2012 05 24 exhibit b 30 bc hydro ires 4 to bcuc and intv · 1.3 is n‐1 reliability being provided...

BC hydro REGENERATION

Janet Fraser Chief Regulatory Officer Phone: 604-623-4046 Fax: 604-623-4407

s m bchyd roreg u latoryg rou [email protected]

May 24,2012

Ms. Alanna Gillis Acting Commission Secretary British Columbia Utilities Commission Sixth Floor - 900 Howe Street Vancouver, BC V6Z 2N3

Dear Ms. Gillis:

RE: Project No. 3698640 British Columbia Utilities Commission (BCUC) British Columbia Hydro and Power Authority (BC Hydro) Application for a Certificate of Public Convenience and Necessity (CPCN) for the Dawson CreeklChetwynd Area Transmission (DCAT) Project BC Hydro Responses to Information Requests

BC Hydro encloses its Information Responses as follows:

Exhibit B-29 BC Hydro Public Responses to Round 3 BCUC, BCUC Panel and Intervener Information Requests as set out in Appendix B to BCUC Order G-56-12 and BC Hydro Exhibit B-27

Exhibit B-29-1 BC Hydro Confidential Responses to Round 3 BCUC, BCUC Panel and Interveners as set out in Appendix B to BCUC Order G-56-12 and BC Hydro Exhibit B-27

Exhibit B-30 BC Hydro Responses to all Round 4 BCUC and Intervener Information Requests except for the responses to CECBC which will be filed on May 25,2012

For further information, please contact Geoff Higgins at 604:..623-4121 or bye-mail at [email protected].

,

. (for) Janet Fras r Chief Regulatory Officer

gh/af Copy to: BCUC Project No. 3698640 (DCAT) Registered Intervener Distribution List.

British Columbia Hydro and Power Authority, 333 Dunsmu ir Street, Vancouver BC V6B 5R3 www.bchydro.com

B-30

markhuds

BCH-CPCN Dawson Creek-Chetwynd Area Transmission Project

markhuds

Highlight

ALANNA GILLIS ACTING COMMISSION SECRETARY [email protected] web site: http://www.bcuc.com

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, BC CANADA V6Z 2N3

TELEPHONE: (604) 660‐4700 BC TOLL FREE: 1‐800‐663‐1385 FACSIMILE: (604) 660‐1102

Log No. 37327

PF/BCH‐DC/CAT CPCN/A‐29_Commission IR No 4

VIA EMAIL [email protected] May 11, 2012 BC HYDRO – DAWSON CREEK/CHETWYND

TRANSMISSION PROJECT CPCN EXHIBIT A‐29 Ms. Janet Fraser Chief Regulatory Officer British Columbia Hydro and Power Authority 333 Dunsmuir Street Vancouver, BC V6B 5R3 Dear Ms. Fraser:

Re: British Columbia Hydro and Power Authority Project No. 3698640/Order G‐132‐11

Certificate of Public Convenience and Necessity Application for the Dawson Creek/Chetwynd Area Transmission Project

Further to Commission Order G‐56‐12, which established a Revised Regulatory Timetable with respect to the above noted Application, enclosed please find Commission Information Request No. 4. In accordance with the Revised Regulatory Timetable, please file your responses electronically with the Commission by Thursday, May 24, 2012 in accordance with the Commission’s Document Filing Protocols, effective May 16, 2005. Yours truly, Alanna Gillis /yl Enclosure cc: Registered Interveners (BCH‐DC/Cat‐RI)

BCH‐Dawson Creek/Chetwynd 1 Commission Information Request No. 4

REQUESTOR NAME: British Columbia Utilities Commission INFORMATION REQUEST ROUND NO: 4 TO: British Columbia Hydro and Power Authority DATE: May 11, 2012 PROJECT NO: 3698640 APPLICATION NAME: Dawson Creek/Chetwynd Area Transmission Project

1.0 Reference: Project Alternatives Exhibit BC Hydro F2012 to F2014 RRA, BCUC 2.50.1 Exhibit B‐22, Q&A 13

Q13. BC Hydro has indicated that the aggregate load of the five new customers cannot be served to a N‐1 standard, even if DCAT Project is built. What assurances have you provided to these customers that you will be able to eventually meet the N‐1 standard in the context of their load requirements? A13. BC Hydro has indicated that under MRS it is required to serve all its bulk system customers, including their new load, to the N‐1 standard. It has further advised them that it expects that this objective will be accomplished through the Phase 2 GDAT project but that this approach is dependent upon the British Columbia Utilities Commission (BCUC) issuing a Certificate of Public Convenience and Necessity (CPCN) first for the Dawson Creek/Chetwynd Area Transmission (DCAT) Project and then for a GMS Dawson Creek Area Transmission (GDAT) project. If the BCUC declines to issue a CPCN for one or both of these projects, BC Hydro has indicated that it will seek appropriate alternative ways to meet its obligation to serve these customers (underlining added for emphasis).

1.1 Please explain how the DCAT load will be served if the Commission declines to issue a CPCN for

one or both of these projects (first for the DCAT Project and then for a GDAT project). Please describe the alternate means/ways that BC Hydro is considering to meet its obligation to serve “these customers”.

1.1.1 What is the current stage of development of these options, their associated implementation costs, and what would be the proposed in service date for each of these alternatives.

1.2 Please discuss the pros and cons of utilizing these alternative means as a bridge to permit time for another option (other than the preferred alternative) to be investigated and implemented. The discussion should encompass the total picture to serve the area over the 30 year planning horizon i.e. both the DCAT and GDAT phases.


1.3 Is N‐1 reliability being provided to Tembec (LAP) as part of the Project where they currently do not enjoy this added reliability expense? Please discuss.

2.0 Reference: Shell Canada Ltd. Exhibit B‐22, Section 2.4, p. 18

“Shell first contacted BC Hydro in April 2009 to inquire about potential new load in the DCAT Project area. In October 2009, at a meeting between BC Hydro’s Key Accounts Manager and Shell representatives, Shell indicated that it was interested in obtaining at least 120 MW of service from BC Hydro.” (Exhibit B‐22, Q&A 45)

“On October 21, 2010 Shell submitted a request for a joint System Impact and Facilities Study. At that time it estimated a future total load of 281 MW for five potential gas plants located in Groundbirch area.” (Exhibit B‐22 Q&A 46)

2.1 What is the timing of the additional capacity requested from this customer? Will this potential additional load all be served at transmission levels from SLS and/or BMT? Please discuss BC Hydro’s understanding to date.

3.0 Reference: Tariff Supplement 6 (TS 6) Exhibit B‐22, Cover Letter, pp. 3‐4

“Under TS 6, new and expanding transmission voltage customers (New Loads) are required to pay for the cost of any dedicated facilities to extend or reinforce the transmission system to serve their new load. New Loads may also be required to contribute to additions and alterations to BC Hydro's existing transmission facilities that are required to serve their load. For very large loads (> 150 MV.A), the incremental cost of generation plant and associated transmission, or transmission lines of 500 kV and over required to serve the New Load, are also included as system reinforcement costs that must be paid by the customer.”

3.1 In some instances, a customer may not add their entire anticipated new load at the same time. For example, a plant may be built in phases with the first phase adding 100 MW and a subsequent phase adding an additional 100 MW. What is the existing tariff or BC Hydro policy that defines the timing of capacity requests totaling 150 MV.A or greater such that the customer is not obligated to contribute to generation reinforcement costs? For greater clarity, if a customer stages an application with first phase of 100 MW, for an entire service totaling 150 MV.A or greater, would they avoid contributing to generation reinforcement costs that would otherwise be payable if all load was added at the same time? Please explain.


4.0 Reference: Project Alternatives Exhibit B‐22, Section 4 System Planning, pp. 35‐72

“The new forecast suggests that load can be expected to ramp up a little more slowly over the next two years and then rise to a higher and more sustained peak.” (Exhibit B‐22, Q&A 64)

4.1 As a result of the updated DCAT load forecast, will BC Hydro be advancing the GDAT project and if so, when is the CPCN filing anticipated?

“With the updated load forecast both Alternatives 1 and 2 may require additional system upgrades subsequent to the F2016 stage to meet the revised load forecast over the 30 year planning period.” (Exhibit B‐22, Q&A 76)

4.2 Given BC Hydro’s information available to date, please describe the most likely system upgrades that will be required i.e. capacitor additions, additional transmission line(s) or substations, Static Var Compensator or other.

4.3 Given:

• the Clean Energy Act (CEA’s) self sufficiency requirement in 2016;

• the Integrated Resource Plan (IRP) has not been approved;

• the uncertainty of the rate of load increase in the DCAT area; and

• the system is not anticipated to be in surplus condition until F2017. (Exhibit B‐22 Q&A 68, p. 36)

Please discuss if the provincial government may have to relax the restrictions on Burrard Generating Station (BGS) in order to meet the load associated with DCAT and/or with LNG facilities (Exhibit B‐22, Q&A 90) until new clean resources can be acquired from Independent Power Producer’s (IPPs) (currently estimated at $116 MW/h per Exhibit B‐22, Q&A 67). For greater clarity, can enough BC energy be acquired from IPPs in time to meet the forecasted load without running BGS? Please discuss.

4.3.1 Please discuss if the alternative to not running BGS is to lock into $116 MW/h contracts with IPPs and sell this energy at $50 MW/h when the system has surplus capacity. (Exhibit B‐22, Q&A 67)

4.4 Please explain BC Hydro’s rationale for not accepting line taps as an acceptable technical alternative to lower costs.

4.4.1 Please discuss if line taps are a viable technical solution or not? Are there other utilities that employ line taps for customers served at 230 kV? Please discuss.

4.4.2 Are “reliability concerns” and “lower reliability” the only concerns for not employing line taps? Please discuss.


4.5 Could the reluctance to use line taps be considered as an example of: over engineering, the desire to be the best and/or low risk tolerance as mentioned in the BC Hydro 2011 Government Report on BC Hydro? Please discuss each perceived issue.

4.6 BC Hydro does not appear to favor a line tap and a single 230/138 kV transformer as sufficient backup to Chetwynd (CWD’s) supply (alternative B4 and B5, A81, p. 54). Please confirm and explain why line taps are not acceptable when this contingency would only be used in an emergency, for planned maintenance to 1L361 and/or maintenance on a few CWD substation assets.

4.6.1 BC Hydro uses Present Value of losses in justifying the preferred alternative or discounting some of the B1 to B5 alternatives. Given that the frequency of utilizing this back‐up supply would be low, please explain why this alternate 138 kV source to CWD could not be de‐energized or CBO (circuit breaker open) until required. (Q&A 78, p. 51)

4.7 Some of the responses (Exhibit B‐22, Alt B3, p. 43 for example) indicate lower reliability to the Tumbler Ridge load for the loss of a 230 kV line‐please discuss further as a line loss from Gordon M. Shrum to Wildmare and/or Sukunka would appear to be common to any of the line B1 to B5 Alternatives or to the preferred solution prior to the completion of GDAT.

“This alternative was rejected at the planning stage because BC Hydro was not able to obtain sufficient information from the customer in the Groundbirch area about the location of new loads to allow it to locate a site for a single substation. A two substation configuration, albeit more costly at the outset, allows greater ability to react to the actual location of loads when known. While BC Hydro has enhanced knowledge of the likely location of some of the loads now, uncertainty remains. A significant amount of work has occurred to identify a potential substation location for the Groundbirch POI. There is a high likelihood the identified site may not be able to accommodate the SLS Facilities.”

4.8 Please confirm that the locations of Saturn and Sunset (Exhibit B‐22, Q&A 50, p. 20) remain unknown as of Exhibit B‐22’s submission date.

4.8.1 Please describe the Point of Interconnection for both Saturn and Sunset. For greater clarity, will there be two 230 kV lines emanating from SLS to serve both Saturn and Sunset or will there be four lines coming from SLS (two to Saturn and two to Sunset). Please provide the anticipated single line diagram for the Goundbirch area over the planning period showing all transmission customers’ interconnections to SLS and/or Bear Mountain Terminal.

4.9 The discussion on Alternatives B4 & B5 (Exhibit B‐22, Q&A81, p. 54) indicates that the costs are expected to be higher than the cost estimate for the Project. Please discuss the overall cost comparison in relation to incorporating this added 30 km of 230 kV double circuit right‐of‐way as part of the GDAT project. For greater clarity, the response did not indicate if the GDAT project would be lower by a similar amount that would be added for these solutions to the DCAT project i.e. please compare the total end state costs (at a high order of magnitude level) upon completion of both the DCAT and GDAT phases. Please include a discussion on the overall footprint required for both BC Hydro’s and the transmission customers’ facilities in the comparison.


4.10 BC Hydro states that Alternatives B4 and B5 could not meet the required in‐service date of the DCAT Project. In relation to the request for further information on how the load would be served in Commission IR 1.1 above, please explain how and if BC Hydro could serve the DCAT load until alternatives B4 or B5 could be implemented in F2017. (Exhibit B‐22, Q&A 91)

4.11 As depicted below‐please confirm that a larger footprint is required after Sundance Lakes (SLS) and the 230 kV customers’ Right‐of‐Way is/are added than for Alternative B1, B4 & B5. For greater clarity, please confirm that the overall footprint is smaller for Alternative B1, B4 & B5 when SLS and the customers’ transmission line requirements are included (note: only B5 and the preferred alternatives are illustrated). Please discuss the relative size of the footprint for these options (Project, B1, B4 and B5) in terms of approximate hectare requirements.

‐ ‐

Alternative B5 Modified to Include SLS and Customer Lines

SLS

Total 230 kV ROW


‐

5.0 Reference: N‐1 Evidence Exhibit B‐22 Section 5, pp. 73‐74

5.1 Is N‐1 reliability being provided to the new transmission customers as part of the Project? If yes, are the new customers contributing to these added costs or is BC Hydro obligated to serve these new customers at the higher standard? Please explain and include the cost contributions in the reply.

6.0 Reference: TS 6 Exhibit B‐22, Q&A 103

6.1 Figure 5 is somewhat confusing‐ please confirm that the new transmission customers will pay for all transmission connection costs for facilities 90 meters downstream of BC Hydro’s new substation and not 90 meters downstream of BC Hydro’s closest transmission line.

Customer Sub

Customer DC 230 kV Lines

Total 230 kV ROW


7.0 Reference: Load Resource Balance Exhibit B‐22 Q&A 68, p. 36; A‐21 BCUC 3.83 Series

BC Hydro has committed to answering BCUC 3.83 Series of IRs (Exhibit B‐27), however the questions need to be modified in the context of: the latest in service date; updated LRB; and supplemental evidence, in order to understand the possible impacts the Project will have on rates (particularly during a low water year(s) when the system does not have surplus energy available ‐ currently forecasted to be F2017 or later) and the energy would have to be purchased from IPPs at $116/MWh to serve the 5 new DCAT customers. (Exhibit B‐22, Q&A 67) It is understood that BC Hydro does not purchase energy for a specific project and therefore should not attribute specific energy to a project, however the fact remains that the 5 new gas producers will have an impact on rates and that is the context for the information requested.

7.1 BCUC IR 3.8.3.1 a response is requested to the IR as written.

7.2 BCUC 3.8.3.2 changes are underlined.

Given the circumstances of no system surplus energy available and the current rate structure‐would a reasonable order of magnitude calculation of the approximate BC Hydro costs to acquire the energy to service these customers be 176 MW x 0.85 load factor x 8760 hrs/yr x $116 /MWh = $152 million ? (Exhibit B‐14, 2.25.1)


Given the circumstances of no system surplus energy available and the current rate structure‐would a reasonable estimate of the net difference (i.e. $152 m ‐$58 m) be an approximate $94 million annual first year loss and further increasing as more load is added until such time the load drops off? Please confirm or provide BC Hydro’s estimate. (Exhibit B‐14, 2.19.5, p. 1)


Given the circumstances of no system surplus energy available and the current rate structure‐would a reasonable estimate of the net loss associated with the total load of 176 MW be $2.82 billion ($94 million X 30 years) at the current rate? Please confirm that potential losses from these five customers for future load increases beyond the first year of normal operations are not factored into this calculation. (Exhibit B‐14, 2.19.6, p. 1)



8.0 Reference: N‐1 Exhibit A‐21, BCUC 3.12.1; T2: p. 166

BC Hydro objected to answering BCUC 3.12.1 “What are the circumstances that would supply a new customer connection with N‐1 level of service where the present system would have to be upgraded from N‐0? Please discuss.”


8.1 For greater clarity‐please describe BC Hydro’s understanding of the application of Mandatory Reliability Standards (MRS) around meeting new customer load to N‐1 level standard when you’re at N‐0. Please include the applicable MRS reference(s).

8.1.1 What contributions would BC Hydro make and what contributions would be required from the customer?

8.2 Please explain the planning criteria (under existing tariff(s) or applicable MRS standard) that BC Hydro employs to determine if customers will be served by a radial system or by a network?

9.0 Reference: Rate Impact Exhibit A‐21, BCUC 3.27.1; B‐27 Exhibit BC Hydro F12‐14 RRA, B‐23, BCUC 2.50

BC Hydro committed to answering BCUC 3.27.1, 3.27.1.1 and 3.27.1.2, however the response will be, in part, based on the supplemental evidence of the revised in service date of April 30, 2014, and the assertion that the system currently has forecasted surplus capacity until F2017 (B‐22 Q&A 68, p. 36). Since the rate impact of the Project will not be material until the following test period, these IRs have been replaced as below. To be clear, a response to BCUC 3.27.1, 3.27.1.1 and 3.27.1.2 is no longer required.

‐

9.1 Please provide a range of forecasted %Rate Increases for the years F2015 to F2019 under the assumptions of Cost of Energy 1) when the system in surplus energy and 2) when the system has no surplus energy.

9.2 Please explain if BC Hydro intends to enter into additional IPP contracts to provide insurance that it will have sufficient energy to supply the Project.


10.0 Reference: N‐1 Evidence Exhibit B‐22, Supplemental Evidence Q&A 92 and Q&A 93

The DCAT Project will allow BC Hydro to serve 185 MW in the DCAT Project area at the N‐1 standard. BC Hydro expects load to exceed 185 MW before or soon after the DCAT Project can be brought into service. Accordingly, BC Hydro has advised all new industrial customers that they will need to participate in a remedial action scheme (RAS) until a future GDAT project can be brought into service.... The DCAT Project (and the GDAT project) are planned to ensure that service to the DCAT Project area continues to meet the N‐1 standard.

Q: It would seem that the DCAT projects compliance with N‐1 standard will be delayed until future phases. Therefore, the full cost of system reinforcement to accommodate the new load, in compliance with the required reliability standard, will be incurred over the course of several years. However, BC Hydro is only seeking financial support from new customers from the portion of these costs that will be incurred in the DCAT phase. How does BC Hydro intend to have further system reinforcement costs supported by the customers? Does the phasing of this project place the reinforcement contribution burden on the broader public (i.e. all provincial ratepayers)?

11.0 Reference: TS 6 Exhibit B‐22, Supplemental Evidence Q&A 101

Q&A 101 states: The DCAT Project does not include Basic Transmission Extension costs for the individual customer, though these exist on the BC Hydro side of the Point of Delivery. Also, the Project does not include any equipment or costs on the customer side of the Point of Delivery.

Section 1(b)(ii) of TS 6 states: “the Basic Transmission Extension is the responsibility of B.C. Hydro, who shall undertake the required work at the Customer's expense.” Section 6(b)(ii) of TS 6 states that customers will pay the Actual Costs, as incurred by BC Hydro, for the Basic Transmission Extension, up to a maximum amount equal to the Agreed Maximum Costs, determined pursuant to clause 4, in accordance with periodic billings, as set out in a Facilities Agreement.

Please confirm that new customers requiring a Basic Transmission Extension will pay the Actual Costs and provide those Actual Costs. Please provide the Facilities Agreements for all customers that require Basic Transmission Extensions, on a confidential basis if required. If those agreements have not been executed yet, please provide draft agreements.

British Columbia Utilities Commission Information Request No. 4.1.1 Dated: May 11, 2012 British Columbia Hydro & Power Authority Response issued May 24, 2012

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British Columbia Hydro & Power Authority Application for a Certificate of Public Convenience and Necessity (CPCN) for the Dawson Creek/Chetwynd Area Transmission Project (DCAT)

Exhibit: B-30

1.0 Reference: Project Alternatives

Exhibit BC Hydro F2012 to F2014 RRA, BCUC 2.50.1 Exhibit B-22, Q&A 13

Q13. BC Hydro has indicated that the aggregate load of the five new customers cannot be served to a N-1 standard, even if DCAT Project is built. What assurances have you provided to these customers that you will be able to eventually meet the N-1 standard in the context of their load requirements?

A13. BC Hydro has indicated that under MRS it is required to serve all its bulk system customers, including their new load, to the N-1 standard. It has further advised them that it expects that this objective will be accomplished through the Phase 2 GDAT project but that this approach is dependent upon the British Columbia Utilities Commission (BCUC) issuing a Certificate of Public Convenience and Necessity (CPCN) first for the Dawson Creek/Chetwynd Area Transmission (DCAT) Project and then for a GMS Dawson Creek Area Transmission (GDAT) project. If the BCUC declines to issue a CPCN for one or both of these projects, BC Hydro has indicated that it will seek appropriate alternative ways to meet its obligation to serve these customers (underlining added for emphasis).

4.1.1 Please explain how the DCAT load will be served if the Commission declines to issue a CPCN for one or both of these projects (first for the DCAT Project and then for a GDAT project). Please describe the alternate means/ways that BC Hydro is considering to meet its obligation to serve “these customers”.

RESPONSE:

A BCUC decision to decline a CPCN for the DCAT Project would delay BC Hydro’s ability to serve customer load. System requirements may also change as a result of such a decision. In particular, the load forecast may be materially impacted if BC Hydro is unable to serve customers’ needs in the requested timeframes. BC Hydro would evaluate needs and undertake further system planning to consider system conditions and requirements evident at that time.

BC Hydro is unable to speculate on possible alternatives in light of uncertain requirements.

Refer also to the responses to BCSEA IRs 2.28.1 and 2.28.2.

British Columbia Utilities Commission Information Request No. 4.1.1.1 Dated: May 11, 2012 British Columbia Hydro & Power Authority Response issued May 24, 2012

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Exhibit: B-30





4.1.1.1 What is the current stage of development of these options, their associated implementation costs, and what would be the proposed in service date for each of these alternatives.

RESPONSE:

Please refer to response to BCUC IR 4.1.1.


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Exhibit: B-30





4.1.2 Please discuss the pros and cons of utilizing these alternative means as a bridge to permit time for another option (other than the preferred alternative) to be investigated and implemented. The discussion should encompass the total picture to serve the area over the 30 year planning horizon i.e. both the DCAT and GDAT phases.

RESPONSE:

Refer to the response to BCUC IR 4.1.1.


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Exhibit: B-30





4.1.3 Is N-1 reliability being provided to Tembec (LAP) as part of the Project where they currently do not enjoy this added reliability expense? Please discuss.

RESPONSE:

Tembec (LAP) will not have N-1 level of service until a GDAT project is implemented. With the loss of any of the 230 kV lines between GMS and SNK and SLS, the LAP load would be shed.


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Exhibit: B-30

2.0 Reference: Shell Canada Ltd.

Exhibit B-22, Section 2.4, p. 18

“Shell first contacted BC Hydro in April 2009 to inquire about potential new load in the DCAT Project area. In October 2009, at a meeting between BC Hydro’s Key Accounts Manager and Shell representatives, Shell indicated that it was interested in obtaining at least 120 MW of service from BC Hydro.” (Exhibit B-22, Q&A 45)

“On October 21, 2010 Shell submitted a request for a joint System Impact and Facilities Study. At that time it estimated a future total load of 281 MW for five potential gas plants located in Groundbirch area.” (Exhibit B-22 Q&A 46)

4.2.1 What is the timing of the additional capacity requested from this customer? Will this potential additional load all be served at transmission levels from SLS and/or BMT? Please discuss BC Hydro’s understanding to date.

RESPONSE

No additional service beyond the 120 MW has been requested by this customer. Please refer to Exhibit B-22, Q&A 49.

If the future load did materialize during the planning period, BC Hydro expects it would be served from the transmission system.


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Exhibit: B-30

3.0 Reference: Tariff Supplement 6 (TS 6)

Exhibit B-22, Cover Letter, pp. 3-4

“Under TS 6, new and expanding transmission voltage customers (New Loads) are required to pay for the cost of any dedicated facilities to extend or reinforce the transmission system to serve their new load. New Loads may also be required to contribute to additions and alterations to BC Hydro's existing transmission facilities that are required to serve their load. For very large loads (> 150 MV.A), the incremental cost of generation plant and associated transmission, or transmission lines of 500 kV and over required to serve the New Load, are also included as system reinforcement costs that must be paid by the customer.”

4.3.1 In some instances, a customer may not add their entire anticipated new load at the same time. For example, a plant may be built in phases with the first phase adding 100 MW and a subsequent phase adding an additional 100 MW. What is the existing tariff or BC Hydro policy that defines the timing of capacity requests totaling 150 MV.A or greater such that the customer is not obligated to contribute to generation reinforcement costs? For greater clarity, if a customer stages an application with first phase of 100 MW, for an entire service totaling 150 MV.A or greater, would they avoid contributing to generation reinforcement costs that would otherwise be payable if all load was added at the same time? Please explain.

RESPONSE:

The 150 MV.A provision of TS 6 does not specifically address the timing of incremental load increases. However, in a case where BC Hydro has information that a customer is, or may be, planning to add load to BC Hydro’s system on a phased basis – whether the load is above or below 150 MV.A – BC Hydro will assess what constitutes the “Customer’s Plant” for purposes of the application of TS 6 and the determination of the system reinforcements and other facilities necessary to serve the Customer’s Plant. Factors BC Hydro would consider include:

Information obtained from the customer, e.g. regarding the substation and other electrical facilities the customer would itself be installing;

Public announcements by the customer concerning its project;


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Exhibit: B-30

Information contained in environmental or other applications and permits relating to the project;

Any plans that the customer has to develop the project in phases within a short period of time, e.g., 1-3 years.

If it appeared that the customer planned to develop the entire project (even though in phased approach) in a relatively short period of time, and had sized its own electrical equipment so as to serve the full, aggregated load, it is likely BC Hydro would treat it as a single “Customer’s Plant” and apply TS 6 accordingly. On the other hand, if the customer’s plans for expansion, or adding of additional load, were tentative, with the possible additional load being added several years in the future, and subject to other contingencies, then it is likely BC Hydro would not treat it as a single “Customer’s Plant” at the time the application for service was received from the customer.

It should also be noted that it is not in the customer’s best interest to attempt to circumvent the 150 MV.A provision by underestimating their load, because doing so increases the risk that BC Hydro will be unable to provide timely and adequate service, including the risk that the customer will be required to accept some form of interruptible service.


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Exhibit: B-30


Exhibit B-22, Section 4 System Planning, pp. 35-72

“The new forecast suggests that load can be expected to ramp up a little more slowly over the next two years and then rise to a higher and more sustained peak.” (Exhibit B-22, Q&A 64)

4.4.1 As a result of the updated DCAT load forecast, will BC Hydro be advancing the GDAT project and if so, when is the CPCN filing anticipated?

RESPONSE:

Please refer to the response to BCUC IR 1.52.1 with respect to timing of an application for a GDAT project.

The updated DCAT load forecast does not advance the timing of a GDAT application.


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Exhibit: B-30



“With the updated load forecast both Alternatives 1 and 2 may require additional system upgrades subsequent to the F2016 stage to meet the revised load forecast over the 30 year planning period.” (Exhibit B-22, Q&A 76)

4.4.2 Given BC Hydro’s information available to date, please describe the most likely system upgrades that will be required i.e. capacitor additions, additional transmission line(s) or substations, Static Var Compensator or other.

RESPONSE:

With the updated load forecast, the future system with the F2016 stage reinforcement will be thermally constrained at approximately F2031. Consideration of regional load growth development that would result in further system reinforcements is discussed in response to BCUC IR 1.18.3. Given the late staging of the possible system reinforcement under the current forecast scenario, detailed system planning is not warranted at this time.


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Exhibit: B-30




4.4.3 Given:

the Clean Energy Act (CEA’s) self sufficiency requirement in 2016;

the Integrated Resource Plan (IRP) has not been approved; the uncertainty of the rate of load increase in the DCAT area;

and the system is not anticipated to be in surplus condition until

F2017. (Exhibit B-22 Q&A 68, p. 36)

Please discuss if the provincial government may have to relax the restrictions on Burrard Generating Station (BGS) in order to meet the load associated with DCAT and/or with LNG facilities (Exhibit B-22, Q&A 90) until new clean resources can be acquired from Independent Power Producer’s (IPPs) (currently estimated at $116 MW/h per Exhibit B-22, Q&A 67). For greater clarity, can enough BC energy be acquired from IPPs in time to meet the forecasted load without running BGS? Please discuss.

RESPONSE:

BC Hydro’s updated load resource with the initial two LNG facilities suggests that the system would have a surplus of firm energy until F2017. The two initial LNG facilities are Douglas Channel LNG facility and Kitimat LNG facility. BC Hydro expects to be able to acquire firm energy supply to meet requirements in F2017 and would not require any energy contribution from Burrard Generating Station given its surplus energy position until that time.


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Exhibit: B-30




4.4.3.1 Please discuss if the alternative to not running BGS is to lock into $116 MW/h contracts with IPPs and sell this energy at $50 MW/h when the system has surplus capacity. (Exhibit B-22, Q&A 67)

RESPONSE:

Please refer to the response to BCUC IR 4.4.3.


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Exhibit: B-30




4.4.4 Please explain BC Hydro’s rationale for not accepting line taps as an acceptable technical alternative to lower costs.

RESPONSE:

BC Hydro does accept line taps but each case is assessed individually to determine the impact on system reliability and protection sensitivity. BC Hydro endeavors to identify and understand all system risks prior to making a recommendation.


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Exhibit: B-30




4.4.4.1 Please discuss if line taps are a viable technical solution or not? Are there other utilities that employ line taps for customers served at 230 kV? Please discuss.

RESPONSE:

Refer to the response to BCUC IR 4.4.4. BC Hydro is not certain if other utilities seek to employ line taps for customers served at 230 kV.


Page 1 of 1


Exhibit: B-30




4.4.4.2 Are “reliability concerns” and “lower reliability” the only concerns for not employing line taps? Please discuss.

RESPONSE:

No, degradation in the protection sensitivity is also a concern. Decreased sensitivity of protection can negatively impact the ability of the transmission system to properly detect and isolate faults. Operational flexibility is also a consideration.


Page 1 of 1


Exhibit: B-30




4.4.5 Could the reluctance to use line taps be considered as an example of: over engineering, the desire to be the best and/or low risk tolerance as mentioned in the BC Hydro 2011 Government Report on BC Hydro? Please discuss each perceived issue.

RESPONSE:

Refer to the responses to BCUC IRs 4.4.4. and 4.4.4.2.


Page 1 of 1


Exhibit: B-30




4.4.6 BC Hydro does not appear to favor a line tap and a single 230/138 kV transformer as sufficient backup to Chetwynd (CWD’s) supply (alternative B4 and B5, A81, p. 54). Please confirm and explain why line taps are not acceptable when this contingency would only be used in an emergency, for planned maintenance to 1L361 and/or maintenance on a few CWD substation assets.

RESPONSE:

BC Hydro discusses its use of line taps in response to BCUC IR 4.4.4.

The installation of the 230/138 kV transformer requires the construction of a new substation. If Alternative B4 or B5 were implemented, the single transformer substation would be operated normally in service, and not on a contingency basis as suggested by this question. CWD is presently connected to the BC Hydro system by two transmission lines 1L361 and 1L358 under normal operation. BC Hydro would retain this level of reliability for CWD after the system is upgraded such as in the DCAT project. These lines also supply some load beyond CWD.


Page 1 of 1


Exhibit: B-30




4.4.6.1 BC Hydro uses Present Value of losses in justifying the preferred alternative or discounting some of the B1 to B5 alternatives. Given that the frequency of utilizing this back-up supply would be low, please explain why this alternate 138 kV source to CWD could not be de-energized or CBO (circuit breaker open) until required. (Q&A 78, p. 51)

RESPONSE:



Page 1 of 1


Exhibit: B-30




4.4.7 Some of the responses (Exhibit B-22, Alt B3, p. 43 for example) indicate lower reliability to the Tumbler Ridge load for the loss of a 230 kV line-please discuss further as a line loss from Gordon M. Shrum to Wildmare and/or Sukunka would appear to be common to any of the line B1 to B5 Alternatives or to the preferred solution prior to the completion of GDAT.

RESPONSE:

As stated on page 55 of Exhibit B-22, Alternatives B4 and B5 provide a lower level of reliability to the Tumbler Ridge area because with the loss of the 230 kV line between WDM and SNK, the load in the Tumbler Ridge area would be disconnected from the BC Hydro system. This is also true for Alternative B3. On the other hand, if the same line is lost (or any other 230 kV line between GMS and WDM) with the DCAT Project, 2L312 between SLS and SNK and the Tumbler Ridge area remains connected to the BC Hydro grid. This is also true for Alternatives B1


Page 1 of 1


Exhibit: B-30




4.4.8 Please confirm that the locations of Saturn and Sunset (Exhibit B-22, Q&A 50, p. 20) remain unknown as of Exhibit B-22’s submission date.

RESPONSE:

Please refer to response to BCUC IR 4.4.8.1.


Page 1 of 2


Exhibit: B-30




4.4.8.1 Please describe the Point of Interconnection for both Saturn and Sunset. For greater clarity, will there be two 230 kV lines emanating from SLS to serve both Saturn and Sunset or will there be four lines coming from SLS (two to Saturn and two to Sunset). Please provide the anticipated single line diagram for the Goundbirch area over the planning period showing all transmission customers’ interconnections to SLS and/or Bear Mountain Terminal.

RESPONSE:

BC Hydro clarifies that while the location of Shell’s Saturn and Sunset loads (in context of their coordinates) has been known, the uncertainty was around their Point of Interconnection (POI) on the BC Hydro grid, specifically that of Shell’s transmission network connecting these loads.

The single POI for Shell will be a new 230 kV switching station located on the DCAT 230 kV lines 20 km east of SLS and 40 km west of Bear Mountain Terminal (BMT). Shell’s interconnection of Saturn and Sunset will use the same POI.

The single line diagram below shows the major transmission customers anticipated in the area between SLS and BMT. This includes POI’s for Shell and EnCana (KIS). The POI of other load interconnections in the area are not confirmed at this time.


Page 2 of 2


Exhibit: B-30


Page 1 of 1


Exhibit: B-30




4.4.9 The discussion on Alternatives B4 & B5 (Exhibit B-22, Q&A81, p. 54) indicates that the costs are expected to be higher than the cost estimate for the Project. Please discuss the overall cost comparison in relation to incorporating this added 30 km of 230 kV double circuit right-of-way as part of the GDAT project. For greater clarity, the response did not indicate if the GDAT project would be lower by a similar amount that would be added for these solutions to the DCAT project i.e. please compare the total end state costs (at a high order of magnitude level) upon completion of both the DCAT and GDAT phases. Please include a discussion on the overall footprint required for both BC Hydro’s and the transmission customers’ facilities in the comparison.

RESPONSE:

The PV of the capital cost for Alternatives B4 and B5 (including a GDAT project connecting GMS and WDM) are calculated to be approximately $240-$245 million respectively. The PV of the capital cost for the DCAT project (including a GDAT project connecting GMS to WDM to SLS) is calculated to be approximately $228 million. Because the transmission losses of Alternatives B4 and B5 are expected to be similar to the DCAT project (refer to table on page 72 of Supplemental Evidence), they do not make a material difference to the comparison.

For a discussion of the footprint of these alternatives, please refer to response to BCUC IR 4.4.11.


Page 1 of 1


Exhibit: B-30




4.4.10 BC Hydro states that Alternatives B4 and B5 could not meet the required in-service date of the DCAT Project. In relation to the request for further information on how the load would be served in Commission IR 1.1 above, please explain how and if BC Hydro could serve the DCAT load until alternatives B4 or B5 could be implemented in F2017. (Exhibit B-22, Q&A 91)

RESPONSE:

If Alternatives B4 or B5 were to be implemented, BC Hydro would not be able to serve additional load in the DCAT area until the selected alternative is in service.


Page 1 of 2


Exhibit: B-30




4.4.11 As depicted below-please confirm that a larger footprint is required after Sundance Lakes (SLS) and the 230 kV customers’ Right-of-Way is/are added than for Alternative B1, B4 & B5. For greater clarity, please confirm that the overall footprint is smaller for Alternative B1, B4 & B5 when SLS and the customers’ transmission line requirements are included (note: only B5 and the preferred alternatives are illustrated). Please discuss the relative size of the footprint for these options (Project, B1, B4 and B5) in terms of approximate hectare requirements.


Page 2 of 2


Exhibit: B-30

RESPONSE:

Please refer to response to BCUC IR 4.4.8.1 for clarification on the point of interconnection of the Groundbirch customer.

When SLS is added to Alternative B1, B4 and B5, the alternatives have a larger footprint than without SLS.

With SLS, the overall footprint of Alternative B1 is the same as the footprint of the DCAT Project, and including the F2016 stage. This is assuming that SLS would have one 230/138 kV transformer, 1L358 would terminate at SLS and the customer substation would be a 230 kV switching station.

With SLS, the overall footprint of Alternative B5 is approximately the same as the footprint for the DCAT Project, and including an F2016 stage which connects through WDM rather than SNK. This is assuming the single 230/138 kV transformer substation is moved to the SLS location.

With SLS, the overall footprint of Alternatives B4 is less than the footprint of the DCAT Project, and including an F2016 stage which connects through WDM rather than SNK. This is also assuming the single 230/138 kV transformer substation is moved to the SLS location. With the decommissioning of 2L312, Alternative B4 will have a footprint that is approximately 90 hectares (approximately 30 km in length, and 30 m in width) smaller.

The customer’s transmission facilities beyond the POI are common for all alternatives (including the DCAT Project).


Page 1 of 1


Exhibit: B-30

5.0 Reference: N-1 Evidence

Exhibit B-22 Section 5, pp. 73-74

4.5.1 Is N-1 reliability being provided to the new transmission customers as part of the Project? If yes, are the new customers contributing to these added costs or is BC Hydro obligated to serve these new customers at the higher standard? Please explain and include the cost contributions in the reply.

RESPONSE:

No, N-1 reliability is not being provided to the new transmission customers as part of the DCAT Project.


Page 1 of 1


Exhibit: B-30

6.0 Reference: TS 6

Exhibit B-22, Q&A 103

4.6.1 Figure 5 is somewhat confusing- please confirm that the new transmission customers will pay for all transmission connection costs for facilities 90 meters downstream of BC Hydro’s new substation and not 90 meters downstream of BC Hydro’s closest transmission line.

RESPONSE:

BC Hydro will build a Basic Transmission Extension (BTE) from an existing substation or transmission up to 90 meters to a customer owned Transmission Line. The customer pays for the costs associated with the BTE.


Page 1 of 1


Exhibit: B-30

7.0 Reference: Load Resource Balance

Exhibit B-22 Q&A 68, p. 36; A-21 BCUC 3.83 Series

BC Hydro has committed to answering BCUC 3.83 Series of IRs (Exhibit B-27), however the questions need to be modified in the context of: the latest in service date; updated LRB; and supplemental evidence, in order to understand the possible impacts the Project will have on rates (particularly during a low water year(s) when the system does not have surplus energy available - currently forecasted to be F2017 or later) and the energy would have to be purchased from IPPs at $116/MWh to serve the 5 new DCAT customers. (Exhibit B-22, Q&A 67) It is understood that BC Hydro does not purchase energy for a specific project and therefore should not attribute specific energy to a project, however the fact remains that the 5 new gas producers will have an impact on rates and that is the context for the information requested.

4.7.1 BCUC IR 3.8.3.1 a response is requested to the IR as written.

RESPONSE:

BC Hydro provides its response to BCUC IR 3.8.3.1 in its response to the BCUC IR 4.7.1, and repeats the question here for ease of reference.

3.8.3.1 Based on the rate schedules above [sic BCUC IR 3.8.3], would a reasonable order of magnitude calculation of the approximate first year of post DCAT annual BC Hydro revenue be $48 million for a Gas Composite Transmission Voltage Customer (i.e., 155 MW x 85 per cent load factor x 8760 hours/year x an effective energy charge of $42/MWh) and $10 million for a Composite Distribution Voltage Customer (21 MW x 0.85 per cent load factor x 8760 hours/year x an effective energy charge of $65/MWh) giving a total approximate annual BC Hydro revenue of $58 million? Reference: B-14, 2.19.3, p. 1

BC Hydro is forecasting to receive $58 million in revenue from the five large customers in their first year of normal operations.

Please refer to response to BCUC IR 2.34.2 for the revenue derivation, which shows the seven years revenue calculation. The one-year estimate is done similarly. Note that the revenue calculations ignore BC Hydro’s general rate increases and inflation over time.


Page 1 of 2


Exhibit: B-30




4.7.2 BCUC 3.8.3.2 changes are underlined. Given the circumstances of no system surplus energy available and the current rate structure-would a reasonable order of magnitude calculation of the approximate BC Hydro costs to acquire the energy to service these customers be 176 MW x 0.85 load factor x 8760 hrs/yr x $116 /MWh = $152 million? (Exhibit B-14, 2.25.1)

RESPONSE:

The very simplified calculation does not reflect the reality of BC Hydro’s current portfolio position, nor does it reflect the system operational impacts that occur with the addition of a new high load factor industrial load or the new generation resources. These would typically be undertaken through portfolio modeling.

BC Hydro has contracted an adequate volume of clean energy to meet existing and forecast domestic needs until F2017 with the additional Kitimat LNG load, or until F2022 without the Kitimat LNG load. Accordingly, BC Hydro would not anticipate incurring any incremental costs to acquire energy for these customers until 2017 at the earliest. Refer to the response to CEC IR 4.17.9.

Once new generation resources are required, BC Hydro would have to assess its needs employing its portfolio model and taking into account the characteristics of these customers. To determine the cost of energy to serve these customers, BC Hydro would have to compare the costs of energy for the system as a whole with and without their load based on the state of the system at that time. BC Hydro cannot reliably perform that analysis given uncertainty in load requirements and has not attempted to do so.


Page 2 of 2


Exhibit: B-30

Notwithstanding these observations, BC Hydro acknowledges that on an order of magnitude basis, the calculation presented in the question may be a reasonable approximation of the cost to acquire energy under the assumptions noted. However, there are two important caveats that need to be recognized in connection with the calculation.

First, the calculation in the question would have a similar result for any new load in BC Hydro’s system whether from existing or new customers. Second, this cost of energy calculation bears no relation to the calculation that would be appropriate if BC Hydro were calculating generation costs as part of system reinforcements for a load in excess of 150 MVA. In that regard please refer to the response to CP IR 1.1.4.2.


Page 1 of 1


Exhibit: B-30




4.7.3 BCUC 3.8.3.3 changes are underlined. Given the circumstances of no system surplus energy available and the current rate structure-would a reasonable estimate of the net difference (i.e. $152 m -$58 m) be an approximate $94 million annual first year loss and further increasing as more load is added until such time the load drops off? Please confirm or provide BC Hydro’s estimate. (Exhibit B-14, 2.19.5, p. 1)

RESPONSE:

Please refer to the response to BCUC IR 4.7.2. BC Hydro notes that the caveats identified in that response apply to this question as well. Notwithstanding BC Hydro is forecast to be in a surplus energy position until at least F2017, assuming the simplified calculation in the question, the calculated impact to revenue requirements of $94 million may be a reasonable approximation that could occur based on the assumptions in the question.


Page 1 of 1


Exhibit: B-30




4.7.4 BCUC 3.8.3.4 changes are underlined. Given the circumstances of no system surplus energy available and the current rate structure-would a reasonable estimate of the net loss associated with the total load of 176 MW be $2.82 billion ($94 million X 30 years) at the current rate? Please confirm that potential losses from these five customers for future load increases beyond the first year of normal operations are not factored into this calculation. (Exhibit B-14, 2.19.6, p. 1)

RESPONSE:

Please refer to the response to BCUC IR 4.7.2. BC Hydro notes that the caveats identified in that response apply to this question as well. Notwithstanding BC Hydro is forecast to be in a surplus energy position until at least F2017, assuming the simplified calculation in the question, the calculated impact to revenue requirements of $2.82 billion over the 30-year period may be a reasonable approximation that could occur based on the assumptions in the question.


Page 1 of 1


Exhibit: B-30





RESPONSE:


3.8.3.5 Would it be reasonable to say that this order of magnitude loss would result in an approximate 3 percent increase in rates for BC Hydro customers due to increased operating costs to provide 176 MW of energy to these five gas producers (assuming these costs are not placed in a deferral account)? Please confirm.

With respect to the revenue requirement impact percentage, BC Hydro notes that an additional revenue requirement of $94 million, as suggested in BCUC IR 4.7.3, would lead to a revenue requirement impact of approximately 1.7 per cent ($94 million ÷ $5,650 million total revenue requirement). BC Hydro cannot forecast a rate increase as that would be dependent on all changes to revenue requirements for the applicable test period.


Page 1 of 1


Exhibit: B-30





RESPONSE:


3.8.3.6 Would it be reasonable to forecast that BC Hydro will be applying for a 3.5 percent increase in rates to cover the Capital and Operating costs for the DCAT Project (assuming these costs are not placed in a deferral account)? Please confirm.

The impact of the DCAT Project will be taken into consideration in the appropriate revenue requirement application, along with all other changes to revenue requirements. The sum total of all changes to revenue requirements will determine what rate changes occur.


Page 1 of 1


Exhibit: B-30

8.0 Reference: N-1

Exhibit A-21, BCUC 3.12.1; T2: p. 166

BC Hydro objected to answering BCUC 3.12.1 “What are the circumstances that would supply a new customer connection with N-1 level of service where the present system would have to be upgraded from N-0? Please discuss.”

4.8.1 For greater clarity-please describe BC Hydro’s understanding of the application of Mandatory Reliability Standards (MRS) around meeting new customer load to N-1 level standard when you’re at N-0. Please include the applicable MRS reference(s).

RESPONSE:

MRS does not specify when new customer load should be supplied with N-1 level of service if the system presently has N-0 level of service. BC Hydro evaluates radial systems, which have an N-0 level of service, on an individual basis to assess the cost and benefits of upgrading these systems to meet the N-1 standard. Some contributing factors in an assessment would be the size of load supplied radially, the reliability of the existing radial system and the cost to upgrade the system to N-1 level of service. These issues do not arise in the context of the DCAT Project because it is part of the network or bulk system.

In an area of the system, such as Dawson Creek, that is supplied by N-1 transmission service as part of the bulk system, new customer load demand increase can cause the system to become overloaded even when one circuit is out of service. In this case, the performance requirements of the TPL-002 standard (Table I, Category B) may no longer be met. The system may no longer be stable, and voltage and thermal limits may no longer be within their applicable ratings following the outage of a single transmission circuit. In addition, there may be loss of demand, curtailment of firm transfers or cascading outages. In this situation system reinforcements would be required to restore the system to an N-1 standard.

Please also refer to the response to BCSEA IR 1.3.1.


Page 1 of 1


Exhibit: B-30

8.0 Reference: N-1

Exhibit A-21, BCUC 3.12.1; T2: p. 166


4.8.1.1 What contributions would BC Hydro make and what contributions would be required from the customer?

RESPONSE:

TS6 does not expressly deal with the calculation of a customer contribution to system reinforcements in circumstances where the contemplated reinforcements will improve service to existing customers and non-transmission voltage new customers, as well as permit service to the new transmission voltage customers requesting service. This is the context for the DCAT Project.

BC Hydro has sought to discern and apply the plain meaning of the tariff in the absence of express language dealing with this situation. In the result, BC Hydro has proposed a method of cost allocation based on the percentage of the project that is necessary to achieve the N-1 standard. In particular, that percentage is allocated to existing load, and the residual percentage is allocated to the new customer. The share allocated to the new customer is then subject to an offset by BC Hydro, pursuant to the tariff.

BC Hydro has not considered if this approach is appropriate for all cases that may be covered by the hypothetical circumstances of the question, but does believe that it is appropriate in this case.

Please also refer to the response to AMPC IR 3.1.4.


Page 1 of 1


Exhibit: B-30

8.0 Reference: N-1

Exhibit A-21, BCUC 3.12.1; T2: p. 166


4.8.2 Please explain the planning criteria (under existing tariff(s) or applicable MRS standard) that BC Hydro employs to determine if customers will be served by a radial system or by a network?

RESPONSE:



Page 1 of 1


Exhibit: B-30

9.0 Reference: Rate Impact

Exhibit A-21, BCUC 3.27.1; B-27 Exhibit BC Hydro F12-14 RRA, B-23, BCUC 2.50

BC Hydro committed to answering BCUC 3.27.1, 3.27.1.1 and 3.27.1.2, however the response will be, in part, based on the supplemental evidence of the revised in service date of April 30, 2014, and the assertion that the system currently has forecasted surplus capacity until F2017 (B-22 Q&A 68, p. 36). Since the rate impact of the Project will not be material until the following test period, these IRs have been replaced as below. To be clear, a response to BCUC 3.27.1, 3.27.1.1 and 3.27.1.2 is no longer required.

4.9.1 Please provide a range of forecasted %Rate Increases for the years F2015 to F2019 under the assumptions of Cost of Energy 1) when the system in surplus energy and 2) when the system has no surplus energy.

RESPONSE:



Page 1 of 1


Exhibit: B-30

9.0 Reference: Rate Impact

Exhibit A-21, BCUC 3.27.1; B-27 Exhibit BC Hydro F12-14 RRA, B-23, BCUC 2.50

BC Hydro committed to answering BCUC 3.27.1, 3.27.1.1 and 3.27.1.2, however the response will be, in part, based on the supplemental evidence of the revised in service date of April 30, 2014, and the assertion that the system currently has forecasted surplus capacity until F2017 (B-22 Q&A 68, p. 36). Since the rate impact of the Project will not be material until the following test period, these IRs have been replaced as below. To be clear, a response to BCUC 3.27.1, 3.27.1.1 and 3.27.1.2 is no longer required.

4.9.2 Please explain if BC Hydro intends to enter into additional IPP contracts to provide insurance that it will have sufficient energy to supply the Project.

RESPONSE:

BC Hydro’s updated load resource balance that includes the mid-load considered in the Project suggests that BC Hydro would be in a surplus firm energy position until F2017 at the earliest. BC Hydro does not expect to enter into any additional IPP contracts prior to F2017 to provide insurance that it will have sufficient energy to supply the Project.


Page 1 of 1


Exhibit: B-30

10.0 Reference: N-1 Evidence

Exhibit B-22, Supplemental Evidence Q&A 92 and Q&A 93

The DCAT Project will allow BC Hydro to serve 185 MW in the DCAT Project area at the N-1 standard. BC Hydro expects load to exceed 185 MW before or soon after the DCAT Project can be brought into service. Accordingly, BC Hydro has advised all new industrial customers that they will need to participate in a remedial action scheme (RAS) until a future GDAT project can be brought into service.... The DCAT Project (and the GDAT project) are planned to ensure that service to the DCAT Project area continues to meet the N-1 standard.

It would seem that the DCAT projects compliance with N-1 standard will be delayed until future phases. Therefore, the full cost of system reinforcement to accommodate the new load, in compliance with the required reliability standard, will be incurred over the course of several years. However, BC Hydro is only seeking financial support from new customers from the portion of these costs that will be incurred in the DCAT phase. How does BC Hydro intend to have further system reinforcement costs supported by the customers? Does the phasing of this project place the reinforcement contribution burden on the broader public (i.e. all provincial ratepayers)?

RESPONSE:

BC Hydro plans to take the same approach in a GDAT project by seeking security from new customers 10MW or over that are requesting electric service at that time. This will ensure that the BC Hydro ratepayers are not unfairly burdened with the subsequent reinforcement costs, and are protected from any potential stranded investments associated with a GDAT project.

No contribution in aid of construction for the cost of a GDAT project is being sought from the five customers for loads associated with the DCAT Project because all the five customers will be served prior to the implementation of a GDAT project. Exhibit B-22, Q&A 113 indicates that the revenue applicable to the offset calculation from the five customers is expected to be approximately $429 million. Based on these forecast revenues, BC Hydro expects that even if all of GDAT project costs in addition to 60 per cent of the DCAT Project costs were allocated to the five customers, BC Hydro’s calculated offset under the Tariff would not result in a requirement for a customer contribution in aid of construction.


Page 1 of 1


Exhibit: B-30

11.0 Reference: TS 6

Exhibit B-22, Supplemental Evidence Q&A 101

Q&A 101 states: The DCAT Project does not include Basic Transmission Extension costs for the individual customer, though these exist on the BC Hydro side of the Point of Delivery. Also, the Project does not include any equipment or costs on the customer side of the Point of Delivery.

Section 1(b)(ii) of TS 6 states: “the Basic Transmission Extension is the responsibility of B.C. Hydro, who shall undertake the required work at the Customer's expense.” Section 6(b)(ii) of TS 6 states that customers will pay the Actual Costs, as incurred by BC Hydro, for the Basic Transmission Extension, up to a maximum amount equal to the Agreed Maximum Costs, determined pursuant to clause 4, in accordance with periodic billings, as set out in a Facilities Agreement.

Please confirm that new customers requiring a Basic Transmission Extension will pay the Actual Costs and provide those Actual Costs. Please provide the Facilities Agreements for all customers that require Basic Transmission Extensions, on a confidential basis if required. If those agreements have not been executed yet, please provide draft agreements.

RESPONSE:

New customers requiring a Basic Transmission Extension (BTE) will pay the Actual Costs associated with the BTE.

A Facilities Agreement with one customer is expected to be completed in early June. BC Hydro will provide a copy of the executed Facilities Agreement at that time.

The remaining four new customers are in the study phase and do not currently have Facilities Agreements (and/or the equivalent equivalent) in place. BC Hydro expects to complete binding security agreements with these customers in a similar timeframe. BC Hydro will also provide a copy of these agreements.

Reply Attention of: Matthew D. Keen Direct Phone: 604.641.4913 Direct Fax: 604.646.2551 E-mail: [email protected] Our File: 11-3512 Date: May 14, 2012

British Columbia Utilities Commission 6th Floor – 900 Howe Street Vancouver, BC V6Z 2V3 Attention: Alanna Gillis, Acting Commission Secretary Dear Madame: Re: British Columbia Hydro and Power Authority (“BC Hydro”) Certificate of Public

Convenience and Necessity Application (“Application”) Dawson Creek/Chetwynd Area Transmission (“DCAT”) Project Project No. 3698640 Association of Major Power Customers (“AMPC”) IR No. 4 to BC Hydro

We are legal counsel to AMPC in this matter. Please find attached Information Request No. 4 from AMPC to BC Hydro pursuant to Commission Order G-56-12. AMPC also responds below to the Commission’s invitation to clarify to its outstanding IR No. 3.1.4 to BC Hydro. AMPC 3.1.4 follows BC Hydro’s response to BCUC IR No. 2.18.1. In that response BC Hydro described the “allocation of costs with respect to required system upgrades” as based on the Electric Tariff - presumably Tariff Supplement 6 (“TS 6”). AMPC seeks to understand whether the cost allocation calculation is simply mechanical (i.e., without discretion) or, given that this appears not to be the case, how discretion is involved in applying TS 6 - what are the underlying principles and what factors did BC Hydro take into account to calculate the cost allocation? As BC Hydro subsequently put it on p. 83 of Exhibit B-22, the DCAT circumstances “led to some complexity, and a requirement for some decisions to be taken in interpreting TS 6.” These decisions included whether and how to split System Reinforcement costs between old and new customers, and how to divide costs between the new customers. As AMPC noted in Exhibit C3-8, supplemental questions 115 and 116 of Exhibit B-22 discuss these decisions, but do not directly respond to AMPC’s request to explain the basis for them in the Electric Tariff / TS 6. Please contact the writer if you have any questions. Yours truly, Bull, Housser & Tupper LLP

Matthew D. Keen

C3-9

markhuds


REQUESTOR NAME: Association of Major Power Customers (AMPC) INFORMATION REQUEST ROUND NO: 4 TO: British Columbia Hydro & Power Authority (BC Hydro) DATE: May 14, 2012 PROJECT NO: 3698640 APPLICATION NAME: CPCN Application for the DCAT Project ______________________________________________________________________

1

1.0 TOPIC: Natural gas price forecast and evaluation of local natural

gas generation alternatives Reference 1: Exhibit B-22, page 25 (supplementary question 58):

The [electricity demand] forecast until F2014 has been reduced to reflect the influence of very low current natural gas prices. These prices have led to reduced drilling activity and production rates in the sector as a whole.

Reference 2: Exhibit B-22, pages 64-65 (supplementary question 89):

• Gas generation cost and performance data are as per the BC

Hydro 2010 Resource Options data for 50 MW CCGT and 100 MW SCGT units.

… • Gas market prices are based on BC Hydro’s most recent

forecast for the “mid” and “low” scenarios. The mid and low scenarios represent levelized gas prices of approximately $7/GJ and $5/GJ, respectively, both referenced to Station 2.”

Background: Reference 1 acknowledges that a trend of low natural gas prices has negatively affected its price forecast until 2014. Reference 2 discusses the cost of using local natural-gas fired generation to meet the DCAT area load and this option to the DCAT project. The comparison uses levelized natural gas prices between $5 - $7 / GJ and refers both to BC Hydro’s most recent natural gas price forecast and BC Hydro’s BC Hydro 2010 Resource Options data.

Request:

1.1 Please confirm that the $5-$7 levelized price forecast in Reference 2

remains accurate, and that it reflects the influence of very low current natural gas prices identified in Reference 1.

1.2 Please provide the natural gas price forecast. 1.3 Please describe when the natural gas price forecast was prepared and the

methodology used to prepare it. 1.4 Please provide the levelized cost of producing electricity (expressed in

$/MWh) from the referenced gas generation units for gas prices within the forecast range and sited in the DCAT area.

REQUESTOR NAME: Association of Major Power Customers (AMPC) INFORMATION REQUEST ROUND NO: 4 TO: British Columbia Hydro & Power Authority (BC Hydro) DATE: May 14, 2012 PROJECT NO: 3698640 APPLICATION NAME: CPCN Application for the DCAT Project ______________________________________________________________________

2

1.5 Please provide the forecast levelized cost of acquiring electricity from a

clean energy call (expressed in $/MWh), including the costs of backing up intermittent resources, and the costs of system transmission and losses from remote areas to provide reliable service in the DCAT area.

Association of Major Power Customers Information Request No. 4.1.1 Dated: May 14, 2012 British Columbia Hydro & Power Authority Response issued May 24, 2012

Page 1 of 2


Exhibit: B-30

1.0 TOPIC: Natural gas price forecast and evaluation of local natural gas

generation alternatives

Reference 1: Exhibit B-22, page 25 (supplementary question 58):



Gas generation cost and performance data are as per the BC Hydro 2010 Resource Options data for 50 MW CCGT and 100 MW SCGT units.

Gas market prices are based on BC Hydro’s most recent forecast for the “mid” and “low” scenarios. The mid and low scenarios represent levelized gas prices of approximately $7/GJ and $5/GJ, respectively, both referenced to Station 2.”

Reference 1 acknowledges that a trend of low natural gas prices has negatively affected its price forecast until 2014. Reference 2 discusses the cost of using local natural-gas fired generation to meet the DCAT area load and this option to the DCAT project. The comparison uses levelized natural gas prices between $5 - $7/GJ and refers both to BC Hydro’s most recent natural gas price forecast and BC Hydro’s BC Hydro 2010 Resource Options data.

4.1.1 Please confirm that the $5-$7 levelized price forecast in Reference 2 remains accurate, and that it reflects the influence of very low current natural gas prices identified in Reference 1.

RESPONSE:

In Exhibit B-22 Q&A 58, BC Hydro specifically refers to the impact on the natural gas producing sector as a result of current (as in short-term spot market) natural gas prices. BC Hydro in its 2011 Load Forecast has assumed that these prices have caused some producers to defer some projects and decrease some near-term gas production.

The long-term natural gas scenarios referenced in Exhibit B-22, (pages 64 to 65) are still current and being used by BC Hydro in development of its Integrated Resource Plan (IRP).


Page 2 of 2


Exhibit: B-30

The referenced gas prices of approximately $5/MMBtu and 7/MMBtu are 40-year levelized prices starting in 2014. BC Hydro maintains these scenarios, but it has revised its relative weightings of the scenarios based on current conditions, such that the low price scenario has been afforded a greater weighting than it had when the 2010 Load Forecast was created. Scenario planning will be discussed in BC Hydro’s IRP.

For reference, BC Hydro provides its current three long-term 2010 gas price forecasts and historical prices as follows:


Page 1 of 1


Exhibit: B-30









4.1.2 Please provide the natural gas price forecast.

RESPONSE:

Please refer to the response to AMPC IR 4.1.1.


Page 1 of 1


Exhibit: B-30









4.1.3 Please describe when the natural gas price forecast was prepared and the methodology used to prepare it.

RESPONSE:

Please refer to the response to AMPC IR 4.1.1.


Page 1 of 1


Exhibit: B-30









4.1.4 Please provide the levelized cost of producing electricity (expressed in $/MWh) from the referenced gas generation units for gas prices within the forecast range and sited in the DCAT area.

RESPONSE:

Please refer to table included in the response to CEC IR 4.22.1. The requested levelized unit energy costs for the range of market scenarios assumed are provided in the rows labelled "Alternative G1" and "Alternative G2."


Page 1 of 1


Exhibit: B-30









4.1.5 Please provide the forecast levelized cost of acquiring electricity from a clean energy call (expressed in $/MWh), including the costs of backing up intermittent resources, and the costs of system transmission and losses from remote areas to provide reliable service in the DCAT area.

RESPONSE:

Please refer to the response to CEC IR 4.17.2.

REQUESTOR NAME: BCOAPO INFORMATION REQUEST ROUND NO: #4 TO: BRITISH COLUMBIA HYDRO & POWER

AUTHORITY DATE: May 14, 2012 PROJECT NO: 3698640 APPLICATION NAME: CPCN – Dawson Creek/Chetwynd Area

Transmission Project ______________________________________________________________________ 1.0 Reference: Exhibit B-22, page 33

Exhibit B-6, BCOAPO 1.6.1 and 1.6.2

1.1 Please revise the responses to BCOAPO 1.6.1 and 1.6.2 based on the updated load forecast.

2.0 Reference: Exhibit B-22, pages 5 and 25 Exhibit B-5, BCUC 1.39.1

2.1 The response to BCUC 1.39.1 indicates that the existing area load is 112 MW.

2.1.1 What period (e.g. winter F2010 or winter F2011) was used to determine the 112 MW referenced in BCUC 1.39.1 as the “existing area load”?

2.1.2 Does the 112 MW include the 20.6 MW of load for 2011 associated with the five new customers (per Exhibit 22, page 5)?

2.1.3 Does the 112 MW include any other loads associated with Gas Producers with in-service dates after F2010? If yes, what are the MWs involved and when did they come “in-service”?

2.2 What portion of the 40 MW reduction for the winter of F2012 is due to new customers not energizing as forecast as opposed to existing customers having lower loads than forecast?

2.3 Please provide a schedule that sets out for each of the Other Load and Gas Producer loads: i) the F2010 (actual) values; ii) the original load forecast values for F2011 and F2012; and iii) the actual F2011 and F2012 loads.

2.4 What is the current (winter F2012) value for the load associated with those customers used to determine the original 112 MW value?

2.5 Based on this current value, please re-calculate the portion of the increase in capacity required to meet existing load (per BCUC 1.39.1).

2.6 Does BC Hydro plan to revise its capital contribution calculations based on these proportions? If not, why not?

C7-14

ylapierr

Dawson Creek/Chetwynd Area Trans

3.0 Reference: Exhibit B-22, pages 6-7; 24 and 31 Exhibit B-6, BCOAPO 1.1.2.1 and 1.4.1

3.1 Exhibit B-22 states that BC Hydro has “recently been requiring new customers to sign agreements that BC Hydro can shed their load”. Is this the same requirement noted in response to BCOPAO 1.1.2.1 and that was initiated in 2009?

3.1.1 If not, please indicate how this current requirement differs in terms of the size of customers it applies to and when this change in requirements was introduced?

3.2 Based on the revised load forecast, how much (MWs) of the Other Load page 31) and Gas Producer (page 24) load forecast for F2012 and F2013 is interruptible?

3.3 If not all of the Gas Producer load forecast for F2012 and F2013 is “interruptible” please explain why not.

3.4 Exhibit B-22, page 6 (line 28) states that “new customers” are required to sign agreements that BC Hydro can shed their load, while page 7 (line 28) states that all new industrial customers over 1 MW have to accept load shedding. Please clarify: i) do the required load shedding agreements just apply to new customers over 1 MW and ii) do they just apply to new industrial customers?

4.0 Reference: Exhibit B-22, pages 6-8 and 73 (lines 16-17)

4.1 Assuming DCAT and GDAT come into service in F2014 and F2016 as planned, will BC Hydro be able to meet the revised load forecast as of those dates based on the N-1 standard?

4.2 If the utility is not able to meet the N-1 standard for F2014, will any of the customers who have entered into load shedding agreements since 2009 be granted firm (i.e., N-1) service after DCAT is in-service? If so, how will the determination be made as to which of these customers receive firm service?

5.0 Reference: Exhibit B-22, pages 6, 11, 16, 18 and 21

5.1 Please provide an update as to the status of the binding and interim agreements addressing each customer’s portion of the DCAT System Reinforcement security.

6.0 Reference: Exhibit B-22, pages 5, 6 and 83-85 Exhibit B-1-3, page 4-23 (revised) Exhibit B-5, BCUC 1.39.1

6.1 Exhibit B-22 (page 6) states that each of the five customer’s security arrangements will be based on its proportionate share of “new customer load”. Given the range of in-service dates noted in the discussion on the individual customers (pages 5 and 9 to 21), what in-service dates will be included in the identification of the MWs used to determine each customer’s “proportionate share”?

6.2 Exhibit B-22 uses a project cost of $219 M when describing the determination of security to be provided by the DCAT customers. However, the updated cost of the project is $222.3 M. Please reconcile.

6.3 As no DCAT customer has sought a Detailed Estimate please confirm that the final security deposit requirements will be based on the Actual Cost or the Estimated Actual Cost. If the latter, at what point in time will this “estimate” be established?

7.0 Reference: Exhibit B-22, page 36

7.1 Please confirm whether the $116/MWh represents a levelized cost in real or nominal terms (i.e. if in real terms it would escalate at inflation to obtain the nominal cost in years after 2011 whereas if in nominal terms the $116/MWh would also represent the nominal cost in future years).

7.2 Similarly, please clarify whether the $50/MWH in 2011 $ market price is in real or nominal terms.

8.0 Reference: Exhibit B-22, pages 41, 49 and 72

8.1 If possible, please indicate the degree to which the capital cost and the PV for Alternative B1 is less than that of the proposed DCAT project (e.g., is the difference less than 5%, greater than 20%?).

9.0 Reference: Exhibit B-22, pages 59-60

9.1 What was the total generation (GWh) in each of years from 2008-2011 from the five gas-fired plants listed?

9.2 Are the five gas-fired plants listed used primarily as base load generation? If not, when/how are they typically operated?

9.3 In Table 2, are the values shown for “energy contribution from existing gas-fired generation” the anticipated production over F2014-F2030 or the firm energy the stations are capable of producing in this period?

9.4 Does BC Hydro interpret the CEA as requiring at least of 93% of firm energy capability being from clean or renewable resources or at least 93% of energy actually produced being from clean or renewable generation?


10.1 Please provide a schedule that sets out the annual energy (MWh) used in the determination of the Cost of Energy in Table 7 for Alternatives G1 and G2. If the total energy supplied is not the same for both alternatives, please explain why.

10.2 On the same schedule please show for each alternative (G1 and G2) the split in energy as between system energy and local gas-fired generation.

10.3 Please confirm that, for purposes of costing system energy a market price of $50/MWh ($2011) was used for prior to the system need date of 2017

and an average plant gate price of $116/MWh ($2011) was used after the need date. If not, please explain what values were used and why.


11.1 Please provide a schedule that sets out the annual energy used in the determination of the Cost of Energy in Table 8. If the values are not the same as those for Table 7 please explain why.

11.2 Please explain why, for purposes of Table 8, this energy was not valued at $50/MWh ($2011) for energy used prior to the system need date of 2017 and an average plant gate price of $116/MWh ($2011) for energy used after the need date.

11.3 Please re-do Table 8 where the Cost of Energy is valued at $50/MWh ($2011) prior to the system need date of 2017 and an average plant gate price of $116/MWh ($2011) after the need date.

12.0 Reference: Exhibit B-22, pages 6-7 and 73 Exhibit B-6, BCOAPO 1.1.2.1

Preamble: On page 73 BC Hydro states that it “has advised all new industrial customers that they will need to participate in a remedial actions scheme (RAS) until a future GDAT project can be brought into service”.

12.1 Is this the same requirement and does this involve the same customers as the load shedding agreement requirement described in response to BCOAPO 1.1.2.1 and/or discussed on pages 6-7?

12.2 If not, what customers does this requirement (i.e., participation in a RAS until a future GDAT can be brought into service) apply to? In responding please describe both the size of customers it applies to and after what point in time this new requirement (as opposed to that outlined in BCOAPO 1.1.2.1) applied to customers requesting service.

13.0 Reference: Exhibit B-22, pages 25 and 75 Exhibit B-6, BCOAPO 1.2.2

13.1 At this point in time, does BC Hydro have any formal commitments (per BCOAPO 1.2.2) with Gas Producers who require service prior to F2016 apart from five identified customers? If yes, what are the total MWs associated with those customers whose individual loads fall into each of the following ranges: i) 0-1 MW; ii) 1-10 MW and iii) >10 MW?

13.2 Does the revised load forecast (for the period up to F2016) assume any loads for individual customers that fall into the following ranges: i) 0-1 MW or ii) 1-10 MW?

13.3 If yes, please break the revised Gas Producer load forecast down into the following three categories: i) individual customers with loads between 0-1 MW; ii) individual customers with loads between 1-10 MW and ii) individual customers with loads >10 MWs.


14.1 Please clarify what is meant by an “eligible” customer. In doing so, please confirm whether, in order to be eligible, the customer must comply with the conditions of BC Hydro’s approved tariffs.

15.0 Reference: Exhibit B-22, pages 80-81 Exhibit B-1, page 4-26 and Appendix I

15.1 For purposes of calculating the “rate impact” of project, BC Hydro assumes there is no increase in overall energy sales (per Appendix I). However, for purposes of BC Hydro Offset calculation under Tariff 6 it is assumed that the project generates additional revenues (as a result of increased sales). Please reconcile this inconsistency.

16.0 Reference: Exhibit B-22, pages 73 and 80-82 Exhibit B-15, BCOAPO 2.9.1 Exhibit B-14, BCUC 2.19.1

16.1 Please confirm that the value for R is calculated using the full transmission or distribution rate as applicable to each customer. If not, what “rate” is used?

16.2 Does the $429 M represent 7.4 times the estimated first 12 months of revenue for each customer? If not, how was it calculated?

16.3 Please provide a table (similar to page 5, Table 1) that sets out the total new customer loads (by year of in-service) used in the calculation of the R value.

16.4 If the total new loads used to calculate R exceed 73 MW please explain why this higher MW value is used when the DCAT upgrade can only provide N-1 service to 73 MW of new load (per BCUC 2.19.1)?

16.4.1 Also, please explain why any new loads in excess of the 73 MW wouldn’t be associated with the GDAT project and used in future calculations of potential customer cost responsibility for System Reinforcement costs connected with that project.

16.5 Please recalculate the equivalent of the $429 M values based on 73 MW of new load at Transmission Service rates. For purposes of the calculation please assume an overall customer load factor equivalent to the (weighted) average for the three transmission customers.

16.6 Page 81 indicates that the value for R in the offset calculation is based on the first 12 months after the normal operations begin. In determining the offset amount of $429 M did BC Hydro assume there was an unrestricted supply available to each customer in the first year to meet all of its electrical requirements?

16.6.1 If not, what assumptions were made about the availability of electricity to each customer?

16.6.2 If yes, please reconcile this assumption with the fact some customers are currently using on-site generation (per page 17) and all customers have load shedding agreements.

17.0 Reference: Exhibit B-22, pages 82-83 Exhibit B-5, BCUC 1.51.3

Preamble: The response to BCUC 1.51.3 states that the two Distribution Service customers will be required to pay an additional Distribution Extension Fee.

17.1 Please confirm that in calculating the Distribution Extension Fee required from customers, the offset provided by BC Hydro is based on the customer’s anticipated billing demand (per Section 8.3 of the Terms and Conditions).

17.2 If this the case, are these customers not being credited twice for their anticipated billing demand – once in the determination of the Distribution Extension Fee and a second time in the determination of the BC Hydro offset to be provided under Tariff 6 for Transmission Reinforcement? If not, please explain why not.

17.3 Please recalculate the equivalent of the $429 M – but exclude the loads associated with the two Distribution service customers.

17.4 Based on BC Hydro’s calculations what is the proportionate share (i.e., %) attributable to the two distribution customers?

18.0 Reference: Exhibit B-1-3, pages 4-23 (revised)

18.1 Please outline the reasons for the increase in: i) Direct Definition Phase Costs and ii) Project Management, Engineering, Property, Consultation, and Environment Costs.

18.2 Given the later in-service date why has the allowance for inflation not increased?

18.3 Given that the P50 cost estimate has increased, why is the Project Reserve less?

British Columbia Old Age Pensioners' Organization Information Request No. 4.1.1 Dated: May 14, 2012 British Columbia Hydro & Power Authority Response issued May 24, 2012

Page 1 of 2


Exhibit: B-30


Exhibit B-6, BCOAPO 1.6.1 and 1.6.2

4.1.1 Please revise the responses to BCOAPO 1.6.1 and 1.6.2 based on the updated load forecast.

RESPONSE:

The following figures have been revised with the updated load forecast. The N-0 and N-1 limits for Alternatives 1 and 2 have not been updated because the study for the GDAT Project is still ongoing. The limits will be updated when GDAT study is completed.

0

100

200

300

400

500

600

'12 '14 '16 '18 '20 '22 '24 '26 '28 '30 '32 '34 '36 '38 '40 '42

MW

Fiscal Year

HIGH Alternative 1 (N-0)

DC Area Load Forecast Alternative 1 (N-1)

LOW

Alternative 1


Page 2 of 2


Exhibit: B-30

0

100

200

300

400

500

600

'12 '14 '16 '18 '20 '22 '24 '26 '28 '30 '32 '34 '36 '38 '40 '42

MW

Fiscal Year

HIGH Alternative 2 (N-0)

DC Area Load Forecast Alternative 2 (N-1)

LOW

Alternative 2


Page 1 of 1


Exhibit: B-30

2.0 Reference: Exhibit B-22, pages 5 and 25

Exhibit B-5, BCUC 1.39.1

4.2.1 The response to BCUC 1.39.1 indicates that the existing area load is 112 MW.

RESPONSE:

Regarding the reference to 112 MW, the response to BCUC IR 1.39.1 did not indicate that the 112 MW was existing area load. The 112 MW figure was provided as an assumption based on an earlier forecast.

With respect to actual loads, please refer to Exhibit B-22, Q&A 57.

British Columbia Old Age Pensioners' Organization Information Request No. 4.2.1.1 Dated: May 14, 2012 British Columbia Hydro & Power Authority Response issued May 24, 2012

Page 1 of 1


Exhibit: B-30



4.2.1.1 What period (e.g. winter F2010 or winter F2011) was used to determine the 112 MW referenced in BCUC 1.39.1 as the “existing area load”?

RESPONSE:

Please refer to the response to BCOAPO IR 4.2.1.


Page 1 of 1


Exhibit: B-30



4.2.1.2 Does the 112 MW include the 20.6 MW of load for 2011 associated with the five new customers (per Exhibit 22, page 5)?

RESPONSE:


This estimate would not have included BC Hydro serving in 2011 the 20.6 MW of load associated with the five new customers.


Page 1 of 1


Exhibit: B-30



4.2.1.3 Does the 112 MW include any other loads associated with Gas Producers with in-service dates after F2010? If yes, what are the MWs involved and when did they come “in-service”?

RESPONSE:

Yes, BC Hydro’s estimate of 112 MW would have included other loads associated with Gas Producers with in-service dates after F2010.

The estimated loads with in-service dates after F2010 include approximately 17 MW (9 MW for Gas Producers and 8 MW for Other – Gas Processors). These loads would have been forecast to enter service in F2011. As noted in Q&A 8, Exhibit B-22, some gas producer loads may be served through interim self-generation until the DCAT Project is implemented.


Page 1 of 1


Exhibit: B-30



4.2.2 What portion of the 40 MW reduction for the winter of F2012 is due to new customers not energizing as forecast as opposed to existing customers having lower loads than forecast?

RESPONSE:

About 90 per cent of the reduction is due to anticipated new customers not energizing in the expected timeframe. The remainder is due to existing customers having lower loads than anticipated. Please also refer to Exhibit B-22, Q&A 57.


Page 1 of 1


Exhibit: B-30



4.2.3 Please provide a schedule that sets out for each of the Other Load and Gas Producer loads: i) the F2010 (actual) values; ii) the original load forecast values for F2011 and F2012; and iii) the actual F2011 and F2012 loads.

RESPONSE:

DCAT Project Area Load Forecast Update in the Supplemental Evidence Forecasts with Actuals: i) F2010 Actuals Est. Actuals F2010

Gas Producer 7 Other 45 Total 52

ii) DCAT (original) Forecasts for F2011 & F2012 DCAT Forecast F2011 F2012

Gas Producer 70 83 Other 65 70 Total 135 153

iii) Actuals F2011 & F2012 Est. Actuals F2011 F2012

Gas Producer 18 29 Other 54 57 Total 71 86


Page 1 of 1


Exhibit: B-30



4.2.4 What is the current (winter F2012) value for the load associated with those customers used to determine the original 112 MW value?

RESPONSE:

The current (winter 2012) value for the load associated with those customers used to determine the early estimate of 112 MW is the same number as provided in the response to BCOAPO IR 4.2.3 – point (iii) for F2012: approximately 86 MW.


Page 1 of 1


Exhibit: B-30



4.2.5 Based on this current value, please re-calculate the portion of the increase in capacity required to meet existing load (per BCUC 1.39.1).

RESPONSE:

The allocation is unchanged based on the area load estimate of 112 MW, as this capacity is still required when customers are in full operation as noted in this series of questions.


Page 1 of 1


Exhibit: B-30



4.2.6 Does BC Hydro plan to revise its capital contribution calculations based on these proportions? If not, why not?

RESPONSE:

No. Please refer to the response to BCOAPO IR 4.2.5.

Further, BC Hydro’s discussions with customers are too advanced to revisit the proportional allocation of the DCAT Project capital costs. Note, the allocation affects security only, not capital contributions, as discussed in Q&A 113 to 116 of Exhibit B-22.


Page 1 of 1


Exhibit: B-30

3.0 Reference: Exhibit B-22, pages 6-7; 24 and 31

Exhibit B-6, BCOAPO 1.1.2.1 and 1.4.1

4.3.1 Exhibit B-22 states that BC Hydro has “recently been requiring new customers to sign agreements that BC Hydro can shed their load”. Is this the same requirement noted in response to BCOPAO 1.1.2.1 and that was initiated in 2009?

RESPONSE:

Yes.


Page 1 of 1


Exhibit: B-30



4.3.1.1 If not, please indicate how this current requirement differs in terms of the size of customers it applies to and when this change in requirements was introduced?

RESPONSE:

Please refer to response to BCOAPO IR 4.3.1.


Page 1 of 1


Exhibit: B-30



4.3.2 Based on the revised load forecast, how much (MWs) of the Other Load page 31) and Gas Producer (page 24) load forecast for F2012 and F2013 is interruptible?

RESPONSE:

Since F2010, all new load associated with industrial customers with a load greater than 1 MV.A is interruptible. The interruptible load included in the F2012 and F2013 forecast is as follows:

a) Other Forecast includes 18 MW of load in F2012 and 34 MW of load in F2013; and

b) Gas Producer Forecast includes 31 MW of load in F2012, and 48 MW of load in F2013.


Page 1 of 1


Exhibit: B-30



4.3.3 If not all of the Gas Producer load forecast for F2012 and F2013 is “interruptible” please explain why not.

RESPONSE:



Page 1 of 1


Exhibit: B-30



4.3.4 Exhibit B-22, page 6 (line 28) states that “new customers” are required to sign agreements that BC Hydro can shed their load, while page 7 (line 28) states that all new industrial customers over 1 MW have to accept load shedding. Please clarify: i) do the required load shedding agreements just apply to new customers over 1 MW and ii) do they just apply to new industrial customers?

RESPONSE:

The required load shedding agreements apply to all new customers over 1 MW.


Page 1 of 1


Exhibit: B-30


4.4.1 Assuming DCAT and GDAT come into service in F2014 and F2016 as planned, will BC Hydro be able to meet the revised load forecast as of those dates based on the N-1 standard?

RESPONSE:

When the DCAT project comes into service, some customers will not have N-1 level of service (as explained on page 73 of Exhibit B-22, the Supplemental Evidence). When a GDAT project comes into service, BC Hydro will be able to meet the updated load forecast on an N-1 basis. A GDAT project is still in the planning stage, and further upgrades may be required towards the end of the 30-year planning period depending on the scope of a GDAT project.


Page 1 of 1


Exhibit: B-30


4.4.2 If the utility is not able to meet the N-1 standard for F2014, will any of the customers who have entered into load shedding agreements since 2009 be granted firm (i.e., N-1) service after DCAT is in-service? If so, how will the determination be made as to which of these customers receive firm service?

RESPONSE:

None of the customers who have entered into load shedding agreements since 2009 will be granted firm service after the DCAT Project is in service. N-1 service will not be available until a GDAT project is implemented.

Please refer to the response to CEC IR 1.1.8 that describes load shedding regime and rules.


Page 1 of 1


Exhibit: B-30

5.0 Reference: Exhibit B-22, pages 6, 11, 16, 18 and 21

4.5.1 Please provide an update as to the status of the binding and interim agreements addressing each customer’s portion of the DCAT System Reinforcement security.

RESPONSE:



Page 1 of 1


Exhibit: B-30

6.0 Reference: Exhibit B-22, pages 5, 6 and 83-85

Exhibit B-1-3, page 4-23 (revised) Exhibit B-5, BCUC 1.39.1

4.6.1 Exhibit B-22 (page 6) states that each of the five customer’s security arrangements will be based on its proportionate share of “new customer load”. Given the range of in-service dates noted in the discussion on the individual customers (pages 5 and 9 to 21), what in-service dates will be included in the identification of the MWs used to determine each customer’s “proportionate share”?

RESPONSE:

The proportionate share of security is not dependent on the in-service dates of the new customer load served by the DCAT Project. As noted in Exhibit B-22, Q&A 10, security will be required to be provided by the customers within ten days of notification that a CPCN is issued.


Page 1 of 1


Exhibit: B-30


Exhibit B-1-3, page 4-23 (revised) Exhibit B-5, BCUC 1.39.1

4.6.2 Exhibit B-22 uses a project cost of $219 M when describing the determination of security to be provided by the DCAT customers. However, the updated cost of the project is $222.3 M. Please reconcile.

RESPONSE:

Discussions with customers pertaining to the security arrangements were too far advanced when this minor change in the cost estimate was identified.


Page 1 of 1


Exhibit: B-30


Exhibit B-1-3, page -23 (revised) Exhibit B-5, BCUC 1.39.1

4.6.3 As no DCAT customer has sought a Detailed Estimate please confirm that the final security deposit requirements will be based on the Actual Cost or the Estimated Actual Cost. If the latter, at what point in time will this “estimate” be established?

RESPONSE:

Please refer to the responses to BCUC Panel IR 1.1.2 and BCUC IR 3.19.4.

BC Hydro will amend its security requirements in the event that the Actual Cost varies materially from the basis on which the initial security was calculated. Estimated Actual Costs are used where final costs are not available, as per the Tariff. Generally, for practical purposes costs are established close enough to the end of the Project to ensure any estimate will be an accurate reflection of the Actual Costs.


Page 1 of 1


Exhibit: B-30


4.7.1 Please confirm whether the $116/MWh represents a levelized cost in real or nominal terms (i.e. if in real terms it would escalate at inflation to obtain the nominal cost in years after 2011 whereas if in nominal terms the $116/MWh would also represent the nominal cost in future years).

RESPONSE:

The $116/MWh represents a levelized cost in real terms.


Page 1 of 1


Exhibit: B-30


4.7.2 Similarly, please clarify whether the $50/MWH in 2011 $ market price is in real or nominal terms.

RESPONSE:

The $50/MWh represents a levelized cost in real terms.


Page 1 of 1


Exhibit: B-30

8.0 Reference: Exhibit B-22, pages 41, 49 and 72

4.8.1 If possible, please indicate the degree to which the capital cost and the PV for Alternative B1 is less than that of the proposed DCAT project (e.g., is the difference less than 5%, greater than 20%?).

RESPONSE:

BC Hydro estimates that the cost difference between the DCAT Project and Alternative B1 is in the range of 5 per cent to 10 per cent.


Page 1 of 1


Exhibit: B-30


4.9.1 What was the total generation (GWh) in each of years from 2008-2011 from the five gas-fired plants listed?

RESPONSE:

The annual generation from the five gas-fired plants is shown in the table below, for calendar years 2008 through 2011.

(GWh) 2008 2009 2010 2011 Burrard 299.6 259.2 57.9 16.9 Island Generation 2065.0 1671.7 1720.2 108.4 Fort Nelson 343.2 309.5 329.3 239.2 Prince Rupert 0.6 7.8 3.8 1.0 McMahon 820.5 839.2 835.7 824.6


Page 1 of 1


Exhibit: B-30


4.9.2 Are the five gas-fired plants listed used primarily as base load generation? If not, when/how are they typically operated?

RESPONSE:

McMahon Cogeneration Plant is operated as base load generation.

Fort Nelson Generating Station is operated to carry the Fort Nelson area load in conjunction with available power from Alberta. It can also be dispatched by AESO to support regional reliability for Alberta’s northwest region.

Island Generation is operated during times of system capacity need and is also dispatched economically when its cost of generation is attractive compared to market electricity prices or the cost of BC Hydro’s hydro generation.

Prince Rupert Generator is typically operated to during times of transmission outages in the North Coast.

Burrard is operated as allowed under the conditions set out in the CEA and subsequent Minister’s regulation to provide system capacity and regional capacity to the Lower Mainland region.


Page 1 of 1


Exhibit: B-30


4.9.3 In Table 2, are the values shown for “energy contribution from existing gas-fired generation” the anticipated production over F2014-F2030 or the firm energy the stations are capable of producing in this period?

RESPONSE:

The values shown are the firm energy capability of the generating stations.


Page 1 of 1


Exhibit: B-30


4.9.4 Does BC Hydro interpret the CEA as requiring at least of 93% of firm energy capability being from clean or renewable resources or at least 93% of energy actually produced being from clean or renewable generation?

RESPONSE:

BC Hydro plans such that its generation would be at least 93 per cent clean while meeting all of BC Hydro’s load obligations net of DSM from B.C. resources under average water conditions. Specifically, BC Hydro would develop resource plans where energy contribution under average water conditions of Heritage hydro facilities combined with the firm energy contribution from clean IPP resources would be at least 93 per cent of load requirements.


Page 1 of 1


Exhibit: B-30


4.10.1 Please provide a schedule that sets out the annual energy (MWh) used in the determination of the Cost of Energy in Table 7 for Alternatives G1 and G2. If the total energy supplied is not the same for both alternatives, please explain why.

RESPONSE:

Please refer to the excel Attachment 1 to the response to CEC IR 4.26.2 that provides details on the PV cost calculations for Alternatives G1 and G2. The schedules of energy used to determine the cost of energy for Alternatives G1 and G2 are shown at the respective tabs labelled “PV Calcs – Alt G1” and “PV Calcs – Alt G2” (line 8 for G1, and lines 8 + 11 for G2). The energy values are not the same for Alternatives G1 and G2 because Alternative G1 is assumed to serve a smaller portion of the Dawson Creek area load as explained at pages 47 to 49 of Exhibit B-22 (i.e., the Groundbirch portion of the load would be supplied by local generation in Alternative G2, but would be served via the BC Hydro integrated system in Alternative G1).


Page 1 of 1


Exhibit: B-30


4.10.2 On the same schedule please show for each alternative (G1 and G2) the split in energy as between system energy and local gas-fired generation.

RESPONSE:

The schedules of annual energies assumed for Alternatives G1 and G2 (as shown in the references provided in the response to BCOAPO IR 4.10.1) are assumed to be supplied only by local gas-fired generation. That is, no system energy is included in the evaluation of the cost of energy for Alternatives G1 and G2.


Page 1 of 1


Exhibit: B-30


4.10.3 Please confirm that, for purposes of costing system energy a market price of $50/MWh ($2011) was used for prior to the system need date of 2017 and an average plant gate price of $116/MWh ($2011) was used after the need date. If not, please explain what values were used and why.

RESPONSE:

The cost of energy for the local gas generation Alternatives G1 and G2 was determined based on the fuel, variable O&M, GHG offset costs, and Motor Fuel Tax cost components applicable to the local gas fired generating units from year F2016 onward (refer to the excel Attachment 1 to the response to CEC IR 4.26.2 for details). The assumption is that the local gas-fired units must run to meet reliability requirements, thus the option of importing system energy at $50/MWh prior to F2017 is not applicable to G1 and G2.


Page 1 of 1


Exhibit: B-30


4.11.1 Please provide a schedule that sets out the annual energy used in the determination of the Cost of Energy in Table 8. If the values are not the same as those for Table 7 please explain why.

RESPONSE:

Please refer to the excel Attachment 1 to the response to CEC IR 4.26.2. The schedules of energy quantities for DCAT Scenarios 1 and 2 are set out at lines 27 and 28 of tab “PV Calcs – Alt G1” and lines 30 and 31 of tab “PV Calcs – Alt G2,” respectively. The energy quantities for Alternative G1 and DCAT Scenario 1, used to develop the Cost of Energy values for Tables 7 and Table 8, respectively, are the same. The corresponding energy quantities for Alternative G2 and DCAT Scenario 2 are the same.


Page 1 of 1


Exhibit: B-30


4.11.2 Please explain why, for purposes of Table 8, this energy was not valued at $50/MWh ($2011) for energy used prior to the system need date of 2017 and an average plant gate price of $116/MWh ($2011) for energy used after the need date.

RESPONSE:

For the purpose of Table 8, the $50/MWh price for energy was used for year F2016. However, from F2017 onwards, the DCAT Scenarios assume that the principal source of new supply for the DCAT load would be a new gas-fired 250 MW CCGT unit located in the Kelly Lake/Nicola region of the BC Hydro integrated system. Starting in F2017 it is assumed that the energy supply for the DCAT Scenarios 1 and 2 would be at the variable cost of production from the 250 MW CCGT unit. The intention is to provide a cost comparison between meeting the DCAT area load with large scale CCGT gas generation on the integrated system plus the DCAT project, versus using small scale local CCGT/SCGT gas generation.

Note that for simplification, the IPP plant gate price of $116/MWh was used for the purpose of valuing the transmission losses associated with each gas generation alternative and DCAT Scenarios 1 and 2.


Page 1 of 1


Exhibit: B-30


4.11.3 Please re-do Table 8 where the Cost of Energy is valued at $50/MWh ($2011) prior to the system need date of 2017 and an average plant gate price of $116/MWh ($2011) after the need date.

RESPONSE:

As discussed in the response to CEC IR 4.26.3.5, BC Hydro cautions that the combined generation and transmission scenarios for DCAT based on these assumptions cannot be appropriately compared to the local gas Alternatives G1 and G2 for the purpose of determining the cost-effectiveness of the DCAT Project.

To respond to the question, however a revised version of Table 8 incorporating the requested assumptions is provided below.


Page 1 of 1


Exhibit: B-30

12.0 Reference: Exhibit B-22, pages 6-7 and 73

Exhibit B-6, BCOAPO 1.1.2.1

On page 73 BC Hydro states that it “has advised all new industrial customers that they will need to participate in a remedial actions scheme (RAS) until a future GDAT project can be brought into service”.

4.12.1 Is this the same requirement and does this involve the same customers as the load shedding agreement requirement described in response to BCOAPO 1.1.2.1 and/or discussed on pages 6-7?

RESPONSE:

Yes, the load shedding agreement described in the response to BCOAPO IR 1.1.2.1 specifies the terms and conditions for implementing the Remedial Action Scheme (also known as a Local Area Protection Scheme). All customers with loads in excess of 1 MW must sign the load shedding agreement. Please refer to the response to CEC IR 2.14.2.


Page 1 of 1


Exhibit: B-30

12.0 Reference: Exhibit B-22, pages 6-7 and 73

Exhibit B-6, BCOAPO 1.1.2.1

On page 73 BC Hydro states that it “has advised all new industrial customers that they will need to participate in a remedial actions scheme (RAS) until a future GDAT project can be brought into service”.

4.12.2 If not, what customers does this requirement (i.e., participation in a RAS until a future GDAT can be brought into service) apply to? In responding please describe both the size of customers it applies to and after what point in time this new requirement (as opposed to that outlined in BCOAPO 1.1.2.1) applied to customers requesting service.

RESPONSE:



Page 1 of 1


Exhibit: B-30


Exhibit B-6, BCOAPO 1.2.2

4.13.1 At this point in time, does BC Hydro have any formal commitments (per BCOAPO 1.2.2) with Gas Producers who require service prior to F2016 apart from five identified customers? If yes, what are the total MWs associated with those customers whose individual loads fall into each of the following ranges: i) 0-1 MW; ii) 1-10 MW and iii) >10 MW?

RESPONSE:

BC Hydro believes that a signed Electricity Service Agreement is the best indication of “formal commitment” from a distribution customer. Apart from the five DCAT customers, there are two other distribution customers with loads between 1 MW and 10 MW that have signed Electricity Service Agreements and plan to interconnect to the BC Hydro system.


Page 1 of 1


Exhibit: B-30



4.13.2 Does the revised load forecast (for the period up to F2016) assume any loads for individual customers that fall into the following ranges: i) 0-1 MW or ii) 1-10 MW?

RESPONSE:

Yes, the table below provides a breakdown of the revised gas producer load forecast.

The forecast assumes that a majority of loads in the 1 to 10 MW range will connect to the transmission system rather than the distribution system.

(All loads in MW) Size F2012 F2013 F2014 F2015 F2016 0 - 1 MW 0.1 0.4 0.4 0.4 0.4 1 – 10 MW 20 37 48 74 94 >10 MW 14 16 115 157 185


Page 1 of 1


Exhibit: B-30



4.13.3 If yes, please break the revised Gas Producer load forecast down into the following three categories: i) individual customers with loads between 0-1 MW; ii) individual customers with loads between 1-10 MW and ii) individual customers with loads >10 MWs.

RESPONSE:



Page 1 of 1


Exhibit: B-30


4.14.1 Please clarify what is meant by an “eligible” customer. In doing so, please confirm whether, in order to be eligible, the customer must comply with the conditions of BC Hydro’s approved tariffs.

RESPONSE:

An “eligible” customer is a customer that meets the availability criteria set out in the applicable BC Hydro tariff and is otherwise prepared to accept service under the provisions of BC Hydro’s tariff.


Page 1 of 1


Exhibit: B-30

15.0 Reference: Exhibit B-22, pages 80-81 Exhibit B-1, page 4-26 and Appendix I

4.15.1 For purposes of calculating the “rate impact” of project, BC Hydro assumes there is no increase in overall energy sales (per Appendix I). However, for purposes of BC Hydro Offset calculation under Tariff 6 it is assumed that the project generates additional revenues (as a result of increased sales). Please reconcile this inconsistency.

RESPONSE:

The calculation of the rate impact of the project and the determination of BC Hydro’s offset under TS 6 are wholly unrelated.

As set out in the response to BCUC IR 1.60.3, BC Hydro’s rate impact model is intended to analyze the impacts on overall rates of making expenditures on the facilities for which a CPCN is sought. BC Hydro is not seeking a CPCN with respect to any generation facilities in the context of the DCAT Project and accordingly, neither the cost of acquiring nor the revenue from selling energy is included in the rate impact analysis presented in Appendix I.

The calculation of BC Hydro’s offset under TS 6 is made pursuant to a formula which does require consideration of incremental revenue from customer sales. The purpose of this calculation is to determine whether the customer should be charged for system reinforcement that is necessary in order to serve its load.

The BCUC, in approving the formula within TS 6, can be taken to have concluded that a contribution should only be required from customers if the total revenue they contribute to BC Hydro over the 7.4 years of service is insufficient to cover the costs of that system reinforcement. The tariff requires BC Hydro to estimate those revenues.


Page 1 of 1


Exhibit: B-30

16.0 Reference: Exhibit B-22, pages 73 and 80-82

Exhibit B-15, BCOAPO 2.9.1 Exhibit B-14, BCUC 2.19.1

4.16.1 Please confirm that the value for R is calculated using the full transmission or distribution rate as applicable to each customer. If not, what “rate” is used?

RESPONSE:

The value of R was based on a combined effective energy charge of approximately 4.5 cents per kWh, based on the applicable transmission and distribution rates under the Electric Tariff.


Page 1 of 1


Exhibit: B-30



4.16.2 Does the $429 M represent 7.4 times the estimated first 12 months of revenue for each customer? If not, how was it calculated?

RESPONSE:

Yes.

For a description of the BC Hydro maximum offset calculation of $429 million, please also refer to the response to BCUC IR 1.48.2.


Page 1 of 1


Exhibit: B-30



4.16.3 Please provide a table (similar to page 5, Table 1) that sets out the total new customer loads (by year of in-service) used in the calculation of the R value.

RESPONSE:

The calculation of R was for the purpose of calculating BC Hydro’s maximum offset, which was determined to be $429 million, using an estimated combined load of 176 MW for the five customers. The offset determined if the customers would be required to make a contribution. BC Hydro saw no need to split out the customer loads by year, since the bulk of the new loads corresponded to when the DCAT Project is put into service.


Page 1 of 1


Exhibit: B-30



4.16.4 If the total new loads used to calculate R exceed 73 MW please explain why this higher MW value is used when the DCAT upgrade can only provide N-1 service to 73 MW of new load (per BCUC 2.19.1)?

RESPONSE:

As described response to BCUC IR 2.19.1, the five new customers are accepting the risk of interruption until sufficient system upgrades are in place to meet the N-1 planning criteria. BC Hydro will supply the full load of 176 MW under N-0 conditions and will receive the associated revenues for that supply. In some instances, customers are maintaining interim back-up facilities until N-1 service is available.


Page 1 of 1


Exhibit: B-30



4.16.4.1 Also, please explain why any new loads in excess of the 73 MW wouldn’t be associated with the GDAT project and used in future calculations of potential customer cost responsibility for System Reinforcement costs connected with that project.

RESPONSE:


As explained in the response to BCOAPO IR 4.16.4, those loads will be added as part of the DCAT Project and the costs will be incurred as part of the DCAT Project. Since the new loads in excess of 73 MW are comprised of current requests as opposed to forecasts, BC Hydro can see no logical reason, nor can it find any tariff support, for not recognizing these costs and the associated revenues in calculating the customer cost responsibility and BC Hydro’s offset for the DCAT Project.


Page 1 of 1


Exhibit: B-30



4.16.5 Please recalculate the equivalent of the $429 M values based on 73 MW of new load at Transmission Service rates. For purposes of the calculation please assume an overall customer load factor equivalent to the (weighted) average for the three transmission customers.

RESPONSE:

The equivalent calculation would be simply a proration of 176 MW, i.e., 73 MW/176 MW x $429 million = $175.8 million. In this case, BC Hydro’s maximum offset would still exceed the estimated cost of system reinforcement allocated to customers of $131.5 million.


Page 1 of 1


Exhibit: B-30



4.16.6 Page 81 indicates that the value for R in the offset calculation is based on the first 12 months after the normal operations begin. In determining the offset amount of $429 M did BC Hydro assume there was an unrestricted supply available to each customer in the first year to meet all of its electrical requirements?

RESPONSE:

Yes. BC Hydro assumed that it was able to supply the full combined load of the five customers of 176 MW.


Page 1 of 1


Exhibit: B-30



4.16.6.1 If not, what assumptions were made about the availability of electricity to each customer?

RESPONSE:

Please refer to response to BCOAPO IR 4.16.6.


Page 1 of 1


Exhibit: B-30



4.16.6.2 If yes, please reconcile this assumption with the fact some customers are currently using on-site generation (per page 17) and all customers have load shedding agreements.

RESPONSE:

BC Hydro understands that the customer generation is temporary until the DCAT Project is in service. BC Hydro is expecting to supply the full 176 MW once the DCAT Project is implemented.


Page 1 of 1


Exhibit: B-30



The response to BCUC 1.51.3 states that the two Distribution Service customers will be required to pay an additional Distribution Extension Fee.

4.17.1 Please confirm that in calculating the Distribution Extension Fee required from customers, the offset provided by BC Hydro is based on the customer’s anticipated billing demand (per Section 8.3 of the Terms and Conditions).

RESPONSE:

Confirmed. BC Hydro’s maximum contribution is $200 per kW of estimated billing demand.


Page 1 of 1


Exhibit: B-30




4.17.2 If this the case, are these customers not being credited twice for their anticipated billing demand – once in the determination of the Distribution Extension Fee and a second time in the determination of the BC Hydro offset to be provided under Tariff 6 for Transmission Reinforcement? If not, please explain why not.

RESPONSE:

Yes, customers may be credited twice, however BC Hydro does not consider the result to have a material financial impact.


Page 1 of 1


Exhibit: B-30




4.17.3 Please recalculate the equivalent of the $429 M – but exclude the loads associated with the two Distribution service customers.

RESPONSE:

BC Hydro believes that it is appropriate to include distribution revenue in the offset calculation because distribution customers will be required to pay or post security for transmission upgrades on the same basis as transmission service customers.

If the revenue from the two distribution customers is removed, the annual revenues from the five DCAT customers of $58 million (shown in the response to BCUC IR 2.19.2) would decrease to $48 million and the maximum offset under TS 6 would decrease from $429 million to $355 million.


Page 1 of 1


Exhibit: B-30




4.17.4 Based on BC Hydro’s calculations what is the proportionate share (i.e., %) attributable to the two distribution customers?

RESPONSE:

Based on the calculation shown in response to BCOAPO IR 4.17.3 the proportionate share of transmission attributable to the two distribution customers is approximately 17 per cent.


Page 1 of 1


Exhibit: B-30


4.18.1 Please outline the reasons for the increase in: i) Direct Definition Phase Costs and ii) Project Management, Engineering, Property, Consultation, and Environment Costs.

RESPONSE:

The reasons for the cost increases identified in the question are as follows:

Direct Definition Phase Cost Estimates:

The Direct Definition Phase cost estimate (Table 4-1, line 1) increased due to the update of the regulatory and legal related costs, and increased project management costs due to the extension of the project timelines.

Project Management, Engineering, Property, Consultation and Environment Cost Estimates:

The Project Management, Engineering, Property, Consultation and Environment cost estimate (Table 4-1, line 3) increased by approximately $5.2 million. The table below (based on the table provided in the response to BCUC IR 1.55.3) summarizes the cost changes:

All costs are in thousands ($000).

August 2011 March 2012 Variance Project Management 8,130 8,499 369 Engineering 8,439 11,381 2,942 Property 12,415 14,207 1,792

Total 28,984 34,087 5,103

The change in Engineering costs is due refinement of the estimate for the work required to design the line, including additional equipment testing, GIS mapping, permitting support, and owner’s engineer costs.

The Properties costs were updated based on the refinement of the property required for the line that has occurred as the design has progressed.


Page 1 of 1


Exhibit: B-30


4.18.2 Given the later in-service date why has the allowance for inflation not increased?

RESPONSE:

The allowance for inflation has not increased as a result of a later in-service date for the Project because the timing of significant expenditures is delayed, as well as other changes to expected cash flows during the life cycle of the Project.

Please refer to the response to BCUC IR 1.55.4 for an explanation of the calculation for inflation.

The inflation shown in Exhibit B-1-3, revised page 4-24, Table 4, line 6, is incorrect due to a typographical error and should be $6.1 million. Exhibit B-1-3 revised Appendix C page 1 of 1, is correct.


Page 1 of 1


Exhibit: B-30


4.18.3 Given that the P50 cost estimate has increased, why is the Project Reserve less?

RESPONSE:

The two cost estimates were produced seven months apart. During that time, additional work was undertaken which has resulted in a better understanding of the project and has reduced project uncertainty, reducing the overall project risk. This improved understanding and increased certainty is reflected in a reduced variation in the Monte Carlo analysis, which in turn allowed a reduction in the project reserve.

REQUESTOR NAME: BC Sustainable Energy Association and Sierra Club of British Columbia INFORMATION REQUEST ROUND NO: 4 TO: B.C. Hydro DATE: May 14, 2012 PROJECT NO: 3698640 APPLICATION NAME: Dawson Creek/Chetwynd Area Transmission Project ______________________________________________________________________ 4.41.0 Topic: BCSEA-SCBC IR3

Reference: Exhibit C8-6, BCSEA-SCBC IR#3; Exhibit B-25; Exhibit B-22, Supplemental Evidence; Exhibit B-27; Exhibit A-28, Order G-56-12

In Exhibit C8-6, BCSEA-SCBC made its Round 3 IRs to BC Hydro, numbered 3.33 to 3.40. In Exhibit B-25, BC Hydro listed intervenor and staff IRs it saw as either outside the proper scope of the proceeding or answered in the Supplemental Evidence (Exhibit B-22). BC Hydro addressed BCSEA-SCBC IR 3.33.1, 3.33.2 and 3.33.3, each of which BC Hydro said were out of scope. BC Hydro did not list BCSEA-SCBC IRs 3.34 to 3.40 as being either out of scope or answered in the Supplemental Evidence. In Exhibit B-27, BC Hydro lists intervenor and staff Third Round IRs that it commits to answering. The list does not include any of BCSEA-SCBC’s IRs 3.34 to 3.40. In Order G-56-12 (Exhibit A-28), the Commission issued a scoping determination in this proceeding.

4.41.1 For each of BCSEA-SCBC IRs 3.34 to 3.40, please provide either an answer, an explanation of why BC Hydro considers the question out of scope in light of Order G-56-12, or a reference to where the question is answered in the Supplementary Evidence.

4.42.0 Topic: Scope of proceeding Reference: Exhibit B-22, Supplemental Evidence; Exhibit B-25; Exhibit A-28 Scoping Decision;

In Order G-56-12 [Exhibit A-28], the Commission ruled on BC Hydro’s submissions regarding the scope of the proceeding.

4.42.1 Please parse the Commission’s scoping decision in Order G-56-12 and indicate whether each element is consistent with, or different than, BC Hydro’s submissions regarding the proper scope of the proceeding.

4.42.2 In light of the Commission’s scoping decision, are there any intervenor or staff Round 3 IRs that BC Hydro had previously considered out of scope that now should be considered within scope? If so, please list them and provide answers.

4.43.0 Topic: GHG emissions reductions Reference: Exhibit B-1, s.2.61; : Exhibit A-28 Scoping Decision

C8-9

markhuds


BCSEA-SCBC IR 4 May 14, 2012 BC Hydro DCAT Page 2 of 3

In the original application, BC Hydro argued that the Project would have a favourable impact on BC’s GHG emissions reduction targets, per CEA, subsection 2(g), and on encouraging the switching from one kind of energy source or use to another that decreases greenhouse gas emissions in British Columbia, per CEA, subsection 2(h). In IR 3.33.2, BCSEA-SCBC asked:

“Does BC Hydro agree that, other things being equal, the DCAT project would be more likely to be determined to be in the public interest if there was some assurance that the natural gas production electrical load would be comprised of the most efficient machinery reasonably possible? If not, please explain why not?”

BC Hydro’s April 17, 2012 letter (Exhibit B-25) explains its view that BCSEA-SBCC IR 3.33.2 is out of scope (and as follows:

“BC Hydro has set out its objections to investigating the use to which the electricity will be put in the context of this application in the March 23rd

Letter at page 5 under the heading End Use Rates. BC Hydro has outlined the efforts it has made to introduce its new customers to its power smart programs in SE Questions 19, 27, 32, 41 and 51.”

The March 23, 2012 letter (Exhibit B-22) includes the following under the heading End Use Rates:

“BC Hydro's rates and the terms and conditions of service do not distinguish between customers based on the use to which power is put. ... BC Hydro has not assessed the economic, environmental and social benefits or costs resulting from the proposed activities of the DCAT Project customers except as they relate to the government's energy objectives. ...”

Order G-56-12 states in point 4 on page 7 of 9: “...Any questions relating to the application of the CEA to the DCAT project is [sic] appropriate and necessary for a CPCN application.”

4.43.1 Please explain BC Hydro’s current position regarding how the Project would affect BC’s Energy Objectives regarding GHG emissions reductions (CEA, subsection 2(g)) and fuel-switching to reduce GHG emissions (CEA, subsection 2(h)).

4.43.2 Has this position changed since the Application was filed? If so, please explain.

4.43.3 Please confirm that in the original application, BC Hydro’s analysis of the impact of the Project on GHG emissions reductions is based primarily on the comparative GHG emissions of the customers to be served by the Project with and without the Project. If not, please explain.

BCSEA-SCBC IR 4 May 14, 2012 BC Hydro DCAT Page 3 of 3

4.43.4 Please reconcile the GHG consequences analysis in s.2.6.1 of the Application with BC Hydro’s position in Exhibits B-22 and B-27 objecting to investigating the use to which the electricity will be put in the context of this application. If the to-be-served customers’ use of the electricity is not relevant to the review of the Project then how is the alternative in which the to-be-served customers do not use electricity relevant?

BC Sustainable Energy Association and Sierra Club of British Columbia Information Request No. 4.41.1 Dated: May 14, 2012 British Columbia Hydro & Power Authority Response issued May 24, 2012

Page 1 of 1


Exhibit: B-30

41.0 Topic: BCSEA-SCBC IR3

Reference: Exhibit C8-6, BCSEA-SCBC IR#3; Exhibit B-25; Exhibit B-22, Supplemental Evidence; Exhibit B-27; Exhibit A-28, Order G-56-12

In Exhibit C8-6, BCSEA-SCBC made its Round 3 IRs to BC Hydro, numbered 3.33 to 3.40.

In Exhibit B-25, BC Hydro listed intervenor and staff IRs it saw as either outside the proper scope of the proceeding or answered in the Supplemental Evidence (Exhibit B-22). BC Hydro addressed BCSEA-SCBC IR 3.33.1, 3.33.2 and 3.33.3, each of which BC Hydro said were out of scope. BC Hydro did not list BCSEA-SCBC IRs 3.34 to 3.40 as being either out of scope or answered in the Supplemental Evidence.

In Exhibit B-27, BC Hydro lists intervenor and staff Third Round IRs that it commits to answering. The list does not include any of BCSEA-SCBC’s IRs 3.34 to 3.40.

In Order G-56-12 (Exhibit A-28), the Commission issued a scoping determination in this proceeding.

4.41.1 For each of BCSEA-SCBC IRs 3.34 to 3.40, please provide either an answer, an explanation of why BC Hydro considers the question out of scope in light of Order G-56-12, or a reference to where the question is answered in the Supplementary Evidence.

RESPONSE:

In a letter dated April 17, 2012 (Exhibit B-25), BC Hydro provided its view on the Round 3 IRs which required answering in view of its submission of the Supplemental Evidence (Exhibit B-22). In its letter, BC Hydro invited interveners to identify IR3 questions which in their view required responses. The BCUC Staff and some Interveners responded in writing to identify requested IR3 responses prior to the procedural conference of May 2.

At the procedural conference, BC Hydro and all Interveners were provided the opportunity to address requirements for responses to IR3 questions.

The BCUC’s Order No. G-56-12 (and associated Reasons for Decision) expressly addressed and identified the Round 3 IRs to be responded to by BC Hydro. The Order also allowed for a further round of IRs (IR4).

In these circumstances, BC Hydro considers that the BCUC has determined that BC Hydro should limit its response to those questions it either volunteered to answer at the Prehearing Conference, the BCUC expressly required it to answer in Order No. G-56-12 or are found in Round 4 IRs relating to Exhibit B-22. BC Hydro is complying with that direction in this round of responses.


Page 1 of 1


Exhibit: B-30

42.0 Topic: Scope of proceeding

Reference: Exhibit B-22, Supplemental Evidence; Exhibit B-25; Exhibit A-28 Scoping Decision;


4.42.1 Please parse the Commission’s scoping decision in Order G-56-12 and indicate whether each element is consistent with, or different than, BC Hydro’s submissions regarding the proper scope of the proceeding.

RESPONSE:

In BC Hydro’s view the BCUC Order No. G-56-12 and associated Reasons for Decision speaks for itself and renders unnecessary reconciling the decision with the submissions of BC Hydro’s or any other participant in the proceeding.


Page 1 of 1


Exhibit: B-30

42.0 Topic: Scope of proceeding

Reference: Exhibit B-22, Supplemental Evidence; Exhibit B-25; Exhibit A-28 Scoping Decision;


4.42.2 In light of the Commission’s scoping decision, are there any intervenor or staff Round 3 IRs that BC Hydro had previously considered out of scope that now should be considered within scope? If so, please list them and provide answers.

RESPONSE:

Please refer to the response to BCSEA IR 4.41.1.


Page 1 of 1


Exhibit: B-30

43.0 Topic: GHG emissions reductions

Reference: Exhibit B-1, s.2.61; Exhibit A-28 Scoping Decision




“BC Hydro has set out its objections to investigating the use to which the electricity will be put in the context of this application in the March 23rd Letter at page 5 under the heading End Use Rates. BC Hydro has outlined the efforts it has made to introduce its new customers to its power smart programs in SE Questions 19, 27, 32, 41 and 51.”


“BC Hydro's rates and the terms and conditions of service do not distinguish between customers based on the use to which power is put. ...

BC Hydro has not assessed the economic, environmental and social benefits or costs resulting from the proposed activities of the DCAT Project customers except as they relate to the government's energy objectives. ...”


4.43.1 Please explain BC Hydro’s current position regarding how the Project would affect BC’s Energy Objectives regarding GHG emissions reductions (CEA, subsection 2(g)) and fuel-switching to reduce GHG emissions (CEA, subsection 2(h)).

RESPONSE:

Please refer to section 2.6.1 of Exhibit B-1.


Page 1 of 1


Exhibit: B-30











4.43.2 Has this position changed since the Application was filed? If so, please explain.

RESPONSE:

No.


Page 1 of 2


Exhibit: B-30











4.43.3 Please confirm that in the original application, BC Hydro’s analysis of the impact of the Project on GHG emissions reductions is based primarily on the comparative GHG emissions of the


Page 2 of 2


Exhibit: B-30

customers to be served by the Project with and without the Project. If not, please explain.

RESPONSE:

The analysis is described in response to BCSEA IR 1.8.1. The underlying assumption is system clean electricity supplied by BC Hydro would result in lower GHG emissions relative to what would otherwise occur if natural gas producers in the DCAT region were to self-supply their work energy requirements.


Page 1 of 2


Exhibit: B-30











4.43.4 Please reconcile the GHG consequences analysis in s. 2.6.1 of the Application with BC Hydro’s position in Exhibits B-22 and B-27


Page 2 of 2


Exhibit: B-30

objecting to investigating the use to which the electricity will be put in the context of this application. If the to-be-served customers’ use of the electricity is not relevant to the review of the Project then how is the alternative in which the to-be-served customers do not use electricity relevant?

RESPONSE:

At page 5 of BC Hydro’s letter of March 23, 2012 filed as Exhibit B-22, BC Hydro sets out its position with respect to end-use rates. There, BC Hydro indicates that it does not distinguish between customers based on the use to which power is put and that it has only assessed the economic, environmental and social benefits or costs resulting from the proposed activities of the DCAT project customers to the extent they relate to the government’s energy objectives.

Section 2.6.1 of the Application contains a discussion of the impact on greenhouse submissions of providing customers with the ability to employ electric as opposed to natural gas compressors. BC Hydro has not objected to questions in connection with that issue.

BC Hydro has objected to questions that contemplate providing discriminatory service or rates to customers based on the nature of their end use. BC Hydro has consistently taken the position that proposals to profoundly revise BC Hydro’s tariff should not be considered in the context of this CPCN application.

…./ 1

344 - 7th Avenue NE Calgary, AB T2E 0M9 W: (403) 233-7037 F: (403) 233-7036 British Columbia Utilities Commission 600-900 Howe Street Vancouver, B.C V6Z 2N3

Attention: Ms. Alanna Gillis Acting Commission Secretary

Dear Madam:

RE: British Columbia Hydro and Power Authority Dawson Creek/Chetwynd Area Transmission Project, Certificate of Public Convenience and Necessity Application Project No.3698640/Order G-132-11 RE: IR4 to BC Hydro

Attached please find Information Requests to BC Hydro.

Sincerely,

Jamie Shand President, Current Solutions Inc.

C15-4

ylapierr

Dawson Creek/Chetwynd Area Trans

…./ 2

Current Solutions Inc. INFORMATION REQUEST ROUND NO: 4

TO: BRITISH COLUMBIA HYDRO & POWER AUTHORITY May 14, 2012

PROJECT NO: 3698640 CPCN – Dawson Creek/Chetwynd Area Transmission Project

_________________________________________________________________________ IR4.1 Preamble: On March 11, 2010 five wind generation projects, connected to the

Peace region 230 kV system, were selected for an award of an Electricity Purchase Agreement (EPA) under the Clean Power Call.

Reference: System Planning Report Exhibit B‐1, (pdf page 215)

Exhibit B-1, (Pdf page 212-214) Information Request:

a. Has a System Impact Study (SIS) been undertaken for each of these wind generation projects?

b. How was system upgrade costs allocated to the 230 kV wind projects? _________________________________________________________________________ IR4.2 Preamble With respect to wind generation operation and its impact on the

transmission system, BC Hydro has not specified which system limits have been and not been exceeded.

Reference: BC Hydro Response to CEC Information Request No. 2.17

Exhibit B‐15, (pdf page 194) 2.17.2 Please clarify where the BC Hydro system is now with respect to approaching these limits on wind integration in terms of added MW of wind generation before the limits are reached. RESPONSE: Presently, BC Hydro has two wind farms interconnected to the transmission system in the Peace Region: Bear Mountain Wind Park in Dawson Creek area and Dokie Wind Project near GMS. The integration of wind generation (Bear Mountain Wind Park and the Dokie Wind Project) does not cause the limits of the current BC Hydro system to be exceeded.

…./ 3

Reference: 2.2.2 Dawson Creek Transmission System

Exhibit B-1, page 2-5, (pdf pg. 31) The only local source of generation in the Dawson Creek area is the 102 MW Bear Mountain Wind Farm located approximately 15 km south west from the City of Dawson Creek, which provides an intermittent source of electricity to the area. The wind farm is connected to BMT by a customer owned 138 kV line (1L354).

Information Request:

a. Is Bear Mountain Wind (BMW) the only wind farm on BC Hydro transmission system connected at 138 kV?

b. Were BC Hydro’s reliability requirements met while evaluating the forecast system load and the 102 MW’s of BMW wind generation during the system study phase?

i. Please file the study’s results and assumptions showing the system reliability with BMW generation operating under N-0 and N-1 conditions.

c. Were load flow and dynamic switching studies part of the System Impact Study (SIS) under taken for the interconnection of the BMW generation at 138 kV?

i. If yes, please file the SIS study. d. Has BC Hydro’s steady state voltage criteria in the area ever been exceeded

due to BMW connecting to and disconnecting from the system under N-0 and N-1 conditions?

e. During the period from October 2010 to May 2012, has the 138/25 kV Dawson Creek substation ever been required to shed load due to the intermittent generation output from the Bear Mountain Wind farm?

i. If yes. What was the generation in MW’s of Bear Mountain Wind that was switched off the transmission system?

ii. What was the area system load at the time the load was shed? iii. Likewise, have any customers been requested to shed load? iv. Please provide details for these outages.

_________________________________________________________________________ IR4.3 Preamble With respect to wind generation operation and its impact on the

Transmission system, BC Hydro does not specify if the operation of the Bear Mountain Wind generation improves when interconnected at 230 kV.

Reference: Wind generation

4.3.2 Wind Generation Criteria Page 34 (pdf page 232) Exhibit B-1 Wind generation is assumed to have zero MW output when determining all load driving constraints under both N-0 and N-1 system conditions because it is an Intermittent resource. The cumulative 30-year EENS indicates that Alternative 1 offers better reliability than Alternative 2.

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a. Were load flow and dynamic switching studies part of the System Impact Study (SIS) under taken for the evaluation of the proposed DCAT Alternative 2?

i. If yes, please file the SIS study. b. Please describe how the proposed Dawson Creek Area Transmission System

voltage on the 138 kV bus at the 138/25 kV Dawson Creek substation responds when the 102 MW’s of BMW generation is instantly removed from the local system and the generation source swings to GMS?

c. Likewise, please describe the impact when 102 MWs of wind power are added.

d. If operation of the Bear Mountain Wind farm causes BC Hydro’s voltage criteria to be exceeded, shouldn’t BC Hydro allocate the entire cost of the required DCAT 230 kV upgrade to either the wind generation or the system?

_________________________________________________________________________ IR4.4 Preamble BC Hydro has proposed changes to Electric Tariff terms and

Conditions for distribution customers. It is expected that some aspects of the Tariff terms and conditions that previously only applied to transmission customers will now apply to distribution customers.

Reference: 2.8 Proposed Tariff Revision

Exhibit B-1: page 2-20 (pdf page 46) The revision to the Electric Tariff Terms and Conditions will permit BC Hydro to recover from distribution customers that seek new service in excess of 10 MW some of the costs of transmission reinforcement made necessary, in whole or in part, by the new load.

Reference: BC Hydro response to BCUC IR1.51.3.2 Exhibit B-5 BC Hydro’s maximum contribution is based on an Extension Allowance of $200 per kW of estimated billing demand for distribution customers.


a. How was the 10 MW level applicable to distribution customers selected?

b. Will distribution customers subject to the proposed Tariff revisions continue to pay for electricity at RS1611 or will they be switched to the RS1823 tariff?

c. Will the existing $200 per kW distribution capital contribution now be increased to account for the extra costs that distribution customers will incur to provide credit for system infrastructure?

d. Has an estimation of overhead costs for the administration of LOC’s for the distribution customers been made?

a. If no, does BC Hydro consider that the logistics, cost and administration burden to manage the proposed Tariff Revision not a material cost increase?

…./ 5

e. Please outline in detail the past, current and future resources and costs

(both internally and externally) to administer this new proposed LOC commercial program (Key Account Managers, lawyers, finance, regulatory resources, accountants, etc.).

i. Is this extra cost going to be added to the general overhead for all rate payers?

ii. If so, what tariffs will these ongoing costs be charged to? _________________________________________________________________________ IR4.5 Preamble BC Hydro is concerned with risk mitigation of the cost of system

expansions. Current Solutions Inc. is also concerned with the risk mitigation of system upgrade projects.

Reference: 2.8 Proposed Tariff Revision

Exhibit B-1: page 2-20 (pdf page 46) To resolve this inequity and to protect existing customers against the risk of over capacity if new customers choose not to use electricity for compression, BC Hydro is applying to revise its Electric Tariff to permit it to recover security for the cost of transmission reinforcements from appropriate distribution customers.


a. Is BC Hydro aware that the Oil and Gas customers have already paid over $6 billion to the BC government for land leases?

b. Does BC Hydro consider BC Government energy policy (such as build before contract, BC Energy Plan, Electricity Policies, #12) when considering system upgrades?

i. If yes, how is this policy reflected in BC Hydro’s proposed tariff changes?

c. Has BC Hydro asked the BC Government to back stop system expansions? i. If “No”, why has BC Hydro not approached the BC Government to

address risk mitigation concerns? ii. If “Yes”, what was the BC Governments response?

Current Solutions Inc. Information Request No. 4.1.a Dated: May 14, 2012 British Columbia Hydro & Power Authority Response issued May 24, 2012

Page 1 of 1


Exhibit: B-30

1.0 Reference: System Planning Report

Exhibit B-1, (pdf page 215)

On March 11, 2010 five wind generation projects, connected to the Peace region 230 kV system, were selected for an award of an Electricity Purchase Agreement (EPA) under the Clean Power Call.

4.1.a Has a System Impact Study (SIS) been undertaken for each of these wind generation projects?

RESPONSE:

System Impact Studies were performed for all five wind farms connecting to the Peace 230 kV system in accordance with the Standard Generator Interconnection Procedures in the OATT tariff. The corresponding SIS reports are posted on the BC Hydro website at http://transmission.bchydro.com/generator_interconnection/engineering_studies_data/studies/interconnection/generator/

Current Solutions Inc. Information Request No. 4.1.b Dated: May 14, 2012 British Columbia Hydro & Power Authority Response issued May 24, 2012

Page 1 of 1


Exhibit: B-30

1.0 Reference: System Planning Report

Exhibit B-1, (pdf page 215)

On March 11, 2010 five wind generation projects, connected to the Peace region 230 kV system, were selected for an award of an Electricity Purchase Agreement (EPA) under the Clean Power Call.

4.1.b How was system upgrade costs allocated to the 230 kV wind projects?

RESPONSE:

The only upgrade costs required for the 230 kV wind projects, were the individual interconnection costs associated with each project. These costs are assigned to each project and are paid by the customer. There were no other system upgrades required for these five projects.


Page 1 of 1


Exhibit: B-30

2.0 Reference: BC Hydro Response to CEC Information Request No. 2.17 Exhibit B‐15, (pdf page 194)

2.17.2 Please clarify where the BC Hydro system is now with respect to approaching these limits on wind integration in terms of added MW of wind generation before the limits are reached.

RESPONSE: Presently, BC Hydro has two wind farms interconnected to

the transmission system in the Peace Region: Bear Mountain Wind Park in Dawson Creek area and Dokie Wind Project near GMS. The integration of wind generation (Bear Mountain Wind Park and the Dokie Wind Project) does not cause the limits of the current BC Hydro system to be exceeded.

2.2.2 Dawson Creek Transmission System Exhibit B-1, page 2-5, (pdf pg. 31)

The only local source of generation in the Dawson Creek area is the 102 MW Bear Mountain Wind Farm located approximately 15 km south west from the City of Dawson Creek, which provides an intermittent source of electricity to the area. The wind farm is connected to BMT by a customer owned 138 kV line (1L354).

With respect to wind generation operation and its impact on the transmission system, BC Hydro has not specified which system limits have been and not been exceeded.

4.2.a Is Bear Mountain Wind (BMW) the only wind farm on BC Hydro transmission system connected at 138 kV?

RESPONSE:

Yes, Bear Mountain Wind (BMW) is the only wind farm on the BC Hydro transmission system connected at 138 kV.


Page 1 of 2


Exhibit: B-30








4.2.b Were BC Hydro’s reliability requirements met while evaluating the forecast system load and the 102 MW’s of BMW wind generation during the system study phase?

i. Please file the study’s results and assumptions showing the system reliability with BMW generation operating under N-0 and N-1 conditions.

RESPONSE:

For the condition where area load does not exceed the transmission system capacity (N-1), the following system performance is expected:


Page 2 of 2


Exhibit: B-30

Bear Mountain Wind at Full MW output

Under System Normal conditions (N-0), no thermal or steady state voltage violations are expected.

The loss of the BMW wind farm would not result in thermal or steady state voltage violations.

The loss of one 138 kV transmission line would not result in thermal or steady state voltage violations.

Bear Mountain Wind at zero MW output

Under System Normal conditions (N-0), no thermal or steady state voltage violations are expected.

The loss of one 138 kV transmission line would not result in thermal or steady state voltage violations.

However, for the condition where area load exceeds the transmission system’s capacity to supply load after a transmission line forced outage event, a load shedding scheme has been implemented to ensure the system continues to operate within safe limits. This load shedding scheme adjusts shedding requirements based on area load and BMW output. Though BMW is an intermittent resource, higher BMW output, when available, reduces shedding requirements because area load is displaced by BMW generation. Therefore, BMW helps the area reliability by minimizing shedding requirements when area load exceeds system capacity.

Current Solutions Inc. Information Request No. 4.2.c Dated: May 14, 2012 British Columbia Hydro & Power Authority Response issued May 24, 2012

Page 1 of 1


Exhibit: B-30



RESPONSE: Presently, BC Hydro has two wind farms interconnected to the

transmission system in the Peace Region: Bear Mountain Wind Park in Dawson Creek area and Dokie Wind Project near GMS. The integration of wind generation (Bear Mountain Wind Park and the Dokie Wind Project) does not cause the limits of the current BC Hydro system to be exceeded.




4.2.c Were load flow and dynamic switching studies part of the System Impact Study (SIS) under taken for the interconnection of the BMW generation at 138 kV?

i. If yes, please file the SIS study.

RESPONSE:

Load flow and transient stability studies were undertaken as part of the System Impact Study for the interconnection of BMW. Dynamic switching studies were not undertaken.

Generator Interconnection Studies can be found on BC Hydro’s website at:

http://transmission.bchydro.com/generator_interconnection/engineering_studies_data/studies/interconnection/generator/

Current Solutions Inc. Information Request No. 4.2.d Dated: May 14, 2012 British Columbia Hydro & Power Authority Response issued May 24, 2012

Page 1 of 1


Exhibit: B-30








4.2.d Has BC Hydro’s steady state voltage criteria in the area ever been exceeded due to BMW connecting to and disconnecting from the system under N-0 and N-1 conditions?

RESPONSE:

Please refer to the responses to CSI IRs 4.2.b and 4.2.e.

Current Solutions Inc. Information Request No. 4.2.e Dated: May 14, 2012 British Columbia Hydro & Power Authority Response issued May 24, 2012

Page 1 of 2


Exhibit: B-30








4.2.e During the period from October 2010 to May 2012, has the 138/25 kV Dawson Creek substation ever been required to shed load due to the intermittent generation output from the Bear Mountain Wind farm?

i. If yes. What was the generation in MW’s of Bear Mountain Wind that was switched off the transmission system?

ii. What was the area system load at the time the load was shed?

iii. Likewise, have any customers been requested to shed load?

iv. Please provide details for these outages.


Page 2 of 2


Exhibit: B-30

RESPONSE:

Under system normal operations, BC Hydro is not aware of any incident where intermittent generation output from BMW caused load shedding.


Page 1 of 1


Exhibit: B-30

3.0 Reference: Wind generation 4.3.2 Wind Generation Criteria Page 34 (pdf page 232) Exhibit B-1

Wind generation is assumed to have zero MW output when determining all load driving constraints under both N-0 and N-1 system conditions because it is an Intermittent resource. The cumulative 30-year EENS indicates that Alternative 1 offers better reliability than Alternative 2.

With respect to wind generation operation and its impact on the Transmission system, BC Hydro does not specify if the operation of the Bear Mountain Wind generation improves when interconnected at 230 kV.

4.3.a Were load flow and dynamic switching studies part of the System Impact Study (SIS) under taken for the evaluation of the proposed DCAT Alternative 2?

i. If yes, please file the SIS study.

RESPONSE:

Load flow studies were undertaken, but dynamic switching studies were not undertaken as part of the DCAT system planning study for the evaluation of the proposed DCAT Alternative 2.

The results of the load flow studies are incorporated in BC Hydro’s System Planning Report (Appendix B of Exhibit B-1).


Page 1 of 1


Exhibit: B-30




4.3.b Please describe how the proposed Dawson Creek Area Transmission System voltage on the 138 kV bus at the 138/25 kV Dawson Creek substation responds when the 102 MW’s of BMW generation is instantly removed from the local system and the generation source swings to GMS?

RESPONSE:

The steady state voltage performance criteria are met when 102 MW of BMW generation is removed from the local system.

Voltage performance criteria can be found in section 4.3.1 of Appendix B – System Planning Report of Exhibit B-1.


Page 1 of 1


Exhibit: B-30




4.3.c Likewise, please describe the impact when 102 MWs of wind power are added.

RESPONSE:

Bear Mountain Wind operating at 102 MW results in acceptable system performance.


Page 1 of 1


Exhibit: B-30




4.3.d If operation of the Bear Mountain Wind farm causes BC Hydro’s voltage criteria to be exceeded, shouldn’t BC Hydro allocate the entire cost of the required DCAT 230 kV upgrade to either the wind generation or the system?

RESPONSE:

Bear Mountain Wind does not cause BC Hydro’s voltage criteria to be exceeded.


Page 1 of 1


Exhibit: B-30

4.0 Reference: 2.8 Proposed Tariff Revision Exhibit B-1: page 2-20 (pdf page 46)

The revision to the Electric Tariff Terms and Conditions will permit BC Hydro to recover from distribution customers that seek new service in excess of 10 MW some of the costs of transmission reinforcement made necessary, in whole or in part, by the new load.

BC Hydro response to BCUC IR1.51.3.2 Exhibit B-5

BC Hydro’s maximum contribution is based on an Extension Allowance of $200 per kW of estimated billing demand for distribution customers.

BC Hydro has proposed changes to Electric Tariff terms and Conditions for distribution customers. It is expected that some aspects of the Tariff terms and conditions that previously only applied to transmission customers will now apply to distribution customers.

4.4.a How was the 10 MW level applicable to distribution customers selected?

RESPONSE:

BC Hydro’s experience is that requests for connection to the distribution system tend to be relatively small, or they tend to be for loads of approximately 10 MW or higher. The larger loads impose costs of the transmission system that are similar to the costs that can be imposed by transmission-connecting customers. This led BC Hydro to conclude that a 10 MW cut-off was most appropriate.


Page 1 of 1


Exhibit: B-30






4.4.b Will distribution customers subject to the proposed Tariff revisions continue to pay for electricity at RS1611 or will they be switched to the RS1823 tariff?

RESPONSE:

Distribution customers will continue to pay for electricity at the appropriate distribution rate schedule, i.e., RS 1611.


Page 1 of 1


Exhibit: B-30






4.4.c Will the existing $200 per kW distribution capital contribution now be increased to account for the extra costs that distribution customers will incur to provide credit for system infrastructure?

RESPONSE:

BC Hydro has no plan to change the maximum contribution of $200 per kW of estimated demand for distribution upgrades, needed to serve general service customers.



Page 1 of 1


Exhibit: B-30






4.4.d Has an estimation of overhead costs for the administration of LOC’s for the distribution customers been made?

i. If no, does BC Hydro consider that the logistics, cost and administration burden to manage the proposed Tariff Revision not a material cost increase?

RESPONSE:

BC Hydro determines the form of security it requires, which is in this case a LOC or Guarantee. These are credit support instruments commonly allowed by BC Hydro and requiring very little administration. BC Hydro already has systems to keep in place and monitor the security provided by other distribution customers. There is negligible impact administering the additional security provided by the DCAT distribution customers.


Page 1 of 1


Exhibit: B-30






4.4.e Please outline in detail the past, current and future resources and costs (both internally and externally) to administer this new proposed LOC commercial program (Key Account Managers, lawyers, finance, regulatory resources, accountants, etc.).

i. Is this extra cost going to be added to the general overhead for all rate payers?

ii. If so, what tariffs will these ongoing costs be charged to?

RESPONSE:

Please refer to response to CSI IR 4.4.d.

BC Hydro expects few customers of the size requiring administration of this tariff provision, and therefore, the cost of administering the additional security to be provided by applicable distribution customers is not material.


Page 1 of 1


Exhibit: B-30


To resolve this inequity and to protect existing customers against the risk of over capacity if new customers choose not to use electricity for compression, BC Hydro is applying to revise its Electric Tariff to permit it to recover security for the cost of transmission reinforcements from appropriate distribution customers.

BC Hydro is concerned with risk mitigation of the cost of system expansions. Current Solutions Inc. is also concerned with the risk mitigation of system upgrade projects.

4.5.a Is BC Hydro aware that the Oil and Gas customers have already paid over $6 billion to the BC government for land leases?

RESPONSE:

It is BC Hydro’s view that a response to this question is not relevant to the DCAT Project Application proceeding.


Page 1 of 1


Exhibit: B-30




4.5.b Does BC Hydro consider BC Government energy policy (such as build before contract, BC Energy Plan, Electricity Policies, #12) when considering system upgrades?

i. If yes, how is this policy reflected in BC Hydro’s proposed tariff changes?

RESPONSE:

BC Hydro’s consideration of the B.C. Government’s energy policy is discussed in Chapter 2 of Exhibit B-1.


Page 1 of 1


Exhibit: B-30




4.5.c Has BC Hydro asked the BC Government to back stop system expansions?

i. If “No”, why has BC Hydro not approached the BC Government to address risk mitigation concerns?

ii. If “Yes”, what was the BC Governments response?

RESPONSE:

No, BC Hydro’s service is governed by its Electric Tariff.

2012 05 24 exhibit b 30 bc hydro ires 4 to bcuc and intv · 1.3 is n‐1 reliability being provided...

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