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Home My WebLink AboutAPA167EXHIBIT 0 PROJECT COSTS AND FINANCING Nl)"EMBER 1982 DRAFT _L ~i'~,., - FERC LICENSE APPLICATJON-.---'.-.-. Prepared by: ·I~IO , ~-I.)-,-----------"'---\\~\\;-,\,--·......-----r---------..-----,>n I :~\ iii! I,':,,-., .j, - SUSITNA HYDROELECTfflCPROJECT [}{l&OO~&c~®&®©© Susitna Joint Venture Document Number f t:-....~............ALASKA POWER AUTHQR ITY~....._,......--.-,...............--""""1(;'1 -,Iv- I'c'.I'!I'1{ I r; J ) j I '" JI I I.} ~ li, I I ,-' {>.'. " ~~l·~ ~ ,I 1 ---- , 1-1 1-1 1-1 1-2 1-3 1-4 1-5 1-5 1-5 1-6 1-8 1-8 1-9 1-9 1-10 1-10 1-11 1-11 1-11 1-12 1-12 1-12 2-1 3-1 3-1 3-1 3-2 3-3 3-3 3-4 3-4 List of Tables List of Figures EXHIBIT D ..PROJECT COSTS AND FINANCING 4 -EVALUATION OF ALTERNATIVE ENERGY PLANS .••••••o .....~••••••••4-1 4"1--General .......•...,..•.,'~.,..,..•.•,.•.,0 •••'••••••'•••••~'•J~,.'.4...·1, 4.2 -Existing Systern Characteristics tl 4-2 (a)System Deser i pti on o.•• ••••••• • •4-2 (b)Retirement Schedule '"....••••••••..•••••4-2 (c)Schedule of Additions 4-3 TABLE OF CONTENTS 1 -ESTIMATES OF COST ~~.~~~•• 1.1 -Construction Costs .•••...•'"•". Ca)Code of Accounts ". (b)Plpproach to Cost Estimating . (c)Cost''Oata.cr ••--:se ~'•.•:~••••....••••••.••••••'e,'. (d)Seasonal Influences on Productivity .. (e)Construction Methods . (f)Quant ity Takeoffs .H . (9)Indirect Construction Costs . 1.2 -Mitigation Costs . 1.3 -Engineering and Administration Costs .•••••..••.•••..• (a)Engineeri ng and Project fvlanagement Costs . (b)Construction Management Costs .. (c)Procurement Costs .0 "". (d)Owners.Costs . 1.4 -Operation,r~aintenance and Repl acement Costs ••••.0 .. 1.5 -Allowance for Funds lJsed During Construction . 1..6 -E'sc,;alati:on ill Ii •••,••e ...•••-u 1.7 Cash Flow and Manpower Loading Requirements . 1.•8 Contin,ge:nc',y ~..•••.,•-...•••••.••.,';'ft ••'•••',••e,I)• 1 ..9 -Previously Constructed Project Facilities ..••...••..• 1.10:-EBASCO Check Estimate 0 .. 2 -ESTIMATED ANNUAL PROJECT COSTS .•••••..•••••.•.•..•...•••.•. 3 -MARKET VALUE OF PROJECT POvlER . 3.1-The Railbelt Power System H •• 3.2 -Reg;on a1 E1 ectri c prywer Demand and Supply ~.. 3.3 -Market and Price for Watana Output in 1994 . 3.4 -Market Price for Watana Output 1995-2001 . 3.5 -Market and Price for Watana and Devil Canyon Output in2003'.••••...~~•.•~••~•••••••••9 •••••••$.~.. 3.6 -Potential Impact of state Appropriations .. 3 7 C '.''".,'--"one,IASlonS '"••••• 1 j I 1I J I 11 "r'_ I I .. I; REFERENCES Diesel Power Generation 0 ••••~.o 0 Pl an Formu1 ati on and Eval uat ion •.•.••••.......•• .. Pa.ge 4-3 4-4 4-4 4-5 4-6 4-9 4-9 4-10 4-11 401·12 4-13 4-13 4,·15 4-16 4..16 4,...16 4..17 4-18 4-27 4-32 4-32 4-33 4-34 4",34 4 ..35 4-36 4...45 5-1 5..1 5..1 6-1 6-1 6-1 6-1 6..2 Coal-Fired Steam .o.~.•"•••,'e . ,Combi'ned::eye l e:•••••'•~,It _•••••'..••••••~••.••••••••',8 n ~-·T··u··_L ':_-bas --,.r-.,J III ~'••'..'••'••'••-it iii :••"~a '•••'••'.;'.-."••••0'.'.'...-.'.'-._...; 6.1 -Forecast Financial Parameters . 6.2 -lnfl ationary Financing Deficit .o . 6.3 -Legislative Status of Al aska Power Authority and Sus itna Project ~. 6.4 -Financing Pl an .•,.. '4.3 Fairbanks -Anchorag.e Intertie .0 ·..···..·.. 4.4 -Hydroelectt·i~A1ternatives 0 0 ••.. (a)Sel ect ion.Process 0 • • • • • • • • (cb)Selected Si tes t,•••••0 •..••••• • (e)Lake Chakachamna 'O . 4 ..5 -Thermal Options ~...•.....•.......•..•...•.... (a).Assessment of Thermal Alternatives .'O ••••0 . (b) (c) .I i'\ rO} (e) (f) 4.6 -Without Sus;tna Plan ~"·••.• (a)System as of January 1993 "0 •••••••••• (b).System Additions . (cl System as of 2010 !"••••••• 4.7 -Economic Evaluation &. (a)Economic Principles and Parameters .,.. (b)Analysis of Net Economic Benefits "".. 408 -FtobabiJityAssessment and Risk Analysis .. (a)Multivariate Sensitivity Analysis ....•........•. (b)Compari son of Long-Term Costs 0 (c)Net Benefit Compari son . (d)Sensitivity of Results to Probabilities ..o .. 4.9 -Battelle Railbelt Alternati:ves Study :. (a)Alternatives Evaluation .to ••••••••• <.b.)Energy 'P-'ans ••'.~',•....'•.•...•...''•..•.iii ••••.,0 ••:••0 5 -CONSEQUENCES OF LICENSE DENIAL •••••..••.••.••••.....•..•••. 5.1 -Cost of License Denial . 5.2 ..Future Use of Damsites if License is Denied .•..•.•..•• 6 ~FINANCING ......•~_.:•..'.....•...•..•.,.~..~O ••6 •••,5 EXHIBIT D-TABLE OF CONTENTS (Continued) 1 I 1 I I 1 ~"I'··,~. I I '1.'.;':.~, I W.;.·~I M -r..... 11 ."{II.'.,j • !I.t.·~'.'.:'~ fa .I.~I ~•• t;• ~~,,"i 1~.•.\ I. j: ~ It Ii I l-~ I -, I, I I - LIST OF TABLES Table No .. 0 ..1 Summary of Cost Estimate 0.2 Estimate Summary -Watana 0.3 Estimate Summary -Devi 1 Canyon 0 ..4 Mitigation Measures -Summary of Costs Incorporated In Construction Cost Estimates . 0 ..5 Summary of Operation and Maintenance Costs 0 ..6 Watana and Devil Canyon Cumulative and Annual Cash Flow D.7 Pro-Former Financial Statements No Fund-No State Conttibut ion Scenario 0.8 Susitna Cost of Power 0.9 Forecast Financial Parameters 0.10 Railbelt Utilities Providing Market Potential 0.11 Li<st of Generating ~lants Supplying Railbelt Region 0.12 Total Generating Capacity Within the Railbelt System 0.13 Generating Units Within the Railbelt -1980 D.14 Schedule of Planned Utility Additions (1980-1988) D..15 Operating and Economic Parameters for Selected Hydroe1~ctric Plants D.16 Results of Economic Analyses of Alternative Generation Scenarios 0.17 Summary of Thermal Generatir.g Resource Plant Parameters/1982$ 0 ..18 Real (Inflation-Adjsuted)Annual Growth in Oil Prices D.19 Domestic Market Prices and Export Opportunity 'Values of Natural Gas 0.20 Summary of Coa]Opportunity Values 0.21 Summary of Fuel Prices Used in the OGP5 Probability Tree Analys.is 0 ..22 Economic Analysi.s Susitna Project -Base Plan D.23 Summary of Load Forecasts Used for Sensitivity Analysi.s 0.24 Load Forecast Sensitlvity Analysis 0.25 Discount Rate Sensitivity Analysis 0.26 Capital Cost Sensitivity Analysis 0 ..27 Sensitivity Analysis -Updated Base Plan (January 1982)Coal Prices 0.28 Sensitivity Analysis -Rea.1 Cost Escalation 0.29 Se;lsitivity Analysis -rJon-Susitna ~Plan withChakachamna 0 ..30 Sensitivity Analysis -Susitna Project Delay 0.31 Summal"y of Sensitivity Analysis Indexes of Net E:onomic Benefits 0 ..32 Battelle Alternatives StUdy for the Railbelt Candidate Electric Energy Generating Technologies 0.33 Battelle Alternatives StudYll Summary of Cost and Performance Characteristics of Selected Alternatives ., Watana Development Cumul at ive and Annual.Cash Flow January,1982 Doll ars Devil Canyon Development Cumulative and Annual Cash Flow January,1982 Dol'ars Sus:itna Hydroel eetrie Project Cumul ative and J\nnual Cash Flow Entire Project,January,1982 0011 ars Railbelt Region Generating and Transmission Facil ities Servi ce Areas of Rai lbelt Ut;l it i es Energy Supply;fenerating Facilities;Net Generation by Types of Fuel;Relative Mix of Electrical Generating Technology -Rai.lbelt Util iti.es-1980 Energy Demand and Deliveries From Susitna Energy Pr'icing Compari sons -1994 Sy.stemCosts Avoided by Developing Susitna Energy Pricing Comparisons -2003 Loe ati on Map FormUlation of Plans Incorporating Non-Susitna Hydro Generation Selected Alternative Hydroelectric Sites Generation Scenario Incorporating Thermal and Alernative Hydropower Developments -Med i urn La ~d Forecast Formulation of Plans Incorporating All-Thermal Generation Alternative Generation Scenario Battelle Medium Load Forecast Probabil ity Tree -System with ,Alternatives to Susitna Probabi 1ity Tree -System with Sus itna Susitna MUltivariate Sensitivity Analysis -Long-Term Costs vsCumul ative Probability SusitnaMultiva'riate Sensitivity Analysis -Curnul ative Probability vs Net Benefits . Energy Cost Comparison -iOO%Debt Financingoand7%Inflation LIST OF FIGURES 0.1 0.2 D.3 0.4 0.5 0..6 ~ Figure No • D.7 0.8 0.,9 0.10 0.11 0.12 D.13 D.14 0.15 0.16 0.17 0.18 0.19 D.,20 0.21 .""",'""".',''{"..,.'~-=".'".I""'....,".......J '•. .~frs',~.~,....,'"",,'~'..,.,~.:•J,.......'(~..~~'."4....... m rn '(j"".'...., ~ot,' I,,J ~',', ••'1.,!~ ~; :,1_- I IJ :11 .......... :. ••• I .1, lJ-Ill l;j tl II ~;~ _It, ..~ 1 ~ ~. I ~. i, I] I. I, {jIi i\ ! 1 -ESTIMATES OF COST j i, U ~ IJ ~ .~ IJ I I EXHIBIT D-PROJECT COSTS AND FINANCING Tbisexhibit presents the estimated project cost for the Susitna Hydroelectric Project,the market value of project power and a financing pl an for the project.Alternative sources of power which were studied are also presented. 1-ESTIMATES OF COST This section presents estimates of capital and operating costs for the Susitna Hydroelectric Project,comprising the Watanaand Devil Canyon deve.lopments and associated transmission and access faci.lities..The costs of design features and facil ities incorporated into the project· to mitigate environmental impacts during con struct ion and operation ~e.._-,-~._.-"_.-._.. identified.Cash flow schedules,outlining capital requirements during planning,construction,and start-up are presented.The approach to the derivation of the capital and operating costs estimates is described. The total cost of the Watana and Devil Canyon projects is summarized in Table 0.1.A more detailed breakdown of cost for each development is, present ed tn Tables 0.2 and 0.3. 1.1 -Construction Costs This section describes the process used for derivation of construction costs and discusses the Code of Accounts established,the basis for the estimates and the various assumptions made in arriving at the.esti- mates.For general consistency with pl anning studi.es,all costs devel .., oped for the'project are in January,1982 dollars. (a)Code of Accounts Estimates of construction costs were developed.using the FERC.for- mat as outlined in the Federal Code of Regulations,Title 18 (1).. The estimates have been subdivided into the fo'lowing main cost groupings: 1-1 • 1-2 The detai 1ed schedul e Of costs using this breakdown is presented in Reference 5. Further sUbdivision within these gro~pings was made on the basis of the various types of \J«>rk involved,as typically shown in the following example: Excavation Rock Production Plant Main Dam Structure Reservoir,Dam,and Waterways Main Dam" Costs for equipment and fac;1i - ties required for the.operation and mainten~nce of the produc- tion and transmi ssion pl ant. Costs that are conmon toa nurnber of construct ion act ivi - ties.For this estimate only camps have been identified in this group.The estimate for camps -incl udes el ectric power costs.Other indirect costs have been included in the costs under production,transmission, and general pl ant costs. Costs for engineering and admini stration. Costs for structures;equip- ment ,and faciTi ties necessary to produce power. Costs for structures,equip- ment,and fac;l ities necessary to transmit power from the sites to load centers. Description Indirect Costs Overhead Construction Costs General Plant Transmission Plant Graue. Production Plant -Group: ...Account 332: -Main Structure 332"3: ...E"'ement332"31: ...Work Item 332.311: ...Type of Work: (b)8J?proach to Cost Estimating. The estimating process used generally included the following steps: I ...•~......I..•~......;~- ~ I.e11!.1Ii mil ;1"' .•••.'ii..:\(~~.~ 11 (11 'I.~ ..~ IJ !~ 'I -I ·····11····.·· 'Ii, 1-3 Cost Data -Collection and assembly of detail ed cost.data for labor,mater- ial,and equipment as well as infonnation on prOductivity,cli- matic conditions,and ot.her rel ated items; a-hour shifts °9_hour shifts lO-hour shifts ., Mechanical/Electrical Work FormworklConcreteWork Excavation/Fill Work -[)eve1opment of construct ion ;ndirect-costs by review -of·l abor, material,equipment,.supporting.facilities,and overheads;and -Deve10pment of construct ion camp S1 ze and support requ;rements from the 1abor demand generated by tht:;construction direct and indirect costs. -Revie\'1 of engineering draWings and technical information with regard to construction methodology and feasibil ity; -Product ion of detail ed quarlltity takeoffs from drawi ngs in .accor- dance with the previously developed Code of Accounts and item 1isting; -Determination of direct unit costs for each major type of \\Qrk by development of labor,material,and equipment requirements; development of other costs by use of estimating guides,quota-' tions from vendors,and other infohfiatiofi as appropri ate; Cost information was obtained from standard estimating sources, from sources in Alaska,from quotes by major equipment suppliers and vendors,and from representativ.e recent hydroelectric pro- jects:Labor and equipment costs for 1982 were developed from a number of soUrces (2,3)and from anana1ys;s of costs for recent projects performed in the Alaska environment. It has been assumed that most contractors tli 11 w:>rk an average of two lO-hour shifts per day,6 days per week.Due to the severe compression of construction activities in 1985-86,it has been assumed that most work in this period Will be on two 12-hour shifts.,7 days per week. The lO-hour work shift assumption provides for high utilization of construction equipment and reasonable levels of overtime earnings to attract workers •The two-shift basis generally achieves the most economical hal ance between labor and camp costs .. .Constr'uction equipment costs were obtained from vendors on an FOB Anchorage basis with an appropr i ate all owance included for trans- port<ltion to site.A representative list of construction e.quip- ment required for the project was assembled as a basis for the estimate.It has been assumed that most equipment would be fully depreciated over the life of the project~For some activities (c)t'·~'H:t ~1~:' l~,~; IfI: ~",t ~I "\ t l (' " [ 11~ I I [I''! I ~; _.r;J.J_,~ (d) such as construct;-on of theWatana main dam,an allowance for major overhaul was included rather than fleet replacement.Equip"" ment operating costs were estimated from industry source data, with appropriate modifications for the remote nature and extreme climatic environment of the site.Alaskan labor rates were used for equipment ma;ntenance and .repair..Fuel and 0;1 prices have been based upon FOB site pric~s. Information for permanent mechanical and electrical equipment was obtained from vendors and manufacturers who provided guidel ine . costs on major power plant equipment. The costs of materials required for site construction were esti- mated on the basi s of supp 1 iers J quotat ions with allowances for shi.ppi ng to site .. Seasonal Influences-nn Prm~uctivlty~_.--~,...._. A review of climatic conditions together with an analysis of experience in Al askaandin Northern Canada on large construction projects was undertaken to determine the average duration for various key activities.It has been projected that most aboveground activities will eithe.r stop or be curtailed during the period of December and JanUiiry becaus.e of the extreme cold weather and the ass.ociated lower prt>ductivity.For the main dam construction activitiesJ the folloWing seasons have been used: -Watana dam fi 11 -6-month season;and -Devi 1 Canyon arch dam -H-month season. Other aboveground actiVities are assumed to extend up to 11 months depending on the type of ~Nork and the criticality of the schedule. Underground activities are generally not affected by climate and should continue throughout the year. Studi es by others (4)haVe indicated a 60 percent or greater decrease in efficiency .fin constr'uction operations under adverse winter conditions..Therefore,it is expected that most contractors would attempt to schedule outside work over a period of between 6 to 10 months. Studies performed as part of thi swork program indicate that the general construction activity at the Susitna damsite during the months of April thrQugh September would be comparable with that in the northern sections ·of the western United States..Rainfall in the general region of the site is moderate between mid-April and mid-October,.ranging from a low of 0.75 inches precipitation in April to a high of 5.33 inches in August.Temperatures in tois period range fram 33°F to 66°F for a twenty-year average...In the five-month period from November through March the.temperature ranges from 9.4°F to 20.3°F J with snowfall of 10 inches per month. 1...4 [,. l- EI' .t' J. [ "':V ·,'L, Ir::~t .1I.• tr _r .,''': " ~: II 'I'i"!; II.: ,i: j [ I I t'·..f:f j .....0;. 11 l IrIi I ( ( (e)Constructi on Mf~thods The construction methods assumed for development of the estimate and cQnstructJlon schedule are generallY considered .as normal to the industry,in line with the available level of technical information"A conservative approach has been taken in those clreaswheremore detailed information wi 11 be developed during s;ubsequent invest;g at i on and eng;neer i og programs •for example, norrnal dri 1.il ;r~g,hI ast iog,and mucki ng methods have been assumed for all underground excavation.Conventional equipment has also been considered for major fill and concrete WOrk • (f)Quantity Takeoffs Detail ed quantity takeoffS were produced from the engineet"ing draWings using methods normal to the industry.Thequantities developed are listed in the detail ed summary estimates in Appendix C to the Susitna Hydroelectric Feasibility Report (5). (g)Indirect Construction Costs Indirect construction costs were estimated in detail for the civil construction activities.A more general evaluation was used for thernechanieal and el ectrical viOrk. Indirect costsineluded the following: -Mobi1i zat;on; ...Techniealand supervisory personnel above the level of trades foremen; ...fill vehicle costs for supe.rv;sory personnel; ,.Fixed offices,mobile offices,workshops,storage fae;l ities, and 1aydown areas,inclUding all services; ...l',eneral transportation for-workmen on site'and off site; -Yard cranes and floats; ...Utilities including electrical power,heat,water,and com- pressed air; ...Small tools; ...Safety program and equ;pment; -fi nanc;og; 1-5 1'~''1'~ --.~: ; 1 11' ~.~ I,,' -~,, I;' 11 'I, '1'\"r -.~ I"~:ll, I, I,' .J I"....... I. I- I." I I I"~ • -Bonds and securities; -Insuraoct:!; -Taxes; Permits; -Head office overhead; ..Cont.ingency allowance;and -Profit .. In developing contractors indirect costs,the following assumptions have been made: -Mobil i zation costs have generally been spread QveY'~onstr'Jction. items; _No escalation allowances have been made,and "..hereforeany risks associated with escalation are not included; _Financing of progress payments has been estimated for 45 days, the average time between expenditure and reimbursement; -Holdback would be 1imited to a nominal a;nount; _Project all-ri skinsurance has been estimated as a contractor's indirect cost for this estimate,but it is expected that this insurance would be carried by the owner;and _Contract packagi ng woul d provide for the supply of major mater- ials to contractors at site at cost.These include fuel,elec- tric power,cement,and reinforcing steel. 1.2-Mitigation Costs The project arrangement incl udes a,number of features des;gned to mitigate potential impacts on the natural environ!J1ent and on residents and communities in the vicinity of the project.In addition,a number of measures are pl anned duri ng construction of the project to reduce similar impacts caused by construction activities.These measures and facilities represent additional costs to the project than would otherwise be required for safe and efficient operation of a hydroelectric development.These mitigation costs have been estimated at $153 million and have.been summarized in Table D.4.In addition, 1...,6 .. ,1 -\..'; 1 ,! I- I t "'" , j 11 I I I I I I! I I I. I I I the costs of ful]reservoir clearing at both sites has been estimated at $85 million.AlthQugh full clearing is considered good engineering pr?i,ct;ce,it is not essential to theoperatioo of the power facilities. These costs include direct and indirect costs,engineering, administration,and contingencies. [NOTE:Thls .section will be revised to be made exact after the completion of mitigation pl anning.] A number of mitigation costs are associated with facilities, impr,Qvementsor other programs not directly rel ated ·to the project or located outside the pro,jectboundaries.Thesev/ould include the following items: ...CaribOU barriers; ...Fish channels; ...Fish hatcheries; ...Stream improvements; ...Salt 1icks;. ...Recreational facil it ies; ...Habitat management for moose; -Fish stocklng program in reservoirs;and ....Land acquistioncost for recreation. It is anticipated that some of these features or programs will not be required duvtng or after construction of the project.In this regard a probabil 'tty factor has been assigned to each of the above items,and the est ima'ted cost of each reduced accord;ngly..The estimated cost of these measures has been covered in the construction contingency. A number of studies and programs will be required to monitor the, impacts of the project on the environment and to develop and record various data during project construction and operation.These include: ....Archaeological stodies; ..Fisheries and wildl ife studies; ...Right"of...wa.y stUdies;and ...Socioeconomic planning studies. The costs for the above work have been incl uded in the o\'JOer's costs under project overheads. 1..7 I·-~.;.··.1J 11 IJ I 11 I I 11.·.'! I I I I I • I I I I 1.3 -Eng;neering and Adrninistration Costs Engineering has been subdivided into the following accounts for the purpose]of the cost estimates: -Account 71 •Engineer;ng ~.nd Project Management ..Construction Management •Procurement -Account 76 ..(Mner I s Costs The total cost of engineering and administrative activities has been e.stimated at 12.5 percent of the total construct ion costs,incl udi ng contingencies.A detailed breakdown of these costs is dependent on the organizational structure established to undertake design and management of the project,as well as more definitive data relating to the scope and nature of the various project components.However,the main elements of cost included are as follows: (a)Engineering and Project Management CuSt2. These costs include allowances for: _Feasibility studies,including site surveys.and investigations and logistics support; ..Preparation of the 1icenseappl ication to the FERC; ...Technical and administrative input for other federal,state and local permit and license appl ications; _Overall coordination and administration of engineering,con- struction management,and procurement activities; _Overall planning,coordination,and monitoring activities related to cost and schedule of the project; -Coordination with and reporting to the Power Authority regarding all asper'ts of the project; -Prel iminary and detailed des;gn; _Technical input to procurement of construction services,support services,and equi pment; • r ·I'~ :",1 I' I' I; I' 'I';,, ; I; ( I I J' ,;A. I "'ii .. I m I m 'I 11 ....Monitori ng of construction to ensure conformance to des;gn requi rements ;, Preparation of start ...up and acceptance test procedures,;and _Preparation of project operating and maintenancemallua.is. (b)Construct.ionManagement Costs Construction management costs have been assumed to incl ude: _Initial planning and scheduling and establishment of project procedures and organ;zation; _Coordination of onsite contractors and construction manag.ement activities; ...Administration of onsite contractors to ensure harmony of trades,compliance with appl icable regUlations,and maintenance of adequate site security and safety requirements; _ Development,coordination,and monitoring of construction schedules; ...Construction cost control; ~Materi aI,eqUipment and drawing control; _Inspection of construction and survey control; -Measurement for payment; ...St.art...up and accept ance tests for equ;pment and sys tems; ...Compilation of as-constructed records;and ...Final accep~ance. (c)ProcurementCosts Procurement costs have been assumed to include: ...Establishment of project procurement procedures; ...Preparat ion of non ...techn ic al procurement documents; ...Sol icitat i on and review of bids for construct ion services,sup- port services,permanent equi pment,and other items requi red to complete,the project; -Cost administration and control for procurement contracts;and 1....9 • r I~ I~ 'I~' ,Ie, I' I: I~ 'I'" I I m Ii.. t I.,'IJ W ~'~ 'i; 11 -Quality assurance services during fabrication Ot manufacture of equipment and other pur-chased items. (d)Owner's Costs Owner's costs have been assumed to include the following: -Administration and coordination of project management ana engineering organi,zations;, Coordination with other state,local,and federal agencies and groups having jurisdiction or interest in the project; -Coordination with interested public groups and individuals; -Reporting to legislature and the public on the progress of the project;and -Legal costs 1.4 -Operati.on,Maintenance and Replacement Costs The facilities and procedures for operation and maintenance of the project are described in Section 15 of the Susitna Hydro(:~lectric Project Feasibility Report,Volume 1.Assumptions for the size and extent of these facilities have been made on the basis of experience at large hydroe.lectric developments in northern climats.The annual costs for operation and maintenance for the Watana development have been estimated at $10 million.When Devil Canyon is brought on line these costs increase to $15.2.million per annum.Int,erim rep,lacementcosts have been estimated at .3 percent per annum of the capital cost. The breakdown in Table D..5 is prOVided in support of the allowance used in the finance/economic analysis of the Susitna Hydroelectric Project. It is based on an operating plan involving full staffing of power plant and permanent town site support personnel.A total of 1.05 wi 11 be employed forWatana with another 25 to be added when Dev'n Canyon comes on-line..This manpower level will provide manned supervisory staff on a 24-hour,3 shift basis,with maintenance crews to handle all but major overhaulsc A nominal allowance has been made for major maintenance work which woul d uti 1i ze contracted 1abor '/It is unl ikely that major overhauls will be necessary in the first 10 years of project operation..In earlier years,this allowance is a prUdent provision for unexpected start-up costs over and above those coverE~d by warranty. Allowance for contracted services also covers helicopter operations and access road snow-c leari pg and maintenance .. 1...10 I '.\. I I I I I I I I I IJ _I I I :1 IJ ID III Allowances have also been made for environmental mitigation as well as a .contigenc.y for unforseen costs. Estimates for Susitn~have been based on ori gina1 estimates and actual experience at Churchill Falls.It should be realized that alternative operating plans are possible which would eliminate the need for petmanent town site facil ities and rely on more remote supervisory systemsand/or operations/maintenancecrews transported to the pl ant on a rotating shift basis.Cost imp];cations of these alternatives have not yet been examined. 1.5 '"'Allowance for Funds Used During Construction At current high levels of interest rates ;n the financial marketplace, AFDC will amount to a significant element of financing cost for the lengthy periods required for construction of the Watana and Devil Canyon projects.-However~in economic evaluations of theSusitna project the low real rates of interest assumed would have a much reduced impact on assumed project deve.lopment costs.Furthermore, direct state involvement in financing of the Susitna project \'lillalso have a significant impact on the amount,if any,of AFDC.For purposes of the feasibility study,therefore,the conventional practice of calculating AFDC as a separate line item for inclusion as part of project construction cost has not been followed.Provisions for AFDC at appropri ate rates of interest are made in the economic and financi~l analyses included in this Exhibit. 1.6 -Escalation All costs presented in thi s Exhi bit are at January 1982 1evel s,and consequently include no allowance for future cost escalation.ThUS, these costs would not be truly representative of construction and procurement bid prices..This is because provision must be made in such bids for continuing escalation of costs,and the extent and variation of escalation which might take place over the lengthy construction periods involved.Economic mud financial evaluations take full account of such escalation at appropriate rates.These rates are shown in Table D.9. 1.7 -Cash F t ow and--.t1anpower Loadi og Requirements' The cash flow requirements for construction of Watana and Devil Canyon are an essential input to economic and financial planning studie.s.The bases for the cash flow are the construction cost estimates in January 1982 dollars and the.construction schedules presented in Exhibit Ct with no provision being made as such for escalation.The cash flow estimates were computed on an annual bas is and do not inc lude adjustments for advanced payments for mObilization Or for holdbacks on construction contracts.The results are presented in Table 0.6 and Figures 0.1 through 0.3.The manpower loading requirements were 1...11 I I I I 1 I 'I I I I I I 11 IJ .1 I IJ IJ IJ IJ III developed from cash flow projections.These curves were used as the basts for camp loading and associated socioeconomic impact studies. 1.8 -Contingency A contingency al10wan(:e.of 17.5 percent of construction costs has been included ;n the cost estimates.The contingencyi s estimated to include cost increases which may occur in the deta.iledeogineering phase of the project after more comprehensive site investigations and final designs have been completed and after the requirements of various concernedagenci es have been s·atisfied.The cont ingencyest imate also includes allowances for inherent uncertainties in costs of labor, equipment and materials,and for unforeseen conditions which may be encountered during construction.Escal ati on 'I n costs due to inflation is not included.No allowance has been inc""ded for costs associated wi th s i go i fi c ant del ays .in.proj ect~j mp 1ement elti on. 1 ..9 -Previously Constructed Project Facilities An electrical intertie between the major load centers of Fairbanks and Anchorage is currently under construction.The line will connect existing transmission systems at Willow in the.south and Healy in the north.The intertie is being built to the same standards as those proposed for the Susitna project transmission lines and If/ill become part of the licensed project.The line will be energized initially at 138kV in 1984 and will operate at 345 kV after the Watana phase of the Susitna project is complete. The current estimate for the completed iotertie is $130.8 million .. This cost is not included in the cost estimates of this section. 1 ..10-EBASCO Check Estimate An independent chck estimate was undertaken by EBASCO Services Incorporated.The estimate was based on engineering drawings, technical information and quantities prepared by Acres.Major quantity items were checked.The EBASCOcheck estimated capita.'cost was apprOXimately 7 percent above the Acres estimate . . A meeting \"as held with APA,EBASCO and Acres torev·j ew difference~in the estimates.It was generally possible to reconcile the differences and it was conclUded that no major changes were required in the Feasibility Report estimate. 1-12 • I I I I I ,'1,,I I ill 11 IJ 8t,Ij IJ IJ Iii'11 III ·mt ~~ ,¥ t' II::W 2 -ESTIMATED ANNUAL PROJECT COSTS I I I ", I I I I I I I I} .11 :1) IJ IJ ~. 2 --ESTIMATED ANNUAL PROJECT COSTS Asa two-stage (Watana and Devil Canyon)development with va'rying levels of energy output and the assumption of ongoing infl ation (at 7 percent per annum),the real cost of Susitna power wi 11 be continually varying.Asa consequence,no simple single value real cost of power can be used. Table D.7gives the projected year-by-year projection energy levels a-fir" the first line and the second,the year-by-year unit cost of power in 1982 dollars.Costs are based on power sales at cost assuming 100 percrent debt fi nance at 10 percent interest.Thi sis seen to resul t in a real cost of power of 128 mi 11 s in 1994 (fi rst 'normal'year of Wata,na)falling to 72.76 mills in 2003 (the first 'normal'year of Wat(ma and Devil Canyon).The real cost of power would then fall pro9ressively for the whole remaining life. The Cost of Power given in Table D.8is designed to reflect as fully as possible the economic cost of pwoet for purposes of broad comparison with alternative power options.It is,therefore,based on the capacity cost which would arise if the project were 100 percent debt financed at market rates of interest.It does not reflect the price at which power will be charged into the system.This,on the financing plan shown in Section 6 is given on RL 521 of Table D.36. 2..1 - -I I I I 11, ~l', -;-,\ I i ......,-' 1< I I,,~ __.•.J 11 ,, I,l _"-t j I·; :1' '11,I' ".. 'I".' ,~.. IJ' ,-1l "( '~',~ -$ IU",-t1 :l ,II ~. lli 3 -MAHKET VALUE OF PROJECT POWER •• I I 1..•..1,) 11.·1't I I I ....j I 11 I: Ii I) .. 11 "1 1 j I,~ I~ IJ 'IJ ~ ~ 3 -MARKET VALUE OF PROJECT POWER This section presents an assessment of the market in the Rai lbelt region for the energy and capacity of the Susitna development..A range of rates at which this power could be priced is presented together with a proposed bas is for contract;n9 for the supply of Susitna energy ... 3 ..1-The Railbelt Power System Susitna capacity and energy will be del ivered to the "Rai lbelt Region Interconnected Systemll which will result from the linkage af the Anchoragegnd Fairbanks systems by an intertie to be completed in the mid-1980s. The Railbelt region covers the Anchorage-Cook Inlet area,the Fairbanks-Tanana Val1-ey areai'and the Glennallen-Valdez area (Figure 0.4).The utilities,military installations and universities \'lithin this region which own electric generating.facilities are listed in Table D.10 ..The set"'vice areas of these utilities are shown in Fi gure U.5 and the generat ing plants serv'j og the regi on are 1 i sted in Table D..11. The Railbelt region is currently served by nine major utility systems; five ate rural electric cooperatives,three are municipally owned and operated,and one isa federal wholesaler.The relative mix of electric generating technologies and types of fuel used by the Railbelt utilities in 1980 is summarized in Figure D.6. In 1980~the Anchorage-Cook Inlet area had 81 percent,the Fairbanks-Tanana Valley area 17 percent,and the Glennallen-Valdez area 2 percent of the total energy sales in the Railbelt region. Due to the pending construction of the Willow to Healy transmission line,the Anchorage and Fairbanks po\'/er systems will be intertied before the Susitna Project comes into operation.The proposed intertie will allow a capacity transfer of up to 70 MW in either direction.The proposed p'fan of interconnection envisages initial operation at 138 kV with subsequent uprating to 345 kV allowing the line to be integrated into the Susitna tt'ansmission facillties ... 3.2-Regional Electric Power Demand and Supply A review of the socioeconomic scenarios upon which forecasts of electric power demand were based is presented in ExhibitS of this .. • I I' I I) I I I. .1, I'I I~ I I~ l l l l L .~ appli cat i on ~The forecasts used here are in the mid-range levels made by Battelle Northwest in December 1981.The results of studies presented in Exhi.bit B call for Watana to come into operation in 1993 and to del i ver a full year's energy~\eneration in 1994.Devil Canyon will come into operation in 2002 and deliver a full year's energy in 2003 •.Energy demand in the Railbelt region and the deliveries from Susitnaare shown in Figure D.7. 3.3 -Ma\"ket and Price for Watana Output in 1994 It has been assumed that Watana energy will be supplied at a single Wholesale rate on a free market basis.This requires,in effect,that Susitna energy be priced so that it ;'s attractive even to utilities with the lowest cost alternative source of energy..On this basis it is estimated that for the initially mark.etabl e 3315 GWh of energy generated by Watana in 1994 to be attractive,a price of 145 mills per kWh in 1994 dollars is reqUired.Justification for this price is ;llustrated in Fi gure n..8.Note that the assumpti on is made that the only capital costs which would be avoided in the early 1990s would be those due to the alternative addition of new coal-fired generating plants (i.e.,the 2 x 20QMW coal-fired Beluga station).The Susitna energy price of 145 mills/kWh suggested here matches closely the value determined from generation planning analysis.in the financial eval uation • The financing considerations under which it would be appropriate for Watana energy to be sold at approximately 145 mills per kWh price are considered in Section 6 of this Exhibit;however lr it shOUld be noted that some of the energy which would be displaced byWatana's production would have been generated at a lower cost than 145 mills,andutilities might wish to delay accepting it at this price until the escalating cost of natural ..gas or other fuels made it more attractive.A number of approaches to the resolution of this problem can be postulated, inclUding pr.e-contruct arrangements. The Power Authority will seek to contract With Railbelt Utilities for the purchase of Susitna capacity and energy on a basi s appropri ate to support financi og of the project. ·Pricing policies for Susitna output,as defined by the Alaska legis'lature,will be constrained by both cost and by the price of energy from the best alternative option.These options are discussed in Section 4 of this Exhibit. Marketing Susitna's output within these tW'in costraints would ensure that all state financial support for Susitna flowed through to consumers and under no circumstances would prices to consumers be 3-2 I I I I I I' I I I I I I I IIIt. I • In U~..M I, higher than they would have been under the best alternative option.In addition,consumers would also obtain the long-term economic benefits of Susitna's stable cost of energy. 3.4 -Market Price for Watana Output 1995 ...2001 After its initial entry into the system ;n 1994,the price and market for the total 3387Gwh of Watana output is consistently uphel d over the years to 2001 by the projected 20 percent increase in total demand over tni s period as projected in Exhibit B forecasts .. There would,as a reSUlt,be a 70 percent increase in cost savings compared with the best thermal generating alternative.:the increas ing cost per unit of output from a system without Susitna is illustrated in Figure 0 ..9. The addition of the Susitna project will add a large generating resource'rn the system in 1993,displacing a'significant amount of'the e:<;sti n9 generati ng resources in the system.The project wi 11 pY'ovide about 70 percent of total energy demand.The displ aced units 'IIi 11 be used as reserve capacity and to meet growing load until the Devil Canyon project comes on line.This effect is illustrated on Fi guy'e 'D~7 .. 3.5 -Market and Price forWatana and Devi 1 Canyon Output in 2003 A diagramatic analysis of the total cost savings which the combined Watana and Devi 1 Canyon output wi 11 confer on the system compared with the alternative thermal option ;n the year 2003 is shown in Figure 0.10..These total savings are divided by the energy contributed by Susitna to indicate a price of 250 mi l1s per kWh as the maximum price Which can be charged for Susitna output. Only about 90 percent of the total Susitna.energy output will be absorbed by the systerriin 2002;the bal ance of the output wi 11 be progressively absorbed over the following decade.This will provide additional total savings to the system with Susitna since no other resources will be needed. After the Devil Can'yon project comes on line,the Susitna project will provide 90 percent of the energy demand.The excess Susitna power occurs in the summer while additional energy from other resources is requi red in the winter.The generati 09 resources di spl aced are units nearing retirement and will be used as reserve capacity.,This effect is shown on Figure 0.7 . 3...3 I I I I I I I I 1I ;1,.IJl.• ;:.1 I +~ •..•..·.~.l •..••...'. :'j \1'cil"..:"~'!I .'. I..1.(OJ 1 1 ;11'j .•... 'f(t<..it ;'.'11 ,:........I:.·'.J',~,:, t.' ,., :.••.•.a,..·1·.··.'~.I'f ••I..'.~:."II ,~ :~r~ ;:.:1 ·11·.·•...••..i;~..." ;',:...:,1 :"~1; t~1;~I,IJ11.1 .1'1'·.'.,'".'",',~'. ~;;.'. A i ;- 3 ..6 ..fotential Impact of State APpropri ations In the preceding paragraphs the maximum price at whi ch Susitna energy could be sold has been ident<ified.Sale of the energy at these prices will depend upoD the magnitude of any proposed state appropri ation designed to reduce the cost of Susitna energy in the e~rl i er'years.."At significantly lower prices it is 1 ikely that the total system demand will be.higher than assumed.Thi s ~combi ned with a state appropriation to reduce the energy cost of Watana energy,would make it correspondingly easier to market the output from the Susitna development;however,as the preceding analysis shows,a viable and strengthening market exists for the energy from the development that would make it possible to price the output up to the cost of.the best thermal alternative. 3.7--Conclusions Based on the assessment of the market for power and energy output from the Susitna Hydroel ectric Project,it has been conel uded that~~ith the appropriate level of state appropriation and with pricing policy as defined in Alaska State Laws,a viable basis exists for the Susitna power to be absorbed by the Railbelt utilities. I 3-4 ,I l II U' ~, U, U, 4-EVALUATION OF ALTERNATIVE ENtRGY PLANS 4 -EVALUATION OF ALTERNATIVE ENERGY PLANS 4.1 -General This section describes the process of assembling the 'information 'leces ... sary to carry aut the sy~:,temwide generation plnnning studies necessary for assessment of E!conomfc feasibi.lity of the Susitna Project.Includ- ed iStl.discussion of thf~.existing system characteristics j thl=l planned Anchorage-Fairbank~)iniertie,and details of var-ious generat;1'lg options including hydroelectric and thel"mal.Performance and cost information required for the generation planning studies is presented for the hydroelectric and thermal generation options considered. The approach taken in economically evaluating the Sus'ii;na project involved the development of long term generation plans for the Rai1belt e.1 ectrical supply-1;ystem with-'andwithout the proposed project.In order to compare the with and without plans,the cost of the plans were compared on a presl:nt worth basi s.A generation pl ann;ng model whi ch simulated the operation of the system annually was used to project the annual generation costs .. Durirtg the pre-l ic~~nse phase of the Susitna project pl anning,two studies pro.ceeded 'in parallel which addressed the alternatives in generating power in the Alaska Railbelte These stud'ies are the Susitna Hydroelectric Project Feasibility Study done by Acres American Incorporated for theAl aska Power Authority and the Rai 1belt Electric Power Alternatives Study done by Battelle Pacific Northwest Laboratories for the Office of the Governor,State of Al aska., One objective of the Susitna Feasibility was to determine the feasibility of the proposed project.The economic evaluations done during study found the project to be feasible as documented in this exhibit.The.indeplendent stUdy done by Battelle focused on the feasibility of all possible generating and conservation alternatives, Although the studie!s were independent,several key factors were consistent.Both studies used the approach of comparing costs by using generation planning simulation models.ThUS,selected alternatives were put i nta a pI an context and theit economi c performance compared by compari n9.costs of the plans.Additionally,parameters such as costs for fuel and capital costs and es:calation were consistent between the twostudi eS .. The following presentation focuses primarilY on the Susitna Feasibility study process and findings.A separate sect'jon provides the findings of the Battelle Study,which generally agree with the feasibility study findings .. 4-1 .. • 30 years 35 years 20 years 30 years 30 years 30 years 50 years I..''.--"".. sg=; 4...2 -Combined Cycle Units: -Conventional Hydro: -Diesels: -Large Coal ...Fired Steam Turbines (>100 MW): -Small Coal-Fi red Steam Turbines «100 MW): -Oil ..FiredGas Turbines.; -N<atura1 Gas-Fired Gas Turbines: .. (a)System Description The.tWd major 10ad centers of the Railbeltregion are the Anchorage-Cook In 1 etarea and the Fairbanks-Tanana Valley area ($ee Figure D.11),which,.at present,operate indepenrlently.The existing transmission system betwe.en Anchorage and Willow consists ofa network of 115 kV and 138 kV lines with interconnection to Palmer.Fairbanks is primari ly served by a 138 kV 1ine from the 28 MW coal-fired plant at Healy"Comnunities between Willow and Healy are served by local distribut'lon. There are currently nine electric utilities (including the Alaska Power Administration)prov~din9 power and energy to the Railbelt system.Table 0.12 summarizes the total generating capacity within the Railbelt system;n 1980,based on information prOVided by Railbelt utilities and other sources.Table 0.13 presents the resulting detailed listing of units currently operating in the Railbelt,information on their performance characteristics,and their online and projected retirement dates for generation planning purposes.The total Railbelt installed capacity of 984 MW as of 1980 consists of two hydroelectric plants totaling 46 MW plUS 938 MW of thermal generation units fired by oil,gas,or coal,as summarized in Table 0..14. (b)Retirement Schedul e In order to establish a retirement policy for the existing gener- ating units,several sources were consulted,including the Power Authority's draft feasibil ity stUdy gui del ines,FERGguidel ines, the Battelle Railbelt Alternatives StUdy,and historical records. Utilities,particularly those in the Fa.irbanks area~were also consulted.Based on these sources,the following retirement peri ods of operation'were adopted for use in th is analys;s: 4 ..2 ..Existing System Characteristics I';! I:"", :::'. ~, •.:' :~r ! "1- r; I tf1' lit I I '~ C W m W IJ ~'J,,..:~ l~ IJ 1< ,': 1<;".· i,... I~ I I""· " :lJ J"m ~. m In m, .~ w Im ...·.l·'..~ 1"·,:1 :,"., i Table D.14 lists the retirement dates for each of the current generating units based on the above retirement policy. (c)Schedule of Additions Six new projects were expected to be added to the Railbelt system prior to 1990.The Chugach Electric Association is in the process of adding gas-fired combined-cyel e capacity in Anchorage at a plant called Beluga No ..8.When camp"lete,the total plant capacity will be 178 MW,but the plant will encompass existing Units 6 and 7.Chugach added a 26.4 MW gas turbine rehab;l itation at Bernice Lake No.4 in August 1982. The Corps of Engineers is currently in the post-author"j zat;on planning phase for the Bradley Lake hydroelectric project located on the Kenai Peninsula.The project would include between 60 and 135 MW of install ed ..capacity.and.would produce an average annual en~r.gy of 350 Gwh.For analysis purposes,the project is assumed ta come on line in 1988. Three other un;ts are also sctH~dul ed or have bE~en added to the system since 1980.Anchorage Municipal Light tmd Power Department is planning to add a 90 Ml~gas turbine in 1983··84 called AMLPD No. 8e.Copper Valley Electric Association i~operating the new 12 MW Solomon Gulch Hydroelectric Project which is o~med by the Al aska Power Authority.Finally,the 7 HW Grant Lake Hydroelectric Proj ect 'is undergo;ng planning for add iti on to the system in 1988 by the Alaska Power Authority. 4.3 -Fairbanks -Anchorage Intertie Engineering studies have been undertaken for construction of an inter- tie between the Anchorage and Fa;rbanks systems.As.presently envi s- aged,this ~connection will involve a 345-kV transmis.sion line between wtllow and Healy sche.f"~oled for completion in 1984.The line will initially be operated at 138 kV ,With the ca.pability for expansion as the loads grow in the load centers. Based on these evaluat;ons~it was concluded that an interconnected system should be assumed for the generation plann.inSI studies,and that the basic intertie fa.cilities would be common to all generation scenarios considered. Costs of additional transmission facilities were added to the scenarios as necessary for each unit added.In the "with Susitna"scenarios,the costs of adding circuits to the intertie corridor were added to the 4-3 ··I.~·!.·•...« I I··.·..·.'.·.··:~ J I IiII I I I ·.'J.ll .j IJ'1--; ,'j IJ Il II... rI .lJt].. 'j .~d <i I IJ :.1,:.'.lj~i'E:'1-·' f I Susitna project cost.For the non-Susitna units,transmission costs were added as follows: No eosts were added for combined-eyel e or gas-turbine units,5i nee they were assumed to have sufficient siting fl exi bi 1i ty to be placed near the major transmi s5i on works; _A.multiple coal-fired unit "development in the Beluga fields was esti ... mat.ed to have a transmission system with equal security to that pI anned for Susitna,costing $220 mi 11 ion.This system woul d tak.e power from the bus back to the existing load center;and _ A single coal ...fired unit development in the Nenana area using coal mined in the Healy fields would reqUire a transmission system costing $117 million dollars .. With the addittonofa unit in'lhe Fairbanks area in the l'3'90s,no additions to the 345kV line were considered necessary.Tbus,no other transmission changes were made to the non-Susitna plans. 4.4 ...Hydroelectric Alternatives Numerous studies of hydroel ectric potenti al in Al aska have been under- taken.These date as far back as 1947 and were performed by various agencies including the then Federal Power Comnission,th r Cor,ps of Engineers,the u.s.Bureau of Reclamation,the U.S.Geological Survey, and the State of Al aska.A significant amQunt of the identified potential is located in the Rai1be1t region,;.ncluding sevE~ralsites in the Susitna River Basin. (a)Selection Process The application of the five-step methodology (Figure 0.12)for selection of non-Susitna plans which incorporate hydroelectric developments is summarized in this section.The analysis was completed in early 198.1.and is based on Januaty 1981 cost figures; all other parameters are contained in the Development Selection Report (6).Step 1 of this process essentially established the overall objective of the exercise as the select-ion of an optimum Railbelt generation plan which incorporated the proposed nOn- Susitna hydroel ectri c developments for compari son with other plans. Under Step 2 of the selection process,all feasible candidate sites were identified for inclusion in the subsequent screening exercise.A total of 91 potent;a.1 sites were obtained from inventories of potential sites published '1n theCaE National 4-4 • .~",....."..',,\ ,:1 U .1'·;·':··'1••.i'liii (b) Hydropower Study.and the Power Admini.strati on report "Hydroelectric Alternatives for the Alaska Railbelt.1l The screening of sites under Step 3 requi.reda total of four suCcessive iterations to reduce the number of alternatives to a manageable short list"The overall objective of this process was defined as the selection of apprOXimately 10 sites for consideration in plan formUlation,essentially on the basis of publ ished data on the s ite§and appropri ately defi ned criteri a. Figure 0.13 shows 49 of the sites which remained after the two initial screens. In Step 4 of the plan selection process,the ten sites shortlisted under Step 3 were further refined asa basis for formulation of Railbelt generation plans.Engineering sketch-type layouts were produced for each of the sites,and quantities and capital costs were evaluated.These costs,listed in Table 0.15,incorporate a. 20 percent allowance for contingencies and 10 percent for engineering and owner's administration.A total of five plans were formulated incorporating various combinations of these sites as input into the Step 5 evaluations. "'"Power and energy values for each of the developments were reevaluated in Step 5 utilizing monthly streamflow and a computer reservoir simul ation model.The results of ,these calculations are summarized in Table 0.15. The essential objective of Step 5 was established as the derivation of the optimum pl an for the future Railbelt generation incorporating non-Susitna hydro generation as well as required thermal generation. Selected Sites The selected potential non-Susitna Basin hydro developments were ranked in terms of their economic cost of energy.They were then introduced into the all-thermal generating scenario during the generation planning analyses,in groups of two or three.The most economic schemes were introduced first and were followed by the less economic schemes.The methods of analysis are the same as those discussed in Section 4.5 (f). The results of these analyses.,completed in early 1981,are summarized ;n Table 0.16 and illustrate that a minimum total system cost can be achieved by the introduction of the Chakachamna,Keetna,and Snow projects (Seeal so Figure 0 .•14). Note that further studies of the Chakachamna project were i niti atedin mi d...1981 by Bechtel for the Al aska Power Authority" 4 ...5 -'iIIiIiIiii\Iil__t,_:;_"_'_r_'....w..n.m.x·'.rr.d1u••p••"..iJJ.'•.•"_.'.n.T.I.II'J·,·.!.niill'_.'•••rmrs!l!e't:e~=~i!iil=••1.l'i.!r•••t.m.~""'~2IIIIIIHIl:'.'·'·"'-¥rm8tr_~.,--..'.t~.¥,.~~~lfi'm,~~1 I I I I I I II E lID .~ .•~.fl..\ l I ...... ( .1. ,~I:., I 1-:·:' i,f1·:,\, .~"Ij ~:'" .'!\-': \;5 r\ q Two basic alternatives have been identified to harness the hydraulic head for the generation of electrical energy.One is via the valley of the Chakachatna River.This river runs out of the easterly end of the lake and descents to about elevation 400 feet where the river ~leaves the confines of the valley and spi 11 S out onto a broad alluvial flood plain.A maximum hydrostatic head of about 740 feet could be developed via this alternative. The other alternative is for development by diversion of the lake outflow to the valley of the McArthur River vtlich·lies"to the" southeast of the lake outlet.A maximum hydrostatic head of about 960 feetcoul d be harnessed by this diverSion. (i)Project Layout The Bechtel study eva'uated the.merits of devel opi ng the power potenti al by diversion of water southeasterlY to the .~1cArthur river vi a a tunnel about IO-mil es long,or easter1 y down the Chakachatna valley either by a tunnel about 12-miles long or by a darn and tunnel development.In the Chakachatna valley,few sites,adverse foundation conditions,the need for a large capacity spillway and the nearby presence of an act ive volcano made it evident that the feasibility of constructing a dam there would be probl ematical.The main thrust of the in it;al study was therefore directed toward the tunnel al ternat i ves • Two al i gnments were studi ed for the McAY'thur tunnel.The first considered the shortest distance that gave no opportunity for an addit ionaI point of a.ccess during construction via an intermedi ate ad it.The secondal i gnment was about a mile longer,hut gave an additional point of access,thus reducing the lengths of headings and also the time required for construction of the tunnel..Cost comparisons neverthel ess favored the shoy'ter 10-mil e 25-foot di ameter tunnel. The second alignment running more or less parallel to the Chaka(;hatna River in the right (southerl y)wall of the valley afforded two opportunities for intermediate access adits.These,plUS the upstream and downstream portals VK>uld allow construction to proceed simultaneously in 6 headings and reduce the construction time by 18 months from that required for the McArthur tunnel. 4-6 " I I I I I I I I I IJ IJ IJ 11IJ ~:lI If all the controlled "later were used for power generation, the McArthur powerhouse could support 400 MW installed capacity,and,produce average annual firm energy of 1753 GWh.The effects of making a provisional reservation of approximately 19 percent of the average annual inflow to the 1ake for instream flow requirements in the Chakachatna River were found to reduce the economic tunnel diameter to 23 feet.The installed capacity in the powerhouse would then be reduced to 330 MW and the average annual firm energy to 1446 MW. For the Chakachatna powerhouse,diversion of all the controlled water for power generation would support an installed capacity of 300 MW with an average annqal firm energy generation of 1314 GWh.Provisional reservation of approximately 0.8 percent of 'the average annual inflow to the lake for instrecm flow requirements in the Chakachatna· River was regarded as having negligible effect on the install ed capacity and average annual finn energy because that reduction is within the accuracy of the Bechtel study. (ii)Technical Evaluation and Discussion Severalal tern at i ve methods of developi n9 .the project have been identified and reviewed.Based on the analyses performed,.the more viable alternatives have been identified by Bechtel for further study. ...Chakachatoa Dam Alternati ve The construction of a dCiIl1 in the Chakachatna River canyon approXimately 6 miles downstream from the lake outlet, does not appear to be a reasonable al ternat i ve.Whi lethe site is topographically suitable,the foundation· conditions in the river valley and left abutment are poor. Furthennore,its environmental impact specifically on the fisheries reSOUl"'ce will be significant although provision of fish passage facilities could mitigate this impact to a certain extent .. -McArthur Tunnel Alternatives A and B Diversion of floW from Chakachamn~Lake to the McArthur vall ey to develop a head of approx imately 900 feet has been identified as the most advantageous With respect to energy prod uc t ion and cost. The geologic conditions for the various project fac;l ities i nel udingi ntake~power tunnel,and powerhouse.appear to be favorable based on a 1981 field reconnaissance..No 4-7 I I I I I il! II .~11 [ I I I I··:···~·.•'Ii. (."..'...•;,,\ '( I ..,..!'...•.It I ...r i nsurmountab 1eengineering prohl ems appear to ex.i st in development of the project .• Alternative A,in whichessentia11y all stored water would be diverted form Chakachamna Lake for power production purposes could del ;ver 1664 GJh of firm eneYgy per year to Anchorage and provide 400MW of peaking capacity .. Hov.ever~since the flow of theChakachatna River below the 1akeoutlet would be adversely affected,the existing anadromous fishery resource which uses the river to gain entry to the lake and its tributaries for spawning,would be lost.In addition,the fish which spawn in the lower Chakachatna R;\verWQuld also be impacted due to the much reduced river flow.For this reason,Alternative.B has been developed\t with essent;ally the same project arrangement except that approximate.ly 19 percent of the average annual flow into Cha1<achamna take would be" released into the Chakachatna River below the lake outlet to maintain the fishery resource.Because of the smaller flow avail able for power production,the installed capacity of the project would be reduced to 330 MW and the firm energy del i \tered to Anchorage woul d be 1372l GWh per year.Obviously~the long term environmental impacts of the project tn this AlternativeB are significantly reduced in comparison to Alternative A,since the r;'4Jer flow is maintained,albeit at a reduced amount ..Estimated project costs for Alternatives A and Bare $1.5 billion and $1.45 bill ion tespectively., -Chakachatna Tunnel Alternatives C and 0 An al ternatlve to the development of thi s hydroel ectric resource by diversion of flows from Chakachamna Lake to the McArthur River is by constructing a tunnel thorugh the right wall of the Chakachatna valley and locating the powerhouse near the dovmstream end of the valley.The general layout of the project would be similar to that of Alternatives A and B for a slightly longer power tunnel • The g.eologic conditi.ons for the variousjlroject features inclUding intake~power tunnel,and powerhouse appear to be favorable and very similar to those of Alternatives A and B.Simil arly,no insurmountable engine.ering problems appear to exist in development of the project. Al ternative C,in \'tlich essenti ally all stored water is diverted from Chakachamna Lake for power product ion ~coUld deliver 1248 GWh of firm energy per year to Anchorage.and prqvide 300 MWof peaking capability.While the riverflow 4-8 I I I I I I I 11 I ~riIJ [ I I I IrlIi I'," 1 [', " ~:Ii ,~: ~ in the Chakachatna Ri ver below the powerhouse at the end of the canyon Will not be SUbstantially affected,the fact that no releases are provided into the river at the Jake outlet will cause a substantial impact on the anadromous fi:sh which normally enter the lake and pass through it to the upstream tributaries.Alternative D was therefore proposed in which a release of 30 cfs is maintained at the 1 ake outl et to fac;1 itate fish passage thorugh the canyon section into the lake.In either of Alternatives C or D the environmental 'impact would be limited to the Chakachatna River as opposed to Alternatives A and B in which both the Chakachatna and McArthur Rivers would be affected 0 Since the instream flow release for Alternative D is less than 1 percent of the total available flow,the power production of Alternative D can be regarded as being the same as those of Alternative C (300 MW peaking capabil itY:J 1248 GWh of firm energy del ivered to ----,"- Anchorage).Estimated project costs for AlternativesC and Dare $1.6 billion and $1.65 billion respectively. 4.5 -Thermal Options -Development Selection As discussed earli er ;n th'is section"the major portion of generating capabi 1 ity in the Railbelt is currently thermal;principally natural gas with some coal-and oil-fired insta.llat;ons~There is no doubt that the future electric energy demand in the Railbelt could be satisfied by an all-thermal generation mix.In the following paragraphs!t an outl i ne is presented of the analysis undertaken in the feasibility study to determine an appropriate all ...thermalgeneration scenario for comparison with the Susitna hydroelectric scenario. (a)Assessment of Thermal Alternatives The overall objective established for this selection process was the selection of an optimum all-thermal Railbelt generation pIan for comparison with other plans (Figure 0.15). Primary consideration was given to gas"coal,and oil ...fired generation sources which are th~most readily developablfi' alternatives;n the Rai lb~lt frorll the standpoint of technical and economic feasibility.The br~ader perspectives of other alternative resources such as peat.,refuse:J geothermal,wind and solar and the relevant environmental,social,and ether issues involved were addressed in the Battelle alternatives study (32). • I I I I I Il "...,1, 1-: 1 ,'",'." I I 1'-: ,J 1"'(: ~'t l IJ I,), .,1 ,,1 ...."'" I: I 1;(, :r "i ~ f'i'I:', ,l~; l~, '~:","',<;, ( I,;," .:7 1fJ~j :r As such,a screening process was therefore considered unnecessary in this study,and emphasis was placed onselectiQn of unit sizes appropriate for inclusio'n in the generation pl anning exercise. For analysis purposes the following types of thermal power generation units were considered: -Coal-fired steam; -Gas-fireu combined-eyel e; -Gas-fired gas turbine;and -Diesel. The following paragraphs present the thermal options used in developing the present without Susitna pl an .. (b)Coal-Fired Steam A coal-fired steam pl ant is one in whieh steam is generated by a coal-fired boiler and used to drive a steam-turbine generator. Cooling of these units is accomplished by steam condensation in cooling tdwersor by direct water cooling. Aside from the mil itary power pl ant at Fort Wainwright and the self supplied generation at the University of Alaska,there are currently two coal"fired steam pl ants in operation in the Railbelt.These plants are small in comparison With new units under consideration in the lower 48 states and in Alaska .. (i)Capital CQ.sts A detai 1ed cost study wa.s done by Ebascd Services Incorpor- ated as part of Battellc~s alternative study.The report found that it was feasible to establish a plant at either the.umievelvpedHeluga field or near Nenana,.using Healy field coal.The study produced costs and operating characteristics for both plants.All new coal units were estimated to have an average heat rate of 10,000 Btu/kWh' and invo1vean average construction period of five to six years"Capital costs and operating parameters are defined for.coal and other thermal generating plants in Table 0.15. It was found that,rather than develop solely at one field in the non-Susitna case,development would be likely to take place in both fields.Thus,one unit would be developed neat"Nenana to.service the Fairbanks load center, with other units placed in the Beluga fields .. 4...10 4-11 (ii)Fuel Costs 2001-2010 1.2% l.l~ 1982-2000 2.6% 2.3% Bel uga/Coal Healy Coal at Nenana ," Details of the fuel cost information are.included in Reference 31 'of th i s report. Other Performance Character;st i cs{o 0 oJ'\111 To satisfy the national New Performante Standards~the cap- ital costs incorporate provision for installation of flue gas desulfurization for sulphur control,highly efficient combustion technology for control of nitrogen acids,and baghouses for particulate.,removal. A new combined cycle plant unit size of 200 ..MW capacity was considered to be representative of fut.ure additions to gen- erating capabi 1ity in the Anchorage area.This is based on economi c s i:z;ng for plants in the lower 48 st ates and pro- jected load increases in the Ratlbelt.A heat rate of 8,000 BtU/kWh was adopted based on the alternative stUdy completed by Battelle. The capital cost was estimated using the Battelle study basis and is listed in Table 0.17. Fuel costs based on long-term opportunity values were set at $1.43/MMBtu for Beluga field coal and $1.75/MMBtu for Healy coal to be used at Nenana.Real escal.ation on these values was estimated as follows: Annual operation and maintenance costs and representati ve forced outage rates are shown in Tab1 e 0.17. Combined Cycle A combined cycle plant is one in which electricity ;s generated partly in a gas turbine and partly in -a steam turbine cycle.Com- bined cycle plants achieve higher efficiencies than conventional gas turbines.There are two combined cycle plants in Al askaat present...One is operational and the.other is under ~onstruction. The plant under construction ;s the Beluga No.8 unit owned by Chugach Electric Association (CEA).It is a 42 ...MW steam turbine, which will be added to the system in late 1982,and utilize heat from currently operating gas turbine unit~,Beluga Nos~6 and 7. (i)Capital Costs (c) I I I I I I I I I I I: I) I I, I. '.Il Q 1, It ~•.It, Il?i; I> i I I I I I I 1i...·.1IJJ I I I I ·1;.·:':,; I ~~ I I I IJ (ii)Fue]Costs The combined cycle facilities would burn only gas with a domestic market value of $3.00 per MM Btu was chosen to reflect the equitable value of gas in Anchorage,assuming development of the export market.Currently,the local incremental gas market price is about one-third of this amount due to the relatively light local demands and limited facilities for export. Using an approach similar to that u~ed for coal costs.,a real annual growth rate in gas costs of 2.5 percent (1982-2000)and 2 percent (2000-2040)was used in the analysis. (iii)Other Performance Characteristics Annual operation and mal ntenance costs,along with a.repre- sentative forced outage rate,are given in Table 0.17. (d)Gas-Turbine Gas tUfolnes burn natural gas or oil in untts similar to jet engines which are coupled to electric generators..These also require an appropriate water cooling arrangement. Gas turbines are by far the main source of thermal power generating resources in the Railbelt area at present.There are 470 MW of installed gas turbines operating on natural gas in the AnChorage area and approximately 168 MW of oi I-fired gas turbines supplying the Fairbanks area (see Table 0.13).Their low initial cost,simplicity of construction and operation,and rel atively short implementation lead time have made them attractive as a Railbelt generating alternative.The extremely low-cost contract gas in the Anchorage.area al'so has made this type of gerlerating facility cost-effective for the Anchorage load center. (i)Capital Costs A unit size of 75 MW was considered to be representative of a modern gas turbine plant addition in the Railbelt region .. However,the possibility of installing gas turbine units at Beluga was not cons;dered~since the Beluga development is at this time primarily being considered tor coal. Gas turbine plants can be built over a two-year construc- tion period and have an average heat rate of approximo:~:ely 10,000 Btu/kWh.The capita.l costs were again taken from the Battell e alternatives study" 4-12 I I I I I I ····1·\.··...!. I~; I .~ Ii I I I I IJ IJ (ii)Fuel Costs Gas tlJrbine units can be operated on oi 1 as well as natural gasa The opportunity value and market cost for oil are considel ::;0 to be equal,at $6.50 per million Btu.The real annual 90wth rates in 0;1 costs used were 2 percent for 1982-2000 and 1 percent for 2000 ..2040. (iii)Other Performance Characteristics Annual operation and maintenance costs and forced outage rates.are shown in Table D.17. (e)Diesel Power Generation Most diesel plants in the Railbelt today are on standby status or are operated only for peak load service.Nearly all·the~cont";flu ous duty units were retired in the past several years because of high fuel prices.About 65 MW of diesel plant capacity is cur- rently avai 1able. (i)Capital Costs The high cost of diesel fuel and low capital cost makes new diesel plants most effective for emergency use or in remote arEas where small loadS exist.A unit size of lOMW was selected as appropriate for this type of facility.The capital cost was derived from the same source as given in Table 0.17. {i f)Fuel Costs Oi esel fue'j costs and growth rates are the same as oil costs for gas turbines. (iii)Other Performance Characteristics 4...13 I I I]' IJ ~. ~: Ij' ~' I' E, m- Il 11 I It I area consumer be assessed ana systemwide basis..Since the consumer is supplied by a large number of different generating sources,it is necessary to determine th~total Rai lbelt system cost in each case to compare the various Susitna Basin development options. The primary tool used for system costs was the mathematical model developed by the Electricity Uti]ity Systems Engineering Department of the General Electric Company.The model is commonly known asOGP5 or Opt imi zed Generat ion Pl anning Model,Version 5. The following inform~t;on is paraphrased from GE 1 iteratur~on the program. The OGP5 program was develop~d over ten years to comhine the three main elements of generation expansion planning (system reI iabil ity,operating and investment costs)and automate generation addition decision analysis.QGP5 will automatically develop optimum generation expansion patterns in terms of economics,reliability and operation.Many utilities use OGP5 to study load management,unit size,capital and fuel costs,energy storage j forced outage rates,and forecast uncel"tainty. The OGP5 program requires an extensive system of specific data to perform its planning function.In developing an optimal plan,the programconsi ders the exi st i ngand committed units (pl anned and under construction)available to the system and the character;s- tics of these units inclUding age,heat rate,size and outage rates as the base generat ion pl an.The prQgreml then considers the given load forecast and operation criteria to determine the need for addit ional system capacity based on given rel iabi 1ity criteria.This determines "how much"capacity to add and Itwheo'· it should be installed.If a need exists during any monthly iteration$the progrclJTl will consider additions from a list of alternatives and select the avail able unit best fitting the system needs.Unit selection is made by computing production costs for the systan for each alternative included and comparing the results .. The unit resulting in the lowest system.produr-tion costs is selected and added to the system.Finally,an investment cost analysis of the capital costs is completed to answer the question of "what kind"of generat ion to add to the system" The model is then further used to compare al ternative pl ans for meet ing vari able el ectr'~cal demands,b~.5ed on system rel i abil ity and production costs for the study period cO 4...14 I 'I ~ IfJ ~11 "~ ·.IW ~ ~ II!!Ii I,;' 1I 11,.J.IJ 1. 1 . 1I! 1 I I,) /':H ..l~ Thus,it shoUl-d be recognized that the production custs modeled represent onlY a portion of ultimate c'onsumer costs and in effect are only a portion,albeit major,of total costs. The use of the output from the generation planning model is in Section 4.6{a}. 4.6 -Without Susitna Plan In order to analyze the economies of developing the Susitna project,it was necessary to analyze the costs of meeting the projected Alaska Rai,lbelt load forecast with and wfthout the project ..Thus,a plan using the ~dentified components was developed .. Using the OGP5 system mlJdel,a base case lfwithout Susitna"pI an was structured based on middle range projections.The.base case input.,to the model included: -Battel"1 e J s middle range load forecast (Exhi bit B); -Fuel cost as specified; -Coal-fired steam and gas-fired combi ned-cycle and combust ion turbine units as futu,re additions to the system; ...Costs and characteristics of future additions as specified; ...The existiiig system as specified and scheduled commitments listed in Table D.12; -Middlc.~ran~le fuel escal ation as specified; -Economic parameters of thtee percent interest and zero percent gener- al inf]atibn; -Real e$cal ation on operat ion and rnai ntenance and capital costs at a rate of 1.8 percent to 1992 and 2 percent thereafter;and ~Generation system reliability set to a loss of 10ad probability of one day in ten years.This is a ptobabilistic measure of the inabil- ity of the generating system to meet projected load..One day in ten years isa value generally accepted;n the inaustry for planning gen- eration systems. The model wasin;tially to be operated for a period from 1982 ..2000..~t was found that,under the medium load forecast,the critical period for capacity addition to the system would be in the winter of 1992-1993. 4...15 Until that time,the eXisttng system!'given the additions of the planned intertie and the pI anned units,appear to be sufficient to meet Rai 1belt demands.Gi ven this information,the p~riod of plan devflop- ment us i ng the model was set as 1993 -2010. The folloWing was established as the non",Susitna Railbelt base plan (see Figure 0.16): (a)System as of January 1993 Total (accounting for retirements and add:tions)2037MW 800 Coal Fired Unit (MW) 1 x 200 (Bel ugaCoal) 1 x 200 (Beluga Coal) 1 x 200 (Nenana/Healy Coal) 1 x 200 (Bel uga wal) 59 MW 452 MW 140 r~w. 67 MW 317MW 155 MW 813 MW 746 MWoMW 6 MW 317 MW 155 MW ,u 70'~1\I 1 x 70 1 x 70 1 x 70 1 x 70 1 x 70 2 x 70 1 .x 70 Coal-fired steam: Natural gas GT: Oil&r: Diesel: Nat ural gas CC: Hydropo~r: Year 1993 1994 1996 1997 1998 2001 2003 2004 2005 2006 2007 2009 Total (incl uding comnitted conditiops):1190 MW (b)SystemAdd;tion~ Gas Fired Gas Turbine (MW) Total 630 (c)System as of 2010 Coal ..fired steam: Nat ural gas GT: 0,1 GT: Diesel; Natural gasCC: Hydropower = I] I I I I] I I I ·1."" ,11, ••r.1.~.i t' I 1]'.1"I .1]".",1.,j '1 I .1....:.....1•II 1 I I I I ( I IJ There is one p.articularly important assumption underlying the plan. The costs associated with the Beluga development are based on the openinq of that coal field for cOhlmercial development.That development is not a certainty now and is somewhat beyond.the control of the state,since the rights are in the hands of private interests. Even if the seam is mined for export,there will be environmental problems to overcome.The greatest problem will be the cNailability of cooling water for the units.The problem could be solved in the "worst"case by using the sea water from Cook Inlet as coo1;.ng water; however,this solution would add significantly to project costs. Two alternatives which Battelle included in their base plan which have not been included in this plan are the Chakachamna and Allison Creek hYdroelectric plants.T~e Chakachamna plant is currently the subject of a feasibility study by the Power Authority.The current plan would develop a 330 MW plant at a cost of $1.45 billion at January,1982 price levels.The plant would produce nearly 1500 GWh on an average annual basis. Due to some current questions regarding the feasibility of the Chaka- chamna plant,it has not been inclUded in the non-Susitna pl an.It has been checked,however,in the sensitivity analysis presented later in this section. The Allison Creek Hydroelectric froject was included on the non-Susitna base plan by Battelle.It has not been included in this base plan due to its high costs ($125/MWh in 1981 doll ars). The thermal plan described above ha.s been selected as representative of the genet"'ation scenario that would be pursued in the absence of Susit- na.The selection has been confirmed by the Battelle results which show an almost identical plan to be the lowest cost of any non-Susitna plan. 4.7 ...Economic Evaluation This section provides a diScussion of the key economic parameters used in the stUdy and develops the net economic benefits stemming from the Susitna Hydroelectric Project.Section 4.7 (a)deals with those economic principles relevant to the analysis of net economic benefits and develops inflation and discount rates and the Al askan opportunity values (shadow prices)of Oil,natural gas and coal.In partiCUlar the analysis is focused on the longer-term prospects for coal markets and prices.This follows from the evaluation that,in the absence of Susitna,the next best thermal generation plan would rely on exploitati.on of Alaskan coal.The future coal price is therefore considered in detail to provide rigorous estimates of prices in the 4..17 most likel y alternative markets and hence the market price of coal "at the mine-head within the state. Section 4.7 (c)presents the net economic b~nefits of the proposed hydroelectric power investments compared with this thermal alternative. These are measured in terms of present val ued differences between benefits and costs.,Recogni zing that even the most careful estimates wi 11 be surrouo'ded by a degree of uncertai nty,the benefi t -cost assessments .arealso carried out in a probabilistic framework as shown in Section 4.8.The analysis therefore provides both a most likely estimate of net economic benefits accruing to the state.and a range of ~let economic benefits that can be expected wi th a 1;ke 1 ihood ~onfidence level)of 95 percent or more. (a)Economic Principles and Parameters (i )[collomi c Prinei pIes -Concept of Net Economi c Benefits'-.._.- A necessary condition for maximizing the increase in state income and economic growth is the select ion of public or private investments wi th the hi ghest present va]ued net benefits to the state.In the context of Al askan electric po~r ir.vc~tments,the net benefits are defined as the dif- ference between the costs of optimal Susitna-inclusive and Susitna-excl usi ve (all thermal)generat ion plans .. The energy costs of ~wer generat ion are i ni ti ally meas ured in terms of opportunity val uesor shadow prices which may differ from accounting or market prices currently prevail- ing in the state..The concept and use of opportunity val- ues is fundamental to the optimal a.llocation of scarce re- sources.Energy investment decisions should not be made scl ely on the baSis of accounting prices in the statei f the i nternat ional val ue of tr adedenergy commod iti es such as coal and gas diverge from loca'~market prices. The choice of a time horizon is al so crucial..If a short .... term planning period is selected,the investment rankings and choices will d'iffer markedly from those obt.ained through along-term perspect ive.In other words,the benefit-cost analysis would point to different generation expansion plans depending on the selected planning period .. A short-run opt iffiization of state income WQuld,at best, allow only a moderate growth in fixed capital investment; at worst,it would lead to underinvestment in not only the energy sector but al so in other infrastructure facilities such as roads,airports,rospital s,schools,and communica- tions. 4-18 It therefore follows that the Susitna Project,like other Ala'skan investments,should be apprai sed on the basis of long-run optimization.,where the long~run is defined as the expected economic life.of the facility.For hydroelectric projects,this service life is typically 50 years or more. The costs of a Susitna-inclusivegeneration plan have therefore been compared with the costs of the next-best alternative which is the al1-thennalgeneration plan and assess~q over a pI anning period extending from 1982 to 2040~ustng internally consi stent sets of economic scenarios and appropriate opportunity val ues of Al askan energy. Throughout the analysis,all costs and prices are expressed in real (inflation-adjusted)terms using January 1982 dol- lars~Hence,the results of the economic calculations are not sensitive to modified assumptions concerning the rates of general price inflation.In contrast,the financi.al and market analyses conducted in nominal (tnfl at ion-incl usive) terms wi 11 be infl uenced by the rate of general pr ice infl ation from 1982 to 2051. (ii)Price Inflation and Discount Rates -General Price Inflation Despite the filct that price level s aregeneraIly higher in Alaska than in the Lower 48,there is little differ- ence in the comparative rates of price changes ;i.e ~, price inf1 at ion.Between 1970 and 1978,for examples the U.S.and Anchorage consumer price indexes rose at annual rates of 6.9 and 7.1 percent,re.spectively.From 1977 to 1978,the differential was even small er:the consumer prices increased byB.e percent and 8.7 percent in the U.S ...and Anchorage (7). ,Forecasts of Al askan pf;ce.s extend only to 1986 (8). These indicate an average rate of increase of 8~7 percent from 1980 to 1986..For the longer period between 1986 and 2010$1 it is assumed that ~laskan priceswiIl a's .. cal ate at the overall U.S ..rate:;or at 5 to 7 percent compounded annually"The average annual rate of price i nfl ation is therefore about 7 percent between 1982 and 2010..Since this is consistent With long-term forecasts of the CPI advanced by leading economic consulting organi zat ions,7 percent has been adopted as the stUdy val ue (9,10). ~Discount Rates Di scount rates are.requir.ed to compare and aggregate cash flows occurring in different time periods of the planning 4-19 horizon.In essence,the di>count rate is a\~ighting factor reflecting that a dollar received tomorrow is worth less than a.dollar received today.Thfs holds even in an infla:ion-free economy as long as the productivity of cap;tal is positive.In other words,the value cfa doll ar received in the futurernust he def]ated to refl ect its earning power foregone by not receiving it today. The use of di scount rates extends to both reai dollar (economic)and escalated dollar (financial)evaluations, with corresponding infl at ion-adjusted (real)and ;.nflation-inclusive (nominal)values. •Real Discount and Interest Rates Several approaches have been suggested forestimat iog the real discount rate applicable topubl ic projects" (or to private projects from the public perspective). Three cOl1l11on alternat ives incl ude: ••the social opportunity cost (SOC)rate; ...the social time preference (STP)r"ate;and ..the government •s real borrow;ng rate or the real co~t of debt capital (11,12,13). The SOC rate measures the real social return (before taxes and SUbsidies)that capital funds could earn in alternative investments.If,for examp:e,the marginal capital;nvestment in Alaska has an estimated soc;al yield of X percent,theSusitna Hydroelectric Project shou.ld be appra.i sed using the X percent measure of IIforegone returns ll or opportunity costs.A shortcoming for this concept is the difficulty inherent in deter-. mining the nature and yi el ds of the foregone invest- ments .. TheSTP rate measures society's preferences for aIle- cat ing resources between i nvestmentand consumption. This approach is also fraught with practical measure- ment difficulties since a Wide range of STP ratt~S may be inferred from market interest rates and soci all y- desirable rates of investment. A sub-set of STP rates used in project evaluations is the owner's real cost of borrowing;that is,the real cost of debt capital.This industrial or government borrow'jng rate may be readily measured and provides a starting point for determining project-specific dis- cQw'ltrates.For example.,long ...tenn industrial bond 4..20 rates have averaged about 2 to 3 percent in the U.S"in real (inflation...adjusted)terms (9,14).Forecasts of real interest rates show average val uesof about 3 percent and 2 percent in the periods of 1985 to 1990 and 1990 to 2000,respectively.The U.S.Nuclear Regulatory Commission has also analyzed the choice of discount rates for investment appraisal in the electric utility industry and has recommended a 3 percent rea] rate (30).Therefore,a real rate of 3 percent has been adopted as the base case discount and interest rate for the period 1982 to 2040 • .Nominal Di scount and Interest Rates The nominal discount and interest rates are derived from the real values and the anticipated rate of gen .. eral price inflation.Given a 3 percent real discount rate and a 7 percent rate 'of price inflation,the nomi .. nal discount rate is determined as 10.2 percent or about 10 percent*: (iii)Oil and Gas Prices -Oil Prices In the base period (January 1982),theA]~$Kan 1982 dollar price of No.2 fue"J oil is estimated at $6.501 MMBtu. Long-term trends in oil prices will be influenced by events that are economic,political and technological in nature,and are therefore es.timated within a probabilis- tic framework. As shown in Table D.18,the base case (most 1'ike lyes-;; cal ationrate)is estimated to be2 percent to 2000 and 1 percent fro!:)2000 to 2040.To be consistent with "Batte 11 e forecasts,a 2 percent rate was used ~hroughout the OGP pl~nning period 1982 to 2010 and 0 percent thereaftt:.r.In other scenarios the'growth rates were estimated at 0 percent from 1982 ..2051 (low growth);and at 4 percent to 2000,and 2 percent beyond 2000 (high growth).These projections are also consistent with *(1 +the nominal rat.e)::(1 +the real rate)x (1 +theinfl ation tate)::;1.03 x L.07,or 1.102 4-21 I I I I I I I [I I I I I I] I .!o"... I I] Mi.Ii I I I those recent ly advanced by such organ;zat ions dS DRI (15)$World Bank (16),.U.S.DOE (17).,and Canadian National Energy Board (18)Ii A September 1982 review of major forecasts for oil pr~~c~ trends reaffirms the Battelle projection.Projections from seven sources indicated ten forecasts which varied from a low trend projection of ·0.5 to a high nf 5.3 percent.Seven of the ten trend forecasts were witnin a band of +1.7 to +3.4 percent. -Gas Prices Al askan gas prices have been forecast usi ng both export opportunity values (netting back ClF prices from Japan to Cook 1nl et).and damest i c market pri Ces as 1i ke lY to be faced in the future by Alaskan electric utilities.The generation pl anning ana lysi s used market pri ces as estimated by Battelle,since there are indications that Cook Inlet reserves may remain insufficient to serve new export ",arkets. .Domestic Market Prices Table D,.19 depicts the low,medium and high domestic market prices used in the generation planning analysis. In the medium (most 1 i ke1y)case,pri ces escalate at real rates of 2.5 percent from 1982 to 2000 and 2 percent beyond 2000.In the low case,there is zero escalation and in the high case,gas prices grow at 4 percent 1982 to 2000 and 2 percent beyond 2000. •Export Opportunity Val ues Table 0.19 also shows the current and projected oppor- tunity value of Cook In1 etgas in a SCenario where the Japanese export market for LNG continues to be the al... ternative to domestic demand..From a base period plant gate price of $4.69MMBtu (ClF Japan),low,medium and high price escalation rates have been estimated for the intervals 1982 to 2000 and 2000 to 2040..The cost of liquefaction and shipping (assumed to be constant in real terms)was subtracted from the escalated ClF prices to derive the Cook In1 et pl ant-gate pri ces and their growth rates.These Alaskan opportunity values are projected to escalate at 2.7 percent and 1.2 per... cantin the medium (most likely)case.Note that the export or /ortunity val uesconsi stently exceed the domestic prices.In the year 2000,forexample~the opportunity value is nearly double the domestic price est imatedbyBattell e. 4...22 (iv)Coal Prices The shadow price or opportunity val ue of Beluga and Healy coal is the delivered price in alternative markets less the cost of transportation to those markets.The most likely alternative demand for thermal coal is the East Asian market,principally Japan,South Korea,and Taiwan.The development of 50-year forecasts of coal prices in these markets is conditional on the procurement policies of the importing natioris.Tnesefactors~in turn,are influenced to a large extent by the price movements of crude oil. -Historical Trends Examination of historic31 coal price trends reveals that FOB and ClF prices have escal ated at annual real rates of 1.5 percent to 6.3 percent as shown below: ..Coal pri ces (bituminous"export unit val ue,FOB U.S. ports)grew at real annual rates of 1 ..5 percent (1950 to 1979)and 2.8 percent (1972 to 1979)(Il). •In Alaska,the price of thermal coal sold to the GVEA uti1 it,y advanced at real rates of 2.2 perc~nt (1965 to 1978)and 2.3 percent (1970 to 1978)• ..In Japan,the average ClF prices of steam coalexperi ... enced real esca.1 at ion ~ates of 6.3 percent per year ;n the period 1977 to 1981 (26,27).This represents an increase in the average price from app-rox imatel y $35.22 per metric ton (mt)in 1977 to about $76.63/mt in 1981. As shown below~export prices of coal are highly correl- ated with oil prices,and an analysis of production costs has not pred icted accuratel y the 1evel of coal pri ces .. Even if the product ion cost forecast itself is accurate, it will establish a mi.nimum coal price,rather than the market clearing price set by both supply and demand con- ditions. •In real terms export price.s of U..Soc cQal showed a 94 percent and 92 percent correlation with oil prices (1950 to 1979 and 1972 to 1979h* •Supply funct-;on (production cost)analysis has estimated Canadian coal at.a price of $23.70 (1980 U.S. $/ton)for S.E.British Columbia (B.C.)coking COal, FOB Roberts Bank,B.C",,Canada (24.29).In fact J Kai.ser Resources (now B.C.Coal Ltd,,)hassi gnedagree.- '. *Analysis is based on data from the World Bank~ 4...23 ments with Japan at an FOB Price of about $47..50 (1980 U.S.$/ton)(25).This is 100 percent more than the prlce estimate based on productton costs. ·The same comp~,ri son foY'CancHH an B.G..thermal coal i n- dicates that the expected price of $55 ..00 (1981 Canadian $)per MT (2200 pounds)or about $37.00 (1980 u.S.$)per ton would be 60 percentabO\(ee5ti:lllates founded on production CQ'5ts{24,25,29).. •In 1 anger-term coa.'i export contracts,there has been provi sion for reviewing the b,ase price (regardl ess of escal ation clauses)if significant developments Occur in pricing or markets,.That is.,.prices may respond to market conditions even before the expiration of th.e contract.* •Energy-importing nations in Asia,especially Japan, have a stated pol icy of d*iversified procurement for their coal supp1 ;es.They wi 11 not bUy on1 y from the lowest-cost supplier (as v/ould be the case in a per- fectly competit ive model of coal trade)but .instead will pay a risk premium to ensure security of supply (24,29).. -Survey of Forecasts Data Resources Incorporated is projecting an average annual real growth rate of 2.6 percent for U.S.coal pt"jces ;n the period 1981 to 2000 (9).The Worl d Bank has forecast that the real price of steam coal would advance at approximatelY the same rate as oilpr;ces (3 percentl a)in the period /1980 to 1990 (16)•Canadian ResourceconLim;ted has recentlY forecast growth rates of 2 percent to 4 percent (1980 to 2010)for subbituminous and bituminous steam coal (28).. -0pP..Qrtuni t,y Val ue of Alaskan Coal ..Delivered Pr;~es,CJF Japan Based on these considerations,the shadow price of coal (CIF price in Japan)was forecast using conditiona.l *fhi s cl ause forms part of the recently conel uded agreement betwee~ Denison Mines and reck Corporation and Japanese steel makers .. 4-24 4-25 The 1982 base period price was initially estimated using the data,from the Battelle Beluga Narket Study (24).Based on this study,a sample of 1980 spot. prices (averaging .$1.66/MMBtu)was escal ated to .;January 1982 to provide a starting value of $1.95/MMBtu in January 1982 doll ars.* probabilities given low,medium,and high oil price scenari os.Tab 1e D.20 depi cts the est imated coal price growth rates and their associated probabilities,given the three sets of oil prices.Combining these proba- bilities with those attached to the ail price cases yields the following coal priCe scenarios,CIF Japan. Real Price Growth 2 percent (1982-2000) 1 percent (2000-2040) o percent (1982-2040) 4 percent (1982-2000) 2 percent (2000-2040) Probabil ity Low 24 percent High 27 percent Medium 4\9 percent (most likely) Scenario As more recent and more complete coal import pricesta- tistics became available,this method of estimating was found to give a significant underestimate of actual ClF prices.By late 1981,Japan1s.average import price of steam coal reached $2.96/MMBtu,,**An important sensitivity case was therefore developed reflecting these updated actual ClF pri ces.The updated buse p~r;od value of $2 ..96 was reduced by 10 percent to $L ..66 to recognize the price discount dictated by quality different i al s between Al askan coal and other --,-- *The escalation factor was 1.03 x 1.14,where 3 percent ;$the fore- cast real growth in prices (mi d-1980 to January 1982)at an annual rate of 2 percent,and 14 percent is the 18..;monthincrease if the CPl is used to convert from mid-1980 dollars to January 1982 dollars. **As reported by Coal Week International in October 1981,the average CIFvalue of steam coal was $75.50 per NT.At an average heat value of 11,500 Btu/lb,this is equivalent to$2.96/MMBtu. ~11.1.Ii I I I 11 t."...•':...'.1'.ji!,j .. :!I I t ".1 •.•.1.'..•I',r ' ~., ••••,;~ L~''.H •. I I I -I I '..I ~.I' ·,.;,'··1.:·.1-...• ;, \~....11 H tr; d I;. I I 1:.1 t i III I lIJ·.1:~ ;~ I Ii---!Ii~. i[ .1 ~ I Ii 1"1:_11 I jJ 'IiI.:!. sources of Japanese coal imports,as est imated by' Battelle (24). .Opportunity Values in Al aska Base Case-Batte11 e-based ClF Prices, No Export Pot~ntial for Healy Goal' Transportation costs of $O.52/MMBtu were subtracted from the initially estimated elF price of $1.95 to determine the opportunity value of Bel uga coal at Anchorage.In January 1982 doll ars,this base period net-back price is therefore $1.43.In subse- quent years,the opportunity value is derived as the· difference between the escalated elF price and the transport cost (estimated to be constant in real terms).The lrealgrowth rate in ttlese-FDB,'prices ;s determined tesidually from the forecast opportunity values.In the medium (most likely)case"the Beluga opportunity values escalate at annual rates of 2.6 percent and 1.2 percent during the intervals 1982 to 2000 and 2000 to 2040,respectively. For Healy coal,it was estimated that the base period price of $1.75/r~MBtu (at Hea)y)would also escalate at 2.6 percent (to 2000)and 1.2 percent (2000 to 2040)•Adding the esca latedcost of trans- portation from Healy to Nenana results ina January 1982 price of $1.75/MMBtu ..*In subsequent years, the cost of transportation (of which 30 pE!rCent is represented by fuel cost which escalates a\t2 percent)is added to the Healy price,resulting ;n Nenana prices that grow at real rates of 2 ~3.percent (1982 to 2000)aad 1.1 percent (2000 to 2040). Table 0.20 summar;zes the realescal ation Y'ates applicable to Nenana and Beluga coal in the low, medi um,and high pri ce scenari as • ••Sensitivity Case -Updated elf Prices~ Export Potential for Healy Coal The updatedCIF price of steam coal ($2.66/MMBtu after adjusting for quul i(y different;als)was re- duced by shipping costs,from Healy and Beluga to Japan to yield Alaskanopportun;ty values.In *Transportation costs are based on Batterl e (18~23).. 4..26 I I I I I I-.··.jI I IJ Ill.iii If I ~~, ~[ I I l I I I January 1982,prices were $2.08 and $1.74 at Anchorag ':and Nenana,respectively.The difference~ between escalated elF prices and shipping costs result in FOB prices that have real growth rates of 2.5 percent and 1.2 percent for Beluga coal and 2 ..7 percent and 1.2 percent for Healy coal (at Nenana). Table DI.20 shows escalation rates for the opportunity villue of Alaskan coal in the low, medium,and h'igh price scenarios,using updated base period values. (v)Generation Planning Analysis -Base Case Study Values Based on the considerations presented in (i)through (iv) above,a.consistent set of fue.l prices was assembl ed for the base case probabilistic generat'j onpl ann;ng (OGP5) analysis,as shown in Table 0.21.The stUdy values include probabi 1iti€IS for the low,medium and high fuel price scenarios.The probabilities are comnon for the three fuels (oil,gas and coal)within each scenario in order to keep the number of generation planning runs to manageable size.In the case Of the natural gas prices,domestic market prices were selected for the base case analysis with the export opportunity values used in sensitivity runs. The base period value of $3 was derived by deflat'ing the 1996 Battelle prices to 1982 by 2.5 percent per year.Coal prices were also select.ed from the base case using Battelle·s 1980 sample of prices as the starting point~ with the updated GlF prices of coal reserved for sensitivity runs.Oil prices have been escalated by 2 percent (1982 to 2040). (b)Analysis.of Net Economic Benefits (i)Model i nfjAppro ac[ Using t.he economic parameters discussed 1n the previous section and data relating to the.electrical energy genera- tion Qllternatives available for the Rai lbelt,an analysis WaS m;~de comparing the costs of el ectr'ical energy produc- tion with and without the Susitna project.The primary tool for the analysis w(~s a generation planning model (OGPS)which simul ates prOduction costs over a planning period extending from 1982 to 2010. The method of comparing the "with"and Ilwithout"Susitna alternative generation scenarios is based on the long-term present worth (P.W)or total system costs Ii The pI anning model determines the total production CGstsof alteY'nati.ve plans on ayear ...by-year basis.These total costs for the 4-27 •• I I I I I I I I 1 ."•....:1, I t,I ,~ ..,.J I i J'j~.j I ti I I~ It I" ( J~ [, L '1"'1 :~'''¥ period of modeling include all costs of fuel and operation and maintenance (O&M)for all generating units included as part of the system~and the annualized investment costs of any generating and system transmission plants added during the period of 1993 to 2010.Factors which contribute to the ultimate consumer cost of power but which are not in- cluded as input to this model are investment costs for all generation plants in service prior to 1993 investment~cost of the transmission and distribution facilities already in service,and administrative costs of utilities.These costs are Common to all scenarios and therefore have been omitted from the study . In order to aggregate and compare costs on a si gni ficant ly long-term basis,annual costs have been aggregated for the period of 1993 to 2051.Costs have been computed as the sum of two components and converted to a 1982 PW.The first component ;s the 1982 PW of cost output from the first 18 years of model simulation from 1993 to 2010.The second component is the estimated PW of long-term system costs from ZOllto 2051. FOr an assumed set of economic parameters on 0,particul ar generation alternative,the first element of the PW value represents the amount of cash (not including those costs noted above)needed in 198.2 to meet electrical production needs in the Railbelt for the period 1993 to 2010.The second element of the aggregated PW value is the long-term (2011 to 2051)PW estimate of production costs.In consid- ering the value to the system of the addition of a hydro- electric power plant which has a useful life of approximately 50 years>the shorter study pericd would be inadequate.A hydroelectric pl ant added in 1993 or 2002 would accrue PW benefits for only 17or9 years!, respect ively,using an investment horizon that extends to 2010.However~to model the system for an additional 40 years it Would be necessary to develop future load forecasts and generation alternatives which are beyond the realm of any lJrudent projections.For this reason,it has be,en assumed that the production costs for the final study year (2010)would simply reoccur fQr an additional 41 years~and the PW of these was added to the la-year PW (199,5 to 2010)to estab 1i sh the long-term cost differences between alternative methods of power generation'" (ii)Base Case Analysis -P~~tern of Investments "With"and "Without"Susitna l'he ba~e case ~,:omparison of the "With"and "without" Susitna plans is based on an assessment of the PW produc.- • 4-28 • tion costs for the period 1993 to 2051,using mid-range values for the energy demand and load forecast,fuelprices~fuel.price escalation rates,capital costs~and capital cost escalation rates. The with-Susitna plan calls for 680 MW of generating capacity at Watana to be available to the system in 1993. Although the project may come 00-1 ine in stage~1 during that year,for modeling purposes full-load generating capability is assumed to be available for the entire.r~ar.The second stage of Susitna,the Devi 1 Canyon project,is scheduled to come on-line in 2002.The op'l:imum timing for the addition of Devil Canyon was tested for earl i er and 1ater dates •Addition;n the year 2002 was found to result in the lowest long-term cost. Devil Canyon will have 600 MW of installed capacity. The without-Susitna plan is discussed in Section 4.5.It inCludes three 200 MW coal-fired plants added at Beluga in 1993~1994,and 2007.A 200MW unit is added at Nenana in 1996 and nine 70 MW gas-fired combustion turbines {GTs)·would be added during the 1997 to 2010period. -Base Case Net Eco~10mic Benefits The econorulC comparison of these plans is shown in Table 0.22.During the 1993 to 2010 study period,the 1982 PW cost for the Susitna plan is $3.119 billion.the annual production costin 2010 is $0.385 billion.The PW of this level cost~which remains Virtually constant for a period extending to the end of the life of the Devil Canyon plant (2051),is $3.943 billion.The resulting total cost of the with-Susitna plan is $7.06 billion in 1982 dollars,presently valued to 1982. The non-Susitna plan (Section 4.5)which was modeled has a 1982 PW cost of $3.213 billion for the 1993 to 2010 periods with a 2010 annual cost of $0.491 bi 11 ion.The total long-term cost has a PW of $8.·24 billion. Therefot'e,the net economi c benefit of adopti n9 the Susitna plan is $1.18 billion.In other words~the present valued cost difference between the Susitna plan and the expansion plan based on thermal plant addition is $1.18 billion in 1982 dollars.This is equivalent to a 1982 per capita net economic benefit of $2,700 per capita for the 1982 population of the State of Alaska. Expressed in 1993 do 11 ars (at the on-I foe date of 4-29 4-30 It is emphasi zed that these net economic benefits and the rate of ret urn stemni n9 from the Susi tna project are in- herently conservat i ve est imates due to several assump- tions made in the.OGP5 analysis. •Zero Growth in Long-term Costs From 2010 to 2051,the OGP5 anal ysi s assumed constant annual production costs in both the Susitna and non- Susitna plans.This has the effect of excluding real escalation in fuel prices and the capital costs of thermal pI ant repl acements,and thereby understat i ng the long-term PW costs of thermal generation pI ans . •Loss of Load Probabilities The 10ssof load probability in the non-Susitna plan is calculated at 0.099 in the year 2.010..This means that It is noted that the magnitude of net economic benefits ($1.18 billion)is not particularly sensitive to altern a- tive assumptions concerning the overall rate of price in- fl ation as measured by the Consumer Price Index..The analysis has been carried out in real (inflation- 9-djusted)tenns.Therefot"e~the present val ued cost savings will.remain close to $1.18 billion regardless of CPI movements,as 1ongas the real(infl at i on-adj usted) discount and interest rates are maintained at 3 percent. Watana),the net benefits would have a level i zed value of $2..48 .bill i on ~* The Susitna project's internal rate of return (IRR), i.e.,the real (inflation-adjusted)discount rate at which the with-Susitna pl an has zero net economic bene... fits,or the discount rate at which the costs of the with-Susitna and the al ternat ive plans have equo:j costs, has al so been determined"The IRR is about 4.1 percent in real terms,and 11.4 percent in nominal {in'if1 at ion- inclusive)terms.Therefore,the investment ln Susitna \1Quld signi ficantly exceed the 5 percent nouinal rate of returnUtest ll proposed by the State of Al.aska in cases where state appropriations may be involved.'I:* - *$1 •.18 bill ion times 2.105,where 2.105 is the general price infl at ion index for the peri od 1982 to 1993. **See State.ofA1 aska 's 56 -25t Section 44.83.670. ." :1: I" I. I I I' I" I' I:".•.•,.J I.~IW: :,j ~: ffiIW',""~...:j ~!);.'.,",-:1 ~. I"",' .~.~Y; ."-' 4-31 D • I: Rather than rely on a single point cortlparison to assess the net benefit of th€Susitna project,a sensitivity analysts was carried out to identify the impact of modified assump- tiQns on the results.The analysis was directed at the following variables: -Load forecast; --Real interest and discount rate; -Construct ion per iod; -Period of analysis; -Capital costs; •Susi tna •Thermal al ternat ives the system in 2010 is on the verge of adding anaddi- tiona1 plant~and would do 50 io 2011.These costs are however,not incl uded in the ana]ys ;.5,whi ch is cut off at 2010.On the other hand,the Susi tna plan has a loss of load probabil ity of 0 ..025$1 and may rrot require additional capacity for several years beyond 2010. •Long-term Energy From Susitna Some of the Susitna energy output (about 350 GWh)is st i 11 not used by 2010.Thi s energy output woul d be available to meet future increases tn projected denand in the summer months.No benefit is attributed to this energy in the analysis. •§gual Environmental Costs The generation planning analysis has implicitly assumed equal environmental costs for both the Susi tnq,and the non-Susitna pl ans.To the extent that the thermal generat ion expansion plan is expected to carry greater environmental costs than the Susitna pl an,the economic cost savings from the Susi tna project are understated .. It is conceivable that these so-called negative external ities·from coal-fired electricity generation wi 11 have been mit igated by 1993 and beyond as a resul t of the enactment of new environmental legislation. (11 i)Sensitivity Analysis ide vli-Ai IIri···'~ }. f .11f-! I[I ! III I I I I I I~W ~ I~; Ii. The greatest variability in results occurs in sensitivity tests pertaining to fuel escalation rates~discount rates, and base period coal prices..For example,a scenario with hi gh fuel price escal ation results in net benefits that have a value of 253 reI ati ve to the base case.In other words~the high case provides 253 percent Df the base case net benefits..In general,the Susitna pI an maintains its positive net benefits over a reasonably wide range of values assigned to the key variables .. -O&M costs; -Base period fuel price; -Real escalation in capital costs,O&r·1 costs,and fuel prices; 4-32 -Syst em rel i abi 1i ty; -Chackachanma;and -Susitna Project delay .. Tables D.24 to D.31 depict the results of the sensitivity analysis..In particular,Table 0 ..31 summarizes the net economic benefits of the Susitna.Project associated with each sensitivity test.The net benefits have been compared using indexes relative to the base case value ($1.176 billion)which is set to 100. A multivariate analysis in the form of probability trees has been undertaken to test the joint effects of varying several assumptions in combination rather than individual- ly.This probabilistic analysis reported in Section 4.7 provides a range of expected net economic benefits and probability distributions that identify the chances of exceeding particular values of net benefits at given levels of confidence .. 4 ..8 -Probabilit.yAssessment (a)MUltivariate Sensitivity Analysis The feasibility study of the Susitna Hydroelectric Pro,ject in- cluded an economic analysis based on a comparison of generation system production costs with and without the proposed project using a computeri.zed model of the Rai lbel t generation system.In I I I I II m I~IJI I'~ I I' a E ~ .~ E order to carry out this analysis~numerous projections and fore- casts of future conditions were made.These forecasts of uncer- tai nconditions incl ude futureel ectrical demand,costs ,andesca- lation..In order to address these uncertain conditions,a sensi- tivityanalysis on key factors was carried out.This analysis focused on the var;ance of each of a number of forecast condit ions and determined the impact of variance on the econ.omic feasibil ity of the project.Each factor was varied singularly with all other variables held constant to determine clearly it.s importance. The purpose of this multivariable analysis was to select the most critical and sensitive variables in the economic analysis and to test the economic feasibil ity of the Susitna Project in each pos- sible combination of the selected variables. While a number of variables were identified and tested in the sing1 e variabl &sensit~vity analysis for the Susitna economic feasi.bil tty study,the vari ables Which were chosen for the muTt i- variate senSitivity analysis represent the key issues such as load forecasts.,capital cost of alternative.s,fuel escalation and Su s;t na c api tal co st • The methodology for the multivariate analysis was implemented by constructing probability trees of future conditions for the Alaska Rai 1bel t e1 ectr ical system,wi th and wi thout the Susitna Project. Each branching of the tree represents three values for a given variable.These were assigned a high,medium,and low value as well asa corre~ponding probability of occurrence.The three \f~1 ues represent the expected range and mid-po int for a given va...i able.In some.cases,the mi d-po intrepresents the most 1 i kely val ue \'A1ich WaUl d be (=xpected to Occur.End 1 imbs of the proba- hil ity tree represent scenarios of mixed vari able condit ions and a probabil ity of occurrence of the scenario. The OGP 5 product ioncQst model was then used to detenni ne the PW (in 1982 dollars)of the long-term cost of the electric generation related to each variable.The PW of the long-term costs for each tlWith U and "without II Susitna scenario in terms of cumul at ive pro- bability of occurrence were determined and plotted.Net benefits of the project have also been caleal atedand.analyzed in a proba- bilistic manner. Figures 0.17 and 0.18 present the non-Susitna and Susitna proba- bility trees with resultant long-tenn costs. (b)Comparison of Long-term Costs Figure 0.19 presents the two histogra.lls of long-term costs for the II with li and "without U Susitna cases plotted on the same axes.FrOO1 these plots it is seen that the non-Susitna plan costs couid be 4-33 A seco.nd method of compar iog the "wi th II and "wi thout"Su~;itna pro- bability trees is by making a direct comparison of-similar scen- arios and calculating the net benefit which appl ies.As in the case of the individual tree cases,the net benefits were:ranked from low to high and plotted against cumulative probability.This graph has been represented as a 5i nglel ine due to the number of ~ints on the curve.It,however,would be most accurately por- trayed as a histogram in the manner.of Figure 0..1.9.The net bene- fits vary from a negative $2.92 billion with an associated proba- bi'lityof ..0015 toa high of $4.80 billion with an associated probability of .018..The single comparison with the highest pro- babilityof occUrrence of .108 has a net benefit of $2.09 bill ion. Figure D.20 plots the net benefit with the cross-over between the Uwith U and "without"Susitna costs occurring at about 23 percent. This is consistent with the previoiJscomparison and with the ex- pected value net benefit calculated by this method of $1.45 bil- lion.. expected to be .significantly less than the Susitna pI an costs for ,about 6 percent of the t ime~,approximately equal to the Susitna costs 16 percent of the time',and 51 gnific antl y greater for'78 percent of th?time. A comparison of the expected val.ue of long-term costs of the Uwith U and ISwithout"Susi tna cases yi eIds an expectesJvalue net benefit of $1~45 billion.This value represents the diffE~rence between the non-Susitna LTC of $8.48 billion and the Susitna LTC of $7.03 billion. 4...34 (d)Sensitivity of Results to Probabi 1 ities In assigning the probabilities of o.ccurrence.for each set of vari ... ables,a number of subjective assumptions were made.An exception was the Susitna capital cost probability distribution which was supported by a probabilistic risk assessment of construction cost. The probc\bilities for load forecast of 0.2,.0.6 and 0.2 for the low 9 mediuffi.and high cases respectively,reflect the analysis by Battelle and the probabil ity of exceedence of approx imately 10 percent fClr the high level of demand. Capital costs for alternative generation modes estimated in the Battelle study reflect a 0.20,0.60 and 0 ..20 distribution,again Within a range of a 90 percent chance of exceedence of the low and 10 percent exceedence of the high level. The single variable to which the results are most sensitive is the rate of real fuel escalation adopted.(This conclusion is sup- (c)Net Benefit Comparison I ,'••' I a I I I ~ .JiJ t:l1I"--~~~l I~l...·j ,~ ported by the single variable analysis as well.)The distrfbution of probabilities was 0.25,0.50 and 0.25 for low,mediUm and high fuel cost escalation scenarios.A case can be made for the argu- ment that some of the combined events,for example high fuel cost ,escalation,load and capital cost are not (as our results assume) independent of each other.High fuel prices,it may be argued, would result in lower load and increased capital cost..It is pro ... bable,however,that the greater revenues consequent on higher fuel prices would result in greater economic activity in.1\1 asl<a thus i'ncreasi ng demand for energy.Th is and other cons iderat ions led to the conclusion that the n~sults WOUld be relatively insen- sitive to probable ranges of interdependence. A.9 ...Battel'e Railbelt Al ternat i yes StUdy [Note to Power Authority-This .section will be revised upon receipt of the final (and extel~sively revised)Battelle reports.] The Office of the Gover~Qr~State of Alaska,Qivision of Policy Development and Plann;nglind the Governorls Policy Review Committee contracteq with Batte']1e I Pacific NorthwBst Laboratori es to investigate potent~i al strategies for future electric ~0wer development in the Railbeltregion of AlasKa ..This section presents a summary of final results of the Ra.ilbelt Electric Power A7t0 r natives Study. The overall approach taken on this study involved five major tasks or activities that lead to the results of the project,a com'parative evaluation of electric energy plans for the Railbelt.The five tasks conducted as'part of the study evaluated the fo 11 ow;ng aspects of electrical power planning: ..fuel supply and price analysis -electrical ~emahd forecasts -generation and conservation alternatives evaluation development of electric energy themes or IIfutures"availablf,:to the .Rai lbelt , -systems integration/evaluation of electric energy plans. .Note that while each of the tasks contributed data and informa'tiori to the final results of the project,they also developed important results that are of interest independent of the final reSUlts of this project. The first task evaluated the price and availability of fuels,that either directly could be used as fuels for electrical generation or indirectly could compete with electricity in end-use applications.such as space or water heating. 4-35 .. I I I C ~ ~ I~,_tJ ~ [J L "'.,·.;:" /; £ The second task,.electrical demand forecasts,was required for two reasons.The amount of electricity demanded determines both the size of generating units that can be included in the system and the number of generating units or the total generating capacity required.The forecast used from this study in the Susitna feasibility study is presented in Exhibit B. The third taskls purpose was to identify electric power generation and conservation alternativRs potentially applicable to the Railbelt region and to examine their feasibility,considering several factors.These factors inclUde cost of power,environmental and socioeconomic effects, and public acceptance.Alternat ives appear;ng.to be best ,sui ted for future application to the region were then SUbjected to additional in-df2oth study and were incorporated into one or more of the electric energy plans. The fourth task,the development ofel ectri c energy themes or pI ans, presents possible'electric energy "futures"for the RaiIbelt.These plans were developed both to encompass the full range of viable alternatives available to the region and to provide a direct compari.son of those futures currently receiving the greatest interest within the Raflbelt.A plan is defined b-y a set of electricalgeneratiQn and conservation alternatives sufficient to meet the peak demand and annual energy requirements over the t irne horizon of the study.The time horizon of the study is from 1981 ....2050 time period.The set of alternatives used in each pI an was drawn from the alternatives selected for further study in the analysis of alternatives task .. As the name implies,the purpose of the fifth ta~~,the system integration/comparative analysis task,was to integrate the .results of the other tasks and to produce a comparative evaluation of the electric energy plans.This compaj~ti~e evaluation basically is a description of the implications and impacts of each electric energy pI an.The major criteria used to eva1 uate and compare the pI ans are cost of power,environmental and socioeconomic impacts,as well as the susceptibi lity of the pI an to future uncertainty in assumptions and parameter estimates~ This summary focuses on the third,fourth and fifth tasks:alternatives evaluation,plan development and plan comparison.- (a)Alternatives Evaluation The Battelle study reviewed a much wider range of generating alternatives than the Susitna feasibility study.The following text summarizes the process followed and results of selecting technologies for developing energy plans. SeI ectinggenerati og .alternati ves for the Rai 1belt electr;cenergy plans proc~eded in three stages..First,a broad set of candidate 4-36 I I f{..'.,U 1'1.",.1U ..PJ.....1"Iii, [ E .I...~J).•.\..'111 technologies was identified,constrained only by the availability of the technology for commerc fal service prj Of to year 2000., After a study was prepared on tnecandidate technologies,they were evaluated based on several technical,economic,environmental and institutional considerations..Using the results of that study,a subset of more promi sing techno 109,;es subsequently was identified.Finally,prototypical generating facilities (specific s itesi n the case of hydropowet)were identified for further development of the data reqUired to support the analysis of electric energy plans • A wide variety of energy resources capable of being applied to the generation.of electricity ;s found in the Railbelt.Resources currently used include coal,natural gas,petroleum-derived 1i quids and hydropower.Energy resources currently not be;ng used but which could be develop-3d for producing electric power within the planning period of this study include peat.~wind power t solar energy,municipal refuse,;,,-derived fuels,and wood waste ...Light water reactor fuel is manufactured in the J110wer 48"states and could be readily suppl ied to the Rai lbelt,if desired.Candi.date electric generating technologies using these resources and most likely to be available for commercial order prior to year 2000 are listed in Table D.32.The 37 generation technologies and combinations of fuel conversion-generation technologies shown in the table comprised the candidate set .of technologies selected for additional study.Further discussion of the selection process and technalogi es rejected from consideration at this stage are provided in Reference 33. Se1ection of generation alternatives was based on the followinng considerations: -the avai 1abil ity and cost of energy r.esources; -the likely effects of minimum plant size and operational characteristics on system operation; -the economic performance of the various technologies as reflected in estimated busbar power costs; . -pUblic acceptance,both as reflected in the framework of electric energy plans within which the selection was conducted and as impacting specific technologies;and ...ongoing Railbeltelectric power p'~'1ning activities~ From this analysis.described morefully in Reference 33 t 13 generating technologi~s were selected for possible inclusion ;n the Railbelt electric power plans.For each nonhydro technology, a prototypical plant was def'ined to facilitate further development 4-37 ~-.l;.'..~.....'].' I~..l}L 111Ll r; Ii L'··\ ..:; I-,I ~~\ I:J <,.!~ ~-<- 11 r-":~.:'; I:i't·,:(", ,~ r:~ r:~ L In t.i of the needed information.For the hydro technologies,promising sites were selected for further study.These prototypical pl ants and sites consistute the generating alternatives selected for consideration in the Railbelt electric energy plans..In the following paragraphs,each of the 13 preferred technologies is briefly described!.along with some of the principal reasons for its se1 ection.All so described are the prototyp;cal pl ants and hydro sites sel ected for further study. (i)Coal-Fired Steam-Electric Plants Coal-fired steam-electric generation was selected for consideration in Railbelt electric energy pl ans because it isa commerci any mature and economical technology that potentially is capable of supplYing ,,11 of the Railbelt1s base-load electric power needs for \.he indefinite future. An abundance of coal in the Rai 1bel t should"be-mineable at '--,-..- costs allowing electricity production to be economically competitive with all but the most favorable alternatives throughout the pI anni ng peri od.The extremely low sulfur content of Rai Ibelt coal and the avai 1 abil ity of commercially tested oX.ides of su1 pher (SOx)and partic- u1 ate control devices will faci1 itate control of these emissions to levels mandated by theCl ean Air Act. Principal concerns of this technology are environmental impacts of coal mining,possible ambient air-quality effects of residual SOx'oxides of nitrogen (NO~)and particulate emissions,long-tenn atmospheric bUl1dup of C02 (common to all combustion-based technologies)and the long term suscept ibil ity of busbar power costs to inflc,tion. Two prototypical facilities were chosen for in-depth study: in the Bel uga area a 200-MW pl ant that uses coal m.ined from the Chutna Fi eld,and at Nenana a pl ant of simil ar capacity that uses coal del ivered from the Nenan field at Healy by Al aska Rai 1 road.The resul ts of the prototypi cal study are doc umented in Reference 34. (i i )Goa.l Gas ifier -Combi ned-eye 1e Plants These pl ants conSist of coal gasi fiers praduci ng a synthetic gas that is burned in combustion turbines that drive electric generators.Heat-recovery boilers use turbine exhaust heat to rai se steam to drive a steam turbine-generator. These plants,when commercially available,should ~11ow continued use of Alaskan coal resources at costs comparable to conventional coal steam-e1 ectric plants,While providing 4-38 I I I .".IIJ [ I: !:":":t,'~ ! ".;, ~~ -~'", f'.J '[-'f'; ') '["" [ '[ l [" ,~):: " 0_',: ,,'J: 'i ~";i "1, t I III~ enviromental and operat tonal advantages compared to conventional plants.Environmental advantages include less waste-heat rejection and water consumption per unit of output due to higher pI anteficiency.Better control of OOx'SOx and particulate emission is al so afforded. From an operat lanaI standpoint,these pI ants offer a potential for load-fa Tlowi ngoperat ion,broadening their application to intermediate loading duty.(However,much of the existing Railbeltcapac);t,Y most likely will be ava i1 able for intermedi ate and peak lo adi ng duri,ng the planning period.)Because of superior .pl ant efficiencies, coal gasi fi ed -combined-cycle pI ants should be somewhat less susceptible to infl ation fuel cost than conventional steam-electric plants.Principal concerns relative to these pI ants incl ude land di sturbance resuI ting from mining of coal,C02 production ,and uncertai nti esio pI ant performance and --capital cost due to the current state of technology development. A prototypic a]pl ant was sel ected for in -del?th anal ysi s. This 200 MW plant is located in the Bel uga area and uses coal mined from the Chuitna Field.The pl ant would use oxygen-blown gasifi.ers of Shell design,producing a medi urn Btu synthesi s gas for combustion turbine firing.The pl ant ~uld be capable of load-following .operation.The results of the study of the prototypical plant are described in Reference 35. (iii)Natural Gas Combustion Turbines Although of relatively low efficiency~natural 9\;;.5 combustion turbines serve we 11 as peaking un its·in a system dominated by steam-electric pl ants..ihe short construct ion 1ead times characteri st i.c ·of these un its also offer opport unit ies to meet unexpected or temporary increases in demand.Except for production of CO2'dnd potenti al local n01 se ptoblems,these units produce minimal environ- mental impact •.The prine;pa,l economcconcern is the sensitivity of these plants to escala~ing fuel costs. Because the costs and performance of combustion turbines are rel atively well understood t and because a major component of future Railbelt capacity additions most likelY would not consist of combustion turbines,no prototype was selected for in-depth study.. (i v)NaturaI-Gas-Combi ned-eycl e Plants Natural gas -combined-cycle pI ants were selected for consideation beCause of the current availability of 10w- 4-39 cost natural.gas in the Cook Inlet area and the li'kel,y future availaBility of North Slope supplies in the Rallbelt (al though at prices higher than those currently experienced)...Combined-cycle plants are the mosteconom- ical and environmentally benign method currently available to generate electric power using natural gas.The principal economic concern is the sensitivity of busbar power costs to the possible substanti al ri se in natural gas costs •.The principal environmetnal concern is CO 2productionandpossiblelocalnoiseproblems. A nominal 200 MW prototypical plant was selected for further study.The plant is located in the Beluga area and uses Cook Inlet natural gas.The results of the analysis of this prototype are documented in Reference 35. (v)Natural Gas Fuel-Cell Stations 4-40 These pl ants \iK)uld consi st of a fuel condit ioner to convert natural gas to hydrogen and C02'phosphoric ae id fuel cells to produce de power by electrolytic oxidation of hydrogen,a power conditioner to convert the de po~r output of the fuel cell s to ae -power.Fue 1-ce11 stat ions most likely would be rel atively small and sited near load centers . Natural gas fuel-cell stations were considered in the Railbelt electric energy plans primarily because of the apparent peaking duty advantages they may offer over combustion turbines for systems relying upon coal or natural-gas fired base and intermediate load units.Plant effici encies most 1i kely will be far supe.r ior to combust ion turbines .and rel ativelY unaffected by parti al powar operation.Capital investment cost most likely will be comparable to that of combustion turbines.These cost and performance characteristics should lead to significant reduction in busbar power costs,and greater protection from escal at ion of natural.gas prices compared to combustion turbines.Construction lead time should be comparable to those of combustion turbines.Because enVironmental effects most likely wi 11 be 1 imited to C02 product ion ,1 0 ad-c~{lter sit i ng wi 11 be pos sib1e and transmision losses and costs consequently will be reduced .. No prototypical pl ant was sel ected for further stUdy. (vi)Natural-Gas ..Fuel-CeTl -Combined-Cycle These pl ants would consist ·of a fuel condit ioner that converts natural gas to hydrogen and carbon dioxide,mol ten carbonate fuel cells that 'produce dc power byel ectrol yt.ic 1·7"·'·.'.···'..". ~~ [-',. [ [ ["'. !, ",~ lJ"',· ,:1 ,1 ~'j :JI I II' ti [ '.[ .'~ ;5 rl: ~ ,I I':~Il,:1. '1l[ ., cost natural gas in the Cook In1 et area and the 1i kel y .. future availa5ilit.,y of North Slope supplies in the Rallbelt (although at pric,",u 'higher than those currently exper;enced).Combined-cycle plants are the most econom'" ical and environmentally benign method currently avai 1 able to generate el ectric power usi 09 nat ural gas.The principal economic concern is the sensitivity of busbar power costs to the possible substanti al ri se in natural gas costs.The principal environmetnal concern is C02 production and possible local noise problems. A nominal 200 MW prototypical pl ant was selected for further study.The plant is located in the Beluga area and uses Cook Inlet natural gas.The results of the analysis of thi s prototype are documented in Reference 35. Natural Gas Fuel-Cell Stations 4-40 These plants would consist of a fuel conditioner that converts natural gas to hydrogen and carbon dioxide,molten carbonate fuel cells that produce dc power by .electrolytic These pl ants \\Quld consist of a fuel condit ioner to convert natural.gas..to hYdrOgen.and CO.2'PhosPhoriC.ac.i.d f.uel cell s to produce dc power by el ectrol yt ic ox idat ion of hydrogeo,a po~r conditioner to convert the dc power output of the fuel cells to ac 'Power~Fuel-cell stations most likely would be relatively small and sited near load centers. Natural gas fuel-cell stations were considered in the Railbelt electric energy plans primarily because of the apparent peaking duty advantages they may offer over combustion turbines for systems relying upcocoal or natural-gas fired base and intermediate load units.Plant efficiencies mostl ikely will be far superior to combustion turbines and telatively unaffected by partial power operation.Capital investment cost most likely will be compar abl e to that of combustion turb ines.These cost and performance characteri st ics shaul d lead to si gni ficant reduction in busbar power costs,and greater pl'otection fromescal at ion of natural gas prices compared to combustion turbines.Constf"'uction lead time should be comparable to those of combust ion turbines.Because environmental effects most likely will be limited to CO 2 production,'load-center siting will be possible and transmision losses and costs consequently will be reduced. No prototypical plant was selected for further stUdy. Natural-Gas -Fuel-Cell -Combined-Cycle-----------------------------""""~=:.._~.:.........:::..--- (v) (vi) I I I I.'.~';;"i> rIJ I'" , "..~ [~ "~ 1'1 "J:l.;' [ [ ~. [ [;': ,I,', [ rLJ t gi, LJ oxidation of hydrogen,and heat recovery boilers that use waste heat from the fuel cells to raise stean for driving a steam turb i ne-generator.A power cond it ioner converts the dc fuel cell power to ac power for distribution.If they attai n commerci al maturity as envi sioned,fuel-cell combined-cycle pl ants should demonstrate a substanti al improvement in efficiency over conventiona'.,cnmbustion turbine-combined-cycle pl ants.Al though the potent;al capital costs of these plants currently are not well know, the reduct ion in fuel consumpt ion promi sed by the forecasted heat rate of these plants would result in a baseload plant less sensitive to inflating fuel costs and less consumptive of limited fuel suppl ies than conventional combined-cycle pl ants.An added advantage is the 1 i kely absence of si go;ficantenv iTonmenta1 impact. OperationallY,these plants appear to be less flexible than conventional combined-eye]e p]ants and wi 11 be 1imited to baseload operation • Because of tha6arly stages of development of these plants, additional study Within the scope of thi s project Was believed to Yield little additional useful information. Consequently,no prototypical plant was selected for study. (vii)Conventional Hydroelectric Plants Substantial hydro resources are present in the Railbelt region..Much of this could be developed with conventional (approximately 15 MW installed capacity or 1 arger)hydro- electric pl ants..The data and al ternatives consi dered were the same as those di scussed in Sect ion 3 of thi s eXhibit. (Viii)Small-Scale Hydroelectric Plants, Small-scale hydroelectric plants include facilities having rated capacity of 0.1 MW to 15MW.Several small-scale hydr.o sites have been identified in the Railbelt and two currentl y undeveloped si tes (All i son and Gr ant Lake)have been subject to recent feasibility sfudies.Although typically not as economically favorable as conventional hydro because of higher capital costs~small-scale hydro affords simila.r long-term protection from escalation of costs. Two small-Scale hydroelectr';c projects were selected for considerat ion in Railbelt e1 ectric energy pI ans:the Allison Hydroelectric Project at Allison Lake near Valdez and the Grant Lake Hydroelectric Project at Grant Lake 4-41 I Ii I III 11 I: IJ (] ~ I, ..~. [ J '. I;IL .:': L [ :1 .<' " [ [ l II'L [ north of Seward.These two projects appear to have rel at;vely favorableeconoq]lCS compared with other small hydroelectf'ic sites,and r;elat;vely minor environmental impact. (ix)Mlcrohydroetectri c Systems M;crohydroelectric systems are hydroelectric installations rated at 100 kW or less.They typically consist of a \'/ater-intake structure,a penstock,and turbine-generator. Reservors often are not provided and the units operate on run-of-the~stream. Microhydroelectric systems were chosen for analysis because of public interest in these systems,their renewable character and potent;ally modest,environmental impact. Concrete informat ion on power product ion costs typical of these facil'ities were not avail able when the preferred technologies were selected.Further analysis indicated, ho~ver,that fe\\f michrohydroel ectric reservoirs could be developed forle.ss than 80 mills/kWh and even at considerably higher rates,the contribut ion of thi s reSource ~uld likely be minor.BecaUSe of the very limited potential of this technology in the Railbelt,it was subsequently dropped from considerat ion.However, installations at certain sites,for exampl e residences or other facilities remote from distribution systems,may be justified .. (x)Large Wind Energl Conversion Systems Large wind energy conversion systems consist of machines of 100 kW capacity and greater.These systems typically would be installed in clu~:._rs in areas of favorable wind resource and waul d be operated as central generating units. Operation is in the fuel-saving mode because of the intermittent nature of the wind resource. Large wi rod energy convers;on systems were sel ected for consideration in Railbelt electric nergy plants for several reasons.Several areas of excellent wind resource have been identfted in the Railbel't,notably in the Isabell Pass ar<~a of the Alaska Range,and in coastal locations •.The wi nds of these areas are strongest during fall,wi nter and spring months,coinciding with the winter ...peaking electric load of the Railbelt.Furthermore,.developing hydroal ectric projects in the Railbelt would prove compl ementary to wi nd energy systems..Surplus Wind-generated electricity could be readily Ustored"by reduc ;og hydrogeoeration."Hydro operation coul d be used I I~', ; ~ I i 'I /; 'm" ..'. .~{ I [ [ .11 '" 11 '..;"1 [ [' [ [":( I", j " [ I:L' IfL [ L to rapidly pick up load during'periods \)f wind insufficiency.Nind machines could provide additional energy,whereas excess installed hydro capacity could provide capacity credit.Finally,wind systems have few adverse environmental effects with the exception of their visual presence and appeaf'to have widespread public support • A prototypi c al large wi nd energy conversion system was se1 ected for fw"ther study.The prototype consi sted of a wind farm 1ocatedin the Isabell Pass area and was campri sed of ten 2.5 MW rated capacity,Boe;og MOD -2, hor;lootal ax is wi nd turb i nes.The resul ts of the proto~ype stud;ed are provided in Reference 36. (xi)Small Wind EnergyConve't'sion Systems Small wind energy conversion systems are small wind turbines of either horizontal or vertical axis;,design rated at less than 100 kW capacity.Machines of this size w:>uld generally be dispersed in individual househOlds and in commercial establishments. Small wi nd energy conversion systems were 5el ected for consideraton in Railbelt'electric energy plans for sc.vel"al reasons.Within the Rai lbe1 t,sel ectedareas have been identified as haVing superior wind resource potential. Another reason for sel ection is becGl,use the resource is renewable.Finally,power.produced by these systans appeared to possibly be marginally economically competitive with generating facil it tes currently operat ing in the Railbelt ..However,these machines operate in a fuel-saver mode because of the intermittent nature of the wind resource~and bec ause their economic performance can be analYled only by comparing the busbar power cost of these machines to the energy cost of power they could di splace. ~~~te~~r'w:~~t~~ke~nf~~~iih~ft~6~~~1 ~~~d p;g¥rf~s:onF~~f~~~ analy~fsQf this alternative indicated that 20 MW of installed capacity producing approximately 40 G\~hof electric energy possible could be economically developed at 80 mill m·,rginal power costs~under the high1.v unl ikely assumpt ion of full penetrat ion of the available market (households).Furthermore f in this analySis these machines were give parity wi th firm generat i 09 al ternat ives for cost of power comparisons..Because the potenti al contr ibution of thi s a1 ternat ive is rel at ivel y mi nor even unde\the rather liberal assumptions of this analysis,the potential energy product ion of small wind energy conversion systPo1S 4-43 • I I m 'Iff~~ .~' I} If:IIJ [ [ I: [ I'",~, I:, [" ~.-\ I[ I .. [ [ Ift< [ L was not included in the analysis of Railbelt electric energy pI ans. (xii)Tidal Power Tidal power pl ants typically consi st of a IIti dal barrage" extending across a bay or ;nlet that has substanti al tidal fl uctuatiQns.,The barragecontai ns 51 ui ce gates to admit 1:'!ater behind the barrage on the incoming tide,and turbine ...generator units to generate power on the outgoing tide.Tidal power is intermittent ,avail able,and requires a power system with equivalent amount of installed capacity capable to cycl ing in complement to the output of the t ida1 plant.Hydro capacity is especially suited for this purpose.Alternatively,energy storage facilities (pumped hydro,compressed ajr,storage batteries)can be used to regulate the pO\f/er"output"of the tidal facility. Tidal power was selected for consideration in Railbelt . e1 ectric energy plans because of the substanti al Cook Inlet. tidal resource,because of the renewable character of this energy resource and because of the substanti alinterest ;n the resource,as evidenced by the first-phase oissessment of Cook Inlet tidal power development .. Estimated production costs of unretimed tidal pov,t.. facility would be competitive with principal alternative sources of'power,such as coal-fired power pl ants ,if all power production could be used effective.ly..The costs would not be competitive,however,unless a specialized industry were establ ished to absorb the predictable,but cyclic output of the pl ant.Al ternativelY,only the port ion of the power output that could be absorbed by the Rail bel t power system coul d be used.The cost of thi s energy would be extremely high relat ive to other power-produc ing opt ions because only a fraction of the "rawll energy production ·could be used.An additional alternative wuld be.to construct a retiming facil ity, probably a pumped storage pl ant.Due.to the increased capital costs and power losses inherent in thi s opt ion, busbar'power costs would still be SUbstantially greater than for nontidal generatingal ternatives..For these reasons,the Cook Inlet tidal power alternative was not considered further in the anal ysi sof Rai Ibel t electric energy plans. (xiii)Refuse-Derived Fuel St~am Electric Plants These plants consist of boilers,fired by the combustible fraction of municipal refuse.that produce steam for the 4-44 where: 4-46 The 1evel i zed cost of power is computed usi 09 the present worth of the annual costs of power produced over the time hor;zon..In equati~n form: 1 (l+d)i n TAC. "'*LJ EPP . .'I 1,= PWCP = In turn'~ where: To compare the costs of power for the various pl ans,Battelle used the concept of a levelized cost of power.The levelized CO$t of power is computed by estimating a singlel evel annual pa)11lent which would be equivalent to the present worth,given assumpt ons about the time value of money- PWCP =Present worth·of the cost of power d ::;Real discount rate i =year'-1981 (base year) d (1 +d'iLevelizedCostofPower=PWCP *\-,) (l+d)i -1 TACi :::totalannua]costs in year i ($) EPP i =e1 ectr ic al power produced i 0 year i (kWh) n ::;time hor;zon (years) Formal forecasts of power costs were not made by Battell e beyond 2010,however,this difference ;n power costs between with and without Susitna plans can be expected toincrese over the service life of the Upper Susitna project..This difference is expected to be maintained because the other pl ans are rel utively more rel iant on fossil fuel,which is expected to continue to escalate in price. To recognize this longer term behavior of power costs.,the 1eveli zed costs of power were comput,ed for two different time horizons (1981-2010 and 1981-2050)throughout the Battelle anal ysis..The shorter time hor;zon was picked to correspond to the ti.me horizon of the study.However,since the study evaluates the Upper'Susitna project,Which has an economic lifetime of 50 I I1J I IJJ I ·1 Ii 11 I'; II,! alJ I] lI] IJ I.; II; IJ IJJ ~ Itj 4-47 Based upon the eval uat ion of the soc ioeconomicand environme'1tal effects of the plans and sensitivity analyses of factors affecting For the low economic scenario,ag ai n 1ittl e difference ex i sts in thelevelized costs of power over the 1981-2010 time horizon.The advantages of the pl ans inclUding the Upper susitna proj.ect are smaller than for the medi um economic scenario. (m'111 s/kWh) \High Economic Scenario ~ 2010 2050 Cost of Power ~1edi um Economic ScenarioT981-1-:'-98-"'r-~:: 2010 2050 Level ;zed Low Economic Scenario ~ 2010 2050 Pl an 1A 58 65 58 64 60 66 Plan 1B 58 63 58 59 58 60 Pl an ~?-A 58 65 59 66 58 66 PI an 2B 57 61 58 61 57 69 P'I an 3 58 67 59 65 62 68 Plan 4 57 64 59 66 61 68 For the medium economic scenario,essentially no difference ex i5ts in the 1evel i zed cost of power among the vari us e1 ectr ic .energy pI ans over the 1981-2010 time period.Over the longer'time hori zon the costs of power for the pl ans i ncludi ng the Upper Susitna project (Plans IB and 2B)are 10wer than for the other pl ans. years {and an even 1ongerexpected service 1ifetime),the 1coger time is also used to correspond to the economic lifetime of the project.The level ized costs of power for the 1981-2050 time period are computed assuming that no change will occUr in the annual cost of power over the 2010-2050 time hor;zon.Wher.eas this assumption understates the relative advantages of the plans that include the Upper Susitna project,it does indicate advantages of these pl ans over the project lifet ime.The 1eve1 i zed costs of power fOl'the si x pl ans over the two pe.riods of analysis are presented below. In the case of the hi gh economic scenario,'t~l ati vel y little diffe.rence exists in the cost.s of power over-the shorter time period,although the pl an'S including the Upper Susitnaj:\"oject - have slightly lower pOwer costs..Over the.longer time period,the plans including the Upper Susitna project have s;gnificantl~v lower power costs.The pl ans heavily rel i ant on fossil fuel s,Pl ans lA, 3,and 4~have relatively high power costs in the high economic scenario..In genera'f,the longer the time period and.the higher the demand,the more attractive are pl ans containing the Upper Susitna proj.ect. I II I' f II I~ I" f11 I I I I. I II It l II [ IL I .•....'... \ I II I·.··•.····.··.'"•~ I 1\ I I. I I I I ~ II~, II, I .~ the plans,the following conclus;onsare drawn for the-various e1 ectr;c energy plans. ti)Plan lA:Base Case Without Upeer Susitna -The 1 evel i zed costs of power for this plan are relatively stab]eamong the various sensitivity tests. Generally,it is neither the highest nor the lowest cost pl an .. -Significant potential impacts on air quality,land use, and susceptibility toinflat ion due to fossi,1 fuel use ate possible • -Incremental coal mining and reclamation activities will occur due to expanded co al use in the Bel uga and Heal y area.s 0 -The development of a coal export mine at Beluga to supply coal to generating plants located therei s uncertain. -The costs and environmel1tal impacts of the Chakachamna hydroelectric project are uncertain. (ii)Plan 18:Base.Case ~:1th Upper Susitna -Except for cases assuming higher than est imated capital costs for the Upper Sgsitna project,this plan provides relativelY low power costs over the 1981-2010 time periQd.The pl an provides either the lowest or nearl y the loWest cost of po;,Jer in all senst ivity tests over the extended time period. -E1 ectric power needs can be met without sign;ficant impacts to air quality,visibility,health and safety and other environmental sectors.However~improper river flow control may be detrimental to fish PY'ad uct i on .~ -Relatively good information is available on capital CQst and environmental impacts of the Upper Susitna Project. -The plan is resistant toinfl ationonce the project is constructed. -Significant boom/bust,land-use effects and high capital costs are associ ated with the c6nstruction af the Upper Susitna project .. 4-48 . (v)Plan 3:Increased Use of Coal -This plan produces rel at ively high costs of power o~:er the 1981-2050 time period..The pl an is more attracti ve in the Case with lower fuel price escalation rates • -This pI an assumes that a state conservation grant progr am ex i sts .. (iv)PI an 28:Hi gh Conservation and Use of Renewabl e Resources With UP.per Susitna Plan2A: -Thi s pl an has.s]i ghtlyhi gher power costs ·~n most cases. The costs are high mainly because of the p·~anlsreliance on rel atively high capital cost generating al ternatives (hydroelectric,refuse-derived fuel,and wind)... -Reduced air infiltration associated with building conservation may present health.and.safety hazards from indoor air pollution.The ex.act reT ationship between building conservation and indoor air pollution has not be estab 1ished. -The capital costs of al ternate hydroel ectric pro.jects are uncertain. -TIl is pI an has much the same costs and impacts as Pl an 1B~This s imflarity is expected 51 nce they both i ncl ude the Upper Susitna project. -The health and safety aspects of the indoor air qual ity of conservat ion act iviti.es are unknown. 4-49 -As with 'lA,this pl an assumes an extensive state conservation grant program. . -Significant potential problems are possible in air qual itY!l water qual ity,vi sual impacts,and 1and-use and inf]ation effects. -Constraints due to nondegradationair-qualty regulations are possible. Incremental coal mlnlog and recl am at ionacti vit i es \'/i 11 occur due to expanded coal use in the Beluga and Healy area. High Conservation and Use of Renewable Resources Without Upper Susitna-------------_...:....:-_-------------------------,..,'-"".- (iii) I I I If I II I I I I I I I II I II III It WJ I 11 I I.. Ii .'•" I I I m m II I, I1I m If f.·..l1 "...iii W -The deve10pment ofa coal export mine at Belugai s uncertain. (vi)Plan 4:Increased Use of Natural Gas -This plan behaves very simil arly to Plan 3.It provides the 1owest cost of power over the 1981-2010 time period in the case of lower fuel price escalation rates and in the case of reduced demand beyond 1995.It is one of the higher cost alternatives over the extended time horizon. -This plan has little impact on all sectors of the environment.No major problems are associated with jobs,boom!bus t effects,or land use . -Due to high technology of fuel cells and gas combined- cycle units susbstanti al spending wi 11 occur outside the state. -Inflation effects are significant because power production is directly tied to the pric~of natut"'al gas .. -Existing reserves of natural gas in the Cook Inlet area wi 11 not be adequate to support expanded gas-fired generation beyond 1990-1995..The discovery of additional reserves is uncertain. As indicated by this discussion,much uncertainty remains regarding all key alternatives to the Upper Susitna project.Coal,natural gas and hydroelectric projects are the primary alternatives to the Upper Susitna project. \oJhereas uncertainties do remain regarding the Upper Susitna proj ect,more is known about the costs and impacts of the Upper Susitna project than any of the al ternatives.The following uncertainties are associ ated with the al ternati ves: -Coal-based generation at Bel uga depends upon the development of a 1arge-scale export mine..Such a mine is based upon Pacifi c Rim steam coal market development. While this market .is expanding development of Beluga coal resources is uncertain. -Current reserves of natural gas in the Cook Inlet area are not expected to be adequate for generation beyond 1990-1995.The availability of additional reserves by that time is uncertain. 4-50 5 ~CONSEQUENCES OF LICENSE DENIAL 6 ...FINANCING ~,J I I I '"'••->•~,,,••••.,,.'.''"-. l~...~....1 ..~J ~r ",!: h 6 ~FINANCING 6.1 -Forecast Financial Parameters The financi a],economic,and engineering estimates usedi n the financi al analys;s are summati zed in Table D.9.The interest rates and forecast rates of inf1 atioD (in the Consumer Price Index -CPI)are of special importance.They have been based on the forecast inflation rates and the forecast of interest rates on i ndustri al bonds as gi ven by Data Resources Incorporated (9),and conform to a range of other authoritative.forecasts.To allow fOl"the factors which have brought about a narrowing of the differential between tax exempt and taxable securities,it has been assumed that any tax exempt financing would be at a rate of 80 percent rather than the hi stor;f'n.l 75 percent Of so of the taxable interast rate.This identifies the .:orecast interest rates in the financing periods from 1985 in successive five-year periods as being of the order of 8.6 percent,7.8 percent,and 7 percent.The accompanying rate of inflation would be about 7 percent.In view of the uncertainty attaching to such forecasts and in the interest of conseT"vatism,the financial projections which follow have been based upon the assumption of a 10 percent rate of interest for tax-exempt bonds and an ongoing iof1 ation fate of 7 percent. 6.2 ..,In~1.~tionary Financing Deficit The basic financing problem of Susitna is the magnitude of its "inflationary financing deficitsI'.Under inflationary conditions these deficits (early year losses)are an inherent characteristic of almost all debt financed,long life ll capital intensive projects (see Figure D.21).As such,they are entirely compatible (as in the Susitna cas~) with a.proje~t showing.a good economic rate of return.However,unless a.dditional state equity is included to meet this II-inflationary f'inancing deficit"the project may be unable to proceed without imposing a substantial and possibly unacceptable burden of high early-year costs on consumers. 6.3 -Legisl ative Status of Al aska Powe~Authority and Susitna Project The Alaska Powel"Authority is a publ ic corporation of the State in the Department of£ommerce and Economic Development but with separate and independent legal eXistence. The Authority was createn with all general powers necessary to finance, construct and operat2 power ptoductionand transmission facilities throughout the State.The Authority is not regul ated by the Al aska PUblic lJnitilities Commission,but is subject to the Executive Budget Act of the State and mustident ify projects for development in accord- 6-1 6-2 The completion of the Susitna project by the building of Devil Canyon is expected to be financed on the same basis reqUiring (as detailec in Table D.33)the issuance of approximately $2.2 billion of revenue bonds (in 1982 dollars)over the years 1994 to 2202. Minimize market area electrical power costs; Minimize adverse environmental and social impacts while enhancing environmental values to the extent possible;and Safeguard both life and property. Se.ction 44.83.36 Project Financing states that lithe Susitna River Hydroel ectr;cProject shall be financed by general fund appropriations ~ general obligation bonds,revenue bonds,or other pl ans of finance as approved by the legislature.1I 6.4 -financing Plan The financing of the Sus;tna Project is expected to be accomplished by a combination of direct State of Alaska appropriations and revenue bonds issued by the Power Author;ty.Iti s expected that project costs for Watana through early 1991 (estimated at $3.0 billion in 1982 doll ai's)wi 11 be funded frOID such state appropri ati ons..Thereafter completion of Watana is then expected to be financed by issuance of approximately $.9 billion (1982 dollars)of revenue bonds.On the assumption of 7 percent annual inflation from 1982 to the end of construction~the $.9 billion in 1982 dollars will have a then current money value of approximately $1.8 million as detailed in Table 0.35. These annual par amounts do not exceed the Authority's estimatedanrlual addition debt capacity for the period 1991 to 1995. ance with the project sel ection process outl ined.within Al aska Statues. The Authority must receive legislative authorization prior to proceeding with the issuance of bonds for the financing of construction of any project which involves the appropriation of State Funds'or a project which exceeds 1.5 megawatts of installed capacity. The Alaska State Legislature has specifically addressed the Susitna Proj'ect in legislation (Statute 44.83.300 Susitna River Hydroelectric Project).The legislation states that the purpose of the project is t:> generate,transmit and distri bute el ectric power in a manner which will: The Revenue bonds are expected to be secured by project power sales contracts,other available revenues,and by a Capital Reserve Fund (funded by a Stateappropri ation equal to a maxim~m annual debt service)and backed by the "moral obligation ll of the State of Alaska. At the issuance of the fi rst revenue bonds for ~vatana,expend;tures of Stateappropria:ionsare expected to have funded sufficient construct i on progress so th at subsequent construct;on risks wi'"be relatively small. (1) (2) (3) Wf, i')1 ~. [' [~ [~ Ir [ [ [ t. ('i ". (, ~~ ~. Summary financfal statements based on the assumption of 7 percent inflation and bond financing at a 10 percent interest rate and other estimates;n accordance with the above economi.canalysis.aY'e given in Tables D.36 and 0.7 Ii The actual interest rates at wh feh the project wi 11 be fi nanced in the 1990's and the reI ated rate ofinfl atlon evidently cannot be determined with any certainty at the present time. A material factor will be securing tax exempt status for the Revenue bonds..This issue has been extensively reviewed by the Power Authority·s financi al advi sors and it h~s beenconcl uded that it would' be reasonable to assume that by the operative date the relevant requirements of Sect ion 103 of the IRS code woul d be met..On thi s assumption the 7 percentinfl ation and 10 percent interest rates used in the analysis are consistent with authoritative estimates of Data Resources (U ..S.Review July 1982)forecasting a cpr rate ofinfl ation 1982-1991 of approximately 7 percent and interest rates of AA Utility Bonds (non exempt)of 11.43 percent in 1991 dropping to 10002 percent in 1995 .. 6-3 LIST OF REFERENCES 15..Data Resources,Inc.~personal communication,November 1981 .. 14.U.S ..Department of Commerce,iurvey of Current Business,variOUS issues. ·1 Susitna Hydroelectric Project Prepared for the Alaska Power Acres American Incorporated. Development Selection Report. Authority,December 1981. 7..U.S.Department of Labor,Monthly Labor Review,various issues .. 6. 3..Caterpill arPerfoy'mance'Handbook,Caterpillar Tractor Co ..,Peor;a,m i nois,Octo6er 19'8I: 4e Roberts,William S ..,Regionalized Feasibility Studyof Cold Weather Earthwork,CaTer-Regions Research and-Engineering Laboratory,Ju'ly 1976,Special Report 76-2 .. 5.Acres American,Inc..Susitna Hydroelectric Project Feasjbility Report.,Vol ume 6 (Appendix C)..Prepared for the Al aska Power Authority,r~arch 1982 .• 1..Gode of Federal Regulations,Title 18,Conservation of Power and Water Resources,Parts land 2,Washington,D..C.,Government Printing Office,1981 .. 2..Alaska Agreements of Wages and Benefits for Construction Trades .. 1n effect January 1982 ..\, 8.Alaska Department of Commerce and Economic Development,The Alaska Economic Information and Reporting System,July 1980..!.'= 9..Data Resources Inc.,U.S.tong-Term Review,Fall 1980,Lexington., MA,1980 .. 10.Wharton Econometric Forecasting Associates,Fall 1981,Philadel- phia,PA,(reported in Economic Council of Canada CANDIDE Model 2-0 Run,dated December 18,1981 ..) 11..Baumol,W.J.,liOn the Soci al Rate of Discount~',American Econ0'!lic Review,Vol.58,September 1968. 12.Mishan t E..J ..,Cost-Benefit Analysis,George Allen and Unwin, London,1975..' 13.Prest~A..R.and R.Turvey,"Cost-Benefit Analysis:A Survey", Economic Journal,Vol.7S!I 1965 .. '--_.<t' If· RJ [' '_'.,'5 I~" :,1' f"Ii 11 f' ;"': ( ~..; I·,: .d " ~. [~ C· ",.j. 26.Coal Week International,various issues. 20.Segal,J."Slower Growth for the 1980's",Petroleum Economist, December 1980. 27.Japanese Ministry of International Trade and Industry,personal communication,January 1982. 28.Canadian Resourcecon Limited,Industrial Thermal Coal Use in Canada,1980 to 2010,May 1980. 29.Battelle Pacific Northwest Laboratories,Alaska Coal Future Avail- b 24.Battelle Pacific Northwest Laboratoriss,Beluga Coal Market Stu~, Final Report,Richland,Washington,1980. 25.B.C.Business,August 1981. 21.Segal,J.and F.Niering,nSpecial Report on World Natural Gas Pricing",Petroleum Economist,September 1980~ 22.SRI International,personal communic-ation,-October 1981. 23.World Bank,Commodity Trade and Price Trends$Washington 1980.-------.....« ability and Price Forecast,May 1981. 30.Roberts,J.O.et al,Treatment of Inflation in the Development of Discount Rates and Level i zed Costs in NEPA Analyses for the' Electric UtilitYlndustry~u.s.Nuclear Regulatory Comnission~ washington,[j.C.,•January 1980. 31.Acres Jlmerican Incorporated..Report on "Econdmic,Marketing and F'inancia]Evaluation ll for Susitna HydroeTectric Project. 32.Battelle Pacific Northwest,ItRailbelt Electric Power Alternatives Study:Evaluation of Railbelt Electric Energy Plans",prepared -for the Wficeof tHe Governor,State of Afaska,August 1982. 33~Battelle Pacific Northwest "Rail belt El ectric Power Alternatives StudyCandfdate Te~hnolgiesll,prepared for tf}e Office of the Governor,State of Alaska,August,1982. 16.World Bank,personal communication,January 1981. 17"U.S.Department of -Energy,Energy Information Admin;stration, Annual Report to Congress,Washington,D.C .•,1980 .. 18.National Energy Board of Canada,.Ottawa,Canada,personal communi ... cation,October 19B1. 19.Noroi i,"Natura.1 Gas and International LNG Trade",Vol.9,October 1981. 11I~<.,«......;! ":! I]I:; (; I I I 'Il,) '",: 1·-: .} ~: 34.Battelle pacific NorthwestilRai Ibelt Electric Power Alternatives. Study:Coal Fired Plants lt ,prepared for the Office of the Governor,A$tate of A"aska~August,1982. 35.Battelle Pacific Northwest uRa·;lbelt Electric Power Alternatives Study:Natural Gas and Comb"'fi1ed·Cycle",prepareCrfor the Office "Of the Governor,State of ATaSka,August,1982.. . 36"Battelle Pacific Northwest I'Railbelt Electric Power Alternatives Study:Wind Energylf,prepareo Tor tne officeort11'e Governor, State of Afaska,August,1982 .. TABLE D.1:SUM/MRY OF caST EST I MJ\TE January 1982 DoBars $X 106 • Total $3,362 561 10 641 $4,514 512 $5,146 $1j1 069 105 5 212 $1,391 174 $',565 De'!!!r CanYonWatana $2~293 456 5 429 $3,183 39a $3,581 Category TrallSml5$,10n Plant Gel1eralPlan+ Indirect Total Construction Overhead Constructton TOTAL FROJECT ll:'~ ..¥!•...',.';j I I J'iill I I ESTIMATESUMMARY'-TASLE 0.2 WATANA CL.l£NT ALASKA roWER AUTHORITY TYPE OF ESTIMATE ..all....iRlIi 11.ca.03.l"UmI34. REMARKS -'OBNUMaE:RP5700.00~~------FILE NUMBER P5100 ..14.09--,-----SHEET 1 OF 5 BV ..DATE 'CHICO JRP DATE .....2/-8-2- ~~'-" TOTALS (x 106 ) Feasl hi I.I ty t~T':'I~~~ (x 106 ) $51 74 1,547 66 21 14 2.14 1,987 306 I S 2,293 AMOUNT APPROVED BY J_D..;.,L__---- E"!~ COST? UNIT 9 ••••••••• .G ••••••., .'. ••••••••• ••••••••• f·.'".), UNIT '.!_~@;~ QUANTITY (Machan leal)....It •••••••,.) ..p;ef:';1 -.-,:,.,..,......;;:':;:~ff::~-- .~~ ~- SUSITNA HYDROELECTR ICFROJECT a;":~ .,DESCRIPTION PROJECT 'Pi- PROOl£T ION PLANT Land &Land lUghts ••••o •••••o •.•••le.Q."••••••••.•••••~o)",••••••••• " Wata'whesls,Turbines &GeneratorS/••••••••••••u •••"'•••IU ••• Po ~.plant Structures &fnlproveme!s ."••o t 41 ••R<lservo'~.f.\jm$4 Waterways ;. /iccessory EI ectrlcal Equl.pment •••Ie Ie •••u ••• SObtQtztl •••"~••••_••_•••~.e •••••••••••: o •••It ••••_•••oj ••••••••• MIscellaneous PoWer-plant Equlpmen Roads &~11 roads ••••a ••••••••••••Ie !•.••;••II ••"••••". Co"tl gency ••••II ••••••••••••II ••••••1•••It ••II It •••••••II •-I ••••'"II •••"•••••II ••• TOTA~PRODLCTI ON PLANT :",••••••~.II.II It •••••II II II ••••_••• AIbr.~ No. 330 331 332 333 335 336 .334 fE" Overhead Conductors &.DevIces uH.~ee •••••••••41 ..Io •••••••••"'. SUbtotal 0 ••••••••••••10 ·••••••"'•••••••.•t1 •••••••• Roads,&Trails ••••••••••••••"•••••~••••••;o •••••••Io ••••••".tI ••·. 'RIll1......~ I'.oa.o~·.''''''1~4A REMARKS JOBNUMBER·!5jOO.OO FILE NUMBER P5700.14.09--SHr.1c.lr 2 .OF'··'·~ l"""-'-"'~ BY .JRP'.-DATE , CHKD "DATE 718T""" 2,293 .,.--y~,~t r'y',f~.~ TOTALS .$2,749 (x 106 ) Feasibility- '$ ~:\!I;,","'."',-'~~"'.~';~~M $8 12 131 131 100 13- 395 61 I 456 (x 106 ) A MOUN.T APPROVED BY J_D.....L _""-__ " TYPE OF ESTIMATE ..."'\~'"!"'""'~ ~L~ CONSTIUIT •••••••• r :...;~.~.# UNIT TABLE 0.2 ,WATANA ....,. s:~;~ QUANTITY ...•..$.~~~~.~... '",...,F':;,.IICT'.'•~~.','.""'~~~,,~,~ SUS fTNA HYOROELECTR Ie mOJECT ALASKA POWER AUTHORITY ~.~. CLIENT PROJECT , ESTIMATE SUMMARY ~~ COot Jgency •••••••••••••••Q ••••••••~•••••••"••.II •o.II ~.."•~••••0/. SUbstatIon &,Swltchl ng StatIon EqullPment ••••Qu .....10 •••·....."'II ••.••••• SUbstatton&Switch I ng$t~t Ion Strt.+::tures &ImprovE3mej)ts •••••lI!u ...... Steel Towers &Fixtures •••••••••••"•••••••••••••••••10 •••••••0-1 ... l15nd&landRtghts ••,..."~••II ••••••~••••••••"'"9 •••II II.~.9.'•••0.of".'...... DESCRIPTION TO'fAL BROUGiT FORWARD "••••••••,••• 10TALTRANSMISSION PLANT 1 10 .. TRANSMISSION PLANT ~ 'No. 350 352 353 354 356 359 ,. fc:..• TOTAL (;£NERAL PLANT 1-/I ••e,•••••Ie ••41 . TOTAL BRQUGlT FORWARD /I tI'••••ule • e e (eo •• Sfructures&Improvements ••••••••~•••••••••••8.fi eel••••••••• --,---, 4.J-. e 7.02.()3.'or","4. REMARKS ~. Incl uded lI1der 330 .t nc I ud ad undei""331 Incl uded trlder 399 IV " tt " "" "" IV " tt " 19 " JOB.NUMSERr?7QO.OO FILE NUMBER P5700.14.09 SHEET 3 OF5 -BY DATE CHKD JRP DATt .....27.....13.....2- 5 2,749 TOTAL.S $2,754 $ (x 106 ) $ ~.*~ Feas I bll Jty--........_--- -- 5 ex 1(6) $ ~~ AMOUNT APPROVED BY JDL.....-- TYPE OF ESTIMATE t;::*:'!f'i:l!~ COSTIUNIT ••••••••• ••••••••• itt.~..-.c:.';;'= ~ UNIT TABLED •.2 WATANA. ••••••••~•••e ••••~ ~~ QUANTITY Ct-;:,::.:,;.;.c:l .••••••••••••••••• 1:"-'':.:Itv":=- ALASKA POWER •AUTHCRI TV SUS ITNA HYDROELECTR 10 FROJECT DESCRIPTION CLIENT ESTIMATE SUMMARY PROJECT Laboratory Equ!pment •••••~•••••••Ie •••••••••••••••••Io ••••••••tI •••••••••• other Tang Ib Ie Property ••••••••••1 ,tI •••••••••• Tools Shop &GlSrage Equipment ••••Jo •••••••••••••••••p ••"•••••e1 . Trans partat lon.EquIpment •••••••••~~••.•••••••;••••••••.e1 ••••••••• PPwer-Q~rated Equ I pmeot t ··..··4 • ••..~.•••••••• Communlcetlons Equipment ••••••••~•••••H ••••••:••••Ie •••••••• Stores EqUI pment lr ••••10 •••••••••••••••••10 ••••••••o!••••••••• Oft'Ce Furn tture/Equl pment ••.,••••It It ••e •••••tie .••e ••••• Miscellaneous Equt pment •••••••••••Ie "'. Land &Land Rights •••••••••••••••• , GENERAl.PLANT No. 389 390 391 392 393 ·394 395 396 391 398 399 Labor Ex pen se It ••••••I••••1 1•••••e lo ••e S4btotal ~,"'.-1 •••0 tI •••••••It . Temporary ConstruetJon facilities I ,.-1-e ralr"~1IIit'.'_B,-~;, .r;"". Saet'bte See t'bte See I'bte 17,02..os.,."',l!'~'" REMARKS See Note 'See t'bte J08NUMBEA P5700.00~~--........._- FIL£NUMBER P5700.14.09 SHEltT 4 OF 5 BY DATE tH.·.K.D JRP ....- .•..,.,.27"'"0......2 .....__..-__DATE F>~~""-·~-r""'! ~~~ 429 3,183 2,754 ,."'--:-, ie:"l,:':l!!Il (x 106 ) $ TOTALS $ -s r .,,"-, f!'!~ 373 373 56 (x 106 ) $ ~.~~. AMOUNT TYPE OF ESTIMATE Fees!b lIlt! APPROVEO SV ,-JD-L ------_ '-::c:.""" 5~~tl ..••••eft_". e •••••••'. ••••••••• ••••••••• ........... b'S"':!. UNIT TABLE 0.2 WATANA c-~-'.~~-,.,.~.~ QUANTITY 6--.....~._-.~~,.;,..., •••o ••••••••"'••••••••••o •••••~.j ••~•••••• ~'i-:" ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC ffiOJECT ..I·FORWARD fl ,.,.••c."'••••1-•••••••j , , p;:.'w, DESCRIPTION " PROJECT ESTlMATESUtJiMARY CLIENT ,..,..., IND IREGl COSTS f-bte:Costs.undl:lr.accoun.ts·.61,6.~.,.64,65,66~and 169 are lncl uded tn the approf,rt fate d Irectcosts II stoo above.. lnsUl"'aocl:l •••••••••"••••••••••••••,••••••••••••••••••1 . Fel:ls ••••••••••••0 "1 ••••••••••••••{eI e •••• ContI gency •••••••tI 0 "'0 -I ~"co .. TOTAL I NOIR ~T COSTS Camp &Coetm lssary f It •••••••••-I ••••••••Q lo -I e ~•• Superintendence •••••••••••••••••0\•••••••••••••••••"'••••••••• lOTAL.CONSTRLCTiON'COSTS Construct:lol"lEqul prnent lo •••••lo •••-r ••••••••lo I•••••s e ••••••• TOTAL BROUGlT p;..-'~ No. 61 62 63 64 65 66 69 .. ~ Engineering!Acinlnlstratlon •••••••~•••••••••••••••••••~••••••••J I $ Taxes s 10 ••••••••••••••••••10 ••••••••-I ••••••••• Total Overhead "'10 ••"co . -i1!'IJJrII;~=-,r;:R;~.'.'~.... ...":t REMARKS Included In 71 Notespp I leah 1e Inc I udeci In 71 tbt I nc I Uded Not Included JOBr-4UMBER _P_.57....0_0_.0._0 ...........--...-.- FILE NUMBER P570Q.141)09 ".-.-........---.......--- SHEET ,5 OF 5 ~~;JRP~:~~.ZlB2 ~....---.,--- ~-~, 398 3,581 3,183 f"'·"O'· 11":-","<_~J!"l'I TOT:~lS $ (x 106 ) $ Faas Ibll.1 ty ...---- , re-~r~ ..: 398 ~;...~ AMOUNT (~106) APPROVEoev JOL .. TYPE Of'ESTIMATE ;;,:.:~:; COSTTIUNI ~_.~ UNIT TABLE 0.2 WATANA J:-~~- QIJA.NTITY .Ir.·....,_,_".L.",J",..~I...,....~~k~ . ALA;_S_·KA_-FO.....-WE-R......AU...T...H-OR...I...T-y-------------__--_- SUSlTNA HYDROELECTRiC moJECT ~-. OEseR I PTION' CLIENT ESTIMATE SUMMARY PROJECT ~... Earn IngslExpensesOur Ing Construeillon ••••••••••••••\-u •••• Interest "\•••Io.o •••••••o.It •••••Io~<>••••••e1·•••••••• TOTAL ffiOJECT'COST •••~"1 j.. AdmlnlstratlvEl &GenerlJl Expenses 1 ~I o "••••••••• OVERHEADCONSTRl£T10N COSTS (PROJ~T 'NO IRECTS ) Legal Expenses 10 •••••••••••••••••10 ". TOl'AL CONSlROOT10NCOSTS BROUGiT'FPRwARD ~-••e U 01 . ,.:--, No. 71 72 75 76 77 80 , ·~ " ....~ REMARkS ),;;:1"....,~ '~lil!/ 1,069 r......·.'·......•!'""~ittr~~ $ feasfbility r::= (]l7 142 22 72 646 42 14 12 119 r"-llM;;_ APPAOVEDBY _,.....J;...;DL~_ TYPE OF ESTIMATE ••••0 ••,. •••••••'iQ. •••••••••• ••0 •••••• ••••••••• ••••••••• pc jl..,,:,,~ 'TABLE 0.3 DEVIL CANYON ~.~~ (Meehan leal)!ttl ••10 . ·k......<~~r'~~ ALASKA flOWER AUTHOR lTV~>-~" .~ tCL.1 ENT PROJEct,SUSJINA HxmOELECTRICFROJECl',. ESTIMATE SUMMARY ~- .. •FbwerpJant Sflructures&improveme~ts Q ..,1 . Wat\:H'"wheels,Turbines &.Gen<M"'aior~41.1 0 Land &Land Rights I ~1••••u .,••J 1 $ Accessory EI ectrlc81Equlpment u~•••~o~•••0 0 0 .1 . SUbtofal,••iO ••••••••••••0 ••••••••••1.......•••41 •••••••••1•••111 "'e •••• ContI ngehcy '••••••1 1 04 g •• Reservoir,Oesms &Waterways .~1•••••••••••••C!~I'e . Roads &Rall roads .~••"iO •••••••~.I."'.'fI o ••lo .•••••••• MIs¢t)llaneous fbwerplant f!iulpmen 10TAL.PRODl.CT ION PLANT '••J-o o"Je 1."to •••••eo. PRODUCTION PLANT .1 J:",~•','-.,:, 330 331 332 333 334 335 336 ;L.......,. >-'",-.~." _I No.~_.OESCRIPTION .I QUANTITY -+UNI:I 8~~tl I A MOOt-;at I TOTALSIt()(106 )-,(x 106)r r'------------~_.-'...i. JOB NUMBER P5700.00 i FIL.ENUMBER P5700.14.09- SHEET _1 .",...OF 5 BY OAT-e---..........-- CHKD :IRE'DATE L/82 Subto-tal -I •••••;_.- _•••~•••••1 . SUbstafton&SWltchfng Station Strlucturas &lmprovetients 81 Ccmf I ngencY ,'••••••••~•••••••1•••••e 'It •••••1 . 1iR-:-:1illiIilI . .~.·~1I. lncl udoo In Watana Estimate r~ ~ REMARKS Incl uded In WatanaEstlmate . •JOBNUMBER P5'lOO~00 ~ILE NUMaERP5700.14.09 2-·- .SHEE.TOF 5 --....----- 8Y DATE CHkO JRP ...""""2"ft'l;a;-z--_,DATE 105 1,069 f""":::~·(',......b:'~~ $1,174 $ ex 106 ) TOTALS $ r".:....~1Iu.~... 91 14 ? 21 29 34 r-hr~ ex 106) $• AMOUNT '". TYPE Of'ESTIMATE FeasIbility APPROVEOBV _.........-;,JO;.;;L;..._- COSTI UNIT •••eo-••••• •eo •••-•.••D ••••••••• ••••••••• .......,.. ••••••••• ••••••••• c"'-=...... UNIT TABLE 0.3 OEVIL CANYbN r.:...:--~- QUANTITY J:,..,,~t-~~~. , J-.~ DESCRIPTION PflO~ECT ~ TOTAl:..TRANSMISSJ ON:PLANT ,I (01 •.••••••••• ()Y~'head Cond tt::iors&Devlces 1 5 to.01 "'. Sutistat 1.011 &SW I ichl ngSt~t10 II Eq~.Ip",.Qllt ..; -~_:_.,-I..'.....'. Steel Tdwers &F Ixtures ••••••••••1••••••••••••••••••1••••••••~ Ibi!lds &"Tralls I•••••••••••••'•••ol ••••!ul •.•• f: Land &.r.and Rt ghts ••••~•••••••••'1'"-I .. TRANSMt 5S ION PLANT !OTA!..aROUGiTFORWARD.$~.I••••••••••••••u ••Ie •••••(I •• ~ "'0. 350 352 353 .354 356 359 ~ I.ESTIMATE SUMMARY Ct.tENT'ALJ.SKA roWER AUTHORITY • sus lTNAHYmOtLECTR ICffiOJECT I -4 ....".I =.\TOTAL..S (x 106 ) Mls=ell~neousEqulpment 1••••••••"•••••••••1 . ;,.=-r..;:q ',.,'::-'-:',.__.c.. ,<>t;"""!I!l!\ ~":~ REMARKS 674 02.«)). "08 NUMBER P5700"00 ,--- FU..E~!UMlaER P5700..14.09 --SHEET ,3 OF 5-.'"---......... BY DArE CHKD JRp ."'"'l2P"W1S-Z'"DATE 1,174 -......,.,..,--:. $1,179 s Feas Ibility Inct uded !.nder330 Incl uded under 331 Inc I uded Ulder 399 "" "n II " It " "" "!! It II I I 5 "'$5 s ;Ii. APfROVED BY JDL ~ TYPE OF ESTIMATE .0 ••••••• •••••c ••• •••••••••• •••••e-••• .........: ........'. ••••••••• ••••••••• .',.. TABLE D.~ DEVIL CANYON ~-= SL'SlTNA~HY~OELECTRIC ffiOJECT .ALASKA POWER AUTHORITY . CL.IENT ESTIM"ATE SUMMARY PRO"JEC·T Stt'Uctl!ras &ImprOVOOlents ,..."I /_. fbwerOperated Eq ul pment ••eo ,;••••1••••••~1••It lie ••••II .. Laboratol"'Y Equipment •••O •••Clfl •••"'••••~o.o •••••e/. Tools Shop &Gara£JEI Equlp,aent ....I••u ••~.......·••••I•••;.••••• . J fLand&Land RIghi's ••••••••••••••4.~.. G"ENERAL FLANT Stores Equ!pmen-;-.,ej _/. ~.,.het Tangible Property J "o.:..u.~~*~••••••• TOTAL GENERAL PLAtfr ••••••••••••••.."•••••••••~•••••-I ••:. "TOTAL 6ROUGIT FORWARD ......,••••••••1•••••••••e ••••••••1•••••••••• CommUllcatlonsEqUlpment ".of 1I."ol eo .a .. Office FurnJture/EqlJl pment u.,.e ~. •TrZStlsportlltloh'Equl pment 1•••~,."1 .. f .. No. 399 397 391 ~25 396 398 389 3~1 3'92 393 394 L·-"..... •~,-,"",~-,""",,,,..,,","C~"-'~_=¥....Jtil '.~1 lJ -$11 t i"I'id'irtrzs ft.A.M JIIlIli!!! ~t-::;~ REMARKS "'''.01.03,'o,'it,l3.-... See Note See Note See f'hte See tbta Sea t-bte See tbte . JOBNUMBER P5700.00 FtLENUMbEf\!:5700.14.09 ".... SHE£T 4 OF ..2 -- BY DATE . CHKO JRP -OATE....,2.....7S-2- 212 1,179 1,:;91$ $ TOTALS- ex 106 ) $ , Feasibility ,.. 184 28 ·164 $ APPROVED BY J;.;.,D.;;.L _ TYPE OF ESTI MATE TABLE 0..3 DEVIL CANYON QUANTITVI_ I I -,e I I I AMOUNT ex 1(6 ) ALASKA POWER AUTHORITY SUSITNh HYl:ROElECTRIC FROJECT DESCRIPTION Cf..'·ENT ESTIMATE SUMMARY PROJECT ·1 I • Insurance ••••.~"••••J 1 .. ·l fees ••.••••••••"0(.j ,to.to . Labor EXpense ••••••••••••••e ••••~•••••••••••••••••eI ••••I'......II •••••II •• tbte:Costs.Under accounts 61,6.1~,64,65,66,an.d 169 are Included tn the appniIvrtlata d lrect ~osts listed above. Superintendence tI ••••••'11 01 ~••'II . SUbtotal e/••••••••••"~."••••,"••• Co ot i 9 ency ••••~••••"••••••"" "•••~••D ~••"e ~•••••••"• ConstructIon Equipment ",,~•••••••D. TamporaryConstruet?-on Facti Ittes I ••~••••••••••••.••••-I \II .. TOTAL CONSIRLCTION COSTS TOTAL 1NOIR Eel COSTS'•••"."tif """'I'"Gl •••"•••".... Camp &Cornm Is~ry eII'I'••••"-I ~••••••••• TOTAL ElROUGlT FORiIARD ·1 ·••••••"I·..·······r·······Q. lND.IRECT COSTS '1 ,) No. 61 62 .63 64 65 •66 69 .. r:._=--~""~. ~ ~ .. ~J a:.~:;.;.~,.,it\ ••.A'"A.•......~.u ..... REMARKS lncl udej t r'i 71 NotApp I Jeabla Inet UdEdln 71 t'bt Inc t IJded flbt Included JOSNUMBER f'5700.00 FILE NUMSER P5700"J4.09 SHEET 5 OF 5 BY 04T-E.....;;.---- CHKO JRP DATE 2/82 174 1,565 ex 106 ) 1,391 TOTALS $ c:'=~_••~.~",,,,. - no $174 (n1~) t.~~ AMOUNT TYPEOFESTIMATE Feastbll ftyI APPROVED'BV._,_.:---e:J,..,O_l -- l'J"'::----< ,COST] UNIT .......... ."...".~ . UNIT TAaLE 0.3 DI;V;L CANYON ~..~ QUANTITY ~~,',ll\ • ORWARO ,."••J.Cl ~•••"••I • ALASKA POWER AUTHORITY ~~ ,DESCRiPTION ESTIMATE SUMMARY CLIENT PRO~ECT -SUS!TNAHYOOOElECTRIC mOJECT ~....;;i!0 ;.; I ... 'l"' Earn I ngs/EX pen ses Our'ng ConstructIon •u ~.1 ••". Interest'•••"'-I •••"'••••••••••"••of •••••C'. Legal ExPfJl1SGS 9 ••"•••••e "••oj •••••••••It ••••••••01 ••••••,,..+/I " Eng Jnearlng ••1'1 01 ..,$••"It ••OIl••••"••01 •••IHI ~••••••••j OVERHEAD CONSTRlCTIONCOSTS'(PRO.I'CT tNDIRECTS) AtininlstrC2t've &Gener81 Expensesl el •••••~.•••<t ••••••u TOTAL CQNSTRlC1'ION COSTSBROUGtT . Taxes ••••••e ••••••~•••••••'.8 •••-1 "~••'."••.,. T<:rtaIOverhfJadCosts n oI ~"'••••"••u""C>" TOTAL ffiOJECT COST tI •••••••••••••••••tI."•••••••~•••oil."•• ~.......; NG. 71 72 75 76 .17 80 :-S--"~__~·lll,<t"'~~-;':i:~.~"t1:!.e..:sA:~'J ..,,«,o,1,:~~~=;,;:;,.M;"~;;~t!~"'4;.~~:."::~'::;:::t~,~,~:;,_.w~",-,:~;:,,",!<,,:~~~~-,::-:~.'t:.'!4,~~.91..;4}:"""'''~;_,...¥...,:;,'':1~;:~:.~~~.....:~~;;Joo'·i'~~..;..'1~::~2:;~'~.~~:t=,~~-:'~:~~~.2.:::~~Wt.~,~~~Jt~.; ~,.;;,.., ,~.:-::~;i _.b I TABLE 0.4:MIT IGI\T IONMI:J\StRES -SIJ,1M!\RY OF COSTS HCOOR>RATED IN CON5TROOTION COSTE:ST I M\TES 14,600 47,100 1,600 N6t. 600 ~ 2,300 j,OOO 4,100 2,000 400 200 100 100 18,400 No\ 10,200 9,000 800 500 85,600 27,400 17,100 5,500 102,700 32,900 12,800 4,100 115,500 37,000 152,500 COSTS ItcORPOAATED If'.!CONS1HOOTlON E5T1M\TES Outlet faer.il'les M~10 t:emCltPev IICl!lnyo n Tunne!Spillway atWatana R.estoratlon of Borrow Aroa 0 Reslorat 101'1 of Borrow "reeF Restoration of Camp and Village Resiorat Ion of ~nstruetIon 51 tes fencing aroU1d camp fenelrg around ~rbage 01 sposal Area MUltHevel'ntai4:l Structure C~pFacilltJes AssociaTEd With tryIng to ¥eep Wor!<.ers out of laces I Commm Itles Resfuratton of H(Su5 RoadS SLBTOTAL Q:lntlngency 20$ TOTAL CONS1Rl.CT ION EngineerIng 12.5$ TOTA L FROJECT WATAtt\ $x 10- lEVI L C~NYON $X 10 . ~.",..~<~•••,~.~, ~".v "~'~1'~"·~;;,tt;·\f'rr;l!'Ml;-:.t:t:~~v:J.:.~,---...·_-'~""~~,:,,,,,_~.=--;;:,;~;;..,;;::::::::::."'!-~,..f::I':::::~:.::.~~;-::0;JG;.,::;:;_-2...:.:;~::"":~!!~:";!~--?".,_';;'~~_:~~,~~~_,::.,i~_'-'~;'-'~~i"'~-'~'''''''~~1:--._,,'~;:,:~:,"'W'~:;·_·~~ TABLE D.5~SUr-N\RY OFOPEAAT ING AND M\I NTENAOOE COSTS ,",,;"r .'Wtt"'~fC ~1~,~-,~ 200 2420 480 200 1000 500 .4,000 500 480 80 ,'~-;'t~~~!.4·"'~'f'i<'~'~~!if~itJ.:it~~~~~~~:f.;.~~w.l\_._jJiWtM g'nr~..,i-"-,".'..-",',..,'""_'0 -.'__"..",,...,'.-',.-•....-"...-_....-..-,..',.'-.~.',".~..." il:Vlt CANYON 120 1920 r.E Vi L CAN)ON ($OOOts Omitted) -EXpense Labor Items Subtota I ~:~:;;,;,.",,-:"':J 400 1000 ~O 6320 000 880 rO;40-0 990 900 340 WA1At-i\ 540 -- 5330 WATA~ ($oOots OmItted) EXpense - Labor Items SUbtotal ~":.~::..J f1:)wer &Transmt.s$Ion Oper~tJonl MaIntenance Contracted Serv Ices Permanent TownsIte OperatIons Allowance for Erw I rormenta I MItigation Conttgnecy Add Itlonal Allowance from 2002 tc>Rept ace CommlJltty Fac Illtles Total Operatlrg and Ma Intenanca Expend ltureEsttmate Power'Development and Transm tsston Fac II ttles i =- r-.f'.'~,~t~""·~,.."";~:,,",,,''£~.~,~"...,-,...":>I e~''''''~r':1:tfl 27.6 27.6 27.6 12.9 4n4 40.5 28.1 6g,2 69.2 48.5 117.7 117.7 198.6 316.:5 316.:5 282.7 59$\0 59Sa 0 294.1 a9~1 893.1 367.4 1260.5 1260.5 436.5 1697.0 16.910 624.9 2321.9 23214)9 4.9 611.1 2928,1 4.9 2933.0 48.1 475.3 335$:5 53.J 0 3408.1 68.9 221.4 3507.8 121.9 362g,1 64.6 138.0 3581.2 186.5 3761.7 65.2 65.2 251.7 3832.9 115.8 115.8 3645 3948.7 204,2 204.2 571.1 4'15~9 t, 295.1 295.1 866.8 4448.0 261.0 281.0 1147.8 412~O 242.8 242.8 139\16 497L.8 156.1 156.1 154~3 512&5 17.7 17.7 156$0 5146 Z- 1565.0 5146.2 ANNUAL CASH FLOW CUMULAT IVECASH FL9W (TO END OF YEAR Watana and DavHCanyon C"",ulatlve and Annual Cash Flow ..;.;YEA;;;;.;.;.;R:...._.............:.;.W\.;.;,.T.;.;,ANA~..-;;.O.;;;;.EV;;..;I..;:;L....;C;;.;.;A;.;.;.NY...;..;O;.;.;.N".,.coml NEOWATANA DEV 1..!:.."CANYON COtoSl NED TABLE 0.6 -SUSJTNA HYDROELECTRIC PROJECt _JANlU\RY 1_982J)OLLARS ...IN MI LLI ONS 1981 27.6 82 12.9 B3 28.7 84 48.5 85 198.6 86282.7 87 294.1 88 367.4 89 436.5 90 624.9 91 60~2 92 427.2 93 152.5 94 73.4 95 96 97 98 99 2000 2001 2002 TOTAL 3581.2 b""""",,, ~'Ii,',,',""....... r'..~V~ TABLE D.7 • l''j];''·~·Y$~~»t',i~"'~·--'"$'..<.,:< 0.0 0.0 0.0 0.0 0.0 56.5 61.6o.u 0.0 0.0 0.0 0.0 8gel 100.1 0 ••0 0.0 0.0 0.0 0.0 0.0 0.1,) 2136.5 3268.5 5167.1 6931.,5 8301.1 663~.2 889,3.42Z==========z:==S~===~:=~s=:=:=s s:'======zs:==:=~=:==:=~= 2136.5 3288.5 5161.1 6931.5 830la 1 8180.4 9055.1s========================~c==:======~===••==~===Z%====== OclO 0.0 0.0 0.0 0.0 0.0 O.Q 0.0 0.1)0.0 OeO 0.0 0.0 61,,4 0.0 0.0 0.0 0.0 0.0 1~6.2 162.3 2136.5 3288 ..5 5161.1 6931.5 8301.1 8631,.2 883Z.0 411.6 693.'5 1057.3 921.'5 1)13.0 153.0 98.6 1508.t,2201.9 3259.Z 4186.1 4B59.8 5012,,7 5111.3 0.00 O.Uo 0.00 0.00 0.00 1.00 1.03 3,3.8 1090 ..8 0.00 0.0 0.0 0.0 14H8.1:s=.==:== 1488.1z=======0 ..0 0.0 0.0 1488.1 0.0 0.0,. 0.0· 916.8 318.4 691.0 O.OQ =2:-2::=':,=-: o ao0 00. 91b.d==:e_=====916.8 ,Ii~:L-..i'~'_"",(~'C~"'·'~~''''''''~r,.""'',~"".""c~"",,,,~'''_~_~''''''~',•.•,.,}'''¥'''''J'''''''''''''''-''''''''''''''''N""~";",!,,.,,,,,,.'I'W~'lIllliMINII'alllJ1ll....~, NO STATE CONTRIBUTION SCENARIO 7%INFLATION AN"D.10%INTEREST 0.0 0.0 0.10 0.0 0.0 0.0 0.0 0.0 851.0 963Q<1 0.0 0.0 ~410 0.0 0.0 0.0 0.0 0.0 U,.9 29.3 ~-~~,~~--~~~----~~~-~-~..--~--~~~----~,---~~~--~~~~~-~--~-~~~~--,-~---~-~~-~~.~--.~~ 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 830.1 933.80.0 0.0 0.0 0.0 0.0 0.0 0.0 0 ...0 0.0 5 ..60,.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 14.6 O~O ':>'0 0.0 0.0 0,,0 0.0 0.0 0.0 830.1 863.4 ~~~~~-~-~~~~~-~---~-~~------~-------~----~~-~~~~-~-~-.~--~~---~-~~.--~--~~-~-~--0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 61.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 61.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 ~03.7 513.0 571.4 648.4 1152.0 1879.Z 1763.8 1369.6 333",1 2,29.7 0.0 0.0 0.0 0.0 0.0 0 ..0 0.0 0.0 1"6.2 16.1 -~-~-~----~~--~-~-----~-~--~~--~--~--------~----------~-~-~----~.--------~--~-~-~03.7 513.0 511.~648.~1152.0 18.19.2 1763.8 1369.6 ,.19.3 301.2 403.7 513.0 511.4 646.4 1152.0 1819.2 1163.8 1369.6 33j.l 25902 0.0 0.0 0.0 0.0 0.0 000 0.0 0.0 146.~16.1 0.0 0.0 0.0 0.0 0.0 0.0 0.1)0.0 0.0 31.9 0.0 000 0.0 OeO 0.0 0.0 0.0 0.0 0.0 0.0 ~~~------~~~------~--------~~-~---------.._........---------..--_....__...----..---.._--~....-.- 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 O.f)0 ..0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 .0.0 0.0 0.0\).0 ~laO 403.7-:a==,==='= 403.1s==s==== 0.0 0.0 0.0 403.1 318.6 318.6 0.00 ~,W'.i->:,: ·-~~-lNt~HE~~~-~--~-~~~~~~~-,eVENLJE ttl!UP,ERAT1NG COSTS OPERAftNGINCOME!'oDD INTeRESTEARNEO ON FUNDSLESSINTERESTO~SHU~T TERM DEBTLESSiNTeRESTor-{lONG fERMoeaT ~ET'E~RNINGS fROMOPERS --,...-..:ASH SOUF!~CE AND USE---- ~ASH INCOMf:FROK JPERSSTATE.CONTRlilUTl':JN tONG TER'"OeBTIJ~AUDOWNS "ORC~P OEnT DaA\oliJOWNS TOTAL SOURCES OF FU~DS LESS :APIT.\l EXPENDITURE lESS ri3~CAP AND F~NDSLESSUEaTR~PAYME~TS LESS PAYlO\;';NT TO 5TATt: :ASH SURPLUStDEFICITJSHOr{T TERM DEBT:ASH,ECOVSREO 1985 1986 198',1 1988 1989 1990 1991 1992 1993 1991t CASH FLOW SUMMARY 13 ENERGY'GWH ==.(SMlllIUN)==~·3381 3'381a0000a00 521~EALP)~1 ce-Mi llS 0.00 0.00 0.1)0 0000 0.00 9.00 o.oq g.oo lI9:l~l!~:~~~6~INFLATION INDEX 126.7Z 135.59 145.U8 155.Zit 166.10 11 .13 190.1 20 .48 520 PRICe';'MlllS 0.00 0.00 0.00 0.00 0 ..00 0.00 0.00 0.00 Z53.0~Z64.31 -----aAlANcE.SHEET---..-----..zzc;JtESER~E AND CONT.FUNO 311 JTHER wO~~lNGt.PITAL •,.~AS~SURPLUS RETAiNED 310 CUM.~APITAL f:XPENOJTURE .~5 CAPlt4L EMPLOYED 461 STATE CUNTR1'l}UTliJ'~ ~bZ ~eTAl~tn .tAk~INGS555Ol:BT :JUTSTANj)lN\J-SHO~T TERM55....OEBI uUTSTANllING-·lONG Tl:RH 542 ANNUAL DEBT URAWloIvOWN l19tJ·2 S~3 CUM.OEBT URAWWUOWN $19132519~t:8T SERVICE C;OVER 549446 Ilt3 Z4lJ 5~~J 3;"0 It'..8 l.bO :$CJ5 141 Zlt9 lt44 516 Uti 511 Zl~ ~;IJ )91 5it8 ••O•••••**O$.,oi;ll.*.~,t••*.**••***.crfJl*~$(l**.(l••,..~•••~••••~1lo'l.1lo'l.1lI.JIll1ll•••11IlnU,lIll••••1Jl •••••$.*1Jt.~I*.$•••$*••*•••*••••••••*•••••••••••,.**.0*•• DA1AIQ"G W4TANAlONlINE 1993)-NOSTATE FUNDS'""1 NFlAT ION l~-INT,EREST 10:t-CAPt:OST $5.1:11 BN ..8-NOV"8Z••*•••*~.***.*~lll~**••**.~.******.*.**.**••********~*****.******l~************t;t**.***lQl~I.**:$**.**«t****.***.****••••••••*******~**t* Sheet 1 of 3 (::;. .t;,'JI 2004 5605 13.95 458.29 338.92 ~ ~-'".-.--.., 2.003 5414- 81.12 428.~1 3~7.44 ,002 5~23 84.91 ~00.29 339.87 lOOl 3'3d7 80.08 314.10 299.58 2000 3381 84090349.62, 296.83 i>-~f;¢.~,w~":C~':::C\,J.i,;Ii\:~.~.,.:"'"",.,;.~.':,JW 1997 1998 1'199 CASH FLUW SUMMARY ~;·I~M1ttlaN)~::= 3387 33673387 101.00 95.b~90.08Z8Sa.0 305.38 32&.15 2~9~95 29Z.0b 294.35 1.996 3361 l07.Q9266.,73 zad.03 1995 3387 114.g.. 2.49.2.6 '2.ao.26 TAJ;\lLE D.7 NO STATE CONTRIBUTION SCENARIO 7%INFLATION AND 10~INTEREST --969 ..5 975.5 9~2.0 989.2 996 •.9 1005.3 1014.6 1775.0 1880.9 189';).532.•0 35 •.(.)38.1 41.6 45.4 49.6 54.1 'H.l 99.1t 108.5_...._.____...._...____..___....._____._.a ....__....._..__~...._,..,...___...__.__.,___~,______...__..____,-..__...._..- 937.5 940.5 ,943.q 947.6 951.5 95!>.7 9bi).5 Ib8~.q 17tH.5 1191.0tI.2 6.7 7.3 8.0 8 0 1 9 ..5 10.4 11.4 19.1 20.9 ltJ.Z 16.9 17.6 10.4 19.3 20.2.21.2 2l.3 38 ..3 41..2dIiQ.2,656.1 t!.52.9 84b.6 844 ..0 &38 ..&633.2 1545.3 1568.7 1558.5 -----,--.--..-..----.....------..........._-...--_...'-~-..---..,.-------------__....._....._------.__......_.........._.-t:b1.2,73.6 60.7 Sti.S 97.0 106;82 116.5 127(.7 193.6 2lol.l ,~ 67.2 ,13.6 80.7 88.5 97.0 106.2 116.5 127.7 193.6 21 ~~.Z.0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 .•0 0.0 0.038~.1 4tt3 ..7 409.7 1115.2 1441.9 1613.4 1483.1 3D..>.."}0.0 0.06.7 1.2;7 •.8 0.6 9.'3 lO.l 11.1 1S"'.2 29.3 22.3 -~--~~---~~~-__~~-~o-_~_~.--__~__--------......-_..-...-...._--_._.._................_....~-,--_.._....-..._-... 459.9 524.5 498.2 12,12.3 1548.2 1129.8 1610.7 589.8 223.0 234.5 "'l8.2 47a.8 448.0 1217.1 1487.6 1663.3 1531.5 362.3 90.9 99.2 6.7 1.2 7.8 8.6 9.3 10.l 11.1 159.2 ~9.3 22..335.0 3tS.5 42.4 46.6 ~1.3 5b.4 ol.l 6ts.3 102.7 113.0 0.0 0.0 0.0 0.0 0.0 0.0 OliO 0.0 0.0 0.0~__~_____.~~_~~~___~__~_______~~_~__~__~_~__~~~__~_~_______~a~~__~__~____~_,~____ 0 ..0 U.f}0.0 0.0 0.0 0.0 O.f)0.0 0.0 0.10.0 0.0 0.0 0:-0 0.0 0.0 0.0 0.0 0.0 -0.10.0 0.0 0.0 0.>0 0.0 OeO 0.0 o.c 0.0 0.0 61.2 13.4 aO.1 137.4 95.4 104.1 113.7 Itn.3 20&.8 22'7.8 1 01 .8 102.•a 1 0 3.9 1 05.2 1 06.5 10 BII 0 1 0 q .6 191.2 2 03 .0 20 b 0 2 0 ..0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9311.6 9190.4 10238.5 1145~.~12941~1 14606.4 16143.8 1~50b.2 16591.0 16696.2 .S~=,=:==.~=:=:======;=========~=a~====:=2======:Z~==:~=:2SS=~==t a==~==~=s=:==~:= 9480.&'996b.b 10~Z2.:)11648.113145.0 1't818.5 16367.1 1688b.6 17008.8 17130.3••~~==.~sc===~:=:::===.:=ae:::::aaa::=:==.==~=%=••=••:._==a_:=_:.=~===.=a==a=:== 0.0 0.0 O~O 0.0 0.0 O~O 0.0 0.0 O~O 0.0 128.5 202.2 Z0.2.9 311.4 468.4 514.6 691.1 818.7 1012.4 1224.6 Ib9.0 17b~3 184.1 192~1202.0 212.2.Z23~438l.6 411.9434.19183.0 958a.2.9955.511084.0 12414s6 IlJ031.b 15452.615687.315584.515411.5 154.9 16b~3 1.43.6 3lJ4.8 44h3 46h5396.4 7S.7 .0.0 0.0 52,b6.2 5432.5 5516~1 5960.9 6402.2 6863.1 72bO.l 133~.b 7335.8 73'35.8 1.Oit 1.04 1.04 1.05 1.05 1 ..06 1.06 1.04 h 05 1.06 ----..I,~taHE ...--..~-·'-«;)-......-e:ti-..-!EVcNuc It;SS ·JPl:.RAT IN.c,cost S aPERATIN~I~CO~c AOl1 l\llE.REST EARNED ON fUNOS LESS INT~REST UN SHURT TERM DEBT Ll:,SS INTEREST ON LONGTER'"DEaT ~erE~RNIN.GS FROM opeRS ...----;:.ASH SI.JUA.CE ANI)USI:-......- GASH l~Cui4EFRO't ;JPERS S.TATE CONTRUWTIONLONGTERMDEdTO:tAl'lOOWNS,.fORLAit UEBT DRA.lDlJWN5 TotAL SOURCes OF FUNOS L~SS CAPITAlfXPENOITURE L t:.sSffuR·CAPANO FuNDSLESS~E8TRl:PAYf'1tNTS l.ESSPAYMENT TO STATE :ASrlSUltPLUS(OEFICIT) SHORf Tr:Rl'4 0&:8T CASli ~ECO~ERED 510 170 Sl7 21~ ,,~o 3'11 SitS 548 1t"6143 ZitS ~49 320 4 ..a 200 3.lJ~ 1...1 249 4lt4 Sheet 20f 3 73 5~E~GV c,wrt 52,1 :tE.ALP~lce-""ILLS ftcf.)1 NfLAT J ON INoa;x 520 PltlLE-fULLS ***;:t*****************.(:**(c*****r;t*,;t****************~*Jlr******************************loC#****************************#*********~****UATAlj)KG"'~TAn'A(t)Nll1'~l:1l]9~)-NO STATE FUN05-'1NflATIDN 7%-1 NTI£Ri:.ST 10-l:"CAPCOST $5-.117 aN d-NOV-Hl ***~****~*ill**#*.***************"'***#******************************************:~*********************************************)',r*** --"--~ALANCE sHeEr ..-----·.....:... 22S i\.t.S:.:l'\ic ANa ceNT.FUND111aTHtR.~O'&lNGCAPlTAl 4S~CASH SURPLUS RET Al NED 310 CUM.CAPITAL rXPENOITURE ."65 CAP!.TAL €"'PLavEO 4blSTATECON.TR I:lUTI O~ 4bZ ~ETA1~E'O EA~~lNGS 55'>OtCT JUTSTANIH NG-SHORT TERM 55ft ilEal JUTSTAN:>lUG-LONG TERM S4lAUNU41.OEBTORANWOOWN $J.982543:UM.OE8TORAWWOOWN Sl~al Sl~'fai SER~lCE COvER )****~*(&*******~****(t**********~*************#***-=******.***********~'~********:)~**~u>tt**Jll********~*****************t.Il;\***********9.)ArAIJl'I.uW~rANA CON LINE 199~U-NO ·S.TAT';'fUNO$-1.fl1FLATION 1'.:...INTcRE;ST lo~~tAPC.(JST"5.111 &iN..o;S-NOV-oZ ~*****~u~***************$****I)I)C*****************#***************r~****lIi'******(Jl******************************¥******************** ""v;-c-'!)'Fr-'·i,;c-,:t.\t~j:-·:.;,(;;"::;;;/_,C"'~",*~;:~:"I~.l'<,,,q~...t~"-M";<~~~~~~~'4"'.2:~~::i,~niJil':~~~j L'f1~:~"-~'-(''j)"'JIIl .•_1 IIJIi® c::. 4330 ..8 0.3 0.0 0.3 3031 q ...0 412.4 145.6 25055.5 21202 ..3 18113.9 751.6Z336..5 0.0 4330.a 0.016119.9 151.6 32521.6 220,.0 0.0 4330 •.5 751 ..6 13783e4 7335.8 7335.8 0.00 • z=:::.::.==::: ...,-'..---....- ...........c-..._ r.".~. 500.6 l51.0 0.0 1811311I9-=======18865.5 TABLE D.1 533.2 2l7.9 48.8 2bb.5 0.0 Z152 ..2 l38.4 484(14 0.0 0.0 48.8 0.0 0.0 0.0 191?l.8 45 ..9 10.3 1405 ..0 434.4 GD"'__'.·"__ .-_"C'.._.......... ---._---_... 50006 251.0 0.0 18113.9IC:=:::=::::= 18865.5a======= 0.0 4330.5751.6 13183.4 0.0133~.R 1.13 ...,~~~~"'< Id9~.0 42.0 6~.8 14l~.l "'42.0 "".z.o0.0 0,,0 4 4a1 2113,,4· 21~.4 lt86.7 199.1 4.$·.1 ZltZ,.3 UIIU 0.1o.u 0.1 w __........._·_ __c __..'_.._ .......,tD _ ........----..... 458.7 24-4.1 0.0 11896.011:=0:======18S98.BIIZ·=a:==== 0.0 311'46.1 70L.a 1404'1.9 0.0 1335 ..1:1 1.1l. l077 •.9 20\.1.1 1817.7 38..5. 01 ..1 11.51 •.2 403.2 0)1 0,,0 0.1 ~03.2 0.0 0.0 ~1.0 •llf'l':1"'" 444.2. 182119 41 ..0 220.2 0 ..0 0,,0 3404.2 658.1 14292.1 0.0 1335.8 lel1 ==-=-====': 420.3 Z37.8 0.0 17b96.3=======:1:18354.4 .....'-----,- ....-...-_..,... 2010 2011 201.2 2013 TOTAL 6blb 6638 b660 6682 10it826 44.95 42854 40Q30 38.23 OfloOO6a7..77 735.91 lel.42 842..54 0.00 309.15 ~13.04 317.35 3Z 2.11 0.00 405.-4 lb7.b 31.5 200.2 0.0 Uibl"B35.3 5&.0 141103 361.9 2045.2 183.4 0.1 0.0 0.1 367.9 0.0 0.0 37.5 0.0 3001.0 b17.1 14~12.1t 0.0 1335.d 1~10 ....,.;;J),......__.__ =.::'=:::=:::':= 385.1 23Z.0 OoU 1751:h4=======:::lS130.5 ~J,.~,-t;;r;u\_~"~.;:;~ 335,,6 3.35,,6 0.0o,~o 34,.4 0,,1 -0.1 0.0 2015.3 Ib8.0 37rJ.l 153.6 34.4182..0 0 ...0 1 8~1.3 32.3 54.5 Ilt69.5 --_.._--~ --_.__._...• .....--...-·-1-- 352.8 226.7 0.0 1734508::===:::1= 119251'3••===z=== 0.0 2633.2 ')79.5 14112.6 0 ..0 1335.8 1.09 'i!.:+;;'~i::;:",:~~ a06.1 -0.1 0.1 0.0 1987.6 153.9 1833.9 29"b 51.4 I~Ob.Q 30tul 0.0 0.0 31.5 337.b 140.1 31.5 165.~"'.0 0.0 2297.6 5ltS.2 14894.6 0.0 13350& 1.03 ======== 323.3 221.9 OcO 1719Z.2========17731.3 ---....---- ..._---_....- .._------- 279.It 0,,0 o.~c.o 1821.8 ~7.1 48.5 1521.0 I 2007 zoo~2009 CASH FLOW SUMMARY===('HI lU ON)='':==6250 647,6544 ~5.94 ~1.13 41.92S61.42 600.12 ~4l.71 314.07 307.1~501.98 308.2 li8.9 28.9 150.4 0.0 2.79.4, 0.0 0.0ze.9 19b2.tl 141.0 29b.Z 211.4 0.0 11051.5========'L7565.1======== 0.0 1.991.5 513.6 15060.0 0.0 7335«8 1.08 --_._----_.- 0.0 1335.8 1..07 2:14.9 1<)39.8 n!~.l. 254 CJo(}o 0 26 5 ZOG6 281.3 118.1 Z6.5 136.7 ~.o 0.0 0.0 0.0 1310.6 24.9 45.8 1534.7 b147 .60.15524.69 315$59 211.4 213 •.4 0.0 169;',2.bz=======11407 ..3========0.0 1712.1 484.8 15l10.5 ..-.,..---~-- 0411 -0.10.0, fNO STATE CONTRIBUTIO.N SCENARIO 1CXJ INFLATION AND 10$INTEREST .256.9 1.08.2 24.2 124.30,.0 232.b 232.6 0.0 G•.O 24.2 2005 1918.8 ~1.6 •.4 6092 64.24 1lt':llh31 314.CJ9 1800 ~4 22.8 43.4 1541 ..2 {hO 1'<-51 ..2 4~a ..3 153o\7.Z 0.0 7335 ..8 h06 ==z===''::'': --.).----- ........_._....- 248.7 209.6 O~!O 168041/4-:=::==1== 11l6Z.7 --_.....--- r ~J'::~'.;w;..:'~'to' 4bl 4b2 555 S~4 542 5lt3 519 2:2, 371 1t54 310 46; 73 ENE~GY Gwa 521 ~£:AL .PUCf!..,MI LlS 4bb lNFL4(lUNlNQ~X 5ZJ PIH(.e-HiLLS Sheeit 3 of3 -·-~"".IN.CO"'E."'''--'''·_--''''-----''-- Slb ~EVE'tJE' 110 LfSSOPiRATl~G COSTS ·511 oP£aATlNG IH~oME 214,\00 INTF;REST EAR.Nl:O ON FIJNUS550LtSSlNT&kf:ST UN SHORT .TERH UtAT 3'11 Lf:SS INTEREST ON LONG Ta;RHDE8T 543 .~T E'R~lHGS FROM DPERS -----CASH SLJURG.t:AND USE"'--- 54a :ASHINLOMeFRQ~oP£a~ it4b STAT c CONIR I?urlON Ilt3 LJN(,TERM UEBT DRj"WawNSZitS,40RCAPDEBT DitAW,JOWNS 54~rOTAl SOURCES OF FUNOS )lO Lt:SS C.4PITAL t..XPENOITURf: 448 L~SS ~JRCAP AND FUNOS 2bO Li:.S5 vI:bT IU:;PAVf1ENTS 395 L~SS PAYMENT TO STATE 141:ASH s.!JRPLUS~OE.Fltl T)24~SHO~l'TERK DcBT ~44 :ASrl ~fCOVEaED -----3ALANG.tSHEET--~--~--- ~ESERV!A~DCONr.FUND OTHeRrlUR.1C.ING CAP1TALC&\SH SURPLUS REr~\l NED CUM.CAPITAL EXPENOITURE CAPITAL Ef1PlJVED STATE CONTRIJUTION It £:TAI ~EO ·EARNINGS JEBTZJUTSfANOING-SHORT TEstH ilEBT JUTSTANOING-lCiNG TERM 4NNOAl DtBT ORAWwOOWN $19uz;UH..DEaf ORAW~OOWN 51982:near SERVice COVER . ...·,;;·::..",··-_I::·.:,.~c,::\;;_....;,,~m.-.wwnm ,se._Cd t ......;"..l..i !! TABLE Q.8:SUS!lNA COST Of POWER Notes:n}RL:.Re terence Line on far left of pr I n to u1' 14.33 2392 243.74 2003 $'s Per NeT KI I 0 ~at t Actual $I.S 1982 $IS .09 •10 •.00 0..00 0,00 0.00 10.19 Percent 10..00 (2)Cost In 1982 $'s Is derived throughout by deflating AcTUal dollar costs by the Inflation Index CRt 466). (3)At the 38 percent plant factor In 2003thfs glves a cost of POWer of 71.5 mills kWh tn 2003 (tn 1982 dol lars).the cost of 61.12 mills kWh tn Tab I e2 results frem t"etOora deta t I ad c6st analysis Qf that tabfearnd In partICUlar .atlowance for renawalsC!This data reflects thf\economIc cost of power tn 2003.The c narga to consUmer~for 1'h t s po r;er-WI II be d~termlnad by the level of state appropriation and the =?paelflcs oftheflnancJng plctn.For the plan gIven In the text the cha.rge to conSUmers 'sas$hoWn In RL 5210fTllbi e 1 at 55.54 mJ I Is !n2003. Federilll ncome Fed era I Mlscal t aneous Si~ate &Local Fixed Charges (a)Cost of Money (b)Depreciation n 0%SO yr S.F,,) (c)Ins urance (d)TaxEls FIrst f utI year of 'W~tana &Dey t I Canyon (See lable Stor Detail) Total Plant Investment I ne.I.D.C (RL 370 ,..466) II.Fixed Operat i ngCosTs Ca)Operation &Maintenance 'neludlng admInistratIve and general expense (RL170) Total Annual CBpacfty Costs fl·~ J ,J TABLE 0.9:fORECAST FINANCIAL PARA~ETERS Haal Rate of Increase In OpllJrdtl ng Costs ..1982 to 1987 ..1988 on Real RatEtof Incre;~;ii(:)In Capital Costs -1962 to 1985 -1986 to 1992 ..1993 on $4.41$1.5,35 3 387 GWh 5223 " 6 616 " lotal Devil Fanyon 2002 Sl.470 $.<~117 bill ton b vIlion $5.42 $15.42 mtil Jon -...millIon 1-5 percr:mtQf Operating Costs 10 percent of Revenue 100 percent of OperatIng Costs 100 percent of Prov islon for CapItal Renewals 10 percent per annum 35 years 7 percent per annum ~7 percent per annum 2.0 percent per annum 1.1 percent per annum ~o percent per an I'l um 2.o percent per annum Watana 1993 $10.94 s :s.647 b II I Ion $10.0 mH lIon Interest Rate Operating Costs ..per annum Reserve and o,ntlngency FUllId 03bt Repayment PerIod Inflation Rate PrO'll sion for CapItal Renewals"per annum (0.3 percent of Capl tel Costs) OperatIng WorkIng Capital Proj eetCcmp Jetlon -Year Energy level ..1993 ..2002 ..2010 Costs In Jan~ry 1982 Doll ars Capt fa.1 Costs ........."--" ,-.....'........'• 37.4 116.7 316.7 2571.1 • Utility Annual Enea-gy Demand 19BO GWh Provides Whole$a~e Supply Purchases Wholesale Electrical Energy NOll-Exempt Tax Status Re:IRS Section 1103 Exempt NOll-Exempt Non ..ExemPt Noti-Exempt ......~t.,6~........ SCCT T.ABLE D.10 .....RAILBElT UTILITIES PROVlDING MARKET POTENTIAL ST/Diesel SeCT/Diesel ST ST Predominant Type of Generation 19.«1 221.6 SCCT Exempt *-585.8 395.1.SCCT NOll-Exempt **941.3 0.9 Diesel Noo ..ExeMpt *-268.•0 2.6 Diesel !\Ion·Exempt *-284.8 5.5 Diesel Non-Exempt *-26.4 30.0 Hydro Non-Exempt * 53.8 ST Non..Exempt 25.0 SeCT Non-Exempt 68.5 221.6 18.6 46.5 1114.3 Generating Capacitv1981 MWatO°F Rating __"'"'......c:~<~_~."c,~__~--:..,.c,',~"c,~,.38_,".c.gL.W:~4=.~~,=~,l'''4'''''~F~'''''~__.....'IJ ~"'''..~',"N·"",,,•..,,......--..._'The "__l.....S=-.~:i~· tr l i IN GLENALLEN/VALDEZ AREA Copper Valley ElectrIc Association UTILITY IN FJMRBANKs -TANANA VALLEY ~' Fairbank$Mul1~c:p~1 Utility System' Goldl!n Valley Elec:tricAssoc;ation1 University of Alaska National Defense' TI')T)~L IN ANCHORAGE..COOK !NLET AREA Anchorage MunlcipalLigM and Power ChugachEle~ri¢Association Mat.nu5ka Electric Association Homer ElectrIc Assoc~ation Seward Electric System . Alad:aPower Administration c', NaticIOal Defense fndul;tri~I-Kenai 1PO()ling Al'rangements in Force '~T'.·'·L-'L~_.~_._.~_..<.-.....:,-....,:"""'-.:-_.:-,~~~-~~(..:.0 U kJl c I ''"''.~'''''W ~~li:OIb'"l6l!lOiailiiil'iiliib 1twiiI'.Zli~,.iaIlil 'i~"',,,t .';",,"-..oo...~•• I TYPE OF OWNERSHIP Municipal Municipa! Federal Muni~ipcd Cooperative Federal Cooperative Cooperative Federal Federal Federal Federal Federal Cooperative CQoperadve Cooperati~e Ceoperative Federal Municipal Municipal Cooperative Cooperati/e Cooperative PLANT LIST UTILITY Anchorage MU1~·icipal Light and Power Anchorage MunicIpal Light and Power Alaska Power Administration' Fairbanks Municipal UtHities Syste.m Chugach Electric Association,Inc. United States Air Foree Golden ValleyEleetric AS$ociat~on,Inc. Chugach Electric Asso~iation,Inc. United States Air Force United States Army United States Air ForcQ United States Air Force United States Army Chugach Electric Associatioo~1 nco Chugach Electric As,;ociation,Inc. Golden Valley EJectric Associatlon,!nc. ChU9achElectd~Association,loco United States Air Force Collier-Kenai Cordova Public UtiJitie$ Golden Valley electric A$sociation,Inc. Gold~n VaHey Electric Association,hlC. Golden Valley Electtic Association,Inc. Fairbanks Anchorage No.1 Anchorage Eklutna Ch~na KnikArm Elmendorf-West NAME OF PLANT Cooper Lake Ef mendorf·East Ft.Richardson Ft.Wainright EUson Ft.Greeley Bernice Lake International Station Healy 8eluga Crear AFB Collier-Kenai Eyak ~lorth Pole Valdez Glennallen TABLE 0.11 ....LIST OF GENERATING PLANTS SUPPl..YING RAJf..BELT REGION-----------_._---------------,--..,---,---- PLAN'r No. 2 3 6 7 10 22 23 32 34 35 36 37 38 47 55 58 59 75 80 81 82 83 84 ,III [ii,.''...._' ill .\'Jf~ri il··.··;.'! ..~IT ..~. ..~.j.....~.r'.i :t ) {} ,.~ ,t~' i.~ j ,l, ~ I I I II I I TABLE 0.12:TOTALGENEHATlNG CA~AClT,(WITHIN,THE AAILBELT SYSTEM (1)Installed capa¢lty as of 1980 at O·F (2)Exctudes Natlonaill3fel'l~Instal ied capacJty of 46.5MW 1InstaIIadCapacity 221..6 RtH I bett Utll Ity Ancoorage M~fclpal Ltght &Fbwer Department Chugach El ectr Ie AssocIation Golden Valley Elecirlc Assocl~tlon fairbanks t-tJn!clpal uti f ity System Copper Valley El ec"lr Ie AssocJat 100 ~LPD TOTAL CFA GVtA Ff-1 t.S CV.EA MG\ HEA SES APAd AbbrevIations 39~.1 221.6 6&.5 19.6. . Matanuska EI ectr Ic Association a.9 HOfller Electric Assocla1'Joo 2.6 S~ward EI ectrlc System 5.5 A18Skaf'bWer Adnil\istratlo~..3QO U of A Un 1versIty of A IllSka 18.6~':;"'::':"':::":"--::'::':':";:~:::":";..l-...:.::':"":~:':::':';=--""""_"""""':'::':~'_ 984.0 ~ 1.-=-.1.' ,.......' ,,,'.Ct ,;""",", ...... 1992 1994' 1998 2002 20n 1998 1998 2003 2005 2012. 2012 1993 2002 2008 1994- 1995 2000 2011 2002 1997 1996 1997 1991 1992 1995 1995 1995 1995 19.95 1995 1995 1995 1989 1987 1987 1993 2UU5 1991 1997 1998 1998 .~~,..(t:~,,;.ntR¥ii~,;,... Io.:;-~::.;'W' NG NG NG 00 NG NG NG 00 NG 00 NG NG NG NG NG NG NG Coal 01 I OU 011 Oil Oli 011 Ott 01' all OIJ CJf I 011au Coal Coal Coal 011 Coal 011 011 011 Ot I J;,;, ,,",.,~,~.,;-~ ~;::'~~,~,,~\?~"_~;,~'t"S~~,~_~~~:i~~_,,"L::...•!'!~~"'~~~",-.-..,~!!:l!~,tl ,",=;h~8 ;,. o :vta.;,p,;;;__"'-"-'--~''''~~'''''''-:li£''''',....',-;. Gf 1962 14,~O()16.3 Gl 1964 14,000 16.3 GT 1968 14,000 1&0 GT 1912 12,000 32.0 CC 1979 6,500 13900 GT 1968 15,000 16.1 GT 1968 15,000 i 6.!' Gf 1913 10,000 53.0 b'T 1975 15,000 5e 0 Sf 1976 15,000 6&0 GT 1977 15,000 6aO Gf 1963 23,440 &6 GT 1972 23~440 ta,9 GT 1978 23,440 2ti 4 GT 1964 40,000 14.0 GT 1965 -*140 GT 1970 --*18.0 HY 1961 ....*16,0 51 1967 11,808 2!i 0IC196714,000 2.8 GT 1976 13,000 65.0 Gf 1977 13,500 65.Q GT 1911 14,5(};.~1&4 GT 1972 14,500 17.4 GT 1915 14,900 3.5 Gf 1915 14,~O 3..5 IC 1965 14,.000 3.5IC196514,000 3.5IC196514,000 3.5Ie1.965 14,000 3.5 IC 1965 14,ot~3.5 IC 1965 14,000 3»5 S'T 1954 14,000 5.0ST195214,>000 2.5 51 1952 »4,coo 1.;) GT 1963 16,500 "'.051197014,500 21.0 Gf 1916 12,490 23.1Ie1961.~1,000 2.8IC1968j1,000 2..8 IC 1968 11,000 2.e .t.~~~~,..,~~~..~t.1iiI" 1 2 :5 1 2 3 5 6 7 1 ? 3 "1 2 1 2 1 2 3 4 5 6 1 S 9 10 1 2 3 4 5 6 1 2 3 1 2 3 4 5,6,7 . l'ABLE 0.13:.GENER/',ltN$l~YrswlTHIN 1HERAILBELT ...1980 i1~~~:'I,-',, STaT'lob lEtT Ilia "lnsTallatlon ~TRate.lnsTall9d Nama NOt;rype Yea1"__(Btu/kWh)capacity (MW)FuelTyp~Retlremant !t~..ar Inte.-naT lanai STatiori MtLPD lV~lro AMlPD AtJiLPO G..~SU III van BelUga Beluga B61ug" Beluga BsllJgcl Bal uga Bern Ice Ulke Copper La~.a Healy tbrthPole Zeilander' Ch~l1a FMLS 7 ..Id'o."""#05''t~.....ib "V-II '.....~_..~...#.C'.~.,...Q •='"'••~!'" ..",..~~.,.".- Chljgact: Electric AsSO\;latlon (CrA) ~belT UTility Anchorage f.tJn tel pa I LIght&A::>wer Dapartm~t (AM LPD 1 Go I den Vii lliay E]act,.-Ic AsSQc tattoO (GVrAl fairbanks Municipal ut1.l Ity SystemC fM L6) .[t-,-·"';'iJ..~_,,_,~_,~_~~~,~.,t;t"'-"'''11 JAB!.E 0.13 (Continued) ~~~'_?~~-~~_....:..-_~~~-~~-~ ~,4 l2't~"~ :) >.~-~,:fJI!' :j ~-,,~~!lIl~. '..;.;.:~~,;t'~:"'7.'~~!'1 ~~ me,elt Station U1lt U1lt Installation Heat Rate install ad UtHtty Name No..Tyee Year (Btu/kWh)Capacity (MW)....!'..uel Type Retirement Year HamarEI ec-rr Ie Association (HeAl th Ive:-<:>l t~'of Alaska (U of Ai Copper Va IleY Electric AssoclatJon (CVEA) MatanuskaEI ac. Assoc:lat Ion (MfA) Saward iEI ectr Ic System (SES) 'Alaska FbJter Adm In Istratlon (APAd) Hoo!er Kenai pt.Graham S61dovla Ul tversti'l' lkJlvers Ity lA'1lversltyu..lverslty lkllverslty C'IEA CVfA CVEA CVfA CVEA CVEA CVEA C'iE"A Talkeetna SES Ekluma 1 IC 1979 15,000 0.9 Otl 2009 1 IC 1911 1',000 n2 011 2001 1 IC 1952 15,000 0..3 OU 1982 2 IC 1964 1511 OQO 0.6 OJI 1994 3 Ie 1910 l5,;000 0..6 011 2000 1 5T 1900 12,000 1.,5 Coal 2015 2 S1 !980 12,000 1.5 Coal 2ot5 3 S1 1900 12,000 H10 Coal 2015 1 Ie 19B()10,~O 2.8 011 2011 2 IC 1980 10,5.00 2.8 on 2011 1-3 IC 1963 10,500 1.2 Oi I 1993 4-5 Ie 1966 10,500 2.4 OU 1996 6-7 Ie 1916 10,500 !i2 ~Oil 2006 1-3 IC 1961 10,500 1.8 011 1991 4 IC 1972 10,500 ttl 9 011 2002 5 Ie 1915 10,500 1.0 on 2005 6 IC 1915 10,500 2.6 on 2005 7 Gr 1976 14,000 3.5 au 1996 1 IC 1961 15,000 0..9 Oll 1997 1 Ie 1965 '5,000 1.5 011 1995 2 Ie 1965 15,000 1.5 011 1995 3 IC 1965 15,000 2.5 011 1995 HY 1955 --3(10 --2005 TOTAL Notes: 984.0----.............._----------.......--------~--,--,-----~_.--:;..:;..;.;:...;:;...-----------_.......-----........_--- GT=Gas turbine CG=Combined cycle HY ;.:::ConventIonal hrdro Ie .=internal combust Ion S1 :;:.Steam turbine NG =tefural gas ~=Not available *Thls val uaJUdged to b&tJlreallstlc for large rangapl ann log and thlrefore Is adJ ustf3<i 10 15,,000 for genarat Ion ptann Ing stUdl £IS. 1!'BLE 0.14:SCHEDULE OF PLANNED UfILIIY ADDITIONS (1980...1988) -Av~51ergy (GWh) 55 *f'eWUltt/lb.a wH I encanpass lhl+s 6 and 7,ei3Ch rated at 68 MW.Total new station capacity will be 178 MW. lABlEOa 1.~:OPERATING AND ECONOMIC PARAtETERS FOR SELECTED HYDROELECTRIC PLANTS ---- Max.Average (198.,,.~2 '.1 Economic Gross Installed Annual Plant Capit,1 Cost of Head Capacity Energy Factor Q:>s'6 Energy No.SIte River Cft)(MW)(Gwh)<%)($10 )(S/1000 Kwh)- 1 SnoW Snow 69Q 50 220 50 255 45 2 Brusktlsna'Nenana 235 30 140 53 238 113 3 Keetna Tal keatna 330 100 395 45 463 73 4 Cache Ta'keetna 310 50 220 51 564 100 5 fkoWhe Nenana 195 100 410 47 625 59 6 Tal kee"tna-2 Tal kaetna 350 50 215 50 500 90 7 HIcks 3 Matanus ka 275 60 245 46 529 84 8,Chakachamna Chal'..achama 945 500 19'25 44 1480 30 9 All t SOn AllIson Creak 1270 8 33 47 54 125 10.Strand ;.~n e la~Bel Uga 810 20 8S 49 126 115 Notes: 0)Inct tJdtngeng inear tng and oWner's admtn lstratlve costs butexcl ud In9 AFoo. (2)Inci udl n9 I DC,Insurance,AmorflzafJon,and Operation ClndMa intenance Costs. (3)Anlodepedent stUdy by Bec:hteI has proposed an tfjstall edcapacity of 330 MW, 1500 GWh annuallyafa CQstof $1,405 mUllon (1982 dollars),Incl U(Un9 AFPG. (1l Installed capacity.. 7040 8130 7080 7041 1064 7088 lota r $ys tam ft8sent Worth Cost - ($106 ) 1895 1.990 2005 1958 1978 2028 144 744 894 822 822 922 50 70 10 60 30 30 801 576 501 576 426 576 000 l.QO 700 500 700 Insta.I ad Capac Ity dii>by )"otl:ti~""jiern Category In 2010 Instalioo lherniT !:!ldro Capacity Innoar-Gas oJ I •2010 (MW) 500 l1£1 L'M1 I.FL 7 LWP7 LXF1 L403 OOP5Run I d.No.load Forecast Medium Mad lum Mad IUm Medium Mad fUm Medium ·tb Renewals N-,,·Renewa J 5 Plus:l Chal<achamna (500)-1993 l<eetna (100)-1997 TABLE 0.16:RESULTS OF ECONOMIC ANALYSES Or ALTERNATIVE GENERATION SCENARIOS No .Renewa I s PI us: Chakachamna (500)-19~ Keetna (00)-1997 Snow (50)-2002 No Renewals Plus: Chakachamna (500)-199.3 f(6etna (100)-1996 Strand line (20), A I If am Cr eel<.(8).. Snow (50)-1998 No Renewal s Plus: Chakachamna(500l-1993 Kcietna (100)-1996 Strand.llne (20), Allison Creek (8).. 500W(50)-2002 No Renewa Is PI us : Chakachamna (500)-199.3 Keetna (100)-1996 Snow (5('1,Cache (50), Alils:>n (;resk (8), Tal keefna-2 (50).. Strand Ilrie (20)-2002 Generation Scenar'lo -!ypG;Description All lhennal ThermalPJ us Alternative HYdro Notes:-_........-...._---_...._----_...._---------,--,--,_...._--_....._---------------------------------------_....._--_....------------,....._----- TABLED.17:SUt.M\RY OF THERM4.L GENERATING:RESOURCEPLANTPARAt.£TERSI1982$ \ (1)As estimated by Batfelfe/EbascoWftooLrt AF~. (2)InclUdIng IOC at 0 pa::ent escalatIon and 3 percent Interes'f, assufIj fng an $""'Shaped expand'ture C!K"ve. (3)Excl udes tranSlrJ ss Ion. 0.·55 $38 D!esel 10 MW 11,5()(J 1900 1 5 1 1 856 869' G,s TurbIne 70 MW 12,200 1984 2.7 4.8 3.2 8 4 fJ27 636 8,000 1980 125 1.69 Ccmbfned CYclEl 200 MW 1,075 1,107 200MW 1~OOO 1989 8 7~.1 8 6 2 6 4 1~83 0.6 2,242 2,309 Parameter He~tRate (Btu/kWh) E~rl last Ava n at)n ~.~ O&M Costs FIxed O&M ($/yr/kW) Var f ab re O&M (&IT*!) Outages Plclnneej OJtages c%) FOI"'Ce«;l Outages <%> Cc)OstructJoll PerIod (yrs) Startup TIme (yrs) Unit Capital Cost ($/kW)1 RaIl belt Bel uga 2,061 Nenana 2,107 Unltqapltal Cost ($/kW)2 RallbelT 8elugi3 Nenana Notes: TAStE .Q.18:R&.L (I NFLA TION-ADJUSTED)ANNtJ!'.L GROWTH IN OIL PR ICES 1 OGP5 al1alysl$used danestlc market prIces With zero escalation beyond 201(1(~urce:BattQ11 e) 2 Ba$ad on elF prIce In Jzlpan ($fi,.75)less esttmated cost of liquefaction andshlpplng(.$2.10)..(~urce:19,20,.21). 3 SoutCEH (9),(22). 4 Alaskc)OPportl.til lty VCiILIG Eiscal atesmore rapt dl Y than OlF pr tees as II que'" fl);tton and shlpplrg costs areestfmated to r<:mafn constant In real tenns. TABU:a.t 9:~EST IC MARKET FR ICES AND E)f10RT OPPORTUNITY VALUES Or NATURAL GAS .f!:.obab I I fty 0.3 QS 0.2 -$4.65/M'v1Btu2 - Export opportunft~Va I Ue Low •Medium .igh 27%46%27% 2000-2040 o t,0 2.0 N.··Aa 0%2%4% 0%t%2% •••••~•••~0W717 tmt nM....".tlls' $3.OOft.f.1Btu 1982-2000 o 2.0 4",0 Growth Rates (Percent) 0%2.5%5.0%0%2-7%5.2% 0%2-0$2.0%0%t,2%2.2% Domestic Market Prlce 1 Low M"6d j l!m.High Low Case MedIum (most Jlkely case) High Case ~se Period (January 1982) Pr ICQ of !'b.2 Fue I 01 I -.$6..5Oftt1Btu. Probab i lay of Occurrence Base Per tod Va I lie Reclitscalat40nCIF' Pr ice,Japan .... 1982 ..2000 2000 -2040 Real Escalat!on AI aska Pr Ice 1982 -2000 2000 -2040 1 AssUn1''''Ig a 10 percent discoUnt for Alaskan cpal due -rn\quality dlfferem- tfal$,and exPOrt potential for Healy coal. 1.95 4-0 2.0 271.43 5.0 2.2 271.75 4.5 t.9 27 2.66 4a 0 2,0 272,08 4.8 2.2 271.74 ,,~3 2.3 27.......' 24 24 24 ?rohab II i ty of Cbcurronce % oo ~1 2000 ..2040 (%> oo ~J AnnUal Real Growth Rate l~ao ....;~D9Q ('$) 11l•••••••,I'.T.'.-.ilFlli1I1.·IIPilIII~m.·."M"'a"_•."1Ii:.l'UWmtt1iu:llililillliill.l!l:;...lIiIIi··•.....r~~__~~ 1.95 2.0 t.0 491.4;3 2.6 1.2 494752.3 10 1 49 1.95 443 1.75 2.66 2,,0 t.O 492.08 2.5 1.2 491.74 2.7 1.2 49 466 0 0 242.08 0 0 241.74 -0.2 -0..1 24 Base Period (.Jc,n.1982) Val ua ($/MM3tU)-'--':',----- TABLE 0.20:SUf.M\RY OF COAL OPPORTUNITY VALUES >==.~ ~WSc6{'lar fo -elF Japan ..F<BBeluga -Nenana BatteI I eSase Per lad C IF IT Ice Mad I umScei1ar fa -elF ~~~ -FCBSel uga ..Nenana Base Case High ScenarIo - e IF Japan "'"FCB Beluga ..Nenana Sensitivity Ca!!. \.%>datedBase , Per lod elF Fr Ice Moolum Scenario ..C IF Japan ..FeeSel uga -FCB Nenana low Scenar 10 ..C IF Japan ..FCB Bel Ug~ ..F<BNenana High Scenario ..C IF Japan "FCB Beluga -FCB Nena,lla I BeYOnd 2010,i'he OGP analysJs has USed zero real escalation Inallcasas. Hlg.h. 25% Fuel PricoScanarlo 25% 6.50 6.50 6.50 3.00 3.00 3.00 1.4:5 1.43 4431.75 1.75 1.75 0 2.0 4-002.0 2.0 0 2..5 5.002.0 2.0 0 Z.6 5.001.2 42 111 2.3 4.5Q.1 1-1 1.9 Probabf I ity of oCcurrence Base period J~nuary 1982 prices (1982Sj'M\1Btu) TABJ"Eo.21:SLMMARY Of FLf.L FRICES LGED IN THE OGP5PRO~B IL ITY TREE ANAl"YS I 5 fuel OJ I Coal -Bel vga -Nenana Real asca~atfon rates per ""'ear(percent) FUe!011 ...1982 2000 ...2000 2040 Natural Gels -1982 2000 ...2000 2040 Bel uga Coal ...1982 -2000 -2000 -2040 Nenana Coal -1982 ""2 OOU -2000 -2040 Mediuni Low High MW GWh MW GWh MW GWh- 1900 892 4,456 802 3~999 1,098 5,703 2000 1,084 5,469 921 4,641 1,439 7,457 2010 1,531 7,191 1,245 6,303 2,165 11,435 1~p.~eS()ftt·\tk!~"t~of System Costs $:x 1(j~ 8,238 1,176 7,0li2 5,025 3,943 EstImated 1993- 2011-2051 2051 491 3853,119 1993- 2010 2010 630MW Gr 600 MW Wat3na 600 M«Dav II Canyon 1ooM¥i GT Components 600 MW Coal-8el uga 200 M~Coi.'ll-Nenana TABLE 0.22;rcONa.4IC A~L'1S!S _____..!~IS ITNA_rR0JECT.,~.BA..;?E P~ TABLE 0.23:SlMAARY CF'LO\D rffiEDASTS_.....--.....:U:;;:;S;::ED:-..;..FOR;::..:...·..:;.:SE:::.,NS ITIVITY ANAL YSI S, 10 A C Noll Susltna Susttna Naf Econcmtc Benefit ofSusltnat Plan Plan- 228 1;612 109 (513) 2,617 1,176 Ne1- Econom ie Benefit 6,650 1993 ... 2051 4,238 5,380 6,6cB 3,768 Estlli.ated 2011 ...2051 404 360 70G 564 2010 1982 Pr~sentWorth of Syst!!!l Costs ($x 106 ) ~t 6:onQritc Benefit 4,176 2,640 1993- 2010 3,867 lABLE 0.25:DISCOUNT RATE SENSITIVITY ANALYSIS 1982 Present Worth of System Costs tSx1 06 ) TABLE 0.24:LOAD FORECAST SENS IT tv ITY ANALYS I ~ Comeonents 400MW Coal-8'i~~uga 200MW Coal-Nenana 560 fwtiGT 6SOMW Watana (1995) 600 MW 1)),,11 Canyon (2004) 000 MW Coal-Bel uga 200MW Coal-i"enana '100 t-tf GT 430MWPr-G-1993 600MW Watana (1993) 600 MW De"II Can ycm n 997) 350·"'"GT 430 MW Pre-1993 ID Susltna KZ with lo w Forecast Scsltna .1.2 with High Forecast rbn-Susltna J, ..,lfh HlghFor~a$f 1 Fran 1993 to 2040 Plan Non-Susltna with L,w Forecast Real Discount Rate 1993-Estimated 1993- Plan 10 {Percent)2010 2010 2011-2051 2051-- Non-Sustfna Q1 2 3,701 465 7,766 11,167 SusJtna Q2 2 3,156 323 5,394 8,550 N:m-5usl1na A 3 3,213 491 5,025 8,328 Sus~tna C 3 3,119 385 3,943 7,052 Non-Sus itna 51 4 2,791 517 3,444 6,235 5usitna 52 4 3,000 457 3,046 6,126 Non-Susftna PI 5 2,468 550 2,478 4,·.~6 Sl~~ftna P2 5 3,032 539 2,426 5t 459 TABLE 0.26:CAPITAL COST SENSITIVITY ANALYS!S 1,968 Nat E'concmlc Benefits 1,1767,062 7,0629,030 Costs of Costs of l'bn-Susl ina Susltna f1~n Plan 1982 Present Worth of System Costs ($x 106 ) Net 1993-E'conanle 2051 Benef it 1993-Estimated 2010 ~2011-2051 1962 Present Worth of System Costs....-,'._,....... 10 G 3,46il 528 5.39El 8,858 C 1 3,119 385 3,943 7,062 1,.976 G 3,084 472 4,831 7,915 C1 3,119 385 3,943 7,062 853 A 3,213 491 5,025 8,238 X2 2,710 336 3,441 6,151 2,087 A 3,213 491 5,025 8,236 Y2 3,529 434 4,44's 7,974 264 10 43 Base ~rtod Sel uga CoalPr lee (t982 $/MfoBtu)""'-'"!:':os: 2.08 TABLE 0.27:SJ:~1'1'1 '111"'(AN\L YS IS ...UPQ\TEO eASE PLAN (JANU\RY t 982 )COAL,f2'"':.!9!~·_.........._ Plan JlbI"l-Susl1rtaCaPI ta! Costs Up 20 Percent fbl"l-Susltna Susrtna t-Q1"I-8usl tnaCapl tal Costs Down 10 Percent Non-Suslina Susltna SUsl tnaC2lpitai Costs Less Conti ngency 1 AnadJustmant cal culatlon ~s made regard Il1g the +capital costs of the 3GT~its added In 2007-201 o since the dl ffarence was less than $1 Ox 10 ~Beyond 2010,thl.s effe.c·t WClS not tocl uded. Non-Sus ftoil Susltna SuslmaCapttat Costs J:Lus Doubled Contingency Non-Sus I tna Susltnl1 Base case sensIti"Ity CUp<iated)Case TABLE 0028:SENSITIVITY ANALYSIS -REAL COST ESCALATtoN 7f5l. 7,S99 7,062 7,157 5,585 1,572 a,crZ3 6,737 1,286 9,811 9"029 5,660 6,738 (1,078) 10,367 7,388 2,979 4,861 Estimated 1993...~t 2011-2051 2051 Benefit-- 4,319 3,060 6,161 5,148 4,881 3,74~ 6,5<'4 4,121 3,427 3,736 1993 2010 2010 ~------- 1982 Pre!$nt Worth gf SY$tem Costs ($X 30 )_..----.c ........... 1993-Estimated 1993-l'et 2010 20iO 2011-20512051 Benef Ii' 1982 Present Worth nf SY$tem Costs ($X lOb) 3,142 4T1 2,98.8 366 2,838 422 2,525 299 3,650 602 3,881 503 2,233 335 3,004365 4,063 643 3,267 403 10 B 330 MW Chfi.kachamne 2,0:58 475 400 M;lCoa 1-i3E)1 uga 200 MW Coal-Nenana 440 t-l4 GT C 600 MW Watana 3,119 385 600 f.wOav II (Jar\ya,O lao MW GT Htgh Escalation I n Fuel Prices ESCalatIon 10 Capital 1 Costs and O~~(Battelle) •N:>n-Susltna ••Susltna Zero-Esca!atlon In Cap ltaland O&M Costs Plan •N::>n-Su5Itoe •Susltna lCapitCllI ar;d 'O&M cc:sts assumed 10 ~alate at 1.~percent 1982 to 201 0 TABl£o.29:SENSITIVITY AtftLYSIS ...NON-SUSIT~ PLAN WJlH CHA~CHAt.flA •thnaSusitna •Susltna •tbn-Susttna •Susitna Plan •flbn-Sus I tna wi ttl Chakachmma (hub Ie Esc aIat Ion gap ita I and O&M Costs •~n-Su$ttna •Susttna Zaro-Esca I atton In Fuel.Prtces-. •Susttna TABLE 0.710:SENSJtIVITYA~L'YSIS SUS lTNA PROJECT DEL"Y C 7,062 1,176 C3 7,105 "133 OJ 7,165 1"134 Susl1na Base Case One-ye8r delay for Watana (994) Q'le-YEtur de\lay for Dev II CaryOn (2003) Ona-year dEtlay for Wati!nn·and Dav II Canyon (1994,2(03) 10 C5 $x 106 1982 Present Worth -2!....§~+em Costs 7,230 S x 106 Net Economic Ben..ef),'t 1,138 TABLE 0.31:SLMMARYOf SENS IT IVITY A~tYS IS INlEXEs OF NET ECONOMIC BENEFITS 1 High fue!~~al atroncase provJdes net benefits equal to 253 percent of the base val ua,2.53 x $1,176,or $2:>97!i 2 LoW ruel·escalation caSEl ptovtdas minus 92 percent of the base caseoet benefits,....92 X $1,176,or ....$1,082. 71 96 96 97 100 23 178 168 73 137 19 67 t09 134 -44 9 223 167 Index Values Susl1na capl tal Cost -HIgh -low F'~~I Escalation ..HIgh -Low 01 SC:OWlt Pates -Hlgh.-High (5%) -HIgh -(4%) -Low (2%) Updatec.lBaseCoal Pr fee -. Planned ~lay In Susitna ?roJ~t ...One-year del a.y,Wa.t-~nct -Q'la-year delaya.WClltana and Davil Canyon -Tw,,-year del ay<,"hJt~na and Dav 11 C~n yon BASE CASE ($1,176 MILLION) Chai<acharnna (1 nc!udad tn N:>n-susitna Phsn) Non-Susltna (Thermal) Capital Costs ...High -lDw Load Forecast -HIgh -Low Cap I ta I al'i~O&M Cost Escalation -High ..Intermediate (Battelle) ..Low ~i·\;i " 1t I I Currentl,v Available Currentl.V Available . Currenth Availahle Currently Avail~hle Currently Available 1985-1990 1990-1995 Currently Available Currently Available Currentl.v Avai lable 1995-1990 1990-1995 Currentl.V Available Currentl.v Available Ava Uabilit,V for Commercial Orrler Currently Available Typical Application Baseload 1985-1990 Base load/Cyc ling 1985-1990 Base 10adlCycli ng 1985-1990 Base load .1990-1995 Baseload ~aseload/Cycling Baseload/Cyc ling 8aseload Baseload/Cycling Base load/eye 11n9 Base load 8ase load /C.vc ling Baseload/C.ycl1n9 Baseloacl Baseload /Cyc 11 ng Generation Techno 109Y _ Direct-Fired Steam-Electric Baseload(ii) Dirac t"Fired Steam-Electric Baseload(a) Direct-Fired Steam-Electric Base load 1990 ...2000 Combined Cycle Base 1oadlC.Vc Hn~1990-2000 Fuel-Cell -Combined-Cycle Baseload 1990-?OO(r Direct"fired Steil:m-Ele'~trlc 8aseload Direct-Fired Steam-Electric Baseload 1985-1990 CQIIlbined Cycle ..Baselooo/C.vcl1n9 1985-1990 Fuel ..Cell -Combined-Cyc~e Baseload 1990-1995 Direct-fired Steam..ElectrlcBaseload Direct-fired Steam-Electric CombinedCyc1e Fuel-.Cell Station Fuel-Cell -Combined-Cycle Combustion Turbine Direct-fired Steam-Electric Combined Cycle fuel-Ce11 Stations fuel-Cen -Combined-Cycle Combustion Turbine DleselElectric Direct-fired Steam-Electric Combined Cycle Fuel-Cell Station FUel-Cell -Combined-Cycle fuel Conversion Sort &Classify None None f Liquefaction Gasification Refine to distlllate iand residual fractions •Hog · .·CABLE '0;312:.'BATTELLE :AIi.TERNATI'lE"srOOY Principal Sources for Ral1belt Gasification Beluga Field.Cook Inlet Crush Nenana Field.Healy Cook Inlet North Slope Kenai Anchorage Nenana Fairbanks Cook Inlet North Slope Kenai Peninsula lower Susitna Valley Natural Gas Resource Base Peat Wood Waste Petroleum Hun lcipa 1 Refuse Anchorage Fairbanks Coal , .¥~'~>;~'~~~~"''''''"''.''=_.._=r:t'i'WCrSo:~....5'ttt ~.~"""'1&IiEliSi diUaiIIt.........&Milif t •_,....... Currentl,Y Available 1985-1990 1995-2000 1985 ..1990 1985-1990 1990-2,000 Currp.otly Available TyP1ca.l Ava il ahi lit.\'for Appl1ca~lt!."_____Comnp.rctalOrder 8aseload Fuel Saver' fuel Sayer Fuel Saver fup.l Saver fuel Saver Currel1tl.v Available 8iiselolld/Cycl1ng .turrann.v AvaUahle Bltseload/Cyclt"9 Currentl,V AVi)HaJ>lp (bl Currentl.V Available foel Saver CurrentlY Available Generation Technology. Solar Photovoltaie Solar Thentlal light Water Reaetors large Wind Energy SYstems Sma 11 Wind Energy Systems Tidal Electric Tidal Electric w/Retime C()nvenU""alHydr'ool ectric Small-Scale Hydroelectric MicrOhydroelectr1c "otory Rock -Steam-El.~trh;Base 1oad Hydrothermal-Stealll-Electric Base load TABLE 0.32 (Contd) fnel ConversiQ!) Enrichme.tt & Fabrication Throughout Region Pr1ilCipal Sources for RaHbelt Import Isabell Pass Offshore Coastal Cook Inlet kenai Mountains Alaska Range . Wrange 11 ~u"tai"s Ch 19o11t Mo.."ta ins .. Resource Base. Uranium Wind Solar (a)Supplementa 1 firing (w/coall \«Juld be required to slIPPort.baseload operation due to eye Heal fuel supply.(b)May .bebaseload/cycling or fuel saver depending upon reservoir capacity. Tidal Power Hydroelectric Geothermal • .. TABLE D.34:.'.BATTELLE ALTERNATIVES STUDY la}Configuration in parentheses used in analysis of RailbeH electric energy plus taken from earlier estimates (Alaska Power Authority 1980) (b)•.'"en rate of 12,000 Btu/kWh W/lS used in analysis of Railbelt electric energyplans~13,000.Btu/k\llt is.probably more representative of partial load operation characteristic of peaking duty. (c)An earlier estimate of 8500 BtU/kWh was used in the analysis of Rllllbelt electric energy plans. (d)Configuration selected in preliminary feasibility study (Elechtel Civil and Minerals 1981) (e)Configuration selected in Railbelt altern.litives study (Ebasco 1982b) CapaUjY Heat Rate (MW).,rntu/kWh) 200 10,000 200 10.000 220 9,29() 10 13,800(b) 200 8,2ooft )1.1 3.3 15 15 Variable O&rM (mills/kWh) 0.6 0.6 3.5 140 140 Fixed O&M ($!kW/'yr) 16.10 16.70 14~80 48 7.30 42 50 9 4 4 5 5 5 7 5 44 5 44 44 3~70 730 1050 890 4470 4820. 2840 2490 3190 3860 2100 4669 168 2263 5850 5480 7240 2980 .3320 Capital Cost (S/k~ 2090 2150 347 8 395 8S 430 37 1570 1923 3459 3334 220 36 94 94 94 94 94 94 94 94' 94 94 N/A "/A Average An"ual Availability Energy (%)...1§!!hL 87 87 85 89 85 91 83 94 .- 9.,~OO 5,700 14.000 14,000 25 50 20 680 340 600 63 100 20(11) 100(80) a 7 25. . Natl.Gas Fuel cell Stations Alternative. COil Steam-Electric (Se1uga) Col 1 Steam-t:ler;tric (Nenana) ca.l Gasifier-COIIbined Cyere Natl.Gas Combustion Turbines Nat1.Gas COIIIbined Cyele Natl.&1$Fuel cell CClIlb.eye.200 Bradley Lake Hydroelectr-ic 90 Chakac:hM'l11 Hydroelec.(330 fII)(d}330 ChaJcachalll'1a Hydroe lee.{4aO ...}(e)480 Upper Susitna (Wauna 1) Upper Susftnl.(Watin!II) Upper Sus.itna (Devil Cinyon) Snow Electric leeetn.ii.Ydroeltctric Strandline Lake Hydro'elec. Browne Hydroelectric Allison Hydroelectic Grant Lake Hydr~lectr1c Isabell Pass WirKl Firm Refuse-Derived Fuel Steam Electric (Anchorage) Refuse-Der1vedFuel Steam Electric (Fairbank$) /T' TABLE D..3.t:Surrrnary of Electrical Energy Alternatives Included as Future Additions in Electric Energy Plans (a)Plan 1:Base Case A.Without Upper Susitna B.With Upper Susitna Plan 2;High conservation and use ofrene\'Jables A.Without Upper Susitna B.With Upper Susitna Plan 3;Increase Use of Coal Plan 4:Increase Use of Na~ura1 gas El ectri c Energ:{..Plan (a) 1 IB 2A 28 .34 Xxx X X X X X X X X X X X x x x X X X x X X X X X X X X X x X x X X X x x X X x x x X X X X X CYCLING ALTERNATIVES Building Conservation BASE LOAD ALTERNAT IVES Coal Steam Electric Refuse-Derived Fuel Steam Electric Coal Gasifier-Combined-Cycle Natural Gas -Fuel Cell-Stations Natural Gas -Combined-Cycle Natural GaS -Combustion Turbine Natural Gas"Fuel-Cell Combined-Cycle Bradley Lake Hydroelectric Grant Lake Hydroelectric i:,ake Chakachamna Hydroel ectric Upper Susitna Hydroelectric A11;son Hydroe 1ectri c Browne Hydroelectric Keetna Hyd.roelectric Snow Hydroe leetr ic Strandline Lake Hydroelectric FUEL·SAVER'INTERMITTENT)ALTERNATIVES Large Wi nd Energy Conversion System ELECTRlq£fiERGY$UBSTITUTES P.assive So Jar Space Heat;ng Active Solar Hot Water Heating Wood-Fired Space Heating ELECTRIC ENERGY CONSERVATION 4J.2 ..6 371.1 139.0 922~7 90.8 148,,0 160.3 138.5 380.8 438.6 458 ..8 393 ..9 34.5 318.6 348.2 330.9 321.8 564.9 872 ..3 243.3 3156.9 2244.2 3000 ..0 1982 Purchasing Power 9049.1 Actual 211.6 368.9 427.7 395.4 1163.0 1432.3 1604.7 1473.5 137.8 1214 ..9 784 p 7 754.9 294.6 1834.2 4806.7 403.7 472.7 479.7 499.5 939.3 1550.4 462.4 II II II " 11 " " II " II " Revenue Bonds " Revenue Bonds State Appropriation II $]'1il1ion Interest Rate 10% Inflation Rate 7% Total pevi1 Canyon BOnds 1994 5 6 7 8 9 2000 1 2 TABLEiD.3'5:FINAL~CING REQ'lJIREMENTS ....$MILLION FOR $3 .0 BILLION STATE APPROPRIATION Total Watana Bonds '1'0 tal Sus i tn a Bon ds 1990 1 2 3 Total State Appropriation 1985 86 878a 89 90 91 ~'--.-:I I p.a6 rm(~1·TABLE 0.0 0 ..0 0.0 0.0 0.0 0.,0 0 ..0 0 ..0 Z19.3 Zl1.2 0.0 0.0 0.0 0.0 0.0 0.0 000 0.0 26.q 29",3-----------~------------_._._---._-___....._____.___.____......_.__~·__'il.._:___...,..____________,__.__._____.._ 0.0 0.0 0.0 0 ..0 0.0 0.0 0.0 0 ..0 192.1t 241 ..Q 0 ..0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 5.6 0 ..0 0.0 o.a 0.0 0.0 0.0 0.0 0.0 o.a 9.8 0.0 0.0 0 ..0 0 ..0 DeO 0.0 0.0 0.0 15lt.0 -103.1t.....___._____._,__,__,____.___'__._______.___.__.___.___.____.__•~.__..________._.___.-u_,__________.___._ 0.0 0 ..0 0.0 0.0 0.0 (i.0 0 ..0 0.0 3805 5443 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 38.5 5~.l lt03.1 472.7 419.1 499 ..5 938.3 1550.1)lt62.4 0.0 0 ..0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 784.7 754.9 29\.6 211.6 1l.0 0.0 0.0 0.(1 0.0 '0.0 OaO 0.0 98.0 11.1 --~~~-~-~~-~-----~--~----.-.-.-'-_.-.-.----------------------------------------_.------- 40).1 \12.1 419.7 ".99 ..5 Q~8.3 lS~iO ....I Zltl.1 1')4.9 431.1 283.1 403.7 ~12.1 419.7 499.5 938.~.l550 •.t,.1247.1 154.9 333.1 25Q.2 0.0 0.0 0.0 0.0 0.0 0 ..0 0.0 0.0 90.0 11 ..1 0 ..0 0.(1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 6.8 --~------------------------------------------------~--------~-------------------0 ..0 0.0 0 ..0 D..a 0.0 0.0 0 ..0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 •0.0 0.0 0.0 0.0 0.0 0 ..0 C).O 0.0 0.0 0 ..0 0.0 0.0 0.0 0..,0 0.0 0.0 0.0 0.0 0.0 0 ..0 0 ..0 0.0 0.0 0.0 56.·~61",6 0.0 0.0 0.0 e.o 0 ..0 0.0 0.0 0.0 Itl.'5 5~..1 0.0 0.0 0 ..0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 403.?876.4 13'56.1 1855.6 2794.0 4344.3·5591.4 6346.3 6619",4 6931h6=========:===:::======:=:======~==~=======:z====~=~===s==:=::==:~~Z=2=:=:~%=%%s= 403,,1 '376."1356.1 1855.6 ~194.0 ';340\.3 5591.4 6346.3 6117 .."10.154.3 =~========~==::====~==:======='.:=~:~==~~=z:========:====~::sz:====zs===~=s:=z~=.~ 403.7 811;"'"1356.1 1855.6 279\,,0 "344.3 "~O6.1 ~806.1 ~806.1 4806 ..7 0.0 0.0 0.0 o.~0 ..0 0.0 0.0 0.0 38 ..5 92.8 0.0 0.0 0.0 O~O 0.0 0,,0 0.0 0.0 98 ..0 115.1 0.0 0.0 0.0 0.0 0.0 0.0 184.7 1539.5 183".2 Z039.0 0.0 0.0 0.0 0.0 0.0 0.0 ~12.6 371.0.135.3 90.8 0.0 0.0 0.0 0.0 0.0 0.0 It 12.6 183.6 918 ..9 1009.1 0.00 1).00 0.00 0.00 0.00 0.00 0 ..00 0.00 ...25 1.25 1$3.BILLION (1982 DOLLAR-SI STATE APPROPR IA.TI.ON SCENARIO 7%INFLATIOl'j AND 10%INTEREST TOTAL SOURCES OF FU~OS LESS CAPITAL eXPENOITUf't:LESS WORCAP AND FUNDSlESSOE6T~EP~Y"ENTS ~ASHSURPlUSCDEFJ~lT. SHORTTERH Of:::8T CASH Kl:COVEREO -----BAtANCE SH([T---------- ~fiSERVE AND CONT.FUNDaTHERWORKINGCAPITAL CASH SURPLUS RETAINED CUM.CAPITAL EXPENDITURE CAPITAL EKPLOYEO STATE CONTRIbUTION RETAtN~D EARNINGSDEBTOUTSTANDING-SHORT TfRn DEeT OUTSTANOING-LONG TERM ANNUAL DE6T ORAWWOO~~'1962 CUM.DEBT DRAWWOOWN $1~8ZilEBTSERVICECOVeR J 1985 1986 19!J1 1988 1989 1990 1991 1992 1993 1994 CASH FLOW SUMMARY===i SHllL1ONI=~== 73 ENERGY GWH 0 0 0 0 ()0 0 0 3387 3387 521 REAL PRICE-~ILlS !hOO 0.00 0.00 0.00 0.00 0.00 0.00 0.00 29.14 3".38 4b6 INFlATI0K IHOEX 126.72 135.59 145.08 L55.24 166.10 111.73 190.11 203 ....6 217.13 232.97 S20 PRIC€-'lIlLS 0.00 O~OO 0.00 OltOO 0.00 0.00 0.00 0.00 6'h16 80.08 46~ 141 249 ltV. !>'"J --"'--INCQ~E----......-----------5l~~Ev£tWE 110 LESS OP(RATl"G COSTS 511 ~PERATING INCOME ZI~400 INTEREST EARNEO ON FUNDS 'iiI)lF~S INTEREST ON ".HORTTERM DEBT 391 LESS JtHEREST ON LONG TER"'OEBT ~41 HET £AKHINGS FR~K OPERS -----(,ASHSOURtr:ANO U5(---- ~411 CASHiNCOMS t=ROM CPERS 44b SrATf CONTRIOUTIDN lit 1 lONG TFRM nnnDRA~OOWNS ~.ItH •101 OlH•.J\P Ot ~H onAWOO~NS 461 462 S55 554 542 543 519 2l~ 111 454 370 J2~ 1,46 260 *r,;*********:"'l*****.**************#*************~u::=:t*~*~lt.**~***:(:***(c**t):****:(,******.*********.*.*************.*******************••0DATAIOKWIlTANA-DC CON LINE 1993-2002)....$3.1)8'"($l98..ll $~41'E FUNOS-INF LA TI ON n:-(NTEREST 10:t....CAPCOST IS.117 8N Z]-FEB-82 .*******~*.***.*.*••****.**.*~********.*.********(lI.**(l******••••****•••*******••***••••*•••••••****$**.***•••****$••*.*•••***•• S:'eet 1 of 3 ~~I~=-------~ l I . Ii 88.220•., 36.3 891..5 200~ 281.~ 1296.7 108.5 5605 50.49 458.29 2iH.31 0.0 :3163.0 1.25 135.4 0.0 135.~ 221.8171.6 0.0 146fJ8 ..3 zz:.:Itx==;: 15103.7 3:11::O:Z==== "~06.7 1023.8 405.4 8867 ..1 281.40.0 0.0 42.8--_.-....._._... 320\.3 99.2 0\2.8 ~6.e ~. " 217.2.0.0 0.0 2~!I'" 301.9 90 ..9 24.1 ~ZCl6 2.11.2 2003 1188.1t19.1 34.1 895.1 1281.8 99 ..4 541 oft 55.54 428.31 237.89 Ilt3.7 -9.1 134.6 208.8 153.8 OliO 14599.1 =z:sz ••= llt961.7 ::112:==:1:= 4806.7 811.8 362.6 8914.6 0.0 3163.0 1.25 TABLe D.36 Iluml 239.0 50".8 362".3 126 ..0 1~.5 239.0 0.0 131.8 128.0 2002 5223 58.55 400.29 234.36 0.0 0.0 0.0 PH.3 146.f1 0.0 14508.2 ::'=-:Z::':Jt% lit8~6.1 =zzwzaz= "806 ..1 735.2 346.9 8951.1 3"'.-\ 3163.0 1.25 ----....-...- 1224.0 91.1--------1132.9 H.4 21.9 883.4 2001 301.4 51t.l 151,6.5 15l1.9 12.) 13.2 6~J.7 0.0 1473.5 12.3 ?>381 2~.79314.10 89 ..00 -6.8 6.8 000 11 J ..1 96.2 0 ..0 14145.9=z:===::z== 14355.8==z=z:=z= 4806.7 496.2 219 ..0 8833.8 393.q 3128.6 1.25 2~7.3 10."20.0 171.0----"--"1---60.1 -2.3 2 ..3 0.0 2000 296.5 49.6 2~6.9 9.5 18.7 116.2 59.5, "t806.7 435.5 199.8 1313.5 459.0 2134." 1025 :1381 25.04.349.62 87.5~ -------~-------- 59.5" G.O 160~..7 10.4--.---'--'-l614.1 1654.5 10.4 lZ.0 --."----- 104.1 93.4 0.0 12618.0========12615.6 58.lt 0.0 1'432.3 10.6__.__cs _ 1501.3 1A,19.8 10.6 10.9 292.1 45 ..4 0 ..0 0.0 0.0 95.4 91.1 0.0 101"1630'5====:===11150.6==z=:::=== 4806.1 316.0 167.1 5780.8 438.3 2215.1 1.25 246.6 8.1 17.1 179.3----,--.-- 58.4Sl.S 246.2 ~.o 16.4 1'30.3 261.8 It.!.6 0.03.0 0.0 a1.4 1)9.1 0.0 9483 u 7 1232.1 12iO.5 12.2 9.9 96bO.3 51.5 0.0 1163.0 12.2 480ta"' 3Ue5 116.b 4359.4 380.8 i837.4 1.25 ------,--_.,1.-- ==:======,:; 56 ..6 0.0 3.95." 11.2 56 ..6 245.7 7.3 15.3 l!U.Z 283.6 38.1 463.1 1\42 ...<) 11.l900 0.0 O.l;) 0.0 .10.1 !l4 ..Z 0.0 8273.2 0#1991 1996 1999 CASH FLOW SUMMARY ~.:($MILtJOH.=:== 3381 3361 3387 29.31 21.83 26.39 285 ••0 3US.38 326.15 83.81 8~.91 86.24 8431.~ ==.:>".===,.~= "t80~,.7 2fJ.l 1',It.3 3ZJ6.4 .38.5 14-;6.6 1.25 "'=:;===== ...·1-_-_-...- 55.7 278.3 35.0 243.4 b.7 12.4 182.0 ~5.1 OQlO 427.7 29.3 1996 512 ..8 415.3 29.3a.2 0.0 0.0 0.0 13 4 19 7o0 1830.3 3337 30 11 81 266.73 aZ.IS 7983.~ ..806.7 203.5 1'33.1 2820.0 100.4 1318.0 1.25 ==.====== =======; 55.0 55.0 0.0 368.9 6 ..1 199!.j· 243.1 6.2 11.6 182 0 7 215.2 32.0 432.0 416.4 8.1 7.4 0.0 0.0 0.0 7470.8 67.2 56.6 0.0 7355.0 3367 32 59 2"'9 28 31 25 ~806.1 147.8 123.9 2400.5 148.0 1157.7 1.25 _."'._".__'........_...__._'_..,oc-_.'._._ =======-= ======== $3 BILLiON (1982 DOLLARS)STATE APPROPRIATION SCENARIO~ 7%INFLATION AND 10%INTEREST~.._._--._..----_.-•..._........_._--- ~f CASk SURPLUSfOEFICIT)SHORT TERM DF-BT CASH RECOVERED -----BALANCE 5HrET-----------RE:SCRVI;AND CONT.fUND OTH~RWOR~lNG CAPITAL CASH SU~PLUS RETAINED CUM.CAPlfAL EXPENDITURE CAPITAL EMPL'JYED STATE CONTRIBUTION RETAINED EARNINGS ~EaTOUTSTANOING-SHORT TERM OEBY OUTSTANDING-LONG TeRM A~NUAl DEBT DRAWWOOWN i1982 tUM.DEBT ORAWWDOWN 11.982 DEBT StRY~CE COVER ENERGY GWU R~Al PRI CE-MlllS U'fl.A TI ON I NOEX PJtICE-MlLl.S -----(NCOKE----------...------ttEVE'''UE LeSS OPERATING COSTS OPeRATING It.COHEADOIHTERESTEA~NEn ON fUNDS lESS INTEREST Of\l SHORT TER"DEBT LESS HHEREST ON lONG TeR"DEBT NET EARNINGS FRQK OPERS ---..-CASH SOURCEA~D USE----CASH INCOME FROHUPCRSSTATECONTR18UTfON LONG TERM nEBT DRAWOOW~S WORCAP DEBT DRAWDOWNS TOTAL SOURCt:S OF fUNDS y 5.t11~ 5"'8 516 170 ~4a 44b 1.43 7.~3 ~17 21 .. 55? 39l 73 521 4bb :i20 22S 311 454 310 465 461 462 555 5S~ 542 543 519 l'tl 249 444 120 LESS CAPITAL EXPENDITURE 44~LESS WORCAP ANOFUNDS 260 LESS DE'T ~[PAYMENTS **:~***~.**********~*~********.*********~:)***~************************************.****~*****.*.*.********.**•••*•••**••••**.**.DATA10K WAlANA-DC·«ON l!NE 1(9)-2002)-'3.03~U11962.STATE fUNOS-1 NFLATION It-I NTEREST 10~-CAPCOST i5.1118H .23-FE6-8.2******.ti:**:e<***************************lQl***JC:****lQl********(I:****:QI********:)lQl****.**.l!ll*••••*.****:t:Gl*••**••*••••••*.*.*.*1)••••••**••*. t Shf.!et2 of3 II ,·1 .lc ~~~~~~~'.·.i'..•\.·'.',."]I,.I,..··••·,.. *~*~::::********,::~****_*******"t***"'~***t.::***:c:****************..,:*(:::.r****:O:*****:t,t***********:tr*\l*~**....****:tr**.**********O.~*••**.***.*.*••DATAIOI<WATANA-OC (ON LINE.1993-lIl02J-'3.tlaNlU9B.2J.STATF.FUNOS"'INFlATION 7~""HHEREST 10~-CAPCOSTS5.H18N ...l3-FE8-8Z*******.~~**:lr*************::)********************************~***********O*************lf)*:Iil!*.O*****O*••*.*lOr**.*•••:;II*:Q::lj(oo ••••••••••• Wi IM·5"..~ 412.4 7"0 ..6 12013.6 963.5 0.0 963.5 18656.4 2202.0 18180.1 16115.9 819.1 880.9 410·h6 "lO~.6-tB06 ..7 90~''hO 819.7 -.,---_...... 500.6319.2 0.0 16116 ..0 ==:It:2:%:%:II)I: 16935.7 %ZS,~Z'=.= 4806.7 3141 ..1 819 ..1 8166.1 3163.0 3163.C 0.00 ---.-....~-- 3"5.00.0 0.0 ""..9 16.1 0.0 16 ..7 3~5.0 500.6 319.l 000 16116",0 389.9 211.9 4".9tl0.~ 0.0 3163 ..0 1.25 Z==:Z:==::'J: 16935 ..7 =:az='J::a= "806.7 3Ul.1819.7 1U68.1 --'---'_"'- 14"2.9 238 .... --'-;,-'-----1204.5 45.977.5 821.9 TABLED,,3S 335 ..0 1204.2 42.D 13.4 831.9 335.0 0.0 0.0 41.2 1422.6 lUJ.,4 ),\.9 .0 3".9 316.1 1~9.1'tl.Z 100.4 "58"!1316.2 0.0 A5898.1=::::%:::aa= 16612.9 Z:::::Z::Z:f::tz: "806.1' 28U'.8 774.88Z18.6 0.0 3163.0 1 •.25 -----.._-- 182.9 37.7 9l.3 4806.7 2512.7 'TJhl 3318.Q 0.0 3163.0 1~Z5 51.6 0.0 51.6 363.6 325.80.0 0.037.7 1"04.1ZOO.I =:;=:::='=:r 420.3 313." 0.0 15696.4="':;=======16432.1 _._----',-- 120~.0 38.5 69.6 84".0_._._----- 325.8 -,...------ -------~---t ~~..~~~j 369.5 167.6 52..0 63.0 311.5 0.0 0.0 52.0 1385 ..3 183 ..-t 61.0 0.0 61.0 385.1 310.9 0.0 15515.5====-==.:::;=16ZU.~ ========"eot...7 2238 .•56Q6.0 8~10.Z 0.0 3163.0 1.25 1202.0 35.3 64.'t 855.3-_......_._-- 311'.5 8hO 0.0 81.0 ,0.0 3163.0 1..25 355.9 153.645.9 15.4 310.0 0.0 0.0 't5 •.9 310.0 1368.'t 168.0-..,.:-....-._;- Il00.":lZ.3 59.8 662.9 352.8 291.2 0.0 1531,7 ..9 =-=:==,'":::= 159'~1.9 =.=z::==== ~e06.1 1961.9 64~.0 8553.2 303.1 303.1Q.O 0.0 45.8 349.0 140.7 45.8 68.6 93.9 0.0 93 ..9 323.3 274.9 0.0 1'5P~4.3========15792 .~ ==~',,::,::,=== 4806.7 1158.9 598.2 0628 ..6 0 ..0 3163.0 1.25 ....__.....-.._.- --'----_.-. 135·2 •.; 153.9---_._--- 119fh 5 29 ..6 55.2 869.7 0.0 3163 ..0 1.25 296.9O.t) 0.0 59 ..3 480b.1 1549.6 5S2.It 8691.2 296.9 105.6 0.0 105.6 296.2 256.2 0.0 15053.6 35b.2. 128.9 59.3 '>2.3 lS605.9======::_._.-'--'_._--_._--_._- 1136.1 141.0-----.---1195.0 27c>1 4.q.~ 876.0 ....__·0_._.__ 0\806.1 1358.3 493.1 8759.5 0.0 3163 ..0 1.25 29hZ 0.0 0.0 51.3 116."0.0 116.4 1321.4 129 •.7 342.5 l1fhl 51.35b.7 ---~----------~- 11'n.2 24.9 44.2 861.6.---:-----2'n.2 211.4 221 •.7 0.0 14924.6--_..__......_--'--.------15H7.7 lO05 ZOOb 2001 zooa 2009 2010 2011 2012 2013 TOTAL CASH Ftow SUMMARY===(SMllLIIJNt==== 60'12 b141 6150 6~12 65"0\b616 663fJ 6660 6682 100\826 ·43.1)2 40.97 lEi.Oft 34.79 32.53 30.1,5 28.7"27 ..13 25.63 0.004'10 •.37 524.69 ')61.42 600.12 61+2.17 687 ..17 135.91 187.0\2 042.5 ..0.00 ?l "-89 21'''.98 l1h79 208.98 20<).12 109.4ti Zl1.5"7.13 ..62 215.95 0.00 1309.0 Ita.1t 286.1 12~.3 0 ..0 126.) 286 ..1 0 ..0 Q.O 36.4 ,322.5 1011.2 36.It 51.5 1190.6 22.8 40.5 886.6 ItB06.7 titH.S 441.3 8816.2 1).0 3163.0 Ie>25 l4'.7193.2 0.0 14306.5 15246.3 ======::=. =.:'':===== -.----'--- $3 BILLION (1982 DOLLARS)STATE APPROPRIATION SCENARiO 7%INFLATION AND 1()O~INTEREST . 73 r:UERCY GWH -5.H 'H:AL Prr.JCE-M,U.S 4b~I~FLATJO~INQEX .,~O P~ICF"MILLS -----JNCOMF----....------------516 ~EVENlJC 170 LESS OPEflAT ING COS TS 517 OPERATING.INCOME 114 AD9 InTEREST EARNED ON FUNOS 550 t.ESS.INTCREST ON SHORT TERM DFOT 391 tess lNTEREST ON LONG TERHDE8T 548 ~~T EARNINGS FROM IJPERS -----C.~H SOURCE AND USE---- j4i3tASlf H'COH[FROM OPC:RS 446 5 T ATECONTR IBUTliJN 14)LONG YERM c.c:aT OR.AWDOWNS243WORCAPDEBTDRAWOOHNS 541 TOTAL SOuRCES lJFFUNDS 320 LESS CAPITAL EXPENDITURE 4~1 lFSSWORCAP 4NOfUNOS 2 611 lESS DE tiTIU::PAYHENT S l4!~ASH SURPlUS(OEFICITJ 249 SHORT TERM 0:8T 444 CASH Rl:COVEREO ....----8AlANCE SHtfT---------- 22~qeSERVE AND CONT.FUND 371 GTHt:R WOIlKING CAPITAL 454 CASH SURP1USRETAINEO 370 CU ....CAPITAL EXPENDITURE 465 CAPITAL EMPlOYEO 4bl STATE CONTRJ~UTI!J~ 4~.2 RETA!NED EARN I NGS55';DEBT OUTSTANiHNG-SHO'H TERf~ 554 Oti3T OUTSTMIQ lNG-tuN';;TER'" 542 ANNLAL orOT ORAWWOOWN Sl~6Z ".i4J r::UH.OEDT DRAWWOOWN n982 519 OE8T SeRVICE COVER Sheet 3 of 3 .!t. ~l_'~_·""'~~~ft~_~~·.,--- I l Il' t I ! I~r I I ~o ..Ju.. tomm m 0 0" 2! U) rr:cw Ol )0- U) !!! «i U) !!! (,()mm o :::.'. : oo 2 000 000 ~fa to ! (SH\f1100.:10 SNOI11IW)M01.:1 HS\fO 3AIJ.'ll1n~nO ooo 10 -IX· oo to1<\ \ (7) «o ILl>i= .r:f:.. o ...I U. d(S?:I'nl0Q .;10 $NOI11IW)lA01='HS\f:>iVnNNV Wc:::0 0 0 0 0 0 0 ::;)0 0 0 0 0 0 0 0 (!)U)....lD \()~010N 0 I.L. ooo 'It '\. ~o ...J ....u" Z:r: WCI)cn~«0.:25°« ijj ....l :i ><t o.::>~Z 0 ZN Z «COoen >-c .. ;ZZ>-««a:: u « ..j1JJ::>_>Z>-« IJJ ti ..., O...J :::> .~::> (,) Q) en en (/) 0:: -:t U.l ,..)0- en en rooo(IJ o o oo to oo ... ooo ooNooII) oo to (S~V110(j .:fO Stl!OIl11~)~Ol.i HSWO 1VnNNV (S~V1100 .::10 SN01l1IW)M01::1 HSVO JI\IJ.V1nWnO ooo (IJ oo.. f 1 Ir I II " Ir f j f,; I t l.iII 10 ::1 III Q 2CI,=.2'*',I::+-;IE ICAU IN MlL.ES D.S -SERVICE AREAS OF RAILBELT UTILlT.ESFIGURE LOCATION MAP ----JlIWOPOIrD ,.JCV u •. LEGEND "PROPOSED DAM SITES .. J ~......... c.,. eo,,>II.... T...... '---(111_- 1$ ...,.,.. A.........-aMM UnA,....,." Ab*a R....EIIcIric Coop8rcId•• 5B .8....·.,... ~ B GENERATING FACIliTIES (.....on ,.....~lItinwClIIlUit,,... c.~Cydla C....llnT.....(1."...'•• U.a.G••au _ AIIIIut,.., ..................-11I.... A ENERGY SUPPLY (...~.N(!t G.....ation 1910. 1.0....,...,0 It¥...., ,MIl..'*"T U ,.,AII*e 1.Dell ....1&'11IIIIIo ~EMIlY "- ....,I..'.]'TIll u.........01 AIIIb 01 a I fCN~T GENERAT'ON BY TYPES OF FUEL D RELATIVE MIX OF ELECTRICAL GE_""nNG .~.. (a-d eft N"O....atioQ ,..TECHNOLOGY -RAILBELT UTll.ITlES -,.~. ......__•.,__._-,.-=-_F_'_GU_R_E_.·_O._6___.-_1 r &' r - 3010 ..I...----- -'-"l Nctt:OGP-I .........I lJIIWe 0IItpMI.Two V_I...... ...,..,. " ..- ... 7.aao ..... .... t FaGURE D.8 -ENERGY PRICING COMPARISONS-1894 ;~---',.-,;....,-; ---_._-~~-~. ..."~r:.'~ [mANA ONLY IN1.] '" EMIlY COlt of lullitna .0ttti0II I....,Coit.f ..1 ..........~ o,.red..COIta of Thor .........in ..,.. hi 1113 EXhndId to ,. IhIIdId AI'OII R Pl8M ~ •1M2 D~byW..... LEGEND ••••••••• --- • ."-;'~"'."~f:' ....- Annuli Enersv OUtpUt Gwh , i~\lj m: :;:::-:.•.;,' ::.~':~:::....':;~;~ ?ilt~l ArM U.....ThII Line Ie Annutl Colt af Belt T........OptiOn :::::.UndudinllnvlltnWl'?t Costl):.:. ,...l~--...__.....L _ JIL...I [.A....UnderThii Line II Annuli eo.of hcitnl Option ~:::::::::-.......'......~~~•••~•••••"••••••••~••••••••••••~•••••••~••e ••••••••~.... :Ar.Under Thit Line"AnnUli i :Opeming Colt of Exi$ting CaplCity 1993/4 :(AvoidedCoItl of F,*lind OIIM Only;•• :A....Rtpnlllnt5 AnnuM Opntinf Costa :from Exiltinl Gerwating Pllnt_11=""'So'"SUlitnund:..Therm"Options IIJllilll· Medium Grow'h System EIMII'IY ForetIiItfor1IM;",828 GWh o.,'.;.;·;·;.;·?;······..i;;;;·j·i·i·j·;·r·;·;;;:I·y··..•••••••••••*.~~~~~~._~?~.~;r••~•••~•••~.~.;.~,.~.;.~•••;.;,;;;;;,·.tn::~~:':.:t·~·Pr&.·-r=-4?3 ' , 1,000 .2,000 3,000 4,~;$':;6,000 50 260 300 200 I i ~160 fw '~ 100 ~r, !'-~ -~~~~~:z:Jf,,;."ijo:l"1i;V4·~J.ItYt-H'..,,"A.-~~;p,.~~1 7 iIIlIibI.t ~.~.. ..•.''''.''_h,.,-.r..."",~,..._~':"'~;."l :'--::'~~~3'.~i.."S:1~~ COSTIAVINGI FROM IUIITNA INCHEAlING OVEn WHOLE LIFE OF PROJECT """~':J 04 06 06 07 08 W 2010 11 12 13 FIGUR~0.8 -SYSTEM COSTS AVOIDED BY DEVELOPINGSUSITNA o..iI c."~o"o'''SttellR in .2QOZ.! ..,..-,- t ."~"\ IncrUlil1l.Th'tlllillfue'.r Coati AvoidMi ~•~,~_.....~..,. /I /.-Avoid'Colt of a FurtMr 200 'NtN CQ..Fir"Generating Unit•I• SYSTEM COSTS AVOIDED BY DEVELOPING SUSITNA COMPARED WlrH BEST THERMAL OPTION IN MillS PER UNIT OFSUSRTNA OUTPUT IN CURRENT DOLLARS be A".oid.Colt of 2 x200MW eo.I Filled Generating Units 180 340 300 380 160 140 1~ 360 320 -.I:1 280 ~·260., a..240l• S220 ~ !200w Rev.1 I 100kj W'~lOn au""'l ..1"3 I -------~... ~_~"'~"'.":~"'lO'~*4 ''''''''i('''''~'''~''?'<'J''''"'7'''''''''''''''''''-''-~~''''.v~~I¢''lIlJ.U IIt!l!.l:XL••JS!4iIf~.1 _'UI EIBb 5'..7j ..IiJ ..."h_......I ,----_...._---....-----_...."..FIGURE·D.IO -ENEAQYPRICit4Q COIJIPARISONl-2003 ~\'.•'~~~-...,.,.-:~~.,',~.'lI;'·"~..."."T_t'..:.u,~'....,,"•.,.."~~."'<~~Y""Wi!":dli(/iitlII.~,Itl!"""JI"IIfII~Jl!IItIIe"Uj;l_l.j_'.b_.Z •mil'*_... ~:~~'11~'.~,£~-~ 1,000' 3L3lS IWATANA.DEVIL CANVONIN~ r:;::;::l~~,;~~,.,.,~J Medium GrowthSyawnEnergy ~. \ '-IU8INO,I ,,,-Under Thle Line II AOOUIII CoN of IIiIt ThIrmII Option I (lndudmt IlWIItment Colt)----I ....ColIC",............,...'{JptWR \.....11...~MI'IY Cult flf 0ptJcNI________IiiIl___IIII!!! I -~CoItI of r ........PIInt III UtII11I,.13 E~to 11M I .n n~~R~~~i t~;;:;:~;~:~:;::;;;0;0........It;.au;n.---.-.....--- ~~ii~!!!t::::;:::;::::::::::::::Ii .".;:::::::::::::::::;:::;:;:;:::;:::a ..[.·~U'"thill LIM 11 AnnuW Colt of lusitnl Option~@~*.I~,.~il~ij~~~~tl•••••I •••la••I ••••~M••,•••I •••••i ••I •••••••••••,••••••••I •••.a.I•••5a •••••I ••~••I ••••3••••Gi.8••••••••••I.~ ~~jljj~jjjj1jIjj1jjj1jjjjjljlj11 .I !.i m~~W~~I.---.-.---m---_~--_--.------.--~;;:;:;:;:;:;:::;::~::::::;:::::::::::::;:;:;:;:::;:::;:;:;:;:::;:::::::;:::;:::=:;:::::;::':-- .o I ·i·i.i·i·i·'i·i?;·;-;-,.lLH:h;·t.'''i·i·'N..,·;·ti·;'';~·;·:·i·'OS?,.;.,?,,,,o,.;.'?:-;-'.:'.I _I!I __" 1,000 2,000 3,000 4,000 1,000 Annuli e.....gy OutpUt GWh ....r-- it ~:; 100 300 I::: ~ Szoo f III DII'.u.s LEGEND. ~PROPOSED .OA-M SITES ) ----~.~u .. LOCATION MAP FIGURE 0.11......-------.;,-~:..-._----=:.:.:..::.:.:....=~------~~~-...... --IIIIIII~·STEP NUMBIR INSTANOARIl PROCESS (APPENDIX A) CH .1(.5 a THERMAL LEGENO_ CRITERIA-ECONOMICS DAT~ON DIFFERENT tHERMAL GENERAnNl SOURCES COMPUTER MODELS/TO EVALUATE -POWER AND ENERGY YIELDS ..SYSTEMWIDE ECONOMICS -CHi I( -CHi K.I -CH,·I(.SS,Sl.AC· -CH .1C.S.Il.AC -CH i IC.S .SL,AC.CA,""2 ENGENEERING LAYOUTS AND ~TSTUDIES OBJEC';iVE. 'I ECONOMICS CRIT~RlA ECONOMICS ENYiRONMENTAt .. \. ,__:,OTER~TiONS _. SNOW ($) BRUSKASNA (B) KEETNA (k.) CACHE (CA) BROWNE (BR) TALt(EETNA -2 (T-2 ) HICkS (H) CHAKACHAMNA(CH) ALLISON CREEk!AC) STRANOLINE LAkE (SL J lOt • FORMULATION Of 'PLANSINCORPORATINGNQN-SUSITNAHYDROGENERATION FIGURE 0.12 S!Te: SELECTION ".........._._.~..."-,-'-~~j.1!",i.t¥4.-_U ca 4,i@iA;e......u·_,~>1,~I!JL""""_~i:''''';,'~'~T'.tt;ei'.E«~41J9II.!~bd"'- .::::::::;../.",....~. I 'f·'I til 39.LANE 40..TOI<ICHITlilA 41._YENTIIIA 42 •CATH€OMLLUFFS 43..JOHNSoN.....~ ~..JlJNCT!ONIS. 'i6.V-CHOH IS. 47.TAlitHA 48.I(!;NAI Ul([ 49.CHAKACH~_ FIGURED.I! o >lOOW 2'.SNOW 21 •KEN'"LOWUn.ClEltSTl.E It.TAMAMA ft. 30.~ 31.l<AHTISHHA ft. 32 •UPf'D'!ELOOA 33.COfFEE 304.GOl.KANA lit. '.~.kLUTIHA 36.BRADLEY LAKE 37.HICK'S SITE 341.LOWE 13.WHISKE~' 1<4.COAL ·I~•CI'lUUT'" If.OHIO .7 •LC:lW£It CHULmIA ".;;ACHE It.GltE£NSTOHE 20.TAl.KE~T*2 !••eltAHITE toItG£ 22.I(EETAA n,SfiEEPCl't£[1( 2<4,SKWENTNA U.T~AdiUUTHA SELECTED ALTERNATIVE HY~'RC SITES SCALE-MILES I INCH EQUALS APffiOXI~TEL'I'.-o·MILES I,STRAHC!JHE I .. 2.LOWV!~t.uliA 3 •LOWER L~Cl't. 4 •ALL lION .l;ft. 5.C~SC£H't LAI<£2 6.GftAHT LAKE 7.McCLI,lM aAY IS.lrPPtll NELLIE JUAN 9.~Ei't CM:E:K 10,SILVER LAI<E II •SOLOlifOH GULCH 12.TlrSTUll4EI« i -j\ I i I I I J 2010 '. KEETNA "'CHAKACHAMNA 2000 EXISTING AND COMMITTED 1990 COAL fitED THERMAL Qll FIRED THERMAl (Nar $HOWN ON ENERGY DIAGRAM)· GAS AREOTHERMAl NOTE :RESULTS OBTAINED FROM OGPSRUN L FL '1 0-~YOROELECTRIC III E:ZI• L.EGEMJ' PEAK LOAD TIME GENERATION SCENARIO INCORPORATING THERMAL AND ALTERNATIVE HYDROPOWER DEVELOPMENTS -MEDIUM LOAD FORECASl-FIGURE 0.14 19ao 1910 % ~6 oo·o 2 10 0 .......-..........---..---------..........---------------------... 3 8 ~ :1 2ooo t >!:: U ~I Co .,.-...........------------.----------------........v I >-(!) 0:4.wzau I' c STEP NUMBER IN STANDARD PROCESS ('APPENDIX A » 4 L.EGEND-- NO gA3RENEWAl:S ~·N••,.~,',w._.1 _~"'~.~.!<,_,;~:~ ';j ...',~'<!I "-::T.,,,j;Jli;;:?.7l;:;\,'':::;;:~'~_,",'i, , ECQNOMIC OBJECTIVE EVALUATION COMPUTEftMODELS TO EVALUATE SVSTEM WIDE ECONOMICS GAS RENEWALS NO GAS .RENEWAl.S PLAN fORMULATION ECONOMIC OBJECTIVE UNIT TYPE SELECTION PREVIOUS STUDIEs ~) FORMULATION OF PLANS INCORPORATING ALL-THERMALGENERArION COAL ;,ooMW 250 MW 500 MW CmtBINED CVCLE1~SOUW GA43 TURBINE:15 MW DIESEL:IOMW La '.,,-~:..._• :FIGURE 0.15 I I r l. iIILl 1 I 968 813 2037 ..... 2031 JIJI FIGURE 0.16 789~~ 634 IS91 U573 TIME EXISTING a COMMITTED TOTAL. OISPATCHED ENERGY ALTERNATIVE GENERATION SCENARIO BATTELLE MEDIUM L.OAOFORECAST COAL FIRED THERMAL. GAS FIRED THERMAL. O.IL FIRED ttiERMAL (NOT SHOWN ON ENERGY DIAGRAM) rlJJ• .:-:.:.:.:.:.:.:.:.:.:-:.:.:.:.:.:.:.:...........••.:.:.:.:.:.:.::::.::::::::::::::::::::=:.;,.:.~••••:..•...•.••....::::::::::.:~:~~~~~.........•..•..:.:..............:.:.:::::. ••ifo.~~•••"....'•••••"•"Jlj!l~~~:;:L ~~J6::t!~~L ~·~~.~.~.~.~"""""'__."....J:.~.~..~..~.~..~..~.:l•••;••••••5•• o 1980 1990 2000 2010 o L--'-981:0.:..-----------,9J.90----------2....1000~~........---1Ii----~20:-:,~O LEGENDoHYDROEL,ECTRIC TIME 6 2 8 \ % ~ <!) oo,0)-4t >- CDa::: IIJz l&I =2o ~ I>....o ~clo n··l.•.•t ~ fl ' t .!!'l~,!!.,'j 1 ~ ~T:~~."';-'.,.~ LONG-TERM COST PRESENT WORTH .........""'4I"..I<'''''~'U;r.:z . ,~ •p """,,,,:J~--;"'.-..-,.;.::,;,l PROBABILITY i,A RESULT 10 ~ j:..-~1~, FUEL COST ESCALATION. ~- lOW .04 HIGH J2 ~ ALTERNATIVE CAPITAL COST - i-·~'~{ ~...- I·UJO FIGURE D.17-:-PROBABILITY TREE-SYSTEM WITH Al.TERNATIVESTOIUSITNA LOAD FORECAST t~.r- HIGH TOI .01 ".,.. HIGH .04!.&MEDMJIlI TO!.02 11,"1 ..LOW T03 .01 7,124-"""--------4 l04 ...03 14,114 .,.IGH :20 1/00 MEOIUM J2 I ;/lOS .01 10'- I .......I "106 .03 7,313 I TO?.01 13,142 .I08 .02 10,103"II09 .In 71 114 - I TIO .03 11,172Ifl.01 I,.~~~~II2 .03:,,.,I/..TI3 .01 10,137~w MEDIUM .60~eEOIUM .~0 fl1 •:::::: I ,.03.10,321 ,LOW .12 ,I ?----J '0 .08 ~10 _.OJ MIl I .01 I,m HIGH .~I (I,'~.02 7,480 ./_.01 4!_---------------1 l2Z .03 1,7.\.LOW .20 1/60 MEDIUM .12 I /1:23.......1.171 ""124 -.03 4,110 tJj HIGH •..-.'T2!5 .01 1,412 '"LOW •04 1---&MEDIUM T26 .OJ 1.101 ,.oL LDW T 27 .Ot .4.412 .!."':"~r'''~'-'-.. .. lI',1~~...,~~ f ~"!~~......."~-t _,.; .01 ,01 .IS ~ HIGH &..OW lOW ~~~ "."~'" ALTERNATIVE CAPITAL COST ~.,~ LOAD FORECAST '~••~.B".··~L-_.rll..•.':-',',.':-""",'..',...:'.,.A •t •~ FIGURE 0.18-PROBABILITY TR~E -sYSTEM WITH IUSITNA I, 0 1Nt I I SUSITNA FUEL (~OST CAPITAL RESUlT LDNG-TERM COST ESCALATJ.9.H COST JD ~PRI;$ENT WQRTI:iHl.~.!l!l-~!YM ~8k ==~::::: .S03 .0010 .',714v:~-504 .0030 10,110 ,..._..-~K AOV ~---1 <-lSi :=::=_ I S07 ._..001'_...~_....~.......•,.,_.__ .SOB..-..008 1,010.........-------------s.os:.0010 1.111 . _ /"_"f~<IW ::;::~::::_.=~-=-= ......--------------S12 .0110 '.1.~_ I HIGH 20 r,60 M£OIUM ,121«50 MEOIUM,oq <=~l :=-':::::-.::----'-::.: "--------Sl~.0-'.19.__.._ ,--.._-,{~\;::::::::-.---- \S 18 .0110 1.1. I 519 .GD11 11,414 ------~.M 10,514 ....ill .DG '.114 I ./'Ml 522 .0030 10,1. \--.04 ~'~MEDiUU =t ('52Zi .0010 '.221 \524 .Q120 ..1,321 /525 .00115 .,•• ......,;;;;;;.--.;..;..-.•---.:xL.-·~1 ......(!F--·---$26 .0021 1," \5.21 .0010 7J111 .HIGH ,15 1 /528 .028 ',311 /f-529 ,mI.1,311 \530 .0iQ0 ',417 It MEDIUM .60''1 10 MEDIUM L./'MEO!'IIU ,..J /S 31 .0410 1 •.174 "--....fIO ~ro UM ~(-532 .1710 1,012 \533 .1100 ',111 I 5..34 ,0221 7,110S35.Q7B •~7~"s..36 oaOo"5.12=1----- HIGH 05 /"531 .0071 7,&14 I '.E-538 .01D 1,"1.\...539 01fM)-.lJJn.._ \LOW 20 1 10 ~eOIUM 20 V 50 MEO'\I1oI ,10 I (~1?:g~'.:::: \,542 .0100 1.151 ,HIGH 543 .0011 1.331 ....--'W!(.25 MEDIUM 844 .0125 '~37 {b LOW S~~.0300 n ,.&43'~':---------- E·t,OOO r .:~.;.~... I ~ J 'i-~. .~ r--r ./ Non-lulitna .........-r\r V/r-'r •J ~.,r ~ --J r IushnaPlan . FIGURED.19--IUSITNA MULTIVARIATE SENSITIVITY ANALYSIS -LONG-TERM COITI va CUMULATIVE PROBABILITY ',,_",.:0 ~~-...·:·.tt....•.n~~ 1.0 ~ .1 ~~ .1 ~ .7 ~ .1 ~~ .Ii ... ~Jv.Probability .4.3.2.1 2 o 12 14 10 -,.-)( §I..-..- S !•] 4 t±'~#<:~I!"1 ,CU"~! ImlgSlaBg~9~~-~~~~~!.M~~~~~ ~,... '/ ../ /,- .-III V / ./V /V /:~; --'"V FIGURE D.20 -IUIITNA MUlTIVARIATEIENllTMVITY ANALYIII-CUMULATIVE PROBABILlTV V'NETBENEFITI 5&00'4IiOO360026001600(&00)0 600 Net Btnefit -•x 106 (11182 sa .'500)(~)(3600)(4S00) 1.0 .1 •• .7 ~. J •• .6 =i I .4 .3 .2 .1 ..'.. 13 l1li 12 - 11 .. 201009 .. 06 Mill Rite COlt .BeIt The~)n"Option 0%Inflation,3%In.relt .. 0'1 "COST IAVINGS GROWING OVER WHOLE<OF SUSITNA LIFE 08 ifill "~:£;·'?'::J1r.;:":~:i::--.?~;,·,.-0f1~:'~0:::~.i_-:t~~:S~~,:~~2t~L~~fu.~M~1RiS"~.'......... 66 Mill R."Colt Bat rhermlllOption 1%lnlllllon,10%IntllNlt j:_~...!7~<. IiiiI 04 ,....:..~~.:<:~.~,~" v... .... 0302 &~ 0.21-ENERGV COST COMPARISON -,,~DEBT FINANCING oAND ""'NFLATION 01 ~ FIGURE 2000I ~ 8 ~ COST SAVINGS IulimlMl1i Rata Colt Whh '1%,Inflation,1.Intllreat 7 NO STATE APPROPRIATION SCENARIO 100%DEBT FINANCING ~ • ~~.--~ & ~ . r --....-----------.,""'~-~-------- I "...----"~-.-,~-- .~•...._----- :!iII"fff!i#Negligible Fin.ncing Deficit witbZero Inflation -SUlitna Cott wid.O%lnfl,tion,3%IntoNd 94 100 120 I!I!II!lII ......~1 - .-\--~i". _~~."!.!f!'_,!'"__.,.......'"""",