Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
An Economic & Technical Assessment of the Marketability of Western Arctic Slope Coals 1983
COA Alaska Energy Authority 048 LIBRARY COPY Dames & Moore AN ECONOMIC AND TECHNICAL ASSESSMENT OF THE MARKETABILITY OF WESTERN ARCTIC SLOPE COALS Prepared For State of Alaska Division of Legislative Finance Representative Albert P. Adams Chairman, House Finance Committee By Marvin Feldman Charles Mann Leslie Young Of DAMES & MOORE February, 1983 CoA of O B27MLF#10 TABLE OF CONTENTS 1.0 INTRODUCTION AND EXECUTIVE SUMMARY =) 1.1 PROBLEM SETTING I-} 1.2 PURPOSE, SCOPE, AND STUDY ORGANIZATION j=t 1.3. OVERVIEW OF THE STUDY METHODOLOGY 1-2 1.4 SUMMARY OF RESULTS AND POLICY IMPLICATIONS 1-3 2.0 DOMESTIC DEMAND FOR ARCTIC SLOPE COAL 2-1 2.1 A BRIEF SURVEY OF PREVIOUS STUDIES OF POTENTIAL COAL USE IN ALASKA 2-1 2.2 ENERGY DEMAND PROJECTIONS 2-2 2.2.1 Total Energy Demands 2-9 2.2.2 Coal Demand Scenarios 2-9 2.3 COAL SUPPLY ALTERNATIVES FOR THE CAPE BEAUFORT COAL MARKET AREA 2-10 2.3.1 Competition from Undeveloped Alaskan Coal Sources 2-13 2.3.2 Competition from Existing Coal Mines 2-16 2.3.3 Arctic Slope Coal Price and Availability 2-18 2.4 COAL TRANSPORTATION SCENARIOS AND COSTS 2-21 2.4.1 A Feasible Coal Distribution System 2-21 2.4.2 Coal Transportation From Mines To the Distribution Centers 2-22 2.4.3 Coal Transportation From Distribution Centers To Surrounding Villages 2-24 2.4. Marine Transportation Costs 2-25 2.5 AN ECONOMIC COMPARISON OF ARCTIC SLOPE COAL VERSUS OTHER ENERGY SOURCES 2-30 2.5.1 Description of Supply/Demand Scenarios 2-30 2.5.2 Arctic Slope Coals Versus Imported Coal Supplies 2-31 2.5.3 Arctic Slope Coals Versus Existing Diesel Energy Sources 2-35 2.6 SOCIAL, POLITICAL, AND ENVIRONMENTAL CONSIDER- ATIONS AFFECTING ALASKAN MARKETABILITY 2-39 2.6.1 Social Acceptability of Coal Space Heating 2-39 2.6.2 Other Socioeconomic Considerations 2-41 2.6.3 Environmental Issues 2-42 3.0 EXPORT MARKETS 3-1 3.1 STEAM COAL MARKETS Ka | 3.1.1 Methodology 3-1 3.1.2 Summary of Demand Analysis 3-3 3.1.3 Summary of Quality Requirements 3-3 3.1.4 Summary of Import Requirements 3-9 3.1.5 Summary of Import Strategies 3-9 B29MLF#10 Table Table Table Table Table Table Table Table Table Table Table Table Table Table Table Table Table Table Table 2-10 2-11 3-2 3-3 3-4 3-5 LIST OF TABLES Energy Demand for Electrical and Space Heating in the Arctic Slope Coal Movement Area ~ 1982 and 2000 Demand Scenarios, Year 2000 Electrical and Space Heating Demand for Coal, By Scenario (Year 2000) Physical and Economic Characteristics of Alaskan Coal Occurrences Comparison of Quality of Cape Beaufort, Usibelli, and Prince Rupert Coal Preliminary Estimate Of The Cost To Mine Western Arctic Slope Coals (From Arctic Slope Consulting Engineers, 1982) Barge Capacities of Distribution Centers Marine Transport Costs by Distribution Center Annual Levelized Handling Costs by Scenario Costs of Coal for Electricity and Space Heat by Source and Scenario Comparison of Cost of Oil with Cost of Coal in Year 2000 Forecast of Thermal Coal Demand in Pacific Rim Countries Coal Quality Requirements Forecast of Thermal Coal Demand in Pacific Rim Countries by Sector and Sulfur Content Import Requirements of Pacific Rim Countries Summary of Major Projections of Steam Coal Imports U.S. Export of Metallurgical Coal in 1981 Projected World Crude Steel Production (1981-1985) Projected Supply and Demand of Seaborne Met Coal Trade in 1981 2-10 2-11 2-14 2-17 2-20 2-23 2-26 2-28 2-32 2-36 3-4 B30MLF#10 Table Table Table Table Table Table Table Table 3-9 3-10 3-11 3-12 A-1 A-2 A-3 A-4 LIST OF TABLES (Continued) Projected Supply and Demand of Seaborne Met Coal Trade in 1985 Quality of Competing Australian Metallurgical Coals Delivered Costs of Coals From Various Exporting Countries to the Pacific Rim (Yokohama) Estimated Shipping Costs--Cape Beaufort to Yokohama Summary of Utility Coal Demand Sensitivity Analysis Summary of Projections of 1990 Utility Coal Demand Summary of Projections of Steam Coal Demand (Excluding Utility Demand) Expected On-Line Date for Nuclear Capacity 3-20 a-21 3-26 3-28 B28 MLF #10 3.2 3.3 ww ee ue 3.6 TABLE OF CONTENTS (Continued) METALLURGICAL COAL MARKETS 3.2.1 Met Coal Demand Background and Current Situation Basis for Demand 3.2.2 Potential Demand for U.S. Met Coal Exports 3.2.3 Coal Prices COMPETING PRODUCERS--STEAM COAL 3.3.1 Utah and Colorado 3.3.2 Australia Profile of Industry Coal Quality Production Costs Pricing Position and Strategy 3.3.3 Pacific Basin--Supply/Demand and Prices SHIPPING ECONOMICS AND FOBT ALASKA PRICES GENERAL MARKETING CONSIDERATIONS 3.5.1 Contract Arrangements 3.5.2 Timing 3.5.3 Effects of Short Shipping Season 3.5.4 Startup Problems -5 Coal Quality CLUSIONS el Steam Coal 5 ON! 6 -6.2 Metallurgical Coal 3 Cc 3 3 4.0 POLICY IMPLICATIONS 4.1 4.2 POLICY FINDINGS RECOMMENDATIONS FOR FURTHER STUDY 5.0 BIBLIOGRAPHY Appendix A: Appendix B: Background and Methodology For Coal Demand Projections Conceptual Design and Preliminary Coal Analysis “3-13 3-13 3-13 3-15 3-19 3-20 3-22 3-22 3-23 3-23 3-24 3-24 3-24 3-25 3-27 3-30 3-30 3-30 3-31 3-32 3-32 3-32 3-32 3-33 4-1 4-1 4-3 a1 A-l B-1 A30MLF#10 Figure Figure Figure Figure Figure Figure LIST OF FIGURES Local Cities and Villages in Proximity of Cape Beaufort Mine Forecast of Thermal Coal Demand by Sector in Pacific Rim Countries Forecast of Growth and Electric Demand Along the Pacific Rim by Source Fuels Forecast of Demand for Thermal Coal in Pacific Rim Countries by Sector and Preferred Sulfur Content Steel Process Routes Maximum Deadweight Tonnage Versus Draft Conventional Collier 3-6 3-10 3-16 3-29 B20MLF#10 1.0 INTRODUCTION AND EXECUTIVE SUMMARY 1.1 PROBLEM SETTING The people of rural Alaska are faced with burdensome energy costs, costs which consume a disproportionate share of most families’ cash income. Recent studies conducted for the Alaska Power Authority, such as the Northwest Alaska Coal Feasibility Study (Dames & Moore, 1981), The Kotzebue District Heating Study (ASTS et al 1982), and the Bethel Area Power Plan (Dames & Moore, 1982) indicate that the vast resources of the Western Arctic Slope coal deposits are the most cost-effective energy source potentially available. Development of a coal mine in this area, whether at a large scale for export or at a small scale for domestic use would profoundly affect Northwestern Alaska, bringing with it needed jobs and revenues. However, the marketability and consequent economic viability of such a mine has not been previously determined. 1.2 PURPOSE, SCOPE, AND STUDY ORGANIZATION The purpose of this study is to make a preliminary determination of the marketability of Western Arctic Slope coals, both in the Alaska domestic market and in the international market. To accomplish this task, Dames & Moore has drawn upon existing literature and on the Western Arctic Coal Resource Assessment recently completed by Arctic Slope Consulting Engineers. This is a level-of-effect reconnaissance study. The level of funding and the preliminary nature of the data on which the marketability findings are based preclude any rigorous determination of marketability. Another important task of this study therefore, is to identify the areas of uncertainty which could significantly influence marketability. The reader is referred to Section 4.2 for a list of these areas. The study is organized into three main sections. Section 2.0 addresses the marketability of Western Arctic Slope coal in Alaska. Section 3.0 addres- ses the marketability on an international market. Findings and recommenda- tions are presented in Section 4.0. Section 5.0 consists of a bibliography. 1-1 B21MLF#10 1.3 AN OVERVIEW OF THE STUDY METHODOLOGY The following steps outline the analytic approach used in determining the extent of domestic (Alaskan) marketability: 1. 2. 3. 4. 5. 6. 7. 9. 10. Define the potential market area for Western Arctic Slope coal. Determine existing diesel fuel usage. Project future (year 2000) deisel fuel usage in the potential market area.* Convert future demands to coal equivalents. Postulate high medium and low demand scenarios. Determine competitive coal sources. Determine the costs of transporting and handling coal from the Arctic Slope and from competing sources. Compare the delivered cost of coal from the competing sources to the cost of Arctic Slope coal. Compare the cost of Arctic Slope coal to the cost of existing diesel fuel uses. Explore social and political and environmental factors affecting Alaskan marketability. The methodology for determining the international marketability of Arctic slope coals involves: 1. 2. 3. 4, 5. 6. Analysis and projection of Asian demand for both metallurgical and thermal coal. Analysis of quality requirements and contract terms. Determination of the price structure of competiting coal sources. Estimation of costs to ship Arctic Slope coal to Asian markets. Determination of the maximum competitive price per ton F.0.B. Cape Beaufort. Comparison of the competitive price with the cost of production. * The potential market area (shown in Figure 2-10) encompasses most coastal communities north of the Alaska Peninsula. B22MLF#10 1.4 SUMMARY OF RESULTS AND POLICY IMPLICATIONS Our analysis of international coal markets indicates that quantities of Arctic Slope thermal coal up to five million tons would be potentially competitive at a price of about $49 per ton F.0O.B. Cape Beaufort. Metallur- gical grade coal (up to one million tons) would also be marketable and would command an additional $3-4 per ton premium over thermal coal. The preliminary cost estimates in ASCE (1982) indicate that a mine operating at a scale of about 2 to 5 million tons per year could produce coal at the above price. However, both the cost estimates and the resource availability to sustain these levels of production are not yet firmly established. If a Western Artic Slope mine of export scale were operational (even at a one million ton per year scale), coal from such a mine would be the least expensive source of coal available to the coastal communities north of the Alaska Peninsula. By the year 2000, the fuel cost savings for switching from the existing diesel fuel-based energy system to one largely fired by coal would amount to as much as $88 million per year* (in constant 1982 dollars). Coal from a smaller scale mine--one designed to serve only the demands of coastal Alaska--would be of questionable marketability. A mine producing only 100,000 tons per year would be adequate to serve 30 percent of the space heating needs of the area as well as 80 percent of the electrical demands of Kotzebue, Nome, and Bethel (our low demand scenario). However, such a mine would produce coal at about $103 per ton according to ASCE's preliminary estimates (Table 2-6). At this price, and given the marine transport and handling cost estimates developed in Section 2.4, Arctic Slope Coal would not be competitive with coal from Canada (Prince Rupert) for the southern two dis- tribution centers (Bethel and Dillingham). Since these two areas account for 63 percent of the low scenario demand, the market for Arctic Slope coal all but vanishes at this price. * Based on the energy demands in Table 2-1 and the coal versus oil cost comparison in Table 2-1l. i=3 B23MLF#10 Lowering the cost of Arctic Slope coal to $90 per ton (as assumed in our medium demand scenario), does not materially change the marketability picture. Bethel and Dillingham could still obtain coal from Canada at a much lower coste Only if coal were available from Cape Beaufort (or other Western Arctic Slope deposits) at about $50 per ton would it be competitive with coal from Prince Rupert in crucial southern distribution centers. This again, as with the export market demand, suggests a scale of operation on the order of two million tons per year. If the conclusion that a small scale mine is uneconomic is substantiated by further analysis (subseqent to this study), two policy options emerge with regard to the development of Western Arctic Slope coal: 1. The mine must operate at a scale of about 2 million tons per year from the outset; or 2. If a small scale operation is necessary to establish mining experi- ence and export contract credibility, the output of such a mine must be sold at a subsidized price at least to Bethel and Dillingham users. The findings in this study are based on a careful analysis of existing information. We have identified the following policy-sensitive issues needing further research, in order to more accurately determine the marketability of Western Arctic Slope coal. Establish extent of economically mineable coal reserves. Accurately determine that heat content of the coal. Accurately estimate costs to mine the coal. Determine air quality impacts of extensive coal use. Determine costs to retrofit facilities to burn coal. Refine coal transportation and handling costs. oooeoo98 8 Analyze social and institutional impediments to coal utilization. A-1 MLF #10 2.0 DOMESTIC DEMAND FOR ARCTIC SLOPE COAL Numerous previous studies have noted the severe problem of supplying energy to rural Alaska at an affordable price. Several of those studies have identified coal from the vast Arctic Slope deposits as an economic alternative energy source for Western Alaska. This section provides an in-depth examina- tion of the potential Alaskan demand for Arctic Slope coal. The section begins with a brief survey of the previous studies of coal use in Alaska. Section 2.2 develops estimated energy and coal demands for the potential market area for Arctic Slope coal. Section 2.3 describes the price and availability of Arctic Slope coals and of other coals which could poten- tially serve the market area. The transportation costs for delivering coal to and with the market area are estimated in Section 2.4. Section 2.5 combines the cost and transportation data in an economic comparison of Arctic Slope coal versus alternative energy sources. Finally, Section 2.6 discusses other social and environmental domestic marketability. 2.1 A BRIEF SURVEY OF PREVIOUS STUDIES OF POTENTIAL COAL USE IN ALASKA In a reconnaissance study of energy sources for Northwestern Alaska for APA (Dames & Moore, 1981), Cape Beaufort coal was identified as the most economic alternative to existing diesel fuel energy sources. The Bristol Bay Regional Power Plan for APA (Stone & Webster, 1982) considered only supplies from Usibelli and Vancouver, but found that coal was considerably more econo- mic than existing energy sources. In the Bethel Area Power Plan (Harza, 1982), coal was identified as the most economic energy supply plan for space heating. In Appendix C-1 of the Bethel Area Power Plan (Dames & Moore, 1982), Cape Beaufort coal is found to be the least costly coal source for Bethel. The Kotzebue District Heating Study (ASTS et al, 1982) also identified Cape Beaufort coal as the most economic energy supply source. A2MLF#10 All of the above-mentioned studies treat Arctic Slope coal as a potential source for a limited region. This study, however, endeavors to look at Arctic Slope from the perspective of its entire potential market area, and to deter- mine the scale of operation and resultant economics of scale applicable to the demand in the market area. In addition, this study differs from previous studies in that it builds on its companion study, the recently completed Western Arctic Coal Resource Assessment prepared by Arctic Slope Consulting Engineers (ASCE, 1982). 2.2 ENERGY DEMAND PROJECTIONS The potential market area for Cape Beaufort coal is considered to be all coastal communities north of the Alaskan Peninsula.e Figure 2-1 shows the location of the communities in the market area and the marine transport network. In this area, the distribution centers Kotzebue, Nome, Bethel, Dillingham, and their nearby barge-accessable villages were considered to be feasible to supply with Cape Beaufort coal. For comparative purposes, all tonnage figures are expressed as ton equi- valents (T.E.), or short tons of coal with a heat content of 10,000 BTU per pound, because coals from different sources have different heating values. Actual tonnages demanded of a particular coal are obtained by multiplying the T.E. tonnage by the ratio of 10,000 over heating value to get the heat content value. For example, Cape Beaufort coal is conservatively estimated to have a heat content of 10,500 BTU's per pound. The heat factor is thus: 10,000 = 0.952 10,500 Thus from Table 2-1 the City of Bethel will require 20,395 T.E. x 0.952 = 19,416 tons of Cape Beaufort coal to satisfy its electrical demand in the year 2000. 2-2 CHUKCHI SEA PT. WORE OREVIG \ RISSION ST.MARTS att: © _otstarsution center comme BARGE SERVICE FROM MIME TO DISTRIBUTION CERTER —— BARGE SERVICE FROM DISTRIBUTION CEBTER TO VILLAGES SLEETRUTE FIGURE 2-1: POTENTIAL MARKET AREA FOR ARCTIC SLOPE COAL SHOWING THE PROPOSED MARINE TRANSPORTATION SYSTEM Dames & Moore 9-7 LAY TABLE 2-1 ENERGY DEMAND FOR ELECTRICAL AND SPACE HEATING IN THE ARCTIC SLOPE COAL MARKET AREA -~1981 AND 2000 Electrical Energy Demand Space Heating Energy Demand 1981 2000 1981 2000 oil Coal Coal oil Coal Coal Population Equivalent’ Equivalent Equivalent" Equivalent® Equivalent Equivalent" Community _(1981)° Qo%ca1) (10 T.B.)* (10 TB.) (0? Gat) (10 T.e.)* (10 TB.) CAPE_BEAUFORT aaa) Barrow “J 2,539 3,028,118 21.000 36.800 2,883,922 20.000 35.070 Wainwright 4104 48,580° 337° 480° 122.033° 846 945° Pt. Lay 68 18,599 129 162 40.200 +279 292 Pt. Hope 531 53.990 374 532 141,600 +982 1,067 Cominco = = = 45.000 - - - Kivilina 249 27.889 +193 +298 70.600 490 596 TOTAL 3,797 3,177,176 22.033 82.272 3,258,355 22.597 37.970 KOTZEBUE 2,250 1,200,000 8.322 9.091 1,800.000 12.483 13.210 Ambler 198 28.360 197 +265 66.408 461 503 Buckland 2 36.634 +254 +267 45.585 +316 343 Deering 155 45.000 2312 282 27.000 187 2192 Kiana 356 34.063 +236 +296 102.029 +708 +769 Kobuk 644 8.431 058 086 24,350 +169 +179 Noatak 273 32.711 227 321 88,200 612 +718 Noorvik 508 46.881 +325 559 175.390 1,216 1.319 Shishmaref 425 38.769 +269 403 103.800 720 822 Shungnak 208 26.243 182 +275 66.620 462 550 Selawik 372 46.470 322 569 182.712 1.267 1.370 TOTAL 5,020 1,543,562 10.704 12.414 2,682,094 18.601 19.975 NOME 3,039 1,000.000 6.935 7.249 1,240.000 8.599 9.419 Wales 143 20.479 142 +194 56.800 2394 398 Teller 229 44 303 307 2354 78.420 2544 2566 Golovin % 21.566 2149 174 37.859 +263 278 Unalakleet 672 180,518 1,252 1.405 295.000 2.046 2.150 Brevig Mission 149 23.360 162 +189 43.134 +299 +310 White Mtn. 135 15.762 109 2155 38.600 +268 302 Elim 228 24.151 167 +219 54.149 +376 407 Koyuk 203 23.668 164 +216 57.500 399 “413 Shaktoolik 177 30.458 e211 +254 51.200 2355 406 St. Michael 258 48.836° 339° -402© 90.575© 628 665° Kot lik 339 64.169° 445° 528° 119,011° 2825 874° Emmonak 568 107.516 746° 884° 199,405° 1,383 1.4604 St. Marys 432 81,772° 567° 672° 151.660° 1,052 1,113 Hooper Bay 624 118.116° 819° 971° 219.065° 1.519 1,608° TOTAL 7,290 1,804,664 12.514 13,866 2,732,378 18.950 20.375 * T.E. = Ton equivalents of coal with heat content of 10,000 BTU's per pound. s-z \3 TABLE 2-1 (Cont'd) ENERGY DEMAND FOR ELECTRICAL AND SPACE HEATING IN THE ARCTIC SLOPE COAL MARKET AREA -~1981 AND 2000 rns Ss 2 EEE Electrical Energy Demand Space Heating Energy Demand 1981 2000 1981 2000 oil Coal < Coal ale O11 Coal 1 Coal 11 Population Equivalent Equivalent* Equivalent’ Equivalent Equivalent ® Equivalent ’ Community cige1)° (o°cat) _ (10 T.E.)* (10 TB) 10° Gal 10° T.E.)* (10? TE. )* BETHEL 3,549 1,346.215 9.336 19.416 6,155,443 42.688 59.556 Akiachak 435 29.704 +206 414 122.567 850 1,700 Akiak 197 17.159 e119 +213 36.482 +253 525 Atmaut luak 226 20.476 142 -211 73.540 510 925 Eek 226 27.830 +193 309 105.407 +731 1.250 Kasigluk 431° 39.510 274 2447 139,149 965 1,900 Kwethluk 451 27,397 +190 359 99.351 +689 1,350 Napakiak 283 26.820 186 416 81.182 563 1,050 Napaskiak 242 23.937 166 277 64.311 446 825 Nunapitchuk 2648 24.225 168 274 85.220 2591 1.250 Oscarville 56 3.172 022 074 19,899 +138 +250 Tuluksak 2344 20.908 145 +256 74.405 516 875 Tuntutuliak 216 15.141 +105, +195, 69.647, 483, 1,025, Antak 3384 28.695 +1998 357 100.649 698 1,340 Sleetmute 107 9.084 063 113 31.867 a22ie 424° Quinhagak 409 34.607 240° 432° 121.846 845° 1.621° TOTAL 7,664 1,688.825 11,712 23.763 7, 380.966 51.187 75.860 DILLINGHAM 1,670 796.367 5.523 15.962 2,029,216 14,073 38.739 Aleknagik 152 a a a a a a Clarks Point 78, 56.493 392 613 65.474 454 +684 Fgegik 755 118.453 821 1,088 106.916 +741 1,051 King Salmon 545 b b b b b b Ekwok 764 14,123 098 #212 32.633 +226 390 Igiugig 334 16.857 e117 2212 31.107 216 353 Iliamna 944 129,387 897 2.737 145,548 1,009 2.352 Leve lock 79 17,312 -120 373 77,542 538 957 Manokotak 2904 39.180 +272 698 124,637 864 1.529 Naknek 318 1,339,428 9.289 15.254 1,968,528 13.652 30.107 Newhalen 135 k k k k k k New Stuyahok 327 50.115 348 922 105.771 +734 1,380 Nondalton ly k k k k 2 k Portage Creek 484 8.201 057 127 23.617 164 +271 South Naknek 145 b b b b b b Togiak 511 162.105 1,124 2.555° 257.895° 1,789° 3.270° TOTAL 4,747 2,748,021 19.058 65.418 4,968,884 34.460 81.083 TOTAL FOR MARKET AREA 28,518 10,962,248 76.021 198,733 21,022.677 145.795 235.263 A5 LAY#4 Notes: (a) Included in Dillingham. (b) Included in Naknek. (c) Source: Alaska Department of Labor, 1982. Alaska Population Overview 1981, Table 1.3, Official July 1, 1982 Alaska Population by Organized Area and Date of Incorporation. (d) Source: Alaska Department of Labor, 1982. Alaska Population Overview 1981, Table II.7, Total Population by Place and Census Area, 1960 to 1980, State of Alaska. Populations for Kasigluk and Nunapitchuk were estimated as a 62 percent and 38 percent split, respectively, of Akolmiut City's 1980 population of 641. (e) Estimates based on average demand per acre per resident, excluding first class cities. Specific assumptions are given in footnote at top of column. (£) Demand forecasts for oil in 1980-81 for Beaufort, Kotzebue and Nome areas based on Dames & Moore, 1980, Phase II, Table 1-1. Estimates for vil- lages not covered in this previous study and designated by footnote (e) were based on the following assumptions: 1) Average oil use by Beaufort area villages for electricity demand 1980-81 equals .118 x 103 gallons/ resident; 2) Average oil use by Beaufort area villages for space heating demand, 1980-81, equals .298 x 103 gallons/ resident; 3) Average oil use by Nome area villages for electricity and space heating demand, 1980-81, equals .189 x 103 gallons/ resident and .351 x 103 gallons/ resident, respectively; and 4) Coal demand was projected from oil demand figures using a conversion factor of .0069 tons of coal per gallon of oil. 2-6 Notes: (continued) (g) (h) (i) (4) Demand forecasts of coal requirements in 1980-81 for electricity and space heating for the Bethel area based on Dames & Moore, 1982, Table 2-3. Estimates for villages not covered by this previous study and designated by footnote (e) were based on the following assumptions: 1) Average coal demands by Bethel area villages for electricity and space heating in 1980-81 equals .0006 x 103 tons/resident and 0021 x 103 tons/ resident, respectively; and 2) Oil demand was projected from coal demand figures using a conversion factor of 144 gallons of oil per ton of coal. Demand forecasts for coal in 2000 for the Beaufort, Kotzebue and Nome areas based on Dames & Moore, 1980, Phase II, Table 1-2, prepared for the Alaska Power Authority. Estimates for villages not covered in the previous study and designated by footnote (e) were based on the following assumptions: 1) Average coal use in 2000 for electricity and space heating for Beaufort area villages equals .0012 tons/resident and 0023 tons/resident, respectively; and 2) Average coal use in 2000 for electricity and space heating for Nome area villages equals .0016 tons/ resident and .0026 tons/resident, respectively. Demand forecasts for coal in 2000 for the Bethel area based on Dames & Moore, 1982, Exhibit 5. Estimates for villages not covered in the previous study and designated by footnote (e) were based on the assump- tion that average coal use in 2000 for electricity and space heating for Bethel area villages equals .0011 tons/resident and .0040 tons/resident, respectively. Demand forecasts for Barrow are based on current natural gas energy use rate (1981) of 420,000 and 400,000 MCF for electricity and heating, respectively (Sheldon Tiegland, Barrow Utilities, personal communication, 12/23/82). Projections to year 2000 are based on an assumed annual demand growth rate of three percent. 2-7 ATLAY #4 Notes: (continued) (k) Included in Iliamna. (1) (m) Demand forecasts for coal in the Dillingham area are based on Alaska Power Authority projected energy and power requirements based on the base plan scenario by ISER (ISER Report, Appendix C, Tables 3.2-3 and 3.2-10). Current forecasts are based on 1980 and 1982 data. Future projections are extrapolated from 1977 and 2002 projections. Estimates for Togiak, designated by footnote (e), were based on the following assumptions: 1) Average coal used by Togiak equals .0022 x 10° tons/ resident in 1980- 81 for electricity, .0050 x 10° tons/resident in 1980-81 for space heating, .0035 tons/resident in the year 2000 for electricity, and .0064 x 10° tons/resident in the year 2000 for space heating; 2) Coal demand was projected using a 27 percent efficiency factor for electrical conver- sion at .6319 tons/MWh/year; 3) Space heating coal demand was projected at .2405 tons/MWh/year; and 4) Oil demand was projected from coal demand figures using a conversion factor of 144 gallons of oil per ton of coal. The electric demand for Cominco is estimated to be 87,600 MWh per year (personal communication to Pam Knode, 1/6/83). At an assumed 33 percent conversion efficiency (1,934 KWh/T.E.), the demand is 45,000 T.E. per year. 2-8 A3MLF #10 2.2.1 Total Energy Demands About two-thirds of the estimated energy demand in the area for the year 2000 is for space-heating, with the remainder for electrical generation. Existing 1981 and projected year 2000 energy requirements expressed in oil and coal equivalents are shown in Table 2-1. Total energy demand in 1981 is esti- mated as about 4.5 million gallons of oil and 31,464 ton equivalents of coal. In the year 2000, total energy requirements were estimated to be about 433,996 T.E.; 198,733 T.E. for electrical requirements (33 percent of total demand), and 235,263 T.E. (67 percent of total demand) for space heating requirements. Demand forecasts were taken from two previous Dames & Moore studies: 1) Assessment of the Feasibility of Utilization of Coal Resources of Northwestern Alaska for Space Heating and Electricity, which provided estimates for Cape Beaufort, Kotzebue, and Nome centers and villages, and 2) Bethel Area Power Plan Feasibility Assessment - Appendix C-l, for Bethel and neighboring vil- lages. The demand for coal in villages not covered in these reports was estimated on per capita basis. It was assumed that a mine at Cominco will exist by the year 2000, and will require about 45,000 ton equivalents (T.E.) of coal. The Cominco mine, potentially a major lead zinc (and some silver) mine, is still in the planning stages. This mine would be located near the village of Kivilina. Although mining representatives have not discussed the possibility of using coal as an energy source for the mine, it is likely that coal would be used if a low cost source of coal existed at Cape Beaufort. 2.2.2 Coal Demand Scenarios Dames & Moore developed three demand scenarios, a high, medium, and low demand scenario, to reflect the uncertainty of these demand projections and to show the sensitivity of the quantity of coal demanded to the price of coal. Specific assumptions used to develop the high, medium and low scenarios are summarized in Table 2-2. For the high demand scenario it is assumed that Al7 LAY#4 TABLE 2-2 DEMAND SCENARIOS, YEAR 2000 HIGH DEMAND SCENARIO Electric - 80 percent of all distribution centers and villages within 60 miles (except 100 percent for Cominco). Space heat - 80 percent of all distribution centers and all neighboring villages. MEDIUM DEMAND SCENARIO Electric - 80 percent of all distribution centers only (except 100 percent for Cominco). Space heat - 50 percent of all distribution centers and all neighboring villages. LOW DEMAND SCENARIO Electric - 80 percent of all Kotzebue, Nome, Bethel distribu- tion centers (none for Cominco). Space heat - 30 percent of all distribution centers and all neighboring villages. Source: Dames & Moore assumptions. 2-10 A4MLF#10 coal will provide 80 percent of space heating needs. Coal-fired electrical generation is assumed to provide 80 percent of the electricity in the distri- bution centers and (by electrical intertie) 80 percent of the electricity to village within 60 miles of the distribution center. The circles on Figure 2-1 defined the electrical intertie boundary. It is also assumed that under a medium and high demand scenario, a power plant would be constructed at the Cominco mine port near Kivilina and power would be supplied to Cominco via transmission line; no neighboring villages are expected to be supplied from this plant. No coal-fired power plant was assumed at Cominco in the low demand scenario. For space heating demands, it is expected that both bulk and sacked coal would be used at the distribution centers. Villages would use sacked coal brought in from distribution centers on barges and unloaded onto the local dock. The breakdown of demand by distribution center by use (electric, bulk, or sacked coal) is given in Table 2-3. These demands are estimated by assuming that 40 percent of coal going to distribution centers for space heating would be bulk coal; the remaining 60 percent would be in sacks. All coal for space heating for villages is assumed to be sacked. As Table 2-3 shows, total demand for coal in the year 2000 under the high demand scenario is expected to be 279,548 T.E., roughly one and a half times the medium demand scenario of 195,656 T.E., and almost three times the low demand scenario of 99,185 T.E. 2.3 COAL SUPPLY ALTERNATIVES FOR THE CAPE BEAUFORT COAL MARKET AREA Demand for Arctic Slope coal depends in part on the price and availabil- ity of Cape Beaufort coal relative to coal from potential competing sources. 2-10 ALL Layés TABLE 2-3 ELECTRICAL AND SPACE HEATING, DEMAND FOR COAL BY SCENARIO (YEAR 2000)* Electrical Demand 10? + wivalents) Space Heating Demand ao? Ton Equivalents) High Medium Low High Medium Low Sack-~ Sack-— Distribution Distribu- q _Pistribu- Distribu- ‘ . Sack Distribu- | Sack p Distribu- | Sack Center tion Center Villages’ tion Center tion Center Bulk tion Center’ Villages tion Center Villages Bulk” tion Center® Villages CAPE BEAUFORT = - = 7 ia = 30.376 - = 16,985 - . 41.391 COMINCO 45.000 - 45.000 - - - - - - - - - - KOTZEBUF. 7.273 1,166 7,273 7,273 4.227 6.341 5.412 2.642 3,963 3,383 1,585 2.378 2,030 NOME 5.799 0.407 5.799 5.799 3,014 4.521 8.765 1,884 2,826 5.478 1,130 1.696 3.287 BETHEL 15.533 2,756 15,533 15,533 19,058 28,587 13,043 11,911 «17,867 8.152 7.147 10,720 4.891 DILLINGHAM 4.418 8.986 4.418 - 12,396 = 18.595 33.875 7.748 = 11,622 21,172 4,649 6.973 12,703 TOTAL ALL AREAS 78.023 13.315 78.023 28.605 38.695 58.044 91.471 24,185 36.278 57.170) 14,511 21,707 %.W2 See Footnotes on following page. 2-11 Total ie. 30.376 45.000 24.419 22.506 78.977 78.270 279.548 3 10_T.E. ium 18.985 45.000 17.261 15.987 53.463 44.960 195.656 11.391 13.266 11.912 38.291 24.325 99.185 Al3 LAY#4 Notes: (a) Calculated from Table 2-1 using scenario assumptions in Table 2-2. (b) Assumed to be 40 percent of total distribution center demand. (c) Assumed to be 60 percent of total distribution center demand. (d) Villages considered within 60-mile radius of the distribution center: Beaufort - none Kotzebue - Deering - Kiana - Noatak - Noorvik Nome - Teller - White Mountain Bethel - Akiachak - Akiak - Atmautluak - Eek - Kasigluk - Kwethluk - Napakiak - Napaskiak - Nunapitchuk - Oscarville - Tuluksak - Tuntituliak Dillingham - Aleknagik - Clark's Point - Ekuk - Ekwok - Manokotak - Portage Creek - Togiak 2-12 ASMLF #10 These potentially competing sources include undeveloped Alaskan deposits as well as coal from existing mines. These supply sources are discussed in Sections 2.3.1 and 2.3.2, respectively. In Section 2.3.3, the price and availability characteristics of the Arctic Slope coals are summarized from the recent Arctic Slope Consulting Engineers Study (ASCE, 1982). 2.3.1 Competition From Undeveloped Alaskan Coal Sources Alaska has a majority of the potential coal resources in the U.S., yet it has only one operating coal mine. The remaining coal occurrences are un- developed and for the most part unexplored. Attachment 1, a map published by the U.S. Geological Survey showing the location, extent and grade of Alaska's coal occurrences, is in a pocket at the back of this report. Table 2-4 summarizes the characteristics of some of the major undeveloped Alaskan coal Occurrences. The following is a brief discussion of these occurrences, roughly in order of commercial potential. Beluga Coal: Very extensive surface-mineable deposits are known to exist in this areas Although the coal is lignite and has a low heat content, this deposit benefits from its extensiveness, its tidewater location, and its relatively close proximity to the population and developed infrastructure of the Anchorage areas Two major leaseholders, Diamond-Shamrock and Placer-AMEX control most of the resources. Diamond-Shamrock is currently investigating mining in the area, but their plans include converting this coal to methanol prior to shipment. The Placer-AMEX project is on hold awaiting improvement of the world coal market. Even if development proceeds, those mines will not be competitive with the domestic market for Arctic Slope coal due to long trans- port distances and low heat content. Bering River Coal: The City of Cordova has, at the time of this writing, just embarked on an exploration and feasibility study program to assess the Bering River coal deposits. Distance probably precludes this coal from competing with Arctic Slope coals. 2-13 TABLE 2-4 PHYSICAL AND ECONOMIC CHARACTERISTICS OF ALASKAN COAL OCCURRENCES SOURCE AND LOCATION Nenana District Usibelli Mine Healy, ak Kuskokwim District Munivak and Nelson Islands Unalakleet District Various locations near Unalakleeet and up to 40 miles upriver Mulato District Various occurrences on Yukon River between Ruby and Anuk Flat District Iditarod River Deposits Cape Beaufort/ Corwin Bluff District Various occurrences Broad Pass Susitna (Beluga) Matanuska Kenai (Homer) Alaska Peninsula Herendeen Bay Unga Island Chignik Coal Field Bering River District Bering River Coal Sevard Peninsula Chicago Creek RANK AND/CR HEAT CONTENT (Btu/1b.) Subbituminous 7,850 Bituminous 10,000 Lignite 6,500 Bituminous 10,000 Anthracite 14,000 Bituminous to Anthracite 12,000 - 14,000 Lignite (5,410 - 7,040) Lignite-sub- bituminous (7 ,030-9,520) Bituminous (9000-14 ,000) Lignite (6,500) Bituminous (11,500) Bituminous 9,600-11,200 Bituminous— anthracite (10,000-15 ,000) Lignite (6,500) FACTORS AFFECTING MINEABILITY Existing surface mine with capacity to meet Bethel's requirements. Thin beds (2 feet or less), high ash, remote location, occurrences probably on native lands, mo port facilities. Low grade coal, access by Tiver barge, no developed infrastructure. History of small scale mining. Mostly thin beds and limited extent. Access only by shallow draft Tiver barges. Very limited resources. Access by shallow draft Tiver barge, remote location. Probably extensive resources, some in thick gently dipping beds. Access to tidewater, but no developed infre- structure. Extensive resources but development contingent on Beluga. Low rank. Mineable by large-scale surface techniques on tidewater, but low rank Previously developed mine, could be reopened. Mineable by large-scale surface techniques on tidewater, but low rank Moderate folding, but some thick beds. Near tidewater. Remote location. Remote location, very low Fairly extensive deposits with some 3-foot beds, but surface mineability unknown. Highly folded occurrence with extensive deposits. Steep dips, but thick beds. Shallow access. 2-14 DEVELOPMENT STATUS Developed Very unlikely Unlikely Unlikely Unlikely Good long term prospect Possible in long tera Under active consideration Possible medium term Possible in long tera Possible in long tera Very unlikely Possible in long ters Under considere— tion by Cordova Unlikely A-6 MLF #10 Matanuska Coal: These coals are of fairly good quality, but the best coals have already been mined out of this area. If production were to resume, Mananuska's competitive position would probably be similar to that of the existing Usibelli mine (See Section 2.3.2). Herendeen Bay Coal: This coal is an attractive prospect because of its reportedly high quality and proximity to tidewater. Herendeen Bay is a reasonable distance from the southern part of the Arctic Slope Market area, particularly Dillingham and Bethel, but little is known about the extent or mineability of these deposits. No recent development plans have been proposed for these deposits. Broad Pass, Susitna, Chignak Coal: These coals are fairly low rank (low quality). Because of their distance from the Arctic Slope coal market area, their landed cost per unit of energy is likely to be much higher than Arctic Slope coal. Chicago Creek Coal: Despite its proximity to tidewater and location within the Arctic Slope coal market area, Chicago Creek coal is not competi- tive due to its low rank and the difficulty of access because of the shallow water depth of the southern end of the Kotzebue Sound. Although a geologic exploration program conducted by the State Geological Survey during the summer of 1982 indicated considerable surface-mineable reserves, this resource is not likely to be economically competitive with Arctic Slope coal, as indicated by Dames & Moore, 1981 and 1982 and ASTS et al, 1982. Other Coal Districts: Coal from the Nulato and Flat districts are probably not mineable because of their limited extent and because they are accessible to tidewater only by shallow barge. Despite their high rank and proximity to the market area, these coals will not compete with Arctic Slope _ coals. Coal from Nunivik and Nelson Island is probably not competitive with Arctic Slope coal due to their suspected small extent, their lack of mine- ability and their problematic land status. 2-15 A7MLF#10 In summary, with the possible exception of the Manauska Coal Field, Tone of the currently known potential Alaskan coal occurrences pose a serious competitive challenge to the domestic marketability of Arctic Slope coal. 2.3.2 Competition From Existing Coal Mines Only one coal mine is currently operating in Alaska--the Usibelli mine in the Healy District north of Fairbanks. This mine currently produces about 900,000 tons per year, most of it is consumed in the Fairbanks area. Recent reports indicate that the mine has successfully completed negotiations with Korea to supply coal for Transpacific shipment, which will result in an increased scale of operations at the mine. Coal from Usibelli will be shipped via the Alaska Railroad to Seward where it could be barged to the Artic Slope coal market area. In late 1982, this coal cost about $48.00 per ton F.0.B. Seward (Dames & Moore, 1982). The recent Korean contract could marginally reduce this cost. Thus, despite its relatively low rank and poor quality, (see Table 2-5) Usibelli coal must be considered competitive with Arctic Slope coal. In identifying the least costly alternative for supplying coal to Bethel, Dames & Moore (1982) conducted an extensive comparison of coal from existing mines from Canada and the Lower 48. The results of this analysis indicated that coal from British Columbia (the Bull Moose Mine) barged from Prince Rupert was the least costly source, at a cost of $52.00 per ton, F.0.B. Prince Rupert. Since this coal is highest in heat content (12,400 BTU per pound) and closest to the Arctic Slope coal market area of any existing source there is no reason to repeat this analysis. Prince Rupert coal does present a serious potential challenge to the domestic marketability of Arctic Slope coal. Rather than comparing the marketability of other Canadian and Lower 48 sources such as Vancouver, Powder River, and Utah coals, only Prince Rupert coals will be analyzed. To the extent that Arctic Slope coal can be shown to be competi- tive with Prince Rupert coal, it will also be competitive with other existing coal sources. Table 2-5 presents the quality characteristics of Prince Rupert coal. 2-16 A23. LAY#4 TABLE 2-5 COMPARISON OF QUALITY OF CAPE BEAUFORT, USIBELLI, AND PRINCE RUPERT COAL Se —_ Cape Beaufort’ Usibelli Mine” Prince Rupert® Rank Bituminous Subbituminous Bituminous Heat content 9,000-13,000 7,850 12,400 (BTU's per pound) Ash (percent) 4-10 6-7 ci Sulphur (percent) 0.1-0.3 0.2 0.4 Fixed carbon 35-50 36 gi" (percent ) Volatiles 27-38 40 22.54 (percent ) Moisture 3-6 27 1.2% (percent ) Grindability N.Aw 29.45 85 (Hargrove) (a) Approximate range of values for uncontaminated samples on an as~ received basis, (Callahan & Sloan, 1978). (b) As shipped typical analysis. Personal communication with Steven Denton, Usibelli Coal Mine, 8/4/82. (c) Personal communication with Dick Drozd, Bullmoose Mine, 10/28/82. (d) Based on air-dried sample. N.A. - Not Available. 2-17 A8MLF #10 2.3.3 Arctic Slope Coal Price and Availability The companion study to this report, The Western Arctic Coal Resource Assessment (ASCE, 1982)*, presents a detailed picture of the current state of knowledge about the availability and price of Arctic Slope coals. This report will, therefore, only briefly summarize the results of that study which bear on the marketability of Arctic Slope coal. In the Resource Assessment, the Cape Beaufort area (Site V) is identi- fied as the top priority site for a small scale (100,000 tons per year) mine due to its proximity to tidewater and its fairly good mineability. A total of 26 coal beds ranging from a few inches to 17.6 feet have been identified at this site, some as close as 4 miles from tidewater (Callahan and Sloan, 1978). Dips (the inclination of the coal beds) range from 14 to 23 degrees. Callahan (1976) calculates that 35 million tons of measured reserves and 312 tons of indicated resources are present at the site, although much of these Tesources may not be surface mineable. Cape Beaufort coal is highly volatile bituminous with good coking poten- tial. The heat content is estimated to be 10,500 BTU per pound in the resource assessment. This is very conservative since values in excess of 13,500 BTU per pound have been reported for some beds. The conservative value is used throughout this report, although the marketability sensitivity of using a 13,000 BTU per pound value is discussed in Section 2.5. The quality of Cape Beaufort coal is compared with Usibelli and Prince Rupert coal in Table 2-5. The Resource Asessment (Page 3.0-5) identifies the Howard Syncline (Site III) as the top priority site for a large scale mine producing 1 to 5 million tons per year. That site was selected because of its very good coking properties, low dips, shallow overburden, low ash and high heat content. Cape Beaufort is second in priority for a large scale mine. Neither site has sufficient proven reserves to sustain a mine of this scale, although exploration is far from complete. * Hereafter referred to as the “Resource Assessment”. 2-18 ASMLF #10 Other potential mine sites in the Western Arctic Slope area include the Epizetca Anticline, the Barbara Syncline, and the Snowbank Anticline, all along the Kukpowruk River, and the Deadfall Syncline, just north of Cape Beaufort. These sites are described in the Resource Assessment. For purposes of this economic analysis, we will focus only on the Cape Beaufort site. According to the preliminary feasibility analysis, Howard Syncline coal has a higher assumed heat content than Cape Beaufort coal, but it is more expensive to mine and load. As a result, the two sources are almost identical on a per-unit-energy basis. These costs are shown on Table 2-6. The cost analysis contained in the Resource Assessment was based on a 1977 study by Kaiser Engineering of a Kukpowruk River mine site. The Resource Assessment updated the costs in that study and adjusted costs for the slightly different mine site location, and different scale of operation. As seen on Table 2-6, Cape Beaufort coal costs $103.00 per ton at a 100,000 ton per year scale, $62.30 per ton at 1 million tons per year, and $34.26 at 5 million tons per year. These costs include loading at Cape Beaufort. It is apparent that the cost to mine coal is highly dependent on the scale of operation. Since the fixed capital investments in infrastructure to house workers, maintain equipment, and to load coal must be made especially to serve the proposed mine, the larger the quantity of coal these costs can be spread over, the lower the per-unit cost. The cost per ton is intimately interrelated to the level of demand. The aggregate Alaskan demand for coal totals 280,000 tons per year for the high demand, 196,000 tons per year for the medium demand, and 99,000 tons per year for the low demand scenario (Table 2-3). The low demand scenario closely corresponds to the small scale mine of the Resource Assessment, where coal costs $103.00 per ton. The medium demand scenario implies a larger scale mine which lowers production costs. For purposes of comparison, coal in the medium demand scenario is assumed to cost $90.00 per ton. The high demand scenario implies that coal replaces diesel energy sources to a great extent. This 2-19 TABLE 2-6 PRELIMINARY ESTIMATES OF THE COST TO MINE WESTERN ARTIC SLOPE COALS (FROM ARCTIC SLOPE CONSULTING ENGINEERS, 1982) Cape Beaufort (Site v) 100,000 ton/yr 1,000,000 ton/yr 5,000,000 ton/yr t eins, Capital Costs thousands) Capital Costs thousands) Capital Costs thousands) Annual Costs (thousands) Peice Per Ton (dollars) Price Per Million Beu (dollars) 1 + Surface mining 2 - Transportation trom mine site to ocean transport } - Price for coal loaded on ocean transport 2-20 A1OMLF#10 would only occur if low cost coal were available, which would be the case if a large-scale mine geared to export operations were already in place. Thus, the cost of coal in the high demand scenario is $34.26, the cost of coal under the 5 million ton per year mine. The costs for the 1 million ton mine were not used because coal from that mine is too expensive to compete on a world market (See Section 3.0). Since that demand level does not exist in the Alaskan market, that scale of mine is not likely to occur. 2.4 COAL TRANSPORTATION SCENARIOS AND COSTS 2.4.1 A Feasible Coal Distribution System The presumed market area for Arctic Slope coal was defined largely on the basis of marine transportation infrastructure. Coal is a low value product per unit of weight. The only way that coal can be economically justified is if it can be delivered at a reasonable cost. For this reason, only those cities and villages which are on, or fairly close to, tidewater can be consid- ered as potential coal users. The marine transportation infrastructure, shown on Figure 2-1, includes only those communities on or near the coast. Economical coal transportation to the coastal communities presents a difficult problem. The largest possible barges must be used to economically transport coal over long distances. However, since many communities can accomodate only shallow draft vessels, large barges cannot be used. Further- more, handling convenience in the villages requires that coal be delivered in sacks. However, sacked coal cannot be carried on large barges, nor can it be rapidly loaded or unloaded. The solution to this problem (developed in consultation with Dillingham Maritime) involves transporting bulk coal in medium-sized barges from the proposed Cape Beaufort mine site to distribution centers at the major communities. At these distribution centers the coal is sacked for delivery to the villages in small lighterage barges. On Figure 2-1, the routes from Cape Beaufort to the distribution centers are indicated with a thick line, while the routes from the distribution ane) A11MLF#10 centers to the villages are indicated with a thin line. Section 2.4.2 dis- cusses transportation from mine to distribution center. The village distribu- tion system is discussed in Section 2.4.3. The analysis performed by Dillingham Maritime (under subcontract to Dames & Moore) is incorporated in this analysis and reproduced in its entirety as Appendix B. 2.4.2 Coal Transportation From Mines To The Distribution Centers Coal mined at Cape Beaufort is assumed to be loaded at a coal loading dock capable of accomodating vessels of up to 15 foot draft. At this facil- ity, 7000 deadweight ton (DWT) ocean barges 286 feet long and 76 feet wide can be loaded in about eight hours. Fully loaded barges have a draft of 15 feet. However, the draft limitations at several of the distribution centers requires that less than a full load be carried. According to Dillingham Maritime, it is more economical to partially load a 7,000 ton barge than it is to fully load a shallow draft barge. By lightly loading the barges the costs of lightering (transferring cargo to shallow draft barges while at anchor) are avoided. For comparison purposes, this same tug-barge concept conceived for the Cape Beaufort mine could be used to ship coal from Usibelli (via Seward) or from Prince Rupert. The same draft limitations at the destination would apply but a longer shipping season could be used. While shipping from Cape Beaufort is limited to the average 103-day ice-free season there, coal shipped from an ice-free port could use a 150-day shipping season available at Bethel or Dillingham. Shipments to the more northerly destinations would take place during the 103-day season. Distances from Seward and Prince Rupert to the distribution centers are shown on Table 2-7. Once the barges are docked at the distribution center, coal would be offloaded using a crawler crane fitted with a 6-cubic-yard clam bucket. The bucket would empty into a hopper which would feed a conveyor belt that carried the coal to a stockpile. If an electric-fired power plant uses coal, it would be most economical to locate that plant near the dock area stockpile. 2-22 A29LAY #4 TABLE 2-7 BARGE CAPACITIES OF DISTRIBUTION CENTERS Tonnage Distance From Draft Limitation Distribution Cape Beaufort Limitation (in 7,000 DWT Center (Nautical Miles) (feet) Barges) CAPE BEAUFORT 0 15 7,000 COMINCO™ 150 15 7,000 KOTZEBUE 220 6 2,500 NOME 316 6 2,500 BETHEL 881 15 7,000 DILLINGHAM 920 12 5,500 (a) Although Cominco is not a distribution center it is assumed that it will have a medium-to-deep-draft port capable of receiving bulk shipments. Source: Dillingham Maritime, 1983; Dames & Moore assumptions. 2-23 A14MLF#10 If land use or air quality considerations make that option infeasible, it would be necessary to transport coal, to a second stockpile near the power plant using front-end loaders and dump trucks. Coal used for space heating would be handled one of three ways, depending on its intended use. Coal destined for use in large commercial establish- ments and public buildings could be distributed by covered coal trucks with chutes which can directly fill coal bins under or alongside the buildings. Coal used for heating smaller commercial buildings and residences in the distribution center would be loaded into 100 pound sacks. These sacks would be delivered by a flatbed truck or picked up at the stockpile by the consumer. Coal destined for the outlying villages would be sacked, and the sacks Placed on 4-by-4 foot wooden pallets, each holding 20 one-hundred pound sacks. A forklift would be used to load these pallets onto flatbed trucks, which would bring the pallets to the cargo dock for distribution to the villages. 2.4.3 Coal Transportation From Distribution Centers To Surrounding Villages The distribution centers identified in the previous subsection already serve the surrounding villages with diesel fuel and general cargo, usually using 500-ton lighterage barges with bulk fuel storage tanks for diesel and deck storage of cargo. These same vessels could be used to distribute sacks and pallets of coal. However, if coal quantities to serve 50 to 80 percent of heating needs (assumed in the medium and high demand scenarios) were to be distributed, it would be more efficient and economical to utilize a dedicated fleet of 2,000-ton barges. As noted previously, lightly loaded larger barges can carry greater cargos than fully loaded smaller barges at a given draft limitation. The draft limitation at many villages is in the 3 to 5 foot range. The villages served from each distribution center are shown in Table 2-3. Villages typically do not have developed docking facilities. Barges are beached at or near the village during high tide, then unloaded across the 2-24 A15MLF#10 beach during low tide. The distribution barges would each carry a fork lift to unload the coal pallets. Coal would be stockpiled at scme central location in the villages in much the same way that diesel is now stored in central tanks. 2.4.3 Marine Transportation Costs The costs of barging coal from the mine to the docks of the various distribution centers were estimated with the aid of research conducted by Dillingham Maritime in Seattle. Because Dillingham Maritime has considerable transportation experience in Alaska, they were asked to prepare cost estimates for transporting coal from Cape Beaufort to the distribution centers, and from the distribution centers to neighboring villages. For the purpose of this analysis, “transport” costs are defined as the cost of moving coal from the mine to the pier of the distribution center and from the distribution center to the neighboring villages. “Handling” costs are defined as these additional costs required to move coal from the pier of the distribution center and to package it for delivery to its ultimate destination--either to a power plant, in bulk form to the distribution center, or in sacked form to the distribution center or to the villages. Per-ton handling costs vary by the quantity of coal handled, while per-ton transport costs are invariant as to quantity. Transport costs to the various distribution centers from three sources of coal are shown in Table 2-8. The three sources of coal, Cape Beaufort, Prince Rupert, and Usibelli, are discussed in detail in Section 2.2. Because trans- port costs depend primarily on the distance between the mine and the distribu- tion center, the least expensive source of coal is typically the closest source (Table 2-8). Cape Beaufort coal, therefore, is the cheapest of the three sources for Cape Beaufort, Cominco, Kotzebue, and Nome. Although Cape Beaufort is a slightly closer source of coal to Bethel and Dillingham than the Usibelli mine, transport costs from Cape Beaufort are slightly higher than 2-25 14.-1-axyra TABLE 2-8 MARINE TRANSPORT COSTS BY DISTRIBUTION CENTER nn ee eaten aI UyE SIE IS ISIS RU SSERERRSUESU Available Tonnage Cape Beaufort Coal Prince Rupert Usibelli istribution Draft Per Distance Cost Distance Cost Distance Cost Center (Feet )* Barge* (Naut. mi.) Per Ton?*® (Naut. mi.) Per Ton’*? (Naut. Mi.) Per Ton od ‘APE BEAUFORT 15 7,000 0 $ 0.00 2,200 $ 61.12 1,700 $ 48.78° ‘OMINCO 15 7,000 150 11.25 2,050 45.12 1,550 35.42 OTZEBUE 6 2,500 220 36.51 1,980 122,52 1,480 95.38 OME 6 2,500 316 43.37 1,746 109.82 2,386 144.56 (ETHEL 15 7,000 881 29.90 1,546 35.34 1,046 25.65 \ILLINGHAM 12 5,500 920 39.32 1,507 14.02 1,007 31.68 lotes: ‘a) Source - Dillingham Martime, personal communication 1/14/83; see Appendix A. ‘b) Based on 1 knot headway for tug/barge plus four days for loading and unloading. ‘c) Based on an annual operating cost of $15,000/day underway, $13,000/day standby and a 103-day season. ‘d) Based on a daily operating cost of $11,400/day underway, $9,400/day standby and a 150-day season. 'e) Draft at Beaufort is assumed to be 12 feet in absence of mine. 2-26 A16MLF#10 from Usibelli because of higher operating costs for vessels out of Cape Beaufort, and a somewhat shorter season out of Cape Beaufort (103 days) compared to the Usibelli area (150 days). Prince Rupert coal ranks as the most expensive of the three sources in nearly every case due to’ distance. Handling costs shown in Table 2-9 are adopted from the previous Dames & Moore Bethel Area Power Plan study, Exhibit 13 (1982). It is assumed that handling costs at all distribution centers would be the same as handling costs estimated for Bethel. Costs are estimated by use of the formulas identified in the table footnotes. The first half of the formula estimates costs of transporting coal from the pier to the power plant stockpile and is the same regardless of the ultimate use of the coal. The second half of the formula Tepresents costs associated with the coal's ultimate use; the cost of having coal from the stockpile into the power plan for electrical use, the cost of bulk delivery for the use of bulk coal for space heating, or the cost of sacked coal delivery for the use of sack coal for space heating. Both fixed and variable costs are reflected in these estimates. Handling costs are shown in levelized form. All costs are shown in 1982 dollars. Further details on how handling costs are estimated are described in detail in the Bethel Area Power Plant report. As Table 2-9 shows, handling costs by ton are expected to be similar in Bethel and Dillingham, and similar in Kotzebue and Nome (though higher than in Bethel and Dillingham). Handling costs to the villages vary widely, ranging from $14.00 per ton for sacked coal to villages near Bethel, $29.06 per ton to villages near Dillingham, $75.23 per ton to villages near Kotzebue, and $112.08 per ton to villages near Nome. t 2-27 A1SLAY#4 TABLE 2-9 ANNUAL LEVELIZED HANDLING COSTS BY TON, BY SCENARIO (1982 $ PER TON) Community & Use High Demand Medium Demand Low Demand CAPE BEAUFORT Electrical(a) (Cominco only) 16.5 17.7 - Village(d) 25.8 25.8 25.8 KOTZEBUE Electrical(a) 34.7 43.1 51.2 Bulk(b) 51.5 71.2 100.8 Sacked(c) 90.1 105.5 127.2 Village(d) 7502 7522 75.2 NOME Electric(a) 37.9 46.9 56.8 Bulk(b) 61.0 86.3 126.3 Sacked(c) 90.0 105.3 127.3 Villages(d) 112.1 112.1 112.1 BETHEL Electric(a) 18.2 21.5 24.5 Bulk(b) 22.6 28.0 36.2 Sacked(c) 67.6 72.6 79.9 Village(d) 14.0 14.0 14.0 DILLINGHAM Electric(a) 19.2 30.7 - Bulk (b) 25.0 33.5 49.6 Sacked(c) 66.9 73.0 84.8 Village(d) 29.1 29.1 29.1 See footnotes on following page. 2-28 Notes: (a) Derived using the formula 463,000 + 5.037, + 47,000 + 4.76)» where T, is total quantity of coal demanded (Table 2-3) T, T, and T, is quantity of coal demanded for electrical use (Tab1é 2-3). The first half of the equation is the cost of transporting coal from the pier to the power plant stockpile. This cost would be accrued regardless of the ultimate use of the coal. $463,000 is the fixed cost; $5.03 is the variable cost per ton for handling costs, as estimated in the Dames & Moore 1982 Bethel Area Power Plan, Exhibit 13. The second half of the equation represents the cost of transporting coal from the stockpile to inside the power plant, where $47,000 is the fixed cost and $4.76 is the variable cost per ton (all costs are from the Bethel Area Power Plan study). (b) Derived using the formula 463,000 + 5-037, + 85,000 + 7.227)» T, defined as above, T, is quantity of bulk coal T, T, demanded for space heat ing (Table 2-3). The first half of the equation is the same as described above. The second half of the equation represents the cost of bulk coal delivery, using fixed and variable costs from the Bethel Area Power Plan study. (c) Derived using the formula 463,000 + 5.03T, + 151,000 + 53.08T,, Ty) defined as above, T, is quantity of sacked coal Ty Ty demanded for space heating for both distribution center and neighboring villages (Table 2-3). (d) The first half of the equation is the same as described above. The second half of the equation represents the cost of putting coal into sacks, using fixed and variable costs from the Bethel Area Power Plan study. SR + $1.399 million SR + TU s where S number of tons demanded for city a (Table 2-3), R = ton-weighted average miles between each village and city a, T = number of tons demanded for city b (Table 2-3), U = ton-weighted average miles between each village and city b. City a = Bethel or Kotzebue; City = Dillingham or Nome Ton-weighted average miles calculated as: 43 miles - Bethel 149 miles - Nome 89 miles - Dillingham 100 miles - Kotzebue $1.399 million is estimated annual cost for one literage tug/barge combination (Dillingham Maritime estimate, Appendix B). 2-29 A20MLF#10 2.5 AN ECONOMIC COMPARISON OF ARTIC SLOPE COAL VERSUS OTHER ENERGY SOURCES 2.5.1 Description of Supply/Demand Scenarios Western Arctic Slope coal deposits are considered to be attractive to mine because of their high quality, proximity to tidewater, and suspected large size of the deposits. If these deposits prove to be sizeable, easily mined, and of consistently good quality, it may be economically feasible to export coal from Cape Beaufort to international markets such as Japan, Korea, Taiwan, Hong Kong, and Singapore as well as supplying local Alaskan demand. The economics of such an export market are discussed in Section 3.0. If international exporting is not economic, Arctic Slope mines will be limited to supplying coal to the local market, the nearby cities and villages shown in Figure 2-1. In Section 2.2.2 we have described high, medium, and low demand scenar- ios. Demand is intimately interconnected with price since more coal will be utilized if its cost is low. Demand also affects price, since the more coal that is mined, the lower the price per ton will be, due to economies of scale. This price/quantity relationship is apparent from Table 2-6. In order to provide a starting point for cost analysis and comparison, three supply/price scenarios are associated with the three demand scenarios. 1) High Demand Scenario: coal is supplied to the local market from a large-scale export-market mine. The mine is assumed to be located at Cape Beaufort and operate at the five million ton per year scale. A price of $34.26 per ton is assumed (Table 2-6). 2) Low Demand Scenario: coal is assumed to be supplied from a local- market-only mine at Cape Beaufort. From Table 2-3, we find that the low demand totals about 100,000 tons per year. This corresponds to a cost to mine of $103 per ton (Table 2-6). 2-30 A21MLF#10 3) Medium Demand Scenario: the medium demand assumes 200,000 tons per year (Table 2-3). Since this is twice as large a mine as the low demand scale mine, the cost to mine should be lower than $103 per ton. For this analysis, we have assumed that a 200,000 ton per year mine can supply coal at $90 per ton. Clearly, a sequence of development could occur where Cape Beaufort coal served only local needs initially, then expanded when conditions were right to compete internationally. In this case, the cost of coal to local areas would be relatively high at the outset when the mining operation was small, but would decline considerably due to economies of scale when mine operations expanded. For simplicity, however, this gradational case was not modeled. The port of origin cost of coal from the competing sources (Prince Rupert and Usibelli) does not vary by demand scenario, since the purchase cost would not change with quantity ordered. The small incremental demand for meeting Alaskan demand would have an insignificant effect on the cost and scale of operation of these large mines. 2.5.2 Arctic Slope Coal Versus Imported Coal Supplies The cost of coal per ton equivalent is compared in Table 2-10 for three sources of supply (Cape Beaufort, Prince Rupert, and Usibelli) and for three demand scenarios (high, medium, and low demand). Three components of cost were included in this estimate: 1) cost of coal F.0.B. Port of Origin, 2) transport cost, and 3) handling cost. The cost of constructing the coal-fired power plants at the distribution centers and purchases of coal-fired space heating systems for commercial and home use are not included in these esti- Mates. It was assumed that the cost of such capital equipment would be roughly the same regardless of the source of the coal, thus making it possible to meaningfully compare the cost of alternative sources. 2-31 2°70 Layee ‘ INARIO: CE: ‘A SERVED CAPE BEAUFQRT: ‘lectrig llage fe ‘sv. WEIGHTED AV. T”~ZEBUE: e lecgric ulk 2 Sacked Village fe SEIGHTED AV. Execgric® Sulk a Sacked b Village TON WEIGHTED AV.° THEL: a Electric Bulk Sack® b Village e N WEIGHTED AV. DILLINGHAM; Elecgric Bulk 2 Sacked b Village e “"N WEIGHTED AV. See Footnotes on next TABLE 2-10 COSTS OF COAL FOR ELECTRICITY AND SPACE HEATING - BY SOURCE AND SCENARIO (1982 $ PER TON EQUIVALENT) High Demand Medium Demand Low Demand Cape Prince Cape Prince Cape Prince Beaufort Usibelli Rupert Beaufort Usibelli Rupert Beaufort Usibelli Rupert 58.99 142.45 105,02 113.33 143.98 105.98 - - - 57.14 156.90 113.65 110,28 156.90 113.65 122.67 156.60 113.65 58.24 148,27 108.50 112.43 147.81 108.26 122.67 156.60 113.65 100.34 312.46 202.36 161.49 323.16 209.14 181.67 333.48 215.67 116.34 333,87 215.91 188,29 358.96 231.80 228.87 396.67 255.67 153.14 383.04 247.04 220.99 402.65 259.46 253.97 430.30 276.96 138.95 364.09 235.95 192.14 364.09 235.95 204.52 364.09 235.95 125.38 348.40 225.36 185.26 354.91 229.42 203.77 363.07 234.54 109.98 353.48 191.42 171,72 364.95 198.76 193.50 377.56 206.71 131.98 382.91 210.09 209.22 415.14 230.56 259.70 466.09 262.75 159.58 419.85 233.48 227.32 439.34 245.82 260.60 467.37 263.56 180.62 447.98 251.39 233.76 447.98 251.39 246.53 447.98 251.39 150.40 409.27 226.81 207.23 412.47 228.85 223.97 418.18 232.45 78.35 128.23 96.02 134.69 132.44 98.68 149.87 136.26 101.10 82.55 133.84 99.57 140,89 140,72 103.92 161.07 151.16 110.53 125.45 191.16 135.86 183,29 197.53 92.63 202.67 206.83 145.78 74.38 122.88 92.63 127,52 122.88 139.89 139.90 122.88 92.63 88.49 151.29 110.04 151.22 154.58 112.70 165.45 157.09 114,29 88.32 139.75 106.11 152.36 154.40 115.39 - - - 93.82 147,14 110.79 155.06 157.97 118/65 182.74 178.47 130.63 133.73 200.51 144,58 192.66 208.28 149.30 216.34 223.32 137.41 97.70 152.31 114,07 150.84 152.31 114,07 163.22 152.31 114,01 104.04 162.23 120.35 162.53 167.96 123.92 182.18 177.67 130.14 2-32 page. Notes: (a) (b) Column 7 of Table 2-9. Column 9 of Table 2-9. £0. ¢2P.0 47.0 #3749 (c) EE B'B s’s viv Calculated using the formula & Where PE = Cost of coal for electricity for Cape Beaufort (Table 2-10). a = Quantity of coal demanded for electricity in both distribu- tion center and villages. PB = Cost of bulk coal for bulk space heating from Cape Beaufort (Table 2-10). Q, = Quantity of bulk coal demanded for space heating (Table 2-3). B Ps = Cost of sack coal for space heating in distribution center from Cape Beaufort (Table 2-10). Q. = Quantity of sack coal demanded for space heating in distri- S bution center (Table 2-3). PY = Cost of sack coal for space heating in villages from Cape Beaufort (Table 2-10). Q = Quantity of sack coal demanded for space heating in villages (Table 2-3). Q. = Total quantity of coal demanded in both distribution center and villages. 2-33 A22MLF#10 In order to discuss the differences in cost by source by area without considering cost differences by use-category, weighted average costs were calculated by area, by weighting the cost of coal in each use by the quantity demanded by that use. These ton-weighted averages provide a single cost figure to compare with coal costs from competing sources. The cost of coal for the competing sources (Prince Rupert and Usibelli) vary only slightly due to differences in demand scenarios. The small differ- ences for each area and use are due to economies of scale in handling cost. The other two cost constitutents, transportation cost and cost of coal F.0.B. Point of Origin are sale-independent (i.-e., they do not vary as a function of quantity). For coal from Cape Beaufort, however, the mining cost varies considerably due to quantity demanded, in addition to the small handling cost differences. As a result, Cape Beaufort coal is the lowest cost supply for all use categories in the high demand scenario, due to the low cost to mine at a large scale, and the lower transportation costs to get coal from Cape Beaufort to the relatively close distribution centers. For the low and medium demand scenarios, the low transportation costs for Cape Beaufort coal is offset by the higher mining cost at small scale. The high transportation costs for moving coal over the long distances from Usi- belli (Seward) and Bullmoose (Prince Rupert) to Nome and Kotzebue more than offsets their lower price F.0O.B. Point of Origin. Therefore, Cape Beaufort coal is the cheapest source. Bethel and Dillingham are somewhat further from Cape Beaufort and rela- tively closer to Seward and Prince Rupert than are Nome and Kotzebue. Thus, the transportation cost savings are somewhat lower for Bethel and Dillingham. As a result, those two areas show Cape Beaufort coal as more costly than coal from Usibelli or Prince Rupert in the low and medium demand scenarios. The “local source edge” is overcome by cheaper coal from the larger imported source mines. Paradoxically, the local source edge is not sufficient to make Cape Beaufort coal competitive in its own “backyard” in the low and medium demand 2-34 A23MLF#10 Scenarios. Because of the presumed existence of a deep water port at the Cominco mine, transport costs from Prince Rupert are not too large. This effect combines with the low F.0.B. mine cost of Prince Rupert coal to make that coal cheaper than the very nearby Cape Beaufort mine coal. Given that Cape Beaufort coal is the cheapest source only at Kotzebue and Nome in the medium and low demand scenarios, a Cape Beaufort mine that pro- duced only for the local market probably would not be an economic prospect. This scenario would only be viable if used as the first step towards estab- lishing an international market. In this case, the price of Cape Beaufort coal could be subsidized, making this source the least cost alternative of the other three distribution centers and at other locations inside and outside the state. Larger amounts of coal would be produced to meet rising levels of demand, resulting in economies of scale that would reduce the costs associated with production and transportation. Eventually, price subsidies would be no longer needed. 2.5.3 Arctic Slope Coal Versus Existing Diesel Energy Sources The cost of using coal from Cape Beaufort would be cheaper than using oil (expressed as constant 1982 dollars per ton equivalent of coal) in most demand scenarios, as shown in Table 2-ll. The cost of oil in 1982 is somewhat less than coal in two cases primarily because the cost of transporting oil from the distribution centers to the villages was not included in oil cost estimates. Even without this added cost, coal costs are typically less than oil costs in 1982. By the year 2000, the cost of coal is expected to be far less than oil. Costs in 1982 were escalated to year 2000 costs by using the following escalation assumptions developed by Dames & Moore (1982): 1) the constant dollar price of coal will increase by two percent annually in export market mines (the high demand scenario) and by 0.5 percent in local mines (the medium and low demand scenarios) and 2) the price of oil would increase by 3.5 percent annually between 1982 and 2000. Coal costs in Table 2-11 include the F.0.B. cost at Port of Origin, transport, and handling costs, both to the distribution center and neighboring villages. The cost of purchasing coal 2-35 Al8 LAY#4 TABLE 2-11 COMPARISON OF THE COST OF OIL WITH COST OF COAL IN THE YEARS 1982 AND 2000 (In Constant 1982 Dollars) Coal oil Coal oil $ Per $ Per $ Per $ Per Area/Demand TEs T.E. of Coal, T.E. T.E. of Coal, Scenario (1982 Prices)* (1982 Prices)” (2000 Prices)© (2000 Prices) CAPE BEAUFORT (includes Cominco) High 58.24 202.61 61.43 376.86 Medium 112.43 202.61 118.55 376.86 Low 122.67 202.61 131.87 376.86 KOTZEBUE High 125.38 202.61 179.71 376.86 Medium 185.26 202.61 199,15 376.86 Low 203.77 202.61 216.80 376.86 NOME High 150.40 201.90 215.07 375.53 Medium 207.23 201.90 222.77 375.53 Low 223.97 201.90 240.77 375.53 BETHEL High 88.49 176.63 75.70 328.53 Medium 151.22 176.63 162.56 328.53 Low 165.45 176.63 177.88 328.53 DILLINGHAM High 104,04 175.76 148.78 326.91 Medium 162.53 175.76 174.72 326.91 Low 182.18 175.76 195.84 326.91 See Footnotes on next page. 2-36 Al9 LAY#4 Notes: (a) Ton-weighted averages from Table 2-10 for the Cape Beaufort source only. (b) (c) (a) Po, 20 x 106 Calculated using the formula 137,800 Where Pos = cost of oil in July, 1982 by distribution center i. The following costs were used: $1.219 $1.396 $1.391 $1.217 Dillingham Kotzebue Nome Bethel (Personal communication with Lynn Phillips, Chevron U.S.A., 1/18/83) It was assumed that the cost of oil in Cape Beaufort and Cominco is equal to the cost of oil in Kotzebue. Column 1 times one of the following escalation factors: high demand - 2.0 percent annually, or 1.43 times the 1982 price. medium demand - 0.5 percent annually, or 1.075 times the 1982 price. low demand - 0.5 percent annually, or 1.075 times the 1982 price. Column 2 times the following escalation factor: 3.5 percent annually, or 1.86 times the 1982 price. 2-37 A24MLF#10 heating systems for commercial and individual use and purchasing and maintain- ing equipment required for coal transport is not included in this estimate. Oil costs are projections of current 1982 oil prices at the distribution centers adjusted for differences in heating value, and include no estimate of the cost of transporting oil to the villages. Costs of oil versus the cost of coal in the year 2000 shown in Table 2-11, therefore, are not strictly compar- able, but represent order-of-magnitude estimates. It appears that the economics of using local coal is very dependent on the relative rates of inflation in oil and coal between 1982 and 2000. If prices of oil and coal escalate at approximately the same rate in the future, the economics of coal will remain strongly positive in the high demand case (where the Cape Beaufort mine produces for both local and international markets), weakly positive in the medium demand case, and not economic at all for the low demand case. If, as assumed, the price of oil inflates at a faster rate than coal, however, coal will be economic at all levels of demand. 2-38 A25MLF#10 2.6 SOCIAL, POLITICAL, AND ENVIRONMENTAL CONSIDERATIONS AFFECTING ALASKAN MARKETABILITY The foregoing analysis in this section has dealt exclusively with techni- cal and economic considerations affecting the marketability of Arctic Slope coal. These considerations impose necessary but not sufficient conditions on marketability. Social, political, and environmental considerations must also be taken into account before Alaskan marketability conditions can be com- pletely assessed. The following paragraphs briefly assess these important but poorly understood considerations. 2.6.1 Social Acceptability Of Coal Space Heating While the decision to use coal for electric generation will turn, for the most part, on economic grounds, the same is not true for space heating. Since residential space heating is by far the largest use under all scenarios (See Table 2-3), social acceptability is quite important. Modern design coal stoves are highly efficient, clean burning, and safe. They offer an economical alternative to the existing diesel-fired stoves currently in use. However, despite the long burning time and even self- stoking features which are available on some stoves, they require more atten- tion than stove-oil stoves. The majority of the residences in the study area use a single convective heat source rather than a central furnace with a distribution system, such as forced hot air. This simpler single-source system is more functional because most homes have an open floor plan, with smaller rooms opening onto a larger central room. In almost all cases, the heat source is a stove-oil (diesel) convective furnace. Some households have both wood stoves and stove-oil furnaces and use the wood stove during the day to save money. Area residents can easily convert to coal heating by replacing their stove-oil furnaces with simple coal stoves consisting of a cast iron or fire 2-39 A26MLF#10 brick-lined fire box, a grate, and an ash box. The flue is usually thermosta- tically controlled to permit long-burning time and adjustable heat output. Modern coal stoves are completely airtight with the draft designed to provide air for combustion of the hot coals as well as the volatile gases. An adequately sized residential stove should need stoking only twice a day. During stoking, the ashes and clinkers are removed from the ash box and a new charge of coal is added. Sufficient hot coal should remain so that there is no need to relight the stove. Coal, in 100 pound sacks, would be obtained from the central stockpile about as often as a drum of diesel.* In the villages, the sacks would be moved by snow-machine sled; in the distribu- tion centers, they could be delivered by truck. The coal sacks could be stored under or beside the house and brought in by bucket as needed. While not as convenient as diesel stoves, which need attention only every few days, the inconvenience of coal-stoves is minimal. Most people would probably accept the minimal inconvenience in exchange for significantly lower heating bills. Coal could augment wood by stoking the wood stove with one part coal to three or four parts wood. Using straight coal in stoves designed for wood could produce a dangerous leak of carbon monoxide into the house. Further- more, coal produces more intense heat and could burn out a wood firebox or corrode metal chimneys designed only for wood. To install a coal stove, the existing diesel stove chimney would be replaced by a specially designed prefabricated insulated coal-stove chimney made of special heat and corrosion resistant sheet metal surrounded by insula- tion and an outer sheet metal layer. Where the chimney passes through the ceiling, a heat shield is needed. At the roof, a flashing roof assembly is required. The chimney is capped with a “round-top” to prevent rain or down- drafts from entering the chimney. * Seven 100-pound sacks of coal have about the heat content of one 55 gallon oil drum. 2-40 A27MLF#10 Most of the modern design coal stoves are manufactured in Europe where coal is used extensively for home heating. These stoves are available for less than $1,000. For example, the West German Budarus~Juno stove which produces up to 52,000 BTU's/hour is available in Anchorage for $650, complete with thermostat. Acceptability of coal space heat in large commercial and public buildings is also an important factor, but convenience is less of an issue than avail- ability of funds to make the required furnace conversion. Commercial coal furnaces (or steam boilers in the largest buildings and complexes) would require a fairly major capital investment to convert to coal. Even if the life cycle cost of a coal system is lower than continued use of oil, the funds May not be available to make the investment. If coal use is to be encouraged, a state agency may wish to provide low interest funds for coal retrofitting. This is an area which bears further study. 2.6.2 Other Socioeconomic Considerations Apart from the obvious fuel cost savings which a coal energy system would produce, local coal production would yield numerous social benefits, including providing a cost stable energy supply, increasing local employment opportunities, and increasing the basic sector of the economy. Fuel cost stability is a matter of extreme importance in rural Alaska since a large percentage of each families' cash income must be devoted to energye There are obvious peace-of-mind benefits to removing this life-or- death control from the hands of OPEC oil ministers and placing it under local control. In an area of high chronic unemployment, it is equally obvious that job creation is another important issue. Coal mining, transporting, and handling systems would create jobs even if the export scale mine does not materialize. 2-41 A28MLF#10 The importance of creating basic sector activity is perhaps less obvious. Fuel dollars used to purchase oil are essentially lost to the local economy. By contrast, fuel dollars spent to mine and distribute coal are spent within the local economy at least partially to pay workers who live in the area. This money is respent locally and has important secondary effects. If the export scale mine does materialize, foreign capital will leak into the local economy. This effect would be even more pronounced if the Arctic Slope Regional Corporation were the owner of the mine. Then profits, as well as wages, would pass into the local economy through the dividends paid to native shareholders. 2.6.3 Environmental Issues The problems of mining coal in an environmentally and legally acceptable manner is an important issue, but one which is beyond the scope of this study. Environmental issues connected with coal use can be briefly addressed, however. Coal use has potential impacts on air and water quality and land use. These effects appear to be minor, but further study is indicated. A reconnaissance-level analysis of the air quality impacts of extensive coal use in Bethel indicated that while air quality would be degraded some- what, the air would still meet the very strict quality standards specified under State law (Dames & Moore, 1982, Section 5.0). Particulates are the major pollutants from coal burning. In Bethel, as in most of coastal Alaska, both vertical and horizontal air movements are usually rapid enough to quickly disperse pollutants. Some aesthetic concerns have been expressed by Bethel residents about coal dust blackening the snow or affecting the taste or rain- water catchment systems. Those concerns are probably unfounded but they should be the subject of further study before coal-use plans are implemented. Water quality effects from coal use derive from coal dust entering the aquatic environment (especially from coal handling facilities) and from ash disposal. Careful design and planning of coal handling facilities, and the use of sacked coal in residences and for village use, should easily mitigate 2-42 A29MLF#10 these effects. In fact, water quality in the freshwater environments might improve overall with less oil entering the environment than under the existing diesel fueled energy system. Land use is impacted by conversion to coal because coal storage requires more land than oil storage. Enough land must be set aside to provide at least one year's storage at both the distribution centers and the villages, since deliveries can only take place during the ice-free summer season. In Bethel, for example, a high demand coal use scenario would require about a four-acre stockpile. The stockpile must, at least temporarily, be located within a half mile or less of the coal unloading dock to permit rapid barge unloading. This coal could later be trucked to another site, although this will increase hand- ling costs. Land for coal storage in villages is probably not an important issue, since the quantities are not large, the coal is compactly stored on pallets, and ample land is usually available. 2-43 3.0 EXPORT MARKETS This section is a review of the tonnage, size, quality require- ments, and prices likely to prevail in the market for coal for export to Pacific Rim consumers. The importing countries considered are Japan, Korea, Taiwan, Hong Kong, and Singapore. While other Pacific countries, such as the Philippines, may import some coal, the tonnages are likely to be small, and Australia will probably be the dominant supplier. Since the North Slope area contains some coal which might be used for coke-making (metallurgical or "met" coal), both steam and met coal marketing are reviewed. Market conditions assumed are through the year 2000. The analysis presented below is based on studies performed by Dames & Moore about 1 year ago and on various published reports. Some marketing problems which are specific to the possible develop- ment of Alaskan North Slope coal are explored only briefly here and could be the subject of further examination. The following characteristics of possible Alaskan North Slope coal development are significant from a marketing viewpoint: e Production for export would start around 1987-1990; contracts would be negotiated 3 to 5 years earlier. e The mine would be in a location with no history of production, so that reliability and costs would be perceived as very uncertain. e The shipping season would be restricted to 3 months per year, requiring some special accommodation with buyers. 3.1 STEAM COAL MARKETS 3.1.1 Methodology The demand for steam coal comes from two economic sectors--electric utility and industrial. Utility uses include coal burned in existing coal-fired plants, plants with dual-firing capacity which are being converted to coal, and new coal-fired plants under construction or planned. We have estimated utility coal demand by projecting future electricity generation requirements for each country; the available mix of capacity (by fuel type); and plans for construction of new nuclear, coal-fired, and hydroelectric facilities. Industrial demand, including use in cement manufacture, is estimated based on evaluation of various published reports. A coal demand forecast must consider a number of variables--econo- mic growth, electricity growth, availability and planned use of alter- native fuels (excluding nuclear), and planned use of nuclear. With these relationships in mind, we have forecasted the demand for coal in five countries along the Pacific Rim--Japan, Hong Kong, Korea, Taiwan, and Singapore. Forecasts of the utility and the industrial demand for coal were developed using different methodologies. Because of the paucity of available data we were forced to rely solely on the Interagency Coal Task Force Report and pertinent supporting documentation for our forecast of nonutility coal demand. Utility coal demand was developed in a more rigorous manner, treating coal as a residual fuel--the fuel that would be used to meet shortfalls once alternative fuels were accounted for. We thus projected GNP growth and growth of electricity. We also projected the expected utilization of nuclear power. Coal demand was assumed to be equal to electricity production minus the portion expected to be supplied by alternative fuels (exluding nuclear), minus the portion expected to be supplied by nuclear. We have developed this forecast with three critical assumptions in mind: e There will be no large increase or decrease in the relative cost-price advantage of coal compared to oil. This differen- tial is now about $3.00 (million Btu delivered). e There will be no nuclear powerplant disaster which dramati- cally alters the political acceptability of nuclear power. e There will be no dramatic change in coal utilization costs, either upward because of much more stringent regulation, or downward because of improved technology. Because most of the increase in coal requirements will come about due to the construction of new coal-fired powerplants to meet rising electricity requirements, coal demand is less sensitive to oil prices than one might expect. Oil prices would have to drop drastically (i.e., to less than $20 per barrel) to make oil competitive for this use. 3.1.2 Summary of Demand Analysis Table 3-1 summarizes the results of the demand analysis. Figures 3-1 and 3-2 were developed from the data in Table 3-1. Data are in metric tons of coal equivalent (MTCE).* Figure 3-1 graphically depicts the total utility and nonutility demand for coal in the countries studied. As shown, in 1980, coal demand was 10.8 million MTCE; by 1985, it is forecast to be 39.3 million MTCE; in 1990, 78.6 million MTCE; and by 2000, the demand for coal is forecast to reach 235.7 million MTCE. This represents over a 21-fold increase. Figure 3-2 illustrates the projected growth in the demand for electricity by source fuel. Coal is currently used to generate less than 1 percent of electricity demand, but by the year 2000, it will supply slightly more than one-third of all the electricity produced. 3.1.3 Summary of Quality Requirements Concern over the environmental ramifications of increased coal use varies among the Pacific Rim countries. Japan, a small, densely populated country, is perhaps the most concerned and has the strictest emission requirements, as shown in Table 3-2. Korea has also established strict emission limitations, and Singapore, which currently burns no coal, has stated that environmental concerns are one of the most serious obstacles to introducing coal to the country. The combined results of these concerns in 1980 was that 95 percent of all coal demanded by electric utilities contained less than 1 percent sulfur. As other Pacific Rim countries--such as Hong Kong and Taiwan, which are not as concerned with coal emissions--begin to account for a larger share of total Pacific Rim demand, the relative importance of low-sulfur coal will decline somewhat. By 2000, 65 percent of all coal used by utilities will be low-sulfur. Table 3-3 tabulates projected demand by sulfur *Tons of coal equivalent are tons of coal containing 12,600 Btu/lb (i.e., 27.7 million Btu). Japan South Korea Taiwan Hong Kong Singapore Utility 8.2 1.6 TABLE 3-1 Forecast of Thermal Coal Demand in Pacific Rim Countries” 1980 Nonutility Total 0.5 8.7 0 1.6 NLA. 0.5 0 0 0 0 0.5 10.8 ®Excludes metallurgial coal. Utility Nonutility Total 11.5 4.6 2.4 4.1 1985 11.3 2.7 2.7 0 0 16.7 22.8 7.3 5.1 4.1 Utility 28.5 71 15.6 7.6 0 58.8 1990 Nonutility 13.5 2.7 (million metric tons of coal equivalent (MTCE) ) 2000 Utility 106.5 15.0 27.1 7.0 54.5 7.5 16.8 0 1.3 0 206.2 29.5 = == Nonutility Total 121.5 34.1 62.0 16.8 1.3 235.7 Utility Coal Demand w o e = - 2 w a < = > o w a < ° oO w ° ” 2 ° e S c e w = uw ° a 2 ° a 2 = Nonutility Coal Demand FIGURE 3-1 FORECAST OF THERMAL* COAL DEMAND BY SECTOR IN PACIFIC RIM COUNTRIES** “Excludes metallurgical coal **Japan, Korea, Taiwan, Hong Kong, Singapore SuOOW 2 S3aNwYG 150 125 100 75 25 Hydro 0 1980 1985 1990 1995 2000 YEAR ao Oo e = - 2 w a < 2 2 o w a < ° o u ° a” 2 °o - 2 « - w = wu °o a 2 o a 2 = FIGURE 3-2 FORECAST OF GROWTH OF ELECTRIC DEMAND *Japan, Korea, Hong Kong, Singapore, Taiwan ALONG THE PACIFIC RIM* BY SOURCE FUELS muOONW 3dSsSaNVva ®xorean bonus penalty system: Calorific value Total moisture content Puel ratio (fixed carbon/ volatile matter) Ash Sulfur Nitrogen Hardgrove grindability index Ash fusion temperature Ash composition Fouling index Size Volatile matter TABLE 3-2 Coal Quality Requirements Japan Korea” Utility Cement Utility Cement 6,200 kcal/kg 6,400 kcal/kg 5,000-7,000 kcal/kg 108 maximum 108 maximum 15% maximum 4-108 2.2 maximum 1.5 maximum 1.67-2.30 1.1-1.6 1.1 preferred maxinum 208% maximum 15% preferred No problem 17.8% maximum 10-208 18 maximum 20 maximum 18 maximum 1,5-38 1.68 maximum 1.5% maximum 20 maximum 45 minimum 45 minimum 45 minimum 50-60 1,300°C minimum 1,300°C minimum 1,400°C preferred 1, 250°C minimum 1,250-1,400°C Na,o Na,o Nao 0.1-28 0.04-1.58 0.5-0.88 Ca + Mg0/Fe.0, = Cad + Mg0/Fe,0, = 1 maximum 1.3 maximum minus 40 mm, minus 50 mm 1008 (2 in.) minus 20 ma, 308 (1 in. maximum) Taiwan General 5,200 kcal/kg 19% maximum 1.58 (air dried) 50 1,200°C (cement) 240 maximum Certain deviations from the preceding coal quality requirements are tolerated, but the price paid for the coal is correspondingly modified as follows: NOTE: (1) (2) (3) (4) Total moisture: The quantity corresponding to the percentage in excess of 8 percent up to 15 percent shall be deducted from the quantity certificated at loading port(s). Calorific value: Bonus: FOBT price of each year x "Y" - 6,400/6,400 x 0.05. Penalty: FOBT price of each year x 6,400 - "Y"/6,400 x 1.5. Sulfur: $U.S. 0.60 x "Y" - 0.7/0.1. Nitrogen: $U.S. 0.50 x "Y" - 1.7/0.1. "y" refers to the certified analysis in question. TABLE 3-3 Forecast of Thermal Coal Demand in Pacific Rim Countries by Sector and Sulfur Content(a,b) 1980 1985 1990 2000 (10° mrcey _(%) (10° nce) _(%) ~—(10° Mc) __(8) (10° mcg) _(8) Utility <18 sulfur 9.8 90 16.1 41 35.6 44 134.9 58 Utility >1% sulfur 0.5 5 6.5 16 25.70 32 71.6 30 Nonutility <1.5% sulfur N.A. — 2.70 a 3.60 4 7.50 3 Nonutility >1.5% sulfur 0.5 5 14.00 36 16.20 20 22.00 9 TOTAL 10.8 100 39.3 100 81.1 100 236.0 100 | Excludes metallurgical coal. Psapan, South Korea, Taiwan, Hong Kong, Singapore. content for the Pacific Rim from 1980 to the year 2000. Figure 3-3 presents this information in the form of a pie chart. 3.1.4 Summary of Import Requirements The demand for steam coal in Pacific Rim countries is expected to increase dramatically over the next 20 years. Domestic production, however, is expected to decline. Neither Singapore nor Hong Kong has any indigeneous coal resources. A number of interrelated factors will cause Korea's domestic coal production to drop from 2.1 million MTCE in 1985 to zero by 1990. Only Japan and Taiwan are expected to be able to continue production until the year 2000 at current levels of 6 million MTCE and 2.2 million, respectively. As a result, imports of steam coal to Pacific Rim countries will increase from 29 million MTCE in 1985 to 227.5 mil- lion MTCE in the year 2000. Steam coal demand, domestic production, and import requirements are shown in Table 3-4. Table 3-5 compares our estimates of required imports to other recently published estimates. 3.1.5 Summary of Import Strategies The import strategies of the Pacific Rim countries are remarkably similar. Economics, supply diversity, and supply security are the major considerations. Japan, currently the only major steam coal importer, has indicated a willingness to import from higher priced suppliers to achieve diversity and security of supply. Generally speaking, the United States is seen as a desirable source in spite of higher prices for three reasons: ~ The country is politically secure. e Coal prices and export levels are set in a competitive environment by market forces. e Production levels can be increased more quickly than in other exporting countries. By contrast, Australia is perceived to be an insecure source due to labor problems, and South Africa due to political unrest. China is perceived as a desirable source, but deficiencies in infrastructure preclude an extensive export market before 2000. In the long term, Canada may emerge as the most serious competition to the United States Utility Coal < 1% Sulfur Utility Coal > 1% Sulfur Nonutility Coal 1-1.5% Sulfur Nonutility Coal > 1.5% Sulfur FIGURE 3-3 FORECAST OF DEMAND FOR THERMAL* COAL IN PACIFIC RIM COUNTRIES ** BY SECTOR AND PREFERRED SULFUR CONTENT * Excludes metallurgical coal **Japan, Korea, Taiwan, Hong Kong, Singapore DAMES & MOORE TABLE 3-4 Import Requirements of Pacific Rim Countries (million MTCE) 1985 1990 2000 Japan Demand 22.8 42.0 121.5 Domestic production 6.0 6.0 6.0 Imports 16.8 36.0 255: Taiwan Demand 5.1 19.2 62.0 Domestic production 2.2 2.2 2.2 Imports 2.9 17.0 59.8 Hong Kong Demand 4.1 7.6 16.8 Domestic production 0 0 0 Imports 4.1 7.6 16.8 Korea Demand . 9.8 34.1 Domestic production i2ou) 0 0 Imports 2 9.8 34.1 Singapore Demand 0 0 1.3 Domestic production 0 0 Imports 0 0 i. Pacific Rim Imports 29.0 70.4 227.5 ®Forecast as of December 1981. See text for discussion. 3-11 ZT-€ TABLE 3-5 Summary of Major Projections of Steam Coal Imports Supporting Documentation IEA wocoL Zinder-Neris ICE Task Force ICF Report Dames & Moore 1977 1980 1980 1980 1981 1981 qo® MICE) (MTCE) qo® MT) aoe MICE) qo® MICE) qo® MICE) Year Imports Year Imports Year Imports Year Imports Year Imports Year Imports Japan 1976 2.5 1977 2.0 _- = 1979 0.6 1979 2.4 - - 1985 13.7 1985 6-7 1985 27.5 1985 21.8 1985 22.8 1985 16.8 1990 33.1 1990 24-33 1990 62.7 1990 42.5 1990 43.5 1990 36.0 2000 76.5 2000 53-73 2000 N.A. 2000 86-103 2000 89.0-106.7 2000 115.5 Hong Kong N.A. NLA. 1975 0 -_ aa =< i 1979 NLA. —_ = 1985 1.0 1985 3.4 1985 4.0 1985 4.1 1985 4.1 1990 2.0 1990 8.2 1990 8.0 1990 - 8.3 1990 7.6 2000 6.0 2000 N.A. 2000 16.0 2000 10.4 2000 16.8 Korea N.A. N.A. 1975 0 - oy =< —_ 1979 5.3 ae —— 1985 14.0 1985 8.7 1985 7.8 1985 8.3 1985 5.2 1990 30.0 1990 15.7 1990 14.2 1990 14.5 1990 9.8 2000 69-88 2000 NLA. 2000 44.0 2000 45.5 2000 34.1 Singapore NLA. NLA. 1975 0 _ -_ _ -_ _- _ -_ _ 1985 0 1985 1.6 NLA. NLA. N.A. NLA. 1985 0 1990 2.0 1990 3.2 - - = - 1990 0 2000 5.0 2000 NLA. - -_ _ - 2000 1.3 Taiwan NLA. NLA. 1975 0 = - — - 1979 4.8 -_ ed 1985 7 1985 3.5 1985 3.56 1985 3.2 1985 2.9 1990 12.0 1990 15.8 1990 15.80 1990 14.5 1990 17.0 2000 54-65 2000 N.A. 2000 41.0 2000 37.3 2000 59.8 Note: N.A..= not available. since its prices are expected to be slightly lower than U.S. prices, and it is perceived as a politically secure country. Hampering Canada in the short term is the inability of existing infrastructure to support sub- stantially increased exports. Since the provincial governments have intervened in coal and other energy pricing previously, consumers are likely to be concerned about whether Canadian coal will continue to be regionally priced. This concern may limit Candian market penetration. Therefore, the United States is ensured of a small-to-moderate portion of the Pacific Rim import market. And as U.S. prices become more competitive with Australian prices due to capital improvements required in Australian mines, the relative position of the United States will improve. The import strategies of Hong Kong, however, depart somewhat from those of other countries along the Pacific Rim. Hong Kong's plan is to enter a cooperative agreement with China by which China supplies Hong Kong with coal, and in return Hong Kong exports electric power to China. Australia and the United States are, however, expected to be able to capture a small share of this market also. 3.2 METALLURGICAL COAL MARKETS 3.2.1 Met Coal Demand Background and Current Situation. Metallurgical coal is used to make coke for steelmaking and, to a lesser extent, for melting iron and steel in foundry operations. Met coal is distinguished from other grades of bituminous coal by generally tighter specifications on sulfur and ash content than are allowed for coals used as fuel, and by the special characteristics of the coal which cause it to form a hard strong, coke. Roughly 1,100 pounds of coke is required for each ton of iron smelted in blast furnaces today; the Western world consumption of metallurgical coal amounts to well over 200 million tons/yr. Some of the highest quality coals are those produced in the Appalachian states. These coals are used in steelmaking in the United States and also in steel mills in Europe and Japan. In 1981, 65.2 million tons of metallurgical coal was exported from the United States. The destinations of these exports and the ports of exit are summarized in Table 3-6. The major consumers, as 3-13 TABLE 3-6 U.S. Export of Metallurgical Coal in 1981 (thousand short tons) Destination Net Tons NORTH AMERICA Canada 5,813 Mexico 373 Bahamas 32 Other io Subtotal 6,218 SOUTH AMERICA Argentina 479 Brazil 2,650 Chile 103 Other 2 Subtotal 3,234 EUROPE European Economic Community Belgium/Luxembourg 2,981 Denmark 547 France 5,062 Germany (Fed. Rep.) 2,051 Greece 53 Ireland 312 Italy 7,078 Netherlands 3,059 United Kingdom 1,697 Subtotal 22,840 Other European Countries Albania 91 Pinland 45 Gibraltar 275 Norway 269 Portugal 216 Romania 307 Spain 3,002 Sweden 1,083 Switzerland 415 Yugoslavia 1,614 Other _- Subtotal 7,317 Total (Europe) 30,157 ASIA, AFRICA Algeria 701 Egypt 591 India 99 Israel 18 Japan 21,902 Korea 1,360 Pakistan 27 South Africa a4 Taiwan 314 Turkey 569 Other -_ Subtotal 25,625 ‘TOTAL 65,234 (Excluding Canada and Mexico) 59,048 3-14 the table indicates, are the steelmaking countries of Japan, France, Germany, and Italy, and other Western European consumers. Small quanti- ties are also shipped to steelmakers in many other countries. Steelmaking is a highly capital-intensive process in which every effort is made to maximize the output of blast furnaces and other parts of the steelmaking operation. Hence, very tight control over the quality of coke (and of coking coal) is an essential aspect of efficiency in modern steel mills. The specifications for metallurgical coal tend to be extraordinarily tight, and many operators of coke ovens seek sources of coal from a wide range of locations to blend to specific quality specifications. Basis for Demand. The demand for metallurgical coal ultimately results from the demand for steel in all its final product forms. Steel demand, in turn, is sensitive to general economic conditions. Not only must the demand for steel be considered in analyzing the demand for metallurgical coal, but also there is a complex and flexible linkage between the various processes used for producing steel and the corres- ponding coal requirements. In the basic outline of the alternative steel processes shown in Figure 3-4, steel is produced in two principal ways. Most is made from molten iron plus some scrap steel in an oxygen blow converter (the basic oxygen furnace or BOF). Steel can also be made in an electric furnace in which the charge (feed metal) consists mostly of scrap metal. To the degree that scrap metal is used, no coal is required. The major process in which coal is used is the reduction of iron ore to molten metallic iron, which takes place in the blast furnace. The blast furnace consists of an enormous chimney-shaped structure into which a mixture of coke, iron, or limestone and small amounts of other materials are fed. The coke acts as a fuel to heat the charge and provides carbon monoxide, which acts as a chemical reductant, producing metallic iron. Steel- makers have been able to significantly reduce the amount of coke required to produce a ton of blast furnace output. The trend of reduction in the coke rate has leveled off in recent years. Coke is also used in the sintering furnace, in smaller quantities, for the preparation of iron ore and other iron materials prior to charging to the blast furnace and 3-15 METALLURGICAL COAL COKE OVEN COKE + IRON ORE, LIMESTONE, ETC. Lt BLAST FURNACE MOLTEN IRON ——> INGOT SCRAP IRON, ETC. ELECTRIC FURNACE FIGURE 3-4 STEEL PROCESS ROUTES 3-16 Dames & Moore in foundries. The key determinants of growth in coke requirements are the total steel output, the relationship between steel output and blast furnace production, and the coke rate. The market for U.S. metallurgical coal exports includes all the countries shown in Table 3-6. Two of these, Canada and Mexico, do not receive U.S. coal via seaborne shipments. The remaining met coal importers are grouped into four categories--Europe, Japan, other Asia and Africa, and South America. Exports of U.S. met coal to these regions will depend on steel production, the resulting coal requirements, and competition between the United States and other suppliers, such as Australia and Poland. : Steel production has been seriously affected by the worldwide eco- nomic recession, which started almost 2 years ago. Compared to 1979 levels, crude steel (the output of molten metal from all types of steel- making furnaces) production in 1981 declined by 9 percent. Met coal consumption fell by 20 million tons as a result. Our analysis of future met coal exports is based on the assumption that there is a gradual recovery from the current recession, beginning in 1983, so that crude steel production again reaches the 1979 level in 1985. The timing of this resurgence is uncertain; it might not start until 1983 or even later. Steel production will not rise evenly in all regions. The mostly likely developments are as follows: e A reduction in European exports to the United States, result- ing from negotiations currently underway. e Continuing loss of market share by Japanese steelmakers to Korea and Taiwan; Japanese production has been static for the last 2 years, while Korean production has increased. These developments are reflected in our estimates of crude steel output by region for 1981 to 1985, as shown in Table 3-7. We assume (very conservatively) that there is no increase in production above 1979 levels. 3-17 TABLE 3-7 Projected World Crude Steel Production (1981-1985)? (million short tons) 1gel 1982983 1984 = 1985, South America 18.5 18 18.5 19 20 Europe 170.6 162 170 175 180 Japan 101.7 100 105 107 110 Other Asia & Africa 24.8 24.5 26 28 30 TOTAL 315.6 304.5 319.5 329 340 @actual. Metallurgical coal for the regions examined in Table 3-7 is mined domestically in some countries (particularly the European countries and Japan) and imported from various sources. In order of volume, the United States, Australia, Canada, Poland, South Africa, and the USSR are the major sources of seaborne coal imports. The approximate tonnages of imports from these sources (excluding the USSR) are summarized in Table 3-8. Note that these data are estimates compiled from various sources, since no complete data in this form are published. TABLE 3-8 Projected Supply and Demand of Seaborne Met Coal Trade in 1981 (million short tons) Producing Country Consuming Region USA Poland ierica Canada Australia Total South America 3.2 —— — 1.5 0.7 5.4 Europe 30.2 5 2 1.3 6.3 44.8 Japan 21.9 — 3 11.2 31.6 67.7 Other Asia & Africa 3.7 —— — 2.6 5.4 11.7 TOTAL 59.0 5 5 16.6 44.0 129.6 3-18 3.2.2 Potential Demand for U.S. Met Coal Exports The continuation of the relatively large U.S. market share of the seaborne met coal trade depends on the position of the competing producers. There is not likely to be much of an increase or decrease in the domestic (internal European and Japanese) production of metallur- gical coal. This is because the existing coal production is extremely uneconomical and heavily subsidized by the governments, which are unwilling to make substantial increases in output given the high cost. It is politically unacceptable to make any drastic reduction in domestic production. Therefore, the question is how much of the imported coal will be supplied from producers in the United States. Poland is in a position to offer prices as low as necessary to sell any production they have available, since they are very badly in need of "hard currency" earnings. We assume that the political situation will gradually become less volatile and that exports will rise to one-half to two-thirds of the historic peak (1979) levels. This is a reasonable guess; and Polish met coal exports could be anywhere in the range of 5 to 15 million tons. South Africa produces little coal of met quality, and the require- ments of the domestic steel industry are rising; hence, met exports are likely to remain stable. Japan, a major customer, plans essentially no increase in imports from South Africa. In Western Canada, several major mines are under construction for production of premium quality low-volatile met coal, after several years of debate and negotiation. Pricing is favorable, and contract announce- ments indicate a good penetration of the Asian markets. Australian met coal is now marginally competitive in Europe, but contract commitments--partly rising out of investments made by European consumers, will cause an increase in exports to Europe. Japanese buyers have indicated a strong desire to diversify away from Australian coal, especially toward the new suppliers in Canada, as well as China and the USSR. U.S. met exports more or less have what is left over. Since the United States is a high-cost source of coal for Japan, exports will drop 3-19 as other coals become available. In Europe, the United States is likely to lose some of the market gained from Poland during the last 2 years. The consequences of these forces are reflected in the projected supply/ demand balance shown in Table 3-9. The net effect is a probable reduction in U.S. met coal exports from 59 million tons in 1981 to 52 million tons in 1985. Exports from 1986 to 1990 are assumed to continue at the 1985 level, as estimated. TABLE 3-9 Projected Supply and Demand of Seaborne Met Coal Trade in 1985 (million short tons) Producing Country Consuming Region USA Poland sfticn Canada Australia Total South America 3.5 -- = 1.8 0.7 6 Europe 30.0 10 2 2.0 7.0 51 Japan 15.0 -- 3 19.0 35.0 72 Other Asia & Africa 4.0 -- = 4.0 6.0 14 TOTAL 52.5 io 5 26.8 48.7 143 The major uncertainties in this estimate of U.S. exports are Poland (+ 5 million tons), the pace of increase in steel production (+ 3 mil- lion tons), Canadian exports (+ 3 million tons), and Australian exports to Europe (+ 4 million tons). The resulting range in possible 1985 U.S. exports is 46 to 62 million tons, with 52 million being the most likely quantity. 3.2.3 Coal Prices Prices for metallurgical coal are highly sensitive to coal quality. One Arctic Slope seam has been identified which is of promising quality for met uses. This is the "20-foot seam" along the Kukpowruk River. Kaiser Engineers estimated this seam to have approximately the following specifications (as received basis) : e Moisture: 2.8 percent e Ash: 3.5 percent 3-20 Fixed carbon: 58.5 percent Volatile matter: 35.2 percent Sulfur: 0.25 percent Free swelling index: 4.5 This coal would be classed as high volatile, with a low-moderate coking tendency. As the Kaiser Engineers report pointed out, it is comparable in many respects to high-volatile coking coals produced in New South Wales, Australia, and in Utah. It differs primarily in that the ash content is exceptionally low, and the sulfur content is lower than normal. These characteristics would make it valuable as a blending component in coke oven mixes, aS a means of offsetting the higher ash and sulfur contents of some competing coals (which might have other desirable characteristics). It is possible to compare this coal to other coals now sold in the Pacific market and to estimate its value, compared to the competing coals. Quality specifications of several significant competing coals are summarized in Table 3-10. The current delivered price of these coals to Japan is about $61 per metric ton (+ $3 per ton). Based on comparison with these coals, the "20-foot seam" coal would today command a price of about $65 to $70 per metric ton ($58 to $62.50 per short ton) CIF Yokohama. TABLE 3-10 Quality of Competing Australian Metallurgical Coals (As Received Basis) Australian Mines Characteristics Lemington Gregory Wambo Kukpowruk River Moisture (%) 8 10 # 2.8 Ash (%) 8.5 8.5 Z 3.5 Fixed carbon (%) 50 49 52 58.5 Volatile matter (%) 34 31 34 35.2 Sulfur (%) 0.5 0.7 0.45 0.25 Free swelling index 5 7-9 4-5 4-5 3-21 While the authors have made no detailed examination of future pricing of metallurgical coal, on balance, we believe it is unlikely that real prices will increase by more than a few percent over the next decade, due to slow growth in the world steel markets and large expan- sions of mining capacity already underway in Canada and Australia. 3.3 COMPETING PRODUCERS--STEAM COAL 3.3.1 Utah and Colorado Currently, as elsewhere in the industry, there is surplus capacity in Utah and Colorado (UT/CO). Spot prices are in the range of $20 to $25 per ton. During the summer of 1980, we surveyed many UT/CO producers to determine the price they can offer for coal from new or expanded mine capacity coming online about 1985. For mines with 11,500 to 12,000 Btu/lb coal, the prices offered were generally around $25 per ton ($1.05 to $1.10 per MMBtu). Adjusting for inflation, this price would equal $28 to $29 today. Productivity emerges as the key factor. Recent productivities of all major Utah producers average 17 tons/man-shift. The productivity for the entire coal labor force, including all classes of employees, is about 14 tons/man-shift. The offered prices (i.e., $25 per ton in mid- 1980) are consistent with a productivity for a new operation of 14 tons/ man-shift, which is the current average. There is little technical reason for new operations to hope to better this figure. This reinforces our conviction that the current price is reasonable for the long term. We believe that there are tremendous reserves which can be profitably developed at this selling price. Hence, $29 per ton is a fair estimate of the future competitive price of UT/CO coals. However, the majority of these reserves are in Colorado, with more limited reserves in Utah. Hence, $29 per ton is a fair estimate of the future competitive price of UT/CO coal. By 1990, demand for Utah coal will saturate existing and planned capacity, hence Colorado coal will be moved west as well as east, adding $4 to $7 to the cost of coal for shipment from the west coast. 3-22 3.3.2 Australia Profile of Industry. The industry consists of private firms dominated by a few large companies--Broken Hill Proprietary (BHP), CSR Ltd., British Petroleum Australia Ltd. (BP), CRA (subsidiary of Rio Tinto), Utah Development, and Royal Dutch Shell. Japanese companies are minority participants in many projects, especially the metallurgical mines (e.g., Mitsui, Mitsubishi, Sumitomo). Current law requires a minimum of 51 percent Australian ownership. Exports account for half of bituminous production. The Government has encouraged cartels to maxi- mize export prices. Such a cartel was established for the recent New South Wales (NSW) coking coal contract negotiations. The coal industry has grown rapidly, primarily for metallurgical coal export to Japan. The potential for highly profitable operations has attracted major mining and oil companies from around the world. Production is a mix of surface and underground mining. Reserves are extensive and not a limiting factor, though surface reserves are not large enough to displace underground mining in the long run. All new steam coal projects are surface mines with some expansion of existing deep mines. Reserves are mostly within 250 rail miles of the coast. As mines are opened in more remote areas (western areas of New South Wales coal fields and in Queensland generally), substantial rail and town site infrastructure are required. The political situation is reasonably stable, though the Government tends to "soak" the coal producers for revenue. Examples include a $5.06 per ton ($4.60 per short ton) export levy, requirements for private contributions to town site infrastructure, and very high rates set by the (state-owned) railroads. Regulation is fairly stringent. The labor situation is somewhat unfavorable, with militant unions organized along craft lines (a number of unions at each mine). Work stoppages are becoming more frequent (about 4 to 5 percent lost time, compared to 8 to 15 percent for UMWA mines in the United States) and particularly affect export mines. Instead of the U.S. system of a single union, as many as 30 to 40 unions are present at a mine. 3-23 Coal Quality. Australia exports both steam and metallurgical coals. Most met exports are of high volatile coals. Generally, Austra- lian met coals are higher in ash (averaging about 9.5 percent ash) than U.S. (6 to 7 percent ash) and Canadian (7 to 8 percent ash) met exports. The boundary line between the better steam coals and the met coals is unclear and a number of projects which do or will produce metallurgical coal will also sell a "middling" steam product. The range of steam coal quality (clean basis) is as follows--caloric value, 11,500 to 12,200 Btu/lb; ash, 12 to 18 percent; sulfur, 0.2 to 1.5 percent. A typical product would be 11,800 Btu/lb, 15 percent ash, and 0.6 percent sulfur. Ash fusion temperature is generally over 1500°%. A Hardgrove grind- ability of 50 is usual. Production Costs. New surface mines are large in scale (3 to 5 million ton/year) and low in stripping ratio (5:1). Capital costs for mine facilities are roughly $55 per annual ton ($50 per annual short ton); some mines will have costs for infrastructure as high as $55 per annual ton ($50 per annual short ton); and productivity is 25 tons/man- shift. Total cost including return on investment (ROI) is roughly $31 to $40 per ton ($28 per short ton). Deep mines are in thick (more than 5 feet), flat seams in medium cover (600 feet or less). Capital costs are roughly $44 per annual ton ($40 per annual short ton). Productivity is 10 tons/man shift. Total cost, including ROI, is $36 to $39 per ton ($33 to $35/short ton). Transportation to port is by rail, from 100 to 200 miles at approxi- mately $0.04 per ton-mile. Port charges are roughly $2.75 per ton ($2.50 per short ton). Total FOBT port costs would be $45.45 per ton ($41.31 per short ton)--$36 per ton, FOB mine; $5.50, rail freight; $1.15, export tax; and $2.80, port charges. Pricing Position and Strategy. Australian export coal pricing can be considered as potentially monopolistic. The Government can and has stepped in to help coordinate pricing among producers--for example, to counter the concerted action of Japanese purchasers. This is managed through Government review of export contracts and through free communi- cation (without concern about antitrust) among producers. From a cost point of view, Australian producers could offer steam coal (from new 3-24 underground mines) for about $46 per ton ($42 per short ton) FOB vessel. Recent contracts have been in the range of $52 to $54 per ton ($47 to $49 per short ton) FOB vessel. Because the other producers are not competitively priced, in the long run the United States is the price-limiting producer in the Pacific. Australian prices could reach the mid- to upper-$40 range and still be competitive. Based on contracts with producers and rumors about current negotiations, contracts are now being set at around $49.50 per ton ($45 per short ton) for steam coal. 3.3.3 Pacific Basin--Suppl emand and Prices On a cost-of-production basis, the United States is the high cost supplier to the Pacific market. Table 3-11 summarizes the approximate delivered costs (not prices) of the competing coals to the major market in Japan. The position of each exporter is as follows: e Australia can increase output fairly rapidly (initially from Queensland, later from NSW). Pricing will be set just under U.S. levels to maintain maximum market share. e South Africa cannot get full pricing for Pacific market sales compared to Europe, but would like to diversify customers. Pricing is likely to be marginally attractive for the Pacific Rim (e.g., on a par with U.S. prices). e Canada can "coordinate" pricing, and supply will be short through 1985-1987. Canada is likely to match Australian prices. e Chinese and Soviet prices will be significantly under levels from other sources because of the nature of financing of projects. Given this overall picture, the United States emerges as the last in line from a price competitiveness viewpoint. Stability/security considerations and desire for diversity of supply will allow the United States to gain a small market share, sufficient to provide a "cap" on prices other producers (particularly Australia) can charge. Therefore, prices in the 1985-1990 period are likely to be about $62 to $68 per metric ton ($55.40 to $60.70 per short ton). 3-25 97-€ TABLE 3-11 Delivered Costs of Coals From Various Exporting Countries to the Pacific Rim (Yokohama) (1985 prices, 1981 dollars) Vessel Size FOB Port Ocean Freight Total Cost Total Cost Origin (DWT) ($/metric ton) ($/metric ton) ($/metric ton) ($/10 Btu) Haypoint, Australia 120,000 51.70 9.90 61.60 2.45 Richards Bay, South Africa 150,000 33.00 18.70 51.70 2.15 Qinhuangdao, China - ? 4.40-6.60 - - Vostochunyi, USSR -_ ? 4.40-6.60 —_ ~_ Los Angeles, USA 120,000 57.20 11.03 68.20 2.60 Vancouver, Canada 150,000 41.80 9.90 51.70 1.95 3.4 SHIPPING ECONOMICS AND FOBT ALASKA PRICES Coal in the Pacific export market moves to the major consumers (in Japan, Korea, and Taiwan) in ships generally ranging in size from 40,000 to over 120,000 dwt.* The ships employed are either specialized dry bulk carriers or ships designed to carry either dry or liquid bulk cargos (combination carriers or ore-bulk-oil ('ers)--OBO's). Most of these ships are independently owned and chartered by the importer for a single voyage or for a period of months or years. These vessels commonly fly Liberian, Panamanian, or other "flags of convenience." A smaller number, mostly Japanese, are either owned or under long-term (multi- year) charter to the steel producers. Shipping rates for these vessels, except for those under long-term charters, are established in a competitive world market. The same ships carry coal, ore, grains and other bulk commodities. Therefore, shipping costs can and do vary widely with market condi- tions. Currently, the bulk carrier capacity is in tremendous excess supply, and rates have fallen to less than one-half of the most recent peak year (1980) levels. At current rates, most shipowners are recover- ing only out-of-pocket costs. In a strong market, owners earn a return on their investment. Economic theory says that at the point where the demand for shipping exceeds the current supply, rates must rise at least to a level which encourages owners to invest in new vessels. There is a great discrepancy between current rates and the levels which would support this invest- ment. Therefore, our analysis of shipping costs must consider market conditions. Shipping costs will thus be presented based both on current market rates and on rates which offer a reasonable return on capital invested in a new ship. While both sets are estimated below, it is not within the scope of this study to try to predict market conditions at the time when Arctic coal might come onto the export market. *Dead weight tons (dwt) is a measure of ship size which corresponds closely to capacity. 3-27 A second aspect of coal shipping which is reflected in the rates presented below is the considerable savings to be had in rates with larger ship sizes. In most cases, the major steam and met coal importers will be able to unload ships of up to 120,000 dwt. Therefore, in Table 3-12, rates are estimated for ship sizes from 40,000 to 120,000 dwt. The corresponding water depth for a ship of conventional design is shown in Figure 3-5. Rates are based on a round trip from Cape Beaufort to Yokohama, a distance of approximately 3,000 nautical miles. TABLE 3-12 Estimated Shipping Costs--Cape Beaufort to Yokohama ($/short ton)? Ship Size Current Rates” "ROI" Rates© 40,000 dwt 8.00 13.00 60,000 dwt 6.00 9.00 120,000 dwt 4.50 6.00 'costs are based on an approximate 3,000-nautical-mile, one-way voyage. Psanuary 1983--Source: Coal Trade Freight Report (Rodriquez Sons Co.). SLong-term charter for new buildings, foreign registry, oil fired at $225 per long ton for bunker "C" oil. 3-28 z = 6 ” = o < 2 2 o e et = o = a < Co a 1 45 DRAFT (FEET) FIGURE 3-5 MAXIMUM DEADWEIGHT TONNAGE VERSUS DRAFT CONVENTIONAL COLLIER Dames & Moore 3.5 GENERAL MARKETING CONSIDERATIONS This section examines some of the possible problems to be overcome in marketing Arctic Slope coal. The marketing of this coal will be strongly affected by who develops the coal reserves. For example, financial participation by the consumers can help to secure markets, as well as financing. The skill and experience of the organization charged with developing markets will be a major factor. Coal does not sell itself, particularly coal produced from the first mine in an unfamiliar and hostile environment. 3.5.1 Contract Arrangements Export steam and metallurgical coal is sold on spot (single ship- ments or less than l-year purchase agreements) and on contracts ranging in duration up to 20 years. Large-scale "grassroots" coal projects in Australia and Canada have been planned and financed on the basis of (supposedly) firm long-term contracts which fix tonnages and prices according to some escalation formula. There is no such thing as a "standard" coal contract. Long-term contracts can range from a brief and straightforward few pages to complex agreements of more than 100 pages. The common practice of large-scale new mines has been to seek a contract which provides a secure price and tonnage sufficient to cover the payback period of the major financing required--the so-called "bank- able contract." Thus far, Japanese buyers have been the main partici- pants under such contracts for export coal. These contracts, which are the result of lengthy negotiations, may also involve equity participation by the buyers, or debt financing arranged by the buyers. The contract negotiation process can begin as soon as detailed feasibility-level studies are completed. 3.5.2 Timing The consumers buy a substantial portion of their expected coal requirements on long-term contracts. The Japanese, in fact, have been known to contract far in excess of 100 percent of their needs. While precise contract volumes are hard to determine (or even define in many cases), the major consumers are apparently fully contracted for steam 3-30 coal through at least 1986 or 1987, depending on how fast coal imports rise. Arctic Slope coal, which would come onto the export market after 1987, could probably be worked into the consumers' contract planning. However, contracts would probably be required to justify and support financing of a major export mine. Therefore, contracts would have to be negotiated 3 to 4 years before initial production. For a 1988 startup, contracts would therefore be sought starting in 1984. Market conditions in 1984 are likely to be less favorable than those in 1986 and thereafter. This is not to suggest that initial marketing efforts should be delayed--they should not; but the more progress which can be made and the later the date at which contract commitments are finalized, the better. 3.5.3 Effects of Short Shipping Season From a purely mechanical standpoint, there is no reason why buyers could not arrange to move several million tons from the Cape Beaufort area to Pacific ports over a 90-day period. Obviously, to handle 3 mil- lion tons in 3 months requires a port facility which can load at around 3,000 tons/hr. This is well within current technical limits. If the production was sold to many consumers so that each one took no more than 10 percent of their requirements from this source, the summer deliveries could be incorporated into the normal flow without much disruption. If any consumer was forced to store a significant amount of the coal to level out requirements, there would be a significant cost penalty. Large-scale (1 million tons or more) coal storage facilities (exclusive of land costs) have a capital cost on the order of $20 to $40 per ton stored.* On an annualized basis, including carrying costs (at 10 percent), storage costs could add $3 to $5 per ton to the overall cost to the consumer of leveling out 3 months of deliveries over a full year. Land costs for congested Pacific Rim coal-using countries could add to the $3 to $5 per ton storage cost. *These costs are difficult to define because some storage is always necessary; only the cost of incremental storage capacity should be assigned as a cost of seasonal delivery. 3-31 3.5.4 Startup Problems Arctic Slope coal is likely to be perceived by consumers as an uncertain and risky source of supply, in the early years of production. This is simply because of a combination of factors--a mine in a region with no history of mining costs and no resident labor force, and the obviously hostile physical environment. These doubts could be offset through a number of factors: e Low prices e Engineering e A recognized, knowledgeable operator e Assurances of favorable regulatory and tax treatment - The lack of a railroad interposed between the mine and the buyers e A good marketing effort. 3.5.5 Coal Quality The reported quality of the Kukpowruk River coals is good in relationship to competing coals (see Sections 3.1 and 3.2) and should be acceptable in the export market. 3.6 CONCLUSIONS Regarding the international marketability of Arctic coal, this section summarizes our conclusions on the volume and price of coal which could be sold on the international market from a new mine in the Cape Beaufort region. 3.6.1 Steam Coal The overall market for steam coal in the Pacific will expand fairly rapidly over the next decade. The major consumers are seeking diverse sources of coal. The quality of the coals considered in this study is acceptable in the market, and is actually better than that of most competing coal sources. The major consumers have made contractual commitments which will satisfy their requirements until around 1986. After that time, assuming that the price and other terms are attractive, 3-32 it should be possible to secure contracts for up to 5 million tons/yr-- which could provide the basis for planning and financing a new mine. The price at which the coal can be sold will depend on the shipping market and the ability of the project developers to find a number of consumers, sO aS to ease the problem of handling the mine output during the brief 3-month shipping season. If the short shipping season does not prove to be a major economic problem, prices in the range of $49 to $54 per short ton FOB Cape Beaufort can be expected. This assumes a continu- ation of the current badly depressed market for bulk shipping. A stronger shipping market would benefit Alaska coal by $2 to $3 per ton, due to the shorter haul compared to movements from Australia or the Los Angeles/Long Beach area. On the other hand, the 3-month shipping season might impose an economic penalty of $3 to $5 per ton, for some users. Given this range of expected prices and the mining costs estimated elsewhere in the study, a mine with production in the range of 2 to 5 million tons/yr might be economically attractive. 3.6.2 Metallurgical Coal The market for metallurgical coal is not expected to expand rapidly, nor will there be a great deal of pressure on consumers to make long-term contract commitments, particularly for a relatively risky operation. Nonetheless, the total tonnage sold in the market is great, and the quality of some of the Kukpowruk River coal is promising. It would appear to be possible to identify contract markets for at least 1 million tons/yr production of metallurgical coal, at per tonnage prices $3 to $4 higher than those prevailing in the steam coal market. There are also significant advantages in diversifying the markets for the coal insofar as possible. The reader should note that the prices quoted above are the highest prices which would still be competitive. The prices actually obtained will depend greatly on the market conditions at the time contract commitments are sought and on the skill of those on both sides of the negotiating table. 3-33 BLIMLF#10 4.0 POLICY IMPLICATIONS 4,1 POLICY FINDINGS Our analysis of international coal markets indicates that quantities of Arctic Slope thermal coal up to five million tons would be potentially competitive at a price of about $49 per ton F.0.B. Cape Beaufort. Metallur- gical grade coal (up to one million tons) would also be marketable and would command an additional $3-4 per ton premium over thermal coal. The preliminary cost estimates in ASCE (1982) indicate that a mine operating at a scale of about 2 to 5 million tons per year could produce coal at the above price. However, both the cost estimates and the resource availability to sustain these levels of production are not yet firmly established. If a Western Artic Slope mine were of export scale operational (even at a one million ton per year scale), coal from such a mine would be the least expensive source of coal available to the coastal communities north of the Alaska Peninsula. By the year 2000, the fuel cost savings for switching from the existing diesel fuel-based energy system to one largely fired by coal would amount to as much as $88 million per year* (in constant 1982 dollars). Coal from a smaller scale mine, designed to serve only the demands of coastal Alaska, would be of questionable marketability. A mine producing only 100,000 tons per year would be adequate to serve 30 percent of the space heating needs of the area as well as 80 percent of the electrical demands of Kotzebue, Nome, and Bethel (our low demand scenario). However, such a mine would produce coal at about $103 per ton according to ASCE's preliminary estimates (Table 2-6). At this price, and given the marine transport and handling cost estimates developed in Section 2.4, Arctic Slope Coal would not be competitive with coal from Prince Rupert for the southern two distribution centers (Bethel and Dillingham). Since these two areas account for 63 percent of the low scenario demand, the market for Arctic Slope coal all but vanishes at this price. * Based on the energy demands in Table 2-1 and the coal versus oil cost comparison in Table 2-11. 4-1 B12 MLF #10 3-4-83 so Lowering the cost of Arctic Slope coal to $90 per ton (as assumed in our medium demand scenario), does not materially change the marketability picture. Bethel and Dillingham could still obtain coal from Prince Rupert at a much lower cost. Only if coal were available from Cape Beaufort (or other Western Arctic Slope deposits) at about $50 per ton would it be competitive with coal from Prince Rupert in crucial southern distribution centers. This again, as with the export market demand, suggests a scale of operation on the order of two million tons per year. In reaching these conclusions, one must bear in mind the preliminary nature of the estimates on which they are based. For example, the heat content of Cape Beaufort coal is assumed to be only 10,500 Btu per pound, to be consistent with the admittedly conservative figure presented in ASCE (1982). However, on the basis of the range of samples reported in Callahan and Sloan, 1978, a heat content of 12,500 BTU per pound could be easily justified. This would reduce all costs per ton equivalent of Cape Beaufort coal by 16 percent. This adjustment would bring the cost of Beaufort coal in Bethel to within $15 per ton of the Prince Rupert prices If the preliminary cost estimates were $15 per ton too high, as is easily possible, then the finding of the non-marketability of a local market scale mine would be over- turned. If the conclusion that a small local-market scale mine at Cape Beaufort is not marketable is substantiated, however, two policy options emerge for the development of Western Arctic Slope coal: 1. The mine must operate at a scale of about 2 million tons per year from the outset; or 2. If a small scale operation is necessary to establish mining experi- ence and export contract credibility, the output of such a mine must be sold at a subsidized price at least to Bethel and Dillingham userse 4-2 B13 MLF #10 3-4-83 so There is excellent political justification for subsidizing the output of the mine in its early stages. In addition to providing the communities of coastal Alaska with a cost stable energy source, the mine will bring much needed jobs and income to the area. However, if it is determined that econo- mically available coal resources are not sufficient to justify an export scale mine, then such a subsidy would be of little value, since the mine would not be cost competitive with Canadian sources (again assuming that preliminary cost and quality estimates are correct). 4,2 RECOMMENDATIONS FOR FURTHER STUDY The foregoing report is based on a level-of-effort study of marketability factors. Such a study is, perforce, constrained to using existing information sources. The following are recommendations of issues needing further research. These issues were selected because of their policy sensitivity in determining the marketability of Western Arctic Slope coal. Local and Export Market Issues 1. Establish the existence of economically mineable resources to sustain an annual production of at least 2 million tons (i-e., a total recoverable tonnage in excess of 50 to 60 million tons). 2. Sample the mineable beds to determine heat content. If this is in excess of 10,500 BTU's per pound, value per ton will increase proportionally and the minimum economic scale of mine will decrease. 3. Obtain more accurate estimates of the cost to mine Western Arctic Slope coals at alternative scales of operation. Local Market Issues 1. Determine air quality impacts of extensive coal use more precisely. B14 MLF #10 3-4-83 so Determine the cost to retrofit existing heating and generating facilities to burn coal. Verify or modify the marine coal transportation’ concepts developed in this study and adjust costs accordingly. Verify or modify the coal handling concepts developed in this study and adjust costs accordingly. Even if Western Arctic coal is not the most cost-effective source, it is important to determine what institutional and social impediments are currently operating to inhibit coal use. Programs to encourage coal use should be developed because coal use could offer significant relief from burdensome energy costs. 4-4 5.0 BIBLIOGRAPHY Alaska Field Operations Center, 1978. Alaska's Mineral Potential 1978. U. S. Bureau of Mines, Juneau, AK. Alaska Information Service, 1981. The Alaska Series: Special Reports for Management - Alaska Coal Development. Alaska Series Circulation Office, 3037 S. Circle, Anchorage, AK. 99507, February. Arctic Slope Consulting Engineers, n.d. Western Arctic Coal Resource Assessment Study for State of Alaska, Division of Legislative Finance, Anchorage. Arctic Slope Technical Services, Inc., 1982. Wainwright Central District Heating and Power Generation Project. North Slope Borough, Barrow, AK., V. 1, February. Arctic Slope Technical Services, Inc., Ralph Stefano Associates, Inc., and Veco, Inc., 1982. Kotzebue--Coal-Fired Cogeneration, District Heating and Other Energy Alternatives Feasibility Assessment. The Alaska Power Authority, Anchorage, AK., V. 1, October. Arctic Slope Technical Services, Inc., Ralph Stefano Associates, Inc., and Veco, Inc., 1982. Kotzebue--Coal-Fired Cogeneration, District Heating and Other Energy Alternatives Feasibility Assessment. The Alaska Power Authority, Anchorage, AK., V. 2, October. Barnes, Farrell, F., 1967. Coal Resources of Alaska. Geological Survey Bulletin 1242-B: Contributions to Economic Geology. U. S. Department of Interior, Geological Survey, Washington, D. C. Callahan, J. E., and Sloan, E. G., 1978. Preliminary Report on Analysis of Cretaceous Coals from Northwestern Alaska. United States Geological Survey Open File Report No. 78-319. Charles River Associates, Inc., 1979. Design for Coal Supply Analysis System. EPRI EA-1086. Electric Power Research Institute, Palo Alto, California, May. Clark, Paul R., 1973. Transportation Economics of Coal Resources of Northern Slope Coal Fields, Alaska. M.I.R.L. Report No. 31. Mineral Industry Research Laboratory, University of Alaska, Fairbanks, AK., May. Dames & Moore and Resource Associates of Alaska, Inc., 1980. Assessment of Coal Resources of Northwest Alaska-Phase 1, V. II: Task 2 - Coal Resources of Northwest Alaska. Job No. 12023-003-20. Alaska Power Authority, Anchorage, AK., December. Dames & Moore, 1981. Assessment of the Feasibility of Utilization of Coal Resources of Northwestern Alaska for Space Heating and Electricity. Phase II Report 12023-004-20. Alaska Power Authority, Anchorage, AK., December. Dames & Moore, 1982. Coal Resource Assessment for the Bethel Area Power Plan. Harza Engineering, Alaska Power Authority, Anchorage, AK. Edblom, Greg, 1981. Markets for Bulk Coal. Alaska Division of Energy and Power Development. Presented at Resource Development Council Alaska Coal Marketing Conference, Anchorage, AK., January 23, 1981. Global Marine Engineering Company, 1978. A Preliminary Feasibility Study of a Tanker Transportation System Serving the Northwest Coast of Alaska. Final Report-Appendices (Part 3 of 3). U. S. Department of Commerce, Maritime Administration, Office of Commercial Development, Washington, D.C., February. Global Marine Engineering Company, 1978. A Preliminary Feasibility Study of a Tanker Transportation System Serving the Northwest Coast of Alaska. Final Report - Part 2 of 3. U. S. Department of Commerce, Maritime Admin- istration, Office of Commercial Development, Washington, D. C., February. Harza, 1982. Bethel Area Power Plan Feasibility Assessment Report - Draft. Harza Engineering Company for Alaska Power Authority. Heiner, Lawrence E., ed., and Ernest N. Wolff, 1969. Final Report - Mineral Resources of Northern Alaska. Mineral Industry Research Laboratory, University of Alaska, College, AK. Herbert, Charles F., 1981. Characteristics of Alaskan Coal. Presented at Resource Development Council Alaska Coal Marketing Conference, Anchorage, AK., January 23, 1981. Institute of Social and Economic Research, 1980. Review of Social and Economic Conditions - Alaska's Unique Transportation System. V. XVII:2, University of Alaska, Fairbanks, AK., June. Jones, F. H., and John Gray, 1981. Coal Transport Infrastructure Require- ments. Presented at Resource Development Council Alaska Coal Marketing Conference, Anchorage, AK., January 23, 1981. Kaiser Engineers, Inc., 1977. T chnical and Economic Feasibility Surface Mining Coal Deposits North Slope of Alaska. U. S. Department of Interior, Bureau of Mines, Washington, D. C. Contract No. J0265051, August. Kazickas, Joseph, 1980. World Coal Trade: Policies, Politics and Procedures. Presented at the Energy Bureau Coal Export Conference, Washington, D. C. December 15, 1980. Kolankiewicz, Leon, J., 1982. Alaskan Coal Development: An Assessment of Potential Water Quality Impacts. Alaska Department of Environmental Conservation, Water Quality Management Section, July 27, 1982. Louis Berger & Associates, Inc., and Philleo Engineering & Architectural Services, Inc., 1981. Western and Arctic Alaska Transportation Study. Summary Report. State of Alaska, Department of Transportation and Public Facilities, Anchorage, AK. 5-2 Lowenfels, Jeff, 1981. Laws and Regulations Directly Affecting Coal Exploration and Surface Mining and Reclamation in Alaska. Office of the Attorney General, State of Alaska, Juneau, AK. Presented at Resource Development Council Alaska Coal Marketing Conference, Anchorage, AK., January 23, 1981. McFarland, Cole E., 1982. The Alaskan Coal Industry - A Status Report. Placer Amex, Inc., San Francisco, California. John J. McMullen Associates, Inc., 1980. National Petroleum Reserve - Alaska, Marine Transportation System Analysis. Executive Summary. U. S. Department of Commerce, Maritime Administration, Office of Maritime Technology, Washington, D. C., Report No. PB81-105033, October. Pacific Northwest Laboratory, Battelle Human Affairs Research Centers, and CH2M Hill, 1979. Beluga Coal Field Development: Social Effects and Management Alternatives. PNL-RAP-29/UC-11. U. S. Department of Energy, Office of Technology Impacts through Alaska Division of Commerce and Economic Development, Anchorage, AK., May. Rao, P. Dharma, ed., and Ernest N. Wolff, 1975. Focus on Alaska's Coal '75: Proceedings of the Conference held at the University of Alaska, Fairbanks, October 15-17, 1975. M.I.R.L. Report No. 37. School of Mineral Industry, University of Alaska, Fairbanks, AK. and Federal Energy Administration, Anchorage, AK. Resource Development Council, 1981. Alaska Coal Marketing Conference. Resource Development Council for Alaska, Inc., January 23, 1981. Rubin, B., I. Borg, and W. Ramsey, 1978. An Assessment of the Potential for Using Alaskan Coal in California. Lawrence Livermore Laboratory, Livermore, California, July 14, 1978. Schaff, Ross G., 1981. Alaska Coal Reserves. Presented at Resource Development Council Alaska Coal Marketing Conference, Anchorage, AK., January 23, 1981. Stefano, Ralph R., 1981. Air Quality Controls and Their Effect on Coal Use in Alaska. Stefano & Associates, Inc., Anchorage, AK. Presented at Resource Development Council Alaska Coal Marketing Conference, Anchorage, AK., January 23, 1981. Sturdevant, Dave, 1981. Environmental Constraints to Coal Development. Alaska Department of Environmental Conservation. Presented at Resource Development Council Alaska Coal Marketing Conference, Anchorage, AK., January 23, 1981. Snyder, Daniel J., 1980. Pacific Rim Coal Export Problems and Prospects from the Viewpoint of a Western Coal Producer. Westmoreland Coal Co. Presented at the Energy Bureau Coal Export Conference, Washington, D.C., December 15, 1980. Triplehorn, Julia H., 1982. Alaska Coal - A Bibliography. M.I.R.L. Report No. 51. School of Mineral Industry, Mineral Industry Research Laboratory, University of Alaska, Fairbanks, AK., January 1, 1982. Triplehorn, Don, 1981. Some Perspectives on Use of Alaska Coal. Presented at Resource Development Council Alaska Coal Marketing Conference, Anchorage, AK., January 23, 1981. United States Department of Energy, 1980. Transportation and Market Analysis of Alaska Coal. Office of the Regional Representative, Region X, Seattle, WA., November. Wilson-Smith, N. G., 1981. Far East Markets. Presented at Resource Development Council Alaska Coal Marketing Conference, Anchorage, AK., January 23, 1981. Wolff, E. N., C. Lambert, Jr., N. I. Johansen, E. M. Rhoads, and R. J. Solie, 1973. Optimum Transportation Systems to Serve the Mineral Industry North of the Yukon Basin in Alaska. M.I.R.L. Report No. 29. Mineral Industry Research Laboratory, University of Alaska, Fairbanks, AK., September. APPENDIX A BACKGROUND AND METHODOLOGY FOR COAL DEMAND PROJECTIONS The basis of our methodology is that coal balances out electric generating requirements, after other fuels are taken into account. Therefore, the sensitivity analysis indicates large swings (up or down) in coal use keyed to changes in electricity demand or nuclear generation. Particularly on the "down" side, this overstates the effect of electri- city demand on coal use, since once coal-fired generation is installed, it will be used to replace oil-fired generation if total capacity is "excessive." Since the coal-fired generation projected for 1985 is for plants already in operation or under construction, the effect of lower electricity growth is reduced--as far as 1985 use is concerned. However, growth for the 1985-1990 period and beyond begins from a lower base, and the effects will be seen over a long period. The sensitivity analysis given for "low electric growth" for 1985 (Table A-1) is a better indicator of the effective reduction in coal use in later years, say 1990. Therefore, the projected 1985 thermal coal demand of 39.3 MICE will be only slightly affected (perhaps a couple of million tons) by the current recession, but 1990 thermal coal use could be reduced from 78.6 MTCE to 58 to 63 MTCE. Our forecasts for 1990 are compared to existing forecasts in Tables A-2 and A-3. Unfortunately, we could not compare the results of our sensitivity analysis since none of the existing forecasts included sensitivity analyses. GNP growth and the growth of electricity production were estimated for a high and a low scenario by comparing historical data and existing projections. Historical information obtained used OECD and World Bank data for the years 1960-1973 and 1973-1979 and were statistically analyzed by fitting the data to both linear and exponential curves using the method of least squares. Probabilities of occurrence were assigned to each scenario using all available information. In the case of GNP growth, we subjectively considered factors such as historical perfor- mance, degree to which total primary energy is imported, balance of trade, industrial productivity, unemployment rates, inflation rates, Japan Korea Taiwan Hong Kong TOTAL TABLE A-1 Summary of Utility Coal Demand Sensitivity Analysis (million MTCE) 1985 1990 2000 To Electric To Nuclear To Electric To Nuclear To Electric To Nuclear Growth Growth Growth Growth Growth Growth Low High Low High — Low High Low = High Low High Low High 9.00 -13.50 -0.41 3.69 20.83 -31.24 -1.29 11.57 71.38 -71.38 -21.60 21.60 4.89 -3.26 -0.25 2.28 2.39 13.52 -2.23 5.21 11.11 44.44 -11.27 11.27 2.59 -6.04 -0.90 2.09 8.93 -13.40 -1.62 1.62 24.07 -56.14 -3.24 3.24 0.42 -0.42 0.00 0.00 1.15 -1.73 0.00 0.00 4.68 -7.01 0.00 0.00 16.90 -23.22 —-1.56 8.06 33.30 -32.85 -1.54 18.40 111.24 178.98 -36.11 36.11 TABLE A-2 Summary of Projections of 1990 Utility Coal Demand IEA Report WOCOL Report IEA Report ICF Coal Used Coal Used Coal Used Coal Used GNP Elect. GNP Elect. ae Ne Elect. ah Elects Growth Growth eleracs GNP Electy) joo stects Growth — Growth a Growth — Growth a 85-90 85-90 4 Growth — Growth oie (®) (%) (10° _MTCE) (8) (i) (10° _MTCE) (%) _(%) (10° _MTCE) | (8) (8) (10° MICE) | Japan 5.0 4.7 48.8 4.1-4.6 4.1-4.7 30-37 5.0 2.4 N.A. N.A. N.A. 37.4 Hong Kong NLA. NLA. NLA. 6.3 9.1 2.5 N.A. NLA. NLA. NLA. NLA. NLA. Korea N.A. N.A. N.A. 9.0 9.9 14.2 N.A. N.A. N.A. N.A. N.A. 10.8 Singapore N.A. N.A. N.A. 6.8 10.6 1.6 N.A. N.A. N.A. N.A. N.A. N.A. Taiwan N.A. N.A. N.A. 6.8 11.0 9.3 N.A. N.A. N.A. N.A. NLA. 22.0 Zinder Neris ART Dames & Moore Coal Used Coal Used Coal Used GNP Elect. GNP Elect. oe Sa Growth Growth a canes GNP Elec. per Growth Growth - Sen - 85-90 85-90 mee on Growth Growth mace on (a) i) (20° MT) co) (a) (10° _MTCE) (a) (a) (10° _MTCE) _ Japan NLA. NLA. 56.7 4.5 3.8 37.0 -- -- 28.5 Hong Kong NLA. N.A. 8.2 6.2 6.9 8.0 = _ 7.6 Korea N.A. N.A. N.A. 6.0 8.1 11.5 = = 71 Singapore NLA. NLA. - -- -- - -- -- 0 Taiwan N.A. N.A. 14.5 6.0 9.0 13.8 — — 15.6 (%) qo® MTCE) Korea Taiwan Japan Singapore Hong Kong TABLE A-3 Summary of Projections of Steam Coal Demand (Excluding Utility Demand) (1990) IEA WOCOL Zinder-Neris ICF Dames & Moore cup Tatrlal gue Tadurbelal gap oo cat Growth Growth 6 Growth 6 Growth 6 Growth 6 (8) (10 MTCE) (%) (10” MT) _(%) (10 _MTCE) (%) (10__MTCE) _ _ -_- 9.0 0.6 - N.A. Cd 0.4 _- 2.7 << = 6.75 3.4 ar == —_ 5.0 a 3.6 = 9.9 4.0-4.5 5.0-14.0 -- 18.8 = 14.5 _ 13.5 -_- - 6.77 == —— == = = == 0 -- -- 6.26 -- -- -- -- -- -- 0 relative labor rates, industrial development potential, and political stability. This analysis allowed an expected value to be computed. Our analysis indicated that the relationship between GNP growth and growth of electricity production is more complex than commonly assumed. To examine the relationship, we linearly regressed historical data on GNP and electricity production in Europe and along the Pacific Rim. Some of the countries had low correlation coefficients, indicating that electricity production does not respond directly to changes in GNP. One possible explanation for this is that electricity production may, in fact, be related to GNP, but there may be a delay in the response of one to the other. If, in some countries, electricity production and GNP are not related, there are several possible causes. Electricity could grow at an increasingly faster rate than GNP if the country was trying to replace oil heat with electric heat, or if the country was characterized by low electric saturation, such as commonly found in developing countries. Alternatively, GNP could grow increasingly faster if, in spite of an overall healthy economy, a particular electricity-intensive industry was declining. In other countries, GNP and electricity production were well correlated, but the ratio of electricity growth to GNP growth showed some variation over time. Consequently, we did not attempt to define electric growth as a fixed multiple of GNP growth. Instead, we treated electri- city growth separately, creating high and low scenarios by comparing historic trends to existing forecasts. Probabilities of occurrence were subjectively determined considering economic outlook, degree of electri- fication, plans to substitute oil-fired residential heating with electric heat, conservation programs, and the historic relationship between GNP growth and growth of electricity production. The expected value was then computed. Since these projections were developed (late 1981), the economic outlook has worsened. Economic growth expected in 1982 was not realized, and many economists believe that 1983 will be a year of rather slow recovery from the current recession. The effects of lower economic growth on the projections for each country are discussed later. Projections of nuclear-produced electricity were arrived at deter- ministically using the "World List of Nuclear Power Plants, Operable, Under Construction or On Order as of 6/30/81," as it appeared in Nuclear News. Using this information, we developed a high nuclear scenario and a low nuclear scenario. Scenario assumptions are shown in Table A-4. Review of other information resulted in occasional adjustments to the deterministically derived figures and enabled the subjective determina- tion of the probability of each scenario, as well as projections concern- ing the time from 1990 to 2000.* Factors considered included citizens' reactions to nuclear power, existing nuclear track record, existence and outcome of cost studies comparing coal to nuclear, financing ability, political climate, and reasonableness of construction plans and timing. To convert capacities to expected demand, we assumed that the plants would operate as baseload, with an average load factor of 60 percent in the low nuclear case and 70 percent in the high nuclear case. In deference to the problems experienced with nuclear capacity in Japan, we altered this assumption somewhat by assuming that in the low nuclear case plants would operate at a 55 percent load factor, while in the high nuclear case they would operate at a 60 percent load factor. To project the future demand for other electricity source fuels (i.e, oil, gas, hydro, other), we relied extensively on the supporting documentation to the ICE Task Force Report. Combining the above projections and treating coal as a residual fuel, we computed the demand for coal. To facilitate experimental vary- ing of parameters and to perform sensitivity analyses, these computa- tions were computerized. *None of the countries studied have formal plans for nuclear capacity additions beyond 1989. TABLE A-4 Expected On-Line Date for Nuclear Capacity Scenario 1980-1985 1985-1990 1990-2000 High nuclear case All plants currently All plants scheduled to Subjectively determined under construction come on-line by 12/31/90 using all available data and scheduled to come will do so on-line by 12/31/85 will do so Low nuclear case Plants currently more All plants currently Subjectively determined than 50 percent com- under construction using all available data plete and scheduled to and scheduled to come come on-line by on-line by 12/31/85 12/31/85 will do so will be on line by 12/31/90, as will plants more than 50 percent com- plete which are scheduled to come on-line by 12/31/90 PROJECT: Dames & Moore - Arctic Slope Marketability Assessment. I. Provide estimates of the cost per ton for transporting bulk coal from an assumed barge loading facility at Cape Beaufort to the cities listed in attachment 1. Because of the water depth available at the distribution centers and coastal communities tug-barge systems were used in this study as the transportation equipment. Barge: 7000 DWT ocean going Length 286' Breadth 76° Depth 18' Light draft 3.3' Loaded draft 15.0' Tug: Shallow draft tug suitable for towing and maneuvering the above named barge. Cape Beaufort has a draft limitation of 12 feet at the loading site. This lack of water depth correspondingly reduces the deadweight tonnage capability of the barge. The following table indicates the effect of draft on the transportation of coal to the distribution centers: Available Tonnage/ Annual No. Barge Loads Dist Center Draft Barge Tonnage Req'd Annually Bethel 15’ 5500 83,582 15 Dillingham 12' 5500 85,332 16 Kotzebue 6' 2500: 29,066 12 Nome 6' 2500 24,254 10 Total 222,204 “SS The average ice breakup at Cape Beaufort is in late June and average freezeup is in early November. Navigation is difficult from early November to late June and usually is suspended from mid-December to late June. Allowing a 10 day cushion in July and October the operating season at Cape Beaufort is 103 days. All deliveries to the distribution centers must be made within that period. Hiles from *No. Days No. Roundtrip Cape Beaufort Roundtrip Voyages Total Days Bethel 881 12 15 180 Dillingham 920 14 16 224 Kotzebue 148 4 12 48 Nome 316. 6 10 60 Total “SS B12 ny Total operating days required to supply distribution centers 51 Number of operating days available annually Number of tug/barge combinations required ee: *Round trip voyage assume an avg speed of seven knots and one day each for loading and offloading. B-2 Dillingham Maritime PROJECT: Dames & Moore - Arctic Slope Marketability Assessment. In order to supply the distribution centers with the projected annual tonnage, five (5) tug/barge combinations would have to be employed. Each combination would be utilized completely between the loading facility and the distribution centers during the operating season. Cost per ton for transportation of coal to distribution centers **Projected annual cost for one (1) tug/barge combination $1,546,000 No, of combinations required for transportation to the distribution centers X 5 Annual cost $7,730,000 Divide by annual tonnage of coal to be delivered 222,234 Cost per ton from Cape Beaufort to distribution centers 34.78 **Includes all operating costs and profit for the vessels. B-3 Dillingham Maritime PROJECT: Dames & Moore - Arctic Slope Marketability Assessment. II. Provide either specific estimates or a method for estimating the cost of transporting sacked coal from the nearest city to the coastal communities. ~The delivery of sacked coal from the distribution centers to coastal communities would require a second tug/barge fleet. The draft limitations at many of the coastal communities would require shallower draft vessels than those used to deliver coal to the distribution centers. It should be noted that at the time of this report offloading and dockage facilities are non-existent at many of the coastal communities. The design and cost analysis of dockage facilities and a coal transfer system is beyond the scope of this study. Therefore it is presumed that where necessary the barges would be beached and the pallets of sacked coal offloaded at that point. In order for the "cost per ton" estimates to be relevant it was necessary to break down each coastal communities tonnage requirement into barge loads (e.g. 2500 tons maximum) or barge load equivalents (e.g. percentage of a barge load). The following table is a summary of each coastal community's annual coal requirement and its corresponding barge load equivalent. Coastal — ***Barge Dist Center Community Tons Req'd Loads Bethel Steetmute 424 -17 Aniak 1,340 54 Tuluksak 875 35 Oscarville 250 -10 Napaskiak 825 33 Kasigluk 1,900 -76 Nunapi tchuk 1,250 -50 Atmaut]uak 925 -37 Tuntituliak 7,025 41 Fek 1,250 -50 misc. (add on) 4,630 1.85 Subtotal : 14,694 6.00 ***One (1) barge load = 2500 tons maximum - percentage barge loads are used to comprise one (1) voyage. B-4 Dillingham Maritime PROJECT: Dames & Moore - Arctic Slope Marketability Assessment. ; Coastal ***Barge Dist Center Community Tons Req'd Loads Dillingham Togiak 35270 1.31 i Manokotak 1,529 -61 Naknek 30,107 12.00 Ignigig 353 14 Il liamna 2,002 -94 Levelok 957 -30 Ekwok 390 16 New Stuyahok 1,380 00) Clark's Point 684 rz) Ekuk 49 -02 Subtotal 41,071 17.00 Kotzebue Shishmaref 822 ack) Noatak 718 29 Kiana 769 ool Noorvik 1,319 52 Kobuk 179 -07 Ambler 563 23 Shungnak 550 22 Deering 192 -08 Buckland 343 -14 Selawik 1,370 -55 Subtotal 6,825 3.00 Nome Wales 398 -16 Teller 568 -23 Hooper Bay 1,608 -64 St.Mary's I BUUE 44 St. Michael 665 -27 Unalakleet 2,150 -86 Shaktoolik 406 -16 Golovin 278 11 Koyuk 413 016 White Mountain 302 12 Subtotal 7,901 4.00 ***One (1) barge load = 2500 tons maximum - percentage barge loads are used to comprise one (1) voyage. B-5 Dillingham Maritime PROJECT: Dames & Moore - Arctic Slope Marketability Assessment. Coastal Barge Dist Center Comunity Tons Req'd Loads Cape Beaufort Kvalina 596 24 Pt. Lay 292 12 Wainwright 945 .38 Barrow 35,070 14.00 Pt. Hope 1,067 -43 Subtotal 37,970 16.00 Total 108,461 46.00 Following is an analysis of the number of tugs and barges necessary to provide the transportation requirements to the coastal communities: No. of Tug/Barge Dist Center Combination Req'd Bethel/Dillingham 1 Nome/Kotzebue 1 Cape Beaufort 2 Total TE The short operating season out of Cape Beaufort is the primary reason for the additional equipment requirement. For example; fourteen barge loads of coal must be transported 248 miles to Barrow in a period of approximately fifty-three days. Projected annual cost for one (1) literage tug barge combination $1,399,000 No. of tug/barge combinations required xX 4 Total annual costs $5,596,000 Divide by annual tonnage to Coastal Communities TOS, 467 Cost per ton from distribution centers to coastal communities 51.59 B-6 Dillingham Maritime PROJECT: Dames & Moore - Arctic Slope Marketability Assessment. III. Advise Dames & Moore of the feasibility of the distribution system and suggest alternatives if it is found to be infeasible. Given the operating scenario set forth and our knowledge of the current ~status of the distribution centers and coastal communities to be served the feasibility of the proposed system is questionable at best. From a marine transportation standpoint the distribution system is possible. The coal transfer systems, however, at this point in time are not feasible. There are two primary obstacles: 1) Water depth available at many of the discharging sites 2) The limited operating season due to icing conditions at all cities and communities to be served. The combination of #1 and #2 above demand that excessive tug and barge combinations be used to satisfy the annual requirements. The equipment is forced to operate in a partially loaded manner and thus make additional voyages. B-7 Dillingham Maritime DEPARTMENT OF THE INTERIOR UNITED STATES GEOLOGICAL SURVEY eae _320* ie COAL FIELDS OF THE UNITED STATES | SHEET 2 ALASKA By Farrell F. Barnes see onesie | aod \, Point Ree antion ankiaty (Coal Fields of the United States are shown on sheet 1) SCALE 1:5 000000 Approximately 1 inch to 80 miles 100 0 100 1961 200 MILES EXPLANATION Anthracite and semianthracite i { Bituminous coal High volatile except in the Bering River field (low volatile) and the eastern part of the Matanuska field (medium and low volatile) Subbituminous coal Includes some liginite in the Nenana, Susitna, and Kenai fields ) eR wR Tenacros® ey 2k AG Np txSa an Lignite Deep color represents areas known to contain coal beds of minable thickness and quality. In general the minimum thicknesses included are 14 inches,for an- ihe 2, ees tr e = Nasheed, ‘sy zl thracite and bituminous coal and 30 inches for bitumi- 2 nous coal and lignite. ° FE SIDE onse ey ey oe “Ponnive Light color represents, with one exception, areas of eoal-bearing rocks where information on the thickness and quality of the coal is meager or lacking. The ex- ception is the Little Susitna district, northwest of the town of Palmer at the west end of the Matanuska coal field, which has been mapped in detail but found to contain little or no coal of minable thickness and quality. Crosses represent isolated occurrences of coal of unknown extent. Light color and stippling denote that the coal- ‘atte WILLIAM, oY PRIBCE Wit ra SOUND pay le Ne Sieevo bearing formations are under cover ranging from a i : See ‘doco } few hundred to several thousand feet. ta) ¢ inchinbioal”| 9-0 SBS & oi 3, Montague t %, wSemistiis 4 | ‘ | R ISLANDS £ Ely N G) tasg,_fragis! Poist i j o a © Sabai Baten ig} s AGN é \ 2 1S. & A ae, batt Fag “ DIXON ENTRA 5 SHEET 2 OF 2 ORIGINAL RESERVES AND PRODUCTION OF ALASKA COAL FIELDS (In millions of short tons) ORIGINAL RESERVES : Coal field Lignite and Bituminous | Semianthracite T eeu fe subbituminous coal coal and anthracite | Total ij Northern Alaska’ 60,000 20,000 | ——--———~ 80,000 (2 Nenana® 5,000 -—--- | —--—--- 5,000 66 Jarvis Creek* 7% | ----- —----- 73 0.0 Broad Pass* 68 | —-——-—- |] ~—---—-——— 638 @) Matanuska® = | —-—————-— 201 1 202 48 Kenai® 2400 | ———-- | ~-----—- 2,400 @) Bering River'* | —-——~———— 1,100 2,100 3,200 2) Other fields’ 73,600 100M ee 3,700 (2) Total 71,136 21,401 2,101 94,638 11.9 1 Reserve figures are based on reconnaissance surveys and indicate general order of magnitude only. 2 Less than 100,000 tons. 3 Reserve figures based on detailed survey of part of each field and reconnaissance survey of remainder. Reserves based on detailed surveys include 1 billion tons in Nenana field, 13 million tons in Broad Pass field, 102 million tons in Matanuska field, and 400 million tons in Kenai field. 4 Reserve figures based on detailed survey. 5 Available data suggest that most of the coal in the Bering River field probably is too badly crushed and faulted to be economically recoverable. 6 Includes the Herendeen Bay and Chignik fields. 1 Includes the Eagle, Susitna, and Unga Island fields. BTU 16,000 14,000 12,000 | | | i 10,000 F- Anthracite — ag uf 3 3 8 rae) a = £ £ 5 a 4 ¥ E E £ A 2 = rat 8000 3 3° 3 2 = EF ‘S Y & £ & a a 2 s = E E € a <x og = op S 3 S o ec Ra 2 = 2 2 ® = o a et 2 Pol 5 o om 2 2 2 3 G Ss E 6000 S S s = z 6 = on n n =} $ ie a z z z Bo sy = = 4000 | 2000 Meta-anthracite PERCENT 100 80 60 40 20 0 Ea HEAT VALUE OF COAL OF DIFFERENT RANKS COMPARED TO PROXIMATE ANALYSES Base map by Topographic Division U.S. Geological Survey, 1947 EXPLANATION \ / : \ Tertiary S st cy bg : Rite ou ‘ort \ Cretaceous & hg rd —?# one ee cen St Lawrence ! Ss Carboniferous Crosses represent isolated occurrences of coal of unknown extent St Matthew | sf o 50 «100 200 Mies Nunivak | on 6 Na S @ & St Paulie Pribilof Is, ors VY 4 ~~) sKetchikan * WY S1 + aor? SS ao yan a Be yeu! Se ot ee Asatte f ae a i cw i | ave” Soqitat semisopechnol || Sarge ve * B Cae i : i Cae . ate ag yiosks | = ' $ & garet Qe" reese? Raa | leet | i > u vane RY t | SS Unslge! oe ¢ Some ae al a A 1 mE gavage arof \ N | ci Duisk! A p | | 2 amatignak | E ! i i GEOLOGIC AGE OF COALS OF ALASKA West of Genwi SELECTED REFERENCES NORTHERN ALASKA Collier, A. J., 1906, Geology and coal resources of the Cape Lisburne re- gion, Alaska: U.S. Geol. Survey Bull. 278, 5( p. Smith, P.S., and Mertie, J. B., Jr., 1930, Geolegy and mineral re- sources of northwestern Alaska: U.S. Geol Survey Bull. 815, p. 290-320. Toenges, A. L., and Jolley, T. R., 1947, Investigation of coal depo- sits for local use in the Arctic regions of Alaska and proposed mine development: U.S. Bur. Mines Rept Inv. 4150, p. 8-18. U.S. Geological Survey, 1957 et seq., Exploration of Naval Petroleum Reserve No. 4 and adjacent areas, northern \laska, 1944-53, pt. 3, Areal geology: U.S. Geol. Survey Prof. Paper 303. Issued in separate chapters. ” SEWARD PENINSULA Henshaw, F. F., 1909, Mining in the Fairhaven precinct: U.S. Geol. Survey Bull. 379, p. 355-369. Toenges, A. L., and Jolley, T. R., 1947, Investigation of coal deposits for local use in the Arctic regions of Alaska and proposed mine development: U.S. Bur. Mines Rept. Inv. 4150, p. 3-8. YUKON RIVER BASIN Collier, A. J., 1903, Coal resources of the Yukon, Alaska: U.S. Geol. Survey Bull. 218, p. 71 Mertie, J. B., Jr., and Harrington, G. L., 1924, The Ruby-Kuskokwim region, Alaska: U.S. Geol. Survey Bull. 754, p. 119-120. Smith, P. S., 1914, Mineral resources of the Lake Clark-Iditarod region: U.S. Geol. Survey Bull. 622, p. 268-270. NENANA COAL FIELD Martin, G. C., 1919, The Nenana coal field, Alaska: U.S. Geol. Survey Bull. 664, 54 p. Wahrhaftig, Clyde, 1951, Geology and coal deposits of the western part of the Nenana coal field, Alaska: U. 8. Geol. Survey Bull. 963-KE, p. 169-186. Wahrhaftig, Clyde, Hickcox, C. A., and Freedman, Jacob, 1951, Coal deposits on Healy and Lignite Creeks, Nenana coal field, Alaska: U.S. Geol. Survey Bull. 963-E, p. 141-168. JARVIS CREEK COAL FIELD Wahrhaftig, Clyde, and Hickcox, C. A., 1955, Geology and coal de- posits, Jarvis Creek coal field, Alaska: U.S. Geol. Survey Bull. 989-G, p. 353-367. ; BROAD PASS COAL FIELD Hopkins, D. M,, 1951, Lignite deposits near Broad Pass station, Alaska: U.S. Geol. Survey Bull. 963-E, p. 187-191. Rutledge, F. A., 1948, Investigation of the W. E. Dunkle coal mine, Costello Creek, Chulitna district, Alaska: U.S. Bur. Mines Rept. Inv. 4360, 9 p. Wahrhaftig, Clyde, 1944, Coal deposits of the Costello Creek basin, Alaska: U.S. Geol. Survey mimeographed rept.,7 p. SUSITNA COAL FIELD Capps, S. R., 1918, The Yentna district, Alaska: U. S. Geol. Survey Bull. 534, p. 28-36, 72. 1935, The southern Alaska Range: U. S. Geol. Survey Bull. 862, p. 60-65, 95-96. Maloney, R..P., 1958, Reconnaissance of the Beluga River coal field, Alaska: U.S. Bur. Mines Rept. Inv. 5430, 18 p. MATANUSKA COAL FIELD Barnes, F. F., and. Payne, T. G., 1956, The Wishbone Hill district, Matanuska coal field, Alaska: U.S. Geol. Survey Bull. 1016, 88 p. Barnes, F. F., and Sokol, Daniel, 1959, Geology and coal resources of the Little Susitna district, Matanuska coal field, Alaska: U. 5. Geol. Survey Bull, 1058-D, p. 121-138, Capps, S. R., 1927, Geology of the upper Matanuska Valley, Alaska: U.S. Geol. Survey Bull. 791, 92 p. Martin, G. C., 1912, Geology and coal fields of the lower Matanuska Valley, Alaska: U.S. Geol. Survey Bull. 500, 98 p. Waring, G. A., 1936, Geology of the Anthracite Ridge coal district, Alaska: U.S. Geol. Survey Bull. 861, 57 p. KENAI COAL FIELD Barnes, F. F., and Cobb, E. H., 1959, Geology and coal resources of the Homer district, Kenai coal field, Alaska: U.S. Geol. Survey Bull. 1058-F, 44 p. ALASKA PENINSULA Atwood, W. W., 1911, Geology and mineral resources of parts of the Alaska Peninsula: U.S. Geol. Survey Bull. 467, p. 41-59, 96-120. Knappen, R. S., 1929, Geology and mineral resources of the Aniakchak district, Alaska: U.S. Geol. Survey Bull. 797-F, p. 189-198, 212-221. BERING RIVER COAL FIELD Barnes, F. F., 1951, A review of the geology and coal resources of the Bering River coal field, Alaska: U.S. Geol. Survey Cire. 146, 11 p. Martin, G. C., 1908, Geology and mineral resources of the Controller Bay region, Alaska: U.S. Geol. Survey Bull. 335, p. 9-112. SOUTHEASTERN ALASKA Buddington, A. F., and Chapin, Theodore, 1929, Geology and mineral resources of southeastern Alaska: U.S. Geol. Survey Bull. 800, p. 262-263, 353-354. PERCENT 100 98 92 Dry, m-m-free 86 Moist, m-m-free Btu = 73 M. A. 69 DRY, MINERAL-MATTER-FREE FIXED CARBON 3 40% fixed carbon = ———————_-—_ eae 100M EOS F.C. Btu 100—(1.1 A. +018.) Where F.C. =Fixed carbon percentage Moisture percentage Ash percentage S. = Sulfur percentage Btu = British thermal units, all taken from the proximate analysis (as-received basis) 16,000 14,000 13,000 11,000 9500 8300 MOIST, MINERAL-MATTER-FREE BTU x 100 7000 100 6000 BTU BASIS OF RANK CLASSIFICATION OF COALS IN THE UNITED STATES, AND THE FORMULAE USED IN MAKING APPROXIMATE RANK DETERMINATIONS Determinations based on the above cannot be considered final or even adequate for any but the most general application. For further information, see the Standard Specifications for Classifi- cation of Coals by Rank of the American Society for Testing Materials, A.S.T.M. designation This map was reproduced by electronic color scanning of an earlier printin, D388-38 INTERIOR—GEOLOGICAL SUAVEY, RESTON, VA—1961, REPHINTED, 1978, 1979, 1982—G82203 1g (1961). For sale by Alaska Distribution Section, U.S. Gealogical Survey, 310 First Avenue, Fairbanks, AK 99701, and Branch of Distribution, U.S. Geological Survey, Box 25286, Federal Center, Denver, CO 80225, and Branch of Distribution, U.S. Geological Survey, 1200 South Eads Street, Arlington, VA 22202.