2008 10 23 exhibit b 4 2 bch fort nelson related ...€¦ · fort nelson evidentiary update ... bc...

BChgdroJoanna SofieldChief Regulatory OfficerPhone: (604) 623-4046Fax: (604) 623-4407bchvdroregulatorvgroup(wbchvc1ro. com

October 24 2008

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

Dear Ms. Hamilton:

RE: Project No. 3698514British Columbia Utilities Commission (BCUC)British Columbia Hydro and Power Authority (BC Hydro)2008 Long Term Acquisition Plan (2008 LTAP)

Further to BC Hydro's letter of October 15, 2008 accompanying the filing of the non FortNelson-related second round Information Request (IR) responses, BC Hydro encloses theFort Nelson evidentiary update (Exhibit B-1-1 0) and responses to Fort Nelson second roundIRs (Exhibit B-4-2).

1. Fort Nelson Evidentiary Update

Exhibit B-1-10 updates the evidentiary record related to Fort Nelson, and is comprised ofthe following:

(1) Amendment of the Order sought with respect to the Fort Nelson Generating StationUpgrade (FNGU) as a result of updated cost estimates for FNGU. Refer to therevised Appendix A to the 2008 LTAP, and revised FNGU and Fort Nelson-relatedparts of Chapter 1 and 6 of the 2008 LTAP. The revised version of Appendix Asupersedes prior versions of Appendix A (Exhibits B-1-1, B-1-5, B-1-6).

(2) Revised versions of Appendices N1 and N2, which supersede previous versions ofthese Appendices. Appendices N1 and N2 have been revised to not only reflect theupdated FNGU cost estimates, but also to address many of the issues raised by theFort Nelson-related IRs. For example, as a result of several BCUC IRs, analyses ofa 10 MW bioenergy plant and -27 MW combined cycle gas turbine have resulted inadditional Appendix N1 analysis. In addition, for ease of reference BC Hydro hasconsolidated and incorporated prior versions of Appendices N1 and N2(Exhibits B-1-1, B-1-5, B-1-7, B-1-8) into the revised versions of Appendices N1 andN2 filed as Exhibit B-1-10.

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

B-4-2

ylapierr

2008 LTAP

-2-

2. Fort Nelson-Related IR Responses

BC Hydro encloses as Exhibit B-4-2 its responses to the following Fort Nelson-relatedRound 2 IRs.

BCOAPO IR 2.1.1 BCOAPO IR 2.1.2 BCOAPO IR 2.1.3 BCOAPO IR 2.1.4

BCOAPO IR 2.5.1 BCUC IR2.216.1 BCUC IR 2.216.2 BCUC IR 2.216.3

BCUC IR 2.217.1 BCUC IR 2.217.2 BCUC IR 2.217.3 BCUC IR 2.218.1

BCUC IR 2.218.2 BCUC IR 2.218.3 BCUC IR 2.218.4 BCUC IR2.219.1







BCUC IR 2.223.7 BCUC IR 2.224.1 BCUC IR 2.225.1

Consistent with established practice, BC Hydro requests that intervenors who have issuesregarding the adequacy of responses to these IRs contact Craig Godsoe, BC Hydro counselprior to taking any formal steps with the BCUC. Contact information for Craig Godsoe is:604-623-4403 (telephone) and [email protected] (e-mail).

Yours sincerely,

Joanna SofieldChief Regulatory Officer

c. Project 3698514 Intervenors

BCOAPO et al. Information Request No. 2.1.1 Dated: September 10, 2008

Page 1 of 1

British Columbia Hydro & Power Authority Response issued October 24, 2008 British Columbia Hydro & Power Authority BC Hydro 2008 LTAP Application

Exhibit: B-4-2

1.0 Reference: Exhibit B-1-8 (Errata to the Application, Sept 5 2008)

APPENDIX N1 to BC Hydro's 2008 LTAP Page 17 of 84 [Revision 3 - September 5, 2008] Text deleted from the original Appendix: Each company provided BC Hydro with estimates of their potential load assuming they electrified some or all of their operations. BC Hydro assumed that these estimates were understated given the competitive environment of the oil and gas sector. Therefore, other information such as land sales and proximity to gas fields was used to estimate further potential load. BC Hydro asked each company for a five year load profile of their operations. If the company could not provide further details beyond a single number, this estimate was spread out over a number of years to mimic a staged approach to development. All projected load, i.e. potential load, was assumed to have a minimum lifespan of 20 years. BC Hydro assigned a probability to each company's potential load. Loads where the estimates were provided solely by the company were assigned a high probability whereas loads estimated solely by BC Hydro were assigned a low probability. A mix of company projections and BC Hydro assumed projects were assigned medium probability.

2.1.1 Did the processes described in the deleted text not actually take place, despite being set out in the original Appendix?

RESPONSE: The text deleted from the original Appendix was the subject of an errata. Refer to Exhibit B-1-8. A further explanation is provided in the response to BCUC IR 1.38.3 (Exhibit B-3).


Page 1 of 1


Exhibit: B-4-2



2.1.2 How did this passage find its way into the original Appendix?

RESPONSE: Please refer to the response to BCUC IR 2.1.1.


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Exhibit: B-4-2



2.1.3 Why does BC Hydro wish to delete this passage (by characterizing it as an erratum) from the Application?

RESPONSE: Please refer to the response to BCOAPO IR 2.1.1.


Page 1 of 1


Exhibit: B-4-2



2.1.4 Please describe whatever process was actually followed instead of the deleted one.

RESPONSE: Please refer to the response to BCOAPO IR 2.1.1.


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Exhibit: B-4-2

5.0 Reference: Exh.B-3, BCUC 1.38.1 and EnCana 1.9.4.

2.5.1 Has BC Hydro considered any DSM programs to encourage the use of gas drives for oil and gas compression and pumping loads in Ft Nelson? If so please provide details.

RESPONSE: BC Hydro has not considered any DSM programs to encourage the use of gas drives for oil and gas compression and pumping load in Fort Nelson.

British Columbia Utilities Commission Information Request No. 2.216.1 Dated: September 11, 2008

Page 1 of 1


Exhibit: B-4-2

216.0 Reference: Fort Nelson Generating Station Upgrade

Exhibit: B-1-7, pp. 4-6

2.216.1 Further to Table 3, please explain why the effluent discharge for the FNG case is so much higher than for the FNGU cases.

RESPONSE: Please refer to section 2.4.1 of Appendix N2 (Exhibit B-1-10).


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7, pp. 4-6

2.216.2 Please identify any material problems that are caused by raw water usage or effluent discharge for FNG, in terms of regulatory permits, cost or operations.

RESPONSE: No material problems will be caused by raw water usage or effluent discharges for Fort Nelson Generating Station (FNG) in terms of permit amendments, cost or operation. For example, both Fort Nelson Generating Station Upgrade Case 3.2 (FNU3) and Fort Nelson Generating Station Upgrade Case 2 (FNU2) will result in significant reduction in water consumption and effluent discharge, as shown in Table 2-3 of Appendix N2 (Exhibit B-1-10). Please also refer to section 2.4.1 of Appendix N2.


Page 1 of 1


Exhibit: B-4-2


Exhibit B-1-7, pp. 4-6

2.216.3 Please expand Table 5 to include FNGU Case 3.2 without duct firing. Will this be the normal operating mode?

RESPONSE: Please refer to Table 2-5 of Appendix N2 (Exhibit B-1-10). With respect to the operating mode of FNU3 under various portfolios and scenarios, please refer to Table 7-6 of Appendix N-1 (Exhibit B-1-10) which identifies the capacity factor of the gas-fired generation in Fort Nelson for the duct fired portion of FNU3 separated from the remaining gas-fired units.


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7, pp. 13, 14, 16

2.217.1 With reference to Figures 1 and 2, what is the “largest single contingency assumed to be unavailable” (N-1) in Figure 2?

RESPONSE: The largest single contingency is the FNG at 47.8 MW. Please refer to Figure 5-6 of Appendix N1 (Exhibit B-1-10).


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7, pp. 13, 14, 16

2.217.2 Please explain why the N-1 scenario for Figure 2 does not reduce available supply, rather than increase load.

RESPONSE: As described in Section 5.6 of Appendix N1 (Exhibit B-1-1), BC Hydro chose to add the value of the single largest contingency to the load rather than subtract it from the available supply, to demonstrate the N-1 requirement. The difference between the demand and the available supply less the single largest contingency is the same as the demand plus the single largest contingency and the available supply. The N-1 resource in any one year and any one scenario may change. Adding the N-1 resource to the load allows all resources to be presented in the figures.


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7, pp. 13, 14, 16

2.217.3 Please provide a figure for the N-1 scenario that is based on forecast load and the supply that would be available under N-1 conditions.

RESPONSE: The column at the left for each year is the Alberta Electric System Operator (AESO) supply (AESO FDS and TMR)1 and the FNG generator. As can be seen, the FNG is the largest unit. Removing the N-1 resource (FNG) is the same as assuming the left-hand column is the supply after N-1. The gap between the AESO and the load scenario is the same as the gap presented in Figure 5-6 of Appendix N1.

0

25

50

75

100

125

150

175

200

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026

MW

AESO FDS without TMR AESO FDS with TMRCurrent FNG Reference ForecastLow Scenario Medium ScenarioHigh Scenario

1 For details on AESO FDS and TMR, refer to Section 2.2 of Appendix N1.


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7, p. 19

2.218.1 BC Hydro states that approximately 35 MW of additional capacity will be available from TMR, but that this is of no additional value for providing firm service. Please explain if the need to run TMR generation on the Alberta side in some way limits the firm capacity that AESO can or will provide to BC Hydro, and how any such impediment could be removed.

RESPONSE: The referenced paragraph describes the load/resource balance in Table 9 on the same page. The portfolio and scenario being described are the FNU2 combined with the AESO A1 transmission portfolio measured against the Low Scenario. As stated on page 50 of 84 of Appendix N1 (Exhibit B-1-1), the N-1 reliability condition is based on the lower of the capacity of the largest local contingency and the import capability, as one must be capable of supporting the other. With respect to Table 9 (Exhibit B-1-7), the AESO Capacity (no TMR) on the second line is greater than the FNU2 capacity (first line) in the years 2011 through 2015. In the years 2016 and 2017, it is slightly less. Therefore, in the years 2011 through 2015 the AESO A1 capacity without TMR, and not the FNU2, is the largest contingency. For example in 2012 it is 62.2 MW as compared to 57.3 MW for the FNU2. The AESO A1 (no TMR) is the “-1” in the N-1 reliability measure, and that resource is effectively removed in the N-1 reliability calculation. Adding 35 MW of TMR capacity to the AESO (making it 97.2 MW) has no effect in the calculation because the resource was already the largest contingency. In 2016, the AESO A1 capacity is identified as 57.1 MW, which is 0.2 MW less than FNU2. The 0.2 MW is identified in the line “AESO TMR Required”, and the 0.2 MW is added to the firm supply, reducing the “Firm Surplus/Deficit with TMR”. This is further described in section 7.4 of the revised and updated Appendix N1 (Exhibit B-1-10). A complete set of load/resource balances for the portfolios analyzed is provided in section 10 of Appendix N1.


Page 1 of 1


Exhibit: B-4-2



2.218.2 BC Hydro further states that “the interconnection is setting the N-1 condition (no room for firm capacity over the size of FNGU)”. As it is not obvious why the size of FNGU is directly related to the capacity of the interconnect, please explain the statement.



Page 1 of 1


Exhibit: B-4-2



2.218.3 What is the current physical capacity of the interconnect with the Alberta system? Could this interconnect be expanded by a small amount at modest cost? What would be the amount of the small increase, and what would it cost?

RESPONSE: The current physical capacity is described in section 5.5.4 of Appendix N1 (Exhibit B-1-10). There are two elements involved in identifying the physical capacity of the AESO interconnection; the available physical capacity is the lower of the two:

1. The capacity of the transmission line from Rainbow Lake (RB) to Fort Nelson (FN), identified as 117 MW (refer to section 5.5.3 of Appendix N1 (Exhibit B-1-10)); and

2. The transmission capacity that the transmission network to the FN/RB

region can support net of the Rainbow Lake area (Alberta side) load (refer to section 6.5 of Appendix N1 (Exhibit B-1-10)).

Please refer to Figure 2-1 of Appendix N-1 (Exhibit B-1-10). The net physical transmission capacity available to BC Hydro is identified in Figure 6-1 of Appendix N1 (Exhibit B-1-10). In that Figure, the line titled “Committed no TMR” is the capacity of the current and committed AESO transmission system without TMR and the line titled “Committed with TMR” is the capacity with TMR. The full calculation is provided in the load/resource balance tables for the portfolios analyzed in the FN RP/LTAP provided in section 10 of Appendix N1 (Exhibit B-1-10).


Page 1 of 1


Exhibit: B-4-2



2.218.4 Please discuss any contractual, regulatory or other similar limits on the capacity of the interconnect.

RESPONSE: Please refer to Appendix N1 (Exhibit B-1-10), and in particular:

• section 2.3.4 with respect to the regulatory regime and regulated service from the AESO;

• sections 5.5.2, 5.5.4 and 5.5.5 with respect to the commercial limits; and

• section 6.5.1 with respect to possible development risks involved with

AESO A2.


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7, pp. 5, 17, 20, 23

2.219.1 Please confirm that Figures 7 and 9 indicate that FNGU Case 2 and 3.2 are approximately equivalent with respect to meeting load under N-1 conditions through 2011.

RESPONSE: Confirmed. For purposes of Appendix N1 (Exhibit B-1-10) analysis, FNGU is assumed to be first available for calendar year 2012. Therefore, the resources are the same in both cases.


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7, pp. 5, 17, 20, 23

2.219.2 Please confirm that Figures 7 and 9 indicate that FNGU Case 2 and 3.2 are approximately equivalent with respect to meeting load under N-1 conditions after about 2015.

RESPONSE: The references in Exhibit B-1-7, the “AESO TMR Required” identified in Table 9 with respect to FNU2 and Table 10 for FNGU Case 3.2 (FNU3) post 2010 are missing from both Figure 7 and Figure 9.

• As identified in Table 9, the portfolio that includes FNU2 and AESO A1 has a firm deficit in all years presented; while

• As identified in Table 10, the portfolio that includes FNU3 and AESO A1

meets the load in all years starting in 2012. Full load/resource balances (graphical and table format) for both cases are provided in section 10 of revised and updated Appendix N1 (Exhibit B-1-10):

• As shown in section 10.9, the portfolio that includes FNU3 and AESO A1 can meet Full N-1 reliability based on the Low Scenario through 2025; while

• As shown in section 10.7, FNU2 AESO A1 never meets the Full N-1

reliability criteria.


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7, pp. 5, 17, 20, 23

2.219.3 Please confirm that FNGU Case 3.2 Net capacity of 75.5 MW under winter peak conditions is capable of meeting the New Inquiries & Reference Forecast until 2015.

RESPONSE: Not confirmed. FNU3 does not on its own have sufficient capacity to meet the New Inquiries & Reference Forecast as was set out in Table 8 of Exhibit B-1-7. Design updates since the filing of Exhibit B-1-7 for the FNU3 have resulted in a reduction in the estimated capacity of FNU3 to 72.5 MW. The New Inquiries & Reference Forecast as was set out in the above mentioned Table 8 identifies a peak demand of 72.7 MW in 2013 and increasing to 73.1 MW in 2015. Please refer to sections 10.4 and 10.9 of Appendix N1 (Exhibit B-1-10) for updated load/resource balances for portfolios with FNU3 plus the AESO A0 (current and committed transmission capability) and FNU3 plus AESO A1 respectively. Please also refer to the response to BCUC IR 2.220.3.


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7, pp. 5, 17, 20, 23

2.219.4 Please explain BC Hydro’s contingency plan for meeting the additional load after 2015.

RESPONSE: Please refer to section 8.3 of Appendix N1 (Exhibit B-1-10).


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7, pp. 5, 17, 20, 23

2.219.5 Please outline the schedule for developing the plans and constructing the facilities to provide the supplies in excess of 75.5 MW.



Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-1, pp .6-49, 6-50 Exhibit: B-1-7, p. 28

2.220.1 BC Hydro states “The only portfolio of resources that BC Hydro is aware of that can provide this requirement on a firm basis is the combination of the AESO Option A1 transmission upgrade and the FNGU Case 3.2”. Please clarify if BC Hydro seeks Commission approval of FNGU Case 3.2 in this LTAP filing.

RESPONSE: Please refer to revised and updated Appendix A (Exhibit B-1-10), setting out BC Hydro’s requested order.


Page 1 of 1


Exhibit: B-4-2



2.220.2 Considering the relatively small differences in load serving ability of Case 2 and Case 3.2 and the inability of Case 3.2 to meet potential additional load growth after about 2015, please explain why the relative costs of the options were not identified as factors to be taken into consideration when comparing the various options?

RESPONSE: Please refer to the response to BCUC IR 2.219.2 with respect to the difference in capability to meet firm load of FNU2 and FNU3. Exhibit B-1-7 was an incremental evidentiary update that included no costs or cost analysis. The revised and updated Appendix N1 (Exhibit B-1-10) contains the full evaluation of the options, including the economic evaluation. In particular, the Option/Portfolio analysis is provided in section 7 of Appendix N1 (Exhibit B-1-10). This section includes the reliability analysis, physical supply analysis and economic analysis. The resulting Fort Nelson Long Term Acquisition Plan is provided in section 8 of Appendix N1 (Exhibit B-1-10).


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Exhibit: B-4-2



2.220.3 Considering that Figure 9 indicates that FNGU Case 3.2 will not be able to supply the objective Low scenario load under N-1 conditions until 2012, please explain why a further year or two of delay should be considered serious enough to rule out other alternatives.

RESPONSE: The addition of FNU3 to the existing and committed resources supplying the Fort Nelson region would provide sufficient capacity to meet the Low Scenario to a Full N-1 reliability measure through 2019. Refer to section 10.4 of Exhibit B-1-10. BC Hydro’s Base Plan in the 2008 FN RP/LTAP (Appendix N1, Exhibit B-1-10), which comprises the portfolio of FNU3 plus the AESO transmission option AESO A1, would provide sufficient capacity to meet the Low Scenario to a Full N1 reliability measure through 2025. Refer to section 10.9 of Appendix N1. BC Hydro’s reasons for proposing that FNU3 be developed and placed in service by the end of 2011 to be in service in 2012 are set out in section 8.1 of Appendix N1. Analysis leading to the Base Plan that proposes proceeding with FNU3 is set out in section 7 of Appendix N1, and in particular, the conclusion to that analysis is provided in section 7.5.3.


Page 1 of 1


Exhibit: B-4-2



2.220.4 For FNGU: Case 2, please outline the construction schedule, and identify the period(s) when no power would be available from FNG.



Page 1 of 1


Exhibit: B-4-2



2.220.5 Please repeat the previous question for FNGU: Case 3.2.



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Exhibit: B-4-2



2.221.1 Please provide estimates of the incremental capital costs for each of FNG, FNGU: Case 2 and FNGU: Case 3.2, and include the level of accuracy of each estimate.

RESPONSE: The estimated incremental capital cost for FNG is $2.0 million and $0.1 million in F2009 and F2010 respectively. Please refer to Table 2-7 of Appendix N2 (Exhibit B-1-10) for the capital cost for FNU2 and FNU3.


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Exhibit: B-4-2



2.221.2 What are the annual depreciation amount and the current net book value of FNG?

RESPONSE: At the end of August 2008, the net book value of FNG was $36.2 million and the annual depreciation is $1.8 million.


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Exhibit: B-4-2



2.221.3 Please provide estimates of the annual capital charges for each of FNG, FNGU: Case 2 and FNGU: Case 3.2.

RESPONSE: Please refer to Table 2-8 of Appendix N2 (Exhibit B-1-10).


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Exhibit: B-4-2



2.221.4 Please provide estimates of the annual OM&A expenses for FNG, FNGU: Case 2 and FNGU: Case 3.2.



Page 1 of 1


Exhibit: B-4-2



2.221.5 Please compare the annual costs to ratepayers of FNG, FNGU: Case 2 and FNGU: Case 3.2.

RESPONSE: Please refer to Table 2-8 of Appendix N2 (Exhibit B-1-10) with respect to the annual costs to ratepayers if FNG/FNU2/FNU3 operate at full capacity. With respect to the annual costs to ratepayers for the performance of FNG/FNU2/FNU3 under a variety of potential operating conditions, please refer to section 7.5.2.3 of Appendix N1 (Exhibit B-1-10). The present value of costs presented in this section would be equal to the average cost per year to rate payers.


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7; pp. 5, 24-27

2.222.1 As FNG has a capacity of 47.8 MW, please confirm that FNG plus a CCGT with a capacity of 27.7 MW (75.5 – 47.8) would provide the same amount of capacity as FNGU: Case 3.2.

RESPONSE: Confirmed. Excluding minor differences that may exist in any final product, a CCGT with a capacity of 27.7 MW (75.5 – 47.8 MW) would provide the same amount of capacity as FNU3. A 31 MW CCGT (called C31) was the design size that most closely matched the requested characteristics that BC Hydro was able to investigate. An estimate of the characteristics of such a plant, including capital cost, is provided in section 6.3 of Appendix N1 (Exhibit B-1-10). An economic comparison of portfolios that contain FNU3 to portfolios that contain C31 is provided in section 7.5.2.2 of Appendix N1 (Exhibit B-1-10). This analysis is from a ratepayers perspective. The load/resource balances for portfolios that were compared are provided in section 10 of Appendix N1. As identified in the referenced sections, FNU3 is a preferable resource from both a cost and a scheduling perspective.


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7; pp. 5, 24-27

2.222.2 Further to page 25, please provide an estimate of the capital cost and in-service date of a new greenfield CCGT with a capacity of approximately 27.7 MW.



Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7; pp. 5, 24-27

2.222.3 Please compare the annual costs to ratepayers of the alternative of retaining FNG and the construction of a smaller new CCGT.



Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7; pp. 5, 24-27

2.222.4 Please discuss whether the difference in in-service dates between such a smaller new CCGT and FNGU: Case 3.2 would be material in the circumstances.



Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7; pp. 5, 24-27

2.223.1 Further to Section 2.10.3.2, please provide descriptions of the six bioenergy projects, including the MW of capacity that would be expected to be available from each.

RESPONSE: The responses to the Fort Nelson Request for Expressions of Interest (RFEOI) indicated potential private sector projects ranging from 0.1 MW up to 30 MW in capacity with fuels being biomass from woodwaste for five of the projects and municipal solid waste for one of the projects. Note that the responses to the Fort Nelson RFEOI are not binding price bids and do not necessarily reflect viable projects. During 2007 BC Hydro conducted the Bioenergy RFEOI and the Fort Nelson RFEOI which provided information regarding the potential cost of power from bioenergy projects. Based on both RFEOIs, the estimated power cost for new bioenergy projects ranged between $150 and $175 per MWh. In section 3.3.3 (Exhibit B-1), BC Hydro estimated that the UEC for wood-based biomass projects fell in a range of $104 to $158 per MWh. This estimated cost of power comes with significant delivery and development risk due to the variable nature of biofuel availability in various regions of the province and the difficulties associated with taking on fuel risk. Thus, there is no certainty that the cost estimates for bioenergy power will be actually achieved in competitive acquisition processes.


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7; pp. 5, 24-27

2.223.2 Assuming FNG remains in service and AESO Option A1 upgrade goes ahead, please discuss the ability of the bioenergy projects to provide a sufficient amount of capacity that has adequate reliability and dispatchability.

RESPONSE: Please refer to sections 6.4, 7.5.1.5 and 7.5.2.1 of Appendix N1 (Exhibit B-1-10).


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7; pp. 5, 24-27

2.223.3 What does BC Hydro expect would be the cost to ratepayers of power from the bioenergy projects? Please explain the basis of the estimate.



Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7; pp. 5, 24-27

2.223.4 Assuming the bioenergy projects are in effect base loaded, what would be the expected annual cost of power from these projects?

RESPONSE: With respect to the price range from the two RFEOIs conducted in 2007, please refer to the response to BCUC IR 2.223.1. For a 10 MW biomass facility with an assumed 90 per cent load factor, the annual power costs would approximate $11 to $14 million.


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7; pp. 5, 24-27

2.223.5 What would be the expected net annual savings when the reduced fuel consumption at FNG and the reduced power purchases from the AESO are taken into consideration?

RESPONSE: Please refer to section 7.5.2.1 of Appendix N1 (Exhibit B-1-10).


Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7; pp. 5, 24-27

2.223.6 Please expand Table 6 on page 6 to include the case where the bioenergy projects are base loaded, with FNG treated as dispatchable generation.



Page 1 of 1


Exhibit: B-4-2


Exhibit: B-1-7; pp. 5, 24-27

2.223.7 Please provide an overall assessment of the costs and benefits of the alternatives of retaining FNG and obtaining the additional power from either a smaller new CCGT or from bioenergy projects, compared to FNGU: Cases 2 and 3.2.

RESPONSE: Please refer to sections 7.5.2.1, 7.5.2.2, 7.5.3 and 10 of Appendix N1 (Exhibit B-1-10).


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Exhibit: B-4-2


Exhibit: B-1-7, p. 18 FNGU Alberta Transmission Option

2.224.1 Does BC Hydro have any preliminary indication, or has it approached the AESO for an indication, of the cost of arranging additional capacity supply from the Northwest Alberta Area Upgrade project?

RESPONSE: The Northwest Alberta Area Upgrade project is identified in Appendix N1, (Exhibit B-1-10) as the Alberta transmission option AESO A0 (section 6.5.1 of Appendix N1). As identified in section 7.3 of Appendix N1, BC Hydro has made Preliminary Assessment Applications (PAAs) to the AESO for additional capacity. At the time of this IR response, the AESO had initiated its internal request review process, but has not yet provided a schedule for completion of the review or resulting terms of service. The capacity associated with the PAAs, if ultimately contracted in full, would increase the demand service with the AESO to 47 MW in mid 2009 and 75 MW starting in 2012.


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Exhibit: B-4-2


Exhibit: B-3, EnCana IR 1.9.1 FNGU Development Load Times

2.225.1 The IR requested lead times required to develop oil and gas production such as that reflected in the three load growth scenarios. BC Hydro replied that since the information was project specific it was not able to provide the requested information. Has BC Hydro approached the proponents of the three projects in order to understand lead time? Since, if the lead time for the projects were in excess of the lead times for FNGU, BC Hydro would be able to perform the upgrades after the projects were committed to by the proponents, and thereby not risk constructing assets that turn out not to be required, wouldn’t it be prudent for BC Hydro to acquire such information?

RESPONSE: Project schedules for oil and gas development are part of discussions between BC Hydro and project proponents. BC Hydro’s main point in the response to EnCana IR 1.9.1 (Exhibit B-3) is that it was not possible to provide a single generic lead time for oil and gas sector development since lead times are significantly dependent on the nature of the specific project and the project proponent. BC Hydro does not propose to commit significant capital investment for large new supply, where such supply could cause material stranded assets in the absence of firm commitment from customers that the new large loads will materialize. Project proponents are being made aware that the sooner they provide project information to BC Hydro and commitments for receiving electricity service, the sooner BC Hydro can develop new supply for meeting their needs. With respect to FNU3 and the Appendix N1 (Exhibit B-1-10), BC Hydro’s assessment of the commercial risk of stranded assets resulting from the identified actions is provided in section 7.5.2.4.5 of Appendix N1 (Exhibit B-1-10). With respect to this IR and the impact that uncertainty of both the magnitude and lead time of potential load growth could have on construction cost risk:

• BC Hydro considers there to be little likelihood of the load being below the Low Scenario. Therefore, the risk of load that FNU3 is intended to serve not materializing is considered low;

• The longer term options (BCTC transmission, AESO transmission or a new

CCGT) are being advanced through Investigation and Definition phases to

British Columbia Utilities Commission Information Request No. 2.225.1 Dated: September 11, 2008 British Columbia Hydro & Power Authority Response issued October 24, 2008

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British Columbia Hydro & Power Authority BC Hydro 2008 LTAP Application

Exhibit: B-4-2

retain each as an option in the event of higher load growth. Development costs for these phases of the identified projects are relatively low;

• None of the longer term options could be committed to full implementation

before the end of 2009 given their current stages of development, leaving any decisions to proceed or cancel such projects for some point in the future; and

• Regardless of which of the longer term options is ultimately committed to,

if any, the Fort Nelson upgrade to CCGT will provide capacity related services to the Fort Nelson region.

2008 10 23 exhibit b 4 2 bch fort nelson related ...€¦ · fort nelson evidentiary update ... bc...

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