Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
Reconnissance Study of Energy Requirements Appenidx Unalaska 1984 Draft
ALASKA DIVISION OF GEOLOGICAL & GEOPHYSICAL SURVEYS REPORT OF INVESTIGATIONS 84- WELL D1 METERSFEET COMMENTS%OF MODE("¢}TEMPERATUREVEINS/FRACTURES Y PER 10FT3€ GRAPHIC LITHOLO 464 PPP PPP PPP APDPwwwwwslatinitil 150100 an bay) HOO 1800 coy 1700-4 ABD 1500 AAD 1400 -- AON ag) 1300 WELL ST 1WELLE1 454°GO wv°”woT 2 { CHLORITE-ACTINOLITE OO> S4e4* of &>a5 % al =) cegEge & 28 é » F- etLe.l. - ¢-ZEEESS - » a 2taieeg? §$ EPIDOTE ske ES 2st w 5 <tin'a 2 5 =cc 2-2 ELE 2 ¥ ? =Ly = . Ts oO 2 q 7 ar 2 = 2 > (ép) i we a { a =. t > ) st OL q * -J Soe ot < » PYRITE fans = 2 Lu<< tL 73¢3 ™ aD § a ne bay oe ) SiPE:s 9 MaGneTITE Seegeig 2{ WAIRAKITE S 5 } 1 S ° - _ LAUMONTITE rs3 r > - "” 7” } MORDENITE z ILLITE O m - &---- MONTMORILLONITE < t 1 5 cc 8 < _ -ee RK: sos2 CHLORITE-ACTINOLITE LW y g F- 0 # ( - e:. - >; EPIDOTE < » -<- PYRITE = 4 w g ANHYDRITE > 4 > --- -ome CALCITE q > - }QUARTZ> ' 2z»woqwie @ epe-ss aha wgGOofat.5aWas: . . __ _ .. _ . owns L 11i! 1 |! ! i | | 1 ii L i Li L\j i | ! Le I I A caeeede 4. be t ben ed whe } ive]be2Lu==i?)ia) Fio a an ee F=En ae L_ 2 CHLORITE-ACTINOLITE wi _ ) oba 2 sf 5 E @ EPIDOTE wh9 2 x » - ) 14 ? a [(- PYRITE L Ln. |ari nycan ' - , MAGNETITE 4» - 9 walnakite ' } LAUMONTITE ( »? MORDENITE ) . )2 ILLITE 22 MONTMORILLONITE q ) _ CHLORITE-ACTINOLITE $ - - - EPIDOTE $ - PYRITE $ -- om om - - --9 ANHYDRITE ” § c mn 5 awe ee ee - - - ° _ - @ CALCITE 2 ) 5 ; t ' seme -_--- _ _ - _ - - ---2 Quaniz ran . ) =o-- 20aaa S46Us >a §sf > 6 C) rx) 0) ee e e Zo 0) _ wae ee SwArasocORC +++Ft t+ott+t+Ftt+Fttwitte+++F+FFF Se i a i aa is + ++++++ to Fe eR HH tH ++tfoF+F+&2|O zo ey q Dore Ft+ ++ +vph ht ytata tate tet tft ++ £04 At++++&Ft+ HF HF t++F H+ +++t+ ++ aaa a i eo ++++F++F+++2no LO MOI2TSL'0E +t+++ ++btAtp tweet +yt tat yth++ +44 Vt A + ++++++ aa ee ee i ee ee ++++ + +++Q4 xi yo moQwe? OFwat++ ++FVtewty teesth We Ft+ tt +447:Oe eeee ++++++ a a a aa ee eo $+ +++ $$ +++++-2 ce wise O®eoon ++++ Peeeeeee eS etee ee eeee a eeeeee + ++++++ a ++++++++D 4 | T | ] T | T | T ] T t T T | | T i : t ] T T r | t e o 2 2 =) ° 2 ° fo) =) ° 25.3 S 83 $s3= 8 3 88S8 = 3 S S 5 = i I ! i 3 1 ne oe 4 i r it 4 fi fj 1 - Le 1 1 L i 1 i waa { ' . L 1, L 4 at 1 4 L ) 1 t 1 b ml L. |. 4| pa [ | T T 1 | | + r T | T i 7 } | 1 t 4 Qo Lon) Q a Q Qo Q fon] Oo Qo Oo fan) Lo Oo oO OQ Q Qa fen] QoQ Oo a Oo oO Qo Qo oO Oo a Q Qa oO oS Da Co o ™N - fon] co ™ oO wy ws fos) N - N im vt wm Oo <° i J I j i 1 i i it L 1 i i L it 1 i 1 i a 4 1 i it i i eeaa e <t 5 Y us ” 2 a g LsPRLY2iw ?7a<> ' < > : y : Y L- be L10 Lf CHLOKITE AG TINOLITE 0 n Ww ( OQ ar { SE <l Cc[ * isvt sr4 5 EPIDOT: foe i ae2 Q =o SE I o_O eONF /\ mr L } aa wn L4 PYRITE hd L2 > QO (a) L ALe Fou _ ae <3 za ;MAGNE FILE < 4qQ WAIRAKITE, -_! , Y ;§ LAUMONTITE - ; k 200 § MORDENITE .za < c ; = < r 2ILLE ke - op) a <x Ok 150 § MONTMOILLONITE cr < ad > q ag -<& 1% PYRITE F | Db ( -I iol <t IT oo =--___o--- = - - tet attrition § CHLORITE-ACTINOLITE Z mRral ? Zz cece nee cc co ore meena swe ee . oeeeeS EPIDOTE = i 4 Lu -_ eh ; 2 > eee -_-__- ANHYDRITE ” wn 5 < tc on ltelialeatatatetateteteretetetal eledaletiatetetatiematetetetel a - ----- {? CALCITE ia yo Llj =) 5 i ( z - i | | - 11g ouarT? 'am or ) < uewer2e , Zar c2 Gu10 2Le | ve e. o00 ee O) e e¢6 e a < Om + 7iia i iiaiaiia aa + ++++++ ++++LY ré gto o+ ++Wat a aa ee a 2 ++e++ +++2Om ao 4 + +tA+++++++++++++++++++ + ++++++ ++++2 > LO . Sa +++++ bob +2 oh A 4 P++ ¢¥eg+ ++++ tot +++++++ + ++++++ +++4) x c T a J ' | | | | | ] ' | ' q | | a UI =)Tt 7 . . I>G i wed ee. 1 een L l 1 i i i R L i r _ L --L i i = mate ee) - - : rea} omoO porn tee ) a r | O° ( . ) s § ||| d »>3 O Q n Pa F § ww 2 za = oa 2 LL O 55; Y) 5$ - 5; < 55 <f 55 = § _ oO - § CHLORITE-ACTINOLITE WZ |I] a f 5 roS -L af $ Z< -- r+ ) EPIDOTE sa ub 2 ujUW OL | /J-- ) oh x , na _> L ra [4 q PYRITE O re r=F JN ee q 4 3 MAGNETITE Li >4 Lu 4 WAIRAKITE ||j ( = 3 Cc 4; LAUMONTITE z O | ¢ MORDENITE O f-200 4 -_ () ; | ?ILLITE aS : 5 rr LL r D>-- - e e -- e- - - = - - - - - - MONTMORILLONITE F O F 150 ) zx I sass - oe meee eee ec ceees : wee ---_ 2 CHLORITE ACTINOLITE al *-_ oe e za St nT ee eee ee Bee ee ee ee - eee ») PYRITE Er -__-_ - as ' - - _ ae _ +9 > O wr 700 2 uw ) 4 wees meee a me eee ee ! ai CS eee -- -- - -_--_ + EPIDOTE _/ tuaa - oe eee eee = wT -3ANHY DRITE w f oO _- }CALCIT 7 Ok wm gy a an Lé faT ed fe peepee Jeee- res we eeegeeee te eee =->- i s-----_---- ae -_ " ; 2 q Gr a - ° | |; QUARTZ radars 5 Ae er $z z ee ye -£F 10 wc eet [™ 2 Om Dt ° DrAtT +* aia:+FFtA++++*F2+++++++++++++ Fs a 2*. $ta Ft t+++-:26 iS +4 aA 'Hatat +++oe+++o++ ¢Q4+ ++++b +++++++++ +++++ +*Sat+ + Tey as a7 ve 4 FGtAt+ ++++++ Hye ++tA+t++++Y+++&+FF++ + t++fF+++ +48 ++ + ae a to a AS +D+D+ ++++&++rr +Q> Ft++49 de4+++F++F ++t++++ +est+ + vot wate che + vv O04 +¢++++++ £4 +++++++++4++ut ut Ut Ut Ut.; ++is+++ + +V¥4 4s : + ; = T i T T J T | T T , ad | t if DISSEMINATED ALTERATION VEIN ALTERATION REPORT OF INVESTIGATIONS 84-3ALASKADIVISIONOFGEOLOGICAL& PLATE 2 OF 2GEOPHYSICALSURVEYS A'A 3000'-3000' 2000"Makushin Valley}°° 1000 +1000' ;Qal Sea Level Tg -Sea Level Pakushin Cone |B' Nateekin 4000" Glacier Valley QTve QT ve QTve QTve Valley! en ae ;; -3000'aa Tu NL Tg QTve Projection of thermal gradient hole |-1aS_=<)Ho ;T 'es oal Qal Tuh 4 :Tuh ;Tuh »fn -1000' Tuf .Tg Sea Level \Tg L_Sea Level é C C' 4000'4000 00+, . shi +300030GlacierValleyMakushinValleyotve 00014 Projection of thermal gradient hole I-1 Qe Projection of thermal gradient hole E-1 Sugarloaf :QTve Qal Qal _L£f Qal'--a. 10005 va 4 w Tuh \<___Qvp >.wil Qhvf oal Le run SS Qhvf Qhvp Tuf ik |'¢Tg Tg Tuh Tuh Sea Level _Tuf ll Tuf Tg ../Tg ie Tuh GEOLOGIC CROSS SECTIONS OF THE MAKUSHIN GEOTHERMAL AREA,UNALASKA ISLAND,ALASKA -88,97,9]INTRODUCTION:- A process has been developed using a spreadsheet programKnownasLotus1-2-3 which allows one to analyze the current operating practaces'of the City of Unalaska's Electric Utility.Themodeldevelopedinthisstudyaliowsonetoprojectfutureoperatingcostsunderdifferentscenarios.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.° FT TABLE 3 Gr'"ATING EXPENSE ACCOUNT ASSUY°TIGNS d The upper table tdentifies the inflation ruvws used to trend upthepreviousyearsoperatingexpensesonTable6.The percentincreasesfortheyears1993,1998,and 2003 represent the compounded percent increase over the S-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 costof$1.20/qal.The total fuel expense is computed using an assumedefficiencyfactorof10KWH/Gal in 1984,and 14 KWH/Gal in 1988,withthefactorbeinginterpolatedfortheyearsinbetween. The lower table identifies any large dollar additions tatheseoperatingexpenseaccountsbeyondtheannuaiinflationfactor. TABLE 2A LANT 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 duetoKnowniargedollaradditions The fourth section contains the total account balances as of the year end.The account balance includes the previous year's balanceplusplantadditionsfromboththeinflateddollarsfromsectiontwo and the large dollar additions from section three. fon ieaineadinattanTABLE£5 ANOS 20 PLANT ADDITIONS AND OEFRECIATICN EXPENSE These tables t 7k the account balances f:each to the plantaccountsfromyeartoyear.For each category of plant ,thefollowinginformationi8accumulated: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 numbersinputinthispartoftheschedule.,The depreciation expense is computed based on the plant balances,and the designated useful life as input.A half years depreciationistakenonbothplantadditionsandretirements. TmiS Lacie comontes the projected total n-"ver of customers foreachrateclass,sed on several different zumptions.The first seci n identifies the projyecte.annual percentincreaseofcustomersintheGS-1,and GS-2 rate classea.The projected rate ia 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 S PROJECT KILOWATT HOUR SALES This table computes the projected KWH sales wy 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 areinterpolated.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 larag@ 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 classes GS-1,GS-2,largepower,and streetlights are computed from the projected totalconsumers(from tabie 3)for these rate classes,and their respectivemonthiyKWHusagesfromsectiononeonthistable:annual KWH sales =(number of customers)X (monthiy KWH used per consumer?X (12 months). System Line losses(as a percent?are input for i983 and i983,andinterpolatedfortheiterveninqgyearsaswasdoneinsectiononeabove.The system loss in KWH is added to the projected annual KWHsalestogetthetotalKWHrequiredbythesystem.Both components ofKWHpurchased,purchased power and co-generation,are input numbers.The totai KWH purchased is subtracted from the total annual KWH required by the system to compute the KWH required to be oroduced by the City of Unalaska. TABLE SB SYSTEM LOAD FACTORS This table 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 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 ludcgement of the rate desiqnerinvolvedwiththisstudy.As the system matures moré 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 proyected coincidental peak demand.When thisexcessdemandbecomesnegative,the system should concider adding another generation unit. TABLE 6 OPERATI REVENUE This table adjusts the operating expenses during the test year,February 1983 to January 1984,for known changes in operations,well as for the projected changes per table i.The rate base computation ia 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 to charges,pole rentals,ete to arrive at a Revenue Requirement fromElectricEnergy. DRAFT TABLE 7 SUMMARIZC™T™DATA FOR RATE DESIGN SCHF™MLES 'Tables 7 thru 10 cons__-ute a system whereby all --sts 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. VVALROAH CLWET DIDI ET REVENUE QE9CTIENEN7 PROCESTIONS TOBE 1 EXSENSE ASSUMOTIONS er)i364 Lae {S66 (387 '3t8 {553 {$35 2202 VETHCD, EXPENSSS-ANNLGL INFLATTON QaT=5 BY Sm rn men nm me ne mn mene ne ee me - ADMIN &GENERAL-SOLARIES ae 3 3 3 3 3 5.93 15,93 £93 2 ¥/PERTOD PARTS-WAGES He 3 3 3 3 3 15.53 1.93 15.93 3 X/PERTOD CUSTOMER ACCSUNTS-BAD DEBTS i nA NA Na NO xe Ne Na KA Kp CUSTOMER ACCOUNTS-METE9 QEADING :3 3 3 2 3 13,93 15,93 15,93 3 X/PERTOD DISTRIBUTION-wASES int 3 3 3 3 3 15,23 15.33 15,93 3 X/PERIOD DISTRIBUTION-TOOLS &MATERZALS :5 5 5 5 =27.63 27.63 27,63 5 ¥/PER1D ENGINEERING EGUIT-WOGES °int 3 3 3 2 z 15.93 15.93 15.93 3 X/ERIOD ENGINEERING EQUIP-DIESEL FUEL &PARTS ni 5 5 5 5 5 27.63 27.63 27.63 5 x/PERIOD BENERAT ILON-WAGES a 3 3 3 3 3 15.93 15.93 15.92 3 X/PERTOD GENERATION-CTHER SUPPLIES tt 5 5 5 5 5 27.63 27.63 27.63 5 x/PERIS GENERATICN-UTILITIES &CONTR,SERV,nu 7 7 7 7 7 6,26 62,26 43.26 7 Y/PERLOD GENERATION-MATERIALS Ht 5 5 =5 5 27,63 27.63 27.63 5 x/PERTOD GENERATION-LEASED EQUIO,tht 2 a 2 2 e &.ee 0.@2 a,22 @ X/PERIOD GENERATION-AUTO FARTS,GAS &WAGES nn 4 4 a 4 4 21,67 21.67 21.67 4 X/PERIOD HEAT RECOVERY int 3 2 3 3 3 15,93 15,93 15.33 3 X/PERIOD FUEL COSTS-$/GAL ii 3 3 3 3 3 15.33 15.93 15.33 3 X/PERIOD PURCHASED POWER 2 z 2 z 2 2.21 2.44 2.63 2 Y/PERIOD TNSURANCE tu 4 a 4 é 4 £1.67 e1,67 21,67 4 X/PERIOD KEREREEER EERE RENEE EE EERIE ER EERE RE RE HERRERERE REE ER EREREREREEREE EEE EE EREREEE SE EH ERE EEE ERE EEE EERE ERE REFERER EERE REDE EE EERE SER EAEEE DEERE REFEREE EHERE ERE EERE EEE LER ERE EERE RERE EERE EERE EEEREREEREEFRERERRERERSEEREEE ES REE REAEEE EGE 1983 1384 1385 1385 1987 1988 1993 1998 2003 EXPENSES-DIRECT DOLLAR ADDITIONS i ADMIN &GENERAL-SALARIES int @ 35,¢2 2 @ 2 2 2 @ PARTS-WAGES bn @ Q 2 2 a a z Q CUSTOMER ACCOUNTS-BAD DERTS Q @ t 2 2 Q 2 2 CUSTOMER ACCOUNTS-METER READING 2 «6,Bae @ a z 8 2 a DISTRIBUTION-WAGES rh a @ e e @ Q @ a DISTRIBUTION-TOOLS &MATERIALS it @ @ a a a @ @ 2 ENGINEERING EQUIP-WAGES tnt @ ')@ @ @ 2 z Q ENGINEERING EQUIP-DIESZL FUEL &PARTS tnt a a @ @ @ @ ¢@ GENERATION-WAGES ttt 32.020 38.220 e 2 2 @ ¢2 GENERATION-OTHER SUCPLIES th:a a ")3 @ Q @ @ GENERATION-UTILITIES &CONTR,SERV,tts 2 2 )a @ @ 2 a GENERATION-MATERZALS int a a @ a a a @ a GENERATION-LEASED EQuID.rn 2 2 @ 2 2 )a z GENERATION-AUTG PARTS.SAS &WAGES re a a @ @ @ 2 Q a HEAT RECOVERY ©rt 2 £2,820 @ 2 a z 2 z PURCHASED ROWER CENTS /KWH rh 12.88 ree 14,2@ 15,@2 15,#2 16,22 16,ta 16.de INSURANCE th e e @ a @ a e e FUEL COSTS-$/S0L i 1.c2 tem 1.27 1.31 1.35 1.33 1.61 1.87 2.17 12,5 he 11.5 12.8 12,2 12.2 £2,@ INTERPOLOTED 1984-88FUELEFFICTENCY-KWH PRODUCED /GAL Hee 1&2 @¢ PLANT ACCOUNTS-TRENDED GENERATION HERT RECOVERY DISTRIBUTION LINES TRANSFORMERS METERS GENERAL PLANT STREETLIGHTS TRENDED $ADDITIONS GENERATION HEAT RECOVERY DISTRIBUTION bb TRANSFORMERS METERS GENERAL PLANT STREETLIGHTS PLANT ACCOUNT LARGE DOLLAR ADDITIONS BeNERAT ION HEAT RECOVERY DISTRIBUTION LINES GENERAL PLANT STREETLIGHTS PLANT ACCOUNTS: GENERATION HEAT RECOVERY DISTRIBUTION LINES TRANSFORMERS METERS GENERAL PLANT STREETLIGHTS ACCUMULATED DEPRECIATION NET PLANT 375,5¢9 44,174 441,532 38,046 Q @ Q 899,268 UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE 2A PLANT ACCOUKT ASSUMPTIONS (51,358) 1383 1984 1985 1986 1987 1988 1933 1398 2003 METHOD, i t i {1 i a 18 5,1¢5.Le { é ra é é é €2.43 $a,41 18,41 é H 1 I {t i 5.12 3.18 5.18 1 @ 16 6 {7 4 4 /ie 43 14 PERCENT INCREASE IN NON-CO DEMAND PEAK a 3e 19 2 ig 14 ie¢il t2 PERCENT INCREASE KWH SALES 4 4 4 4 4 4 21,67 21.67 e1.67 4 4 4 4 4 4 4 ei.67 21,67 21.67 4 @ 3,705 3,733 3.831 3.869 3,948 c@,Loe 21,159 22,238 ge 883 1,421 1,429 1.458 1,487 7,893 B,714 3,bet @ 15,3¢@4 33,977 73,341 74,Jae ABS 465,747 a72.162 698,665 @ 1,714 1.578 i,656 1,65.i,747 1@.664 13,273 16,476 @ 138 Th Laz 152 $45 136 £14 96 @ 7 2,a2 2,268 2,163 4,258 23,939 29,125 35,435 @ eee ete 216 retake)a34 1,318 1,623 1,351 @ @ a @ a 2 @ a 3 @ 25,e¢a @ a id a a Q ') @ 588.22D 1,228,BBA @ @ e °y a Q @ 5a,AO Q St,228 @ 2 Q @ @ @ Q @ ge 2 id a @ 375,589 379,254 383,856 396,887 SW,756 394,£63 414,795 435,954 458,192 44,174 72,007 9 71,459 72,888 74,345 73,832 83,725 Je,439 1@2,868 332,182 985,486 1,939,463 92,014,803 92,089,745 2,172,ch0 962,636,007 3,288,169 3,906,834 38,046 39,762 41,338 43,166 44,839 46,626 57,298 7@,663 87,339 46,25 46,546 46,719 45,639 47,049 47,195 47,331 47,446 47,541 @ SAA 52,BAU 54,082 186,243 118,493 134,432 163,557 198,992 5,B08 3,20d 5,48 3,£24 5,649 6,033 7,40!9,885 18,956 B99,268 1,496,315 2,523,434 2,624,366 2,758,827 2,851,153 3,380,981 4,027,232 4,811,913 57,726 «6134856 9257,738 409,344 576,747 742,286 932,259 1,157,@@5 1.423,972 841,534 1,361,459 GcB1.724 9 e,c15,@c4 =188,08 |2.108.867 «448,Tee |2,B78,e27 §8=-3,387,942 UNRLASKA COWER SYSTEM REVENLE REQUIREMENT PROJECTIONS DEPRECIATION EXPENSE COMPUTATION TABLE 2B DEPRECIATION EXPENSE COMOUTATION USEFUL LIFE 1383 3984 1985 1986 1987 2988 1993 1998 ere? GENERETION PLENT -- B.S.¥.PLANT BALANCE 375,09 =S75.589 379,c64 28a,057 386,387 SH,706 334,664 414,796 435,934 ADDITIONS a 3,755 3,793 3.831 3,863 3,988 2@,132 21,159 22,238 RETIREMENTS g Q @ g @ @ 3 @ Q E.9.Y.PLANT BRLANCE 375,589 379,c64 383,057 386,887 398,756 334,G64 414,736 435,954 438,192 DEPRECIATION EXPENSE 15 YEARS B.0.Y.BALANCE 25,024 25,034 5,294 e0,507 5,792 26,Poe 26,311 é7,693 29,G64 ADDITIONS a 25 126 128 ie3 139 é7i 705 TAL RETIREMENTS g z @ @ t a a @ e Eo.Y.c5,034 5,159 coat 25,G65 ao,921 26,13!c6,992 £8,358 23,BGS HEAT RECOVERY PLANT B.0.¥.PLANT BALANCE 44,174 48,574 73,257 74,459 72,888 74,346 73,432 83,725 32,439 ASOITIONS B 5,683 42h 1.429 1,458 1,487 7,893 6,714 9,621 RETTREMENTS Pg t Q e 2 @ @ a e E.0.Y.PLANT BALANCE 44174 78,257 71,459 72,688 Ta,S46 73,832 83,7¢5 92,439 122,B5e DEPRECIATION EXPENSE B.O.Y.BALANCE 12 YEARS 4,437 4,417 7,86 7,146 7,€89 7,435 7,583 8,373 9,244 ADDITIONS e 1,294 78 71 73 74 395 436 461 RETIREMENTS e ¢ry @ @ @ @ a @ -.0.¥.BALANCE 4,417 3,712 7,076 7,217 7,362 7,589 7,978 8,828 9,725 DISTRIBUTION PLANT B,O.Y.PLANT BALANCE 392,322 392.332 «95,636 «=,939,613 92 14,954 892,089,895 oc,172,418 CL 636,857 |3ct8,old OCOITIONS @ 515,524 1.833.977 75,341 74,342 62.5.5 465,747 oie.18 638,665 RET ITEMENTS z a e Q @ a rg @ é &O.Y.PLANT ZaLANCE 39,332 905,686 1,999,522 2,004,958 2c,C8 AIT L7241@ ©-£,636,157 3,288,519 3,926,984 DEPRECIATION EXPENSE B.0,Y.BALGNE ad YiRa5 19.527 {Rel?4S cae 96.981 123,748 i@4,455 i238,Gc 132,Bed 162,816 RDOITIONS 2 ic-€6$0 -c5,049 1,864 ie Br4 e014 31.664 $4,od4 $7,467 RETIREMENTS PY 2 rg @ 6 é a g a E.0.¥.BALANCE 19,517 932,599 7t,it 98,854 22,621 126,528 128,154 146,1i2 177,883 TRENSECAMER SLANT 8B.a.Ye Pa ANT BALANCE 20,065 28,045 34,758 412d 43,135 44,G48 46,626 27,3?72,663 QDDITICNS Q 1,714 1,578 1,856 i,653 i,787 18,664 13,373 16,676 aot et lero TABLE2C0°REVE USEFUL LIFE METERS B.G.¥,"ANT BOL_ANCE ADDITIONS RETIREMENTS £.0.¥.PLANT BOLANCE DEPRECTOTION EXPENSE B.0.Y.BALANCE ADDITIONS RETIREMENTS GENERAL PLANT EONS RETIREMENTS Zz.0.Ye -ANT BALANCE DEPRECIATION EXPENSE BE.0.¥.BALANCE ADDITIONS RETLREMENTS £.0.¥.BOLANCE STREET LIGHTS RET TREMENTS Y,PLAN?BALANCE DEPRECIOTION EXPENSE B.0.¥.SA8NCE ADDIF TONS RETLREMENTS .BALANCE TOTG.BLAST BOLANCES BG,¥.PLANT BALANCE PODITIONS RETIREMENTS SG.¥.FANT BALANCE TOTAL DEPRECIATION EXPENSE B,0.Y.BALANCE ADDITIONS RETIREMENTS fo BA_SNCE {@ YEORS 3 YEARS 43 VENSS /NELRGKO POWER SVSTEN &REQUIREMENT OROSECTIONS SIATION EXPENSE COMPUTATION (CONT INLED) 1383 1984 4385 1986 1987 1999 1993 1998 EZ 46,ct@ 4B,C82 48,258 45,569 45,749 46,939 £7,045 47,al 47,8 a {98 s71 18%He 146 136 14°%6 Qe @ a @ @ 2 C4 a a 46,222 45,298 =46,569 46,749 46,899 47,245 47,181 47.2%47,391 4.622 4,620 4,640 4,657 4.675 4,670 4,785 4,788 4,738 a it 3 3 §7 7 6 a @ z a Q e @ a e a 4.628 4.622 4,£48 4.097 47 4,7e6 4,734 @ z 92,€28 52,02 24,082 $05,643 112,493 134,432 163,587 Bo Ta eee c.2ed 2,082 oe.162 4,258 23,939 29,125 35,425 e Q 2 e 2 @ e @ @ 2 Fe,82d 52,2O 54,PS £05,043 112.433 $34,432 182,557 198,332 a @ 18,222 12,42a £2,8:6 e.,249 EF,099 26,ABG 32,711 e 5.022 2ea ees 3,216 825 2,394 2.42 3,543 t e @ e fy a @ z a @ 5.288 18,288 18,688 15,022 21,674 24,432 c9,799 36,255 5.82 5,222 51228 5,488 8.22 ©.843 6,882 7,42)3.G2 z e22 228 216 ce e534 1,318 1,683 a.35h @ a a 8 a @ ?Q 5.32a 5.222 5,6@8 5,624 3.849 5,933 7,401 9,225 18.956 BN 333 wT ce.375 Th 45 433 622 a 7 7 ?7 8 44 53 65 a fg é cd g@ 2 e a z68 222 738 463 547 $65 633.261 BIR C61 1.496.915 6.559435 2.624.959.73GB 851,154 3,588.982 4,827,233 @ 597.055 1,043,129 84,933 554,462 32,326 529,828 646,25!784,681 2 gt eg a a @ a (J a E.651,1846 3.300382 4,027,233 4,BEL,914 57,726 =87,726 =98,534 243,214 54,013 166.732 $74,266 205,668 243,831 @ 13,484 26.342 2,482 7,383 2,747 15,687 19,065 23,136 Q 8 Q Q @ 2 @ a @ 7,726 T7230 lee,874 Thi bi4 151,4a 271,239 189,973 c24,745 266,967 a+ UNALASHA POWER SYSTEM REVENUE REQUIREMENT PROJECTIGNS TABLE 3 PROJECTED CUSTOMER NUMBERS #OF CUSTOMERS-TRENDED (%INCREASE) 55 1 65-2 Le INTERRUP TABLE HEAT RECOVERY STREETLIGHTS #GF CUSTOMERS-NUMBER GF ADDITIONAL CUSTOMERS (FROM %INCREASE) GS-1 65-2 LP INTERRUPTABLE HEAT RECOVERY STREETLIGHTS TOTAL NUMBER OF ADDITIONAL CUSTOMERS (LARGE ADDITIONS) 65-1 GS-2 Lp INTERRUPTABLE HEAT RECOVERY STREETLIGHTS TOTAL TOTAL CUSTOMERS GS-1 65-2 LP INTERRUPTABLE HEAT RECOVERY STREETLIGHTS TOTAL 1983 1984 1985 1985 1987 &4 &&& 3 3 g x)3 N/A N/A N/A N/B N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/R N/A N/Q N/A N/A N/A N/A N/B N/A N/A {1 le fe ie N/A i 4 1 i N/A N/A N/A N/R N/A N/G N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/B N/A N/A N/A K/A N/A N/A N/A ie 12 43 13 N/A @ @ 4 a N/A a a a @ a 2 {{a a g |i i N/A @ @ a Q N/A Q a 8 a N/A @ a @ @ 277 288 380 3te 324 27 26 2 38 31 3 5 6 7 7 Q g {é 3 !i i i i i i i i { 3e9 323 338 333 367 14 Qaeoa-9s8vate cl.67 15.93 N/A N/A N/A N/A N/A N/A N/A N/A 73 Ss8FOO9&412 N/A N/R N/A N/A 95 aeooes8&499 2SGeeoe@&607 673 wt ars 4 ¥/SERTCD 3 ¥/PERIOD ev -mee& ADDITNL LARGE POWER CONSUMERS (FLRM)Ki/MONTH UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE 4 PROJECTED KWH SALES CONSUMER Kw USAGES*ONTK ADDITIONAL INTERRUPTABLE LOADS (ANNUAL KWH)4é:KWH SALES GS-1 65-2 Le HEAT RECOVERY STREETLIGHTS A B Cc D TOTAL NEW LARGE CFOWER KWH/MONTH A B C D TOTAL INTERRURTABLE Kwik 65-1 65-2 LP INTERRUPT. HEAT RECOVERY STREETLIGHTS KWH-TOTAL SALES SYSTEM LOSS (x) SYSTEM LOSS (KWH) KWH REQUIRED BY SYSTEM KWH PURCHASED PURCHASED POWER CO-GENERATION TOTAL KWH PURCHASED KWH PRODUCED 1983:1984 £998 1986 $367 1988 1793 1998 2Re3 442 48¢454 wth ced cud ood Niet Sud INTERPOLATED 1984-88 1,124 1,383 i.662 1,942 e.c¢i 2,582 2,500 2,ote 2,080 INTERPOLATED 1984-88 14,821 15,617 16,713 17,808 18.92 ct,eed e@,220 EB,282 2%,220 INTERPOLATED 1984-88 @ 4 a a a J 2 @ @ INTERPOLATED 1984-88 2,5ta 2,7k?z,92 3.1a 3,2a 3,500 3,522 3,50@ 3,50@ INTERPOLATED 1984-88 eR.O2 he,SAN eS,eee 27,See 3,Cee 30,A22 38,G22 30,28 2A,080 22,25,C82 27,500 20,COE 38,222 38,G22 38,220 12,0¢2 13.333 16.667 20,022 28,C28 20,820 2,028 ot,200 55,022 62,222 £2,280 62,228 62,02a @ 40,02@ 55,222 113,333 126.667 142,O28 140,202 142,228 142,O@e 102,220 116,667 133,333 158,@e@ 158,24a 158,086 152,2008 182,220 125,@22 152,Q0@ 15@,ee 158,G02 158,88 184,@2@ 138,020 15,228 150,G22 158,G2 £58,O@@ 150,20 152,@¢158,GQ a @ 122,Ae 216,667 358,333 688,G22 628,Bee 629,C22 622,082 1.452,568 1,596,672 1,742,482 1,894,464 ¢,252,864 2,c24,c0@ 2,726,028 3,293,488 4,206,288 387,695 464,755 578,515 638,376 828,13 560.020 1,112,022 1,298,082 =1,508,BAD 22,756 1,042,205 1,261,654 2,001,1@2 2.200.551 2,488,022 2,408,008 2,480,000 2,400,000 Q @ 182,eae 216,667 358,333 608,G28 E29,220 G82,C82 628,O28 @ g @ Q @ ®Q 8 ® 30,020 =32,408 =34,BBD 37,200 39,600 42,220 42,028 42,020 42,208 2,373,@12 3,136,032 3,717,369 4,648,409 5,477,486 6,226,202 6,858,000 7,625,422 8,548,208 17.92 15.94 13.95 11.97 9.98 8.08 8.0@ 8.08 8.@8 INTERPOLATED 1984-88 518,@84 594,497 682,742 659,144 687,528 541,489 596,348 663,078 743,322 2,891,096 3,730,529 4,320,111 5,587,553 6,085,014 6,767,689 7,454,348 8,288,478 9,291,5e2 Q V)@ @ @ «4,022,AAA =--5,AAA,OVA =,HVA,AAG =,BER,BBE a 8 @ g @ g @ 8 @ Q J @ @ @ 4,009,022 5.228,C20 6,088,C22 8,HAO,AA2 2,89!,096 3,738,529 4,320,511 S.587,553 6,085,014 767,629 2,454,348 9 ¢,c88,478 =1,591,52e UNALASKA POWER SYSTEM REVENUE REQUIREMENT ERGJECTIONS TABLE SA SYSTEM DEMAKD DEMAND 1983 13861385 1386 1387 1338 1393 1338 22e3 INSTALLED MW (SYSTEM)=UNIT 1 £20 gee Eee 6ee Bae 520 bez gee 6a@ UNIT 2 Eee ota 5e?eva 6t2 Bee Bee eee 628 UNIT 3 Bae 520 Bae Eee Bee 522 Bee 528 bee UNIT 4 30a 20a 3a 3ea 320 a 3ee 3e0 32a UNIT 5 UNIT 6 woo UNI uN TOTAL INSTALLED v 2108282 te 102 2 108 128 2122 2,100 2,108 LESS:LARSEST UNIT (bad)(BRN)LB)(622)1502)(622)622)S22)(608) ALASKA FIN CAPACITY 151,502.52 £500 1.523 1,528 See 1,520 1,50@ KW 65-1 COINCIDENT PEOK 557 572 5a5 5e!617 535 172 gua 1.143 NON-COINCIDENT PEP CF CLASS 835 gca aca B32 B37 B46 1.038 1,853 16504RVERAGE/EXCESS 658 675 bag 638 7a nS 833 1.274 1.387 KW GS-2 COINCIDENT PEAK 17 143 163 195 219 244 e82 327 3B NCN-COINCIDENT PEAK OF CLASS 163 189 213 235 258 274 317 368 42gAVERAGE/EXCESS 136 162 189 213 236 25a 298 346 403 MWi-LORGE POWER COINCHDENT PEO4 "4g 293 327 437 523 E4R cag 548 548 NON-COINCIDENT DED OF (1.088 199 372 Per 635 661 685 685 685 665AVERAGEEXCESS171322353557504623629603629 KW-INTEROTOBLE COINCIDENT PERK a a rT 25 ry 68 £8 68 68 NON-COINCIDENT PERM 2 z it 25 'i 68 a 2g 6gOVERAGE/EXCESS a a i zs 'a 68 £6 £3 6a KW-HEAT RECOVERY COINCIDENT PEAK a a a 2 Q 2 Q a ) NON-COINCIDENT PEAK a Q a a Q a 2 a aAVERAGE/EXCESS Q @ a @ @ Q 2 a ') KW-STREETLIGHTS COINCIDENT PEEX 7 ?3 a 3 2 'ie 19 NON-COINCIDENT PEOH 8 8 8 3 3 1@ 12 1@ 1AVERAGE/EXCESS 7 B 8 3 3 10 1@ 10 1@ KW-SUM CCINCIDENT PEAK B29 1,084 L108 1.325 1,409 1,524 1.582 1,893 2,158 NON-COINCIDENT PEBX Lee5 13885.485 1,735 1.623 1,853 2.403 2,386 2.716AVERAGE/EXCESS Be SE |.dEE 1.52!1.582 "B72 £858 2128 2,338 SYSTEM AVEROGE DEMAND 27 356 424 553 625 Tit 783 ara a76 SYSTEM LORD FACTOR 3.7%3ST TBS 4.BX 4a,at 47.2%46,6x 46.0%65,4k ALASKA FIRM LESS TOTAL COINCIDENT PEAK 67:4%333 75 3 a)182)(352)(650) SYSTEM LOAD FACTOR GS-1 LP INTERRUPTABLE HEAT RECOVERY STREETLIGHTS UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE SB SYSTEM LGAD FACTORS . COINCIDENT PERK NON-COINCIDENT PEAK AVERAGE/EXCESS COINCIDENT PEAK NON-COINCIDENT PEAK AVERAGE/EXCESS COINCIDENT PERK NON-COINCIDENT PEAK AVERAGE/EXCESS COINCIDENT PEAK NON-COINCIDENT PEAK AVERAGE/EXCESS COINCIDENT PERK NON-COINCIDENT PEAK AVERAGE/EXCESS COINCIDENT PERK NON-COINCIDENT PEAK AVERAGE/EXCESS 1983 1984 1985 1986 1987 1968 30 32 34 26 38 40 20 22 24 26 28 kr 25 27 29 i 33 35 35 37 39 At 43 45 25 28 31 34 37 42 30 33 35 38 48 43 4Q 42 44 46 48 52 38 32 34 6 38 49 35 37 39 AL 43 45 100 100 102 100 128 100 100 120 120 100 100 100 108 100 188 120 100 100 1,920,000 1,002,000 1,000,000 1,000,000 1,000,000 1,220,ec0 1,000,020 1,0@2,000 1,002,002 1,002,022 1,022,022 1,008,0001,020,02@ 1,020,000 1,000,000 1,008,e¢@ 1,002,00@ 1,000,200 58 50 58 59 59 58 45 46 47 48 49 52 43 48 49 49 59 59 1998 2003 40 INTERPOLATED 1984-68 30 INTERPOLATED 1984-88 35 INTERPOLATED 1984-88 45 INTERPOLATED 1984-88 42 INTERPOLATED 1984-88 43 INTERPOLATED 1984-88 5@ INTERPOLATED 1984-88 40 INTERPOLATED 1984-88 45 INTERPOLATED 1984-88 103 INTERPOLATED 1984-88 1@@ INTERPOLATED 1984-88 1@@ INTERPOLATED 1984-88 1,000,680 INTERPOLATED 1984-88 1,890,0@8 INTERPOLATED 1984-68 1,088,088 INTERPOLATED 1984-88 5@ INTERPOLATED 1984-88 S@ INTERPOLATED 1984-88 S@ INTERPOLATED 1984-88 UNDLASKA POWER SYSTEM REVENUE RIQUIREMENT PROJECTIONS TABLE 6&OPERATING REVENUE PER G/L TEST VEAR ADJUSTMENT REFERENCE 1383 COST OF SERVICE: ADMIN &GENERAL -SALARIES cel.2ot PARTS-WAGES 16,295 9,185 NI CUSTOMER ACCOUNTS-BAD DEBTS 5.981 CUSTOMER ACCOUNTS-METER READING 3,268 DISTRIBUTION-WAGES 24,738 38,638 N4 DISTRIBUTION-TOOLS &MATERIALS 13,517 ENGINEERING EQUIP-WAGES 12,258 ENG,EQUIP-DIESEL FUEL &PARTS 2,632 GENERATION-WAGES 57,154 4,497 GENERATION-OTHER SUPPLIES 19,668 GENERATION-UTILITIES &CONTR.SERV,14,469 5,2 GENERAT ION-MATERTALS 25,838 GENERATION-AUTO PARTS,GAS &WAGES 14,267 HEAT RECOVERY Q FUEL COSTS 282,353 24,B63 PURCHASED POWER 8 DEPRECIATION:GENERATION 74,671 HEAT RECOVERY 6 DISTRIBUTION LINES Q TRANSFORMERS/METERS 8 GENERAL PLANT ® OTHER EQUIPMENT @ [1 5,128 N3 iALCOMPONENT: NORMALIZED OPERATING EXP. LESS:DEPRECIATION TIMES 45/365 OTHER COMPONENTS: MATERTALS &SUPOLTES PREPAYMENTS TOTAL W/C REQUIREMENTS NET UTILITY PLANT RATE BASE RATE OF RETURN RETURN ON RATE BASE NORMALIZED EXPENSES REVENUE REQUIRED LESS-OTHER REVENUE REVENLE REQUIRED FROM ENERGY SALES AVERAGE CENTS/KWH %INCREASE (DECREASE)/YEAR NORMALTZED TEST YEAR 1383 1384 1385 1386 1987 1988 1993 1998 2223 221.251 227,889 269.725 277,817 286,151 294,736 341,68 396,181 459,189 25.480 926.044 =27,832 27,B43 26,578 29,538 34,243 39,697 46,822 5,981 6,585 7,221 8,383 9,38 1@,516 11,572 12,726 13,991 3,268 3,358 9,459 9,742 18,@35 10,336 11,36e 13,898 16,183° 63,448 65,343 67,383 69,323 71,482 73,544 85,258 98,837 114,598 13,517 14,193 14,982 15,648 16,432 17,251 22,018 28,181 35,865 12,258 =12,626 =-:13,085 13,395 13,7%14,218 16,474 19,898 22,139 2,632 2.764 2,#2 3,047 3,199 3,359 4,287 5,472 6,983 61,651 93,501 126,306 130,095 193.998 138,017 162,020 185,484 215,027 19.668 28,651 2t.684 22,768 23,387 25,1@2 32,@37 4@,888 Se,185 19.469 28,832 a2,298 23,858 25,528 27,326 38,298 53,716 75,339 25,830 27.122 28,478 29,91 31,397 32,966 42,074 93,699 68,535 14,267 14,838 =15,431 16,048 16,638 17,358 21,119 25,694 31,261 Q 8 =18,eee 18,388 10,609 18,927 12,668 14,685 17,024 307,216 461.093 323,795 656,537 714,651 328,B42 329,844 356,537 233,263 a @ Q a Q 64@,220 820.Ota 32.008 =1,288,OA25.034 8 =€5,159 eS,aid 25,665 25,921 26,181 26,982 26,358 23,685 4,417 5,712 7,076 7,217 7,362 7,589 7,978 8,888 9,725 19,517 ©32,399 971,138 98,864 102,621 106,528 120,164 146,Ite 477,BB3 8,425 8,See 8,783 8,892 9,884 9,e71 9,87 1i,tee 12,634 @ 5,028 18,288 12,628 16,@32 21,674 24,492 23,799 36,255 333 348 354 368 382 398 443 SA7 665 5.18 5,384 5,516 5,737 5,946 6.205 7,549 9,185 41,175 858,746 1,079,391 1,287,922 1,471,973 1,563,214 1,643,754 2,161,076 2,538,555 2,965,645 Q58,746 1,879,391 1,c87,922 1,471,973 1,563,214 1,843.754 2,161,076 2,538,555 2,965,645 (57,726)(77,130)(122,874)(151,614)=161.403)(171,539)(189,973)=(224,746)«=(266,967)98.736 123,566 =143,636 162,784 172,Be6 206,164 243,013 285,264 332,714 @ @ @ 8 @ @ Ly Q 8 8 Q Q Q 8 a a @ Ly 98,756 123.566 143.636 162,784 172,826 206,164 243,813 285,264 332,714 841,534 1,361,459 2,081,704 2,215,024 2,188,081 2,108,867 2,448,722 2,870,227 3,387,942 940,298 1,485,026 2,425,360 2,377,808 2,360,907 2.315.031 2,691,734 3,155,491 3,728,655 8.8,e 8.e%8,e%8.0%8.0%6.e%8.Ox 8,0% 73,223 118,882 194,827 198,225 168,873 185,02 215,339 252,439 297,652 858.746 1,079,391 1,287,922 1,471,973 1,563,214 1,843,754 2,161,876 2,538,595 2,965,645 933,969 1,198,194 1.481.949 1,662,197 1,752,087 2,028,957 92,376,415 92,798,994 9-3,263,297 @ Q Q @ g a Q 8 8 933,969 1,198,194 1.401.949 1,66€,197 1,752,087 2,0¢8,957 2,376.415 2,798,994 3,263,297 39.36 38.21 39.87 34.28 31.99 32.59 34.65 36.68 38.18 (3)4 (14)(7)2 6 6 4 4UNALASKA 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-SALARIES PARTS-WAGES CUSTOMER ACCOUNTS BAD DEBTS CUSTOMER ACCOUNTS-METER READING DISTRIBUTION-WAGES DISTRIBUTION-TOOLS &MATERIALS ENGINEERING EGUiP-WAGES ENG.EQUIP-DIESEL FUEL &PARTS GENERAT TON-WAGES GENERATION-OTHER SUPPLIES GENERATION-UTILITIES &CONTR,SE GENERATION-MATERIALS GENERATIGN-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 78,57 905,486 39,760 46,54859,00¢ 5,200 1,496,315 20,B32 27,122 14,838 0 461,093 ) 25,159 5712 32,399 8,520 KW 65-1 COINCIDENT PEAK NON-COINCIDENT PEAK AVERABE/EXCESS KW GS-2 COINCIDENT PEAK NON-COINCIDENT PEAK AVERAGE/EXCESS KW LP COINCIDENT PEAK NON-COINCIDENT PEAK AVERAGE /EXCESS KW-INTERPT.COINCIDENT PEAK NON-COINCIDENT PEAK AVERAGE/EXCESS HEAT RECOVER COINCIDENT PERK NON-COINCIDENT PEAK AVERAGE/EXCESS KW-STREETLIGCOINCIDENT PEAK NON-COINCIDENT PERK AVERAGE/EXCESS #OF KWH CUSTOMERS SOLES BS-1 288 1,596,672 BS-2 28 464,755 LP 5 1,042,205INTERRUPT,@ @ HEAT REC.!a STREETLIGHTS 1 32,400 RETURN ON RATE BASE 118,8@2 UNHLHONH PURER DTD IE REVENUE REQUIREMENT PROJECTIONS FOR THE FISCAL YEAR 1564 TABLE 8 PLANT ALLOCATION ELECTRIC UTILITY PLANT ALLOCATION TO FUNCTION-RATE CLASS ALLOCATED PLANT )DATA FOR FEBRUARY 1983 TO JANUARY 194 -o-ALLOCATION PERCENT } 4 OF KWH KW KW KW DIRECT CONSUMERS COINCID.NON-COIN =AVE/EXCESS PLANT ACCOUNTS: GENERATION 379,264 ax @%100%ax Ox ax _HEAT RECOVERY 78,G57 ex ey ex Qe ex 1ae% DISTRIBUTION LINES 905,486 oes Q%Q%oes Gx ex TRANSFORMERS 39,768 Sex O%Ox ae ex ex METERS 46,548 1@a%Q%ex @%Q%Q% GENERAL PLANT 56,082 50%Q%Sex Q%Q%ey OTHER EQUIPMENT 5,ce Ox Ox ax Ox a%1eax GROSS PLANT 1,496,315 #OF KWH Ki KW Ki DIRECT =-PLANT CONSUMERS COINCID.NON-COIN AVE/EXCESS TOTAL PLANT MENU ALLOCATION: GS-1!288 861,596,672 578 828 675 @ 994,762 x 89.2%5@.9%56.8%59.3%.e%66,5% 65-2 28 464,755 143 189 163 @ 168,996 %8.7%14,B%14,3%13.6%14.0%0.0%11.3% LARGE POWER 5 1,042,285 283 372 322 @ 248,233 %1,0%33.2%28.2%26,6%27.5%8.8%16.6% a INTERRUPTABL a @ g Q 8 8 @ :%0.8%8.%@.@x @.e%Q.2%0.a%@.0% HEAT RECOVER 1 @ Q a a 8 76,942 %8.3%Q.0%a.2%@.eX 8,&%Q.e%Det STREETLIGHTS i 32,420 7 8 8 a 7,383 %@.3%i.e%t.7%@.E%B.7%188,OX a.5% TOTAL 323 3,136,832 1,004 1,356 1,166 @ 1,496,315 %180.@%108.0%102.@%128.@%42.2%=188.Q%=18.OX (IN $) #OF Kin Kid KW KW DIRECT CONSUMER COINCID.|NON-COIN AVE/EXCESS a @ 379,264 7])) Q Q @ a @ 72,@57 452,743 Q @ 452,743 a ) 19,88@ )@ 13,880 @ @ 46,548 2 a )Q @ 25.00 )25,022 @ )@ Q @ )Q @ 5,200 544,174 2 404,264 =472,623 8 75,257 #OF KWH Kd KW KW DIRECTCONSUMERSCOINCID.|NON-COIN AVE/EXCESS 485,205 @ 229,428 =280,129 Q @ 47,173 @ 57,757 64,066 Q @ 8,424 @ 1th 1e@ =125,789 @ a @ a )@ )a 1,685 ")a Q )75,257 1,685 @ 2,98@ 2,719 @ ) 544,171 @ 404,264 =«472,623 )75,257 UMALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS "TABLE 9 COST GF SERVICE ALLOCATION FOR THE FISCAL YEAR 1364 (ALLOCATION PERCENT )A_LOTATED EXPENSES ) [IN $8) oF iw KW fei Kid DiRELY PLANT a oF Kat dW "6 Hol DIRECT PLANS EXPENSE ©»CONSUMERS COINCID.NON-COIN =AVE/EXCESS CONS ERS COTNCID.NON-COIN,=AVE/EXCESS COST OF SERVICE:sooo "- ADMIN &GENERAL-SALARTES 227,883 nex fo bra)ex Qn a as 113,944 g 113,944 @ @ Q e PARTS-WAGES 6,264 5e%a Ses ey et ex a 13,tee e 13,122 Qe a @ ° @ CUSTOMER ACCOUNTS-BAD DEES 6,585 ex 1@ax ex en a (a @ 6,525 ge @ @ g gz CUSTOMER ACCOUNTS-METER READ 3,358 10Q%a ex Ox ax ey rad 3,358 Qa a id Q @ a DISTRIBUTICN-WOGES 65,343 @x 1@a%ex ex ex a a @ 63,243 a @ a a @ DISTRIBUTION-TOOLS &WOTERTA 34,193 ex Lee%ex rod a a3 at @ 14.1353 ca a a 8 a ENGINEERING EGUIP-WAGES se,626 a an {ans eK fad ex ax gz 2 12,626 @ a Q Qa ENG,EQUIP-DIESEL FUEL &PAR 2,The ex en SQe%ay ey ex at e a 2.7€4 a @ @ @ GENERATION-WOGES 93,5a!ee a Laan 2%ra a.en rd i 33,58 2 @ Q Q GENERATIIN-OT+ER SUPPLIES 20.651 2%red LO2%Peg ay a e%@ ?20.65;@ a Q Q GENERATIONAITILEITIES &CONTR 20,632 a oe L2ex ex On ax ax 2 Qa 24,832 Q C)(J 8 GENERATION-MATERTALS e7,122 @x ex 120%aK ex ay ex @ a 27,lee @ a 8 8 GENERATION-AUTO PARTS,GAS &16,838 tad Qn LQQx ex a ex x Q Qa 14,B38 Q Q Q 8 HEAT RECOVERY 8 ex a fad ay a 1aex ey a @ @ a a @ @ FUEL COSTS 461.833 ex 102%rad rad a a ray z 461,233 e @ a 8 2 PURCHASED POWER a %1ae%re)ra et ex px e z @ 8 Q 2 Q DEPR:GENERAT TON 25,159 ad ex ex ax es Ci Leex a @ @ @ @ a 25,159 HEAT RECOVERY 5,712 a x ex ex as ex 100%@ a Q Q 6 a 5.7i2 DISTRIBUTION LINES 32,399 ox ex as a et ex 120%a @ a @ @ @ 32,399 TRANSFORMERS/METERS 8.528 ex ex ey a4 ex ey 1eex @ a Q a @ Q 8,52e GENERQL PLANT 5.028 2X es at ex ras ex Lean cd ?a 2 @ a 5,22a OTHER EQUIPYENT Tae res ex a ra a a it a a fd Qe cd a 342 INSURANCE 5,3t4 ex %ox ex ax on Leda 2 a @ e a @ 5,324 TOTAL OPERATING EXPENSES 1.979,331 RETURN ON RATE BASE 118,a2 Ox a rad @%ex Ox 100%@ @ a @ @ @ $18,A@2 REVENUE REQUIREMENT (OVERS)130,426 R47,136 313,399 t ry ?2@1,236 2,198,194 ASKA ELESTAIC UTILITY REVENUE REQUIREMENT A_UCCATED 70 RATE CAG REVEN.T REGUIRIMENT ($)ALLOCATED TO RATE CLASSES ALLOCATION MENS: #CF Vs tn "w BC)Dac”re a "as oe 4a An Dlaecr PLANT "ore, SCNSUYENS TOINCISEN?NON-COCSDI0D,BV EYTESS TONS ERE COCAC IDENT ACA-COINCTO.RVEVEXZESS eS-1 288 =1.596.572 se 8cb 875 @ 594,75 116.092 278,267 18.265 2 a @ 383,783 729,987 %83,e%58.9%ub,S%£3.a%2,a%@.2%56.2% 55-2 23 454,755 ie?183 @ 154,936 +0 bth 81 844 43,835 z @ @ ce,728 258.75t %3,7%£4,6%53.&3 "0%a 2%ax LARGE POWER St,242,225 233 WE fe 2 248,233 EF 1Bi,83%98,147 Q @ @Q 33,384 37,381 t 1%33,2%26,e%£6.E%27,5%8.2%18.6% INPERRIET,z @ td rd 2 zt zt @ t z g a a a @ %a,as 8,2x &,0%B88 aay ay aes HEAT RECOVER 1 a ?@ z @ 76,34 49a e 2 @ @ 8 20,348 18,752 %@,3%2,2%Q.es @.2%Bex a.2%5.1% STREETUT G+7S i 32.A428 ?&id @ 7,482 634 r.33 F,a4 a g a 733 9,hie %?,o%we)e.7%aes aie hemes Rox Tora 32300 5.156,822 40 CRG a,252 1.085 21.456.310 oe.4e4 Tar,36 319,363 a a a par ove 8 ta aA we I PAL I REVENUE PEQUTRE WENT PAO CERT TANG TAB 62 C27 STATISTICS BY RATE Tas asoGa THE FpSCP.vEAg s7Be feegE 65-1 65-2 L7 "rH BASE DATO; #CF CONSUMERS 298 2a 1 3 KKH!SOLD 16E96.872 S64,785 BEARS 2,126,022 tab PVE /CENGUMEA/MONTH 42 4,383 2.788 B23 4am COINCIDENTAL sve 143 7 1.206 KW-NON-COTNCEDENTOL 5856.5!B28 199 8 1,398 Kii-AVERAGE EXCESS 675 163 3 4168 %OF CuS7.CHARGE IN DESIGNED RATE 50%75%sea 12a eax 12% %DF CO-DEDY IN DESIGNED RATE ee ex ase 25x 2x any DEMAND RATCHET ax a 73% REVEN-E REQUIRED 782.987 168,75:207 a a 75E 3,426 CUSTOMER COSTS 118.292 1B 2 a ape 424 FIXED COSTS 355.049 69,264 123 a 1,2k 3.3467 EMERSY COSTS 278,567 Bt PRe Lat,a a 5.683 CUSTOMER $/C°NSUMER/*DNTH S68 3268 0 BLS a 23.65 33.65 FIXED $/CONGUMER/MCNTH S116 2A.45 2,058.85 a 862,3!278.95 FIXED $/KilsCO-PEQK/MONTS 46.29 9-39.73 6A ERR ERA 37.71 FIXED $/4W:NON CO-PERH/MONTH 31.69)328 87.69 £28 ti 34.69FIXED$/Miés OVE-EXCESS/MONTH 35,89 34,98 3.2.ERR ERG 35.28 ENERGY CENTS/4MH S745 17.4E 17,AE ER za 17,85 7,43 BVEROGE CENTS /KWY-DRESS 44.85 34,52 29,63 Esa E54 23,82 a TARGET REVENUE (NO TILT) $/CINSUMER/MONTH $225.41 $478.62 $5,123.22 ERR $895.96 $783.63 AVERAGE CENTS/MWH 4446 (36.89 2.89 Eea ERR 29.02 Fo SN ) CBSTQUER Colle $16.82 $25.26 $33.65 £9 $33.65 $33.65 AND CHARG $2.02 $8.22 $3.05 ER ERA $9.43EasyCHARINCENTS/MuH 40.82 832.76 «25,32 ERR ERR 27.43 SHEE EEE EES EEE RE ERD ER EE TERRES ED ESE REE ERERERESESRERE ESS PEGE RPEEA SE EE ES EES ESET CEE EE TEES EAH EEE EES EEE EEE EES 4H OEE TILT IN $ TILTED REVENUE REQUIREMENT (32,G2) 659,987 {2,dee 178,751 42,22¢2 2 2 @ 347,361 a 10.75¢2406 6,198.194 RAE AAG EEE EE EAE EEE EERE REESE ERE RAR EES EEE EES ER EEE EERE ER ESTER ELE ER EEREEERSEERS EEE SE REEE EEE EE EERE EERE REE EECEE EERE NSH TARGET REVENUE (TILTED) $/CONSUMEV/¥ONTS GVERASE CENTS /Mas RATE DESIGN (TILTED) CUSTOMER CHARGE DEMAND CHPRGE ENCSGY CHARGE IN CENTS /Minet $355 4 $25.82 $@.22 27.63 $25.26 $33.65 ER $33.65 $33.65 $2.22 £5,209 59a £95 $3,493 36,32 ae,26 FR?EWR e762 OU 7 Preseckt as Le ° :SRevied Co ey .SS-O7-0 )DRAFT RECONNAISSANCE STUDY OF ENERGY REQUIREMENTS AND ALTERNATIVES APPENDIX :UNALASKA APRIL 1984 pRAri PREPARED BY: ARE _|ALASKA POWER AUTHORITY__ TABLE OF CONTENTS Section A -Summary of Findings and Recommendations ..««6 ««6 «©«©«©»«« B -Demographic and Economic Conditions ..2.2.«6 «©©«©©©©«©© C -Community Meeting Report..2.2 «©«©«©©©©©©©©©©©©@ D -Existing Power and Heating Facilities .....©«©«©e w«« E -Energy Balance..«.«©©«©©©©©©©©©©©©©©eo ee F -Energy Requirements Forecast..«2 6 ©«©«©©«©©©©©©©©© G -Village Technology Assessment a a H -Energy Plan Desrciptions and Assumptions..«««««©«©«©««« I -Energy Plan Evaluations .2.2.«©©©«©©©©©©©©©©ew J -Environmental and Social Impacts..2.2.«««©«©©©©©©©« APPENDIX A --Cost Estimates Developed by Republic Geothermal,Inc. Geothermal Plant at Mt.Makushin APPENDIX 6B --Alaska Power Authority Project Evaluation Guidelines A_ -SUMMARY OF FINDINGS AND RECOMMENDATIONS A.1l -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: 1.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.Maaa10740ww(al2.With the data available,it appears that the econgnics of,geothermalhowareaarenotoDfive"Od focrekins °duster,pun ty unce rtanhy OF foprltin,akad lead x,ch3.While state Sooport Ju resea and detailed feasibility studies of geo-thermal energy on Unalaska Island and elsewhere in the state may be @appropriate,the investment of public money for construction of such *projects seems imprudent.The participation of private investors,who zg S can benefit from Federal tax benefits for investment in renewable energy projects,should be encouraged,7)pate4.The City should very carefully consider siting its 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 gen- erating 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.MfGyAyo7cinaywchaMniinomyoAyes5.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. ,6.An investigation should be made of the yailability 0of systems whieh usewasteheatfromdieselenginesteetores.Such sys- tems could be attractive to the seafood processors located near the gen- erator plant(s). 7.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. 8.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 couJd be an a propriate site for aLYMbopanewindturbinedemonstrationproject'.undant wind resource there.Because of the relatively low cost of diese!fuel at Unalaska,a wind turbine would face stiff economic competition and would tikelynoeshowanyadvantageoverthedieselsystem. B_-DEMOGRAPHIC AND ECONOMIC CONDITIONS B.1 -LocationpieCityofUaalashe Consish of te frp Lommoenites ofUnalaskaandDutchHarborewelocatedgneaa=oP?the Fox Islands,a group of islands in the northern part of the Aleutian af &The ommunity ofDutchHarborisonAmaknakIsland,a small island separated or UnalaskaIsland(and the ¥ittege/of Unalaska)ttee##)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 i any-Ca6e0;-thrsTeport-wiilconsider-them as one honfigeneous community. B.2 -Population , Depar betDataprovidedbytheStateofAlaska*s Bivrsten of Community and Regional Affairs shows the following population trends for Unalaska /(treteding Dutch Harbor: \ 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 pect ten Aleuts,the original inhabitants of the area.The rela- tively sudden predominance of white residents has come about as a result of Unalaskat mecegeteton as an excellent base for commercial crabbing and fishing activities. B.3 -Economy Unalaska stands ak the economic center of 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 itsharbor,Unalaska has become a base for rk 8 and bottomfishing fleetswhichoperatethroughouttheNorthPacifichearea's salmon industryy and ths se ttre oil companies involved in exploratory activities in the southern BeringSeaandNorthPacific. 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.lf such an industsy ys developed,it seems logicalthatUnalaskawouldbegrverprimeeeaSathebaseoftheneces- 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,developedas 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."te-=-wee Air-Pac whieh-hee recently intro- duced jet service to Unalaska using British Aerospace BA-146's.Unlike the similarly-sized Electras,the BA-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.)p addy 'Wy,Sclududd Qn WNLAon. afpetii"practicat_wayoftravetting-to_or ff 'fromUnataska.,The Alaska Marine Highway det3 provides ferry service to Unalaska from Homer.A trip from Homer to Unalaska requires four days. 4onfeisla Ww Jai ltitig!loTransportationiandDutchHarborisby-car-eer-t FHhe-tTty> 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 Outch 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.Inc.,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,DC,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)andtheAlaskaPowerAuthority(Mr.Donald Markle)eet 3e-dayO visit to Unalaska tsit-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 Direct of City Finance),the visitors were given the opportun- ity to address 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 realized 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 to, 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. ih D -EXISTING POWER AND HEATING FACILITIES Unalaska electric utility customers are presently served by a municipalfyf- operated diesel generating plant located near the high school and the city offices.The City's diesels have the following ratings: l 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 pooly the city pEAS SSS the communitycenterythecityclinic)and the police station. wi that the waste heat system saves these users about 58,000 gallons of fuel oil each year. TheseCity-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 CONSUMELS -OeictneniGGedeell Leer PTO-vidi fe their own source of electricity.The processors and other industri-. al users all have their own diesel generators.In many cases,Dutch Harbor estimates”bythe businesses and,;darmitory-sty h using unit oo Bees!Deeg fe qpesaocompanies,hoes ose poet idl)pee their parents ener- cating-_facitities.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.Care selection of the siteforthenewpowerplantcouldprovideBoRangeforthewasteheat. 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 is We : 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 ave An energy balance for a community can be ought of in much the same way,an income statement developed for a businesd +6 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.l -Capital Projects Forecast F.1l.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 cargoboundforwesternAlaska(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 \y will operate in the same manner as Ee crabbers ,bavt,This newXS,industry will likely use new ships heverteeen outfitted as catcher/processor ships.These ships may not call at port for peri-ods measured in months.They would also ret have*heed for the large shore-based support activities associated with processing.As a result,the City may see few economic benefits cresulting from an expanded bottomfish industry. F.2 -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 foryunalaska waspreparedin1982bytheAnchorageofficeofDames&Moore. Ttey 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,mhteicpenes &Moore saw as the leader of Unalaska's futureeconomicbase.iz 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 catchMinkwhiehwillbedoneonshore.It is our opinion that the modern bottomfishindustry(especially the foreign participants in thatindustry)will'makeextensiveuseofself-contained catcher/processor ships.For that reason, this report ignores the Dames &Moore "high bottomfish"projections.-_-we em ee ee eee oo -%We pitty se'Dames &Moore's "no bottomfish"projections as our low fore-castey eith-dhots."low bottomfish"and "best-quess bottomfish"projections hbeing our "best-guess"and "high-growth"projections,respectively. Table 1 onm-the-felewing-page gives Dames &Moore's data for the various bottomfish catch possibilities. 10 Notes: TABLE 1 UNALASKA/OUTCH HARBOR POPULATION FORECAST (data taken from Dames &Moore,1982) DAMES &MOORE DAMES &MOORE DAMES &MOORE DAMES &MOORE "NO BOTTOMFISH""LOW BOTTOMF ISH""BEST-GUESS BOTTOMFISH""HIGH BOTTOMFISH" CACRES "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 °°'11,500 1,210 2,710 1,707 1,450 3,157 1,900 1,570 3,470Lam 1985 1,506 -978 2,484 _1,530 1,285 2,815 1,785 1,590 3,375 2,030 1,740 3,770 (C04 1986 1,330 F631 990 2,520 «1,780 1,340 3,120 2,270 1,700 3,970 3,300 1,850 5,150 1987 1,550/56,1,010 2,560 2,020 1,400 3,420 2,760 1,800 4,560 4,570 1,970 6,540ISS™99g 1,580 yo4$1,020 2,600 2,270 1,450 3,720 3,240 1,900 5,140 5,840 2,080 7,920(573 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 i 8,380 2,440 10,820 13,800 3,300 17,100 1995 -1,812 1,175 2,987 5,799 1,883 7,Pd 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 1,313 3,336 11,550 2,317 13,867 16,972 2,894 19,866 22,287 3,459 25,7461,340 sah 12,700 15,100 18,500 2,970 21,470 23,700 3,440 27,140 1,370,"3,48¢13,800 16,250 \20,000 3,040 23,040 25,100 3,420 28,5201,400 3,55 15,000 17,580 500 3,120 24,620 26,600 3,410 30,010 _1,420 3,610 ,860 23,000 3,190 26,190 28,000 3,390 31,390 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. < 1l F.3 -Electrical Energy Forecast Beginning-ia-this section,-end-continuing through __the--remainder-ef-the report,we presents "Low,"""Best-Guess,""and "High"forecasts of economic activity and electric energy use growth.References to bottomfish catch levels wfITl generally-be omitted.; Onrg_' .hr onceUnalaskaresidentialcustomershavehed-accese-te both a centralized utili-beh Ske ..ty system and"a'sou cegofOincome long enough to have attained a relativelyhighlevelofconsumptionFor<rural Alaska conmuni tis.City officialsnotethata"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.Seyond 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:. . %mi TABLE 2 - ae v EXISTING LOADS (i Are(From Unalaska Loan Applicati Documents) Cust jee Cul a c tion (MWh)=<ustomer yA eman onsumption L tv »a we Standard Oil Company OB 200 834 i ;esitdentie in 12g-20 0---______----8 7 6-American President Line So 870:493 |semmeStrawberry Hill Mridnkiel i 30 144 4,4 _-Whitney-Fidalgo-(closed)cece Qe ee nime Qe fast Point Seafoods Gy 860 841 Universal Seafoods })5D 2,450 10,074 yy >=-Panama Marine 34 1,1,400 3,000 pr 7 Pan Alaska Seafoods u5O 1,750.3,942 2b-Pacific Pearl Closed 50 570 1,314.abCityAirportCineludingexpansion)344 ws 68 -328-IU 5o}eeeSea Alaska uso 1,750_3,942 2b City Dock 20.200.)175 10 City Boat Harbor 50 256 500 219 47%10-City-of-Unalaska Salés™CO eee"140 22,500.8.Steck Vic fi a"TOTALS 11,745 28,682 foYASpKphbeue?, Note:-1 MWh =1,000 kWh UNALASKA/DUTCH HARBOR HOUSING AND RESIDENTIAL ELECTRICITY USE FORECAST TABLE 3 FROM ACRES'LOW-GROWTH POPULATION FORECAST (assuming no bottomfish development) 12 i HOUSES Nr apartvents \V \vPOPULATIONNUMBEROFENERGmMPOWERNUMBEROFENERPOWERENERG POWER YEAR RESIDENT TRANSIENT _TOTAL HOUSES USE_(KWh)DEMAND (én)APARTMENTS USE kWh)DEMAND (kW)|USE (Wh)DEMAND (kW)7 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 5,202 888 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 2,592 360 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 B14 2,930 407 6,735 1,087 1996 1,850 1,200 3,050 463 3,889 695 831 2,992 416 6,881 1,111 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 4,603 822 984 3,542 492 8,145 1,314 aAssumptions:1.75 percent of "Resident"population is assumed to live in single-family homes at 3 people per house;25 percent iapartment-type dwellings at 2 people per unit.100 parreent %tg eomstent population is assumed to live io aparfhe?°type dwellings at 2 people per unit.a >”oy "97 rUowal}Wu i.5 (7 -?a oem,.Houses will be assumed to consume 700 kWh/mont ak'a veok demand (coincident)of about 1.5 kW;apartment-stypey ay 5 dwellings will be assumed to consume 340 kWh/month,with a peak demand (coincident)of about 0.5 kW.WAY a hike 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 17,019 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- .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 2,934 352 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 requiredtokeepthemfrozen.We do not believe Ynat any more than 40 percent oftheareacatchwillbeprecessed_a aska,This proportion could be as low as 25 percent of the tch. the fish caught under Acres'"Best-Guess"and own on Tables 6 and 4-en-the--following-pages. The energy used to freez "High-Growth"forecasts are DAMES &MOORE LOW BOTTOMFISH TABLE6UNALASKA/DUTCH HARBOR BOTTOMFISH PROCESSING ENERGY ESTIMATES TO BE USED WITH ACRES'BEST-GUESS FORECAST yo AN LN 'goin PORTION OF AREA CATCH PROCESSED wo oo 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 0 0 1981 0 0 0 0 0 0 0 1982 )0 o | )))0 1983 0 0 0 \0 0 0 0 1984 10 268 )\201 )168 ) 1985 55 1,474 1 1,106 Q 921 0 1986 90 2,412 1 |1,809 1 1,508 1 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 ll |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 10 18,425 8 2002 1,200 32,160 14 '26,120 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 16 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 (108 1b)ENERGY (MWh)POWER (MW)ENERGY (MWh)POWER (MW)ENERGY (MWh)POWER (MW) 1980 0 0 0 0 0 0 0 1981 1)0 0 0 0 0 0 1982 i)0 0 0 '0 0 0 1983 0 0 0 0 0 0 0 1984 30 804 0 603 0 503 0 1985 110 2,948 1 2,211 1 1,843 l 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 ll 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 11 20,100 9 1998 1,300 34,840 16 26,130 12 21,775 10 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-BOTTOMF ISH BOTTOMF ISH 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 5,279 0.85 28,700 12 0 0 0 0 33,979 13 1982 5,346 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 ol 20 0,008 34,222 13 1985 5,604 0.90 28,700 12 0 0 20 0.008 34,324 ©13 1986 9,687 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 0 100 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 35,995 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 13 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 1.32 28,700 12 0 0 vi 0,098 37,105 13 TABLE 9 TOTAL ELECTRICITY USE--ACRES'BEST-GUESS FORECAST NON-BOTTOMFISH Wy .Coty anes BOTTOMF ISH 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 Q 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 oO 40 0.015 34,349 13 1983 5,808 0.93 28,700 12 0 of 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 1)100 0.038 36,125 13 1986 6,953 Ll 28,700 12 1,809 1 160 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 7 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 CU. 19 TABLE 10 TOTAL ENERGY USE--ACRES*HIGH-GROWTH FORECAST NON-BOTTOMFISH BOTTOMFISH 20 RESIDENTIAL INDUSTRIAL LOADS PROCESSING LOADS MISCELLANEQUS 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 ")O )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 )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 7 1 1990 14,556 2.37 28,700 12 8,844 4 800 0.300 52,900 19 1991 17,375 2.85 28,700 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 4) 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 21 UNALASKA LOAD FORECAST 50-}---------toonne ten wenoe-terneneee tere cee---tenon en- H 45-1 - H H 40-]---------torre teen neon tereeeeee t---------tanec ene 5 H H 35-1 -H B H B POWER "B DEMAND 30-|---------+teen eene-e $o2 eee=+---H- ---toe cnn----toon ---H+(MW)B H B B 25-1 -H H B B HH B 20-]| --------torneo ---+-H-------tere ----$e eenne--tonne-4 H BB 8 HH B HH B BB 15-]- H B BB ee eee FE LELEELELLEERLLEEELELEELELEL 10-|--------+-tar nn enone poen een -+o--------See +-------- LEGEND:L =ACRES'LOW-GROWTH FORECAST B="BEST-GUESS " 5-|-H ="HIGH-GROWTH " *=YEARS OF FORECAST QVERLAP 0 ||||| 1980 1985 1990 1995 2000 2005 YEAR ? ENERGY USE (MWh) UNALASKA ENERGY USE FORECAST 22 150,000-]-- ---- -.ton eneonee teen eee ---too --e tae n weeneeto--+---+ H 140,000-4 -4 H 130,000-|-4 H 120,000-}-H a H 110,000-}-B + H B 100,000-; --- -----$e ewes +$eenwe eee oes ee Heon--4----++o------- B 90,000-|-H B - H B 80,000-]-B 4 - H B 70,000-}-H B + H 60,000-|-HH B 4 H B B 50,000-]--------.-tennnre-H-+---B-B---+---------tore ---toonneee + H H B 40,000-|-HHBBBB **e ee eee E EEE E LEE LEE EEL LULL L 30,000-|-= LEGEND:L =ACRES*LOW-GROWTH FORECAST 20,000-|-B ="BEST-GUESS "+ H ="HIGH-GROWTH " 10,000-|-*=YEARS OF FORECAST OVERLAP 4 *|i || 1980 1985 1990 1995 2000 2005 YEAR 23 uot G -VILLAGE TECHNOLOGY ASSESSMENT The purpose of this part of the report is to briefly dis uss th -dtioustechnologieswhichhavebeenusedtogenerateelectricitBaechsmaybeusedinUnetecta.{[oer aa fet 4 27dig+e ;;Because-of the area's fishing aftd_crabbing industr and the _on-shorepersonnelrequiredtoprovidemaitenance,Unalaska has javailable-to-tt-a >relatively skilled work pool."In the operation of a utility system,access e-such ahigh-gradeoflabor 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 supporta small coal-fired power plant,but it is believed that the importation of coal may.make this alternative so expensive as to be uncomptetitive.S ° ' 2.Conservation.This is a (resources:available to virtually all energyusersanywhereinthestat'Ometimes even the simplest steps taken can save appreciable amounts of energy.Based on conversations with City officials,Acres'staff believe that Unalaska residents activelyractice/caonservation in their electricity vee bee hey make an effort to below the 600 kWh limit of the ate subsidy.Individual effor 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 nearenousgeothermalresourcethattheycouldpossiblytakeadvantageofit.The Alaska Power Authority has been actively exploring the geo- thermal tential of Mt.Makushin,about 12 miles to the east of thecity.Pre 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 £9 d terming,the/,sts associated with availablehydropowersites.trey MAEM 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.<thte-eittratien-wititTikéely_rontinte-fes-inte-the-feturesThecity's generators any 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 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-tat eecovery,s”dnergy that woul otherwise wre iven u to yihe atmospherecanbecapturedandputtousé,.A Bardeen ete at aeheat 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.-”tiv ala bedfypunkbaalAnotherpossibleuse,gis 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 aie turbine.The turbine is then used to generat electricity.Such a process is known as an "Qrganic Rankine €e." In conversations with a major manufacturer of this type of egtipment, Acres'staff learned that systems smaller tha Npadoutt poyhould notbeconsideredfortheuseofthistechnologysaid 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.7? In addition to the waste heat technologies used to provide aT heat For other-usees and WJ mere electricity,there is a system available from Japan's Hitachi Corporation which can use waste heat to produce getd. Instead of fr amet er to users near pg generating plant,this sys-tem would flow Vety cold ammonia or freon tc nearby users.In a com- munity such as Unalaska,where treresase tremendous amounts of energy le used for chilling and freezing,the anvestigationm of this type of equipment may be quite worthwhile.Ae \ann,Cutcrun*t Photovoltaic.This alternative is presently too expensive to consider for utility application in Alaska. Wind.The Aleutian Islands are aT1 exposed to very windy conditions. Although wind turbines,for the mast 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 éfre utilitysyatendtowhichtheyare-connected that eestomers _heve-ted-thete ratesreduced;te veduer colin fo gyrtrerce, 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.1l -Base Case The base case plan wit assune that the City of Unal will continue todevelopitscentralizedelectricutilitysystem.Tey will use diesel engines to generate electricity and will recover and sell waste heat. We ae?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 «iett--tre made: ®Beginning in 1984,t City will +egin-to increase generation capacity to the point mney:can supply all electricity needed in the commun-ity.In 1984,y pill bring two new 2,500 kW ma nes 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. atrey will have a lifetime Installation of the units will run another $300/kW,for a d V *The diesel units will require a major overhaul every 10 yeaps.TheseoyoverhaulswillcosttheCityabout1,price of theMKmachinesor$100/kW. ba e diesels wil $150/kW."The waste heat systems will have lifetimes Ov To "yeare. *The diesels whii-be-expected to produce 12 kWh of electrical energy for each gallon of diesél fuel used.They will also be ebtemio produce 10 kWh (34,000 Btu)of waste heat (recovered from the cooling water)For IYthis.-sames gallon of fuel. we .Normal operation and maintenance of the diesels and their waste heat7dsystens,Ihice will require a mi Ay Aut crew of three people for theinitialmachinesywithonemore',added for every three additional machines.The payroll costs of edch 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 beaeabout$20,000 per machineman X01: w™3 Fuel is estimated to cost $0.98/per gallon when the new plant is built im 1984."The plant will have a direct pipeline:from the Chevron bulkplantonAmakanakIsland.Fuel costs will escallate at 2.5 percent /annually thro in constant thereafter.4qov 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 The fuel oil price to these customers will be assumedburningfueloil. 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 wher 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 pth.”forthelevelofdetailrequiredforareconnaissancestudy.Ké cost esti- mates were used without change to develop the following assumptions regard- ing the geothermal plant: be For Acres!low-growth forecast,two 5,000 kW units will be installed tobeoperationalby1993.This re ort will refer te Asenctab oufigurationas"the-I0O MW plant."After alTI in-plantt.load »6,700 kW would be available to the City.Republ estimates that this plantwould\cost $68.3 miynion bop ollars. ATM ae e Republic estimates tha e MW plant wuld cost $1.8 million eachyear(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).Urey \n-beve suggested at least two options for a construction schedule forsuchaplante 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 atUnalaska.Republic estimates that such a plant would cost $20Z million in 1983 dollars.is 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.id ®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 "B" 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.l -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. In our economic analysis of the Mt.Makushin geothermal project (Alternat- i "aN di igh f d lt di -ive ),we diverge slightly rom APA st 9 rdsf Bagh osu ve is s3-\igqns.be ween Ajaska Power Aughositygand i ;e i Acres 'tras==been (Joram fue Luddirceted to assume that a geothermal project has a useful life of 35 years and a financing term of 25 years.,For this project,these numbers replace prevaesAPAguidelinesofa15yearamedreneVEandfinancingperiod.ath App al»r%)To clearly identify the economic advantages of one project over anothers}Power Authority guidelines suggest that anlyses take into account expenses 4 which are unique to a particular alternative.In this case,Acres assumes ethattheCitywillpursuethedevelopmentofafull-capacity diesel piant |regardless of the existence of a Mt.Makushin geothermal plant or the hydroplantsidentifiedbytheCorpsofEngineers.This approach is taken 7because,in the opinion of Acres'staff,the reliability of the Mt.4) Makushin plant and its power transmission line is not sufficiently assured.py The reliability of a single transmission circuit or a single right-of-wayFaddoesnotprovidetheassurancethatpowerwouldbeavailablefromthegeo- thermal project with a small probability of extended outages.The redun-y yr dancy of the extra diesel capacity is relatively cheap insurance againstis'the failure of geothermal plant equipment or its transmission line. ena Thus the only savings wlth be attributed to any of the projects to beevaluated_lis derived i l-which-must he burnedwhneJoybytheCity's diesels to produce electricity.Tacs It Hreusf 2%,;present éeblegeef calculations used to determine they°.\\\relative economics of the wariqus alternatives studied.Following theseystablesisabriefsectionAGShpresentsadiscussionofdecisiontheory and its application to this study. TABLE 11 30 ECONOMIC ANALYSIS OF BASE CASE PLAN (LOW-GROWTH FORECAST)a %feiPOWERENERGYFUELFUELFUELWASTEHEATSALESPRICEREVENUEFROM 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)(Btu)($1000/Btu)($1,000)($1,000)($1,000) 1984 13 34,222)2,852 0.980 2,795 97,253 .0084 817 1,978.0 1,911.1 1985 13 34,324 2,860 1.004 2,872 97,526 .0084 819 2,053.0 1,916.5 1986 13 34,427 2,869 1.029 2,952 97,833 .0086 841 2,111.0 1,903.9 1987 13 34,515 2,876 1.055 3,034 98,072 -0090 883 2,151.0 1,874.4 1988 13 34,627 2,886 1.082 3,122 98,413 .0092 905 2,217.0 1,866.7 1989 13 34,712 2,893 1.109 3,208 98,651 *,0094 927 2,281.0 1,855.6 1990 13 34,794 2,900 1.136 3,294 98,890 .0097 959 2,335.0 1,835.3 1991 13 34,952 2,913 1.165 3,393 99,333 .0099 983 2,410.0 1,830.2 1992 13 35,117 2,926 1.194 3,494 99,777 .0101 1,008 2,486.0 1,824.0 1993 13 35,273 2,939 1.224 3,598 100,220 -0104 1,042 2,556.0 1,811.9 1994 13 35,407 2,951 1.254 3,700 100,629 .0107 1,077 2,623.0 1,796.5 1995 13 35,555 2,963 1.286 3,810 101,038 -0110 1,lll 2,699.0 1,786.2 1996 13 35,721 2,977 1.318 3,923 101,516 .0112 1,137 2,786.0 1,781.4 1997 13 35,921 2,993 1.351 4,044 102,061 .0115 1,174 2,870.0 1,773.1 1998 13 36,097 3,008 1.385 4,166 102,573 -0118 1,210 2,956.0 1,764.4 1999 13 36,235 3,020 1.419 4,285 102,982 0121 1,246 3,039.0 1,752.6 2000 13 36,422 3,035 1.455 4,416 103,494 .0124 1,283 3,133.0 1,745.7 2001 13 36,587 3,049 1.491 4,546 103,971 -0127 1,320 3,226.0 1,736.9 2002 13 36,771 3,064 1.528 4,682 104,482 .0130 1,358 3,324.0 1,729.1 2003 13 36,947 3,079 1.567 4,825 104,994 .0134 1,407 3,418.0 1,717.9 2004-2038 13 37,105 3,092 1.567 4,845 105,437 .0134 1,413 3,432.0 33,331.6 NOTE:ALL COSTS IN 1983 DOLLARS ; TOTAL: 69,545.0 TABLE 12 31 ECONOMIC ANALYSIS OF BASE CASE PLAN (BEST- GUESS FORECAST) POWER ENERGY FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM PRESENT VALUE DEMAND USE USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD TOTAL COSTS OF TOTAL COSTS YEAR (MW)(MWh)(1,000 q)_($/gal)($1,000)(MBtu)($1000/MBtu)($1,000)($1,000)($1,000) 1984 13 34,986 2,916 0.980 2,857 99,436 0084 835 2,022.0 1,953.7 1985 13 36,125 3,010 1.004 3,022 102,641 0084 862 2,160.0 2,016.4 1986 14 37,622 3,135 1.029 3,226 106,904 .0086 919 2,307.0 2,080.7 1987 14 39,005 3,250 1.055 3,429 110,825 .0090 997 2,432.0 2,119.2 1988 14 40,398 3,367 1.082 3,643 114,815 0092 1,056 2,587.0 2,178.3 1989 16 41,982 °3,499 1.109 3,880 119,316 0094 1,122 2,758.0 2,243.6 1990 16 43,371 -°3,614 1.136 4,106 123,237 0097 1,195 2,911.0 2,288.0 1991 16 45,948 3,829 1.165 4,461 130,569 .0099 1,293 3,168.0 2,405.8 1992 7 48,760 4,063 1.194 4,852 138,548 0101 1,399 3,453.0 2,533.5 1993 18 51,384 4,282 1.224 5,241 146,016 .0104 1,519 3,722.0 2,638.5 1994 19 54,195 4,516 1.254 5,663 153,996 .0107 1,648 4,015.0 2,749.9 1995 19 56,782 4,732 1.286 6,085 161,361 .0110 1,775 4,310.0 2,852.4 1996 21 62,348 5,196 1.318 6,848 177,184 0112 1,984 4,864.0 3,110.0 1997 23 67,891 5,658 1.351 7,643 192,938 .O115 2,219 5,424.0 3,350.9 1998 24 73,420 6,118 1.385 8,474 208,624 0118 2,462 6,012.0 3,588.6 1999 26 78,982 6,582 1.419 9,340 224,446 .0121 2,716 6,624.0 3,820.1 2000 27 84,525 7,044 1.455 10,249 240,200 0124 2,978 7,271.0 4,051.4 2001 29 90,077 7,506 1.491 11,192 255,955 .0127 3,251 7,941.0 4,275.4 2002 31 95,200 7,933 1.528 12,122 270,515 .0130 3,517 8,605.0 4,476.3 2003 32 100,764 8,397 1.567 13,158 286,338 0134 3,837 9,321.0 4,684.7 2004-2034 34 106,238 8,853 1.567 13,873 301,887 0134 4,045 9,828.0 95,449.5 NOTE:ALL COSTS IN 1983 DOLLARS TOTAL:154,866.9 TABLE 13 32 ECONOMIC ANALYSIS OF BASE CASE PLAN (HIGH-GROWTH FORECAST) POWER ENERGY FUEL FUEL FUEL WASTE HEAT SALES PRICE =REVENUE FROM PRESENT VALUE DEMAND USE USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD TOTAL COSTS OF TOTAL COSTS YEAR (MW)(MWh)(1,000 q)_($/qal)($1,000)(MBtu)($1000/MBtu)($1,000)($1,000)($1,000) 1984 13 36,427 3,036 0.980 2,975 103,528 .0084 870 2,105.0 2,033.9 1985 14 38,522 3,210 1.004 3,223 109,461 0084 919 2,304.0 2,150.8 1986 16 41,491 3,458 1.029 3,558 117,918 0086 1,014 2,544.0 2,294.4 1987 16 44,242 3,687 1.055 3,890 125,727 -0090 1,132 2,758.0 2,403.3 1988 17 47,173 3,931 1,082 4,253 134,047 0092 1,233 3,020.0 2,542.8 1989 17 49,950 4,163 1.109 4,616 141,958 -0094 1,334 3,282.0 2,669.9 1990 19 52,900 4,408 1.136 5,008 150,313 0097 1,458 3,550.0 2,790.3 1991 20 57,668 4,806 1.165 5,599 163,885 0099 1,622 3,977.0 3,020.1 1992 22 62,493 5,208 1.194 6,218 177,593 -0101 1,794 4,424.0 3,245.9 1993 22 67,137 5,995 1.224 6,848 190,790 0104 1,984 4,864.0 3,448.1 1994 24 71,962 5,997 1.254 7,520 204,498 0107 2,188 5,332.0 3,651.9 1995 25 76,798 6,400 1.286 8,230 218,240 0110 2,401 5,829.0 3,857.6 1996 27 83,437 6,953 1.318 9,164 237,097 -0112 2,655 6,509.0 4,161.9 1997 30 91,706 7,642 1.351 10,325 260,592 -O115 2,997 7,328.0 4,527.2 1998 32 98,262 8,189 1.385 11,341 279,245 0118 3,295 8,046.0 4,802.7 1999 35 106,573 8,881 1.419 12,602 302,842 -0121 3,664 8,938.0 5,154.5 2000 36 113,774 9,481 1.455 13,795 323,302 -0124 4,009 9,786.0 5,452.8 2001 38 121,143 10,095 1.491 15,052 344,240 0127 4,372 10,680.0 5,750.1 2002 41 129,432 10,786 1,528 16,481 367,803 -0130 4,781 11,700.0 6,086.3 2003 43 135,693 11,308 1.567 17,719 =385,603 0134 5,167 12,552.0 6,308.6 2004-2038 46 143,962 11,997 1.567 18,799 409,098 -0134 5,482 13,317.0 129,334.7 NOTE:ALL COSTS IN 1983 DOLLARS TOTAL:205,687.8 TABLE 14 ECONOMIC ANALYSIS OF ALTERNATIVE "A"(WITH 10 MW PLANT) (LOW-GROWTH FORECAST) 33 ENERGY GEOTHERMAL DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM GEOTHERMAL PRESENT VALUE USE PRODUCTION PROD'N USE PRICE COSTS PRODUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR (MWh)(MWh)(MWh)(1000 gq)($/gqal)($1000)(MBtu)-($1000/Btu)($1,000)($1000)($1,000)($1,000) 1984 34,222 ft]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 a)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 1,855.6 1990 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 1,830.2199235,117 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 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 4,440.0199635,721 25,000 10,721 893 1.318 1,178 30,451 0112 341 5,900 6,737.0 4,307.6199735,921 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 3,589.9 2003 36,947 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 SOLO PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR (MWh)(MWh)(MWh)(1000 q)($/qal)($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 0 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 0 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 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 -0115 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 886 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 10,256.5,335.2 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 COSTS YEAR (MWh)(MWh)(MWh)(1000 g)($/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 2,150.81986=«41,491 QO 41,491 3,458 1.029 3,558 117,918 0086 1,014 0 2,544.0 2,294.41987=44,242 0 44,242 3,687 1.055 3,890 125,727 .0090 1,132 i)2,758.0 2,403.31988=47,173 0 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 2,669.91990=2,900 QO 52,900 4,408 1.136 5,008 150,313 .0097 1,458 0 3,550.0 2,790.3199157,668 O 57,668 4,806 1.165 5,599 163,885 0099 1,622 0 3,977.0 3,020.1199262,493 0 62,493 5,208 1.194 6,218 177,593 -0101 1,794 0 4,424.0 3,245.9199367,137 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 5,308.0199576,798 47,000 29,798 2,483 1.286 3,193 84,670 -O110 931 5,900 8,162.0 5,401.6199683,437 47,000 36,437 3,036 1.318 4,002 103,528 0112 1,160 5,900 8,742.0 5,589.6199791,706 47,000 44,706 3,726 1.351 5,033 127,057 0115 1,461 5,900 9,472.0 5,851.8199898,262 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 6,284.32000113,774 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 6,695.52002129,432 47,000 82,432 6,869 1.528 10,496 234,233 -0130 3,045 5,900 13,351.0 6,945.22003135,693 47,000 88,693 7,391 1.567 11,582 252,033 20134 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 36ECONOMICANALYSISOFALTERNATIVE"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)(1000g)($/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 1,911.1198534,324 0 34,324 2,860 1.004 2,872 97,526 -0084 819 0 2,053.0 1,916.5198634,427 0 34,427 2,869 1.029 2,952 97,833 .0086 841 0 2,111.0 1,903.9198734,515 0 34,515 2,876 1.055 3,034 98,072 -0090 883 0 2,151.0 1,874.4198834,627 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 1,855.6199034,794 0 34,794 °2,900 1.136 3,294 98,890 .0097 959 0 2,335.0 1,835.3199134,952 0 34,952 2,913 1.165 3,393 99,333 -0099 983 0 2,410.0 1,830.2199235,117 ft)35,117 2,926 1.194 3,494 99,777 -0101 1,008 0 2,486.0 1,824.0199335,273 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 10,879.6199535,555 24,900 10,655 888 1.286 1,142 30,281 -0110 333 15,100 15,909.0 10,528.6199635,721 25,000 10,721 893 1.318 1,178 30,451 .0112 34]15,100 15,937.0 10,190.1199735,921 25,100 10,821 902 1.351 1,218 30,758 -0115 354 15,100 15,964.0 9,862.6199836,097 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 16,008.0 9,231.8200036,422 25,500 10,922 910 1.455 1,324 31,031 -0124 385 15,100 16,039.09 8,936.9200136,587 25,600 10,987 916 1.491 1,365 31,236 -0127 397 15,100 16,068.0 8,651.0200236,771 25,700 11,071 923 1.528 1,410 31,474 -0130 409 15,100 16,101.0 8,375.7200336,947 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)(131,073.09)(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 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)(Mh)(MWh)(1000 q)($/qal)($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 0 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 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 Q 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 «f 1,293 0 3,168.0 2,405.8199248,760 0 48,760 4,063 1.194 4,852 138,548 .0101 1,399 0 3,453.0 2,533.5199351,384 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 11,169.3199556,782 39,700 17,082 1,424 1.286 1,831 48,558 .0110 534 15,100 16,397.0 10,851.5199662,348 43,600 18,748 1,562 1.318 2,059 53,264 .0112 597 15,100 16,562.0 10,589.7199767,891 47,500 20,391 1,699 1.351 2,296 57,936 -OLLS 666 15,100 16,730.0 10,335.8199873,420 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 9,853.5200084,525 59,200 25,325 2,110 1.455 3,071 71,951 -0124 892 15,100 17,279.0 9,627.9200190,077 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-GROWTH FORECAST) 38 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 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 O 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 2,403.3 1988 47,173 0 47,173 3,931 1.082 4,253 134,047 .0092 1,233 0 3,020.0 2,542.8 1989 49,950 O 49,950 4,163 1.109 4,616 141,958 .0094 1,334 0 3,282.0 2,669.9199052,900 i)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 3,245.9199367,137 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 11,435.81995'76,798 53,800 22,998 1,917 1.286 2,465 65,370 .0110 719 15,100 16,846.0 11,148.7199683,437 58,400 25,037 2,086 1.318 2,750 71,133 .0112 797 15,100 17,053.0 10,903.7199791,706 64,200 27,506 2,292 1.351 3,097 78,157 .OL1S 899 15,100 17,298.0 10,686.7199898,262 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 10,254.92000113,774 79,600 34,174 2,848 1.455 4,144 97,117 .0124 1,204 15,100 18,040.0 10,051.92001121,143 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 20134 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 "B"(WITH BOTH HYORO 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 PROOUCED OF WASTE HEAT WASTE HEAT SOLD PLANT COSTS TOTAL COSTS OF TOTAL COSTS YEAR (MWh)(MWh)(MWh)(1000 g)($/gal)($1000)(MBtu)-($1000/m8tu)($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 a)34,324 2,860 1.004 2,872 97,526 .0084 819 0 2,053.0 1,916.5 1986 34,427 1)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 20110 943 460 2,749.0 1,819.3 1996 35,721 5,400 30,321 2,527 1.318 3,330 86,171 .O112 965 460 2,825.0 1,806.3 1997 35,921 5,400 30,521 2,543 1.351 3,436 86,716 -O11L5 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 NOTE: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 (MWh)(MWh)(MWh)(1000 q)($/qal)($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 0 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 5,400 36,582 3,049 1.109 3,381 103,971 -0094 977 460 2,864.0 2,329.9 19900 43,371 5,400 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 89,800 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 1.567 713,168 286,542 -0134 3,840 50 9,378.0 32,401.0 NOTE:ALL COSTS IN 1983 DOLLARS TOTAL:159,786.3 TABLE 22 4)ECONOMIC ANALYSIS OF ALTERNATIVE"8"(WITH BOTH HYDRO PLANTS)CHIGH-CGROWTH FORECAST) ENERGY HYDRO DIESEL FUEL FUEL FUEL WASTE HEAT SALES PRICE REVENUE FROM HYDRO PRESENT VALUE -YSE 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 q)($/qal)($1000)(MBtu)-_($1000/m8tu)($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 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 2,403.3 1988 47,173 0 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 2,755.3 1990 52,900 5,400 47,500 3,958 1.136 4,497 134,968 .0097 _1,309 460 3,648.0 2,867.3 1991 57,668 5,400 52,268 4,356 1.165 5,074 148,540 0099 '1,471 460 4,063.0 3,085.4 1992 62,493 5,400 57,093 4,758 1.194 5,681]162,248 .0101 1,639 460 4,502.0 3,303.1 1993 67,137 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 3,693.0 1995 76,798 5,400 71,398 5,950 1.286 7,651 202,895 -0110 2,232 460 5,879.0 3,890.7 1996 83,437 5,400 78,037 6,503 1.318 8,571 221,752 -0112 2,484 460 6,547.0 4,186.2 1997 91,706 5,400 86,306 7,192 1.351 9,717 245,247 .0115 2,820 460 7,357.0 4,545.2 1998 98,262 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 5,158.6 2000 113,774 5,400 108,374 9,031 1.455 13,140 307,957 .0124 3,819 460 9,781.0 5,450.0 2001 121,143 5,400 115,743 9,645 1.491 14,381 328,895 .0127 4,177 460 10,664.0 5,741.5 2002 129,432 5,400 124,032 10,336 1.528 15,793 352,458 .0130 4,582 460 11,671.0 6,071.3 2003 135,693 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 Ill through 22 have provided net present worth estimates for all four of the energy-supply alternatives considered for Unalaska.These wyestimatesaresummarizedinTable23,below:4 Ae /fy / TABLE 23 Of poTOTALPRESENTWORTHOFALTERNATIVESjeGATEACHGROWTHRATESTUOIEDf (Costs shown are in millions of 1983 dollars) FUTURE GROWTH RATES ALTERNATIVE LOW BEST GUESS /HIGH 1.Base Case (Diesels)69.5 154.9 y 205.7 Tle2.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 quiteqbvious.> 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. »\r-17 ye 43 J -ENVIRONMENTAL AND SOCIAL IMPACTS ou daresItis,expected that of the alternatives examined by this report would have -wempFnegative 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 afteeees by the development of ahydroprojectonShaishnikofRiver.In 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 GEQTHERMAL,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 1384 334 W.Sth Ave. Anchorage,AK 99501 ALASKA POWER AUTHORITY, Subject:Electrical Power Generation Economic Analysis NCHORAGEContractCC08-2334,Amendment No.6 ANCH 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 LTS.and operation and maintenance (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"PAIS!¥The two power plant sizes are derived by superimposing the installed capacity of all units over the estimated power KLdemandasshownontheattachedfigures.To ensure that power |will be available during both normal and emergency operations, 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 in a . 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 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.MThis requires a total equity investment of $101,158,000 having a 1983 present value of $45,984,000 if discounted back ata 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 £18] 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.Table I -Capital cost estimate for the development of a 10 MW gross (6.7.MW net)geothermal power plant. 2.Table II -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 III -Capital cost estimate for the development of a 30 MW gross (20 MW net)geothermal power plant with the wells drilled asneededineachphdseofplantdevelopment. 4.Table IV -Operation and maintenance cost estimate for a 10 MW gross (6.7 MW net)geothermal plant development. 5.Table V -Operatton 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 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 gtve 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 injection well.This provides for almost a full spare production well when the plant ts 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 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 kvtransmissionlinefromthepowerplantsitetoasubstationin 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 construction 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 burying the cable approximately 30"underground from the power plant site to Broad Bay and then going underwater to Outch 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 uncertainties about the underwater portion of the line which has to be buried in the ocean floor. Escalation Escalation 1s 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 (0&M)costs estimates show the total annual cost in 1983 dollars to operate and maintain the overall geothermal 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. TABLE I NO-BOTTOMFISHING DEVELOPMENT CASE UNALASKA 10 MW GROSS (6.7 MW NET)BINARY POWER PLANT DEVELOPHENT COSTS IN THOUSANDS OF DOLLARS Total 1985 1986 1987 1988 Costs Field Development Costs (1983) Production Wells (2)3,747 2,352 0 0 6,099 Injection Well (1)1,600 0 0 0 1,600 Well Testing 521 236 0 0 757 Direct Operation &Maintenance 513 526 426 734 2,199 Home Office 475 600 400 525 2,000 Start-Up 0 0 0 210 210 Subtotal Field Costs 6,856 3,714 826 1,469 12,865 Power Plant Costs (1983) Power Plant Eng.&Const.0 2,504 10,516 7,010 20,030 Production Pipeline 0 0 963 0 963 Injection Pipeline 0 0 0 453°453 Spare Parts 0 0 0 200 200 Consulting &Coordination 162 200 200 238 800 Start-Up 0 0 0 400 400 Insurance 0 0 130 130 260 Subtotal Power Plant Costs 162 2,704 11,809 8,431 23,106 Other Costs (1983) Road Construction 0 5,146 0 0 5,146 Transmission Line 0 0 0 6,405 6,405 Subtotal Other Costs 0 5,146 0 6,405 11,551 TOTAL COSTS (1983)7,018 11,564 12,635 16,305 47,522 Escalation 1,017 2,602 3,927 6,564 14,110 TOTAL ESCALATED COSTS 8,035 14,166 16,562 22,3869 61,632 Interest Expenses 259 978 2,018 3,399 6,654 TOTAL DEVELOPMENT Costs 8,294 15,144 18,580 26,268 638,286 Equity 4,147 7,572 9,290 13,134 34,143 Debt 4,147 7,572 9,290 13,134 34,143 TOTAL USE OF FUNDS 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 t 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 11 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 At}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 §21 354 354 0 1,229 0 0 0 0 0 0 1,229 §13 526 526 734 2,299 426 =,734 1,160 426 734 1,160 4,6194756006005252,200 400 *625 925 400 §25 925 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 QO 2,504 10,516 7,010 20,030 10,015 10,015 20,030 10,018 10,015 20,030 60,090009630963963096332503252,251 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 QO 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 QO 5,146 0 6,405 11,551 0 0 0 0 0 0 11,551 7,018 15,334 19,293 16,305 §7 ,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 3,125 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 2n2 ,316 Field Development Costs (1983) Production Wetls (5) Injection Wells (3) Well TestingDirectOperation &Maint. Home Office Start-Up i 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 CASE UNALASKA 30 MW GROSS (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 199]1992 Second Phase 1998 1999 Third Phase All Phases 3,747 2,352 0 0 6,099 5,799 0 5,799 3,747 0 3,747 15,6451,600 i)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 4,7194756004005252,000 600 £625 1,125 600 525 1,125 4,250000210210Q1501500100100460 6,856 3,714 826 1,469 12,865 8,879 1,409 10,288 6,709 1,359 8,068 31,221 QO 2,504 10,516 7,010 20,030 10,015 10,015 20,030 10,015 10,015 20,030 60,090009630963963096332503252,25}0 0 0 453 453 0 453 453 0 453 453 1,35900020020002002000200200600 162 200 200 238 800 200 200 400 200 200 400 1,60000040040002002000150150750 0 0 130 130 260 0 130 130 0 130 130 §20 162 «2,704 11,809 8,431 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 O 5,146 0 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 14,166 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 26,248 68,286 35,558 26,174 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 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 8i- =PEAK LOAD DEMAND 6 kK 5 } - BASE LOAD DEMAND PCE OEE DE VO RN GON DE ONO ODN SN DN GSS DSU MN NS SIN DN DN MU 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 YEARS ae AGI E1594 NO BOTTOMFISH DEVELOPMENT CASE POWER PLANT DEVELOPMENT SCHEDULE ELECTRICALPOWERDEMAND-MW6.7MW(NET)COMPOSEDOF2IDENTICALUNITSBINARYGEOTIWERMALPOWERPLANTel]orea !L !L !f !L L0 1985 1987 1989 1991 1993 1995 1997 1989 2001 2003 2005 2007 ) YEARS a>DIESELGENERATORS--pe4X2.5MWAGI E1529 NO BOTTOMFISH DEVELOPMENT CASE POWER GENERATION-NORMAL OPERATION ELECTRICALPOWERDEMAND-MWALL UNITS AVAILABLE PEAK LOAD DEMANDEe BASE LOAD DEMAND eeencnnnSraaSSSnSAERS 3h aun of 2- 1 a 0 ee 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS AGI E1528 ee ee NO BOTTOMFISH DEVELOPMENT CASE POWER GENERATION-EMERGENCY OPERATION LARGEST UNIT DOWN AND SECOND LARGEST UNIT TRIPPED ' eb Le one |.©ope ©am ©ome 0 ame 0 ome ©ce 2 ee ee 2 a ©=©a 6 am 6 oem ©- 1 PEAK LOAD DEMAND canceennanseel -- |ELECTRICALPOWERDEMANDMW0 en ES SS SO19851987198919911993199519971999200120032005 2007 YEARS RG!E1527 ELECTRICALPOWERDEMAND-MW.C7LOW BOTTOMFISH CATCH CASE ELECTRICAL GRID LOAD FORECASTS I !|!!J J i I J !yt !1 it ! 1986 1988 1990 1992 1994 1996 1998 2000 YEARS 2002 2004 re (AGI E1633 LOW BOTTOMFISH CATCH CASE POWER PLANT DEVELOPMENT SCHEDULE ELECTRICALPOWERDEMANDanes36 BINARYGEOTHERMALPOWERPLANTSener,3X6.7MW(NET)PLANTSEACHINCLUDING2IDENTICALUNITS{{I !}{0 1985 1987 1989 1991 1993 1895 1997 1999 2001 2003 2005 2007 YEARS -----fo|0dDIESELGENERATORS4X2.5MWUNITSAGI &1§31 LOW BOTTOMFISH CATCH CASE POWER GENERATION-NORMAL OPERATION ALL UNITS AVAILABLE ELECTRICALPOWERDEMAND4 ee ee OO SO SO19851987198919911993199519971999200120032005 2007 YEARS RGI E1$29 LOW BOTTOMFISH CATCH CASE POWER GENERATION-EMERGENCY OPERATION LARGEST UNIT DOWN FOR MAINTENANCE AND SECOND LARGEST UNIT TRIPPED ELECTRICALPOWERDEMAND0 l es Ss 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS RGi E1830 APPENDIX B ALASKA POWER AUTHORITY PROJECT EVALUATION GUIDELINES MAR 2&8 198 ALASKA POWER AUTHORITY 334 WEST 5th AVENUE -ANCHORAGE,ALASKA 99501 Phone:(907)277-7641 (907)276-0001 ANCHORAGE ,ACRESMarch28,1984 AMERICAN ec, 7 FILE NO. Mr.Jim Landman Pr (,Go)Acres American,Inc.SEQ.NO.1577 C Street,Suite 305 y //Anchorage,Alaska 99501 inDteaBle|ear man:g A (>The Alaska Power Authority's economic analysis guidelines appear to ---4-be unrealistic with respect to the economic life and term of |_ifinancingofgeothermalpowerfacilities.Several outside sources KL.experienced in géothermal development have confirmed that aegeothermalsystemscanbeexpectedtohavea30-year economic life iandthat25-year financing is generally accepted.For your econom-.|--- }y ic analysis of the geothermal alternative for the Unalaska recon-ae naissance study,please use these figures in place of the 15-year aeconomiclife/15-year financing recommended in past Power Authority |_. Dave Denig-Chakroff Project Manager DDC/ms 544/173/D1/F1 !Jucy Ge Cererent 2/1} 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 conditions would preclude the Authority from acting in keeping with its purpose. 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 by environmental,socioeconomic and public preference constraints.The method attempts to identify the real economic resource costs of all options under study;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 and--energy cost trends;(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 oeProject Evaluation Procedure Page 2 the preferred plan;(6)evaluating the preferred plan's cost of powerunderavarietyoffinancingarrangementsinrelationtoanticipatedpowercostswithouttheplan;and (7)identifying those financingarrangementswhichresultinacceptablepowercosts. Forecasting Future Requirements. A planning period is first adopted to define the period of time over which forecasts are developed and energy plans are formulated.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 of alternatives: 1.All reasonable alternative means of providing each end use are identified. The per unit cost of energy is determined for each alternative2. 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 lag time for substitution of energy forms.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 identifyina 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 peakloadrequirementsovertheplanningperiod. 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 needs should be met to a significant extent by electrical energy,then plans are formulated to meet both thermal and electrical requirements.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 is termed the "base case plan";this plan is developed assuming a continuation of existing practice in the study area and is used as a common yard stick for comparison of the other plans. 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. steam,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 enduserequirementsratherthansimplyelectricalenergyneeds. 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 in future years reflect relative price changes only.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 andfutureprices."The Task Force endorses either "life-cycleanalysis"(which includes inflation)or "inflation freeanalysis".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 thattherelativeplancostsbecomparedovertheeconomiclifeof the projects under consideration.When hydroelectric and steam plant projects are being addressed,the economic evaluation period exceeds the 20 (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 Toad 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 benefits are equal to the gross benefits associated with a plan,less plan cost. The benefits 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: 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. 1. 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 Cost Case 100 A 120 B 90 Case Evaluation - benefits:100 cost:100 net benefits:0 benefit/cost ratio:l 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 Subsidiary Net Benefit 10 15 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 years 0%#£-Thereafter Cost of Power Analysis Inflation Rate -7.0% Project Debt to Equity Ratio -1:0 Cost of Debt -12.03% 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 10 20 15 30 20. economic life is by unit and not total plant capacity. years years years years years years yearsyears. years years years years years years years years -a Lfl*tFsg > 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,national and local economists,and Investment Brokerage Firms,the forecast ofdistillatefuels(diesel and fuel oil)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 with Financial Institutions and Energy consulting Firms forecast the National 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 fortheprevious12monthperiodasdeterminedfromtheWeeklyBondBuyers30yearindexofrevenuebonds.This average is currently approximately13%.It is anticipated that the average will decrease only slowly.during:the 1983 fiscal year. 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 decreasingparticipationoftheRuralElectrificationAdministrationinproviding federal low interest financing. 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 for new hydroelectric projects.As a result the economic life of a new hydroelectric project is set at 50 years and the term of financing at 35 years.For all other alternative generation sources,the economic life and the term for which financing can be obtained is assumed to be the 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 Waste Heat Recapture Equipment 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 TurbinesSteamTurbines(Including Coal *and-Wood-fired Boilers) Onder 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. The following economic Also this REFERENCE Inflation Rate Discount Rate Fuel Escalation Rate Or.Scott Goldsmith . I.S.E.R.6.0%3.0%2.3% Or.David Reaume Economic Consultant 7.0%3.0%2.6% Lehman Brothers, Kohn Loeb 5.0 -6.0%.3.0 -3.5%2.8% Or.Bradford Tuck : University of Alaska 6.0%3.5%2.65% Donald MacFayden , Salomon Brothers 6 -8%4.02%3.0 -4.0% Peter W.Sugg URS/Cloverdale &. Colpitts-6.0 -7.0%4.042%4.0% Gary Anderson, Stanford Research Institute 7.0%|4.0 -4.04%3.0% Or.Mike Scott Battelle Pacific N.W.Lab.5.0 -7.0%3.0%2.7% Mr.Thomas ThurberDataResources,Inc.625%3.0%2.0% Victor A.Perry III Bechtel Corp.5.0%3.0%2.5% William L.Randall The First Boston Corp.7.0 -8.0%3.5%3.0 -3.5% Wm.Micheal'McHugh Applied Economics Associates 7.0 -8.0%3.5%3.0 -3.5% Fredric J.Prager . Smith,Barney,Harris .Upnam &Company 5.0 -6.0%4.0%2.5% John Oelrocali Wharten Econometric Fotcasting Asso.7.0%3.5%2.3% Michael G.Moroney Peat,Marwick & Mitchell.Inc.6.5%3.0%2.5% E¢-07.7) ALASKA GEOTHERMAL ENERGY The Hawaiians called her Pele,the Greeks christened him Hephaistos and the Latins Vulean:terrifying deities that could unleash the catastrophic forces from within the insides of the earth.Today,these forces can be harnessed in the form of environmentally benign,potent and abundant geothermal energy. Much of the earth is composed of molten rock under several miles of solid crust. A geothermal "anomaly"is when this hot molten rock comes closer to the ground because of a variety of reasons.An extreme form of a geothermal anomaly is of course a voleano.Either past or future voleanoes can form ideal geothermal sites.The other necessary conditions for a geothermal field is the presence of water which,trapped and heated for centuries,can serve as the medium for the energy transport. Historically,commercial application of geothermal energy for generating electricity dates back to 1906 in Italy and more recently in New Zealand,Mexico, Iceland,Indonesia,the Philippines,Japan and the United States.The most intense development of geothermal energy is in Northern California,where there is a match between large resources of geothermal power and a demand for it. The world's foremost geothermal field is at The Geysers just north of San Francisco.The current capacity of power production is expected to double (2000 megawatts by 1990),more than enough to meet the demands of San Francisco.The Wairakei Geothermal Field is New Zealand,representing another type of geothermal field with "two-phase"fluid has been producing 150 MW of power since 1958. A "vapor-dominated"field like the one in The Geysers or Larderello and Travale in central Italy is simple to operate.The naturally occuring steam drive turbines that produce power.The "two-phase"systems as the ones in New Zealand,Philippines,and Indonesia normally use a separator,splitting the fluid into steam and liquid with the first turning of the turbine. Geothermal energy,especially when the temperature of the fluid is not high enough for power production,can be used in a number of other applications such as space heating,light industries and agriculture. Alaska includes some of the world's most exciting geothermal prospects capable of producing both high "enthalpy"fluids that could be used for power generation and low "enthalpy"fluids that could be used directly. Not all voleanoes are created equal in their potential for driving high temperature hydrothermal systems.The classic major geothermal reservoirs around the world are all associated with young (less than one million years old)voleanice systems of a particular type;those which produce a rhyolitie lava through the direct melting of the shallow crust of the earth.Alaska has 55 active volcanoes,most of them in the Peninsula and the Aleutian chain.Several of these may have high temperature geothermal resources. Although they are of the andesitie type which derives its lava from deep within the earth's interior,it is often possible that magma on its way to the surface may be trapped under the voleaniec pile and can serve as a significant heat source.Some spectacular surface manifestations occur all along the Aleutian chain in places such as Atka,Umnak and Akutan. The international geothermal community is watching with great interest the progress of the geothermal project at Makushin Volcano,on Unalaska Island in the Aleutians.A 2,000 foot test well,ST-1,drilled in the summer of 1983 with a $5 million appropriation from the Alaska state legislature,and managed by the Alaska Power Authority,has revealed a highly productive geothermal reservoir that can easily sustain major power development.We have estimated that just one commercial size well,using new power conversion technology,could sustain close to a 10 MW plant,very near the present electrical needs of the Island.The total potential of the reservoir may exceed several hundred MW. Other sites in Alaska where geothermal exploration has been undertaken include Pilgrim Springs near Nome where six wells,the last drilled in 1982,have proven a shallow,(100 feet deep)geothermal reservoir containing almost boiling water. One of the problems associated with geoheat is the transportability factor.The unit cost of the geothermal energy delivered to the user must be competitive with other sources of energy/heat.Since the production costs at the wellhead depend primarily on the reservoir characteristics of the field,the distribution costs are determined by a number of local factors.The long distance transmission cost is the principal problem. Geothermal fluids cannot be transported,so direct use must be very close to the site.On the other hand power transmission is more flexible but a much smaller number of reservoirs is capable to sustain electricity production. This is somewhat of a problem in Alaska.While the State has perhaps as many geothermal resources as the rest of the United States combined,the scarcity of the population centers prevents full utilization.Across the mid-section of the State there is a belt of very prolific,high temperature Hot Springs such as Chena Hot Springs,Manley Hot Springs,and Circle Hot Springs that all could supply enormous quantities of hot water.But with the exception of minor recreational development no other application is now in the horizon. Southeast Alaska,amid stunning beauty,contains many natural geothermal manifestations.Hot Springs near Sitka (Goddard)and Tenakee have for years seemed as local tourist attractions.A modest drilling program at Tenakee Hot Springs showed promising results for possible future village-wide geothermal heating.In the Copper River Valley,some impressive "mud"voleanoes are now the center of exploration to assess their geothermal potential. The choice of all these sites coincides with the possibility of using geothermal energy because of their proximity to population centers.On Unalaska,a fishing and, quite possibly petroleum exploration center,the demand for power is expected to justify a fairly rapid geothermal energy development. Other sites may follow through in utilizing this abundant and alternative form of Alaskan energy. THE AUTHORS: Dr.Michael J.Economides has been the geothermal consultant to three State agencies and has been involved with almost all geothermal activities in Alaska.He has worked at The Geysers,New Zealand,Italy and Greece and has published extensively on major geothermal projects.He is now with the Petroleum Engineering Department at the University of Alaska,Fairbanks. Dr.John W.Reeder is a geologist with the Alaska State Geological Survey in Anchorage.He has done major work on geothermal investigation for most sites in Alaska.He is considered as one of the originators of the Unalaska geothermal development. SUGESSTED PHOTOGRAPH CAPTIONS Row 1 1.Artist's illustration for a geothermal system showing the heat source (geothermal anomaly),the fluid reservoir,a production well,a power plant and an injection well. (Courtesy Republic Geothermal Inc.) 2.New Zealand's Wairakei Geothermal field in the North Island of New Zealand.The field,one of two major ones in that country has been producing 150 MW of electricpowersince1958.(Photo by Dr.Christine Ehlig-Economides) 3.Okmok Caldera on Umnak Island in the Aleutian Chain.One of the world's most symmetrical calderas.(Photo by Dr.John Reeder) 4.Spectacular warm mud lake on Atka Island,one of the many surface geothermalmanifestationsonthatisland.(Photo by Dr.John Reeder) Row 2 1.Recently errupted Akutan voleano on Akutan Island.(Photo by Dr.John Reeder) 2.Fumarolic activity on Atka Island.High pressure steam roars through a crack in theground.(Photo by Dr.John Reeder) 3.Magnificent Makushin Volcano on Unalaska Island as seen from Makushin Valley.The flanks of the voleano have been the site of a three year exploration and drilling project financed by the State of Alaska.A highly productive geothermal reservoir has been discovered,capable of producing electric power many times the present needs of the Island and its large fishing industry.(Photo by Dr.Michael Economides) 4,The summit of Makushin Voleano at 6,100 feet and one of the Aleutians most active voleanoes,errupting many times in recent history.(Photo by Dr.MichaelEconomides) Row 3 1.One of the main fumarole fields on the flanks of Makushin Voleano.The field covers an area of 1/2 by 1 kilometers.(Photo by Dr.John Reeder) 2.High pressure fumaroles on the south flank of Makushin Voleano -Unalaska Island. (Photo by Dr.John Reeder) 3.Exploration well ST-1,drilled in the summer of 1983.At 1950 foot depth,the slimhole(3"diameter)test-well is capable of producing 50,000 pounds of fluid per hour. A commercial size well (12"diameter)has been estimated as capable of producing 880,000 pounds of fluid per hour,enough to supply 6-10 MW of electric power depending on the technology used.Just one well can supply the domestic electric power needs of 6,000 to 10,000 people.(Photo by Dr.John Reeder) 4,Pilgrim Springs near Nome,site of a 1978 -1982 exploratory drilling project.Six wells have been drilled on the field revealing a hot and very shallow geothermal reservoir that would be ideal for space heating,agriculture,and light industry.The Kigluaik Mountains loom in the horizon.(Photo by Dr.M.J.Economides) Row 4 2.The drilling rig at work at Pilgrim Springs.(Photos by Dr.M.J.Economides) 3.Artesian flow from very shallow geothermal well at Pilgrim Springs.(Photo by Dr.M.J.Economides) 4,Idyllie Tenakee Springs in Southeast Alaska,where natural Hot Springs occur. Geothermal space heating is feasible if the economics prove attractive.(Photo by Dr.John Reeder) Row 5 1.Lower Klawasi Mud Voleano in Copper Valley near Copper Center.This mud voleano,one of the largest anywhere,is presently the site of exploration for theidentificationofthearea's geothermal potential.(Photo by Dr.John Reeder at 45° below) 2.Geothermal exploration in these remote areas has not been without hazards,such as this crashed helicopter during our work on Makushin Voleano.,(Photo by R.Yarder) SS LIAS = ,rtPy 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 MAR071984 334 W.Sth Ave. Anchorage,AK 99501 ALASKA POWER AUTHORITY Subject:Electrical Power Generation Economic Analysis Contract CC08-2334,Amendment No.6 Dear Dave; As requested in your February 2,1984 letter,please find enclosed a draft of the economic feasibility section of the subject report.This section addresses the estimated capital and operation and maintenance (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. The two power plant sizes are derived by superimposing the installed capacity of all units over the estimated power demand as shown on the attached figures.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 separate section of the report. 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.MThis requires a total equity investment of $101,158,000 having a 1983 present value of $45,984,000 if discounted back ata 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 £18] 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.Table I -Capital cost estimate for the development of a 10 MW gross (6.7.MW net)geothermal power plant. 2.Table II -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 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. 4,Table IV -Operation and maintenance cost estimate for a 10 MW gross (6.7 MW net)geothermal plant development. 5.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 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. 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 injection well.This provides for almost a full spare production well when the plant is operated at full capacity and ensure adequate power generation itn 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 1s 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 placeduringspringandsummermonths(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 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 ts ready to receive major equipment as 1t is unloaded from the barge,road construction ts 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 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 will 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. d.Escalation Escalation is based on an annual inflation rate of seven percent. e.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 geothermal 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. TABLE I NO-BOTTOMFISHING DEVELOPMENT CASE UNALASKA 10 I4W 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 1,600 0 0 0 7,600 52)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 22,369 61,632 259 978 2,018 3,399 6,654 8,294 15,144 18,580 26,268 638,286 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. Hone 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 [1 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 199]1992 Second Phase 1998 1999 Third Phase All Phases 3,747 4,404 4,404 0 12,555 0 0 0 0 0 0 12,5551,600 1,600 1,600 0 4,800 0 0 0 0 0 0 4,80052135435401,229 0 0 0 0 0 0 1,229 513 526 526 734 2,299 426 734 1,160 426 734 1,160 4,6194756006005252,200 400 525 925 400 525 925 4,05000021021001501500100100460 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 60,090009630963963096332503252,251000453453045345304534531,35900020020002002000200200600 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 11,809 8,431 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 O 5,146 0 6,405 17,551 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 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 INT LOW-BOTTOMFISH CATCH CASE UNALASKA 30 MW GROSS (20 MW NET)BINARY POWER PLANT DEVELOPMENT COSTS IN THOUSANDS OF DOLLARS WELLS DRILLED AS NEEDEO IN EACH 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 2,352 0 0 6,099 5,799 0 5,799 3,747 0 3,747 15,6451,600 0 0 0 1,600 1,600 0 7,600 1,600 0 1,600 4,80052123600757354035423602361,3475135264267342,199 526 734 1,260 526 734 1,260 4,7194756004005252,000 600 525 1,125 600 525 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 QO 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 2,25]0 0 0 453 453 0 453 453 0 453 453 1,35900020020002002000200200600 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 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 0 5,146 0 6,405 11,551 0 0 0 0 i¢)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 14,166 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 26,768 68,286 35,558 26,176 61,734 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 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 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 8k Ue PEAK LOAD DEMAND 6k 5 oe BASE LOAD DEMAND4)|cscanumerenn st ASSESSES LE LO I 0 I I !!!!i !I I !!!!I l !!{| 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 YEARS -e RGI E1534 NO BOTTOMFISH DEVELOPMENT CASE POWER PLANT DEVELOPMENT SCHEDULE 6.7MW(NET)COMPOSEDOF2IDENTICALUNITS"BINARYGEOTHERMALPOWERPLANT<r7-PEAK LOAD DEMAND §ELECTRICALPOWERDEMAND-MWwJ'--pe|-edDIESELGENERATORS|4X26MW5=-P-_©a ©a ©aE ©aD 6 oe 6 ae ©ame ©ae 6 ame ©ae 6 am 0 oe 0 ame 6 -_- 4 BASE LOAD DEMAND 3- 0 en Se OS SS SN OS 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS AGI £1529 NO BOTTOMFISH DEVELOPMENT CASE POWER GENERATION-NORMAL OPERATION ELECTRICALPOWERDEMAND-MWALL UNITS AVAILABLE 8 = 5S-oo --« 4 BASE LOAD DEMAND 3 ooma 2 1 a 0 es ee 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS 7h PEAK LOAD DEMAND op Ces THERIWH4: RGt €1528 "NO BOTTOMFISH DEVELOPMENT CASE POWER GENERATION-EMERGENCY OPERATIONLARGESTUNITDOWNAND SECOND LARGEST UNIT TRIPPED ELECTRICALPOWERDEMAND-MWCr2 be i =- 7r PEAK LOAD DEMAND. | | 4 BASE LOAD DEMAND |i l !I !i I 10. 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS RG!E1527 ELECTRICALPOWERDEMAND-MWLOW BOTTOMFISH CATCH CASE ELECTRICAL GRID LOAD FORECASTS Ld=cz.TFy a SR SN DN PN GON NN GN OS DO DON GON SOON GN GN OO TS DO 1904 1986 1988 1990 1992 1994 «1996 1998 =2000 2002 «2004 YEARS =e AGI E1633 LOW BOTTOMFISH CATCH CASE POWER PLANT DEVELOPMENT SCHEDULE ae36 34 3X6.7MW(NET)PLANTSEACHINCLUDING2IDENTICALUNITSELECTRICALPOWERDEMANDBINARYGEOTHERMALPOWERPLANTSoa ©a=6 oo 6.eee @ <,. 12 i I 4 8 oem ¢aw 6 au ¢au «é a S6i.= 4 29goeaeeeeeees122as 0 en 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS RG!E1531 LOW BOTTOMFISH CATCH CASE POWER GENERATION-NORMAL OPERATION ELECTRICALPOWERDEMANDALL UNITS AVAILABLE 4 e 36 = 34 = 32 = 30 os Ss _DinseEe ole Back ve 'Gtormecemn 'Ro WE RR: °0 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 YEARS AGI £1529 LOW BOTTOMFISH CATCH CASE POWER GENERATION-EMERGENCY OPERATION LARGEST UNIT DOWN FOR MAINTENANCE AND SECOND LARGEST UNIT TRIPPED Fuct Poorer 74e [=| =z < = babel [=| 7 Des EE =Bacev? < bo [oad poms oJ fed _l tad Geovneem AL 'PowER: 0 {es es ee es Se19851987198919911993199519971999200120032005 2007 YEARS RGI E1530 2F.907-4] University of Alaska PETROLEUM ENGINEERING DEPARTMENT ROOM 17,DUCKERING BUILDING FAIRBANKS,ALASKA 99701 PETROLEUM ENGINEERING (907)474-7734 February 14,1984 RECEIVED Mr.David Denig-Chakroff Project Manager FEB}?1884AlaskaPowerAuthority 334 West Sth Avenue ALASKA POWER AUTHORITYAnchorage,Alaska 99501 Dear David: Please find enclosed two copies of my work on the reservoir evaluation based on present data from the Unalaska project. Two bound copies of this report are forthcoming.Feel free to disseminate the contents to any interested parties.Republic Geothermal has a number of copies already,since this is a revised version of my analysis with Don Campbell. Sincerely, oO2 M.J.Economides Assistant Professor Petroleum Engineering Department MJE:djl DATA FROM STRATIGRAPHIC TEST WELL NO.1 MAKUSHIN VOLCANO,UNALASKA ISLAND by Don A.Campbelltand Michael J.Economides TRepublic Geothermal,Inc.,Santa Fe Springs,CA. 2University of Alaska,Fairbanks,AK. ABSTRACT Geothermal resource investigations have been conducted for the past four years on Unalaska Island,in the Aleutian Chain.The focus of the work has been Makushin Voleano,about 12 miles from the cities of Unalaska and Dutch Harbor. In the summer of 1982,three widely spaced deep temperature 'gradient holes were drilled,which encountered high temperatures. During the Summer of 1983,a three inch diameter "slim hole" well,ST-1,was drilled to 1,949 feet.A shallow,low pressure, stean zone and a relatively productive hot water zone at total depth were encountered.The lower zone produced 47,000 lb/hr, limited by reaching critical mass velocity at the orifice.The static bottom hole pressure and temperature were 478 psig and 379°F,respectively. Analysis of transient pressure and flow data yielded a productivity index of 3,470 1b/hr/psi and a permeability- thickness of 50,900 md-ft for the three foot (at the wellbore) lower zone fracture.A preliminary reservoir/wellbore flow evaluation for a possible power plant indicates two commercial size wells could easily fuel a 10 megawatt facility. INTRODUCTION Unalaska Island,located approximately 990 miles southwest of Anchorage,Alaska,is one of the Fox Islands in the central portion of the Aleution Islands are (Figure 1).Makushin Volcano,the 6,680-foot high active volcano situated on the northern end of Unalaska Island,has numerous fumarole fields on its eastern.flanks,indicating the presence of geothermal resources beneath the volcano.- The cities of Unalaska and Dutch Harbor,which together comprise the primary northern Pacific port for the crabbing and bottom fishing industries,are located approximately 12 miles east of Makushin Volcano on Unalaska Bay.The area's electrical demand _of approximately 11 megawatts is presently satisfied by diesel generators.Because fossil fuel costs (and thus electric power costs)are high on Unalaska Island,both the local community and the state-of Alaska have been interested in evaluating the potential for economically exploiting geothermal energy.To this end,in late 1981 the Alaska Power Authority (APA),advised by. the University of Alaska and the Alaska Geological Survey,. contracted with Republic Geothermal,Ine.(Republic)to explore the vicinity of Makushin Volcano for geothermal resources.The multiyear exploration project was to _include geological, geochemical,and geophysical field work and culminate in the drilling and testing of a resoucre exploration well.Should a commercial resource be identified,additional work beyond the scope of the project could lead to the construction of a small geothermal electrical generating facility to provide economical, reliable electrical energy for the island. This report first briefly reviews the results of the 1982 exploration program,principally data from three thermal gradient holes and the geothermal resource model developed.The focus of the discussion which follows thereafter is the data from the drilling and testing of the first stratigraphic test well,ST-1, completed during the summer of 1983. DRILLING OPERATIONS AND LOGISTICS| Drilling operations and logistics were unique in many respects because they were significantly influenced by a combination of _rugged topography,limited access,available equipment,and adverse weather.The topography of northern Unalaska Island,is a mixture of glaciated (U-shaped)valleys,cirques,and aretes; volcanic (lava and pyroclastic)plateaus and cliffs;and deep, steep-sided stream and river valleys.Areas of reasonably gentle relief capable of adequately accommodating a deep wellsite (without the need for extensive earthmoving)were limited over much of the geothermal area. The rugged topography also limited overland access to the area. Although these problems should not prevent the construction of a road if a power plant is eventually built,budget limitations required that both the exploration program and the deep well . drilling be supported entirely by helicopter. Weather probably provided the biggest operational constraint, because it limited the project to a relatively short summer field season (approximately May 1 to September 15).Snow was up to eight feet deep at the base camp plateau (1,200 feet)in mid-May, and remained on the ground at that elevation well into late- June.Snow and freezing rain were common early and late in the season,-and rain was prevalent throughout the operations..The two biggest weather constraints,however,were wind and fog. Winds of 40 to 50 mph were common,and gusts of hurricane force were not infrequent.These conditions often hampered helicopter transport of materials by sling.Fog also frequently grounded the helicopter. TEMPERATURE GRADIENT HOLES Following geological,geophysical,and geochemical surveys of the Makushin geothermal area,three +1,500-foot temperature gradient holes were sited and drilled in the summer of 1982.Temperature gradient hole D-1 was drilled on a plateau approximately one mile _ northwest of the base camp (Figure 1).The hole was spudded in glacial boulder till that mantled a sequence of Makushin Volcanics extending to 1,220 feet.The volcanics are a series of essentially unaltered andesite flows with interbeds of cinders, lahars,and gravel.Below the volcanics,from 1,220 feet to total depth (T.D.)at 1,429 feet,the hole penetrated a highly altered and fractured,fine-grained diorite.The diorite was intensely fractured and veined in the upper portion,with most fractures having near-vertical inclinations.Alteration minerals included sulfur,pyrite,kaolinite,calcite,epidote,quartz, anhydrite,and chlorite.Most of these minerals are products of the reaction between the rock and high temperature (>300°F) hydrothermal fluids. Temperature measurements made in D-=1 (Figure 2)indicated essentially isothermal convective conditions (ground water circulation)to approximately 700 feet.Below this depth the temperature increased at a high rate (22°F/100-ft)in a conductive (linear)manner to T.D.The zone of high temperature gradients corresponds with a self-sealed zone defined by whole- rock geochemical studies.The elevated temperature recorded at T.D.(212°R),the high gradient,and the high temperature alteration of the surrounding rock all suggest the presence of a relatively shallow (+4 ,000 feet)hydrothermal system. The E-1 hole located near the base camp penetrated a sandy tuff from surface to approximately 40 feet (Figure 1).It then encountered weathered diorite which quickly graded into. relatively fresh,hard massive diorite.The diorite extended from 40 feet to T.D.at 1,501 feet,in marked contrast to the D<1 hole in which andesites and other volcanic rocks comprise the first 1,220 feet of hole.Veins and fractures were present throughout the hole,but were commonly found in 10 to 15-foot thick zones seperated by massive unfractured diorite.The major fractures were dominantly vertical,with the smaller fractures and veins dipping about 45°to the core axis.The alteration and vein-filling minerals were essentially the same as those in the D=-1 hole,with quartz,epidote,and anhydrite representing the 'higher temperature hydrothermal alteration minerals. The temperature profile in E-1 was essentially conductive from surface to T.D.Gradients in the first 1,200 feet were quite consistent and high,and averaged 26°F/100 ft (Figure 2).At 1,200 feet,the profile began to roll over and the gradients declined abruptly to about 5°F/100 ft over the last 285 feet. This was taken to indicate that the hole had nearly penetrated the self-sealed zone and that it was approaching a convective hydrothermal systen,. Temperature gradient hole I-1 was located in Glacier Valley, approximately three miles south-southwest of the camp and the E-1 site (Figure 1).Stratigraphically,I-1 was very simlilar to E- 1,and confirmed the hitherto unknown wide distribution of the diorite intrusive body.The hole was spudded on the remnant of a terrace underlain by glacial till and materials about 40 feet thick.From 40 feet to T.D.at 1,500 feet,the rock drilled consisted of massive,eryptocrystalline to medium-grained diorite. The diorite is generally altered,as in E-1,with alteration minerals including chlorite,quartz,carbonate,clay,and epidote.The upper third of the hole contained pervasive fractures commonly lined with pyrite,quartz,and epidote that were deposited during an older,high-temperature hydrothermal episode.Fractures filled with a variety of secondary minerals were,as in the other holes,distributed throughout the bottom two-thirds of the hole. The temperature data recorded in I-1 (Figure 2)was quite different from that found in the first two holes.The profile indicated two separate thermal regimes.The first was a shallow (surface to 225+feet)system that produced large flows (>150 gpm)of 64°F to 77°F artesian water while drilling.The second system extended from about 250 feet to T.D.and appears to be a relatively conductive system,with gradients of 2°F/100 ft to 5°F/100 ft and a maximum temperature of 176°F at 1,400 feet. The data in Figure 2 also shows that there is a small temperature reversal (4°F)over the last 100 feet of the hole. The overall temperature regime and profile of this hole indicates that it is on the southern edge of the present geothermal system, at least for this depth range,although the intense fracturing and mineralization indicates the previous presence of a high. temperature geothermal system. The geochemistry of the cuttings from the gradient holes (e.g, enrichments of Hg,F,Li.As.S)suggests the existence of a liquid-dominated reservoir not far below 1,500 feet.The local existence of fumarolic activity and of chloride-poor thermal waters implies that a steam cap overlies the hot-water reservoir.A vapor zone does not appear to be ubiquitous,but may be limited to areas beneath the active fumaroles where open fractures permit boiling.Lower elevation hot springs in Glacier and Driftwood Bay Valleys are chloride-rich. The static temperature measured in FE-1 suggests that the subsurface geothermal reservoir temperature exceeds 380°F,The geochemical signatures of the core recovered from E-1 imply a fluid temperature greater than 390°,Calculations utilizing four different geochemical thermometers and samples from the fumaroles and hot springs indicate resource temperatures as high as 570°F. GEOTHERMAL RESOURCE MODEL The geothermal resource model described below was developed following synthesis of the resultsof studies conducted on the Makushin volcano geothermal area through 1982.Figure 1 depicts the surface locations of the geologic cross sections contained in Figure.3.These north-south east-west cross sections best illustrate the proposed model of the Makushin geothermal system on the basis of current interpretations.Figure 3 also includes temperature isotherms that have been overlain on the geology. The heat source of the Makushin geothermal system appears to be a buried igneous intrusion associated with the volcano.Fourteen historical eruptions of Makushin suggest that molten or partially molten rock is currently likely to exist.The temperature and post-glacial volcanic distributions suggest that the heat source for the system is not directly beneath the sumnit,but rather is offset asymmetrically to the east. The geothermal reservoir is probably situated primarily within the Makushin dioritic stock at commercially exploitable depths. The occurrence of most of the surface geothermal manifestations within diorite outcrops,the high,conductive temperature profiles recorded in the diorite,and the elevated observed temperatures are all evidence for a diorite reservoir.Some volcanic rocks act as-a seal for the reservoir,as seen in D-1, while chemical precipitates appear to have "self-sealed"the diorite,as seen in E-1. The location of the Makushin geothermal reservoir appears to be structurally controlled by a major northeasterly striking fracture zone.This zone is a long,wide,older tectonic feature whose inherent weakness probably played a major role in the intrusion of the original diorite stock.This zone has been refractured at least twice since the initial dioritic intrusion,- as shown by several sequences of vein-filling minerals in the three gradient holes.Nore recent movement along this northeastern-trending zone maintains the permeability for the fractures in the present-day geothermal reservoir,as well as the ruptures in the impermeable cap along which the majority of the surface geothermal manifestations occur.The gravity data and mercury soil anomalies confirm the position and extent of the northeasterly trending fracture zone. In summary,the Makushin geothermal system appears to be a 'liquid-dominated resource with temperatures in excess if 390°F, It is "situated in.fractured diorite within a north-easterly trending zone about two miles wide.The commercially exploitably reservoir is probably below 2,000 feet and may cover more than seven square miles.Reservoir waters rising upward (convecting) boil below an elevation of 1,200 feet in localized open fractures to form a steam cap that is limited in size and extent.Leakage of steam from this cap feeds fumaroles and mixes with ground waters to form the chloride-poor hot springs.Reservoir waters appear to be mixing with ground waters before exiting in Glacier and Driftwood Bay valleys as chloride-rich hot springs. This model of the hydrothermal system,in conjunction with logistical considerations,was used as a basis for selecting the test well location drilled in the summer of 1983. DRILLING OF ST-1 The decision to support the deep drilling operations by helicopter placed certain limitations on the drilling equipment which could be used."Helicopter"rotary rigs,which have been modified so that all loads are smaller than 4,000 pounds (the maximum lift capacity of a medium helicopter),have been created for use in similar situations,but few now exist.The two which were located were both rated at 16,000 feet and would require the support of at least two medium helicopters.This pushed the estimated cost of drilling a full-size deep well to approximately $5,000,000.Because the Longyear 38 continuous wireline coring rig used to drill the three 1,500-foot temperature gradient holes 10 had performed well,it was decided instead to drill a small- diameter stratigraphic test well using a Longyear 44,a slightly larger wireline diamond core drilling rig.This lowered the cost to about one-third of that estimated for the rotary rig,although the lesser depth capability of the rig (4,000 feet)and smaller diameter of the bottomhole (2-3 inches)somewhat limited the amount of reservoir productivity data obtainable. Stratigraphic Test Well No.1 (st-1)was spudded on July 2,1983 near the E-1 temperature gradient hole (Figure 1).The well was "intended to provide a "slim hole"(three inch diameter)test of the stratigraphy and the geothermal resource to 4,000 feet.A number of drilling problems were encountered.These were primarily associated with boulders in the shallow volcanic tuff/lahar,lost circulation zones,low strength (small diameter) core pipe,and limited cementing capabilities.Mechanically,the well was completed with H.Q.core pipe (3.06 inches I.D.) cemented to 650 feet,and 2.98 inch diameter open hole below to a total depth (T.D.)of 1,949 feet. Diorite with varying degrees of alteration and fracturing was cored continuously from below the shallow volcanics (170+feet) to T.D.The first significant open fractures were ecountered at 672 feet.Limited testing at this depth indicated a steam zone with a shut-in pressure of +109 psig and bottom hole temperature in excess of 310°F ,Flow rates with only 13 psig wellhead pressure were less than 5,000 lb/hr.The zone was mostly shut- 11 off with lost circulation material and cement,and coring continued. Due to continuing severe lost circulation problems,the wellbore was cemented from 1,056 feet to 550 feet and then redrilled.It is unclear whether these lost circulation problems were due to the breakdown of the zone at 672 feet or to multiple fracture zones below this point.Below 1,056 feet coring continued with| 90 percent returns to 4,916 feet,where total lost circulation was experienced again.The well was cored "blind"(no circulation)to 1,926 feet and then a test was attempted,but sustained flow could not be obtained. After coring blind an additional 20 feet (to 1,946 feet),the drilletring dropped free for three feet,indicating a major void.In a preliminary test,the well flowed steam and water for. three hours with a gradually increasing wellhead pressure.Shute in wellhead pressure reached 102 psig,with the well reportedly standing full of water.Preparations for a formal test were begun. TEST FACILITIES AND INSTRUMENTATION Logistical considerations severely limited the type of test facilities and instrumentation which could cost effectively be employed to test ST=-1.A relatively simple two-phase orifice meter and James tube were installed at the end of a flow line to measure the flow rate.Upstream/downstream orifice pressures 12 were recorded continuously with a differential pressure flow meter.James tube lip pressure was monitored continuously and manually recorded at frequent intervals using a carefully pre- calibrated test quality gauge.Pressure and temperature were also recorded frequently at the wellhead and elsewhere with conventional gauges. In the absence of a separator or weir it was necessary to estimate the fluid enthalpy to calculate a flow rate from the James(3)tube pressure.This was done using the two-phase orifice pressure drop data and/or by estimation from the measured pre-flash flowing wellbore temperature adjusted for uphole heat losses. Downhole pressure and temperature were measured using conventional Amerada instruments modified for high temperature service.Two elements of each type were available and each was calibrated before and after testing.Temperature elements with a 200-500°F range,sensitivity of one part in 2,000,and accuracy of 42°C were employed.Pressure elements with a 0-4,000 psig range,one part in 2,000 (+2 psig)sensitivity,and +8 psig accuracy were used. The inaccuracy,insensitivity,and erratic response of the pressure elements in the low pressure,0-500 psig range later proved to be a major problem.However,it should be noted that initial planning was for reservoir pressures of about 1,600 psig 13 (+4 ,000-fo00t T.D.)s Even when testing was initiated about 900 psig was anticipated (1,950-foot T.D.,+100 psig shut in wellhead pressure).When the critical value of the 0-500 psig range was recognized after "the first survey,the end of the "summer" operating season was near.Delay of the testing to locate, modify (for geothermal),and calibrate new instruments was not feasible. FLOW TEST MEASUREMENTS _The flow test plan was a simple one consisting of:(1)initial| static pressure/temperature (P/T)surveys;(2)flow until stable at the highest practical rate with bottomhole P/T measurements; (3)flow at a reduced rate until stable with P/T measurements in the hole during the rate change;(4)shut-in and buildup with two pressure instruments in the hole;and (5)final static P/T surveys.Instruments could not be in the hole during the initial drawdown because of the danger of "floating"in the small hole, which could not be elvaluated until the rate was known.Extreme turbulence in the two-phase flow region also prevented any meaningful data from being measured above the flash point. Figure 4 shows the static pressure traverses measured in ST=1 before (Run 1)and after (Run 7)the flow period.Figure 5 shows the corresponding static temperature data.At the selected pbottomhole datum of 1,900 feet,a substantially subhydrostatic initial pressure of 478 psig was measured.After the flow, element No.21367 returned to 473 psig,which is essentially the 14 same as the initial pressure within the rated accuracy of the instrument.However,one element No.22407 was lower by about 20 psig.This element (No.22407),suffered severe buffeting in the two-phase zone on its initial run into the well while flowing (Run 3)and is suspect in all its.subsequent measurements (even though it recalibrated "OK"after the test).Both temperature runs are in reasonable agreement with a bottomhole temperature of 379 °F at 1,900 feet. The most striking and surprising feature of the static surveys is_ the presence of a gas zone above 900 feet,both before and after the flow.Steam apparently refluxes up to about 300 feet,with a noncondensable gas (>95%C05)"cap"above that.A maximun stable shut in wellhead pressure of 136 'psig has since been measured (two months later).This can only be attributable to noncondensable gas evolution from the shallow dry stream zone, inasmuch as the noncondensables measured in the flowing fluid were extremely low (<300 ppm).Apparent differences in the gas zone pressure between runs may either be attributable to the erratic response of the elements in this low pressure range,to variable shut in times,or to slight pressure leak-off at the lubricator packing upon initiation of each run. Two additional features of the static temperatures surveys deserve comment.The cooling anomaly in Run 1 at about 700 feet probably reflects the continuous loss of drilling fluids to the lost circulation zone at 672 feet.The apparent cooling in the 15 wellbore above 4,600 feet after the flow (Run 7)is extremely puzzling.Flashing was always above 1,000 feet as shown by the existence of liquid gradients in the wellbore during flow from T.D.to at least this depth. The test rate/wellhead pressure history is shown on Figure 6 along with the downhole pressures measured at the 1,900-foot datum throughout the test.Wellhead pressure declined from 108 psig toa stable 36 psig within 15 minutes of opening the well. The rate stabilized at 47,000 lb/hr in the same 15 minute "period.Calculations showed that at this rate,the well was limited by reaching critical mass velocity at the orifice.Only minor perturbations associated with running the Amerada instruments in and out were experienced thereafter.The flowing pressure measured at 1,900 feet several hours after opening the well was stable.The absolute value of the indicated drawdown of 25 to 30 psig is suspect (element No.22407),however,because (as previously noted)the element was possibly damaged during the run-in through the two-phase zone and later returned to a "static"value which was about 20 psig low.The same element 19 hours later again indicated stability,but 5 psig higher. Upon lowering the rate to 34,700 lb/hr,the wellhead pressure rose to 52 psig within five minutes and was stable until shut in.The downhole pressure showed no change for over an hour after the rate change and then went down about one psig rather than up (No.22407).While the absolute pressure magnitudes are 16 suspect,both pressure elements exhibited this phenomena of _declining pressure upon shut-in.Both elements exhibit similar character during the buildup,first declining one to two hours after shut in and then rising slowly for many hours,with a curious more "rapid"rise in the last three hours.The static survey a day later showed that no futher pressure increase had occured. PRESSURE/FLOW "ANALYSIS" Any analysis of the transient pressure data described above would - be speculative at best at this stage because:(1)the pressure drawdown achievable from this reservoir with a three-inch wellbore is apparently slight;(2)the response of element No. 22407 is suspect for the reasons previously mentioned;(3)the- apparently valid response of element No.21367 is within the range of its rated accuracy (i.e.,+8 psig);and (4)some limited communication between the shallow stream zone and the main liquid reservoir (1 ,946-49 feet)exists,at least at the wellbore,and may be influencing the apparent responses (e.g.,crossflow or high compressibility steam cap). Nonetheless,the data from element No.21367 should be analyzable . in principle,and may actually represent a valid reservoir response.At a minimum,it is possible to calculate a productivity index (PI)and,from it,a permeability thickness (kh)based on a porous media,radial flow model as follows: 17 Pl -q =kh P =P (70.21)Bu In (re/rw) Where: q =34,700 lb/hr - (flow rate) Py-Pr ;=478-468 psig =10 psig (initial pressure-flowing pressure) B =1.14 (formation volume factor) u =0.14 ep (viscosity) In re/rw =9 (40-acre radial drainage|assumed) (ratio of effective drainage radius to wellbore radius) kh.PI =44.67 kh =50,900 md-ft A linear flow model may be more appropriately applied to the Makushin fractured reservoir,but possible interpretations are highly sensitive to assumed fracture dimensions which are unknown.Attempts at matching/analysis of the buildup data employing conventional type curves,etc.,were unsuccessful. It must be coneluded that either the reservoir response is exceedingly complex,or that the instrumentation sensitivity/accuracy is inadequate for this application.It is intended that testing over a longer period during the summer of 1984 will be performed employing a quartz erystal pressure transducer and capillary tube in order to at least resolve the instrumentation ambiguities. POWER POTENTIAL The estimation of individual well power potential for commercial operations requires the fundamental assumption that an extensive reservoir can be represented by the fluid properties,initial pressure,temperature,and productivity index derived from the slim hole data.Given this as a bases,then a wellbore flow model yielding wellhead pressure vs rate curves for various commercial-size wellbore configurations may be generated and related to appropriate power cycles with some degree of| confidence. The flow simulator used for this study was developed by Intercomp (3)and has been used extensively by the industry for geothermal| and geopressured wellbore flow calculations for several years. It is a commercially available,vertical,multiphase flow simulator and incorporates treatment for variable well diameter with depth,heat losses,and noncondensable gases.The "nominal" commercial well conditions arrived at were as follows: Initial Pressure A78 psig @ 1,950 feet Bottomhole Temp.379°F @ 1,900 feet Salinity 6,000 ppm TDS COs 300 ppm Productivity Index =3,470 1lb/hr/psi 13-3/8 inch casing to 1,750 feet 42-1/4 inch open hole to 1,950 feet 19 Using these conditions,a cross-plot of a double flash steam cycle and the simulator generated curve for wellhead pressure vs flow rate was constructed.An optimum output of 870,000 lb/hr at 60 psia wellhead pressure was found to generate six gross megawatts of power (Figure 7).Thus,two commercial-size wells could supply the 10 megawatts desired to service the current needs of Dutch Harbor and Unalaska. CONCLUSTONS The Unalaska geothermal exploration program has been very successful thus far.Geological,geophysical,and geochemical surveys of the Makushin area resulted in the siting of three temperature gradient holes in 1982.Two of these holes provided strong evidence of a geothermal resource while the third defined a southern limit.The resource model subsequently developed was then tested with the drilling a deep slim hole production well in the summer of 1983. Results from the slim hole confirmed the basic model of a shallow dry steam zone overlying a liquid-dominated reservoir in fractured diorite.Temperature (379°F)was about 10°F lower than predicted,but the well barely penetrated the top of the reservoir at 1,949 feet.Planned deepening next summer (1984) may yield substantially higher temperatures if some of the geochemical indicators are valid. 20 Flow testing of the well proved that the reservoir is potentially highly productive,with only three feet of fractured interval (at the wellbore)producing 47,000 lb/hr through three inch pipe and little reservoir pressure drawdown.Unfortunately,problems with insensitive and/or inaccurate pressure instrumentation in the unexpectedly low pressure range encountered does not allow rigorous analysis."A "ball park"productivity index of 3,470 lb/hr/psi and permeability-thickness of 50,900 md-ft can be calculated.Additional testing next summer with improved instrumentation is expected to resolve present ambiguities. Assuming the conditions encountered in the slim hole.are representative of an extensive reservoir,the power potential of a commercial-size well is estimated to.be in the range of six megawatts.Given the relatively small requirement for power on Unalaska (currently about 11 megawatts)and the estimated seven square mile resource extent,there is strong indication even at this early stage that a more than adequate geothermal power facility can be developed. REFERENCES 4.Isselhardt,C.F.,et al (1983),"Temperature Gradient Hole. Results from Makushin Geothermal Area,Unalaska Island, Alaska,"Geothermal Resources Council Transactions,Vol.7, October 1983,pgs.95-98. 2.Isselhardt,C.F.,et al (1983)."Geothermal Resource Model for the Makushin Geothermal Area,Unalaska Island,Alaska," Geothermal Resources Council Transactions,Vol.7,October 1983,pgs.99-102. 3.James,Russell (1980),"A Choke-Meter for Geothermal Wells Which Measures Both Enthalpy and Flow,"Geothermal Energy, 21 May 1980,pgs.27-30. 4."Vertical Steam-Water Flow in Wells With Heat Transfer, "Selentific Software-Intercomp,February 1982. ACKNOWLEDGEMENTS The authors wish to thank the Alaska Power Authority for their support and numerous members of Republic's staff for their input to this report. 22 E¢Pe ead taantrteatnaiaie"die dielDRIFTWOODBAY=mpage *qtuiiviiuitpattatttgar ,Co Dy aereEE=a=E=EQF |ppp,Pabapete <Soo,WN VALLEY Z"UNALASKA BAshDtnanSES,o A OOP SUMMER BAY SZ,Ame «Peps OA TL fF S =MAKUSHIN VOLCANO A 363 DUTCH Hanson a SI7A °6enLPUNALASKA p arene Rw PPP 1Beeeraces UNALASKA ISLAND X<BASE CAMP @ THERMAL GRADIENT HOLES ©st-1 FIGURE 1.UNALASKA GEOTHERMAL EXPLORATION PROJECT LOCATION MAP D-1 FOX CANYON @®-NXE @ 1425" AT -700-1425"©22.3°F/100"° E-1 CAMPSITE @-wrr ease ®-387°@ 485° ST =500-860"=24.7°F /100°850 1200'=26.5°F/100°1200-1485"=6.3°F/100° l-1 GLACIER VALLEY ®ea 1718 AT 250-1500"©6.079F/100" 1050-1500 =2.76°F/100" 1400-1500"©1.98°F/100° TEMPERATURE °C | 104 176248320392 100 LegOEPTH(FEET)[|Wo vod \ watt MN \ -nN i.\ 1800 Ol |Piel FIGURE 2.TEMPERATURE GRADIENT HOLES 24 Sd.cr A-A'CROSS SECTION B B' SOUTH FUMAROLE #3.we pace /FUMAROLE #2 non 409°GLACIER VALLEY .; :_-4.000t,oro 1-1 se”ST-1&E-1 --3.000 2,000 -('\:7 -209001,000 --:--1,000 o--o °SCALE °Cd 100°c 180°C 200°C ©2,000 4,000 FEET A 'A' EAST , WEST 8,000 --B-B'CROSS SECTION D-1 PROJECTED --5,000 &SOUTH z f=]MAKUSHIN PYROCLASTICS4,000 -----«eaten'a . b B Hheisees YOUNGER MAKUSHIN VOLCANICSiw3,000--S$,ib.¢.%,JOLOER MAKUSHIN VOLCANICS +2,000---Oe IL,|MAKUSHIN OIoRITE1,000-- ry <FA unacasca Formation -°e ,¢*,'.Sass Sanat Fe Sie OEE oe ee ee ry 2p0°¢aay CS .SCALE .eS _eeeNORTHEASTFRACTUREZONE©2,000 4,000 FEET FIGURE 3.GEOLOGIC CROSS SECTIONS DEPICTING THE MODEL OF THE MAKUSHIN VOLCANO GEOTHERMAL AREA DEPTH(FEET)DEPTH(FEET)|250 RUN NO.1 ELEMENT NO.21367 500 750 RUN NO.7 ELEMENT NO.22407 0 100 200 300 400 PRESSURE (PSIG) FIGURE 4.MAKUSHIN ST-1 UNALASKA ISLAND . STATIC PRESSURE PROFILES 8i}RUN NO.1 ELEMENT NO.10617 gI|RUN NO.7 ELEMENT NO.10617 1750 L_ 2000 |1250275300325350 375 400 425 TEMPERATURE (DEGREES F} FIGURE 5.MAKUSHIN ST-1 UNALASKA ISLANDSTATICTEMPERATUREPROFILES 26 LeFLOWRATE(1000L8S/HA)PRESSURE(PSIG)80 40 500 480 460 TIME (HOURS) |=SHUTIN "=HIGHRATE FLOW|LOW RATE FLOW a SHUT IN (BUILD UP)_] a %3O"JAMESTUBE |-2.0%JAMES TUBE -penccccessoees =:2.6"ORIFICE 1.75"ORIFICE poncensccnoncnsseorre”- :gvaccaccesose® -::- e p Peonanesaseovanseneoasnenes -eeesveccossnescesves |-- ---=INSTRUMENT ON BOTTOM some POSTULATED RESPONSE a?1 OP OP OS ep we me TRLET ; -_- =|Cr ELEMENT NO.21367 pemrrnnnnnoe]ee er nn ee OS SD OS Oe Oe cy, /-ELEMENT NO.22407 |ence ee en meee Sm|ee perenne nm me od be dead - 1)10 20 30 40 50 60 70 80 90 100 120 FIGURE 6.MAKUSHIN ST-1 UNALASKA ISLAND FLOW TEST HISTORY AND PRESSURE AT 1900 FEET (8/31/83 THROUGH 9/15/83) WELLHEAD PRESSURE (PSIG) !!!!!!a eee) 0 i] 1090 200 300 400 500 600 700 900 900 =61000 WELLHEAD FLOW (1000 LES/HR) FIGURE 7. FLOW RATE vs. WELLHEAD PRESSURE AND POTENTIAL POWER GENERATION (BASED ON DOUBLE FLASH STEAM CYCLE) 28 POTENTIAL GROSS POWER GENERATION (MW) 58 :O7,.0f 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. Vr ctf itt Llre>wee 2.; G-/Y felas (78 [ayer are Pre.pole!ok ee.freee lion Holocene faults and volcanic dikes reflect orientations that have occurred for faults and dikes since late Miocene or early Pliocene in the Makushin Volcano region of the Aleutian arc.Both the faults and dikes appear as several similarly oriented swarm sets.The two most prominent sets observed throughout this region for both faults and dikes have strikes of N50°Wt and of N 68°Wt.The N 50°W set is theoretically expected given the fairly constant maximum tectonic stress direction of N 45°Wt.The formation of the other set appears to have been influenced by a pronounced N 68°to 88°W fracture set exposed dominantly in the plutonic and older rocks of the region.This set most likely reflects a fracture system that has been rotated from the expected N 45°W trend in late Miocene or early Pliocene.The N 50°W set dominated only in the Quaternary basaltic volcano fields where the pre-Pliocene rocks would be fairly deep. 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 +80 km to the south.The floor of the Pacific Ocean (Pacific Plate)approaches the Aleutian are (North American Plate)in a northwesternly direction at a rate of about 7 cm/yr (Minster et al.,1974).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).The Pacific Plate is being subducted under the North American Plate at the Aleutian trench. This underthrusting causes compressional stresses in the direction of plate convergence in the arc region (Lensen 1960;and Nakamura,1977). Because the Pacific and North American Plates converge at about a N. 45°W angle in the Unalaska Island region,near vertical northwest-striking fracture and dikes would be expected to have formed in response to a regional N.45°W.maximum horizontal compressional force.Indeed,for Makushin Volcano which is located on the northern part of Unalaska Island,Nakamura et al.(1977)determined on the basis of the orientation of flank eruptions a maximum horizontal compressional stress orientation of about N.60°W. Geologic mapping at a scale of 1:63,360 complimented with some geophysical and geochemical surveys has been undertaken in the northern part of Unalaska Island since 1979.The main objective of this work was to assess the hydrothermal resources of this region (Reeder et al., 1980).This report presents some of the findings with respect to the configuration and regional distribution of dikes,faults,joints,and air-photograph lineations. GEOLOGIC SETTING The rocks of Unalaska Island include an older group of altered sedimentary and volcanic rocks designated the Unalaska Formation by Dremes and others (1961),a group of intermediate-age plutonic rocks, and a younger group of unaltered volcanic rocks (Figure 1). The Makushin Volcano (Ajagisch,Ajagin)of Unalaska Island is one of at least 36 volcanoeson the Aleutian arc that have been reported 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 its eastern-northeastern side.The largest fumarole activity occurs nearly on the top of the volcano.which is dominated by a 2.4 km-diameter caldera that formed about 8,000 B.P. (Reeder,1983).The most recent eruptions of Makushin Volcano occurred in 1938,1951,and possibly 1980 as steam-ash flank eruptions where the 1938 event was the largest (Simkin et al.,1981;and Swanson,1982). 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 Makushin Cone to Table Top Mountain (Figure 1). The unaltered volcanics unconformably blanket the Unalaska Formation as well as any intermediate-age plutonics it contains.Most of these unaltered volcanics are pre-Holocene and post-Pliocene,and appear to have been derived mainly from the immediate Makushin Volcano region. Except for Pakushin Cone and Wide Bay Cone,the Quaternary Cones of the area have been subjected to 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 Dremes and others (1961)to have formed within the last several thousand years where they based their claim on 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 evidence,based on ash stratigraphy and on the geographic locations of the cones and glacial moraines,suggest that these cones as well as the sugarloaf cone occurred at about the time of the Makushin Volcano caldera-forming event. The Unalaska Formation is upper Oligocene to middle Miocene (i.e.,about 30 to 15 mybp)as based on binalres,barnacle plates,burrow fillings, and a vertebra (Lankford and Hill 1979),and based on bones and teeth of a dismostylid (Dremes et al.,1961).This formation has been intruded by three plutons and several smaller intensive bodies.Individual plutons are zoned from mapic margins to felric 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 allitization,chloritization,epidotization, silicification,and zeolitization. Dikes,faluts,and joints The Unalaska Formation in the northern part of Unalaska Island consist of coarse sedimentary units as well as of numerous volcanic flows and volcanic breccias.This formation throughout the region has been cut by porphyritic basaltic-to-dacitic dikes.Most of these dikes do not appear to be directly related to the volcanic flows and breccias of the formation,although a few of the dikes were found to be directly related to sills contained in it.In addition,many of the dikes were found not only to cut the Unalaska Formation,but the numerous intermediate-age plutonic bodies that have intruded it.In the Makushin Volcano and Table Top Mountain region,most of the dikes are directly related based on field and petrographic observations to the unaltered volcanics. Unfortunately,no rediometric ages have been successfully obtained so far for any of these dikes.But,it does appear that the diking process for this region has been occurring since late Miocene or early Pliocene. Faults,dominantly being near vertical and having small displacements, also are found throughout the region.Although a few rare faults appear to be related to the forceful intrusion of some of the intermediate-age plutonic bodies,most of the faults appear to post-date these intrusive events where they cut both the Unalaska Formation and the intrusives. 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.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 5 meters,such as the scarps related to the near E-W and the N-W trending scarp that cuts the recent cinder cones along the Point Kadin rift zone on the northwestern ''flank of Makushin Volcano. The consistent pattern of orientation for the dikes and faults are shown by the contour of the per 12 area lower hemisphere equal-area projections of poles,Figures 2 and 3 respectively.For both of these projections,most of the data was obtained from the immediate Unalaska Bay region and the Makushin Volcano region where most of the work has been concentrated although field observations have been made on a reconnaissance nature throughout the region.With respect to the dikes, the primary strike trend for dikes is about N 53°W with a very steep dip either to the south or to the north,where steeply dipping corresponding dikes strike approximately N 14°W,n 35!E,and N 70°E. A fairly large number of dikes were also observed striking about N 71°W, where they dip steeply either to the south or to the north.No corresponding dike sets were found to relate to this secondary strike group.With respect to faults,the primary strike trend was found to be about N 52°W,where more of the faults dip steeply to the south than to the north.Steeply dipping corresponding faults have been recognized which strike about N 14°W,N 31°E,and N 87°E.A fairly large number of steeply dipping faults were also found striking about N 67°W with one corresponding fracture set striking about N 35°W. 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 Bay region and in the plutonics near the Makushin Volcano,is shown in Figure 4.The primary strike for these joints is about N 78°W (a range between N 69°W to No 90°W)where most of these joints dip steeply to the south.The corresponding joints have strikes of N 30°W, N 25°E,and N 74.5°E.A fairly prominent secondary strike set exist at about N 42°W where the joints dip steeply either to the north or to the south.Corresponding joints have been recognized striking N 05°W,N 49°E,and N 85°E.Most of these joints probably formed during or shortly after the cooling of the intrusive rocks presently exposed, which would place most of these joints at about 13-11 mybp or shortly after. Lineations Air photograph lineations have been carefully noted for the entire region shown in Figure 1 in an attempt to gain better insight in the nature of fracture systems.Unfortunately,due to the thick grfass-moss cover of Unalaska Island,good rock outcrops are not always easy to find.Yet,due primarily to the lack of trees,lineations are quite pronounces and easily recognized on air photographs and in the field. In all cases where good bedrock exposure could be found,all lineations were found to be dikes or faults,and in a few cases were found to reflect joints.In only one case was a lineation found to reflect a lateral glacial moraine.Although exceptions are expected to exist to this nearly perfect one to one correlation between lineations and observed faults,dikes,or joints,it is assumed that all of the lineations that were mapped indeed reflect such features.These Unalaska lineations do make regular patterns that probably reflect the numerous unexposed joints,faults,and dikes. Figure 5 is a rose diagram for the accumulative lengths of lineations for section F which is the region just southeast of Makushin Volcano. The principle trend for these lineations is about N 74°W,which reflects the trend of the Point Kadin rift zone that radiates from Makushin volcano.The corresponding lineation sets are N 29°W,N 21° E,and N 67°E.Another much less pronounced lineation trend is N 50°W where N 8°E,and N 89°E,and N 53°E are the corresponding trends.The regions to the southeast and to the northwest of section F have similar patterns.For section C,the Unalaska community region,the principle lineation trend is N 38°W which reflects numerous steeply dipping dikes and some faults.Corresponding lineation trends are N 40°E,N 52°E,and N 86°W.Another much less pronounced lineation trend exist at a N 61°W bearing with N O8°W and N 69°E as corresponding trends.In section E, the principle set of trends is N 46°W,N 89°W,N 52°E,and N 2°W. Lineations directly related geographically at least with the Table Top Mountain volcano trend N 51°W,N 1°W,N 38°E,and N 86°E, Discussion 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 (Jacob et al.,1977).Steeply dipping N 45°W fractures and dikes with corresponding N,N 45°E,and E fractures and dikes would be expected. Indeed,such trends do occur as previously shown,but other trends also exist.The lineations related with Table Top Mountain and with section E agree well with theory.In section F,the N 74°W lineation trend dominates over the predicted N 50°W trend.In section C,the N 38°W trend dominates where no N 45°W trend has been recognized.Although dike and fault orientations agree with theory (i.e.,N 53°W,and N 52°W respectively)other fairly pronounced sets have been recognized (N 71° W,and N 67°W respectively).The most pronounced deviation from theory occurs with the joints,where a secondary joint set does fit theory well (i.e.,N 42°W),the most pronounced joint set is striking roughly N 7 NS 78°W (actually have a N68°W to N 88°W range). The dike and fracture patterns that deviate from the patterns inspected must be due either to local stress forces and/or to part geologic and/or tectonic events.An approximate N 45°W trend does exist in all of the dike,fault,joint,and lineation data except for section C which suggest that the maximum horizontal N 45°W compression direction does exist and that other local stress forces are not large enough to cause substantial deviations from this direction.In fact,because most of the dikes,faults,and lineations are fairly straight rules out the 10 possibility of topographic (local granity)effects on the stress field. The other patterns must reflect fractures that,even though some are still active,formed in the past under either a different stress field and/or that have been shifted from their original orientation. The subduction of the Kula Spreading Ridge and the resulting greenschist regional metamorphism of the existing Aleutian rocks,which are found 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 where the Unalaska Formation formed approximately between 30-15 mybp.This intermediate-age intrusive activity marks the approximate time of resumption of not only magmatism but of subduction after the approach of the Kula Spreading Ridge to the Aleutian Ridge.This resumption of subduction and magmatism is also marked by the abrupt appearance of ash layers (approximately 11-12 mybp) in nearby ocean sediments (Creager et al.,1973)and in the initial formation of numerous summit basins in late Miocene and/or early Pliocene (Scholl et al.,1975). Atwater and Molnar (1973)reconstruction of the relative positions of the Pacific and North American Plates indicate that the relative motion directions between the "two plates has been fairly constant during Cenozoic time.In fact,their reconstruction only indicates an increase in subduction rate for the Pacific Plate since the initiation of subduction after the approach of the Kula Spreading Ridge.A different regional stress field has not existed in this region based on the above 11 since the initiation of subduction at about 15 mybp except for local force effects and stress magnitude variations. The plutonic rock (Shales Pluton)exposed south of Makushin Bay formed about 11 +3 mybp (Marlow et al.,1975)where a good part of the dikes, faults,and joints would have formed at this time.The principle lineation set is N 47°W,N 89°W,N 2°W,and N 52°E,which indicates that the maximum horizontal compression for this part of Unalaska Island existed at the time of formation of the plutonic rock and that this part of Unalaska Island has been fairly stationary.In contrast,it appears that the Makushin Volcano region (section F and the region northwest of Section F and the region south of Beaver Inlet)have undergone a counterclockwise shift shortly after the plutonic intrusions by about 29°.The region immediately northeast of the Unalaska community (section C)appears to have shifted about this time clockwise by about 7°where no further substantial fracturing has been occurring since. The end result of Buch notations would be the formation of a small graben roughly reflected by Unalaska Bay during the late Miocene and/or early Pliocene such as occurred elsewhere on the arc at about this time. A strike-slip fault located in the immediate Unalaska community region in addition helps to substantiate this rotation model (Figure 1). CONCLUSION Holocene faults and volcanic vents reflect orientation trends that have occurred.for dikes and faults since late-Miocene and/or early-Pliocene in the Makushin Volcano region of the Aleutian arc.The faults and 12 dikes appear to reflect orientations expected for a stress field caused by the subduction of the Pacific Plate;i.e.,namely an approximately N 50°W set with corresponding N,E,and N 40°E sets.The other prominent sets have been explained as being caused by the late-Miocene and/or early-Pliocene rotations of parts of Unalaska Island.The older rocks of the Makushin Volcano-Beaver Bay region appear to have been rotated counterclockwise by about 30°,resulting in the prominent N 68°W set of fractures and dikes.The older rocks immediately northeast of the Unalaska community appear to have been rotated about 8°clockwise.The approximate N 50°W set dominates only in the Quaternary basaltic volcanic fields where the pre-Pliocene rocks would be fairly deep. 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 Dickson,Kathy Grimnes,and the Curriers. 13 REFERENCES Atwater,T.and Molnar,P. 1973 Black,R.F. 1976 Coats,R.R. 1950 Relative motion of the Pacific and North American Plates deduced from sea-floor spreading in the Atlantic,Indian, and South Pacific Oceans,In:Proc.Conf.on Tectonic Problems of the San.Andreas Fault System (ed.by R.L. Korack and A.Nur),Stanford University.pp.136-148. Geology of Umnak Island eastern Aleutians as related to the Aleuts:Arctic and Alpine Research,v.8,no.1,p. 7-35. Voleanic activity in the Aleutian arc:U.S.Geological Survey Bulletin 974-B,p.35-49. Creager,J.S.,Scholl,D.W.,and Supko,P.R. 1973 Introduction,in Initial reports of the Deep Sea Drilling Project,Volume 19:pp.3-16,U.S.Govt.Printing Office,Washington,D.C. DeLong,S.E.,Fox,P.J.,and Mc,F.W. 1978 Subduction of the Kula Ridge at the Aleutian Trench: Geological Society of Americal Bulletin,v.89,p.83-95. 14 Drewes,Harold,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,p.583-676. Jacob,K.,and Hamada,K. 1972 The upper mantle beneath the Aleutian Island are from pure-path Rayleigh-wave dispersion date:Seismological Society of America Bulletin,V.62,p.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.AGU Monograph,Ewing Sysposium on Island Arcs and Back-are Regions,in press. Kay,S.M.,Kay,R.W.,and Citron,G.P. 1982)Tectonic controls on tholeiitic and calc-alkaline magmatism in the Aleutian Arc,Jour.of Geophysical Research,Vol.87,no.135,pp.4051-4072. Lankford,S.M.and Hill,J.M. 1979 Stratigraphy and depositional environment of the Dutch Harber Member of the Unalaska Formation,Unalaska, Alaska:U.S.Geol.Survey Bull.1457-B,p.B1i-Bl4. 15 Lensen,G.J. 1960 Principal horizontal stress directions as an aid to the Study of crustal deformation,Publ.Dom.Ohs.Ottawa 24, 389-397. Marlow,M.S.,Scholl,D.W.,Buffington,E.C.,and Alpha,Tau Rho 1973 Tectonic history of the central Aleutian arc:Geological Society of America Bulletin,v.84,p-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,v. 36,p.541-576. Nakamura,K. 1977 Volcanoes as possible indicators of tectonic stress orientation---principle and proposal:Journal of Volcanology and Geothermal Research,v.2,p.1-16. 'Nakamura,K.,Jacon,K.H.,and Davis,J.N. 1977 Volcanoes as possible indicators of tectonic stress orientation -Aleutians and Alaska,Pageoph,Vol.115, pp.87-112. 16 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,Vol.55,pp.87-112. 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:New York,Columbia University,Ph.D.dissertation,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,v.45,p.16-22. Perfit,M.R.;Brueckner,H.,Jawrence,J.R.,and Kay,R.W. 1980 _Trace element and isotopic ranalions in a zoned pluton and associated rocks,Unalaska Island,Alaska:A model for fractionation in the Aleutian calc-alkaline suite: Contrib.Min.Pet.v.73,p.69-87. Reeder,J.W.,Motyka,R.J.and Wiltse,M.A. 1980b The State of Alaska geothermal program:Geothermal Resource Council Transactions,V.4,p.823-826. 17 Reeder,J.W. 1981b Reeder,J.W. 1983 Vapor-dominated hydrothermal manifestations on Unalaska Island,and their geologic and tectonic setting:1981 IAVCEI Symposium -Arc volcanism,Volcanological Society of Japan and the International Association of Volcanology and Chemistry of the Earth's Interior. Preliminary dating of the caldera forming Holocene volcanic events for the eastern Aleution Islands: Abstracts with Programs,the Geological Society of America,p.668. Scholl,D.W.,Duffington,E.C.,and Marlow M.S. 1975 Plate tectonics and the.structural evolution of the Aleutian-Bering Sea region,In:Forbes,R.B.ed., Contributions to the geology of the Bering Sea basin and N .adjacent regions:Geological Society of America Special Paper 151,p.1-31. Simkin,T,Siebert,L.,McClelland,L.,Bridge,D.,Newhall,C.,and Latter,J.H. 1981 Siranson,H. 1982 Volcanoes of the World,A regional directory,gazetteer, and chronology of volcanism during the last 10,000 years, Smithsonian Institute,Washington D.C.,pp.232. The Unknown Island,Cuttlefish VI,Unalaska City School District,204 p. FIGURES Figure l. Figure 2 Figure 3. Figure 4. Figure 5. Figure 6. Simplified geologic map of the northern part of Unalaska Island, Equal-area lower hemisphere projections of poles to 100 dike surfaces in the Makushin Volcano 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 region of Unalaska Island,Diagram contoured in ,,,as indicater per 1 ,,, area, s Equal-area,lower hemisphere projections of poles to 63 joint surfaces in the Makushin Volcano region of Unalaska Island,"Diagram contoured in ,,,as indicated per 1 ,,, area. Rose diagram showing the accumulative lengths of air photograph lineations for the section F of Figure 1. Rose diagram showing the accumulative lengths of air photograph lineations for the section C of Figure 1. 19 Figure 7. Figure 8. Rose diagram showing the accumulative lengths of air photograph lineations for the section E of Figure l. Rose diagram showing the accumulative lengths of air photograph lineations related to the Table Top Mountain. 20 T 6 o J 10 Kmaei- NORTH Bishop Pt 63°46" Makushin Bay Sea .Totte Top "ve, y Nur &ona*/=%Wide flay Cons\. Unotothea \ 166°30' eae Boy Map Symbols Fumarole fleld Warm and/or hot springs Recent volcanic vent Caldera Unaltered volcanic rocks Plutonic rocks Unalaska Formation --Fault:dashed where approximate oF \-map location (Northern part of Unataske feland) "tH fuzeae',7 Rope dieg-am showing eccumuiative seongine of air protograph linestions tor the eection E '\ mmm 'v . Ress Megram chewing sovemviative wagths of ak photograph Heeations ter the postion F vt ae -Senin oe he ee rm ee me me ee a ey ee tee -_-ee Rese Gisgram showing secumuiative longthe eo af photog aph lneations for the eoction C la ;PionA a wee et Reee dagen i?twee of ar pretog apt Hneasttons fer the immediate Mebusht Veicane regen 10 ka 10 ka Suggested Title -Sample Log of Core from the Makushin Geothermal Area, Unalaska Island,Alaska Author -L.D.Queen Introduction 'The Makushin geothermal area is located on the east flanks of Makushin volcano,about 16 miles west of the village of Unalaska on Unalaska Island, _Alaska (Figure 1). Descriptions of the area's thermal manifestations can be found in Motyka.and others (1983);geology of the Makushin geothermal area is described by Nye and others (1984).Logs shown on this plate are based on the core recovered during drilling of three temperature gradient holes (Dl,El,Il)in 1982 and one test well (ST-1)in 1983 (Figure 1).The state-funded Unalaska geothermal drilling program was administered by the Alaska Power Authority.Republic Geothermal,Inc.,of Californt*was the prime contractor overseeing drilling operations. The upper portions of cores Dl,El,and Il are Nx size (54.8 mm diameter), the lower portions of these holes are Bx (42.1 mm diameter).The upper 670 feet of ST-1 is HQ core (64 mm diameter)and the remainder is Nx (54.8 m diameter).The core from these drill holes is permanently stored at the DGGS core-storage facility in Eagle River,Alaska. Methods The bulk of both the lithology and alteration shown in this report is based on hend sample logging of the core.Selected samples were removed for additional study by x-ray diffraction and petrography.The location of these samples is shown on the logs. All minerals which could not be identified in hand sample either because of their fine-grained nature (clays)or the uncertainty of identification were identified by x-ray diffraction.No special preparation techniques other than crushing to 100 mesh were employed.Thin sections of representative samples of the core were examined to assist in the description of the lithological units.Surface samples of similar rocks were also examined in thin section. The uppermost portions of the wells for which core was not recovered have been left blank.The brief discussion of surface units in each log is based on observations at and around the drill site. The temperature logs for wells Dl,EL,anceand Il are static temperature gradientsmeasuredbyRepublicGeothermal,Inc.,'Fi6-deys efter Urine ceesedy Thebottomholetemperature(193°Celcius)indicated for ST-1R is a flowing wwelltemperature.Frettemperatire-bogss-forittiz Et,and Il were repeated brie end_showed little change,on the summer of /7*%7,excep}forthelowerpracehELwhrchkwesmeasuredpr1992.Lithological Units Homogenous Volcanics -(Nye and others,1984)Plagioclase-crthopyroxene- clinopyroxene-olivine phyric andesites.The orthopyroxenes are reversely ° zoned and the olivines are normally zoned (Nye,unpublished data).Six flows can be distinguished in the core.The flow boundaries are characterized by oxidized and vesiculated layers.The color ranges from medium grey to black. The volcanics lack alteration. Cinders -Black to red,1-2 cm,cinders.Unconsolidated and unaltered. Recovery of material by drilling was poor (10%). Gravel -Moderately well sorted,1-2 cm,angular gravel.Mixed lithologies. Overlies the basal lahar in Dl.Unconsolidated. Lahars -Poorly sorted,moderately to well indurated debris flows.Brown to greenish brown.Angular to subangular clasts.Locally has lenses of brown laminated clay and silt.The matrix consists of sand and clay. Andesitic Dikes -Grey to grey-green porphyritic dikes.Similar in appearance to the Homogenous Volcanics.Green color is due to chlorite and epidote alteration.Randomly distributed throughout the gabbronorite as 2-30 ecm dikes.Only shown in Dl where a 4 m dike occurs. Hornfels--Contact metamorphosed volcaniclastics,sediments,flows and dikes of the Unalaska Formation.The hornfels seen in the core is,for the most part,of the pyroxene or hornblende hornfels facies,although some albite-epidote hornfels is present. The hornfels is light green to dark green to black and aphanitic to fine grained.In hand specimen small plagioclase laths can be seen in some samples.Alteration is not as common in the hornfels as in the gabbronorite. This may be due to the limited occurrence of hornfels in the core. Gabbronorite -Medium grained (1-2 mm)equigranular to slightly porphyritic. Dark to light grey.Primary mineralogy 50-70%plagioclase (An )> .;0-70approximatelysubequalamountsofothropyroxeneaniclinopyroxeneand accessory magnetite and apatite.Intergranular quartz may locally comprise a few percent of the mode.Alkali feldspars and albite are restricted to late stage pegmatitic veins (1-3 cm wide)which are scattered randomly throughout the stock.wie, Structure The density of veining/fracturing,the approximate dip of the fractures,and the presence and relative age of breccia zones were determined during logging. The density of the veining/fracturing is indicated on the logs as the number of veins/fractures per 10 foot interval.The density varies from 0 to 25 per 7, 10 feet.In general the more fractured zones are the more intensely altered. The dip of most of the fractures and veins is greater than 50°.In many cases the veins are almost vertical.Exact values for the dips were not determined. Breccia zones in the core can be divided into co-magmatic and post-magmatic. The co-magmatic breccias consist of hornfels clasts surrounded by gabbro and are most common near contacts between the Unalaska and gabbro.Some breccias are associated with large amounts of deuteric alteration including biotite and hornblende.These are considered late stage co-magmatic breccias. The post-magmatic breccias are always associated with intense alteration.The thickest section of breccia occurs in ST-1l.From about 75 m to 210 m below the surface the core consists of clasts of gabbro surrounded by a matrix of quartz,calcite,magnetite,and sparry anhydrite.The clasts are angular,2-4 cm in diameter and almost always have a chloritic alteration rim.A smaller breccia section occurs in Dl where hornfels is brecciated and the matrix is _Sparry calcite rather than anhydrite.However the alteration rim is chloritic as in S$T-1 and the clasts are of similar size and shape.The origin of these post-magmatic breccias is presently unknown. Alteration Minerals Alteration for the purpose of this report is divided into vein and disseminated alteration."Vein alteration"consists of those minerals which occur in regular or irregular veins or breccias and their immediate alteration envelopes."Disseminated alteration"consists of those minerals outside the zone of plagioclase alteration where such zones are associated with an alteration envelope around a vein. Quartz -Quartz veins are present throughout the cores.They vary from grey cryptocrystaline veins to clear doubly terminated crystals in anhydrite-montmorillonite zones.The quartz veins range in size from 0.5 mm to 2.0 cm in width. Anhydrite -Two distinct habits of anhydrite veins are present in the core. The most common habit is white,finely crystalline regular veins.These veins may also contain calcite,quartz,and pyrite as well as occasional zeolites. Some of the veins are open space and lined with crystals.The alteration envelopes around these veins are usually about the same thickness as the veins.Typically the plagioclase in the envelope has been altered to montmorillonite. The less common habit is a sparry,coarsely crystalline auhydrite found in irregular veins or as breccia fillings.It is associated with magnetite, quartz and calcite.Vugs with crystals of quartz,calcite and anhydrite are locally present.The veins are typically 0.5-2.0 cm wide.Chlorite is the principal mineral of the alteration envelope.The fine grained anhydrite veins always cut the sparry veins.The sparry veins are most common into the upper 210 m of ST-l.. Calcite -Calcite is present as both veins and as fine-grained mixtures with clay alteration.Most of the clay zones contain at least a trace of calcite. Calcite occurs as the principal mineral in some thin veins (1-2 mm)and as crystals in larger open space veins. Pyrite -Pyrite is principally an accessory mineral in veins although some short (2.0 cm),thin (0.5 mm)veins of pyrite have been observed.In other veins it is present as small euhedrals crystals (0.5-1.0 mm). Pyrite is also present as small disseminated grains.In this habit it commonly replaces magnetite grains in relatively unaltered gabbro.It may also replace pyroxenes or their alteration products.It is a common phase in vein alteration envelopes. Oo 7; Epidote -Epidote,like pyrite and chlorite-actinolite,occurs both in veins and as disseminated anhydral grains in the rock.In veins it is never the dominant mineral.Typically the epidote is associated with quartz or less commonly with calcite veins.It is also found with the sparry anhydrite although rarely with the fine grained anhydrite.It occurs as euhedral crystals in irregularly shaped,miarolitic,albite-quartz-epidote veins.It may make up to 1-2%of the mode in the albite-quartz-epidote.In the disseminated form it occurs as 0.5-1.0 mm grains scattered throughout altered zones,especially near the contacts between hornfels.and gabbro. Chlorite-actinolite -These minerals were grouped together due to their intimate association and the difficulty in distinguishing them in hand _ specimen.The majority of the disseminated occurrences of these minerals are deuteric alteration of the pyroxenes and are associated with anthophyllite-cummingtonite. The chlorite-actinolite veins are usually thin (0.5-3.0 mm),regular in shape, and light to dark green.They typically exhibit shallower dips than other veins.These veins may also contain a small amount of quartz.The high temperature stability of these minerals indicates these veins are deuteric in origin. Chlorite also forms dark green 3-4 mm thick alteration envelopes around sparry anhydrite veins.Chlorite is a common phase in the montmorillonite zones. Montmorillonite -Montmorillonite is most abundant in the clay zones which dominatethe alteration in the upper portions of the cores.In general these clay zones do not extend much deeper than 40 m feet below surface but in I-l (the coldest well)the zones occur down to 450 m feet below surface.The clay zones are grey to grey green and from 2-20 cm wide.Calcite is usually present.Mixed layer clays,found in the montmorillonite clays from the surface,are not seen in clay zones of the core.The heights of the chlorite and montmorillonite x-ray peaks is constant,which suggests that the ratio of these minerals is also fixed. Montmorillonite also replaces plagioclase in alteration envelopes around anhydrite veins.Here the montmorillonite forms white pseudomorphs after the plagioclase laths. Illite -Illite is found in a clay zone in well I-l.The zone is similar in appearance to the montmorillonite clay zones. Mordenite -Mordenite occurs as white acicular crystals in an open-space calcite-quartz vein in I-l. Laumontite -Laumontite occurs as stubby euhedral crystals in open-space calcite veins throughout the cores.In general it is found closer to surface than wairakite. Watirakite -Wairakite occurs in E-1l and ST-1.In El it occurs as euhedral white crystals in an open-space quartz vein.In ST-1 it occurs as a massive alteration of the gabbro.It is light grey and aphanitic.Euhedral pyrites make up about 1-2%of the altered zone.The alteration surrounds a fracture zone which produced steam (205 m depth). ' :w©' Magnetite -Magnetite occurs as an accessory mineral disseminated throughout the gabbronorite.Most of this magnetite appears to be primary and therefore is not shown on the logs. The magnetite indicated on the logs occurs as large (2-3 mm)anhedral grains associated with the sparry anhydrite veins.This magnetite is sooty in _appearance.Large magnetite grains also occurs as isolated grains apparently removed from any other alteration. Alteration Assemblages Although not explicitly indicated on the logs,the alteration minerals do have distinctive associations and occurrences and can thus be grouped into five assemblages.The assemblages are determined from consistent mineral associations,habit and relative age relationships of the alteration.While not based on assumptions of origin,the assemblages can be interpreted genetically.The genetic interpretations are documented by direct association with hydrothermal fluids,by correlation with other geothermal fields and by theoretical mineral stabilities. The relative ages of the assemblages are ascertained by cross-cutting relationships seen in the cores.The assemblages are discussed from youngest to oldest. MontmorillonitetChlorite+Calcite+Pyrite The assemblage montmorillonite+chloritet+calcitet+pyrite is common in the upperportionsofthecoresandaccountsformostofthemontmorilloniteoccurrences in the cores.The clay zones in which this assemblage occurs are described in the section on montmorillonite. The depth at which the assemblage occurs,the lack of mixed layer clays and the consistent ratio of chlorite to montmorillonite indicates the assemblage is hydrothermal in origin.The presence of the assemblage in Makushin geothermal area fumarole fields and the restriction to shallow depths indicates that the'assemblage is formed by the cooler and/or more oxidized part of the current hydrothermal system.This assemblage is found in the cooler portions of other geothermal systems (Ellis,1979). Anhydrite+Quartz+Calcite+tCa zeolitestEpidote+Pvrite The veins are locally open-space and have euhedral crystals of anhydrite, quartz,calcite and Ca zeolites growing along the edges.It occurs in regular steeply dipping veins (70°)throughout the cores.The assemblage anhydrite+quartz+calcite+Ca zeolitestepidote+pyrite constitutes most of the alteration observed in veins.'Sealed veins are much more abundant.These range in size from 0.5 mm to 2.0 cm in width.The assemblage is restricted to depths of more than 120 m from the surface.This assemblage is found in fracture zones in well ST-1 which yielded steam and hot water (193°C).These minerals are generally regarded as being indicative of "water-dominated" geothermal systems.Initial estimates of equilibrium give evidence that the hot water obtained from the 593 m fracture zone of ST-1 is in equilibrium with this assemblage. Oo The age relationship between this assemblage and the montmorillonite assemblage cannot be conclusively determined,although they both appear to be contemporary. Anhydrite+Quartz+Calcite+Magnetite+Chlorite+Pyrite+Epidote The assemblage anhydrite+quartztcalcite+magnetit+chlorite+pyritetepidote ismineralogicallysimilartotheaboveassemblage,however details of mineral habit indicate they are not the same.This assemblage is characterized by sparry rather than massive or fine grained anhydrite and it occurs as a breccia filling as opposed to regular veins.Furthermore the vein assemblage is found to cut the breccia assemblage showing that the vein assemblage is younger.This breccia assemblage is described in the anhydrite section. The fact that the assemblages are not the same and are of different ages implies that the breccia assemblage is not directly related'tothe current system (i.e.,thermal waters at the depths which the assemblage occurs are not in equilibrium with the assemblage.)The similarity between the assemblages suggests that this breccia assemblage may represent an earlier stage of the active system, .\ Albite+Biotite+tEpidotetHornblendetActinolite+Quartz The assemblage albite+biotitetepidote+hornblendetactinolite+quartz occurs as dike-like veins and as pervasive alteration in co-magmatic breccias.The veins range from 1-10 cm in width and may contain miarolitic cavities.The biotite typically occurs along the borders of the veins.Trace amounts of alkali feldspars are found in these veins. In the co-magmatic breccias the assemblage is not restricted to veins.The breccia is dark grey with angular 2-5 cm clasts of gabbro in an aphanitic matrix.The matrix is made up of albitetbiotite+hornblende+quartzt+tepidote with accessory rutile and hematite.Few if any primary minerals are present in the matrix.The clasts retain the original plagioclase laths but the pyroxenes have been placed.The replacement does not retain the original shape of the pyroxenes.The biotite and the hornblende are frequently euhedral in both the clasts and the matrix.They are,however,always found with the fine-grained albite and quartz indication they are not primary. This assemblage,like the one below,is indicative of high temperatures and, in this case,low f0,.This.assemblage is interpreted to be a late stagemagmaticalteration.It appears to be the same age as the chlorite+actinolitetanthophyllitet+cummingtonite+magnetitetpyrite assemblage. ChloritetActinolite+Anthophyllite+Cummingtonite+tMagnetite+Pyrite The assemblage chloritet+actinolitetanthophyllite+cummingtonite+magnetite+ pyrite replaces mafic phases in the gabbronite and hornfels.This assemblage along with the one above are the oldest alteration seen in the core.It is also the most widespread alteration assemblage,being present throughout the 'core and on the surface.Rocks which have been altered to this assemblage are frequently greenish with cloudy plagioclase.The characteristics of this alteration are consistent with those described by Taylor (1979)for intrusives which have interacted with surface-derived waters. References Ellis,A.James,1979,Explored Geothermal Systems:in Geochemistry of Hydrothermal Ore Deposits,Second Edition,H.L.Barnes,ed.,New York:John Wiley and Sons,p.637-683. _Motyka,R.J.,Moorman,M.A.,and Poreda,Robert,1983,Progress Report - Thermal Fluid Investigation of the Makushin Geothermal Area,Alaska Division of Geological and Geophysical Surveys RI 83-15,p.52. Nye,C.J.,Queen,L.D.,and Motyka,R.J.,1984,Geologic Map of the Makushin Geothermal Area,Unalaska Island,Alaska,Alaska Division of Geologicaland Geophysical Surveys RI 84-3,2 plates. Taylor,Hugh P.,1979,Oxygen and Hydrogen Isotope Relationships in Hydrothermal Mineral Deposits:in Geochemistry of Hydrothermal Ore Deposits, Second Edition,H.L.Barnes,ed.,New York:John Wiley and Sons,p.236-277. D1 Comments Area around drill site covered with glacial till.Streams in the area indicate the till is no more than one or two meters thick.. Began coring 104.8 m. Fractures 0°dip. Fractures in flows have surface oxidation but lack alteration. 2 per cent recovery in cinders.No alteration. Fractures in gabbro are vertical. Brown to tan to yellow clay fill fractures.Clay is detrital plagiclase and montmorillonite. Laumantite filled vein. Brecciated hornfels.Breccia is filled with sparry calcite and anhedral pyrite.Hornfels is green in breccia zone,grades to black in unaltered sections. Total depth 435.7 m. El Comments Surface deposits are ash-flow and air-fall tuffs interbedded with debris flows and mudflows.Deposits appearto be about 50 m thick. Begin coring 26.0 m. Biotite and hornblende present in breccia. Veins and fractures are vertical. 1.0 cm euhedral to subeuhedral magnetite crystals. Actinolite crystals in miarolitic cavity with quartz and epidote. 40 per cent recovery for 2 meters. Biotite surrounding quartz +epidote veins. Euhedral crystals of yugowaralite. Euhedral crystals of wairiakite. Miarolitic cavities with quartz and epidote crystals. Thin (5-15 cm)mafic dikes. Total depth 457.2 -ST-1 Comments Surface deposits are ash-flow and air fall tuffs interbedded with debris flows and mud flows.Deposits appear to be about 50 m thick. Clays in the matrix of the lahar change from brown to bbrownish-green. First meter 'of gabbro is highly altered and fractured.The appearance and mineralogy of this zone is similar to that of the fumaroles. Gabbro is brecciated.Matrix is sparry anhydrite,calcite, and magnetite. Magnetite is very abundant in breccia. Rock altered to massive wairakite. Steam entry. Kaolinite present in clay zones. Trace.biotite.- Hot water entry (193°o): Begin coring 16.8 m. Total depth 593.1 m. ci Bc Comments Drill'site on glacial outwash terrace.Terrace is approximently 15 meters high.Composed of poorly sorted glacial debris. Begin coring 30.48 m. Biotite present in breccia zone. Pyrite in clay zone as small (0.5 mm)hexagonal plates. Possible replacement of pyrrhotite. Magnetite grains altered to hematite.No other significant alteration in the area. Total depth 457.5 m. OG.If DEVELOPMENT POTENTIAL OF THE MAKUSHIN GEOTHERMAL RESERVOIR OF UNALASKA ISLAND,ALASKA David Denig-Chakroff(?)John W.Reeder (2)Michael J.Economides (3) (1)Alaska Power Authority,334 West Fifth Avenue,Anchorage,AK 99501, U.S.A. (2)Alaska Division of Geological and Geophysical Surveys,Pouch 7-028, Anchorage,AK 99510,U.S.A.(3)Dowell-Schlumberger,Marble Arch House,66/68 Seymour Street, London W1H5AF,U.K. ABSTRACT Flow tests and reservoir analyses have confirmed the existence of a_productive geothermal reservoir beneath Makushin Volcano on Unalaska Island in the Aleutian Chain.A prelim- inary economic analysis has been conducted todeterminethepotentialfordevelopingthe resource to meet the electric power demands of the Unalaska/Dutch Harbor community.The analy- sis was based on characteristics of the resource, deliverability of the reservoir,logistics of development and operation,and power market conditions at Unalaska.The analysis indicates that a geothermal power system may be econom- ically competitive with a diesel power system on the island.A detailed feasibility study of the project should be conducted which concentrates on electric load projections and market conditions at Unalaska. INTRODUCTION Unalaska Island is located in the Aleutian Archipelago about 800 miles southwest of Anch-orage,Alaska (Figure 1).The City of Unalaska, consisting of the adjacent communities of Unalaska and Dutch Harbor,is situated at the northern end of the island on a well-protected bay.Unalaska was an important crossroads for shipping and trade during Russian occupation(1741-1867)and during the Klondike and Nome gold rushes from 1897 to 1900.Its sheltered, deep-water port made Dutch Harbor a prime loca- tion for a major naval base during World War II. Since that time,the fishing and crabbing indus- tries have been the mainstay of Unalaska's economy. The Alaska Power Authority has recently completed a geothermal exploration program at Makushin Volcano near Unalaska and is involved in Studies of both energy needs at Unalaska and alternatives for meeting those needs,includingthegeothermalalternative.The Alaska Power Authority is a state agency governed under execu-tive and legislative oversight by a seven-member board of directors appointed by the Governor ofAlaska.Its goal is the orderly and economic development of energy resources to provide power at the lowest possible cost to the consumer and to encourage the long-term economic growth of the state. One objective of this paper is to sunmmar- ize the final results of the Unalaska geothermal exploration program.A second objective is to present a preliminary economic analysis of utilizing geothermal resources, which were discovered in the vicinity of Makushin Volcano,to meet the current and future power needs of Unalaska.The economic analysis has taken into account the charac- teristics of the resource,the deliverability of the reservoir,the logistics of development and operation,and the demand of the power market. X ease caw @ tetmear on rorens nous >CLO;me mea,RELOURCE WHEL Figure 1.Map showing the location of the Unalaska geothermal project. THE RESOURCE AND THE RESERVOIR In 1981,the Alaska Legislature appropri-ated $5 million to the Alaska Power Authorityforgeothermaldrillingandexplorationat Makushin Volcano located 14 miles west of the Denig-Chakroff and others City of Unalaska (Figure 1).The appropriation was preceded by a number of geologic investigations that indicated potential for a significant resource at Makushin Volcano. A competitive request for proposals was issued in 1981 and,after evaluation of the responses,Republic Geothermal,Inc.,of Santa Fe Springs,California was selected by the Power Authority to plan and coordinate the exploration and drilling program.The program consisted ofthreephases.Phase I activities included data review and synthesis;technical planning;land status determination;permitting requirements; acquisition of baseline environmental data; geological,geochemical,and geophysical inves- tigations and mapping;and the drilling of three temperature gradient holes.Phase II activities included the drilling of a deep exploratory well and initial testing of the geothermal resource encountered.Phase III activities included continued and more extensive testing of thegeothermalresource,the drilling of a fourth temperature gradient hole,and an electrical resistivity survey to delineate the extent of the reservoir. Under Phase I,the first three temperature gradient holes were drilled in 1982 to depths of 1500 feet and encountered temperatures of up to383°F.Two of the holes indicated a close proximity to geothermal resources below,while the third appeared to be on the fringe of the geothermal system.The Phase I findings conclud- ed the strong probebility of a water-dominated geothermal system in excess of 480°F on the eastern flank of Makushin Volcano at a depth of1983)4,000 feet (Republic Geothermal,Inc.,1983). Phase II of the exploration program was initiated in the Spring of 1983.The exploratory well was started in early June.The well?encoun- tered a fracture at 1,946 to 1,949 feet that contained a substantial geothermal resource. Initial well tests confirmed a water-dominated geothermal system with a steam cap and with a bottomhole pressure of 478 psi (RepublicGeothermal,Inc.,1984a).The bottomhole flowing temperature was measured at 379°F;however,a static temperature of 395°F was measured at that depth.This temperature difference coupled with an observed static temperature gradient reversal from a maximum 399°F at 1500 feet indicates that the geothermal reservoir is located some distance from the well and communicates with the wellbore through a high conductivity fracture system(Economides and others,1985).The results of gravity and geologic investigations add substan-tial support to this conclusion (Reeder and others,1985).The fluid from the producing horizon.is approximately 16%vapor and 84%liquidbymassatusablewellheadpressures.It mea- sures 7800 ppm total dissolved solids. Phase III of the project,conducted in 1984, consisted of further well testing and reservoir analysis,drilling a fourth temperature. gradient hole,and conducting an electrical resistivity survey.The temperature gradient hole,drilled in an area that would be more accessible to development than the exploration wellsite,showed no indications of the exis- tence of a similar geothermal resource.The electrical resistivity survey revealed that the site of the current exploration well is ac- tually the most accessible site for encounter- ing the geothermal resource at a reasonable depth. Flow tests and reservoir analyses conduct- ed in 1984 confirmed a highly productivegeothermalreservoir(Economides and others,1985).Sustained flow of 63,000 Ib/hr was achieved through the three-inch diameter wellbore with less than two psi pressure drawdown from the initial 494 psi bottomhole pressure after 34 days.The productivity index derived from the flow test was in excess of 30,000 Ib/hr/psi,which indicates a phenomenal permeability-thickness product in the range of 500,000 to 12 million md-ft.Wellbore flow modeling indicated that a commercial-size well at the site should be capable of flow rates of 1.25 to 2 million lb/hr at a wellhead pressure of 60 psia.A material balance calculation byEconomidesandothers(1985)provided an estimate of reserves that could maintain this flew rate (capable of producing 7 to 12 MW ofelectricpower)for over 500 years. LOGISTICS OF DEVELOPMENT AND OPERATION The location of Unalaska in the Aleutian Islands creates difficulties for any capital project development.Although there are dailyscheduledairfreightandpassengerflightsandregularlyscheduledbargeservicefrom Anchorage and Seattle,its distance from population centers may increase construction and operation expenses by a factor of 50%or more over continental U.S.costs. The Makushin geothermal exploration wellsite is located approximately 13 miles west of the City of Unalaska in a remote,rugged, roadless terrain.Access to the site from the city requires crossing a three-mile wide bay, traversing the length of a seven-mile tong, wetland valley,and contending with three miles of steep,rocky slopes and canyons.Thislocationwouldclearlyhavea_significanteffectonthecostsofbothconstructionand operation of a power plant at the site and a transmission line to the City of Unalaska. In addition,weather conditions may be a serious impediment to development and opera- tion.Although the average annual temperature(38°F)at Unalaska is higher than many other regions of the state,heavy construction is generally limited to a four-month construction "window"due to wind and snow conditions.Even during summer months,when the average tempera- ture is around 50°F,high winds,heavy rains,and fog could impede construction,operation,and maintenance of a remote power facility. POWER DEMAND The power demand of the Unalaska/Dutch Harbor community has been marked by large fluc- tuations that follow the cyclical trend of the fish-processing industry.In 1978,Dutch Harbor was the nation's leading fishing port based on the value of its landed catch (Morrison-Knudsen Company,Inc.,1981).It has been estimated that the population of Unalaska Island has reached over 5,000 during peak fishing seasons.At such times,the peak power demand has reached 13+MW. However,over the past year,during a serious slump in the fish-processing industry,the population has been estimated at about 2,000 and the peak demand has fallen as Tow as 4+MW. Unalaska is pursuing numerous options to diversify its economy,which could both increase and stabilize electrical loads.These options include developing additional marine support facilities,establishing a bottomfish industry, and increasing its tourist trade.In addition, the U.S.Coast Guard is considering the island as the site for a large search-and-rescue facility to respond to calls in the Bering Sea and North Pacific and the petroleum industry may use Dutch Harbor as a staging area for offshore oil development.Any one or combination of these ventures or a rejuvenation of the established fish-processing industry on the island could significantly change the power demand outlook at Unalaska over a very short period of time. The electric power demand on the island is met entirely with diesel powered generators.The city-owned electric utility primarily serves residential and small commercial users.The city has a current installed capacity of 3.9 MW and plans to increase its diesel generating capacity to 9.5 MW by 1987.Larger commercial establish- ments and industrial users generate power with their own diesel generators.They have expressed interest in tying into the city system once it has sufficient capacity to economically and d ir demand.ependably meet their demand uw ot,5 a,gun.ECONOMIC ANALYSIS gree vide @ety aWveursemectecte-at the economics ofdevelopingageothermalpowerfacilityon Unalaska Island.Prior to design and con- struction,a far more detailed feasibility study would be required. dete This analysis used ,present -werth calcu-lations to compare numerous energy plans for Unalaska based on three possible load growth scenarios and three types of power systems. Binary and total flow geothermal systems of various sizes were analyzed to determine the optimum size for each of the three growth scenar- Denig-Chakroff and others ios.Each geothermal energy plan assumes an on-line date of 1990 and,a,35-year useful life.The net present Veet in 1985 of each geothermal fower plan is compared to the net present )Of comparable diesel power system plans that would meet the demands of the respective growth scenarios over the same period. The choice of geothermal systems analyzed and the system cost estimates were based on the actual reservoir characteristics,logistics of development and operation,and market con- ditions.Since the exploration well is be- lieved to have encountered a high conductivity fracture that communicates with a geothermal reservoir some distance away,there is no guarantee that a well at a second location in the vicinity of the exploration well will encounter an equally productive resource. Consequently,geothermal power conversion systems with high resource use factors were an- alyzed so that the economics could be based on an assumption of drilling a single commercial- size well at the exploration wellsite.Because the geothermal fluids encountered are of excellent quality with respect to undesirable constituents and total dissolved solids,power system costs were considered both with and without the need for an injection well. Preliminary hydrologic data indicate that geothermal effluent may be disposed of in surface drainage without adversely affecting the environment.Consequently,the results presented here assume that reinjection will not be required.Due to the remote location of the site,conservative cost estimates for a road and transmission line were used,and the total cost of each geothermal power system was subjected to a 20%contingency factor.Final- ly,because of the relatively low demand at Unalaska,only geothermal power systems that . are cost competitive in small unit sizes were considered. The electric load forecasts used in the analysis were based on three population growth scenarios over a 20-year planning period(1985-2005).Populations and loads were assumed to remain level from year 2005 until 2025--the erid of the 40-year period used for the economic analysis.A 2%annual increase in population was considered to be a minimum andsomewhatconservativegrowthscenarioforthe planning period.A°4%growth scenario was. analyzed as a reasonable expectation of moderate growth.An 11%growth scenario was considered,based on a population projection byDamesandMoore(1982)which assumed a low level of bottomfish harvest and processing on the island.For each growth scenario,electric load forecasts were developed for residential, commercial,and industrial users and for city services.Figure 2 illustrates the total electric load forecast'for each growth scenario. Denig-Chakroff and others A diesel power system plan was developedasthe"base case"to compare the geothermal power system plans under consideration.A dieselgeneratorcapacityaddition/replacement schedulewasdevisedsuchthattheneedsprojectedinthe electric load forecasts would be met even with the largest power unit down for maintenance.Thereplacementschedulewasbasedonanassumption that diesel generators have a 20-year usefullife.A separate diesel power system plan was developed for each of the three growth scenarios. UNALASKA/DUTCH HARBOR TOTAL LOAD FORECAST VIX growth seonarie RNEAGYUSE(MARe¥r)(Treucanas)g14%growth scenarie @Z growth swenerie 10 sn ee i eeeeee Figure 2,Graph showing the total electric load forecast for Unalaska/Dutch Harbor from1985to20£5. a) The geothermal power system plans weredevelopedbyassumingthatoneormoregeothermalunitswouldcomeonlinein1990.Geothermal units were based on net MW deliverable to the power grid after making deductions necessary to supply station service.Ten geothermal power plans were analyzed for each of the three growth scenarios.These included plans for installing from one to six 2.1 MW net total flow geothermal units and from one to four 3.35 MW net binary geothermal units.It was assumed that the geothermal units would produce 90%of the annual energy demand or 90%of the potential net production of the geothermal system,whicheverwasless.The remaining energy demand would be met with backup diesel generators.Uo bateThenetpresentworthof each power system plan was calculated using a 3.5%annual discount rate.Geothermal system construction costs weretakenfromRepublicGeothermal,Inc.(1984c)and modified to reflect a 20%contingency factor. Construction of a 34.5 kv transmission line and a road to the geothermal site were estimated at $15.473 million,including a 30%contingency factor.Diesel fuel prices were tetd-constantthrough-1988--and-then were-escalated at 3.0%-per ;++-2610.Fuel costs were based on a production of 12 kilowatt-hours per gallon of fuel.Diesel generator cost and salvage valuewereestimatedat$700 per kilowatt of installed Qutumed oO feacan lon dA ow 1996,Abana Canstowd trial dy,avdWho"Were SL bu a4 onan ued,1 2008, capacity.Annual operation and maintenancecostswereassignedconstantvaluesof $1.012 million for the "base case"diesel: system and $1.275 million for the geothermal systems. RESULTS spa(4ThenetpresentMiseeh was calculated for each power system plan.The net present worth of the optimum systems analyzed is depicted in Figure 3.Geothermal system plans were compared to the diesel system plan for each respective growth scenario using acost-to-cost ratio (Figure 4).For the 2% scenario,the diesel/total flow cost-to-cost ratio is very near unity for all sizes of the geothermal system:considered.With the binary system,at 2%growth,the cost-to-cost ratio is at unity for a 3.35 MW unit and declines to .73 for a 13.4 MW system.Considering a 4%growth scenario,the optimum total flow system is 4.2 MW with a 1.23 cost-to-cost ratio and the optimum binary system is 3.35 MW with a 1.14 ratio.At 11%growth,the geothermal systems are clearly more economical than the diesel plan considered,with optimum cost/cost ratios of 1.80 for a 13.4 MW binary system and 2.05 for a 12.6 MW total flow system. COST OF OPTIMUM POWER PLANS22AND4%GROWTH SCEMARIOS HETPRESENTWORTH(iiilieons)220 ae 200+19041004170+xEte4ia4ir}120 +ébe we4wsi=]ts3 100.«2 0.o- ©3] x boas 4 e- x 4 a 4 C) 2)dese biacry ES tote!New Figure 3.Graphs showing the net present worth of optimum power system plans for three growth scenarios. Denig-Chakroff and others COST/COST RATIO DIESEL VS TOTAL FLOW SYSTEM Cc'CRATIO0.9 r 1 1 P 2A 4.2 6.3 8.4 10.5 12.6 NET GEOTHERMAL CAPACITY (MW)[2]2%scenarto +4%scenario °11%scenario DIESEL VS BINARY SYSTEM 1.9 1.6 - 1.4 -c/CRATIOow1.2 - 0.7 T T 3.35 6.70 10.05 13.40 NET GEOTHERMAL CAPACITY (MW) o 2%scenario +4%scenario °11%scenario Figure 4.Graphs showing the cost/cost ratios of diesel power system plans to geothermal power system plans for three growth scenarios. Denig-Chakroff and others CONCLUSIONS Although this is a very preliminary economic analysis,some general conclusions can be drawn from the results.It eppears that a geothermal power system may be competitive with a diesel power system on Unalaska Isiand.Major factors contributing to the economic feasibility of a geothermal system are the characteristics of the resource,the logistics of development and operation,and the power market conditions.In the case of Unalaska,construction and operation costs can be developed with a fair amount of certainty because the characteristics of the geothermal fluid and the deliverability of the reservoir have been well defined through flowtestsandreservoiranelyses(Economides andothers,1985).Major factors affecting the logistics of development have also been ascer- tained.Factors that are not known with the same degree of certainty are the future load growth of the community,the projected escalation rate of diesel fuel prices,and whether reinjection of geothermal fluids is necessary.Aspects of development that have not been addressed in this analysis,but which may have an effect on the feasibility of a gecthermal project,are the potential benefits that may be achieved from utilizing waste heat from the diesel power system for district heating in the community and thepotentialforcascadingusesofthe=spentgeothermalfluidafteritleavesthepowerplant. Based on this preliminary economic analysis,a more detailed study should be conducted to determine the feasibility of developing the Makushin geothermal reservoir for power generation on Unalaska Island,concentrating on load projections and market conditions in the community of Unalaska. ACKNOWLEDGMENTS The authors wish to extend a =e sincereexpressionofgratitudetoNancyGrossand veff Currier of the City of Unalaska and to Brent Petrie,Bob Loeffler,and Irene Tomory of the Alaska Power Authority for their assistance and support. REFERENCES Dames and Moore,1982.Aleutian regional airport,project documentation,report for the City of Unalaska,p.44-45. Economides,M.J.,Morris,C.W.,and Campbell, D.A.,1985.Evaluation of the Makushin geothermal reservoir,Unalaska Island, Proceedings of the Tenth Workshop on Geothermal Reservoir Engineering,SGP-TR-84, Stanford University,Stanford,Ca.,in press. Morrison-Knudson Company,inc.,1981.Geother- mal potential in the Aleutians:Unalaska, report for the Alaska Division of Energy and Power Development,p.2-5. Reeder,J.W.,ODenig-Chakroff,0.,and Economides,M.J.,1985.The geology and geothermal resource of the Makushin vol- cano region of Unalaska Island,Alaska, Transactions of the 1985 International Symposium on Geothermal Energy,Kailua- Kona,Hawai?,in press. Republic Geothermal,Inc.,1983.Unalaska geo- thermal project,phase IB final report for the Alaska Power Authority contract CC-08-2334,v.1,p.2 Republic Geothermal,Inc.,1984a.The Unalaska geothermal exploration project,phase I! final report for the Alaska Power Authority,contract CC-08-2334,p.X19- X25, Republic Geothermal,Inc.,1984b.The Unalaska geothermal exploration project,executive final report for the Alaska Power Authority,contract CC-08-2334,p.16-18. Republic Geothermal,Inc.,1984c.The Unalaska geothermal exploration project:electrical power generation analysis,final report for the Alaska Power Authority,contract CC-08-2334,p.48-51. A_-SUMMARY OF FINDINGS AND RECOMMENDATIONS A.1 -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: 1.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. 2.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. 3.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. 4.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. 5.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). 6.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. 7.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 cast of diesel fuel at Unalaska,a wind turbine would face stiff economic competition and would likely not show any advantage over the diesel system. I_-ECONOMIC EVALUATIONS OF ENERGY PLAN ALTERNATIVES I.1l -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 l5-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 tegardless 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. A_-SUMMARY OF FINDINGS AND RECOMMENDATIONS A.1 -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. 2.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. 3.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. 4.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. 5.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). 6.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. 7.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. 2000 oa 0 -2° 2 >asax=22.5oO a2oZz o«&o<OWwW> - atad . 5 we re © 3 D aa{ we 4 Ss a<zoa2o © =x rTom t, ' Lf ' BS 3 T ryt: co) 8 ro) 8vio + > a = FIDODMHCZOW OU SWOKCSKee- TODIENW FIGURE 3 UNALASKA, ALASKA 16 SMALL HYDROPOWERFEASIBILITY STUDYHISTORICAL & PROJECTED ENERGY Alaska District, Corps of Enginee |CQYNSSY)RESIDENTIAL,SMALL COMMERCIAL AND GOVERNMFNT iy \ =” (cosVp) g5 , IV : J= : ' £2>>. YVSA 28H©°+2&,omaWw. O}- tJoseFj&Oeg75 we uw' oajm 3 NN NY Za4o= NNN WN ou 5 MINN NNW or WY NNN 2 ANS NNN a3 NN NNN qs NNN ANN = ANY = NNNANN =a NN +LOCc toe| Wwp>=©wn ONVW30 1VLOL GEEZ 06 SSIYSNNVO GY O09 GNV IVIOYSWWOO TIVWS 'IVILN3GIS3SY GSKABK) >-=£>Se§aeWsmf69FHon t that jius,it res 2 and rgy>.jon in roughout ,the she same i on the rporatingple"local ential, until the ue to 'lation in full shows the jo.This d analysis ture ry <}.beeaBSSe a = y 3 't.@m ..S{>i 'Oo q oO.aha LY Lo Nx5=\Xo - \.Lt22:Sa >=o jog 2.3 . <Oo=C2 a . li © a)2 weeOwlweonus \°a=>5 \oyBoos-2 Oud.hdd \ \ 1 |ox \LL.o><<' \om Wi \-> \ '\\ \ t \ a !-\-ro)!pslibo >o oO -_ a a. i? <q Oo loved Oo -” =ro) *a9 F .@T'tT T T T t D ' °°"e 'S g ©o ¢a 7 g@ ge QO: Swocd Saker w FIGURE 2 15 UNALASKA,ALASKA SMALL HYOROPOWER FEASIBILITY STUDY HISTORICAL & PROJECTED CAPACITY Alaska District,Corps of Engineers