2009 08 05 BC Hydro 2009 Mica Gas Insulated Switchgear ... Hydr… · Mica Gas Insulated Switchgear...

BChydro mFOR GENE 100\JS

Joanna SofieldChief Regulatory OfficerPhone: (604) 623-4046Fax: (604) 623-4407bchyd [email protected]

August5,2009

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

Dear Ms. Hamilton:

RE: British Columbia Utilities Commission (BCUC)British Columbia Hydro and Power Authority (BC Hydro)Mica Gas Insulated Switchgear Project

BC Hydro encloses its application filed pursuant to section 44.2(1 )(b) of the UtilitiesCommission Act, seeking a BCUC Order accepting that the expenditures associated with theMica Gas Insulated Switchgear Project are in the public interest.

BC Hydro proposes to hold a workshop on August 20, 2009 as the first step of the regulatoryreview process.

All communications with respect to the application should be directed to:

Ms. Joanna SofieldChief Regulatory OfficerBC Hydro333 Dunsmuir Street, 17th FloorVancouver, BC V6B 5R3Telephone No. (604) 623-4046Fax No. (604) 623-4407

E-Mail: [email protected]

and to:

Ms. Nicole PriorLegal CounselBC Hydro333 Dunsmuir Street, 17th FloorVancouver, BC V6B 5R3Telephone No. (604) 623-3692Fax No. (604) 623-3606

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

B-1

markhuds

BCH_Mica Gas Insulated Switchgear Project

August5,2009Ms. Erica M. HamiltonCommission SecretaryBritish Columbia Utilities CommissionMica Gas Insulated Switchgear Project

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

Yours sincerely,

~£///Joanna SofieldChief Regulatory Officer

Enclosure (1)

BChydro

Page2 of2

c. BCUC Project No. 3698500 (BCHydro F2009/F2010 Revenue Requirements Application)Registered Intervenor Distribution List.

First Nations and Tribal Councils identified for consultation (per Table 5-1 of the application)

Mica Gas Insulated Switchgear Project

i

Table of Contents

Chapter 1. INTRODUCTION 1.1 Introduction .......................................................................................................................1-1 1.2 B.C. Government Energy Policy........................................................................................1-1 1.3 Revenue Requirement and Service Plan Cost Estimates .................................................1-1 1.4 Project Highlights ..............................................................................................................1-2

1.4.1 Mica Generating Station Description.......................................................................1-2 1.4.2 Project Description ..................................................................................................1-2 1.4.3 Project Schedule .....................................................................................................1-3

1.5 Project Justification ...........................................................................................................1-3 1.5.1 Need........................................................................................................................1-4 1.5.2 Project Benefits .......................................................................................................1-4 1.5.3 Cost-Effectiveness ..................................................................................................1-4

1.6 Public and First Nations Consultation ...............................................................................1-5 1.7 Order Sought.....................................................................................................................1-5 1.8 Proposed Review and Application Process.......................................................................1-6 1.9 Structure of the Application ...............................................................................................1-6

Chapter 2. APPLICANT 2.1 Name, Address and Nature of Business ...........................................................................2-1

2.2 Financial and Technical Capacity of the Applicant..................................................2-1 2.2.1 Financial Capacity ...................................................................................................2-1 2.2.2 Technical Capacity ..................................................................................................2-1

2.3 Project Delivery Governance.............................................................................................2-2

Chapter 3. PROJECT DESCRIPTION AND IMPACTS 3.1 Project Description ............................................................................................................3-1

3.1.1 Description of Mica..................................................................................................3-1 3.1.2 Project Description ..................................................................................................3-4 3.1.3 Project Components................................................................................................3-9

3.2 Project Schedule .............................................................................................................3-10 3.3 Project Costs ...................................................................................................................3-13

3.3.1 Construction Costs ................................................................................................3-13 3.3.1.1 Contingency/Risk Allowance: ........................................................................3-14 3.3.1.2 Mica Units 5 and 6 Equipment.......................................................................3-16

3.3.2 Operating, Maintenance and Outage Costs ..........................................................3-16 3.3.3 Planned Outage Costs and Risks .........................................................................3-16 3.3.4 Non-BC Hydro Project Related Capital Costs .......................................................3-17

3.4 Project Life Cycle ............................................................................................................3-17 3.5 Construction Market Impacts...........................................................................................3-18


ii

3.6 Social and Environmental Impacts ..................................................................................3-18 3.6.1 Environmental Assessment Approvals..................................................................3-18 3.6.2 Federal Permits, Approvals and Authorizations ....................................................3-19 3.6.3 Provincial Permits, Approvals and Authorizations.................................................3-19 3.6.4 Municipal Bylaws...................................................................................................3-19 3.6.5 SF6 Management ..................................................................................................3-20 3.6.6 Columbia River Water Use Plan............................................................................3-20

3.7 Analysis of Estimated Rate Impact..................................................................................3-21

Chapter 4. PROJECT JUSTIFICATION 4.1 Introduction .......................................................................................................................4-1 4.2 Need for the Project ..........................................................................................................4-1

4.2.1 Reliability and Outage Risk .....................................................................................4-2 4.2.2 Life Cycle Asset Management.................................................................................4-3 4.2.3 GIS Condition Assessment .....................................................................................4-5

4.2.3.1 Independent Condition Assessment Reports ..................................................4-5 4.2.3.2 BC Hydro Condition Assessment Conclusions................................................4-7 4.2.3.3 Condition Assessment Summary ..................................................................4-13

4.3 Identification of Project Benefits ......................................................................................4-13 4.3.1.1 Disconnect Switches .....................................................................................4-14 4.3.1.2 Maintenance Access .....................................................................................4-14

4.3.2 Environmental Benefits .........................................................................................4-17 4.3.3 Benefit to Mica Units 5 and 6 ................................................................................4-18

4.4 Architecture Evaluation and Selection.............................................................................4-18 4.4.1 Problem Scope and Architecture Options .............................................................4-19 4.4.2 Architecture Conclusions.......................................................................................4-21 4.4.3 Holm, Hampton and Heil Recommended Architectures........................................4-22

4.5 Timing and Sequencing of GIS Replacement .................................................................4-23 4.5.1 Timing of GIS Replacement ..................................................................................4-23 4.5.2 Planned Outage Requirements for Alternatives ....................................................4-25 4.5.3 Sensitivity Analysis for Mica Units 5 and 6 ISDs ...................................................4-29 4.5.4 Recommended Project Scope...............................................................................4-33

Chapter 5. PUBLIC AND FIRST NATIONS CONSULTATION 5.1 Introduction .......................................................................................................................5-2 5.2 General Consultation.........................................................................................................5-2

5.2.1 Environmental Assessment.....................................................................................5-2 5.2.2 Core Committee ......................................................................................................5-3 5.2.3 Future Public Consultation ......................................................................................5-4

5.3 First Nations Consultation .................................................................................................5-4 5.3.1 Identification of Interested First Nations ..................................................................5-5 5.3.2 Expected First Nation Impacts ................................................................................5-6


iii

5.3.3 First Nation Consultation Activities..........................................................................5-7 5.3.4 Presentation of Project at Core Committee Meeting ...............................................5-8 5.3.5 Project Notification Letter from BC Hydro ...............................................................5-8 5.3.6 Project BCEAO Amendment ...................................................................................5-9 5.3.7 Future First Nation Consultation Plan ...................................................................5-10 5.3.8 Adequacy of First Nations Consultation ................................................................5-10

Chapter 6. PROJECT RISKS AND RISK MANAGEMENT 6.1 Introduction .......................................................................................................................6-1 6.2 Definition Phase Risks ......................................................................................................6-1

6.2.1 Investment at Risk...................................................................................................6-1 6.2.2 Environmental Regulatory .......................................................................................6-2 6.2.3 First Nations ............................................................................................................6-2

6.3 Implementation Phase Risks.............................................................................................6-3 6.3.1 Safety Risks ............................................................................................................6-3 6.3.2 Security Risk ...........................................................................................................6-5 6.3.3 Capital Cost Risk.....................................................................................................6-5 6.3.4 Schedule Risk During Construction.........................................................................6-6 6.3.5 Risk of Labour Unrest during Construction .............................................................6-7 6.3.6 Congestion in the Mica Powerhouse during Construction.......................................6-8 6.3.7 Environmental Risk during Construction .................................................................6-8 6.3.8 SF6 Risk During Construction..................................................................................6-9 6.3.9 Contractor Credit/Counterparty Default...................................................................6-9 6.3.10 Commissioning Risk..............................................................................................6-10

6.4 Operations Risks.............................................................................................................6-10 6.4.1 Failure and Outage Risk........................................................................................6-10 6.4.2 Environmental Risk ...............................................................................................6-10 6.4.3 Operating and Maintenance Costs........................................................................6-11

6.5 Risk Summary.................................................................................................................6-11


iv

List of Figures

Chapter 1. INTRODUCTION Figure 1-1 Project Schematic...............................................................................................1-3

Chapter 2. APPLICANT Figure 2-1 EARG Functional Organization Chart.................................................................2-3 Figure 2-2 Project Organization Structure ...........................................................................2-4

Chapter 3. PROJECT DESCRIPTION AND IMPACTS Figure 3-1 Columbia/Kootenay Area Generation.................................................................3-2 Figure 3-2 Mica Underground Powerhouse .........................................................................3-3 Figure 3-3 Mica Dam Showing Planned Switchgear Building Extension .............................3-3 Figure 3-4 GIS in Transformer Gallery for Single Generating Unit ......................................3-5 Figure 3-5 GIS Bus in Lead Shaft ........................................................................................3-6 Figure 3-6 Cut-away of GIS Bus ..........................................................................................3-6 Figure 3-7 GIS Conducts High Voltages in the Powerhouse ...............................................3-7 Figure 3-8 Original Design of Mica GS included Three Lead Shafts Running to

Switchgear Building ............................................................................................3-8 Figure 3-9 Project Schedule ..............................................................................................3-11 Figure 3-10 Annual Rate Impact ..........................................................................................3-22

Chapter 4. PROJECT JUSTIFICATION

Figure 4-1 Bus Cone Insulator ...........................................................................................4-10 Figure 4-2 Condition Assessment Summary .....................................................................4-13 Figure 4-3 Repair of Surge Arrestor under Existing GIS Layout........................................4-15 Figure 4-4 Height of Existing GIS ......................................................................................4-16 Figure 4-5 Improved GIS Layout........................................................................................4-17 Figure 4-6 Mica GIS Ultimate Layout.................................................................................4-22 Figure 4-7 Reliability Realization from Staging Lead Shaft 3 First.....................................4-27


v

List of Tables

Chapter 3. PROJECT DESCRIPTION AND IMPACTS Table 3-1 Project Stages ..................................................................................................3-12 Table 3-2 Project Cost ......................................................................................................3-14 Table 3-3 Total Contingencies and Reserves...................................................................3-15

Chapter 4. PROJECT JUSTIFICATION Table 4-1 Analysis of GIS by Component.........................................................................4-11 Table 4-2 PV of Replacement Alternatives.......................................................................4-24 Table 4-3 Replacement of Lead Shaft 1 and 2 with or without Lead Shaft 3 in Place......4-28 Table 4-4 Sensitivity Analysis for Meeting Alternative Mica Units 5 and 6 ISD ................4-32

Chapter 5. PUBLIC AND FIRST NATION CONSULTATION Table 5-1 First Nations and Tribal Councils Identified for Consultation..............................5-6

Chapter 6. PROJECT RISKS AND RISK MANAGEMENT

Table 6-1 Mica Project Risks Summary............................................................................6-11


vi

List of Appendices

Appendix A Glossary and Key Assumptions

Appendix B Draft Order

Appendix C Project Schedule

Appendix D Project Lifecycle and Project Cost Estimating

Appendix E Condition Assessment Reports

Appendix F Mica Gas Insulated Switchgear Capital Expenditures

Appendix G Most Severe Single Contingency

Appendix H Lead Shaft Requirements for Mica with Four to Six Units

Appendix I GIS Replacement Alternative Assumptions

Appendix J First Nations Consultation Record

Appendix K B.C. Environmental Assessment Act Order


Chapter

1

Introduction


1-i

Table of Contents

1.1 Introduction.................................................................................................................1-1

1.2 B.C. Government Energy Policy .................................................................................1-1

1.3 Revenue Requirement and Service Plan Cost Estimates ..........................................1-1

1.4 Project Highlights........................................................................................................1-2

1.4.1 Mica Generating Station Description ..............................................................1-2

1.4.2 Project Description..........................................................................................1-2

1.4.3 Project Schedule.............................................................................................1-3

1.5 Project Justification.....................................................................................................1-3

1.5.1 Need ...............................................................................................................1-4

1.5.2 Project Benefits...............................................................................................1-4

1.5.3 Cost-Effectiveness ..........................................................................................1-4

1.6 Public and First Nations Consultation.........................................................................1-5

1.7 Order Sought ..............................................................................................................1-5

1.8 Proposed Review and Application Process................................................................1-6

1.9 Structure of the Application.........................................................................................1-6 List of Figures

Figure 1-1 Project Schematic ........................................................................................1-3

Chapter 1 - Introduction


1-1

1.1 Introduction 1

This application (the Application), filed pursuant to section 44.2(1)(b) of the Utilities 2

Commission Act (UCA), contains a schedule of capital expenditures that British Columbia 3

Hydro and Power Authority (BC Hydro) anticipates making for the Mica Dam and 4

Generating Station (Mica) 500 kilovolt (kV) Gas Insulated Switchgear (GIS) Project (the 5

Project). BC Hydro seeks, per section 44.2(3)(a) of the UCA, that the British Columbia 6

Utilities Commission (BCUC) accepts that the expenditures referred to in the schedule of 7

capital expenditures are in the public interest. 8

In considering whether the expenditures are in the public interest, according to 9

section 44.2(5) of the UCA the BCUC must consider: the Government’s energy objectives; 10

BC Hydro’s most recent long term resource plan; whether the expenditure schedule is 11

consistent with section 64.01 and 64.02 of the UCA in respect of electricity self-sufficiency 12

and clean and renewable resources; and the interests of present and future ratepayers. 13

1.2 B.C. Government Energy Policy 14

The Project is consistent with Policy Action Item #17 of the British Columbia (B.C.) 15

Government’s updated energy policy, “The BC Energy Plan: A Vision for Clean Energy 16

Leadership”, (2007 Energy Plan) regarding investment in upgrading and maintaining the 17

heritage facilities and transmission lines to retain the ongoing competitive advantage these 18

assets provide to the Province. 19

1.3 Revenue Requirement and Service Plan Cost Estimates 20

BC Hydro’s F2009 and F2010 Revenue Requirements Application (F09/F10 RRA) Capital 21

Plan (Exhibit B-1) and the 2009/2010 to 2011/2012 Service Plan estimated that the cost for 22

the replacement of the Mica 500 kV GIS would fall within a range of cost of 23

$120 million - $300 million (Exhibit B-1, Appendix J page 36 of 120). Since the time of these 24

previous estimates, the scope of the Project has been finalized. The F09/F10 RRA stated 25

“we are also considering replacing the transformers at the same time.” Further investigation 26

showed that the unit transformers are in fair condition and they were, therefore, removed 27



1-2

from the Project’s scope of work. The Project Expected Cost1 of $180.6 million and 1

Authorized Cost of $200.2 million are in the project cost estimate range provided in 2

BC Hydro’s F09/F10 RRA and the 2009/2010 to 2011/2012 Service Plan. 3

1.4 Project Highlights 4

1.4.1 Mica Generating Station Description 5

Mica is located on the Columbia River approximately 130 kilometres (km) upstream from the 6

Revelstoke Dam and Generating Station (Revelstoke), and 135 km upstream of the City of 7

Revelstoke. Mica accounts for roughly 17 per cent of BC Hydro's current installed capacity. 8

The large storage capacity at Mica Dam, the Kinbasket reservoir, enables BC Hydro to 9

serve domestic load during high demand periods and store water in light load periods or to 10

maximize export earnings for ratepayers by generating at peak value periods and storing 11

water at low value periods. 12

The Mica powerhouse contains the four generating units, Mica Units 1 through 4 and is 13

located underground, 200 meters (m) below the dam crest. Electricity is generated by 14

Mica Units 1 through 4 at 16 kV and transformed to 500 kV in single-phase transformers 15

located in the transformer chamber at Mica. The 500 kV electricity then flows through the 16

GIS which runs through lead shafts2 to the switchgear building located at the dam crest 17

200 m above. From the switchgear building, the 500 kV electricity flows into the transmission 18

system operated by British Columbia Transmission Corporation (BCTC). 19

Refer to Chapter 3 for further details on Mica and GIS. 20

1.4.2 Project Description 21

With the exception of the recently replaced circuit breakers in the switchgear building, the 22

Project will replace, with modern GIS technology, all the existing GIS at Mica. In addition, 23

the Project includes the installation of GIS to lead shaft 3. To accommodate the GIS in lead 24

shaft 3, the switchgear building will be extended as part of the Project because lead shaft 3 25

1 Refer to Appendix D-2 for an explanation of Expected and Authorized Costs. 2 At Mica the three lead shafts are tunnels of approximately 3 m in diameter that lead from the transformer

chamber through bedrock to the switch gear building.



1-3

currently terminates outside of the switchgear building. Figure 1-1 is a schematic showing 1

the Mica GIS equipment before and after the Project. 2

Figure 1-1 Project Schematic 3

Not in the scope of this project

Style Legend

Not In Scope

Replace

Remain

Lead

Sha

ft

Lead

Sha

ft

G1

T1

500 kV16 kV

Pow

erho

use

Sw

itchg

ear B

uild

ing

Circuit Breaker

Disconnect Switch

Transformer

Generator

Surge Arrester

Transmission Line

Reactor

5L71 5L72

G2

T2

G3

T3

G4

T4

G5

T5

G6

T6Le

ad S

haft

New

1.4.3 Project Schedule 4

BC Hydro is of the view that it is in the interest of ratepayers to proceed with the Project as 5

soon as possible, and has framed the Application around a June 2013 Project completion 6

date. Refer to Chapter 3 and Appendix C for more details on the Project schedule. 7

1.5 Project Justification 8

The existing GIS is more than 30 years old and poses the risk of forced outages to 9

BC Hydro. The purpose of the Project is to mitigate the risk of forced outages. 10



1-4

1.5.1 Need 1

The GIS at Mica was the first 500 kV GIS installed in North America. BC Hydro understands 2

that Mica may have the last GIS equipment of this vintage in North America. As a result, 3

there are no spare parts for surge arrestors, spare parts for disconnect switches have limited 4

availability and BC Hydro has only about 30 m of spare bus. 5

Three independent condition assessments were carried out on the GIS (attached in 6

Appendix E). The condition assessments were consistent in that they recommended that 7

BC Hydro address the reliability issues of the GIS. One of the risk assessments concluded 8

that the risk of simultaneous multiple outages of Mica Units 1 through 4 as a result of GIS 9

failure could be as high as one in ten years. 10

1.5.2 Project Benefits 11

The purpose of the Project is to maintain the reliability of Mica; however, the Project 12

provides additional safety and environmental benefits. Refer to Chapter 4 for more details 13

on the Project benefits. 14

1.5.3 Cost-Effectiveness 15

The replacement of the GIS at Mica is cost-effective when compared to deferring 16

replacement or replacing using different configurations. The Project is attractive because it: 17

maintains the reliability of the Mica; 18

reduces sulphur hexafluoride3 (SF6) leakage; 19

reduces safety risks to workers; and 20

allows BC Hydro to achieve the earliest in-service date (ISD) for Mica Units 5 and 6 of 21

F2014 and F2016 as per BC Hydro’s 2008 Long-Term Acquisition Plan Application 22

(2008 LTAP) contingency resource plans (CRPs). 23

3 GIS contains SF6, an extremely good electrical insulator; however SF6 is also a potent greenhouse gas

(GHG).



1-5

For further details on the Project justification refer to Chapter 4. 1

1.6 Public and First Nations Consultation 2

BC Hydro has undertaken consultation with First Nations and public stakeholders to identify 3

issues specific to the Project. BC Hydro expects the Project will have minimal, if any adverse 4

impacts since it is within the Mica generating station or on previously disturbed ground and 5

has no impact on the Kinbasket or Revelstoke reservoirs. Taking into consideration the 6

factors listed in section 5.3.8, BC Hydro is of the view that the consultation conducted for the 7

Project is adequate. BC Hydro will continue to update First Nations and public stakeholders 8

during the implementation phase of the Project. 9

Details of the consultation that has taken place are in Chapter 5 while a full consultation 10

record with First Nations is provided in Appendix J. 11

1.7 Order Sought 12

BC Hydro is applying for a BCUC order that accepts that this expenditure schedule to 13

complete the Project is in the public interest according to subsection 44.2(3)(a) of the UCA. 14

BC Hydro is targeting a completion date of June 2013 with a Project Expected Cost of 15

$180.6 million and a Project Authorized Cost of $200.2 million. 16

BC Hydro intends to file with the BCUC quarterly progress reports on the Project schedule, 17

costs and any variances or difficulties that the Project may be encountering. The form and 18

content of the quarterly progress reports will be consistent with other BC Hydro capital 19

project quarterly reports filed with the BCUC. Within six months of the end or substantial 20

completion of the Project BC Hydro will file a final report. The final report will include a 21

complete breakdown of the final costs of the Project, a comparison of these costs to the 22

Project Expected Cost estimate and provide an explanation of all material cost variances. 23

As directed per BCUC Letter No. L-78-06, BC Hydro has included in Appendix B of the 24

Application a draft final order. 25



1-6

1.8 Proposed Review and Application Process 1

BC Hydro proposes a written hearing process consisting of: 2

Application Filed 3

Application filed on Wednesday, August 5, 2009. 4

Workshop 5

A BC Hydro workshop on the Application on Thursday, August 20, 2009. 6

Information Request (IRs) 7

BCUC IRs issued by Tuesday, August 25, 2009; 8

BC Hydro responds to BCUC IRs on Tuesday, September 15, 2009. 9

BCUC Round 2 and Intervenors IRs issued by Tuesday, September 22, 2009; 10

BC Hydro responds to BCUC and Intervenor IRs on Tuesday, October 13, 2009. 11

Written Submissions/Reply 12

BC Hydro final written submission by Tuesday, October 20, 2009; 13

Intervenors final written submissions by Tuesday, October 27, 2009; and 14

BC Hydro written reply by Tuesday, November 3, 2009. 15

To meet the June 2013 ISD, BC Hydro is filing the Application with the expectation that the 16

proposed process will support a BCUC order being granted by no later than the end of 17

December 2009. 18

1.9 Structure of the Application 19

The Application consists of six chapters. It has been structured to comply with the BCUC’s 20

March 2004 CPCN Application Guidelines (Letter No. L-18-04). 21



1-7

Chapter 2 contains information on BC Hydro including the Project team. 1

Chapter 3 contains a detailed description of the Project, including costs and schedule and 2

rate impact. 3

Chapter 4 details the justification, including the need for the Project, the benefits, and 4

alternatives. 5

Chapter 5 details the First Nations, public and government agency consultations conducted 6

by BC Hydro. 7

Chapter 6 identifies the various risks to the Project. 8

Appendix A-1 is a glossary of terms and acronyms and Appendix A-2 provides key financial 9

assumptions used in this Application. 10

Appendix B contains a draft of the requested final order for the Project. 11

Appendix C sets out the schedule for the completion of the Project. 12

Appendix D-1 sets out BC Hydro’s standard project life cycle for large generation projects 13

and Appendix D-2 provides a summary of BC Hydro’s project cost estimating practices for 14

large generation projects. 15

Appendix E contains the three condition assessment reports of the Mica GIS. 16

Appendix F provides the Project capital expenditures. 17

Appendix G is a letter from BCTC related to its most severe single contingency (MSSC) 18

limits. 19

Appendix H is an explanation of the lead shaft requirements for Mica. 20

Appendix I is a summary of the assumptions for GIS replacement alternatives and options. 21



1-8

Appendix J-1 is BC Hydro’s First Nations consultation log for the Project, Appendix J-2 1

contains the notification letter. Appendix J-3 contains BC Hydro’s core committee 2

presentation material for the project. 3

Appendix K-1 contains a letter to the British Columbia Environmental Assessment Office 4

(BCEAO) requesting the removal of the switchgear building extension from the British 5

Columbia Environmental Assessment Certificate (BCEAC) review. Appendix K-2 is a copy 6

of the notice from the BCEAO seeking First Nations comments regarding BC Hydro’s 7

request and Appendix K-3 is the BCEAO Order removing the Switchgear Building extension 8

from the BCEAC Review. 9


Chapter

2

Applicant


2-i

Table of Contents

2.1 Name, Address and Nature of Business.....................................................................2-1

2.2 Financial and Technical Capacity of the Applicant .....................................................2-1

2.2.1 Financial Capacity...........................................................................................2-1

2.2.2 Technical Capacity..........................................................................................2-1

2.3 Project Delivery Governance......................................................................................2-2 List of Figures

Figure 2-1 EARG Functional Organization Chart ..........................................................2-3

Figure 2-2 Project Organization Structure.....................................................................2-4

Chapter 2 Applicant


2-1

2.1 Name, Address and Nature of Business 1

BC Hydro is a Crown Corporation established in 1962 under the Hydro and Power Authority 2

Act. BC Hydro is mandated to generate, distribute and sell electricity; upgrade its power 3

sites; and purchase power from, or sell power to, a firm or person. BC Hydro is the largest 4

electric utility in B.C., serving over 94 per cent of the provincial population. 5

BC Hydro’s head office is located at 333 Dunsmuir Street, Vancouver, B.C. 6

2.2 Financial and Technical Capacity of the Applicant 7

2.2.1 Financial Capacity 8

BC Hydro is an agent of Her Majesty the Queen in right of the Province of B.C. The 9

B.C. Minister of Finance is the fiscal agent of BC Hydro. BC Hydro has constructed some of 10

the largest projects in the Province undertaken by a single corporation and has the financial 11

capacity to undertake the Project and other large projects by means of: borrowing 12

guaranteed by the Province, borrowing directly from the Province, and by funds generated 13

internally from the operation of its business. 14

Moody’s Investors Service and Standard & Poor’s Corporation, two major financial rating 15

agencies in the United States of America (U.S.), have rated BC Hydro bonds as Aaa and 16

AAA respectively. The rating from the Dominion Bond Rating Service in Canada is at 17

AA High. 18

2.2.2 Technical Capacity 19

BC Hydro has been responsible for the planning, design and construction of generation and 20

distribution facilities since 1962. BC Hydro was also responsible for these functions with 21

respect to the transmission system until 2003. In 2003, BCTC was formed. Under the 22

Transmission Corporation Act and a number of designated agreements between BC Hydro 23

and BCTC, BCTC currently has the responsibility to operate, plan and manage the 24

BC Hydro-owned transmission system. BC Hydro currently owns and operates 25

30 grid-connected hydroelectric generating stations within the Province. The existing GIS at 26

Chapter 2 Applicant


2-2

Mica was put into service in 1976. The GIS in the switchgear building is under BCTC 1

management but is in the process of being transferred back to BC Hydro. 2

BC Hydro has a proven track record in implementing capital projects at BC Hydro’s 3

generation facilities. In recent years BC Hydro designed, constructed and commissioned 4

into service the Seven Mile Generating Station (Seven Mile GS) gas insulated switchgear 5

replacement project and is in the process of adding gas insulated switchgear to support the 6

addition of the fifth unit at Revelstoke. The contractor, Mitsubishi Electric Power Products 7

Inc. (MEPPI), which supplied and installed the gas insulated switchgear for both the 8

Revelstoke and Seven Mile GS gas insulated switchgear projects, was also awarded the 9

design, supply and install contract for the Project. These projects have provided BC Hydro 10

and MEPPI with experience and technical knowledge that will benefit the Project. 11

The Seven Mile GS gas insulated switchgear replacement project was completed on time 12

and on budget. The addition of gas insulated switchgear to support Revelstoke Unit 5 is 13

currently projected to be completed on time and on budget. 14

Along with MEPPI and BC Hydro staff working on the Project, BC Hydro has retained the 15

services of specialized consultants to advise on various aspects of the Project. For example, 16

BC Hydro has retained SNC-Lavalin Group Inc. to design the switchgear building extension 17

and MWH Canada Inc for project management advice. BC Hydro commissioned 18

independent condition assessment reports of the GIS (refer to Appendix E) by Mr. Bjorn 19

Holm, Dr. Brian Hampton, and Rohe International Inc. 20

2.3 Project Delivery Governance 21

Figure 2-1 is a functional organization chart of the Engineering, Aboriginal Relations and 22

Generation (EARG) business group that is accountable for the delivery of the Project. 23

Chapter 2 Applicant


2-3

Figure 2-1 EARG Functional Organization Chart 1

Chris O’Riley, a senior vice-president, leads the EARG line of business. David Lebeter, who 2

reports directly to Chris O’Riley, leads the EARG generation operations group. This group is 3

responsible for operating and maintaining the plants in the fleet, as well as asset and capital 4

planning and for initiating EARG projects. The generation operations group also directly 5

delivers some of the smaller projects in BC Hydro’s capital plan. Diane McSherry, another 6

direct report to Chris O’Riley, leads EARG generation project delivery group. This group is 7

accountable for delivery of the majority of the EARG projects in BC Hydro’s capital plan. 8

Other functional groups in EARG such as Engineering, Aboriginal Relations and 9

Negotiations (ARN), and Safety and Technical Training provide personnel to staff projects; 10

those individuals are accountable to the project manager for the purposes of the project. 11

The Project organization chart is provided as Figure 2-1. 12

Safety & TechnicalTraining

Diana Cochran

Finance

Gurj Parmar

Senior Vice-President- Chris O’Riley

Generations Operations

David Lebeter

Generation ProjectDelivery

Diane McSherry

Aboriginal Relations & Negotiations

Lyle Viereck

Human Resources

Terry Schumaker

Engineering

Roy Grout

Chapter 2 Applicant


2-4

Figure 2-2 Project Organization Structure 1

Project InitiatorDavid Lebeter

Project ManagerOwen Williams

Construction Mgr.Bill Hanson

Aboriginal RelationsRyan McFadden

EnvironmentalDavid Wilson

Project Sponsor Chris O’Riley

Communications Jeanette Hoft

Estimating & SchedulingKelman Ng

Reg. Env. Stakeholder

CommunicationsDeb Bisson

Contract Mgr.Clement Terragni

Project Engineer/Design Lead

Damien Clapa

Commercial Mgr.Alan Tan

Director, Generation Project DeliveryDiane McSherry

Project DirectorKen McKenzie

BC Hydro EARG projects are led by a project manager who is accountable to a project 2

initiator and to a portfolio project director. The project manager leads the project team to 3

complete the objectives of the project and is accountable to the project initiator for the 4

definition (statement of objectives, original and revisions) and justification (original and 5

revised business case) of the project. The project initiator defines the problem or opportunity 6

that requires a project to be initiated. The project manager, representing the project team, 7

proposes a set of objectives (statement of objectives) to address the problem or opportunity 8

and a plan to achieve those objectives. Approval of the proposed objectives by the project 9

initiator defines the project to be delivered. The same concept applies to the business case. 10

The project manager is accountable to the portfolio project director for delivery of the project 11

in accordance with the approved definition of the project. In other words, the project 12

manager is accountable for determining how the project will be delivered, including delivery 13

models, procurement strategies, obtaining resources, obtaining all permits and regulatory 14

approvals, putting contracts in place, and managing to the plan to achieve the agreed 15

objectives. 16

Chapter 2 Applicant


2-5

Chris O’Riley, senior vice-president of EARG is the project sponsor (Project Sponsor) of 1

this Project and is responsible for supporting the success of the Project by acting as liaison 2

with BC Hydro’s executive team and approving key decisions. David Lebeter, the Director of 3

Generation Operations, is project initiator (Project Initiator) and is accountable to the 4

Project Sponsor for the definition and the justification of the Project, while Diane McSherry, 5

the Director of Generation Project Delivery, is accountable to the Project Sponsor for 6

delivery of the Project. The Director of Finance, Gurj Parmar, is accountable to the Project 7

Sponsor and BC Hydro’s Executive Vice President and Chief Financial Officer for financial 8

due diligence for the Project. 9

Additional information on BC Hydro’s project lifecycle and project cost estimating practices is 10

contained in Appendix D. 11


Chapter

3

Project Description and Impacts


3-i

Table of Contents

3.1 Project Description......................................................................................................3-1

3.1.1 Description of Mica .........................................................................................3-1

3.1.2 Project Description..........................................................................................3-4

3.1.3 Project Components .......................................................................................3-9

3.2 Project Schedule.......................................................................................................3-10

3.3 Project Costs ............................................................................................................3-13

3.3.1 Construction Costs........................................................................................3-13

3.3.1.1 Contingency/Risk Allowance:................................................................3-14

3.3.1.2 Mica Units 5 and 6 Equipment ..............................................................3-16

3.3.2 Operating, Maintenance and Outage Costs..................................................3-16

3.3.3 Planned Outage Costs and Risks .................................................................3-16

3.3.4 Non-BC Hydro Project Related Capital Costs...............................................3-17

3.4 Project Life Cycle......................................................................................................3-17

3.5 Construction Market Impacts ....................................................................................3-18

3.6 Social and Environmental Impacts ...........................................................................3-18

3.6.1 Environmental Assessment Approvals .........................................................3-18

3.6.2 Federal Permits, Approvals and Authorizations............................................3-19

3.6.3 Provincial Permits, Approvals and Authorizations ........................................3-19

3.6.4 Municipal Bylaws ..........................................................................................3-19

3.6.5 SF6 Management ..........................................................................................3-20

3.6.6 Columbia River Water Use Plan ...................................................................3-20

3.7 Analysis of Estimated Rate Impact ...........................................................................3-21 List of Figures

Figure 3-1 Columbia/Kootenay Area Generation ..........................................................3-2

Figure 3-2 Mica Underground Powerhouse ..................................................................3-3

Figure 3-3 Mica Dam Showing Planned Switchgear Building Extension.......................3-3

Figure 3-4 GIS in Transformer Gallery for Single Generating Unit................................3-5

Figure 3-5 GIS Bus in Lead Shaft .................................................................................3-6

Figure 3-6 Cut-away of GIS Bus ...................................................................................3-6

Figure 3-7 GIS Conducts High Voltages in the Powerhouse ........................................3-7

Figure 3-8 Original Design of Mica GS included Three Lead Shafts Running to Switchgear Building .....................................................................................3-8

Figure 3-9 Project Schedule........................................................................................3-11

Figure 3-10 Annual Rate Impact ...................................................................................3-22


3-ii

List of Tables

Table 3-1 Project Stages............................................................................................3-12

Table 3-2 Project Cost ...............................................................................................3-14

Table 3-3 Total Contingencies and Reserves ............................................................3-15

Chapter 3 - Project Description and Impacts


3-1

3.1 Project Description 1

3.1.1 Description of Mica 2

Mica is located on the Columbia River about 130 km upstream from Revelstoke, and 135 km 3

upstream of the City of Revelstoke (refer to Figure 3-1). Mica consists of an earth-filled dam, 4

an underground powerhouse, which contains generating units 1 through 4 and a switchgear 5

building (refer to Figure 3-2 and Figure 3-3). When constructed, the Mica powerhouse was 6

built to accommodate two additional generating units, Mica Units 5 and 6. Mica Dam forms 7

the Kinbasket reservoir, which extends 10 km to the confluence of the Columbia Reach, the 8

Wood Arm, and the Canoe Reach. From this confluence Kinbasket reservoir extends 9

120 km along the Columbia Reach to Donald and 95 km along the Canoe Reach to 10

Valemount. 11

Mica Dam was built under the terms of the Columbia River Treaty ratified by Canada and 12

the U.S. in 1964. Kinbasket and Arrow reservoirs are principal components of the Columbia 13

River Treaty and are governed by operating plans between B.C. and U.S. entities. Within 14

the constraints of these operating plans Mica and Revelstoke are key generating resources 15

that are operated with flexibility to follow BC Hydro system load and support trade 16

opportunities. Because of its size (1,805 megawatts (MW)), Mica is valued for the operating 17

flexibility it provides to the BC Hydro system as a whole. 18

Mica and Revelstoke together comprise 37 per cent of BC Hydro’s capacity. BC Hydro is 19

generally able to operate Kinbasket reservoir and Revelstoke reservoir to generate more 20

electricity at the times of the day when the load is greatest. The large storage capacity in the 21

Kinbasket reservoir and the synchronous condense ability at Mica and Revelstoke, allow 22

BC Hydro to take advantage of fluctuations in market prices. BC Hydro can import electricity 23

at times when it is cheaper than the value placed on the stored water and meanwhile store 24

that water for use and sale when demand and market prices are high. 25

Kinbasket and Revelstoke reservoirs are key swing reservoirs that allow BC Hydro to 26

effectively manage instantaneous demand for electricity as well as providing ancillary 27



3-2

services4 to the electric grid. Mica and Revelstoke are operated in balance with operations 1

on the Peace River system at GM Shrum Generating Station (at the Bennett dam) and 2

Peace Canyon Generating Station. For instance, Mica and Revelstoke are critical in 3

balancing generation when GM Shrum Generating Station is required to reduce its 4

generation to lower the risk of flooding in the town of Peace River, located in Alberta on the 5

Peace River, during ice freeze-up in the fall and ice break-up in the spring. 6

Figure 3-1 Columbia/Kootenay Area Generation 7

Definitions DDM – Duncan Dam HLK – Hugh Keenleyside KCL – Kootenay Canal MCA – Mica REV – Revelstoke SEV – Seven Mile Small Generation ABF – Aberfeldie ELK – Elko SHU – Shuswap SPN – Spillimacheen WGS – Whatshan WHN – Walter Hardman

4 These services include operating and spinning reserve, voltage support, black start, Voltage amps reactive

(VAR) compensation and rotating energy.



3-3

Figure 3-2 Mica Underground Powerhouse 1

Figure 3-3 Mica Dam Showing Planned Switchgear 2 Building Extension 3

Existing Switchgear & Office Building

Switchgear Building extension

Dam face



3-4

3.1.2 Project Description 1

The Mica powerhouse is underground, approximately 200 m below the dam crest. The 2

technology used to conduct the electricity out of the underground powerhouse to the 3

transmission network is 500 kV GIS. The GIS runs from the 500 kV (high-voltage) side of the 4

single-phase transformers through the lead shafts to the switchgear building. Figure 3-4 5

shows the GIS configuration in the transformer chamber from the three single-phase 6

transformers of one generating unit to the GIS entering a lead shaft. The glossary, found in 7

Appendix A explains the function of the bus, disconnect switches, circuit breakers and surge 8

arrestors identified in Figure 3-4. 9

GIS is used at three BC Hydro generating stations and a number of BCTC managed 10

substations because of its unique electrical insulating properties. SF6, the insulating gas 11

used in GIS, provides extremely good electrical insulation and effectively quenches electric 12

arcs. These properties of SF6 make it possible to build electrical equipment that is very 13

compact and safe. Figure 3-5 shows the close proximity of three phases of 500 kV GIS bus 14

in a lead shaft. Figure 3-6 shows a cut-away of GIS bus which includes an inside conductor 15

supported by an epoxy bus cone insulator within an outer SF6 enclosure. Workers are able 16

to safely stand beside GIS without risk of electrical contact (refer to Figure 3-7). SF6 is the 17

only feasible technology for 500 kV disconnect switches, surge arrestors and circuit 18

breakers. 19

As Mica was originally designed to accommodate six units, three lead shafts were 20

constructed (refer to Figure 3-8). However, only four generating units and the GIS bus 21

associated with these generating units, including GIS in two of the three lead shafts, was 22

installed. As a result, Mica currently does not have GIS in lead shaft 3. 23



3-5

Figure 3-4 GIS in Transformer Gallery for Single 1 Generating Unit 2

500 kV GISDisconnect Switches

3 -500kV Single Phase TransformersPer Generator

16kV Circuit Breakers

500kV GIS Surge

Arrestors

500kV Gas Insulated Bus

16kV Iso-Phase bus

Bus up lead shaft 200 meters to surface and to switchgear building

From Turbines and Generators



3-6

Figure 3-5 GIS Bus in Lead Shaft 1

Figure 3-6 Cut-away of GIS Bus 2

Conductor Bus Cone Insulator

Outer Enclosure



3-7

Figure 3-7 GIS Conducts High Voltages in the Powerhouse 1

The scope of the Project is to replace, with modern GIS technology, the existing 500 kV GIS 2

at Mica and install GIS in lead shaft 3. 3

The switchgear building houses the interface between the GIS and the transmission system. 4

This includes the termination of lead shafts 1 and 2, disconnect switches, circuit breakers 5

and bus. The switchgear building will be extended to house the termination of the lead 6

shaft 3 and the associated disconnect switches, circuit breakers and bus. The switchgear 7

building extension will also provide a clean, protected working area necessary during the 8

installation of GIS.5 9

A partial mezzanine6 and overhead crane will be added to the transformer chamber to 10

improve the operability and maintainability of the new GIS. Additionally, the mezzanine and 11

5 It is critical that no particles or impurities enter the GIS bus on installation. This is to prevent flash over failure

when energized or gradual degradation and eventual failure due to partial discharge. 6 The partial mezzanine are the platforms which support access to the disconnect switches and some of the

main bus in the transformer chamber.

GIS Bus



3-8

overhead crane will reduce the cost to remove the existing equipment and install the new 1

GIS7. The new GIS in the switchgear building will be more accessible than the current 2

design. 3

Figure 3-8 Original Design of Mica GS included Three Lead 4 Shafts Running to Switchgear Building 5

7 Based on the 1984 repair at Mica, a faulted bus section in a lead shaft can be expected to take between

one and three months to repair depending on the location of the fault, the phase of bus affected and the availability of skilled workers and supervisors.



3-9

3.1.3 Project Components 1

The Project will result in a complete upgrade of all original GIS at Mica. In addition, the 2

Project includes the installation of GIS required to put lead shaft 3 into service. Specifically, 3

the Project includes the design, supply and installation of: 4

3,500 m of single phase gas insulated bus; 5

66 (22 sets of 3) disconnect switches; 6

three (one set of three) circuit breakers; 7

18 (six sets of three) surge arrestors; 8

an overhead crane in the transformer chamber; 9

a partial mezzanine in the transformer chamber; 10

a new lift8 for lead shaft 3 and upgrades to the lifts in lead shafts 1 and 2; 11

upgrades to fire protection, auxiliary mechanical systems, electrical infrastructure and 12

miscellaneous civil improvements to support the new equipment; 13

an extension of approximately 560 square metres to the switchgear building and related 14

heating, ventilation and air conditioning (HVAC), electrical and fire protection systems; 15

and 16

protection and control (P&C) for GIS. 17

The circuit breakers in the switchgear building which were replaced by BCTC9 in 2008 due 18

to reliability problems are not required to be replaced. 19

8 The lift is a small inclined geared elevator, also referred to as a funicular. 9 Equipment in the switchgear building, under BCTC management, is being transferred to BC Hydro’s control.



3-10

3.2 Project Schedule 1

The Project will be implemented in stages over four years. The first step is the construction 2

of an extension to the switchgear building. The switchgear building extension will house an 3

extended bus, circuit breakers and disconnect switches that connect lead shaft 3 bus to the 4

existing switchgear equipment. The Switchgear building extension work is expected to be 5

complete by March 2010. 6

The GIS equipment required to put lead shaft 3 into service will be installed next. This will 7

reduce the risk of a forced outage as lead shaft 3 will be available prior to and during the 8

replacement of bus in lead shafts 1 and 2. 9

The existing GIS will be replaced over two years, two units at a time. In 2011 the GIS 10

serving Mica Units 3 and 4 will be replaced. A four month outage of Mica Units 3 and 4 is 11

required from March to July in 2011. In 2012, the GIS serving Mica Units 1 and 2 will be 12

replaced. A four-month outage of Mica Units 1 and 2 is required from March to July in 2012. 13

The Project includes civil work, lead shaft lift installation and upgrades, and nine stages of 14

major activities as shown in Figure 3-9 and Table 3-1. A detailed Project schedule is 15

provided in Appendix C. 16



3-11

Figure 3-9 Project Schedule 1

Mica Switchgear Project 1

Mica Switchgear Project Schedule July 09 –Dec 09

Lead Shaft 3

Jan 10 –Jun 10

Jun 10 –Dec 10

Jan 11 –Jun 11

Jan 12 –Jun 12

Jun 12 –Dec 12

Jan 13 –Jun 13

Stage 1

Stage 2

Stage 3

Jun 11 –Dec 11

Design & Manufacture

Stage 4

Stage 5

Stage 6

Stage 7

Stage 8

Stage 9

RingSwitchgear Building Ring Extension

Lead Shaft 3

InterfaceInterface existingGIS to Lead Shaft 3

Unit 3 & 4Mica Units 3 & 4

RingSwitchgear BuildingRing Bus

Units 1 & 2Mica Units 1 & 2

RingSwitchgear BuildingRing Bus

Lead Shaft 2 LS 2

Lead Shaft 1 LS 1

Completion Completion



3-12

Table 3-1 Project Stages 1

Stage Location Description Start of Work End of Work

Non-GIS Work

Switchgear building Addition of 560 square meters to Switchgear building to house termination of lead shaft 3.

September 2009 March 2010

Lead Shaft Lifts

Lead Shafts 1 - 3 Upgrade lifts in lead shafts 1 and 2. Add lift to lead shaft 3.

May 2010 August 2010

GIS Work

1 Install GIS support structures in Lead Shaft 3

Install bus, GIS support structures, and gas monitoring systems for lead shaft 3 GIS

October 2010 December 2010

2 Switchgear Building Ring Extension

Install disconnects, ground switches, gas monitoring, GIS support systems required to operate and connect lead shaft 3 to existing GIS in switchgear building

October 2010 January 2011

3 Install GIS equipment in Lead Shaft 3

Install disconnects, surge arrestors, gas monitoring and interface between existing equipment and lead shaft 3 in transformer chamber. Includes crane and mezzanine over this section of the chamber.

October 2010 January 2011

4 Mica Units 3 and 4 GIS Replacement

Replace disconnects, surge arrestors and connecting bus on Mica Units 3 and 4 in transformer chamber. Extend crane and mezzanine and all GIS support structures for this section of transformer chamber.

March 2011 May 2011

5 Switchgear Building - Transmission Line to Reactor

Replace all existing original disconnects, air bushing and bus between Transmission Line Air Bushing 5L71 to Reactor 5RX4 in switchgear building including Return bus.

(Excludes circuit breakers replaced by BCTC in 2008.)

April 2011 June 2011

6 Mica Units 1 and 2 GIS Replacement

Replace disconnects, surge arrestors and connecting bus on Mica Units 1 and 2 in transformer chamber. Extend crane and mezzanine and all GIS support structures for this section of transformer chamber.

March 2012 July 2012

7 Switchgear Building to Lead Shaft 2

Replace all existing original GIS between Air Bushing 5L72 and Reactor 5RX3.

March 2012 July 2012

8 Lead Shaft 2 Replace with new GIS equipment in lead shaft 2. Upgrade skip and gas monitoring systems.

August 2011 January 2012

9 Lead Shaft 1 Replace with new GIS equipment in lead shaft 1. Upgrade skip and gas monitoring systems.

August 2012 December 2012

Project Close Complete documentation, manuals and maintenance instructions.

June 2013



3-13

3.3 Project Costs 1

3.3.1 Construction Costs 2

The Expected Cost for the Project is $180.6 million -10 per cent/+15 per cent (range from 3

$163 million to $208 million) and the Authorized Cost for the Project is $200.2 10million (refer 4

to Table 3-2). This estimate includes the Project costs to date, all management, engineering 5

and design costs, the cost to supply and install all equipment, the cost of the switchgear 6

building extension, an allowance for overhead, interest during construction (IDC), costs for 7

regulatory and permitting approvals, inflation adjustments and a contingency. 8

Cost certainty has been increased by tendering the Project early. On March 26, 2009, 9

BC Hydro received three competitive bids in response to an open tender for the design, 10

supply and installation of the GIS. A fixed price contract was awarded to MEPPI for a base 11

value of $42 million. The contract represents about 60 per cent of the total amounts to be 12

contracted for this Project or 43 per cent of the direct construction costs. As a result, a 13

significant portion of the direct construction costs are defined, limiting the potential for future 14

cost increases.15

10 Appendix F contains the capital expenditure schedule for the Project.



3-14

Table 3-2 Project Cost 1

PROJECT COMPONENT AMOUNT ($ million)

Direct Construction Cost $ 94.6 Project Management and Engineering 18.8

Sub-total: Construction Cost before Contingency (Note 1) $113.4 Contingency on Expected Cost 11.3 Dismantling and Removal 1.0 Inflation and Escalation (Note 2 ) 8.4

Sub-total: Implementation Phase Cost (Direct) $134.1 Capital Overhead (Note 3) 17.7 Interest During Construction (Note 4) 21.3

Sub-total: Implementation Phase Cost (Loaded) $173.1

Identification and Definition Phase (loaded) 7.5 Total Expected Cost $180.6

Project Reserve (Note 5) 19.6 Total Authorized Cost (note 6) $200.2

Notes: 2 1. The construction cost before contingency includes allowances for other supporting items such as P&C, 3

HVAC, and Fire Protection equipment. 4 2. Inflation and escalation rates used are five per cent and four per cent in F2010 and F2011 respectively, and 5

three per cent in F2012 and beyond. 6 3. Capital overhead is 13.3 per cent of the direct Implementation phase cost excluding dismantling and 7

removal. 8 4. An IDC rate of 6.52 per cent is applied to the sum of the direct Implementation phase cost and corporate 9

overhead accumulated in each year. 10 5. The Project reserve is the sum of the management reserve and the additional contingency in the Authorized 11

Cost above the contingency in the Expected Cost (refer to section 3.3.1.1 for further details on 12 contingencies). 13

6. On May 22, 2009, BC Hydro’s Board of Directors approved the project with an authorized cost of 14 $238 million for implementation. Subsequently, with the award of the MEPPI contract, the authorized cost 15 has been reduced to $200.2 million. 16

3.3.1.1 Contingency/Risk Allowance: 17

Contingencies have been assigned to take into account the uncertainties and risks identified 18

during the Project Identification and Definition phases. Contingencies are estimated based 19

on the total construction costs. 20



3-15

The Expected Cost includes a contingency of $11.3 million (unloaded) while the Authorized 1

Cost includes additional contingencies of $11.3 million. Inflation, capital overhead and IDC 2

are applied to contingencies such that there is a total contingency of $32.2 million (loaded) 3

included in the Authorized Cost. The contingency for the Expected Cost and Authorized 4

Cost are based on range estimating methods in developing a Monte Carlo risk analysis. 5

Refer to Appendix D-2 for a description of BC Hydro’s cost estimating practices. 6

Table 3-3 provides a more detailed breakdown of the Project contingency and reserves. 7

Table 3-3 Total Contingencies and Reserves 8

$ millions

Description Total Contingency on

Expected and Authorized Costs

Project Reserve Project Cost

Project Expected Cost A $180.6 Contingency included in Expected Cost B $11.3

Inflation, escalation and loadings on Contingency included in Expected Cost (Note 1)

C $4.8

Incremental Contingency on Authorized Cost D $11.3

Inflation, escalation and loadings on Incremental Contingency included in Authorized Cost (Note 1)

E $4.8

Total Contingency included in Project Authorized Cost B+C+D+E $32.2

Total Incremental Contingency included in Authorized Cost F=D+E $16.1

Management Reserve (Note 2) G $3.5 Authorized Project Reserve H=F+G $19.6 $19.6 Project Authorized Cost A+H $200.2

Notes: 9 1. Loadings on contingency include capital overhead and interest during construction. 10 2. Management reserve is requested to allow for additional snow removal costs, accommodation allowances 11

and contract claims. 12



3-16

3.3.1.2 Mica Units 5 and 6 Equipment 1

The supply and installation of six of 18 (two out of the six sets) surge arrestors and related 2

bus11 is for the yet to be installed Mica Units 5 and 6. It is estimated that the loaded cost of 3

these six surge arresters and related bus is approximately $2 million. These six surge 4

arrestors are being installed as part of the Project to ensure operating instructions and spare 5

parts will be the same throughout Mica. In the event Mica Units 5 and 6 do not proceed, the 6

cost would be stranded. However, BC Hydro is of the view that the operational benefit 7

makes it worthwhile to commit to this relatively small expenditure at this time. 8

3.3.2 Operating, Maintenance and Outage Costs 9

There is no material change in maintenance costs expected as a result of the Project. 10

Ongoing maintenance requires two to three person days per month for inspection and 11

monitoring of the GIS and an annual inspection of each lead shaft lift. The addition of GIS 12

equipment to lead shaft 3 will increase the amount of equipment that will need monitoring 13

and inspection. However, efficiencies introduced as a result of modern monitoring, P&C 14

equipment and the easier access for inspection are expected to offset any additional costs 15

associated with the inspection and maintenance of the added equipment. 16

3.3.3 Planned Outage Costs and Risks 17

A four month outage for Mica Units 3 and 4 and a separate four month outage for 18

Mica Units 1 and 2 are scheduled in 2011 and 2012 respectively to connect the new GIS to 19

the single-phase transformers of Mica Units 1 to 4. The two outages are planned from 20

March to July of each year as this period represents the lowest average cost to BC Hydro. 21

The actual cost of the outage and the cost of possible extensions of the outage are highly 22

dependant on a number of variables including: 23

systems reservoir conditions particularly the relative storage of Kinbasket and Williston 24

reservoirs; 25

stream flow conditions; 26

11 Related bus refers to the bus extension beyond lead shaft 3 to connect Mica Unit 6 transformers and the

branches from the main bus to the Mica Units 5 and 6 transformers.



3-17

market conditions; and 1

electricity demand. 2

All of these variables are highly uncertain. Heavy winter loads or high demand is less likely 3

after mid-March so outages in this time frame are preferred. One of the best indicators for 4

predicting system reservoir conditions and stream flows is the snow pack condition that 5

exists around the beginning of March. This information is evaluated to ensure that BC Hydro 6

can meet firm load and flow obligations under the Columbia River Treaty during the outage 7

period. 8

There is a risk that the Project could extend beyond the planned four month period of each 9

year. The cost of extending the planned four month outage by one month in August can vary 10

significantly from as low as $3 million to as high as $20 million. The range is based on the 11

lost export opportunity cost, Mica stream flows, Columbia Treaty obligations and Pacific 12

Northwest flow conditions. Columbia River Treaty storage is usually full in the Arrow and 13

Kinbasket reservoirs by August. Extending the planned outage because of schedule delays 14

in the Project could lead to spills at Mica. 15

3.3.4 Non-BC Hydro Project Related Capital Costs 16

There are no non-BC Hydro related capital costs. BCTC has confirmed that the Project does 17

not require any changes to the transmission system. 18

3.4 Project Life Cycle 19

The Project began in the Initiation phase with three condition assessment reports. These 20

indicated the unsatisfactory condition of a number of components of the GIS requiring 21

immediate replacement, and the eventual replacement of all GIS equipment. 22

The Identification phase began in November 2007. During the Identification phase BC Hydro 23

developed and analyzed numerous potential replacement architectures and configurations. 24

BC Hydro then recommended a specific architecture. A business case and Project plan was 25

prepared for the Definition phase. At the end of the Identification phase the Project Sponsor 26

made the decision in July 2008 to continue the Project through to the Definition phase. 27



3-18

The next phase of the Project was the Definition phase in parallel with early Implementation 1

phase work. This phase included the development of the preliminary design. It also included 2

the tendering of the GIS design, supply and install contract. 3

BC Hydro’s Board of Directors approved the Project to advance to Implementation phase on 4

May 22, 2009. The Implementation phase includes detailed design, material and equipment 5

procurement, construction, testing, and commissioning into service. The fixed price contract 6

for the GIS was awarded to MEPPI on June 15, 2009 for a base value of $42 million. The 7

Implementation phase will end with the Project Initiator acknowledging acceptance of the 8

Project results by signing the Project completion report. 9

Appendix D1 describes BC Hydro’s project life cycle. 10

3.5 Construction Market Impacts 11

The ongoing global financial crisis and current economic conditions have significantly 12

impacted the landscape in many industries. In general, circumstances are such that 13

BC Hydro is in a favourable position to proceed at this time, and in the near future, with 14

capital projects. BC Hydro does not expect material challenges to the Project related to the 15

general construction market conditions. Additionally BC Hydro now has a contract with 16

MEPPI for the design, supply and installation of the GIS. As a result MEPPI now assumes, 17

for a significant portion of the Project, any risks related of the construction market. 18

3.6 Social and Environmental Impacts 19

3.6.1 Environmental Assessment Approvals 20

The Project does not require any regulatory approval pursuant to either the B.C. 21

Environmental Assessment Act (BCEAA) or the Canadian Environmental Assessment Act 22

(CEAA). 23



3-19

Under the BCEAA, approval is not required because the Project is not a “modification” to 1

increase capacity.12 2

Under the CEAA there are no federal permits or approvals required for the Project, therefore 3

there is no requirement for a CEAA review. 4

Most of the Project work will be performed indoors, and there will be no releases or activities 5

that could affect fish bearing waters. As a result, there is no requirement for approval (or 6

authorization) for the Project under the federal Fisheries Act. 7

3.6.2 Federal Permits, Approvals and Authorizations 8

There are no federal permits, approvals or authorizations required for construction or 9

operation of the Project. 10

3.6.3 Provincial Permits, Approvals and Authorizations 11

Depending on construction methodologies there may be provincial permits or approvals 12

required for culverts to redirect natural surface drainage on the cliff above where the 13

switchgear building will be extended. 14

In accordance with the contract BC Hydro entered into with MEPPI for the supply and 15

installation of the GIS equipment and BC Hydro’s Environmental Management Plan for the 16

Project, any contractors will be required to obtain any environmental permits, licences, or 17

approvals applicable for their work. 18

3.6.4 Municipal Bylaws 19

There are no applicable municipal bylaws. 20

12 Appendix K contains the BCEAO order removing the switchgear building from the BCEAC review of

Mica Unit 5.



3-20

3.6.5 SF6 Management 1

SF6 is used in three BC Hydro generating stations and at various BCTC operated 2

substations because of its electrical insulating properties. SF6 is a potent GHG: 3

1 kilogram (kg) of SF6 is equal to 23,900 kg of carbon dioxide (CO2) equivalents. The 4

current GIS at Mica leaks an excessive amount of SF6 and more significant leaks are 5

expected to develop over time as the equipment ages. In 2008, a total of 565 kg of SF6, 6

representing a leakage rate of 3.8 per cent per year, leaked at Mica. Due to the GHG 7

intensity of SF6, this amount is equivalent to 13,503 tonnes of CO2, and accounts for about 8

20 per cent of total BCTC and BC Hydro SF6 leakage. Based on the U.S. Environmental 9

Protection Agency estimates, the average passenger vehicle produces 5.2 tonnes of CO2 10

equivalents a year. Based on this, the SF6 leakage at Mica is comparable to 2,600 average 11

passenger vehicles. 12

For new GIS, the current industry standard leakage rate is 0.5 per cent per year. New GIS 13

equipment being installed in Japan and Europe is achieving leakage rates of 0.1 per cent 14

per year or less. GIS installations at Revelstoke generating station and Seven Mile GS are 15

currently achieving nearly zero losses. 16

As part of its GHG management program, BC Hydro has implemented procedures to 17

minimize SF6 releases during maintenance and operation of SF6 equipment, and to monitor 18

any releases. The contract for the design, supply and installation of the GIS equipment 19

specifies a maximum SF6 leakage rate at the industry standard level of 0.5 per cent. During 20

construction, MEPPI is required to implement SF6 tracking and management procedures 21

and standards equivalent to BC Hydro’s. MEPPI will also be required to comply with all 22

applicable federal and provincial legislation with respect to the management, storage, and 23

transportation of new and used SF6, including the monitoring of releases. Used SF6 will be 24

recycled by MEPPI. 25

3.6.6 Columbia River Water Use Plan 26

Because this Project has no effect on water flows or water levels upstream or downstream 27

of Mica, there is no impact on the Columbia Water Use Plan and no need for a 28

Project-related Addendum. 29



3-21

3.7 Analysis of Estimated Rate Impact 1

The impact that the Project would have on BC Hydro’s revenue requirements is discussed in 2

this section and the resulting estimated annual incremental rate impacts from the Project 3

with a final ISD of June 2013 at an Expected Cost of $180.6 million and an Authorized Cost 4

of $200.2 million are shown in Figure 3-10. 5

The Long Term Rate Increase Forecast (LTRIF) as filed in the 2008 LTAP13 is the starting 6

point for the analysis of the incremental revenue requirements and rate increase/decrease 7

impacts of the Project14. 8

The Project would affect the following elements of BC Hydro’s revenue requirements: 9

amortization; finance charges; and return on equity. 10

There is an initial increase to BC Hydro’s revenue requirements in the early years the 11

Project is placed into service. This annual increase, based on the Project Expected Cost, 12

would be highest in F2014 at around $19 million the first year the entire project is in-service. 13

By F2033 the annual revenue requirement would be at around $11 million based on the 14

Project Expected Cost. 15

Figure 4-8 shows the resulting estimated incremental annual rate impact of the Project, 16

relative to the overall projected annual BC Hydro rate increase forecast for a particular year 17

as estimated in the LTRIF. 18

As shown in Figure 4-8, the Project would give rise to incremental annual rate increases in 19

the beginning in F2010 as components of the Project are placed in-service. This results from 20

the initial effect of the amortization and financing costs of the Project. From F2014, there 21

would be small, but declining incremental rate increase impacts arising from the Project. 22

13 Exhibit B-3, BC Hydro response to BCUC IR 1.7.1. 14 BC Hydro reiterates that this forecast is highly uncertain and subject to significant variability depending on

the assumptions used. The forecast does not represent BC Hydro’s view as to its future revenue requirements applications, and any rate increases requested in those applications will be based on BC Hydro’s detailed assessment of its expected revenues and costs at the time of filing.



3-22

Figure 3-10 Annual Rate Impact 1

0.00%

0.10%

0.20%

0.30%

0.40%

0.50%

0.60%

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032

Fiscal Year

Per C

ent

Expected

Approved


Chapter

4

Project Justification


4-i

Table of Contents

4.1 Introduction.................................................................................................................4-1

4.2 Need for the Project....................................................................................................4-1

4.2.1 Reliability and Outage Risk.............................................................................4-2

4.2.2 Life Cycle Asset Management ........................................................................4-3

4.2.3 GIS Condition Assessment .............................................................................4-5

4.2.3.1 Independent Condition Assessment Reports..........................................4-5

4.2.3.2 BC Hydro Condition Assessment Conclusions .......................................4-7

4.2.3.3 Condition Assessment Summary..........................................................4-13

4.3 Identification of Project Benefits ...............................................................................4-13

4.3.1.1 Disconnect Switches.............................................................................4-14

4.3.1.2 Maintenance Access.............................................................................4-14

4.3.2 Environmental Benefits .................................................................................4-17

4.3.3 Benefit to Mica Units 5 and 6 ........................................................................4-18

4.4 Architecture Evaluation and Selection ......................................................................4-18

4.4.1 Problem Scope and Architecture Options.....................................................4-19

4.4.2 Architecture Conclusions ..............................................................................4-21

4.4.3 Holm, Hampton and Heil Recommended Architectures ...............................4-22

4.5 Timing and Sequencing of GIS Replacement...........................................................4-23

4.5.1 Timing of GIS Replacement..........................................................................4-23

4.5.2 Planned Outage Requirements for Alternatives............................................4-25

4.5.3 Sensitivity Analysis for Mica Units 5 and 6 ISDs...........................................4-29

4.5.4 Recommended Project Scope ......................................................................4-33 List of Figures

Figure 4-1 Bus Cone Insulator ....................................................................................4-10

Figure 4-2 Condition Assessment Summary...............................................................4-13

Figure 4-3 Repair of Surge Arrestor under Existing GIS Layout .................................4-15

Figure 4-4 Height of Existing GIS................................................................................4-16

Figure 4-5 Improved GIS Layout .................................................................................4-17

Figure 4-6 Mica GIS Ultimate Layout ..........................................................................4-22

Figure 4-7 Reliability Realization from Staging Lead Shaft 3 First ..............................4-27


4-ii

List of Tables

Table 4-1 Analysis of GIS by Component ..................................................................4-11

Table 4-2 PV of Replacement Alternatives ................................................................4-24

Table 4-3 Replacement of Lead Shaft 1 and 2 with or without Lead Shaft 3 in Place.................................................................................4-28

Table 4-4 Sensitivity Analysis for Meeting Alternative Mica Units 5 and 6 ISD..........4-32

Chapter 4 - Project Justification


4-1

4.1 Introduction 1

Section 4.2 of this chapter explains BC Hydro’s need to replace the GIS. Section 4.3 2

describes the additional benefits that BC Hydro will realize as a result of implementing the 3

Project. Section 4.4 explains the process BC Hydro has undertaken to identify GIS as the 4

proposed architecture for the Project taking into consideration the recommendations by 5

external experts, BC Hydro’s own analysis and considering the longer term requirements of 6

a six unit Mica which requires GIS in all three lead shafts in order to transmit the full output 7

of six units. 8

In section 4.5.1, alternative GIS implementation timing and sequences for the proposed GIS 9

architecture for the Project are compared. These alternatives result in the replacement GIS 10

being fully installed at later dates than the Project schedule provided in Table 3-1, and have 11

different present values (PV) than the Project as proposed. The timing of the installation of 12

lead shaft 3 and the switchgear building is considered in the implementation timing of 13

alternatives since without the GIS in lead shaft 3, additional planned outages are required 14

leading to a later ISD for the Project. The reason for the additional planned outages is 15

discussed in section 4.5.2. Given the uncertainty of the ISDs for Mica Units 5 and 6, 16

section 4.5.3 compares the PV of the Project to other options that may be feasible if the ISD 17

for Mica Unit 5 was alternatively 2018 or 2025. These other options are sequenced 18

differently than as proposed in Chapter 3, but result in the proposed GIS architecture being 19

implemented prior to an ISD for Mica Unit 5 of 2018 or 2025. Section 4.5.4 summarizes the 20

justification for BC Hydro’s recommended Project scope. 21

4.2 Need for the Project 22

The existing GIS at Mica presents a substantial risk of forced outages to BC Hydro. The 23

GIS, which is over 30 years old, may be the last 500 kV GIS equipment of this vintage and 24

manufacturer still in operation in North America. The purpose of the Project is to mitigate this 25

risk of forced outages. 26



4-2

4.2.1 Reliability and Outage Risk 1

Mica is designated as a key facility in BC Hydro’s generation strategic asset management 2

system. Key generation facilities provide approximately 90 per cent of BC Hydro’s average 3

annual energy. BC Hydro’s F2007 Generation Strategic Asset Plan (filed as Attachment 1 to 4

the response to BCUC IR 1.5.1 (Exhibit B-11) during BC Hydro’s F07/F08 RRA), includes 5

the following objective: 6

Over the next 5 years, cost effective plans will be implemented (and completed) 7

at all large (key) facilities to refurbish or replace all equipment assessed by EHR 8

to be in “poor” or “unsatisfactory” condition or, alternatively, a strategy 9

implemented to mitigate the risk of failure of such equipment. 10

Replacement of the GIS, as described in this application, is one of the actions required to 11

meet this objective. 12

Mica supplies approximately 16 per cent of the energy and 17 per cent of the capacity for 13

BC Hydro. At Mica, the expected cost of a forced or unplanned outage in any month varies, 14

ranging from zero to over $20 million per month depending on time of year. In the event of 15

an outage, replacement energy and capacity may need to be purchased on the market at a 16

higher cost than the cost of self-generation. The costs of outages at Mica are mitigated as 17

BC Hydro can store water in the Kinbasket reservoir for future generation and income 18

earning opportunities. However, BC Hydro would incur a permanent loss of generation due 19

to an outage at Mica if BC Hydro needs to spill water at Mica to manage Kinbasket reservoir 20

levels or downstream flow requirements. 21

Currently, if all other Mica equipment is in operation, failure of the GIS in one lead shaft 22

restricts the output of Mica to 1,500 MW15 (single contingency outage). During the repair 23

period for such a failure, Mica is vulnerable to a full plant outage if a second GIS failure 24

occurs (BC Hydro does not typically design equipment to mitigate second contingency 25

failures). 26

15 The BCTC Most Severe Single Contingency (MSSC) requirement restricts the plant output which can be

connected to the transmission system through one lead shaft bus (refer to Appendix G).



4-3

Many GIS failures may result in either one or two units being out of service for an extended 1

period. In particular, the disconnect switches and the majority of bus in the transformer 2

chamber all require two unit outages for repair work to proceed. 3

One of the independent GIS experts who assessed the Mica GIS (as discussed in 4

section 4.2.3.1 below) concluded that there was a 99 per cent chance of a GIS failure within 5

ten years or, in other words, there is a 33 per cent chance of failure in each of the next ten 6

years. The risk of a GIS failure is expected to increase over time as the GIS ages. 7

4.2.2 Life Cycle Asset Management 8

BC Hydro has applied its Life Cycle Asset Management (LCAM) principles and practices in 9

its assessment of the need to replace the Mica GIS. LCAM is described further below. 10

BC Hydro is committed to managing its generation assets through the effective and efficient 11

application of the LCAM principles and practices. LCAM is used to maximize economic 12

return on physical assets over their life by achieving desired performance outcomes, while 13

effectively managing the risks inherent in owning, managing and operating a large asset 14

base. 15

LCAM considers several dimensions of business value including: safety; availability and 16

reliability; commercial performance; contribution to revenue; total unit cost of production; 17

and environmental and social performance. 18

The asset management framework enables making trade-offs amongst these value 19

dimensions, leading to optimization of business value. 20

The LCAM is used for BC Hydro’s generation assets to ensure consistency in decision-21

making processes and to provide transparency to external stakeholders and regulatory 22

agencies16. 23

16 BC Hydro’s LCAM system for generation assets is consistent with the British Standard Institution (BSI)

PAS 55 Asset Management Specifications.



4-4

One of the key decisions in asset management is when to overhaul or replace equipment. 1

There are three specific factors that trigger replacement: 2

1. Below target reliability or availability or declining reliability or availability trend combined 3

with: 4

maintenance costs that are increasing or can be economically reduced by equipment 5

replacement; or 6

equipment is obsolete (e.g., spare parts are no longer economically available or 7

technical experience is limited or difficult to obtain). 8

2. Estimated business risk to BC Hydro is too high; or 9

3. Additional energy or capacity can be produced economically (e.g., Resource Smart 10

opportunity). 11

Under the LCAM model, BC Hydro uses, for most major assets, a standardized condition 12

assessment methodology known as Equipment Health Rating (EHR), to assist in identifying 13

when capital investment in major equipment is required. 14

In assessing the health of specific equipment, the EHR methodology considers: 15

the design and original quality of the asset; 16

the current condition of the asset; 17

the maintainability of the asset, including the availability of spare parts and technical 18

experience; 19

how the asset has been and will be operating; 20

how the asset has been and will be maintained; and 21

opportunities for investment to improve the asset. 22



4-5

BC Hydro also uses a risk assessment methodology to assist in making investments in 1

generation assets. Risks are assessed in terms of their frequency or probability of 2

occurrence and in terms of their consequences or severity and are evaluated in four 3

categories: safety, financial, environmental, and damage to reputation. 4

Because of the limited use of GIS at its facilities, BC Hydro has not developed an EHR 5

methodology for assessing the condition of GIS equipment. Instead, BC Hydro retained 6

three consultants to assess the condition of the Mica GIS, using the same factors 7

considered in BC Hydro’s EHR and risk methodologies. 8

Finally, BC Hydro’s LCAM requires that alternative solutions be evaluated. This involves, for 9

each of the alternative solutions considered, balancing the tradeoffs between the risk and 10

performance dimensions and the total lifecycle cost. BC Hydro’s objective is to maximize the 11

lifecycle value of its generation assets while being mindful of the impact on customer rates. 12

Alternative solutions with respect to the Project are addressed in section 4.4 13

4.2.3 GIS Condition Assessment 14

This section outlines the conclusions and recommendation from condition assessments 15

performed by both external GIS experts and by BC Hydro. 16

4.2.3.1 Independent Condition Assessment Reports 17

Three independent condition assessments were performed17 by three external GIS experts. 18

The relevant recommendations from these reports are presented in this section. The reports 19

are provided in Appendix E. 20

17 The independent experts did not assess the condition of the GIS in the switchgear building as this equipment

was managed by BCTC (the management of the switchgear building is being transferred to BC Hydro). BC Hydro considers the condition assessments applicable to the equipment in the switchgear building because the switchgear building contains GIS of the same vintage and manufacturer as that in the transformer chamber.



4-6

Bjorn Holm Condition Assessment Recommendations 1

Mr. Bjorn Holm of International Switchgear Consulting prepared a report titled “Condition 2

Assessment of 550 KV ITE SF6 Gas Insulated Switchgear Equipment in the Transformer 3

Gallery and Lead Shafts” dated October 2005. 4

His recommendations include: 5

Install spare phase of bus in the transformer chamber in the short term; 6

Install GIS in lead shaft 3; and 7

Replace the GIS in stages starting within about eight years (or by 2013). 8

Edgar Heil Condition Assessment Recommendations 9

Mr. Edgar Heil (of RoHe International) prepared a report titled ”BC Hydro Mica Generating 10

Station - ITE GIS Condition Risk Assessment” dated, June 30, 2007. 11


Immediately - Replace all disconnect switch operating rods; 13

Medium Term (within five years) - Replace all “O-rings” in bolted flanges to stop SF6 14

leaks; and 15

Long Term (five - 30 years): 16

install bus in lead shaft 3; and 17

replace all GIS components in the transformer chamber. 18

Mr. Heil provided the following note to the recommendations: 19

“If a replacement GIS is considered, then the recommended “Medium Term Solution” 20

may be delayed. However, some unscheduled outages, repairs maintenance will 21

most likely be the result of this delay.” 22



4-7

Dr. Brian Hampton Condition Assessment Recommendations 1

Dr. Brian Hampton, formerly of the Central Electricity Generating Board London, prepared 2

the condition assessment report titled “The Present Condition and Future Reliability of the 3

Transformer Gallery GIS at Mica Unit 500 kV Substation” dated June 25, 2007. 4


Phase 1 - Replace all disconnects and surge arrestors in the transformer chamber in the 6

short term; 7

Phase 2 - Install a second (or redundant) bus in the transformer chamber in the medium 8

term; and 9

Phase 3 - Replace lead shaft 1 and 2 in 2014. 10

4.2.3.2 BC Hydro Condition Assessment Conclusions 11

The condition assessments consistently recommend that BC Hydro address the reliability 12

issues of the GIS. The details of the recommendations may vary – but the general 13

recommendations are consistent. Dr. Hampton concluded that there was a 99 per cent 14

chance of GIS failure within ten years. Nine months after this prediction, a surge arrestor 15

failed on Unit 3, which resulted in it being out of service for ten weeks. 16

Since the condition assessments, BC Hydro identified additional GIS issues for the following 17

key GIS components: 18

Surge Arrestors – Surge arrestors protect electrical equipment, particularly transformers, 19

from damage that could result from voltage spikes. A transformer is capable of absorbing 20

a narrower range of voltage variation and without a surge arrestor in place could be 21

damaged if exposed to voltage variation outside of this range. 22

Mica Unit 3 has been in operation without surge arrestors on A and C phases since 23

spring 2008. The A-phase surge arrestor on Mica Unit 3 was removed immediately after it 24

failed in March 2008 and the C-phase surge arrestor was removed shortly after. 25

Mica Unit 3 has only one remaining surge arrestor on B-phase. This results in Mica Unit 4 26



4-8

surge arrestors protecting both Mica Units 3 and 4 transformers from fast front surges, 1

typically caused by lightning. This means the transformers on Mica Unit 3 and Mica Unit 4 2

have a lower level of protection than designed. This designed redundancy in surge 3

arrestors might otherwise act to prevent damage in the event of a voltage surge. 4

Following the March 2008 surge arrestor failure, the damaged surge arrestor was 5

inspected to investigate the cause of failure. The grading capacitor of the surge arrestor 6

had damage that clearly preceded the surge arrestor flashover that caused the 7

March 2008 outage. It is likely that the surge arrestor was providing little or no protection 8

before it failed, and in fact was the cause of the forced outage. BC Hydro also concluded 9

that the surge arrestor could not be refurbished. An operating restriction has been 10

established at Mica to prevent manual operation of the disconnect switches while the bus 11

is energized to reduce the occurrence of voltage surges. Based on the root cause 12

analysis performed on the failed surge arrestor, a hypothesis for the failure mechanism 13

was developed. As part of the ongoing regular monitoring of the surge arrestors, the 14

remaining surge arrestors are now monitored for indications of this failure mode 15

occurring. 16

As a result of this ongoing monitoring, a surge arrestor on Mica Unit 2 showed indications 17

of this failure mode and as a result was removed from service. 18

The remaining nine surge arrestors on Mica Units 1 through 4: 19

have reached the end of life; 20

have a high likelihood of failure; 21

may no longer be protecting the transformers; and 22

are likely increasing the risk of failure and subsequent damage to surrounding 23

equipment. 24

Disconnect Switches – There has been a history of disconnect switch failures over the life 25

of Mica. Many have been due to disconnect rod failures. Disconnect rods are insulated 26

rods connected to the mechanism used to open and close disconnect switches. To date, 27

BC Hydro has successfully repaired all of the disconnect switch failures. However, with 28



4-9

the surge arresters out of service, failure of a disconnect switch may result in damage to 1

other equipment such as the 500 kV transformers, as the surge arrestors offer protection 2

to the transformers for this sort of fault. In 2000 Powertech Labs Inc. examined a number 3

of Mica disconnect rods and found a breakdown of the insulating properties of the rods. 4

This will eventually lead to flash-over failures of the disconnect switches, which in most 5

cases will result in a forced outage of at least one generating unit. 6

Bus Cone Insulators – BC Hydro performed in situ ultra high frequency testing in 2005 7

and again in 2008 on the bus cone insulators during normal operation. The bus cone 8

insulators are distributed throughout the bus to support the conductor (refer to Figure 9

4-1). The testing detected extensive partial discharge which is an indicator of poor 10

equipment health, and will eventually result in flash-over failure leading to forced outages. 11



4-10

Figure 4-1 Bus Cone Insulator 1

Spare Parts - There are no spare parts for surge arrestors, and spare parts for disconnect 2

switches have limited availability. There is 30 m of spare bus available. 3

Table 4-1 provides additional details on the current state of the GIS components along with 4

additional details on outage requirements to replace GIS and the consequences of forced 5

outages.6

Conductor Bus Cone Insulator

Outer Enclosure



4-11

Table 4-1 Analysis of GIS by Component

Component Current State Planned Outage Required for Replacement or Installation

Forced Outage Consequence

Benefits of New Equipment

Surge Arrestors

The probability of failure is very high: – one has already failed – another has been removed – a third is suspect

Existing surge arrestors may not be protecting transformers.

No spare parts

Mica staff monitoring electrical behaviour for signs of imminent failure with every switching event.

5 – 7 days per Surge Arrestor or one month per unit (3 surge arrestors per unit).

One generator out of service.

No spare parts.

Surge arrester must be removed or substituted.

6 weeks outage to remove and repair associated damage.

6 months to obtain new technology replacement.

Risk of catastrophic transformer failure increased.

Existing surge arresters are an obsolete technology.

Modern metal oxide surge arrestors are demonstrably better at protecting transformers than the existing gap type surge arresters.

Disconnect switches and bus in Transformer Chamber

The probability of failure is very high.

Motor operating mechanisms on disconnects do not function properly and are not repairable.

Existing disconnects are first generation of GIS equipment and there have been several past failures. To reduce risk of failures, operating restrictions are imposed on how disconnect switches are operated. Need to de-energize units on either side to operate – consequently operation results in short outage in all cases.

Extensive partial discharge has been found in most disconnect operating rods indicating electrical breakdown activity. Operating rods with the highest risk have been replaced.

Partial discharge has also been detected in several other locations. Repairs at other partial discharge locations would require extensive dismantling and refurbishing.

3 – 4 months to replace the GIS for one or two units.

Replacing two units at a time would minimize outage times and costs.

Long lead times and customized design work required.

Two coincident failures could result in full Mica outage depending on location.

Any repair requires extensive scaffolding, rigging and dismantling.

Enables remote operation, alleviating staff resources and improve operating efficiency.

Newer technology disconnects will not impose any operating restrictions.

Reduced risk of fault and resulting forced outage.



4-12


Forced Outage Consequence

Benefits of New Equipment

Disconnect switches and bus in switchgear building

Same as above. Same as above but can transfer power from 3½ units up alternate lead shaft during replacement. Limit dictated by transmission restrictions.

Failure of one disconnect switch could result in extended ½ unit outage.

Enables remote operation.

Reduced risk of fault and resulting forced outage.

GIS in Lead Shaft 1 & 2

Deteriorated condition of solid insulators is associated with increased risk of failure.

Equipment is at steep inclines in confined space so any failure is difficult to repair.

Condition of solid insulators and SF6 seal systems have deteriorated and require replacement.

Some spare bus parts.

Mica limited to transferring only 3½ units of power up single lead shaft because of MSSC limitations.

See alternatives in Table 4-3.

Based on the 1984 lead shaft repair at Mica and similar repairs carried out at Revelstoke, a faulted bus section in a lead shaft in Mica can be expected to take between one to three months to repair depending on the location of the fault, the phase of bus affected and the availability of skilled workers and supervisors. The work would not extend the useful life of equipment.

Mica output is reduced by 300 MW if one lead shaft is out of service.

Mica would be out of service for extended period of time if the second lead shaft fails.

Reduced risk of failure

New equipment would provide an estimated life of 50 years

New equipment would be more cost effective than refurbishing

Better monitoring of SF6 pressure. Partial discharge activity will be monitored to better provide warning of impending failure.



4-13

4.2.3.3 Condition Assessment Summary 1

Based upon the condition assessment work performed by external GIS experts and 2

BC Hydro, the condition assessment of the GIS is summarized in Figure 4-2. 3

Figure 4-2 Condition Assessment Summary 4

Lead

Sha

ft

Lead

Sha

ft

500 kV16 kVP

ower

hous

eS

witc

hgea

r Bui

ldin

g

4.3 Identification of Project Benefits 5

In addition to the purpose of the Project, namely to maintain the reliability of Mica, there are 6

benefits that will be realized with the implementation of the Project. 7



4-14

4.3.1.1 Disconnect Switches 1

One of the benefits from the Project will be to improve worker safety at Mica. Currently, the 2

existing disconnect switches have disconnect motors that do not operate as intended and as 3

a result, manual operation of the disconnect switches is required. Such operations introduce 4

the risk of operator error and pose potential electrical contact risk to workers. This risk is 5

currently being managed through BC Hydro safe work practices and site-specific operating 6

instructions. The disconnect switches can also only be operated when the bus is 7

de-energized. In some cases, this requires a two unit outage and impacts the operating 8

flexibility of Mica. 9

Replacing the GIS provides an opportunity to address this issue while also improving the 10

layout or architecture of the GIS. This latter benefit, also results in safety benefits as 11

equipment is made more accessible for maintenance and repair, as described further below. 12

4.3.1.2 Maintenance Access 13

Currently access for repair of the GIS requires the construction of temporary structures as 14

shown in Figure 4-3. For example, in 2008, scaffolding was erected to remove the failed 15

surge arrestor. Lifting equipment had to be rigged from the roof. Temporary rigging is 16

required to lift many types of heavy equipment currently. This temporary rigging often does 17

not provide an optimum configuration and as a result, workers are required to perform 18

considerable manual lifting which puts them at risk of strains and sprains. Figure 4-4 is 19

another view showing the height at which the GIS is currently located. 20

Worker safety and access to the equipment can be improved through the addition of cranes 21

and partial mezzanines. 22

The Project is designed to include structural safety improvements including an overhead 23

crane and a mezzanine. These additions reduce risks to workers by improving access, and 24

reduce repair time by providing a crane which can safely remove and install equipment, 25

eliminating the need for workers to lift heavy equipment or work from scaffolding. Figure 4-5 26

is a computer generated three dimensional image showing the improved GIS layout on the 27



4-15

mezzanine along with the new crane which will allow for easy installation and removal of 1

GIS components. 2

Figure 4-3 Repair of Surge Arrestor under Existing GIS Layout 3



4-16

Figure 4-4 Height of Existing GIS 1



4-17

Figure 4-5 Improved GIS Layout 1

4.3.2 Environmental Benefits 2

SF6 is used in three BC Hydro generating stations and at various BCTC operated 3

substations because of its electrical insulating properties. SF6 is a potent GHG: 1 kg of SF6 4

is equal to 23,900 kg of CO2 equivalent. The GIS leaks an excessive amount of SF6 and 5

more significant leaks are expected to develop over time as the equipment ages. In 2008, a 6

total of 565 kg of SF6, representing a leakage rate of 3.8 per cent per year, leaked at Mica. 7

Due to the GHG intensity of SF6, this amount is equivalent to 13,503 tonnes of CO2. 8

The “O” rings, which provide a seal between the bus flanges, have a finite life. BC Hydro 9

has taken measures to reduce SF6 leakage by in part replacing “O” rings where practicable. 10



4-18

However, the “O” rings in the bus in the lead shafts are difficult and costly to replace due to 1

the design of the equipment. As identified in the Edgar Heil condition assessment, these 2

remaining “O” rings are likely to begin to fail soon as a result of their age, resulting in more 3

significant SF6 gas leaks. In addition, the replacement of “O” rings does not improve the 4

reliability of the vast majority of bus cone insulators in the lead shafts, which are a more 5

critical reliability concern. 6

For new GIS, the current industry standard leakage rate is 0.5 per cent per year. New GIS 7

equipment being installed in Japan and Europe is achieving leakage rates of 0.1 per cent 8

per year or less. GIS installations at Revelstoke and Seven Mile GS are currently achieving 9

nearly zero losses. 10

BC Hydro has specified that MEPPI must meet standards of 0.5 per cent leakage or less 11

per year. However, based on typical performance of modern equipment it is reasonable to 12

expect near zero leakage. 13

4.3.3 Benefit to Mica Units 5 and 6 14

In order to operate Mica with six units, GIS is required in all three lead shafts. The Project 15

reduces the scope of a future Mica Units 5 and 6 project by eliminating the need to include 16

installation of GIS in lead shaft 3 and extension of the switchgear building in that project. As 17

a result, the Project will benefit these units by enabling them to achieve an earlier ISD. 18

In the 2008 LTAP, Mica Units 5 and 6 are identified capacity resources required in 19

2013 (F2014) and 2015 (F2016) respectively in the CRP, while in the 2008 LTAP Base 20

Resource Plan (BRP) Mica Unit 5 is a required capacity resource in 2024 (F2025). The 21

Project allows for Mica Units 5 and 6 to achieve the ISDs required in the CRP. 22

4.4 Architecture Evaluation and Selection 23

This section discusses the process BC Hydro undertook to analyze and evaluate various 24

architecture alternatives to replace the GIS. This process led to BC Hydro’s 25

recommendation of new GIS architecture to replace the existing GIS. Also, this section 26

discusses BC Hydro’s consideration of the external GIS experts’ recommendations in the 27

selection of architecture for the Project. 28



4-19

4.4.1 Problem Scope and Architecture Options 1

Section 4.2.3 presented the conclusions and recommendations made by three external GIS 2

experts. The focus of each expert was how to reduce the risk of forced outages posed by 3

the GIS. Once it became clear to BC Hydro that a significant investment would be required, 4

BC Hydro broadened the scope of the investigation. The broader investigation scope 5

included the consideration of delivering additional benefits such as improved safety for 6

workers, improved maintenance access for workers, and reduced leakage of SF6. 7

BC Hydro considered a number of options for GIS replacement architectures. Alternatives 8

and evaluation criteria were based on BC Hydro’s user requirements developed through 9

consultation with the Project Initiator and other BC Hydro stakeholders. Initially, high level 10

options were considered including some with architecture that would, if practical, 11

significantly alter the configuration of Mica. Also, while BC Hydro initiated the Project to 12

address the reliability risks posed by the aging GIS, consideration was also given to the 13

longer term requirements of a six unit Mica18 which requires GIS in all three lead shafts in 14

order to transmit the full output of six units. 15

Two of the architectures BC Hydro considered that did not include GIS were: 16

moving the 500 kV transformers out of the Mica powerhouse to the surface; and 17

using an insulating gas other than SF6. 18

However, BC Hydro concluded early in the process that the constraints of the underground 19

Mica powerhouse and technology did not permit the development of these architectures. 20

Also, SF6 gas is the only technology available for disconnect switches, circuit breakers and 21

surge arrestors for indoor 500 kV applications such as at Mica. 22

A structured decision making process was used to select the architecture that best 23

addressed BC Hydro’s requirements. As part of this process detailed engineering studies 24

18 Appendix H contains analysis of the number of lead shafts required for Mica GIS with four, five and

six generating units.



4-20

were conducted to help make architecture recommendations. Following this, the options 1

were analyzed to determine the best timing for replacement. 2

BC Hydro identified eight of the more practical architecture alternatives. The options 3

included architectures with either high or low side circuit breakers, different bus 4

arrangements in the transformer chamber and options using cross-linked polyethylene 5

(XLPE) cable in the lead shafts. These eight alternatives were further narrowed to four after 6

further evaluation. Of the four architectures that were studied, two (XLPE cable and 7

replacement GIS) were clearly superior and warranted further optimization and subsequent 8

restudy. Subject matter experts and quantitative data were used to score the final two 9

alternatives and select the best architecture for Mica. 10

As a result of the structured decision making analysis, BC Hydro concluded that: 11

Application of 500 kV XLPE cables in the lead shafts is not recommended for Mica based 12

on the maturity of the technology, repair complexity, installation duration and the 13

configuration and technical requirements of Mica. Specifically: 14

knowledgeable personnel are available locally for GIS, but not 500 kV XLPE cable; 15

the cable alternative is not available with the same transfer capacity as GIS; 16

the initial cost of the cable alternative is estimated to be lower but had higher risks 17

because the technology had never been implemented in North America; 18

the cable has insufficient operational history, for its long-term performance to be 19

adequately assessed, particularly for 500 kV applications; 20

the cost over the life of the cable alternative was estimated to be higher than GIS due 21

to the cost of planned outages required for installation; and 22

the safety and environmental risks for both alternatives are estimated to be similar; 23

GIS is the only feasible technology for replacement of active components (circuit 24

breakers, disconnect switches, and surge arrestors) due to the space constraints of 25

locating equipment in indoor and underground locations; 26



4-21

The current architecture with circuit breakers on the low voltage side of the transformers 1

should remain; 2

Obsolete gap type surge arrestors should be replaced with modern metal oxide surge 3

arrestors; 4

Disconnect switches should be replaced with ones that are more reliable and can be 5

operated remotely; 6

Worker safety and access to equipment in the transformer chamber can be improved by 7

installation of partial mezzanine and overhead crane; 8

A single bus architecture is preferable to a ring or double bus architecture in the 9

transformer chamber; and 10

An architecture can be developed that is more tolerant of equipment failure than the 11

current architecture. 12

4.4.2 Architecture Conclusions 13

A one line diagram of the ultimate layout for Mica was completed with a proposal that Mica 14

should be operated with GIS installed in all three lead shafts (refer to Figure 4-6). A 15

conceptual general arrangement was completed using three dimensional modelling to 16

confirm space requirements for new equipment in the Mica transformer chamber. 17



4-22

Figure 4-6 Mica GIS Ultimate Layout 1

Not in the scope of this project

Style Legend

Not In Scope

Replace

Remain

G1

T1

Circuit Breaker

Disconnect Switch

Transformer

Generator

Surge Arrester

Transmission Line

Reactor

5L71 5L72

G2

T2

G3

T3

G4

T4

G5

T5

G6

T6

New

4.4.3 Holm, Hampton and Heil Recommended Architectures 2

In this section, the GIS architectures recommended by the external GIS experts are 3

compared with the proposed Project. 4

Dr. Hampton’s recommended GIS architecture formed the basis of one of the architectures 5

considered. The basis for this architecture was the addition of a second bus in the 6

transformer chamber. Upon detailed analysis, it was concluded that: 7

1. the second bus provides limited reliability improvements once the primary bus is 8

replaced; and 9

2. the physical constraints of the transformer chamber makes it impractical to install the 10

second bus. 11

Mr. Holm’s recommendation is incorporated into the BC Hydro proposed architecture with 12

the exception of the spare phase of GIS. It would be difficult to add this spare phase due to 13

the space constraints in the transformer chamber. 14



4-23

Mr. Heil’s recommended architecture is similar to the architecture proposed by BC Hydro. 1

However, while Mr. Heil recommended that all “O” ring seals be replaced by the year 2012, 2

BC Hydro views this as being risky, expensive, and disruptive to Mica. BC Hydro is of the 3

view that replacing the GIS with architecture similar to that recommended by Mr Heil, and in 4

the timeframe recommended by Mr Heil is more appropriate. 5

4.5 Timing and Sequencing of GIS Replacement 6

4.5.1 Timing of GIS Replacement 7

Given the significant reliability risks posed by the existing GIS, the option to “do nothing” 8

was not considered viable. The existing GIS must be replaced and as a result of the process 9

described in section 4.4, BC Hydro proposes replacing the existing GIS with new GIS and 10

adding GIS to lead shaft 3. 11

BC Hydro’s analysis of the alternatives for the timing and sequencing of the GIS 12

implementation assumes in all cases that the GIS in lead shaft 3 would be completed first to 13

meet a Mica Unit 5 ISD of 2013 (F2014) and varies the timing for replacing the existing GIS 14

in lead shaft 1 and 2. Four primary alternatives for the timing and sequence of the BC Hydro 15

proposed architecture were considered for replacement: 16

1. Replacement of the aging GIS with new GIS equipment by 2013 (Alternative 1); 17

2. Alternative 1 but defer the replacement by five years (Alternative 2a) or ten years 18

(Alternative 2b); 19

3. Replacement of the existing GIS as a series of smaller projects between 2010 and 20

2017, rather than a single project (Alternative 3); and 21

4. Alternative 1 with the exception of deferring the replacement of the GIS in lead shafts 1 22

and 2 (Alternative 4). 23

The analysis in section 4.5.3 considers variation of the ISD of Mica Units 5 and 6. 24

The cost of each of the four alternatives is evaluated taking into account a range of probable 25

outage costs, the capital investment required, and the cost of GHG emissions. 26



4-24

The actual cost of an outage at Mica can vary significantly depending on the time of year, 1

the market price of capacity and energy, and demand. Table 4-2 shows the life cycle 2

PV cost of each alternative under three scenarios of low, moderate and high outage costs 3

ranging from $6 million to $19 million19. An inverse relationship is applied such that there is a 4

higher probability of a low cost outage compared to a high cost outage. As the existing 5

equipment is aging, the probability of failure is increased by one per cent per annum. 6

Table 4-2 PV of Replacement Alternatives 7

Schedule for GIS component Installation/Replacement

1 2 3 4 5 6 7 8 9 10 11 12 13Low Cost

($6 M)Moderate

Cost ($12 M) High Cost

($19 M)

Activity 2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

Probability(33%)

Moderate Probability

(25%)

Low Probability

(15%)Alternative 1

Replace Existing GIS $61Lead shaft 3 and interface $56

PV of project costs $117 $117 $117 $117Range of Outage costs $5 $8 $8GHG Credit Cost $1 $1 $1Range of Adjusted PV of Project $123 $126 $126

Alternative 2 a

Replace Existing $54Lead shaft 3 and interface $53


Alternative 2 bReplace Existing $46Lead shaft 3 and interface $53


Alternative 3Replace Existing $65Lead shaft 3 and interface $53


Do Nothing - Defer implementaion of Project by 5 years

PV Project and Outage Costs(in $millions)

Outage probability increasing by 1% per year

Implement project piecemeal over time

Do Nothing - Defer implementaion of Project by 10 years

PV Project

Cost

Full implementation of Project by 2013

Alternative 4Replace existing GIS in tranformer chamber and switchgear building

$42

Lead shaft 3 and interface $56Lead shafts 1 and 2 $20


Same as Alternative 1 but defer replacement of lead shafts 1 and 2

Note: For Alternatives 2a, 2b and 3, the activity “lead shaft 3 and interface” PV of $53 million is calculated 8 based on an in-service date in 2012 whereas for Alternative 1 and Alternative 4 the PV is $56 million for 9 an in-service date of 2011. 10

19 For details on the range of outage costs refer to section 3 and section 4 of Appendix I.



4-25

As shown in Table 4-2, the life cycle PV cost20 of Alternative 1 is not significantly different 1

than the PV of Alternatives 2(a) and 2(b) (deferring the Project by five or ten years), when 2

the potential cost of outages is included. For moderate and high outage consequences, 3

replacing the GIS now is the least cost alternative. 4

Alternative 3, “a series of smaller projects”, is an estimate of the increase in cost if the GIS 5

were run to failure. Replacing the existing GIS in a series of small projects is the most 6

expensive option as the cost to design, engineer, supply and install increase significantly if 7

portions of the Project are deferred. The design and engineering of bus and interfaces is 8

customized or unique to each location. Deferring any portion of the Project would require the 9

duplication of design and engineering work by both the supplier and BC Hydro. The unit cost 10

of manufacturing is also expected to increase as the size of the order decreases. Additional 11

mobilizing and training costs are also expected to be incurred if the Project is segmented. 12

The replacement cash flows were escalated by 15 per cent to reflect the incremental 13

procurement and mobilization costs, and $3 million is included for additional engineering 14

and planning costs. BC Hydro is of the view that the actual planned and forced outage costs 15

for this alternative are likely to be much higher than indicated in Table 4-2. 16

Alternative 4 (deferring replacement of GIS in lead shafts 1 and 2) is more expensive than 17

Alternative 1 since, like Alternative 3, there will be additional costs as a result of the work 18

being broken into separate projects. 19

Given that the existing Mica 500 kV GIS poses substantial reliability risks to BC Hydro, it 20

was concluded that deferral was not an option. Alternative 1 has the lowest life cycle PV 21

cost under moderate and high outage scenarios. Additionally, Alternative 1 realizes the 22

safety and environmental benefits at the earliest date, allows the development of an 23

improved GIS design and architecture, and allows replacement of the aging GIS with new 24

GIS equipment by 2013. As a result, Alternative 1 is the proposed alternative. 25

4.5.2 Planned Outage Requirements for Alternatives 26

Different implementation or staging strategies for the GIS replacement have a significant 27

impact on the planned outage required and the Project risks. The proposed Project 28

20 For the basis of the PV project costs shown in Table 4-2, refer to section 5 of Appendix I.



4-26

recommends building the switchgear building extension and installing GIS in lead shaft 3 1

first. The switchgear building extension will also serve as a clean storage and working area 2

while replacing the existing GIS. 3

If lead shaft 3 and the switchgear building extension are in place, it is possible to implement 4

the full Project scope over four years with planned spring outages in two of the years. 5

Staging analysis for the proposed Project scope indicates that it would be possible to 6

construct the GIS in lead shaft 3 as non-outage work prior to the first spring outage in 2011. 7

All remaining work would then occur in a four month spring outage in 2011 and a 8

subsequent four month outage in spring of 2012, during periods when the cost of the 9

outages are significantly lower. 10

If the scope of the Project were to only include the replacement of the existing GIS, it would 11

result in longer planned outages and increase the Project schedule and reliability risk. 12

Replacement of the existing GIS would require four consecutive years of four month 13

outages. The critical work in the transformer chamber and switchgear building would occur 14

in the first two outages and each lead shaft would be replaced in each of the following two 15

years during similar spring outages. The requirement for four separate outages is driven by: 16

space constraints for staging work (since the switchgear building would not have been 17

extended) and schedule and outage risks associated with undertaking the lead shaft 18

replacement and the transformer chamber replacement concurrently. Figure 4-7 below 19

illustrates the approximate reliability realization in time with the two options (GIS in lead 20

shaft 3 first versus replacing existing GIS only). The area between the curves is the net 21

resulting reduction in exposure to outages based on the two options. Building lead shaft 3 22

and extending the switchgear building first provides early improvements and significantly 23

reduces exposure to forced outages. Table 4-3 provides additional details on the outage 24

requirements for the replacement of the GIS in lead shafts 1 and 2 with and without GIS in 25

lead shaft 3. 26



4-27

Figure 4-7 Reliability Realization from Staging Lead Shaft 3 First 1

0%

20%

40%

60%

80%

100%

2010 2011 2012 2013 2014Year

Rel

iabi

lity

Rea

lizat

ion

Lead Shaft 3 FirstOnly Replace Existing



4-28

Table 4-3 Replacement of Lead Shaft 1 and 2 with or without Lead Shaft 3 in Place 1


Forced Outage Consequence Benefits of New Equipment

Replace GIS in lead shafts 1 or 2 without lead shaft 3 in place

Curtail transfer of power to 3½ units for alternate lead shaft.

3 – 4 months outage to replace. (Cannot replace transformer chamber equipment and switchgear building equipment and lead shaft bus in the same calendar year without lead shaft 3).

Curtails power transfer on alternate lead shaft to 3½ units.

During single lead shaft outage the plant is exposed to risk of complete outage for many second contingency failure events in the GIS.

Same consequence of failure in future as existing plant.

Replace GIS in lead shafts 1 or 2 with lead shaft 3 in place

Addition of third lead shaft recommended by external consultants as this significantly improves reliability of entire Mica.

5 – 8 day outage to disconnect and reconnect. 3 – 5 months to replace but can be done without outage. Replacement can be at same time as outage for disconnects

Provides contingency in event of failure in either lead shaft 1 or lead shaft 2.

Loss of one lead shaft out of three should not impact plant generation output.

Very robust architecture that allows minimal disruption in the case of one lead shaft bus outage and most possible second contingency GIS failure events.

Significantly reduces consequence of failure in future.

Lead shaft 3 is required, in any event, for the proposed Mica Units 5 and 6 capacity addition.



4-29

4.5.3 Sensitivity Analysis for Mica Units 5 and 6 ISDs 1

Given the uncertainty as to the ultimate ISD for Mica Units 5 and 6, this section compares 2

the Project PV based on the schedule in Table 3-1 with the PV of options which result in 3

implementing the proposed architecture but which have different ISDs based on later ISDs 4

for Mica Unit 5 of 2018 or 2025. These options could be undertaken if the actual ISD for 5

Mica Unit 5 was known for certain. All options compared have GIS being put into service in 6

the three lead shafts before Mica Unit 5 is put into service. Completing the GIS installation 7

for the proposed architecture assumes that at least a five unit Mica will be in place by at 8

least 2025. 9

In the analysis it is estimated that deferring portions of the Project may incur additional 10

procurement costs as BC Hydro would be ordering less GIS bus with each individual project, 11

and there would also be a duplication of engineering costs and mobilization costs. Savings 12

from use of tools, training, skill development and fixed costs of work plans, high-angle 13

rescue plans and in-place project/construction management structure make the incremental 14

cost of doing the full replacement now low compared to tendering the work separately. In 15

addition, changes in Project scope do not reduce certain fixed Project costs (refer to 16

Appendix I for details of the financial analysis). This analysis only considers the time value 17

of the investment required and does not include a value for reduced planned outage time or 18

the possible forced outage consequences caused by failures in the lead shafts. 19

The analysis compares the PV of the Project cost for seven scheduling alternatives: 20

1. Base Case - Replace all existing GIS, install lead shaft 3 and extend the switchgear 21

building now. This assumes that Mica Unit 5 will have an ISD in 2013; 22

2. Defer lead shaft 1 and lead shaft 2 for Mica Unit 5 ISD of 2018 – Install lead shaft 3, 23

extend the switchgear building and replace the GIS in the transformer chamber and 24

switchgear building now. Defer lead shaft 1 and lead shaft 2 installation until just in 25

advance of the Mica Unit 5 ISD in 2018; 26

3. Defer lead shaft 3 and the switchgear building extension to the Mica Unit 5 ISD 27

of 2018 – Replace all existing GIS now. Lead shaft 3 and the switchgear building 28

extension is deferred and installed just in advance of the Mica Unit 5 ISD in 2018; 29



4-30

4. Defer lead shaft 1 for Mica Unit 5 ISD of 2018 – Replace lead shaft 2, install lead shaft 3 1

and replace GIS in transformer chamber and switchgear building now. Lead shaft 1 is 2

deferred and installed just in advance of the Mica Unit 5 ISD in 2018; 3

5. Defer lead shaft 1 and lead shaft 2 for Mica Unit 5 ISD of 2025 - Install lead shaft 3, 4

extend the switchgear building and replace the GIS in the transformer chamber and 5

switchgear building now. Lead shaft 1 and lead shaft 2 are deferred and installed just in 6

advance of the Mica Unit 5 ISD in 2025; 7

6. Defer lead shaft 3 and the switchgear building extension to the Mica Unit 5 ISD of 2025 - 8

Replace all existing GIS now. Lead shaft 3 and the switchgear build extension is 9

deferred and installed just in advance of the Mica Unit 5 ISD in 2025; and 10

7. Defer lead shaft 1 for Mica Unit 5 ISD of 2025 - Replace lead shaft 2, install lead shaft 3 11

and replace GIS in transformer chamber and switchgear building now. Lead shaft 1 is 12

deferred and installed just in advance of the Mica Unit 5 ISD in 2025. 13

Options 2, 3 and 4 assume a Mica Unit 5 ISD of 2018 while options 5, 6 and 7 assume a 14

Mica Unit 5 ISD of 2025. 15

In all of the options, there is a risk that the Project schedule cannot be met and the planned 16

outage extended. However, in options 3 and 6 the Project risks are greater because: 17

a. These options require planned outages spanning four years compared to two years. An 18

extension of the planned outage by one month, to include the month of August, is 19

estimated to have an opportunity cost in the range of $3 - $20 million. The variance is 20

largely due to varying trade benefits; 21

b. Generation must be curtailed by a minimum of 300 MW for four months in each of 22

four years; and 23

c. There is a risk that the GIS in the alternate lead shaft will fail during construction 24

compromising 1,500 MW of generation at Mica for an extended period. 25

The sensitivity analysis shows that if Mica Unit 5 is constructed at anytime before 2018 the 26

proposed option (base case) with a PV of $117 million is the least cost. If the Mica Unit 5 27



4-31

project is deferred to 2025, the PV of deferring portions of the project (as shown in 1

Options 5, 6 and 7) range from $114 million to $118 million21. Of these, option 6 with a PV of 2

$114 million is the least cost alternative. This is before considering the exposure of a 3

$3 to $20 million outage cost due to an extension in the Project schedule by one month in 4

both of the years that existing GIS in lead shafts 1 and 2 are replaced. There is the 5

additional risk of an entire plant outage should a failure occur in the alternate lead shaft. 6

Since the base case option meets the CRP for Mica Units 5 and 6, the risks associated with 7

option 6 do not justify deferring the installation of GIS in the third lead shaft by 12 years. It is 8

recommended that the full Project scope be implemented with an ISD of 2013 because the 9

risks and cost variances do not justify deferral. Table 4-4 compares the seven options. 10

21 For details on the costs for the seven options refer to section 7 of Appendix I.



4-32

Table 4-4 Sensitivity Analysis for Meeting Alternative Mica Units 5 and 6 ISD 1

Option/ Year

Present Value Cost ($millions) 20

10

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

$117 x x

$124 x x

$127 x x x x

$119 x x

$118 x x

$114 x x x x

$116 x x

LEGENDLead Shaft 3 and switchgear buildingLead Shaft 1Lead Shaft 2Base ComponentsPlanned Outage - 4 months xMica Unit 5 In-service date

MIC

A 5 IS

D

MIC

A 5 IS

D

5) Defer Lead Shaft 1&2 ten years

6) Defer Lead Shaft 3 ten years

7) Defer Lead Shaft 1 ten years

MIC

A 5 IS

D

1) Base Case - Do All Now

2) Defer Lead Shaft 1&2

3) Defer Lead Shaft 3

4) Defer Lead Shaft 1

Chapter 4 - Project Justification Project Justification


4-33

4.5.4 Recommended Project Scope 1

The scope of work for the Project has been developed. All original GIS in the transformer 2

chamber and switchgear building are to be replaced to maintain Mica reliability. The 3

disconnect switches and surge arrestors are at end of life, and the condition of the original 4

bus justifies replacement of all original GIS equipment. The addition of GIS equipment to 5

lead shaft 3 is identified as being key to the success of the Project, independent of the 6

proposed Mica Units 5 and 6 projects. Replacement of GIS in lead shafts 1 and 2 is flagged 7

as a high risk to the project schedule if done before GIS is installed in lead shaft 3. 8

Installation of GIS to lead shaft 3 and the related work to integrate lead shaft 3 results in 9

significant reliability improvement and can be done with relatively short and inexpensive 10

outages. 11

The key points for defining the scope of work for the Project are: 12

For the existing four-unit Mica, GIS in lead shaft 3 provides redundancy during 13

construction and ongoing operations; 14

GIS in lead shaft 3 reduces the planned outage required for replacement of the existing 15

lead shafts from months to days; 16

GIS in lead shaft 3 is required for any future installation of Mica Units 5 and 6; 17

Including GIS in lead shaft 3 significantly reduces planned outages once put into service; 18

and 19

Replacement of the GIS associated with Mica Units 1 to 4 and the remaining original 20

equipment in the switchgear building can be completed during spring outages in 2011 21

and 2012 when the costs of the outages are minimized. 22


Chapter

5

Public and First Nations Consultation


5-i

Table of Contents

5.1 Introduction.................................................................................................................5-2

5.2 General Consultation..................................................................................................5-2

5.2.1 Environmental Assessment ............................................................................5-2

5.2.2 Core Committee..............................................................................................5-3

5.2.3 Future Public Consultation..............................................................................5-4

5.3 First Nations Consultation...........................................................................................5-4

5.3.1 Identification of Interested First Nations..........................................................5-5

5.3.2 Expected First Nation Impacts ........................................................................5-6

5.3.3 First Nation Consultation Activities .................................................................5-7

5.3.4 Presentation of Project at Core Committee Meeting.......................................5-8

5.3.5 Project Notification Letter from BC Hydro .......................................................5-8

5.3.6 Project BCEAO Amendment...........................................................................5-9

5.3.7 Future First Nation Consultation Plan ...........................................................5-10

5.3.8 Adequacy of First Nations Consultation........................................................5-10 List of Tables

Table 5-1 First Nations and Tribal Councils Identified for Consultation .......................5-6

Chapter 5 - Public and First Nations Consultation


5-2

5.1 Introduction 1

This chapter discusses the consultation processes BC Hydro has undertaken with First 2

Nations and public stakeholders to identify issues specific to the Project. 3

5.2 General Consultation 4

As described in previous chapters, the addition of GIS to lead shaft 3 will reduce the 5

likelihood of outages caused by equipment failures. Three lead shafts will also be required if 6

BC Hydro installs an additional generating unit at Mica. As lead shaft 3 may be used for 7

future interface and operations of Mica Units 5 and 6, the Project was included as a 8

component of the Mica Units 5 and 6 project description to be considered for review under 9

the BCEAA process. Pursuant to the BCEAA process, BC Hydro offered and conducted a 10

range of consultation activities to provide information sharing opportunities for interested 11

stakeholders and First Nations to understand and comment on the Project. This section 12

describes consultation activities associated with the BCEAA process, and those that were 13

components of BC Hydro’s consultative committee process. 14

5.2.1 Environmental Assessment 15

In March 2008, BC Hydro submitted project descriptions to the BCEAO to seek an BCEAC 16

for the Mica Units 5 and 6 projects. The project descriptions included an overview of the 17

Project and described the main components. A number of procedural documents were 18

issued by the BCEAO which made reference to the Project. 19

In July 2008, the BCEAO convened a project working group meeting to discuss the 20

proposed project (including Mica Units 5 and 6) and draft procedural documents. 21

Government agencies, stakeholders, First Nations and Tribal Councils were invited to attend 22

and provide comments. No issues or comments were raised in regards to the Project. 23

On September 17, 2008, BC Hydro and the BCEAO conducted a site visit to Mica. All 24

members of the project working group, which included the 25 First Nation and Tribal 25

Councils identified in the BCEAA section 11 and 13 Procedural Orders were invited to 26

attend. Representatives of the BCEAO, the BC Ministry of Environment, the Columbia 27



5-3

Shuswap Regional District, Okanagan Nation Alliance, Ktunaxa Nation Council, Little 1

Shuswap, Splatsin, as well as some BC Hydro staff at Mica participated. The location of the 2

current building and proposed extension of the switchgear building were pointed out. No 3

concerns were raised by any of the attendees. 4

Since the Project was included in the Mica Units 5 and 6 BCEAA process, replacement of 5

the GIS equipment could not start prior to the issuance of the Environmental Assessment 6

Certificate. However, due to a significant extension of the Mica Units 5 and 6 First Nation 7

consultation timeline, BC Hydro requested the BCEAO approve an amendment to remove 8

the Project from the BCEAA process to preserve the Project schedule (Appendix K-1). 9

It should be noted that BC Hydro made the request for the amendment after most of the pre-10

application consultation had occurred for the Mica Units 5 and 6 projects, during which no 11

concerns had been raised by First Nations. On April 17, 2009, the BCEAO approved the 12

request and granted BC Hydro an amending order, which removed the Project from the 13

Mica Units 5 and 6 BCEAA process (Appendix K-3). The steps taken by the BCEAO to 14

consult with First Nations prior to issuing the amendment are outlined in section 5.3.4. 15

5.2.2 Core Committee 16

A key consultative tool for the Mica Units 5 and 6 project, was the core committee process 17

which began in January 2008 and completed in May 2009. This process was developed by 18

BC Hydro to provide a facilitated and structured process of committees and meetings to 19

integrate First Nation and stakeholder values into environmental assessment and water use 20

planning decisions related to the potential incremental impacts of the Mica Units 5 and 6 21

project. Participants included: 22

federal and provincial agencies; 23

local government representatives; 24

First Nations; 25

former Columbia Water Use Plan and Revelstoke Unit 5 Core Committee members; 26



5-4

not-for-profit organizations; and 1

interested community individuals. 2

On January 29, 2009, during a core committee meeting at the City of Revelstoke, BC Hydro 3

made a presentation on the Project. BC Hydro’s presentation materials for this meeting are 4

contained in Appendix J-3. In the presentation BC Hydro explained: 5

the purpose of the Project and the switchgear building extension; 6

the need for the switchgear maintenance and refurbishment work; 7

the connection to the Mica Units 5 and 6 project; 8

the expectation that there would be no environmental or heritage impacts; 9

the contract and procurement timelines; and 10

the possibility of employment opportunities. 11

Participants in the meeting, including First Nations representatives, did not raise any 12

concerns related to the Project. 13

5.2.3 Future Public Consultation 14

In support of the Mica Units 5 and 6 projects, BC Hydro created a webpage for the public to 15

view project information. On May 29, 2009, BC Hydro posted Project content on its website 16

and sent local stakeholders a newsletter about current and planned upgrades at Mica. 17

Further newsletters and website updates will be provided throughout the Project as 18

appropriate. 19

5.3 First Nations Consultation 20

This section identifies the First Nations that may be impacted by the Project, describes the 21

First Nation consultation activities in support of the Project, including the consultation that 22

has taken place and proposed activities as the Project proceeds. 23



5-5

The objectives of this consultation in respect of those First Nations, whose rights or interests 1

are potentially impacted by the Project, are to: 2

ensure that the First Nations are provided with all appropriate and relevant information 3

associated with the Project so that the First Nations understand the nature and potential 4

impacts of the Project; 5

receive any input from the First Nations on the Project; 6

ensure that any potential adverse and beneficial impacts on the First Nations’ 7

rights or interests are clearly understood by BC Hydro and the First Nations; and 8

where First Nations are potentially adversely impacted by the Project, work with the First 9

Nations to identify possible strategies for avoiding or mitigating such impacts and, to the 10

extent avoidance or mitigation of impacts is not possible, discuss and develop with the 11

affected First Nation, other potential accommodation options. 12

5.3.1 Identification of Interested First Nations 13

Mica is located on the Columbia River about 130 km upstream from Revelstoke, and 135 km 14

upstream of the City of Revelstoke (refer to Figure 3-1). Based on a review of consultative 15

boundary maps provided by the Province, and maps of Statement of Intent (SOI) areas 16

submitted by First Nations in the British Columbia Treaty Commission process, BC Hydro 17

determined that the Project lies within the collective traditional territory of the Ktunaxa, 18

Okanagan, and Shuswap Nations which are comprised of 29 First Nations and four Tribal 19

Councils. Additionally, Lheidli T’enneh First Nation’s consultative boundary is situated just 20

north of Mica. 21

Through information sharing and discussions with First Nations, Tribal Councils, and the 22

BCEAO, 22 First Nations and three Tribal Councils were identified as having a potential 23

interest in the Mica Projects (Mica Units 5 and 6, and GIS). Table 5-1 lists the First Nations 24

and Tribal Councils that were identified and subsequently contacted. 25



5-6

Table 5-1 First Nations and Tribal Councils Identified for Consultation 1

First Nation/Tribal Council/Association Shuswap Nation Tribal Council

(SNTC) Ktunaxa Nation Council (KNC) Okanagan Nation Alliance (ONA) Other

Adams Lake Columbia Lake Okanagan Lheidli T’enneh

Bonaparte Lower Kootenay Osoyoos Kamloops St. Mary’s Lower Similkameen

Little Shuswap Tobacco Plains Penticton Neskonlith Upper Nicola Shuswap Upper Similkameen Simpcw Westbank

Skeetchestn Splatsin

Whispering Pines

5.3.2 Expected First Nation Impacts 2

BC Hydro anticipates that the Project will have minimal, if any, adverse impacts on First 3

Nations or Tribal Councils for the following reasons: 4

Most of the work on the Project will occur underground within the existing powerhouse 5

and three lead shafts; 6

The Project will have no impact on the Kinbasket or Revelstoke reservoirs; 7

Although the Project will have an incremental footprint impact due to an extension of the 8

existing switchgear building: 9

the works will occur on previously disturbed lands owned by BC Hydro; and 10

the extension area was assessed under the Mica Units 5 and 6 BCEAA process and 11

no potential heritage or environmental impacts or other concerns were identified. 12

Environmental and social impacts are addressed in section 3.6. 13



5-7

5.3.3 First Nation Consultation Activities 1

The First Nations and Tribal Councils were contacted to determine their interest and 2

requirements for consultation and communications. Consultation activities included the 3

following: 4

Consultative Processes: All 25 First Nations and Tribal Councils were invited to 5

participate as members of the BCEAA, core committee or sub-committee process, and/or 6

engage in consultation directly with BC Hydro. 7

Capacity Funding: To facilitate participation of First Nation and Tribal Council 8

representatives in meaningful consultation and BCEAA activities, BC Hydro offered initial 9

capacity funding to ensure participants were provided with opportunities to review project 10

materials, determine level of interest, and identify potential project-related impacts. 11

BC Hydro advised First Nations and Tribal Councils that should they require more 12

extensive resources, further capacity funding would be provided though Comprehensive 13

Capacity Funding Agreements (CCFAs). Opportunities to receive capacity funding were 14

outlined in project letters, discussed during follow-up phone calls and further explained 15

throughout all of the project meetings. BC Hydro has an ongoing commitment that should 16

any First Nation or Tribal Council require capacity funding, BC Hydro is prepared to work 17

with them to ensure they have sufficient resources to facilitate their participation in 18

consultation activities. 19

Participation in Environmental Studies: BC Hydro invited interested First Nations or 20

Tribal Councils by letter and through follow-up phone calls to participate on field teams to 21

conduct wildlife and vegetation, fisheries, and archaeology studies. Ktunaxa Nation 22

Council, Okanagan Nation Alliance, Splatsin, Little Shuswap, and Adams Lake were 23

active participants as determined by their interest. Field studies included an assessment 24

of the proposed area for the switchgear building extension. All 25 First Nations and Tribal 25

Councils were provided with copies of the completed project studies for review and 26

comments. BC Hydro offered to engage in direct consultation to review and address any 27

issues that were identified. Upon review of the completed project studies, no First Nations 28

or Tribal Councils raised any issues specific to the Project. 29



5-8

Traditional Use Studies: BC Hydro offered capacity funding for First Nations and Tribal 1

Councils to gather and submit traditional use information to inform BC Hydro’s 2

understanding of potential impacts. BC Hydro provided terms of reference which outlined 3

the study area which should include the proposed area for the switchgear building 4

extension. Six First Nations and two Tribal Councils representing ten additional First 5

Nations are currently involved in gathering traditional use information. The deadline for 6

Final Reports is October 2009. Any issues identified in these reports that relate to the 7

Project will be addressed accordingly. 8

Site Visits: As outlined in section 5.2.1, on September 17, 2008, the BCEAO hosted a 9

tour of Mica. Members of the Okanagan Nation Alliance, Ktunaxa Nation Council, Little 10

Shuswap, and Splatsin attended. During the site visit the location of the switchgear 11

building extension was pointed out. No concerns were raised by any of the attendees. 12

A separate site visit was requested by the Ktunaxa Lands and Resources Committee and 13

was held on May 26, 2009. As part of a comprehensive tour to view the major 14

components of the Mica Units 5 and 6 projects, participants viewed the three lead shafts 15

from the powerhouse to the interconnection point at the existing switchgear building, the 16

flange sections where much of the leakage of SF6 gas seems to occurs were pointed out, 17

and the site for the proposed switchgear building extension was inspected for potential 18

environmental impacts. No issues were raised by any of the participants. 19

5.3.4 Presentation of Project at Core Committee Meeting 20

As outlined in section 5.2.2, a presentation on the Project was given at the January 29, 2009 21

Core Committee meeting at the City of Revelstoke. This meeting was attended by 22

environmental technical representatives for the Ktunaxa Nation Council and the Okanagan 23

Nation Alliance. None of the core committee participants raised any concerns related to the 24

Project. 25

5.3.5 Project Notification Letter from BC Hydro 26

On February 19, 2009, BC Hydro sent a “Switchgear Replacement Project” Notification 27

Letter (Notification Letter) to all 25 First Nations and Tribal Councils indicating BC Hydro 28



5-9

would be performing work to extend the switchgear building to accommodate the installation 1

of new and replacement switchgear (Appendix J-2). The Notification Letter included: 2

a Google Earth Photo of Mica GS Showing switchgear building; 3

a photo of the existing switchgear building; 4

a rendering showing what the switchgear building will look like with the extension; and 5

a diagram showing an architectural view of how the lead shafts connecting the 6

switchgear building to the underground powerhouse. 7

In the Notification Letter, BC Hydro provided an overview of the environmental assessment 8

findings, offered capacity funding, and invited First Nations and Tribal Councils to contact 9

BC Hydro if they are concerned that the Project may affect Aboriginal rights or interests. 10

On March 31 and April 1, 2009, follow-up phone calls were made to all 25 First Nations and 11

Tribal Councils identified in Table 5-1 to confirm their receipt of the Notification Letter and to 12

determine if they had any questions or concerns. 13

A complete list of the record of contact is included in Appendix J-1. 14

No issues were raised by any of the First Nations or Tribal Councils and no requests were 15

made to receive any capacity funding. As of the June 25, 2009, no further comments or 16

issues have been raised by First Nations or Tribal Councils either directly to BC Hydro or 17

through ongoing consultation meetings in support of Mica Units 5 and 6. 18

5.3.6 Project BCEAO Amendment 19

As described in section 5.2.1, on April 17, 2009, the BCEAO issued an amendment order 20

(Appendix K-3) removing the switchgear building extension from the Mica Units 5 and 6 21

BCEAA process. 22

Prior to this, on March 23, 2009, the BCEAO sent an email with a copy of the draft 23

amending order to First Nations and Tribal Councils listed in Table 5-1 to provide an 24



5-10

opportunity for representatives to raise any questions or concerns (included in 1

Appendix K-2). The email outlined the background and scope of the Project and the 2

switchgear building extension, reviewed completed activities to assess the potential for 3

environmental impacts, and highlighted no issues were raised during the site visit or through 4

the core committee process. 5

First Nations and Tribal Councils were asked to contact the BCEAO prior to April 3, 2009 6

with any comments or specific concerns about the removal of the switchgear building 7

extension work from the Mica Units 5 and 6 BCEAA approved Terms of Reference and the 8

draft amending order. No First Nations responded with any comments or concerns. 9

5.3.7 Future First Nation Consultation Plan 10

BC Hydro will continue consultation with First Nations and Tribal Councils as the Project is 11

implemented. BC Hydro will provide additional information updates when applicable and will 12

respond to any questions of information requests that may be received regarding the 13

Project. BC Hydro will work to understand and address any concerns or issues that are 14

raised by First Nations and Tribal Councils and where appropriate, BC Hydro will engage in 15

discussions with First Nations and Tribal Councils to further identify means to mitigate, 16

minimize and otherwise accommodate any concerns or issues relating to the Project. 17

5.3.8 Adequacy of First Nations Consultation 18

Taking into consideration the following factors, BC Hydro is of the view that the consultation 19

conducted for the Project is adequate: 20

Information shared through the BCEAA, consultative committee processes, Notification 21

Letters, field work, and site visits provided adequate opportunities for First Nations and 22

Tribal Councils to understand the scope of the Project and to raise comments or 23

concerns; 24

No First Nations or Tribal Councils expressed any concerns or interest in engaging in 25

consultation or discussions following a Project Notification Letter that was sent by 26



5-11

BC Hydro to all 25 First Nations and Tribal Councils, and subsequently followed-up by 1

phone; 2

First Nations and Tribal Councils were offered capacity funding to review Project 3

materials, participate in the BCEAA and consultative committee processes, attend site 4

visits, and engage in community and Chief and Council discussions to identify issues 5

relating to the Project; 6

No First Nations or Tribal Councils expressed any concerns or interest in engaging in 7

consultation or discussions with the BCEAO following a Project amendment letter that 8

was sent by BCEAO to all 25 First Nations and Tribal Councils; 9

It is anticipated that the Project will have minimal, if any, adverse impacts in First Nations 10

or Tribal Councils for the reasons described in section 5.3.2; 11

BC Hydro has been consulting with the identified First Nations since March 2008 and will 12

continue to inform First Nations about the Project through the implementation phase as 13

required and will address any issues as they arise; and 14

BC Hydro will address any issues connected to Project that arise from the Traditional Use 15

Studies (TUS) and/or Aboriginal Interest and Use Studies (AIUS). 16


Chapter

6

Project Risks and Risk Management


6-i

Table of Contents

6.1 Introduction.................................................................................................................6-1

6.2 Definition Phase Risks................................................................................................6-1

6.2.1 Investment at Risk ..........................................................................................6-1

6.2.2 Environmental Regulatory...............................................................................6-2

6.2.3 First Nations....................................................................................................6-2

6.3 Implementation Phase Risks ......................................................................................6-3

6.3.1 Safety Risks ....................................................................................................6-3

6.3.2 Security Risk ...................................................................................................6-5

6.3.3 Capital Cost Risk ............................................................................................6-5

6.3.4 Schedule Risk During Construction ................................................................6-6

6.3.5 Risk of Labour Unrest during Construction .....................................................6-7

6.3.6 Congestion in the Mica Powerhouse during Construction ..............................6-8

6.3.7 Environmental Risk during Construction.........................................................6-8

6.3.8 SF6 Risk During Construction .........................................................................6-9

6.3.9 Contractor Credit/Counterparty Default ..........................................................6-9

6.3.10 Commissioning Risk .....................................................................................6-10

6.4 Operations Risks ......................................................................................................6-10

6.4.1 Failure and Outage Risk ...............................................................................6-10

6.4.2 Environmental Risk .......................................................................................6-10

6.4.3 Operating and Maintenance Costs ...............................................................6-11

6.5 Risk Summary ..........................................................................................................6-11 List of Tables

Table 6-1 Mica Project Risks Summary .....................................................................6-11

Chapter 6 - Project Risks and Risk Management


6-1

6.1 Introduction 1

This chapter describes the Project Definition and Implementation phase risks as well as 2

operational risks once the Project is complete. It does not address the risk to BC Hydro and 3

its customers of any shortfall in capacity that might occur as a result of a failure of the 4

Mica GIS. 5

Over the life of the Project, and consistent with BC Hydro’s standard project management 6

practices and procedures, risk screenings have been conducted to identify the major Project 7

risks and their associated mitigation strategies. This chapter provides a summary of the 8

material risks, plans to manage these risks, and any residual risks. 9

The risks associated with the Project are considered within the phases of the project life 10

cycle. In the Definition phase, the major risks are associated with the design, estimating, 11

and tendering processes. The main risks for the Implementation phase are construction 12

related. Equipment risks once in service are primarily those associated with performance 13

and maintenance of the GIS. 14

6.2 Definition Phase Risks 15

Although normally an Implementation phase activity, the Project design, supply and install 16

contract was tendered in December 2008 during the Definition phase of the Project to 17

provide for greater cost certainty before deciding to proceed to Implementation phase. 18

Accordingly this reduced the cost risk. Further development risks arise as a result of the 19

regulatory approval process and related First Nations consultation. These risks are 20

addressed in the subsections below. 21

6.2.1 Investment at Risk 22

BC Hydro seeks per section 44.2(3)(a) of the UCA that the BCUC accepts that the capital 23

expenditures for the Project are in the public interest. If approval for Implementation phase 24

is not granted, the remaining Project investment is at risk. Rather than proceed, BC Hydro 25

may defer the Project. If the Project is deferred there will be investment at risk. If the Project 26

is deferred in January 2010 then the investment at risk is estimated to be $43 million. If the 27



6-2

Project is deferred in April or December 2010 then the investments at risk would be 1

$58 million or $91 million respectively. 2

Although, BC Hydro awarded the contract for the GIS design, supply and install to MEPPI, it 3

retains the right to terminate the contract in the event BCUC or any other approval is not 4

granted. 5

6.2.2 Environmental Regulatory 6

There are no major environmental regulatory approvals required for the Project. However, 7

parts of the Project were included in the Mica Unit 5 project under the Mica Units 5 and 6 8

BCEAA review process – namely the addition of GIS to lead shaft 3, and the extension of 9

the switchgear building for GIS addition to lead shaft 3. These parts of the Project are 10

included in the Mica Unit 5 project under BCEAA because they are required for the 11

operation of Mica Units 5 and 6. Under BCEAA, the scope of a project must include all parts 12

of the project, and no part of the project can be constructed without the BCEAA approval 13

(certificate). So, if the Mica Unit 5 BCEAA process or certificate is delayed, it could delay the 14

addition of GIS to lead shaft 3, which is the necessary first stage of the Project. 15

This risk was partially mitigated by an April 17, 2009 Order under BCEAA (provided in 16

Appendix K-3), removing the switchgear building extension from the scope of the 17

Mica Unit 5 project. BC Hydro applied for this order because a delay in the BCEAA schedule 18

for the Mica Unit 5 project to accommodate further First Nations consultation put the 19

switchgear building construction schedule at risk. 20

6.2.3 First Nations 21

Inadequate First Nations consultation is a risk to regulatory approvals and the Project 22

schedule. BC Hydro consulted First Nations, as described in Chapter 5. BC Hydro submits 23

that the consultation conducted is adequate and meets the current standard for a 24

refurbishment project that is not adding capacity. No First Nations have indicated any 25

concerns with the Project, or any desire for further consultation or accommodation. 26



6-3

However, there is a risk that a First Nation could challenge the adequacy of consultation. 1

This may impact the BCUC approval process and consequently BC Hydro’s decision to 2

proceed with the proposed Project schedule. This risk is mitigated in part by the ongoing 3

consultation and updates that BC Hydro will be conducting on all the projects planned for 4

Mica over the coming years. This consultation is expected to include funding and 5

employment opportunities for those First Nations that are interested. 6

6.3 Implementation Phase Risks 7

The following are the risks that may occur during Implementation phase. The key risks at 8

this stage of the Project relate to safety, environment, cost escalation, schedule delays and 9

labour unrest. 10

6.3.1 Safety Risks 11

Safety risks are those with the potential to result in harm to workers or members of the 12

public. During construction, safety risks are being managed through the following 13

preventative measures: 14

During the Definition phase of the Project BC Hydro conducted a safety risk analysis 15

(safety hazard assessment), the results of this analysis will be communicated to 16

contractors so that BC Hydro’s recommendations may be incorporated into work plans; 17

BC Hydro conducted further safety reviews that incorporated both construction and 18

on-going maintenance safety considerations into the design of the new equipment, 19

facilities, and work plans, for inclusion in the tender specifications; 20

Tender documents include a copy of BC Hydro’s site specific Safety Management Plan, 21

and contractors are required to submit their own safety management plan in conformance 22

that: 23

indicates how the contractors would comply with BC Hydro’s “Site Specific Safe Work 24

Procedures”, as well as safety standards issued by WorkSafe BC and BC Hydro; 25



6-4

indicates how the contractors would comply with the BC Hydro Safety Management 1

Plan; and 2

provides for worker safety training. 3

During construction there will be dedicated construction and safety officers on site who 4

are further supported by BC Hydro’s Coordinator of Occupational Safety and Health 5

assigned to site operations. These representatives will monitor work to ensure that the 6

contractors are following safety plans and will intervene if unsafe conditions are identified. 7

During construction, work will be undertaken near live transformers and within the confines 8

of the underground transformer chamber. There is a low risk that a transformer may fail 9

catastrophically resulting in fire or explosion that causes harm to workers. A risk analysis 10

was undertaken to identify potential causes of failure and define preventative and mitigating 11

measures. Such measures include: 12

development of procedures for running the transformers under low load during periods of 13

construction; 14

monitoring the health of the transformers continually during the Project; 15

protecting the transformers from accidental contact from equipment, including the 16

installation of physical barriers; 17

providing enough air to ensure maximum venting of smoke from the transformer chamber 18

in the event of a fire; 19

making mandatory personal protective equipment for working in the transformer 20

chamber; and 21

development of an emergency evacuation plan for the people who will be working in the 22

transformer chamber during construction. 23



6-5

6.3.2 Security Risk 1

During construction there is an increased security risk. BC Hydro will assess the risk and 2

develop a security plan that will include measures such as: 3

training of on-site operations staff and contractors on site-security; 4

providing extra security guards where appropriate; 5

providing visible identification for staff and construction workers; and 6

installing new access locks on gates and doors. 7

6.3.3 Capital Cost Risk 8

As identified in Chapter 3, BC Hydro has completed an Implementation phase cost estimate 9

with a range of -10 per cent/+15 per cent. Cost risks are being managed by: 10

tendering the majority of work prior to the Implementation phase. BC Hydro now has a 11

fixed price contract with MEPPI for the supply and install of the 500 kV GIS; 12

obtaining fixed price bids for the switchgear building extension; 13

clearly defining the scope of the Project; 14

preparing unambiguous specifications; 15

basing the cost estimate upon costs from previous comparable projects. For instance the 16

Revelstoke Unit 5 project and Seven Mile GS Unit 4 project both installed 500 kV GIS 17

similar to the equipment to be installed at Mica; 18

using appropriate contingencies and reserves based on detailed cost analysis using a 19

Monte Carlo simulation that takes into consideration uncertainty in the estimates. Costs 20

are estimated over a possible range with the most likely cost being the Project Expected 21

Cost; and 22



6-6

planning implementation work early and thoroughly so as to reduce the number of 1

equitable adjustments. 2

6.3.4 Schedule Risk During Construction 3

There is a risk that the implementation of all or portions of the Project are delayed. An 4

outage of four months for two units is planned in each of spring 2011 and 2012. If work does 5

not proceed as planned, there is a risk that the outage will be extended beyond the 6

four-month period. The outages are planned during the spring months when BC Hydro’s 7

domestic demand is typically low, and can be serviced by two units. However, if the outage 8

extends beyond this period the opportunity cost to BC Hydro and ratepayers could be high. 9

These costs could be as low as $3 million or as high as $20 million for the month of August, 10

depending on the market. 11

The following are measures taken to mitigate the risk of schedule delays causing extended 12

outages: 13

bonus payments and liquidated damages were included in the GIS design, supply and 14

install contract to better ensure equipment is delivered on a timely basis and to reflect the 15

importance of meeting the schedule; 16

Implementation phase work was planned well in advance and in detail; 17

BC Hydro plans to prepare the site prior to the start of GIS installation; 18

the schedule was planned to ensure significant contingency to avoid the need to spill 19

water in the event of a delay; and 20

a detailed schedule analysis was conducted using Monte Carlo simulation to represent 21

the potential best, worst and most likely scenarios for work completion. 22

BC Hydro reserves the right to decide whether or not it deems the vendor to be adequately 23

prepared to start work at milestone dates, particularly prior to decommissioning and removal 24

of existing equipment. 25



6-7

Delays may also be initiated by BC Hydro due to water conditions. Should water conditions 1

throughout the Province be such that Mica will be required to meet domestic demand, 2

BC Hydro reserved the right to defer the construction. 3

There is also risk of schedule delay from a Mica failure. With two units out of service during 4

construction, there is a risk that failure in the other two units may impact BC Hydro’s ability 5

to generate electricity from Mica. Also, a failure in the GIS in lead shaft 1 or 2 could require 6

up to 12 weeks for repair. 7

The risk of failure of an operating unit has been mitigated with the following measures: 8

maintenance on equipment in the transformer chamber prior to the start of construction; 9

procedures developed for the continuance of Project work in the event of a failure of one 10

of the generating units; 11

the Project will have limited dependence on Mica equipment and tools that may be 12

required in the event of a unit outage. MEPPI are required to supply the tools and 13

equipment required to complete their work; and 14

there is a communications plan between the Mica operations personnel and the Project 15

personnel that includes a plan to escalate unresolved issues to senior management for 16

resolution. 17

The consequence of failure of GIS in lead shafts 1 or 2 during construction will be reduced 18

by installing GIS in lead shaft 3 at the beginning of the Project. 19

6.3.5 Risk of Labour Unrest during Construction 20

Labour unrest can lead to construction delays. BC Hydro has agreed to apply the Columbia 21

Hydro Constructors22 agreement (CHC) to the Project because the Project and the 22

Mica Units 5 and 6 project may occur on site simultaneously and some GIS work supports 23

the Mica Units 5 and 6 projects. The Mica Units 5 and 6 projects are named projects under 24

22 Columbia Hydro Constructors is a subsidiary of BC Hydro.



6-8

the Collective Agreement between the Allied Hydro Council (AHC) and the CHC. The site 1

trade labour required for work in connection with a named project must be supplied by the 2

unions in compliance with the Collective Agreement. The Collective Agreement contains a 3

no-strike clause and provisions to address working conditions. Therefore by applying the 4

CHC agreement to the Project, the risk of labour unrest is mitigated. 5

6.3.6 Congestion in the Mica Powerhouse during Construction 6

Mica has an underground powerhouse with limited space and limited access. Construction 7

for the Project may occur at the same time as some of the Mica Units 5 and 6 project 8

construction. Between the two projects and the day-to-day operation of Mica, there is the 9

potential for congestion in the powerhouse and routes to the powerhouse. This risk is being 10

mitigated by: 11

the Implementation phase work has been thoroughly planned to ensure there are 12

appropriate allocated work areas for all activities occurring at Mica; 13

large components will be preassembled outside the powerhouse; 14

a traffic control plan has been developed for workers and material; 15

work areas and access routes have been clearly delineated; and 16

there will be coordinated bus transportation between Mica Village and Mica. 17

6.3.7 Environmental Risk during Construction 18

Environmental incidents on site during construction could cause costly delays and have 19

further cost implications. The agreements that the major Project contractors enter into with 20

BC Hydro include an Environmental Management Plan that establishes requirements and 21

prohibitions necessary to ensure environmental protection during construction. As well, for 22

activities posing particularly significant environmental risk, contractors are required to submit 23

to BC Hydro an Environmental Protection Plan that provides how those activities will be 24

conducted so as to meet the requirements of the BC Hydro Environmental Management 25

Plan. During construction BC Hydro will have an on-site Environmental Monitor to ensure 26



6-9

appropriate environmental management. These measures mitigate the risk of an 1

environmental incident. 2

6.3.8 SF6 Risk During Construction 3

Two risks related to SF6 are present for this Project. The first, which can impact the 4

schedule, is related to removing the used SF6 from the equipment to be decommissioned. 5

To do this, good quality and adequate capacity gas carts are required. Inadequate gas carts 6

triple the time it will take to remove the used SF6 from the GIS as it is being 7

decommissioned. MEPPI is required to supply its own gas carts of adequate capacity and 8

quality. These gas carts will be delivered to Mica in advance of the work so BC Hydro has 9

the opportunity to determine that they are adequate. If the gas carts are found to be 10

inadequate, there will be sufficient time for alternative gas carts to be delivered to Mica. The 11

SF6 removed from the equipment to be decommissioned will be recycled by MEPPI. 12

The second risk related to SF6 is related to it being a GHG. Releases of SF6 impact the 13

environment and affect BC Hydro’s ability to meet its GHG inventory targets. SF6 releases 14

are tracked by BC Hydro as part of its GHG inventory. They are not currently regulated other 15

than for reporting purposes, but may be regulated in the future. BC Hydro has addressed 16

this risk with contractual terms, including the requirement for a specific SF6 management 17

plan, in the contract with MEPPI. These terms require the contractor to take responsibility for 18

the cost of penalties or GHG offsets in the event of a negligent or uncontrolled release of 19

SF6 arising from the contractor’s work. 20

6.3.9 Contractor Credit/Counterparty Default 21

There is the potential for a contractor to experience credit failures that affect its ability to 22

deliver on its obligations to BC Hydro. BC Hydro’s normal tender procedures address this 23

risk as follows: 24

the tender documents require all bidders to submit bid security with their tenders in the 25

form of a bid bond, letter of credit, or certified cheque in the amount equivalent to 26

10 per cent of the total tendered amount; 27



6-10

BC Hydro reviews the preferred contractor’s capacity to perform the scope of work 1

detailed in the contract including its financial capacity and credit rating. BC Hydro’s 2

Treasury group performs a background check on all bidders, including a review of each 3

company’s financial structure; and 4

the award of contracts are subject to the contractor submitting performance security in 5

the form of performance and labour and materials bonds or letter of credit in the amount 6

of 17.5 per cent of the total contract price supported by a third party guarantee. 7

6.3.10 Commissioning Risk 8

There is a risk that the new GIS will not perform to specifications. This risk is mitigated 9

through the procurement process in which BC Hydro specifies the standards required and 10

evaluates the vender’s qualifications bids, including its experience with past similar projects. 11

At the commissioning stage the new GIS will be subject to high voltage testing on 12

installation to ensure its suitability for service. Once commissioned, the GIS will be subject to 13

guarantees and manufacturer warranties. 14

6.4 Operations Risks 15

6.4.1 Failure and Outage Risk 16

The risk of an outage on the new GIS will be less than the risk of an outage on the current 17

aged GIS. The new equipment will have a manufacturer’s estimated life of 50 years and is 18

expected to be reliable. 19

There will also be significant improvement in monitoring and detection devices that will 20

reduce the potential impacts of failure. Plus, the addition of GIS to lead shaft 3 provides an 21

additional conductor to transfer energy from the Mica powerhouse. If a failure occurs in one 22

lead shaft or if maintenance is being performed, there is more redundancy. 23

6.4.2 Environmental Risk 24

As described in Chapter 4, because of its age and deterioration, the current GIS leaks SF6 25

which impacts BC Hydro’s GHG inventory and targets. These emissions will be reduced with 26



6-11

the installation of new GIS with a much improved leakage rate. BC Hydro has specified that 1

MEPPI must meet standards of 0.5 per cent or less per year. But, based on typical 2

performance of modern equipment it is reasonable to expect a leakage rate of near zero. 3

6.4.3 Operating and Maintenance Costs 4

Design improvements have reduced the risk of an increase in operating and maintenance 5

costs. BC Hydro expects no material change in planned maintenance costs. The 6

maintenance on existing GIS requires two to three person days per month for inspection and 7

an annual inspection of lead shaft lifts. With this Project, while there will be more equipment 8

length to inspect and maintain as well as an additional lift, it is expected that the cost of this 9

work will be offset by improvements to monitoring systems as well as equipment that is 10

designed for easier access. Training for plant personnel on new equipment has been 11

included in the contract with MEPPI. 12

6.5 Risk Summary 13

Table 6-1 is a summary of the material risks for the Project. 14

Table 6-1 Mica Project Risks Summary 15

Risk Mitigation strategy Frequency and Consequence

Definition Phase First Nations consultation on switchgear building extension not considered adequate, resulting in a schedule risk.

All local First Nations notified, and no First Nations have indicated any concerns with the Project, or any desire to consult further.

Moderate probability Moderate Impact to schedule

Implementation Phase Fire and smoke in transformer chamber during construction due to catastrophic failure of transformers resulting in a safety risk.

Real-time monitoring of transformer health.

Perform transformer maintenance prior to the start of construction.

Lower transformer load during construction.

Emergency egress plans.

Procedures for plant and construction personnel working in the area.

Low probability High impact



6-12


During construction, there is an increased security risk

The Project will as a minimum:

provide extra security guards,

provide for identifying signage on hard hats, and

install new access locks on gates and doors.

Medium probability Low impact

Risk that contractors will not be able to meet scheduled milestones and work will extend beyond scheduled outage windows.

Write liquidated damages and bonuses into the GIS contract.

Do not allow work to start if all required equipment and tools are not onsite prior to an outage.

Moderate probability Moderate impact

Risks that implementation costs will exceed estimates.

Obtaining firm pricing on major contracts.

Prepare detailed cost estimates based upon tendered prices, and costs incurred on previous, comparable projects.

Detailed cost analysis using a Monte Carlo simulation that takes into consideration uncertainty in the estimates. Costs are calculated over a possible range with a most likely at Expected Cost.

Medium probability Moderate impact

Labour relations problems due to differences in agreements between those working on GIS and those working on Mica Units 5 and 6 could cause delays.

Inclusion of Project under CHC agreement.

Low probability Low impact



6-13


Congestion in powerhouse due to two large projects (Mica GIS and Mica Units 5 and 6) occurring at the same time leading to safety concerns and/or delays.

Thoroughly plan the implementation work.

Preassemble large components outside the powerhouse.

Develop a traffic control plan.

Delineate work areas and access routes have been clearly delineated.


Risk of damage to environment or non-compliance with environmental regulatory requirements resulting in delays and/or increased costs.

BC Hydro has prepared an Environmental Management Plan (EMP) that must be complied with throughout the project.

The contractors must submit Environmental Protection Plans conforming to the BC Hydro EMP.

BC Hydro will engage an Environmental Monitor during construction to oversee implementation and conformance with the plans and general ensure environmental protection.


Risk of a significant uncontrolled release of SF6 that impact the environment.

MEPPI is required to provide equipment before the start of work for BC Hydro inspection.

MEPPI is required to submit a SF6 management plan for BC Hydro’s approval prior to the commencement of construction.

Under the contract MEPPI assumes the risk of any releases of SF6.


Contractors experience credit and cash flow issues that could affect their ability to perform.

Tender documents require all bidders to submit bid security.

A background financial check is preformed on all bidders and the preferred bidder’s financial capacity is reviewed by BC Hydro prior to award.

BC Hydro obtains performance security in the form of labour and materials bonds or a letter of credit in the amount of 17.5 per cent of the total contract price supported by a third party guarantee.


Equipment fails during commissioning, thus affecting operation schedule

Warranty clauses in contract.

Commissioning tests have been defined.

Moderate probability Low impact



6-14


Operations Phase The equipment does not perform as expected and the number of unplanned outages increases

Warranty provisions in the contracts. Low probability High impact

Risk of SF6 releases during operation that impact the environment.

Train staff on the operation and maintenance of the new equipment.

The new equipment is subject to SF6 standards specified in the tender.

Warranties against SF6 leakage in any amounts exceeding industry standards.


The cost of operation and maintenance of the equipment increases

Use of modern equipment and design reduces the time required for maintenance.

Include training for plant personnel in the operation and maintenance of the new equipment.



Appendix

A

Glossary and Key Financial Assumptions

Glossary

This Appendix lists defined terms, acronyms and metric units used in the Application.

Authorized Cost Estimate

Authorized Cost is comprised of the Expected Cost and a Project Reserve amount.

AHC Allied Hydro Council of British Columbia, an affiliation of international building and construction trades unions.

ARN Aboriginal Relations and Negotiations, a department of BC Hydro’s EARG group.

BCEAA British Columbia Environmental Assessment Act

BCEAO British Columbia Environmental Assessment Office

BC Hydro BC Hydro is a crown corporation established in 1962 under the Hydro and Power Authority Act.

BCTC British Columbia Transmission Corporation

BCUC British Columbia Utilities Commission

BRP Base Resource Plan as defined in BC Hydro’s 2008 Long-Term Acquisition Plan filed with the BCUC.

Bulk Transmission System

This is the “backbone” or major high voltage transmission system that carries the majority of the power from the generators to the lower voltage regional systems and carries the interchanges with the U.S. and Alberta.

Bus and Buswork An electrical conductor that provides shared connection to equipment.

Bus Cone Insulators Bus cone insulators are installed throughout the bus enclosure at specified length to support the conductor and also to provide enough clearance insulation between the conductor and enclosure.

Mica Gas Insulated Switchgear Project Appendix A-1

Page 1 of 7

Capacity 1. The instantaneous power output of a generator at any given time, normally measured in kilowatts (kW) or megawatts (MW), of a power plant.

2. The instantaneous electricity demand at any given time, normally measured in kilowatts (kW) or megawatts (MW).

3. A transmission facility’s ability to transmit electricity, at any instant.

Several related terms are commonly used:

Maximum Capacity: The highest generating plant output or transmission loading that can actually be achieved in situ.

Installed Capacity: (Also referred to as Nameplate Rating). The maximum rating of a generator or transmission station equipment identified by the manufacturer under specified conditions.

Dependable Capacity: The amount of megawatts a plant can reliably produce when required, assuming all units are in service. Factors external to the plant affect its dependable capacity. For example, streamflow conditions can restrict the dependable capacity of hydro plants and fuel supply constraints can impact thermal plant dependable capacity. Planned and forced outage rates are not included.

CEAA Canadian Environmental Assessment Act

CHC Columbia Hydro Constructors Ltd., the employer of all employees working under the scope of the collective agreement applicable to the construction of the Mica dam and powerhouse.

Circuit Breakers A device used for switching-in and switching-out a piece of equipment or part of the system or for tripping when there is a fault.

CCFA Comprehensive Capacity Funding Agreement. A BC Hydro agreement to provide funding for First Nation participation in decision-making processes.

CFO Chief Financial Officer

CO2 Carbon dioxide

CRP Contingency Resource Plan as defined in BC Hydro’s 2008 Long-Term Acquisition Plan filed with the BCUC.


Page 2 of 7

Demand The rate at which electric energy is delivered to or by a system, generally expressed in kilowatts (kW) or megawatts (MW), at a given instant or averaged over any designated time interval. Several related terms are commonly used:

Instantaneous Demand: Rate of energy delivered at a given instant.

Average Demand: The electric energy delivered over any interval as determined by dividing the total energy by the units of time in the interval.

Peak Demand: The highest electric requirement occurring in a given period (e.g. an hour, a day, month, season or year). For an electric system, it is the sum of the metered net outputs of all generators within a system and the metered line flows into the system, less the metered line flows out of the system.

Disconnect Rods Disconnect rods are insulated rods connected to the mechanism used to open and close disconnect switches.

Disconnect Switches A device used for isolating a piece of equipment or section of bus.

EAC Environmental Assessment Certificate, issued pursuant to the BC Environmental Assessment Act.

EARG BC Hydro’s Engineering, Aboriginal Relations and Generation Business Unit

Efficiency The effective rate of conversion of a natural resource (e.g. natural gas) to useable energy and capacity or the effective rate of conversion of electricity to an end use (e.g. heating).

Equipment Health Ratings (EHR)

An objective, repeatable equipment health evaluation system. EHR enables comparison of the health of BC Hydro generation assets. The EHR system uses test and inspection data and other information to determine the condition or health of assets. The result is a technical evaluation of the asset resulting in a letter grade; Good, Fair, Poor, Unsatisfactory (G,F,P,U), as follows:

• Good - no noticeable deterioration/defects;

• Fair - some deterioration/defects exist (function not affected);

• Poor - serious deterioration/defects exist in at least some portions of the asset (function affected); and

• Unsatisfactory - extensive deterioration/defects (no longer functions as required).


Page 3 of 7

Expected Cost Estimate

Expected Cost is comprised of the Cost Estimate, Contingencies, Escalation, Overhead and Interest During Construction (IDC).

Flash-over Failure A short circuit failure caused by electrical discharge between phase to phase or phase to ground.

Forced Outage An outage caused by a permanent fault or equipment failure.

Gas Cart A portable device used for adding or removing SF6 to or from GIS.

Generator A machine that converts mechanical energy into electric energy.

GHG Greenhouse Gas

Gigawatt-Hour (GWh) One million kilowatt-hours – an amount of electric energy that will serve about 100 residential customers for one year.

GIS Gas Insulated Switchgear

GMS Gordon M. Shrum, the Generating Station at the Bennett Dam

GS Generating Station

HVAC Heating, Ventilation, and Air Conditioning

Headcover Non-rotating structural component that: 1) supports the wicket gate upper stems and the operating mechanism, 2) acts as a seal between the water passages and turbine pit, 3) is an important part of the system for managing the thrust load created by water passing through the turbine.

IDC Interest During Construction

Kilovolt (kV) A volt as a unit of electromotive force. Kilovolt is equal to 1,000 volts.

Interconnection Study A British Columbia Transmission Corporation (BCTC) study determines the technical feasibility of a customer’s facilities connecting to the BC transmission system.

IR Information Request

ISD In-Service Date

LCAM Life-Cycle Asset Management

Lead Shafts The vertical tunnels at Mica containing the gas insulated switchgear that runs from the underground transformer chamber to the above-ground switchgear building.


Page 4 of 7

Long-Term Acquisition Plan (LTAP)

BC Hydro’s action plan to cost effectively meet growing customer electricity requirements. The LTAP sets the course for the first 10 years of a 20-year planning horizon.

Megawatt (MW) One million watts. This term is commonly used to measure both the capacity of generating stations and the rate at which energy can be delivered.

MEPPI Mitsubishi Electric Power Products, Inc.

Mica Mica Dam and Generating Station.

MSSC Most severe single contingency

NPV Net Present Value

Refurbishment Inspection and replacement of worn components.

P & C Protection and Control

Control equipment enables remote operation of the circuit breakers and disconnect switches and monitors the SF6 gas pressure. Protection equipment includes relays that detect equipment faults and automatically isolate faulted equipment from the electrical system.

Penstock Enclosed intake / pipe system that delivers water to a hydroelectric turbine.

Project The BC Hydro Mica Gas Insulated Switchgear Project

Project Initiator David Lebeter, BC Hydro’s Director of Generation Operations in the EARG line of business. Is accountable to the Project Sponsor for the definition and the justification of the Project.

Project Sponsor Chris O’Riley, BC Hydro’s Senior Vice President of EARG. Is responsible for supporting the success of the Project by acting as liaison with BC Hydro’s executive team and approving key decisions.

Reliability A measure of the continuity and quality of electric service. Reliability of service to an individual customer depends on the reliability of generation, high-voltage transmission and low-voltage distribution.

Revelstoke Revelstoke Dam and Generating Station

Revenue Requirements Application (RRA)

BC Hydro filing to the British Columbia Utilities Commission (BCUC) to seek approval for rate levels to support forecast revenue requirements.


Page 5 of 7

Runner Device for transforming potential energy (water stored in reservoir) into kinetic energy. It is constructed of multiple hydrofoil blades fixed to a supporting structure (crown and band).

Seven Mile GS Seven Mile Generating Station

SF6 Sulphur Hexafluoride. Used as the insulating gas in GIS.

Statement of Intent (SOI)

Under the Six-Stage treaty process coordinated by the BC Treaty Commission, A First Nation files with the Treaty Commission a SOI to negotiate a treaty with Canada and BC. The SOI must identify the First Nation's governing body for treaty purposes and the people that body represents and show that the governing body has a mandate from those people to enter the process. The SOI must also describe the geographic area of the First Nation's distinct traditional territory and identify any overlaps with other First Nations.

Surge Arrestor Surge arrestors are mechanisms to protect transformers from lightening and switching power surges.

Switchgear A combination of circuit breakers, disconnect switches, and ground switches used for switching and isolating part of the electrical system.

Transient Surges A transient surge is an over-voltage (higher than normal voltage) that can occur during the closing or opening of a switch or when a fault (e.g. short circuit) occurs on a system.

Transformer A device that transfers energy from one circuit to another with different voltages.

Transformer Chamber The location of the transformers in the generating station.

Turbine A rotary device caused to turn by the movement of gases, steam or water.

UCA Utilities Commission Act

Unit A single power generation system within a multi-unit power generation facility. For example, the BC Hydro GMS Generating Facility contains 10 Units. Each Unit is comprised of several components, including the turbine, generator, transformers, conductors, circuit breakers, and ancillary equipment, all of which are required to create electrical energy and deliver it to the Bulk Transmission System.

Upgrade Replacement of components

Water License The authority granted under the Water Act to BC Hydro by the Comptroller of Water Rights of the Province of British Columbia to store and divert water for generating electricity and other purposes.


Page 6 of 7

Water Use Plan A Water Use Plan is a technical document that defines the detailed operating parameters to be used by hydroelectric facility managers in their day-to-day decisions. WUPs are intended to clarify how rights to Provincial water resources should be exercised, and to take account of the multiple uses for those resources. WUPs are reviewed by the Comptroller of Water Rights pursuant to the Water Act.

Wicket Gates A series of hydrofoil-shaped gates that regulate the flow of water from the penstocks to the runners. The wicket gates for GMS Units 1 to 5 are being proposed for replacement as part of the upgrade project.

XLPE cable Cross-linked polyethylene cable


Page 7 of 7

Key Financial Assumptions

Factor Assumption

Nominal Discount Rate 8 per cent

General Inflation F2009: 0.5 per cent

F2010: 2.0 per cent

F2011 through F2013: 2.1 per cent

F2013+: 2 per cent

Construction Escalation Rates Ranges from 0.9 per cent to 3.0 per cent with cumulative escalation of 25.5 per cent over 15 years or 1.7 per cent average per year

Reference Value of Energy (to Lower Mainland)

$93/MWh. Figure calculated using the cost of marginal energy delivered to the Lower Mainland, identified in the 2006 Call for Tenders at $88/MWh (F2006 Dollars)

Dependable Capacity Reservation cost $17/MW winter


Page 1 of 1


Appendix

B

Draft Order

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

web site: http://www.bcuc.com

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

FACSIMILE: (604) 660-1102

BRITISH COLUMBIA

UTILITIES COMMISSION ORDER NUMBER G-

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473

and

An Application by British Columbia Hydro and Power Authority


BEFORE: ________, Commissioner XX, 2009

O R D E R WHEREAS:

A. On August 5, 2009, British Columbia Hydro and Power Authority (“BC Hydro”) filed an application for

acceptance, pursuant to Section 44.2(1)(b) of the Utilities Commission Act (the “Act”), that capital

expenditures BC Hydro anticipates making in respect of the Mica Gas Insulated Switchgear Project (“Mica

GIS Project”) are in the public interest; and

B. The Commission has considered the application, evidence, and submissions of intervenors and BC Hydro.

. . ./2

Mica Gas Insulated Switchgear Project Appendix B

Page 1 of 2

2

Order/

BRITISH COLUMBIA

UTILITIES COMMISSION ORDER NUMBER G-

NOW THEREFORE the Commission determines for the Reasons stated in the Decision, that: 1. The expenditures required to complete the Mica GIS Project, as described in the application, are in the public

interest in accordance with Section 44.2(3)(a) of the Act.

2. BC Hydro is directed to file with the Commission quarterly progress reports on the Mica GIS Project

schedule, costs and any variances or difficulties that the Mica GIS Project may be encountering. The form and

content of the quarterly progress reports will be consistent with other BC Hydro capital project quarterly

reports filed with the Commission. The quarterly progress reports will be filed within 30 days of the end of

each reporting period.

3. BC Hydro is directed to file a final report within six months of the end or substantial completion of the Mica

GIS Project. The final report is to include a complete breakdown of the final costs of the Mica GIS Project, a

comparison of these costs to the Project Expected Cost estimate and provide an explanation of all material

cost variances.

DATED at the City of Vancouver, in the Province of British Columbia, this day of ________ 2009.

BY ORDER

Mica Gas Insulated Switchgear Project Appendix B

Page 2 of 2


Appendix

C

Project Schedule

Act

ivity

Nam

eO

rigin

alD

urat

ion

Sta

rtFi

nish

Def

initi

on P

hase

293

17-D

ec-0

8 A

24-F

eb-1

0

File

BC

UC

App

licat

ion

175

17-D

ec-0

...18

-Aug

-09

Rem

oval

of S

GB

from

Mic

a 5/

6 E

AO

(Dra

ft)20

02-A

pr-0

9 A

30-A

pr-0

9 A

Rem

oval

of S

GB

from

Mic

a 5/

6 E

AO

(App

rove

d)23

17-A

pr-0

9 A

17-A

pr-0

9 A

Obt

ain

BC

UC

App

rova

l22

320

-Apr

-09

A24

-Feb

-10

Impl

emen

tatio

n Ph

ase

976

05-J

un-0

9 A

29-A

pr-1

3

EA

R A

ppro

val f

or IM

P11

05-J

un-0

9 A

15-J

un-0

9 A

ME

PP

I Pro

cure

men

t (P

lace

Hol

der)

784

30-J

un-0

929

-Jun

-12

Aw

ard

Con

tract

for S

witc

hgea

r Bui

ldin

g0

30-J

ul-0

9*S

ubm

it G

as In

sula

ted

Sw

itchg

ear (

GIS

) Det

aile

d D

esig

n S

umm

ary

9511

-Aug

-09

21-D

ec-0

9

Com

plet

e O

vera

ll S

witc

hgea

r Bui

ldin

g - W

eath

er T

ight

6811

-Sep

-09

15-D

ec-0

9

Com

plet

e O

vera

ll S

witc

hgea

r Bui

ldin

g10

816

-Dec

-09

14-M

ay-1

0M

EP

PI G

IS C

ontra

ct S

tage

1 -

Inst

all L

ead

Sha

ft 3

4901

-Oct

-10

08-D

ec-1

0

ME

PP

I GIS

Con

tract

Sta

ge 2

- In

stal

l Sw

itchg

ear &

GIS

Equ

ipm

ent

(U5

& U

6)84

01-O

ct-1

026

-Jan

-11

Pla

nned

Sum

mer

Out

age

2011

Win

dow

109

01-M

ar-1

1*29

-Jul

-11*

ME

PP

I GIS

Con

tract

Sta

ge 3

- U

3 &

U4

GIS

Rep

lace

men

t52

01-M

ar-1

111

-May

-11

ME

PP

I GIS

Con

tract

Sta

ge 4

- Tr

ansm

issi

on L

ine

to R

eact

or @

SG

B51

15-A

pr-1

124

-Jun

-11

ME

PP

I GIS

Con

tract

Sta

ge 5

- Le

ad S

haft

211

102

-Aug

-11

03-J

an-1

2

Pla

nned

Sum

mer

Out

age

2012

Win

dow

109

01-M

ar-1

2*31

-Jul

-12*

ME

PP

I GIS

Con

tract

Sta

ge 6

- U

1 &

U2

GIS

and

SG

B G

IS

Rep

lace

men

t89

01-M

ar-1

203

-Jul

-12

ME

PP

I GIS

Con

tract

Sta

ge 7

- Le

ad S

haft

110

101

-Aug

-12

19-D

ec-1

2

Pro

ject

Com

plet

ion

Doc

umen

tatio

n90

11-D

ec-1

229

-Apr

-13

MJ

Jul

AS

ON

DJ

FM

AM

JJu

lA

SO

ND

JF

MA

MJ

Jul

AS

ON

DJ

FM

AM

JJu

lA

SO

ND

JF

MA

MJ

Jul

2009

2010

2011

2012

2013

24-F

eb-1

0, D

efin

ition

Pha

se

File

BC

UC

App

licat

ion

Rem

oval

of S

GB

from

Mic

a 5/

6 E

AO

(Dra

ft)

Rem

oval

of S

GB

from

Mic

a 5/

6 E

AO

(App

rove

d)

Obt

ain

BC

UC

App

rova

l29

-Apr

-13,

EA

R A

ppro

val f

or IM

PM

EP

PI P

rocu

rem

ent (

Pla

ce H

olde

r)A

war

d C

ontra

ct fo

r Sw

itchg

ear B

uild

ing

Sub

mit

Gas

Insu

late

d S

witc

hgea

r (G

IS) D

etai

led

Des

ign

Sum

mar

y

Com

plet

e O

vera

ll S

witc

hgea

r Bui

ldin

g - W

eath

er T

ight

Com

plet

e O

vera

ll S

witc

hgea

r Bui

ldin

gM

EP

PI G

IS C

ontra

ct S

tage

1 -

Inst

all L

ead

Sha

ft 3

ME

PP

I GIS

Con

tract

Sta

ge 2

- In

stal

l Sw

itchg

ear &

GIS

Equ

ipm

ent (

U5

& U

6)

Pla

nned

Sum

mer

Out

age

2011

Win

dow

ME

PP

I GIS

Con

tract

Sta

ge 3

- U

3 &

U4

GIS

Rep

lace

men

t

ME

PP

I GIS

Con

tract

Sta

ge 4

- Tr

ansm

issi

on L

ine

to R

eact

or @

SG

B

ME

PP

I GIS

Con

tract

Sta

ge 5

- Le

ad S

haft

2

Pla

nned

Sum

mer

Out

age

2012

Win

dow

ME

PP

I GIS

Con

tract

Sta

ge 6

- U

1 &

U2

GIS

and

ME

PP

I GIS

Con

tract

Sta

ge

Pro

ject

Co

MIC

A G

ISLe

vel 1

Sch

edul

eP

rint D

ate:

22-

Jul-0

9

Rem

aini

ng L

evel

of E

ffort

Act

ual L

evel

of E

ffort

Act

ual W

ork

Rem

aini

ng W

ork

Crit

ical

Rem

aini

ng W

ork

Mile

ston

eS

umm

ary

Pag

e 1

of 1

Mica Gas Insulated Switchgear Project Appendix C

Page 1 of 1


Appendix

D

Project Lifecycle and Project Cost Estimating

BC Hydro Standard Project Lifecycle

A standard Project Life Cycle is an essential component of good project management

practice. BC Hydro’s Project Lifecycle is provided as Figure 1.

Figure 1 Project Life Cycle

The Project Life Cycle is composed of phases and stages within those phases. Each

phase results in the development of key deliverables that are subject to checking and

independent review, functional endorsement and financial due diligence before they

receive approval to proceed.

For each of the Project Life Cycle phases, the project initiator and project manager

present the recommendations of the key deliverables to a gateway committee for

approval to proceed. The gate committee is composed of members of the EARG senior

management team. Once the gate committee approves proceeding with the next phase

of the project, the recommendation and results of the financial due diligence are

presented to Chris O’Riley, the project sponsor, for approval. If the project sponsor does

not have the necessary level of delegated financial authority, the decision proceeds to

the level required to make the business decision, which for funding requests greater than

$20 million, is the BC Hydro Board of Directors.

Mica Gas Insulated Switchgear Project Appendix D-1

Page 1 of 3

Initiation Phase

When BC Hydro’s EARG generation operations group identifies a problem or

opportunity, it is entered into BC Hydro’s asset management process. If the project is not

included in BC Hydro’s current Capital Plan it is reviewed by management prior to formal

assignment to the EARG generation project delivery group. If the project is included in

the capital plan, the EARG generation project delivery group assigns a qualified project

manager to the project. The Initiation phase ends when the EARG finance group

approves initial funding for the Identification phase to initiate planning and a project

manager to plan and deliver the project has been assigned.

Identification Phase

During the course of the Identification phase conceptual designs are prepared to identify

solutions to address the problem or opportunity. Subsequently, feasibility studies are

carried out and a preliminary business case is prepared. The Identification phase ends

with the selection of a preferred alternative to address the problem or opportunity. At the

end of the Identification phase, the gate committee decides whether to fund the

Definition phase of the project.

Definition Phase

During the course of Definition phase, field and other studies (preliminary design) are

completed to comply with any regulatory obligations, and to finalize the business case. In

addition, applicable regulatory authorizations1 are sought and the project plans and

business case are revised to incorporate any conditions imposed by regulatory agencies.

The Definition phase ends when the gate committee decides whether to proceed to

implement the project.

1 May include: Water Act, Canadian Environmental Assessment Act and BC Environmental Assessment

Act and the Utilities Commission Act.


Page 2 of 3

Implementation Phase

During the course of the Implementation phase, detailed design occurs; equipment is

procured2; the work is manufactured, supplied, installed and constructed; and the testing

and commissioning is completed. At this stage, the assets for the project are transferred

from the custody of the project team to the staff in the EARG generation operations

group that will operate and maintain the asset. The project is complete when the project

initiator accepts the project results by signing the project completion report.

Throughout the Project Life Cycle, project monthly reports are issued and reviewed by

senior management, and issues are escalated as required to move forward.

2 Where appropriate, senior management may approve the tendering of equipment in advance of

regulatory approvals to reduce project risk. In such cases the contracts awarded will be subject to regulatory approval and contain termination provisions that limit financial exposure.


Page 3 of 3

BC Hydro Project Cost Estimating Practices

BC Hydro’s estimating practice for projects expected to cost over $6 million is to

establish a range of possible costs based on a probability analysis to determine

contingency1 allowances, and to include specific possible adverse developments outside

BC Hydro’s control, and potential but uncertain scope expansions. The probability

analysis is carried out by breaking the project cost2 into distinct cost elements, which are

internally similar but statistically independent. For each cost element, BC Hydro makes

an estimate of the range of possible cost outcomes from low to high, as well as a single

best estimate, with the intention that there is only a five per cent probability that the

actual outcome will lie outside the low - high range. This range is intended to cover the

common reasons for estimate differences, including:

Difference in site conditions;

Design refinements as engineering continues;

Labour productivity not as assumed;

Quantity variations; and

Changes in cost or extra costs.

The estimate of the appropriate cost range is determined by experience, professional

judgement, or common industry practice, after review of the project Risk Register and

discussion with key members of the project team about potential risks and uncertainties

in the project. These range estimates are used to create a statistical model of the total

project cost; the output of the statistical model is a probability density function indicating

the probability of a particular aggregate cost outcome – of particular interest are the P50 1 “Contingency – An amount added to an estimate to allow for items, conditions, or events for which the

state, occurrence, and/or effect is uncertain and that experience shows will likely result, in aggregate, in additional costs.” Association for the Advancement of Cost Engineering International; Recommended Practice No 10S-90. A contingency is expected to be expended on items that cannot be identified in advance, but are likely to occur (with varying degrees of confidence) over the course of the project.

2 This analysis includes directs costs and BC Hydro costs, such as Engineering and Project Management, but excludes loadings for overhead or IDC. The range estimates are in constant dollars, which are then increased to reflect anticipated escalation in construction costs.


Page 1 of 3

and P90 values; the cost estimates at which there is a 50 per cent probability that the

actual outcome will be less than the estimate, and at which there is a 90 per cent

probability that the actual outcome will be less than the estimate. These values are then

“loaded” by including them in a monthly cash-flow schedule over the project life. The

cash flow schedule allows calculation of IDC to reflect the carrying cost of an asset that

has not gone into service, Inflation and Escalation to reflect the nominal dollars to be

expended, and an overhead charge to reflect the burden of administrative and financial

functions that do not make a direct contribution to the project.

The Loaded P50 value is the Expected Cost of the project, representing BC Hydro’s

estimate of the likely project cost: by definition there is an equal chance that the actual

outcome will be above this value or below this value. The P90 value is a reasonable

upper estimate of the cost of the project, except it does not include possible costs

outside the control of BC Hydro, including:

Material changes in exchange rates or general inflation and escalation rates;

Changes in project scope or operating requirements;

Accidents with material cost or schedule implications for the project;

Abnormal weather; and

Changes in governmental policy, environmental standards or regulated working

conditions.

BC Hydro estimates the likelihood of such events and the possible cost impact (on a

Loaded basis), and the project initiator and project sponsor jointly determine whether

they wish to reflect such costs in the project’s Authorized Cost by including them in a

Management Reserve. The decision as to what should be included in a Management

Reserve is based on professional judgement and experience and will reflect the

likelihood and materiality of these uncontrollable risks. The project’s Authorized Cost is

the P90 estimate together with the Management Reserve established by the project

initiator and project sponsor.


Page 2 of 3

All projects requiring approval of the BC Hydro Board of Directors (BoD), such as this

Project, include a Project Reserve for the Implementation phase. Authority to approve

the use of this Project Reserve is delegated to the Chief Executive Officer, unless

otherwise determined by the BoD. Any cost overruns that are forecast to exceed the

Authorized Cost amount require BoD approval. The project manager is delegated the

authority to spend the Expected Cost amount on the project.


Page 3 of 3


Appendix

E

Condition Assessment Reports

1

Mica Generating Station

Condition Assessment of 550 kV ITE SF6 Gas Insulated Station (GIS) Equipment in the

Transformer Gallery and Lead Shafts

October 2005

This report was written by

Bjorn Holm International Switchgear Consulting Ltd

14728 Upper Roper Ave White Rock, B.C. Canada, V4B-2C9

The report was reviewed by

Darren Kahl, Electrical Maintenance Engineer Upper Columbia Generation

Mica Gas Insulated Switchgear Project Appendix E-1

Page 1 of 6

2

Introduction The gas insulated switchgear (GIS) at Mica is now about 30 years old. This was the first 550 kV GIS made by ITE. This make has been prone to flash over failures and SF6 leaks. Disconnects are now no longer operated with motor drives and are only switched while being de-energized on both sides. This has reduced flashover failures, but it has also imposed severe operating restrictions. Service Life Considerations Utilities commonly expect a GIS life span of about 40 to 50 years before being faced with refurbishing or replacement. Life limiting materials include seals, epoxy insulation, spring contacts at insulators and current carrying sliding contacts. Most replacement decisions have been made due to insulation flashovers and SF6 leaks, some due to sliding contact failures. Arizona Public Service has replaced their three 230 kV GIS stations. TVA is in the process of replacing their three 550 kV GIS stations. The service life for these stations varies from 20 to 30 years. National Grid, ConEdison and Entergy have all performed extensive repairs and refurbishing, but have not replaced stations yet. Mica Failure History The failures to date have all occurred in the switchgear building, with the exception of one in a lead shaft and one in the transformer gallery. The failure in the lead shaft was likely due to particles or contamination in SF6. The failure in the transformer gallery was due to contamination during an operating rod installation. Most of the failures in the switchgear building have been associated with the circuit breakers. Some have been due to internal disconnect operating rod flash over and some due to particles or contamination. Failures have not yet occurred due to internal flash over within cone insulators or due to insulator insert spring degradation. The onset of such failures would be likely to indicate chronic future problems and a need for GIS replacement. The time required for tendering, manufacturing and installing new GIS is normally up to two years after budget approval. Major refurbishing requirements can develop within this time frame. It is therefore important to take the expected time required for replacement into account in order to avoid major refurbishing. Generator G5 Installation The addition of generator G5 would require new GIS from new transformers T5 to existing disconnects 5D10, and new GIS in lead shaft #3 to the switchgear building. New GIS in lead shaft #3 would provide additional contingencies and thus allow easier replacement of the existing GIS when needed, particularly in lead shafts. It is advantageous to install the GIS for generator G5 before installing the generator in order to reduce risks and consequences of failures in the ITE GIS, as well as to facilitate replacement.


Page 2 of 6

3

Risk of Two Unit Outage A flash over failure in the transformer gallery GIS would result in two generators being out of service until completion of repairs. The time to repair after operating rod failures has usually taken only a few days. Other types of failures are more likely to take about five to six weeks, provided the technical resources, parts and tools are available at site. A two unit outage after a flash over could be reduced to one unit by installing disconnects to sectionalize the bus. Two sets of two disconnects would be required, one set between lead shaft #1 and transformer T2, and one set between lead shaft #2 and transformer T3. This sectionalizing could be made similar to the existing sectionalizing arrangement at disconnects 5D7/5D8 and disconnects 5D9/5D10. Alternately, the time required to get both units back in service after a flash over could be reduced from a few weeks to a few days by installing a connectable spare phase along the length of the transformer gallery, parallel to the existing bus. This spare phase would need provision for connection to the 12 transformer disconnects and to the 6 lead shaft disconnects. Three sections would be required for temporarily connecting the spare bus in order to bypass the faulted portion. The faulted bus could then be repaired while all units remain in service, and then returned to service during a two unit outage at an opportune time. Equipment Concerns The wire type spring contacts and the age of seals dictated replacement of the GIS at Seven Mile. Disconnect design, surge arrester design and age, age of seals, age of solid insulation, and floating electrode type defects are the critical issues at MCA. Disconnects Flashover failures, test results, and dissections, have shown that disconnect operating rods contain contaminants from manufacture and have too high electrical stress at the end fittings. All rods should be replaced as soon as possible. Motor operators as well as contact configurations need major modifications. The original equipment manufacturer has provided product support for operating rod replacement, but support for major modifications has not been offered. Cone Insulators Internal PD can be present for decades before a flash over failure results. UHF tests have detected partial discharge (PD) in cone insulators. However, there has been no internal flash over within insulators so far. Flash over at surfaces due to contamination have occurred. Spring Contacts at Insulator Insert Wire type contact springs at insulator inserts have contributed to early replacement of several ITE stations, including the 230 kV GIS at Seven Mile. Vibrations have often been associated with the partial discharge at this wire type of spring connection.


Page 3 of 6

4

The springs at Mica are a flat type that has so far not been associated with failures at this station. However, UHF signatures due to partial discharge, and consistent with floating electrode type defects, have been detected at many locations. Contact springs are a likely source of such partial discharge signals. Surge Arresters The surge arresters in the transformer gallery are gap type arresters using obsolete technology. Counter history can be analyzed. Grading currents can be measured. Spark over voltage can be measured to determine if SF6 has leaked into the nitrogen compartment. Functionality is questionable and cannot be tested. A defective surge arrester would add stress to the bus as well as the transformers. Insulation weaknesses would be likely to result in flash over due to lack of switching surge suppression. SF6 Leaks The bypass piping at Mica has had numerous leaks from the time of installation. Such leaks are normally relatively inexpensive to repair and repairs have been completed in recent years. There are also a number of leaks at bolted flanges. Some of these leaks can be easy to repair, such as at access covers and ground switches but success rate to date has been low due to warped flanges. Some of the flange leaks require extensive dismantling in order to replace O-rings. Temporary repairs are commonly made to defer dismantling until a convenient time. The most serious SF6 flange leaks are in the switchgear building. There are fewer critical flanges in the transformer gallery. Insulation Test Results Partial Discharge Detection Partial discharge degrades SF6 gas as well as solid insulation, and results in insulation flash over at some point in time. Partial discharge produces electromagnetic radiation in the ultra high frequency (UHF) spectrum, acoustic signals of up to about 100 kHz, and chemical decomposition of SF6. UHF signals travel up to about 60’ inside GIS, depending on materials and geometries involved. UHF signals may be detected at disconnect view ports at Mica. Partial discharge inside solid insulators generates UHF signals, but the magnitudes are usually relatively low. Sonic and ultrasonic signals from partial discharge usually travel up to about 6’ depending on materials and geometry involved. Acoustic analysis can detect partial discharge in SF6 but not inside the epoxy insulators, due to damping of signals in epoxy. Vibrations can mask acoustic signals. Partial discharge in SF6 produces gaseous and solid decomposition products. The decomposition gases may be detected on site using chemical analysis. Partial discharge inside solid insulation does not decompose SF6 and cannot be detected. Desiccants adsorb decomposition gases. Sampling lines can affect test results.


Page 4 of 6

5

UHF Test Results UHF signals from partial discharge have been detected at almost all disconnect view ports. A high portion of the detected UHF signals have originated at contamination inside disconnect operating rods. After rod replacement, signals from other sources may be identified, and some have been characterized further to include floating electrode type partial discharge as well as from voids or contamination. UHF signals characterized as floating electrode have been detected at 4 view ports adjacent to bus section 5BT2T1 B phase. UHF time of flight measurements have been made at these 4 disconnect view ports, where the same signal might be detected at two or more view ports, thus enabling the partial discharge to be located. Results so far indicate one source close to disconnect 5D2B and one source close to disconnect 5D1B. Acoustic Test Results Acoustic signals have provided information about partial discharge in the lead shafts, but not yet in the transformer gallery, due to vibrations caused by operation of the generators and transformers. SF6 Chemical Decomposition SF6 decomposition gases have been detected in gas zone GBT3A. This is a small zone at T3A that includes disconnect 5D3A, which contains desiccant for moisture and SF6 decomposition gas removal. Conclusions A flash over in the transformer gallery is likely to result in two units being out of service for about five to six weeks. If a failure occurs in one of the two lead shafts, the work could take longer, but in this case all Mica output would depend on one lead shaft. One spare phase, connectable to bypass a faulted section in the transformer gallery would reduce the consequences of a failure from two generators being out of service for a number of weeks, to the two generators being back in service within a number of days. Disconnects can only be operated manually while both sides are de-energized. Replacement would allow normal operations to resume. The gap type surge arresters in the transformer gallery are likely to be at, or close, to end of life. Test results have correlated well with GIS condition based on internal inspections at Mica and Seven Mile. Partial discharge has been detected in numerous locations in the transformer gallery GIS. Flash over failures are likely to occur, probably within the next few years. More problems have been detected in the transformer gallery than in the lead shafts, perhaps because of ease of detection, but perhaps also because of lower vibrations.


Page 5 of 6

6

GIS lead shaft repairs due to flash over or GIS replacement due to end of life would leave Mica output dependent on one lead shaft, perhaps for an unacceptable length of time. Advancing the installation of GIS for G5 in lead shaft #3 would avoid this weakness. The condition, obsolescence and design weaknesses of the ITE GIS indicate that replacement will be necessary, probably within about 8 years. The number of issues involved, as well as the amount of partial discharge that has been detected indicates internal problems that are less costly to solve by replacement. Recommendations Install one spare phase with provisions to temporarily bypass a faulted GIS section in the transformer gallery. Review requirements for parts, tools, equipment and access needed for emergency repairs in the transformer gallery. Perform more frequent UHF, chemical and acoustic tests to locate defects that might require immediate repairs. Install GIS in lead shaft # 3 for the G5 generator position to facilitate GIS replacement. Replace the ITE GIS in stages within about 8 years, starting in the transformer gallery. Whenever the GIS in the transformer gallery is replaced, install two additional sets of sectionalizing disconnects, one set between lead shaft #1 and T2, one set between lead shaft #2 and T3.


Page 6 of 6

ROHE INTERNATIONAL, INC.

June 30th

-2007

349 NORTHGATE DRIVE, WARRENDALE, PA 15086 page 1 of 7

PHONE 724-933-0260 FAX 724-933-0266

BC Hydro - Mica Generating Station ITE-GIS

Condition and Risk Assessment

Situation found at Site

Historic operational documentation of the ITE GIS was obtained at Revelstoke and Mica

Power Station. Available data of problems, faults, repairs and leakage was reviewed. A

tour of the transformer gallery and also of the upper GIS building was completed. The

one-line diagram was reviewed. A few key factors appear to dominate the problems

experienced over the years. These factors continue to be the main concern about the

future of the ITE GIS.

1. Much higher than expected leakage rate

2. Partial discharge in several areas

3. Operating rods on disconnect switches.

4. Electric operating mechanisms of disconnect switches

5. Internal leakage of Barrier-Type insulators

6. SF6 Density Monitors

7. Integrity of sliding contacts

8. Arrestors are only spark gap type and not Zink-Oxide

Historic problems from other ITE GIS substations need also to be considered. They are:

9. Aging of all seals and O-rings and associated higher leakage and loss of SF6

10. Electric contact Springs between sliding bus and support insulator’s inserts

(details page 2)

Elaboration on above points.

To 1. The expected leakage rate on a modern GIS is less than 0.5 % per year. (for

instance compare with Revelstoke and Peace Canyon). The loss of SF6 is not only a cost

factor but also a reliability issue. The aging of the seals has also a negative effect on

reliability and the leakage rate will increase continuously and can lead eventually to

catastrophic losses. Additionally, in future BCH faces a possible environmental liability.

The Canadian equivalent of the EPA will eventually issue heavy fines for the usage (loss)

of SF6 gas – we expect it to be similar to what is already in effect in Europe. The total

amount of SF6 used at Mica Generating Station during 2004 was 172.9 kg, during 2005

was 56.8 kg and during 2006 it was 92.9 kg. The reduction of SF6 loss in 2005 was

mainly due to repairing the by-pass piping. The increasing amount for 2006 is an

indication that the repair is only temporary and also most likely the leakages in seals and

O-rings are on the increase. The Green house effect can easily be calculated.


Page 1 of 7


June 30th

-2007


PHONE 724-933-0260 FAX 724-933-0266

To 2. Partial discharge will lead sooner than later to internal electrical breakdown with

resulting flash-over and lengthy repair time of the component. The associated

unscheduled outage time can be a few days or a few weeks depending on where the fault

occurs and the availability of spare components. The financial loss of such an

unscheduled outage (measured by multiples of cost per MW hours) can quickly offset the

cost for new GIS.

The severity of PD at Mica has been greatly reduced by replacing some of the disconnect

switch operating rods. However the PD activity as a whole in Mica is still much larger

than in other stations. This indicates that we have to expect in future a higher than normal

failure rate. To predict this failure rate is almost impossible since it depends not only on

normal, in service conditions but also on occurring over-voltages produced by switching

operations (internally) and other network system conditions (externally). Historically and

technically we know that partial discharge inside GIS leads almost always to a failure.

To 3. The old, solid epoxy type operating rods had reliability problems from the very

beginning. Aging of these rods including the associated internal PD has resulted in

premature failures. The detected UHF discharge suggested a fairly quick deterioration of

the insulation properties and triggered the replacement of these operating rods.

The replaced operating rods of the disconnect switches are functioning well and there

seems to be no immediate danger of further failures. The only concern is that we do not

have long time experience on these newly designed rods and therefore there is no

historical data available to evaluate the long term reliability.

To 4. All electrical operating mechanisms of the disconnect switches have been disabled

do to unreliability. The adjustment of the auxiliary switches is extremely difficult and

also unstable. The result is a drifting “start-stop position” for the motor and the switch

position for the remote indicators are some times incorrect. The aux. contacts themselves

have a tendency to corrode. Presently all switching operations are carried out manually.

This can easily lead to human error and is potentially dangerous. A correctly interlocked

disconnect switch can not be operated in the wrong mode. At Mica it is relatively difficult

to gain access to the disconnect switches and associated operating mechanisms. Due to

this fact the writer thinks it is easy possible for the operator to make a mistake and

manually open or close a wrong disconnect switch. Should an operator error occur and a

disconnect switch is opened or closed in the wrong mode, a ground fault at the switch is

unavoidable. The operator will be positioned within 2 or 3 feet of this fault, shielded only

by the enclosure of the GIS. The resulting induced voltages and currents to the platforms

and structures are potentially dangerous, not to mention a possible melt-through of the

enclosure. Additionally these disconnect switches can not be used to de-energize the

transformers and associated bus-works. The manual operation takes substantially more

time than remote control . The extra time to perform the switching and the inability to

switch under live condition increases cost, loses revenue and reduces operational

flexibility.


Page 2 of 7


June 30th

-2007


PHONE 724-933-0260 FAX 724-933-0266

To 5. A “Barrier-type” insulator is supposed to be a barrier between two gas

compartments. This condition is designed to allow work to be performed on one side of

the barrier without degassing the other. If an internal leak exists through the barrier, the

SF6 gas can escape during inspection and/or maintenance and can cause a failure if not

detected. The station personnel reported at least one of these incidents at Mica. Aging

has an effect on the integrity of the sealing system of the barrier insulators. This fact will

contribute to future difficulties maintaining the GIS.

To 6. The Density Monitors provide a vital function by constantly checking the

temperature compensated pressure inside the SF6 compartments. If a Density Monitor

should fail to provide the “Low Gas Pressure Alarm” on time, an internal flashover would

result. We have found no history of a Density Monitor failure. Calibration and regular

checks of the Density Monitor’s set points are a requirement. These checks should be a

combination of manufacturer’s recommendations and operational history. In a GIS

installation with a history of many leaks, the function of these Density Monitors becomes

very critical. The station personnel mentioned that they check the internal pressure of

each SF6 compartment manually approx. every two month. A modern GIS has a visible

pressure indicator in combination with the density monitor. This eliminates the manual

task of connecting and disconnection a pressure gauge to each compartment every few

month, reducing the risk of further leaks being introduced.

To 7. The existing UHF PD signatures point to a potential problem on some of the

sliding contacts. Similar signatures where found at burning or welding of sliding contacts

in other stations. At this time the condition of the inspected sliding contacts at Mica

(from the switchgear building) is very good. The remaining sliding contacts in the lead

shafts and transformer gallery bus runs are unknown. They have not caused any failures.

If a life-extension of the ITE GIS at Mica should be considered an inspection of the

sliding contacts would need to be included in this process, especially in areas where UHF

signatures have indicated contact burning.

Other UHF fingerprints / time of flight measurements indicate some PD at or near support

insulators. If the level of PD, based on test results (chemical & UHF), is judged to be

dangerous, then these areas should be inspected and possible corrective action taken.

To 8. The presently installed Surge Arresters are of the Gap-Type design. These

arresters are obsolete. They are installed primarily to protect the 16/550 kV transformers.

The new, much more reliable, design is a Metal-Oxide. The new type arresters provide a

much better protection, especially against faster rising transient over-voltages. Counter

readings indicate that these arresters are in working condition.

To 9. At this moment there are a few leaks on flanged connections. The O-rings and

seals in the rest of these flanges and entering points of operating shafts are aging faster

than other components of this GIS. Historically the leakages on gaskets, seals and O-

rings increase at an accelerating rate. The O-rings, gaskets and seals are getting older.


Page 3 of 7


June 30th

-2007


PHONE 724-933-0260 FAX 724-933-0266

The artificial softener imbedded into the rubber evaporates with time. The hardening and

associated shrinkage of these rubber type materials accelerates with age until they loose

all memory and elasticity. To replace these seals and O-rings the switchgear would need

to be dismantled. The leakage rate indicates that this GIS is getting closer to the time

when this work is unavoidable. Newer type of sealing compounds have a longer live

expectancy.

To 10. These springs have been a problem in other ITE GIS installations. This contact

spring provides solid electrical contact between the sliding busbar and the inner metallic

inserts of the support insulator. If the contact spring is displaced and/or looses the contact

pressure the metallic insert becomes a floating potential with partial discharges. The

particular vintage of GIS installed at Mica has a flat contact spring. This flat spring is not

associated with the kind of failures reported at other stations where a round spring was used.

Operational History

By-Pass Piping:

The design of the by-pass piping is not up to present standards. Leakages, even after

repair, can not be totally avoided indicated by increasing leakage rate in 2006 compared

to 2005 after repair of by-pass piping.

Bolted Flanges and Enclosures:

Leakages continue in some areas and will increase with time. Provisions for dismantling

some sections of the GIS-BUS are not part of this design. Therefore the replacement of

O-rings are going to be very time consuming.

Epoxy components:

The conical support and barrier insulators have no history of internal failure and are

actually of a reliable design. Nonetheless there is some evidence of small PD on or near

some insulators. We believe that this PD is not significant enough to cause failures in the

immediate future. Some of the epoxy operating rods of the disconnect switches with PD

have been replaced. Ground-switch insulators are prone to leakage.

Electrical Failures:

Mica GIS operating fault history confirms that most failures were associated with the

disconnect switch operating rods and disconnect switches inability to switch magnetizing

current of transformers and associated GIS bus.

The reason for the reported flash-over in LS1 in November of 1984 could not be clearly

identified. It was speculated that electrical stress from an earlier transformer failure could

have contributed to this flash-over. This failure was not internal to the insulator. This

fact makes us believe that the support and barrier type insulators are actually of sound

design and are not subject to regular failures. However some insulators show signs of

internal PD (small voids or contamination in epoxy). This is not a design but a


Page 4 of 7


June 30th

-2007


PHONE 724-933-0260 FAX 724-933-0266

manufacturing defect which was not detectable at time of production due to non

availability of UHF testing. The risk for future failures is relatively small, specially if

UHF testing is done in regular intervals and UHF signal fingerprints are compared.

Inspections

A. We verified that many SF6 leaks are still present at by-pass piping and other

components. The design and age combination of this type of GIS does not

allow many of these leaks to be corrected economically and reliably.

B. During the site visit we had the opportunity to inspect many of the

components removed from the switchgear building. The sliding contacts are

in very good condition. The metallic (Aluminum) portion of the bolted flanges

and enclosures have no signs of corrosion and appear also to be in very good

condition, specially if compared with an outdoor installation.

C. The surge-arresters have been regularly checked and there is no evidence of

SF6 leaking into the Nitrogen compartments. Operating counters show that

the arresters have operated.

Recommendations

I. For the immediate future:

The probability for immediate failures exist mainly at the disconnect switch

operating rods. To secure the operational reliability and safety of the GIS, all of

the remaining disconnect switch operating rods need to be changed. After all

operating rods have been replaced a new UHF survey should be done and

fingerprints compared to previous results. If the operating rods are not replaced,

UHF tests have to be done at least once per year to monitor the condition and

deterioration of these rods.

II. Medium term solution (approx. 5 years –see also VI. below)

a. Repair and stop all SF6 leaks including replace all O-rings in bolted flanges

and all shaft seals.

b. Investigate and repair units with higher level of PD

c. Replace SF6 Monitors, add extra monitors and create smaller gas

compartments. This makes searching for leaks easier.

d. Regular tests and surveys need to be part of the maintenance program.

III. Long term solution (5 to 30 years)

a. Install a GIS bus run in the 3rd

lead shaft

b. Replace all the GIS components in the transformer gallery, including the busbar

c. The existing lead shafts are working adequately at this time. Their

replacement should be determined by future leak rates and other occurring

operational problems. After the installation of the 3rd

lead shaft, an outage of

any lead shaft does not represent any longer a high operational risk.


Page 5 of 7


June 30th

-2007


PHONE 724-933-0260 FAX 724-933-0266

IV. Internal inspections can only be recommended as a last step to assist in the

decision making to extend the life of the Mica GIS. In case a life extension

should be considered, internal inspections should be based upon further UHF

survey in combination with chemical analysis of the SF6 and acoustic testing.

This combined process might help to determine if a life extension is justified.

V. The UHF signatures reveal that there are still severe problems at some

locations. It is known that the disconnect operating rods are the single most

failure prone component. We highly recommend to monitor the situation of

the disconnect operating rods very closely and change all of them to the new

design at the first possible opportunity.

VI. Remarks to the recommendations:

How many of the above recommendation can or should be implemented

depends on monetary and philosophical considerations including future plans

for this station. The problems resulting in the complex operating procedures

(manual operation of disconnect and grounding switches and manual checks

for SF6 pressure) can not be resolved without considering the long term plans.

If a replacement GIS is considered than the recommended “Medium Term

Solutions” may be delayed until the new GIS is installed. However some

unscheduled outages, repairs and maintenance will most likely be the result of

this delay.

Summary

The GIS at Mica is 30 years old. Based on the “ pioneer type design” at time of

production, it has survived and served reasonably well. New designs of GIS take

advantage of experience gained during this time frame and also of the availability of new

materials ( gaskets, seals, polymers)

Future reliability and end of life of major components can not be determined very

accurately, however our assumption is that the disconnects and ground switches are at the

end of their reliable live cycle. This is mainly due to the aging of seals, O-rings and

leaking by-pass plumbing. The disconnect switches have never been capable of

switching transformer currents as per original specification. Further, the Motor Operated

Mechanisms of the disconnect switches are non functional and it is almost impossible to

reliably repair these mechanisms.

The bus runs and associated insulators could probably survive some time without too

many failures. The lack of “Dismantling Units” however makes it very hard and time

consuming to do any maintenance; not only on the bus runs but also on the disconnect

switches. Present and increasing leakage rates on by-pass plumbing and bolted flange

seals are limiting the economic long term life extension.


Page 6 of 7


June 30th

-2007


PHONE 724-933-0260 FAX 724-933-0266

The lead-shaft bus can not be surveyed using the UHF method due to the fact that there

are no windows or any other ports to access the PD signals. Acoustic surveys provide

only some information about the health of the lead shaft bus insulation.

If no maintenance is done the following could happen.

• SF6 Leaks will increase beyond maintainability

• Disconnect operating rods will fail

• Density monitors will fail

• SF6 will leak into nitrogen filled compartments of surge arresters

• Eventually support (cone) insulators will start to fail internally

• Sliding contacts could eventually deteriorate, even so, present evidence does not

support serious contact problems at many locations.

The writer thinks that the ITE GIS has served its purpose. The availability of newer,

better and more reliable components and bus runs justifies replacement of the existing

GIS. The long term solution is the replacement of the ITE designed GIS; at least all the

GIS in the transformer gallery should be replaced. This would ensure future, very reliable

and flexible operation of Mica Creek Power Plant. The fact that we have a third lead

shaft available and an existing plan to install two additional generators, should aid and

accelerate the decision making process for the renewal of the ITE GIS as recommended

above.

This report has been prepared by

Edgar Heil Rohe International, Inc.


Page 7 of 7

Report for the attention of

Mr Owen Williams

Project Manager, Generation

BCHydro

THE PRESENT CONDITION AND FUTURE RELIABILITY OF THE TRANSFORMER GALLERY GIS

AT MICA 500kV SUBSTATION

Prepared by

Brian Hampton

25 June 2007


Page 1 of 15

1

CONTENTS

1. Objective

2. Review of significant reports

2.1 Operating history

2.2 Diagnostic testing

3. Assessing the future reliability of the Transformer Gallery GIS

3.1 Plant items

3.1.1 Gas leaks

3.1.2 Disconnects

3.1.3 Surge arresters

3.2 Busbar configuration

3.2.1 Transformer bay connections

3.2.2 Lead shafts

4. Failure risk assessment

5. Proposed actions to improve the future reliability of the GIS

5.1 Factors to be considered

5.2 Recommendations

6. Further diagnostic studies

7. Acknowledgements

8. References

Appendix

CV of Brian Hampton


Page 2 of 15

2

1. Objective

The purpose of the study reported here is to assess the present condition of the 500kV GIS

located in the Transformer Gallery and lead shafts at Mica by reviewing its operating history,

together with the inspections & diagnostic tests made on it, and recommend actions needed to

ensure its long-term reliability and safe operation.

2. Review of significant reports

2.1 Operating history

The generating units were put into service in 1976 [1], and the initial operating experience

revealed significant defects, which included:

Excessive gas leakage – the GIS specification called for a maximum gas loss of 2% per annum,

but the initial leakage was 0.2% per day. This was said to be caused by poor welds and by-pass

piping joints.

Disconnects – which were found to be incapable of breaking the magnetizing current of the

generator transformers, and had problems with their motor-controlled operating mechanisms.

Another report [2], which includes a written update, includes details which indicate a pattern of

failures in some equipment:

Dec 1976 disconnect failure while de-energising a generator transformer

Aug 1978 disconnect failure while de-energising a busbar

Sept 1978 surge arrester failure during a system over-voltage (said to be a not uncommon

event for conventional, gapped arresters)

Aug 1983 damage to a generator transformer and its associated surge arrester following an

operational error in switching

Apr 1985 the operating rod of a disconnect failed soon after the disconnect was energised

Nov 1985 the same disconnect failed when the replacement operating rod failed

1989 disconnect failed when its operating rod flashed over

It will be seen that over this period, five failures occurred in disconnects. These can be attributed

to either their poor design or manufacture. The other two failures involved surge arresters, and

were probably caused by these conventional, gapped arresters being too slow to suppress the

very fast transient over-voltages which occur in GIS. All this points to the failures being caused

by generic defects in the plant, and not by infant mortality. It is therefore likely that further

failures of these items will occur.


Page 3 of 15

3

2.2 Diagnostic testing

The high failure rate of disconnect operating rods indicated a possible type fault, and to

investigate this surveys were made of the PD activity in the GIS. These were undertaken using

the UHF technique, which enables any source of PD to be recorded, and both the nature of the

defect & its location to be found. This work is documented in [3,4], and will not be explained

here.

The main conclusions of the studies were:

(i) there were high levels of PD activity over most of Mica GIS

(ii) most of the PD signals were of the same type, and were typical of those coming from

discharges either in or on the surface of solid insulation

(iii) many of these discharges were located, and their source found to be at the operating rods of

disconnects

(iv) the high level of these discharges would have masked most other PD signals which might

have been present, but some further PD typical of floating electrodes was seen. It was thought

that this may have arisen from sparking at the flat spring connection between the barrier inner

sleeve and the conductor. Very high levels of PD typical of contact sparking were also seen

briefly.

Further partial discharge and analytical tests on operating rods taken from disconnects were

made for BC Hydro at the Powertech Labs Inc. The results are comprehensively reported [5,6,7],

and showed that the operating rods examined contained embedded metallic particles, together

with signs that they had been discharging. Subsequent to these tests and analysis, the operating

rod was re-designed and so far those in five disconnects have been replaced. PD

measurements made recently at one of these disconnects still indicated a high level of PD, and

further tests including time of flight location of the PD are needed to clarify this.

3. Assessing the future reliability of the Transformer Gallery GIS

The experience gained with operating the GIS to date, together with the results of the diagnostic

investigations made on it, identify weaknesses in plant items which must be addressed before

an acceptable long-term reliability can be expected. In addition, the present busbar configuration

in the GIS is very inflexible and significant benefits would be obtained by upgrading it.


Page 4 of 15

4

3.1 Plant items

3.1.1 Gas leaks

Gas leaks do not in themselves affect the performance of the GIS unless the gas pressure falls

appreciably, but unless corrective action is taken many outages will be needed over the next

several years when the leaks need to be repaired.

The loss of SF6 to the atmosphere contributes to global warming, especially since the effect of

SF6 on the atmosphere is far greater than that of CO2. Of course we know that against this the

volume of SF6 released is orders of magnitude less than the volume of CO2; but global warming

is a major concern in the West, and governments are seizing every opportunity (real or

imaginary) to be seen to limit the amount of greenhouse gases released to the atmosphere.

The IEC standards presently limit the amount of SF6 that can be lost from a GIS to 0.5% per

annum, and there are proposals to reduce this to 0.1% per annum. It is understood that such

limits do not apply in North America, but there is every chance that similar constraints will be

enforced there before long.The GIS at Mica has always been prone to gas leaks, and records

show that 170kg was used by Generation to replace the losses which occurred in 2005. The

total amount of gas in the Transformer Gallery and lead shafts is 10,521kg, and so the loss rate

for 2005 was 1.6%.

A gas leak survey conducted by EPRI in 2001 revealed 75 leaks in the following locations (note

that this survey included the switchgear floor):

Number of leaks Leak description

36 Bypass pipe assembly

9 Desiccant plugs in cabinet

7 Plumbing fittings in cabinet

4 Ground switch flange

6 Repair site bolted flange leaks

6 Welds

2 Access cover flange view ports

1 Access cover flange

1 Ground switch view port

1 Rupture disk

2 SF6 tank plug


Page 5 of 15

5

Most leaks were found in the gas by-pass lines, which contain many compression joints made

with what appear to be standard plumbing fittings. Many of the leaking fittings were tightened to

reduce the gas loss, and in a random inspection made now, some six years later, some were still

gas-tight. Against this, leaks were found in other by-pass lines. The instrument used to check the

leakage was a Dilo Leak Detector type 3-033-R002, and it is not known how the sensitivity of the

present measurements compares with those made by EPRI.

However, it is not thought that leaks in the by-pass lines present a major maintenance problem,

because it would not be difficult to replace the lines either by others of welded construction, or

with high quality fittings designed for use with gas. Similarly, leaks found in access cover ports,

or other situations where the O-ring seals are easily accessible, may readily be repaired if the

flanges and O-ring groove are in good condition.

The situation with leaks occurring at bolted flanges between bus chambers is quite different, and

often it would be necessary to dismantle a major part of the bay before the joint could be

separated, or the busbar moved until O-rings could be passed over it. The need to replace these

seals is likely to increase in the future as the present neoprene and ethylene propylene rubber

O-rings age – especially since they have a very much smaller cross-section than the O-rings

commonly used today, and will deform more readily.

It is interesting to note that there are 24 gas seals in the two lead shafts, 20 in the main busbars,

and 240 in the transformer bays. The importance of first sealing the transformer bays is evident.

3.1.2 Disconnects

There are no circuit breakers in the Transformer Gallery, and disconnects are used to isolate

those sections which, for whatever reason, need to be grounded. For example, if a generator is

out of service for maintenance, the generator breaker is opened to isolate it from the low-voltage

winding of the generator transformer. However the high-voltage winding of the transformer

continues to be back energised from the 500kV busbar, from which it draws a magnetising

current. The normal practice would then be to open the bay disconnect so that both the

transformer and surge arrester could be grounded. However, the existing breakers have proved

to be incapable of interrupting the magnetizing current, and may, as in Dec 1976, fail if this is

attempted. Since then the procedure of operating disconnects only when the busbars are de-

energised has been in place, and without this restriction many more failures would have


Page 6 of 15

6

occurred – although the penalty of doing so has been the loss of the twin generator when the

single busbar is de-energised. This is the first problem with the disconnects.

Second, the motor drives of the disconnects were defective, and have been disabled. This

means that the disconnects and earth switches have to be operated manually, which prevents

any safety interlocking and leads to a higher risk of operator error. These factors lead to an

unwelcome restriction on normal operating practice.

Third, the present disconnect operating rods are faulty, and it has not yet been shown that the

replacement rods being applied on a limited scale have solved the problem. The many studies

made in universities and research laboratories throughout the world have shown that some

types of defect are more likely to cause failure than others. In particular it is recognised that

flashover across an insulating surface can occur quite readily, for example if it is triggered by a

defect on or embedded in its surface. The explanation for this is that the tip of the triggering

discharge deposits charge on the surface as it travels across it, and since the insulating material

has a relatively high permittivity, a high charging current is maintained in the discharge channel.

This results in a low voltage drop along the length of the channel, which maintains the high

electric stress at its tip. The discharge then becomes self-propagating until it reaches the

opposite electrode. Any insulating surface, in this case that of a disconnect operating rod, is

inherently weaker than either the gas in which it is immersed or the solid insulation, and defects

on it are particularly to be avoided.

Fourth, gas leaks are present in at least some disconnects.

In summary, the disconnects are in a poor state and will cause further problems in the future

unless remedial action is taken.

3.1.3 Surge arresters

The gapped type of surge arresters fitted at Mica are of quite complex construction, and contain

both SF6 and nitrogen filled compartments. Bearing in mind that the gas seals in the arresters

are now 30 years old, it seems likely that internal gas leakages will occur in the not-too-distant

future.

SF6 molecules have a high electron attachment coefficient, which gives the gas its excellent

electrical strength. Non-attaching gases such as nitrogen are inherently much weaker, but


Page 7 of 15

7

adding a proportion of SF6 to them raises their strength markedly. The protective gaps in a surge

arrester are filled with nitrogen, and if even 1 or 2% of SF6 leaked into the nitrogen the sparkover

voltage of the gaps could increase to a level higher than that needed to protect other plant in the

GIS. This could no doubt be prevented if the arresters were stripped down and serviced, but

they would still have the fundamental disadvantage that they operate slowly compared with the

newer metal oxide arresters, and cannot control the very fast voltage transients generated by

switching operations in the GIS.

3.2 Busbar configuration

3.2.1 Transformer bay connections

Transformer bays 1 & 2 are connected to a single busbar, as are bays 3 & 4. If a failure were to

occur in a busbar, then the output from both the generator bays connected to it would be lost.

This would not be the case if an additional busbar was installed to provide a double busbar (1½

disconnect) configuration.

3.2.2 Lead shafts

If a failure occurred at the lower end of a lead shaft, in a gas zone next to the disconnect, it is

understood (discussion with Mr Darren Kahl) that the disconnect would not provide a point of

isolation, and the main busbar would need to be taken out of service while a repair was made.

This would not be the case with a double busbar configuration.

4. Failure risk assessment

The CIGRE Task Force D1.03.09 ‘Risk Assessment of Defects in GIS based on PD Diagnostics’

was set up 5 years ago with the objective of collecting data and developing the procedures to

calculate the risk of a GIS failing due to a particular defect. This has proved to be an impossible

task. In laboratory studies where all the parameters of the defect (size, shape, motion pattern,

etc.) are known, and the applied stress can be varied, it can sometimes be predicted that failure

will occur. In an operational GIS, PD measurements reveal only the type of defect, its

approximate discharge magnitude, and its location – and with only this data a risk assessment

cannot be calculated with any confidence.

For the time being at least, the prediction of failure remains an art based on the considerable

experience gained using UHF measurements in GIS the world over. My previous company, for

example, is presently continuously monitoring the PD data from upwards of 80 GIS rated from


Page 8 of 15

8

154-800kV, and advising utilities when it seems necessary to intervene and correct a defect.

The characteristics of the UHF signals which allow this judgement to be made are:

(i) the type of defect (a free particle, floating electrode, void in insulation, etc), which is

determined from the PD pattern

(ii) the location of the defect, found using time-of-flight measurements

(iii) the approximate amplitude of the signal

(iv) whether the signal is constant or intermittent

(v) whether the characteristics of the signal are changing with time (trend analysis)

In truth, there is more experience than science in this, but the results are convincing – over all

the GIS being monitored, only 3 in-service failures have occurred during the past 10 years. With

my own knowledge gained during this time, I have no doubt at all that there is a 99% probability

of Mica GIS failing during the next 10 years unless some action is taken.

5. Proposed actions to improve the future reliability of the GIS

5.1 Factors to be considered

The Transformer Gallery GIS at Mica has proved to be exceptionally reliable over the 30 years in

which it has been in service, and there is a temptation to leave well alone. However there are

signs that it is ageing – discharging disconnect operating rods, discharges in the vicinity of cone

insulators, gas leaks – and it is unwise to assume that the good record will be maintained. With

the present configuration some failures of the GIS could result in a major reduction in output

over periods of some months, and long-term remedial action is needed.

The ways in which the reliability of the GIS could be improved have been examined. The

sections of the GIS most in need of attention are the transformer bays, made up of the

disconnect & surge arrester, and the bus chambers connecting them to the generator

transformer and main busbar. There are three such bays for each generator, and twelve in total.

Consideration was given to refurbishing the bays. For this each bay would need to be

dismantled up to the disconnect flange nearest to the main busbar, so that all the O-ring seals in

the bay could be replaced. The by-pass piping would be renewed at this time. Although the

seals and the operating rod in the disconnect would be replaced, it would still not be possible to

operate it remotely, nor restore its capacity to break the transformer magnetizing current.

The surge arrester is of the gapped type, which was the only one available when the GIS was

built. It too needs refurbishing but even then would not protect the GIS adequately. For this, the

faster-operating metal oxide arrester is needed. In all, the effort required to refurbish the bay in

this way is not commensurate with the benefits obtained.


Page 9 of 15

9

5.2 Recommendations

The objective of this report is to recommend actions needed to ensure the long-term reliability

and safe operation of the Transformer Gallery GIS. However these recommendations are based

solely on a technical assessment, and whether or not they are adopted will depend on other

factors such as weighing the cost of the remedial work against the financial losses which would

be incurred should a failure occur. Without knowledge of the commercial aspects, several

options (Phases 1-3, below) are presented for evaluation.

In these, Phase 1 is the essential work needed to keep the substation in operation; the addition

of Phase 2 adds operational flexibility such that if a failure were to occur in a main busbar, no

longer would half the generating capacity of the station be lost for some weeks; and Phase 3, in

which the reliability of the lead shafts is considered, should also be undertaken. These three

phases naturally follow each other – for example, the condition and probability of a failure in the

main busbars (Phase 2) cannot be properly assessed until the high levels of PD currently arising

in the transformer bays have been eliminated (Phase 1). From a technical point of view, the

highest reliability of the GIS will be achieved by implementing all three of these phases.

Phase 1

Replace the present disconnects by those of a newer design and improved performance, and

the surge arresters by a metal oxide type. Since all the O-ring seals of the chambers would also

need to be replaced, and adaptor plates fitted, it is simpler to replace the complete bay and this

is the recommended course.

It is common practice in many utilities to install UHF couplers into new GIS, for use both during

commissioning tests on the new plant and later when it is in service. Fitting new chambers will

enable internal couplers to be specified, and all major switchgear manufacturers are able to

supply these mounted on a suitable port. (The existing disconnects are fitted with large windows

on which UHF couplers can be mounted, but it is unlikely that any present-day disconnect will

have windows of sufficient size for this purpose).


Page 10 of 15

10

To increase the long-term reliability of the GIS, this needs to be followed by Phase 2. Provision

should be made to install a second main busbar, and changes needed to the present bay are

illustrated in Fig 1.

Fig 1 Layouts of the existing and new transformer bay allowing for Phase 2 (for illustration only)

Phase 2

The transformer bays will now be substantially free of PD, although the operating rods in the

inter-tie and lead shaft disconnects may still be discharging. If this interference is not too high, it

should now be possible to detect and locate any PD activity in the busbar. Should the busbar be

reasonably discharge-free, it could be retained. Whether or not to replace it is essentially a

commercial decision, which would no doubt take into account the number of adaptor flanges

which would need to be fitted to the present busbar.

A second busbar will be installed to improve the operational flexibility of the GIS. The

disconnects at the bottom of the lead shafts will be replaced by separate disconnects for each

busbar. The existing inter-tie disconnects will also be replaced (if the present busbar is to be

retained), and others installed in the new busbar.

disconnect 2 disconnect 1

generator transformer

generator transformer

surge arrester

surge arrester

busbar

busbar 1

provision for busbar 2

disconnect


Page 11 of 15

11

Phase 3

The discharge levels in lead shafts 1 and 2 will be measured, using both UHF and acoustic

technology. Unless a specific problem is found, they will not be replaced until the third lead shaft

is commissioned in 2014.

6. Further diagnostic studies

The reliability of the cone insulators in the busbars has so far been excellent, with only one

failure being reported (lead shaft 1, C phase, 1983). The UHF surveys made in 1999 and 2000

showed a very high level of PD activity throughout the whole GIS, and many of the PD sources

were traced to the disconnect operating rods. Some of these have been replaced by others of a

new design, but the few UHF measurements made subsequently still do not show the GIS to be

completely discharge free. This needs to be investigated further before the operating rods in

other disconnects are replaced.

In the previous surveys, other PD sources were largely masked by the high signals from the

disconnects, but some appeared to be associated with cone insulators. Once the signals from

the disconnects have been eliminated – or at least much reduced – any discharges then found

at the cones should be examined. It is reported in [8] that insulators in sound condition do not

exhibit any ageing mechanisms which might cause an increase in their failure rate with time, and

lifetimes much longer than 30 years are expected. However if the insulators were not

manufactured to a high standard, or have manufacturing defects, their lifetime may be reduced.

The object of this survey is to establish whether any cones are developing internal PD indicative

of degradation.

While the UHF technique is in general the most sensitive method of detecting defects in GIS, it

may lack sensitivity along the lead shafts because no UHF couplers can be fitted there. In this

location further acoustic measurements, such as those reported in [9], may be needed.

Other techniques, notably chemical analysis, have given useful results in the past and may also

be required.

7. Acknowledgement

The assistance given by Mr Bjorn Holm in preparing the technical documents for review, and for

calling on his expert knowledge of the GIS to answer detailed questions, is gratefully

acknowledged.


Page 12 of 15

12

8. References

1. ‘Comparative review of GIS installations in BC Hydro generating stations and their

operating experience’, R F Cleven, CEA SF6 Insulation Coordination Committee, March

1989.

2. ‘Mica Gas Insulated Switchgear – Problems’, Appendix, File 211-1517.16.0, February

1986.

3. ‘Partial Discharge Survey of Mica 500kV GIS’, Brian Hampton, Report to BC Hydro, 30

March 1999.

4. ‘Identifying and Locating Partial Discharges in Mica 500kV Substation’, Brian Hampton,

Report to BC Hydro, 25 May 2000.

5. ‘Failure Analysis on 500kV SF6 Operating Rod from Mica Generating Station’, Powertech

Labs Inc., Project No 12474-27, July-August 2000.

6. ‘Partial Discharge Test on 500kV SF6 Operating Rods from Mica Generating Station’.

Powertech Labs Inc., Project No 12722-27, December 2000.

7. ‘Partial Discharge Test on 500kV SF6 Operating Rods from Mica Generating Station’.

Powertech Labs Inc., Project No 13536-27, February-March 2002.

8. ‘Long-term Performance of SF6 Insulated Systems’, Paper 15-301, Study Committee 15,

CIGRE Session 2002.

9. ‘Detection of Flaws using the Acoustic Insulation Analyser Type AIA-1’, Report No. TN-

40.400.527.1, May 2000.


Page 13 of 15

13

APPENDIX: CURRICULUM VITAE of BRIAN HAMPTON 1951-1954 Undergraduate at Imperial College of Science and Technology, London.

Degree of BSc (Eng) with 1st class hons awarded.

1954-1957 Postgraduate research in the Electrical Engineering Dept. of IC, on the study of

particle tracks in a cloud chamber.

Degree of Doctor of Philosophy awarded.

Associate of the City & Guilds Institute awarded.

Diplomate of Imperial College awarded.

Membership of professional institutions:

Fellow, Institution of Electrical Engineers

Fellow, Institute of Physics

Chartered Engineer

Membership of CIGRE:

UK member, Study Committee 15 ‘Insulating Materials’ 1986-1998

UK member, Working Group 15-03 ‘Gaseous Insulation’ and its WG Task Forces, 1986-

present

Employment:

1958-1988 Research Laboratories of the UK utility Central Electricity Generating Board,

London. Responsible for research into failures in transformers, overhead lines

& gas insulated substations, and for technical collaboration with the Research

Departments of the utilities EDF (France) and ENEL (Italy).

1988-1997 Manager, Diagnostics Laboratory of the Centre for Electrical Power

Engineering, University of Strathclyde, Glasgow. Developed the (then) novel

UHF technique, and its practical application in EHV substations.

1997- 2001 Managing Director, Diagnostic Monitoring Systems, Glasgow, a new spin-out

company from the University. DMS designs and manufactures UHF monitoring

equipment for EHV substations.

2001 –2007 President, Diagnostic Monitoring Systems.

Jan 2007 Retired


Page 14 of 15

14

Experience particularly relevant to the present report:

In 2001 DMS was ready for rapid growth, and I took responsibility for promoting sales. I visited

several of the major utilities many times to discuss the problems they were experiencing with

their GIS, and demonstrate how the UHF technique could help them. Those utilities I came to

know best were in countries where the industry was undergoing the strongest growth, or where

problems with ageing GIS were developing. They were:

Far East: Japan, Korea, Hong Kong, China, Taiwan, Malaysia, Singapore

Middle East: Bahrain, Saudi Arabia, Dubai, Jebel Ali, Sharja

Europe: UK, Germany, France, The Netherlands, Italy

Americas: Canada, USA, Brazil, Paraguay

My experience with GIS in these places has been gained using either portable or installed

monitoring equipment, both during commissioning tests and with GIS in service. Very many

defects were found and corrected during this time, and this has provided the background on

which some of the opinions in my report are based.


Page 15 of 15


Appendix

F

Mica Gas Insulated Switchgear Capital Expenditures

Mic

a G

IS R

epla

cem

ent P

roje

ct -

Sche

dule

of A

utho

rized

Exp

endi

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ion

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5

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0.2

Mica Gas Insulated Switchgear Project Appendix F

Page 1 of 1


Appendix

G

Most Severe Single Contingency

July 13, 2009

Owen Williams, M.Eng, P.Eng, PMP Project Manager, Generation BC Hydro

Re: BCTC’s review of the proposed Mica switchyard configuration:

Dear Owen, Mica GS is one of the largest generation stations in the BC electric system and plays a critical role in system reliability. A high level of reliability is expected from Mica 500 kV GIS switchgear from a system planning perspective. Presently, the Most Severe Single Contingency (MSSC) in the BCTC / BC Hydro system is 1000MW. This represents the largest possible loss of generation as a result of the outage of a single element, a lead shaft at Revelstoke. Once Revelstoke unit 5 is commissioned, the MSSC will increase from 1000MW to 1500MW as three 500MW generating units will be connected to a single lead shaft. Studies for the integration of Revelstoke unit 5 concluded that this increase in MSSC was acceptable. 1500MW was determined to be an upper limit for the MSSC that could be managed by relying on generation reserves within BC and the North West Power Pool without negatively affecting system reliability or transfer limits. BCTC notes that while the proposed designs for Mica units 5 and 6 incorporate the addition of a third lead shaft, there may be switching configurations that allow more than two units connected to a single lead shaft. BCTC will require BC Hydro to limit the amount of generation that may end up being connected to a single Mica lead shaft to 1500MW in order to respect the MSSC limit. Sincerely,

Paul Choudhury

Manager, System Planning & Performance Assessment

c.c. K. Zhang, G. Kehl, G. Wang, BCTC File: STN:MCA

Paul Choudhury P.Eng

Manager, System Planning & Performance Assessment

Suite 1100, Four Bentall Centre

1055 Dunsmuir Street

P O Box 49260

Vancouver, B.C. V7X 1V5

Phone: (604) 699-7374

Fax: (604) 699-7452

e-mail: [email protected]

Mica Gas Insulated Switchgear Project Appendix G

Page 1 of 1


Appendix

H

Lead Shaft Requirements for Mica with Four to Six Units

Lead Shaft Requirement for Mica with Four to Six Units In evaluating replacement options and how the Project can best meet the long term

needs of Mica, an understanding of the number of lead shafts required for different

generating capacities is required. Engineering practice is to design wherever possible, to

ensure the maximum power from Mica can continue to be transmitted in the event of a

single contingency (i.e. a failure of one major piece of equipment). While each lead shaft

is capable of conducting the power of all six units, BC Hydro is restricted to transferring a

maximum of 1500 MW. This restriction is imposed to ensure system wide operating

stability. A sudden drop in generation of 1500MW or more has the potential to impacts

the stability of the electric grid.

Table 1 shows that with the existing four unit Mica and two lead shafts, 500MW of power

cannot be transferred during a planned or forced outage of a lead shaft. Three lead

shafts for a four unit Mica would provide more flexibility and reduce the need for planned

outages for some maintenance and replacement work. Additionally, with three lead

shafts, the capacity at risk in the event of a single GIS equipment failure is nil for Mica

regardless of whether it had four, five or six units.

The addition of one or two more units (estimated at 500 MW each) requires an additional

lead shaft for Mica as otherwise 800 MW or 1300 MW of capacity is at risk in during a

planned or forced outage of a lead shaft GIS.

Table 1 - Capacity at Risk

Description Formula Measure Number of Units

Number of Generating Units Units 4 5 6

Approximate Capacity of incremental Unit MW 500+ 500+

Mica Capacity A MW 1800 2300 2800

Transfer capacity of each Lead Shaft B MW 1500 1500 1500

2 lead shafts in-service Capacity at risk in event of planned or forced outage of one of the two lead

C=A-B MW 300 800 1300

3 lead shafts in-service Capacity at risk in event of planned or forced outage of one of the three lead shafts

D = (B X 2) - A Nil Nil Nil

Mica Gas Insulated Switchgear Project Appendix H

Page 1 of 1


Appendix

I

GIS Replacement Alternative Assumptions

GIS Replacement Alternatives Assumptions

1. Introduction

The purpose of this appendix is to explain the basis for the PVs provided in Tables 4-2 and 4-4

of the Application.

Section 2 of this appendix provides the assumptions used for the PV calculations. Section 3

explains the basis for the range of outage consequences at Mica from $6 million to $19 million

shown in Table 4-2. Section 4 shows how, by combining the outage consequences with outage

probabilities the "Range of Outage costs" shown in Table 4-2 are determined. Section 5

provides the breakdown of the major Project components (i.e., lead shaft 1, lead shaft 2 etc.)

which are used for calculating the PVs of the alternatives and options shown in Tables 4-2 and

4-4. Section 6 provides the construction schedule and cost assumptions used in determining the

PVs for the alternatives in Table 4-2. Section 7 provides the construction schedule and cost

assumptions used for determining the PVs of the options in Table 4-4.

2. Key Assumptions

• The GIS must be replaced by 2025 in all scenarios. This was the original life expectancy of

the asset before considering the actual condition of the asset.

• The discount rate applied for PV analysis is 8 per cent nominal or 6 per cent real.

• $134 million is used as the base case project cost consisting of the implementation phase

project cost (direct) (excluding inflation) of $130.6 million (refer to Table 4) plus $3 million for

planning and engineering (refer to Table 5).

• The estimated costs are based on an ISD of 2013.

• If the Project schedule or staging is changed such that portions of the Project are deferred

cost increases were assumed due to:

tendering and procuring lower quantities;

incremental engineering, planning and design for Identification, Definition and

Implementation phases;

additional interfaces;

Mica Gas Insulated Switchgear Project Appendix I

Page 1 of 10

higher mobilization costs due to multiple mobilizations as a result of piecemeal

approach; and

fixed project costs which would not be reduced due to changes in scope.

• References to lead shaft 3 include the cost of the switchgear building extension, installing

bus in lead shaft 3, circuit breakers, disconnect switches and bus to connect new GIS to

existing GIS. These components are combined due to assumed dependencies. For

example, it is assumed that the switchgear building extension would not occur without

installing GIS in lead shaft 3;

• Escalation rates used range from 0.9 per cent to 3 per cent with cumulative escalation of

25.5 per cent over 15 years or 1.7 per cent average per year. Escalation is an estimate of

the expected incremental inflation on certain cost of materials and labour not included in

estimates of average annual inflation rates. The cost of alternatives which defer a portion or

all of the Project costs to later years are escalated based on these rates; and

• Where GHG offsets are included, the estimated value applied is $23 per tonne of CO2

equivalent. This is based on the 2008 LTAP average cost of the low scenario forecast for

GHG offsets for the period 2013 to 2027.

3. Range of Outage Consequences

This section describes how, for the purpose of this application, the range of outage

consequences at Mica is determined. This range of outage consequences is, as described in

section 4 below, combined with various probabilities of outages to come up with the “range of

outage costs” for each alternative in Table 4-2 of the Application.

Mica represents 16 per cent of BC Hydro’s capacity and all of the units have an annual average

utilization factor of 45 per cent. Maintenance is usually performed in the April to July period of

each year, with planned outages on two units. During winter peak periods and in late July to

September the utilization factor is higher due to domestic load and trade opportunities.

The opportunity cost of capacity and energy vary significantly due to domestic load

requirements, trade opportunities, and variances in water conditions and stream flows in the

Pacific Northwest. If a one unit forced outage were to occur during the winter peak the

opportunity cost is estimated to be about $2 million per week based on:

Average import price net of transmission cost = $40/MWh


Page 2 of 10

Capacity per unit = 450 MW

Winter Load = 69 per cent

Opportunity Cost = $2 million 1 per week.

The cost of outages at Mica can be significantly reduced because, in most cases, the water can

be held in the reservoir for future generation and future revenue earning opportunities. However,

depending on reservoir levels and stream flow conditions, situations could occur where water

would have to be spilled at Mica to maintain water flows downstream for Revelstoke and for

water license requirements. Although less likely to occur, the consequence of spilling are costly.

GIS failures can result in extended forced outages. Failures of GIS in a lead shaft could take

ten weeks to repair as access and repair is challenging. Combined with the lack of spare parts

for the equipment, outages of two days to 12 weeks are considered likely. The cost of

purchasing replacement parts on an emergency basis can be two to three times more than the

cost to purchase on a planned basis. Depending on the cause and location of a GIS failure in

Mica, two unit outages are also possible. Table 1 provides examples of potential outage

consequences, with a range in value of $2 million to $36 million.

Table 1 Potential Outage Consequences (in $000’s)

Outage Scenario Opportunity Cost Energy

Capacity Reservation

Labour and Material

Total Outage cost

Assumption

A Forced outage in spring

Nil Nil $2,000-6,000 $2,000-6,000 Forced outage occurs between April to July

B 6 week of 2 Unit forced outage

$1,740 $850 $2,000 $4,590 Valuation based on equal chance of outage throughout year, Opportunity cost of energy at $43.25/MWh, Capacity Reservation cost at $17/MW winter

C 12 weeks of 2 units forced outage

$4,080 $1,700 $4,000 $9,780 Same assumption as B

D 4 weeks of 4 units forced outage

$8,210 $2,620 $6,000 $16,830 Same assumption as B

1 450MW x $40/MWh X 24 hours/day x 7 days/week x 69 per cent = $2 million per week.


Page 3 of 10

Outage Scenario Opportunity Cost Energy

Capacity Reservation

Labour and Material

Total Outage cost

Assumption

E 6 week of 2 Unit forced outage

$3,480 $1,060 $2,000 $6,540 Validation based on equal chance of outage throughout the year. Opportunity cost of energy based on 2006 Call for Tender price of $83/MWh net of transmission, Capacity Reservation cost at $34/MW

F 12 weeks of 2 units forced outage

$8,160 $2,125 $4,000 $14,285 Same assumption as E

G weeks of 4 units forced outage

$16,420 $3,275 $6,000 $25,695 Same assumption as E

H 300 MW loss resulting from single lead shaft failure, 8 weeks

$7,260 $3,000 $10,260 300 MW outage, Opportunity cost of energy estimated at $40 MWh; 45 per cent plant utilization of all units.

I 300 MW loss resulting from single lead shaft failure, 8 weeks

$23,090 $6,000 $29,090 300 MW outage, Opportunity cost of energy estimated at $83 MWh and 69 per cent winter plant utilization.

J 450 MW unit out 8 weeks outage

$10,890 $1,000 $11,890 450 MW outage, Opportunity cost of energy estimated at $40 MWh; 45 per cent average plant utilization.

K 450 MW unit out 8 weeks outage

$34,640 $2,000 $36,640 450 MW outage, Opportunity cost of energy estimated at $83MWh and 69 per cent winter plant utilization.

Table 1 illustrates outage costs depending on time of year, market prices, plant utilization and

water conditions for some probable outage scenarios. To reduce the number of scenarios for

financial analysis, the range of potential outage consequences is reduced to probable low,

moderate and high consequences. Outage values provided in Table 2 below are used as

proxies for the outage costs of Mica.


Page 4 of 10

Table 2 Range of Outage Consequence Costs used in Financial Analysis

Outage Consequence Scenario Total Cost

($ million)

Low Consequence $6

Moderate Consequence $12

High Consequence $19

In 2009, a review of the consequence of extending a planned four month (April to July) two unit

outage by one month through August was estimated to cost between $3 million and $20 million.

Given that prolonged planned two-unit outages during this period are common, the study

supports the range of values in Table 2 being used in the financial analysis in Table 4-2 of the

Application.

4. Probability and Cost of Outages

This section describes how the range of outage consequences in Table 2 is combined with the

probability of a failure at Mica to determine the PV of outage costs. The PV of outage costs are

then used to determine the “range of outage costs” in Table 4-2 of the Application.

One of the independent GIS experts who assessed the Mica GIS concluded that there was a

99 per cent chance of a GIS failure within ten years or, in other words, there is a 33 per cent

chance2 of failure in each of the next ten years. The risk of a GIS failure is expected to increase

over time as the GIS ages.

Table 3 provides a summary of the PV of the potential cost of outages if BC Hydro deferred the

replacement for ten years. The PV of outage costs is shown for the three outage consequence

scenarios from Table 2 and a range of annual failure probabilities.

2 A 99 per cent failure in ten years can be translated to a 33 per cent failure per annum by applying the Bernoulli

formula as follows: [Probability of Failure in x = 1 - (1 - Probability of failure/year)x ].


Page 5 of 10

Table 3 PV Cost of GIS Failures at Different Probabilities of Failure for 10 years

Model Parameters

Real discount rate 6.00%

Number of useful years of service 10 Annual Probability of Failure

Outage Cost Predicted

Scenario Parameters ($2009 $000) 15.0% 20.0% 33.0% 40.0%

Case 1 - Low Consequence $6,000 ($000) ($000) ($000) ($000)

Annual Outage Costs

($6000xAnnual Probability of Failure) $900 $1,200 $1,980 $2,400

PV of Outage Costs for 10 years $6,624 $8,832 $14,573 $17,664

Case 2 - Moderate Consequence $12,000

Annual Outage Costs

($12000xAnnual Probability of Failure) $1,800 $2,400 $3,960 $4,800


Case 3 - High Consequence $19,000

Annual Outage Costs

($19000xAnnual Probability of Failure) $2,850 $3,800 $6,270 $7,600


5. Project Cost

In order to determine the PV of the alternatives and options in Table 4-2 and Table 4-4 of the

Application, the costs of the components of the Project (i.e. lead shaft 1, lead shaft 2 etc) were

determined. This section provides the component costs.

Table 4 is the breakdown of total Project costs. The $2009 Implementation phase direct capital

cost of the Project is used for the financial analysis. The direct cost represents the incremental

cost to BC Hydro before, inflation, IDC and overhead. The breakdown of Implementation phase

direct costs by component is shown in Table 5.


Page 6 of 10

Table 4 Project Cost

PROJECT COST AMOUNT ($ million)

Direct Construction Cost 94.6

Project Management and Engineering 18.8

Sub-total: Construction Cost before Contingency $113.4

Contingency on Expected Cost 11.3

Dismantling and Removal 1.0

Escalation 4.9

Implementation Phase Cost (Direct Capital) $2009 $130.6

Inflation 3.5

Sub-total: Implementation Phase Cost (Direct Capital) $134.1

Capital Overhead 17.7

Interest During Construction 21.3

Sub-total: Implementation Phase Cost (Loaded) $173.1

Identification and Definition Phase (Loaded) 7.5

Total Expected Cost $180.6

Project Reserve 19.6

Total Authorized Cost $200.2


Page 7 of 10

Table 5 Allocated Implementation Phase Direct Cost by Major Component

Component Cost ($2009 millions)

Replacement of existing GIS in transformer gallery 31

Replacement of existing GIS in switchgear building 14

Lead shaft 2 13

Lead shaft 1 13

Lead shaft 3, switchgear building extension, and all new GIS required in the transformer chamber and switchgear building

60

Total Implementation Phase (Direct) Project cost $131 Identification and Definition Planning and Engineering (Direct) 3

Total Direct Cost $134

The cost of implementing a different scope of work in the future is not expected to be equivalent

to the allocated component cost shown in Table 4. The cost to design, engineer and procure a

smaller scope of work is not proportionally reduced by the scope of the Project. To provide a

comparison of the alternatives in Table 4-2 and options in Table 4-4, the total direct cost

($2009) for the Project of $134 million is compared to the alternatives of Table 4-2 in Table 6

and compared to the options of Table 4-4 in Table 7 below.

6. Alternative Analysis

Table 6 provides a summary of the direct costs ($2009) for the alternatives of Table 4-2 along

with the construction schedule and cost assumptions used to determine the cost of the

alternatives. All alternatives assume that Identification and Definition phase Project costs will be

$3 million for the Project undertaken in full and for components of the Project that are deferred.

The costs are escalated to reflect the cost that is likely to be incurred if deferred but exclude

general inflation increases. Cash flows are discounted by 6 per cent.


Page 8 of 10

Table 6 Cost of Replacement Alternatives

Description of Alternative Construction Schedule and Cost Assumptions

Percent change in cost from

Base (%)

Direct Cost ($2009 millions)

Alternative 1: Implement Full Project Scope by 2013

Base Case, lead shaft 3 (2010/11), lead shaft 2 (2012) and lead shaft 1 (2013).

Base 134

Alternative 2a: Implement lead shaft 3 by 2013, defer replacement of existing GIS by 5 years

Lead shaft 3 (2011/12), replacement costs deferred (2017 or 5 years) Base Case plus additional $3 million for duplicate planning costs as Project segmented.

2 136

Alternative 2b: Implement lead shaft 3 by 2013, defer replacement of existing GIS by 10 years

Lead shaft 3 (2011/12), replacement cost deferred (2021 or 10 years). Base Case plus additional $3 million for duplicate planning costs as Project segmented.

2 136

Alternative 3: Implement lead shaft 3 by 2013, piecemeal replacement of existing

Lead shaft 3 (2011/12) replacement of existing GIS in 4 separate projects over next 10 years. Additional costs incurred for planning, procurement and mobilization

15 153

Alternative 4: Implement lead shaft 3 by 2013, defer replacement of Lead shaft 1 and 2

Lead shaft 3 (2011/12), transformer gallery and switchgear building GIS (2012/2013), lead shaft 2 (2020) and lead shaft 1 (2021) Additional costs incurred for higher procurement and mobilization.

9 146

7. Option Analysis

Table 7 provides a summary of the direct costs ($2009) for the options of Table 4-4 along with

the construction schedule and cost assumptions used to determine the cost of each option.

Since the ISD for Mica Unit 5 is uncertain, the dates and hence the timing of the investment in

the lead shafts 1, 2 and 3 have been varied. However for all alternatives it has been assumed

all Project components would be in-service before Mica Unit 5. Options 2, 3 and 4 are

implemented before 2018 while option 5, 6 and 7 are implemented before 2025. It is assumed

that certain planning and engineering, mobilization and procurement costs would not decline

proportionately if portions of the Project were deferred. All alternatives assume that Identification

and Definition phase Project costs will be $3 million for the Project undertaken in full and for


Page 9 of 10

components of the Project that are deferred. The costs are escalated to reflect the cost that is

likely to be incurred if deferred but exclude general inflation increases. Cash flows are

discounted by 6 per cent.

Table 7 Cost of Options

Description of Alternative Construction Schedule and Cost Assumptions

Percentage change in cost

from Base (%)

Direct Cost ($2009 millions)

Option 1: Implement Full Project Scope by 2013

Base Case, lead shaft 3 (2010/11), lead shaft 2 (2012) and lead shaft 1 (2013).

Base $134

Options 2: Replace existing GIS by 2013, defer lead shaft 2 and 1

Lead shaft 3 (2010/11), existing in transformer gallery and switchgear (2012/2013), lead shaft 2 (2017), lead shaft 1 (2018). Estimated of increase based on fixed procurement, planning and mobilization costs.

9 146

Options 3: Replace existing GIS by 2013, defer lead shaft 3

Existing in transformer gallery and switchgear building (2010/2011), lead shaft 2 (2012), Lead shaft 1 (2013) lead shaft 3 (2016/17) Estimated of increase based on fixed procurement, planning and mobilization costs.

17 157

Options 4: Replace existing GIS and implement lead shaft 3, defer lead shaft 1

All existing and lead shaft 3 by 2013 except lead shaft 1 (2018) Estimated of increase based on fixed procurement, planning and mobilization costs.

4 139

Options 5: Replace existing GIS by 2013, defer lead shaft 2 and 1

Lead shaft 3 (2010/11), existing in transformer gallery and switchgear (2012/2013), but Lead shaft 2 (2023), Lead shaft 1 (2024) Estimated of increase based on fixed procurement, planning and mobilization costs.

9 146

Option 6: Replace existing GIS by 2013, defer lead shaft 3

Existing in transformer gallery and switchgear building (2010/2011), lead shaft 2 (2012), lead shaft 1 (2013) lead shaft 3 (2023/2024) Estimated of increase based on fixed procurement, planning and mobilization costs.

17 157

Option 7: Replace existing GIS and implement lead shaft 3, defer lead shaft 1

All existing and lead shaft 3 by 2013 except lead shaft 1 (2025) Estimated of increase based on fixed procurement, planning and mobilization costs.

4 139


Page 10 of 10


Appendix

J

First Nations Consultation Record

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Mica Gas Insulated Switchgear Project Appendix J-1

Page 1 of 27

Switc

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Page 2 of 27

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erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.

2009

-Feb

-19

KN

C

Lette

r BC

H (R

yan

McF

adde

n)

KN

C (B

ill G

reen

) N

/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.


Page 3 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 4

of 2

7

2009

-Feb

-19

Lhei

dli T

’enn

eh

Lette

r BC

H (R

yan

McF

adde

n)

Lhei

dli T

’enn

eh

(Chi

ef D

omin

ic

Fred

eric

k)

N/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.

2009

-Feb

-19

Littl

e S

husw

ap

Lette

r BC

H (R

yan

McF

adde

n)

Littl

e Sh

usw

ap

(Chi

ef F

elix

Ar

nous

e)

N/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.

2009

-Feb

-19

Low

er K

oote

nay

Lette

r BC

H (R

yan

McF

adde

n)

Low

er K

oote

nay

(Chi

ef C

hris

toph

er

Luke

) N

/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g


Page 4 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 5

of 2

7

will

look

like

with

the

exte

nsio

n;

a

diag

ram

sho

win

g an

arc

hite

ctur

al v

iew

of h

ow

the

lead

shaf

ts c

onne

ctin

g th

e sw

itchg

ear b

uild

ing

to th

e un

derg

roun

d po

wer

hous

e; a

nd

P

ower

Poi

nt p

rese

ntat

ion

on th

e G

IS P

roje

ct w

as

give

n at

the

Janu

ary

29, 2

009

Cor

e C

omm

ittee

.

2009

-Feb

-19

Low

er

Sim

ilkam

een

Lette

r BC

H (R

yan

McF

adde

n)

Low

er

Sim

ilkam

een

(Chi

ef J

osep

h D

enni

s)

N/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.

2009

-Feb

-19

Nes

konl

ith

Lette

r BC

H (R

yan

McF

adde

n)

Nes

konl

ith (C

hief

Ju

dy W

ilson

) N

/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.


Page 5 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 6

of 2

7

2009

-Feb

-19

Oka

naga

n Le

tter

BCH

(Rya

n M

cFad

den)

O

kana

gan

(Chi

ef

Fabi

an A

lexi

s)

N/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.

2009

-Feb

-19

ON

A

Lette

r BC

H (R

yan

McF

adde

n)

Oka

naga

n N

atio

n Al

lianc

e (E

xecu

tive

Dire

ctor

Pau

line

Terb

aske

t)

N/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.

2009

-Feb

-19

Oso

yoos

Le

tter

BCH

(Rya

n M

cFad

den)

O

soyo

os (C

hief

C

lare

nce

Loui

e)

N/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g


Page 6 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 7

of 2

7

will

look

like

with

the

exte

nsio

n;

a

diag

ram

sho

win

g an

arc

hite

ctur

al v

iew

of h

ow

the

lead

shaf

ts c

onne

ctin

g th

e sw

itchg

ear b

uild

ing

to th

e un

derg

roun

d po

wer

hous

e; a

nd

P

ower

Poi

nt p

rese

ntat

ion

on th

e G

IS P

roje

ct w

as

give

n at

the

Janu

ary

29, 2

009

Cor

e C

omm

ittee

.

2009

-Feb

-19

Pen

ticto

n Le

tter

BCH

(Rya

n M

cFad

den)

P

entic

ton

(Chi

ef

Ste

war

t Phi

llip)

) N

/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.

2009

-Feb

-19

Shus

wap

Le

tter

BCH

(Rya

n M

cFad

den)

Sh

usw

ap (C

hief

P

aul S

am)

N/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.


Page 7 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 8

of 2

7

2009

-Feb

-19

Sim

pcw

Le

tter

BCH

(Rya

n M

cFad

den)

S

impc

w (C

hief

K

eith

Mat

thew

) N

/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.

2009

-Feb

-19

Ske

etch

estn

Le

tter

BCH

(Rya

n M

cFad

den)

Ske

etch

estn

(C

hief

Ric

k D

enea

ult)

N/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.

2009

-Feb

-19

SN

TC

Lette

r BC

H (R

yan

McF

adde

n)

SN

TC (D

irect

or

Bob

Moo

dy)

N/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g


Page 8 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 9

of 2

7

will

look

like

with

the

exte

nsio

n;

a

diag

ram

sho

win

g an

arc

hite

ctur

al v

iew

of h

ow

the

lead

shaf

ts c

onne

ctin

g th

e sw

itchg

ear b

uild

ing

to th

e un

derg

roun

d po

wer

hous

e; a

nd

P

ower

Poi

nt p

rese

ntat

ion

on th

e G

IS P

roje

ct w

as

give

n at

the

Janu

ary

29, 2

009

Cor

e C

omm

ittee

.

2009

-Feb

-19

Spl

atsi

n Le

tter

BCH

(Rya

n M

cFad

den)

S

plat

sin

(Chi

ef

Way

ne C

hris

tian)

N

/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.

2009

-Feb

-19

St.

Mar

y's

Lette

r BC

H (R

yan

McF

adde

n)

St.

Mar

y's

(Chi

ef

Sop

hie

Pie

rre)

N/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.


Page 9 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 10

of 2

7

2009

-Feb

-19

Toba

cco

Pla

ins

Lette

r BC

H (R

yan

McF

adde

n)

Toba

cco

Plai

ns

(Chi

ef M

ary

Mah

seel

ah)

N/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.

2009

-Feb

-19

Upp

er N

icol

a Le

tter

BCH

(Rya

n M

cFad

den)

Upp

er N

icol

a (C

hief

Tim

M

anue

l) N

/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.

2009

-Feb

-19

Upp

er

Sim

ilkam

een

Lette

r BC

H (R

yan

McF

adde

n)

Upp

er

Sim

ilkam

een

(Ric

hard

Hol

mes

) N

/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g


Page 10 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 11

of 2

7

will

look

like

with

the

exte

nsio

n;

a

diag

ram

sho

win

g an

arc

hite

ctur

al v

iew

of h

ow

the

lead

shaf

ts c

onne

ctin

g th

e sw

itchg

ear b

uild

ing

to th

e un

derg

roun

d po

wer

hous

e; a

nd

P

ower

Poi

nt p

rese

ntat

ion

on th

e G

IS P

roje

ct w

as

give

n at

the

Janu

ary

29, 2

009

Cor

e C

omm

ittee

.

2009

-Feb

-19

Wes

tban

k Le

tter

BCH

(Rya

n M

cFad

den)

W

estb

ank

(Chi

ef

Rob

ert L

ouie

) N

/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.

2009

-Feb

-19

Whi

sper

ing

Pin

es

Lette

r BC

H (R

yan

McF

adde

n)

Whi

sper

ing

Pin

es

(Chi

ef M

icha

el

LeB

ourd

ais)

N

/A

Sw

itchg

ear P

roje

ct N

otifi

catio

n Le

tter i

ndic

atin

g B

C H

ydro

w

ould

be

initi

atin

g m

aint

enan

ce a

nd re

furb

ishm

ent w

ork

to

exte

nd th

e sw

itchg

ear b

uild

ing

to a

ccom

mod

ate

the

inst

alla

tion

of n

ew a

nd re

plac

emen

t sw

itchg

ear.

A

ttach

men

ts a

nd e

nclo

sure

s in

clud

ed a

pho

to o

f Mic

a D

am

show

ing

switc

hgea

r bui

ldin

g;

a

phot

o of

the

exis

ting

switc

hgea

r bui

ldin

g;

a

rend

erin

g sh

owin

g w

hat t

he s

witc

hgea

r bui

ldin

g w

ill lo

ok li

ke w

ith th

e ex

tens

ion;

a di

agra

m s

how

ing

an a

rchi

tect

ural

vie

w o

f how

th

e le

adsh

afts

con

nect

ing

the

switc

hgea

r bui

ldin

g to

the

unde

rgro

und

pow

erho

use;

and

Pow

erP

oint

pre

sent

atio

n on

the

GIS

Pro

ject

was

gi

ven

at th

e Ja

nuar

y 29

, 200

9 C

ore

Com

mitt

ee.


Page 11 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 12

of 2

7

2009

-Mar

-23

Adam

s La

ke

Emai

l B

CE

AO

(Bria

n M

urph

y)

Adam

s La

ke

(Chi

ef N

elso

n Le

on)

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Bona

parte

Em

ail

BC

EA

O (B

rian

Mur

phy)

B

onap

arte

(Chi

ef

Mik

e R

etas

ket)

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Can

im L

ake

Emai

l B

CE

AO

(Bria

n M

urph

y)

Can

im L

ake

(C

hief

Mik

e A

rchi

e)

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Can

oe C

reek

Em

ail

BC

EA

O (B

rian

Mur

phy)

Can

oe C

reek

(C

hief

Han

k A

dam

) N

/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.


Page 12 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 13

of 2

7

2009

-Mar

-23

Esk

etem

c E

mai

l B

CE

AO

(Bria

n M

urph

y)

Esk

etem

c (C

hief

C

harle

ne B

elle

au)

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Hig

h B

ar

Emai

l B

CE

AO

(Bria

n M

urph

y)

Hig

h B

ar (C

hief

Le

nora

Fle

tche

r) Te

ena

Sella

rs

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Kam

loop

s Em

ail

BC

EA

O (B

rian

Mur

phy)

Kam

loop

s (C

hief

Sh

ane

Got

tfrie

dson

) N

/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

KNC

Em

ail

BC

EA

O (B

rian

Mur

phy)

K

NC

(Bill

Gre

en)

Chr

is B

eers

S

ophi

e P

ierre

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.


Page 13 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 14

of 2

7

2009

-Mar

-23

Lhei

dli T

’enn

eh

Emai

l B

CE

AO

(Bria

n M

urph

y)

Lhei

dli T

’enn

eh

(Chi

ef D

omin

ic

Fred

eric

k)

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Littl

e Sh

usw

ap

Emai

l B

CE

AO

(Bria

n M

urph

y)

LSIB

(Chi

ef F

elix

Ar

nous

e)

Rec

eptio

n

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Low

er K

oote

nay

Em

ail

BC

EA

O (B

rian

Mur

phy)

LK

oot (

Chi

ef

Chr

isto

pher

Luk

e)

Rec

eptio

n

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Low

er

Sim

ilkam

een

Emai

l B

CE

AO

(Bria

n M

urph

y)

LSIM

(Chi

ef J

oe

Den

nis)

N

/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.


Page 14 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 15

of 2

7

2009

-Mar

-23

Nes

konl

ith

Emai

l B

CE

AO

(Bria

n M

urph

y)

Nes

konl

ith (C

hief

Ju

dy W

ilson

) N

/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Nor

ther

n Sh

usw

ap T

ribal

C

ounc

il Em

ail

BC

EA

O (B

rian

Mur

phy)

N

STC

(Gor

don

Ste

rritt

) N

/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Oka

naga

n Em

ail

BC

EA

O (B

rian

Mur

phy)

O

KIB

(Chi

ef

Fabi

an A

lexi

s)

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

ON

A

Em

ail

BC

EA

O (B

rian

Mur

phy)

ON

A (E

xecu

tive

Dire

ctor

, Pau

line

Terb

aske

t) Ja

y Jo

hnso

n H

eidi

McG

rego

r Ad

die

Veda

n

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.


Page 15 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 16

of 2

7

2009

-Mar

-23

Oso

yoos

E

mai

l B

CE

AO

(Bria

n M

urph

y)

Oso

yoos

(Chi

ef

Cla

renc

e Lo

uie)

N

/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Pen

ticto

n E

mai

l B

CE

AO

(Bria

n M

urph

y)

PIB

(Chi

ef S

tew

art

Phill

ip)

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Soda

Cre

ek

Emai

l B

CE

AO

(Bria

n M

urph

y)

SC

RE

EK

( Chi

ef

Lenn

y S

ella

rs)

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Sim

pcw

E

mai

l B

CE

AO

(Bria

n M

urph

y)

Sim

pcw

(Chi

ef

Kei

th M

atth

ew)

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.


Page 16 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 17

of 2

7

2009

-Mar

-23

Ske

etch

estn

E

mai

l B

CE

AO

(Bria

n M

urph

y)

Ske

e (C

hief

Ric

k D

enau

lt)

Rec

eptio

n

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

SNTC

Em

ail

BC

EA

O (B

rian

Mur

phy)

SN

TC (T

ribal

D

irect

or B

ob

Moo

dy)

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Spl

atsi

n E

mai

l B

CE

AO

(Bria

n M

urph

y)

Spl

atsi

n (C

hief

W

ayne

Chr

istia

n)

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

St.

Mar

y's

Em

ail

BC

EA

O (B

rian

Mur

phy)

S

TM

(RS

ebas

tian)

) N

/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.


Page 17 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 18

of 2

7

2009

-Mar

-23

Toba

cco

Plai

ns

Emai

l B

CE

AO

(Bria

n M

urph

y)

TAB

P (C

hief

Mar

y M

ahse

elah

) A

dmin

istra

tion

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Upp

er N

icol

a Em

ail

BC

EA

O (B

rian

Mur

phy)

U

PN

IC (C

hief

Tim

M

anue

l) N

/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Upp

er

Sim

ilkam

een

Emai

l B

CE

AO

(Bria

n M

urph

y)

UP

SIM

(Chi

ef

Ric

hard

Hol

mes

) N

/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

Wes

tban

k E

mai

l B

CE

AO

(Bria

n M

urph

y)

WB

AN

K (C

hief

Jo

nath

an K

ruge

r) C

Clo

ugh

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.


Page 18 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 19

of 2

7

2009

-Mar

-23

Whi

sper

ing

Pine

s Em

ail

BC

EA

O (B

rian

Mur

phy)

W

PIN

ES

(Chi

ef

Mic

hael

Le

Bou

rdai

s)

N/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-23

McD

onal

d an

d C

o.

Lega

l Cou

nsel

Emai

l B

CE

AO

(Bria

n M

urph

y)

Mic

hael

McD

onal

d N

/A

BC

EA

O (B

M) i

ndic

ated

BC

H h

ave

requ

este

d an

am

endm

ent t

o th

e A

ppro

ved

Term

s of

Ref

eren

ce (A

TOR

) an

d S

ectio

n 11

Ord

er to

rem

ove

the

rem

ove

the

switc

hgea

r bu

ildin

g ex

tens

ion

wor

k fro

m th

e sc

ope

of th

e B

CE

AA

pr

oces

s. F

irst N

atio

ns a

nd T

ribal

Cou

ncils

wer

e as

ked

to

cont

act t

he B

CE

AO

prio

r to

Apr

il 3,

200

9 w

ith a

ny

com

men

ts o

r spe

cific

con

cern

s.

2009

-Mar

-31

Adam

s La

ke

Tele

phon

e C

all

BCH

(Jan

ice

Fost

er)

Adam

s La

ke

(Chi

ef N

elso

n Le

on)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

left

a m

essa

ge o

n W

hisp

erin

g P

ines

Chi

ef 's

(NL)

voi

cem

ail a

skin

g if

Chi

ef N

L

had

rece

ived

the

Sw

itchg

ear P

acka

ge, c

ompr

ised

of

Sw

itchg

ear l

ette

r, at

tach

men

ts (7

pho

tos)

and

Pow

erP

oint

pr

esen

tatio

n th

at w

as d

ated

and

sen

t out

Feb

ruar

y 23

, 20

09. J

anic

e as

ked

Chi

ef N

L to

con

firm

that

it w

as re

ceiv

ed

and

let h

er k

now

if h

e ha

d an

y qu

estio

ns o

r con

cern

s re

gard

ing

the

Sw

itchg

ear R

epla

cem

ent.

2009

-Mar

-31

Bona

parte

Te

leph

one

Cal

l BC

H (J

anic

e Fo

ster

) B

onap

arte

(Chi

ef

Terr

y P

orte

r)

N/A

BC

H (J

F) s

poke

with

Bon

apar

te R

ecep

tioni

st a

nd a

sked

if

Bon

apar

te C

hief

(TP

) had

rece

ived

Sw

itchg

ear P

acka

ge,

com

pris

ed o

f Sw

itchg

ear l

ette

r, at

tach

men

ts (7

pho

tos)

and

P

ower

Poi

nt p

rese

ntat

ion

date

d an

d se

nt o

ut F

ebru

ary

23,

2009

. Rec

eptio

nist

con

firm

ed S

witc

hgea

r pac

kage

had

be

en re

ceiv

ed. J

F le

ft a

voic

emai

l for

Chi

ef T

P a

skin

g if

Chi

ef T

P h

ad a

ny q

uest

ions

or c

once

rns

rega

rdin

g th

e S

witc

hgea

r Rep

lace

men

t pro

ject

.

2009

-Mar

-31

Bona

parte

Te

leph

one

Cal

l B

onap

arte

(Chi

ef

Terr

y P

orte

r)

BCH

(Jan

ice

Fost

er)

N/A

Te

leph

one

call

from

Bon

apar

te C

hief

(TP

) to

BC

H (J

F) le

ft JF

a m

essa

ge a

skin

g th

at S

witc

hgea

r pac

kage

be

re-s

ent t

o hi

s at

tent

ion.


Page 19 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 20

of 2

7

2009

-Mar

-31

Col

umbi

a La

ke

Tele

phon

e C

all

BCH

(Jan

ice

Fost

er)

Col

umbi

a La

ke

(Chi

ef W

ilfre

d Te

nese

e)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

left

a m

essa

ge fo

r Col

umbi

a La

ke's

Chi

ef (W

T) w

ith C

olum

bia

Lake

(Rec

eptio

nist

) ask

ing

if C

hief

WT

had

rece

ived

the

Sw

itchg

ear P

acka

ge,

com

pris

ed o

f Sw

itchg

ear l

ette

r, at

tach

men

ts (7

pho

tos)

and

P

ower

Poi

nt p

rese

ntat

ion

that

was

dat

ed a

nd s

ent o

ut

Febr

uary

23,

200

9. J

anic

e as

ked

Chi

ef W

T to

con

firm

that

it

was

rece

ived

and

let h

er k

now

if h

e ha

d an

y qu

estio

ns o

r co

ncer

ns re

gard

ing

the

Sw

itchg

ear R

epla

cem

ent.

2009

-Mar

-31

Kam

loop

s Te

leph

one

Cal

l BC

H (J

anic

e Fo

ster

)

Kam

loop

s (C

hief

Sh

ane

Got

tfrie

dson

) N

/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

left

a vo

icem

ail a

nd in

quire

d if

Kam

loop

s C

hief

(SG

) had

rece

ived

the

Sw

itchg

ear

Pac

kage

whi

ch w

as c

ompr

ised

of t

he S

witc

hgea

r let

ter,

atta

chm

ents

(7 p

hoto

s) a

nd P

ower

Poi

nt p

rese

ntat

ion

that

as

date

d an

d se

nt o

ut F

ebru

ary

23, 2

009.

Kam

loop

s (R

ecep

tioni

st) c

onfir

med

the

Sw

itchg

ear p

acka

ge h

ad b

een

rece

ived

. JF

requ

este

d C

hief

(SG

) to

cont

act h

er w

ith a

ny

ques

tions

or c

once

rns

rega

rdin

g th

e S

witc

hgea

r R

epla

cem

ent p

roje

ct.

2009

-Mar

-31

KNC

Te

leph

one

Cal

l BC

H (J

anic

e Fo

ster

)

KN

C (F

inan

cial

A

dmin

istra

tor

Jaim

e C

hris

tale

s)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

spo

ke w

ith K

NC

(JC

) and

in

quire

d if

KN

C (B

ill G

reen

) had

rece

ived

the

Sw

itchg

ear

Pac

kage

whi

ch w

as c

ompr

ised

of t

he S

witc

hgea

r let

ter,

atta

chm

ents

(7 p

hoto

s) a

nd P

ower

Poi

nt p

rese

ntat

ion

that

as

date

d an

d se

nt o

ut F

ebru

ary

23, 2

009.

JC

sta

ted

she

wou

ld

chec

k w

ith B

G a

nd le

t JF

know

. JF

also

ask

ed J

C to

che

ck

with

BG

if h

e ha

d an

y qu

estio

ns o

r con

cern

s re

gard

ing

the

Sw

itchg

ear p

roje

ct.

2009

-Mar

-31

Lhei

dli T

’enn

eh

Tele

phon

e C

all

BCH

(Jan

ice

Fost

er)

Lhei

dli T

’enn

eh

(Chi

ef D

omin

ic

Fred

eric

k)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

left

a m

essa

ge w

ith L

heid

li T'

enne

h's

Chi

ef (D

F) R

ecep

tioni

st a

skin

g if

Chi

ef D

F ha

d re

ceiv

ed th

e S

witc

hgea

r Pac

kage

, com

pris

ed o

f Sw

itchg

ear

lette

r, at

tach

men

ts (7

pho

tos)

and

Pow

erP

oint

pre

sent

atio

n th

at w

as d

ated

and

sen

t out

Feb

ruar

y 23

, 200

9. J

F as

ked

Chi

ef D

F to

con

firm

that

it w

as re

ceiv

ed a

nd le

t her

kno

w if

he

had

any

que

stio

ns o

r con

cern

s re

gard

ing

the

Sw

itchg

ear

Rep

lace

men

t.


Page 20 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 21

of 2

7

2009

-Mar

-31

Littl

e Sh

usw

ap

Tele

phon

e C

all

BCH

(Jan

ice

Fost

er)

Littl

e Sh

usw

ap

(Lan

d an

d R

esou

rces

M

anag

er S

tew

art

Ada

mso

n)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

left

a vo

icem

ail a

nd in

quire

d if

Littl

e S

husw

ap (S

A) h

ad re

ceiv

ed th

e S

witc

hgea

r Pac

kage

w

hich

was

com

pris

ed o

f the

Sw

itchg

ear l

ette

r, at

tach

men

ts

(7 p

hoto

s) a

nd P

ower

Poi

nt p

rese

ntat

ion

that

as

date

d an

d se

nt o

ut F

ebru

ary

23, 2

009.

JF

requ

este

d (S

A) c

onta

ct h

er

with

any

que

stio

ns o

r con

cern

s re

gard

ing

the

Sw

itchg

ear

Rep

lace

men

t pro

ject

.

2009

-Mar

-31

Low

er K

oote

nay

Tele

phon

e C

all

BCH

(Jan

ice

Fost

er)

Low

er K

oote

nay

(Chi

ef C

hris

toph

er

Luke

) N

/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

spo

ke w

ith R

ecep

tioni

st fo

r Lo

wer

Koo

tena

y C

hief

(CL)

and

ask

ed if

Chi

ef C

L ha

d re

ceiv

ed th

e S

witc

hgea

r Pac

kage

, com

pris

ed o

f Sw

itchg

ear

lette

r, at

tach

men

ts (7

pho

tos)

and

Pow

erP

oint

pre

sent

atio

n da

ted

and

sent

out

Feb

ruar

y 23

, 200

9. T

he R

ecep

tioni

st

conf

irmed

the

Sw

itchg

ear p

acka

ge h

ad b

een

rece

ived

. JF

left

a vo

icem

ail f

or C

hief

CL

requ

estin

g he

con

tact

her

with

an

y qu

estio

ns o

r con

cern

s re

gard

ing

the

Sw

itchg

ear

Rep

lace

men

t pro

ject

.

2009

-Mar

-31

Low

er

Sim

ilkam

een

Tele

phon

e C

all

BCH

(Jan

ice

Fost

er)

Low

er

Sim

ilkam

een

(Chi

ef J

osep

h D

enni

s)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

spo

ke w

ith R

ecep

tioni

st fo

r Lo

wer

Sim

ilkam

een

Chi

ef (J

D) a

nd a

sked

if C

hief

JD

had

re

ceiv

ed S

witc

hgea

r Pac

kage

, com

pris

ed o

f Sw

itchg

ear

lette

r, at

tach

men

ts (7

pho

tos)

and

Pow

erP

oint

pre

sent

atio

n da

ted

and

sent

out

Feb

ruar

y 23

, 200

9. R

ecep

tioni

st

conf

irmed

Sw

itchg

ear p

acka

ge h

ad b

een

rece

ived

. JF

left

a m

essa

ge re

ques

ting

that

Chi

ef J

D c

onta

ct h

er w

ith a

ny

ques

tions

or c

once

rns

rega

rdin

g th

e S

witc

hgea

r R

epla

cem

ent p

roje

ct.


Page 21 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 22

of 2

7

2009

-Mar

-31

Nes

konl

ith

Tele

phon

e C

all

BCH

(Jan

ice

Fost

er)

Nes

konl

ith (C

hief

Ju

dy W

ilson

) N

/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

left

a vo

icem

ail a

nd in

quire

d if

Nes

konl

ith C

hief

(JW

) had

rece

ived

the

Sw

itchg

ear

Pac

kage

whi

ch w

as c

ompr

ised

of t

he S

witc

hgea

r let

ter,

atta

chm

ents

(7 p

hoto

s) a

nd P

ower

Poi

nt p

rese

ntat

ion

that

as

date

d an

d se

nt o

ut F

ebru

ary

23, 2

009.

JF

requ

este

d C

hief

JW

con

tact

her

with

any

que

stio

ns o

r con

cern

s re

gard

ing

the

Sw

itchg

ear R

epla

cem

ent p

roje

ct.

2009

-Mar

-31

Oka

naga

n Te

leph

one

Cal

l BC

H (J

anic

e Fo

ster

)

Oka

naga

n (T

errit

oria

l St

ewar

dshi

p D

ivis

ion

Man

ager

C

olle

en

Mar

chan

d)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

spo

ke w

ith O

kana

gan

(CM

) an

d as

ked

if O

kana

gan

had

rece

ived

the

Sw

itchg

ear

Pac

kage

whi

ch w

as c

ompr

ised

of t

he S

witc

hgea

r let

ter,

atta

chm

ents

(7 p

hoto

s) a

nd P

ower

Poi

nt p

rese

ntat

ion

that

w

as d

ated

and

sen

t out

Feb

ruar

y 23

, 200

9. C

M c

onfir

med

th

e pa

ckag

e w

as re

ceiv

ed a

nd th

at O

kana

gan

did

not h

ave

any

ques

tions

or c

once

rns

rega

rdin

g th

e S

witc

hgea

r pro

ject

.

2009

-Mar

-31

ON

A

Tele

phon

e C

all

BCH

(Jan

ice

Fost

er)

Oka

naga

n N

atio

n Al

lianc

e (E

xecu

tive

Dire

ctor

Pau

line

Terb

aske

t)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

spo

ke w

ith R

ecep

tioni

st fo

r O

NA

(PT)

and

ask

ed if

PT

had

rece

ived

Sw

itchg

ear

Pac

kage

, com

pris

ed o

f Sw

itchg

ear l

ette

r, at

tach

men

ts (7

ph

otos

) and

Pow

erP

oint

pre

sent

atio

n da

ted

and

sent

out

Fe

brua

ry 2

3, 2

009.

Rec

eptio

nist

con

firm

ed th

e S

witc

hgea

r pa

ckag

e ha

d be

en re

ceiv

ed. J

F le

ft a

mes

sage

requ

estin

g th

at P

T co

ntac

t her

with

any

que

stio

ns o

r con

cern

s re

gard

ing

the

Sw

itchg

ear R

epla

cem

ent p

roje

ct.

2009

-Mar

-31

Oso

yoos

Te

leph

one

Cal

l BC

H (J

anic

e Fo

ster

) O

soyo

os (C

hief

C

lare

nce

Loui

e)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

left

mes

sage

with

R

ecep

tioni

st fo

r Oso

yoos

Chi

ef (C

L), a

skin

g hi

m to

con

firm

th

at h

e ha

d re

ceiv

ed th

e S

witc

hgea

r Pac

kage

whi

ch w

as

com

pris

ed o

f the

Sw

itchg

ear l

ette

r, at

tach

men

ts (7

pho

tos)

an

d P

ower

Poi

nt p

rese

ntat

ion

that

was

dat

ed a

nd s

ent o

ut

Febr

uary

23,

200

9. J

F al

so re

ques

ted

Chi

ef C

L co

ntac

t her

if

he h

ad a

ny q

uest

ions

or c

once

rns

rega

rdin

g th

e S

witc

hgea

r pro

ject

.


Page 22 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 23

of 2

7

2009

-Mar

-31

Pen

ticto

n Te

leph

one

Cal

l BC

H (J

anic

e Fo

ster

) P

entic

ton

(Rec

eptio

nist

) N

/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

spo

ke w

ith R

ecep

tioni

st, w

ho

coul

d no

t con

firm

Pen

ticto

n re

ceiv

ed th

e S

witc

hgea

r pa

ckag

e an

d as

ked

that

the

pack

age

be re

-sen

t. JF

sai

d th

at s

he w

ould

re-s

end

the

pack

age.

2009

-Mar

-31

Shus

wap

Te

leph

one

Cal

l BC

H (J

anic

e Fo

ster

) Sh

usw

ap (C

hief

P

aul S

am)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

left

mes

sage

for S

husw

ap

Chi

ef (P

S),

aski

ng h

im to

con

firm

that

he

had

rece

ived

the

Sw

itchg

ear P

acka

ge w

hich

was

com

pris

ed o

f the

S

witc

hgea

r let

ter,

atta

chm

ents

(7 p

hoto

s) a

nd P

ower

Poi

nt

pres

enta

tion

that

was

dat

ed a

nd s

ent o

ut F

ebru

ary

23,

2009

. JF

als

o re

ques

ted

Chi

ef P

S c

onta

ct h

er if

he

had

any

ques

tions

or c

once

rns

rega

rdin

g th

e S

witc

hgea

r pro

ject

.

2009

-Mar

-31

Sim

pcw

Te

leph

one

Cal

l BC

H (J

anic

e Fo

ster

) S

impc

w (R

efer

rals

D

epar

tmen

t) N

/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

spo

ke w

ith S

impc

w

(Ref

erra

ls D

epar

tmen

t) w

ho re

mem

bere

d se

eing

the

Sw

itchg

ear p

acka

ge, b

ut c

ould

not

loca

te it

. RD

ask

ed th

at

JF re

-sen

d th

e le

tter,

atta

chm

ents

and

Pow

erP

oint

el

ectro

nica

lly, w

hich

JF

did

and

copi

ed S

impc

w C

hief

(Kei

th

Mat

thew

). R

D s

tate

d he

wou

ld fo

llow

up

with

Chi

ef K

M a

nd

cont

act J

F if

ther

e w

ere

any

ques

tions

or c

once

rns.

2009

-Mar

-31

Sim

pcw

Em

ail

BCH

(Jan

ice

Fost

er)

Sim

pcw

(Chi

ef

Kei

th M

atth

ew);

cc: S

impc

w

(Ref

erra

ls

Dep

artm

ent)

N/A

Em

ail f

rom

BC

H (J

F) to

Sim

pcw

Chi

ef (K

M) r

espo

nded

to

requ

est f

rom

Sim

pcw

(Ref

erra

ls D

epar

tmen

t) th

at B

CH

re

send

info

rmat

ion

rega

rdin

g S

witc

hgea

r Rep

lace

men

t pr

ojec

t ele

ctro

nica

lly; B

CH

(JF)

atta

ched

the

Sw

itchg

ear

Pro

ject

Not

ifica

tion

Lette

r, ph

oto

atta

chm

ents

and

the

Pow

erP

oint

pre

sent

atio

n se

nt to

Sim

pcw

on

Febr

uary

23,

20

09.


Page 23 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 24

of 2

7

2009

-Mar

-31

Sim

pcw

Em

ail

BCH

(Jan

ice

Fost

er)

Sim

pcw

(Chi

ef

Kei

th M

atth

ew);

cc: S

impc

w

(Ref

erra

ls

Dep

artm

ent)

N/A

Em

ail s

ent f

rom

BC

H (J

F) to

Sim

pcw

Chi

ef (K

M) s

tate

d th

at

prev

ious

atte

mpt

by

JF to

sen

d th

ree

atta

chm

ents

my

emai

l w

as u

nsuc

cess

ful,

and

that

she

wou

ld re

-sen

d th

em o

ne

emai

l at a

tim

e. S

witc

hgea

r Pro

ject

Not

ifica

tion

Lette

r was

at

tach

ed.

2009

-Mar

-31

Sim

pcw

Em

ail

BCH

(Jan

ice

Fost

er)

Sim

pcw

(Chi

ef

Kei

th M

atth

ew);

cc: S

impc

w

(Ref

erra

ls

Dep

artm

ent)

N/A

E

mai

l sen

t fro

m B

CH

(JF)

to S

impc

w C

hief

(KM

) atta

ched

S

witc

hgea

r Rep

lace

men

t Pow

erP

oint

pre

sent

atio

n.

2009

-Mar

-31

Ske

etch

estn

Te

leph

one

Cal

l BC

H (J

anic

e Fo

ster

)

Ske

etch

estn

(C

hief

Ric

k D

enea

ult)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

left

mes

sage

for S

keet

ches

tn

Chi

ef (R

D),

aski

ng h

im to

con

firm

that

he

had

rece

ived

the

Sw

itchg

ear P

acka

ge w

hich

was

com

pris

ed o

f the

S

witc

hgea

r let

ter,

atta

chm

ents

(7 p

hoto

s) a

nd P

ower

Poi

nt

pres

enta

tion

that

was

dat

ed a

nd s

ent o

ut F

ebru

ary

23,

2009

. JF

als

o re

ques

ted

Chi

ef R

D c

onta

ct h

er if

he

had

any

ques

tions

or c

once

rns

rega

rdin

g th

e S

witc

hgea

r pro

ject

.

2009

-Mar

-31

SN

TC

Tele

phon

e C

all

BCH

(Jan

ice

Fost

er)

SN

TC (D

irect

or

Bob

Moo

dy)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

spo

ke w

ith R

ecep

tioni

st fo

r S

NTC

(BM

); R

ecep

tioni

st c

onfir

med

that

BM

had

rece

ived

th

e S

witc

hgea

r Pac

kage

whi

ch w

as c

ompr

ised

of t

he

Sw

itchg

ear l

ette

r, at

tach

men

ts (7

pho

tos)

and

Pow

erP

oint

pr

esen

tatio

n th

at w

as d

ated

and

sen

t out

Feb

ruar

y 23

, 20

09.

JF re

ques

ted

BM

con

tact

her

if h

e ha

d an

y qu

estio

ns

or c

once

rns

rega

rdin

g th

e S

witc

hgea

r pro

ject

.


Page 24 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 25

of 2

7

2009

-Mar

-31

Spl

atsi

n Te

leph

one

Cal

l BC

H (J

anic

e Fo

ster

)

Spl

atsi

n (E

xecu

tive

Secr

etar

y Th

eres

a W

illiam

)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

left

mes

sage

for S

plat

sin

(TW

), as

king

her

to c

onfir

m th

at s

he h

ad re

ceiv

ed th

e S

witc

hgea

r Pac

kage

whi

ch w

as c

ompr

ised

of t

he

Sw

itchg

ear l

ette

r, at

tach

men

ts (7

pho

tos)

and

Pow

erP

oint

pr

esen

tatio

n th

at w

as d

ated

and

sen

t out

Feb

ruar

y 23

, 20

09.

JF a

lso

requ

este

d TW

con

tact

her

if s

he h

ad a

ny

ques

tions

or c

once

rns

rega

rdin

g th

e S

witc

hgea

r pro

ject

.

2009

-Mar

-31

St.

Mar

y's

Tele

phon

e C

all

BCH

(Jan

ice

Fost

er)

St.

Mar

y's

(Chi

ef

Sop

hie

Pie

rre)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

left

mes

sage

for S

t. M

ary'

s C

hief

(SP

), as

king

her

to c

onfir

m th

at s

he h

ad re

ceiv

ed th

e S

witc

hgea

r Pac

kage

whi

ch w

as c

ompr

ised

of t

he

Sw

itchg

ear l

ette

r, at

tach

men

ts (7

pho

tos)

and

Pow

erP

oint

pr

esen

tatio

n th

at w

as d

ated

and

sen

t out

Feb

ruar

y 23

, 20

09.

JF a

lso

requ

este

d C

hief

MM

con

tact

her

if s

he h

ad

any

ques

tions

or c

once

rns

rega

rdin

g th

e S

witc

hgea

r pro

ject

.

2009

-Mar

-31

Toba

cco

Plai

ns

Tele

phon

e C

all

BCH

(Jan

ice

Fost

er)

Toba

cco

Plai

ns

(Rec

eptio

nist

) N

/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

spo

ke w

ith R

ecep

tioni

st fo

r To

bacc

o P

lain

s C

hief

(Mar

y M

ahse

elah

) and

ask

ed if

the

Chi

ef h

ad re

ceiv

ed th

e S

witc

hgea

r Pac

kage

whi

ch w

as

com

pris

ed o

f the

Sw

itchg

ear l

ette

r, at

tach

men

ts (7

pho

tos)

an

d P

ower

Poi

nt p

rese

ntat

ion

that

was

dat

ed a

nd s

ent o

ut

Febr

uary

23,

200

9. J

F w

as a

sked

to c

all b

ack

as th

e pe

rson

man

agin

g th

e in

com

ing

mai

l was

off

sick

.

2009

-Mar

-31

Upp

er N

icol

a Te

leph

one

Cal

l BC

H (J

anic

e Fo

ster

)

Upp

er N

icol

a (C

hief

Tim

M

anue

l) N

/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

spo

ke w

ith R

ecep

tioni

st fo

r U

pper

Nic

ola

Chi

ef (T

M);

Rec

eptio

nist

con

firm

ed th

at C

hief

TM

had

rece

ived

the

Sw

itchg

ear P

acka

ge w

hich

was

co

mpr

ised

of t

he S

witc

hgea

r let

ter,

atta

chm

ents

(7 p

hoto

s)

and

Pow

erP

oint

pre

sent

atio

n th

at w

as d

ated

and

sen

t out

Fe

brua

ry 2

3, 2

009.

JF

requ

este

d C

hief

TM

con

tact

her

if h

e ha

d an

y qu

estio

ns o

r con

cern

s re

gard

ing

the

Sw

itchg

ear

proj

ect.


Page 25 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 26

of 2

7

2009

-Mar

-31

Upp

er

Sim

ilkam

een

Tele

phon

e C

all

BCH

(Jan

ice

Fost

er)

Upp

er

Sim

ilkam

een

(Rec

eptio

nist

) N

/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

spo

ke w

ith R

ecep

tioni

st fo

r To

bacc

o P

lain

s an

d as

ked

if th

ey h

ad re

ceiv

ed th

e S

witc

hgea

r Pac

kage

whi

ch w

as c

ompr

ised

of t

he

Sw

itchg

ear l

ette

r, at

tach

men

ts (7

pho

tos)

and

Pow

erP

oint

pr

esen

tatio

n th

at w

as d

ated

and

sen

t out

Feb

ruar

y 23

, 20

09.

JF w

as a

sked

to c

all b

ack

as th

e pe

rson

man

agin

g th

e in

com

ing

mai

l was

not

in th

e of

fice

that

day

.

2009

-Mar

-31

Wes

tban

k Te

leph

one

Cal

l BC

H (J

anic

e Fo

ster

)

Wes

tban

k (In

terg

over

nmen

tal

Affa

irs M

anag

er

Rap

hael

D

eGue

vara

)

N/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

that

left

a m

essa

ge fo

r W

estb

ank

Chi

ef (R

D) a

skin

g if

Chi

ef R

D h

ad a

ny q

uest

ions

or

con

cern

s re

gard

ing

the

Sw

itchg

ear p

acka

ge s

ent o

n Fe

brua

ry 2

3, 2

009.

2009

-Mar

-31

Wes

tban

k Te

leph

one

Cal

l BC

H (J

anic

e Fo

ster

) W

estb

ank

(Chi

ef

Rob

ert L

ouie

) N

/A

Tele

phon

e ca

ll fro

m B

CH

(JF)

spo

ke w

ith E

xecu

tive

Ass

ista

nt to

Wes

tban

k C

hief

(RL)

and

ask

ed if

Chi

ef R

L ha

d re

ceiv

ed th

e S

witc

hgea

r Pac

kage

whi

ch w

as c

ompr

ised

of

the

Sw

itchg

ear l

ette

r, at

tach

men

ts (7

pho

tos)

and

P

ower

Poi

nt p

rese

ntat

ion

that

as

date

d an

d se

nt o

ut

Febr

uary

23,

200

9. A

ssis

tant

sta

ted

the

Sw

itchg

ear

pack

age

had

been

rece

ived

and

pas

sed

JF o

ver t

o W

estb

ank

(Rap

hael

DeG

ueva

ra).

2009

-Mar

-31

Whi

sper

ing

Pin

es

Tele

phon

e C

all

BCH

(Jan

ice

Fost

er)

Whi

sper

ing

Pin

es

(Chi

ef M

icha

el

LeB

ourd

ais)

N

/A

Tele

phon

e C

all f

rom

BC

H (J

F) w

ith W

hisp

erin

g Pi

nes

(Rec

eptio

nist

) for

and

ask

ed if

Whi

sper

ing

Pin

es C

hief

(ML)

ha

d re

ceiv

ed S

witc

hgea

r Pac

kage

, com

pris

ed o

f Sw

itchg

ear

lette

r, at

tach

men

ts (7

pho

tos)

and

Pow

erP

oint

pre

sent

atio

n th

at w

as d

ated

and

sen

t out

Feb

ruar

y 23

, 200

9.

Rec

eptio

nist

con

firm

ed th

e Sw

itchg

ear p

acka

ge h

ad b

een

rece

ived

. JF

left

a m

essa

ge w

ith th

e R

ecep

tioni

st fo

r Chi

ef

ML

to c

onta

ct h

er w

ith a

ny q

uest

ions

or c

once

rns

rega

rdin

g th

e S

witc

hgea

r Rep

lace

men

t pro

ject

.


Page 26 of 27

Switc

hgea

r Fi

rst N

atio

n Lo

g –

Mar

ch 3

1, 2

009

Dat

e (y

yyy,

mm

,dd)

Fi

rst N

atio

n M

etho

d of

C

omm

unic

atio

n In

itiat

ed b

y R

ecip

ient

Pa

rtic

ipan

ts

Key

Dis

cuss

ion

Pag

e 27

of 2

7

2009

-May

-26

Ktu

naxa

Nat

ion

Cou

ncil

Site

Vis

it BC

H (R

yan

McF

adde

n)

N/A

7 m

embe

rs o

f th

e K

tuna

xa

Land

s an

d R

esou

rces

C

omm

ittee

(K

LRC

) M

CA

GS

P

lant

Sta

ff B

C H

ydro

A

R&

N

Vie

wed

the

maj

or c

ompo

nent

s of

the

Mic

a G

S, l

ead

shaf

ts

1-3

and

flang

e se

ctio

ns, p

ower

hous

e, e

xist

ing

switc

hgea

r bu

ildin

g, a

nd th

e si

te o

f the

pro

pose

d sw

itchg

ear b

uild

ing

exte

nsio

n to

asc

erta

in if

ther

e w

ere

any

appa

rent

en

viro

nmen

tal c

once

rns.


Page 27 of 27

The attached letter was sent to the First Nations and Tribal Councils

indentified in Table 5-1 of the Application.

The contact information has been

redacted for privacy.


Page 1 of 17

hydro WI ·

FOR GENERATIONS

Ryan McFadden Sr. Aboriginal Relations Coordinator BC Hydro Aboriginal Relations & Negotiations 6911 Southpoint Drive - 16th Floor, Burnaby, BC, V3N 4X8

February 23, 2009

Dear :

Re: Switchgear Replacement Project

This is to advise you that in 2009-2010 BC Hydro will be extending the Switchgear Building located at Mica Dam as part of a project to replace aging switchgear1 that has reached end-of-life and is affecting generation and transmission system reliability.

The following Attachments are provided to assist your understanding of the work:

Attachment A: Attachment B: Attachment C: Attachment D:

Attachment E:

Google Earth Photo of Mica Dam Showing Switchgear Building Photo of the existing Switchgear Building Photo showing what the building will look like with the extension Architectural view of how the lead shafts connect the switchgear building to the underground powerhouse Photos (3) of Mica Switchgear Building Extension Site

The Switchgear Building is attached to the office tourist centre structure at located on the west side of the Mica. The structure will be extended by 124 feet or roughly 1/3 of its current length to accommodate the commissioning of a third lead shaft needed to conduct replacement work on the conductors in the two lead shafts lead shafts currently in use. The excavation for the third lead shaft has been in place since the original construction of the dam. Commissioning involves the installation of the gas insulated

1 Switchgear refers to the combination of electrical disconnects, fuses and/or circuit breakers used to isolate electrical equipment. Switchgear is used both to de-energize equipment to allow work to be done safely, and to clear faults downstream.

II!

~ - BC hydro m • FOR GENERATIONS

,. ~ vancouver 2010 vancouver 2010 OFFICIAL ,..uu.lYMtlCGAMES

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REDACTED

REDACTED


Page 2 of 17

Chgd .. o WI

FOR GENERATIONS

conductors used to bring power from the underground generators to the above-ground transmission system.

The third conductor will serve two purposes. Because two conductors are required to reliably operate the four existing generating units, the third conductor will be used while each of the existing two conductors is being replaced. The third conductor is also needed for the operation of all six generating units once units 5 and 6 are added.

The extension of the Switchgear Building will occur on a previously disturbed site within the BC Hydro generating station yard. See Attachment E for photos of the site. BC Hydro assessed the site and no potential wildlife, vegetation, or heritage impacts were identified. The site was pointed out during a site visit attended by regulatory agencies, stakeholders, and some First Nations on September 17, 2008.

It is anticipated that an Application will be submitted to the BCUC in June/July 2009, with a decision expected before 2010. For more information about the BCUC process, please visit their website at www.bcuc.com.

For additional information on the Mica Switchgear Building Project, please find enclosed a presentation that was shared at the most recent Core Committee meeting in Revelstoke held on January 29th, 2009. So far no concerns have been raised.

Should you require further information, capacity funding, or should you have any concerns that the proposed Project may affect the rights or interests of

please do not hesitate to contact me at 604-528-2833 or [email protected], and/or

Deb Bisson, Regulatory, Environmental, and Stakeholder Manager, BC Hydro Project Delivery, Upper Columbia, [email protected], 604-528-1913

Respectfully,

Ryan McFadden Sr. Aboriginal Relations Coordinator Aboriginal Relations and Negotiations

Enclosures (1)

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Page 3 of 17

B hydro au

FOR GENERATIONS

Attachment A: Google Earth Photo of Mica Dam Showing Planned Switchgear . Building Extension

Dam face

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Page 4 of 17

BC hydro FOR GENERATIONS

Attachment B Photo of Switchgear Building

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Page 5 of 17

BC hydro m FOR GENERATIONS

Attachment C - Rendering of Switchgear Building Extension

Mica GIS Switchgear Building Addition

5

Building extension on right side of yellow line

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Page 6 of 17

BC hudro m FOR GENERATIONS

Attachment D Architectural View of Lead Shafts

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Page 7 of 17

BChydro FOR GENERATIONS

Attachment E - Photos of Site for Switchgear Building Expansion

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Page 8 of 17

BC hudro m FOR GENERATIONS

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Page 9 of 17

hydro m FOR GENERATIONS

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Page 10 of 17

Mica Generating Unit 5 and Unit 6 and

Mica Switchgear Project

Switchgear Building Extension

Switchgear Building For Units 1 to 4

• Existing building located on west side of the dam

• Houses high voltage switchgear at the terminal of the two SF6 conductors .

• SF6 conductors bring power from the . underground powerhouse transforms (twelve

transformers, three per unit) through two shafts to the switchgear building

1


Page 11 of 17

2


Page 12 of 17

Reason for Switchgear Building Extension

• Building is being extended to accommodate the switchge"ar that will terminate the conductor to be installed in the third empty shaft

• Switchgear and conductor to be installed in the third shaft so that: a) It can be used while the conductors in the first and second

shafts are being maintained or replaced; and b) To provide the required reliability for six units once Unit 5

" and Unit 6 are operational

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Page 13 of 17

. Switchgear Building Extension

• Switchgear building extension is· included in the "Scope" of the Mica 5 Project environmental assessment because part of the reason for the extension relates to the reliable delivery of power from the additional units

• Switchgear building extension is planned to be constructed as part of a separate BCH project - the Mica Switchgear Project

• Switchgear building extension is included in the "Scope" of the Mica 5 Project environmental assessment .

• . The site for the extension is adjacent to the existing building on previously disturbed ground

• Environmental assessment includes; - Wildlife - Vegetation - Archeology

4


Page 14 of 17

Mica Switchgear Project

• Project replaces aging SF6 equipment units 1 to 4 • Plant requires two conductors in service to ensure reliable

delivery of power to the high voltage grid • Switchgear building expansion included in Mica Switchgear

project so that an existing conductor can be de-energized and replaced while maintaining reliability for existing four units

• In addition to replacing existing SF6 equipment for Units 1 to 4, Mica GIS Project includes installing new conductor in the third lead shaft, termina'l switchgear for the third conductor as well as the construction of the switChgear building extension

Existing Gas Insulated Switchgear

5


Page 15 of 17

• Starts late 2009 or early 2010 - complete early 2013 • Estimated cost range $90 million to $229 million (June 2008

estimate) • Work at site under CHC Agreement • Work about 85 persons years

- 201029 person years, peal< about 30 - 2011 26 person years, peak about 40 - 2012 25 person years, peak about 40 - 2013 5 person years, peak about 16

• Separate contract for switchgear building extension - Concrete building - 1000 cubic yards of concrete - About 40 feet wide, 130 feet long, 40 feet high - Start late 2009 or early 2010 after receipt of the Mica 5

Environmental Approval Certificate

Mica Switchgear Building - Rendition of Extended Building

Mica GIS Swllc.hgear Building Addition

6


Page 16 of 17

Mica Switchgear Building Extension

- Questions

7


Page 17 of 17

Mic

a G

ener

atin

g U

nit 5

and

Uni

t 6

and

Mic

a Sw

itchg

ear P

roje

ct

Sw

itchg

ear B

uild

ing

Ext

ensi

on


Page 1 of 13

Switc

hgea

r Bui

ldin

g Fo

r Uni

ts 1

to 4

Exi

stin

g bu

ildin

g lo

cate

d on

wes

t sid

e of

the

dam

Hou

ses

high

vol

tage

sw

itchg

ear a

t the

te

rmin

al o

f the

two

SF6

con

duct

ors

SF6

con

duct

ors

brin

g po

wer

from

the

unde

rgro

und

pow

erho

use

trans

form

s (tw

elve

tra

nsfo

rmer

s, th

ree

per u

nit)

thro

ugh

two

shaf

ts to

the

switc

hgea

r bui

ldin

g


Page 2 of 13

Mic

a Sw

itch

Bui

ldin

g an

d Ex

tens

ion


Page 3 of 13

Mic

a Sw

itchg

ear B

uild

ing


Page 4 of 13

Rea

son

for S

witc

hgea

r Bui

ldin

g Ex

tens

ion

Bui

ldin

g is

bei

ng e

xten

ded

to a

ccom

mod

ate

the

switc

hgea

r tha

t will

term

inat

e th

e co

nduc

tor t

o be

in

stal

led

in th

e th

ird e

mpt

y sh

aft

Sw

itchg

ear a

nd c

ondu

ctor

to b

e in

stal

led

in th

e th

ird

shaf

t so

that

:a)

It

can

be u

sed

whi

le th

e co

nduc

tors

in th

e fir

st a

nd s

econ

d sh

afts

are

bei

ng m

aint

aine

d or

repl

aced

; and

b)

To p

rovi

de th

e re

quire

d re

liabi

lity

for s

ix u

nits

onc

e U

nit 5

an

d U

nit 6

are

ope

ratio

nal


Page 5 of 13

Shaf

ts


Page 6 of 13

Switc

hgea

r Bui

ldin

g Ex

tens

ion

Sw

itchg

ear b

uild

ing

exte

nsio

n is

incl

uded

in

the

“Sco

pe” o

f the

Mic

a 5

Pro

ject

en

viro

nmen

tal a

sses

smen

t bec

ause

par

t of

the

reas

on fo

r the

ext

ensi

on re

late

s to

the

relia

ble

deliv

ery

of p

ower

from

the

addi

tiona

l un

its

Sw

itchg

ear b

uild

ing

exte

nsio

n is

pla

nned

to

be c

onst

ruct

ed a

s pa

rt of

a s

epar

ate

BC

H

proj

ect –

the

Mic

a S

witc

hgea

r Pro

ject


Page 7 of 13

Mic

a 5

Proj

ect a

nd th

e Sw

itchg

ear

Bui

ldin

g Ex

tens

ion

Sw

itchg

ear b

uild

ing

exte

nsio

n is

incl

uded

in th

e “S

cope

” of t

he M

ica

5 P

roje

ct e

nviro

nmen

tal

asse

ssm

ent

The

site

for t

he e

xten

sion

is a

djac

ent t

o th

e ex

istin

g bu

ildin

g on

pre

viou

sly

dist

urbe

d gr

ound

Env

ironm

enta

l ass

essm

ent i

nclu

des;

– W

ildlif

e–

Veg

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Page 8 of 13

Mic

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Pro

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repl

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agi

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t uni

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to 4

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deliv

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itchg

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expa

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clud

ed in

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that

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exis

ting

cond

ucto

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be

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nerg

ized

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the

switc

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ldin

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tens

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Page 9 of 13

Exis

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Gas

Insu

late

d Sw

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Page 10 of 13

Mic

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to $

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(Jun

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08

estim

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site

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icat

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Page 11 of 13

Mic

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- Ren

ditio

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Ext

ende

d B

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Page 12 of 13

Mic

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Exte

nsio

n

– Q

uest

ions


Page 13 of 13


Appendix

K

B.C. Environmental Assessment Act Order

Ken R. McKenzie, P.Eng., M.B.A. Project Director Generation Engineering 6911 Southpoint Drive, Floor B02 Burnaby, B.C. V3N 4X8

12 March 2009

Task Number: S600 Mr. Brian Murphy Environmental Assessment Office 1st Floor 836 Yates Street PO Box 9426 Stn Prov Govt Victoria, BC V8W 9V1 Dear Mr. Murphy:

Mica Generating Station Unit 5 Project Requested Amendment Regarding the Switchgear Building

I am writing to request an amendment to the Terms of Reference and Section 11 Order for the Mica Generating Station Unit 5 Project to remove the switchgear building extension work from the scope of the project. Currently the Section 11 Order for Mica Generating Unit 5 “Scope of the Project”, Section 3.1, includes the switchgear building extension because this work is needed to accommodate installation of the 500 kV conductor in shaft #3 and circuit breakers, which will be needed to bring power from Mica Unit 5 to the transmission system. The following (as bolded) is the relevant scope provision in the Terms of Reference, and the Section 11 Order,

• Bank of three single phase 16kV/500kV generator transformers. The switchgear

building will be extended to accommodate the new 500 kV circuit breakers;

At the Mica Generating Station, BC Hydro is scheduled to proceed with the Mica Switchgear Replacement (Mica GIS) project which involves replacement of the original and aging Mica GIS (Gas Insulated Switchgear) equipment for the existing four generating units. This equipment is now in poor condition and poses an unacceptable outage risk at Mica Generating Station. Recent significant outages caused by the failure of this equipment have proved costly because they render Mica generation inaccessible to the grid. BC Hydro needs to prevent the risk and costs of further outages by replacing this equipment as soon as practicable. The replacement of this equipment, including the conductors in shafts #1 and #2, cannot reasonably commence until the conductor in shaft #3 has been commissioned because there must be two conductors in operation at any given time to service four generating units. Therefore, BC Hydro wants to move forward with the site preparation work on the switchgear building extension in the fall of 2009. With the recent BC Hydro extension to the pre-application phase of the Mica Generating Unit 5 project Environmental Assessment process to allow for additional First Nation consultation and stakeholder engagement, the earliest the environmental certificate could be issued is March 2010. For these reasons BC Hydro is requesting that the

British Columbia Hydro & Power Authority, B02, 6911 Southpoint Drive, Burnaby, BC V3N 4X8 www.bchydro.com

Mica Gas Insulated Switchgear Project Appendix K-1

Page 1 of 4

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switchgear building extension be removed from the Mica Generating Station Unit 5 Terms of Reference and Section 11 Order.

The size of the switchgear building extension is approximately 40 feet wide, 130 feet long and 40 feet high. It will be a concrete structure with a steel roof. The building is located adjacent to the existing switchgear building (see attached photographs). The area has been previously disturbed and is currently used for parking and equipment storage. As part of the preparation of the Mica Generating Unit 5 EA Application, studies were undertaken on wildlife, vegetation, and archeology at the site. No potential impacts were found. As well, during a site visit this past fall, and a presentation at the last Core Committee meeting, no concerns were raised about the switchgear building extension. Given that,

• the building extension is required in the public interest to reliably operate the existing Mica generation and transmission system, and

• no potential environmental or heritage impacts were found, and • no concerns have been raised through consultation and engagement to date, and • BC Hydro voluntarily opted into the BCEA process with the Mica Generating Station Unit 5

project, we trust that you will be able to grant our request to remove the above noted (bolded) wording from the Mica Generating Station Unit 5 Terms of Reference and Section 11 Order, through a section 13 amendment order, or otherwise. Thank you for your consideration of this matter. Yours sincerely, Ken McKenzie Project Director KRM/kc Attachments c. Peter Northcott – BCH David Wilson – BCH Ryan McFadden - BCH Owen Williams – BCH


Page 2 of 4

- 3 -


Photo of Current Site and Switchgear Building


Page 3 of 4

- 4 -


Rendering of Proposed Switchgear Building Extension


Page 4 of 4

From: Murphy, Brian EAO:EX Sent: Monday, March 23, 2009 8:32 AM To: '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; XT:Johnson, Jay Okanagan Nation Alliance; '[email protected]'; XT:Osoyoos Indian Band EAO:IN; '[email protected]'; XT:Chief, Westbank First Nation EAO:IN; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]'; XT:Terbasket, Pauline Okanagan Nation Alliance EAO:IN; '[email protected]'; '[email protected]'; '[email protected]'; '[email protected]' Cc: Darling, May Y EAO:EX; Murphy, Brian EAO:EX Subject: Mica Generating Station Unit 5 - Section 11 order and Approved Terms of Reference

Mica Generating Station Unit 5 First Nations:

British Columbia Hydro and Power Authority (Proponent) wrote to me requesting (see attached) an amendment to the Approved Terms of Reference (ATOR) (section 4.3.1, page 24) and the section 11 order (section 3.1, bullet 3) to remove the switchgear building extension work. The switchgear building extension is needed to accommodate the installation of the 500 kV conductor in shaft #3 and circuit breakers to bring power from the proposed Mica Generating Station Unit 5 Project to the transmission system. As part of the request letter there is a photo of the current site and switchgear building and a second photo that includes a rendering of the proposed building extension. The size of the switchgear building extension is approximately 40 feet wide, 130 feet long and 40 feet high. It will be a concrete structure with a steel roof. The extension will be located adjacent to the existing building, as shown in the rendering. I have also attached additional photos of the area.

At the Mica Generating Station, the original Mica GIS (Gas Insulated Switchgear) equipment that services the existing four generating units is now in poor condition and poses an unacceptable outage risk. I understand that recent significant outages were caused by the failure of this equipment and resulted in the Mica Generating Station being unable to connect to the grid. In order to prevent further outages, the Proponent is proposing to replace the original and aging Mica GIS equipment. The replacement of the equipment will include the conductors in shafts #1 and #2. However, the replacement cannot begin until the conductor in shaft #3 is commissioned because there must be two conductors in operation at any given time to service four generating units. Shaft #3 is, at this time, excavated but not in use. The Proponent wants to move forward with the site preparation work on the switchgear building extension to the fall of 2009. The area proposed for the extension has been previously disturbed and it is currently used for parking and equipment storage. As part of the review process for the Mica Generating Station Unit 5 Application for an Environmental Assessment certificate, studies were undertaken by the Proponent on wildlife, vegetation and archaeology at the site; no potential impacts were found. Also, during a site visit in the fall of 2008, and


Page 1 of 2

a presentation at the January, 2009 Core Committee meeting, no concerns were raised about the switchgear building extension.

I have attached the draft section 13 order. If you have any specific concerns about the removal of the switchgear building extension work from the ATOR and the section 11 order, please contact me with your concerns prior to April 3, 2009. Thank you.


Page 2 of 2

IN THE MATTER OF THE ENVIRONMENTAL ASSESSMENT ACT S.B.C. 2002, c.43 (the Act)

AND

THE ENVIRONMENTAL ASSESSMENT OF THE

MICA GENERATING STATION UNIT 5 PROJECT (the Project)

ORDER UNDER SECTION 13

WHEREAS:

A. On March 4, 2008 British Columbia Hydro and Power Authority (Proponent) applied in writing to the Executive Director of the Environmental Assessment Office (EAO) and requested that the Project be designated a reviewable Project under section 7 of the Act;

B. The Executive Director, EAO, granted this application under section 7(3)(a) by return mail dated March 31, 2008;

C. The Executive Director has delegated to the undersigned powers and functions under the Act, including the power to issue orders under section 10, 11 and 13 of the Act;

D. On April 18, 2008, under section 10(1 )(c) of the Act, the Project Assessment Director issued an order to the Proponent stating that the Project requires an Environmental Assessment Certificate, and that the Proponent may not proceed with the Project without an assessment;

E. On October 28, 2008, the Project Assessment Director issued an order under section 11 of the Act, determining the scope of the required environmental assessment and the procedures and methods for conducting the assessment;

F. On December 19, 2008, Schedule B of the section 11 order was amended to include additional First Nations whose asserted traditional territories the Project lies within; and,

G. On March 12, 2009, the Proponent requested an amendment to the section 11 order to remove the switchgear building extension work. The existing equipment is now in poor condition and poses an unacceptable outage risk at Mica Generating Station. The Proponent is scheduling to replace the existing switchgear equipment, in the fall of 2009, to ensure reliable operation of the existing Mica generation and transmission system.

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Page 1 of 2

NOW THEREFORE:

Pursuant to section 13 of the Act, I order that:

Section 3.1, bullet 3, of the section 11 order issued on October 28, 2008 is varied by removing the following sentence:

• The switchgear building will be extended to accommodate the new SOOkV circuit breakers;

irector ion Unit 5 Project

Dated April 17, 2009 at VictOria , British Columbia

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