2.0 Reference: Application, Volume I, Chapter 2, Consolidated Revenue Requirements and Financial Schedules

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1 1 2.0 Reference: Application, Volume I, Chapter 2, Consolidated Revenue Requirements and Financial Schedules , Table 2-2: Please indicate for Columns C and D whether or not an average expected value was used for the key variables used in establishing this table. Please provide an update to Column C and D for the following sensitivities (note that BC Hydro may wish to change the proposed sensitivities and/or the variability if they are felt to be inappropriate): Load variations due to weather variation (+/-2%) Streamflow variations (+/-5%) Market fluctuations (+/-10%) Fluctuations around Power Smart take up rates (+/-20%) Constraints or opportunities on the operation of Burrard that might result from the MLA review Other credible scenarios that might have an impact on customer rates RESPONSE: The average expected values were used for the key input variables. However, for cost of energy calculations, market purchases and system dispatch were determined for a wide range of weather conditions, including inflows. The dispatch results for each weather sequence were then averaged to determine the cost of energy. Sensitivities: The following analysis assumes that each of the variables discussed below are independent of each other. The correlation between such variables as weather, water inflow levels, and market prices for energy are ignored in order to provide information on each specific variable as requested. Load variations due to weather variation (+/-2%) Impact on net income ($ millions) +/- 5 +/- 8 Weather impacts predominately affect the residential load. A 2% increase/decrease in the residential sales volumes translates to an approximately 320 GWh change in sales volumes. Adding line losses of approximately 12% would result in a change in the domestic load requirement of approximately 360 GWh. This change in load would likely impact the level of market energy purchases. Based on the information below, revenues from residential customers would increase/decrease by an estimated $21 million (i.e. change in sales volumes of 320 GWh x average tariff) in each of F2005 and

2 2 F2006. Domestic cost of energy would increase/decrease by an estimated $16 million and $13 million in F2005 and F2006, respectively (i.e. change in load of 360 GWh x average purchase price). The net impact to income would be approximately $5 million for F2005 and $8 million for F2006. Net income would increase with an increase in load and decrease with a decrease in load as shown in the table below. Assumptions: F2005 F2006 Residential revenues ( 2-44, Schedule A-5) $1,041 million $1,077 million Residential sales volumes ( 2-44, Schedule 15,836 GWh 16,063 GWh A-5,) Average tariff (calculated from above) $65.7/MWh $67.0/MWh Average market electricity purchase price ( 2-49, Schedule A-9) $45.3/MWh $36.5/MWh Streamflow variations (+/- 5%) Impact on net income ($ millions) +/- $94 +/- $74 Streamflow variations impact the level of hydro-generation. A higher level of inflows would correspond to a higher level of hydro-generation. While changes to inflow levels would impact more than one year, because water management is undertaken on a multiple year basis, the following analysis assumes any change in streamflow conditions would only impact a single year. The analysis also assumes that a 5% change in streamflow conditions would correspond to a 5% change in hydro-generation. An increase in hydro-generation would likely decrease market electricity purchases and could result in the sale of surplus energy. A decrease in hydro-generation would likely increase market purchases or increase the use of thermal generation. As a result, the impact on net income would be the difference between the variable cost of hydrogeneration (i.e. water rentals) and the cost of market electricity purchases as shown in the table below.

3 3 Assumptions: F2005 F2006 Hydro-generation ( 2-49, Schedule A-9) 46,130 GWh 46,293 GWh Impact of 5% change in hydro-generation (calculated) 2,310 GWh 2,315 GWh Incremental water rental charge $4.9/MWh $5.2/MWh Average market electricity purchase price ( 2-49, Schedule A-9) Market electricity purchases ( 2-49, Schedule A-9) Sale of surplus energy (Note 1) $45.3/MWh $36.5 MWh 2,316 GWh 1,506 GWh 809 GWh Note 1. Surplus energy would be created as the level of expected market purchases in F2006 is less than the assumed increase in hydro-generation. For purposes of this analysis it is assumed that the surplus energy would be sold for 5 per cent more than the average electricity market purchase price shown above. ($ millions) F2005 F2006 Impact of 5% lower hydro-generation Decrease in water rental charges Increase in market purchase costs $(11) 105 $(12) 85 Total incrase in cost of energy and decrease in net income $94 $73 Impact of 5% higher hydro-generation: Increase in water rental charges Decrease in market purchase costs $(11) 105 $(12) 55 Total decrease in cost of energy $94 $43 Increase in revenues from sale of surplus 31 Total increase in net income $94 $74 The analysis above ignores the impact on finance charges that would result due to the change in cash flows as the amount would be insignificant. The analysis also assumes that changes in hydro conditions do not impact market prices. It should be noted that the simplifying assumptions made to isolate the impact of this specific variable mask the potentially asymmetrical impact of lower than average streamflows compared to higher than average streamflows. If low streamflow conditions are prevalent throughout Western North America, they can often result in increased market prices. Also, limitations on minimum reservoir levels can limit operating flexibility in low water years. Accordingly,

4 4 the magnitude of the income impact tends to be greater under lower than average streamflow conditions compared to higher than average streamflow conditions. It should be noted that hydro conditions will also impact the supply from hydro-based IPP projects. However, this impact is not material given the proportion of IPP supply to total supply and the fact that the sensitivity is only on the variability of this portion of supply. Market fluctuations (+/- 10%) Impact on net income ($ millions) +/- $20 +/- $15 Changes to market (electricity and gas) prices would impact the costs of the following resources used to meet domestic load; market purchases, gas costs related to BC Hydro s thermal generation, and gas costs associated with BC Hydro s energy purchase agreement (EPA) with the Island Cogeneration Project, an Independent Power Producer (IPP). Under this EPA, BC Hydro bears the gas price risk on the energy deliveries. BC Hydro also has one EPA with a hydro-based IPP (Miller Creek) wherein the purchase price is indexed to Mid-C electricity prices. Changes to market prices could also impact Trade Income should the spreads between the high load hour (HLH) prices and low load hour (LLH) prices change due to market fluctuations. For purposes of this analysis, it is assumed that the spreads remain the same and that the relative prices between years also remains unchanged. A shift in relative prices between years can shift the timing of trade sales and purchases for both domestic and trade purposes. The changes in market prices identified above would impact the domestic energy costs shown in the table below. F2005 F2006 Gas costs included as part of IPP costs (note 2) $69 $77 Gas costs related to thermal generation Market electricity purchases (schedule A-9, page 2-49) Miller Creek Power Project 6 7 $198 $153 Impact of 10% change in prices $20 $15 Note 2. BC Hydro has two other EPAs in which the purchase price of any excess energy deliveries are indexed to market prices. However, these EPAs

5 5 are not included as part of the market fluctuation analysis as BC Hydro is not obligated to purchase the excess energy. Fluctuations around Power Smart take up rates (+/- 20%) Impact on net income ($ millions) Nil -/+ $ 2 The volume impact at the customer s meter is calculated by taking 20% of the annual net incremental energy savings from Appendix I, Table 4.1. The line loss estimates are from Appendix I, 9. The average tariff rate is calculated by dividing the total revenue by the sales volume from Schedules A- 5 to A-7 on s 2-44 to The average rate for the Industrial sector is further adjusted based on the assumption that 85% of this sector s consumption is from the Large Industrial class (Schedule A-7) and the remaining 15% from the Light Industrial and Commercial class (Schedule A-6) (Appendix I, s 8-9). The Power Smart program cost impact is calculated by taking 20% of its variable cost, estimated by the sum of the annual incentive cost plus 20% of the annual non-incentive program costs from Appendix I, Tables 4.3 and 4.4. The analysis above is summarized in the table below. F2005 F2006 Change in savings Residential 15.8 GWh 12.0 GWh Change in savings Commercial 29.2 GWh 30.8 GWh Change in savings Industrial 58.0 GWh 47.8 GWh Average tariff rate Residential $65.7/MWh $67.0/MWh Average tariff rate Commercial $57.0/MWh $58.1/MWh Blended tariff rate Industrial $39.7/MWh $40.3/MWh Line losses Residential (Appendix I, 9) 7% 7% Line losses Commercial (Appendix I, 9) 7% 7% Line losses Industrial (Appendix I, 9) 3.6% 3.6% Average market electricity purchase price ( 2-49, Schedule A-9) $45.3/MWh $36.5/MWh Change in Power Smart variable cost $13m $11m A change in Power Smart take up rate would impact domestic revenue, cost of energy, and Power Smart costs. An increase in the Power Smart take up rate would lower domestic revenue as energy consumption is decreased resulting in a negative impact on net income. Similarly it would lower cost of energy as load requirement is decreased resulting in a positive impact on net income. As well, it would increase Power Smart program cost resulting in higher amortization cost and a negative impact on net income. The impact on domestic revenue is determined by multiplying the change in savings by the average tariff rate for each sector.

6 6 The impact on cost of energy is determined by inflating the change in energy savings by the line loss and multiplying the result by the market price for each sector. Although the short-term market prices are used for this analysis for consistency purposes, Power Smart has only used the long-term supply cost in its 10-Year Plan. Power Smart costs incurred in the current year are amortized over 10 years starting the following year. Therefore, the change in Power Smart costs from a change the Power Smart take up rate in F2005 will impact the amortization costs starting in F2006 (10% each year for 10 years). Similarly, a change in Power Smart costs in F2006 will impact the amortization costs starting in F2007. The impact of a 20 per cent increase in the Power Smart savings would be as follows: ($ millions) F2005 F2006 Increase (decrease) in domestic revenue (5) (4) Decrease (increase) in cost of energy 5 3 Decrease (increase) in amortization cost - (1) Net Impact on Net Income $- ($2) Constraints or opportunities on the operation of Burrard that might result from the MLA Review. The potential range of opportunities and/or constraints that may result from the MLA committee Review is significant and it is difficult to assess the potential impacts of this Review. Potential impacts include: changes to the Maintenance and Operations and Administration costs related to Burrard Generation Station (currently estimated at $12 million per year); changes to the depreciation of Burrard (currently estimated at $24 million per year); changes to the Cost of Energy, although Burrard Generating Station is not expected to be heavily utilized during the test years, so these impacts would be minor; changes to the cost of new resource acquisition, although these impacts would not be significant within the test years; changes to the potential Trade Income, particularly if Burrard Generating Station VAR capability was reduced, impacting the transmission system capability, and possibly the Cost of Energy.; and reductions in Burrard Generating Station s dependable capacity below what is currently assumed during the test years will require BC Hydro to rely on other firm capacity resources to meet reserve margin requirements.

7 7 Please also see BC Hydro s response to BCUC IR # Other credible scenarios that might have an impact on customer rates. 1. Changes in short-term interest rates (+/- 100 basis points) BC Hydro s debt portfolio consists of fixed and variable rate debt. Based on BC Hydro s current debt portfolio, a 100 basis point change in interest rates would impact finance charges by approximately $30 million per year. 2. Changes in the return on pension plan assets The expected return on pension fund assets has been assumed at a 7 per cent annual return for the test years. An actual return of 5 per cent a year would result in an increase to pension costs of $5 million and $10 million for F2005 and F2006, respectively. An actual return of 10 per cent a year would result in a decrease in pension costs of $10 million and $15 million for F2005 and F2006, respectively. BC Hydro s next mandatory tri-annual actuarial valuation on its pension fund liability is due in F2005. The impact of any changes from this valuation is not determinable at this time. 3. Changes in load forecast arising from factors other than weather variations Impact on net income ($ millions) +/- 3 +/- 13 As noted in Chapter 4, 4-22, short-term uncertainty driven by weather variations and economic conditions can cause load (energy and capacity) variations of 1% to 2%. A 2% variation arising from nonweather factors across all rate classes would reduce or increase firm domestic sales by 2% and would likely have a corresponding volume reduction or increase in market purchases. The effect would be to reduce revenues and energy costs or conversely to increase revenues and costs as shown in the table below.

8 8 F2005 F2006 Change in sales volume Residential 317 GWh 321 GWh Change in sales volume Commercial 340 GWh 344 GWh Change in sales volume Industrial 295 GWh 292 GWh Change in Supply Load including line losses 1,057 GWh 1,064 GWh Average tariff rate Residential $65.7/MWh $67.0/MWh Average tariff rate Commercial $57.0/MWh $58.1/MWh Average tariff rate Industrial $36.1/MWh $37.2/MWh Average market electricity purchase price ( 2-49, Schedule A-9) $45.3/MWh $36.5/MWh The volume impact is calculated by taking 2% of the sales volumes from Schedules A-5 to A-7 and the average tariff rate is calculated by dividing the revenues by the sales volumes from these schedules. The change in supply load is based on adding line losses of 4% for distribution and 8.1% for transmission to the total change in sales volumes (the industrial category would only attract the transmission line losses whereas the residential and commercial categories attract both the transmission and distribution line losses). These line loss estimates are consistent with the Load Forecast. ($ millions) F2005 F2006 Increase (decrease) in domestic revenues $51 $52 Decrease (increase) in cost of energy (48) (39) Net Impact on Income $3 $13

Revenue Requirement Application 2004/05 and 2005/06. Volume 1. Chapter 2. Consolidated Revenue Requirements and Financial Schedules

Revenue Requirement Application 00/0 and 00/0 Volume 1 Chapter. Consolidated Revenue Requirements and Financial Schedules Table of Contents LIST OF FIGURES... -IV LIST OF TABLES... -IV LIST OF SCHEDULES...-V