November 2013 IRP Appendix 3A-27: 2013 ROR Update – Run-of ... · 2013 Resource Options Report...
Transcript of 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.
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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
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TECHNICAL MEMORANDUMRun of River Hydroelectric Resource Assessment for
British Columbia 2013 RevisionsJune 20, 2013
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.
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TECHNICAL MEMORANDUMRun of River Hydroelectric Resource Assessment for
British Columbia 2013 RevisionsJune 20, 2013
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
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TECHNICAL MEMORANDUMRun of River Hydroelectric Resource Assessment for
British Columbia 2013 RevisionsJune 20, 2013
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)
< 1 MW 1 to 30 MW > 30 MW Total
< $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
< 1 MW 1 to 30 MW > 30 MW Total
< $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.
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Page 6 of 72 November 2013
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.
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TECHNICAL MEMORANDUMRun of River Hydroelectric Resource Assessment for
British Columbia 2013 RevisionsJune 20, 2013
Figure 1: Supply Curve for Run-of-River Potential in BC at 6% Discount Rate
0
50
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150
200
250
300
350
400
450
500
0 10,000 20,000 30,000 40,000 50,000
Un
it E
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gy
Co
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$/M
Wh
)
Cumulative Energy (GWh/yr)
UEC at 6% Discount Rate
Curve above $500/MWh not displayed in order to show detail at lower UECs
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TECHNICAL MEMORANDUMRun of River Hydroelectric Resource Assessment for
British Columbia 2013 RevisionsJune 20, 2013
Figure 2: Run-of-River Potential Supply Curves by Transmission Region at 6% Discount Rate
0
50
100
150
200
250
300
350
400
450
500
0 2,000 4,000 6,000 8,000 10,000
Un
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gy
Co
st (
$/M
Wh
)
Cumulative Energy (GWh/yr)
Central Interior
East Kootenay
Kelly Nicola
Lower Mainland
Mica
North Coast
Peace River
Revelstoke/Ashton Creek
Selkirk
Vancouver Island
Curve above $500/MWhnot displayed in order to show detail at lower UECs
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TECHNICAL MEMORANDUMRun of River Hydroelectric Resource Assessment for
British Columbia 2013 RevisionsJune 20, 2013
Figure 3: Supply Curve Breakdown for Run-of-River Potential in BC at 6% Discount Rate
0
50
100
150
200
250
300
350
400
450
500
Un
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ner
gy
Co
st (
$/M
Wh
)
Cumulative Energy (GWh/yr)
Supply Curve for Run-of-River Potential in BC at 6% Discount Rate
Average of UEC - At Gate ($/MWh) Average of UEC - Access/Powerline ($/MWh)
Curve above $500/MWh not displayed in order to show detail at lower UECs
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TECHNICAL MEMORANDUMRun of River Hydroelectric Resource Assessment for
British Columbia 2013 RevisionsJune 20, 2013
Figure 4: Average Site Category Cost Breakdown1
1 Does not include Annual Costs or IDC
0
20
40
60
80
100
120
140
160
180
Category A Category B Category C Category D
Co
st in
Mill
ion
s ($
)
Site Category A: <50km radius from a major town or city centreSite Category B: 50 to 1999 km radius from a major town or city centreSite Category C: 200 to 399 km radius from a major town or city centreSite Category D: > 400 km radius from a major tow
Engineering
General
Mobilization
Powerline
Road
Electrical
Equipment
Civil Works
Penstock
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Page 11 of 72 November 2013
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TECHNICAL MEMORANDUMRun of River Hydroelectric Resource Assessment for
British Columbia 2013 RevisionsJune 20, 2013
Figure 5: Average Site Category Cost Breakdown as a Per cent of Total2
2 Does not include Annual Costs or IDC
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Category A Category B Category C Category D
Per
cet
of
To
tal P
roje
ct C
ost
Site Category A: <50km radius from a major town or city centreSite Category B: 50 to 1999 km radius from a major town or city centreSite Category C: 200 to 399 km radius from a major town or city centreSite Category D: > 400 km radius from a major town o
Engineering
General
Mobilization
Powerline
Road
Electrical
Equipment
Civil Works
Penstock
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TECHNICAL MEMORANDUMRun of River Hydroelectric Resource Assessment for
British Columbia 2013 RevisionsJune 20, 2013
Figure 6: Monthly Energy Profiles – Small Hydro Potential by Transmission Interconnection Region
Figure 7: Supply Curve with Unit Energy Cost Sensitivity to Discount Rate
0%
5%
10%
15%
20%
25%
30%
35%
Per
cen
t o
f A
nn
ual
Ave
rag
e E
ner
gy
Month
Central Interior
East KootenayKelly NicolaLower MainlandMicaNorth Coast
Peace RiverRevelstoke/Ashton CreekSelkirkVancouver Island
0
50
100
150
200
250
300
350
400
450
500
0 10,000 20,000 30,000 40,000 50,000Un
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UEC at 6% Discount Rate
UEC at 8% Discount Rate
Curve above $500/MWh not displayed in order to show detail at lower UECs
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 13 of 72 November 2013
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Run-of-River Hydroelectric Potential in
British Columbia 2013 Update
June 2013
Map 1
KERR WOOD LEIDAL
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 14 of 72 November 2013
Run-of-River Hydroelectric Resource Assessment for British Columbia
2010 Update
Final Report
March 2011
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 15 of 72 November 2013
Run-of-River Hydroelectric Resource Assessment for British Columbia 2010 Update
Final Report March 2011
KWL File No. 478.103-300
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 16 of 72 November 2013
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
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 17 of 72 November 2013
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 ................................................................................................
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 18 of 72 November 2013
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.................................................................
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 19 of 72 November 2013
Executive Summary
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 20 of 72 November 2013
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
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 21 of 72 November 2013
ii KERR WOOD LEIDAL ASSOCIATES LTD.
Consulting Engineers 478.103
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.
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 22 of 72 November 2013
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
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 23 of 72 November 2013
iv KERR WOOD LEIDAL ASSOCIATES LTD.
Consulting Engineers 478.103
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)
Dependable Generating
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
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 24 of 72 November 2013
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Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 25 of 72 November 2013
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Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 26 of 72 November 2013
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Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 27 of 72 November 2013
Section 1
Introduction
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 28 of 72 November 2013
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.
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 29 of 72 November 2013
I l ~ ! l
I
PACIFIC
North Coast ~
OCEAN
ALBERT A
BC hydro m Run-of-River Hydroelectric Resource
Assessment for British Columbia 2010 Update
Legend
<!> Integrated Substation
~ Non-Integrated Substation
® Planned Sub&talion
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- - - • Planned NTt. Une
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~~L---------------------------------------------------------------------------------------------------L-----------~F~ig~u~re=-1~-~1
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 30 of 72 November 2013
Section 2
Power and Energy Analysis
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 31 of 72 November 2013
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.
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 32 of 72 November 2013
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
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 33 of 72 November 2013
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
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Page 34 of 72 November 2013
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
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 35 of 72 November 2013
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
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 36 of 72 November 2013
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.
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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.
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Page 38 of 72 November 2013
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
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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)
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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
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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
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Page 42 of 72 November 2013
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
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Page 43 of 72 November 2013
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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Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
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d
Hyd
rolo
gic
Zo
ne
s
Fig
ure
2-3
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 47 of 72 November 2013
Q:'(I40Q.O.Itw:71-103"oo»-GIS\MXD.Itp\17110)_Fl02-4111ll0 312512011 11:08:-.ISAM
Digital Elevation Model (IN)
Elevation Drop (OUT)
Project No.
478-103 Date
March 2011
Hydrology (IN)
Normal Annual Runoff lsolines (IN)
·~------------------_, ........ ,. ... 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
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 48 of 72 November 2013
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.................................................................
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 49 of 72 November 2013
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
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 50 of 72 November 2013
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
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 51 of 72 November 2013
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.
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 52 of 72 November 2013
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
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Page 53 of 72 November 2013
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
Dependent variables:
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Page 54 of 72 November 2013
Power Line
Dependent variables:
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)
Dependent variables:
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
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Page 55 of 72 November 2013
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.
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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
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Page 57 of 72 November 2013
Section 4
Results of Assessment
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Page 58 of 72 November 2013
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
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 59 of 72 November 2013
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.
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 60 of 72 November 2013
Table 4-2: Run-of-R ro l in B it
sion RegioNu
Proje
AAEn
(GW
arm ergy
r)
lled acity
(MW)
Dependable Generating
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
< 1 MW 1 to 30 MW > 30 MW Total
< $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
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 61 of 72 November 2013
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
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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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Page 63 of 72 November 2013
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Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 64 of 72 November 2013
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t Rat
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050100
150
200
250
300
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400
450
500
02,
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06,
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00
Cum
ulat
ive
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gy (G
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tral I
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Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 65 of 72 November 2013
RU
N-O
F-R
IVER
HYD
RO
ELEC
TRIC
RES
OU
RC
E A
SSES
SMEN
TFO
RB
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ISH
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4-8
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Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 66 of 72 November 2013
BC
HYD
RO
&PO
WER
AU
THO
RIT
Y
RU
N-O
F-R
IVER
HYD
RO
ELEC
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RES
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Cat
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Cost in Millions ($)
Eng
inee
ring
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iliza
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1. C
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-4
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 67 of 72 November 2013
RU
N-O
F-R
IVE
R H
YD
RO
EL
EC
TR
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RC
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90%
100%
Cat
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Cat
ego
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Cat
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Percent of Total Project Cost
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inee
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Gen
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1. C
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Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 68 of 72 November 2013
BC
HYD
RO
PO
WER
AU
THO
RIT
Y
RU
N-O
F-R
IVER
HYD
RO
ELEC
TRIC
RES
OU
RC
E A
SSES
SMEN
TFO
R B
RIT
ISH
CO
LUM
BIA
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RT
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thly
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rgy
Prof
iles
- Sm
all H
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Pot
entia
l By
Tran
smis
sion
Reg
ion
051015202530
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Mon
th
% of Annual Average Energy
Cen
tral I
nter
ior
Eas
t Koo
tena
yK
elly
Nic
ola
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er M
ainl
and
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aN
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stP
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4-11
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re 4
-6
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 69 of 72 November 2013
RU
N-O
F-R
IVER
HYD
RO
ELEC
TRIC
RES
OU
RC
E A
SSES
SMEN
TFO
R B
RIT
ISH
CO
LUM
BIA
201
0 U
PDA
TEFI
NA
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EPO
RT
- MA
RC
H 2
011
BC
HYD
RO
&PO
WER
AU
THO
RIT
Y
4-12
Figu
re 4
-7
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R W
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ASS
OC
IATE
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1603
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Supp
ly C
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with
Uni
t Ene
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t Sen
sitiv
ity t
o D
isco
unt R
ate
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150
200
250
300
350
400
450
500
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000
10,0
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0025
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30,0
0035
,000
40,0
0045
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50,0
00
Cum
ulat
ive
Ener
gy (G
Wh/
year
)
Unit Energy Cost ($/MWh)
UE
C a
t 6%
Dis
coun
t Rat
e U
EC
at 8
% D
isco
unt R
ate
Cur
ves
abov
e$5
00/M
Wh
not
disp
laye
din
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rto
show
det
ail a
t low
er U
EC
s
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 70 of 72 November 2013
Section 5
Report Submission
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 71 of 72 November 2013
5. RT SUBMISSION
KERR WOOD LEIDAL ASSOCIATES LTD.
_______________________________________
yce, P.Eng. Project Manager
Reviewed by:
_______________________________________ Ron Monk, M.Eng., P.Eng. Senior Project Reviewer
REPO Prepared by:
Stefan Jo
Integrated Resource Plan Appendix 3A-27 2013 Resource Options Report Update Appendix 8-A
Page 72 of 72 November 2013