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Home My WebLink About200408272004 IRP technical appendix.pdfProviding 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 SSaalleess aanndd LLooaadd FFoorreeccaasstt 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. 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 Ho u r Su n d a y Mo n d a y Tu e s d a y We d n e s d a y Th u r s d a y Fri d a y Sa t u r d a y Ho l i d a y 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 Ho u r Su n d a y Mo n d a y Tu e s d a y We d n e s d a y Th u r s d a y Fri d a y Sa t u r d a y Ho l i d a y 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 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 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 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 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 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 m i l l i o n s o f d o l l 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 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 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 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 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 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 m i l l i o n s o f d o l l a r s 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 $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 m i l l i o n s o f d o l l a r s 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 SSuummmmaarryy ooff NNoorrtthhwweesstt UUttiilliittyy 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