1.0 reference: exhibit b-5-1, page 1-2 - bc hydro - power smart · · 2018-04-08... (gdp) of...

Independent Power Producers of BC Information Request No. 1.1.1 Dated: July 5, 2006 British Columbia Hydro & Power Authority

Page 1

Response issued July 26, 2006 British Columbia Hydro & Power Authority BC Hydro F07/F08 Revenue Requirements Application

Exhibit: B-11

1.0 Reference: Exhibit B-5-1, page 1-2

1.1.1 What growth in domestic load (both GWh and % growth) was forecast based on the anticipated growth of the B.C. economy of 3.1%, and what was the actual growth realized when the economy grew at 3.6%? Are these growth rates for the economy stated in terms of Gross Domestic Product or what other measure? What relationship is assumed between the growth of provincial real GDP and the load growth for residential, commercial, and industrial electricity?

RESPONSE: Tables below show: (i) the projection of the annual growth in total domestic billed sales, with DSM, consistent with the projection in the growth of real Gross Domestic Product (GDP) of 3.1%, and (ii) the estimated sales and growth consistent with the estimated real GDP growth of 3.6%.

Projected Sales with DSM and GDP Growth Domestic Billed Sales Growth Projection F2005 to F2006 Growth1 (%)

Domestic Billed Sales Growth Projection F2005 to F20061 (GWh)

Real GDP Growth Projection Calendar Year 2004 to 20051 (%)

0.8 395 3.1

Actual Sales and GDP Growth Domestic Sales Growth Estimate F2005 to F20062 (%)

Domestic Sales Growth Estimate F2005 to F2006 (GWh)2

Real GDP Growth Estimate Calendar Year 2004 to 2005 (%)

2.1 1,065 3.6

Notes:

1. Growth projection based on December 2004 Forecast, Appendix K-1, 2006 IEP.


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Exhibit: B-11

2. Growth estimate is based on growth between actual sales for F2005 as

stated in December 2005 Forecast, Appendix K-2, 2006 IEP and LTAP and the forecast of sales for F2006, based on the February 2006 Update.

Please refer to the response to IPPBC IR 1.10.1 for details on the relationship between GDP and sales for the residential, commercial and industrial sector.


Page 1


Exhibit: B-11


1.1.2 Is it correct that Section 1.2.1 states that about 40% of the total variance in Domestic Energy Costs over the past 2 years (i.e. about 40% of $621 million) was due to the variance in the load forecast? Please provide the complete variance analysis of Domestic Energy Costs for each of the years F2005 and F2006, including the impact of changes in the Canadian/US exchange rate.

RESPONSE: Confirmed. An analysis of changes in the Domestic Cost of Energy is provided in Chapter 3, section 3.2, as well as in the Deferral Account Reports in Appendix D and Appendix E. The Deferral Account Reports include the effects of foreign exchange (for example, see Appendix D, Schedule C). The Deferral Account Report as at March 31, 2006 is attached in the response to BCUC IR 1.17.0.


Page 1


Exhibit: B-11

2.0 Reference: Exhibit B-5-1, page 1-4, Section 1.2.2.2, Electricity Demand Growth

1.2.1 This section states that the load for F2007 is forecast to grow by 1.8% and for F2008 by a further 1.3%, after the impact of DSM. How much would these growth forecasts be without the impact of DSM? What is the assumed growth in real GDP that forms the basis for these forecasts?

RESPONSE: The expected growth in the total Domestic Sales forecast between F2006 and F2007, before DSM is 2.9 per cent and the expected growth between F2007 and F2008, before DSM, is 1.9 per cent. For the February 2006 Update, there is no direct assumption of the growth in GDP used to develop the forecast as the forecast reflects 11 months of actual sales and 1 month of forecast. The growth assumptions of real GDP used to develop the Load Forecasts for F2007 and F2008 were 3.1% and 3.1%, respectively.


Page 1


Exhibit: B-11

3.0 Reference: Exhibit B-5-1, page 1-4, Table 1-2

1.3.1 The forecast Operating Expenses for F2006 appear to be about 31% higher than the estimate made in the last RRA ($659 million vs. $504 million). If the F2006 load was only 5% higher than forecast, why are the Operating Expenses 31% higher? Please provide a complete variance analysis to explain the difference.

RESPONSE: The F2006 forecast amount of $659 million includes the following one-time and non-recurring costs: ($ millions) First Nations provision for potential settlements 88.0 Mountain Pine Beetle (was not included in F06 RRA) 6.6 Environmental costs 3.7 Settlement of Disputes 7.0 Correction of Variable Pay Accrual 14.0 Standard Labour Rate variances 8.2 Lower Non-Current Service Pension Costs (9.2) Site C expenditures 4.2 ABSU Permanent Pricing Methodology payment 6.0 Total 128.5 Excluding these items, operating costs were $530.5 million which is a 5.2 per cent increase from the F06 RRA. This increase is in line with the percent increase in load from the F06 RRA to the F2006 forecast. For further discussion on the increase in operating expenses, please refer to sections 2.2.2, 6.7, 7.4.2, and 8.7.3.


Page 1

Response issued August 1, 2006 British Columbia Hydro & Power Authority BC Hydro F07/F08 Revenue Requirements Application

Exhibit: B-11

4.0 Reference: Exhibit B-5-1, page 1-15, Section 1.4.2, Capital Plan Requests

1.4.1 This section states that the proposed capital plan expenditures are in the interest of ratepayers. What financial tests are applied to support the choice of these expenditures in preference to choosing more IPP power or more DSM? Is there a single financial test that is applied to all these alternative resources?

RESPONSE: At a high level, the 2006 IEP provides justification for certain capital plan expenditures in the F07/F08 RRA that affect BC Hydros supply-demand balance. Section 8.2 of the LTAP (Exhibit B1-A in the 2006 IEP and LTAP proceeding) sets out the specific orders sought for capital plan expenditures, which have their justification in the IEP. The capital plan expenditures in section 1.4.2 of the F07/F08 RRA, however, extend beyond those expenditures that have their basis in the IEP or are otherwise meant to address BC Hydros supply-demand balance.

Please refer to the BC Hydro response to IPPBC IR 1.12.1 in the 2006 IEP and LTAP proceeding (attached) for a description of the modeling process employed in the IEP to provide a high level economic assessment of the system impacts of various portfolios of resource options that could meet customers requirements.

BC Hydros project evaluation evidence (Exhibit B-11) filed in the 2006 IEP and LTAP proceeding and section 8.5 in the 2006 IEP (Exhibit B1-A) provide further guidance on BC Hydros economic evaluation of DSM, Resource Smart and IPP projects.

Independent Power Producers of British Columbia Information Request No. 1.12.1 Dated: June 5, 2006 British Columbia Hydro & Power Authority

Page 1

Response issued July 5, 2006 British Columbia Hydro & Power Authority 2006 IEP & LTAP Application

Exhibit: B-10-1

12.0 Reference: Exhibit B-1A, page 4-28

This section describes a variety of different types of assets that are included in the load resource balance, including: DSM, existing EPAs and planned resources from the F2006 Call, Heritage Assets, and Resource Smart projects.

1.12.1 Please provide the financial or economic models that are used to evaluate each of these different types of assets to demonstrate how they are all evaluated on equal terms, in spite of their many obvious differences. Specifically, please provide the economic model that evaluates a Heritage Asset project like Site C on the same basis as a DSM or Resource Smart project, or on the same basis as an IPP is evaluated.

RESPONSE: The 2006 IEP analysis provides a high level economic assessment of different portfolios of resources each designed to meet customers requirements. Within each portfolio, resources are analyzed on an aggregate basis using the HYSIM and MAPA models that take into account individual resource attributes. This analysis has resulted in the actions presented in the LTAP. As described in the response to JIESC IR 1.5.5, MAPA is a tool used in the portfolio analysis, including the costing of each portfolio, as well as the performance with respect to other attributes being analyzed. MAPA is not used to rank, select or reject projects or pick individual projects. As BC Hydro implements the LTAP, it will utilize a process as described in Section 8.5 of the LTAP to assess resource costs and impacts. An example of this process is shown in the response to CPC IR 1.2.6 which contains the results of the Aberfeldie analysis. Please also refer to the response to BCUC IR 2.305.3 for a discussion of discount rates, etc., that were used to ensure that all types of projects are evaluated on a consistent basis for the purposes of building and comparing portfolios of resources.

IPPBC IR 1.4.1Attachment 1


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Exhibit: B-11

5.0 Reference: Exhibit B-5-1, page 2-15, Section 2.2.7, Trade Income

1.5.1 Why does BC Hydro compare the F2007 Trade Income ($135 million) to the last RRA forecast ($91 million), when there is a more recent estimate for the F2006 actual ($190 million)? Why is the F2007 Trade Income expected to be $55 million lower than the F2006 amount?

RESPONSE: Please see the response to BCUC IR 1.284.0.


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Exhibit: B-11

5.0 Reference: Exhibit B-5-1, page 2-15, Section 2.2.7, Trade Income

1.5.2 This section mentions higher returns on longer-term deals not previously held. Please provide details of these longer-term deals, including the source or destination of the electricity, the fuel type, the duration of the contract, and the price indexing method.

RESPONSE: For the reasons set out in the response to BCUC IR 1.284.0 the requested information has not been provided.


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Exhibit: B-11

6.0 Reference: Exhibit B-5-1, page 2-18, Section 2.3.2, Deferral Account Disposition

1.6.1 Why should a 4-year amortization be preferable to any other period? What is the periodicity of the underlying business cycle that affects these accounts?

RESPONSE: Please refer to the response to BCUC IR 1.228.4.


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Exhibit: B-11

7.0 Reference: Exhibit B-5-1, page 2-47 to 2-49, Schedules 2-10 to 2-12, Load Forecast History

1.7.1 Are the Forecasts listed in these tables always from the immediately preceding year to the Actuals (i.e. one year ahead forecasts)? Are the years calendar or fiscal years?

RESPONSE: Please refer to the responses to BCUC IRs 1.20.1 and 1.20.2.


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Exhibit: B-11


1.7.2 If the volumes are on a billed basis, how is it that they do not include the impact of DSM?

RESPONSE: The footnote contained in Schedules 2-10 to 2-12 could have been more clearly expressed as follows: The forecasts and actual sales values shown in this schedule are on a billed sales basis and by definition include the impact of DSM, and exclude losses.


Page 1


Exhibit: B-11


1.7.3 Schedule 2-12 indicates that the forecast for Large Industrial GWh for 2005 was only off by 1.9%, but the statement in section 1.2.1 (on page 1-2) indicated the error was 10%. What causes this discrepancy?

RESPONSE: The variance of 1.9 per cent, from Schedule 2-12, is based on the difference between the forecast for F2005, based on the December 2004 Load Forecast, and actual sales for Large Industrial class for F2005. The statement on page 1-2 of the application reflects the difference between the forecast for the Large Industrial sales for F2005, based on the December 2003 Load Forecast, and the actual sales for this sector for F2005. It was the December 2003 Forecast that was used as the basis for the F05/F06 RRA.


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Exhibit: B-11

8.0 Reference: Exhibit B-5-1, page 2-55, Schedules 2-18, Return on Equity

1.8.1 Please explain the term Deferred revenue listed under Deferred Credits, and exactly what transactions give rise to this amount. At what point in time will this revenue no longer be deferred?

RESPONSE: Revenues collected in advance of the earnings process are recorded as deferred revenue, a liability account, and recognized as income in future periods when the earnings process has been completed. The deferred revenue listed under Deferred Credits in Schedule 2-18 consists principally of amounts received by BC Hydro under the Skagit River Agreements which commenced in 1986. Annual fixed payments are received from Seattle City Light under this agreement up to and including December 31, 2020 (F2021). These payments are deferred and included in income as revenue on an annuity basis over the energy delivery period, which is scheduled to end January 1, 2066. Other deferred revenue consists mainly of amounts received from transmission cell site customers. These customers are billed once a year, in January, for services to be provided for the year. The revenue related to the Skagit River Agreements will no longer be deferred after F2066.


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Exhibit: B-11

9.0 Reference: Exhibit B-5-1, page 3-2, Table 3-1, Cost of Energy, F2006 to F2008

1.9.1 Is it correct that the energy costs forecast for F2007 were based on the assumption of 93% of average system water inflows?

RESPONSE: Yes.


Page 1


Exhibit: B-11

9.0 Reference: Exhibit B-5-1, page 3-2, Table 3-1, Cost of Energy, F2006 to F2008

1.9.2 If the F2007 cost was adjusted for the freshet prices experienced in May and June 2006, how much would the annual energy cost change?

RESPONSE: The forecast F2007 energy cost will be revised to reflect the actual market prices for the first few months of the fiscal year in the evidentiary update to the application.


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Exhibit: B-11

10.0 Reference: Exhibit B-5-1, page 3-3, Table 3-2, Domestic Sales Volume, F2006 to F2008

1.10.1 Is it correct that this table is indicating an increase in Total Domestic Sales of only 1.9 per cent for F2007 (compared to the latest forecast for F2006) and a further increase of only 1.3 per cent for F2008? Is it also correct that the provincial economic growth assumption (real GDP) is 3.1 per cent for each of those years (according to Table 2-8 on page 2-26)? Given the recent forecast errors, does this relationship to GDP growth seem reasonable?

RESPONSE: The forecast increase for Total Domestic Sales, as shown in Table 3-2 between F2006 and F2007, is 1.8 per cent. The increase in the forecast between F2007 and F2008 is 1.3 per cent. For the February 2006 Update, there is no direct assumption of the growth in GDP used to develop the forecast as the forecast reflects 11 months of actual sales and 1 month of forecast. The provincial economic growth assumptions (i.e. real GDP) for F2007 and F2008 that were used to develop February 2006 Update are provided in the table below.

Calendar Year

Real GDP Growth

(per cent) 2007 3.1 2008 3.1

In BC Hydros forecasting methodology, there is not a one to one translation of the growth in the GDP forecast to the growth in the forecast of total domestic sales. The forecasts are done by using separate models for the residential, commercial and industrial sectors. Forecast for sales to the other utilities are also developed and combined with the sector forecast to develop a forecast for total domestic sales. The models use various drivers such as housing starts, projections for use rates and GDP. For those sector models that use GDP as a direct driver of the forecast (i.e. commercial and industrial), BC Hydro believes that there is a strong relationship between sales and GDP.


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Exhibit: B-11

The relationship between BC GDP and commercial sector sales (GWh) is shown on page. 61 of Appendix K-2 of the 2006 IEP and LTAP. The relationship between BC GDP and industrial sector sales (GWh) is shown in Appendix K-2, pages 63-65. No direct relationship is estimated between BC GDP and residential sales. The forecast of residential sales is based on the forecast of accounts and use per account.


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Exhibit: B-11

11.0 Reference: Exhibit B-5-1, page 3-7, Section 3.2.3.2, System Storage and Section 3.2.3.3 Operating Plan Summary

1.11.1 Please update the tables provided in response to IPPBC IR 1.80.3 in the BC Hydro RRA 2004/05 and 2005/06. Please include reservoir levels in both feet and GWh above the minimum level. Please add to the tables the corresponding annual inflows as a percent of normal.

RESPONSE: The following tables are updated to include the data from 2004 and 2005.

Water Year inflow as % of 1971-2000 normal inflow

GMS MCA 1961 103% 113% 1962 101% 98% 1963 104% 105% 1964 129% 100% 1965 96% 105% 1966 108% 111% 1967 101% 128% 1968 103% 109% 1969 84% 105% 1970 87% 90% 1971 89% 101% 1972 117% 122% 1973 100% 83% 1974 104% 111% 1975 89% 94% 1976 116% 124% 1977 100% 88% 1978 71% 97% 1979 96% 94% 1980 72% 93% 1981 110% 106% 1982 97% 107% 1983 95% 96% 1984 103% 91% 1985 96% 85% 1986 89% 100% 1987 109% 95% 1988 111% 91% 1989 87% 94%


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Exhibit: B-11

Water Year inflow as % of 1971-2000 normal inflow

GMS MCA 1990 107% 108% 1991 90% 120% 1992 115% 96% 1993 99% 82% 1994 100% 95% 1995 92% 95% 1996 125% 109% 1997 123% 111% 1998 90% 105% 1999 107% 107% 2000 97% 98% 2001 109% 80% 2002 120% 99% 2003 98% 90% 2004 95% 97% 2005 109% 97%

Kinbasket Reservoir - Elevation/Storage by Water Year (October to September)

Water Year Ending

Max Elevation (feet)

Min Elevation (feet)

Max Storage (GWh)

Min Storage (GWh)

1974 2409.13 2157.40 fill period fill period 1975 2407.57 2281.65 fill period fill period 1976 2474.91 2403.52 fill period fill period 1977 2474.43 2414.64 10492 52031978 2475.78 2397.95 10627 39901979 2474.00 2403.75 10449 43961980 2470.17 2387.30 10068 32841981 2472.37 2406.10 10285 45661982 2473.06 2413.25 10354 50981983 2474.31 2415.00 10479 52311984 2472.28 2387.60 10275 33031985 2470.54 2385.91 10103 31971986 2475.39 2401.71 10587 42511987 2466.24 2388.48 9684 33591988 2453.87 2365.16 8518 20001989 2454.56 2345.21 8581 10361990 2473.95 2389.60 10442 34311991 2475.75 2389.34 10624 34141992 2467.49 2389.70 9805 34381993 2442.88 2340.40 7530 8241994 2437.89 2350.82 7097 12921995 2470.73 2374.77 10123 25271996 2475.43 2404.23 10591 44311997 2474.54 2383.60 10502 30521998 2475.36 2386.42 10584 32281999 2474.64 2373.55 10511 2458


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Exhibit: B-11

Kinbasket Reservoir - Elevation/Storage by Water Year (October to September)

Water Year Ending



Max Storage (GWh)

Min Storage (GWh)

2000 2465.26 2384.51 9589 31092001 2449.08 2344.98 8082 10262002 2465.06 2337.24 9570 6882003 2459.58 2342.75 9049 9272004 2450.52 2357.15 8212 15942005 2462.44 2378.25 9319 2729

Note: No power was produced prior to the Water Year Ending 1977. This period represents the initial filling of the reservoir.

Williston Reservoir - Elevation/Storage by Water Year (October to September)

Water Year Ending



Max Storage (GWh)

Min Storage (GWh)

1974 2205.94 2172.94 18630 106651975 2204.56 2167.89 18259 96091976 2206.08 2166.72 18667 93701977 2203.97 2172.83 18101 106421978 2200.99 2162.18 17315 84641979 2184.15 2149.34 13162 60851980 2184.56 2152.31 13257 66111981 2205.18 2163.42 18424 87081982 2204.80 2163.78 18322 87801983 2205.57 2186.51 18531 137151984 2205.28 2177.73 18451 117061985 2204.98 2172.18 18372 105031986 2198.38 2155.53 16639 71981987 2197.72 2162.94 16471 86141988 2195.92 2151.73 16013 65071989 2184.69 2146.95 13287 56701990 2195.36 2149.43 15873 61001991 2196.20 2155.94 16085 72741992 2196.61 2159.63 16188 79711993 2195.98 2153.36 16028 68021994 2193.04 2148.65 15295 59651995 2201.61 2162.60 17477 85471996 2201.25 2173.00 17382 106781997 2201.90 2147.15 17554 57041998 2203.38 2168.27 17944 96881999 2194.61 2152.66 15684 66742000 2192.09 2155.22 15061 71412001 2199.37 2152.06 16895 65672002 2204.99 2159.35 18373 79182003 2200.95 2161.17 17306 82682004 2193.13 2161.03 15317 82402005 2204.20 2169.65 18163 9972


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Exhibit: B-11

11.0 Reference: Exhibit B-5-1, page 3-7, Section 3.2.3.2, System Storage and Section 3.2.3.3 Operating Plan Summary

1.11.2 In each of F2000 to F2006 how much was drawn from storage for domestic purposes? For export? Has there been any trend in terms of withdrawals from storage since 1986 e.g. reduction in operation of Burrard, withdrawals for export purposes, etc.?

RESPONSE: The pattern of changes in system storage for the period F1994 to F2006 is provided in the table below, along with the allocation of purchases and sales between domestic and trade, which became available following the implementation of the Transfer Price Agreement in 2003.

Net Imports to System

Net Imports to Trade Account

Net Imports to Domestic

Burrard Production

BC Hydro Hydroelectric Production

System Storage (End of Period)

System Storage (Change)

GWh GWh GWh GWh GWh GWh GWhF1994 600 3300 40100 8000F1995 -900 3900 39900 11800 3800F1996 -200 3600 41700 16400 4600F1997 -7400 500 53300 10000 -6400F1998 -7900 1400 50500 14600 4600F1999 -2400 3200 47500 10600 -4000F2000 -3500 1300 50100 11200 600F2001 1700 4000 45500 9300 -1900F2002 5200 2700 40500 10100 800F2003 1800 100 47600 10100 0F2004 5100 -200 5300 100 44800 10200 100F2005 7400 500 6900 500 41800 13800 3600F2006 4400 -1500 5900 0 47200 14400 600Notes:

1. Net Imports includes market purchases from Alberta, US, and within-BC IPPs (value is negative if net exports)

2. Net Imports to Trade Account includes only electricity imports - trade account deposits due

to thermal operations are omitted

3. System Storage is storage in Williston and Kinbasket Reservoirs

As can be seen in the table, the net change in storage over the last five fiscal years has been positive each year, indicating storage deposits rather than withdrawals. During this same period, the system has been a net purchaser of energy. Burrard is typically operated as though it were a market resource, i.e. it is used to displace market purchases when it is economic to do so. Without Burrard


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Exhibit: B-11

energy, the current system is in a resource deficit that requires the purchase of an average of approximately 3,800 GWh per year under normal inflow conditions.

Storage is operated to maximize its long-term value to the ratepayers. Over the long-term, storage deposits and withdrawals will be approximately equal. On a shorter time frame storage may be used to shift energy sales and purchases (including Burrard production) between periods, but ultimately any net deficiency or surplus of energy in the system relative to the load must be either purchased from or sold to the market.

Providing data prior to F1994 would require a significant effort as data is not readily available in this format. Given the limited relevance of this data, BC Hydro declines to provide it.


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Exhibit: B-11

12.0 Reference: Exhibit B-5-1, page 5-15, Compensation and Performance

1.12.1 Table 5-3 outlines the Variable Pay Targets. Of the targets listed in this table, what proportion was actually paid out in F2005 and F2006.



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Exhibit: B-11


1.12.2 Please provide more details of the executive compensation program, including pensions.

RESPONSE: The following documents are attached:

CEO Executive Contract;

Appendix 1: Compensation Structure for Vice Presidents;

Appendix 2: Executive Pension Plan; and

Appendix 3: Summary of BC Hydro Executive Benefit Plan.

British Columbia Hydro & Power Authority, 333 Dunsmuir Street, 15th floor, Vancouver, BC V6B 5R3www.bchydro.com

October 28, 2003

Mr. B. EltonDunsmuir 18

Dear Bob:

Re: Employment

This letter renews and amends your existing contract between British Columbia Hydro andPower Authority (BC Hydro) and yourself on the following terms:

A. JOB DESCRIPTION

Effective November 10, 2003 you will serve as the Chief Executive Officer of BC Hydro. Asthe Chief Executive Officer, you will report directly to the Chair of BC Hydros Board ofDirectors.

You acknowledge that BC Hydro must make changes on a continuing basis in order toefficiently and effectively operate its business. As a result, you agree that BC Hydro mayalter its methods of doing business, its corporate structure, and the reporting relationshipsfrom time to time. These changes may result in occasional changes to your job duties, titleand reporting relationship. Provided that these changes are not so significant as tofundamentally alter the terms of your employment, you agree that such changes may bemade and that you accept them as a normal incident of your employment contract.

B. SALARY AND INCENTIVE PAY

Effective November 10, 2003 your salary will be $295,000 per annum, paid bi-weekly.Subject to Board approval, this salary will be reviewed periodically in relation our market andpeer companies with comparable positions.

In addition to your annual salary, you are eligible for variable incentive pay with a target of30 percent and a maximum of 60 percent of your annual salary based upon an annualnegotiated contract with the Chair. The determination of the amount to be paid will bebased upon your individual Incentive Contract. This variable pay is included in annualincome for pension purposes. That is, your base salary plus your variable incentive pay willbe considered the same as your base salary for pension calculation purposes. Please referto the Supplemental Pension for Executives document that is part of your totalcompensation package.

C. EMPLOYMENT POLICIES

BC Hydros Corporate Policy Statements (CPSs) form part of the terms and conditions ofyour employment with BC Hydro. We ask that you review them from time to time as you areexpected to understand and adhere to all corporate policies. They form a part of youremployment contract notwithstanding that they may be revised, amended, or added to fromtime to time.


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D. BENEFITS

BC Hydro will provide you with coverage for health and welfare benefits at no cost to you, asoutlined in the attached document Benefit Coverage for Executives.

You will receive pension benefits under the BC Hydro Pension Plan and the SupplementalPlan for Executives. A copy of the Plan and Supplemental Pension documents are availablefor your review, since they form part of the terms and conditions of your employment withBC Hydro.

E. ANNUAL VACATION

Your vacation entitlement will be the same as for BC Hydro M&P employees as set out inM&P Online, available on the Intranet. Recent provincial legislation now requires annualvacation to be used or paid out in the year following the year in which the vacation isearned. Your annual vacation will commence at five weeks.

F. CORE DAYS

You will be eligible for core day benefits equivalent to the M&P package.

G. VEHICLE

You are eligible for a BC Hydro pool car, or $1,100 per month, or you may choose a BCHydro leased vehicle. Please refer to the attached Vehicles for Executives document.

H. EXPENSES

You will be reimbursed for any receipted business expenses in accordance with BC HydroBusiness Travel & Expense Claims Policy and Procedure. In addition, a $500 taxablemonthly executive allowance will be paid to you. This amount may be revised by BC Hydro.

I. TERMINATION PROVISIONS

If you wish to terminate your employment with us, we ask that you give us at least onemonths notice.

Should BC Hydro terminate your employment for reasons other than cause, you will beprovided with 12 months of notice if you are terminated in the first year of employment. Inaccordance with the Public Sector Employers Act, if you are terminated in any subsequentyear, the notice will be increased by one month for each year of service, to a total maximumof 18 months, recognizing that you joined BC Hydro on December 5, 2001.

In the event of your termination, you will not be eligible for a lump sum payout of anyaccumulated CORE Days, notwithstanding any Corporate Policy Statement or M&Ppackage provision to the contrary.


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If you are in agreement with the foregoing terms, I ask that you sign your agreement on theenclosed copy of this letter and return it to me.

Yours truly,

BRITISH COLUMBIA HYDRO AND POWER AUTHORITY

per:

Larry BellChair

I HAVE READ, UNDERSTOOD AND AGREE WITH THE FOREGOING. I ACCEPTEMPLOYMENT ON THE ABOVE TERMS AND CONDITIONS.

Dated the _____ day of , 2003

__________________________________Name

__________________________________Signature

__________________________________Witness



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Exhibit: B-11


1.12.3 What is the average length of service of employees who retired in F2005 or F2006

RESPONSE: Average Length of Service of Retirees

Fiscal YearAverage Service (Years)

F2005 29.3F2006 30.1Overall Average 29.7

Excludes temporary employees and excludes Powerex, Powertech and CBU.


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Exhibit: B-11


1.13.1 In its October 29, 2004 Revenue Requirements Decision the BCUC said: The Commission Panel approves the initial $1.9 million sought for F2005 for Stage 1 Cabinet approval of Site C expenditures and denies approval for $5.5 million sought for F2006. BC Hydro may apply for approval of F2006 expenditures as contemplated by BC Hydros proposed approach to the investigation of Ste C. Please provide an itemized list of all expenditures in excess of $5,000 with respect to any item or person, internal and external which were made with respect Site C in F2005. Please provide copies of any reports, terms of reference, studies or the like that have been prepared including without limitation electronic and hard copies of any financial model(s).

RESPONSE: BC Hydro has assigned internal staff to assist in the completion of Stage 1 work. In addition, there are a number of consultants and contractors performing various aspects of the project work in the three identified time periods. The list of consultants and a brief description of the work they have been or are performing is provided below. While for the purposes of responding to this IR, BC Hydro assumed that Stage 2 would begin in October of 2006, the decision as to whether and when to proceed beyond the current stage would be taken by the government. Stage 1, June 2004 to March 2006 The external consultants/third parties that BC Hydro has used to date range from individuals contracted to provide specific services to international environmental and engineering firms. Environmental firms that have conducted various baseline environmental studies and related work (such as the development of terms of reference) include Pottinger Gaherty Environmental Consultants Ltd., Golder Associates Ltd., Keystone Wildlife Research Ltd., Jacques Whitford Ltd., AMEC Americas Ltd., Triton Environmental Consultants Ltd., LGL Limited, Lions Gate Consulting Inc. and Zig Hathorn and Associates.


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Exhibit: B-11

A design review was performed by Klohn-Crippen Berger Ltd. and SNC Lavalin. A review of the project cost estimate was performed by the Washington Group International. Financial, project management and engineering assistance was provided by a number of consultants which included Utility Contract Services, Gordon D. Fonstad, Energy Vision, UBC Engineering and Michael Weiss. Various other consultants with total billings under $5,000 provided minor support and assistance. Third parties have also provided general business support and administrative services (Accenture Business Services for example). Finally, BC Hydro has retained several consultants, the names of which and services to be provided cannot be disclosed at this time, because to do so may constitute a waiver of privilege. Stage 1, April 2006 to September 2006 Much of the work referred to for the period June 2004 to March 2006 continues in F2007. Additional design review work is planned, and environmental studies are ongoing. Many of the same firms noted above have scopes of work that continue in this period. Stage 2, October 2006 to July 2007 In addition to ongoing technical and environmental work, additional external consultant/third party services are anticipated for the period of October 2006 to July 2007. Services are anticipated to be secured from various independent advisors. The ultimate scope of work that would be performed will in part be the subject of input from stakeholders and First Nations. In light of BC Hydro's decision to not seek recovery in rates of any costs incurred in respect of Site C in F2005 or F2006 it is BC Hydro's view that the more specific information requested is not relevant to this proceeding. Moreover, providing the level of detail requested would, in light of the significant number of IRs BC Hydro is responding to and the lack of relevance of such information, impose an unreasonable burden on BC Hydro. Finally, providing the requested information, because it is irrelevant, would have the effect of unnecessarily cluttering an already very large and increasingly unwieldy record. For these reasons BC Hydro declines to provide information at the level of detail requested.


Page 1


Exhibit: B-11

14.0 Reference: Exhibit B-5-1, page 5-56 Table 5-21

1.14.1 In its October 29, 2004 Revenue Requirements Decision the BCUC said: The Commission Panel approves the initial $1.9 million sought for F2005 for Stage 1 Cabinet approval of Site C expenditures and denies approval for $5.5 million sought for F2006. BC Hydro may apply for approval of F2006 expenditures as contemplated by BC Hydros proposed approach to the investigation of Ste C. Did BC Hydro seek BCUC approval before making ay of the expenditures listed under the heading F2006 Forecast in Table 5-21? If not, why not? Please provide an itemized list of all expenditures in excess of $5,000 with respect to any item or person, internal and external which were made with respect Site C in F2006. i.e. in more detail than Table 5-21. Please provide copies of any reports, terms of reference, studies or the like that have been prepared.

RESPONSE: Please refer to the response to IPPBC IR 1.13.1.


Page 1


Exhibit: B-11

14.0 Reference: Exhibit B-5-1, page 5-56 Table 5-21

1.14.2 Please provide an itemized list of all expenditures in excess of $5,000 with respect to any item or person, internal and external which are expected to be made with respect Site C in F2007 and F2008. i.e. in more detail than Table 5-21. Please provide copies of any reports, terms of reference, studies or the like that have been prepared.



Page 1


Exhibit: B-11

15.0 Reference: Exhibit B-5-1, page 5-56, Section 5.11.3, Site C Stage 1 to Stage 3 costs

1.15.1 This section is requesting $10 million to be spent in F2007. What is the status of engineering and design drawings for the Site C project? How much was spent on these in the past and was that amount expensed or capitalized? Will any of that design work have to be redone? Will that sunk cost be included in the project costs going forward?

RESPONSE: BC Hydro is basing its work on the 1991 Design, which in turn was based to a great extent on the 1981 Design. Wherever possible, BC Hydro is relying on previously completed work. All work performed through F2006 was expensed. Approximately $3.9 million was spent in F2005 and F2006, although this was for work other than the creation of engineering and design drawings. Only costs incurred in F2007 and beyond will be included in the project cost going forward. BC Hydro notes that it is not seeking recovery of F2007 and F2008 expenditures in the F07/F08 RRA, and is requesting that the BCUC approve the creation of a regulatory asset to hold these investigation and evaluation costs until such time as either the project is brought into service or discontinued, in which case recovery of those costs from ratepayers may be sought.


Page 1


Exhibit: B-11


1.16.1 Please provide details of a more robust management team and oversight structure are planned.



Page 1


Exhibit: B-11


1.16.2 Please identify the studies, insofar as they havent been previously itemized, referred to in lines 14-16.



Page 1


Exhibit: B-11

17.0 Reference: Exhibit B-5-1, page 7-52, Section 7.12.1, Line of Business Support Units

1.17.1 Please explain the change in capital overhead methodology mentioned in line 12.

RESPONSE: Please refer to the responses to BCUC IR 1.239.1 and BCUC IR 1.275.2 for an explanation of this change.


Page 1


Exhibit: B-11

18.0 Reference: Exhibit B-5-1, page 8-17, lines 17-19, Distributions Planning Process

1.18.1 This section states that Distribution uses an iterative process to select those projects and programs that maximize contributions towards objectives. Please explain the financial tests that are applied to allow BC Hydro to choose between Distribution capital projects, Generation capital projects, IPP projects, Transmission projects, or DSM projects. How are all these different investment options evaluated on a consistent and balanced basis?

RESPONSE: Most of Distributions capital expenditures are not incurred to meet BC Hydros load/resource balance, with the exception of DSM. As a result, there are no other options for most Distribution projects. DSM expenditures are compared with other options to meet the load/resource balance in the IEP process. Please refer to the response to IPPBC IR 1.12.1 from the 2006 IEP and LTAP proceeding (attached).

Independent Power Producers of British Columbia Information Request No. 1.12.1 Dated: June 5, 2006 British Columbia Hydro & Power Authority

Page 1

Response issued July 5, 2006 British Columbia Hydro & Power Authority 2006 IEP & LTAP Application

Exhibit: B-10-1

12.0 Reference: Exhibit B-1A, page 4-28

This section describes a variety of different types of assets that are included in the load resource balance, including: DSM, existing EPAs and planned resources from the F2006 Call, Heritage Assets, and Resource Smart projects.

1.12.1 Please provide the financial or economic models that are used to evaluate each of these different types of assets to demonstrate how they are all evaluated on equal terms, in spite of their many obvious differences. Specifically, please provide the economic model that evaluates a Heritage Asset project like Site C on the same basis as a DSM or Resource Smart project, or on the same basis as an IPP is evaluated.

RESPONSE: The 2006 IEP analysis provides a high level economic assessment of different portfolios of resources each designed to meet customers requirements. Within each portfolio, resources are analyzed on an aggregate basis using the HYSIM and MAPA models that take into account individual resource attributes. This analysis has resulted in the actions presented in the LTAP. As described in the response to JIESC IR 1.5.5, MAPA is a tool used in the portfolio analysis, including the costing of each portfolio, as well as the performance with respect to other attributes being analyzed. MAPA is not used to rank, select or reject projects or pick individual projects. As BC Hydro implements the LTAP, it will utilize a process as described in Section 8.5 of the LTAP to assess resource costs and impacts. An example of this process is shown in the response to CPC IR 1.2.6 which contains the results of the Aberfeldie analysis. Please also refer to the response to BCUC IR 2.305.3 for a discussion of discount rates, etc., that were used to ensure that all types of projects are evaluated on a consistent basis for the purposes of building and comparing portfolios of resources.



Page 1


Exhibit: B-11

19.0 Reference: Exhibit B-5-1, page 8-28, Table 8-8 as revised by Exhibit B-5-6

1.19.1 Please clarify. Does this table indicate that BC Hydro plans to spend $2.875 million on the F2007 Call for Energy, over the next two fiscal years? If so, why does the majority of it fall after F2007? For comparison purposes, how much is the estimated spending on the F2006 Call during F2006 and F2007?

RESPONSE: Yes, this table indicates BC Hydro does plan to spend $2.875 million on the F2007 Call over the next two fiscal years. BC Hydros estimated spending for the F2006 Call in F2006 is $1.15 million and in F2007 it is $0.83 million. Please refer to the response to BCUC IR 1.42.1 for further information on the F2006 Call.


Page 1


Exhibit: B-11

19.0 Reference: Exhibit B-5-1, page 8-28, Table 8-8 as revised by Exhibit B-5-6

1.19.2 Please provide full details of the electricity purchase contract and evaluation criteria that will be used for the F2007 Call.

RESPONSE: BC Hydro has not yet designed the electricity purchase contract or the evaluation criteria that will be used for the F2007 Call. Stakeholder input will be sought on all major elements as part of designing the F2007 Call.


Page 1


Exhibit: B-11

20.0 Reference: Exhibit B-5-2, Appendix C, page 13, Schedule 4.0, Domestic Cost of Energy

1.20.1 Please explain the terms Market Purchases to Non-Heritage, Net Purchases from Powerex, Net Sales to Powerex (Displaced Hydro), and Exchange net. Why do some of these categories show dollar amounts but no GWh amounts, or vice versa?

RESPONSE: Market Purchases to Non-Heritage: Heritage Energy is limited to a volume of 49,000 GWh by the Heritage Contract. Purchases above this amount are allocated to Non-Heritage Energy. Schedule 4.0 shows the purchases on a gross basis in Heritage Energy and shows the volume and cost allocated to Non-Heritage Energy. Market Purchases to Non-Heritage has corresponding dollar and volume amounts. Net Purchases from Powerex: BC Hydros net trade account activity with Powerex is recorded as either net purchases or net sales. The costs of the net purchases are shown on Schedule 4.0 on line 14. The revenue from the net sales are recorded as Intersegment Revenues and are shown on Appendix C, Schedule 3, line14. . Net Sales to Powerex (Displaced Hydro): Please refer to the response to BCUC IR 1.40.2 for a definition of Displaced Hydro. Exchange net: Please refer to the response to BCUC IR 1.122.0.


Page 1


Exhibit: B-11

20.0 Reference: Exhibit B-5-2, Appendix C, page 13, Schedule 4.0, Domestic Cost of Energy

1.20.2 What is the difference between Net Sales to Powerex (Displace Hydro) shown in this Schedule, and Net Sales to Powerex Future Use as shown in Appendix D, Schedule C?

RESPONSE: The former is a measure of volume while the latter is a measure of the corresponding revenue.


Page 1


Exhibit: B-11

21.0 Reference: Exhibit B-5-2, Appendix D, Schedule A-2, Consolidated Statement of Operations

1.21.1 Please give details of what transactions have been included in line 40, Regulatory provision for future removal and site restoration costs. Will these amounts be included in the capital costs of any projects for evaluation purposes?

RESPONSE: The regulatory provision for future removal and site restoration costs in line 40 are asset disposal and dismantling costs. These are summarized in the following table.

($ million) F2005 Actual Distribution System 9 Generation Facilities 2 Other 2 Total 13

An allowance for asset decommissioning may be included in the evaluation of proposed capital projects when the timing and cost of decommissioning can be reasonably predicted.


Page 1


Exhibit: B-11

22.0 Reference: Exhibit B-5-2, Appendix D, Schedule B, Domestic Cost of Energy

1.22.1 Please explain the meaning of line 44, Net Sales to Powerex. Does this mean that Hydro planned to have 1,550 GWh to sell to Powerex in F2005 but, in fact, purchased 664 GWh from Powerex due to the higher than expected load and lower than expected generation?



Page 1


Exhibit: B-11

22.0 Reference: Exhibit B-5-2, Appendix D, Schedule B, Domestic Cost of Energy

1.22.2 Where is the dollar value that corresponds to the GWh shown on line 44? The only other line that refers to Powerex is line 20 Net purchases from Powerex (Trade Account) and that has no dollar value for the Plan column.

RESPONSE: Line 44 Net Sales to Powerex shows BC Hydros net trade account activity with Powerex in GWh. Net sales are denoted by brackets as is the case for the Plan column. The revenues associated with the sales volumes are recorded under Intersegment Revenues on Schedule A-2, Appendix D, Line 16. These intersegment revenues are further detailed on Schedule D, Appendix D, with sales denoted on line 7.

Transactions between BC Hydro and Powerex are governed by the BC Hydro/ Powerex Transfer Pricing Agreement. Please refer to the attachment to the response to BCUC IR 1.68.0.


Page 1


Exhibit: B-11

23.0 Reference: Exhibit B-5-2, Appendix D, Schedule C, Transfers to HDA and NHDA

1.23.1 Line 50 to 52 refers to forward contracts with Powerex to mitigate commodity risk on domestic energy costs. Please provide copies of any such forward contracts.

RESPONSE: Lines 50 to 52 refer to forward purchases and sales entered into by Generation and Powerex pursuant to the Transfer Pricing Agreement.

Please refer to the response to BCOAPO IR 1.3.1.


Page 1


Exhibit: B-11

24.0 Reference: Exhibit B-5-2, Appendix D, Schedule C-1, Transfers to HDA and

NHDA contd

1.24.1 Line 1 refers to derivatives to manage foreign exchange exposure. Please give details of any such transactions entered into during F2005 or F006, or planned for F2007 or F2008.

RESPONSE: Please refer to the attached table for foreign exchange purchase transactions entered into during F2006.

No specific transactions are planned for F2007 or F2008.

Foreign Exchange Purchase Transactions Hedging Electricity Purchases

Reference Transaction Size (US$) Rate Transaction Date Settlement Date000373 2,700,000 1.22110 04/08/2005 11/21/2005000379 3,500,000 1.21620 04/08/2005 05/23/2006000389 4,500,000 1.25165 04/28/2005 06/20/2005000391 2,000,000 1.24230 04/28/2005 06/20/2006000392 2,000,000 1.24170 04/28/2005 07/20/2006000402 3,300,000 1.24549 05/05/2005 06/20/2005000417 1,400,000 1.25420 05/18/2005 02/21/2006000418 1,200,000 1.25350 05/18/2005 03/20/2006000420 1,300,000 1.25280 05/18/2005 04/20/2006000432 4,700,000 1.25975 05/26/2005 03/21/2006000433 4,800,000 1.25895 05/26/2005 04/20/2006000446 1,600,000 1.23830 06/02/2005 04/20/2006000448 900,000 1.23735 06/02/2005 05/23/2006000476 2,000,000 1.22523 07/06/2005 06/20/2006000477 1,900,000 1.22441 07/06/2005 07/20/2006000510 500,000 1.19470 07/22/2005 05/25/2007000564 1,100,000 1.15902 10/27/2005 06/20/2006000566 1,100,000 1.15813 10/27/2005 07/20/2006000572 1,100,000 1.17165 11/02/2005 06/20/2006000573 1,000,000 1.17070 11/02/2005 07/20/2006000583 900,000 1.18850 11/15/2005 06/20/2006000584 900,000 1.18760 11/15/2005 07/20/2006000585 900,000 1.17960 11/15/2005 05/22/2007000587 900,000 1.17870 11/15/2005 06/20/2007000589 900,000 1.17790 11/15/2005 07/20/2007000593 2,500,000 1.16610 11/23/2005 06/20/2006000594 2,400,000 1.16530 11/23/2005 07/20/2006000595 900,000 1.15870 11/23/2005 05/22/2007000596 1,000,000 1.15810 11/23/2005 06/20/2007000597 1,000,000 1.15750 11/23/2005 07/20/2007000619 1,000,000 1.15120 01/05/2006 05/22/2007000620 1,000,000 1.15060 01/05/2006 06/20/2007000621 1,000,000 1.15000 01/05/2006 07/20/2007000623 1,000,000 1.15960 01/12/2006 04/20/2006000624 1,500,000 1.15865 01/12/2006 05/23/2006000625 1,000,000 1.15785 01/12/2006 06/20/2006000626 1,000,000 1.15715 01/12/2006 07/20/2006000645 1,900,000 1.14927 01/20/2006 05/23/2006000646 1,800,000 1.14851 01/20/2006 06/20/2006000647 1,900,000 1.14770 01/20/2006 07/20/2006000663 1,400,000 1.14035 01/31/2006 05/23/2006000664 1,600,000 1.13959 01/31/2006 06/20/2006000665 1,500,000 1.13877 01/31/2006 07/20/2006000678 600,000 1.13810 02/01/2006 04/25/2006000679 1,400,000 1.13725 02/01/2006 05/25/2006000680 1,400,000 1.13630 02/01/2006 06/27/2006000681 1,400,000 1.13550 02/01/2006 07/25/2006000682 2,300,000 1.14208 02/07/2006 05/22/2007000683 2,500,000 1.14156 02/07/2006 06/20/2007000684 1,500,000 1.14103 02/07/2006 07/20/2007000687 1,000,000 1.14727 02/15/2006 05/22/2007


000688 1,000,000 1.14664 02/15/2006 06/20/2007000689 1,900,000 1.14599 02/15/2006 07/20/2007

Foreign Exchange Purchase Transactions Hedging Gas Purchases

Reference Transaction Size (US$) Rate Transaction Date Settlement Date000372 2,400,000 1.22475 04/08/2005 06/27/2005000374 1,000,000 1.22000 04/08/2005 12/28/2005000375 1,200,000 1.21920 04/08/2005 01/25/2006000376 1,200,000 1.21835 04/08/2005 02/27/2006000377 1,300,000 1.21760 04/08/2005 03/27/2006000378 1,100,000 1.21690 04/08/2005 04/25/2006000380 900,000 1.21480 04/08/2005 07/25/2006000381 1,000,000 1.21410 04/08/2005 08/25/2006000382 1,000,000 1.21310 04/08/2005 09/25/2006000383 900,000 1.21230 04/08/2005 10/25/2006000384 1,100,000 1.21150 04/08/2005 11/27/2006000390 1,900,000 1.24290 04/28/2005 05/25/2006000393 1,100,000 1.24110 04/28/2005 08/25/2006000394 1,100,000 1.24050 04/28/2005 09/25/2006000395 1,100,000 1.24000 04/28/2005 10/25/2006000396 1,000,000 1.23940 04/28/2005 11/27/2006000397 1,000,000 1.23880 04/28/2005 12/27/2006000398 1,100,000 1.23820 04/28/2005 01/25/2007000399 1,100,000 1.23760 04/28/2005 02/26/2007000400 1,900,000 1.23700 04/28/2005 03/26/2007000403 600,000 1.24224 05/05/2005 10/25/2005000404 600,000 1.24043 05/05/2005 12/28/2005000405 600,000 1.23964 05/05/2005 01/25/2006000406 600,000 1.23881 05/05/2005 02/27/2006000407 600,000 1.23746 05/05/2005 04/25/2006000408 900,000 1.23680 05/05/2005 05/25/2006000409 1,000,000 1.23580 05/05/2005 07/25/2006000410 500,000 1.23360 05/05/2005 11/27/2006000411 600,000 1.23300 05/05/2005 12/27/2006000412 500,000 1.23240 05/05/2005 01/25/2007000413 500,000 1.23190 05/05/2005 02/26/2007000414 500,000 1.23130 05/05/2005 03/26/2007000419 900,000 1.25330 05/18/2005 03/27/2006000421 2,600,000 1.24500 05/18/2005 04/25/2007000422 900,000 1.24450 05/18/2005 05/25/2007000423 900,000 1.24420 05/18/2005 06/25/2007000424 900,000 1.24370 05/18/2005 07/25/2007000425 900,000 1.24330 05/18/2005 08/27/2007000426 900,000 1.24300 05/18/2005 09/25/2007000427 900,000 1.24250 05/18/2005 10/25/2007000428 900,000 1.24210 05/18/2005 11/26/2007000429 1,400,000 1.26515 05/26/2005 09/26/2005000430 900,000 1.26420 05/26/2005 10/25/2005000431 1,300,000 1.26325 05/26/2005 11/25/2005000434 900,000 1.25620 05/26/2005 08/21/2006000435 900,000 1.25560 05/26/2005 09/20/2006


000436 900,000 1.25500 05/26/2005 10/20/2006000443 1,100,000 1.24180 06/02/2005 12/28/2005000444 1,100,000 1.24090 06/02/2005 01/25/2006000445 1,100,000 1.23978 06/02/2005 02/27/2006000447 1,100,000 1.23820 06/02/2005 04/25/2006000449 1,200,000 1.23650 06/02/2005 06/26/2006000450 900,000 1.23580 06/02/2005 07/25/2006000451 1,000,000 1.23260 06/02/2005 11/27/2006000471 1,500,000 1.23495 07/06/2005 08/25/2005000472 1,000,000 1.23390 07/06/2005 09/26/2005000473 1,000,000 1.23291 07/06/2005 10/25/2005000474 1,000,000 1.23184 07/06/2005 11/25/2005000475 1,100,000 1.22759 07/06/2005 03/27/2006000488 1,700,000 1.21235 07/22/2005 12/23/2005000493 1,900,000 1.21110 07/22/2005 01/25/2006000494 2,200,000 1.20906 07/22/2005 03/24/2006000495 700,000 1.20920 07/22/2005 03/20/2006000496 1,900,000 1.20790 07/22/2005 04/25/2006000497 1,000,000 1.20570 07/22/2005 06/26/2006000498 2,100,000 1.20590 07/22/2005 06/20/2006000499 1,100,000 1.20470 07/22/2005 07/25/2006000500 2,000,000 1.20485 07/22/2005 07/20/2006000501 500,000 1.20363 07/22/2005 08/25/2006000502 1,000,000 1.20260 07/22/2005 09/25/2006000503 1,000,000 1.20162 07/22/2005 10/25/2006000504 400,000 1.20063 07/22/2005 11/24/2006000505 600,000 1.19970 07/22/2005 12/22/2006000506 700,000 1.19860 07/22/2005 01/25/2007000507 700,000 1.19760 07/22/2005 02/26/2007000508 600,000 1.19660 07/22/2005 03/26/2007000509 700,000 1.19560 07/22/2005 04/25/2007000511 500,000 1.19370 07/22/2005 06/25/2007000512 500,000 1.19270 07/22/2005 07/25/2007000513 500,000 1.19180 07/22/2005 08/24/2007000514 500,000 1.19090 07/22/2005 09/25/2007000515 500,000 1.19000 07/22/2005 10/25/2007000516 500,000 1.18910 07/22/2005 11/26/2007000518 2,200,000 1.19448 08/11/2005 02/24/2006000519 700,000 1.19350 08/11/2005 03/24/2006000520 1,900,000 1.19235 08/11/2005 04/25/2006000521 1,500,000 1.19125 08/11/2005 05/25/2006000522 1,100,000 1.19025 08/11/2005 06/23/2006000523 1,000,000 1.18920 08/11/2005 07/25/2006000524 500,000 1.18810 08/11/2005 08/25/2006000525 1,200,000 1.18395 08/11/2005 12/22/2006000526 1,200,000 1.18280 08/11/2005 01/25/2007000527 600,000 1.18180 08/11/2005 02/23/2007000528 500,000 1.18080 08/11/2005 03/23/2007000529 600,000 1.17970 08/11/2005 04/25/2007000559 2,000,000 1.16446 10/27/2005 12/28/2005000560 2,100,000 1.16351 10/27/2005 01/25/2006000561 1,800,000 1.16156 10/27/2005 03/28/2006000562 1,900,000 1.16069 10/27/2005 04/25/2006000563 1,500,000 1.15980 10/27/2005 05/25/2006


000565 2,100,000 1.15882 10/27/2005 06/27/2006000567 2,000,000 1.15799 10/27/2005 07/25/2006000568 800,000 1.15708 10/27/2005 08/25/2006000569 800,000 1.15617 10/27/2005 09/25/2006000570 700,000 1.15529 10/27/2005 10/25/2006000571 800,000 1.15442 10/27/2005 11/27/2006000574 800,000 1.16610 11/02/2005 12/27/2006000575 900,000 1.16530 11/02/2005 01/25/2007000576 1,500,000 1.16450 11/02/2005 02/26/2007000577 1,300,000 1.16380 11/02/2005 03/26/2007000578 1,500,000 1.16290 11/02/2005 04/25/2007000580 3,600,000 1.19205 11/15/2005 02/27/2006000581 1,500,000 1.19115 11/15/2005 03/27/2006000582 1,700,000 1.19025 11/15/2005 04/25/2006000586 1,200,000 1.17945 11/15/2005 05/25/2007000588 1,200,000 1.17860 11/15/2005 06/25/2007000590 1,200,000 1.17790 11/15/2005 07/20/2007000601 1,300,000 1.14240 12/06/2005 05/25/2007000602 1,400,000 1.14170 12/06/2005 06/25/2007000603 1,200,000 1.14100 12/06/2005 07/25/2007000604 1,300,000 1.14030 12/06/2005 08/27/2007000605 1,300,000 1.13960 12/06/2005 09/25/2007000606 1,200,000 1.13900 12/06/2005 10/25/2007000607 1,300,000 1.13830 12/06/2005 11/26/2007000616 2,200,000 1.15494 01/05/2006 11/27/2006000617 1,500,000 1.15421 01/05/2006 12/27/2006000618 1,500,000 1.15350 01/05/2006 01/25/2007000629 1,200,000 1.15610 01/16/2006 05/25/2006000630 1,300,000 1.15530 01/16/2006 06/26/2006000631 1,200,000 1.15460 01/16/2006 07/25/2006000632 1,200,000 1.15390 01/16/2006 08/25/2006000633 1,200,000 1.15330 01/16/2006 09/25/2006000634 1,200,000 1.15270 01/16/2006 10/25/2006000635 600,000 1.15200 01/16/2006 11/27/2006000636 700,000 1.15130 01/16/2006 12/27/2006000637 800,000 1.15070 01/16/2006 01/25/2007000638 700,000 1.15030 01/16/2006 02/26/2007000639 700,000 1.14990 01/16/2006 03/26/2007000640 700,000 1.14950 01/16/2006 04/25/2007000650 800,000 1.14435 01/24/2006 12/27/2006000651 700,000 1.14370 01/24/2006 01/25/2007000652 800,000 1.14320 01/24/2006 02/26/2007000653 700,000 1.14275 01/24/2006 03/26/2007000654 800,000 1.14230 01/24/2006 04/25/2007000655 500,000 1.14185 01/24/2006 05/25/2007000656 500,000 1.14135 01/24/2006 06/25/2007000657 600,000 1.14090 01/24/2006 07/25/2007000658 600,000 1.14035 01/24/2006 08/27/2007000659 600,000 1.13990 01/24/2006 09/25/2007000660 600,000 1.13940 01/24/2006 10/25/2007000661 600,000 1.13885 01/24/2006 11/26/2007000662 700,000 1.13838 01/24/2006 12/27/2007000666 700,000 1.13492 01/31/2006 12/27/2006000667 800,000 1.13425 01/31/2006 01/25/2007


000668 700,000 1.13365 01/31/2006 02/26/2007000669 700,000 1.13316 01/31/2006 03/26/2007000670 700,000 1.13263 01/31/2006 04/25/2007000671 600,000 1.13210 01/31/2006 05/25/2007000672 600,000 1.13155 01/31/2006 06/25/2007000673 600,000 1.13102 01/31/2006 07/25/2007000674 600,000 1.13044 01/31/2006 08/27/2007000675 600,000 1.12994 01/31/2006 09/25/2007000676 600,000 1.12942 01/31/2006 10/25/2007000677 600,000 1.12886 01/31/2006 11/26/2007000690 1,400,000 1.14270 02/15/2006 12/27/2007000691 2,200,000 1.14211 02/15/2006 01/25/2008



Page 1


Exhibit: B-11

24.0 Reference: Exhibit B-5-2, Appendix D, Schedule C-1, Transfers to HDA and NHDA contd

1.24.2 Line 16, Note 3, refers to Schedule C line 16 Net Sales to Powerex (Future Use). Does this mean that Powerex maintains an inventory of electricity which it has purchased outside of BC, and sold to BC Hydro, but which it has the right to reclaim from inventory at some future date in order to sell that electricity on the export market? If so please provide a table showing the balance of such inventory owed by BC Hydro to Powerex at the end of each month since April, 2000 to the present (in GWh and dollars), and also into the planning period of F2007 and F2008.

RESPONSE: No, Powerex does not maintain an inventory of electricity. All energy brought into B.C. is used by BC Hydro to serve domestic load. Certain energy purchases by BC Hydro from Powerex, under the Transfer Pricing Agreement, create limited rights (and obligations) for Powerex to purchase energy back from BC Hydro for later use in electricity trade. These purchases and sales are allocated to the trade account. The trade account is a notional construct used for financial reporting purposes. A copy of the Transfer Pricing Agreement is included with the response to BCUC IR 1.68.0.


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Exhibit: B-11

24.0 Reference: Exhibit B-5-2, Appendix D, Schedule C-1, Transfers to HDA and NHDA contd

1.24.3 Please provide a table showing how much electricity Powerex has purchased for domestic requirements in LLH and HLH for each month of F2005 and F2006 and what the forecast is for F2007 and F2008. Please include in the table the point of origin of any such purchases (a % breakdown will be sufficient).

RESPONSE: All BC Hydro imports are acquired from Powerex at the B.C. borders through the Transfer Pricing Agreement, a copy of which is attached to the response to BCUC IR 1.68.0. BC Hydro owns all the energy it buys from Powerex. Powerex has limited rights under the Transfer Pricing Agreement to purchase from BC Hydro energy previously allocated to the trade account.

Thus, while all imports by BC Hydro serve domestic load, regardless of whether they are allocated to the trade account or not, since F2003 it has been possible for financial reporting purposes to distinguish between imports for domestic purposes, and imports that both serve domestic load and are expected to be made available to Powerex at a future time for export sale.

The following table shows the volumes of electricity purchased by Powerex and imported into the BC Hydro system that were allocated for domestic purposes and the net volumes of electricity allocated to the trade account for the years F2005 and F2006 and the forecast for F2007 and F2008.


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Exhibit: B-11

Month HLH (GWh) LLH (GWh) Total (GWh)April 2004 310 350 660 May 2004 424 464 888 June 2004 482 481 963 July 2004 118 343 461 August 2004 189 338 527 September 2004 586 557 1,143 October 2004 421 357 778 November 2004 159 318 477 December 2004 3 73 76 January 2005 88 305 393 February 2005 7 82 89 March 2005 116 325 441

F2005 Actual 2,903 3,993 6,896 485 7,381 April 2005 307 443 750 May 2005 441 486 927 June 2005 188 387 575 July 2005 6 90 96 August 2005 - 4 4 September 2005 - - - October 2005 - - - November 2005 6 102 108 December 2005 76 57 133 January 2006 767 580 1,347 February 2006 667 456 1,123 March 2006 402 481 883

F2006 Forecast 2,860 3,086 5,946 (1,550) 4,396 April 2006 524 578 1,102 May 2006 485 607 1,092 June 2006 266 422 688 July 2006 26 277 303 August 2006 9 232 241 September 2006 44 360 404 October 2006 98 380 478 November 2006 62 188 250 December 2006 66 101 167 January 2007 142 340 482 February 2007 126 207 333 March 2007 84 375 459

F2007 RRA 1,932 4,067 5,999 (1,542) 4,457 April 2007 36 219 255 May 2007 222 478 700 June 2007 170 325 495 July 2007 10 203 213 August 2007 - 135 135 September 2007 10 146 156 October 2007 33 142 175 November 2007 18 128 146 December 2007 7 64 71 January 2008 128 226 354 February 2008 240 239 479 March 2008 121 305 426

F2008 RRA 995 2,610 3,605 (1,178) 2,427

Purchases for Domestic Purposes

Net Imports allocated to

Trade Account (GWh)

Total Imports (GWh)


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Exhibit: B-11

Powerex purchases electricity from many different parties at several locations and assembles a portfolio of resources to meet all its commitments, including those to BC Hydro, which it schedules to minimize transmission costs. The identification of which resources are imported into B.C. would be arbitrary since specific resources are not targeted to be imported and the tagging of resources is also at the discretion of upstream counterparties in the scheduling path (for example, if Powerex purchases from another marketer, it is generally the marketers choice as to how it fulfills its obligation to Powerex). The only distinction which could be made physically is between imports from the US and imports from Alberta. Because Alberta is a pool, it also does not source output from particular resources.


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Exhibit: B-11

25.0 Reference: Exhibit B-5-2, Appendix E, Schedule A-2, Summary of Deferral Account Transfers

1.25.1 Line 31-32 refers to the First Nations Regulatory Asset Account Transfer. What transactions have given rise to this deferral account and what is the year end balance in the account for each of the years since it began, and including the forecast for F2007 and F2008? What will determine the timing and amount of this account that will be charged against income in future years?

RESPONSE: In F2006, negotiations with two First Nations groups that have brought actions against BC Hydro progressed to the point where, according to GAAP, a provision for potential settlements was required to be recorded. Consequently, a loss provision of $87.7 million was recorded in F2006. This estimate was based upon the net present value of potential settlement payments as outlined in draft agreements. Accretion expense has also been included in each year within the test period, which would increase the regulatory account balance in F2007 and F2008 to $94.3 and $101 million, respectively.

The timing and amount of this account that will be charged against income in future years is dependent upon final resolution of negotiations with the First Nations groups. If and when settlement payments are made, those would be included in future revenue requirements through the amortization of the related regulatory account.


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Exhibit: B-11


1.25.2 To which specific projects does this $87 million cost relate? Will this charge be included in the capital cost of those projects for evaluation purposes?

RESPONSE: The claims that have been brought against BC Hydro by the First Nations groups relate to existing facilities. The costs that have been provided for relate to legal contingencies which will be accounted for as operating costs and will not be included in the capital cost of any projects.


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Exhibit: B-11


1.25.3 Is it BC Hydros intention to recover this $87 million cost from the ratepayers or from the government?

RESPONSE: BC Hydro intends to recover the costs from ratepayers based on the actual settlement payments incurred.


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Exhibit: B-11


1.25.4 Is there any expectation that additional amounts will be required for any other projects in the future?

RESPONSE: Yes, although as noted in the response to IPPBC IR 1.25.2, the future amounts would not relate to projects, but to existing facilities. Timing and amounts are unknown.


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Exhibit: B-11

26.0 Reference: Exhibit B-5-2, Appendix E, Schedule B, Domestic Cost of Energy

1.26.1 Please indicate which lines contain the cost of gas supplied to the McMahon and ICP cogen facilities.

RESPONSE: The cost of gas for ICP is included on line 15 of Appendix E, Schedule B. BC Hydro does not purchase, and has never purchased, gas for the McMahon IPP facility. Gas procurement is the responsibility of the project owner.


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Exhibit: B-11


1.26.2 Is the gas for McMahon still purchased on a long-term fixed price contract? If so, what is the remaining term of that contract? If not, when did that fixed price contract expire?



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Exhibit: B-11


1.26.3 Please confirm that BC Hydro was offered a long-term fixed price gas supply contract for ICP but elected not to contract for fixed price gas for that facility.

RESPONSE: Confirmed. BC Hydro was offered a fixed price arrangement for gas supply to ICP. The original proposal from the ICP project proponents included both variable and fixed pricing proposals from gas suppliers. However, BC Hydro elected not to choose the fixed pricing option because forecast spot market gas prices were expected to be significantly below the fixed prices proposed when viewed over a 15 to 20 year term.


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Exhibit: B-11

27.0 Reference: Exhibit B-5-2 and B-5-3, Appendices H to N (Mica, GMS, John Hart, Ruskin, Aberfeldi, Peace Canyon, and Coquitlam)

1.27.1 Please provide the economic/financial evaluation models for each of the projects in these Appendices, in electronic form. Please provide the models which perform the Levelized Unit Cost analysis, the Net Present Value analysis, and the Cost of Service/ Rate Impact analysis for each of the projects in Appendices H to N.

RESPONSE: There are numerous projects at different stages of development cited in Appendices H to N. For projects at Identification and Definition phases, the primary focus of investigation is to increase confidence in costs and benefit assumptions. The detailed financial analysis requested is not yet available given the uncertainties around key project variables. All of this information will be presented in the Implementation phase business case. There are six projects included in Appendices H to N that are in Implementation phase, namely GMS G1-G4 Stator Replacement, GMS DC System and Unit Protection Upgrade, Mica G1-G4 Stator Replacement, the Aberfeldie Redevelopment, Peace Canyon G1-G4 Stator Replacement and the Coquitlam Dam Seismic Upgrade. Please refer to the response to CPC IR 1.2.6 from the 2006 IEP and LTAP proceeding and the related supplemental filing for a copy of the model for Aberfeldie. These are included as attachments to this response. The financial analysis conducted for each of the other projects is distinct given different levels of available data, different variables to be captured and different drivers. For example, the Coquitlam Seismic upgrade was put forward to mitigate risk and therefore the NPV would include costs but no financial benefit and provide little information to inform the decision. Similarly, a sustaining capital investment like a stator replacement would require different analysis than a plant redevelopment like Aberfeldie. The particular circumstance for each investment is captured in the business cases that are included in Appendices H to N. The financial assumptions and schedules are included that set out detailed calculations that were deemed to be critical to the decision being made. Providing the excel spreadsheets would provide no additional information over that contained in the respective business cases.

Columbia Power Corporation PageInformation Request No. 1.2.6 Dated: June 5, 2006 1British Columbia Hydro & Power AuthoritySUPPLEMENTAL Resoonse issued June 21,2006British Columbia Hydro & Power Authority Exhibit:20061EP & L TAP ADDlication B-1 0-2

ORIGINAL REQUEST

2.0 Reference: 20041EP, Page 59.

BCH defines Resource Smart projects as physical and operational modificationsto existing facilities that provide additional electricity to BCH. They typically havevery low environmental impacts, can enhance reliability through the replacementof older equipment and can have more limited licencing risk than new facilities.

1.2.6 Please provide spreadsheets that calculate the levelized unit cost ofincremental energy for the Aberfeldie Redevelopment, GM Shrum andall other Re

1.0 reference: exhibit b-5-1, page 1-2 - bc hydro - power smart · · 2018-04-08... (gdp) of...

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