March 7, 2011 Ms. Erica M. Hamilton Commission Secretary British - - PDF document

British Columbia Hydro and Power Authority, 333 Dunsmuir Street, Vancouver BC V6B 5R3 www.bchydro.com Joanna Sofield Chief Regulatory Officer Phone: 604-623-4046 Fax: 604-623-4407 bchydroregulatorygroup@bchydro.com

March 7, 2011

• Ms. Erica M. Hamilton

Commission Secretary British Columbia Utilities Commission Sixth Floor – 900 Howe Street Vancouver, BC V6Z 2N3 Dear Ms. Hamilton: RE: Project No. 3698623 British Columbia Utilities Commission (BCUC) British Columbia Hydro and Power Authority (BC Hydro) Ruskin Dam and Powerhouse Upgrade Project (Project) Application for a Certificate of Public Convenience and Necessity (CPCN) Attached as Exhibit B-2 is BC Hydro’s presentation from the Ruskin Dam and Powerhouse Upgrade Project CPCN Application Information Session held on February 28, 2011. For further information, please contact Geoff Higgins at 604-623-4121 or by e-mail at bchydroregulatorygroup@bchydro.com. Yours sincerely, Joanna Sofield Chief Regulatory Officer

sh/rh

Enclosure Copy to: Kwantelen First Nation Sto:lo Tribal Council Matsqui First Nation BCUC Project No. 3698592 BC Hydro F11 RRA Registered Intervener Distribution List B-2 BC HYDRO – RUSKIN DAM AND POWERHOUSE UPGRADE PROJECT EXHIBIT

1

Ruskin Dam and Powerhouse Upgrade Project

CPCN Application Information Session

February 28, 2011

2

INTRODUCTION

WORKSHOP AGENDA

• Introduction (Geoff Higgins);
• CPCN Application Overview (Craig Godsoe);
• Facility and Project Overview (Chris O’Riley);
• BC Hydro’s Load Forecast and Load/Resource Balance (Randy Reimann);
• Alternatives Analysis (Dean Cardno);
• First Nations Consultation and Public Engagement (Boyd Mason);
• Project Risk and Risk Mitigation (Boyd Mason);
• Rate Impact and BCUC Regulatory Timetable (Geoff Higgins).

3

CPCN Application Overview

REGULATORY APPROVALS

• Project does not trigger CEAA or BCEAA:
• BCEAA: modification to an existing facility below 50MW threshold;
• EAO rejected BC Hydro’s voluntary opt-in request.
• CEAA:
• DFO concluded no HADD if mitigation measures are followed;
• Transport Canada advisory opinion that Project will not increase interference with

navigation.

• No amendments to Conditional Water Licenses or Water Use Plan;
• Only material regulatory approval is Certificate of Public Convenience and

Necessity (CPCN) from the BCUC.

4

CPCN Application Overview

APPLICATION STRUCTURE

• Application structure largely follows BCUC CPCN Guidelines;
• Chapter 1 – Introduction:
• Order sought and why BC Hydro is applying for a CPCN (Section 1.1);
• Implications of Clean Energy Act (Section 1.1);
• BC Hydro’s past project experience (Section 1.3);
• List of Appendices (Section 1.5).
• Chapter 2 – Project Description and Impacts:
• Existing Facility (Section 2.1);
• Project Scope (Section 2.2);
• Cost Estimate, Schedule and Rate Impact (Sections 2.4 – 2.6);
• Environmental and Social Impacts (Sections 2.7 and 2.8).

5

CPCN Application Overview

APPLICATION STRUCTURE (Continued)

• Chapter 3 – Project Justification:
• Condition of Dam and Powerhouse (Section 3.2.1);
• Project needed to meet Load/Resource Gap (Section 3.2.2);
• Project Alternatives (Section 3.3):
• Long-Term: 5 Alternatives (2 De-Rate and 3 Decommissioning);
• Short-Term Deferral to implement either the Project or 2 De-rate or 1 Decommissioning.
• Alternative Means of Carrying Out the Project (e.g. 2 versus 3 units) (Section 3.4).
• Chapter 4 – First Nations Consultation and Public Engagement
• Chapter 5 – Project Risks and Risk Management:
• Definition Phase (Section 5.2);
• Implementation Phase (Section 5.3);
• Operation phase (Section 5.4);
• Summary (Section 5.5).

6

CPCN Application Overview

ORDER SOUGHT

• Set out in Appendix A; reporting requirements similar to other projects;
• Pursuant to subsection 46(1) of the Utilities Commission Act, BC Hydro filed

its application for the BCUC to grant a CPCN to construct and operate the Ruskin Dam and Powerhouse Upgrade Project (Project);

• BC Hydro seeks a CPCN on the basis of, amongst other things, the

Authorized Amount. This is also consistent with BC Hydro’s Capital Project Filing Guidelines:

• The form of the BC Hydro Board of Directors authorization informs the

Application.

7

Facility Overview

HISTORY OF RUSKIN

• Dam and Powerhouse Unit 1
• riginally constructed in 1930;
• Second and Third Units

constructed in 1938 and 1950;

• No major refurbishments

have been carried out since

• riginal construction;
• Seismic and structural

deficiencies require that extensive investment is required to ensure safety and reliability of Ruskin. Original 1930 Construction

8

Facility Overview

RUSKIN TODAY Right Abutment Dam Powerhouse and Switchyard Left Abutment

9

Facility Overview

• Dependable capacity of 105MW;
• Average annual energy output of 348 GWh, 88 per cent of which is firm;
• Located in the Lower Mainland, which accounts for about 70 per cent of BC

Hydro’s Load;

• With the benefit of the combined storage capacity of the Stave River System

reservoirs, Ruskin is able to provide the following additional benefits:

• Dispatchability, which can be used to meet peak load requirements and to respond

to short term variations in load or resource balance;

• On-call reserve support or the ability to reduce output for BC Hydro as it seeks to

integrate increasing amounts of intermittent clean or renewable energy.

• Provides dependable voltage and local reactive power (VAr) support for the

Lower Mainland 69 kV transmission network and electrical system. BENEFITS PROVIDED BY RUSKIN

10

Facility Overview

Right Abutment

• Consists of highly erodible soils;
• Both seismic and static deficiencies have been identified:
• Efforts to date to mitigate sand erosion have only been partially successful;
• Damage to the Right Abutment seepage barrier of could occur at an earthquake

return period of less than 1 in 475 years.

Left Abutment

• Portion behind the Powerhouse is steep and unstable and could fail following

a major earthquake with a return period of less than 1 in 2,475 years, which is below CDA guidelines for an earth embankment. Spillway Gates

• Seismic deficiencies in the existing spillway gates, piers, and roadway of the

Dam where cracking of structures could occur with ground motions of 0.12 g (an event with an expected return period of 1 in 100 years). RUSKIN DAM DEFICIENCIES

11

Facility Overview

• The Ruskin dam is categorized as “Very High Consequence”, meaning that

the downstream impacts of a dam breach may include loss of life, and significant financial and environmental damage;

• A seismic event could result in dam or abutment damage. The level and

extent of damage could include dam or abutment failure and uncontrolled release of the reservoir;

• If Spillway gates or spillway gate piers are damaged in an earthquake, BC

Hydro could lose the ability to pass water during a post-earthquake drawdown

• r during a MDE, which could lead to overtopping and dam failure;
• BC Hydro has undertaken a number of actions in recent years to mitigate

dam risk (section 2.3); in particular, an operating restriction was put in place in 2005 to limit the maximum operating level of the reservoir to El 41.4 m (a 1.5 m reduction) which impacts both the environment and public use of the reservoir. RUSKIN DAM – CONSEQUENCES OF FAILURE

12

Facility Overview

Deficiencies

• Powerhouse structure and/or Left Abutment (behind the Powerhouse) do not

meet seismic standards and could collapse in a large earthquake;

• Major generating components, including the turbines and generators,

exciters, governors and transformers (located between the Powerhouse and Left Abutment) are in poor to unsatisfactory condition;

• Switchyard, located on the Powerhouse roof is a circa 1930’s design and

does not allow maintenance work to be performed at the switchyard without a full station and transformer line outage, and poses safety risks to worker safety (limits of approach);

• Third party consultant RW Beck found that the major generating components

“[have] well exceeded [their] expected useful life” and that the performance of the Powerhouse equipment has been declining. CONDITION OF THE POWERHOUSE

13

Facility Overview

Consequences of Failure

• Collapse of the Left Abutment or Powerhouse building could result in

injury/death, the loss of generating output from Ruskin, and environmental consequences;

• A failure in one or more of Ruskin’s three generating units will likely result in

an outage of more than a year with increased costs and could result in environmental impacts;

• RW Beck found that “there is a high likelihood of a major equipment failure

that could cause personal injury as well as extended outage and result in extensive repair and replacement costs”. CONDITION OF THE POWERHOUSE

14

Project Overview

• The Scope of the Project is to correct dam safety deficiencies and replace or

rehabilitate powerhouse equipment and ancillaries to extend the facility life by at least 50 years;

• Given the extent of work being undertaken by the Project, BC Hydro has not

currently identified any need to undertake significant future capital expenditures at the Ruskin Facility in the short to medium term. PROJECT OBJECTIVE

15

Project Overview

Dam Safety Upgrades

• Complete work to address seismic deficiencies identified at the Right

Abutment;

• Address Left Abutment, Spillway Gates and Spillway Piers seismic

deficiencies;

• Rebuild and widen road crossing overtop of Ruskin Dam.

Powerhouse Upgrades

• Address Powerhouse structural and safety deficiencies;
• Replace and refurbish turbine and generator equipment;
• Replace balance of plant, ancillary equipment;
• Relocate and replace Switchyard;
• Upgrade powerhouse access bridge.

PROJECT SCOPE

16

Project Overview

Right Abutment

2012 - 2013

Dam

Late 2013 - 2017

Powerhouse

Structure: 2012 -2013 Generators: 2014-2017

Switchyard

Between 2014 and 2017

Left Abutment

2016 - 2017

17

LONG-TERM PLANNING

• Need for Ruskin in Load Resource Balance:
• F2017 for Firm Energy;
• F2017 for Dependable Capacity.
• Need is determined by:
• Net Load Forecast after Demand Side Management (DSM);
• Less Existing, Committed and Planned Supply.
• The Clean Energy Act is a key Input

Load Resource Balance

18

METHODOLOGY AND CHANGES

• Methodology for the 2010 Load Forecast is substantially unchanged;
• Used most recent (2010) Long Term Rate Forecast;
• Oil & Gas and Mining sector growth;
• Electric Vehicles (EVs) are included in 2010 Forecast;
• Adjustment to load projections for DSM / Load Forecast (DSM/LF)

Integration: Resolution of the overlap with the Power Smart Codes and Standards;

• The need for the project’s firm energy and dependable capacity is

based on the 2010 Load Forecast without the increased load impacts of Electric Vehicles and DSM/Load Forecast double counting.

2010 Load Forecast

19

2010 Load Forecast

TOTAL INTEGRATED GROSS REQUIREMENTS BEFORE DSM AND WITH RATE IMPACTS* – 2010 FORECAST VS. 2008 LTAP EU FORECAST

* Rate Impacts refer to load reductions from forecast electricity rate changes but do not include load reductions from two-tier rate design

• Between F2008 and F2010, total requirements have declined by approximately 3,500 GWh or 6.0 per cent.
• Transmission sales have declined by 2,400 GWh or 15.0 per cent over the same time period. This reflects a number of

permanent closures, curtailments and rapid decline in demand for BC’s raw exports. Sector most effected by global slow down includes forestry and mining. Recent trends indicated that commodity prices and demand have stabilized.

• Current load growth projections reflect agreements reached for Northwest Transmission Line (NTL); and increased

inquiries and nomination for electricity service for mining and oil gas. However these loads can be volatile – up or down.

• The 2010 Load Forecast includes the impact of EVs (2,100 GWh in F2030) and adjustments for DSM/LF Integration

Overlap of efficiency estimates associated with codes and standards (1,000 GWh in F2030). 2010 Forecast without EV or DSM/LF Integration (GWh) 2008 LTAP EU Forecast (GWh) 2010 Less 2008 LTAP EU (GWh) 2010 Less 2008 LTAP EU (%)

F11 56,818 60,490 (3,672) (6.1%) F12 59,295 61,362 (2,067) (3.4%) F17 68,326 66,172 2,154 3.3% F21 70,658 68,480 2,178 3.2% F25 74,248 72,080 2,168 3.0% F29 77,506 75,937 1,569 2.1%

55,000 60,000 65,000 70,000 75,000 80,000 85,000 F 1 1 F 1 2 F 1 3 F 1 4 F 1 5 F 1 6 F 1 7 F 1 8 F 1 9 F 2 F 2 1 F 2 2 F 2 3 F 2 4 F 2 5 F 2 6 F 2 7 F 2 8 F 2 9 GWh 2010 Forecast 2010 Forecast without EV or DSM/LF Integration 2008 LTAP EU Forecast

20

2010 Load Forecast

INTEGRATED TOTAL PEAK BEFORE DSM AND WITH RATE IMPACTS – 2010 FORECAST VS. 2008 LTAP EU FORECAST

* Forecast excludes Fort Nelson and includes capacity transfers from BC Hydro to other Utilities including Fortis BC, Seattle City Light and the City of New Westminster .

• Current Peak demand projection is below 2008 forecast in the short term. Reflects historical decline in transmission peak

demand from reduced loads and closures.

• Middle and long term forecast above 2008 forecast. Reflects anticipated higher peak demand from oil and gas and mining

loads.

• EV impact reflected in later 10 years of the 2010 Load Forecast. EV peak impact reflects a charging profile that builds up

through the day. Profile based on battery depletion rates and driving patterns and data is supported by EPRI studies.

10,000 11,000 12,000 13,000 14,000 15,000 16,000 F11 F12 F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 MW 2010 Forecast 2010 Forecast without EV or DSM/LF Integration 2008 LTAP EU Forecast

2010 Forecast without EV or DSM/LF Integration (MW) 2008 LTAP EU Forecast (MW) 2010 Less 2008 LTAP EU (MW) 2010 Less 2008 LTAP EU (%)

F11 10,562 11,144 (582) (5.2%) F12 11,044 11,279 (234) (2.1%) F17 12,362 11,761 601 5.1% F21 12,754 12,241 513 4.2% F25 13,354 12,891 464 3.6% F29 13,912 13,604 308 2.3%

21

CLEAN ENERGY ACT

• Self Sufficiency by F2017 and Insurance by F2021:
• Critical Water;
• The 2,500 GWh/year of non-firm energy/market allowance and 400 MW of market

reliance is removed after December 31, 2015.

• Demand Side Management:
• 2008 LTAP Evidentiary Update Option A - 79% in F2021.
• Burrard:
• No planned reliance for energy;
• Up to 900 MW of capacity until all of the following projects are completed and the

resulting facilities are providing service:

• Mica Units 5 and 6;
• the Interior to Lower Mainland Transmission Project, and
• the Meridian substation transformer project.
• Thereafter, no planned reliance:
• Smart Metering Initiative – Energy Theft Loss Reduction:
• Energy – 64 GWh in F2017 up to 555 GWh in F2025;
• Capacity – 9 MW in F2017 up to 77 MW in F2025.

Load Resource Balance

22

Load Resource Balance

COMMITTED RESOURCES

• Those resources for which

material regulatory approvals have been secured (BCUC, either secured or through exemption; and environmental assessment- related), and the Board has authorized. EXISTING & COMMITTED RESOURCES

• Heritage Hydroelectric;
• Heritage Thermal;
• Resource Smart;
• Waneta Transaction;
• Mica Units 5 and 6;
• Existing and Committed IPPs:
• Pre-Clean Power Call;
• Clean Power Call;
• Alcan;
• Island Generation;
• Bioenergy Phase 1;
• SOP (signed EPAs);
• IPO (signed EPAs);
• Alta Gas (signed EPA);
• Waneta Expansion.

23

Load Resource Balance

PLANNED RESOURCES

• Those resources for which

material regulatory approvals have been secured and the Board has not authorized. PLANNED RESOURCES

• Alta Gas (2 without EPAs);
• Bioenergy Phase II;
• IPO (without EPAs);
• 2010 SOP.

24

Load Resource Balance: Energy

50,000 55,000 60,000 65,000 70,000 75,000 F2012 F2013 F2014 F2015 F2016 F2017 F2018 F2019 F2020 F2021 F2022 F2023 F2024 F2025 F2026 F2027 F2028 F2029 F2030 F2031

Fiscal Year (year ending March 31) Firm Energy Capability

(GWh) Existing and Committed Planned IPPs 2010 Mid Load Forecast After DSM + Insurance 2010 Mid Load Forecast After DSM Without EV + Insurance 2010 Mid Load Forecast After DSM Without EV and DSM/LF Integration + Insurance

Operating Planning

25

Load Resource Balance: Capacity

11,000 12,000 13,000 14,000 15,000 F2012 F2013 F2014 F2015 F2016 F2017 F2018 F2019 F2020 F2021 F2022 F2023 F2024 F2025 F2026 F2027 F2028 F2029 F2030 F2031

Fiscal Year

(year ending March 31)

Capacity

(MW) Existing and Committed Planned IPPs 2010 Mid Load Forecast After DSM 2010 Mid Load Forecast After DSM Without EV 2010 Mid Load Forecast After DSM Without EV and DSM/LF Integration

Operating Planning

26

Value of Ruskin Products

VALUE OF ENERGY

• Based on the Clean Power Call in F2011$
• Firm:

$129/MWh

• Non-Firm:

$50/MWh

• Weighted Average:

$120/MWh

VALUE OF CAPACITY

• Based on Revelstoke Unit 6 in F2011$:

$55/kW-year

• Capacity Cost Sensitivity:

$37 - $107/kW-year Capacity Credit None Low Market, Trans- Limited $37/kW-year Domestic $55/kW-year High Market $107/kW-year Unit Energy Cost ($/MWh) 67.5 56.3 50.9 35.3

27

Alternatives Analysis

GENERATING ALTERNATIVES

Project – Retain 3 (recommended alternative): The spillway gates and piers will be replaced. All three generating units replaced/refurbished. Current 41.5m operating restriction is removed. Alternative A – De-Rate 2: The spillway gates would be removed and small (approx 2.5m in height) automated crest gates installed

• n the Dam crest to provide enough spill capability to ensure that a

plant trip does not dewater the lower Stave River. Only two of the three generating units would be replaced/refurbished. Alternative E – De-Rate 3: As in the Permanent De-Rate Alternative, the spillway gates would be removed and small (approx 2.5 m) automated crest gates installed on the Dam crest. A lower unit 3 intake would be installed. All three generating units and their ancillaries would be replaced/refurbished.

41.4m Reservoir Crest Gates 37.0m Reservoir 41.4m Reservoir 42.9m Reservoir New Spillway Gates Crest Gates 41.4m Reservoir 37.0m Reservoir Crest Gates

28

Alternatives Analysis

DECOMMISSIONING ALTERNATIVES (NO GENERATION)

Alternative B – Overflow: The spillway gates would be removed and flashboards installed on the crest of the five interior spillway bays. The Powerhouse would be removed down to the generator floor and new discharge valves would be installed in a newly-constructed valve- house where the powerhouse existed. Alternative C – Remove: The Dam would be removed and the Hayward Lake Reservoir would be returned, to the extent practicable, to its original condition. The Powerhouse would be removed to the generator floor, and all three penstocks would be filled with gravel and capped with concrete at both ends, as would all three draft tubes. This alternative would require dewatering Hayward Lake Reservoir prior to removal of the Dam. Alternative D – Tunnel: This alternative is similar to the abandonment with dam removal; rather than removing the Dam, a large opening would be excavated through the base of the Dam to allow water passage.

41.4m Reservoir Flashboard 37.0m Reservoir No Reservoir – No Dam No Reservoir – with Dam

29

Alternatives Analysis

ALTERNATIVES BENEFIT COMPARISON

Project Retain 3 Alt A De-Rate 2 Alt B Overflow Alt C Remove Alt D Tunnel Alt E De-Rate 3 Generating Units 3 2 none none none 3 Reservoir Elevation Return to 42.9m Reduce to 37.0m Reduce to 37.0m Drain Reservoir Drain Reservoir Reduce to 37.0m Annual Energy GWh 379 308 n/a n/a n/a 322 PV of Energy 4,393 3,566 n/a n/a n/a 3,734 Nameplate Capacity MW 120 70 n/a n/a n/a 105 Dependable Capacity 114 70 n/a n/a n/a 100 PV of Dependable Capacity 1,322 811 n/a n/a n/a 1,156

30

Alternatives Analysis

ALTERNATIVES NPV COMPARISON

Project Retain 3 Alt A De-Rate 2 Alt B Overflow Alt C Remove Alt D Tunnel Alt E De-Rate 3 Project Benefits Energy ($129 & $50/MWh) NPV$M 525.1 426.3

• 446.3

Capacity ($55/kW-Yr) 72.7 44.6

• 63.6

Total Benefits 597.8 470.9

• 509.9

Project Costs (Expected Amount) Capital Costs 385.2 314.5 146.9 219.9 215.6 374.2 Operating Costs 59.2 45.3 1.2

• 53.9

Total Costs 444.4 359.9 148.1 219.9 215.6 428.2 Project NPV 153.3 111.0 (148.1) (219.9) (215.6) 81.8 Avoided Decommissioning 148.1 148.1 148.1 148.1 148.1 148.1 NPV - net of Decommissioning 301.4 259.1

• (71.8)

(67.5) 229.8 Total Costs (Authorized Amount) 515.4 452.7 180.6 275.2 269.9 543.2 Project NPV 82.4 18.2 (180.6) (275.2) (269.9) (33.2) Avoided Decommissioning 180.6 180.6 180.6 180.6 180.6 180.6 NPV - net of Decommissioning 263.1 198.8

• (94.6)

(89.2) 147.4

31

Alternatives Analysis

ALTERNATIVES NPV COMPARISON

Authorized Authorized Authorized Expected Expected Expected De-Comm Credit De-Comm Credit De-Comm Credit 50 100 150 200 250 300 Project Retain 3 Alt A De-Rate 2 Alt E De-Rate 3 $M NPV

*

32

Alternatives Analysis

ALTERNATIVES LEVELIZED COST COMPARISON

Project Retain 3 Alt A De-Rate 2 Alt B Overflow Alt C Remove Alt D Tunnel Alt E De-Rate 3 Levelized Cost (Expected Amount) Capital Costs (incl Sunk & Switchyard) 87.7 88.2 33.4 50.0 49.1 100.2 Operating Costs 5.3 4.9 0.3 6.2 Water Rental (Energy) 6.9 6.9 6.9 Water Rental (Capacity) 1.3 0.9 1.3 Market Purchase 119.5 119.5 119.5 Levelized Cost $/MWh 101.2 100.9 153.2 169.6 168.6 114.7 Avoided Decommissioning (33.7) (41.5) (33.7) (33.7) (33.7) (39.6) $/MWh 67.5 59.4 119.5 135.9 134.9 75.0 Capacity Credit (16.5) (12.5) (17.0) $/MWh 50.9 46.9 119.5 135.9 134.9 58.0 Levelized Cost (Authorized Amount) 117.3 126.9 160.6 182.2 181.0 145.4 Avoided Decommissioning (41.1) (50.7) (41.1) (41.1) (41.1) (48.4) $/MWh 76.2 76.3 119.5 141.0 139.8 97.1 Capacity Credit (16.5) (12.5)

• (17.0)

$/MWh 59.6 63.8 119.5 141.0 139.8 80.0

33

Alternatives Analysis

ALTERNATIVES LEVELIZED COST COMPARISON

• Cap. Cr.
• Cap. Cr.
• Cap. Cr.

Expected Expected Expected Expected Authorized Authorized Expected Expected Authorized Authorized Auth. Auth. 30 60 90 120 150 Project - Retain 3 Alt A - De-Rate 2 Alt B - Overflow Alt C - Remove Alt D - Tunnel Alt E - De-Rate 3 $/MWh

34

Alternatives Analysis

SUMMARY

• The Project is the highest capital cost option. The lowest capital cost

alternative is abandonment of the Powerhouse with overflow of the existing dam (Alternative B);

• When compared with the alternatives, the Project (upgrade of all three units)

provides:

• The highest net present value;
• The greatest energy and capacity benefits; and
• A competitive unit energy cost.
• The next best alternative is Alternative A (Upgrade only 2 units and lower

reservoir);

• The earliest that any of the alternatives could be implemented is November

2015;

• Environmental and Socio-Economic impacts of the Project and Alternatives

are discussed in the Application at Section 3.3.1.5.

35

First Nations Consultation

CONSULTATION OVERVIEW

• Notification provided to five First Nation groups;
• Sto:lo Nation Council directed BC Hydro to consult with Kwantlen (see

following slide for Kwantlen consultation);

• Project information has been provided to Matsqui and Sto:lo Tribal Council

(STC); to date, neither Matsqui nor STC have raised any issues or concerns;

• Although the Project appears to be outside the territory of Hul’qumi’num

Treaty Group (HTG), HTG was provided with Project information and to date have not raised any Project issues or concerns;

• Copies of the Application were provided to Kwantlen, Matsqui, and STC.

36

First Nations Consultation

CONSULTATION WITH KWANTLEN

• Kwantlen was notified of the Project in November 2006;
• Kwantlen provided feedback and BC Hydro responded to information

requested regarding the Project, including alternatives and environmental impacts – these discussions continue;

• Capacity Funding Agreement reached in 2010;
• Parties continue to discuss a benefits agreement and contracting/employment
• pportunities for Kwantlen.

FUTURE CONSULTATION

• Consultation will be ongoing through the Implementation phase of the Project;
• BC Hydro will assess the adequacy of consultation as part of Final Argument.

37

Public Engagement

PUBLIC ENGAGEMENT PROCESS

• Initiated in 2006;
• Letters of support received from District of Mission and Mission Chamber of

Commerce;

• Participants in BC Hydro’s engagement process understand the need and

justification for the Project;

• Discussions are on-going related to management of construction impacts.

38

Project Risks

DEFINITION PHASE

• Issuance of a Certificate of Public Convenience and Necessity;

OPERATIONS PHASE

• Completed upgrade operational risks, including reliability, safety and

environmental risks, are lower when compared with current operation;

• Future benefits following the completion of the Project include:
• Improved unit reliability and efficiency;
• Fewer expected reservoir drawdowns;
• Addition of auto-spill functionality.

39

Project Risks

IMPLEMENTATION PHASE

• Schedule Risk;
• Environmental Risk;
• Cost Risk.

40

Project Schedule

ID Task Name Start Finish

2012 2013 2014 2015 2016 2017 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

1 2013-07-17 2012-01-27 Right Abutment 2 2017-03-16 2013-11-25 Dam Spillway Piers and Gates 3 2015-02-27 2013-11-25 Piers and Gates 1 and 2 4 2016-06-20 2015-03-02 Piers and Gates 3 and 4 6 2017-06-30 2012-03-08 Powerhouse Upgrade 7 2013-06-13 2012-03-08 Powerhouse Super Structure 8 2015-11-18 2014-12-30 Generating Unit 1 9 2016-09-14 2015-11-27 Generating Unit 2 11 2017-06-30 2014-03-31 Switchyard Re-Location and Upgrade 5 2017-03-16 2016-06-21 Piers and Gate 7 10 2017-06-30 2016-09-15 Generating Unit 3

First turbine shipped, received at site, and ready for installation Bulkhead fabrication, bridge footing, and dam access complete, first Spillway Gates ready for installation

41

Schedule and Environmental Risks

SCHEDULE RISK Three key schedule delay risks during construction: 1. Excavation work, and materials challenges; 2. Adverse weather; and 3. Inflow conditions. ENVIRONMENTAL RISK Two key areas of environmental risk include:

• 1. The potential for a significant spill to maintain flow continuity; and
• 2. The potential for loss of flow continuity.

42

Schedule and Environmental Risks

SCHEDULING AND ENVIRONMENTAL RISK MITIGATION In addition to implementing contract and project management best practices, the Project has been sequenced as follows to minimize scheduling and environmental flow-related risks:

• 1. The generating unit replacements will take place sequentially one unit at a

time, allowing greater work area to the contractors and mitigating environmental downstream flow continuity and spill risk by leaving two generating units available for service to mitigate the risk impact of an unplanned generating unit outage.

• 2. Work that requires a reservoir drawdown is scheduled to occur during the

Fraser River freshet so that tailwater elevations can be maintained downstream from the Dam for fish habitat in the event of a forced unit outage at the Ruskin Facility.

• 3. The Right Abutment work is being performed first as it represents the highest

risk exposure for this project.

43

Project Cost

PROJECT COMPONENT Amount ($ million) Pre-Implementation Phase Costs (Loaded) 87.0 Direct Construction Cost 325.2 Project Management and Engineering 40.3 Other Indirect Construction Costs 14.7 Project Contingency on Expected Amount 56.0 Dismantling and Removal 10.4 Inflation (Note 1) 41.4 Implementation Phase Costs (Before Loadings) 488.0 Capital Overhead 77.5 IDC 65.6 Implementation Phase Costs (Loaded) 631.1 Total Expected Amount 718.1 Incremental Project Contingency on Authorized Amount 67.1 Incremental Inflation, Capital Overhead and IDC on Authorized Amount 31.7 Management Reserve 40.0 Total Authorized Amount 856.9

44

Project Cost Risk

KEY CONTRIBUTORS TO COST RISK

• Project involves the replacement of equipment within an existing facility, with

limited working space, that will be operating, resulting in a higher level of cost uncertainty;

• Project scope and schedule adjustments during construction, and market

interest have the greatest potential to affect the overall cost of the Project. MITIGATION OF COST RISK

• Scheduling strategy described earlier;
• Cost risk has been mitigated through:
• Clearly defining scope of Project;
• Contingencies to accommodate unknown risks;
• Management reserve for FX and market condition-driven price increases;
• Third party due diligence review of cost estimate;
• Development of a procurement strategy incorporating such elements as

constructability reviews, early contractor involvement, and experienced BC Hydro Project staff.

45

Rate Impact

• 0.40%
• 0.30%
• 0.20%
• 0.10%

0.00% 0.10% 0.20% 0.30% 0.40% 0.50% F2011 F2012 F2013 F2014 F2015 F2016 F2017 F2018 F2019 F2020 F2021 F2022 F2023 F2024 F2025 F2026 F2027 F2028 F2029 F2030 F2031 F2032 F2033 F2034 F2035 Fiscal Year Per Cent % Expected Amount Authorized Amount

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BCUC Regulatory Timetable

EVENT DATE (2011) Intervener Registration Thursday, March 10 Commission Information Request No. 1 Thursday, March 10 Intervener Information Requests No. 1 Friday, March 18 BC Hydro Response to Information Requests No. 1 Friday, April 8 BCUC and Intervener Request No. 2 Thursday, April 21 BC Hydro Responses to Information Requests No. 2 Friday, May 13 BC Hydro Final Written Submission Friday, May 27 Intervener Final Written Submission Friday, June 10 BC Hydro Written Reply Submission Friday, June 24

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Questions?