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Geothermal Potential at Unalaska Abstract 1984
"BS.07.00GEOTHERMALPOTENTIALATUNALASKA ABSTRACT David Denig-ChakroffTheAlaskaPowerAuthority 334 W.5th Avenue Anchorage,Alaska 99501 In 1982,the Alaska Power Authority received a $5 million state appro- priation for geothermal exploration at Makushin Volcano on UnalaskaIsland.The appropriation was preceded by preliminary economic and resource evaluation of Unalaska's geothermal potential. Field work in 1982 included the drilling of three temperature gradient wells;the maximum temperature in the gradient wells exceeded 390°F. This:and other field data indicated the potential for a geothermal reservoir system within 4,000 feet of the surface.i The drilling of a confirmation well began in mid-June,1983.On Au- gust 25,1983,the drillers encountered a substantial geothermal re-source at 1,947 feet with a bottom hole temperature of 370°F.=Thereservoiriswaterdominatedwithasteamcap.The Power Authority fs optimistic about the commercial prospects of this discovery.The small-diameter exploration well produces 53,000 pounds of steam and hot water every hour and fs capable of generating 500 kilowatts of electric- ity.At this rate,larger production-size wells could be expected topreduce2substantiallygreateramountsofpower. Exploration at Makushin Volcano will continue this Spring and Summer. The objective of the 1984 field work fs to further delineate the extent of the reservoir.Proposals being considered include performing a 45 - day flow test and deepening the producing well,drilling another re- source confirmation well,and performing an electrical :resistivity survey of the area. The future of the project depends on economics.The Power Authority is performing a reconnaissance study to assess the power alternatives available to Unalaska including wind,diesel,hydroelectric,and geothermal.If geothermal shows high potential relative to the other alternatives in the reconnafssance study,the Power Authority can initiate a more detailed feasibility analysis of geothermal power development.If geothermal development proves feasible and if land status and financing issues can be resolved,Alaska could see its first geothermal power facility under construction before 1990. ZY-67-9) _ ; "-GEOTHERMAL ENERGY DEVELOPMENT ABSTRACT Donald R.Markle The Energy Company 334 E.2nd Avenue Anchorage,Alaska 99501 Geothermal Energy is defined as the earth's natural heat.Of the earth's total volume of more than one trillion cubic kilometers,al}but a relatively thin crust averaging 30 kilometers thick is extremely hot. The sources of this tremendous energy are radioactive decay,friction and pressure within the earth's interior.In areas where the earth's crust is weak or thin,geothermal energy may be manifested ifn hot springs,fumeroles,geysers and most dramatically as volcanoes. There are three primary types of geothermal resources:hydrothermal, hot dry rocks,and geopressured zones.Nearly all of the currently developed geothermal resources are hydrothermal systems,where naturally occurring ground water 1s heated at depth.These systems can be eithervapordominated(steam)or hot water dominated,depending on temperatureandpressure.The two other types of systems.are hot dry rock,which requires injecting water as a heat transfer medium,and geopressure zones,in which water {s trapped with natural gas at great depth where it is heated and pressurized. The cost of recovery of geothermal energy is directly related to its depth of production and proximity to use.The quality of the resource is of paramount concern once the initial feasibility 1s determined. The use of geothermal energy depends on the nature of the resource and the requirements of the recipient.Use is typically divided into two basic categories:electrical generation usually requiring temperatures in excess of 150°C;and direct use such as space heating.In many instances end uses can be combined,using both high temperature and lower temperature resources.Using the effluent of an electrical gen- eration facility to dry wood,and in turn using that effluent to heatwaterforfishfarmingisanexample. Alaska has a great deal of geothermal potential with 106 hot springs and 83 active volcanoes. |ae Br 07,oO}INTRODUCTION: A process has been developed using a spreadsheet programKnownasLotus1-2-3 which allows one to analyze the currentoperatingpractacesoftheCityofUnalaska's Electric Utility.Themodeldevelopedinthisstudyallowsonetoprojectfutureoperatingcostsunderdifferentscenarios.This method also gives us the Current cost data for rate structure preparation.The model was prepared in this manner to provide the City ofUnalaskawithalivingdocumentwhichcanbeusedasmanagementtooltomonitortheElectricSystem's operations. TABLE i OF ATING EXPENSE ACCOUNT ASS iTIGNS The upper table identifies the inflation rates used to trend upthepreviousyearsoperatinexpensesonTable6.The percentincreasesfortheyears1993,1398,and 2003 represent the compoundedpercentincreaseovertheS-year period. The bad debt expense is computed using the ratio of the previousyear's bad debt expense to the previous year's total operatingexpense,and therefor are trended fronm 1983 data.The fuel costs are computed using the most recent 1984 fuel costofSi.20/qal.The total fuel expense is computed using an assumedefficiencyfactorof10KWH/Gal in 1984,and 14 KWH/Gal in 1988,withthefactorbeinginterpolatedfortheyearsinbetween. The lower tabie identifies any large doilar additions toZingexpenseaccountsbeyondtheannualinflationfactor. rT TABLE ZA PLANT ACCOUNT ASSUMPTIONS The topmost section identifies the inflation rates used to trendupthepreviousyearsPlantaccounts.The second section identifiesthedollarsaddedtoplantresultingfromtheseinflationfactors.The third section identifies large dollar additions to plant duetoKnowniargedoliaradditions. The fourth section contains the total account balances as of the year end.The account balance includes the previous year's balanceplusplantadditionstromboththeinflateddollarafromsectiontwo and the large dollar additions from section three. TABLE 28 ("2 20 PLANT ALOLTIONS AND "SPORECIATION EXPENSE These tables track the account balances fl.each to the plantaccountsfromyeartoyear.For each category of plant ,thefollowinginformation18accumulated:the ending balance from thepreviousyeariscarriedforwardasthebeginningbalanceofthecurrentyear,total plant additions from table 2a are added to thebeginningaccountbalance,and plant retirements are subtracted fromthebeginningbalances.The plant retirements are the only numberainputinthispartoftheschedule. The depreciation expense is computed based on the plant balances,and the designated useful life as input.A half years depreciationistakenonbothplantadditionsandretirements. This tasie cor tes the projected totain rer of Customers Tor each rate class ,sed on several different iumptions.The first section identifies the projected annual percentincreaseofcustomersintheGS-1,and GS-2 rate classes.The projected rate is input in the far right column headed method.Thesecondsectionconvertsthepercentincreaseforthesetworateclassesintocustomernumbers. The third section identifies the number of additional customers in the large power rate class,interruptable power,heat recovery,and streetlights.The large power customers are computed from thedatatakenfromtable4, The fourth section has the projected total number of customersforeachrateclassbasedonthethreesectionsdiscussedabove. TABLE 5S PROJECT KILOWATT HOUR SALES This table computes the projected KWH sales by rate class,thesystemlineloss,purchased power,and total KWH needed to beproducedbythesystem.-The first section identifies the monthly KWH usage for theaverageconsumerbyrateclass.This monthly usage is input for1983and1988.The usage for the intervening years are interpolated.The usage for 1993,1998,and 2003 are the same as theusagefor1988.The monthly usage for the large power consumers isfortheexistingconsumersonly.Additional large power consumers areaddedusingthedirectKWHassignmentmethodasdiscussedbelow.The second section identifies the projected additional large powerandinterruptableconsumers-one line for each additional consumer.For large power consumers,this section identifies the monthly KWHusedbyeachconsumer.The additional interruptable consumers areidentifiedbytheirtotalannualKWHused. The third section (KWH sales)are computed from the statisticscompiledabove.The KWH sales to rate ciasses GS-1,GS-2,largepower,and streetliaqhts are computed from the projected totalconsumers(from table 3)for these rate classes,and their respectivemonthlyKWHusagesfromsectiononeonthistable:annual KWH sales =(number of customers)X (manthly KWH used per consumer?)XK (12 months). System iine losses(as a percent)are input for i983 and 1988,andinterpolatedfortheiterveningyearsaswasdoneinsectiononeabove.The system loss in KWH is added to the projected annual KWHsalestogetthetotalKWHrequiredbythesystem.Both components ofKWHpurchased,purchased power and co-generation,are input numbers.The total KWH purchased is subtracted from the total annual KWHrequiredbythesystemtocomputetheKWHrequiredtobeproduced by the City of Unalaska. DRA TABLE SB SYSTEM LOAD FACTORS This table identifies the Load Factors for each category ofdemandbyrateclass.: The load factors are input for 1983 and 1988.The load factorsfortheinterveningyearsareinterpolated.The load factors for1993,1998,and 2003 are the same as for 1988.This method is used for all rate classes.The selection of these input load factors arecriticaltotheaccuracyofthecompletemodel.Close attention should be paid to historic and current load factor information.Present data is dependent upon the iudgement of the rate designerinvolvedwiththisstudy.As the system matures more reliance can be put upon the historic data. TABLE SA SYSTEM DEMAND This table computes the total installed KW,the Alaska firmdemand,and three categories of demand-coincidental peak demand, non-coincidental peak demand,and average/excess demand-for each rateClass.From these data the system average demand,the system loadfactor,and the Electric System's Alaska firm capacity in excess ofthesystem's projected coincidental peak demand.The first section lists all the generation units by rated KW-onelineforeachunit.These are all input numbers.The Alaska firmcapacityiscomputedbythemodel:the largest generation unit issubtractedfromthetotalinstalledcapacity. The second section contains the computed demands for each rateclass.The three categories of demand are computed based on the loadfactorforeachcategoryfortherespectiverateclass(see tableSb),and the projected KWH sales for each rate class as projected ontable4.The total demand in each of the three categories are added at the bottom the this section. The third section computes the average demand of the system,thesystemloadfactor,and the Electric System's Alaska firm capacity inexcessofthesystem's projected coincidental peak demand.When thisexcessdemandbecomesneqative,the system should concider adding another generation unit. TABLE 6 OPERATING REVENUE This table adjusts the operating expenses during the test year,February 1983 to January 1984,for known changes in cperations,well as for the projected changes per table 1.The rate base computation is done in two steps:the workingcapitalcomponentiscomputed-normalized operating expenses lessdepreciationtimes45/365 days-and then added to the net utilityplant.The rate of return on the rate base is input.The returnratebaseiscomputedandaddedtothetotalnormalizedexpensesarriveattherevenuerequiredfromthesystem.From this it ispossibletodeduct"Other Electric Revenue"such as installation as on toa charges,pole rentals,etc to arrive at a Revenue Requirement fromElectricEnergy. TABLE 7 SUMMARIZ DATA FOR RATE DESIGN SCH.LES Tables 7 thru 10 constitute a system whereby all costs within thereturnrequirementareallocatedtospecific,predetermined classesofconsumers.The basis for the allocation process is derived fromthemanualpreparedbytheNationalAssociationofRegulatoryUtilityCommissioners.Within this manual many judgements are required.InthisstudythejudgementhasbeensuppliedbytheRateDesignConsultantParticipatinginthepreparationofthesefindings.These tables are constructed in a manner which allows the allocation of any single year's data produced by the previous 6tables.One can design rates for the future once any set ofconditionshasbeenfixed. 55,707.0)VEL DISCUSSION DRAFT CITY OF UNALASKA ELECTRICAL RATE AND LOAD PROJECTION STUDY NOVEMBER,1984 a Introduction: The accompanying Electrical Rate and Load projection Study was pre- pared pursuant to the request for proposal from the City of Unalaska dated November 16,1983. The City of Unalaska (City)is substantially expanding the electric distribution system and changing the power production facilities. This expansion allows the City's electric system to serve additional customers,some of whom have been providing for their own electrical needs.Associated with the system expansion,the City has incurred new debt.Accordingly,revision of the rates charged for electrical services are required in order to provide for the increase in depre- ciation and debt service relating to these new facilities. In addition to the above,the City desires a long-range planning guide in order to anticipate system requirements in the future and establish preliminary alternatives to meet those requirements. The computations presented with this report in tables 1 through 9 were processed on a model developed by Mr.Jim Patras of Arthur Young and Company and Mr.James R.Hendershot,Rate Consultant,using an elec- tronic spreadsheet program (Lotus 1-2-3).The purpose of developing the model are: e To process the information and assumptions required to pre- pare the accompanying report. e To provide the capability to respond instantly to any changes in assumptions or rate designs arising from the presentation of a draft report to the City Council and Management. e To provide a tool for future forecasting and rate deter- Mination as conditions and assumptions change. Exhibit I,Scopes of Services and Presentation,presents the seven tasks undertaken in this engagement.The underscored items represent increases in the scope of services not contemplated in the proposal to provide services submitted by Arthur Young. 2. SCOPE OF SERVICES AND PRESENTATION CITY OF UNALASKA ELECTRICAL RATE AND LOAD PROJECTION STUDY Analyze the service area and existing studies on demographics, economic,and energy use forecasts to estimate loads and peak demands the next twenty years on at least five year increments. Analyze the existing service area to determine the economic viabi- lity of system expansion to currently unserved consumers and thewillingnessofthosepotentialconsumerstopurchasepowerfrom the City including the rates that potential consumers would con- Sider economic and the amount and timing of potential purchase of electricity from the City. Analyze the service area with respect to existing electrical generation systems in order to determine cogeneration potential. Estimate the City's avoided costs (broken down into energy and capacity avoided costs)and provide an estimate of the value of cogenerated power to the City.Analyze the effect of the City'scogenerationpolicyordinanceontheeconomicsofcogenerated power and,if appropriate,make recommendations for revisions to the ordinance. Analyze the waste heat recovery potential for sale and consequent reduction of system operating costs. Analyze the existing City electrical system,planned upgrades, cogeneration potential,and waste heat recovery potential andprovideacapacityadditionplanandacapacityretirementplan. Determine the rate requirements necessary for operation,main- tenance and debt retirement. Analyze rate structure and load management alternatives based on the existing system,planned upgrades,and capacity addition and retirement plans in order to determine options that would levelize daily peak capacity demands and stabilize load factors. Provide the City of Unalaska with a written report that presents and discusses the data obtained,analyses performed and conclu- sions reached in items 1 through 6 above.The capacity addition plan and capacity retirement plan required in item 5 may be pro- vided in the form of a letter with supporting attachments. Presentations: The accompanying report is presented in the form corresponding to the services listed above and include topics aS appropriate to each task: Methodology Information services Reference to corresponding tables Model description Conclusion of responses the following TASK 1: Analyze the service area and existing studies on demographics,econo- mic,and energy use forecasts to estimate loads and peak demands over the next twenty years on at least five year increments. The methodology to develop future loads was to review February 1983 through 1984 (test year)sales statistics for number of customers, customer usage,and customer characteristics.Based on this infor- mation and discussions with the utility manager and the public works director,classes of consumers were determined and future growth rates were developed.These growth rates are reflected in the development of the following tables: PROJECTED NUMBER OF CUSTOMERS: Table 3,projected number of customers computes the projected total number of customers for each rate class,based on several assumptions. The first section identifies the projected annual percent increase of customers in the GS-1 (residential),and GS-2 (small commercial)rate classes.The list of existing consumers was ana- lyzed by the rate consultant and city employees.All identified commercial consumers were recorded in the GS-2 class in Table 3. The large power consumers are defined as customers with more than 7500 KWH use/month.At present there are three consumers that qualify as being in this class--the school,Alascom,and Carls. The projected assumed growth rate is input in the far right column headed "method." The second section of Table 3 converts the annual percent increase into the number of projected additional customers. The third section of Table 3 inputs the assumed number of addi- tional customers in the large power rate class,interruptable power,heat recovery,and streetlights.The large power customer additions are listed in Table 4 (See Task 2). The fourth section of Table 3 calculates the projected total number of customers for each rate class based on the three sec- tions discussed above. PROJECTED KWH SALES: In Table 4,projected KWH sales,average KWH used per month per customer reflected in the first column of the first section was determined from usage data from the test year.The 1988 usage reflects the assumed growth in customer monthly usage as deter- Mined through discussion with the utility manager.The inter- vening years are interpolated.Large power and interruptable loads were determined by review of the existing large loads that could be within the City's system.These potential customers were reviewed with City personnel and probable customers determined (See Task 2).The estimated loads of these probable customers were then input into section 2 of this table. The bottom half of this table is the calculated annual KWH sales based on the information in Table 3 and the top of Table 4. System line loss for 1983 was determined from historical data, assumed for 1988 and interpolated for the intervening years.The calculated result is the projected system KWH requirements. The KWH purchased section in this table has values of zero for all years and is included in the table only to provide an example of the capability of the model to incorporate future wholesale power suppliers or cogenerators,if any. SYSTEM DEMAND: The first section of Table 5A lists all the generation units by rated KW.It should be noted that the addition of the 1.4 MW unit and the 2-2.8 MW units were added at the direction of the utility Manager and represent planned on contemplated additions.The Alaska firm capacity is computed by the model.This computation is a measure of the generation capacity available to a utility if its largest generation unit should breakdown.This "worst case assumption"has proven to be a useful measure of available capa- city for Alaskan electric utilities because of the isolation in which many generation systems exist.The Alaska firm capacity is computed by summing the capacity of all generation units,then subtracting the largest unit's capacity. The second section contains the computed demands for each rate class.The three categories of demand are computed based on the estimated load factor for each demand category for each respective rate class (see Table 5B),and the projected KWH sales for each rate class as projected on Table 4.The total demand in each of the three categories is added at the bottom of this section. The third section computes the average demand of the system,the system load factor,and the system's Alaska firm capacity in excess of the system's projected coincidental peak demand.When this excess demand approaches zero,the system should consider adding another generation unit.This occurs in 1985.The KW capacity of any wholesale supplier or cogenerator has not been considered in this computation,although provision for a supplier of firm power could be readily added. SYSTEM LOAD FACTORS: Table 5B,System Load Factors,identifies the load factors for each category of demand by rate class. The load factors are input for 1983 and 1988.The load factors for the intervening years are interpolated.The load factors for 1993,1998,and 2003 are the same as for 1988.This method is used for all rate classes.The selection of these input load fac- tors are critical to the accuracy of the complete model.Close attention should be paid to historic and current load factor information.Present data are dependent upon the judgment of the rate designer involved with this study.As the system matures, more reliance can be put upon the available historic data. CONCLUSION: Based on this assumptions and factors as stated above,the system projected peak demands are as shown in Table 5A. TASK 2: Analyze the existing service area to determine the economic viability of system expansion to currently unserved consumers'and _the willingness of those potential consumers to purchase power from the City including the rates that potential consumers would consider eco- nomic and the amount and timing of potential purchase of electricity from the City. Through discussions with the utility manager and the public works director the following list of potential customers were identified. Based on assumed peaks and load factors as listed,annual KWH require- ments were calculated. Annual Load Projected Annual Customer Load Factor KW KWH Boat Harbor Firm 25%250 438,000 City Dock Firm 25%100 175,000 Airport Firm 50%75 295,650 UNISEA Interrupt 50%950 3,700,000 Process 10%.1,500 1,314,000 Standard Oil Interrupt 50%105 413,910 Eastpoint Sea Interrupt 20%100 131,000 Process 10%860 753,360 Pacific Pearl Interrupt 45%100 350,400 Process 10%570 499,320 Panama Marine Interrupt 45%100 350,400 Pan Alaska Interrupt 30%1,750 3,832,500 American Presid.Interrupt 45%120 420,480 Process 10%750 657,000 Sea Alaska Interrupt 50%150 591,300 Process 10%1,750 1,533,000 Strawberry Hill Firm 503%50 197,100 II -1 From discussion with the electric utility manager and the Director of Public Works,four of the above are considered to be potential custo- mers:the Boat Harbor,the City Dock,the Airport and the UNISEA System.These potential customers are shown joining the City's system in 1984 (the first three mentioned)and the UNISEA System in 1985 (Tables 3 and 4). The willingness of these potential customers to hook-up to the City's system and the rates that they might be willing to pay is dependent on several factors.Typically,a business that must provide its own power needs does not segregate its accounting for the related costs in a manner that will provide a true cost per KWH.In most cases,costs of labor,capital investment,maintenance,etc.,relating to self- generation are combined into other cost centers.In addition,the circumstances of each of these potential customers is,in all likeli- hood,different with respect to condition of equipment,capacity v/s needs,availability and quality of maintenance requirements and response to emergencies,etc.Therefore,each potential customer's concept of an attractive rate will differ.However,the rates offered should be cost based as is developed in the accompanying tables. There are,however,two incentives that should be considered by these potential customers: e Since certain utility costs are fixed,the costs per KWH decreases as KWH sales increase. e Establishment of an interruptable rate. The interruptable rate is discussed more fully in Task 6.Generally, such a rate recovers fuel cost,customer cost and a small return such as one or two cents per KWH.This type of arrangement should be attractive to the potential customer who has sized his equipment to handle his peak requirements but experiences periods of time that require self-generation at very inefficient load levels.Thus,the II -2 City could offer power during the low load level periods at attractive rates provided that these periods coincided with non-peaking periods on the City's system.The City would determine the periods of availa- bility of power under these rates and control the flow of power. II-3 TASK 3: Analyze the service area with respect to existing electrical genera- tion systems in order to determine cogeneration potential.Estimate the City's avoided costs (broken down into energy and capacity avoided costs)and provide an estimate of the value of cogenerated power to the City.Analyze the effect of the City's cogeneration policy ordi- nance on the economics of cogenerated power and,if appropriate,make recommendations for revisions to the ordinance. CONSIDERATIONS: The City's electric utility is not a regulated utility. Therefore,the order issued by the Alaska Public Utilities Commission pursuant to federal regulations (PURPA)relative to cogeneration are not requirements that the City needs to comply with.However,there may be advantages to the City of entering into cogeneration or power purchase agreements.There are several potential suppliers of power that will be within the City's distribution system when it is completed (see Task 2--interrup- table loads).In addition,it is our understanding that the City has been approached regarding purchasing power from a potential privately developed hydroelectric facility and a wind generation facility. There are numerous factors to be considered before entering into any agreement to purchase power.Among these are: e Firm power or interruptable e The timing of power availability,i.e.,at which points in the systems daily,monthly and annual load curves. e Can the City avoid the investment of adding more genera- tion capacity? Iti -l e Is the cogenerated power such that City equipment would be operated at inefficient loads? e Would the power be provided in such a manner that the City could overhaul or maintain their production units on a more frequent basis and thereby prolong their use- ful lives? e Responsibilities for safety requirements on suppliers facilities. e Is the pricing of such power of any advantage to the City and it's consumers? e Are there social or political considerations? e Long-term consideration of non-fossil fuel sources of energy. e Engineering standards. The primary considerations should be the engineering integrity of the system when and if any cogeneration is attached and the purchase power rate should not exceed the cost of power generated by the City's utility.The controlling document in this case should be standards which are to be developed by the Director of Public Works pursuant to ordinance No.82-84.Cogeneration offers made'to the City must be considered on a case by case basis and should include the analysis and advice of a qualified electrical engineer. In summary,appropriate cogeneration is a viable source of energy assuming it meets (1)engineering considerations and (2)economic considerations necessary to make it attractive.However,in no ITI -2 case should it be considered at the expense of he existing con- sumers if alternatives are available. AVOIDED COSTS: On August 20,1982,the Alaska Public Utilities Commission (APUC) in Docket U-81-35 Order No.5 adopted regulations to encourage the development of cogeneration and small power production in Alaska. The regulations,3AAC 50.750--3AAC 50.820 are used for the basis to compute avoided costs below and in the accompanying section relating to the City's Ordinance No.82-84. This section of this report addresses the purchase of non-firm power only.Non-firm power is defined in the regulation as electric power generated by the qualifying facility (OF)that is supplied to the electric utility in unpredictable quantities and at unscheduled times and intervals,and will enable the electric utility to avoid energy related costs.The regulations state the following: e For purchases from a qualifying facility which supplies non-firm power,rates shall be based on the cost of energy which the electric utility avoids by virtue of its interconnection with the qualifying facility. e Unless otherwise modified by the commission,avoided energy costs,expressed in cents per kilowatt-hour, shall be determined from the sum of fuel and variable Operation and maintenance expenses and/or the energy portion of purchased power expense for a 12-month period,approved by the commission,updated by sub- sequent fuel costs,divided by the number of kilowatt- hours sold for the same time period.Expenses')and III -3 kilowatt-hours sold associated with hydroelectric generation shall be specifically excluded from the com- putation of avoided energy costs. e Until such time as the OF's interconnected to a utility's system contribute ten percent of its total energy requirements,the Commission will allow,but not require a utility to set variable O &M expenses at zero.However,when the ten percent energy threshold has been reached,the utility will be required to reassess the extent to which variable O &M expenses are avoided by its purchase of energy from OF's and to recalculate its avoided cost.This approach recognizes that,given the size and operating conditions of Alaskan electric utilities,it is extremely unlikely that OF's will materially affect 0 &M costs until they contribute at least ten percent of a utility's total energy requirements.Therefore,it attempts to reduce the utilities'computational burden accordingly. According to the direction furnished in the above regulations and tariffs filed with and approved by the APUC relative to the purchase of non-firm power,the calculation of avoided energy costs is accomplished as follows: Current price of fuel x Fuel consumed previous 12 months KWH sold during the previous 12 months Note (1)KWH sold should be decreased for purchased KWH,if any. Note (2)Assumes avoided 0 &M at 0. Accordingly,the avoided energy cost for the City of Unalaska Electric Utility as of June30,1984 is: III -4 Fuel consumed during previous 12 months 287,884 gals. Latest fuel price x $.876 Cost of fuel $252,186 KWH sold during previous 12 months -2,858,222 Avoided energy costs per KWH Ss -0882 med Considering the substantial changes currently in process relative to the City's distribution and production systems along with the potential of substantially increasing the KWH sales,the avoided energy cost for non-firm power purchases should be expected to change significantly.Production efficiency and line losses will not be the same as indicated from historical statistics. Accordingly,statistics relative to KWH sales,fuel consumption gallonage and average fuel purchase price (for each respective month)should be maintained for each of the preceeding twelve months on a schedule which updates this informaiton monthly.The avoided energy cost can then be recalculated at any time.In addition,there are other uses for this schedule as mentioned further in this study. AVOIDED CAPACITY COSTS: Avoided capacity costs relate to purchases of firm power for base load or peaking purposes.Such purchases are usually based on long-term contracts which provide for demand guarantees and true- ups.Typically,the need or desirability to consider and/or enter into such contracts is based on system planning results in which load growths and capacity reserves are estimated.This planning process is complicated by uncertainty and technological constraints.Load growth may be slower or faster than expected leading to demand that is higher or lower than anticipated. Determination of target reserve capacity is extremely complex due III 5 to technological constraints such as fixed unit sizes,lead time requirements,and marketability of off-peak power. In considering the generation planning,three cases are likely: Case 1:The utility has a unit planned or under construction but has the ability to cancel the unit,defer the on-line date,or to alter the size of the unit by either down- sizing the unit or by selling or leasing part of the unit,as a result of the cogenerator's supply. Case 2:The utility has a unit under construction,but the unit cannot be altered or deferred. Case 3:The utility has an adequate supply of generation capacity now and for the foreseeable future. Combinations of these are possible,For example,a utility with one unit virtually completed and ready to go on-line and other units on the planning board would be a combination of Case 1 and Case 2. The results of Table 5A indicate that Case 3 is an accurate description of the City's electric utility.This comment, however,should be qualified for the following reasons: e The 1.4 MW unit is included in Table 5A (lot test unit). The unit has not been installed and costs for transpor- tation,installation,related equipment requirements, and purchase price at the end of the two year test period have not been provided by the City. e Additional capacity on Table 5A is reflected by the 2-2.8 MW units pursuant to instructions from City mana- III -6 gement.These units are apparently available at bargain purchase prices and it is anticipated that grant funds will be utilized to acquire,transport and install them. Accordingly,costs have not been included in the study to reflect depreciation or return. e The 600 KW unit purchased in 1984 and the 300 KW unit rebuilt in 1984 have not been installed but are included in Table 5A as available capacity. e Large power loads as listed in Task 2 may become firm power customers of the utility but have been included only to the extent shown in Task 2. To illustrate the estimated effect of adding all of the estimated loads listed at Task 2,graphs are prevented at appendix 4.It should be noted that significant excess capacity remains even after adding these loads assuming the capacity additions reflected in Table 5A. Typically,avoided capacity costs are computed based on the decreased revenue requirement resulting from avoided investment, carrying costs and operation and maintenance costs,including insurance.The computation is based on the estimated costs of a planned unit or a recently installed unit.Operation and main- tenance materials,are determined based on records maintained for specific units. Therefore,considering the above comments,the City has not pro- vided sufficient information to compute an estimated avoided capa- city cost.Technically,a unit financed entirely by grant funds would result in a zero avoided carrying costs.Only avoided Operation and maintenance costs would be considered in these cir- III -7 cumstances.Should the City desire a computation on a hypotheti- cal unit or on the basis of a planned unit not made known or on the 600 KW unit acquired in 1984 and not installed,then the following information or assumptions are required: KW rating Assumed annual operating percent Financing cost rate Return required if more than interest cost Annual operation and maintenance cost Insurance cost Estimated life Capitalized interest,if any Inflation rate The City is currently considering purchasing power from a proposed privately owned hydroelectric project.It does not appear to be economically appropriate to purchase such power as long as the City can provide its own capacity requirements through grant funds Or extremely low cost loan funds.However,the availability of such a long-term facility not subject to variations in costs relating to fossil fuels may be desirable should the present plans of the City not materialize as anticipated or alternate uses of grant funds be considered. In this case,several new issues are presented that will require the consulting services of our electrical engineer.These issues include: ®The avoided KW costs relating to hydro cogeneration are typically based on the estimated lowest KW available from the cogenerator.Possible variations might occur if the system peak period coincides with the hydro peak III -8 which is possible with the addition of significant fish processing loads. Should wind cogeneration be installed and situated to economically provide for excess power and power fluc- tuations utilization in pumping recycled water for hydro storage,the KW characteristics of the hydro will change. The term of a contract in this situation will probably encompass the life of at least two diesel units. Therefore,inflation factors would need to be estimated for replacement cost purposes. Determination of when a cogenerator begins to accrue or earn a capacity value.This can occur when the coge- nerator unit comes on line,or at a later date, depending on the utility's reliability level or the scheduled on-line date of the next available unit. The timing of payments determination,i.e.,on-line date On avoided planned unit on-line date results'in financing problems for the cogenerator relative to on- line date of the planned unit and discounted payments relative to the cogenerator on-line date. The payment pattern to the cogenerator can be based on either of the following: 1)Payments that reflect the avoided revenue requirement relating to the associated unit. This would result in decreasing payments over time to reflect decreasing interest costs. III -9 2)Any other payment pattern provided that the present value of the total payment stream is equal to the present value of the avoided cost stream over the life of the utility unit. There are several valid arguments for either of the above options. COGENERATION ORDINANCE: The Cogeneration Ordinance should address all of the provisions required by the APUC for cogeneration tariffs since both documents provide rates,rules and regulations to the general public,con- sumers and potential suppliers of power.Primarily,these requirements include: e Avoided energy cost rate stated in cents per KWH (non-firm power). e Notice that avoided cost will change with changes in fuel cost and generation efficiency. e Recovery of interconnection costs,if any. e Rates for sale of power to interconnected facilities including supplementary power,back-up power,main- tenance power,and interruptable power. e Disconnection rights. The above do not include regulations or rules relative to safety requirements since APUC felt that such rules needed to be deve- loped. The ordinance should also address purchases of firm power.This section should state that the purchased power rate shall be based III 10 on the costs of energy and capacity which the electric utility avoids by virtue of its interconnection with the qualifying faci- lity.Each proposed interconnection should be considered on a case by case basis and be subject to a negotiated contract. Attached as appendix 2 to this document is the cogeneration tariff of Kotzebue Electric Association to provide guidance to you for amending your ordinance.This tariff has the most provisions of all the tariffs reviewed.Included in appendix 2 is 3AAC 50.820 DEFINITIONS.These definitions should also be incorporated in the Ordinance for clarity.This can be done by reference,if desired. III -ll TASK 4: Analyze the waste heat recovery potential for sale and consequent reduction of system operating costs. The task does not consider existing heat recovery systems at Unalaska. It appears that in the new generation configuration the existing heating loads will be taken off the waste heat recovery system and replaced by direct fired boilers. Expenditures made to-date in preparation of heat recovery systems at the new generation site are approximately $280,000. Only one current site is ready to accept energy from heat recovery as primary source of heat--City Airport. ANALYSIS OF CURRENT SITE: To connect the Airport to the proposed new generation site would take about one-half mile of thermal insulated transmission piping to the site and an equal amount of return facility.If one used a conservative figure of $50/foot for the installed system one would find the cost to be $132,000.The current fuel consumption at the Airport Site is 23 gallons of fuel per day.Assuming fuel cost of $1 per gallon and no other cost reflected,the total savings would Only amount to $8,400 annually.There appears to be no justifica- tion to include this in a "feasibility study". ANALYSIS OF POTENTIAL SITES: Near Term Under present conditions,and with present generation sizes the only potential use for the in-place heat recovery materials would seem to be within the generation plant itself.From an economics standpoint the heat (BTU)output of the generation is not great enough to allow for the transmission to distant points. It does seem appropriate to use the heat at the generation site and if other uses of the building facilities which house the generators can be developed in a compatible manner,the City could expect to begin to recover some of the funds expended on the deve- lopment of the heat recovery system. Long Term With the system in-place the chances are good that the facilities will be available for use in adjacent camps,processing plants, and housing developments.However,with current generation sizing and loads and the cost of development of the outside facilities necessary to connect services of this type may not fit into the feasibility. There are potential uses for waste heat that can be developed to specifically fit the availability of heat at the site.This could be in the form of greenhouse facilities or some sort of heat pro- cess requiring temperatures in the 180 degree range. SOME NOTES OF CAUTION: The current heat recovery system in the City of Unalaska is an interesting case study.The idea of providing heat to the public buildings and the school fits well into the feasibility in the front end,however,as the system grew,the source and use deve- loped other problems such as noise which made the systems adjacent location unacceptable--one had to go.This situation is common in the history of heat recovery systems. IV -2 Another problem that seems to follow heat recovery development is that the heat load may grow faster than the demand for the product that produces the "waste heat."Because the heat delivery system is in place it then becomes tempting and in some cases necessary to supplement the "waste heat"with some type of direct fired system.This supplemental supply is much more expensive and the ability to recover these cost becomes a complex problem of setting the proper rate for the BTU's used -one can no longer say that they are "excess"and a fixed fee to cover the installation and operating cost will not do the trick of recovering the true cost. Metering BTU's and spreading variable (fuel)cost in some manner becomes necessary. SUMMARY: A qualitive analysis of the subject seems to indicate that the existing system should be restricted to on-site use as a source of heat.As the system matures and adjacent heat loads develop the system will be ready to meet the demands.Such loads should be assumed with caution.Considerable long term planning should go into may determination of connecting any heat load.Contractual arrangements should be developed to avoid situations wherein Supplemental heat requirements may become an issue. The hard data is not available to produce a quantitative analysis of the issue.At best,a complete feasibility study of further development should be prepared.This would require projections based on growth assumptions which have not been made available at this point. This study has taken into consideration the facts that are available and has made provision for incorporating any future pro- Iv -3 jections that may become available.Until a full blown feasibi- lity study is completed the question of the effect of the "waste heat"facilities on the overall Unalaska Electric Utility will have to be "best guess." At the present the "best guess"is the primary value of the "waste heat facilities"that are or may be put in place will assist only in the dispursement of the engine heat developed in the generation of electricity.The long run value may be that the system was developed with the idea of waste heat in mind. Iv-4 te TASK 5: Analyze the existing City electrical system,planned upgrades,coge- neration potential,and waste heat recovery potential and provide a Capacity addition plan and a capacity retirement plan.Determine the rate requirements necessary for operation,maintenance and debt retirement. PLANT CONSTRUCTION: The study consultants were provided a tour of the City's electri- cal facilities.The City is currently involved in extensive distribution system additions and the relocation of the power house. The costs for these projects were arrived at by examining expen- ditures to date,and expected additional costs to complete as pro- vided by the utility manager,and assumed to be placed in service as follows: 1984 -Primary line construction S$39,052 Secondary line construction 44,523 S$83,575 1985 -Substation construction 600,000 Distribution project 1,775,648 2,375,648 1985 -Power house renovation 676,599 Generation placement 90,017 Machinery and equipment 10,614 777,230 1984 Heat recovery system 334,141 Total known additions S 3,570,594 =_- PLANT ACCOUNT ASSUMPTIONS: The plant account assumptions are shown in Table 2A.The topmost section of this table identifies the assumed inflation rates used to trend up the previous years Plant balances.The second section identifies the dollars added to plant resulting from these infla- tion factors. The third section identifies large dollar additions to plant due to the known large dollar additions listed above.No distinction Or allocation was made between grant funds or borrowed funds (see Task 3 comments relating to generation additions). The fourth section contains the total account balances as of year end.The account balance includes the previous year's balance plus plant additions from both the inflated dollars from section two and the large dollar additions from section three. Streetlights and meter costs were estimated for beginning plant and reclassified from the distribution lines account. PLANT ADDITIONS AND DEPRECIATION EXPENSE: The plant additions and depreciation expense tables track the account balances for each to the plant accounts from year to year. For each category of plant,the following information is accumulated:the ending balance of the current year,total plant additions from Table 2A are added to the beginning account balance,and plant retirements are subtracted from the beginning balances.The plant retirements,if any,are the only amounts input in this part of the schedule.No retirements were assumed. The depreciation expense is computed based on the plant balances, and the designated useful life as input.A half years depre- ciation is taken on both plant additions and retirements. Note that depreciation expenses has been computed on all plant additions regardless of the sourceof financing.Accordingly,any plant additions financed by grants,if any,have also been included in this computation and in calculating revenue require- ments in Table 6,Operating Expenses and Revenue Requirement.The City may wish to account for depreciation on grant financed faci- lities as a reduction to the computed depreciation expense and thus,remove this cost from revenue requirements. LONG-TERM DEBT: The City's debt to the Alaska Power Authority (APA)related to the plant additions reflected herein is $1,810,486.This debt is repayable over a 20 year term including interest at the rate of 2% per annum commencing on the first day of the calendar year following completion of the project and annual =payments thereafter.However,an agreement dated November 30,1983 with APA provides for a repayment schedule that is contingent upon cer- tain occurances in future periods.Therefore a definite debt retirement schedule is not determinable.However,a level payment schedule would require approximately $110,700 in annual payments. Additional financing of $145,231 has been obtained from a bank which is repayable in monthly payments of $3,649 ($43,788 annually)including interest at the rate of 9.5%per annum and maturing in February 1988. One year's interest on these loans is calculated to be $47,947. RATE OF RETURN: The required return has been considered in the computation of forecasted revenue requirements in Table 6 in the following manners: te e Interest expense has been assumed to be the return com- ponent in the calculation of revenue requirements.This assumption is pursuant to the wishes of the City Council expressed at the presentation of a draft of this study. The draft study has used an 8%of rate base return. e Depreciation expense has been included in the study for all plant additions as stated earlier in this task. Since depreciation is a non-cash expense,its inclusions in the revenue requirements computation provides the cash resources to fund principal debt retirement. REVENUE REQUIREMENTS AND COST ALLOCATIONS: The operating expenses and rate of return are allocated to classed of consumers using the guidelines suggested by the cost allocation manual prepared by the National Association of Regulatory Utility Commissioners (NARUC).However,because the City's utility is not regulated by the Alaska Public Utility Commission,there are some discretionary changes that can be made by the City of Unalaska in determining the rates: e The individual operating expenses may be allocated to the individual customer classes on a different basis. e The rate of return may be set at another rate. The cost of service and revenue requirement schedules are biult up from the information in Table l. EXPENSE ASSUMPTIONS: the upper portion of Table 1,Expense Assumptions identified the inflation rates used to trend up the previous years operating Se expenses on Table 6 operating expense and revenue requirement. The percent increases for the years 1993,1998,and 2003 represent the compounded percent increase over the 5-year period. Note that the test year data in Table 6 reflects expenses for hte fiscal year ended June 30,1984.This information was updated subsequent to the draft presentation. The bad debt expense is computed using the ratio of the previous year's bad debt expense to the previous year's total operating expenses,and thereafter are trended from 1983 data. The fuel costs are computed using the most recent 1984 fuel cost available of .876¢/gal.This is projected to increase at a rate of 3%annually.The fule efficiency was determined to be 10 KWH/gal of fuel in 1983.This as held constant into 1984 and escalated up to 12 KWH/gal in 1988,and held constant after that. The fuel cost and fuel efficiency are used along with projected KWH produced (as computed in Table 4)to compute the projected annual fuel expense (on Table 6).Because this is a large com- ponent of total operating costs these parameters should be closely monitored. The lower of Table 1 identified any large dollar additions to these operating expense accounts beyond the annual inflation fac- tor.After discussion with the Electric Utility Manager and hte Public Works Director,the model factors in the wages for an addi- tional employee in hte generation facility in 1984,and then an additional employee in 1985.Given the assumed growth in the system,additional employees were projected for 1985 as follows: 1 full time Administrative Employee $35,000 1 part time meter reader S$6,000 Both sections of the table are used to project the future Operating costs in Table 6.Table 6,Operating Expenses,adjusts the operating expenses during the test year ended June 30,1984, for known changes in operations,as well as for the projected changes per Table l. RETURN ON RATE BASE: The return on rate base is the amount of interest expense as discussed under Task 3.the rate of return computes the return the City realizes on its investment in the electric facility, i.e.,the amount invested in plant as well as the cash needed for 45 days of working capital. The return on rate base is added to the normalized expenses to arrive at the total revenue required by the utility to finance day to day operations.From this required revenue the other electric revenue is backed out to arrive at the revenue required from the sale of energy to customers. The last two lines of Table 6,average costs/KWH and the percent increase/years,are memorandum entries only. SUMMARIZED DATA FOR MENU SCHEDULES: This table is just a summary of the information used in the rate design computations in Tables 8 and 10. PLANT &COST OF SERVICE ALLOCATION TABLES: These two tables allocate the Revenue Requirement to the rate classes as prescribed in the above mentioned NARUC manual.The intent of this allocation process is to assign the costs that were t incurred by the utility to that class of consumers that caused the utility to incur the costs.Or as the Alaska Public Utility Commission states the matter "the cost causer must be the cost payer." RATE DESIGN: This table uses the allocated revenue requirement to design the rates for each class.This table uses all the assumptions discussed above,and the usage statistics developed on all other schedules to compute the rates. Two versions of Table 10 are included in the study.The version for fiscal 1983 doesn't include any additional customers to the electric system.It represents what this rate should be,given the test year data and the known changes.The 1984 version shows what the rates should be if the additional customers noted on Tables 3 and 4,are added to the system. The customer charge is a monthly charge levied on all customers. It represents the fixed costs of reading meters,billing custo- mers,etc.that the utility will incur no matter how many addi- tional KWH are sold. The demand charge is a charge for each kilowatt used by large power consumers.Implementing this charge will require this class of customer to have demand meters rather than the current type of meters used.The demand charge is intended to send a price signal to these consumers that will encourage them to even out their demand for electricity on the City's electric system. The large difference in the electric rates between the two years is caused primarily by the three additional large power consumers ™ who would significantly increase the energy usage of the system. The model can be updated to reflect any changes in these critical assumptions. RATE DESIGN ALTERNATIVES: The model provides for the development of rates on any revenue requirement that is developed in Table 6,Operating Expenses for Rate Design.Alternatives to the suggested rate design are numerous and include the arbitrary shifting of costs from one class of consumer to others based on managements decisions.The model provides for this alternative in Table 10,Rate Design although it has not been used in this study and was not suggested at the presentation of the draft report.Alternative rate designs that might be appropriate in this system are as follows: Flat rate with no customers charge Flat rate with no distinction between customers classes A declining block rate structure with a customer charge A declining block rate structure with a minimum charge Block rate structures are typically developed from the results of bill frequency analyses which determine the historical usage pat- terns at various levels.The model provides a target monthly revenue per customer for each class in Table 10.The model will accomodate the insertion of any rate design and calculate the revenues result and compare it to the above mentioned target. In this study,the information and current factors were used to arrive at the rates reflected in Table 10. The magnitude of usage on this system suggests that the customer charge and single energy charge are appropriate.Declining block te rates are useful on systems which have high average usage by the residential class.This is not the case on this system and pro- bably will not be the case in the future due to the high cost of energy.The inclusion of a customer charge is appropriate in that it allows recovery of some of the utility's fixed costs regardless of usage. The recognition of rate classes in the rates is a step forward in providing equitable pricing to large users.These classes and the rate design suggested in this study,i.e.,a customer charge and single energy charge,reflect the preferred methodology of the Alaska Public Utility Commission. CONCLUSIONS -RATE REQUIREMENTS: Present Rates: The City's present retail rates are a flat KWH charge for all KWH's sold to all classes of consumers,While such a rate is easily administered and readily understood by the consumer,this type of rate does not reflect the cost causal relationship on encourage the usage characteristics desired by the utility. Basis for Recommendation: The Alaska Public Utilities Commission in Docket U-83-47 adopted regulations (3AAC 48.500--3AAC 48.560)relative to cost of service methodology and pricing objectives in the design of electric rates.The regulations and guidelines were incorporated in the accompanying study.The regulations relating to this case state: °Pricing objectives for pricing electricity are: 1)The cost causer should be the cost pager . 2)The revenue requirement or utility financial need objective ; 3)The equity objective which includes the fair- cost apportionment among customer classes 4)The conservation objective 5)The optional use objective which includes con- Sideration of efficiency The Commission has expressed its'preference of the three part rate as follows: fe)Customer charge .o)Flat energy charge fe)Demand charge (for customers over 7500 KWH/mo on 20 KW in 3 consecutive months) Recommendation: Based on the results of the accompanying study at Table 10,the rates that should be adopted to recover the revenue requirement for the test year ended June 30,1984 which reflects the sale of 3,698,796 KWH are as follows (rounded): Customer Energy Demand Charge Charge Charge Residential $17 29.2¢/KWH $0 Small Commercial S$25 23.3¢/KWH S$0 Large Power S$34 15.3¢/KWH S15/KW Street Lights s 0 20 .0¢/KWH $s 0 Interruptable S$0 15.3¢/KWH Ss 0 Heat Recovery $457 0 $0 Demand Ratchet 75% It should be noted that the KWH statistics furnished by the City indicate that KWH sales increased approximately 27%for the period January through June 1984 over the like period in 1983.Single this represents a substantial change and additional large power customers are now within the systems service area,it is recommend that the revenue requirement and the resulting effect on rates be redetermined at least on an annual basis. The City should also consider implementation of a fuel cost adjustment provision in its"rate ordinance.In a period of declining fuel prices,the utility overrecovers its revenue requirement and the reverse is true in a period of escalating fuel prices.The formula for computing this charge or credit is as follows: {¢/gal base cost]-[¢/gal current cost]=¢/KWH FCRA KWH sold per gallon of fuel based on a moving 12 month average Note:The revenue requirement determined herein is based on a fuel price of 87.6¢/gal (base cost). CAPACITY ADDITION PLAN: The first step in the process of the determination to add genera- tion capacity is to project future demand requirements and compare the result to available (and planned)firm demand capacity. This step is accomplished in the accompanying Table 5A.The results of the computations in Table 5A,given the planned addi- tion of 5.6 MW diesel generation (Currier letter 9/13/84)and load assumptions discussed in Task 1,indicate that additional genera- tion capacity will not be required through the year 2003,even if the test cat unit is removed from the system. v-1l The critical point with this schedule is the unknown existing at the time of conducting this study relative to the large potential customers available to the system.Providing full service to any of these potential customers not included in the assumptions at Task 2 could create significant variations in the results at Table 5A.A graphic comparisons is provided at appendix 3 to provide a "worse case scenario."Table 5A should be updated annually so as to incorporate changed conditions and current assumptions. CAPACITY RETIREMENT PLAN: A capacity retirement plan is a new term to the consultants involved in this.study.It is anticipated that such a plan involves the monitoring and recording of information relative to each production units efficiency performance,utilization,repair and maintenance performed and the related cost. It is assumed that,except for very large systems,a capacity retirement is an integral part of the capacity addition process. In this process,the statistical information listed above enters into the decision process relative to sizing of capacity additions other considerations may include: fe)Powerhouse space availability fe)Logistics .o)Salvage value,if any,of existing units fe)Physical depreciation v/s accounting depreciation CONCLUSION: In the City of Unalaska's case considering the present and near- term changes taking place in the system,the utility should adopt a format and procedures that will provide for the accumulation of the statistical date mentioned above and for summarizing these stat- istics into monthly reports. it.teTASK 6: Analyze rate structure and load management alternatives based on the existing system,planned upgrades,and capacity addition and retire- ment plans in order to determine options that would levelize daily peak capacity demands and stabilize load factors. RATE STRUCTURE ALTERNATIVE: Rate structure features that could be considered in an effort to levelize daily peak capacity demands and stabilize load factors include the following: e Time of day rates e Demand charge for large power customers e Interruptable rate TIME OF DAY RATES: Time of day rates could be a potential approach to levelizing daily peaks.However,the determination to utilize this type of rate should be based on historical daily load curve statistics. This information is not presently available.In addition,the substantial charges presently occuring with the City systems will, in all probability,have considerable effects on these daily sta- tistics had they been maintained.Therefore,it is recommended that a time of day rate not be considered until the system has Operated through a full years'operating cycle with daily load curve data accumulated. If this is to be considered in the future,metering should be developed now so that daily peak information could be taken on each class of service.This type of equipment will be expensive "oe but necessary if one is to prove up the need and correctiness or time of day rates. DEMAND CHARGES: Demand charges,for large power customers are considered to be an efficient and effective means to minimizing peak demands.This is accomplished by the installation of demand meters including a demand charge in the rates. The manner in which a demand charge accomplishes this goal is that a price signal is sent to the customer imposing large demands on the system.This becomes even more evident if an annual ratchet provision is included in the demand rate.The ratchet provision requires that the customer be billed each month for at least a percentage of the highest peak recorded on his meter during the proceeding 12 months (billed demand).Generally,the percentage is 70%to 80%and it is not out of the relm of possibility to impose a 100%ratchet where fixed costs are high,such as in this case. INTERRUPTABLE RATE: To optimize load factor stability,the City needs to encourage use of interruptable loads.There could be large loads as projected in the study at Task 2 or could be relatively (at some point) small loads such as controllable electric heat.However,it is not recommended that experiments into controllable electric heat made until the City's system is operated in a stabilized condition for a full year's operating cycle.Relatively small interruptable loads could also be established by in-line electric heaters on hydrophonic systems.This would require facilities investment by the utility (including a second meter)and dispatch control by VI -2 City personnel.For further information regarding these systems, see appendix 3--Paper prepared for the Alaska Power Authority by Robert Retherford,. The rate offered is generally established at an amount per KWH that recovers energy costs,customer costs,and a small return component.Typically,a demand component is not included.Such a rate would have to be attractive when compared to oil or other fuel in the area. The objective of this rate is to encourage customer use of the system to take advantage of existing capacity (and planned capacity)to maximize production efficiency.Control of usage under this rate is accomplished through dispatching by City per- sonnel or by contractual arrangement relating to specific periods of time. Inclusion of this type of rate in the City's ordinance of electric rates is recommended.The recommended KWH charge is included in the conclusion in Task 5. LOAD MANAGEMENT ALTERNATIVES: Load management alternatives relative to mechanical means,produc- tion unit sizing,etc.are subjects that are best addressed by electrical engineers and are not within the expertise of the con- sultants engaged in this study. Load management alternatives relating to cost driven techniques are addressed under the section entitled "Rate Structure Alternatives." GSALAOAH FLDT SYD EM: REVENUE REQUIREMENT PROJECTIONS 3 VA 6)6)TOBLE 1 EXPENSE ASSUMOTIONS tit 1383 1984 1385 1366 1387 1368 1993 1598 2e8e3 METHOD. EXPENSES-ANNUAL INFLATION RATES tts ADMIN &GENERAL-SALARIES ins 3 3 x)3 3 15.93 15,93 15,93 3 %/PERIGD PARTS-WAGES rt 3 Z 3 3 3 18.93 15.93 15.93 3 %/PERTOD CUSTOMER ACCOUNTS-BAD DEBTS tn NA NA Nf NG NO NA NA NA NA CUSTOMER ACCOUNTS-METER READING rn 3 3 3 2 3 13.92 15,93 15,93 3 4/PERTOD DISTRIBUTION-WASES .rs 3 3 3 3 3 15,33 15.33 15,93 3 X/SER1OD DISTRIBUTION-TOO_S &MATERIALS :rj 5 i 5 =27.63 27,63 27.63 =£/7ER]OD ENGINEERING IGUIP-WOGES :Z 2 3 2 Zz 15,93 15.93 15.93 3 X/PERTOD ENGINEERING EQUIP-DIESEL FUEL &PARTS :af 5 a)5 3 27.63 27.63 27.63 5 */PERIOD BENERA™LON-WAGES :Z 3 3 3 3 15,93 15.33 55,92 3 4/PERTOR GENERATION-OTHER SUPSLIES :5 se =5 3 27,63 £7.63 27.63 5 */PERIOD GENERATION-UTILITIES &CONTR,SERV,:7 7 7 7 7 49,25 42,26 40,26 7 */PERTOD GENERATION-MATERIOLS tht i i =i)3 27,63 27,63 27,63 ©%/PERTOD GENERATION-LESSED EGUIS.rhs 2 a @ z 7 @ 22 a,2 a,22 @ ¥/PERIOD GENERATION-AUTO PARTS,GAS &WAGES phi 4 &&4 4 21.67 21.67 21.67 4 */PERIOD HEAT RECOVERY tht 3 Z 3 3 3 15.93 15.93 15.93 3 4/PERIOD FUEL COSTS-$/GAL th 3 3 3 3 3 15.93 15.93 15.93 3 X/PERIOD PURCHASED POWER tf!2 rd 2 é 2 2.21 2,44 2.69 2 %/PERIOD TNSURANCE ti 4 4 rn 4 4 E1,67 é1.67 21.67 4 X/PERIODJBBTEHEEEHHHEISEBIEEHUBSEES :1383 1384 $385 1985 1987 1988 1993 1998 #23 EXPENSES-DIRECT DOLLAR ADDITIONS He ADMIN &GENERAL SALARIES :@ 35,tr Z g z z 2 z FRATS-WAGES rn @ 2 Pa a a a Pa 0 CUSTOMER ACCOUNTS-BSD DEBTS rt @ ?ra 2 z 2 z @ CUSTOMER ACCOUNTS-METER READING a 6,22 z 2 z a Q 2 DISTRIBUTION-WAGES 2 cy z é @ Q t a DISTRIBUTION-TOGLE &MATERIALS d Pg a a a @ rd a ENGINEERING EQUIP-WAGES z@ @ a @ z Py Pi ry ENGINEERING EGUIP-DIESZL FUEL &FARTS a @ Q @ Vg 4 t e GENERATION-WAGES 28,822 52,C22 'J ?2 g q 2 GENERATION-OTHER SUCRLIES tnt rg a @ %Pi a é Pd GENERATION-UTILITIES &CONTR,SERV.rts 2 a 2 g @ t e a GENERATION-MATERIALS tnt a a Q a 2 Q t a BENERATION-LEASED EQUID,?z @ @ 2 a 7 7d GENERATION-AUTG PARTS.GAS &WAGES tre 2 a @ @ @ ?2 a HEAT RECOVERY th z £2,028 @ 2 '7 t a v PURCHASED POWER CENTS /KwH gts 12.a8 13.@e 14,22 15,@2 15,2@ 16,#16,@2 16.02 TNSURANCE rit é ??a ')a z FUEL COSTS-$/58L , tres tc?teed i.e?Lai 1.35 ied 1,61 1.47 c.i? 12,5 th.?11.5 12,2 12.2 12.8 £2,@ INTERPOLOTED 1984-88FUELEFSECIENCY-HWH PACDUCED/GAL rt "Be UNALBSKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TEBLE 2A PLANT ACCOUNT ASSUMPTIONS 1983 1384 1935 1386 1987 yaa "ve Ae PLANT ACCOUNTS-TRENDED - GENERATION {i t i { LEAT FECDVERY 2 2 z é é i tes ee atts DISTRIBUTION LINES i i i ':i 5.12 5.12 5.1@ TRANSFOAMERS we (tl 16 6 17 4 4 2 13 14 METERS a a 32 19 32 13 14 :it 2 GENERAL PLANT Oo,Se \4 4 4 4 4 4 21.67 21.67 21,67 STREETLIGHTS Rs %4 4 4 4 4 4 £1.67 21,67 21,67 TRENDED $ADDITIONS i GENERATION @ 3755 3,733 3,831 3,869 3.928 20,132 21,159 22,238 HEAT RECOVERY 8 8831,41 1,429 1.458 1,487 7,893 8,714 3,621 DISTRIBUTION LINES @ 15,304 33,977 75,34!74,942 RSIS 465,747 572,162 =698,665TRANSFORMERS@1,714 1.578 1,856 1,653 1,787 12,664 13,373 16,676 METERS @ 138 171 182 152 146 136 114 96 GENERAL PLANT a @ 2,eee 2,268 2 163 4.250 23,939 29,125 35,435STREETLIGHTS2200i)216 225 234 1,318 1,603 1,351 PLANT ACCOUNT LARGE DOLLAR ADDITIONS BENERAT ION a e 2 e a a @ 2 2 HEAT RECOVERY @ 25,2e2 Q a e a a 2 @ DISTRIBUTION LINES @ 50.222 1,022,220 Q Q 2 a 2 a GENERAL PLANT ®@ 5a.eca 2 52,a¢a a a a g STREETLIGHTS a a 2 g 2 a ?@ a PLANT ACCOUNTS: GENERATION 375,509 375,509 379,264 383,056 =386,887 =394,756 =394,663 414,795 =435,954 =458,192HEATRECOVERY44,174 44,174 70,057 71,459 72,888 =74,345 =75,832 =83,725 «=92,439102,B80DISTRIBUTIONLINES441,532 (51,352)39182 95,486 1,939,463 2,014,883 2,089,745 2,172.250 2,636,827 3,208,169 3,906,834TRANSFORMERS38,046 38,045 33,762 ©41,33@ 43,186 44,839 46,626 =57,290 70,863 87,339 TERS a 45.352 46,350 46,545 46,719 45,839 7,049 47,195 47,331 47,446 47,54 GENERAL PLANT 2 2 50,002 52,002 =54,262 186243 112,493 134,432 163,55 198,992 STREETLIGHTS a 5,002 5.022 «5,208 5,48 5.624 5,B49 6,283 7,42%9,005 18,956 899,262 BF2,260 1,436,315 2,523,434 2,624,368 2,758,827 2,851,153 3,380,981 4,027,232 4,811,913CCUMULATEDDEPRECIATION57,725 134.856 257,720 409,364 =570,747 742,286 «=932,259 1,157,005 1.423,972 NET PLANT 841,524 1,361,453 2.281.726 2.615.¢S 2,188,08:2.128.857 2.448,7EZ 2,872,227 2,387.542 wed, FERTENT INCREASE PERCENT INCREASE 4 4 IN NON-CO DEMAND PEAK KWH SALES DEPRECIATION EXPENSE COMPUTATION UNALASKA GOWER SYSTEM REVENLE REQUIREMENT PAQJECTIONS TABLE 2B DcPRETIATION EXPENSE COMPUTATION USEFUL LIFE GENERATION PLENT B.S.Y. ADDITIONS RETIREMENTS PLANT BOLANCE £.2.Y¥.PLANT BRLANCE DEPRECIATION EXPENSE PB.O.Y.BALANCE ADDITIONS RETIAEMENTS HEAT RECOVERY PLANT BE.0.Y.PLANT BALANCE DOI TIONS RETLREMENTS £.0.Y.PLANT BALANCE DEPRECIATION EXPENSE B.QO.Y.BALANCE ADDITIONS RETIREMENTS &a.¥.BOLANCE DISTRIBUTION PLANT B.G.¥.PLANT BSLANCE ADDITIONS RET LREMENTS &.0.¥.PLANT BRLANCE DEPRECIATION EXPENSE B.0.Y.BALANCE ADDITIONS RETIREMENTS E.0.Y¥.BALANCE TRANSFORMER GLANT B.0.Y.PLAN”BALANCE ADDITIONS RETIROMENTS 1983 1984 1985 1986 1987 1988 1993 1998 2003 375.529 375.529 379,664 383.057 386,887 390.756 334,664 414,79 435,954 @ 3,755 3,793 3.83!3,863 3,528 20,132 21.159 22,238 Q @ 2 2 a 2 2 2 @ 275,529 379,264 383.057 386,087 390.756 394,664 414,796 435,954 458,192 15 YEARS 5,234 «25,034 28,294 25,537 25,792 26,e52 26,3!1 27,653 29,64 _Q 125 126 128 iga 530 67;75 Tat \a 2 2 z @ 2 2 2 2 25,034 25,159 Sas 25,65 £8,921 Ze,ig!26,592 £8,358 23,885 44,174 4,178 =7,RE7 71,453 72.888 Th,346 75,632 83.725 32,633 2 25,683 1.421 1,429 1.453 1,487 7,833 6,714 9,621 2 2 @ 2 2 a a ) 4,174 7257)71,459 72,838 74,346 73,832 83,725 92,439 122,62 £3 VEARS 4,417 4,417 7,006 7,146 7,289 7,435 7,583 B,373 9,244 @ 61,294 72 7!73 7%335 436 ABL z ?2 2 e a 2 a a 4,417 5,712 --7,@76 7,217 7,362 7,529 7,978 8,824 9,725 392,322 292,332 995,636 1,939,613 2,014,954 2,039.895 2,172,412 2,636,157 3,228,319 2 $15,324 1.223.977 75,341 74,342 B2.5:5 465,747 572.352 698,665 2 2 2 a Q )z Q 3 390,352 905,626 1,939,512 2,014,954 2,038,895 2,i724i2 2,636,157 3,228,319 3,926,984 2 YEA33 13.557 19517 45,288 96.981 122.743 124,495 108,5el 131,808 «160,416 @ 12,883 £5,843 1,884 1,874 2,013 11,644 14,324 17,467 z 2 @ @ @ a a @ @ 13517 32,399 71,131 98,864 122,621 106,523 120,154 146,112 177,883 3,245 28,245 39,752 41,350 43,135 44,840 45,626 £7,232 78,663 @ 4.714 $578 1,656 1,653 1,787 10,664 13,373 {6.676 2 Q @ z ?@ a 0 ? /¥LAGRG POWER SYSTEM _REVENDE REGUTREMENT PRIVECTIONS TABLE 20 SISSECISTLON EXSENST COMPUTATTEN CAT IALED) USEFUL LIFE 13823 1384 1388 1386 13997 2389 £993 1999 eeez METESS iad no oo Bod.Y,SLANT BALANCE £6,ct®45,788 52 45,569 46,743 46,433 £7,245 47.194 47,038 ADDITIONS @ 198 7h 18a 15a 146 136 114 FE; RETTSE*ENTS z g @ @ @ #a 3 a 2.0.¥.ONT BOLANCE 45.222 46.298 46,569 46,769 45,879 47,245 47,104 87,236 47,391 DEPRETIETION EXPENSE 12 YEORS B.0.Y.PALANCE 4.822 4,4%4,637 4,675 4,60 4,725 4,718 4,730 ADDITIONS it 3 3 8 7 7 6 5 RETIREMENTS @ a rd @ @ @ e Q E.o0.¥.BALANCE 4,632 4,648 4.565 S682 4.097 aT 4,76 4,734 GENERAL PLANT B.0.Y.@ 2 «5a,828 52,222 34,@82 $06,243 11,493 134,432 163,557 ADDITIONS 52,820 2,222 2,Be Se,163 8,258 23,939 29,125 35,435 SETI REMEN e@ @ a a @ Q @ &.0.¥.Puna?BALANCE a 2,828 2,2AM 34,O88 186,€43 112,693 134,432 163,557 198,992 DEPRECIATION EXPENSE B.0.¥.BALANCE S YEARS a @ 12,Ge 12,4828 $8,B16 21,269 22,099 26,886 32,711 ADDITIONS Q 5,OC?2ee 2@8 5,216 425 2,394 2,912 3,343 RETIREMENTS a a (4 @ 8 a 4 zg 8 E.0.Y.BOLANCE @ 5.23@ =18,288 10,688 16,032 21,674 24,492 29,793 36,255 STREET LIGHTS B.0,Y.PLANT BALANCE =,28@ 5,228 5,288 5,488 5.4c4 =,649 6,833 7,42!9,@2E ADDI"TONS a 2ed 2e8 216 225 c34 1.318 4,683 1.954 RETIREMENTS @ a a 8 a @ a a @ E.G.¥.PLANT BALANCE 5,022 5,22a 5,488 5,624 5.849 6,083 7AM 9,@25 12,956 DEPRECIOTION EXPENSE BE,0,¥.BALQNCE Va VEAAS a5g 533 347 38.BE wR ate 493 6ze ADDITIONS a 7 7 7 7 8 44 53 65 RETIREMENTS a e (7 a @ @ e@ Q a Ef.¥.BALANCE 232 J4e Be 368 282 238 449 347 665 TOTAL PLANT BALANCES BO.Y.PLANT BALANCE 839,261 699.261 1,496,516 2,539,435 2.624.569 ¢.758,828 2,851,154 3,988,982 4,827,223 ADDITIONS @ S97.055 1.043119 B4,933 134,460 92,326 523,828 646,231 784,681 RETIREMENTS @ 4 g a a @ Q Q a &0.¥.PLANT BALANCE 899.251 1,496,316 2.533,435 2,626,369 2,758.88 2,851,154 3,388,982 4,027,253 4,B11,914 TOTAL DEPRECIATION EXPENSE B.0.Y.BALANCE 57,726 57,726 3 996,534 149,214 134,013 168,792 174,266 285,668 243,B31 ADDITIONS Q 13,404 =26,348 2,488 7,383 2,747 15,687 19,085 23,136 RETIREMENTS @ @ @ a a @ Q 8 @ -.9,¥.BALANCE 37,726 9 77,230 ide,B74 151,614 161,483 74,23 189,973 £24,746 266,67 UNALASHA ROWE?SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE 3 PROJECTED CUSTOMER NUMBERS 1983 1984 1985 1986 1987 1388 1993 1998 eee METHOD. #OF CUSTOMERS-TRENDED (%INCREASE) GS-1 4 4 4 4 4 4 21.67 21.67 e1.67 4 ¥/PERIOD 65-2 3 3 3 3 3 3 15.93 15.93 15.93 3 ¥/PERTOD Le N/A N/A N/A N/A N/A N/A N/A N/A N/A INTERRUPTABLE N/A N/A N/A N/A N/A N/A N/A N/A N/A HEAT RECOVERY N/A N/A N/A N/A N/A N/Q N/A N/A N/A STREETLIGHTS N/A N/A N/A N/A N/A N/A N/A N/A N/A #OF CUSTOMERS-NUMBER OF ADDITIONAL CUSTOMERS (FROM %INCREASE) 65-1 N/A il le fé i2 13 73 83 188 &S-2 N/A 1 i 1 i 1 3 6 7 ww ™we N/A N/9 N/a N/A N/A N/Q N/A N/A N/A %ao INTERRUPTABLE N/A N/A N/A N/A N/A N/A N/A N/A N/A EA REAT RECOVERY N/A N/A N/O N/O No NID N/O N/A N/R ; STREETLIGHTS N/A N/A N/A N/A N/a N/A N/A N/A N/A TOTAL N/Q ie 12 13 13 i4 78 95 415 NUMBER OF ADDITIONAL CUSTOMERS (LARGE ADDITIONS) 65-1 N/B @ @ @ 2 g e e @ GS-2 N/R a a a @ 2 z Q 8 iP 8 é i i e @ @ 8 @ INTERRUPTABLE r g |i i i @ a 8 HEAT 3ECOVERY N/A a @ 3 @ a @ @ a STREETLIGHTS N/A @ Q 3 @ a Q 8 @ TOTAL N/O @ @ 2 a Q 2 ¢2 TOTAL CUSTOMERS fore G5 1 e77 268 220 sie 324 337 41Q 499 627 65-2 e7 28 29 20 31 32 37 43 58 LP 3 3 6 7 7 7 7 7 7 INTERRUPTABLE a a i z 3 4 4 4 4 HEAT RECOVERY i {l :1 i i 1 STREETLIGH?S i 1 i 1 1 i ii TOTAL akg 323 238 KR 367 382 462 559 672 CONSUMER KWH USAGE/MONTH ADDITNL LARGE POWER CONSUMERS (FIRM)KWH/MONTH ADDITIONAL INTERRUPTABLE LOADS (ANNUAL KiH) KWH SALES UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS _TABLE 4 PROJECTED KWH SALES 1983 1985 1985 1986 1987 1988 1993 1998 2003 GS-1 46g 462 4a 526 528 55¢55@ 550 558 INTERPOLATED 1384-88 68-2 1,104 =1,383 1,662 1,942 2,221 2,508 2,520 2,500 2,50@ INTERPOLATED 1984-88Lp14,521 15,617 16,713 «17,808 =18,924 «=20,222)2802 )=-28,AR =A,MAM INTERPOLATED 1984-88 HEAT RECOVERY a Q 8 @ a 8 a a @ INTERPOLATED 1984-88 STREETLIGHTS 2,500 2,702 2,928 3,108 3,322 3,502 3,580 3,50@ 3,50@ INTERPOLATED 1984-88 A ---2.002 22,502 BE,ARD Ss 27,5U]RCD 20,ORS 30,022 30,000 B f Oh cn A c Raft fe {2,002 «13,333 «16,667 28,0020,0AD 2A 20,RR D i 52,20 «55,022 GRAD GB,PAD GN,RDD 0,RA TOTAL NeW LARGE POWER Kiii/MONTH 2 40,022 «55,222 «113,333 «126.667 140,022 142,022 =140,08]140,088 A 102,222 «116,667 «133,333 «152,202 =150,080 =«158,88e «152,ae B 102,002 «125,822 =150,020 =152,002 =158,028 158,00 c 102,220 «152,022 150,029 =150,088 =150,008 D 158,0@@ ©158,022 «158,008 =--152,8e@ TOTAL INTERRUPTABLE KWH @ @ 128,002 216,667 358,233 BCA,OREM,AP =A,AR =0D,282 63-1 1,452,560 1,596,672 1,742,422 1,894,464 2,052,854 2,224,20@ 2,726,000 3,293,400 4,206,20068-2 357,695 454,755 578,515 638,976 826,138 HER AAD «1,112,022 1,292 ke 1,502,00 LP 522,756 1,042,205 1,261,654 2,001,102 2,200,551 2,400,002 2,402,020 2,482,000 2,400,000INTERRUPT.a @ 102,000 216,667 358,333 «600,AND GAA)GOA,AUG 6NM,AS HEAT RECOVERY a @ a @ ®8 @ a ) STREETLIGHTS 30,020 32,400 34,822 =37,200 «39,602 42,000 20RD 42,0 KWH-TOTAL SALES 2,373,012 3,136,032 3,717,369 4,848,409 5,477,485 6,226,202 6,858,000 7,625,402 8,548,208 SYSTEM LOSS (x)17.92 15.94 «=«13.95 11.97 9.38 8.2 8,80 8.08 8.@@ INTERPOLATED 1984-88 SYSTEM LOSS (KWH)518,084 594,497 602,742 659,144 607,528 541,403 596,348 =663,878 743,222 KWH REQUIRED BY SYSTEM 2,891,096 3,730,529 4.390,111 5,587,553 6,085,014 6,767,689 7,454,348 8,288,478 9,291,522 KWH PURCHASED PURCHASED POWER @ @ @ @ @ 4,002,222 5,000,020 6,080,008 8,A,208CO-GENERAT ION a @ @ @ g 2 a a @ TOTAL KWH PURCHASED @ a a @ ®4,002,0¢@ 5,020,200 6,002,000 8,600,ere KWH PRODUCED 2,891,096 3,730,529 4,320,111 5,527,553 6,085,014 2,767,629 2,454,348 2,288,478 1,291,522 UNALASKA PIES SoSTEM REVENUE REQUIREYENT CROLSTTI TABLE SA SYSTEM NEMAND ONS oEMOND 1982 324 38S 385 er a i955 333 ries INSTALLED Mw (SYSTEM)UNITE EN E82 eee Se?bee 67t 6a?see £02 uNIT 2 6a?622 6R2 bea 5e2 fea ote fee 6a UNIT 3 682 £29 eee £22 622 are bee 523 622 UNIT &30a 22 32 sea see cea 30?wee 2a UNIT 5 UNIT 6 UNIT 7 UNIT 8 TOTAL INSTALLED CAPNCITY 2,182 2,182 2.182 E10 2,228 z,122 2,188 2,108 LESS :LARSES?UNIT {682)622)(E20)fade)(G22)i622)520)(628) ALASKA FIRM CAPACITY i,ce?18?5,cee i.528 1.5¢2 1,5?£58 1,502 KW GS-1 572 585 ro 617 635 TIE 948 1,143 f 3 324 829 B22 B37 646 1,022 4253 i65e8 AVERAGE /EXCESS 658 sre EAG e358 mW 72S 833 ee)1,227 KW 65-2 COINCIDENT PEAK 27 142 362 495 213 244 e62 3e7 381 NGN-COINCIDENT PEAK OF CASS 163 a9 a3 235 es 274 a7 368 428 AVERAGE /EXCESS 136 $62 189 213 )esa 298 346 483 Hw-LORGE POWER COINCIDENT Fees 249 283 327 437 S23 548 546 548 548 NON-COINCIDENT DEAK OF CLASS 199 372 4c 635 661 685 685 685 665 AVERAGE /EXCES!i7t see 369 S57 584 689 609 609 629 KE INTERPTABLE COINCIDENT PEAK Q ?it es "1 66 68 $e 68 NON-COINCISENT PEAK z @ il 25 4 68 68 58 £8 AVERAGE /EXCESS a 3 i es 4 68 La)68 68 KW-HEAT RECOVERY COINCIDENT PEAX Q a a @ 8 a Q Q 8 NON-COINCIDENT PEAK Q @ @ 3 Q 'a 2 @ a AVERAGE /EXCESS a a 8 @ 8 Q @ a @ KW-STREETL IGHTS COINCIDENT PEAK 7 7 §8 3 if i i@ 12 NON-COINCIDENT FEAK a 8 8 3 3 1@ 1@ 1@ 1a AVERAGE /EXCESS 7 8 8 9 3 ia $e 1@ 1@ KW SUM COINCIDENT PEAK Beg 1,004 4,1@t 1,328 1,489 1,524 1.56¢1,893 e.15e NON-COINCIOENT PEP 2.225 26338 36485 1.725 1.523 1.863 c.it &.384 2.716 AVERAGE /EXCESS 382 1.158 ne G82 Loa 1.582 1878 20858 2,128 2,336 SYSTEM AVERAGE DEMAND 27h 386 424 583 625 Tih 783 878 976 SYSTEM LORD FACTOR 32.7%35,7%29,54%4.8%44.4%47,2%46,&%46,a%45,4% ALASKA FIRM LESS TOTAL COINCIDENT PERK 671 496 393 i785 31 (4)(162)(333)(652) UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE 5B SYSTEM LOAD FACTORS SYSTEM LOAD FACTOR GS-1 COINCIDENT PEAK NON-COINCIDENT PEAK AVERAGE/EXCESS 65-2 COINCIDENT PEAK NON-COINCIDENT PEAK AVERASE/EXCESS LP COINCIDENT PERK NON-COINCIDENT PEAK AVERAGE /EXCESS INTERRUPT ABLE COINCIDENT FEAK NON-COINCIDENT PEAK AVERAGE/EXCESS HEAT RECOVERY COINCIDENT PEAK NON-COINCIDENT PEAK AVERASE/EXCESS STREETLIGHTS COINCIDENT PEAK NON-COINCIDENT PERK AVERAGE/EXCESS anenenifA8 40 INTERPOLATED 1984-68 3@ INTERPOLATED 1984-68 35 INTERPOLATED 1984-88 45 INTERPOLATED 1984-88 49 INTERPOLATED 1984-88 43 INTERPOLATED 1984-88 S@ INTERPOLATED 1984-88 4Q INTERPOLATED 1984-88 45 INTERPOLATED 1984-88 10@ INTERPOLATED 1984-88 {@@ INTERPOLATED 1984-88 1@@ INTERPOLATED 1984-88 1,8@@,6@@ INTERPOLATED 1964-88 1,@0@,@@@ INTERPOLATED 1964-88 1,000,@@@ INTERPOLATED 1984-88 S@ INTERPOLATED 1984-88 5@ INTERPOLATED 1984-88 1983 1984 1985 1986 1987 1988 1993 1998 2083 38 32 34 36 38 4Q 48 49 2e 22 24 Fats 26 2 38 38 rote e7 £3 31 33 35 35 35 35 37 33 4l 45 45 45 25 28 31 34 37 48 4a 4 38 33 33 38 4a 43 43 43 4@ 42 44 46 48 oe oe 38 38 3e 34 36 38 4a 4Q 40 35 37 39 43 43 45 45 45 122 1828 122 120 128 100 182 102 108 120 1&2 {ed 188 188 122 188 108 128 182 128 128 1a 108 1088 1,020,072 1,000,200 1,020,022 1,000,222 1,020,000 1,020,008 1,020,220 1,000,900 1,022,220 1,000,052 1,008,030 1,002,022 1,202,028 1,088,022 1,822,082 1,282,202 1,O22,222 1,022,000 1,022,028 1,022,020 1,C02,822 1.000,008 1,000,902 1,000,022 oe ve i 5@ Hi"oe oe 38 45 46 47 48 49 se 58 38 48 48 49 49 30 58 58 oe o@ INTERPOLATED 1984-88 UNDLASKA POWER SYSTEM REVENUE REQUTREMENT PROJECTIONS "TABLE &GPERATING REVENLE PER GL NORMALIZED TEST VEAR ADJUSTMENT REFERENZTE TEST YEAR $383 1363 1984 1963 1386 1987 1988 1993 1938 Far COST OF SERVICE:. ADMIN &GENERAL -SALARIES 221,251 cel.col 227,889 =269.725 277,817 206,151 £34,736 341,688 3%,181 409,189 PARTS-WAGES 16,295 9,185 Ni 25,480 =e644 27,O32 27,843 28,678 £3,538 34,243 39,637 46,028 CUSTOME?ACCOUNTS-BAD DEBTS 5,981 5,98!6,585 7,221 8,389 9,382 12.516 41,572 12,726 13,991 CUSTOMER ACCOUNTS-METER READINGS 3,268 3,262 3,358 3,459 9,742 18,@35 1@,336 11,982 13,898 16,183 DISTREBUTION-WAGES 24,758 36,638 N4 63,448 65,543 67,383 69,323 Tt,482 73,544 85,258 98,837 114,588 DISTRIBUTION-TOOLS &MATERIALS 13,517 13,517 14,193 14,#2 15,648 16,438 17,251 22,818 28,1@1 35,865 ENGINEERING EQUIP-WAGES 12,258 12,258 12,6e6 =13,885 13,395 43,7%14,218 16,474 19,@98 22,139 ENG.EQUIP-DIESEL FUEL &PARTS 2,632 2,632 2,764 2,We 3,047 3,199 3,359 4,287 5,472 6,983 GENERATION-WAGES 57,154 4,497 61,651 93,501 126,386 130,095 133,9398 138,017 162,028 185,484 215,827 GENERATION-OTHER SUPPLIES 19,668 13,668 20,651 21.684 22,768 23,87 25,182 32,037 40,888 Se,185 GENERATION-UTILITIES &CONTR.SERV.14,469 5,G22 19,469 8,32 d2,298 23,852 25,528 27,36 38,298 53,716 73,339 GENERAT ION-MATERTALS 25,838 25,638 27,122 =28,478 29,WH 31,397 32,966 42,074 53,699 68,535 GENERATION-AUTO PARTS,GAS &WAGES 14,267 14,267 =14,838 15,431 16,048 16,698 17,358 21,119 25,694 31,eb! HEAT RECOVERY 8 8 @ 18,088 10,388 10,689 18,927 12,668 14,685 47,024 FUEL COSTS 282,353 24,BE3 307,216 461,093 523,795 636,537 714,651 320,842 329,B44 356,537 233,263 PURCHASED POWER 8 @ Q 8 Q @ 640,200 88,020 962,088 =1,284,BBO DEPRECIATION:GENERATION 74,671 25.034 825,159 925,411 25,665 25,921 26,181 26,982 28,358 29,885 HEAT RECOVERY 8 4,417 5,7i2 7,076 7,217 7,Se 7,389 7,978 8,608 9,725 DISTRIBUTION LINES 9 19,517 32,399 71,131 98,864 102,621 106,508 122,164 146,Li2 177,883 TRANSFORMERS/METERS @ 8.425 8,See 8,783 8,892 9,984 9,271 9,907 1k,122 12,634 GENERAL PLANT 8 e 5,082 =18,288 18,608 16,32 21,674 24,492 29,799 36,255 OTHER EDUIPMENT 8 333 se 354 368 we 398 449 547 665 INSURANCE @ 5,188 N3 5.128 5,304 5,516 5,737 5,966 6,285 7,549 9,185 {1,175 TOTAL COST OF SERVICE 788,356 858,746 1,079,391 1,287,922 1,471,973 1,563,214 1,863,754 2,161,076 2,538,559 2,965,645 RATE BASE COMPUTATION WORKING CAPITAL COMPONENT:- NORMALIZED OPERATING EXP.858,746 1,079,391 1,287,9e2 1,471,973 1,563,214 1,843,754 2,161,076 2,538,555 2,965,645 LESS:DEPRECIATION (57,726)(77,130)(122,874)(152,614)(161,403)(171,539)(189,973)(224,746)=(266,967) TIMES 45/365 98,76 123,566 143,636 162,784 17e,826 206,164 243,013 285,264 332,714 OTHER COMPONENTS: MATERIALS &SUPOLTES @ @ 8 @ e @ @ 8 Q PREPAYMENTS 8 a Q @ Qa a @ @ @ TOTAL W/C REQUIREMENTS 98,756 123,566 143,636 162,784 172,826 206,164 243,013 285,264 33e,714 NET UTILITY PLANT 841,534 1,361,459 2,281,704 2,215,024 2,186,081 2,108,867 2,448,722 2,878,227 3,387,942 RATE BASE 940,292 1,485,026 2,425,348 2,377,808 2,360,907 2,315,031 2,691,734 3,155,491 3,728,655 RATE OF RETURN 8.es 8,e%8.0%8,0%8.0%8.e%8.0%8.0%8.0% RETURN ON RATE BASE 73,223 118,802 194,@27 198,225 168,873 185,282 215,339 252,439 297,652 NORMALIZED EXPENSES 856.746 1,079,391 1,287,922 1,471,973 1,563,214 1,843.754 2,161,076 2,538,555 2,965,645 REVENUE REQUIRED 933.969 1,196,194 1.481.969 1,662,197 1,752,087 2,@28.957 2,376,415 2,798,994 93,263,297 LESS-OTHER REVENUE a a 8 8 a a a @ 8 REVENUE REQUIRED FROM ENERGY SALES 933,969 1,196,194 1,481,949 1,662,197 1,752,087 2,028,957 2,376,415 2,798,994 3,263,297 AVERAGE CENTS/KWH 39.36 38.21 39.87 34.28 31.99 32.59 34.65 36.£8 38.18 *INCREASE (DECREASE)/YEAR 3}4 (14){7}2 6 6 4 UNALASKA POWER REVENUE REQUIREMENT TABLE 7 SUMMARIZED DATA FOR MENU SCHEDULES PLANT ACCOUNTS: GENERATION HEAT RECOVERY DISTRIBUTION LINES TRANSFORMERS METERS GENERAL PLANT STREETLIGHTS GROSS PLANT COST OF SERVICE: ADMIN &GENERAL-SALARTES PARTS-WAGES CUSTOMER ACCOUNTS-BAD DEBTS CUSTOMER ACCOUNTS-METER READING DISTRIBUTICN-WAGES DISTRIBUTION-TOOLS &MATERIALS ENGINEERING EQUIP-WAGES ENG.EQUIP-DIESEL FUEL &PARTS GENERAT TON-WAGES GENERATION-OTHER SUPPLIES GENERATION-UTILITIES &CONTR,SE GENERATION-MATERZALS GENERATION-AUTO PARTS,GAS &WAGE HEAT RECOVERY FUEL COSTS PURCHASED POWER DEPRECIATION:GENERATION HEAT RECOVERY DISTRIBUTION LINES TRANSFORMERS/METERS GENERAL PLANT STREETLIGHTS INSURANCE SYSTEM PROJECTIONS 379,264 78,057 985,486 39,768 46,548 58,020 5,208 1,496,315 20,651 28,832 27,122 14,838 a 1,033 ) 25,159 5,712 32,399 8,520 KW 65-1 COINCIDENT PEAK NON-COINCIDENT PEAK AVERAGE /EXCESS KW 65-2 COINCIDENT PEAK NON-COINCIDENT PEAK AVERAGE /EXCESS KW LP COINCIDENT PEAK NON-COINCIDENT PEAK AVERAGE /EXCESS KWEINTERPT.COINCIDENT PEAK NON-COINCIDENT PEAK AVERAGE/EXCESS HEAT RECOVER COINCIDENT PEAK NON-COINCIDENT PEAK AVERAGE/EXCESS KwW-STREETLIGCOINCIDENT PEAK NON-COINCIDENT PEAK AVERAGE/EXCESS #OF Kul CUSTOMERS SALES BS-1 288 1,596,672 68-2 28 464,755 LP 5 1,042,205 INTERRUPT.@ @ HEAT REC.1 @ STREETLIGHTS 1 32,420 RETURN ON RATE BASE 118,a2 FOR THE FISCAL YEAR 1984 ELECTRIC UTILITY PLANT ALLOCATION TO FUNCTIDN-RATE CLASS DATA FOR FEBRUARY 1983 TO JANUARY 19(ALLOCATION PERCENT UNALASKA POWER SYSTEM | REVENUE REQUIREMENT PROJECTIONS TABLE &PLANT ALLOCATIOIN }ALLOCATED PLANT ) #OF KWH KW KW KW DIRECT CONSUMERS COINCID.|NON-COIN AVE/EXCESS PLANT ACCOUNTS:GENERATION 379,264 ox ex 100%ex ox ex HEAT RECOVERY 72,057 ox en ox a ex 102% DISTRIBUTION LINES 9@5,486 50%ox ex 50x ax ex TRANSFORMERS 39,768 50%ax ex 50%et ox METERS 46,548 100%ex ex ox ot ax GENERAL PLANT 5@,eee 50%ox 50%ex ax ex OTHER EQUIPMENT 5,200 ex ex ex et ex 100% GROSS PLANT 1,496,315 .ge pene =es #OF KWH Ki KW Kid DIRECT PLEXT£R is'ji CONSUMERS COINCID, NON-COIN AVE/EXCESS TOTAL PLANT MENU ALLOCATION: 65-1 288 1,596,672 570 828 675 @ 994,762 %89.2%50.9%56.8%59,3x @@%66.5% 6-2 28 464,755 143 189 163 @ 168,996 %8.7%14,8%14,3%13.6%14.0%@e%=11.3% LARGE POWER 5 1,042,205 203 372 322 @ 248,233 %1.5%33.2%28,2%26,6%27.5%@.e%16.6% INTERRUPTABL Q @ Q @ a a @ %3.@%a.ex a.ex 2.2%@.2%0.8x 2.0% HEAT RECOVER 1 Q a a a @ 75,542 x Q.2%@.ax 2.2%2.0%@.ax 0.0%5.1% STREETLIGHTS 1 32,40a 7 8 8 @ =7,383 *@ 3%1.0%2.7%4 R7%180.2%2.5% TOTAL 323 3,136,032 1,024 1,358 1,168 @ 1,456,315 x 120.@x 120,%100.x 120.O%42.2% 1PD.OX =:AR (IN $) #OF Kid KW KW KW DIRECTCONSUMERCOINCID.|NON-COIN AVE/EXCESS a @ 379,264 @ a Q Q )')8 '78,@57 452,743 Q @ 452,743 '2 19,88e Q @ 19,680 @ @ 46,548 Q Q a 2 @ 25,020 @ 25,000 @ )@ Q Q @ a )5,200 544,173 @ 484,264 =:72,623 2 75,257 #OF Ki Kid KW Kid DIRECTCONSUMERSCOINCID.|NON-CDIN AVE/EXCESS 485,205 @ 229,428 «280,129 a ) 47,173 @ 57,757 64,O66 @ @ B,424 @ =1th,18@-«125,783 @ @ Q °a @ a a 1,685 a a Q 8 75,257 1,685 Q 2,988 2,719 Q a 544,171 @ 484,264 =472,623 @ 75,257 SMALASMA FQWE? REVENE REGUTRE! "TABLE 9 2037 CF SE FOR THE FISCAL YEAR 1364 ALLOCATION PER"=W=) ant Ane KW Ka ew DIRECT BURNT EXOENGE CONSUMERS COINCID.©MOA-CRIN.OVE EXCESS COST OF SERVICE:- ADMIN &GENERALS.ARIES 227,889 5x a 5ex ax ex a aPARTS-WAGES 6,264 5e%a Ses ex ex ex ey CUSTOMER ACCONTS-£AD DZETS GSS a 100K a a ex e a CUSTOMER ACCOUNTS-*ETER READ «3,388 108%a a ax x a aDISTRIBUTION-WOGES 65,343 a 100%ax a a ax a DISTRIBUTION-TOOLS 8 #ATERIA 14,133 ex 100%ex a e a aX ENGINEERING EGUIP-WAGES 12,626 ax ex sae a a ex aENG,EQUIO-DIESEL FUEL 4602 ©2,766 ex ex 1a ax a a a GENERATION-WOGES 93,5@1 et ax 20 XM a a a GEMERATION-CTHER SuPo IES 20,681 a a 102%a ax a ex GENERATIONAUTILITIES &CONTR 20,832 ox ex ees a ax a a GENERATION-MATERTALS 27,122 a es 100%a ex a a GENERATION-AUTO PARTS,GAS &«14,838 o ox ees on a a ox HEAT RECOVERY Q ax ex ox a a tae ex FUEL COSTS 461,033 e 100%e a e a ax PURCHESED POWER 8 a eax a a a a a DEPR:GENERATION 25,159 a ax a a a a tees HEAT RECOVERY 5,712 a e%e ox a ee 88% DISTRIBUTION LINES 32,399 a ex ox a ex aX tO TRANSFORMERS /METERS a.52@ e ox a ay ex ex seex GENERO PLANT 5.220 a a ex ex zx 18k OTHER EQUIPWENT ze ex a a a a eX eax INSURANCE 5,304 ex a a ex ex (fe TOTAL DPERATING EXPENSES 1.073,331 RETURN ON RATE BASE 118,892 w e ek ex e e100 REVENUE REQUIREMENT(OVERGLL)1,138,PsFUNRAMRA ELECRIC UTILITYcdgcementsAecaTeD70 RATE Cases ON MENG: #oF ai tin '0 oi DCT tLe CONSUYERS COINCISENT NEN-DOINCID.Ov EYTESS 68-1 2B8 1,596,672 S78 828 675 @ 954,762 89,2%50,9%56.a £3.3%ye ee 65-2 28 464,755 143 123 163 @ 168,956 8,7%14,8%14,3X 13.6%eS nL estes LARGE POWER S 1,042,205 283 372 228 @ 248,233 1.5%33.2%28,2%26.6%ee eS INTEARE™,a e e 2 Q 2 t 0.2%ae 2.0%acu nee |Ak HEAT RECOVER 1 8 2 8 2 @ 76,342 t @,34 ae @.2%@.2%ae aee SIX STREETLISHTS t 3r.are 7 8 8 @ 7,382 x 72 Lae ay aes or cor an Toa,323 3,136,022 1.84 1.258 1.168 2 1,436,315 120%120%vex 120%re tT etc !)TITER EYEERSES------neem 7 +0F nat <i ry si DpAeC7 Fen CONG MERE CRMID.--MOA-COTN AVE ZERETSS 13 Jue 183,944 2 @ a . 2 13,122 ?3122 @ Q @ @ 2 6,525 @ a @ a 2 3.358 a a 2 a °2 é 63,343 a @ )a @ @ 14,533 a a @ @ @ @ 2 12,626 e @ Q a ?a 2,764 a )@ a ?2 33,281 @ a @ a 2 a 20.65:@ a a a 2 q 28,B32 @ )@ @ @ a 27,122 @ @ a @ a a 14,838 @ 8 Q Q @ a @ e @ @ @ Z 461,233 @ @ a @ a @ ?@ a a @ r) a )@ @ )r)25,159 Q a 3 a a a 5.712 a @ @ @ Q @ 32,239 a @ a @ @ @ 8,520 2 z a 2 a @ 5,28 a a a 7 2 a 340 a a @ @ a Q 5.224 @ @ a @ e @ =188,a@2 1626 S47134 313,399 a ?@ =1,236 1,298,194 REVENUE REQUIREMENT ($)ALLOCATED 79 RATE CLASSES &oF oe 4a Ee]cy DIRECT PLANT "8 SEAS SESS COINCIDENT NCN-COINCT.AVE/EXCESS 116,292 278.567 18.265 e @ @ 133,783 789,987 $1,326 8:284 65,632 2 @ a 22,728 168,75! 2.059 181,832 90,147 @ @ a 33,384 =307,381 Q 2 g a 2 @ a q 44 @ @ a g @ 10,348 10,752 aa =.853 2,354 a @ a 333 9,BG 13424 847,126 319,359 @ @ @ R236 198,194 2 @ @ a @ 0 1 a wht HOS PULTE OYE? FEVENUE REQUIREMENT CROIECT TONG TABLE 12 COST STATISTICS BY RATE Cia FOR THE FISCAL VEAQ 1784 MENT =} 65-1 BS-2 SRST MRE INTERET,«|FECOVERY ST,LTR TOTAL BASE DATA: #OF CONSUMERS 208 Fa)5 e 1 i 3:3 Kis SOLD 1896672 464,755 1,262,228 2 Q@ BE AR2 2,126.822 it PVE /CONSLME3/MONT 62 1,383 17,378 238 e 7a B24 Kin COINCIDENTAL 57@ 143 263 2 7 1,004 KW NON-COINCIBENTOE,5596.51 B28 189 372 a a 8 1.398 Hw SWVERAGE/EXCESS 675 163 328 2 a a 1568 4 OF CUS",CHARGE IN DESIGNED RATE Sax 75%aan iat Hea 120% 1 fF SO-DERY IN DESIGNED ROTE ax ax 2ex ary on ee DEMAND)RATCHET a a 73 REVENCE REQUIRED 723,997 a a.752 3,4d6 CUSTOMER COSTS 115,232 a age 26 FIXED COSTS 315,049 2 0,268 3.347 ENEASY CASTE 278,567 a @ 5,653 CUSTOMER $/CTASUMER/YON"33.68 2S e%i 24,65 33.65 FIXED $/CONGUMER/MCNTH 51.16 2A3.4 .HR ABZ!278.9 FIXED $/KW:CO-DEQK/MONTE 46.25 3373 9 36,38 529 FRR 37.71 FIXED $/KW:NON CO-PERK/MONTH 3169 9 322502769 £38 vm 34.69 FIVED $/MWi:DVE-EXCESS/MONTH 38.89 34,98 32.0 ERR Enq 36.20 ENERGY CENTS/dH!17.45 $7.65 17,05 ER8 278 17.65 PYEROGE CENTS /KW#-BROSS 4b0h 24,59 1 3 E23 ER4 23.85 TARGET REVENUE (NC TILT) $/CONSUMER/MONTH $225.41 $478.42 $5,227.82 ERR $395.3%$783.63 AVERAGE CENTS/MWH re Re ESR ERR 29.02 RATE DESIGN (M0 TILT) CUSTOMER CA9SE $6.82 $25.26 $22.65 ERR «$34,685 $33.65 DEYAKD CHARGE $2.02 $e 85.85 Enq ERR $3,43 ENERGY CHARGE IN CENTS/¥W §aR2 92.7%E.R eR ERs 27.43 SIEGE EEE EEE EAE ARES EEE EERE EERE SRE TEED EE EERE EEE EERE EPH EDD EEE RHEER ERE SER OER ER UEC TE PENSE EERSTE EELS SEER ESL EPREREEEEES ERE EG FEDER S TILT IN $iz.due)(Pee!&F,222 a <t gz TILTED REVENMIE REGUISEMENT 659.307 7A,751 0 347.foi a h€,7SE R406 1,398,554 REFEREE EERE RE EEE ERLE EE EEE EER EERE EER ERERE EEEER EEE TREES EERE ELE EE ER EEE EERE RHEE ERR EKER EGS EER REER EEE REED ERE EEREREE EE EERE TEESE TARGET REVENUE (TILTED) {CONSUME 2/YONS Si30K 8a,GF EuR $755,63 CvERASE CENTS Stam 41,38 36.74 Es5 63.8 RATE DESISN (TILTED) CUSTOME?C4ARGE $16.82 $27,24 $23.65 BY $33,63 DEMAND CHARGE $2,G2 $2,e2 #3,@9 5a $3,63 ENEAGY TMGRGE IN CEN S74 a7,63 24,3 de.te it e7.43 -y,G7.G| RECEIVED £75 191884 THE UNALASKA GEOTHERMAL EXPLORATION PROJECT ALASKA POWER AUTHORITY ELECTRICAL POWER GENERATION ANALYSIS -FINAL REPORT - Prepared By: Republic Geothermal,Inc. For: The Alaska Power Authority April 1984 TABLE OF CONTENTS Page Executive Summary ..1.6.6.6 ew ee ee ew we we ew tw ew we te 1 Introduction.©.2.2 6 ee ewe we ee ee ee ee ee 2 Power Conversion Options.i 3 Power Conversion Process Description.........60 08468828288 5 Flash Steam Process Description .......4.+2.+..0882808c880848 5 Binary Process Description...2...1.1.2 ew ew ew ee ew ewe 8 Hybrid Process Description..2...1...2.2 ww ee we ee eee 8 Total Flow Process Description.......Ck we we ew we ee W Power Plant Constructors..2...2.6 ee we ww ww we ee ee we 13 Load Forecasts.2.2 6 6 1 we ee ee ww we we we we ee ee ew ee 16 Unit Sizing and Scheduling....2...2.2.2 2 ee ew ew ew ee ew 2] Geothermal Power Development Technical Characteristics..........29 Geothermal Power Development Cost Comparisons .........660468-4 39 Positive and Negative Aspects of each Type of Power Plant Considered...45 Power Conversion Process Recommendation ........2.6 ©we ee ew 47 Binary System Development Costs ...2...2 2 we we we ew we we 48 Conclusions ..2.1.2 we ew we tw wt tt we tw tt tt th ht tt tw 57 Fiqure 10 VW 12 13 14 15 LIST OF FIGURES Page Single-Flash Steam Process -Schematic Flow Diagram.......6 Double-Flash Steam Process -Schematic Flow Diagram.......7 Binary Process -Schematic Flow Diagram..........-2.-.9 Hybrid Process -Schematic Flow Diagram............-.10 Total Flow Process -Schematic Flow Diagram...........12 No-Bottomfish Development Case -Average and Maximum Power Demands as Estimated by Acres American,Inc...2.2.2.2 6 0 ee ew ew ew ew ew ww ew 7 Low-Bottomfish Catch Case -Average and Maximum Power Demands as Estimated by Acres American,Inc...2...2 6 ee ew we ee ew ew et te 18 No-Bottomfish Development Case -Electrical SystemLoadDemands..2...2.2 2 2 ww we ew we ew ee te 19 Low-Bottomfish Catch Case -Electrical SystemLoadDemands....2.2.2.1 2 ee we ew we ee we ee tw 20 No-Bottomfish Development Case -Power GenerationDevelopmentSchedule...2...1.2 2 2 we we ew ww we ens 23 No-Bottomfish Development Case Power Generation During Normal Operation -All Units Available.........24 No-Bottomfish Development Case -Power Generation During Emergency Operation -Largest Unit Down and Second Largest Unit Trapped..........2..24240868-6 25 Low-Bottomfish Catch Case -Power Generation Development Schedule...2...1 2 1 ewe we ee ee ew 26 Low-Bottomfish Catch Case -Power Generation During Normal Operation -All Units Available.........27 Low-Bottomfish Catch Case -Power Generation During Emergency Operation -Largest Unit Down and Second Largest Unit Trapped ...........46.0.624.6-.28 14 List of Figures (continued) Figure 16 7 18 19 20 2] 22 23 Page Potential Net Power Generation of Average Production Well When Using Single-Flash Steam Cycle.........4...33 Potential Net Power Generation of Average Production Well When Using Double-Flash Steam Cycle..........2..34 Potential Net Power Generation of Average ProductionWellWhenUsingBinaryCycle.....2...2.2.2.ee ee ene 35 Potential Net Power Generation of Average ProductionWellWhenUsingHybridCycle....1...1.2 ee we ew ew we 36 Potential Net Power Generation of Average Production Well When Using Total Flow Cycle..........0862428026-37 Geothermal Power Plant -Total Installed Cost vs Power Plant Unit Size...1 1 ww we we ee we et ew ee te 42 Geothermal Power Plant -Installed Cost Per kw vs Power Plant Unit Size Based on Continental USA Construction.....43 Geothermal Power Plant -Installed Cost Per kw vs Power Plant Unit Size Based on Unalaska Construction..........44 111 LIST OF TABLES Page No-Bottomfish Development Case -Geothermal Power Development Technical Matrix ..........2.260.606.2.088-8 30 Low-Bottomfish Catch Case -Geothermal Power Development Technical Matrix.........668858280eee 31 No-Bottomfish Development Case -Geothermal Power Development Capital Costs Matrix ............086.40 Low-Bottomfish Development Case -Geothermal Power Development Capital Costs Matrix .........0.0.+228-.4) No-Bottomfish Development Case -Unalaska 10 MW Gross (6.7 MW Net)Binary Power Plant Development Costs.......49 Low-Bottomfish Catch Case -Unalaska 30 MW Gross (20 MW Net)Binary Power Plant Development Costs - All Wells Drilled in First Phase of Power Development.....50 Low-Bottomfish Catch Case -Unalaska 30 MW Gross (20 MW Net)Binary Power Plant Development Costs - Wells Drilled as Needed in Each Phase of Power Plant Development...2...6 2 1 we ww ee tw ee te ww 51 No-Bottomfish Development Case -Unalaska 10 MW Gross (6.7 MW Net)Binary Power Plant -Combined Plant and Field Annual Operation and Maintenance Costs .......52 Low-Bottomfish Catch Case -Unalaska 30 MW Gross (20 MW Net)Binary Power Plant -Combined Plant and Field Annual Operation and Maintenance Costs .......53 \v EXECUTIVE SUMMARY The objective of this study was to determine the most cost-effective powercycleforutilizingtheMakushinVolcanogeothermalresourcetogenerate electricity for the towns of Unalaska and Dutch Harbor.It is anticipated that the geothermal power plant would be intertied with a planned conventional power plant consisting of four 2.5 MW diesel-generators whose commercial operation is due to begin in 1987.Upon its completion in late 1988,the geothermal power plant would primarily fulfill base-load electrical power demand while the diesel-generators would provide peak-load electrical power and emergency power at times when the geothermal power plant would be partially or completely unavailable. This study compares the technical,environmental,and economic adequacy offive"state-of-the-art"geothermal power conversion processes.Options con- sidered are single-and double-flash steam cycles,binary cycle,hybrid cycle, and total flow cycle. The power plant designs considered were limited to those capable of beingunitizedinpre-assembled and pre-tested modules so as to facilitate transpor- tation,erection,and start-up.The size and number of units were determined by an evaluation of commercially available units and by an analysis of the electrical load demands as estimated by Acres American,Inc.for APA.As requested by APA,both "no-bottomfish demand"and "low-bottomfish catch"cases were considered. Because of the uncertainties in the electrical load forecasts it is recom- mended herein that the geothermal power plant be developed in phases that are timed to the growth in demand.The first phase of development should consist of two identical 5 MW gross binary units capable of generating a total of 6.7 MW net of electrical power.This plan satisfies the estimated demand for the no-bottom fishing case past the year 2000. Should bottom fishing take place and electrical load demand increase in accordance with the "low-bottomfish"projections,then a second and third phase would be added to become commercial in early 1993 and 2000 respectively.Each of these two phases would comprise two 5 MW gross binary units identical to those installed in Phase I. The binary cycle was selected because it is the most economical process in the small unit size considered,it is efficient,1t does not incur the risk of freezing during winter months operation and it can be installed quickly,thus adding scheduling flexibility. INTRODUCTION The city of Unalaska,a community in the Aleution Island region of south-western Alaska is expanding and modernizing the electric power systems in the towns of Dutch Harbor and Unalaska.As part of this electrification program, a larger electrical distribution system is being built,an old power house is being refurbished and the installation of four 2.5 MW diesel-generator units is being planned. Acres American Inc.has been requested by the Alaska Power Authority (APA) to prepare an economic study to determine how to supplement the electricity produced by the diesel-generating system as the system demand grows and thus, minimize reliance on high cost diesel-fired power generation.Because the state of Alaska is attempting to utilize indigenous energy sources located close to population centers,one of the options being considered is the use of geothermal energy. A significant geothermal resource was discovered in 1983 as a result of the Unalaska geothermal exploration project conducted by Republic Geothermal Inc.for the APA.A small diameter resource confirmation well,Makushin ST-1, was drilled in the flank of the Makushin Volcano which is located within 12 miles of the towns of Unalaska and Dutch Harbor.A short test of the well yielded fluid from that flowed from a three-inch orifice at 47,000 1b/hr with a 16 percent steam flash.Analyses of samples collected during the flow test indicate that the reservoir contains a sodium-chloride type water with a total dissolved solids (TDS)content of approximately 6,000 ppm by weight and that the preflash carbon dioxide content is 217 ppm.At these low concentrations, the dissolved solids and gases are not expected to pose any problems in the conversion cycles. While more testing is necessary to further characterize and delineate the resource,theoretical calculations predict that a full-scale production well would yield approximately 900,000 Ib/hr at a pressure of 57 psia both of which parameters are more than adequate for commercialization. The study that is described below establishes the best means of generating electricity from the Makushin resource,presents a power generation develop- ment scenario based on estimated load forecasts and estimates the cost of commercializing geothermal power on Unalaska.The report addresses all of the tasks listed in the "scope of work"section of Amendment No.6 to Contract CC-08-2334 as modified by the letter dated February 2,1984 from the APA. POWER CONVERSION OPTIONS The conversion of hydrothermal energy from Makushin-type liquid-dominated geothermal resource into electric power can be accomplished by the following processes: 1.Flash Steam In the flash steam process,steam 1s produced from the geothermal fluid by reducing the pressure of the fluid below the saturated liquid pressure.The steam is then used to directly power a turbine, which in turn drives an electric generator. 2.Binary In the binary process,a low boiling point fluid,such as freon or isobutane,is passed through a heat exchanger where it is vaporized by proximity to the geothermal brine.The superheated vapor is then used to power a turbine,which in turn drives an electric generator. 3.Hybrid In the hybrid process,part of the geothermal fluid is flashed into steam which is used to drive a steam turbine-generator.The residual fluid is then used to vaporize a low boiling point fluid through a heat exchanger.The superheated vapor produced is then used to power a second turbine-generator. 4.Total Flow In the total flow process,all of the geothermal fluid is expanded through a mechanical device which converts both thermal and kinetic energy of the well fluid into shaft work (torque).This shaft work is then used to drive an electric generator. Numerous commercial power plants using the flash steam process are in operation and several more are under construction in various locations throughout the world.Notable examples of successful geothermal flash steam plants include installations in the Imperial Valley of the United States,New Zealand,Mexico,Japan,The Philippines,and Iceland.It is safe to say that the flash steam process is proven. One 10 MW geothermal binary plant is presently operating successfully in the Imperial Valley and a number of others are under construction in the United States.While the binary process has not been widely used to date in geothermal applications,the organic fluid Rankine cycle has been used extensively over the years in petrochemical and waste heat recovery plants. The binary process is,therefore,considered to be technologically proven,at least in units in the 0.5 to 5.0 MW size range. There are no operating geothermal power plants using the hybrid cycle atthepresenttime,however,Republic Geothermal,Inc.4s planning to build one soon in the Imperial Valley.The hybrid process is simply the combination of two proven processes (flash steam and binary)for greater conversion effici- ency and it is,therefore,considered to be proven as well. The total flow process,which was developed specifically for geothermal application,comes in technically different options which are in various stages of development.The two best known are the Sprankle helical screw expander and the Biphase rotary separator turbine.The Sprankle expander has been tested extensively on a small scale,and may be ready for commerciali- zation.A full-scale version of the Biphase turbine has been tested successfully in Utah for the last few months and is definately ready for commercialization.The Biphase turbine does not involve significant technical risks and is considered to be state-of-the-art. Only state-of-the-art processes are being considered for the commercial development of the Unalaska Island resource. POWER CONVERSION PROCESS DESCRIPTIONS Flash Steam Process Description Both single and double flash steam options have been considered in this study. 1.Single Flash Steam Process Two-phase geothermal fluid produced by the wells is piped to a steam separator where the steam is separated from the geothermal water. The steam is then piped from the separator to a steam turbine- generator where it is expanded to produce electrical power.The exhaust steam from the turbine is then ducted to an extended-surface, air-cooled heat exchanger where its is condensed by rejecting heat to the atmosphere.Noncondensable gases are removed from the condenser by a combination of steam jet ejJectors and liquid-ring vacuum pumps. Condensate pumps transfer the warm water from the condenser to an injection surge tank. The residual geothermal water flows from the separator into the injection surge tank where it is mixed with the condensate from the steam cycle.The water is then pumped out of the surge tank and injected back into the ground. Figure 1 is a schematic flow diagram of the single flash steam process. Double Flash Steam Process Two-phase geothermal fluid produced by the wells is piped to a steam separator where the high-pressure steam is separated from the geothermal water.The geothermal water then flows to a flash tank where low-pressure steam is generated by reducing the pressure. High-and low-pressure steam from the separator and the flash tank is piped to a dual inlet steam turbine-generator where it 1s expanded to produce electrical power.The exhaust steam from the turbine is ducted to an extended-surface,air-cooled heat exchanger where it is condensed by rejecting heat to the atmosphere.Noncondensable gases are removed from the condenser by a combination of steam jet ejectors and liquid-ring vacuum pumps.Condensate pumps transfer the warm water from the condenser to an injection surge tank. The residual geothermal water is transferred out of the flash tank into the injection surge tank where it is mixed with the condensate from the steam cycle.The water is then pumped out of the surge tank and injected back into the ground by the injection pumps. Figure 2 is a schematic flow diagram of the double flash steam process. FIGURE 1 SINGLE FLASH STEAM PROCESS SCHEMATIC FLOW DIAGRAM STEAM TO ATMOSPHERE Lp NON-CONDENSIBLE GASES EVACUATION SYSTEM STEAM SEPARATOR - PRODUCTION WELLS INJECTION RESIDUAL >SURGEHOTWATERTANK A at u -2 > INJECTION PUMPS AIR COOLED CONDENSER CONDENSATE PUMPS Ls INJECTION WELLS STEAM TURBINE-GENERATOR RGI E1485 FIGURE 2 DOUBLE FLASH STEAM PROCESS SCHEMATIC FLOW DIAGRAM LOW PRESSURE STEAM HIGH PRESSURE STEAM PRODUCTION WELLS £. \ STEAM SEPARATOR - HOT WATER TRANSFER FT UY PUMPS RESIDUAL WATER -S INJECTION .SURGE TANK TO ATMOSPHERE NON-CONDENSIBLE GASES EVACUATION SYSTEM A STEAM TURBINE-GENERATOR Y,AIR COOLED CONDENSER LW] CONDENSATE PUMPS -| INJECTION PUMPS. i INJECTION WELLS RCL E1486 Binary Process Description Two-phase geothermal fluid produced by wells is piped to a steam separatorwherethesteamisseparatedfromthegeothermalwater. The steam and water are piped separately from the separator to a series of shell-and-tube-heat exchangers.The water preheats and evaporates the binary fluid,which can be a hydrocarbon such as isobutane or a fluocarbon such as freon R-114.The steam superheats the binary fluid vapor.The superheated fluid vapor is then piped to a binary turbine-generator where it 1s expanded to produce electric power. The exhaust vapor from the turbine is then ducted to an extended-surface, air-cooled heat exchanger where it is condensed by rejecting heat to the atmosphere.Condensate pumps transfer the binary fluid condensate from the condenser back to the binary fluid heat exchangers where the cycle is repeated. Cooled geothermal water and steam condensate flow from the binary fluidheatexchangersintoaninjectionsurgetank.The water is then pumped out of the surge tank and injected back into the ground. Figure 3 is a schematic flow diagram of the binary process. Hybrid Process Description Two-phase geothermal fluid produced by the wells is piped to a steam separator where the steam is separated from the geothermal water. The steam is piped from the separator to a steam turbine-generator where {ts is expanded to produce electric power.The exhaust steam from the turbine is directed to an extended-surface,air-cooled heat exchanger where it is condensed by rejecting heat to the atmosphere.Noncondensable gases are removed from the condenser by a combination of steam jet ejectors and liquid- ring vacuum pumps.Condensate pumps transfer the warm water from the condenser to an injection surge tank. The residual geothermal water flows from the separator to a serie of shell-and-tube heat exchangers where it preheats,evaporates,and superheats the binary fluid,which can be a hydrocarbon such as isobutane or a fluocarbon such as freon R-114.The superheated binary fluid vapor is piped to a binary turbine-generator where it is expanded to produce electric power. The exhaust vapor from the binary turbine is ducted to a second extended- surface,air-cooled heat exchanger where it is condensed by rejecting heat to the atmosphere.The binary fluid condensate is then transferred by the con- densate pumps from the binary fluid condenser back to the binary fluid heat exchangers where the cycle is repeated. Cooled geothermal water flows from the binary fluid heat exchangers into the injection surge tank and mixes with the condensate from the steam cycle. The water is then pumped out of the surge tank and injected back into the ground. Figure 4 is a schematic flow diagram of the hybrid process. 8 STEAM SEPARATOR STEAM -P> PRODUCTION WELLS FIGURE3 BINARY PROCESS SCHEMATIC FLOW DIAGRAM STEAM CONDENSATE BINARY FLUID SUPERHEATER BINARY FLUID TURBINE-GENERATOR <q- > -\/\/\> HOT WATER lab'BINARY FLUID EVAPORATOR >== BINARY FLUID PREHEATER >) CONDENSATE BINARY FLUID CONDENSER G INJECTION PUMPS - INJECTION WELLS PUMPS INJECTION SURGE TANK RESIDUAL WATER RGI E1487 OTFIGURE 4 HYBRID PROCESS SCHEMATIC FLOW DIAGRAM STEAM STEAM TO ATMOSPHERE TURBINE-GENERATOR NON-CONDENSIBLE esveune >GASES EV EATONTEMSTEAM-SEPARATOR h BINARY FLUID |BINARY FLUID jf HOT WATER ><q i<-j<---EVAPORATOR-PREHEATER EVAPORATOR:AIR COOLED CONDENSER STEAM CONDENSATE BINARY FLUID INJECTION TURBINE-GENERATOR SURGE TANKPUMPS>RESIDUAL WATER | -pt.Pp:«\)AMMN 2 INJECTION BINARY FLUID PUMPS BINARY FLUID CONDENSATE AIR COOLED CONDENSER PUMPS PRODUCTION WELLS Len) INJECTION WELLS RCI E1488 Total Flow Process Description Two-phase geothermal fluid produced by the wells is piped to a steamseparatorwherethesteamisseparatedfromthegeothermalwater. The steam is piped from the separator to the high-pressure inlet of a steam-turbine generator.The separated geothermal water is piped to a two- phase nozzle which converts the thermal and pressure energy of the expanded liquid and gas mixture to high efficiency fluid kinetic energy.The two-phase jet is directed tangentially on the inner surface of the rotary separator where steam and water are separated by centrifugal forces.A liquid turbine rotor mounted into the rotary separator converts the kinetic energy of the liquid to shaft power.The turbine shaft is connected to one end of the double-ended electric generator. The resulting low-pressure steam from the rotary separator is piped to the low-pressure inlet of the steam turbine-generator where it is expanded together with the high-pressure steam to produce electric power.The exhaust steam from the turbine is then ducted to an extended-surface,air-cooled heat exchanger where it is condensed by rejecting heat to the atmosphere.Non- condensable gases are removed from the condenser by a combination of steam jet ejectors and liquid-ring vacuum pumps.Condensate pumps transfer the warm water from the condenser to an injection surge tank. The residual geothermal water from the rotary separator flows into the injection surge tank where it is mixed with the condensate from the steam cycle.The water is then pumped out of the surge tank and injected back into the ground. Figure 5 is a schematic flow diagram of the total flow process using a Biphase rotary separator. While the Sprankle helical screw expander may be a viable candidate machine for conversion of geothermal energy by the total flow process,it is not considered in this study due to lack of available test data and to the large physical size required to produce significant power output. However,should it be used,the geothermal fluid produced by the wells would be piped directly to the positive-displacement device which operates by direct expansion of the two-phase fluid meshing rotors.The fluid entering through a nozzle control valve into a high-pressure pocket is expanded through a pocket that elongates continually as the rotors revolve all the way down to the exhaust port. 11 ralFIGURE 5 TOTAL FLOW PROCESS SCHEMATIC FLOW DIAGRAM HIGH PRESSURE STEAM -p> watt PRODUCTION WELLS LOW PRESSURE STEAMSTEAM SEPARATOR ROTARY SEPARATOR TURBINE TWO-PHASE NOZZLE RESIDUAL WATE > -- INJECTION WELLS TO ATMOSPHERE STEAM - INJECTION SURGE TANK L___p» i INJECTION PUMPS > NON-CONDENSIBLE GASES EVACUATION SYSTEM |TURBINE-GENERATOR oe A AIR COOLED CONDENSER <q \3 CONDENSATE PUMPS RCI £1489 POWER PLANT CONSTRUCTORS Geothermal power plants can be designed,engineered,and constructed by Engineer ing-Construction (E&C)companies or by Equipment Manufacturing Companies. 1.Engineer ing-Construction Typically,E&C companies do not manufacture,but they do specify,select,and purchase the equipment which is integrated into the overall power plant design.Because of their large and diversified staff,E&C companies can select the optimum cycle for the resource as well as optimize and engineer any selected power cycle.While they do not warrant individual pieces of equipment used to construct the plant,they will ensure that the equipment manufacturers do so and will guarantee the overall plant performance and workmanship. The following is a short list of E&C companies having geothermal power plant experience. a.Large E&C Firms: Bechtel Power Corporation 12400 E.Imperial Highway Norwalk,CA 90650 Phone:(213)864-6011 Contact:Joseph A.Falcon Fiuor Engineers and Constructors,Inc. 3333 Michelson Drive Irvine,CA 92730 Phone:(714)975-6839 Contact:Jake Easton III The Ralph M.Parsons Co. 100 West Walnut St. Pasadena,CA 91124 Phone:(213)440-2000 Contact:Roy E.Gaunt Gibbs and Hill,Inc. 226 W.Brokaw Road San Jose,CA 95110 Phone:(408)280-7091 Contact:Larry R.Krumland Morrison-Knudsen Co.,Inc. P.0.Box 7808 Boise,ID 83729 Phone:(208)386-5000 Contact:Frank G.Turpin 13 b.Small E&C Firms: The Ben Holt Co. 201 South Lake Ave. Pasadena,CA 91101 Phone:(213)684-2541 Contact:Clement B.Giles Ultrasystems,Inc. 2400 Michelson Drive Irvine,CA 92715 Phone:(714)752-7500 Contact:Phillip J.Stevens Equipment Manufacturers Typically Equipment Manufacturers,generally turbine-generator and/or heat exchanger manufacturers,prepackage power module assemblies incorporating their own equipment into the overall power 'plantdesign.Because most equipment manufacturers specialize in one segment of the industry,they can only offer one type of power cycle which may or may not be optimum for the resource.The following is a short list of equipment manufacturing companies that design,engineer, and buitd geothermal power plants: a.Equipment Manufacturers for Flash Steam Plants General Electric Company 1100 Western Ave. Lynn,MA 01910 Phone:(617)594-4146 Contact:Howard C.Spears Fuji Electric Company,Ltd./Nissho Iwai American Corp. Broadway Plaza,Suite 1900 700 South Flower St. Los Angeles,CA 90017 Phone:(213)688-0671 Contact:Mikio (Michael)Ikukawa Mitsubishi International Corp. 555 South Flower St. Los Angeles,CA 90071 Phone:(213)977-3767 Contact:Sam Miyamoto Toshiba International Corp. 465 California St.,Suite 430 San Francisco,CA 94104 Phone:(415)434-2340 Contact:Hisashi Ohtsuka 14 Equipment Manufacturers for Binary and Hybrid Plants Ormat Systems Inc. 168 Sendra Ave. Arcadia,CA 91006 Phone:(213)445-4202 Contact:H.Ram Mechanical Technology Inc. 968 Albany-Shaker Road Latham,NY 12110 Phone:(518)785-2400 Contact:Thomas E.Williams Barber-Nichols Engineering 6325 West 55th Avenue Arvada,CO 80002 Phone:(303)421-8111 Contact:Kenneth Nichols Equipment Manufacturers for Total Flow Plants Biphase Energy Systems 2800 Airport Ave. Santa Monica,CA 90405 Phone:(213)3917-0691 Contact:Donald J.Cerini Hydrothermal Power Co.,Ltd. P.O.Box 2794 Mission Viejo,CA 92690 Phone:(7174)837-3081 Contact:Roger Spankle 15 LOAD FORECASTS The electrical load forecasts for Unalaska and Dutch Harbor have recentlybeendevelopedaspartofareconnaissancestudyfortheAlaskaPowerAuthority by Acres American Inc.As requested by the Alaska Power Authority,only the "No-Bottomfish Development"case and the "Low-Bottomfish Catch”case are being considered in this study.Figures 6 and 7 show the average and maximum power demand estimated by Acres American Inc.for these two cases. The average power demand,which is calculated by dividing the annual energy use by 8760 hours,is less than 30 percent of the maximum power demand, indicating possible large seasonal and/or daily demand variations.Discussion with Mr.Jeff Currier of Unalaska Public Utility to clarify this matter seems to disprove this interpretation of the data.While the calculated average power demand appears to be representative of the expected base load demand for the electrical system,he does expect this base load demand to be less than approximately 60 percent of maximum power demand. In the absence of load duration curves showing daily and seasonal variations in estimated load demand,it is therefore assumed that the electrical system base load demand is the average load demand estimated by Acres and that it is 60 percent of the system peak load demand.Figures 8 and 9 show both base load and peak load demands assumed for the two cases under study. 16 LTELECTRICALPOWERDEMAND-MW16 14 13| 12 11 10 9 8 7 6 5 4 3 2 1 0 1 FIGURE 6 NO BOTTOMFISH DEVELOPMENT CASE AVERAGE AND MAXIMUM POWER DEMANDS AS ESTIMATED BY ACRES AMERICAN INC. MAXIMUM POWER DEMAND AVERAGE POWER DEMAND - - = !]!!I |||!I !!|j ||f 984 1986 1988 1990 1992 1994 -1996 1998 2000 2002 2004 YEARS 8T.ELECTRICALPOWERDEMAND-MWFIGURE 7 LOW BOTTOM FISH CATCH CASE AVERAGE AND MAXIMUM POWER DEMANDS AS ESTIMATED BY ACRES AMERICAN INC. 1 |7 }3 |3 5 ||||ff |YF ||||| 984 1996 1988 1990 1992 1994 1996 =s«1998 2000 2002.+2004 YEARS AGI E1539 61ELECTRICALPOWERDEMAND-MWFIGURE8 NO BOTTOMFISH DEVELOPMENT CASE ELECTRICAL SYSTEM LOAD DEMANDS 8 i- Th PEAK LOAD DEMAND 6H 5 BASE LOAD DEMAND|eS LL Ji 2 tr 0 |SN RL NN ON NN SN ON ON NG PON GN NN OO MN DO 1984 1986 1988-1990 1992 1994 1996 1998 2000 2002 2004 YEARS Lh aad RG!E1694 02ELECTRICALPOWERDEMAND-MW'FIGURE 9 'LOW BOTTOMFISH CATCH CASE ELECTRICAL SYSTEM LOAD DEMANDS Fy aL EN SN ON ON NN CO DO NN ON DN 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 YEARS AGI E1533 UNIT SIZING AND SCHEDULING It is anticipated that a geothermal power plant would be intertied with a planned conventional power plant to supply the electrical power needs of Unalaska and Dutch Harbor.The conventional power plant will consist of four 2.5 MW diesel generators and is scheduled to begin commercial operation in early 1987.To allow for orderly planning of financing,field development, and power plant/transmission line engineering and construction,the geothermal power plant would be scheduled to begin commercial operation in January 1989. Upon completion,the geothermal power plant would primarily provide base load power while the diesel generators would provide peak load and emergency power should the geothermal power plant be partially or totally disabled. Due to the remoteness of the geothermal construction site,the difficult site access and the need for high reliability,the geothermal power plant would be unitized.The size,number and phasing schedule of the geothermal units for each of the power conversion processes studied are determined as follows: 1.Unit Sizing Economical size of the units is determined by an evaluation of commercially available units.To minimize field erection and start-up operations,only units that can be completely or partially shop-assembled and tested in modules are considered.Modules are sized to be truck-transportable on both main throughfares and unpaved gravel roads. 2.Determination of number of units and commercial operation schedule. The Number of units required to meet power demand forecasts and the commercial operation schedule for these units are determined by Super imposing the net generating capacity of all units over the estimated power demands.During "normal operation",which is when all installed units are available for power generation,the net generating capacity of the geothermal units will always be kept above the electrical system base load demand.During "emergency operation", which is when the largest installed unit is down for maintenance and the second largest installed unit is down on emergency trip,the net generating capacity of all remaining units will always be kept above the electrical system peak load demand. In order to meet the electrical system load demands estimated up to the year 2000 for both the "No-Bottomfish Development"and "Low-Bottomfish Catch" cases,a geothermal power plant using any one of the five different power conversion cycles studied could be used to meet the criteria described above. 21 1.No-Bottomfish Development Case. a.Single or double flash steam cycles. One 5 MW net unit to be commercial in January 1989 and one 5 MW net unit to be commercial in January 2000. Binary cycle. Two 3.35 MW net units to be commercial in January 1989. Hybrid cycle. Three 3.35 MW net (1 steam and two binary)units to be commercial in January 1989. Total flow cycle. One 5 MW net unit to be commercial in January 1989 and one 5 MW net unit to be commercial in January 2000. 2.Low-Bottomfish Catch Case. a.Single or double flash steam cycles. Two 5 MW net units to be commercial in January 1989,one 5 MW net unit to be commercial in January 1993,and one 5 MW net unit to be commercial in January 1998. Binary cycle. Two 3.35 MW net units to be commercial in January 1989,two 3.35 MW net units to be commercial in January 1993,and two 3.35 MW net units to be commercial in January 2000. Hybrid cycle. Three 3.35 MW net (1 steam and two binary)units to be commercial in January 1989 and three 3.35 MW net units to be commercial in January 1997. Total flow cycle. Two 5 MW net units to be commercial in January 1989,two 5 MW net units to be commercial in January 1993,and two 5 MW net units to be commercial in January 1998. Figures 10 through 15 show the power generation development schedule,the power generation during normal operation,and the power generation during emergency operation for both the "no bottomfish development"and "low bottom- fish catch"cases for an electrical power system with a geothermal power plant using a binary cycle. 22 FIGURE 10 NO BOTTOMFISH DEVELOPMENT CASE POWER GENERATION DEVELOPMENT SCHEDULE 3.35 MW NET BINARY UNIT 2.5 MW DIESEL-GENERATOR Bensteseiennenennsiehielh ELECTRICALPOWERGENERATION&ELECTRICALPOWERDEMAND-MWeo\:eee es ee See"BASE LOAD DEMAND 0 ae nia19851987198919911993199519971999 2001 2003 2005 2007 YEARS RGI E1529 23 -FIGURE12 NO BOTTOMFISH DEVELOPMENT CASE POWER GENERATION-EMERGENCY OPERATION LARGEST UNIT DOWN AND SECOND LARGEST UNIT TRIPPED DISABLED UNIT43.35 MW NET BINARY UNIT own©a=6ome6eo@pe6oe6ee6eeeeeELECTRICALPOWERGENERATION&ELECTRICALPOWERDEMAND-MWwo\0 --1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS , , AGI £1527 25 FIGURE 13 LOW BOTTOMFISH CATCH CASE POWER GENERATION DEVELOPMENT SCHEDULE oe3.35 MW NET BINARY UNIT a=2.5 MW DIESEL-GENERATORa ELECTRICALPOWERGENERATION&|ELECTRICALPOWERDEMAND-MWf-=e 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS RG!£153126 FIGURE 14 LOW BOTTOMFISH CATCH CASE POWER GENERATION-NORMAL OPERATION ELECTRICALPOWERGENERATION&ELECTRICALPOWERDEMAND-MWALL UNITS AVAILABLE ">3.35 MW NET BINARY UNIT 34)-ES ;2.5 MW DIESEL-GENERATOR "a ee ee a | 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS 27 .RGI E1529 GEOTHERMAL POWER DEVELOPMENT TECHNICAL CHARACTERISITICS The technical characteristics of each geothermal power development altern- ative considered for both the "No-Bottomfish Demand"and Low-Bottomfish Catch* cases are shown on Tables 1 and 2.Each power development alternative includes both the power plant and the associated field development.The basis used in developing the power development technical matrices is defined below: 1.The electrical power generation capacity of each alternate power plant is determined by matching economically sized units to the power load demands estimated beyond the year 2000 for the electrical system, as described in the previous section "Unit Sizing and Scheduling." Due to the low average dry-bulb temperature of the air on Unalaska Island,a direct dry cooling system is incorporated into all altern- ative cycles.In a dry cooling system the heat to be rejected from the power cycle is transferred through the walls of an air-cooled heat exchanger directly to the ambient air stream.Use of this system allows for 100 percent geothermal fluid reinjection and elim- jnates the need for an outside source of water. Customarily a power plant is designed for a constant output that can be assured year-around,as determined by the capacity of the heat rejection system at reasonable worst-case conditions.Alternatively, a power plant can be designed to allow for a power output that will vary as the capacity of the waste heat rejection system is affected by ambient conditions.This variable output concept is termed "floating"power. The thermodynamic properties of steam are not compatible with the variable output mode creating excessive in costs and efficiencies. Therefore,all steam flash alternatives are designed for a constant output mode based on a 50°F dry-bulb ambient temperature. The thermodynamic properties of organic hydrocarbons or fluocarbonsdoallowturbinestooperateoverawiderangeofbackpressurewith only minor reductions of peak efficiencies;therefore,all binary alternatives have been designed for a floating output mode based on an average 30°F dry bulb ambient temperature. As described in the "Unit Sizing and Scheduling"section,each power plant unit 1s comprised of completely or partially shop-assembled andtestedmodules.This modular approach facilitates field erection and start-up as well as transportation.It has been assumed that moduleswouldbebargedfromthemainlandtoDriftwoodBaywheretheywould be unloaded and trucked to the construction site. 29 OcPower Plant Gross Power Generation Capacity Power Plant Net Power Generation Capacity Power Plant Heat Rejection Type Power Plant Design Ambient Temperature Power Plant Construction Type Shop Assenbly Field Construction Transportation Power Plant Operation Number of Power Generation Units Largest Module Weight of Heaviest Module Maximum Net Power Generation Potential of Average Production Well Minimum Geothermal Fluid Flow Required per Net kw of Power Generation Minimum Total Geothermal Fluid Flow Required andCorresponding Wellhead Pressure Minimum Number of Production Wells Required Nunber of Production Wells Provided Average Flow per Production Well Production Wellhead Pressure Production Wellhead Temperature Percent Reinjection Minimum Nusiber of Injection Wells Required Number of Injection Wells Provided Average Flow per Injection Well injection Wellhead Pressure Injection Wellhead Temperature Waste Discharge to Atmosphere Expected Reliability Expected Substainable Capacity Factor TABLE 3 NO-BOTTOMFISH DEVELOPMENT CASE GEOTHERMAL POWER DEVELOPMENT TECHNCTAL MATRIX Single Flash Steam Plant 11.2 MW 10 MW Dry Cooling 50°F Modular Maximum Minimum Barge &Truck Constant Output 2 Turb ine-GeneratorSets 130,000 1b 4.35 MW 206.9 Ib/hr 2,069,000 1b/hr at 57 psia 2.3 3 690,000 1b/hr 75 psia 308°F 100% 1.15 2 1,035,000 1b/hr Atmospheric 260°F 476 lb/hr Noncondensable Gases High 85% Double Flash Steam Plant 11.5 MW 10 MW Dry Cooling 50°F ° Modular Maximum Minimum Barge &Truck Constant Output 2 Turbine-Generator Sets 145,000 1b 5.5 MW 163.6 Ib/hr 1,636,000 Ib/hr at 57 psia 1.82 2 815,000 1b/hr 65 psia 298°F 100% 9} 1 1,636,000 Ib/hr Atmospheric 200°F 376 \b/hr Noncondensable Gases High 85% Binary Plant 10 MW 6.7 MW Dry Cooling 30°F Modular Max imum Minimum Barge &Truck Floating Output 2 Heat Exchangers 120,000 ib 6.1 MW 143.4 Ib/hr .961,000 1b/hr at 59 psia 1.1 2 365,000 1b/hr 96 psia 325°F 100% 053 1 961,000 1b/hr Atmospheric 170°F 221 1b/hr Noncondensable Gases High 85% Hybrid Plant 14 MW 10 MW Dry Cooling 50°F (steam unit) 30°F (binary units) Modular Maximum Minimum Barge &Truck Floating Output 3 (1 steam +2 binary) Heat Exchangers and Steam Turbine- Generator Sets 120,000 1b 6.75 MW 133.3 1b/hr 1,333,000 1b/hr at 57 psia 1.48 2 665,000 1b/hr 77 psia 309°F 100% 74 1 1,333,000 1b/hr Atmospheric 170°F 307 1b/hr Noncondensable Gases High 85% Total Flow Plant 11.5 MW 10 MW Dry Cooling 50°F Modular Max imuin Minimum Barge &Truck Constant Output 2 Turbine-Generator Sets 213,000 1b 5.8 MW 155.2 1b/hr 1,552,000 Ib/hr at 57 psia 1.72 2 775,000 1b/hr 68 psia 301°F 100% 86 1 1,552,000 Ib/hr Atmospheric 200°F 357 \b/hr Noncondensable Gases High 85% TePower Plant Gross Power Generation Capacity Power Plant Net Power Generation Capacity Power Plant Heat Rejection Type Power Plant Design Aubient Temperature Power Plant Construction Type Shop Asseubty Field Construction Transportation Power Plant Operation Number of Power Generation Units Largest Module Weight of Heaviest Module Maximum Net Power Generation Potential of Average Production Well Minimum Geothermal Fluid Flow Required per Net kw of Power Generation Minimum Total Geothermal Fluid Flow Required and Corresponding Wellhead Pressure Minimum Number of Production Wells Required Number of Production Wells Provided Average Flow per Production Well Production Wellhead Pressure Production Wellhead Temperature Percent Reinjection Mininun Number of Injection Wells Required Number of Injection Wells Provided Averaye Flow per Injection Well Injection Wellhead Pressure Injection Wellhead Temperature Waste Discharge to Atmosphere Expected Reliability Expected Sustainable Capacity Factor LOW-BOTTOMFISH CATCH CASE TABLE 2 GEOTHERMAL POWER DEVELOPMENT TECHNCIAL MATRIX Single Flash Steam Plant 22.4 MW 20 MW Dry Cooling 50°F Modular Maximum Minimum Barge &Truck Constant Output 4 Turbine-Generator Sets 130,000 1b 4.35 MW 206.9 Ib/hr 4,138,000 1b/hr at 57 psia 4.6 5 +1 standby 825,000 1b/hr 64 psia 297°F 100% 2.3 3 +1 standby 1,379,000 Ib/hr Atmospheric 260°F 952 1b/hr Noncondensable Gases High 85% Double Flash Steam Plant 23 MW 20 MW Dry Cooling 50°F Modular Maximum Minimum Barge &Truck Constant Output 4 Turbine-GeneratorSets 145,000 1b 5.5 MW 163.6 1b/hr 3,272,000 Ib/hr at 57 psia 3.64 4 +1 standby 815,000 Ib/hr 65 psia 298°F 100% 1.82 2 +1 standby 1,636,000 Ib/hr Atmospheric 200°F 752 1b/hr Noncondensable Gases High 85% Binary Plant 30 MW 20 MW Dry Cooling 30°F Modular Maximum Minimum Barge &Truck Floating Output 6 Heat Exchangers 120,000 1b 6.1 MW 143.4 Ib/hr 2,883,000 1b/hr at 59 psia 3.3 4 +1 standby 595,000 1b/hr 82 psta 314°F 100% 1.6 2 +1 standby 1,442,000 1b/hr Atmospheric 170°F 663 Ib/hr Noncondensable Gases High 85% Hybrid Plant 28 MW 20 MW Ory Cooling 50°F (steam unit)30°F (binary unit} Modular Max imum Minimum Barge &Truck Floating Output 6(2 steam +4 binary) Heat Exchangers and Steam Turbine- Generator Sets 120,000 1b 6.75 MW 133.3 1b/hr 2,666,000 1b/hr at 57 psia 2.96 3 +1 standby 890,000 1b/hr 58 psia 291°F 100% 1.48 2 +1 standby 1,333,000 1b/hr Atmospheric 170°F 634 1b/hr Noncondensable Gases High 85% Total Flow Plant 23 MW 20 MW Dry Cooling 50°F Modular Maximum Minimum Barge &Truck Constant Output 4 Turbine-Generator Sets 213,000 tb 5.8 MW 155.2 1b/hr 3,104,000 tb/hr at 57 psia 3.45 4 +1 standby 775,000 1b/hr 68 psia 301°F 100% 1.72 2+1 standby 1,552,000 \b/hr Atmospheric 200°F 714 Wb/hr Noncondensable Gases High 85% 10. The maximum net power generation potential of an average production well,the minimum geothermal fluid flow required per net kw of power generation,the minimum total geothermal fluid flow required and the minimum number of production wells required are derived from curves shown in Figures 16 through 20 where the wellhead pressure vs flow rate curve for a commercial well with 13-3/8 inch casing is cross- plotted with electricity generation curve for the various power cycles studied.To stay within safe operating conditions,the well flow and wellhead pressure have been limited to 900,000 Ib/hr and 57 psia respectively. The average flow per production well,the production wellhead pres- sure and the production wellhead temperature are derived from the number of operating production wells provided.No-bottomfish development case power development does not include any dedicated spare production well as it cannot be economically justified. However,the "low-bottomfish catch"case power development does include one dedicated spare production well. The number of injection wells required is based on the assumption that one injection well will be able to dispose of 1,800,000 lb/hr of cooled geothermal fluid at atmospheric wellhead pressure. The average flow per injection well is derived from the number of operating injection wells provided.No-bottomfish development case power development does not include any dedicated spare injection wel] as it cannot be justified economically.However,the "low-bottomfish catch"case power development does include one dedicated spare injec- tion well. Waste discharge to atmospheric assumes total removal of the non- condensable gases contained in the geothermal fluid.Analysis of gas samples collected during the Makushin ST-1 test indicate,that very low initial concentrations of noncondensable gases (approximately .023 percent by weight)can be expected.The gases are predominantly C05(94%),plus Ho(5%),with traces of HoS,NH3,Ho,Ar, CHa,and He.They should therefore,not pose any problems in the conversion cycles and can be directly discharged to atmosphere. The composition of liquids produced from the Makushin Resource is given in the Unalaska Geothermal Exploration Project Phase II Final Report.The geothermal fluid,averaging approximately 6,000 ppm total dissolved solids (TDS),is not expected to be corrosive or to pose any scaling problems,thus allowing for use of standard con- struction materials.Because of the benign nature of the fluid, filtration is not expected to be required prior to reinjection of the spent fluid. 32 ceWELLHEADPRESSURE-PSIAFIGURE 16 POTENTIAL NET POWER GENERATION OF AVERAGE PRODUCTION WELL WHEN USING SINGLE FLASH STEAM CYCLE 4 a 120 |-6 100 -l5 = = y = [as] ce i -a o L rr60438 = cre v == 40 }-ce +22aKrs< :et 5 2 we a =i ot 5 4 201-Se =<1 l l !l l l l l _ 100 200 300 400 500 600 700 800 900 WELL FLOW-1000 LBS/HR RGI E1560 veWELLHEADPRESSURE-PSIAFIGURE 17 POTENTIAL NET POWER GENERATION OF AVERAGE PRODUCTION WELL , WHEN USING DOUBLE FLASH STEAM CYCLE 4 e 120 5 100 15 = -= S 80 -]4 E tc ts == rc 60}--}3 ou= = -=<_ |we"== ao}-OyeF S 22 rye u.=Ag =2 -Se =ioF:2 201-é =---|1 ae l |. 100 200 300 400 500 600 700 800 900 WELL FLOW -1000 LBS/HR AGI E1561 GEWELLHEADPRESSURE-PSIAFIGURE 18 . POTENTIAL NET POWER GENERATION OF AVERAGE PRODUCTION WELL WHEN USING BINARY CYCLE 4 J 120 =-16 100 | is == [ = 2 80 f- j4&cc ul Leas = uu ao tr60F-{3 8 oOo a io"=z 40}-7 S +422 ===i 5 2 20}-=1 |I jd ||i |i . 100 200 300 400 500 600 700 800 900 WELL FLOW-1000 LBS/HR AGI E1589 9€WELLHEADPRESSURE-PSIAFIGURE 19 POTENTIAL NET POWER GENERATION OF AVERAGE PRODUCTION WELL | WHEN USING HYBRID CYCLE | 120 = 100 80 }-- _re40Ry POTENTIALNETPOWERGENERATION-MWMAXIMUMFLOW20 |i l |||l |i j 100 200 300 400 500 600 700 800 900 WELL FLOW -1000 LBS/HR al aad RGt E1558 LEWELLHEADPRESSURE-PSIAFIGURE 20 POTENTIAL NET POWER GENERATION OF AVERAGE PRODUCTION WELL WHEN USING TOTAL FLOW CYCLE 120 -6 100 -- 80 POTENTIALNETPOWERGENERATION-MW©|yeyJaMAXIMUMFLOW20- l j i j |I !|| 100 200 300 400 500 600 700 800 900 WELL FLOW-1000 LBS/HR AGIE 1562 11.All alternative power plants on Makushin Volcano are assumed to beenclosedandincludethefollowingthreemainprefabricatedbuildings: a. b. A power building;housing the power generation equipment. A control building;housing the control room,switch gear,and laboratory. A maintenance building;housing the maintenance shop,the ware- house for storage of spare parts,and the living quarters for the crew. 38 GEOTHERMAL POWER DEVELOPMENT COST COMPARISONS The capital costs required to develop geothermal power using each of the alternative processes considered for both "No-Bottomfish Demand"and "Low- Bottomfish Catch”cases are shown on Tables 3 and 4.Each power development alternative includes power plant costs and associated major field development costs.Costs for infrastructure items,such as road and transmission line, are not included as they are identical for all alternatives.All costs are in 1983 dollars and do not include escalation and interest during construction. Power plant costs are limited to the costs of the power generation units and are broken down as follows: 1.Power plant engineering and fabrication costs which include engineering,shop fabrication and testing of power modules, prefabricatton of auxiliary systems and transportation to Driftwood Bay. 2.Power plant construction costs which include transportation fromDriftwoodBaytojobsite,construction camp,construction labor,and construction management.Construction costs at the Unalaska site are estimated to be four times the construction costs at a site in the continental United States. Associated field development costs are limited to the following major items: 1.Production well costs which include drilling,completion,and short testing of all production wells to be provided to supply the geo- thermal fluid flow required by the power plant. 2.Injection well costs which include drilling,completion,and short testing of all injection wells to be provided to dispose of the residual geothermal fluid flow from the power plant. 3.Production pipeline costs which include engineering and construction of insulated pipeline between production wells and power plant. 4,Injection pipeline costs which include engineering and construction of noninsulated pipeline between power plant and injection wells. Costs include injection pumps as required. Figures 21,22,and 23 were developed to show the total installed cost andtheinstalledcostperkwofageothermalpowerplant,using each alternative process considered,based on power generation unit size.To illustrate theimpactofthehighconstructioncostsestimatedfortheIslandofUnalaska,wehaveshownboththeinstalledcostsatahypotheticalsiteinthe"lower 48" United States and the costs at the site on Unalaska Island. It is notable that the cost per installed kw of geothermal power decreasessubstantiallyasthepowergenerationunitsizeincreases,particularly for flash steam plants. 39 OvTABLE 3 NO-BOTTOMFISH DEVELOPMENT CASE GEOTHERMAL POWER DEVELOPMENT CAPITAL COSTS MATRIX ALL COSTS IN THOUSANDS OF 1983 DOLLARS Power Plant Net Generating Capacity Number of Power Generation Units Power Plant Engineering and Fabrication Costs Power Plant Construction Costs Subtotal Installed Power Plant Costs Number of Production Wells Provided Number of Injection Wells Provided Production Well Costs Injection Well Costs Production Pipeline Costs Injection Pipeline Costs Subtotal Field Development Costs Total Geothermal Power Development Costs Cost Per MW of Net Power Generated Single Flash Double Flash Total Flow Steam Plant Steam Plant Binary Plant Hybrid Plant Plant 10 MW 10 MW 6.7 MW 10 MW 10 MW 2 2 2 3 2 14,820 17,000 8,590 14,520 18,720 21,800 24,800 =1,440 =20,080 =27,200 36,620 41,800 20,030 34,600 45,920 3 2 2 2 2 2 1 J ]] 8,151 6,099 6,099 6,099 6,099 3,200 1,600 1,600 1,600 1,600 1,445 963 963 963 963 900 680 453 453 680 13,696 9,342 9,115 9,115 9,342 50,316 51,142 29,145 43,715 55,262 5,031.6 5,114.2 4,350 4,371.5 5,526.2 TYTABLE 4 LOW-BOTTOMFISH DEVELOPMENT CASE GEOTHERMAL POWER DEVELOPMENT CAPITAL COSTS MATRIX ALL COSTS IN THOUSANDS OF 1983 DOLLARS Single Flash Double Flash Total Flow Steam Plant Steam Plant Binary Plant Hybrid Plant Plant Power Plant Net Generating Capacity 20 MW 20 MW 20 MW 20 MW 20 MW Number of Power Generation Units 4 4 6 6 4 Power Plant Engineering and Fabrication Costs 28,160 32,300 25,770 29,040 37,440 Power Plant Construction Costs 41,420 47,120 34,320 40,160 54,400 Subtotal Installed Power Plant Costs 69,580 79,420 60,090 69,200 91,840 Number of Production Wells Provided 6 5 5 4 5 Number of Injection Wells Provided 4 3 3 3 3 Production Well Costs 14,907 12,555 12,555 10,503 12,555 Injection Well Costs 6,400 4,800 4,800 4,800 4,800 Production Pipeline Costs 2,701 2,251 2,251 1,801 2,251 Injection Pipeline Costs 2,/18 2,038 _1,359 _1,359 2,038 Subtotal Field Development Costs 26,726 21,644 20,965 18,463 21,644 Total Geothermal Power Development Costs 96,306 101,064 81,055 87,663 113,484 Cost Per MW of Net Power Generated 4,815.3 5,053.2 4,052.8 4,383.2 5,675.2 cvFIGURE 21 GEOTHERMAL POWER PLANT TOTAL INSTALLED COST vs.POWER PLANT UNIT SIZE 130 F- wseracrercmem SINGLE FLASH STEAM CYCLE Po120eeeoe=DOUBLE FLASH STEAM CYCLE wt =ee ee TOTAL FLOW CYCLE .7110=DonPTTTTTTTTitty)seer BINARY CYCLE Z ”UNALASKACONSTRUCTIONc100HYBRIDCYCLE-_-TOTALINSTALLEDCOSTINMILLIONSOFDOLLARSCONTINENTALUSACONSTRUCTION5 10 15 20 25 30 35 40 45 50 POWER PLANT UNIT SIZE -MW NET RGIE 1565 FIGURE 22 GEOTHERMAL POWER PLANT INSTALLED COST PER KW vs.POWER PLANT UNIT SIZE BASED ON CONTINENTAL USA CONSTRUCTION INSTALLEDCOST-$/KW2600 ' . \-SINGLE FLASH STEAM CYCLE \ae-§=DOUBLE FLASH STEAM CYCLE2400\oo me ees oe *TOTAL FLOW CYCLE \Senccccensescsuese BINART CYCLE \HYBRID CYCLE 2200 \\\ 2000 1800 1600 1400 1200 a .se ° e - .me . , 1000 ae oe 800 ws l i |!||l i |= 5 0 #41 2 2 30 35 £440 £45 50 POWER PLANT UNIT SIZE -MW NET 43 RGIE 1564 INSTALLEDCOST-$/KWFIGURE 23 GEOTHERMAL POWER PLANT INSTALLED COST PER KW vs. POWER PLANT UNIT SIZE BASED ON UNALASKA CONSTRUCTION SINGLE FLASH STEAM CYCLE «= DOUBLE FLASH STEAM CYCLE wemmecamemees TOTAL FLOW CYCLE eseccesncocusce aeee BINARY CYCLE \HYBRID CYCLE 5 10 15 20 25 30 35 40 45 50 POWER PLANT UNIT SIZE -MW NET 44 RGILE 1563 POSITIVE AND NEGATIVE ASPECTS OF EACH TYPE OF POWER PLANT CONSIDERED 1.Single Flash Steam Plant a.Positive Aspects 1.Uses proven and reliable process to generate electrical power. 414i.Simple plant with few components. 411.Easily operated and maintained. b.Negative Aspects 4.Requires more geothermal fluid flow and therefore more wells than all other alternative plants due to a very low brine utilization factor. 41.Requires careful monitoring during winter months operation to prevent freezing of steam condensate. 411.Not cost competitive in the small unit size contemplated. 2.Double Flash Steam Plant a.Positive Aspects i.Uses proven and reliable process to generate electrical power. it.Simple plants with few components. 411.Easily operated and maintained. b.Negative Aspects 1.Requires careful monitoring during winter months operation to prevent freezing of steam condensate. 11.Not cost competitive in the small unit size contemplated. 3.Binary Plant a.Positive Aspects 4.High brine utilization factor. 41.Does not run the risk of freezing during winter months operation due to the low freezing point of the working fluid. 45 411.Lowest cost in the small unit size contemplated. iv.Can be easily modularized. Negative Aspects 4.Uses less proven process than flash steam process. 41.Some working fluids may pose potential fire or environ- mental hazards if they should leak to the atmosphere. 411.Requires a large number of components increasing theoperationandmaintenancecosts. 4.Hybrid Power Plant a.Positive Aspects j.Highest brine utilization factor. 41.Combines the advantages of both steam flash and binary processes. Negative Aspects i.To be efficient and economical,must be developed in a minimum of 10 MW increments which provides for large excess capacity up front. 41.Combines the disadvantages of both flash steam and binary processes. 5.Total Flow Plant da.Positive Aspects 1.High brine utilization factor. Negative Aspects 4.Uses the least proven of all studied processes. ii.Requires careful monitoring during winter months operation to prevent freezing of steam condensate. 411.Not cost competitive in the small unit size contemplated. 46 POWER CONVERSION PROCESS RECOMMENDATION Considering the positive and negative aspects of each cycle considered as discussed previously,the binary cycle is recommended as the best power con- version process to generate electricity from the Makushin resource for the following reasons: 1.It is the most economical process for the small estimated base load demand (5 to 20 MW)of the electrical system. 2.It is an efficient power conversion process requiring relativelysmallftelddevelopmenttosupportthepowerplant. 3.While it has not been as widely used as the flash steam process,it is easily developed in small units thus,adding reliability to the overall plant. 4.It can be fabricated in small,shop assembled and tested modules that can be easily transported and installed. 5.It can be easily automated to require minimal operating supervision. 6.It does not incur a risk of freezing during winter months operation. 7.It can be installed quickly,adding scheduling flexibility if power demand increases faster than expected. 47 BINARY SYSTEM DEVELOPMENT COSTS The economic feasibility of developing the Makushin geothermal resource for electrical power generation will be assessed by ACRES American,Inc.as requested by the Alaska Power Authority.To permit this assessment,Republic Geothermal,Inc.has prepared the following tables showing the capital cost estimate and the operation and maintenance cost estimate for the 10 MW and the 30 MW scenario.All cost estimates are based on the use of the recommended binary cycle for power generation. 1.Table 5 -Capital cost estimate for the development of a 10 MW gross(6.7.MW net)geothermal power plant. 2.Table 6 -Capital cost estimate for the development of a 30 MW gross(20 MW net)geothermal power plant with all the wells drilled during the first phase of plant development. 3.Table 7 -Capital cost estimate for the development of a 30 MW gross(20 MW net)geothermal power plant with the wells drilled as needed in each phase of plant development. 4.Table 8 -Operation and maintenance cost estimate for a 10 MW gross(6.7 MW net)geothermal plant development. 5.Table 9 -Operation and maintenance cost estimate for a 30 MW gross (20 MW net)geothermal plant development. An analysis of the costs of drilling all wells required for the 30 MW gross power plant upon construction of the initial phase,instead of drilling the wells as each increment is constructed shows the following: If all wells are drilled in the initial phase of development (as shown on Table 6),the total development costs are $202,316,000.This requires a total capacity investment of $101,158,000 having a 1983 present valkue of $45,984,000 if discounted back at a factor of 10.5%per year. If the wells are drilled as each increment 1s constructed (as shown on Table 7),the total development costs are $220,334,000.This requires a total equity investment of $110,172,000 having a 1983 present value of $46,201,000 if discounted back at a factor or 10.5%per year. Assuming that the amortization of the debt starts upon completion of each phase of construction,a high penalty would be paid if all wells are drilled up front,as the debt service will be substantially higher.Based on this, and because of the uncertainties in electrical demand growth,it is recom- mended that the wells be drilled as each increment is developed,thus minimizing the risks to the existing consumer base. 48 TABLE 5 NO-BOTTOMFISHING DEVELOPMENT CASE UNALASKA 10 MW GROSS (6.7 MW NET)BINARY POWER PLANT DEVELOPMENT COSTS IN THOUSANDS OF DOLLARS Field Development Costs (1983) Production Wells (2) Injection Well (1) Well Testing Direct Operation &Maintenance Home Office Start-Up Subtotal Field Costs Power Plant Costs (1983) Power Plant Eng.&Const. Production Pipeline Injection Pipeline Spare Parts Consulting &Coordination Start-Up Insurance Subtotal Power Plant Costs Other Costs (1983) Road Construction Transmission Line Subtotal Other Costs TOTAL COSTS (1983) Escalation TOTAL ESCALATED COSTS Interest Expenses TOTAL DEVELOPMENT COSTS Equity Debt TOTAL USE OF FUNDS Total 1985 1986 1987 1988 Costs 3,747 2,352 0 0 6,099 7,600 0 0 0 1,600 521 236 0 0 157 513 526 426 134 2,199 475 600 400 525 2,000 0 0 0 210 210 6,856 3,714 B26 1,469 12,865 0 2,504 10,516 7,010 20,030 0 0 963 0 963 0 0 0 453 453 0 0 0 200 200 162 200 200 238 800 0 0 0 400 400 0 0 130 130 260 162 2,704 11,809 8,431 23,106 0 5,146 0 0 5,146 0 0 0 6,405 6,405 0 5,146 0 6,405 13,551 7,018 11,564 12,635 16,305 47,522 1,017 2,602 3,927 6,564 14,110 8,035 14,166 16,562 22,869 61,632 259 978 2,018 3,399 6,654 8,294 15,144 18,580 26,268 68,286 4,147 7,572 9,290 13,134 34,143 4,147 7,572 9,290 13,134 34,143 8,294 15,144 18,580 26,268 68,286 osField Development Costs (1983) Production Wells (5) Injection Wells (3) Well Testing Direct Operation &Maint. Home Office Start-Up Subtotal Field Costs Power Plant Costs (1983) Power Plant Eng.&Const. Production Pipeline Injection Pipeline Spare Parts Consulting &Coordination Start-Up Insurance Subtotal Power Plant Costs Other Costs (1983) Road Construction Transmission Line Subtotal Other Costs TOTAL COSTS (1983) Escalation TOTAL ESCALATED COSTS Interest Expenses TOTAL DEVELOPMENT COSTS Equity Debt TOTAL USE OF FUNDS LOW-BOTTOMFISH CATCH CASE TABLE 6 UNALASKA 30 MW GROSS (20 MW NET)BINARY POWER PLANT DEVELOPMENT COSTS IN THOUSANDS OF DOLLARS ALL WELLS DRILLED IN FIRST PHASE OF POWER PLANT DEVELOPMENT Total Costs Total Costs Total Costs Total Costs 1985 1986 1987 1988 First Phase 1991 1992 Second Phase 1998 1999 Third Phase All Phases 3,747 4,404 4,404 0 12,555 0 0 0 0 0 0 12,555 1,600 1,600 1,600 0 4,800 0 0 0 0 0 0 4,800 621 354-354 0 1,229 0 0 0 0 0 0 1,229 513 526 526 734 2,299 426-734 1,160 426 734 1,160 4,619 475 600 600 525 2,200 400 525 925 400 =525 925 4,050 0 0 0 210 210 0 __150 150 0 __100 100 460 6,856 7,484 7,484 1,469 23,293 826 1,409 2,235 826 1,359 2,185 27,713 0 2,504 10,516 7,010 20,030 10,015 10,015 20,030 10,015 10,015 20,030 60,090 0 0 963 0 963 963 0 963 325 0 325 2,251 0 0 0 453 453 0 453 453 0 453 453 1,359 0 0 0 200 200 0 200 200 0 200 200 600 162 200 «=200-Ss-238 800 200 =.200 400 200 200 400 1,600 0 0 0 400 400 0 200 200 0 150 150 750 0 0 130 _130 260 0 _130 130 0 130 130 520 162 2,704 11,809 8,43)°23,106 11,178 11,198 22,376 10,540 11,148 21,688 67,170 0 5,146 0 0 5,146 0 0 0 0 0 0 5,146 0 0 0 6,405 6,405 0 0 0 0 0 0 6 405 0 5,146 0 6,405 11,551 0 0 0 0 0 0 11,551 7,018 15,334 19,293 16,305 57,950 12,004 12,607 °24,611 11,366 12,507 28,873 106,434 1,017 3,451 5,997 6,564 17,029 8,621 10,570 19,191 19,993 24,416 44,409 80,629 8,035 18,785 25,290 22,869 74,979 20,625 23,177 43,802 31,359 36,923 68,282 187 ,063 259 1,125 2,598 4,295 8,277 655 2,091 2,746 997 3,233.4,230 15,253 8,294 19,910 27,888 27,164 83,256 21,280 25,268 46,548 32,356 40,156 75,512 202,316 4,147 9,955 13,944 13,582 41,628 10,640 12,634 23,274 16,178 20,078 36,256 101,158 4,147 9,955 13,944 13,582 41,628 10,640 12,634 23,274 16,178 20,078 36,256 101,158 8,294 19,910 27,888 27,164 83,256 21,280 25,268 46,548 32,356 40,156 72,512 202,316 TSField Development Costs (1983) Production Wells (5) Injection Wells (3) Well Testing Direct Operation &Maint. Home Office Start-Up Subtotal Field Costs Power Plant Costs (1983) Power Plant Eng.&Const. Production Pipeline Injection Pipeline Spare Parts Consulting &Coordination Start-Up Insurance Subtotal Power Plant Costs Other Costs (1983) Road Construction Transmission Line Subtotal Other Costs TOTAL COSTS (1983) Escalation TOTAL ESCALATED COSTS Interest Expenses TOTAL DEVELOPMENT COSTS Equity Debt TOTAL USE OF FUNDS "TABLE 7 LOW-BOTTOMFISH CATCH CASEUNALASKA30MWGROSS(20 MW NET)BINARY POWER PLANT DEVELOPMENT COSTS IN THOUSANDS OF DOLLARS WELLS DRILLED AS NEEDED IN EACH PHASE OF POWER PLANT DEVELOPMENT ' Total Costs Total Costs 1986 1987 1988 First Phase 199]1992 Second Phase 1998 Total Costs Total Costs 1985 1999 Third Phase All Phases 3,747 2,352 0 0 6,099 5,799 0 5,799 3,747 0 3,747 15,645 1,600 0 0 0 1,600 1,600 0 1,600 1,600 0 1,600 4,800 521 236 0 0 757 354 0 354 236 0 236 1,347 513 526 426 734 2,199 526 734 1,260 526 734 1,260 4,719 475 600 400 525 2,000 600 §25 1,325 600 §25 1,125 4,25000021021001501500100100460 6,856 3,714 826 1,469 12,865 8,879 1,409 10,288 6,709 1,359 8,068 31,221 O 2,504 10,516 7,010 20,030 10,015 10,015 .20,030 30,015 10,015 20,030 60,090 0 0 963 0 963 963 0 963 325 0 325 2,251 0 0 0 453 453 0 453 -453 0 453 453 1,359 0 0 0 200 200 0 200 200 0 200 200 600 162 200 200 238 800 200 200 400 200 200 400 1,600 0 0 0 400 400 0 200 200 0 150 150 750 0 0 130 130 260 0 130 130 0 130 130 520 162 2,704 11,809 8,431 23,106 11,178 11,198 22,376 10,540 11,148 21,688 67,170 O 5,146 0 0 5,146 0 0 0 0 0 0 5,146 0 0 0 6,405 6,405 0 0 0 0 0 0 6,405 O 5,146 0 6,405 11,551 0 0 0 0 0 0 41,551 7,018 11,564 12,635 16,305 47 $22 20,057 12,607 32,664 17,249 12,507 29,756 109 ,942 1,017.2,602 3,927 6,564 14,110 14,405 10,570 24,975 30,342 24,416 54,758 93,843 8,035 14,166 16,562 22,869 61,632 34,462 23,177 57,639 47,591 36,923 84,514 203,785 259 978 2,018 3,399 6,654 1,096 2,999 4,095 1,513 4,297 5,810 16,559 8,294 15,144 18,580 26,268 68 ,286 35,558 26,176 61,734 49,104 41,220 90,324 220,344 4,147 7,572 9,290 13,134 34,143 17,779 13,088 30 ,867 24,552 20,610 45,162 110,172 4,147 7,572 9,290 13,134 34,143 17,779 13,088 30,867 24,552 20,610 45,162 110,172 8,294 15,144 18,580 26,268 68,286 35,558 26,176 61,734 49,104 41,220 90 ,324 220,344 TABLE 8 NO-BOTTOMFISHING DEVELOPMENT CASE UNALASKA 10 MW GROSS (6.7 MW NET)BINARY POWER PLANT COMBINED PLANT AND FIELD ANNUAL OPERATION AND MAINTENANCE COSTS (Thousands of 1983 Dollars) Administration 85 Operation and Maintenance Labor 580 Contract Maintenance 350 Well Reconditioning 75 Outside Consulting 150 Power Plant Insurance 100 Miscellaneous __460 TOTAL ANNUAL COST 1,800 52 TABLE 9 LOW-BOTTOMFISH CATCH CASE UNALASKA 30 MW GROSS (20 MW NET)BINARY POWER PLANT COMBINED PLANT AND FIELD ANNUAL OPERATION AND MAINTENANCE COSTS (Thousands of 1983 Dollars) Administration 170 Operating and Maintenance Labor 790 Contract Maintenance 650 Well Reconditioning 225 Outside Consulting 150 Power Plant Insurance 300 Miscellaneous 550 TOTAL ANNUAL COST 2,835 53 Capital Costs Capital cost estimates show the field development costs,power plantconstructioncosts,and other necessary costs in 1983 dollars for each alternative.Addition of these costs gives a total development cost in 1983 dollars.To this total,escalation and interest during construction are added to give a total capital cost required for the development of each alternative. 1.Field Development Costs The field development costs include production well drilling andcompletion,injection well drilling and completion,well testing necessary to prove productivity and injectivity,direct field operation and maintenance during development,home office sup- port and services,and field operation and maintenance during power plant start-up. Ten MW gross field development includes two production wells and one injection well.This provides for almost a full spare pro- duction well when the plant is operated at full capacity and ensures adequate power generation in the unlikely event of the catastrophic failure of a production well.The injection well provides approximately 40 percent more capacity than necessary to reinject the total fluid required to run the power plant at full capacity.In the very unlikely event of a catastrophic failure,it is assumed that temporary disposal of the spent brine on the ground would be permissible. Thirty MW gross field development includes five production wells and three injection wells,which provides for one spare produc- tion well and one spare injection well. Power Plant Costs Power plant costs include engineering and construction of the binary units,engineering and construction of the production pipeline,engineering and construction of the injection pipe- Tine,spare parts,consulting services and coordination support, start-up including operator training,and fire and casualty insurance during construction. 10 MW gross power plant construction is assumed to take place during spring and summer months (April to October)of the first year of construction and continuously from April to end of con- struction of second year of construction. First phase of 30 MW gross power plant construction (20 MW gross)is assumed to take place as described above.Second and third phases will take place continuously,starting in April of the first year until completion at the end of the second year. 54 Power plant engineering and construction costs are based on aturnkeytypeproposalofferedbytheBenHoltCo.for a binary plant similar to one being built in the Sierra Nevada of California.Construction costs are multiplied by a factor of four to reflect the high construction cost expected on Unalaska. Construction field costs include manual labor,nonmanual labor, indirect field costs and construction management. Other Costs Other costs include the construction of a road from Driftwood Bay to the power plant site and the construction of a 34.5 kv transmission line from the power plant site to a substation in Dutch Harbor. The road construction estimate is based on a Dames and Moore study prepared for Republic Geothermal,Inc.and Alaska Power Authority in February 1,1983.It includes existing road grading,repair and gravel surfacing;new road construction including culverts and major.canyon crossing;and mobilization and demobilization.To ensure that the road is ready to receive major equipment as it is unloaded from the barge,road construc- tion is scheduled for the summer months of the year prior to actual field construction of the first 10 MW gross power plant. The transmission line estimate is based on burial of the cable approximately 30"underground from the power plant site to Broad Bay and then going underwater to Dutch Harbor.The estimate includes a substation to be located in Dutch Harbor that will tie the power plant to the distribution system.It also includes a 30 percent contingency to account for the uncertain- ties about the underwater portion of the Tine which has to be buried in the ocean floor. Escalation Escalation is based on an annual inflation rate of seven percent. Interest Expenses Interest expenses represent the interest to be paid during construction based in a debt to equity ration of one and on an interest rate of 12 percent per year. 55 Operation and Maintenance Costs Operation and maintenance (0&M)costs estimates show the total annualcostin1983dollarstooperateandmaintaintheoverallgeothermal development. O&M costs assume that operation and maintenance labor as well as administration personnel are shared by both power plant and field. O&M costs do not include any royalty payment on the resource utilized during commercial operation or any taxes on the power plant or field. 56 CONCLUSTONS On the strength of this study,the following conclusions can be drawn: 1.The Makushin geothermal resource can be utilized to generate elec- trical power for the towns of Unalaska and Dutch Harbor. 2.Due to its high development costs,geothermal power is best suited to meet baseload demand of the electrical system. 3.The binary cycle is the preferred power conversion process to generate electricity from the Makushin geothermal resource. 4.A 10 MW gross (6.7 MW net)geothermal power development would satisfy the electrical load demand estimated by Acres American,Inc.for the "no-bottomfishing"case past the year 2000.Preferred development would consist of two identical 5 MW gross binary units together with two production and one injection wells. 5.A 10 MW gross geothermal power development could be commercial byJanuary1989andwouldcostatotalof$68,286,000. 6.A 30 MW gross (20 MW net)geothermal power development would satisfy the electrical load demand estimated by Acres,America,Inc.for the "low-bottomfish catch"case past the year 2000.It is recommended that such a power plant be developed in three phases timed to the growth in demand.The first phase of development would consist of two identical 5 MW gross binary units together with two production and one injection wells and would become commercial in January 1989. The second phase of development would consist of duplicating the initial phase and would become commercial in January 1993.The third phase of development would consist of two additional binary units identical to the units provided in phases 1 and 2 together with one production and one injection wells and would start commercial opera- tion in January 2000. 7.A 30 MW gross geothermal power development as outlined above would cost a total of $220,344,000. 57 as TG),Ol DRAFT RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES APPENDIX:UNALASKA APRIL 198a4 DRAF PREPARED BY: Ait L ALASKA POWER AUTHORITY___| TABLE OF CONTENTS Section A -Summary of Findings and Recommendations ...«««©©«©«©©©« B -Demographic and Economic Conditions .....«©©«©©«©«©© C -Community Meeting Report...««©«©©©«©©©©©©©©©©©© D -Existing Power and Heating Facilities ..2.«.«©©«©«©«©we «© E -Energy Balance...2.2 «©©©©«©©©©©©©©©©6 we ew F -Energy Requirements Forecast...««©©©©©©©«©©©©©© G =Village Technology Assessment ..«.««©©©©«©©©©©©©«©2 H -Energy Plan Desrciptions and Assumptions...«««6 ««©«©«©» I -Energy Plan Evaluations ..2.«©2 ©©©«©©©©©©©©©©© J -Environmental and Social Impacts.....2.«©«©«©«©©«©©©« APPENDIX A --Cost Estimates Developed by Republic Geothermal,Inc. Geothermal Plant at Mt.Makushin APPENDIX B ==Alaska Power Authority Project Evaluation Guidelines Page 29 43 A_-SUMMARY OF FINDINGS AND RECOMMENDATIONS A.l -General After an analysis of the information gathered on the communities of Una- laska and Dutch Harbor,the recommendations which seem to be most appropri- ate to the existing and anticipated conditions and the wishes of village residents are as follows: l.For the near term,and for the forseeable future,the most economical source of electricity will be diesel engines,especially when they are equipped with waste heat recovery systems. Based on available data,a large (30 MW)geothermal facility does not appear to be economically competitive with the diesel resources which were examined.A smaller (10 MW)geothermal plant is more competitive in cost,but still does not appear to be as economical as diesel. Because of the preliminary nature of this report and the small differ- ences in the costs associated with the diesel system with and without the 10 MW geothermal plant,it is recommended that further research be conducted to provide refined cost and plant operating data.Future studies should concentrate their efforts on developing feasibility level data for geothermal plants in the 5 to 10 MW range. The City should very carefully consider siting new diesel generators so that the sale of recovered waste heat may be facilitated.A number of power plants (perhaps even individual power plants for each new generat- ing unit)should be considered so that all available waste heat can be delivered to users.Piping lengths must be kept as short as possible to minimize heat losses.The sale of waste heat to seafood processors and other users could offset a substantial amount of the system's cost. The City should consider using fuels heavier than the No.2 diesel fuel they currently burn in their diesels.These less-refined fuels can be obtained at significantly less cost than the light distallate fuels. An investigation should be made of the availability of systems which use waste heat from diesel engines to produce cold temperatures.Such sys- tems could be attractive to the seafood processors located near the gen- erator plant(s). Hydroelectric plants identified by the US Army Corps of Engineers,while not providing a substantial savings to the power system,may be worthy of further consideration.They may offer other benefits to the City, such as an enhanced water supply. Considering its present state of development,wind energy is not a viable alternative for use at Unalaska in any role except that of an experimental installation.Unalaska could be an appropriate site for a wind turbine demonstration project because of the abundant wind resource there.Because of the relatively low cost of diesel fuel at Unalaska,a wind turbine would face stiff economic competition and would likely not show any advantage over the diesel system. B_-DEMOGRAPHIC AND ECONOMIC CONDITIONS B.1 -Location Unalaska and Dutch Harbor are located on one of the Fox Islands,a group of islands in the northern part of the Aleutian Islands.The community of Dutch Harbor is on Amaknak Island,a small island separated by Unalaska Island (and the village of Unalaska itself)by a narrow channel.The sep- aration of these two communities is so small that,for the purposes of this report,they will be considered to exist on the same island.In many cases,this report will consider them as one homegeneous community. B.2 -Population Data provided by the State of Alaska's Division of Community and Regional Affairs shows the following population trends for Unalaska (including Dutch Harbors Year:1960 1970 1980 1983 (December) Population:218 340 1,322 1,983 In the recent past (as recently as 1970),the majority of Unalaska's resi- dents have been Aleuts,the original inhabitants of the area.The rela- tively sudden predominance of white residents has come about as a result of Unalaska's recognition as an excellent base for commercial crabbing and fishing activities. B.3 -Economy Unalaska stands as the economic center af the Aleutian Islands and the southern part of the Alaska Peninsula.Dutch Harbor provides virtually the only deepwater in Alaska west of Kodiak.Because of the quality of its harbor,Unalaska has become a base for crabbing and bottomfishing fleets which operate throughout the North Pacific;the area's salmon industry;and the oil companies involved in exploratory activities in the southern Bering Sea and North Pacific. A significant industry has developed to support the fishing and shipping activities in the area.Dutch Harbor has a number of marine machine shops and a repair facility which boasts of being "Western Alaska's largest ship- yard."A major refiner operates a sizeable bulk fuel plant at Dutch Harbor,dispensing a wide range of fuels throughout the region.So depend- ent is the community upon the maritime industry that many businesses list their ship-to-shore channels in advertisements. The University of Alaska operates a Rural Education Center in Unalaska, There is a local television station and a radio station.Two airlines serve Unalaska,one of which recently inagurated jet service to the island. Over the past several years,especially with the decline in prices paid for Alaska salmon and the poor performance of the Aleutian crab industry,con- siderable interest has been given to the establishment of a bottomfish industry in the area,If such an industry is developed,it seems logical that Unalaska would be given prime consideration for the base of the neces- sary support industry (supplies,repair facilities,fuel,"R&R"opportuni- ties,etc). A number of studies have been done to assess the possible impact of a bot- tomfish industry on the area,some of which are mentioned in Part F and Part H of this report.In some cases,the forecasts of future population made for Unalaska and Dutch Harbor seem quite difficult to believe.One study,developed as a part of the work done to justify the expansion of the Dutch Harbor airport,suggested that under certain conditions,the year- round population of Unalaska could reach more than 22,000 by the year 2,000.This represents more than a ten-fold increase in population in the next fifteen years.The work done for this energy reconnaissance suggests that such a forecast may be unrealistically inflated.Acres expects much less growth for the community. B.4 -Government Unalaska is incorporated as a first class city (as are most other major cities throughout the state)with a mayor and city council directing the city government.The city provides infrastructure (water,sewer,electric- ity,roads,etc)services for residents of Unalaska and Dutch Harbor. B.5 -Transportation As was mentioned previously,Unalaska is served by two airlines.The "traditional"carrier,Reeve Aleutian Airways,operates Lockheed Electras (L-188's)and Japanese-built Nihon YS-ll's into Dutch Harbor from Anchorage via Cold Bay.Air-Pac,operating in cooperation with Alaska Airlines,runs direct flights between Anchorage and Dutch Harbor using Fairchild Metro II's (F-27's)and Nihon YS-ll's.It was Air-Pac which has recently intro- duced jet service to Unalaska using British Aerospace BA-146's.Unlike the similarly-sized Electras,the B8A-146's are designed to take off fully laden from as little as 3500 feet of runway.The existing runway at Dutch Harbor is only about 4,300 feet long,seriously limiting the type of aircraft available to serve the community. Plans have been developed to expand the existing airport or to develop a new,larger facility.The considerable expense ($30 to $100 million depending upon the approach taken)of these options and the recent decline in oil revenue makes the near-term likelihood of improved airport facili- ties quite remote. Except for the airlines,there is no "practical"way of travelling to or from Unalaska,.The Alaska Marine Highway does provide ferry service toa Unalaska from Homer.A trip from Homer to Unalaska requires four days. Transportation in Unalaska and Dutch Harbor is by car or truck.The City has an extensive and (by rural Alaska standards)well-maintained system of gravel streets and roads.Two taxi services exist as does a truck rental company.Until a bridge was built across the channel between Unalaska and Dutch Harbor,traffic used a car ferry to shuttle between the two communities. References 1."City of Unalaska Electrification Study,"R.W.Retherford Assoc., Anchorage,1979;prepared for the City of Unalaska. 2."Geothermal Potential in the Aleutians:Unalaska,"Morrison-Knudsen Co.Inec.,Anchorage,1981;prepared for the Alaska Division of Energy and Power Development. 3."Aleutian Regional Airport--Project Documentation,"Dames &Moore, Anchorage,1982,prepared for the City of Unalaska. 4."54°North,"54 Degrees North Publishing Co.,Unalaska,1983 5."Going Dutch--AIRPAC Brings the Jet Age to the Aleutians,"Alaska Journal of Commerce and Pacific Rim Reporter,Pacific Rim Publishing Co.,Anchorage,March 26,1984. 6."United States Government Flight Information Publication--Supplement, Alaska"US Dept of Commerce,National Oceanic and Atmospheric Admin, Nat'l Ocean Survey,Washington,DOC,1980. 7."Jane's All the World's Aircraft,"London,1982. C_-COMMUNITY MEETING REPORT In October 1983,representatives of Acres American (Mr.James Landman)and the Alaska Power Authority (Mr.Donald Markle)paid a 3-day visit to Unalaska.The purpose of the visit was to gather data on energy use and resources and to provide an opportunity for local input to the conduct of this study. In addition to meeting individually with City officials (the City Manager; the City Planner;Director of Public Works;Director of Electrical Pro- jects;and Director of City Finance),the visitors were given the opportun- ity to address the City Council meeting which was held on the 20th of October. The City Council meeting was well attended (about 30 people present)and after the agenda was cleared,Messrs.Landman and Markle were given an opportunity to discuss the purpose of their visit.As was expected,most of the audience's interest was focused on the Power Authority's work on the geothermal test drilling program underway on Mt.Makushin.Mr.Markle was able to give a detailed summary of the project's findings to date and work yet to be undertaken.It was apparent that some people in the audience believed that a geothermal plant,since it used no fuel per se,would pro- vide nearly free electricity.Mr.Landman spent some time explaining that while such a plant would require no fuel,there was little possibility of such a plant actually reducing the price of electricity as it is delivered to the customer.It was pointed out that,even if the City's utility required no diesel fuel,electricity would be far from free.Costs such as system maintenance and administration,debt service,and contingency funds would still have to be paid by the consumers.Data provided by the City's Director of Finance has shown that only about one quarter to one third of the price of electricity goes to pay for fuel.This was explained to the audience and the idea was introduced that the only savings which would be tealized by the construction of a geothermal plant would be from the reduction of fuel use. The discussion by Messrs.Landman and Markle lasted about an hour,at which point the Council meeting adjourned and informal discussion continued. Staff from the local television station (KIW)asked the vistors to partici- pate in an interview at their studios that evening.This was agreed toa, and an interview was taped for later broadcast in the community.As was the case in the City Council meeting,most of the interviewer's interest was in the Power Authority's geothermal exploration project. Prior to leaving the island on the 21st,the visitors visited APA's drill- ing sites on Mt.Makushin with the City Manager and the Director of Elec- trical Projects. D -EXISTING POWER AND HEATING FACILITIES Unalaska electric utility customers are presently served by a municipally- operated diesel generating plant located near the high school and the city offices.The City's diesels have the following ratings: Ll unit at 600 kW 2 units at 300 kW each As part of a pilot project,the Alaska Power Authority installed a waste heat recovery system at the City's plant.This system extracts heat from the diesels'cooling water and distributes that heat to nearby users.In the case of the Unalaska waste heat system,the energy recovered is used to heat the high school and its swimming pool;the city offices;the community center;the city clinic;and the police station.It is estimated by the APA that the waste heat system saves these users about 58,000 gallons of fuel oil each year. These City-owned generators adequately serve the present needs of the resi- dents and the small businesses in Unalaska.However,virtually all of the industrial consumers are located in Dutch Harbor and are not served by a centralized utility system.Individual consumers are responsible for pro- viding their own source of electricity.The processors and other industri- al users all have their own diesel generators.In many cases,Dutch Harbor businesses and dormitory-style housing units are owned by the processor companies.These users are provided with power by their "parents'"gener- ating facilities.A number of processors have equipped their diesel sys- - tems with waste heat recovery systems to provide heat and hot water (not steam)for their own use.: The City utility is in the process of building an underground power distri- bution system to provide electricity to all potential customers in both Unalaska and Dutch Harbor.In conjunction with the construction of this distribution system,they plan to build a new generation plant in Dutch Harbor to provide electricity throughout the system.Present plans call for the installation of a new 2,850 kW generator.The existing units will be moved to the new plant when it is completed.This will mean the end of the availability of waste heat for the swimming pool and city offices. However,it is expected that the new generating plant will have equipment installed to provide waste heat recovery.Careful selection of the site for the new power plant could provide nearby customers for the waste heat. Initial discussions between the City and potential Dutch Harbor industrial customers have shown an almost uniformly enthusiastic reception of the idea of a City-operated utility in Dutch Harbor. Almost all space heat in the city is provided by fuel oil.Although the Unalaska climate is not especially cold by Alaska standards,the area is windy enough that homes and other buildings tend to use more heat than the commonly-used "heating degree days"data for the area would indicate. E_-ENERGY BALANCE An energy balance for a community can be thought of in much the same way an income statement developed for a business is.The energy balance identi- fies all the sources of energy (oil,wood,coal,hydroelectric,etc.)and then lists their corresponding uses (space heating,water heating,power generation,transportation,and heat losses).As its name implies,the total energy contributed by the sources must exactly equal the energy absorbed by the uses.Such a balance statement,especially when it is developed in a graphical form,can give energy planners an idea of where most of a community's energy is coming from and how it is being used. The development of a good energy balance for Unalaska and Dutch Harbor is virtually impossible.This is largely because of the community's role as a major port for the north Pacific and the entire west coast of Alaska.The Chevron bulk plant,which is a major supplier to Dutch Harbor users,also serves the fleet which calls at Dutch Harbor and serves as a transshipment point for bulk fuel deliveries made to western cities and villages.Their recordkeeping does not break out the amount of fuel specifically sold in Unalaska and Dutch Harbor.Of the fuels that pass through the Chevron bulk plant,it is believed that only a small fraction are consumed in the city. F_-ENERGY REQUIREMENTS FORECAST F.1 -Capital Projects Forecast F.1.1 -Scheduled Capital Projects New generating plant to be built by the City (1984) Ongoing development of generating facilities as load grows. F.1.2 -Potential Developments The development of Unalaska as a support base for area oil explora- tion (1985 -20007) Increased bottomfishing activity (1984 and later) Increasing importance of Unalaska as a transshipment port for cargo bound for western Alaska (1990 and later) F.1.3 -Economic Forecast The realatively healthy economy now enjoyed by Unalaska and Dutch Harbor is due mainly to the crab industry.During the past few years,the crabbers have turned in increasingly poor harvests due to a decline in crab stock in the area.As a result,there has been a slowing of the City's growth. Some see the potential bottomfish industry as being able to help even out some of the feast-and-famine cycles which plague the crab industry.It should not be expected that the bottomfish industry will operate in the same manner as the crabbers have.This new industry will likely use new ships which have been outfitted as catcher/processor ships.These ships may not call at port for peri- ods measured in months.They would also not have need for the large shore-based support activities associated with processing.As a result,the City may see few economic benefits resulting from an expanded bottomfish industry. F.L2 =Population Forecast The prediction of future populations of relatively "stable"communities is a difficult task.To predict the future growth of a community such as Unalaska,which is so dependent upon such volatile industries as crabbing, fishing,and petroleum is virtually impossible.This report makes an effort to put existing data to the best use to develop forecasts of popu- lations for Unalaska (including Dutch Harbor). The most recent and perhaps one of the most well thought-out planning docu- ments which provides details of future growth estimates for Unalaska was prepared in 1982 by the Anchorage office of Dames &Moore.They prepared a report to establish the community's need for a new or upgraded airport. This work provided a detailed estimate of the growth of the area's bottom- fish industry,which Dames &Moore saw as the leader of Unalaska's future economic base.Their report developed individual forecasts for the years 1980 through 2000 for low,medium,and high bottomfishing activity,and for no bottomfishery development.The population estimates for the year 2000 ranged from 2300 people (under the "no bottomfish"forecast)to almost 26,000 ("high bottomfish"). From past experience in Alaskan projects,Acres'staff have learned that far too many reports and forecasts are based on unrealistic assumptions. In the case of the Dames &Moore work,we believe that their population forecasts overestimate the amount of processing of the bottomfish catch which will be done on shore.It is our opinion that the modern bottomfish industry (especially the foreign participants in that industry)will make extensive use of self-contained catcher/processor ships.For that reason, this report ignores the Dames &Moore "high bottomfish"projections. We will use Dames &Moore's "no bottomfish"projections as our low fore- casts,with their "low bottomfish"and "best-gquess bottomfish"projections being our "best-guess"and "high-growth"projections,respectively. Table 1 on the following page gives Dames &Moore's data for the various bottomfish catch possibilities. TABLE 1 10 UNAL ASKA/OUTCH HARBOR POPULATION FORECAST (data taken from Dames &Moore,1982) DAMES &MOORE DAMES &MOORE DAMES &MOORE DAMES &MOORE "NO BOTTOM ISH""LOW BOTTOMFISH""BEST-GUESS BOTTOMFISH""HIGH BOTTOMF ISH" (ACRES "LOW GROWTH")(ACRES "BEST GUESS")(ACRES "HIGH GROWTH") YEAR RESIDENT TRANSIENT _TOTAL RESIDENT TRANSIENT -TOTAL RESIDENT TRANSIENT -TOTAL RESIDENT TRANSIENT TOTAL 1980 1,395 905 2,300 1,395 905 2,300 1,395 905 2,300 1,395 905 2,300 1981 1,420 920 2,340 1,420 980 2,400 1,473 1,040 2,513 1,520 1,070 2,590 1982 1,440 930 2,370 1,450 1,060 2,510 1,550 1,180 2,730 1,650 1,240 2,890 1983 1,460 950 2,410 1,480 1,130 2,610 1,630 1,320 2,950 1,780 1,410 3,190 1984 1,480 960 2,440 1,500 1,210 2,710 1,707 1,450 3,157 1,900 1,570 3,470 1985 1,506 978 2,484 1,530 1,285 2,815 1,785 1,590 3,375 2,030 1,740 3,770 1986 1,530 990 2,520 1,780 1,340 '3,120 2,270 1,700 3,970 3,300 1,850 5,150 1987 1,550 1,010 2,560 2,020 1,400 3,420 2,760 1,800 4,560 4,570 1,970 6,540 1988 1,580 1,020 2,600 2,270 1,450 3,720 3,240 1,900 5,140 5,840 2,080 7,920 1989 1,600 1,040 2,640 2,510 1,510 4,020 3,730 2,010 5,740 7,120 2,200 9,320 1990 1,622 1,053 2,675 2,757 1,567 4,324 4,215 2,115 6,330 8,388 2,312 10,700 1991 1,660 1,077 2,737 3,360 1,630 4,990 5,260 2,200 7,460 9,740 2,560 12,300 1992 1,700 1,100 2,800 3,970 1,690 5,660 6,300 2,280 8,580 11,100 2,810 13,910 1993 1,740 1,130 2,870 4,580 1,760 6,340 7,340 2,360 9,700 12,400 3,050 15,450 1994 1,770 1,150 2,920 5,190 1,820 7,010 8,380 2,440 10,820 13,800 3,300 17,100 1995 1,812 1,175 2,987 5,799 1,883 7,682 9,425 2,521 11,946 15,151 3,547 18,698 1996 1,850 1,200 3,050.6,950 1,970 8,920 10,900 2,600 13,500 16,600 3,520 20,120 1997 1,900 1,230 3,130 8,100 2,060 10,160 12,400 2,670 15,070 18,000 3,510 21,510 1998 1,940 1,260 3,200 9,250 2,140 11,390 14,000 2,740 16,740 19,400 3,490 22,890 1999 1,980 1,280 3,260 10,400 2,230 12,630 15,500 2,820 18,320 20,900 3,480 24,380 2000 2,023 1,313 3,336 11,550 2,317 13,867 16,972 2,894 19,866 22,287 3,459 25,746 2001 2,060 1,340 3,400 12,700 2,400 15,100 18,500 2,970 21,470 23,700 3,440 27,140 2002 2,110 1,370 3,480 13,800 2,450 16,250 20,000 3,040 23,040 25,100 3,420 28,520 2003 2,150 1,400 3,550 15,000 2,580 17,580 21,500 3,120 24,620 26,600 3,410 30,010 2004 2,190 1,420 3,610 16,200 2,660 18,860 23,000 3,190 26,190 28,000 3,390 §=31,390 ¢ 2.Ab 84.qo Notes:Population data for 1980,1985,1990,1995,and 2000 were taken direcly from Dames &Moore's 1982 report "Aleutian Regional Airport,Project Documentation."Data for other years were estimated using linear interpolation. 11 F.3 +Electrical Energy Forecast Beginning in this section,and continuing through the remainder of the report,we present "Low,""Best-Guess,"and "High"forecasts of economic activity and electric energy use growth.References to bottomfish catch levels will generally be omitted. Unalaska residential customers have had access to both a centralized utili- ty system and a source of income long enough to have attained a relatively high level of consumption for rural Alaska communities.City officials note that a "normal"level of residential electricity use is about 600 kWh per month.The State subsidy program (Power Cost Assistance Program)has set its cutoff at 600 kWh/month.Beyond that level,the customers must pay "full price"for electricity.In Unalaska,that would be about $0.17 per kWh,which is relatively inexpensive for diesel-generated electricity in a rural community. The consumption levels of many of the non-residential users have been care- fully estimated by City utility staff members,even though they are not yet customers of the City system.These users and their consumption levels are given in Table 2,below: TABLE 2 EXISTING LOADS (From Unalaska Loan Application Documents) Customer Demand (kW)Consumption (MWh) Standard Oil Company 200 834 Standard Oil Hill (residential)200 876 American President Lines 870 493 Strawberry Hill 30 144 Whitney Fidalgo (closed)0 0 East Point Seafoods 860 841 Universal Seafoods 2,450 10,074 Panama Marine 1,400 3,000 Pan Alaska Seafoods 1,750 3,942 Pacific Pearl 570 1,314 City Airport (ineluding expansion)75 328 Sea Alaska 1,750 3,942 City Dock 200 175 City Boat Harbor 250 219 City of Unalaska Sales 1,140 2,500 TOTALS 11,745 28,682 Note:1 MWh =1,000 kWh TABLE 3 UNALASKA/DUTCH HARBOR HOUSING AND RESIDENTIAL ELECTRICITY USE FORECAST FROM ACRES'LOW-GROWTH POPULATION FORECAST (assuming no bottomfish development) 12 HOUSES APARTMENTS POPULATION NUMBER OF ENERGY POWER NUMBER OF ENERGY POWER ENERGY POWER YEAR RESIDENT TRANSIENT -_TOTAL HOUSES USE (kWh)DEMAND (kW)|APARTMENTS USE (kWh)DEMAND (kW)[USE (kWh)DEMAND (kW) 1980 1,395 905 2,300 349 2,932 524 627 2,257 314 5,189 838 1981 1,420 920 2,340 355 2,982 533 638 2,297 319 5,279 852 1982 1,440 930 2,370 360 3,024 540 645 2,322 323 5,346 863 1983 1,460 950 2,410 365 3,066 548 658 2,369 329 5,435 877 1984 1,480 960 2,440 370 3,108 555 665 2,394 333 5,502 888 1985 1,506 978 2,484 377 3,167 566 677 2,437 339 5,604 905 1986 1,530 990 2,520 383 3,217 575 686 2,470 343 5,687 918 1987 1,550 1,010 2,560 388 3,259 582 699 2,516 350 5,775 932 1988 1,580 1,020 2,600 395 3,318 593 708 2,549 354 5,867 947 1989 1,600 1,040 2,640 400 3,360 600 720 2,992 360 5,952 960 1990 1,622 1,053 2,675 406 3,410 609 729 2,624 365 6,034 974 1991 1,660 1,077 2,737 415 3,486 623 746 2,686 373 6,172 996 1992 1,700 1,100 2,800 425 3,570 638 763 2,747 382 6,317 1,020 1993 1,740 1,130 2,870 435 3,654 653 783 2,819 392 6,473 1,045 1994 1,770 1,150 2,920 443 3,721 665 796 2,866 398 6,587 1,063 1995 1,812 1,175 2,987 453 3,805 680 814 2,930 407 6,735 1,087 1996 1,850 1,200 3,050 463 3,889 695 831 2,992 416 6,881 '1,ll 1997 1,900 1,230 3,130 475 3,990 713 853 3,071 427 7,061 1,140 1998 1,940 1,260 3,200 485 4,074 728 873 3,143 437 7,217 1,165 1999 1,980 1,280 3,260 495 4,158 743 888 3,197 444 7,355 1,187 2000 2,023 1,313 3,336 506 4,250 759 909 3,272 455 7,522 1,214 2001 2,060 1,340 3,400 515 4,326 773 928 3,341 464 7,667 1,237 2002 2,110 1,370 3,480 528 4,435 792 949 3,416 475 7,851 1,267 2003 2,150 1,400 3,550 538 4,519 807 969 3,488 485 8,007 1,292 2004 2,190 1,420 3,610 548 4,603 B22 984 3,542 492 8,145 1,314 Assumptions:1.75 percent of "Resident"population is assumed to live in single-family homes at 3 people per house;25 percent in apartment-type dwellings at 2 people per unit. type dwellings at 2 people per unit. 100 percent of "Transient"population is assumed to live in apartment- 2.Houses will be assumed to consume 700 kWh/month,with a peak demand (coincident)of about 1.5 kW;apartment-type dwellings will be assumed to consume 350 kWh/month,with a peak demand (coincident)of about 0.5 kW. TABLE 4 UNALASKA/DUTCH HARBOR HOUSING AND RESIDENTIAL ELECTRICITY USE FORECAST FROM ACRES'BEST-GUESS POPULATION FORECAST (assuming a low-growth bottomfish industry) 13 HOUSES APARTMENTS TOTALS POPULATION NUMBER OF ENERGY POWER NUMBER OF ENERGY POWER ENERGY POWER YEAR RESIDENT TRANSIENT -TOTAL HOUSES USE (kWh)DEMAND (kW)]APARTMENTS USE (kWh)DEMAND (kW)|USE (kWh)DEMAND (kW) 1980 1,395 905 2,300 349 2,932 524 627 2,257 314 5,189 838 1981 1,420 980 2,400 355 2,982 533 668 2,405 334 5,387 867 1982 1,450 1,060 2,510 363 3,049 545 711 2,560 356 5,609 901 1983 1,480 1,130 2,610 370 3,108 555 750 2,700 375 5,808 930 1984 1,500 1,210 2,710 375 3,150 563 793 2,855 397 6,005 960 1985 1,530 1,285 2,815 383 3,217 575 834 3,002 417 6,219 992 1986 1,780 1,340 3,120 445 3,738 668 893 3,215 447 6,953 1,115 1987 2,020 1,400 3,420 505 4,242 758 953 3,431 477 7,673 1,235 1988 2,270 1,450 3,720 568 4,771 852 1,009 3,632 505 8,403 1,357 1989 2,510 1,510 4,020 628 5,275 942 1,069 3,848 535 9,123 1,477 1990 2,757 1,567 4,324 689 5,788 1,034 1,128 4,061 564 9,849 1,598 1991 3,360 1,630 4,990 840 7,056 1,260 1,235 4,446 618 11,502 1,878 1992 3,970 1,690 5,660 993 8,341 1,490 1,341 4,828 671 13,169 2,161 1993 4,580 1,760 6,340 1,145 9,618 1,718 1,453 5,231 727 14,849 2,445 1994 5,190 1,820 7,010 1,298 10,903 1,947 1,559 5,612 780 16,515 2,727 1995 5,799 1,883 7,682 1,450 12,180 2,175 1,666 5,998 833 18,178 3,008 1996 6,950 1,970 8,920 1,738 14,599 2,607 1,854 6,674 927 21,273 3,534 1997 8,100 2,060 10,160 2,025 17,010 3,038 2,043 7,355 1,022 24,365 4,060 1998 9,250 2,140 11,390 2,313 19,429 3,470 2,226 8,014 1,113 27,443 4,583 1999 10,400 2,230 12,630 2,600 21,840 3,900 2,415 8,694 1,208 30,534 5,108 2000 11,550 2,317 13,867 2,888 24,259 4,332 2,602 9,367 1,301 33,626 5,633 2001 12,700 2,400 15,100 3,175 26,670 4,763 2,788 10,037 1,394 36,707 6,157 2002 13,800 2,450 16,250 3,450 28,980 5,175 2,950 10,620 1,475 39,600 6,650 2003 15,000 2,580 17,580 3,750 31,500 5,625 3,165 11,394 1,583 42,894 7,208 2004 16,200 2,660 18,860 4,050 34,020 6,075 3,355 12,078 1,678 46,098 7,753 Assumptions:1.75 percent of "Resident"population is assumed to live in single-family homes at 3 people per house;25 percent in apartment-type dwellings at 2 people per unit. type dwellings at 2 people per unit. 100 percent of "Transient"population is assumed to live in apartment- 2.Houses will be assumed to consume 700 kWh/month,with a peak demand (coincident)of about 1.5 kW;apartment-type dwellings will be assumed to consume 350 kWh/month,with a peak demand (coincident)of about 0.5 kW. TABLE 5 UNALASKA/DUTCH HARBOR HOUSING AND RESIDENTIAL ELECTRICITY USE FORECAST FROM ACRES'HIGH-GROWTH POPULATION FORECAST (using the best-guess bottomfish estimates) 14 HOUSES APARTMENTS TOTALS POPULATION NUMBER OF ENERGY POWER NUMBER OF ENERGY POWER ENERGY POWER YEAR RESIDENT TRANSIENT -TOTAL HOUSES USE (kWh).DEMAND (kW)|APARTMENTS USE (kWh)DEMAND (kW)|USE (kWh)DEMAND (kW) 1980 1,395 905 2,300 349 2,932 524 627 2,257 314 5,189 838 1981 1,473 1,040 2,513 368 3,091 552 704 2,534 352 5,625 904 1982 1,550 1,180 2,730 388 3,259 582 784 2,822 392 6,081 974 1983 1,630 1,320 2,950 408 3,427 612 864 3,110 432 6,537 1,044 1984 1,707 1,450 3,157 427 3,587 641 938 3,377 469 6,964 1,110 1985 1,785 1,590 3,375 446 3,746 669 1,018 3,665 509 7,411 1,178 1986 2,270 1,700 3,970 568 4,771 852 1,134 4,082 567 8,853 1,419 1987 2,760 1,800 4,560 690 5,796 1,035 1,245 4,482 623 10,278 1,658 1988 3,240 1,900 5,140 810 6,804 1,215 1,355 4,878 678 11,682 1,893 1989 3,730 2,010 5,740 933 7,837 1,400 1,471 5,296 736 13,133 2,136 1990 4,215 2,115 6,330 1,054 8,854 1,581 1,584 5,702 792 14,556 2,373 1991 5,260 2,200 7,460 1,315 11,046 1,973 1,758 6,329 879 17,375 2,852 1992 6,300 2,280 8,580 1,575 13,230 2,363 1,928 6,941 964 20,171 3,327 1993 7,340 2,360 9,700 1,835 15,414 2,753 2,098 7,553 1,049 22,967 3,802 1994 8,380 2,440 10,820 2,095 17,598 3,143 2,268 8,165 1,134 25,763 4,277 1995 9,425 2,521 11,946 2,356 19,790 3,534 2,439 8,780 1,220 28,570 4,754 1996 10,900 2,600 13,500 2,725 22,890 4,088 2,663 9,587 1,332 32,477 5,420 1997 12,400 2,670 15,070 3,100 26,040 4,650 2,885 10,386 1,443 36,426 6,093 1998 14,000 2,740 16,740 3,500 29,400 5,250 3,120 11,232 1,560 40,632 6,810 1999 15,500 2,820 18,320 3,875 32,550 5,813 3,348 12,053 1,674 44,603 7,487 2000 16,972 2,894 19,866 4,243 35,641 6,365 3,569 12,848 1,785 48,489 8,150 2001 18,500 2,970 21,470 4,625 38,850 6,938 3,798 13,673 1,899 52,523 8,837 2002 20,000 3,040 23,040 5,000 42,000 7,500 4,020 14,472 2,010 56,472 9,510 2003 21,500 3,120 24,620 5,375 45,150 8,063 4,248 15,293 2,124 60,443 10,187 2004 23,000 3,190 26,190 5,750 48,300 8,625 4,470 16,092 2,235 64,392 10,860 Assumptions:1.75 percent of "Resident"population is assumed to live in single-family homes at 3 people per house;25 percent in apartment-type dwellings at 2 people per unit. type dwellings at 2 people per unit. 100 percent of "Transient"population is assumed to live in apartment- 2.Houses will be assumed to consume 700 kWh/month,with a peak demand (coincident)of about 1.5 kW;apartment-type dwellings will be assumed to consume 350 kWh/month,with a peak demand (coincident)of about 0.5 kW. 15 Acknowledging that some fraction of the bottomfish catch harvested in Unalaska's service area will be brought to shore for processing,we now calculate the amount of energy used for this operation. Since bottomfish are generally frozen (instead of being canned),the great- est use of energy in their processing is consumed in the freezing operation.Once the fish are frozen,relatively little energy is required to keep them frozen.We do not believe that any more than 40 percent of the area catch will be processed at Unalaska.This proportion could be as low as 25 percent of the catch. The energy used to freeze the fish caught under Acres'"Best-Guess"and "High-Growth"forecasts are shown on Tables 6 and 7 on the following pages. TABLE 6 UNALASKA/DUTCH HARBOR BOTTOMPISH PROCESSING ENERGY ESTIMATES TO BE USED WITH ACRES'BEST-GUESS FORECAST DAMES &MOORE LOW BOTTOMFISH PORTION OF AREA CATCH PROCESSED IN UNALASKA/DUTCH HARBOR CATCH ESTIMATE 40 PERCENT 30 PERCENT 25 PERCENT YEAR (10 1b)ENERGY (MWh)POWER (MW)ENERGY (MWh)POWER (MW)ENERGY (MWh)POWER (MW) 1980 0 0 0 0 0 0 0 1981 0 0 )0 0 )) 1982 0 ny ny 0 0 )0 1983 0 0 0 0 Q )0 1984 10 268 0 201 0 168 0 1985 55 1,474 1 1,106 0 921 i) 1986 90 2,412 1 1,809 1 1,508 l 1987 120 3,216 1 2,412 1 2,010 1 1988 150 4,020 2 3,015 1 2,513 1 1989 190 5,092 2 3,819 2 3,183 1 1990 220 5,896 3 4,422 2 3,685 2 1991 260 6,968 3 5,226 2 4,355 2 1992 310 8,308 4 6,231 3 5,193 2 1993 350 9,380 4 7,035 3 5,863 3 1994 400 10,720 5 8,040 4 6,700 3 1995 440 11,792 5 8,844 4 7,370 3 1996 550 14,740 7 11,055 5 9,213 4 1997 660 17,688 8 13,266 6 11,055 5 1998 770 20,636 9 15,477 7 12,898 6 1999 880 23,584 11 17,688 8 14,740 7 2000 990 26,532 12 19,899 9 16,583 7 2001 1,100 29,480 13 22,110 lo 18,425 8 2002 1,200 32,160 14 24,120 ll 20,100 9 2003 1,300 34,840 16 26,130 12 21,775 10 2004 1,400 37,520 17 28,140 13 23,450 ll TABLE 7 UNALASKA/DUTCH HARBOR BOTTOMFISH PROCESSING ENERGY ESTIMATES TO BE USED WITH ACRES'HIGH-GROWTH FORECAST DAMES &MOORE BEST-GUESS BOTTOMFISH PORTION OF AREA CATCH PROCESSED IN UNALASKA/DUTCH HARBOR CATCH ESTIMATE 40 PERCENT 30 PERCENT 25 PERCENT YEAR (106 1b)ENERGY (MWh)POWER (MW)ENERGY (MWh)POWER (MW)ENERGY (MWh)POWER (MW) 1980 )0 ")0 0 0 0 1981 )0 0 )0 0 0 1982 0 0 )0 i)ny 0 1983 0 0 "))0 fn)0 1984 30 804 0 603 0 503 ny 1985 110 2,948 1 2,211 1 1,843 1 1986 180 4,824 2 3,618 2 3,015 1 1987 240 6,432 3 4,824 2 4,020 2 1988 310 8,308 4 6,231 3 5,193 2 1989 370 9,916 4 7,437 3 6,198 3 1990 440 11,792 5 8,844 4 7,370 3 1991 530 14,204 6 10,653 5 8,878 4 1992 620 16,616 7 12,462 6 10,385 5 1993 700 18,760 8 14,070 6 11,725 5 1994 790 21,172 9 15,879 7 13,233 6 1995 880 23,584 11 17,688 8 14,740 7 1996 1,000 26,800 12 20,100 9 16,750 8 1997 1,200 32,160 14 24,120 ll 20,100 9 1998 1,300 34,840 16 26,130 12 21,775 lo 1999 1,500 40,200 18 30,150 14 25,125 ll 2000 1,650 44,220 20 33,165 15 27,638 12 2001 1,800 48,240 22 36,180 16 30,150 14 2002 2,000 53,600 24 40,200 18 33,500 15 2003 2,100 56,280 25 42,210 19 35,175 16 2004 2,300 61,640 28 46,230 21 38,525 17 TABLE 8 18 TOTAL ENERGY USE--ACRES'LOW-GROWTH FORECAST NON-BOTTOMFISH BOTTOMFISH RESIDENTIAL INDUSTRIAL LOADS PROCESSING LOADS MISCELLANEGUS LOADS TOTALS ENERGY POWER ENERGY POWER ENERGY POWER ENERGY POWER ENERGY POWER YEAR USE (MWh)DEMAND (MW)USE (MWh)DEMAND (MW)USE (MWh)DEMAND (MW)USE (MWh)DEMAND (Mw)USE (MWh)DEMAND (MW) 1980 5,189 0.84 28,700 12 0 0 0 0 33,889 13 1981 5,279 0.85 28,700 12 0 0 0 0 33,979 13 1982 9,346 0.86 28,700 12 0 0 0 0 34,046 13 1983 5,435 0.88 28,700 12 0 0 20 0.008 34,155 13 1984 5,502 0.89 28,700 12 0 0 20 0.008 34,222 13 1985 5,604 0.90 28,700 12 (8)0 20 0.008 34,324 13 1986 5,687 0.92 28,700 12 0 0 40 0.015 34,427 13 1987 5,775 0.93 28,700 12 0 0 40 0.015 34,515 13 1988 5,867 0.95 28,700 12 0 0 60 0.022 34,627 13 1989 5,952 0.96 28,700 12 0 0 60 0.022 34,712 13 1990 6,034 0.97 28,700 12 0 0 60 0.022 34,794 13 1991 6,172 1,00 28,700 12 0 0 80 0.030 34,952 13 1992 6,317 1.02 28,700 12 0 0 190 0.038 35,117 13 1993 6,473 1.14 28,700 12 0 0 100 0.038 35,273 13 1994 6,587 1.06 28,700 12 0 0 120 0.045 35,407 13 1995 6,735 1.09 28,700 12 0 0 120 0.045 35,555 13 1996 6,881 1.11 28,700 12 0 0 140 0.052 35,721 13 1997 7,061 1.14 28,700 12 0 0 160 0.060 35,921 13 1998 7,217 1.16 28,700 12 0 0 180 0.068 36,097 13 1999 7,355 1.19 28,700 12 0 0 180 0.068 36,235 13 2000 7,522 1.21 28,700 12 0 0 200 0.075 36,422 3 2001 7,667 1.24 28,700 12 0 0 220 0.082 36,587 13 2002 7,851 1.27 28,700 12 0 0 220 0.082 36,771 13 2003 8,007 1.19 28,700 12 0 0 240 0.090 36,947 13 2004 8,145 1.31 28,700 12 0 0 260 0.098 37,105 13 TABLE 9 TOTAL ELECTRICITY USE -ACRES'BEST-GUESS FORECAST NON-BOTTOMF ISH BOTTOMFISH RESIDENTIAL INDUSTRIAL LOADS PROCESSING LOADS MISCELLANEOUS LOADS TOTALS ENERGY POWER ENERGY POWER ENERGY POWER ENERGY POWER ENERGY POWER YEAR USE (MWh)DEMAND (MW)USE (MWh)DEMAND (MW)USE (MWh)DEMAND (MW)USE (MWh)DEMAND (MW)USE (MWh)DEMAND (MW) 1980 5,189 0.85 28,700 12 0 0 0 0 33,889 13 1981 5,387 0.87 28,700 12 0 0 20 0.008 34,107 13 1982 5,609 0.90 28,700 12 0 0 40 0.015 34,349 13 1983 5,808 0.93 28,700 12 0 0 60 0.022 34,568 13 1984 6,005 0.96 28,700 12 201 0 80 0.030 34,986 13 1985 6,219 0.99 28,700 12 1,106 0 100 0.038 36,125 13 1986 6,953 1.11 28,700 12 1,809 I 160 0.060 37,622 14 1987 7,673 1.23 28,700 12 2,412 1 220 0.105 39,005 14 1988 8,403 1.36 28,700 12 3,015 1 280 0.128 40,398 14 1989 9,123 1.48 28,700 12 3,819 2 340 0.150 41,982 16 1990 9,849 1.60 28,700 12 4,422 2 400 0.172 43,371 16 1991 11,502 1.88 28,700 12 5,226 2 520 0.218 45,948 16 1992 13,169 2.16 28,700 12 6,231 3 660 0.270 48,760 17 1993 14,849 2.44 28,700 12 7,035 3 800 0.322 51,384 18 1994 16,515 2.73 28,700 12 8,040 4 940 0.375 54,195 19 1995 18,178 3.00 28,700 12 8,844 4 1,060 0.420 56,782 19 1996 21,273 3.53 28,700 12 11,055 5 1,320 0.518 62,348 21 1997 24,365 4.06 28,700 12 13,266 6 1,560 0.608 67,891 23 1998 27,443 4.58 28,700 12 15,477 7 1,800 0.697 73,420 24 1999 30,534 5.11 28,700 12 17,688 8 2,060 0.758 78,982 26 2000 33,626 5.63 28,700 12 19,899 9 2,300 0.848 84,525 27 2001 36,707 6.16 28,700 12 22,110 10 2,560 0.945 90,077 29 2002 39,600 6.66 28,700 12 24,120 ll 2,780 1.028 95,200 31 2003 42,894 7.21 28,700 12 26,130 12 3,040 1.125 100,764 32 2004 46,098 7.75 28,700 12 28,140 13 3,300 1.223 106,238 34 19 TABLE_10 TOTAL ENERGY USE--ACRES*'HIGH-GROWTH FORECAST NON-BOTTOMFISH BOTTOMF ISH 20 RESIDENTIAL INDUSTRIAL LOADS PROCESSING LOADS MISCELLANEOUS LOADS TOTALS ENERGY POWER ENERGY POWER ENERGY POWER ENERGY POWER ENERGY POWER YEAR USE (MWh)DEMAND (MW)USE (MWh)DEMAND (MW)USE (MWh)DEMAND (MW)USE (MWh)DEMAND (MW)USE (MWh)DEMAND (MW) 1980 5,189 0.84 28,700 12 0 0 0 0 33,889 13 1981 5,625 0.90 28,700 12 0 0 40 0.015 34,365 13 1982 6,081 0.97 28,700 12 0 it)80 0.030 34,861 13 1983 6,537 1.04 28,700 12 0 0 120 0.045 35,357 13 1984 6,964 1.11 28,700 12 603 0 160 0.060 36,427 13 1985 7,411 1.18 28,700 12 2,211 1 200 0.075 38,522 14 1986 8,853 1.42 28,700 12 3,618 2 320 0.120 41,491 16 1987 10,278 1.66 28,700 12 4,824 2 440 0.165 44,242 16 1988 11,682 1.89 28,700 12 6,231 3 560 0.210 47,173 17 1989 13,133 2.14 28,700 12 7,437 3 680 0.255 49,950 17 1990 14,556 2.37 28,700 12 8,844 4 800 0.300 52,900 19 1991 17,375 2.85 28,708 12 10,653 5 940 0.353 57,668 20 1992 20,171 3.33 28,700 12 12,462 6 1,160 0.435 62,493 22 1993 22,967 3.80 28,700 12 14,070 6 1,400 0.525 67,137 22 1994 25,763 4.28 28,700 12 15,879 7 1,620 0.608 71,962 24 1995 28,570 4.75 28,700 12 17,688 8 1,840 0.690 76,798 25 1996 32,477 5.42 28,700 12 20,100 9 2,160 0.810 83,437 27 1997 36,426 6.09 28,700 12 24,120 ll 2,460 0.922 91,706 30 1998 40,632 6.81 28,700 12 26,130 12 2,800 1,050 98,262 32 1999 44,603 7.48 28,700 12 30,150 14 3,120 1.170 106,573 35 2000 48,489 8.15 28,700 12 33,165 15 3,420 1,282 113,774 36 2001 52,523 8.84 28,700 12 36,180 16 3,740 1.402 121,143 38 2002 56,472 9.51 28,700 12 40,200 18 4,060 1.522 129,432 4l 2003 60,443 10.19 28,700 12 42,210 19 4,340 1.635 135,693 43 2004 64,392 10.86 28,700 12 46,230 21 4,640 1.755 143,962 46 POWER DEMAND (MW) UNALASKA LOAD FORECAST 50-)---------ee nnnn-ee power eeen-pore--too-------toren---- H 45-4 - H H 40-]---------$oon------Stated tatedtern we----tooo ------power e--- H H 35-]-H B H B B 30-{---------$oeerenn---$e wee eeeee +o--H-----$oe-------to------HF B H B B 25-1 -H H B B HH B 20-]---------tree enre nee +-H-+------Howe enn tanennn---$-------4 H BB B HH B HH B B B 15-4 - HB 8 B ee *ee FE LLELELLELEELLELELLELLELERL 10-+]---------peo e----to eeereene $oeeeecenne poe een---$ooe----4 LEGEND:L =ACRES'LOW-GROWTH FORECAST B ="BEST GUESS " 5+-H ="HIGH-GROWTH " *=YEARS OF FORECAST OVERLAP 0 ||||| 1980 1985 1990 1995 2000 2005 YEAR 21 UNALASKA ENERGY USE FORECAST 150,000-]oe $oewee----$oeenen---teen neon--toon n-----a " H 140,000-|- H 130,000-|- H 120,000-|-H H 110,000-4 -B H B 100,000-} --------$owe eee ee $oeeee----+oecee H---4---------to------- B 90,000-|-H B H B 80,000-]-B H B 70,000-|-H B ENERGY H USE 60,000-|-HH B (MWh)H BB 50,000-]-------..teow eree H-+---§-B---+---------to eer weno--+e------ HH B 40,000-|-HH 8 8 BB e*ee ee Xe LE LEE LELELELEELELLELLL 30,000-|- LEGEND:L =ACRES'LOW-GROWTH FORECAST 20,000-|-B="BEST-GUESS " H="HIGH-GROWTH '" 10,000-|-*=YEARS OF FORECAST OVERLAP Ss SE SS SE19801985199019952000 2005 23 G_-VILLAGE TECHNOLOGY ASSESSMENT© The purpose of this part of the report is to briefly discuss the various technologies which have been used to generate electricity as they may be used in Unalaska. Because of the area's fishing and crabbing industry and the on-shore personnel required to provide maintenance,Unalaska has available to it a relatively skilled work pool.In the operation of a utility system,access to such a high grade of labor can be quite important.In this regard, Unalaska enjoys a considerable advantage over most other rural communities when the application of relatively sophisticated generation equipment is considered. 1.Coal.There are no known coal deposits in the Unalaska area.Any application of coal for the generation of power would require that it be shipped in (likely from the Healy area).The city may be large enough to support a small coal-fired power plant,but it is believed that the importation of coal may make this alternative so expensive as to be uncomptetitive. 2.Conservation.This is a "resource"™available to virtually all energy users anywhere in the state.Sometimes even the simplest steps taken can save appreciable amounts of energy.Based on conversations with City officials,Acres'staff believe that Unalaska residents actively practice conservation in their electricity use when they make an effort to hold stay below the 600 kWh limit of the State subsidy.Individual efforts to conserve are likely to be the most effective.As energy becomes more and more expensive more people (not just those in Unalaska)will take this option more seriously. 3.Geothermal.Unalaska is one of the few Alaska cities located near enough a geothermal resource that they could possible take advantage of it.The Alaska Power Authority has been actively exploring the geo- thermal potential of Mt.Makushin,about 12 miles to the east of the city.Their work done to date has shown that the mountain has a large geothermal resource.The economics of utilizing the area's geothermal energy are explored in later sections of this report. 4.Hydroelectric.The US Army Corps of Engineers have carried out studies on Unalaska Island to determine the costs associated with available hydropower sites.They have uncovered at least two sites which may be worthy of further consideration.These are considered in later sections of this report. 5.Petroleum.Fuel oil is the principal source of heat and electricity for Unalaska.This situation will likely continue far into the future. The city's generators are run on diesel fuel.The use of diesel engines is the predominant means of providing electricity throughout rural Alaska.With the large (by Alaskan standards)load on the 7. 8. 24 Unalaska system,larger,more fuel-efficient diesel engines can be used. Technologies are available which can be used with diesel engines to make them more efficient sources of energy.Called "waste heat recovery,"energy that would otherwise be given up to the atmosphere can be captured and put to use.A common form of waste heat recovery is now operating at the Unalaska power plant,where heat normally given up by the diesels'radiators is captured to heat the surrounding buildings. Another possible use is to route hot exhaust gasses through a heat exchanger to generate steam or,in some cases,to turn relatively cool liquid organic fluids (such as freon)to hot gasses,so they can be used to run ae turbine,The turbine is then used to generate electricity.Such a process is known as an "Qrganic Rankine Cycle." In conversations with a major manufacturer of this type of equipment, Acres'staff learned that systems smaller than about 25,000 should not be considered for the use of this technology.They said that,as a rule,about 10 percent of a power plant's "nameplate"rating can be recovered in this manner.Organic Rankine Cycle equipment has seen very little application in this country.It may be considered to be too experimental for use at Unalaska. In addition to the waste heat technologies used to provide (a)heat for other users and (2)more electricity,there is a system available from Japan's Hitachi Corporation which can use waste heat to produce cold. Instead of piping hot water to users near a generating plant,this sys- tem would flow very cold ammonia or freon to nearby users.In a com- munity such as Unalaska,where there are tremendous amounts of energy is used for chilling and freezing,the investigation of this type of equipment may be quite worthwhile. Photovoltaic.This alternative is presently too expensive to consider for utility application in Alaska. Wind.The Aleutian Islands are all exposed to very windy conditions. Although wind turbines,for the most part,considered to be too unreli- able for serious consideration for utility use,they have attracted a fair amount of attention from the US Department of Energy and other research agencies.The State of Alaska has funded the installation of a number of small wind turbines in locations from Skagway to Kotzebue. None of these units have yet contributed enough energy to the utility systems to which they are cannected that customers have had their rates reduced, Wood.While in use throughout much of Alaska as a heating fuel,wood is not widely available at Unalaska.Its use as an energy source was not given serious consideration in this report. 25 H -ENERGY PLAN DESCRIPTIONS AND ASSUMPTIONS H.1 -Base Case The base case plan will assume that the City of Unalaska will continue to develop its centralized electric utility system.They will use diesel engines to generate electricity and will recover and sell waste heat. We will use a number of assumptions to simplify the calculations in this report.It is believed that the recommendations which are based upon our economic analysis will not be compromised by the use of these assumptions, especially if they are applied uniformly from one alternative to another. With regard to the base case plan,the following assumptions will be made: ®Beginning in 1984,the City will begin to increase generation capacity to the point where they can supply all electricity needed in the commun- ity.In 1984,they will bring two new 2,500 kW machines on-line.Each year thereafter,they will add two more of these units until the load capacity is met.As the load increases (as is the case under the best- guess and high-growth forecasts),they will add more units as needed. ®The diesel generating units will have capital costs of $300 per kW and they will have a lifetime of 20 years.Installation of the units will run another $300/kW,for a total installed cost of $600/kW. ©The diesel units will require a major overhaul every 10 years.These overhauls will cost the City about 1/3 the original price of the machines or $100/kW. ®The diesels will be equipped with waste heat recovery systems which will cost,complete with piping and heat exchangers at the user locations, $150/kW.The waste heat systems will have lifetimes of 15 years. ®The diesels will be expected to produce 12 kWh of electrical energy for each gallon of diesel fuel used.They will also be able to produce 10 kWh (34,000 Btu)of waste heat (recovered from the cooling water)for this same gallon of fuel. ®Normal operation and maintenance of the diesels and their waste heat systems.This will require a minimum crew of three people for the initial machines,with one more added for every three additional machines.The payroll costs of each of these workers is estimated at $130,000 per year,including overtime,and all fringe benefits and over- head expenses.General O&M parts and supplies will be assumed to be about $20,000 per machine. ®Fuel is estimated to cost $0.98/per gallon when the new plant is built in 1984,The plant will have a direct pipeline from the Chevron bulk plant on Amakanak Island.Fuel costs will escallate at 2.5 percent annually through 2003 and remain constant thereafter. 26 Waste heat will be assumed to be sold to customers at a price which is 10 percent less than what they could have produced it themselves from burning fuel oil.The fuel oil price to these customers will be assumed to be the same as that purchased by the City to run the generators. The economic calculations associated with the base case are given in section I. 27 H.2 -Alternative Plan "A" This alternative plan will examine the economics of a geothermal energy plant on Mt.Makushin when operated in conjunction with the diesel system described in the base case plan.The addition of diesel units to meet sys- tem load will continue as before,but they will only be used to provide the energy which cannot be provided by the geothermal plant.In this type of arrangement,the only savings realized by the construction of a geothermal plant will be due to the reduced consumption of diesel fuel. Most of the data used to evaluate this alternative have been provided by Republic Geothermal,Inc,the company under contract to the Alaska Power Authority to conduct the Mt.Makushin exploration.It should be noted that while Acres'staff may not agree totally with some items in Republic's cost estimates,these estimates are believed to be quite satisfactory for the level of detail required for a reconnaissance study.Their cost esti- mates were used without change to develop the following assumptions regard- ing the geothermal plant: °For Acres'low-growth forecast,two 5,000 kW units will be installed to be operational by 1993.This report will refer to such a configuration as "the 10 MW plant."After all in-plant load was taken care of,6,700 kW would be available to the City.Republic estimates that this plant would cost $68.3 million in 1983 dollars. °Republic estimates that the 10 MW plant would cost $1.8 million each year (1983 dollars)in operation,maintenance,and administrative costs. ®For higher growth levels,Republic proposes that a 30 MW plant be built (which will be able to provide 20,000 kW of power to the City).They have suggested at least two options for a construction schedule for such a plant. The first option (and the less expensive option by a slight margin)is to initially drill enough geothermal wells to supply the entire plant when it is buit to its full capacity.Generating units would be added in increments as they are required to meet the increasing load at Unalaska.Republic estimates that such a plant would cost $202 million in 1983 dollars. The second option available is to build the geothermal plant in incre- ments of both geothermal wells and generating units.Republic has estimated that such a plant would cost $220 million. bd The operation,maintenance,and administration of the 30 MW plant has been estimated to cost $2.8 million per year. 28 H.3 -Alternative Plan "8" This alternative plan assumes the existence of the Unalaska diesel system, as in the case of the two previously described cases.However,in this case,data provided by the US Army Corps of Engineers in their report "Unalaska,Alaska,Small Hydropower Interim Feasibility Study and Environ- mental Impact Statement"is used to examine the economics of constructing one or more small hydro projects near Unalaska. The assumptions used for this part of the report (in addition to those pre- sented for the base case plan)were,for the most part,directly from the Corps report.They are as follows: ©A hydropower project constructed on the Shaishnikof River could have a capacity of 700 kW.The Corps estimates construction costs of such a project to be about $6.0 million (in 1983 dollars).Such a project would have a lifetime of 50 years.The project is estimated to be cap- able of producing about 3,100,000 kWh each year.This level of energy production could save the City about 260,000 gallons of fuel each year. ®The Shaishnikof project would cost about $30,000 per year for operation, maintenance,and administrative expenses. ®A hydropower project constructed on Pyramid Creek could have a capacity of 260 kW.The Corps estimates that this project would cost about $845,000 (in 1983 dollars)and have a lifetime of 50 years.The Pyramid Creek plant would produce about 2,200,000 kWh each year,thus saving the City about 180,000 gallons of fuel *The Pyramid Creek project would cost about $20,000 per year to maintain. 29 I_-ECONOMIC EVALUATIONS OF ENERGY PLAN ALTERNATIVES I.1 -General In this section of the report,we will examine in some detail the relative economics of the alternatives as they were described in Section H.The method followed was developed by the Alaska Power Authority to provide a uniform analysis of diverse project types. At the request of the Alaska Power Authority,our economic analysis of the Mt.Makushin geothermal project (Alternative "A")assumes an economic life of 35 years and a financing term of 25 years.Power Authority guidelines suggest that a 15-year life and financing term be assumed for geothermal projects.These guidelines are directed at low-temperature geothermal resources and are not appropriate for projects such as the proposed Mt. Makushin plant.Geothermal systems of this type use steam turbines having economic lives and financing terms similar to those used by coal-or wood- fired boilers.Several firms contacted by the Power Authority who are experienced in the development of geothermal facilities similar to those proposed for Unalaska have confirmed that a 35-year economic life and a 25-year financing term are realistic paramaters for this analysis. To clearly identify the economic advantages of one project over another, Power Authority guidelines suggest that anlyses take into account expenses which are unique to a particular alternative.In this case,Acres assumes that the City will pursue the development of a full-capacity diesel plant regardless of the existence of a Mt.Makushin geothermal plant or the hydro plants identified by the Corps of Engineers.This approach is'taken because,in the opinion of Acres'staff,the reliability of the Mt. Makushin plant and its power transmission line is not sufficiently assured. The reliability of a single transmission circuit or a single right-of-way does not provide the assurance that power would be available from the geo- thermal project with a small probability of extended outages.The redun- dancy of the extra diesel capacity is relatively cheap insurance against the failure of geothermal plant equipment or its transmission line. Thus the only savings which can be attributed to any of the projects to be evaluated is derived from the reduced quantity of fuel which must be burned by the City's diesels to produce electricity. The following pages present tables of calculations used to determine the relative economics of the various alternatives studied.Following these tables is a brief section which presents a discussion of decision theory and its application to this study. TABLE 11 ECONOMIC ANALYSIS OF BASE CASE PLAN (LOW-GROWTH FORECAST) 30 POWER ENERGY FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM PRESENT VALUE DEMAND USE USE PRICE costs PRODUCED OF WASTE HEAT WASTE HEAT SOLD TOTAL COSTS OF TOTAL COSTS YEAR (MW)(MWh)(1,000 g)_($/gal)($1,000)(MBtu)($1000/Btu)($1,000)($1,000)($1,000) 1984 13 34,222 2,852 0.980 2,795 97,253 .0084 817 1,978.0 1,911.1 1985 13 34,324 2,860 1.004 2,872 97,526 -0084 819 2,053.0 1,916.5 1986 13 34,427 2,869 1.029 2,952 97,833 .0086 841 2,111.0 1,903.9 1987 13 34,515 2,876 1.055 3,034 98,072 .0090 883 2,151.0 1,874.4 1988 13 34,627 2,886 1.082 3,122 98,413 .0092 905 2,217.0 1,866.7 1989 13 34,712 2,893 1.109 3,208 98,651 -0094 927 2,281.0 1,855.6 1990 13 34,794 2,900 1.136 3,294 98,890 -0097 959 2,335.0 1,835.3 1991 13 34,952 2,913 1.165 3,393 99,333 .0099 983 2,410.0 1,830.2 1992 13 35,117 2,926 1.194 3,494 99,777 .0101 1,008 2,486.0 1,624.0 1993 13 35,273 2,939 1.224 3,598 100,220 -0104 1,042 2,556.0 1,811.9 1994 13 35,407 2,951 1.254 3,700 100,629 .0107 1,077 2,623.0 1,796.5 1995 13 35,555 2,963 1.286 3,810 101,038 -0110 1,111 2,699.0 1,786.2 1996 13 35,721 2,977 1.318 3,923 101,516 -0112 1,137 2,786.0 1,781.4 1997 13 35,921 2,993 1.351 4,044 102,061 0115 1,174 2,870.0 1,773.1 1998 13 36,097 3,008 1.385 4,166 102,573 .0118 1,210 2,956.0 1,764.4 1999 13 36,235 3,020 1.419 4,285 102,982 .0121 1,246 3,039.0 1,752.6 2000 13 36,422 3,035 1.455 4,416 103,494 0124 1,283 3,133.0 1,745.7 2001 13 36,587 3,049 1.491 4,546 103,971 .0127 1,320 3,226.0 1,736.9 2002 13 36,771 3,064 1.528 4,682 104,482 .0130 1,358 3,324.0 1,729.1 2003 13 36,947 3,079 1.567 4,825 104,994 .0134 1,407 3,418.0 1,717.9 2004-2038 13 37,105 3,092 1.567 4,845 105,437 .0134 1,413 3,432.0 33,331.6 NOTE:ALL COSTS IN 1983 DOLLARS TOTAL: 69,545.0 TABLE 12 31 ECONOMIC ANALYSIS OF BASE CASE PLAN (BEST-GUESS FORECAST) POWER ENERGY FUEL FUEL FUEL WASTE HEAT SALES PRICE -REVENUE FROM PRESENT VALUE DEMAND USE USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD TOTAL COSTS OF TOTAL COSTS YEAR (MW)(MWh)(1,000 gq)_($/gal)($1,000)(MBtu)($1000/MBtu)($1,000)($1,000)($1,000) 1984 13 34,986 2,916 0.980 2,857 99,436 .0084 835 2,022.0 1,953.7 1985 13 36,125 3,010 1.004 3,022 102,641 0084 862 2,160.0 2,016.4 1986 14 37,622 3,135 1.029 3,226 106,904 0086 919 2,307.0 2,080.7 1987 14 39,005 3,250 1.055 3,429 110,825 .0090 997 2,432.0 2,119.2 1988 14 40,398 3,367 1.082 3,643 114,815 0092 1,056 2,587.0 2,178.3 1989 16 41,982 3,499 1.109 3,880 119,316 0094 1,122 2,758.0 2,243.6 1990 16 43,371 3,614 1.136 4,106 123,237 .0097 1,195 2,911.0 2,288.0 1991 16 45,948 3,829 1.165 |4,461 130,569 .0099 1,293 3,168.0 2,405.8 1992 17 48,760 4,063 1.194 4,852 138,548 -0101 1,399 3,453.0 2,533.5 1993 18 51,384 4,282 1.224 5,241 146,016 0104 1,519 3,722.0 2,638.5 1994 19 54,195 4,516 1.254 5,663 153,996 0107 1,648 4,015.0 2,749.9 1995 19 56,782 4,732 1.286 6,085 161,361 °0110 1,775 4,310.0 2,852.4 1996 21 62,348 5,196 1.318 6,848 177,184 0112 1,984 4,864.0 3,110.0 1997 23 67,891 5,658 1.351 7,643 192,938 0115 2,219 5,424.0 3,350.9 1998 24 73,420 6,118 1.385 8,474 208,624 0118 2,462 6,012.0 3,588.6 1999 26 78,982 6,582 1.419 9,340 224,446 0121 2,716 6,624.0 3,820.1 2000 27 84,525 7,044 1.455 10,249 240,200 0124 2,978 7,271.0 4,051.4 2001 29 90,077 7,506 1.491 11,192 255,955 .0127 3,251 7,941.0 4,275.4 2002 31 95,200 7,933 1.528 12,122 270,515 -0130 3,517 8,605.0 4,476.3 2003 32 100,764 8,397 1.567 13,158 286,338 -0134 3,837 9,321.0 4,684.7 2004-2034 34 106,238 8,853 1.567 13,873 301,887 0134 4,045 9,828.0 95,449.5 NOTE:ALL COSTS IN 1983 DOLLARS TOTAL:154,866.9 TABLE 13 32 ECONOMIC ANALYSIS OF BASE CASE PLAN (HIGH-GROWTH FORECAST) POWER ENERGY FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM PRESENT VALUE DEMAND USE USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD TOTAL COSTS OF TOTAL COSTS YEAR __(MW)(MWh)(1,000 g)_($/gal)_($1,000)(MBtu) ($1000/8tu)($1,000)($1,000)($1,000) 1984 13 36,427 3,036 0.980 2,975 103,528 0084 870 2,105.0 2,033.9 1985 14 38,522 3,210 1.004 3,223 109,461 .0084 919 2,304.0 2,150.8 1986 16 41,491 3,458 1.029 3,558 117,918 .0086 1,014 2,544.0 2,294.4 1987 16 44,242 3,687 1.055 3,890 125,727 .0090 1,132 2,758.0 2,403.3 1988 17 47,173 3,931 1.082 4,253 134,047 .0092 1,233 3,020.0 2,542.8 1989 17 49,950 4,163 1.109 4,616 141,958 .0094 1,334 3,282.0 2,669.9 1990 19 52,900 4,408 1.136 5,008 150,313 .0097 1,458 3,550.0 2,790.3 1991 20 57,668 4,806 1.165 5,599 163,885 .0099 1,622 3,977.0 3,020.1 1992 22 62,493 5,208 1.194 6,218 177,593 0101 1,794 4,424.0 3,245.9 1993 22 67,137 5,595 1.224 6,848 190,790 .0104 1,984 4,864.0 3,448.1 1994 24 71,962 5,997 1.254 7,520 204,498 .0107 2,188 5,332.0 3,651.9 1995 25 76,798 6,400 1.286 8,230 218,240 .0110 2,401 5,829.0 3,857.6 1996 27 83,437 6,953 1.318 9,164 237,097 0112 2,655 6,509.0 4,161.9 1997 30 91,706 7,642 1.351 10,325 260,592 .0115 2,997 7,328.0 4,527.2 1998 32 98,262 8,189 1.385 11,341 279,245 0118 3,295 8,046.0 4,802.7 1999 35 106,573 8,881 1.419 12,602 302,842 .0121 3,664 8,938.0 5,154.5 2000 36 113,774 9,481 1.455 13,795 323,302 0124 4,009 9,786.0 5,452.8 2001 38 121,143 10,095 1.491 15,052 344,240 .0127 4,372 10,680.0 5,750.1 2002 41 129,432 10,786 1.528 16,481 367,803 .0130 4,781 11,700.0 6,086.3 2003 43 135,693 11,308 1.567 17,719 385,603 .0134 5,167 12,552.0 6,308.6 2004-2038 46 143,962 11,997 1.567 18,799 409,098 0134 5,482 13,317.0 129,334.7 NOTE:ALL COSTS IN 1983 DOLLARS TOTAL:205,687.8 TABLE 14 33 ECONOMIC ANALYSIS OF ALTERNATIVE "A"(WITH 10 MW PLANT) (LOW-GROWTH FORECAST) ENERGY GEOTHERMAL DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM GEOTHERMAL PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR (MWh)(MWh)(MWh)(1000 g)($/gal)($1000)(MBtu)-($1000/MBtu)($1,000)($1000)($1,000)($1,000) 1984 34,222 0 34,222 2,852 0.980 2,795 97,253 .0084 817 0 1,978.0 1,911.1 1985 34,324 0 34,324 2,860 1.004 2,872 97,526 .0084 819 0 2,053.0 1,916.5 1986 34,427 0 34,427 2,869 1.029 2,952 97,833 .0086 841 a 2,111.0 1,903.9 1987 34,515 1)34,515 2,876 1.055 3,034 98,072 .0090 883 0 2,151.0 1,874.4 1988 34,627 0 34,627 2,886 1.082 3,122 98,413 .0092 905 a 2,217.0 1,866.7 1989 34,712 Oo 34,712 2,893 1.109 3,208 98,651 -0094 927 0 2,281.0 1,855.6 1990 34,794 0 34,794 2,900 1.136 3,294 98,890 .0097 959 i}2,335.0 1,835.3 1991 34,952 0 34,952 2,913 1.165 3,393 99,333 .0099 983 0 2,410.0 1,830.2 1992 35,117 i)35,117 2,926 1.194 3,494 99,777 .0101 1,008 )2,486.0 1,824.0 1993 35,273 24,700 10,573 881 1.224 1,078 30,042 -0104 312 5,900 6,666.0 4,725.5 1994 35,407 24,800 10,607 884 1.254 1,108 30,144 .0107 323 5,900 6,685.0 4,578.6199535,555 24,900 10,655 888 1.286 1,142 30,281 .0110 333 5,900 6,709.0 4,440.0 1996 35,721 25,000 10,721 893 1.318 1,178 30,451 .0112 341 5,900 6,737.0 4,307.6 1997 35,921 25,100 10,821 902 1.351 1,218 30,758 -0115 354 5,900 6,764.0 4,178.8199836,097 25,200 10,897 908 1.385 1,258 30,963 -0118 365 5,900 6,793.0 4,054.7 1999 36,235 25,400 10,835 903 1.419 1,281 30,792 -0121 373 5,900 6,808.0 3,926.2 2000 36,422 25,500 10,922 910 1.455 1,324 31,031 .0124 385 5,900 6,839.0 3,810.7 2001 36,587 25,600 10,987 916 1.491 1,365 31,236 .0127 397 5,900 6,868.0 3,697.7200236,771 25,700 11,071 923 1.528 1,410 31,474 .0130 409 5,900 6,901.0 3,589.9200336,947 25,900 11,047 921 1.567 1,443 31,406 0134 421 5,900 6,922.0 3,479.0 2004-2017 37,105 26,000 11,105 925 1.567 1,450 31,543 .0134 423 5,900 6,927.0 36,733.9 2018-2027 37,105 26,000 11,105 925 1.567 1,450 31,543 -0134 423 1,400 2,427.0 6,055.4 2028-2037 37,105 26,000 11,105 925 1.567 1,450 31,543 -0134 423 5,900 6,927.0 12,253.9 2038 37,105 26,000 11,105 925 1.567 1,450 31,543 -.0134 423 (44,100)(43,073.0)(7,714.4) NOTE:ALL COSTS IN 1983 DOLLARS TOTAL:108,935.2 TABLE 15 34 ECONOMIC ANALYSIS OF ALTERNATIVE "A"(WITH 10 MW PLANT) (BEST-GUESS FORECAST) ENERGY GEOTHERMAL DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM GEOTHERMAL PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR (MWh)(MWh)(MWh)(1000 g)($/gal)($1000)(MBtu)-($1000/Btu)($1,000)($1000)($2,000)($1,000) 1984 34,986 O 34,986 2,916 0.980 2,857 99,436 .0084 835 0 2,022.0 1,953.71985=36,125 O 36,125 3,010 1.004 3,022 102,641 .0084 B62 0 2,160.0 2,016.4 1986 37,622 O 37,622 3,135 1.029 3,226 106,904 .0086 919 i)2,307.0 2,080.71987.=.39,005 6 39,005 3,250 1.055 3,429 110,825 .0090 997 0 2,432.0 2,119.2 1988 40,398 0 40,398 3,367 1.082 3,643 114,815 .0092 1,056 0 2,587.0 2,178.3 1989 =41,982 O 41,982 3,499 1.109 3,880 119,316 0094 1,122 0 2,758.0 2,243.6 1990s 43,371 O 43,371 3,618 1.136 4,106 123,237 .0097 1,195 0 2,911.0 2,288.0 1991 45,948 0 45,948 3,829 1.165 4,461 130,569 .0099 1,293 0 3,168.0 2,405.8 1992 48,760 0 48,760 4,063 1.194 4,852 138,548 .O1dl 1,399 0 3,453.0 2,533.5 1993 51,364 36,000 15,384 1,282 1.224 1,569 43,716 .0104 455 5,900 7,014.0 4,972.2 1994 54,195 37,900 16,295 1,358 1.254 1,703 46,308 .0107 495 5,900 7,108.0 4,868.3 1995 56,782 39,700 17,082 1,424 1.286 =1,831 48,558 .0110 534 5,900 7,197.0 4,763.0 1996 62,348 43,400 18,948 1,579 1.318 2,081 53,844 0112 603 5,900 7,378.0 4,717.5 1997 67,891 47,000 20,891 1,741 1.351 2,352 59,368 -O115 683 5,900 7,569.0 4,676.1 1998 73,420 47,000 26,420 2,202 1.385 3,049 75,088 .0118 B86 5,900 8,063.0 4,812.8 1999 78,982 47,000 31,982 2,665 1.419 3,782 90,877 .0121 1,100 5,900 8,582.0 4,949.2 2000 «84,525 47,000 37,525 3,127 1.455 4,550 106,631 .0124 1,322 5,900 9,128.0 5,086.1 2001 90,077 47,000 43,077 3,590 1.491 5,352 122,419 .0127 1,555 5,900 9,697.0 5,220.9 2002 95,200 47,000 48,200 4,017 1.528 6,137 136,980 .0130 1,781 5,900 10,256.0 5,335.2 2003 100,764 47,000 53,764 4,480 1.567.7,021 152,768 0134 2,047 5,900 10,874.0 5,465.3 2004-2017 106,238 47,000 59,238 4,937 1.567 7,735 168,352 0134 2,256 5,900 11,379.0 60,342.8 2018-2027 106,238 47,000 59,238 4,937 1.567 7,735 168,352 0134 2,256 1,400 6,879.0 17,163.1 2028-2037 106,238 47,000 59,238 4,937 1.567 7,735 168,352 .0134 -2,256 5,900 11,379.0 20,129.5 2038 106,238 47,000 59,238 4,937 1.567 7,735 168,352 .0134 2,256 (44,100)(38,621.0)(6,917.0) NOTE:ALL COSTS IN 1983 DOLLARS TOTAL:165,404.2 TABLE 16 35 ECONOMIC ANALYSIS OF ALTERNATIVE "A"(WITH 10 MW PLANT) (HIGH-GROWTH FORECAST) ENERGY GEOTHERMAL DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM GEOTHERMAL PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTSYEAR_(MWh)(Mth)(MWh)(1000 g)($/gal)($1000)_(MBtu)_($1000/MBtu)($1,000)($1000)($1,000)($1,000) 1984 36,427 0 36,427 3,036 0.980 2,975 103,528 0084 870 0 2,105.0 2,033.9 1985 38,522 QO 38,522 3,210 1.004 3,223 109,461 0084 919 0 2,304.0 2,150.8 1986 41,491 O 41,491 3,458 1.029 3,558 117,918 0086 1,014 0 2,544.0 2,294.4 1987 44,242 0 44,242 3,687 1.055 3,890 125,727 .0090 1,132 0 2,758.0 2,403.31988=47,173 O 47,173 3,931 1.082 4,253 134,047 0092 1,233 0 3,020.0 2,542.8 1989 49,950 0 49,950 4,163 1.109 4,616 141,958 .0094 1,334 0 3,282.0 2,669.9 1990 52,900 O 52,900 4,408 1.136 5,008 150,313 0097 1,458 .0 3,550.0 2,790.3 1991 57,668 0 57,668 4,806 1.165 5,599 163,885 .0099 1,622 0 3,977.0 3,020.1 1992 62,493 0 62,493 5,208 1.194 6,218 177,593 0101 1,794 0 4,424.0 3,245.9 1993 67,137 47,000 20,137 1,678 1.224 2,054 57,220 0104 595 5,900 7,359.0 5,216.8 1994 71,962 47,000 24,962 2,080 1.254 2,609 70,928 0107 759 5,900 7,750.0 5,308.0 1995 76,798 47,000 29,798 2,483 1.286 3,193 84,670 .0110 931 5,900 8,162.0 5,401.6 1996 83,437 47,000 36,437 3,036 1.318 4,002 103,528 0112 1,160 5,900 8,742.0 5,589.6 1997 91,706 47,000 44,706 3,726 1.351 5,033 127,057 0115 1,461 5,900 9,472.0 5,851.8 1998 98,262 47,000 51,262 4,272 1.385 5,916 145,675 0118 1,719 5,900 10,097.0 6,026.9 1999 106,573 47,000 59,573 4,964 1.419 7,045 169,272 .0121 2,048 5,900 10,897.0 6,284.3 2000.113,774 47,000 66,774 5,565 1.455 8,096 189,767 0124 2,353 5,900 11,643.0 6,487.5 2001 121,143 47,000 74,143 6,179 1.491 9,212 210,704 0127 2,676 5,900 12,436.0 6,695.5 2002 129,432 47,000 82,432 6,869 1.528 10,496 234,233 0130 3,045 5,900 13,351.0 6,945.2 2003 135,693 47,000 88,693 7,391 1.567 11,582 252,033 0134 3,377 5,900 14,105.0 7,089.2 2004-2017 143,962 47,000 96,962 8,080 1.567 12,662 275,528 0134 3,692 5,900 14,870.0 78,855.6 2018-2027 143,962 47,000 96,962 8,080 1.567 12,662 275,528 0134 3,692 1,400 10,370.0 25,873.2 2028-2037 143,962 47,000 96,962 8,080 1.567 12,662 275,528 0134 3,692 5,900 14,870.0 26,305.0 2038 143,962 47,000 96,962 8,080 1.567 12,662 275,528 0134 3,692 (44,100)(35,130.0)(6,291.8) NOTE:ALL COSTS IN 1983 DOLLARS TOTAL:214,789.8 TABLE 17 36 ECONOMIC ANALYSIS OF ALTERNATIVE"A"(WITH 30 MW PLANT)(LOW-GROWTH FORECAST) ENERGY GEOTHERMAL OIESEL FUEL FUEL FUEL'WASTE HEAT SALES PRICE REVENUE FROM GEOTHERMAL PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR (MWh)(MWh)(MWh)(1000 qg)($/qal)($1000)(MBtu)_($1000/MBtu)($1,000)($1000)($1,000)($1,000) 1984 34,222 0 34,222 2,852 0.980 2,795 97,253 .0084 817 0 1,978.0 1,911.1 1985 34,324 0 34,324 2,860 1.004 2,872 97,526 -0084 819 0 2,053.0 1,916.5 1986 34,427 i)34,427 2,869 1.029 2,952 97,833 .0086 841 0 2,111.0 1,903.9 1987 34,515 O 34,515 2,876 1.055 3,034 98,072 -0090 883 0 2,151.0 1,874.4 1988 34,627 0 34,627 2,886 1.082 3,122 98,413 .0092 905 0 2,217.0 1,866.7 1989 34,712 ft)34,712 2,893 1.109 3,208 98,651 .0094 927 0 2,281.0 1,855.61990«=34,794 0 34,794 2,900 1.136 3,294 98,890 .0097 959 0 2,335.0 1,835.3 1991 34,952 0 34,952 2,913 1.165 3,393 99,333 .0099 983 0 2,410.0 1,830.2 1992 35,117 0 35,117 2,926 1.194 3,494 99,777 .0101 1,008 0 2,486.0 1,824.0 1993 35,273 24,700 10,573 881 1.224 1,078 30,042 -0104 312 15,100 15,866.0 11,247.4 1994 35,407 24,800 10,607 884 1.254 1,108 30,144 .0107 323 15,100 15,885.0 10,879.6 1995 35,555 24,900 10,655 888 1.286 1,142 30,281 .0110 333 15,100 15,909.0 10,528.6 1996 35,721 25,000 10,721 893 1.318 1,178 30,451 .0112 341 15,100 15,937.0 10,190.1 1997 35,921 25,100 10,821 902 1.351 1,218 30,758 O11 354 15,100 15,964.0 9,862.6 1998 36,097 25,300 10,797 900 1.385 1,246 30,690 .0118 362 15,100 15,984.0 9,540.8 1999 36,235 25,400 10,835 903 1.419 1,281 30,792 .0121 373 15,100 16,008.60 9,231.8 2000 36,422 25,500 10,922 910 1.455 1,324 31,031 .0124 385 15,100 16,039.0 8,936.9 2001 36,587 25,600 10,987 916 1.491 1,365 31,236 .0127 397 15,100 16,068.0 8,651.0 2002 36,771 25,700 11,071 923 1.528 1,410 31,474 .0130 409 15,100 16,101.0 8,375.7 2003 36,947 25,800 11,147 929 1.567 1,456 31,679 0134 424 15,100 16,132.0 8,107.9 2004-2017 37,105 26,000 11,105 925 1.567 1,450 31,543 .0134 423 15,100 16,127.0 85,521.5 2018-2027 37,105 26,000 11,105 925 1.567 1,450 31,543 0134 423 2,800 3,827.0 9,548.4 2028-2037 37,105 26,000 11,105 925 1.567 1,450 31,543 0134 423 15,100 16,127.0 28,528.7 2038 37,105 26,000 11,105 925 1.567 1,450 31,543 -0134 423 (132,100)(131,073.0)(23,475.2) NOTE:ALL COSTS IN 1983 DOLLARS TOTAL:222,493.5 TABLE 18 37 ECONOMIC ANALYSIS OF ALTERNATIVE "A"(WITH 30 MW PLANT) BEST-GUESS FORECAS ENERGY GEOTHERMAL OIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM GEOTHERMAL PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR (MWh)(MWh)(MWh)(1000 gq)($/gal)($1000)_(MBtu)-_($1000/MBtu)($1,000)($1000)($1,000)($1,000) 1984 34,986 0 34,986 2,916 0.980 2,857 99,436 .0084 835 fr)2,022.0 1,953.7 1985 36,125 0 36,125 3,010 1.004 3,022 102,641 .0084 862 0 2,160.0 2,016.4 1986 37,622 0 37,622 3,135 1.029 3,226 106,904 .0086 919 0 2,307.0 2,080.7 1987 39,005 0 39,005 3,250 1.055 3,429 110,825 .0090 997 0 2,432.0 2,119.2 1988 40,398 0 40,398 3,367 1.082 3,643 114,815 .0092 1,056 0 2,587.0 2,178.3 1989 =41,982 0 41,982 3,499 1.109 3,880 119,316 .0094 1,122 0 2,758.0 2,243.6 1990)43,371 O 43,371 3,614 1.136 4,106 123,237 .0097 1,195 0 2,911.0 2,288.0 1991 45,948 0 45,948 3,829 1.165 4,461 130,569 .0099 1,293 0 3,168.0 2,405.8 1992 48,760 0 48,760 4,063 1.194 4,852 138,548 .0101 1,399 0 3,453.0 2,533.5 1993 51,384 36,000 15,384 1,282 1.224 1,569 43,716 .0104 455 15,100 16,214.0 11,494.1 1994 54,195 37,900 16,295 1,358 1.254 1,703 46,308 .0107 495 15,100 16,308.0 11,169.3 1995 56,782 39,700 17,082 1,424 1.286 1,831 48,558 .0110 534 15,100 16,397.0 10,851.5 1996 62,348 43,600 18,748 1,562 1.318 2,059 53,264 -0112 597 15,100 16,562.0 10,589.7 1997 67,891 47,500 20,391 1,699 1.351 2,296 57,936 -OLLS 666 15,100 16,730.0 10,335.8 1998 73,420 51,400 22,020 1,835 1.385 2,541 62,574 .0118 738 15,100 16,903.0 10,089.4 1999 78,982 55,300 23,682 1,974 1.419 2,800 67,313 0121 814 15,100 17,086.0 9,853.5 2000 84,525 59,200 25,325 2,110 1.455 3,071-71,951 .0124 892 15,100 17,279.0 9,627.9 2001 90,077 63,000 27,077 2,256 1.491 3,364 76,930 .0127 977 15,100 17,487.0 9,415.0 2002 95,200 66,600 28,600 2,383 1.528 3,642 81,260 .0130 1,056 -15,100 17,686.0 9,200.3 2003 100,764 70,500 30,264 2,522 1.567 3,952 86,000 .0134 1,152 15,100 17,900.0 8,996.5 2004-2017 106,238 74,400 31,838 2,653 1.567 4,158 90,467 .0134 1,212 15,100 18,046.0 95,697.9 2018-2027 106,238 74,400 31,838 2,653 1.567 4,158 90,467 -0134 1,212 2,800 5,746.0 14,336.3 2028-2037 106,238 74,400 31,838 2,653 1.567 4,158 90,467 .0134 1,212 15,100 18,046.0 31,923.4 2038 106,238 74,400 31,838 2,653 1.567 4,158 90,467 .0134 1,212 (132,100)(129,154.0)(23,131.5) NOTE:ALL COSTS IN 1983 DOLLARS TOTAL:250,268.3 TABLE 19 ECONOMIC ANALYSIS OF ALTERNATIVE "A™(WITH 30 MW PLANT) CHIGH-GROWTHFORECAST)=-=-"'(i'(ai'(i'<CS; *S;*# 38 ENERGY GEOTHERMAL OIE€SEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM GEOTHERMAL PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR (MWh)(MWh)(MWh)(1000 g)($/gal)($1000) (MBtu) ($1000/MBtu)($2,000)($1000)($1,000)($1,000) 1984 36,427 0 36,427 3,036 0.980 2,975 103,528 .0084 870 0 2,105.0 2,033.9 1985 38,522 0 38,522 3,210 1.004 3,223 109,461 -0084 919 0 2,304.0 2,150.8 1986 41,491 0 41,491 3,458 1.029 3,558 117,918 .0086 1,014 0 2,544.0 2,294.4 1987 44,242 0 44,242 3,687 1.055 3,890 125,727 .0090 1,132 0 2,758.0 2,403.31988=«47,173 0 47,173 3,931 1,082 4,253 134,047 .0092 1,233 fh)3,020.0 2,542.8 1989 =49,950 0 49,950 4,163 1.109 4,616 141,958 .0094 1,334 0 3,282.0 2,669.9 1990 52,900 0 52,900 4,408 1.136 5,008 150,313 .0097 1,458 0 3,550.0 2,790.3 1991 57,668 0 57,668 4,806 1.165 5,599 163,885 -0099 1,622 0 3,977.0 3,020.1 1992 62,493 0 62,493 5,208 1.194 6,218 177,593 .0101 1,794 0 4,424.0 3,245.9 1993 67,137 47,000 20,137 1,678 1.224 2,054 57,220 -0104 595 15,100 16,559.0 11,738.7 1994 71,962 50,400 21,562 1,797 1.254 2,253 61,278 .0107 656 15,100 16,697.0 11,435.8 1995 76,798 53,800 22,998 1,917 1.286 2,465 65,370 .0110 719 15,100 16,846.0 11,148.7 1996 83,437 58,400 25,037 2,086 1.318 2,750 71,133 .0112 797 15,100 17,053.0 10,903.7 1997 91,706 64,200 27,506 2,292 1.351 3,097 78,157 .0115 899 15,100 17,298.0 10,686.7 1998 98,262 68,800 29,462 2,455 1.385 3,400 83,716 .0118 988 15,100 17,512.0 10,452.9 1999 106,573 74,600 31,973 2,664 1.419 3,781 90,842 .0121 1,099 15,100 17,782.0 10,254.9 2000 113,774 79,600 34,174 2,848 1.455 4,144 97,117 .0124 1,204 15,100 18,040.0 10,051.9 2001 121,143 84,800 36,343 3,029 1.491 4,516 103,289 .0127 1,312 15,100 18,304.0 9,854.9 2002 129,432 90,600 38,832 3,236 1.528 4,945 110,348 .0130 1,435 15,100 18,610.0 9,680.9 2003 135,693 95,000 40,693 3,391 1.567 5,314 115,633 0134 1,549 15,100 18,865.0 9,481.5 2004-2017 143,962 100,800 43,162 3,597 1.567 5,636 122,658 .0134 1,644 15,100 19,092.0 101,244.9 2018-2027 143,962 100,800 43,162 3,597 1.567 5,636 122,658 -0134 1,644 2,800 6,792.0 16,946.0 2028-2037 143,962 100,800 43,162 3,597 1.567 5,636 122,658 .0134 1,644 15,100 19,092.0 33,773.7 2038 143,962 100,800 43,162 3,597 1.567 5,636 122,658 -0134 1,644 (132,100)(128,108.0)(22,944.1) NOTE:ALL COSTS IN 1983 DOLLARS TOTAL: 267,862.5 TABLE 20 39 ECONOMIC ANALYSIS OF ALTERNATIVE "8"(WITH BOTH HYDRO PLANTS) (LOW-GROWTH FORECAST) ENERGY HYDRO DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM HYDRO PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR (MWh)(MWh)(MWh)(1000 gq)($/gal)($1000)(MBtu) ($1000/MBtu)($1,000)($1000)($1,000)($1,000) 1984 34,222 i)34,222 2,852 0.980 2,795 97,253 0084 817 0 1,978.0 1,911.1 1985 34,324 0 34,324 2,860 1.004 2,872 97,526 -0084 819 0 2,053.0 1,916.5 1986 34,427 0 34,427 2,869 1.029 2,952 97,833 .0086 841 0 2,111.0 1,903.9 1987 34,515 0 34,515 2,876 1.055 3,034 98,072 .0090 883 0 2,151.0 1,874.4 1988 34,627 0 34,627 2,886 1.082 3,122 98,413 .0092 905 0 2,217.0 1,866.7 1989 34,712 5,400 29,312 2,443 1,109 2,709 83,306 .0094 783 460 2,386.0 1,941.0 1990 34,794 5,400 29,394 2,450 1.136 2,783 83,545 .0097 810 460 2,433.0 1,912.3 1991 34,952 5,400 29,552 2,463 1.165 2,869 83,988 .0099 831 460 2,498.0 1,897.0 1992 35,117 5,400 29,717 2,476 1.194 2,957 84,432 .0101 853 460 2,564.0 1,881.2 1993 35,273 5,400 29,873 2,489 1.224 3,047 84,875 -0104 883 460 2,624.0 1,860.2 1994 35,407 5,400 30,007 2,501 1.254 3,136 85,284 .0107 913 460 2,683.0 1,837.6 1995 35,555 5,400 30,155 2,513 1.286 3,232 85,693 .0110 943 460 2,749.0 1,819.3 1996 35,721 5,400 30,321 2,527 1.318 3,330 86,171 -0112 965 460 2,825.0 1,806.3 1997 35,921 5,400 30,521 2,543 1.351 3,436 86,716 .0115 997 460 2,899.0 1,791.0 1998 36,097 5,400 30,697 2,558 1.385 3,543 87,228 .0118 1,029 460 2,974.0 1,775.2 1999 36,235 5,400 30,835 2,570 1.419 3,646 87,637 .0121 1,060 460 3,046.0 1,756.6 2000 36,422 5,400 31,022 2,585 1.455 3,761 88,149 -0124 1,093 460 3,128.0 1,742.9 2001 36,587 5,400 31,187 2,599 1.491 3,875 88,626 -0127 1,126 460 3,209.0 1,727.7 2002 36,771 5,400 31,371 2,614 1.528 3,995 89,137 .0130 1,159 460 3,296.0 1,714.6 2003 36,947 5,400 31,547 2,629 1.567 4,120 89,649 .0134 1,201 460 3,379.0 1,698.3 2004-2023 37,105 5,400 31,705 2,642 1.567 4,140 90,092 .0134 1,207 460 3,393.0 23,415.1 2024-2038 37,105 5,400 31,705 2,642 1,567 4,140 90,092 .0134 1,207 50 2,983.0 10,306.3 NOTEs ALL COSTS IN 1983 DOLLARS TOTAL:70,355.2 ECONOMIC ANALYSIS OF ALTERNATIVE "B"(WITH BOTH HYDRO PLANTS) TABLE 21 40. (BEST-GUESS FORECAST) ENERGY HYDRO DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM HYDRO PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR _(Mih)(Mth)(MWh)(1000 g)($/qal)($1000)_(MBtu)_($1000/MBtu)($1,000)($1000)($1,000)($1,000) 1984 34,986 O 34,986 2,916 0.980 2,857 99,436 0084 835 y 2,022.0 1,953.7 1985 36,125 O 36,125 3,010 1.004 3,022 102,641 0084 862 0 2,160.0 2,016.4 1986 37,622 O 37,622 3,135 1.029 3,226 106,904 0086 919 0 2,307.0 2,080.7 1987.39,005 0 39,005 3,250 1.055 3,429 110,825 .0090 997 0 2,432.0 2,119.21988=.40,398 O 40,398 3,367 1.082 3,643 114,815 .0092 1,056 0 2,587.0 2,178.3 1989 41,982 5,400 36,582 3,049 1.109 3,381 103,971 .0094 977 460 2,864.0 2,329.9 1990 43,371 45,400 37,971 3,164 1.136 3,595 107,892 0097 1,047 460 3,008.0 2,364.3 1991 45,948 5,400 40,548 3,379 1.165 3,937 115,224 .0099 1,141 460 3,256.0 2,472.6 1992 48,760 5,400 43,360 3,613 1.194 4,314 123,203 0101 1,244 460 3,530.0 2,590.0 1993 51,384 5,400 45,984 3,832 1.224 4,690 130,671 .0104 1,359 460 3,791.0 2,687.4 1994 54,195 5,400 48,795 4,066 1.254 5,099 138,651 0107 1,484 460 4,075.0 2,791.0 1995 56,782 5,400 51,382 4,282 1.286 5,506 146,016 .0110 1,606 460 4,360.0 2,885.4 1996 62,348 5,400 56,948 4,746 1.318 6,255 161,839 0112 1,813 460 4,902.0 3,134.3 1997 67,891 5,400 62,491 5,208 1.351 7,035 177,593 .0115 2,042 460 5,453.0 3,368.9 1998 73,420 5,400 68,020 5,668 1.385 7,851 193,279 .0118 2,281 460 6,030.0 3,599.3 1999 78,982 5,400 73,582 6,132 1.419 8,701 209,101 .0121 2,530 460 6,631.0 3,824.1 2000 84,525 5,400 79,125 6,594 1.455 9,594 224,855 0124 2,788 460 7,266.0 4,048.6 2001 90,077 5,400 84,677 7,056 1.491 10,521 240,610 .0127 3,056 460 7,925.0 4,266.8 2002 95,200 5,400 989,800 7,483 1.528 11,435 255,170 .0130 3,317 460 8,578.0 4,462.3 2003 100,764 5,400 95,364 7,947 1.567 12,453 270,993 .0134 3,631 460 9,282.0 4,665.1 2004-2023 106,238 5,400 100,838 8,403 1.567 13,168 286,542 0134 3,840 460 9,788.0 67,547.0 2024-2038 106,238 5,400 100,838 8,403 1.567 13,168 286,542 .0134 3,840 50 9,378.0 32,401.0 NOTE:ALL COSTS IN 1983 DOLLARS TOTAL:.159,786.3 TABLE 22 4l ECONOMIC ANALYSIS OF ALTERNATIVE "6"(WITH BOTH HYDRO PLANTS) (HIGH-GROWTH FORECAST) ENERGY HYDRO DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM HYDRO PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR (MWh)(MWh)(MWh)(1000 gq)($/gal)($1000)_(MBtu)_($1000/MBtu)($1,000)($1000)($1,000)($1,000) 1984 36,427 O 36,427 3,036 0.980 2,975 103,528 0084 870 0 2,105.0 2,033.9 1985 38,522 O 38,522 3,210 1.004 3,223 109,461 -0084 919 0 2,304.0 2,150.819863=s_-41,491 0 41,491 3,458 1.029 3,558 117,918 -0086 1,014 0 2,544.0 2,294.4198744,242 O 44,242 3,687 1.055 3,890 125,727 .0090 1,132 0 2,758.0 2,403.31988=47,173 O 47,173 3,931 1.082 4,253 134,047 -0092 1,233 0 3,020.0 2,542.8 1989 49,950 5,400 44,550 3,713 1.109 4,117 126,613 0094 1,190 460 3,387.0 2,755.31990§=©52,900 5,400 47,500 3,958 1.136 4,497 134,968 -0097 1,309 460 3,648.0 2,867.3199157,668 5,400 52,268 4,356 1.165 5,074 148,540 .0099 1,471 460 4,063.0 3,085.4199262,493 5,400 57,093 4,758 1.194 5,681 162,248 .0101 1,639 460 4,502.0 3,303.1199367,137.=5,400)61,737 5,145 1.224 6,297 175,445 -0104 1,825 460 4,932.0 3,496.3 1994 71,962 5,400 66,562 5,547 1.254 6,956 189,153 .0107 2,024 460 5,392.0 3,693.0199576,798 5,400 71,398 5,950 1.286 7,651 202,895 -0110 2,232 460 5,879.0 3,890.71996=:83,437 «5,400 =78,037 6,503 1.318 8,571 221,752 0112 2,484 460 6,547.0 4,186.2199791,706 +=©5,400 86,306 7,192 1.351 9,717 245,247 0115 2,820 460 7,357.0 4,545.2199898,262 5,400 92,862 7,739 1.385 10,718 263,900 0118 3,114 460 8,064.0 4,813.4 1999 106,573 5,400 101,173 8,431 1.419 11,964 287,497 0121 3,479 460 8,945.0 5,158.62000«113,774 5,400 108,374 9,031 1.455 13,140 307,957 0124 3,819 460 9,781.0 5,450.02001121,143 5,400 115,743 9,645 1.491 14,381 328,895 .0127 4,177 460 10,664.0 5,741.52002129,432 5,400 124,032 10,336 1.528 15,793 352,458 .0130 4,582 460 11,671.0 6,071.32003135,693 5,400 130,293 10,858 1.567 17,014 370,258 0134 4,961 460 12,513.0 6,289.0 2004-2023 143,962 5,400 138,562 11,547 1.567 18,094 393,753 0134 5,276 460 13,278.0 91,631.5 2024-2038 143,962 5,400 138,562 11,547 1.567 18,094 393,753 0134 5,276 50 12,868.0 44,458.9 NOTE:ALL COSTS IN 1983 DOLLARS TOTAL:212,861.9 42 I.2 -Decision Analysis Tables 11 through 22 have provided net present worth estimates for all four of the energy-supply alternatives considered for Unalaska.These estimates are summarized in Table 23,below: TABLE 23 TOTAL PRESENT WORTH OF ALTERNATIVES AT EACH GROWTH RATE STUDIED (Costs shown are in millions of 1983 dollars) FUTURE GROWTH RATES ALTERNATIVE LOW BEST GUESS HIGH l.Base Case (Diesels)69.5 154.9 205.7 2.Alternative A (Diesels plus 10 MW geothermal)108.9 165.4 214.8 3.Alternative A (Diesels plus 30 MW geothermal)222.5 250.3 267.9 4.Alternative B (Diesels plus small hydro)70.3 159.8 212.9 At each level of load growth studied,it may be seen that the least expensive alternative is the continued (and expanded)use of the diesel units.In a case such as this,the conclusion to be drawn is quite obvious. Had the outcome not been so clear-cut,with the ranking of the alternat- ives'costs differing from one growth rate to the next,there are widely accepted methods for selecting the one alternative to be pursued to min- imize cost or to minimize risk of loss.These techniques were not need- ed in the study of this set of alternatives, 43 J_-ENVIRONMENTAL AND SOCIAL IMPACTS It is expected that none of the alternatives examined by this report would have any negative impacts upon the environment in and around Unalaska nor upon the social structure of the community. The diesel engines which would exist in any event give off exhaust and noise.The nearly constant wind at Unalaska will disperse exhaust emissions quickly.Noise can be controlled when adequate consideration is given to engine enclosures and muffler systems. The danger of fuel spills associated with the installation of diesel engines must be acknowleged.The danger of such spills may be minimiz- ed with proper design.A well-developed spill management plan can help to avoid unnecessary damages if a spill should occur. Salmon spawning areas may be adversely affected by the development of a hydro project on Shaishnikof River.In their draft report on the pro- ject,the Corps of Engineers described measures available to mitigate the damages to such habitat. The construction of a geothermal plat on Mt.Makushin could have sig- nificant environmental impacts,especially upon the surrounding land. With carefully planned construction activities,these damages can be minimized.Areas worth special consideration are the construction of the access road and the disposal of down-hole material and drilling mud. Any one of these projects could provide significant employment possi- bilities to the residents of the area. APPENDIX A COST ESTIMATES DEVELOPED BY REPUBLIC GEOTHERMAL,INC. FOR A GEOTHERMAL PLANT AT MT.MAKUSHIN MAR -8 1984 REPUBLIC GEOTHERMAL,INC. 11823 EAST SLAUSON AVENUE SANTA FE SPRINGS,CALIFORNIA 90670 TWX .910.586.1696 (213)945-3661 March 5,1984 RECEIVED Mr.David Denig-Chakroff Alaska Power Authority MAR 07 1984 334 W.Sth Ave. Anchorage,AK 99501 ALASKA POWER AUTHORITY, Subject:Electrical Power Generation Economic Analysis CHORAGEContractCC08-2334,Amendment No.6 AN ACRES AMERICAN Dear Dave;INC. FILE NO. As requested in your February 2,1984 letter,please find enclosed a draft of the economic feasibility section of the SEQ.NO.subject report.This section addresses the estimated capital 67andoperationandmaintenance(O&M)costs required for the two : cases of a 10 MW gross (6.7 MW net)geothermal power plant and for a 30 MW gross (20 MW net)geothermal power plant on the Island of Unalaska.WYOINI'alaisidVvThe two power plant sizes are derived by superimposing the installed capacity of all units over the estimated power KLdemandasshownontheattachedfigures.To ensure that powerwillbeavailableduringbothnormalandemergencyoperations, the power generation capacity of all available units is always kept above the peak load demand.Normal operation is defined as all installed units available for power generation.Emer- gency operation is defined as the largest installed unit down for maintenance and the second largest installed unit down on emergency trip.Determination of power plant sizing,unit sizing,and phasing schedule will be described in detail ina 3 separate section of the report.FILE!! Based on the above criteria,The 10 MW gross plant will satisfy the electrical load demand estimated by Acres American,Inc.for the ""no-bottomfishing case"well into the future.The 30 MW gross plant will satisfy the electrical load demand estimated by Acres American,Inc.for the "low- bottomfish catch case"well past the year 2000. Due to the uncertainties in the electrical load forecasts, it is recommended that the geothermal power plant be developed in phases that are timed to the growth in demand.The first phase of development would consist of two identical 5 MW gross REPUBLIC GEOTHERMAL.INC. Mr.D.Denig-Chakroff March 5,1984 Page 2 binary units capable of generating a total of 6.7 MW net of electrical power.Should bottomfishing take place and elec- trical load demand increase,than a second and third phase would be added as required.If the load demand follows the low-bottomfish catch projection,the second and third phases would each consist of two 5 MW gross binary units,duplicating the initial phase.They would become commercial in early 1993 and 2000,respectively. We also have analyzed the effects of drilling all wells required for the 30 MW gross plant upon construction of the initial phase,instead of drilling the wells as each increment is constructed.If all wells are drilled in the initial phase,the total development costs are $202,316,000.This requires a total equity investment of $101,158,000 having a 1983 present value of $45,984,000 if discounted back at a factor of 10.5%per year. If the wells are drilled as each increment is constructed, the total development costs are $220,334,000.This requires a total equity investment of $110,172,000 having a 1983 present value of $46,201,000 if discounted back at 10.5%per year. Assuming that amortization of the debt starts upon com- pletion of each phase of construction,a high penalty will bepaidifallwellsaredrilledupfront,as the debt service will be substantially higher.Based on the this,and because of the uncertainties in electrical demand growth,it is recom- mended that the wells be drilled as each increment is con- structed to minimize the risk to the existing consumer base. In order to finalize the draft report by the end of March as scheduled,we would appreciate your comments to the attached at your earliest convenience.If you have any questions,please let us know. Sincerely, J.Bi A{B-] Sr.Power Plant Engineer JB/lc ECONOMIC FEASIBILITY The economic feasibility of developing the Makushin geothermal resource for electrical power generation will be assessed by ACRES American,Inc.as requested by the Alaska Power Authority.To permit this assessment,Republic Geothermal,Inc.has prepared the following tables showing the capital cost estimate and the operation and maintenance cost estimate for each alternative studied: 1. 5. Table I -Capital cost estimate for the development of a 10 MW gross (6.7.MW net)geothermal power plant. Table II -Capital cost estimate for the development of a 30 MW gross (20 MW net)geothermal power plant with al]the wells drilled during the first phase of plant development. Table III -.Capital cost estimate for the development of a 30 MW gross (20 MW net)geothermal power plant with the wells drilled as needed in each phase of plant development. Table IV -Operation and maintenance cost estimate for a 10 MW gross (6.7 MW net)geothermal plant development. Table V -Operation and maintenance cost estimate for a 30 MW gross (20 MW net)geothermal plant development. The cost estimates are based on using the recommended binary cycle for power generation. 1.Capital Costs Capital cost estimates show the field development costs,power plant construction costs,and other necessary costs tn 1983 dollars for each alternative.Addition of these costs gives a total development cost in 1983 dollars.To this total,escalation and interest during construction are added to give a total capital cost required for the development of each alternative. a.Field Development Costs The field development costs include production well drilling and completion,injection well drilling and completion,well testing necessary to prove productivity and injectivity,direct field operation and maintenance during development,home office support and services,and field operation and maintenance during power plant start-up. Ten MW gross field development includes two production wells and one tnjection well.This provides for almost a full spare production well when the plant is operated at full capacity and ensure adequate power generation in the unlikely event of the catastrophic failure of a production well.The injection well provides approximately 40 percent more capacity than necessary to reinject the total fluid required to run the power plant at full capacity.In the very unlikely event of a catastrophic failure,it is assumed that temporary disposal of the spent brine on the ground would be permissible. Thirty MW gross field development includes five production wells and three injection wells,which provides for one spare production well and one spare injection well. Power Plant Costs Power plant costs include engineering and construction of the binary units,engineering and construction of the production pipeline,engineering and construction of the injection pipeline,spare parts,consulting services and coordination support,start-up including operator training,and fire and casualty insurance during construction. 10 MW gross power plant construction is assumed to take place during spring and summer months (April to October)of the first year of construction and continuously from April to end of construction of second year of construction. First phase of 30 MW gross power plant construction (20 MW 'gross)is assumed to take place as described above.Second and third phases will take place continuously,starting in April of the first year until completion at the end of the second year. Power plant engineering and construction costs are based on a turnkey type proposal offered by the Ben Holt Co.for a binary plant similar to one being built in the Sierra Nevada of California.Construction costs are multiplied by a factor of four to reflect the high construction cost expected on Unalaska.Construction field costs tnclude manual Jabor, nonmanual labor,indirect field costs and construction management. Other Costs Other costs include the construction of a road from Driftwood Bay to the power plant site and the construction of a 34.5 kv transmission line from the power plant site to a substation in Dutch Harbor. The road construction estimate is based on a Dames and Moore study prepared for Republic Geothermal,Inc.and Alaska Power Authority in February 1,1983.It includes existing road grading,repair and gravel surfacing;new road construction including culverts and major canyon crossing;and mobilization and demobilization.To ensure that the road ts ready to receive major equipment as it is unloaded from the barge,road construction 1s scheduled for the summer months of the year prior to actual field construction of the first 10 MW gross power plant. The transmission line estimate 1s based on burying the cable approximately 30°underground from the power plant site to Broad Bay and then going underwater to Dutch Harbor.The estimate includes a substation to be located in Dutch Harbor that wil] tie the power plant to the distribution system.It also includes a 30 percent contingency to account for the uncertainties about the underwater portion of the line which has to be buried in the ocean floor. Escalation Escalation is based on an annual inflation rate of seven percent. Interest Expenses Interest expenses represent the interest to be paid during construction based in a debt to equity ration of one and on an interest rate of 12 percent per year. Operation and Maintenance Costs Operation and maintenance (O&M)costs estimates show the total annual cost in 1983 dollars to operate and maintain the overall geothermaldevelopment. O&M costs assume that operation and maintenance labor as well as administration personnel are shared by both power plant and field. O&M costs do not include any royalty payment on the resource utilized during commercial operation or any taxes on the power plant or field. TABLE I NO-BOTTOMF ISHING DEVELOPMENT CASE UNALASKA 10 MW GROSS (6.7 Mi NET)BINARY POWER PLANT DEVELOPMENT COSTS IN THOUSANDS OF DOLLARS Field Development Costs (1983) Production Wells (2) Injection Well (1) Well Testing Direct Operation &Maintenance Home Office Start-Up Subtotal Field Costs Power Plant Costs (1983) Power Plant Eng.&Const. Production Pipeline Injection Pipeline Spare Parts Consulting &Coordination Start-Up Insurance Subtotal Power Plant Costs Other Costs (1983) Road Construction Transmission Line Subtotal Other Costs TOTAL COSTS (1983) Escalation TOTAL ESCALATED COSTS Interest Expenses TOTAL DEVELOPMENT COSTS Equity Debt TOTAL USE OF FUNDS Total 1985 1986 1987 1988 Costs 3,747 2,352 0 0 6,099 ],600 0 0 0 1 ,600 521 236 0 0 757 513 526 426 734 2,199 475 600 400 525 2,000 0 0 0 210 210 6,856 3,714 826 1,469 12,865 0 2,504 10,516 7,010 20,030 0 0 963 0 963 0 0 0 453 453 0 0 0 200 200 162 200 200 238 800 0 0 0 400 400 0 0 130 130 260 162 2,704 11,809 8,431 23,106 0 5,146 0 0 5,146 0 0 0 6 ,405 6,405 0 5,146 0 6,405 11,551 7,018 11,564 12,635 16,305 47,522 1,017 2,602 3,927 6,564 14,110 8,035 14,166 16,562 22,869 61,632 259 978 2,018 3,399 6,654 8,294 15,144 18,580 26,268 68,286 4,147 7,572 9,290 13,134 34,143 4,147 7,572 9,290 13,134 34,143 8,294 15,144 18,580 26,268 68,286 Field Development Costs (1983) Production Wells (5) Injection Wells (3) Well Testing Direct Operation &Maint. Home Office Start-Up Subtotal Field Costs Power Plant Costs (1983) Power Plant Eng.&Const. Production Pipeline Injection Pipeline Spare Parts Consulting &Coordination Start-Up Insurance Subtotal Power Plant Costs Other Costs (1983) Road Construction Transmission Line Subtotal Other Costs TOTAL COSTS (1983) Escalation TOTAL ESCALATED COSTS Interest Expenses TOTAL DEVELOPMENT COSTS Equity Oebt TOTAL USE OF FUNDS LOW-BOTTOMFISH CATCH CASE TABLE U1 UNALASKA 30 MW GROSS (20 MW NET)BINARY POWER PLANT DEVELOPMENT COSTS IN THOUSANDS OF DOLLARS ALL WELLS DRILLED IN FIRST PHASE OF POWER PLANT DEVELOPMENT Total Costs Total Costs Total Costs Total Costs 1985 1986 1987 1988s First Phase 1991 1992 Second Phase 1998 1999 Third Phase All Phases 3,747 4,404 4,404 0 12,555 0 0 0 0 0 0 12,555 1,600 1,600 1,600 0 4,800 0 0 0 0 0 0 4,800 521 354 354 0 1,229 0 0 0 0 0 0 1,229 513 526 526 734 2,299 426 734 1,160 426 734 1,160 4,619 475 600 600 525 2,200 400 525 925 400 525 925 4,050 0 0 0 210 210 0 150 150 0 100 100 460 6,856 7,484 7,484 1,469 23,293 826 1,409 2,235 826 ==1,359 2,185 27,713 O 2,504 10,516 7,010 20,030 10,015 10,015 20,030 10,015 10,015 20,030 60,090 0 0 963 0 963 963 0 963 325 0 325 2,251 0 0 0 453 453 0 453 453 0 453 453 1,359 0 0 0 200 200 0 200 200 0 200 200 600 162 200 200 238 800 200 200 400 200 200 400 1,600 0 0 0 400 400 0 200 200 0 150 150 750 0 0 130 130 260 0 130 130 0 130 130 520 162 2,704 11,809 8,43)23,106 14,178 11,198 22,376 10,540 11,148 21,688 67,170 0 5,146 0 0 5,146 0 0 0 0 0 0 5,146 0 0 6,405 6,405 0 0 0 0 0 0 6,405 OQ 5,146 0 6,405 11,551 0 0 0 0 0 0 11,55) 7,018 15,334 19,293 16,305 57,950 12,004 12,607 24,611 11,366 12,507 28,873 106 434 1,017.3,451 5,997 6,564 17,029 8,621 10,570 19,191 19,993 24,416 44,409 80,629 8,035 18,785 25,290 22,869 74,979 20,625 23,177 43,802 31,359 36,923 68 ,282 187 ,063 259 «1,125 2,598 4,295 8,277 655 2,091 2,746 997.3,233 4,230 15,253 8,294 19,910 27,888 27,164 83,256 21,280 25,268 46,548 32,356 40,156 75,512 202,316 4,147 9,955 13,944 13,582 41,628 10,640 12,634 23,274 16,178 20,078 36,256 101,158 4,147 9,955 13,944 13,582 41,628 10,640 12,634 23,274 16,178 20,078 36,256 101,158 8,294 19,910 27,888 27,164 83,256 21,280 25,268 46 548 32,356 40,156 72,512 202,316 Field Development Costs (1983) Production Wells (5) Injection Wells (3) Well Testing Direct Operation &Maint. Home Office Start-Up Subtotal Field Costs Power Plant Costs (1983) Power Plant Eng.&Const. Production Pipeline Injection Pipeline Spare Parts Consulting &Coordination Start-Up Insurance Subtotal Power Plant Costs Other Costs (1983) Road Construction Transmission Line Subtotal Other Costs TOTAL COSTS (1983) Escalation TOTAL ESCALATED COSTS Interest Expenses TOTAL DEVELOPMENT COSTS Equity Debt TOTAL USE OF FUNDS TABLE ITT LOW-BOTTOMFISH CATCH CASEUNALASKA30MWGROSS(20 MW NET)BINARY POWER PLANT DEVELOPMENT COSTS IN THOUSANDS OF DOLLARS WELLS DRILLED AS NEEDED IN EACH PHASE OF POWER PLANT NEVELOPMENT Total Costs Total Costs Total Costs Total Costs 1985 1986 1987 1988 =First Phase 1991 1992 Second Phase 1998 3999 'Third Phase All Phases 3,747 2,352 0 0 6,099 §,799 0 5,799 3,747 0 3,747 15,6451,600 a 0 0 1,600 1,600 0 1,600 1,600 0 1,600 4,80052123600757354035423602361,3475135264267342,199 526 734 1,260 526 734 1,260 4,719475600400§25 2,000 600 §25 1,125 600 §25 1,125 4,2500it)a 210 210 Q 150 150 0 100 100 460 6,856 3,714 826 1,469 12,865 8,879 1,409 10,288 6,709 1,359 8,068 31,221 O 2,504 10,516 7,010 20,030 10,015 10,015 20,030 10,015 10,015 20,030 60,090009630963963096332503252,251000453453045345304534531,35900020020002002000200200600 162 200 200 238 800 200 200 400 200 200 400 1,60000040040002002000150150750 0 0 130 130 260 0 130 130 0 130 130 520 162 2,704 141,809 8,43)23,106 11,178 11,198 22,376 10,540 11,148 21,688 67,170 O 5,146 0 0 5,146 0 0 0 0 0 0 5,146 0 0 0 6,405 6,405 0 0 0 0 0 0 6,405 O 5,146 Q 6,405 11,551 0 0 0 0 0 0 11,551 7,018 11,564 12,635 16,305 47,522 20,057 12,607 32,664 17,249 12,507 29,756 109 ,942 1,017 2,602 3,927 6,564 14,110 14,405 10,570 24,975 30,342 24,416 54,758 93,843 8,035 14,164 16,562 22,869 61,632 34,462 23,177 57,639 47,591 36,923 84,514 203,785 259 978 2,018 3,399 6,654 1,096 2,999 4,095 1,513 4,297 5,810 16 ,559 8,294 15,144 18,580 26,268 68,286 35,558 26,1746 61,734 49,104 41,220 90,324 220,344 4,147.7,572 9,290 13,134 34,143 17,779 13,088 30 ,867 24,552 20,610 45,162 110,172 4,147)7,572 =99,290 13,134 34,143 17,779 13,088 30,867 24,552 20,610 45,162 110,172 8,294 15,144 18,580 26,268 68 286 35,558 26,176 64,734 49,104 41,220 90 ,324 220,344 TABLE IV NO-BOTTOMFISHING DEVELOPMENT CASE UNALASKA 10 MW GROSS (6.7 MW NET)BINARY POWER PLANT COMBINED PLANT AND FIELD OPERATION AND MAINTENANCE COSTS (Thousands of 1983 Dollars) Administration Operation and Maintenance Labor Contract Maintenance Well Reconditioning Outside Consulting Power Plant Insurance Miscellaneous TOTAL ANNUAL COST TABLE V LOW-BOTTOMFISH CATCH CASE UNALASKA 30 MW GROSS (20 MW NET)BINARY POWER PLANT COMBINED PLANT AND FIELD OPERATION AND MAINTENANCE COSTS (Thousands of 1983 Dollars) Administration Operating and Maintenance Labor Contract Maintenance Well Reconditioning Outside Consulting Power Plant Insurance Miscellaneous TOTAL ANNUAL COST ELECTRICALPOWERDEMAND-MWNO BOTTOMFISH DEVELOPMENT CASE ELECTRICAL GRID LOAD FORECASTS 7L-PEAK LOAD DEMAND BASE LOAD DEMAND 4 sana ene ROE OT ET TA TC TA TCE ie ATTA ts AAT ATTA ITE Si eT TN DE aT TT AE TE Le, 2 1}- !i !!!|J l !f J !!!!|!!|0 1984 1986 1988 1990 1992 1994 1996 1998 2008 2002 2004 YEARS a oa AGI E1634 NO BOTTOMFISH DEVELOPMENT CASE POWER PLANT DEVELOPMENT SCHEDULE ELECTRICALPOWERDEMAND-MW1 19 01985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 6.7MW(NET)COMPOSEDOF21DENTICALUNITSBINARYGEOTILERMALPOWERPLANTL LL l {it -PEAK LOAD DEMAND i L YEARS BASE LOAD DEMAND >CG ©a ©aD ©ED ©ae 6 GD 6 GED ©GS ©GED 6.4 ©am 6 a ¢ae 6 aa aa DIESELGELGENERATORS'4X2.6MWAGI E1529 NO BOTTOMFISH DEVELOPMENT CASE POWER GENERATION-NORMAL OPERATION ALL UNITS AVAILABLE 9 8=- oom =PEAK LOAD DEMAND §-ELECTRICALPOWERDEMAND-MWS=_lo =<© 4 BASE LOAD DEMAND 3+ e ame ¢a= a oem of 2 1_- 0 ee 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS AG:£1528 NO BOTTOMFISH DEVELOPMENT CASE POWER GENERATION-EMERGENCY OPERATIONLARGESTUNITDOWNAND SECOND LARGEST UNIT TRIPPED oeELECTRICALPOWERDEMAND-MW4 BASE LOAD OEMAND I_- 2 1_- a i Ltt!Lt a 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS RG!€1527 ELECTRICALPOWERDEMAND-MWLOW BOTTOMFISH CATCH CASE ELECTRICAL GRID LOAD FORECASTS lL |¢f ¢f |||f fy ff ff Jf ft |}! 1986 1988 1990 1992 1994 1996 1998 2000 YEARS 2002 2004 oe AGI E1639 LOW BOTTOMFISH CATCH CASE POWER PLANT DEVELOPMENT SCHEDULE ELECTRICALPOWERDEMANDwwaTo?_--2->©©ae ¢a ©a=«BINARYGEOTHERMALPOWERPLANTS3X6.7MW(NET)PLANTSEACHINCLUDING2IDENTICALUNITSil I |!|!!!!0 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2008 2007 YEARS DIESELGENERATORS4X2.5MWUNITSAGI 21531 LOW BOTTOMFISH CATCH CASE POWER GENERATION-NORMAL OPERATION ALL UNITS AVAILABLE ELECTRICALPOWERDEMAND9 ee | 1985 1987 1983 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS AGI €1§29 LOW BOTTOMFISH CATCH CASE POWER GENERATION-EMERGENCY OPERATION LARGEST UNIT DOWN FOR MAINTENANCE AND SECOND LARGEST UNIT TRIPPED ELECTRICALPOWERDEMANDa L ee ee 1985 1987 1989 1981 1993 1995 1997 1999 2001 2003 2005 2007 YEARS RG!€1$30 APPENDIX 8B ALASKA POWER AUTHORITY PROJECT EVALUATION GUIDELINES MAR 28 1984 ALASKA POWER AUTHORITY 334 WEST 5th AVENUE -ANCHORAGE,ALASKA 99501 Phone:(907)277-7641 (907)276-0001 ANCHORAGE ACESMarch28,1984 AMERICAN WC, FILE NO. 4Mr.Jim Landman |G ¢a7AcresAmerican,Inc.SEQ.NO.1577 C Street,Suite 305 ,Anchorage,Alaska 99501 - 1 5 {9 Dear M (Raman :g =po The Alaska Power Authority's economic analysis guidelines appear to eebeunrealisticwithrespecttotheeconomiclifeandtermofSiezj \financing of geothermal power facilities.Several outside sources RLexperiencedingeothermaldevelopmenthaveconfirmedthat geothermal systems can be expected to have a 30-year economic life and that 25-year financing is generally accepted.For your econom- ic analysis of the geothermal alternative for the Unalaska recon- naissance study,please use these figures in place of the 15-year Dave Denig-Chakroff Project Manager DDC/ms 544/173/D1/F1 ceo' /JucyGe Lacrent U/IF /y ALASKA POWER AUTHORITY PROJECT EVALUATION PROCEDURE The Power Authority's project evaluation procedure reflects the Organization's purpose and philosophy.The Power Authority was established as an instrument of the State to intervene for the purpose of bringing to.fruition worthy projects that would otherwise be excluded from development by the constraints of financial markets.Most,if not all,Alaskan capital intensive power projects would be precluded from conventional financing due to the perception of added risk inherent in building projects in small,isolated Alaska communities. Thus,the Authority's approach to project evaluation does not consist,as some have recommended,of using market financial parameters to determine the ability of the project to generate sufficient sales to cover revenue requirements.Instead,the approach entails first assessing a project's "worthiness"apart from the constraints of financial markets,and,second,determining if there is the ability and political will to intervene to establish financing arrangements and terms that permit the project to be financed.To reiterate,the Authority's purpose is to intervene in financial markets to permit worthy projects to be developed.A project evaluation procedure that requires a project to pass a financing test using market conditionswouldprecludetheAuthorityfromactinginkeepingwithitspurpose. The means that the Authority has adopted to assess a project's worthiness are consistent with traditional federal evaluation methods for.public water resource projects.The goal is to maximize net economic benefits from the state's perspective,tempered byenvironmental,socioeconomic and public preference constraints.The method attempts to identify the real economic resource costs of alloptionsunderstudy;the magnitude of these costs are independent of the entity that finances and implements the options. The Authority's project evaluation procedure has evolved since 1979 and continues to undergo refinement.Some desired characteristics of the procedures are: 1.Consistency from one study and market area to another. 2.Equity in the treatment of alternatives. 3. Practicality,given data limitations. 4,Responsiveness to statutory direction. In general terms,the procedure entails (1)forecasting end use requirements on the basis of assumptions regarding economic activity andenergycosttrends;(2)formulating various alternative plans to satisfytheforecastedrequirements;(3)estimating the capital,operation, maintenance and fuel costs of each plan over its life cycle;(4)discounting the cost of each plan to a common point in time;(5)comparing the total discounted costs of each plan and determining _--a- Project Evaluation Procedure Page 2 the preferred plan;(6)evaluating the preferred plan's cost of power under a variety of financing arrangements in relation to anticipatedpowercostswithouttheplan;and (7)identifying those financing arrangements which result in acceptable power costs. Forecasting Future Requirements. A planning period is first adopted to define the period of timeoverwhichforecastsaredevelopedandenergyplansareformulated.The length of the planning period is limited by the practical difficulties of forecasting far into the future.A period of 20 years from thepresentisnormallyadopted.End use requirements (space heating,waterheating,lights and appliances,and industrial processes)are forecastovertheplanningperiodforeachofthreesectors(residential,commercial/government,and manufacturing).The end use requirement forecasts are initially developed irrespective of the form of energy being used to energize the end use.The forecast for each end use reflects a range of economic activity/population forecasts and a range of overall energy prices.With respect to the former,economic base analysis founded on discreet developmental events is used as the basis of forecasting rather than simple trend projections,whenever possible. With regard to the latter,the end use forecasts reflect situations both where energy prices,overall,rise faster than general prices and where energy prices,overall,rise at a rate in keeping with general pricelevels.(It can be expected that the actual energy costs of thepreferredplanwilleventuallybeshowntofallwithinthatrange.)An intermediate forecast is used as the basis for the initial planning steps.-For each end use where more than one energy form is available to energize that end use,a mode split analysis is performed.This isaccomplishedinthecourse.of the following initial screening ofalternatives: 1.All reasonable alternative means of providing each end use are identified. 2.The per unit cost of energy is determined for each alternative using the Power Authority's economic evaluation parameters. 3.The amount of energy (or the amount of energy savings)that can be provided by each alternative is estimated. 4.For each end use,cost curves are developed showing relative cost,over time,of providing the end use by each of the reasonable alternatives. 5.The lowest cost means,or combination of means of providing each end use is identified.This determines the mode split after due consideration of the existing mode split and lagtimeforsubstitutionofenergyforms.The results also serve as a tool for formulating energy plans,which is the next step in the analysis. Project Evaluation Procedure Page 3 The forecasts address both energy and peak load requirements. Plan Formulation. The first step in formulating energy plans is identifying and screening all reasonable energy supply and conservation options.These include structural and non-structural alternatives and alternatives that provide intermittent as well as firm energy.This is accomplished in the course of the previous step in the analysis. Existing energy generation facilities and conservation practices are also evaluated for their performance,operation and maintenance costs,condition and remaining economic life. Given the menu of options available,the relative cost and mode split information developed in the course of forecasting energy requirements,and any additional comparative analysis of the options, two or more energy plans are formulated.Each plan must,with a consistent level of reliability,meet the forecasted energy and peak load requirements over the planning period. Whether plans are formulated to meet electrical energy requirements only,or both electrical and thermal requirements,depends upon the results of the mode split analysis.If it is shown that thermal needsshouldbemettoasignificantextentbyelectricalenergy,then plans are formulated to meet both thermal and electrical reauirements.If it is shown,on the other hand,that electricity should not play a significant part in providing thermal needs,then the bounds of the study are_limited to electrical energy requirements only. One plan fs termed the "base case plan";this plan is developed assuming a continuation of existing practice in the study area and isusedasacommonyardstickforcomparisonoftheotherplans. If opportunities exist,a plan is formulated to improve the basecaseplanbyincreasingitsefficiencyorbyothermeans. One or more additional plans are formulated incorporating various combinations of options with the objective of identifying the lowest cost plan that is environmentally and socially acceptable. The sequence and timing of plan components are optimized as an integral part of plan formulation.This is accomplished by a systematic testing of different sequences and project timing in search of the sequence and timing that results in the lowest present value of plan costs. Project Evaluation Procedure Page 4 Discussion: 1.The Authority initially confined the forecasting to electrical energy requirements only.There are two problems with this approach.First,electrical energy supply plans often have associated with them certain amounts of waste heat suitable for space,water or process heating.In such cases,a forecast of thermal energy requirements is needed to determine the possibility of effectively utilizing this heat. Second,in forecasting electrical energy alone,the analyst is either explicitly or implicitly assuming a certain mode split in those end uses where more than just electrical energy can provide that end use.It is necessary to make the analysis of mode split explicit,and to do so requires a forecast of end use requirements rather than simply electrical energy needs. 2.In amplification of the procedure for mode split determination,the goal is to determine,based on full economic cost of alternatives and rational economic behavior, the lowest cost way of providing the end use. Estimating Project Costs. Alt costs for all projects are estimated with reference to a base year and -in terms of the base year price levels.Costs incurred infutureyearsreflectrelativepricechangesonly.Capital cost estimates are "overnight"estimates. Capital costs (in the year they are incurred)are added to annual operation and maintenance costs and any fuel costs to give the total yearly cost of a plan.The series of yearly costs is discounted to a common point in time,typically the first year of the planning period. Discussion: 1.A constant dollar approach has been adopted in the economic analysis to keep from having to forecast a long term inflation rate that would always serve as source of dispute,and to ease the computational burden.As reported by the Water and EnergyTaskForceoftheU.S.Water Resources Council in their © December 1981 report entitled "Evaluating Hydropower Benefits,"the critical element in an analytical approach is the "use of consistent assumptions about interest rates and future prices."The Task Force endorses either "life-cycleanalysis"(which includes inflation)or "inflation free analysis".The Power Authority's approach is specifically cited by the Task Force as an example of the latter. Project Evaluation Procedure Page 5 2.Life cycle analysis dictates,state statute requires,and the long term planning horizon of a state government suggests that the relative plan costs be compared over the economic life of the projects under consideration.When hydroelectric and steam plant projects are being addressed,the economicevaluationperiodexceedsthe20(or sometimes 30)year planning horizon.Yet,it is inappropriate to forecast load growth or escalation trends beyond the limits of the planning period.Also,project economic lives differ for varying types of facilities.These problems are handled by addressing costs throughout the economic evaluation period,but by assuming no load growth or cost escalation beyond the planning period. Facilities are replaced throughout the economic analysis period as dictated by their economic lives.Salvage values are included in the final year of the period as necessary. The economic evaluation period extends to the year that thelongestlivedproject(that is added during the planningperiod)reaches the end of its economic life.For instance, if a hydroelectric project with a 50-year economic life is added in the tenth year of the planning period,the economic evaluation period would be 60 years in duration. Plan Comparison. Plans are compared in terms of total net benefits.Net benefitsareequaltothegrossbenefitsassociatedwitha,plan,less plan cost. The benéfits are defined as the discounted total cost of the base case plan,supplemented by any subsidiary benefits of a particular plan (seediscussion). The plan offering the greatest net benefits is the preferred plan from an economic perspective.A benefit/cost ratio can also be used as an indicator of a plan's cost effectiveness. Discussion: 1.In the event a plan provides a beneficial output other than that specifically being addressed in the study,incremental costs required to realize that benefit are subtracted from the benefit in each year,and these annual subsidiary net benefits are discounted to the common base date. 2.Consider the following hypothetical example:All cost andbenefitfiguresarethesumofannualamountsdiscounted to the base date. Project Evaluation Procedure Page 6 Plan Base Plan Plan Base Plan Plan Subsidiary Cost Net Benefit Case 100 - A 120 10 B 90 15 Case Evaluation - . benefits:100 cost:100 net benefits:0 benefit/cost ratio:1 A Evaluation - benefits:100 +10 =110 cost:120 net benefits:110 -120 =-10 benefit/cost ratio:110/120 =0.92 B Evaluation - benefits:100 +15 =115 cost:90 net benefits:115 -90 =25 benefit/cost ratio:115/90 =1.28 SUMMARY OF RECOMMENDATIONS Analysis Parameters for the 1983 Fiscal Year Economic Analysis Inflation Rate -0% Real Discount Rate -3.5% Real Oil]Distillate Escalation Rate 2.5%.-First 20 years0%#£-Thereafter Cost of Power AnaTysis Inflation Rate -7.0% Project Debt to Equity Ratio -1:0 Cost of Debt -12.02 Economic Life and Term of Financing Gasification EquipmentWasteHeatRecaptureEquipment.Under 5 MW Over 5 MWSolar,Wind Turbines,Geothermal and Organic Rankine Cycle Turbines Diesel Generation* Units under 300 KW Units over 300 KW Gas Turbines Combined Cycle Turbines Steam Turbines (Including Coal and Wood-fired Boilers) Under 10 MW Over 10 MW Hydroelectric Projects Economic Life Term of Financing Transmission Systems Transmission Lines w/Wood Poles Transmission Lines w/Steel Towers Submarine Cables Oil Filled Solid Dielectric *Diesel Reserve Units will have longer life depending on use. 10 years 10 years 20 years 15 years 10 years 20 years 20 years 30 years. 20 years 30 years 50 years 35 years 30 years 40 years 30 years 20 years economic life is by unit and not total plant capacity. Also this Inflation Rate For the purpose of the economic analysis there is assumed to be no inflation. Recommendation:The inflation rate should therefore remain at 0%. Discount Rate As previously indicated in the Analysis Parameters of FY 82 the historic inflation free cost of money to the utility industry appears to be approximately 3.0%.Currently national and local economists and financial experts estimate the overall real discount rate to be in the range of 3%to 4%with a likelihood that the real cost of money for utilities is increasing slightly due to the increasing size and cost of electric generation projects currently being undertaken.It is also acknowledged that historically the real cost of money in Alaska contains an "Alaska factor"and is therefore somewhat higher than in the rest of the nation.However,the discount rate is also intended reflect the state opportunity cost of money and reflect long term trends. Recommendation:In regards to the above analysis and review,the Discount Rate should be set at 3.5%. Escalation Rate Based upon'a composite research of Energy Consulting Companies,nationalandlocaleconomists,and Investment Brokerage Firms,the forecast ofdistillatefuels(diesel and fuel oi1)are expected to increase at an average real rate of 2.5%per annum for the period from 1982 to 2001. Beyond the year 2001 further increases in fuel are assumed to be zero. This assumption is based upon the belief that although additionalincreasesareexpectedtheyaretoospeculativetoquantify.. Recommendation:The escalation rate for diesel and fuel oil be set at 2.5%per annum for the first 20 years of the economic analysis. Thereafter,further increases in the rate are assumed to be zero. Inflation Rate For the 1983 Fiscal Year,national and local economists along withFinancialInstitutionsandEnergyconsultingFirmsforecasttheNational inflation rate between 6 and 8 percent. Recommendation:The inflation rate should be set at 7%per year. Debt to Equity Ratio At the present time and under legislation currently in effect it is difficult to estimate the extent of debt financing for future Power Authority projects.It is also common utility practice to debt finance capital intensive projects. Recommendation:In spite of the Power Authority's legislation,the debt to equity ratio for power project financing should remain at 1:0. Cost of Debt Cost of Debt is largely determined by the interest rate identified by statute for loans from the Power Project Loan fund.That interest rate is equal to the average weekly yield of municipal revenue bonds for the previous 12 month period as determined from the Weekly Bond Buyers 30 year index of revenue bonds.This average is currently approximately 13%.It is anticipated that the average will decrease only slowlyduringthe1983fiscalyear.Recommendation:Because of the anticipated slow decrease in the weekly revenue bond index it is recommended that the cost of debt be set at 12% to reflect current long term tax exempt rates with a decreasingparticipationoftheRuralElectrificationAdministrationinProvidingfederallowinterestfinancing. Economic Life and Term of Loan Although in certain instances economic lives of up to 100 years may be warranted for hydroelectric projects,both the State Division of Budget and Management and F.E.R.C.recommend the use of 50 year economic lives As a result the economic life of a new hydroelectric project is set at 50 years and the term of financing at 35years.For all other alternative generation sources,the economic lifeandthetermforwhichfinancingcanbeobtainedisassumedtobethe for new hydroelectric projects. same even though they vary for each alternative. lives and loan terms should be used for various power project alternatives. Economic Life and Term of Financing Gasification Equipment 10 years Waste Heat Recapture Equipment Under 5 MW 10 years ;Over 5 MW -20 years Solar,Wind Turbines,Geothermal and Organic Rankine Cycle Turbines 15 years Diesel Generation* Units under 300 KW 10 years Units over 300 KW 20 years Gas Turbines 20 years Combined Cycle Turbines 30 years Steam Turbines (Including Coal 'and-Wood-fired Boilers) Onder 10 MW 20 years Over 10 MW 30 years Hydroelectric Projects Economic Life 50 years Term of Financing 35 years Transmission Systems Transmission Lines w/Wood Poles 30 years.Transmission Lines w/Steel Towers 40 years Submarine Cables Oil Filled 30 years Solid Dielectric 20 years *Diesel Reserve Units will have longer life depending on use. economic life is by unit and not total plant capacity. The following economic Also this REFERENCE Discount Rate Fuel Escalation RateInflationRate Or.Scott Goldsmith I.S.E.R. Or.David Reaume Economic Consultant Lehman Brothers, Kohn Loeb Or.Bradford Tuck University of Alaska Donald MacFayden Salomon Brothers Peter W.Sugg URS/Cloverdale & Colpitts- Gary Anderson, Stanford Research Institute Or.Mike Scott Battelle Pacific N.W.Lab. Mr.Thomas Thurber Oata Resources,Inc. Victor A,Perry III Bechtel Corp. William L.Randall The First Boston Corp. Wm.Micheal*McHugh Applied Economics Associates Fredric J.Prager 6.0% 7.0% 5.0 -6.0% 6.0% 6 -8% 6.0 -7.0% 7.0% 5.0 -7.0% 625% 5.0% 7.0 -8.0% 7.0 -8.0% Smith,Barney,Harris Upnam &Company John Delrocali Wharten Econometric Fotcasting Asso. Michael G.Moroney Peat,Marwick & Mitchell,Inc. 5.0 -6.0% 7.0% 6.5% 3.5% 3.5% 4.0% 3.5% 3.0% 2any.ANT .5%Nmdaae.0% -3.5% ;ws.a7. THE ECONOMICS OF THE UNALASKA GEOTHERMAL DEVELOPMENT RECEIVEDby it)O06 1984 ALASKA PO Dr.Michael J.Economides WER AUTHORITY, August 2,1984 There are certain important considerations that one must take into account in any intelligent economic evaluation of this project. Geothermal energy in general must be viewed in terms of the reservoir itself i.e. the characteristics,thermodynamics and chemistry of the fluids,the deliverability of the reservoir and its depth (translated into feet to be drilled)and local conditions (terrain, reservoir characteristics and market demand). THE RESERVOIR AND TTS FLUID .The main reservoir on Makushin voleano is at unknown depths,although this issueinitselfmaybemoot.The known fact is that a high conductivity fracture (almost invariably vertical)has been met at 1950 ft.in ST-1.This fracture is connected to a reservoir (or reservoirs)at depth. | In a recent temperature.survey,conducted a year after drilling and initial flow testing,the well exhibited what appears to be a slight yet certain temperature gradient inversion.This phenomenon,not uncommon in geothermal reservoirs elsewhere,may indicate a significant distance from the purported 440°F temperature that was suggested by geothermometers.Further,it could also imply thatt drilling within relative proximity to ST-1 may not result in|equally attractive fractures.Even in a highly developed fieldenrree such as the Geysers,the success rate of.drilling ranges from 30-70%depending on the location.This is within the presumed drainage area of the geothermal systems. The fluid:from the discovered_Producing horizon is approximately 16%(mass)vapor and 84%liquid at the wellhead (at usable wellhead pressures).Such a fluid is of low thermodynamic quality,although a simulator has predicted a highly prolific reservoir (880,000 lb/hr per 12 in.well).As a result,conventional technology such as the double iedLy flash or even the binary.power 'generation systems would produce 1low conversion efficiencies.There have been recent technological advances,suggesting generators that use the "total flow"of the reservoir fluid.These two-phase (liquid and vapor combined) generators are expected to be superior to the other power schemes with the advantage being further enhanced at low thermodynamic quality fluids,exactly of the type that was discovered on Makushin voleano.Hence,while traditional schemes are estimated to produce 6 MW per commercial size well,a "total flow"system may generate as much as 10 MW.This is a significant increase,resulting in the avoidance of a second well for a 10 MW plant.The Makushin reservoir at 16%vapor should be a prime candidate for the testing of these new technologies. rd Finally,the Makushin fluid is of exceptional quality with regards to its content in undesirable constituents or the total dissolved solids.The T.D.S.have been measured at7800PPM.Further,the effluent of a commercial size well (880,000 Ib/hr)is equivalent to 5 cubie feet/second (efs).By comparison,the Makushin river flow rate has been measured seven times between 270 and 400 cfs.Another measurement resulted in a flow rate of 60 cfs.In the worst case,the dilution of the T.D.S.would be 1/12,decreasing to 1/54 to 1/80 at the most persistent flow rates.The latter would result in an addition of less than 100 PPM to the Makushin river if the effluent were discharged init.This figure is well within the 500 PPM that is considered environmentally acceptable in similar situations.The temperature elevation 'would be a fraction of a degree.Hence the unavoidable inference is that reinjection for a10MW and even perhaps for a 20 MW plant may not be necessary.This is not "virgin ground”since in New Zealand,effluent from a 150 MW power plant has been discharged into a river throughout its 25 year history.The possible avoidence of reinjection would be a major cost cutter.A detailed year-around monitoring of the flow behavior of the Makushin river is indicated prior to any definitive © decisions on the subject.Yet,the preliminary assessment points towards the avoidence of reinjection wells. LOCAL CONDITIONS Certainly the distance from the market (Unalaska/Dutch Harbor)and the terrain to be traversed have been much discussed issues.Among the questions that beckon to beansweredisthenecessityorlackthereofofaroadaccessingthesite.While traditional technologies and economic evaluations done thus far have included the road construction into the geothermal power plant ecomonics,it is not at all clear whether the practice is warranted.Manufacturers of the "total flow"systems have indicated that a main feature of their product is its compactness,optimum small increments and ability to be helicopter transported,installed and maintained.Hence,while a road to Makushin may be desirable for other reasons it should not be necessarily assessed to the geothermal development. As a direct consequence of the arguments presented in the previous subjection regarding the avoidance of reinjection (and hence discharge in the river)one may easily envision a hydroelectric plant on the site.In other words,a seemingly hostile environment may be used positively.I have estimated that the effluent from a commercial size well,utilizing the 600 ft.drop from the ST-1 plateau down to the river, could produce 170 KW of power for a very small capital investment. .:a -\Finally,and more importantly,an optimization scheme for Unalaska,comparing geothermal energy to diesel (other options are prima facie considered unattractive)must be done.Starting from the present demand (13 MW?)to whichever plausible projection, an optimization should be done using.credible increments that the reservoir could deliver.If at 20 MW (or less)diesel is more attractive what about at 30 MW?which is the juncture point,where geothermal becomes more attractive? An optimization attempt such as this would have varying degrees of uncertainty in the figures involved.Drilling may result in dry,deep and costly holes.Yet,while a generalized optimization is in order,a more specific economic evaluation must be eonsidered. There are compelling arguments towards a 10 MW plant as an initial stage of development: 1.One well,using two-phase power conversion technology,could supply close to 10 MW. 2.The well could be drilled,with a certainty of success,at 2000 ft.and exactly on the site of ST-1. 3.No reinjection well is needed. 4.No road is needed. . 5.170 kw of power may be added via a small hydroelectric scheme using the well effluent.| ; Because of these particular items,the certainty associated with them and the luck in discovering ST-1,the economy of scale may not be applicable when a 20 (or 30)MW plant is compared with a 10 MW. | The above,cursory,outline of considerations must be taken into account in any attempt towards a credible economic evaluation of geothermal energy on Unalaska Island. AN ANALYSIS OF FAULT AND VOLCANIC DIKE ORIENTATIONS FOR THE MAKUSHIN VOLCANO REGION OF THE ALEUTIAN ARC by John W.Reeder State of Alaska Division of Geological &Geophysical Surveys Pouch 7-028 Anchorage,Alaska 99510 U.S.A. International Symposium on Recent Crustal Movements of the Pacific Region Victoria University of Wellington Wellington,New Zealand February 9-14,1984 Abstract Holocene faults and volcanic vents reflect the regional crustal stress as well as older fractures of the Makushin Volcano region of the Aleutian arc. Both the observed faults and dikes appear as several similarly oriented swarm sets.Two of the more prominent sets observed throughout this region for both faults and dikes have strikes of N 50°Wt and of N 75°Wi.The N 50°W set is theoretically expected given the fairly constant N 45°W+direction of maximum horizontal compression of regional stress since the Miocene.The formation of the other set appears to have been influenced by a pronounced N 75°W+fracture system exposed dominantly in the plutonic and older rocks of the region.This fracture system has been apparently rotated from a N 45°W+ direction that formed in the late Miocene. INTRODUCTION The Aleutian arc is part of a ridge-trench system associated with active volcanism and seismicity.For the Unalaska Island region of this arc,the Aleutian trench is located about 180 km to the south.The floor of the Pacific Ocean (Pacific Plate)approaches the Aleutian arc (North American Plate)in a northwesterly direction at a rate of about 7 cm/yr (Minster et al.,1974)where the Pacific Plate is being subducted under the North American Plate at the Aleutian trench.On the basis of seismic models,the Pacific Plate dips about 30°under the Aleutian arc until it reaches a depth of 40 km,where its dip increases abruptly to about 70°(Jacob and Hamada, 1972). This Pacific Plate underthrusting causes a regional compression in the direction of plate convergence in the arc region (Nakamura et al.,1980). Because the Pacific and North American Plates converge at.about a N.45°W angle in the Unalaska Island region (Jacob et al.,1977),near vertical northwest-striking fracture and dikes would be expected in response to a regional N 45°W direction of maximum horizontal compression (Anderson,-1951; Odé,1957;and Nakamura et al.,1977).This direction is also approximately the same direction of principal horizontal shortening (Lensen and Otway, 1971).Indeed,for the Makushin Volcano which is locatedon the northern part of Unalaska Island,Nakamura et al.(1977)determined on the basis of the orientation of flank fissures a N 60°W+direction of maximum horizontal compression of regional stress. Faults and dikes have also been observed in the Unalaska Island region that strike at approximately 45°increments to the direction of maximum horizontal compression.For three-dimensional strain of a brittle material to occur in the Unalaska Island region,four fault sets in orthorhombic symmetry would be required (Reches,1983)):two sets of conjugate strike-slip faults having strikes at approximately 45°from the direction of maximum horizontal compression,and two sets of dip-slip faults with one striking in the direction of maximum horizontal compression and the other striking approximately perpendicular to it. Geologic mapping at a scale of 1:63,360 complemented with some geophysical and geochemical surveys has been undertaken in the northern part of Unalaska Island since 1979.The main objective of this work has been to assess the hydrothermal resources of this region (Reeder et al.,1980).This report presents some of the findings with respect to the orientation and regional distribution of dikes,faults,joints,and lineaments. GEOLOGIC SETTING The rocks of Unalaska Island include an older group of altered sedimentary and volcanic rocks designated the Unalaska Formation by Drewes et al.(1961), a group of intermediate-age plutonic rocks that have intruded the Unalaska Formation,and a younger group of unaltered volcanic rocks (fig.1). The region southeast of Makushin Volcano consists mainly of rock exposures belonging to the Unalaska Formation,whereas unaltered volcanics make up the Makushin Volcano and most of the rock exposures to the northwest of a line extending from Pakushin Cone to Table Top Mountain (fig.1). The Unalaska Formation is upper Oligocene to middle Miocene (i.e.;about 30 to 15 mybp)as based on bivalves,barnacle plates,burrow fillings,and a vertebra (Lankford and Hill,1979),and as based on bones and teeth of a desmostylid (Drewes et al.,1961).This formation in the northern part of Unalaska Island consist of conglomerate and sandstone units as well as of numerous volcanic flows and volcanic breccias. The Unalaska Formation has been intruded by three plutons and several smaller intrusive bodies.Individual plutons are zoned from mafic margins to felsic interiors and show calc-alkaline chemical characteristics (Perfit et al., 1980).Radiometric ages determined for two of these plutons yielded ages of 11 +3 mybp (Marlow et al.,1973)and 13 mypb (Lankford and Hill,1979). Perfit and Lawrence (1979)argued that the rocks of the Unalaska Formation were altered mainly during the emplacement of these plutonic bodies.Such alteration includes albitization,chloritization,epidotization, silicification,and zeolitization. The Makushin Volcano of Unalaska Island is one of at least:36 volcanees:-on------- the Aleutian arc that have been active since 1760 (Coats,1950).Active hydrothermal surface manifestations in the form of fumaroles and warm springs are quite numerous on the flanks of this volcano except for its western-northwestern side.The largest fumarole activity occurs near the top of the volcano,which is dominated by a 2.4 km-diameter caldera that formed about 8,000 ybp (Reeder,1983).The most recent eruptions of Makushin |... Volcano occurred in 1938,1951,and 1980(?)as steam-ash flank eruptions with the 1938 event being the largest (Simkin et al.,1981;and Swanson,1982). The unaltered volcanics unconformably blanket the Unalaska Formation as well as any intermediate-age plutonics that have intruded it.Most of these unaltered volcanics are pre-Holocene and post-Pliocene (late Pliocene volcanics are believed to exist at the lowest section of the unaltered volcanics although no reliable age dates have been obtained from rocks of this section),and have been derived mainly from the immediate Makushin Volcano region.Except for Pakushin Cone,Wide Bay Cone,and the Point Kadin cones,the volcanic cones of the area have undergone intense glacial erosion. Both the Pakushin and Wide Bay Cones are suspected to have formed since the last glacial maximum which ended about 11,000 ybp (Black,1976).The line of cones trending toward Point Kadin and the corresponding lavas are believed by Drewes et al.(1961)to have formed within the last several thousand years due to the lack of glacial erosion on the cones and flows,and on the degree of development of a submarine bench at Point Kadin.My own field work,based on ash stratigraphy and on the geographic locations of the cones and glacial moraines,indicates that these cones as well as the Sugarloaf Cone occurred at about or shortly after the time of the Makushin Volcano caldera-forming. event (Reeder et al.,1984b). DIKES,FAULTS,AND JOINTS The Unalaska Formation throughout the region has been cut by porphyritic--- basaltic-to-dacitic dikes (Reeder et al.,1984a).Based on field and - petrographic observations,most of these dikes are not directly related to the volcanic flows and breccias of the Unalaska Formation,although a few of the dikes are directly related to younger sills contained in the formation. In the areas of the intermediate-age (late Miocene)plutonic bodies that have intruded the Unalaska Formation,most of the dikes were found to cut the plutonics.These dikes have formed since late Miocene.For section B and C of Figure 1,no dikes of Quaternary age have so far been found.Yet,most of the dikes in the Makushin Volcano and Table Top Mountain region are directly related to the unaltered late Pliocene and Quaternary volcanics (i.e.,about 65 percent of the dikes observed in section A and E,and about 90 percent of the dikes observed in section D of Figure 1).The diking process for the northern part of Unalaska Island has been occurring,based on geologic field relations,since late Miocene where they are still occurring in the Makushin Volcano and Table Top Mountain regions (section A,D,and E of Figure 1). Faults,mostly near vertical and having small displacements,are also found throughout the region (Reeder et al.,1984a).Although a few of the faults appear to be related to the intrusion of some of the late Miocene plutonic bodies,most of the faults cut both the Unalaska Formation and the plutonics and thus post-date the intrusive events.In a few cases,faults have been found trending directly into Quaternary volcano centers such as Pakushin Cone,Sugarloaf Cone,and even active Makushin Volcano (Reeder et al., 1984b).Such normal faults may be the surface manifestations of dikes that did not reach the surface except at volcanic vents.Many of these faults show Holocene scarps as high as 4 meters.For example,such scarps occur along the EW and the NW trending faults that roughly intersect at the Sugarloaf Cone which is located just northwest of Makushin Volcano,as well as the NW trending normal fault .that cuts the Holocene cinder cones along the Point Kadin rift zone on the northwestern flank of Makushin Volcano (fig.1; and Reeder et al.,1984b). The pattern of orientation for the dikes and faults for the region of Figure 1 are shown by the contour of the %per 1 %area lower hemisphere equal-area projection of poles,Figure 2 and 3 respectively.For both of these projections,most of the data was obtained from the immediate Unalaska community region (i.e.,section B of fig.1)and the immediate Makushin Volcano region (i.e.,northwestern part of section A and southeastern part of section D of fig.1),although field observations of a reconnaissance nature have been made throughout the region (Reeder et al.,1984a).One of the prominent strikes for dikes is about N 52°W (i.e.,includes about 21%of all observed dikes)which have very steep dips either to the south or to the north.Steeply dipping corresponding dikes (i.e.,geologically similar dikes having strikes at approximate 45°increments from the N 52°W strike which are in approximate orthorhombic symmetry)strike approximately N 14°W,N 35°E,and N 70°E (fig.2).About 17%of the observed dikes were also observed striking about N 71°W,where they dip steeply either to the south or to the north.In slight deviation to this prominent strike,the dikes for section B (fig.1)primarily strike in a N 38°W+direction which represents 10%of the total observed dikes with a steep dip either to the south or to the north,while another prominent steeply dipping set strikesN 59°W which represents 6%of the total observed dikes (Reeder et al.,1984a).One of the primary strikes for faults observed was N 51°W which represents 21%of the observed faults (fig.3),with more of the faults dipping steeply.to the south than to the north.Steeply dipping corresponding faults (i.e.,faults having strikes at approximate 45°increments from the N 50°W strike which are in approximate orthorhombic symmetry)have been recognized which strike about N 14°W,N 31°E,and N 87°E.About 18%of the observed faults strike about N 68°W with one corresponding fracture set striking about N 35 °W. In slight deviation to this average trend,about 9 percent of the total observed faults in the region of Figure 1 strike about N 40°W in section B where a secondary set representing 6 percent of the total observed faults strikes about N 60°W in section B (Reeder et al.,1984a). A contour of the %per 1%area lower hemisphere equal-area projection of poles from 63 joint surfaces,found principally in the plutonics of the Unalaska community region (section B of fig.1)and in the plutonics near the Makushin Volcano (northwestern part of section A of fig.1 which is where about 70%of the joints were observed),is shown in Figure 4.One of the primary strikes for these joints is about N 78°W+which represents about 24% of the total observed joints.These joints dip steeply to the south.The corresponding joints have strikes of about N 25°W,N 25°E,and N 74.5°E. Another fairly prominent set strikes about N 50°W which represents about 19% of the total observed joints..These joints dip steeply either to the north or to the south.Corresponding joints strike about N 05°W,N 49°E,and N 85°E.Most of the joints formed during or after the cooling of_the intrusive rocks presently exposed,which would place most of them at about 13-11 mybp or younger. LINEAMENTS A lineament is a straight or gently curved physiographic feature on the ground surface usually marked by slight depressions to more major linear topographic relief,fault scarps,aligned drainage,and/or slight to fairly pronounced changes in vegetation.Lineaments have been carefully noted for the entire region shown in Figure 1 in an attempt to gain better insight into the regional nature of the fracture systems (Reeder et al.,1984c)which has not been entirely obtainable from the geologic mapping due to the lack of continuous outcrops.Fortunately,due primarily to the lack of trees, lineaments are quite pronounced and can be easily recognized on air photographs as well as in the field.When good bedrock exposures were present,the lineaments were found to correlate with faults,dikes,or more rarely joints.The longer lineaments usually reflect faults or in rarer cases dikes.Joints were found to be almost always limited to the shorter lineaments.In only one case was a lineament found to reflect a lateral glacial moraine.Although exceptions are expected to exist to this nearly perfect one to one correlation between lineaments and observed faults,dikes, and/or joints,it is assumed that all of the lineaments that were mapped indeed reflect such features.Most of the lineaments are undeflected by the topography and thus define nearly vertical features.In general,the Unalaska lineaments make regular patterns that most likely reflect the numerous unexposed joints,faults,and dikes of the region. Figure 5(a)is a rose diagram for the cumulative lengths of lineaments for section A (fig.1)which is the region just southeast of Makushin Volcano.One of the principal trends of lineaments for this section is N 75° Wwhich reflects about 11%of the cumulative length for this section.The . Point Kadin rift zone that crosses Makushin Volcano fits this trend,Figure 1.The corresponding set of lineaments (i.e.,sets found at approximately 45°increments from the N-75°W set)are N 29°-W,N 21°E,and N 67°E. These sets reflect about 14%,3%,and 12%of-the cumulative lengths for section A,respectively...Another less pronounced lineament trend is N 50°W where N 08°E,N 54°E,and N 89°E are corresponding trends.These sets reflect about 6%,3%,5%,and 9%of the cumulative length for this section, respectively:For section B (fig.5(b)),one of the principal .lineament trends is N 86°W which reflects about 14%of the cumulative length for this section.Corresponding lineament trends are N 38°W,N 04°E,and N 52°E which reflect about 15%,4%,and 8%of the cumulative length for this section,respectively.Another much less pronounced lineament trend for section B is N 61°W with N 08°W and N 69°E as corresponding trends.These sets reflect about 7%,5%,and 8%of the cumulative length for this section, respectively.In section C (fig.5(c)),the principal sets are N 47°W,N 89°W,N 52°E,and N 02°W.These sets reflect about 8%,16%,22%,and 7% of the cumulative length for the section,respectively.Lineaments directly related geographically with Table Top Mountain of section E (fig.5(d))trend N 47°W,N 01°W,N 38°E,and N 88°E. DISCUSSION As previously mentioned,the direction of maximum horizontal compression or the direction of maximum horizontal shortening expected for this region due to the convergence of the North American and the Pacific Plates is about N 45°W.Steeply dipping N 45°W+striking -fracturesand dikes with corresponding approximate N,N 45°E,and E striking fractures and dikes would be expected for three-dimensional strain to occur.A good number of dike,fault,and joint orientations agree with this expected N 45°W strike (i.e.,N 52°W for dikes,N 51°W for faults,and N 50°-W for-joints)."But, another fairly pronounced NW striking set has also been recognized-(i.e.,N 71°W for dikes,N 68°W for faults,and N 78°W for joints).The lineaments 'related to Table Top Mountain of section E and the lineaments of.section C agree well with the expected N 45°W trend.In section A,the N 74°W lineament trend dominates over the N 50°W trend (i.e,the N 50°W trend is taken instead of the expected N 45°W trend since it is representedin the. 10 field).In section B,the N 86°W lineament trend dominates over a N 61°W trend,where no N 50°W trend has been recognized. The dike and fracture patterns that deviate from the patterns expected must be due either to local stresses and/or to past geologic and/or tectonic events.An approximate N 50°W trend does exist for all of the dikes,faults, joints,and lineaments except for section B.This suggests that the direction of maximum horizontal compression is N 50°W+and that other local stresses are not large enough to cause substantial deviations from this direction.In fact,because most of the dikes,faults,and lineaments are fairly straight,it is unlikely that topographic (local gravity)effects have a substantial influence on the stress field.The other patterns must reflect fractures that,even though some are still active,either formed in the past under a different stress field,and/or have been shifted from their original orientation. The subduction of the Kula Spreading Ridge,and the resulting greenschist regional metamorphism of the then existing Aleutian rocks which now exist throughout the Aleutian Islands,occurred about 30-35 mybp (DeLong et al.,-- 1978).The more localized greenschist metamorphism of the Unalaska Formation-- resulted from the intermediate-age intrusive activity (Perfit,1977)that occurred 13-11 mybp (late Miocene),while the Unalaska Formation formed .- ° approximately 30-15 mybp.This intermediate-age intrusive activity marks the approximate time of resumption not only of magmatism but also of subduction after the approach of the Kula Spreading Ridge to the Aleutian arc.This resumption of subduction and magmatism is also marked by the abrupt appearance of ash layers (approximately 11-12 mybp)in nearby ocean sediments 11 (Creager et al.,1973)and in the initial formation of numerous structural basins along the Aleutian arc in late Miocene and early Pliocene (Scholl et al.,1975). The Atwater and Molnar (1973)reconstruction of the relative positions of the Pacific and North American Plates indicates that the direction of relative motion between the two plates has been fairly constant during Cenozoic time. In fact,their reconstruction indicates only an increase in subduction rate for the Pacific Plate (i.e.,no change in relative motion with the North American Plate)since the initiation of subduction after the approach of the Kula Spreading Ridge.If this model is correct,the regional stress field has been fairly constant since the initiation of subduction at about 15 mybp, except for possible local gravity effects due to topography,local intrusive activity,and regional stress-magnitude variations. The Shaler Pluton exposed south of Makushin Bay (section C of.fig...1)formed about 1]+3 mybp (Marlow et al.,1973)and at this time some dikes,faults, and joints also formed.But,as based on geologic observations,most of the dikes and faults of section C formed during the Pliocene.The principal lineament sets for section C are N 47°W,N 02°W,N 52°E,andN 89°W. This indicates that a N 45°W+direction of maximum horizontal compression existed at the time of plutonism as well as during the Pliocene,which is the same direction of maximum horizontal compression that presently exists. Assuming the direction of relative motion between the North American and the Pacific Plates has indeed been fairly constant,then this part of Unalaska Island has been rotationally stationary since the time of plutonism as based on the orientationof lineaments. 12 In contrast,it appears that the Makushin Volcano region (section A and D)as well as the Unalaska community region (section B)have undergone a counterclockwise rotation after the late Miocene plutonism by about 25°. This rotation occurred during a time when the joints were being formed (i.e., sometime during the cooling of the plutonic bodies).Then dike emplacement, faulting,and jointing continued to occur after this late Miocene rotation, resulting in a N 50°W trend set for dikes,faults,and joints as well as corresponding trend sets.Faulting and diking also continued to occur along the N 75°W fractures which indicates that the magnitude of horizontal stress in this region has been nearly uniform directionally for at least part of the time.This N 75°W trend actually dominates over the N 50°W trend for both faults and dikes in the immediate Makushin Volcano region (fig.1 and fig. 5(a)). The region northeast of,as well as including,the Unalaska community (section B)appears to have rotated sometime in the-Pliocene in a-- counterclockwise direction by another 10°,and no further fracturing and diking have been recognized as occurring since this rotation (i.e.,no Quaternary dikes or faults have been recognized in this section).This rotation apparently occurred after intrusion of all of the dikes,where-the dikes would have been represented before this last rotation by the expected N 75°W and N 50°W striking sets as well as corresponding sets.All-of these dikes would have then been rotated to approximately the N 85°W-and-N 60°W striking sets observed in the field (Reeder et al.,1984a). The N 75°W trending lineaments of section A bend about 10°counterclockwise as they approach section B (fig.1;and Reeder et al.,1984c).Left-lateral 13 offsets of faults and dikes exist near the Unalaska community (fig.1;and Reeder et al.,1984a).For example,a fairly pronounced N 47°E normal fault which is located just south of Summer Bay of section B has been offset by about 1.5 kms to the southeast at the Unalaska community.The strike of this fault changes to N 66°E near section A.Such geologic observations support a regional counterclockwise rotation of the crust and the relative amounts of such rotations. Coats (1962)examined lineaments and seismic data for the entire Aleutian arc.Coats argued that the Aleutian arc has been broken into several large fault blocks by large right-lateral strike-slip faults which trend at high angles to the axis of the arc.Such large fractures would allow counterclockwise rotations about vertical axes.The small WNW striking left-lateral strike-slip fault observed at the Unalaska community (fig.1) could be a conjugate fault to such a high angle right-lateral strike-slip fault.Rotations in the Bonin Islands which are located near the boundary of the converging Pacific and Philippine Sea Plates as based on paleomagnetic data have also been explained as tectonic rotation accompanied by lateral movement of blocks in strike-slip fault zones (Kodama et al.,1983). Rotations as based on paleomagnetic data are actually common at both strike-slip and convergent plate boundaries (Beck,1976 and 1980)where rotations of both senses have been suggested in southeast Alaska (Hicken and Irving,1977;and Grommé and Hillhouse,1981)and for Kodiak Island which is about 900 km NNE of Unalaska Island (Plumley et al.,1983).Some counterclockwise rotations have also been suggested for the Matanuska Valley of the southcentral part of Alaska (Bruhn and Pavlis,1981)as based on the 14 deformation-axis technique (Arthaud,1969).'Such rotation would be expected as based on the theory of three-dimensional strain of a brittle material especially if not all of the four faults in orthorhombic symmetry occur (Reches,1983). An analysis of lineament patterns for the southern part of Adak Island (Lattman and Segovia,1961)which is located about 700 km ESE of Unalaska Island points out a slight difference in the lineament pattern between the two sides of the N 63°E striking Finger Bay Fault.Such a difference suggests substantial relative movements between the two sides of the fault. Because the Pacific and North American Plates converge at about a N 50°W angle in the Adak Island region (Jacob et al.,1977),a N 50°W direction of maximum horizontal compression would be expected.Lattman and Segovia (1961) recognized a concentration of lineament trends in Eocene metavolcanics which range from N 50°W to N 65°W.This suggests that a 15°counterclockwise rotation for the southern part-of Adak Island has occurred sometime since the.. Focene.Paleomagnetic data (Cameron and Stone,1970)for the same Eocene rocks in the northern part of Adak Island suggest a 30°counterclockwise rotation for this part of Adak Island. Naturally,it would be nice to obtain paleomagnetic data to confirm these- proposed Unalaska Island rotationsas well.as to obtain more data.on the ages and nature of faults and dikes.-Although such attempts are presently -- underway,the lack of good fossils,the extent of rock alteration,and the lack of good bedrock exposures are making such attempts difficult. 15 CONCLUSION Many of the fractures of the northern part of Unalaska Island reflect orientations expected for a regional stress caused by the subduction of the Pacific Plate;i.e.,namely an approximately N 50°W striking set with approximate corresponding N 05°W,N 40°E,and N 85°E sets.The direction of relative motion between the North American and Pacific Plates has been fairly constant since at least the Miocene,where Holocene faults and volcanic vents reflect orientation trends that have occurred for dikes and faults since the late Miocene in the Makushin Volcano region.Another observed N 75°W striking set has been explained as being caused by the late Miocene rotation of the northern part of Unalaska Island.The older rocks of the Makushin Volcano and Unalaska Bay region appear to have been rotated at this time counterclockwise by about 25°,resulting in the prominent N 75°W set of fractures and eventual dikes which originally reflected a N 50°W fracture system.Then,in the Pliocene,additional counterclockwise rotations occurred in the Unalaska community region by about 10°,resulting in the observed N 85°W and N 60°W striking fractures sets.Additional geologic work is underway to prove or disprove this proposed geologic model. Nevertheless,the analysis of the pattern of fracture orientations in the Unalaska Island region has helped to yield insight into the tectonic stress field as well as the rotational stability of the crust in this region.of the Aleutian arc. ACKNOWLEDGMENTS - I thank field assistants Kirk E.Swanson (1980 and 1983),Mark J.Larsen (1981),David B.Edge (1982),and Mark S.Ripley (1983).I also thank all of the Unalaska residents for their generous help,including especially Abi 16 Dickson,Kathy Grimnes,and the Curriers.Special thanks is given to Dr. Ross G.Schaff,State Geologist for Alaska,who made it possible for me to initiate this project.The project was funded by the State of Alaska Power Authority and by the United States Department of Energy,as well as by the State of Alaska Division of Geological and Geophysical Surveys. 17 REFERENCES Anderson,E.M.,1951:The Dynamics of Faulting and Dike Formation with Application to Britain,Oliver and Boyd,London,2nd ed.:206 p. 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Black,R.F.,1976:Geology of Umnak Island eastern Aleutians asrelatedtotheAleuts.Arctic and Alpine Research 8(1):7-35. Bruhn,R.L.,-and Pavlis,T.L.,.1981:Late Ceneozoic deformation in the Matanuska Valley,Alaska:-Three-dimensional strain in a forearc region. Geological Society of America Bulletin 92:282-293. Cameron,C.P.,and Stone,D.B.,1970:Outline geology of the Aleutian Islands with paleomagnetic data from Shemya and Adak Islands. University of Alaska Geophysical Report 213:153 p. Coats,R.R.,1950:Volcanic activity in the Aleutian arc.U.S.-.Geological Survey Bulletin.974-B:35-49.=--- Coats,R.R.,1962:Magma type and crustal structure in the Aleutian.-arc,in MacDonald,G.A.,and Kuno,H.,eds.,The Crust of the Pacific Basin.Geophysical Monograph Number 6:American Geophysical Union, Washington,D.C.:92-109.oo Creager,J.S.,Scholl,D.W.,and Supko,P.R.,1973:Introduction,in Initial Reports of the Deep Sea Drilling Project 19,U.S$.Govt._._ Printing Office,Washington,D.C.,3-16 DeLong,S.E.,Fox,P.J.,and McDowell,F.W.,1978:Subduction of the Kula Ridge at the Aleutian Trench.Geological Society of America Bulletin 89:83-95. 18 Drewes,H.,Fraser,G.D.,Snyder,G.L.,and Barnett,H.F.,Jr.,1961:Geology of Unalaska Island and adjacent insular shelf,Aleutian Islands, Alaska.U.S.Geological Survey Bulletin 1028-S:583-676. Grommé,C.S.,and Hillhouse,J.W.,1981:Paleomagnetic evidence for northward movement of the Chugach terrane,southern and southeastern Alaska.U.S.Geological Survey Circular 823-B$70-72. Hicken,A.,and Irving,E.,1977:Tectonic rotation in Western Canada. Nature 268:219-220. Jacob,K.,and Hamada,K.,1972:The upper mantle beneath the Aleutian Island arc from pure-path Rayleigh-wave dispersion date.Seismological Society of America Bulletin 62:1439-1453. Jacob,K.H.,Nakamura,K.,and Davies,J.N.1977:Trench-volcano gap along the Alaska-Aleutian arc:Facts,and speculation on the role of terrigenous sediments for subduction,in Talwani,M.,and Pitman, W.C.,III,eds.,Island Arcs,Deep Sea Trenches,and Back-arc Basins. Maurice Ewing Series 1:American Geophysical Union,Washington,D.C.: 243-258. Kay,S.M.,Kay,R.W.,and Citron,G.P.,1982:Tectonic controls on tholeiitic and calc-alkaline magmatism in the Aleutian Arc.Journal of Geophysical Research,87(B5):4051-4072. Kodama,K.,Keating,B.H.,and Helsley,C.E.,1983:Paleomagnetism of the Bonin Islands and its tectonic significance.Tectonophysics 95: 25-42.: Lankford,S.M.and Hill,J.M.,1979:Stratigraphy.and depositional .. environment of the Dutch Harbor Member of-the Unalaska Formation,_.Unalaska,Alaska.U.S.Geological Survey Bulletin 1457-B:B1-B14. Lattman,L.H.,and Segovia,A.V.,1961:Analysis of fracture trace pattern of Adak and Kagalaska Islands,Alaska.American Association of Petroleum Geologists Bulletin 45(2): 249-263. Lensen,G.J.,and Otway,P.M.,1971:Earthshift and post-earthshiftdeformationassociatedwiththeMay1968Inangahuaearthquake,-New --.Zealand.Royal Society of New Zealand Bulletin 9:107-116. Marlow,M.S.,Scholl,D.W.,Buffington,£.C.,and Alpha,Tau Rho,1973: Tectonic history of the central Aleutian-arc.Geological Society of America Bulletin 84:-1555-1574. Minster,J.B.,Jordan,T.H.,Molnar,P.,and Haines,E.,1974: Numerical modeling of instantaneous plate tectonics.Geophysical -Journal of the Royal Astronomical Society 36:541-576.=| Nakamura,.K.,Jacob,K.H.,and Davies,J.N.,1977:Volcanoes-as -..--possible indicators of tectonic stress orientation -Aleutians and Alaska.Pageoph 115:87-112. 19 Nakamura,K.,Plafker,G.,Jacob,K.H.,and Davies,J.N.,1980:A tectonic trajectory map of Alaska.using information from volcanoes and faults.Bulletin of the Earthquake Research Institute 55:87-112. Odé,H.,1967:Mechanical analysis of the dike pattern of the Spanish Peaks area,Colorado.Geological Society of America Bulletin 68: 567-576. Perfit,M.R.,1977:The Petrochemistry of Igneous Rocks from the Cazman Trench and the Captains Bay Pluton,Unalaska Island -Their Relation to Tectonic Processes:Columbia University Ph.D.dissertation, New York 375 p. Perfit,M.R.,and Lawrence,J.R.,1979:Oxygen isotopic evidence for meteoric water interaction with the Captains Bay pluton,Aleutian Islands.Earth and Planetary Science Letters 45:16-22. Perfit,M.R.,Brueckner,H.,Lawrence,J.R.,and Kay,R.W.,1980:Trace element and isotopic variations in a zoned pluton and associated rocks, Unalaska Island,Alaska:A model for fractionation in the Aleutian calc-alkaline suite.Contrib.Min.Pet.73:69-87. Plumley,P.W.,Coe,R.S.,and Byrne,T.,1983:Paleomagnetism of the Paleocene Ghost Rock Formation,Prince William terrane,Alaska. Tectonics 2(3):295-314. Reches,Z.,1983:Faulting of rocks in three-dimensional strain fields, II.theoretical analysis.Tectonophysics 95:133-156. Reeder,J.W.,Motyka,R.J.and Wiltse,M.A.,1980:The State of Alaskageothermal-program.--Geothermal-Resource Council Transactions.4:....... 823-826. Reeder,J.W.,1981:Vapor-dominated hydrothermal manifestations on Unalaska Island,and their geologic and tectonic setting.1981 IAVCEI Symposium -Arc volcanism:Volcanological Society of Japan and theInternationalAssociationof.Volcanology and Chemistryof the Earth'sInterior:297-298.. Reeder,J.W.,1983:Preliminary dating of the caldera forming Holocene-volcanic events for the eastern Aleutian Islands.:The Geological = Society of America,Abstracts with Programs 15(6):668. Reeder,J.W.,Swanson,K.E.,Larsen,M.J.,and Edge,D.B.,1984(a):|Geologic bedrock observation and map of the Makushin Volcano and Dutch Harbor Region,Unalaska Island,Alaska.Alaska Division of Geological and Geophysical Surveys Report of Investigations:in Press.-Z Reeder,J.W.,Swanson,K.E.,and Larsen,.M.J.,1984(b):Unconsolidated deposits and geologically recent volcanic rocks and faults of the.Makushin Yolcano and Dutch Harbor region,Unalaska Island,-Alaska.- .--Alaska Division of Geological and Geophysical Surveys Report of Investigations:in Press. 20 Reeder,J.W.,Ripley,M.S.,Larsen,M.J.,and Swanson,K.E.,1984(c): Photogeologic linear features map of the Makushin Volcano and DutchHarborregion,Unalaska Island,Alaska.Alaska Division of Geological and Geophysical Surveys Report of Investigations:in Press. Scholl,D.W.,Marlow M.S.,and Buffington,E.C.,1975:Summit basins of Aleutian Ridge,North Pacific.The American Association of Petroleum Geologist Bulletin 59(5):799-816 Simkin,T,Siebert,L.,McClelland,L.,Bridge,D.,Newhall,C.,and Latter,J.H.,1981:Volcanoes of the World,A Regional Directory, Gazetteer,and Chronology of Volcanism during the Last 10,000 Years: Washington D.C.,Smithsonian Institute,232 p. Swanson,H.,1982:The Unknown Islands.Cuttlefish VI:Unalaska City School District,204 p. 21 FIGURES Figure 1. Figure 2. Figure 3. Figure 4. Figure 5. Simplified geologic map of the northern part of Unalaska Island,after Drewes et al.(1961)and Reeder et al.(1984a). Equal-area lower hemisphere projections of poles to 100 dike surfaces in the Makushin Volcano and Unalaska Bay region of Unalaska Island.Diagram contoured in %as indicated per 1% area. Equal-area,lower hemisphere projections of poles to 44 fault surfaces in the Makushin Volcano and Unalaska Bay region of Unalaska Island.Diagram contoured in %as indicated per 1% area. Equal-area,lower hemisphere projections of poles to 63 joint surfaces in the Makushin Volcano and Unalaska Bay region of Unalaska Island.Diagram contoured in %as indicated per 1% area. Rose diagram showing the cumulative lengths of lineaments-..at 5°intervals for (a)section A,(b)section B,(c)section C,and (d)Table Top Mountain region (i.e.,the region within a 4kmradiusofTableTopMountainofsectionE)of Figure 1. 22 ,aunbryFig wee { 4 Map Symbols Fault:dashed where approximate Fumarole field Warm.and/or hot springs aRecentvolcanicvent[xrieCaldera.Map location (Northern part ofUnalteredvolcanicrocksUnalaskalatand) Plutonic rocks Unalaska Formation wemcomem Regions referred to in text Figure / zaunbe4Figure 2 i CJ OM B&B B Ci 0-1%1-2%2-4%a-6%68%8-t0%10-12%12-44%14-16%>16% Figare a €aunblyFigure 3 1-3%im ie 3-6%6-A%810%>10% Figure 3 yaunbi40AsDhya=rtMfiFigure ¥Figuce 7 G aunbL4 (9) J (8) (P) (9) wy Ot wy€ we wr gt wy at