november 2013 irp appendix 3a-27: 2013 ror update – run-of ... · 2013 resource options report...

Integrated Resource Plan

Appendix 3A-27

2013 Resource Options Report Update

Run-of-River Report

2013 Update Memorandum and

2010 Report

Appendix 8-A is comprised of two parts:

Part 1: 2013 Resource Options Report Update – Run-of-River Technical Memorandum

Run-of-River Hydroelectric Resource Assessment for British Columbia 2013 Revisions (June 2013)

During the process of preparing the run-of-river data for the BC Hydro August 2013 Integrated Resource Plan, Kerr Wood Leidal Associates Ltd. (KWL) identified that some items from its 2010 run-of-river report required revisions. This technical memorandum provides an overview of those revised items.

Part 2: 2010 Resource Options Report – Run-of-River Report

Run-of River Hydroelectric Resource Assessment for British Columbia 2010 Update (March 2011)

In 2010, BC Hydro commissioned KWL to complete an update to the 2007 inventory of run-of-river hydroelectric potential in British Columbia.

Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A

Page 1 of 72 November 2013

Technical Memorandum DATE: June 20, 2013

TO: Nan Dai, BC Hydro

Ellen Feng, BC Hydro FROM: Colleen O’Toole, P.Eng.

Stefan Joyce, P.Eng. RE: RUN OF RIVER HYDROELECTRIC RESOURCE ASSESSMENT FOR BRITISH COLUMBIA

2013 REVISIONS Our File 0478.133-300

Introduction In 2010, BC Hydro commissioned Kerr Wood Leidal Associates Ltd. (KWL) to complete an update to the 2007 inventory of run-of-river hydroelectric potential in British Columbia. In advance of the 2013 Integrated Resource Plan process, BC Hydro sought further data for analysis. During the data extraction for BC Hydro some items requiring revision were identified. This technical memorandum provides a discussion of the revisions made and provides an update on the inventory of British Columbia’s run-of-river hydroelectric potential.

Discussion of Revisions to Run of River Inventory Analysis The following revisions were made to the 2010 Run-of-River Hydroelectric Resource Assessment (2010 RoR Update):

Penstock Friction In the process of this work KWL found that the penstock friction calculation needed to be revised. In most cases the penstock frictional losses formulation was underestimating the headloss and hence overestimating the net capacity (MW). In a few cases the friction was overestimated and the net capacity underestimated.

The changes to capacity due to penstock friction revisions affect:

• capital cost since the turbine sizing (MW) and costing of other components affected by capacity (MW) changed in some cases;

• annual costs that are based on either capital cost or capacity;

• annual and monthly energy, dependable capacity, ELCC and firm energy; and

• Unit Energy Cost (UEC), due to a change in both the costs and annual energy.



2 \\Libra25.burnaby.kerrwoodleidal.org\0000-0999\0400-0499\478-133\300-Reports\RoR_Update_Final_TechMemo_2013-06-20.docx

TECHNICAL MEMORANDUMRun of River Hydroelectric Resource Assessment for

British Columbia 2013 RevisionsJune 20, 2013

Turbine Sizing and Selection Multiple turbine case costing: The model was selecting a single large turbine for costing, when in some cases, multiple smaller turbines was planned.

Turbine selection: Adjustments have been made to the head range being considered when selecting the turbine. The turbine selection and costing has now been adjusted.

Where revisions resulted in a change to turbine selection or multiple turbine costing, this affected:

• capital cost;

• annual costs components that are based on capital cost;

• annual and monthly energy, dependable capacity, ELCC and firm energy, due to a change in the turbine shutoff; and

• UEC, due to a change in both the costs and annual energy.

Mobilization The model was referencing only a portion of the factors that influence mobilization. It was referencing the materials when it should have also been referencing equipment in the estimation of mobilization costs.

The mobilization calculation has been revised to include consideration of both equipment and materials. These revisions affected:

• capital cost; • annual costs components that are based on capital cost; and • UEC.

To account for site variations due to regional factors and remoteness (proximity to city centres), costs for construction camps and transportation of people and equipment were added to estimates. Four site categories were used to indicate the remoteness of location. Category A sites were located within a 50 km radius of a major town or city centre (population of 25,000 or more). Category B or C sites were located within 200 to 400 km for a centre, respectively. Category D sites were located anywhere outside a 400 km radius from a city centre. Camp and transportation cost estimates for Site Categories A through D are shown in Table 1 below. Table 2 provides a summary of the additional cost allowance provided for the mobilization and demobilization to and from the site (Note that Table 2 was not presented in the 2010 RoR Update report – March 2011).

Table 1: Total Camp and Transportation Costs ($)

Project Capacity Location Class A

Location Class B

Location Class C

Location Class D

Less than 1 MW 111,300 222,600 800,830 934,3901 to 10 MW 222,600 445,200 1,304,330 1,571,450Greater than 10 MW 333,900 667,800 1,807,830 2,208,510



3



Table 2: Additional Site Location Mobilization/Demobilization Allowance Site Location

Class % of Capital Cost

A 6

B 10

C 18

D 24

Water Survey of Canada Proxy Gauge In the algorithm that compared an intake’s drainage area to the watershed areas of the Water Survey of Canada (WSC) gauges within a hydrologic region, larger intake drainage area value was being used. The algorithm selected a WSC gauge from the correct hydrologic region, but it was not necessarily selecting and weighting based on the gauges KWL set out in the methodology.

The methodology was set out such that within each hydrologic zone, a site was associated to one or two WSC gauges by identifying WSC gauges with the next larger and next smaller drainage area (as compared to the drainage area of the project site). A weighted average based on the ratio of drainage area was used to calculate the energy and power factors for the project site. If the drainage area of the project site was larger than the largest WSC drainage area, then the largest WSC gauge was used. If the drainage area of the site was smaller than the smallest WSC drainage area, the smallest WSC gauge was used. Since the incorrect area for the project site intake was being used, this methodology had not been implemented as planned.

In addition, there was an issue with correct weighting in cases where the project was bigger than the smallest WSC gauge, but smaller than the next gauge in a hydrologic region.

WSC proxy gauge assignment and weighting has been revised. Where revisions resulted in different gauge selections or weightings, this affected:

• annual costs (water rental rate is based on energy); • annual energy, dependable capacity, ELCC and firm energy; • monthly energy distribution; and • UEC, due to a change in annual energy.

Results of Assessment The study identified over 7,200 potential run-of-river hydroelectric sites in BC. These sites have a revised potential installed capacity of nearly 17,000 MW and annual energy of over 55,000 GWh/yr. KWL estimated the cost for each project, including costs for access and power lines to interconnect to the BC Hydro and Fortis BC grids. Table 3 provides the number of projects, energy, and capacity by price bundle.






Table 3: Total Run-of-River Hydro Potential in BC

Price Bundle Number of Projects

Average Annual Energy

(GWh/yr)

Annual Firm Energy

(GWh/yr)

Installed Capacity

(MW)

Effective Load-Carrying Capacity

(MW) 80 - 89 4 375 317 118 990 - 99 7 1065 870 311 53

100 - 109 7 968 798 247 30110 - 119 17 1474 1166 406 47120 - 129 19 1477 1083 404 55130 - 139 25 1381 1062 407 37140 - 149 21 1182 916 333 47150 - 159 24 1276 1050 359 49160 - 169 25 1242 988 353 42170 - 179 31 1215 977 362 33180 - 189 27 996 687 307 38190 - 199 44 1358 1030 414 58200 - 250 190 4816 3671 1487 167250 - 500 902 15187 11503 4727 570

500 - 1000 1159 8276 6079 2654 311>1000 4780 12892 8778 4017 390Total 7,282 55,180 40,978 16,906 1,936

A supply curve for run-of-river hydroelectric potential in BC is presented in Figure 1. Supply curves for the ten (10) major transmission regions in BC are presented in Figure 2.

The attached Map 1 of BC entitled Run-of-River Hydroelectric Potential in British Columbia 2013 Revision shows the location of the nearly 7,300 sites with associated size and estimated unit energy cost range.

Discussion of Results Given the large number of potential hydropower sites identified, there is considerable potential for future development of run-of-river hydroelectric projects in BC.

As this study involved identifying a complete inventory of potential run-of-river hydroelectric projects, the unit energy costs presented include both the most and least cost-effective projects. The assessment identified 11 projects estimated to have a unit energy cost under $100/MWh with approximately 430 MW of capacity and approximately 1,440 GWh/yr of average annual energy. Table 4 provides a breakdown of the projects with estimated unit energy costs under $100/MWh by major transmission region. Tables 5, 6 & 7 present a breakdown by project size and unit energy cost of total annual energy, capacity, and number of sites respectively.

Table 4: Run-of-River Hydro Potential in BC for Sites under $100/MWh1

Transmission Region Number of Projects

Average Annual Energy

(GWh/yr)

Annual Firm Energy

(GWh/yr)

Installed Capacity

(MW)

Effective Load-Carrying Capacity (MW)

Lower Mainland 7 553 404 164 28Vancouver Island 2 450 395 119 29Kelly Nicola 2 438 388 147 5Total 11 1441 1187 430 62Note: The cost is based on a 6% discount rate



5



Table 5: Energy by Project Size1

Price Bundle Annual Energy (GWh/year)

< 1 MW 1 to 30 MW > 30 MW Total

< $100/MWh 0 364 1,077 1,441 $100 to 149/MWh 0 3,514 2,968 6,482

> $150/MWh 5,348 38,405 3,504 47,257

Total 5,348 42,283 7,549 55,180 1 The cost is based on a 6% discount rate

Table 6: Capacity by Project Size1

Price Bundle Installed Capacity (MW)


< $100/MWh 0 99 330 429 $100 to 149/MWh 0 1,037 760 1,797

> $150/MWh 1,765 11,950 965 14,680

Total 1,765 13,087 2,055 16,906 1 The cost is based on a 6% discount rate

Table 7: Number of Sites by Project Size1

Price Bundle Number of Projects


< $100/MWh 0 6 5 11 $100 to 149/MWh 0 74 15 89

> $150/MWh 3,963 3,195 24 7,182

Total 3,963 3,275 44 7,282 1 The cost is based on a 6% discount rate

The unit energy cost (UEC) is greatly influenced by the remoteness of the site, where access and power lines can account for a significant portion of the capital cost. A supply curve with the UECs broken down by site infrastructure and access/transmission costs is presented in Figure 3.

Each site was treated as though it were developed in isolation of other projects. The study is an inventory level assessment and has not individually optimised the size of each plant. As such, the assumptions used to size, optimise and locate potential sites in this study may not provide the most economically viable site configuration or sizing.

More comprehensive site investigation, First Nations consultation, environmental and social assessments, hydrologic data collection and analysis, and concept development is required for developers to proceed with potential project applications prior to licensing, electricity purchase agreements, and construction.



KERR WOOD LEIDAL ASSOCIATES L TO.

Colleen O'Toole, P.Eng. Project Engineer

Reviewed by:

Ron Monl<, MEng, P.Eng. Energy & Mining Sector Leader

SFJ/cot/sl<

Encl.

St<.-lt~ment of- Umit<'ltion•

TECHNICAL MEMORANDUM Run or River Hydroelectric Resource Assessment for

British Columbia 2013 Revisions June 20, 2013

Stefan Joyce, P.Eng. Project Manager

This document has been prepared by l<err Wood Leidal Associates Ltd. (I<WL) for the exclusive use and benefit or the intended recipient. No other party is entitled to rely on any or the conclusions, data, opinions, or any other information contained in this document.

This document represents t<WL's best professional judgement based on the information available at the time of its completion and as appropriate for the project scope of work. Services performed in developing the content or this document have been conducted in a manner consistent with that level and skill ordinarily exercised by members of the engineering profession currently practising under similar condilions. No warranly, express or implied, is made.

Copy a ight NoticP

I

This work product (text, tables, and figures) is the property of BC Hydro. I<WL retains ownership of all Intellectual Property associated with the Rapid Hydro Assessment Model developed by I<WL.

t10vi<..:icm I th tory

Revision fJ Date Status Revision Author

0 June 18. 2013 Dr all SFJ/COT

1 June 20, 2013 Final Comments incorporated SFJ/COT

l __._K_·~-~-~~-· w_._.~_?_?_L_E_I_D_AL ASSOCIATES LTD.

6 \\l.lbra25.burnaby.kerrwoodleidal.org\0000·099910~00·0499\4 76-133\300·ReportslfloR_ Update _Final_ TechMemo _ 2013·06·20.docx



SKinoshita

Seal Disclaimer

7



Figure 1: Supply Curve for Run-of-River Potential in BC at 6% Discount Rate

0

50

100

150

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0 10,000 20,000 30,000 40,000 50,000

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Curve above $500/MWh not displayed in order to show detail at lower UECs






Figure 2: Run-of-River Potential Supply Curves by Transmission Region at 6% Discount Rate

0

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Curve above $500/MWhnot displayed in order to show detail at lower UECs



9



Figure 3: Supply Curve Breakdown for Run-of-River Potential in BC at 6% Discount Rate

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Supply Curve for Run-of-River Potential in BC at 6% Discount Rate

Average of UEC - At Gate ($/MWh) Average of UEC - Access/Powerline ($/MWh)







Figure 4: Average Site Category Cost Breakdown1

1 Does not include Annual Costs or IDC

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80

100

120

140

160

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Engineering

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Mobilization

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11



Figure 5: Average Site Category Cost Breakdown as a Per cent of Total2

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Figure 6: Monthly Energy Profiles – Small Hydro Potential by Transmission Interconnection Region

Figure 7: Supply Curve with Unit Energy Cost Sensitivity to Discount Rate

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Run-of-River Hydroelectric Potential in

British Columbia 2013 Update

June 2013

Map 1

KERR WOOD LEIDAL



Run-of-River Hydroelectric Resource Assessment for British Columbia

2010 Update

Final Report

March 2011



Run-of-River Hydroelectric Resource Assessment for British Columbia 2010 Update

Final Report March 2011

KWL File No. 478.103-300



BC HYDRO RUN-OF-RIVER HYDROELECTRIC RESOURCE ASSESSMENT FOR BRITISH COLUMBIA 2010 UPDATE FINAL REPORT – MARCH 2011 BC HYDRO & POWER AUTHORITY

KERR WOOD LEIDAL ASSOCIATES LTD. Consulting Engineers 478.103

BC Hydro. No other party is entitled to rely on any of the conclusions, data, opinions, or any other information contained in this document.

ional judgement based on the information available at the time of its completion and as e been conducted in

on currently practising

COPYRIGHT AND INTELLECTUAL PROPERTY NOTICE

T wor t, t nd f BC Hydro. KWL retains ow all Intellectual Property a ciate a dr l (RHAM) developed by KWL.

REVISION HISTORY

Revision # Date Status Revision Author

STATEMENT OF LIMITATIONS

This document was prepared by Kerr Wood Leidal Associates Ltd. (KWL) for the exclusive use and benefit of

This document represents KWL's professappropriate for the project scope of work. Services performed in developing the content of this document hava manner consistent with that level and skill ordinarily exercised by members of the engineering professiunder similar conditions. No warranty, express or implied, is made.

his k product (tex ables a figures) is the property o nership of sso d with the GIS R pid Hy opower Assessment Mode

A Dec 17, 2010 Draft Draft for BC Hydro Review SFJ

B March 21, 2011 Final Final for BC Hydro Review SFJ



KERR WOOD LEIDAL ASSOCIATES LTD. Consulting Engineers 478.103

CONTENTS

X ....................... I

. ...................1-1 ........................1-1

.2 ........................1-1

. ...................2-1 ........................2-1

2.2 ........................2-2 ........................2-2

.4 ........................2-4 ........................2-6 ........................2-8

SITE CAPACITY, DEPENDABLE CAPACITY AND FIRM ENERGY ...........................................................2-10 ......................2-13

......................2-13

......................2-13

......................2-13

3. ...................3-1 ........................3-1

3.1 ........................3-2 ........................3-2

3.2 ........................3-2 ........................3-2 ........................3-2 .......................3-3 ........................3-3 ........................3-3 ........................3-4 ........................3-4

.3 ........................3-6 3.4 3-7

........................3-7

4. RESULTS OF ASSESSMENT ..........................................................................4-1 4.1 POWER DEVELOPMENT POTENTIAL..................................................................................................4-1 4.2 POWER DEVELOPMENT POTENTIAL BY TRANSMISSION REGION.........................................................4-2 4.3 PROJECT COSTS AND UNIT ENERGY COSTS.....................................................................................4-3 4.4 CLOSING.........................................................................................................................................4-5

5. REPORT SUBMISSION....................................................................................5-1

E ECUTIVE SUMMARY ..........................................................................

1 INTRODUCTION............................................................................1.1 OBJECTIVES AND SCOPE.........................................................................................1 FIRST NATIONS AND STAKEHOLDER INPUT ...............................................................

2 ......................................2.1

POWER AND ENERGY ANALYSIS ........GIS RAPID HYDRO ASSESSMENT MODEL OVERVIEW................................................GEOGRAPHIC INFORMATION SYSTEM TERMINOLOGY.................................................

2.32 POTENTIAL HYDROPOWER PROJECT IDENTIFICATION METHODOLOGY .....................

GEOGRAPHIC INFORMATION SYSTEM DATA SOURCES ................................................

S SITE CREENING.....................................................................................................POWER PROJECT IDENTIFICATION ............................................................................

2.5 QUALITY CONTROL .................................................................................................MEAN ANNUAL DISCHARGE VALIDATION ...................................................................INTER-DRAINAGE FLOW ...........................................................................................TRANS-BOUNDARY FLOW ........................................................................................

COST AND ECONOMIC ANALYSIS .............................................GENERAL DESCRIPTION AND LIMITATIONS ................................................................M .... .....................ETHODOLOGY ... ...........................................................................DATA COLLECTION AND RESEARCH..........................................................................CAPITAL COSTS ......................................................................................................PENSTOCK ..............................................................................................................INTAKE AND POWERHOUSE CIVIL WORKS .................................................................GENERATION EQUIPMENT – TURBINE/GENERATOR AND ELECTRIC BALANCE OF PLANT

ROAD AND POWER LINE COST .................................................................................CONSTRUCTION CAMP AND TRANSPORTATION..........................................................ENGINEERING, ENVIRONMENTAL AND OTHER............................................................UNIT COST ESTIMATES ............................................................................................

3 ANNUAL COST ANALYSIS ........................................................................................LAND ALLOWANCE..........................................................................................................................

3.5 UNIT ENERGY COST ................................................................................................



RUN-OF-RIVER HYDROELECTRIC RESOURCE ASSESSMENT FOR BRITISH COLUMBIA 2010 UPDATE FINAL REPORT – MARCH 2011 BC HYDRO & POWER AUTHORITY

KERR WOOD LEIDAL ASSOCIATES LTD.

Consulting Engineers 478.103

FIGURES Figure E-1: Supply Curve for Run-of-River Potential in BC at 6% Discount Rate................................ v

nt Rate ......................................... vi unt Rate ......... vii

........................1-2

......................2-14

......................2-15

......................2-16

......................2-17

........................3-8

........................4-6

........................4-7 unt Rate.........4-8

Figure 4-4: Average Site Category Cost Breakdown............................................................................4-9 5: Average Site Cost Breakdown as a Percentage of Total................................................4-10 6: Monthly Energy Profiles – Small Hydro Potential by Transmission Region................4-11

......................4-12

........................... ii

.......................... iv

........................2-2

........................2-3

........................2-6

........................2-7

........................3-3

........................3-3 Table 3-3: Total Camp and Transportation Costs Including Mob/Demob ($) ....................................3-4

Allowances (% of Capital Cost) ...................................................................................3-4 ial in BC .....................................................................................4-1

ites under $100/MWh........................................4-3 .............................................................................4-3

.......................................4-3 Table 4-5: Number of Sites by Project Size...........................................................................................4-4

APPENDICES Appendix A: Hydrologic Gauge Data Appendix B: Roads & Power Lines Cost Estimation Using GIS Appendix C: Hydropower Potential by Transmission Region (Note: Appendices A, B & C are provided in a separate file on the BC Hydro Integrated Resource Plan website)

Figure E-2: Supply Curves by Transmission Region at 6% DiscouFigure E-3: Supply Curve Breakdown for Run-of-River Potential in BC at 6% DiscoMap E-1: Run-of-River Hydroelectric Potential in British Columbia 2010 Update (Note: Map E-1 is provided in a separate file on the BC Hydro Integrated Resource Plan website) Figure 1-1: BC Electricity Transmission and Distribution System .............................Figure 2-1: Topographic Surface of British Columbia .................................................Figure 2-2: Normal Annual Runoff Isolines and Surface .............................................Figure 2-3: WSC Gauge Locations and Hydrologic Zones ..........................................Figure 2-4: GIS Rapid Hydro Assessment Model Process Flowchart ........................Figure 3-1: Site Location Categories .............................................................................Figure 4-1: Supply Curve for Run-of-River Potential in BC at 6% Discount Rate .....Figure 4-2: Supply Curves by Transmission Region at 6% Discount Rate................Figure 4-3: Supply Curve Breakdown for Run-of-River Potential in BC at 6% Disco

Figure 4-Figure 4-Figure 4-7: Supply Curves with Unit Energy Cost Sensitivity to Discount Rate .......

TABLES Table E-1: Run-of-River Hydro Potential in BC.............................................................Table E-2: Run-of-River Hydro Potential in BC for Sites under $100/MWh................

.Table 2-1: GIS Terminology................ ............................................................................Table 2-2: Data Sources for Hydropower Assessment ................................................Table 2-3: Physical Boundary Conditions .....................................................................Table 2-4: Undevelopable Areas.....................................................................................Table 3-1: Turbine Selection ...........................................................................................Table 3-2: Turbine No. of Units Selection......................................................................

Table 3-4: CostTable 4-1: Run-of-River Hydro PotentTable 4-2: Run-of-River Hydro Potential in BC for S

....Table 4-3: Energy by Project Size .........................Table 4-4: Capacity by Project Size.................................................................



Executive Summary



EXECUTIVE SUMMARY

In 2007, BC Hydro commissioned Kerr Wood Leidal Associates Ltd. (KWLinventory of the run-of-river hy

) to conduct an droelectric potential in British Columbia. KWL completed the

d improved site an optimisation

e in gross power divided 00 m to 5,000 m. stream, which is length.

ated project size (capacity & energy) that is expected to what a developer might construct for that reach of stream. In

ore capacity and energy and often with lower unit electricity costs (UEC). ative of British

hydroelectric sites in BC. These sites have a potential installed capacity of over 17,400 MW and annual energy of nearly 63,000 GWh/yr. KWL estimated the cost for each project, including costs for access and power lines to interconnect to the BC Hydro and Fortis BC grids. Table E-1 provides the number of projects, energy, and capacity by price bundle. It also includes an estimation of the impacted area and job creation opportunities.

hydroelectric resource assessment using a Geographic Information System (GIS) Hydropower Assessment Model developed by KWL. This report provides an update on the 2007 study with a revised methodology anoptimisation process. Projects were identified for each stream reach throughroutine that determines the project penstock length by assessing the changby the change in length for each potential project location at penstock lengths of 5The optimised penstock distance routine selects the largest project on a given optimised to find the greatest change in gross power over the change in penstock The new methodology results in an estimprovide a closer representation of general it results in mThe 2010 methodology provides a new inventory that is more representColumbia’s run-of-river hydroelectric potential.

DISCUSSION OF UPDATES

The study identified over 7,200 potential run-of-river



ii KERR WOOD LEIDAL ASSOCIATES LTD.


Table E-1: Pote BC

Price dle

mbof

Projects

erann

Energy(GWh/y

En y (GWh/yr)

InCap

(MW

Dependable Generating

Capacity (MW)

Run-of-Riv

Nu

er Hydro

er AvA

ntial inge

ual

Annual

Firm Bun

r) erg

stalled ac yit

)

65 - 69 1 89 20 2 66 70 - 74 3 212 1 53 1 72 75 - 79 3 664 5 17 6 03 3 80 - 84 5 930 6 222 17 98 85 - 89 3 177 1 45 0 42 90 - 94 7 698 5 16 12 31 7 95 - 99 9 684 5 17 8 56 9

100 - 109 30 2,135 1,708 54 34 3 110 - 119 46 3,512 2,710 84 61 7 120 - 129 22 1,251 1,045 330 8 130 - 139 36 1,706 1,379 44 18 3 140 - 149 44 1,920 1,549 48 27 6 150 - 159 39 1,971 1 49 25 ,584 2 160 - 169 37 1,427 1 37 8 ,189 6 170 - 179 47 1,758 1 47 15 ,449 3 180 - 189 40 1,401 1,141 363 14 190 - 199 51 1,330 1,098 357 5 200 - 299 452 10,32 8,321 2,82 63 0 0 300 - 399 399 6,149 4,978 1,73 31 2 400 - 499 365 4,204 3 1,19 16 ,331 3 500 - 599 277 2,16 63 9 3 1,733 7 600 - 699 241 2,015 1,575 570 8 700 - 799 230 1,621 1,255 472 5 800 - 899 193 1,578 1,229 445 5 900 - 999 177 1,124 875 322 3

1000 + 4,525 11,816 9,075 3,645 16

Total 7,282 62,858 49,890 17,404 420

A supply curve for run-of-river hydroelectric potential in BC is presented in Figure E-1. Supply

E-2.

ritish Columbia 2010 Update shows the location of the nearly 7,300 sites with associated size and estimated unit

Methodology

The GIS Rapid Hydropower Assessment Model (RHAM) developed by KWL estimated in-stream power using topographic and hydrologic GIS data. The resulting output was over 10 million data points representing potential power plant points-of-diversion complete with flow,

curves for the ten (10) major transmission regions in BC are presented in Figure The attached Map E-11 of BC entitled Run-of-River Hydroelectric Potential in B

energy cost range.

1 Note: Map E-1 is provided in a separate file on the BC Hydro Integrated Resource Plan website.



KERR WOOD LEIDAL ASSOCIATES LTD. iii Consulting Engineers 478.103

head and power estimations. This data was then screened for physical paramrun-of-river power development, and areas considered undevelopable such as areas, salmon streams and existing project locations. The aforementioned 7,300 projects were

eters suitable for legally protected

identified using an optimisation process based on power output relative to the infrastructure

roduction. This nd used

GIS capabilities to distribute the resulting statistics to the proposed project locations. Annual on flow duration ischarge.

ocation were used to estimate an approximate cost to develop each project. This was accomplished through the

civil works) that s and power line

Unit energy cost (UEC) was determined based on available estimated energy production and uming a 40-year

6%. A discount rate of 8% was also considered ivity analysis. Other annual costs included property taxes, water rental,

maintenance.

level unit energy costs may not reflect what an independent power producer may lectricity to BC Hydro due to factors such as:

tial hydropower sites identified, there is considerable potential for future development of run-of-river hydroelectric projects in BC. As this study involved identifying a complete inventory of potential run-of-river hydroelectric projects, the unit energy costs presented include both the most and least cost-effective projects. The assessment identified 31 projects estimated to have a unit energy cost under $100/MWh with approximately 900 MW of capacity and approximately 3,500 GWh/yr of average annual energy. Table E-2 below provides a breakdown of the projects with estimated unit energy costs under $100/MWh by major transmission region.

required. Regional hydrology analysis was carried out to develop an estimate of energy pexercise involved statistical analysis of Water Survey of Canada (WSC) hydrologic data, a

energy production, ‘firm energy’ and ‘dependable capacity’, were estimated basedcurves. Minimum flow releases for fish were assumed to be 15% of mean annual d Upon identifying potential project sites, the physical characteristics and project l

development and utilization of cost curves for project components (e.g., turbine, were based on actual projects developed in British Columbia. Each site had accescosts estimated as if it were constructed in isolation of other projects.

annual capital and operating costs. Annual capital costs were calculated assamortization period, with a real discount rate offor comparison in a sensit

tions and and plant opera The planningoffer to sell e Site-specific considerations; Cost of capital; Contract terms; Taxation; and Other factors.

DISCUSSION OF RESULTS

Given the large number of poten



iv KERR WOOD LEIDAL ASSOCIATES LTD.


Table E-2: Run-of-Ri o P in B te 10

ion Region um

of Projec

AvAnnua

(GWh

rgy h/yr)

C ty

(MW)


Capacity (MW)

ver Hydr

N

otential

ber

C for Si

erage l E gy

s under $Annual

Firm

0/MWh

In edTransmiss

ts ner/yr)

Ene(GW

stallap cia

East Kootenay 3 25 6 0 5 23 76Kelly Nicola 6 87 58 8 8 3 6 22Lower Mainland 17 1,3 25 16 28 1,0 323North Coast 2 15 4 0 3 12 40Revelstoke/Ashton Creek 1 67 51 17 1 Vancouver Island 2 778 573 175 21

Total 31 3,455 2,668 858 47

The unit energy cost (UEC) is greatly influenced by the remoteness of the site, wpower lines can account for a significant portion of the capital cost. A supply curvbroken down by site infrastructure and access/transmission costs is presented in Fi

here access and e with the UECs gure E-3.

The study is an plant. As such, y not provide the

le site configuration or sizing. More comprehensive site investigation, First Nations consultation, environmental and social assessments, hydrologic data collection and analysis, and concept development is required for developers to proceed with potential project applications prior to licensing, electricity purchase agreements, and construction.

Each site was treated as though it were developed in isolation of other projects. inventory level assessment and has not individually optimised the size of eachthe assumptions used to size, optimise and locate potential sites in this study mamost economically viab



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Section 1

Introduction



1.

WL) to conduct tish Columbia. In August 2010,

onnection to the

pportunities for

in BC have identified many potential hydroelectric projects in the study area, these past of-river projects. -of-river power

07 KWL Study were completed using a Geographical Information

L, which .

The primary project objectives of the update to the 2007 GIS based inventory of run-of-

considered undevelopable such as legally protected areas, reaches of streams that are ations.

Development of a new run-of-river hydropower inventory for BC using a developed by KWL, since 2007, that

more closely compares with hydroelectric projects that are presently being proposed

Develop inventory-level cost estimates for run-of-river hydro by transmission region based on updated cost data in January 1, 2011 dollars.

1.2 FIRST NATIONS AND STAKEHOLDER INPUT

KWL gratefully acknowledges the input of First Nations and stakeholders from meetings held by BC Hydro on September 14 and 20, 2010.

INTRODUCTION In 2007, BC Hydro commissioned Kerr Wood Leidal Associates Ltd. (Kan inventory of run-of-river hydroelectric potential in BriBC Hydro engaged KWL to conduct an update to the 2007 study with a revised methodology, updated costing, and improved site optimisation process. Figure 1-1 shows BC Hydro’s transmission and distribution system. Cexisting integrated power system was included in the assessment. The geography and precipitation of British Columbia provides many ohydroelectric development. While previous studies of run-of-river hydroelectric potential

studies focused on areas near existing power lines and on small run-This study includes a complete assessment of all potential rundevelopment in the province.

This study and the 20System (GIS) Rapid Hydro Assessment Model (RHAM) developed by KWenabled a more comprehensive study of the hydroelectric potential in BC

1.1 OBJECTIVES AND SCOPE

river hydroelectric potential for BC include: An update to the areas and reaches of streams excluded from the analysis that are

used by salmon, glacier areas, and existing and committed project loc

revised/improved optimisation methodology

and developed in BC.



I l ~ ! l

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PACIFIC

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OCEAN

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Assessment for British Columbia 2010 Update

Legend

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- - - • Planned NTt. Une

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478-103

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Section 2

Power and Energy Analysis



2.

r the province of British Columbia. This was made possible through improved GIS technology and data, and the

generate power. eir, dam or low

t of diversion) to direct a portion of the stream flow into a penstock that conveys flow to a powerhouse. A turbine and generator in the

electricity, and the diverted water is

2.1

S-based tool referred to as the Rapid Hydro Assessment Model or ements in GIS

as well as increased availability of high-quality topographic and hydrologic aintaining a

parameters for

sizing potential

cts;

n and potential

ng frictional or

Once these parameters were estimated, project components were sized, frictional losses were estimated and the resulting ‘net’ power was calculated. This information was then used to estimate available hydroelectric capacity and approximate capital costs. In addition to estimating hydropower potential, GIS capabilities have been used in preparing estimates of capital costs for items such as access roads and power lines (see Section 3: Cost and Economic Analysis).

POWER AND ENERGY ANALYSIS KWL estimated the run-of-river hydroelectric potential fo

recent assessment tools developed by KWL. Run-of-river facilities use the unregulated flow of rivers or creeks to This type of hydroelectric project can be constructed with a small wdiversion structure (intake or poin

powerhouse convert the potential energy into returned to the stream via a tailrace channel.

GIS RAPID HYDRO ASSESSMENT MODEL OVERVIEW

KWL developed a GIRHAM for estimating run-of-river power potential. With improvtechnology, data, it is possible to assess power potential on a widespread basis, while mrelatively high level of detail. The tool developed by KWL is capable of determining three key power generation:

Stream Flow and Distribution: used to select a design flow for power proje

Static Head: the vertical distance between the point-of-diversio

powerhouse locations; and Power: product of head, flow and fluid density, not includi

generation losses.



Regional hydrology analysis was carried out to develop an estimate of enThis involved statistical analysis of Water Survey of Canada (WSC) hyduse of GIS capabilities to distribute the resulting statistics to the p

ergy production. rologic data, and otential project

locations. Annual energy production, ‘firm energy’ and ‘dependable capacity’, were

er ArcGIS 10) software with the Spatial Analyst extension, which is available from ESRI Canada. This software is widely

g GIS applications.

2.2 YSTEM TERMINOLOGY

is docum erms and abbreviations commonly u

e 2-1: G

S ases with

nalysis.

estimated based on flow duration curves. The model was developed using ArcGIS 9.2 (and lat

recognized as the industry standard for engineerin

GEOGRAPHIC INFORMATION S

Th ent refers to GIS-specific terminology. Some of the tsed in this report are as follows:

Tabl IS Terminology

GGI

eographic Information Systems – a tool that merges databspatial references, and provides tools for mapping and a

DEM Digital Elevation Model – a continuous representation of the Earth’s

r networks. surface using spot elevations, uniform grids of cells, or triangula

Vector sent entities as points, lines or

polygons. A data model for discrete objects; can repre

Raster A data model for continuoattribute to form a ‘surface’.

us data; uses uniform grids of cells with a single

Geoprocessing Automated tools for analyzing relationships between or within datasets.

NTS National Topographic System – a gridded reference systemProvincial and Federal governments for mapping products.

used by

2.3

The primary data sources used in this assessment were acquired through public data warehouses available through the Internet. These websites include the Land Resource Data Warehouse (lrdw.ca) operated by the Integrated Land Management Bureau (Province of BC), Geobase (geobase.ca) and Geogratis (geogratis.ca), operated by Natural Resources Canada (NRCan). BC Hydro & Fortis BC Data transmission and distribution system data were also utilized on this project. Table 2-2 describes the publicly available datasets used in the assessment.

GEOGRAPHIC INFORMATION SYSTEM DATA SOURCES



Ta Data So ydr sment

AccSour scription

ble 2-2: u Hrces for opower Asses

Dataset Data Type/

uracy ce/Author De

Canadian DigitaEle

lvation Data (C

1ti

uous representation of

DED)

DEM/resolu

:250K Geobas

on e

Continsurface relief.

Normal Annual RIsolines

/ur inte

Onual depth of unoff Vector

conto500 mm

LRDW/rval

bedkoff et al.Normal anrunoff.

BC Watershed Atlas Vector/1:20K mappi

DW/We nch

phic reference for mapped hydrologic features.

based on ng

LRManag

ater ment Bra

Topogra

HYDAT Data 2005 TabularWater SCanada (WSC)

data recorded and hived by WSC for all of

Canada.

urvey Daily flow arc

Hydrologic Zones Vector/1:2M et al. similar AreLRDW/Obedkoff 29 Regions of hydrologically

as in BC.

Canadian Digital Elevation Data (CDED)

The CDED DEM is supplied in tiles based on the NTS 1:250K grid system. Each tile is x 100 km in size, with a ‘pixel’ size of approximately 93 m. The

DEM is corrected for hydrology, which means that elevations have been adjusted such stream direction.

The Normal Annual Runoff Isolines data were developed as a part of the 1998 British ntinuous surface ows the normal

BC Watershed Atlas

d is widely used tures. The key

mapped streamlines, bodies of water and watershed . This dataset provides topographic names for associating the power model

results to known features.

a Gwaii may be here no isolines

were available. This may affect a small number of sites as a large portion of this area is also park and not considered developable.

Hydrologic Data

Water Survey of Canada (WSC) records and archives historic hydrometric flow data for Canada. Daily WSC flow data, geographic locations, and gauge characteristics are available online and can be downloaded (HYDAT 2005). The historical daily data to 2005 for all the WSC gauges in BC were used for the purposes of this study.

approximately 100 km

that cells occurring along known hydrologic features ‘flow’ in the downFigure 2-1 shows a topographic map of BC using the CDED DEM.

Normal Annual Runoff Isolines

Columbia Streamflow Inventory. The isolines were interpolated to a coand combined with the DEM for estimating streamflows. Figure 2-2 shannual runoff for BC.

The BC Watershed Atlas has been in existence for a number of years, anas a topographic reference for named and unnamed hydrologic feacomponents of this dataset are boundaries

Streamflow on the far western portion of Vancouver Island and the Haidslightly underestimated due to a boundary effect in the runoff surface w



Hydrologic Zones

A hydrologic zone is defined as an area where, theoretically, hydrologare similar. Data collected in each hydrologic zone can there

ic characteristics fore be extrapolated to

estimate characteristics at ungauged sites with a reasonable degree of accuracy. For this teristics.

he 1998 British Columbia Streamflow Inventory. Subsequent work by Obedkoff between 1998 and 2003

e in tal hydrologic zones to 29. C hydrometric stations.

2.4 OLOGY

am hydropower ocations. Given e for identifying

ort economically viable projects, and comparing relative suitability between proposed project locations. Although a planning level

elopment purposes optimal watershed should be confirmed as part of a more detailed

nted in this study is intended to

d in assessing hydropower potential. These include:

er; y technically feasible project locations;

ntifying suitable projects within a watershed; Sizing of project components such as penstock, powerhouse and power lines;

r; and

ps are described below. Figure 2-4 describes the model conceptually.

GROSS HYDROPOWER POTENTIAL

Two parameters flow (Q) and head (H), are required for determining in-stream power potential. In-stream power is the product of head, flow and fluid weight, as described by the following equation:

project, hydrologic zones are used to estimate regional streamflow charac Hydrologic zones in BC were defined by Coulson and Obedkoff in t

updated th formation in each region, and increased the toFigure 2-3 shows these hydrologic zones and their constituent WS

POTENTIAL HYDROPOWER PROJECT IDENTIFICATION METHOD

This section describes the steps involved in estimating available in-strepotential and in identifying potential run-of-river hydropower project lthe wide coverage and coarse source data, the results are most appropriatapproximate locations that could supp

optimisation process has been applied in this study, for devlocations within a given watershed-specific assessment. The methodology preseidentify streams that warrant further investigation. Several steps are involve Estimation of in-stream pow General screening to identif An optimisation routine for ide

Estimation of net powe Estimation of energy production.

Each of these ste



Pgross = γwQHs

ower (kW)

Q = flow (m3/s)

Hs = static head from intake to powerhouse (m)

GIS tools as an available at a site (a design flow factor was later

appli the area upstream of n combined with

Discharge

re validated against hydrological statistics from Water Survey of Canada stream flow gauges (see Section 2.5 – Quality Control).

endently of any e model do not

ArcGIS. These t and return the

minimum elevation, which was assigned back to the search location. The search was

nventory. Some nd constructed with

updates should .

in a neighbouring watershed, an algorithm was developed. This was completed using the smallest watershed division, as defined in the BC Watershed Atlas, and by combining a unique identifier for each watershed with the data returned from the statistical function. Static head was estimated by subtracting the minimum elevation returned by the search algorithm from the elevation of the current DEM cell for each iteration. The end result was a series of rasters of potential static head at various search distances. The search distance then formed the basis for estimating the penstock length at a given location.

where,

Pgross = in-stream p

γw = 9.81 kN/m3 (constant)

Flow

Mean annual discharge (MAD) at any given site can be estimated usinginitial estimation for the average flow

ed). These GIS tools were applied to the DEM to calculateeach cell within a raster. The resulting area accumulation raster was thethe runoff surface to estimate mean annual runoff:

Area Accumulation x Mean Annual Runoff Depth = Mean Annual

Mean annual discharges we

The above procedure identifies stream locations implicitly, and indepexisting stream mapping. For this reason, streamlines generated by thalways align with mapped streams.

Head

Head is estimated by using spatial statistics functions that are included infunctions were configured to perform a search around a given poin

conducted radially in 500 m increments, from 500 m to 5,000 m. The raw topographic head dataset from 2007 was utilized for the 2010 irun-of-river hydroelectric projects are now being designed apenstocks in excess of 5,000 m long. Future run-of-river inventoryconsider the application of penstock lengths that are longer than 5,000 m To prevent the search from identifying a minimum elevation



In-Stream Power Potential

As shown above in the in-stream power equation, head was multiplied bweight to yield in-stream power. ArcGIS was used to multiply the head and fthereby producing a raster of in-stream power. The power rasters were tvector datasets of points representing potential power project locatiodataset was a

y flow and fluid low rasters,

hen converted to ns. The vector

ble to store all of the information at each location, including head, flow and g approximately

Because in-stream power potential was based on MAD, the in-stream power output e average power potential available within a typical year. Project locations

analysis represent the point-of-diversion.

Given the large siz ial power model output, the next step was to identify sites are technically le for development. Table 2-3 describes the physical

istics used criteria.

ysical B

Parameter Valid Range

instream power. This resulted in the production of a dataset containin10 million points.

represents thspecified in this

SITE SCREENING

Boundary Conditions

e of the initthat feasibcharacter as screening Table 2-3: Ph oundary Conditions

Slope > 4% Mean Annual Discharge

0.1 – 200 m3/s

Static Head 30 – 1,000 m In-Stream Power > 100 kW

In general, the minimum flow, head and power conditions represent pgenerating grid connected small hydropower from an economic smaximum flow condition essentially establishes a limit for medium-sizedThe maximum head condition represents a maximum practicable prepenstocks a

ractical limits to tandpoint. The hydro facilities. ssure rating for

nd generating units.

Exclusion Areas

In some areas, it was assumed that a power project could not be built. These areas were masked in GIS and intersected with the power model output to extract only those points that were considered suitable locations for developing power. Table 2-4 summarizes the type of features included in the mask, the source of the data, and the process used to create the mask.



Table 2-4: Undevelopable Areas

ture u Process Fea So rce

Salmon Species Presence Province of British No projects within 100 m

usion area Columbia, Ge)

oBC, LRDW of excl(FISS

Biodiversity Areas Province of BColumbia, GeoBC, ILMB

cts within 100 m of exclusion area

ritish No proje

Wildlife Management Areas areas for which administracontrol has been transferreMinistry of Environment (M

tion and d to the oE) via the

to the significan

ent

Province of British Columbia, GeoBC, LRDW

No projects within 100 m of exclusion area

Land Act due ce of their wildlife/fish values and designated as Wildlife ManagemAreas under the Wildlife Act Conservancy Areas

cy areas deconservanthe Park

signateAct or by the Protect

opme Act

Province of British bia, Ge

No projects within 100 m usion area d under

ed Colum

Areas of British Columbia Act devel

, whose management and nt is constrained by the Park

oBC, LRDW of excl

National Parks Province of British Columbia, GeoBC, LRDW

No projects within 100 m of exclusion area

Energy Purchase Agreement/ Existing BC Hydro Facilities

, MO jects within 500 m ting projects

s (EPAs) BC Hydro E Water No proLicenses of exis

Legally Protected Areas cal Reserves, Protecte

s, Provincial Parks, RecrAreas

of Bbia, Ge

jects within 100 m usion area Ecologi

Aread

eation ColumProvince ritish No pro

oBC, LRDW of excl

Canadian Forces Bases CFB Esquimalt (Navy) CFB Comox (Air Force)

No projeof exclu

cts within 100 m sion area

Migratory Bird Sanctuaries Environment Canada No projects within 100 m

of exclusion area

Glaciers Columbia, GeoBC, CWB of excluProvince of British No projects within 100 m

sion area

Provincial and National Parks and protected areas are not suitable for construction of power projects, access roads or transmission lines. Stream reaches containing salmon resources are unlikely to be approved for water licenses without significant mitigation and protection measures, and have also been excluded. In areas where projects or Electricity Purchase Agreements (EPAs) exist, no new projects in the watershed within a distance of 500 m were permitted.



POWER PROJECT IDENTIFICATION

After screening out locations in undevelopable areas, a large quantitdevelopable sites remained. An optimisation routine was developmanageable inventory of projects tha

y of potentially ed to create a

t could be developed independently, and without ocations, project

The 2010 update included the application of new optimisation methodology developed by es with hydroelectric projects that are presently being

imisation and selection methodology of the 2007 KWL study found the t drop for a

rby, the larger of MAD) was used

tifying potential ectiveness of the

a location since many rtion of the total t drop in a reach

at is greater than the MAD. The new optimisation and esigned to align

of the stream,

size (length of nd a higher design flow. It selects the largest project on a

stream reach and also includes nearby steep channel sections and nearby steep drops within the total length of the penstock. In addition to this, a larger design flow of 150% of MAD was used. Conflicts between potential projects were resolved by creating buffers around projects using the optimised penstock distance. The smaller of the conflicting projects was removed from the project inventory. After completing the optimisation process, a total of 7,282 potential sites were identified.

encroachment upon each other. After identifying potentially optimal lcomponents were sized and net power estimated.

KWL that more closely comparproposed and developed in BC.

Optimisation Routine & Design Flow Factor

The site optgreatest power per unit length of penstock. This effectively finds the steepesgiven reach of stream. As an example, if there are two steep drops neathe two will generally be selected. In 2007 the mean annual discharge (as the design flow. The methodology from the 2007 work was a reasonable indicator for idensites, but often developers design a larger project to optimise the cost effproject and extract as much capacity and energy as they can fromcapital costs are less sensitive to the size of the project and are a large pocost. This generally results in a project that extends beyond the steepesof the stream and a design flow thsite selection methodology used for the 2010 run-of-river update was dmore closely with what a developer might construct. Both the 2007 and 2010 methodology consider the steepest sectionhowever the 2010 methodology generally selects larger projects with the steepest section encompassed by the larger potential project The 2010 optimisation results in both a change to the project layoutdiverted stream and head) agiven stream which is optimised to find the greatest change in gross power over the change in penstock length. This effectively finds the steepest drop of a



Penstock Design Criteria

To estimate costs and potential power generation, the size and length of the water conduit

, with a maximum slope of 75%;

based on static

% of static head inimum overall

ent.

nominal penstock diameter assumed was 5 m (198 in.). Inside pipe nduits have been

e potential design flows exceed the capacity of the largest penstock diameter.

Net Pow

After sizing the penstock, the net available power was calculated according to the followin

MAD

Hs = static head from intake to powerhouse (m) Hf = frictional headloss (m) η = power plant efficiency at design flow, assume 0.85

After allowing for frictional and power plant losses and including the 1.5 times MAD design flow factor, the design plant capacities of the identified projects ranged from 0.1 MW to 98 MW, with the output power efficiency ranging from 75% to 84% of the in-stream power.

was determined as per the following criteria:

Penstock Slope: static head over search distance Penstock Length: length obtained from optimisation routine;

Penstock Material: steel, either (250 psi) or (600 psi) pressure ratinghead, Hazen Williams C-factor of 120; and

Penstock Sizing: allow maximum friction loss through conduit of 20

using Hazen-Williams relationship or as required to maintain a mpower efficiency of 75%, with a 10% length allowance for adjustments to alignm

The maximumdiameters were used to estimate friction losses. In some cases, parallel cospecified wher

er Calculation

g ation: equ

P = γ F Q (Hs - Hf)η net w Design MAD

where: Pnet = design plant capacity (kW) γw = 9.81 kN/m3 (constant) FDesign = Design Flow Factor (1.5 used for this study) Q = mean annual discharge (m3/s)



SITE CAPACITY, DEPENDABLE CAPACITY AND FIRM ENERGY

The variability or distribution of flow, and hence power generation, wahistorical daily flow data. With this information, the annual energy normal year (annual energy), ann

s estimated from production for a

ual energy production for a low flow year (firm energy), and periods (dependable capacity)

are provided below:

ted annually on ic record;

he total quantity of energy that could be generated during the lowest flow water year (October to September) on record;

m power that can be generated at the site, equal to the

generated 85% of the time in January

he MAD.

tabase

cords were tial project sites

piled and subdivided into the 29 hydrologic zones identified by Obedkoff.

as follows:

/reservoirs) were removed as they do not represent natural flow conditions and would not be representative for a run-of-river site;

Years with greater than one month of missing data were excluded from each

hydrometric record to avoid biasing annual and seasonal statistics; and Hydrometric records with less than 10 years of data (after partial years removed)

were excluded.

and the power that can be relied upon during high demcan be estimated for potential project sites. Some definitions referred to in this section

Annual Energy: the total quantity of energy that could be generaaverage for the entire period of hydrolog

Firm Energy: t

Installed Capacity: the maximu

design plant capacity; Dependable Capacity: the power that could be

and December peak demand period; and Minimum Flow Releases for Fish: these were assumed to be 15% of t

Assembling WSC Gauges into a Regional Stream Flow Da

For the purposes of this assessment, Water Survey of Canada (WSC) reassumed to provide reasonable flow distribution characteristics for potenwithin the same hydrologic zone. The available WSC records were com

Once compiled, WSC gauge records for BC were screened Regulated hydrometric stations (i.e., stations downstream of dams



Following the screening process, a list of WSC gauges was compileavailability of screened gauge data for each hydrologic zone. Some hwere found to have limited WSC data. In Hydrologic Zone 5, a discont

d to assess the ydrologic zones

inued gauge with only 9 years of data was included to improve representation of small drainage areas. A

x A.

eal. The gauge

with small drainage areas. For example, in Hydrologic Zone 27 the majority of gauges rologic Zone 10

e variability across each zone is still expected. Estimates of flow distribution for potential hydro sites

stribution characteristics of sub-regions with a effect will depend on the degree of

hydrologic variability within the defined hydrologic zone.

a flow duration

Capacity Factor was calculated based on this flow duration curve and represents the erating at design

e manner as the annual energy capacity factors, but with the data sorted by month.

w duration curve annual runoff on

1. A Firm Energy Capacity Factor was the Firm Energy ll times.

The Dependable Capacity Factor was calculated based on the power that could be produced at the flow that is exceeded 85% of the time in January and December peak demand period over the entire set of daily data. Fisheries flows were subtracted prior to the power calculation.

The Effective Load Carrying Capability (ELCC) was calculated as the capacity (MW)

based on 60% of the average energy of December & January divided by the number of hours in the period.

summary table for the gauges by hydrologic zone is provided in Appendi The geographical distribution of WSC gauges in some zones is not iddensity tends to be lower in remote or sparsely populated areas, particularly for gauges

are concentrated in the southern portion, while most of the gauges in Hydare in the eastern portion. Although hydrologic zones are defined to be relatively homogeneous, som

may therefore be biased toward the flow dihigher density of gauges. The strength of this

Estimating Power and Energy Factors for WSC Gauges

Energy factors were calculated for each WSC gauge as follows: The Annual Energy Capacity Factor was calculated by preparing

curve with daily data (less fisheries flows) for the data set. An Annual Energy

ratio of the annual energy production to the energy if a site were opcapacity at all times.

The Monthly Energy Capacity Factors were calculated in the sam

The Firm Energy Capacity Factor was calculated by preparing a flo

using the daily data (less Fisheries Flows) for the year with the lowestrecord for a water year starting October calculated based on this flow duration curve and represents the ratio ofproduction to the energy if a site were operating at design capacity at a



The impact of reduced turbine efficiency at low flows on energy factorfor by assuming no operation at less than a set turbine shut off flow whthe turbine type and number of turbines (see Section 3.2). For sites with low flows

s was accounted ich depended on

during the months of December and January, this often resulted in a Dependable Capacity

ded in Appendix A.

ied by Obedkoff.

ilar in drainage ach site was associated with at least one WSC gauge in the

same hydrologic zone. This was done by identifying WSC gauges with the next larger project site). A te the energy and

ainage area, then smaller than the

er project are a s that affect the

d distribution of the flow. storage and attenuation can include (but are

lope and ground difficult to fully

the potential SC gauges with ite.

Regional factors can also affect variability and distribution of the flow. The amount and form of precipitation at a given site may be strongly influenced by physical factors such as latitude, distance from the coast, and dominant regional climate processes such as large-scale orographic (i.e., elevation of land) uplift. As described above, the annual runoff isolines were used to develop site-specific estimates of mean annual discharge. Flow characteristics were assigned based on WSC gauges located in the same hydrologic zone. This process incorporates a significant amount of the larger-scale regional variability into the results.

Factor of zero. A table with factors for the WSC gauges by hydrologic zone is provi

Estimating Power and Energy Factors for Potential Hydropower Sites

Potential project sites were grouped into the 29 hydrologic zones identifPower and energy factors (Annual Energy, Firm Energy, and Dependable Capacity) for each potential project were estimated from WSC records for gauges simarea to that project site. E

and next smaller drainage area (as compared to the drainage area of theweighted average based on the ratio of drainage area was used to calculapower factors for the project site. If the drainage area of the project site was larger than the largest WSC drthe largest WSC gauge was used. If the drainage area of the site was smallest WSC drainage area, the smallest WSC gauge was used.

Flow Distribution and Seasonal Variability

Energy production and dependable capacity for a run-of-river hydropowfunction of the variability and distribution of the flow. The factordistribution and timing of the runoff for a watershed are complex. Watershed storage and attenuation can affect variability anWatershed characteristics that provide runoff not limited to) lakes and groundwater storage, large drainage area, scover. Snow and glaciers also strongly affect the timing of runoff. It isaccount for storage and attenuation given the limits of the historical WSC records and the inventory-level nature of this resource assessment. Nonetheless, some ofvariability in watershed storage and attenuation is reflected by using Wsimilar drainage areas to predict stream flow variability for each project s



In general, using area and hydrologic zone to attribute flow distribureasonable approximation but does not provide a complete picture of sdistribution and seasonal variability. Individual sites require a more in-depth reg

tion provides a ite-specific flow

ional analysis as well as local in-stream hydrometric data collection as part of site feasibility

ent.

2.5

e locations was the model.

The values f om e directly compared to the values from the gauge and a as developed. It was found that on average the model estimates were

R2 value of 0.97

l throughout BC, ge flow existed.

ndaries (inter-drainage flow) generally occurred in areas of flat terrain, especially in areas with many interconnected lakes, which results in the modelling

le to determine which direction the water flows.

mprove drainage at no

In the case of watersheds that have flows that originate outside the provincial boundaries, flow contribution from outside of British Columbia, was not accounted for. This does not affect watersheds that originate in British Columbia and subsequently flow outside the provincial boundary. This was considered acceptable for this inventory level as this represents a relatively very small portion of the Province’s watersheds by area and it would tend to underestimate the flow in those locations and result in a conservative power estimate.

assessment and developm

QUALITY CONTROL

MEAN ANNUAL DISCHARGE VALIDATION

The mean annual discharge estimated by the model at WSC gaugcompared to the observed mean annual discharge to assess the validity of

r the model werlinear trend line w2% less than the observed mean annual discharge. The trend line had awhich is a very good fit.

INTER-DRAINAGE FLOW

Once the model produced an initial estimate of in-stream power potentiaa quality control measure was taken to check that no major inter-drainaFlows across drainage bou

process not being ab These areas were identified and corrected by changing the DEM to idefinition within the modelling process. The DEM was changed in such a way thexcess power would be estimated.

TRANS-BOUNDARY FLOW



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Digital Elevation Model (IN)

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Project No.

478-103 Date

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Hydrology (IN)

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·~------------------_, ........ ,. ... MAI-..o'-Oet""'Ooc

Dependable Capacity Average and Firm Energy (OUT)

Run-of-River Hydroelectric Resource Assessment for British Columbia 2010 Update

GIS Rapid Hydro Assessment

Model Process Flowchart

BChydro m

Figure 2-4



RUN-OF-RIVER HYDROELECTRIC RESOURCE ASSESSMENT FOR BRITISH COLUMBIA 2010 UPDATE FINAL REPORT – MARCH 2011 BC HYDRO & POWER AUTHORITY



FIGURES Figure E-1: Supply Curve for Run-of-River Potential in BC at 6% Discount Rate................................ v

nt Rate ......................................... vi unt Rate ......... vii

........................1-2

......................2-14

......................2-15

......................2-16

......................2-17

........................3-8

........................4-6

........................4-7 unt Rate.........4-8

Figure 4-4: Average Site Category Cost Breakdown............................................................................4-9 5: Average Site Cost Breakdown as a Percentage of Total................................................4-10 6: Monthly Energy Profiles – Small Hydro Potential by Transmission Region................4-11

......................4-12

........................... ii

.......................... iv

........................2-2

........................2-3

........................2-6

........................2-7

........................3-3

........................3-3 Table 3-3: Total Camp and Transportation Costs Including Mob/Demob ($) ....................................3-4

Allowances (% of Capital Cost) ...................................................................................3-4 ial in BC .....................................................................................4-1

ites under $100/MWh........................................4-3 .............................................................................4-3

.......................................4-3 Table 4-5: Number of Sites by Project Size...........................................................................................4-4

APPENDICES Appendix A: Hydrologic Gauge Data Appendix B: Roads & Power Lines Cost Estimation Using GIS Appendix C: Hydropower Potential by Transmission Region (Note: Appendices A, B & C are provided in a separate file on the BC Hydro Integrated Resource Plan website)

Figure E-2: Supply Curves by Transmission Region at 6% DiscouFigure E-3: Supply Curve Breakdown for Run-of-River Potential in BC at 6% DiscoMap E-1: Run-of-River Hydroelectric Potential in British Columbia 2010 Update (Note: Map E-1 is provided in a separate file on the BC Hydro Integrated Resource Plan website) Figure 1-1: BC Electricity Transmission and Distribution System .............................Figure 2-1: Topographic Surface of British Columbia .................................................Figure 2-2: Normal Annual Runoff Isolines and Surface .............................................Figure 2-3: WSC Gauge Locations and Hydrologic Zones ..........................................Figure 2-4: GIS Rapid Hydro Assessment Model Process Flowchart ........................Figure 3-1: Site Location Categories .............................................................................Figure 4-1: Supply Curve for Run-of-River Potential in BC at 6% Discount Rate .....Figure 4-2: Supply Curves by Transmission Region at 6% Discount Rate................Figure 4-3: Supply Curve Breakdown for Run-of-River Potential in BC at 6% Disco

Figure 4-Figure 4-Figure 4-7: Supply Curves with Unit Energy Cost Sensitivity to Discount Rate .......

TABLES Table E-1: Run-of-River Hydro Potential in BC.............................................................Table E-2: Run-of-River Hydro Potential in BC for Sites under $100/MWh................

.Table 2-1: GIS Terminology................ ............................................................................Table 2-2: Data Sources for Hydropower Assessment ................................................Table 2-3: Physical Boundary Conditions .....................................................................Table 2-4: Undevelopable Areas.....................................................................................Table 3-1: Turbine Selection ...........................................................................................Table 3-2: Turbine No. of Units Selection......................................................................

Table 3-4: CostTable 4-1: Run-of-River Hydro PotentTable 4-2: Run-of-River Hydro Potential in BC for S

....Table 4-3: Energy by Project Size .........................Table 4-4: Capacity by Project Size.................................................................



3.

apital and annual dy area. Since this assessment is an inventory level

intended to provide the magnitude of costs

DESCRIPTION AND LIMITATIONS

stimates prepared for potential hydropower projects are of an

uming steel pipe);

ouse, based on design flow of project (assumes pre-engineered building);

turbine, generator and electric balance of plant ad and power output;

n to existing grid;

p (if required);

Allowance for engineering: 15%;

and insurance: 2%;

llowance: 5%; and

Interest during construction. The cost estimates do not include the following site-specific considerations (not exhaustive): Geotechnical allowances; Market shortages of labour and/or materials; and Delays due to difficult construction conditions, terrain or weather.

COST AND ECONOMIC ANALYSIS The following sections outline the assumptions and process to estimate ccosts for hydro projects in the stustudy, the analysis and estimates of costs are and to gauge relative costs between projects.

GENERAL

The capital cost einventory level. The cost estimates include:

Intakes, size based on design flow of project; Penstocks, based on diameter, slope and pressure rating (ass

Powerh

Energy equipment, including (controls, protection and substation), based on he

Road access;

Power line connectio Mobilization and transport costs, including cam

Bonding

Environmental and social mitigation a



The cost estimates include a 30% contingency allowance on civil itcontingency on generation equipment and electronic balance of plan

ems and a 10% t. All costs are presented

in 2011 $ Canadian dollars, and do not include any local, provincial or federal taxes.

3.1

pment of hydro s experience was ject components

plished by comparing component costs for projects that were either constructed or in an advanced

e. This data was sing regression. These comparisons showed that specific

rmation used to

es were also relevant for projects over 50 MW as the costs were developed

p tainty, however; with low head projects over 50 MW due to large water diversions that push the bounds of the cost curves. Of the

s identified in the study less than 0.2% have capacity over 50 MW.

3.2

were obtained for typical penstock construction within British Columbia in Canadian dollars. These costs were used to calibrate cost curves that were developed for the assessment.

INTAKE AND POWERHOUSE CIVIL WORKS

Intake and powerhouse components were sized and costed based on experience with projects in British Columbia. These costs were used to calibrate cost curves that were developed for this assessment.

METHODOLOGY

DATA COLLECTION AND RESEARCH

Kerr Wood Leidal Associates Ltd. staff have been involved in the developrojects in British Columbia ranging from 1 to 50 MW in capacity. Thiused to develop average quantities and their costs for individual pro(intake, powerhouse, penstock, generating equipment). This was accom

stage of development where contractor and supplier quotes were availablused to develop cost curves usite conditions affect the cost of project components significantly. Specifics to how this data was generated cannot be disclosed, as the infogenerate the cost curves is confidential.

The cost curvon a com onent basis. There is greater uncer

project

CAPITAL COSTS

PENSTOCK

Known capital costs



GENERATION EQUIPMENT – TURBINE/GENERATOR AND ELECTRIC BALA

Conceptual cost tables were based on actual projects and curves fodeveloped for a variety of project capacity, heads and flows. Costdeveloped for the supply and installation of energy equipment (e.g. turbiand electrical balance of plant (switchgear, controls, substation).

NCE OF PLANT

r projects were estimates were

ne and generator) The type of turbine

elton) selected for each project was based on the design head at each of the sites (Table 3-1) and the number of units based on design capacity (Table 3-2).

Turbine Selection Head Turbine Type

(Kaplan, Francis or P

Table 3-1:

8 – 40 m Kaplan/Propeller40 -200 m Francis 200 – 1,00 n 0 m Pelto

Table 3-2: Turbine No. of Units Selection

Kaplan Francis and Pelton < 6 MW N/A < 5 MW 1 Unit 6 – 12 MW 1 Unit 5 – 30 MW 2 Units > 12 MW 2 Units > 30 MW 3 Units

R P L C OAD AND OWER INE OST

nes can be found .

roximity to city transportation of people and equipment were

added to estimates.

ory A sites were on of 25,000 or from a centre,

km radius from a

Transportation costs included travel time to and from a site for the necessary construction crews as well as any overtime and air or ferry costs related to travel for the duration of construction. The construction period required for a potential project would vary depending on size. For the purposes of this study, construction periods of one, two, and three years were used for project capacities of less than 5 MW, five through 15 MW and greater than 15 MW respectively. The permitting, design and assessment periods were estimated to be three and five years for project capacities of less than 50 MW, and greater than or equal to 50 MW, respectively.

Information relating to the estimation of the cost for roads and power liin Appendix B

CONSTRUCTION CAMP AND TRANSPORTATION

To account for site variations due to regional factors and remoteness (pcentres), costs for construction camps and

Four site categories were used to indicate remoteness of location. Categlocated within a 50 km radius of a major town or city centre (populatimore). Category B and C sites were located within 200 and 400 kmrespectively, and Category D sites were located anywhere outside a 400 centre. Figure 3-1 shows these site location categories.



It was assumed that all category C and D projects would include a camp, used during the construction period and could be downsized for use dThe components of the camp included sleeper, kitchen and office traileand treatm

which would be uring operation. rs, water supply

ent equipment, sewage treatment, drainage systems and power supply. Costs for construction and set-up of the camp were also included. Operating costs are included

on periods for site categories A e 3

Total Camp and Transpo o ing Mob/Demob ($)

coc

Class A LClass B

n Location Class D

in Section 3.3. Camp and Transportation cost estimates for the constructithrough D ar shown in Table 3- below:

-3: Table 3 rtation C sts Includ

Project Capa ity L ation ocation Locatio

Class C Less than 1 MW 111,300 222,600 800,830 934,390 1 to 10 MW 222,600 445,200 1,304,330 1,571,450 Greater than 10 MW 333,900 667,800 1,807,830 2,208,510

ENGINEERING, ENVIRONMENTAL AND OTHER

Project specific costs such as those for engineering or environmental management require si e r inventory level estimates in this report, ll xpressed as a percentage of total capital cost are given to account for

t cost ite In this s , allowa for each site category were as follows:

Table 3-4: Cost Allowances (% of Capital Cost) Bonding

and Environmental Engineering

detailed typical a

te informowances e

ation to det rmine. Fo

hese ms. tudy nces

Generating Equipment Installation1 Insurance

10% 2% 5% 15% 1. Generating equipment installation only applied to Turbine/generator and

ectric Balance of Plant costs. El

T ESTIMATES

marizes the dependant variables and assumptions used to determine unit owing project components.

Penstock

Dependent variables: Diameter; Pressure rating; and Penstock gradient.

UNIT COS

This section sumcosts for the foll



Assumptions:

All pipes constructed of steel, lined and coated; Two average pipe pressure ratings: penstock average of 1,725 kPa (250 psi) and

to 75+%.

Powerhouse, Intake and Miscellaneous Civil

Dependent variables:

Assumptions:

d construction (weir, gates, valves, etc.) Required at intake site; and Size of powerhouse and intake directly related to plant design flow.

nt variables:

on); and head and flow.

tion equipment is 10% of equipment cost.

alance of Plant

Number of turbines; and Capacity: net head and flow.

Assumptions: Installation of Electric Balance of Plant is 10% of equipment cost (excluding camp,

access costs).

penstock average of 4,135 kPa (600 psi); and Slope of terrain ranges from 0

Plant design flow (1.5 times Mean Annual Discharge).

Blasting an

Generation Equipment

Depende Turbines: number and type (Kaplan, Francis, Pelt Capacity: net

Assumptions:

Installation of genera

Electric B




Power Line


line; city: net head and flow; and

er lines constructed at 25 kV or above; 25 and 69 kV lines may be single pole, roadside construction; and

rain ranges from 0 to 75%.

Availability of materials; ion; and

a s a e m wide;

d decking of timber;

Portion of cut volume requires blasting; and ranges from 0 to 30%;

3.3 ANNUAL COST ANALYSIS

nance.

Operations and maintenance costs were estimated to be 2% of total capital costs for at gate and access roads and 1.1% of total capital costs for power lines.

Water Rental and Taxes

Water rental fees were estimated in accordance with the “Annual Water Licence Rental Rates Associated with Power Production” document, revised December 11th, 2009. For authorized capacity, the charge is $4.345 per kW. For output, the charge is $1.304 per MWh/yr up to 160,000 MWh and $6.084 per MWh/yr up to 3,000,000 MWh.

Voltage of power Capa Terrain for construction.

Assumptions: All pow

Slope of ter

Access Road(s)


Terrain for construct Difficulty of construction.

Assumptions:

All new ro d r 6 Includes clearing an Forestry type road construction with 0.3 m gravel topping;

Road grade

This section includes estimates of annual costs for operations and mainte

Estimated O&M Cost



Land Taxes

Property taxes were estimated to be 3% of the assessed property value, which was f the capital cost of the civil infrastructure.

t lead-time interest was calculated by taking all development costs and dividing til project COD

Project construction period interest was calculated by taking all construction costs ment) and dividing them into equal annual payments. Interest was then

lated annually until project COD is reached.

3.4

cost that was included in consideration of the cost to purchase, lease or obtain permission through negotiations to use the land for

and operation of hydropower projects. An annual cost of 5% of the wance for these

3.5 UNIT ENERGY COST

Unit energy costs were calculated by amortizing the total capital cost as described in Section 3.2 for each project at a 6% real discount rate (and 8% as sensitivity) over 40 years, adding the annual costs described in Section 3.3 and dividing by the annual energy estimate for the site.

assumed to be 80% o

Interest During Construction

Projecthem into equal annual payments. Interest is than calculated annually unis reached.

(including equipcalcu

LAND ALLOWANCE

A land allowance cost in the form of an annual

the construction estimated assessed value (civil infrastructure) was included as an allohighly variable, and difficult to predict costs.



I 1

Legend

1::] Study Area

Centre> 25,000 Pop. (Census) (wilh tho exception of Fort St. John)

-- Major Roads

Site Category

Location Class

0 A- < 50 km from Major Centre

0 B - 51 - 200 km from Major Centre

0 C- 201 - 400 km from Major Centre

C D- > 400 km from Major Centre

l<mt KERR WOOD~~.~~~''"''"' L____ C.OS!II:L -r i NG [. N t;I !Vt.f.A~

0'*'1~-~M-tN

Project No. Date

478-103 March 2011

200 100 0 200

--...___ ( ,Calgary

( Lethl?ridge I I r \._../ ----____ ... -

Run-of-River Hydroelectric Resource Assessment for British Columbia 2010 Update BC hydro m

Site Location Categories Figure 3-1



Section 4

Results of Assessment



4. RESULTS OF ASSESSMENT

4.1

s in BC. These energy of nearly

63,000 GWh/yr. The estimated cost for each of the projects includes access roads and C Hydro and Fortis BC grids. Table 4-1 provides the

s w e n pro er paci undle.

Table 4-1: Run-of-Ri Po BC

rice ndle

Numbeof

Project

AveragAnnuEnerg

(GWh/

Annual

Energy (G yr)

Installed Capa y

(M

Dependable Generating Capacity

(MW)

POWER DEVELOPMENT POTENTIAL

The study identified over 7,200 potential run-of-river hydroelectric sitesites have a potential installed capacity of over 17,400 MW and annual

power lines interconnecting to the Bresult

ith of th umber of

ver Hydro

jects, en

tential in

gy and ca

ty by price b

PBu

r

s

e al y

yr)

Firm

Wh/

citW)

65 - 69 1 89 2 2 66 0 70 - 74 3 212 53 1 172 75 - 79 3 66 17 6 4 503 3 80 - 84 5 93 22 17 0 698 2 85 - 89 3 17 45 0 7 142 90 - 94 7 69 16 12 8 531 7 95 - 99 9 68 17 8 4 556 9

100 - 109 30 2,13 54 34 5 1,708 3 110 - 119 46 3,51 84 61 2 2,710 7 120 - 129 22 1,25 33 8 1 1,045 0 130 - 139 36 1,70 44 18 6 1,379 3 140 - 149 44 1,92 48 27 0 1,549 6 150 - 159 39 1,97 49 25 1 1,584 2 160 - 169 37 1,42 37 8 7 1,189 6 170 - 179 47 1,75 47 15 8 1,449 3 180 - 189 40 1,40 36 14 1 1,141 3 190 - 199 51 1,33 35 5 0 1,098 7 200 - 29 452 10,3 2,8 63 9 20 8,321 20 300 - 39 399 6,1 1,7 31 9 49 4,978 32 400 - 499 365 4,204 3,331 1,193 16 500 - 599 277 2,163 1,733 637 9 600 - 699 241 2,015 1,575 570 8 700 - 799 230 1,621 1,255 472 5 800 - 899 193 1,578 1,229 445 5 900 - 999 177 1,124 875 322 3

1000 + 4,525 11,816 9,075 3,645 16

Total 7,282 62,858 49,890 17,404 420



A supply curve for run-of-river hydroelectric potential in BC is presentedThe inventory identified potential sites tha

in Figure 4-1. t could contribute approximately

The unit energy costs do not reflect what an independent power producer may offer to to BC Hydro due to factors such as:

apital; Contract terms;

expected to better represent what a developer might construct for that reach of stream. In nit energy costs inventory that is

of British Columbia’s run-of-river hydroelectric potential.

er Hydroelectric Potential in

4.2 POWER DEVELOPMENT POTENTIAL BY TRANSMISSION REGION

apacity by price ndix C. Supply ission regions in

As this study involved identifying a complete inventory of potential run-of-river hydroelectric projects, the unit energy costs presented include both the most cost-effective and least cost-effective projects. There are 31 projects estimated to have a unit energy cost of under $100/MWh with approximately 900 MW of capacity and nearly approximately 3,500 GWh/yr of average annual energy. Table 4-2 below presents the run-of-river hydro potential for sites under $100/MWh by transmission region.

3,500 GWh/yr of new green energy in BC for under $100/MWh.

sell electricity Cost of c

Taxation; and Other factors.

The new methodology results in an estimated project size (capacity & energy) that is

general it results in more capacity and energy and often with lower u(UEC) than the 2007 study. The 2010 methodology provides a new more representative

The attached map of BC (Map E-1)2 entitled ‘Run-of-RivBritish Columbia’ shows the location of more than 7,200 sites with associated size and estimated unit energy cost.

A summary of the results with the number of projects, energy and cbundle is broken down by transmission region and presented in Appecurves for run-of-river hydroelectric potential for the ten major transmBC are presented in Figure 4-2.

2 Note: Map E-1 is provided in a separate file on the BC Hydro Integrated Resource Plan website.



Table 4-2: Run-of-R ro l in B it

sion RegioNu

Proje

AAEn

(GW

arm ergy

r)

lled acity

(MW)


Capacity (MW)

iver Hyd Potentia

mber of

C for Sverage nnual

es underAnnu

Fi

$100/MWh l

taTransmis n

ctsergyh/yr)

En(GWh/y

InsapC

East Kootenay 3 76 0 255 236 Kelly Nicola 6 8 658 228 8 73 Lower Mainland 17 1, ,025 323 16 328 1North Coast 2 40 0 153 124 Revelstoke/Ashton Creek 1 67 51 17 1 Vanc u and 2 o ver Isl 778 573 175 21

Total 31 3,455 2,668 858 47

4.3

d for each site. UEC was calculated average energy production, annual and capital costs. A 40-year amortization

period was used to calculate UEC with a real discount rate of 6%, with a sensitivity at 8%. te assumed not to

The results of the study demonstrate that large projects are often more economic than in size comprise 55% of the energy in the

10 h ra that cost range. Further, ts l n 1 e un 0/M Tables 4-3 through 4-5 provide a

price bundle with totals of energy and capacity and f site

Table 4-3: En y Proj e Annual Energy (GWh/year)

PROJECT COSTS AND UNIT ENERGY COSTS

Project costs and unit energy costs (UEC) were estimatebase on the

Each site was treated in isolation (i.e., no cluster development) with each sishare infrastructure with other projects being developed concurrently.

PROJECT SIZING

small projects. Projects greater than 30 MW is about 23% of the projects inless than $ 0/MW

es hange. This M erno projec s t W w d 5er $1 Wh.

breakdown by project size and number o

s.

ergy b ect Siz

Price Bundle < 1 MW 1 to 30 MW > 30 MW Total

< $100/MWh 1, 1 3,455 554 1,90$100 to

6,72 03 10,525 149/MWh

2 3,8

> $150/MWh 40,44 4 48,878 5,293 1 3,14

Total ,293 48,7 7 62,858 5 18 8,84

Table 4-4: Capacity by Project Size

Installed Capacity (MW) Price Bundle


< $100/MWh 387 471 858 $100 to 149/MWh 1,714 935 2,649

> $150/MWh 1,729 11,386 782 13,897

Total 1,729 13,487 2,189 17,404



Table 4-5: Num SiteNu

ber of s by Project Size mb of Projects er

Price Bundle < 1 MW 1 to 30 MW Total MW > 30

< $100/MW 24 31 h 7$100 to 149/M 158 178 Wh 20

> $150/MWh 3,884 3,170 19 7,073

Total 3,884 3,352 46 7,282

al discharge, the iency. As this is

to be more cost-effective configurations for each ise each project. The analysis did not

consider diversion of tributary strea s, multiple projects on a stream reach or other site-

.

n down by site

t by component for each site remoteness category (Site Categories A through D) are provided in average costs and percentages in Figures 4-4 and 4-5

igher t are not remote

d in isolation of sts are considerably

tions than they would be if areas were developed in clusters and

) of many projects could be improved in remote areas if new major transmission lines or major roads were constructed with public resources.

MONTHLY ENERGY PROFILE

The monthly energy distribution of projects in each region can be found in Figure 4-6. The majority of energy is typically produced May through September during snowmelt periods, with the exception of Vancouver Island, which has less snow melt as a percentage of its runoff compared to the rest of the province.

Capacity was based on design flows of one and a half times mean annuoptimised penstock distance (and head), frictional losses and plant effican inventory level study, there is likely project site. Further analysis is required to optim

mspecific opportunities to decrease unit energy costs.

COST BREAKDOWN BY COMPONENT AND SITE REMOTENESS

The unit energy cost was greatly influenced by the remoteness of the site The supply curve presented in Figure 4-3 displays the UEC brokeinfrastructure (at gate cost) and access / power line costs. Breakdowns of cos

respectively. Power line, access road, and mobilization costs are a substantially hpercentage of total costs for remote sites (Site Category D) than sites tha(Site Category A).

CLUSTER DEVELOPMENT

Each site has access and power line costs estimated as if it is constructeother projects. Since each site was treated in isolation, the unit cohigher in remote locainfrastructure shared.

MAJOR ROAD AND TRANSMISSION LINE DEVELOPMENT

Cost-effectiveness (lower UECs



UNIT ENERGY COST SENSITIVITY

The unit energy cost (UEC) sensitivity to real discount rate was explopresented in this report were calculated using a 6% real discount rate. also calculated at a real discount rate of 8% to compare against the resulcurves are shown on Figure

red. The UECs The UECs were ts at 6%. Supply

4-7 for both 6% and 8% real discount rates. Using a discount rate of 8% increased the capital amortization portion of each UEC by approximately 20%

tal costs calculated using 6%.

4.4

hydroelectric projects in BC.

the options that

More comprehensive site investigation, First Nation discussions, environmental and social assessments, hydrologic data collection and analysis, and concept development is required for developers to proceed with potential project applications, licensing, electricity purchase agreements, and construction.

from to

CLOSING

There is large potential for future development of run-of-river The study is an inventory level assessment and does not explore all ofcould be available to developers at individual sites.



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Section 5

Report Submission



5. RT SUBMISSION


_______________________________________

yce, P.Eng. Project Manager

Reviewed by:

_______________________________________ Ron Monk, M.Eng., P.Eng. Senior Project Reviewer

REPO Prepared by:

Stefan Jo



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november 2013 irp appendix 3a-27: 2013 ror update – run-of ... · 2013 resource options report...

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