.145 $1.145 $1.145 PV of Projecl Cools: Tranm~ission $2,129 $4,12 1 $6.601 58.978 I Present Value o f A l l Capital 567,354 PV or Benelils $25.126 $45.659 $71.217 595.875 NPV ) (~35.179) (516.837) 56.239 $28,520 Net Present Value (to the Province) $58.482 - - Uiscourled CF &~~efi t /Cort Ratio 0542 0.73 1.10 1.41 Benefit Cost Ratio 1.87

Year

SVA Cdculation Revenues: Adjusled for the Annual Rate o f Inflation Water Capacity Fee: Adjusted for inflalion Vnriable Water Rentals: Adjusted for inttation Taxes &Granu: Adjusted for inflation Site OMA' adjusted for inflation less Economic depreciation less annual salvage (removal cost) accrual corporation Capital Taxes add CIA amortization Net Operating profit less Capital charge

SVA Discount Rate D i s m t e d SVA Cumulative discounled SVA

Opening Net Book Value Additions less accumulated depreciation Net book value less contributions i n aid add accum CIA amortization less salvage liability Net total invested capital Capiul charge (cost o f capital x prior yr net)

Cash Flow Calculation Revenues Water Capacity Fee: Adjusted for inflation Variable Water Rentals. Adjusted for inflation Taxes &Grants: Adjusted for inflation Site OMA: adjusted for inflation less Capital expenditures Corporation Capital Taxes less salvagd(removal cost) plus wntributiona ill r i d Net Cash Now

Disuwnl Rate Disuwntcd cash flow Cumulative discounted cash flow

o o o o o o o o o (I o o o n n 7,042 7,UJ4 7,048

0.49 0.46 0.43 0 (306) (7.599) (24.768) (25.503) 6.122 6.051 5.561 5,023 4.250 3,926 3.681 3.450 3.235 3.033 0 (306) (7.865) (32.633) (58.136) (52.014) (45,963) (40.402) ( 3 5 . 3 7 9 ) ' ) (27.203) (23.522) (20.072) (16.837) (13.805) -

7M U4 In s e ~ c e 2004 as of November 23 2000

-"- Seven Mile Financial E v a l u a t i o n

Contributions i n aid (CIA)

- DRAFT

R e a l Dollars

0 0 0

SVA Calcul8lion Revenues: Adjusted for the Annual Rate of Inflation Water Capacity Fee: Adjusted for inflation Variable Water Rentals: Adjusted for inflation Tues &Grants: Adjusted for inflation Site OMA: adjusted for inflation

less Economic depreciation less annual salvage (removal wst) accrual Corporation Capital Taxes add CIA amortization Net Operating profit l a s Capital elwge

SV A

Discount Rate 1)ircounled SVA Cun~ulrt ive discounlrd SVA

Opening Net Book Value Additions less rown~ulated depreciation Net book value less wntributions i n aid add accum CIA amonization less salvye liability Net total invested capital Capital charge (cost o f capital x prior yr net)

Cash Flow Cdculal ion Revenues Water Capacity Fee. Adjusted for inflation Variable Water Rentals: Adjusted for innation Taxes k G r m u : Adjusted for inflation S ia OMA: adjusted for inflation less Capital expend~tures Corporatio~~ Capital Taxer less salva&d(re~~~avrl cost) plus con~ributiuns in aid N r t Cash Flow

Diswunl Rate Discounted cash flow Cumulative discounted cash flow

-- Seven Mile Financial E v a l u a t i o n

- DRAFT

R e a l D o l l a r s

Contributions in aid (CIA)

Year 32 33 34 35 36 37 38 39 40 4 I 42 43 44 45 46 47 48 49

SVA C8lcul8lion Revellua. Adjusted for the Annual Rate o f Inflation \\'ater Capacity Fee: Adjusled for inflation Variable Water Renlnls: Adjusted for inflation Taxu &Granu: Adjusted for inflation Site OMA: adjusted for inflation

less Econotnic depreciation less mnual salvage (ren~oval wst) accrual Corporalion Capital Taxes add CIA amoniulion Net Operating profit less Capital charge

SVA Discount Rate Discounled SVA Cun1ul8live discnunled SVA

Openins Nel Bmk Value Additions less accumulacd dep'reciation Net book value less contributions in aid add accunl CIA amortization less salvage liability Net total invested capital Capital charye (wst o f capital x prior yr net)

Cash Flow Calcul8lion Revenues Water Capacily Fee: Adjusted for inflation Variable Water Renlals: Adjusted for inflation Taxa &eranu: Adjusted for inflation Site OMA. adjuslcd for inflation less Capital cxpcndilures Corporation Capital Taxa l u r salvawcMrcn~oval cost) - . plus contributions in aid Net Cash Plow

Discount Rate Diswunled cash flow Cumulative discounted cash flow

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 7.101 7,104 7.108 7.112 7,116 7,120 7,124 7,129 7.133 7.138 7,143 7,148 7.154 7,159 7,165 7,171 7,177 7.184

0.13 0.12 0.11 0.10 0 0.05 0.05 0 04 0.04 891 836 784 735 689 646 606 568 533 500 469 440 412 387 363 340 319 299

18.352 19.188 19.972 20.707 21.396 22.042 22,648 23.216 23.749 24.249 24.718 ' 25,158 25.570 25.957 26.320 26.660 26.979 27,279 7M U4 In service 2004 as of November 23 2000

Contributions in aid (CIA)

-- Seven Mile Financial Evaluation DEAFT

Real Dollars

50151 51/52 52/53 53/54 54/55 55/56 56157 57/58 58/59 59160 60161 61162 62/63 63/64 64/15 Year 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64

SVA Calculation Revenues: Adjusted for the Annual Rate o f Inflation \Vater Capacity Fec: Adjusted for inflation Variable Water Rentals: Adjusted for inllation T a m &Granu: Adjusted for inflation Site OMA: adjusted for inflation

less Economic depreciation less annual salvage (removal cost) accmal Corporation Capital Taxer add CIA amortization Net Operating profit less Capital charge

SVA

Discount Rate Discounted SVA Cumulrtivc dircouutcd SVA

Opening Net Book Value Additions lus accumulated depreciation N a bmk value less contributions in aid add accum. CIA amortization l u r salvage liability Net total inverted capital Capital charge (cost o f capital x prior yr net)

Cash Flow Calculation Revenua Water Capacity Fee: Adjusted for inflation Variable Watu Rentals: Adjusted for inflation Taxa &Crane: Adjusted for inflation Site OMA: adjusted for inflation less Capital expenditures Corporation Capital Taxes less salvage/(removal cost) plus contributions in aid Net C u b Flow

Discount Rate Discounted cash flow Cumulative discounted cash flow

281 264 247 232 218 (0) 0 0 0 0 0 0 0 0 0

7M U4 In seme 2004 as of November 23 2000

8 9 10 1 1

3 , 1

18 1 March HLH 54.27 166.61 92.29 60.10 54.19 56.31 57.14 53.57 51.28 52.32 51.16 19 1 LLH 53.70 180.90 91.43 59.06 53.09 54.64 54.72 53.13 49.50 51.01 49.88

, January HLH 51.79 178.82 88.13' 59.16 52.38 54.15 53.47 52.14 48.87 50.45 49.33 LLH 48.30 181.17 82.161 51.44' 43.67' 45.82 47.33 50.07 42.86 46.15 45.13

Average

I L

13 14 15 16 + 7

20 1 Average I

7 4 I I

February HLH 53 82 171 01 91 57 59 56 53 97 56 30 55 89 53 45 49 95 51 80 50 65 LLH 53 82 181 04 91 61 59 53 53 97 5630 55 83 53 15 49 95 51 70 50 56

Average

5269 125 22 89 64 55 87 51 05 5370 5446 5245 48 33 5091 49 78

- A2 11 1OA 08 71 61 46 92 A2 51 43 79 A4 65 45 05 42 08 43 37 4240

-- A v e r a g e

L I

28 May HLH 4470 106 91 75 98 48 35 44 33 44 54 45 08 4570 41 64 42 69 41 75 29 LLH 28 71 68.76 48 93 33.49 31 51 33.20 32 82 3447 34 57 34 43' 33 67 30 Average I

32 33 34 35 36

June - HLH 4864 112 34 82 82 53 36 49 46 49 68 48 57 48 80 46 96 46 35 45 32

LLH -- 31 07 71 94 52 eo; 36 lo 32 80 33 02 34 35 33 go 33 46 33 99 33 24 Average

I -- I 37 38 39

I !

164.92 126.24 91.62, 59.63' 54.99 56.79 56.04 53.06 51.29 51.55 50.41 54 1 LLH 156.18 122.51: 89.10' 58.37. 53.16 54.89 54.01 49.08 47.87 49.11, 48.02

- July HLH 53 59 125 51 9042 5843 52 32 55 34 56 18 5274 49 01 50 65 49 52

LLH 45 82 108 59 7733 49 59 4477 45 39 46 48 45 14 41 58 41 57 40 65 -0 ] Average I

41 1 I - I 42 !

-- -- - - -- 171.62 12G5 92.68; 61.08: 55.20 57.09 56.25 53.13

LLH 144.52 125.76 90.62, 59.16' 53.40 55.50 55.36 52.28 49.29 51.02 49.89

43 44 45 46 .-,

A v e r a g e I

August HLH -- 5370 12579 9063; 5879 5311 5769 6306 5339 4932 5345 5227 LLH 48 30 112 27 81 53 50 91 45 61 46 26 46 78 47 05 41 97 43 07, 42 12

Average 8

Average 182326 311337 202121 131329 118547 123115 123949 118385 111789 115236, 112683

14684 92

63 64

62-- December HLH 170.74 132.47 99.00' 64.17: 56.76 59.10 58.24 53.59 54.29 55.36, 54.13

' LLH -- 144.44 111.70 80.66' 54.46' 47.95 48.24 50.75 43.44 44.89 46.10: 45.08

CALCULATION OF FORWARD PRICES: NOMlNAL

Fiscal Yea Fiscal Year Investment Cumlative Beginning Endlng Year I 0 I 2000 I 0

HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH

Inflation 100 100

LLH 142.82 19 2019 19 HLH 145.68

LLH HLH U H HLH LLH HLH LLH HLH LLH HLIi LLH HLH LLH HLH LLH HLH LLH 17069

28 '2026 26 HLH 174.10 LLH 174.10

29 2029 29 HLH 177.58 LLH 177.56

30 2030 30 HLH 181.14 LLH 161.14

31 2031 31 HLH 184.76 LLH 164.76

32 2032 32 HLH 168.45

Inflation Factor

2.00% 2 00% 2 00% 2 00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2 00% 2.00% 2.00% 2 00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2 00% 2 00% 2.00% 2.00% 2.00% 2.00% 2.00% 2 00%' ' 2 00% 2.00% 2.00% 2.00% 2.009 2 00% 2 00% 2.001 2.00% 2 00% 2.00% 2.00% 2 00% 2 00% 2.00% 2.00% 2.00% 2 00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2 00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00%

April UMWh

1 48.98 $39.67

$116.41 $ 96 07 $63.33 $67.47 $51.94 544.21 $47.46 $40.06 $49.92 $41.26 $50.63 $42 07 $48.76 $42.45 $44.93 $39.65 $47 33 $40.86 $46.27 $41.66 $49.24 $42.51 $50.22 $43.36 $51 23 $44.23 $52.25 $45.11 $53.30 $46.02 $54.38 $46 94 $55.45 $47.88 $56 56 $48.83 $57.69 $49.61 $58.64 $50.61 $60.02 $51.62 $61.22 $52.88 $62.45 $53.92 $63.69 $54.99 $64.97 $56.09 S68.27 $57.22 $67.59 $58.36 $68.95 $ 59.53 $70.32 $60.72 $71.73 $61.93 $73.17

May June UMWh UMWh

Seven

July SlMWh

150.05 543.37

$1'17.21 $102.76

104.44 173.19 954.58 W6.94 $49.42 $42 36 $51.66 $42 96 $52.47 $49.35 $49.25 $42.72 $45 77 $59.35 147.29 VJ9.04 $48.24 $40.13 $49.21 540.93 $50.19 $41.75 $51.19 $42.58 SS2.22 $43.44 153.26 w a i $54.33 $45.19 $55.41 $46.10 St6.62 $47.02 $57.65 147.96 $58.61 $48.92 $59.98 549.89 $61.16 $50.89 $62.40 551.81 $63.65 $52.95 184.93 $54.01 $66.22 $55.09 $67.55 $56.19 566.90 $57.31 570.28 $58.46 $71.68 159.63 273.12

I Mile Financial Evaluatl

August September SIMWh SIMWh

on

October SIMWh

1152.97 $146.99 1117.10 $115.30 $64.96 183.86 155.31 $54.93 $51.01 $50.03 152.68 $51.66 551.98 $50.83 $49.21 $46 19 $47.57 $45.06 $47.62 $46.22 $48.77 547.15 $49.75 $48.09 $50.75 $49.05 $51 76 $50.03 $52.80 $51.03 153.85 $52.05 $54.93 553.10 $58.03 554.16 157.15 $55.24 $58.29 556.35 $59.46 $57.47 $60.85 $58.62 561.88 $59 79 $63.10 $60.99 $64.36 $62.21 $65.64 $63.45 $66.96 164.72 566.30 $66.02 $69.66 $67.34 $71.06 $68.66 $72.46 $70.06 $73.93

November SlMWh

$157.36 $134 81 $1 16.67 $117.31 $64.99 $84.53 $58.02 $55.18 $50.62 $49 81 $52.36 $51.77 $51.59 $51.64 $48.72 $48.77 $46.62 $45.97 $48.22 $47.59 $49.18 $46.54 $50.17 $49.51 551.17 $50.50 $52.19 $51.51 $53 24 $52.54 $54.30 $53.59 $55.39 $54.67 $58.49 $55.76 $57.62 $56.87 $56.78 $58.01 $59.95 $59.17 $61.15 $60.36 $62.37 $61.56 $63.62 $62.79 $64.89 $64.05 566.19 $65.33 $67.52 $66.64 566.87 $67.97 570.24 $69.33 $71.65 $70.72 273.08 572.13 574.54

December SIMWh

1156 22 $134.59 $121.21 $ 104.06 $90.56 $75.15 $58.71 550.74 $51.93 $44.87 $54.08 544.95 $53.28 $47.28 $49.03 140.48 $49 67 $41 62 $50.65 $42.95 $51.66 $43.81 $52.70 $44.69 $53.75 $45.58 $54.63 $46.49 $55.92 547.42 $57.04 $48.37 $58.16 $49.34 $59.35 $50.32 $60.53 $5.1.33 $61.74 $52.35 $8.2.98 $5'3.40 $64.24 $54.47 $65.52 555.56 560.83 $56.67 $60.17 $57.81 $60.53 $56.96 $70.92 $60.14 $72.34 $61.35 $73.79 $62.57 $75.26 $63.62 $70.77 $65.10 $76.30

Calculate Revenue Price ~ k e s

UMWh SlMWh UMWh

$71.03 $70.44 $72.45 7M W h service 2004 as 01 November 23 2WO

- Calculate Revenue Price Curves

-

Fiscal Yea Fiscal Year Investment Year

0

33

34

35

36

37

38

39

40

41

42

43

44

45

48

47

48

49

50

51

52

53

54

55

56

57

58

59

60

61

Cumlative innation

100 100

LLH 188.45 HLH 192.22

LLH 192 22

HLH 196.07 LLH 196.07 HLH 199.99 LLH 199 99 HLH 203.99 LLH 203 99 HLH 208 07 LLH 208.07 HLH 212.23 LLH 21223 HLH 216.47 LLH 21847 HLH 22080 LLH 22080 HLH 225 22 LLH 225.22 HLH 229.72 LLH 229 72 HLH 234.32 LLH 234.32 HLH 239.01 LLH 239.01 HLH 243.79 LLH 243.79 HLH 248.68 LLH 248.66 HLH 25383 LLH 253.63 HLH 258.71 LLH 258.71 HLH 263.88 LLH 283.88 HLH 289.18 LLH 269 18 HLH 274 54 LLH 274.54 HLH 28003 LLH 280.03 HLH 285.63 LLH 285.63 HLH 291.35 LLH 291.35 HLH 297.17 LLH 297.17 HLH 303.12 LLH 303.12 HLH 309.18 LLH 309.18 HLH 315.36 LLH 315.36 HLH 321.87 LLH 321.87 HLH 328.10 LLH 328.10 HLH 334.67

Inflation Factor

2 00% 2 00%

2.W%

2.00% 2.00% 2 00% 2 00% 2 00% 2 00% 2 00% 2.00% 2 00% 2.00% 2.00% 2 00% 2 00% 2.00% 2.00% 2 00% 2 00% 2.00% 2.00% 2 00% 2 00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2 00%" 2.00% 2.00% 2.00% 2.00% 2.09% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2 00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00%

April WMWh

$63 17 $74 63

$64.43

$78.12 565.72 577.64 $67.04 579.20 $68.38 $60 78 $89.75 $82.40 $71.14 584.04 $72.58 $85.72 $74.01 $87.44 $75.49 $89 19 $77.00 $90 97 $78 54 192.79 $80.12 $94.65 $81.72 $96.54 $83.35 $98.47 $85.02

2100.44 $66.72

$ 102.45 188.45

$104.50 $90.22

$108.59 $92.03

$108.72 $93.87

1110.89 995.75

$113.11 $97.88

$115.37 $99.81

$117.68 S101.81 5120.04 5103.84 $122.44 5105.71 $124.88 $107.83 $127.38 5109.98 H29.93

May June July August September October November December January February March SlMWh SlMWh SlMWh SlMWh SlMWh $/MWh SlMWh SIMWh $lMWh SIMWh, 5IMWh

.-

Seven Mlle Flnanclal Evaluation -

Cakulate Revenue Price Curves

Fiscal Year Fiscal Year Bopinning Endinp r 1999 I 2000 I

HLti LLH HLH LLti HLH LLH HLH LLH HLH LLH HLH LLH HLn LLH HLn LLH HLH LLn HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLH HLH LLn HLH LLH HLH LLH HLn LLH HLH LLH HLH LLH HLH LLn HLH LLH HLH LLn HLH LLH HLH LLH HLH LLH HLH LLH HLH

1 2 3 4 5 8

In-Sewic In-Ssrvlc April May June July August eptembcr Year

0 0 0 0 0 0 0 0 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1

7 8 9

October November December

Nominal Revenues

12

Marsh Annual Dispatchability ($000) ($000)

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Conversion to Real Revenues

Inflation

Factor Annual (SOOO~

100 0.00% 0 100 0.00% 0 102 2.00% 0 102 2.00% 0 104 2.00% 0 104 2.00% 0 106 2.00% 0 106 2.00% 0 108 2.00% 0 108 2.00% 0 110 2.00% 8150.899 110 2.00% 2922.554 113 2.00% 8107.259 113 2 00% 2942.747 115 2.00% 7919.523 115 2.00% 2976.01 117 2.00% 7713.266 117 2.00% 2906.381 120 2.00% 7097.051 120 2.00% 2808028 122 2.00% 7040.344 122 2.00% 2767.353 124 2.00% 7040.344 124 2.00% 2767.353 127 2.00% 7040.344 127 2.00% 2767.353 129 2.00% 7040.344 129 2.00% 2767.353 132 2.00% 7040.344 132 2.00% 2767.353 135 2.00% 7040.344 135 2.00% 2767.353 137 2.00% 7040.344 137 2.00% 2767.353 140 2.00% 7040.344 140 2.00% 2767.353 143 2.00% 7040.344 143 2.00% 2787.353 146 2.00% 7040.344 148 2.00% 2767.353 149 2.00% 7040.344 149 2.00% 2767.353 152 2.00% 7040.344 152 2.00% 2767.353 155 2.00% 7040.344 155 2.00% 2767.353 156 2.00% 7040.344 158 2.00% 2767.353 181 2.00% 7040.344 161 2.00% 2767.353 164 2.00% 7040.344 164 2.00% 2767.353 167 2.00% 7040.344 187 2.00% 2767.353 171 2.00% 7040.344 171 2.00% 2767.353 174 2.00% 7040.344 174 2 00% 2767.353 178 2.00% 7040 344 178 2.00% 2767.353 181 2 00% 7040.344 181 2.00% 2767.353 185 2.00% 7040.344

Seven Mile Financial ~ ia luat ion Calculate Revenue Price &es

Fiscal Year Fiscal Year Beginning Ending

1 1999 1 2000 1 In-Servic

Year

LLH 1 HLH 1

LLH 1

HLH 1 LLH 1 HLH 1 LLH 1 HLH 1 LLH 1 HLH 1 LLH 1 HLH 1 LLH 1 HLH 1 LLH 1 HLH 1 LLH 1 HLH 1 LLn 1 HLH 1 LLH 1 HLH 1 U H 1 HLH 1 LLH 1 HLH 1 LLH 1 HLH 1 LLH 1 HLH 1 LLH 1 HLH 1 LLH 1 HLH 1 LLH 1 HLH 1 LLH 1 HLH 1 LLH 1 HLn 1 LLH 1 HLH 1 LLH 1 HLH 1 LLH 1 HLH 1 LLH 1 HLH 0 LLH 0 HLH 0 LLH 0 HLH 0 LLH 0 HLH 0 LLH 0 HLH 0 LLH 0 HLH 0

In-Servic Month

April May June July Aupust IlOOO) ISOOO) ($ooo) ($000) ($0001

0 0 0 0 0 0 0 0 0 0 0 2286.663 2340.093 608.2138 0

1492.572 471005 5392.195 1342.426 78.82534

0 231222 2388.895 820378 0

1522.423 4804.251 5500.039 1369.274 80.19784 0 2358.465 2434633 632.7856 0

1552 871 4900.336 5610.04 1396.66 81.8018 0 2405.634 2483.325 645.4413 0

1583.929 4998.342 5722.241 1424.593 83.43784 0 2453.747 2532.992 658.350

1615608 5098.309 5836.685 1453.085 85.10659 5 0 2502.822 2583.651 671.5171 1647.92 5200.275 5953.419 1482.147 66.80872

0 2552.878 2635.325 684.9475 0 1680.878 5304.281 6072.487 1511.79 88.5449

0 2603.936 2688.031 6986464 0 1714.496 5410.366 6193.937 1542.025 90.3158

0 2656.014 2741.792 712.6194 0 1748.786 5518.574 6317.816 1572.866 92.12211

0 2709.135 2796.627 726.8718 0 1783.761 5828.945 6444.172 1604.323 93.66455

0 2763.317 2852.56 741.4092 0 1819.436 5741.524 6573.056 1636 41 95.84385

0 2818584 2909.611 7562374 0 1855.825 5856355 6704.517 1669.138 97.78072

0 2874.956 2967.803 771.3621 0 1892.942 5973482 6838.607 1702.521 99.71594

0 2932.455 3027.18 786.7894 0 1930.801 6092 951 8975.379 1736.571 101.7103

0 2991.104 3087.703 802.5252 0 1969.417 6214.81 7114.887 1771.302 103.7445

0 3050.926 3149.457 818.5757 0 2008.805 8339.107 7257.185 1806.728 105.8194

0 3111.944 3212.446 834.9472 0 2048 981 db5.889 7402.328 1842.863 107.9357

0 3174.183 3276.695 851.6461 0 2089 961 6595.206 7550.375 1879.72 110.0945

0 3237.667 3342.229 668679 0 2131.76 6727.111 7701.382 1917.315 112.2963

0 3302.42 3409.073 886.0526 0 2174.395 6861.653 7855.41 1955.661 114.5423

0 3368.469 3477.255 503.7737 0 2217.883 6998.886 8012.518 1994.774 118.8331

0 3435.838 3546.8 921.8491 0 2262.241 7138864 8172.769 2034.67 119.1698

0 3504.555 3617.736 940.2861 0 2307.485 7281.641 8336.224 2075.363 121.5532

0 3574.646 3690.091 959.0918 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

eptsrnber ($000)

0 0 0 0

0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

October No\ (SOW)

0 0 0 0

0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

rember December (SOOO) ($000)

0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

January (SOOO)

0 0 0 0

0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

February March Annual Dispatchability ($000) ($000) ($0001

0 0 0 0 0 0 0 0 0 0 5215.189 403.18758 0 517.3036 13533.17 1046.2528

0 0 5319.493 41125133 0 527.6497 13803.83 1067.1779 0 0 5425.883 419.47636 0 538.2026 14079.91 1088.5214 0 0 5534.401 427.86588 0 548.9667 14361.51 11102918 0 0 5645.089 436.4232 0 559.946 14648.74 1132.4977 0 0 5757.99 445.15167 0 571.145 14941.71 1155.1476 0 0 5873 15 454.0547 0 582 5678 15240.55 1176.2M6 0 0 5990.613 463.13579 0 594.2192 15545.36 1201.8156 0 0 6110.426 472.39851 0 606.1036 15856.27 1225.8519 0 0 6232.634 481.84648 0 618.2257 16173.39 +250.3689 0 0 6357.287 491.48341 0 630.5902 16496.86 1275.3763 0 0 6484.432 501.31308 0 643.202 16826.8 1300.8839 0 0 6614 121 511.33934 0 656.066 17163.33 1326.9015 0 0 6746.403 521.56812 0 669.1873 17506.6 1353.4396 0 0 6881.332 531.99745 0 682.5711 17856.73 1380.5083 0 0 7018.958 542.6374 0 696.2225 18213.87 1408.1165 0 0 7159.337 553.49014 0 710.147 18578.14 1436.2809 0 0 7302.524 564.55995 0 724.3499 18949.71 1465.0065 0 0 7448.575 575.85115 0 738.8369 19328.7 1494.3066 0 0 7597.548 587.36817 0 753.6136 19715.27 1524.1928 0 0 7749.497 599.11553 0 768.6859 20108.58 1554.6766 0 0 7904.487 611.09784 0 784.0596 20511.77 1585.7702 0 0 8062.577 823.3198 0 '799.7408 20922.01 1617.4856 0 0 8223.828 635.7862 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Factor Annual ($0001

100 0.00% 0 100 0.00% 0 188 2.00% 2787.353 192 2 00% 7040.344

192 2.00% 2767.353 196 2.00% 7040.344 196 2.00% 2767.353 200 2.00% 7040.344 200 2.00% 2787.353 204 2.00% 7040.344 204 2.00% 2767.353 208 2.00% 7040.344 208 2.00% 2767.353 212 2.00% 7040 344 212 2.00% 2767.353 218 2.00% 7040.344 216 2.00% 2767.353 221 2.00% 7040.344 221 2.00% 2767.353 225 2.00% 7040.344 225 2.00% 2767.353 230 2.00% 7040.344 230 2.00% 2767.353 234 2.00% 7040.344 234 2.00% 2767.353 239 2.00% 7040.344 239 2.00% 2767.353 244 2.00% 7040.344 244 2.00% 2767.353 249 2.00% 7040.344 249 2.00% 2767.353 254 2.00% 7040.344 254 2.00% 2767.353 259 2.00% 7040.344 259 2 00% 2767.353 264 2.00% 7040.344 264 2.00% 2767.353 269 2.00% 7040.344 269 2.00% 2767.353 275 2.00% 7040.344 275 2.00% 2787.353 280 2.00% 7040.344 280 2.00% 2767.353 286 2.00% 7040.344 2Bg 2.00% 2767.353 291 2.00% 7040.344 291 2.00% 2787.353 297 2.00% 7040.344 297 2.00% 2767.353 303 2.00% 0 303 2.00% 0 309 2.00% 0 308 2.00% 0 315 2.00% 0 315 2.00% 0 322 2.00% 0 322 2.00% 0 328 2.00% 0 328 2.00% 0 335 2.00% 0

7M U4 In smvica 2W4 er of November 23 2000 200101-09

21


%ter the Alternative Case # t o be Reviewed in this Spreadsheet: r j In-Service April 2011 1

Case # In-Service April 201 1 0 High Market Price Case 1 Low Market Price Case 2 High Hydro -Low PriceCase 3 Low Hydro - High Price Case 4


Annual rate of Set Inflation & De-escalation: Revenue Annual rate o f Net Inflation & De-escalation: Cost of Annual rate of Net Inflation d De-escalation: OMA Annual rate o f Net Inflation & De-escalation Capital

Construction begins in Fiscal Year Ending March In-Service Month ( April is I. March is 12) In-Service Year Fiscal Year Ending March Economic Life of Asset First Year o f Benefits End of Useful Life: Fiscal Year Ending March: Discount Rate' Real

Discount Rate: Nominal

USS Exchange Rate

Benefit Related Assumptions

VOE HLH Annualized Revenue Benefits: REAL S VOE LLH Annualized Revenue Benefits: REAL S VOE Annualized Dispatchability Premium. REAL S Dispatchability Premiums as a % of elecvicity revenues

Change in Base Case Levelized Price Per W h

Generation Impacts for theFoward Price Curve: - - Heaw Load Net HLH Light Load Net LLH

GW.h Regional

April

- May - - June

July pus1 >tember

dctober November December January February March Total Annual Incremental Ceoeratio


Project Cost Assumptions

Water Capacity Fee Water Rmtal Rate YMWh

Facility OMA Taxes & Grants Annual Proxy used in VOE for Corporation Capital Taxa Incremental Annual OMA Expenditures Overhead charged to capital Available Capacity ClFT Costs to LM. Transmission Capital Rate on Capacity Revenue Grant Taxes in Lieu and Property Tax Rate Corporation Capital Tax Combined tax rate Capital tinanced through debt (for CCT)

Generation Capital Cash F l o w Real S

Write-Down


w m v I v VARIABLES k case: uo

VOE HLH Revenues VOE HLH Revenues VOE Dispatchabiliry & Resewe Premiums Dispatchability dr Reserve Prem~ums as a % of Revenues 12.45% Generation: Heavy Load Light Lord

CW.h GW.h

April

May June July August September October November December January February March Total Annud In, iremental G m r a t i o 102

VOE Lwelizcd Bare Case Price VOE L o e l i d Sensitivity Price -1 Price Change: 0 CQ%

!Y le

July August September October November December January February March Total Annual Incremental G n e r


VOE Levelized Bare Care Price VOE Levelized Sensitivity Price

Price Change: 5.71%

VOE HLH Revenues VOE HLH Revenua VOE Dispatchability & R e s w e Premiums Dispatchability & Reserve Premiums as a % of Revenues Generation:

Heavy Load t i g h t Load CW.h GW.h

April

May June July August September October November December January February

sch la1 Annual Incremental Generatio 347 163

VOE Levelired Bare Case Price VOE Levelized Sensitivity Price B I Price Change: -15.71%

Key Assumptions

In-Service April


June July August September October November December January February March Total Annual Incremental Cenention 200 102

VOE Levelized Base Case Price VOE Levelized Sensitivity Price -1 I Price Change: -5.71%

VOE HLH Revenua VOE HLH Revenues 51.94 VOE Dispatchability & Reserve Premiums Dispatchability &Reserve Premiums ar a % of Revenues 1 8 . W

I Generation: Heavy Load t ight Load

GW.h GW.h

April

May June July August September October November December January February March Total Annual lncremenlal

0 0 0 1 2 0

1 0 0 0 0 1

G n e n t i o n 131 70


--ter the

I

Alternative Case # to be Reviewed i n th is Spreadsheet: 1-1 In-Service April 2011

Case # In-Service Apr1l2011 0 High Market Price Case 1 Low Market Price Case 2 High Hydro -Low Price Case 3 Low Hydra - High Price Case 4


Annual rate o f Net lnflation & De-escalation: Rwcnue Annual rate o f Net Inflation % De-escalation: Cost o f Annual rate of Net Inflation & De-escalation: OMA Annual rate of Net lnflation &De-escalation: Capital

Constroction begins in Fiscal Year Ending March In-ServiceMonth ( April is 1. March is 12) In-Service Year: Fiscal Year Ending March. Economic Life of Asset First Year of Benefits End of Useful Life: Fiscal Year Endiny March: Discount Rate: Real

Discount Rate. Nominal

USS Exchange Rate

VOE HLH Annualized Rwenue Benefits: REAL S VOE LLH Annualized Revenue Benefits: REAL 5 VOE Annualized Dispatchability Premium: REAL S Dispatchability Premiums as a % of electricity rwmues

Change is Base Case Levelired Price Per M W h

Generation Impacts lor the Fomrrd Price Curve: Heavy Load Net H L H l i g h t Load Net L L H

GW.h Regional GW.h Regional

April May June luly

wst [ember

dctober November December January February March Total Annual Incremental G ~ r r l i o


Project Cost Assumptions

Water Capacity Fee Water Rental Rate YMWh

Facility OMA Taxes & Grants Annual Proxy used in VOE for Corporation Capital Taxes Incremental Annual OMA Expenditures Overhead charged to capital Available Capacity ClFT Costs to LM: Transmission Capital Rate on Capacity Revenue Grant. Taxes in Lieu and Property Tax Rate Corporation Capital Tax Combined tax rate Capital financed through debt (for CCT)

Generation Capital Cash Flows: Real S

Write-Down

Summary of Financial ms~ns 201 1 in servic. wim sept p r i m 20014149


YSlTlVlM VARIABLES

i Caw: #O 1

Key Assumptions

Indervice April

VOE HLH Revenues VOE HLH Rwenua VOE Dispatchability & Reserve Premiums Dispatchability & Reserve Premiums as a % of Revenues

IG"eration: Heavy Load t i g h t Load I

April May June July august September October November December January February March Told Annual In(

VOE Lcvclized Base Case Price VOE Levelized Sensitivity P"ce -1 Price Change: 0 GQ%

High Price Sensitivity C u e : 111

I VOE HLH Rwenues VOE HLH Revenues VOE Dispatchability & Reserve Premiums

--

l ~ i s ~ a t c h a b i l i t ~ & Reserve Premiums as a % of Revenues 12 32

Heavy Lord Light Load GW.h CW.h

I ,*"I

: ne

July August September October Xovember December Jlnuary February March Total Annual Incremental Generatio 200 102

VOE Lwelired Base Casc Price VOE Levelizcd Se,vity P r i a

Price Change: 5.71%

VOE Dispatchability & Reserve Premiums Dispatchability & R e s m e Premiums as a % of Rwenues Generation: 1 . April !day June July August September Ocrnbcr November December January -2bruaty

)rch ~ t a l Annual In#


I 29 1 0 :remental Generatio 347 163

VOE Levelized Base Caw Pricc VOE Lwelizcd Sensitivity Price -1

l ~ r i c e Chmgc: -15.71%

Low Price Sensitivity Caw: #1 VOE HLH Rwenues VOE HLH Revenues

I VOE Dirpatchability & Reserve Prcmiumr Dispatchability & Reswvc Premiums as a % of Revenues 12.58%

Heavy Load Light Load CW.h GW.h

April

May June July August September October November December January February March Total Annual IncrcmenUl Generation 200 102

VOE Lwelized Base Casc Price l o e v e i z e d e i t i v i r i c e

I P r i n Change: -5.71%

Low Hydro Sensitivity Casc: 114

VOE HLH Revenues VOE HLH Revenues S1.94 VOE Dispatchability & Reserve Premiums Dispatchability & Reserve Premiums as a % of Revenus 18 W' Gneration: .


April

May June July August September October November Ddember January February Mdrch Total Annual Incrementai Cencradon 131 70

I VOE Levclizcd Base Case Price VOE Levclized Sensitivity Price

Price Change: 25.71% Summary of Finanu


Summary 01 Financial results 201 1 in sewice with sapt pnces 2W101-09


!curve: Nominal In-Service April 2011

PV of SVA (514.264) (510,885) (59.507) 55,593 Present Value of Corporate Benefits 553.272 55,663.44 I - 518.045 51.579.62 Present Value of Water Rentals And Taxes -

PV of Project Costs 541.036 541.036 541.036 541.036 Present Value of Provincial Benefits 571.317 56.243 06

CORPOWTE PERSPECTIVE End or

Summary 5 Yean of I0 Years 20 Yean Economic or Results Benefits of Bcnefits or Benefits Lire

15/16 20RI 30Dl 2061

PROVINCUL PERSPECnVE (excluder dividends) End or

Economic Li k

2053

PV of Project Costs: Overheads 5821 5821 S821 $821 PV or Project Costs: Transmissio $2,050 53,221 41-63? 55,822 PV of Benefits 57.037 520,050 536.672 553,272 NPV Discounted CF &nefit/Cost Ratio 0.16 0.44 0 5; 1.07

Price Curve: Real

Present Value of All Capital 547.679 Y.173.79

Net Present Value (to the Province) - 523.638 52.069.27


I CORPORATE PERSPECTIVE

End of S Yean of 10 Yean 20 Y u n Economic

S u m m a 7 of Resdts Eknefits of Bencfis of Benefits tih

PV of SVA (510.242) (513.928) (57.781)

PV of Project Operating Costs S30.019.99 52,627.94 Annualized Unit Cost or Incremental Gneration 122.52

PV of Project Costs 56,258 540.367 340,367 540,567 PV or Project Costs: Overheads 5125 5807 SS07 5807 PV of Project Costs: Trmsminio 10 51.117 53.597 56,084 PV of Benefits (515.021) 67.9281 517.563 543.335

511.975 35 S1.048.32 517.29

PROVMCIAL PERSPECTIVE (excluder dividends) End of

Economic Life

2053 Present Value of Corporate Benefits a.061 -

S43.335 Present Value of Water Rentals And Taxes Present Value of Provincial Benefits S45.396

value O ~ U I capital 547.259

I Net Present Value (to the Province) (11.862) - Benefit Cost Ratio 0.96

PV of Project Operating Costs S:l.OSB 01 S?.ltl 49 Annualized Unit Cost of Incremental G n e n t i o n 5 17 71

PV of Project Operating Costs 511.81172 180683 Annualized Unit Cost ollncremental Gneration 513 36

. - Seven Mile Financial Evaluation

--

Year

SVA Cdculr l ion Kevcnuer Adjusted for IIW A~lrnlal Kate of lnllalius Water Capacity Fee: Adjusted for innation Variable Water Rentals. Adjusted for inflalion Tues &Grants Adjusted for inflation SiteOMA: adjusted for inflalion

less Economic depreciation less rnnurl salvayc ( rc r~uvr l cost) accrual Corporation Capital Trxcs add CIA an~orl iut lon Net Operatin8 prolit less Capital charye

SV A

Discount Rate Discounted SVA Cun~ulal ive discounted SVA

Opening Net Book Value Additions less accumulated depreciation Net book value less wnlributions in aid add accum. CIA amonintion l e u salva8e liabilily Net total invested capital Capital charge

(wst of capital x prior yr net)

Cash Flow Calculation Revenua Water Capacity Fee: Adjusted for inflation

Variable Water Rentals. Adjusted Tor inllation 'Taxer &Grants: Adjusted fur inflalion Site OMA: adjarled for inllation less Capital expenditures Corporation Capital Taxes less salvage/(removal cost) plus contributions in aid

Net Cash Plow

Nominal Dollars ]CORPORATE PERSPECTIVE JPROVINCIAL PERSPECTIVE (excludes dividends) I

End of

5 Years of I 0 Years of 20 Years of Economic knc61s kne f i l s knef i ts Life

Resulls l o the end o l Fiscal Year 15/16 2001 30131 2061 PV of SVA (114.264) (510,885) (59.507) 55.593

PV of Projecl Cosls 141,036 141.036 $41.036 541.036

PV of Project Costs: Overheads 5821 5821 5821 $821

PV of Projcr l Cosls: Tranmntission 12.050 53.221 54.632 55.822 PV o r ~ c ~ ~ e f i l s $7.037 120.050 $36.672 153.272

End o f Economic

Lire 206 1

Present Value of Corporafe Benefits 53.272

118,045 Prbscnl Value o r Water Rentals And Taxer Present Value o f Provincial Benefits 171.317

I Presenl Value o f A l l Capital $47,679

Discount Kate Discounted cash flow Cun~ulaJvc dirwuntcd cash fluw

knefiVCosc Ratio (disc.)

NPV (536.8701 (125.029) (19.816) 15.591 --- Discounted CF kncf i t /Cos l Ratio 0 16 044 053 107

Net Press111 Value ( lo tho Provlncc) 123.638 - Benefil Cost Ratlo I 50 I I

$45,078 $46,488 547.679

-- . Sev'en Mile Financial Evaluation DRXFT

Nominal Dollars

Year

SVA Calculalion Revenues: Adjusted for the Annual Rate of Inflation Waer Capacily FCC: Adjusted for inflation Variable Water Rentals: Adjusled for inflation Taxes &Grants: Adjusted for inflation Site OMA: adjusted for inflation

less Economic depreciation less annual salvage (removal cost) accrual Corporalion Capital Taxa add CIA amortilalion Nct Ope18linp prolil less Capital charyc

SVA Discount Rate Discounled SVA Cumulative discounted SYA

Opening Net Bmk Vaha Additions less accumulated depreciation Net book valuc less contributions in aid add accunl. CIA amortization less salvaye liability Net total inverted capital Capital charge ( m t o f capital x prior yr net)

Cash Flow Calculation Revcnucs Water Capacity Fee. Adjusted for inflation Variable Water Rentals. Adjusled for innation Taxes &Grants: Adjusted for inflation Site OMA: adjusted for inflation less Capital expenditures Corporation Capital Taxes less salva8e/(removal cost) plus contributions in aid Net Cash Flow

Discount Rate Discounted cash flow Cumulative discounted cash flow

BcnefiVCosl Ratio (disc.)

3.009 2.832 2.664 2.507 2,359 2,220 2,090 1,967 1,851 1.743 1,641 1,544 1.454 1.369 1.289 1.213 1.142 1.075 13.460) (12.171) (10.958) (9.816) (8.741)

of 9Ahncia1 reQd4 201 I inW&ice w i t h U P prices 0.8 I 2001-0109

6

e

Seven Mile Financial Evaluation DRKFT Nominal Dollars

SVA Calculaliou Revenue: Adjusted for the Annual Rate o f Inflation Water Capacity Fee: Adjusted for inflation

Variable Water Rentals: Adjusted for inflation Tsxe &Grants. Adjusted for inflation Site OMA: adjusted for inflation

lur Ewnomic depreciation l u s annual salvye (removal cost) accrual Corporation Capital Taxw add CIA amortization Net Operating profit less Capital charge

SVA

Diswunl Rate Discounted SVA Cunul.tivc ditcountcd SVA

Opening Net Book Value Additions less acsumulatcd depreciation Net book value less wntributions i n aid add accum. CIA unonization less salvage liability Net total invulcd capital Capital charge (wst of capital x prior y r net)

Cash Flow Calculation Revenue Water Capacity Fee: Adjusted for inflation Variable Waar Rentals: Adjusted for inflation Taxes &Grants: Adjusted for inflation Site OMA: adjusted for inflation less Capital expenditures Corporation Capital Taxw Ius saka~d(removsI wst) plus wntributions i n aid Net Cash Flow

Discount h e Discounted cash flow ~un~u ln t i ve diswunted cwh flow

&ncBLICost Ratio (disc.)

0 0 0 0 0 0 0 0 0 0 0 0

1.012 953 898 845 7% 749 705 664 625 589 554 522 492 463 436 410 386 364 (7.721) (6.775) (5,878) (5.031) (4,237) (1,488) (2,782) (2,118) ( 4 9 ) (904) (34V) 173 665 1.128 1.561 1.974 2.360 2.724

d r n & d . ( ~ r ~ 201 1 i n t w i c e with WB~ price- 2001-01-09

7

- Seven Mile Financial Evaluation DRAFT

Nominal Dollars

SVA Calrul8tiom Revenuer: Adjusted for the Annual Rate o f Inflation Waler Capacity Fee. Adjusled for inflalion Variable Water Rentals: Adjusted for inflalion Taxes &Grants: Adjusted for inflalion Site OMA: adjusted for inflation

less Economic depreciation less annual salvage (removal cost) uccmal Corporation Capital Taxss add CIA an~onization Net Operaliny profit . less Capital charge

SVA

Diswua Rate

16.586 17,151 17.719 18.187 18.847 19.390 19,897 20,331 20.611 20.496 31,197 (1.835) 0 0 0 v 3

002 0.01 0.01 001 0.01 OOI 0.01 0.01 0.01 0.01 00067 0.01 0.01 001 0.00 Disuwnted SVA Cumulalivc discouuled SVA

Opening Net Bmk Value Additions lcrr accumulated depreciation Net b&k value less contributions in aid add accun~. CIA amonization less salvqe liability Net :owl invested capital Cepild charge (wst o f capital x prior yr net)

Cash Flow Calculation Revenue Walcr Capacity Fee: Adjwkd for inflation Variable Water Rentals' Adjusted for inflation Tax- &Grants: Adjusled for inflation Site OMA: adjusted fur infla~ion less Capilal expwdiluru Corporation Capital Taxes l us salvugd(removal wsr) plus contributions in aid Nd Cash Flow

Diswunt Kale I)iscounled cash flow Cumula~ivc disuxrnted cash flow

BcnclUCosl Ralio (disc.)

343 322 304 286 269 253 239 225 212 190 219 (0) 0 0 0 3.066 3,319 3.693 3.971 4,241 4,501 4,740 4,964 5.176 5,375' 5,593 5.593 5.593 5.593 5,593

1.06 1.07 1.08 1.08 1 .O9 1.09 1.10 1.10 I . 1 1 1.11 1.12 1.12 1.12 1.12 & M h y olFinancia1 resuns 2011 in s e r v b with rep1 prices

-- Seven Mile Financial Evaluation DRIAFT

Real D o l l a r s

0 0

I Write-Down 0 3.3W 1.660 1.660 1.660 1.660 1.660 0 0 0 0 0

)CORPORATE PERSPECTIVE (PROVINCIAL PERSPtCTIVE (cxcludcr dividends) End of

Ecouon~ic Life

2061 43,335

519.246 562.582

End or 5 Years of 10 Vcan of 20 Years of Economic

Bmefib Bcacfils Benefits Life Results to the md or Fiscal Year 07/08 12/13 22/23 2061 PV of SVA (S10.242) (5 13.928) (57,782) 5932

PV of Projecl Costs $6.258 540,367 540.367 $40.367 PV of Project Costs: Overheads $125 5807 $807 $807 PV of Proiccl Costs: T ran rnh iau 50 51.1 17 $3.597 $6.084

- - ..~.~ -

NPV 1 Net Present Value (w the Province)

Discou~ited C F &nefit/Cost Ratio -9.81 -0.21 0.44 0 98 Benefit Cost Rado

Present Value o f Corporate Benefits

Present Value o f Water Rentals And Taxes P r ~ l l l Value o f Pmvincial Benefits

Present Value of A l l Ca~ital

Year 0 0 I 2 3 4 5 6 7 8 9 10 I I

SVA Calculation Revenues: Adjusted for the Annual Rate o f Inflation Water Capacity Fee: Adjusted for innation Variable Water Rentals: Adjusted for innation Taxes &Grants: Adjustd for inflation Sile OMA: adjurled for inflation

less Economic depreciation less mnud salvage (removal cost) acclual Corporation Cap~tal Taxes add CIA amonization Net Operating profit lesr Capiol charge

SV A

Discount Rate Discounted SVA Cun~ulalive Jisrouulrd SVA

Openinn Net Boot Value Additions less accuniulalcd depreciation Net book value less contributions in aid add accunl. CIA aniorlizrtion less salvage liability Net total invuted capilal Capital charge (ox1 of capital x prior yr net)

Cash Flow Calculation Revenuer Water Capacity Fec: Adjusted for inflation Variable Water R ~ t a b : Adjusted for inflation Taxes &Grants: Adjusted for inflation Site OMA: adjusted for inflation less Capital expenditures Corporation Capital Taxes lesr ralvagrf(ron~ovrl cost) plus conlributions in aid Ncl Cash Flow

Diswunt Rate Dircounted u s h flow Cumulative dimunted cash flow

0 0 0 0 0 0

0 (3,300) (1.556) (1.458) (1.367) (1.281) (1.200) (1.230) (5.157) (17.000) (17.627) (855) 3.441 3.226 3.024 0 . 0 3 0 ) (48.589) (45.363) (42,339)

Summary of Financial ntsulls 2011 in service wrlh sepl prices


Write-Down

DRTAFT Real Dollars

0 0 0

SVA Calcul8lion Revenues. Adjusted for the Annual Rate o f Inflation Water Capacity fee: Adjusted for inflation Variable Water Rcntalr: Adjusted For inflation T l x u &Grants: Adjusted for inflation Site OMA: adjusted for inflalion

Icu Economic dcprecia~ion less mnual salvage (removal cost) accrual Corporation Capital Taxes add CIA arnoniration Nel Operating profit less Capital charme

SVA

Discount Rale Discounted SVA Cumulalive dbcountcd SVA

Opening Net Book Value Additions less accumulated depreciation Net b m k value less contributions i n aid add accum. CIA amonization lerr salvape liability Net total invested capital Capital charge (cost of capital x prior yr net)

Cash Flow Calculalion Revenuer Water Capacity Fee: Adjusted for inflation Variable Water Rentals: Adjusted for inflation Taxen &Granu: Adjusled for inflation Site OMA: adjusted for inflalion less Capital expenditures Curporation Capital Taxes less salva~r/(removal cost) plus contributions in aid Nc l Cash Flow

Discount Rale Discounted c u h now Cumulative discounted w h flow

2.835 2.658 2.492 2.336 2.190 2.053 1,925 1,805 1.692 1,586 1.487 1.394 1.307 1.226 1,149 1.078 1.010 947

Summary 01 Fmannal resuffs 201 1 m s e ~ ~ c e WIN, sepl pnces

-.- Seven Mile Financial Evaluation

Write-Down

DRAFT Real Dollars

0 0 0 0 0 0 0

32133 33/34 34/35 35/36 36/37 37/38 38/39 39/40 40141 41/42 42/43 43/44 44145 45/46 46/47 4 7 48N9 49/50 Ycrr 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49

SVA Cslculrtiou Revenues: Adjuslcd for lhe Annual Rate o f Inflation Water Capacity Fee. Adjusted for inflation Variable Water Rentals: Adjusted for inflation Tases &Grants: Adjusted for inflation S m OMA. adjusted for ir~flalion

less Economic depreciarion less annual salvage (removal wst) accrual Corporation Capital Taxes add CIA anionization Ncl Opuaring profit less Capital charge

SVA

Diswunl Rae Discountul SVA Cumulalivc discounted SVA

Openin8 Net Book Value Additions less accumulated depreciation Net book value less contributions i n aid add accum. CIA amorlizalion less salvage liability Net lolal inverted capital Capital charge (cost o f capital x prior yr net)

Cash Flow Calcu la t io~~ Revenues Water Capacity Fee: Adjuned for inflation Variable Water Renlals. Adjusted for inflation Taxer &Grants: Adjusted for inf laion Site OMA: adjusted for influlion less Capital expenditures Corporation Capilal Tases l eu salvsyd(ren~oval cost) plus conrributions i n aid Net Cash Flow

Oiswunl Rate Dircounted cash flow Cumulative discounted cash flow

Summary of Financial results 201 1 in service wi(hsept$ces- 2001-01-09

13

Seven Mile Financial Evaluation DKAFT Real Dollars

Wria-Down

scar

SVA Cnlculation Revenues: Adjusted for the Annual Rale of Inflation Water Capacity Fee. Adjusted for inflation Variable \Vatu Rentals: Adjusted for inflation Taxes &Grants Adjusted for inflation Sire OMA. adjusted for inflation

less Ewnomic depreciation less atnual salvage (removal cost) accrual Corporation Capita! Taxer add CIA amonizarion Net Operating profit less Capital charge

SVA

Discount Rate Discounted SVA Cumulative dircouuted SVA

Opening Net Book Value Additions l u s accu~nulated depreciation Net b w l value lurr wnlribulions in aid add accum. CIA amonization less salvage liability Net mtal invested capital Capital charge (wst o f capital x prior yr net)

Cash Flow Calculation Revenues Water Capacity Fee. Adjusted for inflation Variable Water Rentals: Adjusted for inflation Taxer &Grants: Adjusted for inflation Sile OMA: adjusted for inflation less Capital expenditures Corporation Capital Taxes less salvagd(removal cost) plus wntributions in aid Net Cssh Flow

Discount Rale Diswuntd cash l low Cumulative diswunted cash flow

279 262 246 231 216 203 190 179 168 157 191 (0) 0 0 0 0

Summary of Financial results 201 1 i n service with sep(p~ices

- A I B ( H I I ) J ) K ~ L I M ~ N ~ O ~ P I Q ~ R

1 Marginal Cost Summary for BC Border (CDNS Nominal) 2 -- - 3

N K " a ? b n Factor 101.39% 103.06% 105.04% 107.14% 109.29% 6TransArea BCHA 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

B % n u a v HLH 51 79 178 82 88 13 59 16 5238 54 15 5347 52 14 4887 5045 4933 LLH 4830 18117 8216 5144 4367 4582 47.33 5007 4286 4615 4513

" , 18 1 March HLH 54 27 166 61 92 29 60 10 54 19 5631 57 14 53 57 51 28 52 32 51 16 19 1 LLH 5370 180 90 91 43 59 06 53 09 5464 5472 53 13' 49 50 51 01 49 88

10 11 12 13 -- 14 15 16 17

20 1 Average 91 I I

Average

February HLH 53 82 171 01 91 57 59 56 53 97 56 30 55 89 53 45 49 95 51 80 50 65 LLH 53 82 181 04 91 61 59 53 53 97 56 30 55 83 53 15 4995 51 70 50 56

Average

5269 12522 8964 55 87 51 05 5370 5446 5245 48 33 50 91 49 7 i 42 11 104 08 71 61 46 92 42.51 43 79 44 65 45 05 42 08 43 37 42 40

-. Average -

d l I 38 ] July HLH 53 59 12551' 90 42 58 43 52 92 55 34 56 18 52 74 49 01 50 65 49 52 39 1 LLH 45 82 108 59 7733 49 59 4477 45 39 4648 45 14 41 58, 41 57 40 65

28 29 30 1 4

40 1 Average I

! I

27.- May HLH 44 70 106 91 75 98 48 35 44 33 44 54 45 08 4570 41 64 4269 41 75

LLH 28 71 68 76 48 93 33 49 31.51 33 20 32.82 34 47 34 57 34 43 33.67 Average

LF-- HLH 53 70 125 79 90 63 58 79 53 11 57 69 63 06 53 39 49 32 5345 52 27

-- LLH 4830 11227 8153 5091 4561 4626 4678 4705 4197 43.07, 4212 Average

17

. - - .. - - . - 171.62 127.45 92.68 61.08 55.20 57.09 56.25 53.13, 50.83 52.58 51.41

LLH - - - - .- -- 144.52 125.76 90.62 59.16 53.40 55.50 55.36 52.28 49.29 51.02 49.89

- 48 49 51

53 54 55

DL

63 December HLH 17074 13247 9900 6417 5676 5910 5824 5359 5429 5536 5413 64 LLH 14444 11170 8066 5446 4795 4824 5075 4344 4489 4610 4508

Average I

182326 311337 2021 21 131329 118547 1231 15 123949 118385 111789 115236 112683 14684 92

69 -- 7"

- . - - - - 53.93 126.04 91.05 59.58 53.67 60.66 60.13. 55.88. 51.72 54.90 53.68 September HLH '

-- LLH 51.90 120.26 87.62 56.18 50.99 52.73 51.90 49.20 46.39 47.84 46.78 Average 50---

52- i October HLH 164.92 126.24 91.62 59.63 54.99 56.79 56.04 53.06 51.29 51.55 50.41

LLH 156.18 122.51 89.10 58.37 53.16 54.89 54.01 49.08, 47.87 49.11 48.02 Average

CALCULATION OF FORWARD PRICES: NOMINAL

Seven Mi le Flnanclal Evaluation Calculate Revenue Price C k e s

Fiscal Ysa Flscal Year Investmenl Beginning Endin

[ 0 [ 20000 I Year

0

1

2

3

4

5

6

7

6

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

Cumlalive Inflation

100 100

HLH 102 00 LLH 102.00 HLH 104.04 U H 104.04 HLH 106.12 LLH 10612 HLH 10824 LLH 108.24 HLH 110.41 LLH 110.41 HLH 112.62 LLH 112 62 HLH 114.87 LLH 114.87 HLH 117.17 LLH 117.17 HLH 119.51 LLH 119.51 tlLH 121.90 LLH 121 90 IILH 124.34 LLH 124 34 HLH 126.82 U H 126 82 HLH 129.36 LLH 129.36 HLH 131.95 LLH 131 95 HLH 134.59 LLH 134.59 HLH 137.28 LLH 137.28 nLn 140.02 LLH 140.02 HLH 142.62 LLH 142.82 HLH 14566 U H 145.68 HLH 146.59 LLH 148.59 nLn 151.57 LLH 151.57 HLH 154.60 LLH 154.60 HLH 157.69 LLH 157.69 HLH 160.84 LLH 160.84 HLH 164.06 LLH 164.06 HLH 167.34 LLH 167.34 HLH 170.69 LLH 170.69 HLH 174.10 LLH 174.10 H W 177.58 LLH 177.58 HLH 181.14 LLH 161.14 HLH 184.76 LLH 184.76 HLH 186.45

Inflation Factor

200% 2 00% 2.00% 2.00% 2.00% 2 00% 2 00% 2.00% 2 00% 2.00% 2 00% 2.00% 2.00% 2.00% 2 00% 2.00% 2 00% 2.00% 2.00% 2 00% 2.00% 2.00% 2.00% 2.00% 200% 2 00% 2.00% 2.00% 2.00% 2.00% 2.009. 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.0046 2.00% 2.00% 2 00% 200% 2.00% 2.00% 2.00% 2.00% 2 00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00%

April UMWh

$46.98 $39.67

H16.41 $98.07 $83.33 $67.47 $51 94 $44 21 $47.46 $40.08 549.92 $41 26 550.63 $42.07 $48.76 $42.45 $44 93 $39.65 $47.33 $40.66 548.27 $41.68 549.24 $42.51 $50.22 143.36 $51.23 $44.23 $52.25 $45.1 1 $53.30 $46.02 $54 38 $46.94 $55.45 $47.86 $56.56 $48.83 $57.69 $49.81 $58.84 $50.81 $60.02 $51.82 $61.22 552.86 $62.45 $53.92 $63.69 $54.99 564.97 $56.09 $68.27 $57.22 $67.59 $58.36 $68.95 $59.53 570.32 $60.72 $71.73 $81.93 $73.17

~ a y June SlMWh SIMWh

July UM wn

550.05 543.37

$117.21 $102.78 $84.44 $73.19 $54.56 $46 94 $49 42 $42 38 $51.68 $42.88 $52.47 549.35 149.25 142.72 $45.77 $39 35 147.29 239.34 $48 24 540.13 $49.21 $40.93 550.19 $41.75 $51.19 342.58 552.22 $49.44 $53.26 544.31 $54 33 145.19 $55.41 $46.10 556.52 $47.02 $57.65 $47.98 $58.81 $48.92 $59.96 $49.89 $61.18 $50.89 $62.40 $51.91 $63.65 $52.95 $64.93 $54.01 566.22 $55.09 567.55 $56.19 $68.90 $57.31 $70.28 $58.46 571.66 $59.63 573.12

Auoust Seotember SlMWh

$50 09 145.71

$117.33 $106.25 $84.54 $77 16 $54.84 $48 18 $49 54 $43.17 $53.81 $43.79 $58.62 $44.27 549.80 $44.53 $46.00 139.73 $49.86 $40.76 $50.86 $41.58 $51.88 $42.41 $52.91 $43.26 $53 97 $44.12 $55.05 $45.01 $56.15 $45.91 $57.27 $46.82 558.42 $47.76 $59.59 $46.72 $60.78 $49.69 $6200 $50 68 $63.24 $51.70 $64.50 $52 73 $65.79 $53.79 $67.1 1 $54.86 568.45 $55.96 $69 82 $57.06 $71.21 $58 22 $72.64 $59.38 574.09 $60.57 $75.57 $61.76 $77.08

UMWh

$50.25 $49.12

$117.44 $113.82 $64 83 $82.92 $55 52 553.18 $50.01 548.26 156.52 $49.91 $58.02 $49.12 552.07 $46.57 $48.19 143.91 $51.15 $45 28 $52.17 $46.18 $53.22 247.11 $54.28 $48.05 $55.37 $49.01 $56 47 $49 99 $57.60 $50.99 $58.75 152.01 $59.93 $53.05 $61.13 554.11 $62.35 $55.19 $63.60 $56.30 $64.87 $57.42 $66.17 $58.57 $67.49 $59.74 $66.84 $60.94 $70.22 $62.16 $71.62 $63.40 $73.05 $64.67 $74.52 $65 96 $76.01 $67.26 $77.53 $68.63 $79.08

October November December SlMWh

$152 97 $146 99 $117.10 $115.30 $84.98 $83 86 $55 31 $54.93 $51.01 $50.03 $52.68 $51.66 $51.98 $50.83 549.21 $46.19 $47.57 545.06 $47.82 $46 22 $46.77 $47.15 $49.75 $48.09 $50.75 $49.05 $51.76 $50.03 $52.80 551.03 $53.85 $52.05 $54.93 $53.10 $56.03 $54.16 $57.15 155.24 $58.29 $58.35 $59.46 $57 47 560.65 $56.62 161.86 559.79 $63.10 $80.99 $64.36 582.21 $65.64 $63.45 $66.98 $64.72 $66.30 $68.02 $69.66 $67.34 $71.06 $68.68 $72.46 $70 06 $ 73.93

SlMWh

5157 38 $134.81 $116.87 $117.31 $84 99 $84.53 $56.02 $55.18 550.82 $49 81 $52.36 $51.77 $51 59 $51.64 $48 72 $48.77 $46 62 $45.97 $48.22 $47.59 $49.18 $48 54 $50.17 $49.51 $51.17 $50.50 $52.19 $51.51 $53.24 $52.54 $54.30 $53.59 $55.39 $54.67 $56.49 $55.76 $57 62 $56.87 $58.78 $58.01 $59.95 559 17 $61.15 $60.38 $62 37 $61.56 $63.62 $62.79 $64.89 $84 05 $66.19 $65.33 $67.52 $66.64 $66.87 $67.97 $70.24 $69.33 $71.65 $70.72 $73.08 $72.13 $74.54

January SIMWh

$163.80 $168.81

$80 73 $76.55 $54.19 547.93 $47.98 140.69 $49.60 $42 70 $48.96 $44.10 $47.76 $46 65 544.77 $39.94 $46 21 $43.00 $45.19 142.05 $46.09 $42.89 $47.01 $43.75 $47.95 $44.62 $48.91 $45.52 $49.89 $46.43 $50.89 $47 38 $51.91 148 30 $52.94 $49.27 $54.00 150.25 $55.08 $51.26 $56.18 $52 28 $57.31 $53.33 $56.45 $54.40 $59.62 $55.48 $60.82 $56.59 $62 03 557.73 $63.27 $58.68 584.54 560.06 $65.83 $61.26 $67.15 $62 48 568.49 $63.73 $69.88

February March UMWh

$156 64 $160 88

$83.88 $85 36 $54 55 $55 47 $49 44 $50.29 151.57 $52.46 $51.19 $52.02 $48.96 $49.52 $45.76 $46.54 $47.45 $48.17 $46 40 $47.11 $47.32 $48 05 $48.27 $49 01 $49 24 $49.99 $50.22 $50 99 $51.23 $52.01 $52.25 $53.05 $53.30 $54.11 $54.38 555.19 $55 45 $56 29 $56.56 $57.42 $ 57.69 $56.57 S 58.64 $59.74 160.02 $60.94 $61.22 $62.15 182.44 $63.40 $63.69 $64.67 $64.97 $65 98 566.27 $67.28 $67.59 $66.62 $68.94 $70.00 570.32 $71.40 $71.73

$70.44 SuEJr7a)6of Finencialmsuls 201 1 in service wilh rep1 prices

Fiscal Yea Fiscal Year Investment Beginning Endin

[ 0 1 zoo: 1 Year

0

33

34

35

36

37

38

39

40

4 1

42

43

44

45

48

47

48

49

50

51

52

53

54

55

56

57

58

59

60

61

Cumlative Inflation

100 100

LLH 188.45 HLH 192.22

LLH 192.22

HLH 19607 U H 196.07 HLH 199.99 LLH 199.99 HLH 20399 LLH 203 99 HLH 208.07 LLH 208.07 HLH 212.23 LLH 212.23 HLH 216.47 LLH 21647 HLH 220.80 LLH 22080 HLH 225.22 LLH 225.22 HLH 229.72 LLH 229.72 HLH 234.32 LLH 234.32 HLH 239.01 LLH 239.01 HLH 243.79 LLH 243.79 HLH 248.66 LLH 248.66 HLH 253.63 LLH 253.63 HLH 258.71 LLH 258.71 HLH 263.88 U H 263.88 HLH 269.16 LLH 289.16 HLH 274.54 LLH 274.54 HLH 280.03 LLH 280.03 HLH 285.63 LLH 285.63 HLH 291.35 LLH 291.35 HLH 297.17 LLH 297.17 HLH 303.12 LLH 303.12 HLH 309.18 LLH 309.18 HLH 315.36 LLH 315.36 nLH 321.67 LLH 321.67 HLH 328.10 CLH 328 10 HLH 334.67

inflation Factor

2.00% 2 00%

2 00%

2.00% 2 00% 2.00% 2 00% 2.00% 2 00% 200% 2 00% 2.00% 2.00% 2.00% 2 00% 2.00% 2 00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00%' 2 00% 2.00% 2.00% 2.00% 2.00% 2.00% 2 00% 2.00% 2.00% 2.00% 2.00% 2 00% 2 00% 2.00% 2.00% 2 00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2 00% 2.00% 2.00%

April WMWh

$63.17 $74 63

$64.43

$76.12 565.72 $77.64 267.04 $79 20 $68.38 $80.78 $69.75 582.40 $71.14 $84 04 $72.56 $85.72 $74.01 $87.44 $75.49 $89 19 $77.00 $90.97 $78.54 $92.79 180.12 $94.65 $81.72 $96.54 $83.35 $98.47 $85.02

1100.44 $88.72

$102.45 $88.45

$104.50 $90.22

$106.59 $92.03

5108.72 $93.87

5110.89 $95.75

$113.11 $97.66

$115.37 $99.61

$1 17.68 $101.61 $120 04 $103.64 $122.44 $105.71 $124.88 $107.83 $127.38 $109.98

May June SlMWh SlMWh

-- Seven Ml le F lnancla l Evaluat ion

August September SIMWh SlMWh

October November Docernbe! UMWh

January SlMWh

$65.01 $71.28

$68.31

$72.88 $67.63 $74.13 $68.99 $75.62 570.37 $77.13 571.77 $78.67 $73 21 $80.25 $74.67 $81.85 576.17 $83.49 $77 69 $85.16 $79.25 $8688 $80.83 $88.60 $82.45 290.37 $84.10 $92 18 $85.78 $94.02 $87.49 $95.90 $89.24 $97.82 $91.03 $99.78 $92.85

$101.77 $94.71

$103.81 $96.60

5105.88 $98 53

$108.00 $100.50 $110.16 $102.51 $112.36 H04.56 5114.61 $106.65 $116 90 $108.79 $119.24 $110.96 $121.63 $113.18 $124.08

February SlMWh

$72 82 $73.16

$74.28

$74 63 575.77 $76 12 $77.28 $77.84 $78 83 $70 19 $80.90 980.78 $82 01 $82.39 $83.65 $84 04 $85.32 $85.72 $87.03 $87.44 $88.77 $89.19 $90.55 $90.97 592.36 192.79 $94.21 $94.64 $96.09 $96.54 $98.01 $98.47 $99.97

$100.44 $101.97 $102 45 $104.01 $104 49 $106 09 $106.58 $108.21 $108.72 $110.38 $1 10.89 $112.58 $113.11 $114.84 $115.37 $117.13 $117.68 $119.47 $120.03 $121.86 $122.43 $124.30 $124.88 $126.79

Calculate Revenue ~ r i c e r u ~ e s

March SIMWh

Summary 01 Finulcial msuls 201 1 in sewm with sepl pices 200101-09

19

-- Seven Mlle Flnanclal Evaluatlon Calculate Revenue P r i c e X u ~ e s

Fiscal Year Fiscal Year Baginning Ending

I 1999 1 2000 1 2000 2001

2001 2002

In-Sewic In-Sewic Year Month

HLH 0 0 LLn 0 0 HLH 0 0 LLH 0 0 HLH 0 0 LLH 0 0 HLH 0 0 LLH 0 0 HLH 0 0 LLH 0 0 HLH 0 0 LLH 0 0 HLH 0 0 LLH 0 0 HLH 0 0 LLH 0 0 HLH 0 0 LLH 0 0 HLn 0 0 LLH 0 0 HLH 1 5 LLH 1 5 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLn 1 0 LLH 1 0 HLH 1 0 LLn 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLn 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLn 1 0 U H 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0

1 2 3 4 5

April May June July Aupurf ($000) (SOOO) (SOOO) fS000) (SOOO)

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ' 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ; ! ; 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 50.85794 0 0 0 0 0

984.7626 3107.577 3557.64 885,7001 51.8751 0 1525.547 1574.815 409.3104 0

1004.458 3169.728 3628.793 803.4141 52.9126 0 1556.058 1606.312 417.4968 0

1024.547 3233.123 3701.369 921.4824 53.97086 0 1587.179 1638.438 425.8466 0

1045.038 3297.785 3775.396 939.912 55.05027 0 1618.923 1671.207 434.3835 0

1065.939 5363.741 3850.904 958.7103 56.15127 0 '1651.301 1704.631 443.0506 0

1087.256 3431.018 3927.922 977.8845 57.2743 0 1684.327 1738.723 451.9118 0

1109.003 3499.636 4006.46 997.4422 58.41978 0 1718.014 1773.498 460.95 0

1131.183 3569.829 4088.61 1017.391 59.58816 0 1752.374 1808.968 470.169 0

1153.806 3841.021 4168.342 1037.739 60.77994 0 1767.422 1845.147 479.5724 0

1178.883 3713842 4251.709 1058.494 61 99554 0 1823.17 1882.05 489.1839 0

1200.42 3788.119 4336.743 1079.663 63.23545 0 1859.633 1919.691 498.9471 0

1224.429 3663.881 4423.478 1101.257 64.50018 0 1696.826 1958.085 508.9281 0

1246.917 3941.159 4511.948 1123.282 65.79018 0 1934.763 1997.247 519.1046 0

1273.895 4019.982 4602.167 1145.746 67.10597 0 1973.458 2037.192 529.4867 0

1299.373 4100.382 4694.23 1166.662 88.44609 0 2012.927 2077.935 540.0764 0

1325.361 4182.389 4788.115 1192.036 69.81705 0 2053.186 2119.494 550.878 0

1351.868 4266.037 4883.877 1215.876 71.21339 0 2094.249 2181.884 561.8955 0

1376 905 4351.358 4981.555 1240.194 72.63766 0 2136.134 2205.122 573.1334 0

1406.464 4438.365 5081.186 1264.998 74.09041 0 2178.857 2249.224 564.5961 0

1434.813 4527.153 5182.81 1290.296 75.57222 0 2222.434 2294.209 596.288 0

1463.305 4617.696 5286.466 1316.104 77.08366

7 8

October November De< ~S000) (SOOO)

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

10

January ~$000)

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Nominal Revenuer

11 12

February March Annual Dispatchability ($000) ($000) ($000)

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 334.6121 385.4701 29.800788 0 0 0 0 0 341.3044 8928.859 690.29229 0 0 3509.673 271.33368 0 348 1305 9107.436 704.09814 0 0 3579.866 276 76036 0 355.0931 9289.585 718.1801 0 0 3651.464 282.29556 0 362.195 9475.377 732.54371 0 0 3724.493 287.94147 0 369.4388 8884.884 747.19458 0 0 3798.963 293.7003 0 376.8276 9858.182 762.13847 0 0 3874.962 299.57431 0 3843642 10055.35 777.38124 0 0 3952.462 305.5658 0 392.0515 10258.45 792.92887 0 0 4031.511 311.67711 0 399.8925 10461.58 808.78744 0 0 4112.141 317.91065 0 407.8803 10670.81 824.96319 0 0 4194.384 324.26887 0 416.0481 10884.23 841.46246 0 0 4278.272 330.75424 0 424.3691 11101.91 658.2917 0 0 4363.837 337.36933 0 432.8565 11323.95 875.45754 0 0 4451.114 344.11672 0 441.5136 11550.43 892.86669 0 0 4540.136 350.99905 0 450.3439 11781.44 910.82602 0 0 4630.939 358.01903 0 459 3508 12017.07 929.04254 0 0 4723.558 365.17941 0 468.5378 12257.41 947.62339 0 0 4818.029 372.483 0 477.9085 12502.56 966.57586 0 0 4914.369 379.93266 0 487.4887 12752.61 985.90738 0 0 5012.677 387.53131 0 497.2161 13007.66 1005.6255 0 0 5112.931 395.28194 0 507.1604 13267.81 1025.73&msy vya

Conversion to Real Revenues

Inflation Factor Annual

($000) 100 0.00% 0 100 0.00% 0 102 2.00% 0 102 2.00% 0 104 2.00% 0 104 200% 0 106 2.00% 0 108 2.00% 0 108 2.00% 0 108 2.00% 0 110 2.00% 0 110 200% 0 113 2.00% 0 113 2.00% 0 115 2.00% 0 ,115 2.00% 0 117 2.00% 0 117 2.00% 0 120 2.00% 0 120 2.00% 0 122 2.00% 0 122 2.00% 0 124 2.00% 310.0193 124 2.00% 0 127 2.00% 7040.344 127 2.00% 2767.353 129 2.00% 7040.344 129 2.00% 2767.353 132 2 00% 7040.344 132 2.00% 2767.353 135 2.00% 7040.344 135 2.00% 2767.353 137 2.00% 7040344 137 2.00% 2767.353 140 2.00% 7040.344 140 2.00% 2767.353 143 2.00% 7040.344 143 2.00% 2767 353 146 2.00% 7040.344 146 2.00% 2787.353 149 2.00% 7040.344 149 2.00% 2767.353 152 2.00% 7040.344 152 2.00% 2767.353 155 2.00% 7040.344 155 2.00% 2767.353 158 2.00% 7040.344 158 2.00% 2767.353 161 2.00% 7040.344 161 2.00% 2767.353 164 2.0096 7040.344 164 2.00% 2767.353 167 2.00% 7040.344 167 2.00% 2767.353 171 2.00% 7040.344 171 2.00% 2767.353 174 2.00% 7040.344 174 2.00% 2767.353 176 2.00% 7040.344 178 2.00% 2767.353 181 2.00% 7040.344 181 2.00% 2767.353 165 2.00% 7040.344

Seven Mile ~inanciaiEvaluatlon Calculate Revenue Price Curves

Fiscal Year Fiscal Year Beginning Ending

1 1999 1 2000 1 In-Sewic In-Sewic

Year Month

LLH 1 0 HLH 1 0

LLH 1 0

HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH I 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 CLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLH 1 0 HLH 1 0 LLU 1 0 HLH 1 0

April May Juna July Au~ust (SOOO) ($000) (sm) ($000) isoool

0 0 0 0 0 0 0 0 0 0 0 2266.883 2340.093 608.2138 0

1492.572 4710.05 5392.195 1342 426 78.82534

0 2312.22 2386.895 620.378 0 1522.423 4804.251 5500.039 1369.274 80.19784

0 2358.465 2434 633 632.7858 0 1552.871 4900.336 5610.04 1396.66 81.8018

0 2405.634 2483.325 645.4413 0 1583 929 4998 342 5722.241 1424.593 83.43784

0 2453.747 2532.992 658.35 1615.606 5098.309 5836.685 1453.08 85.10659

0 2502.822 2583.651 671.517 1 : 1847.92 5200.275 5953.419 1482.147 86.80872

0 2552.878 2835.325 664.9475 0 1680 878 5304.281 6072.487 1511.79 88.5449

0 2603.938 2608.031 698.6464 0 1714.496 5410366 6193.937 1542.025 90.3158

0 2656.014 2741.792 712.6194 0 1748.786 5518.574 6317.818 1572.866 92.12211

0 2709.135 2796.627 726.8718 0 1783.761 5628.945 6444.172 1604.323 93.96455

0 2763.317 2852.50 741.4092 0 1819.436 5741.524 6573.056 1636.41 95.84385

0 2818.584 2909.811 756.2374 0 1855.825 5856.355 6704.517 1669.138 97.78072

0 2874.956 2967.803 771.3621 0 1892.942 5973.482 6838.607 1702.521 99.71594

0 2932.455 3027.18 786.7894 0 1930.801 6092.951 8975.379 1736 571 101.7103

0 2991.104 3087.703 802.5252 0 1969.417 6214.81 7114.887 1771.302 103.7445

0 3050.928 3149.457 818.5757 0 2008.805 8339.107 7257.185 1808.726 105.8194

0 3111.944 3212.446 834.9472 0 2048.981 8b5.889 7402.328 1842.863 107.9357

0 3174.183 3278.695 851.6461 0 2089.961 6595.208 7550.375 1879.72 110,0945

0 3237.667 3342.229 868.679 0 2131.76 6727.111 7701.382 1917.315 112.2963

0 3302.42 3409.073 886.0526 0 2174.395 6861.653 7655.41 1955.661 114.5423

0 3368.469 3477.255 903.7737 0 2217883 8998.886 8012.518 1994.774 116.8331

0 3435.838 3546.8 921.8491 0 2262.241 7138.864 6172.789 2034.87 119.1698

0 3504.555 3617.736 940.2861 0 2307.485 7281.841 6336.224 2075.363 121 5532

0 3574.648 3690091 959.0918 0 2353.635 7427.274 8502.948 2116.87 123.9842

0 3646.139 3763.892 978.2737 0 2400.708 7575.819 6673.007 2159.208 126.4639

0 3719.082 3839.17 997.8392 0 2448.722 7727.336 8846.468 2202.392 128.9932

0 3793.443 3915.954 1017.796 0 2497.696 7661.882 9023.397 2248.44 131.5731

0 3869.312 3994.273 1038.152 0 2547.65 8039.52 9203.865 2291.369 134.2045

0 3946.698 4074.158 1058.915 0 2598.603 8200.31 9387.942 2337.196 136.8886

eptsmber ($000)

0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

October November Del (SOOO) ($000)

0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

January I ($000)

0 0 0 0

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

'ebruary March Annual Dispatchability ($0001 isooo) ($000)

0 0 0 0 0 0 0 0 0 0 5215.189 403.18758 0 517.3036 13533.17 1048.2528

0 0 5319.493 411.25133 0 527.6497 13803.83 1067.1779 0 0 5425.883 419.47636 0 538.2028 14079.91 lo88 5214 0 0 5534.401 427.86588 0 548.9667 14361.51 1110.2918 0 0 5645.089 436.4232 0 559.946 14648.74 1132.4977 0 0 5757.99 445.15167 0 571.145 14941.71 1155.1476 0 0 5873.15 454.0547 0 582.5678 15240.55 1178.2508 0 0 5990.613 463.13579 0 594.2192 15545.36 1201.8158 0 0 8110428 472.39851 0 606.1036 15858.27 1225.8519 0 0 8232.634 481.64648 0 618.2257 18173.39 1250.3689 0 0 6357.287 491.48341 0 630.5902 16498.88 1275.3763 0 0 6404.432 501.31308 0 643.202 16826.8 1300.8839 0 0 6614.121 511.33934 0 656.068 17163.33 1328.9015 0 0 6748.403 521.56812 0 669 1873 175066 1353.4396 0 0 8881.332 531.99745 0 682.5711 17856.73 1380.5083 0 0 7018.956 542.6374 0 696.2225 18213.87 1408.1185 0 0 7159.337 553.49014 0 710.147 18578.14 1436.2809 0 0 7302.524 564.55995 0 724.3499 18949.71 1485.0065 0 0 7448.575 575.85115 0 738.8369 19328 7 1494.3066 0 0 7597.548 587.36817 0 753.6136 19715.27 1524.1928 0 0 7749.497 599.11553 0 768.8859 20109.56 1554.6766 0 0 7904.487 611.09784 0 784.0596 20511.77 1565.7702 0 0 8062.577 823.3198 0 799.7408 20922.01 1617.4856 0 0 8223.828 635.7862 0 815.7356 21340.45 1649.8353 0 0 8388.305 648.50192 0 832.0503 21767.26 1682.832 0 0 8558.071 661.47196 0 848.6914 22202.6 1716.4886 0 0 8727.192 874.7014 0 865.6652 22648.65 1750.8184 0 0 8901,736 688.19543 0 882.9785 23099.59 1785.8348 0 0 9079.771 701.95933 0 900.6381 23581.58 1821.5514

Factor Annual (SOOO)

100 0.00% 0 100 0.00% 0 166 2.00% 2787.353 192 2 00% 7040.344

192 2.00% 2787.353 196 2.00% 7040 344 196 2.00% 2767.353 200 2.00% 7040.344 2M) 2.00% 2767.353 204 2.00% 7040.344 204 2.00% 2767.353 208 2.00% 7040 344 208 2.00% 2767.353 212 2.00% 7040.344 212 2.00% 2767.353 216 2 00% 7040.344 216 2.00% 2767.353 221 2.00% 7040344 221 2.00% 2767.353 225 2.00% 7040.344 225 2.00% 2767.353 230 2.00% 7040 344 230 2.00% 2767 353 234 2.00% 7040.344 234 2.00% 2767.353 239 2.00% 7040.344 239 2 00% 2767.353 244 2.00% 7040.344 244 2.00% 2767.353 249 2.00% 7040344 249 2.00% 2767.353 254 2.00% 7040.344 254 2.00% 2767.353 259 2.00% 7040.344 259 2.00% 2767.353 264 2.00% 7040.344 264 2.00% 2767353 269 2.00% 7040.344 269 2.00% 2767.353 275 2.00% 7040.344 275 2.00% 2767.353 280 2.00% 7040.344 280 2.00% 2767.353 286 2.00% 7040.344 286 2.00% 2767.353 291 2.00% 7040.344 291 2.00% 2767.353 297 2.00% 7040.344 297 2.00% 2767.353 303 2.00% 7040.344 303 2.00% 2767.353 309 2.00% 7040.344 309 2.00% 2767.353 315 2.00% 7040.344 315 2.00% 2767.353 322 2.00% 7040.344 322 2.00% 2767.353 328 2.00% 7040.344 328 2.00% 2767.353 335 2.00% 7040.344

Summary 01 Fmancial nsWs 201 1 in remint with ~ e p l prices 2001.01-W

21

seven mile generating station … mile generating station installation of the fourth generating unit...

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