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Geothermal Potential in the Aleutians UNALASKA 1981
PROPERTY OF: Alaska Power Authority 334 W. 5th Ave. Anchorage, Alaska 99501 GEOTHERMAL POTENTIAL IN THE ALEUTIANS: UNALASKA Submitted to the Alaska Division of Energy and Power Development by Morrison-Knudsen Company, Inc. 1981 TABLE OF CONTENTS 1. INTRODUCTION 2. SITE DESCRIPTION 2.1 Location 2.2 Climate 2.3 Demographics 2.4 Economy 2.4.1 Fisheries 2.4.2 Transportation 2.4.3 Community 2.4.4 Employment 2.4.5 Economic Projections ‘2.5 Land Use and Institutional Considerations 2.6 Current Energy Use 2.7 Energy Demand Projections 2.8 Energy Alternatives 3. GEOTHERMAL RESOURCES EVALUATION 3.1 Summer Bay 3.1.1 Geology 3.1.2 Reservoir Analysis 3,2 Makushin Volcano Region 3.2.1 Geology 3.2.2 Reservoir Analysis 4. GEOTHERMAL DEVELOPMENT POTENTIAL 4.1 Summer Bay Resource 4.1.1 Aquaculture 2-10 2-10 3-1 3-1 3-1 3-3 3-7 3-12 4-1 4-1 5. 6. 7. 4.1.2 Table of Contents (continued) Greenhous ing 4.2 Makushin Volcano Resource 4.2.1 4.2.2 4.2.3 Power Plant Development Development Schedule Logistics and Hazards ECONOMIC ANALYSIS 5.1 Overview 5.2 Summer 5.2.1 6.262 5.2.3 5.2.4 5.3 Public 5.3.1 5.3.2 CONCLUSIONS REFERENCES Bay Development Assumptions for Analysis of Greenhouses Results of Analysis Assumptions for Analysis of Salmon Fisheries Results of Analysis Sector Investment Assumptions for Power Plant Analysis Results of Analysis Page No. 4-4 4-4 4-4 4-6 4-10 5-1 5-1 5-1 5-1 5-4 5-11 5-14 5-18 5-18 5-26 6-1 7-1 LIST OF FIGURES Page No. 1. Cross-section of Aleutian Subduction Zone 1-2 2. Typical Temperatures for Geothermal Resource Utilization 1-4 3. Unalaska Location Map 2-2 4. Northern Unalaska Island 2-3 5. Average Monthly Temperatures - Unalaska 2-4 6. Total Employment, 1980 - 2000 2-8 7. Electric Power Capacity Requirements Projections 2-11 8. Map of Summer Bay Warm Spring & Regional Faulting 3-2 9.a. Simplified Cross-section of the Summer Bay Resource 3-5 b. Simplified Cross-section of the Makushin Volcano Resource 3-5 10. Trace of the Unconformity Beneath the Makushin Volcanics 3-8 11. Makushin Volcano Fumarole Fields 3-9 12. Typical Schedule for Geothermal Power Development 4-7 13. Projected Power Demand & Development Schedule 4-8 LIST OF TABLES Page No. 1. Chemistry of Summer Bay Samples 3-4 2. Summer Bay Exploratory Drilling Well Data 3-6 3. Chemistry of Makushin Volcano Samples 3-11 4. Design Data, Summer Bay Aquaculture Facility 4-3 5. Preliminary Design, Summer Bay Greenhouse 4-5 6. Power Development Schedule 4-9 7. Diesel versus Geothermal Greenhouse - Schedule of Investment 5-3 8. Diesel versus Geothermal Greenhouse - Operating Costs and Net Cash Cost 5-5 List of Tables (continued) Page No. 9. Diesel versus Geothermal Greenhouse - Cash Flow and Incremental Net Present Value - 5-8 10. Summer Bay Salmon Hatchery, Shallow and Deeper Systems - Investment 5-12 11. Summer Bay Salmon Hatchery, Shallow and Deeper Systems - Rate of Return 5-15 12. Investment - 10 MW and 20 MW Power Plant 5-20 13. Fuel to Geothermal Net Present Value Comparison - 10 MW and 20 MW Power Plant 5-22 14. Capital Investment - Geothermal Power Plants 5-24 15. Investment - 30 MW Power Plant 5-27 16. Fuel to Geothermal Net Present Value Comparison - 30 MW Power Plant 5-31 GEOTHERMAL POTENTIAL IN THE ALEUTIANS: UNALASKA 1. INTRODUCTION The Aleutian Island arc, which extends 1800 km from the Alaska Peninsula to the Russian Kamchatka Peninsula, is perhaps the remotest area in the United States. General concerns about rising energy costs and uncertain fuel supplies are magnified on these islands, where difficult transportation and logistics contribute to an expensive and vulnerable energy picture. The situation is complicated by’ boom-town growth in several communities as a result of expanding seafood industries and oil and gas exploration. Villages are faced with outdated energy production and transmission facilities, energy demands which strain system capacities, and few, if any, alternative energy resources. In many locations, improvements in living and economic conditions are severely constrained by insufficient energy supplies. Geothermal energy is one of the most promising energy alternatives available on the Aleutians. The islands are part of the Pacific "ring of fire," a region of high volcanic and seismic activity resulting from the subduction of oceanic plates under continental plates (Figure 1). In these areas, the natural heat flow is high, and there is the potential for economic recovery of this geothermal heat. There are three primary types of geothermal resources: hydrothermal, hot dry rock, and geopressured. Nearly all of the currently developed geothermal resources are hydrothermal systems, in which ground water is heated at depth. These systems can be either vapor-dominated (steam) or hot water-dominated, depending on temperature and pressure conditions. The essential ingredients for a hydrothermal system are a heat source near the earth's surface, a sufficient supply of ground water, and a transport medium (porous rock or natural fractures) to bring the heated ground water to relatively shallow depths where it can be developed as an energy resource. Nearly all of the currently developed geothermal resources in the world are hydrothermal resources, and the technology is available to economically develop and utilize these resources. The worldwide hydrothermal electric power capacity in 1979 was 1,500 MWe, with a direct-use total of approximately 7,000 MWt. The two other types of geotheriial resources are hot dry rock, which utilizes injected water as a heat transfer medium, and geopressured zones, in which hot water is trapped with natural gas under thousands of meters of sediments. Economic development of these two types of resources is currently in the research stage. ALEUTIAN VOLCANOES BERING SEA PACIFIC OCEAN P =. HAMBER) NTINENTA PLATE) FIGURE | CROSS-SECTION OF ALEUTIAN SUBDUCTION ZONE MORRISON KNUDSEN Geothermal resources have been developed for applications ranging from space heating to electric power production. The optimum use of a geotherinal resource depends not only on its temperature, chemistry, and supply, but also on the nature of the energy demand in its vicinity. Conventional methods of economic geothermal power production require resource temperatures of at least 180 degrees C, although research is being conducted at temperatures as low as 140 degrees C. Lower temperature resources can be utilized directly in such applications as aquaculture, balneological baths, food processing and hybrid energy systems (Figure 2). Two areas with significant geothermal potential have been identified on Unalaska: Summer Bay and Makushin Volcano. This report presents a summary of the resource potential at each location, as well as a market and economic assessment of potential applications of these energy resources. 1-3 CONVENTIONAL POWER PRODUCTION 350° and UP ALUMINA PROCESSING DRYING FARM PRODUCTS EXTRACTION OF SALTS |! REFRIGERATION (mod.temp.) ;29° CONCRETE BLOCK CURING CRAB PROCESSING DRYING FISH | SPACE HEATING | REFRIGERATION (low temp. GREENHOUSES | BALNEOLOGICAL BATHS SOIL WARMING | FERMENTATION, DE-ICING FISH FARMING RESOURCE UTILIZATION FIGURE 2 TYPICAL TEMPERATURE FOR GEOTHERMAL @ wee’ 2.1 2.2 2.3 2. SITE DESCRIPTION Location Unalaska Island is one of the Fox Islands, a group in the Eastern Aleutian chain 1,300 kilometers by air southwest of Anchorage (Figure 3). The Island itself has an area of 310,000 hectares, most of which is uninhabited. The town of Unalaska on the northeast coast of the island consists of the traditional Aleut Village of Unalaska and settlements on Amaknak Island (Figure 4). Unalaska is one of the few deep water ports in the Aleutians and is the only port where a container ship can dock between Kodiak and Japan. It serves as a major transportation link to the Western Alaskan mainland and off-shore areas, the North Slope, and the western Aleutian Islands. Climate Unalaska's climate can be considered moderate and is tempered by its marine environment. Weather fronts in the Aleutians generally move from west to east; consequently, the northeast shores offer the most protected locations. Average temperatures in Unalaska range from 5 to 15 degrees C in the summer and -5 to +5 degrees C in the winter (Figure 5). The lowest recorded temperature in 27 years of record is -15 degrees C. Total annual heating degree days average 8,900 (70 degrees F base). ‘There is some precipitation on the Aleutian Islands during more than 200 days of each year. On Unalaska, the total annual precipitation averages 150 cm, with a total snowfall of 200 cm. Accumulations of snow are generally less than a meter. The mean hourly wind speed at the airport at Dutch Harbor is 7 m/s from the south-southeast. Winds estimated as high as 70 m/s have occurred, i the Aleutian's nickname of "Birthplace of the Winds" (Morgan, 1980). Demographics Unalaska has recently experienced a major population growth to become the largest non-military settlement in the Aleutians. The 1939 census recorded less than 300 residents, who were evacuated during World War II and relocated in Sitka. During the War, 65,000 troops were located on the Island, which became the major military center in the Aleutians. The base was abandoned in 1947, leaving an estimated 1100 major structures and quonset huts, and numerous other miscellaneous structures such as gun emplacements, storage sheds, pill boxes and ammunition bunkers (BLM, 1981). Delays in decisions regarding facility transfer to the private sector, lack of maintenance, and weather served to destroy many of the magnificent military installations. 2-1 FUMAROLES MAKUSHIN My Mtoe SUMMER 4 MAKUSHIN go VOLCANO OHOT x Xx SPRING UNALASKA UNALASKA ISLAND FIGURE 3 UNALASKA LOCATION MAP SS js hy 6 . 3 Gi s Be eS = d i rhe \ Sd ¢ 4) Sy a » Sse 38 (= A CO T ey ca NS SAMI NSA 4 oS = jakushi ES oe tn CO _Bgriet OE f ~ Cathdrah QS PE a Z C9 Portage) op FIGURE 4. NORTHERN UNALASKA_ ISLAND @ xs DEGREES C 13 12 10 0 T T T T T T ™ T T T JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC FIGURE -5 AVERAGE MONTHLY TEMPERATURES-UNALASKA @ wes 2.4 By 1950, the population of Unalaska was only 173, as evacuated residents returned to the Island in reduced numbers. Moderate growth increased the population to 342 by 1970. The expansion of the seafood industry during the last decade has resulted in a major increase in the population. The 1980 census indicates a permanent resident population of 1322, which swells to an estimated 5000 during the peak fishing season. While the population increased 290% between 1970 and 1980, the number of conventional housing units in Unalaska only increased 190%, to a total of 323 units. The critical housing shortage is considered one of the most serious problems facing the community. Coincident with Unalaska's population growth, there has been a significant change in its racial make-up. In 1970, 64% of the residents were Aleut; by 1980 the Aleut population comprised only 15% of the total. Several projections of population growth are available for Unalaska. Agreement between the projections is limited to assumptions of continued growth and a conversion of transients to permanent residents as the local industry becomes more established. Unalaska's Recommended Community Development Plans (1977) project 5000 permanent residents by the year - An electrification study conducted for the community (Retherford, 1979) indicated an estimated population of over 7000 by 2000. Socioeconomic assessments for the Bureau of Land Management's Outer Continental Shelf oi] and gas leasing program project a population in the year 2000 of over 13,000 under base case conditions and over 14,000 with moderate oi] and gas development (BLM, 1981). An estimated 75% of the OCS projected growth is tied to development of a domestic bottomfish industry in the Aleutians.) Economy 2.4.1 Fisheries The economy of Unalaska is based on its harbor, which is considered the best in the Aleutians with respect to depth, weather protection and location. The present economic climate was established in the 1960's with the development of seafood processing facilities in the harbor. By 1980, 15 processing plants were located there. The fisheries are dominated by king and tanner crab with relatively minor catches of salmon, halibut, Dungeness crab, shrimp and bottomfish (BLM, 1981). In 1975, Unalaska was not on the National Marine Fisheries Service list of top U.S. ports, but by 1978, Unalaska was the number one port in the U.S., based on the value of its landed catch. During the 1979-1980 season, more than 60 million kilograms of king crab were taken from the Bering Sea region. Over 80% of the boats landed their catch with Unalaska processors. Although king crab still accounts for the majority of the catch value, tanner crab is becoming more important. The king crab industry is presently overgeared; consequently, it is less profitable for individual boats. 2-5 2.4.2 2.4.3 2.4.4 In addition to expansion of the tanner and spider crab fisheries, there is increasing interest in the development of the Bering Sea bottomfish resources (including Pacific pollack, ocean perch, sable fish, flounder, sole and pogy fish). Kodiak and Unalaska are considered the most probable locations for shore-based bottomfish operations, which provide the greatest potential for population and economic growth in the near future (BLM, 1981). Transportation The only other significant economy in Unalaska is based on its function as a trans-shipment point. The port is located on shipping routes between the west coast of the U.S. and the western Alaska mainland and North Slope region. It is the only port in the Aleutians where container ships can dock and both the American President Line and Sea-Land Service have built docks in the harbor. The city of Unalaska now owns and operates the sea-land- dock. Chevron has a 50,000 m3 tank farm on Amaknak Island which serves as a regional fuel storage depot. Air service is provided by Reeve Aleutian Airways and small air. taxi operations. Service is restricted because the existing runway (circa WWII) is too short to accommodate jets and larger cargo planes. Community Unalaska is a first class city with a city council/mayor government. The city's objectives are to provide community services and an infrastructure for future development. Provision of basic services (power, water, sewer, etc.) dominates the community plans. The major economic growth which has occurred in Unalaska during the past fifteen years is also reflected in the city's operations. Six years ago, the total city budget was $500,000. The present operating budget alone is $3.5 million (Richard Careaga, 1981). Proposed developments being considered for Unalaska include extension of the existing runway, building up the electric system (including installation of larger generators), and construction of a primary sewer treatment facility. Emp] oyment The 1980 employment in Unalaska, converted to an average annual full-time basis, was 1600 jobs. Over 80% of these jobs were directly related to fishing. and seafood processing. Analyses of employment sectors presented in the BLM's St. George Basin Petroleum Development Scenarios Local Socioeconomic Systems Analysis (1981) Teavcate an extreme ratio of 1.0 to 0.1 between the basic. sector (fishery) and secondary employment sectors. No unemployment figures are available for Unalaska; however, regional rates are normally low and unemployment during the peak of the fishing season is virtually zero. 2-6 2.4.5 Economic Projections Continued growth of Unalaska's economy is assured, based on growth of the bottomfish industry, expansion of its trans-shipment role and off-shore exploration for oil and gas. The greatest growth potential is considered to be development of a domestic bottomfish industry, which is projected to account for 75% of the population growth by the year 2000 (BLM, 1981). Outer continental shelf oi] and gas lease sales are scheduled in the region in the next 5 years and both exploration and development will affect Unalaska's economy. There could eventually be a standoff between oi] and gas development and bottomfishing in the Bering Sea in terms of facilities and resources available for development. Total employment is projected to increase to over 9000 by the year 2000 with moderate oi] and gas development in the region (BLM, 1981). This represents an increase of 90%, or the equivalent of 1500 jobs in the traditional economy, nearly 1600 jobs in the bottomfish industry and 320 jobs permanently added to the employment base as a result of oil and gas development (Figure 6). 2.5 Land Use and Institutional Considerations Land status in Alaska has changed significantly in the last decade with the passage of the Alaska Native Claims Settlement Act (1971) and the Alaska Lands Bill (1980). Native claims to Alaska lands date back to the purchase from Russia, at which time the U.S. agreed to "honor all native claims”. ‘Under ANCSA, a total of 18 million hectares and approximately $960 million were conveyed to natives through approximately 230 village corporations and 13 regional corporations. These corporations function basically as investment companies, with land, money and stock as corporation assets (Wayne Lewis, 1981). The amount of land each village corporation received was a function of the number of shareholders. The Ounalashka Corporation, the village corporation on Unalaska, was entitled to select a total of 46,600 hectares, including Summer Bay and the Makushin Valley. Although the village corporation's stock cannot be sold for 25 years, the land conveyed to the corporation is surface real estate that can be sold with no restrictions. The Ounalashka Corporation has established a policy of leasing rather than selling their land. They receive an estimated $50,000 a month from leases and became the first village corporation in Alaska to pay a dividend to its stockholders. The Aleut (regional) Corporation, in general, owns the subsurface rights under land held by village corporations within the region. According to Alaska state law, geothermal resources are defined as "the natural heat of the earth at temperatures greater than 120 degrees C, measured at the point where the highest temperature resources encounter, enter or contact a well or other resource extraction device..."(Reeder, et. al., 1980). Under this definition, rights to geothermal resources with temperatures above 120 degrees C are controlled by the regional corporation (in this instance, the Aleut Corporation). The Aleut Corporation has not yet established a policy for geothermal leasing or development. 2-7 10,000 - 9,000 - Yan RE Vlas ees ees eat eg He ee ea So sites aes emi tae ame a: OS oi Sit ee LN3WAOTdW3 WWLOL FIGURE 6 TOTAL EMPLOYMENT, 1980-2000 BASE CASE AND MEAN OCS SCENARIO @ was 2.6 Rights to the use of resources below 120 degrees C are transferred by means of a water right under the Alaska Water Use Act. To minimize potential conflicts between geothermal resource rights and water rights, Alaska law exempts geothermal fluids (greater than 120 degrees C) from regulation under the Water Use Act. However, to protect water rights, geothermal drilling cannot begin until: (1) it is determined that the well will not interfere with or substantially impair prior water rights, (2) water rights have been acquired to offset any potential interference, or (3) an equivalent amount of replacement water of comparable quality has been supplied to the affected water right holder (Reeder, et. al., 1980). Current Energy Use There is no central system which supplies the total energy needs of the city of Unalaska. The city utility has two 600 kw and two 300 kw diesel generators which provide electricity to residential and small commercial users on the main island of Unalaska. The transmission lines for the utility are presently in need of repair or replacement. The system maintains firm power at 1200 kw, with an estimated average demand of 300 kw and a current peak demand of 450 kw. Individual generators supply power for the process ships and the facilities on Amaknak Island. In 1979, the processors had a combined total installed capacity of 12,250 kw, with a non-coincidental peak load of 7460 kw. Approximately 40% of the processor's electricity is used in refrigeration. Chevron and the Ounalashka Corporation have an additional 400 kw installed capacity (BLM, 1981). The total estimated residential space heating load in Unalaska (including transient housing units) is 13 million BTU/hr, with an estimated peak demand of 34 million Btu/hr. A few processors recover waste heat from generator exhaust and cooling systems for space heating needs and the Unisea Inn is totally heated by waste heat from Universal Seafoods' process boats (R. White, 1981). Only a rough estimate of the total diesel fuel use on the island can be determined. Total fuel used by the processors for their generators, boilers, and space heating needs is the equivalent of approximately 1 liter of fuel for each 5 kilograms of seafood processed. This yields an estimate of 11,000,000 liters per year for processors’ energy requirements. An estimated additional 4.9 million liters are used annually for residential space heating, small commercial needs, and the city utility, for a total of nearly 17 million liters per year. At 1981 diesel prices, this is the equivalent of over $5 million annually. Utility rates for electricity in Unalaska are 170 mills per kwh for the first 500 kwh and 150 mills per kwh thereafter. This year, however, the city passed a balanced budget in the electric fund, which could mean raising the price to 460 mills per kwh (Richard Careaga, 1981). Summer 1980 power bills for the average consumer were $114 to $150 per month; at the new rates the bills would be $310 to $400 per month. 2-9 2.7 2.8 Energy Demand Projections Power demand projections for Unalaska are as varied as population projections. The electrification study conducted by R.W. Retherford Associates (1979) for Unalaska projected a peak demand of 21 MW in 1995 and a total demand of 105,000 MWH for residential, small commercial, and large industrial users. These projections were based on an energy growth rate of 10% per year through 1985 and 7% per year thereafter. The outer continental shelf oi] and gas leasing report (1981) projects total capacity requirements of 50 MW in the year 2000 under base case development, and 56 MW with moderate oil and gas development. These projections are summarized in Figure 7. Energy Alternatives Unalaska is faced with major changes in its energy system. The primary reasons for this are: 1. The existing utility generating and transmission facilities are in need of repair and improvement. 2. The utility's electrical capacity is not sufficient either to supply the present needs of large industrial users or to meet projected future residential, commercial, or industrial requirements. 3. The community is totally dependent on fossil fuels; consequently, energy costs are extremely high. ‘Several alternatives for meeting Unalaska's future energy needs have been and are presently being considered. The Retherford electrification study recommended a central generation system supplying power to processors, as well as supplying residential demands. Their study indicated that a combination of diesel generators, gas turbines, and hydroelectric facilities would be the most economical system. Retherford's projected busbar costs for this system are 130 mills per kwh in 1985 and 150 mills per kwh in 1995. These costs were based on diesel price projections which are lower than current diesel prices. Four hydroelectric sites were identified for inclusion in the combined energy system. These sites are: 1. Trail Lake, 5600 kw capacity 2. Portage Bay (upper), 2000 kw capacity 3. Portage Bay (lower), 2000 kw capacity 4. Udmak Cove, 5500 kw capacity The estimated costs for these facilities range from $1500 to $2400 per installed kilowatt (Retherford, 1979). 2-10 60 BLM, MEAN 7 ” SCENARIO 7 a 7 7 BLM, BASE CASE MEGAWATTS : ‘XN ‘XN aN XQ ‘\ ain o ° “ ‘“ RETHERFORD (1) : eg dT tor eS SCO 1980 1985 1990 1995 2000 FIGURE 7 ELECTRIC POWER CAPACITY REQUIREMENTS PROJECTIONS (Il) ASSUMES LARGE INDUSTRIAL LOAD BEGINNING IN 1983 MORRISON KNUDSEN The city of Unalaska is considering changing the utility to a rural electric cooperative, reserving seats on the board for industrial users. Experience in other Alaskan communities has indicated that processors will utilize central power generating systems if they're __available. Retherford's estimates of power costs for processors are 410 mills per kwh in 1995 if they continue to use their own systems. One of the more attractive and economic alternatives for energy production on Unalaska is geothermal. The occurrence of geothermal resources on Unalaska Island and the potential for supplying present and future energy needs is addressed in the following sections. 2-12 3. GEOTHERMAL RESOURCES EVALUATION The Aleutian Islands are the crests of a chain of submarine volcanoes which rise to a maximum height of 10,000 meters above the ocean floor. At least 26 of the 46 active volcanoes in the chain reportedly have erupted since 1760. The last major eruption of Makushin Volcano on Unalaska Island was in 1938. The fumaroles and hot springs which occur on Unalaska Island are evidence of hot water or vapor-dominated hydrothermal systems. High heat flows associated with the recent volcanic activity are suspected and could be driving the hydrothermal system (Reeder, 1981). These resources appear to be limited to the northern part of the island and are being evaluated by geologists and geophysicists at the present time. There are limited existing data concerning the estimates of reservoir volumes and thermal energies on Unalaska. Three reservoir types have been identified on the island: 1) small sedimentary basins, 2) fault and fracture systems, 3) and calderas. The evaluation in this report will concentrate on the Summer Bay Lake warm springs and the fumarole fields which exist on Makushin Volcano. 3.1 Summer Bay The evaluation of this area is in a preliminary exploration phase. The resource was initially identified based on an existing hot (warm) spring (Figure 8). The evaluation efforts have been directed at defining the potential of finding similar warm waters on Unalaska Island. First order geologic mapping has been initiated, with additional geophysical and geochemical exploration scheduled for the summer of 1981. 3.1.1 Geology The rocks of Unalaska Island consist of an older group of altered sedimentary and volcanic rocks, a group of plutonic rocks of intermediate age, and a younger group of unaltered volcanic rocks. Unalaska Island consists mainly of rock exposures belonging to the older group of volcanic and sedimentary rocks designated the Unalaska Formation. The Unalaska Formation has been divided into three lithologically distinct parts: "“argillite southwest of Beaver Bay (southwest part of island), graywacke and conglomerate in the northern bulge area and south of Makushin Bay, and _ coarse pyroclastic deposits in northeastern Unalaska Island, separated by wide transition zones...and intercalated with dacitic, andesitic, and basaltic flows and sills...and dikes of undetermined age...(where) all rocks were slightly altered". The Unalaska Formation was found to consist mainly of tuffaceous breccia and magma flows having a regional dip of 10 degrees north to slightly northeast and a regional strike of east west to northwest (Reeder, 1981). The Unalaska Formation, at least in the northern part of Unalaska Island, is upper Oligocene to middle Miocene in age (i.e., about 20 to 30 m.y.b.p.). 3-1 al AMAKNAK ISLAND “7 DUTCH HARBOR ° 1500 M CONTOUR INTERVAL -S00ft (150m) FIGURE 8 MAP OF SUMMER BAY WARM SPRING & REGIONAL FAULTING MORRISON (After Reeder, 1981) KNUDSEN 3.1.2 The type section for the Dutch Harbor Member was measured by Hankford and Hill (1969) just southeast of the community of Unalaska. At the type section, they found the Dutch Harbor Member to be 126 meters thick, and to consist predominantly of "greenish-gray, hard, indurated sandstone and interbedded sandstone and conglomerate." The beds were found to dip between 20-30 degrees to the northeast with a strike of about N 30 degrees W. Extensive faulting has been observed in the peaks at the head of Unalaska Valley. Many of these faults are a series of nearly parallel normal faults striking roughly to the northeast and dipping steeply to the west. A large normal fault striking about N 45 degrees W and dipping 60 to 75 degrees south is well exposed along the coast just south of Summer Bay (Figure 8). Extension of this fault is projected across Summer Bay Lake and through the Summer Bay warm spring. Unfortunately, extensive bedrock examination at the spring does not indicate the presence of this fault, although joints striking about N 45 degrees W are highly suspected as controlling the source waters for the spring, and accounting for the alignment in Hu direction of a smaller spring near the main spring (Reeder, 1981). The Summer Bay warm spring occurs near the base of the exposed Unalaska Formation in a boggy swamp located south of Summer Bay Lake. Extensive talus, glacial till, alluvium, and/or beach deposits were suspected to exist underneath this swampy region, j.e., material that could easily contain aquifers of warm water. Water sample analysis of the springs indicate a surface temperature of 35 degrees C and a discharge of approximately 4 liters per minute. Quartz adiabatic geothermometry of this water indicates a reservoir source temperature of 60 degrees C, based on preliminary data. Chemical analyses of spring water are shown in Table 1. Reservoir Analysis The Summer Bay Lake area consists of two thermal resources, a shallow sedimentary basin and a deeper fault/fracture controlled system (Figure 9a). The shallow sedimentary reservoir consists of a semi-confined production zone capable of an estimated yield of 15 L/sec with a production temperature of 50 degrees C. Further definition of this resource will be required in order to determine specific hydraulic characteristics for input to development design. Based on the results of exploratory drilling (see Table 2), the production zone of this sedimentary reservoir is approximately one meter thick with an overlying cold water aquifer, . The temperature and chemistry of the warm spring indicate that there is considerable mixing between the geothermal resource and _ the overlying cold water aquifer. The estimated yield of 15 L/sec is based on a maximum pumping rate established to limit further cold water mixing and resultant adverse resource temperature drops. 3-3 Table 1 Chemistry of Summer Bay Samples] (in mg/L unless otherwise noted) Warm Spring Well #1 Well #2 B 0.5 0.5 0.5 Ca 202 460 372 K 3.0 6.5 5.5 Mg 1.0 6.3 10 Na 150 332 276 Si02 18 35 25 Cl- 404 923 741 F- 0.2 0.4 0.4 HCO3- 73 S04= 245 528 423 pH 6.98 Cond. (umhos/cm) 1810 T (0C) 35 50 ae 1 Motyka, et al, in review 3-4 ~~ SUMMER BAY “HEATED. WATER | * FIGURE 9a SIMPLIFIED CROSS-SECTION OF THE SUMMER BAY RESOURCE FIGURE 9b SIMPLIFIED CROSS SECTION OF THE MAKUSHIN VOLCANO RESOURCE @ wes Table 2 SUMMER BAY EXPLORATORY DRILLING WELL DATA Well No. 1 Depth: 16 meters Initial Conditions: flow = 3 L/sec temperature = 49.5 degrees C After 24 hours production: flow = 3.2 L/sec temperature = 50 degrees C Pressure head: 2 meters Well No.2 Depth: 17 meters Flow: 0.5 L/sec Temperature: 43.5 degrees C Pressure head: 1 meter 3-6 The deeper geothermal system appears to control the thermal hydraulics of the shallow sedimentary system. The deeper reservoir is believed to be a _ fault-controlled system with a temperature estimated at 86 degrees C. This system is estimated to have a yield of approximately 15-30 L/sec. There is the potential for a deeper thermal anomaly underlying the Summer Bay Valley, but further geologic definition and drilling are necessary for resource evaluation. If further drilling is planned, it is recommended that a target depth of 150 meters be considered. 3.2 Makushin Volcano Region The evaluation of this area is in a preliminary exploration phase and is part of the Summer Bay evaluation (Northern Half Unalaska Island). Additional reconnaissance mapping will be conducted during the summer of 1981. The State has appropriated $5 million for exploratory drilling on Makushin this year. 3.2.1 Geology The Makushin Volcano is a thick pile of unaltered and little-deformed lava and pyroclastic rocks which overlie the Unalaska Formation and forms a broad volcanic dome more than 1800 meters high and 16 kilometers wide. These rocks, which consist of basalt and subordinate andesite, are here designated the Makushin volcanics. They are now restricted to the northern part of the northern bulge of the Island, though they probably once extended further south. Locally they are uncomformably capped by basaltic flows and pyroclastic rocks that retain their constructional forms (Figure 10). The thickness of the Makushin volcanics is highly varied but probably does not exceed several thousand feet. The Formation is of Pliocene (?) and Pleistocene age; the bulk of the rocks are probably late Pleistocene. (Drewes, et. al. 1961). The Makushin volcanics consist of about four-fifths basalt and andesite lava flows and one-fifth intercalated agglomerate, tuff breccia, and flow breccia. Flows 3 to 15 meters thick form smal] steplike cliffs on steep slopes, alternating with benches underlain by the fragmental rocks. In most places platy fractures are parallel to the flow structures, emphasizing the gentle dips, but locally these structures are erratic. Most of the pyroclastic units are massive and unsorted; a few are well sorted and well bedded. (Drewes, et. al. 1961). Seven fumarole fields have been identified on Makushin Volcano (Figure 11). Fumarole field No. 1 is located just east of Makushin Volcano in the upper reaches of Makushin Valley at an elevation of about 430 meters above sea level. Field No. 2 is located further up the valley at elevations between 600 and 800 meters. Field No. 3 is located in the upper reaches of Glacier Valley at an elevation of about 670 meters. Field No. 5 is located at an elevation of 800 3-7 UNCONFORMITY woru emery UNCONFORMITY COVERED BY YOUNGER ROCKS TN Te mis STRUCTURE CONTOURS (INTERVAL 500') FIGURE 10 TRACE OF UNCONFORMITY BENEATH THE MAKUSHIN VOLCANICS z oe Cape Cheerfuh, ¥ PX - A) 1a 4 ‘oe Zant SU) A AN vad vs TS , is GS ead Needle R SS: i Tap xv \ f q e < f ZENS } S (P* 2, \ +) mS \ aA GVt gh a : i D MZ ish _Apastor we 7ANC on = ie pe iL ti} 60 x eho d as A Y i ape Kofriahhat ga) A , SS SIRE. yo \e SJ Sf) Z 8 KG HS Mi S PPh NE —*¥8 : DIAL \S ) GY Nd Z ; Y LADS Loe : “ RANE AN p We 0 MG) y Wi ft (ol Y) ) yy ys ries nC. A \ ¢) BRA Y @ ci Pez OHS SSeS) Wz em (> Fla Ss Ci 002 G1 [ Ys) FY oO A FIGURE {| MAKUSHIN VOLCANO FUMAROLE FIELDS MORRISON (After Reeder, 1981 ) KNUDSEN 1 Chemistry of Makushin Volcano Samples! (in mg/L unless otherwise noted) Si02 Cl- HC03- S04= Motyka, et al, in review Table 3 fa) fb) 0.5 0.5 11.7 32.1 4.8 5.7 4.0 10.6 52.0 87.2 94 125 10 5 0.1 0.3 37 288 129 95 6.40 6.50 3-11 69.3 12.2 28 140 191 155 5.48 23.1 3.4 8.0 13.9 88 116 21 5.32 3.2.2 meters on the south side of Makushin Volcano. Fumarole field No. 6 is located on the top of Makushin Volcano. Field No. 7 is located on the north side of Makushin. Chemical analyses of water samples taken on the volcano are summarized in Table 3. Several faults striking between N 40 degrees W to N 70 degrees W have been identified in the vicinity of the fumarole fields. These faults appear to control potential hydrothermal systems related to the fumarole fields (Figure 11). Reservoir Analysis Due to the limited nature of the existing data, this analysis is based on the existance of surface manifestations exhibited at the seven fumarole fields and geological field mapping on Makushin Volcano. The geothermal resource of Makushin Volcano can be divided into seven fumarole systems with intermediate-depth fault controls and a potential deep hydrothermal system (Figure 9b). The projected geothermal potential of the seven fumarole fields is based on surface expressions of steam, geologic controls at each site and individual reservoir configurations at each of the fields. The reservoir model is dominated by structure control provided mainly by faults and fractures with localized hydrothermal fluids. Geochemical analyses show that there is little chemical correlation between the fumaroles, indicating that they may be independent systems. The potential of the seven fumarole fields is estimated at 2 - 10 megawatts per field with a conservative total of 100 megawatts. Development of this resource would involve production centers at each field. Each production center could involve a cluster of production/injection wells (or the spent fluids could 8 down selected valleys and utilized in multi-use facilities with eventual discharge to the sea). Fumarole fields #1 and #7 appear to have the highest potential for initial development. Both of the fields appear to be fault/fracture controlled with an estimated production depth of 370 meters. The production estimate of approximately 30 megawatts for both fields is based on probable geologic controls described by John Reeder, geologist for the State of Alaska. These controls are two major fault systems associated with possible plutons underlying the fumarole fields. The hydraulic characteristics of these fields appear to be limited to fracture storage and snowmelt/precipitation recharge at each field. There is a reasonable probability of a deeper thermal anomaly underlying the Makushin Volcanics. This is evident by the existence of extensive fault and fracture systems with southeast trends and identification of younger intrusive bodies underlying the Makushin Volcanics. Since these volcanics are andesitic and related to plate junctions, they are similar to proven economic geothermal resources 3-12 found around the Pacific. It seems reasonable to conclude that a deeper thermal reservoir exists. If such a system exists, the power production potential from Makushin could be much higher with reservoir recharge from a larger area. Target production areas in this case would be lower on the mountain. It is recommended that a more detailed geologic and geophysical exploration program be initiated. The target sites should be fumarole fields #1 and 7. The resource definition should include local and regional structure, identification of temperature parameters with depth, fracture permeability and porosity, expansion of the geophysical data base and definition of local and regional hydrologic controls of the sites. 3-13 4. GEOTHERMAL DEVELOPMENT POTENTIAL Geothermal resources in Alaska have not been developed to any significant extent. The existing facilities are limited to recreational and therapeutic purposes, and many of these have been closed. Much of the lack of interest in geothermal development is related to little knowledge of the resource, high development risk, and scattered, small energy demand centers. The philosophy of high development risk is a misconception, as has been shown by successful development of similar geothermal resources in Japan, the Phillipines, Russia, Indonesia, Costa Rica, and Canada. These types of geothermal areas can be identified, explored, and developed as competitive energy resources. Market colocation and accessibility are just as important exploration criteria as geology in the Aleutians. Unalaska is one of only a few locations in this region that has a ready market and a lack of major institutional constraints. Industrial development (and consequently energy demand) is expanding rapidly, and the community is presently evaluating alternate resources for supplying the needed energy. The analysis of potential applications of geothermal energy on Unalaska is based on a selection of applications which are appropriate to the local economy, which can be constructed with a reasonable capital investment, which can be operated using primarily local labor, and which can be expected to yield a reasonable return on investment. 4.1 Summer Bay Resource The estimated temperature and production capability of the shallow geothermal resource at Summer Bay indicate that it could be developed for greenhousing, aquaculture and recreational and therapeutic purposes. Residential space heating was not considered because there is no local demand, and the estimated resource temperature and supply preclude piping the resource to the community of Unalaska. The design considerations used in the economic analysis of greenhousing and aquaculture at Summer Bay are summarized in the following sections. 4.1.1 Aquaculture Aquaculture is perhaps the lowest temperature commercial application of geothermal resources. The overall capital investment required for an aquaculture facility is moderate, and the technology required for construction and operation is readily available. There is an established market for the product, and the facilities for handling and processing the product are available at Unalaska. Two types of facilities were considered: a salmon hatchery and a salmon/trout farm. 4-1 The temperature and flow from the existing warm spring at Summer Bay are low; consequently, development of an aquaculture facility would require drilling a production well. Economic considerations indicate that development of the deeper geothermal resource for its higher temperature and production potential would be more profitable than the shallower resource. A salmon hatchery utilizing 80 degrees C water from a 150-meter deep welt could support a 50,000,000 egg facility. The preliminary design data for such a development are summarized in Table 4. Process water could be supplied by local surface water (water quality requirements for salmon hatcheries are too stringent to use the geothermal fluids directly). The expected chemistry of the geothermal fluids is such that they could be surface discharged rather than injected. Based on an analysis performed for Pilgrim Hot Springs (Nebesky and Goldsmith, 1980), a facility of this size would release an estimated 28,000,000 fry with an expected return of 1%. At 2 to 2.5 kilograms each, this would be the equivalent of 640,000 kilograms of production annually (with initial returns 2 to 3 years after operation begins). The market value of the harvest would be an estimated $1.6 million (1980 $), assuming 50% are processed for sale at $5 per kilogram and 50% are retained for brood stock. Rather than releasing the fry from.a hatchery, salmon and trout could be raised in tanks to a market size of 0.5 kilograms. The rearing of trout and salmon to a market size is profitably carried out in various regions of the U.S. Shrimp production is still in the development stages in much of the U.S., and it may be too early to attempt commercial production of Alaskan shrimp. The use of multiple tanks with a capacity of 30 to 40 cubic meters each, rather than one large tank, helps’ reduce the spread of diseases although the initial investment is higher. The ideal tank temperature is 12 to 14 degrees C. Conservative production from the tanks should be about 80 kilograms of product per year per cubic meter of water. For such a facility, geothermal resources could be used to provide space heating for the facility, as well as heated process water for the aquaculture tanks. The critical feature in the facility design is the use of temperature control valves in the heat exchange system to maintain temperature fluctuations in the tanks to within 1 degree C. Feed for the fish in the aquaculture facility could be supplied by wastes from the processors at Unalaska. These wastes would require cooking to ensure a disease-free product, and drying is recommended to extend product shelf life. The conversion rate of food to salable fish is approximately 1.7:1 on a weight basis. The feed requirements for a facility at Summer Bay could be readily met in the local area. Table 4 Design Data: Summer Bay Aquaculture Facility Size: 50,000,000 eggs Production: 640,000 kilograms per year Geothermal Production Well: 150 meters deep 80 degrees C 40 L/sec Heat Exchanger Temperature Drop: 75 degrees C Process Water: 350 L/sec (at 1 degree C) 4-3 4.1.2 Greenhousing The establishment of a geothermal greenhouse at Summer Bay would require a resource temperature of 50 degrees C or above. The greenhouse facilities would have to be competitive with California and Arizona installations which process and ship large quantities of fresh fruits and vegetables at reasonable prices. Even at the high prices paid for produce in Alaska, a greenhouse cannot compete, unless there is a large local market. The anticipated population growth at Unalaska may make growing produce, particularly tomatoes, profitable. The preliminary design requirements for a quarter-acre greenhouse at Summer Bay are shown in Table 5. These requirements are based on a report on geothermal development at Pilgrim Hot Springs (Nebesky and Goldsmith, 1980). The initial economic analysis of a geothermally-heated greenhouse versus an equivalent facility heated with diesel indicate that the geothermal operating costs are approximately half that of the diesel facility. Detailed economic analyses of this facility are presented in Section 5 of this report. 4.2 Makushin Volcano Resource The preliminary resource assessment of the Makushin Volcano fumarole fields indicates there is a high temperature (up to 300 degrees C) resource which could be developed for power production. The two areas targeted for initial exploration and development are fumarole fields #1 and #7. The estimated economic production from these two fields is 30 megawatts. Due to the rugged terrain in the targeted development areas, directional drilling may have to be used in the production wells. Drilling a fault/fracture controlled resource requires more exploration and reservoir evaluation to ensure a high degree of success than drilling stratigraphically-controlled resources. Intersecting the fracture system at depth is generally necessary for commercial production in these types of resources; consequently, well locations are critical and may not be readily moved because of terrain restrictions without decreasing the probability of success. Directional drilling allows a little more flexibility in locating surface facilities. In some cases, the same drill pad can be used for several wells, significantly decreasing access and construction requirements. 4.2.1 Power Plant Development For the preliminary economic analysis of geothermal power development at Makushin (see Section 5), it was assumed that the first plant developed would be a 10 MW plant. If initial exploration and drilling are successful, development of a second 20 MH plant would then begin. Assuming an average fluid production of 110,000 kilograms per hour at a temperature of 215 degrees C from 4-4 Table 5 PRELIMINARY DESIGN: SUMMER BAY GREENHOUSE Greenhouse Size: 20 x 45 m (1/10 hectare) Peak Heat Loss: 1.3 x 106 Btu/hr. Production: 30,000 kg/yr (two crops of tomatoes) Power requirements: 15 kw generator Geothermal System Production Well: 50 m deep Resource Temperature: 50 degrees C Flow: 8 L/sec Supply Pipeline: 60 m, 15 cm diameter Pump: 4500°- 6000 watt 4.2.2 each well, a total of 12 production wells would be required for the two plants. This is a conservative analysis to account for the fact that 100% success in production drilling is never achieved, particularly in fault/fracture controlled reservoirs. This analysis assumes that the geothermal resource is a liquid-dominated system and that a flashed-steam or binary cycle will be utilized for power production. There is a possibility that the Makushin resource is a vapor-dominated system like that at The Geysers in California. If this the case, a total production on the order of 300,000 kg/hr would be required to produce 30 MW. The resource assumptions on which the analysis of the 10 MW and 20 MW geothermal power plants is based are considered conservative given the lack of definitive resource data. An additional economic analysis was performed for comparison, using optimistic assumptions. The analysis is based on one 30 MW geothermal power plant located at fumarole field #1. The same access was considered for the 30 MW plant as for the 10 MW plant discussed previously. The primary factor changed for this analysis is the resource potential. It was assumed that the resource at this location could support a 30 MW plant with an individual well production rate of approximately 340,000 kg/h. Based on this assumption, five production wells would be required to support the plant, as compared to a total of 12 wells for the 10 MW and 20 MW plants. The difference this assumption makes in the plant economics is presented in Section 5. The preliminary analysis does not include an injection system. The water quality of the geothermal resource, regulatory requirements, and reservoir recharge considerations will dictate whether surface disposal or injection of the fluids is necessary. There is also a potential for cascading utilization of the power plant effluent for direct applications (the temperature of the effluent would be on the order of 100 degrees C). If future industrial development occurs at Broad Bay or in the Makushin Valley, the utilization of the plant effluent may become economic. The estimated total power production potential for the identified fumarole fields on Makushin is 100 MW. The occurrence of numerous zones of hydrothermal alteration southeast of Makushin Volcano are an indication of past activity and the hydrothermal system may be much more extensive than indicated by the surface manifestations. Development of a deeper system could yield as much, if not more, power than the identified systems. Much more geologic and geophysical analysis is required before the areal extent of hydrothermal resources in the Makushin region and reasonable production potentials can be determined. Development Schedule Experience with geothermal power developments of the 10 MW to 50 MW size indicates that an average of seven years is required between exploration and power-on-line (Figure 12). The earliest that geothermal power could be supplied to Unalaska is 1989. 4-6 EXPLORATION FIELD DEVELOPMENT CONSTRUCTION LONGLEAD PROCUREMENT PERMITS CHECK - OUT, SHAKEDOWN FIGURE 12 TYPICAL SCHEDULE FOR GEOTHERMAL POWER DEVELOP Aen @ wax KNUDSEN 60 TOTAL no 40|F BK at = <= oO i 30 = (1) 20 POWER CAPACITY RESIDENTIAL ee & -_-- COMMERCIAL = - 10 oo iss” a2? Tea’ ee" Teal’ load oat? oat ~To96 ‘98° 200 FIGURE 1I3 PROJECTED POWER DEMAND AND DEVELOPMENT see TABLE 6 siemaitatinn KNUDSEN TABLE 6 POWER DEVELOPMENT SCHEDULE YEAR 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 19% 1993 1994 1995 19% 1997 1998 1999 2000 PEAK DEMAND (MW) ame T Ee case Al 8.8} 9.7 ]10.5] 11.6] 12.7} 13.4 | 14.0] 14.4] 14.8] 15.2 — Case Bl 19.3 | 20.2 | 21.1] 22.0] 22.8] 23.6 | 24.4 | 25.3] 26.2] 27.1 Case cl 25.3 | 28.6 | 31.5] 34.7 | 38.0] 40.9 | 43.4 | 45.8] 48.0} 49.5 UNITS BROUGHT ON-LINE (MW) Geothermal Hydroelectric Diesel 1.24] 1.0 | | ae Gas Turbine 2.8 | Heat Recovery CAPACITY (MW) : Total 1.2 | 2.2] 5.0] 6.3] 6.3] 9.1] 10.4 | 16.0 | 26.0] 26.0] 46.0 | 51.5 | 51.5 | 53.5 | 53.5 | 63.5 | 63.5 | 63.5 63.5 | 63.5 }———+ {jf —t — joj s{6 Firm 0.6 | 1.2] 2.2] 3.5] 3.5] 5.0] 6.3]11.9 | 18.2] 18.2] 33.2 | 38.7 | 38.7 | 40.7 | 40.7 | 50.7 | 50.7 | 50.7 | 50.7 | 50.7 1 Case A: Residential and commercial, based on population projections. Case B: Minimum total load (residential, commercial, and industrial) from Retherford, 1979. Case C: Mean total load, from BLM, 1981. 2 Existing (_) Shown for planning purposes. Other options available. 4.2.3 Expansion of the existing power generation facilities in Unalaska will be required to meet projected demands until geothermal power is available. The recommended system expansion is a combination of diesel, combined cycle gas turbine units, geothermal, and hydroelectric facilities. An analysis of power demands vs system capacity was conducted, based on the Unalaska Electrification System (Retherford, 1979) and projections of power demands by the BLM for Outer Continental Shelf oil and gas development (BLM, 1981). This analysis, which includes recommended timing and mode of power system expansion, is summarized in Figure 13 and in Table 6. An estimated 1 MW of industrial load could be brought on to the central system by 1984. More of the industrial load could be supplied by a central system at this point with the addition of diesel or gas turbine units. However, these additional units would no longer be needed by the early 1990's, which is not enough time to reasonably amortize the capital costs of these units. Therefore, it was assumed that most of the industrial load would be added to the system when hydroelectric and geothermal power is available. Nearly 80% of the total projected power demand could be supplied by 1990, and excess power is available when the 20 MW geothermal power plant is brought on line in 1991. At this point, some decision on continued power development would have to be made. Some of the options are: 1. put the diesel units on standby to maintain essential services in the event other units are shut down. 2. replace much of the fossil fuel-based capacity with hydroelectric facilities (the electrification study identifies an additional 9.5 MW of hydroelectric potential). 3. continue both hydroelectric and geothermal development and attract more land-based industries. The availability of land and taxes are important considerations, along with the availability of reliable power. By 1994, without additional development, the system capacity is equivalent to the projected total load. Geothermal and hydroelectric are the primary options for further development at this point. If economic, development of these indigenous energy resources is preferable to continued reliance on fossil fuel. If an extensive, high-grade geothermal resource was discovered in the Makushin region, there could be enough power to attract energy- intensive industry such as aluminum or manganese processors. Additional exploration would be required to evaluate this potential. Logistics and Hazards The two primary considerations in the construction and operation of geothermal power plants on Makushin are: 1) logistics and 2) hazards. The most feasible and cost-effective access to the two fumarole fields proposed for development is via an existing air 4-10 strip at Driftwood Bay. An old road from the strip runs to within two kilometers of the #1 fumarole field. The cost estimate for power development at this site includes upgrading the existing road and constructing a bridge and two kilometers of new road. The cost estimate for development of fumarole field #7 includes construction of 13 kilometers of road from the Driftwood Bay strip. The Aleutian Islands are included in seismic risk zone 4, indicating a high potential for damaging earthquakes. Makushin Volcano has erupted as recently as 1938, and there is a potential for further eruptions during the operating life of a geothermal plant. The location of fumarole fields is such that development will probably occur on steep slopes and the potential for landslides will be a concern. These hazards should be included in the design of the well field, transmission pipelines and power production facilities. The most critical elements to be considered are production well control, seismic criteria for facility design, facility isolation during a volcanic eruption, a seismic monitoring and alarm system and maintenance of slope stability. . 4-11 5.1 5.2 5. ECONOMIC ANALYSIS Overview The economic analysis focuses on the feasibility of developing the geothermal resources from two perspectives. These are: 1) activities which could be developed by the private sector and 2) activities which could be developed by the public sector (utilities and rural electric associations). These activities are as follows: Private Sector Investment Public Sector Investment Fisheries Electric Power Generation Greenhouses Several geothermal resources are feasible for greenhouse and fisheries activities; consequently, the economic analysis conducted on these activities is generic to most locations. The analysis conducted on public sector activities is site specific due to minimal requirements of temperature and flow for the geothermal resource and requirements of populated areas with electric and heating requirements for consumption of output. Summer Bay Development Greenhouse and fisheries activities are assumed to be conducted by the private sector. In all cases the assumption is made that a private investor will require a minimum discounted cash flow rate of return (DCFROR) of 20% on after tax investment over the lifetime of the project. 5.2.1 Assumptions For Analysis of Greenhouses The following assumptions apply to the analysis conducted on greenhouses: 1. Methodology - Incremental NPV Analysis The analysis develops the required after tax investment and operating costs for a greenhouse heated with diesel fuel and compares this to the required investment and operating costs of a geothermal greenhouse. The geothermal greenhouse has a higher initial investment than the diesel greenhouse; however, operating costs for the geothermal greenhouse are less than the diesel heated greenhouse. The analysis calculates the additional initial investment for the geothermal greenhouse and the after tax operating savings of the geothermal reenhouse onan annual basis. The after tax investment Togsts and annual operating savings are then discounted at a 20% interest = rate. The discounted values are then accumulated, resulting in a net present value (NPV). If the 5-1 NPV is positive then the annual operating savings earn more than 20% on the additional investment over the project life. If the NPV is negative then the annual operating savings do not return 20% on the additional investment. Escalation Rates Investment and operating costs are escalated at the following rates: Year Escalation Rate 1982 10.5% 1983 10.0% 1984 9.5% 1985 9.0% 1986 8.5% 1987 8.0% 1988 and all 7.5% future years Investment Diesel Greenhouse: The capital investment in 1981 dollars is estimated to be $152,350. The greenhouse would require one year to construct and the analysis assumes a_ start of production in 1984. The production life is assumed to be 25 years and the total escalated investment is estimated to be $185,181 (Table 7). Geothermal Greenhouse: The investment in 1981 dollars is estimated to be $208,450. It is assumed that the greenhouse will require two years to construct (1982 - 1983) with 1982 allocated to well development. The greenhouse begins production in 1984 and has a_ total production life of 25 years. The total escalated investment is estimated to be $247,269 (Table 7). Investment in the geothermal greenhouse is greater than investment in the diesel greenhouse due to the cost of the production wells and piping. Operating Costs Diesel Greenhouse: Total annual operating costs in 1981 dollars are estimated to be $140,800. The costs are escalated at the above rates giving annual operating costs in the beginning year of production (1984) of $187,401 (Table 8). Geothermal Greenhouse: Total annual operating costs in 1981 dollars are estimated to be $81,400. Costs are escalated at the above rates giving annual operating costs in the beginning year of production (1984) of $108,341 (Table 8). The essential difference between direct operating costs is the additional cost of fuel required to heat the diesel greenhouse. 5-2 DIESEL VERSUS GEOTHERMAL GREENHOUSE TABLE 7 SCHEDULE OF INVESTMENT DIESEL GREENHOUSE INVESTMENT GREENHOUSE HEADHOUSE EQUIPMENT PIPING GENERATOR FURNACE CIRCULATION PUMP LIGHTS TOTAL INVESTMENT €-g GEOTHERMAL GREENHOUSE INVESTMENT GREENHOUSE HEADHOUSE EQUI! PMENT PIPING GENERATOR WELLS PUMP PIPE LIGHTS TOTAL INVESTMENT 1982 1983 0 53,482 0 30,084 0 25,404 0 20,056 0 18,719 0 0 2,674 61,018 186,251 wie 5. Depreciation Depreciation on total escalated investment is taken double declining balance, switching to straight line over a 20-year life. Depreciation commences in 1984. The depreciation deductions for the geothermal greenhouse are higher than the diesel greenhouse due to the additional investment in wells (Table 8). 6. Net Cost Before Taxes The net cost before taxes for both the diesel and geothermal greenhouses is the sum of annual escalated operating costs and depreciation deductions (Table 8). 7. Federal and State Tax The combined federal tax rate and Alaska state tax rate is assumed to be 51%. Taxes are deducted from the net before tax cost to arrive at the after tax cost for both the diesel and geothermal greenhouses. 8. Investment Tax Credit The investment tax credit is assumed to be 10% of escalated investment for both the diesel and geothermal greenhouses. The investment tax credit is taken in 1984 in both cases. 9. Net Cost The net after tax cost for both greenhouses consists of the sum of annual costs before taxes, less annual taxes, plus the investment tax credit (Table 8). 10. Net Cash Flow The net after tax cash flow for the two greenhouses consists of investment plus depreciation plus net after tax cost (Table 9). 5.2.2 Results of Analysis Subtracting the cash flow of the geothermal greenhouse from the cash flow of the diesel greenhouse results in the annual incremental costs of savings of investing in the geothermal greenhouse (Table 9). The net present value of the annual incremental cash flows, discounted at 20% is $198,680. This indicates that given the above assumptions, if an investor is contemplating a commercial greenhouse operation for the area, the better course of action is to invest in a geothermal greenhouse as opposed to a greenhouse heated by diesel fuel. The annual operating savings justify the additional investment in wells for the geothermal greenhouse if the investor's minimum after tax return on investment is 20%. 5-4 ~ a { AUGUST 6, 1981 OPERATING COSTS DIESEL GREENHOUSE LABOR FUEL MATERIALS MISCELLANEOUS TOTAL OPERATING COSTS DEPRECIATION NET BEFORE TAX FEDERAL & STATE TAX 51% INVESTMENT TAX CREDIT NET COST OPERATING COSTS GEOTHERMAL GREENH LABOR FUEL MATERIALS MISCELLANEOUS TOTAL OPERATING COSTS DEPRECIATION NET BEFORE TAX FEDERAL & STATE TAX 51% INVESTMENT TAX CREDIT NET COST 1982 eooo TABLE & DIESEL VERSUS GEOTHERMAL GREENHOUSE OPERATING COSTS AND NET CASH COST 1990 106, 862 139, 386 41,816 9,292 JOUSE o °o 1988 1989 92,472 99,407 120,615 129,661 36,185 38,898 8,041 8,644 257,312 276,610 12,150 10,935 (269,462) (287,545) (137,426) (146,648) 0 0 (132,036) (140,897) 92,472 99,407 12,062 12,966 36,185 (307,198) (156,671) (150,527) 106, 862 13,939 41,816 9,292 1983 1984 1985 1986 1987 0 67,347 73,408 79,648 86,020 0 87,844 95,750 103,889 112,200 0 26,353 28,725 31,167 33,660 0 5,856 6,383 6,926 7,480 0 187,401 204,267 221,630 239,360 0 18,518 16,666 15,000 13,500 0 (205,919) (220,933) (236,629) (252,860) 0 (105,019) (112,676) (120,681) (128,959) 0 18,518 0 0 0 0 (82,382) (108,257) (115,948) (123,901) 0 67,347 73,408 79,648 86,020 0 8,784 9,575 10,389 11,220 0 26,353 28,725 31,167 33,660 0 5,856 6,383 6,926 0 108,341 118,092 128,130 0 24,727 20,029 (133,068) (140,346) (148,158) (156,406) (67,865) (71,577) (75,561) (79,767) 0 olcoo oluooo (40,476) (68,770) (72,598) (76,639) (164,982) (84, 141) (174,516) (89,003) (85,513) (80,841) (185,050) (94,375) 0 (90,674) TABLE 8, Cont. AUGUST 6, 1981 DIESEL VERSUS GEOTHERMAL GREENHOUSE OPERATING COSTS AND NET GASH COST 1991 1992 1993 1994 1995 1996 1997 1998 1999 OPERATING COSTS DIESEL GREENHOUSE LABOR 114,877 123,493 «132,755 142,711 «153,415 164,921 «177,290 ~-—«190,587 ~—s-204,, 881 FUEL 1493840 161,078 «173,158 = 1865145 200,106 ~—215,114 =~. 2317248 = 248591 2677236 MATERIALS 4952 -48323,«5 13948 = 55,844 = 605032 «= 64534 = 6973 7h 74,577 80,171 MISCELLANEOUS 93989 10,739 113544 12,410 13,340 14, 344 15,417 16,573 17,816 TOTAL OPERATING COSTS 319,658 343,632 369,405 397,110 426,893 458,910 493,329 530,328 570,103 DEPRECIATION 8,857 7,971 7,174 6,457 6,457 6,457 6,457 6,457 6,457 NET BEFORE TAX (328,515) (351,604) (376,579) (403,567) (433,350) (465,367) (499,786) (536,785) (576,560) FEDERAL & STATE TAX 51% (167,543) (1797318) (1923055) (205,819) (221,009) (237,337) (2547891) (273,760) (294,046) INVESTMENT TAX CREDIT 0 0 0 0 0 0 0 0 0 NET COST (160,972) (172,286) (184,524) (197,748) (212,342) (228,030) (244,895) (263,025) ( ic D OPERATING COSTS GEOTHERMAL GREENHOUSE LABOR 114,877 123,493 «132,755 142,711 «153,415 164,921 +~—«177,290-—«'190,587 ~—s-204, 881 FUEL 14, 984 16, 108 17,316 18,615 20,011 21.511 23/125 24,859 26,724 MATERIALS 443952: 48,323 51,948 55,844 607032 64534 «= 953 74 74.577 80,171 MISCELLANEOUS 93989 107739 113544 127410 13,340 14) 3u41 15,417 16,573 17/816 TOTAL OPERATING COSTS 184,802 198,662 213,562 229,579 246,798 265,308 285,206 306,596 329,591 DEPRECIATION 11,827 10, 644 9,580 8, 622 8, 622 8, 622 8, 622 8, 622 8, 622 NET BEFORE TAX (196,629) (209,307) (223,142) (238,201) (255,419) (273,929) (293,827) (315,218) (338,213) FEDERAL & STATE TAX 51% (100,281) (106,746) (113,802) (121,483) (1302264) (1397704) (1492852) (160,761) (172,488) INVESTMENT TAX CREDIT 0 0 0 0 0 0 0 0 0 NET COST (96,348) (102,560) (109,340) (116,719) (125,156) (134,225) (143,975) (154,457) (165, 724) . N TABLE 8, Cont. DIESEL VERSUS GEOTHERMAL GREENHOUSE OPERATING COSTS AND NET CASH COST 2005 316,193 412,425 123,728 27,495 2006 339,907 443,357 133,007 29,557 2007 365,400 476,609 142,983 31,774 2008 392,805 512,355 153,706 34,157 879,841 (879,841) (448,719) 945,829 1,016, 766 (945,829)(1,016, 766)(1,093,023) (482, 373) (518,551) 0 (557,442) (431,122) 316,193 41,243 123,728 27,495 (463,456) 339,907 44, 336 133,007 29,557 (498,215) 365,400 47,661 142,983 31,774 (535,581) 392,805 51,235 153, 706 34,157 508,658 546,807 587,818 631,904 (508,658) (259,416) (546,807) (278,872) (587,818) (299,787) (631,904) (322,271) AUGUST 6, 1981 2000 OPERATING COSTS DIESEL GREENHOUSE LABOR 220,247 FUEL 287,278 MATERIALS 86, 184 MISCELLANEOUS 19,152 TOTAL OPERATING COSTS 612,861 DEPRECIATION 6,457 NET BEFORE TAX (619,318) FEDERAL & STATE TAX 51% (315,852) INVESTMENT TAX CREDIT 0 NET COST (303,466) OPERATING COSTS GEOTHERMAL GREENHOUSE LABOR 220,247 FUEL 28,728 MATERIALS 86, 184 MISCELLANEOUS 19,152 TOTAL OPERATING COSTS 354, 310 DEPRECIATION 8,622 NET BEFORE TAX (362,932) FEDERAL & STATE TAX 51% (185,095) INVESTMENT TAX CREDIT ~ 0 NET COST (177,837) 2001 2002 2003 2004 236,765 254,523 273,612 294, 133 308, 824 331,986 356,885 383,652 92,647 99,596 107, 066 115,095 20,588 22,132 23,792 25,577 658,825 708,237 761,355 818,457 6,457 6,457 6,457 0 (665,282) (714,694) (767,812) (818,457) (339,294) (364,494) (391,584) (417,413) 0 0 0 0 (325,988) (350,200) (376,228) (401,044) 236,765 254,523 273,612 294, 133 30,882 33,199 35,689 38,365 92, 647 99,596 107,066 115,095 20,588 22,132 23,792 25,577 380,883 409,450 440, 158 473,170 8,622 8,622 8,622 0 (389,505) (418,071) (448,780) (473,170) (198,648) (213,216) (228,878) (241,317) 0 0 0 0 (190,857) (204,855) (219,902) (231,853) (249,242) (267,936) (288,031) (309,633) 8-S AUGUST 6, 1981 CASH FLOW DIESEL GREENHOUSE INVESTMENT DEPRECIATION NET COST CASH FLOW CASH FLOW GEOTHERMAL GREENHOUSE INVESTMENT DEPRECIATION NET COST CASH FLOW INCREMENTAL NPV ANALYSIS CASH SAVINGS (COSTS) GEOTHERMAL OVER DIESEL DISCOUNTED AT 20% NET PRESENT VALUE 20% (61,018) (61,018) (61,018) ~ (61,018) TABLE 9 DIESEL VERSUS GEOTHERMAL GREENHOUSE 1983 1984 (185,181) 0 0 18,518 __0 (82, 382) (185,181) (63,864) (186,251) 0 0 24,727 0 (40,476) (186,251) (15,750) (1,070) 48,115 (891) 33,413 (61,909) (28,497) 1985 0 16,666 (108,257) (91,591) 0 22,254 (68,770) (2,411) CASH FLOW AND INCREMENTAL NET PRESENT VALUE 1986 1987 0 0 15,000 13,500 (115,948) (123,901) (100,949) (110,402) 0 0 20,029 18,026 (72,598) (76,639) 1988 0 12,150 (132,036) (119,887) 0 16,223 (80,841) 1989 0 10,935 (140,897) (129,962) 0 14,601 (85,513) (70,912) 59,050 16,480 76,722 1990 0 9,841 (150,527) (140, 686) 0 13,141 (90,674) ~ (77,534) 63,152 14,687 91,409 6-S AUGUST 6, 1981 CASH FLOW DIESEL GREENHOUSE INVESTMENT DEPRECIATION NET COST CASH FLOW CASH FLOW GEOTHERMAL GREENHOUSE INVESTMENT DEPRECIATION NET COST CASH FLOW INCREMENTAL NPV ANALYSIS CASH SAVINGS (COSTS) GEOTHERMAL OVER DIESEL DISCOUNTED AT 20% NET PRESENT VALUE 20% TABLE 9; Cont. DIESEL VERSUS GEOTHERMAL GREENHOUSE CASH FLOW AND INCREMENTAL NET PRESENT VALUE 1991 1992 1993 1994 1995 0 0 0 0 0 8,857 7,971 7,174 6,457 6,457 (1602972) (1727286) (1842524) (197,748) (2127342) (152,115) (164,314) (177,349) (191,291) (205,885) 0 0 0 9,580 8, 622 8,622 (109; 340) (1257156) (84,521) (116,534) 67,594 72,398 77,590 83,194 89,351 13,100 1,693 10,443 9,331 8,351 104,509 116,202 126,645 135,976 144,327 1996 0 6,457 (228,030) (221,573) 0 8,622 (134,225) (125,604) 95,969 7,475 151,801 1997 0 6,457 (244,895) (238,438) 0 8,622 (143,975) (135,354) 103,084 6 158,49 1998 Oo 6,457 (263,025) (256,568) 0 8,622 (154,457) (145,835) 110, 733 5,989 164,481 1999 0 6,457 (282,514) (276,057) 0 8,622 (165,724) (157,102) 118,955 5,362 169,843 OI-S AUGUST 6, 1981 CASH FLOW DIESEL GREENHOUSE INVESTMENT DEPRECIATION NET COST CASH FLOW CASH FLOW GEOTHERMAL GREENHOUSE INVESTMENT DEPRECIATION NET COST CASH FLOW INCREMENTAL NPV ANALYSIS CASH SAVINGS (COSTS) GEOTHERMAL OVER DIESEL DISCOUNTED AT 20% NET PRESENT VALUE 20% 2000 0 6,457 (303,466) (297,009) 0 8,622 (177,837) (169,215) 127,794 4,800 “174, 643 TABLE 9, Cont. DIESEL VERSUS GEOTHERMAL GREENHOUSE 2001 oO 6,457 (325,988) (319,531) 0 8,622 (190,857) (182,236) 137,296 4,297 178,941 2002 0 6,457 (350,200) (343,743) 0 8,622 (204,855) (196,233) 147,510 182, 78 2003 0 6,457 (376,228) (369,771) 0 8,622 (219,902) (211, 280) CASH FLOW AND INCREMENTAL NET PRESENT VALUE 2004 0 0 (401,044) 3,065 (431,122) (249,242) (249,242) 181,880 2,745 192,043 2006 0 0 (463,456) (463,456) 0 0 (267,936) (267,936) 195,521 2,459 194,503 2007 2008 0 0 0 0 (498,215) (535,581) (498,215) (535,581) (288,031) (309,633) (288,031) (309,633) 210,185 225,948 2,203 196,706 198,680 5.2.3 Assumptions for Analysis of Salmon Fisheries The following assumptions apply to the analysis: 1. Methodology - Discounted Cash Flow Rate of Return Analysis (DCFROR) The analysis calculates the net after tax cash flow for two hatcheries, a hatchery utilizing a shallow geothermal resource and a hatchery utilizing a deeper, higher temperature resource at Summer Bay (see Section 4). A DCFROR is calculated over the entire life of both projects which entails a 2-year construction period and 25-year production period. Escalation Rates Investment, revenues, and operating costs are escalated at the following rates: Year Escalation Rate 1982 10.5% 1983 10.0% 1984 9.5% 1985 9.0% 1986 8.5% 1987 8.0% 1988 and all 7.5% future years Investment Shallow System: The investment for a hatchery utilizing the shallow geothermal resource at Summer Bay (50 degrees C at 50 m) is estimated to be $4.95 million (1981 dollars). The capacity of the hatchery is assumed to be 10,000,000 fry with a heat load of 7,400,000 Btu/hr. The hatchery requires two years to construct, with 40% of the investment occurring in 1982 and the remaining 60% in 1983 (Table 10). The hatchery begins production in 1984 and has a_ total production life of ar Revenue from sales on returning fish commences in 6. Deep System: The investment for a hatchery utilizing a deeper eothermal resource at Summer Bay’ is estimated to be 10 million. With a resource production of 30 L/sec at 85 degrees C, the facility could support 50,000,000 fry (heat load of 28,000,000 Btu/hr). The hatchery requires two years to construct with 40% of the investment occurring in 1982 and the remaining 60% in 1983 (Table 10). The hatchery begins production in 1984 and has a total production life of 25 Se Revenue from sales of returning fish commences in 5-1] TABLE 10 SUMMER BAY SALMON HATCHERY SHALLOW AND DEEPER SYSTEMS - INVESTMENT $000 100% EQUITY 1982 1983 TOTAL SHALLOW SYSTEM INVESTMENT CAPITAL EXPENDITURES 2,188 3,610 5,798 TOTAL INVESTMENT 2,188 3,610 5,798 DEEPER SYSTEM INVESTMENT CAPITAL. EXPENDITURES 442k 7,300 11,725 TOTAL INVESTMENT 442k 7,300 5-12 Revenues Shallow System: The analysis assumes a 1.0% return of fish beginning in 1986. The average weight of returning fish is assumed to be 2.3 kilograms. Revenue in 1981 dollars is calculated as follows: Revenue from commercial sales: Revenues Number of From Returning Kilograms Per Sales Price Percentage Commercial Fish Fish Per Kilogram Sold Sales 69,440 x 2.3 x $5.50 x 50% = $439,208 Revenue from brood stock: Kilograms of Percentage Returning Used For Price Per Revenue From Fish Brood Kilogram Brood 159,712 x 50% x $0.72 = $57,288 Revenues are escalated at the above rates giving annual petelnatl ° the beginning year of production (1986) of $779,000 Table 11). Deep System: The analysis assumes a 1.0% return of fish beginning in 1986. The average weight of returning fish is assumed to be 2.3 kilograms. Revenue in 1981 dollars is calculated as follows: Revenue from commercial sales: Revenues Number of Price From Returning Kilograms Per Per Percentage Conmercial Fish Fish Kilogram Sold Sales 280,000 x 2.3 x $5.50 50% = $1,771,000 Revenue from brood stock: Kilograms of Percentage Price Revenue Returning Used For Per From Fish Brood Kilogram Brood 644,000 x 50% x $0.72 = $231,000 Revenues are escalated at the above rates giving annual revenues : the first year of fish return (1986) of $3,151,000 (Table 11). 5-13 5.2.4 10. li. Operating Costs Shallow System: Total annual operating costs in 1981 dollars are estimated to be $165,000. Deep System: Total annual operating costs in 1981 dollars are estimated to be $330,000. The difference in operating costs are due to the larger size and increased pumping power requirements assumed for the facility based on the deeper geothermal resource. Depreciation Depreciation on total escalated investment for both systems is taken double declining balance, switching to straight line over a 20-year life. Depreciation commences in 1984. Net Income Before Tax Net income before tax for both hatcheries is the sum of revenue nal annual operating expenses less annual depreciation (Table 11). Federal and State Tax Rate The combined federal and Alaska state tax rate is assumed to be 51%. The assumption is made that tax savings occur in years during operating losses. Investment Tax Credit The investment tax credit is assumed to be 10% of escalated investment for both hatcheries. The investment tax credit is taken in 1984. The assumption is made that the investor has other projects generating sufficient tax liability to allow the credit to be taken as a deduction in this year. Net Income Net income for both hatcheries consists of the sum of net income before taxes, less taxes, plus the investment tax credit (Table 11). Net Cash Flow Net cash flow for both hatcheries consists of the sum of net income less investment plus depreciation (Table 11). Results of Analysis Shallow System: The DCFROR (Internal Rate of Return) over the hatchery life is 8.8% given the above assumptions. This return is below the required minimum return of 20.0% and is probably not sufficiently high to attract private investment. 5-14 GL-S AUGUST 6, 1981 SHALLOW SYSTEM ANALYSIS REVENUE OPERATING EXPENSES DEPRECIATION NET INCOME BEFORE TAXES FEDERAL & STATE TAX AT 51% INVESTMENT TAX CREDIT NET INCOME CASH FLOW & RATE OF RETURN INVESTMENT DEPRECIATION NET INCOME NET CASH FLOW PAYBACK INTERNAL RATE OF RETURN DEEPER SYSTEM ANALYSIS REVENUE OPERATING EXPENSES DEPRECIATION NET INCOME BEFORE TAXES FEDERAL & STATE TAXES AT 51% INVESTMENT TAX CREDIT NET INCOME CASH FLOW AND RATE OF RETURN INVESTMENT DEPRECIATION NET INCOME NET CASH FLOW PAYBACK INTERNAL RATE OF RETURN 1982 TABLE 11 SUMMER BAY SALMON HATCHERY SHALLOW AND DEEPER dogo - RATE OF RETURN 000 1983 1984 (3,610) 768 (5,798) (5,030) 0.0 0.0 0 Oo 0 439 0 1,172 0 (1,612) 0 (822) 0 1,172 ; = 1985 479 1986 1987 (7,300) 1,555 (11,725) (10, 169) 0.0 0.0 304 (9,866) 0.0 490 (3,407) 0.0 100% EQUITY 1989 1990 972 1,045 32k 3u8 32 308 306 389 156 198 0 0 150 191 0 0 342 308 150 191 492 499 (2,915) (2,416) 0.0 0.0 9T-S TABLE 11, Cont. AUGUST 6, 1981 SUMMER BAY SALMON HATCHERY 100% EQUITY SHALLOW AND DEEPER SYSTEMS ~- RATE OF RETURN $000 1991 1992 1993 1994 1995 1996 1997 1998 1999 SHALLOW SYSTEM ANALYSIS REVENUE 1,124 1,208 1,299 1,396 1,501 1,613 1,734 1,864 2,004 OPERATING EXPENSES 375 403 465 500 538 578 621 668 DEPRECIATION 277 250 202 202 202 202 202 202 NET INCOME BEFORE TAXES 472 556 729 798 873 954 1,041 1,134 FEDERAL & STATE TAX AT 51% 241 283 372 407 445 487 531 578 INVESTMENT TAX CREDIT 0 0 0 0 0 0 0 0 NET INCOME 231 272 357 391 428 467 510 556 CASH FLOW & RATE OF RETURN EE INVESTMENT 0 0 0 0 0 0 0 0 0 DEPRECIATION 277 250 225 202 202 202 202 202 202 NET INCOME 231 272 314 357 391 428 467 510 556 NET CASH FLOW 509 522 539 559 593 630 670 712 158 PAYBACK (1,908) (1,386) (847) (288) 305 936 1,605 2,317 3,075 INTERNAL RATE OF RETURN 0.0 0.0 0.0 0.0 8 2.1 3.2 4.1 4.9 DEEPER SYSTEM ANALYSIS REVENUE 4,545 4, 886 5,252 5,646 6,070 6,525 7,015 7,541 OPERATING EXPENSES 749 805 866 931 1,001 1,076 1,156 1,243 DEPRECIATION 561 505 454 409 409 409 409 409 NET INCOME BEFORE TAXES 3,235 3,576 3,932 4,307 4,661 5,041 5,449 5,889 FEDERAL & STATE TAXES AT 51% 1,650 1,824 2,006 2,197 2,377 2,571 2,779 3,003 INVESTMENT TAX CREDIT 0 0 0 0 0 0 0 0 NET INCOME 2,670 CASH FLOW AND RATE OF RETURN INVESTMENT 0 0 9 0 0 0 0 0 0 DEPRECIATION 561 505 454 409 409 409 409 409 409 NET INCOME 1,585 1,752 1,927 2,110 2,284 2,470 2,670 2,886 3,117 NET CASH FLOW 2,146 2,257 2,381 2,519 2,692 2,879 3,079 3,294 3,526 PAYBACK 1,783 4,040 6,421 8,940 11,633 14,511 17,590 20,885 24,411 INTERNAL RATE OF RETURN 2.7 5.3 7.3 8.8 10.1 11.1 12.0 12.7 13.3 L1-S AUGUST 6, 1981 SHALLOW SYSTEM ANALYSIS REVENUE OPERATING EXPENSES DEPRECIATION NET INCOME BEFORE TAXES FEDERAL & STATE TAX AT 51% INVESTMENT TAX CREDIT NET INCOME CASH FLOW & RATE OF RETURN INVESTMENT DEPRECIATION NET INCOME NET CASH FLOW PAYBACK INTERNAL RATE OF RETURN DEEPER SYSTEM ANALYSIS REVENUE OPERATING EXPENSES DEPRECIATION NET INCOME BEFORE TAXES FEDERAL & STATE TAXES AT 51% INVESTMENT TAX CREDIT NET INCOME CASH FLOW AND RATE OF RETURN INVESTMENT DEPRECIATION NET INCOME NET CASH FLOW PAYBACK INTERNAL RATE OF RETURN TABLE 11, Cont. SUMMER BAY SALMON HATCHERY SHALLOW AND DEEPER SYSTEMS - RATE OF RETURN $000 2000 2001 2002 2003 2004 2005 2,155 2,316 2,490 2,677 2,877 3,093 718 772 830 892 959 1,031 202 202 202 202 70 0 1,234 1, 342 1,458 1,582 1,918 2, 062 629 684 743 807 978 1/052 0 0 0 0 0 0 605 658 714 775 ~~ -940~—S—S=«*YT; 010 0 0 0 0 0 0 202 202 202 202 0 0 605 658 714 775 940 1,010 807 860 916 977 940 1,010 3,882 4, 742 5,658 6,636 7,576 8,586 5.6 6.2 6.7 7.2 7.6 8.0 12,510 2,062 0 10,448 5,329 0 5,120 0 0 0 0 0 0 409 409 409 409 0 0 3, 366 3,633 3,921 4,230 4, 762 5,120 35715 4,042 4,330 4,639 4,762 5,120 28, 185 32,227 36,557 41,195 45,958 51,077 13.8 44.2 14.6 44.9 15.2 15.4 2006 100% EQUITY 2007 2008 3,575 3,843 1,192 1,281 0 0 2, 383 2, 562 1,215 1,307 0 0 1,255 0 0 0 0 1,168 1,255 1, 168 1,255 10,840 12,095 8.6 8.8 14,457 15,541 2, 383 2,562 0 0 12,074 12,980 6,158 6,620 0 0 5,916 6, 360 0 0 0 0 5,916 6,360 5,916 6, 360 623497 «68,857 15.8 16.0 Deep System: The DCFROR (Internal Rate of Return) over the project life is 16.0%. This return is below the required minimum return of 20.0% for private investors. However, the return is high enough that interest by private investors could be generated through the use of government subsidies. Subsidies would probably have to range between 10% and 20% of the total investment. 5.3 Public Sector Investment Public sector activities include geothermal electric power generation and geothermal space heating. The required investment in these activities can be raised through the formation of local utilities, Rural Electric Associations and Rural Water Power Associations. All analyses which follow assume that investment is raised through the formation of the above entities. The analyses assume that the entities involved are tax exempt and issue tax exempt bonds to raise the required investment. As tax exempt entities own the power plants, an after tax analysis is not required. The analyses calculate the rate which must be charged by the tax exempt owner to recover operating costs and payments of loan principal and interest on the debt issued to finance the construction costs of the plant. The economic analysis of power production on Makushin includes two development scenarios: 1) a 10 MW geothermal power plant with production beginning in 1989 and a 20 MW geothermal power plant with production beginning in 1991, and 2) a 30 MW geothermal power plant with production _ beginning in 1989, based on optimistic resource assumptions. 5.3.1 Assumptions for Power Plant Analysis The following assumptions apply to the analysis: 1. Methodology - Discounted Cost - Breakeven analysis The analysis develops the required mill rate per kilowatt-hour of electricity sold to recover operating costs, loan principal payments, and interest payments for the power plants. The mill rate per kilowatt-hour of supplying the same amount of electricity using a diesel fuel is calculated in answer to the following question: "Assuming the average cost of tax exempt bonds is 10.0% annually (this implies an annual discount rate of 10.0%); at what rate must the annual price of diesel fuel escalate to make investment in a geothermal power plant economically feasible?” The factors used to calculate the diesel fuel savings of geothermal power are based on the combined diesel/gas turbine/hydroelectric system proposed by R. W. Retherford Associates (1979). 2. Escalation Rates 5-18 3. Investment and operating costs of the geothermal plants are escalated at the following rates: Year Escalation Rate 1982 10.5% 1983 10.0% 1984 9.5% 1985 9.0% 1986 8.5% 1987 8.0% 1988 and all 7.5% future years Investment 10 MW Geothermal Power Plant: Investment in 1981 dollars for the power plant is estimated to be $52.2 million. In addition, 19 kilometers of transmission line, one bridge and 8 kilometers new and reworked road are required. Estimated costs for these items total $4.9 million in 1981 dollars. Total estimated investment in 1981 dollars is $57.1 million. Permitting, engineering, well development, and plant construction are estimated to require seven years beginning in 1982 (Table 12). The assumption is made that the geothermal resource proves adequate in temperature and flow to support the power plant with four production wells. The plant begins production in 1989 and has a production life of 25 years. 20 MW Geothermal Power Plant: Investment in 1981 dollars for the power plant is estimated to be $112.4 million. In addition, 13 kilometers of new road are required costing $8.0 million. Total estimated investment is $120.4 million in 1981 dollars. Permitting, engineering, well development and plant construction are estimated to require seven years beginning in 1984 (Table 12). The assumption is made that the geothermal resource proves adequate in temperature and flow to support the power plant with eight wells. The plant begins production in 1991 and has a production life of 23 years. 30 MW Geothermal Power Plant: Investment in 1981 dollars for the 30 MW power plant is estimated to be $126.7 million. In addition, 19 kilometers of transmission line, one bridge and 8 kilometers of new and reworked road are required. The estimated total cost for these items is $4.9 million in 1981 dollars. The total investment in the plant and facilities is $131.6 million (1981 dollars). Permitting, engineering, well development, and plant construction are estimated to required seven years beginning in 1982 (Table 13). The assumption is made that the geothermal resource proves adequate in temperature and flow to support the power plant with five wells. The plant begins production in 1989 and has a production life of 25 years. 5-19 ao DO AUGUST 28, 1981 INVESTMENT - 10 MEGAWATT POWER PLANT 4 WELL SYSTEMS PLANT AND ENGINEERING PERMITTING AND MISCELLANEOUS TRANSMISSION LINES : 19 km NEW ROADS : 2 km BRIDGE CONSTRUCTION ROAD REWORK : 6 km BRINE SYSTEM TOTAL INVESTMENT SCHEDULE OF DEBT ANNUAL LOAN DRAW CUMULATIVE DRAWDOWN ANNUAL_ INTEREST CUMULATIVE INTEREST INTEREST ON INTEREST ANNUAL DEBT AND INTEREST CUMULATIVE DEBT INVESTMENT - 20 MEGAWATT POWER PLANT 8 WELL SYSTEMS PLANT AND ENGINEERING PERMITTING AND MISCELLANEOUS NEW ROADS : 13 km BRINE SYSTEM TOTAL INVESTMENT SCHEDULE OF DEBT ANNUAL LOAN DRAW CUMULATIVE DRAWDOWN ANNUAL_ INTEREST CUMULATIVE INTEREST INTEREST ON INTEREST ANNUAL DEBT AND INTEREST CUMULATIVE DEBT TABLE 12 UNALASKA GEOTHERMAL ANALYSIS INVESTMENT = 10 MEGAWATT & 20 MEGAWATT POWER PLANT $000 1982 1983 1984 1985 2,210.0 4,862.0 13, 309.7 5,803.0 0:0 0:0 0:0 27611.4 1,243.1 1,504.8 1,197.9 1,469.6 0:0 0:0 0:0 0:0 1,105.0 0:0 0:0 0.0 1,657.5 0:0 0.0 0:0 1; 326.0 0:0 0:0 0:0 0:0 0:0 0:0 754.4 7,541.6 14,507.6 7,541.6 14,507.6 10,638.4 77541 .6 28,416.0 39,0544 754.2 2,841.6 3,905.4 7542 4986.6 8; 892.0 0:0 214.5 498.7 8,295.8 7,833.0 a 8,295.8 16, 128.8 33, 692.5 0.0 0.0 5,323.9 11,606.1 0:0 0:0 0:0 0:0 0:0 0:0 2,287.9 2,743.4 0:0 0:0 10; 647.8 0.0 0:0 0:0 0.0 0.0 18, 259.6 0.0 18,259.6 14, 349.5 0:0 18; 259.6 32,609.1 0.0 3,260.9 0:0 5; 086.9 0:0 182.6 0 17, 793.0 .0 1986 11,254.6 50,309.1 5,030.9 13,923.0 889.2 1987 MPODONVWVSCSO ecooonco Wo 13,600.0 8,287.5 2,629.9 92,854.8 9,285.5 1,171.2 10% DEBT 1988 wor wou = © Ay 0. 9. 4, 5. QO. oO. oO. 0. NOOCOMwoo 84,622.9 0.0 22,273.6 3,770.1 31,641.3 124,496.2 12,449.6 33,447.5 2,099.8 Te-S AUGUST 28, 1981 INVESTMENT - 10 MEGAWATT & 20 MEGAWATT POWER PLANT 1989 0 0 0. oO. QO. oO. QO. oO. INVESTMENT - 10 MEGAWATT POWER PLANT 4 WELL SYSTEMS PLANT AND ENGINEERING PERMITTING AND MISCELLANEOUS TRANSMISSION LINES : 19 km NEW ROADS : 2 km BRIDGE CONSTRUCTION ROAD REWORK : 6 km BRINE SYSTEM TOTAL INVESTMENT eooooo0°0o SCHEDULE OF DEBT ANNUAL LOAN DRAW 0.0 CUMULATIVE DRAWDOWN 84,622.9 ANNUAL_ INTEREST 8,462.3 CUMULATIVE INTEREST 38,021.8 INTEREST ON INTEREST 2,956.0 ANNUAL DEBT AND INTEREST 11,418.2 CUMULATIVE DEBT 130, 780.5 INVESTMENT - 20 MEGAWATT POWER PLANT 8 WELL SYSTEMS PLANT AND ENGINEERING PERMITTING AND MISCELLANEOUS NEW ROADS : 13 km BRINE SYSTEM TOTAL INVESTMENT SCHEDULE OF DEBT ANNUAL LOAN DRAW 58,993.9 CUMULATIVE DRAWDOWN 183,490.0 ANNUAL INTEREST 18,349.0 CUMULATIVE INTEREST 51,796.5 INTEREST ON INTEREST 3,344.7 ANNUAL DEBT AND INTEREST CUMULATIVE DEBT TABLE 12, Cont. UNALASKA GEOTHERMAL ANALYSIS $000 1990 TOTAL 0.0 26, 184.8 0.0 30,043.7 0.0 13,494.8 0.0 2,131.8 0.0 1,105.0 0.0 1,657.5 0.0 1,326.0 0:0 8,679.3 0.0 84,622.9 0.0 84, 622.9 84, 622.9 84, 622.9 8,462.3 46, 484.1 46, 484.1 46, 484.1 3,802.2 11,937.9 12,264.5 143, 044.9 0.0 62,011.5 20,591.1 94,250.7 5,444.5 24,104.9 0.0 10,647.8 5,174.2 23,684.9 31,209.7 214,699.8 31,209.7 214,699.8 214,699.8 214,699.8 21,470.0 73,266.4 73,266.4 73,266.4 5,179.6 12,486.7 9 300,452.9 10% DEBT ce-S TABLE 13 AUGUST 28, 1981 UNALASKA GEOTHERMAL ANALYSIS 10% DEBT INVESTMENT - 30 MEGAWATT POWER PLANT $000 1982 1983 1984 1985 1986 1987 1988 TOTAL INVESTMENT - 30 MEGAWATT POWER PLANT 5 WELL SYSTEMS 2,762.5 6,077.5 16,637.2 7,253.8 0.0 0.0 0.0 32,731.0 PLANT AND ENGINEERING 0.0 0.0 0.0 9,974.0 27,055.2 52,594.6 25,128.1 114,751.9 PERMITTING AND MISCELLANEOUS 2,244.3 2,715.4 2,162.8 2,652.0 3,837.6 5,179.9 5,568.4 24,360.4 TRANSMISSION LINES : ‘19 km 0.0 0.0 0.0 0.0 816.0 1,315.8 2,131.8 NEW ROADS : 2 km 0.0 0.0 0.0 0.0 0.0 0.0 1,105.0 BRIDGE CONSTRUCTION 0.0 0.0 0.0 0.0 0.0 0.0 1,657.5 ROAD REWORK : 6 km 0.0 0.0 0.0 0.0 0.0 0.0 1,326.0 BRINE SYSTEM 0.0 0.0 2,502.6 6,789.0 13,197.1 6,304.9 28,793.5 TOTAL INVESTMENT I @ SCHEDULE OF DEBT ANNUAL LOAN DRAW 38,317.2 206,857.1 CUMULATIVE DRAWDOWN 21 206,857.1 won ANNUAL INTEREST CUMULATIVE INTEREST INTEREST ON INTEREST ANNUAL DEBT AND INTEREST CUMULATIVE DEBT The total capital investment in 1981 dollars for the three power plants is shown in Table 14. These costs include a construction cost location adjustment factor of 2.5 over construction costs in the lower 48 states. This is based on a factor of 2.0 between Seattle and Unalaska and an additional factor of 0.5 from Unalaska to the remote location on Makushin. The installed costs for the three power plants (without wellfield costs) are $3710 (10 MW), $4020 (20 MW), and $3553 (30 MW). If the construction cost factor is taken into account, these costs are comparable to those for remote geothermal power plants currently in the design phase or under construction. Annual Power Production and Sales 10 MW and 20 MW System: Power production begins in 1989 with the 10 MW plant producing 68 gigawatt hours of electricity annually. Power production is calculated according to the following formula: Net Production = 10MW x 91% net x 8760 hours x 0.001 GWH/MWH x 85% efficiency with brine filtration. Total power production increases to 204 gigawatt hours in 1991 when production of 136 gigawatt hours begins from the 20 MW plant. Sales of power are based on projections of population growth and commercial business activities. Net annual sales of geothermal power are projected below. The assumption is made that if total demand for power exceeds production of geothermal power, the remaining demand will be supplied by non-geothermal generation: Power Demand Year GWH/Year 1989 68 GWH or greater 1990 68 GWH or greater 1991 170 GWH 1992 and all 204 GWH or greater future years 30 MW Plant: Power production begins in 1989 with the 30 MW plant producing 204 gigawatt hours of electricity annually. 5-23 TABLE 14 CAPITAL INVESTMENT - GEOTHERMAL POWER PLANTS Well Systems Plant and Engineering Permitting and Miscellaneous Transmission Lines Roads and Bridges Brine System Total ($000 - 1981) 10 MW $ 20,000 18,000 9,000 1,200 3,700 5,200 $57,100 5-24 20 MW $ 40,000 47,400 13,000 -0- 8,000 12,000 $120,400 30_MW $ 25,000 68,700 16,000 1,200 3,700 17,000 $131,600 Annual Operating Costs 10 MW Geothermal Power Plant: Annual operating costs in 1981 dollars are estimated to be $2.5 million. Operating costs are escalated at the rates listed above. A breakdown of operating costs in 1981 dollars is as follows: Item Expenditure Operating and Maintenance Expense $ 420,000 General and Administrative Expense (10% of 0 & M) 42,000 Insurance 338,000 Royalty (25 mills/KWH) 1,700 ,000 Total $2,500,000 20 MW Geothermal Power Plant: Annual operating costs in 1981 dollars are estimated to be $5.2 million. Operating costs are escalated at the rates listed above. A breakdown of operating costs in 1981 dollars is as follows: Item Expenditure Operating and Maintenance Expense $ 840,000 General and Administrative Expense (10% of 0 & NM) 84,000 Insurance 859,000 Royalty 3,400,000 Total $5,183,000 30 MW Geothermal Power Plant: Annual operating costs in 1981 dollars are estimated to be $7.39 million. Operating costs are escalated at the rates listed previously. A breakdown of operating costs in 1981 dollars is as follows: Item Expenditure Operating and Maintenance Expense $1,260,000 General and Administrative 126,000 Expense (10% of 0 & M) Insurance 828,000 Royalty (25 mills/KWH) 5,175,000 Total $7,389,000 5-25 6. Loan Principal and Interest The assumption is made that the plants are financed during construction through the issuance of government bonds at an assumed average annual interest rate of 10.0%. Interest on debt is rolled over during construction and becomes part of the cumulative debt owed on each plant. Repayment of debt commences in 1989 for the 10 MW plant and the 30 MW plant and 1991 for the 20 MW plant. Debt on each plant is repaid over a 20-year term in annual installments of level principal plus declining interest at a rate of 10.0%. 7. Total Expenses Total annual expenses for each plant consist of the sum of annual operating costs and annual principal and interest payments. 8. Total Expenses Mills/KWH Total expenses for both plants are added together and converted to mills per kilowatt-hour by dividing annual power sold into annual expenses (Table 15 and 16). 9. Diesel Fuel Savings R. W. Retherford Associates (1979) proposes a combined diesel generator, gas turbine, and hydroelectric system to meet the future power needs of Unalaska. For this analysis, it is assumed that geothermal power would replace all or part of the diesel fuel systems. To compute the diesel fuel savings by operating a geothermal plant, the 1989 diesel fuel costs were set at 224 mills/KWH as projected in the Retherford report. Diesel fuel costs were escalated at a breakeven rate of 3.04 percent per year beginning in 1990 for the 30 MW plant and at 6.73 percent per year for the 10 MW and 20 MW plants. 5.3.2 Results of Analysis The total annual combined costs of providing geothermal power from the 10 MW and 20 MW plant in milts/KWH are subtracted from the annual savings in diesel fuel in mills/KWH. The results show the net annual (costs) or savings of providing geothermal power over the proposed combined system (Table 15). The annual (costs) or savings are discounted at a rate of 10% beginning in 1982. The discounted values are then added together to yield a NPV. Results of the analysis indicate that if diesel fuel escalates at an annual rate above 6.73% then the discounted savings of providing geothermal power would be greater than the discounted costs (NPV is positive). Therefore, the costs of providing geothermal power over the production life of the two plants would be less than providing the equivalent amount of power with the combined system analyzed in the Retherford report. If diesel fuel escalates at an annual rate below 6.73% then the discounted costs of providing geothermal power would exceed the discounted savings (NPV is naputive! 5-26 Le-S TABLE 15 AUGUST 28, 1981 UNALASKA GEOTHERMAL ANALYSIS FUEL TO GEOTHERMAL Nee PRESENT VALUE COMPARISON 000 1982 1983 1984 1985 1986 PRODUCTION : GWH PER YEAR 0 0 0 0 0 EXPENSES FOR 10 MEGAWATT POWER PLANT OPERATING AND MAINTENANCE 0 0 0 GENERAL AND ADMINISTRATIVE 0 0 0 INSURANCE 0 0 0 ROYALTY 0 0 0 DIRECT EXPENSES 0 0 OTHER EXPENSES LOAN PRINCIPAL 0 0 0 0 0 INTEREST it TOTAL EXPENSES 0 EXPENSES FOR 20 MEGAWATT POWER PLANT OPERATING AND MAINTENANCE 0 GENERAL AND ADMINISTRATIVE 0 INSURANCE 0 ROYALTY 0 DIRECT EXPENSES 0 OTHER EXPENSES LOAN PRINCIPAL 0 INTEREST 0 0 o °o TOTAL EXPENSES BREAKEVEN FUEL TO GEOTHERMAL COMPARISON GW HOURS SOLD FUEL ESCALATION RATE - 6.73% FUEL EXPENSES - MILLS/KWH 0 GEOTHERMAL EXPENSES - MILLS/ KWH 0. SAVINGS OF GEOTHERMAL PLANT 0.0 0.0 0.0 SAVINGS DISCOUNTED AT 10% 0.0 0.0 NET PRESENT VALUE OF SAVINGS 0.0 0.0 °o 10% DEBT 82-S TABLE 15, Cont. AUGUST 28, 1981 UNALASKA GEOTHERMAL ANALYSIS : FUEL TO GEOTHERMAL NET PRESENT VALUE COMPARISON $000 1990 1991 1992 1993 1994 1995 PRODUCTION : GWH PER YEAR 68 204 204 204 204 204 EXPENSES FOR 10 MEGAWATT POWER PLANT OPERATING AND MAINTENANCE 887 954 1,025 GENERAL AND ADMINISTRATIVE 89 95 103 INSURANCE 715 768 826 ROYALTY 3,590 3,860 4,149 DIRECT EXPENSES 5,281 5,677 6,103 OTHER EXPENSES LOAN PRINCIPAL 7,152 INTEREST 12,159 TOTAL EXPENSES 25,414 EXPENSES FOR 20 MEGAWATT POWER PLANT OPERATING AND MAINTENANCE 2,050 2,204 GENERAL AND ADMINISTRATIVE 205 220 INSURANCE 2,096 2,253 ROYALTY 8,298 8,920 DIRECT EXPENSES 12,649 13,598 OTHER EXPENSES LOAN PRINCIPAL 15,023 15,023 INTEREST 28,543 27,041 TOTAL EXPENSES 56,215 55,661 BREAKEVEN FUEL TO GEOTHERMAL COMPAR! SON GW HOURS SOLD 68 170 204 204 204 204 FUEL ESCALATION RATE - 6.73% FUEL EXPENSES - MILLS/KWH 239.1 255.2 272.3 290.7 310.2 331.1 GEOTHERMAL EXPENSES - MILLS/ KWH 382.7 485.5 400.1 396.2 392.7 389.8 SAVINGS OF GEOTHERMAL PLANT (143.6) (127.8) (105.5) (82.5) SAVINGS DISCOUNTED AT 10% (60.9) (88.8) (44.8) (33.6) (23.9) (15.5) NET PRESENT VALUE OF SAVINGS (270.9) (304.5) (328.4) (343.9) 10% DEBT 204 204 353.4 377.2 387.5 385.8 62-G TABLE 15, Cont. AUGUST 28, 1981 UNALASKA GEOTHERMAL ANALYSIS 10% DEBT FUEL TO GEOTHERMAL NET PRESENT VALUE COMPARISON $000 1998 1999 2000 PRODUCTION : GWH PER YEAR 204 204 EXPENSES FOR 10 MEGAWATT POWER PLANT OPERATING AND MAINTENANCE GENERAL AND ADMINISTRATIVE INSURANCE ROYALTY DIRECT EXPENSES OTHER EXPENSES LOAN PRINCIPAL INTEREST TOTAL EXPENSES EXPENSES FOR 20 MEGAWATT POWER PLANT OPERATING AND MAINTENANCE 3,401 3,656 GENERAL AND ADMINISTRATIVE 340 366 INSURANCE 3,477 3,738 ROYALTY 13,767 14,799 DIRECT EXPENSES 20,985 22,559 OTHER EXPENSES LOAN PRINCIPAL 15,023 15,023 INTEREST TOTAL EXPENSES BREAKEVEN FUEL TO GEOTHERMAL COMPAR! SON GW HOURS SOLD 204 FUEL ESCALATION RATE - 6.73% FUEL EXPENSES - MILLS/ KWH 402.6 GEOTHERMAL EXPENSES - MILLS/kWH 384.9 SAVINGS OF GEOTHERMAL PLANT 17.7 SAVINGS DISCOUNTED AT 10% 3. 8.1 12.0 NET PRESENT VALUE OF SAVINGS ’ 2001 2002 2003 1994 2005 15.3 18.0 20.3 22.1 23. (297.0) (276.7) (254.6) (230. O€-S AUGUST 28, 1981 , FUEL T 2006 PRODUCTION : GWH PER YEAR 204 EXPENSES FOR 10 MEGAWATT POWER PLANT OPERATING AND MAINTENANCE 2,821 GENERAL AND ADMINISTRATIVE 282 INSURANCE 2,274 ROYALTY 11,420 DIRECT EXPENSES 16,797 OTHER EXPENSES LOAN PRINCIPAL 7,152 INTEREST TOTAL EXPENSES EXPENSES FOR 20 MEGAWATT POWER PLANT OPERATING AND MAINTENANCE GENERAL AND ADMINISTRATIVE INSURANCE ROYALTY DIRECT EXPENSES OTHER EXPENSES LOAN PRINCIPAL INTEREST TOTAL EXPENSES BREAKEVEN FUEL TO GEOTHERMAL COMPARISON GW HOURS SOLD 204 FUEL ESCALATION RATE - 6.73% FUEL EXPENSES - MILLS/ KWH 677.8 GEOTHERMAL EXPENSES = MILLS/kWH 409.0 SAVINGS OF GEOTHERMAL PLANT 268.8 SAVINGS DISCOUNTED AT 10% 24.8 NET PRESENT VALUE OF SAVINGS (206.1) TABLE 15, Cont. UNALASKA GEOTHERMAL ANALYSIS © GEOTHERMAL NET PRESENT VALUE COMPARISON $000 2007 2008 2009 2010 2011 2012 204 204 204 204 204 204 25.7 26.4 29.2 29.0 33.0 31.9 10% DEBT T€-S TABLE 16 AUGUST 28, 1981 UNALASKA GEOTHERMAL ANALYSIS FUEL TO GEOTHERMAL NET PRESENT VALUE COMPARISON $000 1982 1983 1984 1985 PRODUCTION : GWH PER YEAR 0 0 0 0 EXPENSES FOR 30 MEGAWATT POWER PLANT OPERATING AND MAINTENANCE 0 0 0 0 GENERAL AND ADMINISTRATIVE 0 0 0 0 INSURANCE 0 0 0 0 ROYALTY 0 0 0 0 DIRECT EXPENSES 0 0 0 0 OTHER EXPENSES LOAN PRINCIPAL 0 ) ) 0 INTEREST 0 0 0 0 TOTAL EXPENSES 0 0 0 0 BREAKEVEN FUEL TO GEOTHERMAL COMPARISON GW HOURS SOLD 0 0 0 0 FUEL ESCALATION RATE - 3.04% FUEL EXPENSES - MILLS/ KWH 0.0 0.0 0.0 0.0 GEOTHERMAL EXPENSES - MILLS/KWH 0.0 0.0 0.0 0.0 SAVINGS OF GEOTHERMAL PLANT 0.0 0.0 SAVINGS DISCOUNTED AT 10% 0.0 0.0 NET PRESENT VALUE OF SAVINGS 0.0 0.0 10% DEBT 1988 1989 0 204 0 2,475 0 248 0 1,626 0 10,167 0 14,515 0 0 2€-S TABLE 16, Cont. AUGUST 28, 1981 UNALASKA GEOTHERMAL ANALYSIS 10% DEBT FUEL TO GEOTHERMAL NET PRESENT VALUE COMPARISON $000 1990 1991 1992 1993 1994 1995 1996 1997 PRODUCTION : GWH PER YEAR 204 204 204 204 204 204 204 204 EXPENSES FOR 30 MEGAWATT POWER PLANT OPERATING AND MAINTENANCE 2,661 2,861 3,075 3,306 GENERAL AND ADMINISTRATIVE 266 286 308 331 INSURANCE 1,747 1,879 2,019 2,171 ROYALTY 10,929 11,749 12,630 13,577 DIRECT EXPENSES 15,604 16,774 18,032 19,384 OTHER EXPENSES LOAN PRINCIPAL 13,732 13,732 INTEREST 23,345 21,972 TOTAL EXPENSES 55,109 55,088 BREAKEVEN FUEL TO GEOTHERMAL COMPARISON GW HOURS SOLD 204 204 204 204 204 FUEL ESCALATION RATE - 3.04% FUEL EXPENSES - MILLS/KWH 230.8 237.8 245.1 276.2 284.6 GEOTHERMAL EXPENSES - MILLS/KWH 2ri.t 270.7 270.1 272.9 275.0 SAVINGS OF GEOTHERMAL PLANT (40.9) (25.1) SAVINGS DISCOUNTED AT 10% (17.3) (12.7) (8.8) NET PRESENT VALUE OF SAVINGS (40.2) (52.9) (61.7) €€-G TABLE 16, Cont. AUGUST 28, 1981 UNALASKA GEOTHERMAL ANALYSIS FUEL TO GEOTHERMAL NET PRESENT VALUE COMPARISON $000 1998 1999 2000 2001 2002 2003 PRODUCTION : GWH PER YEAR 204 204 204 204 204 204 EXPENSES FOR 30 MEGAWATT POWER PLANT OPERATING AND MAINTENANCE 4,746 5,102 6,813 GENERAL AND ADMINISTRATIVE 475 510 681 INSURANCE 3,117 3,350 4,474 ROYALTY 19,492 20,954 27,983 DIRECT EXPENSES 27,829 29,916 39,952 OTHER EXPENSES LOAN PRINCIPAL 13,732 13,732 INTEREST 2 8,239 TOTAL EXPENSES 57,381 61,924 BREAKEVEN FUEL TO GEOTHERMAL COMPARISON GW HOURS SOLD 204 204 FUEL ESCALATION RATE - 3.04% FUEL EXPENSES = MILLS/KWH 293.3 340.7 GEOTHERMAL EXPENSES - MILLS/ KWH 277.8 303.5 37.1 SAVINGS OF GEOTHERMAL PLANT SAVINGS DISCOUNTED AT 10% 3.1 3.8 NET PRESENT VALUE OF SAVINGS (65.2) (61.4) 10% DEBT 1994 2005 204 204 7,324 7,874 732 787 4,810 5,170 30,082 32,338 42,948 46,169 13,732 13,732 6, 866 5,493 63,547 204 204 351.0 311.5 39.5 4.4 4.2 (39.1) (34.9) vE-S TABLE 16, Cont. AUGUST 28, 1981 UNALASKA GEOTHERMAL ANALYSIS 10% DEBT FUEL TO GEOTHERMAL *t PRESENT VALUE COMPARISON 000 2006 2007 2008 2009 2010 2011 2012 2013 PRODUCTION : GWH PER YEAR 204 204 204 204 204 204 204 204 EXPENSES FOR 30 MEGAWATT POWER PLANT OPERATING AND MAINTENANCE 9,099 9,781 10,515 11, 304 12,151 13,063 14,042 GENERAL AND ADMINISTRATIVE 910 978 1,051 1,130 1,215 1,306 1,404 INSURANCE 5,975 6,423 67905 73423 73980 83578 93221 ROYALTY 37,370 402173 437 186 465425 497907 537650 57,674 DIRECT EXPENSES 53, 354 57, 356 61, 658 66, 282 71, 253 76,597 82, 342 OTHER EXPENSES LOAN PRINCI PAL 13,732 13,732 0 0 0 0 0 INTEREST 2,746 1,373 0 0 0 0 0 TOTAL EXPENSES 69,833 72, 462 61,658 66, 282 71, 253 76,597 82, 342 BREAKEVEN FUEL TO GEOTHERMAL COMPARISON GW HOURS SOLD 204 204 204 204 204 204 204 204 FUEL ESCALATION RATE - 3.04% FUEL EXPENSES - MILLS/KWH 372.7 384.0 395.7 407.7 420.1 432.9 446.0 459.6 GEOTHERMAL EXPENSES - MILLS/KWH 330.8 342.3 355.2 302.2 324.9 349.3 375.5 403.6 SAVINGS OF GEOTHERMAL PLANT 41.7 40.5 105.5 SAVINGS DISCOUNTED AT 10% 3.9 3.5 3.1 7.3 6.0 4.8 3.7 2.7 2) (6.4) (2.7) (.0) NET PRESENT VALUE OF SAVINGS (31.1) (27.6) (24.5) (17.2) (11 The net annual (costs) or savings of providing power from the 30 MW geothermal power plant over the proposed combined system are shown in Table 16. The annual (costs) or savings are discounted at a rate of 10 percent beginning in 1982. The discounted values are then added together to yield an NPV. Results of the analysis indicate that if diesel fuel escalates at an annual rate above 3.04 percent then the discounted savings of ptoviding geothermal power would be greater than the discounted costs (NPV is positive). Therefore, the costs of providing geothermal power over the production life of the plant would be less than providing the equivalent amount of power with the combined system. 5-35 6. CONCLUSIONS An assessment of the available data on the geothermal resources at Summer Bay and Makushin Volcano on Unalaska Island indicate that there is a _ promising potential for economic geothermal energy development. Preliminary market and economic analyses indicate that the following applications could be feasible. 1. A salmon hatchery, utilizing 80 degree C geothermal fluids from the deeper Summer Bay resource. Harvest from a hatchery operation could yield first year (1986) revenues of at least $3 million dollars. The estimated internal rate of return for the system presented in this report is 16%. The hatchery could be combined with a fish farm to produce marketable fish and reduce the loss expected from releasing the finger] ings. This could increase annual revenues and provide a more efficient utilization of the land and energy resources committed to the project. 2. A greenhouse facility for the production of tomatoes at Summer Bay. The greenhouse could be heated with 50 degree C geothermal fluids from the shallow Summer Bay resource. Although the initial investment in a geothermal greenhouse would be greater than the investment in a comparable diesel greenhouse, the annual operating costs are estimated to be 40% less. The net present value of investing in a geothermal greenhouse rather than a diesel greenhouse is approximately $200,000. 3. A 10MWand a 20 MW geothermal power plant utilizing the Makushin Volcano resource. The two plants could meet 60% of Unalaska's projected electrical demand in the year 2000. The investment required to develop and operate these plants was analyzed based on the "avoided" diesel generating capacity. If diesel costs escalate at an annual rate over 6.73%, the costs of providing geothermal power would be Jess than the costs of an alternate diesel/gas turbine/hydro-electric system. The estimated geothermal power costs, including site access and logistics considerations, wellfield development, and remote construction factors, are approximately 400 mills/kwh for the life of the two plants, compared to an average diesel power cost of 545 mills/kwh over the same period. 4. A 30 MW geothermal power plant on Makushin using optimistic assumptions about the geothermal resource potential. The breakeven diesel cost escalation rate for this plant is 3.04 percent. The estimated average geothermal power costs over the life of the plant are 300 mills/kwh. It is important to note the significance of logistical factors in the cost of geothermal power on Unalaska. The estimated total access costs for the 10 MW and 20 MW plants analyzed in this report in 1981 dollars are $11,700,000, or nearly 7% of the total installed cost of the plants. If a single 30 MW plant were constructed, the access costs would be approximately $3,700,000. The high cost of logistics on Makushin make a major contribution to the economy of scale of geothermal power plants. 6-1 There is an excellent colocation between geothermal resource potential and energy demand on Unalaska. Projections of growth in this community indicate that there could be a severe energy shortage in the near future unless alternate energy resources are developed. Geothermal development for power generation and direct applications could alleviate some of Unalaska's future energy crisis. The most important consideration in fostering geothermal development on Unalaska is the need for further resource exploration. Geologic, hydrologic, and geophysical assessments need to be performed to develop reliable estimates of the resource potential at Summer Bay and Makushin Volcano and to confirm the existence of more extensive resources. 6-2 7. REFERENCES Bureau of Land Management, 1981. St. George Basin Petroleum Development euener los Local Socioeconomic Systems Analysis, OCS Technical Report o. 59. Careaga, R., Director of Planning, City of Unalaska, Communication with S. G. Spencer, 6/23/81. Drewes, H., G. D. Fraser, G. L. Snyder, and H. F. Barrett, 1961. Geology of Unalaska Island and Adjacent Insular Shelf, Aleutian Islands, Alaska, U.S. Geological Survey Bulletin 1028-5, p. 1439-1453. Hankford, S. M., and J. M. Hill, 1979. Stratigraphy and Depositional Environ- ment of the Dutch Harbor Member of the Unalaska Formation, Unalaska, Alaska, U. S. Geological Survey Bulletin 1457-B, p. B1-B14. Lewis, W. F., Executive Assistant, The Aleut Corporation, Communication with S. G. Spencer, 6/25/81. Morgan, L., editor, 1980. The Aleutians, Alaska Geographic, V. 7, No. 3. Motyka, R. J., M. A. Moorman, and S. A. Liss, in review. Assessment of Thermal Spring Sites Aleutian Arc, Atka Island to Decherof Lake, Preliminary Results and Evaluation, U.S. Geological Survey. Nebesky, W. E., and 0. S. Goldsmith, 1980. Economic Analysis of Demonstration Project Alternatives for the Pilgrim Springs Alaska Geothernal Site, Institute of Social and Economic Research, University of Alaska. Reeder, J. W., 1981 (draft). Preliminary Assessment of the Geothermal Resources of the Northern Part of Unalaska Island, Alaska, Alaska Department of Natural Resources. Reeder, J. W., P. L. Coonrod, N. J. Bragg, and D. R. Markle, 1980. Alaska Geothermal Implementation Plan, U.S. Department of Energy. Retherford, R. W. and Associates, 1979. City of Unalaska Electrification Study. White, Rich, 1979, Universal Seafoods, Communication with S. G. Spencer, 7/81. Cover design based on a photograph by Bob Bennett