1.0 Reference: Application, Volume 1, Chapter 1, p. 1-9, Section 2.4, Trade Revenues (BCUC Information Request No )

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1 Information Request No... Dated: 2 March Reference: Application, Volume, Chapter, p. -9, Section 2.4, Trade Revenues (BCUC Information Request No...).. Streamflows as a percentage of average are as follows: Please provide the estimated stream flows percentage for FY Please see BC Hydro s response to BCUC IR#2.4..

2 Information Request No...2 Dated: 2 March Reference: Application, Volume, Chapter, p. -9, Section 2.4, Trade Revenue (BCUC Information Request No...)..2 Annual hydro electric energy generation are as follows: Please provide the estimated hydro electric generation for FY Please see BC Hydro s responses to WAIT IR #.4.0 and BCPIAC IR #.b.0.

3 Information Request No...3 Dated: 2 March Reference: Application, Volume, Chapter, p. -9, Section 2-4, Trade Revenues (BCUC Information Request No...)..3 Net Annual Surplus Sales: Please provide the estimated net surplus sales for FY Under the Transfer Pricing Agreement definition, no sales of Surplus Hydro Electricity is expected for F2004.

4 Information Request No...4 Dated: 2 March Reference: Application, Volume, Chapter, p. -9, Section 2-4, Trade Revenues (BCUC Information Request No...)..4 Trade Revenues: Trade revenues have in recent years been strongly influenced by external markets. For the period FY2005 and FY2006 please describe the anticipated relationship of trade revenues to external markets and to the extent possible quantify the relationship to key external variables. Explain quantitatively how much of the trade revenue in each year is a function of the external variable to which BC Hydro is referring. A number of external variables, including market prices, have an impact on trade revenues. Variables such as market price and demand are interdependent. It is difficult to represent quantitatively and objectively the range of potential future market conditions, the decisions that could be taken in response, and the financial outcomes that could result. Please see BC Hydro s response to BCUC IR #.2.3 for a further discussion of the forecasting challenges.

5 Information Request No...5 Dated: 2 March Reference: Application, Volume, Chapter, p. -9, Section 2.4, Trade Revenues (BCUC Information Request No...)..5 Reservoir Levels: Please quantify the reservoir levels estimated now for the end of FY 2004 versus the reservoir levels assumed under normal water flow and normal temperature conditions for the load forecast used for FY 2005 and FY Please also quantify the reservoir level assumed at the end of FY Please supply the monthly reservoir level assumptions from beginning to end of the FY 2005 and FY Please see BC Hydro s response to BCUC IR #2.4.2.

6 Information Request No..2.. Dated: 2 March Reference: Volume, Chapter, Application overview.2. Trade Income versus budget: (BCUC Information Request No...2) The information shown in the response to the BCUC question..2 shows that 80% of the time BC Hydro s budget is under the actual performance and 20% of the time it is over the actual performance..2.. Does BC Hydro consider it prudent to be conservative in planning for and budgeting an uncertain item such as trade income? Powerex does not forecast Trade Income conservatively by design or otherwise such that actual results are more likely than not to exceed forecast results. It has no incentive to do so given the Trade Income Deferral Account mechanism. In BC Hydro s response to BCUC IR #..2 an explanation was provided on a yearly basis of the reasons Powerex s electricity trade income was either over or under budget. Generally, there were distinct reasons for actual earnings to be higher than budget, such as the sinkhole in BC Hydro s WAC Bennett Dam, the receipt of the Power Marketing Authorisation, and high power prices as a result of the energy crisis in California. Generally, through F200 Powerex was growing its business at a rate much faster than anticipated and operating in a period of steadily rising market prices. The power industry then underwent a period of disruption. The California crisis and bankruptcy of Enron created considerable uncertainty in forecasting for F2002 and F2003.

7 Information Request No Dated: 2 March Reference: Volume, Chapter, Application overview.2. Trade Income versus budget: (BCUC Information Request No...2) The information shown in the response to the BCUC question..2 shows that 80% of the time BC Hydro s budget is under the actual performance and 20% of the time it is over the actual performance Please quantify to the extent possible any source of variance that might affect the budget versus actual performance for forecasting trade revenue. There are several factors that will affect the actual Trade Income. This is documented more fully in BC Hydro s response to BCUC IR #.2.3.

8 Information Request No Dated: 2 March Reference: Volume, Chapter, p. -8 (BCUC Information Request No...4).2.2. For non-union variable pay positions throughout the company please: a) Quantify the total payments made for fiscal years 2003 & b) Aggregate the total of cost savings and or revenue improvements claimed to be achieved for all positions for fiscal years 2003 & c) Identify the assumed cost savings or revenue improvement targets for fiscal years 2005 & d) Quantify the level of cost savings or revenue improvements included in the projections used for the rate application for each of the fiscal years 2005 & e) Quantify the total payment projected for the rate application for fiscal years 2005 & A: Quantify the total payments made for fiscal years 2003 & 2004 The total amount of variable pay expended in F2003 was $2 million and in F2004 payments totaled $8 million, which related to performance for the previous year. B: Aggregate the total of cost savings and or revenue improvements claimed to be achieved for all positions for fiscal years 2003 & BC Hydro does not maintain a separate process to aggregate all savings and/or revenue generation outcomes that occurred as a result of employee s performance against their individual incentive contracts. Such a process incorrectly assumes that BC Hydro only assigns objectives that lead to a financial return to BC Hydro. While some objectives center around the absolute improvement in existing operational measures within the current year, other objectives may require employees to investigate new problems and implement solutions where payback will only materialize in the coming years. For employees working to deliver results that meet BC Hydro s environmental or social objectives, the return to BC Hydro is often not financial in nature but rather intended to meet overall policy objectives. Other employees and work groups may be assigned objectives that have more indirect benefits (i.e. behavioral changes such as improving customer service) where the business payback is linked and understood but difficult to quantify.

9 Information Request No Dated: 2 March Rather than tabulating all individual contracts to arrive at a net financial business impact, BC Hydro determines the amount of variable pay expended by evaluating the overall performance of the corporation, business units and individuals in light of its Service Plan. Variable pay contracts for management and professional staff are required to be either directly or indirectly linked to BC Hydro s Service Plan. The Service Plan outlines the objectives for BC Hydro and the benefits that BC Hydro will provide to its shareholder. By cascading Service Plan objectives throughout the organization in the form of individual incentive contracts and by the effective performance management of these contracts, BC Hydro ensures that it meets its overall commitments to its shareholder. In F2003, BC Hydro met its Net Income Target while exceeding its targets for Customer Satisfaction and All Injury Frequency. These measures are the primary determinants of the level of variable pay and gainsharing in any given year. While the benefits of achieving our Net Income target are obvious, high levels of Customer Satisfaction and reductions in All Injury Frequency produce future economic value. For example, based on analysis from Corporate Safety, for every reduction in injury incidents, BC Hydro can expect an economic return of approximately $00,000. Last year, BC Hydro reduced the total number of safety related incidents by 34. In addition, lines of business attained or exceeded many of their performance targets for Service Plan metrics. For example, BC Hydro Generation s Commercial Performance during the year was 99.4 per cent, well above Plan of 99.0 per cent due to the focus placed on this key indicator of success. A 0. per cent improvement in Commercial Performance equates to approximately $2.5 to $3.0 million additional gross revenue. In summary, the variable pay arrived at for BC Hydro as a corporation reflects achievement against service plan objectives from an economic, environmental and social perspective. C: Identify the assumed cost savings or revenue improvements targets for fiscal years 2005 and 2006 As mentioned in the response above, the purpose of variable pay is to align Management and Professional staff to the objectives and business performance metrics contained in BC Hydro s Service Plan. Therefore, the assumed business benefit of variable pay for F2005 and F2006 is that BC Hydro will meet or exceed the performance targets set out in the service plan across all performance metrics of an economic, environmental, and social nature. D: Quantify the levels of cost savings or revenue improvements included in the projections used for the rate application for each of the fiscal years 2005 and 2006 See answer C above.

10 Information Request No Dated: 2 March E: Quantify the total payments projected for the rate application for years 2005 & 2006 The projections for total variable pay payments for F2005 and F2006 are approximately $8 million and $8.5 million, respectively. The significant drop in the payment level is largely due to the overall change in the make-up of BC Hydro compared to F2003 and F2004, noting that BCTC is now a separate entity and the arrangement with ABS, resulting in a workforce reduction at BC Hydro of approximately,750 FTEs.

11 Information Request No Dated: 2 March Reference: Volume, Chapter, p. -8 (BCUC Information Request No...4) Please identify any processes used to verify and or confirm the claimed achievements on which the variable pay is based. Have any of these processes been audited and are there any internal reports documenting the results? Please see BC Hydro s response to CECBC IR #.2.2. Part b. Managers are responsible for the performance management of their staff and hence evaluate variable pay contracts for completion of assigned objectives. Managers may hold peer reviews at the department and line of business level to compare the evaluated outcomes of staff with employees in other areas. Since line of business and Key Business Unit performance metrics appear on many of these contracts, managers responsible for total unit performance reporting for these groups may provide the data on the actual performance of the group. These series of peer reviews and the data management systems already in place ensure that variable pay awards determined for employees are consistent with the business results identified for the department.

12 Information Request No..3.. Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No. 2.2).3. Sensitivities.3.. For each of the items for which sensitivities are provided please identify which of these will be carried in a deferral account and the name of the deferral account. See BC Hydro s response to BCUC IR # for a description of the proposed Heritage Deferral Account (HDA). The table below identifies each of the sensitivities and the deferral account that might be applied (HDA or Trade Income Deferral Account (TIDA), if the variance is eligible for deferral. The variances estimated are based on the sensitivities requested by the BCUC. (in $millions) Sensitivity F2005 F2006 Deferral Account Load Variations due to +/- $5 +/-$8 weather (+/-2%) Change in GWh due to change in customer load Change in Cost of energy due to higher or lower cost of supply than $/MWh forecast No HDA Streamflow variations (+/-5%) Market fluctuations which impact the domestic energy cost (+/-0%) Market fluctuations which impact Trade income +/- $94 +/-$97 HDA +/-$20 +/-$5 HDA Not estimated Not estimated TIDA

13 Information Request No..3.. Dated: 2 March Sensitivity F2005 F2006 Deferral Account Fluctuations in Power Nil +/-$2 No Smart take up rates (+/-20%) Constraints or opportunities on the operation of Burrard that might result from the MLA review: Not estimated Not estimated Depends on Constraint or opportunity Changes in short-term +/-$30 +/-30 No interest rates Changes in return on +$5/-$0 +$0/-$5 No pension assets 2 Changes in load forecast +/-$3 +/-$3 arising from factors other than weather. Change in GWh due to change in customer load Change in Cost of energy due to higher or lower unit cost of supply No HDA This is for a change of 00 basis points in interest rates. 2 The increase estimate in pension costs is based on a 2% reduction in actual return on pension assets from the forecast 7% and the decrease is based on a 0% actual return on assets.

14 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No. 2.2).3. Sensitivities.3..2 Where it is not expected that an item will be put in a deferral account please identify if the risk will fall to the shareholder or if BC Hydro intends to apply in the future for the actual results. Where it is not expected that an item will be put in a deferral account the risk will generally fall to the shareholder. Please also see BC Hydro s responses to BCUC IR # and IPPBC IR #.9.2.

15 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No. 2.2).3. Sensitivities.3..3 For each item for which sensitivities were provided please identify a probability curve for the range of possible variability. The sensitivities provided in BC Hydro s response to BCUC IR #.2.2 were as follows: Load variations due to weather Streamflow variations Market fluctuations Fluctuations around Power Smart take-up rates Constraints or opportunities on the operation of Burrard that might result from the MLA review Short-term interest rate fluctuations Fluctuations around the return on pension plan assets Changes in load forecast arising from factors other than weather variations. The variability, within an 80 per cent confidence band, of the above noted items is shown below. The impact on income before deferral account transfers is calculated based on the methodology and information used in BC Hydro s response to BCUC IR #.2.2. The limitations of identifying the impact of an individual variable in isolation are also discussed as part of the response to BCUC IR #.2.2. Load variations due to weather Based on historical weather data, it is estimated that weather temperatures (in degree days) fluctuate by approximately +/- 0 per cent from average within an 80 per cent confidence band. This temperature variation would result in residential sales volumes fluctuating by as much as +/- 5 per cent from forecast in the Application (colder winter temperatures would increase residential sales volumes whereas warmer winter temperatures would decrease sales volumes). This range of residential sales volumes is shown in the table below: Residential Sales Volumes: Low Scenario Reference Forecast High Scenario F2005 (GWh) 5,044 5,836 6,628 F2006 (GWh) 5,259 6,063 6,866

16 Information Request No Dated: 2 March There is a 0 per cent chance that residential sales volumes will be below the low scenario and a 0 per cent chance that residential sales volumes will be higher than the high scenario due to weather fluctuations. The estimated impact on income due to this variability would be: F2005 F2006 Impact on income ($ millions) +/- 2 +/- 2 Streamflow variations Streamflow variations impact the level of hydro generation. Hydro generation in F2005 and F2006 could range between 40,000 GWh and 5,000 GWh within an 80 per cent confidence band. Hydro generation in the Application was anticipated to be slightly higher than 46,000 GWh in each of the test years. The confidence band is based on an analysis of historical inflows to the Williston and Kinbasket reservoirs converted to energy together with the historical generation for the remainder of the hydro system over the period 973 to The estimated impact on income before deferral account transfers due to this variability would be: ($ Million) Low High F2005 $(250) $200 F2006 $(200) $55 The low represents the low hydro generation scenario and the high represents the high hydro generation scenario. The low hydro generation scenario would result in a decrease to income and the high scenario would result in an increase to income. Market fluctuations The table below shows the range of average gas and electricity prices within an 80 per cent confidence band. The confidence band is around the forward market prices for gas and electricity used in the Application and is based on a historical analysis of the volatility in prices. Low Median High Average Mid-C prices (Cdn$/MW.h) F2005 $28.5 $44.8 $7.9 F2006 $20. $45.2 $02.2 Average Sumas gas prices (Cdn$/GJ) F2005 $4.49 $5.59 $7.0 F2006 $3.53 $5.27 $7.88

17 Information Request No Dated: 2 March The impact on income is calculated assuming the percentage change in the Mid-C prices from the median forecast translates to the same percentage change in the average purchase price of energy purchases for BC Hydro. Based on this, the impact on income before deferral account transfers due to this variability is estimated to be: ($ Millions) Low High F2005 $70 $(20) F2006 $80 $(90) The low price scenario would increase income and the high price scenario would decrease income. Fluctuations around Power Smart take-up rates In the response to BCUC IR #.2.2, BC Hydro showed that the estimated impact on income from fluctuations of +/- 20 per cent on Power Smart take-up rates were not significant. The impact on income was estimated to be less than $2 million in each of the test years. While a statistical confidence band around the Power Smart savings has not been developed, BC Hydro considers it unlikely that the Power Smart savings will fall outside this range. Constraints or opportunities on the operation of Burrard that might result from the MLA review A confidence band around the potential impacts that may result from this review is not determinable. Some of the potential impacts that may result are described in the response to BCUC IR #.2.2. Short-term interest rate fluctuations The table below shows the range of average Canadian short-term interest rates within an 80 per cent confidence band. The confidence band is calculated using the average implied market volatility on Canadian 3 month Bankers Acceptances. Low Scenario Reference Forecast High Scenario F % 3.63% 4.2% F % 5.06% 5.87% The calculation of the probability band assumes that there is an equal chance that rates may go up or down. It does not factor in whether there is a higher probability that rates may go down more than they will go up. The impact to income due to the above noted variability is estimated to be: F2005 F2006 Impact on income ($ millions) +/- 7 +/- 24

18 Information Request No Dated: 2 March Fluctuations around the return on pension plan assets The table below shows the range for the return on pension plan assets within an 80 per cent confidence band. The confidence band was determined using the current strategic asset mix and the five-year annualized return and risk assumptions. A 7 per cent annual rate of return was used in the Application. Low Scenario Reference Forecast High Scenario F % 7.0% 2.4% F % 7.0% 2.4% The estimated impact on income due to this variability would be: F2005 F2006 Impact on income ($ millions) +/- 5 +/- 5 The impact on F2006 income, due to the fluctuations around the return on pension plan assets, is estimated assuming a 7 per cent return was achieved in F2005. The impact on F2006 income would change if the return in F2005 were different than the 7 per cent assumed. This is due to the impact this change would have on the opening asset values. Changes in load forecast arising from factors other than weather variations Section 7.3, s 4 and 42 of the Load Forecast (Appendix J), details the methodology used to determine a probability distribution which shows the likelihood of various load levels resulting from the combined effect of five major casual factors. The five major casual factors include the economic growth rate, the electricity rate, the effective energy reduction achieved by demand-side management programs, the response to electricity price changes, and electricity intensity. The table below summarizes the results of total domestic sales with Power Smart for the test years from Tables A7.2, A7.5 and A7.6 of Appendix J. Low Scenario Reference Forecast High Scenario F2005 (GWh) 48,527 49,003 49,489 F2006 (GWh) 48,640 49,37 49,987 The high and low scenarios reflect an 80 per cent confidence band. That is there is a 0 per cent chance the outcome will be below the low scenario and a 0 per cent chance that the outcome will be above the high scenario due to changes arising from factors other than weather. The impact to income due to this variability is estimated to be: F2005 F2006 Impact on income ($ millions) +/- +/- 9

19 Information Request No..4. Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.3).4. Trade Revenue Forecast Variability Reservoir Starting Conditions As the CEC understands, this information is based on forecast hydrological conditions and current starting reservoir conditions for BC Hydro. Please quantify the starting reservoir levels assumed in the trade revenue forecast of BC Hydro and explain why they are important as determinants of the trade revenue forecast The assumed reservoir levels at March 3, 2004 for the Kinbasket and Williston Reservoirs are 2,362.8 feet and 2,57.9 feet, respectively. These assumptions were used to produce the forecasts shown in the Evidentiary Update (Chapter 2A). Starting reservoir levels have an effect on Trade Income when reservoir levels are very low or very high to the extent that they affect net purchase or sale requirements for domestic purposes or restrict Powerex s ability to add to or draw from the trade account.

20 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.3).4.2 Trade Revenue Forecast Variability Future Growth The Trade Income forecast for F2008 and beyond is extrapolated from F2007, assuming 5% annual increases for most costs and revenues Please explain why it was reasonable for BC Hydro to forecast a growth of 5% in the future Please explain and quantify what BC Hydro views as the limits of growth Please explain what if any barriers there are to growth at a faster rate toward the same limits. The forecast rate of growth is based on management judgment. The forecast for F2007 and beyond will be refined as those periods approach. It is difficult to forecast beyond the near years due to the limited market information available. Growth may be limited by a number of factors, including market opportunities. The ability to grow at a faster rate depends on the pace of development in the energy markets.

21 Information Request No..5.. Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.9).5. Maintenance for Reliability F2004 versus F2003 ($millions) F2003 F2004 Increase Distribution Generation (.6) Transmission Total F2005 versus F2004 ($millions) F2004 F2005 Increase Distribution Generation Transmission Total Please complete this analysis for 2005 versus 2006 as well and then for all years complete the analysis requested below:.5.. Please provide the following analysis of the increase: Increase due to head count increase Increase due to pay rate increase ($ Millions) F2003 F2004 F2004 Increase Over F2003 F2005 F2005 Increase Over F2004 F2006 F2006 Increase Over F2005 Distribution $67. $74.9 $7.8 $8.9 $7.0 $8.7 $(0.2) Generation (.6) Transmission (BC Hydro TLoB & BCTC) Total $206.9 $226.9 $20.0 $244.2 $7.3 $244.2 $0.0

22 Information Request No..5.. Dated: 2 March The amounts presented in the table above and in BC Hydro s response to BCUC IR #.2.9 reflect the definition of maintenance within O, M and A and not the total spend related to maintaining the reliability of the system. A cost summary of requirements needed to maintain the reliability of the system was provided in BC Hydro s response to BCUC IR #..3. Increase due to headcount increases: None of the increase in maintenance is due to headcount increases, rather the required amount of maintenance is forecast and then resources are assigned to achieve the required maintenance. These resources may include headcount within the lines of business, employees within service organizations, or outside contractors. Increase due to pay rate increases: It is not possible to specifically identify the amount of any increase due to pay rate increases. As described in Chapter 5 (Generation), Chapter 6 (Transmission) and Chapter 7 (Distribution), there are many factors that determine the volume and mix of maintenance in a year. These include both planned maintenance (preventative and condition based) and corrective maintenance. Pay rate increases would not translate into the same dollar increases due to changes in workforce mix, changes in planned maintenance, and anticipated productivity increases.

23 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.9).5. Maintenance for Reliability F2004 versus F2003 ($millions) F2003 F2004 Increase Distribution Generation (.6) Transmission Total F2005 VERSUS F2004 ($millions) F2004 F2005 Increase Distribution Generation Transmission Total Please complete this analysis for 2005 versus 2006 as well and then for all years complete the analysis requested below:.5..2 Of the total amount of amount of maintenance in each year please identify the quantity that is preventive maintenance and the quantity that is reactive maintenance. F2003 F2004 F2005 F2006 ($ millions) P R Total P R Total P R Total P R Total Transmission (BCH LoB/BCTC) $2.9 Transmission Lines $5.5 $27.4 $25.3 $6.3 $3.6 $26.6 $6.6 $33.2 $26.6 $6.6 $ Stations Vegetation Total Transmission (BCH TLoB/BCTC) Distribution Generation Total $46.8 $60. $206.9 $60.7 $66.2 $226.9 $77.6 $7.6 $244.2 $77.4 $66.8 $244.2

24 Information Request No Dated: 2 March Note: P = Preventative R = Reactive

25 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.9).5. Maintenance for Reliability F2004 versus F2003 ($millions) F2003 F2004 Increase Distribution Generation (.6) Transmission Total F2005 versus F2004 ($millions) F2004 F2005 Increase Distribution Generation Transmission Total Please complete this analysis for 2005 versus 2006 as well and then for all years complete the analysis requested below:.5..3 Please identify any preventative maintenance programs being added beyond those already done in prior years. BC Hydro Distribution: Increased preventative maintenance programs are planned for F2005 and F2006 as follows: Annual Cost for F2005 and F2006 ($ millions) Wires Maintenance $6.4 Vegetation Maintenance 0.6 TOTAL $7.0 BC Hydro Generation: As described in Chapter 5, 5-26, Section 6.2., BC Hydro Generation is implementing a Reliability Centered Maintenance (RCM) program at each facility.

26 Information Request No Dated: 2 March The facilities at which RCM has been implemented (and therefore was the basis for the maintenance programs in this Application) are listed in Chapter 5, 5-54, Schedule 5-3. Full implementation of RCM is not expected to materially affect maintenance resource requirements; however a complete understanding of the impacts of RCM will not be known until the RCM implementation has been completed at all facilities. Transmission / BCTC: The following programs are planned for F2005 and F2006 in BC Hydro Transmission / BCTC: Annual Cost for F2005 and F2006 ($ millions) Edge Tree Management Program $3.0 Integrated Vegetation Management Program.0 Transmission Facility Maintenance Program.0 Extra-ordinary Maintenance Program 2.0 TOTAL $7.0 Please see Chapter 6, page 6-20 and 6-2 for a description of these programs, and BC Hydro s response to BCOAPO IR #.52.0(a) for the history of unexpected maintenance expenditures.

27 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.9).5. Maintenance for Reliability F2004 versus F2003 ($millions) F2003 F2004 Increase Distribution Generation (.6) Transmission Total F2005 versus F2004 ($millions) F2004 F2005 Increase Distribution Generation Transmission Total Please complete this analysis for 2005 versus 2006 as well and then for all years complete the analysis requested below:.5..4 Please identify any program frequency changes made or anticipated. BC Hydro Distribution: There are no frequency changes made or anticipated for BC Hydro Distribution maintenance programs. BC Hydro Generation: The outcome of the RCM program will guide decisions around program frequency changes in BC Hydro Generation. Full implementation of RCM is not expected to materially affect maintenance resource requirements; however a complete understanding of the impacts of RCM will not be known until the RCM implementation has been completed at all facilities. Transmission / BCTC: The frequency of maintenance programs is adjusted periodically based on equipment age, assessment of condition, operating performance and criticality to the system. During the introduction of the Station Maintenance Process in 999 (please see BC Hydro s response to JIESC IR #..2(a) and JIESC IR#..2(b)), a number of changes were made to maintenance frequencies.

28 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.9).5. Maintenance for Reliability F2004 versus F2003 ($millions) F2003 F2004 Increase Distribution Generation (.6) Transmission Total F2005 versus F2004 ($millions) F2004 F2005 Increase Distribution Generation Transmission Total Please complete this analysis for 2005 versus 2006 as well and then for all years complete the analysis requested below:.5..5 Please quantify the cost of any programs being added or any program frequency changes. BC Hydro Distribution: Please see BC Hydro s response to CECBC IR # These costs are shown in Chapter 7, 7-37, Table 7-0. BC Hydro Generation: Please see BC Hydro s response to CECBC IR # Transmission / BCTC: See BC Hydro s response to CECBC IR # In most cases, program frequency changes result in decreased maintenance costs, examples of which are noted in the Maintain Stations Process Project Plan explained in BC Hydro s response to JIESC IR #..2(a) and JIESC IR #..2(b).

29 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.9).5. Maintenance for Reliability F2004 versus F2003 ($millions) F2003 F2004 Increase Distribution Generation (.6) Transmission Total F2005 versus F2004 ($millions) F2004 F2005 Increase Distribution Generation Transmission Total Please complete this analysis for 2005 versus 2006 as well and then for all years complete the analysis requested below:.5..6 Please identify if these are ongoing annually or identify the frequency of repetition of the maintenance requirement. BC Hydro Distribution: These programs are ongoing annually. BC Hydro Generation: Please see BC Hydro s response to CECBC IR # Transmission / BCTC: Maintenance activities are carried out annually. The frequency of inspections, repairs and refurbishments depends on the type of equipment, related maintenance standards and the condition of the equipment.

30 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.9).5. Maintenance for Reliability F2004 versus F2003 ($millions) F2003 F2004 Increase Distribution Generation (.6) Transmission Total F2005 versus F2004 ($millions) F2004 F2005 Increase Distribution Generation Transmission Total Please complete this analysis for 2005 versus 2006 as well and then for all years complete the analysis requested below:.5..7 For preventive maintenance programs being added or with an increased frequency. Please identify the reliability criteria to be met and the current level of reliability. BC Hydro Distribution The reliability criteria to be met is an Average System Availability Index performance measure of % as described in Chapter 7, 7-30, Section The F2004 estimated level of reliability is 99.95%. BC Hydro Generation Reliability centered maintenance seeks to optimize reliability and cost. The goal of RCM is to minimize the total cost of maintenance plus the lost opportunity cost of both maintenance outages and forced outages.

31 Information Request No Dated: 2 March For current level of reliability, please see BC Hydro s response to BCUC IR # Transmission/BCTC In general, by means of its maintenance and sustaining programs, BCTC strives to maintain or improve existing reliability. Please see response to BCOAPO IR #.5.0 a), b) and c).

32 Information Request No..6. Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.0).6. Capitalized Projects Please list all capitalized projects being carried and the anticipated date at which the project will be advanced to an in service completion. The table below identifies the net book value of deferred site study projects, deferred aboriginal negotiation and settlement projects, and other deferred projects at March 3, Description NBV ($Millions) Deferred Site Studies COQUITLAM DAM D.I. $3 WAC BENNETT DAM DI 2 REVELSTOKE GS UNIT5-IMPLEM/PH 2 RUSKIN DAM DEFICIENCY 2 KEENLEYSIDE EARTHFILL DAM DI SITE C PROJECT - PEACE RIVER SETON DAM D.I. LA JOIE DEFICIENCY INVEST MICA UNITS &2 TURBINE REP COURSIER DAM DECOMMISSIONING STATHCONA DAM DEF INVEST MICA DAM DI Projects < $500k 3 Deferred Aboriginal Negotiation & Settlement Costs 2 Other Deferred projects ABS Start-up - Deferred RFEI costs 0 Total $5 Expenditures for F2004 to F2006 are stated in BC Hydro s response to BCUC #.2.0. Although site studies may proceed to construction projects, the net book value of the site studies are not capitalized as part of the construction costs. Aboriginal negotiation and settlement projects do not advance to construction projects. Amortization for F2004 to F2006 is stated in BC Hydro s response to JIESC IR #.8.0(a). As stated in the BC Hydro Capital Asset Accounting manual section 5.02 (SSI and Aboriginal Negotiations and Settlement) site survey and investigation (SSI) costs and Aboriginal Negotiations expenditures for a particular project should be detailed and put in service at the end of each fiscal year. Amortization will be based on the life of the asset (5 or 0 years) from the creation of the asset.

33 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.0).6.2 Abandoned projects.6.2. Please explain what BC Hydro proposes to do with any projects, which may be abandoned during 2005 or 2006 that are not identified for abandonment in the analysis presented. For projects that are abandoned, BC Hydro will follow its accounting policy of writing down the asset to net recoverable amount in the year which the project is abandoned.

34 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.0).6.2 Abandoned projects Please identify the impact if any of any such abandonment. If the dollars are significant, BC Hydro may apply to BCUC for inclusion of sunk costs, net of any salvage value, in future rates. Please see BC Hydro s response to IPPBC IR #.54.4 regarding the treatment of costs of Georgia Strait Pipeline Crossing and Vancouver Island Generation Project in the event that they are not developed.

35 Information Request No..7. Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7. Burrard Generating Station ( Burrard ) - Life Please provide the annual remaining life expectancy for Burrard for the years BC Hydro has operated Burrard Generating Station on the assumption that it was an ongoing operation. Consequently, when asset additions were made in the past they were depreciated at the same rate that other similar assets would be depreciated. Until such time that a decision is made to discontinue or change the expected life of the facility, the useful life of specific assets are applied.

36 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.2 Burrard Generating Station - Amortization As CEC understands BC Hydro s evidence limited further capital investment in the facility over the next 0 years and will reduce the net book value of the asset to zero over 0 years. This results in F204 as the last year for amortization.7.2. What gave rise to the choice of 0 years as the period over which to amortize the investment in the Burrard? Please see BC Hydro s Response to BCUC IR #.5..

37 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.2 Burrard Generating Station - Amortization As CEC understands BC Hydro s evidence limited further capital investment in the facility over the next 0 years and will reduce the net book value of the asset to zero over 0 years. This results in F204 as the last year for amortization What documents where produced internally to support this decision? Please supply a copy of any such documents. No specific documentation was produced to support this decision, however, BC Hydro s response to BCUC IR #.5. lists the combination of factors that led to the decision.

38 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall Please explain what firming the capacity to meet system requirements means? In order to count Burrard Generating Station as a dependable capacity resource, the generating units must be able to deliver the required power output when called upon. Firming the capacity to meet system requirements means that the Burrard Generating Station units can be operated to provide the level of dependable capacity when required. The conditions needed to firm up the capacity at Burrard Generating Station are: () firm fuel supply, (2) regular test operations to ensure availability, (3) ongoing capital and O&M expenditures to maintain reliability of units, and (4) ongoing compliance with permits and applicable safety standards.

39 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall What is the value in present value dollars of the firm capacity to meet system requirements which could be supplied by Burrard assuming it is maintained for this purpose? The present value of the firm capacity currently supplied by Burrard Generating Station would depend on the choice of replacement resources. In the short term, an estimate of the cost of a market capacity option for the winter months for 456 MW is of the order of $3million/yr, however, this estimate depends on several factors including the reservation price, length of time, and strike prices. Please see BC Hydro s response to IPPBC IR #.60..

40 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall What is the ongoing cost of maintaining Burrard for this purpose? Please see BC Hydro s responses to CECBC IR # and IPPBC IR #.59..

41 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall What is the present value of this ongoing cost? Please see BC Hydro s responses to BCUC IR #.5.4, IPPBC IR #.59., and IPPBC IR #.60.. To maintain 3 units on generation standby and to use 3 units to provide VAR support is a short- term operating plan for Burrard Generating Station while BC Hydro assesses long-term options for the generating facility. Therefore, a present value analysis over a long period of time is hypothetical.

42 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall Please supply copies of the load resource balance studies referred to. Please see Chapter 4, for BC Hydro s system load resource balance. For F2004 to F2006, the capacity required from the heritage resources is 0,252 MW, which includes 456 MW of dependable capacity from Burrard Generating Station as indicated in BC Hydro s response to the BCUC IR # Please also refer to the 2004 Integrated Electricity Plan.

43 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall What is the short term for the purpose of providing firm capacity? There is not a standard definition for short term for the purpose of providing firm capacity. However, short term used in the context of the BC Hydro s response to BCUC IR #.5., refers to a timeframe of 3 years or less.

44 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall What is the operating cycle regime required to operate Burrard to firm up system requirements? To ensure equipment performance and maintain operator capability for 456 MW of reliable generation capacity at Burrard, the plan is to operate each of Units 4, 5, and 6 for 2 days every 2 months at an average unit loading of 00 MW. During the testing period, the generation output from each unit would vary between 40 and 50 MW with a period of sustained operation at maximum output.

45 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall What if anything limits the capability of Burrard to provide the firm capacity? Subject to the conditions in BC Hydro s response to CECBC IR #.7.3. being satisfied, there are no limits on the capability of the Burrard Generating Station units to provide firm capacity.

46 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall What is the next most viable option to provide firm capacity in place of Burrard? Please see BC Hydro s response to CECBC IR #

47 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall What would this next most viable option cost? Please see BC Hydro s response to CECBC IR #

48 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall What would be the purpose of any potential future recall of the three Burrard Units preserved for future recall? The purpose of maintaining three units at Burrard Generating Station for future recall is that the BC Hydro 0-year demand-supply outlook shows a requirement for additional capacity by F2009. Please also see BC Hydro s response to IPPBC IR #.60..

49 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall What is the expected timeframe for a unit to be recalled? The expected timeframe for a unit to be recalled from dry storage depends on the length of time that the unit has been out of service. Under the current operating strategy, i.e. 3 units on standby and 3 units preserved for recall, within the next 2 years the timeframe to recall the units is estimated to be between 2 and 4 months.

50 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall Does BC Hydro require firm natural gas capacity to operate Burrard for firming up system requirements? If so, how much? Yes, 5 TJ/day of transportation capacity is required for 3 generating units and 230 TJ/day is required for 6 generating units.

51 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.3 Burrard Generating Station Economic Value As CEC understands the evidence, Burrard is still expected to provide firm capacity to meet system requirements. Load resource balance studies conducted by BC Hydro shows that up to three units may be required for firm capacity in the short term. In order to ensure three units are available when required while concurrently minimizing the operating costs at Burrard, three units have been placed in generation standby mode and will be exercised on a regular basis. The remaining three units, not required for firm capacity and not expected to be dispatched for energy, will be preserved for future recall What is the advance time required to get firm natural gas capacity for Burrard? None. BC Hydro has adequate gas transportation capacity under the current Bypass Transportation Agreement with Terasen Gas Inc. Please see BC Hydro s response to BCUC IR #.9.5 for additional information on the Bypass Transportation Agreement.

52 Information Request No Dated: 2 March Reference: Application, Volume I, Chapter 2, Consolidated Revenue Request No..2.).7.4 Burrard Generating Station MLA Review.7.4. Has BC Hydro taken any positions in the MLA Review with respect to the requirement for Burrard? What were they and please provide any written filing of BC Hydro. Compass Resource Management Ltd. was engaged by the MLA Committee to support the Committee with technical, economic and environmental information on the plant and potential policy options. BC Hydro provided data and modelling support to the Committee. However, all assumptions and analysis methods were reviewed independently. The conclusions and recommendations contained in the Burrard Thermal Options Review report are those of Compass Resource Management. BC Hydro did not take a position on Burrard as it related to the work of the Committee. During the review period the MLA Committee made a visit to Burrard Generating Station in February A presentation was made to the committee by the then VP Generation. A copy of the presentation is provided on the enclosed CD-ROM. Towards the end of the review period the current VP Generation met with the MLA committee on 8 October 2003 and made a presentation. The presentation is attached.

53 Burrard Generating Station MLA Review Committee Review of Operations Historic, Current and Future February 2003 T H E POWER IS YOURS

54 a 3 3 N 3, 3 E3

55 Overview History of key events and Burrard Generating Station s contribution to BC Hydro Value of Burrard Generating Station Environmental and Air Quality Opportunities for Burrard Generating Station HE POWER I S YOURS BChyclro m 3

56 Historical Key Events East side Units, 2, 3 - construction commenced 960, last unit commissioned 963 West side Units 43, 6 - construction commenced mid-l960 s, last unit commissioned to 87 - Reduced requirement to generate power due to recession and implementation of new hydro at Revelstoke Burrard sets record production (4,200 GWh) Task force recommends Selective Catalytic Reduction (SCR) installation to reduce NOx emissions and improve environmental performance 995 to SCR s installed on all Units Integrated Electricity Plan recommends replacement of east side with Combined Cycle Gas Turbine (CCGT) technology, possible in-service date on 2004 / International environmental registration with IS0 400 THE POWER I S YOURS BGhydro 3 4

57 THF: Historical Expenditures Capital + Total from I987 to 2002 is $60 million + $59 million to upgrade Units 4, 5 & 6 + $47 million to install SCR to reduce NOx air emissions + $0 million to upgrade old equipment + $0 million for asbestos removal Income Statement + Fixed Operation & Maintenance $3.5 million per year + Variable Operation & Maintenance $.25/MWh, plus natural gas costs + Pro-forma income statement indicates near break-even when not generating POWER I S V'OURb BGhydro m 5

58 Capital Expenditures Burrard GS Distributed Control System (DCS) on Units 4, 5, 6 (West) - enhanced operation & control T H E POWER I S YOUR6 BChydm a 6

59 .,. I t 5 I' c e

60 E3 co 0 (D 0 -L -L 0 m

61 Value of Burrard Generating Station I Net contribution of $900 million for 999 to 2003 Voltage support (VARs) increase transfer ca pa b i I it y Mitigates transmission grid improvements requiring: 0 capital expenditures of $50 million 0 operating & maintenance costs of $8 million per year Mitigates annual transmission line losses of $6 million per year Insurance against transmission line failures Local contribution in annual grants and municipal taxes of $.4 million per year T H E POWEU I S YOURS BChydro 0 9

62 The Environmental and Social Side of Burrard GS T H E PQWER I S YOURS BChudro m I Community Liaison Committee of Municipal Council Philanthropic activity Grants & taxes Employment & other indirect benefits Environment Air emission improvements Aquatic & fish habitat studies 0 Water quality improvement 0 Noise & visual effect i m p rovemen ts 0 IS0 400 registration 0