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HomeMy WebLinkAbout200610022006 IRP Appendix D.pdf;2h _R.
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An IDACORP company
Appendix 0- Technical ApReQ~(-?f
For the 2006 Integrated Resource Plan
, ., ,; '... .
IPC-O6-
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Appendix O-Technical Appendix
For the 2006 Integrated Resource Plan
IDAHO~POWER~
An IDACORP Company
Acknowledgement
Resource planning is a continuous process that Idaho
Power Company constantly works to improve. Idaho Power
prepares and publishes a resource plan every two years and
expects the experience gained over the next few years will
lead to modifications in the 20-year resource plan presented
in this document. Idaho Power invited outside participation
to help develop both the 2004 and 2006 Integrated
Resource Plans.
( ;
Idaho Power values the knowledgeable input, comments
and discussion provided by the Integrated Resource Plan
Advisory Council and the comments provided by other
concerned citizens and customers. Idaho Power looks
forward to continuing the resource planning process with
its customers and other interested parties.
You can learn more about Idaho Power s resource planning
process at www.idahopower.com.
'-.
Safe Harbor Statement
This document may contain forward-looking statements, and it is important to note that the future results
could differ materially from those discussed. A full discussion of the factors that could cause future results to
differ materially can be found in our filings with the Securities and Exchange Commission.
Printed on recycled paper
Idaho Power Company Appendix 0- Technical Appendix
TABLE OF CONTENTS
Glossary of Terms................................................ ........................,...............................................................
Sales and Load Forecast Data """""""""""""""""""""""""""""""""....................................................
Average Annual Forecast Growth Rates..................................
~.............................................................
Expected Case Load Forecast """""""""""""""""""""""""""""""..................................................
Monthly Summary ................................
,..................................................,.......................................
Annual Summary """""""""""""""""""""""""""'""""""""""""""""""""""'
"""""'"..........
70th Percentile Load Forecast..................................................................................
...........................
Monthly Summary .........................................................................................................................
Annual Summary ....................................,.......... ....
.... ............................... ..... .,...... .... ....................
Existing Resource Data............ ....................... ...................
.... .......................................... ..........................
Hydroelectric and Thermal Plant Data.......................................................................................
:..... ..
.46
Qualifying Facility Project Data..........................................................................................................47
Fuel Data....................................................."""""""""""""""""""""""""""'"......................................
Gas and Coal Forecast-Data and Graphs........................................................................................... ..
Natural Gas Price Forecast-Comparison to Other Forecasts...............................................................
Natural Gas Price Forecast-Comparison to Previous Integrated Resource Plans ...............................
Coal Price Forecast-Comparison to Previous Integrated Resource Plans...........................................
Supply-Side Resource Data """"""""""""""""""""""""""""""'"........................................................
Key Financial and Forecast Assumptions.........................................
,..................................................
Energy and Capacity Levelized Cost Data........................................... ...........
................................... .
Brownlee Reservoir Inflow Record..................................................................................................... 60
Monthly Wind Energy Distribution............................ ............................................"........................... 61
Demand-Side Resource Data..............................................................................,......................................
DSM Analysis and Screening Criteria.. ............................................................................................. ..
DSM Program Development..................
""""""""""""""""""""""""""""""'" ...... ..................
Screening Criteria .........................................................................................................................
Static Cost-Effectiveness Analysis """"""""""""""""""""""""""""........................................
Total Resource Cost Test (TRC)...................................................................... ...................... ..
Utility Cost Test ......................................................................................................................
DSM Analysis Calculation Definitions ........................................,..........................................
Program Benefits Calculations ......................................................................................................
Dynamic Modeling ........................................................................................................................
2006 Integrated Resource Plan Page i
Appendix 0- Technical Appendix Idaho Power Company
Surplus/Deficit Analysis Data and Results................................................................................................ 74
Monthly Average Energy Surplus/Deficiency Data............................................................................ 74
50th Percentile Water, 50th Percentile Load Chart..........................................................................
70th Percentile Water, 70th Percentile Load Chart..........................................................................
90th Percentile Water, 70th Percentile Load Chart..........................................................................
Peak-Hour Load Surplus/Deficiency Data...........................................................................................
50th Percentile Water, 90th Percentile Peak-Hour Load Chart .......................................................
70th Percentile Water, 95th Percentile Peak-Hour Load Chart .......................................................
90th Percentile Water, 95th Percentile Peak-Hour Load Chart .......................................................8 I
Northwest Transmission Constraint Surplus/Deficiency Data ............ ................................................
50th Percentile Water, 90th Percentile Peak-Hour Load Chart ...................................
,...................
70th Percentile Water, 95th Percentile Peak-Hour Load Chart .......................................................
90th Percentile Water, 95 th Percentile Peak-Hour Load Chart .......................................................
Northwest Transmission Constraint Surplus/Deficiency Detailed Data..............................................
50th Percentile Water, 90th Percentile Peak-Hour Load (MW) ......................................................
70th Percentile Water, 95th Percentile Peak-Hour Load (MW) ......................................................
90th Percentile Water, 95th Percentile Peak-Hour Load (MW) ......................................................
Portfolio Analysis-Results and Supporting Documentation ......... ......................................
......................
Portfolio Summary and Description .......................... ......................................................................... .
Coal Based Technology Assessment Executive Summary (Draft)......................................................
CO2 Adder Survey Data.....................................................................................................................107
Description of Aurora Computer Model............................................................................................ 1 08
PDR580 Results .................................................................................................................................111
50th Percentile Water, 50th Percentile Load .................................................................................111
70th Percentile Water, 70th Percentile Load................................ ............................................... ..121
90th Percentile Water, 70th Percentile Load...................
:........................................................... ..
131
Scenario Sensitivity Ranking of Initial Portfolios............................................................................ .141
Finalist Portfolio Details ............ ................
............... ........... ..............................................................
142
". ,", ," '
, 7
1.:.0 .
Portfolio F1 .......................................................................................".........................................142
Portfolio F2 ................................................................"""""""""""""""""""""'
"""""""'"......
144
Portfolio F3 """"""""""""""""""""""""""""".............................,..........................................146
Portfolio F4 ..................................................................................................................................148
Capacity Planning Reserve for Finalist Portfolios........................................................................... ..150
Portfolio Fl.....
.............................................................................................................................
150
Page ii 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Portfolio F2 ................................................................................................................................. .151
Portfolio F3 """"""""""""""""""""""""""""..................................................,.......................152
Portfolio F4 """"""""""""""""""""""""""""'"...................................,...................................153
Resource Investment Schedule ................................................................................................. ....... ..154
Portfolio FI .......................................
:..........................................................................................
154
Portfolio F2 ..................................................................................................................................155
Portfolio F3 ........
~...................................................................................................,.....................
156
Portfolio F4 ..................................................................................................................................157
Summary of Northwest Utility Planning Criteria .......................................................
;.......................... ..
15 8
IRP Advisory Council Roster.................................. .............................................................................. ..160
2006 Integrated Resource Plan Page iii
Appendix 0- Technical Appendix Idaho Power Company
. '
(' i
Page iv 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
GLOSSARY OF TERMS
A/C - Air Conditioning
AIR - Additional Information Request
Alliance - Northwest Energy Efficiency Alliance
aMW - Average Megawatt
BOR - Bureau of Reclamation
BP A - Bonneville Power Administration
C&RD - Conservation and Renewable Discount
CAMR - Clean Air Mercury Rule
CCCT- Combined-Cycle Combustion Turbine
CDD - Cooling Degree-Days
CFB - Circulating Fluidized Bed
CFL - Compact Fluorescent Light
CHP - Combined Heat and Power
CO2 - Carbon Dioxide
CRC - Conservation Rate Credit
CSPP - Cogeneration and Small Power Producers
CT - Combustion Turbine
DOE - U.S. Department of Energy
DG - Distributed Generation
DSM - Demand-Side Management
EA - Environmental Assessment
EEAG -Energy Efficiency Advisory Group
EIA - Energy Information Administration
EIS - Environmental Impact Statement
ESA - Endangered Species Act
FCRPS - Federal Columbia River Power System
FERC - Federal Energy Regulatory Commission
GDD - Growing Degree-Days
HDD - Heating Degree-Days
IDWR - Idaho Department of Water Resources
IGCC - Integrated Gasification Combined Cycle
INL - Idaho National Laboratory
2006 Integrated Resource Plan Page v
Appendix 0- Technical Appendix Idaho Power Company
IOU - Investor-Owned Utility
IPC - Idaho Power Company
IPUC - Idaho Public Utilities Commission
IRP - Integrated Resource Plan
IRP AC - Integrated Resource Plan Advisory Council
kV - Kilovolt
kW - Kilowatt
kWh - Kilowatt Hour
LIW A - Low Income Weatherization Assistance
MAF - Million Acre Feet
;' , ~
MMBTU - Million British Thermal Units
MW - Megawatt
MWh - Megawatt Hour
NEP A - National Environmental Policy Act
NWPCC - Northwest Power and Conservation Council
NOx - Nitrogen Oxides
OPUC - Oregon Public Utility Commission
PCA - Power Cost Adjustment
PM&E - Protection, Mitigation, and Enhancement
PP A - Power Purchase Agreement
PTC - Production Tax Credit
PUC - Public Utility Commission
PURP A - Public Utility Regulatory Policies Act of 1978
PV - Present Value
,..
c;;
,.. "" '
QF - Qualifying Facility
REC - Renewable Energy Credit
Rider - Energy Efficiency Rider
RFP -' Request for Proposal
RPS - Renewable Portfolio Standard
RTO - Regional Transmission Organization
- '( -
S02 - Sulfur Dioxide
SCCT - Simple-Cycle Combustion Turbine
W ACC - Weighted Average Cost of Capital
WECC - Western Electricity Coordinating Council
( ,
Page vi 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Average Annual Forecast Growth Rates
(%)
2006-2011 2006-2016 2006-2025
Sales
Residential Sales.............
Commercial Sales...........
rrigation Sales.................
Industrial Sales................2.44
Additional Firm Sales.......0.46
Firm Sales.......................
System Sales..................
Firm Off-System Sales....
Total Sales......................
Loads
Residential Load..............
Commercial Load............
Irrigation Load..................
Industrial Load.................
Additional Firm Load........0.46
Firm Load Losses............
Firm Load.......
.................
System Load...................
Firm Off-System Load.....
Total Load.......................
Firm Requirement Load...
Peaks
Firm Peak........................
System Peak...................
Firm Off-System Peak.....
Total Peak........... ....
........
Firm Requirement Peak...
Winter Peak.....................1.48
Summer Peak..................
Customers
Residential Customers.....
Commercial Customers...2.40
Irrigation Customers........1.49 1.41
Industrial Customers........
2006 Integrated Resource Plan Page 1
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Appendix 0- Technical Appendix Idaho Power Company
ResidentiaL........................
CommerciaL......,.........,.......
Irrigation..............................
IndustriaL............................
Additional Firm........,...........
Firm Sales
Expected Case Sales and Load Forecast Annual Summary
2006
862 268
800 997
643,080
2,421,451
182,934
13,910 730
2007
028 163
938 173
639,190
2,485,427
143,360
234 313
Billed Sales (Megawatt-hours)2008 2009 2010 2011
129,950 5 218,358 5,315,450 5,373,289
061 269 4 177 796 4 293,773 4 384 049
633,080 1 629,431 1 626,475 1,617 721
537 510 2 596 445 2 656,152 2,708,334
162 503 1 177,194 1,194 104 1,210,114
524 313 14 799,225 15 085 955 15 293 506
2012
5,407 204
4,469,715
615 071
765,435
227 715
15,485,140
2013
507 578
587 155
612,422
823 076
240,656
770 885
2014
603,702
702,480
609,760
881 748
257,431
055,122
2015
699,278
818,204
612 308
949 296
274 235
16,353 323
System Sales 13 910 730 14 234 313 14 524 313 14 799 225 15 085 955 15,293,506 15,485,140 15 770 885 16,055,122 16 353,323
Firm Off-System Sales........
Total Sales 13,910,730 14 234 313 14 524 313 14 799,225 15,085,955 15,293,506 15,485 140 15,770,885 16 055 122 16,353,323
ResidentiaL.........................
CommerciaL........................
Irrigation..............................
IndustriaL............................
Additional Firm........,...........
Firm Sales
2006
872,705
807,410
643,102
2,425,530
182 934
13,931 681
2007
034 133
943 800
639 191
2,488,836
143,360
249,320
eneration Month Sales (Megawatt-hours)2008 2009 2010 2011
151 940 5,223,934 5,318,318 5,374,513
077 862 4 182 961 4 297 571 4 387 575
633 086 1 629,432 1 626,473 1 617 722
548,189 2 600 283 2,659,566 2 712 026
162 503 1 177 194 1,194 104 1 210,114
14,573 580 14 813,805 15,096,033 15,301 949
2012
5,430,481
4,487,202
615,077
776,742
227,715
537,217
2013
512,941
592 111
612,423
826 856
240 656
15,784,986
2014
608 872
707 351
609,762
885,549
257,431
16,068,965
2015
704,471
823 108
612,309
953,105
274 235
367,228
System Sales 13,931 681 14,249,320 14 573,580 14 813 805 15 096 033 15,301 949 15,537 217 15 784,986 16 068,965 16 367 228
Firm Off-System Sales........
Total Sales 13,931 681 14 249,320 14,573 580 14 813,805 15,096,033 15,301 949 15 537 217 15,784 986 16 068,965 16,367 228
Loss........,........................... 360,067 1 394 827 1,427 012 1,451 237 1,479,180 1,499,115 1 521 363 1 546 529 1 574 734 1 603,795
Required Generation 15 291.747 15 644 147 16 000,592 16 265 042 16 575 213 16 801,064 17 058,580 17 331 515 17 643,699 17 971,023
ResidentiaL.........................
CommerciaL......,.....,...........
Irrigation.................,............
IndustriaL...........................
Additional Firm....................
Loss.................................,..
Firm Load
Light Load...........................
Heavy Load...........,......,......
System Load
Firm Off,System Load.........
Total Load
Energy Efficiency (MW).......
Demand Response.............
Firm Peak Load
System Peak (1 Hour)
Firm Off,System Peak.........
Loss..........................,......,..
Total Peak Load
2006
556
435
188
277
135
155
746
2006
121
588
870
1,746
746
121
121
2007
575
450
187
284
130
159
786
2007
-46
208
Average Load (Average Megawatts)008 2009 2010 2011587 596 607 614464 478 491 501186 186 186 185290 297 304 310133 134 137 139162 166 169 171822 1 857 1 892 1,918
624
913
786
657
951
822
689
988
857
721
025
892
744
054
918
918
3,459
3,459
2012
618
511
184
316
140
173
942
2012
522
766
080
942
942
522
522
2013
629
524
184
323
142
177
978
2013
-48
597
799
119
978
978
597
597
2014
640
537
184
329
144
180
014
2014
673
832
157
014
014
673
673
2015
651
551
184
337
146
183
051
786 822 857 892
866
197
051
\"
Peak Load (Megawatts)2009 201026 ,73 ,326 3,396
2008
268
2011
459
051
208 268 326 396
( .'
2015
754
208 268 326 396
3,754
754
Page 22 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Residential..........................
Commercial.........................
Irrigation,..,..........................
IndustriaL............................
Additional Firm....................
Firm Sales
Expected Case Sales and Load Forecast Annual Summary
2016
795,818
935,524
614,777
016,981
293 573
16,656,674
2017
895,126
055,838
617 289
086 155
306 995
16,961,402
Billed Sales (Megawatt-hours)2018 2019 2020 2021
997 530 6 100 905 6,206,045 6,314,869
179 326 5 304 556 5,432,315 5,563,441
619,769 1 622,199 1 624 614 1 626 988
156,872 3,229 166 3 303 072 3 378 626
322,898 1 339 087 1 356,188 1 368,805
276 395 17 595,913 17,922,235 18,252,730
2022
6,427 310
698,184
629,358
3,455,865
383 131
18,593,847
2023
541 021
834 756
631,660
534 826
396,756
18,939,019
2024
655,530
972,690
633 955
615 548
1,413,077
290,800
2025
772 209
112 112
636 206
698,070
1,424 582
19,643 178
System Sales 16,656 674 16 961,402 17 276,395 17 595,913 17 922 235 18 252 730 18 593 847 18,939,019 19 290 800 19,643 178
Firm Off,System Sales........
Total Sales 16 656,674 16 961,402 17 276,395 17 595,913 17,922 235 18 252 730 18,593 847 18 939 019 19,290,800 19,643,178
Residential...........,..............
Commercial.........................
Irrigation..............................
IndustriaL............................
Additional Firm....................
Firm Sales
2016
819,653
954 054
614 783
029,177
293,573
16,711,241
2017
900,622
060,951
617 291
090,135
306 995
16,975 992
Generation Month Sales (Megawatt-hours)2018 2019 2020 2021
003,045 6,106,491 6 231 254 6 320 840
184,474 5 309,777 5,452 375 5 568,897
619 771 1 622,200 1 624 620 1 626,990
160 940 3,233,325 3 316 393 3,382,972
322 898 1 339 087 1 356 188 1 368 805
291 128 17 610,880 17 980 831 18 268 505
2022
6,433,315
703,674
629,359
3,460,308
383,131
18,609,786
2023
547 027
840 255
631 661
539 368
396 756
18,955 068
2024
682,049
994 219
633,962
630,098
1,413,077
19,353,405
2025
778,394
117 660
636 207
702 817
1,424 582
19,659,660
System Sales 16 711 241 16 975,992 17,291,128 17 610 880 17 980,831 18,268 505 18,609 786 18,955,068 19,353,405 19 659 660
Firm Off,System Sales........
Total Sales 16 711 241 16 975,992 17 291,128 17 610,880 17 980,831 18,268,505 18,609 786 18,955,068 19 353,405 19 659 660
Loss.................................... 1 636,984 1 663,237 1,694 077 1 725 346 1 761 219 1,789,845 1 823 395 1,857 361 1 896 072 1 926,598
Required Generation 18,348,226 18,639 228 18,985,205 19,336 227 19 742 050 20 058 349 20,433,181 20,812,430 21,249,476 21 586,259
ResidentiaL.....,...........,..,....
CommerciaL........................
Irrigation..............................
IndustriaL...........................
Additionai Firm....................
Loss....................................
Firm Load
Light Load...........................
Heavy Load.........................
System Load
Firm Off,System Load..,......
Total Load
Energy Efficiency (MW).......
Demand Response.............
Firm Peak Load
System Peak (1 Hour)
Firm Off-System Peak.........
Loss........,...........................
Total Peak Load
2016
663
564
184
345
147
186
089
2016
~78
836
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237
089
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2017
674
578
185
353
149
190
128
2017
919
Average Load (Average Megawatts)2018 2019 2020 2021685 697 709 722592 606 621 636185 185 185 186361 369 378 386151 153 155 157193 197 201 204167 2,207 2 248 2,290
935
279
128
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167
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248
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263
263
2022
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186
395
158
208
333
2022
352
121
2,498
333
333
352
352
2023
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212
376
2023
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376
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4,443
2024
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186
413
161
216
2,419
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2,419
2025
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698
187
423
163
220
2,464
241
639
2,464
2,464
2025
627
534 627
128 167 207 248
534 627
Peak Load (Megawatts)2019 202054 -78 -
088 4 175
2018
003
2021
263
2006 Integrated Resource Plan
919 003 088 175
919 003 088 175
Page 23
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Appendix 0- Technical Appendix Idaho Power Company
70th Percentile Sales and Load Forecast Annual Summary
Billed Sales (Megawatt-hours)
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
ResidentiaL.........................998,197 167 721 273,003 364 603 5,464,619 525 263 561 958 665 098 763,903 862 138
Commercia!.........................841 226 979,546 103 786 221 377 338,345 4,429,590 516,234 634 665 750 970 867 680
Irrigation..............,...............788 305 784,413 778,302 774 653 771,697 762,943 760 293 757 644 754 982 757 530
IndustriaL.....,......................2,422,952 2,485,427 537 510 596,445 656,152 708,334 765,435 823,076 881 748 949,296
Additional Firm....................182 934 143 360 162,503 177,194 194,104 210,114 227,715 240 656 257 431 274 235
Firm Sales 233,615 560,466 855 104 15,134 273 424 917 15,636 244 831,635 121 137 16,409 035 710 880
System Sales 233,615 560,466 855 104 15,134 273 424 917 636 244 831 635 16,121 137 16,409 035 710 880
Firm Off-System Sales........
Total Sales 233.615 14,560,466 855,104 134 273 15,424,917 15,636,244 15,831,635 121 137 16,409 035 710 880
Generation Month Sales (Megawatt-hours)
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
ResidentiaL.........................008 756 173 895 295,628 370 326 5,467 617 526,613 585 838 670,580 769,186 867,442
CommerciaL........................847 698 985 286 120,615 226,640 342,236 4,433,210 533,961 639 717 755,936 872 680
Irrigation...................,....,....,788,324 784,413 1.778,308 774 655 771 695 762 944 760,299 757 645 754 984 757 531
IndustriaL............................2,425,530 2,488,836 548,189 600 283 659,566 712 026 776,742 826,856 885,549 953 105
Additional Firm....,....,..........182,934 143,360 162 503 177 194 194 104 210,114 227 715 240,656 257,431 274 235
Firm Sales 253,242 14,575,789 905,243 15,149 098 15,435,220 15,644 906 884,555 16,135,452 16,423,086 724 994
System Sales 253 242 575 789 905 243 15,149,098 15,435 220 644 906 15,884 555 135,452 16,423,086 16,724 994
Firm Off-System Sales........
Total Sales 253,242 14,575,789 905,243 149 098 15,435,220 15,644 906 884 555 16,135,452 16,423 086 724 994
Loss........,......,..........,.........396,358 1,431 623 1,464 372 1,489 006 517 378 537 731 560,455 585,976 614 586 644 050
Required Generation 649 599 007 412 16,369,615 638,104 952 598 182,637 17,445,010 721,429 18,037,673 18,369,045
Average Load (Average Megawatts)
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
ResidentiaL.........................572 591 603 613 624 631 636 647 659 670
Commercia!.........................439 455 469 482 496 506 516 530 543 556
Irrigation,.............................204 204 202 203 202 201 200 201 200 201
IndustriaL............................277 284 290 297 304 310 316 323 329 337
Additional Firm....................135 130 133 134 137 139 140 142 144 146
Loss....................................159 163 167 170 173 176 178 181 184 188
Firm Load 786 827 864 899 935 961 986 023 059 097
Light Load...........................625 662 695 727 760 784 806 840 872 907'
Heavy Load.........................914 958 996 034 072 100 127 167 205 246
System Load 786 827 864 899 935 961 986 023 059 097
Firm Off,System Load.........
Total Load 786 827 864 899 935 961 986 023 059 097
Peak Load (Megawatts)
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Energy Efficiency (MW).......-43 -48
Demand Response (MW)....-46
Firm Peak Load 163 251 312 372 3,442 506 570 647 723 805
System Peak (1 Hour)163 251 312 372 442 506 570 647 723 805
Firm Off-System Peak.........
Loss................,..,................
Total Peak Load 163 251 312 372 3,442 506 570 647 723 805
Page 44 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Residential..........................
CommerciaL..,.....................
Irrigation......,..........,........,...
IndustriaL......,.....................
Additional Firm....,...............
Firm Sales
70th Percentile sales and Load Forecast Annual Summary
2016
961,354
986,002
759,999
016 981
293,573
017 910
2017
063,348
107 332
762 512
086 155
306,995
326 341
Billed Sales (Megawatt,hours)2018 2019 2020 2021
168,444 6 274,528 6,382,438 6,494 082
231,854 5 358,132 5,486 963 5,619 179
764,992 1 767,421 1 769,836 1 772 211
156 872 3 229,166 3 303 072 3 378,626
322,898 1 339 087 1 356,188 1 368,805
645 060 17 968,334 18,298,498 18 632 903
2022
609,379
755,039
774,580
3,455,865
383,131
977 993
2023
725,979
892,744
776 882
534 826
396 756
19,327,187
2024
843,410
031 827
1 :779,178
615,548
1,413 077
19,683,040
2025
963 033
172,410
781,428
698,070
424 582
20,039,523
System Sales 17 017 910 17 326 341 17 645 060 17 968,334 18 298,498 18 632 903 18 977 993 19 327 187 19 683,040 20,039,523
Firm Off,System Sales........
Total Sales 17,017,910 17,326 341 17 645,060 17 968,334 18,298,498 18,632 903 18,977,993 19 327 187 19 683 040 20,039 523
ResidentiaL.........................
CommerciaL,.......,...............
Irrigation..............................
IndustriaL.
................,..........
Additional Firm....................
Firm Sales
2016
985 795
004 786
760,006
029,177
293,573
073,337
2017
068 954
112 545
762,513
090 135
306 995
341 140
Generation Month Sales (Megawatt-hours)2018 2019 2020 2021
174,068 6 280,223 6,408,266 6 500 162
237 103 5 363,456 5 507 297. 5 624 743
764,993 1,767,423 1,769,843 1,772,212
160 940 3 233 325 3,316,393 3,382,972
322,898 1,339,087 1,356,188 1,368,805
660,002 17 983 513 18,357 987 18 648 895
2022
615,491
760 638
774 581
3,460,308
383,131
994 149
2023
732,091
898,354
776 884
539 368
396 756
19,343,454
2024
870,558
053 651
779,184
630,098
1,413 077
746,568
2025
969,319
178 073
781,429
702 817
1,424,582
056 220
System Sales 17 073,337 17 341 140 17 660,002 17,983,513 18 357 987 18,648,895 18,994 149 19,343,454 19,746,568 20,056,220
Firm Off-System Sales........
Total Sales 17 073 337 17 341 140 17,660 002 17 983,513 18 357 987 18 648 895 18 994 149 19,343,454 19,746,568 20 056,220
Loss.................................... 1 677 711 1 704 311 1 735 564 1 767,251 1 803 616 1 832,610 1 866 602 1,901,014 1,940,245 1 971,159
Required Generation 18,751,049 19,045,451 19,395,566 19 750 764 20,161,603 20,481 505 20,860,751 21 244,468 21 686 813 22 027 379
ResidentiaL.........................
CommerciaL........................
Irrigation..........................,...
IndustriaL......
......................
Additional Firm....................
Loss....................................
Firm Load
Light Load...............,...........
Heavy Load..............,..,.......
System Load
Firm Off,System Load.........
Total Load
Energy Efficiency (MW).......
Demand Response (MW)...,
Firm Peak Load
System Peak (1 Hour)
Firm Off-System Peak..,......
Loss..............,.....................
Total Peak Load
2016
681
570
200
345
147
191
135
2016
888
941
286
135
135
888
888
2017
693
584
201
353
149
195
174
2017
'54
972
Average Load (Average Megawatts)2018 2019 2020 2021705 717 730 742598 612 627 642201 202 201 202361 369 378 386151 153 155 157198 202 205 209214 2,255 2 295 2,338
977
329
174
013
372
214
050
2,415
255
087
2,458
295
126
503
338
338
321
321
2022
755
658
203
395
158
213
381
2022
4,411
165
550
381
381
4,411
4,411
2023
769
673
203
404
160
217
2,425
2023
503
205
598
2,425
2,425
503
503
2024
782
689
203
413
161
221
2,469
2024
595
245
644
2,469
2,469
595
595
2025
796
705
203
423
163
225
515
286
693
515
515
2025
689
689
689
2006 Integrated Resource Plan
174 214 255 295
Peak Load (Megawatts)2019 202054 -78 -144 4 231
2018
058
2021
321
972 058 144 231
972 058 144 231
Page 45
Appendix 0- Technical Appendix Idaho Power Company
Hydroelectric and Thermal Plant Data
Hydroelectric Power Plants
American Falls...............................
Bliss...............................................
Brownlee........................................
Cascade........................................
Clear Lake.....................................
Hells Canyon.................................
Lower Salmon................................
Malad - Lower................................
Malad - Upper................................
Milner.............................................
Oxbow............................................
Shoshone Falls..............................
Strike, C J......................................
Swan Falls.....................................
Thousand Springs.........................
Twin Falls.......................................
Upper Salmon "
..........................
Upper Salmon "
..........................
Total Hydro
Thermal, Natural Gas
and Diesel Power Plants
Estimated
Non-
Coincidental
Nameplate Maximum
kVA
102 600 340 112,420
250 000 000
650,444 585,400 728 000
800 12,420 000
125 500 (1)2,400
435 000 391 500 450 000
000 000 000
500 13,500 000
650 270 000
890 59,448 59,448
211 112 190 000 220 000
900 500 (1)500
000 800 000
600 000 547
000 800 (1)000
175 737 300
000 000 000
000 500 000
897 046 706 715
Generator Nameplate Rating
Gross kVA Gross kW
. '
Estimated
Maximum
Dependable
Capability
(MDC)
Net kW
811 053 770 501
000 (2)050 (2)
315 000 283 500
185 053 110 051
192 000 172 800
105,882 000
297 882 262 800
880 000
386,862 084 566
" ,
(3) The HPIIP turbine was upgraded to boost generator output to 58 500 net kW.
706 667
500 (3)
260 650
025 817
'l.,,Bridger (IPC Share).......................
Boardman (IPC Share)..................
Valmy (IPC Share).........................
Total Thermal
Bennett Mountain...........................
Evander Andrews (Danskin)..........
Total Natural Gas
Salmon DieseL..............................
TotaliPC Generation
(.J
171 900
100 000
271 900
500
(1) A power factor rating of 0.8 is assumed on four units (Clear Lake, Unit #2 at Shoshone Falls, and
Units #1 and #2 at 1000 Springs) with a totalkVA rating of 6 127 kVA on which there is no
nameplate kW rating.
(2) The Boardman generator nameplate ratings increased from 59 000 gross kVA to 67 600 gross kVA
and from 56 050 gross kW to 64 200 gross kW. This was due to a rotor rewind, addition of H2
coolers, and static exciter.
Page 46 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Idaho Power Company
Qualifying Facilities
Cogeneration and Small Power Production Projects
Contract
Project On-line Date End Date
Hydro Projects
Barber Dam......,............................. Apr,1989 Apr'2024
Birch Creek........................,............ Nov-1984 Oct,2019
Black Canyon #3........,.......,.........,.. Apr,1984 Apr-2019
Blind Canyon....,...........................,.. Dec,1994 Dec-2014
Box Canyon.................................... Feb-1984 Feb,2019
Briggs Creek................................... Oct-1985 Oct,2020
Bypass,.................:......................... Jun-1988 Jun,2023
Canyon Springs...............,.............. Oct-1984 Non firm
Cedar Draw,......,............................. Jun-1984 May,2019
Clear Springs Trout...........,............, Nov,1983 Oct-2018
Crystal Springs..............................., Apr,1986 Mar-2021
Curry Cattle Company.................... Jun-1983 Jun,2018
Dietrich Drop................,.........,........ Aug,1988 Aug,2023
Elk Creek........................................ May-1986 May,2021
Falls River...................,..............,.... Aug-1993 Aug,2028
Faulkner Ranch....,..................,...... Aug,1987 Aug-2022
Fisheries Development Co............. Jul-1990 Non firm
Geo Bon #2..................................... Nov,1986 Nov-2021
Hailey CSPP..,................................ Jun-1985 Jun,2020
Hazelton A,......,..,........................... Jun,1990 Jun-2010
Hazelton B...................................... May-1993 Apr-2028
Horseshoe Bend Hydroelectric....... Sep,1995 Sep,2030
Jim Knight...............,......,................ Jun,1985 Jun-2020
Kasel and Witherspoon.................. Mar-1984 Feb-2019
Koyle Small Hydro...................,...... Apr,1984 Mar-2019
Lateral #10...................................... May-1985 Apr,2020
Lemoyne...................................,..,.. Jun,1985 Jun-2020
Little Wood Rvr Res........................ Feb-1985 Feb,2020
Littlewood-Arkoosh........................ Aug-1986 Jul-2021
Low Line Midway Hydro.................. Mar-2007 Estimated
Lowline #2....................................... Apr-1988 Apr,2023
Total Hydro Nameplate MW Rating
Thermal Projects
Magic Valley....................................
Magic West.....................................
Nov-1996
Dec-1996
Nov,2016
Nov-2016
Total Thermal Nameplate MW Rating 37.
Biomass Projects
CO~GEN CO...................................
Emmett Facility...............................
Hidden Hollow Landfill Gas.............
Jan,2006
Dec-2007
Oct,2006
Jan-2007
Estimated
Sep-2026
Total Biomass Nameplate MW Rating 43.
Wind Projects
Arrow Rock Wind............................ Dec-2007 Estimated
Burley Butte Wind.............,..,......,.., Dec,2007 Estimated
Cassia Farm................................... Dec-2007 Estimated
Cassia Gulch..........,.........,............. Dec,2007 Estimated
Fossil Gulch Wind........................... Sep-2005 Sep,2025
Golden Valley Wind..................,..... Dec,2007 Estimated
Horseshoe Bend Wind Park........... Feb,2006 Feb-2026
Lava Beds Wind............................. Dec,2007 Estimated
Total Wind Nameplate MW Rating
Contract
Project End Date
Lowline CanaL..............................
Magic Reservoir..............................
Malad River.................,..,................
Marco Ranches...............................
Mile 28.................,..........................
Mitchell Butte..................................
Mora Drop..................................,..,.
Mud Creek S&S,..,..........................
Mud Creek White............................
Owyhee Dam CSPP.......................
Pigeon Cove,.....,.......,.....,.,............
Pristine Springs....,..........................
Pristine Springs #3..............,...,.......
Reynolds Irrigation..........................
Rim View........................,................
Rock Creek #1............,...................
Rock Creek #2................................
Sagebrush................,..,..................
Sahko Hydro...................................
Schaffner...........
,...........,........,.,.....
Shingle Creek....,.......".,.................
Shoshone #2,...........,......................
Shoshone CSPP,.,..........................
Snake River Pottery........................
Snedigar.....................,...,...,.....,.,.,.
Sunshine Power #2.........................
Tiber Dam....................,.,..,.............
Trout-Co.,...,..........,.,.,.,..................
Tunnel #1...........................,............
White Water Ranch...........,............
Wilson Lake Hydro.........................
141.
Simplot Pocatello......................,.....
TASCO-Nampa..............................
TASCO-Twin Falls.........................
Pocatello Waste...........,..................
Tamarack CSPP.............................
Treasure Valley digester.................
Vaagen Brothers Lumber Inc.....,....
Lewandowski Farms.......................
Milner Dam Wind............................
Notch Butte Wind............................
Oregon Trail Wind..,........,..............
Pilgrim Stage Station Wind.............
Salmon Falls Wind....................,.....
Thousand Springs Wind................,
Tuana Gulch Wind......,...................
206.
Geothermal Projects
Raft River Geothermal #1............... Jan,2007 Estimated
Total Geothermal Nameplate MW rating 10.
Total Nameplate MW Rating 438.
On-line Date
May,1985
Jun,1989
May-1984
Aug,1985
Jun,1994
May,1989
Oct-2006
Feb,1982
Jan-1986
Aug,1985
Oct-1984
May-2005
May,2005
May-1986
Nov-2000
Sep,1983
Apr-1989
Sep,1985
Jun-2006
Aug-1986
Aug-1983
May,1996
Jun,1982
Nov-1984
Jan,1985
Dec-1987
Jun,2004
Dec-1986
Jun-1993
Aug-1985
May-1993
Mar-2006
Sep-2003
Aug,2001
Dec,1985
Jun-1983
May,2007
Sep-1995
Mar,2005
Dec-2007
Dec,2007
Dec-2007
Dec-2007
Dec-2007
Dec,2007
Dec,2007
Apr,2005
May-2024
Apr-2019
Jul-2020
May-2029
May-2024
Estimated
Feb,2017
Jan-2021
Aug-2015
Oct,2019
Apr,2015
Apr-2015
May-2021
Non firm
Sep-2018
Mar-2024
Aug-2020
Non firm
Jul-2021
Jul-2018
Apr-2031
Jun-2017
Nov-2019
Dec-2019
Dec,2022
May-2024
Nov,2021
May-2028
Jul,2020
May,2028
Feb,2016
Aug,2008
Aug-2006
Dec-2020
May,2018
Estimated
Aug-2010
Mar-2010
Estimated
Estimated
Estimated
Estimated
Estimated
Estimated
Estimated
Cogeneration and Small Power Production Project (CSPP) Generation Informati
The above is a summary of the Nameplate rating for the CSPP projects under contract with Idaho Power. In the case of CSPP projects,
Nameplate rating of the actual generation units is not an accurate or reasonable estimate of the actual energy these projects will deliver to
Idaho Power. Historical generation information, resource specific industry standard capacity factors, and other known and measurable
operating characteristics are accounted for in determining a reasonable estimate of the energy these projects will produce. The application of
this information to the portfolio of CSPP projects resulted in the average annual MW from CSPP projects being 130 MW.
2006 Integrated Resource Plan Page 47
Appendix 0- Technical Appendix Idaho Power Company
Coal and Natural Gas Price Forecasts Used in Aurora Modeling
($/MMBTU Delivered-Nominal)
Sumas Henry Hub Henry Hub Henry Hub
Wyoming Regional Natural Gas Natural Gas Natural Gas Natural Gas
Year Specific Coal Coal (Expected)(Expected)(High)(Low)
2006 $1.$1.$8.$8.$11.$4.
2007 $1.$1.$8.$8.$10.$4.
2008 $1.$1.$8.$8.$10.43 $4.
2009 $1.$1.41 $7.$8.$10.$5.
2010 $1.$1.45 $5.$6.$9.$5.
2011 $1.$1.49 $5.$6.$9.48 $5.
2012 $1.$1.$6.$6.$9.$5.
2013 $1.$1.$6.$6.$9.$5.78
2014 $1.$1.$6.42 $6.$8.$6.
2015 $1.$1.$6.$6.$9.$6.
2016 $1.$1.$6.$7.$9.$6.
2017 $1.$1.$7.$7.$9.43 $6.
2018 $1.$2.$7.49 $7.$9.$6.40
2019 $1.$2.$7.~8.$9.$6.
2020 $1.40 $2.$8.$8.41 $10.$6.
2021 $1.$2.41 $7.$7.$10.$6.
2022 $1.43 $2.$7.$8.$10.76 $6.
2023 $1.45 $2.$8.$8.$11.$7.
2024 $1.$2.$8.$8.$11.40 $7.
2025 $1.$2.$8.$8.$11.$7.
1 Used in the Aurora analysis for a Wyoming specific coal resource.
2 Used in the Aurora analysis for a non-location specific, regional coal resource.
2006 IRP Fuel Forecast
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
..
i\.
",'".. "
$12
$11
$10
;:) $7
... $5
C.J
-Wyoming Specific Coal-Sumas Natural Gas (Expected)
.. ..
.. Henry Hub Natural Gas (High)
-Regional Coal-Henry Hub Natural Gas (Expected)
.. ..
.. Henry Hub Natural Gas (Low)
Page 48 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Natural Gas Forecast Source Comparison
$/MMBTU (Nominal)
$11.
""'-
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$9.
$8.
$7.
$6.
$5.
$4.
$3.
$2.
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
-NYMEX -IGI Resources ".. -'NPPC-Low -NPPC,Med -NPPC,High -EIA -2006 IRP
Natural Gas Forecast Comparison
$/MMBTU (Nominal)
$11.
/"'
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$9.
$8.00
$7.
$6,
$5.
$4.
$3.
$2.
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
-2006 IRP -2002 IRP -2000 IRP-2004 IRP
2006 Integrated Resource Plan Page 49
Appendix 0- Technical Appendix Idaho Power Company
Coal Forecast Comparison
$/MMBTU (Nominal)
$2.20
""
-f~fJ~
$1.20 --.l
$2.
$1.80
$1.
1 ;
$1.
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
( '
-2006 IRP-Generic Coal
"'--
-2004 IRP -2002 IRP -2000 IRP
" ," ,
Page 50 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
2006 Integrated Resource Plan
Key Financial and Forecast Assumptions
Resource Cost Analysis
Financing Cap Structure and Cost
Composition
~~..........................................."..........,..,........................
Preferred.....,................,..."..,...........,.
......................,.".......
Common.............................................................................
TotaL...,......,......,..................................,.........................
Cost
Debt.,..................................,......................,."....,..............
Preferred......,......,...."...,...",.."......,....""""""""""""""'"
Common...................................,...............................,........
Average Weighted Cos!.............,.,.................................
50.54%
00%
49.46%
100.00%
65%
00%
10.50%
05%
Financial Assumptions and Factors
Plant Operating (Book) Life..................................................... 30 Years
Discount Rate (aka WACC).....................................,....,.......... 6.93%
Composite Tax Rate.........................................,...............,...... 39.10%
Deferred Rate......................................................................... 35.00%
General O&M Esc Rate...................................................,..,.... 3.00%
Emission Adder Esc Rate........................................................ 2.26%
Annual Prop Tax Rate (% if Invest).........,....,.......,.................. 0.41%
Prop Tax Esc Rate............,...................................................... 0.00%
Annual Insurance Prems (% of Invest).......................,............ 0.25%
Insurance Esc Rate................................................................. 5.00%
AFUDC Rate (Annual)...........................,................................. 6.75%
Prod Tax Credits (Firsi 10 years of operations).................,..,.. $19/MWh'
Prod Tax Credits Esc Rate,.................................................,.., 3.00%
1 For those wind and geothermal projects in service by 12,31,2008
Emission Adder Costs (2006 Dollars)
(adders are brought into the analysis beginning in 2012)
CO2..................... $13.62 per ton
NOx..................... $2 600 per ton during May-September
Mercury................ $1 ,443/oz in years 2012-2017; $1 ,731/oz in year 2018 and beyond
CO2....................,
NOx",....,.............
Mercury................
Pulv. Coal
800
00002
Emissions Limits (pounds per MWh by technology)IGCC IGCC w/Seq. CFB Coal717 258 1 8001 1.1 1.00002 0.00002 0.00002
SCCT
164
CCCT
822
2006 Integrated Resource Plan Page 51
Appendix 0- Technical Appendix Idaho Power Company
Fuel Forecast Base Case ($ per MMBTU)
Minemouth
Year Gas Generic Coal Nuclear Biomass Wyoming Coal NW Railed CoalJ
2006 $8.$1.49 $0.40 $2.$1.$1.
2007 $8.$1.48 $0.40 $2.$1.$1.
2008 $8.$1.46 $0.40 $2,$1.$1.
2009 $7.$1.$0.40 $2.$0.$1.
2010 $5.$1.$0.40 $2,$0.$1.
2011 $5.$1.$0.40 $2.$0.$1.
2012 $6,$1.46 $0.40 $2.$1.$1.
2013 $6.24 $1.49 $0.40 $2.$1.$1.
2014 $6.42 $1.$0.40 $2.$1.$1.
2015 $6.$1.$0.40 $2.$1.$1.
2016 $6.$1.$0.40 $2.$1.$2.
2017 $7.$1.$0.40 $2.$1,$2,
2018 $7.49 $1.$0.40 $2.$1.$2.
2019 $7.$1.$0.40 $2.$1.$2.
2020 $8.$1.$0.40 $2.$1.$2.
2021 $7.$1.$0.40 $2.$1.$2.42
2022 $7.$197 $0.40 $2,$1.$2.
2023 $8.$2.$0.40 $2.$1.$2.
2024 $8,$2.$0.40 $2.$1.45 $2.
2025 $8.70 $2.$0.40 $2.$1.$2.
2026 $8.$2.$0.40 $2.$1.$2.
2027 $8.44 $2.$0.$2.$1.44 $3.
2028 $8.$2.$0.40 $2.$1.49 $3.
2029 $9.$2.$0.$2.$1.$4.
2030 $9.48 $3.$0.40 $2.$1.$4.
2031 $9.$3.21 $0.40 $2.$1.$4.
2032 $9.$3.$0.$2.$1.$4.
2033 $9.$3.47 $0.40 $2.$1.$5.
2034 $10.$3.$0.40 $2.$1.$5.
2035 $10.$3.77 $0.40 $2.$1,$5.
1 Used to estimate costs in the resource stack for the southern Idaho pulverized coal resource.
2 Used to estimate costs in the resource stack for the Wyoming pulverized coal resource,
J Used to estimate costs in the resource stack for the regional pulverized, regional ftuidized bed, regionallGCC with carbon sequestraUon, and regionallGCC coal projects.
Page 52 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
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Appendix 0- Technical Appendix Idaho Power Company
Levelized Resource Cost Tables
Energ Levelized Cost per Mwh
Cost of Capital Non-Fuel O
26.91 9.
26.91 21.
33.52 15.
41.25 12.
39.66 16.49
12.75 9.
54.34 6.49
28.95 9.
28.95 9.
24.78 9.
39.66 28.
31,03 10.
54.34 18.
44,71 13.
10.38 7.4739.44 11.
67.05 14.31.49 36.72
10.71 9.43
15.31 17.83.48 33.
173.73 23.
Supply-Side Resources
Geothermal Flash Steam with PTC (50 MW).................................
Geothermal Flash Steam without PTC (50 MW)............................
Advanced Nuclear (1 100 MW)......................................................
Small Hydro Existing Facility (10 MW).......................................,...
Geothermal Binary Cycle with PTC (50 MW)...............,.................
Combined Heat and Power (6 MW).....,.........................................
Wind with PTC (100 MW)..............................................................
Wyoming Pulverized Coal (575 MW).............................................
Regional Pulverized Coal (600 MW)..............................................
South Idaho Pulverized Coal (600 MW).........................................
Geothermal Binary Cycle without PTC (50 MW).......................,....
Regional Fluidized Bed Coal (600 MW)..,......................................
. Wind without PTC (100 MW).........................................................
RegionallGCC with Carbon Sequest. (600 MW)...........................
CCCT (540 MW)...........................................,...........,....................
RegionallGCC (600 MW).........................,...................................
Small Hydro New Facility (10 MW)..................,..............................
Wood Residue Biomass (25 MW).................................,................
Industrial Simple Cycle CT (162 MW).....................,......................
Aero Simple Cycle CT (47 MW).....................................................
Solar Thermal (100 MW)...............................................................
Solar Photovoltaic (5 MW)........................................................,....
Fuel Emission Adders Total
36.
48.
4.41 53.
53.
56.
38.60.
60.
11.11.60.
16.11.66.
21.11.67.
68.
17.11.70 70.
73.
15.76.
53.76.
15.10.77.29
81.
29.98.
80.107.
76.115.
117.
196.
Energy Emission Adders Total
60.64.
60.69.
60,76.
60.76.
60.78.
60.79.49
60.79.
60.81.70
60.81.74
60.81.
Fuel Emission Adders Total
34.
39.
43.
. '
Transmission Plus Market Purchase Alternatives
Transmission-From NW Lolo to IPC System (60 MW)..................
Transmission-From NW McNary to IPC System (180 MW)...........
Transmission-From NW McNary to Boise (180 MW).....................
Transmission-From Montana to IPC System (225 MW)................
Transmission-From Montana to Boise (225 MW)..........................
Transmission-From Wyoming to IPC System (225 MW)...............
Transmission-From Nevada South to IPC System (225 MW)......,
Transmission-From Wyoming to Boise (225 MW).........................
Transmission-From NW Lolo to Boise (60 MW)............................
Transmission-From Nevada South to Boise (225 MW).................
Cost of Capital
14.
14.
16.
17.
18.
19.
19.
20.
Non-Fuel O
1.46
DSM Programs
Commercialln,Place Construction (18 aMW)...........,....................
Industrial Efficiency Expansion (41 aMW),.....................................
Residential In, Place Construction (29 aMW).................................
Cost of Capital Non-Fuel O&M
34.
39.
43.
( ,
Page 58 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Supply-Side Resources
Industrial Simple Cycle CT (162 MW)............................................
CCCT (540 MW).....................................,......................................
Aero Simple Cycle CT (47 MW).........................,..,........................
Combined Heat and Power (6 MW)...............................................
Wind (100 MW).......,......................................................................
South Idaho Pulverized Coal (600 MW).......,.................................
Small Hydro Existing Facility (10 MW)..........................................,
Regional Pulverized Coal (600 MW)..............................................
Wyoming Pulverized Coal (575 MW).............................................
Regional Fluidized Bed Coal (600 MW).................,.,.....................
RegionallGCC (600 MW)......................................,.......................
Wood Residue Biomass (25 MW).................................,................
RegionallGCC with Carbon Sequest. (600 MW)...........................
Advanced Nuclear (1 100 MW)..............................,.......................
Geothermal Flash Steam (50 MW).....,..........................................
Small Hydro New Facility (10 MW).................................................
Solar Thermal (100 MW)...............................................................Solar Photovoltaic (5 .MW)...,..,.,.,.",.............................................
Geothermal Binary Cycle (50 MW)..,............................................,
Levelized Resource Cost Tables
Capacity- Levelized $/kWimonth
Cost of Capital Non-Fuel O&M61 1.226.44 1.58 1,38 1.12.43 3.
15.92 3.
18.19 3,
18.59 3.
18.60 3.
19.93 4.
23.03 4.
18.39 12.
26.11 5.40
22.02 9.
18.67 15.
29.56 4.
25.60 10.
38.05 5.
27.51 18.
Fuel Emission Adders Total
16.40
19.
21.
22.46
22.46
24.
27.
31.
31.
31.
33.
33.
35.
43.
45,
Energy Emission Adders Total
7.20
Fuel Emission Adders Total
13.
15.
16.
Transmission Plus Market Purchase Alternatives
Transmission-From NW Lolo to IPC System (60 MW)..................
Transmission-From NW McNary to IPC System (180 MW)...........
Transmission-From NW McNary to Boise (180 MW).....................
Transmission-From Montana to IPC System (225 MW).....,..........
Transmission-From Montana to Boise (225 MW)..........................
Transmission-From Wyoming to IPC System (225 MW)...............
Transmission-From Nevada South to IPC System (225 MW).......
Transmission-From Wyoming to Boise (225 MW).....................,...
Transmission-From NW Lolo to Boise (60 MW)............................
Transmission-From Nevada South to Boise (225 MW).................
Cost of Capital Non-Fuel O&M
0.78
DSM Programs
Commercialln,Place Construction (34 MW Peak).........................
Industrial Efficiency Expansion (76 MW Peak)...,...........................
Residentialln,Place Construction (55 MW Peak)...,......................
Cost of Capital Non-Fuel O&M
13.
15.
16.
2006 Integrated Resource Plan Page 59
Appendix 0- Technical Appendix Idaho Power Company
Brownlee Reservoir Inflow Record (Million Acre-Feet)
Record Used for 2006 IRP Modeling of Idaho Power Hydropower System
Based on (1) Idaho Department of Water Resources computed Snake River Basin record for January 1928-September 2002
and (2) observed streamflow record for October 2002-December 2004.
Brownlee April-July Brownlee Annual Brownlee April-July Brownlee Annual
Inflow Volume (MAF)Inflow Volume (MAF)Inflow Volume (MAF)Inflow Volume (MAF)
1928 15.1967 11.
1929 3.4 1968 3.4 10.
;- ,
1930 8.4 1969 15.
1931 1970 14.
1932 10.1971 10.22.
1933 1972 20.
1934 2.4 1973 11.4
1935 20.1974
1936 10.1975 17.
1937 1976 16.
1938 13.1977
1939 10.1978 12.
1940 10.1979 10.
1941 10.2 1980 13.
1942 11.1981 11.
1943 18.1982 21.
1944 1983 10.23.
1945 11.1984 11.4 24.4
1946 15.1985 13.
1947 12.1986 8.4 20.
1948 12.1987 9.4
1949 12.1988
1950 6.4 14.1989 10.
1951 16.1990
1952 10.19.4 1991
1953 13.1992
1954 12.1993 12.
1955 1994
1956 17.1995 14.
1957 16.1996 19.
1958 7.4 15.1997 10.24.
1959 10.4 1998 8.4 17.
1960 10.1999 17.
1961 2000 11.
1962 10.2001 2.4
1963 11.2002 3.4
1964 13.2003
1965 8.4 19.2004
1966 10.
c.,.
Page 60 2006 Int~grated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Wind Distribution Profile (from NWPCC's Fifth Power Plan-2005)
Project Size (MW): 100
Annual Capacity Factor: 35%
Flat Monthly Output (aMW): 35
Normalized Monthly Wind Energy Distribution (Basin and Range)
Annual
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average
Estimated Monthly Output (aMW)
Annual
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average
Normalized Monthly Wind Energy Distribution (Basin and Range)
1.40
0.40
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nav Dee Annual
Average
2006 Integrated Resource Plan Page 61
Appendix 0- Technical Appendix Idaho Power Company
DS~Jl Analysis and Screening Criteria
DSM Program Development
In November 2004, Quantum Consulting of Berkeley, California, (now Itron Inc. of Oakland
California) completed a study for Idaho Power assessing the energy savings potential within the
residential and commercial sectors. The study served as the basis for the residential and commercial
retrofit program options analyzed in this IRP. The Company filed the Quantum study with the IPUC in
December 2004 as an addendum to the 2004 IRP. In order to meet the guidelines of the 2006 IRP, the
study output was later expanded with support from Quantum for program extension from 10 to 20 years
of utility operation.
/ '
The assumptions and energy estimates that support the industrial efficiency program extension were
developed internally by Idaho Power s engineering staff. The industrial program expansion and the
residential and commercial retrofit program options were each designed to maximize the potential
energy benefits of the resource while remaining cost-effective from a total resource perspective.
All DSM program options analyzed as part of the 2006 IRP included the following cost components:
( .
Administrative costs
Marketing and advertising costs
Incentive payments
Participant costs
, '. '
Once the program design and costing phase was completed, each new program was put through a series
of static screening analyses prior to being introduced into the dynamic IRP portfolio analysis in Aurora.
Screening Criteria
DSM screening criteria are designed to assess a program s potential to maximize benefits at the lowest
cost for all stakeholders. In addition to the strategic criteria listed in Chapter 5 of the 2006 IRP Plan, key
screening elements are:
, )
Programs will be cost-effective. From a total resource perspective, estimated program benefits
must be greater than estimated program costs.
Programs will be customer-focused. From the participants' perspective, programs will offer real
benefits and value to customers. The Idaho Public Utilities Commission stated in Order
No. 29026
, "
It is our hope that the programs created by the DSM rider will empower customers
to exercise control over their energy consumption and reduce their bills.
Programs will be equitably distributed. From the customers ' perspective, programs will be
selected to benefit all groups of customers. Over time, programs will be offered to customers in
all sectors and in all regions of the company s service territory.
Programs will be as close to earnings-neutral as possible. From the utility s perspective
programs will be selected to minimize the negative impact on shareowners.
Page 62 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
These criteria are used as guidelines in selecting a new program or initiative. A program that doesn
meet all of these criteria is not excluded from consideration, but would have to be further evaluated for
other valued characteristics. Ultimately, all programs must be cost-effective in order to be considered as
ordered by the IPUC.
Static Cost-Effectiveness Analysis
The cost-effectiveness analysis is the primary focus of the screening criteria. The static cost-
effectiveness analysis of DSM programs at Idaho Power is performed using the methods described in the
EPRI End-Use Technical Assessment Guide Manual as well as The California Standard Practices
Manual: Economic Analysis of Demand-side Programs and Projects.2 The proposed DSM programs
considered for inclusion into the 2006 IRP are evaluated from Utility Cost Test and Total Resource Cost
test perspectives.
Total Resource Cost Test (TRC) 3
The TRC test is a measure of the total net resource expenditures of a DSM program from the point
of view of the utility and its customers as a whole. Costs include changes in supply costs, utility
costs, and participant costs. (Transfer payments between customers and the utility are ignored).
The following are the calculations performed by this test:
Net Present Value: A net present value of zero or greater indicates that the program is cost-
effective from the total resource cost perspective.
Benefits-Cost Ratio: A benefit-cost ratio of 1.0 or greater indicates the program is cost-effective
from the total resource cost perspective.
Levelized Cost: This measurement makes the evaluation of potential demand-side resources
comparable to that of supply side resources. The cost stream of DSM resource (in this case, the
stream of utility costs and participant costs) is discounted and then divided by the stream of
discounted kW or kWh that is expected from the program.
Utility Cost Test
The Utility Cost test is a measure of the total costs to the utility to implement a DSM program.
IPUC Order No. 29026, May 20, 2002
2 www.cpuc.ca.gov/static/energy/electric/ energy+efficiency /ru lemaki ng/ std + practice+ ma n ua I. d oc
3 EPRI End-Use Technical Assessment Guide (End-Use TAG), Volume 4: Fundamentals and Methods, Barakat and
Chamberlin, Inc, April 1991
4 EPRI End-Use Technical Assessment Guide (End-Use TAG), Volume 4: Fundamentals imd Methods, Barakat and
Chamberlin, lnc, April 1991
2006 Integrated Resource Plan Page 63
Appendix 0- Technical Appendix Idaho Power Company
The following are the calculations performed by this test:
Net Present Value: A net present value of zero or greater indicates that the program is cost-
effective from the Utility Cost perspective.
( ,
Benefits-Cost Ratio: A benefit-cost ratio of 1.0 or greater indicates the program is cost-effective
from the Utility Cost perspective.
Levelized Cost: This measurement attempts to put demand side resources on equal ground with
supply-side resources. As with supply-side resources, the cost stream ofDSM resource is
discounted and then divided by the stream ofkW and kWh that is expected from the program.
Payback: Number of years required for the energy benefits to equal the participants' costs for a
program.
DSM Analysis Calculation Definitions
Net Present Value: Calculated as the discounted stream of program benefits minus the discounted
. stream of program costs using the Company s weighted average cost of capital (WACC) for resource
planning.
Program Benefits
T=I (l+WACC)t-
(minus)Program Costs
T=I (1+ WACC)t'
Where: N = the total number of years, t = the incremental year, and W ACC = the Company
weighted average cost of capital.
Benefits-Cost Ratio: Calculated as the discounted stream of program benefits divided by the
discounted stream of program costs.
ProQram Benefits
t=1 (1+ WACC)t,
ProQram Costs
t=1 (1+ WACC)t-
Levelized Costs: The present value of total costs of the resource over the life of the program in the
base year divided by the discounted stream of energy or demand savings, depending on how the
resource size has been defined.
PrOQram Costs
T=l (1+WACC)t-
EnerQV SavinQs
T=I (1+ WACC)t,
Payback:, Number of years from the initial program participation to the point at which the
cumulative benefits exceed the cumulative undiscounted costs for participants.
\ ,
Page 64 2006 Integrated Resource Plan
Idaho Power Company Appendix D-Technical Appendix
Incremental Costs: The additional cost incurred by choosing to select one option over another.
Total Installed Cost of Energy Efficient Option
Total Installed Cost of a Non-Energy Efficient Option
~ Incremental Cost
Program Benefits Calculations
To quantify the "benefit" portion of the calculation five costing periods were created for the year that are
consistent with the IPUC approved rate schedule 19 tariff rate pricing periods. Each costing period
contains a price that reflects the alternative cost of energy and capacity at the associated time period.
The alternative cost represents the cost of energy resources that would most likely be the alternative at
that time period. Each time segment has a different alternative cost associated with it depending on the
expected price for that period.
Two methodologies were developed, at the request of the IRP AC, to evaluate the potential benefits
associated with alternative supply costs: peak oriented (gas turbine) and baseload oriented (thermal
plant) resource alternatives.
The peak alternative resource methodology employs five costing periods for each year to reflect the
market dynamics impacting costs associated with different times of the day or seasonally. Each costing
period contains a price that reflects the alternative cost of energy and capacity at the associated time
period. The alternative cost represents the cost of energy resources that would most likely be an
alternative including peak plant or the market cost of energy depending upon the load profile associated
with the program. Each time segment has a different alternative cost associated with it depending on the
expected price for that period. The baseload alternative utilized the capacity and variable cost associated
with a thermal (coal plant) alternative which applied to all hours of the year.
The results of the analyses showed all programs to be cost-effective under both the peak and the
baseload alternative resource cost methodologies. All programs showed greater benefits associated using
the peak resource alternative, however, the industrial efficiency program showed the showed highest
benefits using the baseload analysis. This benefit differential is attributable to the unique seasonal load
profiles associated with each program.
2006 Integrated Resource Plan Page 65
Appendix 0- Technical Appendix . Idaho Power Company
The following tables illustrate the time of day and time of year costing period definitions used in the
peak static program screening analysis:
SUMMER SEASON
June' 1 through August 35
Hour Sunday Monday Tuesday Wednesday Thursday Friday Saturday Holiday
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SMP SMP SMP SMP SMP SMP SMP SMP
SMP SMP SMP SMP SMP SMP . SMP SMP
SMP SMP SMP SMP SMP SMP SMP SMP
SMP SMP SMP SMP SMP SMP SMP SMP
SMP SMP SMP SMP SMP SMP SMP SMP
SMP SMP SMP SMP SMP SMP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SONP SONP SONP SONP SONP SMP . SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP "
SMP SMP SMP SMP SMP SMP SMP SMP
SMP SMP SMP SMP SMP SMP SMP ' SMP
SOFP,SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
( 1
- ,, ;
SOFP = Summer Off-Peak
SMP = Summer Mid-Peak
,~)
SONP = Summer On-Peak
" ,
Page 66 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Hour Sunday
NSOFP
NSOFP
NSOFP
NSOFP
NSOFP6 '' NSOFP
NSOFP
8 NSOFP
NSOFP
10 ":NSOFP
11 "NSOFP,
12 I NSOFP,13 NSOFP14 '. NSOFP
15 NSOFP16 "NSOFP
17 'NSOFP ;18 NSOFP,19 NSOFP20 NSOFP .
NSOFP.
22 'NSOFP ;.23 "" NSOFP
24 NSOFP
' ,
Monday
NSOFP
NSOFP
NSOFP
NSOFP
NSOFP
NSOFP
NSMP
NSMP
NSMP
NSMP
NSMP
NSMP
NSMP
NSMP
NSMP
NSMP
NSMP
NSMP
NSMP
NSMP
NSMP '
NSMP
NSOFP
iNSOFP ,
NON-SUMMER SEASON
September 01 through May
Tuesday Wednesday Thursday Friday Saturday Holiday
NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
NSOFP" NSOFP NSOFP NSOFP :NSOFP NsOFP '
NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
NSQFP NSOFP ," NSOFP ;NSOFP NSOFP.NSOFP
NSOFP NSOFP ' NSOFP "NSOFP,.,:NSOFP) :'NSQFP;
NSOFP NSQFP NSOFP " JNSOFP NSOFP ;,/NSOFP.NSMP NSMP , NSMP NSMP NSMP ;NSOFPNSMP NSMP NSMP NSMP NSMP /NSOFP~NSMP NSMP NSMP NSMP ," NSMP :.NSQEP.,NSMP NSMP NSMP NSMP NSMP ;:;NSPFRi'NSMP NSMP NSMP NSMP NSMP ";iNSbFP~NSMP NSMP NSMP NSMP "NSMP, ~)&~$QFR.ftiNSMP NSMP NSMP ." NSMP NSMP "NSOFP;
:::
NSMP NSMP" NSMP NSMP NSMP ~;NSO~H.NSMP NSMP , NSMP NSMP NSMP JitiSOFR,NSMP NSMP ,NSMP NSMP NSMP ~$QF!It2'NSMP NSMP "' NSMP NSMP NSMP ;;;l\JSQFR;;:NSMP NSMP NSMP "NSMP NSMP ,
' :,
~\\Nsbpp;
NSMP" NSMP NSMP NSMP NSMP ", ;iijSrSQ.f,p?;NSMP NSMP NSMP NSMP ; NSMP NSOFPNSMP, NSMP NSMP NSMP NSMP.1i~NSOFR~*i
NSMP "NSMP NSMP NSMP NSMP ;~:;:NSQFJ?t:i~;
NSOFP:NSOFP' 'NSOFP' 'Ns6FP~'~.~:;N$OFP';;X?#N;SQ5PJ~
. ,.
NSOFP, NSOFP ,NSOFP " :NSOFP:,'NSOFP"2"'NSOFP,
NSOFP = Non-Summer Off-Peak
NSMP = Non-Summer Mid-Peak
Market prices were developed within Aurora using the Preferred Portfolio as a resource basis (May
Aurora 2006IRP _hrly_zone."prices 20yr So Idaho). The values beyond 20 years are extended by
escalating the final year of the forward market price schedule for the additional years needed for the
analysis using the Company s escalation rate of 3.0% for capital investments.
The costing period prices are calculated using the following method:
. NSMP = Average of heavy load prices in January-May and September-December.
. NSOFP = Average of light load prices in January-May and September-December.
SOFP = Average of light load prices in June-August.
. SMP = Average of heavy load prices in June-August.
SONP = IPC variable energy and operating cost of a 162 MW Simple-Cycle Gas Turbine
Annual = IPC variable energy and operating cost of thermal coal plant
2006 Integrated Resource Plan Page 67
Appendix 0- Technical Appendix Idaho Power Company
The following table shows the schedule of variable and market alternative costs used to calculate the
benefit value of each program in the static analysis:
Year
IPC Variable
Peak Cost
$/KW
SONP
$91.
$95.
$88.
$88.
$67.
$67.
$68.
$71.
$73.
$75.
$78.
$82.
$85.26
$89.
$92.
$86.
$89.
$93.
$95.
$99.47
$93.
$97.
$100.
$104.46
$108.
$110.
$112.
$114.
$115.71
$117.42
. Alternative Energy Cost
Seasonal Market Price Forecast ($/MWh)SMP SOFP NSMP NSOFP .
$68.57 $51.54 $77.61 $65.
$69.89 $51.61 $78.95 $65.
$65.98 $48.07 $68.96 $55.
$66.39 $48.52 $68.15 $55.
$50.43 $37.03 $52.75 $42.
$55.93 $41.28 $54.30 $42.
$67.85 $50.72 $64.61 $51.
$71.71 $54.18 $68.18 $54,
$74.02 $56.01 $70.06 $56.
$78.45 $59.19 $74.07 $59.
$82.40 $62.08 $78.96 $63.
$90.38 $66.94 $86.37 $69.
$92.36 $70.70 $90.27 $72.
$98.01 $75.25 $95.24 $76.
$102.92 $79.15 $100.11 $80.
$97.28 $75.60 $94.42 $76.
$104.05 $80.51 $101.25 $81.
$108.84 $84.94 $105.87 $85.
$114.48 $90.26 $111.23 $90.
$120.35 $96.05 $118.21 $95.
$123.96 $98.93 $121.75 $98.42
$127.68 $101.90 $125.40 $101.
$131.51 $104.95 $129.17 $104.41
$135.46 $108.10 $133.04 $107.
$139.52 $111.35 $137.03 . $110.
$143.71 $114.69 $141.14 $114.
$148.02 $118.13 $145.38 $117.
$152.46 $121.67 $149.74 $121.
$157.03 $125.32 $154.23 $124.
$161.74 $129.08 $158.86 $128.42
Fixed plant costs were combined with the variable costs for developing total alternative costs. For the
peak alternative, a 162MW Simple Cycle Combustion Turbine plant was used as the cost basis, for the
baseload alternative, a coal thermal plant served as the cost basis. The levelized capacity cost factors
applied were $64.92/KW (peak) and $247.52(baseload).
DSM program analysis includes the assumption that the energy savings will continue beyond the
measure life time period for each program participant. This assumption is based on the principle that it is
reasonable to assume that once a person participates in the program, they will not revert back to a less
efficient behavior after the measure life expires. As a result, the energy savings schedule for each
program shows a ramp-up period followed by a sustained maximum level for the entire analysis period.
In the 2004 IRP the total period for analysis was 20 years. For the 2006 IRP this period was 30 years.
Page 68 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Dynamic Modeling
The results of the levelized cost analysis showed that the proposed DSM programs had sufficiently
lower costs than all but the geothermal supply-side resources. This result allowed the DSM portfolio to
be included in the dynamic modeling (Aurora simulation model) as a fixed resource for all supply-side
alternative portfolio analyses. This approach differs from the analysis in the 2004 IRP where the
programs were introduced in an equivalent manner as were the supply-side resources to determine the
beneficial impacts to the overall resource portfolio.
The following tables show the annual costs and energy savings associated with the DSM programs.
Energy Savings
MWh (Net of Transmission Losses)
All Residential Commercial Industrial
Year Programs Retro Retro Expansion
2006
2007 280 6,462 817 000
2008 753 639 24,451 663
2009 158 607 980 301 39,327
2010 244 160 554 615 58,990
2011 320,054 134 876 106,525 653
2012 387,019 165 874 122 828 316
2013 446 812 192 391 136,441 117 980
2014 499 130 214,746 146 741 137 643
2015 544 700 233,456 153 938 157 306
2016 585 249 249 083 159 197 176 970
2017 604 010 248 180 159 197 196,633
2018 624 520 248,987 159 237 216 296
2019 645,510 249 796 159 754 235 960
2020 666 299 250,483 160 193 255,623
2021 686 887 251 047 160 554 275 286
2022 707 270 251,486 160 835 294 949
2023 727 346 251 738 160 996 314 613
2024 747 319 251 926 161 116 334 276
2025 767 085 251 989 161 157 353,939
2026 786,749 251 989 161 157 373,603
2027 786 749 251 989 161 157 373 603
2028 786 749 251 989 161 157 373 603
2029 786 749 251 989 161 157 373 603
2030 786 749 251 989 161 157 373 603
2031 786 749 251 989 161 157 373 603
2032 786 749 251 989 161 157 373 603
2033 786 749 251 989 161 157 373 603
2034 786 749 251 989 161 157 373 603
2035 786 749 251 989 161 157 373,603
2036 786,749 251 989 161 157 373 603
2006 Integrated Resource Plan Page 69
Appendix 0- Technical Appendix
Year
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
All
Programs
7.4
18.
27.
36.
44.
51.
57.
62.2
66.
69.
71.
73.
76.
78.4
80.
83.
85.
87.
89.
89.
89.
89.
89.
89.
89.
89.
89.
89.
89.
Average Peak Reduction
aMW (Net of Transmission Losses)
Residential
Retro
Commercial
Retro
Idaho Power Company
Industrial
Expansion
11.
13.
15.
18.
20.
22.4
24.
26.
29.2
31.4
33.
35.
38.
40.4
42.
42.
42.
42.
42.
42.
42.
42.
42.
42.
42.
\.j
2.4
11.4
15.4
18.
22.
24.
26.
28.4
28.
28.4
28.
28.
28.
28.
28.
28.
28.
28.
28.
28.
28.
28.
28.
28.
28.
28.
28.
28.
12.
14.
15.
16.
17.
18.2
18.
18.
18.
18.
18.
18.4
18.4
18.4
18.4
18.4
18.4
18.4
18.4
18.4
18.4
18.4
18.4
18.4
18.4
18.4
...
Page 70 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
July Peak Reduction
aMW (Net of Transmission Losses)
All Residential Commercial Industrial
Year Programs Retro Retro Expansion
2006
2007 4.4
2008 15.
2009 44.29.
2010 70.48.14.4
2011 91.63.4 17.10.
2012 110.4 76.20.7 13.
2013 126.88.22.15.
2014 140.97.24.18.
2015 152.105.25.20.
2016 162.112.26.23.
2017 165.112.2 26.26.
2018 167.112,26.28.
2019 170.112.4 26.31.4
2020 173.112.26.34.
2021 176.112.27.36.
2022 179.112.27.39.
2023 181.113.27.41.
2024 184.113.27.44.
2025 187.113.27.47.
2026 189.113.27.49.
2027 189.113.27.49.
2028 189.113.27.49.
2029 189.113.27.49.
2030 189.113.27,49.
2031 189.113.27.49.
2032 189.113.27.49.
2033 189.113.27.49.
2034 189.113.27.49.
2035 189.113.27.49.
2036 189.113.27.49.
2006 Integrated Resource Plan Page 71
Appendix 0- Technical Appendix Idaho Power Company
Utility Costs
(000'2006 dollars)
All Residential Commercial Industrial
Year Programs Retro Retro Expansion
2006
2007 679 363 $1,408 $908
2008 $6,437 $2,860 102 $1,475
2009 $19,281 $10 728 723 830
2010 $19,186 $10 793 608 $3,785
2011 $18 753 $10 517 529 707
2012 $18 067 898 539 631
2013 $17 854 148 655 050
2014 $16 424 $8,382 078 964
2015 $14 923 663 379 880
2016 $14 336 021 064 251
2017 $5,414 $750 $505 159
2018 274 $750 $454 069
2019 $5,104 $713 $409 982
2020 343 $675 $368 300
2021 $5,212 $675 $331 206
2022 051 $638 $298 115
2023 895 $600 $268 027
2024 745 $563 $241 941
2025 947 $525 $217 205
2026 797 $488.$196 114
- .
Page 72 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Total Resource Cost
(000'2006 dollars)
All Residential Commercial Industrial
Year Programs Retro Retro Expansion
2006
2007 349 992 037 320
2008 $15,496 $5,448 562 $5,486
2009 $33 912 $16 185 $10 002 725
2010 $32 708 $16 210 931 567
2011 $30 965 $15 693 894 378
2012 $29,068 $14 651 223 195
2013 $27,843 $13,405 927 511
2014 $25 318 $12 142 852 324
2015 $22 796 $10 962 693 142
2016 $21,407 913 077 $7,418
2017 $9,508 550 $725 233
2018 $9,044 367 $622 054
2019 612 193 $538 880
2020 630 048 $469 113
2021 305 $956 $412 $6,938
2022 985 $854 $363 767
2023 691 $768 $321 602
2024 $7,426 $699 $286 $6,441
2025 525 $638 $255 632
2026 282 $583 $228 $6,470
DSM Portfolio Options-2006 IRP
Present Value
Savings *Costs (OOOs)Levelized Costs
Summer Annual Utility TRC TRC
Peak Energy Cost Cost (S/kWh)(S/kWh)
aMW MWh
Residential
Existing 113 251 926 $63 768 $96 372 $0.$0.
Commercial
Existing 161 157 $31 903 $54 381.$0.$0.
Industrial
Expansion 373,603 $48 334 $88,856 $0.$0.
Total H:Sf fl:!b bl:!b :ti144 UUt!:tiLj~bU~
Payback
B/C Ratio
TRC
3.4
3.4
* Based on Cumulative Savings in 2025
** Based on December 2005 Rate Schedule
2006 Integrated Resource Plan Page 73
Appendix 0- Technical Appendix Idaho Power Company
Monthly Average Energy SurpluslDeficiency Data
th Percentile Water, 50th Percentile Load, 90th Percentile Peak-Hour LoadFeb March ril June Jul666 437 556 285 232 668 505 650 263 119 643 485 752 230 99 572 455 724 190 84 495 422 603 163 61 535 413 597 134 24 492 393 579 114 (21) 422 359 551 82 (65) 347 321 515 43 (121) 255 288 485 (171) (34) 180 255 455 (225) (83) 104 222 425 (277) (134) 69 188 394 (11) (331) (187) 34 153 362 (46) (384) (240) (25)118 331 (81) (1) (440) (296) (69)(37) 82 298 (117) (49) (497) (353) (114)(74) 45 265 (154) (99) (559) (409) (160)(111) 231 (192) (149) (619) (468) (207)(147) (29) 197 (230) (201) (678) (528) (255)(187) (67) 163 (269) (253) (741) (590) (303)
Year
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Year
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Year
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Jan
(65)
(103)
(142)
(181)
(221)
(260)
Jan
(18)
(53)
(89)
(126)
(163)
(200)
(239)
(278)
(318)
(357)
(398)
Jan
(29)
(110)
(144)
(186)
(221)
(257)
(294)
(331)
(368)
(407)
(446)
(486)
(525)
(566)
th Percentile Water, 70th Percentile Load, 90th Percentile Peak-Hour LoadFeb March ril June Jul326 370 201 83 (35) 319 438 294 62
~~
255 417 396 29 185 386 368 (15) 107 354 247 (67) 118 355 220 (93) 75 335 201 (11) (128) 296 173 (43) (173) (1) 213 137 (82) (229) (57) (15) 153 106 (117) (32) (281) (109) (31)(46) 120 76 (150) (76) (335) (158) (72)(82) 87 45 (184) (120) (388) (210) (114)(117) 52 14 (219) (166) (443) (264) (157)(153) 17 (17) (255) (215) (497) (318) (200)(186) (71) (291) (261) (554) (375) (244)(225) (32) (108) (328) (310) (611) (432) (290)(262) (70) (141) (365) (360) (675) (489) (337)(300) (107) (175) (404) (411) (736) (549) (384)(336) (145) (210) (442) (465) (796) (610) (433)(377) (184) (245) (482) (518) (859) (672) (481)
th Percentile Water, 70th Percentile Load, 95th Percentile Peak-Hour LoadFeb March ril June Jul224 35 10 (97) (12) 285 128 (150) (20) 192 230 (32) 153 202 (4) (77) (13) 121 81 (32) (129) (0) (33) 94 53 (63) (155) (25) (50) 74 34 (85) (190) (59) (87) 40 (117) (235) (103) (29)(119) (29) (156) (41) (291) (159) (77)(160) (97) (191) (83) (343) (211) (121)(191) (159) (224) (127) (397) (260) (162)(227) (228) (258) (171) (450) (312) (204)(262) (13) (285) (293) (217) (505) (366) (247)(298) (48) (317) (329) (266) (559) (420) (290)(331) (83) (349) (365) (312) (616) (477) (334)(370) (119) (382) (402) (361) (673) (534) (380)(407) (157) (415) (439) (411) (737) (591) (427)(445) (194) (449) (478) (462) (798) (651) (474)(481) (232) (484) (516) (516) (858) (712) (523)(522) (271) (519) (556) (569) (921) (774) (571)
1 Final values after thermal peaking resources were applied.
Page 74
Oct
196
180
157
125
(81)
(129)
(167)
(205)
(245)
(285)
(325)
(366)
Oct
154
139
115
(28)
(63)
(99)
(135)
(172)
(210)
(249)
(289)
(329)
(369)
(411)
Oct
(11 )
(69)
(114)
(151)
(188)
(222)
(258)
(295)
(335)
(372)
(412)
(452)
(494)
(534)
Nov
(8)
(44)
(81)
(118)
(157)
(195)
(234)
Nov
(87)
(145)
(185)
(219)
(253)
(287)
(322)
(358)
(394)
(432)
(470)
(508)
(547)
(586)
Nov
(42)
(90)
(113)
(146)
(186)
(220)
(254)
(288)
(323)
(359)
(395)
(433)
(471)
(509)
(548)
(587)
Dee
159
152
121
109
(38)
(75)
(112)
(150)
(189)
(228)
(268)
(308)
(348)
Dee
(7)
(43)
(79)
(116)
(153)
(191 )
(229)
(269)
(308)
(349)
(389)
(430)
...
t )
Dee
(14)
(55)
(91)
(127)
(164)
(201)
(239)
(277)
(317)
(356)
(397)
(437)
(478)
2006 Integrated Resource Plan
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Appendix 0- Technical Appendix Idaho Power Company
Monthly Peak-Hour Load Deficiency Data
th Percentile Water, 50th Percentile Average Load, 90th Percentile Peak-Hour LoadJan Feb March April May June July Aug Sept Oct(64) (175) (131) (263) (42) (177) (319) (13) (96) (225) (383) (270) (78) (159) (287) (467) (187) (105) (225) (359) (525) (204) (187) (281) (428) (595) (265) (242) (348) (501) (678) (325) (470) (417) (588) (770) (427) (371) (478) (660) (859) (712) (485) (545) (751) (951) (622) (527) (611) (835) (1 044) (669) (538) (674) (920) (1 170) (785) (646)
(745) (1 000) (1 232) (840) (871)
(671) (1 138) (1 323) (961) (771) (28) (872) (1 166) (1,470) (1 075) (801) (71) (940) (1 263) (1 522) (1 164) (922) . 0(113) 0 (1 007) (1 352) (1 681) (1 197) (972) (159) 0 (1 072) (1,435) (1 800) (1 313) (1 049) (204) 0 (1 145) (1 531) (1 827) (1,417) (1 097)
th Percentile Water, 70th Percentile Average Load, 95th Percentile Peak-Hour LoadJan Feb March April May June July Aug Sept Oct(15) (85) (213) (20) (60) (154) (302) (20) (32) (112) (196) (357) (59) (80) (173) (256) (426) (324) (152) (236) (321) (512) (245) (209) (303) (383) (567) (270) (265) (361) (452) (663) (339) (324) (422) (528) (723) (364) (543) (494) (608) (815) (478) (450) (561) (692) (907) (771) (570) (627) (775) (998) (691) (612) (692) (859) (1 092) (738) (649) (759) (944) (1 254) (865) (734) (36) (825) (1 028) (1 283) (884) (953) (83) (770) (1 227) (1 379) (1 036) (850) (129) (961) (1 200) (1 558) (1 143) (907) (173) 0 (1 029) (1 288) (1 577) (1 236) (1 017) (216) (5) 0 (1 094) (1 375) (1 773) (1 246) (1 064) (259) (54) 0 (1 163) (1,464) (1 898) (1 368) (1 150) (306) (108) 0 (1 231) (1 553) (1 886) (1,478) (1 185)
Year
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Year
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Year
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
th Percentile Water, 70th Percentile Average Load, 95th Percentile Peak-Hour LoadJan Feb March April May June July Aug Sept Oct(32) (116) (243) (74) (102) (75) (215) (366) (125) (187) 0 .(129) (231) (387) (161) (232) (187) (320) (455) (412) (347) (251) (350) (596) (329) (298) (316) (412) (598) (359) (463) (376) (538) (747) (424) (520) (439) (563) (753) (449) (743) (512) (643) (845) (590) (646) (575) (785) (938) (869) (770) (641) (805) (1 032) (785) (810) (13) (708) (919) (1 126) (798) (825) (54) (775) (1 052) (1 343) (954) (933) (96) (842) (1 063) (1 319) (969) (1 154) (140) (776) (1 364) (1,417) (1 126) (1 050) (190) (35) (985) (1 230) (1 650) (1 242) (1 001) (234) (82) 0 (1 042) (1 317) (1 621) (1 334) (1 214) (275) (6) (130) 0 (1 161) (1,410) (1 864) (1 331) (1 262) (319) (38) (179) 0 (1 178) (1,499) (1 991) (1,433) (1 349) (6)(367) (74) (232) 0 (1 283) (1 589) (1 934) (1 598) (1 385) (19)
1 Final values after thermal peaking resources were applied.
Page 78
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2006 Integrated Resource Plan
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Appendix 0- Technical Appendix Idaho Power Company
Monthly Northwest Transmission Constraint Deficiency Data
th Percentile Water, 50th Percentile Average Load, 90th Percentile Peak-Hour Loadan Feb March April May June July Aug Sept Oct
(12)
(51) (108) (5) (179) (78) (262) (43) (165) (354) (5) 0 , (46) (237) (443) (290) (58) (113) (328) (534) (199) (100) (180) (412) (627) (247) (110) (242) (497) (754) (363) (219) (314) (577) (815) (418) (444) (239) (715) (906) (539) (344) (441) (743) (1 054) (652) (374) (508) (840) (1 106) (741) (495) (576) (929) (1 265) (774) (545)
(640) (1 012) (1 384) (891) (621)
(713) (1 108) (1,410) (995) (670)
th Percentile Water, 70th Percentile Average Load, 95th Percentile Peak-Hour Loadan Feb March April May June July Aug Sept Oct
(51)
(10) (96) (151) (29) (247) (105) (307) (116) (63) (185) (399) (56) (23) (129) (269) (490) (348) (143) (196) (353) (582) (268) (185) (260) (436) (676) (316) (221) (328) (521) (838) (443) (307) (393) (606) (866) (461) (526) (338) (804) (963) (614) (423) (529) (778) (1 142) (721) (480) (597) (865) (1 161) (814) (589) (663) (952) (1 356) (824) (637)
(731) (1 042) (1,482) (945) (723)
(800) (1 130) (1,470) (1 056) (758)
Year
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Year
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Year
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
th Percentile Water, 70th Percentile Average Load, 95th Percentile Peak-Hour Loadan Feb March April May June July Aug Sept Oct
(115)
(39) (179) (181) (35) (115) (331) (1) (93) (8) (140) (336) (27) (316) . 0(80) (220) (428) (168) (219) (144) (362) (522) (446) (343) (209) (382) (615) (362) (383) (277) (496) (710) (376) (398) (343) (629) (927) (532) (506) (411) (640) (903) (546) (727) (344) (941) (1 001) (704) (622) . 0 (553) (807) (1,234) (820) (574) (610) (894) (1 204) (912) (787) (729) (987) (1,448) (909) (835)
(747) (1 076) (1 575) (1 010) (922) 0 0 (851) (1 166) (1 518) (1 176) (958)
1 Final values after thermal peaking resources were applied.
Nay Dee
(43)
(105)
Nay Dee
(43)
(101)
(162)
(223)
(287)
(350)
(414)
(478)
Nay Dee
(50)
(112)
(170)
(231)
(294)
(358)
(422)
(486)
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Appendix 0- Technical Appendix Idaho Power Company
Monthly Northwest Transmission Constraint Deficiency Data with Peakers(2006-2015)
th Percentile Water, 50th Percentile Load, 90th Percentile Peak-Hour Load (MW)Jan Feb Mar Apr May Jun Jul Aug Sep Oct
(64) (175) 180 172 168 165 168 170 17588 87 86 87 88
2006
Peak-Hour Sup.lDef.
Bennett Mountain
Danskin
Evander
Deficiency
2007
Peak-Hour Sup.lDef.
Bennett Mountain
Danskin
Evander
Deficiency
2008
Peak-Hour Sup.lDef.
Bennett Mountain
Danskin
Evander
Deficiency
2009
Peak Hour Sup.lDef.
Bennett Mountain
Danskin
Evander
Deficiency
2010
Peak Hour Sup.lDef.
Bennett Mountain
Danskin
Evander
Deficiency
2011
Peak Hour Sup.lDef.
Bennett Mountain
Danskin
Evander
Deficiency
2012
Peak Hour Sup.lDef.
Bennett Mountain
Danskin
Evander
Deficiency
2013
Peak Hour Sup.lDef.
Bennett Mountain
Danskin
Evander
Deficiency
2014
Peak Hour Sup./Def.
Bennett Mountain
Danskin
Evander
Deficiency
2015
Peak Hour Sup./Def.
Bennett Mountain
Danskin
Evander
Deficiency
Page 86
Jan
180
Jan
180
Jan
180
180
Jan
180
180
Jan
180
180
Feb
178
Feb
178
Feb
178
178
Feb
178
178
Jan
180
180
Feb
178
178
Feb
178
178
Jan
180
180
Jan
180
180
Jan
180
180
Mar
Mar
Mar
176
176
Mar
176
176
Mar
176
176
Mar
176
176
Feb
178
178
Feb
178
178
Mar
176
176
Mar
176
176
Feb
178
178
Mar
176
176
Apr May Jun Jul Aug Sep
(131) (263) 172 168 165 168 17088 87 86 87
(12) pr May Jun Jul Aug Sep(42) (177) (319) (13) 172 168 165 168 17088 87 86 87 1~ 1~ 1~
pr May Jun Jul Aug Sep(96) (225) (383) (270) (78)172 168 165 168 17088 87 86 87 172 168 165 168 170
Apr May Jun Jul Aug Sep
(159) (287) (467) (187) (105)172 168 165 168 17088 87 86 87 172 168 165 168 170(51) pr May Jun Jul Aug Sep(225) (359) (525) (204) (187)172 168 165 168 17088 87 86 87 172 168 165 168 170(108)
Apr May Jun Jul Aug Sep(281) (428) (595) (265) (242)172 168 165 168 17088 87 86 87 172 168 165 168 170(5) (179) pr May Jun Jul Aug Sep(348) (501) (678) (325) (470)172 168 165 168 17088 87 86 87 172 168 165 168 170(78) (262) (43)
Apr May Jun Jul Aug Sep(417) (588) (770) (427) (371)172 168 165 168 17088 87 86 87 172 168 165 168 170(165) (354) (5)
Apr May Jun Jul Aug Sep
(478) (660) (859) (712) (485)174 172 168 165 168 17088 88 87 86 87 174 172 168 165 168 170(46) (237) (443) (290) (58)
Oct
175
Oct
175
175
Oct
175
175
Oct
175
175
Oct
175
175
Nov
177
Nov
177
Nov
177
177
Noy
177
177
Noy
177
177
Oct
175
175
Oct
175
175
Oct
175
175
Oct
175
175
Dec
178
Dec
178
Dec
178
178
Dec
178
178
Dec
178
178
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177
177
Dec
178
178
Noy
177
177
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178
178
Noy
177
177
Dee
178
178
Noy
177
177
Dee
178
178
Noy
177
177
Dee
178
178
2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Monthly Northwest Transmission Constraint Deficiency Data with Peakers (2016-2025)
th Percentile Water, 50th Percentile Load, 90th Percentile Peak-Hour Load (MW)
2016 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(545)(751)(951)(622)(527)(9)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (113)(328)(534)(199)(100)
2017 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(611)(835) (1 044)(669)(538)(66)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (180)(412)(627)(247)(110)
2018 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(674)(920) (1 170)(785)(646)(127)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (242)(497)(754)(363)(219)
2019 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(745) (1 000)232)(840)(871)(9)(182)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (314)(577)(815)(418)(444)
2020 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(671) (1 138)323)(961)(771)(46)(251)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (239)(715)(906)(539)(344)
2021 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(28)(872) (1 166)(1,470)075)(801)(88)(310)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (441)(743) ' (1,054)(652)(374)
2022 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(71)(940) (1 263)(1,522)164)(922)(130)(360)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (508)(840)106)(741)(495)
2023 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(113)007)352)681)197)(972)(174)(421)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (576)(929)265)(774)(545)
2024 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(159)072)(1,435)800)313)(1,049)(332)(491)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (640)012)(1,384)(891)(621)(43)
2025 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(204)145)531)827)417)(1,097)(261)(553)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (713)108)(1,410)(995)(670)(105)
2006 Integrated Resource Plan Page 87
Appendix 0- Technical Appendix Idaho Power Company
Monthly Northwest Transmission Constraint Deficiency Data with Peakers (2006-2015)
th Percentile Water, 70th Percentile Load, 95th Percentile Peak-Hour Load (MW)
2006 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak-Hour Sup./Def.' (15)(85)(213)(20)
Bennett Mountain 180 172 168 165 168 170 175 177 178
Danskin
Evander
Deficiency
2007 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak-Hour Sup./Def.(60)(154)(302)(20)(32)(2)
Bennett Mountain 180 178 172 168 165 168 170 175 177 178
Danskin
Evander
Deficiency (51)
2008 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak-Hour Sup./Def.(112)(196)(357)(59)(80)(26)
Bennett Mountain 180 178 172 168 165 168 170 175 177 178
Danskin
Evander 168 165 168 170 175 177 178
Deficiency
2009 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup./Def.(173)(256)(426)(324)(152)(78)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (10)
2010 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup./Def.(236)(321)(512)(245)(209)(119)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (96)
2011 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup./Def.(303)(383)(567)(270)(265)(87)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (151)
2012 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nay Dec
Peak Hour Sup./Def.(361)(452)(663)(339)(324)(136)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (29)(247)
2013 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup./Def.(422)(528)(723)(364)(543)(195)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (105)(307)(116)
2014 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup./Def.(494)(608)(815)(478)(450)(254)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (63)(185)(399)(56)(23)
2015 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nay Dee
Peak Hour Sup./Det.(561)(692)(907)(771)(570)(312)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (129)(269)(490)(348)(143)
Page 88 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Monthly Northwest Transmission Constraint Deficiency Data with Peakers (2016-2025)
th Percentile Water, 70th Percentile Load, 95th Percentile Peak-Hour Load (MW)
2016 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(627)(775)(998)(691)(612)(370)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (196)(353)(582)(268)(185)
2017 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(692)(859) (1 092)(738)(649)(429)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (260)(436)(676)(316)(221)
2018 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(759)(944) (1 254)(865)(734)(6)(492)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (328)(521)(838)(443)(307)(43)
2019 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup)Def.(36)(825) (1 028)283)(884)(953)(47)(550)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (393)(606)(866)(461)(526)(101)
2020 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(83)(770) (1 227)379)036)(850)(87)(610)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (338)(804)(963)(614)(423)(162)
2021 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(129)(961) (1 200)558)143)(907)(129)(671)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (529)(778)142)(721)(480)(223)
2022 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(173)029)288)577)236)(1,017)(170)(735)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (597)(865)161)(814)(589)(287)
2023 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(216)(5)094)375)773)246) (1 064)(215)(798)
Bennett Mountain 180 178 176 174 172 168 165 168,170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (663)(952)(1,356)(824)(637)(350)
2024 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(259)(54)163)(1,464)898)368)150)(368)(863)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165.168 170 175 177 178
Deficiency (731)042)482)(945)(723)(414)
2025 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(306)(108)231) (1 553)886)(1,478)185)(301)(927)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (800) (1 130)470)056)(758)(478)
2006 Integrated Resource Plan Page 89
Appendix 0- Technical Appendix Idaho Power Company
Monthly Northwest Transmission Constraint Deficiency Data with Peakers (2006-2015)
th Percentile Water, 70th Percentile Load, 95th Percentile Peak-Hour Load (MW)
2006 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak-Hour Sup./Oef.(32)(116)(243)(74)(102)
Bennett Mountain 180 172 168 165 168 170 175 177 178
Oanskin
Evander
Deficiency
2007 Jan Feb Mar Apr Aug Sep Oct Nov DecMayJunJul
Peak-Hour Sup./Oef.(75)(215)(366)(125)(187)(8)
Bennett Mountain 180 178 172 168 165 168 170 175 177 178
Oanskin
( .
Evander
Deficiency (115)
2008 Jan Feb Mar Apr May Jun Jul Aug.Sep Oct Nov Dec
Peak-Hour Sup./Oef.(129)(231)(387)(161)(232)(32)
Bennett Mountain 180 178 172 168 165 168 170 175 177 178
Oanskin
Evander 168 165 168 170 175 177 178
Deficiency
2009 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hol,Jr Sup./Oef.(187)(320)(455)(412)(347)(85)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Oanskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (39)
2010 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee
Peak Hour Sup./Oef.(251)(350)(596)(329)(298)(127)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Oanskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (179)
2011 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Oef.(316)(412)(598)(359)(463)(95)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Oanskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (181)(35)
2012 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
. '
Peak Hour Sup./Oef.(376)(538)(747)(424)(520)(144)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Oanskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (115)(331)(1)(93)
2013 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Oef.(439)(563)(753)(449)(743)(203)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Oanskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (8)(140)(336)(27)(316)
2014 Jan Feb Mar Jun Jul Oct Nov Dec
Peak Hour Sup./Oef.(512)(643)(845)(590)(646)(262)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Oanskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (80)(220)(428)(168)(219)
2015 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Oef.(575)(785)(938)(869)(770)(320)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Oanskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (144)(362)(522)(446)(343)
Page 90 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Monthly Northwest Transmission Constraint Deficiency Data with Peakers (2016-2025)
th Percentile Water, 70th Percentile Load, 95th Percentile Peak-Hour Load (MW)
2016 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup.lDef.(641)(805) (1 032)(785)(810)(377)
Bennett Mountain 180 178 176 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 172 168 165 168 170 175 177 178
Deficiency (209)(382)(615)(362)(383)
2017 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup.lDef.(13)(708)(919) (1 126)(798)(825)(435)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (277)(496)(710)(376)(398)
2018 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup.lDef.(54)(775) (1 052)343)(954)(933)(498)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Eyander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (343)(629)(927)(532)(506)(50)
2019 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup.lDef.(96)(842) (1 063)319)(969) (1 154)(26)(560)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency . 0 (411)(640)(903)(546)(727)(112)
2020 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup.lDef.(140)(776) (1 364)(1,417)126)050)(63)(618)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (344)(941)001)(704)(622)(170)
2021 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup.lDef.(190)(35)(985) (1 230)650)242)001)(105)(679)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (553)(807)234)(820)(574)(231)
2022 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup.lDef.(234)(82)042)317)621)334) (1 214)(147)(742)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (610)(894)204)(912)(787)(294)
2023 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup.lDef.(275)(6)(130)161)(1,410)864)331)262)(191)(806)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (729)(987)(1,448)(909)(835)(358)
2024 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup.lDef.(319)(38)(179)178)499)991)433)349)(6)(327)(870)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (747)076)575)(1,010)(922)(422)
2025 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Noy Dec
Peak Hour Sup.lDef.(367)(74)(232)283)589)934)598)(1,385)(19)(280)(934)
Bennett Mountain 180 178 176 174 172 168 165 168 170 175 177 178
Danskin
Evander 180 178 176 174 172 168 165 168 170 175 177 178
Deficiency (851)166)518)176)(958)(486)
2006 Integrated Resource Plan Page 91
Appendix 0- Technical Appendix Idaho Power Company
Portfolio Summary and Description
Portfolio P-1 - Green
DSM 2007-2025 187 Energy 926
Wind 2008 2009 2011 500 Transmission 450
Geothermal (Binary) 2009 2011- 2014 2016-
, 2020 490 Peak 1099
CHP 2010,2013 150 Total Name Plate 2027
Transmission McNary 2014 , Montana 2018 450
Nuclear 2022 250
Total Name Plate 2027
Portfolio PI comprises a high degree of renewable energy generating resources and a large reliance on
market purchases via upgraded transmission paths to meet peak capacity needs. Portfolio PI represents
the lowest carbon exposure.
Expected Case Aurora Years 1-20 NPV ($000)
Market Purchases $306 212
Resource Total 348 136
Market Sales 670 626
Total 983,722
Portfolio P2 - Transmission
DSM 2007-2025 187 Energy
Wind 2008 100 Transmission
Geothermal (Binary) 2009 Peak
CT 2010 170 Total Name Plate
Transmission Lolo 2011 , McNary 2013
Montana 2018, White Pine 2024 1260
Nuclear 2022 250
Total Name Plate 2017
394
1260
662
2017
Portfolio P2 explores the implications of extensive transmission upgrades and reliance on the market to
provide the bulk of the new base load and peaking needs.
Expected Case Aurora Years 1-20 NPV ($000)
Market Purchases $~58 789
Resource Total 600 116
Market Sales 207 782
Total $5,351 123
Page 92 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Portfolio P3 - 2004 IRP with diversified additions
DSM 2007-2025
Wind 2008 2012
Geothermal (Binary) 2009, 2021 , 2022
CHP 2010,2020
Transmission McNary 2012 , Lolo 2019
Coal 2013
IGCC 2017
Nuclear 2022
Total Name Plate
187
250
225
110
285
250
250
250
1807
Energy
Transmission
Peak
Total Name Plate
1139
285
1284
1807
Portfolio P3 adjusts and extends the 2004 IRP with a diversified mix of renewable, transmission, and
thermal resources.
Expected Case Aurora Years 1-20 NPV ($000)
Market Purchases $517 744
Resource Total $6,313 858
Market Sales 866 829
Total 964 772
Portfolio P4 - Basic Thermal
DSM 2007-2025 187 Energy 1187
Wind 2008 100
CHP 2008 Peak 1562
Geothermal (Binary) 2009 1657
Coal 2012 2016 2020 850
CT 2018 170
Nuclear 2022 . 250
Total Name Plate 1657
Portfolio P4 satisfies the base load and peak growth with a heavy reliance on new pulverized coal and
natural gas peaking generation. It contains no transmission upgrades. This portfolio has the greatest
carbon exposure.
Expected Case Aurora Years 1-20 NPV ($000)
Market Purchases $270,096
Resource Total 227 009
Market Sales 655,419
Total 841 685
2006 Integrated Resource Plan Page 93
Appendix 0- Technical Appendix Idaho Power Company
Portfolio P5 - Clean Coal Portfolio
DSM 2007-2025
Wind 2008
CHP 2008
Total Name Plate
187 Energy 1104
100 Transmission
Peak 1537
Total Name Plate 1632
600
170
225
250
1632
Geothermal (Binary) 2009
IGCC 2012, 2016
CT 2018
CCCT 2021
Nuclear 2022
Portfolio P5 examines heavy thermal portfolio with IGCC coal and a large combines cycle natural gas
resources.
Expected Case Aurora Years 1-20 NPV ($000)
Market Purchases $297 995
Resource Total $7,431 968
Market Sales $2,463 595
Total 266 369
Portfolio P6 - 2004 IRP with Heavy Geothermal and Combustion Turbines (CT)
DSM 2007-2025 187 MW EnergyWind 2008 100 MW TransmissionCHP 2008 100 MW Peak
Geothermal (Binary)
2010 2013 2018
CT 2012 2020,2021
Coal 2013 2017
IGCC 2022
1042
1752
150
510
500
300
1847
Total Name Plate 1847 , , I
Total Name Plate
c,;
(, )~,,
r "
, )
Portfolio P6 adjusts and extends the 2004 IRP with three 170 MW natural gasCT's , 220 MWs of
Geothermal and a 300 MW IGCC coal plant. Idaho Power generation requirements are predominantly
peak driven which requires a large capacity for a relatively few peak hours per year. CT's are one way to
provide this capacity and P6, P7, P8, and P9 examines heavy CT reliance.
Expected Case Aurora Years 1-20 NPV ($000)
Market Purchases $289 365
Resource Total 156,598
Market Sales 501 643
Total 944 319
, ..
Page 94 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Portfolio P7 2004 IRP with Heavy Geothermal and Combustion Turbines with some Transmission
DSM 2007-2025 187 MW EnergyWind 2007 100 MW TransmissionGeothermal (Binary) 2010 50 MW PeakCHP 2010 50 MW Total Name Plate
Transmission McNary 2011 225
Coal 2013,2018 500
CT 2020 2021 340 IGCC 2022 300 Total Name Plate 1752
901
225
1432
1752
Portfolio P7 adjusts and extends the 2004 IRP similarly to P6 but with increased transmission enabling
greater import capacity and consequently market purchases to provide for some of the system peaking
requirements and offsetting a CT and some geothermal and CHP generation.
Expected Case Aurora Years 1-20 NPV ($000)
Market Purchases $412 236
Resource Total 650 659
Market Sales 065 285
Total 997 609
Portfolio P8 2004 IRP with Outrageous CT's and some Geothermal
DSM 2007-2025 187
. Wind 2007 2011 350 CHP 2008 48
Geothermal 2010-2013,2018 250 Coal 2013 250
CT 2012 2017 2020 2021 680
IGCC 2021 300
Total Name Plate 2065
Energy
Transmission
Peak
Total Name Plate
948
1721
2065
Portfolio P8 starts with the 2004 IRP and builds the most peaking focused portfolio. CT's are relatively
cheap to build and if not run a lot of hours provide a good choice to provide capacity. P8 examines the
addition of 4 170 MW CTs. Additionally, some of the pulverized coal identified in the 2004 Ip was off
set with Geothermal resources.
Expected Case Aurora Years 1-20 NPV ($000)
Market Purchases $321 042
Resource Total 026,768
Market Sales 535 129
Total 812 681
2006 Integrated Resource Plan Page 95
Appendix 0- Technical Appendix Idaho Power Company
Portfolio P9 2004 IRP Heavy CTs and IGCC sequestration
DSM 2007-2025 187Wind 2007 100CHP 2008 100
Geothermal (Binary) 2010,2013,2018 150
CT 2012 2020 2021 510
Wyo IGCC w/seq 2013 250Coal 2017 250IGCC 2022 300
Total Name Plate 1847
1042
1752
1847
Energy
Transmission
Peak
Total Name Plate
~ i
Portfolio P9 begins with the 2004 IRP and focuses on peaking and geothermal resources with carbon
sequestered coal generation.
Portfolio P10 - Heavy Pulverized Coal
DSM 2007-2025 187 Energy 1356
Wind 2008 100 Transmission 225
CHP 2009 100 Peak 1592
Geothermal (Binary) 2009 Total Name Plate 1912
Transmission McNary 2014 225
Coal 2012,2016 2018 2023 1000
Nuclear 2021 250
Total Name Plate 1912
Expected Case Aurora Years 1-20 NPV ($000)
Market Purchases $289 882
Resource Total 182 044
Market Sales 501 215
Total 970 712
'-: ;I
Portfolio PI 0 focuses on pulverized coal with four 250 MW projects over the planning period.
Pulverized c.oal is a proven and reliable technology with a plentiful fuel source. Portfolio P10 is
distinguished as the portfolio that adds the most base load generation.
Expected Case Aurora Years 1-20 NPV ($000)
Market Purchases $265,690
Resource Total 503 565
Market Sales $2,797,467
Total 971 787
Page 96 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Portfolio P11 - Transmission Bridger to Boise with Wyoming Wind
DSM 2007-2025 187
Wind 2009,2016,2018 2020 1100 CHP 2009 100
Geothermal (Binary) 2009 50
Transmission
Wyoming 2012, McNary 2014
Coal 2013
Nuclear 2020
Total Name Plate
1475
250
250
3412
Energy
Transmission
1016
1475
893
3412
Peak
Total Name Plate
Portfolio P11 explores increasing the transmission capacity between Wyoming and Boise. There was
enthusiastic support for this configuration among some of the IRP AC members. The rational is to
provide a means of accessing the high capacity wind area that are located in Wyoming. This portfolio
has the distinction of including the most facility nameplate.
Expected Case Aurora Years 1-20 NPV ($000)
Market Purchases $410 636
Resource Total 860,774
Market Sales $2,401 375
Total 870 035
Portfolio P12 Nuclear
DSM 2007-2025
Wind 2008
CHP 2009
Geothermal (Binary) 2009
Coal 2013
187
100
100
250
225
900
1812
Transmission McNary 2014
Nuclear 2016, 2018, 2023
Total Name Plate
Energy
Transmission
Peak
Total Name Plate
1289
225
1492
1812
Portfolio P12 incorporates a nuclear resource solution to Idaho Power generation growth requirements.
Expected Case Aurora Years 1-NPV ($000)
Market Purchases $262 189
Resource Total 500 132
Market Sales 966 285
Total 796,034
2006 Integrated Resource Plan Page 97
Appendix 0- Technical Appendix Idaho Power Company
Summary of Initial Portfolios
Resource P10 P11 P12
CCCT 225
CHP 150 110 100 100 100 100 100
Coal 250 850 500 500 250 250 000 250 250
170 170 170 510 340 680 510
DSM 187 187 187 187 187 187 187 187 187 187 187 187
Geothermal
(Binary)490 225 150 250 150
IGCC 600 300 300 300 300
Nuclear 250 250 250 250 250 250 250 900
Transmission 450 260 285 225 225 1,475 225
Wind 500 100 250 100 100 100 100 350 100 100 100 100
(: .
Wyo IGCC
w/seq 250
Total
Nameplate 027 017 807 657 632 847 752 065 847 912 412 812
Energy 926 394 139 187 104 042 901 948 042 356 016 289
Transmission 450 260 285 225 475 225
Peak 099 662 284 562 537 752 432 721 752 592 893 1,492
" ,
Page 98 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Coal Based Generation Technology Assessment
Executive Summary
DRAFT
With the recent increase in natural gas prices and gas delivery restrictions, coal based power
generation is regaining a stronghold in the power generation industry. When considering the
many common and developing coal generation technologies available for utility application, it is
important to understand the relative benefits and potential pitfalls associated with various options
currently being considered for new power generation facilities.
The purpose of this white paper is to present a summary level comparison of key parameters
associated with each of the most prevalent commercial coal-fired generation technologies
currently being considered in today s power generation market. The technologies addressed
include the following:
Sub-critical pulverized coal combustion.
Super-critical pulverized coal combustion.
Ultra-super-critical pulverized coal combustion.
Circulating fluidized bed combustion.
Integrated gasification combined cycle technologies.
Pressurized fluidized bed combustion.
The relative performance, environmental emissions, and electrical generation costs for each of the
technologies for a western coal application are compared. In addition, the sensitivity of
generation cost for the most prominent technologies to unit size, capital costs, and key
environmental risks for mercury control and carbon dioxide emissions are addressed.
The comparison assumes a typical 600 MW unit, located on a western US plant site, designed to
utilize western bituminous and sub-bituminous coal supplies.
1.1 Overview of Technologies
The following is a brief description of each of the coal generation technologies considered in this
assessment.
Pulverized Coal (PC) Boilers.PC boiler technology is a well-proven technology that is
dominating the current market for large projects under development and construction. This boiler
technology is characterized by firing coal which has been pulverized to a fine particle size (50
microns or smaller) and then blown into the boiler with combustion air and rapidly combusted.
The combination of the fuel particle size and direct injection with combustion air results in very
high combustion rates when compared to other technologies such as circulating fluidized bed
boilers. Pulverized coal boilers consist of a membrane-wall furnace or combustion zone
consisting of either vertical or spiral-wound water tubes. This membrane wall serves as the
evaporative section of the boiler. In the furnace, fuel and combustion air are injected through
wall-mounted burner assemblies with staging of combustion air to minimize the fonnation of
NOx. Some steam superheater surface is often located in the furnace in the form of pendant heat
exchange surfaces. The combustion products or flue gases flow upward through the furnace and
enter a backpass, or convective section which includes steam superheaters, reheaters
economizers, selective catalytic NOx reduction systems, and air heaters. Split backpass sections
061S06-
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DRAFT
2006 Integrated Resource Plan Page 99
Appendix 0- Technical Appendix Idaho Power Company
in which the flue gas flows through two parallel gas paths, are often utilized to assist in steam
temperature control and to minimize the use of water spray attemperation.
The thermodynamic steam cycle for large pulverized coal fired units have been implemented in
three basic steam cycles:
Subcritical drum type units with maximum continuous throttle pressures up to 2 400 psig
and typically 1000 of/1000 OF superheat/reheat steamtemperatures. Overpressure (OP)
design conditions for this cycle would typically allow for temporary operation at a
throttle pressure of 2 520 psig.
Supercritical units with throttle pressures at 3 500 psig, (3 675 psig-OP) and with 1 000
f to 1 100 of superheat and reheat temperatures and typically would be applicable for
units greater than 400 MW class designs. Supercritical technologies operate on a once-
through steam/water cycle concept with no steam drum in the steam generator flow path.
Water is circulated through the boiler heat transfer surfaces, evaporated within the boiler
tubes, superheated and/or reheated, and dire.cted to the steam turbine generator.
Supercritical cycles have typically been implemented with a single steam reheat system.
Ultra-supercritical units with throttle pressures as high as 4 200 psig and 1 100 o
superheat and reheat steam temperatures that are generally applied to extremely large
units (1,000 MW class). These units have been successfully implemented in Europe and
Japan with little operating experience in the United States. Further development and
advancement of the ultra-supercritical technologies is focusing on the development of
new piping and equipment materials required to further elevate the steam cycle
conditions and improve overall thermal cycle efficiency. Ultra-supercritical technologies
are similar to the supercritical technologies with respect to the use of a once-through
steam/water cycle. While supercritical cycles have typically been limited to single reheat
systems, ultra-supercritical units may utilize double reheat steam cycles.
1'.
Circulatin!! Fluidized Bed (CFB) Boiler.CFB boiler technology represents a mature
technology in which crushed fuel and limestone (and/or other inert bed materials) are injected
into the furnace where they are suspended in a fluidized bed by combustion air that flows
vertically through the furnace. The elutriation of the fuel particles and bed material allows for
long residence time for combustion as the gas stream moves from the bottom of the furnace
through a particulate separation device and exits through a standard convective heat transfer
section at the backend of the boiler. Due to the low combustion temperatures and the use of
limestone as a bed material, emissions of NOx and SO2 emissions from CFB boilers are
inherently lower than those of PC boilers. The separator device located at the furnace gas outlet
collects bed material entrained in the flue gas for recycle back into the furnace; thus, the term
circulating fluidized bed is applied. The particle separator at the furnace exit can take many
forms ranging from the typical cyclone design with a vortex finder and J-valve to internal U-
Beam devices which form a tortuous path where particulate collects via impaction with the U-
Beams. CFB boiler designs are adaptable to a wide range of fuels, allowing utilization of low
rank coals, waste fuels, andopportunity fuels such as petroleum coke.
, ." "
Selective non-catalytic reduction (SNCR) systems are typically employed to help furth~r reduce
NO, emissions without the need for a SCR catalyst. SO2 removal efficiencies as high as 95
percent have been achieved through injection of limestone directly into the furnace.
061506-
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DRAFT
Page 100 2006.1ntegrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
CFB boiler technology applications to date have utilized sub-critical thennal cycles. The first
supercritical, 450 MW, once-through CFB unit is currently under construction in Poland by
Foster Wheeler. There are no technical concerns for this enhancement of the technology other
than the threshold criteria of about 400 MW were supercritical designs become more
economically viable. However, designs are offered by other suppliers for larger, supercritical
once through CFB boilers up to 600 MW in size, but to date no units have been built. The current
size limit ofCFB boilers is 400 MW.
Inte2rated Gasification Combined Cycle (lGCC).IGCC is a developing clean-coal technology
that combines the gasification of coal to syngas and integrates this with a standard gas turbine
combined cycle power plant. Gasification processes have and are operating in the chemical
industry for many years with a number of proven utility-size IGCC power plants. !GCC
development projects are prevalent in today s market, but are focused on a select number of
utilities and independent power producers that are funding up-front front-end engineering and
design (FEED) analyses to definitively establish design, performance, and cost information.
Most of the development projects are funding FEED efforts for high sulfur bituminous and
petroleum coke-type fuels. Presently, there appears to be limited interest in developing western
bituminous or sub-bituminous fuel designs by the prominent gasification suppliers (OEMs).
For the gasification process coal is reacted in a gasifier, producing a raw fuel gas that is cleaned
and combusted in a gas turbine as part of a combined-cycle power block. Coal gasification
involves the partial oxidation of coal at an elevated temperature and pressure which produces the
syngas that has combustible components, including hydrogen, carbon monoxide and methane.
Gasification takes place in a gasifier/reactor, where coal is processed in three steps: drying
(evaporating moisture), pyrolysis (decomposition / transformation of chemical compounds) and
gasification (partial oxidation). The syngas from the coal gasifier is then quenched and/or cooled
through a series of integrated heat exchangers and then scrubbed for removal of particulates and
sulfur.
Typical syngas compositions leaving the gasification system have low heating values compared
to natural gas. Clean syngas is combusted in one or more gas turbines, which exhaust to multiple
presstlre, sub-critical heat recovery steam generators (HRSGs). The HRSGs produce steam for a
conventional steam turbine cycle as well as steam required for the gasification process. Oxygen
required for the gasifier (either air-blown or oxygen-blown) is often provided via the gas turbine
compressor. For oxygen-blown designs, a cryogenic air separation unit is required.
Since the volume of the syngas produced is significantly less than the flue gas produced by the
combustion turbines, removal of pollutants is generally more efficient than with other coal
generation technologies. This characteristic is very attractive and has good potential for
economically achieving aggressive pollutant emissions standards. The key area of future benefit
is associated with the capability for carbon dioxide capture for sequestration (CCS) that can be
adapted through this technology.
Pressurized Fluidized Bed Combustion (PFBC).PFBC coal technology can be characterized
as a standard combined cycle facility with an external combustor for the combustion turbine. The
combustor is a pressurized combustor supplied with coal and combustion air from the combustion
turbine compressor. The combustion units are fairly compact and operate at pressures consistent
with the combustion turbine design, typically in the range of 145 to 220 psig, and combustion
temperatures in the range of 1400 to 1600o
061506-
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DRAFT
2006 Integrated Resource Plan Page 101
Appendix 0- Technical Appendix Idaho Power Company
Hot pressurized flue gas from the combustor is used to directly produce steam and is also sent
through hot cyclones and supplied to a gas turbine for expansion and power production. Gas
turbine exhaust gas is then sent through a heat recovery steam generator for additional steam
production for steam turbine power generation. Ultimately the steam turbine will create
approximately 80% of the plant power with the combustion turbine providing the other 20%. The
key challenge to this cycle design is having a gas turbine design that can accept a flue gas with
residual solid particles.
Due to the limited commercial deployment of this technology, the complexity of the various plant
systems, mixed performance results from recent applications, and the limited apparent benefits of
the technology (i.e. lack of significantly improved cycle efficiencies and emissions as compared
to other technologies), PFBC technology is not currently considered a realistic option for a 600
MW power generating facility.
Table 1.1-1 provides a summary level side-by-side comparison of the key differentiators between
the technologies included in this evaluation.
, .''-'- j" '
061506-
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DRAFT
Page 102 2006 Integrated Resource Plan
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Appendix 0- Technical Appendix Idaho Power Company
1.2 Comparison of Performance
The relative performance of the various coal generation technologies is presented in Table 1.2-
This includes the expected plant efficiency, water consumption, waste generation, and emissions
for the various options.
Pulverized Coal CFB IGCC
lJltra-Super-
Units Sub.crltlcal Super.crltlcal Critical Sub,Crltlcal
- -
Plant Performance
Gross Output (MW 649,649,649.435,730.
Auxiliarv Power (MW 49,49.49.35,130.
Net Output (MW 600.600.600.400.600.
Net Cycle Heat Rate (Btu/kWH HHV 371 955 859 289 131
Net Cycle Efficiencv (%HHV)36.42%38.11%38.53%36.74%41,98%
Environmental Considerations
NOx Emissions IIb/MMBtu\07 to 0.45 0:04 to 0.04 to 0.07toO.03 to 0,
S02 Emissions IIbIMMBtu)1 to 0.06 to 0,06 to 0.1 to 0,015toO.
CO2 Emissions (T/MWH (net))
Hg Emissions (lbITBtu)6 to 0,6 to 0.6 to 0.9\01.7 to 1.
Waste Bvproduct Generation
Fly Ash IIb/MWH\52.50,49.67.
Bottom Ash/SlaQ (lb/MWH)13.12,12.17.47.
Gypsum IIb/MWH)20.19.19,
Sulfur (H2 (lb/MWH)
Water Consumption (gaI/MWH)469.4 442,430,453,227,
Table 1.2-1. Technology Performance Summary
In reviewing the relative performance of the various technologies, the combined cycle
efficiencies of IGCC technologies are better relative to the other technologies. The expected
thermal efficiency of a 600 MW IGCC plant is 3 to 4 percent better than the supercritical options
(both super-critical and ultra-supercritical) for the PC and CFB technologies. The !GCC
efficiency is also 5 to 6 percent greater than that of the sub-critical thermal cycles. As expected
for PC and CFB combustion technologies, thermal cycle efficiencies improve' as the steam cycle
pressures and steam temperatHres increase. The ultra-supercritical heat rates are only slightly
better than those of the super-critical cycles.
, -
With regard to emissions, both the PC and the CFB technologies have established Best Available
Control Technology (BACT) standards for control of emissions from plants. It is assumed that
TGCC and PFBC plants, if applicable, can easily attain comparable levels as part of a plant
permitting process. The IGCC technologies appear to be capable of achieving emissions
standards that are equivalent or possibly better than current BACT standards for PC and CFB
technologies; although, further investigation of the total emissions from an IGCC (including
emissions during process start-up and shut-down) is warranted relative to PC and CFB
technologies. The approach for capture of mercury emissions for each of the technologies
appears to be similar (i.e. adsorption with activated carbon) based on current technology
indications; however, given the lower volumes of gas to be treated, the IGCC applications would
have a significant cost advantage.
It should be noted that CO2 sequestration (i.e. permanent disposal of collected CO2) is a
developing concept. If a CO2 control strategy is employed for any of the technologies
implementation of a sequestration strategy would involve a comparable level of equipment and
costs for each of the technologies.
061506-
Cummins & Barnard
DRAFT
Page 104 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
1.3 Comparative Costs
Table 1.1 presents a comparison of capital, fixed and variable operating and maintenance
(O&M) costs, as well as estimates of the costs of electrical generation for each of the coal
generation technologies. It should be noted that this analysis is based on coal firing only without
any supplemental fuels. For this reason, the availability of power generated from the IGCC
facility is limited to a rather aggressive value of 80 percent based upon 100 percent gasifier
capacity and no spare units available. With a spare gasifier, the availability of the IGCC facility
has been increased to 85 percent which is consistent with the remaining technology options.
Pulverized Coal CFB IGCC
ultra."uper-
Units Sub-Criticat Super.Critical Critical Sub-Critical No Spare With Spare
Capital Cost ($/kW net)$1.814 907 $1.913 073 $2.290 $2.430
First Year Cost of Generation.
Caoilal Recoverv ($/MWH)525.S27.S27,$29.S34.$34.42
Fixed O&M Costs ($/MWH)$6.S6.$6.S7,$8,S8,
Variable O&M Costs ($/MWH)$0.SO.$0.45 $0.43 $1.$1.
Consumable O&M Costs ($/MWH)$2.S2.$2.S2.$1.$1.46
Fuel Costs I$/MWH)$13.$13,$13.$13.$12,$12.
Tolal First Year COG ($/MWH)$48.42 $49.42 $49.$53.$57.$57.
Levelized Cost of Generation
Capital Recovery ($/MWH)$25.$27,S27.$29.$34.49 $34.
Fixed O&M Costs $/MWH)$6.$6.$6.$6.$7.$7.
Variable O&M Costs $/MWH)$1.$1.26 $1.$0.$1.$1.
Consumable O&M Costs ($/MWH)$1.$1.$1.78 $2.$0.$0.
Fuel Costs $/MWH)$18,$17.$17.$18.40 $16.$16.
Total Levelized COG ($/MWH)$53.$54.$54.$57,$61.33 $60.
Table 1.3-1. Technology Cost Summary
1.4 Cost Sensitivity to Unit Size
As an indication of the sensitivity ,of generating costs to plant size, Table 1.4-1 presents estimated
capital, fixed and variable O&M, and COG for 300 MW, 600 MW, and 750 MW subcritical
plants and 600 MW and 750 MW supercritical PC generating facilities. As would be expected
the estimated COG decreases as unit size increases due to the economy of scale realized through
the larger generating units.
Project EPC Cost ($ million)Total Project Cost ($ million)
Fil1ltYear C0st8'H,'1~,I.'! ;i;;;~,1:ij;,'::'":
~,,
Fixed O&M Costs ($/MWH)
Variable O&M Costs (5/MWH)
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Table 1.4-1. Unit Size Cost Comparison
061506-
Cummins & Barnard
DRAFT
. ;.
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325 MW Gross 649 MW Gross 810 MW Gross 649 MW Gross 810 MW Gross
531.0 867.6 1032.912 1083.
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2006 Integrated Resource Plan Page 105
Appendix 0- Technical Appendix Idaho Power Company
1.5 Impact of Environmental Risks
Two key environmental risk issues associated with coal-fueled power generation are limitations
on greenhouse gas emissions (namely carbon dioxide, CO2) and limitations on mercury
emissions. Technologies for removal of both constituents are rapidly developing. For mercury,
air quality control equipment suppliers have offered emissions guarantees for new power projects.
Technologies exist for removal of CO2; however, these technologies have not reached a level of
maturity where guarantees have been offered in support of a project.
Table 1.1 presents the estimated costs for removal and sequestration of CO2 emissions from PC
and IGCC plants. Costs for capture of mercury are also presented. The lower costs for
controlling CO2 and mercury emissions from an IGCC plant are directly related to the volume of
syngas that needs to be treated relative to the flue gas volumes of PC and CFB units.
ucrca uper
Mereu Emissions Control
Total First Year Cost for Mereu Removal
Total Levelized Cost for Mereu Removal
First Year Cost of Mercury Removal
CO2 Emissions Control
Estimated Cost for CO2 Caplure $/MWH $1910 $23 $19 to $23
Table 1.5-1. Emissions Removal Cost Expectations
$/MWH $1,
$/MWH . $1,
$/Ib $22 559
$1.
$1.25
$22.887
uper-
CritleaiPC
$1,$0.$0.23 $0.
$1,$2.$0.26 $0.
$22.739 $18 266 358 290
$1910$23 $19 to $23 $1010$15 $10to$15
c i
061506-
Cummins & Barnard
DRAFT
Page 106 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
CO2 Adder Survey Data
Organization AssumptionlTargets/Source
Stanford Energy Modeling Forum ........................... CO2 to 1990 levels by 2010 .......................................
CO2 to -7% 1990 levels by 2010...............................
EIA ........................................................".'..'.""""" Climate Stewardship Act,..........................................
CO2 to -7% 1990 levels by 2012...............................
Interlaboratory Working Group.....,.......................... CO2 to 1990 levels by 2010 .,............................,........
Springer Study Summaries ..................................... Kyoto-liberal trading ................................................
Kyoto-Trading limited to Annex B countries ............
National Commission for Energy Policy (NCEP)..... "Ending the Energy Stalemate
..................................
$ Per Ton CO2
$5.00-37.
$12.50-69.
$15.00-45.
$34.00-41,
$12.
$1.00-22.
$9.00 average
$4.00-74.
$27.00 average
$7.00 in 2010
$15.00 in 2026
NWPPC................................................................... Fifth 2005................................................................... 67% likelihood
$0.00-15.00 in 2008
$0.00-30.00 in 2016
CPUC....................,................................................. Energy and Environmental Economics Inc. report.....
Reported cost of offset emission projects ..................
Dutch, UK, and World Bank trading markets,........................................,....................................................
EU ETS
.................................................................
June 2005 for 2006 settlement ..............,...................
$5,00 near-term
$12.50 in 2008
$17.50 in 2013
$7.50 median
$7.
$27.
2006 Integrated Resource Plan Page 107
Appendix 0- Technical Appendix Idaho Power Company
EPrs, Inc 1"-..URORA~ID
AURO RA~ Electric 11arket Model
Overview of AURORAxmp
. .
AURORA'mp Electric Market Model is price
forecasting and analysis software for the
competitive electric market. AURORAxmp
forecasts:
Electric energy prices.
The market value of electric generating
units.
111e market value of contracts and
portfolios; and
AURORA xmp analyzes the effect of market
uncertainty.
AURORA xmp applies economic principles
dispatch simulation and bidding strategies to
model the relationships of supply,
transportation, and demand for electric
energy.
AURORA xmp forecasts market prices and
operation based on forecasts of key
fundamental drivers such as demand, fuel
prices, and hydro conditions.
AURORA xmp is able to forecast point
estimates in seconds and minutes, and
produce Monte Carlo stochastic analyses in
minutes and a few hours.
In addition to market prices, AURORAxmp
provides information on resource value
portfolio value, net power cost, risk and
uncertainty analysis, and resource planning.
With appropriate inputs, AURORAxmp can be
used for near-term analysis (next day/week)
to very long-term analysis (20 plus years).
Furthermore, the user can make changes to
data (using spreadsheet-like grids) in the
database and run scenarios and what-if cases.
Users are able to add their own proprietary
data to create their own databases.
' !
Modeling Methodology
AURORA xmp is specifically designed to model
wholesale electricity prices in a deregulated
generation market.
In a deregulated generation market, at any
given time, prices should be based on the
marginal cost of production. In a competitive
electricity market, prices will rise to the point
of the variable cost of the last generating unit
needed to meet demand.
One of the principal functions of
AURORA xmp is to estimate this hourly
market-clearing price at various locations in
the national electric market. AURORA xmp
uses a fundamentals approach in estimating
prices, reflecting the economics and physical
characteristics of demand and supply.
AURORA xmp estimates prices by using hourly
demands and individual resource-operating
characteristics in a transmission-constrained
chronological dispatch algorithm.
...( :
The operation of resources within the electric
market is modeled to determine which
resources are on the margin for each area in
any given hour. The database includes all the
NERC reliability areas in the North American
national electric market.
( ,
The AURORA xmp database includes long-term
average demand and hourly demand shap~s
The information herein is copied in part with permission from the AURORATM Electric Market Model- Technical Information on
Model Software and Databases document, for the intent and purpose of the Idaho Power Company 2004 Integrated Resource Plan,
All or parts of this information may not be reproduced without the written permission of EPIS.
(f) Copyright 2002 EPI S, Inc. All rights reserved.
Page 108 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
AURORA'mp Technical Summary
2004 Integrated Resource Plan
Idaho Power Company
Page 2 of 3
for all the areas in the database. These
demand areas are connected by transmission
links with specified transfer capabilities
losses, and wheeling costs.
Existing supply-side generating units are
defined and modeled individually with
specification of a number of cost components
and physical characteristics and operating
constraints. Hydro generation for each area
with instantaneous maximums, off-peak
minimums, and sustained peaking constraints
are also input. Demand-side resources and
price-induced curtailment functions are
defined, allowing the model to balance use of
generation against alternatives to reducing
customer demand.
AURORA xmp uses this information to build an
economic dispatch for the markets. Units are
dispatched according to variable cost, subject
to non-cycling and minimum run constraints
until hourly demand is met in each area.
Transmission constraints, losses, wheeling
costs and unit start-up costs are reflected in
the dispatch. The market-clearing price is
then determined by observing the cost of
meeting an incremental increase in demand in
each area. All operating units in an area
receive the hourly market-clearing price for
the power they generate.
AURORAxmp also has the capability to
simulate the addition of new-generation
resources and the economic retirement of
existing units. New units are chosen from a
set of available supply alternatives with
technology and cost characteristics that can be
specified through time. New resources are
built only when the combination of hourly
prices and frequency of operation for a
resource generate enough revenue to make
construction profitable; that is, when
investors can recover fixed and variable costs
with an acceptab~e return on investment.
AURORA xmp uses an iterative technique in
these long-term planning studies to solve the
interdependencies between prices and changes
in resource schedules.
Existing units that cannot generate enough
revenue to cover their variable and fL'(ed
operating costs over time are identified and
become candidates for economic retirement.
To reflect the timing of transition to
competition across all areas, the rate at which
existing units can be retired for economic
reasons is constrained in these studies for a
number of years.
In summary, AURORA,mp simuhtes the economic
dispatch of resources to meet demand
requirements. AURORA"np:
Solves the whole system dispatch
simultaneously.
Dispatches hourly (\\-'ith sampling
capabilities, where appropriate).
Determines the market-clearing prices
from marginal costs.
Values all the resources in the system.
Prov'ides price and value forecasts for each
time period being studied.
Drivers and Inputs
AURORAxmp uses the fundamental economic
drivers of the electric market to make its
forecast. That information includes:
Electricity demand by geographic area;
annually and monthly including hourly
shapes.
Supply-side resources (all major
generating units) in the system. Resource
heat rates, fuel types, resource-
commitment data and other resource
information. Future resource alternatives
are used in long-term optimization
studies.
Demand-side resources including an
interruptible price curve.
The information herein is copied in part with permission from the AURORATM Electric Market Model- Technical Information on
Model Software and Databases document. for the intent and purpose of the I daho Power Company 2004 I ntegrated Resource Plan.
All or parts of this information may not be reproduced without the written permission of EPIS.
(Q Copyright 2002 EPIS, Inc. All rights reserved.
2006 Integrated Resource Plan Page 109
Appendix 0- Technical Appendix Idaho Power Company
AURORAxmp Technical Summary
2004 I ntegrated Resource Plan
Idaho Power Company
Page 3 of 3
Fuel prices by fuel type and location.
Hydro information for AURORA xmp,
hydro-optimization logic.
Transmission costs and constraints.
For uncertainty analysis, Monte Carlo
sampling from statistical distributions for
demand, fuel prices, hydro conditions and
other drivers is used to forecast price
distributions.
Users manage the cases and analyze the
drivers to electricity-market forecasts by
selecting the underlying assumptions of the
analysis. The projections are created using
assumptions for the chosen inputs, such as
electricity demand growth, fuel prices, and
gas-fired combined-cycle generation efficiency
and cost. For example, the low electricity
market scenario could include low-demand
growth, low fuel prices, and optimistic
assumptions about combined-cycle
combustion turbines. The combination of
assumptions may consist of outcomes that the
user believes are plausible. A user can model
the conditions, cases and options a decision-
maker wants to evaluate. Without any
programming, you determine the assumptions
used in each forecast or study.
,c'
, '
The information herein is copied in part with permission from the AURORATM Electric Market Model - Technical Information on
Model Software and Databases document. for the intent and purpose of the Idaho Power Company 2004 Integrated Resource Plan,
All or parts of this information may not be reproduced without the written permission of EPIS.
(Q Copyright 2002 EPIS, Inc. All rights reserved.
\..
Page 110 2006 Integrated Resource Plan
20
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Initial Portfolios Scenario Sensitivity Ranking
Total Cost-Expected, GHG $50, GHG $0, High Gas (PV 20 Years 2006-2025)
Total Cost
Years 1-Average
Portfolio Expected GHG50 GHGZero HighGas Average Rank
P1 Green Portfolio (F1)983,722 552,013 337 781 $4,305,141 044 664
P2 Transmission Trans, CT, Nuc 351 123 520,496 $4,497 314 297 094 $5,666,507
P3 2004 Preferred Portfolio (F2)964 772 190,763 056,509 511,564 $5,180 902
P4 Thermal Portfolio (F3)841 685 455,705 774 511 124 336 $5,049,059
P5 Thermal Clean Coal, NG, Nuc 266 369 609 253 295 187 603 822 $5,443 658
P6 2004 Preferred Coal, NG, Geo 944 319 384 550 $3,945 024 $4,416 225 172 530
P7 2004 Preferred Coal, NG, Trans 997 609 525 667 975 240 $4,477 690,244 052
P8 2004 Preferredd NG, Coal, Wind 812 681 $6,934 922 $3,930 606 $4,421 864 025 018
P9 = P6 - IGCC w CS 970 712 993 532 132 351 $4,442 368 134 741
P1 0 All Coal, Nuc, Trans 971,787 580,152 $3,895,904 242 195 172 510
P11 Transmission Portfolio (F4)870,035 999 247 999,247 $5,295,614 $5,291,036
P12 Nuclear 796 034 $6,696 660 $3,989,497 008 331 872 631
Rank by
Ranking Expected GHG50 GHGZero HighGas Total pts Total Pts
P1 Green Portfolio (F1)
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P8 2004 Preferredd NG, Coal, Wind
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P11 Transmission Portfolio (F4)
P12 Nuclear
Resource Cost (Excludes Market Purchases and Sales)
Years 1-Average
Portfolio Expected GHG50 GHGZero HighGas Average Rank
P1 Green Portfolio (F1)$7,348,136 $8,164 025 $6,509,463 505,962 $7,381,896
P2 Transmission Trans, CT, Nuc 600,116 368,985 796 771 $5,596,582 $5,590 614
P3 2004 Preferred Portfolio (F2)313,858 531 485 $5,331 752 408 199 396 324
P4 Thermal Portfolio (F3)227 009 $8,920,298 $5,999,133 330,232 $7,369,168
P5 Thermal Clean Coal, NG, Nuc $7,431 968 936 119 315 641 531 453 553 795
P6 2004 Preferred Coal, NG, Geo 156 598 723 322 $6,022 322 $7,411 142 328 346
P7 2004 Preferred Coal, NG, Trans 650 659 138,429 534 508 $6,742 242 $6,766 460
P8 2004 Preferredd NG, Coal, Wind 026,768 301 288 015 482 $7,418,093 190,408
P9 = P6 - IGCC w CS 182 044 328 189 212 225 $7,438 398 290 214
P10 All Coal, Nuc, Trans 503 565 299 812 241,4 72 658 642 675 873
P11 Transmission Portfolio (F4)860,774 $6,863,462 863 462 $8,003,789 397 872
P12 Nuclear 500 132 748,451 484,438 650,356 595 844
Rank by
Ranking Expected GHG50 GHGZero HighGas Total pts Total pts
P1 Green Portfolio (F1)
P2 Transmission Trans, CT, Nuc
P3 2004 Preferred Portfolio (F2)
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P5 Thermal Clean Coal , NG, Nuc
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P7 2004 Preferred Coal , NG, Trans
P8 2004 Preferredd NG, Coal, Wind
P9 = P6 - IGCC w CS
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P11 Transmission Portfolio (F4)
P12 Nuclear
2006 Integrated Resource Plan Page 141
Appendix 0- Technical Appendix Idaho Power Company
Green Portfolio (originally P1)
Total Total
On-Line Average Peak Total Average Energy Total
Date Resource Nameplate Peak Energy DSM Trans Peak Energy DSM Trans
2006
2007
2008 Wind 100
2009 Geothermal (Binary)100 107
2009 Wind 200 110 141
2010 CHP 186 223
2011 Wind 200 217 292
2011 Geothermal (Binary)267 296
2012 Geothermal (Binary)335 395
2013 CHP 100 100 451 491
2013 Wyoming Pulv. Coal 250 250 220 701 654
2014 Geothermal (Binary)765 764
2015 777 769
2016 McNary-Boise 225 225 787 771 225
2017 LoLo to IPCo 790 773 285
2018 Geothermal (Binary)843 824 285
2019 Geothermal (Binary)896 874 285
2020 Geothermal (Binary)949 924 285
2021 Geothermal (Binary)002 975 285
2022 INL Nuclear 250 250 230 254 207 285
2023 257 209 285
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2025 262 214 285
835 075 124 187 285
Resource Summary
Wind 500 Peak 262
Geothermal (Binary)400 Average Energy 214
Coal 250 Transmission 285
CHP 150 DSM Peak 187
Transmission 285 DSM aMW
Max Energy Deficit (312)
Nuclear 250
Total Nameplate 835
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2004 IRP Preferred Portfolio (originally P3)
Total Total
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Date Resource Nameplate Peak Energy DSM Trans Peak Energy DSM Trans
2006
2007
2008 Wind 100
2009 Geothermal (Binary)100 107
2010 CHP 176 161
2011 197 168 - 44
2012 Wind 150 223 222
2012 McNary-Boise 225 225 223 222 225
2013 Wyoming Pulv. Coal 250 250 220 489 448 225
2014 503 453 225
2015 515 458 225
2016 525 460 225
. 2017 RegionallGCC Coal 250 250 200 778 662 225
2018 780 665 225
2019 LoLo to IPCo 783 667 285
2020 CHP 100 100 886 759 285
2021 Geothennal (Binary)939 809 285
2022 Geothermal (Binary)992 859 285
2023 INL Nuclear 250 250 225 244 086 285
2024 247 089 285
2025 250 091 285
585 063 001 187 285
Resource Summary
Wind 250 Peak 250
Geothermal (Binary)150 Average Energy 091
Coal 500 Transmission 285
CHP 150 DSM Peak 187
Transmission 285 DSM aMW
Max Energy Deficit (312)
Nuclear 250
Total Nameplate 585
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Basic Thermal Portfolio (originally P4)
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Date Resource Nameplate Peak Energy DSM Trans Peak Energy DSM Trans
2006
2007
2008 Wind 100
2008 CHP
2009 Geothermal (Binary)150 152
2010 176 161
2011 197 168
2012 Wyoming Pulv. Coal 250 250 220 465 395
2013 482 401
2014 496 406
2015 507 411
2016 Regional Pulv Coal 300 300 264 818 677
2017 820 679
2018 170 170 993 682
2019 996 684
2020 IGCC 300 300 240 299 926
2021 301 929
2022 INL Nuclear 250 250 225 554 156
2023 557 158
2024 560 161
2025 562 163
1,470 375 073 187
Resource Summary
Wind 100 Peak 562
Geothermal (Binary)Average Energy 163
Coal 850 Transmission
CHP DSM Peak 187
Transmission DSM aMW
170 Max Energy Deficit (312)
Nuclear 250
Total Nameplate 1,470
Page 146 2006 Integrated Resource Plan
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Bridger to Boise Transmission Portfolio (originally P11)
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Date Resource Nameplate Peak Energy DSM Trans Peak Energy DSM Trans
2006
2007
2008 Wind 100
2009 CHP 100 104
2009 Geothermal (Binary)150 124
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2013 232 181 225
2014 246 186 225
2015 257 191 225
2016 Bridger- Boise 900 525 268 193 750
2017 Wyoming Pulv. Coal 250 250 220 520 415 750
2018 Geothermal (Binary)573 466 750
2019 Geothermal (Binary)626 516 750
2020 Wind 100 636 557 750
2021 Wind 100 646 598 750
2022 Wind 100 657 637 750
2023 Wind 100 667 674 750
2024 INL Nuclear 250 250 225 920 902 750
2025 923 904 750
325 736 814 187 750
Resource Summary
Wind 500 Peak 923
Geothermal (Binary)150 Average Energy 904
Coal 250 Transmission 750
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Max Energy Deficit (312)
Nuclear 250
Total Nameplate 325
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Appendix 0- Technical Appendix Idaho Power Company
Portfolio F1
Estimated Total Resource Investment (Including AFUDC)-By In-Service Year
(In $OOOs)
2010 2011 2012 2013 2014 2015Resource 2006 2007 2008 2009Wind (100 MW) 177 691
eothermaI(SO MvV
----------------- -- - ------'------
202,502
Wind (iOOM
------------- -
- --,- ,m -
- ----
366,043
CHP(50-
- ---------------------- -
,_--n_,__- --
- -- ---_
m__- --- -
56:150
Wind(200 MW)
--------------------------- --- ---
--,- - --------- -,-_____--n-
------ --
388;335 -----
otherma 50 MW)
--------------
---------_____--m- -
214;834 -
othermal (50 rVfWj---------------
,---,-----
,_____m__
____------------ -------------
--- 221 280
cHP(-jOoMw-j-----
----------------'-- ----------------- ---- -
- n
_- --
122)14-
~~~~~~6
~~~_--------==~=~~:--~~---~---- ~_:__::=:=_:-=::::_::::_,
- -- u-
- -, ----- --=_
~~~:~6~ - 234
755 -
- - -
McNary to IPC Transmission (225 MW)
~CTransmiSSiOn(6OMW)-
--:==:::-'------ -- --
-Un --
Geothermal (50 MW)
GeothermaI(SO rVfWf---
------------- .-
Geothermal (50 Mwf
---,-,---,-_____--______-,------------,--------
GeottiermaJ(50-M'W)- un -- -
---------- --'-- - ---- --,- ------------------- --, -------,,---
INL Nuclear (250 MW)
-'---------'------'--------------- ---
Geothermal (50 MW)
------'-------------------._-
Backbone Transmission -------23f
----
g,'i10 -----z:i,005 49,1S---119 731 -- 135,218'-- 262,510-
'---
153-;-869
- -
1,773--- 0
,-,--------------- - __- _------------'----------------- -
Real Dollars_____--......
........,.....-.,......,..,
231 710 198 696 617 860 175 882 738 387 483 790 931,949 236 529
Present Value.........................,..............231 080 173 749 505,232 134,490 527,982 323,488 582,722 138 299
Cumulatil.e MWs....................................100 350 400 650 700 050 100 100
Cumulatil.e Real Dollars...........................231 941 213,636 831,496 007,378 745,765 229,555 161 504 398,033 398 033 -
Cumulatil.e PV........................................231 311 188,060 693 292 827,781 355,763 679,252 261 973 2,400,273 2,400 273
PPA Real Dollars....................................177 691 568 545 56,150 603,169 221,280 122 714 234,755
Cumulatil.e PPA Real Dollars...................177 691 746,235 802 386 1,405 555 626 834 749,549 984 304 984,304
PV PPA Real Dollars..............................155 381 464 906 936 431 295 147 960 76,730 137 262
Cumulatil.e PV PPA Real Dollars.............155,381 620 288 663,224 094 518 242,478 319 208 1,456,470 1,456,470
Ownership Real Dollars...........................231 710 21,005 49,315 119 731 135,218 262,510 809 235 773
Cumulatil.e Ownership Real Dollars..........231 941 35,946 261 204,992 340,210 602,720 1 ,411 ,955 1,413,729 1,413 729
PV Ownership Real Dollars...........
...........
231 080 368 326 91,554 96,687 175,529 505 992 037
Cumulatil.e PV Ownership Real Dollars.....231 311 679 73,004 164 558 261 245 436 774 942 766 943 803 943,803
Resource 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Wind (100 MW)
Geothermal (50 MW)
Wind (200 M
CHP (50 MW)Wlnd(206M~'------
-------- ---------- -----
Geothermal (50 MW) ,-
-------------------
__,___m______---------------
--'----,,-----,
13eo!!,ermal (50 MwT--
----=-=~==::=:=-::==:=-_-=:':'-=----::=:::_==:-=:~=:::==-=:::::_-----
CHP (100 MW)
Wyoming Coaj(25OMWf-------
-------------------------------------,-------- -
- _u_
- -
--_u-
GOOthermal (50 MW)
---------------------------------------'---'
~~~;I
~~I~~:;~~:~~ss ~~~ ~~) MWj ------m:964---
~;~-:::--::==::===:=====---=-:--::=- --,--- -- - ----_.--- --------------------
Geothermal (50 MW)
-- ------'---------
264~19------------'---
--
-- __n,___- -- - ---
Geothermal (50 MW) ---------'----'----
------'--'------------
272;146----'--- - ,---------
----------------------
Geothermal (50 MW)
-----------,- ---------------------------'--
280;-31"'0" ----
- ---- ----- ",,-,-
Geothermal (50
---------------'--' ._, -----'--'----------"-
288:720--- -
--,.. -
ININUc~25DM\i\'-)
--------
--- ____on
,------
- ----_u_u_--------
-- -----------------
99:272" - ---
~:~~~::4 ~~s ~:~ Orl--
~=:-=
=- O
====
O-- u
=;,
~32---
~;:~=-=::':;:;~:~-=- =::- ~~:~~ '~---::=-----~:::: _,
H~~ --
---
------, __un_
____--- ---,-----,-----,
_u_---------------u_----
------------------ -
--- u- -,-----"
,---------- -------------,----- ------- -----
Real Dollars.....................................,.....112,904 16,332 267,451 275,475 264,530 323,333 1 ,044,614 317,875
Present Value...........................,...,........727 809 119 577 115 173 111,241 118,210 357 131 030
Cumulatil.e MWs....................................325 385 1,435 1,485 535 585 835 835 885 885
Cumulatil.e Real Dollars........................... 3,510 936 527 269 794 720 070,194 354,725 678,057 722,672 722 672 040,547 040,547
Cumulatil.e PV........................................ 2,458,000 2,465 808, 2 585,386 700 559 811 800 930,011 287 142 287,142 382 172 382 172
PPA Real Dollars....................................264 219 272,146 280 310 288,720 999 272 315,492
Cumulatil.e PPA Real Dollars...................984 304 984 304 248 523 520,669 800,979 089,699 088,971 088,971 4,404,463 4,404,463
PV PPA Real Dollars..............................118,132 113,782 109,592 105 556 341 630 94,318
Cumulatil.e PV PPA Real Dollars.............1,456,470 456,470 574 602 688,384 797 976 903 531 245,161 245,161 339.479 339,479
Ownership Real Dollars...........................112 904 16,332 232 329 220 34,613 45,343 383
Cumulatil.e Ownership Real Dollars..........526,632 542 965 546,196 549,525 553,745 588,358 633 701 633,701 636,084 636,084
PV Ownership Real Dollars......................727 809 445 392 650 12,655 15,502 713
Cumulatil.e PV Ownership Real Dollars.....001,530 009,338 010,783 012,175 013 825 026,479 041 981 041,981 042,694 042,694
Page 154 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Portfolio F2
Estimated Total Resource Investment (Including AFUDC)-By In-Service Year
In $0005Resource 2006 2007 2008 2009 2010Wind (100 MW) 177 691
Geothennal(50 r-------'------
----- . ----------------- --
202':502 - -
B.f(50~MWL==--
-=-~==~==-~~-=--==-==~=-~==-=:_=~=~:=-=::-::-::=-- --
----_u_--
- 56,150
_om
---
Wind (150 MW) . 299,988
McNarytoIPC Tran lSsion(225MWY--------------" -
-------,--,.._--
-,--u
.-- '--
100 31'
Wyoming C08l(250 MW)-
~-~-------
_--_--u_nu_- 655,
366
egionallGCCCoal (250 rvjwT-
~---______
n______n_____--
---_---._--. ---- - -..-
- ____--n____-- U, -
.. -
LololQiPC System (60 MWf--~n--~_n__'___---------
----
---'--- ,--___m_nu_--
--, -- ------'---- - _---__-
HP (100 MW --"'--~-_--____n______---~----
---._--,
---u~~..'_--__n---,_.,___,..m ,-
---..-..--- ,---, -- --_
--un' no_. M___--
----
Geothennal (50 MW)---_n--__~m
_____'------------- - -------,
_u
-- ----.. _
_-,_u_,---,..--
,-- -----
Geot enna (50 MW),----_nn- 'n------- - -- _n
~---------~,------ ---------- _.,- -~- ,-- -- .. - -- -
1NLNUC1ear(250MW)-
---=--=-==-==:== =:::==:~-=-=== :::_: ..=:==-:- ::::=:::=---:::.::-----.-------.:::- =:.
-: -- ---- .n- - --- -
- - --.' -:=== -=:::==::::-
Backbone Transmission 7 237 14,074 12 003 25,278 55,583 70 023 299,931 198 893 6,433 13,859
2011 2012 201520132014
------ --
Real Dollars..................................-........
Present Value.....................,..................
Cumulati-..e MWs....................................
Cumulati-..e Real Dollars...........................
Cumulati-..e PV...,....................................
PPA Real Dollars....................................
Cumulati-..e PPA Real Dollars...................
PV PPA Real Dollars...,..........................
Cumulati-..e PV PPA Real Dollars.............
Ownership Real Dollars...........................
Cumulati-..e Ownership Real Dollars..........
PV Ownership Real Dollars......................
Cumulati-..e PV Ownership Real Dollars....
237 074 189,694 227 780 111 733 023 700 233 854 259 6,433 13,859
237 13,161 165,878 186 258 85,438 069 468,214 534 144 761 578
100 150 200 200 575 825 825 825
237 21,311 211 005 438,785 550 518 620 541 320,773 175 032 181,465 195,324
237 20,398 186 275 372,534 457 972 508,041 976,255 510 399 514,161 521,738
177 691 202 502 150 299 988
177,691 380 193 436 343 436,343 736 332 736,332 736 332 736 332
155,381 165,589 42,936 200,589
155,381 320,970 363,906 363 906 564 495 564,495 564,495 564,495
237 14,074 003 25,278 583 023 400 244 854 259 6,433 13,859
237 21,311 33,314 592 114 175 184 198 584,442 1,438,701 445,133 1,458,992
237 161 10,496 670 502 50,069 267 625 534,144 761 578
237 20,398 894 564 94,066 144 136 411,761 945 905 949,666 957 244
Resource
Wind (100 MW)
Geothennal (50 MW)
CHP (50 MW)
Wind (150 MW)
McNary to IPC Transmission (225 MW)
Wyoming Coal (250 MW)
RegionallGCC Coal (250 MW) '----~---------g:j3,616------,u_'n--_----
--__
--n _--__n-- -
----- --- --
--__n' --_n__- ---,----- -
----------
_.n_n'___- - ..---- ,--,~-----_--_u__n__
____----
- _n __,un_,_,__--__--_n .------ n____n--_-
Lolo to IPC System (60 MW) ------~-_nO--
-----
~~2..._--------------
-~---,--,--,----
-,---------u_------------CRP(100 MW) ~====----~--_--____nun__--__
- _~___
1~~~~:3..._____n__-- -- _n
--- --- - ---- - ~--~-
Geothennal (50 MW)288,720Geothennal (50 MW)
----
-~----~--------u~--
~~--------~-----
297:381u---,--_n
- - _
_--_n
--_
INL Nuclear (250 MW) ------
---------,_
--------,___-un_--_,_-----
--- ---'-------
029,250'
--
-----------_u_-----
ackbone Transmission-nn--~-n-----57:n3(46 3)---n----267----' -----2;649----' ---(3,7;56rn'--3'-G;s7- 176 9 _n_--162;'59if --
- -- -
- 0-- 0
2016 2024 20252017202220232018201920202021
- _----n__--
------~
---___n'_n'_____----u---
_---._- -----
u,-- -n--n_--,_,_-- -- -- --u.--------------~------_._---_.,-----------,------,_u_----
-- --, - -~,-, -----.- . ---
---,-----------'u---------------_u_
--- '-------
-----------__,_.---n___
-- --- _
,--n-_------------
-- .---------------~,--------,'--'-_. -- ---____
--_mn- ,no --- ---
,. ,----._-------------
_, _nO- --~--,-
-------------------------. ---, _
'_--n__.n____u--
---'~--~--
Real Dollars................,......,.........,....,....723 867,112 267 976 147 167 320,376 473,680 191 846
Present Value...........,............................29,514 414 584 120 352 537 117 129 161,941 381 030
Cumulati-..e MWs....................................825 075 075 135 235 285 355 585 585 585
Cumulati-..e Real Dollars"."...."....."",......253,047 120,159 120 427 140,403 287 570 607,947 081 626 273,473 273,473 273,473
Cumulati-..e PV""".,.""".".,..",.""".",.",551 252 965,836 965 955 974 307 031 844 148 973 310,914 691,944 691 944 691 944
PPA Real Dollars......."........"......".........150 923 288 720 297 381 029,250
Cumulati-..e PPA Real Dollars...."."..........736 332 736,332 736,332 736,332 887 255 175,974 1,473,355 502,606 502,606 502,606
PV PPA Real Dollars..........."".".""""",006 105,556 101 668 329,048
Cumulati-..e PV PPA Real Dollars,............564,495 564,495 564,495 564,495 623,500 729 056 830,724 159 772 159,772 159,772
Ownership Real Dollars...........".....".......723 867 112 267 976 756)657 176,299 162,596
Cumulati-..e Ownership Real Dollars.".......516 716 383,828 384,095 404 072 2,400,315 2,431 972 608,271 770 867 770,867 770,867
PV Ownership Real Dollars"..."...............29,514 414 584 120 352 (1,469)574 60,273 51,982
Cumulati-..e PV Ownership Real Dollars.....986 757 1 ,40 1 ,341 401,461 1,409,813 1,408,344 419 918 480,190 532,172 532 172 532,172
2006 Integrated Resource Plan Page 155
Appendix 0- Technical Appendix Idaho Power Company
Portfolio F3
Estimated Total Resource Investment (Including AFUDC)-By In-Service Year
In $OOOs
2011 2012 2013 2014 2015Resource 2006 2007 2008 2009 2010
ind (1O0 ---------______mn______----- --_1!!,~9.~-- -- -- ____un ._'u
CHP (50 MW)52;927 -
Geoihermal (50
---------------------------------
262-:-502- ---_u_----,------
---_..,
'----- ..._n______-
------
~~~::l
~~(
1~~0
~~T
~~~~=~==-==~=~~~~=::~-~-~~ ~ "-=~~--=~~=-:~:~, :- . . _
__un ~~~,
~~~-~=::=~~_
=~n_
~:~=:=: =:
Industrial CT (170 MW)
~~~onal IGCC Coai(300MW)==-
~=_~::::_':::::'::='::':::':===-_'::':=-~-~:-=:_-=-:=:-:=--_: -- --:::: ------, ---.._--------~ -.--====---=
INL Nuclear (250 MW)
' '--'-
Backbone Transmission
---- . ,--- --'--
42:f---'2~116-
---
(5,260T-
--'
2;69-i- - --6~356-
- - -
356--'- (88,273)-----6;356
----
25;423-
- -
67~240-
,._--,_. -- ----, ,.,--,,_._.,--~
.m_
Real Dollars...............................,...,.......423 116 225 358 205,199 356 356 548 004 356 25,423 240
Present Value........,....,.".......,....."....,...423 979 197 064 167 794 860 545 366,426 974 865 36,765
Cumulati\e MWs....................................150 200 200 200 450 450 450 450
Cumulati\e Real Dollaro...........................423 540 227,898 433,097 439,453 445 809 993,813 000,169 025,592 092 833
Cumulati\e PV.............................,..........423 402 199,466 367,261 372,121 376 665 743,091 747,065 761 930 798,695
PPA Real Dollars....................................230,618 202,502
Cumulati\e PPA Real Dollaro...................230,618 433,120 433,120 433 120 433 120 433,120 433,120 433,120
PV PPA Real Dollaro..............................201 663 165 589
Cumulati\e PV PPA Real Dollars.............201 663 367 252 367 252 367 252 367,252 367,252 367 252 367 252
Ownerohip Real Dollars,..........................423 116 260)697 356 356 548,004 356 25,423 240
Cumulati\e Ownerohip Real Dollaro..........423 540 (2,720)(23)333 12,689 560 693 567 049 592,472 659,713
PV Ownerohip Real Dollaro.................
.....
423 979 599)206 860 545 366,426 974 865 765
Cumulati\e PV Ownerohip Real Dollaro.....423 2,402 197)869 413 375,839 379,813 394 678 431,443
Resource 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Wind (100 MW)
C HP ( 5OMW )
--=--==-=--==::: ===-.:: == ::~ :- ::::==--==.: -:--_== :':' ~-- =.:- ==.: ':.: -: =_: =~..::: -=: ': ~.:= =.-~:: ~ ::::::-:- =: -=- -::: ~::::'
Geothermal (50 MW) ----
- -
Wyoming Coal(25OMVv)
_.~,-------,-------------------"----_. --------- ".----------- ---,-----
Regional Coal (300 MW) 735 814'
-----'------'-----------------'--"-
----'-,-------u
_..,-------------
- ---- _n --.
---- ----
_n-- - -
--- -- ----,------
-' - n,
__-
Industrial CT (170 MW)121,858
----------., ---- ----------,_._-
_._----,--- --n__- u_
-----,-_._-'- -,-,-, ,------------- ,-----
RegionallGCC Coal (300 MW) 1,197 999INL Nuclear (250 MW) --
------'-
999;272------
--------
Backbone Transmission 158 156 272 737 (3,288) 22,261 (111,944) 767 5~1O6-------:;3z,465 133;566'"---
Real Dollars...........................................893,970 272,737 118 570 22,261 086,055 767 004,378 132,465 133 566
Present Value............
:..........................,
457 081 130,401 012 307 424 610 205 343,375 42,349 39,930
Cumulati\e MWs.....,..............................750 750 920 920 220 220 470 1,470 470 1,470
,-.
Cumulati\e Real Dollaro...........................986 803 259,540 378,109 400 370 3,486 425 3,495,192 499,570 632 035 765 601 4,765 601
Cumulati\e PV..................,.....................255,776 386,177 1,439,189 448,496 873,106 876 311 219 686 262,035 301,965 301 965
PPA Real Dollaro...............,............,....,..999,272 \c.;,
Cumulati\e PPA Real Dollaro..,..,.............433,120 433,120 433,120 433,120 433 120 433 120 1,432 392 432,392 432,392 1,432 392
PV PPA Real Dollaro..............................341 630
Cumulati\e PV PPA Real Dollars.............367,252 367 252 367 252 367 252 367,252 367 252 708,882 708,882 708 882 708,882
Ownership Real Dollars..................,........893 970 272,737 118,570 22,261 086 055 767 106 132 465 133,566
Cumulati\e Ownerohip Real Dollaro..........553 683 826,420 944,989 967 250 053,305 062,072 067 178 199 643 333,210 333,210
PV Ownership Real Dollaro...................,..457,081 130,401 53,012 307 424,610 205 746 42,349 930
Cumulati\e PV Ownerohip Real Dollaro.....888,524 018,925 071 937 081,244 505,854 509 059 510,805 553,154 593 084 593,084
. '
Page 156 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Portfolio F4
Estimated Total Resource Investment (Including AFUDC)-By In-Service Year
In $OOOsResource 2006 2007 2008
~indJ100
~~- ..-- ------------------.------- _
~?7~~1Geothennal (50 MW) '262~sb-2 .
CHp(50MWf.
-----_.
__._n- _._---,- ------- __n____- . .. -__'--_.m_-
54~515
McNary -toIPCSyste;m(22S-wf-- ----.----
----, -
nn- ---
---- --
_n______- ...
BrldgertOlPC-TransmlssJOn(900MWj'- ,--_._,--
-.-..-----
WyorriTngCoal(250-MWT-----m_-- --n_--_
- _.
. _n____--__n
Geot~aT()MW)----__nn__
__._-----
-----,------- nn_- _n
- -----------------
Geothennal (5'0 Mwy---.__nn'._.__'.-'-.'___'__m_- -_.,---- .-- ,,--- _m
- _
_--._'mn ____un no - ,., 'm_
- ,-- -".
"'- m nn- ..
- -,._----,---
ind (100 MW)---"'- ._--
-,,-
- __nn
.__----.- - _
n -
- -,-
Wind (100 MW)
-------------------- '--.---------- .-",.. ...--
-- --- no -
-..
iild('1OOfii1liYf-------- u_-.n___.. m____-"-__n_--_---__
Wind (100 MW) "-
'------'------"---_
.._------_.--'____n___,__.
..,--------_._.
INLNuclear(250fii1W)
_--_- -
--,-, .-. n
_-------.,-.-- .---
Backbone Transmission ___nn ;10 515-".25-;-953 34 251 21 994
2009 2010 2011 2012 2013 2014 2015
.n.
-, -
100,313.
un -
-".._--_
nn__'_' ,u--.
----
""--.--u.....---
..-._'__'_m ---.---.
--,...- -,.,--,-_._-_.
--,---_no--_._,m._m_,____,-
,....._____
n.---
781 257,419 .246,485 225 13,893 723
Real Dollars......................................10,515 953 211 941 279 011 781 257 419 346 799 225 893 46,723
Present Value........................................515 269 185 332 228,151 242 184,067 231 889 143 123 547
Cumulati\e MWs....................................100 200 200 200 425 425 425 425
Cumulati\e Real Dollars......,.,............10,515 36,469 248,410 527,421 589,202 846,621 193 420 201,644 215,537 262,260
Cumulati\e PV.....................................515 34,785 220,117 448,267 , 495,509 679,576 911 464 916,607 924,730 950,277
PPA Real Dollars.................................177 691 257 017
Cumulati\e PPA Real Dollars...................177 691 434 708 434 708 434 708 434,708 434,708 434 708 434 708
PV PPA Real Dollars..............................155 381 210,166
Cumulati\e PV PPA Real Dollars.............155,381 365 547 365,547 365,547 365 547 365,547 365,547 365 547
Ownership Real Dollars...........................10,515 25,953 34,251 994 61,781 257 419 346 799 225 13,893 723
Cumulati\e Ownership Real Dollars..........10,515 36,469 70,720 713 154,495 411,913 758,712 766 936 780,829 827 552
PV Ownership Real Dollars.............,........515 269 951 17,984 242 184 067'231,889 143 123 25,547
Cumulati-.e PV Ownership Real Dollars.....10,515 785 64,735 720 129 962 314 028 545,917 551 059 559 183 584,729
Resource 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Wind (100 MW)
Geothennal (50 MW)
CHP (50 MW)
McNary to IPC System (225M~
-----------------------'_.'---_.__._'..'----'---.----..---,--,-..------------------
Blidger to IPC Transmission (906 MW)
--
, 144 931----"'------
-----------'----'------_._-'--"--,-,--_.. -..----'------------'------_"'---'---'_._-'.-----,
- un .
..--,-_. ----.---'---.
Wyoming Coal (250 MW) 615,377
Geothennal (50 MW)264~2'f9------------------_._--------
-------------
Geothennal (50 MW)
------------------------~--
272:t46
---------_._-'-'--- ,----,-------_.
'-------_U_----
Wind (100 MW)
----_._-------
253,344----------'-'--'--- m_
_-_----'--------.-
Wind (100 MW)
-----------_.- __
h______- ---------260;945----._----- ,--
_._-_.,--------,
\iVindT10OMW)-
== =-====~=-~ :==---=-== ~ ~~~. = -= ~- -=: =-~=: =--==---==-~. .=--= .=: =.-=:. . =
'26 8, ~tL -
~.~ =.. ==-=- =: - =: ~~. =-: =- =-=:.
Wind (100 MW)276,836
INL Nuclear (250 MW) --.-_no.
------.--------.---...-,----------------,--.-,-,--------..-----.
060. f2S.-------'---
Backbone Transmission
-- __-
non, --49-;3of---12;586 . ---28,1oa--116;!J;iz--1'25,844 .91~3Z6-.- --89.222--- -(18~f81).--(14;471f-------6--
_--__n_,.__-----uo'-_.
------,,-----_. --,..._,.._-,----,_..,_._,,----- ---------- --.-- "----..---.---
--------,_on_----------
---_..._._,-,-_._-- ... --.-...,-,..-.- ---- ..,.---,-..------.-------.--
Real Dollars..............................._....,...-194 233 627 963 292 327 388,788 379 188 352,271 357 995 258,655 045,657
Present Value.........-....................-.....-610,603 300 242 130 699 162 549 148,249 128,790 122,391 691 312,604
Cumulati-.e MWs....................................325 575 625 675 775 875 975 075 325 325
Cumulati-.e Real Dollars...........................2,456,493 084,456 376 783 765,571 144,759 497 029 855 024 113,679 159 336 159,336
Cumulati-.e PV........................................560 880 861 121 991 821 154,369 302,619 2,431,408 553,799 636,490 949,095 949,095
PPA Real Dollars....................................264 219 272,146 253,344 260,945 268,773 276 836 060 128
Cumulati-.e PPA Real Dollars...................434 708 434,708 698 927 971,073 224,417 1,485 362 754,135 030 971 091 099 091,099
PV PPA Real Dollars..............................118 132 113,782 99,049 95,401 888 88,504 316 931
Cumulati-.e PV PPA Real Dollars.............365,547 365 547 483,680 597 461 696 510 791,911 883,799 972,303 289,233 289,233
Ownership Real Dollars...........................194,233 627 963 108 116 642 125 844 326 89,222 (18,181)(14,471)
Cumulatl-.e Ownership Real Dollars..........021 785 649 748 677,856 794 498 920,342 011 668 100,889 082,708 068,237 068,237
PV Ownership Real Dollars......................610 603 300,242 567 48,767 49,200 389 503 813)(4,326)
Cumulati-.e PV Ownership Real Dollars.....195,332 1,495 574 508,141 556 908 606,108 639 497 670,000 664 187 659,861 659,861
2006 Integrated Resource Plan Page 157
Appendix 0- Technical Appendix Idaho Power Company
SUMMARY OF NORTHWEST UTILITY PLANNING CRITERIA
Avista Corporation Peak Load: The maximum one-hour load obligation on the expected average coldest
day in January. 5
Peak Resource Capability: The maximum one-hour generation capability of company
resources, plus the net contract contribution.
Planning Reserve: Ten percent (10%) of the one-hour system peak load, plus 90 MW.
Confidence Interval: Eighty percent (80%) confidence interval based on the monthly
variability of load and hydroelectric generation. "This means that for each month there is
only a 10% chance that the combination of load and hydro variability would exceed the
planning criteria.
Bonneville Power
Administration
Load and Resource Balances: System firm energy loads are compared with Federal
system energy resources for each month of Operating Year 2002-2007 (August 2001-
July 2007) under 1937 water conditions. Firm capacity surpluses or deficits are
determined in the same period under 1937 water conditions.
Energy: Based on current generation capability under critical stream flow conditions.
The critical period is defined as historical stream flows that occurred from September 1
1936 through April 30, 1937.
Surplus Energy Analysis: Defined as the amount of generation that can be produced in
excess of firm loads under critical water conditions.
Regional Firm Monthly Peak Load Projections: The peak loads are estimated based
on normal weather conditions using a 50-percent probability that the forecasted peak
load will be exceeded. Total Federal peaking capacity reduced by reserves for forced
outages that are calculated as fifteen percent (15%) of large thermal project output plus
five percent (5%) of the output of other resources.
Hydroelectric Energy Capability: Uses OY I 937-water conditions (the 12-month
period from August 1936 through July 1937) to estimate the firm hydro energy
capability in low water conditions.
Hydroelectric Capacity: The monthly instantaneous capacity of hydroelectric projects
is defined as the full-gate-flow maximum generation available at each project, based on
the average monthly elevation resulting from 1937 -water reservoir levels. BP A assumes
1937 -water levels to estimate the regional hydroelectric capacity because that year
approximates a peaking capability that is consistent with the reliability criteria set forth
in the PNCA.3
( i
2005 Integrated Resource Plan Avista Utilities, Chapter 2.
2002 Final Power Rate Proposal Loads and Resources Study, Bonneville Power Administration WP-02-FS-BP A-
May 2000, Sections 2.3.3., 2., 2.3.4.
2002 Pacific Northwest Loads and Resources Study, Bonneville Power Administration, December 2002, Section 2, Pages 4
and 38.
Page 158 2006 Integrated Resource Plan
Idaho Power Company Appendix 0- Technical Appendix
Idaho Power
Company
Hydro Conditions: 70th percentile hydro conditions based upon historical data from
1928-2003.
Load Forecast: Based upon 50th percentile weather conditions.
Monthly Average Energy: Based on 70th percentile water and 70th percentile average
load conditions.
Capacity: Based on monthly peak-hour Northwest transmission deficit assuming
90th percentile water, 70th percentile average load and 95th percentile peak-hour load
conditions.
Northwest Power
and Conservation
Council
Utilizes a fully probabilistic model: Prospective plans are tested against 20 years of
future conditions defined by probabilistic simulations of principal uncertainties
including hydro conditions, loads, fuel prices, CO2 control requirements, import and
export markets and resource availability. Each case is compared to the previous and
ranked according to risk and cost.
PacifiCorp Hydro Conditions: Median water conditions. 10
Loads: Average energy requirements based upon normal weather conditions.
Capacity: Normal weather peak-hour loading plus a 15% planning margin.
Portland General
Electric Company
Hydro Conditions: Normal/median water conditions based upon 59 years of hydro
history.
Loads: Normal/Median load conditions.
Capacity: Normal weather peak-hour loading plus 12% (6% operating margin
6% planning margin). Then subtract 500 MW (to be filled in with short-term market
purchases).
Puget Sound
Energy
PSE uses the expected peak load for long-term capacity planning. The expected peak
load is the maximum hourly load expected to occur when the hourly temperature during
the winter months (November-February) is 23 degrees at SeaTac Airport.
PSE uses an hourly regression equation to obtain monthly peak load forecasts. The
equation provides both normal and extreme peak loads for residential and
non-residential customers. The regression equation is based on data collected from
January 1991 through February 2004.
Design Temperatures: 230 F for normal peak and 130 F for extreme peak, both
occurring in January.
2006 Integrated Resource Plan Idaho Power Company, September 2006.
The Fifth Northwest Electric Power and Conservation Plan Northwest Power and Conservation Council, 2005.
2006 Integrated Resource Plan PacifiCorp, due to be filed in December 2006.
11 Final Action Plan, 2002 IRP Portland General Electric, March 2004, Appendix 2.
12 Least Cost Plan Puget Sound Energy, April 2005 , Appendix K.
Page 1592006 Integrated Resource Plan
Appendix 0- Technical Appendix Idaho Power Company
Idaho Po\ftJer Company
2006 Integrated Resource Plan Advisory Council ~J1embers
Customer Participants
Micron - Dale Eldridge
Simplot - David Hawk
INL - Tom Moriarty
Heinz Frozen Foods - Steve Munn
AARP - Joe Gallegos
Idaho Retailers - Pam Eaton
Agricultural Representative - Sid Erwin
Meridian Joint School District #2 - Wayne Hanners
c ,
, .
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Commission Participants
Idaho PUC - Rick Sterling
Oregon PUC - Bill McNamee
c 'Environmental Participants
Natural Resource Defense Council- Devra Wang, Audrey Chang or Ralph Cavanagh
Advocates for the West - Bill Eddie
Other Participants
ID EQ - Larry Koenig
Governor s Office - Jim Yost
Idaho State Legislature - Representative Steve Smylie
Northwest Power and Conservation Council- Jim Kempton or Shirley Lindstrom
Consultant - Dan Violette - Summit Blue Consulting, LLC
Page 160 2006 Integrated Resource Plan