2008 05 05 BC Hydro Responses to BCUC Information Request No 3 · Joanna Sofield Chief Regulatory...

BChgdroJoanna SofieldChief Regulatory OfficerPhone: (604) 623-4046Fax: (604) 623-4407bchydroregulatorvgroup(ci)bchvclro. com

May 5,2008

Ms. Erica M. HamiltonCommission SecretaryBritish Columbia Utilities CommissionSixth Floor - 900 Howe StreetVancouver, BC V6Z 2N3

Dear Ms. Hamilton:

RE: British Columbia Utilities Commission (BCUC)British Columbia Hydro and Power Authority (BC Hydro)British Columbia Transmission Corporation (BCTC)Project No. 3698486 - Application for a Certificate of Public Convenience andNecessity for the Interior to Lower Mainland Project (Project)

Please find enclosed as Exhibit C1-12 BC Hydro's responses to the following BCUCInformation Requests in the above noted Project:

BCUC IR 3.216.1BCUC IR 3.216.2BCUC IR 3.216.3BCUC IR 3.216.4

These Information Requests were forwarded by BCTC to BC Hydro for response.

For further information please contact Lyle McClelland at 604-623-4306.

Yours sincerely,

~J;t~~Chief Regulatory Officer

Enclosure

C.: Project 3698486 Registered Intervenors

British Columbia Hydro and Power Authority, 333 Dunsmuir Street, Vancouver BC V6B 5R3www.bchydro.com

C1-12

bharvey

BCTC ILM CPCN

ERICA M. HAMILTON COMMISSION SECRETARY

[email protected] web site: http://www.bcuc.com

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C. CANADA V6Z 2N3

TELEPHONE: (604) 660-4700 BC TOLL FREE: 1-800-663-1385

FACSIMILE: (604) 660-1102

Log No. 22774

BCTC_ILM/Cor/A-18_Cvr Ltr to BCTC IR No3

VIA E-MAIL [email protected] [email protected] April 14, 2008 BCTC – INTERIOR TO LOWER

MAINLAND TRANSMISSION CPCN EXHIBIT A-18 Ms. Janet Fraser Director, Regulatory Affairs British Columbia Transmission Corporation Suite 1100, Four Bentall Centre 1055 Dunsmuir Street PO Box 49260 Vancouver, B.C. V7X 1V5 Dear Ms. Fraser:

Re: British Columbia Transmission Corporation (“BCTC”) Project No. 3698486 / Order No. G-137-07

Application for a Certificate of Public Convenience and Necessity for the Interior to Lower Mainland Transmission Project

Further to the Regulatory Timetable that was Appendix A to Order No. G-137-07, enclosed is Information Request No. 3. BCTC is to respond to this Information Request by Thursday, May 1, 2008. Please provide the response in both hardcopy and electronic versions. Yours truly, Original signed by: Constance M. Smith for: Erica M. Hamilton yl Enclosure cc: Registered Intervenors (BCTC-ILMProject-RI)

mailto:[email protected]

mailto:[email protected]

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BRITISH COLUMBIA UTILITIES COMMISSION Commission Information Request No. 3

British Columbia Transmission Corporation (“BCTC”)

Interior to Lower Mainland Transmission Project Application (“Application”)

188.0 Reference: Loss Evaluation Exhibit B-1, Appendix I, pp. 26-29; Exhibit B-5, Response to BCUC IR 1.2.1; BC Hydro 2007 Alcan EPA Proceeding, Exhibit B-2-1 Value of Energy

In its estimate of the value of losses, BCTC assumed a levelized value of energy of $74/MW.h based on the BC Hydro F2006 Call Weighted Average Levelized Plant Gate Price (Source: BC Hydro response to BCUC IR 4.451.2, dated September 8, 2006, 2006 BC Hydro IEP / LTAP proceeding). BCTC also prepared an assessment of the difference in the PV of 5L83 and UEC under alternative assumptions for levelized energy prices ranging from $30/MW.h to $150/MW.h. BCTC also conducted an analysis assuming that the price of electrical energy would increase at a rate of 2.0 percent per year, which resulted in an even higher savings associated with the 5L83 alternative compared with the UEC alternative. In response to BCUC IR 1.2.1 (Exhibit B-5) BCTC states: “Each base case was modeled with either 5L83 or the UEC option as the ILM reinforcement. Recognizing that the ILM flow would not remain at a constant level throughout the year, these base cases were input into BCTC’s Power Loss (PLOSS) program along with a seasonal load duration curve for 2005 to simulate the changing loading of the grid throughout the year. The PLOSS program uses the load curve to scale the generation on an hourly basis to balance the load and compute losses for each hour of the season.” As part of the 2007 Alcan EPA proceeding, BC Hydro stated: “A table of multipliers (Energy Weighting Factor Table) is provided in the 2007 EPA … that reflects the relative value of the electricity depending on the month of delivery and whether the electricity is delivered in heavy load hours (HLH) or light load hours (LLH) and establishes the price paid by BC Hydro upon delivery (2007 BC Hydro Alcan EPA Proceeding, Exhibit B-2-1, p. 3-27). 188.1 Please confirm the $74/MW.h value derived from the F2006 Call is a levelized real price

that already assumes escalation in the cost of energy over the life of the contracts.

188.2 Please provide a summary of the monthly incidence of the 307 GW.h of losses. Please comment on the suitability of weighting the energy value to reflect the monthly HLH and LLH incidence of losses. Please provide a table showing the monthly HLH and LLH incidence of losses in 2014 and 2020.

188.3 Under the Province’s self-sufficiency policy, BC Hydro is expected to become self-sufficient and eventually acquire resources to provide a small surplus. Under this policy, BC Hydro would become a net exporter in many water years. Under this scenario the value of losses could also be considered the opportunity cost of forgone exports. Please provide an estimate of the real levelized energy cost of losses (based on real discount rates of 2.5 percent, 3.15 percent, 5 percent and 7 percent) over 20 years using the

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188.4 average Mid-C expected prices (EIA 100) filed by BC Hydro in the 2007 Alcan EPA proceeding (of more recent forecasts if available) LESS wheeling and losses from the B.C. border to Mid-C.

188.5 Please provide an estimate of the real weighted average levelized energy costs of losses over 20 years based on the hourly system losses profile referred to in BCTC’s response to BCUC IR 1.2.1 above, the monthly Mid-C price forecast (disaggregated into HLH and LLH periods) LESS wheeling and losses to the BC Border, and the Energy Weighting Factor Table referred to in the 2007 Alcan EPA Proceeding. Please provide an accompanying spreadsheet showing the calculation.

189.0 Reference: Discount Rate Exhibit B-1, Appendix I, Figure 3-1, page 28 Effects on present value

189.1 Please provide additional versions of Figure 3-1 comparing the PV of UEC and 5L83 showing the results of different loss assumptions under different discount rates of 2 percent, 4 percent, 6 percent, 8 percent, 10 percent and 12 percent.

189.2 Please provide additional versions of Table 3-3 comparing the PV of long-term planning sequences under different discount rates of 2 percent, 4 percent, 6 percent, 8 percent, 10 percent and 12 percent, and different higher and lower value of loss assumptions.

190.0 Reference: Forecast Resources and Loads Exhibit B-1, Appendix K, page 7 Effects of Burrard Generating Station

BC Hydro states “Prior to 2014, Burrard Generating Station is modeled as dispatched to provide Reliability Must Run (RMR) generation with zero reactive power output normally, but 300 MVAR reactive power for system voltage control during outages. After 2014, Burrard generation units are modeled as synchronous condensers with 400 MVAR maximum reactive output from the plant.”

190.1 What might the study have concluded had it assumed that Burrard was repowered in 2014/6 as i) a 950 MW combined cycle gas-fired generating station or ii) a 900 MW simple-cycle peaking plant?

190.2 Would BCTC/BC Hydro agree that the issue of Voltage Stability is best addressed by adding generation at the load centre before adding new transmission lines or voltage support equipment?

191.0 Reference: Forecast Resources and Loads Exhibit B-5, Response to BCUC IR 1.1.2 Load Forecast

BC Hydro states “Key events that could cause a deferral of the decision to proceed with ILM construction would include material changes in the load forecast or the resource portfolios provided by BC Hydro.”

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In its 2006 IEP/LTAP Application BC Hydro set out a number of factors that could lead to lower than forecast electrical sales (and thus in lower future forecasts) including:

• increase in the value of the Canadian dollar, which could slow commodity exports from B.C.;

• rise in interest rates in the United States and Canada, which could reduce North American housing demand and the demand for B.C. lumber; and

• reduction in growth in China could lead to a slowing of commodity demand and lower prices.”(Exhibit B-1A, pp. 4-5 and 4-6)

191.1 Please elaborate on this response given that some of the factors that BC Hydro has

identified as causing lowered forecasts are starting to occur. How much would the 2008 Load Forecast need to change before BCTC would seek to defer the Project?

192.0 Reference: Project Implementation Exhibit B-5, Response to BCUC IR 1.4.1 P3 Assessment

BCTC states that it will report any proposed P3 arrangement to the Commission, along with seeking any further necessary approvals from the Commission, before proceeding with such an arrangement.

192.1 Does BCTC think it possible that the decision to proceed with the Project using a P3

approach would change the discount rate it uses to evaluate the PV of the project?

192.2 What is the current status of deliberations concerning a P3 decision?

192.3 Do the codes of conduct of BC Hydro and/or BCTC permit SNC Lavalin to bid on any P3 tender process, given its role in the Project to date?

193.0 Reference: Earned Value Exhibit B-5, Response to BCUC IR 1.7.8 Project cost tracking and reconciliation

In the response BCTC stated: “The use of “earned value” as a means to monitor contractor performance, produce variance reports, review and approve periodic pay estimates, and forecast final cost and schedule results is a valid method of project tracking. There are a various ways to apply the concept. It is especially useful for contractors themselves to internally monitor their own financial performance on fixed price lump sum or unit price contracts.”;

and,

“At this time, BCTC does not anticipate using an overall project earned value measure.”

193.1 To reconcile timing differences between the cost accounting and project schedule, how does BCTC propose to accurately report on a multi-year, $600 million project without using earned value reporting?

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194.0 Reference: Forecast Resources and Loads Exhibit B-5, Response to BCUC IR 1.39.5.1 Availability of CE

In the response BCTC stated: “In the BC Hydro 2006 IEP/LTAP Proceeding, BC Hydro indicated that the CE was not available as a planning resource after 2014”.

194.1 Please provide a reference for this statement and please confirm that the CE is available

until September 15, 2024 at the earliest. Please reconcile these two statements?

195.0 Reference: Identification and Assessment of Risks and Development of Mitigation Plans Exhibit B-5, Response to BCUC IR 1.116.1 Aboriginal Costs

BCTC lists three factors that influence the Aboriginal accommodation costs, and states that “there likely would be differences” between the 5L83 and UEC Project alternatives. 195.1 For each of the three factors, please indicate whether BCTC expects 5L83 or UEC to

have the higher risk and cost, and provide a brief supporting explanation.


In the response, BCTC stated: “The concept of “earned value” is used in various ways by many contractors and owners for project reporting. BCTC does consider “earned value” to be an acceptable measurement in some circumstances; however, it is not the only acceptable measurement technique and is not the best one in this case.”

196.1 Please explain why BCTC does not consider earned value to be an acceptable reporting

measurement is this particular circumstance?

196.2 Would BCTC agree that conventional cost reporting does not take in account project schedule delays that can lead to significant cost increases?

196.3 Would BCTC agree that the timing differences that may occur between accounting system and project performance reports must be reconcilable?

196.4 Would BCTC agree that earned value reporting is a successful, well-established, and internationally accepted method of reporting a time-phased budget plan against baseline project performance?

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In the response, BCTC stated: “BCTC believes that it would be inappropriate for the Commission to determine the detailed methods by which BCTC chooses to manage and measure performance for its projects. This would be comparable to the Commission determining project team reporting relationships, design parameters or procurement strategies.”

197.1 Would BCTC agree that earned value ‘reporting’ at a high level is desirable because of

the time-phased budget?

197.2 Would BCTC agree that earned value ‘reporting’ at a high level provides the ability to:

197.2.1Integrate cost and schedule performance data with technical performance measures?

197.2.2Identify the magnitude and impact of actual and potential problem areas causing significant cost and schedule variances?

197.2.3Provide valid, timely project summary-level status information?

197.3 Would BCTC consider earned value reporting a time-proven ANSI/EIA Standard and accepted by the Project Management Institute for project management?

197.4 Would BCTC agree that earned value can be preformed on Microsoft Project?

198.0 Reference: Analysis of UEC and 5L83 Exhibit B-10, Response to BCUC IR 2.129.3 Updated estimate

198.1 Please provide an updated table, similar to that in IR 2.129.3, that incorporates all cost changes to date from the various IR’s and BCTC’s responses?

198.2 Please provide the same table for UEC.

199.0 Reference: Losses Evaluation (Price and Quantity) Exhibit B-10, Response to BCUC IR 2.137.1 Energy losses related to conductor size

199.1 Please recalculate the dollar value of losses for each of the conductors and summarize them in a table using real discount rates of 2 to 8 percent in increments of one percent, and with losses valued at from $55/MW.h to $95/MW.h in increments of $5.

199.2 Please provide the table but assuming that the $ per MW.h rate for loss savings escalates at general inflation.

199.3 Please provide the cost estimate for 5L83 assuming each of these conductors.

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200.0 Reference: Losses Evaluation (Price and Quantity) Exhibit B-10, Response to BCUC IR 2.137.1 and 2.137.2 Energy losses related to conductor size

200.1 Please confirm the DC resistances of Bunting, Bittern and Lapwing conductors.

200.2 Please provide a breakdown of the $78.8 million incremental cost for using Lapwing conductor as compared to SP926.7 conductor.

200.3 Please comment on the relative uncertainties associated with the incremental benefits of $72.9 million and the incremental cost of $78.8 million for using Lapwing conductor as compared to SP926.7 conductor. Are all associated life cycle costs and benefits included in these amounts?

201.0 Reference: Analysis of UEC and 5L83 Exhibit B-10, Response to BCUC IR 2.140.1 Probability Distribution Curve

201.1 Please provide updated probability distribution curve, and a quarterly cash flow curve, that incorporates all cost changes to date from the various IR’s and BCTC’s responses?

201.2 Please provide updated cumulative probability distribution curve, and a cumulative cost curve, that incorporates all cost changes to date from the various IR’s and BCTC’s responses?

202.0 Reference: Estimate Preparation and Accuracy Exhibit B-10, Response to BCUC IR 2.141.1 Estimate accuracy

202.1 Please clarify the use of estimate accuracy ranges, stated as a plus/minus percentage, and the use of an @Risk cost probability outcome, such as a P50 or P90 outcome. For a single estimate value, do both methods apply, and if so, how is the estimate accuracy applied against the probability outcome? If only stating one or the other is the correct application of the methodology, at what point is the accuracy range abandoned in favour of the probability outcome?

203.0 Reference: Screening Analysis of Alternatives Exhibit B-10, Response to BCUC IR 2.147.2 Sequence and identification of alternatives

The question stated that “over the longer term the sequence of UEC followed by ILM or ILM followed by UEC, one of which is ultimately needed …”. In response, BCTC stated: “BCTC does not agree with the notion that “over the longer term the sequences UEC followed by ILM or ILM followed by UEC, one of which is ultimately needed…”. Both of the specified sequences are examples of long-term planning of the ILM grid based on implementing both the 5L83 and UEC alternatives (Appendix I, page 30, lines 14 and 15). Other conceptual reinforcement sequences are possible and are not discussed in this Application.”

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203.1 Given this response what assurance does the Commission have, that from the longer term planning perspective that there is not another conceptual reinforcement sequence, that does not begin with 5L83, that may be preferable on the longer term perspective? Please provide any and all documentation of other sequences considered and explain why a sequence beginning with 5L83 is the best option.

203.2 The question also stated that in 2020 the ILM grids limits were the same whether UEC was followed by 5L83 or vice versa. Please confirm this is correct. What is the annual value of the “economical dispatch of interior resources” that will occur for those years in which transfer capacity is improved?

204.0 Reference: Alternatives Considered Exhibit B-10, Response to BCUC IR 2.152.1 Alternative 500 kV lines

204.1 Please list the other 500kV lines BCTC considered and provide reasons why the alternatives were not chosen.

205.0 Reference: Analysis of UEC and 5L83 Exhibit B-10, Response to BCUC IR 2.157.1 Incremental transfer capability

In the response, BCTC stated: “It should be noted that despite the fact that transmission loss savings will make 5L83 a more fiscally attractive alternative than the UEC, the UEC was primarily rejected because of its lower incremental transfer capability than 5L83.” 205.1 What lower amount of incremental transfer capability would be required, and for how

long, in order for the UEC to become the preferred option?

206.0 Reference: Losses Evaluation (Price and Quantity) Exhibit B-10, Response to BCUC IR 2.158.2 Value of DSM

206.1 In calculating the Economic Potential what value ($/MW.h in what year) was placed on electricity savings and how does this compare to the $74/MW.h used by BCTC for losses?

207.0 Reference: Timing and Delays Exhibit B-10, Responses to BCUC 2.158.2, 2.169.1, and 2.170.1 Relationship of DSM and Burrard

207.1 For each of the DSM scenarios, the Lower Achievable and Upper Achievable, and assuming that Burrard is not retired in 2014, when would ILM be needed?

207.2 For each of the DSM scenarios, the Lower Achievable and Upper Achievable, and assuming that three units of Burrard are retired in 2014, when would ILM be required?

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207.3 For each of the four foregoing scenarios, would all of the UEC capital expenditures be required in the first year that the need arises? If not, which UEC capital expenditures would be required in which years?

208.0 Reference: Trade Benefits Exhibit B-10, Response to BCUC IR 2.159.1 Curtailment of firm exports

208.1 Is the avoidance of the curtailment of firm exports a material justification for the project?

209.0 Reference: Loss Evaluation Exhibit B-10, Response to BCUC IR 2.168.1, Attachment BCUC IR 2.168.1a.xls Value of energy

209.1 In the above noted spreadsheet, at sheet 5L83 cell G:111, the figure of $74/MW.h is shown with the comment “$74/MWh is taken from BC Hydro 2009 CFT and is also used in BCTC evidence on IEP 2006 as the high value of energy”. Please explain both of these comments.

209.1.1In Exhibit B-1, page 90, Table 6-1 at line 13 the $74 figure is labeled as the “2006 Average Plant Gate Price ($/MW.h). Please explain and provide a reference for the figure.

209.1.2Is this value levelized or in 2006 or F2006 dollars?

209.1.3If this figure is taken from the F2006 Call, please explain how it would be representative of the value of losses saved by 5L83, which may have a different seasonal and hourly load shape than the average of the Call. What adjustment to the $74 is necessary to reflect the shape of losses saved?

209.1.4Why is it appropriate to use an average plant gate price, and shouldn’t the value of losses reflect the value of electricity in the region(s) in which they are avoided (much as the price in the SOP was adjusted)?

210.0 Reference: Inflation Exhibit B-10, Response to BCUC IR 2.168.1, Attachment BCUC IR 2.168.1a.xls Annual inflation rates used for calculation

210.1 The question requested a specific treatment “in order to capture BCTC’s assumption regarding the escalation of capital costs at a rate higher than general inflation ...” In spreadsheet BCUC IR 2.168.1a.xls, sheet 5L83, it appears that the different cash flows associated with the capital costs (lines 19 through 96) inflate at differing annual rates. For each of the projects shown, please show the annual inflation rates and reference the source of the assumed rates.

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211.0 Reference: Analysis of UEC and 5L83 Exhibit B-10, Response to BCUC IR 2.168.1, Attachment BCUC IR 2.168.1a.xls Sensitivity to discount rate and relative capital estimate

211.1 Please prepare a summary table showing (only) the Additional Cost of UEC followed by 5L83 (PV in 2007, $000s) at real discount rates of 2 to 8 percent in one percent increments, for energy loss savings valued at $55 to $95 per MW.h in increments of $5. Please provide a separate summary table for each of the P20, P50 and P90 estimates (low, expected, and high) for UEC and 5L83.

212.0 Reference: Inflation Exhibit B-10, Response to BCUC IR 2.168.1, Attachment BCUC IR 2.168.1b.xls Annual inflation rates used for calculation

212.1 Please provide the Table provided as the response to BCUC IR 2.168.1b.xls, but assuming that the per MW.h rate for loss savings escalates at general inflation.

213.0 Reference: Analysis of UEC and 5L83 Exhibit B-10, Response to BCUC IR 2.173.1 Post-contingency Burrard dispatch

213.1 Could the 20 MVAr of pre-contingency and 250 MVAr of post-contingency VAr support provided by the ING SVC alternatively be supplied by Burrard?

214.0 Reference: Estimate Preparation and Accuracy Exhibit B-10, Responses to BCUC IR 2.177.1 and 2.179.1 Environmental Costs

BCTC anticipates that the maximum impact on project costs associated with restrictions resulting from the environmental assessment process is approximately $30 million. 214.1 Please confirm that the $30 million estimate includes any and all re-routing that may be

required as a result of the environmental assessment process.

214.2 Does the $30 million include all compensation costs resulting from the EA process?

215.0 Reference: Analysis of UEC and 5L83 Exhibit B-10, Response to BCUC IR 2.183.1 Incremental transfer capability

215.1 For each entry in the “DGC Total NI Generation” and “DGC Total SI Generation” columns, please identify, for each Resource Plan Scenario, the horizon year where the status changes to “Could only be dispatched under off peak conditions” or “Cannot accommodate this level of transfer”.

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216.0 Reference: Cost of Capital OIC No. 27 and 28; BC Hydro IEP/LTAP Proceeding and Decision Equity balance, debt and discount rate

In the 2006 IEP / LTAP proceeding, BC Hydro distinguished HC Equity from Commercial Equity. BC Hydro argued that since it cannot raise equity and since its retained earnings will grow each year in accordance with the HC formula regardless of the level of capital expenditure it undertakes, any rate impact analysis for new projects must assume they will be funded by 100 percent debt (BC Hydro 2006 IEP/LTAP Proceeding T18:2780; BC Hydro 2006 IEP/LTAP Proceeding, BC Hydro Argument, p. 123). BC Hydro asserted that HC Equity is unrelated to BC Hydro’s capital assets; that no consideration should be given to HC Equity as a percent of assets; and that it is very unlikely that HC Equity will eventually reach 100 percent as BC Hydro will have an ongoing requirement for significant sustaining capital (BC Hydro 2006 IEP/LTAP Proceeding, Exhibit B-16, BCUC IR 3.6.2). BC Hydro filed three 20-year forecasts of its debt to equity ratios under three scenarios: 1) capital expenditures of $608 million per year; 2) capital expenditures of $1,216 million per year; and 3) capital expenditures of $1,216 million for 10 years and $608 million thereafter to demonstrate that the change in the level of capital expenditures does not change the total HC Equity or Commercial Equity, although the ratios may change over time (BCH 2006 IEP/LTAP Proceeding, Exhibit B-16, BCUC IR 3.32.7). In its 2006 IEP/LTAP Decision dated May 11, 2007, the Commission accepted BC Hydro’s arguments regarding the actual operation of HC1 and HC2, and the minimal linkages between capital depending and actual equity levels in BC Hydro. The Commission noted the long-run incremental cost of funds should still be set based on occasional forecasts of capital expenditures and the availability of debt financing, but accepted that based on the forecasts filed in that proceeding, capital projects will effectively be financed with 100 percent debt for the foreseeable future. By Orders in Council No. 27 and 28 approved on January 17, 2008, the Government amended the definition of BC Hydro’s equity included in Special Directions HC1 and HC2. Under the amended Special Directive HC1, BC Hydro’s equity is now defined using GAAP and therefore BC Hydro’s equity no longer includes deferred revenue, contributions arising from the Columbia River Treaty or contributions in aid of construction. Under GAAP, BC Hydro’s equity currently only includes retained earnings. The amended Special Direction HC2 deems BC Hydro’s equity for ratemaking purposes to be 30 per cent of the sum of BC Hydro’s average debt and average equity balances for the year. Under Special Directive HC1, BC Hydro’s dividend payment to the Province is reduced if the payment would cause BC Hydro’s debt to equity (as redefined) ratio to exceed 80:20. 216.1 Do OIC No. 27 and 28 alter any of the evidence or argument submitted by BC Hydro in

the 2006 IEP / LTAP Proceeding with respect to the effect of incremental capital expenditures on BC Hydro’s level of equity that would be used for rate setting purposes, or the appropriate discount rate for evaluating large projects? Please explain any changes or lack thereof.

216.2 Given the amended Special Direction HC2 deems BC Hydro’s equity for ratemaking purposes to be 30 per cent of the sum of BC Hydro’s average debt and average equity balances for the year, is it possible under any scenarios for the sum of BC Hydro’s debt and deemed equity to exceed its rate base for rate setting purposes? Please discuss.

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216.3 Please provide a forecast of debt and equity levels (as would be used for rate setting purposes) in BC Hydro for the next 20 years for three scenarios:

1) capital expenditures of $600 million per year;

2) capital expenditures of $1,200 million per year; and

3) capital expenditures of $1,200 million for 10 years and $600 million thereafter.

Please assume dividend payments to the Province are maximized and all additional capital expenditures are funded by debt, unless otherwise constrained by the operation of HC1, as amended by the provincial government. Please provide the forecast for each scenario above in a format similar to the table below.

F2009 F2008 … F2029 Rate Base Start of Year

$millions

Rate Base End of Year

$millions

HC1 Equity $millions HC2 (Deemed) Equity*

$millions

Debt $millions Debt as percentage of rate base

HC1 Equity as a % of Rate Base

HC2 (Deemed) Equity as a % of Rate Base*

*As used for rate setting purposes.

216.4 What is an appropriate real discount rate for evaluating ILM Reinforcement options based on the analysis of the effects of OIC No. 27 and 28 on BC Hydro’s cost of capital?

217.0 Reference: Cost of Capital Exhibit B-1, Section 6.4, Revenue Requirement Impacts and Appendix M; Exhibit B-10, Response to IPPBC IR 2.8.1 Equity balance, debt and discount rate

217.1 In response to IPPBC IR 2.8.1, BCTC provided an updated version of Table 6-2 reflected a deemed equity of 30 percent. Do OIC No. 27 and 28 give rise to any other required changes to the analysis in Section 6.4?

217.2 Please provide an updated version of Appendix M to reflect any changes in the analysis.

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217.3 Please define the expression “Canadian Long Term Interest Rate” referred to in Appendix M, and relate it to the cost to BC Hydro of 30-year long-term debt. What is the most current forecast of the cost to BC Hydro of 30-year long-term debt? Does this include the cost of issuing the debt?

217.4 Please confirm that for economic analysis it is not appropriate to consider the cost of short-term debt.

217.5 Please confirm that for economic analysis it is not appropriate to consider BC Hydro’s embedded cost of debt.

217.6 What is BC Hydro’s current return on equity?

218.0 Reference: Other System Requirements BC Hydro Revelstoke Unit 5 CPCN Application, Exhibit B-3, Response to BCUC IR 1.7.2 Transmission system requirements for the integration of Revelstoke Unit 6

218.1 Please identify the likely system reinforcements and their timing to integrate: i) Mica Unit 5; ii) Revelstoke Unit 6; and iii) Mica Unit 6.

218.2 Can any of the 3 projects listed above be constructed and brought into service before 5L83, and if so, how?

British Columbia Utilities Commission Information Request No. 3.216.1 Dated: April 14, 2008

Page 1 of 2

British Columbia Hydro & Power Authority Response issued May 5, 2008 British Columbia Transmission Corporation Interior-Lower Mainland Transmission CPCN

Exhibit: C1-12


In the 2006 IEP / LTAP proceeding, BC Hydro distinguished HC Equity from Commercial Equity. BC Hydro argued that since it cannot raise equity and since its retained earnings will grow each year in accordance with the HC formula regardless of the level of capital expenditure it undertakes, any rate impact analysis for new projects must assume they will be funded by 100 percent debt (BC Hydro 2006 IEP/LTAP Proceeding T18:2780; BC Hydro 2006 IEP/LTAP Proceeding, BC Hydro Argument, p. 123). BC Hydro asserted that HC Equity is unrelated to BC Hydro’s capital assets; that no consideration should be given to HC Equity as a percent of assets; and that it is very unlikely that HC Equity will eventually reach 100 percent as BC Hydro will have an ongoing requirement for significant sustaining capital (BC Hydro 2006 IEP/LTAP Proceeding, Exhibit B-16, BCUC IR 3.6.2). BC Hydro filed three 20-year forecasts of its debt to equity ratios under three scenarios: 1) capital expenditures of $608 million per year; 2) capital expenditures of $1,216 million per year; and 3) capital expenditures of $1,216 million for 10 years and $608 million thereafter to demonstrate that the change in the level of capital expenditures does not change the total HC Equity or Commercial Equity, although the ratios may change over time (BCH 2006 IEP/LTAP Proceeding, Exhibit B-16, BCUC IR 3.32.7).

In its 2006 IEP/LTAP Decision dated May 11, 2007, the Commission accepted BC Hydro’s arguments regarding the actual operation of HC1 and HC2, and the minimal linkages between capital depending and actual equity levels in BC Hydro. The Commission noted the long-run incremental cost of funds should still be set based on occasional forecasts of capital expenditures and the availability of debt financing, but accepted that based on the forecasts filed in that proceeding, capital projects will effectively be financed with 100 percent debt for the foreseeable future.

By Orders in Council No. 27 and 28 approved on January 17, 2008, the Government amended the definition of BC Hydro’s equity included in Special Directions HC1 and HC2. Under the amended Special Directive HC1, BC Hydro’s equity is now defined using GAAP and therefore BC Hydro’s equity no longer includes deferred revenue, contributions arising from the Columbia River Treaty or contributions in aid of construction. Under GAAP, BC Hydro’s equity currently only includes retained earnings. The amended Special Direction HC2 deems BC Hydro’s equity for ratemaking purposes to be 30 per cent of the sum of BC Hydro’s average debt and average equity balances for the year. Under Special Directive HC1, BC Hydro’s dividend payment to the Province is reduced if the payment would cause BC Hydro’s debt to equity (as redefined) ratio to exceed 80:20.

3.216.1 Do OIC No. 27 and 28 alter any of the evidence or argument submitted by BC Hydro in the 2006 IEP / LTAP Proceeding with respect to the effect of incremental capital expenditures on BC Hydro’s level of equity that would be used for rate setting purposes, or the appropriate discount rate for evaluating large projects? Please explain any changes or lack thereof.

British Columbia Utilities Commission Information Request No. 3.216.1 Dated: April 14, 2008 British Columbia Hydro & Power Authority Response issued May 5, 2008

Page 2 of 2

British Columbia Transmission Corporation Interior-Lower Mainland Transmission CPCN

Exhibit: C1-12

RESPONSE:

BCTC FORWARDED THIS IR TO BC HYDRO FOR RESPONSE. BC HYDRO’S RESPONSE IS AS FOLLOWS:

The changes to Heritage Special Directions HC1 and HC2 mean that incremental capital expenditures, all of which are debt financed will now have an impact on BC Hydro’s level of equity for rate setting purposes. In particular, total debt is included in the calculation of deemed equity. Given this, BC Hydro believes it is appropriate to adopt a discount rate that reflects the allowed return on deemed equity rather than solely based on BC Hydro’s long-term debt cost.

Following from the 2006 IEP/LTAP Decision on the appropriate discount rate to use to evaluate resource options, a 30 per cent deemed equity capital structure, forecast average long-term debt costs of 6.00 per cent and forecast allowed return on equity of 11.78 per cent, leads to the adoption of a nominal discount rate of 7.73 per cent, which BC Hydro proposes to round to 8 per cent.


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Exhibit: C1-12





3.216.2 Given the amended Special Direction HC2 deems BC Hydro’s equity for ratemaking purposes to be 30 per cent of the sum of BC Hydro’s average debt and average equity balances for the year, is it possible under any scenarios for the sum of BC Hydro’s debt and deemed equity to exceed its rate base for rate setting purposes? Please discuss.


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Exhibit: C1-12

RESPONSE:


As noted, BC Hydro’s allowed return is based on its deemed equity. BC Hydro does not have a rate base for rate setting purposes. However, as shown in the tables and response to BCUC IR 3.216.3, in some scenarios the sum of BC Hydro’s debt and deemed equity is greater than the sum of BC Hydro’s debt and GAAP equity.


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Exhibit: C1-12





3.216.3 Please provide a forecast of debt and equity levels (as would be used for rate setting purposes) in BC Hydro for the next 20 years for three scenarios:

1) capital expenditures of $600 million per year; 2) capital expenditures of $1,200 million per year; and


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Exhibit: C1-12

3) capital expenditures of $1,200 million for 10 years and $600 million thereafter.

Please assume dividend payments to the Province are maximized and all additional capital expenditures are funded by debt, unless otherwise constrained by the operation of HC1, as amended by the provincial government. Please provide the forecast for each scenario above in a format similar to the table below.

F2009 F2008 … F2029 Rate Base Start of Year

$millions

Rate Base End of Year

$millions

HC1 Equity $millions HC2 (Deemed) Equity*

$millions

Debt $millions Debt as percentage of rate base

HC1 Equity as a % of Rate Base

HC2 (Deemed) Equity as a % of Rate Base*

*As used for rate setting purposes.

RESPONSE:


BC Hydro does not have a “rate base” for rate making purposes, but considered that the following presentation would be responsive:

British Columbia Utilities Commission Information Request No. 3.216.3 Dated: April 14, 2008 British Columbia Hydro & Power Authority

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Response issued May 5, 2008 British Columbia Transmission Corporation Interior-Lower Mainland Transmission CPCN

Exhibit: C1-12

1) Capital expenditures of $600 million per year F2008 F2009 F2010 F2011 F2012 F2013 F2014 F2015 F2016 F2017 F2018 F2019 F2020 F2021 F2022 F2023 F2024 F2025 F2026 F2027 F2028

HC1 Equity (Year end balance) $ millions 1,830 1,878 1,927 1,977 2,028 2,080 2,132 2,185 2,239 2,293 2,347 2,401 2,456 2,511 2,566 2,621 2,676 2,731 2,785 2,839 2,893 HC2 (Deemed) Equity* (average balance during the year) $ millions 2,654 2,727 2,783 2,834 2,881 2,924 2,962 2,996 3,026 3,051 3,072 3,089 3,101 3,109 3,112 3,111 3,106 3,096 3,082 3,064 3,041

Debt (Year end balance) $ millions 7,164 7,308 7,438 7,552 7,651 7,734 7,803 7,856 7,894 7,917 7,925 7,918 7,897 7,861 7,810 7,744 7,664 7,570 7,462 7,339 7,202

Debt as a % of Year End Debt + Year End Equity 79.7% 79.6% 79.4% 79.2% 79.0% 78.8% 78.5% 78.2% 77.9% 77.5% 77.2% 76.7% 76.3% 75.8% 75.3% 74.7% 74.1% 73.5% 72.8% 72.1% 71.3%HC1 Equity as a % of Year End Debt + Year End Equity 20.3% 20.4% 20.6% 20.8% 21.0% 21.2% 21.5% 21.8% 22.1% 22.5% 22.8% 23.3% 23.7% 24.2% 24.7% 25.3% 25.9% 26.5% 27.2% 27.9% 28.7%HC2 (Deemed) Equity as % of average Debt + average Equity during the year 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% *As used for rate setting purposes General assumptions: All revenue requirement items are held constant from F2008, except for incremental costs of amortization (2.5 per cent annual rate) and interest charges (6.0 per cent per annum) from the addition of capital assets. Return on deemed equity is constant at 11.78 per cent.


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Exhibit: C1-12

F2008 F2009 F2010 F2011 F2012 F2013 F2014 F2015 F2016 F2017 F2018 F2019 F2020 F2021 F2022 F2023 F2024 F2025 F2026 F2027 F2028



Debt as a % of Year End Debt + Year End Equity 80.9% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 79.9% 79.8% 79.7% 79.5% 79.3% 79.1% 78.8% 78.5%

HC1 Equity as a % of Year End Debt + Year End Equity 19.1% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.1% 20.2% 20.3% 20.5% 20.7% 20.9% 21.2% 21.5%HC2 (Deemed) Equity as % of average Debt + average Equity during the year 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0%

2) Capital expenditures of $1,200 million per year

*As used for rate setting purposes

General assumptions: All revenue requirement items are held constant from F2008, except for incremental costs of amortization (2.5 per cent annual rate) and interest charges (6.0 per cent per annum) from the addition of capital assets. Return on deemed equity is constant at 11.78 per cent.

British Columbia Utilities Commission Information Request No. 3.216.3 Dated: April 14, 2008 British Columbia Hydro & Power Authority

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Response issued May 5, 2008 British Columbia Transmission Interior-Lower Mainland Transmi

Corporation ssion CPCN

Exhibit: C1-12

3) Capital expenditures of $1,200 million for 10 years and $600 million thereafter. F2008 F2009 F2010 F2011 F2012 F2013 F2014 F2015 F2016 F2017 F2018 F2019 F2020 F2021 F2022 F2023 F2024 F2025 F2026 F2027 F2028



Debt as a % of Year End Debt + Year End Equity 80.9% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 79.3% 78.6% 77.9% 77.1% 76.3% 75.5% 74.6% 73.7% 72.7% 71.7%

HC1 Equity as a % of Year End Debt + Year End Equity 19.1% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.0% 20.7% 21.4% 22.1% 22.9% 23.7% 24.5% 25.4% 26.3% 27.3% 28.3%HC2 (Deemed) Equity as % of average Debt + average Equity during the year 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0% 30.0%

*As used for rate setting purposes General assumptions: All revenue requirement items are held constant from F2008, except for incremental costs of amortization (2.5 per cent annual rate) and interest charges (6.0 per cent per annum) from the addition of capital assets. Return on deemed equity is constant at 11.78 per cent.


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Exhibit: C1-12





3.216.4 What is an appropriate real discount rate for evaluating ILM Reinforcement options based on the analysis of the effects of OIC No. 27 and 28 on BC Hydro’s cost of capital?


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Exhibit: C1-12

RESPONSE:


For the reasons described in the response to BCUC IR 3.216.1, BC Hydro believes that 6 per cent is an appropriate real discount rate and 8 per cent is an appropriate nominal discount rate for the purposes of evaluating the ILM Transmission Project.

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2008 05 05 BC Hydro Responses to BCUC Information Request No 3 · Joanna Sofield Chief Regulatory...

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