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Alaska Native Foundation Kotzebue & Nome Coal Study Final Report 1990
EPrman A= ALASKA NATIVE FOUNDATION PSDs a ! Vays. 4101 University Drive Was? Anchorage, Alaska 99508 KOTZEBUE & NOME COAL STUDY Final Report JANUARY, 1990 G> ARCTIC SLOPE CONSULTING GROUP 4H A Engineers « Architects « Scientists « Surveyors See Prepared For: ALASKA NATIVE FOUNDATION 4101 University Drive Anchorage, Alaska 99508 Alaska Energy Authority Contract No. LC 1822001 KOTZEBUE & NOME COAL STUDY FINAL REPORT January, 1990 Prepared By: Arctic Slope Consulting Group Mechanical Technology, Inc. P.O. Box 652 968 Albany - Shaker Road Barrow, Alaska 99723 Latham, New York 12110 (907) 852-4556 (518) 899-2976 EXECUTIVE SUMMARY Overview of the Assessment The Kotzebue and Nome Coal Study is part of an overall economic development program. Since 1980 there have been fifteen economic feasibility and resource evaluation projects, assessing the feasibility of developing the large coal resource of the Western Arctic as an energy alternative to fuel oil for in-state use. Findings of the projects show the development of the local resource to be a viable means of meeting the energy needs of Northwest Alaska. Further they concluded, besides providing energy self-sufficiency in the region, the overall economic development project has the potential of enhancing the regional economy while reducing or eliminating state energy subsidies in the area. Having established the feasibility of mining in the Western Arctic the resource development project has been advanced to its implementation phase. As a first step towards development the State determined it was appropriate and timely to assess the initial in-state market. In 1989, the Alaska Energy Authority (AEA) sponsored the Kotzebue and Nome Coal Study. The purpose of this assessment was to evaluate in a preliminary manner, the viability of using Western Arctic coal as an alternative to fuel oil for power generation and district heating for the communities of Kotzebue and Nome. The scope of work included, updating the current demographics and energy profile of both communities and an evaluation of coal-based technologies and methods suitable for each community. Because a new energy source and related technologies would have an impact on the communities a socio- economic impact assessment was included in the report. The year long study effort involved field reconnaissance trips to gather information and local input, an evaluation of alternatives with a recommended alternative advanced for further evaluation, preparation of a draft final report which was issued and distributed to appropriate individuals, agencies, and organizations for review and comment. All relevant comments were incorporated into the text of this Final Report. The project team consisted of the Alaska Native Foundation, (ANF) retained by the AEA to administer the project. The Arctic Slope Consulting Group (ASCG) provided overall project management and technical and professional services. Joining the ANF Project Team were Kotzebue Electric Association and id Nome Joint Utility, Mechanical Technology, Inc., The J.R. Heesch Company, Polarconsults, and Northern Economics. The Recommended System After consideration of potential coal-based power and district heating concepts and technologies, a recommended overall system was derived. The proposed system consist of burning coal in a circulating fluidized bed combustor (CFB). Heat generated by the CFB will be used as the motive heat source for an externally fired Brayton cycle, (Air turbine). Compressed air from the air turbine compressor will flow through a regenerator to an external heat exchanger (in the fluidized bed) where it will be heated to the desired turbine inlet temperature. The heated air is returned to the air turbine where it is expanded through the turbine section. A generator connected to the air turbine converts the power generated in the turbine section to electrical power for distribution to the community. The exhaust heat from the CFB combustor and the air turbine exhaust would be utilized as the heat source for the respective district heating systems. Delivered outputs from the system will be 4160 volt electric power and 250'F hot water for use in the district heating systen. The major components of the proposed system are described below: Circulating Fluidized Bed Combustor On another related project, Battelle Memorial Institute, Columbus, Ohio, performed a combustion test on Deadfall Syncline coal. They recommended a fluidized bed combustor (FBC) for our small-scale application, primarily due to its superior emissions control, the low ash fusion temperature characteristic of the coal, ease of operation, and commercial availability in the small size range required by the project. Of the FBCs available the circulating fluidized bed combustor was preferred due to its superior combustion efficiency, reduced erosion/corrosion of the heat transfer surface, and the ability to control turbine inlet temperature independent of load. The CFB design temperatures for this proposed air heater system is 1600°F. Brayton Cycle Both a steam Rankine cycle and externally fired Brayton (air turbine) cycle were evaluated. Although costs are comparable the Brayton cycle was selected primarily ati because it does not use any water. Fresh water is usually expensive to obtain and limited in supply throughout rural Alaska and especially in the community of Kotzebue. District Heating A district heating system would transfer the waste heat from the power system to the homes and buildings. Hot water produced by the heat exchangers in the power plant would be circulated by pumps through heating loops under the streets to the buildings to be served. These loops will consist of two paralleled insulated pipes, each of the fame diameter. In one of these pipes will flow hot, (25@°F), pressurized water from the power plant and in the second pipe the cooler water, (160'F), will flow back to the power plant. Installations The proposed power plants and district heating facilities for Kotzebue and Nome are anticipated to come on line in 1995. One CFB combustor and one air turbine will make up a power system module of 2.5 MW capacity. The proposed replacement plant for Nome will consist of three power modules for a total installed capacity of 7.5 MW. It is anticipated the peak demand for Nome will be about 7MW by 1995. The power plant will require two buildings, the power house and coal storage facility. The power house will be approximately 100 ft by 160 ft with a maximum height of 70 ft to accommodate the CFB combustors. With an annual coal consumption of 37, 000 tons the coal storage structure will be 15@ ft wide by 300 ft long by 40 ft high. The district heating system will provide heat only to structures with a floor area greater than 3000 sq. feet, excluding Icy View and Beltz school area. The system is anticipated to displace the combustion of 1,036,000 gallons of oil per year. This is approximately 56% of the total heating oil consumption in Nome. The proposed power plant for Kotzebue will consist of two power modules for a total installed capacity of 5MW capacity. The 1995 peak demand is estimated at 4152 KW. The power house will be approximately 100 ft by 120 ft. The Kotzebue annual coal requirement is estimated at 20,000 tons per year. The coal storage building will be about 15@ ft wide by 160 ft long by 4@ ft high. iv The district heating system will provide heat to the school complex, Hansen’s store, the new hospital, the airport, and the recreation center. It is anticipated the district heating system will displace 672,500 gallons of oil. Conclusions The assessment was a pre-feasibility level study that resulted in preliminary observations that can be made concerning the feasibility of developing coal-based power plant and district heating facilities in both Kotzebue and Nome. Although the proposed facilities and system need further evaluation, there appears to be no “fatal flaws" and at this preliminary stage, the proposed project appears to be viable from an economic, environmental, and technical point of view. EG appears significant benefits could result from implementation of the project. Benefits to the Northwest Alaska region, Cities of Nome and Kotzebue, residents of the region, and the State of Alaska. In addition to the normal economic benefits associated with the development of the mine and power plants, such as employment and business opportunities and tax revenues from the mining operation, there would also be reductions in the cost of providing power and energy in both communities. These long term potential benefits appear to outweigh any potential downside effects and warrants further investigation by the State of Alaska. Specific conclusions are presented below based on major tasks of the study. Fuel Assessment An evaluation and comparison of Deadfall Syncline coal from the Western Arctic and Chicago Creek coal near Deering, Alaska was performed. Results showed the Chicago Creek coal to be an A-B Lignite coal. The Deadfall Syncline coal was of higher rank, High Volatile Bituminous coal. With a significantly larger resource and better economics in both production and transportation, Deadfall coal was found to be more marketable than Chicago Creek’s. This is important when considering the regional concept of the overall resource development project which anticipates further penetrations within the regional market that will increase annual tonnages produced and thereby decrease the price of coal and, in turn, make the coal resource more marketable. Compared to oil Deadfall coal appears to be economic around the low production level of 50,00@ tons per year with a crude oil price at or above $15 per barrel. Further, combustion of Deadfall coal was found to be environmentally superior to that of fuel oil burned in a diesel generator. The report concludes that the abundance, quality and favorable economics of Deadfall coal make it the preferred energy source for this project. Economic Analysis According to the economic parameters utilized in this evaluation, continuing use of diesel generators to provide power in Nome over the next twenty years will require a subsidy of over $213 million. Adding a District Heating system to the diesel power system would reduce the required subsidy to $70 million over the twenty year period. Switching to the proposed coal fired power generation system will reduce the required subsidy to zero and provide a surplus (profit) of between $26 million and $45 million, depending on the additional demands for Deadfall Syncline coal. In Kotzebue, the results over twenty years are similar. The diesel option will require a subsidy of $137 million versus a profit of $68 million for a coal fired power system with district heating. Sensitivity cases looking at lower and higher inflation rates as well as lower and higher diesel fuel prices indicate the coal system performs substantially better than any of the diesel options regardless of the direction if the economy. Switching to coal will allow AEA to eliminate the subsidy payments currently paid to Nome and Kotzebue. Socio-Economic Impact Implementation of this project along with the development of the local coal resource in the Western Arctic will meet many social and economic objections of the state. Besides the many benefits associated with developing a local energy industry there are several benefits this project will have directly on the two communities. Kotzebue is a community of about 370@ people with an average of 1449 full time jobs. Unemployment has been a chronic problem in the area. In 1988 63% of the vi regional labor force respondents indicated that they were unemployed. Construction of a coal based power plant in Kotzebue is estimated to require 24,000 man hours. This is equivalent to 11.5 full time jobs. Operation of the facilities will require two additional full time employees to the current staffing level. Major cost savings in the production of power will be the largest benefit to the community and the State of Alaska. Installed in 1995 it is estimated Kotzebue would save $649,000 annually by 2000 and $3,450,000 by the year 2014. Nome is a community of about 370@ people with an average of 1,700.5 full time jobs. It is anticipated construction of the power plant and district heating facilities will require about 31,000 man hours of time with close to $2.5 million injected into the Nome economy in terms of wages, materials, and services. Operation of the facilities will require two additional people compared to the existing situation at the power plant. The biggest impact on the community will be a substantial reduction in the cost of power generation. By the year 2000, five years after installation, the community could save up to $460,000 per year. Annual savings should increase and by the year 2014 should be about $5,000,000 per year. For both Nome and Kotzebue the cost to the state, to operate the Power Cost Equalization Program, should diminish as a result of lessened power generation costs. Recommendations Since the economic and technical feasibility of mining Western Arctic coal has been established in previous work and since the preliminary results of the Kotzebue and Nome Coal Study are encouraging and it appears Kotzebue and Nome can be developed to use Western Arctic coal economically and in an environmentally acceptable way, it is recommended the next stage of development include an in-depth engineering feasibility assessment of developing: 1) coal-fired power plant and district heating facilities for the communities of Kotzebue and Nome; and 2) a coal mining industry in the Western Arctic designed to meet the energy demand of both communities. Completion of this next phase of the project would provide final economic assessment and substantial design completion of all facilities associated with the mine and both communities. The completed documents would be used as a control document for project permitting, design document and bid preparation, and construction. vii Section 1. 2. 3. Executive Summary . List List of Figures of Tables. INTRODUCTION. 1.1 1.2 Background TABLE OF CONTENTS Kotzebue and Nome. Coal Study 1 COMMUNITY ASSESSMENT. Zieh 2.2 FUEL Kotzebue Dredie Regional Setting. 2.1.2 Government. . 2.1.2. Zede Zia 2.1.3 In 1, 1 1 1 NNNND NNZ NN Ne 2. NNN NNNNND ASSESSMENT General. 3 03. 3 3 026 WwWwWww Uk WnNe 1 2 2 oS -4 egional Sere eas overnment. . elites 1 2 City of Kotzebue es Northwest Arctic Borough frastructure. . «+s ss oh Water. ||.) Solid Waste. eee Electricity. | |. |< | Transportation . City of Nome ei enneiils State of Alaska. R G Ze a 2.2.3 Federal Government . 2.2.3 Infrastructure. .. 2 2 2 2 2 General. Water, Sewer, and Solid Waste. Electricity. POEG |is) 5) | 3) =) b+ = AST DOLE a) fess) 6) iets Coal Characteristics Comparison. f au2:1 Comk Bank « = 3i./2).,2 | Coal: Comparison 3.2.3 Coal Characteristics Sumaary. mic Comparison. General * . Common Assumptions. Site Differences. WnNnroO 3.3. WWwWW Ww Ww ww w ¢ 1 2 3 4 Energy Value. . Stripping Ratio. Distance to Tidewater. Shipping Distance. viii . . INNNNNNNNNNN Peirtttia SSWINMHHHPWWRPR eR ' FP OwWWUWUORPRP RRR WWWwWww rtEt WWWKWWWWwWw PRePRPREI I I 1 NNR 4. Deadfall Syncline Mine. Chicago Creek Mine. -3.5.1 Mine Size. 5.2 Development Costs. ‘ -5.3 Mine Operation Costs -5.4 Infrastructure Costs 5.5 Non Production Costs ww Ww ue WWWWW WwWWwWWw 6 Economic Comparison Summary elivered Energy Costs 1 General. . -2 Deadfall Delivered Costs. : 3 Chicago Creek Delivered Costs .4 Deadfall acta to Chicago. 1 Resource. . 1 Compared to Fuel. oil. A -1 Environmental Comparison. -2 Economic Comparison ummary. oo AAD Daa Rew ww aun 3. D 3. 3. 3. 3. c c 3. 3. s 3.7 TECHNOLOGY ASSESSMENT. . . 4.1 Coal Combustion Analysis : 4.2 Power Generation Technologies. 4.3 District Heating. . 4.4 System Configuration 4.4.1 General. . Circulating Fluidized Bed Heater. 4.4.2 4.4.3 Air Turbine... 4.4.4 District Heating System 4.5 System Operation 4.5.1 General. . 4.5.2 Plant Control Systen. 4.6 Power and Energy ar deat 4.6.1 General. . 4.6.2 Nome Historical Data. ot 4.6.3 Kotzebue Historical Data. 4.6.4 Future Power Requirements 4.6.5 District Heating Toeeoron 4.6.5.1 General. . . 4.6.5.2 Nome District "Heating. Options. 4.6.5.3 Kotzebue District Heating System INSTALLATION DESIGN 5.1 General... . 5.2 Power Plant Layouts. ECONOMIC ANALYSIS 6.1 Assumptions and Economic Model 6.1.1 Capital Cost. 3 6.1.2 Personnel Requirements. iz DNAAD tat NRPRPR 6.1.3 Operating and Maintenance Cost. . 6-2 6.1.4 System Efficiency ........ 6-3 6.1.5 O21 Prices. . « «= «= «© «© «© # & & & 6-3 6.1.6 Coal Prices... 6-4 6.1.7 Demand Scenarios. 6-5 6.1.8 District Heating. : 6-6 6.1.9 Power and Energy Projections. 6-7 6.2 Results of Evaluation. .... 6-8 7.@ SOCIO-ECONOMIC IMPACT ...... +. + «© « « « © 7-1 7.1 Kotzebue. . sy he eens) ate 7-1 deed Community Today SH pte Topo Sa efile opin (oeneaj y=. Wotee Ropulations 7. «<r «2 sa 2sin «se wes 2S 7.1.3 Bconomy...... 7-3 7.1.3.1 Employment. . 7-3 7.1.3.2 Cost of Living s = 8 7-9 dole4@ PEoject Tmpact. <5. «2 «st ae « 7-11 7.1.4.1 General. .. a 7-11 7.1.4.2 Construction Employment. and Spending ....... 7-11 7.1.4.3 Plant Manpower Requirements. . 7-13 1.4.4.4 Pricing Bifects. .. .. . s « J-14 We2 NOME 2.2 cw cases Sees Be Hw 8 © HH © o PS In2od Population. . ..<.« 56 0 = «= © 6 «© J=15 Teane BCONOMY «© 2 6 1 «6 «@ ¢ ~ 3 « 3 se | Jao 7.2.2.1 Employment ......... . 7-18 7.2.2.2 Unemployment Rates ..... . 7-21 Iw2n200 Cost of Living . 2.5 «= 1 = mw 3 722) Ta2e4 Project Impact. © 5. 3s 2s 2 6 s « 3 J=2a 7.2.4.1 General. . . « « 23 FaRuthad Construction Employment. and Spending ..... a6 T=23 7.2.4.3 Plant Manpower Requirements. . 7-25 1.2.4.4 Pricing Effects: . .«.. « « 1-26 8.@ CONCLUSIONS AND RECOMMENDATIONS ......... 8-1 8.1 Conclusions. . .. © «© © 6 8 «© © © © © © oe we) 6B 8.2 Recommendations. 8-4 9.0 REFERENCES. . . 2. 2. 2 2 6 © © © © © © © © © ew ew e) 69RD APPENDICES - Western Arctic Studies and Investigations, 1980-19990 - Deadfall Syncline Coal Evaluation Community Resolutions - Inflated Cost - Oil, Coal, Capital and O&M - Diesel District Heat Load - Coal Consumption AImOQwW YS 1 LIST OF FIGURES Figure Location Map. ; Subsystem Diagram Comparison of Simple Cycle and. Recuperated. Gas Turbines Pee 1 NR 4-3 Comparison of Thermal Energy to Electrical Power. 4-4 Cycle Sensitivity to Ambient Temperature. . 4-5 Cycle Sensitivity to Gas Path Pressure Loss . 4-6 Cycle Sensitivity to Turbine and Compressor . Efficiencies 4-7 Allison 501 KB5 Gas Turbine ....... 4-8 Allison 501 KG Air Turbine. . . 4-9 Allison 501 KM Air Turbine... . 4-1@ Typical User Hook-up for Domestic Hot Water 4-11 Typical User Hook-up for Heating. . ail ie 4-12 Typical Installation of District Heating. Pipe a| ke 4-13 Process Schematic So eft aril teva ou Ins} ileal ted) ronlaenlinrel/ ike 4-14 Control Network SoH ie ellis 4-15 Rise in Gross Electrical. Generation, “wone, Alaska 4-16 Rise in Nome’s Peak Electrical Demand ...... 4-17 Nome Average Hourly Weekday Plant Output. .... 4-18 1984 Temperature Distribution in Nome ...... 4-19 1986 Temperature Distribution in Nome. . 4-20 1988 Temperature Distribution in Nome. . 4-21 1984 Temperature Distribution in Kotzebue 4-22 1986 Temperature Distribution in Kotzebue 4-23 1988 Temperature Distribution in Kotzebue 4-24 Nome District Heating With Housing. . 4-25 Nome District Heating Without Housing 4-26 Kotzebue District Heating one 1 Kotzebue Powerplant Plan View Sores 2 Nome Powerplant Plan View .......4.. -3 Kotzebue Powerplant Side View a) | | le 4 Nome Powerplant Side View.......46.. xi 3 i io i o LIST OF TABLES WWW 'repette to WNr ee 1 WODADUN SP WNRFPRP WU DIDU&S Pe Pee Hee HeWWWWWWWw ' > ' ray Ss DAAHDAHAHAAVAA HS ' WWDIDKMNEBWNHRR = a ' ray 8 6-11 6-12 6-13 6-14 ASTM Classification of Coals by Rank. ..... Coal Comparison . : Predicted Sulfur Dioxide Enissions. for Various Coals Site Characteristics. .. Deadfall Syncline Mine-28, 050 tpy Mine “costs. Chicago Creek Mine-49,500 tpy Mine Costs. ... Coal Cost Comparison FOB DOG «ws © «s&s ee e & Transportation Cost Estimates ..... Delivered Coal Cost Estimates Comparison of Emissions Between a Diesel and. CFB. Deadfall Syncline Coal Analysis a & 5 Candidate Gas Turbines. . . a ee Nome Pumping Costs and Heat Losses. i a. 5 Historical Power Generation Data in Nome. s - 6 Historical Power Generation Data in Kotzebue. Expected Power Generation Growth, Nome. . . Predicted Power Generation Growth in Kotzebue Nome Space Heat Data... co eo Heating Losses in District. Heating. Systen,. Nome with Houses Heating Losses in District Heating System,. Nome without Houses Kotzebue Space Heating Data ....... 1988 Dollars Per Barrel... . * @ Coal Price at Various Levels of Production. Diesel Fuel Price Projection, 2.5% Inflat . Diesel Fuel Price Projection, 3.5% Inflat . Diesel Fuel Price Projection, 4.5% Inflat . Nome Diesel Only - Baseline, 2.5% Inflat. .. Nome Diesel with District Heat, 2.5% Inflat . Nome Coal With District Heat, 2.5% Inflat . Nome Coal With District Heat &.... Red Dog, 2.5% Inflat. Nome Coal With District Heat, . . Gold Co. & Red Dog, 2.5% Inflat Nome Diesel Only - Baseline, 3.5% Inflat. . Nome Diesel With District Heat, 3.5% Inflat Nome Coal With District Heat, 3.5% Inflat Nome Coal With District Heat, &. ‘ Red Dog, 3.5% Inflat. Nome Coal With District Heat, .. o Red Dog & Gold Co, 3.5% Inflat. xii 6-10 6-11 6-12 6-14 6-16 6-18 6-20 6-22 6-24 6-26 6-28 Nome Diesel Only - Baseline, 4.5% Inflat. ... . 6-32 Nome Diesel With District Heat, 4.5% Inflat ... 6-34 Nome Coal With District Heat, 4.5% Inflat ... . 6-36 Nome Coal With District Heat & ........ . 6-38 Red Dog, 4.5% Inflat. Nome Coal With District Heat, .. oo ee ew 6 6-408 Red Dog & Gold Co., 4.5% Inflat. Kotzebue Diesel, 2.5% Inflat. ea sew ws « os OZ Kotzebue Coal-Nome Only, 2.5% Inflat. <u » ao « ws 6-06 Kotzebue Coal-Nome + Red Dog, 2.5% Inflat .... 6-46 Kotzebue-Diesel, 3.5% Inflat. ... sao new s « SQ Kotzebue Coal-Nome Only, 3.5% Inflat. 1 6 © w & » 6-50 Kotzebue Coal-Nome + Red Dog, 3.5% Inflat ... . 6-52 Kotzebue - Diesel, 4.5% Inflat. ......... 6-54 Kotzebue Coal-Nome Only, 4.5% Inflat. .. » . . 6-56 Kotzebue Coal - Nome + Red Dog, 4.5% Inflat . « « 6-58 Nome Summary of Analyses. .......... +4. «. 6-60 Kotzebue Summary of Analyses. . . aes 2 = 6=61 Employment by Industry, 1970 and 1980 a - « 7-4 Covered Industry Employment, City of Kotzebue . . 7-6 Average Monthly Employment, City of Kotzebue. .. 7-7 Average Household Expenditure, 1987... ... . 7-10 Weekly Cost of Market Basket of Food, ...... 7-11 March, 1988 Population Estimates, Nome, 1880 - 1988 .... . 7-16 Average Annual Full-Time Employment, Nome, 1988 . 7-19 xiii 1.0 INTRODUCTION 1.1 Background The State of Alaska in an attempt to resolve the energy problem that persists throughout rural Alaska has investigated many potential energy alternatives. These investigations generally considered development of an alternative energy source for use in a single community. Alternatives such as wind, geothermal, coal etc. were evaluated but due to the small energy demand of an individual village, the economics were only marginal compared to the continued use of oil. In the late 1970s the Alaska Power Authority instituted the Northwest Alaska Coal Program to investigate the feasibility of developing a local coal deposit to serve several communities in the Northwest region of the state. As part of this effort, in 1981, the State of Alaska Division of Geological and Geophysical Surveys (DGGS) conducted a coal drilling program throughout the region including the Western Arctic, Seward Peninsula, Unalakleet Area, and St. Lawrence Island. The resource assessment was completed in 1983. The Western Arctic area offered the best combination of access, thickness of seams, quantity and quality of coal. Other state and local agencies performed preliminary studies involving the Western Arctic coal source and different marketing scenarios. A list of these reports and others including field investigations are presented in Appendix A - Western Arctic Coal Studies and Investigations, 1980-1990. These reports indicated that the Western Arctic Coal resource represented a potentially feasible and cost-effective substitute for fuel oil for rural communities in western Alaska. Based on past studies and the DGGS Northwest coal resource evaluation program, the Alaska Native Foundation (ANF) pursued further evaluation of the potential of Western Arctic Coal. In 1984 the ANF submitted a proposal to the State Legislature. In response the legislature and the Governor of Alaska appropriated funds to the State Department of Community and Regional Affairs (DCRA) to perform an in-depth assessment of the project, from, an evaluation of the coal reserves, through mine development and shipping operations and ending with community end-use. The DCRA retained the ANF to administer the Western Arctic Coal Development Project (WACDP). The assessment was conducted from 1984 - 1988 and cost $2.5 million. The results of the study were most encouraging. As a result of the WACDP, the Kotzebue Electric Association and Nome Joint Utility requested an assessment be conducted of the feasibility of their communities converting to Western Arctic coal for power generation and district heating. On their behalf the ANF proposed to the state that a Kotzebue and Nome preliminary evaluation be performed. The 1989 State Legislature appropriated $150,000 to conduct this study entitled, Kotzebue and Nome Coal Study. The Alaska Energy Authority sponsored the project and retained the ANF to administer the study. Other interest both public and private was generated by the states WACDP Program. As a result of the state’s efforts, in 1986, the North Slope Borough (NSB) sponsored a coal demonstration program which involved test mining at the Deadfall Syncline mine site of the western Arctic and installation of residential coal stoves in the villages of Pt. Lay, Pt. Hope, and Wainwright. The program is on-going and has produced 700 tons of coal for residential use over three years. To date $2.9 million has been spent on the program with an additional $850,000 ear marked for this year’s effort. In February of 1989 the NSB also sponsored a similar study to the Kotzebue and Nome Coal Study entitled; Barrow Power Generation Coal Conversion study. This study looked at the potential of using coal for Barrow’s power requirements in the mid to long term. In addition to the NSB, the Arctic Slope Regional Corporation (ASRC) has utilized its own resources to evaluate and market Western Arctic coal. Since 1984, they have spent over §$ 1 million to conduct: the Western Arctic Coal Geophysical Program in 1985; Deadfall Syncline Coal Combustion Test in 1989; Pacific Rim exploratory marketing effort in 1989; and preparation and submittal of a five year mining permit application for the Deadfall Syncline Coal Prospect Site. Since 198@ the state of Alaska, NSB, and the ASRC have spent over $ 7 million dollars to assess the development of a coal industry in the Western Arctic. Results of these efforts show the development of the resource to be a viable means of meeting the energy needs of the region and has advanced the project to its development stage. Development of a coal industry in the Western Arctic serving the needs of Nome and Kotzebue would: 1) provide economic power and independence in the Northwest area of the state; 2) reduce, state and local participation in energy assistance programs; 3) provide long term permanent employment and business opportunities in the area; 4) establish an abundant and economic local energy source for future use by other Alaskan communities and industries in the region; and 5) it will establish creditability in the coal industry and thus LS enhance the opportunity to export coal to the rapidly expanding Pacific Rim bituminous coal market. Expansion of the coal mine through increase in demand, whether it be in- state or internationally, will increase the number of jobs and benefits for the State of Alaska while decreasing the cost of coal for its in-state users. 1.2 Kotzebue and Nome Coal Study The purpose of this project is to examine the feasibility of using a local coal source in Alaska as an alternative to imported fuel oil for power generation and district heating for the Kotzebue Electric Association (KEA) and Nome Joint Utility (NJU). (See Figure 1-1). Both utilities are in the process of planning for replacing their current generating equipment through retirement and adding capacity to anticipated growth. This study ultimately would be a consideration in their planning cycle. This project builds on work performed in previous studies including the recently completed state funded Western Arctic Coal Development Project (WACDP) and examines for the communities of Kotzebue and Nome the following: - coal-based power generation technology(s) and method(s) applicable to the Kotzebue and Nome power utilities; = district heating systems and scenarios for each community; = environmental impact of the selected coal-based method and technology; a DEADF LL SYNCLINE COAL SITE J cHuk® " KOTZEBUE @ s EA achicaco CREEK COAL SITE / o 6 12 24 48 MILES ~meer KOTZEBUE AND NOME DATE : JAN. 1990 GD cre sre cos tn COAL STUDY Wc on sac aah Sau LOCATION MAP FIGURE 1-1 1=S - economics of coal-fired power generation and district heating; and - assessment of the socio-economic impact of coal based power. Previous work, including WACDP, established the feasibility of mining coal in the Western Arctic and has advanced the project to its development stage. Development of an in-state market is the next phase for the economic development project. As part of the WACDP report a preliminary marketing effort was conducted throughout the market area. This included a preliminary end-use feasibility effort that assessed coal use for the community of Nome. Several coal-based methods and technologies were found to be superior to the continued use of oil. Also, in 1982, the Alaska Power Authority conducted the "Coal Fired" Cogeneration, District Heating and Other Energy Alternatives Feasibility Assessment for the community of Kotzebue. The conclusion was coal-fired cogeneration may be the most attractive alternative if coal (local or imported) can be provided for around $6.00 /Mbtu. Based on these past efforts the Kotzebue and Nome Coal Study updated the current demographics and energy profiles of both communities and evaluated coal-based technologies and methods for each community. Economic and Financial feasibility was based on the regional concept for the WACDP which identifies both the Kotzebue and Nome utilities and 3 North Slope communities as the preferred initial market This study was performed in conjunction with the North Slope Borough (NSB) Western Arctic Coal Demonstration Program and the Arctic Slope Regional Corporation (ASRC) Deadfall Syncline Coal Combustion Test Program. The NSB Program provided a coal sample for the ASRC testing program. Results of the ASRC testing program provided the data necessary to, design and evaluate coal and ash handling methods, boiler and turbine technology and, desulfurization requirements, and determine the environmental impact of its use. The report can be found in Appendix B. The Kotzebue and Nome coal study has: provided an assessment of the suitability of today’s coal-based technologies and methods and their impact on the communities; determined the impact of the regional approach of supplying energy to the western region of the state on the end-use economics of coal; and provided to the Kotzebue and Nome utilities an energy alternative to oil that can be used in their planning process for future plant retirement and capacity additions. 2.@ COMMUNITY ASSESSMENT 2.1 Kotzebue 2.1.1 Regional Setting Kotzebue is a community of 3700 persons, located on a spit on the northwest flank of the Baldwin Peninsula, facing Kotzebue Sound and eventually the Chukchi Sea to the west (see Figure 1-1). To the east of Kotzebue behind the Baldwin Peninsula lies Hotham Inlet. Kotzebue is situated at the juncture of the marine environment and major river to the north and east respectively. This setting creates the conditions that dominate the natural environment in Kotzebue’s vicinity. The climate is maritime, and prevailing wind and current patterns at sea may abruptly change local weather conditions. Summers are short and cool in which the highest recorded temperature is 85'F, the lowest temperature on record is -538'r. There are an average of 16,039 heating degree days per year, 12% more than Nome. The average annual wind speed is 13.9 miles per hour. The semidiurnal tidal range is small and wave action is generally low, giving the Kotzebue seashore a tranquil appearance that belies the violence of Chukchi Sea storms. Wintertime ice conditions in Kotzebue Sound are unlike those found in the Chukchi Sea proper and along its coastal perimeter. Shorefast ice in the Chukchi Sea extends about ten miles into shallow water, and active lead systems and prevailing winds ensure large, open flaw areas and polynyas that form important seasonal sea mammal habitats, permitting sea mammal hunting adaptations that characterize the indigenous Inupiag societies outside Kotzebue Sound. Ice cover in Kotzebue Sound is stable, but the ice edge is weak and highly unstable and polynyas are rare. The runoff from the main watersheds in the Sound often results in overflow conditions prior to breakup in the Sound per se. These conditions are not favorable for sea mammal populations nor for open-lead hunting. As a result, Kotzebue is not as well situated for intensive sea mammal hunting adaptations as are neighboring communities to the northwest. The terrain in sight of Kotzebue is low but not flat. The Igichuk Hills and Baird Mountains to the north form the most evident contours to the naked eye, and the Baldwin Peninsula itself extends in rolling, rounded hills to the east and south of the town before falling to low meadows and flat beaches, punctuated occasionally by abrupt banks along the shore. The air approach to Kotzebue from the southeast reveals a narrow middle portion of the Baldwin Peninsula that is less than a mile wide. Hence, the north segment of the Peninsula appears much like an island, which possibly gave rise to the Inupiaq term for Kotzebue: ikigtagruk, or "peninsula" (literally, "like an island"). Kotzebue is the headquarters for three important national park areas: Gates of the Arctic National Park and Preserve, Cape Krusenstern National Monument, and Kobuk Valley National Park. In contrast, Nome serves as the headquarters for only one, the Bering Land Bridge National Preserve. 2.1.2 Government 2.1.2.1 City of Kotzebue Kotzebue is incorporated as a second class city with a city manager form of government and a seven-member council from whose membership the mayor is elected. The city currently exercises the following governmental powers: water, sewer and solid waste; police protection and jail facilities; fire protection; streets and sidewalks; recreation; community center; animal control; licensing of taxis; public transportation; planning, platting and land use regulation; building code and inspection; libraries; and flood plain management. These city functions are organized into four main administrative groups: public safety; health and human services; public works; and administration. The City has a total permanent, full-time staff of around 75 employees. Over the past several years Kotzebue has had severe financial difficulties due to declining state, federal and local revenues and increasing service costs. To deal with these, the City has taken effective steps to improve its financial situation, including cutbacks in budget, staff and services, wage reductions, fee increases, and rescheduling of debt service. The City has updated its comprehensive plan, and its principal planning emphasis is on enforcement of existing ordinances. The planning staff reviews building permits (required for commercial structures and optional for residential structures), as do Public Works, the City Manager and the Fire Department. A watershed study is designed to address the city’s chronic water shortages. The Alaska Department of Transportation and Public Facilities is funding a transportation study of the area east of Kotzebue across the lagoon. 2.1.2.2 Northwest Arctic Borough The Northwest Arctic Borough (NWAB) was incorporated as a first class borough in 1986, with its headquarters in Kotzebue. By approval of borough voters in the October 1987 general election, the Northwest Arctic Borough acquired home rule borough status. Under Alaska law, a home rule borough may exercise any powers not expressly prohibited by state law or its own charter. This gives home rule borough great flexibility in assuming and exercising governmental powers. At its outset, the borough chose to exercise only the mandatory powers of education, tax assessment and planning. The school District became part of the borough. The borough assumed the powers of planning, plating and land-use regulation immediately after incorporation. The existing coastal management and regional strategy planning functions were transferred from their former sponsor, Maniilaq Association, to the Borough. The City of Kotzebue still exercises its planning power, pending negotiations with the borough. The Red Dog mine will provide the major revenue base for borough government, as well as an important source of jobs for residents. The borough originally planned to levy a property tax. However, for the time being, a property tax has been deferred, thanks to a financial agreement executed in February 1987 between the borough and Cominco Alaska, the developer of the Red Dog mine. This agreement authorizes payments to the Borough by Cominco in lieu of borough-imposed taxes. Payments are to be made quarterly for 14 years, escalating by $50,000 annually following the fourth through the eleventh years. The initial quarterly payment is $250,000; the final quarterly payment will be $750,000. 2.1.3 Infrastructure 2.1.3.1 Water The City of Kotzebue provides water, sewer and solid waste services. At the present time, all three are at or near maximum capacity. The city’s water supply is Vortac Lake, located to the east across Kotzebue Lagoon in the hillside area. Water is pumped directly from Vortac Lake through a boiler house to the water treatment facility across Third Avenue from the PHS hospital. The heat generated in the boiler house prevents the water from freezing in the winter as it flows through the 8,0@@-foot transmission line to the treatment plant. From there, the water is pumped to an insulated 1.5 million gallon storage tank adjacent to the treatment plant for distribution throughout Kotzebue. The entire distribution system is heated by waste heat from Kotzebue Electric Association power plant. Nonetheless, water lines still occasionally freeze in the winter. The storage capacity of Vortac Lake is approximately 134,500,000 gallons (412 acre-feet). However, in the winter this capacity is reduced to approximately 57,350,000 gallons (176 acre-feet), an overall reduction of 57 percent. Winter water consumption in Kotzebue requires nearly the entire storage capacity of Vortac Lake. This level of demand necessitates pumping water from nearby Devil’s Lake to Vortac Lake to maintain adequate water levels. There are some 825 water hookups in Kotzebue, of which around 10@ are non-residential. Approximately 20 residential structures have not been hooked up to the city water or sewer system. There are 85 water hydrants located throughout the developed area of the city. In response to the recent unforeseen increase in water consumption, the city is investigating alternative water conservation measures. Water metering appears to be a favored option. 2.1.3.2 Solid Waste A seven-acre solid waste landfill is located south of the sewage lagoon. The landfill is over capacity and the city, in concert with DEC, is evaluating alternative sites. Three sites south of the present landfill have been identified, two by DEC and one by the city. No detailed soils information is available for any of the sites. The two sites selected by DEC are adjacent to the road to the Air Force White Alice site. The city’s selection is approximately one and one-half miles east of this road at a higher elevation, which would permit deeper excavation of the landfill. The acreage requirements are dependent upon several factors: depth of the landfill, population, and amount of solid waste generated per capita. The city has estimated that a new landfill sized to serve city needs for 30 years would require from 45 to 177 acres, depending on depth. These estimates are based upon an annual population increase of about four percent. The city will also require land at the existing landfill to accommodate solid waste disposal until a new landfill is operational and to allow proper close-out of that landfill. This landfill is on land owned by KIC and may be addressed as part of the 14 (c) (3) reconveyance. 2.1.3.3 Blectricity The Kotzebue Electric Association (KEA) has been providing electrical power to Kotzebue since it was established as a Rural Electrification Administration cooperative in 1955. The KEA power plant is located near the airport and has a name plate rating-installed capacity of 6,625 megawatts (MW). According to the Alaska Department of labor (1988), the March 1988 cost of 1,000 kWh of electricity in Kotzebue was $239.46 compared to $71.12 in Anchorage. KEA participates in the state’s Power Cost Equalization (PCE) program, which provides state- funded subsidies’ to rural electric utility customers. The amount of state subsidy is a function of the amount of power consumed. In 1988 KEA received $460,000 from the PCE. KEA must obtain approval of the Alaska Public Utilities Commission for the PCE rates it sets as part of its Master Tariff provisions. In 1989, KEA’s Board of Directors, Northwest Arctic Borough Assembly and the Alaska Rural Electric Cooperative Association approved resolutions endorsing KEA’s participation in the Western Arctic Coal Demonstration Project, (see Appendix C). Conversion from an oil to a coal fired technology could have the eventual effect of stabilizing fuel prices to the utility and electricity costs to the consumer. 2.1.3.4 Transportation Kotzebue is the transportation hub for the NANA region. Virtually all goods destined for the NANA region are brought to Kotzebue by air or barge. From there, they are generally shipped by barge during the summer months, although air transport of bulk goods such as construction equipment, fuel and heating oil occurs yearround when required. 2015 The state-owned and operated Ralph Wien Memorial Airport at Kotzebue can accommodate passenger jets and large cargo transports. The airport has two runways, a 15@ foot by 5,900 foot paved runway and a 100 foot by 3,800 foot gravel runway. The taxiway and aprons are paved. The airport presently serves one major carrier (Alaska Airlines), two cargo transports (MarkAir and Northern Air Cargo), and several small commuter and charter airlines (e.g., Cape Smythe, Baker Aviation, and Bering Air) that serve the outlying NANA villages and communities in the North Slope Borough and occasionally on the Seward Peninsula. Kotzebue is served during the ice-free summer months by three Seattle-based mainline barge companies- Alaska Marine Lines, Northland, and Pacific Alaska Line. Village-bound goods are reshipped by river barge to the outlying communities. Frequency of service depends on the duration of icefree water and river water depth. Most communities receive two or three barge shipments a summer from Kotzebue. Because of Kotzebue Sound’s' shallowness, the mainline barges anchor 11-15 miles offshore and cargo is lightered into Kotzebue. This two-step process adds significantly to the cost of shipping. Because of this, consideration is being given to backhauling bulk cargo to the deep water port being developed for the Red Dog mine. The cargo would then be distributed from the port site. It is hoped that this will reduce the shipping cost for commodities such as fuel and heating oil, particularly if sufficient quantities can be stored at Red Dog so that fuel and heating oil need not be flown into the region’s villages to ameliorate winter shortages. 2.2 Nome 2.2.1 Regional Setting Nome, a community of 3700 persons, is located 510 air miles northeast of Anchorage on the southern side of the Seward Peninsula (see Figure 1-1). Nome experiences an annual average of 14,325 heating degree-days. The moderating influence of the open water of Norton Sound is effective from early June to about the middle of November. During the summer months, the daily temperature range is very slight, but the freezing of Norton Sound in November causes a rather abrupt change from a maritime to a continental climate. Snow begins to fall in September, but usually does not accumulate on the ground until early November. The snow cover disappears around mid-June having reached a maximum accumulation in late February or early March. Average wind speeds are 12 to 12 mph with severe windstorms occurring occasionally from October through March. These strong winds, reaching velocities exceeding 7@ mph, produce blowing snow conditions that severely hinder transportation in the area. Nome is a transportation and commerce center for Northwest Alaska. The immediate area has rich mineral potential with gold mining remaining as the major industry after 86 years. 2 - 10 2.2.2 Government 2.2.2.1 City of Nome The City of Nome, incorporated in April 1901, is one of Alaska’s oldest cities. Nome adopted the council-manager form of government in 1965. The elected mayor and council have policy and fiscal responsibility for the city, while the appointed city manager administers city government. Nome is perhaps the most sophisticated city government with the best developed infrastructure in rural Alaska, excepting only Barrow. As a first class city located outside an organized borough, it has all the general law powers of a first class city, including the mandatory education and planning and zoning powers that are otherwise vested in boroughs. Powers exercised by the city include: animal control, building code and inspection, education, electricity, fire protection, library services, museum, planning and land use regulation, platting, police protection, port operation, public transportation, recreation, streets and sidewalks, taxi licensing, visitor and conventional center, and water, sewer and solid waste. The elected Nome School Board manages school operations; the elected Nome Joint Utilities Board supervises electricity, water, sewer, and solid waste services. City operations are located in 12 buildings. The city hall, library/museum, fire/police station, mini convention center, visitor's center, senior citizen’s center, public works building, and 2 - it recreation center are located in the downtown area. Other city buildings include the Icy View Fire Station, a small morgue (there is a three-acre city cemetery), and a large storage building with 5-ton hoist and a mobile home at the port. The city also owns additional buildings and other facilities managed by the school district and Nome Joint Utilities. 2.2.2.2 State of Alaska State government plays an important role in the provision of governmental services in Nome. At least 16 state agencies maintain offices there to deliver services to the town and region. They employ about 200 people in Nome. The Department of Transportation and Public Facilities is the largest state employer in Nome with about 50 employees. It is not likely that the state’s presence in Nome will change significantly in the near term. State budgets have essentially been stable, following a policy of maintaining services and not undermining local employment through excessively drastic cuts in appropriations. If and when major improvements in the state’s economy occur, further expansion of state activities in the region can be expected. 2.2.2.3 Federal Government With one exception, federal employment in Nome has dropped from 74 in 1980 to 47 in 1987. Virtually the entire decrease is accounted for by the loss of 25 Bureau of Indian Affairs (BIA) positions; The 27> 22 BIA staff has since been reduced to three positions. The change stemmed from contracting many services to Native Corporations (Kawerak, Nome Eskimo Community, and others), discontinuance of some services, and consolidation of most administrative services in Juneau. Nome’s other principal federal agencies are the Federal Aviation Administration (30 employees in 1987) and the Postal Service (10 people), both serving the local population as well as having regional responsibilities. FAA operates a regional flight center at the Nome Airport. 2.2.3 Infrastructure 2.2.3.1 General Nome Joint Utilities (NJU) manages and operates all utilities owned by the City of Nome: water and sewer services, electric generation and distribution, and solid waste. Telephone service is provided by privately-owned GTE Alaska. The Nome Joint Utilities Board is granted broad powers over policies, operations, and fiscal affairs, including maintenance, expansion, extension, and improvement of the public utilities. Utility budgets, rates, and real property acquisition and disposal are, however, subject to approval by the city council. The council also has authority over contracts binding the municipal corporation. 2- is 2.2.3.2 Water, Sewer, and Solid Waste The municipal water and sewer improvements installed over the past ten years provide the basic facilities needed to take care of present needs and future growth. The yet unmet needs identified in the City’s Water and Sewer Master Plan, are Icy View water and sewer service; an alternate water supply line; and upgrading of the waste water treatment plant. During the 196@s, Nome installed a pioneering circulating-water and sewer system to serve the downtown and adjacent areas of the city. To keep the system from freezing, pipes were encased in three-foot by five-foot buried wood utilidors. The system was extended in 1976, using six-foot diameter metal utilidors. During 1982-84, water and sewer service was extended to the rest of the core area and to the east end of town. Based on new engineering data on buried pipe and experience with utilidors, water and sewer pipes in the 1982-84 extensions were insulated and buried in the same trench directly in the ground. A one million gallon insulated water tank, together with a set of large diesel and electric pumps, provides storage and capacity to adequately serve the community and take care of fire fighting needs. An additional 300,000 gallons is stored at the Snake River power plant near the airport. a= 54 Garbage collection is mandated by the City and provided by a private company. NJU maintains the city dump that may soon be replaced; a location study for a new dump was recently undertaken. Aside from the potential dump relocation need, solid waste collection and disposal are not expected to cause future problems. 2.2.3.3 Electricity Three power plants, with an installed capacity of about 10,000 kilowatts, generate electricity: the main Snake River power plant (6933 KW), the Belmont Point plant (1800 KW), and a small plant at Beltz High School (60@ KW). A new 1500 Kw unit was installed in the Snake River power plant during 1988. NJU has a 3.4 million gallon fuel storage capacity for power generation. Four new tanks, each of 850,000 gallons, were installed in 1987. NJU is part of the Western Alaska Fuel Procurement Group, which purchases six million gallons at a time to command lower prices for its members. Prior to installing its own storage facilities, the utility purchased fuel from private suppliers in Nome at significantly higher prices. All homes in Nome are served with electricity. NJU has some 1,800 customers within the city limits. Waste heat is utilized from all generators. Waste heat from the Belmont Point plant, north of town, is used to heat the city’s principal water supply. 2S French drains gather the water, which runs by gravity into town. The natural temperature of the water is 34 degrees. Heat exchangers bring the temperature to 5@ degrees to prevent the water system from freezing. At Beltz, waste heat is used in the school’s boiler system. In 1989, both the Nome Joint Utilities Board and the City Council passed resolutions endorsing NJU participation in a coal demonstration project involving the conversion of the Nome power plant from oil to coal, utilizing the coal deposits of the Western Arctic Coal Project. (Respectively, Resolution 89-16 and R-89-5-2 in Appendix C). 2.2.3.4 Port The newly improved Port of Nome saw its first year of operation in 1987. Previously, shallow waters required all freight to be lightered between off- lying vessels and the shore, a step that added considerably to higher costs. New port construction has so far provided a causeway that, with a mooring barge, can accommodate 18.5 foot draft vessels, but the port’s ability to berth fully-loaded line-haul barges is limited. The causeway does provide an 8- inch and two 6-inch petroleum product pipelines. During the 1987 season, petroleum cargo tonnage was 34,52@ tons and dry cargo came to 11,196 tons. Remaining planned port developments, to include improved causeway and docking facilities and inner harbor improvements, do not seem likely to be funded in the near future. 2) = 26 Studies during the planning and construction stage of the causeway projected petroleum as 70 percent of future cargo. Petroleum’s 1987 share was over 75 percent, and it is now expected that it will increase to 8@ percent in view of the reduction of dry cargo in recent years, assuming petroleum continues to be used for power generation and all heating in Nome. Dry cargo has more limited prospects at present because the ramp designed for the causeway is not usable at this time and there is only limited storage space for containers. Because of these unloading problems, only limited use of the causeway is anticipated until a better platform than the floating mooring barge can be built. The city is planning to construct a 200’x200’ mooring facility and a work pad; however, timing of construction is uncertain due to funding constraints. Port billings reached almost $900,000 by the end of the first season, even though the mooring barge was not in operation until September 1987 and a substantial amount of cargo went through on a non- revenue basis to offset shippers’ expenses of investment in handling equipment for petroleum. 1988 port revenues were approximately $350,000, as the initially high tariffs were reduced. Projections call for future revenues equal to those of 1988. Revenues will be sufficient to make the $170,000 annual debt payment to Farmers Home Administration. Payments are not being made on the $5 million NOAA-Local Energy Impact Program loan; negotiations are underway to deal with this 2- i7 obligation. Overall revenues are not sufficient to carry out further needed port improvements. Full port development is not likely in the foreseeable future. If and when it occurs, it will require a causeway extension of an additional 900 feet to reach a 3@ foot depth. 2.2.3.5 Airport Nome is the hub of the regional air transportation system linking the Bering Straits communities to Anchorage and other regional centers. Nome is served by two airports, Nome Airport and Nome City Field. Nome Airport, which is located about a mile west of town, is the main airport and can accommodate commercial jet passenger and cargo aircraft. Nome City Field, located about a mile north of downtown, has a 3, 200 foot gravel and turf runway and is used mainly by local small aircraft. Existing and airport facilities are well described in the Master Plan prepared for both airports by TRA/Farr (1983) for the Alaska Department of Transportation and Public Facilities. Components of the Master Plan included a forecast of aviation demand; a demand/capacity analysis; facility requirements; plans for terminal area, land use, access and parking, and airport layout; and a development schedule. Nome Airport originated as a military field, built as a stopover on the World War II trans-Siberia route to ferry aircraft and military supplies to the 2- 18 Soviet Union. In 1966, ownership was transferred to the State of Alaska which now owns and maintains the airport. Nome is served by Alaska Airlines and by MarkAir (cargo flights only), plus numerous intra-regional flight services. Nome Airport has two existing paved runways, 6,018 feet and 5,575 feet in length respectively, with the longer runway equipped with an instrument landing system. According to the Master Plan, the existing runways and navigational aids were adequate in capacity for the foreseeable future, but proposed that both runways eventually be lengthened to 6,500 feet. The plan stressed the need for major runway maintenance and repairs and apron improvements rather than new landing facilities. a if 3.0 FUEL ASSESSMENT 3.1 General Past geology and feasibility work performed in Northwest Alaska identified the Western Arctic resource as the coal resource having the best potential of meeting the energy needs of the area due to its quantity and quality. In addition to the Western Arctic, several studies have investigated utilizing coal from Chicago Creek to provide power and heat in Kotzebue. Chicago Creek coal is located in the study region across Kotzebue Sound about ten miles south of Deering. The location of both coal fields is shown in Figure 1-1. This section evaluates the Deadfall Syncline coal prospect of the Western Arctic and the Chicago Creek Coal Prospect as potential fuel sources for this project. Coal characteristics and economic data of both coals are compared. The economic comparison involves the development of delivery costs in 1989 dollars from the two sources delivered to Nome and Kotzebue. Further analysis compares these costs to the cost of fuel oil. 3.2 Coal Characteristics Comparison 3.2.1 Coal Rank Coal is not a uniform substance and no two coals are exactly alike in every respect. As the coalification process progresses in nature, the coal characteristics are modified and the rank of coal increases. For example, characteristics such as carbon’ content, calorific value, and reflectance increase with increasing rank while volatile matter, hydrogen and oxygen content Note: decrease with increasing rank. These characteristics and others make up the categories established to form a standard classification of coals by rank. The American Society for Testing of Materials (ASTM) standards, presented in Table 3-1, classifies coal by its fixed carbon and calorific value. The higher rank coals are classified by fixed carbon on a dry basis while the lower rank coals are classified by calorific value ona moist basis. A comparison of coal characteristics of the Deadfall Syncline and Chicago Creek coals are presented in Table 3-2. The data on Chicago Creek is from a 1986 report by Rutherford and the data on the Deadfall Syncline coal is from the 1986 Western Arctic Coal Development Project, Village End Use Technology Assessment Report. TABLE 3-2 Coal Comparison Chicago Creek Deadfall Syncline Moisture % 38.64 4.63 Volatile Matter % 29.27 33.89 Fixed Carbon, % 27.54 53.86 Ash, % 8.55 7.62 Heating Value, Btu/lb 6400 Idee Total Sulfur, % @.82 @.19 Coal analysis based on as-received coal. Table 3-1 ASTM Classification of Coals by Rank Calorific Value Limits Fixed Carbon Limits, Volatile Matter Limits Btu per pound percent(Ory,Mineral- percent(Ory,Mineral- (Moist, Mineral Matter-Free Bas ts) Matter-Free Basis) Matter-Free Basis) qual or qua’ or qual or Greater Less Greater Less Greater Less Agglomer ating Class Group Than Than Than Than Than Than Character 1, Anthracitic 1. Meta-Anthracite 98 --- --- 2 oe --- Nonagglomer at ing 2. Anthracite 92 98 2 8 oe oo- 3. Semtanthracite 86 92 8 14 --- --- IL. Bituminous 1. Low volatile bituminous coal 78 86 14 22 oo: soe 2. Medium volatile bituminous coal 69 78 22 31 --- oe 3. High volatile A bituminous coal o-- 69 2 --- 14, 000d --- Commonly agglom- 4. High volatile 8 bituminous coal o-- oe --- o-- 13,0004 14,000 erating® 5. High volatile C bituminous coal oo- --- o-e o-- 11,500 13,000 10,500 11,500 Agglomer at ing IIL. Subbituminous 1. Subbituminous A Coal --- --- --- 10,500 11,500 Nonagglomer at ing 2. Subbituminous 8 Coal --- --- --- 9,500 10,500 3. Subbituminous C Coal --- --- --- --- 8,300 9,500 IV. Lignitic 1. Lignite A o-- --- oe 6,300 8,300 Wonagglomerat ing 2. Lignite 6 eos --- --- --- 6,300 @ This classification does not include a few coals, principally nonbanded varieties, which have unusual physical and chemical propert teheesi« hich come within the limits of fixed carbon or calorific value of the high-volatile bituminous and subbituminous ranks. All of these coals either contain less than 48 percent dry, mineral-matter-free fixed carbon or have more than 15,500 moist, mineral-matter-free British thermal units per pound. D Moist refers to coal containing its natural inherent motsture but not including visible water on the surface of the coal. C If agglomerating, classify in low-volatile group of the bituminous class. 9 Coals having 69 percent or more fixed carbon on the dry, mineral-matter-free basis shall be classified according to fixed carbon, regardless of ‘ calorific value. It 1s recognized that there may be nonagglomerating varieties a) these roups of the bituminous class, and there are notable exceptions in the - high volatile C bituminous group. Source: ASTM 0 388-77 From Tables 3-1 and 3-2 the Chicago Creek coal would be ranked as an A-B Lignite coal while the Deadfall Syncline coal would be of a higher rank, High Volatile A-B Bituminous coal. 3.2.2 Coal Comparison Although both coals are perfectly acceptable as a fuel for the study application, the significant differences in coal characteristics will play a major role in the design and cost of all facilities associated with the power plant, coal storage, coal and ash handling, ash disposal, and environmental controls. In order to predict the performance of a particular coal in every facet of power plant operation, an in-depth fuel analysis is required prior to plant design. Such an analysis was performed on the Deadfall Syncline coal and its results are presented in Appendix B, Deadfall Syncline Coal Evaluation. A comparison between both coals based on specific coal characteristics follows: Heating Value From table 3-2 the Deadfall Syncline coal has nearly 100% higher heating value than the Chicago Creek coal. The significant difference in heating value will require larger coal and ash handling equipment as well as larger coal storage and ash disposal areas for Chicago Creek coal. Moisture Chicago Creek coal has substantially more moisture than Deadfall Syncline coals. Higher moisture content means lower thermal efficiency since the moisture evaporates during combustion thus carrying heat away. It can also impact feed-system design boiler capacity and size of convection pass. In addition, high moisture can lead to increased Carbon Monoxide emissions because of after - burning. Further high moisture coals are generally restricted to use at the mine site and are uneconomic to ship since transportation is paid for by the pound. Higher Btu coals with less moisture like Deadfall Syncline coals are more economic to transport. Sulfur Sulfur content plays a major role in the design of power plants. In addition to its polluting properties sulfur plays a part in corrosion of air heaters, economizers, and stacks. Pyrite sulfur contributes to clinkering, slagging, and spontaneous combustion. Chicago Creek coal contains four times more sulfur than Deadfall coal. In coal combustion the most important criteria is how much sulfur dioxide, (SO,), will be produced per million Btu. Table 3-3 compares predicted sulfur dioxide emissions for various Alaskan coals and other U.S. coals. TABLE 3-3 Predicted Sulfur Dioxide Emissions for Various Coals lb S0,/Million Btu Coal Type Produced Deadfall Syncline Coal @.30 Chicago Creek Coal 6197 Beluga Coal @.30 Nenana Coal @.67 Northern Appalachia 4.8 Southern Appalachia 1.6 Alabama 2.2 Eastern Midwest 6.5 Western Midwest 9.0 Western aie From table 3-3 considerably more sulfur dioxide is emitted from Chicago Creek coal. This means considerably more desulfurization equipment and/or methods will need to be applied to Chicago Creek coal to bring it within the minimum so, emission standards established by the Environmental Protection Agency (EPA) and State of Alaska. Ash Fusibility Temperature The relatively low ash fusion temperature of Deadfall coal (about 2143°F), will require an increase in grate area in fixed bed furnaces and a larger furnace volume in pulverized combustors. Chicago Creek coals have ash fusion temperatures consistently above 2200°F. Spontaneous Combustion A safety consideration and design of coal _ storage facilities are impacted by the coal’s potential to spontaneously ignite. Spontaneous heating and ignition of coal is an oxidation process. The higher the rank coal, the lower the inherent oxygen of the coal and the slower the rate of oxidation. Lignite oxidizes most readily while anthracite is least readily oxidized. Deadfall Syncline coal is a high volatile bituminous coal and is expected to oxidize fairly readily. Another factor that influences spontaneous combustion is the petrographic composition of the coal. Deadfall Syncline coal contains a low percentage of exinite macerals which have a greater tendency to spontaneously oxidize. Due to this factor the coal is not expected to show a greater tendency to spontaneously oxidize than other coals of similar rank. Moisture plays a significant role in spontaneous combustion too. The exposure of mined coal to ambient air can result in a loss of inherent moisture until the coal reaches an equilibrium with the relative humidity of the ambient air. The reabsorption of moisture by coal, due to increased humidity or rain, can result in an increase in stockpile temperature, thereby promoting spontaneous heating. Low rank coals containing high moisture such as Chicago Creek are susceptible to this scenario. Deadfall Syncline coal contains low moisture and cannot be induced to heat spontaneously by this process. Sulfur is also a factor in the promotion of spontaneous combustion. Oxidation of pyritic sulfur can promote spontaneous heating not only because of the heat generated by oxidation of pyrite and phyrrhotite but also due to coal fines generated by the disintegration of the sulfides. The Northern Alaska Coal Fields comprise the largest accumulation of low sulfur bituminous coal in the world. As part of the Northern Alaska Fields, Deadfall Syncline coals contain little pyritic sulfur, (<.003%), and the spontaneous heat generated by this process would be negligible. Since Deadfall coals are high rank coals, with low moisture and pyritic sulfur, and favorable petrologaphic composition, they have a very low potential for spontaneous heating. Chicago Creek coals, on the other hand, are of lower rank with higher moisture content, and therefore, compared to Deadfall Syncline coal, have a greater potential for spontaneous heating. 3.2.3 Coal Characteristics Summary Many of the coal characteristics of Deadfall Syncline coal give the coal several advantages over Chicago Creek coal, such as: af lower capital cost for coal and ash handling and emission controls equipment; 2) more economic to transport; 3) less space required for coal storage and ash disposal; 4) less environmental impact due to reduced emissions; 5) lower probability of spontaneous combustion. 3-8 The coal characteristic that favors Chicago Creek coal is a higher ash fusion temperature. The ash softening temperature of Deadfall Syncline coal is at the low end and would require special design consideration if used in stoker or pulverized coal combustors. Economic Comparison 3.3.1 General The economic comparison of the Deadfall Syncline and Chicago Creek coal sources requires that the cost components considered be similar. The data available on the two mine sites were generated by different sources using different engineering and economic assumptions. To make a valid economic comparison of the two sites WACDP data was used on both the Chicago Creek and the Deadfall Syncline sites to eliminate as many independent variables as possible. Any advantages of the Chicago Creek site may now enjoy or disadvantages it may suffer from different design and study conditions can be applied to either site. 3.3.2 Common Assumptions The following assumptions were applied to both sites for this comparison: Energy demand: The energy demand in the target market will not be influenced by the coal source. The 1988 Phase III, Stage 1, demand, (28,050 tons of Deadfall Syncline coal at 12,000 Btu/1lb), will be used to compare the Chicago Creek and Deadfall Syncline cases. Mine: The same camp, mining equipment, coal hauling equipment and related physical plant would be used at either site. Marine Transportation: The same port, coal loading and marine transport equipment would be used at either site. Labor: The same labor complement and hourly rates would be used at either site. Financing: Financial costs such as interest, royalties and other non production costs would be the same between the two sites. 3.3.3 Site Differences Several physical characteristics distinguish the two sites and have significant impact on project economics. Considered in aggregate these variables will determine the relative ranking of the two sites. These characteristics are discussed below and summarized in Table 3-4. 3 - 10 Stripping Ratio TABLE 3-4 Site Characteristics Ratio Per Unit Deadfall Chicago Coal Energy Energy Density (Btu/1b) 12000 6800 1.76 1276 Tons of Coal Mined 28050 49500 1271.6 276 2)25 65 Vist ci7, @.64 Leis Distance to Tidewater 5.4 10 1.85 3.27 Nautical Miles to Kotzebue 276 55 @.20 @.35 Nautical Miles to Nome 403 309 0.77 1.35 3.3.3.1 Energy Value Current data indicates a energy value of 12,000 Btu/lb for the Deadfall Syncline coal (Arctic Slope Consulting Group, 1989) while the Chicago Creek coal has an energy value of 6,80@ Btu/lb (Division of Geological and Geophysical Surveys, 1986). The energy density of the Deadfall Syncline coal is approximately 1.76 times greater than the Chicago Creek coal source. This is an extremely significant variable since it indicates that 1.76 units of production and transportation costs must be incurred for the Chicago Creek coal to match one unit of energy (i.e., million Btu’s) from the Deadfall Syncline site. 3.3.3.2 Stripping Ratio Approximately 30 years of Chicago Creek coal is available at the stage 1 consumption rate (1.5 million tons estimated reserve) using a 1:1.7 Sa stripping ration. The Deadfall Syncline site has a stripping ratio of 2:65:1 (Phase III report). As a result the Chicago Creek site requires only 64% (1.7/2.65) as much overburden removal to expose a unit of coal as the Deadfall site. However, when the overburden removal is translated to energy equivalents Chicago Creek requires 13% more overburden removal per million Btu's (12,000/6,800* -64). 3.3.3.3 Distance to Tidewater The Chicago Creek site is approximately 10 miles from Willow Bay, the assumed port site. The Deadfall mine site lies about 5.4 miles from the proposed port site. The Chicago Creek haul distance is 185% of the Deadfall haul distance. Accounting for energy density the difference is 326% (1.76 * 1.85) more per million Btu’s. 3.3.3.4 Shipping Distance The Chicago Creek port site is approximately 55 nautical miles from Kotzebue and 309 miles from Nome. These distances are 20% (55/276 Kotzebue) and 77% (309/403 Nome) of the distances to these communities from the Deadfall site. In energy equivalents, shipping a million Btu’s from Chicago Creek to Kotzebue is approximately 35% of the cost from Deadfall Syncline to Kotzebue (.2 * 1.76 Kotzebue), but 136% of the shipping cost to Nome (.77 * 1.76 Nome). 3 - 12 3.3.4 Deadfall Syncline Mine The Deadfall Syncline Stage 1 mine assessment as presented in the 1988 WACDP Economic Update is the basis of this analysis. Table 3-5 presents the 28,050 mine costs. 3.3.5 Chicago Creek Mine The Chicago Creek site economic assessment uses the 1988 Deadfall Syncline Stage II data modified for the physical differences discussed above. The resulting changes are presented below. 3.3.5.1 Mine Size The energy equivalent of 28,050 tons of Deadfall Syncline coal is 49,50® tons of Chicago Creek coal due to differences in heating value. Table 3- 6 presents the cost for a 49,500 TPY mine. 3.3.5.2 Development Costs Reclamation costs were not adjusted for any site changes. It is assumed that the Chicago Creek Division Dam and associated ditch would have negligible impact on development costs. 3.3.5.3 Mine Operation Costs Equipment and labor operating costs were scaled to reflect the higher production rate and adjusted for the change in the overburden stripping ratio. 3) |) 23 TABLE 3-5 Deadfall Syocline Mine 28,050 Tpy Mine Cost INITIAL ANNUAL ANNUAL TOTAL CAPITAL CAPITAL OPERATING ANNUAL COST FACTORS: cost cost cost cost DEVELOPMENT COSTS: Initial Transportation 250,000 28,369 a 28,369 Environneatal Studies 110,000 12,482 @ 12,482 Development Drilling 200,000 22,695 4 22,695 Eogr. & Constroct. Mang. 795,200 59,031 a 59,031 Contingency 520,200 §9,031 a 59,031 Total Development: 1,875,400 212,815 4 212,815 RECLAMATION COSTS: Annual Reclamation 4 4 6,943 6,943 Final Reclamation 4 4 8,619 8,619 Reclamation Bond 4 @ 14,025 14,025 Total Reclamation Cost: 4 4 29,587 29,587 MINE OPERATION COSTS: Equipment Cost 2,033,000 323,788 191,222 515,010 Labor Cost (12 br days) 4 @ 461,548 461,548 Total Mine Operations: 2,033,006 323,788 652,770 976,558 INFRASTROCTORE COSTS: Bulk Fuel Storage 285,000 32,341 P/A 32,341 Stockpile & Loading 654,000 76,597 70,000 146,597 Road (10 Miles) 2,131,000 241,819 T/A 241,819 Airstrip 1,210,000 137,367 P/A 137,307 Caap Cost 530,000 60,143 186,533 246,675 Total Infrastructure: 4,816,408 $48,206 256,533 804,739 TOTAL PRODUCTION COSTS: 8,718,400 1,084,809 938,890 2,023,699 WOM PRODUCTION COSTS: Profit 93,889 Royalty 80,956 Insurance, Liability 12,000 Insurance, Equipueot 9,149 TAIBS, Local 163,034 TOTAL HON PRODUCTION: 419,027 WHOLESALE COSTS: 2,442,726 3- 14 TABLE 3 - 6 Chicago Creek Mine 49,500 Tpy Mine Cost INITIAL ANNUAL ANNUAL TOTAL CAPITAL CAPITAL OPERATING ANNUAL COST FACTORS: cost cost cost cost DEVELOPMENT COSTS; Initial Transportation 250,000 28,369 a 28,369 Eovironmenotal Studies 110,000 12,482 a 12,482 Development Drilling 300,000 34,043 4 34,043 Bogr. & Construct, Mang. 840,440 95,370 a 95,370 Contingency 532,226 60,395 q 60,395 Total Development: 2,032,666 230,660 4 230,660 RECLAMATION COSTS: Annual Reclamation 4 6 12,244 11,774 Final Reclamation 4 4 15,202 14,618 Reclamation Bond a @ 24,734 23,785 Total Reclamation Cost: 4 a 50,177 50,177 MINE OPERATION COSTS: Equipment Cost 2,033,000 323,788 252,929 648,082 Labor Cost (12 br days) 4 4 610,487 182,739 Total Mine Operations: 2,033,000 323,788 1,107,034 1,430,822 INFRASTRUCTURE COSTS: Bulk Fuel Storage 285,000 32,341 P/A 32,341 Stockpile & Loading 654,000 76,597 70,000 146,597 Road (1@ Miles) 2,131,000 241,819 P/A 241,819 Airstrip 1,210,000 137,307 P/A 137,307 Camp Cost 530,000 60,143 186,533 246,675 Total Infrastrocture: 7,029,296 197,661 388,341 1,186,002 TOTAL PRODUCTION COSTS: 11,094,963 1,352,110 1,545,551 2,897,661 NON PRODUCTION COSTS: Profit 154,555 Royalty 112,641 Insurance, Liability 72,000 Insurance, Bquipmeot 9,149 TAIBS, Local 107,476 TOTAL HON PRODUCTION: §24,174 WHOLESALE COSTS: 3,229,798 3-15 Stripping represents about 40% of the mine operating cost. The change in the stripping ratio from 2.65:1 (Deadfall) to 1.7:1 (Chicago) reduces stripping volume by about 33%. This translates into a 13% operating cost savings (.33 * .40). This 13% saving was reduced to 12% to compensate for differences in the calculating reclamation costs. 3.3.5.4 Infrastructure Costs The road cost was changed to reflect the longer distance (10 miles rather than 5.4). 3.3.5.5 Non Production Costs Non production costs were calculated the same for both the Deadfall and Chicago cases. Profit was held at 10% of total annual operating costs. The royalty formula is unchanged from the 1988 report. Liability was left as a fixed value of $72,000. Equipment insurance was left at 0.45% of the equipment capital cost. Local taxes were left at 1.87% of the total initial capital investment. 3.3.6 Economic Comparison Summary When expressed in terms of cost per ton of coal, the Chicago Creek site provides a lower cost because of economics of scale resulting from the higher production rates and lower stripping ratio. The cost per ton FOB dockside is $65.25 for Chicago Creek as compared to $87.@8 for the Deadfall Syncline. However, the cost per million Btu’s is higher for Chicago Creek due to the lower energy value and longer road haul distance. 3 - 16 Deadfall Syncline coal has a wholesale cost of $3.63 per million Btu’s FOB dockside. The same amount of energy costs $4.80 FOB dockside from the Chicago Creek site. Unless the basic assumptions regarding coal quality are changed Chicago Creek will remain a 32% more expensive energy source with the current mine plan. Table 3-7 compares the costs of Deadfall Syncline and Chicago Creek in costs per ton, million Btu’s, and Deadfall coal equivalent tons. TABLE 3 - 7 Coal Cost Comparison FOB Dock Cost Cost Per Deadfall Per Ton MM_ BTU Equivalents Deadfall fob dock $87.08 $ 3.63 100% Chicago Creek fob dock $65.25 $ 4.80 132% 3.4 Delivered Energy Costs 3.6.1 General The WACDP Phase II transportation model (ASCG 1986) was used to calculate the transportation costs from the Deadfall Syncline and Chicago Creek port sites. These costs do not necessarily represent a true transportation cost but do provide a relative comparison of the two cases studied. Sa) 17 3.4.2 Deadfall Delivered Costs The Deadfall transportation costs are presented in Table 3-8. TABLE 3-8 Transportation Cost Estimates Cost PerTon Cost perMMBtu’s Deadfall Chicago Deadfall Chicao North Slope Villages $16.00 $16.00 $0.67 $1.18 Kotzebue $24.00 $9.50 $1.00 $0.72 Nome $31.00 $20.00 $1.29 $1.47 3.4.3 Chicago Creek Delivered Costs The greater shipping distance to the North Slope Villages is offset by the greater coal volume yielding an equivalent delivery cost per ton for the Chicago coal when compared to the Deadfall coal. The Chicago Creek proximity to Kotzebue gives it a significant advantage over the Deadfall coal with a savings of about $15 per ton. The Nome delivery cost per ton is about $11 less for the Chicago Creek coal. 3.4.4 Deadfall Compared to Chicago The delivered cost estimate for both coals are presented in Table 3-9. The Chicago Creek shipping cost advantage does not survive in Kotzebue when viewed in energy equivalents. 3 - 18 TABLE 3-9 Delivered Coal Cost Estimates Cost PerTon Cost Per MMBtu’s Deadfall Chicago DeadfallChicago North Slope Villages $ 103.1 s3i..3 $4.30 $5.97 Kotzebue $ 111.1 $74.8 $4.63 $5.50 Nome $ 118.1 $85.3 $4.92 $6.27 Chicago Creek coal can only be used economically where little or no transportation is involved, whereas, Deadfall Syncline coal can be utilized more economically throughout the study region. This gives the Deadfall coal an advantage of having the potential of future penetrations in the market area that will increase the annual volume of coal, thereby reducing its price. 3.5 Coal Resource The Chicago Creek deposit consists of a single seam that averages 35 feet in thickness and dips about 45°. The potential mineable identified coal resource is estimated at 4.7 million short tons. About 1.5 million tons could be mined at a stripping ratio of 1.7:1. The remaining 3.2 million tons could be mined at 4:1 to 5:1. Based on the size of the resource, Chicago Creek could support a 235,000 ton per production level for twenty years. The Deadfall Syncline is one of a large number of broad synclinal structural basins which are characteristics of the northern foothills physiographic province of the North Slope. 3 - 19 Within the Deadfall Syncline, nine coal seams ranging in thickness from 4.5 to 18.0 feet were identified. Bedding dips ranged from 8 to 24 degrees. The identified coal resource of the Deadfall Syncline at a 5:1 stripping ratio is about 49 million tons. This would support a 2.4 million ton per year operation for 20 years. The Deadfall Syncline identified resource is approximately ten times that of Chicago Creek’s in terms of tons and twenty times that of Chicago Creek in terms of energy equivalent. Further the potential of finding significant additional coal reserves is higher at the Deadfall Syncline since it is part of the large Western Arctic Coal Fields. These factors along with Deadfall coal’s advantage in transportation lends itself better to the regional concept of the WACDP project. The WACDP established future penetrations in the market area would reduce the price of coal and, in turn, make the coal more marketable. 3.6 Coal Compared To Fuel Oil 3.6.1 Environmental Comparison Currently heat and power are provided, to both Kotzebue and Nome, from fuel oil. Typically, fuel oil has an energy content of 140,000 Btu/gal, a density of 7.7 lb/gal and contains about @.58% sulfur. When burning coal, the first concern is normally sulfur emissions. Comparing the combustion of fuel oil with coal, all sulfur contained in combusted fuel oil is emitted as SO). The so’ emitted for 1000 gallons of combusted arctic fuel oil per year is 89 lbs/year. 3 |= | 20 The energy content of the fuel oil is 140,000 Btu/gal and the energy content of the Deadfall Syncline coal is 12,000 Btu/lb. Thus, 11.67 pounds of coal has the same energy content as one gallon of arctic fuel oil. Burning 11,670 pounds of coal, the equivalent of 1000 gallons of oil, would release (12,273 x .0017 =) 21 pounds of sulfur. The high calcium content of the coal causes 25% of the sulfur to be captured in the ash, releasing only 16 pounds of sulfur to the atmosphere resulting in 32 pounds of so’. Thus switching from oil to Deadfall Syncline coal will cause a 60% reduction in sulfur emissions. Looking at the other emissions, Table 3-10 compares the emissions of a diesel engine, based upon compilation EPA emission factors, with a coal fired circulating fluidized bed (CFB) combustor. TABLE 3-10 Comparison of Emissions Between a Diesel and CFB Diesel CFB 1b/1000 gal/oil 1b/11670 1b/Coal NO,, lb 469 38-80 co, 1b 102.0 6.5-15.0 cO.,1b 22,000 29,200 Unburned Hydrocarbons, lb 577.0 3.5 Burning the Deadfall Syncline coal in a fluidized bed combustor reduces the nitrogen oxide (NO,) emissions up to 90%, reduces the carbon monoxide (CO) emissions up 3 - 21 to 93% and increases the carbon dioxide (CO,) emissions 30%. These emissions pertain only to the generation of electric power. The sources of heat available in Kotzebue and Nome are wood, oil and electric. Both communities are sufficiently far north that trees do not grow; therefore, the wood available for fuel is limited to the driftwood which washes ashore from the Bering Sea. Utilizing the waste heat from the CFB to provide heat to buildings in Nome through the district heating system will significantly reduce the amount of oil burned for heating. This oil that is not consumed for heating represents a further reduction in the amount of sulfur emitted to the atmosphere, the amount of carbon monoxide emitted and the amount of carbon dioxide generated. Overall carbon dioxide emissions will not improve significantly. With a reasonably sized district heating system, the elimination of carbon dioxide emissions for those buildings connected to the district heating system should offset the increased carbon dioxide emissions from the CFB. Thus, the emissions from the combined power generation and heat system represent a significant reduction in sulfur nitric oxide, carbon monoxide and unburned hydrocarbon emissions, as well as a possible slight reduction in carbon dioxide indicating that the switch from oil to coal will have a beneficial impact on the atmosphere emissions. 3.6.2 Economic Comparison Review of the Alaska Department of Revenue Petroleum Forecast for October 1988 indicates no significant change from the March 1988 Forecast used for the 1988 WACDP 3 - 22 economic update. The conclusions reached in the 1988 update are therefore considered valid at this time. This report determined that, at the low production level of 50,000 tons of fuel per year coal would be competitive with oil at a crude oil price of $15 per barrel. 3.7 Summary In comparing Chicago Creek and Deadfall Syncline coals the following factors make the Deadfall Syncline coal _ the preferred coal for supplying energy to the Northwest region of the state: 1) Reserves Chicago Creek 4.7 million short tons Deadfall Syncline 49.2 million short tons 23) Coal Characteristics Deadfall Syncline coal characteristics make it more economic to transport, less impact on land use, reduced environmental impact, lower capital cost for power plant and coal and ash handling facilities and with less chance of spontaneous combustion. 3) Economics Chicago Creek is a 32% more expensive energy source to produce and, in all cases investigated, the total delivered cost exceeds the cost of Deadfall Syncline coal on an energy equivalent basis. 3 - 23 4) Marketability. The low Btu and high moisture content of Chicago Creek coal makes its transport from the mine site economically unattractive. This factor along with the lower reserves makes future market penetrations highly improbable. On the other hand, the larger quantity and higher Btu content of Deadfall Syncline coal should make future penetrations in the region highly probable, which in turn, would reduce the cost of coal to its customers and make the coal even more marketable. Compared to oil DFS coal appears to be economic around the low production level of 50,00@ tons per year with crude oil ata price of $15 per barrel. Environmentally DFS coal burned in a coal fired fluidized bed combustor compared favorably to diesel in the areas of sulfur dioxide, nitric oxide, carbon monoxide, and unburned hydrocarbons. The coal burning unit was estimated to increase carbon dioxide over diesel. 3 - 24 4.0 TECHNOLOGY ASSESSMENT 4.1 Coal Combustion Analysis Battelle evaluated the Deadfall Syncline coal in a fluidized bed combustor and in a conventional suspension fired furnace (see Appendix B). The test results evaluated combustion performance, emissions, carbon burnout, sulfur capture, and ash behavior. A proximate, ultimate, and ash analysis of the coal is provided in Table 4-1. The significant characteristics are the low sulfur content, the low ash content, the relatively high calcium concentration in the ash and the ash fusion temperatures. A fluidized bed combustor was recommended primarily because of the ash characteristics. The initial deformation temperature of 2135" F caused concern that the ash would soften or melt in conventional stoker fired units. The ash composition, specifically the high concentration of CaO, MgO, and Fe,0, places the Deadfall Syncline coal among other coals that have low ash fusion temperatures and are known to cause slagging problems in some large stoker type boilers. Firing this coal in spreader stoker boilers may cause the formation of large ash clinkers on the grate. In such units, the ash remains on the grate for up to 30 minutes. This would provide an opportunity for ash particles to soften and fuse into clinkers which would interfere with the air flow through the grate and possibly impede removal of ash from the ash pit. Whereas the coal is suitable for pulverized coal firing, this application is too small for a pulverized coal system to be economically feasible. TABLE 4-1 Deadfall Syncline Coal Analysis _—_——— ——— ——————SSSSFSFSFSFSSSSs DeadfallSyncline 8 X 20 Mesh -2@ Mesh Proximate Analysis (dry) Volatile Matter, % 38.39 33.10 Fixed Carbon, % 58.93 63.40 Ash, % 2.68 3.38 Heating Value, Btu/lb 12,186 11,939 Ultimate Analysis (dry) Carbon, % 73.66 72.69 Hydrogen, % 4.25 4.08 Nitrogen, % 1.60 1.56 Sulfur, % @.20 @.19 Ash, % 2.68 3.38 Oxygen, % (by diff.) 17.61 18.10 Chlorine, % 0.04 @.04 Ash Analysis c10 29.14 26.11 Al 3, 25.39 21.88 Tid @.62 @.57 Fe 6, 7.79 10.10 Ca 12.74 16.24 MgO 6.53 8.74 K,0 @.77 @.61 Na,0 @.47 @.49 so 12.50 17587 P 1.24 aid std @.49 @.49 Bao 1.60 5 Wes | Mno @.00 @.00 Undetermined @.72 @.52 Ash Fusion Temperature Initial Deformation 2205/2310 2135/2160 Softening 2345/2400 2235/2290 Hemispherical 2510/2490 2355/2430 Fluid 2660/2585 2480/2580 The fluidized bed offers an advantage for in-site sulfur capture at this combustion temperature. While the Deadfall Syncline coal has a very low sulfur content (@.2 percent), sulfur emissions may be further reduced to comply with future New Source Emission Standards. The calcium content of the coal ash is equivalent to a calcium to sulfur mole ratio of 2.4. This calcium is active and serves as a sulfur capture sorbent. Battelle’s fuel evaluation showed 50 percent sulfur capture and additional sorbent, such as limestone, can be added to further reduce sulfur dioxide, so, emissions if required. Current Alaska permitting regulations require sulfur dioxide concentrations of less than 500 ppm. Deadfall Syncline coal is well below this limit without special sulfur removal equipment or additions of limestone. A CFB combustor is recommended because of its demonstrated advantages for combustion efficiency, reduced emissions, and commercial availability in the size range. The CFBC has additional advantages over conventional FBCs for this application because of reduced erosion/corrosion of the heat transfer surface and the ability to control turbine inlet temperature independent of load. An external heat exchanger decouples the combustion and heat transfer operations so each can be optimized separately. The turbine inlet temperature can be controlled by adjusting the solids circulation rate between the external heat exchanger (EHE) and the combustor. The EHE environment is significantly better than conventional FBCs because: 1) The fluidized velocity is lower (1 ft/sec vs. 6 to 8 ft/sec); 2) The average bed temperature is lower; and 3) The bed is not chemically active so there are no coal hot spots nor reducing conditions. The heat transfer tubes are not subjected to alternating oxidizing and reducing conditions which cause corrosion even with expensive exotic alloys. A prior DOE study showed good performance of stainless steel 310 at comparable conditions and stainless steel 309 is expected to perform even better at the proposed conditions. The operating temperature of Fluidized Bed Combustors (FBCs) is normally held to 1600°F or less to ensure effective sulfur capture. This temperature limitation has favorable impacts on NO,, nitrogen oxide, emissions and ash behavior but tends to retard combustion. There is generally a compromise between high temperature for complete combustion and lower temperature for reduced emissions. The design temperature for this proposed air heater system is 1600°F for these reasons and to provide the temperature driving force necessary to efficiently achieve the 1450°F turbine inlet temperature. The CFB combustion temperature if 1600'F is sufficiently below the ash fusion temperature such that slagging and sintering do not occur. The resulting ash is a fine powder that is less abrasive than coal ash that has partially melted from conventional pulverized coal or stoker-fired combustion systems. FBC ash is hydroscopic and cementitous which contributes to its value as a constituent in cement. This characteristic also establishes certain handling criteria to avoid fugitive dust problems or plugging ash hoppers. The ash is classed as non-hazardous material and has value as a soil conditioner especially if lime is added to the coal for sulfur control. 4.2 Power Generation Technologies The selection of the power cycle was strongly influenced by local conditions involving the ambient environment, available services, and technical support. The two major power cycles considered were; a Rankine steam cycle using a high pressure CFB boiler to drive a steam turbine generator; and a Brayton cycle using a CFB combustor to provide high temperature air to an air turbine generator and hot water to a district heating system. The use of a steam powered Rankine cycle was rejected primarily on the basis of water consumption and lower efficiency in this small size range. Water losses associated with a typical steam generating plant will be on the order of 6-8% of the steam rate. The Kotzebue site, like most Northwest Alaska locations, has limited fresh water supply. Comparison of the Rankine cycle to the Brayton cycle indicates that the Brayton cycle is inherently more efficient, thus better able to convert the coal to usable energy. Other objections to the Rankine steam cycle included high installed cost due to the auxiliary equipment requirements, and the total dependence of the CFB boiler for plant operation. An alternate approach to the steam Rankine cycle is an externally fired Brayton cycle using a CFB combustor to supply the power to a generator. Compressed air from the gas turbine compressor is heated in an external heat exchanger associated with a coal. fired CFB combustor. The hot air is returned to be expanded through the turbine which drives a connected generator. This system configuration requires no steam or water and therefore is not subject to the water consumption inherent in the steam Rankine cycle. Much of the operating experience with the externally fired Brayton cycle systems has been concentrated in Europe where more than 20 plants have been installed in the last 4@ years. The application chosen for this study is considerably smaller than the European Units. In addition, the turbine inlet design temperature is 1450 instead of 1325°F and the configuration of the combustion section air heater differs from the European units. Maintenance cost of the externally fired air turbine is very low due to the lack of products of combustion which cause corrosion in the hot sections. Therefore, the air turbine can be expected to operate more than 590,000 hours between overhauls. In order to establish desired air turbine operating characteristics for the two rural sites, a performance model was generated which allowed basic design parameters to be determined. The results of this study were then utilized to identify candidate commercial turbine selections and their applicability to the final system design. The system schematic is shown in Figure 4-1. Assuming the air heater discharge temperature of 1450°F to be fixed by metallurgical considerations, the primary variables available to the system designer are compressor pressure ratio, recuperator effectiveness (if any) and quantity of distillate topping fuel consumed. During the system design, these variables will be analyzed a second time in conjunction with Figure 4 - 1 SUBSYSTEM DIAGRAM SUPPLY 250°) FLUIDIZED BED erties COMBUSTOR 160°) | | | | | DISTRICT HEAT CIRCULATOR @- MANIFOLD HEADER ELECTRIC POWER ¢4160V) energy prices, capital cost and district heat and electric duty cycles. A final selection will seek to minimize the owner’s life cycle cost. A preliminary scoping of the project has been carried out based on 1988 electric usage records for Nome. Approximately 24 million KW hrs were consumed; typical daily rates vary between 2170 KW (base load) and 3900 kW (peak). To date, the maximum recorded kW demand is over 5000 kW. Initially, power generated by the new project will be parallel with existing Diesel electric plant. As actual availability and performance data is obtained, the Diesel units will be phased out but retained for backup and/or peaking service. A second consideration impacting the analysis is the need for multiple modular units. Villages of different electric and thermal needs can employ more or less units. Furthermore, redundancy for thermal delivery is available; each CFB cumbustor can be designed to supply the town’s total need. Regarding the Nome application, a study of the town’s district heat needs showed that about 2 million gallons of oil was utilized by all heated buildings during 1984. Subsequent analyses based on typical heat loss factors and specific district heat routes within the town showed distillates equivalents of 1.1 and 1.8 million gallons, respectively, for "low cost” and "total implementation” installations. The low cost installation, which considered only large loads in close proximity to the power house, was estimated to be about 25% of the capital cost of the total town implementation. Consequently, the smaller project (viz., 1.1 million gallons of oil displaced), with capability for future expansion, was established as the project design basis. No data is available concerning either the hourly ratio of thermal to electric usage or the peak thermal sendout required. 4-8 Selection of Basic Gas Turbine Cycle Assumptions applied to the selected system configuration are as follows: 1) 2) 3) Multiple units must be on line and parallel during normal steady operating conditions. Two units, with a third in reserve, is the most probable arrangement. Achievement of the highest possible thermal efficiency, while meeting the heating requirement of the town, is desired. Some means to provide transient electric load following must be provided. The units are not connected to a “stiff" grid and must, therefore, follow the demand established by the _ town’s connected load while simultaneously maintaining frequency at 6@ Hz. Due to the size and mass of the CFB combustor, the response time of the combustor is on the order of 10 to 15 minutes, and is therefore not capable of meeting short duration transients. The method chosen to achieve transient control employs topping fuel to handle load increases and turbine bypass to accommodate load decreases. The use of topping fuel is extremely efficient and cost effective and, furthermore, provides a convenient, straightforward method to start the system from the “cold iron” condition. (The option of increasing the CFB combustor firing temperature is not available since TIT is limited by the alloy chosen for the air heater). Turbine bypass is inefficient and, hence, is undesirable for Prolonged operation. Over time, bypass flow is reset to zero by reducing the CFB combustor firing rate and turbine inlet temperature. Both simple cycle and recuperated gas turbines were evaluated. Figure 4-2 compares these two options; both cycle types are evaluated with and without topping combustion over a range of compressor pressure ratios. The gas path pressure loss has been included and the 1.18 loss pressure ratio comprises the air heater internal drop as well as piping, inlet air filter, and the district heat coils. Both systems provide about the same level of power per unit air flow; however, the efficiency of the regenerative cycle is significantly higher. The choice of cycle type also depends on district heat requirements. Figure 4-3 presents the ratio of thermal energy (extracted from the district heat coil at the turbine exhaust) to electric power generated as a function of compressor pressure ratio. Commercially available gas turbines in these sizes generally fall in the pressure ratio range of 4 to 10. Figure 4-3 shows that, where thermal loads dominate, the simple cycle configuration would be favored. Otherwise if the regenerative cycle byproduct heat can meet the community’s requirements this cycle would consume less fuel and, therefore, would be the proper selection. Based on an assumption of 3500 kW base load, the byproduct heat capability of the regenerative cycle is 21.5(10)* Btuvhr. This calculation assumes a compressor ratio of 6.5. The estimate further accounts for both additional heat recovered in reducing the bag house inlet temperature from 700° (at the combustion air preheater discharge) to 400°F and the 4)— 10 a | FILTER DISTRICT HOUSE. HEAT DH. ceramectecies PREHEATER[—====5 oe 4 EHE-3 = a r¢ —@ —~- | 1 AIR PREHEATER @ - MANIFOLD SUCTION joa HEADER HEAD CONTROL > ) ——* No ‘COMB, AIR |, | BLOWER (~} 1 MN Sy a \ rl | = ay SPARATIR BYPASS a HAKEUPT | oonee | EHE-2/! - eee | ’ |_| ‘ ! | COAL er | HOPPER | ee CIRC. PUMP 1 v BYPASS CONTROL en TRA COAL FEED 2 —_—&— / NS a * v STARTUP EXHAUST REGENERATHR O ae REGENERATOR DIVERTER 9 one ere a - CONTROL | x . CONTROL oa COMB. AIR L-~--— 4—--» ELECTRIC Fig. 4-13. Process Schematic L aa J POWER GAS TURBINE/GENERATOR 4-36 FIGURE 4-2 COMPARISON OF SIMPLE AND RECUPERATED GAS TURBINES site HE HE i FF ot + tal 44 He a i 4-11 Eee ieee fe ESSE . : Herne — eae Hl ce aapsteetsas a nett Faroe Hace EE CRECH Feet od ened tHe HH + a 1 HE StH 1 AEHGEEN ae M Pte EEE FS ect i H oa He CEH AN rH H Be Kt Hr ane or yeas Hi fe Hi ae Hana PEE —— rae th sett tte) ie Cree Hn ne He it ee fae EL =a% a3 3 aoa a Te NH — Hires E rt - st fe Ee A NEE EEE eee ae EOLA _ ts Se eer ihE : a HI diffs Ae eae : ) ae a Be a HN Seeteeiue ie an ir (ESE a i ae ao Fa aa ee Ee SE ee ee ee eT Tree TTR TEE SITU se errr TTT / assumption that 4000 kW of gross generation is needed to supply 3500 kW to the town (i.e., 500 kW of power house parasitic load). Correlation of the Nome district heat load as a function of ambient temperature showed that, for 93% of the year, district heat requirements were less than the 21.5(10)° Btu/hr available from the regenerated cycle; therefore, the clear choice is the more efficient cycle. Further analysis showed annual savings of $700,000 to $800,900 would be realized vis- a-vis the simple cycle at coal costs of $115/ton. Having established the basic cycle type, a sensitivity analysis was carried out to explore the impact of changes in such key assumptions as ambient temperature, turbine and compressor efficiencies and gas path pressure loss. These results are shown in Figures 4-4, 4-5 and 4-6. None of the variations are sufficiently large to change the selected approach. The lowest graphs on each figure also introduce a new variable, Qy/Q)- This parameter, applying only to the topping combustion case, is the ratio of topping fuel (Btu’s) to heat addition (Btu’s) in the CFB combustor air heater. At 300'F of topping heat addition (the case shown) the quantity of topping fuel is about 58% that added in the air heater; other topping ratios prorate temperature rise linearly. Although fuel (in this case, distillate) is more costly, it is consumed at a marginal thermal efficiency exceeding 60%. In addition, about 30% more byproduct heat is also generated; this could be beneficial if more detailed studies show that peak electrical loads are in phase with peak thermal loads. 4-13 ° oO oo q oo oda tt OO & Qa nw a a oan + a S gas 5 foe Ho o opOW oon + vw Za a” v ~ oO | a uy 4 doo. « Of UW OH HH ] eee wy i BH ow = — Ou ahs % u ef €o 2 90 8 + ° qd OOo Uv Oo “| oe) —eunwn 0 ow 4 ° rTP u an 4 ZB 4a Og | 1oe& 8 0 a 1% & - v oOo 1 @lilir2s o She, ° > 3 a ge my = a == ia D2 =f & : 40 4 3 ‘ — ; out ges one 3 pee eee 10 atrpetainas | -- ° So So 8 3 N ; Vo/ia pue dg ‘*duay, yoTU IgaAy/n . qi ” eee ao ae as sdd/dy ‘aomog otytoedg % ‘Aoustotyygy Teusoqy, Figure 4 - 4 Cycle Sensitivity to Ambient Temperature 4 - 14 Nominal Point ® NOTES ee 3 = ao oa Son e s Greed eames E ) o % —— ee 1 4 = 00 ed Ps mmaty Sasa S & a ae =p SESS ESS a @yro = Et 5 iS on eee epee HOR eS 3 oo Ww a ao 3 uo . * ow Saal Ha wow BH Pa 4 oo Oo 8 Oo Oo n° Oo nn Bo +n H OD N “a = gv YW N 'o 6 : | [wo 8 4 las ° oA oO, Ns “om S| a si = Q Q o OO & ma wn Q ° 4 © ei to v we we ‘-duey Je TUL iozeeq ATV TUM4/N4G Mx/T Vo/l@ pue y% ‘Aouototyya Tewsoyy Figure 4 - 5 Cycle Sensitivity to Gas Path Pressure Loss oo oo mw ~ aoa aoe own ~ 0 Nominal Point ° Ce) 0 eon Be a o ao og Bg o ° > on ou a ov a - UW How Hw H ue oo. 0 on wa a SoH 49 ¢ | 2 00 12 im —— 1450° TIT, No Topping Compressor Pr 8 NOTES Vo/I® pue % ‘Aouototyyg_ [euso9uy, sdd/dy ‘aamod otytoods ‘-duay ye TUL auan/nig ‘M/C aroeyeVey ITY Figure 4 Cycle Sensitivity to Turbine and Compressor Efficiencies 90/85 89/84 88/83 86/81 87/82 Turbine/Compressor Efficiencies, %/% /80 Ww 6 Hardware Options As stated earlier, selection of a specific gas turbine can not be made until a detailed engineering design is completed. More precise information is needed concerning the nature of both the thermal and electric loads to be serviced. Notwithstanding, certain conclusions can be made regarding potential turbine candidates. As shown previously, Figures 4-2 and 4-3 show the general range of compressor pressure ratios anticipated. The desire to utilize at least two units during base load operating conditions (for redundancy) establishes desired air flow rates in the 25 to 4@ lbs/sec rate range. For example, Figure 4-2 shows that at a pressure ratio of 7, the proposed regenerative cycle produces a specific power of 87 hp/lb/sec. Considering typical gear and generator efficiencies, 33 lbs/sec air flow will produce about 2000 kW gross power generation. Table 4-2 shows nine candidate gas turbines covering the ISO flow range 28 to 53 lbs/sec at pressure ratios 4 to 9. Operation at slightly lower speeds, mass flows and pressure ratios may also be considered to improve efficiency at the lower than rated TIT values. All engines are capable of additional distillate firing as indicated by the listed TIT ratings. 4-17 TABLE 4-2 Candidate Gas Turbines Air Compressor Flow Pressure Rate qt Manufacturer Ratio lbs/sec aR Allison 501-KM 9.3 34 1895 Solar Centaur H 9.4 39 1850 Avco Lycoming TF 4@ 8.4 28 1940 Kawasaki MIT-0O1l 8.2 34 1688 Kawasaki MIT-@3 9.2 42 1796 Kongsberg KG2 oo) 29 1517 Kongsberg KG5 6.5 47 1598 Ruston TB5000 6.8 47 1652 Nuovo Pignone 8.3 53 1730 MS 1002 The units shown in Table 4-2 were selected based on one or more of the following criteria: 1) Previous operation as a regenerative unit; 2) Externally mounted combustor (allows access to gas path); and 3) Specifically configured for air.heater operation. In addition to the reasons stated earlier and in order to maintain a competitive situation among potential suppliers, no selection has been made at this time. Some assessment of the state-of-the-art, however, can be made by examining one particular candidate engine, the Allison 5@1 KM. a7 =~ is The 5@1 KM is a new engine to be introduced by Allison in the early 1990's. The engine is a modification of the industrial 501 KB5 which derives from the 156/501 aircraft engine. Over 13000 5@1’s have been produced since introduction in 1954. The new 501 KM is a second generation of the 501 KG originally developed for an externally fired wood burning project. Figures 4-7, 4-8 and 4-9 show the 501 KB5, 5@1 KG and 501 KM engines respectively. The 501 KM is also being configured for a topping combustor system which mounts in the return air connection to the engine. 4.3 District Heating Utilizing the waste heat from the Brayton cycle increases the overall system efficiency. Most cogeneration systems use the waste heat to generate steam for power generation or industrial process use. What industries there are in Nome and Kotzebue do not have a need for process steam and the scarcity of water in this region makes steam systems very unattractive, but with an average of 14325 heating degree days, there is a large requirement for space heat. All buildings in Nome and Kotzebue utilize arctic grade diesel fuel which is similar to No. 1 fuel oil for heating needs. A district heating system would transfer the waste heat from the power system to the homes and buildings. Heat from the CFB combustor exhaust and air turbine exhaust are transferred to the district heating system by heat exchangers located in the exhaust streams. Hot water produced by the heat exchangers in the power plant will be circulated by pumps through heating loops under the streets to the buildings to be served. These loops will 4-19 y Split Outer Combustion Case. The design of the SOI-K engine incorporates a split outer Combustion case. This permits field exchange of any Of six Combustion liners with minimal expense and downume. 501-K Principal Features. The Allison 501-K gas turbine is available in both single shaft/cold end drive and two shafvhot end drive configurations. Both use a common high efficiency compressor design. With the two shaft engine, power turbines are custom designed by our OEM's to be compatible with different makes of pumps, compressors and marine drive units offered for use with 501-K series engines. Quad Entry Fuel Nozzle. Anew quad entry fuel nozzle allows gas oF liquid fuel operation with automatic switch over without the loss of water injection capabilities. Water injection into the combustion section has reduced NOX emissions by as much as 70%, while boosting horsepower by UP (0 8.5%. . .all without increasing Operating temperature. =? Low Emission II Liner. The SOI-K features the low emission i combustion liner originally developed by Allison for the Navy. it has been optimized to eliminate smoke and Provide a burner outlet profile conducive to long turbine life. A thermal barner Coating on the interior liner walls Provides for increased liner life and improved combustion efficiency. Control Options. Allison offers a variety of control systems for the 5OI-K series engine. Traditional hydromechanical, Continental Control Corporation electronic controls, or new Woodward Closed loop electronic conuols are available on most models. Blade and Vane Coating. The coating on first stage turbine blades and vanes is diffusion bonded aluminum (AEP). It's more ductile than previous Coatings. It also provides better bonding, better coverage and greater hot corrosion resistance. Extensive development testing in aircraft and industnal engines, and field experience in aucraft, industrial and marine applica- tions have proven the durability and feliability of AEP coatings. ALLISON FIGURE 4-7 501KB5 GAS TURBINE 4-20 ALLISON 501 KG AIR TURBINE Allison 501 KG Air Turbine Figure 4 - 8 4 - 21 a= a COAL-FUELED GAS TURBINE Figure 4 - 9 ALLISON 501 KM AIR TURBINE + 1 \ os Se ; ~ 1 : er on he SN 8S Oe NESINS Qs _— » PR we : WY peer Wipes eS ORL Sy. s wire sig 25) ROTEL i ee a nh if = aS law Si = mit ite Eee se gs meal "Ge - consist of two parallel insulated pipes, each of the same diameter. In one of these pipes will flow hot, pressurized water from the power plant, and in the second pipe the cooler water will flow back to the power plant. At each building along the way, there will be connections to both the supply and return pipes. The hot water will flow from the higher pressured hot pipe through a heat exchanger in the building back to the lower pressure return pipe. In its journey through the heat exchanger, heat will be extracted from the water. The district heating system heat exchanger will be connected to the building hot water heating system, which will remain connected to the existing boiler. Upon demand from the thermostat, the circulation pump will start allowing heat to be extracted from the district heating system and transferred to the building hot water supply which will be conveyed throughout the building to the baseboard or other heating units. Illustrations of typical building connections are shown in Figures 4-10 and 4-11. The pipe selected for the district heating system is i.c. Moller pipe. The inner pipe is made up of electric resistance welded (ERW) steel pipe with a yield point near 33,000 psi. The outside of this pipe is a high density, polyurethane foam to provide insulation. The foam is generally about 1-1/2 to 2 inches thick, weighs 5 to 6.2 pounds per cubic foot, has a compressive strength near 71 to 85 psi and has a heat conductance, k, of @.05 Btu/ft-hr-'F. The piping system will be equipped with two tin plated copper wires which will serve as an alarm if water leaks from the carrier pipe or through the jacket. These alarm wires are monitored by a device which can be connected to as many as four individual pipe loops. The detection devices also aids in locating the position of a leak which can reduce expensive excavation and assures the pipe is repaired rapidly. 4 - 23 NEW DOMESTIC HEAT EXCHANGER ALTERNATE NO.2 NEW (Second) PLATE HEAT EXCHANGER ip 4 - 10 F s TYPICAL USER HOOK-U FOR DOMESTIC HOT WATER DISTRICT HEATING SYSTE BOILER LEGEND @ BURNER ey) d @ PLATE HEAT EXCHANGER @CcIiRCULATOR e @ISOLATING VALVE (7) va aaa © BALANCING VALVE pf ates Eee @ strainen (D) DISTRICT HEATING SUPPLY AND RETURN @ HEAT METER HEATING SUPPLY TO USER © DRAIN VALVE (8) BYPASS W) DOMESTIC WATER CONNECTIONS (800 DH-2 ALT.#1) TYPICAL USER HOOK-UP FOR HEATING Figure 4 - 11 The steps to assemble two sections of pipe are: the steel carrier pipe is welded together, an outside jacket is bolted on which covers the space between the two outer jackets; then the space between the jacket and the pipe, which has been air tested for integrity, is filled with foam. The pipe is subjected to high operational stresses due to temperature variations between 25°F and 250°F. Compensation for the large differential temperature conditions is handled by bringing the pipe to a neutral stress level at a position about one half way between the two temperature extremes. Heat exchangers for the system will be plate type and manufactured from stainless steel. All the heating systems in the Nome buildings are assumed to be hydronic, i.e., hot water baseboard. A single plate exchanger will be used to heat the water circulated through the baseboards to a temperature of 190°F or above and return it at a temperature of 17°F. A second heat exchanger is included for domestic hot water. This heat exchanger is a double wall type to prevent contamination by the district heating fluid of the domestic water supply. All of the systems are to be equipped with valves, temperature indicating devices and an electrical Btu meter. To obtain meter readings without entering the utility room, wires can be run to a jack external of the structure, or the Btu meters can be connected to a computer for remote reading. The temperature of the working fluid in the main district heating distribution piping is predicated on the maximum operational temperature and pressures of the piping systems and the minimum temperatures used in the typical heating system in the communities. The minimum temperature was 4 - 26 assumed to be 170°, and the maximum temperature was set at 240°F for calculating fluid flows and pipe capacity. The actual temperatures at some points on the system could be as high as 250% and as low as 160°F. Operating temperatures can be increased in some cases to as much as 260°F with some loss in the life of the pipe insulation. With operating temperatures above the boiling point, water pressure in the system must at all times remain in excess of 16 psi, otherwise the water will flash to steam. Where line lengths are long and pumping losses high, heavier strength pipe will be the used. Temperature of the soil used for determination of the heat losses in the pipe was based on 29.5F in Nome. District heating system heat losses are almost exclusively from the pipes, which are usually underground but may be in the air. Ground placement is preferred due to the constant ground temperature when compared to the subzero air temperatures found in the winter. The heat losses for the i.c. Moller “Plus” pipe ranges from values of 20 Btu’s per foot for 1 inch diameter to 47 Btu’s per foot for 12 inch diameter pipe under a differential temperature of approximately 200°F. The heat losses for district heating systems vary as a function of the pipe diameter, the pipe length and the differential temperature. To put the losses in perspective, the heat losses for various loops is shown in Table 4-3; not included in this table are the losses for the individual services. The heat losses are based on an average operating temperature of 205'F and are presented in gallons of oil equivalent which is assumed to yield 96,000 Btu’s/gal. To convert these values to Btu's, the losses in gallons can be multiplied by 96,000. For 4 - 27 TABLE 4-3 Nome Pumping Costs And Heat Losses Nome Pumping Cost Loop Oil Used Q,CFS Pipe Head Loss KW w/houses Gallons sum Length Feet Main * @ 3.444 3,200 44.1 30.86 N. Airport 66 @.127 2,800 40.1 1.03 S. Airport 55 @.106 1,400 25.8 @.55 Airport Tie 31 @.293 900 20.7 Les Belmont Pt. 47 @.090 600 17.6 @.32 West 4th 116 @.223 1,050 22.2 1.01 Front St 289 @.556 3.100 43,2 4.87 3rd Ave Tie 83 26.204: 1,050 2262 10.28 lst Ave Loop 167 @.321 1,590 21.0 1.81 3rd Ave Loop 252 @.485 3,170 43.8 4.32 Division Tie 54 1.315 400 15.6 4.16 4th Ave Loop 206 @.397 3,380 46.0 3.70 5th Ave Loop 423 @.814 3,250 44.7 7.38 TOTAL 1,789 Water 130 @.250 1,500 26.8 1.36 Loop Oil Used Q,CFS Pipe Head Loss KW w/houses Gallons sum Length Feet Main * e 1.744 2,800 40.1 14.18 S. Airport 86 @.166 630 17.9 0.60 Belmont Pt. 23 @.044 150 13.0 @.12 West 4th 77 @.148 1.000 2La7 @.65 Front St 111 @.214 2.530 37.3 1.62 3rd Ave Tie 65 1.17.2 1,050 2202 5.29 lst Ave Loop 124 @.239 1.550 27.3 io2 Division Tie 162 @.809 650 18.1 2.98 5th Ave Loop 258 @.497 2,650 38.5 3.88 TOTAL 906 Water 130 @.250 1,500 26.8 La36 4-— (28 example, the total loss in Nome is 159,840 gallons x 96,000/1,000,000 - 15,345 MMBtu/yr. If the cost to produce a million Btu’s with coal is assumed to be $5.00, the cost of the fuel to replace the pipeline losses would total $76,723 per year. Heat losses can be reduced by decreasing the temperature of the media. A decrease in fluid temperature is possible provided the demand for heat is reduced. If the demand is not reduced, the quantity (hence the velocity) of the fluid has to be increased as the temperature is decreased. Doubling the fluid velocity can halve the differential temperature; as an example, it can alter it from 7@ to 35", In this event, the average pipe temperature can drop 17.5". This represents a change in percentage of about 17.5/175 or 10% reduction in heat losses. To accomplish this requires an increase in the pumping power of 8 times. Temperatures that the fluid operates under can be decreased during periods when demands are reduced such as in the spring, summer and fall. As a practical matter, the minimum temperature of the supply piping would average near 195"F and the return piping near 175% for an average temperature of 185°F during the lower demand periods. This would reduce the pipe losses shown in Table 4-3 which are calculated based on a supply temperature of 205%. The scale of possible pumping power reduction is about 7%. A computer will be installed to operate the district heating system, calculate desired operating temperatures, pumping costs for the systen, and translate this information into output temperatures and fluid flow rates. This will result in the lowest cost operation for the selected system. i = 29 Different media can be used to transfer the heat in a district heating system. The traditional media is water with some form of inhibitor to prevent pipe corrosion. In Alaska, the systems have used a mixture of ethylene and propylene glycol and water to prevent damage to the system if it is shut down and freezing occurs. The problem with using a water-glycol mixture is it reduces the ability of the fluid to carry heat, which increases pumping and heat exchanger costs. In addition, the glycol has a higher viscosity than water requiring greater pumping pressures and causing higher energy losses. The glycol is expensive and should there be a leak, the system must be shut down and the leak found to prevent fluid loss. In Alaska with permafrost ground conditions, the spilled glycol will cause melting and settlement of the affected area. With a buried pipeline, the ground around the pipe is heated well above the freezing temperature even during winter. In fact, the temperature at three foot depths without heating of any kind is about 25'P minimum temperature during the latter part of the winter. This means that a district heating pipe that is buried can be shut down for a very long period before there is any danger of freezing. In Nome, a section of line will be elevated to cross the Snake River. For this section, freezing at very low temperatures with wind could be in hours. To protect this section, valves would be installed to drain the line in the event of loss of heat or a pump failure. The other critical locations are the pipes where they pass from the ground through open air into the buildings. These pipes are less at risk than those of standard water systems as the fluid they carry is hot. The system would be designed and operated so that there was always 4- 30 a small flow through the two service pipes and the heat exchanger so that the lines would not freeze. Another class of failure is a large leak which require the pipeline being shut down, repaired, and put back into service before a low section that has retained water freezes. Generally, for small systems without full time experienced operators, it would not be good judgement to operate a district heating system without some form of freeze protection. Because the district heating system will be supervised by operators who are available and knowledgeable, the use of glycol is neither cost effective or necessary. For this proposal, water was assumed to be the media. Nome heats its water to prevent problems with freezing services and uses about 130,000 gallons of oil equivalent waste heat from the diesel engines to do so. Water is brought from Moonlight Springs through the diesel power plant on the Snake River where it is heated by heat exchangers. Heat can be supplied by the district heating system in place of heat recovery from the diesels to economically heat the community water supply. Kotzebue does not heat their water supply and has occasional problems with freezing water supply pipes. Kotzebue water supply comes from Vortac Lake. Water is pumped from the lake to the treatment plant throughout the year and is stored in the 1.5 million gallon storage tank. Heating the domestic water supply has considerable advantages as it prevents the water system from freezing and reduces the cost to the residents who have to heat the water to higher temperatures before use. Because the district heating system has no losses, the savings in energy compared to inefficient hot water heaters are substantial. As stated previously, Nome and Kotzebue are located in permafrost regions. The permafrost is relatively warm when compared to ambient temperatures of -30'F and -40"F with the arctic winds blowing in off the frozen sea. There are some unfrozen zones in Nome near the coast at Front Street. The general soil conditions for Nome are considered to be mostly frozen ice rich materials. This assumption is based on trenches excavated for the sewer and water system and exploratory drilling for public works. As most of the feasible routes for the pipe lie within the roadway, it is assumed that all of the pipes are placed in an insulated trench. This trench, shown in Figure 4-12, will retard the flow of heat into the subgrade and reduce thaw settlement. During the design effort, insulation thicknesses will be optimized and different configurations explored that may result in lower installation costs. Because the pipes are laid in the unpaved gravel streets in Nome, the backfill for the surface will be classified material which is assumed to be from borrow sources. Construction of this district heating system will utilize the type of piping systems designed and operated in Europe. Ditch excavation in Nome will be to shallow depths, four feet or so, with installation and digging occurring during the summer when the ground is thawed. The problem of significance will be the avoidance of other underground utilities such as water piping and sewer lines. Fortunately, Nome does not have buried electrical services. 4 - 32 NOME ea cael eias hd ° Si basis ee etter ae a te Ry ast ene es eae | sabi Ai Me eecseeg seelg 2" POLYETHYLENE INSULATION STEEL CARRIER PIPE HIGH DENSITY URETHANE 3° INSULATION WITH POLYETHYLENE JACKET Fig 4-12 Typical Installation of District Heating Pipe TYPICAL IFESTALLATION CAT 4” DIAMETER DISTRICT HEATING PIPE System Configuration 4.4.1 General In order to convert from oil to coal in Kotzebue and Nome, the following system is proposed. Coal will be burned in a CFB combustor. Heat from the CFB combustor will be used as the motive heat source for an externally fired Brayton cycle. Compressed air from the air turbine compressor will flow via a regenerator to the external heat exchanger in the fluidized bed where it is heated to the desired turbine inlet temperature of 1450°F. The heated air is returned to the air turbine where it is expanded through the turbine section. A generator connected to the air turbine converts the power generated in the turbine section to electrical power for distribution to the community. The exhaust heat from the CFB combustor and the air turbine exhaust as well as a fluidized bed in the CFB combustor are utilized as the heat source in a district heating system designed to supply heat to the communities. This system is depicted in Figure 4-1. The proposed power plant consists of three main subsystems: 1) A coal fired fluidized bed combustor; 2) An externally fired air turbine.generator; and 3) A pressurized hot water district heating system. 4 - 34 Figure 4-1 illustrates the relationship between these subsystems, and the interconnecting process piping. The primary fuel will be coal burned in a circulating fluidized bed combustor to produce high temperature air to power the air turbine, and hot water for the district heating needs of Nome. A small additional quantity of liquid distillate fuel will be burned in a topping combustor to provide for transient load control. Delivered outputs from the system will be 4162 volt electric power for distribution to the electric utility systen, and 250°F hot water for use in the district heating system. Capacity of the power plant in terms of electric power and thermal delivery to the district heating system will be determined by the number and size of the CFB’s, and the air turbine generators installed. 4.4.2 Circulating Fluidized Bed Heater The CFB combustor is proposed to be designed and built in modular sections for ease of transportation and site erection. The major sections, shown in Figure 4-13, consist of: 1) Coal fuel feed delivery system; 2) Combustion air blower and preheater; 3) Combustion chamber; 4) Gas and particulate separator; 4- 35 5) External heat exchangers, EHE-1 and EHE-2; 6) Stack filter and induced draft fan; and 7) # =%Start-up preheater. The coal feed delivery system meters the coal into the mixed bed of the combustor in response to the combustion gas temperature control system which maintains the hot gas temperature at 1600°F. As the coal delivery rate changes, a fixed ratio signal is sent to the combustion air flow controller. A second signal from an a, sensor in the exhaust duct is used to bias the fuel to air ratio signal and maintain a preset oxygen level inthe exhaust. Burning of the coal and air occurs in the combustion chamber. The hot gases together with the circulating particulates pass out the top and into the cyclone separator where the solids drop down into the two external heat exchangers, EHE-1l and EHE-2, and the hot gases pass out the top to the combustion air preheater. The gases resulting from the introduction of fluidizing air in the external heat exchangers are returned as secondary air to the combustor through connecting vent lines. The circulating particulates collected in the external heat exchanger are returned to the mixed bed in the combustor chamber through a flow control "L valve" located in the elbow of the return piping. Ash removed is discharged from the bottom of the combustion chamber to an ash removal system. Ce it The gas and particulate separator is a high efficiency cyclone design that vents the relatively clean gas out the top to the combustion air preheater, and discharges the recirculating particulates through a dip leg to the external heat exchangers below. The external heat exchangers contain the heat transfer sections for the high pressure (80-120 psig) air turbine heat addition EHE-1. and the district heat hot water supply system, EHE-2. Each of the external heat exchangers is equipped with air distributor piping located in the bottom of the units to provide fluidizing air and enhance the convective heat transfer between the circulating hot bed material and the process flow in the heater sections. The circulation rate of the fine bed material and hence the heat transfer rate is controlled by the "L valve" located in the discharge return line to the coal combustor. A stack gas filter equipped with an induced draft fan is located after the combustion air preheater to collect the residual particulates in the stack exhaust, and provide the necessary draft to insure proper flow through the systen. The stack filter is a bag house design with bypass damper valves for use during initial start up to prevent condensation from damaging the filter media. The start up preheater is a distillate fired burner used to heat the combustion air and bring the combustor up to operating temperature under controlled conditions. The preheater is shutdown once the minimum operating temperature has been reached. 4=- 3 4.4.3 Air Turbine The primary energy source for the air turbine-generator is derived from the external heat exchanger in the CFB combustor. High pressure air produced by the air turbine compressor is first preheated in a regenerative exhaust gas exchanger, and then sent to the external heat exchanger, EHE-1, where its temperature is further increased to 1450°F. This high temperature pressurized air then flows through an external topping combustor where the temperature can be increased as necessary up to 1750°F before entering the turbine. The increase in turbine inlet temperature is accomplished by burning a small quantity of distillate fuel. The use of this supplemental distillate fuel significantly increases the operating efficiency of the turbine and at the same time provides a means to accommodate transient load variations. The mechanical output of the air turbine is connected to a synchronous generator through a reduction gear. The generator produces 4160 volt, 3 phase, 60 Hz electric power that is connected into the utility distribution bus through a power circuit breaker. An automatic voltage regulator together with the necessary protective relays and metering equipment will be mounted in a suitable panel in close proximity to the generator. 4.4.4 District Heating System The distribution system for the district heat is made up of two parallel insulated piping runs; a high temperature (250°F ) supply line, anda low temperature 4 - 39 (160°F) return line. In order to insure under all conditions that the water in the circuit does not flash into steam, Tt is necessary to maintain a controlled elevated pressure on the return flow. This pressure control is provided by a nitrogen capped head tank connected into the suction line of the main circulating. pump(s). The nitrogen gas pressure applied at the top of the head tank will be regulated to maintain the suction pressure to the pumps approximately 25 psi above the saturation pressure of the delivered hot water at the lowest pressure point in the connected system. The main circulating pump will be sized to deliver the required flow and pressure necessary to match the system needs. Due to the critical service requirement for maintaining flow in the district heat circuit, back up pumps will be installed to permit periodic shut down for maintenance and service problems. System make up water will be introduced on the suction side of the main circulating pumps either directly from the domestic water service (if the pressure is sufficient), or with a small make up pump. Return flow from the district heating system will be circulated through an exchanger, EHE-3, in the fluidized bed exhaust duct to cool the exhaust gases to approximately 40°F before entering the filter house. During periods when the district heating load is very low or not required, a bypass cooler will be used to reject the heat from the exhaust gas and maintain the required inlet temperature to the filter house. The preheated water from the exhaust duct heater, EHE-3, will be delivered to the main circulating pumps where the 4- 40 necessary system heat will be supplied. Discharge from the main circulating pumps will next be heated by the gas turbine exhaust gases after the regenerator, and then by the external heat exchanger, EHE-2, in the CFB combustor. The temperature of the delivered flow to the district heating system will normally be controlled by the recirculating rate in the external heat exchanger. This rate will be regulated by the flow control "L-valve” on the return leg of EHE-2 back to the combustor. During off design conditions, typical of warmer weather, the heat input to the district heating circuit can be turned down to essentially zero. EHE-2 on the CFB can be shut down and isolated once the EHE-2 bed has cooled. The heat normally supplied by the air turbine exhaust gases to the water loop can be bypassed through an exhaust diverter valve located after the regenerator exchanger. Excess heat may be utilized to provide inlet air heating for the air turbine when the ambient temperature falls below zero as this has been shown to increase the Brayton cycle performance. During the winter heating season, it will be necessary to keep the district heating system in operation to avoid freeze problems. Brief shut downs not exceeding 1-2 hours for emergency repairs or maintenance can be accommodated due to the average temperature of the water (205°F) and the thermal insulation provided around the piping. The following plant start up description assumes the entire plant has been shut down and is now ready for a restart. a = af 4.5 System Operation 4.5.1 Figure General 4-14 illustrates the key components and control points throughout the system involved in the plant start up and operation. Initially the following conditions and services are assumed to exist: 1) 2) 3) 480V electric power is available to operate auxiliary equipment; Compressed air is available for use with process control valves and actuators; and Distillate fuel oil is available for use in starting the air turbines and operating the start up preheaters on the fluidized bed combustors. 4 - 42 cae. NPUT OUTPUTS & DISPLAYS DISCRETE COMMANDS (START/STOP) ——p» CURRENT DATA HISTORIC DATA COMPUTER TREND ANALYSIS H——» SYSTEM ALARMS SET POINTS & PARAMETER CHANGES +——® SUMMARY REPORTS (DATA HIGHWAY) CONTROL NETWORK PLANT FLOOR The district heat main circulator pump(s) are turned on and the heating water circulated throughout the system. Water inventory is adjusted based on the average system temperature and the liquid level in the head tank. Pump suction pressure is adjusted by regulating the nitrogen gas pressure applied to the top of the pump suction head tank. Next, the air turbine is started on distillate fuel in order to provide a flow of air through the EHE-1 air heater, and to supply some heat to the circulating hot water circuit. An electric hydraulic starter system is used to bring the air turbine up to approximately 20% rated speed at which time fuel is introduced to the combustor and the ignitor energized. The air turbine continues to accelerate on the combination of the hydraulic starter and the power provided by the hot gases. At approximately 65% of rated speed, the starter disengages and shuts down while the turbine continues to accelerate to rated speed on the governor. Once the turbine-generator has reached rated speed, the generator is energized and the voltage adjusted to match the line side bus voltage. The generator frequency is next matched with the line side frequency and when the phase of the two voltages are synchronized, the generator breaker is closed. The load on the generator is increased to approximately 20% of rated load and Maintained at this level while the CFB combustor is started. Prior to starting the CFB combustor from a cold condition, it is necessary to bypass the exhaust flow around the bag house in order to prevent condensation on 4, —7144 the filter media. Isolation dampers are closed on the inlet and outlet of the filter, while a bypass damper around the filter house is opened. In preparation for starting the CFB combustor. the "L valves" on the external heat exchanger return lines are set at their minimum position, the induced draft fan on the exhaust stack is turned on, and the combustion airblower is started. A portion of the combustion air flow (10%) is used to provide the fluidizing air in the external heat exchangers. Warm up of the CFB combustor is accomplished with a distillate fired preheater in the combustion air inlet. The firing rate of the preheater is controlled to produce a temperature rise of 200°F/hour within the combustion chamber. It is important not to exceed this rate of temperature rise in order to prevent damage to the ceramic liner of the combustion chamber. When the flue gas temperature ahead of the bag house exceeds approximately 250°r, the isolation dampers are opened and the by-pass damper closed. This places the bag house in service and insures that any moisture in the flue gas will not condense on the filter media. The temperature within the combustion chamber continues to increase by means of the preheater until it reaches 1200°F. At this Point, the coal feed is started and the dense bed level in the combustion chamber is built to the design value. As the temperature in the CFB combustor rises above 1200'F, the oil fired preheater is shut down. The temperature is allowed to continue to increase up to the design value of 1600%F where it is controlled by means of the coal feed rate. 4- 45 The external heat exchangers are put into service after the preheater is shut down by opening the "L valves” on the circulation return lines to the combustion chamber. This increases the circulation rate of the fine bed material, which in turn, increases the heat transfer to the process fluid flows in each exchanger. Once the CFB combustor has been brought up to rated power, the air turbine distillate fuel flow will automatically be cut back as a result of governor control action. The external air heat exchanger temperature control is now adjusted so that approximately 15-20% of the air turbine load is provided by distillate fuel. This allows the topping combustor fuel control system to respond to sudden load variation while maintaining the generator frequency at 60 Hz. In the event of a sudden drop in electrical load on the air turbine-generator (less than 20%), the fuel control will shut off the flow of distillate fuel. At the same time, high pressure air will be by-passed to the turbine exhaust. The bypass system will be designed so as not to overtemperature the air heater during transients. As soon as the turbine-generator speed has recovered, the compressor discharge bypass valve will close and speed/load control will be maintained by the combined operation of the combustion air bypass and the distillate fuel control. 4- 46 4.5.2 Plant Control Systena The design objectives for the plant control system are: 1) Safety; 2) On line availability; and 3) Economical Operation. The safety of both operating personnel and equipment is a primary design consideration. Adequate sensors and instrumentation will be provided to monitor and detect operating conditions that indicate a malfunction or potential problem. Once a problem has been detected suitable alarms will be produced to alert the plant operating personnel of the condition. If the detected problem requires immediate action, an automatic control response will be initiated to shut down or isolate the malfunctioning equipment. All critical measurements such as turbine over speed, high vibration, and combustor over temperature will be made with multiple sensors to insure reliable readings. A failure analysis will be performed before the completion of the control system design to insure that each potential failure mode can be dealt with in multiple ways. In the event the primary protection circuit fails to detect or take action, a backup circuit independent of the primary will initiate the proper response. 4 - 47 In order for the proposed system to be successful in providing the electric and heating utility services, the power generating system must have a high operating availability. To achieve this goal, the plant should be designed with redundancy in all critical control loops. In the event of a failure or malfunction in a single component a backup device will be put into service to maintain normal operation. Each major subsystem such as the CFB combustor and the air turbine generator, will be capable of operating independently. This will permit greater flexibility in plant operation during off design conditions. In the event the CFB combustor is out of service due to unscheduled repairs, the air turbine generator can remain in service operating on distillate fuel. The district heating service can also be maintained at a reduced level receiving heat supplied by the air turbine exhaust. Ina similar manner, if the air turbine is out of service the district heating can be provided by the CFB combustor. Operation of the district heating and electric power generation systems will be continuously monitored by means of a data acquisition system and analyzed by a computerized optimization program. The most economical operating mode will be continuously determined and used to provide input settings for the control system. A distributed control system will be used to provide the necessary control functions for the entire power station. Each major subsystem will have a local control station equipped with a programmable logic controller (PLC) 4 - 48 capable of providing independent startup and operating control. The individual PLC’s at each subsystem will be interconnected by means of a data highway communications network that in turn is connected to a control computer in the main control room. Figure 4-14 illustrates the control network arrangement. During normal operation. the control of the individual subsystems will be provided by the local PLC based controllers. Operation of each subsystem will be monitored from the central control room computer by means of a data highway communications network. The data highway network will allow data to flow from each PLC control station back to the central control room as well as between the individual PLC’s. This data will be used to provide current status of the plant as well as past performance for evaluating trends in operations. In the event any system parameter being monitored exceeds a preset operating limit, an automatic alarm will appear on the control room monitor. A print out of each alarm will also be recorded in terms of time, date, parameter, and value. The data highway network is also used to transmit information from the central computer monitor to the individual PLC control stations. This information is either in the form of discrete commands such as start stop sequels, or set point and parameter changes that effect the operating points for the 2 local PLC stations. The normal station for the plant operator will be the central control room where he can monitor the performance of the entire plant, and make set point adjustments as 4- 49 necessary. In the event of a malfunction or failure to the central computer or data highway, the operator can maintain control from the local PLC control stations on the plant floor. These local stations will be equipped with the necessary displays and control devices to monitor the subsystem performance, and effect the necessary control changes. Power and Energy Projections 4.6.1 General The previous sections have discussed the air turbine, the coal combustion system, the district heating system, and the system controls and operation. The components combined together form a power generation system capable of meeting the power needs of Kotzebue and Nome as well as providing heat to a large portion of the community from the exhaust stream of the power system. A major difficulty in providing a power and heat system for a community such as Nome or Kotzebue is to determine how large a capacity is required. 4.6.2 Nome Historical Data Nome has three power generating plants. The main plant is located on the Snake River and has six units with an installed diesel generating capacity of 6933 kW. Remote units are located at Belmont Point, a diesel rated at 260@ kW and at Beltz School, a diesel rated at 600 kW. Total production for 1988 was 24,056,200 kWh with a peak demand of 4560 kW. This represents an increase of 5.37% over the 1987 demand. Figure 4-15 illustrates the rise 4- 50 TS (MILLLION KWH) GROSS GENERATION 26 24 ee 20 18 16 14 le RISE IN GROSS ELECTRICAL GENERATION NOME, ALASKA eee 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 Figure 4 - 15 in gross electrical generation in Nome, averaging more than 5% per year. Furthermore. the peak demand keeps growing as shown in Figure 4-16 with a peak of over 52000 kW reached in January of 1989. Figure 4-17 presents the average hourly weekday plant output. Table 4-4 presents historical power generation data from 1979 to 1988. The diesel engines required 1,720,733 gallons of fuel in 1988,for an average efficiency of 13.98 kWh/gal. The State of Alaska subsidizes the cost of electrical power through the Power Equalization Program. In 1988. Nome received more than $600,000 in power equalization payments thus reducing the cost of electricity to residents from 17.0 cents/kWh to 8.5 cents/kWh. TABLE 4-4 Historical Power Generation Data in Nome Year Peak Demand KW Total KWH 1979 3050 14,873,000 1980 3150 15,738.600 1981 3180 16,254,580 1982 3500 18,090.40 1983 3600 19,257,300 1984 3900 20,478,100 1985 4200 21,818,000 1986 3900 22,491.600 1987 4050 22,765,544 1988 4560 24,056,200 4 - 52 cS = 7 DEMAND KILOWATTS 4800 4400 4000 3600 3200 2800 2400 ANNUAL PEAK DEMANDS NOME, ALASKA 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 Figure 4 - 16 Rise in Nome's Peak Electrical Demand US cane, OUTPUT o - < zs < ° w 2 Figure 4 - 17 NOME AVERAGE HOURLY WEEKDAY PLANT OUTPUT In addition, the Gold Company’s power plant operates three 750kW gas turbines (oil-fired) and two 800/kW diesel generators to provide power for the mining operations. Due to the load characteristics of the dredging operation, which vary from normal to almost a dead short when the dredges start cutting at frozen ground, the Nome power utility has been reluctant to tie the two systems together. 4.6.3 Kotzebue Historical Data The Kotzebue Electric Association supplies power to the community. The source of this supply is self generation and consists of five diesel generators and one oil fired gas turbine. The total installed capacity is 7235 kw. Total production for 1988 was 16,250,715 kWh with a peak demand of 3005 kW. The diesel engines consumed 1,254,774 gallons of fuel, for an average efficiency of 12.95 kWh/gal. The cost of generating electricity is $.1001/kWh. In 1988 Kotzebue received $470,000 in power cost equalization payments. Historical data for the past nine years from the KEBEA Power Requirement Study (Morrison-Knudsen Engineers, Inc. - March 1989) are presented in Table 4-5. Although it is not unique in Alaska, the problem of not being connected to a grid system leaves the utility in an isolated position, especially during winter months. It must provide adequate contingency generation. This means providing backup generation in the event that problems develop with one or more of the largest engine generator sets. 4- 55 TABLE 4-5 Historical Power Generation Data In Kotzebue kWh Year Generated L.F. kW Peak 1979 10,453,600 -63 1900 1980 10,626,900 -58 2105 1981 11,530,600 61 2150 1982 12,249,300 -62 2240 1983 13,668,415 67 2338 1984 14,703,000 -63 2662 1985 15,999,200 69 2665 1986 16,101,400 -61 3005 1987 16,222,861 54 3455 Although some of the engine/generator problems that have occurred could have been and are being alleviated by stricter maintenance policies, the basic problems due to remoteness will continue. Numerous examples could be cited where the normal maintenance articles have proven difficult if not impossible for the Association to obtain in days or even weeks. Because of the complete lack of any other source of power, except consumer standby equipment, the Association considers the normal firm power definition of installed capacity minus the largest unit inadequate. The Association desires to maintain second contingency firm power capacity. This firm capacity, where the two largest units are down, is presently 3035 kW. All of the Kotzebue generating units are located in the central powerhouse. 4- 56 4.6.4 Future Power Requirements Another problem in designing power plant systems is predicting the future power and heating requirements. This report assumes the system will become operational in 1995, seven years from the latest available data. This report assumes the average rate of growth of power demand in Nome over the next seven years remains the same as that experienced over the past 10 years. Table 4-4 presents the total kilowatt-hours of electrical power generated and the peak demand required in Nome for the last ten years. The average annual increase for both values is 6.4%. Table 4- 6 presents the expected demand and total kWh for the next 1@ years assuming a 6.4% annual increase. According to the predictions in this Table, Nome’s electric power demands in 1995 will be a total of 37,100,000 kWh generated with a peak demand of 7040 kW. Consequently, these two electrical demand numbers have been selected as the system design point. The predicted growth of the total kWh generated from the Kotzebue Electric Association (KEA) Power Requirement Study (Morrison-Knudsen Engineers, Inc. - March 1989) are presented in Table 4-7. Although the total power generated and the peak demand increased by 55% and 88% respectively over the nine years, only a 33% growth in both the total power generated and the peak demand are forecast for the next nine years. Using the 1995 projections as the Kotzebue system design point, the total power to be generated will be 20,730,376 kWh with a peak demand of 4152 kW. @ | S7 TABLE 4-6 Expected Power Generation Growth Nome Year Peak Demand KW Gross Generation KWH 1989 4850 25,600,000 1990 5160 27,200,000 1991 5495 29,000,000 1992 5845 30,800,000 1993 6220 32,800,000 1994 6615 34,900,000 1995 7040 37,100,000 1996 7490 39,500,000 1997 7970 42,100,000 1998 8480 44,700,200 1999 9020 47,600,000 TABLE 4-7 Predicted Power Generation Growth In Kotzebue kWh Year Generated L.F. kW_ Peak 1988 16,400,000 o57 3285 1989 16.653,005 57 3335 1990 16.744,228 57 3353 1991 18,676,639 oi, 3740 1992 19,121,911 57 3830 1993 19,634,076 57 3932 1994 20.178,744 ou, 4041 1995 20,730.376 57 4152 1996 21.296.217 sod. 4265 1997 21,863,116 57 4379 4- 58 4.6.5 District Heating Requirements 4.6.5.1 General Heat for individual homes, Commercial and institutional facilities in Nome is provided by arctic grade diesel fuel which is similar to No. 1 fuel oil. The most recent data indicates that 2,082,000 gallons of heating oil (arctic grade diesel fuel) were consumed in 1984 at a price of $1.287 per gallon. Table 4-8 presents the 1/84, 1986 and 1988 space heating fuel oil consumption data for both the publicly owned and large commercial buildings in Nome. The total consumption for these buildings is approximately 750,000 gallons per year. In addition, 13@,@00 gallons/year of heating oil was required to heat the domestic water supply before a system was installed to recover heat from the water jacket coolers on the diesel engines. Definition of the heating demand is even less certain. The only information available is provided in Table 4-8, but the heating demand can be defined only in terms of gallons of heating oil burned per year. The system designer must know the maximum and minimum heating demand for the various seasons on an hourly basis. The only method available for converting the yearly oil consumption data into hourly heating demand is to base the demand upon degree days. This is believed to be a conservative approach since most of the load is assumed to be fixed and all varies with ambient temperature. a= §9 TABLE 4 - 8 None Space Heat Data a SSSSSSSSSSSGSGSGSGSe Bldg. No/Nane Mini Conv, Center 6 Visitors Info. 1@ Library 2 Nugget Ino 36 Polaris Hotel 14 Polar Conplex 9 Ak Coan. Store 29 Pld Fed, Bldg. 15 Post Office 16 Hat. Bank of Ak. 17 State Office Bldg. 21 City Hall 53 Bering Wative Corp 63 Horton Sound Hosp. 66 Rec Center 11 Police & Fire Dept 43 Coma. United Meth, 32 Community College 72 Elementary School _ Beltz Compler 73 26 Unit Apt Apartaents Residences 55 Bonanza Auto 75 D.0.%. Shop 74 Power Plant 1988 1986 1984 Gal/ Ft 2 Gal/Yr. Gal/Yr Gal/Yr. | Average |Pt 2 | 5,900 5,487 5,008 6,200 5,565 | 0.94 900 1,347 1,500 1,424 | 1.58 3,600 3,261 3,697 3,200 3,386 | 0.94 15,450 RUCK 29,723) | 92 || 15,400 12,215 12,215 | 0.79 14,806 26,489 26,489 | 1.79 || 86,688 45,455 45,455 | 0,52 23,050 30,619 30,619 | 1.33 25,875 | 38,000 38,000 | 1.47 5,700 4,838 4,838 | 0,85 16,667 | 14,150 15,083 12,500 13,911 | 0.83 13,400 12,006 11,342 16,300 11,214 | 0.84 10,000 | | 10,000 10,000 | 1,00 46,500 100,000 | 86,470 83,017 89,829 | 1.93 Gs009 28,000 13,250 12,506 16,000 13,919 | 0.50 L( 333 9,300 | 13,137 17,423 13,700 14,753 | 1.59 2420 7,800 8,700 8,700 | 1.12 |] 18,655 22,500 17,078 19,789 | 1.06 7 64,300 90,000 86,753 75,000 83,918 | 1.31 Zoe 156,224 159,935 | 188,500 174,218 | 1,12 17,732 33,750 33,750 | 1.96 44,940 34,718 34,718 | 6.77 19,728 14,002 14,002 | 6.71 7,200 13,375 13,375 | 1.86 9,750 | 15,700 15,700 | 1,61 — | Average 667,559 ( 749, 508) 1.12 1 [2,000,000 2,000,000 | N/A / a Nar ij i 489 - |? OS % / ( of ; f AT , fee > Ae 2 yt ( 7 + cu > 4-60 0 A Climate data from the National Oceanic and Atmospheric Administration is presented in Figures 4-18, 4-19, 4-20, 4-21, 4-22 and 4-23 representing the average measured temperatures for each community for each three hour period of 1984, 1986 and 1988. The years 1986 and 1988 were 2% and 4% warmer than normal while 1984 was 3% colder than normal. As a point of reference, the temperature in Kotzebue in February of 1984 was able to climb above o'F on only one occasion. That month the temperature ranged from 1"? to -42"F with an average temperature for the month of -21"F and an average wind speed of 9 mph (Peak wind velocity was 38 mph). To put the weather in Nome in perspective, in 1984 the ambient temperature was below -8'p ten percent of the time and above 50'F only ten percent of the time. Unfortunately, the degree day calculation does not take into account the arctic wind blowing in off the frozen ocean. Therefore, in order to determine what the heating demand loads on the Nome district heating system will be, data on the hourly heating demands will have to be obtained by monitoring the fuel usage of the individual buildings over a one year period. 4.6.5.2 Nome District Heating Options The heating demand is as much a function of the weather as it is a growth in square footage of buildings that require heat. Fortunately, current heating data on most of the larger buildings in Nome 4- 61 29 - ¥ a o+ 4 Lull -20 -! Figure 4 - 18 Ht 1984 Temperature Distribution in Nome £9 - ¥ NOME 1986 Hl yl I | I Ht (a oT TT TTT IT TE TTT Te TT nnn Figure 4 - 19 1986 Temperature Distribution in Nome eT nn Tt Ll Figure 20 1988 Temperature Distribution in None So = £ eh Laer Tt i TUT TTT KOTZEBUE 1984 N | Mata Ty Lue THU LTT LT EE Te TTT TAT TTL FT TT TTT a -40 -30 20 ° 10 20 Figure 4 - 21 1984 Temperature Distribution in Kotzebue © © a pas WwW 2 a Ww N - fe) x TL TAT ell 1986 Temperature Distribution in Kotzebue Figure 4 - 22 49 - % 100 90 80 70 60 50 40 30 20 10 PERCENT Ce elena oesivminabamtet bei ale een teeaeealemts a e ™ °o 1.0 | Figure 4 - 23 all ttl -20 -10 0 = 30 2 KOTZEBUE, ALASKA 1988 10 20 30 40 30 60 70 AMBIENT TEMPERATURE 1988 Temperature Distribution in Kotzebue is available, see Table 4-8. From this limited data, two district heating scenarios were developed. The first scenario provides heat to all buildings within Nome except for the Icy View and Beltz School area, both of which are located some distance north of town. The second scenario would provide heat only to structures with a floor area grater than 3000 square feet, still excluding the Icy View and Beltz School area. The first scenario, listed as Nome with houses presented in Table 4-9, and also in Figure 4-24, would be expected to displace 1,789,200 gallons of heating oil per year based upon the data available. The cost of installing this large district heating system has been estimated at $20.6 million. The second scenario, listed as Nome without houses in Table 4-10 and shown in Figure 4-25, would be expected to displace the combustion of 1,036,200 gallons of oil per year. The cost of installing this limited district heating system has been estimated at million. Thus for 24% of the installed cost, the second scenario will displace 58% of the total heating oil consumption. Since the limited district heating system will adequately demonstrate the concept and feasibility of district heating, the second scenario with the limited district heating system is recommended. In the future, additional structures in Nome can be added to the district heating system as desired. 4 - 68 TABLE 4-9 Heating Losses In District Heating System Nome With Houses Gallons Oil Gallons Oil Location Displaced/yr Lost/yr-Mains Percent Main Q 29,620 NA N. Airport Loop 66,200 15,200 23.0 Airport Tie 31,200 5,400 17. S. Airport Loop 55,000 7,500 14.0 Belmont Point 47,020 3,040 6.5 West 4th Ave 116,200 6,300 5.4 Front Street 289,000 18,200 653 3rd Ave Tie 83,000 8,500 10.0 lst Ave Loop 167,000 9,800 5.9 3rd Ave Loop 252,000 18,700 7.4 Division Tie 54,000 3,300 5.8 4th Ave Loop 226,000 19,300 9.4 Sth Ave Loop 423.000 15,200 3.6 Total 1,789,000 159,840 8.9 Based on Peak Losses 3.2 4- 69 me mak ml a 3 // “ © — PROPOSED PLANT LOCATION | ) BERING SEA rmrwao wn EY ARCTIC SLOPE CONSULTING GROUP NOME DISTRICT HEATING WITH HOUSING 22698008 | 1 BERING SEA PREPARED BY Jinch : 300 teet Q = 6s 1/ ARCTIC SLOPE CONSULTING GROUP NOME Scientists * Surveyors hearerepe, Aan 99810-1580 Nome Districting Heating Without Housing Teteonare (907) 40-9148 fax (907) 40-4213 as Figure 4 - TABLE 4-10 Heating Losses In District Heating System Nome Without Houses Gallons Oil Gallons Oil Location Displaced/yr Lost/yr-Mains Percent Main Q @ NA S Airport Loop 86,200 12,700 15.0 Belmont Point 23,000 800 3.5 W. 4th Ave Loop 77,000 5,100 6.6 Front Street 111,000 13,200 12.0 3rd Ave Tie 65,000 8,600 13.2 lst Ave Loop 124,000 8,900 ee Division Tie 162,000 5,300 3.3 5th Ave Loop 258,000 16,300 6.3 Water 0,902 1,702 i.3 Total 72,600 po 7.0 (40,0 as Wy Based on Peak Losses 2.5 0 50 7 4 50° ih sa : Wwe ry bo) Ao” 1 fgo “ a0 ge? ' qo 9 SO 4.6.5.3 Kotzebue District Heating System The district heating system proposed for Kotzebue will provide heat to the school complex, Hansen's store, the new Hospital, the airport, and the recreation center at an installed cost of $2,305,000 and would be expected to displace 672,50@ gallons of oil. In the future, the system can easily be expanded to the additional buildings listed in Table 4-11. The layout of the district heating system for Kotzebue is shown in Figure 4-26. 4 - 72 TABLE 4-11 Kotzebue Space Heating Data Building Served Eskimo Building Nui-Lukvick Hotel Hanson’s Store Public Works Water Building Community College Armory Rec. Center KIC Apt. (29) AC Store Hospital, New Kotz. Sr. Center City Hall Kotz. Fire Dept. Kotz. Police Kotz. Jail KIC Apt. (41) Museum, NANA School District Office (est) D.O.T. (est) Mark Air Terminal Civil Air Patrol (est) Alaska Airlines A.I.A. (est) School (Total) Elementary Middle High School 2 # ea. Borough Subtotal Water Heating Total 73 Gallons/Year 16,500 47,27@ 5,200 13,500 32,200 9,420 25,000 10,400 18,300 26,000 80,000 22,000 5,400 2,000 500 10,00 22,000 20,000 5,200 5,200 6,500 5,200 11,000 5,200 120,200 15,000 30,000 45,000 30,000 523,770 130,200 653,770 Peak Btu/Hr 474,000 1,360,000 144,000 388,000 925,000 270,000 720,00 299,000 526,000 747,000 2,300,000 632,000 155,000 57,000 14,000 287,000 632,000 575,000 150,000 150,00 187,000 150,000 316,000 150,000 3,450,000 430,000 860,000 1,290,200 860,900 15,048,200 2,800,000 17,848,000 LEGEND - pape size change/junction 6" ameter insulated pipe. — 5 ameter insulated pipe 4° dameter insuiated pipe - 3° ameter insulated pipe GO008 @ # 2.S* ameter insulaled pipe =A | eral KOTZEBUE DISTRICT HEATING Engineers * Scientists + Surveyors 6700 wetic Spur Rood Avcroroge, Aicaxa 99918-1550 Tetepnone: (907) 49-5148 Fax: (907) 349-4213 | 08 Fi gure 4 - 5.@ INSTALLATION DESIGN 5.1 General Installation of a power plant along the northern coast line of Alaska requires special considerations in terms of transporting equipment to the site, and providing specialized services during erection. Access to the coastal sites will be by water with limited harbor facilities for deep water vessels. In addition, shore side equipment to move and handle large components is limited. One option investigated for both transporting the power station to its final destination and providing a suitable site foundation was to build the power plant on an ocean-going barge. The complete power plant would be built on the barge, towed to the site, and anchored at the shoreline adjacent to the community being served. There are several problems with this concept. First, the coastal regions around northern Alaska are typically shallow and would not permit bringing a deep draft (approximately 20 feet) ocean going barge in close to shore. A second problem is the winter icing conditions. Special provisions would be necessary to prevent ice from crushing the hull of the barge during the severe winter months. Finally, a barge mounted power plant would not provide the necessary stability to operate the CFB combustor without a great deal of additional civil construction work in terms of pilings and moorings. The approach selected which best suits the siting conditions makes use of factory built modules that can be easily delivered to the site by shallow draft lighters. The module sizes will be designed for ease of transportation, on site handling capabilities, and minimum interface requirements. When possible, these modules will be completely factory assembled, wired, and functionally tested before shipping. This approach should result in a minimum amount of effort required during site erection and plant startup. A preliminary evaluation of the expected system performance indicates the waste heat from the power generation system will provide sufficient heat to the district heating system down to an ambient temperature of -6"F, A fluidized bed heat exchanger is provided to supply additional heat to the district heating system during the approximately 12% of the year when the temperature is below -6'P, This heat exchanger can be independently controlled to meet the peak heating demand loads. The annual coal consumption for 1995 to provide the electrical power and the district heating load is expected to be 57,000 tons. The usage of coal will be dependent on the weather, particularly the severity of the winter months, the growth of Nome and Kotzebue, the rate at which currently existing independent electrical loads are added to the utility system and the connection of additional customers to the district heating system. The future increase in the electrical loads can be accommodated by adding additional power generation modules to the powerhouse. Each module consists of the CFB combustor, the air turbine, and the connections to the district heating system. The powerhouse will be designed with space for one additional module. Further expansion will be possible by extending the main bay of the powerhouse to provide the needed space, as shown in Figures 5-1 and 5-2. ta Dif of hit iit fini inad o COAL STORAGE LOADING HOPPER Fig. 5-1 PTTUTUITTITTItdy CONTROL ROOM DIST. HEATING re CYCLONE \COMBUSTOR BAGHOUSE COMBUSTION AIR ID FAN CONVECTIVE EXTERNAL COAL Hx HEAT BUNKER EXCHANGER EHX) PLAN VIEW PLOT DIMS: 260’x150’ DA Kotzebue Powerplant Plan View PLOT DMS: 320'x307 OA LOADING vorrer ooo Fig. 5 - 2 Nome Powerplant Plan View 5.2 Power Plant Layouts Conversion from oil to coal in Kotzebue and Nome will require the construction of new powerplants. Each powerplant will require two buildings, the powerhouse with all of the power generating equipment and a building containing a one year supply of coal. The powerhouse will be designed to accommodate one additional power generation module at some future time. A conceptual layout of the Kotzebue powerplant is presented in Figures 5-1 and 5-3. The powerplant would be approximately 100 ft by 120 ft. The powerplant side view, Figure 5-3. shows a maximum height of 70 feet due to the CFB combustor. Kotzebue with an annual requirement of 20,000 tons of coal will require at least 616,000 cubic feet of coal storage. Including allowances for colder than normal winters and future growth in system demands, the coal storage building will be approximately 15@ feet wide by 16@ feet long by 40 feet high. Utilizing the same basis, the conceptual layout for Nome is shown in Figures 5-2 and 5-4. The powerplant, designed for three power generation modules with room for one more in the future, will be approximately 100 feet wide by 160 feet long. With an annual coal consumption of 37,000 tons, the coal storage structure for Nome will be 15@ feet wide by 300 feet long by 4@ feet high. These sizes are approximate and will vary due to the configuration of the hardware and the characteristics of the available land in both communities. The proposed location in Nome will be near the dock facilities to minimize the handling of the coal during the unloading process. In Kotzebue, the proposed site is near the present powerhouse necessitating the trucking of the coal from the docking facilities to the powerhouse. Once the coal has been loaded into the coal storage building, all operations that involve handling coal will take place in enclosed structures to minimize LOADING HOPPER COMBUSTOR COAL BUNKER i t TURB/GEN Fig. 5-3 Kotzebue Powerplant Side View CYCLONE ieescee BAGHOUSE if EXHAUST CONVECTIVE STACK x / ID FAN LOADING HOPPER it EXHAUST CONVECTIVE STACK COMBUSTOR Hx / COAL BUNKER CYCLONE EXTERNAL HEAT EXCHANGER «EHX? TURB/GEN /) DIST. [RATING BAGHOUSE ID FAN Fig. 5-4 Nome Powerplant Side View the release of coal dust into the atmosphere. This design approach combined with the clean burning coal combustion system will ensure the cleanest possible environment in Kotzebue and Nome. 6.1 6.@ ECONOMIC ANALYSIS Assumptions and Economic Model 6.1.1 Capital Cost The technology Proposed for converting Kotzebue and Nome from oil to coal utilizes current modular technology, applied to an unique application, small power systems which are not connected to a power grid. Due to this and the unique environment of northwestern Alaska, estimating the installed cost of one unit must be differentiated into two separate cost categories, installation of the first unit and installation of subsequent units. The difference between the two numbers is the cost of the first installation includes significant up front engineering costs, increased system check out costs, and the costs to develop new operating procedures. Once these non-recurring items have been completed for the first unit, installation of subsequent units will benefit through reduced costs. Including both communities the first installation capacity would be 12000 kW. The estimated installed cost for the first system is $5368 per kilowatt or $64,000,900. The cost of subsequent units is expected to drop to $45 million for a similar 12000 kW installation resulting in a unit cost of $3750 per kilowatt. 6.1.2 Personnel Requirements Operating manpower requirements for both the Nome and Kotzebue coal-fired power plants are similar. Each will require the following personnel: Classification Number Supervisor Clerical/Bookkeeper Power Plant Operators Operators Assistants Material Handlers bree ern Total 1 Ny Personnel is based on four, two man crews for daily operations and two, day workers involved in coal and ash handling and other related day activities. Assuming an hourly rate with benefits of $4@ per hour, the annual Manpower cost will be $998,400. The other operating cost is the cost of coal which will be treated as a variable in the economic analyses. 6.1.3 Operating and Maintenance Cost The operating and maintenance (O&M) cost for the diesel plants are based upon the 1988 operating and maintenance cost reported in each utility’s year-end reports. These reports did not break the costs down to fixed and variable costs. For the economic analyses, the O&M expenses are assumed to vary as a function of the installed capacity, corrected for inflation. Likewise, the O&M expenses for the local system are based upon operational experience at existing fluidized bed installations. The numbers were not’ broken down into fixed and variable costs. The total O&M expenses are assumed to vary as a function of the installed capacity, corrected for inflation. 6.1.4 System Efficiency At the system design point, the system heat rate is 15,500 Btu/kWh representing a system efficiency of 22%. Each fluidized bed combustor will consume just over 2700 lb/hr of coal at the design operating point. The heat rate of diesel installations range from slightly over 10,200 Btu/kWh in Nome to 11,000 Btu/kWh in Kotzebue. 6.1.5 O81 Prices The estimates of world oil prices, provided by the Alaska Energy Authority (AEA), are provided as three projections; low, medium and high. These projections are defined in Table 6-1. TABLE 6-1 1988 Dollars Per Barrel 1990 2000 2010 Low $13 $14 $15 Medium $16 $20 $25 High $19 $26 $35 The AEA has assigned a 30% probability to the low probability; a 60% probability to the medium projection, and a 10% probability to the high projection. Due to the small likelihood of the high projection being accurate, the high projection is not discussed in this report. The analysis for all three projections have been performed and the results are presented for completeness. Converting the world oil price of a barrel of crude oil to the price of diesel fuel delivered to either Nome or Kotzebue was accomplished based upon the current prices. Based upon the crude oil prices provided by AEA, the average fuel escalation rate was determined and used to calculate the diesel fuel price. These numbers are presented in Appendix D. An annual inflation rate of 3.5% was assumed with rates of 2.5% and 4.5% used for sensitivity analyses. 6.1.6 Coal Prices Coal prices include two components, the cost to mine the coal and the cost to transport the coal to the user. The coal cost incorporated in these analyses is based on four assumed levels of coal mining activity: 1) @-80,000 tons/year; 2) 8@,200-156000 tons/year; 3) 156,000-200,000 tons/year; and 4) 200,000 + tons/year. The cost associated with these levels of coal production are presented in Table 6-2. TABLE 6-2 Coal Price at Various Levels of Production Total Coal Mined Mining Transportation Total Cost/ton (ton/yr) Cost Nome Kotzebue Nome Kotzebue 50,200 67.57 32.51 24.91 100.08 92.48 82,000 61.02 28.20 21.80 89.22 82.82 156,000 56.57 17.20 14.25 73.77 70.82 200,900 55.07 11.00 10.00 66.07 65.07 A detailed list of the inflation adjusted coal prices is presented in Appendix D. 6.1.7 Demand Scenarios The analyses were performed utilizing a spreadsheet which assumes the coal-fired power plants are operational at the start of 1995. The analysis covered a period of 20 years. The economic analysis look at the following demand scenarios: 1) Diesel power generation with individual oil heating; 2) Diesel power generation with district heat and oil heating when required; 3) Coal fired power generation with district heat demand based upon Nome and Kotzebue only; 4) Coal fired power generation with district heat coal demand based upon Nome and Kotzebue plus Red Dog Mine; 5) Coal fired power generation with district heat coal demand based on Nome and Kotzebue plus gold companies; and 6) Coal fired power generation with district heat coal demand based on Nome, Kotzebue, Red Dog and the gold companies. 6.1.8 District Heating The district heat system utilized for the diesel power generation option was presented in the November 1987 Nome Waste Heat Feasibility Study by PolarConsult Alaska. Several discrepancies were noted in this report. The heating demand was not quantified nor was the heating demand matched to the heat available from the diesels. In addition, the report indicated that systems such as this which utilized exhaust gas heat recovery were prone to severe corrosion and valve burning. Design modifications and procedures to avoid these problems were not discussed in the report. According to the calculations presented in Appendix E, the diesel can be expected to provide only 42% of the annual district heating load. When sufficient heat from the district heating system is not available, oil heating will be required to make up the difference. The district heat system proposed for the coal fired installation is similar in design with several significant differences. The coal fired fluidized bed operates at a higher operating temperature than the diesel. If more heat is required by the district heating system than is currently available, additional coal can be fed into the fluidized bed to meet the demand. The district heating system proposed in this study would connect only to commercial buildings. Discussions with owners of these buildings indicate willingness to connect to the system. The diesel district heat system was designed to connect all buildings, both commercial and residential. One might expect the initial acceptance of the district heating system to be slow from the residential sector as they are not familiar with the concept. In order to better define the heating needs of Nome and Kotzebue, a reconnaissance study over a one year period should be performed. 6.1.9 Power and Energy Projections The power demand in Nome was assumed to grow at the rate of inflation. The demand in Kotzebue was based upon the findings of the Kotzebue Electric Association Power Requirement Study (Morrison-Knudsen Engineers, Inc. - March 1989). In addition, discussions have been held with the Red Dog Mine to possibly supply them with coal for power generation and heat at the mine. Current demand estimates for Red Dog are for 80,00@ tons/year for the first three years starting in 1995, then increasing to 100,000 tons/year’ thereafter. In addition, Mr. Joe Murphy, Manager of the Nome Joint Utility System, is currently discussing with the gold companies in Nome the possibility of the utility picking up their electric load. The utility expects to start picking up these loads in the next year or so. No sale of coal to Pacific Rim countries have been included in these scenarios, although preliminary talks have been held in japan and Korea. The coal consumption data for Nome and the total coal consumption data for both Nome and Kotzebue is presented in Appendix F. 6.2 Results of Evaluation In each economic analysis the amount and timing of the capital costs are shown. Appendix D presents the inflated cost of diesel and coal power modules. In the coal applications, the O&M expenses for the diesels are reduced in proportion to the amount of output, generally about 15% of normal when the diesels are operating at 5% normal duty. Likewise, when new units are added to the system, the O&M costs are increased proportionally. The economic analyses are presented in Tables 6-3 through 6-31. The results are summarized in Table 6-30 and 6-31. Looking at the high and low sensitivity cases, the results indicate that a change in economic conditions may stretch out the break even point for an additional year or so, but the basic economic comparison of the different options does not change. Concentrating on the medium economic scenario, for Nome, the diesel baseline which represents operating the diesel generators in their current configuration, without a district heating system show that over the next twenty years, with no more than an adjustment of electrical power prices for inflation, costs will exceed revenues by $213,414,000. This represents the subsidy requirements. Adding a district heating system to the diesel engines is economically 3 TABLE 6 - DIESEL FUEL PRICE PROJECTION 2.5% INFLATION RATE STRAIGHT HIGH INFLATION MEDIUM LOW YEAR RERSSSESARARSSESAATARRAGAAS ROE VPODDDAAARHAGOOS AAANNANNNMMNS oe © © eo ew ee ew ee ee ee ee SSSCSSSCOSSOOOOd Addn dd ddd ddd OALTATHMO AR LTADN aan oOrormrnraaw RRQVDWANSMAANNNS noon ANTM OAAeI oe eo ee we ee ee 8 6 ee ee ee SSSCDOOd Add AAA AAA AANNANANNANANAO RHE VAAAAN ANNONMNFNOMONRADANHRVCANNMNTH ooo ee ew ee * 8 8 ee oe ee SSOd ddA AAA AAA AA AANNNAAA OR OMNMRAYNROMNOYTRANAMAARAYAON HH OWDWDHDHAANHOOCOAAANNANATTONOON CODD CSOOOCOddd ddd dd ddd ddddddd BRRAKKSRRGRASSSSSSSSssagaags DOAAAAAAARAAAR $0 dddda AARAARAARARAARROSOSSSSOOSSSONNS Add ddA Ad AAA ANANANANANNAANANAAAN TABLE 6 - 4 DIESEL FUEL PRICE PROJECTIONS 3.5% INFLATION RATE STRAIGHT HIGH INFLATION MEDIUM RRGSISARARSSSAGKARAATIRSBARG SRA DADDANAAHS AANNMMOMS ST OUOnna . oe © © ee eo ee eel oe we ee SSSCSSCSDSOSO Odd d dd ddd dd ddd ddd NOUN D ADTONNNWUADOMANAWYTYTNOW RODDASHANATHOROOTATORANAH OS oe © © © © ee ee ee ee ee le oe ew ee SSACDGd AnH AK AAAAANNNNANAANM MMS 6 - 10 TABLE 6 - 5 DIESEL FUEL PRICE PROJECTIONS 4.5% INFLATION RATE STRAIGHT HIGH INFLATION MEDIUM WODNUOAMAANANTAONRMNANOADOMARD ono BRRAODDANNAGCOAANNMNMNPTNONORNR DADA ANM © 6 SC 6 0 6 6 ee 6 6 8 8 6 ee ee 6 ei te 6 le 6 S999 9CCO dR ddd ddd ddd A AAA A ANNAN PASE SSeBSSRSeaaese4aa Aan YTOrnrnanse nODOnO ANMOMTONNRAOAMT DAMNVDDAASTON ww © [ee @ @) ie e je .9 © e 1 © 6 \9 SSCSOOd ddd AAA ANNNANANN MAMAS SS RSSHRASAARSSRSRASAASSSSRLGS wc SOONDA ANOS ee © © 6 eo ee ee oe © ee ee eee ee WAMNANNA gssgqgegas NOADAA oadm aaanas YONRON Nos RS 6-="171 INFLATION RATE 2.5 | 1995 / 1996 ELECTRIC pore SYSTEM PROJECTED LOAD (KW) 3389// 3474 a CAPACITY: COAL (KW) 0 0 OIL (KW) = 1213312133 oy HEAT RATE: COAL 15500 15500 , (BTU/KWH) OIL 11000>) 11000 _ Ny PRODUCTION COAL 0 0 (000 KWH/YR) OIL 29688 += 30432 FUEL: COAL ($/TON) 0 0 OIL ($/GAL) 0.94 0.97 COAL ($/MMBTU) 0.00 0.00 OIL ($/MMBTU) 6.71 6.93 O&M: COAL, 100% LOAD 936 959 OIL, 100% LOAD 670 687 COSTS: FUEL (COAL) 0 0 FUEL (OIL) 2193 2319 OIL 08M 670 687 CAPITAL (6950 TOTAL | 2863 3006 ELEC. COST ($/KWH) 0.096 0.099 1997 3561 12133 15500 11000 31194 1.00 0.00 7.14 983 2451 704 3155 0.101 71998 3650 12133 ; 15500 11000 31974 1.03 0.00 7.36 1008 722 2588 722 3309 0.103 TABLE 6 - 6 FI I III III II IIIA IIIT IIASA III IN IIIS AISA ISIS ioe WESTERN ARCTIC COAL DEVELOPMENT PROJECT ‘+ +e NOME * =e LOW OIL JAN 90 DIESEL * EIEIO IOI III IIIT III SII AISA IA IAA UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ DIESEL ONLY - BASELINE 1999 2000 2001 2002 2003 2004 2005 3741 3834 3930 4029 4129 4232 4338 0, 0 0 0 0 0 0 14733 14733 14733-14733. 14733-14733 14733 15500 15500 15500 15500 15500 15500 15500 11000 11000 11000 11000 11000 11000 11000 0 0 0 0 0 0 0 32771 33586 = 34427) 35294 936170 9= 37072 = 38001 0 0 0 0 0 0 0 1.07 1.10 1.16 1.17 1.21 1.25 1.29 0.00 0.00 0.00 0.00 0.00 0.00 0.00 7.64 7.86 8.14 8.36 8.64 8.93 9.21 1033 1059 1085 1113 1140 1169 1198 898 920 943 967 91 1016 1041 0 0 0 0 0 0 0 2755 2903 3084 3245 3439 3641 3852 898 920 943 967 m1 1016 1041 7680 3653 3823 4027 4212 4430 4657 4893 0.111 0.114 0.117) 0.119 0.122 0.126 0.129 2006 4447 17333 15500 11000 38956 1.33 0.00 9.50 1228 1256 4071 1256 9120 5327 0.137 2007 4558 17333 15500 11000 39928 1.38 0.00 9.86 1259 1287 0 4329 1287 5617 0.141 2008 4672 17333 15500 11000 40927 1.42 0.00 10.14 1290 1319 0 4566 1319 5886 0.144 2009 4789 17333 15500 11000 41952 1.47 0.00 10.50 1323 1352 4845 1352 6198 0.148 2010 4908 17333 15500 11000 42994 1.51 0.00 10.79 1356 1386 5101 1386 0.151 2011 5031 17333 15500 11000 44072 1.56 0.00 11.14 1389 1421 5402 1421 0.155 2012 5157 17333 15500 11000 45175 1.61 0.00 11.50 1424 1456 5715 1456 7171 0.159 =a 2013 2014 5286 5418 0 0 19333 19333 ) 15500 15500 11000 11000 0 0 46305 47462 0 0 1.66 1.72 0.00 0.00 11.86 12.29 1460 1496 1665 1707 0 0 6040 6414 1665 1707 10850) 7705 8121 0.166 0.171 1995 1996 197 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013-2014 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 206.0 212.2 218.5 225.1 231.9 238.8 246.0 253.4 261.0 268.8 276.8 285.2 293.7 302.5 311.6 320.9 330.6 340.5 350.7 OH AVAIL (MMBTU/YR) 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 CAPITAL COST 0 O&M COST 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 SUPPLEMENTAL OIL HEA 1678.6 1784.1 1894.5 2009.8 2150.5 2277.1 2430.7 2569.6 2737.1 2912.4 3095.8 3287.6 3513.5 3723.8 3970.5 4200.9 4470.3 4751.9 5046.5 5385.8 TOTAL 1678.6 1784.1 1894.5 2009.8 2150.5 2277.1 2430.7 2569.6 2737.1 2912.4 3095.8 3287.6 3513.5 3723.8 3970.5 4200.9 4470.3 4751.9 5046.5 5385.8 SYSTEM OPERATING COST 4541 4790 5049 5319 5804 6100 6458 6781 7167 = 7570 7989-8614 9130 9609 10168 10688 11293 11923 12751 13507 REVENUE PRICE OF ELEC $/KWH 0.08 0.084 0.088 0.093 0.097 0.102 0.107 0.113 0.118 0.124 0.130 0.137 0.144 0.151 0.158 0.166 0.175 0.183 0.193 0.202 ELECTRICAL REVENUE 2375 2556 2751 2961 3187 3429 3691 3973 4275 4601 4952 5330 5736 6174 6645 7151 7696 8283 8915 9595S PRICE OF HEATS/MMBTU 9.06 9.35 9.64 9.93 10.32 10.61 10.99 11.28 11.67 12.05 12.44 12.83 13.31 13.69 14.18 14.56 15.04 15.53 16.01 16.59 ©) HEATING REVENUE 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 TOTAL 2375 2556 2751 2961 3187 3429 3691 3973 4275 4601 4952 5330 5736 6174 6645 7151 7696 8283 8915 9595 cE DEBT 6950 = 6771 6580 6377 = 13841 13413) 12957) 12472) 11954 = 11404 10817 19312 1841217454 «= 16433-15345 14187 = 12954 = 22491 20812 DEBT SERVICE 631 631 631 631 631 631 631 631 631 631 631 631 631 631 631 631 631 631 631 631 697 697 697 697 697 697 697 697 697 697 697 697 697 697 697 697 828 828 828 828 828 828 828 828 828 985 985 TOTAL DEBT SERVICE 631 631 631 631 1328 1328 1328 1328 1328 1328 1328 2155 2155 2155 2155 2155 2155 2155 3140 3140 INTEREST 452 440 428 415 900 872 842 811 7 741 703 1255 1197 1134 1068 97 922 842 1462 1353 PRINCIPLE PAYMENT 179 191 203 216 428 456 486 517 551 587 625 900 959 1021 1087 1158 1233 1313 1678 1787 ENDING BALANCE 6771 6580 6377 6161 13413) 12957) 1247211954 11404 10817) 10192 1841217454 «= 16433-15345. 14187) 12954 11641 20812 19025 CASH FLOW -2797 = --2865 -2929 = 2989-3945 3999-4095 -4136 -4220-4296—-4365-5440 9 -5549 = -5591 -5679 «= 5693-5752. 5795-6976 = - 7052 CUMULATIVE CASH FLOW “2797 = -5662- -8590 --11579 -15524 -19523 -23618 -27754 -31973 -36270 -40634 -46074 -51623 -57214 -62893 -68586 -74338 -80134 -87110 -9%4162 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 5 5 5 5 5 5 2 a oi 5 5 5 5 5 5 5 5 5 5 INFLATION 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 DISTRICT HEAT LOAD 3 3 2 3 = 3 3 S = 3 3 3 3 2 3 3 > 3 s S COST OF MONEY 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 INFLATION 1,025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 DISTRICT HEAT LOAD 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 INFLATION RATE 2.5 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) CAPACITY: COAL (KW) OIL (KW) \ HEAT RATE: COAL 1 (BTU/KWH) OIL ay F» PRODUCTION COAL (000 KWH/YR) OIL FUEL: COAL ($/TON) OIL ($/GAL) COAL ($/MMBTU) OIL (¢$/MMBTU) 08M: COAL, 100% LOAD OIL, 100% LOAD COSTS: FUEL (COAL) FUEL (OIL) OIL O&M CAPITAL TOTAL ELEC. COST ($/KWH) 1995 3389 12133 15500 11000 0.94 0.00 6.71 936 670 0 2193 670 6950 2863 0.096 1996 3474 12133 15500 11000 30432 0.97 0.00 6.93 99 687 2319 687 3006 0.099 TABLE 6 - 7 FEI IO IOI IR III II III II IIIA IIIS ISIS IS ISIS IA ISIA ASAI ta WESTERN ARCTIC COAL DEVELOPMENT PROJECT salad we NOME a oe LOW OIL JAN 90 DIESEL ae EI II II III III II IIT TI IIIT IAI IIIA III IIASA UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ DIESEL WITH DISTRICT HEAT 1997 1998 1999 2000 2001 2002 2003 2004 2005 3561 3650 3741 3834 3930 4029 4129 4232 4338 12133. 12133. «14733. 14733) 14733, 14733-14733) 14733 14733 15500 15500 15500 15500 15500 15500 15500 15500 15500 11000 11000 11000 11000 11000 11000 11000 11000 11000 31194 31974 32771 = 33586 §=— 34427 = 35294 «= 36170-37072 = 38001 1.00 1.03 1.07 1.10 1.14 1.17 1.21 1.25 1.29 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 7.14 7.36 7.64 7.86 8.146 8.36 8.64 8.93 9.21 983 1008 1033 1059 1085 1113 1140 1169 1198 704 722 898 920 943 967 1 1016 1041 2451 2588 2755 2903 3084 3245 3439 3641 3852 704 722 898 920 943 967 1 1016 1041 7680 3155 3309 3653 3823 4027 4212 4430 4657 4893 0.101 0.103 0.111 0.1146 0.117 0.119 0.122 0.126 0.129 2006 4447 17333 15500 11000 38956 1.33 0.00 9.50 1228 1256 4071 1256 9120 5327 0.137 2007 4558 17333 15500 11000 39928 1.38 0.00 9.86 1259 1287 0 4329 1287 5617 0.141 2008 4672 17333 15500 11000 40927 1.42 0.00 10.14 1290 1319 0 4566 1319 5886 0.144 2009 4789 17333 15500 11000 41952 1.47 0.00 10.50 1323 1352 4845 1352 6198 0.148 2010 4908 17333 15500 11000 42994 1.51 0.00 10.79 1356 1386 5101 1386 6487 0.151 2011 5031 17333 15500 11000 44072 1.56 0.00 11.14 1389 1421 5402 1421 6823 0.155 2012 5157 17333 15500 11000 45175 1.61 0.00 11.50 1424 1456 5715 1456 7171 0.159 2013 5286 19333 15500 11000 1.66 0.00 11.86 1460 1665 1665 10850 0.166 2014 5418 19333 15500 11000 47462 1.72 0.00 12.29 1496 1707 6414 1707 8121 0.171 1995 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 DH AVAIL (MMBTU/YR) CAPITAL COST 7306.5 O&M COST 30 SUPPLEMENTAL OIL HEA 967.7 TOTAL 997.7 SYSTEM OPERATING COST 3860 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 2375 PRICE OF HEATS/MMBTU 9.06 cy HEATING REVENUE 1813 TOTAL 4188 th DEBT 14256.5 DEBT SERVICE 1294 TOTAL DEBT SERVICE 1294 INTEREST 927 PRINCIPLE PAYMENT 367 ENDING BALANCE 13889 CASH FLOW -966 CUMULATIVE CASH FLOW -966 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 INFLATION 2.5 DISTRICT HEAT LOAD 3 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 INFLATION 1.025 DISTRICT HEAT LOAD 1.03 1996 206.0 86.8 30.8 1032.2 1063.0 0.084 2556 9.35 1927 13889 1294 1294 903 391 13498 ~1846 5 2.5 3 6.5 1.05 1.025 1.03 1997 212.2 89.0 31.5 1099.9 1131.4 0.088 2751 9.64 2046 4797 13498 1294 1.05 1.025 1.03 1998 218.5 91.2 32.3 1171.0 1203.3 0.093 9.93 2171 5132 13082 1294 1.05 1.025 1.03 1999 225.1 93.5 33.1 1257.3 1290.4 0.097 3187 10.32 2323 5509 20318 1294 697 1991 1321 670 19648 -1425 1.05 1.025 1.03 0.102 3429 10.61 2459 5889 19648 1294 697 1991 1277 714 18934 1296 ~6024 2.5 6.5 1.05 1.025 1.03 0.107 3691 10.99 2625 6316 18934 1294 697 1991 1231 760 18174 -1168 -7192 2.5 6.5 1.05 1.025 1.03 0.113 3973 11.28 2775 6748 18174 1294 697 1991 1181 810 1.05 1.025 1.03 0.118 4275 11.67 7231 17365 1294 697 1.05 1.025 1.03 261.0 105.8 37.5 1731.9 1769.3 0.124 4601 12.05 3145 7746 16502 1294 697 1991 1073 918 15584 -671 +9719 2.5 6.5 1.05 1.025 1.03 2005 268.8 108.4 38.4 1847.0 1885.4 0.130 4952 12.44 3343 15584 1294 697 1991 1013 978 14606 -474 -10193 2:5 6.5 1.05 1.025 1.03 0.137 5330 12.83 3551 8881 23726 1294 697 828 2819 1542 1276 22450 “1272 - 11465 2.5 6.5 1.05 1.025 1.03 2007 285.2 113.9 40.3 2109.9 2150.3 0.144 5736 13.31 3795 9531 22450 1294 697 828 2819 1459 1359 21091 1054 -12519 2.5 6.5 1.05 1.025 1.03 0.151 6174 13.69 4022 10196 21091 1294 697 828 2819 1371 1448 19643 13313 2.5) 6.5 1.05 1.025 1.03 2009 302.5 119.7 42.4 2399.8 2442.2 0.158 14.18 4288 10933, 19643 1294 697 828 2819 1277 1542 18101 =Seo - 13838 2.5 6.5 1.05 1.025 1.03 2010 311.6 122.7 43.4 2547.1 2590.5 0.166 7151 14.56 4537 11688 18101 1294 697 828 2819 1177 1642 16459 -14047 2.5 6.5 1.05 1.025 1.03 0.175 7696 15.04 12524 16459 1294 697 828 2819 1070 1749 14710 119 - 13928 2.5 6.5 1.05 1.025 1.03 0.183 15.53 5132 13416 14710 1294 697 828 2819 6 1862 12848 481 ~ 13447 2.5 6.5 1.05 1.025 1.03 2013 2014 340.5 350.7 132.1 135.4 46.8 48.0 3088.5 3306.3 3135.3 3354.3 10840 = 11475 0.193 0.202 8915 9595 16.01 . 16.59 5450 5817 14365 15411 23698 = 21435 1294 1294 697 697 828 828 985 985 3803 3803 1540 1393 2263 2410 21435-19025 -278 133 -13725 -13592 5 5 2.5 2.5 3 3 6.5 6.5 1.05 1.05 1.025 1.025 1.03 1.03 INFLATION RATE 2.5 1995 1996-1997 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) 3389-3474 ©3561 CAPACITY: COAL (KW) 7500 7500 7500 OIL (KW) 12133-12133. 12133 WEAT RATE: COAL 15500 15500 15500 1 (BTU/KWH) OIL 11000 11000 11000 ~ © PRODUCTION COAL 28203 28911-29635 (000 KWH/YR) OIL. 1484 «15221560 FUEL: COAL ($/TON) 118.96 121.9% 124.99 OIL ($/GAL) 0.94 0.97 1.00 COAL (S/MMBTU) 4.96 5.08 5.21 OIL (S/MMBTU) 6.71) 6,93 7.16 pe eel aly (9492) O&M: COAL, 100% LOAD 959 983 OIL, 100% LOAD 670» 687704 COSTS: FUEL (COAL) 2167 2277 -—-2392 FUEL (OIL) 10116123 OIL 08M Ol 103. 106 CAPITAL §—_ (19260 > UP matloon’”. TOTAL 3313 3455 3604 ELEC. COST (S/KWH) 0.112 0.1146 0.116 TABLE 6 - 8 ISIS III IOI IIIT IIIT IIIT IIIA INIA AAS AAA WESTERN ARCTIC COAL DEVELOPMENT PROJECT NOME LOW OIL JAN 90 COAL EIEIO SISO SITIES IOS IIR II IIS. UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ COAL WITH DISTRICT HEAT Oi a -™ + ” * 1998 1999 2000 2001 2002 2003 2004 2005 3650 3741 «3834-3930 4029 4129 42324338 7500 7500 7500 7500 7500 7500 7500 10000 12133. 12133) 12133-12133) 12133) 12133) 12133-12133 15500 15500 15500 15500 15500 15500 15500 15500 11000 611000 11000 11000 11000 11000 11000 11000 30375 «31133. 331907 32705 33529) 34362) 35219 = 336101 1599 1639 1679 1721 1765 1809 1854 1900 128.11 131.31 134.6 137.96 141.41 144.95 148.57 152.28 1.03 1.07 1.10 1.14 1.17 1.21 1.25 1.29 5.34 5.47 5.61 5.75 5.89 6.04 6.19 6.35 7.36 7, 7.86 8.14 8.36 8.64 8.93 9.21 ont, te Ot" 1008 1033 1059 1085 1113 1140 1169 1598 722 740 758 777 796 816 837 858 2513 2640 2774 2914 3062 3217 3379 3550 129 138 145 154 162 172 182 193 1080111 114 "1700-4119 122 12129 1200 3759 3922 4091 4270 4456 4652 4856 5469 0.118 0.120 0.122 0.126 0.126 0.129 0.131 0.144 2006 4447 10000 12133 15500 11000 37008 1948 156.09 1.33 6.50 9.50 1637 879 3731 132 5704 (0.146 2007 4558 10000 12133 15500 11000 37932 1996 159.99 1.38 6.67 9.86 1678 901 3919 216 135 5949 0.149 2008 4672 10000 12133 15500 11000 2046 163.99 1.42 6.83 10.14 1720 924 4118 228 139 6205 0.152 2009 4789 10000 12133 15500 11000 39854 2098 168.09 1.47 7.00 10.50 1763 7 4326 242 142 6474 0.154 2010 2011 4908 5031 10000 10000 12133-12133 15500 15500 11000 11000 40844 41868 2150 2204 172.29 176.6 1.51 1.56 7.18 7.36 10.79 11.14 1807 1853 970 Ve) 4545 4775 255 270 146 149 6753 7047 0.157 0.160 od == 2012 2013-2014 5157 5286 5418 12500 12500 12500 12133, 1213312133 15500 15500 15500 11000 11000 11000 42917 43990 45089 22590 2315 2373 181.02 185.54 190.18 1.61 1.66 1.72 7.54 7.73 7.92 11.50 11.86 12.29 2374 2433 2494 1019 1045 1071 5017 5271 5538 286 302 321 153, 157 161 14270 7830 8163 8513 0.173 0.176 0.179 ¢. SJ pd Uo -72 jy og k po ee f- 1997 1998 = 1999 2000 2001 2002 §=62003 = 2006S 2005. 2006 = 2007, 2008 )=— 2009S 2010S 2011 2012 2013, 2014 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 212.2 218.5 225.1 231.9 238.8 246.0 9253.4 9261.0 268.8 §= 276.8 9285.2 9293.7 9302.5 311.6 320.9 330.6 340.5 350.7 CAPITAL COST C 2233.65 4.0% p. v-48 O&M COST 40 41.0 42.0 43.1 44.2 45.3 46.4 47.5 48.7 50.0 51.2 52.5 53.8 55.1 56.5 57.9 59.46 60.9 62.6 63.9 TOTAL 40.0 41.0 42.0 43.1 44.2 45.3 46.4 47.5 48.7 50.0 51.2 52.5 53.8 55.1 56.5 57.9 59.4 60.9 62.4 63.9 SYSTEM OPERATING COST 3353 3496 3646 3802 3966 4137 4317 4504 4700 4906 5520 5756 6003 6260 6531 6811 7107 7891 REVENUE PRICE OF ELEC $/KWH 0.08 0.084 0.088 0.093 0.097 0.102 0.107 0.113 0.118 0.124 0.130 0.137 0.144 0.151 0.158 0.166 0.175 0.183 0.193 0.202 ELECTRICAL REVENUE 2375 2556 2751 2961 3187 = 3429 3691 3973 4275 4601 4952 5330 5736 6174 6645 7151 7696 8283 8915 = 9595 PRICE OF HEATS/MMBTU 9.06 9.35 9.64 9.93 10.32 10.61 10.99 11.28 11.67 12.05 12.46 12.83 13.31 13.69 14.18 14.56 15.04 15.53 16.01 16.59 HEATING REVENUE 1813 1927 2046 = 2171 2323 2459 2625 2775 2956 = 3145 3343-3551 3795 4022 4288 4537 4828 5132 5450 5817 TOTAL 4188 4483 4797-55132 5509 5889 6316 6748 7231 7746-8295 8881 9531 10196 §= 10933. 11688 )=— 12524. 13416 14365 15411 DEBT 21493.6 20940 20350 19723 19054 18342 17583 16775 15915 14999 26023 24675 23239 21710 20081 18347 16499 28802 26339 23717 DEBT SERVICE 1951 1951 1951 1951 1951 1951 1951 1951 1951 1951 1951 1951 1951 1951 1951 1951 1951 1951 1951 1951 1089 1089 1089 1089 1089 1089 1089 1089 1089 1295 1295 1295 TOTAL DEBT SERVICE 1951 1951 1951 1951 1951 1951 1951 1951 1951 1951 3040 3040 3040 3040 3040 3040 3040 4335 4335-4335 ZL 8 INTEREST 1397 1361 1323 1282 1238 1192 1143 1090 1034 975 1692 1604 1511 1411 1305 1193 1072 1872 1712 1542 PRINCIPLE PAYMENT 554 590 628 669 712 758 808 860 916 976 1348 1436 1529 1629 1734 1847 1967 2463 2623 2793 ENDING BALANCE 20940 20350 «19723. 19054 18342, 1758316775) 15915 14999 14023-24675 23239) 21710-20081 18347 1649914532 26339-23717 = 20923 CASH FLOW -1116 964 -799 -621 -408 -199 49 293 580 890 -265 85 488 896 1363 1837-2378 1190 1805 2499 CUMULATIVE CASH FLOW “1116-2079 -2879 -3499--3907- -4106 -4057 3764 «= --3183 -2293- -2558 )§=— -2473. Ss -1985 = - 1090 273 2110 4488 5678 7483-9982 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 > 5 5 5 5 2 5 5 5 5 5 > 5 2 5 5 5 5 5 INFLATION 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 DISTRICT HEAT LOAD 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 COST OF MONEY 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 INFLATION 1.025 1.025 1.025 1.025 «1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 DISTRICT HEAT LOAD 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 INFLATION RATE ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) CAPACITY: COAL (KW) OIL (KW) O HEAT RATE: COAL 1 (BTU/KWH) OIL - © PRODUCTION COAL (000 KWH/YR) OIL FUEL: COAL ($/TON) OIL ($/GAL) COAL ($/MMBTU) OIL ¢$/MMBTU) 08M: COAL, 100% LOAD OIL, 100% LOAD COSTS: FUEL (COAL) FUEL (OIL) OIL O&™ CAPITAL TOTAL ELEC. COST ($/KWH) 2.5 1995 3389 7500 12133 15500 11000 28203 1484 106.05 0.94 4.42 6.71 936 670 1932 110 101 19260 3078 0.104 1996 3474 7500 12133 15500 11000 28911 1522 108.71 0.97 4.53 6.93 9 687 2030 116 103 3208 0.105 1997 3561 7500 12133 15500 11000 29635 1560 111.42 1.00 4.64 7.14 2132 123 106 3344 0.107 1998 3650 7500 12133 15500 11000 30375 1599 114.21 1.03 4.76 7.36 1008 722 2241 129 108 3486 0.109 TABLE 6 - 9 EIT III IIIT IIIA TIAA IIASA IIIA IAI AOI IAA oe WESTERN ARCTIC COAL DEVELOPMENT PROJECT ee * aad LOW OIL NOME JAN 90 * COAL ae RISER IRI IOI IOI TOTTI II IIIT TITIAN UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ COAL WITH DISTRICT HEAT 1999 3741 7500 12133 15500 11000 31133 1639 117.06 1.07 4.88 7.64 1033 740 2354 138 11 0.111 2000 7500 12133 15500 11000 31907 1679 119.99 1.10 5.00 7.86 1059 758 2473 145 14 3790 0.113 2001 3930 7500 12133 15500 11000 32705 1721 122.99 1.14 5.12 8.14 1085 2598 154 117 3954 0.115 & REO DOG 2002 4029 7500 12133 15500 11000 33529 1765 126.07 1.17 5.25 8.36 1113 2730 162 119 4124 0.117 2003 4129 7500 12133 15500 11000 34362 1809 129.22 1.21 5.38 8.64 1140 816 2868 172 122 4302 0.119 2004 2005 4232 4338 7500 10000 12133 12133 15500 15500 11000 11000 35219 36101 1854 1900 132.45 135.76 1.25 1.29 5.52 5.66 8.93 9.21 1169 1598 837 858 3013 3165 182 193 126 129 12000 4489 5084 0.121 0.134 2006 4447 10000 12133 15500 11000 37008 1948 139.15 1.33 5.80 9.50 1637 879 3326 132 5299 0.136 2007 4558 10000 12133 15500 11000 37932 1996 142.63 1.38 5.94 9.86 1678 901 3494 216 135 5524 0.138 2008 4672 10000 12133 15500 11000 2046 146.2 1.42 6.09 10.14 1720 924 3671 228 139 5758 0.141 2009 4789 10000 12133 15500 11000 39854 2098 149.85 1.47 6.24 10.50 1763 947 242 142 6005 0.143 2010 4908 10000 12133 15500 11000 2150 153.6 1.51 6.40 10.79 1807 970 4052 255 146 6260 0.146 2011 2012 5031 5157 10000 =12500 1213312133 15500 15500 11000 11000 41868 42917 2204 2259 157.44 161.37 1.56 1.61 6.56 6.72 11.14 11.50 1853 2374 99S 1019 4257 = 4473 270 286 149 153 14270 6529 7285 0.148 0.161 2013 5286 12500 12133 15500 11000 43990 2315 136.77 1.66 5.70 11.86 2433 1045 302 157 6777 0.146 2014 5418 12500 12133 15500 11000 45089 2373 140.18 1.72 5.84 12.29 2494 1071 321 161 0.149 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 CAPITAL COST 2233.6 O&M COST 40 TOTAL 40.0 SYSTEM OPERATING COST 3118 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 2375 PRICE OF HEATS/MMBTU 9.06 HEATING REVENUE 1813 TOTAL 4188 a 1 DEBT 21493.6 j= DEBT SERVICE 1951 © TOTAL DEBT SERVICE 1951 INTEREST 1397 PRINCIPLE PAYMENT 554 ENDING BALANCE 20940 CASH FLOW -881 CUMULATIVE CASH FLOW -881 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 INFLATION 2.5 DISTRICT HEAT LOAD 3 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 INFLATION 1.025 DISTRICT HEAT LOAD 1.03 0.084 2556 9.35 1927 20940 1951 1951 1361 590 20350 “717 -1597 2.5 6.5 1.05 1.025 1.03 1997 212.2 42.0 42.0 0.088 2751 9.64 2046 4797 20350 1951 1951 1323 628 19723 -539 2137 2.5 6.5 1.05 1.025 1.03 1998 218.5 43.1 43.1 0.093 2961 9.93 2171 5132 19723 1951 1951 1282 669 19054 2485 2.5 6.5 1.05 1.025 1.03 1999 225.1 44.2 44.2 0.097 3187 10.32 2323 5509 19054 1951 1951 1238 712 18342 =121 1.05 1.025 1.03 231.9 45.3 45.3 0.102 3429 10.61 2459 18342 1951 1951 1192 758 17583 102 1.05 1.025 1.03 238.8 46.4 46.4 0.107 3691 10.99 2625 6316 17583 1951 1951 1143 16775 365 -2139 2.5 6.5 1.05 1.025 1.03 246.0 47.5 47.5 0.113 3973 11.28 2775 6748 16775 1951 1951 1090 15915 626 -1513 2.5 6.5 1.05 1.025 1.03 1951 1034 916 14999 2.5 6.5 1.05 1.025 1.03 0.124 4601 12.05 3145 7746 14999 1951 1951 975 976 14023 1257 673 2.5 6.5 1.05 1.025 1.03 1951 1089 3040 1692 1348 24675 120 793 2.5 6.5 1.05 1.025 1.03 0.137 5330 12.83 3551 8881 24675 1951 1089 3040 1604 1436 23239 490 1283 2.5 6.5 1.05 1.025 1.03 2007 285.2 53.8 53.8 0.144 5736 13.31 3795 9531 23239 1951 1089 3040 1511 1529 21710 913 2196 2.5 6.5 1.05 1.025 1.03 0.151 6174 13.69 4022 10196 21710 1951 1089 3040 1411 1629 20081 1342 3539 2.5 6.5 1.05 1.025 1.03 302.5 56.5 56.5 0.158 14.18 4288 10933 20081 1951 1089 3040 1305 1734 18347 1832 5371 2.5 6.5 1.05 1.025 1.03 2010 311.6 57.9 57.9 0.166 7151 14.56 4537 11688 18347 1951 1089 3040 1193 1847 16499 2330 2.5 6.5 1.05 1.025 1.03 2011 320.9 59.4 59.4 0.175 7696 15.04 12524 16499 1951 1089 3040 1072 1967 14532 2896 10597 2.5 6.5 1.05 1.025 1.03 2012 330.6 60.9 60.9 0.183 15.53 5132 13416 28802 1951 1089 1295 4335 1872 2463 26339 1735 12331 225 6.5 1.05 1.025 1.03 2013 340.5 62.4 62.4 0.193 8915 16.01 5450 14365 1951 1089 1295 4335 1712 2623 23717 3191 15522 2.5 6.5 1.05 1.025 1.03 2014 350.7 0.202 16.59 5817 15411 23717 1951 1089 1295 4335 1542 2793 20923 3955 19477 2.5 6.5 1.05 1.025 1.03 INFLATION RATE 2.5 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) CAPACITY: COAL (KW) OIL (KW) HEAT RATE: COAL 1 (BTU/KWH) OIL N S PRODUCTION COAL (000 KWH/YR) OIL FUEL: COAL ($/TON) OIL ($/GAL) COAL ($/MMBTU) OIL ($/MMBTU) O&M: COAL, 100% LOAD OIL, 100% LOAD COSTS: FUEL (COAL) FUEL (OIL) OIL O&M CAPITAL TOTAL ELEC. COST ($/KWH) 1995 5079 10000 17333 15500 11000 42267 2225 106.05 0.94 4.42 6.71 1248 670 2895 164 101 28640 4408 0.099 1996 5392 10000 17333 15500 11000 2362 108.71 0.97 4.53 6.93 1279 687 3150 180 103 4713 0.100 1997 5825 12500 17333 15500 11000 48476 2551 111.42 1.00 4.64 7.14 1639 200 106 9850 5433 0.106 1998 5952 12500 17333 15500 11000 49533 2607 114.21 1.03 4.76 7.36 1680 722 3654 211 108 5653 0.108 TABLE 6 - 10 EHEC IIIT IT TI TOTTI = WESTERN ARCTIC COAL DEVELOPMENT PROJECT - * LOW OIL NOME JAN 90 COAL * * * RII IEE III IOI IOI TOTO IIIT IIIA IIA UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ COAL WITH DISTRICT HEAT RED DOG, & GOLD CO 1999 6081 12500 17333 15500 11000 2663 117.06 1.07 4.88 7.64 1722 740 224 111 5883 0.110 2000 6214 12500 17333 15500 11000 51713 2722 99.21 1.10 4.13 7.86 1765 758 3313 235 114 5427 0.100 2001 6350 12500 17333 15500 11000 52845 2781 101.69 1.14 4.26 8.14 1809 3471 249 17 5645 0.101 2002 12500 17333 15500 11000 54001 2842 104.24 1.17 4.34 8.36 1854 261 119 5871 0.103 2003 12500 17333 15500 11000 55192 106.84 1.21 4.45 8.64 1901 816 276 122 6108 0.105 6778 15000 17333 15500 11000 56407 109.51 1.25 4.56 8.93 2338 837 3989 292 126 11710 6744 0.114 2005 6928 15000 17333 15500 11000 57655 3034 112.25 1.29 4.68 9.21 2396 858 4180 308 129 7012 0.116 15000 17333 15500 11000 3102 115.06 1.33 4.79 9.50 2456 879 4380 324 132 0.118 2007 7240 15000 17333 15500 11000 60251 3171 117.93 1.38 4.91 9.86 2518 901 4589 135 0.120 2008 7401 15000 17333 15500 11000 61591 3242 120.88 1.42 5.04 10.14 2581 924 362 139 0.122 2009 15000 17333 15500 11000 3314 123.9 1.47 5.16 10.50 2645 947 5039 142 8209 0.124 2010 15000 17333 15500 11000 64387 3389 127 1.51 5.29 10.79 2711 970 5281 402 146 8540 0.126 2011 7911 15000 17333 15500 11000 65835 130.18 1.56 5.42 11.14 2779 5535 149 0.128 2012 15000 17333 15500 11000 67317 3543 133.43 1.61 5.56 11.50 2848 1019 5801 153 9250 0.131 2013 8272 17500 17333 15500 11000 68840 136.77 1.66 5.70 11.86 1045 6081 473 157 14270 10116 0.140 2014 8459 17500 17333 15500 11000 3705 140.18 1.72 5.84 12.29 3491 1071 6373 501 161 10526 0.142 1995 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 CAPITAL COST 2233.6 O&M COST 40 TOTAL 40.0 1996 206.0 41.0 41.0 1997 212.2 42.0 42.0 1998 218.5 43.1 43.1 261.0 50.0 50.0 2005 268.8 51.2 51.2 2006 276.8 52.5 52.5 2007 285.2 53.8 53.8 2008 293.7 55.1 55.1 2009 302.5 56.5 56.5 2011 320.9 59.4 59.4 2012 330.6 2014 350.7 SYSTEM OPERATING COST 4448 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 3559 PRICE OF HEATS/MMBTU 9.06 HEATING REVENUE 1813 TOTAL 5372 a , DEBT 30873.6 DEBT SERVICE 2802 = TOTAL DEBT SERVICE 2802 INTEREST 2007 PRINCIPLE PAYMENT 79S ENDING BALANCE 30078 CASH FLOW -1877 CUMULATIVE CASH FLOW +1877 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 INFLATION 2.5 DISTRICT HEAT LOAD 3 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 INFLATION 1.025 DISTRICT HEAT LOAD 1.03 0.084 9.35 1927 5894 30078 2802 2802 1955 87 29232 1661 -3539 2.5 6.5 1.05 1.025 1.03 2046 6547 2802 2540 1156 37926 2625 ~6163 2.5 6.5 1.05 1.025 1.03 0.093 9.93 2171 37926 2802 2465 1231 2392 8556 2.5 6.5 1.05 1.025 1.03 0.097 5180 10.32 7503 1.05 1.025 1.03 2000 2001 231.9 238.8 45.3 46.4 45.3 46.4 5473 5692 0.102 0.107 5558 5964 10.61 10.99 2459 =. 2625 8017 = 8589 35384 33988 2802 2802 894 894 2300 2209 1396 1487 33988 32502 “1151 -799 -11827 -12626 5 5 2.5 2.5 5 3 6.5 6.5 1.05 1.05 1.025 1.025 1.03 1.03 0.113 11.28 2775 9174 32502 2802 2113 1583 30918 -440 -13066 - 2.5 6.5 1.05 1.025 1.03 1.05 1.025 1.03 0.124 12.05 3145 10514 40942 2802 1063 4759 2661 2097 38845 -1039 -14134 2.5 6.5 1.05 1.025 1.03 0.130 12.44 3343 11252 38845 2802 1063 4759 2525 2234 36611 570 - 14704 2.5 6.5 1.05 1.025 1.03 0.137 12.83 3551 12039 36611 2802 1063 4759 2380 2379 34232 - 14768 2.5 6.5 1.05 1.025 1.03 0.144 9112 13.31 3795 12906 34232 2802 1063 4759 2225 2534 31698 508 -14260 2.5 6.5 1.05 1.025 1.03 0.151 9780 13.69 4022 13802 31698 2802 1063 4759 2060 2698 1099 -13161 2.5 6.5 1.05 1.025 1.03 0.158 10499 14.18 4288 14788 2802 1063 4759 1885 2874 26127 1764 -11397 2.5 6.5 1.05 1.025 1.03 4759 1698 3060 23066 2453 1.05 1.025 1.03 0.175 12102 15.04 16930 2802 1063 4759 1499 3259 19807 3224 -5721 2.5 6.5 1.05 1.025 1.03 0.183 12993 15.53 5132 18125 19807 2802 1063 4759 1287 3471 16335 4055 1666 2.5 6.5 1.05 1.025 1.03 26541 3169 1503 2.5 6.5 1.05 1.025 1.03 0.202 14980 16.59 5817 20797 26541 2802 1063 1295 1725 4329 22212 4153 5656 2.5 6.5 1.05 1.025 1.03 sog*o 8s7eL oles 2982 L6SSL 2982 66LL £9° <2 00°0 e2"¢ 26709 OO00LL OossL £ELSe 7102 yee 00°0 os SS78S 00011 OOssL ££S22 £199 £102 £6°02 00°0 9L79S OOOLL OOssL £ESe2 L779 2102 6S2°0 estat 6LE2 ESB 6Le2 £291 L2°6L 00°0 OOOLL oossL £ES22 bLoz 872°0 LSOL OLv2L ove LL8oL ove2 B9SL 79° 8 00°0 i9°2 giles OOOLL oosst gese2 gt09 0102 2e2°0 LOgLL SL6L 9886 SL6L SSL 9° Lb 00°0 £72 6£60S OO0LL oossL £661 Sigs L220 O980L oseL 0106 ose 797 9H 00°0 £o°2 71267 OOOLL oosst £2661 BL9S 8002 oL2°0 20001 2821 6128 28Zt abo W2°Sb 00°0 02°2 69SL9 OOOLL oosst ££661 827s 2002 L02°0 02801 2eLt ° 22d 2921 98°71 00°0 97689 OOOLL OOssL £8661 ses 281°0 tese isa 0289 tsa ozs 20°" 00°0 26°L 28277 OOOLL oossL £SELb 290S $002 62L°0 0292 2071 8929 207 922b 62°<b 00°0 98"L 68827 OOOLL OOssL £eelb 9687 L2ZL°O SEL O£Ls SEL xeeb 2s"2b 00°0 9L"b Stvly OOOLL oossL £EeZb O£L7 £002 3NI13SV8 - AINO 138310 £9L°0 oso 0276 60£L tees 0 60£L L6LL 98° LL 00°0 99"L £2009 OOOLL oossL Leet 02S” 2002 bsL°O 2785 SZOL 222? 0 SZOL LSLL bebe 00°0 2s°b OOOLL OOssL <eL7b 997 1002 970 SEs BxOl L729 Sol 2ube 2s°OL 00°0 B7"L 6l22E OOOLL OOssL £e27L L927 0002 gel°O S169 £001 226£ £001 720 00°OL 00°0 Ov"L 6019E OOOLL OOssL £eLrb 227 6661 $ LN3YYND 4O SONVSNOHL NI 3YV SLNNOWY ‘G3LON SS31NN JOUR OU OOOO UU OUUU OOOO UUUUUUUUUUUOUR UU E ae ae ae 138310 06 Nv WON 110 03W 193° OYd LNSWdOT3A30 WOO IILIYV NY3LSIM JOU UU OUR OOO OE IT - 9 HT&VL aa ae LeL"O 88S7 696 6L9E EOL £7°6 00°0 ech Lé68r7E OOOLL oOssL eli 8661 92L°0 2727 286 bigs 286 £001 £6°8 00°0 S2°b goles OOOLL OOssL £EL7b 2661 o2L°0 S26E 0022 S06 o2o¢ S06 6% £7°8 00°0 BLL ozsee OOOLL OOssL Lev Blle 9661 LLL“O CHM/$) 1SO9 °9373 687E WAOL Om. Wildvo Oz W30 110 6912 (110) 1ans 0 (1v0O9) 133 #S1s09 022 qvo1 x001 ‘110 9€6 GvO1 X00 ‘1WOD =W30 00°? <(NLsWW/$) 110 00°0 <NLSWW/$) T¥OD Zu°b = Cav9/s) 110 0 (NOL/$) WOO ?73Nd 997LE 110 = CYA/HAY 000) 0 Woo NOILONGDYd N 0001 10 cHe/nia) 00Sst WOO B1Va 13H Oo ge1zt (AX) ~110 0 (MY) WOO =ALIDVdv 26SE CMA): GVO7_G3193r0¥d W3ISAS Y3MOd 91819373 S661 ss 31Va NOILVIINI 1995 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 DH AVAIL (MMBTY/YR) 0 CAPITAL COST 0 O&M COST 0 SUPPLEMENTAL OIL HEA 2000 TOTAL 2000.0 SYSTEM OPERATING COST 5489.0 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 2517 PRICE OF HEATS/MMBTU 10.80 HEATING REVENUE 0 a TOTAL 2517 ' DEBT 7440 Ox DEBT SERVICE 675 TOTAL DEBT SERVICE 675 INTEREST 484 PRINCIPLE PAYMENT 192 ENDING BALANCE 7248 CASH FLOW -3647 CUMULATIVE CASH FLOW 3647 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 INFLATION 3.5 DISTRICT HEAT LOAD 3 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 INFLATION 1.035 DISTRICT HEAT LOAD 1.03 0.084 2736 11.38 2736 14948 675 1374 972 402 14546 -4733 ~8380 3.5 6.5 1.05 1.035 1.03 1997 1998 1999 2000 2001 2002 = 2003S 2004 = 2005 2006 212.2 218.5 225.1 231.9 238.8 246.0 253.4 261.0 268.8 276.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2368.1 2575.7 2813.8 3063.8 3347.6 3645.7 3981.3 4333.7 4727.7 5141.4 2368.1 2575.7 2813.8 3063.8 3347.6 3645.7 3981.3 4333.7 4727.7 5141.4 6615.3 7163.8 7789.0 8448.8 9194.3 10175.8 11065.6 12003.5 13049.1 14377.3 0.088 0.093 0.097 0.102 0.107 0.113 0.118 0.124 0.130 0.137 2973 3231 3511 3816 4147 4506 4897) 5323 5784 6287 12.05 12.73 13.50 14.27 15.14 16.01 16.97 17.94 19.00 20.06 2973 = 3231 3511 3816 4147) 4506 4897) 5323 5784 6287 14546 14117 1366113175. 12657-21576 9.20745. 19860-18917 += 28783 675 675 675 675 675 675 675 675 675 675 859 859 859 859 859 987 1374 1374 1374 1374 1374 2234 2234 2234 2234 3220 945 918 888 856 823 1402 1348 1291 1230 1871 429 456 486 518 551 831 885 943 1004 1349 14117 1366113175) 12657) 12106 )=— 20745 19860 18917 17913-27434 “5016 =-5307 -5652. -6006 «= 6421-7903. -8402. -8914 = -9498 «-11311 -13396 -18703 -24355 -30361 -36782 -44685 -53087 -62001 -71499 -82810 2 5 5 5 > 5 5 5 5 5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 5 3 3 3 = 3 5 3 5 3 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 27434 675 859 987 3220 1783 1437 25997 AI99L -94807 3.5 6.5 1.05 1.035 1.03 0.151 7424 22.47 7424 25997 675 859 987 3220 1690 1530 24467 12766 -107572 3.5 6.5 1.05 1.035 1.03 24467 675 699 859 987 3220 1590 1630 22837 + 13624 -121196 3.5 6.5 1.05 1.035 1.03 2010 311.6 0.0 0.166 8768 25.17 8768 35307 675 699 859 987 1132 4352 2295 2057 33250 15896 137092 3.5 6.5 1.05 1.035 1.03 26.61 9529 33250 675 699 859 987 1132 4352 2161 2190 31060 - 16883 -153976 3.5 6.5 1.05 1.035 1.03 0.183 10355 28.25 10355 31060 675 699 859 987 1132 4352 2019 2333 28727 ~ 18046 -172021 3.5 6.5 1.05 1.035 1.03 2013 340.5 0.0 0.0 9424.2 9424.2 26146.0 0.193 11254 29.89 11254 28727 675 699 859 987 1132 4352 1867 2485 26243 19243 191265 3.5 6.5 1.05 1.035 1.03 0.202 12230 31.63 12230 40553 675 69 859 987 1132 1299 5650 2636 3015 37538 -22149 213414 3.5 6.5 1.05 1.035 1.03 INFLATION RATE 3.5 1995 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) 3592 CAPACITY: COAL (KW) 0 OIL (KW) 12133 © HEAT RATE: COAL 15500 1 (BTU/KWH) OIL 11000 nN > PRODUCTION COAL 0 (000 KWH/YR) OIL 31466 FUEL: COAL ($/TON) 0 OIL ($/GAL) 1.12 COAL ($/MMBTU) 0.00 OIL ($/MMBTU) 8.00 O&M: COAL, 100% LOAD 936 OIL, 100% LOAD = 720 COSTS: FUEL (COAL) 0 FUEL (OIL) 2769 OIL 08M 720 CAPITAL 7440 TOTAL 3489 ELEC. COST ($/KWH) 0.111 1996 3718 14733 15500 11000 32570 1.18 0.00 8.43 969 905 3020 905 3925 0.120 1997 14733 15500 11000 33708 1.25 0.00 8.93 1003 937 3311 937 4267 0.126 1998 3983 14733 15500 11000 34891 1.32 0.00 9.43 1038 969 3619 969 4588 0.131 TABLE 6 - 12 FIR IIR IRI IIR IR RII RII IAAI IA III III II III III = WESTERN ARCTIC COAL DEVELOPMENT PROJECT -™ - MED OIL NOME JAN 90 DIESEL a * * IIIA IIIS III ITI ITI TAIRA IA IAAI UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ 1999 4122 14733 15500 11000 36109 1.40 0.00 10.00 1074 1003 3972 1003 4975 0.138 2000 4267 14733 15500 11000 37379 1.48 0.00 10.57 1112 1038 4347 1038 5385 0.144 DIESEL WITH DISTRICT HEAT 2001 2002 2003 4416 4570 4730 0 0 0 14733 17333 17333 15500 15500 15500 11000 11000 11000 0 0 0 38684 40033 41435 0 0 0 1.57 1.66 1.76 0.00 0.00 0.00 11.21 11.86 12.57 1151 1191 1233 1075 1309 1354 0 0 0 4772 5221 5730 1075 1309 1354 9470 5847 6530 7084 0.151 0.163 = 0.171 2004 17333 15500 11000 42889 1.86 0.00 13.29 1276 1402 6268 1402 7670 0.179 2005 5067 17333 15500 11000 44387 1.97 0.00 14.07 1320 1451 6870 1451 8321 0.187 2006 5245 19933 15500 11000 45946 0.00 14.86 1367 1727 7509 1727 10870 9236 0.201 2007 5428 19933 15500 11000 47549 2.20 0.00 15.71 1414 1787 8219 1787 10007 0.210 2008 5618 19933 15500 11000 49214 2.33 0.00 16.64 1464 1850 9010 1850 10860 0.221 2009 5815 19933 15500 11000 50939 2.47 0.00 17.64 1515 1915 1915 11801 0.232 2010 6018 22533 15500 11000 52718 2.61 0.00 18.64 1568 2240 10811 2240 12470 13051 0.248 2011 22533 15500 11000 54566 2.76 0.00 19.71 1623 2319 11833 2319 14152 0.259 2012 22533 15500 11000 56476 2.93 0.00 20.93 1680 2400 13002 2400 15401 0.273 2013 6673 22533 15500 11000 58455 3.10 0.00 22.14 1739 2484 14238 2484 16722 0.286 2014 25133 15500 11000 60497 3.28 0.00 23.43 1799 2867 15591 2867 14310 18458 0.305 1995 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 DH AVAIL (MMBTY/YR) 89.7 CAPITAL COST 7896.6 O&M COST 30 SUPPLEMENTAL OIL HEA 1103 TOTAL 1133.0 SYSTEM OPERATING COST 4622.0 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 2517 PRICE OF HEATS/MMBTU 10.80 HEATING REVENUE 2160 a TOTAL 4677 1 S DEBT 15336.6 wn DEBT SERVICE 1392 TOTAL DEBT SERVICE 1392 INTEREST 97 PRINCIPLE PAYMENT 395 ENDING BALANCE 14942 CASH FLOW -1337 CUMULATIVE CASH FLOW +1337 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 INFLATION 3.5 DISTRICT HEAT LOAD 3 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 INFLATION 1.035 DISTRICT HEAT LOAD 1.03 1996 1997 1998 1999 2000 2001 2002 2003 «82004 =92005 §8=— 200639 2007S 2008 = 2009 =. 2010 206.0 212.2 218.5 225.1 231.9 238.8 246.0 253.4 261.0 268.8 276.8 285.2 293.7 302.5 311.6 92.8 96.1 99.5 102.9 106.5 110.3 114.1 118.1 122.3 126.5 131.0 135.5 140.3 145.2 150.3 31.1 32.1 33.3 34.4 35.6 36.9 38.2 39.5 40.9 42.3 43.8 45.3 46.9 48.6 50.3 1192.2 1295.7 1403.6 1527.1 1656.0 1801.9 1954.2 2125.1 2303.5 2502.1 2709.3 2938.8 3191.7 3469.5 3759.2 1223.3 1327.8 1436.9 1561.5 1691.6 1838.8 1992.4 2164.6 2344.3 2544.4 2753.1 2984.1 3238.6 3518.1 3809.5 5147.8 5575.0 6024.9 6536.8 7076.7 7685.5 8522.5 9248.9 10014.1 10865.8 11989.0 12990.7 14098.2 15318.6 16860.6 0.084 0.088 0.093 0.097 0.102 0.107 0.113 0.118 0.124 0.130 0.137 0.144 0.151 0.158 0.166 2736 2973 3231 3511 3816 4147 4506 4897) = 55323 5784 6287 = 6831 7424 8069 = 8768 11.38 12.05 12.73 13.50 14.27 15.14 16.01 16.97 17.94 19.00 20.06 21.21 22.47 23.82 25.17 2344 2558 2782 3039 3309 = 3615 3937 = 4300 4680 5106 5553 6049 = 6599 7205 7842 5080 5531 6013 6550 7125 7763 8444 9197 10003 10890 11839 12881 14023 15274 16610 22642 «22023 21363. 20661-19913 19117 27739 =. 26592-25370 = 24069) 333553. 31798 = 29928) 27936 «= 38286 1392 1392 1392 1392 1392 1392 1392 1392 1392 1392 1392 1392 1392 1392 1392 859 859 859 859 859 859 859 859 859 987 987 987 987 987 1132 2091 2091 2091 2091 2091 2091 2950 2950 2950 2950 3937 3937) 3937 = 3937 = 55068 1472 1431 1389 1343 1294 1243 1803 1728 1649 1564 2181 2067 1945 1816 2489 619 659 702 748 796 848 1147 1222 1301 1386 1756 1870 1991 2121 2580 22023. «21363 2066119913. 19117 18269 )=—- 26592-25370 =. 24069 )=—- 22683 31798 §=—29928)— 27936 =. 25816 =. 35706 +2159 = --2135.--2103.--2077)— -2042,)--2014 = -3029- -3002) -2961 2926) -4086 )=—-4047 ) —-4012. -3981— -5319 +3495 -5630 -7733.—--9810 -11852 -13866 -16895 -19897 -22858 -25784 -29870 -33917 -37929 -41910 -47229 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 3.5 3.5 3.5 3.5 3.9 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.035 1.035 1.035 1.035 «1.035 «1.035 «1.035 «1.035 1.035 «1.035 «1.035 «1.035 1.035 1.035 1.035 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 2011 320.9 155.5 52.0 4076.0 4128.0 0.175 9529 26.61 8542 18070 35706 1392 859 987 1132 5068 2321 2748 32958 -5278 ~52507 3.5 6.5 1.05 1.035 1.03 2012 330.6 161.0 53.8 4436.5 4490.4 0.183 10355 28.25 9340 19695 32958 1392 859 987 1132 5068 2142 2926 30032 -5265 1.05 1.035 1.03 0.193 11254 29.89 10178 21433 30032 1392 859 987 1132 5068 1952 3116 26916 5226 3.5 6.5 1.05 1.035 1.03 0.202 12230 31.63 11092 23322 41226 1392 859 987 1132 1299 2680 3687 37538 ~6781 1.05 1.035 1.03 INFLATION RATE 3.5 1995 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) 3592 CAPACITY: COAL (KW) 7500 OIL (KW) 12133 © WEAT RATE: COAL 15500 1 (BTU/KWH) OIL 11000 nN PRODUCTION COAL 29893 (000 KWH/YR) OIL 1573 FUEL: COAL ($/TON) 127.33 OIL ($/GAL) 1.12 COAL ($/MMBTU) 5.31 OIL ($/MMBTU) 8.00 O&M: COAL, 100% LOAD 936 OIL, 100% LOAD 720 COSTS: FUEL (COAL) 2458 FUEL (OIL) 138 OIL 08M 108 CAPITAL 19260 TOTAL 3641 ELEC. COST ($/KWH) 0.116 1996 3718 7500 12133 15500 11000 30941 1628 131.79 1.18 5.49 8.43 745 2634 151 12 3865 0.119 1997 7500 12133 15500 11000 32023 1685 136.4 1.25 5.68 8.93 1003 771 2821 166 116 4105 0.122 1998 3983 7500 12133 15500 11000 33147 1745 141.17 1.32 5.88 9.43 1038 798 3022 181 120 4360 0.125 TABLE 6 - 13 EI II III IIIT TTI IIIT OI IAI IIIA AIA IIR i) WESTERN ARCTIC COAL DEVELOPMENT PROJECT me * NOME + ae MED OIL JAN 90 COAL ae ESIC IOI IIIS IOOII TIO IIIT TTA IIA IATA UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ COAL WITH DISTRICT HEAT 1999 2000 2001 2002 2003 2004 2005 4122 4267 4416 = 4570 4730 4896 5067 7500 7500 7500 10000 10000 10000 10000 12133-12133, 12133)-—- 12133.) 12133) 12133 12133 15500 15500 15500 15500 15500 15500 15500 11000 11000 11000 11000 11000 11000 11000 34303 35510 36750 438032 939363 40745 = 42168 1805 1869 1934 2002 2072 2144 2219 146.11 151.23 156.52 162 167.67 173.54 179.61 1.40 1.48 1.57 1.66 1.76 1.86 1.97 6.09 6.30 6.52 6.75 6.99 7.23 7.48 10.00 10.57 11.21 11.86 12.57 13.29 14.07 1074 1112 1151 1588 1643 1701 1760 826 855 885 916 948 981 1016 3237 3468 3715 3979 4263 4567 4891 199 217 239 261 286 313 344 124 128 133 137 142 147 152 11930 4634 4926 5237-5965 6335 6728 7148 0.128 0.132 0.135 0.149 0.153 0.157 0.161 2006 5245 10000 12133 15500 11000 43649 2297 185.9 2.08 7.75 14.86 1822 1051 5241 375 158 7596 0.165 2007 5428 10000 12133 15500 11000 45172 2377 192.4 2.20 8.02 15.71 1886 1088 5613 411 163 8073 0.170 2008 5618 10000 12133 15500 11000 46753 2461 199.14 2.33 8.30 16.64 1952 1126 6013 450 169 8584 0.174 2009 5815 10000 12133 15500 11000 48392 2547 206.11 2.47 8.59 17.64 2020 1165 494 175 9131 0.179 2010 6018 10000 12133 15500 11000 50082 2636 213.32 2.61 8.89 18.64 2091 1206 541 181 9712 0.184 2011 12500 12133 15500 11000 51838 2728 220.79 2.76 9.20 19.71 2705 1248 7392 592 187 16260 10876 0.199 2012 12500 12133 15500 11000 53652 2824 228.52 2.93 9.52 20.93 2800 1292 7918 650 194 11562 0.205 2013 6673 12500 12133 15500 11000 55533 236.51 3.10 9.85 22.14 2898 1337 m2 201 12293 0.210 2014 12500 12133 15500 11000 57472 244.79 3.28 10.20 3.43 1384 13072 0.216 DISTRICT HEAT SYSTEM 1995 LOAD (MMBTU/YR) 200 CAPITAL COST 2367.5 O&M COST 40 TOTAL 40.0 SYSTEM OPERATING COST 3681 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 2517 PRICE OF HEATS/MMBTU 10.80 HEATING REVENUE 2160 TOTAL 4677 a DEBT 21627.5 "DEBT SERVICE 1963 N ~s TOTAL DEBT SERVICE 1963 INTEREST 1406 PRINCIPLE PAYMENT 557 ENDING BALANCE 21070 CASH FLOW -966 CUMULATIVE CASH FLOW —-966 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 INFLATION 3.5 DISTRICT HEAT LOAD 3 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY INFLATION ‘4 DISTRICT HEAT LOAD 1.05 -035 1.03 1996 206.0 41.4 41.4 0.084 2736 11.38 2344 5080 21070 1963 1.05 1.035 1.03 1997 212.2 42.8 42.8 0.088 2973 12.05 2558 5531 1963 1963 1331 632 19845 +2336 3.5 5 6.5 1.05 1.035 1.03 1998 218.5 44.3 44.3 0.093 3231 12.73 2782 6013 19845 1963 1963 1290 673 19172 -355 -2690 3.5 6.5 1.05 1.035 1.03 1999 225.1 45.9 45.9 0.097 3511 13.50 3039 6550 19172 1963 1.05 1.035 1.03 2000 231.9 47.5 47.5 0.102 3816 14.27 3309 7125 18456 1963 1963 1200 763 17693 190 2593 3.5 6.5 1.05 1.035 1.03 2001 238.8 49.2 49.2 0.107 4147 15.14 3615 7763 17693 1963 1963 1150 813 16880 514 2079 3.5 6.5 1.05 1.035 1.03 2002 246.0 50.9 50.9 0.113 4506 16.01 3937 8444 28810 1963 1083 3046 1873 1173 27637 -618 -2697 3.5 6.5 1.05 1.035 1.03 0.118 16.97 4300 9197 27637 1963 1083 3046 1796 1249 1.05 1.035 1.03 0.124 5323 17.96 10003 1963 1083 3046 1715 1330 25057 175 +2758 3.5 6.5 1.05 1.035 1.03 268.8 56.4 56.4 0.130 5784 19.00 5106 10890 25057 1963 1083 3046 1629 1417 23641 640 “2117 3.5 6.5 1.05 1.035 1.03 0.137 6287 20.06 5553 11839 23641 1963 1083 3046 1537 1509 22132 1140 1.05 1.035 1.03 2007 285.2 0.144 6831 21.21 12881 22132 1963 1083 3046 1439 1607 20525 1702 724 3.5 6.5 1.05 1.035 1.03 2008 293.7 62.6 62.6 0.151 7424 22.47 6599 14023 20525 1963 1083 3046 1334 1711 18813 2331 3055 3.5 6.5 1.05 1.035 1.03 18813 1963 1083 3046 1223 1823 16991 3033 35 6.5 1.05 1.035 1.03 2010 311.6 67.0 67.0 0.166 8768 25.17 16610 16991 1963 1083 3046 1104 1941 15049 3785 9873 3.5 6.5 1.05 1.035 1.03 2011 320.9 69.4 69.4 0.175 9529 26.61 8542 18070 31309 1963 1083 1476 4521 2035 2486 28823 2604 12477 3.5 6.5 1.05 1.035 1.03 2012 330.6 71.8 71.8 0.183 10355 28.25 9340 19695 28823 1963 1083 1476 4521 1874 2648 26175 3540 16017 3.5 6.5 1.05 1.035 1.03 2013 340.5 74.3 74.3 0.193 11254 29.89 10178 21433 26175 1963 1083 1476 4521 1701 2820 23356 4544 20562 3.5 6.5 1.05 1.035 1.03 0.202 12230 31.63 11092 23322 23356 1963 1083 1476 4521 1518 20352 26213 3.5 6.5 1.05 1.035 1.03 INFLATION RATE 3.5 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) CAPACITY: COAL (KW) OIL (KW) SY HEAT RATE: COAL 1 (BTU/KWH) OIL N 5° PRODUCTION COAL (000 KWH/YR) OIL FUEL: COAL ($/TON) OIL ($/GAL) COAL ($/MMBTU) OIL ($/MMBTU) 08M: COAL, 100% LOAD OIL, 100% LOAD COSTS: FUEL (COAL) FUEL (OIL) OIL O&M CAPITAL TOTAL ELEC. COST ($/KWH) 1995 3592 12133 15500 11000 29893 1573 113.51 1.12 4.73 8.00 936 720 2191 138 108 19260 3374 0.107 1996 3718 7500 12133 15500 11000 30941 1628 117.49 1.18 4.90 8.43 969 745 2348 151 12 3579 0.110 1997 7500 12133 15500 11000 32023 1685 121.6 1.25 5.07 8.93 1003 771 2515 166 116 3799 0.113 1998 3983 12133 15500 11000 33147 1745 125.85 1.32 5.24 9.43 1038 798 2694 181 120 4033 0.116 TABLE 6 - 14 EIS IE EIEIO IE TOI IOITISIIIOII IIIT TOTTI TOIT IIIA ae WESTERN ARCTIC COAL DEVELOPMENT PROJECT a ae MED OIL NOME JAN 90 COAL * * * EIEIO II III TITRA IA IIIA IITA IIIA UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ COAL WITH DISTRICT HEAT 1999 2000 4122 4267 7500 7500 12133 12133 15500 15500 11000 =11000 34303-35510 1805 1869 130.26 134.82 1.40 1.48 5.43 5.62 10.00 10.57 1074 1112 826 855 2886 = 3092 199 217 124 128 4282 4549 0.119 0.122 2001 4416 7500 12133 15500 11000 36750 1934 139.54 1.57 5.81 11.21 1151 885 3312 239 133 4834 0.125 & RED DOG 2002 4570 10000 12133 15500 11000 38032 2002 144.42 1.66 6.02 11.86 1588 916 3547 261 137 11930 5534 0.138 2003 2004 4730 4896 10000 10000 12133 12133 15500 15500 11000 = 11000 39363 40745 2072 2144 149.47 154.71 1.76 1.86 6.23 6.45 12.57 13.29 1643 1701 948 981 3800 4071 286 313 142 147 5872 6233 0.142 0.145 2005 5067 10000 12133 15500 11000 42168 2219 160.12 1.97 6.67 14.07 1760 1016 4361 344 152 6617 0.149 2006 2007 = 2008 5245 5428 5618 10000 10000 10000 12133. 1213312133 15500 15500 15500 11000 11000 11000 43649 45172 46753 2297 2377 2461 165.73 171.53 177.53 2.08 2.20 2.33 6.91 7.15 7.40 14.86 15.71 16.64 1822 1886 1952 1051 1088 1126 4672 5004 5360 375 411 450 158 163 169 7027 7464 7932 0.153 0.157 0.161 2009 2010 5815 6018 10000 10000 12133-12133 15500 15500 11000 = 11000 48392 50082 2547 2636 151.92 157.24 2.47 2.61 6.33 6.55 17.64 18.64 2020 2091 1165 1206 4748 5086 494 541 175 181 7437 7898 0.146 0.150 2011 12500 12133 15500 11000 51838 2728 162.75 2.76 6.78 19.71 2705 1248 5449 592 187 16260 8933 0.164 2012 2013 C447 = 6673 12500 12500 1213312133 15500 15500 11000 11000 53652 55533 2824 2923 168.44 174.34 2.93 3.10 7.02 7.26 20.93 22.14 2800 = 2898 1292 1337 5836 = 6253 650 712 194 201 9480 10063 0.168 0.172 2014 12500 12133 15500 11000 57472 180.44 3.28 7.52 B43 1384 6697 10684 0.177 £0" S£o"b so*L So Ss 2777 ove 2S£02 £00£ Bist L2sy Ln £961 9SSte 2egge 260bL £9 LE oge2 202°0 £0"L SOL sol ] Sim LL9 - 9SES2 ozez bode lesy LL <80L £96L SLL92 £E7le BZLOL 68°62 7S2Lb £6L°0 £0°L sso"b SO"L Sg s*< 81962 2295 SLL92 7181 L2sy 927 £80L £961 S696 0786 S2°92 SSEOL £8L°0 Bl el 9° Oss 2102 £0°L SEO"L so" s9 ss 96652 2789 L2B82 soz Lesy 927 £80L £964 6O£LE 02081 27s8 t9°92 6256 SZL°O 769 7°69 6°02E LLoz £0"L Sso"L so*L So of B776L 66SS 670SL L96L 7OLL <80L £961 L669 OLOSL evel "se 898 99L°0 oZ9 ol9 OLE 0102 £0"L S£0°L SO"L s°9 sf 67BEl 92L9 L669 £2eL gee £80L £961 £1eeL £25 soz 28° S2 esto £0°L SOL so*L sg ss £216 £1eet bLdt eel 970E £801 £961 S2S02 £20971 6689 27°22 927 LsL"O 9°29 9°29 L°£62 £0°L SO°L sO"L s°9 s*¢ ovo Lise se2so2 2091 6erL 970" £801 £961 eel22 Lee2L 6709 bere b2e9 77L°0 2° S82 2002 <£0°L SOL so"L s9 se BOLL 2Lee 60S1 2st £80 £961 Ly9se 6<BLL £SSs 90°02 2829 2£1°0 78S 78S 8°92 £0" SO" so"L So Sas bate babe lyse 2byb 6291 £80L £961 25082 06801 9OLS 00°6L O£L"o 79S 79S 8°892 $002 £0°L SOL so"L s9 ss 056 129 25052 Oss SiZb £80L £961 <£000L 76° Lb £2es 72L°0 s°9S S°9s o"Lg2 £0°L S£O"L SO*L s‘9 os 622 Lez 672b 96LL £80L £961 22922 2616 00¢9 L6°9L 2687 sito 22s Les 7°ES2 £0°L S£O°L So"L iS9. 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Sl? 6° Lee 0002 £0" SEO°L sO"L s9 £ Ss s 9SLL- 6S0S¢ 62EL s9e2 7182 BBE9E 02s8 6£0E os"<L tess 260°0 6°s7 6°S? b*sez 6661 £0°L S£O°L so"L so ss 07S8- SOSL- gv2L 9772 7182 229LE £682 22h LLLS £60°0 £°99 £°97 s"sl2 £0" SOL sOo*L oo cs s£02- 20S2- LE9LE 22th £22 9769S 7182 Le2d 8Ss2 so*2k £2l7 80°0 8'e7 8°29 rar a4 2661 £0°L SeO"L SO*L s°9 se ££S9- 6SL2- OOLL 76S2 7182 6066£ L679 BELL amy 780°0 rly ry 0°902 £0°L QvO1 1V3H LO1YLSIO S£O°L NOILWIINI SO"L ALIQI819313 (001L=S66L) S3DIONI HLMOND s‘9 A3NOW JO LSO9 £ QV¥O1 1V3H 1OI1Y1SIG ss NOLLVIINI s ALIDIY19313 JO 3d1Yd (4A/S) SBLVY NOLLYIVOS3 SZZL- MO1S_ HSVD_BALLWINWNO SLLL- mold HSVO 6020 3ONV1V8 ONIONS 66L ANBWAVd 3IdIONIYd stoz AS3Y31NI 7182 BOIAY3S 1830 W1OL i 21982 301ANaS 1830 S$" LO0LE 1a3q | ‘c 2985 =Wi0L 092 3AN3A3Y ONT L3H O8"OL MLGWH/$LV3H 40 3918d zoe BAN3ARY WO1L9373 80°0 HAX/$ 9373 4O 3D18d BNN3ARY 228% 1809 ONILVY3dO W3LSAS 0°0y = Wi0L oY 1809 W30 s"2982 1800 Wildvo 00z (SA/N18WA) aVvO7 WAISAS 1V3H LOTY1SIO S664 TABLE 6 - 16 EIS III III III III TTI IITA TOI IIIT IIA II ee WESTERN ARCTIC COAL DEVELOPMENT PROJECT _ INFLATION RATE 4.5 on NOME * Sad HIGH OIL JAN 90 DIESEL ae THERIOT ITI III III IIIT TIAA II UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ DIESEL ONLY - BASELINE 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) 3806 3977 4156 4343 4538 4743 4956 5179 5412 5656 5910 CAPACITY: COAL (KW) 0 0 0 0 0 0 0 0 0 0 0 OIL (KW) 14733 14733 14733) «14733-17333. 17333. 17333. 17333 19933 19933 19933 HEAT RATE: COAL 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 & (BTu/KWH) OIL 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 ' (PRODUCTION COAL 0 0 0 0 0 0 0 0 0 0 0 (000 KWH/YR) OIL 33341 34839 36407 38045 39753 41549 43415 45368 47409 49547 51772 FUEL: COAL ($/TON) 0 0 0 0 0 0 0 0 0 0 0 OIL ($/GAL) 1.27 1.37 1.48 1.59 1.72 1.85 2.00 2.15 2.31 2.49 2.68 COAL ($/MMBTU) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 OIL (S/MMBTU) 9.07 9.79 «10.57 11.36 12.29 13.21 14.29 15.36 16.50 17.79 19.14 O&M: COAL, 100% LOAD 936 978 1022 1068 1116 1166 1219 1274 1331 1391 1454 OIL, 100% LOAD 770 805 841 879 1080 1129 1180 1233 1482 1548 1618 COSTS: FUEL (COAL) 0 0 0 0 0 0 0 0 0 0 0 FUEL (OIL) 33273750 4234 4753 5372 6039 = 6822 7664 8605 9693 10902 OIL O&M 770 805 841 879 1080 W129 1180 1233 1482 1548 1618 CAPITAL 7960 9490 11320 TOTAL 4097 4555 5074 5632 6453 7168 8002 8897 10086 =11242 12519 ELEC. COST ($/KWH) 0.123 0.131 0.139 0.148 0.162 0.173 0.184 90.196 90.213 -0.227 0.242 6176 22533 15500 11000 54102 2.88 0.00 20.57 1519 1911 12242 1911 12920 14154 0.262 2007 6454 22533 15500 11000 56537 3.11 0.00 22.21 1587 1997 13815 1997 15812 0.280 2008 6744 22533 15500 11000 59077 3.34 0.00 23.86 1659 2087 15504 2087 17591 0.298 2009 7048 25133 15500 11000 61740 3.60 0.00 25.71 1733 2433 17464 2433 14740 19896 0.322 2010 25133 15500 11000 64517 3.87 0.00 27.64 1811 2542 19618 2542 22160 0.343 2011 7697 27733 15500 11000 67426 4.17 0.00 29.79 1893 2931 22092 2931 16100 25023 0.371 2012 27733 15500 11000 70457 4.49 0.00 32.07 1978 3063 24856 3063 27919 0.396 2013 15500 11000 73628 4.83 0.00 34.50 3501 27942 3501 17580 31443 0.427 2014 8783 30333 15500 11000 76939 5.20 0.00 37.14 2160 31435 3659 35094 0.456 1995 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 DH AVAIL (MMBTU/YR) 0 CAPITAL COST 0 O&M COST 0 SUPPLEMENTAL OIL HEA 2267.9 TOTAL 2267.9 SYSTEM OPERATING COST 6365 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 2667 PRICE OF HEATS/MMBTU 12.25 £¢ HEATING REVENUE 0 TOTAL 2667 DEBT 7960 DEBT SERVICE 722 TOTAL DEBT SERVICE 722 INTEREST 517 PRINCIPLE PAYMENT 205 ENDING BALANCE 7755 CASH FLOW ~4420 CUMULATIVE CASH FLOW -4420 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 INFLATION 4.5 DISTRICT HEAT LOAD 3 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 INFLATION 1.045 DISTRICT HEAT LOAD 1.03 6431.6 6431.6 7118.9 7118.9 -10095 -12319 -13505 -14816 -17654 -19392 -21221 -14680 -20613 -28241 -36580 -45776 -55872 -68191 -81696 -96512 -114165 -133557 -154778 2009 302.5 0.0 0.0 0.158 9779 34.71 9779 45545 722 861 1027 1173 1338 5121 2161 43384 26962 -179740 4.5 6.5 1.05 1.045 1.03 2010 311.6 0.0 0.0 43384 722 861 1027 1173 5121 2820 2301 41082 -27318 207058 4.5 6.5 1.05 1.045 1.03 2011 320.9 0.0 0.0 9723.8 10766.7 11949.3 9723.8 10766.7 11949.3 57182 722 861 1027 1173 1338 1461 6583 3717 2866 54317 -31780 4.5 6.5 1.05 1.045 1.03 54317 722 861 1027 1173 1338 1461 6583 3531 3052 51265 ~ 34835 273673 4.5 6.5 1.05 1.045 1.03 68845 722° 861 1027 1173 1338 1461 1595 8178 4475 3703 65141 -40129 -313802 4.5 6.5 1.05 1.045 1.03 0.202 15554 50.14 15554 65141 722 861 1027 1173 1338 1461 1595 8178 4234 3944 61198 ~44001 ~357803 4.5 6.5 1.05 1.045 1.03 INFLATION RATE ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) CAPACITY: COAL (KW) OIL (KW) HEAT RATE: COAL oO (BTU/KWH) OIL ' os PRODUCTION COAL = (000 KWH/YR) OIL FUEL: COAL ($/TON) OIL (¢$/GAL) COAL ($/MMBTU) OIL ($/MMBTU) O&M: COAL, 100% LOAD OIL, 100% LOAD COSTS: FUEL (COAL) FUEL (OIL) OIL O&M CAPITAL TOTAL ELEC. COST ($/KWH) 4.5 1995 3806 14733 15500 11000 33341 1.27 0.00 9.07 936 770 3327 770 7960 4097 0.123 1996 3977 14733 15500 11000 34839 1.37 0.00 9.79 978 805 3750 805 4555 0.131 TABLE 6 - 17 IRE ICI IIIT TOI IOI III IOI IO TOTTI III IAAI ow WESTERN ARCTIC COAL DEVELOPMENT PROJECT sins * NOME 7 wi HIGH OIL JAN 90 DIESEL Cs EIEIO TIO II III TIAA ITA IAA IAAI IIIA UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ DIESEL WITH DISTRICT HEAT 1997 1998 1999 2000 2001 2002 2003 2004 2005 4156 4343 4538 = 4743 4956 5179 5412 5656 5910 0 0 0 0 0 0 0 0 0 14733, 14733-17333) 17333. 17333.) 17333 19933 19933 19933 15500 15500 15500 15500 15500 15500 15500 15500 15500 11000 11000 11000 11000 11000 11000 11000 11000 11000 0 0 0 0 0 0 0 0 0 36407 = 38045 39753) 41549 943415 45368 «= 47409 49547 = 51772 0 0 0 0 0 0 0 0 0 1.48 1.59 1.72 1.85 2.00 2.15 2.31 2.49 2.68 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 10.57 11.36 «12.29 13.21 14.29 15.36 16.50 17.79 19.14 1022 1068 1116 1166 1219 1274 1331 1391 1454 841 879 1080 1129 1180 1233 1482 1548 1618 0 0 0 0 0 0 0 0 0 4234 4753 5372 6039 6822 7664 8605 9693 10902 841 879 1080 1129 1180 1233 1482 1548 1618 9490 11320 5074 5632 6453 7168 8002 8897 10086 §=11242 12519 0.139 0.148 0.162 0.173 0.184 0.196 90.213 «0.227 0.242 2006 6176 22533 15500 11000 54102 2.88 0.00 20.57 1519 1911 12242 1911 12920 14154 0.262 2007 6454 22533 15500 11000 56537 3.11 0.00 22.21 1587 1997 13815 1997 15812 0.280 2008 6744 22533 15500 11000 59077 0.00 23.86 1659 2087 15504 2087 17591 0.298 2009 25133 15500 11000 61740 3.60 0.00 25.71 1733 2433 17464 2433 14740 19896 0.322 2010 7365 25133 15500 11000 64517 3.87 0.00 27.64 1811 2542 19618 22160 0.343 2011 7697 27733 15500 11000 67426 4.17 0.00 29.79 1893 22092 16100 25023 0.371 2012 27733 15500 11000 70457 4.49 0.00 32.07 1978 3063 24856 3063 27919 0.396 2013 8405 30333 15500 11000 73628 4.83 0.00 34.50 3501 27942 3501 17580 31443 0.427 2014 8783 30333 15500 11000 76939 5.20 0.00 37.14 1995 1996 1997 1998 1999 = 2000 2001 2002 ©2003 2004 2005 2006 §=62007- 2008 )3=— 2009S 2010S 2011 2012-2013 2014 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 206.0 212.2 218.5 225.1 231.9 238.8 246.0 253.4 261.0 268.8 276.8 285.2 293.7 302.5 311.6 320.9 330.6 340.5 350.7 DH AVAIL (MMBTU/YR) 95.1 99.4 103.9 108.5 113.4 118.5 123.8 129.4 135.2 141.3 147.7 154.3 161.3 168.5 176.1 184.0 192.3 201.0 210.0 219.5 CAPITAL COST 8528.1 O&M COST 30, 31.60 «32.8 = 34.20 35.68 387.439. 40.8 42.7 44.6 46.6 48.7 50.9 53.2 55.6 58.1 60.7 63.4 66.3 69.2 SUPPLEMENTAL OIL HEA 1189.5 1304.2 1431.5 1561.9 1715.3 1872.2 2053.0 2237.5 2436.1 2659.6 2897.7 3150.3 3439.7 3732.8 4062.8 4407.2 4788.6 5195.1 5626.1 6092.5 TOTAL 1219.5 1335.5 1464.2 1596.1 1751.1 1909.6 2092.0 2278.3 2478.7 2704.1 2944.2 3199.0 3490.6 3785.9 4118.4 4465.3 4849.2 5258.5 5692.4 6161.8 SYSTEM OPERATING COST 5316 5890 6539 7228 8204 9078 10094 11175 12565 13946 15464 17353 19303 21377 24015 26625 29872 33178 37135 41256 REVENUE PRICE OF ELEC $/KWH 0.08 0.084 0.088 0.093 0.097 0.102 0.107 0.113 0.118 0.124 0.130 0.137 0.144 0.151 0.158 0.166 0.175 0.183 0.193 0.202 ELECTRICAL REVENUE 2667 = 2926 3211 3523 3866 4242 4654 5107 5604 6149 6746 7403-8123 8912 9779 10730 «11775 «12919 = 14176 =: 15554 PRICE OF HEATS/MMBTU 12.25 13.21 14.27 15.33 16.59 17.84 19.29 20.73 22.28 24.01 25.84 27.77 29.99 32.21 34.71 37.32 40.21 43.30 46.58 50.14 HEATING REVENUE 2449 = 2721 3028 3351 3733 4136 4606 5100 5643 6266 6946 7688 = 8552 9459 10502 11628 12905 14312 15858 17585 TOTAL 5117 5648 6239 6874 7599 = 8378 = 9260 10207 11247) 12415 13693 15091 16674 + =18371 20281-22358 «= 24680) 27232) 30034 «= «33139 DEBT 16488.1 16063 15611 15129 24106 = 23316) 22474 «21577 31941 30633-29239 = 40674 «= 3876036722 «= 49292 46600 59834 56366 70254 65868 DEBT SERVICE 1496 1496 1496 1496 1496 1496 1496 1496 1496 1496 1496 1496 1496 1496 1496 1496 1496 1496 1496 1496 861 861 861 861 861 861 861 861 861 861 861 861 861 861 861 861 1027 1027 1027 1027 1027 1027 1027 1027 1027 1027 1027 1027 1173 1173 1173 1173 1173 1173 1173 1173 1173 1338 1338 1338 1338 1338 1338 1461 1461 1461 1461 Se 1595 1595 TOTAL DEBT SERVICE 1496 1496 1496 1496 2358 2358 2358 2358 3385 3385 3385 4558 4558 = 4558 5895 5895 7357 = 7357) 8952 8952 INTEREST 1072 1044 1015 983 1567 1516 1461 1402 2076 1991 1901 2644 2519 2387 3204 3029 = 3889 3664 4566 4281 PRINCIPLE PAYMENT 425 452 482 513 71 842 897 955 1309 1394 1485 1914 2038 2171 2691 2866 «= 3467 3693 4386 9 4671 ENDING BALANCE 16063 15611-15129 14616-23316 9.22474 «= 21577 =. 20621 30633 «29239-27754 += 38760 36722-34552 46600 943734 += 56366 52674 «65868 «61198 CASH FLOW -1696 -1739--1796 1850-2962, -3057-— -3192. -3326- -4703-— -4916 -5156 -6819- -7186 = -7563 = -9629--10162 -12549 -13303 -16054 -17069 CUMULATIVE CASH FLOW -1696 -3435 5231-7081 -10043 -13101 -16292 -19618 -24321 -29237 -34394 -41213 -48399 -55962 -65591 -75754 -88302 -101605 -117659 -134727 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 a 5 5 2 5 5 5 5 5 - 5 5 DB 5 5 5 > S 5 INFLATION 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 S35 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 DISTRICT HEAT LOAD = 3 3 3 3 3 3 3 = 3 2 3 S 3 s > 3 2 3 3 COST OF MONEY 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 INFLATION 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.065 1.045 1.065 1.065 1.045 1.045 1.045 1.045 1.045 1.045 1.045 DISTRICT HEAT LOAD 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 INFLATION RATE ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) CAPACITY: COAL (KW) OIL (KW) HEAT RATE: COAL (BTU/KWH) OIL ' PRODUCTION COAL (000 KWH/YR) OIL FUEL: COAL ($/TON) OIL ($/GAL) COAL ($/MMBTU) OIL = ($/MMBTU) O&M: COAL, 100% LOAD OIL, 100% LOAD COSTS: FUEL (COAL) FUEL (OIL) OIL O&M CAPITAL TOTAL ELEC. COST ($/KWH) 4.5 1995 3806 7500 12133 15500 11000 31674 1667 136.2 1.27 5.68 9.07 936 770 2786 166 116 19260 4004 0.120 1996 3977 7500 12133 15500 11000 33097 1742 142.32 1.37 5.93 9.79 936 805 3042 188 121 4286 0.123 1997 4156 7500 12133 15500 11000 34586 1820 148.73 1.48 6.20 10.57 841 3322 212 126 4596 0.126 1998 4343 7500 12133 15500 11000 36142 1902 155.42 1.59 6.48 11.36 936 879 132 4933 0.130 TABLE 6 - 18 EI III IIIT ITI IIIT OI II AI II III I IAI IIASA IAA. a WESTERN ARCTIC COAL DEVELOPMENT PROJECT es NOME ee HIGH OIL JAN 90 COAL EI IIIS IO III TI III ITO TIT I AIA TI T IAAI IAD UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ COAL WITH DISTRICT HEAT ** * * 1999 2000 2001 2002 2003 2004 2005 4538 4743 4956 5179 5412 5656 5910 10000 10000 10000 10000 10000 10000 10000 12133, 12133-12133) 12133, 12133) 12133) 12133 15500 15500 15500 15500 15500 15500 15500 11000 11000 11000 11000 11000 11000 11000 37765 = 39471 41244 «= 43100 45039 = 47069 = 49183 1988 2077-2171 2268 2370 2477 = 2589 162.42 169.72 177.36 185.34 193.68 202.4 211.51 1.72 1.85 2.00 2.15 2.31 2.49 2.68 6.77 7.07 7.39 7.72 8.07 8.43 8.81 12.29, 13.21 14.29 15.36 16.50 17.79 19.14 1248 1248 1248 1248 1248 1248 1248 918 960 1003 1048 1095 1144 1196 3961 4326 4724 5159 5634 6153 6718 269 302 341 383 430 485 545 138 144 150 157 164 172 179 11180 5616 6020 6464 6947 7476 8057 8691 0.141 0.145 0.149 0.153 0.158 0.163 0.168 2006 6176 12500 12133 15500 11000 51397 2705 221.02 2.88 9.21 20.57 1560 1250 7336 612 187 15210 9696 0.179 2007 6454 12500 12133 15500 11000 53710 2827 230.97 3.11 9.62 22.21 1560 1306 8012 691 196 10458 0.185 2008 6744 12500 12133 15500 11000 56124 2954 241.36 3.34 10.06 23.86 1560 1365 8748 205 11288 0.191 2009 12500 12133 15500 11000 58653 3087 252.23 3.60 10.51 25.71 1560 1426 9555 873 214 12202 0.198 2010 12500 12133 15500 11000 61292 3226 263.58 3.87 10.98 27.64 1560 1490 10434 981 224 13198 0.205 2011 7697 15000 12133 15500 11000 64054 3371 275.44 4.17 11.48 29.79 1872 1557 11395 1105 18960 14605 0.217 2012 15000 12133 15500 11000 3523 287.83 4.49 11.99 32.07 1872 1627 12442 1243 264 15801 0.224 2013 17500 12133 15500 11000 699466 3681 300.78 4.83 12.53 34.50 2184 1701 13587 1397 255 20700 17424 0.237 2014 8783 17500 12133 15500 11000 73092 3847 314.32 5.20 13.10 37.14 2184 1777 14838 1572 267 18860 0.245 1995 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 CAPITAL COST 2367.5 O&M COST 40 TOTAL 40.0 SYSTEM OPERATING COST 4044 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 2667 PRICE OF HEATS/MMBTU 12.25 HEATING REVENUE 2449 TOTAL 5117 a 1 DEBT 21627.5 jy DEBT SERVICE 1963 I TOTAL DEBT SERVICE 1963 INTEREST 1406 PRINCIPLE PAYMENT 557 ENDING BALANCE 21070 CASH FLOW -890 CUMULATIVE CASH FLOW = - 890 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 INFLATION 4.5 DISTRICT HEAT LOAD 3 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 INFLATION 1.045 DISTRICT HEAT LOAD 1.03 1996 206.0 41.8 41.8 0.084 2926 13.21 2721 5648 21070 1963 1.05 1.045 1.03 1997 212.2 43.7 43.7 0.088 3211 14.27 3028 6239 1963 1963 1331 632 19845 1897 4.5 6.5 1.05 1.045 1.03 1998 218.5 45.6 45.6 0.093 3523 15.33 3351 6874 19845, 1963 1963 1290 673 19172 1964 4.5 6.5 1.05 1.045 1.03 1999 225.1 47.7 47.7 0.097 16.59 3733 7599 30352 1963 1015 2977 1973 1005 29348 -1042 6.5 1.05 1.045 1.03 231.9 49.8 49.8 0.102 4262 17.84 4136 8378 29348 1963 1015 2977 1908 1070 28278 +3676 4.5 6.5 1.05 1.045 1.03 1015 2977 1838 1139 27139 =233 1.05 1.045 1.03 2002 246.0 54.4 54.4 0.113 5107 20.73 5100 10207 27139 1963 1015 2977 1764 1213 25925 227 4.5 6.5 1.05 1.045 1.03 2003 253.4 56.9 56.9 0.118 5604 22.28 5643 11247 25925 1963 1015 2977 1685 1292 24633 737 1.05 1.045 1.03 0.124 6149 24.01 6266 12415 24633 1963 1015 2977 1601 1376 23256 1321 -1624 4.5 6.5 1.05 1.045 1.03 268.8 62.1 0.130 6746 25.84 6946 13693 23256 1963 1015 2977 1512 1466 21791 1962 338 4.5 6.5 1.05 1.045 1.03 0.137 7403 27.77 7688 15091 37001 1963 1015 1380 4358 2405 1953 35048 972 1310 4.5 6.5 1.05 1.045 1.03 0.144 8123 29.99 8552 16674 35048 1963 1015 1380 4358 2278 2080 32968 1790 3100 4.5 6.5 1.05 1.045 1.03 0.151 8912 32.21 9459 18371 32968 1963 1015 1380 4358 2143 2215 30753 2654 5754 4.5 6.5 1.05 1.045 1.03 0.158 9779 34.71 10502 20281 30753 1963 1015 1380 4358 1999 2359 28394 3647 9402 4.5 6.5 1.05 1.045 1.03 2010 311.6 0.166 10730 37.32 11628 22358 1963 1015 1380 4358 1846 2512 25882 4725 14126 4.5 6.5 1.05 1.045 1.03 2011 320.9 80.9 80.9 0.175 1775 40.21 12905 24680 44842 1963 1015 1380 1721 6079 2915 3164 41678 3916 18042 4.5 6.5 1.05 1.045 1.03 2012 330.6 0.183 12919 43.30 14312 27232 41678 1963 1015 1380 1721 6079 2709 3370 5267 23309 4.5 6.5 1.05 1.045 1.03 2013 340.5 0.193 146176 46.58 15858 30034 1963 1015 1380 1721 1879 4122 54886 4565 27874 4.5 6.5 1.05 1.045 1.03 2014 350.7 92.3 92.3 0.202 15554 50.14 17585 33139 1963 1015 1380 1721 1879 3568 4390 50497 34103 4.5 6.5 1.05 1.045 1.03 TABLE 6 - 19 ISERIES IIIA III I TIT IRR I ee WESTERN ARCTIC COAL DEVELOPMENT PROJECT - INFLATION RATE 4.5 ae NOME ae Pe HIGH OIL JAN 90 COAL oe PERERA ARR REAR RR ER ER ERR ER ERR ERR ER ER ERE UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ COAL WITH DISTRICT HEAT & RED DOG 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) 3806 3977 4156 4343 4538 = 4743 4956 5179 5412 5656 = 5910 6176 6454 6744 = 7048 = 7365 7697 = 8043S 8405 8783. CAPACITY: COAL (KW) 7500 7500 7500 7500 10000 10000 10000 10000 10000 10000 10000 12500 12500 12500 12500 12500 15000 15000 17500 17500 OIL (KW) = 12133) 1213312133, 12133) 12133, 12133-12133, 12133) 12133-12133) 1213312133) 12133) 12133, 1213312133. 1213312133) 1213312133 oO HEAT RATE: COAL 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 (BTU/KWH) OIL 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 es PRODUCTION COAL 31674 33097 34586 36142 37765 39471 41244 943100 45039 «47069 «4918351397 53710 56124 58653 61292 64054 66934 69046 73092 (000 KWH/YR) OIL 1667 1742 1820 1902 1988 2077 2171 2268 =. 2370 2477 2589 =. 2705 2827 2954 3087 3226 020-3371 3523-3681 3847 FUEL: COAL ($/TON) 121.42 126.88 132.59 138.56 144.79 151.31 158.12 165.23 172.67 180.44 188.56 162.92 170.25 177.91 185.92 194.28 203.03 212.16 221.71 231.69 OIL ($/GAL) 1.27 1.37 1.48 1.59 1.72 1.85 2.00 2.15 2.31 2.49 2.68 2.88 3.11 3.34 3.60 3.87) 4.17) 4.49 4.83 5.20 COAL ($/MMBTU) 5.06 5.29 5.52 5.77 6.03 6.30 6.59 6.88 TotD) || ve9e 7.86 6.79 7.09 7.41 7.75 8.10 8.46 8.84 9.24 9.65 OIL ($/MMBTU) 9.07 9.79 10.57 11.36 12.29 13.21 14.29 15.36 16.50 17.79 19.14 20.57 22.21 23.86 25.71 27.64 29.79 32.07 34.50 37.14 O&M: COAL, 100% LOAD 936 936 936 936 1248 1248 1248 1248 1248 1248 1248 1560 1560 1560 1560 1560 1872 1872 2184 2184 OIL, 100% LOAD 770 805 841 879 918 960 1003 1048 1095 1144 1196 1250 1306 1365 1426 1490 1557 1627 1701 1777 COSTS: FUEL (COAL) 2484 2712 2962 3234 3531 38574212, 4599 5023 5485 5989 5408 5906 = 6449 7043 7690 8399 = 9171-10015 10937 FUEL (OIL) 166 188 212 238 269 302 341 383 430 485 545 612 691 775 873 981 1105 1243 1397 1572 OIL O&™ 116 121 126 132 138 144 150 157 164 172 179 187 196 205 214 224 234 244 255 267 CAPITAL 19260 11180 15210 18960 20700 TOTAL 3702 3956 4235 4540 5186 5551 5951 6388 6865 7389 7962 7767 = 8352 8988 = 9690» 10455 11609 12530 13852. 14959 ELEC. COST ($/KWH) 0.111 0.194 0.116 0.119 0.130 0.134 0.137 0.141 0.145 0.149 0.154 0.144 0.148 §=—0.152 0.157 0.162 0.172 0.178 0.188 0.194 1995 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 CAPITAL COST 2367.5 O&M COST 40 TOTAL 40.0 SYSTEM OPERATING COST 3742 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 2667 PRICE OF HEATS/MMBTU 12.25 HEATING REVENUE 2449 TOTAL = 5117 DEST 21627.5 DEBT SERVICE 1963 TOTAL DEBT SERVICE 1963 INTEREST 1406 PRINCIPLE PAYMENT 557 ENDING BALANCE 21070 CASH FLOW ~588 CUMULATIVE CASH FLOW 588 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY > INFLATION 4.5 DISTRICT HEAT LOAD Ss COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 INFLATION 1.045 DISTRICT HEAT LOAD 1.03 1996 206.0 41.8 41.8 0.084 13.21 2721 5648 21070 1963 1963 1370 593 -313 1.05 1.045 1.03 1997 212.2 43.7 43.7 1331 4.5 6.5 1.05 1.045 1.03 1998 218.5 45.6 45.6 0.093 3523 15.33 3351 6874 19845 1963 1963 1290 673 19172 326 1.05 1.045 1.03 1999 225.1 47.7 47.7 0.097 16.59 3733 7599 30352 1963 1015 2977 1973 1005 29348 -612 -1190 4.5 6.5 1.05 1.045 1.03 231.9 49.8 49.8 0.102 4242 17.84 4136 8378 29348 1963 1015 2977 1908 1070 28278 -200 1390 4.5 6.5 1.05 1.045 1.03 2001 238.8 52.1 52.1 0.107 4654 19.29 4606 9260 1963 1015 2977 1838 1139 27139 279 71111 4.5 6.5 1.05 1.045 1.03 2002 246.0 54.4 54.4 0.113 5107 20.73 5100 10207 27139 1963 1015 2977 1764 1213 25925 787 1.05 1.045 1.03 2003 253.4 0.118 5604 22.28 5643 11247 25925 1963 1015 1685 1292 24633 1348 1024 4.5 6.5 1.05 1.045 1.03 2004 261.0 59.4 59.4 0.124 6149 24.01 6266 12415 24633 1963 1015 2977 1601 1376 23256 1988 3012 4.5 6.5 1.05 1.045 1.03 0.130 6746 25.84 13693 23256 1963 1015 2977 1512 1466 21791 2691 5703 4.5 6.5 1.05 1.045 1.03 2006 276.8 64.9 64.9 0.137 7403 27.77 7688 15091 37001 1963 1015 1380 4358 2405 1953 35048 2901 4.5 6.5 1.05 1.045 1.03 2007 285.2 67.8 67.8 0.144 8123 29.99 8552 16674 35048 1963 1015 1380 4358 2278 2080 12500 4.5 6.5 1.05 1.045 1.03 2008 293.7 0.151 8912 32.21 9459 18371 1963 1015 1380 4358 2143 2215 30753 4954 17454 4.5 6.5 1.05 1.045 1.03 2009 302.5 74.1 74.1 0.158 9779 34.71 10502 20281 30753 1963 1015 1380 4358 1999 2359 28394 6159 23614 4.5 6.5 1.05 1.045 1.03 2010 311.6 0.166 10730 37.32 11628 22358 1963 1015 1380 4358 1846 2512 7468 31082 4.5 6.5 1.05 1.045 1.03 2011 320.9 0.175 11775 40.21 12905 24680 44842 1963 1015 1380 1721 6079 2915 3164 41678 6911 37993 4.5 6.5 1.05 1.045 1.03 0.183 12919 43.30 14312 27232 41678 1963 1015 1380 1721 6079 2709 3370 8538 46531 4.5 6.5 1.05 1.045 1.03 2013 340.5 0.193 14176 46.58 15858 59008 1963 1015 1380 1721 1879 797 3836 4122 54886 8136 54667 4.5 6.5 1.05 1.045 1.03 0.202 15554 50.14 17585 33139 1963 1015 1380 1721 1879 7957 3568 4390 50497 10130 64797 4.5 6.5 1.05 1.045 1.03 INFLATION RATE ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) CAPACITY: COAL (KW) OIL (KW) O’HEAT RATE: | (BTU/KWH) > © PRODUCTION (000 KWH/YR) COAL OIL COAL OIL FUEL: COAL ($/TON) OIL (¢$/GAL) COAL ($/MMBTU) OIL = ($/MMBTU) 8M: COAL, 100% LOAD OIL, 100% LOAD COSTS: FUEL (COAL) FUEL (OIL) OIL O&M CAPITAL TOTAL ELEC. COST ($/KWH) 4.5 1995 5495 12500 19333 15500 11000 45729 2407 100.39 1.27 4.18 9.07 1560 770 2965 240 116 38020 4881 0.101 1996 1997 5895 6421 12500 = =12500 19333 19333 15500 15500 11000 = 11000 49058 53436 2582 2812 104.91 109.63 1.37 1.48 4.37 4.57 9.79 10.57 1560 1560 805 841 3324 3783 278 327 121 126 5283 5797 0.102 0.103 1998 6675 12500 19333 15500 11000 55549 114.56 1.59 4.77 11.36 1560 879 4110 365 132 6167 0.105 TABLE 6 - 20 FEI III IIR TTI IA II IOI IIIT III II ITI AIA IAI IAAI IAI -” -” - HIGH OIL NOME JAN 90 WESTERN ARCTIC COAL DEVELOPMENT PROJECT COAL “ RII IR IR IRI IAAI IRR AAARARII UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ 1999 15000 19333 15500 11000 57755 3040 119.72 1.72 4.99 12.29 1872 918 4466 411 138 11180 6886 0.113 2000 7218 15000 19333 15500 11000 60068 3161 125.11 1.85 5.21 13.21 1872 960 4854 460 144 7329 0.116 COAL WITH DISTRICT HEAT RED DOG & GOLD CO 2001 2002 2003 7507 7810 8127 15000 15000 15000 19333 19333 19333 15500 15500 15500 11000 11000 11000 62473 64995 67633 3288 = 3421 3560 130.73 136.62 142.77 2.00 2.15 2.31 5.45 5.69 5.95 14.29 15.36 16.50 1872 1872 1872 1003 1048 1095 5275 5735 6236 517 578 646 150 157 164 7814 8342 8918 0.119 0.122 0.125 2004 8458 17500 19333 15500 11000 70387 3705 149.19 2.49 6.22 17.79 2184 1144 6782 725 172 13930 9862 0.133 2005 8803 17500 19333 15500 11000 73259 3856 155.9 2.68 6.50 19.14 2184 1196 7376 812 179 10551 0.137 2006 9165 17500 19333 15500 11000 76271 4014 162.92 2.88 6.79 20.57 2184 1250 8025 908 187 11305 0.141 2007 17500 19333 15500 11000 4179 170.25 3.11 7.09 22.21 2184 1306 8731 1021 196 12132 0.145 2008 20000 19333 15500 11000 82687 4352 177.91 3.34 7.41 23.86 2496 1365 9501 1142 205 16610 13344 0.153 2009 10349 20000 19333 15500 11000 86124 4533 185.92 3.60 7.75 25.71 2496 1426 10341 1282 214 14333 0.158 2010 10779 19333 15500 11000 89703 4721 194.28 3.87 8.10 27.64 2808 1490 11255 1436 224 18140 15722 0.167 2011 11230 19333 15500 11000 4919 203.03 4.17 8.46 29.79 2808 1557 12254 1612 16907 0.172 2012 11700 25000 19333 15500 11000 97367 5125 212.16 4.49 8.84 32.07 3120 1627 13341 1808 244 19810 18513 0.181 2013 12192 25000 19333 15500 11000 101462 5340 198.57 4.83 8.27 34.50 3120 1701 13012 2027 255 18413 0.172 2014 12705 19333 15500 11000 105731 5565 207.5 5.20 8.65 37.14 3432 1777 14169 2274 267 21640 20141 0.181 1995 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 CAPITAL COST 2367.5 O&M COST 40 TOTAL 40.0 SYSTEM OPERATING COST 4921 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 3851 PRICE OF HEATS/MMBTU 12.25 HEATING REVENUE 2449 TOTAL 6300 DEBT 40387.5 1 DEBT SERVICE 3665 > _ TOTAL DEBT SERVICE 3665 INTEREST 2625 PRINCIPLE PAYMENT 1040 ENDING BALANCE 39347 CASH FLOW 2286 CUMULATIVE CASH FLOW 2286 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 INFLATION 4.5 DISTRICT HEAT LOAD 3 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 INFLATION 1.045 DISTRICT HEAT LOAD 1.03 0.084 4338 13.21 2721 2558 1108 38239 71931 ~4216 4.5 6.5 1.05 1.045 1.03 0.088 4961 14.27 3028 2486 1180 37060 -1516 *5735 4.5 6.5 1.05 1.045 1.03 0.093 5415 15.33 3351 8766 37060 2409 1257 35803 71112 1.05 1.045 1.03 0.097 5912 16.59 3733 9645 46983 3665 1015 4680 3054 1626 45357 +1969 ~8814 4.5 6.5 1.05 1.045 1.03 0.102 6456 17.84 4136 10592 45357 1015 2948 1732 43625 -1467 -10281 4.5 6.5 1.05 1.045 1.03 0.107 19.29 11656 43625 1015 2836 1844 41780 -890 tiie 4.5 6.5 1.05 1.045 1.03 0.113 7701 20.73 5100 12801 41780 1015 4680 2716 1964 39816 -11446 4.5 6.5 1.05 1.045 1.03 0.118 8415 22.28 5643 14058 39816 3665 1015 4680 2588 2092 37724 403 - 11043 4.5 6.5 1.05 1.045 1.03 0.124 9195 24.01 6266 15461 51654 3665 1015 1264 5944 3358 2587 49067 -405 -11448 4.5 6.5 1.05 1.045 1.03 0.130 10049 25.84 6946 16995 49067 1015 1264 5944 3189 2755 46312 437 -11011 4.5 6.5 1.05 1.045 1.03 0.137 10985 27.77 7688 18674 46312 1015 1264 5944 3010 2934 43378 1359 9652 4.5 6.5 1.05 1.045 1.03 0.144 12009 29.99 8552 20560 43378 1015 1264 5944 2820 3125 40254 2416 4.5 6.5 1.05 1.045 1.03 0.151 13130 32.21 9459 22590 1015 1264 1507 7452 3756 53108 1723 -5512 4.5 6.5 1.05 1.045 1.03 0.158 14360 34.71 10502 24861 53108 1015 1264 1507 7452 3452 4000 49108 3002 -2510 4.5 6.5 1.05 1.045 1.03 0.166 15704 37.32 11628 27332 67248 1015 1264 1507 1646 4371 4727 62521 2434 -76 4.5 6.5 1.05 1.045 1.03 0.175 17179 40.21 12905 62521 1015 1264 1507 1646 4064 5034 57487 3998 3922 4.5 6.5 1.05 1.045 1.03 0.183 18793 43.30 14312 33106 77297 1015 1264 1507 1646 1798 10896 5024 5872 71425 3612 7534 4.5 6.5 1.05 1.045 1.0% 0.193 46.58 15858 36421 71425 1015 1264 1507 1646 1798 1.05 1.045 0.202 22499 50.14 17585 40084 86812 1015 1264 1507 1646 1798 1964 12860 5643 7217 6991 21547 4.5 6.5 1.05 1.045 INFLATION RATE 2.5 1995 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) 2366 CAPACITY: COAL (KW) 0 OIL (KW) 7235 HEAT RATE: COAL 15500 (BTU/KWH) OIL 11000 ' = PRODUCTION COAL 0 (000 KWH/YR) OIL 20726 FUEL: COAL ($/TON) 0 OIL ($/GAL) 0.94 COAL ($/MMBTU) 0.00 OIL ($/MMBTU) 6.71 O&M: COAL, 100% LOAD 649 OIL, 100% LOAD 394 COSTS: FUEL (COAL) 0 FUEL (OIL) 1531 COAL O&M 0 OIL O&M 394 CAPITAL 0 TOTAL 1925 ELEC. COST ($/KWH) 0.093 1996 2431 15500 11000 21296 0.97 0.00 6.93 665 404 1623 404 2027 0.095 1997 2496 15500 11000 21865 0.00 7.14 414 1718 414 2132 0.098 TABLE 6 - 21 EIEIO IOI IIIT IR II II IAA IAAI AI SAIS ISA ng WESTERN ARCTIC COAL DEVELOPMENT PROJECT = ae KOTZEBUE ed =e LOW OIL FEB 90 DIESEL a EISSN III ISI III ITO III III TIT SII SII AIIM UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ KOTZEBUE - DIESEL 1998 1999 2000 2001 2002 2003 2004 2005 2563 2632 2703 2776 = 2851 2928 3007 = 3088 0 0 0 0 0 0 0 0 7235 7235 7235 7235 7235 7235 7235 7235 15500 15500 15500 15500 15500 15500 15500 15500 11000 §=©11000 =11000 11000 11000 11000 11000 11000 0 0 0 0 0 0 0 0 22452 23056 §9= 23678 «= 24318 9 24975-25649 =. 26341 27051 0 0 0 0 0 0 0 0 1.03 1.07 1.10 1.14 1.17 1.21 1.25 1.29 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 7.36 7.64 7.86 8.14 8.36 8.64 8.93 9.21 699 716 734 753 71 791 811 831 424 435 446 457 468 480 492 504 0 0 0 0 0 0 0 0 1817 1938 2046 2178 2296 2439 2587 2742 0 0 0 0 0 0 0 0 424 435 446 457 468 480 492 504 2241 2373 2492 2635 2764 2919 = 3079 = 3246 0.100 0.103 0.105 0.108 0.111 0.114 0.117 0.120 2006 3172 15500 11000 27787 1.33 0.00 9.50 852 517 3421 0.123 2007 3257 15500 11000 28531 1.38 0.00 9.86 873 530 3094 530 3623 0.127 2008 3345 15500 11000 29302 1.42 0.00 10.14 543 3269 543 3812 0.130 2009 3436 15500 11000 1.47 0.00 10.50 917 557 3476 557 4033 0.134 2010 3528 15500 11000 1.51 0.00 10.79 940 571 3667 571 4237 0.137 2011 15500 11000 31766 1.56 0.00 11.14 963 585 0 3891 0 585 4476 0.141 2012 3721 15500 11000 0.00 11.50 600 4123 0 600 4723 0.145 2013 15500 11000 33481 1.66 0.00 11.86 1012 615 4367 615 4981 0.149 2014 3925 15500 11000 34383 1.72 0.00 12.29 5276 0.153 1995 1996 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 206.0 CAPITAL COST 0 O&M COST 0 0.00 TOTAL 0 0.00 SYSTEM COST 1924.77 2026.88 REVENUE PRICE OF ELEC $/KWH 0.08 0.084 ELECTRICAL REVENUE 1658 = 1789 PRICE OF HEATS/MMBTU 10.07 9.35 COST OF HEAT 2014 1927 TOTAL 1658 1789 by ;CUMULATIVE CASH FLOW +2281 -4445.9 > a ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 5 O&M een 2.5 DISTRICT HEAT LOAD 3 > GROWTH INDICES (1995=100) ELECTRICITY 1.05 1.05 O&M 1.025 1.025 DISTRICT HEAT LOAD 1.03 1.03 1997 212.2 0.00 0.00 2131.91 0.088 1928 9.64 2046 1928 1.05 1.025 1.03 1998 218.5 0.00 0.00 1999 225.1 0.00 0.00 231.9 0.00 0.00 2241.29 2373.28 2492.25 0.093 2079 9.93 2171 2079 -9027.9 1.05 1.025 1.03 0.097 2242 10.32 2323 2242 - 11482 1.05 1.025 1.03 0.102 2418 10.61 2459 2418 - 14016 1.05 1.025 1.03 1.05 1.025 1.03 0.113 2811 11.28 2775 2811 -19397 1.05 1.025 1.03 2003 253.4 0.118 3032 11.67 2956 3032 -22240 1.05 1.025 1.03 2004 261.0 0.00 0.00 2005 268.8 0.00 0.00 2006 276.8 0.00 0.00 3079.15 3246.15 3420.67 0.124 3269 12.05 3145 3269 25195 1.05 1.025 1.03 0.130 3525 12.44 3343 3525 1.05 1.025 1.03 0.137 3802 12.83 3551 3802 -31429 1.05 1.025 1.03 2007 285.2 0.144 4099 13.31 3795 4099 ~34748 1.05 1.025 1.03 0.151 4420 13.69 4022 4420 -38162 1.05 1.025 1.03 2009 302.5 0.00 0.00 2010 311.6 0.00 0.00 4033.19 4237.32 0.158 4768 14.18 4288 4768 ~41716 1.05 1.025 1.03 0.166 5140 14.56 4537 5140 ~45350 1.05 1.025 1.03 2011 2012 320.9 330.6 0.00 0.00 0.00 0.00 4476.08 4722.91 0.175 0.183 5544 5977 15.04 15.53 4828 5132 5544 5977 -49110 -52989 5 2 2.5 2.5 3 3 1.05 1.05 1.025 1.025 1.03 1.03 2013 340.5 0.00 0.00 2014 350.7 0.00 0.00 4981.35 5276.49 0.193 16.01 5450 56974 1.05 1.025 1.03 0.202 6951 16.59 5817 6951 ~61116 1.05 1.025 1.03 TABLE 6 - 22 EIEIO IIIS IIIT III ITO IIIT TA IIIT IAA ae WESTERN ARCTIC COAL DEVELOPMENT PROJECT <= on KOTZEBUE a Co) LOW OIL FEB 90 AKA CAP Soha! INFLATION RATE 2.5 RII IIR IRI IOTIIR IOI III IAI IIA ISA ISIS IIIA IIA IA IASI IA UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ KOTZEBUE COAL - NOME ONLY 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 = 2008 2009 2010 2011 2012 2013 2014 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) 2366 2431 2496 2563 2632 2703 2776 2851 2928 3007 3088 3172 3257-3345 3436 3528 3624 3721 3822 20-3925 CAPACITY: COAL (KW) 5000 5000 5000 5000 5000 5000 5000 5000 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 OIL (KW) 7235 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 on HEAT RATE: COAL 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 (BTU/KWH) OIL 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 ' a PRODUCTION COAL 19690 20231 20772 21329 21904 22494 23102 23726 24367 25024 25698 26397 27105 27837 28594 29360 30159 30%6 31807 32664 (000 KWH/YR) OIL = 1036 1065 1093 1123 1153 1184 1216 1249 1282 1317 1353 1389 1427 1465 1505 1545 1587 1630 1674 1719 FUEL: COAL ($/TON) 109.93 112.68 115.49 118.38 121.34 124.38 127.48 130.67 133.94 137.29 140.72 144.24 147.84 151.54 155.33 159.21 163.19 167.27 171.45 175.74 OIL ($/GAL) 0.94 0.97 1.00 1.03 1.07 1.10 1.14 1.17 1.21 1.25 1.29 1.33 1.38 1.42 1.47 1.51 1.56 1.61 1.66 1.72 COAL (S$/MMBTU) 4.58 4.70 4.81 4.93 5.06 5.18 5.31 5.44 5.58 5.72 5.86 6.01 6.16 6.31 6.47 6.63 6.80 6.97 7.14 7.32 OIL ($/MMBTU) 6.71 6.93 7.14 7.36 7.64 7.86 8.14 8.36 8.64 8.93 9.21 9.50 9.86 10.14 10.50 10.79 11.14 11.50 11.86 12.29 O&M: COAL, 100% LOAD 649 665 682 699 716 734 753 71 1186 1216 1246 1277 1309 1342 1376 1410 1445 1481 1518 1556 OIL, 100% LOAD 394 404 414 424 435 446 457 468 480 492 504 517 530 543 557 571 585 600 615 630 COSTS: FUEL (COAL) 1398 1472 1549 1631 1716 1807 1902 2002 2108 2219 2336 2459 2588 2724 2869 3019 3179 3345 3522-3707 FUEL (OIL) 77 81 86 91 97 102 109 115 122 129 137 145 155 163 174 183 195 206 218 22 COAL O&M 292 307 323 340 358 377 397 418 440 463 487 pie 540 569 599 630 663 698 735 77% OIL 08M 6 7 7 7 8 8 8 9 9 10 10 1 12 12 13 13 14 15 16 16 CAPITAL 15170 11420 TOTAL 1773 1867 1965 2069 2179 2294 2416 2544 2679 2821 2970 3128 3294 3469 3654 3846 4051 4264 4491 4730 ELEC. COST ($/KWH) 0.086 0.088 0.090 0.092 0.095 0.097 0.099 0.102 0.104 0.107 0.110 0.113 0.115 0.118 0.121 0.124 0.128 0.131 0.134 0.138 1995 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 CAPITAL COST 1205 O&M COST 40 TOTAL 40 SYSTEM OPERATING COST 1813 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 1658 PRICE OF HEATS/MMBTU 9.06 HEATING REVENUE 1813 TOTAL 3471 a ' >» DEBT 16375 DEBT SERVICE 1486 TOTAL DEBT SERVICE 1486 INTEREST 1064 PRINCIPLE PAYMENT 422 ENDING BALANCE 15953, CASH FLOW 172 CUMULATIVE CASH FLOW 172 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 O&M 2.5 DISTRICT HEAT LOAD 3 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 08M 1.025 DISTRICT HEAT LOAD 1.03 0.084 1789 9.35 1927 3716 15953 1486 1486 1037 449 15504 321 493 2.5 2 6.5 1.05 1.025 1.03 1997 212.2 42.03 1998 218.5 43.08 1999 225.1 44.15 42.025 43.0756 44.1525 3975 15504 1486 1486 1008 478 15026 481 974 2.5 5 6.5 1.05 1.025 1.03 0.093 2079 9.93 2171 4250 15026 1486 1486 977 14516 652 1626 2.5 6.5 1.05 1.025 1.03 0.097 2242 10.32 2323 4565 14516 1486 1486 944 543 13974 855 2481 2.5 6.5 1.05 1.025 1.03 2000 2001 2002 231.9 238.8 246.0 45.26 46.39 47.55 45.2563 46.3877 47.5474 0.102 2418 10.61 2459 4877 13974 1486 1486 578 13396 1051 3532 2.5 6.5 1.05 1.025 1.03 13396 1486 1486 871 615 12780 1283 4815 2.5 6.5 1.05 1.025 1.03 12780 1486 1486 831 655 12125 1509 6324 2.5 6.5 1.05 1.025 1.03 2003 253.4 48.74 48.7361 0.118 3032 11.67 5988 23545 1486 1036 2523 1530 w2 22553 737 7062 2.5 6.5 1.05 1.025 1.03 2004 261.0 0.124 3269 12.05 3145 6415 22553 1486 1036 2523 1466 1057 21496 1021 2.5 6.5 1.05 1.025 1.03 2005 268.8 51.20 2006 276.8 52.48 2007 285.2 53.80 2008 293.7 55.14 51.2034 52.4835 53.7956 55.1404 0.130 3525 12.44 3343 21496 1486 1036 2523 1397 1125 20371 1324 9407 2.5 6.5 1.05 1.025 1.03 0.137 3802 12.83 3551 7353 20371 1486 1036 2523 1324 1198 19172 1649 11056 2.5 6.5 1.05 1.025 1.03 0.144 4099 13.31 3795 19172 1486 1036 2523 1246 1276 17896 2023 13079 2.5 6.5 1.05 1.025 1.03 0.151 4420 13.69 4022 17896 1486 1036 2523 1163 1359 16537 2396 15475 2.5 6.5 1.05 1.025 1.03 2009 302.5 56.52 16537 1486 1036 2523 1075 1448 15089 2823 18298 2.5 6.5 1.05 1.025 1.03 2010 2011 2012 2013 311.6 320.9 330.6 340.5 57.93 59.38 60.86 62.39 56.519 57.9319 59.3802 60.8647 62.3863 0.166 5140 14.56 4537 9677 15089 1486 1036 2523 981 1542 13547 3251 21549 2.5 6.5 1.05 1.025 1.03 0.175 5544 15.04 10372 13547 1486 1036 2523 881 1642 11905 3739 25288 2.5 6.5 1.05 1.025 1.03 11905 1486 1036 2523 77% 1749 10156 4261 29549 2.5 6.5 1.05 1.025 1.03 6446 16.01 5450 11896 10156 1486 1036 34369 2.5 6.5 1.05 1.025 1.03 2014 350.7 63.95 63.946 16.59 5817 12767 1486 1036 2523 539 1983 6311 5451 39820 2.5 6.5 1.05 1.025 1.03 TABLE 6 - 23 PIII IRI IAI RIO IIIA IIIS ISI IIA ISA AIA IAAI AA IASI ae WESTERN ARCTIC COAL DEVELOPMENT PROJECT =m id KOTZEBUE a i LOW OIL FEB 90 AKA CAP sad INFLATION RATE 2.5 RAI II III TR ITA IITITAA IITA AIO IAA AAI OA IS ASI IAIS ASIII IAA UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ KOTZEBUE COAL - NOME + RED DOG 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 = 2008 2009 2010 2011 2012 2013-2014 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) 2366 2431 2496 2563 2632 2703 2776 2851 2928 3007 3088 3172 3257-3345 3436 3528 3624 3721 38220-3925 CAPACITY: COAL (KW) 5000 5000 5000 5000 5000 5000 5000 5000 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 OIL (KW) 7235 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 O\HEAT RATE: COAL 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 1 (BTU/KWH) OIL 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 > ©) PRODUCTION COAL 19690 20231 20772 21329 21904 22494 23102 23726 24367 25024 25698 26397 27105 27837 28594 29360 30159 30966 31807 32664 (000 KWH/YR) OIL = =1036 1065 1093 1123 1153 1184 1216 1249 1282 1317 1353 1389 1427 1465 1505 1545 1587 1630 1674 1719 FUEL: COAL ($/TON) 98.45 100.91 103.43 106.02 108.67 111.38 114.17 117.02 119.95 122.95 126.02 129.17 132.40 135.71 139.10 142.58 146.15 149.80 131.30 134.58 OIL ($/GAL) 0.94 0.97 1.00 1.03 1.07 1.10 1.14 1.17 1.21 Ac25 1.29 1.33 1.38 1.42 1.47 1.51 1.56 1.61 1.66 1.72 COAL ($/MMBTU) 4.10 4.20 4.31 4.42 4.53 4.64 4.76 4.88 5.00 5.12 5.25 5.38 5.52 5.65 5.80 5.94 6.09 6.24 5.47 5.61 OIL ($/MMBTU) 6.71 6.93 7.14 7.36 7.64 7.86 8.14 8.36 = 8.64 8.93 9.21 9.50 9.86 10.14 10.50 10.79 11.146 11.50 11.86 12.29 O&M: COAL, 100% LOAD O49 665 682 699 716 734 753 71 1186 1216 1246 1277 1309 1342 1376 1410 1445 1481 1518 1556 OIL, 100% LOAD 394 404 414 424 435 446 457 468 480 492 504 517 530 543 557 $71 585 600 615 630 COSTS: FUEL (COAL) 1252 1318 1388 1460 1537 1618 1703 1793 1888 1987 2092 2202 2318 2440 2569 = 2704 2847 2996 2697 =. 2839 FUEL (OIL) 7 81 86 91 97 102 109 V5 122 129 137 145 155 163 174 183 195 206 218 232 COAL O&M 292 307 323 340 358 377 397 418 440 463 487 513 540 569 599 630 663 698 735 77% OIL O&M 6 7 7 w 8 8 8 9 9 10 10 1 12 12 13 13 14 15 16 16 CAPITAL 15170 11420 TOTAL 1627 1713 1804 1899 2000 2106 2218 2335 2459 2589 2726 2871 3024 3184 3354 3530 3719 3915 3666 = 3862 ELEC. COST ($/KWH) 0.078 0.080 0.082 0.085 0.087 0.089 0.091 0.093 0.096 0.098 0.101 0.103 0.106 0.109 0.111 0.114 0.117 0.120 0.110 0.112 1995 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 CAPITAL COST 1205 O&M COST 40 TOTAL 40 SYSTEM OPERATING COST 1667 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 1658 PRICE OF HEATS/MMBTU 9.06 HEATING REVENUE 1813 TOTAL 3471 > ' > DEBT 16375 ~ pet seRVICE 1486 TOTAL DEBT SERVICE 1486 INTEREST 1064 PRINCIPLE PAYMENT 422 ENDING BALANCE 15953 CASH FLOW 318 CUMULATIVE CASH FLOW 318 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 O&M 2.5 DISTRICT HEAT LOAD 3 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 O&M 1.025 DISTRICT HEAT LOAD 1.03 0.084 1789 9.35 1927 3716 15953 1486 1486 1037 449 15504 475 793 2.5 6.5 1.05 1.025 1.03 1997 1998 212.2 218.5 42.03 43.08 42.025 43.0756 1846 1942 0.088 0.093 1928 2079 9.64 9.93 2046 2171 3975 4250 15504 15026 1486 1486 1486 1486 1008 977 478 509 15026 = 14516 643 822 1436 2258 5 S 2.5 2.5 > 3 6.5 6.5 1.05 1.05 1.025 1.025 1.03 1.03 1999 2000 225.1 231.9 44.15 45.26 44.1525 45.2563 2044 2151 0.097 0.102 2242 2418 10.32 10.61 2323 2459 4565 4877 14516 = 13974 1486 1486 1486 1486 944 908 543 578 13974 13396 1034 1240 3292 4532 5 3 2.5 2.5 3 3 6.5 6.5 1.05 1.05 1.025 1.025 1.03 1.03 2001 238.8 46.39 2002 246.0 47.55 46.3877 47.5474 0.107 2607 10.99 2625 5232 13396 1486 1486 871 615 12780 1482 6014 2.5 6.5 1.05 1.025 1.03 0.113 2811 11.28 2775 5586 12780 1486 1486 831 655 12125 1718 2.5 6.5 1.05 1.025 1.03 2003 =. 2004 253.4 261.0 48.74 49.95 48.7361 49.9545 2508 2639 0.118 0.124 3032 3269 11.67 12.05 2956 = 3145 5988 = 6415 23545 22553 1486 1486 1036 1036 2523 2523 1530 1466 992 1057 22553 21496 98 1253 8690 = 9942 2 5 2.5 2.5 3 3 6.5 6.5 1.05 1.05 1.025 1.025 1.03 1.03 2005 2006 268.8 276.8 51.20 52.48 51.2034 52.4835 2778 2924 0.130 0.137 3525 3802 12.44 12.83 3343 3551 6869 7353 21496 = 20371 1486 1486 1036 1036 2523 2523 1397 1324 1125 1198 20371 = 19172 1568 1906 11511 13417 5 5 2.5 2.5 S 5 6.5 6.5 1.05 1.05 1.025 1.025 1.03 1.03 2007 285.2 53.80 53.7956 0.144 4099 13.31 3795 19172 1486 1036 2523 1246 1276 17896 2293 15710 2.5 6.5 1.05 1.025 1.03 2008 293.7 55.14 55.1404 0.151 4420 13.69 4022 17896 1486 1036 2523 1163 1359 16537 2680 18390 2.5 6.5) 1.05 1.025 1.03 2009 302.5 56.52 0.158 4768 14.18 4288 16537 1486 1036 2523 1075 1448 15089 3123 21513 2.5 6.5 1.05 1.025 1.03 2010 2011 2012 2013 311.6 320.9 330.6 340.5 57.93 0.166 5140 14.56 4537 9677 15089 1486 1036 2523 981 1542 13547 3566 25079 2.5 6.5 1.05 1.025 1.03 59.38 60.86 62.39 56.519 57.9319 59.3802 60.8647 62.3863 0.175 5544 15.04 10372 13547 1486 1036 2523 881 1642 11905 4071 29150 2.5 6.5 1.05 1.025 1.03 0.183 5977 15.53 5132 11109 11905 1486 1036 2523 77 1749 10156 4610 33760 2.5 6.5 1.05 1.025 1.03 0.193 16.01 5450 11896 10156 1486 1036 2523 1862 5645 39406 2.5 6.5 1.05 1.025 1.03 2014 350.7 0.202 6951 16.59 5817 12767 1486 1036 2523 539 1983 6311 6319 45725 2.5 6.5 1.05 1.025 1.03 INFLATION RATE 3.5 1995 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) 2366 CAPACITY: COAL (KW) 0 OIL (KW) 7235 ©) HEAT RATE: COAL 15500 1 (BTU/KWH) olL 11000 > ©0 PRODUCTION COAL 0 (000 KWH/YR) OIL 20726 FUEL: COAL ($/TON) 0 OIL ($/GAL) 1.12 COAL ($/MMBTU) 0.00 OIL (S/MMBTU) 8.00 08M: COAL, 100% LOAD 649 OIL, 100% LOAD 394 COSTS: FUEL (COAL) 0 FUEL (OIL) 1824 COAL O&M 0 OIL 08M 394 CAPITAL 0 TOTAL 2218 ELEC. COST ($/KWH) 0.107 1996 2431 15500 11000 21296 1.18 0.00 8.43 672 408 1974 408 2382 0.112 1997 2496 15500 11000 21865 1.25 0.00 8.93 422 2147 422 2570 0.118 TABLE 6 - 24 FEISS IIR III IR IIIA IO II IIIA NAIA IAA ISIS AAA ee WESTERN ARCTIC COAL DEVELOPMENT PROJECT si of KOTZEBUE i] a MED OIL FEB 90 DIESEL en PRAIA RATER IARI RRR IO UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ KOTZEBUE DIESEL 1998 1999 2000 2001 2002 2003 2004 2005 2563 2632 2703 2776 2851 2928 3007 = 3088 0 0 0 0 0 0 0 0 7235 7235 7235 7235 7235 7235 7235 7235 15500 15500 15500 15500 15500 15500 15500 15500 11000 11000 11000 11000 11000 11000 11000 11000 0 0 0 0 0 0 0 0 22452 23056 «= 23678 )«9=— 24318 = 24975 25649 = 2634127051 0 0 0 0 0 0 0 0 1.32 1.40 1.48 1.57 1.66 1.76 1.86 1.97 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 9.43 10.00 10.57 11.21 11.86 12.57 13.29 14.07 720 745 7 798 826 855 885 915 437 452 468 484 501 519 537 556 0 0 0 0 0 0 0 0 2329 2536 2753 3000 3257 3547 = 3850 4187 0 0 0 0 0 0 0 0 437 452 468 484 501 519 537 556 2765 2988 3221 3484 3759 = 4066 4387) 4743 0.123 0.130 0.136 0.143 0.150 0.159 0.167 0.175 2006 3172 15500 11000 27787 2.08 0.00 14.86 948 575 4541 575 5116 0.184 2007 3257 15500 11000 28531 2.20 0.00 15.71 981 595 4932 595 5527 0.194 2008 3345 15500 11000 29302 2.33 0.00 16.64 1015 616 5364 616 5981 0.204 2009 3436 15500 11000 30099 2.47 0.00 17.64 1051 638 5841 638 6479 0.215 2010 3528 15500 11000 2.61 0.00 18.64 1087 6998 0.226 2011 15500 11000 31746 2.76 0.00 19.71 1125 0.238 2012 3721 15500 11000 0.00 20.93 1165 707 7504 707 8211 0.252 2013 15500 11000 33481 3.10 0.00 22.14 1206 732 8155 732 8887 0.265 2014 15500 11000 34383 0.00 23.43 1248 757 8861 757 9618 0.280 1995 1996 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 206.0 CAPITAL COST 0 O&M COST 0 0.00 TOTAL 0 0.00 SYSTEM COST REVENUE PRICE OF ELEC $/KWH 0.08 0.084 ELECTRICAL REVENUE 1658 1789 PRICE OF HEATS/MMBTU 12.00 11.38 COST OF HEAT 2400 2344 TOTAL 1658 1789 n 1 CUMULATIVE CASH FLOW -2960 -5897 . ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 5 O&M 3.5 3.5 DISTRICT HEAT LOAD 3 2 GROWTH INDICES (1995=100) ELECTRICITY 1.05 1.05 O&M 1.035 1.035 DISTRICT HEAT LOAD 1.03 1.03 1997 212.2 0.00 0.00 2217.9 2382.19 2569.51 0.088 1928 12.05 2558 1928 1.05 1.035 1.03 1998 218.5 0.093 2079 12.73 2782 2079 ~12564 1.05 1.035 1.03 0.097 2242 13.50 2242 1.05 1.035 1.03 2000 231.9 0.00 0.00 1.05 1.035 1.03 2001 238.8 0.00 0.00 1.05 1.035 1.03 2002 2003 246.0 253.4 0.00 0.00 0.00 0.00 3758.7 4065.75 0.113 0.118 2811 3032 16.01 16.97 3937 = 4300 2811 3032 -29839 -35173 5 5 3.5 3.5 3 3 1.05 1.05 1.035 1.035 1.03 1.03 2004 261.0 0.00 0.00 2005 268.8 0.00 0.00 2006 276.8 0.00 0.00 4386.58 4742.87 5116.37 0.124 3269 17.94 4680 3269 -40970 1.05 1.035 1.03 0.130 3525 19.00 5106 3525 ~47296 1.05 1.035 1.03 0.137 20.06 5553 54161 1.05 1.035 1.03 2007 285.2 0.00 0.00 5527.2 0.144 4099 21.21 6049 4099 -61639 1.05 1.035 1.03 2008 293.7 0.00 0.00 2009 302.5 0.00 0.00 2010 311.6 0.00 0.00 5980.59 6479.19 6997.88 0.151 4420 22.47 6599 4420 -69798 1.05 1.035 1.03 0.158 4768 23.82 7205 4768 78715 1.05 1.035 1.03 0.166 5140 25.17 7842 5140 ~ 88415 1.05 1.035 1.03 7567.59 8211.16 0.175 0.183 5544 5977 26.61 = 28.25 8542 9340 5544 5977 -98980 -110554 5 2 3.5 3.5 3 3 1.05 1.05 1.035 1.035 1.03 1.03 2013 2014 340.5 350.7 0.00 0.00 0.00 0.00 8886.8 9618.46 0.193 0.202 6446 6951 29.89 31.63 10178 = 11092 6446 6951 -123173 -136933 5 5 3.5 3.5 3 3 1.05 1.05 1.035 1.035 1.03 1.03 62b°0 ££b°O - 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TYOD 3N83Z10% $ LN3YYND JO SONVSNOHL NI 3YV SLNNOWY ‘G310N SS37NN ABA UUUUEUU LUE UUUEUUUR OULU. as dv WV 68 190 110 3H ~ os 3N83ZL0% oe s‘¢ BLVa NOILVIANI a 4193P°O¥d LN3WdO13A30 WOO J1LDYV NY31S3N ~ JBOUUUOOOUUOUOUOUUUBUB UB UOUUEULUUUUEE ULL ELLE SZ - 9 AT&VL 1995 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 CAPITAL COST 1205 O&M COST 40 TOTAL 40 SYSTEM OPERATING COST 1926 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 1658 PRICE OF HEATS/MMBTU 10.80 HEATING REVENUE 2160 TOTAL 3818 a ' wi DEBT 16375 _ DEBT SERVICE 1486 TOTAL DEBT SERVICE 1486 INTEREST 819 PRINCIPLE PAYMENT 667 ENDING BALANCE 15708 CASH FLOW 406 CUMULATIVE CASH FLOW 406 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 O&M 3.5 DISTRICT HEAT LOAD 3 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY O&M 1 DISTRICT HEAT LOAD 1.05 +035 1.03 1996 206.0 41.40 41.4 0.084 1789 11.38 2344 4133 15708 1486 1486 785 701 15007 599 1005 3.5 6.5 1.05 1.035 1.03 1997 212.2 42.85 42.849 0.088 1928 12.05 2558 15007 1486 1486 750 14271 822 1827 3.5 6.5 1.05 1.035 1.03 14271 1486 1486 714 13498 1059 2886 3.5 6.5 1.05 1.035 1.03 1999 225.1 45.90 45.9009 0.097 2242 13.50 3039 5281 13498 1486 1486 675 811 12687 1332 4218 3.5 6.5 1.05 1.035 1.03 2000 231.9 47.51 47.5075 0.102 2418 14.27 3309 5727 12687 1486 1486 852 11835 1621 5839 3.5 6.5 1.05 1.035 1.03 2001 238.8 49.17 2002 246.0 50.89 2003 253.4 52.67 2004 261.0 54.52 49.1702 50.8912 52.6724 54.5159 11835 1486 1486 592 10941 1950 3.5 6.5 1.05 1.035 1.03 0.113 2811 16.01 3937 6749 10941 1486 1486 547 939 10002 2298 10086 3.5 6.5 1.05 1.035 1.03 22352 1486 1121 2607 1118 1489 1571 11657 3.5 6.5 1.05 1.035 1.03 0.124 3269 17.94 20863 1486 1121 2607 1043 1564 19299 1988 3.5 6.5 1.05 1.035 1.03 2005 268.8 56.42 56.424 0.130 3525 19.00 5106 8631 19299 1486 1121 2607 965 1642 17657 2455 16100 3.5 6.5 1.05 1.035 1.03 2006 276.8 58.40 0.137 20.06 5553 9355 17657 1486 1121 2607 1724 15933 19050 3.5 6.5 1.05 1.035 1.03 2007 285.2 2008 293.7 2009 302.5 60.44 62.56 64.75 58.3988 60.4427 62.5582 64.7478 0.144 4099 21.21 10148 15933 1486 1121 2607 797 1810 14122 3502 22553 3.5 6.5 1.05 1.035 1.03 0.151 4420 22.47 6599 11019 14122 1486 1121 2607 1901 12221 4114 26667 3.5 6.5 1.05 1.035 1.03 0.158 4768 23.82 11973 12221 1486 1121 2607 611 1996 10226 4791 31458 3.5 6.5 1.05 1.035 1.03 2010 2011 311.6 320.9 67.01 69.36 67.014 69.3594 4866 5179 0.166 0.175 5140 5544 25.17 26.61 7842 8542 12982 14085 10226 8130 1486 1486 1121 1121 2607 2607 511 406 2096 2200 8130 5929 5509 6300 36968 = 43267 3 5 3.5 3.5 x} 3 6.5 6.5 1.05 1.05 1.035 1.035 1.03 1.03 0.183 5977 28.25 9340 15317 5929 1486 1121 2607 2311 3619 7199 50466 3.5 6.5 1.05 1.035 1.03 0.193 6446 29.89 10178 3619 1486 1121 2607 181 2426 1193 8152 58618 3.5 6.5 1.05 1.035 1.03 0.202 6951 31.63 11092 18043 1193 1486 1121 2607 +1355 9194 67812 3.5 6.5 1.05 1.035 1.03 INFLATION RATE ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) CAPACITY: COAL (KW) OIL (KW) HEAT RATE: (BTU/KWH) COAL OIL zs PRODUCTION (000 KWH/YR) COAL OIL FUEL: COAL ($/TON) OIL (¢$/GAL) COAL ($/MMBTU) OIL ($/MMBTU) O&M: COAL, 100% LOAD OIL, 100% LOAD COSTS: FUEL (COAL) FUEL (OIL) COAL O&M OIL O&M CAPITAL TOTAL ELEC. COST ($/KWH) 3.5 1995 2366 5000 7235 15500 11000 19690 1036 105.37 1.12 4.39 8.00 649 394 1340 91 292 6 15170 1729 0.083 1996 1997 2431 2496 5000 5000 7500 7500 15500 15500 11000 = =©11000 20231 + 20772 1065 1093 109.06 112.88 1.18 1.25 4.54 4.70 8.43 8.93 672 695 408 422 1425 1514 9 107 310 330 7 7 1841 1958 0.086 0.090 1998 2563 5000 7500 15500 11000 21329 1123 116.83 1.32 4.87 9.43 720 437 1609 116 350 2084 0.093 TABLE 6 - 26 EI III II III IIIT III IISA IAI AI IAI IAAI IIIA -™ i od MED OIL KOTZEBUE oct 89 WESTERN ARCTIC COAL DEVELOPMENT PROJECT AKA CAP * * 7 IRR IR IRI IIIIRIRIII III IIII III I II OIA IIIA IAAI. UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ KOTZEBUE COAL - NOME + RED DOG 1999 2632 5000 7500 15500 11000 21904 1153 120.91 1.40 5.04 10.00 745 452 1710 127 372 2218 0.096 2000 2703 5000 7500 15500 11000 22494 1184 125.15 1.48 5.21 10.57 71 1818 138 396 2360 0.100 2001 2776 5000 7500 15500 11000 23102 1216 129.53 1.57 5.40 11.21 1933 150 421 2512 0.103 2002 2851 5000 7500 15500 11000 23726 1249 134.06 1.66 5.59 11.86 826 501 2054 163 447 10 2674 0.107 2003 2928 7500 7500 15500 11000 24367 1282 138.75 1.76 5.78 12.57 1282 519 2183 177 475 10 12350 2846 0.111 2004 2005 2006 3007 = 3088 3172 10000 10000 10000 7500 7500 7500 15500 15500 15500 11000 11000 11000 25024 25698 26397 1317 1353 1389 143.61 148.64 153.84 1.86 1.97 2.08 5.98 6.19 6.41 13.29 14.07 14.86 1769 1831 1895 537 556 575 2321 2467 2623 192 209 227 505 537 571 11 11 12 3030 3225 3433 t 0.115 0.119 0.124 2007 3257 10000 7500 15500 11000 27105 1427 159.22 2.20 6.63 15.71 1961 595 2787 247 607 13 3654 0.128 2008 2009 3345 3436 10000 12500 7500 7500 15500 15500 11000 11000 27837 = 28594 1465 1505 164.79 145.85 2.33 2.47 6.87 6.08 16.64 17.64 2030 2626 616 638 2963 2693 268 292 645 686 14 15 3890 3686 0.133 0.122 2010 3528 12500 7500 15500 11000 29360 1545 150.95 2.61 6.29 18.64 2718 660 2862 317 16 3924 0.127 2011 12500 15500 11000 30159 1587 156.24 2.76 6.51 19.71 2813 3043 17 4179 0.132 2012 3721 12500 15500 11000 30966 1630 161.71 2.93 6.74 20.93 2912 707 3234 375 823 18 4450 0.137 2013 15000 7500 15500 11000 31807 1674 167.37 3.10 6.97 22.14 3617 732 3438 875 19 4740 0.142 2014 3925 15000 7500 15500 11000 32664 1719 173.22 3.28 7.22 23.43 3743 757 3654 443 930 20 5047 0.147 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 CAPITAL COST 1205 0&™ COST 40 TOTAL 40 SYSTEM OPERATING COST 1769 REVENUE PRICE OF ELEC $/KWH 0.08 ELECTRICAL REVENUE 1658 PRICE OF HEATS/MMBTU 10.80 HEATING REVENUE 2160 TOTAL 3818 a ' ww ~DEBT 16375 ce DEBT SERVICE 1486 TOTAL DEBT SERVICE 1486 INTEREST 819 PRINCIPLE PAYMENT 667 ENDING BALANCE 15708 CASH FLOW 563 CUMULATIVE CASH FLOW 563 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 2 O&M 3.5 DISTRICT HEAT LOAD 2 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.05 O&M 1.035 DISTRICT HEAT LOAD 1.03 1996 = 1997 206.0 212.2 41.40 42.85 41.4 42.849 1882 2001 0.084 0.088 1789 1928 11.38 12.05 2344 2558 4133 4486 15708 15007 1486 1486 1486 1486 785 750 701 736 15007. 14271 765 999 1327 =. 2326 5 5 3.5 3.5 3 3 6.5 6.5 1.05 1.05 1.035 1.035 1.03 1.03 1998 218.5 44.35 1999 225.1 45.90 2000 231.9 47.51 2001 238.8 49.17 44.3487 45.9009 47.5075 49.1702 12.73 2782 4861 14271 1486 1486 714 13498 1247 3573 3.5 6.5 1.05 1.035 1.03 0.097 2242 13.50 3039 5281 13498 1486 1486 675 811 12687 1531 5104 3.5 6.5 1.05 1.035 1.03 0.102 2418 14.27 3309 5727 12687 1486 1486 852 11835 1833 6937 3.5 6.5 1.05 1.035 1.03 0.107 2607 15.14 3615 6222 11835 1486 1486 592 10941 2175 9112 3.5 6.5 1.05 1.035 1.03 2002 246.0 2003 253.4 2004 261.0 50.89 52.67 54.52 50.8912 52.6724 54.5159 0.113 2811 16.01 3937 6749 10941 1486 1486 547 939 10002 2538 11650 3.5 6.5 1.05 1.035 1.03 0.118 3032 16.97 4300 7331 22352 1486 1121 2607 1118 1489 1825 13475 3.5 6.5 1.05 1.035 1.03 0.124 3269 17.94 1486 1121 2607 1043 1564 19299 2258 15733 3.5 6.5 1.05 1.035 1.03 2005 268.8 56.42 56.424 0.130 3525 19.00 5106 8631 19299 1486 1121 2607 965 1642 17657 2743 18476 3.5 6.5 1.05 1.035 1.03 2006 276.8 58.40 58.3988 0.137 20.06 5553 9355 17657 1486 1121 2607 1724 15933 3256 21733 3.5 6.5 1.05 1.035 1.03 2007 = 2008 285.2 293.7 60.44 62.56 60.4427 62.5582 3714 3952 0.144 0.151 4099 4420 21.21 22.47 6049 6599 10148 = =11019 15933-14122 1486 1486 1121 1121 2607 = 2607 7 706 1810 1901 14122 12221 3827 = 4460 25560 30020 5) 5 3.5 3.5 3 3 6.5 6.5 1.05 1.05 1.035 1.035 1.03 1.03 2009 302.5 64.75 64.7478 0.158 4768 23.82 11973 12221 1486 1121 2607 611 1996 10226 5615 35635 3.5 6.5 1.05 1.035 1.03 2010 311.6 67.01 67.014 0.166 5140 25.17 12982 10226 1486 1121 2607 511 8130 42020 3.5 6.5 1.05 1.035 1.03 2011 320.9 69.36 69.3594 0.175 5544 26.61 8542 14085 8130 1486 1121 2607 2200 5929 49250 3.5 6.5 1.05 1.035 1.03 2012 330.6 0.183 5977 28.25 9340 15317 5929 1486 1121 2607 2311 3619 8188 57438 3.5 6.5 1.05 1.035 1.03 2013 2014 340.5 350.7 74.30 76.90 74.2996 76.9001 4814 5124 0.193 0.202 6446 6951 29.89 31.63 10178 = 11092 16624 18043 3619 1193 1486 1486 1121 1121 2607 = 2607 181 60 2426 = 2547 1193-1355 9203 10312 66641-76952 5 5 3.5 3.5 3 5 6.5 6.5 1.05 1.05 1.035 1.035 1.03 1.03 INFLATION RATE = 4.5 1995 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) 2366 CAPACITY: COAL (KW) 0 OIL (KW) = 7235 O\HEAT RATE: COAL 15500 1 (BTU/KWH) OIL 11000 wn +> PRODUCTION COAL 0 (000 KWH/YR) OIL 20726 FUEL: COAL ($/TON) 100 OIL ($/GAL) 1.27 COAL ($/MMBTU) 4.17 OIL ($/MMBTU) 9.07 O&M: COAL, 100% LOAD 649 OIL, 100% LOAD 3% COSTS: FUEL (COAL) 0 FUEL (OIL) 2068 COAL 08M 0 OIL 08 394 CAPITAL 0 TOTAL 2462 ELEC. COST ($/KWH) 0.119 1996 2431 15500 11000 21296 105 1.37 4.35 9.77 678 427 2289 427 2715 0.128 1997 2496 7500 15500 11000 21865 109 1.48 4.55 10.57 446 2543 2989 0.137 TABLE 6 - 27 ERISA TT IIIA IA IAAI ao WESTERN ARCTIC COAL DEVELOPMENT PROJECT oe ‘ KOTZEBUE a bd HIGH OIL FEB 90 DIESEL ioe ESI ISIS IIIS IIIA IIR UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ KOTZEBUE DIESEL 1998 1999 2000 2001 2002 2003 2004 2005 2563 2632 2703 2776 2851 2928 3007 = 3088 0 0 0 0 0 0 0 0 7500 7500 7500 7500 7500 7500 7500 10100 15500 15500 15500 15500 15500 15500 15500 15500 11000 11000 11000 11000 11000 11000 11000 11000 0 0 0 0 0 0 0 0 22452 23056 §9= 23678 §9=— 24318 )§=— 24975 25649 = 26341 27051 114 119 89 93 97 102 106 7% 1.59 1.72 1.85 2.00 2.15 2.31 2.49 2.68 4.75 4.97 3.72 3.88 4.06 4.24 4.43 3.07 11.39 12.26 «13.21 14.29 15.36 «16.50 17.79 19.14 741 774 809 845 883 923 964 1008 466 487 509 532 556 581 607 854 0 0 0 0 0 0 0 0 2812 3110 3440 3821 4219 = 4655 5153 5696 0 0 0 0 0 0 0 0 466 487 509 532 556 581 607 854 3278 =. 3597 3949-4353 4775 5236 5760 6550 0.146 0.156 0.167 0.179 0.191 0.204 0.219 0.242 2006 3172 10100 15500 11000 27787 2.88 3.21 20.57 1053 893 6288 893 7180 0.258 2007 3257 10100 15500 11000 28531 81 3.11 3.36 22.21 1101 933 6972 933 0.277 2008 3345 10100 15500 11000 29302 3.34 3.51 23.86 1150 975 7690 975 0.296 2009 3436 12700 15500 11000 3.60 3.67 25.71 1202 1281 8514 1281 9795 0.325 2010 3528 12700 15500 11000 3.87 2.75 27.64 1256 1338 9397 1338 10736 0.347 2011 12700 15500 11000 31746 4.17 2.88 29.79 1313 1399 10401 1399 11800 0.372 2012 3721 12700 15500 11000 32596 4.49 3.01 32.07 1372 1462 11499 1462 12961 0.398 2013 15300 15500 11000 33481 4.83 3.14 34.50 1433 1840 12706 1840 14546 0.434 2014 15500 11000 34383 5.20 3.28 37.14 1498 1923 14048 1923 15971 0.464 1995 1996 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 206.0 CAPITAL COST 0 O&M COST 0 0.00 TOTAL 0 0.00 SYSTEM COST 2462.17 2715.43 REVENUE PRICE OF ELEC $/KWH 0.08 0.084 ELECTRICAL REVENUE 1658 1789 PRICE OF HEATS/MMBTU 13.61 13.19 COST OF HEAT 2721 2717 TOTAL 1658 1789 a 1 CUMULATIVE CASH FLOW -3525.5 -7169.1 w “ ESCALATION RATES (5/YR) COAL PRICE 4.5 4.5 OIL PRICE 7.7 7.7 PRICE OF ELECTRICITY 5 5 O&M 4.5 4.5 DISTRICT HEAT LOAD 3 3 GROWTH INDICES (1995=100) COAL PRICE 1.045 1.045 OIL PRICE 1.077 1.077 ELECTRICITY 1.05 1.05 O&M 1.045 1.045 DISTRICT HEAT LOAD 1.03 1.03 1997 1998 1999 2000 2001 2002 2003 = 2004 2005 2006 §=62007 = 2008 39 2009S 2010 2011 2012 212.2 218.5 225.1 231.9 9238.8 246.0 253.4 9261.0 268.8 276.8 285.2 293.7 302.5 311.6 320.9 330.6 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2988.6 3277.95 3596.97 3948.7 4353.25 4774.77 5236.17 5760.46 6550.31 7180.34 7904.6 8664.48 9794.64 10735.9 11800.1 12961 0.088 0.093 0.097 0.102 0.107 0.113 0.118 0.124 0.130 0.137 0.144 0.151 0.158 0.166 0.175 0.183 1928 2079 2242 2418 2607 2811 3032 3269 =. 3525 3802 4099 4420 4768 5140 5544 5977 14.27 15.37 16.55 17.83 19.29 20.73 22.28 3924.01 25.84 27.77 29.99 32.21. 34.71 37.32 40.21 43.30 3028 3359 3726 4134 4606 5100 5643 6266 = 6946 7688 8552 9459 10502 11628 12905 14312 1928 2079 2242 2418 2607 2811 3032 3269-3525 3802 4099 4420 4768 5140 5544 5977 -11257 -15815 -20896 -26561 -32913 -39976 -47824 -56581 -66552 -77619 -89976 -103680 -119209 -136433 -155594 -176891 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 7.7 7.7 7.7 7.7 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 5 5 5 2 5 5 5 5 5 5 5 5 5 5 S 5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 3 3 3 3 3 3 3 3 3 3 3 3 3 3 S 3 1.045 1.045 1.045 1.045 1.045 1.0465 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.077, 1.077 1.077 1.077 1.065 1.065 1.065 1.065 1.065 1.065 1.065 1.065 1.065 1.065 1.065 1.065 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.05 1.065 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 1.03 2013 340.5 0.193 46.58 15858 6446 - 200849 4.5 6.5 4.5 1.045 1.065 1.05 1.045 1.03 2014 350.7 0.202 6951 50.14 17585 6951 +227454 4.5 6.5 4.5 1.045 1.065 1.05 1.045 1.03 TABLE 6 - 28 ISI IIIS IIIS IOIINOIDS nnn On nO nOOnOnonEt re WESTERN ARCTIC COAL DEVELOPMENT PROJECT = INFLATION RATE 4.5 on KOTZEBUE ay) ial HIGH OIL FEB 90 AKA CAP se RRR TR TRI TI III III III II IIIT IIIT II II IAI AN UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ KOTZEBUE COAL - NOME ONLY 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) 2366 2431 2496 2563 2632 2703 2776 2851 2928 8 3007 9=93088 «= «3172 3257-3345 3436-3528 = 3624 3721 38220-3925 CAPACITY: COAL (KW) 5000 5000 5000 5000 5000 5000 5000 ©5000 7500 7500 7500 7500 7500 7500 7500 7500 7500 «67500 = 7500) 7500 OIL (KW) 7235 7500 7500 7500 7500 ©7500 7500 7500 7500 7500 7500 7500 = 7500 7500 7500 7500 = 8=©7500 7500 = 75002 7500 oy HEAT RATE: COAL 15500 15500 15500 15500 15500 15500 15500 15500 15500 15560 15500 15500 15500 15500 15500 15500 15500 15500 15500 15500 , CBTU/KWH) OIL 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 11000 en PRODUCTION COAL 19690 20231 20772 21329 21904 22494 23102 23726 24367 25024 25698 26397 27105 27837 28594 29360 30159 30966 31807 32664 (000 KWH/YR) OIL = 1036 1065 1093 1123 1153 1184 1216 1249 1282 1317 1353 1389 1427 1465 1505 1545 1587 1630 1674 1719 FUEL: COAL ($/TON) 125.85 131.52 137.43 143.62 150.08 156.84 163.89 171.27 178.97 187.03 195.45 204.246 213.43 223.04 233.07 243.56 254.52 265.97 277.94 290.45 OIL ($/GAL) 1.27 1.37 1.48 1.59 1.72 1.85 2.00 2.15 2.31 2.49 2.68 2.88 3.11 3.34 3.60 3.87 4.17 4.49 4.83 5.20 COAL ($/MMBTU) 5.24 5.48 5.73 5.98 6.25 6.54 6.83 7.14 7.46 7.79 8.14 8.51 8.89 9.29 9.71 10.15 10.61 11.08 11.58 12.10 OIL ($/MMBTU) 9.07 9.79 10.57 11.36 12.29 13.21 14.29 15.36 16.50 17.79 19.14 20.57 22.21 23.86 25.71 27.64 29.79 32.07 34.50 37.14 O&M: COAL, 100% LOAD 649 678 709 741 774 809 845 883 1384 1447 1512 1580 1651 1725 1803 1884 1969 2057-2150 2247 OIL, 100% LOAD 394 412 430 450 470 491 513 536 560 586 612 639 668 698 730 763 97 833 870 909 COSTS: FUEL (COAL) 1600 1718 1844 1978 =. 2123 2279 2445 2624 2816 3023 3244 3482 3736 4010 4304 4618 497 5319 5709, 6127 FUEL (OIL) 103 15 127 140 156 172 191 211 233 258 285 314 349 384 426 470 520 575 635 702 COAL O&M 292 313 336 361 387 415 446 478 513 551 591 635 681 731 785 842 904 970 1041 1117 OIL 08M 6 7 7 8 8 9 9 10 1 12 13 14 1S 16 17 18 19 21 22 24 CAPITAL 15170 13330 TOTAL 2002 2153 2314 2487 2674 2875 3092 3324 3574 3843 4133 4445 4780 5141 5531 5948 6401 6884 7408 7970 ELEC. COST ($/KWH) 0.097 0.101 0.106 0.111 0.116 §=0.121 0.127) 0.133 0.139 0.146 = 0.153 0.160 «0.168 )9=— 0.175 0.184 = 0.192. 0.202--0.211 Ss :0.221 Ss: 00.232 1995 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 CAPITAL COST 1205 O&M COST 40 TOTAL 40 SYSTEM OPERATING COST 2042 REVENUE PRICE OF ELEC $/KWH 0.080 ELECTRICAL REVENUE 1658 PRICE OF HEAT $/MMB 12.25 HEATING REVENUE 2449 4107 a ' w DEBT 16375 ™ est SERVICE 1486 TOTAL DEBT SERVICE 1486 INTEREST 1064 PRINCIPLE PAYMENT 422 ENDING BALANCE 15953 CASH FLOW 579 CUMULATIVE CASH FLOW 579 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 2 O&M 4.5 DISTRICT HEAT LOAD s COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.050 O&M 1.045 DISTRICT HEAT LOAD 1.030 0.084 1789 13.21 2721 4510 15953 1486 1486 1037 449 15504 1409 4.5 6.5 1.050 1.045 1.030 1997 212.2 0.088 1928 14.27 3028 4957 15504 1486 1486 1008 478 15026 1113 2521 4.5 6.5 1.050 1.045 1.030 0.093 2079 15.33 3351 5430 15026 1486 1486 14516 1411 3933 4.5 6.5 1.050 1.045 1.030 0.097 2242 16.59 3733 5975 14516 1486 1486 543 13974 1768 5700 4.5 6.5 1.050 1.045 1.030 2000 231.9 49.85 50 0.102 2418 17.84 4136 6554 13974 1486 1486 578 13396 2143 7843 4.5 6.5 1.050 1.045 1.030 0.107 2607 19.29 7213 13396 1486 1486 871 615 12780 2583 10426 4.5 6.5 1.050 1.045 1.030 2002 246.0 0.113 2811 20.73 5100 7911 12780 1486 1486 831 655 12125 3046 13472 4.5 6.5 1.050 1.045 1.030 2003 253.4 0.118 3032 22.28 5643 8675 25455 1486 1210 2696 1655 1041 24414 2349 15821 4.5 6.5 1.050 1.045 1.030 2004 261.0 0.124 3269 24.01 6266 9535 24414 1486 1210 2696 1587 1109 23305 18758 4.5 6.5 1.050 1.045 1.030 2005 268.8 0.130 3525 25.84 6946 10471 23305 1486 1210 2696 1515 1181 22123 3581 22338 4.5 6.5 1.050 1.045 1.030 2006 276.8 0.137 3802 27.77 7688 11490 22123 1486 1210 2696 1438 1258 4285 26623 4.5 6.5 1.050 1.045 1.030 2007 285.2 0.144 4099 29.99 8552 12651 1486 1210 2696 1356 1340 19526 5106 31730 4.5 6.5 1.050 1.045 1.030 0.151 4420 32.21 9459 13880 19526 1486 1210 2696 1269 1427 18099 5972 37702 4.5 6.5 1.050 1.045 1.030 2009 302.5 0.158 4768 %4.71 10502 15269 18099 1486 1210 2696 1176 1519 16580 6968 44670 4.5 6.5 1.050 1.045 1.030 2010 311.6 0.166 5140 37.32 11628 16768 16580 1486 1210 2696 1078 1618 14961 52716 4.5 6.5 1.050 1.045 1.030 2011 320.9 0.175 5544 40.21 12905 18449 14961 1486 1210 2696 972 1723 13238 9272 61988 4.5 6.5 1.050 1.045 1.030 2012 330.6 84.54 85 0.183 5977 43.30 14312 20289 13238 1486 1210 2696 1835 11403 10624 72612 4.5 6.5 1.050 1.045 1.030 2013 340.5 0.193 46.58 15858 22304 11403 1486 1210 2696 741 1955 12112 84725 4.5 6.5 1.050 1.045 1.030 2014 350.7 92.31 92 0.202 6951 50.14 17585 24536 1486 1210 2696 614 2082 13777 98502 4.5 6.5 1.050 1.045 1.030 INFLATION RATE ELECTRIC POWER SYSTEM PROJECTED LOAD (KW) CAPACITY: COAL (KW) OIL (KW) o HEAT RATE: COAL , (BTU/KWH) OIL is PRODUCTION COAL (000 KWH/YR) OIL FUEL: COAL ($/TON) OIL ($/GAL) COAL ($/MMBTU) OIL ($/MMBTU) O&M: COAL, 100% LOAD OIL, 100% LOAD COSTS: FUEL (COAL) FUEL (OIL) COAL O&M OIL O&M CAPITAL TOTAL ELEC. COST ($/KWH) 4.5 1995 5000 7235 15500 11000 19690 1036 112.71 1.27 4.70 9.07 49 394 1433 103 292 6 15170 1835 0.089 1996 1997 2431 2496 5000 5000 7500 7500 15500 15500 11000 =—11000 20231 += 20772 1065 1093 117.78 123.08 1.37 1.48 4.91 5.13 9.79 10.57 678 709 412 430 1539 1651 115 127 313 336 iz 7 1973 2122 0.093 0.097 1998 2563 5000 7500 15500 11000 21329 1123 128.62 1.59 5.36 11.36 741 450 1772 140 361 8 2280 0.102 TABLE 6 - 29 REISE INI III IOI III IOI IIIT TI TTT TAA IAAI AE WESTERN ARCTIC COAL DEVELOPMENT PROJECT KOTZEBUE HIGH OIL FEB 90 AKA CAP ERISA III III III III IIIT IAI IIA UNLESS NOTED, AMOUNTS ARE IN THOUSANDS OF CURRENT $ KOTZEBUE COAL - NOME + RED DOG “* aad -* * ” * 1999 2000 2001 2002 2003 2004 2005 2632 2703 2776 2851 2928 3007 = 3088 5000 5000 5000 5000 7500 7500 7500 7500 7500 7500 7500 7500 7500 7500 15500 15500 15500 15500 15500 15500 15500 11000 11000 11000 11000 11000 11000 11000 21904 22494 23102 23726 24367 25024 25698 1153 1184 1216 1249 1282 1317 1353 134.40 140.45 146.77 153.38 160.28 167.49 175.03 1.72 1.85 2.00 2.15 2.31 2.49 2.68 5.60 5.85 6.12 6.39 6.68 6.98 7.29 12.29 13.21 14.29 15.36 «16.50 17.79 = 19.14 77% 809 845 883 1384 1447 1512 470 491 513 536 560 586 612 1901 2040 2190 2350 = 2522 2707 2905 156 172 191 211 233 258 285 387 415 446 478 513 551 591 8 9 9 10 1 12 13 13330 2452 2637 2836 3050 3279 3527 3794 0.106 0.111 0.117 0.122 0.128 0.134 0.140 2006 3172 7500 7500 15500 11000 26397 1389 156.40 2.88 6.52 20.57 1580 639 2666 314 635 14 3629 0.131 2007 3257 7500 7500 15500 11000 27105 1427 163.44 3.11 6.81 22.21 1651 668 2861 349 681 15 3905 0.137 2008 3345 7500 7500 15500 11000 27837 1465 170.80 3.34 7.12 23.86 1725 698 3071 731 16 4202 0.143 2009 3436 7500 7500 15500 11000 28594 1505 178.48 3.60 7.44 25.71 1803 730 3296 426 785 17 4523 0.150 2010 3528 15500 11000 29360 1545 186.52 3.87 7.77 27.64 1884 763 3537 470 B42 18 0.157 2011 7500 7500 15500 11000 30159 1587 194.91 4.17 8.12 29.79 1969 797 3796 520 904 19 5239 0.165 2012 3721 15500 11000 30966 1630 203.68 4.49 8.49 32.07 2057 833 4073 575 970 21 5639 0.173 2013 15500 11000 31807 1674 212.84 4.83 8.87 34.50 2150 870 4372 635 1041 22 6070 0.181 2014 3925 7500 15500 11000 32664 1719 222.42 5.20 9.27 37.14 2247 702 1117 24 6535 0.190 1995 DISTRICT HEAT SYSTEM LOAD (MMBTU/YR) 200 CAPITAL COST 1205 O&M COST 40 TOTAL 40 SYSTEM OPERATING COST 1875 REVENUE PRICE OF ELEC $/KWH 0.080 ELECTRICAL REVENUE 1658 PRICE OF HEAT $/MMB 12.25 HEATING REVENUE 2449 4107 vn "pest 16375 a DEBT SERVICE 1486 TOTAL DEBT SERVICE 1486 INTEREST 1064 PRINCIPLE PAYMENT 422 ENDING BALANCE 15953 CASH FLOW 746 CUMULATIVE CASH FLOW 746 ESCALATION RATES (5/YR) PRICE OF ELECTRICITY 5 08M 4.5 DISTRICT HEAT LOAD 5 COST OF MONEY 6.5 GROWTH INDICES (1995=100) ELECTRICITY 1.050 O&M 1.045 DISTRICT HEAT LOAD 1.030 1996 206.0 0.084 1789 13.21 2721 4510 15953, 1486 1486 1037 449 15504 1009 1755 4.5 6.5 1.050 1.045 1.030 1997 212.2 15504 1486 1486 1008 478 15026 1305 3061 4.5 6.5 1.050 1.045 1.030 0.093 2079 15.33 3351 5430 15026 1486 1486 977 509 14516 1618 4678 4.5 6.5 1.050 1.045 1.030 0.097 2242 16.59 3733 5975 14516 1486 1486 944 543 13974 1989 4.5 6.5 1.050 1.045 1.030 0.102 2418 17.84 4136 6554 13974 1486 1486 578 13396 2381 4.5 6.5 1.050 1.045 1.030 2001 238.8 52.09 52 0.107 2607 19.29 7213 13396 1486 1486 871 615 12780 2838 11887 4.5 6.5 1.050 1.045 1.030 0.113 2811 20.73 5100 7911 12780 1486 1486 831 655 12125 3321 15208 4.5 6.5 1.050 1.045 1.030 2003 253.4 0.118 3032 22.28 5643 8675 25455 1486 1210 2696 1655 1041 24414 2643 17851 4.5 6.5 1.050 1.045 1.030 0.124 3269 24.01 9535 24414 1486 1210 2696 1587 1109 23305 3252 21103 4.5 6.5 1.050 1.045 1.030 2005 0.130 3525 25.84 10471 23305 1486 1210 2696 1515 1181 22123 3919 25022 4.5 6.5 1.050 1.045 1.030 2006 276.8 64.91 65 0.137 27.77 7688 11490 22123 1486 1210 2696 1438 1258 5101 30123 4.5 6.5 1.050 1.045 1.030 2007 285.2 0.144 4099 29.99 8552 12651 1486 1210 2696 1356 1340 19526 5982 36104 4.5 6.5 1.050 1.045 1.030 2008 293.7 0.151 4420 32.21 9459 13880 19526 1486 1210 2696 1269 1427 18099 6911 43015 4.5 6.5 1.050 1.045 1.030 2009 302.5 0.158 4768 %.71 10502 15269 18099 1486 1210 2696 1176 1519 16580 7976 50992 4.5 6.5 1.050 1.045 1.030 2010 311.6 0.166 5140 37.32 11628 16768 16580 1486 1210 2696 1078 1618 14961 9128 60120 4.5 6.5 1.050 1.045 1.030 2011 320.9 0.175 5544 40.21 12905 18449 14961 1486 1210 2696 972 1723 13238 10433 70553 4.5 6.5 1.050 1.045 1.030 2012 330.6 0.183 5977 43.30 14312 20289 13238 1486 1210 2696 1835 11403 11870 82423 4.5 6.5 1.050 1.045 1.030 2013 340.5 11403 1486 1210 2696 741 1955 9448 13450 W872 4.5 6.5 1.050 1.045 1.030 2014 350.7 0.202 6951 50.14 17585 24536 9448 1486 1210 2696 614 2082 15212 111085 4.5 6.5 1.050 1.045 1.030 09 Diesel Baseline Diesel DH Coal DH Coal DH + Red Dog Coal DH + Gold Co Coal DH + All Cum Cash Flow (1000's) -$213,414 - 69,779 26,213 44,432 > 25,613 8,200 17 1 Cum Cash Flow $357,803 - 134,727 34,103 64,797 - 26,122 21,547 TABLE 6 NOME SUMMARY OF ANALYSES High Year of Positive Cash Flow Cum Cash Flow (1000's) $9, 162 = 13,592 9,982 19,477 = 21,481 5,656 Low Year of Positive Cash Flow 17 16 13 Break Even Year 15 10 19 19 Diesel Baseline Coal DH Coal DH + Red Dog Coal DH + Gold Co Coal DH + ALL LOW Cum Cash Year of Flow Positive (1000's) Cash Flow -$61,116 o- 39,820 1 45,725 1 39,820 1 49,949 1 Break Even Year TABLE 6 - 31 Kotzebue Summary of Analyses MED Cum Cash Year of Break Flow Positive Even (1000's) Cash Flow Year -$136,933 “+ oe 67,812 1 1 76,952 1 1 69,635 1 1 80,497 1 1 Cum Cash Flow (1000's) Cash Flow -$227, 454 98,502 111,085 102,553 115, 155 HIGH Year of Positive attractive since the loss over twenty years is reduced to $69,779,000. This represents a $143,635,000 reduction in subsidy payments. Switching to a coal-fired fluidized bed system with district heating and assuming no other coal usage, the cash flows turns positive in the eight year, the project breaks even after 11 years and over the 20 year period, a profit of $26,213,000 is generated. This profit can be used to further reduce the price of heat and power for the inhabitants in Nome. Compared to the diesel baseline case, the coal fired system represents a savings over 20 years of $239,627,000. Compared to a diesel with a district heating system to the coal system with comparable district heating system, the coal system represents a savings of $95,992,000. If Red dog Mine starts using Deadfall Syncline coal, the reduction in coal prices represents an additional savings of $18,200,000 to Nome. The cash flow turns positive one year earlier and the break even point is reduced to 7 years. The addition of the gold company has a slight negative impact on the economics of this system. The cash flow turns positive after 16 years, and the break even point extends past the 20 years of the analysis. Adding in the coal consumption of the Red Dog Mine helps a little. This impact is due to the small size of the power module, 2500 kW compared to the load growth due to the gold companies. Increasing the size of the power module to approximately 5000 kW will increase the efficiency of the system, reduce the capital cost and provide system economics comparable to or better than the current basic coal system (i.e. 7 year break even point). 6 - 62 The results for Kotzebue are summarized in Table 6-31. A diesel district heating option was not considered in Kotzebue as the author is unaware of any design work in that area. Comparing the current diesel power generation to the coal alternative with district heating indicates a savings of $204,745,00@ over 20 years. Operating the diesels over twenty years will require a subsidy of $136,933,000 as compared to a profit (with no subsidy) of $67,812,000 generated with a coal fired system. The coal-fired system breaks even in the first year. The additional coal demand options in Nome and the low and high sensitivity show only a marginal effect. In all cases, the results of the analysis look very promising for the coal fired CFB power generation system. If the growth in district heating loads exceeds the 3% rate used in this analysis, the additional revenue will further enhance the economics of the coal-fired system. In this analysis, the cost of district heat was set at 90% of the residential price of oil even though the cost of the heat is almost negligible. The residential price of oil was assumed to be 150% of the utility oil price. 6 - 63 7.@ SOCIO-ECONOMIC IMPACT Kotzebue 7.1.1 Community Today The prevailing public and private economic balance in the region shows, in rough terms, public (government) funds contribute about $20 million to the regional economy in the form of institutional revenues, about $4.5 million arrives in the region in the form of Permanent Fund dividends, about $5 million is generated in the private sector, and $1.5 million is derived from ANCSA Corporation dividends to individuals. Government cutbacks, most notable subsequent to 1989, reverberate through the region by reducing service levels and eliminating wages which in turn inhibit private sector trade and services. In June 1988, according to the Alaska Department of Labor, the Northwest Arctic Borough posted the highest unemployment rate in the state, 16.5 percent of the registered work force. As of June 1989, however, the unemployment rate for the region stood at 11.1 percent. Further, employment through a number of NANA companies (NANA/VECO, NANA/Marriott, and Purcell Security) had many residents working outside the region at the Exxon Valdez oil spill in Prince William Sound. Kotzebue residents also pursue economic opportunities in private sector ventures that hold little long term stability as well. Chum salmon prices have been relatively high during 1988, permitting some residents with marginal incomes to recoup business expenses and save money. Commercial fishing contributes less than two percent to the aggregate regional income. Subsistence hunting and fishing also contributes a substantial amount of food to the diets of many Kotzebue residents. In addition, subsistence practices themselves, including harvests, preparation and distribution, reinforce bonds among community residents by establishing patterns of cooperative interaction based on the Inupiaq model, thereby providing a sense of historic continuity and roots, validating long-standing kinship and partnership relationships, and creating ties of mutual support among donors and recipients. The Inupiat Ilitqusiat (spirit) movement evolved a formal position on indigenous values in 1982. These values are knowledge of language, sharing, respect for others, cooperation, respect for elders, love for children, hard work, knowledge of family tree, avoid conflict, respect for nature, spirituality, humor, family roles, hunter, success, domestic skills, humility, and responsibility to tribe. Both the Regional Strategy and Inupiat Ilitqusiat assert a vision of ideal, consensual community life that treads a middle ground between traditional and Western lifestyles and, like any ideal compromise, the vision presents a great challenge to the institutions of Kotzebue and the region. 7.1.2 Population The most recent Alaska Department of Community and Regional Affairs population figure for Kotzebue is 3, 705. Estimates of average household size range from 3.5 to 4.1 persons, with the most likely average falling at the upper end of the range. Demand for new housing outstrips available housing stock as of 1988. The NANA birth rate generally exceeds the Alaskan rate and the rate for other northwest rural regions. Current forecasts by the City of Kotzebue and Kotzebue Electric Cooperative place the rate of population growth at 4.36 and 4.@ percent respectively. Their estimates of Kotzebue’s year 2000 population are 5,901 and 5,583 respectively. The median age of Kotzebue’s Native population has been rising steadily since 1970 when it was registered at 16.3 years. By 1980, the comparable figure had climbed to 21.1 years and permanent fund recipient data for the entire Kotzebue population indicates a continued rise through 1985, when the median age for the population as a whole was 24.9 years. 7.1.3 Economy 7.1.3.1 Employment According to the April 1980 Census, total employment at Kotzebue, including selfemployed, was 718 (see Table 7-1). This was almost double the employment figure of 364 persons recorded by the 1970 Census. The Alaska Department of Labor’s tally of covered wage employment for April 1980 was 1,165, or 62 percent higher than the Census figure. TABLE 7-1 Employment by Industry, 1970 and 1980 1970 198@ Construction 5 29 Manufacturing @ 4 Transportation 45 66 Communications ry} 41 Trade 52 98 F.I.R.E. 8 19 Services 132 290 Public Administration 39 167 Other 61 4 TOTAL 364 718 Source: 198@ Census At Kotzebue, as in many other rural communities, the Census appears to have classified some public service employment as service and underreported public sector employment. On the other hand, the Alaska Department of labor local government employment figures for Kotzebue were likely inflated by the inclusion of all Northwest Arctic School District and all Maniilaq Association employees, regardless of their actual place of work. Thus, the Department of Labor’s local government employment figures and its total employment figures for Kotzebue appear overstated). Table 7-2 summarizes Alaska Department of Labor average annual wage employment by industry in Kotzebue over the period 1980 to 1986. According to the Department of Labor data, total employment increased by 25 percent between 1980 and 1986. Major gains in local government, trade, and state government employment levels were partly offset by losses in federal employment and transportation/ communication/public utilities. The data series for the service sector is spotty but suggest some gains in that sector also, but it should be recalled that the classification of nongovernmental service agencies (e.g., Maniilaq Association) fudges this sector’s figures. Kotzebue’s wage employment pattern exhibits only a mild degree of seasonality. The peak employment months have tended to be September and October, while the low employment months were January through March and July. See Table 7-3. TABLE 7-2 Covered Industry Employment City of Kotzebue 1980-1986 Industry Classification 198@ 1981 1982 1983 1984 Mining @ @ 7) @ ® Construction 36 * * * 164 Manufacturing = @ @ @ @ Transportation, 125 151, 196 194 182 Communication and Public Utilities Trade 113 155 205 189 161 Finance, Insurance a 40 a7! 42 a and Real Estate Services 138 165% 170° * * Government Federal 210 202 139 110 122 State 58 50 58 80 86 Local 449 600 727 506 538 Miscellaneous # ia oi . * TOTAL 1,160 1,443 1,568 1,366 1,399 1985 i19) 169 78 231 136 91 575 * 1986 99 211 66 151 90 560 * 1,417 1,449 . Figures withheld to comply with disclosure regulations. § prorated from nine months of data. > prorated from six months of data. Source: Alaska Department of Labor. January February March April May June July August September October November December Annual Av Source: TABLE 7-3 Average Monthly Employment City of Kotzebue, 1980-1986 Average Monthly Percent Difference Employment From Annual Average 1,338 -4.4% 1,355 -3.2 1,344 -4.0 1,402 +@.1 1,425 +1.8 1,401 +@.1 1,326 -5.3 1,405 +0.4 1,512 +8.0 1,456 +4. 1,429 Ziad 1,410 +0.7 erage 1,402 Alaska Department of Labor. According to preliminary results of the 1988 NANA Region Social Indicators survey of four local communities, 15 of 65 or 23 percent of the sample heads of household worked away from their home community during 1986. The practice of pursuing employment outside the home community on a rotation schedule or seasonal basis is poorly accounted for in official employment data but promises to become increasingly important. This practice has long been widespread within the region. For example, Saario (1966) commented on the habit of many Kivalina men in the late 1950s to find summertime work at longshoring in Kotzebue, construction in Fairbanks and firefighting wherever needed. Kivalina workers later showed this same mobility during the pipeline construction era; a study of Alaska Native hire on the pipeline project (Institute of Social and Economic Research, 1978) found that 31 Kivalina residents, fully one-sixth of the total population, had worked on the project. Kivalina may be an extreme case of this particular adaption to the dearth of local cash employment opportunities, but these data help show that this work pattern is familiar and acceptable to part of the region’s workforce. NANA Development Corporation's ownership interest in a variety of construction, camp operation, security and similar enterprises in the Prudhoe Bay oil patch has given many of its shareholders access to a pool of regular employment outside their home communities, often outside the region, on a rotation basis. And, for the future, the NANA/Cominco strategy for staffing of the Red Dog mine aims to recruit a share of Kotzebue and village residents to work on a rotation schedule at the mine site. Based on the Social Indicators NANA Region sample, average yearly household income is $25,390. This figure is heavily influenced by a handful of very high incomes that exceed $60,000. In this case it is useful to examine the median income, which is $20,000. About one-quarter (28 percent) of the sample incomes were $8,000 annually or less. We have not calculated a cost of living differential for the region, but it is fair to say that these incomes buy far less than they would in metropolitan centers of the state. According to the Northwest Arctic Borough economic surveys of 1987 and 1988, unemployment is a chronic problem in the area. In 1987, 60 percent of the regional “labor force" respondents indicated that they were unemployed. In 1988, the percentage reached 63 percent. The survey reported that, in Kotzebue, 38 percent of the unemployed respondents for 1987 had not worked in the last eight months. In 1988 in Kotzebue, 16 percent of the unemployed respondents had not worked in the last eight months. Although the long-term unemployment problem may eventually diminish when the Red Dog mine starts operation, the survey results show that economic dependency remains a serious concern. In 1987, 59 percent of the Kotzebue respondents indicated that they would be willing to relocate for or commute to a job, and in 1988, the figure was 48 percent. 7.1.3.2 Cost of Living Average and peak yearly expenses in several categories are summarized in Table 7-4 from the MMS Regional Social Indicators sample. The market basket survey provides a great deal of detail on food and other commodity expenses in the region. It is fair to say that these cash expenses seriously undercut the economic status of many regional residents who have access mainly to low and intermittent sources of income. In addition, those residents who are most impoverished cannot afford to make bulk seasonal purchases of food and nonperishable goods, hence they pay a proportionally higher cost of their low incomes for a modest standard of living. TABLE 7-4 Average Household Expenditure, 1987 Average Household Expenditure Rent/Mortgage $3,897 Heat 1,820 Electricity 869 Telephone 865 Other Utilities 845 TOTAL $8,296 Note: 1) Source: McNabb, 1987c. 2) Includes Kotzebue, Buckland, Deering, and Kivalina Table 7-5 displays the March 1988 weekly cost of a Market basket of food for a family of four for Kotzebue and other selected urban and rural regional centers, compiled by the University of Alaska Cooperative Extension Service. By this measure, weekly food costs in Kotzebue ($144.96) were 65 percent higher than in Anchorage ($88.08) and exceeded only by Nome. 7- 10 TABLE 7-5 Weekly Cost of Market Basket of Food March, 1988 Community Weekly Cost U.S Avg. S$ 86.60 Anchorage 88.08 Fairbanks 90.14 Bethel 139207 Dillingham 140.08 Kotzebue 144.96 Nome 146.99 Note: 1) Average weekly cost is estimated for a family of four. 2) Source: University of Alaska, Cooperative Extension Service. 7.1.4 Project Impact 7.1.4.1 General Overall, the effects of construction of a coal fired power plant in Kotzebue are thought to be minimal. The effects will be in three major areas: the effects of employment and spending during construction; the effects on the manpower requirements for plant operation; and the long term electric and heating pricing effects to the consumer. 7.1.4.2 Construction Employment and Spending It is expected that construction of the coal fired plant in Kotzebue will require an estimated 24,000 > uk man hours of time with a total of $750,000 estimated in expenditures. During the period 198@ through 1986, Kotzebue averaged a total of 1,400 average full time jobs. Kotzebue experiences mild seasonal fluctuations in its unemployment rate. 1980 through 1986 seasonal employment rates for Kotzebue varied. Unemployment is at its highest from January through March, and at its lowest September and October. The 24,00@ man hours for construction is equivalent to approximately 11.5 full time, year round jobs. Approximately 80% of the jobs will be filled through local hire and contracting. Construction of the plant is expected to take some twelve months. construction employment would peak shortly after arrival of materials in Kotzebue, and would overlap, in part, with the lowest seasonal unemployment rate. The addition of this employment to the Kotzebue job market would have the effect of reducing the unemployment rate during construction and of injecting some $750,900 in payroll and benefits into the community. In addition to the employment boost, the community will also experience the input of expenditures totalling an estimated $750,000 for additional supplies and materials. These might range from the 7 - 12 purchase of materials such as gravel for fill to the purchase of electrical supplies by a locally hired contractor. Overall, the construction phase of the project will inject close to $1.5 million into the Kotzebue economy. 7.1.4.3 Plant Manpower Requirements The new coal fired power plant in Kotzebue will require a crew compliment of twelve, year-round workers. Classification Number Supervisor 1 Clerical/Bookkeeper 1 Power Plant Operators 4 Operator Assistants 4 Material Handlers 2 Total 12 This is an addition of two workers to the current workforce. These two positions are the "material handlers", required to handle the coal. This addition to the workforce provides Kotzebue with two additional full time workers and infuses approximately $166,000 in salaries and benefits into the Kotzebue employment economy. 7 - 13 7.1.4.4 Pricing Effects The installation of a coal fired power plant in Kotzebue will substantially reduce the cost of power generation in the future, as compared to the continuing escalation of the cost of diesel generation. A comparative analysis of the projected costs show: 1) Diesel With District Heating System; and Year 2000 2005 2010 2014 Tot Power 3221 4743 6998 9618 Gen. Cost* Elec. Cost @.136 @.175 @.226 @.280 ($/KWH) 2) Coal With District Heating System. Year 2020 2005 2010 2014 Tot Power 2572 3513 4799 6165 Gen. Cost* Elec. Cost @.109 @.130 @.155 @.179 ($/KWH) * in thousands of current dollars Coming on line in 1995, the coal fired power plant could save the Kotzebue community a total of $649,000 in power and heat generation costs in the year 2000. By the year 2014, those savings would exceed $3,450,000. 7- 14 These savings would be realized in several ways. The cost per kilowatt hour to the consumer will be reduced. The current presence of the Alaska Power Cost Equalization Program may prevent many residential power consumers from realizing the direct benefits of the reduced power generation costs. Business and industrial users who are not part of the Program, will realize the savings. The State of Alaska may realize savings as the cost to operate the Power Cost Equalization Program may diminish as a result of lessened power generation costs. 7.2 Nome 7.2.1 Population Table 7-6 presents a compilation of population estimates from the U.S. Census and various other sources since the first official census at Nome in 1880 through 1988. The tabular data show Nome’s abruptly and briefly teeming gold rush population, its post-gold rush decline, and its slow long-term growth after World War I. In the years following the flawed 1980 Census, a wide discrepancy has arisen between Nome population estimates accepted by the Alaska Departments of Labor and Community and Regional Affairs, respectively, as shown in Table 7- 6. By 1986, the Department of Labor’s estimate was 3,208 persons compared to the City of Nome’s estimate, accepted by the Department of Community and Regional Affairs, of 3, 876 persons. According to Kevin Waring Associates, an examination of trends in natural increase, school 7 = 35 Year 1880 1900 1910 1915 1920 1930 1939 1950 1960 1960 1967 1968 1969 1970 1978 1975 1975 1976 1976 1978 S79 1980 1980 1980 1981 1982 1982 1983 1983 TABLE 7-6 Population Estimates Nome 1880-1988 Sources of Census Other Estimates Other Estimates 20 (recorded as Chitnashuak) 12,488 2,600 1,000 Osborn (per Koutsky) 852 Lj2is 1,559 1,876 2,316 2,320 Ak.Dept. of Labor (July) 2,450 Federal Field Committee 534 Native; 916 non- Native 2,800 Alaska Area Native Health Service - 1,852 Natives 2,800 Federal Field Committee - 1,950Native; 850non- Native 27a Si 2,380 Ak. Dept. of Labor (July) Zale U.S. Census Bureau 2,380 Ellanna 2,542 U.S. Census Bureau 2,605 CH2M Hill 2,892 City of Nome (July) 2,842 Policy Analysts, Ltd. 2,301 2,430 Ak. Dept. of Labor (July) 2, 892 Dept. Community/Regional Affairs 3.039 Ak. Dept. of Labor (July) 3,416 U.S. Census Bureau (July) 3,430 Ak. Dept. of Labor (July) 3702 Ak. Dept. of Labor (July) 3,620 Dept. Community/Regional Affairs (Continued) 7 26 Year 1984 1984 1984 1985 1985 1986 1986 1986 1987 1988 TABLE 7-6 (Continued) Sources of Census Other Estimates Other Estimates 2,904 U.S. Census Bureau (July) 3,146 Ak. Dept of Labor (July) Sz73e Dept Community/Regional Affairs. 3,236 Ak. Dept. of Labor (July) 3,876 Dept. Community/Regional Affairs. 3,208 Ak.Dept of Labor (July). 3,876 Dept Community/Regional Affairs. 3,876 Dept Community /Regional Affairs. 3,876 Dept. Community/Regional Affairs 4,303 Dept Community/Regional Affairs. enrollment and Permanent Fund dividend applications supports a figure closer to the Alaska Department of Labor’s estimate. Recent vital statistics suggest two important conclusions about Nome’s population: (1) that natural increase contributed more to Nome’s net population growth than immigration, at least through the 1970s and early 1980s, and (2) that birth rates in the Nome area, after a decline in the 1960-1970s, are again rising. The average household size at Nome increased significantly between 1939 and 1970, from 2.5 to 4.0 persons per roon. This increase probably reflects 7 =~ 37 changes in Nome’s population composition and housing stock. The post-197@ data indicate that average household size has since declined. Between 1970 and 198@ the average number of rooms per housing unit was increasing. The average rose from 2.5 rooms per dwelling in 1939 to 3.3 rooms in 1970 to 3.4 rooms in 1980. Thus, while households were getting smaller, homes were getting roomier. 7.2.2 Economy 7.2.2.1 Employment In 1988, government was the largest economic sector in Nome, followed by services, mining and trade; see Table 7-7. State and local government employment grew during the first half of the decade, but recently have begun to decline. State government alone accounted for close to 300 employees. federal employment declined slightly, primarily because several programs have been contracted out of local entities. Service sector employment has been relatively level during the past two or three years. 7- 18 TABLE 7-7 Average Annual Full-time Employment Nome, 1988 Industry Classification Number Percent of Total Agriculture, Forestry and 4.0 @.2 Fishing Mining 300.0 L726 Contract Construction 52.0 3.1 Manufacturing SS @.2 Transportation, Communication 162.5 9.6 and Public Utilities Trade 227.5 13.4 Finance, Insurance and Real 42.0 2.8 Estate Services 370.2 21.8 Government 539.0 31.7, Federal ( 90.0) ( 5.3) State (298.5) (17.6) Local (150.5) ( 8.9) TOTAL EMPLOYMENT 1,700.5 100.0 Source: Kevin Waring Associates employment inventory, 1988. Norton Sound Health Corporation is by far the largest employer. Kawerak is also a major service sector employer. In the case of mining, the figures show an upward trend consistent with the recent revival of Nome’s mining industry. There is increased activity in both offshore and onshore gold T1939) mining activities. Nome has had a relatively large trade sector for many years. Total employment in this sector appears relatively stable. (See Table 7-7). During the first half of 1988, contract construction was at a high level, primarily due to construction of the new elementary school and an addition to the hospital. Employment in the transportation/communication/publicutilitiessector has been stable, despite changes in air carrier service. The finance/insurance/real estate sector has declined somewhat. Nome’s manufacturing sector is represented by one firm - the local newspaper. The 1982 Division of Subsistence survey found that 41 percent of Native households and 32 percent of non-Native households were self-employed to some degree. Commercial fishing for chum salmon and herring is perhaps the most important, if seasonal source of self-employment and cash income for many Nome households. That survey also found that every household whose residents originated outside the region had at least one member employed on a full- time basis. The occupational composition of Nome’s workforce in 1985 closely resembled the statewide workforce, according to an Alaska Department of Labor survey. Nome had about half again as many professional and technical workers as the statewide workforce, but varied from statewide norms for other occupational groups by no more than a few percentages points. 7 - 20 Income assistance programs are a source of income to some low-income families and individuals in Nome. Average monthly payments data to Nome residents for three key income assistance programs. (Aid to Families with Dependent Children, Food Stamps, AFDC and Food Stamps Combined Cases) show that in 1986, the joint contribution of these programs to the cash income of Nome residents averaged $54,640 monthly. For comparison, for 1986, the Department of Labor reported average monthly earnings, exclusive of self-employment, of $4,439,330 at Nome. Thus, cash payments from these transfer programs accounted for less than 2 percent of cash income and do not appear to comprise a large share of total personal cash income for Nome residents. According to a recent Bureau of the Census report, the 1983 per capita income level for the City of Nome, ($11,180), was slightly below the statewide average, ($12,900), but about on par with the other western Alaska regional centers. 7.2.2.2 Unemployment Rates During 1985 to 1987, the Nome region’s official unemployment rate fluctuated between 11.9 percent and 12.9 percent, hovering just a couple of points above the statewide average unemployment rate. However, these figures most likely understate unemployment in the region and in Nome, as many discouraged workers and chronically unemployed in rural Alaska are not counted as part of the active workforce. 7 - 21 Non-resident workers (that is, workers who maintain their residence outside Alaska) capture a significant share of jobs and wages in the Nome Census Area. Non-residents filled about 13 percent of job openings in the Nome Census Area in 1984 and 15 percent in 1985. In general, the private sector employed a higher ratio of non-residents (18.5 percent) than the public sector (10.4 percent). Non-residents were most prominent in the mining industry, where they held almost 44 percent of the jobs and earned 4@ percent of wages in 1985. 7.2.2.3 Cost of Living In rural Alaska, the high cost of bought goods significantly deflates the purchasing power of cash income. This cost inflation particularly erodes the standard of living of rural residents who have low cash incomes and depend upon purchased goods and commodities rather than subsistence provisions. While there is no current comprehensive consumer price index data for Nome, the University of Alaska Cooperative Extension Service has compiled data on food costs at Nome and several other Alaskan communities. According to its March 1988 study, weekly food costs in Nome were among the highest in Alaska. Thus, Nome costs ($146.99 weekly) were 67 percent higher than in Anchorage ($88.08), about 5 percent higher than in Dillingham or Bethel, and slightly higher than in Kotzebue. See Table 7-5. The cost of purchased foods seriously undercuts the economic status of many Nome residents with low and intermittent sources of income who cannot afford to 7 - 22 make bulk seasonal purchases of food and other non- perishable goods. Another source of comparative data on the rural cost of living is the State of Alaska’s "cost of living differential” index developed to adjust State salary scales to regional variations in the cost of living. A 1985 study determined that the cost of living in the Nome region was 133 percent higher than the Anchorage base level. This was higher than the differential for the Bristol Bay region (129 percent), but under the figure for the Bethel region (139 percent) and well below the figure for the Barrow/Kotzebue region (145 percent). 7.2.4 Project Impact 7.2.4.1 General Overall, the effects of construction of a coal fired power plant in Nome are thought to be minimal. The effects will be in three major areas: the effects of employment and spending during construction; the effects on the manpower requirements for plant operation; and the long term electric and heating pricing effects to the consumer. 7.2.4.2 Construction Employment and Spending It is expected that construction of the coal fired power plant in Nome will require an estimated 31,000 man hours of time with a total of $1.5 million estimated in expenditures. 7 ~ 2 During 1985 to 1987, the Nome region's official unemployment rate fluctuated between 112.9 percent and 12.9 percent. During 1988, Nome averaged a total of 1,700.5 average full time jobs. From 1980- 1986, Nome averaged 1,754 jobs. Nome experiences seasonal fluctuations in its unemployment rate. 1986 rates for Nome area varied from a high of 17.4% to a low of 10.5%. Unemployment is at its highest from March through June, and at its lowest September through November. The 31,000 man hours for construction is equivalent to approximately 15 full time, year round jobs. Approximately 80% of the jobs will be filled through local hire and contracting. Construction of the plant is expected to take some twelve months. Construction employment would peak shortly after arrival of materials in Nome, and would overlap, in part, with the lowest seasonal unemployment rate. The addition of this employment to the Nome job market would have the effect of reducing the unemployment rate by one percent during construction and of injecting some $900,000 in payroll and benefits into the community. In addition to the employment boost, the community will also experience the input of expenditures totalling an estimated $1.5 million for additional supplies and materials. These might range from the 7 - 24 purchase of materials such as gravel for fill to the purchase of electrical supplies by a locally hired contractor. Overall, the construction phase of the project will inject close to $2.5 million into the Nome economy. 7.2.4.3 Plant Manpower Requirements The new coal fired power plant in Kotzebue will require a crew compliment of twelve, year-round workers. Classification Number Supervisor 1 Clerical/Bookkeeper Power Plant Operators Operator Assistants Material Handlers NY iv ® 82 Total i This is an addition of two workers to the current workforce. these two positions are the "material handlers", required to handle the coal. This addition to the workforce provides Nome with two additional full time workers and infuses approximately $166,000 in salaries and benefits into the Nome employment economy. 7 =- 25 7.2.4.4 Pricing Effects The installation of a coal fired power plant in Nome will substantially reduce the cost of power generation in the future, as compared to the continuing escalation of the cost of diesel generation. A comparative analysis of the projected costs shows: 1) Diesel With District Heating System: and Year 2000 2005 2012 2014 Tot Power 5386 8321 13051 18458 Gen. Cost* Elec. Cost @.144 @.187 @.248 @.305 ($/KWH) 2) Coal With District Heating System Year 2000 2005 2010 2014 Tot Power 4926 6335 9712 13072 Gen. Cost* Elec. Cost @.132 0.153 @.184 @.216 ($/KWH) * in thousands of current dollars 7 - 26 Coming on line in 1995, the coal fired power plant could save the Nome community a total of $460,000 in power and heat generation costs in the year 2000. By the year 2014, those savings would exceed $5,000,200. These savings would be realized in several ways. the cost per kilowatt hour to the consumer will be reduced. The current presence of the Alaska Power Cost Equalization Program may prevent many residential power consumers from realizing the direct benefits of the reduced power generation costs. Business and industrial users who are not part of the Program, will realize the savings. The State of Alaska may realize savings as the cost to operate the Power Cost Equalization Program may diminish as a result of lessened power generation costs. T- 27 8.@ CONCLUSIONS AND RECOMMENDATIONS 8.1 Conclusions The Kotzebue and Nome Coal Study indicates the conversion from oil to coal is technically and economically feasible, as well as environmentally attractive for the application of this study. There does not appear to be any "fatal flaws’ to the project. The cash flow analyses of both the Kotzebue and Nome installations are positive. For instance, installed in 1995, it is estimated Kotzebue would save $649,000 annually by the year 200@ and $3.4 million annually by the year 2014. For Nome, savings would amount to $460,00@ a year by the year 2000 and $5 million annually by 2014. In 1988, Nome and Kotzebue together received just over $1 million dollars from the state in Power Cost Equalization Program (PCE). Implementation of this project is anticipated to diminish and possibly eliminate PCE assistance in both communities. Both the conventional steam Rankine cycle and the European externally fired Brayton (air turbine) cycle were found suitable power cycles for this application. The air turbine was preferred primarily because it does not use water. This was particularly important for the community of Kotzebue. A circulating fluidized bed combustor was selected as the preferred combustion technology, based on the results of a combustion test performed on Western Arctic coal by Battelle Memorial Institute. Fluidized bed combustors were found to be superior in emissions control, easier to operate than the conventional coal-burning units, and commercially available in the small size range required by this project. These combustors are best suited to burn low ash fusion temperature coals, such as Western Arctic coal. The circulating fluidized bed technology was preferred over other fluidized beds because of its superior combustion efficiency, reduced erosion and corrosion of the heat transfer surface, and its’s ability to better control turbine inlet temperature. The district heating options proposed, offered higher power plant thermal efficiencies and better economics. Further, district heating reduced environmental emissions community wide as a result of displacing individual building oil-fired heating units. Although further evaluation is required, it appears several benefits can be derived in the communities from implementation of this project such as : reductions in the cost of providing power and energy in both communities. This in turn should stimulate the economies of both communities; increase permanent employment in both communities by 2 each, full-time jobs; and provide a boost to the local economy due to the construction of the facilities. Related to the Kotzebue and Nome Coal Study is the Western Arctic Coal Development Project (WACDP). This economic development project performed an in-depth feasibility effort that established the economics of mining coal in the Western Arctic. The Kotzebue and Nome Coal Study was a preliminary feasibility effort looking at the initial in-state market identified by the WACDP. The WACDP proposed to resolve the energy concerns of Northwest Alaska by developing a coal industry in the Western Arctic to supply an energy alternative to the region. This approach would resolve the energy problems by: 1) providing an abundant and economic energy source for local consumption; and 2) providing cash income opportunities to the residents of the area which could be used to pay for fuel and other necessary items. Critical to the WACDP’s ability to provide a stable priced energy source over time was the regional concept of the project. Since the price of fuel is dependent on the annual production level at the mine, it was determined that any increases in the production level would decrease the price of coals as better economies of scale are achieved in both coal production and transportation. The WACDP anticipated future penetrations into the in-state markets thereby reducing or stabilizing the price of coal to all in-state customers. The marketability of the coal source is key to making the WACDP regional concept a reality. Several findings of the Kotzebue and Nome Coal Study support the overall concept of the WACDP: 1) the Nome and Kotzebue coal demand is sufficient, (57,000 tons per year), and exceeds the initial market estimate, (47,900 tons per year), determined by WACDP Phase III Final Report to be the viable startup coal demand for the mine; 2) Nome’s conversion to coal has the potential of providing a surplus (profit) of between $26 million, based on the Nome and Kotzebue coal demand, to $45 million, based on the Nome, Kotzebue and Red Dog coal demand. This demonstrates the regional concept of WACDP whereby future market increases would provide price reductions. 3) The Deadfall Syncline coal resource has sufficient quantity to meet any future in-state growth in demand beyond the Nome and Kotzebue demand. 4) Along with the quantity the quality of Deadfall coal lends itself well to future market penetrations in the region or for export sales. Although further evaluation is needed it appears the overall proposed economic development project offers significant long term benefits to the Northwest Alaska region, Cities of Nome and Kotzebue; residents of the region, the State of Alaska and both North Slope and Northwest Arctic Boroughs. These long term potential benefits appear to outweigh any potential negative impacts and warrants further investigation by the State of Alaska. 8.2 Recommendations Results of this study and the WACDP suggest any future project activities include both, end-use technology (communities) and resource developments. The ANF Project Team recommends an in- depth engineering feasibility assessment, (design phase), be performed on developing: 1) coal-fired power plant and district heating facilities for the communities of Kotzebue and Nome; 2) a coal mining industry in the Western Arctic designed to meet the energy demands of both communities; and 3) the economic feasibility of developing the Red Dog Mine to use Western Arctic coal. This next phase of the overall economic development project would be the information gathering, design and final determination phase of the project. Completion of this phase would provide: 1) final economic assessment and substantial design completion for the Kotzebue and Nome coal-based facilities; and 2) substantial design completion for the development of the coal resource. The completed document would be used as a control document for project permitting, design document and bid preparation, and construction. The following is a list of major tasks proposed to be performed in the design phase. Baseline Data and Monitoring Programs Nome and Kotzebue: 1) determine heating and power needs of each community as a function of time and weather; 2) determine emissions from the existing diesel power plants; and 3) assess environmental impact. Coal Mine: 1) determine movement and activities of the Beluga whales around the coastal area to establish a specific site for marine berthing; and 2) perform vegetation studies in the field to test and demonstrate procedures for reclamation of the impacted area. Red Dog Mine: 1) Determine heating and power requirements. Power Plant Development Mine Nome and Kotzebue: 1) 2) 3) select sites for power plant, coal storage, and for Kotzebue a marine berthing site; establish the power generation and district heating design parameters for Nome and Kotzebue. In Nome an effort should be made to determine the gold companies’s commitment to connect to the city’s power facilities. If the potential is there and the load is significant an evaluation of both the steam Rankine and externally fired Brayton cycles should be evaluated for economic feasibility; and perform conceptual and detail designs and cost estimates for each community system. Red Dog Mine: 1) investigate providing power to Red Dog by developing coal-fired cogeneration facilities at the Red Dog site; and 2) investigate providing power to Red Dog by developing mine mouth power plant at the coal mine site with overhead transmission of power to the Red Dog site. Development Coal Mine: 1) perform a detailed geologic evaluation of the mining unit to define the unit in terms of reserve and economics for supplying both communities; 2) perform infrastructure geotechnical investigation for the design of the infrastructure facilities; 3) determine port, camp and road alignment locations; 4) prepare detail design and cost estimates; and 5) obtain permits and perform archaeological clearing as required. Project Development 1) perform a marine transportation evaluation; 2)) perform a final economic analysis; 3) conduct a financial feasibility assessment. 9.@ REFERENCES Arctic Slope Consulting Engineers; 1986; Western Arctic Coal Development Project, Phase II, Final Report, Volumes 1 & 2. Arctic Slope Consulting Engineers; 1988; Western Arctic Coal Development Project, Phase III, Final Report. Arctic Slope Consulting Engineers; 1986; Western Arctic Coal Development Project, Village End Use Technology Assessment. C.C. Hawley and Associates; 1983; Northwest Alaska Coal Investigation: Alaska Division of geological and Geophysical Survey. Erlich, Richard; 1989; Personal Communication. Handleman, John: 1989; City of Nome. Personal Communication. Hawley Resource Group; 1986; Preliminary Feasibility Study of a Coal Mine at Chicago Creek Summary Report: Alaska Division of Geological and Geophysical Survey. Kevin Waring Associates; 1988; Kotzebue Sociocultural monitoring Study, Final Technical Report. Prepared for U.S.D.0O.I., Minerals Management Service. Kevin Waring Associates: 1988; Nome Sociocultural Monitoring Study, Final Technical Report. Prepared for U.S.D.0.I., Minerals Management Service. Makansi, Jason; 1990, "Fuel Type Preparation Energy as Critical to FBC Design" in Power Magazine, Vol. 134, No. 1, pp. 41-44. Morrison-Knudsen Engineers Inc.; 1989; Power Requirements Study, Alaska 13 Kotzebue Murphy, Joe; 1989; Nome Joint Verity: Personal Communication. Polarconsult Alaska, Inc.; 1983; Nome Waste Heat Utilization Project. Polarconsult Alaska, Inc., 1987; Nome Waste Heat Feasibility Study. Prchal, Polly; 1989; City of Nome. Personal Communication. Reeve, Brad; 1989; Kotzebue Electric Association. Personal Communication. Scott, Mike; 1989; City of Kotzebue. Personal Communication. Smith, Jeff; 1989; Kotzebue Electric Association. Personal Communication. APPENDIX A WESTERN ARCTIC COAL STUDIES AND INVESTIGATIONS 198@ - 1990 Many state and local governments, and privately sponsored coal studies involving the western Arctic coal resource have been conducted from 198@ to the present. Their findings have presented the technical and economic feasibility of developing a local coal mining industry in the Western Arctic serving the needs of an in- state market. In addition to the studies geologic investigations and exploratory drilling programs were conducted in the area during the 8@s. Results have significantly augmented the Western Arctic Coal Resource data base that began in the 1920s. Following is a list of studies and resource investigations involving the Western Arctic coal resource that were performed in this decade. 1980 Assessment of Coal Resources of Northwest Alaska - for Alaska Power Authority (APA). 1981 Assessment of the Feasibility of Utilization of Coal Resources of Northwestern Alaska for Space Heating and Electricity - for APA. 1981 Point Lay and Point Hope Coal Conversion Study - for North Slope Borough (NSB). 1982 Kotzebue Coal-Fired Cogeneration District Heating and Other Energy Alternatives Feasibility Assessment for APA. 1983 1983 1983 1984-1988 1985 1986-Present 1988-Present 1989 1989 1989 1989 An Economical and Technical Assessment of the Marketability of Western Arctic Slope Coals - for State of Alaska Division of Legislative Finance (ADLF). Western Arctic Coal Resource Assessment - for ADLF. Northwest Alaska Coal Assessment, Exploratory Drilling Program - for State of Alaska Division of Geological and Geophysical Survey Western Arctic Coal Development Project, Phases I-III. - for State of Alaska Division of Community and Regional Affairs. Western Arctic Coal Geophysical Program - for Arctic Slope Regional Corporation (ASRC). Western Arctic Coal Demonstration Program, Phases I - IV for NSB. Deadfall Syncline Coal Mining Permit Application - for ASRC Deadfall Syncline Coal Evaluation, Combustion Tests - for ASRC. Pacific Rim Marketing - for ASRC. Barrow Power Generation Coal Conversion Study - for NSB. Kotzebue and Nome Coal Study - for Alaska Energy Authority. APPENDIX B Deadfall Syncline Coal Evaluation PROJECT REPORT on DEADFALL SYNCLINE COAL EVALUATION to ARCTIC SLOPE REGIONAL CORPORATION Barrow, Alaska March 16, 1989 by Richard E. Barrett, Robert D. Litt, and Ted L. Tewksbury BATTELLE MEMORIAL INSTITUTE 505 King Avenue Columbus, Ohio 43201-2693 PROJECT REPORT on DEADFALL SYNCLINE COAL EVALUATION to ARCTIC SLOPE REGIONAL CORPORATION Barrow, Alaska by Richard E. Barrett, Robert D. Litt, and Ted L. Tewksbury BATTELLE MEMORIAL INSTITUTE March 16, 1989 INTRODUCTION ASRC requested evaluation of the Alaskan Deadfall Syncline coal to determine combustion characteristics in a fluidized-bed combustor (FBC) and conventional furnaces. Battelle proposed small-scale tests to evaluate the fuel, ash slagging/fouling behavior and sulfur capture. The small scale minimized the quantity of coal required; this was important as this coal was from a new source and had to be specially obtained for the tests. Test results will be used to evaluate use of the coal in an indirect-fired Brayton cycle facility for cogeneration (electricity and district heating) in selected Alaskan cities. A subsequent engineering study (Kotzebue/Nome Coal Study) by ASRC, MTI, and Battelle will use the test results to develop the specific applications. The test results will also be used to help ASRC develop marketing plans outside Alaska. The coal's low sulfur content should be attractive to many buyers and the test results should aid customers in predicting large-scale performance. 2 OBJECTIVE The project objective is to conduct 2 tests (one in suspension-fired unit and one in FBC) to evaluate combustion performance of Deadfall Syncline coal. Test results will be used to evaluate carbon burnout, sulfur capture and ash behavior in each combustion system. APPROACH Battelle crushed and pulverized the coal for testing to nominal -8 +20 mesh size for the FBC test and -200 mesh for the suspension firing test. These fuel sizes are consistent with general practice for each combustion system. A sample of each sized coal was analyzed for proximate, ultimate and ash analysis. The results are included in Appendix A. Each test facility was prepared by calibrating the coal feeder and air flow meter. Continuous flue gas analyzers were connected and calibrated for the test conditions. Each unit was operated for a brief check-out trial prior to the specific test. Test conditions were established based on the test plan and the limitations determined during the facility check-out. Fuel Evaluation The proximate and ultimate analyses of two coal samples (Appendix A) are consistent with each other and with coal analyses provided by ASRC. It was concluded that the coal samples were representative and suitable for use in combustion tests. The volatile and fixed carbon contents are relatively close to a Montana Rosebud coal (subbituminous). Table 1 provides a comparison of the Deadfall Syncline coal and Montana Rosebud coal. It is not obvious whether the Deadfall Syncline coal would be classified as a bituminous or a subbituminous coal. 3 TABLE 1. COAL ANALYSES Deadfall Syncline Montana’ BX 20 Mesh -20 Mesh Rosebud Proximate Analysis (dry) Volatile Matter, % 38.39 33.16 39.02 Fixed Carbon, % 58.93 63.46 51.82 Ash, % 2.68 3.38 9.16 Heating Value, Btu/1b 12,186 11,939 11,684 Ultimate Analysis (dry) Carbon, * 73.66 72.69 68.39 Hydrogen, % 4.25 4.08 4.64 Nitrogen, % 1.60 1.56 0.99 Sulfur, * 0.20 0.19 0.79 ne % 2.68 3.38 9.16 ccvget % iby diff.) 17.61 18.10 16.01 hlorine, % 0.04 0.04 . 0.02 Ash Analysis $i0. 29.14 26.11 35.4 ald, 25.39 21.88 19.3 0.62 0.57 0.8 red, 7.79 10.10 5.6 cb 12.74 16.24 17:8 6.53 8.74 4.4 KO. 0.77 0.61 0.1 Na,0 0.47 0.49 0.3 SO, 12.50 11.87 16.3 P20, 1.24 1.27 0.3 sto 0.49 0.49 - Bad 1.60 1.38 - MnO 0.00 0.00 - Undetermined 0.72 0.52 - * (Coal Conversion Systems Technical Data Book, DOE/FE/05157-1, June 1982. 4 The ratio of fixed carbon to volatile matter for the Deadfall Syncline coal ranges from 1.5 to 1.9 based on the two samples analyzed. This ratio indicates the expected ease of combustibility of as coals with higher volatile matter burn more readily. The volatile matter content of the Deadfall Syncline coal is sufficiently high to expect excellent carbon burnout. The sulfur content of the Deadfall Syncline coal is very low making it an attractive fuel for users in locations where SO, emissions are strictly controlled. If all the sulfur in the coal were released as SO, it represents 0.33 1b $0,/10® Btu or 290 ppm in flue gas with 3.5 percent 0,. This SO, emission compares favorably with the U.S. EPA's New Source Performance Standard (NSPS) maximum limit for power plants of 1.2 1b S0,/10° Btu. The NSPS is more complicated for low-sulfur fuels such as Deadfall Syncline. For coal containing sulfur equivalent to 0.6 1b S0,/10® Btu or less, 70 percent sulfur removal is required to a minimum level of 0.2 1b $0,/10° Btu. Local authorities can require more stringent SO, controls. The most notable of these are California and Japan where SO, emissions are controlled to less than 0.1 1b $0,/10° Btu. The Deadfall Syncline coal can meet stringent emissions such as this with current state-of-the-art technologies such as fluidized bed combustion or flue gas desulfurization. The nitrogen content of the Deadfall Syncline coal samples was about 1.6 percent; this is slightly high relative to typical coal analyses which average 0.75 to 1.5 percent. For coal firing, fuel nitrogen content is the major contributor to NO, emissions which are increasingly becoming as important as SO, in environmental regulations. For industrial/commercial coal-fired boilers, NO, emissions are based on the type of combustor. They are 0.6 1b NO,/10° Btu for spreader stokers and 0.7 1b NO,/10® Btu for pulverized coal-fired units. The classification of the Deadfall Syncline coal as either bituminous or subbituminous becomes important as the NSPS emission levels for power plants is 0.6 1b NO,/10° Btu for bituminous coals and 0.5 1b NO,/10® Btu for subbituminous coals. Staged combustion and selective 5 catalytic reduction technologies are used to reduce NO, emissions in locations where regulations require it. The oxygen content of the Deadfall Syncline coal is relatively high at 17 to 18 percent although the Montana Rosebud subbituminous coal has 16 percent oxygen. An initial question about weathering of the coal sample is not a major concern because core sample data provided by ASRC (included in Appendix A) does not indicate significantly different heating values. The sample analyses in Pages A-5 through A-9 are for a cleaned coal which shows lower oxygen content than Battelle's coal samples. Ash Analysis The analysis of the Deadfall Syncline coal shows it has an ash that is similar to some Western U.S. coals. It has a low sulfur content, but has a high iron content. Also, the ash has a high CaO and MgO content and has a low Na,0 content. As a result of its high CaO, MgO, and Fe,0, content, the Alaskan coal ash has a base percentage of about 37 to 43 percent. This places the Deadfall Syncline coal among those having low ash fusion, or ash melting, temperatures. Evidence of this tendency of the ash to soften or melt are the low initial deformation temperatures (as low as 2135 F for one sample) and the low estimated Tog temperature (2100 F, see Figure 1). (The Tog, temperature is the temperature at which the ash would have a viscosity of 250 poise, which is that of a thick fluid.) These data suggest that the Deadfall Syncline coal ash would have a tendency to soften at moderate combustion temperatures. Firing this coal in spreader stoker boilers would risk the formation of large-ash clinkers on the traveling grate. In such units, the ash remains on the grate for up to 30 minutes. This would provide an opportunity for ash particles to soften and fuse into clinkers. Clinkers thus formed may interfere with the flow of air through the fuel bed and may impede the removal of ash from the ash pit. 3000 SiO2/Al203 1649 2900} 234 1593 Dolomite .C20 + MgO_}, “ % Total Base iti 2700 99 74 1482 2600}- 39 41427 ut 2500 2 70 1371 °C 2400} & 60 -]1316 2300 5 50 112 2200 3 1204 N 2100-6 1149 2000 1093 10 20 30 40 50 60 70 80 % Base FIGURE 1. ESTIMATION OF Tyg VALUE ACCORDING TO DOLOMITE PERCENTAGE AND PERCENT BASE Two viewpoints may be noted when considering the firing of the Deadfall Syncline coal in pulverized coal-fired boilers. The first approach considers fuel properties and the demands of the pulverized coal-fired systems. The second approach is to examine recommendations of boiler manufacturers. Pulverized coal-fired boilers are designed with furnace exit temperatures of 1900 F to 2150 F. One factor in the selection of the furnace exit gas temperature is avoiding the accumulation of sticky or molten ash on furnace walls (slagging) and avoiding deposits on convection surfaces 7 (fouling). The low-ash fusion and Tagg temperatures of the Deadfall Syncline coal suggest that it (like many Western U.S. coals) could best be fired in units designed for low-furnace exit temperatures. Such a requirement means that the furnace must be of a larger size than units of the same output firing Eastern U.S. coals. Even with a large size furnace, waterwall slagging is likely to be a continuing problem for boiler operators. The low Na,0 content of the ash suggests that it is not likely to cause excessive fouling problems. Considering the second approach, in a recent study for EPRI, ® Battelle requested several boiler manufactures to propose designs for 500 MW boilers intended for firing each of six coals. One of the coals that was specified was similar to the Deadfall Syncline coal in that it had high iron, calcia, and magnesia contents; had low sulfur and sodium contents; and had an initial deformation temperature of 2140 F. In specifying furnaces to fire this coal, two U.S. boiler manufacturers selected furnace exit gas temperatures of 2060 F and 2160 F. One manufacturer recommended a boiler design with about 30 percent more furnace volume than required for firing an Eastern U.S. coal; the other recommended a furnace only slightly larger than considered necessary for an Eastern U.S. coal. One would expect these manufacturers to know how to design boilers for various coals, but one wonders when a furnace exit gas temperature is specified to be 20 F below the initial deformation temperature of the coal ash. It appears likely that the ash would be sticky at these conditions, and that troublesome deposits would result. One possible explanation is that few new utility boilers have been sold in the U.S. in the past 6 or so years, and so the boiler manufacturers have not been put to the test of delivering on boiler performance. Nevertheless, these data are presented for consideration. One additional concern with the firing of the Deadfall Syncline coal in conventional combustion equipment is collection of particulate. The low sulfur and sodium content of this coal means that the flyash will have a high electrical resistivity, and that it will be difficult to collect in electrostatic precipitators (ESP). Some large boilers have used "hot-side” ESPs, where the ESP is located upstream of the air preheater. Hot-side 8 precipitators take advantage of the fact that the flyash has a lower resistivity at higher flue gas temperatures. At least some of the hot-side precipitators have had problems with ash deposits that would not fall off when the ESPs were rapped. An alternate approach is to use a baghouse for particle capture. However, baghouses have not been used on many small boilers, probably because of cost. FLUIDIZED BED COMBUSTION TEST Experimental Equipment The experimental equipment used for the fluidized bed combustion test is shown schematically in Figure 2. A detailed sketch of the fluidized- bed vessel is shown in Figure 3. The external cyclone was used to collect ash and bed carryover of fines from the small-scale experimental system. The equipment is comprised of an air rotameter, an air-preheat furnace, an externally-heated fluidized-bed reactor, a coal feeder and continuous flue gas analyzers. Compressed air was filtered and passed through a pressure regulator set at 28 psig. It then passed through two Dwyer rotameters in parallel; a 0 to 500 cfh meter and a 0 to 20 cfh meter. The indicated flow reading was corrected to actual values by multiplying by the square root of the pressure ratios (¥42/14.7) because the meters were operated at 28 psig, while the scale readings were based on atmospheric-pressure use. In general, air is metered into the system through an electric preheater and enters the reactor through a conical inlet section at the unit base. The air fluidizes the bed of sand (8 x 40 mesh), then exits the reactor through the cyclone to an exhaust line where the flue gas sample is obtained. Coal is continuously fed into the reactor via a variable speed screw feeder. The coal was sized to -8 +20 mesh and premixed with similar size limestone at a calcium to sulfur ratio of 3. Bed temperatures, as well as furnace, _ Vacuum Flue gas ~ (<j Furnace TC Coal feed Air / Bed drain Furnace FIGURE 2. 4-INCH CONVENTIONAL (BUBBLING) FLUIDIZED BED 10 8 OIA. 4 OIA. 1/2 OISCHARGE TUBE: FIGURE 3. 172 GAS INLET SKETCH OF STAINLESS-STEEL FLUIDIZED-BEO REACTOR 11 preheater and exhaust-line temperatures, are monitored using thermocouples connected to a digital temperature indicator. The reactor is constructed of 304 stainless steel and is approximately 4 inches in diameter and 44 inches in overall height. The 4- inch section is 28 inches in height with the upper freeboard area expanded to an 8-inch diameter. The reactor has a conical bottom to diffuse the fluidizing gases entering at the bottom of the cone. A }-inch-diameter gravity discharge tube is fitted into the conical section also. The external heaters are used for startup and to offset/minimize heat losses during testing. Combustion flue gases were continuously sampled and analyzed for 0,, CO,, CO, SO,, and NO,. These instruments were "zeroed" and calibrated with certified span gases at the beginning of the test. The specific instruments used were: 0, Beckman 755 paramagnetic CO, Beckman 864 NDIR CO ~—- Beckman 864 NDIR SO, Horiba PIR-2000 NDIR NO, Beckman 955 Chemi luminescent. Experimental Procedures The reactor was heated to 1000 F, with the specified air flow, by activating both the preheater and the reactor furnaces. The coal feed was then started to the reactor and the temperature allowed to increase to 1600 F. At this time the coal feed rate and the air flow were adjusted to give the desired operating conditions. The data were obtained over a several-hour period with minimal changes to maintain near steady-state conditions. Data were recorded at frequent intervals during the test. 12 At the end of the test, all flows were stopped and the system was cooled. The bed was drained after cooling to a temperature below 500 F. The flue gas analyzers were again calibrated for consistency and any drift or change was noted. The various samples obtained throughout the run were submitted to the Commercial Testing and Engineering Company of South Holland, Illinois, for component analysis. Results Operating conditions for the FBC tests are summarized in Table 2. A mass balance was determined for carbon, sulfur, oxygen, ash, and total mass. The total mass balance showed approximately 96 percent recovery, however most of the ash is thought to have escaped the cyclone which complicates the data analysis and interpretation. TABLE 2. FBC OPERATING CONDITIONS Test 1 Test 2 Parameter Range Mean Range Mean Duration, hrs 3.7 3.0 Temperature, F 1623-1658 1648 1633-1650 1641 Velocity, fps 3.0-4.0 3.3) 6.8 6.8 Bed DP, in H,0 30-40 30 4.0 40 Feed Rate, lb/hr 3.5 3.5 5.4 5.4 Ca:S mole ratio coal 2.4 2.4 2.4 2.4 coal + limestone 5.4 5.4 2.4 2.4 Flue Gas Composition 0., %* 3.0-3.8 3.8 4.0-5.9 4.4 cb, % 16.2-17.4 16.6 14.0.16.2 15.5 CO, ppm 155-165 155 140-200 155 SO,, ppm 30-95 55 80-130 95 NO,, ppm 425-525 525 400-615 540 13 Test 1 appeared to proceed smoothly based on the FBC temperature (1650 F) and the low CO concentration (155 ppm). However, the material captured in the cyclone was very dark which indicated significant unburned carbon and the ash analysis confirmed this at 80 percent carbon in the sample. The sample mass was low relative to the total ash contained in the coal feed. It appears that the actual coal ash was preferentially lost through the cyclone because of its small particle size while the cyclone catch was preferentially unburned coal/char particles. The 0,, CO,, and CO analysis indicate excellent combustion and are considered to be more reliable than the ash sample and analysis for this test. Combustion efficiency is excellent based on the flue gas composition. Sulfur capture of approximately 50 percent is calculated based on the flue gas analysis for the test. This is inefficient sulfur capture for a fluidized bed considering that the calcium to sulfur ratio (Ca:S) was 3.0 for the added limestone and 5.4 when the calcium in the coal ash is considered. The SO, emissions are consistently less than 100 ppm which is quite low even for locations in California and Japan. At these low SO, concentrations, a higher Ca:S ratio is required for sulfur capture because of the decreasing kinetic reaction rate. The NO, emissions were 400 to 500 ppm which is typical for FBC combustion temperatures and the relatively high fuel nitrogen content (1.6 percent). NO, emissions at this level will meet NSPS requirements (0.5 to 0.7 1b NO,/10° Btu) but additional control technology such as staged combustion or selective catalytic reduction would be required to meet more stringent standards. There was no indication of ash sticking or agglomeration during the FBC tests. This is consistent with expectations since the lowest initial deformation temperature for the coal ash was 2135 F. 14 The FBC test was repeated to determine the ash quantity and approximate composition exiting the cyclone. In Test 2, the cyclone was collecting 0.2 1b/hr of ash which accounts for all the coal ash, limestone and some attrited bed material. A flue gas sample was filtered after the cyclone and measured approximately 66 ppm (wt) of particulate. This is an insignificant mass relative to the other streams. The balance of the Test 2 data are consistent with Test 1. Only 30 percent consistent with Test 1. Only 30 percent sulfur capture was achieved which is disappointing but understandable for the low concentrations involved. SUSPENSION FIRING TEST Experimental Equipment Battelle's Bench-Scale Combustion Facility (shown in Figure 4) was used to evaluate conventional firing of the Deadfall Syncline coal. This facility fires pulverized coal (-200 mesh) at feed rates ranging from 1 to 5 lb/hr. It provides an environment that simulates the combustion zone temperatures and residence times typical of commercial boilers. The test fuel is fired downward into a 4-inch diameter silicon carbide combustion tube that is 4-feet long. Combustion zone temperature and residence times are controlled by externally heating the silicon carbide tube with a natural gas flame in the annular space. Actual combustion temperature is measured at the furnace exit before the gases cool and samples are withdrawn. Experimental Procedures The reactor was heated to the specified test temperature using the natural gas-fired annular burner. The combustion air flow was established at the desired rate and the flue gas analyzers were placed in service following routine calibration. (Coal feed was initiated and adjusted to provide 2000 to 2100 F at the furnace exit and approximately 3.5 percent 0, in the flue gas. This condition was allowed to stabilize and was maintained for a several-hour 15 PRIMARY AIR AND COAL, oll, GAS SECONDARY AIR _— TO STACK ‘ REFRACTORY BENCH SCALE COMBUSTOR CARBIDE TUBE ANNULUS — HEATER STAGED AIR SAMPLE PORT ’ TO STACK FIGURE 4. BATTELLE'S BENCH-SCALE COMRIISTION FaArTI TTv 16 period with minimal changes to maintain near steady state conditions. Data were recorded at frequent intervals during the test. At the end of the test, all flows were stopped and the system was cooled. The flue gas analyzers were again calibrated for consistency and any drift or change was noted. The ash sample was submitted to Commercial Testing for component analysis. The combustion tube was inspected for deposits although none were found. Results The operating conditions for the suspension firing test are summarized in Table 3. TABLE 3. SUSPENSION FIRING OPERATING CONDITIONS Parameter Range Mean Duration, hrs 3.0 Temperature, F 1900- 2019 2026 Velocity, fps 15.5 15.5 Feed Rate, 1b/hr 3.9 3.9 Ca:S mole ratio coal 2.4 2.4 coal + limestone - - Flue Gas Composition 0., % 3.2-4.7 3-3 chy, 4 14.6- 16.2 16.5 CO, ppm 50-55 50 S0., ppm 40-70 70 NO,, ppm 670-1500 1450 17 The mass balance for carbon, sulfur and oxygen are inconsistent with the ash analysis from the collected sample. The CO, contained in the flue gas (16.2 percent) represents excellent combustion and is very consistent with expected values for the 0, (3.3 percent) and CO (50 ppm) concentrations. The overall oxygen balance agrees well (90 percent) so that the air and flue gas rates seem to be consistent. Further the sulfur balance is very good (~ 100 percent) and most of the sulfur is in the flue gas as SO, as expected. At combustion temperatures greater than 2000 F, very little sulfur capture is expected with calcium, especially at low SO, concentrations such as expected from firing the Deadfall Syncline coal. NO, emissions of 1500 ppm are typical of suspension firing as the higher combustion temperatures promote NO, formation. The high fuel nitrogen content is equivalent to 2350 ppm NO, so at the test conditions some of the fuel nitrogen is being reduced to N,. These emissions are in excess of current federal standards so use of the Deadfall Syncline coal could require "“denox" in large units and/or in certain locations. There were no apparent problems with the coal ash at a furnace outlet temperature of approximately 2000 F. There were essentially no deposits on the furnace wall or downstream pipe section. The ash that was collected showed no fusion or agglomeration however the unburned carbon content was high (~ 80 percent). This is inconsistent with the flue gas composition and combustion temperature. It appears that the fine ash is very difficult to collect and that the collected ash sample is disproportionately skewed toward large particles which were not completely burned. This unexpected result led to repeating the combustion test with special emphasis on determining a more extensive furnace temperature profile. A long thermocouple was used to probe the vertical temperature profile and the temperatures ranged from 2000 F at the outlet to in excess of 2400 F (limit of Type K thermocouple) at the reactor mid point. Again there was no evidence of molten ash or wall deposits within the furnace or in the exit pipe. Unfortunately, the flue gas composition in this repeat test was distorted because of a leak between the annular burner (natural gas fired) and the coal 18 combustion chamber. Therefore, the mass balances from this test are not meaningful. The ash deposit inspection is stil] meaningful and confirms the earlier test result. CONCLUSIONS AND RECOMMENDATIONS Several conclusions can be drawn from the Deadfall Syncline coal evaluation tests. First the coal burns well in both FBC and suspension-fired furnaces. This conclusion is based on flue gas analyses rather than ash composition because of suspect problems in collecting a representative ash sample. There were no apparent problems with ash agglomeration or slagging in either combustion test. No problems were expected in the FBC test but the reported ash fusion temperature is in the range where molten ash/slag would be expected in high-temperature furnaces such as stokers or pulverized coal boilers. Approximately 50 percent sulfur capture was achieved in the FBC at a calcium to sulfur mole ratio of 5.4 when including the calcium contained in the coal ash. This is relatively poor sulfur capture and limestone utilization for a FBC, although the extremely low sulfur/SO, concentrations provide a kinetic limitation to efficiency. At any rate, SO, emissions can meet U.S. EPA standards without any controls because of the low S content in the raw coal. Lower SOQ, emissions, for locations such as California or Japan, can be achieved by calcium sorption as in a FBC or other conventional desulfurization techniques. NO, emissions from conventional firing will exceed EPA New Source Performance Standards without some control technology applied to the system. Staged combustion, low NO, burners and selective catalytic reduction can be used to reduce NO, emissions as needed by local regulations. NO, emissions from on FBC will meet federal standards because of the lower combustion temperatures. 19 The coal ash was very difficult to collect in a cyclone or by gravity settling. Depending on specific local particulate requirements, a bag filter or electrostatic precipitator would be needed to control ash emissions. An ESP may have resistivity problems which should be discussed with vendors during design and equipment procurement. Battelle recommends the FBC as the preferred small-scale technology rather than a stoker-fired unit because of the lower emissions (SO, and NO,) and the lower risk of ash fusion (clinker) problems. Small-scale FBC units are commercially available in several designs and applications. DOE- Morgantown Energy Technology Center is also funding development of advanced “FBC systems for small industrial and commercial applications. The technology is maturing such that performance and reliability risks can be minimized through prudent design by experienced organizations. The Deadfall Syncline coal is suitable for use in suspension-fired equipment. The low sulfur content makes this a valuable coal for locations requiring stringent SO, emissions. The high fuel nitrogen content requires some “denox" control technology in locations where NO, emissions are limited. (1) (2) (3) 20 REFERENCES Figure 1: Singer, J. G. and Selving, W. A., “Combustion, Fossil Power Systems," Combustion Engineering, Inc., Windsor, Connecticut, Barrett, R. E., "Slagging and Fouling in Pulverized-Coal-Fired Utility Boilers, Volume 2: A Survey of Boiler Design Practices for Avoiding Slagging and Fouling," EPRI Report No. CS$-5523, Vol. 2, December 1987, Coal Conversion Systems Technical Data Book, DOE/FE/05157-1, June APPENDIX A COAL_ASH ANALYSIS . eer =. * eee (CL IW AHO OF O-edoF Bora POL = Al COMMERCIAL TESTING & ENGINEERING CO. GENERAL OFFICES: 1919 SOUTH HIGHLAND AVE., SUITE 210-8, LOMBARDO, ILLINOIS 60148 # (312) 953-9300 ance 1900 Member of the 8G8 Group (Goce! Generale ae Surveillance) PLEASE ADORESS ALL CORRESPONDENCE TO January 26, 1989 18190 VAN ORUNEN RD., P.O. BOX 12! SOUTH HOLLAND, IL 6047: D> «—sdBATTELLE MEMORIAL INSTITUTE Te ES ain er a0 Coluabus Laboratories PAX: (312) 393-308 505 King Avenue Sanple identification by Coluabus, OH 43201 Battelle Menorial Institute ATTN: Ted L. Tewksbury, Rooa 13-3-032 Kind of saaple reported to us Coal Sanaple I.D.: oe 8yncline T 55.4 Sample taken at ----- 8 x 20 Saaple taken by Battelle Mezorial Institute Date sampled -----~ Shipper No. Not Given Date received January 16, 1989 P.O. No, 1-1386 Analysis Report No. 11-69078 Page lof 2 PROXIMATE AMALYSTS QLT IMATE ANALYSIS As Received Dry Basis As Received Dry Basis % Moisture 8.16 XXKKE &% Moisture 8.76 XXXXX § Ash 3.48 2.68 % Carbon 67.31 13.66 % Yolatile 35.03 38.39 & Hydrogen 3.38 4.35 & Pixed Carbon 53.76 58.93 & Nitrogen 1.46 1.60 100.00 100.00 %& Sulfur 0.18 0.20 % Ash 2.45 2.68 Btu/lb 11119 12186 & Oxygen (diff) 16,06 17.61 & Sulfur 0.18 0.20 100.00 100.00 Alk. as Sodium Oxide 0.02 0.03 & Chlorine 0.04 0.04 st § ° Reducing Oxidising Initial Deformation (IT) 2205 2310 Softening (ST) 2345 2400 Henispherical (ET) 2510 2490 Fluid (Ft) 2660 2585 suDmated, SN TESTING & ENGINEERING CO ¢ 2 Manager, South Holland Laboratory (Adven an oer unu) ranosragiee CrosTeAIAAl VI AAATER IN DOIMTIDA! AAAI MINING AREAS. COMMERCIAL TESTING & ENGINEBRING CO. GENERAL OFFICES. 1919 SOUTH HIGHLAND AVE., SUITE 210-8. LOMBARD, ILUNO!S 60148 ¢ (312) 983-9300 ener 1900 Memoer of the $08 Group (Socedie’ Genetee de Survediance) January 26, 1989 ricaor scons ms conmampeneencs > fimocnd ai 80 BATTELLE MEMORIAL INSTITUTE : COMTECO 8 Coluabus Laboratories mms FAX: (912) ox 505 King Avenue Sample identification by Coluabus, O8 43201 Battelle Memorial Institute ATTM: Ted L. Tewksbury, Roca 13-3-022 Kind of seaple reported to us Coal Saample I.D.: a Syncline T $8.4 Saaple taken at ----- 8 x 20 Sanple taken by Battelle Meaorial Institute Date sampled ------ Shipper No. Mot Given Date received January 16, 1989 P.O, Mo. T1386 Analysis Report Mo. 711°69078 Page 2 0f 2 ANALYSIS OF 159 WEIGHT 8, IGHITED BASTS Silicon dioxide 29,14 Aluainua oxide 25.39 Titaniua dioxide 0.63 Tron oxide 1.79 Calcium oxide 12.74 Magnesiva oxide 6.53 Potassium oxide 0.77 Sodium oxide 0.47 Sulfur trioxide 12.80 Phosphorus pentoxide 1,24 Strontiun oxide 0.49 Barium oxide 1.60 Manganese oxide 0.00 Undeterained 9.73 100.00 Silica Value = 51.85 Base:Acid Ratio = 0.51 Fouling Index = 0.24 Tese Teaperature = 2300 °F Slagging Index = 0.10 Respecttuly submitted, COMMERCIAL TESTING & ENGINEERING CO SS -°: ton Q Meneger, South Holland Laboratory (~ OVER 40 BRANCH LABORATORIES STRATEGICALLY LOCATED IN PRINCIPAL COAL MINING AREAS, = feel cect feck |) Jemeted o || cled oe a a ed moe HOO —_—— COMMERCIAL TESTING & ENGINEERING CO. GENGRAL OFFICES. 1919 SOUTH HIGHLAND Avé., SUITE 210-8. LOMBARD. ILLINCI$ 80148 © (312) 983-9300 tact 908 Member of es SG8 Group (Socmbe’ Generale oe Surveillance) PLEASE ADDRESS ALL CORRESPONDENCE TI January 26, 1989 16130 VAN ORUNEN AO., P.O. tox 2 SOUTH HOLLAND, IL 6047 D> so ATTELLE MEMORIAL INSTITUTE TELEX: 286006 CONTECO Biv UI Columbus Laboratories FAX: (312) 3306 $05 King Avenue Sample identification by Columbus, OH 43201 Battelle Menorial Institute ATTM: Ted L. Tewksbury, Room 13-3-022 Kind of saaple reported to us Coal Sammple I.D.: Deadfall Syncline T 55.5 Sample taker at ~---- -20 Sample taken by Battelle Mesorial Institute Date sampled -~---- Shipper Mo. Not Given Date received January 16, 1989 P.O. No. T-1386 Analysis Report Ho. 71-69079 Page lof 2 PROXIMATE AMALYSI$ ULTIMATE ANALYSIS As Received Dry Basis Ag Received Dry Basia & Moisture 8.13 XREXK % Moisture 8.13 AAXAN ®% Ash 3,11 3,38 & Carbon 66,78 712.69 & Volatile 30.46 33.16 § Bydrogen 3.75 4.08 & Fixed Carboa $8.30 $3.46 & Hitrogea 1.43 1.56 100.00 100.00 % Sulfur 0.17 0.19 % Ash 3.11 3.38 Btu/1b 10968 11939 & Oxygen (diff) 16.63 18.10 & Sulfur 0.17 0.19 100.00 100.00 Alk. as Sodium Oxide 0.03 0.03 & Chlorine 0.04 0.04 FUSION TEMPERATURE OF ASH. (°F) Reducing Oxidising Initial Deformation (IT) 2135 2160 Softening (ST) 2235 2290 Beaispherical (HT) 2355 2430 Fluid (Ft) 2480 2580 Reepecttully submitted, COMMERCIAL TESTING & ENGINEERING CO. \ ‘ “Ay : ! 0 <> oe LJ if Manager, South Holland Laboratory (<ZRWER 40 BRANCH LABORATORIES STRATEGICALLY LOCATED IN PRINCIPAL COAL MINING AREAS, COMMERCIAL TESTING & ENGINEERING CO. GENERAL OFFICES: 1919 SOUTH HIGHLAND AVE. SUITE 210-8, LOMBARD, ILLINOIS 60148 # (312) 863-0300 Member of the SG8 Group (Sect! Generate oe Surveriionce) January 26, 1989 BATTELLE MEMORIAL INSTITUTE Columbus Laboratories 508 King Avenue Coluabus, OH 43201 ATTN: Ted L. Tewksbury, Room 13-3-022 Kind of sample reported to us Coal Sample taken at Sample taken by Battelle Memorial Institute Date saapled ececce Date received January 16, 1989 PLEASE ADORESS ALL CORRESPONDENC 16130 VAN OAUNEN AO., P.O. 80 SOUTH HOLLANO, IL s047 TELEPHONE: (912) 331-290: TELEX: 288980 COMTECO St PAX: (312) 333. Saaple identification by Battelle Memorial Institute Samaple I.D.: tT 55.5 -30 Shipper No. Not Given P.O. No. 7-1386 Analysis Report Mo. 71-69079 AMALYSIS OF ASE WEIGHT 8, IGNITED BASIS Silicon dioxide + 26.11 Aluainua oxide 21.88 Titaniua dioxide 0.57 Tron oxide 10.10 Calcium oxide 16.24 Magnesium oxide 8.47 Potassium oxide 0.61 Sodium oxide 0.49 Sulfur trioxide 11.87 Phosphorus pentoxide 1.37 Strontium oxide 0.49 Bariua oxide 1.38 Manganese oxide 0.00 Undetersined 1982 100.00 Silica Value = Base:Acid Ratio = Tacse Teaperature = 42.86 0.74 2055 °F Youling Index = Slagging Index = ity submitiod. Deadfall Syncline Page 2o0f 2 0.36 0.14 ea G, R 40 BRANCH LABORATORIES STRATEGICALLY LOCATED IN PRINCIPAL COAL MINING AREAS i APPENDIX C Community Resolutions a I a hil ‘ nee! ae tom ull ATTACHMENT ‘N° Kotzebue Eleatric Association, Ine. THIRTY MILES NORTH OF THE ARCTIC CIRCLE ‘ P.0. BOX 44 —. Bor Kotzebue, Alaska 99752 =i ™S 4 Fhone (907) 442-3482 August 9, 1989 Board Resolution #689 WHEREAS: The Board of Kotzebue Electric Association, Inc. is responsible for the evaluation of power generation systems, and WHEREAS: The cost of using diesel oil for the production of electrizity does not provide a stable planning environment due to the unstable cost, and fluctuations inherent in the oil market, and WHEREAS: Development of the Kotzebue Electric Association, Inc. Arctic Coal Demonstration Project has progressed to the demonstration stage and there now exists clean coal burning technologies suitable for the Kotzebue environment, and WHEREAS: There is a source of good quality coal located in NW Alaska, and WHEREAS: \otzebue Electric Association has done an indepth st.idy in conjunction with the Alaska Energy Authority to evaluate the benefits of district heating, and WHEREAS: totzebue Electric Association, has property located next to it's existing generation plant that is suitable ts house a clean coal burning technology generation plant, and WHEREAS: funds for the demonstration are available from the Department of Energy, Alaska Science and Technology Foundatioi and other sources, NOW, THERE “ORE BE IT RESOLVED: that Kotzebue Electric Association, wishes to participate in the Clean Coal Technology Demonstration Project, and supports a coal fired power generation and district heating demonstration project i1 the City of Kotzebue. A RESOLUT(ON CALLING FOR SUPPORT OF THE KOTZEBUE ELECTRIC ASSOCIATION, INC., ARCTIC COAL DEMONSTRATION PROJECT FINDINGS FOR THE COMMUNITY OF KOTZEBUE. KOTZEBUE ZLECTRIC ASSOCIATION, INC. » President David Foster, Secretary NORTHWEST ARCTIC BOROUGH RESOLUTION 89-20 ee A RESOLUTION OF THE NORTHWEST ARCTIC BOROUGH IN SUPPORT OF THE REMOTE ALASKA REPOWERING DEMONSTRATION PROJECT IN KOTZEBUE. WHEREAS, the Northwest Arctic Borough was incorporated June 2, 1986; and WHEREAS, the Northwest Arctic Borough supports Energy Conservation, Energy Economy for resident consumers, Energy Resource Development projects, and particularly, The Northwestern Region Demonstration power plant project; and WHEREAS, the Northwest Arctic Borough advocates the Cooperative Demonstration project in Kotzebue with objectives of Economic growth, energy independence, and establishment of efficient, environmentally acceptable coal energy utilization; and WHEREAS, the Remote Alaska Repowering Demonstration project will enable a practical application of the Western Arctic Coal Resource and significant progress in achieving the objectives above; and NOW THEREFORE BE IT RESOLVED THAT: 1) The Northwest Arctic Borough supports the Kotzebue Electric Association effort to obtain funding for the Alaska Repowering Demonstration project from the U.S. Department of Energy and from the State of Alaska. 2) The Northwest Arctic Borough will cooperate in continued development of the power plant Kotzebue Demonstration project in association with the Remote Alaska Repowering Demonstration Project. RESOLUTION 89-20 PAGE TWO PASSED AND ADOPTED this sik day of Soph bev , 1989. Hanglledl by Assembly President " SIGNED AND APPROVED this _@/H day of Libpbev , 1989. Mid ata Mayor ATTESTED to this _@* day ot /cfdber- , 1989. 2D ATIESE orough Clerk > “2 ae Tama a. ARECA Resolution 89-5 SUPPORT FOR ARCTIC COAL DEMONSTRATION PROJECT WHEREAS, The Alaska Rural electric Cooperative Association supports all efforts aimed at reducing the cost of electric generation in Alaska, and WHEREAS, the cost of using diesel oil for the production of electricity does not provide a stable planning environment due to the fluctuations inherent in the oil market, and WHEREAS, the Alaska Rural Electric Cooperative Association supports the use of Alaskan resources, for the production of electricity, and WHEREAS, there is a source of good quality coal located in NW Alaska, and WHEREAS, Kotzebue Electric association has done a_ study in conjunction with the Alaska Energy Authority to evaluate the benefits of district heating and the use of coal, and WHEREAS, development of the Kotzebue Electric Association, Inc. Arctic Coal Demonstration Project has progressed to the demonstration stage and there now exists clean coal burning technologies suitable for the Kotzebue environment, and WHEREAS, funds for the demonstration are available from the Department of Energy, Alaska Science: and Technology Foundation and other sources, NOW, THEREFORE BE IT RESOLVED, that the Alaska Rural Electric Cooperative Association supports Kotzebue Electric Association, Inc. in it's efforts to explore the use of coal as a viable source of fuel, and Ne. BE IT FURTHER RESOLVED, that the Alaska Rural Electric Cooperative Association supports Kotzebue Electric Association, participation in the Department of Energy, Clean Coal Technology Demonstration Grant Program, to establish a coal fired power generation and district heating project in NW Alaska. 1@ oUtal. OR pet at ayenayine sapyiae ices ea sata vert: 0 ce wt As. ewe ke bem IH VINE, UldLd tt LIU 4497 SUES Be NOME JOINT UTILITY BOARD RESOLUTION 87-16 A RESOLUTION CALLING FOR SUPPORT OF THE WESTERN ARCTIC COAL DEMONSTRATION PROJECT FINDINGS FOR THE COMMUNITY OF NUME WHEREAS, the Nome Joint Utility Board is responsible for the evaluation of alternative power generation systems, and WHEREAS, the high cost of producing power and the fluctuations inherent in the price of oil is of concern to the Utility Board, and WHEREAS, the progress in the development of the Western Arctic Coal Demonstration Project has progressed to the demonstration stage and there exist clean coal burning technologies suitable for the Nome environment, and WHEREAS, there exist a local energy source and various coal burning technological options for increasing energy efficiency and energy security for the City of Nome, and WHEREAS, a successful demonstration of coal fired power generation and district heating technologies could improve the economics and environmental impact associated with power delivery throughout rural Alaska, and WHEREAS, funds for the demonstration are available from the Department of Energy, Clean Coal Technology III Demonstration Program, Alaska Science and Technology Foundation, and other sources, and WHEREAS, the development of this project has the potential for encouraging Alaska resource development in Northwest Alaska and the generation of some new employment possibilities that may be desirable for the region as a whole. NOW THEREFORE BE IT RESOLVED that the Nome Joint Utility Board hereby gives ite’ fill enrniragement and sipnart tn a cnal fired power generatian and district heating demonstration project in the city of Nome, Alaska, and makes the following recommendations: 1) that the project be used as a prototype and if successful, be duplicated within the region, and ®) that the project be coordinated with the Nome Joint Utility System and the City of Nome. SIGNED THIS 1g™ DAY OF Nas » 1989 AT NOME, ALASKA. Stan Sobocienski, Chairman NOME JOINT UTILITY BOARD utcher, Secretary NOME JOINT UTILITY BOARD Presented By: City Manager Action Takent Yes af No go. CITY OF NOME, ALASKA RESOLUTION NO. R-89-5-2 A RESOLUTION CONCURRING WITH NOME JOINT UTILITY R-89-16 AND SUPPORTING A COAL FIRED POWER GENERATION AND DISTRICT HEATING DEMONSTRATION PROJECT IN NOME. WHEREAS, on May 16, 1989, the Nome Joint Utility Board adopted R-89-16 in support of tha Western Arctic Coal Demonstration Project; and, narr. WHEREAS, funds for the demonstration are available from the Departmant of Energy, Clean Coal Technology III Demonstration Project, Alaska Science and Technology Foundation and other sources, NOW, THEREFORE, BE IT RESOLVED that the Nome Common Council concurs with NJUB R-89-16 and supports a coal fired ' .. power generation and district heating demonstration project in the City of Nome.. APPROVED and SIGNED this 22) day of (aes , 1989, = ohn &. Handeland, Mayor ATTEST: APPENDIX D Inflated Cost - Oil, Coal, Capital and O&M D-1 Diesel Fuel Projections D-2 Coal Price Projections D-3 Inflated Capital and O&M Costs D-1 Diesel Fuel Projections 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 LOW DIESEL FUEL PROTECTION FUEL PRICE ESCALATION 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 PREP RPRPRPRPRPRPRPEPPP o N o DIESEL PRICE 0.75 0.77 0.80 0.83 0.85 0.88 0.91 0.94 0.97 1.00 1.03 1.07 1.10 1.14 Peay, oak 1.25 1.29 1.33 1.38 1.42 1.47 1.51 1.56 1.61 1.66 1.72 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 MEDIUM DIESEL FUEL PROJECTION FUEL PRICE ESCALATION 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 INFLATION 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 1.025 DIESEL PRICE . ee Bo OT dN NO SF OOO 0) OOO Sr . Ss wl wie SC) wi elie oe OURPANUOUW NNNNNNP RP RPP RP RP RPP RP PRP RRP RP OOOOOOO AWNnNPrPRrPRPNWUNONUNANAOCU 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 LOW DIESEL FUEL PROJECTION FUEL PRICE ESCALATION 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00744 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 1.00694 INFLATION 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 DIESEL PRICE 7s oe ArPANUWUUNAUW NVNUNPRP RP RPP PRP RPP RPP RP RPPPRPFPOOCOOOOO VE QSLRRAAANERYONN PE GOSCL OHHH Aa PNWUNONKTONADAOUNUUO LUO S 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 HIGH DIESEL FUEL PROJECTION FUEL PRICE ESCALATION 1.03187 1.03187 1.03187 1.03187 1.03187 1.03187 1.03187 1.03187 1.03187 1.03187 1.03187 1.03187 1.03187 1.03018 1.03018 1.03018 1.03018 1.03018 1.03018 1.03018 1.03018 1.03018 1.03018 1.03018 1.03018 1.03018 1.03018 INFLATION 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 1.035 DIESEL PRICE oe ee ew ow Oraouw PAMSYNE RSL Sess BPWWWWNNNNNNNEPPRPRPRPPERPPRPOOOCOO OCOMNWrRPUODTUSLNPE Ee eo te a LOW DIESEL FUEL PROJECTION YEAR FUEL PRICE ESCALATION INFLATION DIESEL PRICE 1988 1.00744 1.045 0.75 1989 1.00744 1.045 0.79 1990 1.00744 1.045 0.83 1991 1.00744 1.045 0.88 1992 1.00744 1.045 0.92 1993 1.00744 1.045 0.97 1994 1.00744 1.045 1.02 1995 1.00744 1.045 1.08 1996 1.00744 1.045 1.13 1997 1.00744 1.045 1.19 1998 1.00744 1.045 1.25 1999 1.00744 1.045 1.32 2000 1.00744 1.045 1.39 2001 1.00694 1.045 1.46 2002 1.00694 1.045 1.54 2003 1.00694 1.045 1.62 2004 1.00694 1.045 1.70 2005 1.00694 1.045 1.79 2006 1.00694 1.045 1.89 2007 1.00694 1.045 1.99 2008 1.00694 1.045 2.09 2009 1.00694 1.045 2.20 2010 1.00694 1.045 2.31 2011 1.00694 1.045 2.43 2012 1.00694 1.045 2.56 2013 1.00694 1.045 2.70 2014 1.00694 1.045 2.84 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 MEDIUM DIESEL FUEL PROJECTION FUEL PRICE ESCALATION 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 1.02257 INFLATION 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 1.045 DIESEL PRICE oe ee ew ew oe ee eo we ew @Onanouwn PWWWWWNNNNNNERPEHPHEPEPEPPHEHOOOOO ° ; rPEONWNWODONIHWO MW HIGH DIESEL FUEL PROJECTION YEAR FUEL PRICE ESCALATION INFLATION DIESEL PRICE 1988 1.03187 1.045 0.75 1989 1.03187 1.045 0.81 1990 1.03187 1.045 0.87 1991 1.03187 1.045 0.94 1992 1.03187 1.045 1.01 1993 1.03187 1.045 1.09 1994 1.03187 1.045 1.18 1995 1.03187 1.045 1.27 1996 1.03187 1.045 1.37 1997 1.03187 1.045 1.48 1998 1.03187 1.045 1.59 1999 1.03187 1.045 1.72 2000 1.03187 1.045 1.85 2001 1.03018 1.045 2.00 2002 1.03018 1.045 2.15 2003 1.03018 1.045 2.31 2004 1.03018 1.045 2.49 2005 1.03018 1.045 2.68 2006 1.03018 1.045 2.88 2007 1.03018 1.045 3.11 2008 1.03018 1.045 3.34 2009 1.03018 1.045 3.60 2010 1.03018 1.045 3.87 2011 1.03018 1.045 4.17 2012 1.03018 1.045 4.49 2013 1.03018 1.045 4.83 2014 1.03018 1.045 5.20 D-2 Coal Price Projections PRICE OF DELIVERED COAL BASED UPON THE TONNAGE MINED INFLATION RATE 1.045 NOME KOTZEBUE TONS COAL 50000 80000 156000 200000 50000 80000 156000 200000 1988 100.08 89.22 73.77 66.07 92.48 82.82 70.82 65.07 1989 104.58 93.23 77.09 69.04 96.64 86.55 74.01 68.00 1990 109.29 97.43 80.56 72.15 100.99 90.44 77.34 71.06 1991 114.21 101.81 84.18 75.40 105.54 94.51 80.82 74.26 1992 119.35 106.40 87.97 78.79 110.28 98.76 84.45 77.60 1993 124.72 111.18 91.93 82.34 115.25 103.21 88.25 81.09 1994 130.33 116.19 96.07 86.04 120.43 107.85 92.23 84.74 1995 136.20 121.42 100.39 89.91 125.85 112.71 96.38 88.55 1996 142.32 126.88 104.91 93.96 131.52 117.78 100.71 92.54 1997 148.73 132.59 109.63 98.19 137.43 123.08 105.25 96.70 1998 155.42 138.56 114.56 102.60 143.62 128.62 109.98 101.05 1999 162.42 144.79 119.72 107.22 150.08 134.40 114.93 105.60 2000 169.72 151.31 125.11 112.05 156.84 140.45 120.10 110.35 2001 177.36 158.12 130.73 117.09 163.89 146.77 125.51 115.32 2002 185.34 165.23 136.62 122.36 171.27 153.38 131.15 120.51 2003 193.68 172.67 142.77 127.86 178.97 160.28 137.06 125.93 2004 202.40 180.44 149.19 133.62 187.03 167.49 143.22 131.60 2005 211.51 188.56 155.90 139.63 195.45 175.03 149.67 137.52 2006 221.02 197.04 162.92 145.91 204.24 182.91 156.40 143.71 2007. 230.97 205.91 170.25 152.48 213.43 191.14 163.44 150.17 2008 241.36 215.17 177.91 159.34 223.04 199.74 170.80 156.93 2009 252.23 224.86 185.92 166.51 233.07 208.73 178.48 163.99 2010 263.58 234.97 194.28 174.01 243.56 218.12 186.52 171.37 2011 275.44 245.55 203.03 181.84 254.52 227.93 194.91 179.08 2012 287.83 256.60 212.16 190.02 265.97 238.19 203.68 187.14 2013 300.78 268.14 221.71 198.57 277.94 248.91 212.84 195.56 2014 314.32 280.21 231.69 207.50 290.45 260.11 222.42 204.36 PRICE OF DELIVERED COAL BASED UPON THE TONNAGE MINED INFLATION RATE 1.035 NOME KOTZEBUE TONS COAL 50000 80000 156000 200000 50000 80000 156000 200000 1988 100.08 89.22 73.77 66.07 92.48 82.82 70.82 65.07 1989 103.58 92.34 76.35 68.38 95.72 85.72 73.30 67.35 1990 =107.21 95.57 79.02 70.78 99.07 88.72 75.86 69.70 1991 110.96 98.92 81.79 73.25 102.53 91.82 78.52 72.14 1992 114.84 102.38 84.65 75.82 106.12 95.04 81.27 74.67 1993 118.86 105.97 87.62 78.47 109.84 98.36 84.11 77.28 1994 123.02 109.67 90.68 81.22 113.68 101.81 87.06 79.99 1995 127.33 113.51 93.86 84.06 117.66 105.37 90.10 82.79 1996 131.79 117.49 97.14 87.00 121.78 109.06 93.26 85.68 1997. 136.40 121.60 100.54 90.05 126.04 112.88 96.52 88.68 1998 141.17 125.85 104.06 93.20 130.45 116.83 99.90 91.79 1999 146.11 130.26 107.70 96.46 135.02 120.91 103.40 95.00 2000 151.23 134.82 111.47 99.84 139.74 125.15 107.01 98.33 2001 156.52 139.54 115.37 103.33 144.63 129.53 110.76 101.77 2002 162.00 144.42 119.41 106.95 149.70 134.06 114.64 105.33 2003 167.67 149.47 123.59 110.69 154.94 138.75 118.65 109.01 2004 173.54 154.71 127.92 114.56 160.36 143.61 122.80 112.83 2005 179.61 160.12 132.39 118.57 165.97 148.64 127.10 116.78 2006 185.90 165.73 137.03 122.72 171.78 153.84 131.55 120.87 2007. 192.40 171.53 141.82 127.02 177.79 159.22 136.15 125.10 2008 199.14 177.53 146.79 131.47 184.02 164.79 140.92 129.48 2009 206.11 183.74 151.92 136.07 190.46 170.56 145.85 134.01 2010 213.32 190.17 157.24 140.83 197.12 176.53 150.95 138.70 2011 220.79 196.83 162.75 145.76 204.02 182.71 156.24 143.55 2012 228.52 203.72 168.44 150.86 211.16 189.11 161.71 148.58 2013 «236.51 210.85 174.34 156.14 218.55 195.72 167.37 153.78 2014 244.79 218.23 180.44 161.60 226.20 202.57 173.22 159.16 PRICE OF DELIVERED COAL BASED UPON THE TONNAGE MINED INFLATION RATE 1.025 NOME KOTZEBUE TONS COAL 50000 80000 156000 200000 50000 80000 156000 200000 1988 100.08 89.22 73.77 66.07 92.48 82.82 70.82 65.07 1989 102.58 91.45 75.61 67.72 94.79 84.89 72.59 66.70 1990 105.15 93.74 77.50 69.41 97.16 87.01 74.41 68.36 1991 107.78 96.08 79.44 71.15 99.59 89.19 76.27 70.07 1992 110.47 98.48 81.43 72.93 102.08 91.42 78.17 71.83 1993. 113.23 100.94 83.46 74.75 104.63 93.70 80.13 73.62 1994 116.06 103.47 85.55 76.62 107.25 96.05 82.13 75.46 1995 118.96 106.05 87.69 78.54 109.93 98.45 84.18 77.35 1996 121.94 108.71 89.88 80.50 112.68 100.91 86.29 79.28 1997. 124.99 111.42 92.13 82.51 115.49 103.43 88.44 81.26 1998 128.11 114.21 94.43 84.58 118.38 106.02 90.66 83.30 1999, 131.31 117.06 96.79 86.69 121.34 108.67 92.92 85.38 2000 134.60 119.99 99.21 88.86 124.38 111.38 95.25 87.51 2001 137.96 122.99 101.69 91.08 127.48 114.17 97.63 89.70 2002 141.41 126.07 104.24 93.36 130.67 117.02 100.07 91.94 2003 144.95 129.22 106.84 95.69 133.94 119.95 102.57 94.24 2004 148.57 132.45 109.51 98.08 137.29 122.95 105.13 96.60 2005 152.28 135.76 112.25 100.53 140.72 126.02 107.76 99.01 2006 156.09 139.15 115.06 103.05 144.24 129.17 110.46 101.49 2007. 159.99 142.63 117.93 105.62 147.84 132.40 113.22 104.02 2008 163.99 146.20 120.88 108.26 151.54 135.71 116.05 106.62 2009 168.09 149.85 123.90 110.97 155.33 139.10 118.95 109.29 2010 172.29 153.60 127.00 113.74 159.21 142.58 121.92 112.02 2011 176.60 157.44 130.18 116.59 163.19 146.15 124.97 114.82 2012 181.02 161.37 133.43 119.50 167.27 149.80 128.09 117.69 2013 185.54 165.41 136.77 122.49 171.45 153.54 131.30 120.64 2014 190.18 169.54 140.18 125.55 175.74 157.38 134.58 123.65 D-3 Inflated Capital and O&M Costs INFIATION RATE 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 1.025 KOTZ DIESEL O&M SP0900000COCOCOOCOCOOODOOAOOCOAOCGAOACOO0DO -39 -40 +41 +42 -43 -44 +45 -46 -48 -49 -50 -51 -52 -54 -55 +56 -58 +59 -61 +62 -64 -66 +67 +69 71 72 -74 DIESEL O&M 0.56 0.58 0.59 0.61 0.62 0.64 0.65 0.67 0.69 0.70 0.72 0.74 0.76 0.78 0.80 0.82 0.84 0.86 0.88 0.90 0.92 0.95 0.97 1.00 1.02 1.05 1.07 "2600KW" DIESEL OWOOUODBMDDADNINYNINNANDADARAUW 85 -00 -15 +30 46 -62 -78 95 +13 «31 +49 -68 -87 -06 +27 47 -68 -90 12 -35 -59 -83 -07 +32 -58 -85 -12 COAL MODULE +38 -61 +85 10. 10. 10. 10. 11. 11. 11. 12. 12. 12. 12. 13. 13. 13. 14, 14. 14. 10 35) 61 87 14 42 71 00 30 61 92 25 58 92 27 62 99 INFLATION RATE 1.035 COAL MODULE KOTZ NOME "2600KW" DIESEL DIESEL DIESEL O&M O&M 1988 0.39 0.56 5.85 1989 0.40 0.58 6.05 1990 0.42 0.60 6.27 1991 0.43 0.63 6.49 1992 0.45 0.65 6.71 1993 0.46 0.67 6.95 1994 0.48 0.69 7.19 1995 0.50 0.72 7.44 1996 0.51 0.74 7.70 1997 0.53 0.77 7.97 1998 0.55 0.80 8.25 1999 0.57 0.82 8.54 2000 0.59 0.85 8.84 2001 0.61 0.88 9.15 2002 0.63 0.91 9.47 2003 0.65 0.94 9.80 2004 0.68 0.98 14 2005 0.70 1.01 -50 2006 0.72 1.05 -87 2007 0.75 1.08 +25 2008 0.78 1.12 64 2009 0.80 1.16 -05 2010 0.83 1.20 -47 2011 0.86 1.24 91 2012 0.89 1.29 -36 2013 0.92 1.33 -82 2014 0.95 1.38 31 a. 11. aes 12. 12. 13. 13. 14, 14. 15% 15. 16. 16. 17. 18. LS) 52 93) 35) 78 22 69 17 66 18 Al 26 83 41 02 INFIATION RATE 1.045 COAL MODULE KOTZ NOME "2600KW" DIESEL DIESEL DIESEL O&M O&M 1988 0.39 0.56 5.85 1989 0.41 0.59 6.11 1990 0.43 0.62 6.39 1991 0.45 0.64 6.68 1992 0.47 0.67 6.98 1993 0.49 0.70 7.29 1994 0.51 0.73 7.62 1995 0.53 0.77 7.96 1996 0.55 0.80 8.32 1997 0.58 0.84 8.69 1998 0.61 0.88 9.08 1999 0.63 0.92 9.49 2000 0.66 0.96 9.92 2001 0.69 1.00 10.37 2002 0.72 1.04 10.83 2003 0.75 1.09 11.32 2004 0.79 1.14 11.83 2005 0.82 1.19 12.36 2006 0.86 1.25 12.92 2007 0.90 1.30 13.50 2008 0.94 1.36 14.11 2009 0.98 1.42 14.74 2010 1.03 1.49 15.41 2011 1.07 1.55 16.10 2012 1.12 1.62 16.82 2013 Lol7, 1.70 17.58 2014 1.22 1.77 18.37 12 +38 -80 10. 10. 11. aL. -21 12. 13. 13. 14. 15. 15. 16. 17. 18. 18. 19. 20. 21. 24 70 18 68 76 33 93) 56 21 90 61 36 14 96 81 70 64 APPENDIX E Diesel District Heat Load Computation of heat available from diesels in Nome 1989 Fuel Consumed by Diesels * Per the PolarConsult Report Recover 50% of Energy Heat Lossed in Piping System Heat Exchanger Losses During the summer months, the diesel produces more heat than can be used: Assume 30% of heat generated can't be used. 1,948,655 Gallons 974,325 Gallons 132,081 Gallons 97,433 Gallons 744,811 Gallons (Equiv) 521,368 Gallons (Equiv) 9 521,368 Gallons is equivalent to 73 x 10 Btu/yr. APPENDIX F Coal Consumption F-1 Coal Consumption For Nome F-2 Total Coal Consumption F-1 Coal Consumption For Nome RATE OF GROWIH 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 0.035 NOME BEMA 4050 4850 5020 1200 5195 1200 5377 1200 5565 1700 5760 1700 5962 1700 6171 1700 6387 1700 6610 1700 6841 1700 7081 1700 7329 1700 7585 1700 7851 1700 8125 1700 8410 1700 8704 1700 9009 1700 9324 1700 9650 1700 9988 1700 10338 1700 10700 1700 11074 1700 11462 1700 COAL CONSUMPTION FOR NOME ALASKA TOTAL GROSS GENERATION REPORT GOLD CO 1000 1000 2000 2000 2500 3260 3374 3492 3614 3741 3872 4007 4148 4293 4443 4599 4760 4926 5098 5277 5462 5653 5851 4050 4850 6220 6395 T3U7 8265 9460 9662 10371 11347 11684 12034 12395 12770 13157 13558 13973 14403 14847 15307 15784 16277 16787 17315 17861 18427 19012 NOME NOME+GOLD 25.6 26.5 27.4 28.4 29.4 30.4 31.5 32.6 33.7 34.9 36.1 37.4 38.7 40.0 41.4 42.9 44.4 . . . ee SURLBISaS AAAaAjYNIOnaAW . 25.6 31.3 32.2 37.2 40.2 45.2 46.3 49.4 53.6 55.2 56.9 58.6 60.4 62.3 64.3 . oe . wowayuyu sys NOBUO RPUGEW 25.6 27.2 29.0 30.8 32.8 34.9 37-1 39.5 42.1 44.7 47.6 50.7 53.9 57.3 61.0 64.9 69.1 73.5 78.2 83.2 88.5 94.2 100.2 106.6 113.5 120.7 AVG COAL DEMAND DEMAND 2922 18036 3573 22049 3678 22703 4245 26197 4586 28306 5160 31849 5282 32599 5636 34784 6113 37729 6300 38881 6493 40075 6693 41310 6900 42588 7115 43911 1337 45280 7566 46697 7804 48164 8050 49682 8304 51253 8568 52879 8841 54562 9123 56304 9415 58107 9717 59973 10030 61904 10354 63903 COAL CONSUMPTION FOR NOME RATE OF GROWIH 0.025 NOME BEMA ALASKA TOTAL GROSS GENERATION REPORT AVG COAL GOLD CO NOME NOME+GOLD DEMAND DEMAND 1988 4050 4050 1989 4850 4850 25.6 25.6 25.6 2922 18036 1990 4971 1200 6171 26.2 31.0 27.2 3543 21869 1991 5096 1200 6296 26.9 31.7 29.0 3618 22331 1992 5223 1200 1000 7423 27.6 36.4 30.8 4152 25623 1993 5353 1700 1000 8053 28.3 39.1 32.8 4459 27518 1994 5487 1700 2000 9187 29.0 43.8 34.9 4996 30834 1995 5625 1700 2000 9325 29.7 44.5 37.1 5079 31344 1996 5765 1700 2500 9965 30.4 47.2 39.5 5392 33276 1997 5909 1700 3260 10869 3132 51.0 42.1 5825 35954 1998 6057 1700 3342 11098 32.0 52.1 44.7 5952 36733 1999 6208 1700 3425 11333 32.8 53.3 47.6 6081 37531 2000 6364 1700 soll 11574 33.6 54.4 50.7 6214 38350 2001 6523 1700 3598 11821 34.4 55.6 53.9 6350 39189 2002 6686 1700 3688 12074 35.3 56.8 57.3 6489 40049 2003 6853 1700 3781 12334 36.2 58.1 61.0 6632 40930 2004 7024 1700 3875 12599 37.1 59.4 64.9 6778 41834 2005 7200 1700 3972 12872 38.0 60.7 69.1 6928 42760 2006 7380 1700 4071 13151 39.0 62.0 73.5 7082 43709 2007 7564 1700 4173 13437 39.9 63.4 78.2 7240 44682 2008 7753 1700 4277 13731 40.9 64.8 83.2 7401 45679 2009 7947 1700 4384 14032 41.9 66.3 88.5 7567 46701 2010 8146 1700 4494 14340 43.0 67.8 94.2 7737 47749 2011 8350 1700 4606 14656 44.1 69.3 100.2 7911 48823 2012 8558 1700 4721 14980 45.2 70.9 106.6 8089 49924 2013 8772 1700 4839 15312 46.3 72.5 113 35 8272 51052 2014 8992 1700 4960 15652 47.5 74.1 120.7 8459 52209 RATE OF GROWIH 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 0.045 NOME BEMA 4050 4850 5068 1200 5296 1200 S335 1200 5784 1700 6044 1700 6316 1700 6600 1700 6897 1700 7208 1700 7532 1700 7871 1700 8225 1700 8595 1700 8982 1700 9386 1700 9808 1700 10250 1700 10711 1700 11193 1700 11697 1700 12223 1700 12773 1700 13348 1700 13949 1700 14576 1700 COAL CONSUMPTION FOR NOME ALASKA TOTAL GROSS GENERATION REPORT GOLD CO 1000 1000 2000 2000 2500 3260 3407 3560 3720 3888 4063 4245 4436 4636 4845 5063 5291 5529 5777 6037 6309 6593 6890 4050 4850 6268 6496 7735 8484 9744 10016 10800 11857 12314 12792 13291 13813 14358 14927 15523 16145 16795 17474 18184 18925 19701 20511 21357 22242 23166 NOME NOME+GOLD 25.6 26.8 28.0 29.2 30.5 ce 33.3 34.8 36.4 38.0 39.8 41.5 43.4 45.4 47.4 49.5 51.8 GPaaegeaaegsy Nwonbkrond ONDNFONRP UP 25.6 31.6 32.8 38.0 41.3 46.7 48.1 51.6 56.2 58.5 60.8 63.2 65.8 68.4 71.2 74.1 77.1 80.3 83.6 87.0 90.7 94.4 98.4 102.5 106.8 111.3 25.6 27.2 29.0 30.8 32.8 34.9 37.1 39.5 42.1 44.7 47.6 50.7 53.9 57.3 61.0 64.9 69.1 73.5 78.2 83.2 88.5 94.2 100.2 106.6 113.5 120.7 AVG DEMAND 2922 3602 3739 4339 4718 5331 5495 5895 6421 6675 6940 7218 7507 7810 8127 8458 8803 9165 9542 9936 10349 10779 11230 11700 12192 12705 COAL DEMAND 18036 22230 23078 26782 29118 32904 32915 36381 39628 41195 42834 44545 46334 48204 50157 52199 54332 56562 58891 61326 63870 66529 69307 72210 75244 78414 F-2 Total Coal Consumption RATE OF GROWIH 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 0.025 NOME BEMA 4050 4850 4971 5096 5223 5353 5487 5625 5765 5909 6057 6208 6364 6523 6686 6853 7024 7200 7380 7564 T153) 7947 8146 8350 8558 8772 8992 1200 1200 1200 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 TOTAL COAL CONSUMPTION ALASKA TOTAL GROSS GENERATION KOTZEBUE TOTAL COAL GOLD © 1000 1000 2000 2000 2500 3260 3342 3425 3511 3598 3688 3781 3875 3972 4071 4173 4277 4384 4494 4606 4721 4839 4960 4050 4850 6171 6296 7423 8053 9187 9325 9965 10869 11098 13333 11574 11821 12074 12334 12599 12872 13151 13437 13731 14032 14340 14656 14980 15312 15652 NOME NOME+GOLD 25.6 26.2 26.9 27.6 28.3 29.0 29.7 30.4 31.2 32.0 32.8 33.6 34.4 35.3 36.2 Sie: 38.0 39.0 39.9 40.9 41.9 43.0 44.1 45.2 46.3 47.5 25.6 31.0 31.7 36.4 39 43.8 44.5 47.2 51.0 52.1 53% 54. 55. 56. 58. 59. NPP OHA HW 62.0 63.4 64.8 66.3 67.8 69.3 70.9 72.5 74.1 16.7 16.7 18.7 a9 /e: 19.6 20.2 20.7 21.3 21.9 22.5 23.1 23.7 24.3 25.0 25.6 26.3 27.1 27.8 28.5 29. 30. 30. 31. 32. 33. 34. PUAN Or Ww GEN 42.3 47.7 50.4 55.5 58.7 64.0 65.2 68.5 72.9 74.6 76.4 78.1 79.9 81.8 83.7 85.7 87.8 89.8 91.9 94.1 96.4 98.7 101.0 103.5 106.0 108.5 DEMAND 29802 33635 35506 39080 41327 45066 45928 48283 51383 52585 53806 55048 56309 57662 58967 60363 61853 63295 64762 66322 67908 69520 71157 72892 74655 76445 RATE OF GROWIH 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 0.035 NOME BEMA 4050 4850 5020 5195 5377 5565 5760 5962 6171 6387 6610 6841 7081 7329 7585 7851 8125 8410 8704 9009 9324 9650 9988 10338 10700 11074 11462 1200 1200 1200 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 TOTAL COAL CONSUMPTION ALASKA TOTAL GROSS GENERATION KOTZEBUE TOTAL COAL GOLD CO 1000 1000 2000 2000 2500 3260 3374 3492 3614 3741 3872 4007 4148 4293 4443 4599 4760 4926 5098 5277 5462 5653 5851 4050 4850 6220 6395 7577 8265 9460 9662 10371 11347 11684 12034 12395 12770 13157, 13558 13973 14403 14847 15307 15784 16277 16787 17315 17861 18427 19012 NOME NOME+GOLD 25.6 26.5 27.4 28.4 29.4 30.4 31.5 32.6 O38 eu 34.9 36.1 37.4 38.7 40.0 41.4 25.6 31.3 32.2 37.2 40.2 45.2 46.3 49.4 53.6 55.2 56.9 8 oO DAV Sia APNO a MIC MO we we NOrPUUO SPINS WWW S WOMmwWoarnNrnrnrnny ONNNONUNO 16.7 16.7 18.7 19.1 19.6 20.2 20.7 21.3 21.9 22.5 23.1 23.7 24.3 25.0 25.6 26.3 27.1 27.8 28.5 29.3 30.1 30.9 31.7 32.6 33.5 34.4 GEN 42. 48. 50. 56. 59. 65. 67. 70. 75. 77. 80. WONUNDOFWDAWWUOW 84.7 87.3 89.9 92.6 95.5 98.3 101.2 104.4 107.5 110.8 114.2 117.7 121.4 125.1 DEMAND 29802 33815 35878 39654 42115 46081 47183 49790 53158 54734 56350 58007 59708 61524 63316 65226 67257 69268 71332 73522 75769 78075 80441 82941 85507 88140 RATE OF GROWIH 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 0.045 NOME BEMA 4050 4850 5068 5296 5535 5784 6044 6316 6600 6897 7208 7532 7871 8225 8595 8982 9386 9808 10250 10711 11193 11697 12223 12773 13348 13949 14576 1200 1200 1200 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 1700 TOTAL COAL CONSUMPTION ALASKA TOTAL GROSS GENERATION KOTZEBUE TOTAL COAL GOLD CO 1000 1000 2000 2000 2500 3260 3407 3560 3720 3888 4063 4245 4436 4636 4845 5063 5291 5529 5777 6037 6309 6593 6890 4050 4850 6268 6496 7735 8484 9744 10016 10800 11857 12314 12792 13291 13813 14358 14927 15523 16145 16795 17474 18184 18925 19701 20511 21357 22242 23166 NOME NOME+GOLD 25.6 26.8 28.0 29.2 30.5 31.9 33.3 34.8 36.4 38.0 39.8 41.5 43.4 54.1 POD . eile 16 WONDULUNRrU Soa oa Awon . . 25.6 31.6 32.8 38.0 41.3 46.7 48.1 51.6 16.7 16.7 18.7 19.1 19.6 20.2 20.7 21.3 21.9 22.5 23.1 25 ei 24.3 25.0 25.6 26.3 27.1 27.8 28.5 29.3 30.1 30.9 31.7 32.6 33.5 34.4 GEN 42.3 48.3 51.5 57.1 60.9 66.9 68.8 72.9 78.1 81.0 83.9 86.9 90.1 93.4 96.8 100.4 104.2 108.1 112.1 116.3 120.8 125.3 130.1 135.1 140.3 145.7 DEMAND 29802 33996 36253 40239 42927 47136 48499 51388 55057 57048 59109 61243 63455 65818 68194 70729 73426 76148 78971 81969 85077 88299 91641 95178 98846 102651