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Home My WebLink AboutKetchikan Power Supply Planning Study 1986Alaska Power Authority LIBRARY COPY POWER SUPPLY PLANNING STUDY I REE pe : be nn Engineers BE eons co 2M = Economists BE scientists May 29, 1986 K18200.C0 Mr. Richard A. Southworth Utilities Manager Ketchikan Public Utilities Ketchikan, Alaska 99901 Dear Dick: Subject: Power Supply Planning Study We are pleased to present CH2M HILL's Power Supply Planning Study prepared for Ketchikan Public Utilities. Our con- clusions and recommendations are summarized in Section 7. On the basis of the most recent electric peak load and energy requirement load forecast prepared for the KPU system, our studies show the need for some small-capacity additions to the KPU system staged over the next several years. These additions are required to meet reserve requirements in the event of an interruption of power from the Swan Lake Project. This report is part of the comprehensive long-range planning work for the KPU system that began with KPU's authorization on February 16, 1984. The analysis is based on a computer- ized model of KPU's power system, using software developed by the Westinghouse Electric Corporation. This report should be reviewed and updated periodically, especially as KPU's loads change in the future and as new major loads are being considered. With the basis of this study substantially computerized, updates of this report should be relatively easy to prepare. CH2M HILL Seattle Office 1500- 114th Ave. S.E., Bellevue, Washington 206.453.5000 P.O. Box 91500, Bellevue, Washington 98009-2050 Ory Mr. Richard A. Southworth Page 2 May 29, 1986 K18200.C0 We appreciate the assistance that you and your staff have given us throughout the performance of this work. Sincerely, (ya Richard 0. ne sal - Project Administrator Bob ial Bob Brooks Project Manager in, gks/5680/007 Attachment ome ie : } POWER SUPPLY PLANNING STUDY Ketchikan Public Utilities Ketchikan, Alaska CH2M HILL Bellevue, Washington May 1986 K18200.CO0 KETCHIKAN PUBLIC UTILITIES--BOARD MEMBERS William C. Goodale Maxine Doyle Jim Carlton Jack Davies Val Jackson Arthur W. Morgan Mike Salazar Chairman Secretary Member Member Member Member Member CITY OF KETCHIKAN--MAYOR AND COUNCIL MEMBERS Ted Ferry Paul Boyd Tom Friesen Val Jackson Elaine Seymour Georgia Skannes Alaire Stanton Ed Zastrow Mayor Council Member Council Member Council Member Council Member Council Member Council Member Council Member KETCHIKAN PUBLIC UTILITIES--MANAGEMENT Richard A. Southworth Peter E. Diedrich Richard D. Newland CH2M HILL PROJECT STAFF Robert G. Brooks Richard O. Wagner, Warren G. Edgley, David A. Gray David R. Pitzler P.E. P.E. Utilities Director Utilities Engineer Former Utilities Director Project Manager Project Administrator Senior Consultant Senior Consultant Project Economist n CONTENTS Page 1 Introduction 1-1 2 System Load Forecast 2-1 3 Present KPU Resources Sa 4 Future Power Supply Alternatives 4-1 Thermal Power Plants 4-1 Hydroelectric Power Plants 4-4 Transmission Interconnections 4-6 5 The Power Supply Planning Computer Model 5=1 Description of the Westinghouse AGP Model 5-1 6 Evaluation of Specific Alternatives 6-1 Power Supply Planning Criteria 6-1 Economic Analyses 6-3 v/ Power Supply Strategy and Conclusions 7-1 Appendix A. Fuel Price Forecast Appendix B. Base Case Run Lid, TABLES 2-1 Baseload Peak-Load and Energy Forecast, 1983 - 2005 2-2 High Growth Peak-Load and Energy Forecast, 1983 - 2005 2-3 Baseload Peak-Load and Energy Forecast Load Allocation Among Substations, 1983 Through 2005 2-4 High-Growth Peak-Load and Energy Forecast Load Allocation Among Substations, 1983 - 2005 3-1 Existing Power Supply Resources 3-2 Net Generation by Plant (1980-1984) 3-3 Existing Unit Data and Assumptions 4-1 Future Power Supply Resource Options: Data and Assumptions 6-1 Results of Base Case AGP Computer Run iv 3-4 4-5 6-5 ey) ' 4 — ——s — ve FIGURES Sal S22 3>3) 34 4-1 4-2 51 6-1 6-2 6-3 Monthly Energy Prod. - Ketchikan Lakes Monthly Energy Production - Beaver Falls Monthly Energy Production - Silvis Lake Monthly Energy Production - Swan Lake General Location Map Ketchikan Public Utilities Automated Generation Planning (AGP) Computer Program Structure Case 1: Base Case Expansion Plan Projected Loads Vs. Existing Resources Case 3: Mahoney Lake Expansion Plan Alternative Load Growth Scenarios Case 4: High Load Growth Expansion Plan Case 5: Low Load Growth Expansion Plan Cost of Power Supply, 1985 - 2004 Cost of Power Supply, 1985 - 2004 4-3 5-2 6-6 6-12 6-13 6-14 6=15 ~ SECTION1 _ Introduction - Section 1 INTRODUCTION On February 16, 1984, the Ketchikan City Council authorized CH2M HILL to perform a comprehensive long-range planning ° study for Ketchikan Public Utilities (KPU) consisting of several specific tasks. Electric peak load and energy requirements forecast Utility system maps and fixed asset record and inventory reports, including aerial photography and computer-generated maps of the electric, telephone, and water utility systems. Long-range electric system planning study Power supply planning study Financial forecast for the electric utility Allocated embedded cost-of-service study and retail rate design for the electric utility | This report presents the results of the power supply plan- ning study. The scope of work for this study and the sec- tions of the report that describe the results of each task | are summarized below. Li Evaluate existing system and develop planning and com- { puter model criteria ° Identify the pertinent characteristics of existing [ generation resources available to KPU (Section 2) i ° Establish base cost assumptions and planning cri- teria for subsequent use in a computer model to f evaluate power supply strategies (Sections 4 and 5) Pa Evaluate and prepare sensitivity analyses of { alternative power supply strategies under consideration ° Identify and test several candidate long-term gen- \ eration strategies (Sections 3 and 5) t ° Recommend a preferred strategy based on overall ; costs, environmental aspects and system reliabil- {" ity (Section 6) 3. Prepare a final report that summarizes the work per- f formed and recommendations (Sections 1 through 6) -.SECTION2 __. System Load Forecast Section 2 SYSTEM LOAD FORECAST In August 1984 an electric system load forecast was developed by CH2M HILL and presented to KPU management. The forecast was based on relevant sociological and economic factors associated with the Ketchikan Gateway Borough (Borough). Primary employment sectors were identified for the Borough and compared to Alaska and overall United States averages, and projections of employment, population, and households through the year 2005 were developed. The household projec- tions were used to project energy requirements and system peak loads for KPU. The economic data reviewed as part of this forecast were obtained from published reports and interviews available in mid-1984. A wide range of economic projections for the Borough have appeared in previous studies. Based on the recommendation of the planning director of the Borough and our independent evaluation, the projections of employment growth and estimates of household size used in the forecast were taken from the draft environmental impact statement for the Quartz Hill molybdenum project mine development prepared in 1984 for the U.S. Forest Service. Because of the high degree of speculation about the future of the Borough's economy, an analysis of the sensitivity of the energy requirements and peak-load forecasts to changes in key economic parameters was presented. Two peak-load and energy forecasts were prepared. First was a "baseline" forecast, assuming that the U.S. Borax project does not develop at Quartz Hill. The results of this baseline forecast are shown in Table 2-1. Based on the forecast, the peak load on the KPU system (excluding LPK) is expected to grow from about 20.9 MW in 1985 to about 30.5 MW in the year 2005. Second, a "high-growth" forecast was developed, assuming that the U.S. Borax project is developed at Quartz Hill and that the families of the U.S. Borax employees reside in the Ketchikan area. Table 2-2 shows the results of the high-growth forecast. Based on this forecast, the peak load on the KPU system (excluding LPK) is expected to grow from about 20.9 MW in 1985 to about 36.3 MW in the year 2005. The forecasts also were expanded to allocate the projected loads among the several substation areas in the KPU system. The results of the load allocations among the substation areas for the baseline and high-growth forecasts are sum- marized in Tables 2-3 and 2-4, respectively. TABLE 2-1 2. BASELOAD PEAK-LOAD AND ENERGY FORECAST 1983 - 2005 1983 1984 1985 1986 1987 1988 1989 1990 1995 2000 2005 NUMBER OF CUSTOMERS Residential 5,053 5,094 5,184 5,252 5,320 5,390 5,460 5,531 5,902 6,296 6,717 Boats 341 344 a8 358 365 372 380 387 428 472 521 Commercial 800 795 836 847 872 884 910 922 984 1,067 1,158 General Power 6 6 6 6 6 6 6 6 6 7 7 Area Lighting 70 63 64 65 65 66 67 68 73 77 83 Street Lighting 1 ZL 1 1 1 1 1 1 1 1 1 TOTAL 6,271 6,303 6,442 6,529 6,630 6,719 6,824 6,915 7,393 7,921 8,487 AVERAGE USE/CUSTOMER (kWH) Residential 8,898 9,998 9,496 9,569 9,647 9,730 9,817 9,909 10,347 10,757 11,011 Boats 2,871 3,622 3,300 3,300 . 3,300 3,300 3,300 3,300 3,300 3,300 3,300 Commercial 40,976 44,499 42,500 42,500 42,500 42,500 42,500 42,500 42,500 42,500 42,500 General Power 1,046,500 1,094,000 1,110,410 1,127,066 1,143,972 1,161,132 1,178,549 1,196,227 1,288,676 1,388,270 1,495,561 Area Lighting 3,357 1,937 1,975 2,015 2,055 2,096 2,138 2,181 2,408 2,658 2,935 Street Lighting 599,000 610,000 600,044 610,538 625,160 636,429 652,015 663,928 725,997 805,978 877,363 bt 1 ANNUAL ENERGY USE (kWh x 1,000) NS Residential 53,601 54,805 61,066 67,727 73,961 Boats 1,253 1,278 1,411 1,558 1,721 Commercial 38,675 General Power 7,071 Subtotal 100,601 102,439 112,015 124,356 135,370 Area Lighting 235 - 122 126 130 135 139 144 148 175 206 243 Street Lighting 599 610 600 611 625 636 652 664 726 806 877 TOTAL ENERGY SALES (MWh) 85,834 94,850 93,308 94,942 97,217 98,971 101,396 103,251 112,916 125,368 136,490 UTILITY USE AND SYSTEM LOSSES 11,673 12,900 12,690 12,912 13,221 13,460 13,790 14,042 15,357 17,050 18,563 Va e TOTAL ENERGY REQUIREMENTS (kWh) 97,507 107,750 105,998 107,854 110,438 112,431 115,186 117,293 128,273 142,418 155,052 PEAK DEAMND [58% L.F.MW] (MW) 19,191 21,207 20,862 21,228 21,736 22,129 22,671 23,086 25,247 28,031 30,517 —_— morn cot ey — core — — — os — — nm _—) —— — ——— ~~ Table 2-2 HIGH GROWTH PEAK-LOAD AND ENERGY FORECAST 1983 - 2005 1983 1984 1985 1986 1987 1988 1989 1990 1995 2000 2005 NUMBER OF CUSTOMERS Residential 5,053 5,094 5,188 5,306 5,618 5,756 6,138 6,307 6,874 7,331 7,821 Boats 341 344 351 358 365 372 380 387 428 472 521 Commercial 800 795 837 856 921 944 1,023 1,051 1,146 1,243 1,348 General Power 6 6 6 6 6 6 6 6 6 7 7 Area Lighjting 70 63 64 66 69 71 76 78 85 91 97 Street Lighting 1 1 1 pT 1 1 1 1 1 a 1 TOTAL 6,271 6,303 6,447 6,592 6,981 7,150 7,624 7,831 8,539 9,144 9,796 AVERAGE USE/CUSTOMER (kWH) : Residential 8,898 9,998 9,498 9,616 9,908 10,041 10,385 10,542 11,032 11,385 11,721 Boats 2,871 3,622 3,300 3,300 2,300 3,300 3,300 3,300 3,300 3,300 3,300 Commercial 40,976 44,499 42,500 42,500 42,500 42,500 42,500 42,500 42,500 42,500 42,500 General Power 1,046,500 1,094,000 1,110,410 1,127,066 1,143,972 1,161,132 1,178,549 1,196,227 1,288,676 1,388,270 1,495,561 Area Lighting 3,357 1,937 1,975 2,015 2,055 2,096 2,138 2,181 2,408 2,658 2,935 Street Lighting 599,000 610,000 600,559 617,896 666,739 687,625 748,887 775,280 866,328 956,275 1,044,570 Ny) ANNUAL ENERGY USE (kWh x 1,000) Residential 44,961 50,931 49,278 51,021 55,662 57,796 63,745 66,489 75,833 83,461 91,670 Boats 979 1,246 1,158 1,181 1,205 1,229 1,253 1,278 1,411 1,558 1,721 Commercial 32,781 35,377 35,563 36,372 39,142 40,103 43,478 44,675 48,691 52,808 57,309 General Power 6,279 6,564 6,662 6,762 6,864 6,967 7,071 7,177 7,732 9,718 10,469 Subtotal 85,000 94,118 92,661 95,336 102,872 106,095 115,547 119,619 133,667 147,545 161,169 Area Lighting 235 - 122 127 132 143 149 162 170 205 241 284 Street Lighting 599 610 601 618 667 688 749 775 866 956 1,045 TOTAL ENERGY SALES (MWh) 85,834 94,850 93,389 96,086 103,682 106,932 116,458 120,565 134,738 148,743 162,497 UTILITY USE AND SYSTEM LOSSES 11,673 12,900 12,701 13,068 14,101 14,543 15,838 16,397 18,324 20,229 22,100 TOTAL ENERGY REQUIREMENTS (kWh) 97,507 107,750 106,089 109,154 117,783 121,474 132,297 136,962 153,063 168,972 184,597 PEAK DEMAND (58% L.F.MW] (MW) 19,191 21,207 20,880 21,484 23,182 23,909 26,039 26,957 30,126 33,257 36,332 ¥-Z TOTAL ENERGY REQUIREMENTS (MWh) SUBSTATION AREA Bailey Totem Bight Ketchikan Herring Cove Mountain Point Saxman Bethe Ward Cove PEAK DEMAND (MW) Bailey Totem Bight Ketchikan Herring Cove Mountain Point Saxman Bethe Ward Cove Table 2-3 BASELOAD PEAK-LOAD AND ENERGY FORECAST LOAD ALLOCATION AMONG SUBSTATIONS 1983 Through 2005 1983 1984 1985 1986 1987 1988 1989 1990 1995 2000 2005 97,507 107,750 105,998 107,854 110,438 112,431 115,186 117,293 128,273 142,418 155,052 Percent of Growth 20,452 23,525 22,999 23,556 24,331 24,929 25,756 26,388 29,682 33,925 37,716 0.30 9,767 10,791 10,616 10,802 11,060 11,259 11,535 11,746 12,844 14,258 15,522 0.10 35,386 36,922 36,660 36,938 37,326 37,625 38,038 38,354 40,001 “42,123 44,018 0.15 731 987 943 990 1,054 1,104 1,173 1,226 1,500 1,854 2,170 0.03 2,042 2,554 2,467 2,559 2,689 2,788 2,926 3,031 3,580 4,288 4,919 0.05 5,482 7,787 7,392 7,810 8,391 8,840 9,460 9,934 12,404 15,587 18,430 0.23 20,156 21,436 21,217 21,449 21,772 22,022 22,366 22,629 24,002 25,770 27,349 9.13 4,004 4,260 4,216 4,263 4,327 4,377 4,446 4,499 4,773 5,127 5,443 0.03 1.00 19,191 21,207 20,862 21,228 21,736 22,129 22,671 23,086 25,247 28,031 30,517 Load Factor 3,821 4,476 4,376 4,482 4,629 4,743 4,900 5,021 5,647 6,455 7,176 0.60 2,316 2,566 2,525 2,569 2,630 2,678 2,743 2,793 3,055 3,391 3,691 0.48 6,732 7,144 7,093 7,147 7,222 7,280 7,360 7,421 7,740 8,150 8,517 0.59 208 256 245 257 274 286 304 318 389 481 563 0.44 490 634 612 635 667 692 726 752 689 1,064 1,221 0.46 810 1,677 1,592 1,682 1,807 1,904 2,038 2,140 2,672 3,357 3,970 0.53 4,524 4,012 3,971 4,014 4,074 4,121 4,186 4,235 4,492 4,823 5,118 0.61 800 954 944 954 969 980 995 1,007 1,068 1,148 1,218 0.51 = ~ — —r — — - — eee ee S-2 TOTAL ENERGY REQUIREMENTS (MWh) SUBSTATION AREA Bailey Totem Bight Ketchikan Herring Cove Mountain Point Saxman Bethe Ward Cove PEAK DEAMND (MH) Bailey Totem Bight Ketchikan Herring Cove Mountain Point Saxman Bethe Ward Cove 97,507 20,452 9,767 35,386 731 2,042 5,482 20,156 4,004 19,191 3,821 2,316 6,732 208 490 810 4,524 107,750 23,525 10,791 36,922 987 2,554 7,787 21,436 4,260 21,207 4,476 2,566 7,144 256 634 1,677 4,012 954 HIGH-GROWTH PEAK LOAD AND ENERGY FORECAST 23,027 10,625 36 ,673 946 2,471 7,413 21,229 4,219 20,880 4,381 2,527 7,096 245 613 1,597 3,973 944 pt | Table 2-4 LOAD ALLOCATION AMONG SUBSTATIONS 1986 23,946 10,932 37,133 1,022 2,624 8,103 21,612 4,295 21,484 4,556 2,600 7,185 265 651 1,745 4,044 961 1983 1987 117,783 26,535 11,795 38,427 1,238 3,056 10,044 22,691 4,511 23,182 5,048 2,805 7,435 321 758 2,163 4,246 1,010 - 2005 1988 121,474 27,642 12,164 38,981 1,330 3,240 10,875 23,152 4,603 23,908 5,259 2,893 7,542 345 804 2,342 4,333 1,030 1989 132,297 30,889 13,246 40,605 1,601 3,782 13,310 24,505 4,874 26,039 5,877 3,150 7,856 415 938 2,867 4,586 1,091 32,289 13,713 41,304 1,717 4,015 14,359 25,088 4,990 26,957 6,143 3,261 7,992 446 996 3,093 4,695 1,117 37,119 15,323 43,719 2,120 4,820 17,982 27,101 5,393 30,126 7,062 3,644 8,459 550 1,196 3,873 5,072 1,207 41,892 16,914 46,106 2,518 5,615 21,562 29,089 5,791 33,257 7,970 4,022 8,921 653 1,394 4,644 5,444 1,296 2005 184,597 46,579 18,476 48,450 2,908 6,397 25,077 31,042 6,181 36,332 8,862 4,394 9,374 755 1,587 5,401 5,809 1,384 PERCENT OF GROWTH 0.30 0.10 0.15 0.03 0.60 0.48 0.59 0.44 0.46 0.53 0.61 0.51 The degree to which electric loads are expected to change in the future in Ketchikan is uncertain at this time. The prin- cipal reason for this uncertainty is the question of whether or not U.S. Borax will develop its proposed molybdenum mine project at Quartz Hill. While it is anticipated that U.S. Borax will either serve its own load with local generation at the site or purchase its power supply directly from B.C. Hydro, the influx of employees and their families into the Ketchikan area will have an important impact on the electric load growth of the KPU system. Assuming that the Quartz Hill project will develop within the next few years, peak loads on the KPU system will likely grow at an average compounded annual rate of 2.9 percent through the year 2005, with a higher growth rate in the earlier years. Without the Quartz Hill project, peak loads on the KPU system will likely grow at an average compounded annual rate of 2.1 percent through the year 2005. Specifically, the peak-load and energy forecast produced the following results for the overall system: 1988 2005 With U.S. Borax project Peak load (MW) 23.9 36.3 Energy requirements (GWh) 121.5 184.6 Without U.S. Borax project Peak load (MW) 2251. 30,5 Energy requirements (GWh) 112.4 155.1 — a a ES fy EA, AT RSA WA ay Section 3 PRESENT KPU RESOURCES KPU's existing power supply resources consist of KPU-owned diesel and hydroelectric power plants, and the Swan Lake hydroelectric project which is operated by KPU but owned by the Alaska Power Authority (APA). Thes marized in Table 3-1. Table 3-1 EXISTING POWER SUPPLY RESOURCES Resource KPU_ System: Totem Bight diesel unit Bailey diesel units Total Diesel Ketchikan Lake hydro- electric plant Beaver Falls hydro- electric plant Silvis Lake hydro- electric plant Total Hydroelectric TOTAL KPU System APA System: In addition to the resources in the area listed in Table 3-1, Swan Lake hydroelectric project Total KPU Resources Approxima Year o e resources are sum- te Installed if Capacity Installat 1966 1970-77 1923-57 1947-54 1976 1984 ion (kW) 1,600 13,000 14,600 3,900 22,500 48,000 there are other power generating resources owned by commer- cial and industrial customers in KPU. resource is about 17 MW of capacity owned by the Louisiana- Pacific Ketchikan Corporation (LPK). ity, The most significant LPK uses this capac- fueled by waste woods, to meet its own power requirements. There is a 34.5-kV interconnection between the LPK and KPU systems that can be used to provide backup power to either system when needed if the power is avail- able. Presently, there is no contractural relationship be- tween LPK and KPU regarding nonfirm power supply, and the 34.5-kV interconnection is operated in the open position. Because LPK is not in a position to guarantee the availabil- ity of power from its facility at all times and there is no contractural relationship between LPK and KPU regarding interchange power, LPK's generation was not considered to be a firm resource in this study. The same is true for other minor generating resources owned by KPU's customers in the area. In 1985, KPU entered into a long-term power sales agreement with APA to purchase power from the Four-Dam Pool. This agreement set the terms and conditions for KPU to purchase power from the Swan Lake project. Key provisions of the APA agreement relative to KPU's power supply planning are: ° Capacity and energy from the Swan Lake Project shall be available to KPU on a preference basis for resale to KPU's customers. ° After first dispatching its own hydroelectric re- sources to meet local requirements, KPU must pur- chase power from the Swan Lake project before using power from any other resource, including KPU-owned diesel generation. Table 3-2 provides a summary of net generation by plant for each of the years from 1980 to 1984. As shown in Table 3-2, diesel units provided only 5 percent of total energy requirements in 1984, as compared to 38 per- cent in 1983, because of the addition of the Swan Lake proj- ect. Based on the long-term power sales agreement with APA, KPU's diesel units will be used primarily during Swan Lake outages until KPU's net energy requirements exceed the com- bined capabilities of KPU's own hydroelectric units and the Swan Lake project. According to the load forecast based on U.S. Borax "committee option," this will occur near the end of the 1990's. The diesel units also contribute to KPU's reserve capacity. Data relative to the existing generating units were obtained from KPU staff. Where necessary, this information was sup- plemented with standard industry statistics (e.g., unit forced outage rates). Details of the assumptions used to model KPU's existing units are shown in Table 3-3. Curves showing the average energy generated monthly from the hydro- electric plants are shown on Figures 3-1 through 3-4. These a —_— =] een cet curves were used to model the seasonal fluctuations in the amount of energy available from each hydroelectric plant because of water conditions. The curves were derived from historical data as provided by KPU, after adjustment for unit outages. Table 3-2 NET GENERATION BY PLANT (1980-1984) Net Generation (GWh) Plant 1980 1981 1982 1983 1984 Totem Bight ted tus ies 0.8 - 0.2* Bailey rSi3 13.0 42.8 36.2 Bai Total Diesel 16.4 14,3 a5,1 37.0 4.9 (% of total) 20% 17% 37% 38% 5% Ketchikan 18.6 18.8 16.1 14.3 17.9 Beaver Falls 2708 38.8 34.9 23.9% 25.3 Silvis ee 14.1 10.0 10.6 6.8 Total Hydro 67.8 71ed 61.0 60.8 50.0 (% of total) 80% 83% 63% 62% 46% Swan Lake 0.0 0.0 0.0 0.0 53.0 (% of total) 0s 0s. 0s 0s 49% TOTAL 84.2 86.0 96.1 97.8 107.9 *Station use exceeded gross generation. 3-3 Forced Table 3-3 EXISTING UNIT DATA AND ASSUMPTIONS Scheduled Capacity Outage Rate Outage Rate Unit Name (kW) Diesel Units: Totem Bight Bailey #1 Bailey #2 Bailey #3 Total Diesel 14,600 Hydro Units: Ketchikan Lakes # 3 1,400 Ketchikan Lakes # 4 1,100 Ketchikan La as 1,400 Beaver Falls # 1 1,000 Beaver Falls #3 2,000 Beaver Falls # 4 2,000 Silvis Lake 2,000 Swan Lake # 1 11,250 Swan Lake # 2 11,250 Total Hydro 33,400 senseeene Total KPU 48,000 Notes: 2.8% 2.8% 2. Bx 2. 8% 2. 8% 2.8% 2.8% 2.8% 2.8% 2.8% 2. 8% 2. 8% 2. 6% (weeks/yr) Fixed O&M ($/kW/year) $27.50 $40. 00 $40.00 $40.00 $113.40 $113.40 $113.40 $43.67 $43.67 $43.67 $24.25 $0.00 $0.00 Variable O&M ($/Mih) $17.40 $4.66 $4.66 $4.66 $10.50 $10.50 $10.50 $0.95 $0.95 $0.95 $0.90 $55.50 a $55.50 a Average Heat Rate (Btu/kWh) SESESSESS Fuel Cost ($/MBtu) $4.125 $4. 125 $4,125 $4. 125 SSESESESE (a) Swan Lake energy charge per Four Dam Pool agreement; includes O&M and debt service costs. a a s-€ KWH GENERATED (Millions) MONTHLY ENERGY PROD. — KETCHIKAN LAKES 3.0 2.8 2.6 2.4 2.2 2.0 1.8 1.6 1.4 1.2 1.0 0.8 0.6 0.4 0.2 9.0 1981-1984 AVERAGE (ADJUSTED) MONTH Figure 3-1 KWH GENERATED (Millions) MONTHLY ENERGY PRODUCTION— BEAVER FALLS 1981-1984 AVERAGE {ADJUSTED} 3.5 3.0 2.5 2.0 1.5 1.0 0.5 9.0 —— See MONTH Figure 3-2 —_— o— x a — — —— —— — —— — , L-€ KWH GENERATED (Mittions) MONTHLY ENERGY PRODUCTION — SILVIS LAKE 1.5 1.4 1.3 1.2 1.1 1.0 0.9 90.8 9.7 0.8 0.5 0.4 9.3 0.2 0.1 9.0 1981-1984 AVERAGE {ADJUSTED} Figure 3-3 KWH GENERATED (Millions) MONTHLY ENERGY PRODUCTION — SWAN 1984 (ADJUSTED) 8.0 7.0 6.0 5.0 iB 4.0 3.0 2.0 1.0 9.0 LAKE ¢ = Fut Medes Ce Section 4 FUTURE POWER SUPPLY ALTERNATIVES The various future power supply resource alternatives that were considered during the study are presented in this sec- tion. These alternatives include new hydroelectric and thermal power plants, and transmission interconnections with neighboring utility systems. Figure 4-1 shows the relative locations of these alternatives. THERMAL POWER PLANTS Considering that there presently are no gas pipelines in the immediate vicinity of Ketchikan, natural gas is not a feasi- ble alternative as a power plant fuel for KPU. Coal is also not a feasible alternative, due mainly to the absence of a convenient mode of transporting the coal from the nearest Mines (e.g., in the Fairbanks area) to Ketchikan. It is also likely that there would be environmental problems with siting a coal-fired unit near Ketchikan. In addition, as discussed in Section 6, KPU's capacity requirements during the 20-year study period do not favor large base-load plants. For these reasons, both new natural gas- and coal-fired power plants were excluded from consideration in the study. No. 2 oil (also referred to as "distillate," "diesel oil," or "diesel fuel") is currently used as fuel for KPU's Totem Bight and Bailey diesel units. Given the current conditions in Alaska, it is expected that supplies of diesel fuel will continue to be sufficient to meet the requirements of KPU's existing diesel units. Also, since the completion of the Swan Lake project, KPU has significantly reduced the amount of energy generated by its diesel units. It is therefore reasonable to assume that there will be ample supplies of diesel fuel not only to serve KPU's existing diesel units in the future but also to support additional units if KPU de- cides to install new diesel units in the future. A diesel fuel price forecast for the 1985- to 2004-period was prepared by CH2M HILL in May 1985 for use in this study. The results are summarized in Figure 4-2. Details of the forecast are provided in Appendix A. In light of current economic conditions, the forecast would appear to be con- servatively high. If, however, new diesel-fired generation were selected under this high fuel price forecast, then simi- lar results could be expected with a lower fuel price forecast. The major advantages of diesel-fired generation over other alternatives include: ° Relatively low capital costs 4-2 © SWAN LAKE ( ¢ { na BC HYDRO @ MAHONEY LAKE (at Kitsault) ye QUARTZ HILL Figure 4-1 General Location Map PRICE ($ per galion) $2.40 $2.30 $2.20 $2.10 $2.00 $1.90 $1.80 $1.70 $1.60 $1.50 $1.40 $1.30 $1.20 $1.10 $1.00 $0.90 $0.80 1985 KETCHIKAN 1990 DIESEL FUEL PRICE FORECAST 1995 Figure 4-2 PUBLIC UTILITIES 2000 2005 ° Minimal engineering and design requirements ° Relatively fewer siting problems ° Relatively short construction period and required preconstruction lead time The major disadvantages of diesel generation include rela- tively high fuel costs per kWh compared to hydroelectric energy production, and increased reliance on nonrenewable resources. For this study, cost and operating data for new diesel units were derived from a number of sources. Estimated capital costs were obtained from major equipment suppliers and then adjusted for shipment to and installation in Ketchikan. Fuel and operating and maintenance costs were assumed to be equivalent to those of KPU's existing units at the Bailey plant. Cost assumptions for new diesel units are summarized in Table 4-1. HYDROELECTRIC POWER PLANTS A study of future hydropower resource alternatives in the Ketchikan area was recently performed for KPU by R. W. Beck and Associates. The report, published in April 1986, identi- fied two specific alternative hydroelectric projects avail- able to KPU: the Mahoney Lake Project (10 or 15 MW) and the Lake Grace Project (16 MW). Other potential projects were identified but were not considered viable to KPU because they would mainly benefit the communities of Wrangell and Petersburg. Based on R. W. Beck's initial conclusions and the relative locations of the Mahoney and Grace Lake projects, KPU man- agement instructed CH2M HILL to concentrate the analysis on the Mahoney Lake rather than the Lake Grace project. There- fore, the Lake Grace Project was excluded from further con- sideration in this study. The Mahoney Lake project would be located approximately 8 miles northeast of Ketchikan. Details regarding the Mahoney Lake project were obtained from R.W. Beck. Of the two project alternatives considered by Beck (10 MW and 15 MW configurations), CH2M HILL selected the 10 MW project as Most suitable based on KPU's projected capacity requirements. The average annual energy output of the plant would be about 48,500 MWh. Details of the assumptions used in this study to model the Mahoney Lake project in the computer analyses are summarized in Table 4-1. The primary advantage of the Mahoney Lake project is the relatively low operating cost that is characteristic of most x ees —] le 4-1 FUTURE POWER SUPPLY RESOURCE OPTIONS: DATA AND ASSUMPTIONS Earliest Estimated Capacity Year Cost Resource Type (kW) Available ($ 1985) New diesel generation 2,500 1987 $2,000,000 (a) Mahoney Lake hydro project 10, 000 1989 $40,000,000 (b) Lake Tyee-Swan Lake Intertie NA 1987 $40,000,000 (c) KPU-B.C. Hydro Interconnection NA 1990 $45,000,000 (d) Notes: (a) Estimated at $800 per kW installed. (b) Estimated at $4,000 per kW installed. (c) Estimated at $33.5 million in 1982 dollars by Teshmont Consultants in November, 19824 escalated to 1985 dollars at 6 percent per year to 1985. (d) Estimated at $ 1 million per mile. (e) Assumed to be the same as existing Bailey unit data. (f) Based on current APA estimates for similar hydro projects. (g) Based on 5.55 cents per kWh per Four Dam Pool agreement plus 10 cents per kWh wheeling charge to recover capital cost of transmission line. (h) Assumed. (i) Based on current fuel cost of 64.125 per MBtu and assumed average heat rate of 11,500 Btu per kWh. Fixed O&M Cost (6/kW/year) $40.00 (@) $15.80 (f) $0.00 $0. 00 Variable O&M Cost ($/MWh) $4.66 $0.55 $155.50 $50. 00 fe) (f) (g) (hd) $47.44 $0.00 $0. 00 $0.00 4a) hydroelectric plants. The main disadvantage of the project is the relatively high capital cost, which is estimated at $4,000 per kw. TRANSMISSION INTERCONNECTIONS KPU presently operates its utility system independently, with no interconnections with other electric utilities. Therefore, KPU must provide 100 percent of its own reserve requirements. By interconnecting with a neighboring utility system, KPU could not only reduce its reserve requirements but also take advantage of economy energy exchange opportuni- ties that might become available. Under certain favorable circumstances, KPU could displace diesel generation with lower-cost hydroelectric power generation, thereby reducing the overall cost of power. Two transmission alternatives were evaluated in the study: ° Lake Tyee--Swan Lake 115-kV Interconnection ° KPU-British Columbia Hydro and Power Authority (B.C. Hydro) Interconnection (via Quartz Hill) LAKE TYEE-SWAN LAKE 115-kV_ INTERCONNECTION RR RS = IN a aR 7 t Lake Tyee-Swan_ Lake intertie is a proposed 54-mile 115-kV ansmission line connecting the Swan Lake hydroelectric projects to the Lake Tyee project north of Ketchikan, which are both owned by APA. The transmission line would be built primarily to enable KPU to take advantage of excess energy available from the Lake Tyee project above that which is required to serve the communities of Wrangell and Petersburg. As loads grow in Wrangell and Petersburg, the amount of energy available to KPU would be reduced; however, present projections indicate that there will likely be substantial excess energy available at least through the year 2005. A secondary benefit of the 115-kV transmission line would be to provide additional reserve capacity to Wrangell and Petersburg in the event of an outage of the Lake Tyee project. Since the proposed Lake Tyee-Swan Lake 115-kV line would probably terminate at Swan Lake, development of the intertie would increase the importance of the existing 115-kV trans- mission line from Swan Lake into Ketchikan because the in- tegrity of both the Swan Lake and Lake Tyee projects would be dependent upon that line. For this reason, we investi- gated the possibility of building a second 115-kV line from Swan Lake to Ketchikan along a different route from the ex- isting line. Providing a second 115-kV line between Swan Lake and Ketchikan would provide additional reliability to the KPU system which would help make the proposed Lake Tyee- Swan Lake intertie practical from a reliability standpoint. 7] oo If the Lake Tyee-Swan Lake intertie were built without the second 115-kv line between Swan Lake and Ketchikan, KPU would still need to install additional reserve capacity to prepare for the potential outage of the existing Swan Lake-KPU line. The most likely route for a second 115-kV transmission line between Swan Lake and Ketchikan would be south from Swan Lake along the east bank of Carroll Inlet, crossing both the Carroll and George inlets where convenient, and then ter- minating at Beaver Falls. The estimated cost of the 23-mile transmission line is $23 million in 1985 dollars. Since both the Lake Tyee and Swan Lake projects are owned by APA, it is possible that APA might finance and/or construct the proposed intertie. For the purposes of this study, it was assumed that APA would build the transmission intertie and that the costs associated with the line would be re- covered from KPU through wheeling charges. It was also as- sumed that KPU would finance and construct a second 115-kv transmission line from Swan Lake to Ketchikan. The projected cost of power from Lake Tyee can be broken down into three components: (1) the cost of power directly from the plant; (2) the cost of wheeling from Lake Tyee to Swan Lake; and (3) the carrying costs of the second 115-kvV transmission line from Swan Lake to Ketchikan. The cost of power directly from the Lake Tyee project was based on pro- jections made part of the Four Dam Pool agreement, which establishes the cost of power from both the Swan Lake and Lake Tyee projects. The assumed wheeling cost associated with the proposed intertie was based on the total projected capital cost of the intertie divided by the estimated total number of kWh that would flow through the line over a 30-year period. The estimated carrying costs of the second trans- mission line to Ketchikan were based on an assumed levelized debt service cost representing the amortized estimated capi- tal cost of the line. Assumptions regarding the Lake Tyee-Swan Lake intertie are summarized in Table 4-1. KPU-B.C. HYDRO INTERCONNECTION In 1974, the U.S. Borax Corporation announced the possibility of its developing the Quartz Hill molybdenum project. Quartz Hill is located approximately 45 miles east of Ketchikan, and approximately 26 miles west of the Canadian border. KPU has already considered the possibility of providing electric service to Quartz Hill. It has been assumed that, initially, the project's electric power needs would be met with power generated by B.C. Hydro. In the long term, power might be provided from a number of sources, including B.C. Hydro, the Bonneville Power Administration, APA hydroelectric power resources, KPU and/or other sources. To date, no firm com- mitments have been made by U.S. Borax. For the purposes of this study, it was assumed that B.C. Hydro would provide power to serve the Quartz Hill mine, with U.S. Borax providing onsite diesel generation for backup and reserves. It was also assumed that U.S. Borax would bear the cost of the required transmission line from the B.C. Hydro transmission system (at Kitsault) to the mine facility. Therefore, KPU would bear no share of the cost of providing service to the Quartz Hill mine operation. Addi- tional energy requirements in Ketchikan resulting from the Quartz Hill personnel living in or near Ketchikan has already been considered in the load forecast and included in the "Electric System Planning Study," published in April 1986. If the transmission line from Kitsault to Quartz Hill is built, KPU would be in a position to consider constructing a line from Ketchikan to Quartz Hill. This would enable KPU to purchase power directly from B.C. Hydro. The estimated cost of this transmission line is $45 million (1985 dollars). KPU may also want to explore the possibility of having APA finance and construct the line. Assumptions regarding the KPU-B.C. Hydro transmission inter- connection are summarized in Table 4-1. 4-8 yong i The Power Supply Planning Computer Mo Section 5 THE POWER SUPPLY PLANNING COMPUTER MODEL This study was conducted using the Westinghouse Electric Corporation's Automated Generation Planning (AGP) computer model. In past projects for other utilities, CH2M HILL has evaluated a number of commercially available generation plan- ning programs. On the basis of availability, flexibility, user-friendliness, documentation, technical considerations, and cost, the AGP model was selected for general use by CH2M HILL in power supply planning studies. DESCRIPTION OF THE WESTINGHOUSE AGP MODEL AGP is an interactive computer program designed to aid in power supply planning by determining an optimal system ex- pansion plan. AGP is well documented and has been used in the industry for many years. AGP consists of basic program modules that handle input, output, simulation, and the optimization procedure. The program structure is shown in Figure 5-1. INPUT MODULE The input data requirements for the AGP program are or- ganized into the following categories: General Program Data Economic Data Reliability Constraints Existing Unit Data ° Unit Addition Data Load Data Unit Installation Constraints Fuel Data and Mix Constraints Installation Schedule (for simulation runs) o0o0000000 General program data include report titles, study years, and certain program delimiters used to control program operation. Economic data include the discount rate used in present-worth calculations and fuel and operation and maintenance cost escalation rates. There are two system reliability constraints that must be satisfied by the expansion plan: (1) the minimum generation reserve margin and (2) the maximum amount of unserved energy (the amount of energy that can be purchased from outside the system in the event of a capacity deficiency within the sys- tem or, for KPU, the approximate cost of a capacity shortage per kWh). 5=5 Reliability Module Economic Data Unit Data Load Data Input Module Optimization Simulation Production Costing Module Optimization Module Report Generator Installation Schedule and Costs Figure 5-1 AUTOMATED GENERATION PLANNING (AGP) COMPUTER PROGRAM STRUCTURE mel « Existing unit data include unit operating capacities, forced and scheduled outage rates, average annual heat rates, fuel types, and fixed and variable operation and maintenance costs. The same data are required for unit addition types from which the optimization module selects. The capital cost pertaining to new unit types is also required. Note that the capital costs of existing units are considered to be "sunk" costs and are therefore not considered in this analysis. Required load data include monthly load duration curves, forecast annual peak demands, and forecast annual system energy requirements. The load duration curves may be input directly or derived by AGP from historical hourly load statistics. r AGP allows the user to set the minimum and/or maximum number of additions of a given type of unit in any given year. This is used to force the addition of committed units or to restrict the number of units that AGP can select for con- struction during the year. Fuel data and mix constraints include fuel costs and rela- tive heat content statistics, as well as any constraints on the installed capacity of units that use a given fuel type. This can be useful in simulating contract fuel limitations. For sensitivity runs, where the user preselects an expansion plan to be simulated by AGP, an installation schedule can be input to represent the timing of planned unit additions dur- ing the study year. BRANCH-AND-BOUND MODULE This module is the heart of the AGP program. The function of the branch-and-bound module is to evaluate potential ex- pansion plans and to select the expansion plan with the least cost that serves the load and does not violate any of the reliability or fuel constraints. The branch-and-bound search method used in AGP considers the cost of a given expansion plan in relation to the cost of the best (least-cost) expansion plan previously found. AGP first computes the cost of a "baseline" expansion plan over the study period. Next, the program examines the costs of alternative expansion plans that also meet the system con- straints. If, at any point, the cost of the alternative plan exceeds the cost of the baseline plan, further analysis of the alternative is abandoned. If, however, the alterna- tive is found to be of lower cost over the study period, the alternative then becomes the baseline used in the evaluation 5-3 of other alternatives. This technique minimizes the compu- tations necessary to derive an optimal solution to the gen- eration planning problem. AGP uses a "rolling horizon" technique for optimization. The look-ahead period is the optimization window, which moves ahead in each year of the study. Longer look-ahead periods avoid short-term optimum decisions, but usually produce more capital-intensive plans. This usually occurs if long-term savings in fuel costs are greater than in- creases in capital costs. PRODUCTION COSTING MODULE The production costing module operates during the optimiza- tion or simulation modes. In the optimization mode, it works as a support routine to the branch-and-bound module to calcu- late the operating costs of a given expansion plan. In the simulation mode, it operates as a stand-alone routine. The user has a choice of two production costing methods. The first method is a deterministic method that accounts for forced outage rates by derating the unit capacities. Thus, a unit with a 20-percent forced outage rate would be modeled as being available 100 percent of the time at 80 percent of its rated capacity. The second method is a probabilistic method that uses a set of modified load duration curves, altered statistically to account for the effects of unit-forced outages. The proba- bilistic method generally is preferred because it accounts for all possible combinations of units that may be unavail- able at any given point because of forced outages. RELIABILITY MODULE The reliability module computes the annual percent reserve and unserved energy of each expansion plan, and feeds this information to the branch-and-bound module. Plans that vio- late the reliability constraints are identified and rejected in this module. OUTPUT MODULE The output module sends the reports to the user's terminal, printer, or both. ON 6. = oO Wu oD. i— Section 6 EVALUATION OF SPECIFIC ALTERNATIVES As discussed in Section 3, the primary power supply alterna- tives that were considered during the study were: New diesel-fired generation Mahoney Lake hydroelectric project Lake Tyee-Swan Lake Intertie KPU-B.C. Hydro interconnection oooo The basic assumptions and criteria used in evaluating these alternatives and the results of the evaluation are discussed in this section. POWER SUPPLY PLANNING CRITERIA The primary criteria that govern the selection of new capac- ity additions for a utility system are: ie The need to have sufficient resources to meet pro- jected annual system peak demands and energy re- quirements in each year of the planning period. This is the SYSTEM REQUIREMENT constraint. 2. The need to have sufficient reserve capacity avail- able to provide for planned and unplanned gener- ating unit outages as well as variations in actual loads from projected loads. This is the RELI- ABILITY constraint. 3. The desire to minimize the total present worth of all expenditures for power supply during the plan- ning period, including fixed and variable operation and maintenance costs, fuel costs, wheeling and purchased power costs, and new unit capital costs. This is the COST MINIMIZATION constraint. The System Requirement constraint is dictated by the load forecast. The load forecast used in this study was prepared by CH2M HILL in August 1984. This forecast considered the peak demand and energy requirements of the KPU system with and without the development of the Quartz Hill project. The "base" forecast used in this study assumes that KPU will provide power to additional households because of Quartz Hill but that the mine operations would either purchase power from B.C. Hydro or generate power onsite. Separate analyses were conducted to determine the sensitivity of results of the study to the load and energy forecasts. 6-1 Most generating utilities attempt to maintain generation reserves so that their projected peak demand can be met in the event of an equipment failure that takes out of service the utility's largest single generating source. The Reli- ability constraint used in this study assumes that KPU will plan to maintain generating reserves equal to at least the capacity of its largest "single contingency." For many util- ities, the largest "single contingency" refers to the largest single generating unit. However, for KPU, the largest "single contingency" is the 115-kV transmission line between Ketchikan and to Swan Lake that carries up to 22.5 MW of capacity from the Swan Lake project. The Cost Minimization criterion is applied in all analyses, and takes into account all of the present power supply costs, assumed inflation and price escalation rates, and the proj- ected costs of alternative power supply resources. All of these criteria are considered by the Westinghouse AGP computer program, as described in Section 5. A summary of these criteria and other factors is provided below. BASIC ASSUMPTIONS ° 20-year study period (1985 through 2004 ° Use of probabilistic production costing method (described in Section 5) ° Minimum capacity reserve requirement equal to 22.5 MW (largest single contingency) ° No planned retirement of existing units during the study period ° Maximum of 2 percent unserved energy in any given year ECONOMIC ASSUMPTIONS The following basic economic assumptions were employed in the study: ° 10 percent annual discount rate ° 4 percent general inflation rate ° Cost per kWh of Swan Lake power (and power from Lake Tyee before wheeling) based on projections included in the Four Dam Pool agreement 6-2 ee — — pe ee ae LOAD DATA Load duration curves used in the AGP program were derived from historical load shapes. The projected annual peak de- mands and energy requirements were obtained from the load forecast described in Section 2 and represent the case with Quartz Hill (commute option). ECONOMIC ANALYSES BASE CASE: NEW DIESEL GENERATION As noted above, the baseline load forecast including Quartz Hill was selected for the "base case" in the study. For comparison purposes, sensitivity cases were run using high- and low-load forecasts; the "low" forecast represents the forecast without Quartz Hill. The base case also did not consider the construction of a second 115-kV transmission line from Swan Lake to the KPU system. Since the Lake Tyee- Swan Lake intertie would be dependent upon this second 115-kv line, as noted in Section 4, Lake Tyee was not considered as a resource option in the base case analysis, but was evalu- ated in a separate analysis. The initial AGP computer runs were made using resource op- tions in 1.0-MW increments. The objective of this first phase was to determine the optimal power supply expansion plan when the model was not constrained by whole unit sizes. In the second phase of the analysis, the optimal plan was refined to consider the actual size units that would likely be installed. The first AGP computer run considered new diesel generation, Mahoney Lake, and B.C. Hydro as resource options. The re- sults of the initial AGP run were: ° 1-MW of new diesel generation was selected in each of the following years: 1989, 1990, 1991, 1993, 1995, 1996, 1998, 1999, 2001 and 2003 (a total of 10 MW) ° 1-MW of B.C. Hydro capacity was selected in the year 2004 ° No capacity from Mahoney Lake was selected ° The total net present worth of power supply costs (in 1985 dollars) amounted to $87.5 million. However, the cost of a transmission line from KPU to Quartz Hill, which would be required in order for KPU to take ad- vantage of B.C. Hydro power, was not included in the input data for the B.C. Hydro option. The reason that this cost was excluded was to prevent the model from being biased against B.C. Hydro as an alternative, since the per-unit cost of the transmission line is extremely high. Not in- cluding the capital cost of the line allows the option to be considered on the basis of the energy cost savings that it would provide. However, the cost of the transmission line must be added to the total present worth of power supply costs to obtain a true cost for comparison with other alternatives. The $45 million capital cost for the transmission line, es- calated at 4 percent per year to 2004, then amortized at 10 percent over 30 years, yields a $4.8 million annual car- rying cost (in 2004 dollars). Brought back to 1985 dollars at a 10 percent discount rate, this amounts to about $1.6 million annually. Therefore, the total cost of this option, in 1985 dollars, would be $89.1 million. A second case was run, forcing in 1 MW of new diesel in 2004 to replace the 1 MW of B.C. Hydro capacity selected by AGP. The results of this case were $87.5 million, nearly identical to the previous case. However, since no Ketchikan-Quartz Hill transmission line would be required, the all-diesel case represents a savings of $1.6 million over the case in- volving B.C. Hydro capacity in 2004. This second case was then deemed to be the "base case." Results of the base case analysis are summarized in Table 6-1 and Figure 6-1; details of the analysis are provided in Appendix B. MAHONEY LAKE The Mahoney Lake hydroelectric project was not selected in any of the AGP runs. The reason for this stems from the fact that KPU has sufficient generating capability to meet both its energy and peak demand requirements from existing resources. It is only because of the reliability constraint, which requires that KPU provide sufficient generating re- serves to meet the peak load requirements in the event of an outage equal to the largest single contingency (the loss of the Swan Lake-KPU 115-kV transmission line), that KPU must plan to add to capacity within the 20-year planning period. This situation is illustrated in Figure 6-2. The uppermost horizontal line in the figure represents the total installed capacity of KPU's existing generating units, including Swan Lake. The middle horizontal line represents the available capacity when a reserve requirement equal to the largest generating unit is considered. The lowest horizontal line represents the capacity available to meet peak when the eee —_—- — eo s-9 YEAR 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2003 2004 2005 FIXED SCvUUNMNWUVNFUWwW WWM R ee eee id 3.5 3.8 3.9 4.3 44 4.8 5.2 costs ¢ IN MILLIONS OF DOLLARS CURRENT YEAR DOLLARS ------------ eee nnn new en ene VARIABLE PURCHASE TOTAL FIXED 4.2 0.0 5.5 1.3 4.4 0.0 5.7 1.2 4.8 0.0 6.1 11 5.3 0.0 6.7 14 6.2 0.0 7.8 1a 6.8 0.0 6.8 1.2 7A 0.0 9.3 1.2 7.5 0.0 9.7 ree y 7.8 0.0 10.3 1.2 8.1 0.0 10.7 tad 6.5 0.0 11.3 1.1 8.9 0.0 12.0 11 9.3 0.0 12.5 1.0 9.7 0.0 13.2 1.0 10.2 0.0 14.1 1.0 10.8 0.0 14.7 0.9 11.3 0.0 15.6 0.9 11.9 0.0 16.3 0.9 12.6 0.0 17.4 0.9 13.3 0.0 18.5 0.8 i tn aaoy iain —_—_ Table 6-1 RESULTS OF BASE CASE AGP COMPUTER RUN DIESEL ei.1 ) 1985 DOLLARS VARIABLE PURCHASE 4.2 0.0 4.0 0.0 3.9 0.0 4.0 0.0 4.2 0.0 4.3 0.0 4.0 0.0 3.8 0.0 3.6 0.0 3.4 0.0 3.3 0.0 3.1 0.0 3.0 0.0 2.8 0.0 2.7 0.0 2.6 0.0 2.5 0.0 2.4 0.0 2.3 0.0 2.2 0.0 66.2 0.0 TOTAL 5.5 5.2 5.1 5.0 5.3 5.5 5.3 5.0 4.8 4.5 4.4 4.2 4.0 3.8 3.7 3.5 3.4 3.2 3.1 9-9 PEAK GENERATING CAPABILITY (MW) CASE 1: BASE CASE EXPANSION PLAN {ALL DIESEL) Peak Capability Less Reserves ie Projected Peak Demand (Base forecast ) 1985 1990 1995 2000 2005 PEAK GENERATING CAPABILITY (MW) PROJECTED LOADS VS. EXISTING RESOURCES ALTERNATIVE RESERVE REQUIREMENTS 50 48 Existing Capacity Resources - No Reserve Requirement 46 44 42 40 38 Existing Capacity Resources - Reserves Based on Largest Génerating Unit Out Of Service (11.25 MW at Swan Lake 36 34 52 Projected Peak Demand (Base Forecast ) 30 28 26 Existing Capacity Resources - Reserves Based on Swan Lake - 24 Ketchikan 115-kV Transmission Line Out of Service (22.5 MW at Swan Lake) 22 2G 1985 1990 1995 20090 2005 YEAR Figure 6-2 reserve requirement is set equal to the largest single contingency on the system, in this case the Swan Lake- Ketchikan 115-kV transmission line. As the figure shows, new capacity is only required under the largest “single contingency" reserve criterion case, in which KPU must provide sufficient generation to meet its peak loads during periods when the 115 kV transmission line between Ketchikan and Swan Lake is out of service. The new capacity that is required in this case is solely required to meet reserve requirements. Under these circumstances, the most economical expansion plan would consist entirely of capacity additions with the lowest installed cost per kW; the effi- ciency and running costs of the units become less important than if the units are needed for base-load supply. If a hydro unit, such as Mahoney Lake, were built, it is likely that the unit would be dispatched with the energy produced to displace energy from some other sources. How- ever, the energy displaced by the hydro unit would likely be relatively small, particularly in early years when Swan Lake is able to provide virtually all of KPU's energy require- ments. As noted in Section 3, KPU's agreement with APA states that KPU will take power from Swan Lake to the extent that its requirements exceed the energy produced from KPU's own hydro units. The energy cost savings due to the Mahoney Lake project would therefore not be great enough to offset the significant capital cost of the hydro unit (approximately $4,000 per kW). A separate AGP computer run (Case 2) was made assuming that a 10-MW Mahoney Lake project would be built in 1989. The total present worth cost for this case amounted to $112.4 million, representing a 28.5 percent increase over the base case. The Mahoney Lake project was, however, dispatched by the model at roughly a 30 to 40 percent capacity factor. The running (variable) costs of power are therefore lower in this case than in the base case, but, as the results indi- cate, not by an amount sufficient to offset the much larger fixed (capital) costs associated with the project. Details of this case are summarized in Figure 6-3. LAKE TYEE-SWAN LAKE INTERTIE When the second 115-kV transmission line from Swan Lake to KPU is considered, KPU's capacity reserve requirement drops from 22.5 MW to 11.25 MW, representing either of the two units at Swan Lake, since one unit then would become the largest "Single contingency" on the system. In such a case, no new capacity would be required to meet the baseline load forecast plus reserve requirements. Therefore, the Lake Tyee-Swan Lake intertie would not appear to be an economic ee et —_— oe ee PEAK GENERATING CAPABILITY (MW) CASE 3: 37 36 35 34 33 32 31 30 29 28 27 26 25 24 23 22 1 20 1985 MAHONEY LAKE EXPANSION PLAN (10 MW PROJECT) Peak Capability Less Reserves \ Projected Peak Demand (Base Forecast ) 1990 1995 2000 2005 alternative to KPU unless the cost of the intertie were en- tirely borne by APA. In this case, the energy cost savings from displacing KPU generation with Lake Tyee power might offset the annual costs of the second transmission line. If APA were to propose such an arrangement, it would be prudent for KPU to evaluate the intertie at that time. Input data pertaining to the Lake Tyee-Swan Lake Intertie were entered into AGP in Case 3. biasing the re-_ sults against the intertie, the ad cost of the second 115-kV Swan Lake-Ketchikan transmission line were not in- cluded. The results of this case were identical to the base case; however, to account for the cost of the second 115-kv transmission line, the total cost from AGP was increased by $16.8 million (representing the cumulative present worth of a stream of annual debt service payments on the transmission line over the 16 years from 1989 through 2004). This brought the total for Case 2 to $104.3 million, or 19.2 percent higher than the base case results. LOAD GROWTH SENSITIVITY As shown in Figure 6-4, using the base load forecast and the largest "single contingency" capacity reserve criterion, as discussed above, the first year in which KPU would require new capacity additions would be 1989. A "high load growth" load forecast was derived for use in the study by adding 50 percent to the annual load growth figures from the baseline forecast. Under this high load growth scenario (Case 4), the first year requiring new capacity is 1988. Under the "low load growth" scenario (Case 5), which represents the baseline forecast without Quartz Hill, new capacity is not required until 1996. In all of the load growth sensitivity cases, new diesel-fired generation was selected as the preferred alternative. In the high load growth scenario, a total of 19 MW was selected; in the low load growth scenario, only 5 MW was selected. Results of the load growth sensitivity cases are summarized in Figures 6-5 and 6-6. Figure 6-7 presents a summary of results for the three major cases examined. Figure 6-8 is a summary of the results of the load growth sensitivity runs. 6-10 ALTERNATIVE LOAD GROWTH SCENARIOS Case 4 High Load Growth (With Quartz Hill)— Base Case (With Quartz Hill)—- Case 5 Low Load Growth (Without Quartz Hill) TT-9 PEAK DEMAND (MW) Peak Capability Net of Reserves 1985 : 1990 1995 2000 2005 YEAR Figure 6-4 Cr=9 PEAK GENERATING CAPABILITY (MW) CASE 4: HIGH LOAD GROWTH EXPANSION PLAN Peak Capability Less Reserves “Projected Peak Demand (Base Forecast ) 1985 1990 1995 2000 2005 et-9 PEAK GENERATING CAPABILITY (MW) CASE 5: 31 30 29 28 27 28 25 24 23 22 21 20 1985 Peak Capability Less Reserves 1990 1995 YEAR Figure 6-6 LOW LOAD GROWTH EXPANSION Load Forecast Projected Peak Demand (Base Forecast ) 2000 PLAIN WT x 525 ROSKE S525 RERRELE SS Sv SS SS SS CASE S— INTERTIE CASE 2-MAHONEY LAKE [XS] TRANSMISSION COST OF POWER SUPPLY 1985 -— 2004 RQQQVQVnnn Ss SAV’ RSS yg g{|gj_'_'@'’'ji°oXoanu WX W RVsv WV (SBE) $) 1SQQ Two 6-14 BASE CASE-DIESEL SOQ SS SI SS \ INS XQ“ RV“~““w VK XS a oN ON N ~ W XQ @w“ SN QQAWN LQ \ ADRpECC CC SQ AAA WN N DBRi'E_OO—>?°'C™WN WSN RA RSSVqgq°“ SS $“0“w 'DMC6CEG{ COST OF POWER SUPPLY 198S — 2004 IQ AQ@q SS Qi Rw RSV GG << << AWN WW \\ RQ RX“ 120 19 1 (SBE)l $) 1500 TYLOL 6-15 I. CGGQ WS Qs WN CX << NS pee pane CASE S~-LOMW GROWTH CASE 4—-HIGH GROWTH BASE GASE-DIESEL PX] TRANSMISSION Figure 6-8 ions. Section 7 POWER SUPPLY STRATEGY AND CONCLUSIONS The development of a sound long-range power supply strategy requires the following: ° A reasonable projection of future loads and energy requirements ° Unit production costs for existing facilities ° A knowledge of system load characteristics ° An identification of future resource alternatives ° Projections of future resource costs and availability ° A methodology for evaluating alternatives During the study, the October 1985 load forecast prepared by CH2M HILL was adopted by KPU management as a reasonable pro- jection of future requirements and was subsequently used as input data to the AGP program. Therefore, all alternatives considered in the study were evaluated on the basis of their ability to satisfy the load forecast plus reserve require- ments. However, since there is a certain amount of uncer- tainty inherent in any load forecast, it is appropriate to test the sensitivity of results to various levels of pro- jected demand. Load growth sensitivity is discussed in Section 6. The unit production costs for existing KPU power generation facilities (including Swan Lake), as provided by KPU, were also entered into the AGP data base. Hourly system load characteristics, obtained from KPU's historical records, were considered to be representative of future load charac- teristics, and were therefore entered into the model for use in the derivation of monthly load duration curves. The identification of future resource alternatives is dis- cussed in Section 4. In order to minimize the computation time required for AGP to evaluate a large number of possible combinations of future resource alternatives, these alterna- tives were first analyzed for applicability to the KPU situ- ation. Those alternatives meeting the applicability criteria in the initial screening analysis were then used in the final power supply analyses. Projections of the future costs of various resources, in- cluding capital, fuel, and operating costs, were developed. The diesel fuel price forecast, as described in Section 2, is provided in Appendix A. The projected costs associated with future resource options are described in Section 3. Other assumptions, including the general inflation rate that was applied to non-fuel costs, are described in Section 5. Conclusions Based on our analysis, we conclude that: ° KPU will need to install additional capacity during the 20-year study period in order to meet projected peak demand requirement during periods when the Swan Lake Ketchikan 115-kV transmission line is out of service (or both units at Swan Lake are concurrently out of service). ° The most cost-effective method of providing this required additional reserve capacity, under present economic conditions, will be through the staged installation of approximately 12 to 15 MW of diesel-fired generation. ° If APA (or others) develop alternative resources (such as the Mahoney Lake or Lake Grace hydroelec- tric projects, or the proposed Lake Tyee-Swan Lake 115 kV transmission line), KPU should reevaluate its long-range power supply plan on the basis of the costs of available options at that time. Additional diesel-fired generation should be installed in unit sizes that are cost-effective while meeting the util- ity's requirements for reserve capacity. A suggested schedule is to add 2.5 MW diesel units approximately every 4 years, beginning in 1989. The suggested staged approach to adding new diesel genera- tion is flexible, providing KPU with the opportunity to con- tinually review and modify its plans while still meeting load and reserve requirements and minimizing the overall cost to KPU and its ratepayers. It is probable that the actual load growth for KPU will fall somewhere between the "high" and "low" load forecasts. It is, however, prudent for KPU to plan to meet the high load growth forecast. KPU should therefore proceed with the necessary permit applications and design work required to have a new unit on-line by the winter of 1988-1989. If, as that time approaches, it becomes evident that loads will not grow as fast as the high-load forecast, then KPU should defer the installation of the new unit addition consistent with the latest available estimate of projected loads. In this manner, KPU will be prepared for the eventual need for new capacity, but will not bear the costs of the new capacity before it is required. Given the fact that new diesel units will be needed for standby only, KPU may also wish to investigate the cost and availability of used diesel units. Although the cost analy- sis used in this study have assumed that new capacity addi- tions are, in fact, new, there are substantial cost savings that could be obtained from the purchase of used or recondi- tioned units. 3 el CHMHILL MEMORANDUM TO: Bob Brooks/SEA FROM: Lloyd Pernela/ANC RE: Ketchikan Fuel Price PROJECT: K18200.CO 1. Data Set January 1982 to present MON = month Jan 81 = 1 when shipment occured Jan 82 = 13 etc. DSL$ = delivered price for diesel at that shipment ($/gal.) BBL = $ per BBL diesel OILT = current month's marker crude “ORIENTE" Ave Spot Price $/B [from Platt's] OIL1 ORIENTE $/BBL previous month OIL2 ORIENTE $/BBL at 2nd previous month OILAV Average [oil 1, oil 2] Dropped Jan 81 - Dec. 81 data because the phase out of oil controls had not stabilized the relationship of crude oil prices. ORIENTE (EQUADOR) is what Alaska Department of Revenue uses as marker crude (they no longer use Saudi light/medium). They forecast ORIENTE, then equate this through quality differentials to ANB and deduct transportation to North Slope for revenues. Calibrating model to ORIENTE is representative and we have DR's forecast. Correlation is strongest between OIL2 and BBL which makes sense because of storage and lag of market in reacting to crude price changes. Best model was only with crude (+/-2), OIL2,Ketchikan price = 6.0632 + 1.1564 OIL 2 R= .9046 Second best model included time (months) but was not used because was negative coefficient on months which merely indicates shrinking refinery margins. Error distribution was skewed and it only increased R™ by .0274 R™=.9196 Price Ketchikan = 17.144 + .8691 OIL2 - .0977 Mon Memorandum Bob Brooka Page 2 K18200.CcO Selected model's interpretation is Ketchikan price is constant $6.06 above a 15% markup over crude costs two months ago. Given transportation time, inventory costs, this is reasonable. Various graphs of error, data are positive (in support model). FOR is $/BBL estimate from model ERR is deviation (or FOR-BBL) OIL2 has dropped overtime BBL has dropped over time OIL2 vs. BBL indicates trend ERR vs. months shows good spread ERR vs. BBL shows good spread 2. Forecast Using DR's Oriente through constructed forecast attached DR forecasts to State FY starting July 1 8 months FY (current) + 4 months future FY Calculation assumes the DR forecast constant over each FY month to get calendar year average. Plots show dip in market crude and corresponding dip in diesel price delivered to Ketchikan. Model assumes that transportation and distributor markups will remain in constant ratio to crude price. CYEAR = Calender Year CRUDE = Average over year (CY), $/B ST= Diesel Ket $/B GASS = Diesel $/gal STP-V5 WMU OBS > eo n ou 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 MON 13.00000 14.00000 15.00000 16.00000 17.00000 19.00000 20.00000 21.00000 22.00000 23.00000 24.00000 25.00000 26.00000 27.00000 28.00000 29.00000 30.00000 31.00000 32.00000 33.00000 34.00000 35.00000 36.00000 37.00000 38.00000 49.00000 VAR KETCHIKAN DIESEL PRICE MODEL DSL$ 1.088000 1.088000 1.082000 1.030000 0.9600000 0.9910000 0.9810000 0.9870000 0.9920000 1.022000 1.032000 1.032000 0.9730000 0.9180000 0.9080000 0.8730000 0.8880000 0.8930000 0.8830000 0.9030000 0.9130000 0.9030000 0.9030000 0.8800000 0.8420000 0.8990000 BBL 45.69600 45.69600 45.44400 43.26000 40.32000 41.62200 41.20200 41.45400 41.66400 42.92400 43.34400 43.34400 40.86600 38.55600 38.13600 36.66600 37.29600 37.50600 37 .08600 37.92600 38.34600 37.92600 37.92600 36.96000 35.36400 37.75800 OILT 33.16000 30.13000 28.88000 29.40000 32.95000 32.10000 30.19000 31.50000 31.64000 30.35000 29.00000 29.00000 ,28.00000 25.70000 26.94000 27.25000 27.25000 27.62000 28.50000 28.20000 27.80000 27.68000 26.78000 27.00000 27.49000 25.18000 OIL 33.30000 33.16000 30.13000 28.88000 29.40000 32.81000 32.10000 30. 19000 31.50000 31.64000 30.35000 29.00000 29.00000 28.00000 25.70000 26.94000 27.25000 27.25000 27.62000 28.50000 28.20000 27.80000 27.68000 26.78000 27,00000 26.38000 OIL2 33.30000 33.30000 33. 16000 30.13000 28.88000 32.95000 32.81000 32.10000 30.19000 31.50000 31.64000 30.35000 29.00000 29.00000 28.00000 25.70000 26.94000 27.25000 27.25000 27.62000 28.50000 28.20000 27.80000 27.68000 26.78000 26.70000 OILAV 33.30000 33.23000 31.64500 29.50500 29.14000 32.88000 32.45500 31.14500 30.84500 31.57000 30.99500 29.67500 29.00000 28.50000 26.85000 26.32000 27.09500 27.25000 27.43500 28.06000 28.35000 28.00000 27.74000 27.23000 26.89000 26.54000 PAGE 1 STP-V4 VAR. MON OSL$ OILT OIL OIL2 OILAV BBL W.M.U, **¢#* CORRELATION MATRIX ###¢*% 1.0000 -0.8266 -0.7821 -0.7750 -0.8051 -0.8105 -0.8266 MON — 9-May-85 1.0000 0.6542 0.8203 0.9047 0.8859 1.0000 OSL$ 1.0000 0.8185 0.7057 0.7787 0.6542 OILT REDUCED KETCHIKAN DATA 1.0000 0.9034 0.9734 0.8203 OIL1 1.0000 0.9776 0.9047 OIL2 —— 1.0000 0.8859 OILAV JAN82 THRU PRESENT 1.0000 BBL CORR —_—_—_ ——s — oss PAGE STP-V4 W.M.U, 9-May-85 KETCHIKAN DIESEL PRICE MODEL *¢e** STEPWISE REGRESSION **#** 2 VARIABLES; VARIABLE: BBL IS DEPENDENT STANDARD ERROR OF Y = 3.067706 STEP NO. 1 ENTERING VARIABLE: OIL2 F-LEVEL 108.1586 WITH PROB. 0.0000 STANDARD ERROR OF ESTIMATE 1.334246 COEFFICIENT OF DETERMINATION = 0.8184001 COEFFICIENT OF MULTIPLE REGRESSION = 0.9046547 INCREASE IN COEFFICIENT OF DETERMINATION = 0.8184001 CONSTANT 6.0632 STD.ERR. STANDARDIZED VARIABLE COEFF. OF COEFF. COEFFICIENT T-VALUE OIL2 1.156 0.1112 0.9046547 10.40 PROB. 0.000 STEPR PAGE STP-V5 WMU OBS ooo op NO FGF FF WOW N 13 14 15 16 7 18 19 20 21 22 23 24 25 26 VAR MON 13.00000 14.00000 15.00000 1600000 17.00000 1900000 20.00000 21.00000 22.00000 23.00000 24.00000 25.00000 26.00000 27.00000 28.00000 29.00000 30.00000 31.00000 32.00000 33.00000 34.00000 35 .00000 36.00000 37.00000 38 .00000 4900000 coo KETCHIKAN DIESEL PRICE MODEL BBL 45.69600 45.69600 45.44400 43.26000 40.32000 41.62200 41.20200 41.45400 41.66400 42.92400 43.34400 43.34400 40.86600 38.55600 38.13600 36.66600 37.29600 37.50600 37.08600 37.92600 38.34600 37.92600 37.92600 36.96000 35.36400 37.75800 FOR 44.55800 44.55800 44.39616 40.89348 39.44848 44.15340 43.99156 43.17080 40.96284 42.47720 42.63904 41.14780 39.58720 39.58720 38.43120 35.77240 37.20584 37.56420 37.56420 37.99192 39.00920 38.66240 38.20000 38.06128 37.02088 36.92840 ERR -1.138000 -1.138000 -1.047840 -2.366520 -0.8715200 2.531400 2.789560 1.716800 -0.7011600 -0.4467998 -0.7049599 -2.196200 -1.278800 1.031200 0.2951999 -0.8935995 -0.9015989E-01 -5820036E-01 4782004 0 0 0.6591988E-01 0.6631999 0.7364001 0.2739997 1.101280 1.656880 -0.8295999 PAGE STP-V4 — W.M.U. 9-May-85 PLOT OF VARIABLE: BBL 1--------- Hoecnnnnn- toonenn--- 4o-------- Hoon c nn - onan n--- teen nnn = Hen------- Honnnn nnn tonne nnn +--------- + 44. 43. 42. 42. 41 40. 39. 38. 38. 37. 36. 35. 56 76 96 36 56 76 36 76 Pe ee me ee ee me ee ee eee ee ee (HORIZ.) VS VARIABLE: FOR KETCHIKAN DIESEL PRICE MODEL (VERT. ) 1 2 PAGE 2 STP-V4 W.M.U. 9-May-85 KETCHIKAN DIESEL PRICE MODEL PLOT PAGE 3 VS VARIABLE: ERR (VERT. ) PLOT OF VARIABLE: FOR (HORTZ.) sss 2.790 + 1 I I I 1 2.390 + I I I 1.990 + I I I 1 1 ' 1.590 + I I I 1.190 + I 1 I 1 I 0.7896 + I et I I 1 0.3896 + I 1 I I Tt -0.1044E-01 + I 1 I I -0.4104 + 1 I I I 1 1 -0.8104 + 1 11 1 I 1 I 2 -1.210 + I 1 I I -1.610 + I I I -2.010 + I I 1 I -2.410 + 1 Jernreen--- Poeeecoooeece= Poooocooe== Porereooooe= Poroecceooe= qoeeeerooee Grasmere Goeeceooroee= Porcacnese= + 35.67 37.67 39.67 41.67 43.67 36.67 38.67 40.67 42.67 44.67 STP-V4 W.M.U, 9-May-85 KETCHIKAN DIESEL PRICE MODEL PLOT PAGE 4 PLOT OF VARIABLE: BBL (HORIZ.) VS VARIABLE: ERR (VERT.) Ieeeere---= Pposeanonre Pownanoooe= pocseooone Nps werent Pomme eee= fone eoe: Poeeeooooe= Poensowee=s 1p ernnecoe=: Poeocooooe= + 2.790 ¥ 1 I I I 1 2.390 * I I I 1.990 - I Z 11 1 1.590 + I I I 1.190 ee I 1 I 1 I 0.7896 2 I 1 1 I I 1 0.3896 < I 1 I I 1 1 . -0.1044E-01 + Z 1 I I -0.4104 + 1 I I I 1 1 -0.8104 + 1 I 1 1 I 1 x 2 -1.210 - 1 1 I I -1.610 + I I I -2.010 * I I 1 I -2.410 + I 36.26 , 38.26 40.26 42.26 , 44.26 46.26 STP-V4 W.M.U. 9-May-85 KETCHIKAN DIESEL PRICE MODEL PLOT PAGE 5 PLOT OF VARIABLE: MON (HORIZ.) VS VARIABLE: FOR (VERT.) I--------- tonne tenon nn--- Hoenn n- aman naan +--------- teonnnn--- tonne nn-- tonearm n--- teonnnno-- + 44.56 eee I 1 I 1 I 1 43.76 + I I I 1 42.96 + I I ie I 42.16 + I I I 41.36 + I 1 I 1 1 I 40.56 + i iz 1 39.76 + I ein I 1 1 38.96 = 1 I 1 I I 1 38.16 = vit I 1 1 1 ia 37.36 + I 1 I 1 1 I 36.56 + I I I 35.76 1 Toeoceoeeeoree tone n---- Poeeooooen= Poeeeoe=e= Ponenenco= Femme enne= Poorooooe= oem enen= Pp oneooooe= Poocccces= + 12.60 20.60 28.60 36.60 44.60 52.60 16.60 24.60 32.60 40.60 48.60 -— ( _ co => —_— —— o—e > — r 7 > 7 we STP-V4 W.M.U, 9-May-85 KETCHIKAN DIESEL PRICE MODEL PLOT PAGE 6 PLOT OF VARIABLE: MON (HORIZ.) VS VARTAGTE! ERR VERN ) I--------- Hoennn---- tonne 4--------- tonnnnn--- Hoenn nnn +--------- teennnn nn + 2.790 * 1 I I rE 1 2.390 + I I I 1.990 + I I I 1 1 1.590 + z 5 I 1.190 - Z 1 I 1 I 0.7896 + I 11 I I 1 0.3896 + I 1 1 I I 1 1 -0.1044E-01 + I 1 I I -0.4104 + 1 I I I 1 1 -0.8104 > 1 I 1 1 x 1 1 0 =$:210 + r 1 I I -1.610 + I I I -2.010 + I I 1 1 -2.410 * I STP-V4 40.00 30.00 20.00 10.00 W.M.U. 9-May-85 ##¢¢* HISTOGRAM FOR VARIABLE: ERR sesse + 1 I I I I I z I I + I I a I I I I I I + I I I I I I I I I + I I I I I I I I a IXXXXXI IXXXXXI IXXXXXI IXXXXXI IXXXXXI IXXXXXI IXXXXXT IXXXXXI IXXXXXI IXXXXXI IXXXXXT IXXXXXI IXXXXXI IXXXXXI IXXXXXI IXXXXXT IXXXXXIXXXXXI IXXXXXI IXXXXXIXXXXXI IXXXXXI IXXXXXIXXXXXI IXXXXXI IXXXXXIXXXXXIXXXXK I XXXXAXIXXXXXI ITXXXXXIXXXXXIXAXAAXK I XXAXAXX IT XXXAXI IXXXXXIXXXXXIXXXXXKIXXXXXIXXXXXT IXXXXXIXXXXKIXXXXXIXXXXXIXXXAXXT IXXXXXIXXXXXIXXXXXK I XXAXXX I XXXAXRT IXXXXXIXXXXXK I XXXAXX I XAXKKIXAXAXT TXXXXXIXXAAK I XXXXAKIAXAXAAKAX I AXAXART IXXXXX I XXXAXX I XXXXKIXAXAXXXIXXAXAXT IXXXXXIXXXXKXIXXXXK UI XAXAXAXX I XXXXAT IXXXXXIXXXXXIXAXXAX I XXXXKIXXXXXT ITXXXXX I XXXAXX I XXXXK UT XXAXAXX IL XXXXXT ITXXXXX I XXXXXIXAXAAX TXXXXKUAXXXXX I KETCHIKAN DIESEL PRICE MODEL IXXXXXI IXXXXXI IXXXXXI IXXXXXI IXXXXXIXXXXXIXXXXXI IXXXXXIXXXXXIXXXXXIT IXXXXXIXXXXXIXXXXXI IXXXXX LT XXXXXIXXXXXKI co — co om —_—_— — — . =, — — HIST PAGE 7 oe 7 — pots c- Sr ce lO — — = eae at —~ ens STP-V4 W.M.U. 9-May-85 KETCHIKAN DIESEL PRICE MODEL HIST PAGE 8 **9** HISTOGRAM FOR VARIABLE: FOR esses 20.00 + I I I I I I I I I 15.00 + I I I I I I I IXXXXXI IXXXXXI IXXXXXI IXXXXXI IXXXXXI I IXXXXXI IXXXXXI IXXXXXI IXXXXXI IXXXXXI I IXXXXXI IXXXXXI IXXXXXI IXXXXXI IXXXXXI 10.00 + IXXXXXI IXXXXXI IXXXXXI IXXXXXI IXXXXXI I IXXXXXI IXXXXXI IXXXXXI IXXXXXI IXXXXXI I IXXXXXI IXXXXXI IXXXXXI IXXXXXI IXXXXXI I IXXXXXI IXXXXXI IXXXXXI IXXXXXI IXXXXXI I IXXXXXI1 IXXXXXI IXXXXXI IXXXXXI IXXXXXI I IXXXXX TXXXKXT XXKAX T AAXKAXT IXXXXXI IXXXXXI IXXXXXI IXXXXX LT XXXXXI I IXXXXXIXXXKX TXXXAX I AXKXX I IXXXXXI IXXXXXI IXXXXXI IXXXXXIXXXXXI I IXXXXX I XXXKX I XXXXX I AXKXX T IXXXXXI IXXXXXI IXXXXXI IXXXXXTXXXXXI I IXXXXXEXXXXX IT XXXKX I AXKXX T IXXXXXI IXXXXXI IXXXXXI UXXXXXIXXXXX I I IXXXXX I XXXXX I XXXAX I AXXXX TL IXXXXXI IXXXXXI IXXXXXI IXXXXX I XXXXXI 5.00 + IXXXXX EXXXXX TXXXKX I AXKAX T IXXXXXI IXXXXXI IXXXXXI IXXXXX I XXXXXI I IXXXXX LXXXXX EXAXAX I AXKXX I IXXXXXI IXXXXXI IXXXXXI IXXXXXTXXXXXI I IXXXXXI I XXXXX IE XXXKK LE XXKA T AXA LT XAXKKK TXKAXK T IXXXXXI IXXXXXEXXXXXI IXXXXXIXXXXXI I IXXXXXI IXXXXX IE XXXXX IT XAXXAK TAXAXK LAAAAK LAKKKX T IXXXXXI IXXXXX IT XXXXXI IXXXXX EXXXXXI I IXXXXXI IXXXXX I XXXKK LU XXAAK TXAXAK TAAKAK LXKAXH I IXXXXXI IXXXXXTXXXXXI IXXXXXIXXXXXI I IXXXXXI IXXXXX LE XXXKXT XXKAK LT AKAAK TAKAXK LT AKAKX IXXXXXI IXXXXX IT XXXXXI IXXXXX I XXXXXI I IXXXXXI IXXXXX IT XXXAX I AXKAK TL AKKAK LAKKAK LXKAKK IXXXXXI » UXXXXX I XXXAXT IXXXXX IT XXXXXT I IXXXXXI IXXXXX EXXXXX LT XXXAK IL AXKAX T AXKAK LAXAXH I IXXXXXI IXXXXXIXXXXXI IXXXXX LXXXXX I I IXXXXXI IXXXXX EXXXXK IE AXXKX T AXAAK T AAAKK TXXKAX T IXXXXXI IXXXXX I XXXXXI IXXXXX LXXXXXI I IXXXXXI IXXXXX EXXXXK T AAXKK LXXAXK T AXAK T AXKAXT IXXXXXI IXXXXX I XXXXXI IXXXXX I XXXXXI --t+----- to---- +----- +----- t----- to---- t----- +----- to---- +----- t----- +----- +----- +----- +----- t----- +----- +----- + A TA OA 3a 2A gaa 2A TA 3a OA OA aa oa oa 2A TA OA 2A 3:a A A A A A aA A A A A A A A A aA A aA A A A 36.3 A 37.3 A 38.3 A 39.3 A 40.3 A 41.3 A 42.3 A 43.3 A 44.3 A STP-V4 W.M.U, 9-May-85 REDUCED KETCHIKAN DATA JAN82 THRU PRESENT PLOT PAGE Ws PLOT OF VARIABLE: OIL2 (HORIZ.) VS VARIABLE: BBL (VERT. ) I--------- $--------- teennnn--- += wocten ---+ 45.70 + I I I 44.90 + I iF I 44.10 ? I I I 43.30 + eine 1 I I 1 1 42.50 + 1 I I 41.70 + 1 1 I 1 I 1 I 40.90 + 1 I I I 1 40.10 * I I I 39.30 > I I I 38.50 * 1 I 1 I 1 rc vi 1 37.70 - 1 I 1 I 1 I 1 36.90 Ma 1 11 I I 36.10 - 1 I I 35.30 + 1 Tooeeees-- Goocorroes= $ococcee=—= Goeocooocoes Hoecenso-- Pnsnneooe= tonne n---- tooceceeo== Poeccoooe= toeoreeo--- + 25.62 ad ee 28.82 30.42 32.02 33.62 26.42 28.02 29.62 31.22 32.82 STP-V4 W.M.U, 9-May-85 “REDUCED KETCHIKAN DATA JAN82 THRU PRESENT PLOT * PAGE 14 PLOT OF VARIABLE: MON (HORTZ.) VS VARIABLE: OIL2 (VERT.) I--------- +--------- +--------- +o-------- to-------- +--------- +--------- +--------- tenon ----- tener nn--- + 33.30 +1 1 I 1 I 14 I 32.50 iv I I 1 I 31.70 + 1 I 1 I I 30.90 + I a I 1 30.10 + 1 1 I I z 29.30 . I I 1 14 I 28.50 + 1 I I 1 I 1 i 27.70 + 1 v1 I I ,o4 I 26.90 + 1 I 1 1 I I 26.10 + I I 1 I 25.30 S Teco ee--- Pomeesocoe=: Poenseooe== Poecoeoooe= Peseesrer= Posenasese Poececeere Paomanooeso Poeoeooeecr= Poseeoeere + 12.60 20.60 28.60 36.60 44.60 52.60 STP-V4 W.M.U. 9-May-85 REDUCED KETCHIKAN DATA JAN82 THRU PRESENT PLOT PAGE 15 PLOT OF VARIABLE: MON (HORIZ.) VS VARIABLE: BBL (VERT. ) I- eo tenn------ Hoenn nn ana teennnn--- tooenenan-- Hoenn nnn- toner nn-- = teeern---- + 45.70 al aL . 1 I I 44.90 + I I I 44.10 + I I I 43.30 ¢ 1 11 I I 1 I 42.50 + I iz I 41.70 + 1 1 I 1 I 1 I 40.90 + 1 I I I 1 40.10 = I I I 39.30 i I 1 I 38.50 na 1 I 1 I 1 I 1 rot 37.70 + 1 I 1 I 1 I 1 36.90 + 1 i 1 I I 36.10 + I I I 35.30 + 1 Ieeeere--- Pome een-=— Poeoeccero-= Pome enren= Peecccoece= Porecceocoes= tonnne n= toocecoe=-- toeoeeoor-- Poecoeros= + 12.60 20.60 28.60 36.60 44.60 52.60 é 16.60 24.60 32.6C 40.60 48.60 STP-VS WMU OBS ooo oN Oo YF O© WN 1 Es 13 14 15 16 CYEAR 1985.000 1986.000 1987.000 1988.000 1989.000 1990.000 1991.000 1992.000 1993.000 1994.000 1995 .000 1996.000 1997.000 1998.000 1999.000 2000.000 VAR KETCHIKAN FORECAST USING DIESEL PRICE = 6.0632+1.156*CRUDE(T-2) CRUDE 25.59333 24.48667 24.50667 25.55333 26.97000 28.67667 30. 18333 32.22333 34.04000 36. 15667 38.41000 41.01333 44.22667 47.69333 51.43333 55.47333 EST 35.64909 34.36979 34.39291 35.60285 37.24052 39.21343 40.95513 43.31337 45.41344 47.86031 50.46516 53.47461 57.18923 61.19669 65.52013 70.19037 GAL$ 0.8487879 0.8183283 0.8188787 0.8476870 0.8866790 0.9336530 0.9751222 1.031271 1.081272 1.139531 1.201551 1.273205 1.361648 1.457064 1.560003 1.671199 PAGE STP-V4 W.M.U. 9-May-85 KETCHIKAN FORECAST USING DIESEL PRICE PLOT OF VARIABLE: CYEAR (HORIZ.) VS VARIARESS CRUDE ERT ) [---------+--------- Henn nnn tenn tenn +--------- +--------- to-------- + 55.47 + 1 I I 5 52.27 oa I 1 I I 49.07 + I I 1 x 45.87 + - I 1 I 42.67 + 1 I I 39.47 + I I I 36.27 + 1 I I x 1 33.07 2 I 1 1 I 29.87 + 1 I I I 26.67 + 1 "1 I I 1 1 23.47 + Josoesrs-= teeceren--- Hoenn tener nn teonreno--- Hoesen n-- oe nnn tonne + 1985. 1989 1993. 1997. 2001. 1987. 1991. 1995 1999. es fer ae ea ar (com och — eco — od as —— 6.0632+1. 156*CRUDE(T-2) PLOT Peary PAGE 1 > —- = _— cr — -_— —s —_—— STP-V4 W.M.U,. 9-May-85 KETCHIKAN FORECAST USING DIESEL PRICE = 6.0632+1.156*CRUDE(T-2) PLOT PAGE 2 PLOT OF VARIABLE: CYEAR (HORIZ.) VS VARIABLE: EST (VERT. ) I--------- tenon nn---- tennn----- tonne nnn-- to-nnnnn-- $--------- ten------- $o-------- + 70.19 + 1 I I I 66.99 + I I 1 I 63.79 a I I I 1 60.59 + I I I 57.39 + 1 I I I 54.19 + I 1 r I 50.99 + I 1 I I 47.79 + 1 I I I 1 44.59 + I I 1 I 41.39 * I 1 I I 1 38.19 + I 1 sé I 1 34.99 2 z 1 1 1 I 31.79 + jerooe=e=-- tenern---- ton------- Hoenn n nnn toon enn--- tone eennn- toe e nn n--- t--------- + 1985. 1989, 1993. 1997, 2001. STP-V4 W.M.U. 9-May-85 KETCHIKAN FORECAST USING DIESEL PRICE = 6.0632+1.156*CRUDE(T-2) PLOT PAGE 3 PLOT OF VARIABLE: CYEAR (HORIZ.) VS VARIABLE: GAL$ (VERT.) Somecenetmermel +o 1.671 + 1 I - x 1.591 + I I 1 I 1.511 + I I iE 1 1.431 + x I I 1 1.351 + I I I 1.271 + 1 I I I 1 1.191 + I I I 1 V.008 + I 1 I I 1.031 + 1 I I I 1 0.9512 + I 1 I I 1 0.8712 5 ry 1 I Ez 1 1 0.7912 + x — — a Sa — =e a STP-V4 W.M.U. 9-May-85 KETCHIKAN FORECAST USING DIESEL PRICE = 6.0632+1.156*CRUDE(T-2) PLOT PAGE 4 PLOT OF VARIABLE: CRUDE (HORIZ.) VS VARIABLE: GAL$ (VERT.) I--------- t--------- +--------- +--------- +--------- t--------- +--------- Hanno eo -- + 1.671 ~ 1 I I I 1.591 + I I 1 I 1.511 + t I I 1 1.431 * Z I I 1 1.351 + I I I 1.271 + 1 I I I 1 1.191 a I I I 1 . v.ttt + I 1 I I 1.031 + 1 I I I 1 0.9512 + I 1 I . I 1 0.8712 + I 2 I 12 0.7912 + I--------- +--------- tennn----- Henncnn nn tennn---H- tome nnnn a to-------- toon ------ + 24.09 32.09 40.09 48.09 56.09 SECTION 1 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- GENERAL PROGRAM DATA KETCHIKAN PUBLIC UTILITIES POWER SUPPLY PLANNING STUDY CASE - WITH QUARTZ HILL - WITHOUT TRANSMISSION REINFORCEMENT JANUARY 1986 QUARTZ HILL SERVED BY B.C. HYDRO YRS OF DATA 21 TOTAL & DYNAMIC LOOK-AHEAD YRS 5 SEA 1.01 STU 1s 1 SEA DY YEAR T LAST 20 1=PREOPT NO. SEA 12 O=NO PREOPT SEA 1ST CAL 1=SIM YEAR O=OPT 1985 oO MAX NO PLANS 2 1000 MAINTENANCE FACTORS SEA SEA SEA 1.01 1.04 1.09 1.13 1.07 SEA 1.18 DERATING SEA- SEA 5 9 1=FAST OPT O=SLOW OPT 1 SEA SEA 1.170 «1294 ---- 1=¥, O=N ---- PROB. ECHO SHORT 1 0 oO DELTA COST NO. ITERS CRITRN (PU) EACH UNIT 0.03 100 SEA SEA SEA 1.08 1.00 0.00 PAGE 2 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 PAGE 3 INPUT SECTION 2 : GENERAL ECONOMIC DATA =S== NO.OF CURVES ===== DISCOUNTING EX HYDRO UNSERVED EN. ESC. RATE FIXED CHARGE RATE CURVE O+M ESC. $/MWH ESC. 4 3 1 3 97.8 2 ESC. - ESC. 1ST ust - - ESC. 1ST LST - - ESC, 1ST cs] = - ESC. 1ST St = CURVE RATE(%) YR YR RATE(%) YR YR RATE(%) YR YR RATE(%) YR YR 1 0.00 1985 1985 10.00 1986 2005 2 0.00 1985 1985 4.00 1986 2005 3 0.00 1985 1985 1.860 1986 1986 1.59 1987 1987 7.49 1988 1988 7.45 1989 1989 7.69 1990 1990 1.82 1991 1991 1.79 1992 1992 1.76 1993 1993 1.86 1994 1994 1.83 1995 1995 1.92 1996 1996 1.88 1997 1997 1.97 1998 1998 2.06 1999 1999 2.01 2000 2000 1.97 2001 2001 2.05 2002 2002 2.12 2003 2003 2.19 2004 2004 2.14 2005 2005 4 0.00 1985 1985 -3.60 1986 1986 0.07 1987 1987 3.50 1988 1988 4.60 1989 1989 5.30 1990 1990 4.45 1991 1991 §.75 1992 1992- 4.85 1993 1993 5.40 1994 1994 5.45 1995 1995 6.00 1996 1996 7.00 1997 1997 7.00 1998 1998 7.00 1999 1999 7.10 2000 2000 7.00 2001 2005 FCR. - FCR. 1ST LST - - FCR. 1ST cSt = - FCR. 1ST CST = - FCR. 1ST est = CURVE RATE(%) YR YR RATE(%) YR YR RATE(%) YR YR RATE(%) YR YR 1 10.19 1985 2005 2 12.20 1985 2005 3 13.30 1985 2005 SECTION 3 --- CONSTRAINT (1=Y¥,0=N) MAX RES MIN RES 1 - MI RES. 107 86. 77 71 66 61. N (%) 76 41 -97 71 -43 93 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 : SYSTEM RELIABILITY REQUIREMENTS oO VST YR 1985 1989 1993 1997 2001 2005 Lst - YR 1985 1989 1993 1997 2001 2005 UNSER. EN 1 - MIN RES. 104 83. 76. 70. 65. (%) 73 47 29 30 24 - MAXIMUM ALLOWED - % RES 35.00 1ST YR 1986 1990 1994 1998 2002 UNSER EN 2.00 MINIMUM PERCENT RESERVE REQUIREMENT -~ ust = YR 1986 1990 1994 1998 2002 (%) - MIN RES. (%) 97 81 74 68 64 -06 -55 -69 -95 +10 1ST YR 1987 1991 1995 1999 2003 LST - YR 1987 1991 1995 1999 2003 - MIN RES. (%) 94.11 79.72 73.17 67.65 63.00 VST VR 1988 1992 1996 2000 2004 ust = YR 1988 1992 1996 2000 2004 PAGE 4 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 PAGE 5 SECTION 4 -- EXISTING UNIT DATA --- NUMBER OF EXISTING THERMAL RUN-OF-RIVER PONDAGE PUMP STORAGE THERMAL UNITS UNITS UNITS UNITS CLASSES EXISTING: 4 oO 9 0 DELETED: oO oO oO oO TOTAL: 4 oO 9 oO 2 --- EXISTING THERMAL UNIT DATA --~ = UNIT = CL se= WW ss= FOR SOR YR AVAIL FOM vom HEATRATE 10 NAME CAP DER PU w/y 1ST LST $/KWYR = $/MWH BTU/KWH 1 TOTEM BT 1 2s 0. 0.028 4.0 1985 2005 27.50 17.40 11667. 2 BAILEY 1 2 4 0. 0.028 4.0 1985 2005 40.00 4.66 10000. 3 BAILEY 2 2 4 0. 0.028 4.0 1985 2005 40.00 4.66 10000. 4 BAILEY 3 2 6 0. 0.028 4.0 1985 2005 40.00 4.66 10000. --- EXISTING PONDAGE UNIT DATA. --- UNIT FOR SOR YEAR AVAIL FOM COST VOM COST NO. NAME (Pu) (WKS/YR) FIRST LAST ($/KWYR) ($/MWH) 20 KETCH 3 0.028 2 1985 2005 113.4000 10.50000 21 KETCH 4 0.028 25 1985 2005 113.4000 10.50000 25 SILVS LK 0.028 2. 1985 2005 24.2500 0.90000 26 BEAVER 1 0.028 25 1985 2005 43.6700 0.95000 27 BEAVER 3 0.028 2). 1985 2005 43.6700 0.95000 28 BEAVER 4 0.028 2. 1985 2005 43.6700 0.95000 23 SWAN LK1 0.028 25 1985 2005 0.0000 55.50000 24 SWAN LK2 0.028 2h. 1985 2005 0.0000 55.50000 22 KETCH 5 0.028 2h. 1985 2005 113.4000 10.50000 --- UNIT ---- --- CAPACITY ---- ---- ENERGY ---- ID NAME Mw CURVE MWH/WK CURVE 20 KETCH 3 1.4 10 105. 1 21 KETCH 4 11 10 150. 2 25 SILVS LK 2.0 10 182. 6 26 BEAVER 1 1.0 10 40. 7 27 BEAVER 3 2.0 10 246. 8 28 BEAVER 4 2.0 10 228. 9 — — eco —_— — —a — — — —, aera — — —- WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION --- UNIT ---- --- CAPACITY ---- ---- ENERGY ---- ID NAME mw CURVE MWH/WK = CURVE 23° SWAN LK1 1153 10 376. 4 24 SWAN LK2 11.3 10 784. 5 22 KETCH 5 1.4 10 147, 3 --- DATA FOR THERMAL CLASSES --- CLASS NAME ween RUBE S == - ESC. CURVE - PLANT NO. TYPE $/MBTU FUEL O+M 1 TOTEM BT OSL 4.125 4 2 TOTEM BT 2 BAILEY DSL 4.125 4 i BAILEY AREA KPU KPU 3.3 “~< i> <2 ae zn PAGE 6 —, * WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM SECTION 5 -- UNIT ADDITION DATA NO. OF THERMAL P-H ADDITIONS? P-S ADDITIONS? - VERSION 3.3 ADDITION TYPES (1=¥,0=N) (1=¥,0=N) 2 1 0 ADD FUEL 1ST CALNDR FOM COST VOM COST FIXED CHARGE NAME NO. YRS TYPE TYPE YR AVAIL ($/KWYR) = ($/MWH) CURVE (4 CHAR) IMMATURE 1 DSL 1987 40.000 4.6600 3 DIES 0 2 OMMY 1987 0.000 0.0000 1 BCHY 0 11 MHNY 1987 15.800 0.5500 1 MHNY 0 ADD CAP COST FUEL COST --- ESC. CURVE ---- HEAT RATE CAPACITY PLANT TYPE ($/KW) ($/MBTU) CAP. FUEL O+M (BTU/ KWH) (Mw) ID 1 600.0 4.1250 2 4 2 11500.0 1.00 1 2 2250.0 5.0000 2 2 2 10000.0 1.00 1 WW 4000.0 0.0000 2 0 2 0.0 ADD -IMMATURE- = - MATURE- ADD METH(O-1) - SECOND. ENERG- CAP PS TYPE FOR SOR FOR SOR REL. ~— PUR- METH $/MWH ESC FAC EFF (PU) (WK) (PU) (WK) ONLY CHASE (0-3) CUR (%) (PU) 1 0.042 0.5 0.042 0.5 0 0 0 0.0 0 0.0 0.050 0.0 0.050 0.0 0 0 0 0.0 0 0.0 110 0.028 =61.5 0.028 1.5 0 0 TYPE ---- CAPACITY ---- ---- ENERGY ---- mw CURVE MWH/WK CURVE MHNY 1.00 10 93. 10 SECTION 6 -- LOAD DATA LOC SHAPE (O=BLOCK, NO. OF POINTS - READ FROM TAPE - 1=TRIANGULAR) IN EXIST. LDC METHOD LOC PTS 1 10 2 10 YR SEAS ROW 1-LDC LOADS (MW)----- ROW 2 LDC HOURS ‘14 is 16. 15. 14, 13. «12. Vw. 10. 8. 8. 1 4 0. 42. 219. 384. 441. 484. 528. 576. 679. 744. 1 2 16. 15. 15. 13. 12, 10. 10. Ts 7. Ms 1 2 0. 66. 259. 372. 409. 450. 492. 552. 666. 672. : rs, Cs eo ~~~ res co ain, —_— tao es PAGE 7 — cae Kae ae —_ YR SEAS ROW 1-LDC LOADS (MW) NNYNNNNNNNNNNNNNNNNNNNNN Hw ee eee ee ee ee ee ee eee COBMPVVOOUNS SOW 10 -SCOCOTHBVWVMOUMNS SWOWNN=—=— WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 17, Oo. 16. oO. iit QO. 15. o. 15. 0. 16. o. 18. oO. 16. o. 19. QO. 21. o. 7. QO. 16. oO. 7. o. 17. o. 7, Oo. 16. oO. 16. o. 16. oO. 18. Oo; 16. o. 20. oO. 16. 17. 18. 19. 7. 1. 18. 8. 18. 35. 15. 19. 16. 13. 1S. 21. 19. 3. 20. 5. 16. 42. 15. 66. 16. 7. 15. 19. 17. 1. 15. 8. 15. 35. 16. 19. 7. 13. 18. 21. 19. 3. 18. V7. 15. 115. 14, 5. 13. 44. 14. 93. 14. 70. 16. 50. 18. 175. 16. 30. 18. 18. 16. 219. 15. 259. 15. 17. 15. 115. 14, 5. 14, 44. 14, 93. 16. 70. 17. 50. 15. 176. 17. 30. 14. 292. 13. 263. 14. 99. 13. 173. 13. 236. 13. 225. 14, 135. 13. 345. 16. 167. 17. 123. 14. 384. 13. 372. 14, 292. 13. 263. 14. 99. 13. 173. 13. 236. 14. 225. 16. 135. 13. 345. 7. 167. 13. 425. 13. 381. 13. 250. 12, 318. 12. 381. 12. 380. 13. 295. 13. 423. 14. 344. 16. 328. 14. 441. 13. 409. 13. 425. 13. 381. 13. 250. ¥2- 318. 13. 381. 13. 380. 14. 295. 13. 423. 14. 344. 12. 470. WwW. 450. pus 392. a. 419. 11. 467. 17. 473. 12. 451. We 482. 13. 442. 15. 447. 12. 484. WW. 450. 12, 470. 13. 450. t2. 392. Wt. 419. Ws. 467. 12. 473. v2. 451. Ue 482. 14, 442. ROW 2 LDC HOURS Wt. S21. 10. 513. 10. 470. 10. 477. 10. 516. 10. 516. 10. 523. 10. 522. 10. 499. 125 Si. Mm. 528. 10. 492. 14. 521, 1 513. 10. 470. 10. 477. 10. 516. 10. 516. 1. 523. We. §22. 11. 499. 9. 567. 8. 553. 9. 534. 9. 536. 8. 577. 9. 544. 9. 593. 8. 565. 10. 551. 12. 569. 10. 576. 8. 582. 9. 567. 9. 553. 9. 534. 9. 536. 9. 577. 10. 544. 10. 593. 8. 565. 10. 551. 8. 691, 8. 669. 7. 614. 7. 618. 8. 681. 8. 631. 7. 664. 8. 683. 8. 700. 9. 669. 9. 679. 8. 666. 8. 691. 9. 669. 8. 614. ae 618. 8. 681. 8. 631. 7. 664. 8. 683. 8. 700. PAGE 8 YR SEAS ROW 1-LDC LOADS (MW) WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 ROW 2 LDC HOURS 2 12 2. 21. 19. 18. 16. 18. 13. 12. 2 12 Q. Ss. 18. 123. 328. 447. 511. 569. 3 1 19. 18. 17. 16. 15. 13. 12. VW. 3 1 oO. 42. 219. 384. 441. 484. 528. 576. 3 2 18. 16. 16. 14. 14, VW. VW. 8. 3 2 oO. 66. 259. 372. 409. 450. 492 552. 3 3 18. nig 17. 15. 14. 13. 12 10. 3 3 oO. 17. 117, 292. 425. 470. 521. 567. 3 4 18. 17. 16. 14. 14, 12. 12. 9. 3 4 oO. 19. 115. 263. 381. 450. 513. 553. 3 5 18. 18. 16. 16. 14. 13. ve. 10. 3 5 oO. 1. 5. 99. 250. 392. 470. 534. 3 6 7. 16. 15. 14. 13. 12. VW. 10. 3 6 oO. 8. 44. 173. 318. 419. 477. 536. 3 7 17, 16. 16. 14. 14. 12. Vw. 9. 3 7 Oo. 35. 93. 236. 381. 467. 516. 577. 3 8 18. 7. 16. 15. 14. 13. i. 10. 3 8 oO. 19. 70. 225. 380. 473. 516. 544. 3 9 20. 18. 18. 16. 15. 13. 12 VW. 3 9 0. 13. 50. 135. 295. 451. 523. 593. 3 #10 18. 17. 16. 14. 14. 12. 12. 9. 3 410 o. 21. 175. 345. 423. 482. 522 565. 30°00 21. 21. 18. 18. 15. 15. Ww a. 3°00 oO. 3. 30. 167. 344, 442. 499. 551. 3 (12 23. 22. 20. 19. 7. 16. 14. 13. 3 12 Oo. Ss. 18. 123. 328. 447. S11. 569. 4 1 19. 18. 18. 16. 15. 13. 12. Vw. 4 1 o. 42. 219. 384. 441. 484. 528. 576. 4 2 18. 17. 17. 18. 14. 12. VW. 9. 4 2 oO. 66. 259. 372. 409. 450. 492. 552. 4 3 19. 18. 7, 16, 15. 13. 12, 10. 4 3 QO. 17, #117. 292. 425. 470. 521. 567. 4 4 18. 7. 17. 1S. 14, 13. 12. 10. 4 4 QO. 19. 115. 263. 381. 450. 513 553. 4 5 19. 19. 16. 16. 14. 13. 12. 11, 4 5 o. 1. 5. 99. 250. 392. 470. 534. 4 6 17. 17. 15. 1s. 13. 12. VW. 10. 4 6 Oo. 8. 44. 173. 318. 419. 477. 536. 4 uf 18. 17. 16. 14, 14. 12. 12. 10. 4 7 oO. 35. 93. 236. 381. 467. 516. 577. 4 8 18. 17. 16. 15. 14, 13. VW. WW. 4 8 oO. 19. 70. 225. 380. 473. 516. 544. “ f = 7 oo io 10. 669. 9. 679. 8. 666. 9. 691. 9. 669. 8. 614. 8. 618. 9. 681. 9. 631. 8. 664. 9. 683. 8. 700. Ww. 669. 10. 679. 9. 666. 9. 691. 10. 669. 8. 614. 8. 618. 9. 681. 9. 631. 9. 744. 9. 744. 8. 672. 8. 744. 7. 720. 8. 744, 8. 720. 7. 744. 8. 744. 8. 720. 9. 744. 8. 720. 10. 744. 9. 744. 9. 672. 9. 744. 7. 720. 8. 744. 8. 720. 7. 744. 9. 744. PAGE 9 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 PAGE 10 YR SEAS ROW 1-LDC LOADS (MW)----- ROW 2 LDC HOURS 4 9 2ic 19. 19. 16. 15. 13. 12. We 8. 8. 4 9 0. 13. 50. 135. 295. 451. 523. 593. 664. 720. 4 10 18. 7s 17. 15. 14. 12. 2), 9. 9. 9. 4 10 o. 21. #175. 345. 423. 482. 522. 565. 683. 744. 4 i 22. ce 18. 18. 18. 18. 12. 12. 9. 2. 4 11 o. 3. 30. 167. 344. 442. 499. 551. 700. 720. 4 12 24. 23. 2); 20. 18. 7, 14, 14, Wt. 10. 4 12 oO. 5. 18. 123. 328. 447. 511. 569. 669. 744. 5 1 2 3 20. 19. 17. 17. 15. 13. 12. 1. 10. 5 1 o. 42. 219. 384. 441. 484. 528. 576. 679. 744, 5 2 20. 19. 18. 16. 18. 13. 13. 9. 9. 9. 5 2 oO. 66. 259. 372. 409. 450. 492. 552. 666. 672. 5 3 21. 20. 19. 7. 16. 14, 13. 1. 10. 95 5 3 oO. 17. 0147. «292. 425. 470. 521. S67. 691. 744. 5 4 20. 19. 18. 16. 16. 14, 13. 10. 10. 8. 5 4 o. 19. 115. 263. 381. 450. 513. 553. 669. 720. 5 5 21. ai. 7. 17. 16. 14. 13. 12. iB 9. 5 5 o. 1. 5. 99. 250. 392. 470. 534. 614. 744. 5 6 19. 18. 7. 16. 14. 13. iz WwW. 9. 9. 5 6 Qo. 8. 44. 173. 318. 419. 477. 536. 618. 720. 5 7 19. 18. UUs 16. 18. 13. 13. 11. 10. 8. 5 Lf oO. 35. 93. 236. 381. 467. 516. S77. 681. 744. 5 8 20. 19. 18. ws 15. 14. 125 12. 10. 9. 5 8 oO. 19. 70. 225. 380. 473. 516. 544. 631. 744. 5 9 22. 21. 21. 18. 7. 16. 13. 12. 8. 8. 5 9 oO. 13. 50. 135. 295. 451. 523. 593. 664. 720. 5 10 20. 19. 18. 16. 16. 13. 13. 10. 10. 10. 5 10 Oo. 21. 175. 345. 423. 482. 522. 565. 683. 744. 5 4 24. 23. 20. 20. 7. 7. 13. 13. 9. 9. s 11 Oo. 3. 30. 167. 344. 442. 499. 551. 700. 720. 5 12 26. 2s. 23. 22. 20. 18. 18. 15. Mae 1. 5 12 oO. 5. 18. 123. 328. 447. 511. 569. 669. 744. 6 1 22. 20. 20. 18. 17. 15. 14. 13. VW. 10. 6 1 o. 42. 219. 384. 441. 484. 528. 576. 679. 744. 6 2 21. 19." 19. 16. 16. 13. 13. 10. 10. 10. 6 2 o. 66. 259. 372. 409. 450. 492. 552. 666. 672. 6 3 21. 20. 19. 18. 16. 18. 14. 12. 11. 10. 6 3 o. 17. 017, «292. «8425. 470. 521. 567. 691. 744, 6 4 ai 19. 19. 7. 16. 14, 13. 1. WwW. 8. 6 4 o. 19. 115. 263. 381. 450. 513. 553. 669. 720. 6 5 22: 22. 18. 18. 16. 15. 13. 12. 10. 10. 6 5 oO. 1. 5. 99. 250. 392. 470. 534. 614. 744, YR SEAS ROW 1-LOC LOADS (MW) 20. oO. 20. Os 212 Go: 23. oO. an | 0. 25. oO. 27. G2 ve 0; 21. 0. 22 MPOMONVVVVV NNN SNS SS SSS SOD MDADOOMAMOOOOOD OCOBBVNNOOD Nn--00 SCOMGTOVYMOMOUNMNSSWWNN—=—N WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM ~- VERSION 3.3 0 21. oO. 22 o. 20. o. 20. oO. 21. oO. 24. o. 21. oO. 25. Oo. 28. o. 2a, o. 22. oO. 19. 8. 19. 35. 20. 19. 21. 13. 19. 21. 24. 3. 26. S. 21. 42. 20. 66 21. 7. 20. 19. 22. 1. 20. 8. 19. 35. 20. 19. 22. 13. 20. ais 25. 3. 27. 5. 21. 42. 20. 66. 17. 44. 18. 93. 18. 70. 21. 50. 19. 175. 21. 30. 24. 18. 20. 219. 19. 259. 20. VT 19. 115. 19. 5. 18. 44. 19. 93. 19. 70. 22 50. 19. 175. 21. 30. 24. 18. 21. 219. 20. 259. 7. 173. 16. 236. 7. 225. 18. 135. 17. 345. ZA 167. 22; 123. 18. 384. Was 372. 18. 292. WW. 263. 19. 99. 7. 173. 7. 236. 18. 225. 19. 135. ic 345. 21. 167. 23. 123. 19. 384. a7 322 15. 318. 16. 381. 16. 380. 17. 295. 16. 423. Tes 344. 20. 328. 18. 441. 16. 409. 17. 425. Ws 381. 7. 250. 18. 318. 16. 381. 16. 380. 18. 295. 7. 423. 18. 344, Zi 328. 18. 441. Vis 409. 14, 419. 14, 467. 15, 473. 15. 451. 14, 482. 7. 442. 19. 447. 18. 484. 13. 450. 18. 470. 14. 450. 15. 392. 14. 419. 14, 467. 18. 473. 18. 451. 14, 482. 18. 442. 19. 447. 16. 484. 14. 450. ROW 2 LDC HOURS 12. 477. 13. 516. 13. 516. 13. 523. 14, 522. 13. 499. 16. Sit. 14. 528. 13. 492. 14, 521. 14. 513. 13. 470. 13. 477. 13. 516. 13. 516. 14. 523. 14. 522. 14. 499. 16. Sit. 14. 528. 14. 492. 1. 536. Vt. 577. T2s 544, 12. 593. 10. 565. 13. 551. 15. 569. 13. 576. 10. 552. 12, 567. $1. 553. 42. 534. 11. 536. V1. 577. 12. 544. 13. 593. VW. 565. 13. 551. 16. 569. 13. 576. 10. 552. 9. 618. WW 681. 10. 631. 9 664. 10. 683. 10. 700. 12. 669. ml 679. 10. 666. nie 691. VW. 669. 10. 614. 10. 618. WW. 681. 10. 631. 9. 664. el. 683. 10. 700. 13. 669. Pus 679. 10. 666. 9. 720. 8. 744. 10. 744. 9. 720. 10. 744. 10. 720. ea 744. Wt. 744. 10. 672. 10. 744. 9. 720. 10. 744. 9. 720. 9. 744. 10. 744, 9. 720. V1. 744. 10. 720. 12. 744. VW. 744. 10. 672. PAGE er W YR SEAS OOOOOOOQOOHOOHHOHHOHOHHHOHOONWODRSOBDDOMDMDHOODDOOBMDDOOOD SSO OW MONO OUD SOONN==NN=H-OOOCOMOVVOOUUNS SOW i 21. 26. 22. ROW 1-LDC LOADS (MW) 22. 0 22. 0 23. oO 21. oO oO 22. oO. 24. oO 21. oO 0 28. oO 23. Oo 22. oO 23. oO. 22. 0 23. 0 21. o. 24. Oo 22. oO 2s. 0 oO 27. o. 19. 292. 18. 263. 19. 99. 17. 173. W7. 236. 18. 225. 19. 135. 7. 345. 22. 167. 23. 123. 19. 384. 18 372 19. 292. 18. 263 19 99 18. 173 7. 236. 18. 225. 20. 135. 18. 345. 22. 167. 44l. 7 409. 18. 425. 7. 381. 7. 250. 16. 318 7 381. 17 380. 18 295. 17. 423. 19. 344. 16. 470. 15. 450. 15. 392. 15. 419. 14, 467. 15. 473. 16. 451. 14. 482. 18. 442. 20. 447. 16. 484. 14. 450. 16. 470. 15. 450. 16. 392. 15. 419 15. 467. 16 473. 16. 451. 15. 482. 18. 442. ROW 2 LDC HOURS ¥2. 425. WwW, 381. 7. 250. 16. 318. 16. 381. 7. 380. 18. 295. 7. 423. 18. 344, 21. 328. 14. 521. 14, 513. 14. 470. 13. 477. 14 516. 14. 516. 14. 523. 14. 522. 14 499. 7. 511 15. 528. 14. 492. 15. $21. 14. 513. 14. 470 13. 477. 14 516 14. 516. 14 523. 18. 522. 14. 499. 12. 567. whe 553. 12. 534. 12. 536. Wt. 577. 13. 544. 13. 593. WW. 565. 14. 551. 16. 569. 13. 576. 10. 552. 12. 567. 12. 553. 13. 534. 12. 536. 42:3 577. 13. 544. 13. 593. 41. 565. 14, 551. 11. 691. VW. 669. 10. 614. 10. 618. WW. 681. 1. 631. 9. 664. VW. 683. 10. 700. 13. 669. 12. 679. 10. 666. We. 691. 12. 669. 10. 614. 10. 618. VW. 681. VW. 631. 9. 664, WwW. 683. 10. 700. WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 10, 744. 9. 720. 10. 744. 10. 720. 9. 744. 10. 744. 9. 720. VW. 744. 10. 720. 12. 744. VW. 744. 10. 672. 10. 744. 9. 720. 10. 744. 10. 720. 9. 744. 10. 744. 9. 720. Vd. 744. 10. 720. PAGE 12 YR SEAS 9 9 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 WwW Ww 12 12 POVVOOONSS00ONN—=-NN = -COCOBBVWVOOUNSSOONN== WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 ROW 1-LDC LOADS (MW)-----ROW 2 LDC HOURS 29. 28. 25. 24. 22. 20. 7. 7. 13. o. 5. 18. 123. 328. 447. 511. 569. 669. 24. 22. 22. 20. 19, 16. 15. 14. 12. o. 42. 219. 384. 441. 484. 528. 576. 679. 23. 21. 21. 18. 17. 14. 14. 10. 10. Oo. 66. 259. 372. 409. 450. 492. 552. 666. 23. 22. 21. 19. 18. 16. 15. 13. 12. Oo. 17. 117, 292. 425. 470. 521. S67. 691. 23. 21. 21. 18. 18. 15. 18. 12, 12, o. 19. 115. 263. 381. 450. 513. 553, 669. 24. 24. 20. 20. 18. 16. 14. 13. 10. o. 1, 5. 99. 250. 392. 470. 534. 614, 22. 21. 19. 18. 16. 15. 13. 12. 10. oO. 8. 44. 173. 318. 419. 477. 536, 618. 22. 21. 20. 18. 17. 15. 14. 12. 12. o. 35. 93. 236. 381. 467. 516. 577. 681. 23. 21. 20. 19. gs 16. 14, 13. Ww. o. 19. 70. 225. 380. 473. S16. 544. 631. 25. 23. 23. 20. 19. 17. 15. 13, 10. QO. 13. 50. 135, 295. 451. 523. 593. 664. 22. Zu 21. 18. 18. 18. 18. 11. 11. oO. 21. 175. 345. 423. 482. 522. 565. 683. 27. 27. 23. 23. 19. 19. 14. 14. VW. o. 3. 30. 167. 344. 442. 499. 551. 700. 29. 29. 26. 24. 22. 21. 17. 17. 13. oO. 5. 18. 123. 328. 447. 511. 569. 669. 24. 23. 22. 20. 19. 17. 18. 14. 12. oO. 42. 219. 384. 441. 484. 528. 576. 679. 23. 21. 21. 18. 18. 15. 14. WwW. WwW. oO. 66. 259. 372. 409. 450. 492. 552. 666. 24. 23. 22. 20. 18. 17. 18. 13. 12. oO. 17. #117. 292. 425. 470. 521. S67. 691. 23. 22. 21. 19. 18. 16. 15. 12. 12. 0. 19. 115. 263. 381. 450. 513. 553. 669. 24. 24. 20. 20. 18. Nac 15. 13. WwW. oO. un 5. 99. 250. 392. 470. 534. 614. 22. 2a. 19. 19. 17. 16. 14. 13. 1. oO. 8. 44. 173. 318. 419. 477. 536. 618. 22; 21. 20. 18. 18. 15. 15. 12, 12. oO. 35. 93. 236. 381. 467. 516. 577. 681. 23. 22. 21. 19. 18. 16. 14. 13. WW. (Vs 19. 70. 225. 380. 473. 516. 544. 631. eo -—— as ae Oop eee 13 744 Ww 744 10 672 WW 744 720 10 744 10 720 744 + 744 10 720 WwW 744 Ww 720 13 744 1. 744 iW 672 Ww 744 720 Ww 744. 10. 720. 744. Vis 744. — PAGE 13 — 5 Same — YR SEAS ROW 1-LDC LOADS (MW)-- 20. 135. 19. 345. 23. 167. 25. 123. 21. 384. 19. 372. 20. 292. 19. 263. 21. 99. 19. 173. 19. 236. 20. 225. 21 135. 19. 345. 24. 167. 25. 123. 21. 384. 19. 372. 2%. 292. 20. 263. 21. 99. WwW im VW Ww im] WW Ww Ww 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 13 13 13 13 13 13 13 13 13 13 9 9 10 10 Ww iW 12 12 DUS BWONN==-NN = -COOOBBVVOONNSSOWONN== WESTINGHOUSE AUTOMATIC GENERATION 26. oO. 23. Qo. 28. Oo. 30. oO. 2s. o. 24. 0. 24. oO. 24. Oo. 2s. oO. 22. o. 23. oO. 24. oO. 26. oO. 23. o. 28. o. 31. o. 25. o. 24. oO. 25. o. 24. o. 25. oO. 24. 13. 22. 21. 27. 3. 29. 5. 23. 42. 22. 66. 23. Vis 22. 19. 25. 1. 22. 8. 22. 35. 22. 19. 24. 13. 22. 21. 28. 3. 30. 5. 24. 42. 22. 66. 24. 17. 22. 19. 2b. 1. 24. so. Zils 175. 23. 30. 26. 18. 23. 219. 22... 259. 22. 7. 22. 115. 21. 5. 20. 44. 21. 93. 21. 70. 24. 50. 21. 175. 24. 30. 27. 18. 23. 219. 22. 259. 22. W7. 22. 115. 21. 5. -ROW 2 LOC 19. 17, 295. 451. 18. 18. 423. 482. 20. 19. 344. 442. 23. 21. 328. 447. 20. 7. 441. 484. 18. 18. 409. 450. 19. 47. 425. 470. 18. 16. 381. 450. 19. 7. 250. 392. 7. 16. 318. 419. 18. 16. 381. 467. 18. 7. 380. 473. 20. 17. 295. 451. 18. 16. 423. 4682. 20. 20. 344. 442. 23. 22. 328. 447. 20. 7. 441. 484. 18. 18. 409. 450. 19. 17. 425. 470. 19. 16. 381. 450. 19. 17. 250. 392. PLANNING PROGRAM ~ VERSION 3.3 HOURS 15. 523. 15. 522. 15. 499. 18. 511, 16. 528. 15. 492. 16. 521. 15. 513, 15. 470. 14. 477. 15. 516. 15. 516. 15. 523. 15. 522. 15. 499. 18. 511. 16. 528. 15. 492. 16. 521. 16. 513. 15. 470. 14. 593. 12. 565. 18. 551. 7. 569. 14, 576. Ve. 552 13. 567. #2... 553. 14. 534, 13. 536. 12. 577. 14, 544, 14. 593. 12. 565. 15. 551. 18. 569. 15. 576. We 552. 14. 567. 13. 553. 14. 534. 10. 664. 12. 683. VW. 700. 14. 669. 12. 679. 4. 666. 12. 691. 12. 669. VW. 614. VW. 618. 12. 681. 412. 631. 10. 664. 12. 683. 41. 700. 14, 669. 13. 679. ". 666. 42. 691. 13. 669. as 614. 10. 720. 12, 744, VW. 720. 13. 744. 12. 744. Ve 672. Ww. 744. 10. 720. Vw. 744. 10. 720. 9. 744. VW. 744. 10. 720. 12. 744. Vn. 720. 13. 744. 12. 744. VW. 672. VW. 744. 10. 720. VW. 744. PAGE 14 YR SEAS 13 13 13 13 13 13 13 13 13 13 13 13 13 13 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 15 1s 15 15 COMMNVMMUNMNSSWONNHKHKNNH—COHCOTMOIVIOD 10 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM ~- VERSION 3.3 ROW 1-LDC LOADS (MW)----~- ROW 2 LDC HOURS 23. 22. 20. 19. 17. 16. 14. oO. 8. 44. 173. 318. 419. 477. 23. 22. 21. 19. 18. 16. 15. QO. 35. 93. 236. 381. 467. 516. 24. 23. 22% 20. 18. 7. 18. oO. 19. 70. 225. 380. 473. 516. 27. 25. 25. 21. 20. 18. 16. Oo. 13. S50. 135. 295. 451. 523. 24. 23. 22. 19. 19. 16. 16. oO. 21. 175. 345. 423. 482. 522. 29. 28. 24. 24. 20. 20. 15. o. 3. 30 167. 344. 442. 499. 31. 30. 28. 26. 24. 22. 19. QO. 5. 18. 123. 328. 447. S11. 26. 24. 24. 2\. 20. 18. 16. QO. 42. 219. 384. 441. 484. 528. 25. 23. 23. 19. 19. 16. 15. oO. 66. 259. 372. 409. 450. 492. 25. 24. 23. 21. 19. 18. 16. 0. 7. 6117. «6292. 425. 470. 521. 2s. 23. 22. 20. 19. 7. 16. o. 19. 115. 263. 381. 450. 513. 26. 26. 21. 21. 19. 18. 16. oO. 1. 5. 99. 250. 392. 470. 23. 23 21. 20. 18. 7. 15. oO. 8. 44. 173. 318. 419. 477. 24. 22. 21). 19. 19. 16. 15. QO. 35. 93. 236. 381. 467. 516. 24. 23. 22 20. 19. 7. 18. oO. 19 70. 225. 380. 473. 516. 27. 25. 25. 22. 20. 18. 16. oO. 13. 50. 135. 295. 451. 523. 24. 23. 22. 20. 19. 16. 16. Oo. 21. 175. 345. 423. 482. 522. 30. 29. 25. 25. 21. 20. 16. o. 3. 30. 167. 344. 442. 499. 32. 31. 28. 26. 24. 23. 19. oO. 5. 18. 123. 328. 447. S11. 26. 25. 24. 22. 21 18. 7. o. 42. 219. 384. 441. 484, 528. 25. 23. 23. 20. 19. 16. 16. o. 66. 259. 372. 409. 450. 492. eos 13. VW. 536. 618. 13. 12. 577. 681. 14, 12. 544. 631. 14, 10. 593. 664. 12. 12. 565. 683. 15. 1. 551. 700. 18. 14. 569. 669. 15. 13. 576. 679. ain VW. 552. 666. 14. 13. 567. 691. 13. 13. 553. 669. 14, WwW. 534. 614. 13. WW. 536. 618. 13. 13. 577. 681. 14, 12. 544. 631. 15. 10. 593. 664. 12. 12. 565. 683. 15. 12, 551. 700. 18. 15. 569. 669. 18. 13. 576. 679. 12... 12, 552. 666. — — 111s 720. 10. 744. 145 744. 10. 720. 12. 744. vw. 720. 14 744. 12. 744. 1. 672. 12. 744, 10. 720. Vw. 744 WW 720. 10. 744. 12. 744. 10. 720. 12. 744. 12. 720. 14 744, 12. 744. 12. 672. PAGE i) YR SEAS 15 15 15 15 15 18 15 1s 15 16 15 15 1S 15 15 15 1S 15 iS 15 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 3 -COWOTONVOounNssw —-SCOWOPOVVOOUMNS SWOWNN—=—NN VW WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 ROW 1-LDC LOADS (MW) 26. oO. 25. oO. 26. Oo. 24. o. 24. o. 2s. o. 28. o. 25. oO. 30. o. 33. o. 27. oO. 26. QO. 26. oO. 26. oO. 27. oO. 24. o. 24. oO. 25. oO. 29. oO. 25. Oo. 31. o. 25. 17. 23. 19. 26. 1. 23. 8. 23. 35. 24. 19. 26. 13. 23. 21. 29. 3. 32. 5. 25. 42. 24. 66. 25. 7. 24. 19. 27. 1. 24. 8. 23. 35. 24. 19. 26. 13. 24. 21. 30. 3. 23. 117. 23. 118. 22. 5. 21. 44, 22. 93. 22. 70. 26. 50. 23. 175. 25. 30. 29. 18. 24, 219. 23. 259. 24, V7, 23. 115. 22. 5. 21. 44. 22. 93. 23. 70. 26. 50. 23. 175. 26. 30. 21. 292. 20. 263. 22, 99. 20. 173. 20. 236. 21. 225. 22, 135. 20. 345. 2s. 167. 27. 123. 42. 384. 20. 372. 22. 292. 21. 263. 22, 99. 20. 173. 20. 236. 21. 225. 23. 135. 21. 345. 26. 167. o—_ — — —_— 20. 425. 20. 381. 20. 250. 18. 318. 19. 381. 19. 380. 24. 295. 20. 423. 21. 344. 25. 328. 2). 441. 19. 409. 20. 425. 20. 381. 20. 250. 18. 318. 19. 381. 20. 380. 21. 295. 20. 423. 22. 344. 18. 470. 17, 450. 18. 392. 17. 419. 17. 467. 18. 473. 18. 451. 17. 482. 21. 442. 23. 447. 19. 484. 16. 450. 18. 470. 7. 450. 18. 392. 7. 419. u., 467. 18. 473. 19. 451. 17. 482. 2}, 442. ROW 2 LDC HOURS wT. 521. 16. 513. 16. 470. 15. 477. 16. 516. 16. 516. 16. 523. 16. 522. 16. 499. 19. 511. is 528. 16. 492. TH. $21. 17. 513. 16. 470. 15. 477. 16. 516. 16. 516. 7. 523. 17. 522. 16. 499. 14. 567. 13. 553. 14, 534. 14. 536. 13. 577. 14, 544. 18. 593. 13. 565. 16. 551. 19. 569. 15. 576. 12. 552. 14, 567. 13. 553. 15. 534. 14, 536. 14, 577. 15. 544. 15. 593. 13. 565. 16. 551. 13. 691. 13. 669. 12: 614. WW. 618. 13. 681. 12... 631. TT. 664. 13. 683. 12. 700. 18. 669. 13. 679. 12. 666. 13. 691. 13. 669. 12. 614. 12. 618. 13. 681. 13. 631. th. 664. 13. 683. 12. 700. 12. 744. 10. 720. 12, 744. We 720. 10. 744. 12. 744. Vt. 720. 13. 744. 12. 720. 14. 744. 13. 744. 12. 672. 12. 744. 10. 720. 12. 744. Vn. 720. 10. 744. 12. 744. 1. 720. 13. 744. 12. 720. PAGE 16 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 YR SEAS) ROW 1-L' 16 «12 33. 16 12 oO. 74 27. 7 04 oO. 72 26. 17 2 oO. 173 27, iE oO. 17 4 26. 7 4 oO. 17 5 27. 7 5 0. 17 6 25. ig) 6) oO. 7117 25. ge) oO. 17 8 26. 17 8 oO. 17 9 29. 17 9 oO. 17 10-26. 17 10 oO. Wout 31. wow oO. 17 12034, 17 12 oO. 181 28. 18 1 oO. 18 6226. 18 2 0. 18 327. 18 3 oO. 18 4 ~~ (27. 18 4 oO. 18 528. 18 5 0. 18 6 ~~ 25. 18 «6 oO. 18 7 ~~ 25. 187 oO. 18 8 26. 18 8 oO. DC LOADS (MW)----- ROW 2 LDC HOURS 32. 29. 28. 25. 23. 20. 19. 1S. 5. 18. 123, 9328. 447. 511. 569. 669. 26. 25. 23. 22. 19, 17. 16. 14. 42. 219. 384. 441. 484. 528. 576. 679, 24. 24. 21. 20. 17, 16. 12. 12. 66. 259. 372. 409. 450. 492. 552. 666. 25. 24. 22. 21. 19. 7. 18. 13. 17. #417. 292. 425. 470. 521. S67. 691. 24. 24. 21. 20. 18. 17 14. 14. 19. 115. 263. 381. 450. 513. 553. 669. 27. 23. 23. 20. 19. 16. 18. 12. 1. 5. 99. 250. 392. 470. 534. 614. 24. 22. an 19. 18. 15. 14. 12. 8. 44. 173. 318. 419. 477. 536. 618. 24. 23. 20. 20. 17. 16. 14. 13. 35. 93. 236. 381. 467. 516. 577. 681. 25. 23. 22. 20. 18. 16. 15. 13. 19. 70. 225. 380. 473. 516. 544. 631. 27. 27. 23. 22. 19. 17. 18. 1, 13. 50. 135. 295. 451. 6523. 593. 664. 24. 24. 21. 20. 7. 17. 13. 13. 21. 175. 345. 423. 482. 522. 565. 683. 30. 26. 26. 22s 22. 7. 16. 12. 3. 30. 167. 344. 442. 499. 551. 700. 33. 30. 28. 26. 24. 20. 19. 15. 5. 18. 123. 328. 447. 511. 569. 669. 26. 25. 23. 22, 19. 18. 16. 14. 42. 219. 384. 441. 484. 528. 576. 679. 25. 24. Zt. 20. 1. iw, 12. 12, 66. 259. 372. 409. 450. 492. 552. 666. 26. 2s. 23. 21. 19. 18. 1s. 14. 17. #117. 292. 425. 470. 521. 567. 691. 25. 24. 22. 21. 18. 17. 14. 14. 19. 115. 263. 381. 450. 513. 553. 669. 28. 23. 23. ais 19. 17. 18. 12. 1. 5. 99. 250. 392. 470. 534. 614. 24. aan als 19. 18. 16. 14. 12; 8. 44. 173. 318. 419. 477. 536. 618. 24. 23. 21. 20. 18. 7. 14. 14, 35. 93. 236. 381. 467. 516. 577. 681. 25. 24. 22. 20. 19. 17. 15. 13. 19. 70. 225. 380. 473. 516. 544. 631. oo _—_— mT cc —— ~—— 15. 744. 13. 744, 12. 672. 12. 744. WwW. 720. 12, 744. 1, 720. 10. 744. 12. 744. WW. 720. 13. 744. 12, 720. 15. 744. 13. 744. 12. 672. 12. 744, Tt. 720. lies 744. ze 720. We. 744. Nz 744. — — oo PAGE 7 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM ~- VERSION 3.3 —— YR SEAS ROW 1-LDC LOADS (MW)----- 18 18 18 18 18 18 18 18 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 20 20 20 20 20 20 20 20 20 20 COMWHMAVVOOUNSSWWONn=-=— ONS SWWNN—=-NN 30. Oo. 26. oO. 32. oO. 34. oO. 28. o. 27. oO. 28. Oo. 21. oO. 28. oO. 26. Oo. 26. oO. 27. oO. 30. QO. 27. Oo. 32. oO. 35. oO. 29. Oo. as o. 28. QO. 2%3 oO. 29. oO. 27. so. 24. 175. en. 30. 30. 18. 26. 219. 2s. 259. 2s. V7. 25. 116. 24. 5 23. 44. 24. 93. 24. 70. 28. 50. 24. 175. 27. 30. 31. 18. 26. 219. 25. 259. 26. 117. 2s. 115. 24. 5. 23. 135. 2 21. 345. 4 ZT: 167. 3 29. 123. 3 23. 384. 4 21. 372. 4 23. 292. 4 22. 263. 3 24. 99. 2 22. 173. 3 212 236. 3 22. 225. 3 24. 135. 2 22. 345. 4 27. 167. 3 29. 123. 3 24. 384. 4 22, 372. 4 23. 292. 4 22. 263. 3 24. 99. 2 ROW 2 LDC HOURS 22. 19. 7. 95. 451. 523. 21. 18. 17. 23. 482. 522. 22, 22. 17. 44. 442. 499. 26. 24. 20. 28. 447. 511. 22. 20. 18. 41. 484. 528. 2i. 7. 7. 09. 450. 492. 21. 19. 18. 25. 470. 521. 21. 18. 17. 81. 450. 613. 2. 19. 7. 50. 392. 470. 19. 18. 16. 18. 419. 477. 20. 18. 7. 81. 467. 516. 24. 19. ES 80. 473. 516. 22. 20. Vig 95. 451. 523. 21. 18: 18. 23. 482. 522. 23. 22. 17. 44. 442. 499. 26. 25. 21. 28. 447. S11. 23. 20. 18. 41. 484. 528. 21. 7. 17. 09. 450. 492. 22. 20. 18. 25. 470. 521. 21. 19. 18. 81. 450. 513. 22. 20. 17. 50. 392. 470. 1. 664. 13. 683. 13. 700. 16. 669. 14, 679. 12. 666. 14. 691. 14. 669. 12. 614. 12, 618. 14. 681. 13. 631. WwW. 664. 13. 683. 13. 700. 16. 669. 14, 679. 13. 666. 14. 691. 14. 669. 13. 614, PAGE YR SEAS ROW 1-LDC LOADS (MW) 26. o. 26. 0. 27'. oO. 31. Oo. 27. OF 33. 0. 36. 0. 20 20 20 20 20 20 20 20 20 20 20 20 20 20 OOCWONNOOD 10 10 Ww Un 12 12 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 25. 8. 25. 35. 26. 19. 28. 13. 26. 21. 32. 3. 35. Ss. --ANNUAL PEAKS-~ NO. ODNSWN—-COTVOUNSON=— 21. 29. 35. 21. 30. 36. 23. 44. 24. 93. 25. 70. 28. 50. 25. 175. 27. 30. 31. 18. 23. 31. 36. FEB. MAR. APR. 1. 1. 1. 2. Le -16 1.10 -87 2.05 -00 1.21 -20 1.13 -00 1.00 -00 0.00 -00 0.00 -00 0.00 .00 0.00 -00 0.00 -00 0.00 ecocoeo-4---=+ 00 1.33 00 1.07 17° 1.05 46 3.05 121.49 1.49 1.21 1.21 2.86 1.56 1.34 2.59 1.48 1.00 1.00 0.00 0.00 0.00 0.00 0.00 0.00 22. 20. 18. 173. 318. 419. 22: 2. 18. 236. 381. 467. 23. 21. 19. 225. 380. 473. 24. 23. 20. 135. 295. 451. 22. 21. 18. 345. 423. 482. 27. 23. 23. 167. 344. 442. 30. 27. 25. 123. 328. 447. 24. 26. 31. 32. HYDRO FACTORS MAY JUNE JULY 1.98 1.78 1.35 1 1.50 1.31 1.17 1 1.40 1.19 1.24 1 2.19 1.22 1.00 1 1.52 1.52 1.15 1 1.14 1.00 1.11 1 2.09 2.99 1.69 1 1.40 1.19 1.23 1 1.25 1.35 1.23 1 1.00 1.00 1.00 1. 0.00 0.00 0.00 0. 0.00 0.00 0.00 0 0.00 0.00 0.00 0 0.00 0.00 0.00 0 0.00 0.00 0.00 0 0.00 0.00 0.00 0 ---ROW 2 LDC HOURS 16. 18. 477. 536. 17. 15. 516. 577. 17. 16. 516. 544. 18. 16. 523. 593. 18. 14. 522. S65. 18. 7, 499. 551. 21. 21. Si. S69. 27. 28. 33. 33. 12. 618. 14. 681. 14, 631. 12. 664. 14. 683. 13, 700. 16. 669. 12. 720. VW. 744. 13. 744. 12. 720. 14. 744. 13. 720. 16. 744. 28. 34. AUG. SEPT OCT. NOV. DEC. -08 1.56 1.80 1.68 1.68 -03 1.31 1.26 1.34 1.00 -17°1.35 1.08 1.31 1.00 02 1.07 1.08 1.15 1.55 OO 1.12 1,12 1.24 1,28 22°1.24 1.23 1.43 1.11 88 2.10 2.05 1.92 1.00 30 1.28 1.39 1.39 1.34 27: 1.38 1.53 1.49 1.41 00 1.00 1.00 1.00 1.00 00 0.00 0.00 0.00 0.00 00 0.00 0.00 0.00 0.00 00 0.00 0.00 0.00 0.00 00 0.00 0.00 0.00 0.00 00 0.00 0.00 0.00 0.00 00 0.00 0.00 0.00 0.00 te — -_— ae —) PAGE 19 —. 7 < a — oo — — ~_— — — —_—_— — — — —~ —_— —~—~—s cr WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 PAGE 20 SECTION 7 -- NEW UNIT INSTALLATION CONSTRAINTS THERE ARE NO MINIMUM NUMBER OF UNITS CONSTRAINTS. THERE ARE NO MAXIMUM NUMBER OF UNITS CONSTRAINTS. WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 PAGE 21 SECTION 8 -- FUEL DATA AND MIX CONSTRAINTS. FUEL UNIT OF HEAT CONTENT NAME MEASURE (MBTU/UNIT) 1 OSL BBL 5.88 2 OMMY MBTU 1.00 11 POND THERE IS NO FUEL MIX CONSTRAINT — wre co — — fw cos ~~ oo — — — 7 “nr —~ ~_—- ODBVNONDSWN— 10 Ww 12 13 14 15 16 7 18 19 20 TOTALS WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM ~ VERSION 3.3 YEAR 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 (1985-2004) INSTALLATION 1mwooo-0c0o0o-000-00-0000 a UNIT SCHEDULE TYPE NUMBER FOR KETCHIKAN PUBLIC UTI rey PAGE 22 —_— C@OvOunswn-— 10 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM ~- VERSION 3.3 costs SUMMARY TABLE FOR KETCHIKAN PUBLIC UTI cosTs ( IN WLLL 16 nS OF DOLLARS ) —————— CURRENT<VEAR $ ==<==<=== Base=es=-=s= 1986 § S==-5°-~ YEAR FIXED VARIABLE PURCHASE TOTAL FIXED VARIABLE PURCHASE TOTAL 1985 1. 4. oO. 5. 1. 4. oO. 5. 1986 1. 4. Oo. 6. 1. 4. oO. 5. 1987 1, 5. o. 6. 1. 4. o. 5. 1988 1. 5. oO. Ve 1. 4. oO. 5. 1989 2. 6. oO. 8. 1. 4. oO. 6. 1990 2. 7. 0. 9. 1. 4. oO. 6. 1991 2. ae QO. 9. 1. 4. oO. 5. 1992 3. 7. oO. 10. Tis 4. oO. 5. 1993 3. 8. oO. 10. 1. 4. Oo. 5. 1994 3. 8. QO. 1. 1. 3. oO. 5. 1995 3. 8. QO. iW. 1. 3. o. 4. 1996 3. 9. oO. 12. 1. 3. oO. 4. 1997 3. 9. o. 13. 1. 3. oO. 4. 1998 4. 10. o. 13. 1. 3. oO. 4. 1999 4. 10. 0. 14, 1. 3. oO. 4. 2000 4. WW. oO. 18. 1. 3. oO. 4. 2001 4. 1. oO. 16. Iie Be oO. 3. 2002 5. 12. o. 7. 1. 2b o. 3. 2003 5. 13. oO. 7. 1. 2. o. Se 2004 6. 13. oO. 19. 1. 25 o. 3. TOTALS (1985 - 2004) 22. 66 oO. 88. uw o— co — prac — —— ee — ~~ PAGE 23 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1985) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. OUTPUT COST FACT ADD. cost O+M cost cOsT O+M COST (GWH) = $/MWH (%) DIES 3. oO 0.0 0.0 o. 0.0 0.0 oO. 0.0 0.0 0.0 TOT. o. oO o. oO. o. oO. oO. o. oO. -- SUMMARY OF RESULTS FOR EXISTING UNITS(1985) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME cap O+M FUEL VAR TOTAL OUTPUT cost FACT (mw) (M$) cost O+M cost (GWH) $/MWH (%) TOTEM BT 2. 0.0 0.0 0.0 oO. 0.0 65.5 0.0 BAILEY 13. 0.5 0.4 0.0 oO. 8.6 45.9 736 EX. POND 33. 0.7 0.0 3.8 4 97.4 38.8 33.3 TOTALS 48. ts oO. 4. as 106. -- SUMMARY OF RESULTS FOR SYSTEM (1985) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 20.88 mw INSTALLED CAPACITY = 48.00 Mw PER-CENT RESERVE = 129.88 PER CENT ANNUAL SYSTEM ENERGY = 106.09 GWH -- SUPPLIED BY SYSTEM = 106.09 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH wo ton-n------- MILLION DOLLARS ---------------- FIXED VARIABLE PURCHASE TOTAL COSTS COSTS POWER COST cost 1985 DOLLARS 1.3 4.2 0.0 5.5 1985 DOLLARS 1.3 4.2 0.0 5.5 PAGE 24 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1986) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. OUTPUT COST FACT ADD. COST O+M cost cost O+M cost (GWH) = $/MWH (%) DIES 3. oO 0.0 0.0 oO. 0.0 0.0 oO. 0.0 0.0 0.0 TOT. o. 0 Oo. Oo. o. 0 oO. 0 o. ~~ SUMMARY OF RESULTS FOR EXISTING UNITS(1986) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP Oo+M FUEL VAR TOTAL OUTPUT cost FACT (Mw) (M$) cOsT O+M cost (GWH) $/MWH (%) TOTEM BT 2: 0.0 0.0 0.0 0. 0.0 64.5 0.0 BAILEY 13. 0.5 0.3 0.0 0. 8.6 44.6 7.6 EX. POND 33. 0.7 0.0 4.0 4. 100.5 39.5 34.4 TOTALS 48. 1. oO. 4 109 -- SUMMARY OF RESULTS FOR SYSTEM (1986) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 21.48 Mw INSTALLED CAPACITY = 48.00 Mw PER-CENT RESERVE = 123.42 PER CENT ANNUAL SYSTEM ENERGY = 109.15 GWH -- SUPPLIED BY SYSTEM = 109,15 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH tataeiatatatatatatatatata MILLION DOLLARS ---------------- FIXED VARIABLE PURCHASE TOTAL costs costs POWER COST — COST 1986 DOLLARS 1.3 4.4 0.0 5.7 1985 DOLLARS 1.2 4.0 0.0 5.2 Sere eee PAGE 25 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3,3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1987) -- CASE = KETCHIKAN PUBLIC UTI VARIABLE COST(M$) ENERGY PROD CAP. FUEL VAR TOT. OUTPUT COST FACT UNIT CAP NO. FIXED COSTS (M$) NAME (MW) UNIT CAP, FIX TOT. ADD. COST O+M COST DIES 3. 0 0.0 0.0 TOT. oO. oO QO. QO. COST O+M cost (GWH) = $/MWH (%) 0.0 0.0 oO. 0.0 0.0 0.0 -- SUMMARY OF RESULTS FOR EXISTING UNITS(1987) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP o+M FUEL VAR TOTAL OUTPUT cost FACT (mw) (M$) COST O+M cost (GWH) $/MWH (%) TOTEM BT 2. 0.0 0.0 o. 0.0 65.2 0.0 BAILEY 13. 0.6 o. 8.6 44.8 7.6 EX. POND 33. 0.7 4. 109.1 40.1 37.3 TOTALS 48. 1. 5 118 -- SUMMARY OF RESULTS FOR SYSTEM (1987) ANNUAL PEAK LOAD INSTALLED CAPACITY PER-CENT RESERVE ANNUAL SYSTEM ENERGY -- SUPPLIED BY SYSTEM -- BOUGHT FROM INTERCONNECTIONS -------------- MILLION DOLLARS -- 1987 DOLLARS 1985 DOLLARS -- CASE = KETCHIKAN PUBLIC UTI 23.18 MW 48.00 MW 107.06 PER CENT 117.78 GWH 117.78 GWH 0.00 GWH VARIABLE PURCHASE TOTAL COSTS POWER COST cost 4.8 0.0 6.1 3.9 0.0 5.1 PAGE 26 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1988) -- CASE UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. AOD. cost O+M cost cost O+M cost DIES 3. oO 0.0 0.0 Oo. 0.0 0.0 o. TOT. o. oO 0. oO. oO. 0 oO. -- SUMMARY OF RESULTS FOR EXISTING UNITS(1988) -- CASE CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY NAME CAP Oo+™M FUEL VAR TOTAL OuTPUT (mw) (M$) cost O+m cost (GWH) TOTEM BT 2s 0.0 0.0 0.0 0. 0.0 BAILEY ian 0.6 0.4 0.0 0. 8.6 EX. POND 33), 0.8 0.0 4.9 5. 112.8 TOTALS 48. Ue 0. 5. 5 121 -- SUMMARY OF RESULTS FOR SYSTEM (1988) -~- ANNUAL PEAK LOAD INSTALLED CAPACITY PER-CENT RESERVE ANNUAL SYSTEM ENERGY -- SUPPLIED BY SYSTEM -- BOUGHT FROM INTERCONNECTIONS 1988 DOLLARS 1985 DOLLARS ore KETCHIKAN PUBLIC UTI ENERGY PROD CAP. OUTPUT COST FACT (GWH) $/MWH § (%) 0.0 0.0 0.0 0. KETCHIKAN PUBLIC UTI PROD CAP. cost FACT $/MWH (%) 67.6 0.0 46.4 7.6 43.1 38.6 CASE = KETCHIKAN PUBLIC UTI 23.91 mw 48.00 MW 100.76 = PER CENT 121.48 GWH 121.48 GWH 0.00 GWH MILLION DOLLARS ---------------- VARIABLE PURCHASE TOTAL costs POWER COST cost 5.3 0.0 6.7 4.0 0.0 5.0 mee PAGE 27 seusien — —— —- —s ~~ WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1989) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. OUTPUT COST FACT ADD. cost O+M cost cost O+M cost (GWH) = $/MWH (%) OIES 3. 1 0.3 0.1 0. 0.0 0.0 oO. 0.0 0.0 0.0 TOT. 3. 1 oO. oO. oO. oO. oO. oO. Oo. -- SUMMARY OF RESULTS FOR EXISTING UNITS(1989) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP Oo+™M FUEL VAR TOTAL OUTPUT cost FACT (mw) (M$) cost O+M cost (GWH) $/MWH (%) TOTEM BT 2. 0.1 0.0 0.0 0. 0.0 70.6 0.0 BAILEY 13). 0.6 0.4 0.0 0. 8.6 48.5 7.6 EX. POND 33. -0.8 0.0 5.7 6. 123.6 46.4 42.3 TOTALS 48. Zi 0. 6. 6. 132. -- SUMMARY OF RESULTS FOR SYSTEM (1989) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD INSTALLED CAPACITY PER-CENT RESERVE ANNUAL SYSTEM ENERGY -- SUPPLIED BY SYSTEM -- BOUGHT FROM INTERCONNECTIONS 26.04 MW 50.50 MW 93.94 PER CENT 132.30 GWH 132.30 GWH 0.00 GWH oorn-n-------- MILLION DOLLARS ---------------- FIXED VARIABLE PURCHASE TOTAL COSTS COSTS POWER COST cost 1989 DOLLARS 1.9 6.2 0.0 8. 1 1985 DOLLARS 1.3 4.2 0.0 5.5 PAGE 28 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1990) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. OUTPUT COST FACT ADD. COST O+M COST COST O+M COST (GWH) $/MWH = (%) DIES Ss 1 0.3 0.1 a: 0.0 oO. 0.0 0.0 0.0 TOT. Si. 1 0. Oo. OF oO. oO. oO. -- SUMMARY OF RESULTS FOR EXISTING UNITS(1990) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP Oo+M FUEL VAR TOTAL OUTPUT cost FACT (Mw) (M$) cost O+M cost (GWH) $/MWH (%*) TOTEM BT 25 0.1 0.0 0.0 oO. 0.0 74.1 0.0 BAILEY 13. 0.6 0.4 0.0 oO. 8.6 51.0 7.6 EX. POND 33). 0.9 0.0 6.4 6. 128.3 49.9 43.9 TOTALS 48. 2 0. 6. te. 137. -- SUMMARY OF RESULTS FOR SYSTEM (1990) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 26.96 uw INSTALLED CAPACITY = 50.50 Mw PER-CENT RESERVE 87.34 PER CENT ANNUAL SYSTEM ENERGY 136.96 GWH -- SUPPLIED BY SYSTEM = 136.96 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH asaceesaaa==-= MILLION DOLLARS ---------------- FIXED VARIABLE PURCHASE TOTAL cOosTS costs POWER COST cost 1990 DOLLARS 2.0 6.8 0.0 8.9 1985 DOLLARS i..3) 453) 0.0 5.5 =e mS Oe ot PAGE 29 — aah) Im —_— — acca com crea io Rare me PAGE 30 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM ~- VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1991) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. OUTPUT COST FACT ADD. COST O+M COST COST O+M COST (GWH) $/MWH = (%) DIES 3. 1 0.3 0.1 0. 0.0 0.0 0. 0.0 0.0 0.0 TOT. Si 1 0. oO. 0. oO. 0. 0. oO. -- SUMMARY OF RESULTS FOR EXISTING UNITS(1991) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP Oo+M FUEL VAR TOTAL OUTPUT cost FACT (mw) (M$) cost O+m cost (GWH) $/MWH (%) TOTEM BT 25 O-0 0.0 0.0 oO. 0.0 77.3 0.0 BAILEY ia: O77 0.4 0.1 Or 9.0 53.3 729) EX. POND 33. 0.9 0.0 6.7 Lan 131.2 50.8 44.8 TOTALS 48. 2 0; 7 7 140, -- SUMMARY OF RESULTS FOR SYSTEM (1991) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 27.59 Mw INSTALLED CAPACITY = 50.50 Mw PER-CENT RESERVE = 83.03 PER CENT ANNUAL SYSTEM ENERGY = 140.18 GWH -- SUPPLIED BY SYSTEM = 140.18 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH ererrr tener ne MILLION DOLLARS -~-~------------ FIXED VARIABLE PURCHASE TOTAL costs costs POWER COST cost 1991 DOLLARS 2.1 TaN 0.0 9.2 1985 DOLLARS 2) 4.0 0.0 5.2 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1992) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR ToT. OUTPUT COST FACT ADD. cost O+M cost cost O+M cost $/MWH (%) DIES 3. 2 0.0 0.0 0.0 TOT. 5. 2 -- SUMMARY OF RESULTS FOR EXISTING UNITS(1992) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP O+M FUEL VAR TOTAL OUTPUT cost FACT (Mw) (M$) cost O+M cost (GWH) $/MWH (%) TOTEM BT 2. 0.1 0.0 0.0 Oo. 0.0 81.4 0.0 BAILEY 13 0.7 0.5 0.1 1 9.3 56.2 8.2 EX. POND 33 0.9 0.0 6.9 7 134.1 51.7 45.8 TOTALS 48 2. oO 7 1 143 -- SUMMARY OF RESULTS FOR SYSTEM (1992) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 28.22 Mw INSTALLED CAPACITY = 53.00 MW PER-CENT RESERVE = 87.78 PER CENT ANNUAL SYSTEM ENERGY = 143.40 GWH -- SUPPLIED BY SYSTEM = 143.40 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH . See ere ae MILLION DOLLARS ~---~-~-~-~--~---~---- FIXED VARIABLE PURCHASE TOTAL costs COSTS POWER COST cost 1992 DOLLARS 2.6 7.5 0.0 10.1 1985 DOLLARS 1.3 3.8 0.0 5.2 | —— PAGE 31 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM ~ VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1993) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. OUTPUT COST FACT ADD. cost O+M cost CcOosT O+M cost (GWH) $/MWH (%) DIES 3. 2 0.7 0.3 1. 0.0 0.0 oO. 0.0 0.0 0.0 TOT. 5. 2 1. o. 1. oO. oO. oO. oO. -- SUMMARY OF RESULTS FOR EXISTING UNITS(1993) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP Oo+M FUEL VAR TOTAL OUTPUT cost FACT (mw) (M$) cost O+M COST (GWH) $/MWH (%) TOTEM BT 2. 0.1 0.0 0.0 Qo. 0.0 85.1 0.0 BAILEY 13. 0.7 0.5 0.1 Us 9.7 58.9 8.5 EX. POND 33. 1.0 0.0 7.2 7. 136.9 52.7 46.8 TOTALS 48. 22 1. Va 8. 147. -- SUMMARY OF RESULTS FOR SYSTEM (1993) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 28.86 MW INSTALLED CAPACITY = 53.00 MW PER-CENT RESERVE = 83.66 PER CENT ANNUAL SYSTEM ENERGY = 146.62 GWH -- SUPPLIED BY SYSTEM = 146.62 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH -o-2---------- MILLION DOLLARS ---------------- FIXED VARIABLE PURCHASE TOTAL costs COSTS POWER COST cost 1993 DOLLARS 2.7 7.8 0.0 10.4 1985 DOLLARS 1.2 3.6 0.0 4.9 PAGE 32 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1994) -- CASE = KETCHIKAN PUBLIC UTI PAGE 33 UNIT CAP NO, FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP, FIX TOT. FUEL VAR TOT. OUTPUT COST FACT ADD. COST O+M COST COST O+M COST (GWH) $/MWH (%) DIES 3. 2 0.7, 0.3 t. 0.0 0.0 o. 0.0 0.0 0.0 TOT. 5. 2 1. o. 1. o. oO. oO. o. -- SUMMARY OF RESULTS FOR EXISTING UNITS(1994) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP o+™M FUEL VAR TOTAL OUTPUT cost FACT (Mw) (M$) cost O+M cost (GWH) = $/MWH (*) TOTEM BT = 0.1 0.0 0.0 0. 0.0 89.4 0.0 BAILEY 13. 0.7 0.6 0.1 i. 10.3 62.0 9.0 EX. POND a3. 1.0 0.0 7.5 Bi 139.5 53.6 47.7 TOTALS 48. a. i. 8. 8. 150. -- SUMMARY OF RESULTS FOR SYSTEM (1994) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 29.49 Mw INSTALLED CAPACITY = 53.00 mw PER-CENT RESERVE = 79.71 PER CENT ANNUAL SYSTEM ENERGY - 149.84 GWH -- SUPPLIED BY SYSTEM = 149.84 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH 2------------- MILLION DOLLARS ---------------- FIXED VARIABLE PURCHASE TOTAL cosTS COSTS POWER COST cost 1994 DOLLARS 2.7 8.1 0.0 10.9 1985 DOLLARS 1.2 3.4 0.0 4.6 Coron ———— — foo — me WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 PAGE 34 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1995) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX ToT. FUEL VAR ToT. OUTPUT COST FACT ADD. cost O+M cost cost O+M cOsT (GWH) = $/MWH (%) DIES 3. 2 0.7 0.3 1. 0.0 0.0 QO. 0.0 0.0 0.0 ToT. 5. 2 1. oO. 1. o. o. oO. oO. -- SUMMARY OF RESULTS FOR EXISTING UNITS(1995) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP Oo+M FUEL VAR TOTAL OUTPUT cost FACT (Mw) (M$) Cost O+M cost (GWH) $/MWH (%) TOTEM BT 2. 0.1 0.0 0.0 oO. 0.0 93.9 0.0 BAILEY 13. 0.8 0.6 0.1 1. 11.0 65.3 9.6 EX. POND 33. 1.0 0.0 7.8 8. 142.1 54.6 48.6 TOTALS 48. 25 1, 8. 8. 153. -- SUMMARY OF RESULTS FOR SYSTEM (1995) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD 30.13 MW INSTALLED CAPACITY 53.00 MW 75.93 PER CENT 153.06 GWH 153.06 GWH 0.00 GWH PER-CENT RESERVE ANNUAL SYSTEM ENERGY -- SUPPLIED BY SYSTEM -- BOUGHT FROM INTERCONNECTIONS worcn---------- MILLION DOLLARS ---------------- FIXED VARIABLE PURCHASE TOTAL costs cOsTS POWER COST cost 1995 DOLLARS 2.8 8.5 0.0 11.3 1985 DOLLARS 1.1 3.3 0.0 4.3 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1996) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. OUTPUT COST FACT ADD. COST O+M COST COST O+M COST (GWH) $/MWH = (%) DIES 3. 3 oa) 0.5 0.0 0.0 Oo. 0.0 0.0 0.0 TOT. 8. 3 ae QO. oO oO oO. -- SUMMARY OF RESULTS FOR EXISTING UNITS(1996) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP Oo+M FUEL VAR TOTAL OUTPUT cost FACT (mw) (M$) cost O+M cost (GWH) = $/MWH (%) TOTEM BT 2a 0.1 0.0 0.0 0, 0.0 99.0 0.0 BAILEY 13. 0.8 0.8 O.1 Vis 12.3 69.1 10.8 EX. POND 33. 1.0 0.0 8.0 8 143.9 55.7 49.2 TOTALS 48. Zs 1. 8 9 156. -- SUMMARY OF RESULTS FOR SYSTEM (1996) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 30.75 mw INSTALLED CAPACITY = 55.50 Mw PER-CENT RESERVE = 80.48 PER CENT ANNUAL SYSTEM ENERGY = 156.24 GWH -- SUPPLIED BY SYSTEM = 156.24 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH MILLION DOLLARS ---------------- FIXED VARIABLE PURCHASE TOTAL costs costs POWER COST cost 1996 DOLLARS 3.4 8.9 0.0 12.3 1985 DOLLARS tic 2 3.1 0.0 4.3 _ pee — ce ee PAGE 35 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1997) -- CASE UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) NAME (MW) UNIT CAP. FIX ToT. FUEL VAR TOT. ADD. COST O+M COST cost O+M cost DIES 3. 3 1.1 0.5 2. 0.0 0.0 oO. TOT. 8. 3 1. o. 2. oO o. -- SUMMARY OF RESULTS FOR EXISTING UNITS(1997) -- CASE KETCHIKAN PUBLIC UTI ENERGY PROD CAP. OUTPUT COST FACT (GWH) = $/MWH (%) 0.0 0.0 0.0 0. KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME cap O0+M FUEL VAR TOTAL = OUTPUT cost FACT (mw) (ms) COST O+M. COST (GWH) = $/MWH (%) TOTEM BT 25 0.1 0.0 0.0 oO. 0.0 105.1 0.0 BAILEY 13. 0.8 0.9 0. 1 14.1 73.7 12.4 EX. POND 33); 1.0 0.0 8.2 8 145.3 56.7 49.7 TOTALS 48. 2 1 9 159 -- SUMMARY OF RESULTS FOR SYSTEM (1997) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 31.38 MW INSTALLED CAPACITY = 55.50 MW PER-CENT RESERVE = 76.88 PER CENT ANNUAL SYSTEM ENERGY = 159.42 GWH -- SUPPLIED BY SYSTEM = 159.42 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH wonrn--n------- MILLION DOLLARS ---------------- FIXED VARIABLE — PURCHASE TOTAL costs cosTs POWER COST —— COST 1997 DOLLARS 3.5 9.3 0.0 12.8 1985 DOLLARS iat 3.0 0.0 4.1 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -+ SUMMARY OF RESULTS FOR UNIT ADDITIONS (1998) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. OUTPUT COST FACT ADD. cOsT O+M cost cost O+M cost (GWH) $/MWH (%) DIES 3. 3 V1 0.5 2. 0.0 o. 0.0 0.0 0.0 TOT. 8. 3 te o. 2 QO. oO Oo. -- SUMMARY OF RESULTS FOR EXISTING UNITS(1998) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP Oo+M FUEL VAR TOTAL OUTPUT cost FACT (Mw) (M$) cost O+M COST (GWH) $/MWH (%) TOTEM BT 2 0.1 0.0 0.0 oO. 0.0 111.6 0.0 BAILEY 13. 0.9 1.1 0.1 1. 16.1 78.6 14.1 EX. POND 33. 1.1 0.0 8.5 8 146.5 57.8 50.1 TOTALS 48. 2. 1 9 10 163 -- SUMMARY OF RESULTS FOR SYSTEM (1998) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 32.00 MW INSTALLED CAPACITY = 55.50 MW PER-CENT RESERVE = 73.41 PER CENT ANNUAL SYSTEM ENERGY = 162.61 GWH -- SUPPLIED BY SYSTEM = 162.61 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH 1998 DOLLARS 1985 DOLLARS ae — for oe . MILLION DOLLARS FIXED VARIABLE PURCHASE TOTAL COSTS COSTS POWER COST cOsT 3.6 9.7 0.0 13.3 1.0 2.8 0.0 3.9 ms crn on ‘ase ——F PAGE 37 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (1999) UNIT CAP NO. FIXED COSTS (M$) NAME (MW) UNIT CAP. FIX TOT. FUEL VAR ADD. cost O+M CcOsT cost O+M DIES 3. 3 1.1 0.5 2. 0.0 0.0 ToT. 8. 3 1. 1. 2 o. 0%. -- CASE = VARIABLE COST(M$) ToT. cost o. -- SUMMARY OF RESULTS FOR EXISTING UNITS(1999) -- CASE = KETCHIKAN PUBLIC UTI ENERGY PROD CAP. OUTPUT COST FACT (GWH) $/MWH = (%) 0.0 0.0 0.0 KETCHIKAN PUBLIC UTI CLASS CLASS FIXED ~—- VARIABLE COSTS (M$) ENERGY PROD CAP. NAME cap O0+M FUEL VAR TOTAL OUTPUT COST FACT (mw) (M$) COST O+M COST (GWH) = $/MWH (%) TOTEM BT 2; 0.1 0.0 0.0 oO. 0.0 118.6 0.0 BAILEY oe 0.9 fant 2s 18.0 83.9 15.8 EX. POND 33. iy (OX 08/57, 9 147.8 59.0 50.5 TOTALS 48. 2. tf 9. 10. 166. -- SUMMARY OF RESULTS FOR SYSTEM (1999) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 32.63 MW INSTALLED CAPACITY = 55.50 MW PER-CENT RESERVE = 70.08 PER CENT ANNUAL SYSTEM ENERGY = 165.79 GWH -- SUPPLIED BY SYSTEM = 165.79 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH wocrnrnon----- MILLION DOLLARS --~ FIXED VARIABLE — PURCHASE TOTAL costs costs POWER COST — COST 1999 DOLLARS 3.6 10.2 0.0 13.9 1985 DOLLARS 1.0 27, 0.0 3.7 PAGE 38 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (2000) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. OUTPUT COST FACT ADD. cost O+M cost cost O+M cost $/MWH (%) DIES 3. 4 1.5 0.0 o. 0.0 0.0 TOT. 10. 4 2. oO. -- SUMMARY OF RESULTS FOR EXISTING UNITS(2000) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP Oo+M FUEL VAR TOTAL OUTPUT COST FACT (mw) (M$) cost O+M cost (GWH) $/MWH (%) TOTEM BT 2. 0.1 0.0 0.0 o. 0.0 126.1 0.0 BAILEY 13. 0.9 71.6 2. 20.2 89.6 17.7 EX. POND 33. 1.1 0.0 9. 60.2 50.9 TOTALS 48. 2. 2. 9. WW -- SUMMARY OF RESULTS FOR SYSTEM (2000) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 33.26 MW INSTALLED CAPACITY = 58.00 MW PER-CENT RESERVE = 74.40 PER CENT ANNUAL SYSTEM ENERGY = 168.97 GWH -- SUPPLIED BY SYSTEM = 168.97 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH Tn i MILLION DOLLARS ---~-~-~----~---~--- FIXED VARIABLE PURCHASE TOTAL COSTS COSTS POWER COST cost 2000 DOLLARS 4.4 10.8 0.0 15.2 1985 DOLLARS a0. 2.6 0.0 3.6 Gs . — crn oo _— coor oo — oo ——~) oo —— = PAGE 39 —- TFT" WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (2001) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. OUTPUT COST FACT AOD. cost O+M cost cost O+M cost (GWH) = $/MWH (%) DIES 3. 4 1.5 0.7 0.0 0.0 0.0 TOT. 10. 4 2. 1. Oo. -- SUMMARY OF RESULTS FOR EXISTING UNITS(2001) ~- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP O+M FUEL VAR TOTAL OuTPUT cost FACT (mw) (M$) cost O+M cost $/MWH (%) TOTEM BT 2. 0.1 0.0 134.0 0.0 BAILEY 13. 1.0 95.6 19.6 EX. POND lied 61.4 51.2 TOTALS 2. -- SUMMARY OF RESULTS FOR SYSTEM (2001) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD 33.87 Mw INSTALLED CAPACITY 58.00 mw 71.23 PER CENT 172.09 GWH 172.09 GWH 0.00 GWH PER-CENT RESERVE ANNUAL SYSTEM ENERGY -- SUPPLIED BY SYSTEM -- BOUGHT FROM INTERCONNECTIONS -o-2---------- MILLION DOLLARS ---------------- FIXED VARIABLE PURCHASE TOTAL COSTS COSTS POWER COST cOsT 2001 DOLLARS 4.5 11.3 0.0 15.8 1985 DOLLARS 1.0 2.5 0.0 3.4 PAGE 40 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM ~ VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (2002) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. OUTPUT COST FACT ADD. cost O+M cost cost O+M cost (GWH) = $/MWH (%) DIES 3. 4 1.5 0.8 2. 0.0 0.0 oO. 0.0 0.0 0.0 TOT. 10. 4 2. 1. 2. oO. oO. o. 0. -- SUMMARY OF RESULTS FOR EXISTING UNITS(2002) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP o+M FUEL VAR TOTAL OUTPUT CcOosT FACT (Mw) (M$) cost O+M cost (GWH) $/MWH (%) TOTEM BT 2. 0.1 0.0 0.0 oO. 0.0 142.4 0.0 BAILEY 13. 1.0 2.3 0.2 2 24.5 102.1 21.5 EX. POND 33. 1.1 0.0 9.4 9 150.7 62.7 51.5 TOTALS 48. 2: 2. 10. 2s 175. -- SUMMARY OF RESULTS FOR SYSTEM (2002) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 34.49 MW INSTALLED CAPACITY = 58.00 MW PER-CENT RESERVE = 68.18 PER CENT ANNUAL SYSTEM ENERGY = 175.22 GWH -- SUPPLIED BY SYSTEM = 175.22 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH -------------- MILLION DOLLARS ---------------- FIXED VARIABLE PURCHASE TOTAL cOsTS costs POWER COST cost 2002 DOLLARS 4.6 11.9 0.0 16.5 1985 DOLLARS 0.9 2.4 0.0 3.3 er oy — co a — om oo _ — lene piano! — oy PAGE 4) —= ss WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (2003) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. OUTPUT COST FACT ADD. COST O+M cost cost O+M COST (GWH) = $/MWH (%) OIES 3. 4 1.5 0.8 2. 0.0 0.0 oO. 0.0 0.0 0.0 TOT. 10. 4 Zs 1. 2. oO. oO. oO. o. -- SUMMARY OF RESULTS FOR EXISTING UNITS(2003) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP Oo+M FUEL VAR TOTAL OUTPUT cost FACT (mw) (M$) COST O+M cost (GWH) $/MWH (%) TOTEM BT Qe 0.1 0.0 0.0 oO. 0.0 151.3 0.0 BAILEY 13. 1.9 2.7 0.3 3. 26.7 108.9 23.4 —X. POND 33. 1.2 0.0 9.7 10. 151.7 64.0 51.8 TOTALS 48. 2. 3. 10. 13. 178. -- SUMMARY OF RESULTS FOR SYSTEM (2003) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 35.10 Mw INSTALLED CAPACITY = 58.00 MW PER-CENT RESERVE = 65.23 PER CENT ANNUAL SYSTEM ENERGY = 178.34 GWH -- SUPPLIED BY SYSTEM = 178.34 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH wecrec reno n--- MILLION DOLLARS ---------------- FIXED VARIABLE PURCHASE TOTAL COSTS cOsTS POWER COST CcOsT 2003 DOLLARS 4.7 12.6 0.0 17.3 1985 DOLLARS 0.8 2.3 0.0 3.1 WESTINGHOUSE AUTOMATIC GENERATION PLANNING PROGRAM - VERSION 3.3 -- SUMMARY OF RESULTS FOR UNIT ADDITIONS (2004) -- CASE = KETCHIKAN PUBLIC UTI UNIT CAP NO. FIXED COSTS (M$) VARIABLE COST(M$) ENERGY PROD CAP. NAME (MW) UNIT CAP. FIX TOT. FUEL VAR TOT. OUTPUT COST FACT ADD. cOsT O+M cost COST O+M cost (GWH) $/MWH (%) DIES 3. 5 2.1 1.1 3. 0.0 0.0 Oo. 0.0 0.0 0.0 TOT. 13. 5 2s he 3. o. o. oO Oo. ~- SUMMARY OF RESULTS FOR EXISTING UNITS(2004) -- CASE = KETCHIKAN PUBLIC UTI CLASS CLASS FIXED VARIABLE COSTS (M$) ENERGY PROD CAP. NAME CAP o+M FUEL VAR TOTAL OUTPUT cost FACT (mw) (M$) cost O+M COST (GWH) $/MWH (%) TOTEM BT Ze 0.1 0.0 0.0 Ox 0.0 160.8 0.0 BAILEY 13. 154 3.1 0.3 3. 28.8 116.3 25.3 EX. POND 33. 65.4 52.2 0.0 10.0 10. TOTALS 48. 2. 3. 10. 13. -- SUMMARY OF RESULTS FOR SYSTEM (2004) -- CASE = KETCHIKAN PUBLIC UTI ANNUAL PEAK LOAD = 35.72 MW INSTALLED CAPACITY = 60.50 MW PER-CENT RESERVE = 69.39 PER CENT ANNUAL SYSTEM ENERGY = 181.47 GWH -- SUPPLIED BY SYSTEM = 181.47 GWH -- BOUGHT FROM INTERCONNECTIONS = 0.00 GWH . menrecenn nn nme MILLION DOLLARS ----~-~----------- FIXED VARIABLE PURCHASE TOTAL COSTS COSTS POWER COST COST 2004 DOLLARS 5.5 13.3 0.0 18.9 1985 DOLLARS 0.9 2.2 0.0 3.1 PAGE 43