VIA March 18, 2010 BCTC F2011 CAPITAL PLAN UPDATE EXHIBIT A 4

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1 ERICA M. HAMILTON COMMISSION SECRETARY web site: VIA March 18, 2010 SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C. CANADA V6Z 2N3 TELEPHONE: (604) BC TOLL FREE: FACSIMILE: (604) Log No BCTC F2011 CAPITAL PLAN UPDATE EXHIBIT A 4 Ms. Janet L. Fraser Director, Regulatory Affairs BC Transmission Corporation Suite 1100, Four Bentall Centre 1055 Dunsmuir Street Vancouver, BC V7X 1V5 Dear Ms. Fraser: Re: British Columbia Transmission Corporation Project No /Order G 9 10 F2011 Capital Plan Update Application Further to your January 8, 2010 application for approval of the F2011 Capital Plan Update, enclosed please find Commission Information Request No. 2. Consistent with Commission Order G 9 10, BCTC is to reply to this Information Request by Monday, March 29, Yours truly, /yl Enclosure cc: Registered Interveners (BCTC F2011CPU RI) for: Original signed by: Y. Lapierre Erica M. Hamilton BCTC F2011 Capital Plan Update/GenCor/A 4_IR No2 to BCTC (L)

2 BRITISH COLUMBIA UTILITIES COMMISSION Commission Information Request No. 2 Thursday, March 18, 2010 British Columbia Transmission Corporation An Application by British Columbia Transmission Corporation for Approval of a F2011 Transmission System Capital Plan Update 1.0 Reference: Dawson Creek Area Exhibit B 2, Information Request The engineering service provider is expected to manage the project costs to within ±10 percent of the approved project budget. 1.1 Confirm that the costs to be managed are the total project cost and not just the engineering service costs. 2.0 Reference: Dawson Creek Area Exhibit B 2, Information Request Please explain why BCTC does not plan to opt into the BCEA process. 2.2 When will BCTC determine whether the project will trigger a Federal environmental review? 2.3 Have any cost allowances been included for either the BCEA process or the Federal environmental review? If not, please explain why not. 3.0 Reference: Exhibit B 2, Information Request Please breakdown into further detail the items to be added in line Item #3. For greater clarity does the project include the new feeder section associated with T3 i.e.: 5 new feeder positions? 4.0 Reference: Exhibit B 2, Information Request Has BCTC tendered a price for Transformers less than 67 dba? If so, please give the percentage increase in cost above a base unit? 4.2 Please provide the anticipated reduction in MVA capacity associated with mitigation measures (b) and (c) due to reduced subsequent cooling. BCTC F2011 Capital Plan Update 1 Commission Information Request No. 2

3 5.0 Reference: Exhibit B 2, Information Request The engineering costs in line item #4 appear to be very high in relation to other projects. Please provide actual costs of the most recent comparable project completed by other than SNC. For greater clarity, item 5 is usually 2.5 to 3 times the sum of the items 1 to 3 please provide an explanation. 6.0 Reference: Exhibit B 2, Information Request Please provide a cost breakdown of the $8.2M expenditures listing specific 138kV equipment to be added similar to BCTC'S IR response and include an explanation of the engineering costs as requested in BCUC IR2 to the previous question i.e.: In addition please explain which items are included in the $1.5M transformer addition, such as, T3, protection and control, transformer pad, oil spill containment, bus work, LA's/SA's, 25CXT3, and switches. 6.3 Is 1GD3 a solenoid operated ground switch? 6.4 Why is 1GD3switch required please explain as normally portable grounds are used for grounding associated with transformer isolation. 7.0 Reference: Exhibit B 2, Information Request Please explain if the response includes BCTC's revenue requirements or just B.C. Hydro's. 8.0 Reference: Exhibit B 2, Information Request Does the project include installation of a new oil spill containment facility? Will any of the old equipment be reused from the position vacated in the late 1970's? 8.2 Has BCTC considered installing a larger transformer than 168MVA transformer given the relatively small increase in cost for say 200MVA? If not, why not? 8.3 After the new installation is complete, when is approximate time frame (based on forecasted load growth) that additional transformer capacity will be required? 9.0 Reference: Exhibit B 2, Information Request BCTC F2011 Capital Plan Update 2 Commission Information Request No. 2

4 9.1 If the existing CYP transformer were to fail, why not install the spare transformer from K1 2 in the position that was vacated in the late 1970's? 9.2 Is the pad, buswork and protection and control equipment still in situ, or has this equipment been removed as well? 9.3 Would not utilizing this position save time as the install would not be contingent on the removal of the failed unit? Please explain Reference: Dawson Creek Area Exhibit B 2, Information Request Remedial Action Scheme (RAS) at Dawson Creek and Chetwynd Substations 10.1 Please provide the improved estimate available when the definition phase is completed in April Reference: Dawson Creek Area Exhibit B 2, Information Request Remedial Action Scheme (RAS) at Dawson Creek and Chetwynd Substations 11.1 Please provide the detailed definition cost estimates for both the (Cheakamus/Ashlu Creek Generation Shedding RAS Project and the Dawson Creek and Chetwynd Substations RAS Project and provide a more detailed explanation of the cost differences Reference: Growth Capital Expenditures Exhibit B 2, Information Request Cheakamus /Ashlu Creek Generation Shedding RAS Project, Cheakamus/Ashlu Creek Generation Shedding RAS Project 12.1 The Ashlu Creek IPP was part of BC Hydro's 2003 Green Power Generation Call for Tender, under the terms of which only direct assignment facility costs were paid for by the IPP In BCTC s opinion, should Ashlu Creek IPP have contributed to the RAS project? 12.2 The Cheakamus/Ashlu Creek Generation Shedding RAS is not a direct assignment facility Please explain the term direct assignment facility and why it is a differentiating factor. BCTC F2011 Capital Plan Update 3 Commission Information Request No. 2

5 13.0 Reference: Growth Capital Expenditures Exhibit B 2, BCUC BCTC F2010 Transmission System Capital Plan (F2010 TSCP), p Cheakamus/Ashlu Creek Generation Shedding RAS project No, the Ashlu Creek IPP is not making a contribution in aid of construction toward the Cheakamus/Ashlu Creek Generation Shedding RAS project. The Ashlu Creek IPP was part of BC Hydro's 2003 Green Power Generation Call for Tender, under the terms of which only direct assignment facility costs were paid for by the IPP. (Exhibit B 2, BCUC ) 13.1 For BCTC Growth Capital Expenditures associated IPPs please complete the table below. Growth Capital Description Growth Capital Expenditure ($ millions) In Service Date IPP Project Total 13.2 For BCTC Growth Capital Expenditures associated IPP projects where only direct assignment facility costs were paid for by the IPP please complete the table below. Growth Capital Description Growth Capital Expenditure ($ millions) In Service Date Direct Assignment IPP Project Cheakamus/Ashlu Creek Generation Shedding RAS $0.65 Ashlu Creek IPP Total The 2006 Open Call for Power was grandfathered from BCTC s Standard Generator Interconnection Procedures pursuant to Commission Order G Under the grandfathered process, the proponent pays for all Direct Assignment facilities and indemnifies BCTC for network upgrades. Specific to the 2006 Open Call for Power, BC Hydro has taken over the responsibilities from the proponents in indemnifying BCTC for network upgrades. (BCTC F2010 TSCP, p. 3 38) 13.3 Provide a list of the projects where BC Hydro has taken over the responsibilities from the proponents in indemnifying BCTC for network upgrades. Please use the format of the table below. Project Name Network Upgrade Costs Indemnified by BC Hydro Total BCTC F2011 Capital Plan Update 4 Commission Information Request No. 2

6 14.0 Reference: Exhibit B 2, Information Request BCTC's response to (b) would indicate that the cost estimate of $17M (which includes related substation equipment) as indicated in IR1 response may be low please comment Can the 138kV source be supplied from the same substation providing the present 69kV supply? 14.2 Can the existing 69kV line be upgraded to 138kV on the existing right of way? If not, why not? 14.3 Please provide an order of magnitude cost estimate for the above 14.2 option and indicate if a Duty to Consult with First Nations would be triggered Reference: Exhibit B 2, Information Request The commission wishes to understand the long term plans for the Nanaimo area Does the ultimate plan for Northfield include a 230kV section? If so, please discuss the pros and cons of installing the 230 section now as opposed to a future date Would not a 230/25kV addition or conversion alleviate the requirement for the planned 138kV substation in the Nanaimo area? 15.3 As mentioned in the CVT application there is additional complexity and cost associated with an intermediate voltage (138kV). Would not the customer disruptions and distribution constraints referenced in BCTC's reply still remain regardless of the supply option chosen? 15.4 Please explain why two distinct injection/supply/substations are required and why the load cannot be supplied from a 230/25/kV facility considering two transmission rights of way are required under the present plans for 2 separate substations (138 & 230kV)? The reference to utilizing smaller 25kV switchgear (which is now widely used in Alberta) was provided as a suggested option to be weighed against the cost of additional property required for conventional outdoor switchgear. When did BCTC last investigate the option of utilizing compact 25kV switchgear as several improvements have been made during the last few years? 16.0 Reference: Exhibit B 2, Information Request If BCTC Is building a new 138/25/kV substation, how is a 230/25kV option different with respect to high cost underground feeders i.e. what are the major differences to that make this option unattractive? BCTC F2011 Capital Plan Update 5 Commission Information Request No. 2

7 16.2 Please provide an order of magnitude all in cost comparison of supplying additional Nanaimo area distribution load from the recently approved new 138kV substation verses the option supplying the same load from either a Northfield expansion or a new 230/25kV substation. The all in costs are to include all costs, but not limited to: an estimate of all First Nations anticipated expenditures (including any probable or anticipated on going IMBA funding), ROW acquisitions, underground feeders, IDC, Corporate overhead i.e. for greater clarity the bottom line for each comparison Please provide a planning one line diagram of the Nanaimo area (Qualicum to Ladysmith) substations (all transmission and substations) and indicate the peak load and available transformer capacity on each station Reference: Exhibit B 2, Information Request Please explain why this option was not considered in lieu of building a new 138/25kV and 230/138kV substations. Please explain in detail any distribution constraints Reference: 1L14 Capacity Increase Project Exhibit B 2, Information Request Definition Phase Cost 18.1 Please provide the estimated material cost of the disconnect switch Please provide and explain the other installation costs Reference: Exhibit B 2, Information Request Has Oil Spill Containment been previously installed at GMS, MAN & STW or are these completely new installations? 20.0 Reference: Exhibit B 2, Information Request Please provide actual total costs for the last 5 completed OSC projects. BCTC F2011 Capital Plan Update 6 Commission Information Request No. 2

8 21.0 Reference: Sustainment Capital Expenditures Exhibit B 2, BCUC Oil Spill Containment Program 21.1 Please update the list of PCB contaminated equipment not in use to include a total of the Order of Magnitude Replacement cost Reference: Sustainment Capital Expenditures Exhibit B 2, BCUC Oil Spill Containment Program Disposal of PCB contaminated equipment has been tracked since The cost of disposal of PCB contaminated equipment for 2009 is approximately $700, Please discuss the accounting treatment of the cost related to the disposal of PCB contaminated equipment (asset retirement obligation, O&M cost) For greater clarity what is the order of magnitude costs to dispose of all of BCTC s major equipment that is contaminated with PCB greater than Federal guidelines? 23.0 Reference: Sustainment Capital Expenditures Exhibit B 2, BCUC Oil Spill Containment Program However there are over 10,000 pieces of small equipment, instrument transformers and bushings, located in substations in which the quantity of PCBs is unknown. Some of this equipment is sealed and cannot be tested without destroying the equipment. As a result until BCTC has completed it s testing, it cannot provide a definitive response as to how many substations contain insulating oil with varying PCB concentrations How does BCTC propose to deal with equipment is sealed and cannot be tested without destroying the equipment? 23.2 When will BCTC complete its testing to determine how many substations contain insulating oil with varying PCB concentrations? 23.3 For greater clarity the question refers to major equipment, not bushings, PT s, VT s, CT s etc, so to put the question another way how many substations are PCB free? 23.4 Does BCTC have a PCB removal program to bring BCTC into compliance with Federal regulations? Please explain, along with the order of magnitude costs of the PCB removal program and the approximate time schedule? BCTC F2011 Capital Plan Update 7 Commission Information Request No. 2

9 24.0 Reference: Sustainment Capital Expenditures Exhibit B 2, BCUC Oil Spill Containment Program Oil spill containment systems installed under this program will require yearly inspections and possible repairs of oil stop valves at a cost of approximately $1000 per year for the average substation. In addition, inspection and clean up of oil water separators will be required every five years at a forecast cost of $10,000 per occurrence Using the format of the table below, provide the cost of maintaining oil spill containment by year for F2011 F2013. F2011 Costs 5 Year Oil Water Yearly Separator Cleanup Total F2011 Substation Inspection & Inspection Costs Total 25.0 Reference: Exhibit B 2, Information Request Are these oil spill containment costs included in the transformer projects listed in this application i.e. Merritt, Cypress, Dawson Creek etc? If not, why not? 26.0 Reference: Sustainment Capital Expenditures Exhibit B 2, BCUC Oil Spill Containment Program 26.1 Please explain why the Goward substation only has project design costs in F For F2010 and 2011, please explain how the contingency, overhead and indirect costs were determined Reference: Sustainment Capital Expenditures Exhibit B 2, BCUC Oil Spill Containment Program Substations that had PCB oil spills are listed below with the associated cost to remediate each spill. BCTC F2011 Capital Plan Update 8 Commission Information Request No. 2

10 27.1 Please confirm that the cost of remediating PCB oil spills is treated as an O&M cost. If not, explain why Reference: Sustainment Capital Expenditures Exhibit B 2, BCUC Oil Spill Containment Program 28.1 Please explain why PCB related oil spills increased from an average of less than two spills per year for F2007 F2009 to 11 spills in F Reference: eppm Project Exhibit B 2, Information Request , & Project Management Tool Set As BCTC continues to develop its Project Management Tool Set including the eppm Project, it will be more convenient to use earned value reporting where the data is available and the approach adds value to project management and control. As such, BCTC is using Earned Value Project Reporting for internal management of certain projects during execution, where it has been determined to be an effective management tool. BCTC has found Earned Value Project Reporting to be particularly useful in managing outsourced project managers progress towards portfolio completion. BCTC does not believe that Earned Value Project Reporting would provide improved project management of those projects compared to its existing reporting and project management practices Does BCTC believes that Earned Value Project Reporting would not provide improved project management of certain projects compared to its existing reporting and project management practices and therefore not be in the public interest? 29.2 If as BCTC believes that fixed price contracts for material and construction protects the public interest, can BCTC provide an explanation for the average overrun on its growth capital projects of 48 percent reported in its application F2010 and F2011 Transmission System Capital Plan, Information Request 2.3.1, dated 18 February 2009? Are fixed price contracts affected by project scope changes? Do fixed price contracts account for schedule slippage caused by BCTC? Does eppm handle fixed price contracts and P3 contracts and will BCTC using the software for management of these contracts? 29.3 Please provide additional information on the earned value module, the data fields available for download to external programs, and the ability to build custom reports for other external users? 29.4 Would BCTC please provide an estimate of the burden of providing Earned Value Project BCTC F2011 Capital Plan Update 9 Commission Information Request No. 2

11 Reporting for CVI and ILM as a percentage of total project cost given the eppm project is accepted? 29.5 Will BCTC provide a web portal for Commission and public access to the earned value module of eppm for custom queries? 29.6 Will BCTC be providing the Commission with Cost Management Dashboards for its project reporting? 29.7 One of the claims of eppm is: Oracle's Primavera Contractor is an affordable solution specifically built for contractors that make scheduling, reporting, and progress planning simple. As a contractor, the ability to build an effective schedule that everyone on your project can understand and use is crucial. Primavera Contractor allows you to continually communicate and provide accurate and up todate reports to the project manager as necessary throughout the project to ensure you get paid on time Does BCTC agree with this claim and will it apply eppm to fixed priced contracts? If not, please explain why not? 30.0 Reference: Review of Alternatives Exhibit B 2, BCUC and eppm Project 30.1 BCTC states that the eppm Project will have a net neutral impact on annual OMA, but the average annual cost related sustaining expenditures by year from F2006 to F2009 for BCTC s existing suite of project management tools is $379,000/year while the sustainment costs associated with the proposed eppm Project is approximately $433,000/year. Please explain the difference Please provide a breakdown of the $433,000/year sustainment costs associated with the proposed eppm Project by activity (hardware upgrades, software upgrades, other) Reference: Review of Alternatives Exhibit B 2, BCUC , pp. 3 4 eppm Project Currently project and program managers within BCTC rely on a variety of IT tools to assist them with the management of projects and programs; these include Transmission Investment Planning (TIP), an Access database, to track capital projects, BC Hydro s project management tool called InfoPM for reviewing cost collection and budgeting for Stations related capital projects, AMP Program Execution (AMP PE), a custom application for project progress tracking and reporting, Microsoft Enterprise BCTC F2011 Capital Plan Update 10 Commission Information Request No. 2

12 Projects for web publishing of Gantt charts and for localized project management, Eclipse, a portfolio management tool currently under deployment by the SPPA group to track resource commitments and customer billing and various custom spreadsheets and databases employed by individual employees to track and report on their own projects. (Exhibit B 2, BCUC , p. 3) 31.1 Please provide the gross capital cost, accumulated depreciation and net book value of the Transmission Investment Planning (TIP), AMP Program Execution (AMP PE), Microsoft Enterprise Projects and Eclipse IT tools at November Will the Transmission Investment Planning (TIP), AMP Program Execution (AMP PE), Microsoft Enterprise Projects and Eclipse IT tools be retired when eppm Project is implemented? Furthermore, the costs and complexity associated with maintaining and sustaining these various tools are unnecessarily high. Numerous BCTC personnel and consultants are involved in sustaining these applications. (Exhibit B 2, BCUC , p. 4) 31.3 Please provide the annual sustainment and license costs for the Transmission Investment Planning (TIP), AMP Program Execution (AMP PE), and Microsoft Enterprise Projects and Eclipse IT tools by year for F2009 F Reference: Review of Alternatives Exhibit B 2, BCUC , p. 11 eppm Project 5.1 Comparison of Costs and Valued Benefits ($,000) Oracle Primavera & PM (Recommended) Total capital costs $2,850 Total OMA costs during construction $120 Total OMA incremental ongoing costs P.A. $0 Total F10/11 costs $2,850 Avoided headcount increase NA Realisable headcount reduction NA Realisable direct cost reduction $1,284 Revenue increase NA Personnel efficiency improvement $270 Mitigated risk based cost NA Total monetized benefits $1,554 " 32.1 Given that there are Personnel efficiency improvement benefits, please explain why there are no avoided headcount increases? BCTC F2011 Capital Plan Update 11 Commission Information Request No. 2

13 33.0 Reference: Review of Alternatives Exhibit B 2, BCUC , p. 12 eppm Project The accuracy of this project estimate is expected to be ± 20 percent. BCTC has not negotiated a fixed price statement of work for this work with an appropriate vendor. Cost estimates were derived from several external sources Are all cost included in the estimate in Canadian dollars? If not, please provide the costs included in foreign currencies and the exchange rates used to convert the currencies to Canadian dollars Reference: eppm Project Exhibit B 2, Information Request Pilot Project 34.1 Was the cost of the pilot project ($107K) included in the definition phase accepted by Order G dated 13 July 2009? 34.2 What are the other costs incurred to date? 35.0 Reference: eppm Project Exhibit B 2, Information Request BC Hydro Info PM BCTC states it does not incur any costs for use of InfoPM and relies upon project information from BC Hydro s InfoPM to be transferred to BCTC. The other PM tools are not adaptable to deliver enterprise project management capabilities needed by the program and project managers responsible for delivering the growth and sustain portfolios. InfoPM BC Hydro s project management tool (BCTC will interface to BC Hydro s replacement PM tool as required, expenditure for this replacement is BC Hydro s responsibility). In BC Hydro s F2011 RRA, Section Three Year Operating Cost and FTE Summary, BC Hydro states the PPM tool which is replacing the InfoPM application. These tools will provide robust project portfolio management and reporting with more efficient integration of project and financial information, allowing project managers to better manage project tasks and resources Is the BCTC eppm tool the same or similar as BC Hydro s PMM tool? If so, should the Commission consider the cost advantage of only having one integrated system that both BCTC and BC Hydro can cost effectively use it to their mutual benefit? BCTC F2011 Capital Plan Update 12 Commission Information Request No. 2

14 Is BCTC opposed to this approach and, if so, please explain why this situation would be unworkable? 36.0 Reference: Review of Alternatives Exhibit B 2, BCUC eppm Project 36.1 Are there projects approved in the BCTC Transmission System Capital Pan F2010 and F2011 Decision, or previous capital plans that will be eliminated due to the eppm Project? If yes, please list the project and the cost Reference: Review of Alternatives Exhibit B 2, BCUC eppm Project BCTC is unable to answer this question directly as BCTC does not have access to the sales records of Oracle/Primavera Please confirm that BCTC is not aware of any companies in North America that have implemented the new system and technologies specifically proposed by BCTC Reference: Dawson Creek Substation Redevelopment Exhibit B 2, Information Request Capital Contributions 38.1 Do any BC Hydro applicable tariffs require capital contributions by these industrial load customers? 39.0 Reference: Exhibit B 2, Information Request Why has BC Hydro undertaken an identification and analysis of the potential for impacts to First Nations rights and title and/or treaty rights for BCTC s growth capital projects as listed if BC Hydro doesn t believe there is a duty to consult in the first place? Please explain Reference: Exhibit B 2, Information Request Reference F2011 Capital Plan Update, p12 BCUC Decision re: BCTC Application for approval of a transmission Capital Plan F2010 and F 2011, July 13, 2009 Appendix A; and BCTC s response to BCUC s IR1. BCTC F2011 Capital Plan Update 13 Commission Information Request No. 2

15 40.1 The table provided shows a Radium 12/25kV voltage conversion project. Does the project off load 60L271? If so, by how much does it off load 60L271? 40.2 Please explain if this off loading of Radium is sufficient to defer the CVT project and if so, by how long a time frame Reference: Exhibit B 2, Information Request Doesn t the Merritt Area transmission project envision some 25 km of new 138kV line right ofway in addition to expanding the substation from 69kV to 138kV? If so, does BCTC believe that the new R O W will not require a CPCN regardless of threshold cost? 42.0 Reference: Exhibit B 2, Information Request As with the BCUC IR2 to the previous IR1 BCTC response , does BCTC believe that the construction of a new 138kV substation or extension outside the fence will not require a CPCN regardless of cost? 43.0 Reference: First Nations Consultation Exhibit B 1, Chapter 1.0 F2011 Capital Update Filing, Sec. 1.7 First Nations Consultation Evidence, pp BCTC states BC Hydro s Aboriginal Relations and Negotiations (ARN) department works closely with BCTC in planning and carrying out consultation with First Nations. The detailed capital project descriptions included in this F2011 Capital Plan Update Application include an assessment of the expected First Nations consultation required under the Haida spectrum based on the impact of the project on First Nations interests, and the extent of consultation that has occurred to date Which projects applied for in the BCTC F2011 Transmission System Capital Plan Update did BC Hydro Aboriginal Relations and Negotiation (ARN) analyze for First Nations consultation requirements? For the projects that BC Hydro ARN did not review, who analyzed the First Nations requirements? 44.0 Reference: First Nations Consultation Exhibit B 1, Chapter 2.0 Growth Capital Expenditures, Sec Dawson Creek Substation Redevelopment 138 kv First Nations Considerations, p.23 and Sec L19 Reconductor Project First Nations Considerations, p.35 BCTC states The project will require the expansion of the Dawson Creek Substation on to existing BC Hydro owned property BCTC F2011 Capital Plan Update 14 Commission Information Request No. 2

16 44.1 Is the BC Hydro owned property, on which the expansion will occur, developed or within the fenced enclosure? Please provide a description of the development and an analysis of whether the development precludes the exercise of any aboriginal rights or First Nation treaty rights on the land? 45.0 Reference: First Nations Consultation Exhibit B 1, Chapter 2.0 Growth Capital Expenditures, Sec L19 Reconductor Project First Nations Considerations, p.35, and Exhibit B 2, Response to BCUC IR , 3. 60L19 Reconductor Project, and Exhibit B 2, Response to BCUC IR BCTC states This work involves the purchase of land for the expansion of right of way, the stringing of a new conductor, ground re contouring and clearing of the new right of way to allow for the safety requirements of the new conductor. BCTC has determined that the right of way acquisition required for this project involves private property only. All work for this project will therefore be performed within the BC Hydro owned existing and expanded right of way. BCTC states The existing right of way has been cleared of trees, has had poles installed, and has been subject to routine maintenance and vegetation management. These facts support BC Hydro s assessment that there will be no new impacts on aboriginal rights or title resulting from the project. BCTC states Given that BC Hydro does not believe that the activities associated with the following projects [60L19 Reconductor Project is listed] have the potential to infringe upon aboriginal rights and title or First Nations treaty rights 45.1 Of the activities listed (purchase of land, stringing of a new conductor, ground re contouring and clearing of the new right of way), what specific activities will occur on each of the types of land listed: new right of way acquired from private owners; BC Hydro owned existing right of way; and BC Hydro owned expanded right of way? 45.2 Does the 60L19 Reconductor Project preclude the exercise of any aboriginal rights on the rightof way? Please explain why or why not Did the original installation of 60L19 impact or infringe on the exercise of aboriginal rights? Could the 60L19 Reconductor Project be viewed as a perpetuation of an existing infringement on aboriginal rights? Please discuss Please explain how the activities associated with the 60L19 Reconductor Project have no potential to infringe upon aboriginal rights and title or First Nations treaty rights. BCTC F2011 Capital Plan Update 15 Commission Information Request No. 2

17 46.0 Reference: First Nations Consultation Exhibit B 2, Response to BCUC IR BCTC states The issue of whether or not land owned by BC Hydro is Crown Land is not directly relevant to BC Hydro s assessment of its consultation obligations. The fact that the projects are taking place within the fenced enclosure on BC Hydro property is an important factual consideration that was taken into account when determining whether or not consultation was required in the circumstances. The lands on which the Dawson Creek and Cypress substations are located have been owned by BC Hydro and used for public utility purposes (substations) for many years. The lands are fenced and the nature of the development has precluded any exercise of any aboriginal rights or First Nation treaty rights on the land In BCTC s analysis of First Nations consultation requirements, if each of the following projects took place on Crown land that is fenced and developed to the extent that precludes any exercise of any aboriginal rights or First Nations treaty rights, warrant no First Nations consultation? Please provide reasoning, including relevant case law, to justify the answer. Dawson Creek Substation Redevelopment 25 kv Dawson Creek Transformer Addition Dawson Creek Substation Redevelopment 138 kv Dawson Creek Chetwynd Area Remedial Action Scheme Cypress Substation Transformer Addition Oil Spill Containment Program 47.0 Reference: First Nations Consultation Exhibit B 2, Response to BCUC IR BCTC states the lands are fenced and the nature of the development has precluded any exercise of any First Nation treaty rights to hunt, fish or trap on the land Other than hunting, fishing or trapping, what other First Nation treaty rights or other aboriginal rights have been or could be exercised on the land? BCTC F2011 Capital Plan Update 16 Commission Information Request No. 2