The URL can be used to link to this page

Home My WebLink AboutTransmission Intertie Kake Petersburg A Reconnaissance Report 1981TRANSMISSION INTERTIE KAKE-PETERSBURG,ALASKA A RECONNAISSANCE REPORT PREPARED FOR THE ALASKA POWER AUTHORITY PREPARED BY ROBERT W. RETHERFORD ASSOCIATES CONSULTING ENGINEERS ARCTIC DISTRICT OFFICE OF INTERNATIONAL ENGINEERING CO., INC. ANCHORAGE,ALASKA ALASKA POWER AUTHORITY STATEMENT OF FINDINGS AND RECOMMENDATIONS (To Accompany Report Entitled, Transmission Intertie Kake - Petersburg, Alaska, A Reconnaissance Report) NS, In TOR, a See neat malig Tenor was prepared on the hydroelectric potential of several Southeast Alaska communities. Kake was one of the villages surveyed. Two potential hydroelectric sites were investigated for the Kake area, . This preliminary appraisal suggested that ite. Following up Wn the earlier findings, a reconnaissance study was completed for Kake in 1979. The study included technical, economic and environmental evaluations of the two hydroelectric sites. This i project i i but economic i i . The repor a look be taken of other alternatives including wood-fueled generation and trans- _ RW a This second reconnaissance report was completed in January 1981. The study addressed the technical, economic and environmental aspects of possible trans- mission tielines and of a wood waste fired steam plant. These results were compared to the previous analysis of the hydroelectric projects. The assumptions for this analysis are consistent with economic analysis and cost of energy analysis parameters adopted by the Power Authority on August 29, 1980 and include general inflation at 7%, i and aeeeneanhitaiiedin Viostahiadjpeniassugruusioneaaiee atti ne Pit aliadog v1? 126.1 million kwh's of firm energy available for sales. The cost of energy is based upon sales to Petersburg, Wrangell, and THREA at Kake with a cold storage load at Kake. : The State of Alaska has already appropriated $17 million for development of Lake Tyee. The remainder of the capital needs is assumed to be obtained from the tax exempt revenue bond market at an interest rate of 11%. Any additional The Kake-Petersburg transmission line construction cost estimate is SAB ABHONM) 41-1989 for a conventional three-phase, 34.5 KV, 47-mile line. With ann or the line calculated at $1,000/mile and total investment costs equaling bee including inflation and contingency, the annual cost of the z 1985 transmission line cost of 10.6¢/kwh — This represents a are included, the even with REA 2% financing, despite the fact that the \ project is shown to be economically justified in comparison to continued diesel .s generation. ye ' 4 Lose é — pres f2 Page 1 ALASKA POWER AUTHORITY Kake Load ine ly dec 5 Flint jy Tye froject a r The wholesale cost of power to Petersburg and Wrangell, without the Kake energy sales, is estimated to be 30.8¢/kwh in 1985. As stated above, the wholesale cost of power, including the Kake loads, would be 28.0¢/kwh if the Kake transmission line costs are not included in the Tyee Lake Project cost of energy analysis. issi i i inancing over 30 years. Clearly, it is advantageo all wholesale power customers to include Kake in the power market for Lake Tyee power, and it is most feasible for THREA, in Kake, if the costs of the trans- mission line are included in the Lake Tyee project debt. Additional considerations are that the REA should provide a lien accom- modation to the Power Authority to subordinate REA debt payments to obligations of the Authority to bond purchasers. An advantage to REA is that the REA debt would be more secure depending upon the structure and covenants of the project financing. It is presently anticipated that i The Therefore, there should be no additional cost/kwh for amortization of State and REA loans, and 17.9¢ in 1995. The advantages to the Tlingit-Haida Regional Electrical Authority at Kake from this arrangement are significant whether or not increased state assistance in financing the Lake Tyee project occurs, since the cost of energy from the project will be equivalent to or less than the costs of diesel gene- ration in 1985. Further, this arrangement is preferable to other generation alternatives studied. feat neta Pending a favorable decision from those discussions, detailed feasibility analysis, route selection and design should be undertaken in a manner and according to a schedule that would permit the Kake-Petersburg trans- mission to be commissioned not later than December 1983, the anticipated Tyee Project power-on-line date. “initiated. 7 ; ae , wo Lb Sra - 11% finar cig for Tyek , 2H Frnantivg FOr Ka ky Flin 19385 199¢ } 995 , Tee t ; ney Tyee we Kak 30. 8 dard _— 743 kwh Seas a lh > U4>3) ( 7) anuary, Yee wf, Ka ke a ; ; 4oad, wh J~Lint 29,0 ~ —t Thine Costs 40.6 Tyee n] ka ke i Lord wW/FELing 2809 ZZ 17, 99/ kwh A$. ZF ¢ 554 oh o feest on TVyse TRANSMISSION INTERTIE KAKE-PETERSBURG, ALASKA A RECONNAISSANCE REPORT Prepared for: ALASKA POWER AUTHORITY Prepared by: ROBERT W. RETHERFORD ASSOCIATES A DIVISION OF INTERNATIONAL ENGINEERING COMPANY, INC. ANCHORAGE, ALASKA January 1981 RWRA - Contract No. 2709 This report has been prepared by Dora L. Gropp, P.E. Frank J. Bettine, E.1.T. EERE RISE z Sennen ounce CONSULTING ENGINEERS 5 ed ROBERT W. RETHERFORD ASSOCIATES ARCTIC DISTRICT OF INTERNATIONAL ENGINEERING CO., INC. PO. BOX 6410 ANCHORAGE, ALASKA 99502 PHONE (907) 344-2585 / TELEX 626-380 January 27, 1981 “2709-001 Alaska Power Authority 333 W 4th Avenue, Suite 31 Anchorage, Alaska 99501 Attn: Mr. Eric Yould, Executive Director Subject: Reconnaissance Study of a Transmission Intertie between Kake and Petersburg, Alaska Dear Mr. Yould: We are pleased to present the final report for the reconnaissance study of a transmission intertie between Kake and Petersburg. The study includes technical, economic and environmental evaluation of possible transmission tielines and of a wood waste fired steam plant. It is recommended that a transmission tie be constructed in time to connect Kake to the interconnected Petersburg/Wrangell system when the Tyee Lake Hydro Project becomes operational This study has been conducted using cost and energy data for the Tyee Project taken from the Definite Project Report of December 1979. Recent studies indicate that changes in design would increase the energy output of the project substantially. It is expected that in spite of the higher initial costs of the project, the economic impact on a trans- mission tie to Kake would be beneficial since the increase in available energy would eliminate the need for diesel generation in the later years. The following paragraphs will briefly describe the investigations per- formed: Transmission Intertie The route selected for this study resulted in 45 miles of overhead lines and 2 miles of submarine cables. Transmission of 1.5 MW required power has been investigated for the following configurations and voltage levels: INTERNATIONAL ENGINEERING COMPANY, INC. A MORRISON-KNUDSEN COMPANY INTERNATIONAL ENGINEERING COMPANY, INC. Mr. Eric Yould January 27, 1981 Page 2 2709-001 24.9 kV-three phase 34.5 kV-three phase _ 69 kV-three phase 40 kV-Single Wire Ground Return Due to the lower investment required for the unconventional 40 kV-SWGR line (1980-$3,130,000) compared to 34.5 kV three phase construction (1980-$5 , 185,000), this alternative is recommended for implementation. _ Wood Fueled Generation | oooo Utilization of wood waste in a steam-fired generating plant of 1.5 MW has been investigated. The wood waste could be either locally available or shipped to Kake from lumber mills in Southeastern Alaska. Resource availability and costs are deciding factors for the viability of this alternative. Investment costs for the generating plant are estimated at -1980-$3,600,000 and hog fuel at $30.00/5,000 Ibs It is anticipated that logging operations near Kake could produce sufficient wood waste to supply the generating plant requirements for the next 20 years. Economics All alternate development plans have been compared to the continued use of diesel generation. It has been found that the cost ratios for con- struction of such a transmission line intertie are greater than one for all interest rates making such a line very attractive. It can also be noticed that benefit to cost ratio is highest for a SWGR line closely followed by a more conventional 3-phase 34.5 kV line. Wood-steam gen- eration is beneficial only at the higher load created by the cold storage fackhitiesss The Cathedral Falls Hydro Project and a wood-steam generation plant appear to be cost competitive, but overall less attractive than a trans- mission tie to the system connected to the Tyee Lake Project. Recommendations A transmission tie to the system supplied by the Tyee Lake Project appears to be the most economical source of electric energy for Kake in the future and steps to implement it should be taken as soon as prac- ticable. The most important items to be clarified are: e Assure availability of power from the Petersburg, Wrangell, Tyee interconnected system. INTERNATIONAL ENGINEERING COMPANY, INC. A MORRISON-KNUOSEN COMPANY Mr. Eric Yould January 27, 1981 Page 3 2709-001 e Investigate financing and ownership of the tieline. ° Assess the environmental impact and finalize routing of the tieline. Sincerely, Ii a hy Tanzeém Rizvi{//P.£ TR: tfd Enclosure ACKNOWLEDGEMENTS We would like to thank THREA for making power requirements and operating data for the Kake area available for this study and the Alaska Power Auhtority who released data from the Tyee Lake Hydro Project Definite Project Report. The U.S. Department of Agriculture, Forest Service, the U.S. Department of the Interior, Fish & Wildlife ~ Service and the State of Alaska, Department of Fish and Game were | very helpful in determining a transmission line route that would be acceptable to all concerned parties. SECTION apal7/b4 TABLE OF CONTENTS INTRODUCTION AND SUMMARY 1.1 Introduction 1.2 Summary A. Energy and Power Requirements B. Transmission Intertie C. Wood Fueled Generation D. Economic Analysis 1.3. Recommendations ELECTRIC ENERGY AND POWER REQUIREMENTS 2.1 Existing Facilities 2.2 Power & Energy Forecast 2.3. Projected Power and Energy Demand TRANSMISSION INTERTIE 3.1 Technical Requirements 3.2 Route Selection 3.3. Environmental Impact 3.4 Cost Estimates 3.5 Operational Considerations WOOD FUELED GENERATION 4.1 Resource Assessment 4.2 Conceptual Plant Design 4.3. Environmental Impact 4.4 Cost Estimates 2-1 2-2 3-2 3-5 3-6 4-1 4-1 4-2 SECTION 5 ECONOMIC ANALYSIS 5.1 Introduction 5.2 Diesel Generation 5.3. Cathedral Falls Hydro Project 5.4 Wood Fueled Generation 5.5 Transmission Interties 5.6 Summary 6 RECOMMENDATIONS 6.1 Development Plans 6.2 Institutional and Financial Considerations APPENDICES A Technical Information and Cost Estimates A.1 Transmission Line Characteristics and Performance Data A.2 Wood Fueled Generation A.3. Transmission Line Cost Estimates B Economic Analysis Details B.1 Alternate Development Plans B.2 Parameters Used for the Economic Evaluation B.3. Explanation of Computer Printouts Cc Letters and Comments D References apal7/b5 -ii- PAGE 6-1 6-2 A-1 A-7 A-14 B-1 B-1 TABLES DOr nwn nner nO FIGURES > > FW WwW ee apal7/b6 LIST OF TABLES KAKE ELECTRIC POWER AND ENERGY REQUIREMENTS BUSBAR AND INVESTMENT COST SUMMARY KAKE ELECTRIC SYSTEM EXISTING POWER & ENERGY REQUIREMENTS KAKE ELECTRIC POWER & ENERGY REQUIREMENTS TRANSMISSION LINE COMPARISION SUMMARY ECONOMIC ANALYSIS SUMMARY COST RATIOS TRANSMISSION LINE ELECTRICAL PERFORMANCE FUEL COST FOR KAKE IN DOLLARS/GALLON SURPLUS HYDROELECTRIC ENERGY & BUSBAR COST LIST OF FIGURES KEY MAP KAKE-PETERSBURG INTERTIE CLEARING RIGHT-OF-WAY GUIDE WOOD FIRED STEAM POWER PLANT FLOW DIAGRAM TRANSMISSION LINE TANGENT STRUCTURE - PIN TYPE TRANSMISSION LINE TANGENT STRUCTURE - SINGLE POLE SUSPENSION - DOUBLE ARM "A"-FRAME STRUCTURE - POST INSULATORS - iii - PAGE PAGE 1-2 a7 4-3 A-3 A-4 A-6 SECTION 1 INTRODUCTION & SUMMARY SECTION 1 INTRODUCTION & SUMMARY 1.1 INTRODUCTION The Community of Kake, population about 700, is located on the Northwest tip of Kupreanof Island in southeastern Alaska, approxi- mately 40 air miles northwest of Petersburg, Alaska. (See Figure 1.1). The majority of the inhabitants of the area are Alaskan natives, predominantly Tlingit Indian. The island topography is characterized by steep mountain ranges, narrow fjords, dense growths of timber, large tidal fluctuations, bays, inlets and streams, rivers, abundant wildlife, and super- abundant sea life. The climate is very mild compared to other parts of Alaska but tends to be very wet. Rainfall averages in excess of 40 inches per year. The moderate and damp climate is primarily the result of a branch of the warm Japanese ocean current which flows northerly along the southeast coast and the large mountain ranges which tends to "screen off" the coastal zone from the harsh winter climate of the interior. The area if fairly windy and at times can be spectacularly so. Recorded sea-level winds of over 100 knots are common. A transmission line south of Juneau on an exposed ridge was blown down by winds in excess of 220 knots. The economic base is extremely narrow: fishing, timber and government. Tourism is increasing but remains limited to the urban areas which have established tourist facilities. The native Regional and Village Corporations have plans for industrial developments in timber, fisheries, tourism and minerals, but these plans are severely impacted by high energy costs. apal7/c i= 1 b \Sokofoy Ta Mga Pea island a . Levd! Islands gs ee . Mitchell PordRl ( WORON| Sumner island a7 Ne sh % STRAIT Maz iT a g p i ao hs Vi ed nae," Poin ei : HD NN bes A: ¥% mets ¢ YS do “ETOH Pe Pistons ; oa i ‘ Wg >} ues >] ‘ > emg ¥ oF Point Saint Albin: } 2 my ih g : ~— 5 7 §) ALASKA | J ,om Fanpanns \ oh \sTupy aycronae| AREA VICINITY MAP Ls2 FIG 1-1 KEY MAP INTERNATIONAL ENGINEERING COMPANY, INC. A MORRISON-KNUDSEN COMPANY Life in the villages revolves heavily around the seasonal economy: fishing and logging activities take place only in the summer months. There are very little year-round employment opportunities and these tend to be low paying government or service oriented jobs. In 1979 a reconnaissance-level study of the Cathedral Falls Hydro- electric Potential was undertaken. The report conducted that development of this potential could only be recommended at low interest rates (< 5%) and suggested that other alternatives to continued diesel generation be investigated. Based on this report, it was decided to proceed with a reconnaissance-level study of a transmission intertie between Kake and the City of Petersburg. This would be a 47 mile transmission line and would use power from | the interconnected systems of Petersburg, Wrangell and the proposed Tyee Lake hydroelectric project. Development of a hydro project at Cathedral Falls has been postponed in favor of the transmission project. Robert W. Retherford Associates (RWRA), the Arctic District Office of International Engineering Company, Inc. (IECO), has been engaged by the State of Alaska, Alaska Power Authority (APA), to undertake this reconnaissance level study with focus on a transmission tieline to Petersburg. This report also includes identification, engineering and economic feasibility analysis, and environmental assessment of other potential energy resources and conversion technologies that might provide for local electrical generation uses. 1.2 SUMMARY A. Electric Energy and Power Requirements The Tlingit-Haida Regional Electrical Authority (THREA), REA designation: Alaska 28 THREA, a rural utility with offices in Juneau, Alaska, serves Kake and (4) additional small villages located throughout Southeast Alaska on islands of the Alexander Archipelago. Generation in the community of Kake is with diesel-electric sets. Busbar costs have risen spectacularly during the past five years to the present cost of $0.22 per kWh. This is caused by high fuel and labor costs. It is expected that the trend will continue. There is some use of electric energy for comfort and water heating. The costs are so high however, that most consumers are utilizing or converting to oi]. The major source of heat is fuel oi] with some wood stoves used either as a primary or secondary heat source. Residential electric loads are primarily from kitchen appliances, ranges, radio-T.V., refrigerators, freezers, and washing machines. apal7/c i= 3 There are few clothes dryers. There are at present only two large commercial loads, Soderberg Logging and Construction and Kake ~ Public School. The Kake Tribal Corporation has been involved for sometime in the — _ construction of a cold storage facility. This facility could double Kake's consumption and could produce a significant decrease in unit operating costs system wide. The cold storage facility is not complete as yet and it is doubtful whether it will be connected to the THREA system. Load data have therefore been developed for both cases. TABLE 1.1 KAKE ELECTRIC POWER AND ENERGY REQUIREMENTS With Cold Storage Without Cold Storage Year _kW_ MWh kW MWh 1980 482 1902 482 1902 1981 508 2008 508 2008 1982 534 2114 534 2114 1983 777 3390 560 2220 1984 801 3480 584 2310 1985 825 3570 608 2400 1986 849 3660 632 2490 1987 873 3750 656 2580 1988 897 3840 680 2670 1989 944 4042 708 2780 1990 991 4264 736 2890 1991 1038 4476 764 3000 1992 1085 4688 792 3110 1993 1132 4900 820 3220 1994 1160 5013 848 3333 1995 1188 5126 876 3446 1996 1216 5238 904 3558 1997 1244 5351 932 3671 1998 1272 5464 960 3784 1999 1300 5575 988 3895 2000 1328 5685 1016 4005 apal7/c 1-4 Future energy and power requirements for Kake (with and without the cold storage load) have been based on a 1979 power requirement forecast prepared for the utility (THREA) and from data obtained from the Cathedral Falls Project Report. Table 1.1 shows electric power and energy demands for the community. B. Transmission Intertie The construction of a transmission tieline from Kake to Petersburg to receive energy from the interconnected system of Petersburg, Wrangell and the Tyee Lake hydroproject energy is the most promising alternative examined in this study for supplying lower cost electric energy to Kake. Two types of transmission lines operating at four different voltage levels were examined. In addition four alternative routes for the proposed tieline were studied. Three alternatives using standard REA three phase construction and operating at 24.9 kV, 34.5 kV or 69 kV were investigated. In addition an unconventional Single Wire Ground Return (SWGR) trans- mission system was examined. The results of this analysis indicate that one of the following two types of tieline should be constructed: (1) a three phase 34.5 kV tieline initially energized at 24.9 kV or (2) a 40 kV SWGR tieline!. Initial investment requirements favor the SWGR tieline by a margin of $2,455,000 or about 71% of the conventional alternative. Phase converters would add some cost to the SWGR system. Converter costs are estimated to be $15,000 for the low load (without cold storage) and about $30,000 with the cold storage plant added. These converter costs are therefore of relatively small impact on choices. The transmission route selection is complicated by the many special land use designations and environmentally sensitive areas found with the Tongass National Forest. The most promising route, Route #1, (See Figure 3-1 "Kake-Petersburg Intertie") is 47 miles long, (45 miles overhead, 2 miles submarine). This proposed routing was selected with the help of federal, state and local agencies. 1 A demonstration SWGR project is presently under construction in the Bethel area and is expected to be completed and undergoing testing by the end of October 1980. Successful operation of this project is expected to increase the use of this type of line construction. apal7/c ins C. Wood Fueled Generation The investigation of a wood-waste fired generation plant, to assess its potential as an alternate energy source for Kake yielded encouraging results. Cost estimates indicate that a 1,500 kW wood-fired steam plant can be constructed at Kake for approximately $2,400 per installed kW. Wood gasification was examined, but was discarded as being too costly with the use of presently available commercial equipment. The single greatest limitation to the use of a wood-fired generation is the availability of cheap wood-waste in Kake. Presently, the majority of wood-waste produced from saw mills in southeastern Alaska is being utilized by the two pulp mills in Sitka and Ketchikan. Other possible sources of wood-waste are from the numerous logging operations near Kake. These operations generate a substantial volume of wood-waste materials and could provide a supply of hog fuel which should average the pogui red 10,000 tons per year | for the next 20 ears. 5 this >] D. Economic Analysis a A summary of the results of the analysis for the various alternatives outlined before is listed in Table 1.2 "Busbar and Investment Cost Summary". This summary is presented using THREA + cold storage load and an interest rate of 7%. Comparison of the busbar cost, required capital investment cost and accumulated present worth cost of annual costs clearly indicates that the most cost effective alternative is the 40 kV, SWGR transmission tieline. This alternative results in the lowest energy costs, and lowest accumulated present worth cost of electric energy during the course of this 20 year study. This alternative, though using an unconventional transmission line is a viable, technically feasible option using well proven state-of-the-art. Results also show that if the relatively unconventional 40 kV, SWGR tieline is not acceptable, a 34.5 kV three phase tieline should be constructed. The 34.5 kV tieline, though 2.5 million dollars more costly than the 40 kV, SWGR tieline, is anticipated to provide energy at lower cost than the remaining alternatives. The Cathedral Falls Hydro Project and the wood-fired steam generator alternative appear to be price competitive with one another but more costly then either transmission scheme. Wood-fired generation results in slightly lower energy costs and smaller investment costs than Cathedral Falls. The decision as to which of these two alterna- tives is the more beneficial would require more detailed investigation especially in regard to the availability, quality and costs of the wood-waste. apal7/c 1-6 Diesel generation, as expected, is the most costly alternative after wood-fired steam generation and should be avoided if at all possible. Examination of the detailed calculations in A j il] reveal that the eniaisinenyueneniomnetenreten ee ae _ matives listed above is retained for the two load levels and ste a TABLE 1.2 BUSBAR AND INVESTMENT COST SUMMARY! Busbar Cost $/kWh Accu- Investment mulated? Cost $1,000 Alternative 1980 - 1990 2000 P.W. 1980 1990 2000 40 kV, SWGR T-Line 0.219 0.366 0.320 11,607 1800° 5903 5903 34.5 kV, 30 T-Line 0.219 0.409 0.353 12,708 18002 8270 8270 Catherdral Falls Hydro 0.219 0.408 0.648 =3 1800° 8900 8900 Wood-Fired 0.219 0.417 0.571 13,295 1800° 6210 6210 Diesel 0.219 0.450 1.131 15,510 1800° 1800 1.3 RECOMMENDATIONS The economic analysis favors the development of either a 40 kV, SWGR transmission tieline or a 34.5 kV, three phase tieline from the community of Kake to Petersburg to provide Kake with lower cost energy at the time when the Tyee Hydro- electric Project is operational. The lower cost of the above two options is the 40 kV, SWGR tieline which would save about 2.5 million dollars in investment. issi ieline with the objective of completing construction of the tieline when the Tyee Lake hydroelectric project is brough on-line. Operation and ownership of this line could be either with THREA or the Alaska Power Authority/Thomas Bay Power Commission with THREA purchasing energy from the operator of the interconnected systems. 10% = Accumulated\present worth of annual costs in 1000-$ for study period at discount rate. This data not available from the Cathedral Falls Project Reconnaissance Report. 4 Diesel generation only 5 Existing diesel plant apal7/c dy 2944 SECTION 2 ELECTRIC ENERGY AND POWER REQUIREMENTS SECTION 2 ELECTRIC ENERGY AND POWER REQUIREMENTS 2.1 EXISTING FACILITIES Kake is served by the Tlingit-Haida Regional Electrical Authority (THREA), a rural electric cooperative with offices in Juneau, Alaska, which serves Kake and four additional towns in Southeast Alaska. All power in the Kake area is generated by small diesel-electric units. The power is distributed from the powerhouse and there are no transmission lines interconnecting the town with other areas. Table 2.1 lists the generating units serving the area. All units are owned and operated by THREA. TABLE 2.1 KAKE ELECTRIC SYSTEM EXISTING DIESEL GENERATION FACILITIES Nameplate Capacity (kW) Unit No. Unit Total 1 500 2 500 3 300 4 300 1,600 2.2 POWER AND ENERGY FORECAST The forecast of future electric energy and power needs of Kake is based on a current power requirements forecast prepared for the utility (THREA) and from data obtained from the Cathedral Falls Project Report[1] concerning cold storage consumers. A forecast of the power and energy requirements is as shown in Table 2.2. apal7/d 25.5 TABLE 2.2 POWER AND ENERGY REQUIREMENTS 1978 1983 1988 1993 1998 Peak demand, kW THREA 430 560 680 820 960 Cold Storage . 370 370 530 530 Energy, MWh/yr. THREA 1690 2220 2670 3220 3784 Cold Storage 7 1170 1170 1680 1680 Future requirements for THREA in Kake have been estimated by a Rural Electrification Administration (REA) team[2] in cooperation with THREA. The May 1979 Power Requirements Forecast, covering 10 years, was the result of these efforts. Over the 20 year study period, per capita consumption is assumed to remain substantially constant with load growth coming from new connections. The combined load (THREA + cold storage) is forecast to increase at 3.6 percent per year. 2.3 PROJECT POWER AND ENERGY DEMAND The year by year power and energy requirements for Kake with and without cold storage is as shown in Table 2.3. Data has been interpolated linearly from the information in Table 2.2. A coincidence factor of 1.7 has been applied to the cold storage loads for estimating peak coincidential system demand with cold storage. NOTE: [ ] numbers refer to references listed in Appendix D. apal7/d are TABLE 2.3 KAKE ELECTRIC POWER AND ENERGY REQUIREMENTS With Cold Storage Without Cold Storage Year kW MWh kW MWh 1980 482 1902 482 1902 1981 508 2008 508 2003 1982 534 2114 534 2114 1983 777 3390 560 2220 1984 801 3480 584 2310 1985 825 3570 608 2400 1986 849 3660 632 2490 1987 873 3750 656 2580 1988 897 3840 680 2670 1989 944 4042 708 2780 1990 991 4264 736 2890 1991 1038 4476 764 3000 1992 1085 4688 792 3110 1993 1132 4900 820 3220 1994 1160 5013 848 3333 1995 1188 5126 876 3446 1996 1216 5238 904 3558 1997 1244 5351 932 3671 1998 1272 5464 960 3784 1999 1300 5575 988 3895 2000 1328 5685 1016 4005 apal7/d O43 SECTION 3 TRANSMISSION INTERTIE SECTION 3 TRANSMISSION INTERTIE 3.1 TECHNICAL REQUIREMENTS The transmission line planned to connect Petersburg to the Tyee Lake Hydro Project has sufficient capacity to carry the additional load in Kake without experiencing unduly high voltage drops or power losses. Further investigations in regard to the adequacy of this line are not considered to be necessary for the purpose of this study. The requirements of a 47 mile transmission tieline with a power transfer capability of 1,350 kW at less than 10 percent voltage regulation, between the communities of Petersburg and Kake, Alaska have been technically assessed. Four alternatives were examined in some detail. Transmission line voltages of 24.9 kV, 34.5 kV and 69 kV using standard three phase REA overhead construction were investigated. In addition information regarding the use of a Single Wire Ground Return (SWGR) transmission system operating at 40 kV line-to-ground, employing an unconventional "A'"-frame structure (See Appendix A) and standard single pole design is included. Such a SWGR system is presently under construction near Bethel, Alaska. A comparison summary of the electrical performance and cost per mile of the four alternatives investigated is shown in Table 3.1 “Transmission Line Comparison Summary". Calculations of the electrical and mechanical performance of the transmission tieline for either three phase or SWGR construction have been based upon the use of 4/3 Alumoweld Aluminum Conductor (AWAC) with a rated breaking strength of 14,500 pounds. This conductor is electrically equivalent to AWG 3/0 ACSR. The use of this type of conductor maximizes span lengths while simultaneously maintaining adequate electrical performance and lowering construction costs. apal7/e 3.7L TABLE 3.1 TRANSMISSION LINE COMPARISON SUMMARY! Percent? Voltage Alternative Structure Design Regulation Cost/Mi. 24.9 kV, 36 Single Pole 7.7% $90,000 Double Crossarm 34.5 kV, 36 Single Pole 4.2% $91,000 Double Crossarm 69 kV, 38 Single Pole 0.6% $97 ,000 Suspension Ins. 40 kV, SWGR Single Pole 4.5% $73,000 Post Insulator 40 kV, SWGR Wood Pole 4.5% $58,000 "A"-Frame 3.2 ROUTE SELECTION Suggested transmission line route alternatives are as shown in Figure 3.1 "Kake-Petersburg Intertie". Routings were selected after consultations with the U.S. Forest Service, U.S. Fish and Wildlife and the State of Alaska, Department of Fish and Game. A description of the various routes investigated for the transmission line are as follows: See Appendix A for transmission line characteristics and performance calculations. At 1,350 kW power transfer, load power factor 0.90, distance 47 miles. 3 Estimated from SWGR construction costs in Bethel, Alaska. apal7/e 3-22 R.78& 133° T 2 ”, Wooa Pr é "we * “Ping, z Cl. = nde crest. a24n0s 1 eLe9s 000‘0Sz @INOY 21q1SSOg }SAI4OYS —meeee uo13zsebbng ajnoy awey 3 ysiy *3deqg yy ——-— Db z EES bys a, buerspend Bangssaieg *s°9°S'"f JILYSLNI SUNISYALId-INWy Snes suo13seb6ng | “wow USFS Ce ag Se USFS AEB o apal7/e Route #1 - length 47 miles (45 miles overhead, 2 miles submarine) -- This route closely follows the suggested routing of the U.S. Forest Service and U.S. Fish and Wildlife. The transmission line would cross the Wrangell Narrows via submarine cable, run overhead along the Tonka Mountain Forest Service road, cross the Duncan Canal via underwater cable south of Mitchell Slough. The transmission line would then run overhead northwest through the Big John Creek, Hamilton Creek and Cathedral Creek watersheds to Kake. This routing attempt is to avoid environmentally sensitive and special land use areas. This routing confines at least parts of the transmission line to areas which have received some initial disturbance. Route #2 - length 50 miles (49.4 miles overhead, 0.6 miles submarine) -- The transmission line would cross the Wrangell Narrows via submarine cable in the Petersburg area, follow the east shore of the Lindenberg Peninsula north to the Twelve Mile Creek Valley, then westward through the valley passing south of Portage Bay and north of Kupreanof Mountain and then continue westward to Kake. This «lternative has some disadvantage in that it runs approximately twelve miles along the Fredrick Sound Shore line and may, in places, be very difficult to conceal. Route #3 - length 45 miles (44 miles overhead, 1 mile submarine) -- This route crosses the Wrangell Narrows via submarine cable, runs overhead along the Tonka Mountain Forest Service road, proceeds northwest prior to crossing the Duncan Canal, turns westward in the valley south of Portage Bay and north of Kupreanof Mountain and then continues westward to Kake. This routing was recommended by the State of Alaska, Department of Fish and Game. Route #4 - length 43 miles (42 miles overhead, 1 mile submarine) -- This route follows the shortest and most direct route the terrain will permit. The route crosses several environmentally sensitive areas, areas designated as LUD 1 and LUD 2 lands as well as areas which have high recreational, fish and wildlife values. It is anticipated this routing would be vigorously opposed by environmental and conservation organizations along with the three previously mentioned agencies. 3.3 ENVIRONMENTAL IMPACT Although the transmission line routes shown in Figure 3.1 will probably have minimal environmental impact there will be some disturbance and clearing. This could reduce or modify aesthetic qualities and fish and wildlife habitat which exists within the alignment of the routes. The entirety of Kupreanof Island except for a narrow strip along the Wrangell Narrows is contained within the Tongass National Forest and is managed by the U.S. Forest Service (FS) under the Tongass Land Management Plan. Special land use designations within the Tongass National Forest (i.e. LUD 1, LUD 2, etc.) imposed by the FS has placed further restrictions on certain areas through which certain alternative routes may traverse. Management of these areas by the FS excludes roads, manipulation of vegetation, timber harvesting and other activities. (See Appendix C). An environmental assessment report should be prepared once a definite line route and configuration is chosen to sufficiently delineate project related impacts. The assessment report should provide at least the following information: the type and height of structures to be used, the distance between structures, construction methods (i.e. footing construction, tower construction, construction schedules), the length, width and location of right-of-way clearing, maintenance methods and schedules, unstable soil conditions, habitat use, migratory flyways and small aircraft use patterns. The required right-of-way clearing for the line construction types investigated for the intertie to Kake is illustrated on Figure 3.2 "Clearing of Right-of-Way Guide". This guide is valid for all line designs investigated in this study. The wood pole construction for the "conventional" three phase lines will generally require a pole hole depth of approximately 6 to 8 feet and a diameter of 3 feet which will be backfilled with gravel. The A-frame structure for the Single Wire Ground Return Line does not require pole holes but rests on the surface, reinforced with bogshoes if soft terrain makes this necessary. The A-frame structures can be erected completely without the use of heavy construction equipment. It is therefore anticipated, that this type of construction will pose the least adverse impact on the environment during construction. The average span lengths (distance between structures) calculated for the 4 line types investigated are: 24.9 kV 36 525 feet 34.5 kV 39 525 feet 69 kV 30 750 feet 40 kV 1g 750 feet Average structure height would be 30 feet to 60 feet. apal7/e 355 3.4 COST ESTIMATES Detailed cost estimates for 24.9 kV, 34.5 kV and 69 kV three phase construction or 40 kV SWGR construction are listed in Appendix A.3. The costs of constructing a tieline from Kake to Petersburg using the above cost estimates along the most probable route (Route #1, 45 miles overhead, 2 miles underground) are calculated as follows: apal7/e 3-6 CLEARING RIGHT-OF-WAY GUIDE Jon 1,1962 FIG. 3.2 | U. S. GOVERNMENT PRINTING OFFICE : 1973 © - 527-795 For sale by the Superintendent of Documents, U.S. Government Printing Office Washington, D.C. 20402 - Price $2.25 3-7 A. Alternative, 24.9 kV, 38 Item Quantity Unit Cost (1980-$) Total Overhead Line 45 mi. $90,000 $4,050,000 Submarine Cable 2 mi. $420,000 840 ,000 Substation - - - Total Investment (1980-$) $4,890,000 B. Alternative, 34.5 kV, 38 Item Quantity Unit Cost (1980-$) Total Overhead Line 45 mi. $91,000 $4,095 ,000 Submarine Cable 2 mi. $420,000 840 ,000 Substation 2 $125 ,000 250,000 Total Investment (1980-$) $5,185,000 C. Alternative 69 kV, 39 Item Quantity Unit Cost (1980-$) Total Overhead Line 45 mi. $97,000 $4,365,000 Underwater Cable 2 mi. $506 ,000 1,012,000 Substation 1 (138/69 kV) 175,000 Substation 1 (69 kV step down) 145,000 Total Investment (1980-$) $5,697,000 D. Alternative, 40 kV, SWGR, A-Frame Design Item Quantity Unit Cost (1980-$) Total Overhead Line 45 mi. $58,000 $2,610,000 Underwater Cable 2 mi. $230,000 460 ,000 Substation 2 $30,000 60,000 Total Investment (1980-$) $3,130,000 apal7/e 3-8 E. Alternative, 40 kV, SWGR, Single Pole Design Item Quantity Unit Cost (1980-$) Total ‘Overhead Line 45 mi. ~ $73,000 $3,285 ,000 Underwater Cable 2 mi. $230,000 460 ,000 Substation 2 $30,000 60,000 Total Investment (1980-$) $3,805,000 The 40 kV SWGR tieline utilizing A-frame design would represent the lowest initial investment. If a more conventional 38 line is considered, the 24.9 kV alternative appears to be the most favorable one. 3.5 OPERATIONAL CONSIDERATIONS Comparision in Table 3.1 "Transmission Line Comparison Summary" will show that while electrical performance of the 24.9 kV, 38 tieline is adequate for serving the estimated 1,350 kW load requirement of Kake in the year 2000 a higher operating voltage would prove mo.e desirable in later years as the Kake load continues to grow. A major advantage of operating the tieline at 24.9 kV is, however, that a tap can be made directly to the Crystal Lake Hydro Line in Petersburg subsequent to its upgrade to 24.9 kV. This tap can be accomplished without adversely affecting Petersburg once the Tyee Lake Hydro Project is operational. This would reduce the required initial investment by eliminating the immediate need for new substations at each end of the tieline. An approach which could provide both economy and adequate electrical service in future years would be to construct the tieline for 34.5 kV operation but initially energize it at 24.9 kV by tapping into the Crystal Lake Hydro Line. The cost of 24.9 kV and 34.5 kV long span construction are comparable. At some future date, when load conditions warrant it, 34.5 kV transformers could be installed and the line could be operated at its design voltage. Technical data listed in Appendix A, will show that 34.5 kV is a suitable voltage with which to serve the future power requirements of Kake. This approach will be assumed throughout the remainder of the report. The use of 69 kV, while minimizing voltage drop, is excessively costly. In addition this voltage is not well suited to the load as projected. The relative light loading of the tieline would require the use of compensation reactors at the 69 kV voltage level. For these reasons the use of 69 kV transmission voltage will not be considered further. apal7/e 3-9 voltage with which to serve the future power requirements of Kake. This approach will be assumed throughout the remainder of the report. The use of 69 kV, while minimizing voltage drop, is excessively costly. In addition this voltage is not well suited to the load as projected. The relative light loading of the tieline would require the use of compensation reactors at the 69 kV voltage level. For these reasons the use of 69 kV transmission voltage will not be considered further. Table 3.1 "Transmission Line Comparison Summary" also shows that a 40 kV SWGR transmission system has essentially the same power transfer capability as the 34.5 kV, 3% tieline but at substantially less cost. Successful operation of a SWGR demonstration project, presently in the final phases of construction near Bethel, Alaska is expected to encourage further use of this type of line. See Appendix A for further explanation of the SWGR concept. With the single pole construction being estimated more than 25% higher in initial investment costs, only the A-frame design is given further consideration in this study. apal7/e Sno SECTION 4 WOOD FUELED GENERATION SECTION 4 WOOD FUELED GENERATION 4.1 RESOURCE ASSESSMENT The cost and availability of suitable wood-waste products to fire a wood-waste generation plant in the Kake area is difficult to accurately assess. It is estimated, however, that ample wood-waste and hog fuel will be available to satisfy the average of 10,000 tons per year fuel requirement for a wood-fired plant. Currently the majority of wood chips produced from the local saw mills are being utilized by the two pulp mills. The moisture content of those chips is averaging about 50 percent. The Kake Native Corporation is presently logging about 20 million board feet of timber per year. This generates a substantial volume of wood-waste material that might be used for hog fuel. By "Yum" yarding (yarding of unmerchantable materials) from all the cutting units, considerable volume of wood-waste might be obtained. Another possible future source of material is a field chipping operation at Rowan Bay near Kake which is planned by Alaska Lumber and Pulp Company. This operation would yield a considerable amount of bark that could be utilized for hog fuel. Another source of chip material might be the Forest Service sales in the Kake area. Beach logs which are available in large quantities should not be used for fuel, as the salt content in these logs can create severe operational problems in either a wood-fired steam plant or wood gasifer plants. Currently chips for domestic consumption are being sold for $90/2400 pound unit (oven dry weight), and exportable chips are going for $130/2400 pound unit (oven dry weight). Estimates for the cost of hog fuel (wood-waste) with an equivalent moisture content of 50% and a heat value of 4500 BTU's per pound including adding handling and transportation costs results in about $30 per 5000 pounds delivered to Kake. 4.2 CONCEPTUAL PLANT DESIGN Wood is a potential fuel for power generation at Kake via boiler firing to produce steam for steam turbine generation or for gasification with subsequent gas turbine generation. apal7/f -1 While wood could be gasified in a so-called synthetic fuel plant, the current state of the art and associated economics make it doubtful that such a fuel facility would be constructed solely for the purpose of providing fuel for limited electrical generation. [4] Gasifier cost estimates are subject to several qualifications: there is general reluctance on the part of manufacturers to provide cost estimates for Alaskan installations; gas clean-up requirements can cause significant increase in unit costs; and application experience for commercial turbine firing is severely limited and has been for significantly larger units than that appropriate for Kake. Smal] demonstration gasification power plants have been reported at significantly lower capital costs per installed kW than existing commercial systems. Such demonstration projects may result in lower cost plants, but require a high level of quality and operational control compared to commercial practice. To represent a realistic - case the use of commercially available equipment has been chosen for this study with consequent economic deletion of this option at this time. Several manufaccurers were however, very willing to estimate costs and performance for a 1,500 kW wood-fired steam power plant for Kake. Figure 4.1 shows a basic flow diagram for a wood-fired steam power plant. A cost for a plant of smaller size was investigated but did not exhibit particularly significant cost savings due to similar operational complexity and the apparent fact that a 1,500 kW "package" is a apparent break point for equipment sizing. 4.3 ENVIRONMENTAL IMPACT The use of a wood-fired steam plant is expected to have minimal environmental impact on the area. Fuel used to fire the plant would come from wood-waste products recovered from present logging and sawmill operations. A wood-fired steam plant would, therefore, not require the harvesting of additional standing timber for use as fuel. Air quality standards would most certainly impose limitations as to the nature and quantity of acceptable emmissions and pollutants. Emission and pollutant problems can, however, be alleviated by proper engineering and design of the power plant. : 4.4 COST ESTIMATE The cost estimate for a 1,500 kW wood-fired steam plant installed at Kake is $3,600,000. This equates to an installed cost of $2,400 per installed kW. This estimate is supported by a cost breakdown shown in Appendix A. 2. apal7/f 4:- 2 STACK POLUTION CONTROL FUEL TURBINE STORAGE | CONVEY BOILER PREPARATION PIPING |GENERATOR WATER TRASH CONDENSER REMOVAL ASH HANDLING COOLING WATER ’ Figure 4.1 WOOD FIRED STEAM POWER PLANT FLOW DIAGRAM SECTION 5 ECONOMIC ANALYSIS SECTION 5 ECONOMIC ANALYSIS 5.1 INTRODUCTION A detailed cost analysis of the busbar cost for the various alternatives examined can be found in Appendix B. This analysis examines the busbar cost to Kake consumers with and without the cold storage load for (1) continued use of diesel generation; (2) a 34.5 kV, three phase transmission line; (3) a 40 kV, SWGR transmission line; (4) wood-fired generation; (5) the Cathedral Falls hydroelectric Project, at interest rates of 2, 5, 7 and 9% and a discount rate of 10%. A brief summary stating the salient technical points of each of the five alternatives is provided below. Statistical comparisons for a 7% interest rate are provided following each of the narratives. Projected peak demands and energy usage reflecting future requirements with cold storage (high) and without cold storage (low) loads are listed. 5.2 DIESEL GENERATION This plan assumes the utility will continue to operate only diesel driven generators throughout the study period. A new economic analysis has been performed for the diesel generation alternative to accurately reflect the effects of rapidly rising diesel fuel costs on this alternative. (i.e. present cost $1.034/gallon compared to $0.80/gallon used in the reconnaissance report for the Cathedral Falls Hydro Project[1]). This analysis reflects actual busbar cost and not "differences only" as represented in the Harza report. The 1980, 1990, and year 2000 conditions for this alternative is summarized as follows: apal7/g § - 2 Year 1980 1990 2000 Installed Diesel Capacity 1,600 kW 1,600 kW 1,600 kW Less Largest Unit 500 kW 500 kW 500 kW Firm Power 1,100 kW 1,100 kW 1,100 kW Project Peak (High) 482 kW 991 kW 1,328 kW Project Peak (Low) 482 kW 736 kW 1,016 kW Investment Cost in $1,000 (High) 1,800 1,800 2,9441 Investment Cost in $1,000 (Low) 1,800 1,800 1;800 Total Fixed and Production Cost in $1,000 (High) 416 1,920 6,430 (Low) 416 1,395 4,606 Energy Gross MWh (High) 1,902 4,264 5,685 Energy Gross MWh (Low) 1,902 2,890 4,005 Busbar Cost $/kWh (High) $0,219 ac8*) $0,450 $1.32 Busbar Cost $/kWh (Low) $0.219 1% $0. 483 $$1.150 5.3 TRANSMISSION INTERTIE It has been assumed that the tieline is built for 34.5 kV without the substations (operation at 24.9 kV) and is operational in 1984 when the Tyee Lake Hydro Project is expected to be on_line. The existing diesel generating plant is anticipated to provide standby power in case of transmission line failure. Installation of additional units has been considered unnecessary. A second case with a 40 kV Single Wire Ground Return Line has been evaluated with the same assumptions. Since it has not been defined which entity would | . _ busbar power costs at Kake. Although the Tyee Project power has not been committed yet, i r Definite Project Report would be available for use in Kake. It is” realized that more favorable conditions would most likely be negotiated in actuality and that the cited assumptions represent the "worst 1 Includes additional diesel generation equipment required in 1993. apal7/g S42 case". If then the "worst case" proves economically feasible, a well founded recommendation for development can be made. Results for the 24.9/34.5 kV three phase tieline and the 40 kV SWGR alternative are summarized as follows: 24.9/34.5 KV, 30 TIELINE Year 1980 1990 2000 Installed Diesel Capacity 1,600 kW 1,600 kW 1,600 kW Tieline Capacity! = 1,750 kW 1,750 kW Total Capacity 1,600 kW 3,350 kW 3,350 kW Less Largest Unit 500 kW 1,750 kW 1,750 kW Firm Capacity 1,100 kW 1,600 kW 1,600 kW Project Peak (High) 482 kW 991 kW 1,328 kW Project Peak (Low 482 kW 736 kW 1,016 kW Investment Cost in $1,000 (High) 1,800 8,270 8,270 Investment Cost in $1,000 (Low) 1,800 8,270 8,270 Total Fixed and Production Cost? jin $1,000 (High) 416 1,742 2,004 (Low) 416 1,451 1,734 Energy Gross MWh (High) 1,902 4,264 5,685 Energy Gross MWh (Low) 1,902 2,890 4,005 Busbar Cost $/kWh (High) $0. 2192 — $0.409° — $0.353 Busbar Cost $/kWh (Low) $0. 2192 $0.502 $0. 433 1 Maximum power transfer at 10% voltage regulation, 24.9 kV tieline voltage. 2 Diesel Generation, Kake. 3 Includes Tyee Project costs as supplied by APA. apal7/g Si=-3 40 KV SWGR TIELINE Year 1980 1890 2000 Installed Diesel Capacity 1,600 kW 1,600 kW 1,600 kW Tieline Capacity? -- 3,000 kW 3,000 kW Total Capacity 1,600 kW 4,600 kW 4,600 kW Less Largest Unit 500 kW 3,000 kW 3,000 kW Firm Capacity 1,100 kW 1,600 kW 1,600 kW Project Peak (High) 482 kW 991 kW 1,328 kW Project Peak (Low 482 kW 736 kW 1,016 kW Investment Cost in $1,000 (High)? 1,800 5,903 5,903 Investment Cost in $1,000 (Low)% 1,800 5,903 5,903 Total Fixed and Production Cost? in $1,000 (High) 416 559 1,821 (Low) 416 1,268 1,551 Energy Gross MWh (High) 1,902 4,264 5,685 Energy Gross MWh (Low) 1,902 2,890 4,005 Busbar Cost $/kWh (High) $0. 2192 =s$0R3G6- “S9Gra2Gr Busbar Cost $/kWh (Low) $0. 2192 $0.439 $0. 387 5.4 WOOD FUEL GENERATION This plan assumes the construction of a 1,500 kW wood-fired steam powered generation plant at Kake. Construction to be completed in 1983. It is estimated that such a plant could supply the power | i . This data is summarized below: + Maximum power transfer at 10% voltage regulation Diesel Generation, Kake. 3 These costs do not include 1% to 3% converter equipment. This equipment would be installed at the user's premises. It is estimated that these converter costs would total about $15,000 for the low load scenario and about $30,000 for the high (1980 dollars). 4 Includes Tyee Project costs as supplied by APA. apal7/g 5-4 Year 1980 1990 2000 Installed Diesel Capacity 1,600 kW 1,600 kW 1,600 kW Installed Wood-Fired Capacity -- 1,500 kW 1,500 kW Total Capacity 1,600 kW 3,100 kW 3,100 kW Less Largest Unit 500 kW 1,500 kW 1,500 kW Firm Power 1,100 kW 1,100 kW 1,100 kW Project Peak (High) 482 kW 991 kW 1,328 kW Project Peak (Low 482 kW 736 kW 1,016 kW Investment Cost in $1,000 (High) 1,800 6,210 6,210 Investment Cost in $1,000 (Low) 1,800 6,210 6,210 Total Fixed and Production Cost in $1,000 (High) 416 1,776 3,245 (Low) 416 1,699 3,060 Energy Gross MWh (High) 1,902 4,264 5,685 Energy Gross MWh (Low) 1,902 2,890 4,005 Busbar Cost $/kWh (High) — $0.219 ~$0.417— =oorerr Busbar Cost $/kWh (Low) $0. 219 $0. 588 $0. 764 5.5 CATHEDRAL FALLS HYDROELECTRIC PROJECT This plan assumes the construction of the Cathedral Falls Hydro Project in 1984. Analysis of this option using low load forecast only, was performed by Harza Engineering Company, Chicago, Illinois{1] and is reproduced in Appendix B, Economic Analysis Details for the reader's convenience. The Project would provide replacement energy in the system and would be asleep phURGee™aEETIC IME OP-wever 90 percent of the time. At the time when the water supply permits (about 25% of the time) the project could produce 750 kW. This capacity could be totally absorbed in the THREA system in 1984, assuming the cold storage load is connected, and by 1991 without the cold storage load. In the Project's initial year of operation (1984) it can supply approximately 2,500 MWh of energy if the cold storage load is connected or about 72% of the system's requirements. Without the cold storage load, the project can supply about 1,800 MWh of energy or approximately 80% of the systems requirements in 1984. The Project will ultimately supply 3,680 MWh. In the analysis of the project prepared by Harza cost for diesel generation required to supply system demand are not included in the busbar cost of energy calculated for the hydro project. The busbar cost represent only those costs associated with the hydroelectric project and do not reflect the overall busbar cost of electrical apal7/g 5 -‘5 energy at Kake under this option. The cost figures in following the table, however, have been adjusted to reflect the busbar cost to include any necessary diesel generation (using $1.0341/gal. as 1980-base). The Cathedral Fall related costs have been taken from the Harza report without adjustment for the different inflation rate used in that report. This introduces a slight error favoring the hydroproject. Year 1980 1990 2000 Installed Diesel Capacity 1,600 kW 1,600 kW 1,600 kW Installed Hydro Capacity =< 750 kW 750 kW Total Capacity / 1,600 kW 2,350 kW 2,350 kW Less Largest Unit 500 kW 750 kW 750 kW Firm Power 1,100 kW 1,600 kW 1,600 kW Project Peak (High) 482 kW 991 kW 1,328 kW Project Peak (Low) 482 kW 736 kW 1,016 kW Investment Cost! in $1,000 (High) 1,800 8,900 8,900 Investment Cost? in $1,000 (Low) 1,800 8,900 8,900 Total Fixed and Production Cost in $1,000 (High)? 416 1,741 3,681 (Low)? 416 1,263 2,135 Energy Gross MWh (High) 1,902 4,264 5,685 Energy Gross MWh (Low) 1,902 2,890 4,005 Busbar Cost $/kWh? (High) $0.219 —-$0.408 — -$0.648 Busbar Cost $/kWh? (Low) $0. 219 $0.437 $0.533 5.6 SUMMARY Results of the economic evaluation of all alternate development plans are listed on Table 5.1 "Economic Analysis Summary" for the different interest rates used. Table 5.2 "Cost Ratios" shows the ratios of the accumulated present worth of annual costs for the alternate development plans as compared to continuous use of diesel generation. The construction of a transmission tieline (40 kV, SWGR or 34.5 kV, 3) to_bring power from the interconnedted system to Kake appears to be the most economical development plan of the alternates evaluated. 1 Includes existing $1,800,000 diesel plant investment. 2 Adjusted to reflect cost of necessary diesel generation. Hydro related cost obtained from Cathedral Falls Project Report. 3 Reflects cost of necessary diesel generation. apal7/g 5-6 The calculated bus bar costs reflect the effects of the initial high investment. Table 5.2, "The Cost Ratio Benefit" clearly indicate that a transmission line tie will be more advantageous over the continued use of diesel fuel for both low and high loads. The existence of the interconnected system has an added potential benefit that could not accrue to the isolated system alternatives. Any significant electric energy supplies throughout the interconnected system (such as new hydro, DC connections to Snettisham or Ketchikan, etc.) can be shared with Kake. apal7/g Be 7 UNIT COSTS OF ENERGY AND ACCUMULATED PW OF ANNUAL COSTS Diesel Generation, Low Load Diesel Generation, High Load 38 Transmission, Low Load 30 Transmission, High Load Single Wire Ground Return, Low Load Singel Wire Ground Return, High Load TABLE 5.1 ALTERNATE DEVELOPMENT PLANS ECONOMIC. ANALYSIS SUMMARY Interest 1985 1990 1995 2000 = PW (1000-$) Rate (%) ¢/kWh ¢/kWh ¢/kWh ¢/kWh at 10% Discount 2 32.9 48.3 73.5 115.5 11,460 5 32.9 48.3 73.5 115.5 11,460 7 32.9 48.3 73.5 115.5 11,460 9 32.9 48.3 73.5 115.5 11,460 2 2908. 45.0 71.0 112.4 15,439 5 29.8 45.0 71.5 112.8 15,479 7 29.8 45.0 71.8 113.1 15,510 9 29.8 45.0 72.2 113.5 15,546 2 49.7 41.9 38.2 37.3 9,258 S 55.4 46.6 42.2 40.7 10,077 7 59.8 50.2 45.2 43.3 10,709 9 64.4 54.1 48.5 46.1 11,386 2 42.5 35.2 31.6 31.0 11,258 5 46.4 38.4 34.2 33.4 12,076 7 49.3 40.9 36.3 35.3 12,708 9 52.4 43.5 38.5 37.2 13,385 2 45.8 38.6 35.5 34.9 8,686 5) 49.4 41.6 38.0 37.1 9,211 7 52.1 43.9 39.9 38.7 9,608 9 55.71 46.3 42.0 40.5 10,035 2 39.9 33.0 29.7 29.3 10,684 5 42.3 35.0 31.4 30.9 11,210 7 44.2 36.6 32.7 32.0 11,607 9 46.2 38.2 34.1 33.3 12,034 4-A 4-B UNIT COSTS OF ENERGY AND ACCUMULATED PW OF ANNUAL COSTS Wood Steam Generation, Low Load Wood Steam Generation, High Load TABLE 5.1 ALTERNATE DEVELOPMENT PLANS ECONOMIC ANALYSIS SUMMARY (CONTINUED) Interest 1985 1990 1995 2000 2 PW (1000-$) Rate (%) ¢/kWh ¢/kWh ¢/kWh ¢/kWh at_10% Discount & 47.8 §3.1 60.8 72.3 11,644 €6: bie7 56.3 63.5 74.6 12,275 7 54.7 58.8 65.6 76.4 12,763 9 57.8 61.4 67.8 78.3 13,278 @ 33.4 37.8 43.4 54.2 12,177 5 m6. 1 40.0 45.2 55.8 12,809 7 38.1 41.7 46.6 57.1 13,295 9 40.2 43.4 48.1 58.4 13,811 TABLE 5.2 COST RATIOS OF ACCUMULATED PRESENT WORTH OF ANNUAL COSTS OF DIESEL GENERATION AS COMPARED TO ALTERNATE PLANS Interest Rate Alternate Plans 2% 5% 7% 9% A 38 Transmission (Low) 1.24 1.14 1.07 1.01 B 3 Transmission (High) 1.37 1.28 4.22 1.16 A Single Wire Ground Return (Low) £,32 1.24 1.19 1.14 B Single Wire Ground Return (High) 1.45 1.38 1.34 1.29 A Wood Steam Generation (Low) -98 8 -90 - 86 B Wood Steam Generation (High) 1.27 1.21 1.37 4.13 Cathedral Falls Hydro RLS gh ge BS eae 79.8 as 6 Ratio of PW of accumulated costs at 8% discount rate for displaced energy only at low load growth from [1]. This report [1] also uses different inflation rates and a lower diesel base cost. The combined effect of these different parameters is judged to have slightly negative influence on the cost ratios for the hydro Project. A re-evaluation, using the parameters set for this study, would show higher cost ratios for the project. apal7/g 5 - 10 SECTION 6 RECOMMENDATIONS SECTION 6 RECOMMENDATIONS 6.1 DEVELOPMENT PLANS The economic analysis of the alternate plans investigated favors installation of a transmission tie between Kake and Petersburg to allow use of Tyee Project hydroelectric energy in Kake. Either a conventional 34.5 kV three phase tie or a 40 kV single wire ground return line will result in lower electric energy costs by 1990 than continued use of diesel generation, wood-fired steam generation or the development of the Cathedral Falls Hydro Project. The 40 kV SWGR transmission line is the least costly solution and is a viable, technically feasible alternative using state-of-the-art proven arrangements. This unconventional system can save about 2.5 million dollars in initial investments over the next lowest option available. Since most of the end use of electricity by the consumers on the Kake system is single phase by nature, there is no compelling reason to provide 3-phase power to the whole community. There is good reason to »rovide some 3% converters at specific locations on consumers' premises. Such converters are off-the-shelf items manu- factured by more than one manufacturer and have been in use for at least 30 years on single phase systems all over the United States. It is estimated that about 5% of the small commercial and school loads might require 38 and that 50% of the industrial type loads will require it. This would require about 150 kVA of converters at low loads and 300 kVA at the high load level. Converter costs are today (1980) about $100 per kVA. This cost could be borne by the consumer or the utility - depending on policy. To insure completion of the transmission tie by 1984, or at such a time when the Tyee Hydro Project is completed, the following steps should be undertaken immediately: ° Assure availability of power from the Petersburg, Wrangell, Tyee interconnected system to Kake THREA. ° Establish the line route on large scale maps (U.S.G.S. 1" = 1 mile minimum). ° Assess environmental impact. ° Acquire right-of-way permits. ° Initiate design. apal7/h 6-1 6.2 INSTITUTIONAL AND FINANCIAL CONSIDERATIONS Although the economic analysis for the tranmsission tie has been performed to show the differences for electric energy costs for Kake only, it has to be assumed that THREA will spread these benefits through the utility's entire system. It can be assumed that THREA will be the entity that negotiates contractual matters with the Alaska Power Authority and/or the Thomas Bay Power Commission who are the owners/operators of the Tyee Lake Hydro Project. With the foregoing assumptions the following options are seen for THREA or the Tyee Lake Project owners A. Construction, Ownership and Operation of the Tieline The construction, ownership and operation of the transmission intertie for Kake is practically limited to two entities that appear most likely at this date: (1) THREA (2) Alaska Power Authority THREA ownership, would result in a large portion of the financing for the intertie coming from REA. This source of money is the likely lowest cost source for such a project. THREA is already a REA beneficiary and would qualify for the lowest of interest rates available from REA. Construction and operation of the intertie could certainly be accommodated by the THREA organization and experience. Alaska Power Authority ownership would provide a broader range of options for financing and operation. It is believed that this intertie project to serve Kake could revert REA financial support thru the Alaska Power Authority as an REA borrower. The APA would > via the Alaska Legislature and Private Money Markets through bonding. — Operation of this intertie by APA would provide maximum intergration of market areas and for the efficient use of operating personnel and equipment throughout the Kake-Petersburg-Wrangell-Tyee inter- connected system. The timing for accomplishment of the Kake intertie to provide the best arrangement for all parties involved will become clear when the institutional responsibilities are agreed upon. This report makes clear that there are opportunities for a feasible intertie. The interested parties - Kake, Petersburg, Wrangell, Thomas Bay Power Commission and the Alaska Power Authority - must identify the institutional structure around which appropriate studies would suggest the specific steps to be taken. apal7/h 6-2 B. Impact _on the Tyee Lake Project Construction of the line as part of Tyee Project would increase the _ initial costs for this project by about 7% to 10%. But the higher energy use (5% to 8%) would tend to offset these costs in the early years of the project. Addition of the Kake load could also require early completion of the second stage of the Tyee Project*. This could result in savings to the systems served by the Project by decreasing the amount of diesel generation required in the later 1990s prior to implementation of the second stage. A complete evaluation of this aspect can only be made by a new economic analysis . of the Tyee Project which would include the Kake load and the cost for the transmission line. C. Impacts on Power Costs The impact of Institutional and Financial considerations on the Kake -Petersburg intertie relates to the assumptions made in this study as follows: (1) This study assumed that unit energy costs (See Table B.2) to Kake from the interconnected systems of Petersburg, Wrangell, and the Tyee hydroelectric project in the Tyee Project Report - which did not include the loads of Kake. This is pessimistic since increased sales of energy would tend to reduce these unit costs. (2) This study further assumed that for its interconnected systems would be only the excess energy available from the Tyee Hydroproject that was surplus to the needs of Petersburg and Wrangell. (3) All additional costs related to the Kake intertie and power supply (such as costs of tieline and diesel generation when the excess from Tyee in insufficient) are charged to the Kake intertie. These assumptions, (1), (2) and (3), result in a "worst" case which is still the best alternative. (4) An institutional structure that could meld all the appropriate generation and transmission facilities together would undoubtedly impact power costs favorably. * Recent studies of the Tyee Lake Project indicate that approximately 70% more energy could be derived from the project utilizing a lower lake tap with an increase of original investment costs of approximately 29%. This concept would not require a dam or a future second stage development. At the time of preparation of this report, sufficient data was not available to assess the impact of these changes on this tieline study. apal7/h 6-3 As stated in B above, the interested parties (Kake, Petersburg, Wrangell, Thomas Bay Power Commission, and the APA) must identify an institutional structure around which appropriate additional study can suggest specific steps to accomplish the power purchase agreements in support of financing as well as the physical accomp- lishment of the intertie. apal7/h 6+ 4 APPENDIX A TECHNICAL INFORMATION APPENDIX A TECHNICAL INFORMATION A.1 TRANSMISSION LINE CHARACTERISTICS AND PERFORMANCE DATA A. Three Phase Tieline Alternatives Electrical characteristics of the various three phase transmission tieline alternatives investigated are tabularized in Table A.1. This data has been calculated using the long line transmission line model and A, B, C, D constants. To simplify calculations the tieline is assumed as overhead for its entire length (i.e. cable characteristics ignored). The electrical characteristics of the tieline are based on the use of 4/3 AWAC, which is electrically equivalent to 3/0 Awg, ACSR. The use of this conductor maximizes span lengths while simultaneously maintaining adequate electrical performance. The relatively low power transfer requirements of this tieline allow best utilization of 4/3 AWAC conductor. Standard REA three phase, single pole, double crossarm construction is assumed for a 24.9 kV or 34.5 kV tieline, Figure A.1. Single pole suspensicn insulator construction Figure A.2 is assumed for a 69 kV tieline. Past experience has shown that while standard three phase construction can be adapted for use in the marsh, muskeg and mountainous terrain of southeast Alaska, it can only be done so at premium cost. The high cost for three phase construction calculated in Section 3, verifies this fact. apal7/i Ava <1 TABLE A.1 TRANSMISSION LINE ELECTRICAL PERFORMANCE? Line Percent Line Constants? Voltage (kV) Power (kW) Power Factor Losses Voltage Alternative RQ/mi XcQ/mi Ycxi0-* mhos Rec Send Rec_ Send Max® —- Rec Send (kW) = Regulation 24.9 kV, 39 0.545 0.7229 6.08 25 27.1 1,350 1,437 1,750 0.90 0.93 87 7.7% 34.5 kV, 36 0.545 0.7229 6.08 34.5 36.0 1,350 1,394 3,200 0.90 0.97 44 4.2% 69 kV, 36 0.545 0.7833 5.58 69 69.4 1,350 1,361 12,600 0.90 -0.924 11 0.6% kV, SWGRS 0.651 1.308 4.21 40 41.9 1,350 1,392 3,000 0.90 0.96 42 4.5% Based upon Route #1, 47 miles overhead, no cable, 1,350 kW power transfer. Based on 4/3 AWAC conductor. Maximum power transfer at 10% voltage regulation, where % Veg = Vv no_load - V no load Leading power factor. 1000Q-m soil, 1 ohm terminal resistance each end. V full load x 100 e-v @ 3-8" for 8'-0" Crossorm 4'- 6" for 10'-0" Crossarm TYPE TP-I SINGLE ARM 6'-0" TYPE TP-1A SINGLE ARM 10'-0" LIST OF MATERIAL DRG] REQ™O. FIP-1 |P-2 DESCRIPTION ITEM 1 1 2 t Wood Crossorm x5 1/8 2_| 1 | 2 | 60" Wood Crossarm Brace cu 2.| 4 | 10" Insulator Pin, Lead Thread f 4 1 2_| Pole Top Pin 2 b 1 {578"x 12" Special Eye Bolt for Pole-Top Pin dx | * 6 | 3 | 6 | Pin Type Insulotor ‘ e i | 1 2_| Pole Top Bracket 7 7 i || 8 4 | Double Arming Plate . ct | \ 9 4 {v2 sr Machine Bolt ¢ 10| 2 | 4 | 1/2'x7 Machine Bolt c | ‘| tt | 2 | 1 | 5/812" Machine Bolt ¢ {|i 12 2 | 5/814" Machine Bolt c iil 3 [1 3/4"x 16" Machine Bolt c | | 14 |_| 5/8"x18" Machine Bolt | 15, 1 [3/4™x 20" Machine Bolt cL! 16 4 |3/4"x8" Machine Bolt me iwi 5/8" Machine Bolt, Length os required { | - . - | 79 | 9 | 4 2 4x2 1/4'x 3/16 Galv. Sq. Washer, (3/16 Hole tid 20 | 6 | 12 || 3/8.Golv. Round Washer, 9/16" Hole ty | 21 | 4 [ 8 | Locknuts for 1/2" Bolt ly4 2[ 4] 4 | Locknuts tor 5/8" Bolt 231 39 | Locknuts for 3/4" Bolt it ty a qf | 1 | 1 || 1\ | uu Laid melas, RANSMISSION LIN NGENT STRUCTURES | DOUBLE ARM 6'-0" TRANSMISSIO! Ku in ee Ss IC TYPE TP-2A 7 ' DOUBLE ARM 10'-0" (46 KV. MAXIMUM) q ACROSSAPM TYPE 12 NTS] FIG. A.1 te: Apr_ 1967 TP-1,TP-1A,TP-2,TP-24 NOTES: 1. On Straight Lines Items 20 and 21 May be Mounted On Opposite Side of the Pole. 2. we See Note 2 on Drawing TS-l. [ LIST OF MATERIAL pee. redo] DESGRIPTION (TEM A Sle X 5 5/8" Wood Crossorm « x # 9 ‘y5/o" x 5 5/8" Wood Crossarm & XM | 9 . | cu | 4 2 om 5 3_|$/8"x 8" Eye Bolt o | 6 | 6 |1/2"x 6" Machine Bolt ¢ Z 4 _|1/2"x 8" Machine Bolt c 8 8 |5/8"x8" Machine Bolt c |_ 9 -2__|5/8__Machine Bolt, Length as Required 10 2 | 3/4"x24"Machine Bolt ¢ W 4 74" 2 1/4°x 3/16" Galv. Sq. Washer " Hole a 12 | 20 [1 3/8" Gal Round Washer, 9/16" Hole d 13_| 12 | Locknuts for 1/2” Bolt ok 14 |-15_| Locknuts for 5/8” Bolt _ek 15 7 _[1/4"x 4°x17" Double Arming Plate ct 16 3_|3/4"x 534" Pipe Spacer \7 * |S 34x 10" Suspension Insulator k ! 3__| Suspen: Hook ih 19 3 lamp and Connecting Piece ai 20 t ire Cable Su: ed oe 2l 1 | Ground Wire De sion Clamp m wm 22 2 _| Locknuts for 3/4" Bolt ak fit CL pha plo See 4 pe----- a 3€ & & CROSSARM TYPE 14 i ' =e ry ; i i 11 Kx ie CROSSARM TYPE 22 ; \ ae eu) vg. THet ned i +S thd Tor. cy wld thy TRANSMISSION LINE TANGENT STRUCTURE DRG. |OIMENSIONS ___ KV. SINGLE POLE SUSPENSION- DOUBLE ARM (69 KV. MAXIMUM) FIG. A.2 te: Mor. 1967 REVISED TS-2,TS-2X B. SWGR Alternative The SWGR transmission system concept employs a single overhead energized conductor and uses the earth as the return conductor. While the use of SWGR is unconventional in the sense that applications are not common, it is an accepted system of proven use in several areas of the world. [5], [6], [7]. Three phase equipment can also be successfully operated from this system using phase converter [8]. Electrical performance data of the SWGR transmission line is included in Table A.1. Calculations were performed using A, B, C, D constants. Assumptions stated for the three phase circuit calculations are also valid for the SWGR. Examination of Table A.1 will show that the performance of a 40 kV SWGR tieline is equal to that of the 34.5 kV, three phase circuit. The major advantage of the SWGR system being its substantially lower cost. The transmission line design for the SWGR system is based on the use of a gravity stabilized "A"-frame structure (Figures A.3) using long span construction. The structure has transverse stability from gravity alone and need not penetrate the earth. Longitudinal stability is obtained through the strength and normal tension of the line conductor. This design provides excellent flexibility to adapt to the freeze-thaw cycle. It is believed that the "A"-frame structure design has certain features that will provide opportunities for its use over the terrain of the region, as follows: 1. The structure can be fabricated at a construction site and delivered by helicopter. apal7/i A-5 10" DIA. 7 10'x4"x4" x4" ANGLE IRON 4.75" DIA. 30'-0" 11 27'-0" aos} "A" FRAME STRUCTURE POST INSULATORS FIGURE A.3 2. The structure can be built using for the most part standard REA approved materials. 3. The design contributes to cost savings by utilizing high strength conductor which allows the use of a minimum number of structures and by simplifying construction techniques to avoid the high cost of bringing conventional construction methods to this special terrain. 4. The structure is ideally suited to winter time construction. The "A"-frame structure design has been used in the construction of an 8.5-mile-long SWGR transmission line demonstration project near Bethel, Alaska by R. W. Retherford Associates, for the State of Alaska. Performance of the "A'-frame structure transmission line has been studied for over four months and the initial results have thus far proven quite satisfactory. Little settlement of the structures into the tundra has been noted. A.2 WOOD FUEL GENERATION A. Assumpticus Plant Size is 1,500 kW Assume 85% Plant Availability Assume 80% Boiler Efficiency Assume 4,500 BTU/1b. Wood (50% Moisture) Base Year for $ Estimates is First Half 1980 OPwWwnr B. Capital Cost Thermo-Electron estimated $2.7-3.0x10® turnkey cost for Kake location. Use higher estimate and add 20% contingency = 1.2 ($3,000,000) = $3,600,000 capital cost (which is $2,400/kW). The estimate is arrived at as follows: apal7/i A- 7 Item Boiler and Appurtenances Turbine - Generator }3 Condenser 3 Wood Handling System? Mechanical Auxiliaries Electrical Auxiliaries Civil Works Subtotal Engineering & Construction Management (~20%) Subtotal Contingency (20%) Total C. Labor Cost 1. Operators - 2 per shift, 3 shifts per day per operator per year 2. Yard Equipment Operators - 4 total @ per year D. Maintenance Cost 1980-$ $550 ,000 525 ,000 450 ,000 350 ,000 300 ,000 500,000 $2,675,000 325 ,000 $3,000,000 __ 600,000 $3,600 ,000 Yearly Total Source Manufacturer's estimate Manufacturer's estimate Scale from prior IECO estimate for larger plant Previous similar estimates Previous similar estimates Manufacturer's estimate $50,000 each $300,000 $37,500 each $150,000 $450,000 Use 2.5% of capital investment for yearly maintenance cost. 0.025 ($3,600,000) = $90,000/year 1 Includes conveyors, storage bins, stockpile. apal7/i E. Fuel Cost For 250 psig, 500°F steam, initial enthalpy is 1261.8 Btu/1b. At condensing temperature ~100°F, enthalpy of condensate if 69.74 Btu/1b. [101.7°F]. Thus, Ah = 1261.8 - 69.7 = 1192.1 Btu/lb steam. Wood fuel is taken to have 4500 Btu/1b at 50% moisture (Source: USFS letter to Mr. M. Latour). For 80% efficient boiler, wood required is 1192.1/4500 (0.80) = .3311 1b. wood/1b. steam. Per Marks [Eighth Edition, p 9-52], theoretical steam rate is 9.070 1b. steam/kWh for 2" Hg condenser. Use 75% turbine efficiency (Source: Elliott Company) = 9.070 + 0.72 = 12.597 1b. steam/kWh. For 1500 kW, then, need 12.597 (1500) = 18,896 lb. steam/hr. = use 19,000 1b. steam/hour. So, 19,000 x 0.311 = 6291 say 6300 1b. wood/hour. So, overall fuel rate is 6300 1b/hr x 4500 Btu/1b + 1500 kW = 18,900 Btu/kWh. This compares to existing diesel generation efficiency of 16,430 BTU/kWh. Assume hog fuel is available at $30 per 5000 pound unit 50% moisture content, 4500 Btu per pound this equates to $30/5000 1b x 22000,000 Btu _ ¢1 33/mittion Btu. 4,500 Btu/Ib For a conservation estimate use $1.50 per million Btu. This equates to 20.7 cent per gallon when compared to 138,000 Btu per gallon diesel fuel oil. apal7/i A-9 T ceKMU cLevuT OJ TURBINE GENERATING UNIT | FOR WASTE WOOD APPLICATIONS E war * « + &. & é é s . -~" 2000 KW SYSTEM wa thermo i Electron A - 10 Energy Systems STEAM PRODUCTION GENERATING UNIT € 2 c 2 8 Cc 3 c 8 Figure 1 The current concern over the reliability of supply and the sharply rising costs ofhydrocarbon fuels is acting as a powertul incentive to utilize fuels other than oiland natural gas. Mostpromising in the near term is the utilization of waste wood products for the generation of steam and electricity. Thermo Electron offers a variety of efficient turnkey sys- tems for cogeneration that are ideally suited to wood burning installations. A-11 Produce Your Kiln Drying Process Steam Needs While Simultaneously Generating Electric Power A frequently heard expression around industry these days is “cogeneration”. Cogeneration, technically defined as the simultaneous production of useful heat and power, assures an efficient utilization of available fuel resources. Similarly, the efficient energy utilization from your “waste” wood products can be assured by fulfilling the process steam needs of your drying kiln by means of an extraction steam turbine generating system. Efficient utilization means greater profits, while solving disposal problems and increasing energy independence. Due to the multi-stage construction of the units, steam canbe extracted at a convenient pressure to satisfy all process needs; the balance of the steam, not required for the process, passes through the remaining stages of the turbine to a condenser. In this way the steam that is allocated for process use can do some very valuable work in generating electricity before being used for the drying operation in the kiln. As an example, the inlet pressure to the turbine generator might be 275 psig when generated in a 300 psig boiler; the inlet steam pressure is reduced in the primary turbine stages to an appropriate value at which point an appropriate quantity is allowed to leave the turbine through an extraction opening. This process steam could exit at a sufficient pressure to provide 15 psig steam for kiln drying requirements; the remaining steam is passed to the condenser for efficient utilization and recycling. j The entire generating system can be designed to provide a fairly continuous disposal of your waste wood products, independent of the varying process steam requirements of your drying kiln. When the kiln drying steam requirements are small, the extraction steam turbine generator can pass more steam flow to the condenser for the production of additional electric power. At high drying kiln steam demand, the extraction opening will pass the required amount of steam to satisfy the higher drying kiln steam loading. The drying kiln steam production is the primary concern and the turbine system is designed to float with the process demands, assuring a consistently adequate pressure and steam flow. The byproduct electricity can be used to fulfill inplant requirements and/or exchanges with the local utility. A host of situations exists for the variety of applications and Thermo Electron is prepared to deal with them utilizing over 20 years of experience in composite designs of thermo- dynamic systems. Where appropriate, Thermo Electron can provide the design and controls to allow for the balancing of purchased power and inplant generated power. For instance, in alumber mill where the electrical demand may be beyond the capacity of the inplant generation, controls can be set up to allow purchase power to make up the difference. On the other hand, if more electricity is being generated than required, your local utility may wish to purchase the excess power. Alternatively, we can design to decrease power pro- duction in order to match inplant electrical needs without the export of power. A typical extraction steam turbine generator unit schematic A - 12 for use in a wood burning application is shown in Figure 1. System sizes are in the range from 500 kw through 15,000 kw. Typical quantities of waste wood necessary for such a system should be a minimum of 30 tons/day. For those system applications where multi-stage steam turbine extrac- tion systems may not be advantageous, we are prepared to offer single stage back pressure turbine generator units which can exhaust back pressure steam directly for kiln drying purposes. Such units, which are available in the smaller size ranges, will respond to process kiln demands and generate whatever power processes steam demands allow. System Designed for Efficiency, Reliability and Installation Ease The Thermo Electron system is particularly flexible and can easily be tailored to specific application requirements. Firstly, the standard modular construction of the turbine generator units and their related auxiliaries insure factory precision in component matching, reliability, and ease of field erection. Secondly, the solid forged rotor construction with the wheels forged integrally with the shaft simplifies critical speed prob- lems while allowing a higher RPM to achieve greater efficien- cies. This conservative design allows you to generate an optimum amount of electricity from your heat source. Thirdly, the packaged bed-plate mounted nits have an integral lubricating system and can be provided with an integral condenser to an approximate 6000 kw size. Of course, the specific condenser sizing is tailored to the site location and the particular job to be done. It is desirable in many locations to utilize an air-cooled condenser if the availability of cooling water cannot be assured. Such air-cooled condensers are separately mounted and can be designed for freeze protec- tion and continuous availability. Fourthly, the turbines are ofa multi-stage design maximizing efficiencies and allowing for extraction steam at pressures ideally suited for your kiln needs. A typical packaged integral condenser steam turbine gener- ator unit is shown on the cover of this bulletin. Appropriate generator and switchgear could be supplied by us from the manufacturer of your choice. Controls and safety devices assuring parallel operation and satisfaction of process requirements are supplied to our specifications. Thermo Electron is prepared to assume turnkey responsibility for the entire system. Please call or write our Marketing Manager, Energy Systems Division at the following address: Thermo Jz Sate) CORPORATION 123 Second Avenue Waltham, Massachusetts 02154 (617) 890-8700, Ext. 205 We would be pleased to work with you to deter- mine the feasibility of a system for your specific situation. Thermo Electron serves worldwide indus- trial, Government, and utility markets with products and services that use ther- modynamic technology. The company manufactures waste-heat recovery equipment, papermaking equipment, controlled-atmosphere metal-processing furnaces, refractory metals, marine engines, environmental instruments, and provides metal heat-treating and forming services. Thermo Electron also engages in a broad range of research programs sponsored by the company, by the Gov- ernment, and by utilities, having as their objective the application of thermo- dynamic technology to the development of new products and processes. A major portion of these programs is dirécted at improving the effectiveness with which industry utilizes its resources of capital, energy, and materials. A - 13 Thermo Electron Corporation Principal Offices and Plant Locations Corporate Office 101 First Avenue, Waltham, Massachusetts 02154 Papermaking Equipment Lodding Sword Street, PO. Box 269, Auburn, Massachusetts 01501 AER Corporation 100 Hilltop Road, Ramsey, New Jersey 07446 Joseph Winterburn Ltd. PO. Box 6, Riverside Works, Woodhill Road Bury, Lancashire BL8 1DF, England Lodding de Mexico, S.A. Lago Como Num. 128-A, Colonia Anahuac Mexico 17, D.F. AER-Lodding Ltd. 6875 Bombardier Street, St. Leonard, PQ. Canada, H1P3A1 Lodding do Brasil, Ltda. Rua Domingos Jorge No. 676 04761 Sao Paulo, Brazil Power Systems Energy Systems 123 Second Avenue, Waltham, Massachusetts 02154 Marine Engines 7100 East 15 Mile Road, Sterling Heights, Michigan 48077 Metallurgical Furnaces Holcroft 12068 Market Street, Livonia, Michigan 48150 Holcroft & Company (Canada) Ltd. 94 Bessemer Court, London, Ontario Loftus 5 Gateway Center Stanwix St. and Boulevard of the Allies Pittsburgh, Penn. 15222 Metals and Metallurgical Services Cal-Doran Division 2830 E. Washington Boulevard, Los Angeles, California 90023 Houston Division 411 Jackson Hill Street, Houston, Texas 77007 Metal Treating Division 1575 West Pierce Street, Milwaukee, Wisconsin 52304 Perfection Heat Treating Division 11650 Wormer Street, Detroit, Michigan 48239 Refractory Metals Division 9 Crane Court, Woburn, Massachusetts 01801 Environmental and Health Monitors Air Pollution Instruments 108 South Street, Hopkinton, Massachusetts 01748 Analytical Instruments 45 First Avenue, Waltham, Massachusetts 02154 Waltham R&D Center 85 First Avenue, Waltham, Massachusetts 02154 VE Thermo VE tlectron CORPORATION Energy Systems 101 First Avenue Waltham, Massachusetts 02154 (617) 890-8700 A.3 TRANSMISSION LINE COST ESTIMATES The following cost estimates have been prepared with price information obtained from manufacturers and contractors as well as by correlation to recently completed lines in various areas in Alaska. A. Transmission Line Cost Estimates apal7/i 24.9 kV Three Phase Overhead Line REA standard double crossarm design average span 525' Structures; 10 at $650 Conductor 4/3 AWAC, 15840' @ $350/1000' Survey Clearing Right-of-Way Acquisition Freight Labor 590 man-hours @ $55 Subto’ al Engineering @ 10% 34.5 kV Three Phase Overhead Line REA standard double crossarm design average span 525! Structure, 10 @ $750 Conductor 4/3 AWAC, 15840' @ $350/1000' Survey Clearing Right-of-Way Acquisition Freight Labor 590 man-hours @ $55 Subtotal Engineering at 10% A- 14 Use Use 1980-$/Mile $ 6,500 5,600 8,000 22,000 5,000 2,000 32500 $81,600 8,160 $89 ,760 $90 ,000 1980-$/Mile $ 7,500 5,600 8,000 22,000 5,000 2,000 32,500 $82,600 8,260 $90 ,860 $91,000 3. 69 kV, Three Phase Overhead Line 1980-$/Mile REA standard single pole suspension design, span 750' Structures, 7 @ $1,200 $ 8,400 Conductor 4/3 AWAC, 15840' @ $350/1000 5,600 Survey 5,000 Clearing 22,000 Right-of-Way Acquisition 57000 Freight 2,000 Labor 700 man-hours @ $55 38,500 Subtotal $86 ,500 Engineering @ 12% 10,400 $96,900 Use $97 ,000 1980-$/Mile 4. 40 kV, SWGR Overhead Line "A"-Frame structure design span 750' Structures, 7 @ $650 $ 4,600 Conductor 4/3 AWAC 5280' @ $350/1000 2,000 Survey 5,000 Clearing 22,000 — Right-of-Way Aquisition 5,000 Freight 2,000 Helicopter 1,000 Labor 200 man-hours @ $55 11,000 Subtotal $52,600 Engineering @ 10% 5,260 $57,860 Use $58,000 1980-$/Mile apal7/i A- 15 40 kV, SWGR Overhead Line Standard single pole design, span 750' Structures, 7 @ $1,000 Conductor 4/3 AWAC 5280' @ $350/1000 Survey Clearing Right-of-Way Aquisition Freight Labor 400 man-hours @ $55 Subtotal Engineering @ 12% Use B. Substations 1. apal7/i Transmission Substation, 138 kV/69 kV Auto-Transformer 2.5 MVA Switchgear Bus Structure & Hardware Freight Labor 500 man-hours @ $55 Subtotal Engineering @ 10% Use Transmission/Distribution Substation 69 kV Step Down Transformer 2.5 MVA Switchgear Bus Structure & Hardware Freight Labor 500 man-hours @ $55 Subtotal Engineering @ 10% Use A- 16 $ 7,000 2,000 5,000 22,000 ~5,000 © 2,000 22,000 $65 ,000 7,800 - $72,800 $73,000 1980-$ $ 60,000 30,000 15,000 15,000 __ 33,000 $153,000 15,000 $168 ,000 $175,000 1980-$ $ 50,000 26 ,000 12,000 13,000 27,500 $128,500 13,000 $141,500 $145 ,000 Terminal for Single Wire Ground Return Transmission up to 40 kV Ground Grid Labor 50 man-hours @ $55 Transformer, 19, 1.5 MVA Switchgear & Protection Subtotal Engineering @ 10% Transmission Substation 34.5 kV/24.9 kV or 12.5 kV Transformer 2.5 MVA Switchgear Bus Structure and Hardware Freight Labor 300 man-hours @ $55 Subtotal Engineering 10% Cc. Submarine Cable Cost Estimates 1. apal7/i 25 kV and 34.5 kV Three Phase Submarine Cable 3 single phase cables plus one spare 22,000' @ $15/ft. Labor 1050 man-hours @ $55 Freight Subtotal Engineering @ 10% A- 17 Use Use Use 1980-$ $ 1,500 2,800 18,000 5,000 $27,300 _2,700 $30,000 1980-$ $ 40,000 20,000 13,000 11,000 27,500 $111,500 __ 11,000 $122,500 $125 ,000 1980-$/Mile $316,800 58,000 6,000 $380 ,800 38,000 $418 ,800 $420,000 1980-$/Mile 2. 69 kV Three Phase Submarine Cable 3 single phase cable plus one spare 22,000' @ $18/ft. $396 ,000 Labor 1050 man-hours @ $55 58,000 Freight 6,000 Subtotal $460,000 Engineering @ 10% 46 ,000 Use $506,000 1980-$/Mile 3. 40 kV, SWGR Single Phase Submarine Cable 1 single phase cable plus one spare 11,000' @ $15/ft. $165,000 Labor 700 man-hours @ $55 38,500 Freight 4,000 Subtotal $207,500 Engince. ing @ 10% 20,700 $228,200 Use $230,000 apal7/i A- 18 APPENDIX B ECONOMIC ANALYSIS DETAILS APPENDIX B ECONOMIC ANALYSIS DETAILS B.1 ALTERNATE INVESTIGATED The following cases have been analyzed: 1-A Diesel Generation - Low Load 1-B Diesel Generation - High Load 2-A 34 Transmission - Low Load 2-B 3% Transmission - High Load 3-A Single Wire Ground Return - Low Load 3-B Single Wire Ground Return - High Load 4-A Wood Steam Generation - Low Load 4-B Wood Steam Generation - High Load Low Load represents normal system growth without cold storage. High Load represents normal system growth with cold storage. on B.2 PARAMETERS USED FOR THE ECONOMIC EVALUATION A. Power Demand and Energy Requirements The data listed in Section 2 has been utilized. B. Energy Sources and Supply Firm capacity is assured by assuming the largest unit in the system is non-operational. For alternatives involving the transmission tieline, fuel diesel capacity has been maintained. Energy supplied _ over the transmission tieline to Kake jis surplus hydroelectric energy provided by the Tyee Lake Hydro Project. In alternatives involving hydropower which have been analyzed in this report, the prime energy available has been applied to the annual requirements. Load duration curves and secondary energy have not been utilized. Line losses have been calculated to be less than 2% through most of the study period and have not been taken into account in this analysis. Firm capacity has been established according to the following parameters. apal7/j B-1 ° Local Generation - Total installed capacity less the largest unit installed. ° Tieline Transfer - Total local installed capacity plus maximum tieline transfer at 10% voltage regulation, less largest load generation unit or tieline capacity which ever of the two is the greater Cc. Base Year All cost data as outlined below is for the base year of 1980. Dd. Existing Plant Values Taken from THREA form 7's and the State of Alaska Public Utilities Commission, Tlingit and Haida Regional Electric Revenue Requirements Study and Operation Audit November 1979, prepared by Authur Young and Company. E. Inflation 1. Diesel Fuel Cost - An inflation rate of 10.5 percent per year is applied to diesel fuel cost for the 20-year study period. 2. Naadinkive:. Lasts - An inflation rate of 7 percent per year is applied to wood fuel cost for the 20-year study period. This rate reflects the assumption that resource costs will remain relatively stable and only associated labor costs increase. 3. All Other Costs - An inflation rate of 7 percent is used for the 20-year study period for all other costs (i.e. labor, construction, maintenance, etc.) Fa Insurance A single insurance rate of $3.00/$1,000 invested is applied to all investments except transmission lines. Transmission lines are not insured. This rate is inflated as stated above. G. Labor | 1. Diesel - The present production plant labor costs were determined from THREA utility records and were estimated Taxes, insurance and all fringe benefits were included. Labor costs have been inflated as stated above. apal7/j B= 2 i 2. Wood Plant - Labor cost for a wood-fired plant is estimated This includes 6 plant operations and 4 yard equipment operators. Labor costs have been inflated on stated above. H. Fuel Cost The diesel fuel costs as of July 1980 is $1.034 per gallon. This price is inflated as previously mentioned. Escalated fuel costs by year are shown in Table B.1. : I. Generation Fuel Efficiencies The following assumptions are made in regard to fuel cost calculations and usage. 1. Diesel - apal7/j Be TABLE B.1 FUEL COST FOR KAKE IN DOLLARS/GALLON e Year Cost-$/Gal. 1980 1.034 1981 1.143 1982 1.263 1983 1, 395 1984 1.542 1985 1.703 1986 1.882 1987 2.080 1988 2.298 1989 2.540 1990 2.806 1991 S210 1992 3.427 1993 3.786 1994 4.184 1995 4.623 1996 5.109 1997 5.546 1998 6.238 1999 6.893 7.617 2000 Inflated at 10.5% per year through-out the length of the study. 2. Wood-Fired Generation - a. Heat content of wood, 50% moisture content, 4,500 Btu/lbs. b. Generating efficiency 18,900 Btu/kWh. J. Lube O11, Grease and Operating Supplies Calculated as 10% of fuel costs. K. Diesel Maintenance Materials (Repair) Estimated at $7.44/MWh generated from utility records. Inflation rates have been applied as listed. apal7/j Ben 4 ai ission-Tieli ; Estimated at $500 per mile. Inflation rates have been applied. M. Wood Plant Maintenance» Estimated at $90,000/year. Inflation rates applied. N. Diesel Plant Cost Cost of installing diesel generation is estimated at $950 per installed kW. Those unit costs represent installed cost as experienced lately in the state. An inflation rate has been applied for future installations. 0. Transmission Tieline Cost See Section 3, D, Transmission Intertie Cost Estimates. Inflation rates have been applied as necessary. P. Wood Plant Cost Cost of a wood-fired steam generation plant is estimated at $2400/kW installed. Inflation rate has been applied for future installation. Q. Debt Service Debt services on new investments have been calculated using 2, 5, 7 and 9 percent costs of money. ‘An amortization period of 35 years is used for all new investments. R: Discount Rate — ee ee S.. Surplus Hydroelectric Energy Available surplus hydroelectric energy and busbar cost of this energy through the year 2000 is shown in Table B.2. This data has been provided by Alaska Power Authority. apal7/j Be=S Surplus hydro energy calculated as follows: MWH. + MWH,. - MWH, T c WP Where: MWHL. = Tyee Prime Energy 1984 - 1999 = 75,235 2000 = 126,801 MWHe = Crystal Lake Prime Energy = 12,404 MWH\ )p = Energy Demand Wrangell and Petersburg combined Line Losses have been neglected. apal7/j Ba 6 a ee ERO TABLE B.2 1 _ SURPLUS HYDROELECTRIC ENERGY AND BUSBAR COST — o Busbar Cost Year Available Energy MWh $/kWh 1980 = 5 1981 = > 1982 . r 1983 = _ 1984 91,509 - 280 1985 88,790 2209 1986 85,098 A 1987 81,406 - 256 1988 77,714 -239 1989 . 73,910 224 1990 70,086 212 1991 66,844 - 203 1992 63,600 ~195, 1993 60,357 1893 1994 57,213 . 184 1985 53,071 - 179 1996 50,900 175 1997 47,700 ~ATE 1398 44,500 167 #999 41,300 164 2000 * 38,100 ; .161 B.3 EXPLANATION OF COMPUTER PRINTOUTS The following is a line by line explanation of the enclosed computer printouts. . T This data has been supplied by Alaska Power Authority. apal7/j Bee? DESCRIPTION 1. Load Demand Demand - kW Energy - MWh 2. Sources - kW A. Existing Diesel Location or Unit 6 B. Additional Diesel Unit 1-6 C: Existing Alterate 1 Unit 1-2 D. Additional Alternate 1 Unit 1-3 E. Existing Alternate 2 F. Additional Alternate 2 Unit 1-3 Total Capacity - kW Largest Unit Firm Capacity Surplus or (Deficit) - kW Alt. 1 Generation - MWh Alt. 2 Generation - MWh Diesel Generation - MWh 3. Investment Cost ($1000) 1979 Dollars A. Existing Diesel apal7/j EXPLANATION Projected peak load in kW Projected Energy Requirement in MWh Existing diesel units in kW Diesel Additions in kW and year added Existing Alternate 1 units in kW Alternate #1 additions in kW and year added Existing Alternate 2 units in kW Alternate #2 addition in kW and year added Sum of lines A, B, C, D, E, F above Largest installed unit Total capacity less largest unit Surplus or deficit in existing generation capacity Net annual MWh available from alternate generation Diesel Generation in MWh required to supply load energy. Calculated as Load energy (MWh) less net alternate capacity (MWh), unless diesel generation is required to supply system peak demands. Cost of existing diesel units in 1980 dollars DESCRIPTION B. Additional Diesel Units 1-6 Cc, Existing Alternate 1 D. Additional Alternate 1 Units 1-3 E. Existing Plant Unig. 1-2 F. Additional Alternate 2 Unit 1-3 G. Transmission Plant Addition Total ($1000) 1980 Dollars Inflated values 4. Fixed cost ($1,000) Inflated values A. Debt Service 1. Existing 2. Additions Subtotal 1st% - 2% 2nd% - 5% 3rd% - 7% 4th% - 9% B. Insurance Total Fixed Cost ($1000) 1lst% - 4th% (2% - 9%) 5. Production Cost ($1000) Inflated value A. Operation and Maint. 1. Diesel 2. Alternate 1 3. Alternate 2 apal7/j EXPLANATION Cost of additional diesel units in 1980 dollars Cost of existing alternate units in 1980 dollars Cost of additional alternate units in 1980 dollars Cost of existing alternate units in 1980 dollars Cost of miscellaneous additions in 1980 dollars Cost of transmission lines in 1980 dollars Sum of lines A through H above Sum of Lines A through H above adjusted for inflation Existing debt service on investments Debt service calculated on inflated new additions using 2, 5, 7, and 9% cost of money. Calculated as $3/$1000 invested (inflated values) Sum of Debt Service Existing, Debt Service Additions, Insurance and Taxes Production Plant at interest rates listed. Sum of yearly labor costs related to generation and maintenance costs. DESCRIPTION B. Fuel Oi? and Lube Total Production Cost ($1000) Total Annual Cost ($1000) 1st% - 4th% (2% - 9%) Energy Requirements - MWh Mills/kWh 1st% - 4th% (2% - 9%) Cc. Present Worth Annual Cost ($1000) 1st% - Ath% : (2% - 9%) OD. Accumulated Annual Cost ($1000) 1st% - 4th% (2% - 9%) E. Accumulated Present Worth Annual Cost ($1000) 1st% - 4th% (2% - 9%) Fs Accumulated Present Worth of Energy Mills/kWh 1st% - 4th% (2% - 9%) G. Hydro Busbar Cost (Mi11s/kWh) apal7/j B.- “10 EXPLANATION Sum of fuel oi] and lube oil cost. Lube oi] cost is, assumed as 10% of fuel oi] cost. Fuel oil cost is calculated by dividing Diesel Generation (kWh) by generation. Fuel efficiency in kWh/gal. and multiplying result by the fuel oil cost in $/gal. Sum of operation and maintenance costs and Fuel and Lube Oil costs Sum of total fixed cost and total production cost Project energy requirements in MWh same as line 1, load energy - MWh Obtained by dividing total annual cost by energy requirements in MWh and multiplying by 1000 Present worth of total annual cost 2%- 9% “Accumulated total of annual cost 2%- 9% Accumulated total of the present worth of annual costs. 2%-9% Accumulated total of the present worth of annual energy cost in mills/kWh. 2%-9% Busbar cost of surplus hydro- electric energy generated from Tyee Lake and Crystal Lake hydroelectric projects H. apal7/j DESCRIPTION Total Cost (Mills/kWh) B-2 EXPLANATION Sum of Mills per kWh and hydro busbar cost is mills per kWh. i.e. busbar cost of hydroelectric energy delivered to Kake. 1. LOAD DEMAND DEMAND - KW ENERGY — MWH 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 eULwWn B. ADDITIONAL DIESEL UNIT 1 Tew c. Ex UNIT £ STING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 3 €. EXISTING ALTRNT 2 F. ADDITIGNAL ALTRNT 2 UNIT 1 we TOTAL CAPACITY - KW LARGEST UNIT FIRM CAPACITY - KW SURPLUS OR (DEFICIT) - ALT 1 GENERATION — MWH SLT 2 GENERATION - MWH DIESEL GENERATION - MWH KW 1980 1,702 S00 1,400 soo 1,100 613 14,016 1981 sos 2,008 500 soo 300 1,400 Soo 1,100 592 14,016 1982 534 2,114 soo 500 1,400 500 1,100 S66 14,016 POWER COST STUDY FOR KAKE, ALASKA DIESEL (LOW LOAD) 1983 560 2,220 soo 1,600 500 1,100 540 14,016 1934 534 2,310 soo 500 300 1,400 S500 1,100 S16 14,016 1935 603 2.400 1,600 500 1,100 422 14,016 1986 632 2,490 1,600 S00 1,100 463 14,016 1987 6356 2,580 1,400 500 1,100 444 14,016 19383 680 2,670 1,400 500 1,100 420 14,016 1989 708 2,780 Soo S00 300 1,400 500 1,100 392 14,016 la-L 1990 736 2,370 1,600 S00 1,100 344 14,016 1991 764 3,000 1.600 soo 14,0146 1. LOAD DEMAND DEMAND - KW ENERGY - MWH 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 oUPaNn B. ADDITIONAL DIESEL UNIT 1 ra 3 4 Ss 6 C. EXISTING ALTRNT 1 UNIT 1 2 D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT UNIT 1 = 3 n TOTAL CAPACITY - KW LARGEST UNIT FIRM CAPACITY - KW SURPLUS OR (DEFICIT) — ALT 1 GENERATION - MWH ALT 2 GENERATION - MWH KW DIESEL GENERATION - MWH 1992 792 3,110 1,600 soo 1,100 308 14,016 1993 820 3.220 S00 500 1,600 S00 1,100 230 14,016 DIESEL (LOW LOAD) 1994 348 3,333 1,600 S00 1,100 252 14,016 1995 876 3.446 1,600 soo 1,100 224 14,016 1996 904 3,553 1,600 500 1,100 194 14,016 1997 932 3,671 S00 Soo 300 1,600 Soo 1,100 168 14,016 1993 960 3,784 14600 S00 1,100 140 14,016 1999 933 3,895 S00 500 300 300 1,600 - S00 1,100 112 14,016 2000 1,016 4,005 soo S00 1,600 S500 1,100 34 14,016 1A-2 2. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A, EXISTING DIESEL &. ADDITIONAL DIESEL UNIT 4 3 4 s 6 C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 2 2 3 €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNTT Lt 2 3 G. TRANSMISSION PLANT ADDITIONS UNIT t 2 H. MISCELLANEOUS ADDITIONS WNIT t a TOTAL (61000) BASE YEAR DOLLARS INFLATED VALUES 4. FIXED COST (81000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 1980 1981 1982 1,200 1.800 ds DIESEL (LOW LOAD) 1983 1934 1,300 1,300 79 73 1935 1934 1937 1983 1989 1,200 1,300 1,300 1,200 1,800 ' ‘ ' t ' 1,300 1,800 73 7 1990 1,200 1,300 1,360 72 DIESEL (LOW LOAD) 1A-4 1920 1931 1982 1933 1934 1935 19384 1987 1983 1989 1990 2. ADDITIONS SUBTOTAL 1ST % - - - - - - - oo i - - 2ND % - - - - - - - - - - - 3RD % - - - - - - - - - - - 4TH % - - - - - - - - - - - 3. INSURANCE s 6 6 7 7 3 3 ° ? 10 at So ax - - - - - - - - - - - TOTAL FIXED COST ($1000) 1sT % 41 42 42 77 o 36 37 37 a9 IND % 4t 42 42 77 od 36 37 37 39 SRD % 4. 42 42 77 ss 86 Bo 37 = 39 aTH % 4 2 42 77 3s 3s B46 37 37 3° i, PRODUCTION COST ($1000) INFLATED VALUES 4. OPERATION & MAINT 1. DIESEL 117 157 149 132 195 210 s2$ a4 2. ALTRNT 1 - ~~ - « - ~ - 3. ALTRNT 2 = = ” ~ - _ - > ~ - - i. FUEL & LUBE OIL 1. DIESEL 233 300 350 408 466 335 414 703 3204 2. ALTERNATE 1 - > - ~ “ = > * - = - 3. ALTERNATE 2 = - - - = - 7 - - - ca ‘OTSL PRODUCTION COST ($1000) 376 425 $35 SS2 704 79% 33 1,014 1.25! 1,306 NOTS6L ANNUAL T (#1000) 1sT 416 $27 Ton TaD 1.101 2ND % 416 Te 2 riot ORO % 414s mY 2 tT, rot 4TH % 414 Fad 2 1,101 NEEGY REQUIREMENTS — MWH 1,992 2.002 2.220 2,400 26300 MAT DIESEL (LOW LOAD) tans 1930 1931 193 1933 1934 1935, 1936 1937 1933 1939 1990 MILLS /KWH isT % 219 249 306 329 354 412 445 493 2ND % 219 249 306 329 354 412 444 483 3RD % 219 239 304 329° 354 412 446 4TH % 219, 249 3046 329 354 4i2 445 2. PRESENT WORTH ANNUAL COST ($1000) 1ST % 416 25 436 473 490 493 S14 S23 2ND % 416 425 436 473 420 423 Sia 525 SRD % 416 425 436 473 390 498 s14 S25 4TH % 416 425 436 473 390 4938 S14 Sz5 2. ACCUM. AN. COST ($1000) 1ST % 416 1,311 2.040 2.743 4,420 7.745 2,140 ono 416 1.411 2,940 2,743 4,420 7,745 2.140 SRD 415 Lait 2,040 4,420 7.745 7,140 ATH 414 1.411 2,040 4,420 7.743 7,140 i, ACCUMULATED ANNUAL CF 416 1.277 1,750 2.724 3.727 4.241 % 416 1,277 1.750 2,234 2.724 3.727 4,241 sho % 416 2.234 2.724 4.2481 aTH % 415 1.277 2,234 2.724 4,241 1040 a3 a7 088 ab 2.040 sige tb a3 D. ADDITIONAL. ALTRNT i re INT ADDITIONS 1,800 1,800 1,800 1,300 15800) 1,300 2. ADDITIONS SUBTOTAL 15T % 2ND % SRD O% 4TH % B. INSURANCE c. TAX TOTAL FIXED COST ($1000) 1ST % 2ND % SRD % 4TH % S. PRODUCTION COST ($1000) INFLATED VALUES 4. GPERATION & MAINT 1. OTESEL 2. ALTRNT 1 3. ALTRNT 2 BR. FUEL LUBE OIL 1. DIESEL 2. ALTERNATE 1 3. ALTERNATE 2 TOTAL PRODUCTION COST ($1000) TOTAL ANNUAL COST (#1000) 1st % eNO % 2RO % 4TH % “PGY REMUITREMENTS - MWH 1991 at 89 39 39 37 1 & 1s 1992 20 270 2O 30 283 1993 91 aL mW aL DIESEL (LOW LOAD) 1994 14 92 a2 oD 93 1995 ronergey 1S 92 93 23 23 1996 16 24 74 24 OF) 1997 17 9S 9S 25 9S 1A-7 1998 1999 13 20 6 23 26 93 % 23 24 93 aat ays 3.071 36518 3,532 3,991 2000 21 99 27 2? 29 MILLS/KWH 1ST % <ND % ORD % 4TH % C. PRESENT WORTH ANNUAL COST ($1000) 1ST % 2ND % SRD % ATH % D. ACCUM. AN. COST ($1000) 13T % ND % SRD % 4TH % E. SCCUMULATED PRESENT WORTH ANNUAL T ($1000) 1 =up 3RO 4TH NAN ACCUM PRESENT WORTH OF IERGY IN MILL3/KWH 1ST % 2MD % SRD % 4TH % 1991 S23 S23 S23 $23 aan NNN Ss 5: 55: ss2 10,710 10,710 10,710 10,710 S854 5,354 2,410 25410 2,410 2,410 1992 569 549 36? 56? 564 544 544 564 12,479 12,479 12,479 12,479 6,420 6,420 41420 4,420 2,591 2,591 2,51 2,591 1993 619 619 619 O1? 377 377 S77 577 14,472 14,472 14,472 14,472 61997 +997 by 997 61997 2.770 2.770 2.779 2,770 DIESEL (LOW LOAD) 1994 674 674 674 674 S92 Se2 S92 592 14,713 14,713 14,713 14,713 199S 735 738 735 735 1996 B02 302 B02 621 621 21 621 22,108 22,108 22,105 22,105 1997 377 377 377 377 1993 P59 PS? 259 289 10,196 10,104 19,104 19,104 3.445 3,445 3.4645 34645 1999 649 bb9 649 669 33,041 33,041 33,041 33,041 10,775 10,775 10.775 10,773 2000 1,150 1,150 1,150 1,150 435 635 4385 e385 374647 37+647 37,647 371647 see. 1. LOAD DEMAND DEMAND - KW ENERGY -— MWH 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 TUPeNn B. ADDITIONAL DIESEL UNIT 1 eUPSON C. EXISTING ALTRNT 1 UNIT Lt 2 D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 > 3 TOTAL CAPACITY - KW LARGEST UNIT FIRM CAPACITY - KW SURPLUS OR (DEFICIT) - KW ALT 1 GENERATION - MWH ALT 2 GENERATION - MWH DIESEL GENERATION - MWH 1980 432 1,902 1,400 S00 1,100 618 14,016 1981 Sos 2,003 1,600 500 1,100 S92 14,016 1932 $34 2,114 1,600 soo 1,100 546 14,016 POWER COST STUDY FOR KAKE, ALASKA DIESEL (HIGH LOAD) 1B 1933 777 3,320 500 S500 300 300 1,600 S00 1,100 23 14,016 1984 SOL 3,430 1,600 S00 1,100 299 14,0146 1985, 325 3,570 500 S00 300 300 1,400 S00 1,100 275 14,016 1986 8497 3.660 1,400 S00 1,100 251 14,016 1937 873 3,750 1,400 500 1,100 227 14,016 1983 897 3,840 1,400 S00 1,100 203 14,016 1939 944 4,042 1,400 Soo 1,100 1546 14,016 1990 OIL 4,264 1,600 soo 1,100 109 14,016 1B-1 1991 1,033 4,476 1,600 500 1,100 2 14,016 1992 1. LOAD DEMAND DEMAND - KW 1,085 ENERGY — MWH 4,638 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 S500 2 soo 3 300 4 300 5 - 6 ~ B, ADDITIONAL DIESEL UNIT 1 - 2 - 3 - 4 - S - 6 - C. EXISTING ALTRNT 1 UNIT 1 - 2 ae D. ADDITIONAL ALTRNT 1 UNIT 1 - 2 - 3 - €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 oa 2 - 3 F, TOTAL CAPACITY - KW 1,600 LARGEST UNIT Soo FIRM CAPACITY — KW 1,100 SURPLUS OR (DEFICIT) -— KW 1s ALT 1 GENERATION — MWH - ALT 2 GENERATION — MWH - DIESEL GENERATION - MWH 14,016 1993 15132 4,900 2,100 S00 1,600 463 13,396 1994 1,160 5,013 2.100 soo 1,400 440 13,396 DIESEL HIGH LOAD (1B) 1995 1,183 5,126 2,100 S00 1,400 412 13,396 1996 1,216 S,.233 2,100 soo 1.400 334 13,396 1997 1,244 5.351 1993 1,272 5,464 2,100 S00 1,400 bs 13,39) 2,100 S00 1,400 300 135394 2,100 S00 1,600 272 13,396 1B-2 DIESEL HIGH LOAD (LB) 1B-3 1930 1981 1982 1933 1934 1985, 19846 1937 1988 1989 1990 3. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A. EXISTING DIESEL 1,300 1,800 1,800 1,800 1,300 1,800 1,800 1,300 1,800 1,800 1,800 B. ADDITIONAL DIESEL UNIT 1 “ = - = = - - - _ _ _ oUPWN 1 ' ' ' ' 1 ' ' ' ' 1 C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 - = = 7 is = = = = _ = 2 = = = = = = - - - - 7 3 - - - - - - - - - - - E. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 - - - - - - = - - = = 2 - - - - - es 7 - - = - 3 - = = 7 = - = - - - = G. TRANSMISSION PLANT ADDITIONS UNIT 1 - - - - - - - - - - - 2 - - = os = = 7 = - = - H. MISCELLANEOUS ADDITIONS UNIT 1 - - - - - - - - - - a 2 - = 7 7 ~ - = - - - - TOTAL ($1000) : BASE YEAR DOLLARS 1,300 1,800 1,800 1,300 1,800 1,800 1,300 1,300 1,300 1,800 1,800 INFLATED VALUES 1,£00 1,300 1,800 1,800 1,800 1,300 1,800 1,800 1,300 1,300 1,800 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 36 34 70 73 723 73 73 73 73 73 ra) oe DIESEL HIGH LOAD (1B) 18-4 1930 19731 1982 1983 1934 1985, 1986 1987 19383 1989 1990 2. ADDITIONS SUBTOTAL 1ST % i * = = - - - = - - - 2ND % = - - = - - - x - - - SRD % = i - - = = - = = - - 4TH % = = i - - ~ - - - i - B. INSURANCE Ss 6 6 7 7 8 3 9 9 10 at c. TAX - - - - - - - - - - - TOTAL FIXED COST ($1000) 1st % 41 42 42 77 8s eso 86 37 37 38 89 2ND % AL 42 42 77 3s 86 36 87 s7 838 s? SRD % 41 42 42 77 es 86 36 87 87 38 37 ATH % 41 42 42 77 ss go 86 87 87 83 89 5S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION & MAINT 1. DIESEL 117 26 135 154 168 131 195 209 2. ALTRNT 1 3. ALTRNT 2 = - - - - - - - - - = nN nN a 244 264 B. FUEL & LUBE OIL 1. DIESEL 253 300 350 b19 703 796 902 1,022 1,156 1,348 1,567 2. ALTERNATE 1 3. ALTERNATE 2 - - - - - i ~ = i i oe TOTAL PRODUCTION COST ($1000) 375 426 43s 7758 S71 977 1,097 231 1,391 1,592 1,831 TOTAL ANNUAL COST ($1000) 1ST % 416 468 S27 ss2 956 1,063 1,183 1,318 1,448 1,430 1,920 2ND % Als 463 S27 sS2 ISG 1,063 1,133 1,319 1,468 1,680 1,720 ORD % 41s AL S32 eS2 956 1,063 1,123 1,318 1,463 1,420 1,920 4TH % Ale 463 S27 ss2 IS 1,043 1,183 1,513 15468 1,430 1,920 ENERGY REQUIREMENTS - MWH 1,902 2,003 2.114 3.390 3,570 35460 3.750 3,340 4,052 4,244 MILLS/KWH 1ST % 2ND % SRD % 4TH % C. PRESENT WORTH ANNUAL COST ($1000) 1ST % 2ND % SRD % 4TH % D. ACCUM. AN. COST ($1000) 1ST % 2ND % SRD % ATH % €. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 1ST % 2ND % SRD % ATH % F. ACCUM PRESENT WORTH OF ENERGY IN MILLS/KWH 1ST % 2ND % SRD % 4TH % 219 219 219 219 41S 416 Ald 416 416 416 416 416 416 41S 416 416 219 219 219 219 1981 233 233 233 233 425 425 425 425 94 294 a4 aca S41 S41 S41 841 431 431 431 431 DIESEL HIGH LOAD (1B) 1982 249 249 249 249 436 436 436 436 1,411 1,411 1,41 1,411 1,277 1.277 1.277 1,277 637 637 637 637 1933 251 251 251 251 640 640 640 640 25263 2,263 2,263 2,263 1,917 1,917 1,917 1,917 826 826 S26 B26 1984 275 275 275 275 653 6353 653 483 3,219 3,219 3.219 3,219 2,570 2,570 2,570 2,570 1,014 1,014 1,014 1,014 1985 293 293 298 293 19386 323 323 323 323 1987 351 SSL 351 351 676 676 676 676 6,783 6,733 6,783 6,733 4,574 4,574 1574 4,574 1,561 1,561 1,561 1,561 1B-5 1933 3382 332 382 332 635 685 6sS 635 8.251 8,251 S,251 3,251 5.25? 5.259 5.259 5,257 1,739 1,739 1,739 1,739 1939 415 415 415 41s 712 712 712 712 9,931 9,931 9,931 9 P31 S,971 S,971 S,?71 S971 1,915 1,915 1,915 1,915 1990 450 450 450 450 740 740 740 740 11,851 11,851 11,851 11,851 6 711 6 7iL S 71L 6 711 2,088 2,083 2,083 2,088 3. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL UNIT 1 oUPWN C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 3 G. TRANSMISSION PLANT ADDITIONS WNIT 1 2 H. MISCELLANEOUS ADDITIONS UNIT 1 2 TOTAL ($1000) BASE YEAR DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 1991 1,300 1,800 +300 1992 1,800 73 DIESEL HIGH LOAD (1B) 1993 1,800 475 2,275 25944 73 1994 1,800 475 2.275 2,944 73 1995 1,800 475 2,275 2,944 72 1996 1,800 475 nr ay ba 73 1997 1,800 73 1993 2.278 2.944 73 18-6 1999 2,275 2,944 73 2000 1,800 ' 2,275 2944 72 2. ADDITIONS SUBTOTAL 1ST % 2ND % SRD % 4TH % B. INSURANCE Cc. TAX TOTAL FIXED COST ($1000) 1ST % 2ND % SRD % 4TH % S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION & MAINT 1. DIESEL 2. ALTRNT 1 > 3. ALTRNT 2 B, FUEL & LUBE OIL 1. DIESEL 2. ALTERNATE 1 3. ALTERNATE 2 TOTAL PRODUCTION COST (#1000) TOTAL ANNUAL COST (1000) 1ST % 2ND % SRD % ATH % ENERGY REOUIREMENTS -— MWH A99L 1. 39 387 8? 89 1,813 25104 2,193 2,193 2,193 2.193 4,474 1992 90 90 90 90 309 2,104 2.413 2,503 2,503 2.503 2.502 4,633 DIESEL HICH LOAD (1B) 1993 1994 1995 46 46 46 70 70 70 83 83 3s 109 109 109 21 23 24 145 147 143 149 171 172 187 1399 190 208 210 211 335 360 | 3s 2,430 21746 3,102 2.765 3.106 = 3,490 2,910 3.253 3,638 2,934 3,277 31662 2,952. 3,295 31420 2.973 3,316 3,708 4,200 5.013 5,124 1996 46 79 as 109 26 150 174 192 213 1997 46 70 83 109 23 152 176 194 215 449 1992 46 790 33 109 30 154 173 1946 217 483 13-7 1999 46 790 ss 109 32 156 180 193 219 2000 46 79 33 109 34 153 132 200 221 MILLS/KWH 1ST % 2ND % SRD % 4TH % C. PRESENT WORTH ANNUAL COST ($1000) 1st % 2ND % SRD % 4TH % D. ACCUM. AN. COST (41000) 1st % 2ND % SRD % 4TH % E. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 1sT % 2ND % SRD % 4TH % F. ACCUM PRESENT WORTH OF ENERGY IN MILLS/KWH 15T % 2ND % SRD % 4TH % 1991 490 420 490 490 771 771 771 771 14,044 14,044 14,044 14,044 7,482 7,482 7»482 7482 2,240 2,260 2,260 2,260 1992 793 798 793 793 16,547 16,547 16,547 146,547 8,280 3,230 $,280 3,280 2,430 2,430 2,430 2,430 DIESEL HIGH LOAD (1B) 1993 594 S99 602 607 343 $50 sss S61 19,457 19,481 19,499 19,520 9123 9+130 9,135 Pr Al4L 2,402 2,604 2,404 21606 1994 649 654 657 661 857 863 863 873 22,710 22,753 22,794 22,836 9,980 9,993 10,003 10,014 2.773 2,776 2.777 2.780 1995 710 715 718 722 g71 877 381 886 26.348 241420 26,474 26,537 10,851 10,870 10,984 10,900 21943 25947 2,949 2,953 1996 Tas 732 735 739 see soL 295 900 30,419 30,515 30,587 30,671 11,737 11,761 11,779 11,800 3,112 3117 3,120 3,125 1997 352 S56 ss? 863 902 908 910 914 34,978 35,094 35,186 35,291 12,439 12,647 12,489 12,714 3,231 3,236 35270 31296 1993 934 233 oat 245 917 22 928 929 40,077 40,221 40,329 40,455 13,556 13,589 13,614 13.643 3.449 3,455 3,459 3,466 18-8 1999 1,024 1,022 1,031 1,035 933 937 240 244 45,735 45,953 46,079 46,226 14,489 14,524 14,554 14,537 3616 31623 3,629 35635 2000 1,124 1,123 1,131 1,135 950 953 956 9S 52,173 52,365 52,507 52,677 15,439 15,479 15,510 15,546 3,783 3,791 31796 3,804 1980 1. LOAD DEMAND DEMAND — KW 482 ENERGY — MWH 1,902 2. SOURCES — KW A. EXISTING DIESEL LOCATION OR UNIT 1 500 2 S500 3 300 4 300 5 = & - 8. ADDITIONAL DIESEL. UNIT 1 - 2 - 3 - 4 - Ss - 6 - C. EXISTING ALTRNT 1 UNIT 1 - 2 - D. ADDITIONAL ALTRNT 1 UNIT 1 = 2 - 3 - E. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 - 3 - TOTAL CAPACITY — KW 1,600 LARGEST UNIT S00 FIRM CAPACITY — KW 1,100 SURPLUS OR (DEFICIT) — KW 613 ALT 1 GENERATION — MWH = ALT 2 GENERATION — MWH - OIESEL GENERATION — MWH 14,016 1981 sos 2,008 500 500 300 300 prrrea 1,600 S00 1,100 S92 14,016 1982 534 2114 1,600 Soo 1,100 566 14,016 POWER COST STUDY FOR KAKE+ ALASKA 34.5 kV, 39 (LOW LOAD) 1983 S60 2220 1,600 S500 1,100 S40 14,016 1984 5384 27310 3.350 1,750 1,600 1,016 91,509 14,0186 19385 608 2,400 3,350 1,750 1,600 992 88,790 14,016 1986 632 2490 35350 1,750 14600 968 85,098 14,016 1987 656 2-580 34350 1,750 1,400 944 81,406 14,014 19ss 680 2.670 500 500 300 300 1,750 3,350 1,750 1,600 920 77,714 14,016 1989 708 2,780 3.350 14750 1,600 392 73,910 14,0146 1990 736 2890 3,350 1,750 1,400 864 70,086 14,016 1991 764 3,000. 500 500 300 300 3.350 1.750 1,600 836 66,844 14,016 1992 1. LOAD DEMAND DEMAND — KW 792 ENERGY — MWH 3-110 2. SOURCES — KW A. EXISTING DIESEL LOCATION OR UNIT 1 500 2 500 3 300 4 300 5 - 6 - B. ADDITIONAL DIESEL UNIT 1 - 2 - 3 = 4 - s = ’ - C. EXISTING ALTRNT 1 UNIT 1 - 2 - D. ADDITIONAL ALTRNT 1 UNIT 1 1,750 2 - 3 - E. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 - 2 - 3 = TOTAL CAPACITY - KW 3350 LARGEST UNIT 1,750 FIRM: CAPACITY — KW 1,600 SURPLUS OR (DEFICIT) — KW 803 ALT 1 GENERATION - MWH 63,600 ALT 2 GENERATION — MWH - DIESEL GENERATION — MWH 14,016 1993, 820 3.220 3,350 1,750 14600 780 60,357 14,016 1994 848 3-333 Soo S500 300 300 1,750 3,350 1,750 1,600 7S2 57,213 14,016 1995 876 3,446 soo 500 300 300 1,750 3,350 1,750 1,400 724 54,071 14,016 34.5 kV, 30 (LOW LOAD) 1996 904 3,558 500. S00 300 300 0) 80a eece 1 1.750 3,350 1,750 1,400 696 50,900 14,016 1997 932 3,671 500 S500 300 300 1.750 3,350 1,750 1,600 668 47,700 14,016 1993 960 3.784 S00 S500 300 300 1.750 34350 1,750 1,600 640 44,500 14,016 1999 9383 3,895 S00 500- 300 300 1,750 3350 1,750 1,600 612 41,300 14,016 2000 1,016 4,005 500 Soo 300 300 3,350 1,750 1,600 5384 38,100 14,016 3. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL UNIT t OU aEwh C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 2 3 G. TRANSMISSION PLANT ADDITIONS UNIT 1 H. MISCELLANEOUS ADDITIONS UNIT 2 > TOTAL (#1000) BASE YEAR DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 2. ADDITICNS 1980 1,800 1,800 1,800 1981 1,800 ' 1,300 1,300 y e 34.5 kV, 30 (LOW LOAD) 1982 1933 1,800 1,800 1934 1,800 6,735 8,270 73 1985 1,800 6735 8,270 1986 1,800 6,735 3.270 1987 1,800 4,095 840 1983 1,800 4,095 840 6,735 $,270 73 2A-3 1989 1,300 4,095 840 6,735 8,270 1990 1,300 4,095 340 6,735 3,270 73 SUBTOTAL 1ST % 2ND % SRD % 4TH % B. INSURANCE c. TAX TOTAL FIXED COST ($1000) 1ST % 2ND % SRD % 4TH % S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION & MAINT 1. DIESEL 2. ALTRNT 1 3. ALTRNT 2 B. FUEL & LUBE OIL 1. DIESEL 2. ALTERNATE 1 3. ALTERNATE 2 TOTAL PRODUCTION COST ($1000) TOTAL DIESEL COST (81000) 1ST % 2ND % SRD % 4TH % HYDRO BUS COST (MILLS/KWH) MWH SUPPLIED HYDRO TOTAL HYDRO COSTS 1930 41 41 4 41 117 253 416 416 416 41é 1981 42 42 42 42 126 426 34.5 kV, 36 (LOW LOAD) 1982 42 42 42 42 135 S27 S27 527 S27 1933 77 77. 77 77 146 1984 259 375 S00 612 344 420 535 497 135 SL 1646 S10 646 751 843 447 1985, 259 395 soo 612 Ey 345 421 586 698 144 34 21400 670 1984 289 395 500 612 345 431 S86 693 154 36 190 S35 671 774 Sse 1937 259 395 soo 612 346 482 S587 699 165 3? 204 1933 259 395 S00 612 346 482 587 699 176 41 217 543 499 204 P16 239 2,470 2A-4 1989 289 395 500 612 10 347 483 sss 700 189 1990 259 395 soo 612 at 343 484 sso 701 202 47 S°7 33 $38 950 34.5 kV, 30 (LOW LOAD) 2A-5 1980 1931 1982 1983 - 1934 1985, 1936 1987 1983 1989 1990 TOTAL ANNUAL COSTS 1st % 4lé 463 S27 629 1,157 1,193 1,225 1,210 1,201 1,202 1,210 2ND % 416 463 S27 629 1,293 1,329 1,341 1,346 1,337 1,338 1,346 SRD % 416 463 S27 627 1,398 1,434 1,466 1,451 1,442 1,443 1,451 4TH % 416 463 S27 429 1,510 1,546 1,578 1,563 1,554 1,555 1,563 TOTAL MWH REQUIRED 1,902 2,008 25114 2,220 2,310 2,400 2,490 2,580 2,670 2.780 2,890 MILLS/KWH 1sT % 219 233 249 283 So. 497 492 469 450 432 419 2ND % 219 233 249 283 540 S54 S47 S22 So. 431 466 SRD % 219 233 249 283 605 S93 539 562 540 S19 so2 4TH % 219 233 249 283 454 644 434 606 S82 ss? S41 C. PRESENT WORTH ANNUAL COST ($1000) 1ST % 416 425 436 473 790 741 671 621 5460 S10 466 2ND % 416 425 436 473 883 825 763 oat 624 567 S19 SRD % 416 425 436 473 95 890 S27 744 673 612 ss9 4TH % 416 425 436 473 1,031 960 sal 802 725 639 603 DBD. ACCUM AN COST ($1000) 1ST% 416 834 1,411 2,040 3,197 4,390 5,615 6,825 8,024 9,22: 10,433 2ND% Als $34 1,411 2,040 3,333 41662 4,023 7369 3,706 10,044 11,390 SRDZ ALS 334 1,411 2,040 3,438 4,872 4,333 778? 9.23 10,674 12,125 4TH% ALG B34 1,411 2,040 3,550 S076 6 E74 8,237 I 7AL 11,346 12,909 €. ACCUMULATED PRESENT WORTH ANNUAL COST (#1000) 15T% 416 S41 1,277 1,750 3,231 35972 4,593 5,153 S643 6.129 2ND% Ale B41 1,277 1,750 3,453 4,226 4,917 5,541 6.103 61627 3RDZ 416 S41 1,277 1,750 3,595 4,422 5,146 5,339 4451 7,010 4TH% 416 S4t 1,277 1,750 3,741 4,432 5,434 S152 4313 7,421 F. ACCUM. PRES. WORTH OF ENERGY IN MILLS/KWH 1ST% 219 431 637 sso 1,192 1,501 1,779 2,020 2.231 OND 217 431 &37 850 1,233 1,577 1,304 2.154 2, 38% SRDA 219 421 437 1,263 11634 1,766 2,254 2,504 4THZ 219 431 437 15297 1,497 2,085 2,366 25637 1991 3. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A. EXISTING DIESEL 1,800 B. ADDITIONAL DIESEL UNIT OURWN 1 C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT Lt - 2 - 3 - €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 - 2 3 - G. TRANSMISSION PLANT ADDITIONS UNIT 1 4,095 2 S40 H. MISCELLANEOUS ADDITIONS UNIT 1 - 2 TOTAL (#1000) BASE YEAR DOLLARS 4,735 INFLATED VALUES 3,270 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1." EXISTING 73 2. ADDITIONS 1992 1,800 4,095 $40 73 34.5 kV, 30 (LOW LOAD) 1993 1,300 4,095 840 6,735 3,270 73 1994 1,300 6.735 2,270 1995 1,800 4,095 S40 1996 1,300 4,095 £40 6,735 8,270 73 1997 1,800 4,095 340 6,735 8,270 1998 1,800 4,095 340 6,735 3,270 78 1999 1,300 4,095 840 6,735 8,270 2A-6 2000 1,800 4,095 340 4,735 3,270 73 SUBTOTAL 1ST % ND % SRD % 4TH % B. INSURANCE c. TAX TOTAL FIXED COST ($1000) 1ST % 2ND % SRD % 4TH % S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION & MAINT 1. DIESEL 2. ALTRNT 1 3. ALTRNT 2 B. FUEL & LUBE OIL 1, DIESEL 2. ALTERNATE 1 3. ALTERNATE 2 TOTAL PRODUCTION COST (#1000) TOTAL DIESEL COST ($1000) 1ST % 2ND % SRD % 4TH % HYDRO BUS COST (MILLS/KWH) MWH SUPPLIED HYDRO TOTAL HYDRO COSTS 1991 259 395 500 612 it 343 434 5389 7OL 216 Si 615 731 e356 963 0200 402 1992 259 395 500 612 12 349 435 590 702 231 s4 634 7790 275 937 195 110 34.5 kV, 30 (LOW LOAD) 1993 350 436 SL 703 247 ss 305 655 71 So 1,008 189 609 1994 259 395 500 612 14 351 437 592° 704 265 62 673 814 219 1,031 1995 259 S95 S500 G12 1s 352 438 S93 705 283 66 349 701 837 242 0s4 179 446 1996 259 395 soo 6 12 16 353 4389 594 706 303 7. 3 7 Bi 9 74, 27 62 63 1,080 1 73 1997 259 395 S00 612 17 354 490 s9S 707 324 7& 400 754 390 993 1,107 171 B.471 623 1998 259 395 500 612 138 355 471 S94 703 347 SL P19 1,024 1,136 1999 25? 395 500 612 357 493 S93 710 S71 37 453 s15 OSL 1,056 1,143 164 3,395 639 2A-7 2000 259 395 500 612 358 494 599 7i1 397 93 490 S43 984 1,089 1,201 161 4,005 TOTAL ANNUAL COSTS 1ST % 2ND % SRO % 4TH % TOTAL MWH REQUIRED F. MILLS/KWH 1ST % 2ND % SRD % 4TH % PRESENT WORTH ANNUAL COST ($1000) 1sT % 2ND % SRD % 4TH % ACCUM AN COST ($1000) 1ST% 2ND% SRD% ATHA ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 1ST% 2ND% SRDZ 4THA ACCUM. PRES. WORTH OF ENERGY IN MILLS/KWH 13TH 2ND% 3RD% 4TH% 1991 1,224 15360 1,465 1,577 3,000 403 453 433 S26 431 473 sis sss 11,642 2,750 13,570 14,436 6,560 7105 7,525 71976 1992 1,240 1,376 1,421 1,593 3,110 399 442 476 512 395 433 472 Sos 12,902 14,124 15,071 164,072 4.955 7.543 71997 8.454 2,246 3,072 3,244 3.431 34.5 kV, 30 (LOW LOAD) 1993 1,264 1,400 1,505 1,617 3,220 393 435 467 S02 346 406 436 463 14,166 15,526 14,576 171496 7,32 7.94F 8,433 3,952 21960 3,193 3,379 3,576 1994 1,291 1,427 1,532 15644 3,333 387 428 440 493 340 376 403 433 15,457 16,953 18, 103 19,340 7661 3.325 3,996 9385 31062 3,311 3+ 708 1995 1,318 1,454 1,559 1,471 3,446 382 422 452 43s 3146 343 373 400 16,775 13,407 19,667 21,011 3,153 3.412 3,608 1996 1,350 1,486 1,703 379 41g 447 479 294 323 344 S71 13,125 19,393 21,25: 22,714 8,271 10,15. 503 705 3,926 1997 1,382 1,518 1,623 1,735 3671 376 414 442 473 273 300 321 343 19,507 21,411 22,831 24,449 3.792 4,020 1998 1,415 1,551 1,656 1,748 3,734 374 410 433 467 254 279 293 318 20,922 22,962 24,537 26,217 8,793 2,575 10,174 10,817 1999 1,454 1,570 1,695 1,807 3,895 373 408 435 464 233 240 277 295 22,376 24,552 24.232 23,024 91036 9,335 10,451 11,112 2A-8 2000 1,493 1,629 1,734 1,246 4,005 373 407 433 461 22 242 2538 274 23,869 26,181 27,964 29,8370 9253 10,077 10,709 11,586 3.492 35797 4,004 4,249 1980 1. LOAD DEMAND DEMAND - KW 482 ENERGY -.MWH 1,902 2. SOURCES — KW A. EXISTING DIESEL LOCATION OR UNIT 1 S00 2 500 3 300 4 300 5 = 3 tl B. ADDITIONAL DIESEL UNIT 1 - 2 t 3 tt 4 - 3 nm : é - C. EXISTING ALTRNT 1 i UNIT 1 - 2 I D. ADDITIONAL ALTRNT 1 UNIT 1 7 2 ii 3 4 E. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 - 2 Wy 3 W TOTAL CAPACITY - KW 1,600 LARGEST UNIT 500 FIRM CAPACITY — KW 1,100 SURPLUS OR (DEFICIT) - KW 618 ALT 1 GENERATION — MWH - ALT 2 GENERATION — MWH - DIESEL GENERATION — MWH 14,016 1981 5038 2,008 1,600 S500 1,100 S92 14,016 1982 534 2-114 500 S500 300 300 nr 1,600 Soo 1,100 566 14,016 POWER COST STUDY FOR KAKE, ALASKA 34.5 kV, 30 (HIGH LOAD) 1983 777 3+320 S500 Soo 300 300 1,600 500 1,100 323 14,016 1984 so 3,480 500 S00 300 300 peru 1,750 3,350 1,750 1,400 799 91,509 14,016 1985 825 3,570 500 500 300 300 3.350 1,750 1,600 7758 88,790 14,0186 1986 849 3+660 Soo Soo 300 300 pranrae 1.750 3,350 1,750 1,600 751 85,098 14,016 1987 873 3.750 Soo 500 300 300 prong 3,350 1,750 1,600 727 81,406 14,016 1988 397 3,840 S500 500 300 300 prereeue 3,350 1,750 1,600 703 77,714 14,016 1989 944 4,042 Soo 500 300 300 3,350 1,750 1,400 656 73,910 14,014 1990 991 4,264 500 500 300 300 petro 3,350 1,750 1,600 609 70,086 14,018 2B-1 1991 1,038 4,476 S00 Soo 300 300 1,750 3.350 1,750 1,600 562 66,844 14,016 1992 1. LOAD DEMAND DEMAND — KW 1,035 ENERGY - MWH 4,688 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 soo 2 S00 3 300 4 300 5 Ps ’ i B. ADDITIONAL DIESEL UNIT 1 - 2 Bi 3 x 4 a 5 Hu ‘ Bo C. EXISTING ALTRNT 1 UNIT 1 ext 2 a D. ADDITIONAL ALTRNT 1 UNIT 1 1,750 2 = 3 a €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 7 2 i 3 - TOTAL CAPACITY — KW 3,350 LARGEST UNIT 1,750 FIRM CAPACITY — KW 1,600 SURPLUS OR (DEFICIT) - KW Sis ALT 1 GENERATION — MWH 63,600 ALT 2 GENERATION — MWH - DIESEL GENERATION — MWH 14,016 1993 1,132 4,900 S00 500 300 300 1,750 3,350 1,750 1,600 463 60,357 14,016 1994 15160 5.013 1,750 1 34350 1.750 14600 440 57,213 14,016 34.5 kV, 30 (HIGH LOAD) 1995 1,183 S126 1,750 3,350 1.750 1,600 412 54,071 14,016 1996 1,216 5.238 500 S00 300 300 1,750 3,350 1,750 1,600 334 50,900 14,016 1997 1,244 S.351 500 500 300 300 1,750 3,350 1,750 1,600 356 47,700 14,016 1998 “1,272 5.464 500 S500 300 300 1,750 3,350 1,750 1,600 3238 44,500 14,016 1999 1,300 5.575 3.350 15750 1,600 300 41,300 14,016 2000 1,328 5.6385 500° 500- 300 300 35350 1,750 1,600 272 38,100 14,016 2B-2 3. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL UNIT 1 hed OUawh C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 2 3 G. TRANSMISSION PLANT ADDITIONS UNIT 1 > H. MISCELLANEOUS ADDITIONS UNIT 1 2 TOTAL ($1000) BASE YEAR DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 2. ADDITIONS 1980 1,800 1,300 1.300 36 1981 1,800 1,800 1,800 36 34.5 kV, 30 (HIGH LOAD) 1982 1,300 1,300 1,300 1983 1,800 1,800 1,300 79 1984 1,800 4,735 8,270 73 1985 1,800 6735 8,270 73 1986 1,800 4,095 340 6,735 8,270 73 1987 1,800 4,095 340 6.735 8.270 73 1933 1,300 4,095 840 D> n Wo 3 73 2B-3 1989 1,800 4,095 840 4,735 8,270 73 1990 1,800 4,095 840 6.735 8,270 73 SUBTOTAL 1ST % 2ND % 3RD % 4TH % B. INSURANCE c. TAX TOTAL FIXED COST ($1000) 1st % 2ND % SRD % 4TH % S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION & MAINT 1. DIESEL 2. ALTRNT 1 3. ALTRNT 2 B. FUEL & LUBE OIL 1. DIESEL 2. ALTERNATE 1 3. ALTERNATE 2 TOTAL PRODUCTION COST ($1000) TOTAL DIESEL COST ($1000) 1st 2ND SRD 4TH NNNN HYDRO BUS COST (MILLS/KWH) MWH SUPPLIED HYDRO TOTAL HYDRO COSTS 1930 41 41 4t 4L Als 414 Ale 416 1931 42 42 42 42 300 426 443 443 463 468 34.5 kV, 30 (HIGH LOAD) 1982 1983 1984 - - 259 - - 295 - - S00 - - 412 & 7 7 42 77 344 42 77 480 42 77 ses 42 77 497 135 157 135 - - 31 350 419 - 435 774 166 S27 $52 S10 527 253 646 S27 253 751 S27 as3 263 - - 280 - - 3,480 - - 974 19285 259 395 500 612 345 431 5386 693 144 34 173 23 452 764 876 1986 259 395 500 612 345 431 S86 693 154 36 190 s35 671 776 833 277 1987 259 ses 500 612 346 482 587 699 165 39 sso 636 TAL 203 256 960 1988 259 395 500 612 B46 482 S87 699 176 41 217 563 499 804 1s 239 3,840 AS 2B-4 1989 259 395 500 612 10 347 433 sss 700 189 44 sso 7146 32 933 1990 a, 259 395 S00 612 it 343, 494 S389 701 202 47 249 904 TOTAL ANNUAL COSTS 1ST % 2ND % SRD % 4TH % TOTAL MWH REQUIRED D. MILLS/KWH 1ST % 2ND % 3RD % 4TH % PRESENT WORTH ANNUAL COST ($1000) 1st % 2ND % . SRD % 4TH % ACCUM AN COST ($1000) 1ST% 2ND% SRD% 4TH% ACCUMULATED PRESENT WORTH ANNUAL ACCUM. ENERGY cast ($1000) 1sT% 2ND% SRD% 4TH% PRES. WORTH OF IN MILLS/KWH 1ST% 2ND% SRD% 4TH% 1980 1, 416 416 416 416 902 219 219 219 219 416 416 416 416 41s 416 416 416 416 416 416 416 219 219 219 219 1981 468 463 463 468 2,008 233 233 233 233 425 425 425 425 234 834 8s4 384 341 841 S41 S41 431 431 431 431 34.5 kV, 30 (HIGH LOAD) 1982 27 S27 S27 S27 2114 249 249 249 249 436 436 436 436 1,411 1,411 1,411 1,411 1,277 1,277 1,277 1,277 437 437 437 437 1983 eso ess $s3 353 3,390 252 252 252 252 64L 641 64l 641 21264 2,264 2,264 21264 1,913 1,918 1,713 1,918 824 8246 826 826 1984 1,484 +620 1,725 1,837 3,480 426 466 496 S238 1,014 1,107 1,178 1,255 3,743 3,984 3,939 4,101 2,932 3,025 3,096 3,173 1,117 1,144 1,145 1,187 19385 1,519 455 1,760 1,872 3,570 425 464 493 524 943 1,027 1,092 1,162 S267 5,539 5,749 5.973 3,375 4,052 4,133 4,335 1,331 1,432 1,471 1,512 1986 1,549 1,685 1,790 1,902 3,660 423 460 439 520 874 O51 1,010 1,073 6,316 722 71539 7,875 4,749 5,003 5,193 5,403 1,620 1,492 1,747 1,305 1987 1,510 1,646 1,751 1,842 3,750 403 439 467 497 775 S45 893 956 8,326 8,870 9,230 9,733 5,524 5,348 6,096 41364 1983 1,481 1,617 1,722 1,834 3,840 386 421 443 478 eat 754 $03 85s 9,807 10,487 11,012 11,572 6215 6,402 6,899 7.219 2,007 2,113 21196 2.293 23-5 1989 1,483 1,624 15729 1,841 4,052 367 401 427 454 631 639 733 731 11,295 12,111 12,741 13,413 6,844 7,291 71632 8,000 251463 2,283 2.377 2474 1990 1,501 1,437 1,742 1,854 4,264 352 334 409 435 S79 631 672 JAS 12,796 13,748 14,483 15,267 7425 7,922 8,304 3.715 2,299 2,431 2.535 2.644 3. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL UNIT 1 2 TUSwt C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 E. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 Ps 3 G. TRANSMISSION PLANT ADDITIONS UNIT 1 > H. MISCELLANEOUS ADDITIONS UNIT 1 ° TOTAL ($1000) BASE YEAR DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 2. ADDITIONS 1991 1,800 4,095 840 6.735 8,270 73 1992 1,800 4,095 340 6,735 3,270 73 34.5 kV, 30 (HIGH LOAD) 1993 1,300 4,095 340 6,735 8,270 73 1994 1,300 4,095 340 4,735 8,270 73 1995, 1,800 4,095 840 65735 8,270 73 1996 1,800 4,095 340 6,735 3,270 73 1997 1,300 4,095 340 6,735 8,270 73 1998 1,800 4,095 840 6,735 270 73 1999 1,800 4,095 340 6735 8,270 73 28-6 2000 1,800 4,095 340 6,735 8,270 73 SUBTOTAL 1ST % 2ND % SRD % ATH % B. INSURANCE c. TAX TOTAL FIXED COST ($1000) 1ST % 2ND % SRD % 4TH % S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION & MAINT 1. DIESEL 2. ALTRNT 1 3. ALTRNT 2 B. FUEL & LUBE OIL 1. DIESEL 2. ALTERNATE 1 3. ALTERNATE 2 TOTAL PRODUCTION COST (#1000) TOTAL DIESEL COST ($1000) 1ST % 2ND % SRD % 4TH % HYDRO BUS COST (MILLS/KWH) MWH SUPPLIED HYDRO TOTAL HYDRO COSTS 1991 4a 259 295 500 612 11 348 484 sso 7oL 216 Si 267 615 7S1 ss 263 476 9209 1992 259 395 500 612 12 349 495 590 702 231 54 285 634 779 s75 937 195 34.5 kV, 30 (HIGH LOAD) 1993 259 395 soo 412 13 350 486 S91 703 247 53 Q 5 a 455 71 89% 1,008 189 4,200 926 1994 259 395 soo 412 14 351 437 S92 704 265 62 478 g14 919 1,031 184 5,013 1995, 1s Ss 257 395 soo 612 1S 352 483 S93 705 283 66 349 7O1 $37 942 os4 179 124 O17 1996 259 395 soo 612 16 353 439 594 706 303 71 374 727 8463 968 1,080 175 5,233 917 1997 259 395 500 412 17 354 490 59S 707 324 76 400 7354 370 995 1,107 171 AIS 1998 259 395 500 412 18 355 491 5% 708 347 st 733 919 1,024 1,13) 167 5,464 913 1999 259 395 500 612 20 357 493 S93 710 371 87 a5 951 1,056 1,168 5,575 o14 2B-7 2000 259 395 500 612 21 358 494 599 7iL 397 93 490 843 934 1,089 »201 161 5,685 A158 TOTAL ANNUAL COSTS 1st % 2ND % SRD % 4TH % TOTAL MWH REQUIRED MILLS/KWH 1ST % 2ND % SRD % 4TH % PRESENT WORTH ANNUAL COST ($1000) 1ST % 2ND % SRD % ATH % ACCUM AN COST ($1000) 13T% 2ND% SRDZ ATHX ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 1ST% 2ND% SRDZ 4THX accuUM. PRES. WORTH OF ENERGY IN MILLS/KWH 1ST% 2NDZ SRD% 4THZ 1PPL 1,524 1,440 1,765 1,877 4,476 340 371 394 41? S36 534 621 660 14,320 15,403 16,243 17,144 7961 3,506 $,925 9,375 2.419 2.561 2b74 2.791 1992 1,546 1,682 1,787 1,899 4,683 330 359 381 405 493 S36 S69 605 15,866 17,090 13,035 19,043 3,454 9,042 9.494 94930 2,524 2675 2,795 21920 34.5 kV, 30 (HIGH LOAD) 1993 1,581 1,717 1,822 1,934 4,900 323 350 372 395 458 497 S23 S60 17,447 18,307 19,857 20,977 8,912 2,539 10,022 10,540 2618 2,774 21903 3,034 1994 1,600 1,736 1,841 1,953 5,013 319 346 367 390 421 457 43s 514 19,047 20,543 21,698 22,930 9,333 9199S 10,507 11,054 2,702 2.847 3,000 3,137 1995, 1,613 1,754 1,359 1,971 5,124 316 342 363 335 387 420 445 472 20,665 22.297 23,557 24,901 9,720 10,416 10,952 11,526 2.778 2,949 3,037 1996 1,644 1,780 1,885 1,997 5,238 314 340 360 381 353 387 410 435 22,309 24,077 25,442 26,893 10,073 10,803 11,262 11,741 2,846 3,023 3.1465 3312 1997 1,669 1,805 1,910 2,022 5,351 312 337 357 378 330 357 373 400 23,973 25,882 27,352 23,920 10,408 11,140 11,740 12,361 2,908 3,090 3,23) 1998 1,696 1,332 1,937 2,049 5,464 310 335 sss 375 305 329 343 369 25,674 27,714 29,289 30,969 10,713 11,489 12,033 12,720 2,954 3,150 3,300 3,454 1999 1,729 1,965 14970 2,082 5.575 310 335 353 373 283 305 322 340 27,403 29.579 31,259 33,051 10,994 11,794 12,410 13,070 3,018 +205 3.7598 3.515 28-8 2000 1,763 1,899 2,004 2116 5,635 310 334 353 372 262 232 293 315 29166 31,473 33,263 35,167 11,252 12,074 12,708 13,295 3,061 3,255 B,410 3,570 1930 1. LOAD DEMAND DEMAND ~ KW 482 ENERGY’ — MWH 41902 2. SOURCES — «és A. EXISTING DIESEL LOCATION OR UMIT 1 500 2 S500 3 300 4 300 5 = ’ = B. ADDITIONAL DIESEL UNIT 1 = 2 i 3 ee 4 = s - 4 oa C. EXISTING ALTRNT 1 UNIT 1 = 2 st D. ADDITIONAL ALTRNT 1 UNIT 1 vad 2 = 3 - E. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 - 2 a 3 - TOTAL CAPACITY — KW 1,600 LARGEST UNIT soo FIRM CAPACITY — KW . 1,100 SURPLUS OR (DEFICIT) ~ KW 618 ALT 1 GENERATION - MWH - ALT 2 GENERATION - MWH = DIESEL GENERATION - MWH 14,016 1981 sos 21008 500 soo 300 300 1,400 soo 1,100 592 14,016 1982 534 2114 500 500 300 300 1,600 soo 1,100 566 14,016 POWER COST STUDY FOR KAKE, ALASKA 4OkV, SWCR (LOW LOAD) 1933 560 21220 S500 S00 300 300 prune 1,600 soo 1,100 540 14,016 1984 584 25310 500 500 300 300 4,600 3,000 1,600 1,016 91,509 14,0146 1985 608 21400 500 soo 300 300 3,000 4,600 3,000 12600 992 88,790 14,016 1986 632 21490. soo S00 300 300 peru 3,000 4,600 3,000 1,600 968 85,098 14,016 1987 656 “24580 500 500 300 300 3,000 4,800 3,000 1,600 944 81,406 14,016 1988 680 246790 500 500 300 300 peas 4,600 3.000 1,600 920 77,714 14,016 1989 708 2*780- 500 500 300 300 peu 4,400 3,000 1,600 392 73,910 14,016 3a-1 1990 736 27890 500 500 300 300 1 torrets 4,600 3,000 1.600 864 70,086 14,016 1991 764 -31000- 500 S00 300 300 3,000 4,600 3,000 1.600 836 66,844 14,016 40kV, SWGR (LOW LOAD) 3A-2 1992 1993 1994 1995 1996 1997 1998 1999 2000 1. LOAD DEMAND DEMAND - KW 792 820 848 876 904 932 960 988 1,016 ENERGY — MWH 3-110 3-220 3,333 3446 3,553 3.671 3.784 3895 4,005 2. SOURCES - KW A. EXISTING DIESEL : LOCATION OR UNIT 1 500 500. 500 500 500 500- Soo soo 500 2 soo soo 500 500 500 soo 500° s0o- ‘soo 3 300 300 300 300 300 300 300 300 300 4 300 300 300 300 300 300 300 300 300 s 7 - 7 7 = 2 is 4 = & - - = = re - “ 4 7 B. ADDITIONAL DIESEL UNIT 1 - - - - - - - - - 4 - - - 2 my = ~ 4 i 3 - - - - = - - - 4 - 4 - - - 7 = - - “ 7 5 - - - = = - 7 4 - rs - - - « < s - 2 - C. EXISTING ALTRNT 1 UNIT 1 - - - - - - - - - 2 - - = a - . - 4 - D. ADDITIONAL ALTRNT 1 UNIT a 3,000 3,000 3,000 3,000 3,000 31000 3.000 3,000 3,000 3 . - = - 2 a - 4 - &. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 - - - - - - - - - 2 7 - - ~ « = — 4 7 3 = - = = = 7 - 4 - TOTAL CAPACITY — KW 4,800 4,600 41600 4,400 4.600 4,400 4,600 4,600 4,600 LARGEST UNIT 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3.000 FIRM CAPACITY - KW 1,600 1+600 1,600 1,600 1,400 1,400 1,400 1,400 1,600 SURPLUS OR (DEFICIT) — KW 803 7380 752 724 696 668 640 612 584 ALT 1 GENERATION — MWH 63,600 60,357 57,213 54,071 50,900 47,700 44,500 41,300 38,100 ALT 2 GENERATION —- MWH - - DIESEL GENERATION - MWH 14,016 14,0186 14,016 14,016 14,016 14,016 14,016 14,016 14,016 3. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL UNIT 1 UPON C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 a 3 €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 2 3 G. TRANSMISSION PLANT ADDITIONS WNIT L 2 H. MISCELLANEOUS ADDITIONS UNIT 1 3 TOTAL ($1000) BASE YEAR DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 2. ADDITIONS 1980 1,800 +800 1,300 4OkV, SWGR (LOW LOAD) 1931 1932 1,800 1,500 1,800 1,800 1983 1,800 1,800 1,300 70 1984 1,800 2,610 460 73 1985, 1,800 21610 460 60 4,930 5,903 1936 1,300 2610 460 60 4,939 5,903 73 1987 1,800 2,610 460 40 44920 5,903 73 1988 1,800 45930 5,703 73 3A-3 1989 1,800 2,610 460 60 4,930 5,903 73 1990 1,800 21610 460 60 4,930 5,903 73 SUBTOTAL 1ST % 2ND % SRD % 4TH % B. INSURANCE c. TAX TOTAL FIXED COST ($1000) 15ST % 2ND % SRD % 4TH % S. PRODUCTION COST (#1000) INFLATED VALUES A. OPERATION & MAINT 1. DIESEL 2. ALTRNT 1 3. ALTRNT 2 B. FUEL & LUBE OIL 1. DIESEL 2. ALTERNATE 1 3. ALTERNATE 2 TOTAL PRODUCTION COST ($1000) TOTAL DIESEL COST ($1000) 1ST % 2ND % SRD % 4TH % HYDRO BUS COST (MILLS/KWH) MWH SUPPLIED HYDRO TOTAL HYDRO COSTS 1980 at at 41 41 416 416 416 1921 42 42 42 42 126 443 463 463 463 4OkV, SWGR (LOW LOAD) 1982 42 2 42 42 135 1983 77 77 77 77 146 ss2 629 429 29 629 1934 164 251 S17 33s 249 336 402 473 135 31 166 41s S02 543 439 280 1935, 144 251 317 333 250 337 403 474 144 34 178 Pues nD = by Head nN N 0 2,400 670 19386 164 251 317 338 250 337 403 474 154 3. 2.490 e0 1937 164 251 B17 383 251 333 404 47s 1465 39 204 ss S42 603 479 2,580 640 198! 3 164 251 317 338 251 333 404 475 176 4 1 1 7 463 sss 621 692 39 2 2,670 pe 0 3A-4 1939 164 251 317 sss 10 252 339 405 476 1389 1990 164 251 B17 383 1 253 340 406 477 202 47 S02 sso 655 726 nN n 2,390 613 TOTAL ANNUAL COSTS 1ST n 2ND % SRD % 4TH % TOTAL MWH REQUIRED oO. MILLS/KWH 1ST 2ND 3RD 4TH PRESENT WOR ANNUAL COST 1ST 2ND SRD 4TH ACCUM AN CO: 1ST% 2N0% SRDZ 4TH% nh nh % nh TH ($1000) % n n % IST ($1000) ACCUMULATED PRESENT WORTH ANNUAL COST 1ST% 2ND% SRDZ 4THX ACCUM, PRES. ENERGY IN M 1ST% 2ND% SRD% 4TH% ($1000) « WORTH OF ILLS/KWH 1980 416 416 414 416 902 219 219 219 219 416 ALS 4lé 416 416 416 ale ale 416 416 41s 414 219 219 219 719 1981 443 463 463 463 eos 233 233 233 233 425 425 425 425 884 S84 834 234 S41 S41 S41 S41 431 431 431 431 40kV, SWGR (LOW LOAD) 1982 1983 19 S27 629 1, S27 629 1s 527 629 1, S27 629 1s 2,114 2,220 2.3 249 283 249 233 249 283 249 2833 436 473 436 473 436 473 436 473 1,411 2,040 3 1,411 2,040 3. 1,411 2,040 3, 1,411 2,040 3 1,277 1.750 2 1,277 1.750 2 1,277 1,750 2) 1.277 1,750 2 637 350 Ie 437 $50 1, 437 350 1, 437 S50 1. 34 062 149 215 286 497 S26 SS7 725 735 830 878 102 139 235 326 475 sso 623 164 189° 209 230 19385 1,098 1,185 1,251 1,322 2,400 458 494 S21 SS1 682 736 777 821 4,200 4,374 4,506 4,643 3,157 3,271 3,357 3,449 1,443 1,496 1,532 1,572 1986 1,130 1,217 1,283 1,354 214970 454 439 S15 544 638 637 724 764 5,330 S,Se1 5,78? 6,002 3.795 3,953 4,081 4,213 1987 1,115 1,202 1,268 1,339 491 s19 572 617 6S1 687 6,445 61793 7,057 7,34. 4,367 4,573 4,732 4,900 1,926 2,011 2,078 2,145 1988 1,106 1,193 1,259 1,330 2,670 414 447 472 493 S146 ss6 537 620 7,551 71986 8,316 8,671 4,883 S,131 S319 5,520 2.119 2,219 2,295 2.377 3A-5 1939 1,107 1,194 1,260 1,331 3938 429 453 479 469 S06 S34 S44 8,458 80 9,576 10,002 5,352 5.4637 5,853 6,084 2,288 2,401 2,437 2,530 1990 1,115 1,202 1,268 1,339 2,890 386 416 439 463 430 463 439 S16 9,773 10,382 10,844 11,341 5,782 6,100 61342 4.600 2.437 2,561 21656 2.759 3. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL UNIT 1 > Cuan C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 2 3 G. TRANSMISSION PLANT ADDITIONS UNIT 1 2 H. MISCELLANEOUS ADDITIONS UNIT 1 > TOTAL ($1000) BASE YEAR DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 2. ADDITIONS 1991 1,300 2,610 460 40 4,930 5,903 73 1992 1,800 2,610 460 73 4OkV, SWGR (LOW LOAD) 1993 1,300 2,610 460 1994 1,300 21610 460 60 4,930 5,903 73 1995 1,300 2,610 460 60 4,930 5,903 1996 2.410 440 60 4,930 5,903 73 1997 2,410 460 60 4,930 5,903 73 1993 1,300 2,610 460 45930 5,903 73 1999 1,300 2,610 460 73 3A-6 2000 1,800 2,610 460 60 4,930 5,903 73 SUBTOTAL 15ST % 2ND % SRD % . 4TH % B. INSURANCE c. TAX TOTAL FIXED COST ($1000) 1ST % 2ND % SRD % 4TH % S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION & MAINT 1. DIESEL 2. ALTRNT 1 3. ALTRNT 2 B. FUEL & LUBE OIL 1. DIESEL 2. ALTERNATE 1 3. ALTERNATE 2 TOTAL PRODUCTION COST (#1000) TOTAL DIESEL COST ($1000) 1ST n% 2nD % SRD % 4TH % HYDRO BUS COST (MILLS/KWH) MWH SUPPLIED HYDRO TOTAL HYDRO COSTS 19PL 3 164 251 317 333 11 253 340 406 477 216 Ss. 267 520 607 673 744 900 409 1992 164 251 B17 sss 254 341 407 478 231 s4 1 S39? $26 692 783 195 3,110 606 4OkV, SWGR (LOW LOAD) 1993 1994 1995 164 164 164 2351 251 251 Biz 317 317 383 383 338 13 14 1s 255 256 257 342 343 344 403 409 410 479 4380 481 247 265 283 ss 62 66 305 327 349 S60 ss3 606 447 670 692 713 736 7S? 734 807 830 189 184 179 +22 3,333 31446 409 613 617 1996 144 251 317 388 16 253 345 41 432 303 7L 374 632 719 735 356 175 3,553 1997 164 251 317 383 17 259 346 412 483 324 7% 400 65? 74 si2 333 171 B471 1998 164 251 S17 33s 18 260 347 413 494 347 SL 683 775 B41 912 1999 164 251 317 338 262 349 41S 486 371 87 453 720 307 373 944 164 3,895 439 3A-7 2000 164 251 317 ses 21 263 350 416 437 397 93 490 733 340 906 277 161 4,005 645 TOTAL ANNUAL COSTS 1ST % 2ND % SRD % 4TH % TOTAL MWH REQUIRED MILLS/KWH 1ST % 2ND % SRD % 4TH % C. PRESENT WORTH ANNUAL COST ($1000) 1ST % 2ND % SRD % 4TH % D. ACCUM AN COST ($1000) 1ST% 2ND% 3RD% ATHA €. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 1ST% 2ND% SRODZ 4THZ F. ACCUM. PRES. WORTH OF ENERGY IN MILLS/KWH 1ST% 2N0% SRDZ 4TH% 1991 1,129 1,216 1,282 353 3,000 376 405 427 451 397 423 451 476 10,902 11,593 2,126 12,694 61179 6,523 61793 71078 2,569 2,702 2,006 2917 1992 1,145 15232 1,293 1,369 3,110 368 396 417 440 365 392 414 434 2,047 2,230 13,424 14,063 61544 4,921 +207 7,512 2,686 2.82 2.939 3,057 4OkV, SWGR (LOW LOAD) 1993 1,169 1,256 1,322 1,393 31220 363 390 411 433 339 344 383 404 13,216 14,036 14,746 15,456 NNO ah a =H 8 rOue 2,791 2,942 3,053 3,182 1994 1,196 1,283 1,349 1,420 3.333 359 3385 405 426 ais 338 35s 374 14,412 15,369 16,095 16,876 7193 7+623 75945 3,270 2,886 3,043 3.165 31294 1995, 1,223 1,310 1,376 1,447 3,446 355 380 399 420 293 314 329 346 15,4635 16,479 17,471 13,323 7491 71937 3,274 S436 D971 3,134 S241 3.395 1996 1,255 15342 1,408 1,479 353 377 396 416 273 292 306 322 16,890 18,021 138,879 19,802 71764 3,530 2,958 3,043 S216 3,347 3,436 1997 1,287 1,374 1,440 1,S11 3.4671 351 374 392 412 255 272 2ss 299 18,177 19,395 20.319 21,313 8,019 3,501 3,965 9,257 S.117 3,290 3,425 3,563 1998 1,320 1,407 1,473 1,544 3,734 349 372 389 408 237 253 265 273 19,497 20,3802 21,792 22,857 8,256 3,754 9,130 9,535 3,180 3,357 3.495 3,641 1999 1,359 15446 1,512 1,533 3,895 349 S71 383 406 222 236 247 259 20,854 22,243 23,304 24,440 2,478 8,990 9,377 9,794 3+237 3.413 3.553 3,707 3A-8 2000 1,393 1,485 1,551 1,622 4,005 349 371 387 405 208 231 241 22,254 23,733 24,355 26,062 8,636 9,211 9,608 10,035 3,239 3,473 3,616 3,747 1980 1. LOAD DEMAND DEMAND - KW 482 ENERGY — MWH 1,902 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 500 2 S00 3 300 4 300 5 = é - B. ADDITIONAL DIESEL UNIT 1 - 2 = 3 - 4 = s - 6 7 C. EXISTING ALTRNT 1 WNIT 1 - 2 = D. ADDITIONAL ALTRNT 1 UNIT 1 - 2 - 3 - €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 - 2 - 3 - TOTAL CAPACITY - KW 1,600 LARGEST UNIT . 500 =IRM CAPACITY - KW 1,100 SURPLUS OR (DEFICIT) - KW 618 ALT 1 GENERATION — MWH - ALT 2 GENERATION — MWH - DIESEL GENERATION - MWH 14,016 1981 sos 2,003 1,600 S00 1,100 S?2 14,016 1982 534 2,114 500 S00 300 300 1,400 S00 1,100 566 14,016 POWER COST STUDY FOR KAKE+ ALASKA 40 kV, SWGR (HIGH LOAD) 1983 777 34320 S00 S00 300 300 1,600 S500 1,100 14,016 1984 sol 3,430 soo 500 300 300 4,600 3,000 1,600 799 91,509 14,016 19385 825 3,570 4,600 3,000 1,600 775 88,790 14,016 1986 849 3,660 4,600 3,000 1,400 7SL 85,098 14,016 1937 873 3,750 4,600 3,000 1,600 727 81,406 14,016 1983 397 3,840 4,600 3,000 1,400 703 77,714 14,016 1989 944 4,042 500 500 300 300 ' 4,400 3,000 1,400 656 73,910 14,016 3B-1 1990 99L 4,264 S00 Soo 300 300 4,600 3,000 1,400 609 70,086 14,016 1991 1,033 4,476 S500 soo 300 300 4,600 3,000 1,400 342 66,844 14,016 1. LOAD DEMAND DEMAND —- KW ENERGY — MWH 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 N 3 4 s 6 B. ADDITIONAL DIESEL UNIT 1 CUPWK ©. EXISTING ALTRNT 1 UNIT 1 2 D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 E. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 2 3 TOTAL CAPACITY - KW LARGEST UNIT SIRM CAPACITY -— KW SURPLUS OR (DEFICIT) -— KW -LT 1 GENERATION - MWH -LT 2 GENERATION — MWH TIiESEL GENERATION —- MWH 1992 1,085 4,638 S00 soo 300 300 4,600 3,000 1,600 Sis 63,600 14,016 1993 1,132 4,900 S00 Soo 300 300 4,600 3,000 1,400 463 60,357 14,016 1994 1,160 5,013 S500 500 300 300 4,600 3,000 1,400 440 57,213 14,014 1995 1,139 S126 S500 500 300 300 4,400 3,000 1,600 412 54,071 14,015 40 kV, SWGR (HIGH LOAD) 1996 1,216 5,233 Soo Soo 300 300 4,400 3,000 1,400 334 50,900 14,016 1997 1,244 5,351 S500 S00 300 300 3,000 4,600 3,000 1,600 356 47,700 14,016 1993 1,272 5.464 S500 Soo 300 300 4,600 3,000 1,500 323 44,500 14,014 1999 15300 5,575 500 Soo 300 300 4,600 3,000 1,400 300 41,300 14,0146 2000 15328 5,685 4,600 3,000 1,400 272 38,100 14,016 3B-2 3. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL WNIT 1 cUSWN C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 E. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 3 G. TRANSMISSION PLANT ADDITIONS UNIT 1 2 H. MISCELLANEOUS ADDITIONS WNIT 1 i TOTAL ($1000) BASE YEAR DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 2. ADDITIONS 1980 1,800 1,800 1,200 40 kV, SWGR (HIGH LOAD) 1931 1982 1,300 1,800 1,800 1,800 1,300 36 36 1983 1,800 1,300 1,800 70 1984 1,800 4,930 51903 73 1985, 1,800 2,610 460 60 4,930 5,903 73 1986 1,800 2.610 460 60 4,930 5,903 73 1937 1,300 2,610 460 4,930 5,903 1988 1,300 4,930 5,903 73 3B-3 1989 1,800 2,610 460 73 1990 1,800 2+610 460 60 4,930 5,903 73 SUBTOTAL 1ST % 2ND % SRD % 4TH % B. INSURANCE c. TAX TOTAL FIXED COST ($1000) 1ST % 2ND % SRD % 4TH % S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION & MAINT 1. DIESEL 2. ALTRNT 1 3. ALTRNT 2 B. FUEL & LUBE OIL 1. DIESEL 2. ALTERNATE 1 3. ALTERNATE 2 TOTAL PRODUCTION COST (#1000) TOTAL DIESEL COST ($1000) 1st % OND % SRD % 4TH % HYDRO BUS COST (MILLS/KWH) MWH SUPPLIED HYDRO TOTAL HYDRO COSTS 1980 41 41 41 41 117 253 375 416 416 416 41s 1981 42 42 42 42 126 463 463 463 462 40 kV, SWCR (HIGH LOAD) 1982 42 42 42 42 135 350 438s 1983 77 77. 77 77 157 619 776 $52 e353 353 ss3 1984 164 251 B17 333 249 336 402 473 135 31 166 430 974 1985 164 251 317 383 250 337 403 474 144 34 173 423 sis SOL 652 1986 164 251 317 333 250 337 403 474 154 36 190 440 S27 593 664 277 3,660 1,014 1987 164 251 317 388 251 333 404 475 455 542 403 479 256 750 P40 1983 164 251 317 3388 251 3338 404 475 174 41 217 rrne INAS ne ao 239 3B-4 1939 164 251 317 338 10 252 339 405 476 189 44 903 1990 1464 251 317 333 1. 253 340 406 477 202 47 249 S02 S539 655 726 212 4,264 304 1980 TOTAL ANNUAL COSTS 1ST % 416 2ND % 416 SRD % 416 4TH % 416 TOTAL MWH REQUIRED 1,902 MILLS/KWH 1ST % 219 2ND % 219 3RD % 219 4TH % 219 C. PRESENT WORTH ANNUAL COST ($1000) 1ST % 416 2nD % 416 SRD % 416 4TH % 416 D. ACCUM AN COST ($1000) 1ST% 416 2ND% 416 SRD% 416 4TH% 416 —E. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 1ST% 416 2ND% 416 3RD% 416 4TH% 416 F. ACCUM. PRES. WORTH OF ENERGY IN MILLS/KWH 1ST% 19 2ND% 219 oRDZ 219 4TH% 219 1981 463 463 443 468 003 233 233 233 233 425 425 425 425 S41 S41 S41 841 bpp wd OW 40 kV, SWGR (HIGH LOAD) 1982 S27 327 527 S27 2,114 249 249 249 249 436 436 436 4346 1,411 1,411 1,411 1,411 1,277 1,277 1,277 15277 1983 353 833 sss 853 34390 252 252 252 641 64L 641 641 21264 2,264 2,244 2,264 1,918 1,913 1,712 1,918 326 O24 1984 1,399 1,476 1,542 1,613 3,430 399 424 443 444 949 1,008 1,053 1,102 3.653 3,740 3,806 3,877 2,867 2,928 2,971 3,020 1,999 1,116 1,129 1,143 1985 1,424 1,S1t 1,577 1,643 3,570 399 423 442 462 884 938 979 1,023 5,077 7251 5,383 5,525 3.751 3,064 3,950 4,043 1,347 1.379 1,403 1,430 1986 1,454 1,541 1,407 1,673 3,660 397 421 439 453 S21 870 207 947 6,531 61792 51990 7203 4,572 4,734 4,357 4,990 1,571 1,617 1,651 1,493 1987 1,415 1,502 1,568 1,639 3,750 377 401 418 437 726 771 805 841 7,946 8,294 3,553 8,942 5,298 5,505 31662 S,S31 1,744 1,823 1,365 1,912 1988 1,384 1,473 1,539 1,610 3,840 Sol 384 401 419 646 687 713 751 9,332 21767 10,097 10,452 5,944 65192 6.380 6,582 1,932 2,002 2.052 2,107 3B-5 1989 1,393 1,430 1,546 1,617 4,052 344 365 382 399 SOL 628 656 486 10,725 11,247 11,643 12,069 1990 1,406 1,493 1,559 1,630 4,264 330 350 366 382 342 S76 601 623 12,131 12,740 3,202 13,699 7,077 71396 1637 71896 2,205 2,292 2,395 2,423 3. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL UNIT 1 eUPan C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 2 3 G. TRANSMISSION PLANT ADDITIONS UNIT 1 S. H. MISCELLANEOUS ADDITIONS UNIT 1 mg TOTAL ($1000) BASE YEAR DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 2. ADDITIONS 1991 1,800 2,410 460 60 4,930 5,903 73 1992 1,800 2,610 460 60 4,930 5,903 40 kV, SWGR (HIGH LOAD) 1993 1,800 25610 460 460 4,930 5,903 73 1994 1,800 2,610 460 60 4,920 5,903 73 1995 1,800 2,610 460 73 1996 1,800 2,610 460 73 1997 1,300 2,610 460 40 4,930 5,903 1993 1,800 2,610 440 60 4,930 5,903 73 1999 1,800 2,610 460 60 4,920 5,903 73 3B-6 2000 1,800 25610 460 60 4,930 5,903 73 1st % 2ND % SRD % ATH % SUBTOTAL B. INSURANCE c. TAX TOTAL FIXED COST ($1000) 1ST % 2ND % SRD % 4TH % S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION & MAINT 1. DIESEL 2. ALTRNT 1 3. ALTRNT 2 B. FUEL & LUBE OIL 1. DIESEL 2. ALTERNATE 1 3. ALTERNATE 2 TOTAL PRODUCTION COST (#1000) TOTAL DIESEL COST ($1000) sta“ 2ND % SRD % 4TH % HYDRO BUS COST (MILLS/KWH) MWH SUPPLIED HYDRO TOTAL HYDRO COSTS 1991 164 251 317 38s 11 253 340 406 477 216 St S20 607 673 744 1992 164 251 317 383 12 254 S41 407 473 231 s4 235 S39 426 692 743 19S 40 kV, SWGR (HIGH LOAD) 1993 1994 1995 144 1464 1464 251 251 251 317 317 317 388 388 383 13 14 15 255 256 257 342 343 344 403 409 410 479 480 431 247 265 283 se 62 66 305 327 349 560 593 606 447 470 693 713 736 759 734 807 330 139 1394 179 4,900 3,013 53,124 925 922 P17 1996 1464 251 317 333 16 253 345 4it 482 303 71 374 1997 1464 251 317 333 17 259 346 412 483 324 7& 400 659 746 B12 171 3,351 1993 Sy 164 251 S17 383 18 260 347 413 434 347 st 633 775 S41 FIZ 167 464 1999 164 251 317 333 262 349 41s 436 S71 87 4ss 720 307 873 244 144 575 14 3B-7 2000 164 251 Siz 333 263 350 416 437 397 92 490 733 840 706 9°77 161 5,685 ws TOTAL ANNUAL COSTS 1ST % 2ND % BRD % 4TH % TOTAL MWH REQUIRED MILLS/KWH 1ST % 2ND % SRD % 4TH % C. PRESENT WORTH ANNUAL COST ($1000) 1sT % 2ND % “SRD % 4TH % D. ACCUM AN COST ($1000) 1ST% 2ND% SRDZ 4TH% E. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 15T% 2ND% SRDY 4TH% F. ACCUM. PRES. WORTH OF ENERGY IN MILLS/KWH 15T% 2ND% 3RDZ 4TH% 1991 1,429 1,516 1,582 1,653 4,476 S19 339 353 369 S03 533 S56 Sse. 13,560 14,256 14,784 15,352 7+580 3,477 +317 2411 2.479 2553 1992 1,451 1,533 1,404 1,675 4,688 310 328 342 357 462 490 Sit S34 15,011 15,794 16,388 17,027 8,042 3,419 3,704 9,011 40 kV, SWGR (HIGH LOAD) 1993 1,486 1,573 1,639 1,710 4,900 303 321 334 349 430 456 475 49S 16,497 17,367 18,027 18,737 8,472 8,875 P1779 91506 1994 1,505 +592 1,658 1,729 5,013 300 318 331 345 396 419 437 4ss 18,002 18,959 19,685 20,4466 3,363 9:294 F616 Fy 9bL 2,583 21493 2.772 > 1995 1,523 1,610 1,676 1,747 297 314 327 S41 3465 ses 401 413 19,525 20,569 21,361 22,213 9,233 9,679 10,017 10,379 an nne 1996 1,549 15636 1,702 1,773 5,238 296 312 325 3338 337 356 370 386 21,074 22,205 23,063 23,986 9570 10,035 10,387 10,7465 2,718 2,836 2.921 3,015 1997 1,574 1,661 1,727 1,798 5,351 294 310 323 336 Sil 329 342 356 22,643 23,8466 24,790 25,7384 9,881 10,3464 10,729 11,121 2,774 2,397 2,935 3,081 1993 1,601 1,633 1,754 1,825 S464 293 309 321 334 283 304 315 328 24,249 25,554 26,544 27,609 10,169 10,463 11,044 11,449 2,829 2,953 3,043 3,141 1999 15634 1,721 1,787 1,853 5,575 293 309 321 333 267 231 292 304 25,883 27,275 23,331 29,467 10,436 10,949 11,5326 11,753 2,877 3,004 3,095 3195 3B-8 2000 1,663 1,755 1,821 1,392 5,485 293 309 320 333 243 261 271 281 27,551 29,030 30,152 31,359 10,684 11,210 11,407 12,034 2,921 3,050 3,143 3,245 1. LOAD DEMAND DEMAND - KW ENERGY - MWH 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 2 CUPWN B. ADDITIONAL DIESEL UNIT 1 rTUPon C. EXISTING ALTRNT 1 UNIT 1 2 D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 E. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 2 3 TOTAL CAPACITY - KW LARGEST UNIT FIRM CAPACITY - KW SURPLUS OR (DEFICIT) - ALT 1 GENERATION - MWH ALT 2 GENERATION — MWH DIESEL GENERATION - MWH 1980 482 1,902 1,600 soo 1,100 KW 413 14,016 1931 S08 2,008 1,600 500 1,100 S92 14,016 1932 1,600 S00 1,100 S46 14,0146 POWER COST STUDY FOR KAKE, ALASKA WOOD-STEAM (LOW LOAD) 1983 560 2,220 500 S00 300 300 3,100 1,500 1,600 1,040 13,140 14,014 1934 534 25310 500 500 300 300 3,100 1,500 1,400 1,016 13,140 14.016 1985 608 2,400 34100 1,500 1,400 992 13,140 14,016 1936 632 2,490 3,100 1,500 1,600 963 13,140 14,016 1937 656 2,580 31100 1,500 1,600 244 13,140 14,016 1938 680 2,670 3,100 1,500 1,400 920 13,140 14,016 4A-1 1989 708 2,780 3,100 1,500 1,400 8392 13,140 14,016 1990 736 2,890 3,100 1,500 1,600 864 13,140 14,016 1991 764 3,000 3,100 1,500 1,600 836 13,140 14,016 1992 1. LOAD DEMAND DEMAND - KW 792 ENERGY - MWH : 3,110 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 500 2 S00 3 300 4 300 5 - é - B. ADDITIONAL DIESEL UNIT 1 - 2 - 3 = 4 - 5 7 & = C. EXISTING ALTRNT 1 UNIT 1 7 2 = D. ADDITIONAL ALTRNT 1 UNIT 1 1,500 2 = 3 - €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 i 3 7 TOTAL CAPACITY - KW 3,100 LARGEST UNIT 1,500 FIRM CAPACITY — KW 1,600 SURPLUS OR (DEFICIT) - KW 303 ALT 1 GENERATION - MWH 13,140 ALT 2 GENERATION — MWH ES DIESEL GENERATION — MWH 14,016 1993 320 3.220 3,100 1,500 1,600 730 13,140 14,016 1994 848 3,333 3,100 1,500 1,400 752 13,140 14,016 WOOD-STEAM (LOW LOAD) 1995, 876 3.4446 3,100 1,500 1,600 724 13,140 14,016 1996 904 3.553 S500 S00 300 300 3,100 1,500 1,600 696 13,140 14,016 1997 932 3.671 3,100 1,500 1,400 6463 13,140 14,016 1993 960 3,734 3,100 1,500 1,600 440 13,140 14,014 1999 933 3895 1 3,100 1,500 1,600 612 13,140 14,016 2000 1,016 4,005 3,100 1,500 1,600 5384 13,140 14,016 4A-2 3. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL UNIT 1 oUron C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 = 3 €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 ie 3 G. TRANSMISSION PLANT ADDITIONS UNIT L > H. MISCELLANEOUS ADDITIONS UNIT 1 2 TOTAL ($1000) BASE YEAR DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 1980 1,800 1,800 1,800 36 1931 1,800 1,800 1,800 36 WOOD-STEAM (LOW LOAD) 1932 1,800 1,800 1,800 36 1983 1,800 5.400 6,210 70 1984 1,300 5,400 +210 73 1985 1,500 5,400 +2lo 73 1936 1,800 5,400 6,210 73 1937 1,800 5,400 4.210 73 4A-3, 1983 1,800 5,400 6.210 1989 1,300 5,400 6.210 73 1990 1,800 5,400 6,210 73 2. ADDITIONS SUBTOTAL 1ST % 2ND % SRD % 4TH % B. INSURANCE Cc. TAX TOTAL FIXED COST (#1000) 1ST % 2ND % SRD % 4TH % S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION & MAINT 1. DIESEL 2. ALTRNT t 3. ALTRNT 2 B. FUEL & LUBE OIL 1. DIESEL 2. ALTERNATE 1 3. ALTERNATE 2 TOTAL PRODUCTION COST ($1000) TOTAL ANNUAL COST ($1000) 1ST % ZND % oRD % 4TH % ENERGY REQUIREMENTS — MWH 41 41 41 41 416 ais 414 41s 1,702 1981 42 42 42 > 426 443 469 443 448 2,003 WOOD-STEAM (LOW LOAD) 1982 42 42 42 42 135 350 435 S27 S27 S2 2,114 1983 176 269 341 417 246 359 431 S07 126 SS. 1934 176 269 341 417 21 275 368 440 S16 135 590 1985, 176 269 341 417 277 370 442 Sis 144 631 oS 370 1,147 1,3 2,400 1986 176 269 341 417 24 273 371 443 S19 154 675 104 935 1,213 15306 378 1,454 2,490 1987 176 269 241 417 246 230 373 44s S21 1988 176 269 S41 417 282 375 447 S23 176 773 1,079 1,261 1,454 1,526 1,692 2.470 4A-4 1989 176 269 S41 417 30 234 377 44D S25 189 327 145 1,141 1,445 1,533 1,410 1,406 2.7230 1990 176 269 341 417 286 379 451 S27 202 sss 1461 1,248 1,524 1,627 1,699 1,775 2.390 MILLS/KWH 1ST 2ND SRD 4TH % % nh x C. PRESENT WORTH ANNUAL COST ($ 1ST 2ND SRD 4TH 1000) nh % % % D. ACCUM. AN. COST ($1000) 1st 2ND SRD 4TH €. ACCUMULATED nh % % % PRESENT WORTH ANNUAL COST ($1000) 1st 2ND 3RD 4TH F. ACCUM PRESE! % % n n% NT WORTH OF ENERGY IN MILLS/KWH 1ST 2ND SRD 4TH n% n% % % 19% sO 219 219 219 219 416 416 416 41s 416 416 416 416 416 416 416 416 219 217 219 219 1981 234 234 234 234 425 425 425 425 $34 334 834 834 e41 S41 S41 e41 432 432 422 432 WOOD-STEAM (LOW LOAD) 1982 249 249 249 249 436 436 436 436 1,411 1,411 1,411 1,411 1,277 1,277 1,277 +277 633 633 633 633 1923 459 sot 534 568 7h6 836 890 947 2,431 2,524 21596 2.672 2,042 2,113 2.147 933 1,014 1,039 1,065 1934 470 S10 541 S74 74aL sos 854 906 3,516 3,702 3,846 3,998 2,784 2.715 3,021 3,130 1,304 1,362 1,409 1,457 1985, 473 S17 S47 573 712 770 314 8462 4,663 4,942 5,153 5.386 3,496 3,433 3,835 3.992 1,601 1,483 1,749 1,314 1986 487 S24 SS3 S84 4635 737 773 e2i 5,876 61243 65536 6,340 4,131 4,425 4,613 4313 1,376 1,979 2,061 2146 1937 498 534 562 Sat 459 707 744 783 7 16L 71626 71936 1366 4,840 S,132 5,357 5,596 2,132 2,253 3,049 2,449 1988 S10 345 572 600 635 673 712 7Aa7 8,522 9,080 9 S12 91968 5.475 5,810 6,069 6,343 2,370 2,507 2,614 2.729 4A-5 1989 520 553 S79 606 613 652 483 715 9,967 10,413 11,122 11,454 6,083 6462 6,752 7,053 2,591 2,742 2,362 25926 1990 S31 5463 ses 614 591 627 455 484 11,501 12,245 12,821 13,429 6,679 7,089 7,407 71742 21796 2.959 3,089 +223 1991 3. INVESTMENT COSTS (#1000) BASE YEAR DOLLARS A. EXISTING DIESEL 1,300 8. ADDITIONAL DIESEL UNIT 1 2 - OUP OR 1 C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 2 - 3 - £. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 - 2 3 - G. TRANSMISSION PLANT ADDITIONS UNIT 1 = 2 H. MISCELLANEOUS ADDITIONS UNIT 1 - 2 - TOTAL ($1000) BASE YEAR DOLLARS INFLATED VALUES 5,400 4210 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1. EXISTING 73 1992 1,800 31400 4,210 WOOD-STEAM (LOW LOAD) 1993 1994 1995, 1,300 1,800 1,300 5,400 5,400 5,400 6210 6,210 6210 73 73 73 1996 1,800 314600 5,400 6210 73 1997 1,00 3,400 5,400 6,210 73 1993, 1,800 3,600 5,400 6,210 73 1999 1,800 5,400 4,210 73 4A-6 2000 1,800 5,400 6,210 73 2. ADDITIONS SUBTOTAL 15ST % 2ND % SRD % 4TH % B. INSURANCE c. TAX TOTAL FIXED COST ($1000) 1st % 2ND % SRD % 4TH % S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATICN & MAINT 1. DIESEL 2. ALTRNT 1 3. ALTRNT 2 B. FUEL & LUBE OIL 1. DIESEL 2. ALTERNATE 1 3. ALTERNATE 2 TOTAL PRODUCTION COST (1000) TOTAL ANNUAL COST ($1000) 1st % ND % SRD % 4TH % ENERGY REQUIREMENTS - MWH 1991 174 269 341 417 34 233 381 453 s29 216 247 179 1,430 1,723 1,795 3,000 1992 176 269 341 417 290 333 4ss S31 231 1,013 193 1,442 1,732 1,925 1,397 1,973 3,110 WOOD-STEAM (LOW LOAD) 1993 176 269 341 417 3? 293 386 453 534 247 1,084 1,551 1,344 1,937 2,009 2,085 +220 1994 176 269 341 417 296 339 461 S37 265 1,140 1995, 176 269 341 417 4s 299 392 464 540 1996 176 249 S41 417 43 302 395 467 S43 303 1,323 1,929 2.231 2,32 21396 2.472 3.559 1997 176 269 341 417 S. 305 3°93 470 S546 324 1,421 2,074 2,379 2.472 2.544 2.420 1993 176 2697 S41 417 309 402 474 S50 347 1,521 2,708 2.731 3.784 1999 176 249 S41 417 Ss? 313 406 473 554 371 1,627 4A-7 2000 176 269 B41 417 63 S17 410 432 ss 397 1,742 439 2,573 2,899 2,983 3,060 3,134 4,005 MILLS/KWH 1ST % 2ND % SRD % 4TH % C. PRESENT WORTH ANNUAL COST (#1000) 1ST % 2ND % SRD % 4TH % D. ACCUM. AN. COST ($1000) 1st % 2ND % SRD % 4TH % €. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 1st % 2ND % SRD % 4TH % F. ACCUM PRESENT WORTH OF ENERGY IN MILLS/kWH 1st % 2nD % SRD % 4TH % 1991 543 S74 S93 624 2.937 3,161 3,442 1992 S57 S87 610 634 S52 S82 4605 629 14,863 15,793 16,513 17,273 7,804 8,277 3,443 9,029 3.165 31343 2.493 3.444 WOOD-STEAM (LOW LOAD) 1993 16s 17> 13, 19, 573 602 624 643 1994 520 617 639 662 sis 542 Sé1 Sei 18,472 19,733 20,652 21,5464 8,354 9,38 9,786 10,214 3+ 436 314634 3,842 4,006 1995 603 635 656 678 So. S24 S41 sso 201766 21,975 22,711 23,899 9,357 9,904 10,327 10,773 3.4632 3,836 3,999 4,163 1996 27 453 473 695 436 S04 S21 S33 22,997 24,299 25,307 26,371 9,343 10,410 10,348 11,311 3,742 3,978 4,145 4,319 1997 643 473 693 714 471 4s? S03 S13 25,374 26,771 27,851 28,991 10,314 “10,899 11,351 11,829 3+ S946 4,111 4,440 1998 471 496 71S 735 457 474 487 500 27,916 29,404 30,556 31,772 10,771 11,373 11,838 12,329 4,017 +2346 4,411 4,592 1999 4596 720 733 753 443 4se 470 433 301626 32,207 33,431 34,723 1,214 11,831 12,303 12,312 4,131 4,354 4,532 4,716 4A-8 2000 723 746 764 733 430 444 455 466 33,521 35,199 34,491 37,859 11,4644 12,275 12.763 13,273 4,233 4,465 4,646 4,332 1. LOAD DEMAND DEMAND - KW ENERGY — MWH 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 eUPONn B. ADDITIONAL DIESEL UNIT 1 eUPWN C. EXISTING ALTRNT 1 UNIT 1 ie D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 —. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 2 3 TOTAL CAPACITY - KW LARGEST UNIT FIRM CAPACITY — KW SURPLUS OR (DEFICIT) - KW ALT 1 GENERATION — MWH ALT 2 GENERATION — MWH DIESEL GENERATION - MWH 1980 482 1,902 1,600 S00 1,100 613 14,016 1981 sos 2,008 1,600 S00 1,100 S72 14,016 1982 534 2,114 1,400 500 1,100 566 14,016 POWER COST STUDY FOR KAKE, ALASKA WOOD-STEAM (HIGH LOAN) 1983 777 3,100 1,500 1,600 823 13,140 14,0146 19234 soL 3,480 3,100 1,500 1,600 799 13,140 14,014 1985 3,100 1,500 1,600 773 13,140 14,016 1986 349 31660 3,100 »S00 1,600 751 13,140 14,016 1987 373 3,750 S500 S00 300 300 3,100 1,500 1,400 727 13,140 14,016 1983 897 3,840 S500 500 300 300 3,100 1,500 1,400 793 13,140 14,016 1989 944 4,042 3,100 1,500 1,400 656 13,140 14,016 4B-1 1990 PPL 41264 3,100 1,500 1,600 609 13,140 14,016 1991 1,038 4,476 500 Soo 300 300 ' 3,100 1,500 1,400 S62 13,140 14,016 1. LOAD DEMAND DEMAND — KW ENERGY — MWH 2. SOURCES - KW A. EXISTING DIESEL LOCATION OR UNIT 1 cUPwONn B. ADDITIONAL DIESEL UNIT 1 OUPWN C. EXISTING ALTRNT 1 UNIT 1 > DB. ADDITIONAL ALTRNT 1 UNIT 1 2 3 €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 2 3 TOTAL CAPACITY - KW LARGEST UNIT FIRM CAPACITY ~ KW SURPLUS OR (DEFICIT) -— KW ALT 1 GENERATION — MWH ALT 2 GENERATION - MWH DIESEL GENERATION — MWH 1992 1,085 4,689 500 S00 300 300 3,100 1,500 1,600 S15 13,140 14,016 1993 1994 1,132 1,160 4,900 5,013 500 S00 500 S00 300 300 300 300 3,100 1,500 1,600 440 13,140 13,140 14,016 14,016 WOOD-STEAM (HIGH LOAD) 1995 1,138 5,126 500 s00 300 300 3,100 1,500 1,600 412 13,140 14,016 1996 1,216 5,233 S00 Soo 300 300 3,100 1,500 1,600 234 13,140 14,016 1997 1,244 5,351 S00 S00 300 300 3,100 1,500 1,600 355 13,140 14,016 1998 1,272 5,464 1,500 3,100 1,500 1,600 328 13,140 14,014 1999 1,300 S.575 soo soo 300 300 1,500 3,100 1,500 1,600 300 13,1490 14,016 2000 1,328 5,635 500 500 300 300 3,100 1,500 1,600 272 13,140 14,016 4B-2 3. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL UNIT 1 > OU Pwr C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 E. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 UNIT 1 2 3 G. TRANSMISSION PLANT ADDITIONS UNIT 1 Z H. MISCELLANEOUS ADDITIONS UNIT 1 2 TOTAL. ($1000) BASE YEAR DOLLARS INFLATED VALUES 4. FIXED COST ($1000) INFLATED VALUES A. DEBT SERVICE 1, EXISTING 1980 1,300 1,300 1,800 36 1931 1,800 1,800 36 WOOD-STEAM (HICH LOAD) 1982 1,800 1,500 1,300 1933 1,600 5.400 7210 70 1934 1,300 5,400 6,210 1985 1,800 5,400 4,210 73 1986 1.800 5,400 4,210 1987 1,300 5,400 6,210 73 1988 1,300 5,400 +210 73 4B-3 1989 1,200 5,400 6,210 1990 1,800 5,400 4,210 73 2. ADDITIONS SUBTOTAL 1ST % 2ND % ORD % 4TH % B. INSURANCE c. TAX TOTAL FIXED COST ($1000) 1st % 2ND % SRD % 4TH % S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION & MAINT 1. DIESEL 2. ALTRNT 1 3. ALTRNT 2 B. FUEL & LUBE OIL 1. DIESEL 2. ALTERNATE 1 3. ALTERNATE 2 TOTAL PRODUCTION COST ($1000) TOTAL ANNUAL COST ($1000) 1ST % 2ND % SRD % 4TH % ENERGY REQUIREMENTS - MWH 1980 41 41 at 41 375 416 414 Als ale 1,902 1931 42 2 42 126 WOOD-STEAM (HIGH LOAD) 1932 1983 1934 - 176 176 - 269 269 - 341 S41 - 417 417 6 20 21 42 246 275 42 359 368 42 431 440 42 507 S16 135 126 135 a 551 590 350 - ” - 118 123 455 79S 853 1,041 1,123 1,154 +22 1,224 1,293 1,302 1,369 3,370 3,480 1985 176 269 341 417 23 277 370 442 518 144 631 1926 176 269 341 417 24 278 371 443 S19 154 475 156 285 1,263 1,354 1,423 1,504 3,660 1987 176 269 341 417 26 280 373 445 521 1465 1790 1,053 1,338 1,431 1,503 1,579 3,750 1983 174 269 341 417 23 282 375 447 523 176 773 137 1,136 1,413 1,Sit 1,533 1,659 840 4B-4 1989 176 269 S41 417 284 377 449 S2' 189 327 1990 176 269 B41 417 286 379 451 S27 202 835 i io) a o 1,325 1,411 1,704 1,774 1,852 1264 MILLS/KWH 1ST % 2nD % SRD % 4TH % C. PRESENT WORTH ANNUAL COST ($1000) 1ST % 2ND % SRD % 4TH % D. ACCUM. AN. COST ($1000) 1ST % 2ND % SRD % 4TH % E. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 1st % 2ND % SRD % 4TH % F. ACCUM PRESENT WORTH OF ENERGY IN MILLS/KWH 1ST % 2ND % SRD % 4TH % 1930 219 219 219 219 416 416 416 414 Als 416 41s 416 416 als 416 416 219 219 219 219 1931 233 233 233 233 425 4235 425 425 834 384 834 S41 S41 S41 S41 431 431 431 431 WOOD-STEAM (HIGH LOAD) 1932 436 436 436 436 1,411 1,411 1,411 1,411 1,277 1,277 1,277 1.277 437 437 637 437 1983 313 340 362 3384 797 867 921 978 2.472 2545 637 2.713 2,074 2.144 2,193 2,255 $72 392 209 926 1984 324 351 372 393 1,093 1,132 1,163 1,194 1935 234 261 Sat 402 741 799 344 se1 4,794 5,073 5.289 5.517 sss 3.777 3,925 4,081 1,300 1,356 2 1.444 1986 345 370 390 411 713 765 806 349 6,057 6,429 S717 7,021 4,293 4,542 4,731 4,930 1,495 1,565 1,619 1,474 1987 357 332 4ot 421 687 734 771 B10 7395S 7.340 8,22 3,400 4,935 51276 S,502 S,740 1988 369 393 412 432 661 705 733 774 3,313 9,371 9,803 10,259 5,646 S,931 4,240 6514 1,850 1,944 2,017 2,093 4B-5, 1989 374 397 415 432 641 480 711 743 10,224 10,975 11,479 12,011 +237 S661 ISL 7257 2,009 2,112 2193 2,277 1990 378 400 417 434 621 657 63s 714 11,935 12,679 13,255 13,863 4,903 PAs 71636 7,971 2,155 21266 2,954 2444 3. INVESTMENT COSTS ($1000) BASE YEAR DOLLARS A. EXISTING DIESEL B. ADDITIONAL DIESEL UNIT 1 oUPWN C. EXISTING ALTRNT 1 D. ADDITIONAL ALTRNT 1 UNIT 1 2 3 €. EXISTING ALTRNT 2 F. ADDITIONAL ALTRNT 2 WNIT 1 2 3 G. TRANSMISSION PLANT ADDITIONS UNIT 1 2 H. MISCELLANEOUS ADDITIONS UNIT 1 2 TOTAL ($1000) BASE YEAR DOLLARS INFLATED VALUES 4. FIXED COST (61000) INFLATCD VALUES A. DEBT SERVICE 1. EXISTING 1991 1,300 73 1992 1,300 5,400 6,210 73 WOOD-STEAM (HIGH LOAD) 1993 1,300 3,400 5,400 61210 73 1994 1,300 3,400 5400 4210 78 1995 1,800 3,600 5,400 2210 1996 1,800 3,600 53,400 &»210 73 1997 1,800 5,400 6,210 73 1993 1,800 5,400 »210 73 1999 1,800 . 5,400 6,210 73 4B-6 2000 1,300 73 WOOD-STEAM (HIGH LOAD) 4B-7 1991 1992 1993 1994 1995. 1996 1997 1998 1999 2000 2. ADDITIONS SUBTOTAL 1ST % 176 176 176 176 176 176 174 1746 176 176 2ND % 269 249 269 269 269 269 269 269 269 269 SRD % 341 341 S41 S41 S41 S41 341 341 341 S41 4TH % 417 417 417 417 417 417 417 417 417 417 B. INSURANCE 34 36 39 42 43 43 Si ss Ss? 63 c. TAX - - - - os - - - - = TOTAL FIXED COST ($1000) 1st % 233 290 293 296 299 302 305 309 313 S17 2ND % 381 233 386 389 392 395 393 402 408 410 SRD % 453 4ss 453 461 4464 467 470 474 473 4e2 4TH % S29? S31 534 537 s40 543 S46 sso S54 sss 5S. PRODUCTION COST ($1000) INFLATED VALUES A. OPERATION & MAINT 1. DIESEL 216 231 247 265 283 303 324 347 371 397 2. ALTRNT 1 P47 1,013 1,084 1,140 1,242 1,323 1,421 1,521 1,427 1,742 3. ALTRNT 2 - - - - ~ a: - - - = B. FUEL & LUBE OIL 1. DIESEL - - - - - - i - - - 2. ALTERNATE 1 266 299 335 347 4ot 433 479 s24 S72 624 3. ALTERNATE 2 - - - - - es - - - - TOTAL PRODUCTION COST (1000) 1,429 1,543 1,446 1,792 1,926 2,069 2,224 2,392 2,570 2,743 TOTAL ANNUAL COST (#1000) 1ST % 1,717 1,333 2,083 2,371 2,529 2,701 3,090 ND % 1,810 1,924 2.121 21464 2,622 21794 3,173 SRD % 1,882 1,993 2,253 25390 2,536 2,694 2,864 3,245 4TH % 1,953 2,074 2.329 21446 24612 2,770 2,942 3.32 ENERGY REQUIREMENTS - MWH 4,476 4,482 5,013 5.126 5,239 5,351 S444 MILLG/KWH 1st % 2ND % 3RD % 4TH % C. PRESENT WORTH ANNUAL COST ($1000) 1st % 2ND % SRD % 4TH % D. ACCUM. AN. COST ($1000) 1sT % 2ND % SRD % 4TH % €. ACCUMULATED PRESENT WORTH ANNUAL COST ($1000) 1ST % 2ND % 3RD % 4TH % F. ACCUM PRESENT. WORTH OF ENERGY IN MILLS/KWH 1ST % ND % SRD % 4TH % 1991 304 404 420 437 604 637 662 639 13,652 14,489 15,137 3,821 1992 B91 ait 442 594 614 437 661 15,485 16,415 17,135 17,395 8,096 S$, 569 $8,935 9,321 Nts NOMS Gu) 0 OWN WOOD-STEAM (HIGH LOAD) 1993 400 a1? 423 449 S67 S94 615 637 17,444 18,467 19,259 20,095 1994 417 ay 449 465 550 574 S93 613 19,532 20,648 21,512 22.424 9,213 9737 19,143 10,571 2,641 2,775 2,881 2,991 1995, ana ase AL 4at 533 sss $72 S90 21,757 22,966 11,161 2,745 2,883 21993 31106 1996 453 470 44 499 S16 S36 SS2 568 24,123 25,430 26,433 27,502 10,262 10,823 11,247 11,729 2,344 2,985 3,093 3,215 1997 473 420 S03 sis 500 S19 S33 S543 26,657 23,052 29,132 30,272 10,742 11,347 11,300 12,277 2,938 3,082 3,198 35317 1993 404 sit S338 486 S03 Sis 529 29,358 30,846 31,993 33,214 3,027 3,174 3,292 3414 1999 "A7 534 S47 560 471 487 498 Sit 32,241 33,822 35,046 36,338 11,719 12,337 12,213 13,317 3,504 4B-8 2000 saz 553 S71 594 45s 472 432 494 35,321 36,995 38, 37,65? 25177 12,909 13,295 13,311 APPENDIX C LETTERS AND COMMENTS apal7/k1 aoa r L UNITED STATES DEPARTMENT OF AGRICULTURE FOREST SERVICE Stikine Area, Tongass National Fore c 4 ‘ ane’5, 1980 Xe “od Bice D Robert W. Retherford Associates : P.0. Box 6410 Anchorage, Alaska 99502 ATTN: Mr. Mark Latour, Economic Planner Dear Mr. Latour: In response to your letter of May 2, we would like to offer the following comments: 1. It appears that a full range of alternatives has not been developed for the location of an overhead Petersburg to Kake transmission intertie, nor for additional potential power sources. 2. There appear to be two additional alternatives to an overhead transmission line location that should be considered to assure investigation of all possible alternatives. A. Cross Wrangell Narrows in the area of the Tonka Log Transfer Facility via submarine cable; follow the Tonka road to a point south of Mitchel] Slough on Duncan Canal; cross Duncan Canal via submarine cable; run an overhead line northwest through the pass that joins St. Johns Creek, and then continue northwest to Kake through present and future timber harvest areas. This alternative appears to us to have considerable positive value. B. Cross Wrangell Narrows via submarine cable in the Petersburg area; follow the east shore of the Lindenberg Peninsula north to the Twelve Mile Creek Valley, westward through the valley passing south of Portage Bay and north of Kupreanof Mountain, and then continuing westward to Kake. This alternative has some disadvantages in that it runs twelve miles or so along the Frederick Sound shoreline and may, in places, be very difficult to conceal. Its transition points from overhead to submarine on either side of the Wrangell Narrows may meet strong opposition from Petersburg and Kupreanof, and it would pass critically close to the head of Portage Bay. 6200-11 (1/69) 3. There are some problems with the alternatives your firm has suggested. A. Petersburg Creek Route - The Petersburg Creek VCU is LUD I through TLMP which emphasizes wilderness. This VCU is also a candidate for wilderness designation. Due to these facts, the Forest Service will oppose any powerline corridor through the Petersburg Creek VCU. This area is of primary interest to the people of Kupreanof and Petersburg; therefore, strong opposition can be expected from the public. This route would require presidential approval. The Salt Chuck VCU is LUD II (roadless). The public and the Forest Service would oppose powerline construction in this area; however, this activity is technically permitted under TLMP and the Area Guide. B. Duncan Pass Route - The east end of the line would be visible from Petersburg and Kupreanof. The east end of the line runs through the Kupreanof Corporate area, strong opposition can be expected from the residents of this area. Salt Chuck VCU is LUD II (roadless). Although technically permitted under TLMP and the Area Guide, the public and the Forest Service would be opposed. In a LUD II developments of this kind are permitted if designed to retain over711 primitive characteristics of the allocated area. For this reason the Forest Service can be expected to encourage selection of a less damaging alternative. Overhead wires spanning the Salt Chuck would pose a severe hazard to float planes serving the Salt Chuck area. 4. The alternative of supplying power to Kake via a submarine DC cable from Snettisham should be thoroughly explored and considered. 5. Prior to a decision to develop an overhead transmission intertie to Petersburg, all other alternatives to providing electrical power to Kake using local resources should be thoroughly investigated and considered. A. Woodwaste Fired Generating Plant - The Kake Native Corporation is presently logging about 20 million board feet of timber per year. This generates a substantial volume of wood waste material that could be utilized for Hog fuel. By "YUM" yarding (yarding of unmerchantable material) from all the cutting units, considerable volume of wood waste could be obtained. Currently chips for domestic consumption are going for $90/2400 pound unit (oven dry weight), and exportable chips are going for $130/2400 pound unit (oven dry weight). The moisture content of chips being delivered to the two pulp mills is presently averaging 50 percent. Chips with a moisture content of 50 percent will yield 4,500 B.T.U.'s. Other sources of chip material would be Forest Service sales in the Kake area, and beach logs which are ayailable in large quantities and could be salvaged for this purpose. Currently the majority of the chips produced from the local saw mills are being utilized by the two pulp mills. I do not have a cost for utilizing material from ongoing logging operations, but one can contact Pat Soderberg of Clear Creek Logging at Kake for his estimate. Another possible source of material that is coming up is Alaska Lumber and Pulp Company plans on putting in a field chipping operation at Rowan Bay near Kake. This would yield a considerable amount of bark that could be utilized for Hog fuel. I hope this information will be of help to you. Sincerely, DEAN J. WEEDEN Program Manager Recreation and Lands R 78 £. 133° = ‘stitgy i pl Mc Naughton Pt ? son Pup! Try, Pt Camden . 27" Entrance et": nace? Sinden feoeten eo % Petersburg - Kake Intertie (from U.S.G.S. Petersburg 1:250 000) May 1980 seat as aa a 11-K8LH a mq f rash P / \ iA\ i i tA Ao { JAY S, HAMMOND, Governor DU EA Ef \ [rye / : / DEPARTMENT OF §} / 230 S. Franklin St. Habitat Protectio / duneau, Alaska 99801 May 28, 1980 Mr. Mark. Latour Economic Planner Robert Retherford Associates P.O. Box 6410 Anchorage, Alaska 99502 RE: Kake-Petersburg Intertie Dear Mr. Latour: This is in response to your letter of May 2, 1980 regarding two possible power transmission routes between Petersburg and Kake. Although the powerline will probably have minimal impacts due to the type of construc- tion there will be some disturbance and clearing, and this Department has problems with both of the proposed routings you submitted. The northern route goes through Petersburg Creek valley, not only a very highly used recreational area, but the watershed is also a proposed Wilderness Area. The southern route, although it avoids Petersburg Creek, it crosses Duncan Canal Salt Chuck, another important recreational area as well as Hamilton Creek and other sensitive fish streams. As an alternative route, we recommend the location depicted in red on the enclosed map. It utilizes portions of both your routes, is slightly longer (about ten miles), and avoids Petersburg Creek and Duncan Canal Salt Chuck. We feel this route would be much more acceptable from an environmental standpoint. Please feel free to contact us if you have additional questions. Thank you for the opportunity to comment. Sincerely, eRe OD. tag Richard D. Reed Regional Habitat Protection Supervisor 465-4290 Enclosure cc: USFWS w/enclosure NMFS w/ enclosure D. Logan w/enclosure Petersburg Office w/enclosure Pup! TL >. PLCamden 2" Entrance oe “Mi C is Be S £qung CIP Stedethn a Sy ee Morgen if i ie eee eat Seay i gal} 5) es Berry iio” 7 Oe ;Beacon! ° Petersburg - Kake Intertie (from U.S.G.S. Petersburg 1:250 000) May 1980 United States Department of the Interior FISH AND WILDLIFE SERVICE IN REPLY REFER TO: 1011 E. TUDOR RD. ANCHORAGE, ALASKA 99503 (907) 276-3800 2 8 MAY 1980 Mr. Mark Latour Economic Planner Robert W. Retherford Associates P. 0. Box 6410 Anchorage, Alaska 99502 Dear Mr. Latour: Your May 31 deadline has resulted in a brief review of project related impacts which are of concern to us relative to the construction of a power transmission line from Petersburg to Kake, Alaska. It is our understanding that the proposed transmission lines would traverse the Wrangell Narrows at Petersburg via und rwater cable and portions of Kupreanof Island via overhead lines (Figure 1). The more northern transmission line would traverse portions of the Petersburg Creek watershed, portions of the Portage Bay watershed, the Bohemian Range and thence to Kake. The more southern alignment would cross portions of Coho Creek, Duncan Creek, the east side of McDonald Arm in Duncan Canal, the Duncan Canal salt chuck, the Turner's Lake area, the mouth of Hamilton Creek, Cathedral Falls Creek, Goose Marsh and thence to Kake. The construction of overhead transmission lines would reduce aesthetic qualities and reduce or modify fish and wildlife habitat which exist within the alignments of either route. The Petersburg Creek watershed is a sensitive area because of its high aesthetic, recreational, fish, wildlife and estuarine values. As such, the U. S. Forest Service (FS) under the Tongass Land Management Plan has designated this area as a LUD 1 (Figure 2). This land use designation has placed this watershed in the National Wilderness Preservation System. Management of this area by the FS excludes roads, manipulation of vegetation, timber harvesting and other activities (Figure 3). In addition, local residents have expressed their concerns for the Petersburg Creek watershed through their efforts to have this watershed designated as critical habitat, a State of Alaska land use category. More recently, the estuarine portion of this area is being considered under the local district Coastal Zone Management Plan as an area meriting special attention. This latter land use designation is also presently being considered for the estuarine portion of Coho Creek which flows into the Wrangell Narrows, south of Petersburg Creek. Either alignment would cross the upper portions of Duncan Canal and/or Portage Bay. This area also has high recreational, fish and wildlife values. The pristine qualities of this area, coupled with its values to fish and wildlife (e.g., wintering habitat for migratory waterfowl), requires special management of this area. This area has been designated as a LUD II under the Tongass Land Management Plan and is presently managed by the FS to retain its wildland character (Figures 2 and 3). would b 0 cross the Wrangell Narrows via underwater cable, run overhead lines along the Tonka Mountain FS road (Figure 4), cross Duncan Canal via underwater cable south of Mitchell Slough, run overhead lines northwest through the Big John Creek, Hamilton Creek and Cathedral Creek watersheds to Kake. Portions of the latter three watersheds, as indicated by FS personnel, are presently being logged or are scheduled for timber harvesting in the future. Utilizing such a route would confine at least parts of the transmission line to an area which has received some initial environmental disturbance. This alternative is based upon preliminary information and a more exact route through this area would require more information and study. SST . . The assessment report should provide at least the following inform the type and height of towers to be used, the distance between towers, 5 construction methods (e.g., footing construction, tower construction, con- EV, «ut struction schedules), the length, width and location of right-of-way clearings re (ROW), maintenance methods and schedules, unstable soil conditions, habitat types (e.g., forest, stream, wetlands), aesthetically sensitive areas, land use, migratory flyways and small aircraft use patterns. ation: The environmental assessment report should present a comparison between your present alignments, the one which has been suggested, other alternate land routes, and an underwater cable route leading from Petersburg to Kake. If we can be of any further assistance, please notify us. Sincerely yours, Sond) leuees Assistane Area Director Attachments e o> en ff" Entrance et" <= " at Cre Stetan ti Pu eas “By oer} Petersburg —- Kake Intertie (from U.S,.G.S. Petersburg 1:250 000) : May 1 4 Soers \ SEIU ow 1 Sf ¥ 3 “ SMe Ak 4 ¥, { AN. _eU °S : Nasvisa ‘ioe Vaeh v Ni AN LAND USE DESIGNATIONS - LUD’s Bi LUD | These lands will be recommended for the inclu- sion in the National Wilderness Preservation System. This designation may permit estab- lished air and boat access. It permits hunt- ing and fishing, minerals exploration activi- ties, recreational use, and scientific study. This designation will generally exclude: (1) Timber harvesting. (2) New comfort and convenience recrea- tional facilities. (3) Motorized vehicle use, except as permitted under Wilderness plans. (4) Aquaculture facilities, except for handclearing of streams. (5) Mining exploration after December 31, 1983. | (6) Water projects, unless authorized by the President. (7) Roads. (8) Manipulation of vegetation. LUD Il These lands are to be managed in a roadless state to retain their wildland character, but this would permit wildlife and fish hab- itat improvement and primitive recreational facility development. This designation will exclude: (1) Roads, except for specifically authorized uses. (2) Timber harvesting, except for controlling insect infestations or to protect other resource values. (3) Major concentrated recreational facilities. LUD Iil These lands will be managed for a variety of uses. The emphasis is on Managing for uses and activities in a compatible and complementary manner to provide the great- est combination of benefits. These areas have either high use or high amenity val- ues in conjunction with high commodity values. Allowances in calculated poten- tial timber yield have been made to meet multiple objectives. These lands may in- clude concentrated recreational developments. LUD IV Opportunities will be provided for inten- sive resource use and development where emphasis is primarily on commodity or mar- ket resources. Allowances in calculated potential timber yield have been made to provide for protection of physical and biological productivity. s 13400 0, - 00 vt . sien E. a7 Roi | oe 43°5 A ae, te BS Nie RIM Lake, *\ Sao Patterson oO é , ‘ : ey Mey 2 Pks OOS pees Ie tt: ; | . = m ‘ ° . « s Burnt}: Portage | | & ih} lee ane 3 Hamilton fa * cs ee 7 vent “he h Be 5 Sees TS a . Be » © Sh: . lg, RSL Hamilton) | < 4 Bay» Se ‘ : Jegy DVM ) McDonald y " J é ™: ‘Clark 12%: ‘Be me2 ay hy Mtn . Clark 10”: * - ay fo Nactuen Ok : Sas we. &,, hte *FaRolew, Pt “aa 2 bicidhy fas . %. Su G7 RS im 7 Fo Beity ea ? 4 Oe - ei’ ~ oHigh Castigi 7 Nox ita rien as _ ee N d} vate dB . “\ Sy Ay ee i fi yt hes - pete 4: : = ; . ner x i Sy pomdy eS ah ee ge KE ee 7 RAL. = ai’ | Le Woe : % 2 “Nf Ns \ ‘ y ‘\ an eS JO SBR E fees |) ( is ree) aN a gf Aa . a ' ent ce Lake Lileks a iy <0 te Ne ee taal aes . | : . 1) Battarworthi Hen [PN a a7