200408272004IRP technical appendix.pdf

Providing a foundation for a bright future.
TECHNICAL APPENDIX
FOR THE 2004 INTEGRATED RESOURCE PLAN
TECHNICAL APPENDIX
FOR THE 2004 INTEGRATED RESOURCE PLAN
July 2004
Idaho Power Company
2004 Integrated Resource Plan
Technical Appendix

Table Of Contents

Sales and Load Forecast
Expected Load Forecast
70th Percentile Load Forecast

Existing Resource Data
Hydroelectric Plant Data
Thermal Plant Data
QF Project Data

Fuel Data
Gas & Coal Forecast – Data and Graphs
Gas & Coal Forecast – Comparison to Previous IRPs

Supply Side Resource Data
Resource Cost Data and Operating Assumptions
Levelized Cost Data – Energy and Capacity
Monthly Wind Energy Distribution

Demand Side Resource Data
DSM Analysis & Screening Criteria
DSM Programs - Descriptions
DSM Programs – Load Reductions & Costs by Year
DSM Programs – Portfolio Benefits
DSM Programs – Summary

Surplus/Deficit Analysis Results/Data
Monthly Energy Analysis
50th Percentile Water, 50th Percentile Load
70th Percentile Water, 70th Percentile Load
90th Percentile Water, 70th Percentile Load
Monthly Peak-hour Analysis
50th Percentile Water, 50th Percentile Load
70th Percentile Water, 70th Percentile Load
90th Percentile Water, 70th Percentile Load
Monthly Peak-hour Transmission Deficit Analysis
50th Percentile Water, 50th Percentile Load
70th Percentile Water, 70th Percentile Load
90th Percentile Water, 70th Percentile Load

Resource Portfolios
Portfolio Summary and Description
Portfolio Energy and Capacity Balance

Portfolio Analysis – Results and Supporting Documentation
Aurora Computer Program – Description
PDR580 Results – 50/50, 70/70 and 90/70
Portfolio Comparisons – PVRR for 4 Scenarios
Expected Gas, CO2 @ $0/ton, PTC
Expected Gas, CO2 @ $12/ton. PTC
Expected Gas, CO2 @ $49/ton, PTC
Expected Gas, CO2 @ $12/ton, No PTC
Portfolio Ranking Results – Determination of Finalists
DSM Energy Efficiency Program Ranking – Aurora benefit/cost analysis
Portfolio CO2 Emissions
Finalist Portfolio Comparisons
Expected Gas, CO2 @ $0/ton, PTC
Expected Gas, CO2 @ $12/ton. PTC
Expected Gas, CO2 @ $49/ton, PTC
Expected Gas, CO2 @ $12/ton, No PTC
Low Gas, CO2 @ $12/ton, PTC
High Gas, CO2 @ $12/ton, PTC
Projected Market Sales
Projected Market Purchases
Net of Projected Market Purchases and Sales
Projected Gas Costs
Projected Area Prices

Summary of Northwest Utility Planning Criteria

IRP Advisory Council Roster

2004 Integrated Resource Plan
Technical Appendix

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Expected Load Forecast

70th Percentile Load Forecast

February 26, 2004 08:29:13 N04A3_BC
Description: 2004 Basecase Forecast - Expected Case Scenario
Jan. 2004 Feb. 2004 Mar. 2004 Apr. 2004 May. 2004 Jun. 2004 Jul. 2004 Aug. 2004 Sep. 2004 Oct. 2004 Nov. 2004 Dec. 2004
Residential 708 640 542 426 393 424 485 486 400 418 540 699
Commercial 443 430 405 362 375 415 452 456 404 393 416 458
Irrigation 0 0 3 79 255 520 618 479 298 78 3 2
Industrial 254 257 254 257 252 261 261 265 276 279 276 266
Micron 73 74 74 73 74 75 76 75 75 75 76 75
Simplot 22 22 20 21 21 15 22 22 22 22 22 22
Weiser 7 6 6 5 5 5 6 6 5 5 6 7
Raft River Rural Electric Coop.8 7 7 6 6 6 6 6 5 6 7 7
INEEL 30 28 25 23 20 20 19 21 20 22 25 28
Loss 157 141 128 119 136 173 213 197 153 134 142 166
FIRM LOAD 1,702 1,606 1,463 1,370 1,537 1,915 2,158 2,012 1,658 1,431 1,511 1,730
Light Load 1,583 1,488 1,356 1,233 1,384 1,723 1,949 1,784 1,484 1,286 1,414 1,610
Heavy Load 1,796 1,702 1,540 1,471 1,669 2,055 2,309 2,192 1,797 1,545 1,589 1,825
SYSTEM LOAD 1,702 1,606 1,463 1,370 1,537 1,915 2,158 2,012 1,658 1,431 1,511 1,730
Firm Off-System Load 2 3 3 3 3 3 3 3 3 3 3 3
TOTAL LOAD 1,704 1,609 1,466 1,373 1,540 1,918 2,161 2,015 1,661 1,434 1,514 1,733
FIRM PEAK LOAD 2,354 2,297 2,134 1,868 2,513 2,951 3,037 2,822 2,471 1,986 2,166 2,483
SYSTEM PEAK (1 HOUR)2,354 2,297 2,134 1,868 2,513 2,951 3,037 2,822 2,471 1,986 2,166 2,483
Firm Off-System Peak 3 3 3 3 3 3 3 3 3 3 3 3
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,357 2,300 2,137 1,871 2,516 2,954 3,041 2,825 2,474 1,990 2,169 2,486
Peak Load (Megawatts)
SALES & LOAD REPORT
Average Load (Average Megawatts)
February 26, 2004 08:29:13 N04A3_BC
Description: 2004 Basecase Forecast - Expected Case Scenario
Jan. 2005 Feb. 2005 Mar. 2005 Apr. 2005 May. 2005 Jun. 2005 Jul. 2005 Aug. 2005 Sep. 2005 Oct. 2005 Nov. 2005 Dec. 2005
Residential 720 652 551 432 401 435 500 500 410 426 550 712
Commercial 465 446 420 376 391 433 472 476 420 409 431 473
Irrigation 0 0 3 80 256 523 621 481 299 78 3 2
Industrial 266 265 262 265 260 269 269 273 285 287 284 274
Micron 75 76 76 75 76 77 78 77 77 77 77 77
Simplot 23 23 20 21 21 15 22 22 22 22 22 22
Weiser 7 7 6 5 5 5 6 6 5 5 6 7
Raft River Rural Electric Coop.7 7 7 6 6 6 6 6 5 6 7 8
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 162 145 131 122 139 177 218 202 156 137 146 170
FIRM LOAD 1,754 1,650 1,501 1,405 1,575 1,960 2,212 2,064 1,700 1,468 1,551 1,773
Light Load 1,631 1,529 1,391 1,264 1,418 1,764 1,998 1,830 1,522 1,320 1,451 1,650
Heavy Load 1,860 1,741 1,580 1,508 1,709 2,104 2,396 2,234 1,843 1,586 1,631 1,862
SYSTEM LOAD 1,754 1,650 1,501 1,405 1,575 1,960 2,212 2,064 1,700 1,468 1,551 1,773
Firm Off-System Load 3 3 3 3 3 0 0 0 0 0 0 0
TOTAL LOAD 1,757 1,653 1,504 1,408 1,578 1,960 2,212 2,064 1,700 1,468 1,551 1,773
FIRM PEAK LOAD 2,408 2,359 2,174 1,887 2,575 3,040 3,122 2,905 2,524 2,021 2,218 2,555
SYSTEM PEAK (1 HOUR)2,408 2,359 2,174 1,887 2,575 3,040 3,122 2,905 2,524 2,021 2,218 2,555
Firm Off-System Peak 3 3 3 3 3 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,411 2,363 2,177 1,890 2,578 3,040 3,122 2,905 2,524 2,021 2,218 2,555
SALES & LOAD REPORT
Average Load (Average Megawatts)
Peak Load (Megawatts)
February 26, 2004 08:29:13 N04A3_BC
Description: 2004 Basecase Forecast - Expected Case Scenario
Jan. 2006 Feb. 2006 Mar. 2006 Apr. 2006 May. 2006 Jun. 2006 Jul. 2006 Aug. 2006 Sep. 2006 Oct. 2006 Nov. 2006 Dec. 2006
Residential 733 664 560 439 408 447 516 516 420 433 559 724
Commercial 479 461 434 390 406 450 491 494 436 423 445 488
Irrigation 0 0 3 79 256 522 620 480 299 78 3 2
Industrial 274 273 271 273 268 278 278 282 294 297 293 283
Micron 78 78 79 78 79 80 81 80 79 80 80 80
Simplot 23 23 20 21 21 15 22 22 22 22 22 22
Weiser 7 7 6 5 5 5 6 6 5 5 6 7
Raft River Rural Electric Coop.8 8 7 6 6 6 6 6 6 6 7 8
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 166 149 134 125 142 180 223 207 160 141 150 174
FIRM LOAD 1,797 1,691 1,539 1,439 1,611 2,003 2,261 2,114 1,741 1,506 1,590 1,816
Light Load 1,671 1,567 1,427 1,295 1,450 1,803 2,043 1,874 1,558 1,353 1,487 1,690
Heavy Load 1,897 1,785 1,620 1,555 1,737 2,149 2,450 2,287 1,887 1,626 1,672 1,924
SYSTEM LOAD 1,797 1,691 1,539 1,439 1,611 2,003 2,261 2,114 1,741 1,506 1,590 1,816
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 1,797 1,691 1,539 1,439 1,611 2,003 2,261 2,114 1,741 1,506 1,590 1,816
FIRM PEAK LOAD 2,461 2,406 2,232 1,939 2,637 3,102 3,203 2,967 2,577 2,039 2,254 2,588
SYSTEM PEAK (1 HOUR)2,461 2,406 2,232 1,939 2,637 3,102 3,203 2,967 2,577 2,039 2,254 2,588
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,461 2,406 2,232 1,939 2,637 3,102 3,203 2,967 2,577 2,039 2,254 2,588
Peak Load (Megawatts)
SALES & LOAD REPORT
Average Load (Average Megawatts)
February 26, 2004 08:29:13 N04A3_BC
Description: 2004 Basecase Forecast - Expected Case Scenario
Jan. 2007 Feb. 2007 Mar. 2007 Apr. 2007 May. 2007 Jun. 2007 Jul. 2007 Aug. 2007 Sep. 2007 Oct. 2007 Nov. 2007 Dec. 2007
Residential 746 675 569 445 415 458 531 531 430 441 569 737
Commercial 494 475 448 403 420 467 510 513 451 437 459 502
Irrigation 0 0 3 80 257 523 622 482 299 78 3 2
Industrial 283 282 280 282 277 287 287 291 304 307 303 292
Micron 81 81 81 80 82 83 84 83 82 82 83 83
Simplot 23 23 20 21 21 15 22 22 22 22 22 23
Weiser 7 7 6 5 5 5 6 6 5 6 6 7
Raft River Rural Electric Coop.8 8 7 6 6 6 6 6 6 6 7 8
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 170 152 138 128 145 184 228 212 164 144 153 178
FIRM LOAD 1,841 1,733 1,577 1,474 1,648 2,048 2,315 2,166 1,783 1,544 1,629 1,859
Light Load 1,712 1,605 1,462 1,326 1,484 1,843 2,091 1,920 1,596 1,387 1,524 1,731
Heavy Load 1,942 1,828 1,660 1,592 1,777 2,198 2,507 2,344 1,947 1,657 1,714 1,970
SYSTEM LOAD 1,841 1,733 1,577 1,474 1,648 2,048 2,315 2,166 1,783 1,544 1,629 1,859
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 1,841 1,733 1,577 1,474 1,648 2,048 2,315 2,166 1,783 1,544 1,629 1,859
FIRM PEAK LOAD 2,505 2,433 2,273 1,963 2,700 3,183 3,288 3,044 2,631 2,069 2,302 2,649
SYSTEM PEAK (1 HOUR)2,505 2,433 2,273 1,963 2,700 3,183 3,288 3,044 2,631 2,069 2,302 2,649
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,505 2,433 2,273 1,963 2,700 3,183 3,288 3,044 2,631 2,069 2,302 2,649
SALES & LOAD REPORT
Average Load (Average Megawatts)
Peak Load (Megawatts)
February 26, 2004 08:29:14 N04A3_BC
Description: 2004 Basecase Forecast - Expected Case Scenario
Jan. 2008 Feb. 2008 Mar. 2008 Apr. 2008 May. 2008 Jun. 2008 Jul. 2008 Aug. 2008 Sep. 2008 Oct. 2008 Nov. 2008 Dec. 2008
Residential 760 687 579 452 423 470 548 547 440 449 579 750
Commercial 509 490 463 417 435 484 530 532 467 451 473 517
Irrigation 0 0 3 80 257 524 623 483 300 78 3 2
Industrial 292 291 288 291 285 296 296 300 313 316 312 300
Micron 83 84 84 83 84 85 86 86 85 85 86 86
Simplot 23 23 20 22 21 15 22 22 23 22 22 23
Weiser 7 7 6 5 5 5 6 6 5 6 6 7
Raft River Rural Electric Coop.8 8 7 6 6 6 6 6 6 6 7 8
INEEL 29 28 25 23 20 20 19 21 20 22 25 28
Loss 174 156 141 131 148 189 234 217 168 148 157 182
FIRM LOAD 1,886 1,773 1,616 1,510 1,686 2,095 2,370 2,220 1,826 1,583 1,670 1,903
Light Load 1,754 1,643 1,498 1,359 1,519 1,885 2,141 1,968 1,635 1,422 1,562 1,771
Heavy Load 1,990 1,870 1,709 1,621 1,819 2,262 2,551 2,419 1,980 1,698 1,764 2,007
SYSTEM LOAD 1,886 1,773 1,616 1,510 1,686 2,095 2,370 2,220 1,826 1,583 1,670 1,903
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 1,886 1,773 1,616 1,510 1,686 2,095 2,370 2,220 1,826 1,583 1,670 1,903
FIRM PEAK LOAD 2,555 2,465 2,323 2,000 2,763 3,263 3,374 3,121 2,685 2,098 2,349 2,708
SYSTEM PEAK (1 HOUR)2,555 2,465 2,323 2,000 2,763 3,263 3,374 3,121 2,685 2,098 2,349 2,708
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,555 2,465 2,323 2,000 2,763 3,263 3,374 3,121 2,685 2,098 2,349 2,708
Peak Load (Megawatts)
SALES & LOAD REPORT
Average Load (Average Megawatts)
February 26, 2004 08:29:14 N04A3_BC
Description: 2004 Basecase Forecast - Expected Case Scenario
Jan. 2009 Feb. 2009 Mar. 2009 Apr. 2009 May. 2009 Jun. 2009 Jul. 2009 Aug. 2009 Sep. 2009 Oct. 2009 Nov. 2009 Dec. 2009
Residential 773 699 588 459 431 481 564 563 450 457 589 762
Commercial 524 504 477 431 450 501 549 551 482 465 486 531
Irrigation 0 0 3 80 258 526 625 484 301 78 3 2
Industrial 300 299 296 299 294 304 304 309 322 325 321 309
Micron 86 87 87 86 87 88 90 89 88 88 89 89
Simplot 23 23 20 22 21 15 22 22 23 22 22 23
Weiser 7 7 6 5 5 5 6 6 5 6 7 7
Raft River Rural Electric Coop.8 8 7 6 6 6 6 6 6 6 7 8
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 178 160 144 134 152 193 239 222 172 151 161 186
FIRM LOAD 1,929 1,816 1,654 1,545 1,724 2,140 2,424 2,273 1,869 1,620 1,709 1,944
Light Load 1,794 1,683 1,533 1,390 1,552 1,926 2,189 2,015 1,673 1,456 1,599 1,809
Heavy Load 2,036 1,917 1,749 1,658 1,871 2,297 2,609 2,477 2,025 1,739 1,806 2,050
SYSTEM LOAD 1,929 1,816 1,654 1,545 1,724 2,140 2,424 2,273 1,869 1,620 1,709 1,944
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 1,929 1,816 1,654 1,545 1,724 2,140 2,424 2,273 1,869 1,620 1,709 1,944
FIRM PEAK LOAD 2,603 2,504 2,371 2,036 2,826 3,343 3,459 3,197 2,739 2,123 2,395 2,765
SYSTEM PEAK (1 HOUR)2,603 2,504 2,371 2,036 2,826 3,343 3,459 3,197 2,739 2,123 2,395 2,765
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,603 2,504 2,371 2,036 2,826 3,343 3,459 3,197 2,739 2,123 2,395 2,765
SALES & LOAD REPORT
Average Load (Average Megawatts)
Peak Load (Megawatts)
February 26, 2004 08:29:14 N04A3_BC
Description: 2004 Basecase Forecast - Expected Case Scenario
Jan. 2010 Feb. 2010 Mar. 2010 Apr. 2010 May. 2010 Jun. 2010 Jul. 2010 Aug. 2010 Sep. 2010 Oct. 2010 Nov. 2010 Dec. 2010
Residential 785 709 596 465 438 492 579 578 460 464 597 773
Commercial 538 517 490 443 464 518 568 569 497 479 499 544
Irrigation 0 0 3 80 258 527 626 485 301 78 3 2
Industrial 309 308 305 308 303 313 313 318 332 335 331 318
Micron 89 90 90 89 90 92 93 92 91 91 92 92
Simplot 23 23 20 22 21 15 22 22 23 22 22 23
Weiser 8 7 6 5 5 5 6 6 5 6 7 8
Raft River Rural Electric Coop.8 8 7 7 6 6 6 6 6 6 7 8
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 182 163 147 137 155 196 244 227 175 154 164 190
FIRM LOAD 1,970 1,856 1,690 1,578 1,760 2,185 2,477 2,325 1,910 1,657 1,747 1,984
Light Load 1,832 1,719 1,567 1,420 1,585 1,966 2,237 2,061 1,710 1,489 1,634 1,847
Heavy Load 2,089 1,958 1,779 1,694 1,911 2,344 2,650 2,533 2,070 1,789 1,837 2,093
SYSTEM LOAD 1,970 1,856 1,690 1,578 1,760 2,185 2,477 2,325 1,910 1,657 1,747 1,984
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 1,970 1,856 1,690 1,578 1,760 2,185 2,477 2,325 1,910 1,657 1,747 1,984
FIRM PEAK LOAD 2,649 2,536 2,418 2,072 2,889 3,423 3,543 3,273 2,794 2,145 2,440 2,821
SYSTEM PEAK (1 HOUR)2,649 2,536 2,418 2,072 2,889 3,423 3,543 3,273 2,794 2,145 2,440 2,821
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,649 2,536 2,418 2,072 2,889 3,423 3,543 3,273 2,794 2,145 2,440 2,821
SALES & LOAD REPORT
Average Load (Average Megawatts)
Peak Load (Megawatts)
February 26, 2004 08:29:14 N04A3_BC
Description: 2004 Basecase Forecast - Expected Case Scenario
Jan. 2011 Feb. 2011 Mar. 2011 Apr. 2011 May. 2011 Jun. 2011 Jul. 2011 Aug. 2011 Sep. 2011 Oct. 2011 Nov. 2011 Dec. 2011
Residential 796 719 603 470 444 503 595 593 469 470 605 783
Commercial 551 531 503 456 478 534 586 587 512 492 512 557
Irrigation 0 0 3 80 259 528 627 486 302 79 3 2
Industrial 318 317 314 317 311 323 322 327 341 345 340 327
Micron 92 92 92 91 93 94 95 94 93 94 94 94
Simplot 23 23 20 22 21 15 22 22 23 22 22 23
Weiser 8 7 6 5 5 5 6 6 5 6 7 8
Raft River Rural Electric Coop.8 8 7 7 6 6 6 6 6 6 7 8
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 185 166 150 139 158 200 249 232 179 158 167 193
FIRM LOAD 2,010 1,894 1,725 1,611 1,795 2,229 2,529 2,376 1,951 1,692 1,783 2,023
Light Load 1,869 1,755 1,600 1,449 1,617 2,006 2,284 2,106 1,746 1,521 1,668 1,883
Heavy Load 2,132 1,998 1,816 1,729 1,949 2,391 2,740 2,571 2,114 1,828 1,875 2,125
SYSTEM LOAD 2,010 1,894 1,725 1,611 1,795 2,229 2,529 2,376 1,951 1,692 1,783 2,023
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 2,010 1,894 1,725 1,611 1,795 2,229 2,529 2,376 1,951 1,692 1,783 2,023
FIRM PEAK LOAD 2,695 2,566 2,465 2,108 2,951 3,502 3,627 3,349 2,847 2,165 2,485 2,877
SYSTEM PEAK (1 HOUR)2,695 2,566 2,465 2,108 2,951 3,502 3,627 3,349 2,847 2,165 2,485 2,877
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,695 2,566 2,465 2,108 2,951 3,502 3,627 3,349 2,847 2,165 2,485 2,877
SALES & LOAD REPORT
Average Load (Average Megawatts)
Peak Load (Megawatts)
February 26, 2004 08:29:14 N04A3_BC
Description: 2004 Basecase Forecast - Expected Case Scenario
Jan. 2012 Feb. 2012 Mar. 2012 Apr. 2012 May. 2012 Jun. 2012 Jul. 2012 Aug. 2012 Sep. 2012 Oct. 2012 Nov. 2012 Dec. 2012
Residential 807 729 611 475 450 513 610 608 478 477 613 794
Commercial 565 544 516 469 492 551 605 606 527 505 525 570
Irrigation 0 0 3 81 259 529 629 487 303 79 3 2
Industrial 327 326 323 326 320 331 331 336 351 354 350 336
Micron 93 94 94 93 94 96 97 96 95 95 96 96
Simplot 23 23 20 22 22 15 22 22 23 22 22 23
Weiser 8 7 6 5 5 6 6 6 5 6 7 8
Raft River Rural Electric Coop.8 8 8 7 6 6 6 6 6 7 7 8
INEEL 29 28 25 23 20 20 19 21 20 22 25 28
Loss 189 170 153 142 161 204 254 237 183 161 171 197
FIRM LOAD 2,049 1,928 1,759 1,642 1,830 2,272 2,581 2,427 1,990 1,727 1,818 2,062
Light Load 1,905 1,787 1,631 1,478 1,648 2,044 2,331 2,151 1,782 1,552 1,701 1,919
Heavy Load 2,163 2,033 1,852 1,774 1,974 2,438 2,796 2,626 2,173 1,853 1,912 2,185
SYSTEM LOAD 2,049 1,928 1,759 1,642 1,830 2,272 2,581 2,427 1,990 1,727 1,818 2,062
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 2,049 1,928 1,759 1,642 1,830 2,272 2,581 2,427 1,990 1,727 1,818 2,062
FIRM PEAK LOAD 2,740 2,592 2,511 2,142 3,012 3,580 3,710 3,423 2,900 2,185 2,529 2,932
SYSTEM PEAK (1 HOUR)2,740 2,592 2,511 2,142 3,012 3,580 3,710 3,423 2,900 2,185 2,529 2,932
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,740 2,592 2,511 2,142 3,012 3,580 3,710 3,423 2,900 2,185 2,529 2,932
SALES & LOAD REPORT
Peak Load (Megawatts)
Average Load (Average Megawatts)
February 26, 2004 08:29:14 N04A3_BC
Description: 2004 Basecase Forecast - Expected Case Scenario
Jan. 2013 Feb. 2013 Mar. 2013 Apr. 2013 May. 2013 Jun. 2013 Jul. 2013 Aug. 2013 Sep. 2013 Oct. 2013 Nov. 2013 Dec. 2013
Residential 818 739 618 480 457 524 626 624 488 483 621 804
Commercial 578 557 529 482 506 567 625 624 542 518 537 583
Irrigation 0 0 3 81 260 530 630 488 304 79 3 2
Industrial 336 335 332 335 329 341 340 346 360 364 359 346
Micron 95 96 96 95 96 97 99 97 97 97 98 98
Simplot 23 24 20 22 22 16 22 22 23 22 22 23
Weiser 8 7 6 5 5 6 7 6 6 6 7 8
Raft River Rural Electric Coop.8 8 8 7 6 6 6 6 6 7 8 9
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 192 173 156 145 164 208 259 242 186 164 174 201
FIRM LOAD 2,089 1,968 1,794 1,674 1,865 2,315 2,634 2,478 2,031 1,762 1,854 2,100
Light Load 1,942 1,824 1,663 1,507 1,679 2,084 2,379 2,197 1,818 1,583 1,734 1,954
Heavy Load 2,204 2,077 1,897 1,797 2,011 2,501 2,835 2,681 2,217 1,891 1,950 2,225
SYSTEM LOAD 2,089 1,968 1,794 1,674 1,865 2,315 2,634 2,478 2,031 1,762 1,854 2,100
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 2,089 1,968 1,794 1,674 1,865 2,315 2,634 2,478 2,031 1,762 1,854 2,100
FIRM PEAK LOAD 2,785 2,624 2,557 2,177 3,073 3,659 3,794 3,499 2,952 2,205 2,573 2,987
SYSTEM PEAK (1 HOUR)2,785 2,624 2,557 2,177 3,073 3,659 3,794 3,499 2,952 2,205 2,573 2,987
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,785 2,624 2,557 2,177 3,073 3,659 3,794 3,499 2,952 2,205 2,573 2,987
Peak Load (Megawatts)
SALES & LOAD REPORT
Average Load (Average Megawatts)
February 26, 2004 08:29:14 N04A3_BC
Description: 2004 Basecase Forecast - Expected Case Scenario
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Residential 513 524 535 545 557 568 578 587 597 607
Commercial 417 435 450 465 481 496 511 525 540 554
Irrigation 195 197 196 197 197 198 198 199 199 200
Industrial 263 272 280 290 298 307 316 325 334 344
Micron 75 77 79 82 85 88 91 93 95 97
Simplot 21 21 21 21 21 21 22 22 22 22
Weiser 6 6 6 6 6 6 6 6 6 6
Raft River Rural Electric Coop.6 6 6 7 7 7 7 7 7 7
INEEL 23 23 23 23 23 23 23 23 23 23
Loss 155 159 163 167 171 174 178 182 185 189
FIRM LOAD 1,675 1,719 1,760 1,803 1,846 1,889 1,930 1,970 2,008 2,049
Light Load 1,525 1,565 1,603 1,641 1,681 1,719 1,757 1,793 1,829 1,865
Heavy Load 1,792 1,839 1,884 1,930 1,975 2,021 2,064 2,107 2,150 2,192
SYSTEM LOAD 1,675 1,719 1,760 1,803 1,846 1,889 1,930 1,970 2,008 2,049
Firm Off-System Load 3 1 0 0 0 0 0 0 0 0
TOTAL LOAD 1,678 1,720 1,760 1,803 1,846 1,889 1,930 1,970 2,008 2,049
FIRM PEAK LOAD 3,037 3,122 3,203 3,288 3,374 3,459 3,543 3,627 3,710 3,794
SYSTEM PEAK (1 HOUR)3,037 3,122 3,203 3,288 3,374 3,459 3,543 3,627 3,710 3,794
Firm Off-System Peak 3 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 3,041 3,122 3,203 3,288 3,374 3,459 3,543 3,627 3,710 3,794
SALES & LOAD REPORT
Average Load (Average Megawatts)
Peak Load (Megawatts)
November 6, 2003 17:13:20 N04A2_70
Description: 2004 Basecase Forecast - 70Th Percentile Scenario
Jan. 2004 Feb. 2004 Mar. 2004 Apr. 2004 May. 2004 Jun. 2004 Jul. 2004 Aug. 2004 Sep. 2004 Oct. 2004 Nov. 2004 Dec. 2004
Residential 729 659 558 433 400 437 498 498 414 430 555 723
Commercial 455 436 410 368 382 420 455 459 406 395 418 464
Irrigation 0 0 5 118 300 571 648 497 318 88 3 2
Industrial 258 257 254 257 252 261 261 265 276 279 276 266
Micron 73 74 74 73 74 75 76 75 75 75 76 75
Simplot 23 22 20 21 21 15 22 22 22 22 22 22
Weiser 7 6 6 5 5 5 6 6 5 5 6 7
Raft River Rural Electric Coop.7 7 7 6 6 6 6 6 5 6 7 7
INEEL 29 28 25 23 20 20 19 21 20 22 25 28
Loss 161 144 130 124 142 180 219 201 157 136 144 169
FIRM LOAD 1,742 1,634 1,489 1,428 1,602 1,991 2,209 2,050 1,698 1,457 1,531 1,764
Light Load 1,620 1,513 1,380 1,285 1,442 1,792 1,995 1,817 1,520 1,309 1,433 1,642
Heavy Load 1,838 1,731 1,567 1,533 1,739 2,136 2,364 2,234 1,840 1,574 1,610 1,861
SYSTEM LOAD 1,742 1,634 1,489 1,428 1,602 1,991 2,209 2,050 1,698 1,457 1,531 1,764
Firm Off-System Load 3 3 3 3 3 3 3 3 3 3 3 3
TOTAL LOAD 1,745 1,637 1,492 1,431 1,605 1,994 2,212 2,053 1,701 1,460 1,534 1,767
FIRM PEAK LOAD 2,437 2,347 2,190 1,877 2,541 2,964 3,051 2,862 2,476 2,001 2,213 2,555
SYSTEM PEAK (1 HOUR)2,437 2,347 2,190 1,877 2,541 2,964 3,051 2,862 2,476 2,001 2,213 2,555
Firm Off-System Peak 3 3 3 3 3 3 3 3 3 3 3 3
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,440 2,351 2,193 1,880 2,544 2,967 3,054 2,865 2,479 2,005 2,216 2,558
Peak Load (Megawatts)
SALES & LOAD REPORT
Average Load (Average Megawatts)
November 6, 2003 17:13:20 N04A2_70
Description: 2004 Basecase Forecast - 70Th Percentile Scenario
Jan. 2005 Feb. 2005 Mar. 2005 Apr. 2005 May. 2005 Jun. 2005 Jul. 2005 Aug. 2005 Sep. 2005 Oct. 2005 Nov. 2005 Dec. 2005
Residential 742 671 567 440 408 449 514 514 424 438 565 736
Commercial 472 452 426 383 398 439 475 479 423 410 434 480
Irrigation 0 0 5 118 301 573 651 499 319 88 3 2
Industrial 266 265 262 265 260 269 269 273 285 287 284 274
Micron 75 76 76 75 76 77 78 77 77 77 77 77
Simplot 23 23 20 21 21 15 22 22 22 22 22 22
Weiser 7 7 6 5 5 5 6 6 5 5 6 7
Raft River Rural Electric Coop.7 7 7 6 6 6 6 6 5 6 7 8
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 165 148 134 128 145 184 224 206 161 140 148 174
FIRM LOAD 1,786 1,678 1,527 1,463 1,640 2,037 2,264 2,103 1,741 1,495 1,571 1,807
Light Load 1,661 1,554 1,416 1,317 1,477 1,834 2,045 1,864 1,558 1,344 1,470 1,682
Heavy Load 1,894 1,770 1,607 1,571 1,780 2,186 2,452 2,276 1,887 1,614 1,652 1,898
SYSTEM LOAD 1,786 1,678 1,527 1,463 1,640 2,037 2,264 2,103 1,741 1,495 1,571 1,807
Firm Off-System Load 3 3 3 3 3 0 0 0 0 0 0 0
TOTAL LOAD 1,789 1,681 1,530 1,466 1,643 2,037 2,264 2,103 1,741 1,495 1,571 1,807
FIRM PEAK LOAD 2,480 2,410 2,230 1,895 2,604 3,053 3,136 2,946 2,529 2,036 2,265 2,627
SYSTEM PEAK (1 HOUR)2,480 2,410 2,230 1,895 2,604 3,053 3,136 2,946 2,529 2,036 2,265 2,627
Firm Off-System Peak 3 3 3 3 3 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,483 2,413 2,233 1,898 2,607 3,053 3,136 2,946 2,529 2,036 2,265 2,627
SALES & LOAD REPORT
Average Load (Average Megawatts)
Peak Load (Megawatts)
November 6, 2003 17:13:21 N04A2_70
Description: 2004 Basecase Forecast - 70Th Percentile Scenario
Jan. 2006 Feb. 2006 Mar. 2006 Apr. 2006 May. 2006 Jun. 2006 Jul. 2006 Aug. 2006 Sep. 2006 Oct. 2006 Nov. 2006 Dec. 2006
Residential 756 683 577 447 416 461 530 529 434 445 574 748
Commercial 487 467 440 396 412 456 494 498 438 424 448 494
Irrigation 0 0 5 118 301 572 649 499 319 88 3 2
Industrial 274 273 271 273 268 278 278 282 294 297 293 283
Micron 78 78 79 78 79 80 81 80 79 80 80 80
Simplot 23 23 20 21 21 15 22 22 22 22 22 22
Weiser 7 7 6 5 5 5 6 6 5 5 6 7
Raft River Rural Electric Coop.8 8 7 6 6 6 6 6 6 6 7 8
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 169 152 137 131 148 188 229 211 164 144 152 178
FIRM LOAD 1,830 1,720 1,566 1,498 1,676 2,081 2,314 2,153 1,782 1,533 1,611 1,851
Light Load 1,702 1,593 1,452 1,348 1,510 1,873 2,090 1,909 1,595 1,377 1,507 1,723
Heavy Load 1,931 1,815 1,648 1,618 1,808 2,233 2,507 2,330 1,931 1,655 1,694 1,961
SYSTEM LOAD 1,830 1,720 1,566 1,498 1,676 2,081 2,314 2,153 1,782 1,533 1,611 1,851
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 1,830 1,720 1,566 1,498 1,676 2,081 2,314 2,153 1,782 1,533 1,611 1,851
FIRM PEAK LOAD 2,533 2,457 2,288 1,947 2,667 3,116 3,218 3,009 2,583 2,054 2,300 2,661
SYSTEM PEAK (1 HOUR)2,533 2,457 2,288 1,947 2,667 3,116 3,218 3,009 2,583 2,054 2,300 2,661
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,533 2,457 2,288 1,947 2,667 3,116 3,218 3,009 2,583 2,054 2,300 2,661
Peak Load (Megawatts)
SALES & LOAD REPORT
Average Load (Average Megawatts)
November 6, 2003 17:13:21 N04A2_70
Description: 2004 Basecase Forecast - 70Th Percentile Scenario
Jan. 2007 Feb. 2007 Mar. 2007 Apr. 2007 May. 2007 Jun. 2007 Jul. 2007 Aug. 2007 Sep. 2007 Oct. 2007 Nov. 2007 Dec. 2007
Residential 768 694 586 453 423 472 546 545 444 453 584 762
Commercial 502 481 454 410 427 473 513 516 454 438 462 509
Irrigation 0 0 5 118 301 574 651 500 319 88 3 2
Industrial 283 282 280 282 277 287 287 291 304 307 303 292
Micron 81 81 81 80 82 83 84 83 82 82 83 83
Simplot 23 23 20 21 21 15 22 22 22 22 22 23
Weiser 7 7 6 5 5 5 6 6 5 6 6 7
Raft River Rural Electric Coop.8 8 7 6 6 6 6 6 6 6 7 8
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 173 155 140 134 152 192 234 216 168 147 155 182
FIRM LOAD 1,874 1,761 1,604 1,533 1,714 2,127 2,368 2,206 1,825 1,571 1,650 1,895
Light Load 1,743 1,632 1,487 1,380 1,544 1,914 2,139 1,956 1,633 1,412 1,544 1,764
Heavy Load 1,978 1,858 1,688 1,656 1,849 2,282 2,565 2,387 1,992 1,686 1,736 2,008
SYSTEM LOAD 1,874 1,761 1,604 1,533 1,714 2,127 2,368 2,206 1,825 1,571 1,650 1,895
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 1,874 1,761 1,604 1,533 1,714 2,127 2,368 2,206 1,825 1,571 1,650 1,895
FIRM PEAK LOAD 2,577 2,484 2,329 1,971 2,731 3,197 3,302 3,087 2,637 2,084 2,348 2,721
SYSTEM PEAK (1 HOUR)2,577 2,484 2,329 1,971 2,731 3,197 3,302 3,087 2,637 2,084 2,348 2,721
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,577 2,484 2,329 1,971 2,731 3,197 3,302 3,087 2,637 2,084 2,348 2,721
SALES & LOAD REPORT
Average Load (Average Megawatts)
Peak Load (Megawatts)
November 6, 2003 17:13:21 N04A2_70
Description: 2004 Basecase Forecast - 70Th Percentile Scenario
Jan. 2008 Feb. 2008 Mar. 2008 Apr. 2008 May. 2008 Jun. 2008 Jul. 2008 Aug. 2008 Sep. 2008 Oct. 2008 Nov. 2008 Dec. 2008
Residential 783 707 596 461 432 485 563 562 455 462 594 775
Commercial 517 496 469 424 442 490 533 536 470 453 476 524
Irrigation 0 0 5 119 302 575 653 501 320 89 3 2
Industrial 292 291 288 291 285 296 296 300 313 316 312 300
Micron 83 84 84 83 84 85 86 86 85 85 86 86
Simplot 23 23 20 22 21 15 22 22 23 22 22 23
Weiser 7 7 6 5 5 5 6 6 5 6 6 7
Raft River Rural Electric Coop.8 8 7 6 6 6 6 6 6 6 7 8
INEEL 29 28 25 23 20 20 19 21 20 22 25 28
Loss 177 159 144 137 155 196 240 222 172 151 159 186
FIRM LOAD 1,920 1,802 1,644 1,570 1,753 2,174 2,424 2,261 1,868 1,610 1,691 1,939
Light Load 1,785 1,670 1,524 1,412 1,579 1,957 2,190 2,004 1,673 1,447 1,582 1,804
Heavy Load 2,026 1,900 1,738 1,685 1,891 2,348 2,609 2,464 2,025 1,728 1,787 2,045
SYSTEM LOAD 1,920 1,802 1,644 1,570 1,753 2,174 2,424 2,261 1,868 1,610 1,691 1,939
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 1,920 1,802 1,644 1,570 1,753 2,174 2,424 2,261 1,868 1,610 1,691 1,939
FIRM PEAK LOAD 2,627 2,516 2,379 2,008 2,795 3,278 3,389 3,165 2,691 2,113 2,396 2,780
SYSTEM PEAK (1 HOUR)2,627 2,516 2,379 2,008 2,795 3,278 3,389 3,165 2,691 2,113 2,396 2,780
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,627 2,516 2,379 2,008 2,795 3,278 3,389 3,165 2,691 2,113 2,396 2,780
Peak Load (Megawatts)
SALES & LOAD REPORT
Average Load (Average Megawatts)
November 6, 2003 17:13:21 N04A2_70
Description: 2004 Basecase Forecast - 70Th Percentile Scenario
Jan. 2009 Feb. 2009 Mar. 2009 Apr. 2009 May. 2009 Jun. 2009 Jul. 2009 Aug. 2009 Sep. 2009 Oct. 2009 Nov. 2009 Dec. 2009
Residential 796 719 605 468 439 497 580 578 466 469 604 787
Commercial 532 511 483 437 457 507 553 555 485 467 490 538
Irrigation 0 0 5 119 303 576 654 502 321 89 3 2
Industrial 300 299 296 299 294 304 304 309 322 325 321 309
Micron 86 87 87 86 87 88 90 89 88 88 89 89
Simplot 23 23 20 22 21 15 22 22 23 22 22 23
Weiser 7 7 6 5 5 5 6 6 5 6 7 7
Raft River Rural Electric Coop.8 8 7 6 6 6 6 6 6 6 7 8
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 181 163 147 140 158 200 245 227 176 154 163 190
FIRM LOAD 1,963 1,846 1,682 1,605 1,791 2,220 2,479 2,315 1,911 1,648 1,730 1,981
Light Load 1,826 1,710 1,559 1,444 1,613 1,998 2,239 2,052 1,711 1,481 1,619 1,843
Heavy Load 2,072 1,948 1,778 1,722 1,944 2,383 2,668 2,522 2,071 1,768 1,828 2,089
SYSTEM LOAD 1,963 1,846 1,682 1,605 1,791 2,220 2,479 2,315 1,911 1,648 1,730 1,981
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 1,963 1,846 1,682 1,605 1,791 2,220 2,479 2,315 1,911 1,648 1,730 1,981
FIRM PEAK LOAD 2,675 2,555 2,427 2,045 2,858 3,358 3,474 3,243 2,745 2,138 2,442 2,837
SYSTEM PEAK (1 HOUR)2,675 2,555 2,427 2,045 2,858 3,358 3,474 3,243 2,745 2,138 2,442 2,837
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,675 2,555 2,427 2,045 2,858 3,358 3,474 3,243 2,745 2,138 2,442 2,837
SALES & LOAD REPORT
Average Load (Average Megawatts)
Peak Load (Megawatts)
November 6, 2003 17:13:21 N04A2_70
Description: 2004 Basecase Forecast - 70Th Percentile Scenario
Jan. 2010 Feb. 2010 Mar. 2010 Apr. 2010 May. 2010 Jun. 2010 Jul. 2010 Aug. 2010 Sep. 2010 Oct. 2010 Nov. 2010 Dec. 2010
Residential 808 730 613 473 446 508 596 594 476 476 613 798
Commercial 546 524 496 450 471 524 571 573 500 480 503 551
Irrigation 0 0 5 119 303 577 655 503 321 89 3 2
Industrial 309 308 305 308 303 313 313 318 332 335 331 318
Micron 89 90 90 89 90 92 93 92 91 91 92 92
Simplot 23 23 20 22 21 15 22 22 23 22 22 23
Weiser 8 7 6 5 5 5 6 6 5 6 7 8
Raft River Rural Electric Coop.8 8 7 7 6 6 6 6 6 6 7 8
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 185 166 150 142 161 204 250 232 180 157 166 194
FIRM LOAD 2,005 1,886 1,719 1,639 1,828 2,266 2,533 2,367 1,953 1,684 1,768 2,021
Light Load 1,865 1,747 1,594 1,474 1,646 2,039 2,287 2,098 1,748 1,514 1,654 1,881
Heavy Load 2,126 1,990 1,809 1,759 1,984 2,431 2,709 2,579 2,117 1,819 1,860 2,132
SYSTEM LOAD 2,005 1,886 1,719 1,639 1,828 2,266 2,533 2,367 1,953 1,684 1,768 2,021
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 2,005 1,886 1,719 1,639 1,828 2,266 2,533 2,367 1,953 1,684 1,768 2,021
FIRM PEAK LOAD 2,721 2,587 2,475 2,080 2,922 3,438 3,559 3,320 2,799 2,160 2,487 2,893
SYSTEM PEAK (1 HOUR)2,721 2,587 2,475 2,080 2,922 3,438 3,559 3,320 2,799 2,160 2,487 2,893
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,721 2,587 2,475 2,080 2,922 3,438 3,559 3,320 2,799 2,160 2,487 2,893
Peak Load (Megawatts)
SALES & LOAD REPORT
Average Load (Average Megawatts)
November 6, 2003 17:13:21 N04A2_70
Description: 2004 Basecase Forecast - 70Th Percentile Scenario
Jan. 2011 Feb. 2011 Mar. 2011 Apr. 2011 May. 2011 Jun. 2011 Jul. 2011 Aug. 2011 Sep. 2011 Oct. 2011 Nov. 2011 Dec. 2011
Residential 819 740 621 479 453 520 612 610 485 483 621 809
Commercial 559 538 510 463 485 540 590 591 515 493 515 564
Irrigation 0 0 5 119 304 578 657 504 322 89 3 2
Industrial 318 317 314 317 311 323 322 327 341 345 340 327
Micron 92 92 92 91 93 94 95 94 93 94 94 94
Simplot 23 23 20 22 21 15 22 22 23 22 22 23
Weiser 8 7 6 5 5 5 6 6 5 6 7 8
Raft River Rural Electric Coop.8 8 7 7 6 6 6 6 6 6 7 8
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 189 169 153 145 165 208 255 237 183 161 170 197
FIRM LOAD 2,046 1,924 1,754 1,671 1,864 2,310 2,586 2,419 1,994 1,720 1,805 2,061
Light Load 1,902 1,783 1,626 1,504 1,678 2,079 2,335 2,144 1,785 1,546 1,688 1,918
Heavy Load 2,169 2,030 1,846 1,794 2,023 2,479 2,801 2,617 2,161 1,857 1,898 2,164
SYSTEM LOAD 2,046 1,924 1,754 1,671 1,864 2,310 2,586 2,419 1,994 1,720 1,805 2,061
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 2,046 1,924 1,754 1,671 1,864 2,310 2,586 2,419 1,994 1,720 1,805 2,061
FIRM PEAK LOAD 2,767 2,617 2,522 2,116 2,984 3,518 3,643 3,397 2,853 2,180 2,532 2,949
SYSTEM PEAK (1 HOUR)2,767 2,617 2,522 2,116 2,984 3,518 3,643 3,397 2,853 2,180 2,532 2,949
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,767 2,617 2,522 2,116 2,984 3,518 3,643 3,397 2,853 2,180 2,532 2,949
SALES & LOAD REPORT
Average Load (Average Megawatts)
Peak Load (Megawatts)
November 6, 2003 17:13:21 N04A2_70
Description: 2004 Basecase Forecast - 70Th Percentile Scenario
Jan. 2012 Feb. 2012 Mar. 2012 Apr. 2012 May. 2012 Jun. 2012 Jul. 2012 Aug. 2012 Sep. 2012 Oct. 2012 Nov. 2012 Dec. 2012
Residential 831 750 628 484 460 531 628 625 495 490 629 820
Commercial 573 551 523 476 500 557 609 609 529 506 528 577
Irrigation 0 0 5 119 304 580 658 505 323 89 3 2
Industrial 327 326 323 326 320 331 331 336 351 354 350 336
Micron 93 94 94 93 94 96 97 96 95 95 96 96
Simplot 23 23 20 22 22 15 22 22 23 22 22 23
Weiser 8 7 6 5 5 6 6 6 5 6 7 8
Raft River Rural Electric Coop.8 8 8 7 6 6 6 6 6 7 7 8
INEEL 29 28 25 23 20 20 19 21 20 22 25 28
Loss 192 173 156 148 168 212 260 242 187 164 173 201
FIRM LOAD 2,085 1,959 1,788 1,703 1,899 2,354 2,638 2,470 2,034 1,755 1,840 2,099
Light Load 1,939 1,815 1,658 1,533 1,710 2,119 2,383 2,190 1,821 1,577 1,722 1,954
Heavy Load 2,200 2,066 1,882 1,840 2,048 2,526 2,858 2,673 2,221 1,883 1,936 2,225
SYSTEM LOAD 2,085 1,959 1,788 1,703 1,899 2,354 2,638 2,470 2,034 1,755 1,840 2,099
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 2,085 1,959 1,788 1,703 1,899 2,354 2,638 2,470 2,034 1,755 1,840 2,099
FIRM PEAK LOAD 2,812 2,643 2,567 2,151 3,046 3,596 3,726 3,472 2,906 2,200 2,576 3,004
SYSTEM PEAK (1 HOUR)2,812 2,643 2,567 2,151 3,046 3,596 3,726 3,472 2,906 2,200 2,576 3,004
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,812 2,643 2,567 2,151 3,046 3,596 3,726 3,472 2,906 2,200 2,576 3,004
Average Load (Average Megawatts)
SALES & LOAD REPORT
Peak Load (Megawatts)
November 6, 2003 17:13:21 N04A2_70
Description: 2004 Basecase Forecast - 70Th Percentile Scenario
Jan. 2013 Feb. 2013 Mar. 2013 Apr. 2013 May. 2013 Jun. 2013 Jul. 2013 Aug. 2013 Sep. 2013 Oct. 2013 Nov. 2013 Dec. 2013
Residential 842 760 636 489 467 542 644 641 504 496 637 830
Commercial 587 564 536 489 514 574 629 628 544 520 541 590
Irrigation 0 0 5 119 305 581 660 507 324 89 3 2
Industrial 336 335 332 335 329 341 340 346 360 364 359 346
Micron 95 96 96 95 96 97 99 97 97 97 98 98
Simplot 23 24 20 22 22 16 22 22 23 22 22 23
Weiser 8 7 6 5 5 6 7 6 6 6 7 8
Raft River Rural Electric Coop.8 8 8 7 6 6 6 6 6 7 8 9
INEEL 29 29 25 23 20 20 19 21 20 22 25 28
Loss 196 176 159 151 171 216 266 247 191 167 176 205
FIRM LOAD 2,125 1,999 1,823 1,736 1,934 2,399 2,692 2,522 2,075 1,790 1,876 2,138
Light Load 1,976 1,852 1,691 1,562 1,742 2,159 2,431 2,236 1,858 1,609 1,755 1,990
Heavy Load 2,242 2,110 1,928 1,863 2,086 2,590 2,897 2,729 2,265 1,921 1,973 2,265
SYSTEM LOAD 2,125 1,999 1,823 1,736 1,934 2,399 2,692 2,522 2,075 1,790 1,876 2,138
Firm Off-System Load 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL LOAD 2,125 1,999 1,823 1,736 1,934 2,399 2,692 2,522 2,075 1,790 1,876 2,138
FIRM PEAK LOAD 2,857 2,674 2,613 2,185 3,108 3,675 3,810 3,549 2,959 2,220 2,620 3,059
SYSTEM PEAK (1 HOUR)2,857 2,674 2,613 2,185 3,108 3,675 3,810 3,549 2,959 2,220 2,620 3,059
Firm Off-System Peak 0 0 0 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 2,857 2,674 2,613 2,185 3,108 3,675 3,810 3,549 2,959 2,220 2,620 3,059
SALES & LOAD REPORT
Average Load (Average Megawatts)
Peak Load (Megawatts)
November 6, 2003 17:13:21 N04A2_70
Description: 2004 Basecase Forecast - 70Th Percentile Scenario
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Residential 528 539 550 561 573 584 594 604 614 624
Commercial 423 439 455 470 486 501 516 531 545 560
Irrigation 213 215 214 215 215 216 216 217 217 218
Industrial 263 272 280 290 298 307 316 325 334 344
Micron 75 77 79 82 85 88 91 93 95 97
Simplot 21 21 21 21 21 21 22 22 22 22
Weiser 6 6 6 6 6 6 6 6 6 6
Raft River Rural Electric Coop.6 6 6 7 7 7 7 7 7 7
INEEL 23 23 23 23 23 23 23 23 23 23
Loss 159 163 167 171 175 179 183 186 190 194
FIRM LOAD 1,717 1,761 1,803 1,845 1,889 1,932 1,974 2,014 2,053 2,094
Light Load 1,563 1,603 1,641 1,680 1,720 1,759 1,797 1,834 1,869 1,906
Heavy Load 1,837 1,884 1,929 1,975 2,022 2,068 2,111 2,155 2,198 2,241
SYSTEM LOAD 1,717 1,761 1,803 1,845 1,889 1,932 1,974 2,014 2,053 2,094
Firm Off-System Load 3 1 0 0 0 0 0 0 0 0
TOTAL LOAD 1,720 1,762 1,803 1,845 1,889 1,932 1,974 2,014 2,053 2,094
FIRM PEAK LOAD 3,051 3,136 3,218 3,302 3,389 3,474 3,559 3,643 3,726 3,810
SYSTEM PEAK (1 HOUR)3,051 3,136 3,218 3,302 3,389 3,474 3,559 3,643 3,726 3,810
Firm Off-System Peak 3 0 0 0 0 0 0 0 0 0
Loss 0 0 0 0 0 0 0 0 0 0
TOTAL PEAK LOAD 3,054 3,136 3,218 3,302 3,389 3,474 3,559 3,643 3,726 3,810
Average Load (Average Megawatts)
Peak Load (Megawatts)
SALES & LOAD REPORT
2004 Integrated Resource Plan
Technical Appendix

EExxiissttiinngg RReessoouurrccee DDaattaa

Hydroelectric Plant Data

Thermal Plant Data

QF Project Data

IDAHO POWER COMPANY
PLANT CAPABILITIES
As of January 1, 2004
Hydro Power Plants Estimated
Non-Coincidental
Nameplate Nameplate Maximum
kVA kW kW
American Falls 102,600 92,340 112,420
Bliss 86,250 75,000 80,000
Brownlee 650,444 585,400 728,000
Cascade 13,800 12,420 14,000
Clear Lake 3,125 2,500 (1) 2,400
Hells Canyon 435,000 391,500 450,000
Lower Salmon 70,000 60,000 70,000
Malad - Lower 15,500 13,500 15,000
Malad - Upper 9,650 8,270 9,000
Milner 62,890 59,448 59,448
Oxbow 211,112 190,000 220,000
Shoshone Falls 14,900 12,500 (1) 12,500
Strike, C J 90,000 82,800 89,000
Swan Falls 28,600 25,000 25,547
Thousand Springs 11,000 8,800 (1) 8,000
Twin Falls 56,175 52,737 54,300
Upper Salmon "A" 18,000 18,000 20,000
Upper Salmon "B" 18,000 16,500 19,000
Total Hydro 1,897,046 1,706,715
Steam & Other Generation
Estimated
Generator Generator Maximum
Nameplate Nameplate Dependable
Rating Rating Capability (MDC)
Gross kVA Gross kW Net kW
Bridger (IPCo Share) 811,053 770,501 706,667
Boardman (IPCo Share) 59,000 56,050 55,200
Valmy (IPCo Share) 315,000 283,500 260,650
Evander Andrews (Danskin) 105,882 90,000 100,000
Salmon Diesel 6,880 5,000 5,500
(1) A power factor rating of .8 is assumed on four units (Clear Lake, Unit #2
at Shoshone Falls, and Units #1 and #2 at 1000 Springs) with a total
kVA rating of 6,127 kVA on which there is no nameplate kW rating.
JV 7/12/2004
Project
Contract
On-line
Date
Contract
End Date Project
Contract
On-line
Date
Contract
End Date
Hydro Projects
Barber Dam Apr-1989 Apr-2024 Low Line Canal May-1985 May-2020
Birch Creek Nov-1984 Oct-2019 Lowline #2 Apr-1988 Apr-2023
Black Canyon #3 Apr-1984 Apr-2019 Magic Reservoir Jun-1989 May-2024
Blind Canyon Feb-1995 Feb-2015 Malad River May-1984 Apr-2019
Box Canyon Feb-1984 Feb-2019 Marco Ranches Aug-1985 Jul-2020
Briggs Creek Oct-1985 Oct-2020 Mile 28 Jun-1994 May-2029
Bypass Jun-1988 Jun-2023 Mitchell Butte May-1989 Dec-2023
Canyon Springs Oct-1984 Sep-2004 Mud Creek/S & S Mar-1982 Mar-2017
Cedar Draw Jun-1984 May-2019 Mud Creek/White Jan-1986 Jan-2021
Clear Springs Trout Nov-1983 Nov-2018 Owyhee Dam Cspp Apr-1984 Apr-2014
Crystal Springs Apr-1986 Mar-2021 Pigeon Cove Oct-1984 Oct-2019
Curry Cattle Company Jun-1983 Jun-2018 Pristine Springs Mar-1995 Mar-2005
Dietrich Drop Aug-1988 Aug-2023 Pristine Springs #3
Elk Creek May-1986 May-2021 Reynolds Irrigation May-1986 May-2021
Falls River Aug-1993 Aug-2028 Rim View
Faulkner Ranch Aug-1987 Aug-2022 Rock Creek #1 Sep-1983 Jan-2018
Fisheries Dev. Rock Creek #2 Apr-1989 Apr-2024
Geo-Bon #2 Nov-1986 Nov-2021 Sagebrush Sep-1985 Aug-2020
Hailey Cspp Jun-1985 Jun-2020 Schaffner Aug-1986 Aug-2021
Hazelton A Jun-1990 Jun-2010 Shingle Creek Aug-1983 Jul-2018
Hazelton B May-1993 May-2028 Shoshone #2 May-1996 Apr-2031
Horseshoe Bend Sep-1995 Sep-2030 Shoshone Cspp Jun-1982 Jun-2017
Jim Knight Jun-1985 Jun-2020 Snake River Pottery Nov-1984 Nov-2019
Kasel & Witherspoon Mar-1984 Mar-2019 Snedigar Jan-1985 Dec-2019
Koyle Small Hydro Apr-1984 Apr-2019 Sunshine Power # 2
Lateral # 10 May-1985 May-2020 Tiber Dam Jun-2004 Jun-2024
Lemoyne Jun-1985 Jun-2020 Trout-Co Dec-1986 Nov-2021
Little Wood Rvr Res Feb-1985 Feb-2020 Tunnel #1 Jun-1993 Dec-2027
Littlewood / Arkoosh Aug-1986 Aug-2021 White Water Ranch Aug-1985 Jul-2020
Wilson Lake Hydro May-1993 May-2028
41.78
Thermal Projects
Emmett Facility Jun-2005 Estimated Tamarack Cspp Jun-1983 May-2018
Magic Valley Nov-1996 Nov-2016 Tasco - Nampa Oct-1998 Sep-2003
Magic West Dec-1996 Dec-2016 Tasco - Twin Falls Aug-2001 Jul-2006
Pocatello Waste Dec-1985 Dec-2020 Vaagen Brothers Sep-1995 Sep-2010
Simplot Pocatello Feb-1991 Dec-2001 West Boise Waste Dec-1991 Dec-2006
41.15
Wind Projects
Horseshoe Bend Wind Nov-05 Estimated
Lewandowski Farms
2.61
85.54Total Average Annual Mw
Idaho Power Company
Qualifying Facilities
Cogeneration and Small Power Production Projects
Non Firm
Non Firm
Total Hydro Average Annual Mw
Total Thermal Average Annual Mw
Non Firm
Total Wind Average Annual Mw
Non Firm
Non Firm
2004 Integrated Resource Plan
Technical Appendix

FFuueell DDaattaa

Gas & Coal Forecast – Data and Graphs

Gas & Coal Forecast – Comparison to Previous IRPs

Spot Coal Natural Gas - Expected Natural Gas - Expected
Delivered Sumas Henry Hub Equiv
Year $/MMBtu Delivered $/MMBtu $/MMBtu
2004 $ 1.32 $ 4.50 $ 4.55 $ 6.11 $ 3.71
2005 $ 1.34 $ 4.77 $ 4.80 $ 5.57 $ 2.87
2006 $ 1.36 $ 4.85 $ 4.89 $ 6.27 $ 3.52
2007 $ 1.34 $ 4.81 $ 4.86 $ 6.46 $ 3.66
2008 $ 1.35 $ 4.87 $ 4.92 $ 6.62 $ 3.77
2009 $ 1.29 $ 4.96 $ 5.01 $ 6.86 $ 3.91
2010 $ 1.30 $ 5.10 $ 5.14 $ 7.14 $ 4.09
2011 $ 1.32 $ 5.32 $ 5.35 $ 7.50 $ 4.40
2012 $ 1.34 $ 5.53 $ 5.57 $ 7.77 $ 4.57
2013 $ 1.37 $ 5.75 $ 5.78 $ 8.03 $ 4.78
2014 $ 1.39 $ 6.02 $ 6.05 $ 8.35 $ 5.00
2015 $ 1.41 $ 6.28 $ 6.30 $ 8.65 $ 5.25
2016 $ 1.44 $ 6.03 $ 6.05 $ 8.45 $ 4.95 High & Low
2017 $ 1.47 $ 6.18 $ 6.20 $ 8.65 $ 5.10 Forecast Ends
2018 $ 1.50 $ 6.38 $ 6.40 $ 8.95 $ 5.30 in 2018
2019 $ 1.53 $ 6.54 $ 6.56 $ 9.17 $ 5.44 Escalated from
2020 $ 1.57 $ 6.77 $ 6.79 $ 9.46 $ 5.65 2019 Forward on
2021 $ 1.60 $ 6.78 $ 6.80 $ 9.53 $ 5.64 Forward on prior
2022 $ 1.64 Coal Price $ 6.95 $ 6.96 $ 9.75 $ 5.78 5 years avg
2023 $ 1.68 Forecast Ends $ 7.17 Gas Price $ 7.18 $ 10.03 $ 5.98 escalation
2024 $ 1.72 in 2024 $ 7.54 Forecast Ends $ 7.54 $ 10.45 $ 6.32
2025 $ 1.75 Escalated From $ 7.69 in 2025 $ 7.69 $ 10.66 $ 6.45
2026 $ 1.79 2025 Forward $ 7.87 Escalated From $ 7.87 $ 10.90 $ 6.61
2027 $ 1.82 on prior 5 years $ 8.06 2026 Forward $ 8.05 $ 11.14 $ 6.77
2028 $ 1.86 avg escalation $ 8.24 on prior 5 years $ 8.23 $ 11.38 $ 6.93
2029 $ 1.89 $ 8.43 avg escalation $ 8.41 $ 11.62 $ 7.09
2030 $ 1.93 $ 8.61 $ 8.59 $ 11.86 $ 7.25
2031 $ 1.96 $ 8.79 $ 8.77 $ 12.10 $ 7.41
2032 $ 2.00 $ 8.98 $ 8.95 $ 12.34 $ 7.57
2033 $ 2.03 $ 9.16 $ 9.13 $ 12.58 $ 7.73
2034 $ 2.07 $ 9.31 $ 12.82 $ 7.89
$/MMBtu $/MMBtu
Natural Gas - High Natural Gas - Low
Henry Hub Equiv Henry Hub Equiv
IDAHO POWER COMPANY
2004 IRP COAL & GAS PRICE FORECAST
$/MMBTU
4/26/2004
Gas Forecast Comparison
Nominal $/MMBtu
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
$10.00
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Idaho Power Nymex EIA NWPPC-Low
NWPPC-Med NWPPC-High US Power Outlook
Gas Forecast Comparison
$/MMBtu
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
2004 IRP 2002 IRP 2000 IRP
Coal Forecast Comparison
$/MMBtu
$1.00
$1.10
$1.20
$1.30
$1.40
$1.50
$1.60
$1.70
$1.80
$1.90
$2.00
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
2004 IRP 2002 IRP 2000 IRP
2004 Integrated Resource Plan
Technical Appendix

SSuuppppllyy SSiiddee RReessoouurrccee DDaattaa

Resource Cost Data and Operating Assumptions

Levelized Cost Data – Energy and Capacity

Monthly Wind Energy Distribution

Plant Invest Transmission Invest Total Invest Capacity Fixed O&M Variable Emission Adders Heat
Idaho Supply-Side Resources: $/Kw $/Kw $/Kw Factor $/Kw O&M $/MWh $/MWh Rate
Bennett Mtn CT 2nd Unit (162 MW) $347 $137 $485 58.9% $6.37 $4.14 $7.60 10,487
Danskin Adv CT 3rd Unit (43.7 MW) $534 $137 $671 58.9% $0.78 $3.10 $7.60 8,915
Idaho CCCT (540 MW) $617 $96 $714 85.0% $7.25 $2.80 $5.37 6,880
Danskin CC Conversion (69 MW) $874 $87 $961 88.0% $4.91 $2.07 $5.37 9,404
Combined Heat & Power (6 MW) $932 $182 $1,113 90.0% $6.82 $4.50 N/A N/A
Idaho Wind (100 MW) $1,137 $47 $1,184 35.0% $30.00 -$19.00 N/A N/A
Idaho Pulverized Coal (500 MW) $1,375 $104 $1,479 88.0% $24.81 $3.10 $13.45 9,000
Valmy Unit 3 (130 MW) $1,275 $400 $1,675 88.0% $24.08 $4.15 $13.45 9,000
Idaho - Geothermal (50 MW) $2,912 $28 $2,940 93.0% $81.47 $0.00 N/A N/A
Other Supply Side Resources Analyzed:
MSW Landfill Gas (30 MW) $1,587 N/A $1,587 80.0% $99.57 $0.01 N/A 13,648
Biomass (100 MW) $1,894 N/A $1,894 80.0% $46.47 $2.96 N/A 8,911
Advanced Nuclear (1000 MW) $1,898 N/A $1,898 90.0% $59.17 $0.43 N/A 10,400
Solar Thermal (100 MW) $2,847 N/A $2,847 42.0% $49.48 $0.00 N/A 10,280
Solar Photovoltaic (5 MW) $4,218 N/A $4,218 30.0% $10.08 $0.00 N/A 10,280
Notes Regarding Assumptions and Inputs
1. Cost inputs and operating assumptions were derived from the 2003 Department of Energy Annual Energy Outlook, independent power producers in the region, and IPC engineering staff.
2. The Idaho supply-side resources were analyzed further to include estimates for incremental stand-alone transmission and emissions costs.
3. Plant and transmission investment include estimates for AFUDC interest.
4. Fixed O&M includes estimates for property taxes, insurance, and applicable fixed transmission facilities charges.
5. Production tax credit of $19 for wind resource applied for first 10 years within the discounted cash flow modeling, then $0.
6. The Idaho supply-side transmission includes emmision cost adders (externalities) at a base level of $12/ton CO2, $2,460/ton, NOX, and $2,460 TSP.
Weighted Cost of Capital 8.39%
Operating Life - Years 30
Composite Tax Rate 39.10%
Property Tax Rate (% of investment) 0.41%
Insurance Rate (% of investment) 0.25%
Insurance Esc. Rate 5.00%
O&M Esc. Rate 2.52%
After Tax Discount Rate 7.20%
AFUDC Rate 7.24%
* The capital structure and costs used to determine the weighted cost of capital and after tax discount rate were based on Idaho Power's 2003 base rate case filing with the IPUC.
Since the completion of this resource cost analysis, IPUC order 29505 has been issued which calls for a decrease in the company's allowed return on equity.
This results in an after-tax disount rate calcualtion of 6.7%. Idaho Power recognizes this reduction, however this change did not change the ranking order of the levelized resource costs.
Operating Assumptions and Cost Inputs Used to Price Supply-Side Resource Alternatives
Financing Assumptions used for Levelized Cost Analysis *
2004 Integrated Resource Plan
Idaho Supply Side Resources:Capacity Non-Fuel O&M Fuel Total
Bennett Mtn CT 2nd Unit (162 MW) 4.37 1.06 0.00 5.43
Danskin Adv CT 3rd Unit (43.7 MW) 6.05 0.58 0.00 6.63
Idaho CCCT (540 MW) 6.43 1.33 0.00 7.76
Danskin CC Conversion (69 MW) 8.34 1.25 0.00 9.59
Combined Heat & Power (6 MW) 10.04 1.57 0.00 11.61
Idaho Wind (100 MW) 9.05 4.59 0.00 13.64
Idaho Pulverized Coal (500 MW) 13.34 3.85 0.00 17.19
Valmy Unit 3 (130 MW) 15.10 7.49 0.00 22.59
Idaho - Geothermal (50 MW) 22.48 12.24 0.00 34.72
Other Supply Side Resources Analyzed:
Biomass (100 MW) 17.08 6.57 0.00 23.65
Advanced Nuclear (1000 MW) 17.11 8.00 0.00 25.11
MSW Landfill Gas (30 MW) 14.31 12.29 0.00 26.60
Solar Thermal (100 MW) 25.67 7.60 0.00 33.27
Solar Photovoltaic (5 MW) 36.61 4.19 0.00 40.80
Demand Side Resources Analyzed:
Irrigation Demand Response (30 MW) 0.00 4.22 0.00 4.22
A/C Demand Response (57 MW) 0.00 5.50 0.00 5.50
Irrigation Efficiency (29 MW) 0.00 8.33 0.00 8.33
Residential Efficiency New (9 MW) 0.00 8.39 0.00 8.39
Commercial Efficiency New (4 MW) 0.00 14.17 0.00 14.17
Residential Efficiency Existing (20 MW) 0.00 19.54 0.00 19.54
Commercial Efficiency Existing (16 MW) 0.00 19.95 0.00 19.95
Industrial Efficiency (12 MW) 0.00 20.28 0.00 20.28
Idaho Supply Side Resources:Capacity Non-Fuel O&M Fuel Emission Adders Total
Idaho Wind (100 MW) 35.43 7.51 0.00 0.00 42.94
Idaho - Geothermal (50 MW) 33.11 18.03 0.00 0.00 51.14
Combined Heat & Power (5.5 MW) 15.28 8.43 30.33 0.00 54.05
Idaho Pulverized Coal (500 MW) 20.76 10.15 13.27 13.45 57.63
Valmy Unit 3 (130 MW) 23.51 11.66 13.27 13.45 61.88
Idaho CCCT (540 MW) 10.37 5.90 41.74 5.37 63.38
Danskin CC Conversion ( 69 MW) 9.13 4.81 48.69 5.37 68.00
Danskin Adv CT 3rd Unit (43.7 MW) 14.08 5.50 54.08 7.60 81.27
Bennett Mtn CT 2nd Unit (162 MW) 9.78 8.03 63.62 7.60 89.04
Other Supply Side Resources Analyzed:
Advanced Nuclear (1000 MW) 26.05 12.75 5.00 0.00 43.80
Biomass (100 MW) 29.25 15.23 0.00 0.00 44.48
MSW Landfill Gas (30 MW) 24.50 21.06 0.00 0.00 45.56
Solar Thermal (100 MW) 83.72 24.80 0.00 0.00 108.52
Solar Photovoltaic (5 MW) 173.66 19.15 0.00 0.00 192.81
Demand Side Resources Analyzed:
Industrial Efficiency (12 MW) 0.00 31.05 0.00 0.00 31.05
Commercial Efficiency Existing (16 MW) 0.00 43.35 0.00 0.00 43.35
Irrigation Efficiency (29 MW) 0.00 50.01 0.00 0.00 50.01
Residential Efficiency Existing (20 MW) 0.00 54.43 0.00 0.00 54.43
Residential Efficiency New (9 MW) 0.00 56.66 0.00 0.00 56.66
Commercial Efficiency New (4 MW) 0.00 66.81 0.00 0.00 66.81
Energy - Levelized $/MWH
2004 Integrated Resource Plan
Levelized Resource Cost Table
Capacity - Levelized $/kW/month
Project size - MW 100
Annual capacity factor 35%
Flat Monthly output - aMW 35
Normalized Monthly Wind Energy Distribution Annual
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average
Basin & Range 1.19 1.39 1.07 1.05 0.94 0.71 0.56 0.61 0.72 0.74 1.59 1.43 1
Est. monthly output - aMW 42 49 37 37 33 25 20 21 25 26 56 50 35
2004 Integrated Resource Plan
Wind Distribution Profile
From NW Power & Conservation Council
Normalized Monthly Wind Energy Distribution
Basin & Range
0
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
1.8
Jan Mar May Jul Sep Nov Average
2004 Integrated Resource Plan
Technical Appendix

DDeemmaanndd SSiiddee RReessoouurrccee DDaattaa

DSM Analysis & Screening Criteria

DSM Programs – Descriptions

DSM Programs – Load Reductions & Costs by Year

DSM Programs – Portfolio Benefits

DSM Programs – Summary

DSM Program Development. The demand-side resource options were developed using a
combination of internal engineering estimates as well as external consulting services. The
residential and commercial program options were designed by Quantum Consulting of
Berkeley, California, and Idaho Power’s engineering staff developed the remaining
programs. Each of the energy efficiency programs were designed to maximize the
potential energy benefits of the resource while remaining cost-effective from a total
resource perspective. The demand response options were designed to maximize the load
impact achieved while remaining cost-effective from the utility’s perspective. During this
process, two to four program levels were developed to allow for the determination of the
optimum program level to be included in the IRP.

The demand-side management options were all designed using similar cost components.
The demand response options include some additional costs not contained in the energy
options due to the need for ongoing operation of the programs by the utility. Each of the
energy and demand response program options contain the following cost components:

• Administrative costs
• Marketing and advertising costs
• Incentive or rebate payments
• Participant costs

The demand response program cost structure contains the following additional costs not
included in the energy program options:

• Capital costs
• Operating and maintenance costs
• Increased supply costs (resulting from the energy shifted from on-peak to off-
peak periods)

Once the program design phase has been completed, each new program was put through
a series of static screening analysis prior to being included in the IRP dynamic portfolio
analysis.

Screening Criteria. The DSM screening criteria were designed to assess a program’s
potential to maximize benefits at the lowest cost for all stakeholders.
There are four general categories of criteria taken into consideration when looking at
selecting DSM programs.
• Programs will be cost-effective. From a total resource perspective, estimated
program benefits must be greater than estimated program costs. As shown by the
2002 Idaho Power Integrated Resource Plan, programs that decrease summer peak
demand will be valuable because they reduce the need for new peak resources.
Programs that capture cost-effective, lost-opportunity DSM resources will be
encouraged.
• 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.
These criteria are used as guidelines in selecting a new program or initiative. A program
that doesn’t 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.1

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 2004 IRP are evaluated from Utility Cost Test
and Total Resource Cost test perspectives.

ƒ 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 ratepayers as a whole. Costs include changes in
supply costs, utility costs, and participant costs. (Transfer payments between ratepayers
and the utility are ignored).
The following are the calculations performed by this test:
¾ Net Present Value: A net present value of zero or greater indicates that the
program is cost-effective from the total resource cost perspective.
¾ Benefits-Cost Ratio: A benefit-cost ratio of 1.0 or greater indicates the program is
cost-effective from the total resource cost perspective.
¾ 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

1 IPUC Order No. 29026, May 20, 2002 2 http://www.cpuc.ca.gov/static/industry/electric/energy+efficiency/rulemaking/resource5.doc 3 EPRI End-Use Technical Assessment Guide (End-Use TAG), Volume 4: Fundamentals and Methods,
Barakat and Chamberlin, Inc, April 1991

discounted and then divided by the stream of discounted kW or kWh that is
expected from the program.

• Utility Cost Test4
The Utility Cost test is a measure of the total costs to the utility to implement a DSM
program.

The following are the calculations performed by this test:
¾ Net Present Value: A net present value of zero or greater indicates that the
program is cost-effective from the Utility Cost perspective.
¾ Benefits-Cost Ratio: A benefit-cost ratio of 1.0 or greater indicates the program is
cost-effective from the Utility Cost perspective.
¾ 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 of DSM resource is discounted and then divided by the stream of kW and
kWh that is expected from the program.

DSM Analysis Calculation Definitions: 4

o 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.
N N
∑ Program Benefits (minus) ∑ Program Costs
T=1 (1+ WACC) t-1 T=1 (1+ WACC) t-1
Where: N = the total number of years, t = the incremental year, and WACC = the
Company’s weighted average cost of capital.

o Benefits-Cost Ratio: Calculated as the discounted stream of program benefits
divided by the discounted stream of program costs.
N N
∑ Program Benefits ÷ ∑ Program Costs
t=1 (1+ WACC) t-1 t=1 (1+ WACC) t-1

o 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.

4 EPRI End-Use Technical Assessment Guide (End-Use TAG), Volume 4: Fundamentals and Methods,
Barakat and Chamberlin, Inc, April 1991

N N
∑ Program Costs ÷ ∑ Energy Savings
T=1 (1+ WACC) t-1 T=1 (1+ WACC) t-1

o Discounted Payback: Number of years from the initial program participation
to the point at which the cumulative discounted benefits exceed the
cumulative discounted costs for participants. (Usually calculated for an
average customer who joins the program in its 1st year)
o Undiscounted Payback: Number of years from the initial program
participation to the point at which the cumulative undiscounted benefits
exceed the cumulative undiscounted costs for participants.
o Free riders: Program participants that would have implemented the energy
efficiency measure without the program or incentive.
o 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

To quantify the “benefit” portion of the calculation 5 costing periods were created for the
year that are consistent with the proposed industrial time-of-use rate pricing periods5.
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.

The following is tables are illustrate the time of day and time of year costing period
definitions used in the static program screening analysis:

5 General Rate Case No. IPC-E-03-13.

June 01 – August 31
SOFP = Summer Off-Peak
SMP = Summer Mid-Peak
SONP = Summer On-Peak
SUMMER SEASON
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1 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
2 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
3 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
4 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
5 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
6 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
7 SMP SMP SMP SMP SMP SMP SMP SMP
8 SMP SMP SMP SMP SMP SMP SMP SMP
9 SMP SMP SMP SMP SMP SMP SMP SMP
10 SMP SMP SMP SMP SMP SMP SMP SMP
11 SMP SMP SMP SMP SMP SMP SMP SMP
12 SMP SMP SMP SMP SMP SMP SMP SMP
13 SMP SONP SONP SONP SONP SONP SMP SMP
14 SMP SONP SONP SONP SONP SONP SMP SMP
15 SMP SONP SONP SONP SONP SONP SMP SMP
16 SMP SONP SONP SONP SONP SONP SMP SMP
17 SMP SONP SONP SONP SONP SONP SMP SMP
18 SMP SONP SONP SONP SONP SONP SMP SMP
19 SMP SONP SONP SONP SONP SONP SMP SMP
20 SMP SONP SONP SONP SONP SONP SMP SMP
21 SMP SMP SMP SMP SMP SMP SMP SMP
22 SMP SMP SMP SMP SMP SMP SMP SMP
23 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
24 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP

September 01 - May31
NSOFP = Non-Summer Off-Peak
NSMP = Non-Summer Mid-Peak

NON-SUMMER SEASON
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1 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
2 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
3 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
4 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
5 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
6 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
7 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
8 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
9 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
10 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
11 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
12 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
13 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
14 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
15 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
16 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
17 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
18 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
19 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
20 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
21 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
22 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
23 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
24 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP

Forward market prices are used for the segmented alternative cost periods in all periods
except in the “Summer On-peak” period. Forward market prices are forecasted in two
categories, “heavy load” and “light load”. The heavy load and light load prices are
forecasted by month for 10 years6. For measures with lives beyond ten years, the forecast
is 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 for capital
investments.

6 The forward price curve was taken from the 2002 Idaho Power Integrated Resource Plan.
The costing period prices are calculated using the following method:

™ NSMP = Average of heavy load prices in Jan. – May. And Sept. – Dec.
™ NSOFP = Average of light load prices in Jan. – May. And Sept. – Dec.
™ SOFP = Average of light load prices in Jun. – Aug.
™ SMP = Average of heavy load prices in Jun. – Aug.
™ SONP = Idaho Powers variable energy cost of a 162 MW Simple Cycle
Gas Turbine plus the marginal capacity cost of that Gas Turbine in
$/kW/Year.

The benefit values for the A/C Demand Response and Irrigation Demand Response
programs were calculated under the assumption that these programs will result in no
energy savings. It was assumed that the energy saved during the down time would be
shifted from the high price summer on-peak time period to the lower price summer mid-
peak time period.

The following table shows the schedule of alternative costs used to calculate the benefit
value of each program in the static analysis:

Alternative Energy Cost ($/MWH)

IPCo Variable
Energy Cost Market Price Forecast
Year SONP SMP SOFP NSMP NSOFP
2004 $ 68.43 $ 35.61 $ 29.10 $ 34.76 $ 28.41
2005 $ 70.16 $ 36.37 $ 29.87 $ 35.51 $ 29.16
2006 $ 71.92 $ 37.39 $ 30.63 $ 36.50 $ 29.90
2007 $ 73.74 $ 68.28 $ 35.49 $ 37.74 $ 30.98
2008 $ 75.59 $ 73.32 $ 36.82 $ 40.34 $ 32.60
2009 $ 77.50 $ 76.79 $ 37.78 $ 40.10 $ 34.03
2010 $ 79.45 $ 79.25 $ 38.48 $ 42.83 $ 35.67
2011 $ 81.45 $ 82.13 $ 39.58 $ 45.89 $ 37.36
2012 $ 83.51 $ 84.20 $ 40.58 $ 47.05 $ 38.30
2013 $ 85.61 $ 86.32 $ 41.60 $ 48.23 $ 39.27
2014 $ 87.77 $ 88.50 $ 42.65 $ 49.45 $ 40.26
2015 $ 89.98 $ 90.73 $ 43.72 $ 50.70 $ 41.27
2016 $ 92.25 $ 93.02 $ 44.83 $ 51.97 $ 42.31
2017 $ 94.57 $ 95.36 $ 45.96 $ 53.28 $ 43.38
2018 $ 96.96 $ 97.76 $ 47.11 $ 54.63 $ 44.47
2019 $ 99.40 $ 100.23 $ 48.30 $ 56.00 $ 45.59
2020 $ 101.90 $ 102.75 $ 49.52 $ 57.41 $ 46.74
2021 $ 104.47 $ 105.34 $ 50.77 $ 58.86 $ 47.92
2022 $ 107.10 $ 108.00 $ 52.05 $ 60.34 $ 49.13
2023 $ 109.80 $ 110.72 $ 53.36 $ 61.87 $ 50.36

Alternative Capacity Cost ($/kW/Yr)
162 MW Simple Cycle Gas Turbine
Year SONP SMP SOFP NSMP NSOFP
2004 $ 59.18 $0.00 $0.00 $0.00 $0.00
2005 $ 60.67 $0.00 $0.00 $0.00 $0.00
2006 $ 62.20 $0.00 $0.00 $0.00 $0.00
2007 $ 63.77 $0.00 $0.00 $0.00 $0.00
2008 $ 65.37 $0.00 $0.00 $0.00 $0.00
2009 $ 67.02 $0.00 $0.00 $0.00 $0.00
2010 $ 68.71 $0.00 $0.00 $0.00 $0.00
2011 $ 70.44 $0.00 $0.00 $0.00 $0.00
2012 $ 72.22 $0.00 $0.00 $0.00 $0.00
2013 $ 74.04 $0.00 $0.00 $0.00 $0.00
2014 $ 75.90 $0.00 $0.00 $0.00 $0.00
2015 $ 77.81 $0.00 $0.00 $0.00 $0.00
2016 $ 79.77 $0.00 $0.00 $0.00 $0.00
2017 $ 81.79 $0.00 $0.00 $0.00 $0.00
2018 $ 83.85 $0.00 $0.00 $0.00 $0.00
2019 $ 85.96 $0.00 $0.00 $0.00 $0.00
2020 $ 88.13 $0.00 $0.00 $0.00 $0.00
2021 $ 90.35 $0.00 $0.00 $0.00 $0.00
2022 $ 92.62 $0.00 $0.00 $0.00 $0.00
2023 $ 94.96 $0.00 $0.00 $0.00 $0.00

Notes:
1

IPCo Variable Energy Cost includes fuel and O&M for a 162MW Simple Cycle CT.
(Calculated on "Gas Worksheet")
2 The Market Price Forecast includes capacity cost. (Refer to "Electric Prices" for detail)
3 Escalation rate is 2.52% as stated in the 2002 IRP.
4 Time of Day segments are defined on the "TOD Segments" worksheet.

For all energy programs it is assumed that the energy savings will continue beyond the
measure life time period for each program participant. We felt 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.

Dynamic Modeling. The programs that have been determined to be cost effective using
the static analysis are then put through the Aurora dynamic modeling process to
determine the impacts to the overall resource portfolio. The hourly energy savings
associated with each program is valued within the Aurora simulation model. The model
output is the present value dollar impacts to the overall resource portfolio revenue
requirement. If the present value reduction of overall revenue requirement exceeds the
present value program costs, the program is determined to be cost effective.

The two demand response options were analyzed outside of the Aurora model due to the
complexity of modeling the hourly load reduction of a time constrained resource. The
two demand response programs were analyzed using the static analysis and shown to be
cost-effective. These two programs were also stacked up against the other supply-side
and demand-side options using a 30-year levelized cost measurement. The two programs
were among the lowest levelized costs of all the portfolio resources and were selected
based on those criteria.

Program
Description
Program Size
Average Demand (MWa)6.6
Peak Reduction (MW)28.8
Annual Energy (MWh)57,668
Description
Seasonality Summer Only
Dispatchability No
Target Market All Irrigation Customers
First Year Available 2005
Program Duration (Years)10
Measure Life (Years)15
Customer Participant Payback (Years)3.03
Costs and Benefits (thousands of dollars)
Utility Cost
Test
Total
Resource
Cost Test
Discounted Present Values
Benefits (30 Years)$90,690 $90,690
Costs (10 Years)$18,257 $24,053
Net Benefits $72,433 $66,637
Benefit/Cost Ratio 4.97 3.77
Levelized Costs
Nominal 30-Year ($/kWh)$0.039 $0.051
Nomial 30-Year ($/Peak kW/Mo)$6.40 $8.50
Irrigation Efficiency Program
This program is designed to reduce peak demand and energy of irrigation customers. The
program is targeted at all customers in Rate 24. Idaho Power will pay customers direct
incentives for modifications to existing or new irrigation systems. Incentives will be based
on kW or kWh savings. Measures eligible for incentive payments include low-pressure pivot
or linear packages, larger mainline to reduce friction loss, variable speed drives, and high
efficiency motors. Marketing and education will be accomplished through direct mail pieces,
irrigation workshops and articles in irrigation publications. The primary ramp up of this
program takes place in the first five years. Idaho Power has been operating a small-scale
version of this program since the fall of 2003.
Program
Description
Program Size
Average Demand (MWa)10.8
Peak Reduction (MW)12.0
Annual Energy (MWh)94,265
Description
Seasonality Summer Focus
Dispatchability No
Target Market Industrial Customers w/BLC > 500 kW
First Year Available 2005
Program Duration (Years)10
Measure Life (Years)12
Customer Participant Payback (Years)3.78
Costs and Benefits (thousands of dollars)
Utility Cost
Test
Total
Resource
Cost Test
Discounted Present Values
Benefits (30 Years)$79,324 $79,324
Costs (10 Years)$15,348 $24,413
Net Benefits $63,976 $54,911
Benefit/Cost Ratio 5.17 3.25
Levelized Costs
Nominal 30-Year ($/kWh)$0.020 $0.032
Nomial 30-Year ($/Peak kW/Mo)$12.90 $20.60
Industrial Efficiency Program
This program is designed to reduce peak demand and energy of large industrial and
commercial customers. The program is targeted to all new and existing Rate 19 and Rate
09 customers with a basic load capacity of 500 kW or greater. Idaho Power will provide
direct incentives and assist with audit costs. Incentives will be based on kW or kWh
savings. Measures eligible for incentive payments include refrigeration efficiency, variable
speed drives, lighting and control upgrades. Potential marketing and education activities
include direct mail pieces, newsletters, demonstrations of efficient technologies, workshops,
case studies and articles in industrial publications. Idaho Power will leverage the industrial
efforts of the Northwest Energy Efficiency Alliance to enhance participation. Idaho Power
has been operating a small-scale version of this program since the fall of 2003.
Program
Description
Program Size
Average Demand (MWa)1.1
Peak Reduction (MW)3.8
Annual Energy (MWh)9,605
Description
Seasonality Summer Focus
Dispatchability No
Target Market Commercial New Construction
First Year Available 2005
Program Duration (Years)10
Measure Life (Years)16
Customer Participant Payback (Years)6.77
Costs and Benefits (thousands of dollars)
Utility Cost
Test
Total
Resource
Cost Test
Discounted Present Values
Benefits (30 Years)$19,309 $19,309
Costs (10 Years)$3,788 $5,027
Net Benefits $15,521 $14,282
Benefit/Cost Ratio 5.10 3.84
Levelized Costs
Nominal 30-Year ($/kWh)$0.051 $0.068
Nomial 30-Year ($/Peak kW/Mo)$10.80 $14.40
Commercial Efficiency (New Construction)
This program is designed to reduce peak demand and energy of new commercial customers
in Rate 07 and Rate 09. This program targets new commercial building owners/developers
and architects/engineers. Energy efficiency information, access to technical and financial
resources, and linkages to other relevant information sources are included. The focus is on
business and technical assistance, entering the design and construction process early on to
influence initial design considerations and equipment selection. Information on building
design and construction best practices will be provided. Financial incentives can include
cash rebates or customer incentives. High profile demonstration projects can be used to
prove the viability of energy efficient changes in design and construction practices. Idaho
Power will leverage the efforts of the Northwest Energy Efficiency Alliance Commercial
Program
Description
Program Size
Average Demand (MWa)10.1
Peak Reduction (MW)16.0
Annual Energy (MWh)88,395
Description
Seasonality Summer Focus
Dispatchability No
Target Market Commercial Existing Construction
First Year Available 2005
Program Duration (Years)10
Measure Life (Years)9
Customer Participant Payback (Years)7.77
Costs and Benefits (thousands of dollars)
Utility Cost
Test
Total
Resource
Cost Test
Discounted Present Values
Benefits (30 Years)$76,120 $76,120
Costs (10 Years)$17,699 $32,791
Net Benefits $58,421 $43,329
Benefit/Cost Ratio 4.30 2.32
Levelized Costs
Nominal 30-Year ($/kWh)$0.024 $0.044
Nomial 30-Year ($/Peak kW/Mo)$10.90 $20.20
Commercial Efficiency (Existing Construction)
This program is designed to reduce peak demand and energy of commercial customers on
Rate Schedules 07 and 09. Although a firm program design has not been determined, initial
assumptions include payment of direct incentives for modifications to commercial customers
categorized in 11 different building types including, retail, small office and hospitals.
Incentives will be based on kW or kWh savings. Measures eligible for incentive payments
include those that have summer peak impact; lighting, DX Tune up/advanced diagnostics,
DX packaged systems. Marketing and education will be a large component of this program.
Program
Description
Program Size
Average Demand (MWa)1.9
Peak Reduction (MW)9.3
Annual Energy (MWh)16,612
Description
Seasonality Summer Focus
Dispatchability No
Target Market Residential New Construction
First Year Available 2005
Program Duration (Years)10
Measure Life (Years)14
Customer Participant Payback (Years)6.51
Costs and Benefits (thousands of dollars)
Utility Cost
Test
Total
Resource
Cost Test
Discounted Present Values
Benefits (30 Years)$19,282 $19,282
Costs (10 Years)$4,725 $7,615
Net Benefits $14,557 $11,667
Benefit/Cost Ratio 4.08 2.53
Levelized Costs
Nominal 30-Year ($/kWh)$0.036 $0.058
Nomial 30-Year ($/Peak kW/Mo)$5.30 $8.50
Residential Efficiency (New Construction)
This program is designed to reduce peak demand and energy of new residential customers
under Rate 01. The Idaho Power service territory includes some of the fastest-growing
markets for new residential construction in the Pacific Northwest. Over 90% of all new
homes are built with central air conditioning. It is anticipated that this program will be
patterned after the Energy Star Homes Northwest program, partnering with regional and
state organizations. Direct incentives will be provided to builders and possibly homebuyers.
Incentives will be based on kW or kWh savings. Primary eligible measures include high-
efficiency air conditioners, duct sealing, shell measures, efficient lighting and efficient
appliances. Potential marketing and education activities include direct mail pieces,
newsletters, participation in home shows and home parades. Idaho Power will work with
Program
Description
Program Size
Average Demand (MWa)9.8
Peak Reduction (MW)20.2
Annual Energy (MWh)86,144
Description
Seasonality Summer Focus
Dispatchability No
Target Market Residential Existing Construction
First Year Available 2005
Program Duration (Years)10
Measure Life (Years)12
Customer Participant Payback (Years)6.42
Costs and Benefits (thousands of dollars)
Utility Cost
Test
Total
Resource
Cost Test
Discounted Present Values
Benefits (30 Years)$73,419 $73,419
Costs (10 Years)$23,001 $37,657
Net Benefits $50,418 $35,762
Benefit/Cost Ratio 3.19 1.95
Levelized Costs
Nominal 30-Year ($/kWh)$0.034 $0.055
Nomial 30-Year ($/Peak kW/Mo)$12.10 $19.80
Residential Efficiency (Existing Construction)
This program is designed to reduce peak demand and energy of residential customers on
Rate Schedule 01. Although a firm program design has not been determined, initial
assumptions include payment of direct incentives for modifications to existing single- family
homes, multifamily homes or manufactured homes. Incentives will be based on kW or kWh
savings. Measures eligible for incentive payments include those that have summer peak
impact; high-efficient air conditioners, HVAC O&M measures, duct repair, insulation and
lighting. Marketing and education will be a large component of this program.
Program
Description
Program Size
Average Demand (MWa)--
Peak Reduction (MW)45.2
Annual Energy (MWh)--
Description
Seasonality Summer only
Dispatchability Yes
Target Market Residential Customers with Central A/C
First Year Available 2005
Program Duration (Years)30
Measure Life (Years)15
Customer Participant Payback (Years)N/A
Costs and Benefits (thousands of dollars)
Utility Cost
Test
Total
Resource
Cost Test
Discounted Present Values
Benefits (30 Years)$44,094 $44,094
Costs (30 Years) *$34,271 $26,317
Net Benefits $9,823 $17,778
Benefit/Cost Ratio 1.29 1.68
Levelized Costs
Nominal 30-Year ($/kWh)N/A N/A
Nomial 30-Year ($/Peak kW/Mo)$5.50 $4.02
Air Conditioning Demand Response
This program is designed to provide a dispatchable resource by cycling residential air
conditioners off during times of heavy peak load. The target market is residential customers
under Rate 01 that have central air conditioners. The final design of this program will
depend upon findings of a pilot program being conducted in 2003-2004 in the Boise/Meridian
area. The pilot will help determine costs, kW reduction, recommended program design and
recommended technologies. Idaho Power is testing both radio-controlled thermostats and
radio-controlled compressor switches. Air conditioners are cycled off and on every 15
minutes for four hours, 10 times per month. Participants receive a $10 reduction on their
electricity bill during the three months they are cycled: June, July and August. The pilot
program will be finished early winter 2004.
* Demand response program costs include increases supply costs associated with energy shifted from on
peak to off peak periods.
Program
Description
Program Size
Average Demand (MWa)--
Peak Reduction (MW)30.4
Annual Energy (MWh)--
Description
Seasonality Summer only
Dispatchability No
Target Market Irrigation Customers (no yield reduction allowed)
First Year Available 2005
Program Duration (Years)30
Measure Life (Years)15
Customer Participant Payback (Years)N/A
Costs and Benefits (thousands of dollars)
Utility Cost
Test
Total
Resource
Cost Test
Discounted Present Values
Benefits (30 Years)$35,151 $35,151
Costs (30 Years) *$25,190 $13,016
Net Benefits $9,961 $22,135
Benefit/Cost Ratio 1.40 2.70
Levelized Costs
Nominal 30-Year ($/kWh)N/A N/A
Nomial 30-Year ($/Peak kW/Mo)$4.22 $1.33
Irrigation Peak Demand Response
This program is designed to provide a temporary reduction in demand by turning off irrigation
pumps during times of summer peak. The target market is irrigation customers under Rate
24. The final design of this program will depend upon findings of a pilot program being
conducted in summer of 2004 in four areas across the Idaho Power service territory. The
pilot will determine costs, kW reduction and recommended program design. Each
participating customer offers to have their irrigation pump turned off either once, twice or
three times per week between the hours of 4 and 8 pm. Pumps are installed with automatic
electronic timers. Participants receive a billing credit on their electric bill during the three
months they are turned off: June, July and August. The pilot program will be finished early
winter 2004.
* Demand response program costs include increased supply costs associated with energy shifted from on-
peak to off-peak periods.
Year All Programs
Irrigation
Efficiency
Industrial
Efficiency
Commercial
Efficiency (New
Construction)
Commercial
Efficiency
(Existing)
Residential
Efficiency (New
Construction)
Residential
Efficiency
(Existing)
Air Conditioning
Demand
Response
Irrigation
Demand
Response
2004 N/A N/A
2005 25,107 5,767 9,427 389 5,480 1,070 2,976 N/A N/A
2006 61,589 11,534 18,853 1,087 16,719 2,625 10,771 N/A N/A
2007 99,622 17,300 28,280 1,900 28,420 4,193 19,529 N/A N/A
2008 138,141 23,067 37,706 2,810 39,872 5,784 28,902 N/A N/A
2009 176,385 28,834 47,133 3,801 50,608 7,397 38,612 N/A N/A
2010 214,026 34,601 56,559 4,861 60,361 9,205 48,440 N/A N/A
2011 250,585 40,368 65,986 5,980 69,007 11,028 58,216 N/A N/A
2012 285,909 46,134 75,412 7,149 76,528 12,872 67,814 N/A N/A
2013 319,941 51,901 84,839 8,359 82,964 14,734 77,145 N/A N/A
2014 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2015 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2016 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2017 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2018 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2019 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2020 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2021 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2022 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2023 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2024 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2025 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2026 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2027 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2028 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2029 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2030 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2031 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2032 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
2033 352,689 57,668 94,265 9,605 88,395 16,612 86,144 N/A N/A
Energy Savings
Net of Free Riders, Includes Losses
(in Megawatt-hours)
Year All Programs
Irrigation
Efficiency
Industrial
Efficiency
Commercial
Efficiency (New
Construction)
Commercial
Efficiency
(Existing)
Residential
Efficiency (New
Construction)
Residential
Efficiency
(Existing)
Air Conditioning
Demand
Response
Irrigation
Demand
Response
2004
2005 45.9 2.9 1.2 0.1 1.0 0.6 0.6 9.0 30.4
2006 63.9 5.8 2.4 0.4 3.0 1.5 2.3 18.1 30.4
2007 82.4 8.7 3.6 0.7 5.1 2.5 4.3 27.1 30.4
2008 101.0 11.5 4.8 1.1 7.2 3.4 6.5 36.2 30.4
2009 119.6 14.4 6.0 1.5 9.1 4.3 8.7 45.2 30.4
2010 129.2 17.3 7.2 1.9 10.9 5.3 11.0 45.2 30.4
2011 138.6 20.2 8.4 2.4 12.5 6.3 13.3 45.2 30.4
2012 147.8 23.1 9.6 2.8 13.8 7.3 15.6 45.2 30.4
2013 156.9 26.0 10.8 3.3 15.0 8.3 17.9 45.2 30.4
2014 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2015 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2016 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2017 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2018 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2019 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2020 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2021 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2022 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2023 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2024 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2025 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2026 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2027 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2028 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2029 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2030 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2031 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2032 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
2033 165.7 28.8 12.0 3.8 16.0 9.3 20.2 45.2 30.4
Peak Reduction
Net of Free Riders, Includes Losses
(in Megawatts)
Year Residential Commercial Irrigation Industrial Residential Commercial Irrigation Industrial
2004
2005 4,045 5,869 5,767 9,427 10.3 1.1 33.3 1.2
2006 13,397 17,806 11,534 18,853 22.0 3.4 36.1 2.4
2007 23,722 30,320 17,300 28,280 33.9 5.8 39.0 3.6
2008 34,686 42,682 23,067 37,706 46.0 8.3 41.9 4.8
2009 46,010 54,409 28,834 47,133 58.2 10.6 44.8 6.0
2010 57,644 65,222 34,601 56,559 61.5 12.8 47.7 7.2
2011 69,244 74,988 40,368 65,986 64.8 14.8 50.6 8.4
2012 80,686 83,676 46,134 75,412 68.1 16.7 53.4 9.6
2013 91,879 91,323 51,901 84,839 71.4 18.3 56.3 10.8
2014 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2015 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2016 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2017 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2018 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2019 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2020 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2021 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2022 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2023 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2024 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2025 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2026 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2027 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2028 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2029 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2030 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2031 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2032 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
2033 102,756 98,000 57,668 94,265 74.7 19.8 59.2 12.0
Energy and Peak Reduction by Customer Class
Net of Free Riders, Includes Losses
Energy Savings (Megawatt-hours)Peak Reduction (Megawatts)
All Programs
Irrigation
Efficiency
Industrial
Efficiency
Commercial
Efficiency (New
Construction)
Commercial
Efficiency
(Existing)
Residential
Efficiency (New
Construction)
Residential
Efficiency
(Existing)
Air Conditioning
Demand
Response*
Irrigation
Demand
Response*
Present Value Costs ($453,473)($90,690)($79,324)($19,309)($76,120)($19,282)($73,419)($40,381)($35,151)
2004
2005 (4,323)(228)(580)341 (596)(14)(363)(594)(2,289)
2006 (6,648)(420)(761)28 (1,185)429 (1,261)(1,188)(2,289)
2007 (8,883)(884)(813)(392)(1,197)(458)(1,069)(1,783)(2,289)
2008 (8,560)(431)(1,334)247 (1,700)182 (858)(2,377)(2,289)
2009 (11,108)(1,494)(1,508)442 (1,586)(585)(1,118)(2,971)(2,289)
2010 (24,136)(3,510)(4,114)(1,504)(4,335)(1,545)(3,868)(2,971)(2,289)
2011 (51,228)(6,290)(11,137)(5,838)(1,671)(11,296)(9,736)(2,971)(2,289)
2012 (29,817)(20,705)(3,047)1,243 (2,077)750 (721)(2,971)(2,289)
2013 9,899 3,450 5,239 2,777 (2,967)3,096 3,563 (2,971)(2,289)
2014 (36,308)(13,968)(5,455)(467)(4,609)(1,882)(4,666)(2,971)(2,289)
2015 (75,899)(15,173)(8,695)(13,630)(17,915)(980)(14,247)(2,971)(2,289)
2016 (76,171)(15,336)(19,446)(5,865)(11,384)(9,704)(9,176)(2,971)(2,289)
2017 (1,581)1,878 (2,641)1,635 5,230 7,556 (9,979)(2,971)(2,289)
2018 (1,738)(5,544)2,055 (735)(2,247)9,061 932 (2,971)(2,289)
2019 (40,868)(6,575)(8,974)397 (10,151)(1,249)(9,056)(2,971)(2,289)
2020 (49,254)(6,300)(10,568)(2,832)(12,861)(4,212)(7,222)(2,971)(2,289)
2021 (35,556)(7,092)(8,894)(804)(6,244)(1,424)(5,838)(2,971)(2,289)
2022 (26,916)(5,069)(4,578)581 (4,545)(2,313)(5,733)(2,971)(2,289)
2023 (30,215)(4,924)(5,975)(486)(6,572)(1,212)(5,787)(2,971)(2,289)
2024 (46,945)(8,446)(9,373)(3,923)(6,315)(4,644)(8,984)(2,971)(2,289)
2025 (34,694)(6,714)(7,406)(108)(7,697)(1,962)(5,547)(2,971)(2,289)
2026 (34,757)(6,707)(7,452)(350)(6,846)(2,231)(5,910)(2,971)(2,289)
2027 (39,510)(8,146)(7,954)(1,667)(7,042)(2,378)(7,064)(2,971)(2,289)
2028 (38,671)(7,725)(7,407)(1,016)(7,922)(2,248)(7,093)(2,971)(2,289)
2029 (40,561)(7,912)(7,952)(1,407)(8,046)(2,207)(7,777)(2,971)(2,289)
2030 (41,498)(8,291)(8,589)(1,065)(8,445)(2,689)(7,160)(2,971)(2,289)
2031 (45,708)(9,490)(9,180)(1,360)(9,232)(2,643)(8,543)(2,971)(2,289)
2032 (50,726)(10,494)(10,430)(1,332)(10,273)(3,634)(9,302)(2,971)(2,289)
2033 (52,232)(11,067)(10,446)(1,823)(10,719)(3,376)(9,541)(2,971)(2,289)
* The energy benefit or alternative costs associated with the demand response programs were calculated in a static analysis outside of the Aurora Analysis Model.
Energy Benefit
Aurora Analysis Model Output
(in thousands of 2004 dollars)
All Programs
Irrigation
Efficiency
Industrial
Efficiency
Commercial
Efficiency (New
Construction)
Commercial
Efficiency
(Existing)
Residential
Efficiency (New
Construction)
Residential
Efficiency
(Existing)
Air Conditioning
Demand
Response
Irrigation
Demand
Response
Present Value Costs $147,119 $24,053 $24,413 $5,027 $32,791 $7,615 $37,657 $21,133 $5,485
2004
2005 15,617 3,237 3,286 408 2,997 846 2,149 1,809 887
2006 20,143 3,237 3,286 604 5,049 1,045 4,660 1,934 329
2007 20,974 3,237 3,286 637 5,201 1,020 5,105 2,133 357
2008 21,447 3,237 3,286 669 5,164 1,015 5,420 2,327 329
2009 21,707 3,237 3,286 700 4,993 1,016 5,627 2,519 329
2010 20,285 3,237 3,286 729 4,734 1,065 5,746 1,160 329
2011 20,050 3,237 3,286 755 4,427 1,068 5,795 1,153 329
2012 19,739 3,237 3,286 779 4,099 1,074 5,789 1,146 329
2013 19,384 3,237 3,286 801 3,770 1,079 5,743 1,140 329
2014 19,039 3,237 3,286 820 3,453 1,084 5,666 1,134 359
2015 1,463 1,134 329
2016 1,463 1,134 329
2017 1,463 1,134 329
2018 1,463 1,134 329
2019 1,463 1,134 329
2020 1,463 1,134 329
2021 1,463 1,134 329
2022 1,463 1,134 329
2023 1,463 1,134 329
2024 1,493 1,134 359
2025 1,463 1,134 329
2026 1,463 1,134 329
2027 1,463 1,134 329
2028 1,463 1,134 329
2029 1,463 1,134 329
2030 1,463 1,134 329
2031 1,463 1,134 329
2032 1,463 1,134 329
2033 1,463 1,134 329
Total Resource Costs
(in thousands of 2004 dollars)
All Programs
Irrigation
Efficiency
Industrial
Efficiency
Commercial
Efficiency (New
Construction)
Commercial
Efficiency
(Existing)
Residential
Efficiency (New
Construction)
Residential
Efficiency
(Existing)
Air Conditioning
Demand
Response
Irrigation
Demand
Response
Present Value Costs $116,244 $19,572 $16,453 $4,061 $18,973 $5,065 $24,657 $30,972 $18,609
2004
2005 11,559 2,457 2,066 300 1,389 460 1,175 1,965 1,747
2006 14,649 2,457 2,066 484 2,711 663 2,861 2,239 1,168
2007 15,340 2,457 2,066 500 2,793 650 3,121 2,578 1,175
2008 15,813 2,457 2,066 517 2,783 647 3,309 2,906 1,127
2009 16,260 2,457 2,066 533 2,708 648 3,438 3,225 1,186
2010 14,851 2,457 2,066 547 2,588 663 3,518 1,849 1,165
2011 14,717 2,457 2,066 560 2,442 665 3,559 1,825 1,144
2012 14,539 2,457 2,066 571 2,283 668 3,569 1,802 1,124
2013 14,336 2,457 2,066 582 2,122 670 3,555 1,779 1,104
2014 14,226 2,457 2,066 591 1,966 673 3,524 1,757 1,192
2015 2,883 1,742 1,141
2016 2,848 1,727 1,121
2017 2,814 1,712 1,101
2018 2,780 1,698 1,082
2019 2,822 1,684 1,138
2020 2,788 1,671 1,117
2021 2,755 1,658 1,098
2022 2,724 1,645 1,079
2023 2,693 1,632 1,061
2024 2,764 1,620 1,144
2025 2,703 1,608 1,095
2026 2,672 1,596 1,076
2027 2,642 1,585 1,057
2028 2,613 1,574 1,040
2029 2,655 1,563 1,092
2030 2,625 1,552 1,073
2031 2,597 1,542 1,054
2032 2,569 1,532 1,037
2033 2,541 1,522 1,019
Utility Costs
(in thousands of 2004 dollars)
Residential Commercial Irrigation Industrial Residential Commercial Irrigation Industrial
Present Value Costs $57,846 $37,818 $27,042 $24,413 $44,229 $21,487 $35,616 $15,348
2004
2005 4,803 3,405 4,124 3,286 3,600 1,689 4,204 2,066
2006 7,639 5,653 3,566 3,286 5,763 3,195 3,625 2,066
2007 8,258 5,837 3,594 3,286 6,349 3,293 3,632 2,066
2008 8,763 5,833 3,566 3,286 6,863 3,300 3,584 2,066
2009 9,162 5,693 3,566 3,286 7,311 3,240 3,643 2,066
2010 7,971 5,463 3,566 3,286 6,029 3,135 3,622 2,066
2011 8,016 5,182 3,566 3,286 6,049 3,002 3,601 2,066
2012 8,009 4,878 3,566 3,286 6,038 2,855 3,581 2,066
2013 7,962 4,571 3,566 3,286 6,005 2,704 3,561 2,066
2014 7,883 4,274 3,596 3,286 5,955 2,557 3,649 2,066
2015 1,134 329 1,742 1,141
2016 1,134 329 1,727 1,121
2017 1,134 329 1,712 1,101
2018 1,134 329 1,698 1,082
2019 1,134 329 1,684 1,138
2020 1,134 329 1,671 1,117
2021 1,134 329 1,658 1,098
2022 1,134 329 1,645 1,079
2023 1,134 329 1,632 1,061
2024 1,134 359 1,620 1,144
2025 1,134 329 1,608 1,095
2026 1,134 329 1,596 1,076
2027 1,134 329 1,585 1,057
2028 1,134 329 1,574 1,040
2029 1,134 329 1,563 1,092
2030 1,134 329 1,552 1,073
2031 1,134 329 1,542 1,054
2032 1,134 329 1,532 1,037
2033 1,134 329 1,522 1,019
Costs by Customer Class
(in thousands of 2004 dollars)
Total Resource Costs Utility Costs
Idaho Power DSM Options for the 2004 IRP
Payback (e)
Energy Options
Program Life
(Years)MWa
Peak
MW
Annual
Energy
MWh Utility Cost (b)
Total
Resource
Cost (c)
UC
($/kWh)
TRC
($/kWh)
UC ($/Peak
kW/Mo)
TRC ($/Peak
kW/Mo)
Participant
Payback
(Years)
Irrigation Efficiency 10 6.58 28.83 57,668 18,257,173$ 24,053,100$ 0.039$ 0.051$ 6.4$ 8.5$ 3.0
Industrial Efficiency 10 10.76 12.03 94,265 15,348,063 24,413,488 0.020 0.032 12.9 20.6 3.8
Commercial Efficiency (New Construction)10 1.10 3.79 9,605 3,788,341 5,026,655 0.051 0.068 10.8 14.4 6.8
Commercial Efficiency (Existing)10 10.09 16.03 88,395 17,698,776 32,791,197 0.024 0.044 10.9 20.2 7.8
Residential Efficiency (New Construction)10 1.90 9.27 16,612 4,724,687 7,614,899 0.036 0.058 5.3 8.5 6.5
Residential Efficiency (Existing)10 9.83 20.20 86,144 23,000,777 37,656,976 0.034 0.055 12.1 19.8 6.4
Energy Option Total 40.26 90.15 352,689 82,817,817$ 131,556,316$
Load Control Options
A/C Cycling 30 45.20 29,620,080$ 21,665,664$ N/A N/A 5.5 4.0 N/A
Irrigation Peak Clipping 30 30.37 17,796,609 5,622,967 N/A N/A 4.2 1.3 N/A
Load Control Option Total 75.57 47,416,690$ 27,288,631$
Grand Total 40.26 165.72 352,689 130,234,507$ 158,844,947$
Notes:
(a) All savings numbers reflect the resource size of the fully installed program.
(b) UC = Utility Cost - "UC" represents the total cost to the utility. (includes utility costs and incentive payments made to participants)
(d) Levelized costs are stated in 30-year nominal numbers.
(e) Payback = [(participant cost - incentives) / (rates x annual energy savings)]
Savings (a)Present Value Costs Levelized Costs (d)
(c) TRC = Total Resource Cost - "TRC" represents the total cost to the utility and the rate payers as a whole. (includes utility costs and participant costs) "Participant costs"
represent the incremental capital costs associated with the measures installed by the DSM programs before incentive payments.
2004 Integrated Resource Plan
Technical Appendix

SSuurrpplluuss//DDeeffiicciitt AAnnaallyyssiiss
RReessuullttss//DDaattaa

Monthly Energy Analysis
• 50th Percentile Water, 50th Percentile Load
• 70th Percentile Water, 70th Percentile Load
• 90th Percentile Water, 70th Percentile Load

Monthly Peak-hour Analysis
• 50th Percentile Water, 50th Percentile Load
• 70th Percentile Water, 70th Percentile Load
• 90th Percentile Water, 70th Percentile Load

Monthly Peak-hour Transmission Deficit Analysis
• 50th Percentile Water, 50th Percentile Load
• 70th Percentile Water, 70th Percentile Load
• 90th Percentile Water, 70th Percentile Load

Monthly Monthly Average Energy Resource Balances Data
Years 2004-2013
(2004 IRP Data)
50% Water, 50% Load
YEAR MONTH
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2004 431 804 582 901 401 269 0 0 394 310 134 65
2005 398 771 607 833 341 189 0 0 323 276 97 25
2006 358 733 572 888 332 185 0 0 232 238 58 0
2007 314 691 534 863 326 109 0 0 176 200 19 0
2008 321 703 431 917 360 82 0 0 145 175 0 0
2009 278 660 483 815 271 60 0 0 102 138 0 0
2010 237 620 309 696 389 22 -71 0 61 101 0 0
2011 197 582 274 663 354 0 -123 -31 20 66 0 0
2012 158 548 240 632 319 0 -175 -82 0 31 0 0
2013 119 508 205 600 284 0 -228 -133 0 0 0 -37
70% Water, 70% Load
YEAR MONTH
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2004 252 569 449 516 104 30 -7 0 98 256 50 0
2005 219 536 474 448 44 0 0 0 57 221 13 0
2006 178 497 438 502 35 0 0 0 16 183 0 0
2007 134 456 400 477 28 0 -5 0 0 145 0 0
2008 140 457 286 504 32 0 -27 0 0 110 0 0
2009 97 413 338 402 0 0 -82 0 -25 72 0 -6
2010 55 373 163 282 60 0 -181 -62 -67 36 0 -46
2011 14 335 128 250 24 -31 -234 -114 -108 0 0 -86
2012 0 269 94 218 0 -75 -286 -165 -148 0 -31 -124
2013 0 187 59 185 0 -120 -340 -217 -189 0 -67 -163
90% Water, 70% Load
YEAR MONTH
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2004 22 281 219 167 -10 -184 -182 -80 -43 136 35 -55
2005 0 235 244 99 -70 -110 -76 0 0 101 0 0
2006 0 140 208 153 -79 -115 -126 0 0 63 0 0
2007 0 45 170 128 -86 -192 -180 -45 -34 25 0 -19
2008 0 0 37 131 -88 -228 -216 -84 -76 0 -36 -62
2009 0 0 12 29 -177 -251 -271 -138 -119 0 -75 -104
2010 0 -104 -74 -52 -60 -290 -370 -235 -161 -86 -113 -144
2011 -11 -93 -159 -110 -96 -334 -423 -287 -202 -122 -150 -184
2012 -50 -128 -193 -144 -131 -378 -475 -338 -242 -157 -185 -222
2013 -90 -168 -228 -175 -166 -423 -529 -390 -283 -192 -221 -261
2004 Integrated Resource Plan Page 1 of 13 Idaho Power Company
Monthly Peak-Hour Load Resource Balance Data
Years 2004-2013
50% Water, 50% Load
(2004 IRP Data)
(MW)
2004 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def. 311 279 338 719 10 (299) (314) (251) (24)126 (82) (45)
Bennett Mountain
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 404 371 428 719 98 (212) (228) (164)64 215 9 47
2005 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def. 265 213 296 699 (56) (392) (407) (288) (84)94 (108) (127)
Bennett Mountain 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 358 305 386 699 32 (137) (156) (33)173 357 160 143
2006 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def. 210 167 237 481 (119) (457) (490) (369) (160)76 (150) (162)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 483 438 503 481 141 (202) (239) (114)97 339 118 108
2007 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def. 163 137 193 622 (186) (543) (584) (454) (223)43 (193) (229)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 436 408 459 622 74 (288) (333) (199)34 306 75 41
2008 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def. 162 154 168 634 (349) (618) (643) (504) (265)28 (244) (279)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 435 425 434 634 (89) (363) (392) (249) (8)291 24 (9)
2004 Integrated Resource Plan Page 2 of 13 Idaho Power Company
Monthly Peak-Hour Load Resource Balance Data
Years 2004-2013
50% Water, 50% Load
(2004 IRP Data)
2009 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def. 111 113 115 429 (283) (700) (735) (591) (334)1 (307) (337)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 384 384 381 429 (23) (445) (484) (336) (77)264 (39) (67)
2010 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def. 63 79 67 557 (350) (866) (905) (751) (391) (19) (347) (396)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 336 350 333 557 (90) (611) (654) (496) (134)244 (79) (126)
2011 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def. 14 47 16 519 (416) (951) (995) (833) (444) (37) (393) (455)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 287 318 282 519 (156) (696) (744) (578) (187)226 (125) (185)
2012 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(34)19 (32)317 (481) (1035) (1085) (908) (497) (59) (416) (516)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 239 290 234 317 (221) (780) (834) (653) (240)204 (148) (246)
2013 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(81) (14) (81)280 (678) (1119) (1177) (988) (551) (81) (486) (578)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 192 257 185 280 (418) (864) (926) (733) (294)182 (218) (308)
2004 Integrated Resource Plan Page 3 of 13 Idaho Power Company
Monthly Peak-Hour Load Resource Balance Data
Years 2004-2013
70% Water, 70% Load
(2004 IRP Data)
(MW)
2004 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def. 156 213 292 696 (71) (367) (360) (341) (110)155 (161) (178)
Bennett Mountain
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 249 305 382 696 17 (280) (274) (254) (22)244 (70) (86)
2005 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def. 110 146 249 668 (125) (468) (449) (367) (147)124 (184) (266)
Bennett Mountain 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 203 238 339 668 (37) (213) (198) (113)111 388 84 4
2006 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def. 57 100 190 459 (201) (529) (535) (439) (215)105 (225) (306)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 330 370 457 459 59 (274) (284) (185)43 369 43 (36)
2007 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def. 8 71 146 600 (273) (618) (627) (520) (273)73 (269) (371)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 281 341 413 600 (13) (363) (376) (266) (15)337 (1) (101)
2008 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def. 7 77 111 586 (484) (699) (689) (573) (318)47 (342) (433)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 280 347 378 586 (224) (444) (438) (319) (60)311 (74) (163)
2004 Integrated Resource Plan Page 4 of 13 Idaho Power Company
Monthly Peak-Hour Load Resource Balance Data
Years 2004-2013
70% Water, 70% Load
(2004 IRP Data)
2009 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(44)36 58 380 (422) (777) (780) (663) (395)20 (407) (490)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 229 306 325 380 (162) (522) (529) (409) (137)284 (139) (220)
2010 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(92)2 8 509 (479) (945) (952) (824) (450)0 (445) (548)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 181 272 275 509 (219) (690) (701) (570) (192)264 (177) (278)
2011 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(141) (30) (43)471 (538) (1033) (1043) (907) (504) (18) (492) (607)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 132 240 224 471 (278) (778) (792) (653) (246)246 (224) (337)
2012 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(180) (58) (90)268 (612) (1121) (1134) (984) (554) (41) (513) (670)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 93 212 177 268 (352) (866) (883) (730) (296)223 (245) (400)
2013 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(215) (91) (137)232 (814) (1208) (1227) (1065) (608) (62) (584) (733)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 58 179 130 232 (554) (953) (976) (811) (350)202 (316) (463)
2004 Integrated Resource Plan Page 5 of 13 Idaho Power Company
Monthly Peak-Hour Load Resource Balance Data
Years 2004-2013
90% Water, 70% Load
(2004 IRP Data)
(MW)
2004 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(29)145 209 353 (203) (570) (470) (448) (341)128 (136) (266)
Bennett Mountain
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 64 237 299 353 (115) (483) (384) (361) (253)217 (45) (174)
2005 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(67)73 170 318 (236) (699) (567) (469) (360)102 (160) (357)
Bennett Mountain 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 26 165 260 318 (148) (444) (316) (214) (102)365 108 (87)
2006 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(90)11 106 121 (327) (744) (650) (547) (438)74 (200) (401)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 183 281 373 121 (68) (489) (399) (292) (180)337 68 (131)
2007 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(123) (53)65 251 (404) (840) (746) (630) (497)36 (245) (467)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 150 217 332 251 (145) (585) (495) (375) (239)299 23 (197)
2008 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(161) (101)11 215 (644) (938) (827) (691) (544)3 (318) (534)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 112 169 278 215 (385) (683) (576) (436) (286)266 (50) (264)
2004 Integrated Resource Plan Page 6 of 13 Idaho Power Company
Monthly Peak-Hour Load Resource Balance Data
Years 2004-2013
90% Water, 70% Load
(2004 IRP Data)
2009 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(223) (144) (159)15 (588) (1007) (915) (793) (643) (40) (383) (591)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency 50 126 108 15 (329) (752) (664) (538) (385)223 (115) (321)
2010 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(283) (238) (172)102 (632) (1177) (1089) (954) (695) (66) (422) (648)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency (10)32 95 102 (373) (922) (838) (699) (437)197 (154) (378)
2011 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(341) (320) (222)70 (680) (1271) (1183) (1038) (743) (99) (467) (709)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency (68) (50)45 70 (421) (1016) (932) (783) (485)164 (199) (439)
2012 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(389) (347) (267) (129) (759) (1369) (1277) (1112) (789) (132) (488) (771)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency (116) (77) (0) (129) (500) (1114) (1026) (857) (531)131 (220) (501)
2013 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.(436) (378) (314) (163) (969) (1464) (1375) (1192) (837) (163) (560) (834)
Bennett Mountain 180 178 176 0 172 168 165 168 170 175 177 178
Danskin 93 92 90 0 88 87 86 87 88 89 91 92
Surplus/Deficiency (163) (108) (47) (163) (710) (1209) (1124) (937) (579)100 (292) (564)
2004 Integrated Resource Plan Page 7 of 13 Idaho Power Company
Monthly Peak-Hour Northwest Transmission* Deficit Data
Years 2004-2013
50% Water, 50% Load
(2004 IRP Data)
(MW)
2004 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 0 (56)0 0 0 0 0
Bennett Mountain
Danskin 0 0 0 0 0 0 86 0 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 0 0 0 0 0 0 0
2005 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (68) (144)0 0 0 0 0
Bennett Mountain 0 165 0 0 0 0 0
Danskin 0 0 0 0 0 87 0 0 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 0 0 0 0 0 0 0
2006 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (152) (238)0 0 0 0 0
Bennett Mountain 0 0 0 0 0 168 165 0 0 0 0 0
Danskin 0 0 0 0 0 0 86 0 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 0 0 0 0 0 0 0
2007 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (241) (332) (114)0 0 0 0
Bennett Mountain 0 0 0 0 0 168 165 168 0 0 0 0
Danskin 0 0 0 0 0 87 86 0 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 0 (80)0 0 0 0 0
2008 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (319) (394) (286)0 0 0 0
Bennett Mountain 0 0 0 0 0 168 165 168 0 0 0 0
Danskin 0 0 0 0 0 87 86 87 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 (64) (143) (31)0 0 0 0
* Greater of the Brownlee-
East or Northwest to Idaho
constraints.
2004 Integrated Resource Plan Page 8 of 13 Idaho Power Company
Monthly Peak-Hour Northwest Transmission* Deficit Data
Years 2004-2013
50% Water, 50% Load
(2004 IRP Data)
* Greater of the Brownlee-
East or Northwest to Idaho
constraints.
2009 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (394) (487) (245)0 0 0 0
Bennett Mountain 0 0 0 0 0 168 165 168 0 0 0 0
Danskin 0 0 0 0 0 87 86 87 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 (139) (236)0 0 0 0 0
2010 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (562) (660) (407) (17)0 0 0
Bennett Mountain 0 0 0 0 0 168 165 168 0 0 0 0
Danskin 0 0 0 0 0 87 86 87 88 0 0 0
Surplus/Deficiency 0 0 0 0 0 (307) (408) (153)0 0 0 0
2011 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (658) (753) (481) (73)0 0 0
Bennett Mountain 0 0 0 0 0 168 165 168 0 0 0 0
Danskin 0 0 0 0 0 87 86 87 88 0 0 0
Surplus/Deficiency 0 0 0 0 0 (403) (502) (226)0 0 0 0
2012 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (744) (845) (615) (122)0 0 (19)
Bennett Mountain 0 0 0 0 0 168 165 168 170 0 0 0
Danskin 0 0 0 0 0 87 86 87 0 0 0 92
Surplus/Deficiency 0 0 0 0 0 (489) (594) (360)0 0 0 0
2013 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 (129) (826) (939) (648) (200)0 0 (81)
Bennett Mountain 0 0 0 0 172 168 165 168 170 0 0 0
Danskin 0 0 0 0 0 87 86 87 88 0 0 92
Surplus/Deficiency 0 0 0 0 0 (571) (688) (394)0 0 0 0
2004 Integrated Resource Plan Page 9 of 13 Idaho Power Company
Monthly Peak-Hour Northwest Transmission* Deficit Data
Years 2004-2013
70% Water, 70% Load
(2004 IRP Data)
(MW)
2004 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 0 (60)0 0 0 0 0
Bennett Mountain
Danskin 0 0 0 0 0 0 86 0 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 0 0 0 0 0 0 0
2005 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (55) (131) (38)0 0 0 0
Bennett Mountain 0 165 0 0 0 0 0
Danskin 0 0 0 0 0 87 0 87 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 0 0 0 0 0 0 0
2006 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (106) (234) (95)0 0 0 0
Bennett Mountain 0 0 0 0 0 168 165 168 0 0 0 0
Danskin 0 0 0 0 0 0 86 0 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 0 0 0 0 0 0 0
2007 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (223) (326) (212)0 0 0 0
Bennett Mountain 0 0 0 0 0 168 165 168 0 0 0 0
Danskin 0 0 0 0 0 87 86 87 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 0 (75)0 0 0 0 0
2008 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (319) (374) (360)0 0 0 0
Bennett Mountain 0 0 0 0 0 168 165 168 0 0 0 0
Danskin 0 0 0 0 0 87 86 87 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 (64) (123) (105)0 0 0 0
* Greater of the Brownlee-
East or Northwest to Idaho
constraints.
2004 Integrated Resource Plan Page 10 of 13 Idaho Power Company
Monthly Peak-Hour Northwest Transmission* Deficit Data
Years 2004-2013
70% Water, 70% Load
(2004 IRP Data)
* Greater of the Brownlee-
East or Northwest to Idaho
constraints.
2009 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (382) (495) (329)0 0 0 0
Bennett Mountain 0 0 0 0 0 168 165 168 0 0 0 0
Danskin 0 0 0 0 0 87 86 87 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 (128) (244) (75)0 0 0 0
2010 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (548) (666) (497) (53)0 0 (35)
Bennett Mountain 0 0 0 0 0 168 165 168 0 0 0 0
Danskin 0 0 0 0 0 87 86 87 88 0 0 92
Surplus/Deficiency 0 0 0 0 0 (293) (415) (242)0 0 0 0
2011 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 (48) (610) (752) (583) (112)0 0 (95)
Bennett Mountain 0 0 0 0 0 168 165 168 170 0 0 178
Danskin 0 0 0 0 88 87 86 87 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 (355) (501) (329)0 0 0 0
2012 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 (105) (729) (843) (724) (169)0 0 (153)
Bennett Mountain 0 0 0 0 172 168 165 168 170 0 0 178
Danskin 0 0 0 0 0 87 86 87 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 (474) (592) (469)0 0 0 0
2013 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 (308) (823) (924) (751) (260)0 0 (212)
Bennett Mountain 0 0 0 0 172 168 165 168 170 0 0 178
Danskin 0 0 0 0 88 87 86 87 88 0 0 92
Surplus/Deficiency 0 0 0 0 (48) (568) (673) (496) (2)0 0 0
2004 Integrated Resource Plan Page 11 of 13 Idaho Power Company
Monthly Peak-Hour Northwest Transmission* Deficit Data
Years 2004-2013
90% Water, 70% Load
(2004 IRP Data)
(MW)
2004 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (60) (140) (73)0 0 0 0
Bennett Mountain
Danskin 0 0 0 0 0 87 86 87 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 0 (54)0 0 0 0 0
2005 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (157) (254) (135)0 0 0 0
Bennett Mountain 168 165 168 0 0 0 0
Danskin 0 0 0 0 0 0 86 0 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 0 (3)0 0 0 0 0
2006 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (224) (323) (178)0 0 0 0
Bennett Mountain 0 0 0 0 0 168 165 168 0 0 0 0
Danskin 0 0 0 0 0 87 86 87 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 0 (71)0 0 0 0 0
2007 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (315) (414) (313) (61)0 0 0
Bennett Mountain 0 0 0 0 0 168 165 168 0 0 0 0
Danskin 0 0 0 0 0 87 86 87 88 0 0 0
Surplus/Deficiency 0 0 0 0 0 (60) (163) (58)0 0 0 0
2008 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 (11) (403) (492) (503) (117)0 0 0
Bennett Mountain 0 0 0 0 0 168 165 168 170 0 0 0
Danskin 0 0 0 0 88 87 86 87 0 0 0 0
Surplus/Deficiency 0 0 0 0 0 (148) (240) (249)0 0 0 0
* Greater of the Brownlee-
East or Northwest to Idaho
constraints.
2004 Integrated Resource Plan Page 12 of 13 Idaho Power Company
Monthly Peak-Hour Northwest Transmission* Deficit Data
Years 2004-2013
90% Water, 70% Load
(2004 IRP Data)
* Greater of the Brownlee-
East or Northwest to Idaho
constraints.
2009 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 0 (484) (587) (428) (183)0 0 (6)
Bennett Mountain 0 0 0 0 0 168 165 168 170 0 0 0
Danskin 0 0 0 0 0 87 86 87 88 0 0 92
Surplus/Deficiency 0 0 0 0 0 (229) (335) (173)0 0 0 0
2010 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 (13) (654) (761) (594) (242)0 0 (66)
Bennett Mountain 0 0 0 0 0 168 165 168 170 0 0 0
Danskin 0 0 0 0 88 87 86 87 88 0 0 92
Surplus/Deficiency 0 0 0 0 0 (399) (509) (339)0 0 0 0
2011 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 (80) (741) (853) (679) (300)0 0 (125)
Bennett Mountain 0 0 0 0 0 168 165 168 170 0 0 0
Danskin 0 0 0 0 88 87 86 87 88 0 0 92
Surplus/Deficiency 0 0 0 0 0 (486) (602) (425) (43)0 0 (33)
2012 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 (150) (830) (945) (842) (358)0 0 (183)
Bennett Mountain 0 0 0 0 172 168 165 168 170 0 0 178
Danskin 0 0 0 0 0 87 86 87 88 0 0 92
Surplus/Deficiency 0 0 0 0 0 (575) (694) (588) (101)0 0 0
2013 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Hour Sup./Def.0 0 0 0 (353) (937) (1037) (848) (497)0 0 (241)
Bennett Mountain 0 0 0 0 172 168 165 168 170 0 0 178
Danskin 0 0 0 0 88 87 86 87 88 0 0 92
Surplus/Deficiency 0 0 0 0 (93) (682) (786) (593) (240)0 0 0
2004 Integrated Resource Plan Page 13 of 13 Idaho Power Company
2004 Integrated Resource Plan
Technical Appendix

RReessoouurrccee PPoorrttffoolliiooss

2004 IRP Technical Appendix Page 1 of 6
Portfolio Summary & Description
Portfolio Summary and Description

Portfolio 0 is designed to provide a diversity of supply-side resources. The
renewable resources are included to add price stability to the Portfolio, the coal plant is
included because of its low operating costs, and the combustion turbines are included to
meet the peak requirements with a low capital cost
Portfolio 1 consists of 810 MW of natural gas fired combustion turbines.
Portfolio 1 has the lowest capital cost of all the portfolios and the resource additions can
be closely timed to coincide with the increases in Idaho Power Company requirements.
Portfolio 1 has considerable exposure to natural gas price volatility.

Portfolio 2 emphasizes coal resources to meet the Idaho Power Company
requirements. Coal-fired generation is low cost under present market conditions and
Portfolio 2 minimizes the use of natural gas for base-load generation. Portfolio 2 has the
largest quantity of CO2 emissions of the eight Portfolios analyzed.

Portfolio 2 – Coal
Acquisition Schedule Description (total MW) Resource Type
2006, 2008 250 MW Combustion Turbines Thermal
2009 500 MW Coal Thermal
Additional Capacity (2013) 750 MW
Portfolio Power Supply Costs $8,182 M
Capital Cost $857 M
Carbon Tax (CO2) Ranking 7

Portfolio 0 -- Balanced Resources
Acquisition Schedule Description (total MW) Resource Type
2006 200 MW Wind (10 MW Capacity) Renewable
2007, 2011 324 MW Combustion Turbines Thermal
2008, 2013 150 MW Geothermal Renewable
2009 250 MW Coal Thermal
Additional Capacity (2013) 734 MW
Portfolio Power Supply Costs $ 8,063 M
Capital Cost $1,212 M
Carbon Tax (CO2) Ranking 6

Portfolio 1 – Peaking Resources
Acquisition Schedule Description (total MW) Resource Type
2006, 2008, 2010, 2011, 2013 810 MW Combustion Turbines Thermal
Additional Capacity (2013) 810 MW
Portfolio Power Supply Costs $8,443 M
Capital Cost $421 M
Carbon Tax (CO2) Ranking 2

2004 IRP Technical Appendix Page 2 of 6
Portfolio Summary & Description

Portfolio 3 emphasizes wind generation to meet Idaho Power Company projected
resource needs. Portfolio 3 costs nearly $1.8 billion to construct and has the greatest
capital cost of all the Portfolios analyzed. Portfolio 3 has the minimum CO2 emissions
and a very low operating cost. However, the 648 MW of combustion turbines means that
Portfolio 3 has significant exposure to natural gas price volatility. Lowering the natural
gas price exposure by changing to combined-cycle natural gas turbines would further
increase the capital cost of Portfolio 3.

Portfolio 4 is a balanced approach containing both supply-side and demand-side
resources. Portfolio 4 upgrades the Danskin Plant to a combined-cycle combustion
turbine. In addition, Portfolio 4 includes 12 MW of combined heat and power. Portfolio
is balanced yet the 481 MW of combustion turbines means that the portfolio still has
significant exposure to natural gas price volatility.

Portfolio 3 – Wind + Natural Gas Backup Generation
Acquisition Schedule Description (total MW) Resource Type
2006, 2007, 2008, 2009, 2010 1000 MW Wind (50 MW Capacity) Renewable
2009 50 MW Geothermal Renewable
2007, 2008, 2011, 2012 648 MW Combustion Turbines Thermal
Additional Capacity (2013) 748 MW
Production Cost (30-year) $7,374 M
Capital Cost $1,690 M
Carbon Tax (CO2) Ranking 1 – Lowest Present Value of CO2 emission adders

Portfolio 4 – Balanced Resources
Acquisition Schedule Description (total MW) Resource Type
All years 48 MW DSM Demand-Side
2006 100 MW Wind (5 MW Capacity) Renewable
2007 69 MW Combined Cycle CT Thermal
2007 12 MW Combined Heat & Power Thermal
2008 50 MW Geothermal Renewable
2011 130 MW Coal Thermal
2007, 2009, 2011 412 MW Combustion Turbines Thermal
Additional Capacity (2013) 722 MW
Portfolio Power Supply Costs $8,095 M
Capital Cost $810
Carbon Tax (CO2) Ranking 4

2004 IRP Technical Appendix Page 3 of 6
Portfolio Summary & Description
Portfolio 5 initiates construction of a coal-fired generation plant early. Like
Portfolio 2, there is a heavy reliance on coal and Portfolio 5 has significant CO2
emissions. Portfolio 5 also has significant capital costs. There are concerns that the 2007
date sets an unrealistic timetable to complete 500 MW of coal-fired generation.

Portfolio 6 adds demand-response programs to reduce the Idaho Power summer
peak demand as well as adds seasonal operation of a coal-fired generation facility.
Seasonal ownership is an interesting concept whereby Idaho Power Company would
partner with another utility in the region to own the plant. The most likely utility partner
would be a winter-peaking utility and Idaho Power Company would take the plant output
during the summer months and the partner utility would take the plant output during the
winter months. Seasonal ownership has the advantage of lowering the capital costs and
the CO2 emissions while still providing plant output during the times of need. The key
will be to locate a suitable utility partner.

Portfolio 5 – Early Coal
Acquisition Schedule Description (total MW) Resource Type
2006 44 MW Combustion Turbine Thermal
2007, 2012 750 MW Coal Thermal
Additional Capacity (2013) 794 MW
Portfolio Power Supply Costs $8,064 M
Capital Cost $904 M
Carbon Tax (CO2) Ranking 11

Portfolio 6 – Balanced Resources
Acquisition Schedule Description (total MW) Resource Type
All years 48 MW DSM Demand-Side
All years 76 MW Demand Response Demand-Side
2006, 2007 200 MW Wind (10 MW Capacity) Renewable
2007 12 MW Combined Heat & Power Thermal
2007 88 MW Combustion Turbines Thermal
2008 50 MW Geothermal Renewable
2010 500 MW Coal (seasonal) Thermal
Additional Capacity (2013) 784 MW
Portfolio Power Supply Costs $7,703 M
Capital Cost $805 M
Carbon Tax (CO2) Ranking 8

2004 IRP Technical Appendix Page 4 of 6
Portfolio Summary & Description
Portfolio 7 is a balanced Portfolio that emphasizes renewable resources and
demand-side programs, and includes seasonal ownership of a coal-fired generation
facility. The key difference between Portfolio 7 and Portfolio 6 is the increase in wind
generation from 100 MW to 200 MW and the fact that the seasonal coal plant is not
added until 2012. The late addition of the seasonal coal plant gives Idaho Power
flexibility to locate a suitable utility partner and the later start date gives the utility
partners sufficient time to observe the electric market and tailor the response and
construction schedule to meet the market conditions.

Portfolio 8 is a balanced portfolio with an emphasis on coal. Coal-fired facilities
are on line in 2007 and 2009.

Portfolio 7 – Balanced Resources
Acquisition Schedule Description (total MW) Resource Type
All years 48 MW DSM Demand-Side
All years 76 MW Demand Response Demand-Side
2006, 2007 200 MW Wind (10 MW Capacity) Renewable
2007 12 MW Combined Heat & Power Thermal
2007 88 MW Combustion Turbines Thermal
2008 100 MW Geothermal Renewable
2010 250 MW Coal Thermal
2013 500 MW Coal (seasonal) Thermal
Additional Capacity (2013) 1084 MW
Portfolio Power Supply Costs $7,510 M
Capital Cost $1,352 M
Carbon Tax (CO2) Ranking 10

Portfolio 8 – Balanced Resources with Coal Emphasis
Acquisition Schedule Description (total MW) Resource Type
All years 48 MW DSM Demand-Side
All years 76 MW Demand Response Demand-Side
2006 100 MW Wind (5 MW Capacity) Renewable
2006, 2007, 2008 36 MW Combined Heat & Power Thermal
2007 20 MW Geothermal Renewable
2007 250 MW Coal Thermal
2009 500 MW Coal (seasonal) Thermal
Additional Capacity (2013) 935 MW
Portfolio Power Supply Costs $7,727 M
Capital Cost $912 M
Carbon Tax (CO2) Ranking 12 -- Highest Present Value of CO2
emission cost adders

2004 IRP Technical Appendix Page 5 of 6
Portfolio Summary & Description

Portfolio 9 – Balanced Resources
Acquisition Schedule Description (total MW) Resource Type
All years 48 MW DSM Demand-Side
All years 76 MW Demand Response Demand-Side
2006, 2007 200 MW Wind (10 MW Capacity) Renewable
2007 12 MW Combined Heat & Power Thermal
2007 88 MW Combustion Turbines Thermal
2008 100 MW Geothermal Renewable
2010 250 Coal Thermal
2013 250 MW Coal (seasonal) Thermal
Additional Capacity (2013) 853 MW
Portfolio Power Supply Costs $7,815 M
Capital Cost $1,153
Carbon Tax (CO2) Ranking 9

Portfolio 9 is identical to Portfolio 7 except that the seasonal-ownership coal-
fired generation in 2013 has been reduced to 250 MW from 500 MW.

Portfolio 10 is a balanced portfolio with the addition of combined-cycle natural
gas generation and no coal resources.

Portfolio 10 – Balanced Resources Including Combined-Cycle Combustion
Turbines
Acquisition Schedule Description (total MW) Resource Type
All years 48 MW DSM Demand-Side
All years 76 MW Demand Response Demand-Side
2006, 2007 200 MW Wind (10 MW Capacity) Renewable
2007 88 MW Simple Cycle CT Thermal
2007 12 MW Combined Heat & Power Thermal
2008 100 MW Geothermal Renewable
2010 270 MW Combined Cycle CT Thermal
2013 270 MW Combined Cycle CT
(seasonal)
Thermal
Additional Capacity (2013) 893 MW
Portfolio Power Supply Costs $7,849 M
Capital Cost $904 M
Carbon Tax (CO2) Ranking 3

2004 IRP Technical Appendix Page 6 of 6
Portfolio Summary & Description
Portfolio 11 is a modification of Portfolio 7. Portfolio 11 was modified to add
more wind generation and to remove the 250 MW coal-fired generation in 2010. A
member of the IRP Advisory Council suggested Portfolio 11 after the meeting in April.

Portfolio 11– Balanced Resources
Acquisition Schedule Description (total MW) Resource Type
All years 48 MW DSM Demand-Side
All years 76 MW Demand Response Demand-Side
2006, 2007, 2010 350 MW Wind (18 MW Capacity) Renewable
2007, 2010 48 MW Combined Heat & Power Thermal
2007 88 MW Combustion Turbines Thermal
2008 100 MW Geothermal Renewable
2010 62 MW CT / Distributed Gen Thermal
2011 500 MW Coal (seasonal) Thermal
Additional Capacity (2013) 939 MW
Portfolio Power Supply Costs $7,333 M
Capital Cost $1,238 M
Carbon Tax (CO2) Ranking 5

2004 Integrated Resource Plan
Portfolio Energy and Capacity Balance Analysis
P0 - Balanced 0
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Energy Target 86 132 182 236 258 313 412 465 517 571
Capacity Target 54 3 71 163 249 335 429 522 614 706
Energy
Peakers/ mkt purchase for energy 86 132 143 197 169 73 126 178 132
200 MW wind 06 39 39 39 39 39 39 39 39
50 MW geothermal 08 50 50 50 50 50 50
250 MW coal 09 250 250 250 250 250
50 MW geothermal 13 0 0 50
50 MW geothermal 13 0 50
Total Energy 86 132 182 236 258 339 412 465 517 571
Capacity
200 MW wind 06 10 10 10 10 10 10 10 10
162 MW peaker 07 162 162 162 162 162 162 162
50 MW geothermal 08 50 50 50 50 50 50
250 MW coal 09 250 250 250 250 250
162 MW peaker 11 0 162 162 162
50 MW geothermal 13 0 0 50
50 MW geothermal 13 0 50
Total Capacity 0 0 10 172 222 472 472 634 634 734
Notes:1. Peakers can be run to satisfy monthly energy deficit.
2. Market purchases are also available to satisfy monthly energy deficit.
3. Demand response programs are counted as capacity. Energy efficiency and conservation programs are considered to provide energy and capacity.
4. 75 MW of Red Butte - Borah/Brady transmission is available to reduce NW transmission deficit. If coupled with a firm market purchase of up to 75 MW,
the NW transmission deficit (and the capacity requirement) can be reduced by the amount of the purchase.
5. PPL Montana contract expires in 2009. This analysis assumes that some form of contract will replace it thus no reduction of capacity occurs in 2010.
6. Wind project output based on 35% CF and seasonal shaping from NW Power and Conservation Council resource characterization paper 5th PP.
7. Decreased capacity target by 80 MW starting in 2010 to account for continuation of Montana purchases.
8. Included wind capacity credit of 5 MW per 100 MW of nameplate capacity - based on July data.
9. Deleted reference to a 162 MW peaker that was shown as moved out 1 year to 2014
P0 Balanced 0 - Energy
0
100
200
300
400
500
600
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W
Energy Target Energy Resources
P0 balanced 0 - Capacity
0
200
400
600
800
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW
Capacity Target Capacity Resources
2004 IRP Portfolio Bundles Page 1 of 12 Idaho Power Company
2004 Integrated Resource Plan
Portfolio Energy and Capacity Balance Analysis
P1 - Peakers
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Energy Target 86 132 182 236 258 313 412 465 517 571
Capacity Target 54 3 71 163 249 335 429 522 614 706
Energy
Peakers/ mkt purchase for energy 86 132 182 236 258 313 412 465 517 571
Total Energy 86 132 182 236 258 313 412 465 517 571
Capacity
162 MW peaker 06 162 162 162 162 162 162 162 162
162 MW peaker 08 162 162 162 162 162 162
162 MW peaker 10 162 162 162 162
162 MW peaker 12 0 162 162
162 MW peaker 13 162
Total Capacity 0 0 162 162 324 324 486 486 648 810
-54 -3 91 -1 75 -11 57 -36 34 104
Notes:1. Peakers can be run to satisfy monthly energy deficit.
2. Market purchases are also available to satisfy monthly energy deficit.
3. Demand response programs are counted as capacity. Energy efficiency and conservation programs are considered to provide energy and capacity.
4. 75 MW of Red Butte - Borah/Brady transmission is available to reduce NW transmission deficit. If coupled with a firm market purchase of up to 75 MW,
the NW transmission deficit (and the capacity requirement) can be reduced by the amount of the purchase.
5. PPL Montana contract expires in 2009. This analysis assumes that some form of contract will replace it thus no reduction of capacity occurs in 2010.
6. Decreased capacity target by 80 MW starting in 2010 to account for continuation of Montana purchases.
P1 Peakers - Energy
0
100
200
300
400
500
600
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W
Energy Target Energy Resources
P1 Peakers - Capacity
0
200
400
600
800
1000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW
Capacity Target Capacity Resources
2004 IRP Portfolio Bundles Page 2 of 12 Idaho Power Company
2004 Integrated Resource Plan
Portfolio Energy and Capacity Balance Analysis
P2 - Coal
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Energy Target 86 132 182 236 258 313 412 465 517 571
Capacity Target 54 3 71 163 249 335 429 522 614 706
Energy
Peakers/ mkt purchase for energy 86 132 182 236 258 17 71
500 MW coal 09 500 500 500 500 500
Total Energy 86 132 182 236 258 500 500 500 517 571
Capacity
162 MW peaker 06 162 162 162 162 162 162 162 162
88 MW peaker (2*44) 08 88 88 88 88 88 88
500 MW coal 09 500 500 500 500 500
Total Capacity 0 0 162 162 250 750 750 750 750 750
Notes:1. Peakers can be run to satisfy monthly energy deficit.
2. Market purchases are also available to satisfy monthly energy deficit.
3. Demand response programs are counted as capacity. Energy efficiency and conservation programs are considered to provide energy and capacity.
4. 75 MW of Red Butte - Borah/Brady transmission is available to reduce NW transmission deficit. If coupled with a firm market purchase of up to 75 MW,
the NW transmission deficit (and the capacity requirement) can be reduced by the amount of the purchase.
5. PPL Montana contract expires in 2009. This analysis assumes that some form of contract will replace it thus no reduction of capacity occurs in 2010.
6. Decreased capacity target by 80 MW starting in 2010 to account for continuation of Montana purchases.
7. Deleted reference to a 250 MW coal plant that was shown as moved out 1 year to 2014
P2 Coal - Energy
0
100
200
300
400
500
600
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W
Energy Target Energy Resources
P2 Coal - Capacity
0
200
400
600
800
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW
Capacity Target Capacity Resources
2004 IRP Portfolio Bundles Page 3 of 12 Idaho Power Company
2004 Integrated Resource Plan
Portfolio Energy and Capacity Balance Analysis
P3 - Wind and Peakers
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Energy Target 86 132 182 236 258 313 412 465 517 571
Capacity Target 54 3 71 163 249 335 429 522 614 706
Energy
Peakers/ mkt purchase for energy 86 132 143 158 140 106 166 219 271 325
200 MW wind 06 39 39 39 39 39 39 39 39
200 MW wind 07 39 39 39 39 39 39 39
200 MW wind 08 39 39 39 39 39 39
50 MW geothermal 09 0 50 50 50 50 50
200 MW wind 09 39 39 39 39 39
200 MW wind 10 39 39 39 39
Total Energy 86 132 182 236 258 313 412 465 517 571
Capacity
162 MW peaker 07 0 162 162 162 162 162 162 162
200 MW wind 06 10 10 10 10 10 10 10 10
200 MW wind 07 10 10 10 10 10 10 10
200 MW wind 08 10 10 10 10 10 10
162 MW peaker 08 162 162 162 162 162 162
50 MW geothermal 09 0 50 50 50 50 50
200 MW wind 09 10 10 10 10 10
200 MW wind 10 10 10 10 10
162 MW peaker 11 0 162 162 162
162 MW peaker 12 0 162 162
Total Capacity 0 0 10 182 354 414 424 586 748 748
-54 -3 -61 19 105 79 -5 64 134 42
Notes:1. Peakers can be run to satisfy monthly energy deficit.
2. Market purchases are also available to satisfy monthly energy deficit.
3. Demand response programs are counted as capacity. Energy efficiency and conservation programs are considered to provide energy and capacity.
4. 75 MW of Red Butte - Borah/Brady transmission is available to reduce NW transmission deficit. If coupled with a firm market purchase of up to 75 MW,
the NW transmission deficit (and the capacity requirement) can be reduced by the amount of the purchase.
5. PPL Montana contract expires in 2009. This analysis assumes that some form of contract will replace it thus no reduction of capacity occurs in 2010.
6. Wind project output based on 35% CF and seasonal shaping from NW Power and Conservation Council resource characterization paper 5th PP.
7. Decreased capacity target by 80 MW starting in 2010 to account for continuation of Montana purchases.
8. Included wind capacity credit of 5 MW per 100 MW of nameplate capacity - based on July data.
9. Deleted reference to a 162 MW peaker that was shown as moved out 1 year to 2014
P3 Wind & Peakers - Energy
0
100
200
300
400
500
600
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W
Energy Target Energy Resources
P3 Wind & Peakers - Capacity
0
200
400
600
800
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW
Capacity Target Capacity Resources
2004 IRP Portfolio Bundles Page 4 of 12 Idaho Power Company
2004 Integrated Resource Plan
Portfolio Energy and Capacity Balance Analysis
P4 - Balanced 1
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Energy Target 86 132 182 236 258 313 412 465 517 571
Capacity Target 54 3 71 163 249 335 429 522 614 706
Energy
Peakers/ mkt purchase for energy 86 130 157 127 95 147 243 162 211 262
28 MW DSM CEE, Ind E, REE 0 2 5 9 12 16 19 22 25 28
100 MW wind 06 20 20 20 20 20 20 20 20
69 MW CC (convert Danskin) 07 69 69 69 69 69 69 69
12 MW CHP 07 12 12 12 12 12 12 12
50 MW geothermal 08 50 50 50 50 50 50
130 MW coal (Valmy 3) in 11 0 0 130 130 130
Total Energy 86 132 182 236 258 313 412 465 517 571
Capacity
44 MW DSM CEE, Ind E, REE 0 3 8 13 18 24 29 34 39 44
100 MW wind 06 5 5 5 5 5 5 5 5
88 MW peaker (2*44) 07 88 88 88 88 88 88 88
69 MW CC (convert Danskin) 07 69 69 69 69 69 69 69
12 MW CHP 07 12 12 12 12 12 12 12
50 MW geothermal 08 50 50 50 50 50 50
162 MW peaker 09 0 162 162 162 162 162
130 MW coal (Valmy 3) in 11 0 0 130 130 130
162 MW peaker 12 0 162 162
Total Capacity 0 3 13 187 242 410 415 550 717 722
Notes:1. Peakers can be run to satisfy monthly energy deficit.
2. Market purchases are also available to satisfy monthly energy deficit.
3. Demand response programs are counted as capacity. Energy efficiency and conservation programs are considered to provide energy and capacity.
4. 75 MW of Red Butte - Borah/Brady transmission is available to reduce NW transmission deficit. If coupled with a firm market purchase of up to 75 MW,
the NW transmission deficit (and the capacity requirement) can be reduced by the amount of the purchase.
5. PPL Montana contract expires in 2009. This analysis assumes that some form of contract will replace it thus no reduction of capacity occurs in 2010.
6. Wind project output based on 35% CF and seasonal shaping from NW Power and Conservation Council resource characterization paper 5th PP.
7. Decreased capacity target by 80MW starting in 2010 to account for continuation of Montana purchases.
8. Included wind capacity credit of 5 MW per 100 MW of nameplate capacity - based on July data.
9. Revised cell "C28" to show peaker in service in 2012, consistent with "L28"
P4 Balanced 1 - Energy
0
100
200
300
400
500
600
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W
Energy Target Energy Resources
P4 Balanced 1 - Capacity
0
200
400
600
800
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW
Capacity Target Capacity Resources
2004 IRP Portfolio Bundles Page 5 of 12 Idaho Power Company
2004 Integrated Resource Plan
Portfolio Energy and Capacity Balance Analysis
P5 - Early Coal
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Energy Target 86 132 182 236 258 313 412 465 517 571
Capacity Target 54 3 71 163 249 335 429 522 614 706
Energy
Peakers/ mkt purchase for energy 86 132 182
500 MW coal PF 07 500 500 500 500 500 500 500
250 MW coal 12 0 250 250
Total Energy 86 132 182 500 500 500 500 500 750 750
Capacity
44 MW peaker 06 44 44 44 44 44 44 44 44
500 MW coal PF 07 500 500 500 500 500 500 500
250 MW coal 12 0 250 250
Total Capacity 0 0 44 544 544 544 544 544 794 794
Notes:1. Peakers can be run to satisfy monthly energy deficit.
2. Market purchases are also available to satisfy monthly energy deficit.
3. Demand response programs are counted as capacity. Energy efficiency and conservation programs are considered to provide energy and capacity.
4. 75 MW of Red Butte - Borah/Brady transmission is available to reduce NW transmission deficit. If coupled with a firm market purchase of up to 75 MW,
the NW transmission deficit (and the capacity requirement) can be reduced by the amount of the purchase.
5. PPL Montana contract expires in 2009. This analysis assumes that some form of contract will replace it thus no reduction of capacity occurs in 2010.
6. Decreased capacity target by 80 MW starting in 2010 to account for continuation of Montana purchases.
7. Added notes on "C11" and 'C18"
P5 Early Coal - Energy
0
200
400
600
800
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W
Energy Target Energy Resources
P5 Early Coal - Capacity
0
200
400
600
800
1000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW
Capacity Target Capacity Resources
2004 IRP Portfolio Bundles Page 6 of 12 Idaho Power Company
2004 Integrated Resource Plan
Portfolio Energy and Capacity Balance Analysis
P6 - Balanced 2
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Energy Target 86 132 182 236 258 313 412 465 517 571
Capacity Target 54 3 71 163 249 335 429 522 614 706
Energy
Peakers/ mkt purchase for energy 86 130 159 179 149 0
18 MW DSM - Irrig E, Ind E,CEN, REN 0 2 4 6 8 10 12 14 16 18
100 MW wind 06 20 20 20 20 20 20 20 20
100 MW wind 07 20 20 20 20 20 20 20
12 MW CHP 07 12 12 12 12 12 12 12
50 MW geothermal 08 50 50 50 50 50 50
500 MW coal seasonal 09 500 500 500 500 500
Total Energy 86 132 182 236 258 611 613 615 617 619
0 0 0 0 0 298 201 150 100 48
Capacity
76 MW DSM A/C & Irrig clipping 0 39 48 57 67 76 76 76 76 76
48 MW DSM - Irrig E, Ind E,CEN, REN 0 5 10 15 21 26 32 37 43 48
100 MW wind 06 5 5 5 5 5 5 5 5
100 MW wind 07 5 5 5 5 5 5 5
12 MW CHP 07 12 12 12 12 12 12 12
88 MW peaker (2*44) 07 88 88 88 88 88 88 88
50 MW geothermal 08 50 50 50 50 50 50
500 MW coal seasonal 09 500 500 500 500 500
Total Capacity 0 44 64 183 247 762 767 773 778 784
-54 42 -8 20 -1 426 338 250 164 78
Notes:1. Peakers can be run to satisfy monthly energy deficit.
2. Market purchases are also available to satisfy monthly energy deficit.
3. Demand response programs are counted as capacity. Energy efficiency and conservation programs are considered to provide energy and capacity.
4. 75 MW of Red Butte - Borah/Brady transmission is available to reduce NW transmission deficit. If coupled with a firm market purchase of up to 75 MW,
the NW transmission deficit (and the capacity requirement) can be reduced by the amount of the purchase.
5. PPL Montana contract expires in 2009. This analysis assumes that some form of contract will replace it thus no reduction of capacity occurs in 2010.
6. Wind project output based on 35% CF and seasonal shaping from NW Power and Conservation Council resource characterization paper 5th PP.
7. Decreased capacity target by 80 MW starting in 2010 to account for continuation of Montana purchases.
8. Included wind capacity credit of 5 MW per 100 MW of nameplate capacity - based on July data.
9. Revised cells "C15" and "C27" to show coal plant on-line in 2009, consistent with "I15" and "I27"
10. Revised DSM efficiency programs based on benefit cost ratio's associated with 5_11_05 DSM analysis (programs were change sets to P0)
P6 Balanced 2 - Energy
0
100
200
300
400
500
600
700
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W
Energy Target Energy Resources
P6 Balanced 2 - Capacity
0
200
400
600
800
1000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW
Capacity Target Capacity Resources
2004 IRP Portfolio Bundles Page 7 of 12 Idaho Power Company
2004 Integrated Resource Plan
Portfolio Energy and Capacity Balance Analysis
P7 - Balanced 3
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Energy Target 86 132 182 236 258 313 412 465 517 571
Capacity Target 54 3 71 163 249 335 429 522 614 706
Energy
Peakers/ mkt purchase for energy 86 130 159 179 99 152 0 50 100
18 MW DSM - Irrig E, Ind E,CEN, RE 0 2 4 6 8 10 12 14 16 18
100 MW wind 06 20 20 20 20 20 20 20 20
100 MW wind 07 20 20 20 20 20 20 20
12 MW CHP 07 12 12 12 12 12 12 12
100 MW geothermal 08 100 100 100 100 100 100
250 MW coal 10 0 250 250 250 250
500 MW coal seasonal 13 0 500
Total Energy 86 132 182 236 258 313 413 465 517 919
0 0 0 0 0 0 1 0 0 348
Capacity
76 MW DSM A/C & Irrig clipping 0 39 48 57 67 76 76 76 76 76
48 MW DSM - Irrig E, Ind E,CEN, RE 0 5 10 15 21 26 32 37 43 48
100 MW wind 06 5 5 5 5 5 5 5 5
100 MW wind 07 5 5 5 5 5 5 5
12 MW CHP 07 12 12 12 12 12 12 12
88 MW peaker (2*44) 07 88 88 88 88 88 88 88
100 MW geothermal 08 100 100 100 100 100 100
250 MW coal 10 0 250 250 250 250
500 MW coal seasonal 13 0 500
Total Capacity 0 44 64 183 297 312 567 573 578 1084
-54 42 -8 20 49 -24 138 50 -36 378
Notes:1. Peakers can be run to satisfy monthly energy deficit.
2. Market purchases are also available to satisfy monthly energy deficit.
3. Demand response programs are counted as capacity. Energy efficiency and conservation programs are considered to provide energy and capacity.
4. 75 MW of Red Butte - Borah/Brady transmission is available to reduce NW transmission deficit. If coupled with a firm market purchase of up to 75 MW,
the NW transmission deficit (and the capacity requirement) can be reduced by the amount of the purchase.
5. PPL Montana contract expires in 2009. This analysis assumes that some form of contract will replace it thus no reduction of capacity occurs in 2010.
6. Wind project output based on 35% CF and seasonal shaping from NW Power and Conservation Council resource characterization paper 5th PP.
7. Decreased capacity target by 80 MW starting in 2010 to account for continuation of Montana purchases.
8. Included wind capacity credit of 5 MW per 100 MW of nameplate capacity - based on July data.
9. Added to the comments on cells "C15" and "C28"
10. Revised DSM efficiency programs based on benefit cost ratio's associated with 5_11_05 DSM analysis (programs were change sets to P0)
P7 Balanced 3 - Energy
0
200
400
600
800
1000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W
Energy Target Energy Resources
P7 Balanced 3 - Capacity
0
200
400
600
800
1000
1200
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW
Capacity Target Capacity Resources
2004 IRP Portfolio Bundles Page 8 of 12 Idaho Power Company
2004 Integrated Resource Plan
Portfolio Energy and Capacity Balance Analysis
P8 - Balanced 4
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Energy Target 86 132 182 236 258 313 412 465 517 571
Capacity Target 54 3 71 163 249 335 429 522 614 706
Energy
Peakers/ mkt purchase for energy 86 130 147
18 MW DSM - Irrig E, Ind E,CEN, R 0 2 4 6 8 10 12 14 16 18
100 MW wind 06 20 20 20 20 20 20 20 20
12 MW CHP 06 12 12 12 12 12 12 12 12
18 MW CHP 07 18 18 18 18 18 18 18
20 MW geothermal 07 20 20 20 20 20 20 20
250 MW coal 07 250 250 250 250 250 250 250
6 MW CHP 08 6 6 6 6 6 6
500 MW coal seasonal 09 500 500 500 500 500
Total Energy 86 132 182 325 334 836 838 840 842 844
0 0 0 89 76 523 426 375 325 273
Capacity
76 MW DSM A/C & Irrig clipping 0 39 48 57 67 76 76 76 76 76
48 MW DSM - Irrig E, Ind E,CEN, R 0 5 10 15 21 26 32 37 43 48
100 MW wind 06 5 5 5 5 5 5 5 5
12 MW CHP 06 12 12 12 12 12 12 12 12
18 MW CHP 07 18 18 18 18 18 18 18
20 MW geothermal 07 20 20 20 20 20 20 20
250 MW coal 07 250 250 250 250 250 250 250
6 MW CHP 08 6 6 6 6 6 6
500 MW coal seasonal 09 500 500 500 500 500
Total Capacity 0 44 76 378 398 913 918 924 929 935
-54 42 4 215 150 577 489 401 315 229
Notes:1. Peakers can be run to satisfy monthly energy deficit.
2. Market purchases are also available to satisfy monthly energy deficit.
3. Demand response programs are counted as capacity. Energy efficiency and conservation programs are considered to provide energy and capacity.
4. 75 MW of Red Butte - Borah/Brady transmission is available to reduce NW transmission deficit. If coupled with a firm market purchase of up to 75 MW,
the NW transmission deficit (and the capacity requirement) can be reduced by the amount of the purchase.
5. PPL Montana contract expires in 2009. This analysis assumes that some form of contract will replace it thus no reduction of capacity occurs in 2010.
6. Wind project output based on 35% CF and seasonal shaping from NW Power and Conservation Council resource characterization paper 5th PP.
7. Decreased capacity target by 80 MW starting in 2010 to account for continuation of Montana purchases.
8. Included wind capacity credit of 5 MW per 100 MW of nameplate capacity - based on July data.
9. For ease of analysis, standard CHP building blocks are 6 MW. This doesn't match exactly what David Hawk requested,
but overall the end capacity is only 1 MW off.
10. Added to the comments on cells "C15" and "C28"
11. Revised DSM efficiency programs based on benefit cost ratio's associated with 5_11_05 DSM analysis (programs were change sets to P0)
P8 Balanced 4 - Energy
0
200
400
600
800
1000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W
Energy Target Energy Resources
P8 Balanced 4 - Capacity
0
200
400
600
800
1000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW
Capacity Target Capacity Resources
2004 IRP Portfolio Bundles Page 9 of 12 Idaho Power Company
2004 Integrated Resource Plan
Portfolio Energy and Capacity Balance Analysis
P9 - Balanced 5 Defers 250 MW coal plant in P7 by 1 year
Reduces coal plant in 2012 to 250MW and makes second plant
50% ownership same as first plant and moves out 1 year.
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Energy Target 86 132 182 236 258 313 412 465 517 571
Capacity Target 54 3 71 163 249 335 429 522 614 706
Energy
Peakers/ mkt purchase for energy 86 130 158 177 96 147 43 93
26 MW DSM IRR, CEE, REE, REN 0 2 5 8 11 14 17 20 23 26
100 MW wind 06 20 20 20 20 20 20 20 20
100 MW wind 07 20 20 20 20 20 20 20
12 MW CHP 07 12 12 12 12 12 12 12
100 MW geothermal 08 100 100 100 100 100 100
250 MW coal 10 250 250 250 250
250 MW coal seasonal 13 0 250
Total Energy 86 132 182 236 258 313 419 465 517 677
Capacity
76 MW DSM A/C & Irrig clipping 0 39 48 57 67 76 76 76 76 76
67 MW DSM IRR, CEE, REE, REN 0 5 13 21 29 37 44 52 60 67
100 MW wind 06 5 5 5 5 5 5 5 5
100 MW wind 07 5 5 5 5 5 5 5
12 MW CHP 07 12 12 12 12 12 12 12
88 MW peaker (2*44) 07 88 88 88 88 88 88 88
100 MW geothermal 08 100 100 100 100 100 100
250 MW coal 10 250 250 250 250
250 MW coal seasonal 13 0 250
Total Capacity 0 45 66 188 305 322 580 588 595 853
Notes:1. Peakers can be run to satisfy monthly energy deficit.
2. Market purchases are also available to satisfy monthly energy deficit.
3. Demand response programs are counted as capacity. Energy efficiency and conservation programs are considered to provide energy and capacity.
4. 75 MW of Red Butte - Borah/Brady transmission is available to reduce NW transmission deficit. If coupled with a firm market purchase of up to 75 MW,
the NW transmission deficit (and the capacity requirement) can be reduced by the amount of the purchase.
5. PPL Montana contract expires in 2009. This analysis assumes that some form of contract will replace it thus no reduction of capacity occurs in 2010.
6. Wind project output based on 35% CF and seasonal shaping from NW Power and Conservation Council resource characterization paper 5th PP.
7. Chose DSM projects that have maximum capacity benefits.
8. Decreased capacity target by 80 MW starting in 2010 to account for continuation of Montana purchases.
9. Coal plant in 2010 and 2012 are same location. Build first with enough space for second.
10. Included wind capacity credit of 5 MW per 100 MW of nameplate capacity - based on July data.
11. Added "seasonal" to description on "C30" and added to comment on "C16" and "C29"
P9 Balanced 5 - Energy
0
200
400
600
800
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W
Energy Target Energy Resources
P9 Balanced 5 - Capacity
0
200
400
600
800
1000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW
Capacity Target Capacity Resources
2004 IRP Portfolio Bundles Page 10 of 12 Idaho Power Company
2004 Integrated Resource Plan
Portfolio Energy and Capacity Balance Analysis
P10 - Balanced 6
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Energy Target 86 132 182 236 258 313 412 465 517 571
Capacity Target 54 3 71 163 249 335 429 522 614 706
Energy
Peakers/ mkt purchase for energy 86 130 158 177 96 147 23 73 0
26 MW DSM IRR, CEE, REE, REN 0 2 5 8 11 14 17 20 23 26
100 MW wind 06 20 20 20 20 20 20 20 20
100 MW wind 07 20 20 20 20 20 20 20
12 MW CHP 07 12 12 12 12 12 12 12
100 MW geothermal 08 100 100 100 100 100 100
270 MW Combined Cycle 10 270 270 270 270
270 MW Combined Cycle seasonal 13 0 270
Total Energy 86 132 182 236 258 313 439 465 517 717
0 0 0 0 0 0 27 0 0 146
Capacity
76 MW DSM A/C & Irrig clipping 0 39 48 57 67 76 76 76 76 76
67 MW DSM IRR, CEE, REE, REN 0 5 13 21 29 37 44 52 60 67
100 MW wind 06 5 5 5 5 5 5 5 5
100 MW wind 07 5 5 5 5 5 5 5
12 MW CHP 07 12 12 12 12 12 12 12
88 MW peaker (2*44) 07 88 88 88 88 88 88 88
100 MW geothermal 08 100 100 100 100 100 100
270 MW Combined Cycle 10 270 270 270 270
270 MW Combined Cycle seasonal 13 0 270
Total Capacity 0 45 66 188 305 322 600 608 615 893
Notes:1. Peakers can be run to satisfy monthly energy deficit.
2. Market purchases are also available to satisfy monthly energy deficit.
3. Demand response programs are counted as capacity. Energy efficiency and conservation programs are considered to provide energy and capacity.
4. 75 MW of Red Butte - Borah/Brady transmission is available to reduce NW transmission deficit. If coupled with a firm market purchase of up to 75 MW,
the NW transmission deficit (and the capacity requirement) can be reduced by the amount of the purchase.
5. PPL Montana contract expires in 2009. This analysis assumes that some form of contract will replace it thus no reduction of capacity occurs in 2010.
6. Wind project output based on 35% CF and seasonal shaping from NW Power and Conservation Council resource characterization paper 5th PP.
7. Chose DSM projects that have maximum capacity benefits.
8. Decreased capacity target by 80 MW starting in 2010 to account for continuation of Montana purchases.
9. Included wind capacity credit of 5 MW per 100 MW of nameplate capacity - based on July data.
10. Added to comments on cells "C15" and "C28"
P10 Balanced 6 - Energy
0
200
400
600
800
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W
Energy Target Energy Resources
P10 Balanced 6 - Capacity
0
200
400
600
800
1000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW
Capacity Target Capacity Resources
2004 IRP Portfolio Bundles Page 11 of 12 Idaho Power Company
2004 Integrated Resource Plan
Portfolio Energy and Capacity Balance Analysis
P11 - Balanced 7
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Energy Target 86 132 182 236 258 313 412 465 517 571
Capacity Target 54 3 71 163 249 335 429 522 614 706
Energy
Peakers/ mkt purchase for energy 86 130 159 179 99 152 121 0
18 MW DSM - Irrig E, Ind E,CEN, REN 0 2 4 6 8 10 12 14 16 18
100 MW wind 06 20 20 20 20 20 20 20 20
100 MW wind 07 20 20 20 20 20 20 20
12 MW CHP 07 12 12 12 12 12 12 12
100 MW geothermal 08 100 100 100 100 100 100
150 MW Wind 10 30 30 30 30
36 MW CHP 10 0 36 36 36 36
62 MW Peakers/DG 10 62 62 62 62
500 MW coal seasonal 11 500 500 500
Total Energy 86 132 182 236 258 313 412 793 795 797
0 0 0 0 0 0 0 328 278 226
Capacity
76 MW DSM A/C & Irrig clipping 0 39 48 57 67 76 76 76 76 76
48 MW DSM - Irrig E, Ind E,CEN, REN C 0 5 10 15 21 26 32 37 43 48
100 MW Wind 06 5 5 5 5 5 5 5 5
100 MW Wind 07 5 5 5 5 5 5 5
12 MW CHP 07 12 12 12 12 12 12 12
88 MW peaker (2*44) 07 88 88 88 88 88 88 88
100 MW geothermal 08 100 100 100 100 100 100
36 MW CHP 10 0 36 36 36 36
62 MW Peakers/DG 10 62 62 62 62
150 MW Wind 10 8 8 8 8
500 MW coal seasonal 11 500 500 500
Total Capacity 0 44 64 183 297 312 423 928 934 939
-54 42 -8 20 49 -24 -7 406 320 233
Notes:1. Peakers can be run to satisfy monthly energy deficit.
2. Market purchases are also available to satisfy monthly energy deficit.
3. Demand response programs are counted as capacity. Energy efficiency and conservation programs are considered to provide energy and capacity.
4. 75 MW of Red Butte - Borah/Brady transmission is available to reduce NW transmission deficit. If coupled with a firm market purchase of up to 75 MW,
the NW transmission deficit (and the capacity requirement) can be reduced by the amount of the purchase.
5. PPL Montana contract expires in 2009. This analysis assumes that some form of contract will replace it thus no reduction of capacity occurs in 2010.
6. Wind project output based on 35% CF and seasonal shaping from NW Power and Conservation Council resource characterization paper 5th PP.
7. Decreased capacity target by 80 MW starting in 2010 to account for continuation of Montana purchases.
9. Included wind capacity credit of 5 MW per 100 MW of nameplate capacity - based on July data.
10. Removed "Market Purchase" from description on cells "C17" and "C31", and deleted reference to a 250 MW coal plant in 2009.
11. Revised DSM efficiency programs based on benefit cost ratio's associated with 5_11_05 DSM analysis (programs were change sets to P0)
P11 Balanced 7 - Energy
0
200
400
600
800
1000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W
Energy Target Energy Resources
P11 Balanced 7 - Capacity
0
200
400
600
800
1000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW
Capacity Target Capacity Resources
2004 IRP Portfolio Bundles Page 12 of 12 Idaho Power Company
2004 Integrated Resource Plan
Technical Appendix

PPoorrttffoolliioo AAnnaallyyssiiss –– RReessuullttss aanndd
SSuuppppoorrttiinngg DDooccuummeennttaattiioonn

Aurora Computer Program – Description

PDR580 Results – 50/50, 70/70 and 90/70

Portfolio Comparisons – PVRR for 4 Scenarios
• Expected Gas, CO2 @ $0/ton, PTC
• Expected Gas, CO2 @ $12/ton. PTC
• Expected Gas, CO2 @ $49/ton, PTC
• Expected Gas, CO2 @ $12/ton, No PTC
• Portfolio Ranking Results – Determination of Finalists

DSM Energy Efficiency Program Ranking – Aurora
benefit/cost analysis

Portfolio CO2 Emissions

Finalist Portfolio Comparisons
• Expected Gas, CO2 @ $0/ton, PTC
• Expected Gas, CO2 @ $12/ton. PTC
• Expected Gas, CO2 @ $49/ton, PTC
• Expected Gas, CO2 @ $12/ton, No PTC
• Low Gas, CO2 @ $12/ton, PTC
• High Gas, CO2 @ $12/ton, PTC
• Projected Market Sales Data
• Projected Market Purchases
• Projected Gas Costs
• Projected Area Prices

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.
© Copyright 2002 EPIS, Inc. All rights reserved.
AURORAxmp Electric Market Model
Overview of AURORAxmp
AURORAxmp 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.
• The market value of contracts and
portfolios; and,
• AURORAxmp analyzes the effect of market
uncertainty.

AURORAxmp applies economic principles,
dispatch simulation and bidding strategies to
model the relationships of supply,
transportation, and demand for electric
energy.

AURORAxmp forecasts market prices and
operation based on forecasts of key
fundamental drivers such as demand, fuel
prices, and hydro conditions.

AURORAxmp 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
AURORAxmp 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
AURORAxmp is to estimate this hourly
market-clearing price at various locations in
the national electric market. AURORAxmp
uses a fundamentals approach in estimating
prices, reflecting the economics and physical
characteristics of demand and supply.

AURORAxmp 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 AURORAxmp database includes long-term
average demand and hourly demand shapes
EPIS, Inc
AURORAxmp Technical Summary Page 2 of 3
2004 Integrated Resource Plan
Idaho Power Company

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.
© Copyright 2002 EPIS, Inc. All rights reserved.
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.

AURORAxmp 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 acceptable return on investment.
AURORAxmp 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 fixed
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, AURORAxmp simulates the economic
dispatch of resources to meet demand
requirements. AURORAxmp:
• Solves the whole system dispatch
simultaneously.
• Dispatches hourly (with sampling
capabilities, where appropriate).
• Determines the market-clearing prices
from marginal costs.
• Values all the resources in the system.
• Provides 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.
AURORAxmp Technical Summary Page 3 of 3
2004 Integrated Resource Plan
Idaho Power Company

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.
© Copyright 2002 EPIS, Inc. All rights reserved.
• Fuel prices by fuel type and location.
• Hydro information for AURORAxmp’s
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.

2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
50th Percentile Water - 50th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
BROWNLEE 2004 HCC 319.9 467.2 338.8 442.2 347.3 361.4 318.0 256.5 301.7 190.3 151.5 254.8 312.5
HELLS CANYON 2004 HCC 251.4 369.6 302.2 386.9 292.9 292.8 254.1 220.7 275.5 180.1 138.0 211.3 264.6
OXBOW 2004 HCC 128.5 185.1 151.8 191.7 143.6 146.8 130.1 112.7 136.1 91.6 69.7 107.2 132.9
1000 SPRINGS 2004 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2004 ROR 39.4 29.4 19.4 52.3 88.8 88.3 95.4 76.7 42.9 20.7 8.4 0.0 46.8
BLISS 2004 ROR 62.6 55.3 46.1 53.4 47.9 42.4 45.7 47.5 46.9 46.9 47.1 43.3 48.8
C.J.STRIKE 2004 ROR 83.3 73.6 60.4 69.7 60.1 51.2 50.9 53.9 55.3 58.2 60.7 55.4 61.1
CASCADE 2004 ROR 1.2 1.2 1.2 1.3 6.9 11.9 15.2 14.1 11.0 1.2 1.2 1.2 5.6
CLEAR LAKE 2004 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2004 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2004 ROR 46.9 40.7 30.7 37.6 34.4 29.3 32.9 33.8 32.3 32.6 32.6 29.9 34.5MILNER2004ROR56.0 47.4 22.2 42.3 27.2 8.7 28.0 23.9 9.8 10.8 20.2 12.3 25.7
SHOSHONE FALLS 2004 ROR 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0
SWAN FALLS 2004 ROR 24.8 23.4 19.9 23.0 19.8 17.5 17.0 17.9 18.4 19.3 19.8 18.2 19.9
TWIN FALLS 2004 ROR 50.1 46.7 25.2 41.7 32.1 15.0 30.3 27.8 15.2 16.3 22.2 17.4 28.3
UPPER MALAD 2004 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&2 2004 ROR 18.9 19.0 19.2 19.1 17.6 18.9 19.2 19.1 19.2 19.2 19.2 19.2 19.0
UPPERSALMON 3&4 2004 ROR 17.7 17.7 17.7 17.7 17.7 16.2 17.7 17.7 17.7 17.7 17.7 17.7 17.6
HCC TOTAL 699.8 1021.9 792.8 1020.8 783.8 801.0 702.2 589.9 713.2 462.0 359.2 573.3 710.0
ROR TOTAL 442.1 395.6 303.2 399.3 393.7 340.6 393.5 373.6 309.9 284.1 290.3 255.8 348.5
TOTAL 1141.9 1417.5 1096.0 1420.1 1177.4 1141.6 1095.7 963.5 1023.1 746.1 649.5 829.1 1058.5
BROWNLEE 2005 HCC 319.9 467.2 338.8 442.2 347.3 361.4 324.7 260.9 284.3 190.3 151.5 254.8 311.9
HELLS CANYON 2005 HCC 251.4 369.6 302.2 386.9 292.9 292.8 260.2 227.7 262.1 180.1 138.0 211.3 264.6
OXBOW 2005 HCC 128.5 185.1 151.8 191.7 143.6 146.8 133.2 116.3 134.4 91.6 69.7 107.2 133.3
1000 SPRINGS 2005 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2005 ROR 39.4 29.4 19.4 52.3 88.8 88.3 95.4 76.7 42.9 20.7 8.4 0.0 46.8
BLISS 2005 ROR 62.6 55.3 46.1 53.4 47.9 42.4 45.7 47.5 46.9 46.9 47.1 43.3 48.8
C.J.STRIKE 2005 ROR 83.3 73.6 60.4 69.7 60.1 51.2 50.9 53.9 55.3 58.2 60.7 55.4 61.1
CASCADE 2005 ROR 1.2 1.2 1.2 1.3 6.9 11.9 15.2 14.1 11.0 1.2 1.2 1.2 5.6
CLEAR LAKE 2005 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2005 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2005 ROR 46.9 40.7 30.7 37.6 34.4 29.3 32.9 33.8 32.3 32.6 32.6 29.9 34.5
MILNER 2005 ROR 56.0 47.4 22.2 42.3 27.2 8.7 28.0 23.9 9.8 10.8 20.2 12.3 25.7
SHOSHONE FALLS 2005 ROR 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0
SWAN FALLS 2005 ROR 24.8 23.4 19.9 23.0 19.8 17.5 17.0 17.9 18.4 19.3 19.8 18.2 19.9TWIN FALLS 2005 ROR 50.1 46.7 25.2 41.7 32.1 15.0 30.3 27.8 15.2 16.3 22.2 17.4 28.3
UPPER MALAD 2005 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&3 2005 ROR 18.9 19.0 19.2 19.1 17.6 18.9 19.2 19.1 19.2 19.2 19.2 19.2 19.0
UPPERSALMON 3&5 2005 ROR 17.7 17.7 17.7 17.7 17.7 16.2 17.7 17.7 17.7 17.7 17.7 17.7 17.6
HCC TOTAL 699.8 1021.9 792.8 1020.8 783.8 801.0 718.1 604.9 680.7 462.0 359.2 573.3 709.9
ROR TOTAL 442.1 395.6 303.2 399.3 393.7 340.6 393.5 373.6 309.9 284.1 290.3 255.8 348.5
TOTAL 1141.9 1417.5 1096.0 1420.1 1177.4 1141.6 1111.6 978.5 990.6 746.1 649.5 829.1 1058.3
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
2004 Integrated Resource Plan - PDR580 Output Page 1 of 15 50W - 50L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
50th Percentile Water - 50th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
BROWNLEE 2006 HCC 319.9 467.2 338.8 442.2 347.3 361.4 324.7 286.2 261.6 190.3 151.5 254.8 312.2
HELLS CANYON 2006 HCC 251.4 369.6 302.2 386.9 292.9 292.8 260.2 243.4 244.2 180.1 138.0 211.3 264.4
OXBOW 2006 HCC 128.5 185.1 151.8 191.7 143.6 146.8 133.2 125.3 125.2 91.6 69.7 107.2 133.31000 SPRINGS 2006 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2006 ROR 39.4 29.4 19.4 52.3 88.8 88.3 95.4 76.7 42.9 20.7 8.4 0.0 46.8
BLISS 2006 ROR 62.6 55.3 46.1 53.4 47.9 42.4 45.7 47.5 46.9 46.9 47.1 43.3 48.8
C.J.STRIKE 2006 ROR 83.3 73.6 60.4 69.7 60.1 51.2 50.9 53.9 55.3 58.2 60.7 55.4 61.1
CASCADE 2006 ROR 1.2 1.2 1.2 1.3 6.9 11.9 15.2 14.1 11.0 1.2 1.2 1.2 5.6
CLEAR LAKE 2006 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2006 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3LOWER SALMON 2006 ROR 46.9 40.7 30.7 37.6 34.4 29.3 32.9 33.8 32.3 32.6 32.6 29.9 34.5
MILNER 2006 ROR 56.0 47.4 22.2 42.3 27.2 8.7 28.0 23.9 9.8 10.8 20.2 12.3 25.7
SHOSHONE FALLS 2006 ROR 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0
SWAN FALLS 2006 ROR 24.8 23.4 19.9 23.0 19.8 17.5 17.0 17.9 18.4 19.3 19.8 18.2 19.9
TWIN FALLS 2006 ROR 50.1 46.7 25.2 41.7 32.1 15.0 30.3 27.8 15.2 16.3 22.2 17.4 28.3
UPPER MALAD 2006 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&4 2006 ROR 18.9 19.0 19.2 19.1 17.6 18.9 19.2 19.1 19.2 19.2 19.2 19.2 19.0
UPPERSALMON 3&6 2006 ROR 17.7 17.7 17.7 17.7 17.7 16.2 17.7 17.7 17.7 17.7 17.7 17.7 17.6
HCC TOTAL 699.8 1021.9 792.8 1020.8 783.8 801.0 718.1 654.9 630.9 462.0 359.2 573.3 709.9
ROR TOTAL 442.1 395.6 303.2 399.3 393.7 340.6 393.5 373.6 309.9 284.1 290.3 255.8 348.5
TOTAL 1141.9 1417.5 1096.0 1420.1 1177.4 1141.6 1111.6 1028.5 940.8 746.1 649.5 829.1 1058.3
BROWNLEE 2007 HCC 319.9 467.2 338.8 442.2 347.3 361.4 324.7 291.0 255.3 190.3 151.5 254.8 312.0
HELLS CANYON 2007 HCC 251.4 369.6 302.2 386.9 292.9 292.8 260.2 248.3 239.1 180.1 138.0 211.3 264.4
OXBOW 2007 HCC 128.5 185.1 151.8 191.7 143.6 146.8 133.2 127.8 122.6 91.6 69.7 107.2 133.3
1000 SPRINGS 2007 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2007 ROR 39.4 29.4 19.4 52.3 88.8 88.3 95.4 76.7 42.9 20.7 8.4 0.0 46.8
BLISS 2007 ROR 62.6 55.3 46.1 53.4 47.9 42.4 45.7 47.5 46.9 46.9 47.1 43.3 48.8
C.J.STRIKE 2007 ROR 83.3 73.6 60.4 69.7 60.1 51.2 50.9 53.9 55.3 58.2 60.7 55.4 61.1
CASCADE 2007 ROR 1.2 1.2 1.2 1.3 6.9 11.9 15.2 14.1 11.0 1.2 1.2 1.2 5.6
CLEAR LAKE 2007 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2007 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2007 ROR 46.9 40.7 30.7 37.6 34.4 29.3 32.9 33.8 32.3 32.6 32.6 29.9 34.5
MILNER 2007 ROR 56.0 47.4 22.2 42.3 27.2 8.7 28.0 23.9 9.8 10.8 20.2 12.3 25.7
SHOSHONE FALLS 2007 ROR 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0SWAN FALLS 2007 ROR 24.8 23.4 19.9 23.0 19.8 17.5 17.0 17.9 18.4 19.3 19.8 18.2 19.9
TWIN FALLS 2007 ROR 50.1 46.7 25.2 41.7 32.1 15.0 30.3 27.8 15.2 16.3 22.2 17.4 28.3
UPPER MALAD 2007 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&5 2007 ROR 18.9 19.0 19.2 19.1 17.6 18.9 19.2 19.1 19.2 19.2 19.2 19.2 19.0
UPPERSALMON 3&7 2007 ROR 17.7 17.7 17.7 17.7 17.7 16.2 17.7 17.7 17.7 17.7 17.7 17.7 17.6
HCC TOTAL 699.8 1021.9 792.8 1020.8 783.8 801.0 718.1 667.1 617.0 462.0 359.2 573.3 709.7
ROR TOTAL 442.1 395.6 303.2 399.3 393.7 340.6 393.5 373.6 309.9 284.1 290.3 255.8 348.5TOTAL 1141.9 1417.5 1096.0 1420.1 1177.4 1141.6 1111.6 1040.7 926.9 746.1 649.5 829.1 1058.2
2004 Integrated Resource Plan - PDR580 Output Page 2 of 15 50W - 50L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
50th Percentile Water - 50th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
BROWNLEE 2008 HCC 319.9 467.2 338.8 442.2 347.3 361.4 324.7 291.0 255.3 190.3 151.5 254.8 312.0
HELLS CANYON 2008 HCC 251.4 369.6 302.2 386.9 292.9 292.8 260.2 248.3 239.1 180.1 138.0 211.3 264.4
OXBOW 2008 HCC 128.5 185.1 151.8 191.7 143.6 146.8 133.2 127.8 122.6 91.6 69.7 107.2 133.31000 SPRINGS 2008 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2008 ROR 39.4 29.4 19.4 52.3 88.8 88.3 95.4 76.7 42.9 20.7 8.4 0.0 46.8
BLISS 2008 ROR 62.6 55.3 46.1 53.4 47.9 42.4 45.7 47.5 46.9 46.9 47.1 43.3 48.8
C.J.STRIKE 2008 ROR 83.3 73.6 60.4 69.7 60.1 51.2 50.9 53.9 55.3 58.2 60.7 55.4 61.1
CASCADE 2008 ROR 1.2 1.2 1.2 1.3 6.9 11.9 15.2 14.1 11.0 1.2 1.2 1.2 5.6
CLEAR LAKE 2008 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2008 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3LOWER SALMON 2008 ROR 46.9 40.7 30.7 37.6 34.4 29.3 32.9 33.8 32.3 32.6 32.6 29.9 34.5
MILNER 2008 ROR 56.0 47.4 22.2 42.3 27.2 8.7 28.0 23.9 9.8 10.8 20.2 12.3 25.7
SHOSHONE FALLS 2008 ROR 64.0 64.0 38.0 63.0 48.0 24.0 46.0 42.0 24.0 26.0 34.0 27.0 41.7
SWAN FALLS 2008 ROR 24.8 23.4 19.9 23.0 19.8 17.5 17.0 17.9 18.4 19.3 19.8 18.2 19.9
TWIN FALLS 2008 ROR 50.1 46.7 25.2 41.7 32.1 15.0 30.3 27.8 15.2 16.3 22.2 17.4 28.3
UPPER MALAD 2008 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&6 2008 ROR 18.9 19.0 19.2 19.1 17.6 18.9 19.2 19.1 19.2 19.2 19.2 19.2 19.0
UPPERSALMON 3&8 2008 ROR 17.7 17.7 17.7 17.7 17.7 16.2 17.7 17.7 17.7 17.7 17.7 17.7 17.6
HCC TOTAL 699.8 1021.9 792.8 1020.8 783.8 801.0 718.1 667.1 617.0 462.0 359.2 573.3 709.7
ROR TOTAL 494.1 447.6 329.2 450.3 429.7 352.6 427.5 403.6 321.9 298.1 312.3 270.8 378.1
TOTAL 1193.9 1469.5 1122.0 1471.1 1213.4 1153.6 1145.6 1070.7 938.9 760.1 671.5 844.1 1087.9
BROWNLEE 2009 HCC 319.9 467.2 338.8 442.2 347.3 361.4 324.7 291.0 255.3 190.3 151.5 254.8 312.0
HELLS CANYON 2009 HCC 251.4 369.6 302.2 386.9 292.9 292.8 260.2 248.3 239.1 180.1 138.0 211.3 264.4
OXBOW 2009 HCC 128.5 185.1 151.8 191.7 143.6 146.8 133.2 127.8 122.6 91.6 69.7 107.2 133.3
1000 SPRINGS 2009 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2009 ROR 39.4 29.4 19.4 52.3 88.8 88.3 95.4 76.7 42.9 20.7 8.4 0.0 46.8
BLISS 2009 ROR 62.6 55.3 46.1 53.4 47.9 42.4 45.7 47.5 46.9 46.9 47.1 43.3 48.8
C.J.STRIKE 2009 ROR 83.3 73.6 60.4 69.7 60.1 51.2 50.9 53.9 55.3 58.2 60.7 55.4 61.1
CASCADE 2009 ROR 1.2 1.2 1.2 1.3 6.9 11.9 15.2 14.1 11.0 1.2 1.2 1.2 5.6
CLEAR LAKE 2009 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2009 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2009 ROR 46.9 40.7 30.7 37.6 34.4 29.3 32.9 33.8 32.3 32.6 32.6 29.9 34.5
MILNER 2009 ROR 56.0 47.4 22.2 42.3 27.2 8.7 28.0 23.9 9.8 10.8 20.2 12.3 25.7
SHOSHONE FALLS 2009 ROR 64.0 64.0 38.0 63.0 48.0 24.0 46.0 42.0 24.0 26.0 34.0 27.0 41.7SWAN FALLS 2009 ROR 24.8 23.4 19.9 23.0 19.8 17.5 17.0 17.9 18.4 19.3 19.8 18.2 19.9
TWIN FALLS 2009 ROR 50.1 46.7 25.2 41.7 32.1 15.0 30.3 27.8 15.2 16.3 22.2 17.4 28.3
UPPER MALAD 2009 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&7 2009 ROR 18.9 19.0 19.2 19.1 17.6 18.9 19.2 19.1 19.2 19.2 19.2 19.2 19.0
UPPERSALMON 3&9 2009 ROR 17.7 17.7 17.7 17.7 17.7 16.2 17.7 17.7 17.7 17.7 17.7 17.7 17.6
HCC TOTAL 699.8 1021.9 792.8 1020.8 783.8 801.0 718.1 667.1 617.0 462.0 359.2 573.3 709.7
ROR TOTAL 494.1 447.6 329.2 450.3 429.7 352.6 427.5 403.6 321.9 298.1 312.3 270.8 378.1TOTAL 1193.9 1469.5 1122.0 1471.1 1213.4 1153.6 1145.6 1070.7 938.9 760.1 671.5 844.1 1087.9
2004 Integrated Resource Plan - PDR580 Output Page 3 of 15 50W - 50L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
50th Percentile Water - 50th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
BROWNLEE 2010 HCC 319.9 467.2 338.8 442.2 347.3 361.4 324.7 291.0 255.3 190.3 151.5 254.8 312.0
HELLS CANYON 2010 HCC 251.4 369.6 302.2 386.9 292.9 292.8 260.2 248.3 239.1 180.1 138.0 211.3 264.4
OXBOW 2010 HCC 128.5 185.1 151.8 191.7 143.6 146.8 133.2 127.8 122.6 91.6 69.7 107.2 133.31000 SPRINGS 2010 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2010 ROR 39.4 29.4 19.4 52.3 88.8 88.3 95.4 76.7 42.9 20.7 8.4 0.0 46.8
BLISS 2010 ROR 62.6 55.3 46.1 53.4 47.9 42.4 45.7 47.5 46.9 46.9 47.1 43.3 48.8
C.J.STRIKE 2010 ROR 83.3 73.6 60.4 69.7 60.1 51.2 50.9 53.9 55.3 58.2 60.7 55.4 61.1
CASCADE 2010 ROR 1.2 1.2 1.2 1.3 6.9 11.9 15.2 14.1 11.0 1.2 1.2 1.2 5.6
CLEAR LAKE 2010 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2010 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3LOWER SALMON 2010 ROR 46.9 40.7 30.7 37.6 34.4 29.3 32.9 33.8 32.3 32.6 32.6 29.9 34.5
MILNER 2010 ROR 56.0 47.4 22.2 42.3 27.2 8.7 28.0 23.9 9.8 10.8 20.2 12.3 25.7
SHOSHONE FALLS 2010 ROR 64.0 64.0 38.0 63.0 48.0 24.0 46.0 42.0 24.0 26.0 34.0 27.0 41.7
SWAN FALLS 2010 ROR 24.8 23.4 19.9 23.0 19.8 17.5 17.0 17.9 18.4 19.3 19.8 18.2 19.9
TWIN FALLS 2010 ROR 50.1 46.7 25.2 41.7 32.1 15.0 30.3 27.8 15.2 16.3 22.2 17.4 28.3
UPPER MALAD 2010 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&8 2010 ROR 18.9 19.0 19.2 19.1 17.6 18.9 19.2 19.1 19.2 19.2 19.2 19.2 19.0
UPPERSALMON 3&10 2010 ROR 17.7 17.7 17.7 17.7 17.7 16.2 17.7 17.7 17.7 17.7 17.7 17.7 17.6
HCC TOTAL 699.8 1021.9 792.8 1020.8 783.8 801.0 718.1 667.1 617.0 462.0 359.2 573.3 709.7
ROR TOTAL 494.1 447.6 329.2 450.3 429.7 352.6 427.5 403.6 321.9 298.1 312.3 270.8 378.1
TOTAL 1193.9 1469.5 1122.0 1471.1 1213.4 1153.6 1145.6 1070.7 938.9 760.1 671.5 844.1 1087.9
BROWNLEE 2011 HCC 319.9 467.2 338.8 442.2 347.3 361.4 324.7 291.0 255.3 190.3 151.5 254.8 312.0
HELLS CANYON 2011 HCC 251.4 369.6 302.2 386.9 292.9 292.8 260.2 248.3 239.1 180.1 138.0 211.3 264.4
OXBOW 2011 HCC 128.5 185.1 151.8 191.7 143.6 146.8 133.2 127.8 122.6 91.6 69.7 107.2 133.3
1000 SPRINGS 2011 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2011 ROR 39.4 29.4 19.4 52.3 88.8 88.3 95.4 76.7 42.9 20.7 8.4 0.0 46.8
BLISS 2011 ROR 62.6 55.3 46.1 53.4 47.9 42.4 45.7 47.5 46.9 46.9 47.1 43.3 48.8
C.J.STRIKE 2011 ROR 83.3 73.6 60.4 69.7 60.1 51.2 50.9 53.9 55.3 58.2 60.7 55.4 61.1
CASCADE 2011 ROR 1.2 1.2 1.2 1.3 6.9 11.9 15.2 14.1 11.0 1.2 1.2 1.2 5.6
CLEAR LAKE 2011 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2011 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2011 ROR 46.9 40.7 30.7 37.6 34.4 29.3 32.9 33.8 32.3 32.6 32.6 29.9 34.5
MILNER 2011 ROR 56.0 47.4 22.2 42.3 27.2 8.7 28.0 23.9 9.8 10.8 20.2 12.3 25.7
SHOSHONE FALLS 2011 ROR 64.0 64.0 38.0 63.0 48.0 24.0 46.0 42.0 24.0 26.0 34.0 27.0 41.7SWAN FALLS 2011 ROR 24.8 23.4 19.9 23.0 19.8 17.5 17.0 17.9 18.4 19.3 19.8 18.2 19.9
TWIN FALLS 2011 ROR 50.1 46.7 25.2 41.7 32.1 15.0 30.3 27.8 15.2 16.3 22.2 17.4 28.3
UPPER MALAD 2011 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&9 2011 ROR 18.9 19.0 19.2 19.1 17.6 18.9 19.2 19.1 19.2 19.2 19.2 19.2 19.0
UPPERSALMON 3&11 2011 ROR 17.7 17.7 17.7 17.7 17.7 16.2 17.7 17.7 17.7 17.7 17.7 17.7 17.6
HCC TOTAL 699.8 1021.9 792.8 1020.8 783.8 801.0 718.1 667.1 617.0 462.0 359.2 573.3 709.7
ROR TOTAL 494.1 447.6 329.2 450.3 429.7 352.6 427.5 403.6 321.9 298.1 312.3 270.8 378.1TOTAL 1193.9 1469.5 1122.0 1471.1 1213.4 1153.6 1145.6 1070.7 938.9 760.1 671.5 844.1 1087.9
2004 Integrated Resource Plan - PDR580 Output Page 4 of 15 50W - 50L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
50th Percentile Water - 50th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
BROWNLEE 2012 HCC 319.9 467.2 338.8 442.2 347.3 361.4 324.7 291.0 255.3 190.3 151.5 254.8 312.0
HELLS CANYON 2012 HCC 251.4 369.6 302.2 386.9 292.9 292.8 260.2 248.3 239.1 180.1 138.0 211.3 264.4
OXBOW 2012 HCC 128.5 185.1 151.8 191.7 143.6 146.8 133.2 127.8 122.6 91.6 69.7 107.2 133.31000 SPRINGS 2012 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2012 ROR 39.4 29.4 19.4 52.3 88.8 88.3 95.4 76.7 42.9 20.7 8.4 0.0 46.8
BLISS 2012 ROR 62.6 55.3 46.1 53.4 47.9 42.4 45.7 47.5 46.9 46.9 47.1 43.3 48.8
C.J.STRIKE 2012 ROR 83.3 73.6 60.4 69.7 60.1 51.2 50.9 53.9 55.3 58.2 60.7 55.4 61.1
CASCADE 2012 ROR 1.2 1.2 1.2 1.3 6.9 11.9 15.2 14.1 11.0 1.2 1.2 1.2 5.6
CLEAR LAKE 2012 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2012 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3LOWER SALMON 2012 ROR 46.9 40.7 30.7 37.6 34.4 29.3 32.9 33.8 32.3 32.6 32.6 29.9 34.5
MILNER 2012 ROR 56.0 47.4 22.2 42.3 27.2 8.7 28.0 23.9 9.8 10.8 20.2 12.3 25.7
SHOSHONE FALLS 2012 ROR 64.0 64.0 38.0 63.0 48.0 24.0 46.0 42.0 24.0 26.0 34.0 27.0 41.7
SWAN FALLS 2012 ROR 24.8 23.4 19.9 23.0 19.8 17.5 17.0 17.9 18.4 19.3 19.8 18.2 19.9
TWIN FALLS 2012 ROR 50.1 46.7 25.2 41.7 32.1 15.0 30.3 27.8 15.2 16.3 22.2 17.4 28.3
UPPER MALAD 2012 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&10 2012 ROR 18.9 19.0 19.2 19.1 17.6 18.9 19.2 19.1 19.2 19.2 19.2 19.2 19.0
UPPERSALMON 3&12 2012 ROR 17.7 17.7 17.7 17.7 17.7 16.2 17.7 17.7 17.7 17.7 17.7 17.7 17.6
HCC TOTAL 699.8 1021.9 792.8 1020.8 783.8 801.0 718.1 667.1 617.0 462.0 359.2 573.3 709.7
ROR TOTAL 494.1 447.6 329.2 450.3 429.7 352.6 427.5 403.6 321.9 298.1 312.3 270.8 378.1
TOTAL 1193.9 1469.5 1122.0 1471.1 1213.4 1153.6 1145.6 1070.7 938.9 760.1 671.5 844.1 1087.9
BROWNLEE 2013 HCC 319.9 467.2 338.8 442.2 347.3 361.4 324.7 291.0 255.3 190.3 151.5 254.8 312.0
HELLS CANYON 2013 HCC 251.4 369.6 302.2 386.9 292.9 292.8 260.2 248.3 239.1 180.1 138.0 211.3 264.4
OXBOW 2013 HCC 128.5 185.1 151.8 191.7 143.6 146.8 133.2 127.8 122.6 91.6 69.7 107.2 133.3
1000 SPRINGS 2013 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2013 ROR 39.4 29.4 19.4 52.3 88.8 88.3 95.4 76.7 42.9 20.7 8.4 0.0 46.8
BLISS 2013 ROR 62.6 55.3 46.1 53.4 47.9 42.4 45.7 47.5 46.9 46.9 47.1 43.3 48.8
C.J.STRIKE 2013 ROR 83.3 73.6 60.4 69.7 60.1 51.2 50.9 53.9 55.3 58.2 60.7 55.4 61.1
CASCADE 2013 ROR 1.2 1.2 1.2 1.3 6.9 11.9 15.2 14.1 11.0 1.2 1.2 1.2 5.6
CLEAR LAKE 2013 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2013 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2013 ROR 46.9 40.7 30.7 37.6 34.4 29.3 32.9 33.8 32.3 32.6 32.6 29.9 34.5
MILNER 2013 ROR 56.0 47.4 22.2 42.3 27.2 8.7 28.0 23.9 9.8 10.8 20.2 12.3 25.7
SHOSHONE FALLS 2013 ROR 64.0 64.0 38.0 63.0 48.0 24.0 46.0 42.0 24.0 26.0 34.0 27.0 41.7SWAN FALLS 2013 ROR 24.8 23.4 19.9 23.0 19.8 17.5 17.0 17.9 18.4 19.3 19.8 18.2 19.9
TWIN FALLS 2013 ROR 50.1 46.7 25.2 41.7 32.1 15.0 30.3 27.8 15.2 16.3 22.2 17.4 28.3
UPPER MALAD 2013 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&11 2013 ROR 18.9 19.0 19.2 19.1 17.6 18.9 19.2 19.1 19.2 19.2 19.2 19.2 19.0
UPPERSALMON 3&13 2013 ROR 17.7 17.7 17.7 17.7 17.7 16.2 17.7 17.7 17.7 17.7 17.7 17.7 17.6
HCC TOTAL 699.8 1021.9 792.8 1020.8 783.8 801.0 718.1 667.1 617.0 462.0 359.2 573.3 709.7
ROR TOTAL 494.1 447.6 329.2 450.3 429.7 352.6 427.5 403.6 321.9 298.1 312.3 270.8 378.1TOTAL 1193.9 1469.5 1122.0 1471.1 1213.4 1153.6 1145.6 1070.7 938.9 760.1 671.5 844.1 1087.9
2004 Integrated Resource Plan - PDR580 Output Page 5 of 15 50W - 50L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
70th Percentile Water - 70th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
BROWNLEE 2004 HCC 271.8 390.5 313.3 336.7 286.8 297.8 307.1 279.4 200.6 196.8 154.5 230.4 272.1
HELLS CANYON 2004 HCC 221.2 314.9 270.4 288.7 241.6 240.1 245.6 238.3 182.6 176.5 138.1 191.7 229.1
OXBOW 2004 HCC 112.3 160.5 135.8 145.0 119.5 120.4 126.0 122.7 93.2 89.8 69.7 96.6 116.0
1000 SPRINGS 2004 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2004 ROR 26.8 21.1 14.9 40.3 73.2 81.6 88.6 66.9 35.4 12.8 0.0 0.0 38.5
BLISS 2004 ROR 54.9 50.3 42.6 46.1 38.8 40.0 45.0 46.8 45.6 44.6 41.0 40.6 44.7
C.J.STRIKE 2004 ROR 72.1 65.7 55.5 58.7 47.4 46.2 49.9 53.4 53.7 55.0 52.4 51.8 55.2
CASCADE 2004 ROR 1.2 1.2 1.2 1.3 4.1 10.3 14.6 13.9 11.0 1.2 1.2 1.2 5.2
CLEAR LAKE 2004 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2004 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2004 ROR 40.6 36.0 28.2 31.5 26.6 28.0 32.7 33.4 31.5 30.4 27.3 27.5 31.1MILNER2004ROR46.6 34.7 14.5 22.2 5.8 9.2 26.4 23.5 5.7 4.4 2.1 6.7 16.8
SHOSHONE FALLS 2004 ROR 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 11.9 12.0 12.0
SWAN FALLS 2004 ROR 23.1 21.4 18.5 19.6 16.1 15.7 16.9 17.9 17.9 18.3 17.6 17.4 18.4
TWIN FALLS 2004 ROR 46.2 35.9 17.8 24.7 11.6 14.5 29.0 27.2 11.4 9.7 7.8 11.0 20.6
UPPER MALAD 2004 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&2 2004 ROR 19.0 19.1 18.3 19.2 17.1 17.9 19.2 19.1 19.2 19.2 17.2 17.4 18.5
UPPERSALMON 3&4 2004 ROR 17.7 17.7 16.9 17.7 15.8 16.2 17.7 17.7 17.7 17.7 15.9 16.1 17.1
HCC TOTAL 605.3 865.9 719.5 770.4 647.9 658.3 678.7 640.4 476.3 463.1 362.3 518.7 617.2
ROR TOTAL 389.4 344.3 269.6 322.5 297.7 320.8 381.2 361.0 290.3 254.5 223.6 230.9 307.1
TOTAL 994.7 1210.2 989.1 1092.9 945.5 979.1 1059.9 1001.4 766.5 717.6 585.9 749.6 924.4
BROWNLEE 2005 HCC 271.8 390.5 313.3 336.7 286.8 297.8 307.1 279.7 200.2 196.8 154.5 230.4 272.1
HELLS CANYON 2005 HCC 221.2 314.9 270.4 288.7 241.6 240.1 245.6 238.6 182.2 176.5 138.1 191.7 229.1
OXBOW 2005 HCC 112.3 160.5 135.8 145.0 119.5 120.4 126.0 122.9 93.0 89.8 69.7 96.6 116.0
1000 SPRINGS 2005 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2005 ROR 26.8 21.1 14.9 40.3 73.2 81.6 88.6 66.9 35.4 12.8 0.0 0.0 38.5
BLISS 2005 ROR 54.9 50.3 42.6 46.1 38.8 40.0 45.0 46.8 45.6 44.6 41.0 40.6 44.7
C.J.STRIKE 2005 ROR 72.1 65.7 55.5 58.7 47.4 46.2 49.9 53.4 53.7 55.0 52.4 51.8 55.2
CASCADE 2005 ROR 1.2 1.2 1.2 1.3 4.1 10.3 14.6 13.9 11.0 1.2 1.2 1.2 5.2
CLEAR LAKE 2005 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2005 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2005 ROR 40.6 36.0 28.2 31.5 26.6 28.0 32.7 33.4 31.5 30.4 27.3 27.5 31.1
MILNER 2005 ROR 46.6 34.7 14.5 22.2 5.8 9.2 26.4 23.5 5.7 4.4 2.1 6.7 16.8
SHOSHONE FALLS 2005 ROR 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 11.9 12.0 12.0
SWAN FALLS 2005 ROR 23.1 21.4 18.5 19.6 16.1 15.7 16.9 17.9 17.9 18.3 17.6 17.4 18.4TWIN FALLS 2005 ROR 46.2 35.9 17.8 24.7 11.6 14.5 29.0 27.2 11.4 9.7 7.8 11.0 20.6
UPPER MALAD 2005 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&3 2005 ROR 19.0 19.1 18.3 19.2 17.1 17.9 19.2 19.1 19.2 19.2 17.2 17.4 18.5
UPPERSALMON 3&5 2005 ROR 17.7 17.7 16.9 17.7 15.8 16.2 17.7 17.7 17.7 17.7 15.9 16.1 17.1
HCC TOTAL 605.3 865.9 719.5 770.4 647.9 658.3 678.7 641.2 475.3 463.1 362.3 518.7 617.2
ROR TOTAL 389.4 344.3 269.6 322.5 297.7 320.8 381.2 361.0 290.3 254.5 223.6 230.9 307.1
TOTAL 994.7 1210.2 989.1 1092.9 945.5 979.1 1059.9 1002.2 765.5 717.6 585.9 749.6 924.4
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
2004 Integrated Resource Plan - PDR580 Output Page 6 of 15 70W - 70L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
70th Percentile Water - 70th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
BROWNLEE 2006 HCC 271.8 390.5 313.3 336.7 286.8 297.8 307.1 279.7 200.2 196.8 154.5 230.4 272.1
HELLS CANYON 2006 HCC 221.2 314.9 270.4 288.7 241.6 240.1 245.6 238.6 182.2 176.5 138.1 191.7 229.1
OXBOW 2006 HCC 112.3 160.5 135.8 145.0 119.5 120.4 126.0 122.9 93.0 89.8 69.7 96.6 116.01000 SPRINGS 2006 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2006 ROR 26.8 21.1 14.9 40.3 73.2 81.6 88.6 66.9 35.4 12.8 0.0 0.0 38.5
BLISS 2006 ROR 54.9 50.3 42.6 46.1 38.8 40.0 45.0 46.8 45.6 44.6 41.0 40.6 44.7
C.J.STRIKE 2006 ROR 72.1 65.7 55.5 58.7 47.4 46.2 49.9 53.4 53.7 55.0 52.4 51.8 55.2
CASCADE 2006 ROR 1.2 1.2 1.2 1.3 4.1 10.3 14.6 13.9 11.0 1.2 1.2 1.2 5.2
CLEAR LAKE 2006 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2006 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3LOWER SALMON 2006 ROR 40.6 36.0 28.2 31.5 26.6 28.0 32.7 33.4 31.5 30.4 27.3 27.5 31.1
MILNER 2006 ROR 46.6 34.7 14.5 22.2 5.8 9.2 26.4 23.5 5.7 4.4 2.1 6.7 16.8
SHOSHONE FALLS 2006 ROR 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 11.9 12.0 12.0
SWAN FALLS 2006 ROR 23.1 21.4 18.5 19.6 16.1 15.7 16.9 17.9 17.9 18.3 17.6 17.4 18.4
TWIN FALLS 2006 ROR 46.2 35.9 17.8 24.7 11.6 14.5 29.0 27.2 11.4 9.7 7.8 11.0 20.6
UPPER MALAD 2006 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&4 2006 ROR 19.0 19.1 18.3 19.2 17.1 17.9 19.2 19.1 19.2 19.2 17.2 17.4 18.5
UPPERSALMON 3&6 2006 ROR 17.7 17.7 16.9 17.7 15.8 16.2 17.7 17.7 17.7 17.7 15.9 16.1 17.1
HCC TOTAL 605.3 865.9 719.5 770.4 647.9 658.3 678.7 641.2 475.3 463.1 362.3 518.7 617.2
ROR TOTAL 389.4 344.3 269.6 322.5 297.7 320.8 381.2 361.0 290.3 254.5 223.6 230.9 307.1
TOTAL 994.7 1210.2 989.1 1092.9 945.5 979.1 1059.9 1002.2 765.5 717.6 585.9 749.6 924.4
BROWNLEE 2007 HCC 271.8 390.5 313.3 336.7 286.8 297.8 307.1 279.7 200.2 196.8 154.5 230.4 272.1
HELLS CANYON 2007 HCC 221.2 314.9 270.4 288.7 241.6 240.1 245.6 238.6 182.2 176.5 138.1 191.7 229.1
OXBOW 2007 HCC 112.3 160.5 135.8 145.0 119.5 120.4 126.0 122.9 93.0 89.8 69.7 96.6 116.0
1000 SPRINGS 2007 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2007 ROR 26.8 21.1 14.9 40.3 73.2 81.6 88.6 66.9 35.4 12.8 0.0 0.0 38.5
BLISS 2007 ROR 54.9 50.3 42.6 46.1 38.8 40.0 45.0 46.8 45.6 44.6 41.0 40.6 44.7
C.J.STRIKE 2007 ROR 72.1 65.7 55.5 58.7 47.4 46.2 49.9 53.4 53.7 55.0 52.4 51.8 55.2
CASCADE 2007 ROR 1.2 1.2 1.2 1.3 4.1 10.3 14.6 13.9 11.0 1.2 1.2 1.2 5.2
CLEAR LAKE 2007 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2007 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2007 ROR 40.6 36.0 28.2 31.5 26.6 28.0 32.7 33.4 31.5 30.4 27.3 27.5 31.1
MILNER 2007 ROR 46.6 34.7 14.5 22.2 5.8 9.2 26.4 23.5 5.7 4.4 2.1 6.7 16.8
SHOSHONE FALLS 2007 ROR 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 11.9 12.0 12.0SWAN FALLS 2007 ROR 23.1 21.4 18.5 19.6 16.1 15.7 16.9 17.9 17.9 18.3 17.6 17.4 18.4
TWIN FALLS 2007 ROR 46.2 35.9 17.8 24.7 11.6 14.5 29.0 27.2 11.4 9.7 7.8 11.0 20.6
UPPER MALAD 2007 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&5 2007 ROR 19.0 19.1 18.3 19.2 17.1 17.9 19.2 19.1 19.2 19.2 17.2 17.4 18.5
UPPERSALMON 3&7 2007 ROR 17.7 17.7 16.9 17.7 15.8 16.2 17.7 17.7 17.7 17.7 15.9 16.1 17.1
HCC TOTAL 605.3 865.9 719.5 770.4 647.9 658.3 678.7 641.2 475.3 463.1 362.3 518.7 617.2
ROR TOTAL 389.4 344.3 269.6 322.5 297.7 320.8 381.2 361.0 290.3 254.5 223.6 230.9 307.1TOTAL 994.7 1210.2 989.1 1092.9 945.5 979.1 1059.9 1002.2 765.5 717.6 585.9 749.6 924.4
2004 Integrated Resource Plan - PDR580 Output Page 7 of 15 70W - 70L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
70th Percentile Water - 70th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
BROWNLEE 2008 HCC 271.8 390.5 313.3 336.7 286.8 297.8 307.1 279.7 200.2 196.8 154.5 230.4 272.1
HELLS CANYON 2008 HCC 221.2 314.9 270.4 288.7 241.6 240.1 245.6 238.6 182.2 176.5 138.1 191.7 229.1
OXBOW 2008 HCC 112.3 160.5 135.8 145.0 119.5 120.4 126.0 122.9 93.0 89.8 69.7 96.6 116.01000 SPRINGS 2008 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2008 ROR 26.8 21.1 14.9 40.3 73.2 81.6 88.6 66.9 35.4 12.8 0.0 0.0 38.5
BLISS 2008 ROR 54.9 50.3 42.6 46.1 38.8 40.0 45.0 46.8 45.6 44.6 41.0 40.6 44.7
C.J.STRIKE 2008 ROR 72.1 65.7 55.5 58.7 47.4 46.2 49.9 53.4 53.7 55.0 52.4 51.8 55.2
CASCADE 2008 ROR 1.2 1.2 1.2 1.3 4.1 10.3 14.6 13.9 11.0 1.2 1.2 1.2 5.2
CLEAR LAKE 2008 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2008 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3LOWER SALMON 2008 ROR 40.6 36.0 28.2 31.5 26.6 28.0 32.7 33.4 31.5 30.4 27.3 27.5 31.1
MILNER 2008 ROR 46.6 34.7 14.5 22.2 5.8 9.2 26.4 23.5 5.7 4.4 2.1 6.7 16.8
SHOSHONE FALLS 2008 ROR 64.0 54.0 28.0 37.0 19.0 23.0 44.0 41.0 19.0 16.0 12.9 18.0 31.3
SWAN FALLS 2008 ROR 23.1 21.4 18.5 19.6 16.1 15.7 16.9 17.9 17.9 18.3 17.6 17.4 18.4
TWIN FALLS 2008 ROR 46.2 35.9 17.8 24.7 11.6 14.5 29.0 27.2 11.4 9.7 7.8 11.0 20.6
UPPER MALAD 2008 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&6 2008 ROR 19.0 19.1 18.3 19.2 17.1 17.9 19.2 19.1 19.2 19.2 17.2 17.4 18.5
UPPERSALMON 3&8 2008 ROR 17.7 17.7 16.9 17.7 15.8 16.2 17.7 17.7 17.7 17.7 15.9 16.1 17.1
HCC TOTAL 605.3 865.9 719.5 770.4 647.9 658.3 678.7 641.2 475.3 463.1 362.3 518.7 617.2
ROR TOTAL 441.4 386.3 285.6 347.5 304.7 331.8 413.2 390.0 297.3 258.5 224.6 236.9 326.5
TOTAL 1046.7 1252.2 1005.1 1117.9 952.5 990.1 1091.9 1031.2 772.5 721.6 586.9 755.6 943.7
BROWNLEE 2009 HCC 271.8 390.5 313.3 336.7 286.8 297.8 307.1 279.7 200.2 196.8 154.5 230.4 272.1
HELLS CANYON 2009 HCC 221.2 314.9 270.4 288.7 241.6 240.1 245.6 238.6 182.2 176.5 138.1 191.7 229.1
OXBOW 2009 HCC 112.3 160.5 135.8 145.0 119.5 120.4 126.0 122.9 93.0 89.8 69.7 96.6 116.0
1000 SPRINGS 2009 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2009 ROR 26.8 21.1 14.9 40.3 73.2 81.6 88.6 66.9 35.4 12.8 0.0 0.0 38.5
BLISS 2009 ROR 54.9 50.3 42.6 46.1 38.8 40.0 45.0 46.8 45.6 44.6 41.0 40.6 44.7
C.J.STRIKE 2009 ROR 72.1 65.7 55.5 58.7 47.4 46.2 49.9 53.4 53.7 55.0 52.4 51.8 55.2
CASCADE 2009 ROR 1.2 1.2 1.2 1.3 4.1 10.3 14.6 13.9 11.0 1.2 1.2 1.2 5.2
CLEAR LAKE 2009 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2009 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2009 ROR 40.6 36.0 28.2 31.5 26.6 28.0 32.7 33.4 31.5 30.4 27.3 27.5 31.1
MILNER 2009 ROR 46.6 34.7 14.5 22.2 5.8 9.2 26.4 23.5 5.7 4.4 2.1 6.7 16.8
SHOSHONE FALLS 2009 ROR 64.0 54.0 28.0 37.0 19.0 23.0 44.0 41.0 19.0 16.0 12.9 18.0 31.3SWAN FALLS 2009 ROR 23.1 21.4 18.5 19.6 16.1 15.7 16.9 17.9 17.9 18.3 17.6 17.4 18.4
TWIN FALLS 2009 ROR 46.2 35.9 17.8 24.7 11.6 14.5 29.0 27.2 11.4 9.7 7.8 11.0 20.6
UPPER MALAD 2009 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&7 2009 ROR 19.0 19.1 18.3 19.2 17.1 17.9 19.2 19.1 19.2 19.2 17.2 17.4 18.5
UPPERSALMON 3&9 2009 ROR 17.7 17.7 16.9 17.7 15.8 16.2 17.7 17.7 17.7 17.7 15.9 16.1 17.1
HCC TOTAL 605.3 865.9 719.5 770.4 647.9 658.3 678.7 641.2 475.3 463.1 362.3 518.7 617.2
ROR TOTAL 441.4 386.3 285.6 347.5 304.7 331.8 413.2 390.0 297.3 258.5 224.6 236.9 326.5TOTAL 1046.7 1252.2 1005.1 1117.9 952.5 990.1 1091.9 1031.2 772.5 721.6 586.9 755.6 943.7
2004 Integrated Resource Plan - PDR580 Output Page 8 of 15 70W - 70L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
70th Percentile Water - 70th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
BROWNLEE 2010 HCC 271.8 390.5 313.3 336.7 286.8 297.8 307.1 279.7 200.2 196.8 154.5 230.4 272.1
HELLS CANYON 2010 HCC 221.2 314.9 270.4 288.7 241.6 240.1 245.6 238.6 182.2 176.5 138.1 191.7 229.1
OXBOW 2010 HCC 112.3 160.5 135.8 145.0 119.5 120.4 126.0 122.9 93.0 89.8 69.7 96.6 116.01000 SPRINGS 2010 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2010 ROR 26.8 21.1 14.9 40.3 73.2 81.6 88.6 66.9 35.4 12.8 0.0 0.0 38.5
BLISS 2010 ROR 54.9 50.3 42.6 46.1 38.8 40.0 45.0 46.8 45.6 44.6 41.0 40.6 44.7
C.J.STRIKE 2010 ROR 72.1 65.7 55.5 58.7 47.4 46.2 49.9 53.4 53.7 55.0 52.4 51.8 55.2
CASCADE 2010 ROR 1.2 1.2 1.2 1.3 4.1 10.3 14.6 13.9 11.0 1.2 1.2 1.2 5.2
CLEAR LAKE 2010 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2010 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3LOWER SALMON 2010 ROR 40.6 36.0 28.2 31.5 26.6 28.0 32.7 33.4 31.5 30.4 27.3 27.5 31.1
MILNER 2010 ROR 46.6 34.7 14.5 22.2 5.8 9.2 26.4 23.5 5.7 4.4 2.1 6.7 16.8
SHOSHONE FALLS 2010 ROR 64.0 54.0 28.0 37.0 19.0 23.0 44.0 41.0 19.0 16.0 12.9 18.0 31.3
SWAN FALLS 2010 ROR 23.1 21.4 18.5 19.6 16.1 15.7 16.9 17.9 17.9 18.3 17.6 17.4 18.4
TWIN FALLS 2010 ROR 46.2 35.9 17.8 24.7 11.6 14.5 29.0 27.2 11.4 9.7 7.8 11.0 20.6
UPPER MALAD 2010 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&8 2010 ROR 19.0 19.1 18.3 19.2 17.1 17.9 19.2 19.1 19.2 19.2 17.2 17.4 18.5
UPPERSALMON 3&10 2010 ROR 17.7 17.7 16.9 17.7 15.8 16.2 17.7 17.7 17.7 17.7 15.9 16.1 17.1
HCC TOTAL 605.3 865.9 719.5 770.4 647.9 658.3 678.7 641.2 475.3 463.1 362.3 518.7 617.2
ROR TOTAL 441.4 386.3 285.6 347.5 304.7 331.8 413.2 390.0 297.3 258.5 224.6 236.9 326.5
TOTAL 1046.7 1252.2 1005.1 1117.9 952.5 990.1 1091.9 1031.2 772.5 721.6 586.9 755.6 943.7
BROWNLEE 2011 HCC 271.8 390.5 313.3 336.7 286.8 297.8 307.1 279.7 200.2 196.8 154.5 230.4 272.1
HELLS CANYON 2011 HCC 221.2 314.9 270.4 288.7 241.6 240.1 245.6 238.6 182.2 176.5 138.1 191.7 229.1
OXBOW 2011 HCC 112.3 160.5 135.8 145.0 119.5 120.4 126.0 122.9 93.0 89.8 69.7 96.6 116.0
1000 SPRINGS 2011 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2011 ROR 26.8 21.1 14.9 40.3 73.2 81.6 88.6 66.9 35.4 12.8 0.0 0.0 38.5
BLISS 2011 ROR 54.9 50.3 42.6 46.1 38.8 40.0 45.0 46.8 45.6 44.6 41.0 40.6 44.7
C.J.STRIKE 2011 ROR 72.1 65.7 55.5 58.7 47.4 46.2 49.9 53.4 53.7 55.0 52.4 51.8 55.2
CASCADE 2011 ROR 1.2 1.2 1.2 1.3 4.1 10.3 14.6 13.9 11.0 1.2 1.2 1.2 5.2
CLEAR LAKE 2011 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2011 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2011 ROR 40.6 36.0 28.2 31.5 26.6 28.0 32.7 33.4 31.5 30.4 27.3 27.5 31.1
MILNER 2011 ROR 46.6 34.7 14.5 22.2 5.8 9.2 26.4 23.5 5.7 4.4 2.1 6.7 16.8
SHOSHONE FALLS 2011 ROR 64.0 54.0 28.0 37.0 19.0 23.0 44.0 41.0 19.0 16.0 12.9 18.0 31.3SWAN FALLS 2011 ROR 23.1 21.4 18.5 19.6 16.1 15.7 16.9 17.9 17.9 18.3 17.6 17.4 18.4
TWIN FALLS 2011 ROR 46.2 35.9 17.8 24.7 11.6 14.5 29.0 27.2 11.4 9.7 7.8 11.0 20.6
UPPER MALAD 2011 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&9 2011 ROR 19.0 19.1 18.3 19.2 17.1 17.9 19.2 19.1 19.2 19.2 17.2 17.4 18.5
UPPERSALMON 3&11 2011 ROR 17.7 17.7 16.9 17.7 15.8 16.2 17.7 17.7 17.7 17.7 15.9 16.1 17.1
HCC TOTAL 605.3 865.9 719.5 770.4 647.9 658.3 678.7 641.2 475.3 463.1 362.3 518.7 617.2
ROR TOTAL 441.4 386.3 285.6 347.5 304.7 331.8 413.2 390.0 297.3 258.5 224.6 236.9 326.5TOTAL 1046.7 1252.2 1005.1 1117.9 952.5 990.1 1091.9 1031.2 772.5 721.6 586.9 755.6 943.7
2004 Integrated Resource Plan - PDR580 Output Page 9 of 15 70W - 70L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
70th Percentile Water - 70th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
BROWNLEE 2012 HCC 282.1 375.1 313.3 336.7 286.8 297.8 307.1 279.7 200.2 196.8 154.5 230.4 271.7
HELLS CANYON 2012 HCC 230.7 304.4 270.4 288.7 241.6 240.1 245.6 238.6 182.2 176.5 138.1 191.7 229.0
OXBOW 2012 HCC 117.2 155.2 135.8 145.0 119.5 120.4 126.0 122.9 93.0 89.8 69.7 96.6 115.91000 SPRINGS 2012 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2012 ROR 26.8 21.1 14.9 40.3 73.2 81.6 88.6 66.9 35.4 12.8 0.0 0.0 38.5
BLISS 2012 ROR 54.9 50.3 42.6 46.1 38.8 40.0 45.0 46.8 45.6 44.6 41.0 40.6 44.7
C.J.STRIKE 2012 ROR 72.1 65.7 55.5 58.7 47.4 46.2 49.9 53.4 53.7 55.0 52.4 51.8 55.2
CASCADE 2012 ROR 1.2 1.2 1.2 1.3 4.1 10.3 14.6 13.9 11.0 1.2 1.2 1.2 5.2
CLEAR LAKE 2012 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2012 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3LOWER SALMON 2012 ROR 40.6 36.0 28.2 31.5 26.6 28.0 32.7 33.4 31.5 30.4 27.3 27.5 31.1
MILNER 2012 ROR 46.6 34.7 14.5 22.2 5.8 9.2 26.4 23.5 5.7 4.4 2.1 6.7 16.8
SHOSHONE FALLS 2012 ROR 64.0 54.0 28.0 37.0 19.0 23.0 44.0 41.0 19.0 16.0 12.9 18.0 31.3
SWAN FALLS 2012 ROR 23.1 21.4 18.5 19.6 16.1 15.7 16.9 17.9 17.9 18.3 17.6 17.4 18.4
TWIN FALLS 2012 ROR 46.2 35.9 17.8 24.7 11.6 14.5 29.0 27.2 11.4 9.7 7.8 11.0 20.6
UPPER MALAD 2012 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&10 2012 ROR 19.0 19.1 18.3 19.2 17.1 17.9 19.2 19.1 19.2 19.2 17.2 17.4 18.5
UPPERSALMON 3&12 2012 ROR 17.7 17.7 16.9 17.7 15.8 16.2 17.7 17.7 17.7 17.7 15.9 16.1 17.1
HCC TOTAL 630.0 834.7 719.5 770.4 647.9 658.3 678.7 641.2 475.3 463.1 362.3 518.7 616.7
ROR TOTAL 441.4 386.3 285.6 347.5 304.7 331.8 413.2 390.0 297.3 258.5 224.6 236.9 326.5
TOTAL 1071.4 1221.0 1005.1 1117.9 952.5 990.1 1091.9 1031.2 772.5 721.6 586.9 755.6 943.1
BROWNLEE 2013 HCC 304.6 354.5 313.3 336.7 286.8 297.8 307.1 279.7 200.2 196.8 154.5 230.4 271.9
HELLS CANYON 2013 HCC 241.7 290.4 270.4 288.7 241.6 240.1 245.6 238.6 182.2 176.5 138.1 191.7 228.8
OXBOW 2013 HCC 123.8 148.0 135.8 145.0 119.5 120.4 126.0 122.9 93.0 89.8 69.7 96.6 115.9
1000 SPRINGS 2013 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2013 ROR 26.8 21.1 14.9 40.3 73.2 81.6 88.6 66.9 35.4 12.8 0.0 0.0 38.5
BLISS 2013 ROR 54.9 50.3 42.6 46.1 38.8 40.0 45.0 46.8 45.6 44.6 41.0 40.6 44.7
C.J.STRIKE 2013 ROR 72.1 65.7 55.5 58.7 47.4 46.2 49.9 53.4 53.7 55.0 52.4 51.8 55.2
CASCADE 2013 ROR 1.2 1.2 1.2 1.3 4.1 10.3 14.6 13.9 11.0 1.2 1.2 1.2 5.2
CLEAR LAKE 2013 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2013 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2013 ROR 40.6 36.0 28.2 31.5 26.6 28.0 32.7 33.4 31.5 30.4 27.3 27.5 31.1
MILNER 2013 ROR 46.6 34.7 14.5 22.2 5.8 9.2 26.4 23.5 5.7 4.4 2.1 6.7 16.8
SHOSHONE FALLS 2013 ROR 64.0 54.0 28.0 37.0 19.0 23.0 44.0 41.0 19.0 16.0 12.9 18.0 31.3SWAN FALLS 2013 ROR 23.1 21.4 18.5 19.6 16.1 15.7 16.9 17.9 17.9 18.3 17.6 17.4 18.4
TWIN FALLS 2013 ROR 46.2 35.9 17.8 24.7 11.6 14.5 29.0 27.2 11.4 9.7 7.8 11.0 20.6
UPPER MALAD 2013 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&11 2013 ROR 19.0 19.1 18.3 19.2 17.1 17.9 19.2 19.1 19.2 19.2 17.2 17.4 18.5
UPPERSALMON 3&13 2013 ROR 17.7 17.7 16.9 17.7 15.8 16.2 17.7 17.7 17.7 17.7 15.9 16.1 17.1
HCC TOTAL 670.1 792.9 719.5 770.4 647.9 658.3 678.7 641.2 475.3 463.1 362.3 518.7 616.5
ROR TOTAL 441.4 386.3 285.6 347.5 304.7 331.8 413.2 390.0 297.3 258.5 224.6 236.9 326.5TOTAL 1111.5 1179.2 1005.1 1117.9 952.5 990.1 1091.9 1031.2 772.5 721.6 586.9 755.6 943.0
2004 Integrated Resource Plan - PDR580 Output Page 10 of 15 70W - 70L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
90th Percentile Water - 70th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
BROWNLEE 2004 HCC 220.2 294.8 230.0 222.3 215.8 177.1 248.9 228.2 129.9 158.3 157.9 202.3 207.1
HELLS CANYON 2004 HCC 180.0 236.4 198.4 192.1 184.9 153.0 206.1 202.2 120.9 142.9 137.9 167.6 176.9
OXBOW 2004 HCC 91.2 120.5 98.5 94.7 90.6 76.1 105.1 103.3 61.3 72.7 69.8 84.6 89.0
1000 SPRINGS 2004 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2004 ROR 10.6 10.9 11.7 36.3 66.3 73.3 76.2 55.0 13.8 9.2 0.0 0.0 30.3
BLISS 2004 ROR 43.3 42.7 38.6 37.3 36.3 36.7 40.6 42.0 40.8 41.0 38.8 37.7 39.7
C.J.STRIKE 2004 ROR 54.8 54.6 48.9 44.4 41.9 39.6 42.6 45.5 46.8 50.0 48.8 46.7 47.1
CASCADE 2004 ROR 1.2 1.2 1.2 1.2 1.5 5.4 12.0 11.4 7.6 1.3 1.2 1.1 3.9
CLEAR LAKE 2004 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2004 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2004 ROR 29.3 28.7 24.7 23.7 23.8 24.6 28.0 28.8 27.4 27.4 25.4 24.5 26.4MILNER2004ROR17.5 16.8 7.9 1.6 0.0 3.6 15.3 13.4 0.0 0.0 0.0 0.0 6.3
SHOSHONE FALLS 2004 ROR 12.0 12.0 12.0 10.7 10.1 12.0 12.0 12.0 10.7 10.0 9.9 11.1 11.2
SWAN FALLS 2004 ROR 18.1 18.1 16.4 15.4 14.5 14.1 14.8 15.3 15.5 16.5 16.2 15.8 15.9
TWIN FALLS 2004 ROR 21.0 20.2 11.0 6.8 6.3 9.1 19.6 18.5 6.9 6.2 6.2 7.2 11.6
UPPER MALAD 2004 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&2 2004 ROR 18.9 18.6 15.5 14.8 15.0 15.4 18.1 18.8 17.5 17.2 15.7 15.1 16.7
UPPERSALMON 3&4 2004 ROR 17.4 17.1 14.5 13.8 14.0 14.4 16.7 17.3 16.2 15.9 14.6 14.1 15.5
HCC TOTAL 491.4 651.7 526.9 509.1 491.2 406.2 560.1 533.7 312.1 373.9 365.6 454.5 473.0
ROR TOTAL 273.3 270.1 231.6 235.2 258.9 277.4 325.1 307.2 232.4 223.9 206.0 202.5 253.6
TOTAL 764.7 921.8 758.5 744.3 750.1 683.6 885.2 840.9 544.4 597.8 571.6 657.0 726.7
BROWNLEE 2005 HCC 224.7 288.4 230.0 222.3 215.8 177.1 248.9 228.2 129.9 158.3 157.9 202.3 207.0
HELLS CANYON 2005 HCC 184.1 231.9 198.4 192.1 184.9 153.0 206.1 202.2 120.9 142.9 137.9 167.6 176.8
OXBOW 2005 HCC 93.3 118.2 98.5 94.7 90.6 76.1 105.1 103.3 61.3 72.7 69.8 84.6 89.0
1000 SPRINGS 2005 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2005 ROR 10.6 10.9 11.7 36.3 66.3 73.3 76.2 55.0 13.8 9.2 0.0 0.0 30.3
BLISS 2005 ROR 43.3 42.7 38.6 37.3 36.3 36.7 40.6 42.0 40.8 41.0 38.8 37.7 39.7
C.J.STRIKE 2005 ROR 54.8 54.6 48.9 44.4 41.9 39.6 42.6 45.5 46.8 50.0 48.8 46.7 47.1
CASCADE 2005 ROR 1.2 1.2 1.2 1.2 1.5 5.4 12.0 11.4 7.6 1.3 1.2 1.1 3.9
CLEAR LAKE 2005 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2005 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2005 ROR 29.3 28.7 24.7 23.7 23.8 24.6 28.0 28.8 27.4 27.4 25.4 24.5 26.4
MILNER 2005 ROR 17.5 16.8 7.9 1.6 0.0 3.6 15.3 13.4 0.0 0.0 0.0 0.0 6.3
SHOSHONE FALLS 2005 ROR 12.0 12.0 12.0 10.7 10.1 12.0 12.0 12.0 10.7 10.0 9.9 11.1 11.2
SWAN FALLS 2005 ROR 18.1 18.1 16.4 15.4 14.5 14.1 14.8 15.3 15.5 16.5 16.2 15.8 15.9TWIN FALLS 2005 ROR 21.0 20.2 11.0 6.8 6.3 9.1 19.6 18.5 6.9 6.2 6.2 7.2 11.6
UPPER MALAD 2005 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&3 2005 ROR 18.9 18.6 15.5 14.8 15.0 15.4 18.1 18.8 17.5 17.2 15.7 15.1 16.7
UPPERSALMON 3&5 2005 ROR 17.4 17.1 14.5 13.8 14.0 14.4 16.7 17.3 16.2 15.9 14.6 14.1 15.5
HCC TOTAL 502.1 638.5 526.9 509.1 491.2 406.2 560.1 533.7 312.1 373.9 365.6 454.5 472.8
ROR TOTAL 273.3 270.1 231.6 235.2 258.9 277.4 325.1 307.2 232.4 223.9 206.0 202.5 253.6
TOTAL 775.4 908.6 758.5 744.3 750.1 683.6 885.2 840.9 544.4 597.8 571.6 657.0 726.4
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
2004 Integrated Resource Plan - PDR Output Page 11 of 15 90W - 70L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
90th Percentile Water - 70th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
BROWNLEE 2006 HCC 241.9 256.8 230.0 222.3 215.8 177.1 248.9 228.2 129.9 158.3 157.9 202.3 205.8
HELLS CANYON 2006 HCC 199.8 216.4 198.4 192.1 184.9 153.0 206.1 202.2 120.9 142.9 137.9 167.6 176.8
OXBOW 2006 HCC 101.4 109.4 98.5 94.7 90.6 76.1 105.1 103.3 61.3 72.7 69.8 84.6 89.01000 SPRINGS 2006 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2006 ROR 10.6 10.9 11.7 36.3 66.3 73.3 76.2 55.0 13.8 9.2 0.0 0.0 30.3
BLISS 2006 ROR 43.3 42.7 38.6 37.3 36.3 36.7 40.6 42.0 40.8 41.0 38.8 37.7 39.7
C.J.STRIKE 2006 ROR 54.8 54.6 48.9 44.4 41.9 39.6 42.6 45.5 46.8 50.0 48.8 46.7 47.1
CASCADE 2006 ROR 1.2 1.2 1.2 1.2 1.5 5.4 12.0 11.4 7.6 1.3 1.2 1.1 3.9
CLEAR LAKE 2006 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2006 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3LOWER SALMON 2006 ROR 29.3 28.7 24.7 23.7 23.8 24.6 28.0 28.8 27.4 27.4 25.4 24.5 26.4
MILNER 2006 ROR 17.5 16.8 7.9 1.6 0.0 3.6 15.3 13.4 0.0 0.0 0.0 0.0 6.3
SHOSHONE FALLS 2006 ROR 12.0 12.0 12.0 10.7 10.1 12.0 12.0 12.0 10.7 10.0 9.9 11.1 11.2
SWAN FALLS 2006 ROR 18.1 18.1 16.4 15.4 14.5 14.1 14.8 15.3 15.5 16.5 16.2 15.8 15.9
TWIN FALLS 2006 ROR 21.0 20.2 11.0 6.8 6.3 9.1 19.6 18.5 6.9 6.2 6.2 7.2 11.6
UPPER MALAD 2006 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&4 2006 ROR 18.9 18.6 15.5 14.8 15.0 15.4 18.1 18.8 17.5 17.2 15.7 15.1 16.7
UPPERSALMON 3&6 2006 ROR 17.4 17.1 14.5 13.8 14.0 14.4 16.7 17.3 16.2 15.9 14.6 14.1 15.5
HCC TOTAL 543.1 582.6 526.9 509.1 491.2 406.2 560.1 533.7 312.1 373.9 365.6 454.5 471.6
ROR TOTAL 273.3 270.1 231.6 235.2 258.9 277.4 325.1 307.2 232.4 223.9 206.0 202.5 253.6
TOTAL 816.4 852.7 758.5 744.3 750.1 683.6 885.2 840.9 544.4 597.8 571.6 657.0 725.2
BROWNLEE 2007 HCC 260.1 231.5 230.0 222.3 215.8 177.1 248.9 228.2 129.9 158.3 157.9 202.3 205.2
HELLS CANYON 2007 HCC 216.8 197.5 198.4 192.1 184.9 153.0 206.1 202.2 120.9 142.9 137.9 167.6 176.7
OXBOW 2007 HCC 110.2 99.6 98.5 94.7 90.6 76.1 105.1 103.3 61.3 72.7 69.8 84.6 88.9
1000 SPRINGS 2007 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2007 ROR 10.6 10.9 11.7 36.3 66.3 73.3 76.2 55.0 13.8 9.2 0.0 0.0 30.3
BLISS 2007 ROR 43.3 42.7 38.6 37.3 36.3 36.7 40.6 42.0 40.8 41.0 38.8 37.7 39.7
C.J.STRIKE 2007 ROR 54.8 54.6 48.9 44.4 41.9 39.6 42.6 45.5 46.8 50.0 48.8 46.7 47.1
CASCADE 2007 ROR 1.2 1.2 1.2 1.2 1.5 5.4 12.0 11.4 7.6 1.3 1.2 1.1 3.9
CLEAR LAKE 2007 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2007 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2007 ROR 29.3 28.7 24.7 23.7 23.8 24.6 28.0 28.8 27.4 27.4 25.4 24.5 26.4
MILNER 2007 ROR 17.5 16.8 7.9 1.6 0.0 3.6 15.3 13.4 0.0 0.0 0.0 0.0 6.3
SHOSHONE FALLS 2007 ROR 12.0 12.0 12.0 10.7 10.1 12.0 12.0 12.0 10.7 10.0 9.9 11.1 11.2SWAN FALLS 2007 ROR 18.1 18.1 16.4 15.4 14.5 14.1 14.8 15.3 15.5 16.5 16.2 15.8 15.9
TWIN FALLS 2007 ROR 21.0 20.2 11.0 6.8 6.3 9.1 19.6 18.5 6.9 6.2 6.2 7.2 11.6
UPPER MALAD 2007 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&5 2007 ROR 18.9 18.6 15.5 14.8 15.0 15.4 18.1 18.8 17.5 17.2 15.7 15.1 16.7
UPPERSALMON 3&7 2007 ROR 17.4 17.1 14.5 13.8 14.0 14.4 16.7 17.3 16.2 15.9 14.6 14.1 15.5
HCC TOTAL 587.1 528.6 526.9 509.1 491.2 406.2 560.1 533.7 312.1 373.9 365.6 454.5 470.7
ROR TOTAL 273.3 270.1 231.6 235.2 258.9 277.4 325.1 307.2 232.4 223.9 206.0 202.5 253.6TOTAL 860.4 798.7 758.5 744.3 750.1 683.6 885.2 840.9 544.4 597.8 571.6 657.0 724.4
2004 Integrated Resource Plan - PDR Output Page 12 of 15 90W - 70L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
90th Percentile Water - 70th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
BROWNLEE 2008 HCC 270.7 220.1 226.0 222.3 215.8 177.1 248.9 228.2 129.9 158.3 157.9 202.3 204.8
HELLS CANYON 2008 HCC 227.0 189.6 195.3 192.1 184.9 153.0 206.1 202.2 120.9 142.9 137.9 167.6 176.6
OXBOW 2008 HCC 115.4 95.5 97.0 94.7 90.6 76.1 105.1 103.3 61.3 72.7 69.8 84.6 88.81000 SPRINGS 2008 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2008 ROR 10.6 10.9 11.7 36.3 66.3 73.3 76.2 55.0 13.8 9.2 0.0 0.0 30.3
BLISS 2008 ROR 43.3 42.7 38.6 37.3 36.3 36.7 40.6 42.0 40.8 41.0 38.8 37.7 39.7
C.J.STRIKE 2008 ROR 54.8 54.6 48.9 44.4 41.9 39.6 42.6 45.5 46.8 50.0 48.8 46.7 47.1
CASCADE 2008 ROR 1.2 1.2 1.2 1.2 1.5 5.4 12.0 11.4 7.6 1.3 1.2 1.1 3.9
CLEAR LAKE 2008 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2008 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3LOWER SALMON 2008 ROR 29.3 28.7 24.7 23.7 23.8 24.6 28.0 28.8 27.4 27.4 25.4 24.5 26.4
MILNER 2008 ROR 17.5 16.8 7.9 1.6 0.0 3.6 15.3 13.4 0.0 0.0 0.0 0.0 6.3
SHOSHONE FALLS 2008 ROR 32.0 31.0 18.0 11.7 11.1 15.0 30.0 29.0 11.7 11.0 10.9 12.1 18.6
SWAN FALLS 2008 ROR 18.1 18.1 16.4 15.4 14.5 14.1 14.8 15.3 15.5 16.5 16.2 15.8 15.9
TWIN FALLS 2008 ROR 21.0 20.2 11.0 6.8 6.3 9.1 19.6 18.5 6.9 6.2 6.2 7.2 11.6
UPPER MALAD 2008 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&6 2008 ROR 18.9 18.6 15.5 14.8 15.0 15.4 18.1 18.8 17.5 17.2 15.7 15.1 16.7
UPPERSALMON 3&8 2008 ROR 17.4 17.1 14.5 13.8 14.0 14.4 16.7 17.3 16.2 15.9 14.6 14.1 15.5
HCC TOTAL 613.1 505.2 518.3 509.1 491.2 406.2 560.1 533.7 312.1 373.9 365.6 454.5 470.2
ROR TOTAL 293.3 289.1 237.6 236.2 259.9 280.4 343.1 324.2 233.4 224.9 207.0 203.5 261.0
TOTAL 906.4 794.3 755.9 745.3 751.1 686.6 903.2 857.9 545.4 598.8 572.6 658.0 731.3
BROWNLEE 2009 HCC 293.9 229.9 190.0 222.3 215.8 177.1 248.9 228.2 129.9 158.3 157.9 202.3 204.5
HELLS CANYON 2009 HCC 239.5 203.6 168.2 192.1 184.9 153.0 206.1 202.2 120.9 142.9 137.9 167.6 176.6
OXBOW 2009 HCC 122.7 102.8 83.0 94.7 90.6 76.1 105.1 103.3 61.3 72.7 69.8 84.6 88.9
1000 SPRINGS 2009 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2009 ROR 10.6 10.9 11.7 36.3 66.3 73.3 76.2 55.0 13.8 9.2 0.0 0.0 30.3
BLISS 2009 ROR 43.3 42.7 38.6 37.3 36.3 36.7 40.6 42.0 40.8 41.0 38.8 37.7 39.7
C.J.STRIKE 2009 ROR 54.8 54.6 48.9 44.4 41.9 39.6 42.6 45.5 46.8 50.0 48.8 46.7 47.1
CASCADE 2009 ROR 1.2 1.2 1.2 1.2 1.5 5.4 12.0 11.4 7.6 1.3 1.2 1.1 3.9
CLEAR LAKE 2009 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2009 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2009 ROR 29.3 28.7 24.7 23.7 23.8 24.6 28.0 28.8 27.4 27.4 25.4 24.5 26.4
MILNER 2009 ROR 17.5 16.8 7.9 1.6 0.0 3.6 15.3 13.4 0.0 0.0 0.0 0.0 6.3
SHOSHONE FALLS 2009 ROR 32.0 31.0 18.0 11.7 11.1 15.0 30.0 29.0 11.7 11.0 10.9 12.1 18.6SWAN FALLS 2009 ROR 18.1 18.1 16.4 15.4 14.5 14.1 14.8 15.3 15.5 16.5 16.2 15.8 15.9
TWIN FALLS 2009 ROR 21.0 20.2 11.0 6.8 6.3 9.1 19.6 18.5 6.9 6.2 6.2 7.2 11.6
UPPER MALAD 2009 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&7 2009 ROR 18.9 18.6 15.5 14.8 15.0 15.4 18.1 18.8 17.5 17.2 15.7 15.1 16.7
UPPERSALMON 3&9 2009 ROR 17.4 17.1 14.5 13.8 14.0 14.4 16.7 17.3 16.2 15.9 14.6 14.1 15.5
HCC TOTAL 656.1 536.3 441.2 509.1 491.2 406.2 560.1 533.7 312.1 373.9 365.6 454.5 470.0
ROR TOTAL 293.3 289.1 237.6 236.2 259.9 280.4 343.1 324.2 233.4 224.9 207.0 203.5 261.0TOTAL 949.4 825.4 678.8 745.3 751.1 686.6 903.2 857.9 545.4 598.8 572.6 658.0 731.0
2004 Integrated Resource Plan - PDR Output Page 13 of 15 90W - 70L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
90th Percentile Water - 70th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
BROWNLEE 2010 HCC 311.1 206.3 205.3 202.0 215.8 177.1 248.9 228.2 129.9 158.3 157.9 202.3 203.6
HELLS CANYON 2010 HCC 255.9 185.3 182.9 176.9 184.9 153.0 206.1 202.2 120.9 142.9 137.9 167.6 176.4
OXBOW 2010 HCC 131.1 93.3 90.6 86.9 90.6 76.1 105.1 103.3 61.3 72.7 69.8 84.6 88.81000 SPRINGS 2010 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2010 ROR 10.6 10.9 11.7 36.3 66.3 73.3 76.2 55.0 13.8 9.2 0.0 0.0 30.3
BLISS 2010 ROR 43.3 42.7 38.6 37.3 36.3 36.7 40.6 42.0 40.8 41.0 38.8 37.7 39.7
C.J.STRIKE 2010 ROR 54.8 54.6 48.9 44.4 41.9 39.6 42.6 45.5 46.8 50.0 48.8 46.7 47.1
CASCADE 2010 ROR 1.2 1.2 1.2 1.2 1.5 5.4 12.0 11.4 7.6 1.3 1.2 1.1 3.9
CLEAR LAKE 2010 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2010 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3LOWER SALMON 2010 ROR 29.3 28.7 24.7 23.7 23.8 24.6 28.0 28.8 27.4 27.4 25.4 24.5 26.4
MILNER 2010 ROR 17.5 16.8 7.9 1.6 0.0 3.6 15.3 13.4 0.0 0.0 0.0 0.0 6.3
SHOSHONE FALLS 2010 ROR 32.0 31.0 18.0 11.7 11.1 15.0 30.0 29.0 11.7 11.0 10.9 12.1 18.6
SWAN FALLS 2010 ROR 18.1 18.1 16.4 15.4 14.5 14.1 14.8 15.3 15.5 16.5 16.2 15.8 15.9
TWIN FALLS 2010 ROR 21.0 20.2 11.0 6.8 6.3 9.1 19.6 18.5 6.9 6.2 6.2 7.2 11.6
UPPER MALAD 2010 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&8 2010 ROR 18.9 18.6 15.5 14.8 15.0 15.4 18.1 18.8 17.5 17.2 15.7 15.1 16.7
UPPERSALMON 3&10 2010 ROR 17.4 17.1 14.5 13.8 14.0 14.4 16.7 17.3 16.2 15.9 14.6 14.1 15.5
HCC TOTAL 698.1 484.9 478.8 465.8 491.2 406.2 560.1 533.7 312.1 373.9 365.6 454.5 468.7
ROR TOTAL 293.3 289.1 237.6 236.2 259.9 280.4 343.1 324.2 233.4 224.9 207.0 203.5 261.0
TOTAL 991.4 774.0 716.4 702.0 751.1 686.6 903.2 857.9 545.4 598.8 572.6 658.0 729.8
BROWNLEE 2011 HCC 322.8 189.9 205.3 202.0 215.8 177.1 248.9 228.2 129.9 158.3 157.9 202.3 203.2
HELLS CANYON 2011 HCC 267.4 172.3 182.9 176.9 184.9 153.0 206.1 202.2 120.9 142.9 137.9 167.6 176.2
OXBOW 2011 HCC 137.0 86.7 90.6 86.9 90.6 76.1 105.1 103.3 61.3 72.7 69.8 84.6 88.7
1000 SPRINGS 2011 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2011 ROR 10.6 10.9 11.7 36.3 66.3 73.3 76.2 55.0 13.8 9.2 0.0 0.0 30.3
BLISS 2011 ROR 43.3 42.7 38.6 37.3 36.3 36.7 40.6 42.0 40.8 41.0 38.8 37.7 39.7
C.J.STRIKE 2011 ROR 54.8 54.6 48.9 44.4 41.9 39.6 42.6 45.5 46.8 50.0 48.8 46.7 47.1
CASCADE 2011 ROR 1.2 1.2 1.2 1.2 1.5 5.4 12.0 11.4 7.6 1.3 1.2 1.1 3.9
CLEAR LAKE 2011 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2011 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2011 ROR 29.3 28.7 24.7 23.7 23.8 24.6 28.0 28.8 27.4 27.4 25.4 24.5 26.4
MILNER 2011 ROR 17.5 16.8 7.9 1.6 0.0 3.6 15.3 13.4 0.0 0.0 0.0 0.0 6.3
SHOSHONE FALLS 2011 ROR 32.0 31.0 18.0 11.7 11.1 15.0 30.0 29.0 11.7 11.0 10.9 12.1 18.6SWAN FALLS 2011 ROR 18.1 18.1 16.4 15.4 14.5 14.1 14.8 15.3 15.5 16.5 16.2 15.8 15.9
TWIN FALLS 2011 ROR 21.0 20.2 11.0 6.8 6.3 9.1 19.6 18.5 6.9 6.2 6.2 7.2 11.6
UPPER MALAD 2011 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&9 2011 ROR 18.9 18.6 15.5 14.8 15.0 15.4 18.1 18.8 17.5 17.2 15.7 15.1 16.7
UPPERSALMON 3&11 2011 ROR 17.4 17.1 14.5 13.8 14.0 14.4 16.7 17.3 16.2 15.9 14.6 14.1 15.5
HCC TOTAL 727.2 448.9 478.8 465.8 491.2 406.2 560.1 533.7 312.1 373.9 365.6 454.5 468.2
ROR TOTAL 293.3 289.1 237.6 236.2 259.9 280.4 343.1 324.2 233.4 224.9 207.0 203.5 261.0TOTAL 1020.5 738.0 716.4 702.0 751.1 686.6 903.2 857.9 545.4 598.8 572.6 658.0 729.2
2004 Integrated Resource Plan - PDR Output Page 14 of 15 90W - 70L
2004 Integrated Resource Plan
Average Megawatt Hydro Output from PDR580
90th Percentile Water - 70th Percentile Load
Resource YEAR TYPE JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC AVE. MW
Abbreviations:
HCC - Hells Canyon Complex
ROR - Run of River
BROWNLEE 2012 HCC 322.8 189.9 205.3 202.0 215.8 177.1 248.9 228.2 129.9 158.3 157.9 202.3 203.2
HELLS CANYON 2012 HCC 267.4 172.3 182.9 176.9 184.9 153.0 206.1 202.2 120.9 142.9 137.9 167.6 176.2
OXBOW 2012 HCC 137.0 86.7 90.6 86.9 90.6 76.1 105.1 103.3 61.3 72.7 69.8 84.6 88.71000 SPRINGS 2012 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2012 ROR 10.6 10.9 11.7 36.3 66.3 73.3 76.2 55.0 13.8 9.2 0.0 0.0 30.3
BLISS 2012 ROR 43.3 42.7 38.6 37.3 36.3 36.7 40.6 42.0 40.8 41.0 38.8 37.7 39.7
C.J.STRIKE 2012 ROR 54.8 54.6 48.9 44.4 41.9 39.6 42.6 45.5 46.8 50.0 48.8 46.7 47.1
CASCADE 2012 ROR 1.2 1.2 1.2 1.2 1.5 5.4 12.0 11.4 7.6 1.3 1.2 1.1 3.9
CLEAR LAKE 2012 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2012 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3LOWER SALMON 2012 ROR 29.3 28.7 24.7 23.7 23.8 24.6 28.0 28.8 27.4 27.4 25.4 24.5 26.4
MILNER 2012 ROR 17.5 16.8 7.9 1.6 0.0 3.6 15.3 13.4 0.0 0.0 0.0 0.0 6.3
SHOSHONE FALLS 2012 ROR 32.0 31.0 18.0 11.7 11.1 15.0 30.0 29.0 11.7 11.0 10.9 12.1 18.6
SWAN FALLS 2012 ROR 18.1 18.1 16.4 15.4 14.5 14.1 14.8 15.3 15.5 16.5 16.2 15.8 15.9
TWIN FALLS 2012 ROR 21.0 20.2 11.0 6.8 6.3 9.1 19.6 18.5 6.9 6.2 6.2 7.2 11.6
UPPER MALAD 2012 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&10 2012 ROR 18.9 18.6 15.5 14.8 15.0 15.4 18.1 18.8 17.5 17.2 15.7 15.1 16.7
UPPERSALMON 3&12 2012 ROR 17.4 17.1 14.5 13.8 14.0 14.4 16.7 17.3 16.2 15.9 14.6 14.1 15.5
HCC TOTAL 727.2 448.9 478.8 465.8 491.2 406.2 560.1 533.7 312.1 373.9 365.6 454.5 468.2
ROR TOTAL 293.3 289.1 237.6 236.2 259.9 280.4 343.1 324.2 233.4 224.9 207.0 203.5 261.0
TOTAL 1020.5 738.0 716.4 702.0 751.1 686.6 903.2 857.9 545.4 598.8 572.6 658.0 729.2
BROWNLEE 2013 HCC 322.8 189.9 205.3 202.0 215.8 177.1 248.9 228.2 129.9 158.3 157.9 202.3 203.2
HELLS CANYON 2013 HCC 267.4 172.3 182.9 176.9 184.9 153.0 206.1 202.2 120.9 142.9 137.9 167.6 176.2
OXBOW 2013 HCC 137.0 86.7 90.6 86.9 90.6 76.1 105.1 103.3 61.3 72.7 69.8 84.6 88.7
1000 SPRINGS 2013 ROR 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6
AMERICAN FALLS 2013 ROR 10.6 10.9 11.7 36.3 66.3 73.3 76.2 55.0 13.8 9.2 0.0 0.0 30.3
BLISS 2013 ROR 43.3 42.7 38.6 37.3 36.3 36.7 40.6 42.0 40.8 41.0 38.8 37.7 39.7
C.J.STRIKE 2013 ROR 54.8 54.6 48.9 44.4 41.9 39.6 42.6 45.5 46.8 50.0 48.8 46.7 47.1
CASCADE 2013 ROR 1.2 1.2 1.2 1.2 1.5 5.4 12.0 11.4 7.6 1.3 1.2 1.1 3.9
CLEAR LAKE 2013 ROR 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
LOWER MALAD 2013 ROR 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3
LOWER SALMON 2013 ROR 29.3 28.7 24.7 23.7 23.8 24.6 28.0 28.8 27.4 27.4 25.4 24.5 26.4
MILNER 2013 ROR 17.5 16.8 7.9 1.6 0.0 3.6 15.3 13.4 0.0 0.0 0.0 0.0 6.3
SHOSHONE FALLS 2013 ROR 32.0 31.0 18.0 11.7 11.1 15.0 30.0 29.0 11.7 11.0 10.9 12.1 18.6SWAN FALLS 2013 ROR 18.1 18.1 16.4 15.4 14.5 14.1 14.8 15.3 15.5 16.5 16.2 15.8 15.9
TWIN FALLS 2013 ROR 21.0 20.2 11.0 6.8 6.3 9.1 19.6 18.5 6.9 6.2 6.2 7.2 11.6
UPPER MALAD 2013 ROR 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3
UPPERSALMON 1&11 2013 ROR 18.9 18.6 15.5 14.8 15.0 15.4 18.1 18.8 17.5 17.2 15.7 15.1 16.7
UPPERSALMON 3&13 2013 ROR 17.4 17.1 14.5 13.8 14.0 14.4 16.7 17.3 16.2 15.9 14.6 14.1 15.5
HCC TOTAL 727.2 448.9 478.8 465.8 491.2 406.2 560.1 533.7 312.1 373.9 365.6 454.5 468.2
ROR TOTAL 293.3 289.1 237.6 236.2 259.9 280.4 343.1 324.2 233.4 224.9 207.0 203.5 261.0TOTAL 1020.5 738.0 716.4 702.0 751.1 686.6 903.2 857.9 545.4 598.8 572.6 658.0 729.2
2004 Integrated Resource Plan - PDR Output Page 15 of 15 90W - 70L
Portfolio Bundles Analysis
IPC Portfolio Power Supply Costs: Portfolios 0 to 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Portfolio Scenarios
Scenario #1 Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Scenario #2 Oregon CO2 emission costs set at $49.21/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Scenario #3 Oregon CO2 emission costs set at $0.00/ton
Wind PTC set to $-19.00/MWh, not escalated
Scenario #4 Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $0.00/MWh
Portfolio Bundles Analysis
IPC Portfolio Power Supply Costs: Portfolios 0 to 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $0.00/ton
Wind PTC set to $-19.00/MWh, not escalated
Portfolio Power Supply Cost ($ x 1000)
Year P0 - Balanced 0 P1 - Peakers P2 - Coal
P3 - Wind and
Peakers P4 - Balanced 1 P5 - Early Coal P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4 P9 - Balanced 5
P10 - Balanced
6
P11 - Balanced
7
2004 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$
2005 333,719$ 333,719$ 333,719$ 333,719$ 341,086$ 333,719$ 341,086$ 341,086$ 341,086$ 341,523$ 341,523$ 341,086$
2006 368,829$ 373,343$ 373,343$ 368,075$ 371,676$ 359,822$ 371,676$ 371,676$ 361,516$ 371,794$ 371,794$ 371,676$
2007 377,050$ 374,271$ 374,271$ 383,376$ 380,750$ 379,249$ 374,158$ 374,158$ 392,176$ 373,891$ 373,891$ 373,311$
2008 401,975$ 404,002$ 394,490$ 412,058$ 404,704$ 386,249$ 395,741$ 406,693$ 399,856$ 406,910$ 406,910$ 405,939$
2009 420,603$ 410,945$ 445,281$ 426,960$ 418,918$ 384,221$ 415,073$ 403,228$ 422,805$ 403,638$ 403,638$ 402,513$
2010 422,009$ 434,829$ 440,564$ 425,074$ 424,984$ 385,560$ 412,508$ 430,306$ 416,913$ 431,373$ 430,369$ 421,032$
2011 426,456$ 439,192$ 420,315$ 410,829$ 435,027$ 376,426$ 392,026$ 417,821$ 396,093$ 417,978$ 419,980$ 409,734$
2012 430,909$ 460,447$ 424,752$ 418,471$ 450,432$ 397,930$ 400,216$ 422,552$ 394,877$ 424,125$ 425,881$ 409,671$
2013 431,594$ 457,741$ 405,757$ 393,835$ 429,386$ 372,845$ 380,199$ 390,982$ 377,136$ 401,635$ 413,179$ 386,281$
2014 431,423$ 472,388$ 414,973$ 401,788$ 449,591$ 380,350$ 395,342$ 394,144$ 382,195$ 402,807$ 417,360$ 382,996$
2015 462,546$ 510,221$ 441,954$ 424,422$ 475,052$ 412,842$ 408,460$ 404,554$ 399,597$ 433,963$ 442,579$ 397,923$
2016 485,917$ 510,980$ 456,801$ 436,305$ 486,295$ 437,334$ 420,391$ 411,965$ 418,862$ 445,254$ 460,143$ 409,608$
2017 545,754$ 570,073$ 503,328$ 493,995$ 536,104$ 499,451$ 465,128$ 487,690$ 481,191$ 510,817$ 527,911$ 459,891$
2018 543,212$ 566,126$ 496,705$ 478,849$ 526,806$ 495,793$ 460,809$ 471,346$ 468,836$ 502,562$ 519,506$ 447,399$
2019 576,525$ 603,228$ 522,661$ 505,752$ 559,806$ 527,157$ 485,609$ 497,681$ 503,193$ 529,876$ 554,596$ 472,459$ 2020 633,810$ 673,296$ 583,682$ 561,232$ 570,094$ 579,178$ 549,588$ 539,209$ 550,324$ 585,685$ 604,373$ 519,655$
2021 655,186$ 705,222$ 614,228$ 580,714$ 602,399$ 604,033$ 581,266$ 551,292$ 572,144$ 605,044$ 626,663$ 544,365$
2022 672,471$ 712,701$ 622,073$ 582,355$ 637,205$ 620,340$ 587,834$ 570,862$ 589,940$ 623,163$ 646,638$ 549,514$
2023 707,842$ 751,034$ 653,142$ 612,621$ 668,619$ 651,412$ 618,785$ 593,158$ 617,771$ 657,481$ 686,685$ 573,733$
2024 751,740$ 803,066$ 691,324$ 638,516$ 708,548$ 694,218$ 660,519$ 627,193$ 656,527$ 697,030$ 730,987$ 597,100$
2025 799,624$ 863,796$ 757,528$ 688,603$ 802,262$ 742,508$ 723,536$ 669,145$ 702,462$ 743,057$ 783,747$ 647,332$ 2026 858,297$ 933,683$ 833,664$ 740,780$ 874,731$ 799,936$ 800,486$ 710,631$ 758,496$ 798,842$ 842,497$ 699,835$
2027 935,250$ 1,036,869$ 929,569$ 820,795$ 982,860$ 876,621$ 901,297$ 756,339$ 826,077$ 874,041$ 904,768$ 786,715$
2028 1,022,113$ 1,142,626$ 1,027,916$ 902,237$ 1,084,451$ 962,354$ 999,295$ 834,549$ 906,962$ 956,333$ 994,276$ 864,535$
2029 1,093,208$ 1,218,902$ 1,110,733$ 952,213$ 1,162,700$ 1,032,216$ 1,086,633$ 874,484$ 967,290$ 1,024,084$ 1,057,615$ 918,171$
2030 1,190,347$ 1,324,741$ 1,221,491$ 1,032,638$ 1,267,659$ 1,126,546$ 1,201,515$ 944,199$ 1,055,018$ 1,116,664$ 1,150,077$ 1,001,164$
2031 1,299,033$ 1,441,885$ 1,348,401$ 1,125,372$ 1,394,592$ 1,232,154$ 1,335,869$ 1,017,983$ 1,153,517$ 1,221,701$ 1,248,852$ 1,099,721$
2032 1,457,528$ 1,614,609$ 1,517,708$ 1,265,710$ 1,565,047$ 1,388,662$ 1,509,469$ 1,138,263$ 1,302,379$ 1,376,270$ 1,399,018$ 1,249,976$
2033 1,714,400$ 1,848,583$ 1,773,569$ 1,549,144$ 1,832,287$ 1,618,169$ 1,737,802$ 1,398,249$ 1,581,440$ 1,623,554$ 1,614,414$ 1,518,338$
Total 20,769,596$ 22,312,745$ 20,454,166$ 18,686,665$ 21,164,293$ 19,377,522$ 19,732,540$ 17,771,665$ 18,716,905$ 19,621,323$ 20,120,097$ 17,981,897$
Discount Rate: 7.2002%
30-Year PV 6,666,696$ 7,023,974$ 6,535,652$ 6,191,268$ 6,721,927$ 6,228,641$ 6,292,782$ 6,008,835$ 6,144,382$ 6,382,743$ 6,511,280$ 5,986,528$
Levelized 567,481$ 597,893$ 556,326$ 527,011$ 572,182$ 530,193$ 535,652$ 511,482$ 523,020$ 543,310$ 554,251$ 509,584$
30-Year PV Rank 10 12 9 4 11 5 6 2 3 7 8 1
20-Year PV 4,770,839$ 4,941,182$ 4,637,857$ 4,538,569$ 4,743,631$ 4,446,173$ 4,442,532$ 4,474,487$ 4,459,173$ 4,606,811$ 4,679,060$ 4,395,813$
Levelized 473,545$ 490,453$ 460,346$ 450,490$ 470,845$ 441,319$ 440,958$ 444,130$ 442,610$ 457,264$ 464,435$ 436,321$
20-Year PV Rank 11 12 8 6 10 3 2 5 4 7 9 1
10-Year PV 2,779,779$ 2,821,871$ 2,784,161$ 2,762,096$ 2,809,208$ 2,636,103$ 2,708,176$ 2,752,685$ 2,722,727$ 2,760,553$ 2,768,039$ 2,730,716$
Levelized 413,580$ 419,842$ 414,232$ 410,949$ 417,958$ 392,204$ 402,927$ 409,549$ 405,092$ 410,719$ 411,833$ 406,280$
10-Year PV Rank 9 12 10 7 11 1 2 5 3 6 8 4
Page 1 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Bundles Analysis
IPC Portfolio Power Supply Costs: Portfolios 0 to 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $0.00/ton
Wind PTC set to $-19.00/MWh, not escalated
Difference in Portfolio Power Supply Costs (Scenario - Base Case) ($ x 1000)
Year P0 - Balanced 0 P1 - Peakers P2 - Coal
P3 - Wind and
Peakers P4 - Balanced 1 P5 - Early Coal P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4 P9 - Balanced 5
P10 - Balanced
6
P11 - Balanced
7
2004 -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$
2005 -$ -$ -$ 7,367$ -$ 7,367$ 7,367$ 7,367$ 7,804$ 7,804$ 7,367$ 2006 4,514$ 4,514$ (754)$ 2,846$ (9,007)$ 2,846$ 2,846$ (7,314)$ 2,964$ 2,964$ 2,846$
2007 (2,779)$ (2,779)$ 6,326$ 3,700$ 2,199$ (2,892)$ (2,892)$ 15,126$ (3,159)$ (3,159)$ (3,739)$
2008 2,028$ (7,485)$ 10,084$ 2,730$ (15,726)$ (6,234)$ 4,719$ (2,119)$ 4,935$ 4,935$ 3,964$
2009 (9,659)$ 24,678$ 6,357$ (1,686)$ (36,382)$ (5,530)$ (17,375)$ 2,202$ (16,965)$ (16,965)$ (18,090)$
2010 12,820$ 18,555$ 3,064$ 2,975$ (36,449)$ (9,501)$ 8,297$ (5,096)$ 9,364$ 8,360$ (978)$
2011 12,737$ (6,140)$ (15,627)$ 8,572$ (50,029)$ (34,430)$ (8,634)$ (30,362)$ (8,477)$ (6,475)$ (16,721)$
2012 29,538$ (6,157)$ (12,438)$ 19,523$ (32,979)$ (30,693)$ (8,357)$ (36,032)$ (6,784)$ (5,028)$ (21,238)$
2013 26,147$ (25,837)$ (37,759)$ (2,208)$ (58,749)$ (51,395)$ (40,612)$ (54,458)$ (29,959)$ (18,415)$ (45,313)$
2014 40,965$ (16,450)$ (29,635)$ 18,168$ (51,073)$ (36,081)$ (37,279)$ (49,227)$ (28,616)$ (14,063)$ (48,426)$
2015 47,675$ (20,592)$ (38,124)$ 12,506$ (49,704)$ (54,086)$ (57,992)$ (62,949)$ (28,583)$ (19,967)$ (64,623)$
2016 25,063$ (29,116)$ (49,612)$ 377$ (48,583)$ (65,526)$ (73,952)$ (67,056)$ (40,663)$ (25,774)$ (76,309)$
2017 24,319$ (42,426)$ (51,759)$ (9,650)$ (46,303)$ (80,626)$ (58,063)$ (64,563)$ (34,937)$ (17,843)$ (85,863)$
2018 22,914$ (46,507)$ (64,363)$ (16,406)$ (47,419)$ (82,403)$ (71,866)$ (74,376)$ (40,650)$ (23,706)$ (95,813)$
2019 26,702$ (53,865)$ (70,773)$ (16,720)$ (49,368)$ (90,916)$ (78,845)$ (73,333)$ (46,650)$ (21,930)$ (104,067)$
2020 39,487$ (50,128)$ (72,577)$ (63,716)$ (54,632)$ (84,221)$ (94,600)$ (83,486)$ (48,124)$ (29,437)$ (114,155)$
2021 50,036$ (40,958)$ (74,472)$ (52,787)$ (51,153)$ (73,920)$ (103,894)$ (83,042)$ (50,142)$ (28,523)$ (110,821)$
2022 40,230$ (50,399)$ (90,116)$ (35,267)$ (52,131)$ (84,638)$ (101,610)$ (82,532)$ (49,309)$ (25,834)$ (122,958)$
2023 43,192$ (54,700)$ (95,221)$ (39,223)$ (56,430)$ (89,057)$ (114,684)$ (90,071)$ (50,361)$ (21,157)$ (134,109)$
2024 51,326$ (60,417)$ (113,224)$ (43,193)$ (57,522)$ (91,222)$ (124,548)$ (95,213)$ (54,710)$ (20,754)$ (154,640)$ 2025 64,172$ (42,096)$ (111,021)$ 2,638$ (57,116)$ (76,088)$ (130,479)$ (97,162)$ (56,567)$ (15,877)$ (152,292)$
2026 75,386$ (24,633)$ (117,517)$ 16,434$ (58,361)$ (57,811)$ (147,665)$ (99,801)$ (59,454)$ (15,800)$ (158,462)$
2027 101,619$ (5,681)$ (114,455)$ 47,610$ (58,629)$ (33,953)$ (178,911)$ (109,173)$ (61,209)$ (30,482)$ (148,535)$
2028 120,513$ 5,803$ (119,876)$ 62,338$ (59,759)$ (22,818)$ (187,564)$ (115,151)$ (65,780)$ (27,837)$ (157,577)$
2029 125,694$ 17,525$ (140,995)$ 69,492$ (60,993)$ (6,575)$ (218,724)$ (125,918)$ (69,124)$ (35,593)$ (175,037)$
2030 134,394$ 31,144$ (157,709)$ 77,312$ (63,801)$ 11,168$ (246,148)$ (135,329)$ (73,683)$ (40,270)$ (189,183)$ 2031 142,852$ 49,368$ (173,660)$ 95,560$ (66,879)$ 36,836$ (281,050)$ (145,516)$ (77,332)$ (50,180)$ (199,312)$
2032 157,081$ 60,180$ (191,817)$ 107,519$ (68,866)$ 51,942$ (319,265)$ (155,149)$ (81,258)$ (58,509)$ (207,552)$
2033 134,184$ 59,170$ (165,256)$ 117,887$ (96,231)$ 23,402$ (316,151)$ (132,960)$ (90,846)$ (99,985)$ (196,062)$
Total 1,543,150$ (315,430)$ (2,082,931)$ 394,698$ (1,392,073)$ (1,037,056)$ (2,997,930)$ (2,052,691)$ (1,148,273)$ (649,499)$ (2,787,699)$
Discount Rate: 7.2002%30-Year PV 357,278$ (131,044)$ (475,428)$ 55,231$ (438,055)$ (373,914)$ (657,862)$ (522,314)$ (283,954)$ (155,416)$ (680,168)$
Levelized 30,412$ (11,155)$ (40,469)$ 4,701$ (37,288)$ (31,828)$ (55,998)$ (44,460)$ (24,171)$ (13,229)$ (57,897)$
30-Year PV Rank 11 9 4 10 5 6 2 3 7 8 1
20-Year PV 170,342$ (132,982)$ (232,271)$ (27,208)$ (324,666)$ (328,307)$ (296,353)$ (311,666)$ (164,028)$ (91,779)$ (375,026)$
Levelized 16,908$ (13,200)$ (23,055)$ (2,701)$ (32,226)$ (32,587)$ (29,415)$ (30,935)$ (16,281)$ (9,110)$ (37,224)$
20-Year PV Rank 11 8 6 10 3 2 5 4 7 9 1
10-Year PV 42,093$ 4,383$ (17,683)$ 29,429$ (143,675)$ (71,603)$ (27,093)$ (57,051)$ (19,226)$ (11,740)$ (49,063)$
Levelized 6,263$ 652$ (2,631)$ 4,379$ (21,376)$ (10,653)$ (4,031)$ (8,488)$ (2,860)$ (1,747)$ (7,300)$
10-Year PV Rank 11 9 7 10 1 2 5 3 6 8 4
Notes:All values are averaged over all hours of simulation.
Base case includes all existing and committed resources as of January 1, 2004.
All costs nominal. AURORAxmp hydro modeling modified June 2004.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-21-2004
Page 2 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Bundles Analysis
IPC Portfolio Power Supply Costs: Portfolios 0 to 11 Comparison
NPV Comparison of Portfolio Differences (Portfolio - Balanced 0)
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $0.00/ton
Wind PTC set to $-19.00/MWh, not escalated
-$1,000
-$900
-$800
-$700
-$600
-$500
-$400
-$300
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
2
0
0
4
2
0
0
5
2
0
0
6
2
0
0
7
2
0
0
8
2
0
0
9
2
0
1
0
2
0
1
1
2
0
1
2
2
0
1
3
2
0
1
4
2
0
1
5
2
0
1
6
2
0
1
7
2
0
1
8
2
0
1
9
2
0
2
0
2
0
2
1
2
0
2
2
2
0
2
3
2
0
2
4
2
0
2
5
2
0
2
6
2
0
2
7
2
0
2
8
2
0
2
9
2
0
3
0
2
0
3
1
2
0
3
2
2
0
3
3
P1 - Peakers
P2 - Coal
P3 - Wind and Peakers
P4 - Balanced 1
P5 - Early Coal
P6 - Balanced 2
P7 - Balanced 3
P8 - Balanced 4
P9 - Balanced 5
P10 - Balanced 6
P11 - Balanced 7
Page 3 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Bundles Analysis
IPC Portfolio Power Supply Costs: Portfolios 0 to 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Portfolio Power Supply Cost ($ x 1000)
Year P0 - Balanced 0 P1 - Peakers P2 - Coal
P3 - Wind and
Peakers P4 - Balanced 1 P5 - Early Coal P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4 P9 - Balanced 5
P10 - Balanced
6
P11 - Balanced
7
2004 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$
2005 333,719$ 333,719$ 333,719$ 333,719$ 341,086$ 333,719$ 341,086$ 341,086$ 341,086$ 341,523$ 341,523$ 341,086$
2006 368,829$ 373,343$ 373,343$ 368,075$ 371,676$ 359,822$ 371,676$ 371,676$ 361,516$ 371,794$ 371,794$ 371,676$
2007 377,050$ 374,271$ 374,271$ 383,376$ 380,750$ 379,249$ 374,158$ 374,158$ 392,176$ 373,891$ 373,891$ 373,311$
2008 497,670$ 506,212$ 496,471$ 502,106$ 499,923$ 515,282$ 488,778$ 497,092$ 506,415$ 497,938$ 497,938$ 496,337$
2009 531,069$ 518,151$ 574,445$ 516,009$ 519,279$ 520,160$ 523,982$ 497,894$ 544,939$ 498,425$ 498,425$ 497,179$
2010 539,583$ 548,591$ 576,736$ 514,532$ 530,515$ 528,186$ 527,548$ 543,212$ 546,574$ 544,066$ 537,366$ 519,937$
2011 544,179$ 554,741$ 563,207$ 500,350$ 541,829$ 522,576$ 508,311$ 535,038$ 533,024$ 536,003$ 529,524$ 521,266$
2012 555,247$ 584,178$ 575,762$ 516,249$ 573,253$ 556,010$ 523,889$ 541,147$ 532,636$ 544,301$ 543,437$ 530,230$
2013 551,414$ 581,484$ 559,683$ 495,940$ 557,590$ 546,558$ 507,664$ 536,963$ 523,953$ 529,878$ 519,564$ 497,129$
2014 562,842$ 602,677$ 575,005$ 513,217$ 578,020$ 560,382$ 529,373$ 534,258$ 526,787$ 544,219$ 540,987$ 514,448$
2015 609,256$ 652,096$ 610,378$ 549,075$ 612,448$ 603,864$ 551,691$ 561,256$ 561,380$ 575,635$ 576,297$ 535,249$
2016 625,815$ 656,377$ 630,902$ 558,928$ 622,286$ 634,207$ 569,910$ 583,811$ 583,845$ 604,032$ 600,833$ 552,767$
2017 694,657$ 722,725$ 680,375$ 622,723$ 684,972$ 704,688$ 619,102$ 655,947$ 650,952$ 666,991$ 666,423$ 612,262$
2018 699,452$ 727,014$ 683,905$ 609,053$ 684,159$ 706,912$ 620,962$ 647,848$ 652,148$ 667,463$ 670,092$ 600,402$
2019 739,065$ 769,377$ 717,364$ 642,989$ 718,746$ 747,017$ 653,605$ 685,535$ 689,839$ 705,702$ 715,276$ 636,731$ 2020 788,540$ 831,615$ 770,384$ 691,188$ 732,198$ 790,313$ 705,640$ 717,430$ 732,318$ 751,630$ 762,214$ 679,463$
2021 819,552$ 873,487$ 808,101$ 715,340$ 774,267$ 823,429$ 747,694$ 738,178$ 757,343$ 779,867$ 787,495$ 699,795$
2022 857,189$ 902,822$ 839,725$ 742,596$ 822,030$ 865,969$ 776,148$ 776,486$ 797,425$ 816,746$ 831,852$ 732,020$
2023 900,126$ 953,986$ 878,932$ 775,348$ 863,733$ 908,287$ 814,732$ 810,913$ 836,864$ 859,607$ 877,055$ 759,584$
2024 956,429$ 1,008,478$ 926,697$ 814,475$ 908,658$ 958,754$ 864,078$ 852,744$ 888,538$ 908,695$ 932,124$ 796,138$
2025 1,008,714$ 1,076,152$ 999,626$ 868,470$ 1,009,282$ 1,014,984$ 933,682$ 898,621$ 939,151$ 962,272$ 985,053$ 851,903$ 2026 1,078,349$ 1,158,620$ 1,084,791$ 928,637$ 1,089,178$ 1,084,260$ 1,022,543$ 948,391$ 1,003,277$ 1,028,748$ 1,053,673$ 913,603$
2027 1,159,219$ 1,271,679$ 1,193,383$ 1,017,448$ 1,209,575$ 1,166,276$ 1,131,313$ 1,005,727$ 1,079,919$ 1,108,033$ 1,129,239$ 1,007,358$
2028 1,253,880$ 1,380,961$ 1,298,550$ 1,106,489$ 1,316,504$ 1,262,997$ 1,235,249$ 1,084,201$ 1,167,954$ 1,196,204$ 1,219,941$ 1,094,413$
2029 1,333,562$ 1,465,273$ 1,388,564$ 1,162,912$ 1,402,066$ 1,341,903$ 1,328,994$ 1,137,653$ 1,237,076$ 1,274,689$ 1,295,035$ 1,154,207$
2030 1,439,221$ 1,580,207$ 1,508,478$ 1,250,929$ 1,515,234$ 1,446,640$ 1,452,257$ 1,216,755$ 1,335,505$ 1,375,888$ 1,397,215$ 1,245,148$
2031 1,557,503$ 1,707,334$ 1,645,478$ 1,352,454$ 1,651,962$ 1,563,240$ 1,595,238$ 1,300,869$ 1,441,652$ 1,490,733$ 1,506,378$ 1,353,865$
2032 1,725,025$ 1,890,775$ 1,826,040$ 1,502,253$ 1,832,050$ 1,731,132$ 1,777,775$ 1,431,994$ 1,601,554$ 1,654,784$ 1,668,706$ 1,513,152$
2033 1,993,717$ 2,136,027$ 2,091,805$ 1,797,295$ 2,108,810$ 1,971,009$ 2,019,749$ 1,700,526$ 1,890,019$ 1,914,649$ 1,894,293$ 1,789,387$
Total 25,421,098$ 27,062,598$ 25,906,348$ 22,672,398$ 25,772,306$ 25,468,053$ 24,437,048$ 22,847,633$ 23,976,089$ 24,444,631$ 24,643,870$ 22,510,269$
Discount Rate: 7.2002%
30-Year PV 8,063,729$ 8,442,614$ 8,181,855$ 7,373,879$ 8,095,173$ 8,064,263$ 7,703,435$ 7,509,719$ 7,727,309$ 7,814,839$ 7,849,474$ 7,332,765$
Levelized 686,398$ 718,650$ 696,453$ 627,677$ 689,075$ 686,444$ 655,730$ 639,240$ 657,762$ 665,212$ 668,161$ 624,178$
30-Year PV Rank 8 12 11 2 10 9 4 3 5 6 7 1
20-Year PV 5,748,583$ 5,929,955$ 5,799,894$ 5,355,223$ 5,700,702$ 5,741,516$ 5,430,350$ 5,516,769$ 5,571,208$ 5,602,203$ 5,603,972$ 5,331,247$
Levelized 570,594$ 588,597$ 575,687$ 531,550$ 565,842$ 569,893$ 539,007$ 547,585$ 552,988$ 556,065$ 556,241$ 529,170$
20-Year PV Rank 10 12 11 2 8 9 3 4 5 6 7 1
10-Year PV 3,200,589$ 3,243,196$ 3,281,492$ 3,105,670$ 3,212,120$ 3,178,019$ 3,127,095$ 3,165,906$ 3,199,916$ 3,166,373$ 3,152,457$ 3,114,590$
Levelized 476,189$ 482,528$ 488,225$ 462,066$ 477,904$ 472,831$ 465,254$ 471,028$ 476,088$ 471,098$ 469,027$ 463,394$
10-Year PV Rank 9 11 12 1 10 7 3 5 8 6 4 2
Page 4 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Bundles Analysis
IPC Portfolio Power Supply Costs: Portfolios 0 to 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Difference in Portfolio Power Supply Costs (Scenario - Base Case) ($ x 1000)
Year P0 - Balanced 0 P1 - Peakers P2 - Coal
P3 - Wind and
Peakers P4 - Balanced 1 P5 - Early Coal P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4 P9 - Balanced 5
P10 - Balanced
6
P11 - Balanced
7
2004 -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$
2005 -$ -$ -$ 7,367$ -$ 7,367$ 7,367$ 7,367$ 7,804$ 7,804$ 7,367$ 2006 4,514$ 4,514$ (754)$ 2,846$ (9,007)$ 2,846$ 2,846$ (7,314)$ 2,964$ 2,964$ 2,846$
2007 (2,779)$ (2,779)$ 6,326$ 3,700$ 2,199$ (2,892)$ (2,892)$ 15,126$ (3,159)$ (3,159)$ (3,739)$
2008 8,543$ (1,198)$ 4,436$ 2,253$ 17,613$ (8,892)$ (578)$ 8,746$ 268$ 268$ (1,332)$
2009 (12,919)$ 43,376$ (15,061)$ (11,790)$ (10,909)$ (7,088)$ (33,175)$ 13,870$ (32,645)$ (32,645)$ (33,891)$
2010 9,008$ 37,153$ (25,050)$ (9,067)$ (11,396)$ (12,035)$ 3,630$ 6,991$ 4,483$ (2,217)$ (19,646)$
2011 10,562$ 19,028$ (43,829)$ (2,350)$ (21,602)$ (35,867)$ (9,140)$ (11,155)$ (8,176)$ (14,654)$ (22,912)$
2012 28,930$ 20,515$ (38,999)$ 18,006$ 763$ (31,358)$ (14,100)$ (22,611)$ (10,947)$ (11,810)$ (25,018)$
2013 30,070$ 8,270$ (55,474)$ 6,176$ (4,855)$ (43,750)$ (14,451)$ (27,460)$ (21,536)$ (31,849)$ (54,285)$
2014 39,835$ 12,163$ (49,625)$ 15,179$ (2,459)$ (33,469)$ (28,584)$ (36,055)$ (18,623)$ (21,855)$ (48,394)$
2015 42,841$ 1,123$ (60,180)$ 3,193$ (5,392)$ (57,564)$ (48,000)$ (47,876)$ (33,620)$ (32,958)$ (74,007)$
2016 30,561$ 5,087$ (66,888)$ (3,529)$ 8,391$ (55,906)$ (42,005)$ (41,971)$ (21,783)$ (24,983)$ (73,048)$
2017 28,068$ (14,283)$ (71,934)$ (9,685)$ 10,031$ (75,556)$ (38,711)$ (43,705)$ (27,667)$ (28,235)$ (82,395)$
2018 27,562$ (15,547)$ (90,399)$ (15,292)$ 7,460$ (78,490)$ (51,604)$ (47,304)$ (31,989)$ (29,360)$ (99,050)$
2019 30,312$ (21,700)$ (96,076)$ (20,319)$ 7,952$ (85,460)$ (53,530)$ (49,226)$ (33,363)$ (23,788)$ (102,334)$
2020 43,075$ (18,156)$ (97,352)$ (56,343)$ 1,772$ (82,901)$ (71,110)$ (56,222)$ (36,910)$ (26,326)$ (109,077)$
2021 53,934$ (11,451)$ (104,212)$ (45,285)$ 3,877$ (71,858)$ (81,374)$ (62,209)$ (39,685)$ (32,057)$ (119,757)$
2022 45,634$ (17,463)$ (114,593)$ (35,158)$ 8,780$ (81,041)$ (80,703)$ (59,764)$ (40,442)$ (25,336)$ (125,168)$
2023 53,860$ (21,194)$ (124,778)$ (36,393)$ 8,161$ (85,394)$ (89,213)$ (63,262)$ (40,520)$ (23,071)$ (140,542)$
2024 52,049$ (29,731)$ (141,954)$ (47,771)$ 2,325$ (92,351)$ (103,685)$ (67,891)$ (47,734)$ (24,305)$ (160,291)$ 2025 67,438$ (9,088)$ (140,244)$ 567$ 6,270$ (75,033)$ (110,093)$ (69,564)$ (46,442)$ (23,662)$ (156,812)$
2026 80,270$ 6,441$ (149,713)$ 10,829$ 5,911$ (55,806)$ (129,959)$ (75,073)$ (49,601)$ (24,676)$ (164,747)$
2027 112,460$ 34,164$ (141,771)$ 50,356$ 7,057$ (27,906)$ (153,492)$ (79,301)$ (51,186)$ (29,980)$ (151,861)$
2028 127,081$ 44,671$ (147,391)$ 62,624$ 9,118$ (18,630)$ (169,679)$ (85,925)$ (57,676)$ (33,938)$ (159,467)$
2029 131,712$ 55,002$ (170,649)$ 68,505$ 8,341$ (4,568)$ (195,908)$ (96,485)$ (58,872)$ (38,527)$ (179,355)$
2030 140,986$ 69,257$ (188,292)$ 76,014$ 7,419$ 13,036$ (222,466)$ (103,715)$ (63,333)$ (42,005)$ (194,073)$ 2031 149,831$ 87,975$ (205,050)$ 94,459$ 5,737$ 37,734$ (256,634)$ (115,851)$ (66,771)$ (51,126)$ (203,638)$
2032 165,750$ 101,015$ (222,772)$ 107,025$ 6,107$ 52,751$ (293,031)$ (123,471)$ (70,241)$ (56,318)$ (211,873)$
2033 142,311$ 98,089$ (196,422)$ 115,093$ (22,708)$ 26,032$ (293,191)$ (103,698)$ (79,068)$ (99,423)$ (204,330)$
Total 1,641,500$ 485,250$ (2,748,700)$ 351,208$ 46,955$ (984,050)$ (2,573,465)$ (1,445,009)$ (976,467)$ (777,228)$ (2,910,829)$
Discount Rate: 7.2002%30-Year PV 378,885$ 118,126$ (689,850)$ 31,444$ 534$ (360,294)$ (554,010)$ (336,420)$ (248,890)$ (214,256)$ (730,964)$
Levelized 32,251$ 10,055$ (58,721)$ 2,677$ 45$ (30,669)$ (47,158)$ (28,637)$ (21,186)$ (18,238)$ (62,221)$
30-Year PV Rank 11 10 2 9 8 4 3 5 6 7 1
20-Year PV 181,372$ 51,311$ (393,360)$ (47,881)$ (7,067)$ (318,233)$ (231,814)$ (177,375)$ (146,380)$ (144,611)$ (417,336)$
Levelized 18,003$ 5,093$ (39,044)$ (4,753)$ (701)$ (31,587)$ (23,009)$ (17,606)$ (14,529)$ (14,354)$ (41,424)$
20-Year PV Rank 11 10 2 8 9 3 4 5 6 7 1
10-Year PV 42,607$ 80,903$ (94,919)$ 11,531$ (22,570)$ (73,495)$ (34,683)$ (673)$ (34,217)$ (48,132)$ (85,999)$
Levelized 6,339$ 12,037$ (14,122)$ 1,716$ (3,358)$ (10,935)$ (5,160)$ (100)$ (5,091)$ (7,161)$ (12,795)$
10-Year PV Rank 10 11 1 9 7 3 5 8 6 4 2
Notes:All values are averaged over all hours of simulation.
Base case includes all existing and committed resources as of January 1, 2004.
All costs nominal. AURORAxmp hydro modeling modified June 2004.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-21-2004
Page 5 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Bundles Analysis
IPC Portfolio Power Supply Costs: Portfolios 0 to 11 Comparison
NPV Comparison of Portfolio Differences (Portfolio - Balanced 0)
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
-$1,000
-$900
-$800
-$700
-$600
-$500
-$400
-$300
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
2
0
0
4
2
0
0
5
2
0
0
6
2
0
0
7
2
0
0
8
2
0
0
9
2
0
1
0
2
0
1
1
2
0
1
2
2
0
1
3
2
0
1
4
2
0
1
5
2
0
1
6
2
0
1
7
2
0
1
8
2
0
1
9
2
0
2
0
2
0
2
1
2
0
2
2
2
0
2
3
2
0
2
4
2
0
2
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2
0
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2
0
2
9
2
0
3
0
2
0
3
1
2
0
3
2
2
0
3
3
P1 - Peakers
P2 - Coal
P3 - Wind and Peakers
P4 - Balanced 1
P5 - Early Coal
P6 - Balanced 2
P7 - Balanced 3
P8 - Balanced 4
P9 - Balanced 5
P10 - Balanced 6
P11 - Balanced 7
Page 6 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Bundles Analysis
IPC Portfolio Power Supply Costs: Portfolios 0 to 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $49.21/tonstarting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Portfolio Power Supply Cost ($ x 1000)
Year P0 - Balanced 0 P1 - Peakers P2 - Coal
P3 - Wind and
Peakers P4 - Balanced 1 P5 - Early Coal P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4 P9 - Balanced 5
P10 - Balanced
6
P11 - Balanced
7
2004 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$
2005 333,719$ 333,719$ 333,719$ 333,719$ 341,086$ 333,719$ 341,086$ 341,086$ 341,086$ 341,523$ 341,523$ 341,086$
2006 368,829$ 373,343$ 373,343$ 368,075$ 371,676$ 359,822$ 371,676$ 371,676$ 361,516$ 371,794$ 371,794$ 371,676$
2007 377,050$ 374,271$ 374,271$ 383,376$ 380,750$ 379,249$ 374,158$ 374,158$ 392,176$ 373,891$ 373,891$ 373,311$
2008 766,680$ 801,515$ 791,058$ 746,410$ 771,434$ 869,949$ 754,255$ 751,552$ 806,771$ 752,003$ 752,003$ 750,797$
2009 839,668$ 827,268$ 931,769$ 753,024$ 803,899$ 888,941$ 828,467$ 765,931$ 885,945$ 767,517$ 767,517$ 765,215$
2010 867,915$ 876,487$ 956,774$ 759,312$ 832,485$ 921,608$ 853,574$ 857,878$ 907,892$ 860,082$ 835,094$ 790,047$
2011 881,062$ 889,358$ 945,777$ 753,646$ 879,378$ 931,471$ 844,612$ 855,819$ 894,602$ 858,328$ 833,630$ 827,849$
2012 900,534$ 924,538$ 969,383$ 768,403$ 906,682$ 1,010,884$ 860,963$ 874,658$ 912,634$ 873,569$ 855,865$ 831,715$
2013 903,521$ 945,132$ 978,566$ 769,748$ 913,552$ 1,009,734$ 873,668$ 901,410$ 916,197$ 896,962$ 860,777$ 832,572$
2014 934,162$ 991,855$ 1,022,559$ 801,965$ 949,564$ 1,054,457$ 912,740$ 939,598$ 959,099$ 925,544$ 905,673$ 871,466$
2015 990,878$ 1,067,465$ 1,087,993$ 855,613$ 1,002,730$ 1,115,416$ 962,348$ 974,673$ 1,000,143$ 980,933$ 950,867$ 915,614$
2016 1,034,902$ 1,102,200$ 1,124,360$ 891,739$ 1,047,305$ 1,165,822$ 1,003,478$ 1,021,191$ 1,051,117$ 1,021,296$ 995,726$ 953,554$
2017 1,129,476$ 1,217,418$ 1,232,105$ 1,000,371$ 1,147,747$ 1,262,780$ 1,099,929$ 1,122,138$ 1,143,865$ 1,120,807$ 1,093,239$ 1,052,093$
2018 1,151,742$ 1,249,714$ 1,265,589$ 1,015,682$ 1,173,875$ 1,293,447$ 1,129,371$ 1,138,226$ 1,170,706$ 1,145,216$ 1,119,148$ 1,072,379$
2019 1,211,297$ 1,310,582$ 1,323,003$ 1,070,056$ 1,233,698$ 1,349,953$ 1,187,256$ 1,189,065$ 1,225,924$ 1,199,584$ 1,177,528$ 1,134,434$ 2020 1,253,900$ 1,361,579$ 1,359,797$ 1,110,994$ 1,261,433$ 1,393,626$ 1,225,049$ 1,216,183$ 1,260,032$ 1,227,142$ 1,216,176$ 1,158,263$
2021 1,299,684$ 1,413,083$ 1,428,179$ 1,151,345$ 1,320,760$ 1,449,416$ 1,281,752$ 1,257,957$ 1,303,059$ 1,278,272$ 1,268,216$ 1,202,439$
2022 1,398,370$ 1,522,230$ 1,527,154$ 1,242,594$ 1,416,183$ 1,544,216$ 1,385,829$ 1,354,661$ 1,411,286$ 1,380,837$ 1,369,021$ 1,297,521$
2023 1,473,157$ 1,613,262$ 1,606,466$ 1,307,090$ 1,498,727$ 1,627,352$ 1,461,249$ 1,423,966$ 1,482,166$ 1,450,684$ 1,441,986$ 1,366,549$
2024 1,563,502$ 1,723,760$ 1,709,178$ 1,393,700$ 1,596,654$ 1,719,813$ 1,563,195$ 1,495,266$ 1,565,518$ 1,536,810$ 1,532,100$ 1,450,921$
2025 1,630,224$ 1,795,107$ 1,784,111$ 1,456,308$ 1,686,643$ 1,793,626$ 1,636,877$ 1,567,435$ 1,636,532$ 1,605,877$ 1,602,519$ 1,516,256$ 2026 1,741,268$ 1,922,427$ 1,911,344$ 1,555,098$ 1,808,184$ 1,910,012$ 1,759,915$ 1,652,983$ 1,737,763$ 1,713,082$ 1,708,691$ 1,618,893$
2027 1,838,735$ 2,032,356$ 2,014,009$ 1,650,584$ 1,923,425$ 2,011,724$ 1,869,631$ 1,731,070$ 1,832,196$ 1,812,264$ 1,797,321$ 1,712,143$
2028 1,974,190$ 2,173,171$ 2,160,677$ 1,771,040$ 2,059,775$ 2,153,207$ 2,001,855$ 1,850,125$ 1,964,233$ 1,943,354$ 1,930,529$ 1,830,783$
2029 2,085,850$ 2,306,443$ 2,290,264$ 1,866,836$ 2,191,748$ 2,266,442$ 2,136,265$ 1,939,924$ 2,072,565$ 2,051,154$ 2,039,810$ 1,936,527$
2030 2,231,626$ 2,469,255$ 2,460,021$ 1,992,368$ 2,350,916$ 2,419,400$ 2,298,464$ 2,059,310$ 2,211,128$ 2,194,451$ 2,179,382$ 2,075,278$
2031 2,396,284$ 2,632,723$ 2,640,585$ 2,130,831$ 2,520,754$ 2,598,993$ 2,484,340$ 2,179,834$ 2,360,769$ 2,355,719$ 2,333,722$ 2,221,962$
2032 2,617,556$ 2,863,144$ 2,874,627$ 2,336,729$ 2,750,020$ 2,816,265$ 2,710,254$ 2,370,376$ 2,585,955$ 2,568,587$ 2,563,591$ 2,422,080$
2033 2,894,627$ 3,110,852$ 3,127,724$ 2,628,308$ 3,011,233$ 3,075,094$ 2,935,687$ 2,658,675$ 2,888,201$ 2,843,507$ 2,793,955$ 2,699,702$
Total 39,410,633$ 42,544,483$ 42,924,633$ 35,185,189$ 40,472,541$ 43,046,665$ 39,468,167$ 37,557,048$ 39,601,301$ 38,771,014$ 38,331,520$ 36,713,353$
Discount Rate: 7.2002%
30-Year PV 12,162,062$ 12,917,502$ 13,146,995$ 10,917,728$ 12,354,318$ 13,250,939$ 12,065,369$ 11,754,745$ 12,313,519$ 11,963,130$ 11,807,806$ 11,394,838$
Levelized 1,035,256$ 1,099,560$ 1,119,095$ 929,336$ 1,051,621$ 1,127,943$ 1,027,025$ 1,000,584$ 1,048,148$ 1,018,322$ 1,005,101$ 969,948$
30-Year PV Rank 7 10 11 1 9 12 6 3 8 5 4 2
20-Year PV 8,542,976$ 8,939,280$ 9,182,214$ 7,678,416$ 8,579,965$ 9,314,993$ 8,379,674$ 8,376,702$ 8,712,290$ 8,403,700$ 8,271,056$ 8,032,700$
Levelized 847,961$ 887,297$ 911,411$ 762,146$ 851,632$ 924,590$ 831,752$ 831,457$ 864,767$ 834,137$ 820,971$ 797,312$
20-Year PV Rank 7 10 11 1 8 12 5 4 9 6 3 2
10-Year PV 4,389,906$ 4,453,706$ 4,644,044$ 4,033,265$ 4,365,949$ 4,673,272$ 4,311,839$ 4,298,505$ 4,509,874$ 4,300,192$ 4,241,132$ 4,177,688$
Levelized 653,137$ 662,629$ 690,948$ 600,075$ 649,573$ 695,297$ 641,522$ 639,538$ 670,986$ 639,789$ 631,002$ 621,563$
10-Year PV Rank 8 9 11 1 7 12 6 4 10 5 3 2
Page 7 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Bundles Analysis
IPC Portfolio Power Supply Costs: Portfolios 0 to 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $49.21/tonstarting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Difference in Portfolio Power Supply Costs (Scenario - Base Case) ($ x 1000)
Year P0 - Balanced 0 P1 - Peakers P2 - Coal
P3 - Wind and
Peakers P4 - Balanced 1 P5 - Early Coal P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4 P9 - Balanced 5
P10 - Balanced
6
P11 - Balanced
7
2004 -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$
2005 -$ -$ -$ 7,367$ -$ 7,367$ 7,367$ 7,367$ 7,804$ 7,804$ 7,367$ 2006 4,514$ 4,514$ (754)$ 2,846$ (9,007)$ 2,846$ 2,846$ (7,314)$ 2,964$ 2,964$ 2,846$
2007 (2,779)$ (2,779)$ 6,326$ 3,700$ 2,199$ (2,892)$ (2,892)$ 15,126$ (3,159)$ (3,159)$ (3,739)$
2008 34,835$ 24,378$ (20,270)$ 4,754$ 103,269$ (12,425)$ (15,128)$ 40,092$ (14,676)$ (14,676)$ (15,883)$
2009 (12,400)$ 92,101$ (86,644)$ (35,769)$ 49,273$ (11,201)$ (73,737)$ 46,277$ (72,151)$ (72,151)$ (74,453)$
2010 8,572$ 88,859$ (108,603)$ (35,430)$ 53,693$ (14,341)$ (10,037)$ 39,977$ (7,834)$ (32,821)$ (77,868)$
2011 8,296$ 64,715$ (127,416)$ (1,684)$ 50,409$ (36,450)$ (25,243)$ 13,540$ (22,734)$ (47,432)$ (53,213)$
2012 24,005$ 68,849$ (132,131)$ 6,148$ 110,350$ (39,571)$ (25,876)$ 12,100$ (26,965)$ (44,669)$ (68,819)$
2013 41,611$ 75,045$ (133,773)$ 10,030$ 106,213$ (29,853)$ (2,111)$ 12,676$ (6,560)$ (42,744)$ (70,949)$
2014 57,693$ 88,397$ (132,197)$ 15,402$ 120,295$ (21,422)$ 5,436$ 24,937$ (8,618)$ (28,489)$ (62,696)$
2015 76,587$ 97,115$ (135,265)$ 11,852$ 124,538$ (28,530)$ (16,205)$ 9,265$ (9,945)$ (40,011)$ (75,264)$
2016 67,299$ 89,458$ (143,163)$ 12,404$ 130,920$ (31,424)$ (13,710)$ 16,215$ (13,606)$ (39,176)$ (81,348)$
2017 87,941$ 102,629$ (129,105)$ 18,270$ 133,304$ (29,547)$ (7,339)$ 14,388$ (8,670)$ (36,237)$ (77,384)$
2018 97,972$ 113,847$ (136,060)$ 22,132$ 141,704$ (22,371)$ (13,517)$ 18,963$ (6,526)$ (32,594)$ (79,363)$
2019 99,285$ 111,706$ (141,241)$ 22,401$ 138,656$ (24,041)$ (22,232)$ 14,627$ (11,713)$ (33,769)$ (76,862)$
2020 107,679$ 105,897$ (142,906)$ 7,534$ 139,726$ (28,851)$ (37,717)$ 6,132$ (26,757)$ (37,724)$ (95,637)$
2021 113,399$ 128,495$ (148,339)$ 21,076$ 149,733$ (17,932)$ (41,727)$ 3,376$ (21,411)$ (31,468)$ (97,244)$
2022 123,860$ 128,784$ (155,776)$ 17,813$ 145,846$ (12,541)$ (43,709)$ 12,916$ (17,533)$ (29,349)$ (100,849)$
2023 140,105$ 133,310$ (166,067)$ 25,570$ 154,195$ (11,908)$ (49,190)$ 9,010$ (22,473)$ (31,170)$ (106,607)$
2024 160,258$ 145,676$ (169,802)$ 33,152$ 156,311$ (307)$ (68,236)$ 2,016$ (26,692)$ (31,402)$ (112,581)$ 2025 164,883$ 153,887$ (173,916)$ 56,419$ 163,402$ 6,653$ (62,789)$ 6,308$ (24,347)$ (27,705)$ (113,968)$
2026 181,159$ 170,075$ (186,170)$ 66,916$ 168,743$ 18,646$ (88,285)$ (3,505)$ (28,186)$ (32,577)$ (122,375)$
2027 193,621$ 175,274$ (188,151)$ 84,690$ 172,989$ 30,896$ (107,665)$ (6,539)$ (26,471)$ (41,414)$ (126,592)$
2028 198,981$ 186,488$ (203,150)$ 85,585$ 179,018$ 27,665$ (124,065)$ (9,957)$ (30,835)$ (43,660)$ (143,407)$
2029 220,594$ 204,414$ (219,013)$ 105,899$ 180,592$ 50,415$ (145,925)$ (13,285)$ (34,695)$ (46,040)$ (149,322)$
2030 237,629$ 228,395$ (239,258)$ 119,291$ 187,774$ 66,838$ (172,316)$ (20,497)$ (37,175)$ (52,243)$ (156,348)$ 2031 236,439$ 244,301$ (265,453)$ 124,470$ 202,709$ 88,055$ (216,451)$ (35,515)$ (40,566)$ (62,563)$ (174,322)$
2032 245,588$ 257,071$ (280,827)$ 132,464$ 198,709$ 92,699$ (247,180)$ (31,601)$ (48,969)$ (53,964)$ (195,476)$
2033 216,226$ 233,098$ (266,319)$ 116,606$ 180,467$ 41,060$ (235,952)$ (6,426)$ (51,120)$ (100,671)$ (194,925)$
Total 3,133,849$ 3,514,000$ (4,225,444)$ 1,061,908$ 3,636,032$ 57,534$ (1,853,585)$ 190,668$ (639,620)$ (1,079,114)$ (2,697,280)$
Discount Rate: 7.2002%30-Year PV 755,440$ 984,933$ (1,244,334)$ 192,256$ 1,088,877$ (96,693)$ (407,318)$ 151,457$ (198,932)$ (354,256)$ (767,225)$
Levelized 64,304$ 83,839$ (105,920)$ 16,365$ 92,687$ (8,231)$ (34,672)$ 12,892$ (16,933)$ (30,155)$ (65,307)$
30-Year PV Rank 9 10 1 8 11 6 3 7 5 4 2
20-Year PV 396,304$ 639,238$ (864,560)$ 36,989$ 772,017$ (163,302)$ (166,274)$ 169,314$ (139,276)$ (271,920)$ (510,276)$
Levelized 39,336$ 63,450$ (85,815)$ 3,671$ 76,629$ (16,209)$ (16,504)$ 16,806$ (13,824)$ (26,990)$ (50,649)$
20-Year PV Rank 9 10 1 7 11 5 4 8 6 3 2
10-Year PV 63,800$ 254,139$ (356,640)$ (23,957)$ 283,367$ (78,067)$ (91,400)$ 119,969$ (89,714)$ (148,774)$ (212,218)$
Levelized 9,492$ 37,811$ (53,061)$ (3,564)$ 42,160$ (11,615)$ (13,599)$ 17,849$ (13,348)$ (22,135)$ (31,574)$
10-Year PV Rank 8 10 1 7 11 6 4 9 5 3 2
Notes:All values are averaged over all hours of simulation.
Base case includes all existing and committed resources as of January 1, 2004.
All costs nominal. AURORAxmp hydro modeling modified June 2004.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-21-2004
Page 8 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Bundles Analysis
IPC Portfolio Power Supply Costs: Portfolios 0 to 11 Comparison
NPV Comparison of Portfolio Differences (Portfolio - Balanced 0)
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $49.21/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
-$1,000
-$900
-$800
-$700
-$600
-$500
-$400
-$300
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
2
0
0
4
2
0
0
5
2
0
0
6
2
0
0
7
2
0
0
8
2
0
0
9
2
0
1
0
2
0
1
1
2
0
1
2
2
0
1
3
2
0
1
4
2
0
1
5
2
0
1
6
2
0
1
7
2
0
1
8
2
0
1
9
2
0
2
0
2
0
2
1
2
0
2
2
2
0
2
3
2
0
2
4
2
0
2
5
2
0
2
6
2
0
2
7
2
0
2
8
2
0
2
9
2
0
3
0
2
0
3
1
2
0
3
2
2
0
3
3
P1 - Peakers
P2 - Coal
P3 - Wind and Peakers
P4 - Balanced 1
P5 - Early Coal
P6 - Balanced 2
P7 - Balanced 3
P8 - Balanced 4
P9 - Balanced 5
P10 - Balanced 6
P11 - Balanced 7
Page 9 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Bundles Analysis
IPC Portfolio Power Supply Costs: Portfolios 0 to 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $0.00/MWh
Portfolio Power Supply Cost ($ x 1000)
Year P0 - Balanced 0 P1 - Peakers P2 - Coal
P3 - Wind and
Peakers P4 - Balanced 1 P5 - Early Coal P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4 P9 - Balanced 5
P10 - Balanced
6
P11 - Balanced
7
2004 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$
2005 333,719$ 333,719$ 333,719$ 333,719$ 341,086$ 333,719$ 341,086$ 341,086$ 341,086$ 341,523$ 341,523$ 341,086$
2006 379,364$ 373,343$ 373,343$ 378,609$ 377,054$ 359,822$ 377,054$ 377,054$ 367,365$ 377,958$ 377,958$ 377,054$
2007 388,965$ 374,271$ 374,271$ 406,554$ 387,146$ 379,249$ 385,347$ 385,347$ 398,400$ 385,634$ 385,634$ 384,499$
2008 509,169$ 506,212$ 496,471$ 537,285$ 506,077$ 515,282$ 500,279$ 508,808$ 512,181$ 509,334$ 509,334$ 508,053$
2009 542,459$ 518,151$ 574,445$ 562,214$ 524,874$ 520,160$ 535,873$ 510,231$ 551,791$ 509,852$ 509,852$ 509,515$
2010 550,938$ 548,591$ 576,736$ 573,632$ 536,812$ 528,186$ 538,712$ 555,010$ 553,053$ 555,662$ 548,831$ 540,219$
2011 560,957$ 554,741$ 563,207$ 557,859$ 549,743$ 522,576$ 524,794$ 543,410$ 539,003$ 546,567$ 540,044$ 546,618$
2012 566,013$ 584,178$ 575,762$ 579,007$ 578,070$ 556,010$ 537,068$ 554,567$ 541,723$ 557,802$ 556,271$ 541,800$
2013 565,721$ 581,484$ 559,683$ 548,414$ 562,167$ 546,558$ 516,173$ 545,723$ 525,229$ 541,229$ 537,254$ 522,202$
2014 574,247$ 602,677$ 575,005$ 567,297$ 575,921$ 560,382$ 532,637$ 543,566$ 535,258$ 554,181$ 559,083$ 529,292$
2015 614,988$ 652,096$ 610,378$ 602,166$ 613,412$ 603,864$ 567,486$ 575,218$ 560,261$ 586,680$ 593,473$ 552,629$
2016 643,912$ 656,377$ 630,902$ 614,526$ 636,514$ 634,207$ 582,126$ 585,245$ 594,275$ 610,509$ 614,658$ 576,027$
2017 704,463$ 722,725$ 680,375$ 676,438$ 689,371$ 704,688$ 631,828$ 668,956$ 654,590$ 678,825$ 684,038$ 632,142$
2018 709,364$ 727,014$ 683,905$ 668,522$ 689,322$ 706,912$ 632,612$ 658,558$ 655,936$ 678,342$ 684,444$ 623,557$
2019 750,917$ 769,377$ 717,364$ 704,809$ 726,082$ 747,017$ 664,560$ 694,158$ 697,720$ 716,431$ 724,228$ 657,090$ 2020 798,617$ 831,615$ 770,384$ 748,490$ 738,782$ 790,313$ 717,584$ 724,329$ 731,154$ 763,695$ 767,908$ 697,278$
2021 831,927$ 873,487$ 808,101$ 775,561$ 781,126$ 823,429$ 757,381$ 744,683$ 766,098$ 791,117$ 799,474$ 724,148$
2022 865,453$ 902,822$ 839,725$ 802,001$ 827,829$ 865,969$ 788,592$ 783,981$ 804,066$ 828,854$ 843,269$ 753,456$
2023 908,487$ 953,986$ 878,932$ 832,164$ 866,555$ 908,287$ 828,310$ 823,447$ 842,006$ 867,510$ 885,173$ 781,916$
2024 966,801$ 1,008,478$ 926,697$ 872,915$ 914,477$ 958,754$ 876,059$ 864,324$ 892,176$ 921,769$ 943,447$ 816,493$
2025 1,020,243$ 1,076,152$ 999,626$ 926,360$ 1,014,836$ 1,014,984$ 945,579$ 909,825$ 944,933$ 973,823$ 997,850$ 872,179$ 2026 1,087,762$ 1,158,620$ 1,084,791$ 985,962$ 1,095,277$ 1,084,260$ 1,034,160$ 963,979$ 1,008,185$ 1,040,166$ 1,065,037$ 928,755$
2027 1,170,700$ 1,271,679$ 1,193,383$ 1,074,826$ 1,215,618$ 1,166,276$ 1,142,695$ 1,014,825$ 1,084,702$ 1,119,901$ 1,141,504$ 1,026,515$
2028 1,265,842$ 1,380,961$ 1,298,550$ 1,164,676$ 1,322,483$ 1,262,997$ 1,246,515$ 1,100,302$ 1,173,546$ 1,211,066$ 1,233,792$ 1,115,428$
2029 1,344,892$ 1,465,273$ 1,388,564$ 1,220,743$ 1,408,068$ 1,341,903$ 1,340,337$ 1,148,328$ 1,243,237$ 1,286,585$ 1,306,250$ 1,174,845$
2030 1,451,097$ 1,580,207$ 1,508,478$ 1,309,011$ 1,521,153$ 1,446,640$ 1,463,910$ 1,227,729$ 1,340,599$ 1,387,908$ 1,408,628$ 1,265,734$
2031 1,568,967$ 1,707,334$ 1,645,478$ 1,410,579$ 1,657,778$ 1,563,240$ 1,607,045$ 1,312,412$ 1,447,007$ 1,502,187$ 1,518,203$ 1,374,007$
2032 1,737,226$ 1,890,775$ 1,826,040$ 1,560,685$ 1,837,912$ 1,731,132$ 1,789,415$ 1,443,361$ 1,607,677$ 1,666,582$ 1,680,248$ 1,533,074$
2033 2,004,324$ 2,136,027$ 2,091,805$ 1,854,121$ 2,114,599$ 1,971,009$ 2,031,494$ 1,715,059$ 1,894,981$ 1,924,752$ 1,907,028$ 1,812,558$
Total 25,737,759$ 27,062,598$ 25,906,348$ 24,169,371$ 25,930,370$ 25,468,053$ 24,756,936$ 23,143,745$ 24,128,466$ 24,756,673$ 24,984,661$ 23,038,396$
Discount Rate: 7.2002%
30-Year PV 8,187,108$ 8,442,614$ 8,181,855$ 7,899,644$ 8,155,263$ 8,064,263$ 7,823,073$ 7,619,103$ 7,787,463$ 7,931,315$ 7,979,367$ 7,518,428$
Levelized 696,901$ 718,650$ 696,453$ 672,431$ 694,190$ 686,444$ 665,913$ 648,551$ 662,882$ 675,127$ 679,217$ 639,981$
30-Year PV Rank 11 12 10 5 9 8 4 2 3 6 7 1
20-Year PV 5,851,949$ 5,929,955$ 5,799,894$ 5,777,194$ 5,750,233$ 5,741,516$ 5,529,104$ 5,604,195$ 5,622,084$ 5,696,990$ 5,712,292$ 5,481,265$
Levelized 580,854$ 588,597$ 575,687$ 573,434$ 570,758$ 569,893$ 548,809$ 556,263$ 558,038$ 565,473$ 566,992$ 544,061$
20-Year PV Rank 11 12 10 9 8 7 2 3 4 5 6 1
10-Year PV 3,265,504$ 3,243,196$ 3,281,492$ 3,323,558$ 3,243,711$ 3,178,019$ 3,185,495$ 3,220,618$ 3,231,968$ 3,223,883$ 3,212,761$ 3,192,185$
Levelized 485,847$ 482,528$ 488,225$ 494,484$ 482,604$ 472,831$ 473,943$ 479,168$ 480,857$ 479,654$ 478,000$ 474,938$
10-Year PV Rank 10 8 11 12 9 1 2 5 7 6 4 3
Page 10 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Bundles Analysis
IPC Portfolio Power Supply Costs: Portfolios 0 to 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $0.00/MWh
Difference in Portfolio Power Supply Costs (Scenario - Base Case) ($ x 1000)
Year P0 - Balanced 0 P1 - Peakers P2 - Coal
P3 - Wind and
Peakers P4 - Balanced 1 P5 - Early Coal P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4 P9 - Balanced 5
P10 - Balanced
6
P11 - Balanced
7
2004 -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$
2005 -$ -$ -$ 7,367$ -$ 7,367$ 7,367$ 7,367$ 7,804$ 7,804$ 7,367$ 2006 (6,021)$ (6,021)$ (754)$ (2,309)$ (19,541)$ (2,309)$ (2,309)$ (11,998)$ (1,405)$ (1,405)$ (2,309)$
2007 (14,694)$ (14,694)$ 17,589$ (1,819)$ (9,716)$ (3,619)$ (3,619)$ 9,435$ (3,331)$ (3,331)$ (4,466)$
2008 (2,957)$ (12,698)$ 28,116$ (3,093)$ 6,113$ (8,890)$ (362)$ 3,012$ 164$ 164$ (1,116)$
2009 (24,309)$ 31,986$ 19,755$ (17,585)$ (22,299)$ (6,587)$ (32,229)$ 9,332$ (32,607)$ (32,607)$ (32,944)$
2010 (2,347)$ 25,798$ 22,694$ (14,125)$ (22,752)$ (12,225)$ 4,072$ 2,115$ 4,725$ (2,106)$ (10,719)$
2011 (6,216)$ 2,250$ (3,098)$ (11,214)$ (38,380)$ (36,163)$ (17,547)$ (21,954)$ (14,390)$ (20,913)$ (14,339)$
2012 18,164$ 9,749$ 12,993$ 12,057$ (10,003)$ (28,945)$ (11,446)$ (24,291)$ (8,211)$ (9,743)$ (24,213)$
2013 15,763$ (6,038)$ (17,307)$ (3,554)$ (19,163)$ (49,548)$ (19,998)$ (40,492)$ (24,492)$ (28,468)$ (43,519)$
2014 28,430$ 758$ (6,950)$ 1,674$ (13,864)$ (41,610)$ (30,681)$ (38,989)$ (20,066)$ (15,164)$ (44,955)$
2015 37,108$ (4,610)$ (12,822)$ (1,576)$ (11,124)$ (47,502)$ (39,769)$ (54,727)$ (28,308)$ (21,515)$ (62,359)$
2016 12,465$ (13,009)$ (29,386)$ (7,398)$ (9,705)$ (61,786)$ (58,667)$ (49,637)$ (33,402)$ (29,254)$ (67,885)$
2017 18,262$ (24,088)$ (28,024)$ (15,092)$ 225$ (72,634)$ (35,507)$ (49,873)$ (25,638)$ (20,425)$ (72,321)$
2018 17,650$ (25,459)$ (40,842)$ (20,042)$ (2,452)$ (76,751)$ (50,806)$ (53,428)$ (31,021)$ (24,920)$ (85,807)$
2019 18,460$ (33,553)$ (46,108)$ (24,835)$ (3,900)$ (86,357)$ (56,760)$ (53,197)$ (34,486)$ (26,690)$ (93,827)$
2020 32,998$ (28,233)$ (50,127)$ (59,835)$ (8,304)$ (81,033)$ (74,288)$ (67,462)$ (34,922)$ (30,709)$ (101,339)$
2021 41,560$ (23,826)$ (56,366)$ (50,801)$ (8,498)$ (74,546)$ (87,244)$ (65,829)$ (40,810)$ (32,453)$ (107,778)$
2022 37,370$ (25,728)$ (63,452)$ (37,624)$ 516$ (76,861)$ (81,472)$ (61,387)$ (36,599)$ (22,184)$ (111,997)$
2023 45,499$ (29,555)$ (76,323)$ (41,932)$ (200)$ (80,178)$ (85,040)$ (66,481)$ (40,977)$ (23,314)$ (126,571)$
2024 41,677$ (40,104)$ (93,886)$ (52,324)$ (8,047)$ (90,742)$ (102,477)$ (74,625)$ (45,032)$ (23,354)$ (150,308)$ 2025 55,909$ (20,617)$ (93,883)$ (5,408)$ (5,259)$ (74,665)$ (110,418)$ (75,311)$ (46,420)$ (22,393)$ (148,064)$
2026 70,857$ (2,971)$ (101,800)$ 7,514$ (3,502)$ (53,602)$ (123,784)$ (79,577)$ (47,596)$ (22,725)$ (159,007)$
2027 100,979$ 22,683$ (95,873)$ 44,919$ (4,423)$ (28,005)$ (155,874)$ (85,998)$ (50,799)$ (29,196)$ (144,184)$
2028 115,118$ 32,708$ (101,166)$ 56,640$ (2,845)$ (19,327)$ (165,540)$ (92,296)$ (54,776)$ (32,051)$ (150,415)$
2029 120,382$ 43,672$ (124,149)$ 63,177$ (2,989)$ (4,555)$ (196,563)$ (101,655)$ (58,306)$ (38,642)$ (170,047)$
2030 129,110$ 57,381$ (142,086)$ 70,057$ (4,457)$ 12,813$ (223,367)$ (110,497)$ (63,189)$ (42,468)$ (185,363)$ 2031 138,367$ 76,511$ (158,388)$ 88,811$ (5,727)$ 38,077$ (256,556)$ (121,960)$ (66,781)$ (50,765)$ (194,960)$
2032 153,549$ 88,814$ (176,541)$ 100,686$ (6,094)$ 52,190$ (293,865)$ (129,549)$ (70,644)$ (56,977)$ (204,152)$
2033 131,704$ 87,482$ (150,203)$ 110,275$ (33,315)$ 27,170$ (289,265)$ (109,343)$ (79,572)$ (97,295)$ (191,766)$
Total 1,324,839$ 168,589$ (1,568,388)$ 192,611$ (269,706)$ (980,823)$ (2,594,014)$ (1,609,294)$ (981,086)$ (753,098)$ (2,699,363)$
Discount Rate: 7.2002%30-Year PV 255,506$ (5,254)$ (287,465)$ (31,846)$ (122,845)$ (364,035)$ (568,005)$ (399,646)$ (255,794)$ (207,741)$ (668,680)$
Levelized 21,749$ (447)$ (24,469)$ (2,711)$ (10,457)$ (30,987)$ (48,350)$ (34,019)$ (21,774)$ (17,683)$ (56,919)$
30-Year PV Rank 11 10 5 9 8 4 2 3 6 7 1
20-Year PV 78,006$ (52,055)$ (74,756)$ (101,716)$ (110,433)$ (322,845)$ (247,755)$ (229,865)$ (154,959)$ (139,657)$ (370,684)$
Levelized 7,743$ (5,167)$ (7,420)$ (10,096)$ (10,961)$ (32,045)$ (24,592)$ (22,816)$ (15,381)$ (13,862)$ (36,793)$
20-Year PV Rank 11 10 9 8 7 2 3 4 5 6 1
10-Year PV (22,308)$ 15,988$ 58,054$ (21,793)$ (87,485)$ (80,009)$ (44,887)$ (33,536)$ (41,622)$ (52,743)$ (73,320)$
Levelized (3,319)$ 2,379$ 8,637$ (3,242)$ (13,016)$ (11,904)$ (6,678)$ (4,990)$ (6,193)$ (7,847)$ (10,909)$
10-Year PV Rank 8 10 11 9 1 2 5 7 6 4 3
Notes:All values are averaged over all hours of simulation.
Base case includes all existing and committed resources as of January 1, 2004.
All costs nominal. AURORAxmp hydro modeling modified June 2004.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-21-2004
Page 11 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Bundles Analysis
IPC Portfolio Power Supply Costs: Portfolios 0 to 11 Comparison
NPV Comparison of Portfolio Differences (Portfolio - Balanced 0)
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $0.00/MWh
-$1,000
-$900
-$800
-$700
-$600
-$500
-$400
-$300
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
2
0
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4
2
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5
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0
1
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2
0
2
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2
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2
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2
0
2
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2
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0
2
4
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0
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3
P1 - Peakers
P2 - Coal
P3 - Wind and Peakers
P4 - Balanced 1
P5 - Early Coal
P6 - Balanced 2
P7 - Balanced 3
P8 - Balanced 4
P9 - Balanced 5
P10 - Balanced 6
P11 - Balanced 7
Page 12 of 12 AURORAxmp Ver. 7.1.0.0
2004 Integrated Resource Plan
Portfolio Ranking Analysis - Summary
6/27/2004
P0 P1 P2 P3 P4 P5 P6 P7 P8 P9 P10 P11
CO2 @ $12.30/ton, No PTC 30 yr rank 10 12 11 5 9 8 4 2 3 6 7 1
CO2 @ $12.30/ton, No PTC 20 yr rank 11 12 10 9 5 6 2 3 4 8 7 1
CO2 @ $12.30/ton, No PTC 10 yr rank 9 4 11 12 7 1 2 6 10 8 5 3
CO2 @ $12.30/ton, PTC 30 yr rank 8 12 11 2 10 9 4 3 5 6 7 1
CO2 @ $12.30/ton, PTC 20 yr rank 9 12 11 2 8 10 3 4 5 7 6 1
CO2 @ $12.30/ton, PTC 10 yr rank 7 11 12 1 9 4 3 6 10 8 5 2
CO2 @ $49.21/ton, PTC 30 yr rank 7 10 11 1 8 12 6 3 9 5 4 2
CO2 @ $49.21/ton, PTC 20 yr rank 7 10 11 1 8 12 4 5 9 6 3 2
CO2 @ $49.21/ton, PTC 10 yr rank 8 9 11 1 7 12 6 4 10 5 3 2
CO2 @ $0.00/ton, PTC 30 yr rank 10 12 8 3 11 5 6 2 4 7 9 1
CO2 @ $0.00/ton, PTC 20 yr rank 11 12 7 6 10 2 3 5 4 8 9 1
CO2 @ $0.00/ton, PTC 10 yr rank 6 12 8 5 11 1 2 7 4 9 10 3
Sum of Rankings - all scenarios, all years 103 128 122 48 103 82 45 50 77 83 75 20
Portfolio Ranking - all scenarios, all years 9 12 11 3 9 7 2 4 6 8 5 1
Sum of Rankings - all scenarios, 30 yr only 35 46 41 11 38 34 20 10 21 24 27 5
Portfolio Ranking - all scenarios, 30 yr only 9 12 11 3 10 8 4 2 5 6 7 1
Notes: 1. All rankings are for the present value of portfolio power supply costs.
2. For the all scenarios, all years ranking - each scenario/year combination received equal weighting.
3. For the all scenarios, 30 yr only ranking - each scenario received equal weighting.
Individual DSM Options Compared to P-Zero Portfolio
IPC Net Portfolio Costs
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Portfolio Power Supply Cost, DSM TRC Included ($ x 1000)
Year P0 - Balanced 0 Ind Eff Irr Eff Comm Eff NC Comm Eff EC Res Eff NC Res Eff EC AC Cycling
Irr Peak
Clipping
2004 416,046$ 416,046$ 416,046$ 416,046$ 416,046$ 416,046$ 416,046$
2005 441,603$ 444,294$ 444,607$ 442,361$ 443,989$ 442,435$ 443,380$
2006 457,215$ 459,783$ 460,092$ 457,864$ 461,146$ 458,737$ 460,667$
2007 474,899$ 477,476$ 477,349$ 475,145$ 479,075$ 475,478$ 479,112$
2008 516,335$ 518,401$ 519,347$ 517,329$ 520,020$ 517,629$ 521,228$ 2009 545,155$ 547,077$ 547,039$ 546,430$ 548,875$ 545,616$ 550,105$
2010 561,509$ 560,453$ 561,100$ 560,588$ 561,838$ 560,921$ 563,526$
2011 547,855$ 538,414$ 544,126$ 541,783$ 551,006$ 535,650$ 542,995$
2012 567,882$ 568,075$ 546,468$ 570,326$ 570,227$ 570,074$ 573,892$
2013 553,182$ 563,746$ 561,449$ 557,633$ 554,071$ 558,373$ 564,648$ 2014 602,298$ 599,412$ 588,432$ 602,726$ 600,706$ 601,242$ 603,401$
2015 597,842$ 586,409$ 577,891$ 579,920$ 574,285$ 596,554$ 579,109$
2016 602,202$ 575,988$ 581,528$ 594,295$ 586,856$ 589,120$ 589,831$
2017 641,631$ 637,981$ 644,226$ 643,891$ 648,859$ 652,074$ 627,840$
2018 685,024$ 687,935$ 677,169$ 683,983$ 681,840$ 697,862$ 686,344$ 2019 744,036$ 731,000$ 734,485$ 744,613$ 729,291$ 742,221$ 730,881$
2020 833,280$ 817,543$ 823,898$ 829,063$ 814,129$ 827,008$ 822,525$
2021 851,990$ 838,412$ 841,162$ 850,761$ 842,457$ 849,816$ 843,077$
2022 875,473$ 868,308$ 867,539$ 876,383$ 868,361$ 871,854$ 866,501$
2023 937,123$ 927,536$ 929,223$ 936,343$ 926,578$ 935,179$ 927,837$ 2024 1,007,923$ 992,505$ 994,030$ 1,001,469$ 997,535$ 1,000,284$ 993,145$
2025 1,052,484$ 1,039,994$ 1,041,161$ 1,052,302$ 1,039,503$ 1,049,176$ 1,043,129$
2026 1,135,743$ 1,122,858$ 1,124,146$ 1,135,138$ 1,123,906$ 1,131,885$ 1,125,525$
2027 1,219,729$ 1,205,630$ 1,205,289$ 1,216,773$ 1,207,247$ 1,215,514$ 1,207,207$
2028 1,310,454$ 1,296,994$ 1,296,416$ 1,308,609$ 1,296,058$ 1,306,368$ 1,297,564$ 2029 1,366,045$ 1,351,230$ 1,351,304$ 1,363,424$ 1,351,055$ 1,361,933$ 1,351,557$
2030 1,483,991$ 1,467,586$ 1,468,156$ 1,481,957$ 1,467,862$ 1,478,856$ 1,470,316$
2031 1,617,234$ 1,599,258$ 1,598,652$ 1,614,571$ 1,599,157$ 1,612,058$ 1,600,507$
2032 1,792,547$ 1,771,609$ 1,771,481$ 1,789,873$ 1,771,924$ 1,785,252$ 1,773,873$
2033 2,012,250$ 1,990,751$ 1,989,474$ 2,008,499$ 1,990,191$ 2,005,302$ 1,992,614$ Total 26,450,981$ 26,202,704$ 26,183,284$ 26,400,099$ 26,224,093$ 26,390,518$ 26,248,382$ -$ -$
Discount Rate: 7.2002%
30-Year PV 8,559,288 8,504,378 8,492,652 8,545,006 8,515,959 8,547,621 8,523,526
Levelized 728,581 723,907 722,909 727,366 724,893 727,588 725,537
30-Year PV Rank 7 2 1 5 3 6 4
20-Year PV 6,154,700 6,127,618 6,115,334 6,145,062 6,137,766 6,152,161 6,143,716
Levelized 610,905 608,217 606,997 609,948 609,224 610,653 609,815
20-Year PV Rank 7 2 1 5 3 6 4
10-Year PV 3,588,638 3,597,351 3,589,109 3,591,118 3,606,436 3,588,658 3,611,048
Levelized 533,923 535,219 533,993 534,292 536,571 533,926 537,257
15-Year PV Rank 1 5 3 4 6 2 7
Abbreviations
AC - Air Conditioning
Comm - Commercial
DSM - Demand Side Management
EC - Existing Construction
Eff - Efficiency
Ind - Industrial
Irr - Irrigation
NC - New Construction
Res - Residential
Page 1 of 2 AURORAxmp Ver. 7.1.0.0
Individual DSM Options Compared to P-Zero Portfolio
IPC Net Portfolio Costs
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Abbreviations
AC - Air Conditioning
Comm - Commercial
DSM - Demand Side Management
EC - Existing Construction
Eff - Efficiency
Ind - Industrial
Irr - Irrigation
NC - New Construction
Res - Residential
Difference in Portfolio Power Supply Costs (Scenario - Base Case) ($ x 1000)
Year P0 - Balanced 0 Ind Eff Irr Eff Comm Eff NC Comm Eff EC Res Eff NC Res Eff EC AC Cycling
Irr Peak
Clipping
2004 -$ -$ -$ -$ -$ -$
2005 2,691$ 3,004$ 757$ 2,386$ 831$ 1,777$
2006 2,568$ 2,877$ 649$ 3,931$ 1,522$ 3,452$
2007 2,578$ 2,450$ 246$ 4,176$ 579$ 4,213$
2008 2,066$ 3,012$ 995$ 3,686$ 1,295$ 4,893$ 2009 1,922$ 1,883$ 1,275$ 3,719$ 461$ 4,950$
2010 (1,056)$ (409)$ (921)$ 328$ (588)$ 2,016$
2011 (9,441)$ (3,729)$ (6,073)$ 3,151$ (12,206)$ (4,861)$
2012 193$ (21,414)$ 2,444$ 2,345$ 2,193$ 6,011$
2013 10,564$ 8,267$ 4,451$ 889$ 5,190$ 11,465$ 2014 (2,887)$ (13,866)$ 428$ (1,592)$ (1,057)$ 1,103$
2015 (11,433)$ (19,951)$ (17,922)$ (23,556)$ (1,288)$ (18,733)$
2016 (26,214)$ (20,674)$ (7,907)$ (15,346)$ (13,082)$ (12,370)$
2017 (3,650)$ 2,595$ 2,260$ 7,228$ 10,443$ (13,791)$
2018 2,911$ (7,855)$ (1,041)$ (3,184)$ 12,838$ 1,320$ 2019 (13,035)$ (9,551)$ 577$ (14,744)$ (1,814)$ (13,155)$
2020 (15,737)$ (9,382)$ (4,217)$ (19,152)$ (6,272)$ (10,755)$
2021 (13,578)$ (10,828)$ (1,228)$ (9,533)$ (2,174)$ (8,913)$
2022 (7,165)$ (7,935)$ 909$ (7,113)$ (3,619)$ (8,973)$
2023 (9,587)$ (7,901)$ (780)$ (10,545)$ (1,944)$ (9,286)$ 2024 (15,419)$ (13,894)$ (6,454)$ (10,388)$ (7,639)$ (14,778)$
2025 (12,490)$ (11,323)$ (182)$ (12,981)$ (3,309)$ (9,355)$
2026 (12,885)$ (11,597)$ (605)$ (11,837)$ (3,858)$ (10,219)$
2027 (14,098)$ (14,439)$ (2,955)$ (12,482)$ (4,215)$ (12,521)$
2028 (13,460)$ (14,038)$ (1,845)$ (14,396)$ (4,086)$ (12,890)$ 2029 (14,815)$ (14,741)$ (2,621)$ (14,990)$ (4,112)$ (14,488)$
2030 (16,405)$ (15,835)$ (2,034)$ (16,129)$ (5,135)$ (13,675)$
2031 (17,976)$ (18,582)$ (2,663)$ (18,077)$ (5,176)$ (16,727)$
2032 (20,938)$ (21,066)$ (2,674)$ (20,623)$ (7,295)$ (18,674)$
2033 (21,499)$ (22,776)$ (3,751)$ (22,059)$ (6,948)$ (19,636)$ Total (248,276)$ (267,696)$ (50,882)$ (226,888)$ (60,463)$ (202,598)$ -$ -$
Discount Rate: 7.2002%
30-Year PV (54,910) (66,637) (14,282) (43,329) (11,667) (35,762)
Levelized (4,674) (5,672) (1,216) (3,688) (993) (3,044)
30-Year PV Rank 2 1 5 3 6 4
20-Year PV (27,082) (39,366) (9,638) (16,934) (2,539) (10,984)
Levelized (2,688) (3,907) (957) (1,681) (252) (1,090)
20-Year PV Rank 2 1 5 3 6 4
10-Year PV 8,713 471 2,479 17,797 19 22,410
Levelized 1,296 70 369 2,648 3 3,334
10-Year PV Rank 4 2 3 5 1 6
Notes:All values are averaged over all hours of simulation.
Base case includes all existing and committed resources as of January 1, 2004
All costs nominal.
Simulation:Every 4th hour; MWFSu; second week
Revised 5-11-2004
Page 2 of 2 AURORAxmp Ver. 7.1.0.0
Individual DSM Options Compared to P-Zero Portfolio
Savings To Cost Ratios, TRC Not Included
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Difference in Portfolio Power Supply Costs (Scenario - Base Case) ($ x 1000)DSM Nominal TRC ($ x 1000)
DSM TRC NOT Included Industrial Efficiency Irrigation Efficiency
Commercial
Efficiency (New Construction)
Commercial Efficiency (Existing)
Residential
Efficiency (New Construction)
Residential Effieciency (Existing)
Year
P0 - Balanced
0 Ind Eff Irr Eff Comm Eff NC Comm Eff EC Res Eff NC Res Eff EC Nom TRC Nom TRC Nom TRC Nom TRC Nom TRC Nom TRC
2004 -$ -$ -$ -$ -$ -$ 2004 -$ -$ -$ -$ -$ -$
2005 (595)$ (233)$ 349$ (611)$ (15)$ (372)$ 2005 3,286$ 3,237$ 408$ 2,997$ 846$ 2,149$ 2006 (800)$ (442)$ 29$ (1,245)$ 451$ (1,325)$ 2006 3,368$ 3,319$ 620$ 5,176$ 1,071$ 4,777$ 2007 (876)$ (952)$ (423)$ (1,290)$ (493)$ (1,152)$ 2007 3,453$ 3,402$ 669$ 5,466$ 1,072$ 5,365$
2008 (1,474)$ (476)$ 273$ (1,878)$ 201$ (947)$ 2008 3,540$ 3,488$ 721$ 5,564$ 1,094$ 5,840$
2009 (1,707)$ (1,693)$ 501$ (1,796)$ (662)$ (1,267)$ 2009 3,629$ 3,576$ 774$ 5,515$ 1,123$ 6,216$
2010 (4,777)$ (4,075)$ (1,747)$ (5,033)$ (1,794)$ (4,491)$ 2010 3,721$ 3,666$ 825$ 5,362$ 1,206$ 6,507$ 2011 (13,256)$ (7,487)$ (6,949)$ (1,989)$ (13,446)$ (11,589)$ 2011 3,815$ 3,758$ 877$ 5,140$ 1,241$ 6,728$
2012 (3,718)$ (25,267)$ 1,517$ (2,534)$ 915$ (880)$ 2012 3,911$ 3,853$ 927$ 4,879$ 1,278$ 6,891$
2013 6,554$ 4,317$ 3,474$ (3,712)$ 3,874$ 4,458$ 2013 4,009$ 3,950$ 977$ 4,601$ 1,317$ 7,008$
2014 (6,997)$ (17,916)$ (599)$ (5,912)$ (2,413)$ (5,985)$ 2014 4,110$ 4,050$ 1,026$ 4,320$ 1,356$ 7,088$
2015 (11,433)$ (19,951)$ (17,922)$ (23,556)$ (1,288)$ (18,733)$ 2015 -$ -$ -$ -$ -$ -$ 2016 (26,214)$ (20,674)$ (7,907)$ (15,346)$ (13,082)$ (12,370)$ 2016 -$ -$ -$ -$ -$ -$ 2017 (3,650)$ 2,595$ 2,260$ 7,228$ 10,443$ (13,791)$ 2017 -$ -$ -$ -$ -$ -$
2018 2,911$ (7,855)$ (1,041)$ (3,184)$ 12,838$ 1,320$ 2018 -$ -$ -$ -$ -$ -$
2019 (13,035)$ (9,551)$ 577$ (14,744)$ (1,814)$ (13,155)$ 2019 -$ -$ -$ -$ -$ -$
2020 (15,737)$ (9,382)$ (4,217)$ (19,152)$ (6,272)$ (10,755)$ 2020 -$ -$ -$ -$ -$ -$ 2021 (13,578)$ (10,828)$ (1,228)$ (9,533)$ (2,174)$ (8,913)$ 2021 -$ -$ -$ -$ -$ -$
2022 (7,165)$ (7,935)$ 909$ (7,113)$ (3,619)$ (8,973)$ 2022 -$ -$ -$ -$ -$ -$
2023 (9,587)$ (7,901)$ (780)$ (10,545)$ (1,944)$ (9,286)$ 2023 -$ -$ -$ -$ -$ -$
2024 (15,419)$ (13,894)$ (6,454)$ (10,388)$ (7,639)$ (14,778)$ 2024 -$ -$ -$ -$ -$ -$
2025 (12,490)$ (11,323)$ (182)$ (12,981)$ (3,309)$ (9,355)$ 2025 -$ -$ -$ -$ -$ -$ 2026 (12,885)$ (11,597)$ (605)$ (11,837)$ (3,858)$ (10,219)$ 2026 -$ -$ -$ -$ -$ -$ 2027 (14,098)$ (14,439)$ (2,955)$ (12,482)$ (4,215)$ (12,521)$ 2027 -$ -$ -$ -$ -$ -$
2028 (13,460)$ (14,038)$ (1,845)$ (14,396)$ (4,086)$ (12,890)$ 2028 -$ -$ -$ -$ -$ -$
2029 (14,815)$ (14,741)$ (2,621)$ (14,990)$ (4,112)$ (14,488)$ 2029 -$ -$ -$ -$ -$ -$
2030 (16,405)$ (15,835)$ (2,034)$ (16,129)$ (5,135)$ (13,675)$ 2030 -$ -$ -$ -$ -$ -$ 2031 (17,976)$ (18,582)$ (2,663)$ (18,077)$ (5,176)$ (16,727)$ 2031 -$ -$ -$ -$ -$ -$ 2032 (20,938)$ (21,066)$ (2,674)$ (20,623)$ (7,295)$ (18,674)$ 2032 -$ -$ -$ -$ -$ -$
2033 (21,499)$ (22,776)$ (3,751)$ (22,059)$ (6,948)$ (19,636)$ 2033 -$ -$ -$ -$ -$ -$
Total (285,119)$ (303,995)$ (58,706)$ (275,907)$ (72,067)$ (261,169)$ 36,843$ 36,299$ 7,824$ 49,020$ 11,604$ 58,570$
Discount Rate: 7.2002%30-Year PV (79,324) (90,690) (19,309) (76,120) (19,282) (73,419) 24,413 24,053 5,027 32,791 7,615 37,657
Levelized (6,752) (7,720) (1,644) (6,479) (1,641) (6,250) 814 802 168 1,093 254 1,255
30-Year PV Rank 2 1 5 3 6 4 4 3 1 5 2 6
20-Year PV (51,495) (63,419) (14,665) (49,725) (10,154) (48,641) 24,413 24,053 5,027 32,791 7,615 37,657 Levelized (5,111) (6,295) (1,456) (4,936) (1,008) (4,828) 2,423 2,387 499 3,255 756 3,738
20-Year PV Rank 2 1 5 3 6 4 4 3 1 5 2 6
10-Year PV (13,720) (21,631) (2,053) (12,912) (6,942) (11,832) 22,433 22,102 4,532 30,709 6,961 34,241 Levelized (2,041) (3,218) (305) (1,921) (1,033) (1,760) 3,338 3,288 674 4,569 1,036 5,094 10-Year PV Rank 2 1 6 3 5 4 4 3 1 5 2 6
Savings ($) / Cost ($) Ratio30 Year Saving $ / Cost $3.25 3.77 3.84 2.32 2.53 1.95
3 2 1 5 4 6
20 Year Saving $ / Cost $2.11 2.64 2.92 1.52 1.33 1.293 2 1 4 5 6
10 Year Saving $ / Cost $0.61 0.98 0.45 0.42 1.00 0.353 2 4 5 1 6
Abbreviations
AC - Air Conditioning
Comm - CommercialDSM - Demand Side ManagementEC - Existing Construction
Eff - Efficiency
Ind - Industrial
Irr - IrrigationNC - New ConstructionRes - Residential
Portfolio Bundles Analysis
Portfolios 0 through 11 CO2 Emission Data
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Portfolio CO2 Emission Cost ($ x 1000)
Year P0 - Balanced 0 P1 - Peakers P2 - Coal
P3 - Wind and
Peakers P4 - Balanced 1 P5 - Early Coal P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4 P9 - Balanced 5
P10 - Balanced
6
P11 - Balanced
7
2004 -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$
2005 -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$
2006 -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 2007 -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$
2008 316,358$ 317,376$ 318,006$ 316,719$ 318,089$ 363,119$ 317,490$ 316,745$ 362,183$ 316,576$ 316,576$ 316,745$
2009 366,316$ 326,946$ 369,197$ 326,272$ 327,881$ 374,216$ 372,890$ 326,600$ 419,974$ 326,497$ 326,497$ 326,600$
2010 377,218$ 337,999$ 380,318$ 335,711$ 337,663$ 385,676$ 383,541$ 383,292$ 431,309$ 383,419$ 354,366$ 337,112$
2011 389,566$ 348,309$ 391,682$ 346,734$ 373,987$ 396,835$ 394,276$ 394,171$ 443,175$ 394,346$ 367,557$ 395,523$
2012 400,433$ 359,508$ 402,842$ 357,814$ 385,741$ 458,029$ 405,470$ 405,304$ 455,510$ 405,239$ 375,838$ 406,743$
2013 409,777$ 370,485$ 412,321$ 367,163$ 395,236$ 468,538$ 414,844$ 466,295$ 466,005$ 440,385$ 396,911$ 416,169$
2014 419,775$ 380,020$ 422,364$ 376,158$ 405,025$ 479,856$ 425,015$ 477,771$ 477,460$ 451,166$ 404,588$ 426,425$
2015 431,594$ 392,546$ 434,354$ 387,835$ 416,878$ 492,270$ 436,664$ 489,945$ 489,829$ 463,121$ 413,658$ 437,955$
2016 443,908$ 404,808$ 446,313$ 399,539$ 428,918$ 505,686$ 448,817$ 503,715$ 503,647$ 476,216$ 424,479$ 450,362$
2017 452,714$ 415,937$ 455,621$ 408,613$ 438,179$ 515,764$ 458,067$ 514,080$ 514,295$ 486,104$ 430,786$ 459,676$
2018 464,075$ 427,161$ 467,136$ 419,098$ 449,243$ 528,171$ 469,557$ 526,775$ 526,976$ 498,080$ 440,130$ 471,063$
2019 475,497$ 439,077$ 478,742$ 429,828$ 460,569$ 540,647$ 481,146$ 539,566$ 539,753$ 510,119$ 450,818$ 482,344$ 2020 474,477$ 438,846$ 478,469$ 427,666$ 460,436$ 540,892$ 479,774$ 539,054$ 539,433$ 509,110$ 449,923$ 481,039$
2021 486,246$ 452,255$ 490,777$ 438,959$ 472,256$ 553,189$ 491,416$ 551,183$ 551,543$ 520,772$ 461,813$ 492,377$
2022 517,707$ 479,455$ 521,341$ 468,553$ 501,958$ 587,543$ 523,824$ 586,820$ 586,859$ 554,913$ 489,165$ 525,294$
2023 531,746$ 493,871$ 535,481$ 481,463$ 515,815$ 602,707$ 537,580$ 601,533$ 601,768$ 569,248$ 502,877$ 539,094$
2024 547,360$ 509,872$ 551,751$ 495,926$ 531,217$ 619,952$ 553,228$ 618,659$ 618,806$ 585,371$ 517,925$ 554,496$
2025 557,560$ 515,776$ 561,254$ 504,447$ 540,847$ 632,748$ 564,204$ 632,317$ 632,268$ 597,775$ 525,092$ 565,789$ 2026 572,720$ 531,555$ 576,927$ 518,771$ 555,972$ 649,207$ 579,079$ 648,239$ 648,212$ 613,128$ 540,478$ 580,623$
2027 585,542$ 540,240$ 589,006$ 529,216$ 568,773$ 664,706$ 592,520$ 664,217$ 664,219$ 628,020$ 550,161$ 594,360$
2028 602,904$ 557,796$ 606,685$ 545,361$ 586,089$ 683,845$ 609,605$ 682,865$ 683,065$ 645,881$ 567,891$ 611,470$
2029 617,264$ 572,726$ 621,575$ 559,079$ 600,309$ 699,458$ 623,834$ 698,347$ 698,430$ 660,642$ 581,645$ 625,645$
2030 633,936$ 589,760$ 638,472$ 574,592$ 616,787$ 717,570$ 640,140$ 716,051$ 716,184$ 677,610$ 598,428$ 641,984$
2031 651,547$ 608,037$ 656,378$ 591,028$ 634,443$ 736,553$ 657,238$ 734,468$ 734,611$ 695,263$ 617,654$ 658,926$
2032 671,305$ 628,370$ 676,534$ 609,714$ 653,903$ 757,924$ 676,524$ 755,436$ 755,597$ 715,395$ 637,383$ 678,255$
2033 683,914$ 638,488$ 688,945$ 620,203$ 668,520$ 773,387$ 690,078$ 771,539$ 771,627$ 730,306$ 647,409$ 691,908$
Total 13,081,460$ 12,077,220$ 13,172,492$ 11,836,463$ 12,644,733$ 14,728,484$ 13,226,820$ 14,544,988$ 14,832,739$ 13,854,699$ 12,390,049$ 13,167,979$
Discount Rate: 7.2002%
30-Year PV 4,134,065$ 3,803,665$ 4,162,206$ 3,743,696$ 3,975,823$ 4,620,182$ 4,182,155$ 4,512,034$ 4,696,702$ 4,329,101$ 3,919,143$ 4,130,597$
Levelized 351,899$ 323,774$ 354,294$ 318,670$ 338,429$ 393,278$ 355,992$ 384,072$ 399,791$ 368,500$ 333,604$ 351,603$
30-Year PV Rank 6 2 7 1 4 11 8 10 12 9 3 5
20-Year PV 3,051,517$ 2,797,920$ 3,071,997$ 2,763,093$ 2,923,245$ 3,393,913$ 3,088,343$ 3,287,966$ 3,472,489$ 3,171,037$ 2,897,033$ 3,033,779$
Levelized 302,888$ 277,717$ 304,921$ 274,260$ 290,156$ 336,874$ 306,544$ 326,358$ 344,673$ 314,752$ 287,554$ 301,128$
20-Year PV Rank 6 2 7 1 4 11 8 10 12 9 3 5
10-Year PV 1,386,035$ 1,267,508$ 1,395,084$ 1,261,523$ 1,311,011$ 1,497,571$ 1,403,574$ 1,397,716$ 1,581,950$ 1,384,286$ 1,311,154$ 1,344,033$
Levelized 206,216$ 188,582$ 207,563$ 187,691$ 195,054$ 222,811$ 208,826$ 207,954$ 235,365$ 205,956$ 195,075$ 199,967$
10-Year PV Rank 7 2 8 1 3 11 10 9 12 6 4 5
Page 1 of 2 AURORAxmp Ver. 7.1.0.0
Portfolio Bundles Analysis
Portfolios 0 through 11 CO2 Emission Data
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Portfolio CO2 Emission Amounts (Tons)
Year P0 - Balanced 0 P1 - Peakers P2 - Coal
P3 - Wind and
Peakers P4 - Balanced 1 P5 - Early Coal P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4 P9 - Balanced 5
P10 - Balanced
6
P11 - Balanced
7
2004 25,560,732 25,560,732 25,560,732 25,560,732 25,560,732 25,560,732 25,560,732 25,560,732 25,560,732 25,560,732 25,560,732 25,560,732
2005 25,522,482 25,522,482 25,522,482 25,522,482 25,515,649 25,522,482 25,515,649 25,515,649 25,515,649 25,516,485 25,516,485 25,515,649200625,558,889 25,526,713 25,526,713 25,558,889 25,525,089 25,524,960 25,525,089 25,525,089 25,542,096 25,540,626 25,540,626 25,525,089
2007 25,787,590 25,795,477 25,795,477 25,790,734 25,887,511 29,724,879 25,828,428 25,828,428 29,471,176 25,838,023 25,838,023 25,828,428
2008 25,720,139 25,802,854 25,854,145 25,749,471 25,860,853 29,521,810 25,812,134 25,751,567 29,445,766 25,737,839 25,737,839 25,751,567
2009 29,055,377 25,932,615 29,283,869 25,879,142 26,006,792 29,681,942 29,576,798 25,905,213 33,311,401 25,896,972 25,896,972 25,905,213
2010 29,190,310 26,155,429 29,430,222 25,978,396 26,129,469 29,844,849 29,679,596 29,660,320 33,376,049 29,670,166 27,421,960 26,086,824
2011 29,410,575 26,295,865 29,570,362 26,176,976 28,234,416 29,959,357 29,766,133 29,758,247 33,457,799 29,771,461 27,748,998 29,860,320
2012 29,493,636 26,479,341 29,671,114 26,354,582 28,411,533 33,735,855 29,864,672 29,852,398 33,550,297 29,847,619 27,682,134 29,958,447
2013 29,445,752 26,622,296 29,628,538 26,383,569 28,400,825 33,668,167 29,809,863 33,507,030 33,486,176 31,645,160 28,521,213 29,905,070
2014 29,428,463 26,641,446 29,609,939 26,370,687 28,394,376 33,640,426 29,795,799 33,494,314 33,472,486 31,629,126 28,363,794 29,894,694
2015 29,519,072 26,848,350 29,707,856 26,526,120 28,512,522 33,669,022 29,865,825 33,510,032 33,502,080 31,675,371 28,292,345 29,954,095
2016 29,620,743 27,011,745 29,781,248 26,660,175 28,620,502 33,743,040 29,948,300 33,611,536 33,607,017 31,776,618 28,324,303 30,051,432
2017 29,471,553 27,077,400 29,660,812 26,600,603 28,525,351 33,576,094 29,820,064 33,466,519 33,480,460 31,645,261 28,044,055 29,924,770
2018 29,474,346 27,129,850 29,668,753 26,617,749 28,532,312 33,545,177 29,822,489 33,456,491 33,469,281 31,634,020 27,953,553 29,918,133
2019 29,463,199 27,206,501 29,664,221 26,633,399 28,538,219 33,500,054 29,813,197 33,433,054 33,444,692 31,608,433 27,934,009 29,887,433
2020 28,682,902 26,528,963 28,924,244 25,853,128 27,834,088 32,697,791 29,003,115 32,586,685 32,609,593 30,776,492 27,198,571 29,079,602
2021 28,677,434 26,672,748 28,944,636 25,888,571 27,852,324 32,625,523 28,982,326 32,507,244 32,528,457 30,713,676 27,236,440 29,039,005
2022 29,788,215 27,587,208 29,997,264 26,959,944 28,881,997 33,806,454 30,140,162 33,764,891 33,767,126 31,928,985 28,145,922 30,224,767
2023 29,849,745 27,723,612 30,059,422 27,027,088 28,955,450 33,833,179 30,177,240 33,767,235 33,780,433 31,954,944 28,229,175 30,262,209
2024 29,976,827 27,923,713 30,217,284 27,159,962 29,092,740 33,952,393 30,298,197 33,881,607 33,889,647 32,058,514 28,364,772 30,367,645202529,790,663 27,558,130 29,988,054 26,952,804 28,897,662 33,807,979 30,145,660 33,784,970 33,782,318 31,939,362 28,055,896 30,230,364
2026 29,854,305 27,708,500 30,073,585 27,042,085 28,981,276 33,841,353 30,185,791 33,790,927 33,789,497 31,960,657 28,173,622 30,266,245
2027 29,778,215 27,474,350 29,954,404 26,913,720 28,925,441 33,804,171 30,133,101 33,779,297 33,779,423 31,938,464 27,978,902 30,226,667
2028 29,913,370 27,675,316 30,100,941 27,058,324 29,079,093 33,929,255 30,245,848 33,880,653 33,890,587 32,045,693 28,176,183 30,338,376
2029 29,878,852 27,722,961 30,087,556 27,062,380 29,058,167 33,857,473 30,196,889 33,803,686 33,807,720 31,978,595 28,154,735 30,284,542
2030 29,937,443 27,851,242 30,151,658 27,134,952 29,127,585 33,887,022 30,230,426 33,815,316 33,821,594 31,999,910 28,260,588 30,317,483203130,018,648 28,014,033 30,241,227 27,230,344 29,230,617 33,935,111 30,280,853 33,839,037 33,845,636 32,032,765 28,457,105 30,358,637
2032 30,174,604 28,244,699 30,409,642 27,406,152 29,392,371 34,068,036 30,409,163 33,956,229 33,963,453 32,156,384 28,649,806 30,487,009
2033 29,991,565 27,999,518 30,212,175 27,197,676 29,316,486 33,915,202 30,261,852 33,834,162 33,838,023 32,025,976 28,390,716 30,342,129
30 Year Total 868,035,647 808,294,087 873,298,574 795,250,836 841,281,447 966,379,789 876,695,388 948,828,560 974,786,665 910,504,329 827,849,472 871,352,577
20 Year Total 568,721,154 530,121,626 571,862,049 524,092,435 550,180,008 627,381,796 574,307,609 610,462,675 636,378,766 590,368,009 545,187,146 568,133,479
10 Year Total 274,745,483 259,693,804 275,843,653 258,954,973 265,532,869 292,745,035 276,939,093 276,864,673 302,717,142 275,025,083 265,464,981 269,897,340
30 Year Rank 5 2 7 1 4 11 8 10 12 9 3 6
20 Year Rank 6 2 7 1 4 11 8 10 12 9 3 5
10 Year Rank 6 2 8 1 4 11 10 9 12 7 3 5
Notes:All values are averaged over all hours of simulation. Hydro fleet modified from original May 2004 runs.
Base case includes all existing and committed resources as of January 1, 2004.
All costs nominal.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-23-2004
Special Note:
The amounts and costs herein include ALL of the
emissions produced by a given resource, not just Idaho
Power's share.
Page 2 of 2 AURORAxmp Ver. 7.1.0.0
2004 Integrated Resource Plan
Finalist Portfolios with Risk Analysis Scenarios
Portfolio Name Analysis Scenarios
Portfolio 0 Balanced 0 No DSM change as there was no DSM programs in original configuration.
Analysis with HIGH gas prices at Henry Hub.
Analysis with LOW gas prices at Henry Hub.
Portfolio 3 Wind and Peakers No DSM change as there was no DSM programs in original configuration.
Analysis with HIGH gas prices at Henry Hub.
Analysis with LOW gas prices at Henry Hub.
Portfolio 6 Balanced 2 DSM configuration changed to Irrigation Efficency, Industrial Effeciency,Commerical Efficiency New Construction,
and Residential Efficiency New Construction.
Analysis with HIGH gas prices at Henry Hub.
Analysis with LOW gas prices at Henry Hub.
Portfolio 7 Balanced 3 DSM configuration changed to Irrigation Efficency, Industrial Effeciency,Commerical Efficiency New Construction,
and Residential Efficiency New Construction.
Analysis with HIGH gas prices at Henry Hub.
Analysis with LOW gas prices at Henry Hub.
Portfolio 8 Balanced 4 DSM configuration changed to Irrigation Efficency, Industrial Effeciency,Commerical Efficiency New Construction,
and Residential Efficiency New Construction.
Analysis with HIGH gas prices at Henry Hub.
Analysis with LOW gas prices at Henry Hub.
Portfolio 11 Balanced 7 DSM configuration changed to Irrigation Efficency, Industrial Effeciency,Commerical Efficiency New Construction,
and Residential Efficiency New Construction.
Analysis with HIGH gas prices at Henry Hub.
Analysis with LOW gas prices at Henry Hub.
Portfolio Finalists Analysis - Portfolio Power Supply Costs with Varying CO2 Emission Costs
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $0.00/ton
Wind PTC set to $-19.00/MWh, not escalated
Portfolio Power Supply Cost ($ x 1000)
Year P0 - Balanced 0
P3 - Wind and
Peakers P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4
P11 - Balanced
7
2004 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$
2005 333,719$ 333,719$ 340,912$ 340,912$ 340,912$ 340,912$
2006 368,829$ 373,438$ 372,914$ 372,914$ 365,849$ 372,914$
2007 377,050$ 398,335$ 379,228$ 379,228$ 416,346$ 379,229$
2008 401,975$ 444,679$ 403,292$ 414,755$ 423,093$ 414,255$
2009 420,603$ 459,887$ 445,469$ 412,361$ 441,975$ 411,892$
2010 422,009$ 477,218$ 441,248$ 461,408$ 437,663$ 429,199$
2011 426,456$ 456,642$ 423,623$ 446,617$ 412,681$ 444,881$
2012 430,909$ 462,806$ 429,777$ 451,482$ 415,897$ 439,965$
2013 431,594$ 436,667$ 411,055$ 424,849$ 394,737$ 410,276$
2014 431,423$ 443,155$ 415,729$ 416,118$ 398,171$ 417,801$
2015 462,546$ 464,318$ 435,065$ 435,850$ 414,909$ 427,731$
2016 485,917$ 474,732$ 450,082$ 446,150$ 433,719$ 438,758$
2017 545,754$ 530,981$ 492,668$ 512,747$ 496,149$ 486,155$
2018 543,212$ 514,380$ 486,073$ 493,332$ 489,198$ 472,868$
2019 576,525$ 539,825$ 508,898$ 521,471$ 520,218$ 499,289$ 2020 633,810$ 593,844$ 571,863$ 557,509$ 567,765$ 546,916$
2021 655,186$ 611,865$ 603,734$ 570,100$ 583,993$ 568,282$
2022 672,471$ 611,977$ 609,655$ 589,044$ 605,630$ 573,183$
2023 707,842$ 640,611$ 639,919$ 611,150$ 630,726$ 598,014$
2024 751,740$ 664,877$ 680,713$ 652,606$ 669,732$ 619,418$
2025 799,624$ 713,369$ 742,817$ 683,214$ 717,920$ 668,832$ 2026 858,297$ 763,950$ 823,585$ 721,602$ 769,422$ 722,084$
2027 935,250$ 842,553$ 923,510$ 778,900$ 838,171$ 801,184$
2028 1,022,113$ 922,966$ 1,016,645$ 847,857$ 919,520$ 885,331$
2029 1,093,208$ 971,979$ 1,105,282$ 888,662$ 979,841$ 936,886$
2030 1,190,347$ 1,051,566$ 1,219,615$ 958,410$ 1,068,891$ 1,019,745$
2031 1,299,033$ 1,143,573$ 1,354,398$ 1,032,585$ 1,166,005$ 1,117,677$
2032 1,457,528$ 1,283,038$ 1,527,688$ 1,153,335$ 1,315,713$ 1,268,453$
2033 1,714,400$ 1,584,441$ 1,774,850$ 1,422,866$ 1,592,467$ 1,553,347$
Total 20,769,596$ 19,531,618$ 20,350,532$ 18,318,260$ 19,147,539$ 18,585,702$
Discount Rate: 7.2002%
30-Year PV 6,666,696$ 6,529,608$ 6,518,169$ 6,212,625$ 6,320,288$ 6,196,676$
Levelized 567,481$ 555,811$ 554,838$ 528,829$ 537,994$ 527,472$
30-Year PV Rank 6 5 4 2 3 1
20-Year PV 4,770,839$ 4,836,175$ 4,630,364$ 4,647,830$ 4,612,074$ 4,568,684$
Levelized 473,545$ 480,030$ 459,602$ 461,336$ 457,786$ 453,480$
20-Year PV Rank 5 6 3 4 2 1
10-Year PV 2,779,779$ 2,931,710$ 2,808,652$ 2,840,073$ 2,819,019$ 2,803,954$
Levelized 413,580$ 436,184$ 417,876$ 422,550$ 419,418$ 417,177$
10-Year PV Rank 1 6 3 5 4 2
Page 1 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs with Varying CO2 Emission Costs
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $0.00/ton
Wind PTC set to $-19.00/MWh, not escalated
Difference in Portfolio Power Supply Costs (Scenario - Base Case) ($ x 1000)
Year P0 - Balanced 0
P3 - Wind and
Peakers P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4
P11 - Balanced
7
2004 -$ -$ -$ -$ -$
2005 -$ 7,192$ 7,192$ 7,192$ 7,192$ 2006 4,608$ 4,084$ 4,084$ (2,981)$ 4,084$
2007 21,285$ 2,178$ 2,178$ 39,296$ 2,179$
2008 42,704$ 1,318$ 12,780$ 21,119$ 12,280$
2009 39,283$ 24,866$ (8,243)$ 21,372$ (8,711)$
2010 55,209$ 19,239$ 39,399$ 15,654$ 7,190$
2011 30,187$ (2,832)$ 20,161$ (13,775)$ 18,425$
2012 31,897$ (1,132)$ 20,574$ (15,011)$ 9,057$
2013 5,073$ (20,539)$ (6,745)$ (36,857)$ (21,318)$
2014 11,733$ (15,693)$ (15,305)$ (33,252)$ (13,622)$
2015 1,772$ (27,481)$ (26,696)$ (47,637)$ (34,815)$
2016 (11,185)$ (35,836)$ (39,768)$ (52,198)$ (47,159)$
2017 (14,772)$ (53,086)$ (33,007)$ (49,605)$ (59,598)$
2018 (28,832)$ (57,139)$ (49,880)$ (54,014)$ (70,344)$
2019 (36,701)$ (67,627)$ (55,054)$ (56,308)$ (77,237)$
2020 (39,965)$ (61,947)$ (76,300)$ (66,045)$ (86,893)$
2021 (43,321)$ (51,452)$ (85,086)$ (71,193)$ (86,904)$
2022 (60,495)$ (62,817)$ (83,427)$ (66,842)$ (99,289)$
2023 (67,231)$ (67,923)$ (96,692)$ (77,116)$ (109,828)$
2024 (86,864)$ (71,027)$ (99,134)$ (82,009)$ (132,322)$ 2025 (86,255)$ (56,807)$ (116,410)$ (81,703)$ (130,792)$
2026 (94,346)$ (34,712)$ (136,695)$ (88,874)$ (136,213)$
2027 (92,697)$ (11,740)$ (156,350)$ (97,078)$ (134,065)$
2028 (99,147)$ (5,468)$ (174,256)$ (102,593)$ (136,782)$
2029 (121,229)$ 12,073$ (204,547)$ (113,367)$ (156,322)$
2030 (138,781)$ 29,268$ (231,937)$ (121,456)$ (170,602)$ 2031 (155,460)$ 55,365$ (266,447)$ (133,027)$ (181,356)$
2032 (174,489)$ 70,161$ (304,193)$ (141,815)$ (189,075)$
2033 (129,959)$ 60,451$ (291,534)$ (121,933)$ (161,053)$
Total (1,237,978)$ (419,063)$ (2,451,336)$ (1,622,057)$ (2,183,893)$
Discount Rate: 7.2002%30-Year PV (137,088)$ (148,527)$ (454,071)$ (346,409)$ (470,020)$
Levelized (11,669)$ (12,643)$ (38,651)$ (29,487)$ (40,009)$
30-Year PV Rank 5 4 2 3 1
20-Year PV 65,336$ (140,475)$ (123,009)$ (158,766)$ (202,155)$
Levelized 6,485$ (13,943)$ (12,210)$ (15,759)$ (20,066)$
20-Year PV Rank 5 3 4 2 1
10-Year PV 151,931$ 28,873$ 60,294$ 39,240$ 24,175$
Levelized 22,605$ 4,296$ 8,971$ 5,838$ 3,597$
10-Year PV Rank 5 2 4 3 1
Notes:All values are averaged over all hours of simulation. Hydro fleet modified from original May 2004 runs. Transmission costs modified from original May 2004 values.Base case includes all existing and committed resources as of January 1, 2004.
All costs nominal.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-30-2004
Page 2 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs with Varying CO2 Emission Costs
Portfolios 3, 6, 7, 8 & 11 Comparison
NPV Comparison of Portfolio Differences (Portfolio - Balanced 0)
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $0.00/ton
Wind PTC set to $-19.00/MWh, not escalated
-$1,000
-$900
-$800
-$700
-$600
-$500
-$400
-$300
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
2
0
0
4
2
0
0
5
2
0
0
6
2
0
0
7
2
0
0
8
2
0
0
9
2
0
1
0
2
0
1
1
2
0
1
2
2
0
1
3
2
0
1
4
2
0
1
5
2
0
1
6
2
0
1
7
2
0
1
8
2
0
1
9
2
0
2
0
2
0
2
1
2
0
2
2
2
0
2
3
2
0
2
4
2
0
2
5
2
0
2
6
2
0
2
7
2
0
2
8
2
0
2
9
2
0
3
0
2
0
3
1
2
0
3
2
2
0
3
3
P3 - Wind and Peakers
P6 - Balanced 2
P7 - Balanced 3
P8 - Balanced 4
P11 - Balanced 7
Page 3 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs with Varying CO2 Emission Costs
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Portfolio Power Supply Cost ($ x 1000)
Year P0 - Balanced 0
P3 - Wind and
Peakers P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4
P11 - Balanced
7
2004 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$
2005 333,719$ 333,719$ 340,912$ 340,912$ 340,912$ 340,912$
2006 368,829$ 373,438$ 372,914$ 372,914$ 365,849$ 372,914$
2007 377,050$ 398,335$ 379,228$ 379,228$ 416,346$ 379,229$
2008 497,670$ 534,726$ 496,291$ 505,703$ 530,455$ 505,203$
2009 531,069$ 548,935$ 554,149$ 507,129$ 565,738$ 506,661$
2010 539,583$ 566,677$ 558,011$ 574,144$ 566,961$ 527,357$
2011 544,179$ 546,164$ 546,026$ 566,210$ 556,920$ 559,064$
2012 555,247$ 560,583$ 553,809$ 574,660$ 556,582$ 549,791$
2013 551,414$ 538,772$ 541,326$ 548,174$ 544,905$ 529,641$
2014 562,842$ 554,584$ 556,608$ 559,822$ 541,919$ 549,321$
2015 609,256$ 588,972$ 577,236$ 587,705$ 580,028$ 560,821$
2016 625,815$ 597,355$ 595,983$ 605,273$ 606,283$ 582,355$
2017 694,657$ 659,709$ 645,017$ 675,476$ 673,600$ 640,110$
2018 699,452$ 644,585$ 646,793$ 669,615$ 669,583$ 630,004$
2019 739,065$ 677,061$ 677,716$ 703,094$ 705,963$ 663,341$ 2020 788,540$ 723,800$ 731,332$ 734,119$ 747,902$ 705,822$
2021 819,552$ 746,491$ 768,279$ 758,535$ 772,624$ 728,860$
2022 857,189$ 772,217$ 798,489$ 796,843$ 816,068$ 755,702$
2023 900,126$ 803,338$ 835,705$ 830,091$ 848,759$ 788,630$
2024 956,429$ 840,836$ 886,000$ 871,545$ 903,314$ 818,945$
2025 1,008,714$ 893,237$ 953,974$ 916,387$ 953,668$ 873,752$ 2026 1,078,349$ 951,807$ 1,042,010$ 966,157$ 1,016,976$ 934,797$
2027 1,159,219$ 1,039,206$ 1,146,240$ 1,022,529$ 1,087,028$ 1,026,810$
2028 1,253,880$ 1,127,217$ 1,253,078$ 1,103,126$ 1,181,522$ 1,113,987$
2029 1,333,562$ 1,182,679$ 1,347,645$ 1,154,349$ 1,250,536$ 1,174,003$
2030 1,439,221$ 1,269,857$ 1,471,025$ 1,232,630$ 1,348,553$ 1,264,704$
2031 1,557,503$ 1,370,654$ 1,614,084$ 1,315,798$ 1,455,130$ 1,372,596$
2032 1,725,025$ 1,519,581$ 1,798,440$ 1,447,013$ 1,615,935$ 1,532,214$
2033 1,993,717$ 1,832,592$ 2,054,133$ 1,730,137$ 1,902,829$ 1,824,906$
Total 25,421,098$ 23,517,351$ 25,062,676$ 23,369,543$ 24,443,113$ 23,132,674$
Discount Rate: 7.2002%
30-Year PV 8,063,729$ 7,712,219$ 7,935,497$ 7,698,760$ 7,919,749$ 7,547,098$
Levelized 686,398$ 656,477$ 675,483$ 655,332$ 674,143$ 642,422$
30-Year PV Rank 6 3 5 2 4 1
20-Year PV 5,748,583$ 5,652,830$ 5,626,161$ 5,673,429$ 5,740,141$ 5,506,979$
Levelized 570,594$ 561,090$ 558,443$ 563,135$ 569,756$ 546,613$
20-Year PV Rank 6 3 2 4 5 1
10-Year PV 3,200,589$ 3,275,284$ 3,233,762$ 3,245,902$ 3,305,365$ 3,187,854$
Levelized 476,189$ 487,302$ 481,124$ 482,930$ 491,777$ 474,294$
10-Year PV Rank 2 5 3 4 6 1
Page 4 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs with Varying CO2 Emission Costs
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Difference in Portfolio Power Supply Costs (Scenario - Base Case) ($ x 1000)
Year P0 - Balanced 0
P3 - Wind and
Peakers P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4
P11 - Balanced
7
2004 -$ -$ -$ -$ -$
2005 -$ 7,192$ 7,192$ 7,192$ 7,192$ 2006 4,608$ 4,084$ 4,084$ (2,981)$ 4,084$
2007 21,285$ 2,178$ 2,178$ 39,296$ 2,179$
2008 37,057$ (1,379)$ 8,033$ 32,786$ 7,534$
2009 17,866$ 23,079$ (23,940)$ 34,669$ (24,409)$
2010 27,094$ 18,428$ 34,561$ 27,379$ (12,226)$
2011 1,985$ 1,848$ 22,031$ 12,741$ 14,885$
2012 5,336$ (1,438)$ 19,413$ 1,335$ (5,456)$
2013 (12,642)$ (10,088)$ (3,240)$ (6,509)$ (21,773)$
2014 (8,258)$ (6,233)$ (3,020)$ (20,923)$ (13,520)$
2015 (20,283)$ (32,019)$ (21,551)$ (29,228)$ (48,435)$
2016 (28,461)$ (29,833)$ (20,543)$ (19,533)$ (43,460)$
2017 (34,948)$ (49,640)$ (19,181)$ (21,058)$ (54,548)$
2018 (54,867)$ (52,659)$ (29,837)$ (29,868)$ (69,448)$
2019 (62,004)$ (61,349)$ (35,971)$ (33,101)$ (75,724)$
2020 (64,740)$ (57,209)$ (54,421)$ (40,638)$ (82,718)$
2021 (73,062)$ (51,273)$ (61,017)$ (46,928)$ (90,692)$
2022 (84,971)$ (58,700)$ (60,345)$ (41,121)$ (101,487)$
2023 (96,788)$ (64,422)$ (70,035)$ (51,368)$ (111,497)$
2024 (115,593)$ (70,429)$ (84,884)$ (53,114)$ (137,484)$ 2025 (115,478)$ (54,741)$ (92,328)$ (55,046)$ (134,962)$
2026 (126,542)$ (36,340)$ (112,192)$ (61,373)$ (143,553)$
2027 (120,013)$ (12,979)$ (136,690)$ (72,191)$ (132,409)$
2028 (126,662)$ (802)$ (150,753)$ (72,358)$ (139,893)$
2029 (150,883)$ 14,083$ (179,213)$ (83,025)$ (159,559)$
2030 (169,364)$ 31,805$ (206,590)$ (90,668)$ (174,517)$ 2031 (186,849)$ 56,580$ (241,705)$ (102,373)$ (184,907)$
2032 (205,444)$ 73,416$ (278,012)$ (109,090)$ (192,811)$
2033 (161,125)$ 60,417$ (263,580)$ (90,888)$ (168,811)$
Total (1,903,747)$ (358,422)$ (2,051,555)$ (977,985)$ (2,288,424)$
Discount Rate: 7.2002%30-Year PV (351,510)$ (128,233)$ (364,969)$ (143,980)$ (516,631)$
Levelized (29,921)$ (10,915)$ (31,067)$ (12,256)$ (43,977)$
30-Year PV Rank 3 5 2 4 1
20-Year PV (95,753)$ (122,422)$ (75,154)$ (8,442)$ (241,604)$
Levelized (9,504)$ (12,151)$ (7,460)$ (838)$ (23,981)$
20-Year PV Rank 3 2 4 5 1
10-Year PV 74,695$ 33,173$ 45,313$ 104,776$ (12,735)$
Levelized 11,113$ 4,936$ 6,742$ 15,589$ (1,895)$
10-Year PV Rank 4 2 3 5 1
Notes:All values are averaged over all hours of simulation. Hydro fleet modified from original May 2004 runs. Transmission costs modified from original May 2004 values.Base case includes all existing and committed resources as of January 1, 2004.
All costs nominal.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-30-2004
Page 5 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs with Varying CO2 Emission Costs
Portfolios 3, 6, 7, 8 & 11 Comparison
NPV Comparison of Portfolio Differences (Portfolio - Balanced 0)
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
-$1,000
-$900
-$800
-$700
-$600
-$500
-$400
-$300
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
2
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4
2
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m
i
l
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i
o
n
s

o
f

d
o
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a
r
s
P3 - Wind and Peakers
P6 - Balanced 2
P7 - Balanced 3
P8 - Balanced 4
P11 - Balanced 7
Page 6 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs with Varying CO2 Emission Costs
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $49.21/tonstarting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Portfolio Power Supply Cost ($ x 1000)
Year P0 - Balanced 0
P3 - Wind and
Peakers P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4
P11 - Balanced
7
2004 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$
2005 333,719$ 333,719$ 340,912$ 340,912$ 340,912$ 340,912$
2006 368,829$ 373,438$ 372,914$ 372,914$ 365,849$ 372,914$
2007 377,050$ 398,335$ 379,228$ 379,228$ 416,346$ 379,229$
2008 766,680$ 779,030$ 762,716$ 761,101$ 831,338$ 760,601$
2009 839,668$ 785,950$ 860,886$ 776,764$ 907,554$ 776,295$
2010 867,915$ 811,457$ 885,056$ 890,610$ 929,639$ 799,674$
2011 881,062$ 799,460$ 878,975$ 888,582$ 918,892$ 861,052$
2012 900,534$ 812,738$ 889,494$ 907,784$ 937,071$ 865,822$
2013 903,521$ 812,581$ 903,804$ 934,157$ 936,465$ 867,928$
2014 934,162$ 843,332$ 940,843$ 957,331$ 969,284$ 900,423$
2015 990,878$ 895,509$ 993,488$ 1,004,090$ 1,018,241$ 943,672$
2016 1,034,902$ 930,166$ 1,038,818$ 1,044,543$ 1,070,452$ 983,983$
2017 1,129,476$ 1,037,357$ 1,131,087$ 1,148,258$ 1,167,274$ 1,085,908$
2018 1,151,742$ 1,051,214$ 1,162,539$ 1,163,243$ 1,192,442$ 1,104,328$
2019 1,211,297$ 1,104,129$ 1,213,600$ 1,218,381$ 1,249,852$ 1,156,794$ 2020 1,253,900$ 1,143,606$ 1,254,634$ 1,241,632$ 1,276,904$ 1,183,399$
2021 1,299,684$ 1,182,496$ 1,306,567$ 1,280,510$ 1,332,761$ 1,233,126$
2022 1,398,370$ 1,272,215$ 1,411,104$ 1,385,618$ 1,429,542$ 1,327,312$
2023 1,473,157$ 1,335,079$ 1,488,482$ 1,441,283$ 1,500,763$ 1,389,619$
2024 1,563,502$ 1,420,060$ 1,589,340$ 1,522,436$ 1,582,390$ 1,475,033$
2025 1,630,224$ 1,481,074$ 1,657,007$ 1,588,824$ 1,654,322$ 1,541,280$ 2026 1,741,268$ 1,578,269$ 1,777,079$ 1,671,776$ 1,756,530$ 1,637,518$
2027 1,838,735$ 1,672,342$ 1,889,767$ 1,758,314$ 1,848,207$ 1,734,731$
2028 1,974,190$ 1,791,768$ 2,021,112$ 1,869,660$ 1,981,177$ 1,854,185$
2029 2,085,850$ 1,886,602$ 2,156,599$ 1,957,136$ 2,091,027$ 1,955,366$
2030 2,231,626$ 2,011,296$ 2,321,367$ 2,078,695$ 2,231,778$ 2,095,288$
2031 2,396,284$ 2,149,032$ 2,507,587$ 2,201,824$ 2,376,335$ 2,242,207$
2032 2,617,556$ 2,354,057$ 2,733,596$ 2,389,202$ 2,595,790$ 2,448,563$
2033 2,894,627$ 2,663,605$ 2,967,698$ 2,697,971$ 2,895,622$ 2,746,960$
Total 39,410,633$ 36,030,142$ 40,156,524$ 38,193,003$ 40,124,985$ 37,384,346$
Discount Rate: 7.2002%
30-Year PV 12,162,062$ 11,256,068$ 12,316,377$ 11,979,208$ 12,520,500$ 11,624,213$
Levelized 1,035,256$ 958,136$ 1,048,391$ 1,019,691$ 1,065,766$ 989,473$
30-Year PV Rank 4 1 5 3 6 2
20-Year PV 8,542,976$ 7,976,023$ 8,591,003$ 8,560,138$ 8,890,071$ 8,219,011$
Levelized 847,961$ 791,686$ 852,728$ 849,664$ 882,413$ 815,805$
20-Year PV Rank 3 1 5 4 6 2
10-Year PV 4,389,906$ 4,202,879$ 4,416,803$ 4,393,279$ 4,617,279$ 4,260,929$
Levelized 653,137$ 625,311$ 657,139$ 653,639$ 686,966$ 633,948$
10-Year PV Rank 3 1 5 4 6 2
Page 7 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs with Varying CO2 Emission Costs
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $49.21/tonstarting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Difference in Portfolio Power Supply Costs (Scenario - Base Case) ($ x 1000)
Year P0 - Balanced 0
P3 - Wind and
Peakers P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4
P11 - Balanced
7
2004 -$ -$ -$ -$ -$
2005 -$ 7,192$ 7,192$ 7,192$ 7,192$ 2006 4,608$ 4,084$ 4,084$ (2,981)$ 4,084$
2007 21,285$ 2,178$ 2,178$ 39,296$ 2,179$
2008 12,350$ (3,964)$ (5,579)$ 64,658$ (6,079)$
2009 (53,718)$ 21,218$ (62,904)$ 67,886$ (63,373)$
2010 (56,458)$ 17,141$ 22,695$ 61,723$ (68,241)$
2011 (81,602)$ (2,087)$ 7,520$ 37,830$ (20,010)$ 2012 (87,796)$ (11,040)$ 7,250$ 36,537$ (34,712)$
2013 (90,940)$ 282$ 30,636$ 32,944$ (35,594)$
2014 (90,830)$ 6,681$ 23,169$ 35,122$ (33,740)$
2015 (95,368)$ 2,610$ 13,212$ 27,363$ (47,206)$
2016 (104,736)$ 3,917$ 9,642$ 35,551$ (50,919)$
2017 (92,119)$ 1,611$ 18,782$ 37,798$ (43,568)$
2018 (100,528)$ 10,796$ 11,500$ 40,700$ (47,414)$
2019 (107,168)$ 2,303$ 7,084$ 38,555$ (54,503)$
2020 (110,294)$ 735$ (12,267)$ 23,004$ (70,500)$
2021 (117,188)$ 6,883$ (19,173)$ 33,077$ (66,557)$
2022 (126,155)$ 12,734$ (12,752)$ 31,172$ (71,058)$
2023 (138,077)$ 15,326$ (31,873)$ 27,607$ (83,537)$
2024 (143,442)$ 25,838$ (41,065)$ 18,888$ (88,469)$ 2025 (149,150)$ 26,783$ (41,400)$ 24,098$ (88,944)$
2026 (162,999)$ 35,811$ (69,492)$ 15,262$ (103,751)$
2027 (166,393)$ 51,032$ (80,421)$ 9,472$ (104,004)$
2028 (182,422)$ 46,922$ (104,530)$ 6,987$ (120,005)$
2029 (199,247)$ 70,749$ (128,713)$ 5,177$ (130,484)$
2030 (220,330)$ 89,742$ (152,931)$ 152$ (136,338)$ 2031 (247,253)$ 111,302$ (194,461)$ (19,949)$ (154,077)$
2032 (263,499)$ 116,041$ (228,354)$ (21,766)$ (168,993)$
2033 (231,022)$ 73,072$ (196,656)$ 995$ (147,667)$
Total (3,380,491)$ 745,891$ (1,217,630)$ 714,352$ (2,026,287)$
Discount Rate: 7.2002%30-Year PV (905,994)$ 154,314$ (182,854)$ 358,437$ (537,850)$
Levelized (77,120)$ 13,135$ (15,565)$ 30,511$ (45,783)$
30-Year PV Rank 1 4 3 5 2
20-Year PV (566,953)$ 48,027$ 17,162$ 347,095$ (323,965)$
Levelized (56,275)$ 4,767$ 1,703$ 34,452$ (32,156)$
20-Year PV Rank 1 4 3 5 2
10-Year PV (187,026)$ 26,898$ 3,373$ 227,374$ (128,976)$
Levelized (27,826)$ 4,002$ 502$ 33,829$ (19,189)$
10-Year PV Rank 1 4 3 5 2
Notes:All values are averaged over all hours of simulation. Hydro fleet modified from original May 2004 runs. Transmission costs modified from original May 2004 values.Base case includes all existing and committed resources as of January 1, 2004.
All costs nominal.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-30-2004
Page 8 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs with Varying CO2 Emission Costs
Portfolios 3, 6, 7, 8 & 11 Comparison
NPV Comparison of Portfolio Differences (Portfolio - Balanced 0)
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $49.21/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
-$1,000
-$900
-$800
-$700
-$600
-$500
-$400
-$300
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
2
0
0
4
2
0
0
5
2
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6
2
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P3 - Wind and Peakers
P6 - Balanced 2
P7 - Balanced 3
P8 - Balanced 4
P11 - Balanced 7
Page 9 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs with No Wind PTC
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $0.00/MWh
Portfolio Power Supply Cost ($ x 1000)
Year P0 - Balanced 0
P3 - Wind and
Peakers P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4
P11 - Balanced
7
2004 320,226$ 320,226$ 320,226$ 320,226$ 320,226$ 320,226$
2005 333,719$ 333,719$ 340,912$ 340,912$ 340,912$ 340,912$
2006 379,364$ 383,972$ 379,068$ 379,068$ 371,987$ 379,068$
2007 388,965$ 421,512$ 390,660$ 390,660$ 421,837$ 390,662$
2008 509,169$ 569,906$ 508,036$ 517,361$ 535,858$ 516,862$
2009 542,459$ 595,140$ 566,709$ 518,116$ 570,791$ 517,647$
2010 550,938$ 625,776$ 569,138$ 585,656$ 573,488$ 547,419$
2011 560,957$ 603,673$ 557,982$ 576,312$ 555,697$ 575,791$
2012 566,013$ 623,341$ 566,799$ 581,260$ 556,579$ 577,884$
2013 565,721$ 591,247$ 551,811$ 569,434$ 544,267$ 555,999$
2014 574,247$ 608,664$ 565,038$ 575,964$ 550,283$ 560,627$
2015 614,988$ 642,063$ 593,441$ 600,327$ 578,269$ 589,735$
2016 643,912$ 652,953$ 609,701$ 617,448$ 607,916$ 606,029$
2017 704,463$ 713,424$ 658,890$ 686,076$ 678,081$ 660,487$
2018 709,364$ 704,054$ 658,680$ 680,753$ 675,535$ 649,649$
2019 750,917$ 738,882$ 689,360$ 715,426$ 713,586$ 679,800$ 2020 798,617$ 781,103$ 742,397$ 747,544$ 752,230$ 724,191$
2021 831,927$ 806,711$ 780,746$ 766,919$ 779,698$ 744,955$
2022 865,453$ 831,622$ 809,749$ 807,390$ 821,670$ 776,225$
2023 908,487$ 860,154$ 846,376$ 841,539$ 860,298$ 805,642$
2024 966,801$ 899,275$ 897,733$ 883,034$ 909,301$ 839,201$
2025 1,020,243$ 951,126$ 965,565$ 928,126$ 959,500$ 894,366$ 2026 1,087,762$ 1,009,132$ 1,053,759$ 977,286$ 1,022,178$ 950,716$
2027 1,170,700$ 1,096,584$ 1,161,521$ 1,030,852$ 1,098,540$ 1,048,326$
2028 1,265,842$ 1,185,405$ 1,264,662$ 1,115,765$ 1,187,218$ 1,135,217$
2029 1,344,892$ 1,240,509$ 1,359,112$ 1,165,272$ 1,255,991$ 1,193,983$
2030 1,451,097$ 1,327,939$ 1,482,868$ 1,244,398$ 1,354,496$ 1,285,235$
2031 1,568,967$ 1,428,780$ 1,625,681$ 1,327,898$ 1,460,974$ 1,392,454$
2032 1,737,226$ 1,578,013$ 1,809,785$ 1,458,868$ 1,621,630$ 1,552,806$
2033 2,004,324$ 1,889,418$ 2,064,231$ 1,743,349$ 1,908,672$ 1,845,637$
Total 25,737,759$ 25,014,324$ 25,390,636$ 23,693,238$ 24,587,707$ 23,657,746$
Discount Rate: 7.2002%
30-Year PV 8,187,108$ 8,237,984$ 8,058,844$ 7,820,944$ 7,969,531$ 7,734,868$
Levelized 696,901$ 701,231$ 685,983$ 665,732$ 678,380$ 658,405$
30-Year PV Rank 5 6 4 2 3 1
20-Year PV 5,851,949$ 6,074,800$ 5,728,138$ 5,775,123$ 5,778,535$ 5,658,775$
Levelized 580,854$ 602,974$ 568,565$ 573,229$ 573,567$ 561,680$
20-Year PV Rank 5 6 2 3 4 1
10-Year PV 3,265,504$ 3,493,172$ 3,291,845$ 3,304,020$ 3,325,324$ 3,269,882$
Levelized 485,847$ 519,719$ 489,766$ 491,577$ 494,747$ 486,498$
10-Year PV Rank 1 6 3 4 5 2
Page 10 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs with No Wind PTC
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $0.00/MWh
Difference in Portfolio Power Supply Costs (Scenario - Base Case) ($ x 1000)
Year P0 - Balanced 0
P3 - Wind and
Peakers P6 - Balanced 2 P7 - Balanced 3 P8 - Balanced 4
P11 - Balanced
7
2004 -$ -$ -$ -$ -$
2005 -$ 7,192$ 7,192$ 7,192$ 7,192$ 2006 4,608$ (296)$ (296)$ (7,377)$ (296)$
2007 32,547$ 1,695$ 1,695$ 32,871$ 1,696$
2008 60,736$ (1,134)$ 8,192$ 26,689$ 7,692$
2009 52,681$ 24,250$ (24,344)$ 28,332$ (24,813)$
2010 74,838$ 18,200$ 34,719$ 22,550$ (3,519)$
2011 42,716$ (2,974)$ 15,356$ (5,260)$ 14,834$
2012 57,328$ 786$ 15,247$ (9,434)$ 11,871$
2013 25,526$ (13,910)$ 3,713$ (21,454)$ (9,722)$
2014 34,417$ (9,209)$ 1,718$ (23,964)$ (13,620)$
2015 27,075$ (21,547)$ (14,661)$ (36,719)$ (25,253)$
2016 9,041$ (34,211)$ (26,464)$ (35,996)$ (37,883)$
2017 8,962$ (45,573)$ (18,387)$ (26,382)$ (43,976)$
2018 (5,310)$ (50,684)$ (28,611)$ (33,829)$ (59,715)$
2019 (12,036)$ (61,557)$ (35,491)$ (37,332)$ (71,118)$
2020 (17,514)$ (56,220)$ (51,073)$ (46,386)$ (74,426)$
2021 (25,215)$ (51,181)$ (65,007)$ (52,229)$ (86,972)$
2022 (33,831)$ (55,704)$ (58,063)$ (43,783)$ (89,228)$
2023 (48,333)$ (62,111)$ (66,948)$ (48,189)$ (102,846)$
2024 (67,526)$ (69,068)$ (83,767)$ (57,500)$ (127,600)$ 2025 (69,117)$ (54,678)$ (92,117)$ (60,743)$ (125,878)$
2026 (78,630)$ (34,004)$ (110,476)$ (65,584)$ (137,046)$
2027 (74,115)$ (9,178)$ (139,847)$ (72,160)$ (122,373)$
2028 (80,438)$ (1,180)$ (150,077)$ (78,625)$ (130,626)$
2029 (104,383)$ 14,220$ (179,620)$ (88,900)$ (150,909)$
2030 (123,158)$ 31,772$ (206,699)$ (96,601)$ (165,862)$ 2031 (140,188)$ 56,713$ (241,070)$ (107,993)$ (176,513)$
2032 (159,213)$ 72,560$ (278,358)$ (115,596)$ (184,420)$
2033 (114,906)$ 59,908$ (260,975)$ (95,652)$ (158,687)$
Total (723,435)$ (347,123)$ (2,044,521)$ (1,150,052)$ (2,080,013)$
Discount Rate: 7.2002%30-Year PV 50,875$ (128,265)$ (366,164)$ (217,578)$ (452,241)$
Levelized 4,331$ (10,918)$ (31,169)$ (18,521)$ (38,495)$
30-Year PV Rank 5 4 2 3 1
20-Year PV 222,851$ (123,811)$ (76,826)$ (73,415)$ (193,174)$
Levelized 22,120$ (12,289)$ (7,626)$ (7,287)$ (19,174)$
20-Year PV Rank 5 2 3 4 1
10-Year PV 227,667$ 26,341$ 38,515$ 59,820$ 4,378$
Levelized 33,873$ 3,919$ 5,730$ 8,900$ 651$
10-Year PV Rank 5 2 3 4 1
Notes:All values are averaged over all hours of simulation. Hydro fleet modified from original May 2004 runs. Transmission costs modified from original May 2004 values.Base case includes all existing and committed resources as of January 1, 2004.
All costs nominal.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-30-2004
Page 11 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs with No Wind PTC
Portfolios 3, 6, 7, 8 & 11 Comparison
NPV Comparison of Portfolio Differences (Portfolio - Balanced 0)
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $0.00/MWh
-$1,000
-$900
-$800
-$700
-$600
-$500
-$400
-$300
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
2
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P3 - Wind and Peakers
P6 - Balanced 2
P7 - Balanced 3
P8 - Balanced 4
P11 - Balanced 7
Page 12 of 12 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs, Natural Gas Prices at LOW Scenario
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Portfolio Power Supply Cost ($ x 1000)
Year P0 LOW Gas P3 Gas LOW DSM no change P6 Gas LOW DSM NEW P7 Gas LOW DSM New P8 Gas LOW DSM NEW P11 Gas LOW DSM NEW
2004 326,144$ 326,144$ 326,144$ 326,144$ 326,144$ 326,144$
2005 347,744$ 347,744$ 355,549$ 355,549$ 355,549$ 355,549$
2006 377,944$ 382,552$ 379,490$ 379,490$ 376,005$ 379,490$
2007 382,688$ 409,589$ 387,669$ 387,669$ 440,347$ 387,671$ 2008 504,725$ 548,584$ 507,470$ 520,191$ 553,134$ 519,691$
2009 550,519$ 566,833$ 577,789$ 517,130$ 600,555$ 516,661$
2010 553,967$ 586,393$ 576,642$ 595,551$ 596,057$ 537,043$
2011 556,161$ 567,297$ 547,369$ 578,663$ 575,209$ 570,306$
2012 560,198$ 572,572$ 563,587$ 583,757$ 577,788$ 581,103$ 2013 559,139$ 540,327$ 546,124$ 565,206$ 548,132$ 536,897$
2014 571,360$ 554,626$ 555,649$ 585,950$ 570,960$ 560,341$
2015 610,988$ 588,120$ 580,140$ 610,607$ 587,273$ 575,064$
2016 624,129$ 592,580$ 595,832$ 624,037$ 608,306$ 579,607$
2017 693,088$ 649,744$ 639,644$ 686,200$ 676,962$ 638,838$ 2018 691,573$ 632,854$ 638,617$ 675,786$ 671,961$ 628,750$
2019 726,047$ 665,448$ 665,279$ 712,435$ 707,491$ 656,697$
2020 773,038$ 703,476$ 713,407$ 733,836$ 741,033$ 683,883$
2021 802,052$ 715,435$ 744,498$ 752,663$ 760,052$ 712,883$
2022 871,238$ 782,701$ 821,576$ 816,357$ 836,598$ 778,959$ 2023 910,069$ 814,951$ 864,277$ 848,576$ 869,443$ 807,140$
2024 968,545$ 854,553$ 914,169$ 894,822$ 924,390$ 846,286$
2025 1,024,471$ 905,622$ 980,925$ 938,381$ 976,118$ 899,640$
2026 1,095,397$ 958,824$ 1,071,479$ 991,213$ 1,039,831$ 957,099$
2027 1,169,528$ 1,047,790$ 1,171,799$ 1,050,098$ 1,109,102$ 1,047,661$ 2028 1,266,964$ 1,136,089$ 1,280,304$ 1,124,811$ 1,205,092$ 1,141,944$
2029 1,353,980$ 1,198,841$ 1,381,802$ 1,180,017$ 1,279,428$ 1,205,550$
2030 1,463,999$ 1,290,508$ 1,510,615$ 1,264,770$ 1,381,770$ 1,301,883$
2031 1,528,987$ 1,334,300$ 1,592,065$ 1,304,204$ 1,437,349$ 1,353,008$
2032 1,672,792$ 1,457,343$ 1,744,173$ 1,413,681$ 1,577,609$ 1,484,933$ 2033 1,929,680$ 1,761,605$ 1,991,914$ 1,692,459$ 1,857,019$ 1,773,842$
Total 25,467,152$ 23,493,448$ 25,225,998$ 23,710,255$ 24,766,707$ 23,344,562$
Discount Rate: 7.2002%
30-Year PV 8,130,336$ 7,771,448$ 8,026,131$ 7,854,185$ 8,094,880$ 7,657,807$ Levelized 692,068$ 661,519$ 683,198$ 668,562$ 689,050$ 651,846$
30-Year PV Rank 6 2 4 3 5 1
20-Year PV 5,813,039$ 5,718,289$ 5,694,531$ 5,805,456$ 5,895,422$ 5,596,215$
Levelized 576,992$ 567,587$ 565,229$ 576,239$ 585,169$ 555,471$ 20-Year PV Rank 5 3 2 4 6 1
10-Year PV 3,272,450$ 3,365,001$ 3,309,663$ 3,329,222$ 3,434,746$ 3,270,248$
Levelized 486,880$ 500,650$ 492,417$ 495,327$ 511,027$ 486,553$
10-Year PV Rank 2 5 3 4 6 1
Page 1 of 6 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs, Natural Gas Prices at LOW Scenario
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalatedDifference in Portfolio Power Supply Costs (Scenario - Base Case) ($ x 1000)
Year P0 LOW Gas P3 Gas LOW DSM no change P6 Gas LOW DSM NEW P7 Gas LOW DSM New P8 Gas LOW DSM NEW P11 Gas LOW DSM NEW
2004 -$ -$ -$ -$ -$
2005 -$ 7,805$ 7,805$ 7,805$ 7,805$
2006 4,608$ 1,546$ 1,546$ (1,939)$ 1,546$
2007 26,901$ 4,982$ 4,982$ 57,659$ 4,983$
2008 43,859$ 2,745$ 15,466$ 48,410$ 14,967$ 2009 16,314$ 27,270$ (33,390)$ 50,036$ (33,859)$
2010 32,426$ 22,675$ 41,584$ 42,090$ (16,924)$
2011 11,136$ (8,792)$ 22,502$ 19,048$ 14,145$
2012 12,374$ 3,388$ 23,559$ 17,590$ 20,904$
2013 (18,811)$ (13,014)$ 6,067$ (11,007)$ (22,242)$
2014 (16,734)$ (15,711)$ 14,590$ (399)$ (11,018)$
2015 (22,868)$ (30,848)$ (381)$ (23,716)$ (35,925)$
2016 (31,549)$ (28,297)$ (92)$ (15,823)$ (44,522)$
2017 (43,344)$ (53,444)$ (6,888)$ (16,126)$ (54,250)$
2018 (58,719)$ (52,956)$ (15,787)$ (19,612)$ (62,823)$
2019 (60,599)$ (60,768)$ (13,611)$ (18,556)$ (69,350)$
2020 (69,561)$ (59,630)$ (39,201)$ (32,005)$ (89,154)$
2021 (86,617)$ (57,554)$ (49,389)$ (42,000)$ (89,169)$
2022 (88,538)$ (49,662)$ (54,881)$ (34,641)$ (92,279)$
2023 (95,118)$ (45,792)$ (61,492)$ (40,626)$ (102,929)$
2024 (113,992)$ (54,376)$ (73,723)$ (44,155)$ (122,259)$
2025 (118,849)$ (43,546)$ (86,090)$ (48,353)$ (124,831)$
2026 (136,573)$ (23,918)$ (104,184)$ (55,565)$ (138,298)$
2027 (121,738)$ 2,271$ (119,430)$ (60,426)$ (121,868)$
2028 (130,875)$ 13,340$ (142,153)$ (61,872)$ (125,020)$
2029 (155,138)$ 27,822$ (173,963)$ (74,552)$ (148,429)$
2030 (173,490)$ 46,617$ (199,228)$ (82,229)$ (162,116)$
2031 (194,687)$ 63,077$ (224,784)$ (91,638)$ (175,979)$
2032 (215,449)$ 71,382$ (259,111)$ (95,183)$ (187,859)$
2033 (168,075)$ 62,235$ (237,221)$ (72,661)$ (155,838)$
Total (1,973,705)$ (241,154)$ (1,756,898)$ (700,446)$ (2,122,591)$
Discount Rate: 7.2002%
30-Year PV (358,888)$ (104,206)$ (276,152)$ (35,456)$ (472,529)$
Levelized (30,549)$ (8,870)$ (23,506)$ (3,018)$ (40,222)$
30-Year PV Rank 2 4 3 5 1
20-Year PV (94,750)$ (118,508)$ (7,583)$ 82,383$ (216,824)$
Levelized (9,405)$ (11,763)$ (753)$ 8,177$ (21,522)$
20-Year PV Rank 3 2 4 5 1
10-Year PV 92,551$ 37,213$ 56,772$ 162,296$ (2,202)$
Levelized 13,770$ 5,537$ 8,447$ 24,147$ (328)$
10-Year PV Rank 4 2 3 5 1
Notes:All values are averaged over all hours of simulation. Hydro fleet modified from original May 2004 runs. Transmission costs modified from original May 2004 values.
Base case includes all existing and committed resources as of January 1, 2004.
All costs nominal.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-28-2004
Page 2 of 6 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs, Natural Gas Prices at LOW Scenario
Portfolios 3, 6, 7, 8 & 11 Comparison
NPV Comparison of Portfolio Differences (Portfolio - Balanced 0)
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
-$1,000
-$900
-$800
-$700
-$600
-$500
-$400
-$300
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
2
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P3 Gas LOW DSM no change
P6 Gas LOW DSM NEW
P7 Gas LOW DSM New
P8 Gas LOW DSM NEW
P11 Gas LOW DSM NEW
Page 3 and 6 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs, Natural Gas Prices at HIGH Scenario
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Portfolio Power Supply Cost ($ x 1000)
Year P0 HIGH Gas P3 Gas HIGH DSM no change P6 Gas HIGH DSM NEW P7 Gas HIGH DSM NEW P8 Gas HIGH DSM NEW P11 Gas HIGH DSM NEW
2004 308,281$ 308,281$ 308,281$ 308,281$ 308,281$ 308,281$
2005 328,691$ 328,691$ 335,636$ 335,636$ 335,636$ 335,636$
2006 358,681$ 363,289$ 366,566$ 366,566$ 357,150$ 366,566$
2007 368,754$ 382,968$ 367,006$ 367,006$ 384,249$ 367,007$ 2008 485,602$ 512,166$ 479,841$ 484,318$ 496,629$ 483,819$
2009 495,393$ 516,539$ 515,337$ 488,696$ 508,669$ 488,227$
2010 506,381$ 527,607$ 521,904$ 531,126$ 509,112$ 503,894$
2011 515,004$ 511,667$ 509,707$ 526,272$ 491,912$ 502,496$
2012 534,463$ 533,482$ 529,026$ 544,214$ 502,868$ 507,916$ 2013 523,954$ 514,569$ 517,765$ 484,818$ 489,194$ 487,880$
2014 547,315$ 528,086$ 545,525$ 514,455$ 508,713$ 519,381$
2015 594,770$ 570,521$ 573,254$ 528,974$ 541,813$ 534,128$
2016 618,148$ 586,061$ 592,495$ 558,363$ 576,943$ 556,649$
2017 697,515$ 662,729$ 654,054$ 644,405$ 656,212$ 627,801$ 2018 706,064$ 664,618$ 661,569$ 638,574$ 656,274$ 626,125$
2019 752,887$ 707,249$ 703,722$ 681,416$ 699,605$ 662,894$
2020 818,769$ 763,049$ 768,639$ 728,096$ 758,206$ 721,094$
2021 863,946$ 801,826$ 823,941$ 758,224$ 792,783$ 755,013$
2022 889,921$ 815,141$ 840,591$ 790,767$ 828,100$ 779,929$ 2023 948,332$ 859,505$ 890,841$ 828,938$ 876,015$ 821,377$
2024 1,013,449$ 914,403$ 954,576$ 878,591$ 933,138$ 864,620$
2025 1,072,473$ 975,655$ 1,028,886$ 936,248$ 991,319$ 926,987$
2026 1,154,415$ 1,045,635$ 1,128,057$ 994,369$ 1,065,420$ 998,192$
2027 1,244,778$ 1,139,655$ 1,241,983$ 1,063,215$ 1,148,969$ 1,098,957$ 2028 1,348,465$ 1,235,230$ 1,352,641$ 1,149,400$ 1,246,544$ 1,192,851$
2029 1,439,595$ 1,308,615$ 1,461,782$ 1,208,635$ 1,327,615$ 1,265,797$
2030 1,557,849$ 1,408,973$ 1,597,571$ 1,298,817$ 1,435,104$ 1,368,076$
2031 1,689,305$ 1,524,823$ 1,753,169$ 1,393,099$ 1,554,171$ 1,488,592$
2032 1,870,198$ 1,687,289$ 1,948,694$ 1,534,845$ 1,725,452$ 1,660,260$ 2033 2,145,324$ 2,008,392$ 2,210,970$ 1,827,428$ 2,021,208$ 1,961,492$
Total 26,398,721$ 24,706,713$ 26,184,029$ 23,393,792$ 24,727,303$ 23,781,937$
Discount Rate: 7.2002%
30-Year PV 8,144,191$ 7,819,285$ 8,047,679$ 7,520,055$ 7,755,103$ 7,527,489$ Levelized 693,247$ 665,591$ 685,032$ 640,120$ 660,128$ 640,753$
30-Year PV Rank 6 4 5 1 3 2
20-Year PV 5,655,417$ 5,552,888$ 5,549,373$ 5,410,560$ 5,454,059$ 5,338,423$
Levelized 561,347$ 551,170$ 550,821$ 537,043$ 541,360$ 529,883$ 20-Year PV Rank 6 5 4 2 3 1
10-Year PV 3,072,181$ 3,127,186$ 3,093,613$ 3,085,806$ 3,058,997$ 3,035,158$
Levelized 457,084$ 465,268$ 460,273$ 459,111$ 455,122$ 451,575$
10-Year PV Rank 3 6 5 4 2 1
Page 4 of 6 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs, Natural Gas Prices at HIGH Scenario
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalatedDifference in Portfolio Power Supply Costs (Scenario - Base Case) ($ x 1000)
Year P0 HIGH Gas P3 Gas HIGH DSM no change P6 Gas HIGH DSM NEW P7 Gas HIGH DSM NEW P8 Gas HIGH DSM NEW P11 Gas HIGH DSM NEW
2004 -$ -$ -$ -$ -$
2005 -$ 6,945$ 6,945$ 6,945$ 6,945$
2006 4,608$ 7,885$ 7,885$ (1,531)$ 7,885$
2007 14,214$ (1,748)$ (1,748)$ 15,495$ (1,746)$
2008 26,564$ (5,761)$ (1,283)$ 11,028$ (1,783)$
2009 21,146$ 19,944$ (6,698)$ 13,275$ (7,167)$
2010 21,226$ 15,523$ 24,744$ 2,730$ (2,487)$
2011 (3,338)$ (5,298)$ 11,267$ (23,092)$ (12,509)$
2012 (981)$ (5,437)$ 9,751$ (31,595)$ (26,547)$
2013 (9,385)$ (6,189)$ (39,136)$ (34,761)$ (36,075)$
2014 (19,230)$ (1,791)$ (32,860)$ (38,603)$ (27,934)$
2015 (24,248)$ (21,515)$ (65,796)$ (52,956)$ (60,642)$
2016 (32,088)$ (25,653)$ (59,785)$ (41,205)$ (61,499)$
2017 (34,786)$ (43,461)$ (53,110)$ (41,303)$ (69,714)$
2018 (41,446)$ (44,494)$ (67,490)$ (49,790)$ (79,939)$
2019 (45,638)$ (49,166)$ (71,471)$ (53,282)$ (89,994)$
2020 (55,720)$ (50,130)$ (90,674)$ (60,563)$ (97,676)$
2021 (62,120)$ (40,005)$ (105,722)$ (71,163)$ (108,932)$
2022 (74,780)$ (49,330)$ (99,154)$ (61,821)$ (109,992)$
2023 (88,827)$ (57,491)$ (119,394)$ (72,317)$ (126,955)$
2024 (99,046)$ (58,873)$ (134,857)$ (80,311)$ (148,829)$
2025 (96,818)$ (43,587)$ (136,225)$ (81,154)$ (145,485)$
2026 (108,779)$ (26,358)$ (160,046)$ (88,994)$ (156,223)$
2027 (105,123)$ (2,795)$ (181,562)$ (95,809)$ (145,820)$
2028 (113,235)$ 4,176$ (199,065)$ (101,921)$ (155,613)$
2029 (130,979)$ 22,187$ (230,960)$ (111,980)$ (173,797)$
2030 (148,876)$ 39,723$ (259,032)$ (122,745)$ (189,773)$
2031 (164,483)$ 63,863$ (296,207)$ (135,134)$ (200,713)$
2032 (182,909)$ 78,497$ (335,353)$ (144,746)$ (209,938)$
2033 (136,932)$ 65,647$ (317,896)$ (124,116)$ (183,832)$
Total (1,692,008)$ (214,692)$ (3,004,929)$ (1,671,418)$ (2,616,784)$
Discount Rate: 7.2002%
30-Year PV (324,906)$ (96,513)$ (624,136)$ (389,089)$ (616,702)$
Levelized (27,657)$ (8,215)$ (53,128)$ (33,120)$ (52,495)$
30-Year PV Rank 4 5 1 3 2
20-Year PV (102,528)$ (106,044)$ (244,857)$ (201,358)$ (316,994)$
Levelized (10,177)$ (10,526)$ (24,304)$ (19,986)$ (31,464)$
20-Year PV Rank 5 4 2 3 1
10-Year PV 55,006$ 21,432$ 13,626$ (13,184)$ (37,023)$
Levelized 8,184$ 3,189$ 2,027$ (1,962)$ (5,508)$
10-Year PV Rank 5 4 3 2 1
Notes:All values are averaged over all hours of simulation. Hydro fleet modified from original May 2004 runs. Transmission costs modified from original May 2004 values.
Base case includes all existing and committed resources as of January 1, 2004.
All costs nominal.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-28-2004
Page 5 of 6 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Portfolio Power Supply Costs, Natural Gas Prices at HIGH Scenario
Portfolios 3, 6, 7, 8 & 11 Comparison
NPV Comparison of Portfolio Differences (Portfolio - Balanced 0)
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
-$1,000
-$900
-$800
-$700
-$600
-$500
-$400
-$300
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
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$800
$900
$1,000
2
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P3 Gas HIGH DSM no change
P6 Gas HIGH DSM NEW
P7 Gas HIGH DSM NEW
P8 Gas HIGH DSM NEW
P11 Gas HIGH DSM NEW
Page 6 of 6 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Market Sales
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Market Sales Cost, Normal Gas Scenario ($ x 1000)
Year P0 P3
P6 Gas NORM DSM
NEW
P7 Gas NORM DSM
NEW
P8 Gas NORM DSM
NEW
P11 Gas NORM
DSM NEW
2004 (49,189)$ (49,189)$ (49,189)$ (49,189)$ (49,189)$ (49,189)$
2005 (51,256)$ (51,256)$ (51,547)$ (51,547)$ (51,547)$ (51,547)$
2006 (56,885)$ (56,885)$ (50,404)$ (50,404)$ (60,335)$ (50,404)$
2007 (54,257)$ (70,266)$ (64,933)$ (64,933)$ (112,416)$ (64,933)$
2008 (74,393)$ (104,499)$ (88,664)$ (102,055)$ (135,138)$ (102,055)$ 2009 (134,407)$ (141,619)$ (152,598)$ (100,603)$ (209,694)$ (100,603)$
2010 (134,046)$ (173,597)$ (150,226)$ (165,516)$ (207,669)$ (130,384)$
2011 (166,992)$ (218,593)$ (176,569)$ (185,931)$ (228,091)$ (237,099)$
2012 (167,129)$ (232,649)$ (179,240)$ (187,590)$ (238,124)$ (251,458)$
2013 (238,717)$ (267,662)$ (204,308)$ (334,485)$ (257,681)$ (281,498)$ 2014 (229,457)$ (257,120)$ (197,236)$ (324,625)$ (269,265)$ (264,788)$
2015 (198,901)$ (247,764)$ (188,396)$ (294,037)$ (231,459)$ (262,283)$
2016 (200,668)$ (254,059)$ (186,718)$ (289,146)$ (221,690)$ (254,823)$
2017 (133,371)$ (196,168)$ (148,757)$ (215,217)$ (156,972)$ (200,806)$
2018 (149,196)$ (229,886)$ (170,338)$ (235,463)$ (180,880)$ (228,487)$ 2019 (129,765)$ (213,525)$ (160,480)$ (209,589)$ (157,414)$ (206,151)$
2020 (109,139)$ (181,749)$ (136,767)$ (183,484)$ (131,217)$ (173,498)$
2021 (113,804)$ (188,234)$ (143,106)$ (176,827)$ (133,366)$ (178,655)$
2022 (92,503)$ (179,441)$ (129,845)$ (166,088)$ (115,855)$ (176,129)$
2023 (84,104)$ (177,841)$ (134,760)$ (149,225)$ (110,094)$ (169,403)$ 2024 (76,699)$ (187,209)$ (140,323)$ (139,987)$ (94,100)$ (183,491)$
2025 (65,914)$ (162,143)$ (102,926)$ (125,876)$ (80,792)$ (152,236)$
2026 (61,081)$ (151,599)$ (95,298)$ (114,001)$ (73,170)$ (141,265)$
2027 (55,347)$ (115,345)$ (63,382)$ (109,008)$ (71,589)$ (104,350)$
2028 (39,059)$ (93,340)$ (49,355)$ (78,282)$ (44,310)$ (82,488)$ 2029 (43,711)$ (101,458)$ (52,972)$ (76,271)$ (49,343)$ (89,288)$
2030 (34,282)$ (95,773)$ (45,539)$ (64,044)$ (39,747)$ (84,436)$
2031 (25,740)$ (84,083)$ (34,745)$ (53,758)$ (31,821)$ (74,607)$
2032 (21,128)$ (73,051)$ (34,197)$ (45,025)$ (26,220)$ (60,139)$
2033 (15,644)$ (43,617)$ (24,627)$ (34,414)$ (22,785)$ (43,650)$ Total (3,006,781)$ (4,599,619)$ (3,407,445)$ (4,376,622)$ (3,791,974)$ (4,450,141)$
Discount Rate: 7.2002%
30-Year PV (1,366,449)$ (1,874,068)$ (1,478,154)$ (1,832,101)$ (1,760,544)$ (1,820,332)$
Levelized (116,314)$ (159,524)$ (125,823)$ (155,952)$ (149,860)$ (154,950)$ 30-Year PV Rank 6 1 5 2 4 3
20-Year PV (1,280,951)$ (1,660,962)$ (1,350,813)$ (1,669,160)$ (1,656,529)$ (1,623,665)$
Levelized (127,145)$ (164,864)$ (134,079)$ (165,678)$ (164,424)$ (161,162)$
20-Year PV Rank 6 2 5 1 3 4
10-Year PV (730,446)$ (876,975)$ (761,394)$ (822,875)$ (1,007,231)$ (838,889)$
Levelized (108,677)$ (130,478)$ (113,281)$ (122,429)$ (149,857)$ (124,811)$
10-Year PV Rank 6 2 5 4 1 3
Page 1 of 9 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Market Sales
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalatedMarket Sales Cost, LOW Gas Scenario ($ x 1000)
Year P0 LOW Gas
P3 Gas LOW DSM
no change
P6 Gas LOW DSM
NEW
P7 Gas LOW DSM
New
P8 Gas LOW DSM
NEW
P11 Gas LOW DSM
NEW
2004 (40,036)$ (40,036)$ (40,036)$ (40,036)$ (40,036)$ (40,036)$
2005 (26,608)$ (26,608)$ (26,839)$ (26,839)$ (26,839)$ (26,839)$
2006 (40,491)$ (40,491)$ (35,823)$ (35,823)$ (42,949)$ (35,823)$
2007 (41,400)$ (53,659)$ (50,121)$ (50,121)$ (85,761)$ (50,121)$
2008 (56,208)$ (80,596)$ (66,133)$ (75,905)$ (95,864)$ (75,905)$
2009 (107,024)$ (116,255)$ (116,905)$ (81,240)$ (160,118)$ (81,240)$
2010 (111,107)$ (145,201)$ (121,046)$ (134,243)$ (165,977)$ (110,108)$
2011 (147,166)$ (189,215)$ (171,120)$ (167,668)$ (206,055)$ (221,210)$
2012 (152,385)$ (211,200)$ (162,882)$ (172,405)$ (211,241)$ (211,802)$
2013 (223,407)$ (256,151)$ (192,601)$ (313,236)$ (251,463)$ (267,478)$
2014 (209,170)$ (244,362)$ (189,905)$ (291,544)$ (231,825)$ (245,175)$
2015 (184,519)$ (233,719)$ (173,711)$ (264,160)$ (217,618)$ (235,703)$
2016 (187,294)$ (240,808)$ (173,647)$ (261,562)$ (211,283)$ (246,305)$
2017 (118,768)$ (185,402)$ (138,180)$ (197,048)$ (144,208)$ (188,202)$
2018 (140,703)$ (218,299)$ (161,512)$ (220,156)$ (166,506)$ (214,094)$
2019 (124,466)$ (199,835)$ (153,424)$ (189,349)$ (142,630)$ (196,716)$
2020 (101,949)$ (173,071)$ (131,622)$ (172,377)$ (123,580)$ (178,666)$
2021 (105,800)$ (187,505)$ (140,212)$ (170,156)$ (130,549)$ (173,779)$
2022 (76,518)$ (139,461)$ (89,706)$ (139,560)$ (93,081)$ (129,983)$
2023 (72,791)$ (133,775)$ (88,460)$ (126,788)$ (88,124)$ (127,661)$
2024 (66,815)$ (137,907)$ (93,923)$ (115,676)$ (77,840)$ (130,837)$
2025 (54,374)$ (116,693)$ (66,937)$ (102,297)$ (65,265)$ (106,167)$
2026 (50,292)$ (116,755)$ (60,978)$ (91,697)$ (58,883)$ (104,108)$
2027 (50,174)$ (84,868)$ (40,134)$ (84,455)$ (58,368)$ (75,852)$
2028 (34,184)$ (65,105)$ (31,466)$ (64,935)$ (35,406)$ (51,484)$
2029 (37,809)$ (71,689)$ (33,521)$ (64,292)$ (41,926)$ (61,479)$
2030 (28,247)$ (64,999)$ (27,016)$ (52,053)$ (32,507)$ (55,788)$
2031 (20,987)$ (73,715)$ (26,940)$ (44,712)$ (26,109)$ (63,321)$
2032 (19,897)$ (71,499)$ (33,361)$ (46,328)$ (24,988)$ (60,936)$
2033 (18,684)$ (43,510)$ (23,595)$ (32,886)$ (21,209)$ (39,927)$
Total (2,649,270)$ (3,962,389)$ (2,861,754)$ (3,829,547)$ (3,278,209)$ (3,806,744)$
Discount Rate: 7.2002%
30-Year PV (1,181,112)$ (1,619,493)$ (1,252,716)$ (1,587,223)$ (1,496,357)$ (1,566,544)$
Levelized (100,538)$ (137,854)$ (106,633)$ (135,107)$ (127,372)$ (133,347)$
30-Year PV Rank 6 1 5 2 4 3
20-Year PV (1,107,172)$ (1,458,503)$ (1,167,216)$ (1,452,591)$ (1,410,547)$ (1,423,146)$
Levelized (109,896)$ (144,769)$ (115,856)$ (144,182)$ (140,008)$ (141,259)$
20-Year PV Rank 6 1 5 2 4 3
10-Year PV (601,118)$ (731,009)$ (628,686)$ (685,443)$ (820,361)$ (700,048)$
Levelized (89,435)$ (108,761)$ (93,537)$ (101,981)$ (122,055)$ (104,154)$
10-Year PV Rank 6 2 5 4 1 3
Page 2 of 9 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Market Sales
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Market Sales Cost, HIGH Gas Scenario ($ x 1000)
Year P0 HIGH Gas P3 Gas HIGH DSM no change P6 Gas HIGH DSM NEW P7 Gas HIGH DSM NEW P8 Gas HIGH DSM NEW P11 Gas HIGH DSM NEW
2004 (66,873)$ (66,873)$ (66,873)$ (66,873)$ (66,873)$ (66,873)$
2005 (58,916)$ (58,916)$ (59,708)$ (59,708)$ (59,708)$ (59,708)$
2006 (73,306)$ (73,306)$ (64,187)$ (64,187)$ (76,079)$ (64,187)$
2007 (72,013)$ (92,838)$ (86,203)$ (86,203)$ (147,220)$ (86,203)$
2008 (96,693)$ (135,047)$ (114,662)$ (130,805)$ (174,306)$ (130,805)$
2009 (177,214)$ (182,534)$ (196,334)$ (131,259)$ (268,935)$ (131,259)$
2010 (179,475)$ (224,307)$ (194,344)$ (218,482)$ (271,058)$ (172,339)$
2011 (214,442)$ (273,647)$ (225,464)$ (239,672)$ (302,412)$ (308,273)$
2012 (207,850)$ (283,920)$ (218,207)$ (233,096)$ (301,276)$ (309,068)$
2013 (289,732)$ (322,701)$ (248,032)$ (412,423)$ (329,065)$ (343,803)$
2014 (268,342)$ (317,333)$ (228,819)$ (381,413)$ (316,512)$ (314,366)$
2015 (242,041)$ (307,148)$ (218,838)$ (370,427)$ (288,469)$ (314,984)$
2016 (242,580)$ (313,832)$ (224,026)$ (355,307)$ (272,640)$ (312,252)$
2017 (166,792)$ (240,503)$ (173,875)$ (263,644)$ (196,238)$ (244,077)$
2018 (182,967)$ (262,611)$ (197,795)$ (287,977)$ (221,218)$ (268,307)$
2019 (161,323)$ (239,179)$ (178,757)$ (253,751)$ (193,498)$ (246,357)$
2020 (130,528)$ (211,682)$ (153,651)$ (214,632)$ (153,889)$ (202,917)$
2021 (128,033)$ (209,221)$ (149,216)$ (206,635)$ (151,577)$ (203,103)$
2022 (118,705)$ (212,411)$ (148,262)$ (200,707)$ (141,834)$ (201,313)$
2023 (100,202)$ (205,728)$ (147,228)$ (184,531)$ (123,595)$ (192,687)$
2024 (92,466)$ (205,434)$ (149,612)$ (171,680)$ (113,200)$ (201,824)$
2025 (80,936)$ (175,058)$ (108,148)$ (148,216)$ (97,105)$ (166,250)$
2026 (71,673)$ (164,598)$ (99,203)$ (133,489)$ (84,740)$ (152,598)$
2027 (63,330)$ (128,009)$ (62,440)$ (121,363)$ (74,790)$ (112,105)$
2028 (44,760)$ (107,751)$ (54,364)$ (90,959)$ (53,246)$ (91,547)$
2029 (50,091)$ (108,553)$ (54,733)$ (89,950)$ (56,108)$ (95,350)$
2030 (38,733)$ (101,039)$ (46,735)$ (73,140)$ (45,031)$ (88,715)$
2031 (28,837)$ (87,289)$ (35,804)$ (60,856)$ (35,549)$ (77,537)$
2032 (23,547)$ (75,934)$ (35,366)$ (50,852)$ (28,875)$ (62,893)$
2033 (19,272)$ (46,399)$ (26,916)$ (39,078)$ (25,208)$ (44,320)$
Total (3,691,672)$ (5,433,798)$ (3,967,802)$ (5,341,316)$ (4,670,252)$ (5,266,017)$
Discount Rate: 7.2002%
30-Year PV (1,698,905)$ (2,270,748)$ (1,773,103)$ (2,265,416)$ (2,202,371)$ (2,210,042)$
Levelized (144,614)$ (193,290)$ (150,930)$ (192,836)$ (187,470)$ (188,123)$
30-Year PV Rank 6 1 5 2 4 3
20-Year PV (1,598,388)$ (2,039,282)$ (1,639,711)$ (2,074,832)$ (2,082,219)$ (1,997,684)$
Levelized (158,653)$ (202,416)$ (162,755)$ (205,944)$ (206,677)$ (198,287)$
20-Year PV Rank 6 3 5 2 1 4
10-Year PV (933,645)$ (1,104,487)$ (964,206)$ (1,048,579)$ (1,297,550)$ (1,066,563)$
Levelized (138,909)$ (164,327)$ (143,456)$ (156,009)$ (193,051)$ (158,685)$
10-Year PV Rank 6 2 5 4 1 3
Notes:All values are averaged over all hours of simulation. Hydro fleet modified from original May 2004 runs. Transmission costs modified from original May 2004 values
Base case includes all existing and committed resources as of January 1, 2004
All costs nominal.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-28-2004 Page 3 of 9 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Market Purchases
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Market Purchases Cost, Normal Gas Scenario ($ x 1000)
Year P0 P3
P6 Gas NORM DSM
NEW
P7 Gas NORM DSM
NEW
P8 Gas NORM DSM
NEW
P11 Gas NORM
DSM NEW
2004 17,241$ 17,241$ 17,241$ 17,241$ 17,241$ 17,241$
2005 18,550$ 18,550$ 18,263$ 18,263$ 18,263$ 18,263$
2006 24,343$ 24,343$ 28,038$ 28,038$ 23,445$ 28,038$
2007 27,346$ 19,995$ 21,090$ 21,090$ 4,600$ 21,090$
2008 28,185$ 17,289$ 21,046$ 15,789$ 7,629$ 15,789$ 2009 13,061$ 15,070$ 5,136$ 24,770$ 2,080$ 24,770$
2010 19,913$ 16,232$ 7,638$ 10,936$ 3,265$ 22,197$
2011 20,257$ 14,451$ 10,712$ 14,280$ 4,771$ 4,041$
2012 24,971$ 15,767$ 15,370$ 19,832$ 7,544$ 6,276$
2013 20,146$ 19,153$ 19,746$ 4,217$ 9,874$ 8,552$ 2014 26,251$ 24,483$ 25,495$ 6,226$ 13,423$ 12,158$
2015 22,819$ 19,368$ 20,479$ 7,421$ 13,336$ 10,364$
2016 25,292$ 18,551$ 22,807$ 8,338$ 15,487$ 11,737$
2017 30,388$ 18,558$ 27,217$ 11,050$ 18,617$ 13,531$
2018 36,863$ 20,694$ 36,643$ 14,376$ 24,063$ 17,740$ 2019 48,048$ 27,007$ 46,989$ 17,889$ 30,124$ 22,687$
2020 72,908$ 30,780$ 67,645$ 32,242$ 52,134$ 31,577$
2021 94,212$ 41,342$ 96,051$ 42,655$ 69,288$ 48,510$
2022 87,402$ 48,479$ 94,190$ 36,341$ 61,721$ 46,605$
2023 104,062$ 58,196$ 115,414$ 44,396$ 74,869$ 57,219$ 2024 121,164$ 67,975$ 135,835$ 53,296$ 87,277$ 70,336$
2025 162,843$ 106,753$ 172,354$ 74,340$ 114,734$ 92,913$
2026 202,120$ 125,283$ 229,432$ 93,832$ 150,863$ 121,686$
2027 279,774$ 191,526$ 307,345$ 136,873$ 211,662$ 179,018$
2028 334,964$ 230,784$ 378,340$ 171,697$ 260,501$ 224,337$ 2029 386,199$ 256,211$ 443,907$ 194,786$ 304,633$ 261,378$
2030 451,682$ 303,986$ 530,389$ 237,140$ 366,998$ 321,242$
2031 527,865$ 354,371$ 629,949$ 283,404$ 438,308$ 388,655$
2032 656,963$ 452,531$ 778,183$ 382,653$ 565,964$ 503,833$
2033 813,989$ 613,591$ 961,705$ 503,028$ 706,939$ 660,456$ Total 4,699,818$ 3,188,558$ 5,284,649$ 2,526,438$ 3,679,653$ 3,262,239$
Discount Rate: 7.2002%
30-Year PV 964,867$ 663,877$ 1,030,431$ 537,150$ 706,897$ 659,108$
Levelized 82,131$ 56,510$ 87,712$ 45,723$ 60,172$ 56,104$ 30-Year PV Rank 5 3 6 1 4 2
20-Year PV 330,950$ 232,658$ 298,799$ 200,093$ 196,304$ 213,016$
Levelized 32,850$ 23,093$ 29,658$ 19,861$ 19,485$ 21,144$
20-Year PV Rank 6 4 5 2 1 3
10-Year PV 153,720$ 129,959$ 122,033$ 130,249$ 77,604$ 126,070$
Levelized 22,871$ 19,336$ 18,156$ 19,379$ 11,546$ 18,757$
10-Year PV Rank 6 4 2 5 1 3
Page 4 of 9 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Market Purchases
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalatedMarket Purchases Cost, LOW Gas Scenario ($ x 1000)
Year P0 LOW Gas
P3 Gas LOW DSM
no change
P6 Gas LOW DSM
NEW
P7 Gas LOW DSM
New
P8 Gas LOW DSM
NEW
P11 Gas LOW DSM
NEW
2004 15,250$ 15,250$ 15,250$ 15,250$ 15,250$ 15,250$
2005 23,110$ 23,110$ 23,508$ 23,508$ 23,508$ 23,508$
2006 21,061$ 21,061$ 23,693$ 23,693$ 20,370$ 23,693$
2007 20,608$ 15,139$ 16,214$ 16,214$ 3,482$ 16,214$
2008 32,642$ 22,972$ 27,444$ 22,061$ 14,821$ 22,061$
2009 11,744$ 13,353$ 4,716$ 22,483$ 1,915$ 22,483$
2010 17,821$ 14,796$ 6,991$ 10,480$ 3,085$ 20,205$
2011 16,683$ 11,312$ 9,085$ 12,092$ 4,116$ 3,599$
2012 21,639$ 12,415$ 13,256$ 17,770$ 6,379$ 5,217$
2013 17,876$ 16,089$ 17,565$ 3,638$ 8,416$ 7,534$
2014 22,590$ 19,501$ 22,098$ 5,269$ 11,525$ 9,937$
2015 19,179$ 16,017$ 17,516$ 6,351$ 11,380$ 8,691$
2016 21,981$ 15,751$ 19,686$ 7,109$ 13,090$ 9,906$
2017 26,484$ 15,814$ 23,188$ 9,445$ 16,409$ 11,358$
2018 32,146$ 17,495$ 32,149$ 12,329$ 20,487$ 15,132$
2019 42,420$ 23,217$ 41,229$ 15,688$ 26,920$ 19,590$
2020 66,646$ 27,161$ 60,794$ 28,356$ 46,471$ 27,829$
2021 86,770$ 36,878$ 87,496$ 38,634$ 64,154$ 44,551$
2022 113,548$ 55,617$ 104,589$ 49,545$ 81,591$ 50,876$
2023 133,073$ 65,396$ 127,820$ 61,666$ 97,212$ 63,190$
2024 154,082$ 74,575$ 149,806$ 74,679$ 116,167$ 76,035$
2025 198,415$ 114,119$ 194,740$ 95,680$ 146,574$ 103,535$
2026 242,768$ 141,446$ 258,391$ 121,219$ 186,154$ 139,312$
2027 317,001$ 209,893$ 341,733$ 166,015$ 247,146$ 202,628$
2028 378,251$ 254,957$ 421,526$ 205,748$ 302,420$ 255,219$
2029 438,989$ 291,467$ 494,895$ 236,641$ 356,139$ 301,480$
2030 511,978$ 347,319$ 590,613$ 287,369$ 425,008$ 368,514$
2031 532,942$ 358,783$ 636,670$ 289,395$ 443,034$ 394,566$
2032 636,909$ 435,019$ 754,259$ 369,922$ 548,625$ 487,446$
2033 783,819$ 586,371$ 927,094$ 482,965$ 680,827$ 634,346$
Total 4,958,424$ 3,272,292$ 5,464,014$ 2,731,210$ 3,942,674$ 3,383,902$
Discount Rate: 7.2002%
30-Year PV 1,007,625$ 671,205$ 1,058,840$ 573,726$ 760,271$ 676,956$
Levelized 85,771$ 57,134$ 90,130$ 48,837$ 64,716$ 57,624$
30-Year PV Rank 5 2 6 1 4 3
20-Year PV 321,541$ 217,790$ 286,752$ 197,509$ 200,763$ 203,638$
Levelized 31,916$ 21,617$ 28,462$ 19,604$ 19,927$ 20,213$
20-Year PV Rank 6 4 5 1 2 3
10-Year PV 143,755$ 122,347$ 118,078$ 125,572$ 80,192$ 121,781$
Levelized 21,388$ 18,203$ 17,568$ 18,683$ 11,931$ 18,119$
10-Year PV Rank 6 4 2 5 1 3
Page 5 of 9 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Market Purchases
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Market Purchases Cost, HIGH Gas Scenario ($ x 1000)
Year P0 HIGH Gas P3 Gas HIGH DSM no change P6 Gas HIGH DSM NEW P7 Gas HIGH DSM NEW P8 Gas HIGH DSM NEW P11 Gas HIGH DSM NEW
2004 22,638$ 22,638$ 22,638$ 22,638$ 22,638$ 22,638$
2005 21,375$ 21,375$ 20,881$ 20,881$ 20,881$ 20,881$
2006 30,524$ 30,524$ 35,034$ 35,034$ 29,619$ 35,034$
2007 36,060$ 26,909$ 27,837$ 27,837$ 6,022$ 27,837$
2008 36,050$ 22,288$ 27,059$ 20,232$ 9,431$ 20,232$
2009 16,911$ 20,159$ 6,434$ 32,265$ 2,737$ 32,265$
2010 26,132$ 21,964$ 10,144$ 14,405$ 4,372$ 29,827$
2011 27,863$ 22,332$ 14,452$ 19,400$ 6,698$ 5,739$
2012 34,161$ 22,885$ 20,414$ 26,181$ 10,146$ 8,615$
2013 28,740$ 27,151$ 26,292$ 5,561$ 13,136$ 11,671$
2014 36,465$ 33,955$ 33,224$ 7,920$ 17,358$ 16,106$
2015 29,005$ 26,715$ 27,104$ 9,668$ 17,621$ 13,839$
2016 33,390$ 25,976$ 30,520$ 11,210$ 19,842$ 15,407$
2017 38,877$ 25,846$ 36,334$ 14,261$ 24,442$ 17,765$
2018 45,483$ 29,049$ 48,000$ 18,557$ 31,100$ 23,825$
2019 60,847$ 37,382$ 60,835$ 23,263$ 38,224$ 30,081$
2020 89,524$ 41,875$ 84,080$ 40,555$ 64,087$ 40,452$
2021 114,069$ 54,277$ 117,705$ 52,645$ 84,880$ 60,612$
2022 104,948$ 62,747$ 114,493$ 44,702$ 74,580$ 58,455$
2023 125,498$ 73,910$ 139,148$ 54,871$ 90,178$ 70,935$
2024 144,029$ 85,630$ 163,906$ 64,816$ 104,448$ 86,660$
2025 194,097$ 134,410$ 206,837$ 89,316$ 136,323$ 114,180$
2026 236,558$ 156,455$ 269,327$ 111,444$ 176,645$ 146,138$
2027 325,679$ 233,546$ 356,225$ 161,567$ 243,958$ 212,195$
2028 382,956$ 275,023$ 431,569$ 200,136$ 296,822$ 260,497$
2029 436,788$ 301,645$ 502,505$ 225,482$ 345,968$ 301,150$
2030 508,020$ 354,112$ 595,620$ 271,667$ 412,199$ 366,532$
2031 588,731$ 408,206$ 701,177$ 323,111$ 490,119$ 439,672$
2032 724,873$ 509,800$ 854,031$ 428,172$ 624,322$ 561,023$
2033 893,979$ 689,298$ 1,050,694$ 557,924$ 775,793$ 728,688$
Total 5,394,268$ 3,798,083$ 6,034,517$ 2,935,718$ 4,194,586$ 3,778,950$
Discount Rate: 7.2002%
30-Year PV 1,138,051$ 816,005$ 1,204,933$ 641,656$ 822,692$ 784,585$
Levelized 96,873$ 69,460$ 102,566$ 54,619$ 70,029$ 66,785$
30-Year PV Rank 5 3 6 1 4 2
20-Year PV 420,565$ 310,318$ 378,531$ 254,904$ 246,083$ 273,498$
Levelized 41,745$ 30,802$ 37,572$ 25,301$ 24,426$ 27,147$
20-Year PV Rank 6 4 5 2 1 3
10-Year PV 199,884$ 171,861$ 156,046$ 166,810$ 98,218$ 161,943$
Levelized 29,739$ 25,570$ 23,217$ 24,818$ 14,613$ 24,094$
10-Year PV Rank 6 5 2 4 1 3
Notes:All values are averaged over all hours of simulation. Hydro fleet modified from original May 2004 runs. Transmission costs modified from original May 2004 values
Base case includes all existing and committed resources as of January 1, 2004
All costs nominal.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-28-2004 Page 6 of 9 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - NET of Market Purchases & Sales
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
NET Market Purchases & Sales, Normal Gas Scenario ($ x 1000)
Year P0 P3
P6 Gas NORM DSM
NEW
P7 Gas NORM DSM
NEW
P8 Gas NORM DSM
NEW
P11 Gas NORM
DSM NEW
2004 (31,948)$ (31,948)$ (31,948)$ (31,948)$ (31,948)$ (31,948)$
2005 (32,705)$ (32,705)$ (33,284)$ (33,284)$ (33,284)$ (33,284)$
2006 (32,542)$ (32,542)$ (22,366)$ (22,366)$ (36,890)$ (22,366)$
2007 (26,911)$ (50,271)$ (43,843)$ (43,843)$ (107,817)$ (43,843)$
2008 (46,207)$ (87,210)$ (67,618)$ (86,267)$ (127,509)$ (86,267)$ 2009 (121,346)$ (126,549)$ (147,462)$ (75,833)$ (207,614)$ (75,833)$
2010 (114,133)$ (157,365)$ (142,588)$ (154,581)$ (204,404)$ (108,187)$
2011 (146,735)$ (204,142)$ (165,857)$ (171,651)$ (223,320)$ (233,058)$
2012 (142,158)$ (216,882)$ (163,870)$ (167,758)$ (230,580)$ (245,181)$
2013 (218,571)$ (248,509)$ (184,563)$ (330,268)$ (247,807)$ (272,946)$ 2014 (203,206)$ (232,637)$ (171,741)$ (318,400)$ (255,842)$ (252,630)$
2015 (176,082)$ (228,396)$ (167,917)$ (286,616)$ (218,123)$ (251,919)$
2016 (175,376)$ (235,508)$ (163,911)$ (280,808)$ (206,203)$ (243,086)$
2017 (102,983)$ (177,610)$ (121,540)$ (204,167)$ (138,355)$ (187,276)$
2018 (112,333)$ (209,192)$ (133,695)$ (221,087)$ (156,817)$ (210,747)$ 2019 (81,717)$ (186,517)$ (113,490)$ (191,700)$ (127,290)$ (183,464)$
2020 (36,231)$ (150,969)$ (69,123)$ (151,242)$ (79,083)$ (141,921)$
2021 (19,591)$ (146,892)$ (47,056)$ (134,173)$ (64,079)$ (130,145)$
2022 (5,101)$ (130,963)$ (35,655)$ (129,746)$ (54,134)$ (129,525)$
2023 19,958$ (119,645)$ (19,345)$ (104,830)$ (35,224)$ (112,184)$ 2024 44,465$ (119,234)$ (4,488)$ (86,691)$ (6,823)$ (113,154)$
2025 96,929$ (55,390)$ 69,427$ (51,536)$ 33,942$ (59,323)$
2026 141,039$ (26,316)$ 134,134$ (20,170)$ 77,693$ (19,579)$
2027 224,426$ 76,181$ 243,963$ 27,866$ 140,074$ 74,668$
2028 295,905$ 137,443$ 328,985$ 93,416$ 216,191$ 141,849$ 2029 342,488$ 154,753$ 390,935$ 118,515$ 255,290$ 172,091$
2030 417,400$ 208,213$ 484,850$ 173,096$ 327,251$ 236,806$
2031 502,125$ 270,287$ 595,204$ 229,646$ 406,488$ 314,048$
2032 635,834$ 379,480$ 743,986$ 337,627$ 539,744$ 443,695$
2033 798,345$ 569,975$ 937,078$ 468,614$ 684,155$ 616,806$ Total 1,693,036$ (1,411,061)$ 1,877,204$ (1,850,184)$ (112,321)$ (1,187,902)$
Discount Rate: 7.2002%
30-Year PV (401,582)$ (1,210,191)$ (447,724)$ (1,294,951)$ (1,053,647)$ (1,161,224)$
Levelized (34,183)$ (103,013)$ (38,111)$ (110,228)$ (89,688)$ (98,845)$ 30-Year PV Rank 6 2 5 1 4 3
20-Year PV (950,001)$ (1,428,304)$ (1,052,014)$ (1,469,066)$ (1,460,225)$ (1,410,649)$
Levelized (94,295)$ (141,771)$ (104,421)$ (145,817)$ (144,939)$ (140,019)$
20-Year PV Rank 6 3 5 1 2 4
10-Year PV (576,726)$ (747,016)$ (639,361)$ (692,626)$ (929,627)$ (712,820)$
Levelized (85,806)$ (111,142)$ (95,125)$ (103,050)$ (138,311)$ (106,054)$
10-Year PV Rank 6 2 5 4 1 3
Page 7 of 9 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - NET of Market Purchases & Sales
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalatedNET Market Purchases & Sales, LOW Gas Scenario ($ x 1000)
Year P0 LOW Gas
P3 Gas LOW DSM
no change
P6 Gas LOW DSM
NEW
P7 Gas LOW DSM
New
P8 Gas LOW DSM
NEW
P11 Gas LOW DSM
NEW
2004 (24,786)$ (24,786)$ (24,786)$ (24,786)$ (24,786)$ (24,786)$
2005 (3,498)$ (3,498)$ (3,331)$ (3,331)$ (3,331)$ (3,331)$
2006 (19,430)$ (19,430)$ (12,131)$ (12,131)$ (22,579)$ (12,131)$
2007 (20,791)$ (38,520)$ (33,907)$ (33,907)$ (82,279)$ (33,907)$
2008 (23,565)$ (57,625)$ (38,689)$ (53,844)$ (81,043)$ (53,844)$
2009 (95,279)$ (102,902)$ (112,189)$ (58,757)$ (158,203)$ (58,757)$
2010 (93,286)$ (130,405)$ (114,055)$ (123,763)$ (162,892)$ (89,903)$
2011 (130,484)$ (177,903)$ (162,035)$ (155,577)$ (201,939)$ (217,611)$
2012 (130,746)$ (198,784)$ (149,626)$ (154,636)$ (204,862)$ (206,585)$
2013 (205,531)$ (240,062)$ (175,036)$ (309,598)$ (243,047)$ (259,944)$
2014 (186,580)$ (224,861)$ (167,806)$ (286,275)$ (220,300)$ (235,238)$
2015 (165,340)$ (217,702)$ (156,195)$ (257,809)$ (206,239)$ (227,011)$
2016 (165,313)$ (225,058)$ (153,961)$ (254,454)$ (198,193)$ (236,399)$
2017 (92,284)$ (169,589)$ (114,992)$ (187,603)$ (127,799)$ (176,844)$
2018 (108,557)$ (200,804)$ (129,362)$ (207,827)$ (146,019)$ (198,962)$
2019 (82,046)$ (176,617)$ (112,195)$ (173,662)$ (115,710)$ (177,127)$
2020 (35,303)$ (145,910)$ (70,828)$ (144,021)$ (77,109)$ (150,837)$
2021 (19,030)$ (150,627)$ (52,715)$ (131,522)$ (66,396)$ (129,228)$
2022 37,030$ (83,844)$ 14,883$ (90,015)$ (11,491)$ (79,107)$
2023 60,282$ (68,379)$ 39,360$ (65,122)$ 9,088$ (64,471)$
2024 87,267$ (63,331)$ 55,883$ (40,997)$ 38,327$ (54,803)$
2025 144,040$ (2,574)$ 127,804$ (6,617)$ 81,309$ (2,632)$
2026 192,477$ 24,691$ 197,413$ 29,523$ 127,271$ 35,204$
2027 266,827$ 125,024$ 301,598$ 81,560$ 188,778$ 126,776$
2028 344,067$ 189,851$ 390,060$ 140,813$ 267,014$ 203,735$
2029 401,180$ 219,778$ 461,374$ 172,349$ 314,212$ 240,001$
2030 483,731$ 282,320$ 563,597$ 235,315$ 392,501$ 312,726$
2031 511,955$ 285,068$ 609,730$ 244,683$ 416,925$ 331,245$
2032 617,012$ 363,520$ 720,898$ 323,594$ 523,637$ 426,510$
2033 765,134$ 542,861$ 903,500$ 450,079$ 659,619$ 594,419$
Total 2,309,154$ (690,097)$ 2,602,260$ (1,098,337)$ 664,465$ (422,843)$
Discount Rate: 7.2002%
30-Year PV (173,488)$ (948,288)$ (193,876)$ (1,013,498)$ (736,086)$ (889,588)$
Levelized (14,768)$ (80,720)$ (16,503)$ (86,271)$ (62,657)$ (75,723)$
30-Year PV Rank 6 2 5 1 4 3
20-Year PV (785,631)$ (1,240,713)$ (880,464)$ (1,255,082)$ (1,209,784)$ (1,219,509)$
Levelized (77,980)$ (123,151)$ (87,393)$ (124,577)$ (120,081)$ (121,046)$
20-Year PV Rank 6 2 5 1 4 3
10-Year PV (457,363)$ (608,662)$ (510,608)$ (559,870)$ (740,170)$ (578,267)$
Levelized (68,047)$ (90,558)$ (75,969)$ (83,298)$ (110,124)$ (86,035)$
10-Year PV Rank 6 2 5 4 1 3
Page 8 of 9 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - NET of Market Purchases & Sales
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
NET Market Purchases & Sales, HIGH Gas Scenario ($ x 1000)
Year P0 HIGH Gas P3 Gas HIGH DSM no change P6 Gas HIGH DSM NEW P7 Gas HIGH DSM NEW P8 Gas HIGH DSM NEW P11 Gas HIGH DSM NEW
2004 (44,235)$ (44,235)$ (44,235)$ (44,235)$ (44,235)$ (44,235)$
2005 (37,540)$ (37,540)$ (38,827)$ (38,827)$ (38,827)$ (38,827)$
2006 (42,783)$ (42,783)$ (29,153)$ (29,153)$ (46,460)$ (29,153)$
2007 (35,954)$ (65,929)$ (58,367)$ (58,367)$ (141,198)$ (58,367)$
2008 (60,643)$ (112,759)$ (87,604)$ (110,573)$ (164,875)$ (110,573)$
2009 (160,302)$ (162,375)$ (189,900)$ (98,993)$ (266,198)$ (98,993)$
2010 (153,343)$ (202,342)$ (184,200)$ (204,077)$ (266,687)$ (142,511)$
2011 (186,579)$ (251,314)$ (211,012)$ (220,272)$ (295,714)$ (302,534)$
2012 (173,689)$ (261,034)$ (197,793)$ (206,915)$ (291,130)$ (300,453)$
2013 (260,992)$ (295,550)$ (221,740)$ (406,862)$ (315,929)$ (332,132)$
2014 (231,877)$ (283,378)$ (195,595)$ (373,493)$ (299,154)$ (298,260)$
2015 (213,036)$ (280,433)$ (191,734)$ (360,759)$ (270,848)$ (301,145)$
2016 (209,190)$ (287,855)$ (193,506)$ (344,097)$ (252,798)$ (296,845)$
2017 (127,915)$ (214,657)$ (137,541)$ (249,384)$ (171,797)$ (226,312)$
2018 (137,484)$ (233,563)$ (149,795)$ (269,420)$ (190,118)$ (244,482)$
2019 (100,476)$ (201,797)$ (117,922)$ (230,488)$ (155,274)$ (216,275)$
2020 (41,004)$ (169,807)$ (69,571)$ (174,077)$ (89,802)$ (162,464)$
2021 (13,965)$ (154,943)$ (31,511)$ (153,990)$ (66,697)$ (142,491)$
2022 (13,757)$ (149,664)$ (33,769)$ (156,006)$ (67,255)$ (142,858)$
2023 25,296$ (131,818)$ (8,079)$ (129,661)$ (33,417)$ (121,752)$
2024 51,563$ (119,804)$ 14,294$ (106,864)$ (8,752)$ (115,163)$
2025 113,161$ (40,648)$ 98,689$ (58,900)$ 39,217$ (52,070)$
2026 164,885$ (8,143)$ 170,124$ (22,044)$ 91,905$ (6,461)$
2027 262,348$ 105,537$ 293,785$ 40,204$ 169,168$ 100,090$
2028 338,196$ 167,272$ 377,205$ 109,177$ 243,577$ 168,950$
2029 386,697$ 193,093$ 447,772$ 135,531$ 289,860$ 205,800$
2030 469,287$ 253,073$ 548,885$ 198,527$ 367,168$ 277,818$
2031 559,894$ 320,917$ 665,373$ 262,254$ 454,570$ 362,135$
2032 701,326$ 433,866$ 818,664$ 377,320$ 595,447$ 498,130$
2033 874,707$ 642,899$ 1,023,778$ 518,846$ 750,585$ 684,368$
Total 1,702,596$ (1,635,715)$ 2,066,715$ (2,405,597)$ (475,666)$ (1,487,066)$
Discount Rate: 7.2002%
30-Year PV (560,854)$ (1,454,744)$ (568,169)$ (1,623,760)$ (1,379,679)$ (1,425,457)$
Levelized (47,741)$ (123,830)$ (48,364)$ (138,217)$ (117,441)$ (121,337)$
30-Year PV Rank 6 2 5 1 4 3
20-Year PV (1,177,823)$ (1,728,964)$ (1,261,180)$ (1,819,928)$ (1,836,136)$ (1,724,186)$
Levelized (116,909)$ (171,614)$ (125,183)$ (180,643)$ (182,252)$ (171,140)$
20-Year PV Rank 6 3 5 2 1 4
10-Year PV (733,761)$ (932,626)$ (808,160)$ (881,770)$ (1,199,331)$ (904,620)$
Levelized (109,170)$ (138,757)$ (120,239)$ (131,191)$ (178,438)$ (134,591)$
10-Year PV Rank 6 2 5 4 1 3
Notes:All values are averaged over all hours of simulation. Hydro fleet modified from original May 2004 runs. Transmission costs modified from original May 2004 values
Base case includes all existing and committed resources as of January 1, 2004
All costs nominal.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-28-2004 Page 9 of 9 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Natural Gas Expense
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Natural Gas Expense, Normal Gas Scenario ($ x 1000)
Year P0 P3
P6 Gas NORM DSM
NEW
P7 Gas NORM DSM
NEW
P8 Gas NORM DSM
NEW
P11 Gas NORM
DSM NEW
2004 -$ -$ -$ -$ -$ -$
2005 533$ 533$ 447$ 447$ 447$ 447$
2006 343$ 343$ 384$ 384$ 1,825$ 384$
2007 2,342$ 2,094$ 5,643$ 5,643$ 4,409$ 5,643$
2008 3,206$ 5,277$ 6,869$ 6,406$ 6,181$ 6,406$ 2009 4,277$ 8,860$ 7,358$ 9,375$ 7,106$ 9,375$
2010 7,899$ 14,661$ 9,826$ 9,751$ 8,683$ 21,113$
2011 19,738$ 30,090$ 14,701$ 14,421$ 11,936$ 23,821$
2012 21,844$ 40,632$ 15,904$ 15,587$ 12,412$ 24,841$
2013 27,005$ 50,329$ 19,594$ 16,114$ 14,469$ 29,507$ 2014 27,718$ 52,829$ 19,966$ 16,062$ 14,971$ 29,709$
2015 39,009$ 72,139$ 28,538$ 19,398$ 19,252$ 38,515$
2016 42,144$ 76,069$ 28,409$ 20,771$ 21,322$ 39,448$
2017 42,240$ 81,209$ 29,128$ 20,167$ 21,869$ 40,279$
2018 44,958$ 86,813$ 30,719$ 22,003$ 23,890$ 41,703$ 2019 46,876$ 92,411$ 32,441$ 22,812$ 24,600$ 42,614$
2020 58,438$ 113,838$ 42,696$ 23,851$ 26,974$ 51,225$
2021 64,871$ 125,819$ 48,858$ 24,842$ 28,127$ 55,199$
2022 56,008$ 108,476$ 39,876$ 25,964$ 27,234$ 49,866$
2023 63,905$ 119,881$ 45,724$ 27,720$ 30,188$ 55,817$ 2024 70,844$ 133,309$ 52,249$ 31,169$ 33,035$ 61,016$
2025 63,027$ 118,777$ 45,117$ 31,294$ 31,987$ 55,765$
2026 71,380$ 133,297$ 51,224$ 32,506$ 34,478$ 61,926$
2027 64,947$ 119,113$ 45,450$ 31,962$ 33,215$ 57,576$
2028 71,686$ 131,178$ 49,906$ 33,491$ 35,079$ 62,527$ 2029 79,174$ 145,283$ 55,956$ 36,780$ 38,185$ 68,336$
2030 87,470$ 158,940$ 62,008$ 39,140$ 41,010$ 74,089$
2031 97,803$ 176,163$ 69,928$ 43,108$ 45,132$ 81,667$
2032 108,401$ 194,779$ 77,370$ 46,699$ 49,165$ 89,048$
2033 99,037$ 178,800$ 70,185$ 44,280$ 46,268$ 82,638$ Total 1,387,121$ 2,571,943$ 1,006,474$ 672,147$ 693,451$ 1,260,499$
Discount Rate: 7.2002%
30-Year PV 359,085$ 666,410$ 268,647$ 190,652$ 191,955$ 348,302$
Levelized 30,566$ 56,726$ 22,868$ 16,229$ 16,340$ 29,648$ 30-Year PV Rank 5 6 3 1 2 4
20-Year PV 217,821$ 406,972$ 167,942$ 126,054$ 124,377$ 227,235$
Levelized 21,620$ 40,395$ 16,670$ 12,512$ 12,345$ 22,555$
20-Year PV Rank 4 6 3 2 1 5
10-Year PV 50,658$ 88,008$ 49,103$ 47,952$ 41,721$ 72,808$
Levelized 7,537$ 13,094$ 7,306$ 7,134$ 6,207$ 10,832$
10-Year PV Rank 4 6 3 2 1 5
Page 1 of 3 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Natural Gas Expense
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalatedNatural Gas Expense, LOW Gas Scenario ($ x 1000)
Year P0 LOW Gas
P3 Gas LOW DSM
no change
P6 Gas LOW DSM
NEW
P7 Gas LOW DSM
New
P8 Gas LOW DSM
NEW
P11 Gas LOW DSM
NEW
2004 36$ 36$ 36$ 36$ 36$ 36$
2005 283$ 283$ 266$ 266$ 266$ 266$
2006 284$ 284$ 350$ 350$ 1,248$ 350$
2007 2,206$ 1,973$ 4,475$ 4,475$ 3,336$ 4,475$
2008 3,077$ 5,102$ 5,472$ 5,208$ 5,468$ 5,208$
2009 3,912$ 8,027$ 5,604$ 7,259$ 5,991$ 7,259$
2010 6,547$ 11,910$ 8,156$ 8,026$ 7,461$ 16,713$
2011 17,370$ 26,595$ 12,098$ 11,853$ 10,007$ 19,712$
2012 17,855$ 35,585$ 12,857$ 12,859$ 10,051$ 20,799$
2013 22,787$ 44,093$ 16,259$ 13,611$ 12,530$ 24,476$
2014 23,202$ 45,684$ 15,970$ 13,015$ 12,569$ 24,995$
2015 32,765$ 62,253$ 23,853$ 16,457$ 16,266$ 31,880$
2016 34,690$ 63,928$ 23,704$ 17,262$ 17,603$ 32,902$
2017 35,050$ 67,013$ 23,731$ 16,887$ 18,072$ 33,010$
2018 38,054$ 71,769$ 25,460$ 18,431$ 19,790$ 34,869$
2019 39,543$ 77,074$ 26,953$ 18,795$ 20,158$ 35,675$
2020 48,502$ 94,318$ 35,391$ 19,747$ 22,592$ 42,801$
2021 53,576$ 104,111$ 40,452$ 20,667$ 23,418$ 46,036$
2022 46,769$ 89,805$ 33,065$ 21,538$ 22,571$ 41,572$
2023 52,267$ 99,203$ 38,221$ 22,630$ 24,836$ 45,647$
2024 59,208$ 111,290$ 43,389$ 25,926$ 27,544$ 51,202$
2025 53,071$ 99,274$ 37,395$ 26,129$ 26,806$ 46,752$
2026 59,553$ 110,641$ 42,456$ 27,196$ 28,719$ 51,545$
2027 54,570$ 100,328$ 37,859$ 26,605$ 27,856$ 48,406$
2028 59,886$ 110,112$ 41,552$ 28,025$ 29,795$ 52,347$
2029 66,325$ 121,291$ 46,898$ 30,695$ 32,177$ 57,377$
2030 72,699$ 131,866$ 51,609$ 32,643$ 34,331$ 62,007$
2031 81,822$ 147,011$ 58,220$ 35,687$ 37,757$ 67,744$
2032 90,940$ 163,576$ 65,030$ 39,296$ 41,211$ 74,748$
2033 82,546$ 149,151$ 58,787$ 37,096$ 38,679$ 69,259$
Total 1,159,393$ 2,153,585$ 835,567$ 558,671$ 579,144$ 1,050,067$
Discount Rate: 7.2002%
30-Year PV 300,662$ 560,483$ 222,028$ 157,869$ 160,043$ 289,112$
Levelized 25,593$ 47,709$ 18,899$ 13,438$ 13,623$ 24,610$
30-Year PV Rank 5 6 3 1 2 4
20-Year PV 182,487$ 343,741$ 138,104$ 103,945$ 103,401$ 187,766$
Levelized 18,113$ 34,119$ 13,708$ 10,317$ 10,263$ 18,637$
20-Year PV Rank 4 6 3 2 1 5
10-Year PV 43,314$ 77,135$ 39,793$ 39,134$ 34,752$ 59,338$
Levelized 6,444$ 11,476$ 5,921$ 5,822$ 5,170$ 8,828$
10-Year PV Rank 4 6 3 2 1 5
Page 2 of 3 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - Natural Gas Expense
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Natural Gas Expense, HIGH Gas Scenario ($ x 1000)
Year P0 HIGH Gas P3 Gas HIGH DSM no change P6 Gas HIGH DSM NEW P7 Gas HIGH DSM NEW P8 Gas HIGH DSM NEW P11 Gas HIGH DSM NEW
2004 -$ -$ -$ -$ -$ -$
2005 445$ 445$ 583$ 583$ 583$ 583$
2006 491$ 491$ 434$ 434$ 1,918$ 434$
2007 3,123$ 2,496$ 8,069$ 8,069$ 5,750$ 8,069$
2008 4,253$ 7,019$ 9,236$ 8,639$ 8,188$ 8,639$
2009 6,147$ 12,321$ 10,972$ 13,734$ 9,153$ 13,734$
2010 11,829$ 19,868$ 14,659$ 15,004$ 12,558$ 30,023$
2011 27,133$ 40,871$ 21,024$ 21,076$ 15,925$ 33,654$
2012 29,508$ 55,699$ 22,297$ 22,339$ 16,829$ 36,475$
2013 36,802$ 69,345$ 28,099$ 24,666$ 21,213$ 41,548$
2014 38,179$ 70,574$ 28,155$ 22,891$ 21,090$ 41,453$
2015 54,423$ 97,421$ 40,228$ 27,426$ 26,514$ 54,170$
2016 58,698$ 106,415$ 41,505$ 29,565$ 29,566$ 56,115$
2017 60,724$ 111,234$ 40,516$ 28,949$ 31,104$ 56,199$
2018 63,680$ 120,238$ 44,497$ 31,122$ 33,571$ 58,302$
2019 65,711$ 126,436$ 45,369$ 32,037$ 34,944$ 60,066$
2020 80,655$ 158,445$ 59,729$ 33,883$ 38,071$ 72,103$
2021 89,924$ 175,348$ 68,793$ 35,152$ 39,678$ 77,707$
2022 79,582$ 152,436$ 57,201$ 36,346$ 38,587$ 70,219$
2023 89,614$ 169,476$ 64,755$ 39,392$ 42,259$ 78,786$
2024 99,063$ 186,398$ 73,267$ 43,834$ 46,518$ 85,922$
2025 87,698$ 164,767$ 62,966$ 43,970$ 44,927$ 78,103$
2026 99,446$ 185,092$ 71,256$ 45,460$ 48,175$ 86,688$
2027 89,250$ 166,387$ 63,437$ 44,464$ 46,462$ 80,203$
2028 99,479$ 183,458$ 70,006$ 46,751$ 49,910$ 87,587$
2029 111,495$ 203,828$ 78,275$ 51,288$ 53,948$ 96,019$
2030 122,195$ 221,656$ 86,613$ 54,597$ 58,148$ 103,312$
2031 136,838$ 245,397$ 97,416$ 59,627$ 63,567$ 113,412$
2032 150,888$ 271,530$ 107,658$ 64,861$ 68,534$ 123,967$
2033 138,413$ 247,366$ 98,183$ 62,124$ 65,162$ 115,460$
Total 1,935,684$ 3,572,453$ 1,415,198$ 948,284$ 972,851$ 1,768,949$
Discount Rate: 7.2002%
30-Year PV 500,651$ 922,376$ 379,196$ 270,987$ 267,874$ 490,109$
Levelized 42,616$ 78,514$ 32,278$ 23,067$ 22,802$ 41,719$
30-Year PV Rank 5 6 3 2 1 4
20-Year PV 303,715$ 560,772$ 238,547$ 180,784$ 172,785$ 320,828$
Levelized 30,146$ 55,661$ 23,678$ 17,944$ 17,150$ 31,845$
20-Year PV Rank 4 6 3 2 1 5
10-Year PV 69,552$ 119,883$ 70,129$ 70,077$ 56,601$ 103,652$
Levelized 10,348$ 17,836$ 10,434$ 10,426$ 8,421$ 15,421$
10-Year PV Rank 2 6 4 3 1 5
Notes:All values are averaged over all hours of simulation. Hydro fleet modified from original May 2004 runs. Transmission costs modified from original May 2004 values
Base case includes all existing and committed resources as of January 1, 2004
All costs nominal.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-28-2004 Page 3 of 3 AURORAxmp Ver. 7.1.0.0
Portfolio Finalists Analysis - IPC Area Prices
Portfolios 3, 6, 7, 8 & 11 Comparison
AURORAxmp Portfolio Analysis
2004 Integrated Resource Plan
Area Price ($/MWh)Scenario: Oregon CO2 emission costs set at $12.30/ton starting in 2008, escalated annually
Wind PTC set to $-19.00/MWh, not escalated
Year P0 P0 LOW Gas P0 HIGH Gas P3
P3 Gas LOW
DSM no
change
P3 Gas HIGH
DSM no
change P6
P6 Gas NORM
DSM NEW
P6 Gas LOW
DSM NEW
P6 Gas HIGH
DSM NEW
2004 32.2724$ 26.9213$ 43.1838$ 32.2724$ 26.9213$ 43.1838$ 32.2724$ 32.2724$ 26.9213$ 43.1838$
2005 35.8034$ 22.9805$ 40.8635$ 35.8034$ 22.9805$ 40.8635$ 35.7554$ 35.7439$ 22.8862$ 41.1862$
2006 37.9019$ 28.2697$ 47.8700$ 37.9019$ 28.2697$ 47.8700$ 38.0948$ 38.0942$ 28.4103$ 47.9518$
2007 38.7158$ 29.7844$ 50.8667$ 38.5135$ 29.6891$ 50.5591$ 38.4399$ 38.4895$ 29.7004$ 50.6090$
2008 46.8972$ 38.8768$ 59.8093$ 46.6046$ 38.4858$ 59.3992$ 46.7321$ 46.8098$ 38.6051$ 59.5384$
2009 47.8447$ 40.0044$ 62.3130$ 48.6344$ 40.5497$ 62.9461$ 47.7337$ 47.8724$ 39.9042$ 61.9674$
2010 51.9132$ 44.1465$ 68.2923$ 52.9669$ 44.7237$ 69.0993$ 51.9197$ 51.8615$ 44.0764$ 67.8826$
2011 59.2286$ 51.3827$ 77.0716$ 60.4959$ 52.0199$ 78.0192$ 60.1346$ 59.3187$ 53.1036$ 77.1867$
2012 62.0773$ 54.0876$ 79.7689$ 62.5627$ 54.4415$ 80.3493$ 62.5404$ 62.6094$ 55.0589$ 80.2731$
2013 67.3937$ 60.6041$ 85.7573$ 68.1660$ 60.7841$ 86.7264$ 68.9166$ 68.3894$ 61.0126$ 87.1084$
10 Year Average 48.00$ 39.71$ 61.58$ 48.39$ 39.89$ 61.90$ 48.25$ 48.15$ 39.97$ 61.69$
Discount Rate: 7.2002%
Levelized Price 45.7951$ 37.3893$ 58.6490$ 46.1083$ 37.5345$ 58.8973$ 45.9743$ 45.8944$ 37.5872$ 58.7195$
10-Year Rank 10 2 19 16 4 21 14 12 5 20
Area Price ($/MWh) continued
Year P7
P7 Gas NORM
DSM NEW
P7 Gas LOW
DSM New
P7 Gas HIGH
DSM NEW P8
P8 Gas NORM
DSM NEW
P8 Gas LOW
DSM NEW
P8 Gas HIGH
DSM NEW P11
P11 Gas NORM
DSM NEW
P11 Gas LOW
DSM NEW
P11 Gas HIGH
DSM NEW
2004 32.2724$ 32.2724$ 26.9213$ 43.1838$ 32.2724$ 32.2724$ 26.9213$ 43.1838$ 32.2724$ 32.2724$ 26.9213$ 43.1838$
2005 35.7554$ 35.7439$ 22.8862$ 41.1862$ 35.7554$ 35.7439$ 22.8862$ 41.1862$ 35.7554$ 35.7439$ 22.8862$ 41.1862$
2006 38.0948$ 38.0942$ 28.4103$ 47.9518$ 37.8529$ 37.9297$ 28.2612$ 47.7813$ 38.0948$ 38.0942$ 28.4103$ 47.9518$
2007 38.4399$ 38.4895$ 29.7004$ 50.6090$ 37.2893$ 37.2721$ 28.5522$ 48.9710$ 38.4399$ 38.4895$ 29.7004$ 50.6090$
2008 46.5705$ 46.5722$ 38.4403$ 59.3950$ 45.5399$ 45.5219$ 37.8088$ 58.3189$ 46.5705$ 46.5722$ 38.4403$ 59.3950$ 2009 49.2100$ 49.2009$ 41.1183$ 63.7222$ 47.1714$ 47.0718$ 39.2460$ 60.9199$ 49.2100$ 49.2009$ 41.1183$ 63.7222$
2010 51.7497$ 51.7114$ 43.8930$ 68.0180$ 50.7999$ 50.7280$ 43.2500$ 66.6824$ 53.4335$ 53.4388$ 45.6665$ 70.2817$ 2011 59.0834$ 58.9868$ 51.9733$ 76.6776$ 57.4102$ 57.1308$ 50.1992$ 75.5621$ 58.9545$ 58.3865$ 52.0194$ 76.7408$
2012 62.4886$ 62.1901$ 54.5305$ 79.5306$ 60.8719$ 60.5656$ 52.5760$ 78.3555$ 60.8810$ 62.2210$ 53.2383$ 79.6025$
2013 65.3979$ 66.6445$ 59.5471$ 84.9408$ 65.6546$ 65.5424$ 59.3519$ 84.8127$ 67.8060$ 67.7906$ 60.9113$ 86.5336$
10 Year Average 47.91$ 47.99$ 39.74$ 61.52$ 47.06$ 46.98$ 38.91$ 60.58$ 48.14$ 48.22$ 39.93$ 61.92$
Discount Rate: 7.2002%
Levelized Price 45.7398$ 45.7981$ 37.4305$ 58.6287$ 44.9612$ 44.8946$ 36.6796$ 57.7466$ 45.9270$ 45.9858$ 37.5894$ 58.9535$
10-Year Rank 9 11 3 18 8 7 1 17 13 15 6 22
Notes:All values are averaged over all hours of simulation. Hydro fleet modified from original May 2004 runs. Transmission costs modified from original May 2004 values.
Base case includes all existing and committed resources as of January 1, 2004.
All costs nominal.
Simulation:Every 3rd hour; MWFSu; 1st & 3rd weeks
Revised 6-30-2004
Page 1 of 1 AURORAxmp Ver. 7.1.0.0
2004 Integrated Resource Plan
Technical Appendix

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PPllaannnniinngg CCrriitteerriiaa

Summary of Northwest Utility Planning Criteria

Utility Planning Criteria Source
Avista Corporation Peak Load: The maximum one-hour load obligation on the expected average coldest day in January.
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 ten percent
chance that the combination of load and hydro variability would exceed the planning criteria.”

2003 Integrated Resource
Plan, Pages 7-9
Bonneville Power
Administration
(BPA)
Load and Resource Balances: System firm energy loads are compared with Federal system energy
resources for each month of Operating Year 2002 – 2007 (Aug. 2001 – July 2007) under 1937
water conditions. Firm capacity surpluses or deficits are determined in the same period under
1937 water conditions.1
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. 1
Surplus Energy Analysis: Defined as the amount of generation that can be produced in excess of
firm loads under critical water conditions. 1
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. 2
Hydroelectric Energy Capability: Uses OY 1937-water conditions (the 12-month period from August
1936 through July 1937) to estimate the firm hydro energy capability in low water conditions. 2
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. BPA 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. 2

12002 Final Power Rate
Proposal Loads and
Resources Study, WP-02-FS-
BPA-01, May 2000, Sections
2.3.3.2, 2.3.3.3 2.3.3.4

22002 Pacific Northwest
Loads and Resources Study,
December 2002, Section 2,
Pages 4, 38

Page 1 of 2 2004 Integrated Resource Plan
Idaho Power Company
Utility Planning Criteria Source
Idaho Power
Company (IPC)
Hydro Conditions: 70th percentile hydro conditions based upon historical data from 1928 through
2003.
Load Forecast: Based upon 70th percentile weather conditions.
Monthly Average Energy: Based upon hydro conditions and load forecast.
Capacity: Based on monthly peak-hour Northwest transmission deficit assuming 90th percentile water
conditions, 70th percentile load forecast with a 1 in 20 peak.

2004 Integrated Resource
Plan, August 2004. Pages
33, 39-42.

2004 IRP Technical Appendix
B – Sales and Load Forecast,
August 2004, Page 9.
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.

Mr. Jeff King, Northwest
Power and Conservation
Council.
PacifiCorp Hydro Conditions: Median water conditions.
Loads: Average energy requirements based upon normal weather conditions.
Capacity: Normal weather peak-hour loading plus a 15% planning margin.

2004 Integrated Resource
Plan, to be filed December
2004.
Portland General
Electric Company
(PGE)
Hydro Conditions: Normal/median water conditions based upon 59 years of hydro history.
Loads: Median load conditions.
Capacity: Normal weather peak loading plus 12% (6% operating margin, 6% planning margin).
Then subtract 500 MW (to be filled in with short term market purchases).

Final Action Plan, 2002 IRP,
March 2004. Appendix 2,
Table 20, Page 85.
Puget Sound
Energy (PSE)
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 through February) is 23 degrees at SeaTac Airport.
Peak MW = a x Resid aMW + b x Non-Resid aMW + c x (Deviation from Normal Peak Temp) x
(Weather Sensitive aMW) x SeasonDummy + d x Sched48Dummy + e x ElNinoDummy
Where a, b, c, d, e are coefficients to be estimated.
Design Temperatures: 23° F for normal peak and 13° F for extreme peak, both occurring in January.

PSE Least Cost Plan, April 30,
2003. Appendix C, Pages 3
and 8.

Summary of Northwest Page 2 of 2 2004 Integrated Resource Plan
Utility Planning Criteria Idaho Power Company
2004 Integrated Resource Plan
Technical Appendix

IIRRPP AAddvviissoorryy CCoouunncciill RRoosstteerr

Idaho Power Company
2004 Integrated Resource Plan
Advisory Council

CUSTOMER PARTICIPANTS
Micron Technology Inc. – Dan Kincaid
J. R. Simplot Company – David Hawk
INEEL – Tom Moriarty
Heinz Frozen Foods – Steve Munn
AARP – Janice Stover or Francis McDonald
Idaho Retailers Association – Pam Eaton
Idaho Irrigation Pumpers – Lynn Tominaga
The Amalgamated Sugar Company, LLC – Ray Arp or Ed Bulgin

COMMISSION PARTICIPANTS
Idaho Public Utilities Commission – Randy Lobb
Oregon Public Utility Commission – Bill McNamee

ENVIRONMENTAL PARTICIPANTS
Natural Resource Defense Council - Ralph Cavanagh or Devra Bachrach
Advocates for the West - Bill Eddie

OTHERS
Idaho Department of Water Resources – Bob Hoppie
Office of the Governor – Jim Yost
Idaho State Legislature – Representative Steve Smylie
Consultant in Electric-Industry Restructuring – Eric Hirst