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=r OJECT • EXHIBIT D f,'.\ ID JULY T$f~8 .t:.• THORITY·.-3 D/4.L S TATEME,·N'l' EXHIBIT'A EXHIBITC BnUARY 1983 .<:~~':::l.tCU P tltJr1 n Cl ~ aEFORETHE '!'~ '~GYR'EGUlATORY~COMMJSSfON VOLUME '1 lliJA\OO~~c §lID£®©@ SusJtnaJoint VE;nture Document NumbE;r PIE;ase Return To DOCUMENT CONTHOl ~~. -..-.-.;~ I",.'.~ , I"'r I ( [ I" t,,: ." '~I"'",-"~-",r.:. lJ',",~,~,'" :<!~.e'" ;'1," II ",." .", I I I l' f I j .. BEFORE THE FEDERAL ENERGY R'EGULATORY COMl\1ISSrON APPlICAT.lor~FOR LICENSE FOR MAJOR PROJECT SUSITNA HYDROELECTRiC PROJECT VOLUME '1 INITIAL STATEMENT EXHIBIT A EXHQBIT C FEBRUARY 1983 EXH!8IT D REVISED JULY 1983 ALASKA POWER AUTHORITY .........j _Ii "J t l I II, \I, I Ir ! \l I I~),_.-, t'"; ""'..~\\..-:,_••...:~',J:~~,~ No Change o 0...1...1 to 10 D-1-13 0-4-4 to 9 0.2 to 5 D.lto 3 Table of Cont.pg.l 0-4-23 0.7,8,9 0.29,30 Old No.New No. Renumbered 0-4-20 D-4-39 -48 0-4-32 to 41 0...4-49 to 54 Deleted D.6,7,8 0.17 to 22 D.16 to 21 0.38,39 0.11 to 13 t),';to 8 0...1-4 Deleted PAGES FIGURES 0-4-10 to 22 0...4-24 to 31 Deleted 0.4 Deleted 0.5 0.9 Deleted 0.10 0.6 new Deleted 0.31,32 0.10,11,12 Deleted 0.13,14,15 Deleted .0.22 to 27 Oeleted 0.28 Table of Cont ..pg.2 List of Tables pg.i,11 Listnf Figures pg.i'ii 0-1-11,12 0-2-1 0-3-1 to 3 0-4-1 to 3 TABLES 0-5-1 0-6-1 to 3 Revised 0.1 --crra No~New No. D-4-10 to 19 0-4-21 to 38 D.9,lOt 11 0.12,13 0.14 9 15,16 0.23 to 27 0.28 to 33 0 ..34 to 36 0.37 0.40 0.41,42 0.4 to 6 0.7 0.8 and 10 D.9 0.14 0.15 to 18 0.19 IJ t'" ..,(, [ U [ L [ [ l 1 11 il Page TABLE OF CONTENTS EXHIBIT D PROJECT COSTS AND FINANCING SUSITNA HYDROELECTRIC PROJECT VOLUME 1 1-ESTIMATES OF 'COST 0-1-1 1.1 -Construction Costs D-1-1 (a)Code of Accounts D-1-1 (b)Approach to Cost Estimating .~•••••••••••••••••D-1-2 (c)Cost Data •••••••••••Q ••••D D-1-3 (d)Seasonal Influences on Productivity •••••••••••0-1-4 (e)Construct i on Methods "••••••••;0 ••••••"......D-1-5 (f)Quantity Takeoffs 0-1-5 (g)Indirect Construction Costs D-I-5 1.2 -Mitigation Costs eo ••••0-1-7 1 ..3 Engineering ·and Administration Costs ('0-1-8 (a)Engineering and Project Management Costs 0-1-8 (b)Construction Management Costs 0-1-9 (c)Procurement Costs 0-1-10 (d)Owner1s Costs D-I-10 1 ..4 -Operati on,Mai ntenance and Replacement Costs •••••••0-1-10 1.5 -Allowance for Funds Used Ouring Construction •••••••0-1-11 1.6 -Escalation 0-1-12 1.7 -Cash Flow and Manpower Loading Requirements "0-1-12 1.8 -Conti ngency II ;.•••••0-1-13 1.9 -Previously Constructed Project Facilities ••••••••••0-1-13 1.10-EBASCO Check Estimate 0-1-13 2 -ESTIMATED ANNUAL PROJECT COSTS ;•••••0~2-1 3 -MARKET VALUE OF PROJECT POWER ••••••••••••••••••1 •••••••••0-3-1 3.1 -The Railbelt Power System .~,D-3-1 3.2 -Regional Electric Power Oemand and Supply 0-3-1 3.3 -Market and Price for Watana Output in 1994 ".D-3-1 3.4 -Market and Price for Watana Output 1995-2001 •••••••0-3-2 3.5 -Market and Price for Watana and Devil Canyon Output in 2003 J ••••••••••••••••••••••••0-3-3 3.6 -Potential Impact of State Appropriations •••••••••••0-3-3 4 ...EVALUATION OF ALTERNATIVE ENERGY PLANS •It ••••••••••••U II •~0-4-1 4.1 -General ••••••••••••.••••"D 4-1 4.2 ...Existing System Character1stics ••••••••••••••••••••D-4-2 (a)System Description 0-4-2 (b)Retirement Schedule 0-4 ..2 (c)Schedule of Additions '"'"0-4 3 r J I I f I f I i I I I I 1 I ! ! (ReVised,7/11/83) Page 4.3 -Fairbanks Anchor~:1e Intertie 0;••••••,..,0-4-3 4.4 ..Hydroelectric Alternatives 0-4-4 (~j Selection Process o •••••••••~~0-4-4 (b)5e 1e·~""IOd 5i tes ••••It ••••:~0-4-5 (c)LakeChakachamna ••••••••••"0-4-5 4.5 -Thermal Options -Development Selection 0-4-9 (a)Assessment of Thermal Alternatives ,..0-4-9 (b)Coal-Fired Steam.""•••••••••0-4-9 (c)Combined Cycle 0-4-12 (d)Gas-Turbine Cl "D-4-15 (e)O'iesel Power Generation 00 D-4-16 (f)Plan Formulation and Evaluation D-4-16 4.6 Without Susitna Plan ••••••••~D-4-18 (a)System as of January 1993 0-4-19 (b)System Additions ••,lID ••••~0-4 19 (c)System as of 2010 •••••••••••••••.•••••••••••••0-4-20 4.7 -Economic Evaluation 0-4-20 (a)Economic Principles and Pa,:ameters 0-4-21 (b)Analysis of Net Economic Benefits .&1)••••••••••0-4-24 4.8 -Sensitivity to World Oil Price Forecasts ••••••••••••D-4-29 4.9 -Other Sensitivity Assessments 0-4-30 4 ..10-Battelle Railbelt Alternatives Study 0-4-31 LIST OF TABLES i LIST OF FIGURES iii REFERENCES APPENDIX 0...1 FUELS PRICING STUDIES 6 -FINANCING •••,...............................................0-6-1 6.1 -Forecast Financial Parameters 0-6-1 6.2 -Inflat i onary Fi nanci ng Oefi cit 0-6-1 6.3 -Leg.islative Status of Alaska Power Authority and Susitna Project •••••••••••"••••••••••••••••.••••0-6 ...1 6.4 -Financing Pl an 0 ••0-6-2 5 -CONSEQUENCES OF LICENSE DENIAL 0-5-1 5.1 -Cost of License Oenial ••••o •••••••••~•••••••~0-5-1 5.2 -Future Use of Darnsites if License is Denied •••••••••0-5-1 TJ\3LE OF C'JNTENTS (Continued) 'JIii()'-i.i ) 1 f! f:J,"'1t..•.~""'....",j.''<"-'; \,"::,t ~ * ** *** *** *** ****** *** *** ****** **"/t' ********* i (Revised,7/11/83) Summary of Cost Estimate Estimate Sumnary -.Watana Estimate Summary -Devi 1 Canyon Mi ti gat ion Measures -Summary of Costs Incorporated In Construction Cost Estimates Summary of Operation and Maintenance Costs Variables fur AFDC Computations Watana and Devil Canyon Cumulative and Ann~Jal Cash Flow Anchorage Fairbanks Intertie Project Cost Estimate Summary of EBASCO Check Estimate No State Contribution Scenario Susitna Cost of Power Forecast Financial Parameters Total Generating Capacity Within the Rai lbelt System Generating Units Within the Railbelt-1982 Schedule of Planned Utility Additions (1982-1988) Operating and Economic Parameters for Selected Hydroelectric Plants Results of Economic Analyses of Alternative Generation Scenari os Summary of Thermal Generating Resource Plant Parameters/1982$ Bid Line Item Costs for Be.luga Area Station Bid Line Item Costs for Nenana Are~Station Bid Line Item Costs for a Nc.tural Gas-Fired Combined-Cycle 200-MW Station Economic Analysis Forecasts of Electric Power Demand Electric Power Demand Sensitivity Analysis Discount Rate SensitiVity Analysis Capital Cost Sensiti vity Analys is Fuel Price Sensitivity Analysis LIST OF TABLES rrmx ,.,.-...- !\"., 0.1 0.2 0.3 0.4 0.5 0.6 D.7 0.8 0.9 0.10 0.11 0.12 0.13 0.14 0.15 0.16 0.17 D.18 D.19 0.20 0.21 0.22 0.23 0,,24 D.25 0 ..26 0.27 *Revised 7/11/83**New 7/11/83***Page,figure,or table numbers changed.No revisions in content. 7/11/83 fi, [l 'r·,'I ;,'.} ••if\i....,..'.:..,," [1;j ".......,t .[7 ,,~,""' I~..~ ••.:ll. • {~ [ i.t' r,~ l\ L:" ......!.\ .# '. * * * *** *** t ..~~.~~ ... ~\;-",---.• \1 I·". •r ..". ~·~:hx".•!. "r .'.~,, .'...••I.,• •• ;;(Rev;.sed,7/11/83) Summary of Sensitivity Analysis Indexes of Net Economic Benefits ~......... Batte'lle Alternatives Study for the Railbelt Candidate Electric Energy Generating Technologies Battelle Alternatives Study,Summary of Cost and Performance Characteristics of Selected Alternatives Financing Requirements-$Million for $1.8 Billion State Appropriation $1.8 Billion (1982 Dollars)State Appropriation Scenario 7%lnfl ati on and 10%Interest f,D.28 'f'.'.1..D.29,~ ",0.30 ~LIST OF TABL~(Continued) ,fl ' ItIil..,;f, 'I'l' !,; [1 0.31 0.32 [J I"', ....",' '[i I/~ 1 ~''''~ [ t. L~ I,~ "·1······.' r>,,>ilfIl 1,.... '''''~.,..~~..•.......•..,..~'~~""..,-.... ....,....,L.:·...•"...'.....,...........•:"..... ** * * *** *** *** .- • iii (Revised,7/11/83) Watana Development Cumulative and Annual Cash Flow January 1982 Dollars Devil Canyon Development Cumulative and Annual Cash Flow January 1982 Doll ars Susitna Hydroelectric Project Cumulative and Annual Cash Flow Entire Project,January 1982 Dollars Energy Demand and Del iveries From Susitna System Costs Avoided by Developing Susitna Formulation of Plans Incorporating Non-Susitna Hydro Generation Selected Alternative Hydroelectric Sit~s Formul atlon of Pl ans Incorporating All-Thermal Generation Alternative Generation Scenario Reference Case.Load Forecast Enetgy Cost Comparison -100%Debt Financing o and 7%lnfl ation LIST OF FIGURES 0 ..2 \' 0.1 0.3 0.4 0.5 0.6 0.7 0.8 0.9 0.10 F J1. It.: f1 [t fi [:.; ...:.j, [ [, t [ L ~, l',,,, fJJ "j't ~ ····--:r··_. ..Q~script ion Costs for structures,equipment,and facilities nece.ssary to produce power .. Estimates of construction costs were developed using the FERC format as outlined in the Federal Code of Regulations.,Title 18 (GPO 1982). The estimates have been subdivided into the following main cost groupings.: This exhibit presents the estimated project cost for the Susitna Hydroelectric Project,the market value of project power and a financing plan for the project.Alternative sour·ces of power which were studied are al so presented.' This section presents estimates of capital and operating costs for the Susitna Hydroelectric Project,comprising the Watana and Devil Canyon developments and associated transmission and access facilities.The costs of design features and facilities.incorporated into the project to mitigate environmental impacts during construction and operation are 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. 1 -ESTIMATES OF COST EXHIBIT 0 -PROJECT COSTS AND FINANCING-~. This section describes the process used for derivation of construction costs and di scusses the Code of Accounts estab 1 i shed,the basi s for the estimates and the various assumptions made in arriving at the estimates"For general consi stency with pl anning studies,all construction costs developed for the project are in January 1982 doll ars. (a)Code of Accounts The total cost of the Watana and Devil Canyon projects is summari zed in Table 0.1.A more detailed breakdown of cost for each development is presented in Tables D.2 and 0.3. 1.1 -Construction Costs Group Production Plant "~. ':l,,, f. r~-',] ·.1 d f: ("C r; [' l. ( t L l t I,W J ~-!-,r and and faci 1ities operation and production and Costs for structures,equi pment,and facilities necessary to transmit power from the sites to load centers. Costs for engineering admin i str at i on. Costs for equi pment requi red for the maintenance of the transmission pl ant. Costs t:'at are common to a number of construction activities.For this estimate onl y camps have been identified in this group.The- estimate for camps includes electric power costs.Other indirect costs have been included in the costs under prod uct ion,tr ansmi 5S i on,and general plant costs. Reservoir,Dam,and Waterways Production Plant Excavation ~1ain Dam Rock Main Dam Structure Indirect Costs General Plant Overhead Construction Costs -Group: -Account 332: -Main Structure 332.3: 0...1-2 Further subdivision within these groupings was made on the basis of the various types of work involved,as typically shown in the following exampl e: -Element g32.31: -Work Item 332.311: -Type of Work: The detailed schedule of costs using this breakdown is presented in Volume 6 of the Susitna Hydroelectric Project Feasibility Report (Acres 1982a). (b)~proach to Cost Estimating The est i mat i ng process used gener a11 y included the fo 11 owi ng steps: -Collection and assembly of detailed cost data for labor, ,Transmission Pl ant ~'~" '.\ 1 Ifl", r'~· r~"I" ,'II 11''7 ! 1" [- f [:' ~"', t L l 1,: t',:: J J "n 0-1 ...3 It has been assumed that most contractors wi 11 work an average of two lO-hour shifts per day,six 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 shi fts,seven days per week. The lO-hour work shift assumption provides for high util ization of construction equipment and reasonable levels of overtime earnings to attract workers.The two-shift basis generally achieves the most economical balance between labor and camp costs .. Construction equipment costs were obtained from vendors on an FOB Anchorage basi s with an appropri ate allowance incl uded for transportation to site.A representative list of construction Cost information was obtained from standard estimating sources, from sources inA1ask a,from quotes by maj or equi pment supp 1i ers and vendors,and from representative recent hydroelectric proj ects •Labor and equi pment costs for 1982 were developed from a numbE!r of sources (State of Alaska 1982;Caterpi 11 ar Tractor Co. 1981)and from an analysis of costs for recent projects performed in the Alaska environment. material,and equipment as well as information on productivity, climatic conditions,-and other'related items; -Review of engineering drawings and technical information with regard to construction methodology and feasibility; -Production of detailed quantity takeoffs from (drawings in accordance with the previously developed Code of Accounts and item listing; -Determination of direct unit costs for each major type Of work by development of labor;material,and equipment requirements; development of other costs by use of estimating guides,quotations from vendQrs,and other information as appropriate; -Development of construction indirect costs by review of labor, material,equipment,supporting facilities,and overheads;and -Development of construction camp size and support requirements from the labor demand gener ated by the construct ion di rect and indirect costs. (c)Cost Data r,·-" .'1, fl r'l, :' r~ (' f f [ f i-'" l!i,1 4"I,t ; I, I 1 I o 0-1-4 ..... Studies performed as part ;)f this work program indicate that the general constrllction activity at the Susitna damsite during the months of Apri 1 through September would be comparab 1e with that in the northern sections of the western United States.Rainfall in the general region of the site is moderate between mid-Apri 1 and equipment required for the project was assembled as a basis for the estimate.It has been assumed that most equipmentl'.Du1d be fUlly depreci a.ted over the 1ife of the.project Ii For some activities such as construction of the Watana main dam,an allowance for major overhaul WG.f included rather than fleet repl acement.Equipment operating costs were estimated from industry SOurce data,with appropriate modifications for the remote nature and extreme climatic environment of the site. Al aska:1 1abor rates were used for equi pment maintenance and repair..Fuel and oi 1 prices have been based upon FOB ~>ite prices. Information for permanent mechanical and electrical equipment was obtained from vendors and manufacturers who provided gui de'j ire cost,;on maj or power pl ant equi pment .. The costs of materi al s requi red for site construct i.on were estimated on the basis of suppliers'quotations with a1low,ances for shippi ng to site. (d)Seasonal Influences on Productivity A review of climatic conditions together with an analysi.s of experience in Alaska and in northern Canada on large construction projects was undertaken to determine the average duration for various key activities.It has been projected that roost above- ground activities will either stop or be curtailed during December and January because of the extreme col d weather and the associ ated lower productivity.For the main dam construction activities,the following seasons have been used: -Watana dam fi 11 -6-month season -Oevi 1 Canyon arch dam -8-month season. Other above-ground activities ar~assumed to extend up to 11 months depending on the type of work and the criticality of the schedule.Underground activities are generally not affected by climate and shoul d cont;nue throughout the year. Studies by others (Roberts 1976)have indicated a 60 percent or greater decrease inefficiency in construction operations under adverse winter·conditions.Therefore,it is expected that most contractors would attempt to schedule outside work over a period of between six to ten months. "r"" :-" j'',~, ,i '-1 f\ [' r'L f { { t il; l 1\ t' ~---- '.., J iIt t t'£ ,1 ~, r~·· ':\.,~ r'-"'·~ .f, I 1 ;"'iJ f~""",1, r' J I [ I: t ( ",I .J l t ~ J ~i ,I '1"" j (e) (f) (g) o mid-October,ranging from,a low of 0.75 ii~ches pl'ecipitatiion in April toa high of 5.33 inches ;n August.Temperatures in this period range from 33°F tc 66°P for a twenty-year average.In the fi ve-month period from November through March,the temperature ranges from 9.4°F to 20 ..3°F,with snowfall of 10 inches per month. Construction Methods .." The construction methods assumed for development of the estimate and construction schedule,are generally considered normal to the industry,in line with the available level of technical i nformat ion.A conserv at i ve approach has been taken in those areas where more detailed information will be developed during subsequent investigation and engineering programs.For example, normal drilling,blasting,and mucking rnethods have been assumed for all underground excavation.Conventional equipment has also been consi dered for maj or fi 11 and concrete work. Quantity Takeoffs Detailed quantity takeoffs were produced from the engineering drawings using methods normal to the industry"The quantities developed are listed in the detailed summary estimates in the SusitnaHydroelectric Fea~ibility Report (Acres 1982a,Vol.6). Indirect Const~u~tion Costs Indirect construction costs were estimated in detail for the civil construction activities.A more general eval uation was used for the mechanical and electrical work . Indirect costs included the following: ...Mobilization -Technical and supervisory personnel above the level of trades foremen -All vehic'le costs for supervisory personnel -Fixed o.ffices,mobile offices,workshops,storage facilities, and laydown areas,inclUding all serviCeS -General transportation for workmen on site and off site 0-1-5 0-1 ..6 -Mobilization costs have generally been spread over construction items; In developing contractor's 'incirect costs,the following assumptions have been made: -Contingency allowance -Profit. Head offi ce overhead -Yard cranes and floats -Utilities including electrical power,heat,water,and compressed ai r -Permits -Taxes -Insurance -Safety program and equi pment -Financing -Bonds and securities -Small tools -No escal at;on allowances have been made,and therefore any ri sks associated with escal ationare not included.These have been addressed in bot.h the ecunomic and financial studies; -Financing of progress paYments has been estimated for 45 days,t:le average time between expenditure and reimbursement; -Holdback would be limited to a nominal anount; -Project all-r;~1<insurance has been estimated as a.contractor's indirect cost fQr this estimate,but it is expected that this insurance would be carried by the owner;and -Contract packaging would provide for the supply of major materials to contractors at site at cost.Theseincl ude fuel,electric power, cement,and reinfC"V'cing steel. r·~ ~! ,:;'J r1 '. :.1 rl. f': i~~ 'IJ [ f. t t l if L ', i .•' '1;,~ '\,- .1 $3i.million (Approxim~tely) 5 million (ApprOXimately) $'37 mi 11 ion Watana Dev i 1 Canyon Total Project A number of studies and programs wi 11 be required to monitor the impacts of the project on the environment and to develo~and record various data during project construction and operation.These inclUde: ~Archaeological studi!;s -Fisheries and Wildlife studies D...1-7 A number of mitigation costs are associated with facilities, improvements or Gther programs not directly reI ated to the project or located outside the project boundaries.These would include the following items: -Cari bou barri ers -Raptor nesting platforms -Fish channels -Fish hatcheries -Stream improvements -Salt licks -Habitat management for moose -Fish stocking program in reservoirs A detailed discussion of the mitigation programs requir~d for'the project is included in E~'hibit E along with tables listing detailed costs it The costs of t;,ese programs incl uding conti,,'lgency have been estimated as follows and listed under project indirects in the capital cost estimate. 1.2 -Mitigation Costs The pv'oj ect arr angement i ncl udes a number of fe atures .des i gned to miti gate potenti al impacts on the natural environment.and on residents and communities in the vicinity of the project.In addition,a number' of measures are pl anned during the construction of the project to reduce simil ar impacts caused by const'ruction activites.These measures and faci1 ities represent additional costs to the project than would otherwi se be required for safe and efficient operation of a .hydroelect.ic development"These -mitigation costs have been estimated at $153 million and have been summarized in Table D.4.In addition, the cost of full reservoir clearing at both sites has been estimated at $85 million.Although full clearing is considered good engineering practice,i.t is not essential to the operation of the power facilities. These ~nsts include direct and indirect costs,engineering, administration,and contingencies,; ,"; 1 ' I I I P_J......_-f'- andsurveyssite 'J c:·',~ -Fe.asibility studies,including investigations and logistics support; -Prepar;ation of the license application to the FERC; ..Technical andadministra.tive input for other federal,state and local permit and license applications; -Overall coordination and administration of engineering,con struction management,and procurement activities; -Overall planning,coordination,and monitoring activities rel ated to cost and schedule of the project; 0-1-8 •Owner's Costs •Engineering and Project Management •Constr uct i on Man agement •Proc u~'ement -Account 76 -Right-of-way studies;and -Socioeconomic pl anning studies. The costs for the above work have been included under proj~ct overheads and have been estimated at approximately $20 million. 1.3 Engineering and Admini,stration Costs Engineering has been subdivided into the following accounts for the purposes of the cost estimates: -Account?1 The total cost of engineering and administrative activities has been estimated at 12.5 percent of the total construction costs,including contingencies.A detailed breakdown of these costs is dependent on the organi.zational str'ucture establ ished to undertake design and management of the project,as well as more definitive data relating to the scope a.nd nature of the various project components.However,the main elements of cost included are as follows: (a)~n..9ineerinf!and ..,proj ect Man agement .Costs These costs include allowances for: rt , f'r . f' j.., f t' " , t it t t j r ['1 ..>' f'r! f-; f'{, j l f [ l. [ t t l l L:.,:,1 ; I l .1 j -CooY'dination with and reporting to the Power Authority regarding a llaspects of the project; -Prel'i1minary'and detailed de.sign; ...Technical input to procurement of construction services, suppm"t services~and equi pment; -Monitoring of construction to ensure conformance to design requirements; -Preparation of start up and acceptance test procedures;and -Preparation of project operating and maintenance manuals. I (b)Construction Management Costs Construction management costs have been assumed to include: -Initial planning and scheduling and establishment of project procedures and organi zation; ...C00rdination of on site contractors and construction management activities; -Administration of on site contractors to ensure harmony of trades,compliance with applicable regulations,and maintenance of adequate site security and safety requirements; -Development,coordination,and monitoring of construction schedules; ...Construction cost control; -Material,equipment and drawing control; ...Inspect;on of construct ion and survey control; ...Measurement for payment; ..Start up and acceptance tests for equi pment and systems; -Compilation of as-constructed records;and ..Final acceptance. D...1-9 b •.,., ',1 l ! ",,c0'=J-' o o .t (c)Procurement Costs Procurement costs have been assumed to incl ude: -Establishment of project procurement procedures; -Preparation of non-technical procurement documents; -Solicitation and review of bids for construction services, support servi ces,parmanen.t equ i pment 3 and other items requi red to complete the project; D-1-10 -Quality assurance services during fabrication or manufacture.of equi pment and other purchased items. (d)Owner's Costs Owner's costs have been assumed to include the following: ...Administration and coordination of project management and engineering organizations; -Coordination with other state,local,and federal agencies and groups having jurisdiction or interest in the pr1oject; ~oordination with interested public groups and individuals; Reporting to legi S 1 ature and the pub 1 icon the progress of the project;and -Cost administration and control for-procurement contracts;and -Legal costs. 1.4 -Operation,Maintenance and Repl~cement Costs The facilities and procedures for operation and maintenance of the project are described in the Susitna Feasibil ity Report (Acres 1982a, Vol.1).Assumptions for the size and extent of these facilities have been made on the basis of experience at large hydroelectric developments in northern climates.The annual costs for operation and maintenance for the Watana development have been estimated at $10.4 million.When Devil Canyon is brought on line these costs increase to $15.2 million per annum.Interirl replacement costs have been estimated at .3 percent per annum of the capi tal cost. The breakdown in Table 0.5 is provided in support,of the allowance used in the finance/economic analysis of the Sus;tna Hydroelectric Project. It ;s based on an operating pl aninvol ving fUll staff;ng of power pl ant 1"1r1 1'1 f:>' ·Ci·.'i r-',- " f f f l., il f t t t l I I - J i) j, Ir I I I I I I I.I I I ____,,_,rt i ¥ l'!_..- and permanent town site support personnel.A total of 105 wi 11 be employed for Watana,with another 25 to be added when Devil Canyon comes on line.Th1S manpower level will provide manned supervisory staff on a 24-hour,three-shift basis,with maintenance crews to handle all but major overhauls.A nominal allowance has been made for major maintenance work which would utilize contracted labor.It;s unlikely that major overhau1 s wi 11 be necessary in the first ten years of project operation.In earlier years,this allowance is a prudent provision for unexpected start up costs over and above those covered bywarranty. Allowance for contracted services al so covers hel icopter operations and access road snow clearing and maintenance. Allowances have also been made for environmental mitigation as well as a contingency for unforeseen costs. Estimates for Susitna have been based on original estimates and actual experience at Churchill Falls.It should be realizeg that alternative operating plans are possible which would eliminate the need for permanent town site facilities and rely on more remote supervisory systems and/or operations/maintenance crews transported to the pl ant on a rotating shift basis.Cost implications of these alternatives have not yet been examined. D-1 ..11 (Revi.sed 7/11/83) 1.5 -Allowance for Funds Used During Construction (AFDC) At current levels of interest rates,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 the Susitna project the low real rates of interest assumed woul d have a much reduced impact on assumed proj ect development costs.Furthermore,direct state involvement in financing of the Susitna project will also have a significant impact on the amount,if any,of AFDC.Provisions for AFDC at appropriate rates of interest are made in the economic and financial analyses included inthisExhibit. Interest and escalation were calculated as a percent of the total capital costs of the project at the start of construction.The method used for calcul ating the effects of interest and escal ation during construction ;s documented in Phung 1978& An S-shaped symmetric cash flow was adopted where: r; f f: f rr 1 f f ( r t L t l ij i i I J " 1 1 -.,--,---2--..-'2~+B 1n (l+f)] Gl+f~-1 ~1n (l+f) where 1 +f =(1 +X)B co 1 +f co =Total cost upon commercial service expressed as a multiplier of construction cost. x =effective interest rate Y =escal ation rate c =construction period The value of the variables used in the computations'are summarized in Table 0.6.The Watana and Devil Canyon constructions periods were taken from Exhibit C as 8.5 years and 7.5 years,respectively. The resultant total project cost was then calculated for each interest/e.scalation scenario used in OGP-6 economic and financial studies.Interest and escalation were calculated as a percent of annual capital expenditure for the financi al analysi s as shown inTab1e0.1. 1.6 -Escalation. All construction costs presented in this Exhibit are at January 1982 levels and consequently inclUde no allowance for future cost es!calation..Thus,these costs would not be representative of actual construction Wld procurement bid prices"This is because provision must be.made in such bids for continuing escal ation of costs,and the extent and variation of escalation which might take place ov~r the lengthy construction periods involved..Economic and financial evaluations take full account of such escalation at appropriate rates as discussed in the previous paragraph. 1.7 -Cash Flow and Mane,ower Loading Requirements The cash flow requirements for construction of Watana and Devil Canyon are an essenti al input to economic and financi al pl anning studi es.The bases for the cash flow are the construct;on cost estimates in January 1982 dollars and the construction schedules presented in Exhibit C~with no provision being made as such for escalation.The cash flow estimates were computed on a'l annual basis and do not include adjustments for advanced payments for mobilization or for holdbacks on construction contracts.The results are presented in Table D.7 and Figures 0.1 through 0.3.The manpower loading requirements were developed fY'om cash flow projections.These curves were used as the basis for -camp loading 'and associated socioeconomicimpactstudies. 1 +\(1 +f =v 1 +x D-l~12 (Revised 7/11/8 P' ri< r r rf f r f f I I ! nJ ! i' I I I, I) - - ,Mt·....1lI \\ 0-1 ...13 An independent check estimate v.'lS undertaken by EBASCO Services IncorpDJ~ted (EBASCO 1982)0 The estimate was based on engineering drawings,technical information and quan~ities prepared by Acres American in the feasibility study.Major quantity items were checked. The EBASCO check estimated capital cost was approximately 7 percent above the Acres estimate. A summary of EBASCO's check estimate has been included in Table 0.9 of thi s exhi bit. 1.8 -Contingency An overall contingency allowance of approximately 15 percent of construction costs has been included ~n the cost estimates .. Contingencies have been assessed for each account and ran~e from 10 to 20 percent.The contingency is estimated to include cost increases which may -occur in the detailed engineering phase of 'the project after more comprehensive site investigations and final d,;signs have been camp 1eted and after the req·~i rem~nts of vari ous concerned agenci es have been satisfied.The contingency estimate also includes allowances for inherent uncertainties in costs of labor,equipment and materials,and for unforeseen conditions which may be encountered during constructi·on. Escal ation in costs due to infl ation is not incl uded <>No allowance has been included for costs associated with significant delays in project implementation.These items have been accounted for in economic and financi al pl anning studies. 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 1ioes"The line wi 11 be energized initiallY at 138 kV in 1984 and will operate at 345 kV after the Watana phase of the Susitna project is complete. The current estimate for the completed intertie is $130.8 million. This cost ;s not included in the Susitna project cost estimates.A breakout of the cost estimate is shown in Table 0.8. 1.10 -EBASCO Check Estimate . •J11 •••rllrl••"._ r i [ ) r \ r (:. f r rl r I: - 2 -ES ITMATED ANNUAL PROJECT COSTS-=-_~-.:kii.---e-'...--~s··-_";";;.~..;;;.."....;._ The cost of the:proj ect has been est i mated by twa method s..In the first ~the cost of energy.was determined by preparing a financialfOl~ecast for the project assuming 100 percent debt financing.Table 10She~~1 to 4 shows the projected .year:-?l ..year ener~y trends of !,~e proJect and a sUmmary of revenue (RL516),operatlng costs (J.7u):t interest t a'1d cash sources and uses,1"'hese costs ~re in nominal dollars assuming:percent inflation and 10 per~ent cost of capital" Costs are based on power sales at.cost assuming 100 percent debt financing at 10 percent.interest.Th.is results in a nominal cost of power of 298 mills ;n 1994 (first full year of Watana)and 350 mills in 2003 (first full year of Wa,tana and Devil Canyon)as shown online 520 of the table.The real cost of power,adj usted for infl ation of 'I percent per annum,would.be 128 mills in 1994 and 82 mills in 2003 and would then fall progressively for the remaining life of the project $ The annual cost of energy from the project for the period 1993 to 2021 in nominal dollars and real dollars is shown on Sheets 5 and 6, respectively,of Table 10" The cost of power (capacity)from the project ;s shown on Tab 1e 0-11.. Th;s cost is determined in accordance with FERC procedures and is the sum of the annual plant investment cnst and the annual fixed operating cost.As can be seen from Table Dell,the total annual capacity cost in 1982 dollars is $225/kW. No taxes have been assessed to the project t s annual costs.Although these tax,es would be expressed as a percentage of project pl ant in service ;n this type of annual cost estimate)the taxes would be based on revenues.As a corporation of the State~the Alaska Power Authority is a not-far-profit entity.As Such the Authority would not be subject to a revenue tax. - 0-2-1 (Revised) 0-3-1 (Revised 7/11/83) 3.2 ...Re_gional Electric Power Demand and Supply The Reference Case forecast of el ectric power dema:ld is presented in Exhibit B.The results of studies presented in Exhibit B and Section 4 of the Exhibit call forWatana to come into operation in 1993 and to deliver a full year's energy generation 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 Susitna are shown in Figure 0.4. 3,3 -Market and Price for Watana Output in 1994 It is anticipated that Watana energy will be supplied at a single' wholesale rate to Railbelt utilities at a level to permit the maximum use of the Sus i tn a Proj ect,thus achi evi ng its full econom ic benefi t • This requires,in effect,that Susitna energy be priced so that it is attractive even to utilities with the lowest cost alternative source of energy.In evaluating the terms of power sales contracts,utilitie;, can be expected to consider the advantages afforded by Susitna's long-term price stability,as well as the price offered in the initial years.That wholesale price at \\'hich consumers would be neither better nor worse off in 1994 under the with-Susitna plan or the best alternative plan has been selected for evaluation.The actual whOlesale price charged for Susitna energy may vary from this price 3.1 ...The Railbelt Power System The Railbelt region COvers the Anchorage-Cook Inlet area and the Fairbanks-Tanana Valley area.A complete discussion of the Railbelt System is presented in Exhibit B. Susitna capacity and energy will be partially delivered to the Region via the linkage of the Anchorage and Fairbanks systems by an intertie to be completed in the mid-1980s.The intertie will allow a capacity transfer of up to 70 MW in either direction..The interconnection is designed for init'~al operation at 138 kV with sUbsequent uprating to 345 i<V allowing the line to be integrated into the Susitna transmission fac;1 iti es. 3 -MARKET VALUE OF PROJECT POWER This section presents an assessment of rates at which energy and capacity of the Susitna development could be priced,together with a proposed basis for contracting for the supply of Susitna energy.Both the marketing approach and financing plan are the subjects of ongoing r~view and development"The SU,sitna project is scheduled to .begin generating power for the Railbelt in 1993.At that time the project will meet growing electrical demand,replace retiring units and disp 1ace capac ity having more expens;ve runn;n9 rates .. rF \ r f I, " r l t fi' I f I~~' i t 1 1: l n l r r; f" r~ f [ [ ( f, t L 1 J t f j 1 [ l~ depending on the course of power sal es contract negoti ations and On the further development of the marketing approach. This estimated 1994 price is based on calculations using the financial parameters in Table 0.12,Refer~ence Case fuel prices discussed in Section 4.5 s and a prevailing 7 percent rate of inflation per annum. The most cost effective witbout-Susitna pl an from which the estimated 1994 price is derived is specified in Seeton 4.6.The associated plant capital and operating costs are shown in Table 0.18. In order to determine the cost of the alternative thermal capacity and energy which would replace Susitna generation,the cost of thermal generat.i on under the with Susitna pl an was subtracted from the cost of thermal generation under the without Susitna plan.This avoided thermal cost which would be replaced by Susitna generation is shown on Figure 5"The costs shown are expressed in mi 11 s per kilowatt-hour which ;s the total avoided thermal cost divided by the Susitna energy output ina given year.In 1994 this cost is estimated at 136 mills/kWh in nominal dollars. The financing consideY'ations under which it would be appropriate for Watana energy to be sold at apprOXimately 136 mills per kWh price are considered in Section 6 of this Exhibit. The Power Authority wi'll seek to contract with Railbelt utilities for the purchase of Susitna capacity and energy on a basi s appropri ate to support financing of the project"Pricing policies for Susitna output will~e constrained both by cost and by the price of energy from the best alternative option. 3.4 -Market and Price for Watana Output 1995-2001 After its first full year of operation in the system in 1994,2957 GWh of the total 3105 GWh ofWatana output is initially marketable. D-3-2 (ReVised 7/11/83) I I I~I - 3.5 -Market and Price forWatana and Devil Canyon Output in 2003 After the Devil Canyon project comes on line,the Susitna project will provide about 90 percent of the energy demand.The avoi ded thermal costs in 2003 is 230 mills per kWh (2003 dollars,7 percent annual escal ation)as shown on Figure 0.5.The excess Susitn'a power occurs in the summer while additional energy from other resources is required in the winter.The generating resources displaced are units nearing reti rement and wi 11 be used as reserve capac i ty. The excess energy occurs in the summer.The market for the project strengthens over the years to 2001 since energy demand wi 11 increase by 16 percent over this period as projected in the Reference Case forecast.Fi gure D.5 shows the avo;ded cost of energy for the peri od 1995 to 2001. 0-3-3 (Revised 7/11/83) The addition of the Susitna'project will add a laf\'ge generating resource in the system in 1993,displacing a significant amount of the ex.isting generating resources in the system.The project will provide about 70 percent of total energy demand.The di sp 1aced un i ts wi 11 be used as reserve capac i ty and to meet grow;ng load unt i1 the Dev i 1 Canyon project cQmes on line.This effect isi11ustrated on Figure0.4. 3.6 -Potential Impact of State Appropriations In the preceding paragr'aphs,the price facing Railbelt uti'lities in the absence of Susitna has been identified.Sale of Susitilll energy at thi s pri ce wi 11 depend unon the magni tude of any proposed state appropriation and upon the willingness of Rai1belt utilities to pay an appropriate rate in light of the project's long-term benefits. Based on the assessment of the market for power and energy output from the Susitna Hydroelectric Project,it has been concluded that,with the appropriate level of state appropriation a viable basis exists for the Susitna Power to be absorbed by the Railbelt utilities. r' fl r' r~ r·' " f f f r r t I 1 J t t t L~ tl D...4-1 (Rev;.sed 7/11/83) 4 -EVALUATION OF ALTERNATIVE ENERGY PLANS 4 ..1 -General . The following presentation focuses primarily on the Susitna Feasibility Study process and findings.A separate section provides findings of the Battelle stUdy. This section describes the process of assembling the information necessary to carry'out the systemwide generation pl anning studies for assessment of the economic feasibility of the Susitna project .. Included is a discussion of the existing system characteri-stics,the planned Anchorage-Fairbanks intertie,and details of various generating options including hydr.oelectric and thermal.Performance and cost information required for the generatio.n planning studies is presented for the hydroelectric and thermal generation options considered. The approach taken in economically evaluating the Susitna project involved the deveiopment of long-term generation pl ans for the Railbelt el ectri cal supply system wi th and wi thout the proposed proj ect .In order to compare the with-and-without pl ans,the cost of the pl anS were compared on a present worth basis.A generation planning model which simul ated the operation of the system annually was used to project the annual generation costs. During the pre-l icense phase of the Susitna project planning,two studies proceeded in parallel which addressed the alternatives in generating power in the Al aska Railbelt.These studies are the Susitna Hydroelectric Project Feasibil ity Study sponsored by the Alaska Power Authority and the Railbelt Electric Power Alternatives Study sponsot"ed by the Office of the Governor,State of Alaska. The objective of the Susitna Feasibility Study was to deter-mine the feasibility of the proposed project.The economic evaluations performed during the study found the project to be feasible as documented in this exhibit.The Railbelt study focused on the feasibility of all possible generating and conservation alternatives. Although the studies 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 into a pl an context and their economic performance compared by comparing costs of the pl ans. r r f f". r f f I 1 f f 1 1 1 I Ij !1,;- I j 30 years 35 years 20 year:) 30 years 30 years 30 years 50 years - .. D-4~2 (ReVised 7/11/83) -Large Coal-Fired Steam Turbines (>100 MW): -Small Coal-Fired Steam Turbines «100 MW): -Oil-Fired Gas Turbines: -Diesel s: -Natural Gas-Fired Gas Turbines: -Combined Cycle Units: -Conventional hydro: 4 ..2 -Existing System Characteristics (a)System Oeseri pti on The two major load centers of the Railbelt regi.on are the Anchorage-Cook Inlet area and the Fairbanks-Tanana Valley area which at present operate independently.The existing transmission system between Anchorage and Wi 11 ow cons i st s of a network of 115 kV and 138 kV lines with interconnection to Palmer.Fairbanks is primari ly served by a 138 kV line from the 28 MW coal-fired pl ant at Healy.Communities between Willow and Healy are served by local distribution. Table 0.13 summarizes the total generating capacity within the Railbelt system in 1982,based on information provided by Railbelt uti 1it;es and other sources.Tabl e 0.14 presents the resulting detailed listing of units currently operating in the Railbelt, information on their performance characteristics,and their on-line and projected retirement dates for generation pl anning purposes.The total Railbelt installed capacity of 1122.8 MW consists of two hydroelectric plants totaling 46 MH plus 1076.8 MW of thermal generation units fired by oil,gas,or coal,as summari zed in Tab leD .14. (b)Retirement Schedule In order to establish a retirement policy for the.existing generating units,several sources were consulted,including the Power Authority's draft feasibility study guidelines,FERC guidelines (FERC 1979L,the Battelle Railbelt Alternatives Study ('Battelle 1982),and historical records.Utilities,particularly those in the Fairbanks area,were al so consulted.Based on these sources,the following retirement periods of operation were adopted for use in thi~analysis: r--; 1 r ! r I f i l J" ~ ; ~ r. I\, Ij!,.._.~,,"~-,..-.-._-,.,,~~-_.~"..._,-~-~--,~."".,,~_.,._.._,.__._,~~-~,.~.~_.,--.·_·-..~_....A.._.._~~;__~_.n •__.~_.._..~_.•.-:.....~_..._.,~-~_""::''---''''~_'_---~--~.._-:''-:'''''~_.~--'''':'''..-.-L..-_,,,---:';';~~;>L I t 0 I ....«tn.·.ii (c)Schedu'le of Additions 0-4-3 (Revised 7/11/83) Tab 1e D.14 lists the service dates for each of the current generating units which would be retired bas.ed on the above retirement policy. . Two new projects are assumed to be added to the Railbelt system prior,'to 1990,as shown in Table D,,15~The Alaska Power Authority is conducting a feasibil'ity study of the Bradley Lake Hydroelectric Project on the Kenai Peninsula.If the project is determined to be feasible the APA will take steps to build the project.For analysis purposes,the project is assumed to provide 90 MW of generating capacity and 347 GWh of annual energy,and to be in service by 1988. Feasibility study of the Grant Lake Project has been completed by APA recently.Thi s project is pl anned to serve the City of Seward,and to provide 7 MW of generating capacity and 33 GWh of annual energy..For the purpose of analysis,this project is assumed to be in service by 1988 also. In addition,Fairbanks Municipal Util ity Systems is considering the addition of a 25-30 MW cogeneration unit to replace Chena Units 1,2 and 3;however,these pl ans are not defi nite. 4.3 -Fairbanks -Anchorage Intertie Engineering studies have been undertaken,eqUipment has been purchased and construction contracts have been let for construction of an interti e between the Anchorage and I.='airbanks systems.Thi s connection will involve a 345 kV transmission line between Willow and Healy scheduled for completion in 1984.The line will initially be operated at 138 kV with capability of expansion as the loads grow in the load centers. -No costs were added for combined-cycle or gas-turbine units,since they were assumed to have sufficient siting flexibil ity to be pl aced near the major transmission works; Costs of additional transmission facil ities were added to the scenarios as necessary for each unit added.In the "with SJtsitnall scenarios,the costs of adding circuit$to the int.ertie corridor were added to the Susitna project cost.For the non-Susitna units,transmission costs were added as follows: - A multiple coal-fired unit development in the Beluga fields was estimated to have a transmission system With security equal to that planned for Susitna,costing $220 million.';riis system would take power from the bus back to the existing load center;and r« r r' r~' r- [' r f f 1 J L , t t J D..4-4 Under Step 2 of the selection process,all feasible candidate sites were identified for inclusion in the subsequent screening exercise.A total of 91 potential sites were obtained from inventories of potential sites published in the COE National Hydropower Study and the Power Admini stration repJrt IIHydroel ec- tric Alternatives for the Alaska Railbelt.1I The screening of sites under Step 3 required a total of four successive iterations to reduce the number of alternatives to a manageable shortlist.The overall objective of this process was defined as the selection of approximately ten sites for considera- tion in plan formulation,esse.ntially on the basis of pUblished data on the sites and appropriate'ly defined criteria.Fignre D.7 shows 49 of the sites which remained after the two initi tJ screen- ings. In Step 4 of the pl an sel ection pl"ocess,the ten sites short listed under Step 3 were further refined as a basis for formul a- tion of Railbelt generation plans.Engineering Sketch-type lay- (a)Selection Process The application of the five-step methodology (~igure D.6)for sel ection of non-Susitna pl ans which ;ncorportite hydroel ectric developments is summarized in this sSGtion.The analys'is was completed in early 1981 and ;s based on January 1981 cost figures; all other parameters ale contained in the Development Selection Report (Acres 1981b).Step 1 of this process essentially established the overall objective of the exercise as the selection of an optimum Railbelt generation plan which incorporated the proposed non-Sus i tna hydroel ectri c developments for compari son with other plans. - A single coal-fired unit development in the Nenana area using coal mined in the Healy fields would require a transmission system costing $117 mi 11 ion doll ars. With the additio.n of a unit in the Fairbanks area in the 1990 's,no addit-rons to the 345 kV line were cons·idered necessary.Thus,no other transmission changes ~'1ere made to the non-Susitna plans. 4.4 -Hydroelectric Alternatives Numerous studies of hydroelectric potenti al in Al aska have been under- taken.These date as far back as 1947 and were performed by vari ous agencif:s including the then Federal Power Commission:-the Corps of Engineers,the U.S.l3ureau of Reclamation,the U.S.Geological Survey~ and the State .of Al aska.A significant amount of the identified poten- tial is located in the Railbelt region,including several sites in the Susitna River Basin. r f ¥ f l Ir ( 1 f t, [ I< W·'H« Two basic altern~tives have been identified to harness the hydrau- lic head for the generation of el ectrical energy.One.is vi a the valley of the Chakachatna River.This river runs out of the easter 1y end of the 1ake and descend s to about El ev at ion 400 where the river leaves the confines of the valley and spills out onto a broad alluvial flood plain.A maximum hydrostatic head of about 740 feet could be developed via this alternative. (b) 0-4-5 • 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 methc/ds of analysis are the same as those di scussed in Sect;on 4.5 (f;l. The results of these analyses,completed in early 1981,are sum- mar i zed in Table 0.17 and i 11 us~;rate that a mi nirnum total system cost can be achieved by the introduction of the Chakachamna, Keetn a,and Snow proj ects..Note that.further stud i es of theChakachamn~project were initi ated in mid-1981 by Bechtel for the Alaska Power Authority. (c)Lake Chakachamna Bechtel Civil and Minerals studied the feasibility of developing the power potential of Lake Chakachamna (Bechtel C'lvil and Minerals 1981).The lake is on the west side of Cook Inlet 85 mi 1es west of Anchorage.Its water surface 1i es at about El ev a- tion 1140. f~ r r~ r [ i I 1 r ~. i [ f. 1 J l ,.' t, "I lOr \I I I I i I t I ·1I 0-4-6 Two alignments were studied for the McArthur tunnel.The first considered the shortest distance that gave no oppor- tunity for an additional point of access during construction via an intermediate adit.The second alignment was about a mile longer,but gave an additiona.l point of access,thus reducing the lengths of headings and also the time required for construction of the tunnel.Cost comparisons neverthe- less favored the shorter 10-mile,25-foot diameter tunnel. The second al ignment running more or less parallel to the Chakachatna River in the right (southerly)wall of the valley afforded two opportunities for intermediate access adits.These,pl us the upstream and downstream portal s would allow construction to proceed simultaneously in six headings and reduce the construction time by 18 months from that required for the McArthur tunnel. If all the contrOlled water were used for power generation, the McArthur powerhouse could support 400 MW installed capacity and produce average annual firm energy of 1753 GWh. Making a provisional reservation of approximately 19 percent of the average annual inflow to the lake for instream flow rE;qtiirements in the Chakachatna Rivet..reduced the economic tunnel di ameter to 23 feet..The install ed capacity in the powerhouSe would then be reduced to 330 MW and the average annual firm energy to 1446MW. For the Chakachatna powerhouse,diversion of all the con- trolled water for power generat;onwould sUpport an in- stalled capacity of 300 MW with an average annual firm energy generation of 1314 GWh.Prov;s·ional reservation of (i)Project Layo~ The Bechtel study evaluated the merits of developing the power potential by diversion of water southeasterly to the McArthur River viaa tunnel about 10 miles long,or easterly down the Chakachatna valley either by a tunnel about 12 mi.l es long or by a dam and tunnel development.Few sites, adverse foundati on conditi ons,the need for a 1arge capaci ty spi llway and the nearby presence of an active volcano made it evident that the feasibil ity of constructing a dam in the Chakachatna valley would be problematical.The main thrust of the initial study was therefore directed toward the tun- nel alternatives. The other alternative calls for development by diversion of the lake outflow to the valley of the McArthur River which lies to the southeast of the lake outlet.A maximum hydrostatic head of about 960 feet could be harnessed by this diversion~ v'"-- ,.- r r' [ ! r r r r f~ 1 1 1 I { f ( [ I J;, -" ,f'l ~ o 0...4...7 Diversion of f10w from Chakachamna Lake to the McArthur valley to develop a head of apprOXimately 900 feet has been identified as the most advantageous with respect to energy production and cost. The ge!>logic conditions for the various project facilities including intake,power tunnel,and powerhouse appear to be favorable based on a 1981 field reconnaissance..No insurmountable engineering problems appear to exist in development of the project. Alternative A,;n which essentially all stored water would be diverted form Chakachamna Lake for power production purposes,could del iver 1664 GWh of firm energy per year to Anchorage and prov i de 400 MW of pe aki ng capac i ty • However,since the flow of the Chakachatna River below the lake outlet would be adversely affected,the ex i st1ng anadromous fishery resource Which uses the river toga<jn entry to the lake and its tributaries for spawning would be lost.In add it ion,the fi sh wh i ch spawn in the lower Chakachatn a Ri ver woul d al so be impacted due to the much reduced river flow.For this reason,Alternative B has been developed,with essentially the same project arrange- approXimately 0.8 percent of the average annual inflow to the lake for instream flow requirements in the Chakacha,tna River was regarded as having negligible effect on the install:ed capacity and average annual firm energy because that reduction is within the accuracy of the Bechtel study. (ii)Technical Evaluation and Discussion Several alternative methods of developing the project have been identified and reviewed.Based on the analyses per- formed,the more viable alternatives have been identified by Bechtel for further study .. -Chakachatna Dam Alternative The construction of a dam in the Chakachatna River canyon approx imatel y 6 m;1es downstream from the 1ake outl et does not appear to be a reasonable alternative.While the site is topographically suitable~the f0undation conditions in the river valley and left abutment are poor.Furthermore, its environmental impact specifically on the fiSheries resource will be significant (although provision of fish passage facilities could mitigate this impact to a certain extent).. -McArthur Tunnel Alternatives A and B l' r r r I r ( r r r [ I J 1 I L [ J An alternative to the development of this hydroelectric resource by diversion of flows from Chakachamna Lake to the McArthur River is constructi ng a tunnel through the ri ght wall of the Chakachatna valley and locating the powerhouse near the downstream end of the vall ey.The general 1ayout of the project would be simil ar to that of Alternatives A and B for a slightly longer power tunnel. The geologic conditions for the various project features incl uding intake,power tunnel,and powerhouse appe~t'to be favorable and very similai to those of Alternatives A and B.Similarly,no insurmountable engineering problems appear to exist ;n development of the project. Alternative C,in which essenti ally all stored water is diverted from Chakachamna Lake for power production,could del iver 1248 GWh of firm energy per year to Anchorage and provide 300 MW of peaking capability.While the river flow in the Chakachatna River below the powerhouse at the end of the canyon wi 11 not be substanti ally affected,the fact that no rel eases are provided into the ri ver at the lake outlet willcausG a substantial impact on the anadromous fi sh 'ftJi ch normally enter the 1ake and pass throuah it to the upstream tributaries.Alternative D was therefore proposed in which a release of 30 cfs is maintained at the lake outlet to facilitate fish passage through the canyon section into the lake.In either of Alternatives C or 0 the environmental impact would be limited to the Chakachatna River as opposed to Alternatives A and 8 in which both the Chakachatna and McArthur Rivers would be affected ..::Si'rlce the instream flow rel ease for Al te~nati veoislessthan1percentofthetotalavaflableflow,the power production of Alternative 0 can be regarded as being the same as the Alternative C (300 MW peaking capability, 0..4-8 ment except that approximatel y 19 percent of the average annual flow into Chakachamna Lake would be rel eased into the Chakacha,tna River below the lake outlet to maintain the fishery resource.Because of the smaller flow available for power production,the installed,capacity.of the project would be reduced to 330 MW and the firm energy del ivered to Anchorage would be 1374 GWh per year. ObviouslY~the long-term environmental impacts of th,~ project in this Alternative B are significantly reduced compared to Alternative A,since.the.river flow is maintined,al beit at a reduced amount.Estimated proj ect costs for Alternatives A and Bare $1.5 billion and $1.45 billion,respectively. -Chakachatna Tunnel Alternatives C and 0 I l f i r l r [ r~ r r- r As such,a screen ;09 process was therefore cons;dered unnecessary in this study,and emphasis was placed on selecti.on of unit sizes appropriate for inclusion ;n the generation planning exercise. For analysis purposes the follOWing types of thermal power generation units were considered: 1248 GWh of firm energy del ivered to Anchorage). Estimated project costs for Alternatives C and 0 are $1.6 billi.on and $1,,65 billion,respectively. 4.5 -Thermal Options ..Development Selection As discussed earlier in this section,the major portion of generating ct1pability in the Railbelt is currently thermal,principally natural gas with some coal-and oil-fired installations.There is no doubt that the future electric energy demand in the Railbelt could be satis- fied by an all-thermal generation mix.In the following paragraphs,an outl ine is presented of the analysi s undertaken in the feasibi 1 ity study to determine an appropri ate all-thermal generat ion scenari 0 for comparison with the Susitna hydroelectric scenario. (a)Assessment of Thermal A1ternat i ves The overall objective established for this selection process was the selection of an optimum all-thermal Railbeltgeneration plan for compari son wi th other plans (Figure D.8)• -Coal-fired steam -Gas-fired combined-cycle -Gas-fired gas turbine -Diesel. The following paragraphs present the thermal options used in developing the present without-Susitna plan. (b)Coal-Fired Steam A coal-fired steam plant is one in which steam is generated by a Primary consideration was given to gas-,coal-,and oil-fired generation sources which arE!the most readily developable alterna- tives in the Railbelt from the standpoint of technical and eco- nomic feasibil ity.The broader perspectives of other alternative resources such as peat,refuse,geothermal,wi nd and so 1 ar and the relevant environmental,social,and other issues involved were addressed in the Batte 11 e Btl tern at i ves study (Battel 1e 1982). - l J' r r- ( [ r r r r r f I J L f. L f b, 1 0-4-10 (Revised,7/11/83) (i)Capital Costs A detailed cost study was done by EBASCO Services Incorpor- ated as part of Battelle's alternatives study (Battelle 1982,Vol.XII).The report found that it was feasible to establish a plant at either the undeveloped Beluga 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 involve an average construction period cf five to six yearse Capital costs and operating parameters are defined for coal and other thermal generati ng pl ants in Tab leD .180 Cost estimates by maj or account are presented in Tables D.19 and 0.20. 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,two units would be developed near Nenana to service the Fairbanks load center, with the remaining units placed in the Beluga fields. To satisfy the nationa1 New Performance Standards,the cap- ital costs incorporate provision for installation of flue gas desulfurization for sulphur control,highly effic;'ent combustion technology for control of nitrogen acids,and baghouses for particulate removal. (ii)Fuel Costs Coal in the Railbelt in quantities sufficient for electric power generation is availab'le from the Nenana Field near Healy anG the Beluga Field near Anchorage.The analysis presented in Appendix D-1 developed the base cost of coal from these sources,transportation costs,if required,and real pri ce escal at i on rates. For the purposes of the economic analysis,it was assumed that up to two 200-MW coal"'fired steam units would be located at Nenana,rather than at mine-mouth,due to the mine's proximity to Denal i.National Park.A mine-mouth coal-fired boiler and used to drive a steam-turbine generator. Cooling of these units is accomplished by steam condensation in cooling towers or by direct water cooling. Aside from the military power plant at Fort Wainwright.and the self-supplied generation at the University of Alaska,there are currently two coal-fired steam plant's in operation in the Rail- belt.These plants are small compared with most new plants installed to meet base load in the lower 48 states and new plants being considered for the railbelt thermal generation alternatives. o r l r 1. I f [ [ ! [ [ I I t t l L t wew 0-4 ..10 (Revised~7/11/83) (i)Capital Costs A detailed cost study was done by EBASCO Services Incorpor- ated as part of Battelle's alternatives study (Battelle 1982,Vol.XII).The report found that it was feasible to establish a plant at either the undeveloped Beluga field or near Nenana,using Healy field coal.The stUdy produced costs and operati ng character;sties for both pl ants.All new coal units were estimated to have an average heat rate of 10,000 Btu/kWh and involve an average construction period of five to six years.Capital costs and operating parameters are defined for coal and other thermal generating plants in Table 0.18.Cost f~stimates by major account are presented ;n Tables D.19 and 0.20. It was found that,rather than develop solely at one field in the nnn-Susitna case,devel opment \~ould be li kely to take place in both f~elds.Thus,two units would be developed near Nenana to service the Fairbanks load center, with the remaining units placed in the Bel uga fields. To satiSfy the nationa1 New Performance Standards,the cap- ital costs incorporate prOVision for installation of fl ue gas desulfurization for sulphur control,highly efficient combustion technulogy for control of nitrogen acids,and baghouses for particulate removal. (;i)Fue',Costs Coal in the Railbelt in quantities sufficient for electric power generation is available from the Nenana Field near Heal y and the Beluga Fi el d near Anchorage.The anal ysi s presented in Appendix 0-1 developed the base cost of coal from thesl:sources,transportation costs,if required,and real price escal ation rates. For the purposes of the economic analysis,it was assumed that up to two 200-MW coal-fired steam units would be located at Nenana,rather than at mine-mouth,due to the mine's proximity to Denal i.National Park.A mine-mouth coal-fired boiler and used to drive a steam-turbine generator. Cool ing of these units is accompl ished by steam condensation in cooling towers or by direct water cooling. Aside from the military power plant at Fort Wainwright and the self-supplied generation at the University of Alaska,there are currently two coal-fired steQrn plant's in operation in the Rail- bel t.These pl ants are small compared wi th most new pl ants installed to meet base load in the lower 48 states and new plants being considered for the railbelt thermal generation alternatives. I' [ r r [ r 1 , t t l L t price of $1.40/MMBtu in'1983 dollars was estimated for Nenana coal-based on current contrlcts with Golden Valley Electric Association and Fairbanks Municipal Util ity Systems adj usted for changes in prod ucti on leve~s and new 1 and recl aimation regul ations.Transportation costs to Nenana.are estimated to be $0.32/MMBtu in 1983 doll ars. Therefore,the total cost of the coal delivered in Nenana would be $1.72/MMBtu.The coal has an average heat content of about 7800 Btu/lb. D-4-11 (ReVised 7/11183) Agreements between coal suppliers and electric utilities for the sale/purchase of coal are usually long term contracts which incl ude a base price for the coal and a method of escal ation to provide prices in future years. The base price provides for recovery of the capital investment,profit,.and operating and maintenance costs at the level in existence when the contract is executed.The intent of the escalation mechanism is to recover actual increases in labor and material costs from operation and maintenance of the mine.Typically the escal ation mechanism consists of an index or combination of indexes such as the producer price index,various commcdity and labor indexes,the consumer price index applied to operating and maintenance expenses,and or regulation rel ated indices.The original capital investment is not esca1 ated,so the base price of coal to the uti lity tends to increase with general inflation. Several escal ation rates have been estimated for util tty coal in Al aska and in the lower 48 states,and they range from 2.0-2.7%/year (real).Several more generic rates have also been developed by Sherman H.Clark and Associates and by Data Resources Inc.(DRI)"Because the forecasts of DRI and Sherman H.Cl ark are based upon supply-demand factors, they were appl ied to the base contract price of coal.The 2.6%real rate of increase used by DR!and Sherman H.Cl ark is appl ied to the mine-mvuth price of Nenana Fiel d coal as this mine is used principally to supply domestic malrkets. It should be noted 9 tlowever,that this is the price before transport.Transportation costs over-time are assumed to increase at O.9%/yr.The overall real compos;te rate of escal ation incl uding transportation for coal consumed in a generating plant loc.ated at Nenana is 2.3%/yr. Other than the two 200-MW units installed at Nenan~,all other coal-fi red un its wi 11 be mine-mouth un its install ed at Bel u9 a.The base pri ce of coal has been determi ned under the assumption of an export market and was calculated as the net back cost in Alaska based on the value of coal in Japan as described in Appendix 0-1.This cost is $1~86/ MMBtu at 1983 price level s for coal wi th a heat content of about 7BOO Btu/lb. J' r r r J r r r f r [ I J 1. I I. f 'I I I I' I An escalation rate of 1.6%!yr.of the price of Beluga coal is based on escal ation rates developed by DRI and Sherman H.Clark for coal exported to Pacific.Rim countries. Both Nenana and Beluga coa1 prices have been assumed to escalate to the da~e a given generating unit ~nters operation.At that time,the coal price for that unit is assumed to remain constant in real terms until the un it ;s replaced.Using this approach the average coal price escal ation rate for the Reference Case all thermal generation alternative is about l%!yr. The coal escal ation rates di scussed above were used for the reference case and the DR!sensiti vity case.Zero real price escalation of coal was assumed for the DOR-mean and -2 percent sensitivity cases. (iii)Other Performance Characteristics 0-4-12 (ReVised 7/11/83) (i)~pital Costs A new combined cycle plant unit size of 200-MW capacity was considered to be representative of future additions to S?:-'2rating capability in the Anchorage area.This is based on economic si zing for pl ants in the lower 48 states and projected load increases in the Railbelt.A heat rC\te of BOOO/Btu/kWh was adopted based on the al ternative study completed by Battelle. The cap'j tal cost was est;mated us i n9 the Batte.ll e stUdy basis (Battele 19B2~Vol.XXXI)and is listed in Table 0.18.A bid line item cost is shown on Table 21. Annual operation and maintenance and represl1ntative forced outage rates are shown in Table 0.18. (c)Combined Cycle Combined cycle plants ilchieve higher efficiencies than conventional gas turbines.There ar'e two combined cycle plants in Alaska at present.One is the 139-MW G.M. Surl ivan pl ant of Anchorage-Municipal Light and Power (Af~LP).The other is the Beluga No.8 unit owned by Chugach Electric tssociation (CEA).It is a 42-MW steam turbine,which was added to the system in late 1982,and utilizes heat from currently operating gas turbine units s Bel uga Nos.6 and 7. [ f [ r r I I l. r r r r [ I j l I [ I \) Ij -J - '~' o Fuel Costs- D-4-13 (Revised 7/11/83) The future consumption of Cook Inlet gas depends on the gas needs of the major users and their abil ity to contract for needed supplies.Since there is a limited quantity of proven gas and estimated undi scovered reserves ':n the Cook 1'nlet area,reserves will be exhausted at some item in the The availability,use,and price of natural gas are presented in Appendix D-1.Known recover abl e reserves of natural gas in Al aska are located in the Cook Inlet area near Anchorage tand on Al aska J s North 51 ope at prudhoe Bay. Gas is presently being produced from the Cook In1 et area. Some of the gas is committed under firm contract but considerable quantities of gas remain uncommitted and could be used for power gener at ion.,There are sobst ant i a1 recoverable reserves on the North Slope that coula be used for power generation,but unti 1 a pi pel inc uro e.l ectrical transmission 'line is constructed,the gas cannot be utilized"Undis-covered gas resources are believed to exist in the Cook Inlet area and alsC'in the Gulf of Alaska where no gas has been found to date. Natural gas is produc~d and used in Alaska for heating, electrical generation,liquified natural gas (LNG)export, manufacture of ammonia/urea,reinjection in the recovery of o;l~and for field operations ..Most of the production and use (other than reinjection)currently takes place in the Cook In 1et area.Cook In let gas that has been inj ected (or actually reinjected)'is not consumed and is still available for heating,electrical generation,or other uses.Gas used in field operations is "the gas consumed at the wells and gathering areas to assist in the lifting and production of ()i1 and gas" LNG sal es are for export to Japan and the manufactured ammonia/urea is exportf~d to the lower forty-eight states. Both uses of gas have been fairly constantc in the past and clre expected to remain So in future years.Natural gas is used for el ectrical generation by Chugach El ec·tric Plss':lciation and Anchorage Municipal Light and Power.The use of gas by both of these utilities has been increasing to meet increases in electrical load and to replace oil·fired generation.The military bases in the Anchorage arl~a,Elmendorf AFB and Fort Richardson,use gas to generate electricity and to provide steall for heating.The mil itary gas use has been fairly constant in the past and i~,)expected to remain so in the future.The gas utility sales are made principally by Enstar and are for space and water heating and other uses by residential,commerical,and ~ndustrial customers. (ii) r l f r r I fl r r r [ I 1 J I I i ( I D-4-14 (Rev i sed 7/11/83). ()o future.To estimate the quantity of Cook Inlet gas available for electrical generation,the requirements and prioritites of the major users are discussed ;n Appendix D-1.Natural gas consumption for electric generation represents only a small portion of the total Cook Inlet gas consumption.It is projected that,by the year 2005,only about 8 percent of the total cumul ative 'consumption of natural gas would have been for electric generation based on the all thermal generation alternative for the Reference Case., If other gas consumption by retail sales,and cmmonia and gas conversion,continues at the projected rates j the proven reserves pl us the mean of the und i sCCJvered reserves estimates wi 11 be exhausted by 2010.The proven reserves by t.hemselves will be exhausted by 2000.This is true for any of the world oil price forecast scenarios studied. There is no single market price of gas in Al aska since a well developed market does not exist.In addition,the price of gas is affected by regulation via the Natural Gas Policy Act of 1978 (NGPA)which specifies maximum wellhead pri ces that prod ucers can chat~ge for vari ous categori es of gas (some categories will be deregulated in 1985).There are now some existing .contracts for the sale/purchase of Cook Inlet gas which specify well head prices,but since there are no existing contracts for the sale of North Slope gas,the North Slope wellhead price can only be estimated based on an estimated final sales price and the estimated costs to de.l iver the gas to market. The wellhead price agreed on in the Enstar contracts is $2,,32/~icf with an additional charge of $O.35/Mcf beginning ;n 1986.Estimated severance taxes of $0.15/Mcf and a fi xed pi pe 1i ne charge of abbut $0.30/Mef for pi pe 1i ne del ivery from Bel uga to Anchorage are additional costs.The pipeline charge.of $0.30/Mct will,of course,not be inrurred ff the gas ;s used at Bel uga to generate electricity.Future prices (Jan.1,1984 and on)are to be determ;led by escalating the wellhead price plus the demand charge based on the price of #2 fuel 0;1 in the year of esca1 ation versus the price on Janaury 1,1983.If it were assumed that the generating units were located at the source of gas,the Jan.1,1983 price would be $2 ..47/Mcf, as discussed in AppendiX D...1. Real .escalation of the gas price is asstmed to be dependent on the escalation of world oil prices because the current Enstar contract specifically provide';for escal ation of gas prices based on the price of No.2 fuel oil on the Kenai peninsula which is closely related to world oil prices. Real escal ation rates for the reference case are as follows: price % -4.6 .-4.7 o 3.0 2.5 - 1 ..5 1.0 Real Escal ation Rate -,~"....,",j Period 1984 1985 1986-11988 1989-2010 2011-2020 2021-2030 2031-2051 o D-4-15 (Revised 7/11/83) Gas turbine units can be operated on 0;1 as well as natural gas..The market No..2 0;1 is $6.23/MMl:Stu (1983)as discussed in Appendix D-1.The real annual growth rates in oil costs are a')so discussed in Appendix D-1. Other Performance Characteri sti cs---.-..;.-.;.;.;......;.~~..;..o..;......;;.;..;...:...;;;..;....;..,,;;;,..;...;...;;....;;;.. Annual operati.on and maintenance costs and forced outage rates are shewn ;n Table 0.18. (i i ) Real escal ation rates for the sensitivity oil forec·asts are presented in Append ix 0-1. (iii)Other Performance Characteristics Annual operation and maintenance costs,along with a representative forced outage rates,are given in Table 0.18. (i i i) (d)Gas-Turbine Gas turbines are by far the main source of thermal power generati ng resources in the Rail be 1t area at present.There are 720 MW of installed gas turbines operating on natural gas in the Anchorage area and approx imate ly 210 MW of oi l ...fired gas turbi nes supplyi ng the Fairbanks area (see Table 0.14)..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 low-cost of gas in the Anchorage area has made thi s type of generating faci 1ity cost-effecti ve for the Anchorage load center. (i).£!Ejtal Costs A unit size of 75 MW was considered to be representative of modern gas turbine plant addition in the Railbelt region. Gas turbine pl ants can be bui 1t over a two year con- struction period and new plants have an average heat rate of approx imately 12,200 Btu/kWh.The capital costs were again taken from the Battelle alternatives stUdy. Fuel Costs f t r l I I r ( I I, J ""'- I ! } r f 1/ f I ... (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 t!le continuous duty units were retired in the past several years because of high 'fuel prices.About 65 MW of diesel plant capa,city is currently available. (i)Capital Co~ts The h'igh cost of diesel fuel and low capital cost make new diesel plants most effective for emergency use or in remote areas where small loads exist.A unit size of 10MW was selected as appropriate for this type of facility,large by diEsel engine standards"Units of up to 20 MW are under construction in other areas"Potenti a11y,capital cost s av i ng s of 10-20 perc~nt caul d be real i zed by going to the larger'units.However t these larger units operate at very low speeds and may not have the rel iabil ity required if used as a major alternative for Railbelt electrical power. The capital cost was derived from "torle same source as given in Table 0.18 (Battelle 1982,Vol.IV). (ii)Fuel Costs Di esel fuel costs and growth rates are the same as oil costs for gas tUrbines. (i i i)Other Performance Characteri st ics Annual operation and maintenance costs and the forced outage rate are given;n Table 0.18. (f)Plan Formation and Evaluation f I l i The primary tool used for electric system analysis is the mathematical mOdel developed by the General Electric Company.The model is commonly known as OGP 6 or Optimized Generation Planning Model,Version 6.The general concept of the OGP program and its rela'cion.ship with other computer models used in the power market forecast is described ;n Exhibit B,Section 5.3.That section D~4-16 (Revised 7/11/83) The four unit types and si zes di scussed above were used to formulate plans for meeting future Railbelt power generation r requirements.The purpose of this study was to formulate tappropriate plai s for meeting the projected Railbelt demand on the bas is of economi c preferences. Economic evaluation of any Susitna basin development plan requires that the impact of the plan on the cost of enet'gy to the Railbelt area consumer be assessed on a systemwide basis.Since the consumer is supplied by a large number of different generating sources,it is necessary to determine the total Railbelt system cost in each case to compare the various Susitna basin development options. I r \ 1 0-4-17 (Revised 7/11/83) " deals specifically with the use of variables and assumptions in all the models to ass ure that they are cons i stent througho ut the pl anning process.As expl ained in Section 4.6~the OGP 6 model was us~d for the period 1993 ...2020.The load forecasts produced by the RE:D model were extended from 2010 to 2020 using the average annual growth for the peri od 2000 to 2010.The foll owi ng information is paraphrased from GE 1 iterature on the program .. (General Electric,1983) The OGP6 progran:was developed over ten years to combi ne the three main elements of generation expansion planning (system reli- ubiJity,operating and investment costs)and automate generation addition decision analysis.OGPo will automatically develop optimum generation expansion patterns in terms of economics,reli- ability and operation. The.OGP6 program requires an extensive system of specific data to perform its planning function.In developing an optimal plan,the program consid'ers the existing and committed units (planned and under construction)avai'lable to the syst2m and the characteris- tics of thc:;e units .including age,heat rate,size and outage rates as the base generation plan.The program then considers the given load forecast and operation criteria to determine the need for additional system capacity based on.given re.liability tri- teri a.Thi s determines IIhow much"capacity to add and "when ll 'it should be installed.If a need exists during any monthly itera- tion,the program will con~,"der additions from a list of alterna- tive.s and select the available unit best fitting the system needs. Unit selection is made by computing production costs for the system for each alternative included and comparing the results. The unit resulting;n the lowest system production costs ;s selected and added to the system.Finally,an investment cost analysis of the capital costs is completed to answer the question of "what kind ll of generation to add to the syst2m .. The model is then further used to compare al ternati ve pl ans for' meeting variable electrical demands~based on system reliability and production costs for the study period. The use of the output from the g_,leratioil planning model is.in Section 4.6{a). j J \-;;. 4.6 Without SusitnaPlan In order to analyze the economics of developing the Susitna Project.,it was necessary to analyze the co~ts of meeting the projected Alaska Railbe1t load forecast with and without the project..Thus,a plan using the identified components was developed. Using the generation planning model,a base case "without SL:sitna"plan was structured based on the Reference Case power market forecast.The input to the model included: •.The reference case load forecast (Exhibit B Section 5.4.3); -Fuel cost as specified above; ...Coal ...fired steam and gas-fired combined-cycle and combustion turb'ine units as future additions to the system; -Cnsts and characteristics of future additions as specified above; The existing system as specified and scheduled commitments listed inTables0.14 and D.15. -Fuel escalation as specified above; -Economic parameters of 3 percent interest and 0 percent general in-f1 ation; -Generation system reliability set to a loss of load probability of one day in ten years..This is a probabilistic measure of the inability of the generating system to meet projected load.One day 'in ten years is a value generally accepted in the industry for pI anning generation systems. It was found that the critical period for capacity addition to the system would be in the winter of 1992-1993.Until that time,the existing system t given the additions of tnG planned intertie and the planned units,appears to be sufficient to meet Railbelt demands. Given this information,the period of plan development using the modelwassetas1993-2020. In ear 1y years (1993-1996),the economi ca11 y preferred un its are those whi ch generate base load power •.After 400MW of this type of power in the form of coal units are added t the preference switches to gas turbine units which are used to meet seasonal (winter)peak months and daily peaking needs •..During the later years,the generating system needs capacity to.meet target rel i abi 1ity rather than to generate power continually ~,nd adds a mix of coal-fired steam,combined cycle,and gasturbineunits. D-4-18 (Revised 7/11/83) r c 59 MW 452 MW 137 MW 21 MW 317 MW 143 MW 1129 MW'/ Coal Fired Unit (MW) 1 x 200 (Beluga) 1 x 200 (Beluga) 1 x 200 (Nenana) 1 x 200 (Nenana) 1 x 200 (Beluga) 200 1 x 200 Gas-Fired Combined Cycle (MW) E-4-19 (Revised 7/11/83) '~ 1 x 70 1 x 70 1 x 70 1 x 70 1 x 70 1 x 70 1 x 70 1 x 70 1 x 70 1 x 70 ~ Gas-Fired Gas Turbine (MW)Year 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2.015 2016 2017 2018 2019 Total Coal-fired steam: Natural gas GT: Oil GT: Diesel: Natural gas CC: Hydropower: Total (including committed conditions): (b)System Additions The following was established as the non-Susitna Railbelt base plan (see Figure 0.9): (a).§ystem as of January 1993 :·.·1'.···'··", I ·1········•'f \. I \1 \1 I I I ·1'.'.i 1,I· I ;~I I '·'···1··...·.···. , ,I I I ,I c 1000 MW 840 MW o.MW o MW 200 Mt~ 143 MW • •~..~..,,'•,,,~I)I'-~,.hl .:.~r."q j ~.•"""\'~"'l!'"'..~...~,.,..',..("..~.~~.o DID ~P ..•iS~·"')Q ~._."'."• •~'"1 "'~J.;.""'\£\'..0.0'O..r oJ:!'"'..-/~.......~ c....#'I .".f:)•..•of 0*l,""h I •IE ..."",'.•".."la...J III -l}\,J.I ~""1 .,..\oJ'0;....,.,~.~.,..~'..... Coal-fired steam: Natural gas GT: Oil GT: Diesel: Natural gas CC: Hydropower: (c)System as of 2020 0-4-20 (Revised 7/11J83) ,...,.'......2ij-,.,...,..,,. ......0 ..';....,. 4.7 -Economic Eva]uation This section provides a discussion of the key economic parameteps used in the study and develops the net economic benefi ts stemming from the SusitnaHydro~lectrlc Project~Section 4.7 (a)deals with those economic princlples relevant to the analysis of net economic benefits and develops inflation and discount rates. Secti on 4.7 (b)presents the net economi c benef;ts of the proposed hydroelectric power investments ~ompared with this thermal alternative. These are measured in terms of present-value differE:nces between benef1ts and costs.Recogni zin§that even the most careful estimates will be surrouNded bya degree.of uncertainty,particularly in regard to world oil pri:es,the benefit-cost assessJients were subjected to sensitivity analyses as described 1n Section 4.8 (oil prices)and Section A.9 (other variables). Total (accounting for retirements and additions)2183 MW There ;s one particularly important assumption underlying the plan. The costs associated with the Bel uga developmtnt are based t...";the opening of that coal field for commercial 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,ther.e will be environmental prob 1ems to overcome c The gre~,test prob lem wi 11 be the avai 1abi 1;ty of cooling water for the units.The prcblem could be solved in the "worst"case by using the sea water from Cook Inlet as cooling water; however,this r,olution would-add significantly to project costs. The thermal plan described above has been selected as representative of the generation scenario that would be pursued in the absence of Susitna. J1 c'}'•.'".~.c.if "".'-,_'';'~'-_....,_~ .---',':,~.,',0 G ~l - ",__~~~-,--_~~"""~_',_E:"-""'~-__'~~--~.,_~,,,,-'.t~~~-'-'~"~-';..-if~,";~,,;_,-,<"'_,""__•__._.-...;.,."'"~~,.:._••".,:,'~_~_~_~,,~:.~:-,-·=:~~r~~~,:=~:~_~-.,,__--,~_~,~._.·'','-~~._",>.,.,......;....,....._.,._~_~_"_2:~_~_'2___"______.___ I I I I,..... '. I I I I,'. •• I I I " I I I· I I ··.1...·.•.•....f, \/ o t¢W' The choice of a time horizon is also crucial"If a short- term planning period is selected~the investment rank'ings and choices wi 11 differ markedly from those obtained through a long-term perspecti ve.In other words,'the benefit-:.:ost analysis would point to different generat10n expansion plans depending on the selected planning per"jod. A short-run optimization of state income would,at best, all!Jw only a moderate growth in fixed capital investment; at worst,it WQ'ul d lead to underi nvestment in not onl y the energy sector but also ;n other infrastructure facil ities such as roads"airports,hospitals,schools,and communica- tions • It th~refo\"e fellows that the Susitna project,like other Alaskan investments,should be apprai sed on the basis of long-run optimiz~.tion,where the long run is defined as the expected economic life of the fac"llity.For hydroelectric projects,thi$service life ;s typically 50 years or more. The costs of a Susitna-inclusive generation plan have therefore Wee"compared with the costs of the next-best D-4-21 (R~vise.d 7/11/83) .isl'.".--0 The energy costs of po wet..generation are "Initially me~sur5d in terms of opportunity values or 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 allocation of finite pub- lic resources~Energy investment decisions should not be made solely on the basis of accounting prices in the state if the international value of traded energy commodities such as coal and gas diverge from local market prices.The opportuni ty val ue represents the val ue of the resource if disposed of in the most economically attractive alternative manner •.In the case of oi"l,gas,and coal,it would rep- resent the sc:~l e of the Alaskan commodi ti es on the warl d market,compared to their consumption in state.The world price must be adjusted through a net-back exei'cise which accounts for the costs of getting the resource to worl d markets. • (a)Economic Principles and Parameters (i)Economic Principles -Concept of Net Economic Ben~fits A necessary condition for maximizing the increase in state i ocome and I economi c growth is the selection of pub 1 ic or private invastments with the highest present val ued net benefi ts to the state..In the context of Al askan el ectric power investlflents,the net benefi ts are defi ned as the dif- ference between the costs of optimal Susltna~inclusive and Sl..Jsi'tna-exclusive (all thermal)generation plans. 1ft.11 :.1·'··...·.'·.·· ', I I! '1'1....:'•.. ,1.1 .'.i ,\h ,I,·· ,''> l'!!'1,,{i}• 'II :.'.~ I, AI··.~.: I I I I I I I I (, 1 (; 1 I'(....u"'-',..'..,.'"'\-.;,..,)..',,. (',r Di scount rates ore required to compare and aggregate cash flo~IS occurring in different time periods of the planning 0..4-22 (Revised 7/11/83) -General Price Inflation Despite the fact that price levels are generally higher in Alaska than in the lower 48 states,there is little difference in the comparativE;rates of price changes; i.e.,price inflation..Between 1970 and 1978,for ex- ample,the U.S.and Anchorage consumer price indexes rose at annual rates of 6.9 and 7.1 percent,respectively. From 1977 to 1978,the differential was even smaller;the consumer prices increased by 8.8 percent and 8.7 percent in the U.S.and Anchorage,respectively (U.S ..Department of Labor).. Forecasts of Al askan prices extend onl y to 1986 (Al aska Department of Commerce and Economi C Development 1980)" These indicate an average.rate of increase of 8.7 percent from 1980 to 1986.For the longer period between 1986 and 2051,it is assumed that Alaskan prices will escalate at the overall U.S e rate,or at 5 to 7 percent compounded annually.The average annual rate of pric~inflation is therefore about 7 percent between 1982 ana 2051.Si nce this is consistent with long-term forecasts of the CPI advanced by leading economic consulting organizations, (Data Resources 1980;Wharton Econometric Forecasting Associ ates 1981)7 percent has been adopted as the study value.This analysis could have been done with the GNP deflator in lieu of the CPl.Results would be essential- ly the same. -DiscDunt Rates alternative which is the all-thermal generation pl an and .assessed over a planning period extending from 1982 to 2051,using internally consistent sets of economic scenarios and appropri ate opportunity val ues of Al askan energy. Throughout the analysi s,all costs and prices are expressed in real (inflation-adjusted)terms using January 1982 dol- lars except for fuel'which is expressed in January 1983 dollars..Hence,the results of the economic calculations are not sensitive to modified assumptions concerning the rates of general 9rice inflation.In contrast,the financi al and market analyses conducted in nominal (inflation-inclusive)terms will be influenced by the rate of general price inflation from 1982 to 2021. Price Inflation and Discount Rates I I I I I I I I I•f." '.,,:'j I il I, tl; ,I I, I .' I~ I I I,I c c ..·~ I'0 .> ~\ 1I.f ;) 1 I I t'; I) D-4-23 A subset of STP rates used in project evaluations is theownerts real .cost of borrowing;that is,the real cost of debt capital.Thi s industri al or government borrowing rate m~y be readily measured and provides a startior:;point for determining project ...specific dis- count rateS.For example,long-term industrial bond •.the government I s real borrow;ng rate or the real cost of debt capital (Baumol 1968;Mishan 1975; Prest and Turvey 1965)0 ••the social opportunity cost (SOC)rate; ••the social time preference (STP)rate;and Several approaches have been suggested for estimating the real di scount rate app 1i cabl e to pub lie proj ects (or to private projects from the public perspective). Three common alternatives include: The SOC rate measuY'es the real soc i al return (before taxes and subsidies)that capital funds could earn in alternative investments.If,for example,the marginal capital investment in Al aska has an estimated soci 8.1 yield of X percent,the Susitna Hydroelectric Project should be apprai sed using the X percent measure of "foregone returns"or opportunity costs.A shortcoming of this concept is the difficulty inherent in determin- ing the nature and yields of the foregone investments. The STP rate measures society's preferences for allo- eat i ng resources between investment and consumpt ion ~ This approach is also fraught with practical measure ... ment difficulties since a wide range of STP rates may be inferred from market interest rates and soci all y ... desirable rates of investment. ·~,G hor;zan.In essence,the di scount rate is a wei ght i ng factor refl ect i n9 that a do 11 ar recei ved tomorrow is worth less than a dollar received today.This holds even in an inflation-free economy as long as the productivity of capital is positive"In other words,the val ue of a doll ar recei ved in the fut ure must be defl ated to reflect ·its "earning power foregone by'not receiving it today. The use of discount rates extends to both real dollar (economic)and escalated dollar (financial)evaluations, with corresponding infl ation-adjusted (real)and inf]a- tioD-inclusive (nominal)values. .Real Discount and Interest Rates Ii I i "~ I I I I I I; I, I· I, I: il" I il :1 I I, c - rates have averaged about 2 to 3 percent HI the U.S.in real (infl ation-adjusted)terms (Data Resources 1980; U..S.Department of Commerce).Forecasts of real in- terest rates show average val ues of about 3 percent and 2 percent in the periods of 1985 to 1990 and 1990 to 2000,respectively.The·U.S.Nuclear Regul atory Commission has also analyzed the choice of discount rates for investment appraisal in the el ectric util ity industry and has recommended a 3 percent real rate (Roberts 1980).Therefore,a real rate of 3 percent has been adopted as the base case di scount and interest rate for the period 1982 to 2051. ·Nominal Oi scount and Interest Rates . Using the economic parameters di $cussed in the previous section &nd data rel ating to the el ectrical energy generation alt~1rnatives available for the Railbelt,an analysis was made comparing the costs of electrical energy production with and without the Susitna project. The method of comparing the "with ll al"'d II without ll Susitna alternative oeneration scenarios is based on the long-term present"worth (PW)of total system costs" The planning model determines the total production costs of alternative plans on a year-by-year basis. Thes.e total costs for the period of modeling incll~i!e all costs of fuel and operation and maintenance (O&M) for all generating units inc1udedas part of the system t and the annualized investment costs of any generating and system transmiss-'ion plants added during the period of 1993 to 2020.Fuel price real cost escalation was included in the analysis at the rates spec i fi ed above for the Reference Case ~ The nominal discount and interest rates are derived from the real val ues 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 flOmi- nal discount rate is determined as'10.2 percent or about 10 percent*. .Capital Cost Escal ation Based on present trends in construction costs,no real capital cost escal dtion has been assumed for either the hydro or the thermal units. (b)Analysis of Net Economic Benefits (i)~odeling Ap-proach *(1 +the nominal tate)=(1 +the real ratl~)x (l +the inflation rate)=1.03 x I.Ol!.'or 1.102 D-4-24 (Revi::,ed 7/11/83) .' I I ••.\ .., I I I I \1 I, .......11 ......h I. I I '.':". I .: I, \Ii ........_l -Pattern of Investments "With ll and uW;thout II Sus;tna The Reference Case cOI1lj)ari son of the Uwi th ':and uwi thout II Sus i tn a pl ansi s based on an assessment of the PW pi"oduction costs for the period 1993 to 2051,the Reference Case val ues for the energy demand and load forecast,fuel prices~fuel price escalation rates,and capital casts. D-4-25 (Revised 7/11/83) - In order to aggregate and compare costs on a significantly long-term basis,annual costs have been aggregated for the period 1993 to 2051e Costs have been computed as the sum of two components and converted to a 1982 PWe The first component is the 1982 PW of cost output from the first 28 years of model simulation from 1993 to 2020.The second component is the estimated PW of long-term system costs from 2021 to 2051 • . Factors which contribute to the ultimate consumer cost of power but whi ch are not included as input to thi s model are investment costs for all generation plants in service prior to 1993 investment,cost of the tr ansmi ss i on and distribution facilities already in service,and administrative costs of utilities.These costs are common to all scenarios and therefore have been emitted from the study. ~ '----"..:......... For an assumed set of economic parameters on a particular generation .alternative,the first element of the PW value represents the amount of cash (not including those costs noted above)needed in 1982 to meet electrical production needs in the Railbelt for the period 1993 to 2020.The second element of the aggregated PW value is the long-term (2021 to 2051)PW estimate of production costs.In consid- ering the val ue to the system of the addition of a hydro- electric power plant which has a useful life of apprOXi- mately 50 years,the shorter study period would be inade- quate.A hydroelectric pl ant added in 1993 or 2002 would accrue benefits for only 28 or 19 years,r'espectivelYt us ing an investment hori zon that extend s to 2020.However, to model the system for an additi cnal 31 years ~it woul d be necessary to develop future load forecasts and generation alternatives which are beyond the extent of normal projections.For this reason,it has been assumed that the production costs for the final study year (2020)w0uld simply recur for an additional 31 years,however they would be adjusted to take into account real fuel price escal ation,and the PW of these was added to the 2B-year FW (1993 to 2020)to establ ish the long.-term cost differences between al ternati ve methods of power generation • (;i)Reference Case Analysis C' I; I· I II; t' I I. ·····1····;.·l .•.. 11,'.-: .y I I' 11 I I, I I, \( I, I., 'II'" 1 " I 0..4...26 (ReVised 7/11/83) The second stage of Susitna,the Devil Canyon project,is SCheduled to come on line in 2002 with an installed capacity of 600 NvL The combined operation of Wat9,na on peak and Devil Canyon on base will have a dependable capacity of 1270 ~tW in20LO under flow regime C as discussed in Exhibit B,Section 4. The with Susitna case cal i s for Watana to come on line in 1993 to meet system capacity requirements.Although the initi al i nst all ati on at Watan a wi 11 be 1020 MW only about 520 MW wi 11 be dependable during the period Watana operates on base before Devil G::Olyon comes on line in2002~as discussed in Exhibit.B,Sections 3e7 and 4 ..3. The economic comparison of these plans is shown in Table D.22.During the 1993 to 2020 study period,the 1982 PW cost for the Susitna pl an is $3.4 bill ion.The .annual production cost in 2020 is $0.3 billion.The PW of this level cost,which remains virtually constant except for fuel cost escalation fOrtl period extending to the end of the life of the Devil Canyon plant (2051)~is $2.1 billion.The resulting total present wot"th of the w'ith~Susitna plan is $5.5 billiun in 1982 dollars. The non-Susitna plan (Section 4ll5)which was modeled has a 1982 PW cost of $3.9 billion for the 1993 to 2020 period with a 2020 annual CO$t of $0 ..5 billion.The total long-term cost has a PW of $7..3 billion.Therefore,the net economic benefit of adopting the Susitna plan is $1.8 billion.In other words,the In addition to the Susitna pr-ojects,the with ...Susitna pl an calls for the addition of a 7Q-MW gas turb-ine unit in each of the following years,2001,2012,2014,2015,2016,2017,and2Q19 .. Al so a 200-MW gas-fired combined cycle unit would be installed in 2020.The wlthout Susitna plan is discussed in Section 4.5. -Reference Case Net Economic Benefits I,, ;~",'•p I I I' I I I I I I -I: ,I: >..\ '1\t_," I,/- f I -I ;1\if i') 'i I- .} ,f "-~"~t ~·.f .,~,. \'0"'f>..4 ...-0'·'·,_'\.-.O~",'" •,0 ...". flttJ.\.•'.til"•I ,,'t'I '!'•f"'=>~.,I:. I.~C'.:I 4 •~•~~.•...1;t .~,~"~&>'0 '...(."'B ...'"• ft"'i'fer ....... ... o o D-4-21 (Revised 7/11/83) (, . o present val ue cost difference between the Susitna pl an and the expan$ion pl an based on thermal pI ant addition is $1.8 billion in 1982 dollars • It is noted that the magnitude of net economic benefits ($1.8 bill ion);s not particularly s~nsitive to ait~rnativ~'assumptions concerning the overall rate of pr~ice inflation as measured by the Consumer Price Index .. The analysis has been carried out in real.(inflation- adjusted)terms.Therefore,the present val ued cost savings will remain close to $1.8 billion regardless of CPI movements,as long as the real (infl ation-adjusted) discount and interest rates are maintained at 3 percent. The Susitna project1s internal rate of return (IRR), i .e q the real (inflafion-a.djusted)discount rate at which the with-Susitna pl an has zero net economic bene- f;ts,or the di scount rate at wh i ch the cost s of the with-Susitna and the alternative plans have equal costs, has also been determined.The IRR is about 5.0 percent in real terms,and 10.6 percent in nominal (inflation ... inclusiv~)terms.Therefore,the investment in Susitna would significantly exceed the 5 percent nominal rate of return Iltest Ii proposed by the State of Al aska in cases where state appropriations may beinvolved.* *See Alaska legislation A5 44.83.670 I·.....~.. ."~, I I , k •.•..~ I I I I I ,I I.~..i.~' .'/ I I·'.·.·;·.,"; 1, :(\ '...11 ."IJ ·I..,!,) j I I) '1 1.',~l J...."1,.<, h,;..\f, 1 f) D~4-28 (Revised 7/11/83) The generation pl anning analysi s has impl ieitly assumed that all environmental costs for both the Susitna and the non-Susitna Pi ans have.been costed however there are factors rel ating to the non-Susitna pi answhich may increase the net economi.c benefits 'LO the project.To the extent that t.he thermal generation expansion pl an may carry greater environmental costs t·han the Susitna plan,the economic cost savings from the Susitna project may be understated.Due to the greater level of study of the Susitna project,costs for mitig,'\tion plans were included.This may not be the case VJith the coal alternative which may underestimate environmental costs.These differences or added costs cannot be quant i fi ed at thi s stage of studY'cn the eoa 1 al ternati ve. The generation planning analys;s al so did not .assume any restrictions on the supply of natural gas.As stated in Section 4.5(c)Cook Inlet proven reser~/es wi 1i be exhausted by the year 2000,and proven reserves plus the mean of the undiscovered reserves est imates wi 11 be exhausted by 2010.Under the Reference Case without Susitna expansion plan,gas consumption in 2020 would be about 8000 Mcf and total gas consumption for the period from 2020 to 2051 after proven pi us undiscovered reserves are exhausted woul d be 210,000 Mef or about 3.8 percent of the 1982 estimte of proven plus und;scovered reserves.Si nce thi s val ue is relatively small~errors in the estimate of the reserves and in the consumpti on rates for other gas uses could easily affect the date by which gas would be exhausted for el ectrical generation.Al so over the planning horizon to 2051 North Slope gas will probably become available to the Railbelt market,albeit at a hi gher pri ce than Cook In 1et gas. Since the generation planning an~lysis did not assume any supply restrictions of natural gas nor any price increase for substitute gas becoming available,the analysis could underestimate the benefits available to the Sus i tn a pt;oj ect. It..•.·1\, I I 11 ••.;.'.•...tf; I I I I 'I',·,l, I} I I I I··"'..···."; .':""..> I 11; I:.'1.F ~;: 1·\ ".,: I " !.1 I;. 1,1 11: I; I; II""~'...'I I_.~ {).t; 4.8 -Sensitivity to World Oil Price Forecasts Assumptions regarding future world oil prices impact the forecasts of el ectric power demand for the rail belt area.Thi s rel atic:1ship is discussed in detail in Exhibit B,Section 5.4. Table 0.23 contains a summary of the load forecasts considered. A sensitivity analysi s was performed to id'entify the effect of worl d oi 1 price forecasts lower and hi gher than the reference case.Sensitivity analyses wet'e performed for the DRI,DOR-mean and -2 percent load forecasts.The fuel price escal ation rates which correspond to these forecasts are discussed in Appendix D-1.Table D.24 depicts the results of the sensitivity analysis. As can been seen from Table D.24,the DOR.mean case,with negative net benefits fJr a net cost of $85 million is approximately a break-even case in which the costs of the with Susitna pl an are about equal to the costs of the without Susitna plan.Under the -2 percent case,the without Susitna plan is clearly more attractive,haVing a present worth about $1.9 billion less than the with Susitna plan.The DRI plan generates net benefits of $1.82 billion or about the same those of the Reference Case. In perf-irming the above analysis,it was assumed that the initial operat ~,'Q~dates of Watana and Devi 1 Canyon would be the same as und-:::r the reference case,or 1993 and 2002 respectively.A stUdy of ~:L~expansion programs for the sensitivity case showed that new capacity,that could be provided by Watana,would be required in 1993 in all cases and that Devil Canyon could be del ayed by up to 5 years under the -2 percent case.However,sensitivity analyses showed that del aying Devil Canyon would not s;gnific,,-ntly affect the results of the economic analysis. D~4-29 {Revised 7/11/83) ~..,.'.•I)•~•• •li or".I -~••:';•••\• _:•..•J ....._,.....fl,~..tJ 4 .-'Cl •.'~I. .....'"...,,"~(...~'., -..~fII....,I.~""\ f'I Sensitivity Values 2~5 2917,4316 1.,38,2.06 1.49,2.23 1.98,2 96 Esca1 at on to 2020 0·,1 y 3.0 3597 1.72 1.86 2.47 Escal at ion to 2051 Reference Case ValueVariable,Reference Table _____t'" D~4-30 (Revised 7/11/83) Discount Rate (%),.Tabl~D..25 Watana Cap.Costs ($xI0 6 ),Table D.26 Base fuel price ($/r~1M8tu),Table n.27 Coal -Nenana -Bel uga Natural Gas Real Fuel Escalation I 4.9 -Other Sensitivi.ty Assessment~ Rather than relying on a single point comparis\on to assess the net benefit of the Susitna project,a sensitivity analysis was carried out to ldent i fy the impact of a changeirl assumptions on the results.The analysis was directed at the following variables other than those related to the world price of oil. I: I·".i· , ",,,"._.1 I·.i..·..:).'. '.. ..~...,.i I I I I I I I I ,•..1.J '..~.if J .•....'),I.I." '.1··.·'··· ..i".{..' I, ·1··.· ]·.'· ,." c !":1 I I I 1° - , tid'.r...'.'.:'" 4.10 -~ttelle RaiTbelt Alternatives Study The Office of the Governor,State of Alaska,Division of Policy De.velopment and Planning,and the Governor's Policy Review Committee contracted with Battelle Pacific Northwest Laboratories to investigate potenti al strategies for future el ectric power development in the Ra.ilbelt region of Alaska.This section presents a summary of final results of the Railbelt Electric Power Alternatives Study. The overall approach taken on this study involved five major tasks or activities that led to the results of the project,a comparative eval- uation of electric energy plans for the Railbelt.The five tasks con- ducted as part of the study evaluated the following aspects of elec- trical power planning: -fuel supply and price an~lysi s ~electrical demand forecasr.s -generation and conservation alternatives evaluation -development of electric ene\'~gy themes or "futures"available to the Railbelt -systems integration/evaluation of electric energy plans. Note that whi Ie each of the tasks contributed data and information to the final results of the project,they al so developed important results tha.tare of interest .independently of.the final results of this prO- ject.Output from the first three tasks contributed directly as input to analysis of the Susitna project presented in this Exhibit ami in 0-4-31 (Rev;sed 7111/83) Tables 0.25 to 0.27 depict the results of the sensitivity analysis for the variables except for real fuel escalation.Net benefits for.the keference Case would be reduced to about $1.0 billion from $1.8 billion if no rea.l fuel price escalation is applied.Table 0.28 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 Reference Case value ($1.827 billion)which is set to I 100. As can be seen from Table 0.28 the economic analysis is most sensitive to the forecast of world oil prices and the corresponding power market forecast and related fuel price escal ation rates.As stated in Section 4 ..8 under certain forecasts the with Susitna plan is marginal or unattractive when compared to the without Susitna pl an .. The analysis is about equally sensitive to the other three variables mentioned above,discount rate,Watan~capital cost,antI fuel price as can be seen on Table 0.28.Over the range of values given these vc.:~~ables,the with Susitna plan maintains positive .net benefits over the wit~nut Susitna plan. In ~dd;tion to the above sensitivityanalysest)the sensitivity of the analysis to a del ay in th3 construction of the Devil Canyon project and to a change in the loss of load probability was evaluated.Changes in these assumptions had no significant affect on the results of the economic analysi s. J1, I: I" tI~ I 11 II It I, i.~ I, "I~"\ ~, If I I I I 1,··.····.1 ....." t.I'··.·:.....•'i ;<.i t t I I I1 1/) I I" I lrI 1·I (J I ! ,-. I - - Alternatives Evaluation •d The companion Battelle studY reviewed a much wider r:lnge of generating alternatives than the Susitna feasibility st:,~:y.The following text summari·zes·the process followed and results of selecting technologies for developing energy pl ans. D...4..32 (ReVised 7/11/83) (a) Exhibit B.The results of the fourth task is presented in this subsection. The 'first task evaluated the price and &vailability of fuels that either directly could be used as fuels for electrical generation or- indirectly could compete with electr'lcity in end-use applications suc as space or water heating. The second task,el ectri cal demand forecasts,was requi red fot'two reasons.The amount of el ectric ity demanded determines both the si ze of generating units that can be included in the system and the number of generating units or the total generating capacity required ..The fOl"ecast used from thi s study in the Susitna feasibi 1ity study is presented in Exhibit B. The third task's purpose was to identify electric 90wer generation and tonser-vat;on al ternati ves potent;al i y app 1 i cab le to the Rail be"!t region and to examine the'ir feasibility,considering several factors.These factors include ccst of power,environmental and socioeconomic effects, and pUbl ic acceptance.Alternatives appearing to be best sui ted for future application to "the reg'ion were th~n subjected to additional in-depth study and were incorporaterl into one or more of the e~ectric energy pl ans. The fourth task,the development of el ectri C energy themes or pl ans, presents possible electric energy Ilfutures"for the Railbelt.These plans were.developed both to encompass the full range of vi able al ter- natives available to the region and to provide a direct comparison of those futures currently receiving the greatest interest with1n the Raj lbelt.A pl an is defi ned by a set of el ectrical generation and conservation alternatives sufficient to meet the peak demand and annual ~nergy requirements over the time hor;zon of the study.The time horizon of the study ;s the 1981-2050 time period.The set of alterna- tives used in each plan was drawn from the alternatives selected for further study in the analysis of alternatives task. As the name implies,the purpose of the fifth task,the system integration/comparative analysis task,was to integrate the results of the other tasks and to produce a comparative eval uation of the electric energy plans.This comparative evaluation basically isa descr'iption of the impl icationsand impacts of each electric energy pl an..The major criteri a used to eval uate and compare the pl ans are cost of power,environmental and socioeconomic impacts,as well as the susceptibility of the pl an to future uncertainty in assumptions and par ameter est i mates. This summary focuses on the third task:alternatives evaluation. \1;..:...'1'1\d ~I;Ii I, I·.--~.···.·.III I • .•.4'"t...I * 1,. I I I :·1···.'···. :j ~. I '.1·.··.·."····J~; D-4-33 (Revised 7/11183) {) () (j "~;mf-""'" \\•Q o ...the availabi1ity and cost of energy resources; -the likely effects of minimum plant size and operational charac- teristics on system operation; -the economic performance of the various technologies as re- fl ected in estimated busbar~power costs; -pUbl ic acceptance,both as reflected in the frame\'wrk of el ec- tric energy plans within which the selection was conducted and as impacting specific technologies;and ongoing Railbelt electric po wei'"planning activities., From this analysis,described more fully in the Battelle Electric Power Alternatives Study (Battelle 1982,Vol.IV),13 gene.rating Selection of generation alternatives wa,I')based on the followinng considerations: Selecting generating alternatives for the Railbelt electric energy pl ans proceeded in three stages.First,e broad set of candidate technologies was identified,constrained only by the avail abil ity of the technology for commercial service prior to the year 2000. After a study was prepared on the cand i date techno 1ogi es ,they were evaluated based on seVeral technical ,economic ,environmental and institutional considerations.Using the results of that study,a subset of more promising technologies was subsequently i dentifi ed.Finally,prototypi cal generating fac;1 iti es (speci fic sites in the case of hydropower)were identified for further developnl '¥'It 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 is found in the Railbe'it.Resources currently used include coal,natural gas,petroleum-derived li ... qui ds and hydropower.Energy resources current 1y not being used but which could be developed for producing electric power within the planning period of this study include peat,wind power,solar energy,municipal refuse-derived fuels,and wood wasteo Light water reactor fuel is manufactured in the lower 48 states and could be readily supplied to the Railbelt,if desired.Candidate electric generating technologies using these resources and must 1 ikely to be avail able for commerci al order prior to the year 2000 are listed in Table D.29_The 37 generation technologies and com- binations 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 technologies rejected from consideration at this stage are pro- vided in the Battelle El ectric Power Alternatives Study (Battelle 1982,Vol.IV). ~.,,: '; i. 11'-, ,j.~~: •""i ", 1,\ I' I I I II··,t l., I I·.',··,···· {! 1 ' I ··1'.···'.·...<" ,I, iii;I I IJI.••.,f, -J ....,. ,... u"..,~ o- 0-4-34 Coal-fired steam-electric generation was selected for con· sideration in Railbelt electric energy plans because it is a commercially mature ander:onomica.l technology that poten- t'ially is capable of supplying all of the Railbelt 's base- load electric power needs for the indefinite future.An abundance of coal in the Railbelt should be mineable at costs allowing electricity production to be economically competitive with all but the nl0st favorable alternatives throughout the planning pe;iod.Goal may be available frcm both the Beluga and Nenana fields.However,the Beluga fields are not yet opened and their opening is as yet uncertain.Should the fields not be mined for commer- cial use,the coal may not be competitive for Railbelt electrical power.Should thE fields not open,the eXisting Nenana coal fields would need to supply an increased ton- nage at higher prices. The extremely low sulfur content of Railbelt coal and the availability of commercially tested oxides of SUlfur (SOx)and particUlate control devices will facilitate control of these emissions to level s mandated by the Clean Air Act.Principal concerns of this technologyareenvi- ronmental impacts of coal mining,possible ambient air- quality effects of,residual sax,oxides of nitrogen (NO x )and partiCUlate emission~,long-term atmospheric bui 1dup of C02 (common to all combust ion-based technolo- gies)and the long-term susceptibility of busbar power costs to inflation. Two prototypical fac'l ities were chosen for ;~I-depth stUdy: in tne Bel ugaarea,,a 200-MW p'ant that,uscz coal mined from the Chutna Field,and at Nenana a plant of similar capacity that uses coal delivered ft'Oih the Nenana fi·eld at Healy by Alaska Railroad. (ii).Coal Gasifier-Combined-Gycl~Plants lhese plants consist of coal gasifiers producing a synthe- ti:gas that is burned in combust ion turbhfes that drive te\:hnologies were selected for possible inclusion in the Raflbelt electric power plans.For each nonhydro,technology,a prototypical plant was defined to facilitate further development of the needed information.For the hydro technologies,promising sites were selected for further study.These prototypical plants and sites constitllte the generating alternatives selected for consideration in the 'Railbelt electric energy plans'•In tha following paragraphs,each of the 13 preferred technologies is briefly described,along wi""h some of the principal reasrms for its selecti·on.Also described are the prototypical plants and hydro 5i tes se'l ected for further study. (i)Coal-Fired Steam-Electric Plants I' ii,",1 '1 • I I' I I I I tl I ;Ii I Ii I til I, I I ilt i I I l .<J t , , I I ! I. --<' "h.... 0-4-35 electric generators.Heat-recovery boilers use turbine exhaust heat to rai se steam to .dri ve a steam turbine- generator. These plants,when commercially available,should allow continued use of Alaskan coal resources at costs cOO1parable toconvent.ional coal steam-electric .plants,while providing environmental and operational advantages comrared to con- ventional pl ants.Environmental advantages incl ude less waste ..heat rejection and water consumpt ion per unit of out- put due to higher plant efficiency.Better control of NO x ,SOx and particulate emission is also afforded. From an operational standpoint,these plants offel4 a poteh- tial for load-following duty.(However,much of the eXisting Railbelt capacity most likely will be available for intermediate and peak loading during the planning period~)Because of superior plant efficiencies,coal gasifer -combined-cycle plants should be somev"hat less susceptible to inflation fuel cost than conventional steam-electric pl ants.Principal concerns relative to these pl ants incluGe 'land disturbance resulting from mining of coal,C02 production,and uncertainties in pl ant per- fJrmance and capi tal cost due to the current st ate of tech- nology development. A prototypical ·plant was selected for in-depth analy~is (Battelle 1982,Val e XVII)..Thi s 200 Ml,tJ pl ant is located in the Bel ugii area and uses coal mined from the Chui tn a Field"The plant would use oxygen-blown gasifiers of Shell ciesign,producing a medium-Btu synthesis gas for combusti,.;; turbine firing.The plant would be capable G'~ load-following operation. (i ii)Natural Gas Combustion Turbines Although of rel atively low efficiency,natural gas combustion turbines 3erve ~lJell as peaking units in a system dominated by steam-el ectric pl ants..The short construction lead times characteristic of these units also offer opportunities to meet unexpected or temporary increases in demand.Except for product~vn of C02,and potent i al local noise probl~ms,these units produce minimal environmental impact.The principal economoc conern is the sens;.tivity of these plants to esal ating fuel costs. Because the costs and performance of combustion turbines are rel atively we'll understood,no prototype was selected for in-depth stUdy .. I I' I I 'I::!'.'..' il··'.'. (..l ····.1··;. I 1 'J, I I, I . 1.' t~1II~ o 0-4-36 Natural gas fuel-cell stations were considered in the Railbe1t 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 intermedi ate load units.Pl ant efficiencies most likely will be far superior to combustion turbines and rel atively unaffected by parti al power operation.Capital investment costs most likely will be comparable to that of combustion turbines.These costs and performance characteristics should lead to significant reduction in busbar power costs ~and greater protection from escal ation of natural gas prices compared to combustion turbines.Construction lead time should be comparable to those of combustion turbines.Because environmental effects most likely will be limited to C02 production,load-center siting will be possible and transmission losses and co~ts consequently will be reduced .. Since the fuel cell is still an enet'ging technology with commerclal availability scheduled for the late 1980:'s,it was not chosen as a major block in the Railbelt generation future.No prototypical pl ant was selected for further study. These pl ants woul d consi st of a fuel conditioner to convert natural gas to hydrogen and C02,phosphoric acid fuel cells to produce de power by electrolytic oxidation of hydrogen,and a power conditioner to convert the de power output of the fuel cell s to ac po\·,er.Fuel-cell stations most likely would be relatively small and sited near load centers. A nominal 200MW prototypical plant f/as selected for fur- ther study.The pl ant is located in the Bel uga area and uses Cook Inlet natural gas (Battelle 1982,Vol.XIII). (v)Natural Gas Fuel-Cell Stations (iv)Natural-Gas -Combined-C~cle Plants Natural gas -combined--cycl e pl ants were sel ected for consideration because of the current availability of low- cost natural gas in the Cook Inl et area and the likely future availability of North Slope supplies in the Railbelt (although at prices higher than those currently experi- enced).Combined-cycle pl ants are the most economical and environmentally benign method currently avail able togener- ate electric base-load or mid-range peaking power using natural gas.The principal economic concern is the sensi- tivity of busbar power costs to the possible substantial rise ;n natural gas costs.The principal environmental concern is C02 production and possible local no;se prob- lems. 1· ···""'.'•.'>..1 I . ,I,: ~. I·.·····. '1 ~j li,:'~••.' t~.. II'··,~, I··'··~'···jl--, I 'I!."·~ 1'1."" I { "·1.'·,',..... l ~: ::'. (~ij:. 1 .: l,." 'I.··..'I' It ' '..1·······. I 1Ii IJ.iIi 11 tl'..·,·.··;·,I '., • """"I :.'~.•...~ (. I•:1 •I 6 Natural gas fuel-cell stations were considered in the Ra;lbelt 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 efficiencies most likely will be far superior to combustion turbines and relat<jvely unaffected by partial power operation.Capital investment costs most likely will be comparable tv that of combustion turbines.These costs and performance characteristics should lead to significant reduct;on in busbar power costs,and greater protecti on from escal ation of natural gas prices compared to combustion turbines.Construction lead time should be comparable to tnose of combustion tUl~bines..Because environmental.effects most likely will be limited to C02 production,load-center siting will be possible and transmission losses and costs consequently will be reduced. Since the fuel cell is still an emerging technology with commercial availability scheduled for the late 1980's,it was not chosen as a major block in the Railbeltgeneration future.No prototypical plant was selected for further study .. --,> 0-4-37 c These pl ants would consi st of a fuel conditioner to convert natural gas to hydrogen and C02,phosphoric acid fuel cells to produce dc power by electrolytic oxidation of hydrogen,and a power conditioner to convert the de power output of the fuel cells to ac power 0 Fuel-cell stations most likely would be rel atively small and sited near load centers. Natural gas -combined-cycle plants were selected for consideration because of the current availabi'lity of lo\\'- cost natural gas.in the Cook Inlet area and the 1i kely future availability of North Slope supplies in the Railbelt (talthough at prices higher thant those currently experi- enced)•Combined-cycl e pl ants are the most economica-f and environmentally benign method currently available to gener- ate eiectric base-load or mid-range -peaking power using natural gas.The principal economic concern is the sensi- tivity of busbar power costs to the possible substantial rise in natural gas costs.The principal environmental concern is C02 production and possible local noise prob- lems. A nominal 200 MW prototypical plant was selected for fur- ther study.The plant is 1ocatedin the Beluga area and uses Cook Inlet natural gas (Battelle 1982,Vol.XIII). (v)Natural Gas Fuel-Cell Stations (iv)Natural-Gas -Combined-Cycle P'iants. l~..·.')!.•t I( f]1·~··.--.' f i• II'~... I,~.. I·" ". ;1 . ,;;. I;.···f' I II..·."•..• '] \Ii...• I .~ [I'.i.•:t .;;- I ;(1 1 \ I :G' Large wind energy cor,version systems were sel ected for consideration in Railbelt electric energy.plants for several reasons.Severa1areas of excellent wind resource have been identfied in the Kililbelt,notably in the Isabell Pass area of the Al aska Range,and in coastal locations .. The winds of these areas are strongest during fall,winter and spring months,coinciding ~Jith the winter-peaking elec- tric load of the Raflbelt.FUl"thermore,developing hydro- electric projects in the Railbelt would prove complementary 0-4-38 --" Microhydroelectric systems were chosen for analysis because of publ ic interest in these systems,their renewable char- acter and potenti ally modest env ironmental impact.Con- crete information on pOllier product )on costs typical of these facilities was not available when the preferred tech- nologies were selected..Further analys is indicated,how- ever,that few microhydroel ectric reservoir:copl d be de- vel oped for less than 80 mill s!kWh,and even at cons i der- ably higher rates.,the contribution of this resource would likely be minor.Because of the very limited potential of this technology in the Railbelt,it was subsequently dropped from consideration.However ~install ations at certain sites (for example,residences or other facilities remote from distribution systems)may be justified. (x)Lar'ge Wind Energy Conversion ,l;ystems Large wind energy conversi on systems cons i st of machi nes of 100 kW capacity and greater ..These systems typically would be installed in clusters in areas of favorable wind re- source and would be operated as central generating units. Operation is in the fuel-saving mode because of the inter- mittent nature of the wind resource. I Ii I: I 'Ii~.. I ·1···.··'.·.··· '.,, '··1·..··.··· ;1 ,'i I ·1.:.·.·.1 I IJ Ii ~., \. ti ·E.···.···· " \., I Ii • I IID t _. 0-4-39 Small wi nd energy conversi on systems were sal ected for consideration in Railbelt electric energy plans for several reasons.Within the Railbelt,selected areas have been identified as having superior wind resource potential and the resource is renewabl e.Al so,polt/er produced by these system$appeared possibly to be marginally economically competitive with generating facil ities currently operating in the Railbelt.However,these machines operate in a fuel-saver mode because of the intermittent nature of the wind resource and because their economic performance can be analyzed only by comparing the busbar power cost of these machines to the energy cost of power they could di spl ace 0 Data for further analysi s of smal"wind energy conversion systems were taken from the technology profi 1es.Further analysis of this alternative indicated that 20 ~1W of in- stalled capacity producingapprox;mately 40 GWh of electric energy possibly could be economically developed at 80 mill marginal power costs,under the highly unl ikely assumption of full penetration of the available market '(households). Furthermore,in this analysis these machines y/ere given parity with firm generating alternatives for cost of power comparisons.Because the potential contribution of this alternative is relatively minor even undet the rather liberal assumptions of this analysis,the potential energy to wind energy systems.Surplus wind-generated electricity could be readily "stored"by reducing hydro generation .. Hydro operation could be used to rapidly pick up load during periods of wind insuil~iciencyo Wind machines could provide.additional energy,wher:-eas excess installed hydro capacity could provide capacity credit.Pinally,wind systems have fewadver:se environmental effects with ,the except i on of their'vi sua 1 presence and appear to havt~ widespread pUblic support. A prototypical large wind energy conve'rsion system was S~l ~.;cted for further study.The prototype consisted ofa w)nd farm located iA the Isabell Pass area and was com- prised of ten 2.5 MW rated capacity,Boeing MOD-2,horizon- tal axis wind turbines (Battell e 1982,Vol ..XVI).. . (xi)Small Wind Energy Conversion Systems Small wi nd energy conversi on systems are small wi nd tur- bines of either horizontal or vertical axis,desig.n rated at less than 100 kW capacity.Machines of this size would generally be dispersed in individual households and in commercial establishments. r:4. I I I '••~. I .•.;. ,;., I·.·.·.····~.:..· ':", I I I I II," .v I '.~ Ii I I I:·, ." 0-4-40 ....::J - Estimated production costs of an unretimed tidal power facil ity would be competitive with principal alternative sources of power,such as coal-fired power pl ants,if all power production could be use.d effectively.The costs would not be competitive,howev!~r,unless a specialized industry were establ ished to absorb the predictable,but cyclic,output of the plant.Alternatively,only the portion of the power output that could be absorbed by the Railbelt power system could be used.The cost of this energy would be extremely high rel ative to other power-producing options because only a fraction of the "rawn energy production could be used.An additional alternative would be to construct a retiming facility, probably a pumped storage pl ant.Due to the increased capital costs and power losses inherent in this option, busbar power costs would still be substantially greater than for nontidal generating alternatives.For these reasons,the Cook Inlet tidal power alternative was not considered further in the analysis of Railbeltelectric energy plans. Tidal power was selected for consideration in Railbelt electric energy plans because of the substantial Cook Inlet tidal resource,because .of the renewable character of this energy resource and because of the sUDstanti al interest in the resource,as evidenced by the first-phase assessment of Cook Inlet tidal power development (Acres 1981a). production of small wind energy conversion systems was not included in the analysis of Railbelt electric energy pl ans. (xii)Tidal Power Tidal power plants typically consi st of a "tidal barrage" extending across a bay or inl et that has substanti al tidal fl uctuations.The barrage contains sl uice gates tv admit water 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 of cycling 1n complement to the output of the tidal plant.Hydro capacity is especially suited for this purpose.Alternatively,energy storage facilities (pumped hydro,compressed air,storage batteri es)can be used to regUlate the power output of the tidal facility. 11 I :11. \j I '11.,.•t I I ~I I I I I I I I Ii Ii I I I I I I ..I.~~····.·· '.' I I I I I •11 • I I Ii Ii I I.. (xiii)Refuse-Derived Fuel Steam Electric Plants These plants consist of boilers,fired by the combustible fraction of municipal refuse,that produce steam for the operation of a steam turbine-generator.Rated capacities typically are low due to the'difficulties of transporting and storing refuse,a.rel atively low energy density fuel .. Supplemental firing by fossil fuel may be required to compensate for seasonal vari ation in refuse production. Enough municipal refuse appears to be available in the Anchorage and Fairbanks areas to support small refuse- derived fuel-fiTed steam-electric plants if supplemental firing (using coal)were provided to compensate for sea- sonal fl uctuations in refuse avail abi 1 ity.The cost of power from such a facility appears to be reasonably corn- petitive,although this competitiveness depends upon re- ceipt of refuse-derived fuel at little or no cost.Advan- t ages presented by di sposa1 of mun i ci pa 1 refuse by combus- tion may outweigh the somewhat higher power costs of such a facil ity compared to coal-fired pl ants..The pri ncJpal concernsrel ative to thi s type of pl ant rel ate to potenti al rel i ab i1 i ty ,atmospher i c eni ss ion,and odor problems. Cost and performance characteristics of these alternatives as used in the Battelle study (Batte11 e 1982 ,Val.I I)are summarized ;n Table 0.30. 0-4 ...41 (Revised 7/11/83) ;-- I I I I I I I I I I I IJ 11 II IJ 11 I Ii I 6/29/83 5-CONSEQUENCESOF LICENSE DENIAL 5.1 -Cost of License Denial .The forecast energy demand for the Railbelt through the year 2020 can be met without constructing the Watana-Devil Canyon hydroelectric project provided that other,albeit more costly,alternatives are developed.The best alternative generating system is outlined in Section 4.5 of this Exhibit.However,the economic comparison described in Section 4.7 concludes that the Susitna project will yield an expected present valued net benefit of $1.8 billion under the Reference Case. The economic consequences of license denial will be the probable costs menti onedabov e. The Susitna project makes a significant contribution to the energy independence of both the State and the nation.Generation of power by a renewable resource in the State allows for export of non-renewab 1e resources to the lower 48 states.Denial of the license will negate this effort. The most likely alternative to Susitna is subject to a great deal of cost risk due to the uncertain future in fossil fuel prices and the unresolved issues about development in the Beluga coal fields.License denial will forCI?the State into pursuing a less certain program in meeting power needs. 5.2 -Future Use of Damsites if License is Denied There are no present pI ants for an al ternati ve use of the Watan a and Dev i 1 t.:anyon dams i tes .In the ab St~nce of the hydroe 1ectr i c proj ect, they would remain in their present state. 0-5-1 (ReVised 7/11/83) .,d - II o _..--" .-=·,tt D-6-~(Revised 7/11/83) 6 -F INANC ING 6/29/83 6.1 -Forecast Financial Parameters 6.3 -Legislative Status of Alaska Power Authority and SL1sitna Project The Alaska Power Authority is a pUblic corporation of the State in the Department of Commerce and Economic Development but wi til separate and independent legal existence. The Authority was c~eated with all general powers necessary to finance, construct and operate power production and transmiss'ion facil ities t~roughout the State.The Authority is not regul ated by the Al aska Public Utilities Commission,but ;s subject to the Executive Budget Act of the State and must identify projects for development.in accordance The financial par,ameters used in the financial apalys'is are summarized in Tab 1e 0.12.The interest rates and forecast rates of infl at ion are of spec i a1 import ance.They have been based on the f()recast i nfl ati on rates and the forecast of interest }"ates on industl"idl bonds (Data Resources Inc.)and conform to a range of other authoritative forecasts.To allow for the factors which have brought about a narrowing Jf the differential between tax exempt and taxable securities,it has been assumed that any tax exempt financing wou"/d be at a.rate of 80 percent rather than the hi storical 75 percent or so of the.taxable interest rate.This identifies the forecast interest rates ;n the financing periods from 1985io successive five-year periods as bei ng on the order of 8.6 percent,7.8 percent,and 7'percent.The accompanying rate of infl ation would be about 7 percent.In view of the uncertainty attaching to such forecasts and in the interest of conservatism,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 inflation rate of 7 percent. 6.2 -Inflationary Financing Deficit The basic financing problem of Susitna is the magnitude of its "infla- tionary financing deficits.1I Under inflationary cOl1ditions these deficits (early year losses)are an inherent characteristic of almost all debt financed,long life,capital intensive projects (see Figure 0.10).As such,they are entirely compatible (as in the Susitna case) wi th a proj ect showi ng a good economi c rate of return.However,un 1ess additional state equity is incl uded to meet this Ilinf"'ationary financ- ing deficit"the project may be unable to proceed without imposing a substantial and possibly unacceptable burden of high early-year costs on consumers .. Ii II I' I I I I I I I I It I IJ IJ ~ I I Ii,.!'"Ii 11'·,',• I I I I I I I I I I I 11 IJ IJ .~ ~g I IJ I J 6/29/83 with the project selection process outlined within Alaska Statutes. T.he Alithority 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 'whicn exceeds 1.5 megawatts of installed capacity •. The Alaska State Legislature has specifical-ly addressed the Susitna project in legislation (Statute 44.83.300 Susitna River Hydroelectric Project).The legislation states that the purpose of the project is to generate,transmit and distribute electric power in a manner which wi 11 : (1)Minimize market area electrical power costs; (2)Minimize adverse environmental and social impacts while enhancing envir~nmental val ues to the extent possible;and (3)Safeguard both life and property. Section 44.83.36 Project Financing states that lithe Susitna River Hydroelectric Project shall be financed by general fund appropri ations, general obligation bonds,revenue bonds,or other plans of finance as approved by the legislature.1I 6•4 -Fin an cin9 Plan The financing of the Susitna project is expected to be acc'Jmplished by a combination of direct State of Al "-ls'ca appropri ations and revenue bonds issued by the Power Authority but Garrying the "mora'i obligation ll of the State.On this basis it is expected that project costs for Watana through early 1990 will be financed by approximately $1.8 billion (1982 dollars)of state appropriations.Thereafter completion of Watana is expected to be accompl ished by issuance of approximately $2.0 billion (1982 dollars)of revenue bonds.The year-by-year expenditures in constant and then current dollars are detailed in Table Do 31 ~These ann ual borrowi ng cmounts do not exceed the Authori ty IS estimated annual debt capacity for the period. The revenue bonds are expected to be secured by proj et.t power sal es contracts,other avail able revenues,and by a Capital Reserve Fund (funded by a State appropriation equal to a maximum annual debt ser- vice)and bac\<ed by the II mo ral obligation"of the State of Alaska. Thecompletial1 of the Susitna project by the bUilding of Devil Canyon is expected to be financed (as detailed in Table D.31)by the issuance of approximately $2.0 billion of revenue bonds (in 1982 dollars)over the years 1994 to 2002'with no state contribution. Summary financial statements based on the assumption of 7 percent infl ation and bond financing at a 10 percent interest rate and other estimates in accordance with the above economic analysi s are given in Tables D.32 and D.I0~for the $1.8 billion state contribution and 100 percent debt financing cases,respectively.Figure 0.10 shows the cost of energy from Susitna assuming the $1.8 billion state contribution. D~6-2 (Revised 7/11/83) - ;,'\nt •! .......=.J l... I··'··.· I'.. I~·. '. I I I I I '. \1 ~I I .IJ 'I ~ ~ ~ ~ ~ I 6/29/83 The actual interest rates at wh i ch the proj ect w;1~I be fi nanced ;n the 1990s and the rel ated rate of infl ation cannot be determined with any certainty at the present time~Also,while the market for Susitna powe'f'is rel atively insensitive to the world oil prices analyzed,the finance plan is affected by those prices through their impact on the wholesale prices Railbelt util·~ties would face in the absence of Susitn a~ A material factor will be securing tax exempt status for'the revenue bonds.This issue has been exten3ively reviewed by the Power Authority·s financial advisors and it has been concluded 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 percent infl ation and 10 percent interest rates used in the analysis are cc'nsistent with authoritative estimates of Data Resources (U.S.Review July 1982)forecasting a CPI rate of inflation 1982-1991 of approximately 7 percent and interest rates of AA Util ity Bonds (non exempt)of 11.43 percent in 1991,droppi ng to 10.02 percent in 1995. Because of the above cond'itions,-the financing plan is the subject of continuing review and development. D-6-3 (Revised 7/11/83) ..*I··.• I .I j l J Ij, I 0 In Beluga Coal Market______,J,.....~_ .. •51 Alaska,Agreements ofWa~es and Benefits for Construction Trades. effect January 19S.' .- Ba-ctelle Pacific Northwest Laboratories.1980. Study,Final Report.Richland,Washington~ Volume VII:Fossil Fuel Availability and Price Forecasts for the Rai lbelt'R~g10n on:rrasKa.. Volume IX~,Alaska Economic Proj~ctions for E?timating Electricity Requirements ,or ,e al e.'•.'•.aa:q Volume XII:Coal-fired Steam-electric Power Plant Alternat-ives for the Rai"l/biTtlfeglon ·'or-f\laSk£.e :5 Q Alaska Department of Commerce and Economic Development.July 1980 .. The Alaska Economic Information and Reporting Systsm. B.C.Business.August 1981. 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Coal Week International.Various issues. 4 1_ Code of Federal Regulations.1981.,Title 18,Conservation of Powera~esources,P'arts 1 and 2.Government Printing Office,Washington,D.C • Commonwealth Associates Inc. IntertieRoute Selection Report.AUt'horfEy.3' Data Resources,Inc. National Energy Board of Canada,Ottawa,Canada.October 1981. Personal communication. Noroil. 9)• Data Resources Inc. Lexington,MA.~FE!deral Energy Regulatory Commission.Office of Electric Power Regulation.August 1979.HYdroelei:tric Power Evaluation. ;-~Japanese Ministry of lnternational Trade and lndustry.January 1982. Personal communication. -......... I IJ I I I.•'.' f ..i. I I- I I I: ,; .." ~Mlshan,E.J. London. ~ ~ •~ I I I I I I I I I I I I I t f I Phung,Doan L.f\pril 1978.A Method for Estimating Es ical ation and Interest Duri~~"Construc 10 ..ns 1 u e for Energy Analysls,Oak '1mf§e Assoclate~s. 'Prest,A.R.and R.Turvey.1969.Cost-Benefit Analysis:A Survey .• Economic Journal (Volume 75). Roberts,William S.July 1976.Regiona1ized Feasibility Study of Cold We.ather Earthwork.Cold Reglons Re'search annnglneerlng l]boratory,Speclal Report 76-2. SRI International.October 1981.Personal communication. Sega1,J.December 1980.Slower Growth for the 1980's.Petroieum Economist. Segal,J.and F.Niering.Septem0er l~mO..Special Report on World Natural Gas Pricing.Petroleum Economist. U.S.Department of Commerce.S~rvey of Current Business.Various issues. u.s.D~partment of Energy.1980.Anrtual Report to Congress.Energy lnformat ion Admi ni strati on.·was'FiTii"9ton;lJ.c. U.S.Department of Labar.Monthly Labor Review.Various issues. I Wharton Econometric forecasting Associates.Fall 1981.(Reported in Economic Council of Canada CANDIDE Model 2-0 Run,dated December 18,1981).Philadelphia,PAlO World Bank.1930.Commodity Trade 2!l~Price Trend§..Washington,D.C • •January 1981.-Personal communication.--- --,-'" -665 5,760 3,406- 14,316 $5,815 1,924 $12,834 180- 3,200 1,610 6,364 $1,734 $6,364 485 7,952 2,.560 1,796 ............~. January 1982 Dollars $X 10 6 "Rat ana Oevi 1-Canyon -"fO't'a'r__6: $2,293 $1,065 $3,358 456 105 561 5 5 10 442 205 648--- 3,196 1,381 4,577 400 173 573-- - $3,596 $1,554 $5,150 lilt "--1-'7""; Revised 7/11/83 314 $6,470 TABLE 0.1:SUMMARY OF COST ESTIMATE -i Overhead Construction Escalation ECONOMIC ANALYSIS (OGP-6,0 percent inflation,3 percent interest) Escal ation Genera 1 Pl ant Indirect Total Construction Transmission Pl ant Catagory Production Plant AFDC TOTAL PROJECT CONSTRUCTION COST AFDC TOTAL PROJECT COST TOTAL PROJECT COST SUSITNA COST OF POWER (Table 0.10,100%Debt Finance) FINANC.!t\J ANAL.!SIS (Table .0 ..32,$1:.8 Billion state Appropriation) Escalation 2,560 3,200 5,760 AFDC TOTAL PROJECT COST 'f ~, I I I..J' I f f 1 I I I I • I I I I I ,~ =::: ..~.... 9leet 1 of 5 Rancrks. ..:.. Total~){x leP- $2)293 J!IIIJ 51 74 1,547 66 21 14 214 1,007 Di .. ~J~ $ ""'-A~.:.~5 gibe.@4iQ...Ao"'.....~·_."..~·i I Ij I, I j ! I f> LJ· "•-I': ','0 ".'~',,1}'-" "Ie ::,:1 ~,,,",':'';1)'.;'",'~IW __'"i ~,'<.>x ...,:·':.",{i::;::?;,,~'~'~i v,' ~'~~ ~r:r::::::;~::~ TPBl..E D.2:ESTIMl\TE stf.MaRY -Wl\TAW\. ~.~,-,...•......•.~..,............•.. •.~"... ~':"":':i-,.-',.. ~/i\~~""", .':) 'JII!II!IIIIIII 1.,.....,'-"'~_,-c. r.escriptioo ffim.crIOO PlANT LCfld &LCfldRights WaterWleels,TlI"bi nes &~ators II ••••••••••••co •• Reserv.oir ,Dans &Water1tfc\YS {>II •••••••• I'oYa'-pl <Ilt StroctLr"e5 &lrr(Jrovanents •..•••••••••••••?••••••~. Slbtotal «II II ••••••••••••• Coot.;~y •II ~It . Pccessary El ectrical E(~ri JlTe1 i:<>. lDTAL ffim.crICJ.IPlANT 'o!'II It . R1::>cr:ls &Railroads ". Miscel1ClleQUS I'oYa'-pla1t Equiprent(~CI1ical j II •••••• l~"" 33) 331 332 333 334 3li ali 3~;'!"" Line Nurber- .:'j " LJ ..fY');:,;!;' ·.•..·....·.1 ! 4 .'.\J'~ I ,I., 'C ,:J G!:.} IIIIJ .. II1II Sheet 2 of 5 .. Ranarks .. '.~.1IIW'•.-il 456 Total~i x 10'1 $2,293 $2,749 .... 395 61 $8 .'12 131 131 100 13 f:TJ) -JIMIII.--~._.~.._<..•.•...l~"""""--.'._..;,;,:;,,,"; @!gIg;~_,.....---.,..,:;;...J@i-,~_--.._.l r.-...._--..,-.~~~ LCild &LCIldRights Q ~•• Slbstation &Switching Station Stroctures &liqJroV6le1ts ..g ~••••• Slbstation&Switching Station E(JJiprent . ~iP.tiCJ) Ro?rls &Trail¢;.. Contingency It 'I . ().tertlea:l CondtCtors &ll:vices •••••o ••••c •••••••••••••••••••••.,•••••••• Steel TO\Ers &Fixtures "1/It .. 1RAN9-1ISSI~PlANT- IOTA!..1RAN9-1ISSIOO PlANT """"l>.. Slbtotal •" . f~,,-t j "....,._.•~co7l..l<J TOTAL BROUGHT FORWARD ••*.v ••••••••••••••••••••••••••••~••••••••••~•••• l)() 352 d53 li4 356 359 Line ~ ~,-,-"""~- TABLE 0,2 (Calt'd) l·Xill@.......,~,~..•.., ""'1 {I.i III c: :~"'!''''~ ,... II n II IS II II 10 ~"".. . .... II II II II u II .. Iocl u:Jed lI1der 3D Ioc llJ:JOO tn:ier 331 Incl trl€d·lflder 399 Ranarks 9leet 3 of 5 ...I-OIl 5 Total~ JIm $2,749 $ $2,754 ..11;;11 5 f:rJ) 4 $ 1£4!II!..""""",.",,,~;~u~~g§~~t'5~"",.,.;:~.:................,i.;"i ••O ••••••••••~••••••••f ••e •••••••a ••••••• •••••••••••••,.·••0 •••••••••••••.••••••••••••••• ~I lUi!"".,.....~.,>......,..,".,~J •••••••••••••~•••.•O-••••••8 •••••••••••••••••••• ····~···.·••••••••••••••••••O.D •••••••••••••••• ••••••·••~u •••••••'••••••••o •••~••••••••~•••••••••• ••s ••••••••••a •••••••••••••'•••.•••••'•••••••••••••••~_ ~\...,~-_.~~L<-:~,,~Ir-.l,.,.,,~....,..:...,;;;,.:..j Il=scrj~ioo ; Wit.BRO.Gff f(RWJlRf) tH£RI1L PlANT S~E~iJl]e1t 0 '••••:••••••••••••• ' •••••••••••••••••••"••••••••••••••,• Land &.Land Rights 5tru:tures &liqlrovaralts Office Ftrniture/ECJliJl]e1t ". Trillsportation EquiJl]e1t .. lUTPJ..GEf\ERALPlANT "'. Tools .S1op &Gcr~EquiJl]e1t LctKlrator'yEquifl1'el1t . Pa.o.er-QJerataj Equi pm: G:rnTtrlicatioos EquiPTBlt . Hi see11 aleOUS ElJIiprent ()ther TCIlgi b1e.Property ".. (i r-- l39 399 397 398 393 395 396 394 300 391 392 TA8LE 0.2 (Coot'd) line rtnber ~ !:::;> (; I II 1 II'! ({ o r-:IJ ,1 r ,-:::1 ...... Renarks ~I'bte See rt>te ~rbte Seert>te See ~te Sheet 4 of 5 .... 442 r~tr~) $211 754 $ $3,196 ..J!iM~ 29 373 402 40 tn~) $ zgIy!'J!III."'....""'""'-..,.~@Ss r--:- -i'_;._;'''''';:.c_.;,.;~'';'-\._l_~',.,~ ~~) o -,r -----'~>f o ~~4-c..; •••••••••¥••••••G ••••••••••e~••~e ••••••••'••••••••••,•••••••_••• Q O:>sts lIlder a;colllts 61,62,64,65,66,cn:f 69are'inclooed In ttl:!~late dlrect costslista:i cOOve. .:-- ~riptioo Ccl1strtJ:tioo EllJipnent ". IDTPl..BRaHff F~!It •••••••••••••••••••• IMJlRE(,T OOSTS T811JOrary Constru:tion Fcci]ities . CiJ11)&Ccrrmi ssary It •••••II It '•••II • Insl.r<llCe ;). Lci>or'Expense .,"••••••••••••••••• rbte: $uJ:>eri ntenclence •••••••••••••••••••>•.,:;••••••••••~. Fe...-~••••.'11". Mitigation . Cant ingency •••••••••II •••It e . roTAL Ir-IJIRECfOOSTS _:=;... Slbtotal mTPL aJlSTROCTIOOOOSTS ~ .l>h.·,.-.~~'t::...-..;.;...:"-.c=.~ (? 61 62 63 64 65 b6 68 69 TPBL.E 0.2 (Ca1t'rl) ~ ¥¥~ ,.-,- II (} I TPBLE 0.2 (Ccxtt'd) lA:scriptioo I '.,,,,"",-_ ..-.... ~~ks,. .. - .,. Total~ (x !CF) ... f:TJ! lJilil'MI.M@;tEN;112@4..~:~.......--Mi??,£8.M ,".,.,,",~,",,,~,_...;.~.."-4 •.,._..~'~J'!i[-:~~,.,~~is "".. i;..-._...:'.,_.'"~~:g _! line tbrt>er. ~",':-.,/c .} .r, l~'''~l~\) ........·1. .. - Ioc llded in 71 ~t ~1imble Incl~:"3.d in 71 rtlt i rc llk:1a:1 rbt incllk.L~ Sleet 5 of 5 $3,100 400 $3,596 ~i,_ l36 14 $ '0 Engineer'iflg/A::tninistratiOl1 "•• E'J?virot1TB1tal MJrli,toring ••••••••"."."•••••••••••••It ••". OVF.RI£PD ~OCTIOO C()SJS (mca:CT IrlJIRECTS) Taxes ••••••••••••••••••••••••"" "••••••". Legal Expenses ••••••••••••••••••••••••••••••••••••••••.••••••••••••••• Aininistrative &~al Expenses •••••••••to "•••••••••••••••"......"••".... Interest "0 ••••0 ••••••••" •"••••"• "•••••••••••••••••••••••••II!.. Ecrnings/Expenses Dring Constroctioo . TOTJU..mnJ:CTaJST o •••••••"0 .,•••• Total £Nerhecr::l •••••••••••••0 . lOTlU..~OCTIOO C()SJS 'BR<X.Gfr F~.""•••••••••••••"•••"•••"•••"t 71 72 75 76 77 80 '.::::::::J .'}".."" -~,',"~.... Pancrks 91eet 1 of 5 -.. 7~tr~) $1.055 .JIII,!dJJL@ y r 923 142 $22 69 646 42 14 11 119 ~I ·i!LJ'Y,~(B!19£1 !J ~...,.".;,_-~:-';l '.'().~----- tfJl TABLE 0.3;.ESTIMl\TE·SfrMORY -~VIL CJWYOO ; ...--1,,,,,.._.~-,~.:l ••••••••••••••__•••$•••••~•••••••••••••••••••••••••• ~p :'•..1 i; !;...,..,._...-.~ ~,4 ••••••••••••••••O·•••••••••·.-•••••••••G ••••••~••••••••••••••'••• ;.~.. ~SOj1Ptioo i m<nmOOPUWf Land &.Land .Rights Pc>\e'"plCllt StrtJ:tures &lntJroveJe1ts ••••D D ••••••••••••••• WaterWleels,Turbines &Gener-ators •.••11 It . ~servoir ,0000&W~.orw~D •••••••••••••••• kcessory Electrical EquiP1Blt D . Miscell(f}e()US ~li1lt Eqoir:nert.(M:ch~ical). Contingerx:y e •••••••••••It It 0 ••• Stbtotal Roa::ls&Railroa:fs •·•••••.••0 ••••0 0 ••II . lUTPL.mro.crlOO ~•••••••••••••••~•••••••••••••••••••••••••••••••• n !~~ ......<- ,-~--~-~-~-.----_._--- 33) 331 332 333 334 335 3.li ~ F .~ -J I ! ·'f I _..,....'-~""'" lJ'-i .i ,, .-;:,•.·.:1 I °1 i.;.. ,I {t ••d ••'•• ....- IncllX1ed in WatcYla Estimate Rancrks Inc lllJaj in Wat&1aEstimate Sheet 2of5 ..HI 105 $111 055 r~tr~) $ $1,170 'IMQ!¥fItQ 7 21 29 31 91 14 f:jJ) $ @1Mg,-~.........'"",.04)k~;,~ •••••••••••••• ~F"';ruy.,.. o ~--~.J E·LI ga t) rescription- Stbstatioo &Switching Station Stru:tlK'eS &1rrJKoverents W&BRClGffFrn~••••"o ••••••••••••••••••~. lRANSMISSlOO PlANT lcrtd &LifldRights "0 . $lbstatioo.&~1tching Stetloo E~illJ8lt ". (}Jerhecrj Conductors &~ices ",.••••••••••.••••••••••••• StE!elT~'"S &Fixttres ~••••It ••••". t..ontingency II . Rcl;;(fs &Trails ••0 "'••••••••••••••••". Slbtotal ••,". 1OT&~SSIOOPlJWT •••••••o •••••••••••••••••••••"'•••••l>"•• ......~. 350 352. 353 354 ~ 359 TABLE U,,3 (Coot·d) Line rtnber ,~ t II d-J I'I": o ~ I I'~,, lj,: ',,'I rf:,:'»~ j f)'..",~.~..~t J',..\j;._..,.,..."......,-,.,-.' .... II II II II II II II - II II II II II II II IoclllBj lIlder 3ll Incl tdOO·lI1der 331 Inc100ed Ln:Jer 399 9leet 3 of 5 Pancrks I..- 5 ~ f!tr~) $1,170 $ $1,175 limMY; Ii'~3-i 5 Protrtt (-x 1CP!• $ ~tIJIi!!!~... <..',"'''.';';'~....j......~ ···········'···············~.'•••~••••••~•••o. ••••••••••••••••••••a •••••G •••.•••••••••••••••• •••••o •••••••••o •••e •••••••••u ••••••••••••••eo ••••O··.·,••.••••..•..~.a.»•••••••••••o.o •••••• ... ··~··••••••••••••8 ••••~~•••••••e ••••••••••••••••o e~e~.·••••••••••••e •••,••••••••••••••,•••••••••••••• •••••••••••••••••••••••~•••••O •••Q.s •••a •••••s •••••G .O •••~•••••'•••O •••••••••••••••G ••••••••••••o •••~•••••Q •..IM:;~".-,, Il:!sctj,et i<!! lOTPl mcm;r FffiWlVID C£NERPl PLANT,; Lent &.la1d Rights l'W!!IIl!I!I " Stroctures &IrJP"'QvarBlts ••••"•••••••••••••••cj •••••••••••••••••II."'.It •• Office Fumiture/E(JJiprent Trmsportatioo EquiprBlt Stores Equipne1t Tools Sflot:>&Gcr-~Equipre1t . Lcborat.ory E~illJ81t Ib.er ~ated Equiprent Camu1icatioos E~iprent Mi scell CJ'le()US Equi prBlt . ()ther'TGJlgible Property "'. .-::~ IOTft!..~PLANT ••"'..>••••0 •••••,.. ~ 392 395 393 394 396 :B7 398 399 _389 ~ 391 TABLE 0.3 (Calt'd) Line.rtnba-- ~..... I",'jr-I -~-"'--"""";~.....,,;~. Rancrks- ~tbte ------. See ~te See rt>te ~.Nlte See NJte See tbte 9leet 4 af 5 ~ 200 1~281 Total~ (x 1(1')-- $1,175 - $ $ ~ 4 184 188 18 (:>w) $ ~~~..""",,41u='!:~"~-f""""'-"=""" .....'.......•.......•........•..~.,... L-'~~5 •••o •••••~••••••••••••••••••••••••••••••••••••• .oo·······················~·········o ,. "~P.:IN •......o·····.•.........•.o ~. ••e ••••o ••••••••••O~••,D •••••••»••••••••••••••••••••••~•••••~ i'_.L,': •...w·······..••....•.....s ••••••••••••,••••••,~•••••••••s ••••• Costs t.n:Ier a;c olJlts61,62,64,;::"Ci,66,iJ1d 69 are iocllKlerlln the w-oprlate dlt'OCt costs1istajci>ove .• ············,·······*·,··~.~~..•........e.8 ••••••••••••••••••••••e •• r---1'-">'\ ~scriptioo-1 -~ lUTPl..ma.GiT F~••••••••••II ••••••••••" • "". INlIRECT rosrs. Tarporary Const~tioo Fa:ilities Constroctioo EQUi prent Carp &CcJmfissCl"y ". ~~intaldence InstrillCe "••••••••••••••••••• Lalxlr'fxpense II ,"•••It Cl to ••••••••••• Mitigation Fees ~te: Contingency D ". Stbtotal lOTPL II'VIRECT COSTS lOTllL amTRtcrlOO rosrs ~ TPBLE D.3{Coot'd) Line rtnber. i;ltL ..., I ... ···L· ··•.···.·······.i.:.' "i 1 I .~l o D "" .~--......, ~t50f5 Inc 1LXJed in 71 I'bt pppliccble IocllKled in 71 I'bt Inc ll.JCBl ~t Inc ll11ed Rancrks -..., 173 $1,554 ],otal~),(x lLP $l,lU .... 167 6 ~ *<'*1'..... rxoWl $ ..11'I,~~~~ co, l!.~'-~,-ri!tj Inter'e'st •••••~•••••••••••••••.••••••••••••••••iii •••••••••••&5 ••e ••••••• ~a1.Exper1SE!S •••••••••••••••••••.e •••••0 ,e •••••• Ecrnings/Expeoses lAJring Constru;tion "•••• ~Ql\5TROCTlOO Q!iTS (PROJECT IMJIR~CTS) lDTPJ.ffia:EcrOOST"••,•••••••••.•.••••••••••••It •••••••••••••••••••••••• Total (Nailea:t ())sts ,.. Taxes •••••:••••••••••••,•••••••••••••••••It a ••••••'.••it ••••••••••••••••ct.Ii» Envirot'l1'Sltal r-britoring "•••••••••~••••• Engineering/Mninistration •••,.•••,."••••••••••••,.•••.••••••••• ~scriptioo WTPl.Ql\5TROCTIOO ,(I)STS BRCX..G-·rr Frn~••••••••0 ••••••••••0 ••"••••••• Pdninistrative &feneral Expenses . ".~r .$.,_" 71 Line Ntrmer TABLE 0.3 (Coot·d) .... ~ .(j! "'.'"_",r, 72 75 76 I I I 77 00 1"<:- 14,600 NO. W\ 1,OCO '2,ax> 200 100 W\ 9,cm 500 27,400 5,500---- 32,roJ' 4,100 37,000 152,500 [EVIL CANYOO $X IDJ 47,100 1,600 600 2,31) 4,100 400 100 18,400 10,200 800 85,600 17,100 102,700 12,00:>... 115,500 TPBLE 0.4:MITIGl\TIOO trEASLRES -SIJtMDRY (f Q)SJS If\CffiPffiATED IN COOSTRLcrICN COST ESTI~TES Q)SJS ·IrD:RPffiATED IN COOSTROCTICtl ES11Ml\TES--Mlet Fa:ilities Main Dan at !:evil CCIl}Ut1 TlI1ne1 Spi 11way at WatClla Restoratioo of Borrow Jh!a D Restoratioo of &>rrow Prea F Restoratioo of Carp m Villcge Restoratioo of Ql1strl.Ction Sites Fencing crollld Carp F~ing arollld Gartcge DisJX)sal Area ~lti1evel Intake Stn.cture Cam.Fa:f1 ities.Associ ated with try].~to Keep WJrkers out of Local Carnu1itles Restoratioo of Haul Roa:fs SU3TOTAL Contingency 2C'1X IDTAL COOSTROCTIOO Engineering 12.5% IDTflL moJECT f, ., j, ( TABLE 0.5:st.r+mY (f CFERATIOO PH)WUNTErmE COSTS .!21............~J1t-M ~rl>s ~t~~t~-,"8 l'JJlJlI .lUi ••-..-..- ! ~I ().I I --III. I I I 0200 1(1) 500 '4';1m[EVIL ~ ($OOJ's OnittaJ) -S<pense . Lebar Itans Stbtotal 400 1(0) OOJ lO;lmWL\TANl\ - 533)m 6320 1920 500 2420 OOJ ~--400 400 540 340 Em 120 00 an WJ\TJWIl.! ~·S Onittoo) pense lcbor Itans Slbtotal- -. Po\Er.&Tra-tsnissioo QJerationl Mainta1ne PennCfleOt TOIIlJsite QJercd~ioos Al JaNiIlCe for EnvirortJaltal Mitigat.ion Contra:te:f~ices Cootingency A:lditiooal All<>Wa1ce fran 2(X)2 to Reploce CaJJ1wity Foci1ities Total ~atirg <fldMaintEJICl1Ce Expenditu--e Estimate Po\Er~lOJ)JEnt ood TrCfismissioo Focilities (1)Iocrarental ~-:-·'-""'""'-"'-----·_·_·~~·'-'~""l~---- ~.f ~, I I TABLE 0.6:VARIABLES FOR AFDC COMPUTATIONS c \ \... I , I l~ I.-------:::r-i 10 7 8.5 7.5 3o 8.5 7.5 Analysi s Economic Financial Effectiye Intere~t Rate (x)%Escalatl0nRate lY)%.Construction Perloo (B)yrs.WatanaOevi1 Canyon I I I I \ I o J~ t\o \:; (> /,Si[¢I~ .~ I 1 i :f, ~ ~~,.=i~· -..--••'IQII -- '" ML¢A.. ~-..."'-.. r; -',>~ c TABLE D.7 -SUSlffll\HYmCELECTRIC ffiOJECT Wat(fJaa1d~il CCJ1P1 CuuJl ative a1d J1llnual Cash Flaw .27.6 '27.6 Zl.6 12.9 40 ..4 40.5 28.7 69.2 69.2 48.5 117 ..7 117.7 199.5 317.2 317.2 283.9 601.1 601.1 295.4 896.5 896.5 359.0 1265.5 126"':.5 4~.4 1703.9 1703.9 627.6 2331.5 2331.5 4.9 613.7 2940.3 4.9 2945 ..2 47.~t,476.9 3l59.3 52.8 3422.1 68 ..6 221.8 3522",5 121.4 li43 ..9 "t 64 ..3 133.0 3596 ..2 185.7 3781.9 64.9 64.9 250.6 l346.8 115.3 115.3 155.9 3962.1 201.3 201 ..3 f£J7.2 4163.4 291.8 291.8 854.0 4455.2 n ZJ9.7 279.7 lIlt.-,4734.9'! 241.7 7A1.7 IHl.4 4976.6 156.0 156.0 1515,~5132.6 17..6 17.6 1554.0 5150.2-1554.0 5150.2 [) ~i..,...'..... .r.:. !-"" 27'.6 12~9 28.7 48.5 199.5 283.9 295 ..4 li9.0 4~.4 627.6 600.8 429.0 153.2",~ 73.7;fJi 3596.2 ,.. l." ',? Ja..'«.LDRy l~Ill.LMS -IN MIlLI(J\lS~Ll'A'mrnI .:+~J!M -~~RAi'~. ,".;~., 1981 B2 83 84 85 ffi 87 00 89 00 91 9'2 93 94 95 96 97 93 99 2(0) 1..001 2002 IOT& :' ~ '" !~btl [••d.r.. .,I I J r,.!' --"~ (j 55,556 9,449 (a 66,ro> 6,784 3,DJ 3,100 3,960 3,3)) 86,449 21,612 100,001 13),754 TOTPL COST (lOOuSiiCiSOf1:b 11 ars ) - TABLE 0.8:~FAIRBJW<S INTERTIE PROJECT COST ESTIMl\lE Total Line 175.1 miles Total Stb~atioo Cost Slbtota1 R/W Pcquisition ($40.00/Mile) rtbilizatioo -rarooilization 5% Surveying Engineeri ng 6% Coostroctioo MiJl~5% Slbtotal Cc.,tingencies 25% Total Sept.1981 lbllgrs Inflation @ l~/~ar -2 J€ars &luree:Camr.J1v.ea1th Associ ates,JCIluary 1982 I I I ··I····.·'t. ''\ ; I'l '1 I 11 I • .'•..'.! .'1 I I; Ii I) I_- I: I, ,~ I., I. •) o '7 1 I I 1 I G I -;:1 DEVIL CANYON $955 t 723,000 77,712,000 rt,o33";4j5 ,DOer 170,688,000 ~ 184,177,000 $~ 115,000,000 Not Included $I,503-;-300,000 $4,062 x 10 6 1,503 x 10 6.... 5,565 x 10 6 -79 x 10 6 $5,486 x 10 6 • $2,502,053,000 411,774,000 1,113,000 )~ 362,681,000 ~ 503,979,000 $3,781,60D~uurr 280,000,000 Not InclUded ~ .WATANA - __,,0·' ii"•• Jj TABLE D.9:SU~1MARY OF EBASCO CHECK ESTIMATE ) 0 0 REVISED ~Q~~~Y (B~ACRES) Watana Cost Devil Canyon Cost Total Proj~~r:t ~?~v.4) Adjustment for Revision 5 Adjustment Total Pt"oject DESCRIPTION NOTE:.Adjustments were given by EBASCO in meeting in New York on Apr;1 14,1982. PROJECT COST SUMMARY The hydroelectric development cost in ,January 1982 dollars is as follows: The following figures and comments are taken from EBASCO's estimate dated March 26,1982 • Hydraulic Production Plant Transmission ~lant General Plant Total Direct Construction Cost Indirect Construction Cost Subtotal for G0nting~ncy Contingency Totar Specific Construction Cost Professional Services C'f ient Costs Total Project Cost The above costs are based on quantities contained in the Revision 4 Estimating Package dated February 12 t 1982 t as prepared 'uy Acres American.We have not considered any quantities contained in the Revision 5 Estimating Package dated March 4,1982,since the transmittal was received one month later than the revised information cutoff date of February 8,1982. Major cast quantities have been checked to verify Revision 4 quantities as compared to Acres'Project drawings.We have provided an asterisk next to the accounts added by Ebasco to reflect costs not properly included in other accounts.Unit prices supplied by Acres American Incorporated are footnoted. -.'"11 I•..•~, , 11.··o••n,.•.b~~ .~•.o~Ij ..1...:...1 ."\.•i£;1 !., I' 1\.~.:II ", I..OJ.! I I) Ij I , I I I~. I, J, 06***********O***~**C***O**.******.********O****••****************.*****************~*.*~~~********~*.************~****••*¢****CATAi2K.012 WAT4NK (O~LINE 1993J~NO SlATEfUNCS-I~FlA1ICN 1~-lNTE~EST 10~-CAPCCST S!.15 f~.......24-4~~-83*****************************************************************.*******************~**************.******.****.*.*~****.***** ·~~...~.....~--....:-..",....',gm Ilg ~!I -t!!I {!Ie - I _lf$ll~'*,; .~....'...-..... NO STATE CONTRIBUTiON SCENARIO 7%INFLATION AND 10%INTEREST r I I i ~:.~;,~,,:<-~-'Il')J.~-. j. I..~I J i I I I I j I ! I I ~ I HI.? 15.~2<;d -~.. c.e 54.5e.e 116.6 15.3 246.3 1:4.5 H7 ..8 4.(:" 12.f 1c;~.:? 4Ci.2 <;2.3 :oaC E422.4 c.C 74.5 141.5 €30.9 7 r.q......... ~1e(;..1 1.(3 1<;94 e5E3.<; cOlec.ee.e e~Z.1 24.c 2<;~7 12E.C5~,~.a,~~!~ Oc;E.?h --:"-.-'-_.- _._-----,- -._-.__._-- ==,==:::=: ::==.:==~= (J ! I j j 1> TA B LED.10 .'li,.J '--.....~-----..~~..,,-t _~_,..__l.·' f~31 126 :3C C cOle (}.c cOlecOle 2953 119.1:5 211.73 HC.3C 1993 lEC.C c.C 46.C eC.3cOleeZ2C.l c.oc.e 653.1 126.3 14(:.C ~c ..ccOle 14f:.C E:3 47.e 7i:~.E 22.6 e.ec.e 126.~ E2H.l 3eC.2 411C.C;l.ce ---.,--_._- ======== ---_._._._--_.__._-_.- cOlec.o cOlec.ec.e 15t;J.C 176.C 4410.7c.ce ce.oe 2C3.4S e.cc 0'.0 cOlecOle 1561.C alOec.e 1579.2o.e 1<;92 75c1'''C _._--_.._-'- c.c 0.0e.ce.e--_._..__._- c.e --------1519.2 1519 ..2o.cc.c cOle---------o.co..c 0.0 ==:::,==:::=,: "'======:-= 5981.P. o.e 0.0 159t:.c;clle 1991 o.co.c 0.0 1596.<; 1596.<; O"Co.e c.e co.ee 19C.l1o..ec c.eo.e cOle c.•CQ.C SCi a l.e cOlee.ce.G 5ge1.I: 83<;.1 3634.6Oeoe c.oe.eo..ecOle-----_._.-o.e ------_..- =.===.=-=,== ==::==-=-== c.e c.c COlO 439].C cOle c ..c·--_._--_.- c.ec.ee.e 4391.C IS!,,! 219~.:'Co.co ClOtc.ec.ocOle -_.__C).__.._.. c ..c 439).C cclOce 17J.73o.cc IS9C e.ee..c l.1jl~.2c.e--_._----1413.2 ====-==--== 141~e~e.ee.c cOle-_.._.._----c.ecOle c.e :::=:::: oc.co16t:elCo.cc '~~-~~~._--~~, COlO e..oc.e 2911.7 G..oC.O COlO 2911.7 932.1 C.OCoC C.C 932.7 C,,!) COlO c.o COlO 9~2.1c.e cOlec.ec.o 2911.7 5t:l.5 1'99~.Ee..ce ______A.,_ cOlec.oc.ec.e-._---_._-C.o ===::::= ====:'::: G.O 0.0 0.0(J.O 706.7COlO 0.0c.o 0.0 0.0 0.0 0.0 0.0 0.0 10601 '/06.7c.o 0.0 0.0 J.O 0.0 0.0 2C45.0 2C45.0 0.0 0.0o.c 2045.0 455.2 1438.3cOlao =-===-=.::== :=-====== 19a1 1~a8 19€9 CAS~FlCW 5UPM~R' ===(IPIlLICNJ====C ao..~o C.OO 145.e8 155 ..2 ..... 0.00 0.00 COlO C..O 0.0 C.O 0.0 c.O 0.0 0.0 0.0 o.c 511.3 511.3 0.0 0.0 0.0 0.0·c.o 'ill •~ 0.0 c ..n 0.0 0.0 1338.4 1238 ...4 c.~o.eCOlO 13:3 e.4 352.4 983.] 0.00 ==,='===== ::====== SHEET 1 OF 6 425".1cOleCOlO 0.0 cOle O:»CcOleE27.1 Q.OCOlO 425.1cOle COlOo.c cOleCOlO COlOCOlO cOle COlOo.e COlO 1ge6 E21.1 425.1 oo.OC 135.59 0.00 cOlec.e C..O EZ7.1 313.5 630.7 0.00 ,_._-_._--- ~==::::=== ===:==== 0.0 COlO COlO 0 ..0 '.02.a COlO cOla 402.0 0.0 0.0 402.C cOle COlOo.J 0.0 402.0 40.2.0 COlOo.t) C.O 1985 COlO 0.0 0.0 0.0 cOle COlO 0.0 4C2.C 311.2 317.2 0.00 a 0.00126.12 0.00 ======== :'======:= ~-------'~--~----- ~\II tl[1 FA1NINGS FPOM QPERS -----~AS"SOURCE AND USE--~CASH INtGMEFRCMOPERS STATE CONTRIeUTII1'J LONG TERM DEBT D?AWDCW~S HUQcap c~eT nR~HOOWN5 TDTALS~UqC~S OF ~UNDS LESS CAPITAL EX~ENDITURE l.!;.-SS WORCAP IHWfUtlCSL~SS DEBT REPAYMENTS LESS PAYMe~T TO STATt CASH SURPlUS(O~Ftc I1') SHORT TER:1 DEe I CASH RECOVr:REO -----BALAN~E SH~f.T---------RESERVE AND CONT.FUND OTHER weRKING ~APITAlGASHSURPLUSRETAINEDcu~.CAPITAL EXPENDITUF~ ':APIT4l J:foI"l'J'YEIJ ST~TE C'JNT11aUTJ3N tlETAINJ:=C EAPNING1 DEBT OUTSTANDING-SHORT TERM DEBT UUTSTANDING-lDNG lERM ANNUAL DEeT O~AWWOCWN U 982 CUMe DEBr ORAWWDCWN !1~62OE~T SERVICE COVER ~43 54.3 I't46 143 ~4!J 73 EN::rGY .~WH 521 ~EAL PRICE-~ILlS 466 INFLATION l~OEX "l2Q PftlCC:-MlllS -----lNtJMF-----------_---__ '11.3 '1 ~VE~~IJE 17'LESS OPERATI~G COSTS 517 gpe~ATING INC~P~~14.'\CO INTEitcST EARNED Of\FUNes 'j'iO lESS 1 NTEREST ON SHeRr TERM DEBT'}t)l LESS INT::REST C\J lONG TERM DEBT 'i 4 .;» 141 249 44'1 "';ZJ '.4:'1 260 395 (t.~c; 225 371 1f'54 373 461 462 555 554 542 543 519 J If LJ ....__,~_~_"__ I ****,******¢*1)**f,l*l:t**(::'':;':'~¢**~'''':**>!1:*****f,l******:It*~***************************************l)::O 1)JO ~***~****************~.oJ:,):~*.*****lC ***...::,):CATA12Ke012 WAT~NK (.Q"l LINE 1993)-NO STATE FUNCS-Jf\FlATICN 7~-IN1ER!:ST lC":-CAPCCSl S~•.15 ef\2~-Jt;l\-82**********************'::****:¢**********************:¢***,**:¢***~,***:¢:¢*************:¢****:¢r,tn~***1.):,)::,):********:O*:U ******:0.*:O~.*~t.):o :0':0 lC:,)::,)::O * -lllll!!It-kb!lI TABLE D.1 0·'r<-j ,~----.---.-,..........,~.....~-......-..-.....,"D.........1 ..~ ,j MI.R .........--...•.....~.~.-~ JI!lII ';;g;¥i ~~,:)c>" ... ""~..-....~...~. ...(---~ 1995 1ge6 1981 l·~BB 19€9 lC;9C 1991 1992 1993 1~9~ C~SH FLew SU'MARY ===(~~IllIn~t==== 0 0 000 c c 0 2t;'5~2C;~7 0.00 o.oe 0.00 c.oo c.eo c.cc e.ec n.ce 119_15 12!!.cS 126.12 135.59 145.C8 155.24 166.1e 177.13 19C.17 2C3.lte Hl.3 .<t;.~2.~1 0.00 0.00 0.00 0.00 o.ec o.cc o ..ce c.cc 26(.3C Vge ..:?1) e.o c.o c.o COlO CflO c.e c.e c.~7~R ..E ee t.te.o o.c o.c 0.0 c.o c .c·o.c c.e 22 ..15 24.2----------------~--,~-----------~-----~--------------------~---------~-----------C.O 000 C.O c.o c.e e.e O.C Cee 746.0 e~1.e 0.0 O.C 0.0 C.O C.O e.c c.e 000 ~e.e 406 0.0 C.C e.o 0.0 c.o e.G o.c c.e c.e 12.~0 •.0 c.o 0 ..0 0.0 c.o e.e c.e cooe 746.e 7C;~.;---------------------------------------------------------------- ----------------0.0 (l.0 0.0 0.0 c.o COle o.c e.c c.e 1:4.5 0.0 0.0 0.0-0 •.0 ~:8 e.c c.c 0.0 0.0 ~405 0.0 ColO c.o 0.0 e.c 0.0 e.c c.e c.e (t02.0 425.1 'ill.~706.7 932.7 141:.'2 IS96.t;1519.2 6~3.1 11(:.6c.c e.e 0.0 c.o c.o e.e c.e o.c 126.~15.3 -~-----~-------- -------------------------------- --------------------------------402.0 425 ..1 511 ..3 106.7 932.1 1413.2 1596.5 1519.2 1EC.C 2460; 402.0 425.1 511.3 106.7 Cj32.1 1413.2 1591::.<;1579 ..2 f53.7 Hl.1c.o c.e 0.0 c.o e.o 8"C c.e o.c 126.3 15 ..3o.fJ c.o 0.0 I).C e.c .c o.e c ..c c.e 25.3 --",c.c .0.0 0.0 0000 c.c c.e e.e o.e c.e:c.e-'----_._,.-_._--_.__.-_._._--_._,-',---._-_.-.-_.......-.-.-,'..--..---_._-----.------_._._--,-------_.--.--_._---c.o C..o 0.0 0.0 G.e c.e o.c o.c (l.e c.e0.0 e.o 0 ..0 0.0 e.o c.o .o.c o.c c.c c.e 0.0 c.o 0.0 0.0 c.e c.c 0.0 0.0 cee c.e 0.0 c.e o.n :';.0 e.o c.e c.e 0'.0 46.C 45.2c.o o.c c.o 0.0 c.o C.C c.e c.e ee.3 «>2.3 0.0 c.e 0.0 0.0 e.c c.o o.c e.c e.c c.o '.02.0 E27.1 1338.4 2045.a 2911.7 439hC sc;el.e 1Sf1.C e22C.1 E/f 22.lt--._._'--_.-===========================~::========::========---_._._---_._._-----...._...-.__..---_._--_.----_.-.-._--_._-'_.-.------_.__..- 402.0 El.?1 1.:?3ao4 2Clt5.0 2917.7 4391.C 5981.1:1 75~7·.C lnlr,7.C e5t~.s------------------------=.========-----',-_.-==:;=====---'-'_.---------_.-:-=:=====_._.•.__._---------------------------_._--_._.---_._-_._..-------_.------_._..-e.e coe C.fJ c..o c.e (.c c.c c.e e.c CtlCc.o c.e o.e 0.0 c.e e.c c.c coe c.e f 4.•~ 0.0 c.o c.o o.c c.o c.e c.c c.c 126.~Bl.~ 4·02.C 1:21.1 133 e.4 2C45.0 2'111.7 4.391.C 5t;81.E 1561.C Enc.]e~t7.c; 317.2 313 ..5 352.4 455.2 5l:Ie 5 15~.1 83<;.1 116.C 3CC.2 75.8 317.2 630.7 983.1 1438.3 1995.8 27c;~.e 3634.6 4410.7 411e.9 ",et.70.00 o.c'J 0.00 0,..00 c.co a.co o.oc c.cc 1.CC 1.C3 -...~I.e ." "ET FA~"INGS FPOM OPERS -----CASH SOtlRCE AND USE----CASH INCG~EFP.C""OPE~SSTATECONTBleUTJn~ LONG Tf:RH DEBT O"AWOCWf\S HQ~CAP CSeT DRAWDnW~S TOTAL S~uqC~S OF ~UNDS L~S~CAPITAL EXPE~DITUREl:'."S;';ORCAP MW ruw>s(~SS nE~T REPAYMENTS LESS PAYME~T TO STATE C.ASH SURPlUSCO.··j-.-FfC1T)StiOl\T TER:"DEe CASH RECOV~Rr::D -----BALAN~e SH~ET--~------REseRVE AND CaNT.FUND aTHER HCRKINGCAP I TAL CASH SURPLUS RETAINED CU!{.CAPlT ~LE Y,PEND 1 TU PI: ~ '\4';) 141249 444 225 371 4'54 37~ ';43 NO STATE CONTRIBUTION SCENARIO 7%INFLATION AND 10%INTEREST "ZJ 't 4:l 2bO 'J95 54.1 I't46 143 ~4!J 7'3!:N=:PGY GliH 52~~EAL PRIC~-¥ILlS 4.66 I NF LATI Ot\I l\OEX ')2:)P?ICC:-MlllS ----~lNC3MF----------------- 'i 13 'lEVElWE IT')tESS QPE~ATl·'1G COSTS 517 ~PE~ATING INC~~~ ~14 .'\CD INTERcsr EAR~ED 01\FUNes ';')0 lESS nn~REST ON SHORT TERM Dl:BT J~l lESS INT::REST C~LONG TERM DEBT 4S~~APITAl ~'Pt~YE~ 461 ST~T=CDNY".IaUTi::JN 462 ;lETA IW:CEAP N ING:i 555 DEeT OUT STANOING-SHORT Tf.Rlo1 554 DEBT OUTSTANDING-LDNG lERM 342 ANNUAL DEeT DRAWWDCWN 11982 543 CUM..VEBr DRAWWOCWN 11982519nEBTSERVICECOVER ~ ~'\ ~'::"'-----". L>i j ' .~__..~~SHEET_1 OF 6 -_•.~,_'""'_._._...O''..~_••_.....~>•.._,""' (;3 I II '1 c G-.•..'•................................ 41ff 14.ES 45e.t~ 31t;.17 :;, TABLE D.10 I LJ .-.--..,.-.-_-;._...•..........~_"",••-..-J~.•...-;" @!J ~61e el.£:2~2€.31 :;:'~.5P. M!I 4555 85.994CC.29 344.27 ~, ..~ 31C5 78.H; 314.lC 2q~.25 ...k¥!¥ 3Cf484.EC!4g.f2 296.41 11M.. d.vf/·~y .... 3019 !le.59266.73 294.97 - NO STATE CONTRIBUTION SCENARIO 7%INFLATION 1 0%INTEREST SHEET 2 OF 6 300>5 110.3R 2'i9.23 295.10 -- l39f.1 890.5 1394.'i e98.8 9C3.4 <joe.!913.6 1~67.e H32.4 1642.3 25.9 27.7 29.1 11.8 34 ..0 36.4 38.q fc.e 65.1 f.9.7 -------~-------------------------------- ----------------------------------------960.8 e62 .•1 864.8 Eb7.n 86~.4 ell.~e74.7 15 C.6 •c;15 fT.3 1512.6 409 5.3 5.6 6.0 f:.~6.9 7.4 7.9 12.4 1:?2 l~.2 14.6 15.0 15.5 15.9 IE.S 17.0 17.1 2'!.~?C.5 792.4 1J!9.2 785.6 7H.7 711.4 712.1 767.~13~1.1 1391.9 1~e2.f.--'----'-.--.----_._---_._._--_._-_.._._---_.-_._---_._.....,-'--_.:_-_.---------_._---.-._-----.,._--------_.__.- 59.2 64.3 6«;.3 15.9 82.5 89.7 91.~106 ..1 lse.e 172.7 59.2 6.4 ..3 69.8 15.9 e~.5 es.~9l·E lC6.~1~g:2 112.10.0 0.0 0.0 0.0 .0 c.0 ..0",c.c 206.2 :72.6 616.8 1061.1 119 S.0 124~:3 llC2.1 10.5 c.c c.e I I4.0 04.4 4.6 4.9 ....2 6.1 112.9 15.8 IC.S ----~---------------------------------------------------------------~-----------I269.4 441.2 751.3 1141.9 1211.8 1335.5 12Cl:.~289.5 114.6 le3.1 233.1 401.3 101.6 1094.0 122~.2 1211.e 1143.C 113.6 U:.2 10 ..S 4.0 4.4 4.6 4.9 5 •.2 5.1 6.1 112.<;~1j.8 !C.932.3 35.5 39.1 43.0 41.3 52.(51.2 62.9 ~,"1 1 1.9 0,,0 o.c 0 ..0 0.0 c.e coe 0.0 c.e c ..o c.c ~----------------------~----------------------------------------------~---------0.0 0.0 0.0 0.0 c.o o.c 0.0 0.0 o.c c ..C 0.0 o.c 0.0 0.0 c.o c.o o.c o..c o ..e c.e 0.0 o.e 0.0 0.0 c.e o.c c.o cee c.e a.e• 52.6 56.3 60.3 61t.5 f90C 13.E 79.C 12~·.5 1~2.2 141.4 92.9 93.6 94 ..3 95.0 95.1 9t:..l:97 ..5 H5.9 173.1 174.7 0.0 0.0 0.1}0.0 c.e c.c o.c c.o c.c c.e a~55.5 9056.8 91~4.4 In85~.4 12083.6 13361.5 1~!C4.5 14618.1 146e~.3 147':~.1 =;=~=~=:=====:===~=:==========::===::.:::=:==::~====:=~==========~~=~=::=------_.---".--'--'--8301.0 9206.1 9Sle.9 11C17.8 1224S.3 13531.e 14681.C 149'C].6 14geg.5 1:C11.~==========::::=:===:======:;~=====================:=:==:----_._._.-_.._-_._------_.._-------_._._-.-'--"-'---'-_._---.-_._.- 0.0 c.o 0.0 a.o c.o c.e c.c 0.0 c.c c.c 113.6 171.9 247.8 323.7 4tt.2 ItS;.C;59:?4 6C;~.5 858.4 1031.1 14S.S 149.9 154.5 159114 ItA.7 He c4 116.5 2e9.4 3C=.2 316.2 8541.8 8813.9 9516 ..6 10534.7 11617.4 12865.6 13~1t.C 13c;]8.t;1:fP5.S 1~1l4.C aZe1 139111 237.1 347.4 364.2 35~.1 294.7 17.6 c.c O.C 4369.4 5e09.1 5246.2 5593.1 5951.8 €:312.5 6607 ..3 662'1:5 6624.9 ff24.91.03 1.03 1.04 1,04 ).C4 leOS 1.05 1.03 .1.04 l.eS c ~~'L.•'it._ .-----C~SH S~URCE AND USC----CASH INCOME FRO""OPERSSTATECO~TR18UTICN L~NG TtRM nEBTDRAWDOW~SwORCAPDeBTORAWDCN~S TOTALSOU~CES OF FU~DS LESS CAP1TAl EXPEh01TU~ELESSr:ORCAP :\ND FIJNDS L~SS OEer REPA\'~~NTS LESS PAY~ENT Tr.~TArE CASH SURPLUSfDEFICITJSHeRTTFRMDEer CASH RECIJVFRF.D ---~-~AlANCE SHE[T----------RESERVEANCCONT.FUND OTHER WeRKING CAPITALCASHSURPLUSRETAHJEDCUP.CAPITAL EXPENDITURE CAPITAL EfiPlOYED STATE CONTRISUTIONRETAINEDEARNINGSoeBrOUTSTANOING-SHORJ TERJ-1 DEBT OUTSTMWING-lDNG JERI'" ANNU4L DEBT ORAW~DCWN !198Z CU~...oeeT DRAWWDOWN !1932oeelSERVICECCV~R :...- ~4:J '320 H8 Z60 395 141249 444 54'3 44!J 143 24a 225 371 454 370 465 73 ENERGY GWH 521 REAL PRICE-'ILlS466INFLATIONI~OEX I)..';)PR ICE-~n lLS -----1 NCOMF-----------------'i16 IlEVEuur 170 LESS I1PERATPIGCOSTS 517 OPERATING INCOME214ACDINTERESTEARNED Ct\FUNCS SSO LESS INTEREST ON SHORT TERM tEaT 391 LESS INTEREST ON LONG lFR"neer '54 J W:T SARI\IXGS FPDM OPER S 461 462 555 554 542 :'43 ')19 -- I .--I ********************************:;t**~****,:r***.**..**.*~**¢*.***********.*.****»**.*.******~*******:¢****.********:(':.:o******'>***~********.**.*:¢*I.DAT.l12K.D12 WATANA CON lINE 1993'-NO SlATf~FUNCS-!l\FLATICN 7~-INTEREST 10t-cAPeCST $5.15 2"2~-JL,,-e? ***************************************~*o******.*******.******************••**.**~******.************.*******~*****.**~o****** 1995 1996 1991 l~q8 1~99 zeco 20C1 20C2 2CC3 20C~" CftSH FlB~SU~MAR~ :==($~lllIO~)===~ 302S 3055 3C5l103.51 96.35 9C.~~ 285.40 3C=.38 326.15 295.43 2~4.22 295.54 1 I 1 UJ \ !----_.'~..~...-_.~.~~-----.~_._.~\~---~---- I ""trir-~<,....,,,..._-_..~.~ji'~.._)•..--~.,,~"'-AM ,.~._.~"'I"iiIidIai:iL -'.'.."_._,,,w,<,.~,,,,.7,..._.'. ~/- ,j t~, ,~ - ¥ LE.i!$'1lM;a.~~ {I ....~ ,>.,] ...~~~. (I ~ It ~~......~ ZOGS 20C6 20C1 zeca 20C~2010 20u 2012 2C13 2C14 5 'I)CASH flOW SUMP4RY ===($~ILLJCN)====1'3 ENERGY G"IH 4902 5064 5224 53 ~4 ~~44 51C4 5062 6023 tl48 t311521R~A~P~bc£-~bh~s 4~8:11 5~~:g~5gI:~~6~6:l~6~I:19 4~·91 'ieOq 1ti1:Z~~4.§~Citl:§146IF'ATt ~1 I _ 681.;tr:.•.9 84"2.I)!0 ,RIC ::-,..ll lS 317.03 328.42 320.62 313.30 306.62 ~G(j."te 2<;4.94 289.12 286.62 (01.£'; *****..:r*******~*************~********Ji)*****:)*****~*~*******lO***t*(l**.:t**********************lt*********:)Ji)**********.******:¢******~*DATA12K.012 WATANA (ON LH!E 1993)-NO STATE FUNCS-IhFtATIC~1';-IN1EREST 10%-CAPCCS1S5.15 e~2~-Jlt\-83**:¢********~******************:;C*******l\)********'¢*****'¢************:)*****::1.*****~l¢****10 ********************10********lO****.i;:¢*****:0 ~ ..._--....._._-..------ II <I I I I.ji r I t~ iI NO STATE CONTRIBUTION SCENARIO .r !l J. '....·...:..··1'.7%INFLAn.ON 10%INTEREST .L....•.....•..·•.y...••..•J..•...tit "_.......-,.SHEET~3 OF.~_~r-?~ABLE D.10.~)<•• o -----1 NCDME-----------------516 llEVENus 1652 ..0 1663.0 1614.8 1686.7 16Slj.8 1713.8 172P.a 1744.<;17t2.C 17 PC.4170LESSQPERATWGCOSTS74..5 7«;.8 85.3 91.3 <;1.1 104.5 111..,119.1 12!1.1 131.C----------_.~~-~-~-~-------------------------------------------------~-----------517 OPERAT n~G t ~ce!J~1571 ..5 15!3~.2 1589.5 15q5.4 16(2.1 16C9.3 1611 ..C It25=1 1634 ..C If.43 ..4l14ACOINTERESTEA~NED 01'\FUNDS 14.1 15.1 16.2 17 .3 la.s lc;.e 21..2 22.24.~2t(,C550lESSINTEf:lEST eN SHeRT TERH tEeT 31.6 32.8 34.C 35.4 3~.a 38.3 39.9 41.1 43.6 45.5391lESSINTERESTUNLONGTERMDEBT1372.4 13Z!1.2 1348.0 1335.3 132 e.4 13e~~s 12a5.9 1266.0 1244.2 122C.J-----------,--------------------~----------~----------------------------~--------543 ~ET EARNINGS FRaM OPERS lEn.6 204.4 222.8 242.1 263.5 zet.c.;~12.4 34<:.2 31C.!i 4('3.1 -----CASH SOURCE AND USE---- 340.2 ~4J CASHINCDME F&OM OPERS 181.6 204.4 222.8 242.1 263.5 286.9 ~12.4 :nC.5 4C::.l'.46 5TAT~CONTRI3UTION c.o c.o 0.0 c.o c.e c.e;o.e 0.0 c.c cleII143LDNGTERMnEBTD~A~DOW~S c.o 0.0 0.0 c.o c.c c.e o.c o.c c.c c.e24~~Co.CAP DEBT ORAW~CW~S 11.r;12.5 13.4 14.2 15&2 H:.Ii 11.~16 ..1 le ..e '-1.4-------------~-------------------------------------------__l _________~___________I )4)rCTAl sounc~s OF FUNDS 199.1 216.CJ 236.1 256.3 21E.1 3C3~3 32s.a 358.8 3-;c.e 425.1>'1 120 LESS CAPITAL EXPENDITURE 15.8 81.1 86.1 92.8 99.3 lC6.3 113.1 121.7 l~C.2 139.3't4i3 LE.SS HORCAP AND FUNDS 11.5 12.5 13 ..4 14.2 15.2 ~(;.4 17.~le.l 2C.C 2~l:~260 lESS DEBT REPAY~~NTS 112.1 123.4 13 5.7 H9.3 164.2 lC.6 19 e.l :z.8.~2~C.4395lESSPAYHENTTOSTATEc.o 0.0 0.0 0.0 c.c c.e o..e o.c o.c C.o-------~--------------------------------------~-----------_._---------------~--~-!4~~A~H S¥RP~USf:~-rFICIT)-B:1 8:8 ..8.:j s·o 8:'8 8:8 8:8 8:8 8:6 8:f4.>H RT en.0:.0444CASHRECOVER:;D 0.0 0.0 0.0 C.G 0.0 o.c c ...c o.c .o.c c.e-----9AlANEE SHyET---------- I225RESERVEANCON.FUND 151.3 161.9 173.2.leS.4 19S.3 212.2 227.1 243.e 26C.C 21~,,2311OTHERWDRKINGCAPITAL116.4 178.3 1!l0.3 1'32.4 184.7 181.2 Isc;.a IS2.6 1~5.5 lc;e.e4S4C~SH SURPLUS RETAINED c.o c.e 0 ..0 0.0 e.e c.e o.c 0.0 c.c c.e310CUM.CAPITAL EXPENDITURE 14330.9 14911 0'1 14C;ge.7 l5C91.5 151lic.a 152«;1.C 1541C.1 15532.4 15'6f2.t 1~8Cl.5==========:=::::=====================:=~==============================::z==.=====465 CAPITAL E'PlOYED 151sa.5 25252 ..1 15352.2 15459.2 15513 ..8 1565E.4 15E21.E 159El.5 Itl1~.1 If27s.e. :====~====================~==:=========:=======================================:461 iTATE CONTRI3UTIDN c ..o c.o 0 ..0 0.0 c.c c.c o.e c.c c.e Gee462RETAH/[D!:JHl~lNGS 1218.,1 1423.1 1 E4 5.9 1SS!7.9 215J.4 243 a .3"2150.6 3C90.8 ~4E1.4 2E6':e1355DEBTOUTSTANDING-SHORT TERM 323.0 ~40.5 353.5 '36108 383.0 399.4 416.9 435.5 4~5 ..5 4U;.c;554 OEBr DUTSTAN~}fNG-LONG TERM 13611.8 13488.5 13352.8 13203.5 13039.4 128SS.e 12660.1 12441.6 122Cl.2 119.3(;.8~4~A~NUAl DeBT DRAWWDCWN SI982 0.0 o.c 0.0 0.0 c.o e.e C~C 0.0 c.e c.o543CUM.DEBT DRAWWDCWN 11982 6624.q 6e:24.9 6C'Z4.9 6624.9 6624.9 6624.9 6624.9 6624.9 6624.9 ~(;24.c;519 ~EBT SFRVIce ceVER 1.1)~1.05 1.06 1.06 1.07 ].e1 l.oe ].t8 I.C9 l1C9 -:) ;,.' 'I .:; ~."~~~[filM!!~. .TAB LED.1 O·I-~II.....•'.·,.~"·_~.·.••~~.~.•.·t7.···....?··{.·.·!%·.:;:..-. I ~J.i . .~r .,'~~~._......-,.,..~..~'..•......./Ii..~---"~.,.•.....Tf!§,'.'..•.'.'~-.-:--).'''".'.........'.••••_<' f\'"\~~.-"...,'..-' , g!~I@.,~ . ..'~. 0.0c.o 0.0 TC1Al 1914.2c.e 14311.1f15..2 7914.2 429<;2.6 l76!..5 229Ct.5 17eSl.6 E75 ..2 5 Uc;",,1 c"e 144802 8:88o.co o.c7lj14.2 675.2 9117.4 6624.9 6624.9 0 ..00 .jO~fZ:' 965.9 :31e63.7 -._---_._- -_._---_..- _._--.._--- -_._--_._- \ 4116.1 228.5c.c 17C91.6======-== 17166 ..8 ::=:::=: 73a:~ c.c 34.4 138.9 1950.6 22 c.o 6984 l'fl~:~2 279.31 773.3 223.1 34.4 515.;n.e 17~~:1 64.1 969.3 2021 c.oo.c o.c ~'1 cee7914..2 675.2 <;171.4 0.0 6624.9 10 15 ... 446.1 223.5 0.0 17C91.6 17766.8 ----_..--- -_._--_._.- ======:_= =====:;== ~~,---- 617.~ 6ge4 l~~~:~~ 215.C9 e.e 7175.:: 640.e <;692.1 0.0 6624.9 1.14 -----..~~.- 417 ..! 223.3c.e 1f f6 7.~ _._------ 17 ~~:~ 60.<; 1016 ..1 202e 1921.1 2C5.6 11508.8 o.c C"Co.c 6'76:t c.e 32.•1------_..-7CS.6 2C5.C 3,.1 468.4 o.e--.__._.__.- ==-====== ======== !......~ O..Ce..e (J.O 62~:6 c.o 3C.O ~3~3.5 192.2 3<;C ..2 ZIP-lOS CoO lt6SS,,9 651.2 19 ~.~ 3C.0 425.8c.o 11261.6 c.o 6497.8 6C e.7 10161.1 c.o 6624.9 1.13 -----......_- 11~!:~ 51.9lose.7_._------621.2 ------_.- =:=::===: :;:====== '- 569.7 1 e2 .l. 26 ..1 3131.1 0.0 597.a 168R·I34. 55.1 lC97.4 569.7 0.0c.o 28.1 lE67.7 179.6 0.0 0.0c.o 0.0 662409 1.12 C.o 5876 .•6 518.7 1~'iE16.9 -----_.-:- --.-----.- =====:::= 364.6 214.0Q.O 16463.6------------_._,--- 17042 ..2 '- , 0.0 5306.9 55J.6 1091'••1 0.0 6624.9 1.11 5/d!• 8 17C 6 2f.2 3'j 1 9 c.o ';22.6 0.0 0.0 26 ..2 2017 2019 2019 CASH fleW SU~MAR~ g==(S~lllIDN1=:~= 6708 6760 telS 24.!9 .2 1y.38 21.181104.40 lIe .71 1264.43 214.86 216.31 27!~44 0 ..0c.o 0.0 1843.6 167.9--_......_._- 1675.1 31.a 52.4 1132.6.-...,--,_._-_.- 52Z.6 -------- ...."..~-'--"-- ... 340.8 2C 9 •.9 0.0 16281.0--_.__.__.-_._---_._.- 16831.5 :=====-== 5 C3 .9 155 ..5 24.5 31<;.9 c.e ~ 2016 lE21.1 156.9 47 t :3 c.e 24.5 6616 10~~:~~ 275.7.8 c.oe.eo.c 318 0 5 2GS.8C..C1611C,/, 16634./ 0.047'14.4 ~24.3 11326.0 c...o 6tZ~.'1 1.11 -----_._._- 1664 .•22g.a !ie.e 1164 ..6-._---_._- 479.4 --._---..---.-- -.__.__._-- -======:;: ====:::== 439.9 0.0 c.C 22.9 ~3C;ttS 2015 -- 462.CJ 149.0 22.92ljC.9 (j ..0 . 1100 ..1 146.6 6449 23.949b4.63 279.14 1651.4 27.8 47.1 1193.7 297.6 2C2.2c.o 15950.9 c..o 0.0a.a 16450 ..7 0.0 4JC 5.0 49~.8 11645.9 0.0 6624.? 1.10 ----_._--: ======== ======== NO STATE CONTRIBUTION SCENARIO 7%INFLATION 10%INTEREST SHEET 4 OF 6 ~ c(] \l ... Q --------~----..--_._-,-,---- ~,......... ~49 73 ENERGV ~WH~ZI REAL PRICE-'ILLS 4b6 INFlATlcn INDEX 520 PR ICE-MIllS -----lNCO~E-----------_t;I6 ~EVENUE. 171)LESS IJPER.\TJiJG COSTS Cjl7 l'JP F~41 IJo G 1 N"'O ME24AOC,NTl:RESf'EARNr:O 0(\FUNJS 550 lrss INTEREST ON SHORT TERM DEBT391LESSINT~REST I1N lONGTERM'oe8T 54B N'=T E~kNJNGS FROM OPERS -----C~SH SOURCE AND USE----;J~H_.INcnME FPCM o.p~PS .>TAT l..'CONTRIBUTIf1N LUNG TERM DEBT ORAWDnw~s4~PCAPDFBT URJ~CaW~s TaTAl SOU~C~S DF FU~DS LESS CAPITAL EXPENOITU~ElESSW1RCAPAkCFUNDSlESSOEBTaEPAYME~TS LESS PAYMENT TO STATE CASH SURPLIJ$(DEFICIT)SHeRT TERM DEBT CASH R ECOVf:RI:D -----BALANCE SH~rT---------qCSERVE AND CONT.FUND OTHER WC!H<It\G CAPITALCASt-I SUR IT LU S RET A rj EDCUP.CAPITAL EXPENOITUPE CAflITAl EfolPl'1YEO ST!TE CONTRIBUTIONRETAINfOCARNINGS ~~eTQUTSTA~DING-SHDRTTERMDEeTOUTSTANDIHG~lONG TERM ANNUAL CEaT DRAWWDCWN 11932 CUM.O~ST DRAWH&OWN 11982D3BTSERVICECCV~R 548 441> 143 ~43 JZO 1'.43 260 395 141 24J 444 225 371 454 370 465 1'.5\46, 555 554 542 543 519 ********************************4***************••***0·*.*~*****~***~.***O*O********.*****.**.***.*.****~*••****400*O**O~O*4***DATAllK.tl12 WAT.~NA (ON LINE 1993)-NO SlATr;FI.:NCS-HiFLATICN 7:.';-fNTERfST 10t-CAPCCST S~.15 8t\24-Jl.~-S3.*o~*******************o************.**.*o******~*****************0******************0*••••***************************.0******. ~ ':"\ I .1 u 1 fj -, :'.~~=":'-'---.c:--",,-,,-=-~~:.._.....~."'..;_'j .''''''~::2'".".,~~~,....,<""...--,'-'".:::.,'---'.-i',..'C",~'> ~~~.1_d~~~~~_~~~qe~~~_ NO STATE CONTRIBUTION SCENARIO :.7%INFLATION 10%INTEREST"lJ SHEET 5 OF 6 TABLE 0.10 ANNUAL PROJECT COSTS Mills/kWh ..Cost in Nom1nal 1 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 I !()--Operating Expenses 8 11 12 12 13 13 14 15 15 15CapitalRenewals0891010111212139DebtServiceCost252279274273272270270269266320 Total 260 298 295 295 295 294 295 296 294 344 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012---Operat1ngExpenses 17 18 19 19 20 20 21 22 22 ~3Capita1Renewals141515161717181919to,Debt SerVice Cost 318 310 303 293 284 276 268 259 253 247 Total .349 343 337 328 321 313 307 300 295 290 2013 2014 2015 2016 2011 2018 2019 2020 2021 I Iy</ -----I I .I Operating Expenses 24 25 26 27 28 30 31 33 35CapitalRenewals2122232425272830321DebtServiceCost242235230224222219.216 212 212 Total 287 282 279 275 275 276 275 275 279 ~,,,-'::,,-'-:~"''''- ......"~---'fIIIIIIIlIIlI ~.........~...IIII!!I ....,....!!!II RIll ,..·----.,~...- NO ST ATE CONTRIBUTION SCENARIO I...7%INHA TION 10%INTEREST SHEET l)OF 6 TABLE 0.10 ••--".J ANNUAL PROJECT COSTS Mil1s/kWh Cost in Real $1993 1994 1995 1996 1997 1998 1999 2000 2001 2002- Operating Expenses 4 5 5 5 5 4 4 4 4 4CapitalRenewals0444444432DebtServiceCost116119109102958882777280 Total 120 128 118 111 104 96 90 85 79 86 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012---Operating Expenses 4 4 4 4 4 3 3 3 3 3CapitalRenewals3333333333 I i (IDebtServiceCost75686256504642383431. Total 82 75 69 63 57 52 48 44 40 37 I I 2013 2014 2015 2016 2017 2018 2019 2020 2021 I I rJ -----------!Operating Expenses 3 3 3 3 3 2 2 2 2'.l Capital Renewals 3 2 2 2 2 2 2 2 2DebtServiceCost282624222019181615 Total 34 31 29 27 25 23 22 20 19 I I , I; 2116 '1982 $'5 215.62 - Percert 10.00 :~.00 O.CO 0.00 0.00 1O.1!J TABLE Doll:.SUSIM OOST (F ~(Revised) , F)rst Full Yeer of WatClla &r:eri 1 Galyon 2003 T!; Total PI alt.Investment Inc.IaD.C (RIl170 y 466) 1.Fix~Chrgrfgl~i~y fa1 f~~~r S.F.) 1.Fe:Jeral locare 2.Fe1eral Mi see 11 a1eOUS 3.State &Local II.Fixed QJerating Costs (a)~.ration &Mainte1C11CeInclooingPdninistrative CI1d Ga"H:fal Expense (RL171 divided by 466)9.13 Total JlIlnual Capa:ity Costs 225.00 I'btes:(I)HI.=Reference Line on far left of printout 00 Tcble.0.10. I .1 I I' I It r I' I I I f I f f I f { Total 2,957 GWh4..555 II 6,934 II $15.45 5,150.2billion$15.20 million DevilCanyon 2002 $4.66 1,554.0billion $4 ..8 million 15 percent of Operating Costs10percentofRevemle 100 percent of Operating Costs 100 percent of Provision for CapitalRenewals 10 percent per annum 35 years 7 percent per annum Watana 1993 $10.79 3,596.2billion$10.4 million Revised 7/11183 - --'" Reserve and Contingency Fund Interest Rate Debt Repayment Period Iofl ation Rate TABLE D..12:FORECAST FINANCIAL PARAMETERS Project Completion -Year Energy Level -1994..-2002 -2020 Costs in January 1982 Dollars Capital Costs Operating Costs -per annum Provision for CapitalRenewals-per annum(Oe3 percent of Capital Costs) Operating Working Capital I I I I I' 11 "j I f i f, I J I t 311.6 463.5 221.6 68.5 0.9 2..5 5.5 3:>.0 18 ..6 Install ed capa:it;Railbelt Utility T s A1chor~M.rlicipal Light &f'rn\er fRpcr alt O'IlJgoch Ele:tric Associ atioo GJlda1 Valley Electric Associatioo FairbCl1ks M.I1icipal uti 1ity Systan MatClluska Electric Associatioo f1:Jrer Electric Associatioo &:wardEl ectric Systen Al aska Ptw.er Ministration Uliversityof Alaska,- _TPBLE D_.1.-3:_'_'TQT;_._PL_taERA_ai-'_._JI,_OO_CAP__~lLY WITHIN TI-E AAILBaT ?YSTEM-100?, TOTPJ.. C£A GIEA FMJS rEA I-EA SES PPM UofA (1)Installa:f c~Ck:ity as of 1982 at O·F (2)Exclu:Jes Natiooal [)afense installed c~a:ity of 101.3 ~ Reviscrl 7/11183 Ibbreviations I I ·If~.,y I, I I I I I: I I I I I I I I I I _I; Heat Rate (Btu/kWh) Generating Capacity @ O°F (M~~) 30.0 Namepl ate Capacity (MW)Date 1955 .;::-; 1968 15.25 16.1 15,000 19GB 15.25 16 ..1 15,000 1973 53.3 53.0 10~OOO 1976 10.0 10.7 15,.000 1975 58.5 58.0 10,000 1976 72.9 68.0 15,000 1977 72.9 68.0 15,000 1982 55.0 42.0 -Alaska Power Administration Fuel Type Anchorage Municipal Light and Power SCCT NG/O 1962 14.0 16.3 14~OOOSCCTNG/O 1964 14.0 16.3 14~OOOSCCTNG/O 1968 18.0 18.0 14~OOOSCCTNG/O 1972 28.5 32.0 12,500 0 0 1962 1.1 1.1 10,500 D 0 1962 1.1 1.1 10,500 SCCT '0 1974 32.3 40.0 12,500CCST197933..0 33.0 . SCCT 0 1980 73.6 90.0 11,000SCCTNG/O 1982 73.6 90.0 12,500 -..".._,,,, Wnit TABLE D.14 (She.et 1 of 5) EXISTING GENERATING PLANTS IN THE RAILBELT REGION H SCCT NG SCCT NG ReCT NG SCCT NG ReCT NG eeeT NG eeeT NG ceST NG Prime Mover Eklutna(a) Plant/Unit Station #1 (b) Unit #1 Unit #2 Unit #3 Unit #4 Diesel l(c) Diesel 2(c) Station #2(d) Unit #5 Unit #6 Unit #7 Unit #8 Bel uga Unit #1 Unit #2 Unit#3(e) Unit #4 Unit #5 Unit #6 ~~~i :~(f) ,I I I r I~- 1 " I I I I· I I I I . I I' "I f f I I I (; o Il~ I II . -- 15,000 15 t OOO Heat Rate (Btu/kWh) 0.5 3.0 3.0 3.0 5.0 0.9 0.2 16.0 Generating Capacity @ QOF (MW) 0.5 3~0 3.0 3.0 5.0 0.9 0.2 15.0 Nameplate Capacity (MW)Date- 1961 1952 1952 1957 1957 1957 1979 1971 iliiirl'..''i ..j 1.;::, Homer Electric Association Chu.9 ach Electric Association (Continued)--.....;....' ...... NG NG NG NG NG o o Fuel Type- 5T 5T 5T ST 5T seCT NG 1964 14.0 14.0 15,000SCCTNG196514.0 14,,0 15,000SCCTNG197018.5 18.0 15,000 SCCT NG 1963 7.5 8.6 23,400SeCTNG197216.5 18.9 23,400seCTNG1978230026.4 23,400SCCTNG198223.0 26.4 12,000 D 0 1952 0.3 0 ..3 15,000 D 0 1964 0.6 0.6 15,000D019700.6 0.6 15,000 1) D TABLE 0.14 (Sheet 2 of 5) EXISTING GENERATING PLANTS IN THE RAILBELT REGION Prime Mover Unit #1 Unit #2 Unit #3 International Bernice Lake Cooper Lake(g) Unit #l t 2 Plant/Unit Unit #1 Unit #1 Unit,#2 Unit #3 Unit #1 Unit #2 Unit #3 Unit #4 Knik Arm(h) Unit #1 Unit #2 Unit #3 Unit #4 Unit #5 Kenai Unit #1 Pt.Graham 5el dev;ai I I .~Ij1 I I I I I I, I I I I I J f I I I !3 I I 0 I I.1 I,~ 15,000 15,000 15,000 15,000 10,500 12,000 10,500 20,000 14,000 14,000 Heat Rate (Btu/kWh). 0.9 1.5 1.5 2.5 --....., 65.0 65.0 Generating Capacity @ O°F (MWl 0.9 1.5 1.5 2.5 64.7 64.7 2.1 31.5 7.2 18.0 .- Namepl ate Capacity (MW)Date. 1967 1965 1965 1955 1952 1952 1952 1952 1'976 1977 - Seward Electric System I'''.'.... Matanuska Electric Associ ation• Golden Valley Electric Association, o ooo o NG o NG 0 1971 18.4 18.4 15,000 0 1972 17.4 17.4 15,000 0 1975 2.8 3.5 15,000 0 1975 2.8 3.5 15,000 a 1960-70 21.0 21.0 10,500 if' Fuel Type Military Installations -Anchorage Area D D D D ST Coal 1967 64.7 65.0 13,200 D 0 19'67 64.7 65.0 10,500 D ST SCCT 0 SeCT 0 seCT seCT seCT seCT Prime Mover TABLE D.14 (Sheet 3 of 5) EXISTING GENERATING PLANTS IN THE RAILBELT REGION Unit #1 Unit #1 Unit #2 Unit #3 Combined Diesel D GT1 GT2 6T3 GT4 Total Diesel Total ST Pl ant/Unit Talkeetna Elr1endorf AFB Fort Richardson Total Di~Sjl (c)D Total ST~l 5T Healy Coal Healy Di ese·l (c) North Pole Unit #1 Unit #2 Zendher i~13 I I I I I I I- I I -( f I I f f I r Sl ST Coal 1..50 1.50 12~OOO 52 ST Coal 1980 1.50 1.50 12,000 S3 ST Coal 10.0 10.0 12,000 D1 D 0 2.8 2.8 10,500 D2 D 0 2.8 2.8 20,500 20,000 10,500 10,500 Heat Rate (Btu/kWh)." -- Generating Capacity @ O°F (MW),- 3.0 2.5 2.50 6.25 20 2 Namepl ate Capacity (MW)Date 1953 1953 1953 1953 ......., Mid• .. University of Alaska -Fairbanks oo oo Coal Coal Military Installations -Fairbanks____,ri·..........•• Fairbanks Munici·pal Uti 1ities System Q - ,;;;~:::- 'i..-,. ST ST Prime Fuel Mover Type- TABLE D.14 (Sheet 4 of 5) EXISTING GENERATING PLANTS IN THE RAILBELT REGION Chena Unit #1 ST Coal 1954 5.0 5.0 18,000 Unit #2 ST Coal 1952 2.5 2 ..5 22,000 Unit #3 ST Coal 1952 1.5 1.5 22,000 Unit #4 SeCT 0 1963 5 ..3 7.0 15,000 Un't #5 ST Coal 1970 21.0 21.0 13,320 Unit #6 SCCT 0 1976 23.1 28.8 15,000 Diesel #1 D 0 1967 2..8 2.8 12,150 Diesel #2 0 0 1968 2.8 2.8 12,150 Diesel #3 D 0 1968 2.8 2.8 12,150 Eielson AFB 51,S2 S3.S4 Fort Greeley ~~:~~CiY3(i)~ Fto Wainwright(j) S 5 5 1,;52,53,54 ST \ )ST ,Plant/Unit TABLE 0.14 (Sheet 5 of 5) EXISTING GENERATING PLANTS IN THE RAILBELT'REGION -Hydro -Diesel -Simple cycle combustion turbine -Regenerstive cycle combustion turbine -Steam turbine -Combined cycle combustion turbine -Natural gas -Distillate fuel oil H D SeCT RCCT ST CCCT NGo Lege".£! (i)Standby units. (j)Cogenerationused for r,team heating. -......_,., (g)PNerage annual energy production for Cooper Lake is approximately 42 GWh. (h)KnikArm units are old and have higher heat rates;they are not included in in total. (d)Units #5,6,and 7 are designed to operate as a combined-cycle at pl ant. When operated in this mode,they have a generating capacity at OaF of approximately 139 MW with a heat rate of 8500 Btu/kWh. (e)Jet engine,not included in total capacity. (f)Beluga Units #6,7,and 8 operate as a combined-cycle plant.When operated in this mode,they ha\!e a generating capacity of about 178 ~1W with a heat rate of 8500 BtU/kWh.ThUS,Units #6 and 7 are retired from "gas turbine operation"and added to "combined-cycle operations." Source:Battelle Pacific Northwest Laboratories.Existin·Generatin Fac1 1iti~l.aQ~.Planned l\ddition..for.the.Ral e eglOQ o.......~..-~l~SeptemDer,logg~;up~arza:"E'basco SUsl'fna Ventul"e,1983. Note: {a)'\verage annual energy production for Eklutna is approximately 148 GWh. (bJf.l1 AMLP SCCTs are equipped to burn natural gas or oil.In normal operation they are supplied with natural gas.All units have reserve oil storage for oper'ation ;n the event gas is not avail able. or (c)These are black-start units only.They are not inclUded in total capacity •. . .)~ o I ..---=:JJ 33 34700.0 1999 - 97.0 Avg.Energy T.we ~Year (GI1 ) o ~7.0 1008-,,----- ___i'" Revised 7/11/83. Bra:11 ey LiJ<e Q'-CIlt Lake TABLE D.15:SO£cu.E a=PtANNED UTILITY POOITlOOS (1982-1900)-=:. Utility lilit flPA PfJA 10TAL )1 I .~ 1'·4.I J I I I I I~ I I I I I I Ii I I l I .....-=:1 Max.Avercge (1~1 $)Econanic 2 G'uss Installed Pnnual Plif1t Capital Cost of li:!a:I C~a:ity Energy Fa:tor Cost 1 Energyrt>.Site River (ft)(r+I)(Q\I1)(%)($106)($/lCOO KWl) 1 Ylow S1c1tY 690 50 220 50 255 452BruskasnarEnooa2353J140532331133KeetnaTalkeetna33J10039545463734Ca:he Talkeetna 310 50 220 51 564 1005Brow1ef'Enooa 195 100 410 47 625 596Talkeetna-2 Talkeetna EJ 50 215 50 500 ~7 Hicks MatCl1uska 275 60 245 46 529 848O1aktl:hama3 O1aJ<oc:hatna 945 500 1925 44 1400 3J9AllisooAllisonCreek1270833475412510Strnfline Lake Bel~a 810 20 85 49 126 115 rt>tes: TABLE D.16:CPERATIrli,ow ECOOv1IC PJlRPleERS Fffi SELECTED HYrnCELECTRIC PtJWTS g;5 ( (1)Inclooing engineering n1 CWler's aininistrativecosts but excluding .l\FOC. (2)Incltxfing IOC,Insura1Ce,Arortization,ald·Q:>eratioo Cfld Mainte1C11Ce Costs. (3)fJn independent stLk:fy by Bechtel has profX)sed trl installed capccityof 33Jfv\tl, 1500 GIl iJlnually at a cost of $1,405 mill;oo (1982 dollars),inclll1ing PFOC. I I I I I I I, I I I f ,: 1: I, ( ,'j'tp1:'iiFViiil,·fi>:ti! \) (> (; ,I !, I·.,'. 7<m 7010 7034 . 7008 7041 .., axE 19CXl 3J28 1958 1978 744 894 822 922 822 70 00 3J 10 3) 576 576 426 501 576 600 700 500 700 50) L7Wl lFL7 LW7 LXFl L403 .~Renewal s Plus:M=di un O1aka:hama (500)-1993 Keetna (100)-1900 Straxlline (20), All ison Creek (8), &-x>w (50)-19C.13 NJ Renewals Plus:I\kjiun Chaka:hama t5(0)-1993 Keetna(l00)-l~ Strcl'KUine (.20), All i sal Creek (8), ~(50)-2002 ~Renewals Plus:fthtiun (bak~hama (500)1_1993 Keetna (100)-1997 It>Renewal s Pl us:ft8ji un O1akochama (500)-1993 Keetna (100)-1997 &Dw (50)-am. 1 ~d NJRenewals Plus:M:diun O1aka:hama(500)-1993 Keetna (100)-1996 &Dw (50),Ca:he (50), Allisoo Creek (8), Tal keetna-2 (50):, StriJ1dline (20)-2002 C';~ ~ TABLE 0.17:RESllTS (F EC(J[MIC JWLU..YSES CFPlTE:RW\TlVEf£NERATlOO SCENPRIOS, --\~~~--~liEi£H91 !S±Jj E'J5!I !!III !!III llamal Plus Altemative I-M:fro ,t -,~~ocjtY"1mrbY '~an *""TOtal $ysfBil 'Category in 2010 Instal1a:J Presa1t Wirth G:oeratioo &enario 00>5 HlI1 -,,;ennar •.~C~(I;ity in Cost _ i.we .:.mscriPtlOt1 '.[000 Forecast Id.rt>.-roar GaS on LU10(f4l)i~lg.». All Thermal ~bRenewals ftkIiun lJtf1 OOJ 001 50 144 1895 81ll ---,------------./\ 1 NJtes:L.l (1)Installw C~il:jty. I I J 0.55 5.33 Diese'10 MN m f~500 856 Bi9 1 5 1 .1 2.7 4.8 3.2 8 1 4 627 6]) 7..25 1.69 7 8 2 4 1,075 8 5.7 6 6 16.83 0..6 = C{}'aL Garbi r;ej Gas f.i'r·,f!-;(,CJ4;'e Turb i ne 200 'r-w 200 rrw 70.r.w ,_. I,~001 8.&.D lb.~1~1~l~ Parareter H=at Rate (Btu/kWl} Earliest AVailooil,ty (V1 Costs, NJtes: (1)J1s estimated by Battelle/Ebasco witoolIt PFOC. (2)Inclu;iing IOC at 0 P,eC81t e~alatioo CIld 3 percem interest,assumng CIl S-shC{.leO expendlture curve. Source:Battelle 1982,Vol.II,IV,XiII,XIII F.ixed (Yt1 ($/Jr!kW) Varicble C!Ml$/MIi) _M~ P1Cllned MQJes (%) Forced M~s (%). Constrtction Pericd (yrs) Start~Ti~(}rs) Lhit Capital Cost ($/kW)l RailbeltBeluga rEnClla lhit Capital Cost ($/kW)Z RBea,,"belt ",(2.,.242 uga ~-rEnal a 2,3)9 I I 11 I 11 I I I',,. .":,1 ,1 I :,.,11 ~... I I I;,,',' !... 'I'.,; I I I ,I I' " () J J/.('•....".~~ ) .;;;- ;:~ ,. I ·~.:M.::~i~' l,"··..0 ~'"'!'8 Di~fa~st $1,1)3,100 12,151,CO> 16,311,200 9~751,OOO 8,912,000 1,482,cm 21,DJ,00J 37,564,0:0 39 ,50),ax> 8,950,00) 7,076,(0) 23,435,(0) 1,500,(00 3,((0,00) 31,(0),cro . 2,115,(D) 3,(XX),(XX) 6OJ,cm 4,075,COO 100,077,(0)- ~~;,..........",.......-..;-~... 5,(0),COO 10,(0),00) 1,5(J),(Xl) 3,00:>,003 lJ,(OO,OO) 3t ax>,00J 6OO,CXD &bcootra:ts$( (-. ".~lJJgJ 2,fiffi,cro 9,00) 1,100,cm ~I!III 92!00J ~,OO4,OOO '0,14I¢I4K 2,562,(0) 11II.,11 ~rwMon ~t~f<JJipmnt Rent ~~~$----"'-!o2"'"'"!tl:-"'-OO~$$rol,COO-r 110,aD'"" 3,SOO,0Xl 5,]CXi,OOJ 16 1 001 174,roJ 2,391,00)1,235,00} 540,(0)1,001,cro 2,l37,(XX) 7,155,0)) OOJ,OCO 19,500,(00 21,00),00) 1l,lOO,00J 8,950,(ID 1,500,00) 9,(X)),(Xl) 22,m> 5O;~7,(0) •• TPBlE 0.19:BID LIM:ITEM msrs fffiBELLGf\MEA STATlOO(a)(c).__(~flluary 1982 lliTTars) lIMtalll 576,(1) 14,435,00) 1,275,(0) 44;515,(XX)...,.-- I,OCO,OO) 1,015,(0) ~. Calstro:tion Lct>ora1dlnsurCl1Ce --$35O,00J 2,541 1 OOJ . 2,511,(00 5,733,(0) 1,757~llXl 682,(00 1,00:>,00) 15,764,cm 12,400,flX) ...liz]~•.4ialil.Jiii 1.fu1:rovarents to Site 2.Ecrtm..orkcrd Pi]ing 3.CireulatingWater S~en 4.Concrete 5.St~~sSteel,Lifting Eqtrip., 6.Buildings 7.Turbine-G:nerator 8.Stean G:nerator Clld Pccessories 9.Air Qjality Control Systan 10.Other M:chCllical Equiptent 11.Coal Q1d Ash Hcnl1 i09 12.Piping 13.Insul atioo CIld lWJging 14.Instrurentation 15"Electrical E~iPTa1t 16.Painting 17.Off-Site Fa:i1ities 18.,Jaterfront .Coostru:tioo 19.Slbstation 20.Indirect ConstnrtiooCost CI1db) Prchitect/Engineer Services {I .,I I I Q o 11 ~ I!!!I!.'I!'J@ ~I\tW~'.~.J!II!\@iJj !f¥l@l ~d"!f ~!'IJi!1 [!!II E!.'~~~.!!f!II!~'a!!!!!!f~!.~.i@ (, o o Stbtotal $100,354,(00 $55 ,l 533,lXl $2,562,00:>$12,265,cm $103,348,(00 $53 j l00,(OO $333,162,n>Contrcctorts OIertecd inlProfit 21"OCU,(XX)9»(0),00)3J t COO,OOJ Contingencies 47,aXl,OCOTOTPLPRtUcrOOST~ Tar'l'firrro.iect cosh-estimate was devel00ed.b'YdS•,J.G"oves cYld.&In.s ComiIlV...rb allOW({lC~h<iStbettllTB:Jetfor.la1daxl J~rights~c1ient charges.,(O'nfIer'S'M1l1nl:H..ra"tlooj,taxes,.lnterest'lJrulg constroctl00or tfii1snlSS100 costs Dej{m te-sl6SfalC11 axlswif.c"Yar u. (b)Inc.l~~m ..{ffi.••for constr.u:tioocaTllkt $31 J DJ,(ID..for enoineerirlQ services..ald $221548 ..an..far otherlindirectcosts incllding.coostroctiooequl.Cll.!~ls;COOstroctl00 relater uufTif.ngs Crllservlces,OOflnil1Ual stat'r saTarl~,a\:rcratt Pajnl I relataJ costs. (c)Source Battelle l~,Va1.XII. ':l o I II bf ,_.,---"j 'M'_."r .,iI <> " :1 Oi~falost $1,:Ji3,lOO 7,529,(0) 17,001,200 IO,Ol),OCO B,912,cm 1,,482,(0) 21 t DJ,OCXJ 37,612,(0) 39 ,SOO,a:x> 8,950,0Xl 7,SCXJ,COO 23,435,(0) 1,547,003 3,OOJ,COJ 32,670,(0) 1,OO'J,OCO 11,687,COO WA. 4,817,(0) l03;Oll,m> 11,5OJ,tlI) Sux:a:rtrocts $ . - ..,,.. 3,017,(0) .~~._.g,<m :., 12,(0) 11,COO 150,(0) a:n,ocn 25,cm 3,600,(XX) 143,(00 .2;617-,(00-. Jiibt:SbM ""L@!l~,!!~e*§ffi'klf!'!ili ~ ·2;882,00>- 46,(XX) 18,mJ .....,--'~~.~-~;~~ l:E,Ol) 1,150,(0) 58,(0) ~Wg~ $2,100 ' 13,(0) 174,3X) 540,00) 34,(XX) -42;560,(00 _TPBL_·_E _O._al_=.....(3_lR_u~.....INW'r:o~s)ffi N3WIA MfA STATIOO(a}(c) ~l~t(JJiprent Rent ~~ -$'$"001,OCO $110,(0) 5,400,0))16,0X) 2,391,000 1,235,000 1,001,(0)2,l37,(0) 7,155~cm 00),00:> 19 ,500~<XX) 21,00),00) Zl,l00,OOJ 8,950,000 5,785,00:> 9,0»,00) 1,049,(0) 3,00::>,COO 18,cm,GOO 575,OCO 3,260,an ~~ 1,937,(00 14,435,(0) 441,(0) 12,720,cro 1,142,00> 4,827,(00 $350,ocn 2_100,(0) 2,561,(0) 5,982,(0) 1,l757,<m 682,(0) 1,00),00) 15,662,aD 12,400,(0) 1,623,()}) ~54,943,<m Calstroctioo LeberCfldInsurCl1Ce I!!!!II!!!!! a~~\ ,......'..".,.-....'-":,':"-".."•.."' ~·"t"':'cj'l!P_&!!! 1.1rJ1:roVEne1ts to Site 2.ErltMork tnJ PH ing 3.Circulating Water Systan 4.Concrete 5.StSfciRsStee1,Lifting E~ip.~ 6.Bui.ldings 7.Turbine-fe1erator B.Stean felerator ·ald.A:cessories 9.Air QJality Cootrol Systan 10.Other fttchCllical EquifllSlt 11.Coal mAsh H<nIlioo...12..Piping 13.Insulatioo a1d L~ing 14.Instrumntation 15.Electrical EcpJl:lle1t 16.Painting 17.Off-SiteFacilities lB.Waterfroot Ccnstroctioo 19.Slbstatioo -Switchy<rd 20.Indirect Construction Cost crxJo.)Prchita::t/Engineer Servicesr I r I ? $344,136,Dl lJ,COO,Ol) 47,(0),(00 ~ $11,500,00J ~:?!l ~...~s;bj ~..~ $132,748,(0) ~!ll!t4 $17,141,cro ~1i;!!;;t'9¥!1.~ $2,002,(0) .~#JK.t$@ $44,733,:m 9,(0),00) ¥?_llI!Ii 1'\.,I ~.~ $135,li2,m> 21,(0),00) JEt-J~ <; ~.r~;£:t~j Ql\1¥ii4!!S Stbtotal Cootr~tor·s (Nerhea:f tnt Profit Cootingencies lOTPL mcu:cr (X)ST. ~licable. (al lJlelll"O.iect COSt.estimatewas r:levelooed bydS ••J.Gwes Mel funs C01lJilW•.•1tJ allowne hiJstbEen rncrJetfor la1d .a1d J.~rights,client chargesllJloller's <Dlllnbt.f'atlOll],taxes.lnterest Lrlllg constroctioo (r tfitJ$IllSS10ll costs be.)OOJ he -s\tlsta 100 illrswitc'IYcou. (b)IflCl~~816.!XD for constr:trtioo CaJI).$31.:nJ.lXD for E!1llineeril'lQsetvices.Mel $lJ.895~lXD for otherljndirectcosts inclooing <:aIstrttliooequl....,Q,'-au tOOls;constroctloo relatar uufTClmgs cn:)servlC~S,OOf1Oalual starr s(Harle~,cnVcran p~IreJato..r costs. (c)Source Battelle 19B2,Vol.XII. ? II I · Cootr&;tor'sOierhea:l iI1d Profit 15,00:>,00:> QJntingencies 22,224,200 lOTJU.FRfX.[CT rosr $IDJ,2tl2,:m ~Jroject ~estimate WiIS develOOl'rl.by S.J.(hJves iI1d~slhmil'IV.rtJ allO\'J<JJCe hasblfflmaje for l<nl.iI1d 111')(/tiohts climt•-,Ch1ir§es (Ollner S aill1H1stratlOOJ,tal<es,lnterest durllJg con5tfu;tiiii r:t'tr1l'lSlJllSS1Ql costs J)e}OOa tile SihstatlQl ,nniWJtetiyMd. (b)InclOOest $14,816.··..an [or.1SOOioeerirlQ services,aid $18t729 ..~for Qt.her indi~t costS1ioclLKitinQ constroction ~iJl1Blt ald tools,constiU::100 related uUl alngs aoo senl1CeS j nonnCllua staFf-salarles,cn:rcraff .~I rela 00 costs .. (c)&Jurce Battelle 1982,Vol.XII!. L!I \..- (':::' ,~ I"l c;:: I Oi rMatost $3J2,mJ 3,218,200 7,l34,600 5,894,(0) 2,200,COO 683,3X) ~,819,700 12,546,ro:> 7,714,SOO 8,129,500 512,aD 1,135,500 9,~,500 1,146,600. 9,956,40:) 001,600 5,017,D> 16,654,400 33,546,100 162,978,COO 4,400,(0) 1,496,(0) 1,900,cm 491,00) 31,200,OCO 8,600,00) 4,946,200 4,500,(XX) 250,00J 700,00) 5,250,cro 500,(Xl) 979,200 131 t 700 4,035,50:> 69,393,400 ~mt~ ~ '\) 250,fXX) 2()),00> 65,<m 120,(0) 50,(00 10,001 15,(XX) 2,500 2,693,600 23,700 10,(00 1,500,700 5,518,900 ECJli prent Rent-r--m;mr 151,600 28,500 226,600 3,621,100 31,00> 1,lll,600 5,540,lXl 172,500 115,COO 115,cm 345,00:> ffi,DJ 46,cm 57,500 11,500 211,(0) 23,0::0 12,l52,00l 4,313,900 21,357,5CO ~PJ;lff~lon R~l~ 1 ~ 2,666,31)87,DJ 484,400 16,100 348,00J 372,700 61,167,900 ~f)'f1~~F---r-95;600 - 313,(0) 2,455,(,ill 3,450,700 lJ5,oro 192,ax> 5,197,aJO 3,631,~ 2,588,700 3,164,500 126,500 379,500 4,586,00} 632,600 2,451,400 14,400 9tJ8,00J 4,292,400 26,341,~ (1 () TJlBlE 0.21:BID LINE IID1 Pc1m)FCRNL\n.RPL bl\S-FIRED aM3I~D-CYQE 2OO-r4I Station (\lC11uary 1~2 [b11 ars) ;-- 1.Inprovarents to Site 2.Earth\()rk ifld PH ing 3.Circulating Water Systan 4a Concrete 5.Stroctural Steel CI1d Life E~iprent 6.Buildings 7.~at .R£:r:overv rhilersh.~Gas--jt:rblrles,'crKrt:e1erClwrs 8.Stean Turbines CI1d fenerator 9.Other fUhCllical ECJjiJ)JaTt 10.Piping 11.Insulation and Logging 12.Instrurentation 13.El~trical E~ipte1t 14.Painting 15.Off-Site focil ities 16.Waterfront Coostroctioo 170 $lbstation 18.Constroctioo Catp Expenses 19.looirect Coostroction Costs cvd) Prchitoct/Engineer Services\D . SlBIDTPL. .~.--..--_...~-...,---- , U I I I t' I L I 5,4·89 1,827 3,396 ~98~.Presen~,~o~t~ogf System Costs 1993-Estiffi~t~~1993-202D 2020 2021-2051 2051- 3,930 479 3,386 7,316 Revised 7/11/83 TABLE 0.22:ECONOMIC ANALYSIS. ..."..."...·SUSITNA·PROJECT,'-"·BASE PLAN.'"..-..--...-; --= Components 600 MW Coal-Beluga 400 MW Coal~Nenana 840 MW GT 200 MW CC 1020 MW Watana 600 MW Devil Canyon 490 MW 6T 200MW CC Pl an Non-Susitna Susitna Net Economic BenefitofSusitnaPlan r f' f f I r J J I f I \ TABLE 0.23:FORECASTS OF ELECTRiC POW.ER DEMAND NET AT PLANT -----.,~.s C Reference -2 Percent Case DR!DOR Escal ationYear-~-~·~m G~~ 1990 844 4054 850 4085 793 -3808 848 407 2000 1020 4898 1158 5558 950 4567 959 462( 2010 1306 6280 1599 7681 1206 5799 1168 562: 2020 1672 80'~9 2208-10615 1528 7364 1422 686l Revised 7/11/83 o _..,_1"', I 1982 Prese1t WJrth of System Costs r-et Benefits .,..--$-x-lrP ,-$x loS-I 1993-Estimated 1993...,ro2O ro2O 2021--2051 2001:-.al'--. I'Refe"erCe Case ~-Susitna ::''93)479 3136 7316 .~sitna 3396 316 2093 5489 1827I'au rtlrl-Susitna 4~624 4E 9285 I Susitna 4004 499 3384 7468 1818 OCR II fbl-Susitna 2640 334 2392 5OS2 -- &lsitna 3259 283 1858 5117 -85.2 I -2 Percent NJn-Susitna 1941 J86 1056 2997 Susitna 3220 "'3 1711 4931 -1934aJ 'I I J • '1f1Bl:E .0.24:'-8-£CTIUG ·P()£R,fIMllM)SENSITIVITY A~Y5IS Revised 7/11/83 fi::. r'~,d: I f(r .- 5,489 1,827 4,043 3,973 70 ...1982·Present·Worth ·of·System Costs ($x'10 6 ) Net 1993-Economic 2051 Benefit = (Revtsed 7/11/83) TABLE-D~25:'.D-I·SGOl:lNT-RATE ·SEN51"FIVITY·ANALYSIS- Real Discount Rate 1993-EstimatedPlan(Percent).2020 2020 202-1 ...2051 Non-Susitna 2 4,829 457 5,418 Susitna 2 3~679 276 3,058 Non,,·Sus itna 3 3,930 479 3,386 Susitna 3 3,396 316 ~,093 Non-Susitna 5 2,669 562 1,374 Susitna 5 2,925 423 1,048 Ii I TPBLE -D.26:.·\lAPrrPJ:..·OOS'-'5ENSITIV·ITY -PN.AlY5IS 8,281 5,607 2,674 6,474 5,418 1,056 7,316 5,489 1~827 1982.Present·Vbrth ·of System Costs ($x lrP)- Costs of Costs of ~rt>n-Susitna Susitna EcC4101licPlCf1Pla1'Be1efits ~··f 3,93)479 3,300 7,316 2,977 2ffi 1,899 4,876 2lf440 3,9lJ 479 3,~7,316 3,839 347 2,3X>6,139 1,117 ~.Presel~~rth -of-System <:osts ($x 1(6) ret 1993-Estimate1 ~3-Econanic 0010 2010 2011 ...2051 arJl B:r.efit_""b._----- TABLE ·D ..27-:-.FUEL ffiI€E·...SENSITIVITY PWlLYSIS· Revised 7/11/83 Referenr~Case Fue1 Costs Increased 20 Percent Fuel Costs lS:reased 20 Percent Revi sed 7/11/83 P1Cll-Wata1a C~ita1 Coat.S Costs ~'2{)'Percent ftln-SUsitna Susitna watClla Capital Costs Costs tess'23 Perce1t _C3& fbl-Susitna SUsitna .. I -- -- 53 100 100 -5-103 4192 611~ 146 58 Index .Val 'JeS ~.. BASEREFEREra rASE·($1,'827-MII±IOO)_. o (~~;sed 7/11/83) Oil Price ForocasteRr IXR -2 Percent DiscotrTt R1'High .5%~ ~a, WatCfla CapitoJ Cost +20 Percmt -23 PercSlt Fuel Price +2)Percent -aJ Percent Real Fuel Price Esca]ation I'b Escal ation after 202{) '·I.· J •· "I) ~ 11 r Ii .I"~·i '•..! I; f f I) Ii I•..·~,,,\J 1'1 L', ··....l .".;.iJ~;.<: .::./'.-.·'~~~R·....•':-•.•">~'iil:,I••I.I!lJ•••,~~:,.:.tlJ.J~Il••~•.'.••.~.•..•.,.,..•••.•,.\~.',.'' (\·)CiX ..,.".•'...•.'.(L. :.;;;;;~~':~~1"',,-_,.j:Q(.'"'-:"".""-,,',,"_,<._,_,,~~ TPBlE 0,,29,;BATTELLE ALTERW\TIVES STlDY FffiRAILBEtT CArWJ!MTE ELECTRIC ENERGY ~NERATIMJ TECt-rQ.OOIES v c '-,," ',:,I I I ~~I!!IlII"J '",..'-,.'"~..,,,"'_,-i:.1<'""-~~-"~.~ Availability for Qmrerci a1 £h:Ier O..lrreltly J'fIailable Currently AvailiDle 1005-1990lOO5':'lm 19JJ-1995 11005-1900 985-19901~-1900]99()"1995 Clrreflt'jy AvailableCurrentlYAvailcblelOO5-19CXl19»-1995 " Currently Availcble Current ly Alai 1mle ClJtTa'i,ttv Available1985-1~ 1m-1995 Curr'8"ltly Alail ableCurrentlyAvailable UrrootlYAfai 1cb le 1900-200) 19'»--200) Im.2COO Currently Available ~""o?c~"",'~•l:J,,~,(.~.:~;~_._~-j ,'':; .. >0''''''.":.;' ~ T:mical-pppTieation .----..-.;a-:- Baselocrl Baselocrl Baselocrl/C.}C lir~Basel 000 BaselocrlBaseload/CYcling Base10Cll/(;jt:l ing BaseloGrl Basel 000 Baseload!~ling Base lo;x1/t.j1:1ing Base]oadBaseioad/Cycling 3aselocrl Baseloooi~li~Baseload/(;jt:1iogBaseloa:.f BaseloaJ/Q}tiingBase1ocrl/l:.}<:l'i ng Baseloaj EaseloadBaseoad/C~lingBasel000 Baseload{a) BaseloaJ(a) "1 i ~_.-'w S"'--"'-h*i4':m! ---:~ [/ o -,,_"'-':_""!>f,"-:~,,~.~~-,-~,~,; " C£neratiooTochnology--:. Direct Fired Stean-Electric Direct-Fire;1 Stean-ElectricCmbinedC)tle Fuel-Cell -Qnbined-C}(:le Di~tFired Stean-Electric CorblnOO C~leFuel-Cell Statioo Fuel-Gell -COmbined-Cycle Direct-Fired Stean-Electric Carbined C}{:leFuel-Cell Station Fuel-GeH ...Carbiral-C}{:leCarbustiooTurbine Di rect-Fired Stean-El Erlric Cmbined C~lcFuel-Gell stations Fuel-Cell -CartrinErJ-Cy;leCarbustiooTlf'bineDieselElectric Dire:t-Fired Stean-Ele:tric Direct-Fired Stean-E1EctricCarbinedc.}{:1e Fuel-Cell -Cmbined-Cycle Direct-Fired Stean-Electric Direct-Fired Stean-Electric ~ (, ~ Fuel. .'(awersioo . _e ..... Crush Gasificatioo L',quefoctioo NJne Refine todistillate <n1residualfrnioos I'b1e Gasification fbg &>rt &Classify ~ \)'.;. l!'§l11M.~"...,-.--:'-'';'----.",-:;j / "'0 Priocipal Sources for Railbelt ...-.-.,....~..~- Be~~a Field,Cook Inlet l'SlalCi Field,realy Cook Inlet ~r1:h Sl~ Cook Inlet icrth Sl~ ~ Kenai Palinsua1 I.aEr Susitna Valley Jflchor~FairbCllKs Kenai PftdxJr~N9t'lCllaFairbCllks ResourceBase. -=:z Coal Natlral Gas Petroleun Peat Wnf.'~:iSte ~••,~tn'~1·ItQ'llCl~~J\Ct use ~,",,~,J ea.'.,..,',}cef,':; i l I ~--'u---~'-0'-- "j~, (:/ III ;4,.~i.);'-''',''H'~-,~":'--'''''''1'';':''-",,:~,''P,"* () o o I " l)- ,~§li~1 Avai1abilit.y.rfororCctnoorcial~ 19f1)..alX) UUrtently Available Ortently Avail cb leCurreritlyAv;zt;~ub leCurreritlyNai1cble Curra1tly Avai 1cb leCurrentlyAvail<ble ~ 1I:1~ 1985-190019CJS-2OOJ Q.rrently Ptlai]fble ...~.".,,,.,:J ,'&.•.~;.-•.,<. I!I!II!!M! T}{)ical~ricatioo ... Basel 000Baselu;rl BaselOre)C}Cl iog Fool Saver FLel Saver . Baseload/Cjt:llng Fuel Saver Flel Saver Fuel Saver Flel Save'" Baselooo 8.....~3: /] \> G2neration Tedl101Q9Y ~ fbt lk'y Ib:k-Stean-Electricf-{}drothennal-Stean-Electri...; Co.'Y81tiooal H1tfroelectric5nall-Scale f-MJroelectric Microhjdroe1e.ttric Tidal Electric Tidal Electric w/Retirre LargeWird Energy SYstansSnal1WindEnergySystens ~lar Photovoltaic Sol ar Thenna1 Light Water Reoctors ~ ()\) \~ Fuel.Cooversion .,. .__..".-~""- Enridrrt!i'rt& f-eDricatioo @lfJJ§~-1.;,,~<,:';~'''"''''J.-~':-'"''''''''I.:..,,' Principal Sources for Railbelt kr~llMJlJltainsO1ignitMJl.Iltains Kenai M:x.r1tainsAlaskaRCI'lge Cook Inlet liTport Iscbell Pass Offshore Coastal Throughout Regioo ~....~",;/,.;:::;...;pf!j')~'.J TJ!BlE U.29 Contintaf ReSOlrCe Base -_,4 ( feothennal Tidal 'fh..er Ii}tfroela:tric Wirrl LriJ1iun ......~",';;,'1:.~~'_"__":3'.:...'-'....,.,"";' (a)SUWlarmta.l firing (l:Ifcoal)NJIlld be reqJired to S\.Wlrt base.loa:l.pperatlOO dle toC.K:l1cal fuel slQPly.. (b).Majl be baselo&1/c~]lng or fuel ~alJer tEpelding 1,pJrl reservoir c~ocit.Y. SJlar (~~I-,':~J~~,~l1 II j':LL...'cc,~:., t t;;j- ••••••'~L_".-'-.-,-.'~"",",,4.·~_e..-~,~..u:-~ >q o.0 I ,I I 0.6 0.6 3.5 1.7 3.3 15 15 16 ..70 16.70 14.00 4B 7.lJ 42 50 9 4 4 5 5 5 7 5 44 5 44 44 3..70 140 140 3100 ~ 2100 4669 168 2263 5850 5400 7240 4470 4820 2840 2490 2980 3320 8 3334 220 395 85 43:> J1 247 1570 1923 3459 NlA WA 14,COO 14,(0020 50 .TABLE D.ll:BATTELLE J1lTER~TlVES STillY,SlM'4DRY (f msr fWD....,....'PERF~CHDAACTBUSTles {F-SEJ:.EcrED ftJ..TERMTlVES Aver~ Capa;ity ,Pt1nuaT''Capital E'ed W1 ~ia:>leAltellatw~-','.....-(f4iJ).t,a).~/~j f~t!~~;,~·it~_~7~W)($?K~/}r)(mil1sfkW1)-------.;,-----.. Coal Stean-El~tric (Beluga)20CJ lO,COO 87 2C1:XJ Coal Stean-Electric (rt:na'la)a:x>10,COJ 87 2150 ilial Gasifier-Q:n'bined CjCle 220 9,200 85 Natl.Gas CaIDustioo Turbines 70 13,&J)(b)89 Natl.Gas Cmbined C)Cle 200 8,200(C)85 Natl.G3s Fuel Cell Stations 25 9,200 91 Natl..Gas Fuel Cell Carb.CjC.200 5,700 83 Bra:lley Lake Hj{Jroelectric ()~94 Olakcchama H,}droe1ec.(:m M.al)d :m 94 O1aka:hama H,}droelec.(400 tvW)(e)400 94 LPPer Susitna (WatCi1a 1)600 94 U?Per Susitna (WatCl1a II)340 94 QJper Susitna (l:eIil Ca1)OO)600 94 ~w E1~tric 63 94 Keetna H}droelectric 100 94 StrClldline Lake H,}droelec..20(17)94 8rcMne.~roelectric 100(00)-94 Allison HjrlroelEctric 8 94 G"'C11t Lake Hjrlroelectric 7 Iscbel1 Pass Wind Farm 25 Refuse-Ia"ived Foe1 Stean Electric (flncrorcge) ReffJse-~".ad Fuel SteanEl<:dril"(FairbCllks) ~a)Coofiqur.atjoo in pan:mheses used in crt)alysi sof .Ratlbe It el ectric energy plus taken fran ear.l ierestimatestAlas~.a ~r Mhority 1900 (b)~heat lr:ce of 12 t COO Btu/kW]was.used in iJ1alysis of 8ailbelt ;elect;ri~~P1iflS.13,roJ Btu/kWl lS ~~ly rror:e ~€:fItatlve of partlal l P.{ij OPeratlat ~hara:te~lstl.·C or P?aI$lng duty.!C~'fJJt earller estlmate of ~BtU/kWl \'teS usa:l1n the a'1al~lS of Rallbelt electrlc enemY plctls • .d Coofig.urat.'ial sel.ecte:f 111 Qreliminary feasibility stoo..~Y.(Bechtel Ciyil m Minera',s 1981)e Configuration selected in Ra'ilbelt alternatives stooy lEOasco 1982b) 11.\I:'::' if: ·E'; 11 11 I~: 11 ,-I ,..:t..•. .'.' (; I: I I~i r'.I·I'. v.··.t I. :[ ....•,"'" Ii .J :'11 '1; I ~,I '.1'•.i o LrI 317 284 296 369 438 96 1800 532 658 537 217 1953 53 73 76 83 140 237 347 364 355 295 18 20#1 3994 5794 1982 PV"'-.:~asing Power .-$-x -10 6 --_...------ I Nominal $x 10 6 Interest Rate -10% Inflation Rate -7% Ac·tual ,~ I'lL~1 1-..:' (Revised 7/11/83) TABLE 0.31:FINANCING REQUIREMENTS -$MILLION FOR 1.8 BILLION STATE APPROPRIATION .I d 1985 State Appropriation 40286385874298857389728YO171 Total State Appropriation 2688 1990 94591125292109393472 Total Watana B')ods 3782 1992 107931609/177952069637397677981061991190200012400111030270 Total Devil Canyon Bonds 6364 Total Susitna Bonds 10146 Total Susitoa Cost 12834 I"·'''.·1 ~ 11 1""".1..'"i Ii ·I~··~ ....1 1··,···.\.\ I', '.;:."i: 'I Ii I ,~: I; If."IJ .J'~,J II I J .J 11 'I J ,.. ··,._o.-_"'~~~"".:',.""'::,;......... TABLE [.>'.32 ~&!II!<'-.'..•;...,:,l~i<'AI84E~.-"",-."", '" !!IJ;_!~ SHEET 1 OF 6 .. ,.",-~"..'..__.U<'~!~~~"."¥-"-."" 1985 1986 1981 1"8e 1ge9 lC39C 1991 1992 lS93 11S~FlO~SUflMARY ~)~CASH ===(!~ILtIUk)==~: 2~53 2':;~" 0 0 o 0 0 C C CO.CO 0.00 O.CO C.Oo e.oc c.cc o.cc 0.00 5 a".e2 SE.II126.72 135.59 1~5.ca 155.2'4 16f.lC A77.13 190.11 203.413 21;'13 2,a.(.~100000.00 0 ..00 0.00 o.oc a.cc 0.00 c"oo 126.32 f'25'c:-...l~~·t ('c.o 0 ..0 0.0 0.0 C.O t.e lJ.C 0.0 313.0 4CC.10.0 0.0 0 ..0 0.0 0.0 o.c o.c e.G 22.t 24.c---------------- ------------------------------~--------------------~----~-------C.o c.o 0.0 0 ..0 c.e c.c e.e c.o 3SC.4 :ne.50.0 0.0 0.0 0.0 c.e GeC CeC G.G o.e 't.~0.0 c.o 0.0 0.0 c.o c.e c.e c.e e.e e.70.0 0.0 0.0 0.0 c.o D.C o.c c.o 32;;.C 376.2_------------------------------------------------------------,--------------------0.0 c.o 0.0 0.0 c.o c.e o.c 0 ..0 21.04 -3.8 c.o 0 ..0 c.o 0.0 c.o c.o o.e a.1i 21.4 -3.€4C2.0 384.9 426 ..6 572.8 12S.2 110.a o.c,c.e c.e G.e0.0 0.0 0.0 000 c.o 944.6 1252.2 12CC·A 632.3 176.6 I !.1 G.a e.o 0 ..0 <:'00 c.e e.e CeO c.Bf.1 6.2-------- --------------------------------------------------------'----------------402.0 384.9 428.6 572.a 72B.2 In~.4 1252.2 120C.1 7lte.if l1c;.C402.0 384.~428.6 512.8 7~e.2 Ul~."1252.2 12CC.l -,..:3.7 Hl.l0.0 C.O 0.0 0.0 C.O O.C o.C c.e Se.1 6.2C",O o.C 0.0 0.0 C.O O..C .0.0 0.0 C",C 13.S-0 ..a 0.0 0.0 0.0 e.o e.c O.C 0.0 c.e c.e--------------------------------------------~----------.------------------------0.0 0.0 0,,0 0.0 C.o e.e C.O 0.0 e.e -"2.80.0 0.0 C.o 0.0 0.0 O.C oOie 0.0 c .,C 42.80.0 e.o 0.0 0.0 C.o c.e coe e.e e.e Cd;.0.0 0 ...0 0.0 0.0 e.o c.e c.e 0 ..0 ~b.Ci 4S.20..0 0.0 0.0 0.0 C.O G.C 0.0 0.0 4C.7 43.10.0 C.O 0 ..0 0.0 C.o c.e o.e e.e c.e C.C4021lC786.,9 1215.5 17138.3 2S1E.!;'3fl:H.C;4884.(fe84.;:e':!':nIl9 693<;..6-~---------------============~==~=============~==-.---_.-._-----_._--------....========---.-------------_._-_._----_.-._--.....---402.0 135.c;1215.5 1788.3 25lt:.5 ~631.C;488'1.<6C84.2 ~EZ",.f 1C?2.5================================================================_._._------:===:::=---_._----4C2.e 1e6.9 1215.5 17813.3 25H.5 26e1.3 2681.3 26e1.3 26E7..3 26~1.3O.C o.e G.O 0.0 C.o c.e O.C CliO 21.4 17.~0.0 e.o 0.0 0.0 C.O o.e O.C e ..o E6.1 1?5 ..10.0 0.0 G.()0.0 C.o 94':.6 2196.<;3397.0 4C;:9.2 41Sl.!)O~0 C.e:0.0 0.0 .0 531.5 l:ljq;~~99.1 2<;C.4 75.~l~0 ..0 0.0 1').0 VOla .0 53i.5 1189.9 1779.7 207e.t 2145.<;.~0.00 0.00 O.CO 0.00 C CQ c.ec e.cc 0 ..00 1.e7 C.C;5 I ~'§!!..~_...~.,@EJ~.~4 ENERG'fGJlfl REAlPRICt~~llLS INFLATIONiNOEX PR ICE-HI llS -----1 NCOHG--------_ ~eVENUf LESS OPERATING COSTS DPERATING INCOMS ADO I1TEaeST EARNED O~FUNDS lESS INTe'U:ST ON SHORl TERM DEaT LESS INTEREST ON LONG TERM DEBT NET EARNINGS FROM OPERS -----CASH SOURCE AND USE----CASH INCOME FROM DPFRS sTITE CONTRHHJTION L.O~G TERH O~eT DRAWD~W~SWORCAPOEerORAWCCW~~ TOTAL SOURCES OF FUNDS e.:' 73 52.1 466 :;2') 516 170 511 214 550 391 54a 54a 446 143 243 549 ~*~*****~**~****lQo**********~*~***.*****.*****~iO************~***~*************11)**JOi~**"~**********(1.0*********lIl *lCo lO**(I ***~*lCl(l::*~.*:t:oD~TAIlK.D12 WATANA (ON LINE 1993)-Sl.8 BN(S1982JSTATl'=FUNCS-lt\FU\TlCN l~"'I/\TEREST lC2'-CAFCOST S5.15 B/\23-JLf\-S3**********************~v~'*~.**lQo**."***************.(I***~****l('l*****~*~*\lCo~**lt"~*~****.*~~~*.~**~********~**~*********lG*'**I>*.lCIJC*~l¢*~~.* $1.8 BILLION (1982 DOLLARS)STATE ·APPROPRIATION SCENARIO 7%I'NFLATI·ON AND 10%INTEREST 320 LESS CAPtTIlEXPENDITU~E 448 lESS WDRCAP AND FU~OS 260 lESS DEBT REPAYMENT<: 395 LESS PAYMENT TO STATE 141 CASH S¥'RPlUSl'QEFICITJ249SHORTER'"DEer 444 CASH RECOVERED -----BAlANCE SHE'ET----------225 RESERV~Mm CONT.FUND 311 OTHERWCRXING CAPITAL 454 CASH SURPLUS R ETAI NED 370 CV,.Ca~ITAl EXPENDITURE ~65 CAP I T'Al e1'PlOYED 461 STAT~CDNtqI~UTION 452 "ETAIN~il EARNINGS 555 ::Jf.eTOUTSTM~:JING-SHCRT TERM 5:54 !)E':T U'JTST,",fojIJING-lONG TERM 542 ANNYAl DEBT QRAUWDCWN tlqB2 543 CUK~O~eT DRAWWDO~N 11932 519 DEe"SERVJC,E CCV~R l!!:~c c·'.'' I ......''''-.. .. I I \. .Ll.:',•.·.i L _~.,__~................~ ...•••..••.•••.••...•.1.._--".._.._'_."'..~-_---_.-..~~_.__-----._'''~'::'',r..'/,0'..-'-_....-....1 ._~__.__-----_.-"'~__,QL~--....~·~·~'".,.....-~···-..··..-.-.-·-o •.."...\).D...~\ :) c(i:. ti' .(). ~~~..~ <19.$ "'32.7e.e CgC 1157.3 ct).l 47 Q 652.17~5e.2g i41.1:3 2627.3c:5.2u.7.~ C;S19.1 c.e 31)e4.1 1.C~ lCi~:~ 12.ec;€E.l In.; 1C.8 17 .~f1.ec.e c;c;.c; G.Ce.e 17.3 2CC4 1111.4 12!:.Z ?'9.J13272.4 1?62902 -.-_._,_._-- -_._--_._- ----_.__..- -_._--_._- ===::-:==::~ -_._-_._--_._._._---- ~ ~4.7 (;6.2!E'D e~.s.2 C.C ~04.7e..ce.elR..S 2CC3 4l:7C 'iCi.ll: 42€.31 i31.gc; ~530!5 -87.7e.ee.c lCl~:~ 2.2 9"3.1 Ice3.3 (;5.1 TAStE D.32 u,e7.3 7!:~.3 25'C.3 c;IH!IJ.': c ..e .3984.1 c.~e 1;'2.2 IIf:'.l 122 ..C U2Cl.5 _._--_..__.- 1~~72.,~ --_._._--- ---_._-_.- -'-_._.__._.- ===-==,::= -==~=-=:== /llfAIIJ 1 CS.,4 2CC2 113.e 76.22S..S C ...O 4555 54.184CC.,29 21f.88 -38.2O.Q7e.: 76.2 9p.1.a f.:c.a -38 ..2 ~27.C7.5 -16.6 989.6 -Ub:g C..C 123 ..5 lC7.<; 2C9.t 1313:.4 -_.__._-_.- ---_._--- -_._.~-...-~ .....u~I ---'''-~'.-- ==:=-==== 135H.5 =~:=::::== ~6e7.3 720.(; 231t14 9931.2 17.(; 3ge4 ..1 C.93 3105 43.10 374.1C 163.49 ZOCI 51.2O.cc.e 124"f.O.c 1102.1(;.5 ~C7 ..(; 38 ..9 1233.T 1143.C f.521'.C COlt MIll 2687.3 758.e 155.2 $89t.5 294.1 3966.5 1.25 1').r; 1(;.3 32C.Fl 12C21.,7 1?491~e -._-----.. 468 .•17.4 -11.5 363.0 ~----~-~124.(; _._--..,....._- -_·1 ....'---·..71·_ ======== ::.:=:::===:: ~IIJI\ SIc ..1 36,,4 3Cf44l.6a 34g"f2 1f~a7C 20CO :(j.)f C.C C.C 12~:e 124~:~ 131C.O 127l.€7.e2·~.(;c.e 26e1.3 631..314e.e 88'20.8 354.1 3tl1.7 1.2.5 13.t 1~..9 263 ..7 1187 E.1 17.2S'1.2 --_._'_.,--- 4'H .4t."-6.2365.5-,_.---..:--... 12l.1 _._._-_._-- _._.--'.-,--- =======-:; -:;======= "~; 21>S7.3 5i2.2 14]IlC 1,6.ms.~ 364 ..2 3317 .0 1.25 lC'H~.e 6~;9C 72.C 2C?9 t06CC.Q 62.3e..ct.e "SC.~4t,,4 -C.7 367.1 514",4 .34.0 119.9-'--.-----_. ---._--_.._- 1l~.9coe !19C.Cti..Z---'\..,--_.- 1316.1 12~5.2 l:...222.4c.•o_._._-----.. --------_.,,'.--.----. :=::==-:::== .~ 518.2 31.8 117.8 4:6.5 6.0 4.9 369.1 04.60.0 0.0 117 ..a 0.0 1C61.Jo.~' 11'31.1 tC94.0 B.2 20 ..3 0.0 64.5 10.3 ·141.6 9~75.16 9652.0 26(11.3 ~92.3 134.8 6437.7 347.4 2952.8 1 ..25 _.--..-.-'-',- ----._-,--' -------- ====::::==: ======:=-:: ,JII!I!,j 52?...Cj 29.1 -)6.7 G.O(,...) 1161'00..0 676.0 1 ..2 800.0 701.6 7.213.5 0.0 1991 1998 1999 CASH Flew SU~~jRY ==={5~llL1C~t==== 3028 3055 3C5160.47 5~.55 51.50 285.40 3C5.38 326.15 172.57 169.65 16e.2~ 6e.) :>t ..'3 71.1 82J31.6 e 48~~,2 2.s~7.3 274.5 126'll5 5396.9 ~37.1 2~C!:.4 1.25 _._..._.-.---- .492 ..8, 5.6 lC ..9 371.6 ..,;",'"---....:..._-.- 116.0 _._----_._- .'4J ='======= ======== SHEET 2 OF 6 114.3 114.3 0.0 ~l~:~ 1996 525.9 21.7 4c;a.~5._ 15.9 373.3 506.1 'tCI.3 19.2 6.8 0.0 6E.7-53.4o.c 3C1965.31 266.73 114.21 50.3 53.0 lC.3 7574.1 1703.7 26'H .3 15$.5 119.3 4738.6 13'1.1 2368.3 1.25 ... :~. -----:_-- _...._';:.----- ------.._-- _._-..-_._-- =.:=~==':= .::=~.=.::=== '(>1G.0 4.9 13 ..6J14.8 43'3.9 25.9 26.5 0.0 2°9:~ 233.1 7.2 1::•.3c.O -15.615..(,c.o 24C.0 26.5 1995 3 Gll5 58.20 l49.2? 145~07 ... k..;;,.,.:.,,.•·.......'1 7272.l! 52.6 47..So.t17172.7 2~a1.3 44.2 138.5 4382,.,8 82.7 2228.6 1 ..03 _._-_.__._- --..._..__._.- ---....._-_.- --'------.,-- --====:,,= =-===:-:== l'IBI ...~"""'".:"';"::J;::~;.<~:.~~_eT.:'::!;;, 'C ,.. ",.~.o:;.~.:.,.~~:,~~:";:...1'"4'ii'~-".""';;";"~"";j \1 """'- ~ 11 ENE~:GY GWH321DEdLP~I CE-fllllS46&INFlATIC~IN~EX ~2l)PR ICE-IIUlS ---':""--lNCO~E...--...---...----..._~EJPWE lESS OPEqATING COSTS lJPERATltNG Ifl:COII.t ADD lNTEREST FA~u~n D~FUNDS l.ESSI NTERESTOU SH;~RTTr.RM CESTLESS•NTE.Rt.=ST ON tG,IG lERr~DEcT '~rT ::A~:\ttl:,GSfRD~I)PER S -----CASH So.URCE AND USE----CASH JNC~NEFRC~DPEns STAT"::·CQNTRl3lJTION ll)NG TERM VEBT n~A..tt~.D.CWt\'S"~RC"P OEBf DRAt-InCWNS TOTAL SOURCES OF FUNDS ';4.J1 ~16 170 511 21~ sst>311 54 ~~ 44~ 143 l4·q 54 ) ........********************~i~*********~**~***O***OO***O***O***O~*¢***C~********O*~**~¢****~*O*~***O******.***OO**.*****O******.****~*DATA12K.D12 WATAM\(ONollNE 1993J-Sl.a aNIl1982J SlATEFUNCS-l~FtATIC~7%-1~TE~ESTltt-C'FCCST!5.15eN ....23-Jl~-S3***************S::*******:r::**********************00 ~**Oll1:****"'**0***~**')0***********~****~****0**0 *~**:0 ***~**:(:**o:tO :to.'O *0 ***:0 *lC ***:0 *::.* $1.8 BILLION (1982 DOLLARSJ STATE APPHOPRI'ATION SCENABIO 7%INPLATION AND 10~o.INTEREST 120 less CAPITAL EXPENnITURE ....411 lES.i ~imrCAP AflJO FUNes 2511 lESS 0:::,8T 'REPAYMENTS 3';):;LESS PAYMENT TO STATE .ttd,CA.SH SURPLUS(OF-FICIn249SHORTTER~DEBT 444 CASH.f1,ECOVERED -----8AlANCE S~l~tT...--------_215 RESERVE ANt CCNT.FU~D 311 lJTHE~"ICRi<lt-.G CA?rTAL 454 CASH SURPLUS RETllNE~ 31n ':U"".C1\f'ITlIL (.XPHiDITUPE 465 CAPlTAl F~PLnYE9 461 STAT~ca~T~I~~TIO~462 1STAINED E~RNI~G$ '553 !)E~T OUTSTAhO ING ....SHC~T TER'M 554 01:8T OUTSTMDING-LONG lER:~ 542 4NNual CSST DRAWWDC~N 11982 ';1.3 CU"'.DI:BT Or:{AWWDGWN H~82 )1 '9 D~P.T SE1WICE ccy:p r-""""~''',>..,...'~.:;,t IIf hz->I't :':_--*..si:titr'i}r'·""••••"")~>~.".~'..... \I /~u " ~Ill}.It;,.,.","'- 123.2e.c 123.2 422.9 t:317 26"C9~Cl.52 (~~.n 422.9e.cc.e 79.C 2087.3 ,eC;f.f 6<;9.3 P,7'3:.2 c.e 3<;;84.1 1.2: if;14 218.2 421.1e.c14319.1 15::13.4 5C1.5 1311.31<;.CIte..4c.e _._---.-,,-- It,n s.s l:n.c_._----_.- 1348 ..4 '-6.C 62 ..Cees.t: --._----.- _.__.;--_...- ==::==-- ===::=== --';''''<~.""",:".,..... _v.-__...__J'_ 4e8.3 _._--_._-_.- 136:~ 132.3 1413 ..2 !Ze.l 1~C.2 5C.C 145.£1 C.,C 1:45.1 7.~..3 :1.C 9C4.1 4C8.3t.ec.c:c.c f14O, 28.44 842.5~ 23C;.64 2fC.O 360.3c.e '·H1c.i ..e ----_.._._- 458.3 (len -'~'-'---.,...- ==::':.=== 148CC.1 =:.:===== 2687.32:<;7.C 620.3 e8f):.~ e.e 3ge4.1 I1t2~ ~ (;023 3C.83 787.42 242.13 ---_._._._- 395.0c.ec.e 45.3 2t:12 243.0 327.3o.c14C4<;;..1 121.1 45.::1 132.Se.e 140.8C.o }4\).S 14£:1.9 llCJ ..l-'--'--".-_.-1342 ..2 22.7 52.5911.4--_._--_._. 395.0 440.3 ===:=::= 1461<:.9--._----...---'-'.-.__.- 2687.3 2321.0 510.2 9C41.3 O.c 3ge4 ..1 1.25 I!IIt;L .00,,",'= D 1IIit, ...."..;,.J 221.1 297.8o.c1;~2e.c 5B6233.6l: 135.91 24\f06~ 2011 2687.:3 2CH:.8 ~24.<; 9173.<; cae 3984.1 1.25 1',8.8olOe 14£'.8 14!H.q 111.<;-----.---134C.O 21.2 4B.e 92'iJ.4 383.C 14452 ..9 -----_._- 383 ..C 0.0o.c 36.6--_.__.-..-.- 419.6 113."7 ~".612C.5c.c _._~,-_._._- =====::.:== :=-===-=== ~! 372.e 1 ~6,,,2a.e 156.2 143S.5 1e4.~ 1334.9 1~.8 42.4 9AC.4 2Cl~ lC6.3 64.flCS~5c.c 436 ..6 57C43(;.1C 681.11 252.3e 372.Ce.ec.e64.t 26P.7.3 1832.6 4SS.3 9294.4 c.e 3984.1 1.25 143r2.t 212.2 276.1e..e 12814.3 _.-.-._._._-- ---._....__.- -_._----- =..==:====.= ==-=====: ~ .~---,---_. 1333.5 U!.5 3 ~'·".'i·~QSC.3 3(;2.1 "9 ..327.8<;;906c.o 2681.3 16H.9 423.7 94C3.Ci c.o 398-4.1 1.25 1f~:6 163.2 1431.2 C;1e1 _._-_._--- 362.1c.oc.o 27.9-._-_._._._- 389.9 -._------ 198 ..3 22!..'tc.c 137ce.o======== 14131.£1::====:;:= ... '•..;...',.,.•~_.,....",,1 353.0 381.2 169.1 0.0 169.1 353.0 0.0 C..O 28.2 i423.2 n ..3 92.8 28.290.5 0.0 1331.9 17.3 36.a 959.4 26R.7.3 14J8.0 395 ..9 9503.5 0.0 39£)4 ..1 1.25 14C04 ..6 185.4 21C ..5c.o13tC€1 ----,'----- -----_._',- -_._._-_._- :'=:===-== .:;:=-====:-'""" .-. ~r 344.3 0.1) 0.0 23.0 344.8 141h"O 85.3 1330.7 16,.2 34.5 r')61.6 ZOC1 20C8 2CC9 CASh FLew SU~MARY :::::::titIlLln~)==== 5224 5384 !!444~.2a 1".01 4C.1~S61~42 6CO.72 642.11 Z11.CG 264.35 21e.16 175.7 O~O 111j.1 361 ..8 86.1 23.0 82.3 0.0 2687.1 1234.6 367.7 9594.0 0.0 3984.1 1.25 13083.6 11:.2 lq4.5c.o1351".Q _.--_.-.__._- _.-.------ ------_.- =======.= ======== -:.~~"':';"""".,.;.e-.",J 1El.4c..c Ifll.4 1329.4 15.1 32.1 975.1--_._-._--- 331.3 0.0 0.0 23.5 331.3 --_._--_..- 36C.7 81 ..1 23.5H.a 0.0 -.-.-._--,_._-- -.-._._-_._.- 2ue6 506453.04 =24.69 27~.7.9 1409.1. 19.8 161.9 1112 ..8c.o 13·\29.2=:::::::1==== 13173.9--_._-------,--_._- 26P1.3 lC65.(; 344.1 9616.3 c.o 3984.1 1.25 ,... ~'~-."_·.-,·~:t 330.5 lOC5 75.8 53.6 613.0o.c 330.5 0.0 0.0 53.6 4'102'57.86 4'JO.37 21)3 ..11 151.3 16<;;."1 0.0 13348.1 13~S9.3 2681.3 'JOg.1 321.2 9751.1 0.0 3':JS4.1 1.25 3a4.1 186.7 0.0 216.0 139C.6 74.5-"--'--'---1316.1 14.1 11 ..8931.9-'.._.._--_.- ----_,io-...._ =::====== :======= ~ . (r' ... .....:;:;:;_."".'",,;J ... "."._2,.;~:":_:J ~~,,:-:-:::.--,~ -----lNCry~~-------_ '1':VCNU::: less DPERATING C~STS ~PER.~Tl~G JNCrp£ .\r;·lJ INT~R=ST IYlQNcD cr.FUNDS tESS INTER,=ST ON SHCRr TERf"ceBTLessINT~ReST ON LONG T~R~DEBT -----nAlANCES~~GT--------__~ESERV~ANC £~NT.FUND OTIfE'l WCRKINGCAPITAL CASHSUPPlUS PETAINEDCU~.CAPlr~l EXP~NCITURE ........::":;;:(' .iI'9 51/, 17") 343 ~ET ~AaNINGS f~~~UPER$ ---,.,-CASH SlJURCE AUD U5[----CASH INCDMEFRG"DPE~SSTATECONTRl3UTJON LONG TERM ~EaTD~AWDCW~S 1mRC I:\P DEBT :JRAWnC\.INS TCT~l S~U~CES DFFU~DS 51 7 21't 3':;0 391 34:1 445 1~3 24'3 73 E~:I:RGY GloIH~21 RUALPRICE-'ILLS 4b6 tNFlATIO"l INDEX '1\2.0 p~ICE-MIllS 3~~tESS CAPITAL EX?ENDITUfH7443U:SS WfJRCAP A1\O FUND~ 200 lESS DEer REPAYMENTS 395 LESS PAYMENT TO STATE 141 CASU SURPLUS(CEFIClnZ4~SHCRTTE~MO~BT 444 CASH R~CQVER~D ***************************~:¢***:0****************lO ~*********~l*****.**1)~********~~.~~**~.*:o lO ~lO~***~**~**li}**~:O*lI*:O(:l**14.***:»*'"~*:¢***.~:0CATAIlK.Di2 WATAN.~(Of\;LINE 1993)-Sl.a8N(U9B2)ST.1TE FL~CS-II\FLATIt'~.7%-INTE~EST lC,i'-CAFCOST !5 0 15 eN.23-,ILf\-S,! ****q****:;r*>,'l:*********'Jr****::t**********>:l********:O***:O *0::~****l)*:)*,~*>::****~*:~***********~$}JQ *Jl):O:O ********:0:0:0:0 **~:o*~~***10 ""~~:o *J):¢*:¢.¢;~*~:o 225 "371 454 J70 465 tAP1TAl E~PLCV(D 461 STAT!:CGr.,TRI3t:TIJJN 452 ~ETAINEn EARNJNC5 ~55 DEer OUTSTAN9JNG-SHC~T TE,RM 554 neaT DUrSTANJING-LQNG l(~M 542 A~NU~LCEe7 DaAWWDCWN 11982 ~43 CU".C~BT DRAWHDOWN !1932519neaTseRVICE(eVER e -!i '.:1 $1.8 BILLION (1982 DOLLARS)STATE APPROPRIATION SCENARIO~j 7%INFLATION AND 10%INTEREST o-(lL SI-ll:l:T 3 OF 6 TABLE 0 ..32 .t.t.,,c; ::,.'.L-,_.".------,~..,....r-.....'/~---'_ .'.....'"..,.~;.,,.-..:: •___ _..1lIIIO 1lIIIO___1lIIIO__*"1lIIIO ______II·II·.···..·_IlIiza1l1i1·liI·t.ii·'._IiiIIII __:._i1i.··~·~.··'ii·.".."_·i1i-iii·"_bPs-";i"••·d·".•,...,.•'3',.O';;"~..'........'3', ~f;j;;r~ ~. r::~~~w''''....r.-...,.-.",..,.-l' TABLE D.32 ~.-..'~j _~-~-.',~~ii::i:::i:'''.~;,i'.oii·'''''·.-.'.'·.'''''''"'' ~~i•__ti~... r_····'.__.,.,_....... i~'...f~.~ 2015 2016 2017 2018 2C19 2Cz.e 2021 TCTAL CASP flO\;SU(oIlMAR't ===f!flILL1DNJ====6449 6616 6708 !760'6815 fge4 6984 14480224.13 lOj~:H 20.61 19.~8 11.89 16 .~!1·69 g:8891)4 .63 llC4.40 lISt.1 1264.43 1352:~14 .•64232.79 223.78 227.64 .?21.89 226.22 224.96 221.19 e.oc I I -D 1':01.1 1513!15 1526.9 154C.4 15~5.2 1571.C 15a6.6 32114.1146.6 156.9 167.1)179.6 192.2 2C~.6 22C.C 21'e:~.S~---~~----------------------,--------------------~--------~------IJ5~.5 1356.1;1"5°.0 13~9~~11~1:~13~~:.~13~f:1 29 S48.'2 .•8 29.8 31.:;-~-....16.6'3.9 74.0 18.5 112.5 87.0 92.e 95.9 1037.1~n.3.5 e:5.9 '33t:.c;.e1S.1 791.6 765.a 731.4 21353.2 I '"-------------~-----------------~.--------------------------------438 ..9 45f.5 415.9 4'H.3 '52C.e 546.6 515.C e014.9 438.9 ~56.5 475.9 497.3 52C.8 546.6 57S.~e074.9C.O 0.0 C.O 0.0 c.e e.e o.26S1.3C.O 0.0 0.0 C.O e.e c.e o.C 10125.640.5 44.9 4C.l 45.4 49.1.3S.8 31 ..4 <;90.e I I--'-*'~--._-'-_._.__.--._---_._-_.....----_.__.._-_._--_._---_._---'--~.__._--_..--_._-.---'-479.4 ;01.4 1j1f,.0 5~2.7 57C.5 SeS.3 606.4 21f17.9 149.0 1~9.5 17C.6 U~2,,6 19~.4 2C9.C 22~.7 156C8.940.5 44.9 4C"4 45.4 4li ..1 3S·i 31.4 99C.C116.4 194cC 213.234.8 2SS ..3 284.:'12.5 3064.1(I.Q C.O 0.0 0.0 c.e c.e e.c c.e---------------- ------------------------------------------------113 ..4 103.0 91.q 79.9 61.1 53.5 30.3 2214.9C.O 0.0 0.0 C.O C..C c.e o.e O.C113.4 103.0 91.9 19.9 ~7 ..1 53.5 38.e 2214.C; ;'31.6 318.5 34C.8 364.6 39C.2 417.!(146.7 4-46.7/1'42.1 466.2 4il4 .0 505.5 529.1 541.2 543 .3 543.30.0 0.0 C.O 0.0 c.o c.e e.c c .•e141.63.1 14621.(;14793.2 14930.8 151 H.2 15385.2 15£:08,,<;1<:6C8.9===:========================================~=~================~15207.9 l'i412.3 1562".1.~tti851 ..0 1609E.O 1l:343.S 16598.9 HJSSS.9=================================~===:===:===========~:=--_.-.__._----"-'--'-.-2,".l e 7.3 2(;67.3 2687.3 26'37.3 2~l!7.3 2681.3 2681.3 26e7.33222.1 3575.6 3959.1 4311.1 4j83C.7 :323.8 5960.C 58cO,.,C73C;.S 104.7 J3l"•8 810.2 ql~.9 t:iSS.f qqa.c C;<;C ..Ca553.8 e364.7 8151.3 791f.5 76~f!.2 1314.1 lC61.f 1C~I.6e..o c.e O.c 0.0 C.O C.O O.C 3984.13-184.1 3-;84.1 398'••1 3904.1 3984.1 3984.1 3984.1 3984 ..11.25 1.25 1.25 1.25 1.25 1.25 1.25 0.00 .~... 'A,__;·:'-.·:'..~'·' ~~~ SHEET 4 OF 6 (l ~::::~.:::: $1.8 BILLION (1982 DOLLARS)STATE APPROPRIATION SCENARIO 7%INFLATION AND 10%INTEREST t!l~ ,",...--,'"_,,,.......,_"d;;:;;.:'.~ -----CAS»SO~RCE AND USE----CA5~IN'CHf FROM OPERSSTATECCNTR13UllQN LONG TERM DEIlT D~AWDr:Wf\SWORCAPoeBTDRAWJOWNS TOTAL SOU'lCES OF FUt'!)S .~:~b; 73 S:J=RGYGwH521REALPI(ICE--P'IlLS465INFLATIC~I~OEX '29 f-9.{IC(:-MI llS -----1 NC ar.,:;------------__ S16 ~EVENU[ 110 lESS PPERATING COSTS ;11 OPF~All~~IN~GM~~..'.".r_1 tACt)NTd~.:sfE&..~4ED n~FUN/;;, 55:l LESS INTEREST ON SHCP,T TER~OEBT 391 lESS INTEREST C~lONG TERM CEeT 141..,j!:TEi=AQ.NtNGS F~U~;)PcRS 54..3 i46 143 240 ';41 **********************:t ***".O)1(,*:~*¢***************~~::):)***;'c **:¢:)**¢f.:****(I **.;.******I)*******J),llu{):¢****:¢******t I)I:)*.*~'*~*lC<**'**:::1)**~*=(::).****'OAT412i<,0.12 \lIATAN.~eON '''.lNEI993J-H.8 BNlS198Z)SlATE FLNCS-It\FlATICt\n:-INTEREST lCl-CAFCCST !5.15 Bf-'23-JLt\-e3*******;*,*:;U::.(l***,**>;1**:::*~"****¥***************"':****:¢*******'~*t.l*>(l'>*********(1)*****~*******:(1 *'**I)~*:¢*****1lt***'***********'*'***~(I :¢*:¢**::: 32rJ LESS eAPIT~~L EXPENDITUPE 44J LESS WORCAP A~O FUN9SzeDLESSDEeTR(PAYMENT~ 393 Less PAY~eNT TO STATS 141 CASH SURoLUSIOEFICIT)l41 SHCRT TERM C~ET '.44 CASH ReC'JVER::D --~--DAl~l\Ir.ESH;-rT _ ZZS ~ESER9c h~f'CG~Y;'FUNO 371 nTHERWCRKI~G CAPIT.l~54 CASH SURPLUS RETAINED 170 C\J~.CAPITAL EXPEl\OITURE Ih',5 :AoIT,AL f:fI~l.QYED 461 5T~TECG~TRBL!TrON4~2 ~ETAI~CG :AR"JNGS "'i55 ~t:eTOUTST f.ND I NG-SHORT TERM 554 OEeTDUTSTANOIN~-LDNG TERM 542 ANNUAL O~BT DRAWWDCWN 11902 543 CUM.C.aeT ::>RA~WOOWN H982519JEDTSERVICE(eVER !£L!5'~4 rII ~-~--...;I. (I ~~ic#ll ...... ~;g -- ......:,.;;~:"~,:;..' ..m .~i~..l~...ill~''~,---~,~... \ ....:-yc.:::,;:_~~.~•;:;::"::"::~ f ',-••~I~ .--,"...\'0 1 to...·.04"'.-.~".~o.~-~.~~.'~.;...r~..tit'.",~.,~.::.,..,.,•'.'-~.(.,'11 1 . NO-r:E:FOR ANNUAL ENERGY SOLD,SEE LINE 73 OF SHEETS 1-3 OF THIS TABLE ..~"~::,',~::;,dra-e,+:,;---u::.':' C) .. Y:~",~«-i-t ANNUAL ENERG'Y COST "!$1.8 BILLION STATE APPROPRIATION SCENARIOI !7%INFLA TION AND 10%INTEREST ,<I ...SHEE~.5 OF 6 .._TABLE D.32 ,tJ:o i ). I .......,.........""""__ • •..,,__.."~..••.•...···.'-7 .~~~~~_..'T""--c;.0 ...•...•••i'~~.;!i[;:~/Jit?<':f';~?};;~~lft;;-~{~,"""..,"'-""""~~,__._=£. (y ~~.....r M .... ~-,..--.~".1~',....~...':,..')~,,~."-......""'.~:._.;P....-_~~_,,,.~'_~"~...... .. -.'~-"~.",'"'''''''' ... ."....',.<--.-.,;;:..../.".... NOTE:FOR ANN UA l EN ERG Y SOL D.S EEL IN E 7 3 C F SHE E T 1-3 OF TH IS T AS LE ~.~1IIl!!!IIIt ""'•.-:•.--:;-j.,.-<"'..:,;..'::::::,~;:;.J :'~,,:~'Jz'':_~:;:''',,1 ~..... :,t"__:~>,,,-,,,,,~..?~.;<~:.:"',.'_.:.:';;,__.:.._,.if '" ANN'UAL ENERGY COST j $1.8 BILLION STATE APPROPRIATION SCENARIOI7%INFLATION AND 10%INTEREST!''1<1:SHEI:T 6 OF 6 .'T_A~lE ~2 -' c L":"=,~c;;,:"."1 ,,'~'»..":,:~~'¢,*';\.~.;~iJi/"J.J...~,,:fi'!!""".'.M""~.n"_____~ «.~D '. ANNUAL PROJECT COSTSiMillslkWh Cost in Real $1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 Operating Expenses 4 4 4 4 4 4 4 4 4 4CapitalRenewals04444444':I 2..,Debt Service Cost 51 57 52 48 45 42 39 36 34 56 Total 55 65 60 56 53 48 47 44 41 62 ~0 I 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012-------Operating Expenses I}4 4 4 3 3 3 3 3 3f'lltl Capit~lRenewals 3 3 3 3 3 3 3 3 3 3 I j-J Debt Service Cost 53 48 44 40 36 32 30 27 24 22 ITotal60555147423836333128 2013 2014 2015 2016 2017 2018 2019 2020 2021 I----Operating Expensds 3 3 3 3 2 2 2 2 2CapitalRenewal!.3 2 2 2 2 2 2 2 2DebtServiceCost2018171~14 13 12 11 10 Total 26 23 22 20 18 17 16 15 14 M.g.,~-"-"".--~-.±~;t ,--,.of Wi I''''-..-,..'.~.:-.iiI;-~'-"""U L_.~ I I J l ..(::cI, { ( I tIllI ! I I til C C _,JIll III .. •e ••Sf ... I ~ I "I "•~ lilt•e ....--_... (St:lV'110a .:10 SNQl1ll~)MOl='HSVO 3Al1V1nVinO III ~ :~. 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C'I.. ~ •.. ~ ..... ~ III ~ ~ ll'I lI'I ~ ., lI'I !! fit CIl wtfII: 4.., N ~ CIl ~ .- ~ 0.. ~..•! •ID ! ...•~ Ie•~ on Cl 2: ••! o • oon t 8• '0o 2 o52g.... ,.......L g,0 6 0 0..0 ~'"IN ooo fit oo..ocl\lit \ \ oo• 8o.. (S 8 V 110 a..::J 0 SN 01111 LAJ)M01.::J HSVO lVnNNV (S8\'1100 ;fO SNOllliW) MOld HSVO 3AllVl0wno oll'I• 8on.. oo~ j\ \, I I I oo 1ft til o.....oo• I I t----t---+----1!----+------!----f.----+-:---.......- otn'" I I ! I g ll'I• I I I J Ii '\\ 1";.' ----,~----.--------------I-'-----...-~-.~-,,----,.'-'--.--------......'.--~'1...~'-----"-i~-....""~'~'-'-~......-"--,\---.,,-~. II'I'.'.'\'1"~''1!,i,' I I' I I I' I I. II I', ."., I.'·.·.··i' , I, I; I~ 20102005 ENERGY DELIVERIES FROM SUSISTNA YEARS ..",. 2000199319~5 "~---'''''~~ .[.L.\•..'-......'.."..,:-.~" •',1. 't.··~~"..", ;".' ~,"'.:' ,,/ ~'If I..:::;.,' '. '.,.,....•..••.•',..'....•..,..•.~,....•..-:,_..~.;:~'..'.,,';J~~' ".~., j'"""., ..,.c·." '~ 1 ..i ENERGYOEMANP AND DELIVERIEtS FROM SUSITNA Ff' FfGU~E t>.4 \ --,,'--"':;.-..:d.-..•.J.•.•.. 1\•.••...•.':'• \\,.,...".' h ~-, ......-WATANA ALONE ............-..............WATANA AND DEVIL CANYON-----4--t 'THERMAL AND OTHER HYDRO GENERATION '--~----4i----~--f------~_.-.-...._...,......4----_f;--~---""" 2016 2020 6 000 +-------l-------+---------l-- 8000 +----~k__----+_------_t_----_l_------_l_------~ 5000 -I---------.o1I-----11r- 3000 I·~::.-~Jd:::::::1=J-,-_l------_!-__-----l---_J 7 a0 a +-----l--'------+_- '9 aaa ~-----...--------.....-------~-----.---~-------r._------, 1 oc,·'+-~I-----+----------+---+-----+----------+--------_+----__! <4000 +--~---.:lk---~-~+_~_t_--_I__---------_+_------_+_------ 2,000 >- <:) a:wzw 1:1 IJ. I I~ I' I'·".," I' ,1 I; I' I' I: I; I'] It 11 I·~ .\ 1'1 ".."::,'\ !•.i I.'·.·".·""':i i "l ] .>"" /21' 20202015201020052000 I ~J---,.--....--INCREASING THERMAL ";.."....- FUEL COSTS AVOIDED /'~ / / t.,/ AVOIDS COSTS OF FURTHER -.4 ,..,/ 200 MW COA~"'FIRED UNI:X / 7~.---../,..--- ./~-'" ~_._.--/ _"",...-tI ~~--,.- /'AVO!DS COST OF 200 DEV~L C.l\NYON ON STREAM IN 2002 I~-~....MW COALjFIRED UNIT .....v ,.- WATANA ON /7 STREAM IN 1993- , I ,I94 SYSTEM THERMAL COSTS .AVOIDED BY DEVELOPING SUSITNA COMPARED WITH~EST THERMAL OPTION IN MILLS PEA UNIT OF SUSITNA OUTPUT IN CURRENT DOLLARS SOO 1"'"'\.s:: 7003: oX....... (I) -J 600...J-::...., en 500UJ 0 I -I a: I 0.. 400f0.•z« C/)300 I-en 0 0 200 >-,.. ..,.Ja: UJ 100Z W 0 YEARS .-::. FIGURE D.5 {) SUSITNA f I·E:;',---..,.......'..,:~' '1,_, -,~':'Cia ""pS7 ~J !~) ;j cr' ...,...~.......--~-~--.-~,..---~.-,"o ~-;. ()I .! t f .SYSTEM THERMAL COSTS AVOIDED BY DEVELOPING ,I .It~~~...~~.."-~...."~...-t--"--".~. OBJECTIVE ECONOMICS ENGI NEERING LAYOl/TS AND COST STUDIES G) >, ~~1118;.•-,PJ. CRITERIA-fCONOM1CS DATA 0"OIFFERENT THERMAL GENERATING SOURCES _,.!I~ COMPUTER MODELS TO EVALUATE •POWER AND ENERGY YIELDS ..SYSTEM W:~E ECONOMICS ~.'11III,:~~.:~'.~".,.;;".".:-',-," SCREEN CRITERIA ECONOMICS £NVIRQNMENTAL t!IIIIl ... .,._....._,~_..C"\.'" ,~__I~ PREVIOUS STUDIES i~S:;r-. 5,T£ S'~LECTiON ~,~h",".,~,,_._....."~ r ~}sPj\fl1'WFiB."'!1ltTjft;;tt ~·",,~·'t':.:ot"""-·"""'\oi':t~,.:::,"l I II 4 ITERATIONS J SNOW (S) 8RUSKASNA (B I KEETNA (K) CACHE (CA) BROWNE (BR) TALKEETNA -2 (T-2) HICKS (H) CHAKACHAMNA,CH) ALLISON CREEK (AC) STRANDLINE LAKE (SL) ..CHi I( -CH.K ,5 •CH.K.S.SL.AC •CH.K,S,SL.AC -CH.K,S,SL,AC,CA.T-Z CH1K,S &THERMAL LEGEND ......~~STEP NUMBER IN STANDARD PROCESS (APPENDIX AI G FORMULATION OF PLANS INCORPORATING NON-SUSITNA HYDRO GENRATI,ON FIGURE D.6 (~) .....1 .o ...:?•••\•f ,~,".,.".,...:...,-- ~..'.,'.. .-I).A •f .-.-f ;...~•• ...:...e_.,_~..'•..•-.;..-,_..-':"":"-,~__~......_..-,-~......~..".....>-..._..,....-'-...-'~_.-.".~_....--- ECONOMICS ENVIRONMENTAL [ 1L•. .~-* ~f.::~'t~~~.....~ DAtA ON DIFFERENT THERMAL GENEftATING SOURCES :mt..p!r CRITERIA ECONOMICS •POWER AND ENERG Y YIELDS •SYSTEM WIDE ECONOMICS - COMPUTER MODELS TO F.VAlUI'TE .~a:SM'I\!!!!I OBJECTIVE ECONOMICS ENGINEERING LAYOUTS AND COST STUDIES ,:---li .~'M; SCREE~ CRITERIA ~@~.~ PREVfOUS STUDIES lWil ..."'.....,."';c"",~""",,_~:__,,;;;__."" 1..·-..a..~ "","","::,&~i""""ili-- SITE SELECTION 1--~"..~-_.r-.~~ ~iL~4-'--~"(.:row j ",.'tifiilitf I If 4 ITERATIONS FIGURE 0.6 FORtv1UlATION OF PlANSINCOAPOHATING NON"'SUSITNA HYDRO GENRATION SNOW (S) BRUSKASNA (B) KEETNA (K) CACHE (CA) BROWNE (SR) TALKEETNA •2 (T-2) HICKS (H) CHAKACHAMNA(C H ) ALLISON CREEl<(AC) STRANDLINELAKE (SL J •CHi K •CH,K ,S •CH,K,S,SL,AC •CH.K ,5 •SL,AC -CH .I<,S,SL.AC.CA,T-Z CH,K,S a THERMAL LEGEND ---~STEP NUMB~R IN STANDARD PROCESS (APPEfmIX A) v ~....III .?...,.. I.~ TO<IOi.fHA Yt:....T. CATHl:Dl'AL ILI#F. ~ ~ JllHCTo.II VAtttON IS TAlllNA k(NAI L..MC Ctt:lltAC........ o SCAlE""H.ES I lfQt EQUAlS APf"'OlllMATW'~llIllLlS >'00·"- ,~. Q(). 4'. 42.4'. ~. ~. ~. 41. 41..... SHOW I<£~o\!UlMft ~l'I'3Tlt r~'I• fl'lUIlilQIIA 0 ..1'....It. ~"I(UJGA Ct)fnC eYl.IC.utA ft. !CLoUT_ .....tTL..! ...c1l\·S lITE LOWl RAILBELi" WI1ISlllt~ CO~ CHVI.I~'" 0010 ~~~ tllCMI: G"ltNlTCM: TAl,lt[U",-l ~_TI:IOIttI: 'CUT... IHUP CltfCIC ItCwtllt1'"' !llLotlCHOLtTIWl ".14. 15. 13.I.,.1'. It. ZO. II.n. U.,.., ~'. ..... O·2~... STrIA~Dl.IN(L. ,-0*[1'1 I£&.UG& ..eWEI'LA~Clil. "l.LISON (ft. C"tSClJITLM(2 G'NlNT L~f IIIIcCUJ'I(lAY lJfI'IIIt"..u.l.lt Jua", PO!'1("C"IE fl S1LYI"UC( SCIl..C*C*~CM TUlTW€. SELECTED ALTERNATIVE HYDROELECTRIC SITES FIGURE D.7 I. 2.,....,. ••'.I. t. 10. II. 12. I I~••,,,..SO·,.....,-144·1..:- I \ \@ t",oOl ! ..8 __+-_ 1-_........................------------_______f --.....-....,:.:.-....-..-"----------------..........---...-...----."...,...".."..,....------------••.-•••-,.~,...•.•••_.=]""'.••••.t..-~ (~~1. I) I'j iii ..J II I .I-~·'..\~, I-~ "v' I 1....\'.' ....1 I 1-·"'."l .~t I:t I ',.~.' ~t //'.'.I.•~ ..,"\',~ L ~ ----l ~,JIll....:1I'!I!lfI!)'.II6M:.-"", [VALUATION ~ COMPUTER MODELS TO EVALUATE SYSTEM wIDe ECONOMICS .,.,.:~ ~;.~-.,•..~__-<~,;o.....;~....o.~,,_;"";_.~"-'-~'-_..~..,,,,,..,,........,.~....,..---,.;-., ~..:.~~,,_~;,,";7::;" PLAN FORMULATION ',~,ml~ PREVIOUS STUDIES ON!T TYPE SELECTION ...~...~..",,,,,'~-#J ';i,..,.~~;~....<;;--...::-;.;;:.;,;.;;~,--,~'!'",j~':';;'J "'."",..;'"="-,;;,,<,.,,.J I ,II ,.".,-.._.~..-....k".;_,~.,~.._....~~.._-"_--",;"",;...~,,,,~.,...................._ ~,nlW "-T-l?slf~.·AI;_- FIGURE D.8 FORMULATiON OF PLANS INCORPORAT;~4G AL~-THERMAL GENERATION STEP NUMBER IN STANDARD PROCESS (APPENDIX A) .~ LEGEND NO GAS RENEWALS ECONOMIC OBJECTIVE GAS RENEWALS NO GAS RENEWALS ECONOMIC OBJECTIVE a COAL:100 ttWI 250MW 500 MW COMBINED CYCLE-2S0 MW GAS TURBINE r 15 MW DIESEL:10 MW ."'"..;-#•~~...,.•.~. 2020 2020 1143 -'--1 1000h....... FIGURE 0.9 2010 . 2010 956 J.,L...-'-~-------- 8131.-..~ iiiiiiiii!i!ii t 9 5 5 .;;;;;;;;;:;;;-------V 1949 2000 YEAR 2000 YEAR 1990 EXtSTING &COMMtTTEO TOTAL DISPATCHED ENERGY ALTeRNATIVE.GENERATION SCENARIO REFERENCE CASE LOAD FORECAST w. COAL F'RED THERMAL GAS FIRED THERMAL OtL FIAED THERMAL (NOT SHOWNOi'.J ENERGYDIAGRi'l:M) 1980 ~• o 4-----......----+-------.....------t~---~I__--~--._----I__---...... 1980 1990 LEGENDoHYDROELECTRIC 6 J: 3: 0 0 0 0 4..- 1 >- (!) a:wz L!.I 2 o 3 3: ::i 0 2 o o.... ~ >- l--o <a.1< Q I: I; I, I I I It Ii I Ii I I u ~t \.••I 0-,•.,.,...~'{ a ~;;"'.,.i "rttf$t¥i¥J!¢'\tl ;:Wiil~L MgHM~~~~~~~Ll~;~~.iM~~~L:~.~ 800 I I ••__d _U.I (j '" 300 700,l-·------+1------tl--- I ~---t 7 4':"'-"'- ",'"'"I, / " 1 00"DEBT FINAN'ctNG MilL RATE COST BEST 800 -I I t-tHERMAL OPTION1"INFLATION, 10f&'NTEREST T I I I 500 ;(I I I 100.DEBTFINANGINQ..,l I $1.8 Bllll0N STATE CONTR IBUTtON SUSITNA MILL RATE COST'SUSITNA MILL RATE C05T 4001 WITH 1"INFLATION.".WITH 1%INFLATION.-·-------tl 10"IN T ERE 5 T 1 0"IN T ERE S T "~-'--"~,........."';~I~=~~~~~~~~~~~~~~~~~~~~=iliA ,n , • , ,t ' • • • •e'. .•:'7 •..~-••••••••••••••2•••i.'.'.'.'.',..•,.........•.•....',-tfi~·Ft:4JfioNAR·~/Fn~A·~I·~N·G···'D·EFicl~~~~~~~tf~~~~~~'--- - . .:.:..••.;.:..•.•••..•.~:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:':';':'::::.":':':':':':':~':':':':':':':':':':"~'~::;.I •-------......._::::::::::::::::::::::::::::::::::::;:::::::::::::::::::::::::::::.:.:.:.~.~.~---_.......-.......----:.:.:.:.:.::::.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:~.......~.,---....- ------.:..:.:.:.:..•....•..........•.••••..:.:;:,.:.:200 :.:.:.:.:.:.:.:.:.:.:.:.:.....~M L A I BEST THERMAL OPTION·' 0%INFl,A,TlON.3%INTEREST 100 NEGLIGIS E FINANCING DEFICIT ITH ZERO INFLATION ~•_._.~ -~_.-._---_..--.....__.. I SUSITNA COST ITH 0%INFLATION.3 INTEREST;17 .'....... .c 3: .¥ ""-en -'-'-~..... Cfl UJo-a::a. o 2:< CJ).... CIJoo >- "a:wzw ~ I f I 202020152010 YEARS 20052000 0-"'-I I I I I 94 FIGURE 0.10L.ENERGY COST COMPARISON ..Q AND 7%INFLATION ..~.tf _.. ,"..~oJ ,.\..... •'l'';. 1 1 '. SUSITNA HYDROELECTRIC PROJECT VOLUME 1 EXHIBIT D,APPENDIX D-1 FUELS PRICING STUDIES I 1 I I I' I I - I····,'..·"j ~ 11 IJ IJ m I SUSITNA HYDROELECTIC PROJECT VOLUME 1 EXHIBIT 0,APPENDIX D-l FUELS PRICING STUDIES TABLE OF CONTENTS 1 -Natural as 1.1 Re5vurces and Reserves a)Cook Inlet Proven Reserves b)Cook Inlet Undiscovered Gas c)North Slope Gas d)Gulf of Alaska Gas 1.2 Production and Use a)Cook Inlet Current Production and Use b)Cook Inlet Future Use c)Competition For Cook Inlet Gas d)North Slope Gas e)Gul f of Al aska Gas 1.3 Current Prices a)Cook Inlet b)North Slope 1.4 ~Projected Gas Prices 1.5 Effect of Gas Price Deregulation a)Existing Law b)Proposed Changes to the NGPA c)Deregulated Cook Inlet Glas Prices 1.6 References and Notes 2 -Coal 2.1 Resources and Reserves 2.2 Present and Potential Alaskan Coal Production 2.3 Current Al askan Coal Prices a)Nenana Field b)Beluga Field 2.4 Coal Price Escalation 2.5 References and Bibliography 3 -Distillate Oil 3.1 Availabilit~' 3.2 Price 1 I "•..,,*1 - Appendix D-1 LIST OF TABLES 0-1.1 Preliminary Estimates of Undiscovered Gas Resources in Place and Economically Recoverable Gas Resources For the COQK Inlet Basin •. 11_..".,-o Proximate and Ultimate Analysis of Nenana Field Coal Ultimate Analysis of Beluga Coal Coal Field Capacity in Alaska Projected National Share of Japanese Coal Market For~Imports in the Year 1990. Tre Val ue of Coal Del ivered ;n Japan By Coal Ori gin The Market Val ue of Coal From the Bel uga Field FOB Granite PointAl aska Reserves and Resources of the Nenana Field 0-2.7 0-2.8 0-2.2 0-2.3 0-2.4 D-2.5 D-2.6 0-1.2 Historical and Current Production and Use of Cook Inlet Natural Gas 0-1.3 Estimated Use of Cook Inlet Natural Gas by User 0-1.4 CUrreri!Production and Use of North Slope Gas For 1982 0-1.5 Estimated Base Prices For New Purchases of Uncommitted and Undiscovered Cook Inlet Gas -Without LNG Export Opportunities 0..1.6 Estimated 1983 Base Prices For New Purchases of Uncommitted and Undiscovered Cook In1 et Gas -With LNG Export Opportunities 0-1.7 Estimated Cost of North Slope Natural Gas For Electric Generation at Kenai Assuming Implementation of the Trans Alaska Gas System (TAGS) 0-1.8 Estimated 1983 Del ivered Cost of North Slope Natural Gas For Railbelt Electrical Generation 0..1:9 Proj ected Cook In 1et We 11 head Natur alGas Pri ces 0-1.10 Projected North Slope Delivered Natural Gas Prices 0-2.1 Demonstrated Reserve Base in Alaska and the U.S.by Type of Coal I I-" 1',\,111 I I f I I I " I I E I 1* ij,. b o 01-1 1.1 Resources and Reserves Known recoverable reserves of natural "gas are located in the Cook Inlet area near Anchorage and on Alaska'S North Slope at Prudhoe Bay. Gas is presently being produced from the Cook Inlet area.Some of the gas is committed under firm contract but considerable quantities ofgt\S remain uncommitted and could be us~d for power generation.There are SUbstantial recoverable reserves on the North Slope that could be used for power generation,but until a pipeline or electrical transmission line is constructed,the gas cannot be utilized.Undiscovered gas resources are bel ;eved to exist in the Cook Inlet area and al so in the Gulf of Al aska where no gas has been found to date.Estimates of potenti al gas resources in these areas.have been made by the United States Geological Survey and the Alaska Department of Natural Resources.The quantities of proven,potent i al and undi scovered gas from these areas are discussed below. Introduction APPENDIX 0-1 FUELS PRICING STUDIES 1.Natural Gas There are thermal alternatives ,to the Susitna Hydroelectric Project fueled by natural gas or coal..The economic viability of ,these alternatives and their competiveness with the Su.sitna Project depend heavily on the future availability and price of the required fuels. The avai 1 abi 1 ity and price of fuel s to meet Railbel t generation needs through the year 2040 are analyzed in this Appendix.The primary fuels that are analyzed.are natur~al gas,coal,and distillate fuel oil. There are ether potential fuels such as peat and wood,but these are not dis,cussed due to the findings of previous stt1dies that these fuel s are not economically competitive when compared to natural gas and cu~l. Multiple data sources were employed including previous studies by consultants,information from state and federal agencies,and data, plans and other -information from electric and gas-utilities in the Railbelt Region of Alaska.Projections of future natural gas and distillate fuel prices are ti~d to the future world price of oil. Projections of future world oil prices are presented in Exhibit B, Section 5.4 of the Application. Results concerning the availability and price of natural gas,coal and distillate oils ire used as inputs into the Optimum Generation Planning Model (OGP)in the determination of the cost of thermal generating alternatives. 11 -I; 8.,.i1I,'t I·.·••~" ( I r r I···.,:..:.··I, ~;'i I...r .,.'....ri ;, .I...~,.l..',! I I.,j I·..·.'.'.,'t, 1'·.\·\) .,..J 'iii,*,*,r ..··.f.'lit Dl-2 *References for the Natural Gas section are given on p.Dl-23. New ):Antracts between Enstar and Shell &Marathon are shownl"j in Figure D-1.2 as well as the five-year extension of the Phillips/Marq~bon LNG contract with Tokyo Gas and Tokyo Electric Companies.l )Reserves that were formerly committed to Pacific Alaska Liquified Natural Gas (PALNG)Company are shown for reference purposes,but are inc 1uded rs uncommitted reserves, since PALNG's contracts for the gas ex.piredin 1980.This is discussed further under Section 1.2(c).Much of the proven gas is not at present under contract.Figure D-l.2 shows that 1,654 billion cubic feet (BCF)of proven reserves is uncommitted. In addition to proven recoverable reserves in the Cook Inlet area, there is the possibility of additional supplies in the form of undiscovered gas. (b)Cook Inlet Undiscovered Gas Earl ierestimates of additional natural gas resources in the Cook(5~let area ranged from 6.7 trillion cubic feet (TCF)to 29.2 rCF..These estimates may be high si nee subsequent drilling.by Mobil and Areo in Lower Cook Inlec:has not resulte.d in producing wells. A recent study by the Department of Natural Resources of the State of Al aska presents estimates of und;scovered gas and (%1.1 and assigns probabilitie~l to finding those quantiti~s.)The mean or average quantity that is expected to be found is about 3.0 TCF.The estimate is presented in Table D-1.1. The Department al so estimated "economica11y recoverable"resources by assuming a recovery fnctor of 0.9 and a minimum eommerc;al deposit.size of 200 BCF.These are also presented in Table 0-1.1.With an estimate of undiscovered gas is about 2.0 TCF. (a)Cook Inlet Proven Reserves The locations of the Cook Inlet gas fields are shown in Figure D-l.l.Estimated recoverable reserves from the Cook Inlet fi elds and the commitment status of those reserves are shown in Fi gure 1 )q..l.2.This table has been developed from an earlier studyl and,updated and rearranged to refl ect,current conditions.Recoverable reserves are froJl},)the Alaska Oil &Gas Conservation Commission's latest estimate.l~ o I! 11 I L \ I I i~,i ....•) I I I: Ii 11 IJ It I Ir i\ I·: \ IJ .••.• 1.'1.'.·.. ...\., I) •.,1~.; (\ f.····'·····, I I:; ..'~..' f II I 11 I~'" I' 1) 1\ t1l,iI~ I,!,,~'~,"\\ IJ -~, (c)North Sloye G~ Estimated recoverable natural gas reserves from the North Slope ar~about 29 rCF for the Sadlerochit Reservoir at·Prudhoe Bay. Addit~Qnal gas from the North Slope is estimated.to be 4.5 TeF.t}The State of Al aska royalty share of Prudhoe Bay reserves ;s 12.5%or 3.6 TCF.North Slope gas is ourrently either shut-in or reinjected into reservoirs to maintain pressure for oil extraction since there is no pipel ine to areas where the gas can be utilized for electrical generationt heating or other uses. (d)Gulf of Alaska Gas The Gulf of Alaska 11es to the east of the Kenai Peninsula and Anchorage and is close enough to the Rai 1bel t area to be considered as a potential source of gas for Railbelt electric generation (see Figure D-1.3).To date,no oil or gas has been discovered in the Gulf of Alaska.The United States Geological Survey (U.S.G.S.)has,however,developed estimates of the quantities of gas that might exist in the Gulf. The U~S.G~S~presents its estimates of undiscovered gas in terms of the probability of finding "economically recoverable'l gas. Economically recoverable resources are those that can be ecol1omically extracted under price ...cost relationships and technologic~~)trends prevailing at the time of the asse.ssment ~\For thei r lowest imate,there is a probability of 95%that'the estimated value will exceed.For the high,estimate,there is a 5%probability that the estimated value will exceed rGcovering the cost of those volumes.The U.S.G.S. analysis can also be interpv"eted as having a probability of 90% that the amount of undiscovered gas will be between the low and high estimates~In addition to low and high estimates,the U.S.G~S.alSO provides a mean value as the quantity of gas most 1i kel y to be found.'.The U~S~G~S.estj~~tes for the Gul f of Al aska Shelf (to a depth of 200 meters)are:~J Low 0.46 TCF High 9.24 TCF Mean 3..14 reF The estimate for the Gulf of Al aska Slope,i.e.those Gulf areas wi th a water depth from 200 meters to 2,400 meters,is: Low 0..36 TCF High 3~70 rCF Mean 1.53 rCF The long-term availability of Gulf of Alaska gas for electrical generation ;s at this time highly speculative~First,the gas (if 01 ...3 rI ~~-'-' o -f \ Natural gas is used for electrical generation by Chugach Electric Associ ation .and Anchorage Municipal Light and Power.The use of g as by both of these uti 1iti es has been increasing to meet increases in e1ectY~ica1 load and to replace.oil-fired generation. The m;litary bases in the Anchorage area,Elmendorf AFB and Fott Richardson,use gas to generate electricity and to provide steam for heating.The military gas use has been fair'ly constant in the past and is t::xpected to rem&ln so in the future. The gas utillty sales shown are made principally by Enstar and are for space and water heating,and other uses by residential, commerci al,and industri al customers in the Anchorage area.These sal es grow with increases in popul ation CL1d increased use by existing consumers.The growth is expected to continue in the future and will increase when Enstar begins gas service to the tvlatanuska Valley in 1986,. 01-4 fl Natural gas is produced and used in Alaska.for heating,electrical generations liquified natural gas (LNG)export and the manufacture of ammonia/urea.Most of the production and use (other than reinjection) currently takes place in the Cook Inlet area but the large proven qUantities located on the North Slope and undiscovered potential in the Gulf of A1 aska mak.;~these areas worthy of consideration for futlrre use. Current~.nd potential production from the three areas is discussed below. (a)Cook Inl~t Current Production and Use The production and use of Cook Ir:et gas for the past five years ;s shown in Table D-1.2.Ga.s that has been injected (or actually reinjected)was not consumed and is still available for heating 9 electrical generction s or other uses a The use of gas in field oper at ions is the gg§consumed at the well sand gatheri ng \\reas to assist in the lifting and production of oil anli gas.Use depends on the level of activity in oil and gas production vilich has been fairly constant over the last five years. .LNG sal es are for export to Japan and the manufactured ammonia/urea is exported to the lower forty eight states.These uses of gas have been fairly constant in the past and are expect~d to remai n so ;n future years. any)must be found and developed;second~a pipeline must be constructed to deliver the gas to where e.1ectric generation would take place and thiJ'd,the del ivered price would have to be competitive with alternative fuels.Therefore,at this time,gas from the Gulf cannot be depended upon to supply Railbelt generation needs. 1.2 Production and Use o·f Natural Gas ~'"~.,.".', I Ii.11: m (. I, I, I, I E) fA.: r '. ",,1.I: V 1\ I ,I,l~".',·,,'I If,'I' The item,Other Sales,shown in Table D-1.2 is a residual figure according to the Al aska Department of Natural Resources and is the difference between total sales as published by the Oil and Gas Commission and tht'sum of gas obtained from the utilities, Phillips/Marathon,Collier Chemical and other large users. (b)Cook Inlet Future Use The yutute consumpt'~on of Cook In1 et gas depends on the gas needs of the major users and their ability to contract for needed supplies.Since there is a limited quantity of proven gas and estimates of undiscovered reserves in the Cook Inlet area have yet to be proven,gas reserves will be exhausted [j the late 1990·s. In addition,there may not be sufficient gas for electrical generation beyond some point because of higher priorities accorded other uses,ei ther through contr act Dr by order of reg ul atory agencies such as the Alaska Public Utilities Comission.To estimate the quantity of Cook Inlet gas available for electrical generation,the reqUirements and priorities of the major users are discussed below. Phi 11 ips/Marathon LNG tJrrently have 360 BCF of gas under contract and Collier Chemical has 377 BCf (Figure 0-1.2).It is highly probable that both entities will obtain enough of the uncommitted gas in Fi gure 0-1.2 to meet th2ir needs through 2010.The reason is that both Phillips/Marathon .LNG and Collier are established, economicalTy viable facilities.They are also owned by Cook Inlet gas producers who control part of the uncomr;lited reserves .. Phi 11 ips/Marathon LNG and Coll ;er are therefo're estimated to .consume 62 BCF and 55 BCF respectively per year from 1982 through 2010. At present,Enstar has enough gas under contract to serve its reta;1 customers unti 1 after the year 2000~but si nce .Enstar al so sells gas to the military,Chugach Electric Association,and Anchorage Municipal Light and Power for electric generatiop"it may have to seek additional reserves in order to iileet the needs of thOSE 1 arger customers.It is assumed,however,that Enstar wi 11 be able to acquire sufficient gas to meet the needs of its retail customers (including new Matanuska Valley customers).Further,it is reasonabl e to assume th~t those customers'needs wi 11 have priority over the use of gas for electr'icalgeneration.Retail use is est imated to increase from about 18 BCF in 1982 to 52 BCF in :~010.This estimataincorporates an annual growth rate in sales of 3.5%from 1982 to 1998 plus additional sales of 1.5 BCF/year.beginning in 1986 (and growing at 3.5%annually)to customers in the Matanuska Valley.Sales from 1999 to 2010 were obtained by extrapolating total sales at the 1982-1998 growth rate of 3.5%per year.The effective growth rate for total sales from 1982-1998 is 4.5%.The Enstar estimate is reasonably close 01-5 o J -J•:J •, • I' I t., lI~ f o c D1-6 After satisfy"ng all nf the forewent i oned need s,there is st ill a considera,ble amount -Jf gas remaining that could be used for' electrical generat'ion,at least for a number Df years.Chugach El ectric Associ ation has 285 BCF committed through contract (see Figure D-1.2)and Enstar has 759 BCF contracted,some of Ii,nich will be sold to Anchorage Municipal Power and Light and Chugach Electrical Association for electrical generation.Assuming that the Anchorage/Fairbanks intertie is comp.leted in 1984-55,the electrical requirements of both cities could be met (at least in part)with generation using Cook Inl et gas. An estimate of the quantities of Cook Inlet gas that would be required to meet all Railbelt ele~trical requirements was made using the estimated load and energy forecast (Reference Case)for the Railbelt area.Estimated gerteration from the existing Eklutna and Cooper Lake hydro units,and the proposed Bradley Lake hydro units,was sUbtracted,as well as generation frDrn the existing Healy coal-fired unit.Average heat rates for the gas·"fired units (principally simple-cycle combustion turbines)were assumed to be 15 9 000 Btu/KWh unti 1 1995 when the heat rate woul d .decrease to 8500 Btu/kWh to reflect the ins.tallation of high efficiency~ combilJed cycle units. The estimated annual gas requirements for power generation increase from 35 BCF in 1983 to 54 BCF in 2010.The quantity of gas used for electrical generations would,of courses vary with the load and energy use forecast that was assumedc The quantities calculated for electrical generation incorporate electrical energy use from the Reference Case fcrecast (see Exhibit B,Section 5.4). If the forecast for the OOR Mean case were assumed,the Cook Inlet proven reserves would provide for generation for a longer period whi 1e if the forecast for the SHCA Basecase was assumed,proven reserves would last for a shorter period. The forecast annual and cumul ative use of gas for each of the major users,and the total use of gas for the Railbelt,is shown in Table 0-1.3.The remaining proven and undiscovered (mean or expected quanti ty)gas resources are al so shown and as can be seen,proven reserves will be exhausted by about 1998,and expected undiscovered resources by about 2007.The estimated use of Cook In1 et proven reserves and undiscover'ed resources is graphicallY illustrated in Figure 0-1.4. to a State of AJaska estimate which provides for a growth rate of 4.7%per year.tl ) Gas used in field operations and the residual,"Other Sales"vary from year to year but together are est-jmated to average about 25 BCF /yr.over the peri od 1982 to 2010 based on hi storical use as shown in Table D-1.3. I I?:J~: I~ r f f II fi E I Ii ( II! 01-7 . The FERC has appt~oved the PALNG project,but with the condition that PALNG obtain 1.6 TCF of r~zfves for Phas.e I of the project and .2.6 TCF for Phase II.tJ.Pacific Gas and Electric Company,one of the PALNG partuers,does not .01 an to invest any more funds in the project and hasfi led with the Cal iferni a PUblic Utilities Commission (CPUC)for permission to place the expended funds into its upl ant Held for Future Use"account 0 PALNGa 1so cl aims it requ;resadditional ~quity partners to make the project viable,but,to date,has found none.Although PALNG is stil' searching for additional gas reserves,there is little chance that the project would begin construction prior to theerly 1990's. Known potential purchasers for the uncommitted.,recoverable and undiscovered Cook Inlet gas reserves,in addition to those shown in Table 0-1.3,are Pac i fi c Al aska LNG Associ ates and whoever waul d own and oper ate the proposed Trans-Alaska Gas System (TAGS). The'proposed Pacific Al aska LNG (PALNG)project was initi ated about ten years ago,but has been repeatedly delayed due to difficulties in obtaining final regul atory approval for a terminal in Califer'nia.The project has also had diffiCUlty in contracting for sufficient gas reserves in order to obtain Federal Energy Regulatory Commission (FERC)approval of the proj.ect.At one time,PALNG had 980 BCF of recoverable reserves under contract. The contracts expired in 1980,but producers did not give written notice of termination so the contracts have been ;n limbo. Recent 1y,however ,Shell Oi 1 Company sold 220 HeF of gas that was formerly committed to PALNG to Enstar Natural Gas Company.Thi s reduced reserves committed to the PALNG proj.ect to 760 BCF (see Figure D-1.2).. The data from Table 0-1.3 indicates that relying on all gas-fired electrical generation to provide the Railbelt's needs past the year 2000 is ri sky because it depends on the future av ai labi 1i ty of undiscovered reserves for electrical generati.on. Other developments could J1so reduce or eliminate the availability of proven natural gas reserves for use in el ectrical generation. ·For example,there is the view that using natural gas for electric generation does not constitute the best use for the gas and that the 9f I1J hould be conserved and used for space heating and process heat. The uncommitted 1I proven reser'ves and any undiscovered resources could be acquired by entities not shown in Table 0-1.3,reducing or eliminating the availability of Cook Inlet gas for electric generation.This possibility is discussed next. (c)Competition for Cook Inlet Gas o ~J 11 I...'.'·'·,~. ~i O! ~t) .,j" I , Ii ,,.·..·••f.I. ~.'.'~Ih I·,'"···.it i! J,l LJ I Implf.mentation of the project would depend primarily on the availability and price of alternative sources of natural gas for the lower forty eight market and particularly for the ehl iforni a market..Accordinq to one eX,pert,Thomas J.Joyce,"~here are sufficient proven and probabl~reserves of conventional gas in(t~e lower forty ei ght states to 1ast fi fteen to twenty years..) When all of these factors are consi dered,it does not aJ'!~'ear that the PJ\LNG project will be implemented prior to 1995.The recoverable reserves originally committed to PALNG can,therefore, probably be at.quired by other purchasers such as Chugach Electric Associ ationand Enstar .. 01-8 The proposed TAGS project would build a natural gas transmission line from Prudhoe Bay on the North 51 ope to the Kenai Peninsula (near Nikishka).The gas from the Nor~h Slope would bi41iquefied and sol d to Japan and otner Asi an countri es.{)The proposed project is an alternative method of bringing North S10pe gas to market.If implemented it woul d e1 imi n ate the need for the Alaska Natural Gas Transportation System (ANGTS)which would pipe the gas across Al aska,through Canada and to market in the lower forty eight states 3 If the project were implemented,Cook Inlet gas producers might be able to sell their gas to Trans Alaska Gas System for liquefaction and sale to Asia.Sale will depend on the capacity of the 1 iquefaction plant and the market for LNG.The price paid by TAGS to Cook Inlet producers might be i'sigh e'nough to outbid competing purchasers,since the Cook Inlet gas would not be burde.ned with the costs of the transmission line from Prudhoe Bay (although .shorter tr ansm;ssi on and gathering 1i nes woul d probab 1y be requirE::d).Any estimate of the probability of whether TAGS will be implemented is difficult at this time,since the report on the proj ect has j ust b~en pub 1i shed,and there has not been suffi ci ent time for the proposal to be analyzed by many concerned and interested parties.Howeve(~~an estimate of the maximum price that TAGS would probably be wi'1iog to pay Cook Inl et producers for gas delivered to the TAGSliquifacation plant has been made. (See a follow;ngsect i on entitled,Current Prices).. North Slope G~ Over ni nety percent of the North Slope gas is current 1y reinjected.Some is used in field operations,by Trans Alaska Pipeline System,by Prudhoe Bay refineries,and fot North Slope 1Dcal el ectr'i cal generation.A small quant i ty from the South Barrow field is also used to meet residential heating needs. Table 0-1.4 shows North Slope production and use for 1982.The problem in using North Slope gas.for Railbelt electrical generation is that a pi pel ine must be constructed to bring the gas (d) ~f) 1",1,',.,,} "'!" 11",1,.,',.'" t f j 1',1,1\t.\ ,I'-,I"J",," ~'1 j ;{ ,.,. ',' --o C>:;.. 01-.9 to where it is needed,i.e.Fairbanks or Anchorage. Alternatively,an electrical transmission line must be built so that power generated on the North 51 ope can be brought to load centers.The major proposals for utilization of.North Slope gas are discussed below. Al aska Natural Gas Trans ortation S stem (ANGTS):In thi s pl an a Pl pe ,ne wou e constructed rom the North ope v'la Fairbanks and through Canada to the lower forty eight states.The project has been tempora....;ly shel ved due to a high est imated del ivered price and the resulting difficulty in obtaining financing.The project will probably not be operational before the early to mid-1990s,so it is uncertain when North Slope gas can be transported to the Railbelt for electrical generation by this system. Trans Alaska Gas System JTAGS):This alternative was recently proposed by the Governor's Economic Committee on North Slope Natural Gas.A pipeline would be constructed from Prudhoe Bay to the Kenai Peninsula where the gas wfy)Jd be liquified and sold to Japan and other As ian countri es.~'.Some of the gas coul d be utilized for power generation at Kenai (or conceivably from a tap at Fairbanks although an additional processing plant would have to be installed since the gas is to be piped in an unpro- cessed state).Implementation of TAGS is highly uncertain at this time and therefore cannot be counted on to provide gas for future electric generation • Pipeline to Fairbanks:In this p'lan,the North Slope.gas would be .transported to Fairbanks via a small diameter pipeline where it would be used to generate electricity for the Railbelt Area and also to meet residential and commercial heating needs in Fairbanks.Cost estimates indicate that thi s method is economically inferior to other proposed methods for utilization of ~orth Slope16 )gas and will therefore probably not be lmplemented.~ North Slo~Generation:This proposed plan is an alternative to transportlngthe gas by Some means,for the gas would be utilized in combustion turbines located on the North Slope and the electricity transmitted to the Railbelt 1A(17~.The costs of this pl an are also bel ieved to be prohibitive.} (e)Gulf of Alaska Gas To date,there have been no discoveries of gas in the Gulf of Alaska.This potential source of gas for Railbelt electrical generation is theref.ore too specul ative at thi s time to incorporate its use into the future Railbelt generation a 1tern ati ves • I 1·.:\ \) IiII; I] I ([ E f 1'1; ~l ,'r-';. I (, E'j :~;> ",..,.,,... Ii ~,,: I~ ~; ~; IJ I] Ij· I f{ .':f' ;\ ' "\ 1" +1 f,\ 1-·'\,:::~;\, f: Ii" .{!;i: .,,_~:.r 1(1 12- I i'T .,.,....'r Eli f\: .'w".;;) If'~i." ,i , "'!I: -!) I,·, 1 , ~".. ~. li -.: ~,' ~) ~; \\ 1.3 Current Prices of Natural Gas- There is no single marke~price of gas in Al aska since a well deve.loDed market does not exist.In addition,the price of gas is affected by regul ation vi a the Natural Gas Pol icy Act of 1978 (NGPA) which specifies maximum wellhead prices that producers can charge for various categories of I gas (some categories will be I deregulated in 1985).There are some existing contracts for the sale/purchase of Cook Inlet gas which specify wellhead prices but since there are no existing contracts for the sale of North Slope gas,the North Slope wellhead price can only be estimated based on an est imated final sales price and the estimated costs to del iver the gas to market.The current wellhead prices of natural gas for the Cook Inlet area and the North Slope are discussed below. (a)Cook Inlet Currently there are four contracts for the sal e/purchase of Cook Inl et gas where the agreemen~s were negot i ated at arms length and the contracts are public documents.These are: (1)Chugach Electric Assn./Chevron,ARCO,Sh~\b)contract for purchase of gas from the Beluga River Field.~ (2)Enstar/Union,Marathon,ARC0 19 Chevron contract for purchase -of gas from the Kenai Field.t ) (3)Enstar /Shel 't28pntract for purch,ase of gas from the Bel uga River Field.) (4)Enst ar /Mar athon contr act 2tQr purchase of gas from the Ken ai and Beaver Creek Fi el ds.t ') The Chugach contract current price is about $0.28/MCF and under the terms of the contract is estimated to increase to about $0.38IMCF in 1983 dollars by 1995.The contract will not be deregulated in 1985 by Subtitle B,Section 121 of the NG,PA.The contract terminates in 1998 or whenever the contracted qUctntity of gas has been taken.At the maximum annual take of 21.9.BCF/yr., the contract will terminate in 1995 since 285 BCF remained under the contract on January 1,1982 (See Figure 0-1.2). The Enstar/Union contract current wellhead price is about $0.27/MCF and becomes about $0 ..64/Mcf when del ivered to Anchorage because of the addition of transmission costs.The wellhead price remains a.t $0.27/MCF until 1986 where the price becomes the average price that Union/Marathon receives from new sal es to third parties.If there are.no new sales,the price will remain at $0.27/MCF until contr acted reserves.are taken (estimated to be 1990 by Battelle)or the contract expires which isin 1992.Like It jl'" c, The EnstarlShel1and Enstar/Marathon contracts were both signed in December 1982 and are essentially the same in that they have a base wellhead price of $2.32/MCFin 1983 with an additional demand charge of $O.35/MCF beginning in 1986.The base price ~d the demand charge are to be adjusted annually based on the prlce of No.2 fuel oil at the Tesoro Refinery,Nikiski,Alaska.The contracts terminate in 1997 or whenever the contracted quantity of g as has been taken.The we 11 head pri ce of the gas under these contracts wi 11 be.deregul ated in 1985 under the NGPA. The Phillips/Marathon LNG gas (see Section 1.2(b))is not regul ated and has a well head price that f1 uctuates wi th the delivered price of LNG in Japan which is tied to the world price of oj]!)Sources have quoted t.he..)wellhead price as $2.07/~1CF in 1980\2 and $2.02/MCF in 1982.tcL the Chugach contract,thi s gas wi 11 not be deregu1 ated by the NGPA in 1985. 01-11 Estimated Price For New Purchases:If all current and future ~t electrical requirements are to be met with gas generation,new purchases of uncommitted Cook Inlet gas will be required.The price that will have to be paid for the additional gas is important in the evaluation of thet"'mal alternatives versus the Susitna hydroelectric alternative. Previous contracts for gas such as the Chugach/Chevron and Enstar/Union agreements are not indicative of the price that would have to be paid'today for uncommitted gas since these contracts .were entered into long ago and their current prices are substantially below any energy equivalency with oil or coal. A1thoughl ow price gas from these contracts will be used for future electrical generation,t.he contracts expire in the 1990 - 1995 period therefora they are not relevant in the Susitna vs. gas-fired unit alteronative economic analyses which covers the period 1993-2040.There may,however,be some marketing effects in the period 1993-1995 where electric utilities are still using low cost gas for fuel. The price for new purchases would seem to depend heavily on whether the Cook inlet gas can be economically exported as LNG. With the postponement or demise of PALNG this possibility seems remote at the present time.Assuming therefol"e,that there is no competition from LNG exporters,the gas and electric utilities in the area would be the primary,remaining potenti al purchasers. The actual price that would be agreed upon between producers and the utilit'ies is impossible to predict but an indication is provided by the Enstar/Shell and Enstar/Marathon contracts described below. Ii'~J ~.I ~ (....,. ;r ~, :,i ,.."".•......'..~(i 1 ; 1'":1...;.H H I] I , f -I ..~ b¥~.............l;;"1 ! 01 ...12 The wellhead price agreed on in the Enstar contracts was $2.32/MCF with an additional demand charge of $0.35/MCF beginning 'in 1986 • The demand charge of $O.35IMCF in the Enstar/Marathon contract applies to all gas taken under the contract from January 1,1986 to contract expiration.Under the Enstar/Shell contract,the demand charge of $O.35/MCF applies only if daily gas take is in ex.cess of a designated maximum take.fnstar expects they will incur the demand charge because of electric utility requirements that increase the daily take..Estimated severance taxes of $0.15/MCF and a fixed pi pel ine charge of $0.30 for pi pel i ne delivery from Beluga to Anchorage are additional costs.Future prices (Jan.1,1984 and on)are to be determined by escalating the well head price pl us the demand charge based on the price of #2 fuel oil in the year of escalation versus the price on January 1, 1983.If it were assumed that the generating units were located at the source of gas,the pi pel ine charge woul d be el iminated giving a Jan.1,1983 price of $2.47~MCF.(See Table 0-1.5). The price in Table 0 ...1.5 represents the best estimate currently avail able for the cost of Cook Inlet gas·for electrical generation.Therefore this price was used as the base price of fuel for gas-fireu generation in the thermal alternatives to Susitna over the period 1993-2040.Since the price is tied to the future price of oi 1,it was escal ated based on the estimated future price of oi 1 to obtain prices for 1993 to 2040 (See Projected Gas Prices Section). Although the possibility of uncommitted Cook Inlet reserves being purchased for LNG export seems to be remote at the present time!) conditions may change in the future.The price producers might be able to obtain if LNG export opportunities existed might then become important..A method that can be used to estimate wellhead pri ces for LNG export is to beg in wi th the market pr i ce for delivered LNG and then subtract shipping,liquifaction, conditioning,and transmission costs to arrive at the maximum we 11 he ad pr i ce • Asian countries are probably the primary market for Alaska LNG, specifically Japan and Korea.Phillips/Marathon is presently sell ing LNG to Japan.,and the TAGS study previously mentioned plans on selling to the Asian t.ountries.LNG would cbmpete with imported oi lin those markets and its pri ce woul d therefore be dependent upon the worlr price of oil.An example of this LNG/oil price competitivenesss is the existing contract between Phillips/Marathon and the Tokyo Gas and Toyko Electric Companies where the del ivered price of gas is(~QU.al to the weighted average price of oil imported to Japan .:J)For an imported 0;1 price of $34/bbl,the equivalent LNG price would be about $5.85/Mcf (1000 Btu/CF gas)and for an oil price of $29/bbl,about $5.00/MCF. I; I'.·.·-..l..,...••...:\ i , If I~: (: I~ ~ I -c .~ E,; [i,:It:...~. ~; m -;i:1ft j t c I 1 [) 01-13 .....v Conditioning,liquefaction,and shipping cost estimates were recentl y deve10ped by the Governor's Economic Committee in their study of a Trans A1 aska Gas System (TAGS)which would transport North Slope gas to the Kenai P(i!~jt.lSU1a via pipeline,then liquefy and ship the LNG to Japan.\.)These estimated costs are based on the large volumes of gas available from the North Slope,. An.LNG facillity for only Cook I.nlet gas would be considerably I smaller and there might be some economies of scale in going from a small to a large facility.These economies are not believed to be 1 arge however.In addition,it is just as likely that the TAGS will be implemented as a Cook Inlet only LNG facility and producers might therefore have the opportunity to sell their gas to either facility.The estimated costs for conditioning, liquefaction,and shipping of $2.,OO/MCF from the TAGS study are therefore believed to be representative for estimating the wellhead price of Cook Inlet gas whe.re LNG export opportunities exist. The delivered price ;s dependent upon the wellhead price that must be pai d the North 51 ope producet~s and the cost of del i veri ng the gas (or electricity)to the Rai1be1t load centers.The price that producers VJould accept is unknown but it is evident that they do not have a large number of alternatives to utilize the gas. They can shut the gas in or reinject as they are presently doing or se i 1 to some enti ty that wi 11 tr ansport the gas (or electricity)to market.There is a maximum price that the producers can charg.e.si nee the gas is regl...lated by the Natur al Gas Pol icy Act of 1978 but the only minimum would seem to be the value obtained from reinjection. The estimated,netback,wellhead price of Cook Inlet gas for LNG export is shown in Table 0-1,,6.The price would'vary depending on the average price of oil delivered to Japan so prices based on $34/bb 1 and $29/bb1 oil are shown.The maximum price thatcou1 d be paid to producers is $3.00-$3.85/MCF and these prices are higher than the estimated prices where no LNG export opportuniti,es exist as shown in Table 0-1.5..Therefore,if LNG opportunities did'exist,the price of Cook Inlet gas for electrical generation would be higher than the price assumed herein (Table 0-1.5)since the utilities would have to outbid potential LNG exporters • (b)North Sloee The relevant price of North Slope gas for use in Railbelt electrical generation is the "del ivered price",that is,the price of gas del ivered to generating units located near the electric load centers or if generation were to take pl ace on the North Slope,the equivalent price for electricity delivered to the load centers. t L'·\~ ,) 1\:I{ ~,.'"r ,·,f .",.J ~[i '1 J ~':iI, .,.•i I 11 if[I ( ar,',",r} Ii I"";'"~1 ( ~i i >\: I~,','.~;I ,;) I ',':J I, :,',',"'" .'."d I f t'} :<,,1 1 1-.., \\ Ii~I~' I"~" r ::1 I, I~t 1"'7 :,1 iy{ ., 1-: .', ".r I", _"J.,I: " " :.} t:<',,: "~ ~,:.f~;, I''I II',• ~, IV~; 11'~) ~.; ~,.,. ~.\j,i I One method of estiMating a North Slope wellhead price is to begin with a knownol"est'imat.ed price that the gas would bring in a given market and subtract the estimated costs to deliver the gas to that market.Since the sal es price depends on the market to which the gas is delivered and the costs depend on the distance and method of deli very,it is best to an 1 ayze the'North 51 ope t wellhead pl'ice and the cost tof using the North Slope gas Jor electrical generation by the transrortation method employed.This is done below for those transportation methods described under the section,"Production and Use of Natural Gas". Al aska Nla~ural Gas Transportation Sxstem (ANGTSJ~:..The ANGTS project lf constructed as currently proposed,would deliver North S10pe gas to the lower forty ei ght states by means of a 1arge di ameter pi pel ine traversing central Al aska,and Canadae A portion of the ;>roposed 1i newoul d be routed near Fairbanks,Alaska.Due to the line's proximity to Fairbanks,it would be feasible to construct a lateral line from the main ANGTS trunkline to Fairbanks,and thus bring North Slope gas to Fairbanks for use in both electric generation and heating.In a study conducted by Battelle,first year transportation costs to Fairbank~were estimated by apportioning the Al aska segment of the pi pel ine between Fairbanks customers and lower forty eig~~)customers and adding the full costs of gas conditioning.\Battelle's estimated transportation costs in 1982 doll ars were $3.79IMMBtu ($4;03 in 1983 dollars)and at the maximum wellhead price of $2.30/MMBtu (June 1983)the del ivered price to Fairbanks would be $6.32/MMBtu in 1983 dollars. .ihe a ii9~~stc~~{sfO~o~heA~Gis ~e:re;a~s~~~~~~~:~~69ffiC;f (~~~dY s~~ a11 oc at i on method that was used by.Batte11 e is app 1 i ed to the results of the General Accounting Office study,the first year transportation costs are about $4~60/MMBtu in 1982 dollars ($4.88/MMBtu in 1983 dollars).If the costs are levelized over the project's life,the costs would be about $3.87/~IMBtu in 1983 dollars. In a separate 1983 study,the Gel'leral Accounti ng Office (Study II) has al so estimated (29Qditioning and transportation costs associated with ANGTS..)The estimated cost of delivery to the lower forty eight is $5.25/MMBtu (1982$).When the allocation method used by Battelle to determine del ivered costs at Fairbanks is employed,the conditioning and transportation costs are $2 ..80/MMBtu;n 1983 dollars.With a maximum wellhead price of $2.30/MMBtu,the delivered price in Fairbanks is $5.10/MMBtu.The cost estimates of Battelle and the GAO are sUlltmari zed below in .1983 doll ar5 perMMBtu. 01-14 "lIo' l'l'_Ie'..."•: !t• I, I \- I j ~ I ! t 1 I r -I I ! { !"-~"'--'-_._----~'"'._~'"._--~__I :,).............•. ,) 5.10 7.18 6.17 $6.32 2.30 2.30 2.30 $2.30 I .......,........'- f.- .... 2.80 4.88 3.87 ~~aximum Transportation Maximum Total Cost Costs Wel~head Price Delivered to Fbks. GAO Study II First Yea\~ Battelle (1st yr.)$4,03 GAO Siudy I First Year Levelized Estimate Dl-15 None of the cost estimates include severance or state of Al clska property taxes.These taxes are roughly estimated to total somewhere between $0.50 and$1.00/MMBtu. The estimated costs delivered to Fairbanks are well above the Cook Inlet estimated gas costs for 1983 even with a North Slope wellhead price of $0,,00.Because implementation of the ANGTS project is doubtful,its estimated gas costs are not com~idered to be reasonable prices to use as inputs to the thermal alternatives. Trans Alaska Gas System (TAGS):The TAGS proposes to deliver gas to the Kenai Peninsul a for llquefaction and export as LNG.Some of the gas could undoubtedly be used for electric generation at .Kenai.The costs to electric utilities of the gas can be est imated from informati on in the TAGS report.Thi s information is presented in Table D-1.7 for the total TAGS Sjstem and Phase I of the system.A low tariff which would provide a 30%after tax return to equity investors,and a high tariff which would provide 40%~are shown for both the total system and Phase I. The price that electric utilites would have to pay is dependent upon the LNG sales price in Japan so prices of $5.85/MMBtu and $5.00!MMBtu have been shown.These correspond to oi 1 pri ces in Japan of $34/bbl and $29/bbl respectively. Using the netback approach,shipping and liquefaction costs are subtracted from the sales prices for these would be avoided by TAGS if the gas was sold to electric utilities at the LNG plant .. As can be seen,prices V?J.ry frofll $3.03/MMBtu to $4.19/MMBtu but the lower prices.may not be real istic since they may result in low or negative wellhead prices to the producers.In addition,at an estimated sales price of $5.00/MMBtu,the TAGS would probably not be implemented. f I,~ I~'i\ "j \ ! I' I~~'" ',I !' If'~: I~ I~, Ie I~ I," I, {': f\ ,;J ~: 1'" ",) ~Ol ,I: ,E, "-,..-,,,- [ III ~. I,;Ii, 1\,~.: I,~; Ii'fly ~ I, ...!t ." 01-16 The estimi.1ted delivered cost of gas to Railbelt load centers based Oi1 transportation costs and assumed wellhead prices 3.re shown in Tab 1e 0...1 ..8.The only cost for North Slope gas used as an input to the thermal a~ternatives analysis,however,is the cost derived from the TAGS stUdy whi ch was found to be about $4.OO/MMBtu in 1983 doll ars. •m #b#" c:- If it i.s assumed that TAGS would be implemented only at an LNG sales price of $5.85/MMBtu or above,that the total,system would be .constructed and that some point between the low and high tariff 'was acceptable to investors and North 51 ope producers,then the price of gas to electric utilities at Kenai would be $3.96-$4.19/MMBtu.*These assumptions seem to be reasonable and a 1983 cost of North Slope gas of $4.00/MMBtu delivered to the Kenai Peninsu1 a for electric generation will therefol'e be assumed .. Pipeline to Fairbanks:Transportation costs of a small diameter pipeline to FairbanK'S have be2§)estimated to be about $4.80/MMBtu for electrical generation.~Using the average of the reasonabl e TAGS well head prices di scussed above of $1.28/MMBtu (ave.of $0.75 and $1.81lMMBtu)provides a delivered cost in Fairbanks of $6.00/MMBtu.This cost is considerably higher than the estimated cost from TAGS and was therefore not used in the analysis of thermal alternatives. North Slope Generation:Jhis.alternative uses the North Slope gas Without incurri ng transportati on costs for the gas.However,the generatedelectriclty mUbt be transmitted to the Fairbanks load center thereby requiring the construction of an electrical transmission line.The capital costs and O&M costs of this line have a1 so been estimated ~~i)they are about 80%of the cost of the gas transmission lines.~....Based on this,an eqUivalent ugas"transportation cost would be $3.84/MMBtu (0.8 x $4.80/MMBtu) which when added to a wellhead price of $1.28/MMBtu would result in an lIequivalent delivered ll cost of gas of $5.12/~M8tu This is less than the sma11 diameter pipeline alternative but still considerably more than the TAGS delivered cost.This price was therefore not used in the anaiysis of thermal generation al tern at i ves. Subtraction cf ;as conditioning costs and pipe1 ine transmi ssion costs gives the well head price which varies from a negative ,$1.34 to $1.81/~1MBtu depending on the system,tariff,and sal es price assumed. *This would provide investors an after ..tax return on equi ty between 30 and 40%and North Sl ope producers a we 11 head price between $0 .75 and $1,,81/MCF. -----_......_-------------- i.:> I i 1 10I- c ,.""""""'.=J''.'",,._,-""'""'"',,'."',',-",".' ,,;"'1".":, .""...'0- D1-17 1..4 Projected Gas Prices The estimated 1983 cost$of Cook Inlet and North Slope gas were developed in the previous sections.Since the analysis of thermal a1terno.tives covers the period 1983-2040,a method for projecting the 1983 pri ce must be ut i 1i zed. The method selected is to tie the price of natural gas to the world price of oi 1 since the two fuel s can be substituted in many cases and particularly since the.recent Enstar gas purchase contract price is tied to the price of oil.The En~~ar price was used as the J.983 estimated price of gas for ~he Cook Inlet area and it is assumed to be represe,tative of future contracts for Cook In1 et uncommitted and undiscovered.gas. If North Slope gas is sold as LNG to Japan or Korea,the del ivered price will probably be 'tied to the world price of oil in the same manner as the existing Phil1 ips/Marathon LNG contract.Ele"'tric utilities who purchase gas from future LNG exporters will probably also have to pay a price which is adjusted to the world oil price. The future price of Cook Inlet natural gas was calculated by escalating the base 1983 price from Table D...1.5 with the world oil price change scenarios from Exhibit B,Section 5.4.Future gas prices using alternative.oi 1 price projections are shown in Table D-1.9. The future price of North Slope natural gas was calculated by escalating the base 1983 price from Table D-1.8 with the same world oil price change scenarios used for Cook In1 et gas.The estimated future prices are shown in Tab Ie 0-1.10. The natural gas prices from Tables 0-1.9 and D-1.10 were used a~l the price of gas fuel in thta evaluation of Rai1be1t thermal alternatiVE-'S. 1.5 Effect of Gas Price Deregulati~~ The wellhead price of all interstate and intrastate natural gas in the United States is currently set by the Natural Gas Policy Act of 1978 (NGPA).Jlmong other things,the NGPA sets the maximum ceiling prices which can lawfully be changed for specific categories of gas production;ext,~nds federal price controls over the interstate market to include intrc.:state gas;and deregulate?as of November 1,1979 the price of certain categories of "high cost"gas,i.e.deep gas, geopressuri zed gas,coal seam gas and Devonian shal e gas 0 In addition, the NGPA provides a schedule for price deregulation of additional categoriel.}of gas beginning January 1,1985. To speed up the flt~oCess of flatural gas pt'ice decontrol,the Reagan Adminis'tration has recently proposed a bill,.appearing as $.615 in the Senate and as H.R.1760 in the House.It would deregulate the price of I c ~It~, ( ~ [,: ":,i .? .~ L'" ",.'! Ii' ~i t L, ~. L; ~ Ii I I~ ,1,'·i \, ~.....'. "-t - - 01 ..18 _.-_.-" ~, r J f Chug.ach and Chevron,ARCO,Shell Contr act.Chugach ElectficCo'-op has a contact witrcbevron,AltCO and Shell for purchase of Beluga field gas,in the Cook Inlet area. (i) (a)Ex;sti og _L~w Titl e I,Subtit1 e A~the NGPA estab 1 i shes di screte categories of natural gas production,and sets a maximum ceiling price for each category of gas.In def;ni ng these categori es,the NGPA draws a distinction between lIo1d gas,n which was under -:ontract prior to pass age of the NGPA,and "new gas,u or post-NGPA supp 1i es •01 d gas generally has lower ceiling prices,than new gas,and is governed by Sections 104 and 106 in the case of interstate contracts,and Sections 105 cimd 106 in the case of intrastate contracts.New ~Jas ;s govei"ned generally by Sections.102 and 103. In addition to f~njoying higher ceiling prices under Subtitle A, this gas i $potentiallysubj ect to decontrol in 19f:.'5 under the provisions of SUbtitle B,Section 121.Further,North Slope gas to be transported by ANGTS can only be priced under Section 109 and is not eligible for decontrol under Section 121. To ddequately eval\!a'te the effect of NGPA pricing on Al aska gas, all existing contracts are individually analyzed.Potential future contrac"cs are al so addressed It all natural gas,regardless of production category,for which a new contract had been entered,or an old contract amended,after the effec':ive date of the legislation when passed.Several legislative proposals have surfaced in both the Senate and House in oppositon to this proposal.Primarily,.the oppositionls committed to retaining price controls on "old price",that is,gas which has been dedicated to interstate commerce prior to passage of the NGPA.Further,opponents would maintain,'and in some areas restrict,the present NGPA schedule of phased c1econtrolof new gas.Representative of this oppositon is a measure sponsored by Senator John Heinz,(R-Pa.)Heinz's bill,the Natural Gas POlicy Mlendment of 1983 (S.689),would continue indefinitely price controls on all old gas,and for certain old gas would actually roll back the current price to November 1,1978 levels. Further,it would continue ,the NGPA schedule for decontrolling the price for certain new gas categories by January 1,1985. Ir.this section,an an~lysi sand compari son has been made of the potenti al cost s of both Cook Inlet and ~!orth Slope natur al gas under several legislative scenarios.First,examination is made of the effects on existing Cook Inlet contracts and .potential future contracts of continUing present NGPA pricing.and phased decontrol prOVisions.Second,proposed legislative changes either to accelerate deregulation of both old and new gas,or to limit deregUlation!) are examiiled for their most likely effects on Alaska gas prices.These most like.ly resulting Alaska gas prices are then analyzed to determine the potential cost of electrical generation from thermal alternatives in the Railbelt area. I c';......,£± f I~ I~ [ "II) I It ~. ~' D I I'I 1 I \ IL.!. Q til' 01-19 Production under the contract began in 1968 t and the current price is approximately 274/mcf. As an existing intrastate contract at the time of the NGPA's adoption t gas prices under this contract would be governed by Section 105 of the NGPA..Section 105 provides that the maximum lawful price shall be the lower of the ex i sting contract price t or the new natural gas maximum price as computed under,Section 102.The Section 102 ceiling price was $1.75/MMBtu in Apri1 t 1977 t and has been escal ating monthly since that timet in accordance with the terms of Section 101 of the ~GPA.The contract price of the 274/mcf for this Cook Inlet Area gas (Which has an HV of approximately 1000 Btu/ft 3)obviously is lower than the Sect;on 102 price.Therefore t;n accordance with Section lOSt the contract price must serve as the ceiling pt'ice,at least until 1985,when some of the gas under contra.ct may be eligible for decontrol.However,Section 121(a)(3)pertaining to deregul ation of prices for gas under existing intrastate contracts provi.des that such gas prices wi 11 only be deregul ated if the price for such gas woul d exceed $1.00/MMBtu on December 31,1984.As gas under this contract is at present expected to stay at 274/MMBtu on December 31,1984,deregul ation may.not change the contract price of this gas. Enstar t Union,Marathon,ARGO,Chevron Contract.This contracr-for purchase of Renai f'i el d gas from Union, Marathon,;c:RCO,and Chevron was originally executed by Enstar in 1960,but has been amended several times.The price currently is about $0.64/Mcf.As such,it too is governed by Section 105 of the NGPA.As expl ained in.the discussion 'of the Chugach/Chevron contract under Section 105 the contract price would serve as the NGPA ceil ing price,for it also is lower than the Section 102 ceiling price.As with the Chugach/Chevron contract,some of the gas to be produced under this contrct may be el igible for decontrol in 1985.But if the price under this contract remains under $1.00/MMBtu on December 31,1984,decontrol will not alter this contract price. Ensta.r/Shell,Enstar/Marathon Contracts.These contracts were signed in Decem6er,l-ggr-for purchase by Enstar of Kenai field gas from Shell and Marathon.The current price is $2.32/Mcf ..Most of the gas under contr act is new gas governed by Section 102 of the NGPA.The contract al so incl udessome Section 103 gas.The maximum prices for these categories of gas in June 1983 were $2.78/MMBtu and $3.42/MMBtu,respectively. Pursuant to SUbsection B,Section 121,prices for Section 102 and 103 gas would be decontrolled on January 1,1985, therefore gas prices under these two contr act sare subject to eventual decontrol • i L:; j i Ik· I, It I'~ ,..J I"'"'"'·1~~, Ii I~'-; ..)~" I: 1'",' ...;J':.','::J ,J ~ ~ • ~ '"~-~-,-,,",-,-.-, "',. ,.:f "Co ..~! 'C 01-19 Production under the contract began in 1968 9 and the current price is approximately 27~/mcf. As an existing intrastate contract at the time of the NGPA's adoption,gas prices under this cOTltract would be governed by Section 105 of the NGPA.Section 105 provides that the maximum lawful price shall be the lower of the existing contract price,or the new natural gos maximum price as computed under Section 102.The Section 102 ceil ing price was $1.75IMMBtu in April,1977,and has been escal ating monthly since that time,in accordance with the terms of Section 101 of the ~GPA.The contract price of the 274/mcf for'this Cook Inlet Area gas (which has an HV of approx imately 1000 Btu/ft 3)obviously is lower than the Section 102 price.Theref~)re,in accordance with Section 105,the contr act pri ce must serve as the cei 1 i ng price,at least until 1985,when some of the gas under contract may be el igible for decontrol.However,Section 121(a)(3)pertaining to deregulation of prices for gas under ex ist i ng intr ast ate contr act s prov tdes that such gas prices will only be deregulated if the price for such gas would exceed $1.00/MMBtu on December 31,1984.As gas under this contract ;s at present expected to stay at 27~/MMBtu on December 31,1984,deregulation may not change the contract price of this gas. Enstar,Union,Marathon,ARCO,Chevron Contract.This contract for purchase of Kenai fieTa gas from Union, Marathon,ARCO,and Chevron was originally executed by Enstarin 1960,but has been amended several times.The price currently is about $0.64/Mcf.As such,it too is governed by Section 105 of the NGPA.As explained in the discuss ion ·of the Chug ach/Chevron contr act under Sect;on 105 the contract price would serve as the NGPA ceiling price,for it also is lower than the Section 102 ceiling price.As with the Chugach/Chevron contract,some of the gas to be produced under this contrct may be eligible for decontrol in 1985.But if the price under this contract remains under $1.00/MMBtu on Oecember31,1984,decontrol will not alter this contract price. Enstar IShell,Enstar/Mat"athon Contracts.These contr acts were signe"d ;n December,1982 for purchase by Enstar of Kenai fi e1d gas from She 11 and Mar athon.The current pri ce is $2.32jMcf •Most of the gas under contr act is new gas governed by Section 102 of the NGPA.The contract al so includes some Section 103 gas..The maximum prices for these categories of gas in June 1983 were $2 ..78/MMBtu and $3 •.42/MMBtu,respectively. Pursuant to SUbsection B,Section 121,prices for Section 102.and 103 gas would be decontrolled on January 1,1985, therefore gas prices under these two contracts are subject to eventual decontrol. Q I. 'i:l····.I .4 Ii?f 1 _«' j; I IniL .,;' ij ~,"", .', .t IfIt (:J If' L' ':;'! ~. 'J C ...._.f L·'J,1"1.:. ~ ~,,; ,~{:'1 t·!vif. It ~. fr'1 1\ :" .;J I'~ i...... l I } I----:3-) 01-20 _.._..jRliOif"·' The Admini5trations'Bill.This proposed bill would immediately remove federal price control s from all gas not presently committed by contract..In addition,any ex.isting contract could be abrogated by either seller or purchaser during a period from Jan. 1,1985 to Nov.15,1985..If the contr act was not abrog ated during that period,its existing,terms and conditions would'remain in effect unt i1 contr act ex pi r at ion. The Chugach/Chevron,ARCO,Shell contr act would undoubted ly be abrogated by the producers if the Administration bi 11 were New Cook Inlet Contracts.Contracts for Cook Inlet gas signed between now and January 1,1985 will probably be regulated as to maximum price by Subtitle A,Section 102 or Section 103..The current maximum prices for these categori es of gas (June 1983)are $3.42/MMBtu and $2.78/MMBtu respectively.The prices are"allowed to increase at a rate in excess of the inflation rate for. Section 102 gas and at the infl ation rate (GNP defl ator) for Section 103 gas. New contracts will probably be decontrolled by Subtitle B, Section 121(a)of the NGPA on January 1,1985.Further, Section 121(a)(3)provides for decontrol of existing intrastate contracts where the'contract price of the gas is in excess of $1.00/MMBtu on December 31,1984 • . North Slope Gas.There are currently no contracts for sal elpurcfiase of gas from the North Slope.f'4orever,Secti on 102{e)and Section 103(d)specifically exclude from regul ation gas produced from the Prudhoe Bay Unit of Al aska and transported through ANGTS.North S10pe gas tl"ansported via ANGTS is regulated under Section 109,Ceiling Price For Other CategOl~ies of Natural Gas.The base price under Section 109 was $I.45/MMBtu in April 1977 and adjusted for inflation gives the.current·price of $2 .•30/M~1Btu (June 1983).If tr~North 51 ope gas were transported under another system,e.g..TAGS or a small diameter pipeline to Fairbanks,presumably it would be controlled under Section 102 or 103. (b)Proposed Changes totheNGPA Bi 11 s have been introduced into Congress whi ch waul d change the NGPAand its effect on natural gas pr1~es.Chi·ef among these are the Reagan Administration bill (5.615)and a bill introduced by Senator Heinz of Pennsylvania (S.689.)A House bill advancing similar concepts as $.689 has been introduced by Congressman Philip Sharp (D-Ind ..)The effects of $.615 and S.689,and the probable effect on Alaska natural gas prices of efforts to accelerate,or'alternatively restrict,.gas price decontrol are discussed below. .~.totMMtlrottrnt'itKtt 'tPtwnc 'WsH ten &"ttt,(t$¥SYtlW'th... r Ic:~ .'., I~ ~ I~ I~ ~ ~-;It I Ir.< I .I,·1 . I I~, 01 ..21 The Heinz Bi 11.Introduced by Senator Heinz of Pennsylvani at the bi,.,would amend the NGPA to prevent deregulation of certain intrastate contracts that would other\,{i~e be deregulated in 1985 (Section 121 (a)(3)-Intrastate Contracts in Excess of $1.00) and·declare indefinite price escalators to be null and void.The bi 11 apparently makes no change in the status of North Slope gas, i.e.the gas will remain regulated as Section 109 gas,provided it is transported via ANGTS. The bi 11 would deregul ate New Natur al Gas and New Onshore Production Well s that are no\'/scheduled for deregu1 ation under Secti ons 121 (a)(1)and 121 (a)(2)of the NGPA.Any uncommi tted or undiscovered gas in the Cook Inlet area and the Gulf of Alaska wou1 d therefore not be contro 11 ed after passage of the Bill. The principal differential effect this bill would seem to have on Al aska gas when compared With the NGPA would be the null if;cation of the esca1 ation c1 auses in the Enstar/Marathon and EnstariShel1 contracts. implemented.The price of gas under that contract is estimated to be $O.32/MCF on Jan 1,1985 and that price is well below any reasonable estimate of market price at that time (see Tabl e 0 ..1.9). The Enstar/Union contract would also undoubtedly 'be abrogated since the estimated prlce~of gas under that contract wj 11 be $0.64/MCF on Jan.1,1985,again well below estimates of market val ue .. The EnstarlShell and Enstar/Marathon contracts signed in Dec. 1982 mayor may not be abrogated depending on \'klat the producers and Enst ar believe the market prj ce of gas to be re1 ative to the contract price in 1985.The base contract price of $2.32/MCF (plus $0.35/MCF beginning in 1986)changes with the price of No.2 fuel oil and is estimated to be about $2.16/MMBtu in 1985, jumping to about $2.51/MMBtu in 1986 (See Table 0-1.9 -Reference Case)..The estimated maximum price that will be oJtainable for Cook Inlet gas if deregulation occurs is discussed in a later section. - (c)Deregulated Cook Inlet Gas Prices Of the proposed bi 11 s~imp 1ementati on of the Reagan bill would have the greatest effect on natural gas prices in Al aska.The greatest potential effect would be on Cook Inlet gas prices \'Alere producers would undoubtedly exercise their market out rights in 1985 for two of the existing contracts and possibly for the remaining two.There would probablY be no effect on the price for future sal es of North Slope gas for the well head price of that gas t···'····'·.:1 ..1j ~1 ...1,: ,":',, , ;1...1 !;': I ,~; I I I ~\ ~, D1-22 is dictated by the cost to del iver the gas to market and all estimates show that the netback vJellhead price is already below the NGPA regul ated price.• The price that Cook Inlet producers would be able to command for their deregul atedgas is of course unknown,but an estimate of the maximum price that theYlwould be able to charge for sales of gas to use in the generation of electricity is possible..The maximum price would be that price at which electric utilities became indifferent to whether they generated using gas or coal.If producers attempted to charge a higher price,the electric utilities would build coal-fired rather than gas-fired units. The cost of generation using coal can be estimated from the capital,fuel,and operating and maintenance expense associ ated with coal-fired generation.The capital and operating and maintenance expenses for a gas-fired unit can al so be estimated and when these costs are subtracted from the total costs of coal g'eneration,the maximum anount that can be paid for gas fuel is 1eft.Thi s doll ar difference can then be transl ated into a cost per MMBtu through use of the gas-fired units heat rate and annual generation. The calculation of an indifferent gas fuel price is presented in Figure D-1.5.Tne size of both coal and gas-fired units are assumed to be 200MW and generate 1.5 billion kWh per year.Other key paramters for the two units are listed in the figure •. The resulting indifferent gas price is $3.19/MMBtu.Thi s price is the maximum estimated 1983 price that gas producers could charge electric utilities for gas fuel under full deregulation of gas prices..Future year prices for deregul ated gas .would be obtained by escalating the estimated 1983 price at the oil priCE!rates of change from Exhibit B~Section 5.4. I G ~\ "J I, I I I I IJ I l trj' I 01-23 REFER.l 2.1982 Statistical Report!!State of Alaska,Alaska Oil and Gas Conservation Commission,p.24. 3.Gas Purchase Contt"act;Marathon Oil Company and Alaska Pipeline Company,dated Dec.16,1982:Gas Purchase Contract;Shell Oil Company and Alaska Pipeline Coo,dated Dec.17,1982. 4.IIJapan to Keep Phillips Gas Connection",Anchorage Daily News, Tuesday,January 4,1983. 5.Sweeney,~al.,Natural Gas Demand &Supply to the Year 2000 in the Cook Inlet Basin of the South-Central Al aska,Stanford l{esearch Institute,November 1977,tabTe18,page 38. 6.Letter from Mr.Ross G.Schaff,State Geologist,Department of Natliral Resourc~s,Division of Geological and Geophysical Surveys, to Mr.Eric P.Yould,Executive D'irector,Alaska Power Authority, February 1,1983. 7."Historical and Projected Oil &Gas Consumption,January 1983, ~tate of Alaska,Department of Natural Resources,Division of Minerals and Et~ergy Management,p.4.3. 8.Geological Survey Circul;,"860,Estimate of Und;scovered Recoverable Conventional Resources of Oil and Gas in the United States,mI. 9.Us S.Department of the Interior Geological Survey,Conditional Estimates and Marginal Probabilities for Undiscovered Recoverable 0iT"ana Gas """Resources ·If-Yl5rov i nce,Stat i st i c al TraCkgroun"CrData for O.~.Geological Survey Circular 860,Open-File Report 82 ...666A. 10.Historical and Projected Oil and Gas ConsumEtion li Jan.1983,State of·Al aska,Department of Natural Resources,Division of Mineral and Energy Management,pgs .•3.13,3.14,B.10. 11..State of Alaska 1983 Long :r.erm Energ,y Pl an (Working Draft), "Department of Commerce ana Economic Development,Di vision of Energy and Power Development,State ofAl aska~p.1-13. 1 ..6 References and Notes 1.Laboratories.Railbelt Electric Power Fuel Availability and Price -Forecasts, r ,•.'1..•f \ ~" E'·"I'I i Gas D1-24 25.Batte 11 e ,Op.Ci t.p.6.5 26.Tussing,ArIan R.&Barlow,Connie C.,The Struggle For An Alaska Pi pel i ne:What Went Wrong £'9 for the GAO,October 26,1982. 27.Issues Facing the Future Use of Al askan North Slope Natural Gas. Report to the.Honorable Ted Stevens,United States Senate,by the Comptroller General of the United States,GAO/RCED ...83-102,May 12, 1983,p.16. 28.Use of North Slope Gas for Heat and Electricity in The Railbelt, Draft Final Report,Feasibi lity Level Assessment to the Al aska Power Authority,Ebasco Servic~s Inc.,January 1983.(Costs on a ~ere not calCUlated in this report.However,uSlng the reports.estimated capital and O&M costs and estimated average gas throughout produces a rough estimate of about $4.80/MMBtu).. 21.Battelle,Ope Cit ..p.2.20 22.Reference 8,p.A.3. 23.-Anchorage Daily Times,January 4,1983. 24.See Reference 18. 13.Joyce,Thomas J.,IIFuture Gas Supplies",Gas Energy Review,Jlrnerican Gas Assn.,Vol.7,1 No.10,July/August 1979,p.8 ... 14.Trans Al aska Gas System~Economics of an Alternative for North Slope Natural Gas~Report by the Governor's Economic Committee on North Slope Natural Gas,January 1983. 15.See reference 18. 16.Issues Facin the Future Use of Alaskan North S10 e Natural Gas, General Accounting Office,GAO RCED ...83-102,May 12.,1983,p.86. 17.Reference 20,p.86. 18.Battelle,~Cit.p.A.2 19.Battelle,Ope Cit"p.A.10 20.See Reference 3. 12. I 01-25 Alaska has three major coal fields:Nenana,Beluga,and KUkpowruk. It.also has lesser deposits on the Kenai Peninsula,in the northwest and in the Matanuska Valley.Alaska deposits~in total,contain some 130 billion tons of resources (Averitt,1973),and 6 billion tons of reserves as shown in Table 0-2.1.The Nenana and Peluga fields are the most economically promising Alaska deposits as they are very large and have favorable mining conditions..The Kukpowruk deposits of North Slope cannot.be mined economically,and al so face substanti al environmental problems (Kaiser Engineers,1977).The"northwest deposi ts in the area of Kotzebue Sound and Norton Sound are small and have high mining costs associated with them,although little is known about these fields (Dames and Moore 1980;Dames and Moore,1981a;Dames and"Moore,1981b).The Kenai and Matanuska fields are also small and present additional mining difficulties (Battelle t 1980). The Nenana Field,located in central Alaska,contains a reserve base of 457 million tons and a total resource of nearly 7 billion tons as is shown in Table D-2.2.Its sUbbituminous coal ranges in quality from 7400-8200 Btu/lb.It is high in moisture conte.nt,low in sulfur content,and very reactive (see Table 0-2.3).Some 84%of this coal is contained in seams greater than 10 ft.in thickness,and stripping ratios of 4:1 are commonly encountered (Energy Resources Co.,1980). The Beluga Field contains identlfied resources of L.8 billion tons (Department of Energy,1980)to 2.4 billion tons (Energy Resources COOl" 1980).The quality of this subbituminous coal varies according to report.Several analyses are shown in Table D-2.4.Beluga deposits typically are in seams greater than 10 ft.in thickness (Energy Resources Co ..,1980)and may be up to 50 ft.thick in places (Barnes, 1966).Stripping ratios from 2.2 to 6 are commonly found .. 2 -Coal This analysis of coC\l availability and cost in Alaska has been developed to provide the basis for evaluating thermal alternatives to the Susitna Hydroelectric Project.This assessment has been developed by a careful review of available literature plus contacts with Alaskan coal develop~rs and exporters.The literat4re reviewed included the Bechtel (1980)report executive.summary,selected Battelle r-eports (e.g.,Secrest and Swift,1982;Swift,Haskins,and Scott!)1980)and the U.S.Department of Energy (1980)study on transportation and market i ng of Al askan coal.Numerous other reports were used for data confirmation.In addition,Paul Weir Company of Chicago was engaged to develop the estimated cost of a mine in the Bel ugafield for the purpose of electric power generation for thf'Railbelt only. 2.1.Resources and Reserves ", ~.. •..•..J....Jr1 Il.,..·. I;l.;i 1--iti: 1'1l, t IfI~.: I~IL 1;1 <! I l ,0 o 2.•2 Present and Potent;al Al askan Coal Production Currently there is only one signifcjcant producing mine in Alaska,the Usibelli Coal Co.mine located in the Nenana Field.This mine produces 830 thousand tons of coal/yr for use by local utilities,military establ ishments,and the University of Al aska-Fairbanks..These users operate 87.Megawatts (MW)of electrical generation capacity,as shown in Table 0-2.5 ..Plans exist at Fairbanl<s Municipal Utility System (FMUS)to increase the total coal...fired electric generating capacity in Alaska to 108 MW (Sworts!1983).The F~1US capacity shown in Table D-2.5 al so serves the Fairbanks di strict heating system. To produce the 830 thousand tons/yr.,Usibelli Coal Co.employs a 33 cubic yard dragline and a front end loader-truck system.This mine, with its existing equipment,has a production capacity of 1.7-2.0 million tons/yr.Much of that capacity would be employed when the Suneel Alaska COa export contract for 880 thousand tons (800 thousand metric tons)/yr becomes fully operational.That contract calls for full-scale Shipments,as identified above,to the Korean Electric Power Co.beginning in 1985. Production at the Usibelli mine Ultimately could be increased to 4 million tons/yr (Department of Energy,1980;Battelle,1982).The mine,which has been in operation since 1943,has 300 years of reserves remaining at current rates of production..Thus,at 4 million tons of production,mine life would exceed 70 years.This production,which may not be able to be used at the mine mouth for environmental reasons due to proximity to the Denali National.Park (Ebasco,1982),may be shipped to various locations via the Al aska Railroad. The Beluga Field,which totally lacks infrastructure,currently is not producing coal;however,several developers.have pl ans to produce in that region.These developers include the Diamond Alaska Coal Co.,a joint venture of Diamond Shamrock and the Hunt Estates;and Placer Amex Co.Involved in their plans are such infrastructural requirements as the construction of a town,transportation facilities to move the coal to tidewater,roads,and other related systems.These auxiliary systems are necessary if one or more mines are to be made operational. Diamond Alaska Coal Co.holds leases on 20 thousand acres of land (subleasing from the Hunt-Bass-Wilson Group),with 1 billion tons of sUbbituminous resources.Engineering has been performed for a 10 million ton/yr mine designed to serve export markets on the Pacific Rim;and the engineering has involved a mine,a 12 mile overland conveyor to Granite Point,shiploading facilities at Gran;te Point, town faci"7'.ities,and power generation facilities.The mine itself involves two draglines plus power shovels and trucks.The target timefrarne for production is 1988-1991"Placer-Amex plans involve a 5 mi 11 ion ton/yr mine in the Bel uga field,al so serving the export market (Department of Energy,1980). D1 ...26 I L \) 01 ...27 The issue of coal prices can be addressed either from a production cost perspective or a market value perspective,or from a combination of the two.The production cost perspective is particularly app'ropriate if electric utilities serve as th2 primary market,since their contracts with coal suppliers typically are based upon providing the coal operator with coverage of operating costs plus a fair return on investment (typically treated as 15 percent after taxes -_See Bechtel,1980;Stanford Research losti tute,1974;and other reports for use of this 15%ROI).The market value perspective is particularly appropri ate when exports become the dominant coal market.These concepts are employed separately for Nenana and Bel uga coal. (a)Nenana Field Coal pricing data exist for Usibelli coal,and these data provide a basis for estimating the cost of coal at futtlre power gener ation fac i 1 iti es. Currently,Usibelli coal is being sold to the Golden Valley Electric Association (GVEA)Healy generating station.under long term c.fJntr act at a pri ce of $1.16/MMBtu (Baker,1983),and to FMUS at a mine-mouth price of $1.35/MMBtu..The current average price for Usibel1i coa.l is $23,,38/ton of 7800 Btu/lb coal,or $1.50/MMBtu.This value is based,to a large extent,on labor As can be seen ,the primary plans for the Beluga Field are for exporting of coal to the Pacific Rim.The proponents of exports believe that Alaskan coal can compete on a cost basis with Austrailian coal,that Alaskan coal is more competitive than lower 48 U.S.coal (Swift,Haskins,and Scott,1980),and that policy decisions in Japan and.Korea to diversify their sources of coal supply favor the ,export(ing of Alaskan coal (Swift,Haskins,and Scott,1980).The export of U.S. coal to Japan al so is seen as a means for treating the balance of payment problems between the two countries,and this could work in favor of Al askan development.Certain factors,however,mi ght impede development of an Alaskan coal export market,e.g.quality of coal and Japanese coal specifications (Swift,Basins and Scott,1980). It is also feasible to develop the Beluga Field at a smaller scale for local needs,however.This potential is recognized,inferentially,by Olsen,et.al.(1979)of Battelle and supported explicitly by Placer-Amex (McFarland,1983).Diamond Alaska Coal Co.currently is performing detailed engineering studies on a 1-3 million ton/yr mine in this field.As a consequence,it is reasonable to conclude that production in both the Nenana and Beluga fields could be used to support.new coal fired po\'/er generation in Al aska,with or without the development of an export market. 2.3.Current Alaskan Coal Prices .[ ' . r· I Charge (1983 $/million Btut 0.32 0.51 0.60 0.70 0.78 D1-28 ~ "1--'.", « , ei&. Nenana Willow Matanuska Aflchorage Seward Desti nat ion Therefore,the delivered price of.coal to a new power plant is estimated to be $1.72-$2.18 depending upon location.On this basis it is likely that new power plants fueled by Usibelli coal would be in the communities of Nenana or Willow.The ~")propriate Because there is-an apparent di sagreement on coal prices from a second unit of production,and because the Suneel contract is not 'yet in place,the $1.40/mil1ion Btu is used as a conservative base price for Nenana Field coal at theuine mouth..Such coal must be transported to market by railroad,however.FMUS.,for example, pays $O.SO/million Btu for rail shipment of Usibelli coal. Battelle (1982)developed railroad cost functions for coal transport and,on this basis,the following charges should be added to Usibelli coal: The Usibel1 i mine could be expanded to 4 mill ion tons/yr.,given the reserve base available.At such production levels,the additional 2 million tons of production would exhibit the same prices as the current mine wtv:m operating at full capacity. Thi s pricing perspective of the additional two million tons of capacity,however,is not universally shared.The Department ofEnergycoa~transportation study (USDOE,1980),estimates that coal from the additional 2 million tons/yr.will cost $1.88-$2.03/MMBtu ;n January 1983 dollars ($1.62-$1.75/MMBtuin 1980 doll ars)• . The $1.50/MMBtu reflects the.price of coal from the Usibel1i mine operating at about 50 percent of capacity.If production were increased to 1.6 million tons/yr,coal prices would decli1ne to $20/ton ($1.28/MMBtu)•An immediate 10%i ncreasein all coal prices associ ated with that mine can be expected in order to comply w'ith new.land reclaimation regulations.As a consequence, the marginal cost of Usibelli coal can be calculated (in 1983 doll ars)as: $20/ton x 1.1 x ton/15.6 million Btu =$1.40/MMBtu productivity of 50 tons/man day.That is a slight decline in productivity,as Usibelli had achieved 60 tons/man day a value confirmed by the National Coal Associ ation (1980)• j,~Ij II, I' !'~ E-, II 1 Ii 1U,,:.l l:, ~, h· ~ ~ ~ [ Ii -I I I I ! "t l~.' I II Ir~p;' 1~ "J- There are other estimates of the expor't market in the Pacific Rim countri es.The U.5.Department of Energy Interagency Task Force estimates that U.S.exports to the Pacific Rim will be 15 million tons in 1990,and 52 mi 11 ion tons in the year 2000;and Barry Levy,in Western Coal Survey,est imates U.S.exports to the Pacific Rim at 25 million tons in the year 2000 (Levy,1982). These values are consistent with the MRI export estimate of 11.1 million metric tons to Japan in 1990,since they would assume smaller amounts of coal being exported to Korean and Taiwan (see Figures 0-2.3 and D-2 ..4). Regard 1eS~j of whether the Japanese market wi 11 .be 73 or 108 million metric tons in 1990,these forecasts do ill ustrate that a large potential market exi~ts.They are consistent with the data from Swift,Haskins ,and Scott (1980). The Pacific Rim export market is potentially highly available to the Alaskan mines due to their favorable transportation cost differentials compared to other supply sources (SWift,Haskins, and Scott,1980)!'Transportation cost different;al s are based upon the distance to markets as illustrated in Fi.gure 0 ...2.5.Levy 01-29 'F 11tt _'eo._ ! i1;__ f The factors affecting development of an export market for Alaskan coal have bnen previously noted.In th'~s section the existence of t he export market is assumed.Estimates of the magn itude.of that potent i al market have been developed by Sherman H..Cl ark and Associates (Clark,1983),and by Mitsubishi Research Institute (MRI,1983).The Sherman H.Clark values are shown in Figure D-2.2 for Japan and Korea.As this figure illustrates,the projected total market in Japan alone could exceed 100 million metric.tons by the end of thi s decade.The data from MRI are shown in Figures D-2.3 and 0-2.4,with particular emphasis on the use of coal in electric utilities.MRI forecasts a smaller total coal market in Japan in 1990,some 72.7 million tons (vs.Sherman H. Clark's 108.1 million tons).MRI estimates that the U.S.share of that Japanese market is 11.1 million tons,as is shown in Table 0-2.6. Bel uga Fi~l d The methods for estimating the price of coal from the Bel uga field depends~in large measure,on whether or not the export market.for Alaskan coal developS in the Pacific R'im.If that market exists,then both marketing and production cost ana~lyses may apply,\..ith production costs establ ishing a minimum price.In the absence of that market,production costs must be estimated for small er mines. base coal prices for use in power plant anal ysi sare therefore $1.72-$1.91/MMBtu. (b) r IT 1:1 , I~ I" i.I ti' ~' ~~: 11~J L t. l' h h L~ L li ~ o I I I' \ I I ! I I I /--Ii11 Production cost est imates for Bel uga coal have al so been developed.They are based upon large mines (5-10 million tons/yr) producing coal for export,and smaller mines (1-3 million tons/yr) serving only the power pl ant market (200-600 MW). Production cost estimates have been made for large mines serving the export market,and these are reported in TaQle 0-2.9.The ti IT .:1 I'·,., I [ t{[ I] I..'I [ I. f:.I' E ~' i ~., (':, ~} l: ~l l; 01 ...31 lower bound values range from $1.16/l]i11ion Btu to $1.27/million Btu and the higher bound values range from $1.65/million Btu to $1 ..74/million Btu.The average of these estimates,taken as a group,is $1.45/million Btu. For the purposes of deri v;ng a coal cost estimate assuming exports,t.he difference between the market val ue and the production cost value must be addressed.Battelle approached reconciliation by simple averaging (Secrest and Swift t 1982). That approach is shown here as well,with.the average of t'le market values ($1.86/million,Btu)being averaged with the production cost of $1.45/million Btu to achieve a price of $1.66/million Btu. While this averaging technique provides one basis for analysis,it appears that the market val ue is a more meani ngful number to use. If a coal operator could sell coal at $1.86/million Btu FOB Port, and if there were few CQst savings to be achi eved by not transporti ng the coal to ti dewater,then there woul d be no reason to sell at some average price.Rather,assuming the export of 5-10 million tons/yr at 7200-7800 Btu/lb coal,th~practice of sell ing at the average price rather than the market val ue would result in decreased revenues to the coal operation of $lS-$32 million per year.It is not reasonable to assume that the oper:ator w(;ul d forego revenues based on market val ue,therefore the market value of coal is assumed. - Independent estimates were made of the cost of producing Bel uga coal at rates of one million tons/year and three million tons/year.These est imates were made by Paul Weir (1983) consulting mining engineers.These coal price estimates were developed under the follOWing assumptions. (1)a 100%equity investment, .(2)rates of return at 10%,15%,and 20%, The Beluga mines as currently projected h'ave largely been considered as sources of coal to be exported to Pacific Rim .countries such as Japan,Korea t and Taiwan.Further,there is a SUbstantial constituancy promoting such exports (see Resource development Council of Alaska,1983).Whether or not this market develops,h0wever,is still a matter of uncertainty. In the absence of strong export Yllarkets~production costs for smaller mines have to be considered.Production costs for smaller mines have been reported by various potent i al vendors,at $1.S0/MMBtuto $2.00/MMBtu. t' 1-"'-,' i 1 1)- r I> L I'·.." 1,1 K ( ~: I" t'l; Ii i; ~i ,k ~: l: t·! ~•. I D1 ..32 Agreements between coal suppl i ers and el ectrie ut il i ti es for the sale/purchase of coal are usually long term contracts vtlicr include a base price for the coal and a methoJ of escal ation to provid ~prices in future years.The base price provides for recovery of the capital investment,profit\*and operating and maintenance costs at the level in existence when the contract is executed.The intent of theescal ation mechanism is to recover actual increases in labor and material costs from operation and maintenanr;e of the mi·ne.Typically the escal ation mechanism consists of an index or combination of indexes SJch as the producer price index,various commodity and labor indexes,or the consumer price index.The index selected is applied to the beginning 1.61 1.91 2.23 2.65 2.23 $2.72 3.20 3.76 1 Mill ion Ton/Year ?Mill ion Tontfear State FinanciJl9. At 3.5%ROR At 10%ROE At 15%ROE At 20%ROE Private Financing Cost of Coal (3)a mine investment including an ancillary town for workers (With town costs diVided between the mine and thE!power pl ant); (4)an investment including a road or conveying system between the mine and a power pl ant located at tidewater -. Because of the low levels of production~Paul Weir assumed that atruck""s~lovel operation would be more cost effective than a drag1 ine operation on a bucket wheel excavator system.On thi s basis,Paul Wier estimated the delivered cost of coal to be as follows: Under the private fi.nancing case!it was assumed tha~;the coal mine was fin;mced without debt.If a 25 percent debt were incorporated into the analysis,the cost of coal would decrease slightly. Paul Weir Company also estimated the cost of coal under the assumption that the State of Al aska would own and {)perate the mi ne.A real cost of cap;tal of 3.5%was aGsumnd and the resulting estimated cost of coal is shown in the t,tble above. This cost can be compared with the private ownership,l~%ROE case which is close to the real rate of return that pr;\'ate equity investors w0uld require as a minimum .. 2 ..4~Coal Pri ce Escal ation. Ii', r I" [ £ ~' ~, E t [ IL t ~. o I. I I} II', These rates of escal ation can be compared to the real hi storical rate of increase of 2.3%/yr.experienced by Golden Valley Electric Association,since 1974.It is difficult to use that historical GVEA rate,however,for the fo 11 owing reasons:(1)the rate rel ates to an exist"jng contract,and (2)the rate cover-sa period of time when the substantial provisions of the Goal Mine Safety Act of 1969 were being implemented thereby affecting the price of coal. The estimates of Sherman H.Clark and ORI are based more upon supply-demand analyses rather than upon extrapol ations of historica'l data.The demand/supply relationship varies for different types of coal which results in different estimated future price escal ation rates.This relationship 'is shown in Figure 0..,2.6 "Jhere future real escalation rates for .western coal (average 2,,9%/year)and western lignite (average 21J3%/yr.}ar~graphed using data from Sherman Clark and ~'\ssoc;ates" Several free market price escal ation rates were estimated for util ity coal iTT Alaska and in the lower 48 states,and they range from 2.0-2.7%/year as is shown in Table D-2.11.These are real escalation rates"that is in addition to or in excess of the inflation rate. Several more real market rates have a1 so been developed by Sherman H. Clark and Associates and by DRI,and these are shown in Table 0-2.12. 01-33 The SHCA estimated real escalation rates for new contract domestic U.S. coal are shown below by period. The free market price of coal,however,1 could increase or decrease at a; rate above or below the general rate of inflation because of demand/supply relationships in the relevant coal market.The utility with an existing contract tied toa cost reflective index would not experience these real changes until the existing contract ex pi red and was renegotiated,or a contract for new or additional quantities of coal was executed. operating and maintenance expenses so that the level of operating and maintenance expense increases or decreases over time wi th changes in the index.The original capital investment is not escalated,so the price of coal to the utility tends to increase with general inflation, provided the escalation index selected reflects the general rate of i nf1 ation. I I~' l' t~ i-I Ii t f E: ~, ji~.:i 1.<. Ii,,~ I~- -•J•J• j 1 j !. I f 1 I I II . I 2.9 2.8 2.0 2.0 3.9 2.0 , 2.9 2.3 -rj.~ './0 Real Escal ation R~te ...%/yr. 3.1 1.7 2.5 2.6 Real Escalation Rate ..%/yr. Western Coal Western LignitePeriod 1980-1990 1990 ....2000 2000-2010 ~1981-1990 1991-2000 2001 ...200f Average 1983-2005 Period For coal exports,SHCA is forecasting a 2.6%/yr.growth in demand by Japan and a 5.2%/yr.demand gro~1h by South Korea (Figure 0-2.1).This growth in demand together witr a forecast weakening il1 United States currency versus the currenc'ies of the two Asian countries results in an estimated real price escalation rate of 1.6%/yr.which is below the forecast U.S.do~estic rates. The forecasts by SHCA and DRI of future coal prices are based on demand/supply analyses performed by knowledgable,experienced firms. The forecasts are reasonable assessments of the future price trends and have been appl ied to Al askan coal produced from the Nenana and Be"\uga fields .. COCil from the Nenan a Fi e1 d ;s used pri ncipally to .$UPP'Y Alaskan domestic markets.Therefore a domestic price escalation rate of 2.6%/year based on the average of SCHA western coal and lignite (2.9% and 2 ..3%)and the DRI forecast (2'.6%)has been assumed.The 2.6%rate is applied to the 1.983 estimated mine ..mouth.price of $1 ..40/MMBtu to provide the future cost of coal at the Us ibell iMi nee Prices for 01 ..34 D ORIls estimated real escalation rates (Spring 1983)for new ~ontract, domestic,U.,S.coal are shown below by period (DRI does not differentiate by coal type). Average 1980-2010 The rates of price change from period to period for domestic u.s.coal are directly rel ated to mine capacity util ization.The lignite price changes refl ectprojected decl ines in capacity uti 1i zation in Texas and North Dakota fields (Cl ark,1983),whi le western coal capacity utilization is expected to increase ..Capacity utilization rates in Alaska depend upon future use by electric utilities and cannot be readily determined.Therefore,when a domest'ic escal ationrate is applicable,the long-term average rate is employed rather than period rates. l. ~,; ~' U Il t l: t .\'[L~ L, t t Ii l; II· I I I \ 2.6 2.3 202 f f Usibelli mine-mouth Nenana Willow Location While there has been some correl ation between export coal pri.ces and world oil prices historicallY,such a correlation is tenuous,at best, with respect to uti 1it)coal contracts.Technical carrel ations must accommodate differences which exist between coal and oil fired units in the areas of capital costs ($/kW),operating costs,and fuel purchasing agreements.Further such carrel ations must accommodate significant differences in market flexibility and market opportunity betwaen coal and 011 supp1 iers.For these reasons it is necessary to treat coal prices as being independent of world oil prices. Several scenarios of future world oil prices have been used in the economic analysis of thermal alternatives.Natural gas prices for these scenarios move with the {)il prices since it is assumed that future natural gas prices in both the Cook Inlet area and the North Slope will be.tied directlY to the future price of oil (See Section 1.4). Coal prices are treated independently of oi 1 prices,but a coal price scenario is required with each oil and natural gas price scenario in 01-35 The resulting fuel prices for Nenana and Beluga field coal for the period 1983-2010 are shown in Table D-2.14..There are no known projections of coal prices past the year 2010. If an export market for Bel uga coal does not develop,the 198~base price should be assumed to be based on the production costs for a small 1-3 million ton per year mine.This would result in higher coal costs,especially in the initial years when consumption in the Beluga steam pl,,'nt waul d be in the 1 mi 11ion ton per year range requi red by one'200 MW unit. Assuming that an export market for the Beluga field develops,all coal sold from the field will probably t'~at a price dictated by Pacific Rim market conditions.This includes sales to electric utilities for use as fuel for electr;cgeneration.Therefore t it is reasonable to escal ate the estimated $1.86/MMBtu 1983 base price of Bel uga Fiel d coal at the estimated export market rate of escal ation of 1.6%/yr. (Tabl e 0-2.12) h ~, " t,. t L" L, L 11 t:; t:; l~~ r,-...( , ~" ,, ,) t"',....) 11 ~',,, ;~ t, t, ('" '{, ,i ~ ",j;l h, L, ii,I.b l' " i) 3.1 Ava;1abi 1i ty According to Battelle,there iS1fdequateavailability of distillate 011 during the analysis period ..-Although part of the distillate oil used in Alaska is impo,rted,this fact alone will not affect its availability.It has been assumed that distillate oil in the required quantities will,be available during the economic analysis'period 1993 to 2040 from refineries within Alaska or the lower forty-eight states. 3.2 Price.. The average current pr-ice for medium distillate fuels in Anchorage and Fairbanks is shown in Table~1.1.These prices will change with the world market price for 011.-The estimated price changes for several projections of future world oil }>rices have been applied to the 1983 price of distillate oil to obtain the future prices during the period 1983 to 2040.These are shown in Table D-3.2 • ." 11 Battelle Pacific Northwest Laboratories..Railbelt Electric Power Alternative Study:Fossil Fuel Availability and Price Forecasts,Volume V~9g2,p.,8.1._.' 21_See Battelle,p.8.3-B.S .. 01~37 ~"f"',I.' "F [',.... \, f I:, t· t: j , L,,- tIJe (: i' ,<... i',' ;i1 .. 0'''' ~., i{ :1.n:, J..., REFERENCES AND BIBLIOGRAPHY Arthur D.Little,Inc.1983.Long Term Energy Plan,Appendix B.DEPD,Anchorage,Alaska. Averitt,P.1973 ..Coal in United States Mineral Resources. U"S.Survey Professional Paper 820.,U.S.!Government Print- ing Office,Washington.DiC~ Barnes F.196 7•Coal Resources in A1aska•USGS Bu11 e tin 1242 -B• Barnes,F.1966~Geology and Coal Resources of the Beluga-Yentna Region,Alaska.Geological Survey Bulletin 1202-C.U.S.Government Printing Office,Washington,D.C~ Battelle Facific Northwest Laboratories.1982.Existing Generation Facilities and Planned Additions for the Railbelt Region of Alaska Vol VI.Richland,WA. Bechtel Incorporated,1980.Executive Summary,Preliminary Feasibility Study,Coal Export Program,Bass-Hunt-Wilson Coal Leases,Chintna River Field,Alaska. Beluga Coal Company and Diamond Alaska Coal Company.1982. Overv'iew of Beluga Area Goal Developments. Clark,Sherman H.and Associates,1983.Evaluation of World Energy Developments and Their Economic Signifiance,Vol. 11.Menlo Park,CA. Coal Task Force.1974.Coal Task Force Report,Project Inde- pendence Blueprint ..Federal Energy Administration, Washington,D.C.,November. Dames and Moore.1980.Assessment of Coal Resources of North- west Alaska -Phase I,Volume I~For Alaska Power Authority. Dames and Moore.1981a.Assessment of the Feasibility of Utilization of Coal Resources of Northwestern Alaska For Space Heating and Electricity.Phase II.For APA. Dames and Moore~1381b.Assessment of Coal Resources of Northwest Alaska.Phase II.Volume III.For APA. ..'0 ean J J to an d K.Z0 11 en to 198 3 to Co a lOu t 1 00 k•0 at aRe soU r c es , Inc. Demonstrated Reserve Base of Coal in the United States as of January 1,1980.U.S~Department of Energy,Washington, D.C. 01-38 II ' f l I l~ I 1982.Railbelt Electric Power Fossil Fuel Availability and Price Pacific Northwest Laboratories, Secrest,T..and W.Swift. Alternatives Study: Forecasts.BAttell e Ric h 1 an d,W A. Scott,J.et •a 1•1978 •Co al Min i ng•The Nat i on a 1 Res ear ch Co unc i 1 INa t ion a 1 Acad e my of Sci ence s,Was hi n9t on,D.C .. Ebasco Services Incorporated.1983.Use of North Slope Gas for Heat an~Electricity in the Railbelt.Bellevue.WA., 01-39 National Coal Association.1980.Coal Data 1979/1980.NeA, Washington,D.C. Olsen,M.,eta ala 1979.Bdluga Coal Field Development: Social Effects and Management Alternatives.Bettelle Pacific Northwest Laboratories,Richland,WA. Resource Development Council for Alaska,Inc.1983.Policy Statement No.6:Coal Development (draft).Reviewed by RDCA,Mar.29,1983,Anchorage,AK. Ebasco Services Incorporated.1982.Coal-Fired Steam-Electric Power Plant Alternatives for the Railbelt Region Of Alaska • Vol XII.Battelle Pacific Northwest Laboratories,Richland, WA. Energy Resources Co.19800 Low Rank Coal Study:National Needs for Resource De vel 0 pm en t ,V 0 1 2 0 Walnut Creek,CA. (For U.S.DOE~Contract DE-AC18-79FC10066). Meye,C.1983.Forecast Assu~ptions in Review of the U.S. Econ 0 my •Da taR e sou r c e 5,Inc.- Integ -Eb asco 1982.Proj ect Descr i pt ion.800 MW Hat Creek Plant.Ebasco Services Incorporated~Vancouver,B..C. Kaiser Engineers.1977.Technical and Economic Feasibility Surface Mining Coal Deposits North Slope of Alaska.For USBM.Oakl and,CA. Levy,B.1982.The Outlook For Western Coal 1982-1985.Coal Mining and Processing.Jan.1982. "McLean Res~arch Institute.1980.Development of Surfa~e Mine Cost estimating equations.Fol.U.S.DOE ..McLean,VA .. MRI 1982.Future Energy Demand and Supply ·in EcLst Asia Mitsubishi Research Institute,Toyko,Japan (For Arthur D.Little, In c. ~r11 I' t"""i' ." \·1 i" ~.. 'J,1, t~1 'J (:' 1/t; I'j 4 •• ~.. I "r h"!" l' " .. 01 ...40 Mining Cost Estimates Beluga Area Ch ;.c ago,ILL.Paul Weir Company.1983. Hypothetical Mine. u.s.Department of Energy.1980.Transportation and Market Analysis of AT aska Coal.USDOE,Seattle,WA. Stanford Research Institute~1974.The Potential For Developing .Alaska Coal For Clean Export Fuels.Menlo Park~CA.(For the Office of Coal Research). Swi f t ~W.,J.Has kin s ,and M•Scott.1980 . Bel u9a Coal Mar ke t Study.Battelle Pacific Northwest Laboratories,Richland, WA. ~r, ~"•·1 H'.:',,',j, .11-, I',l )1 ~,.: t I·',.\ "'.... t· l;'" :.1.L' t [ ~";1 .u! t" ',' 1 I t"~j I .";Y P ·~.....l 1'/ ,. ,~,,' l~ 11 tel ::.:\, '; (~ I,'t~, t t t t Table 0-1.2 HISTORICAL AND CURRENT PRODUCTION AND USE OF COOK INLET NATURAL GAS QUANTITY -BCF USE 1978 1979 1980 19P-1 1982 ~ Injection 114 ..1 119.8 ~15.4 100.4 103.1 Field Operati cns: Vented,Used on lease, shrinkage 23.5 17.5 28.0 20.6 21.3 Sales: LNG 60.9 64.1 55.3 68.8 62.9 Ammonia/Urea 48.9 51.7 47.6 53.7 55.3 Power Generat ion: Uti lities 24.6 28.2 28.7 29.1 30.5 Mi 11tary 5.1 5.0 4 ..8 4.6 4.7 Gas Uti 1iti es*13.5 14.0 15.5 16.2 17.7 Other Sales 3.3 4.8 5.1 5.7 9.5 Total Sales 156.3 167.8 157.0 178.1 180.6 Total 293.9 305.1 300.4 299.1 305.0 Source:"Historical and Projected Oil and Gas Consumption,Jan.1983 1l , State of Alaska,Dept.of Natural Resources,Division of Mineral and Energy Managements Table 2.8. *Does not include sales made by gas utilities to electric utilities for electric generation. Phillips/Marathon L~/Plant c I r j I!re tr-.•~"k"M'~!"! I ,,I " r~~'~~~ f"SiQ'tiI . I I I I 7 .....I~5 7./I l+a?)r.,;,.f .-_1'55~1 I ~ 190"I i.... t'-"_h,,' '$3371? f·~:J"f 3S"~1 /90,1 ~~"'t.,~,• t::,) ~--~--------~---_. 19.2 19.8 20.5 22.8 23.6 24.4 25.3 26.1 27.1 280 29.0 3).1 31.1 32.2 34.4 34.6 35.8 37.0 38.3 39,,7 40.1 42.6 44.1 45.6 47.2 48.9 50.6 52.4 Enstcr Retail Sales-rr:=r 1m Ie U-1.3 ES;!";;~w811.'5J'!''f ~~LET~AA..~BY l~m:.-Pl~.lM:~BCFf'~,r:.'r.iI",!lIf ~~~.-~Year I:rld . Fi~ld Q:er-Electric reneratioo Total Total Ranainilli!Reserves atlons&Gas Curulative men Plus Other Sales Mi 1itery All Otl'~rs Use hr.·...'r..s User (>rOvel ~an lhdi scoverErl~.......'In II ')(\3:1 '.')(\3 ----~--c..v I ~I.,c..v • 25 5 40.8 207 :0_../410.1 3130.9 5170.9 25 5,43.2 210.0 620.1 2920.9 4960.9 25 5 45.5 213.0 833.1 2707.9 4747.9 25 5.47.6 217.4 1050.5 2490.5 4530.5 25 5 49.7 220.3 1270.8 2270.2 4310.2 25 5 46.5 217.9 1488.7 2Of.e.3 4ce2.3 25 5 48.5 220.8 1709,,5 183L5 ~71.5 25 5 50.5 223.6 1933.1 1607.9 1347.9 25 5 51.8 225.9 2159.0 1382.0 3422.0 25 5 53.1 228.1 2337.1 1153.9 3193.9 25 5 ?D.954.5 230.5 2617.6 923.4 2963.4 25 5 3i t l55.8 232.9 2850.5 69J.5 2730.5 25 5 32.5 210.6 3061.1 479.9 2519.9 25 5 33.1 212.3 3273.4 267.6 2307.6 25 5 33.8 215.2 3488.6 52.4 2092.4 25 5 34.5 216.1 3704.7 (163.7)1876.3 25 5 35.1 217.9 3922.6 1658.4 25 5 35.8 219.8 4142.4 1433.6 25 5 36.8 222.1 4364.5 1216.5 25 5 '37.7 224.4 4588.9 9fQ.l 25 5 40.0 227.1 4816.0 765.0 25 5 41..0 230.6 5046.6 534.4, 25 5 42.0 233.1 5279.7.301.3 25 5 44.6 237.2 5516.9 64.1 25 5 46.0 240.2 5757.1 (176.1) 25 5 47.3 243.2 6(0).3 25 5 48.7 246.3 6246.6 25 5 .50.1 249.5 6496.1 Collier Amo1i a/ll"ea 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 55 ~ l .-- t- 62 62 62 62 62 62 62 62 62 62 62 62 62 62 62 62 62 62 ~ 62 62 62 62 62 62 62 62 62 62 ~ ~. Yeer 1982 1983 1984 1985 1986 1997 1988 1989 19~ 1991 1992 1993 1994 1995 1996 1997 1998 1999 2cro 2001 2002 2003 2004 2005 2tlX5 2fJJ7 2<m 200J 2010 H!.4.t_>t,~ 'r.~,::;"",:,..;....;; A .A• ,,\'.."'........'.'-\'~.....A .... Total 734.7 Other sales Refineries 0.5 Trans Alaska Pipeline System 11.9 Misc.0.2 1 1 f l~r . r 0.4 0.5 . 50.2 Quanity -BCF 671.0 Source:UHistorical and Projected Oil and Gas Consumption Jan.1983 11 ,State of A1aska t Dept.of Natural Resources t Division of Minerals and Energy Management,Table 2.7. Table D-1.4 CURRENT PRODUCTION AND USE OF NORTH SLOPE GAS FOR 1982 Use Injection Field Operations: Vented t Used on shrinkage Sales Power generation (civilian) Gas utilities (residential) 11\ IJj f '..1, ",.I, t, I,I~J l~; I" ..:,:;':.i ...,..- I~ 1,-~.., t:.1J '!L~ t " ;;}, :."),~",. fi i(:t;( t(, I} t~,~ t: t\~ /j o r \- I $2.32/Mcf 0 •.35 0.15 $2.82/Mcf 0,,30 $3.12/Mcf 1986-1997 $2.32tr~cf 0.0 0,,15 $2.47/Mcf 0.30 $2.77/Mcf 1983 ..1986 Table 0-1.5 . ESTIMATED BASE PRICES FOR NEW 'PURCHASES OF UNCOMMITTED AND UNDISCOVERED COOK INLET GAS . (l)Demand charge of $0.35/MCF on Enstar/Marathon contract applies from January 1,1986 on while demand of $0.35 on Enstar/Shell contract applies only if da'1y gas take is in excess ofa designated maximum take. (2)Severance taxes are the greater of $0.064/MCF or 10%of the well head cost adjusted by the "Economic Limit FacY,or."The economic limit factor is based on actual monthly production versus the w~ll s production rate at the economic limit.See Alaska Statutes,Chapter 55, Section 43.55.013 and 43.55.016.The t.ax of $0.15IMCF was estimated ba:-,ed on conversations with Enstar Natural Gas Co .. (3)Prices are es.ca 1 ated based on the pri ce of No.2 fuel oi 1 at the Tesoro R.efi nery,Ni ki ski,A1{iska beg;nni og Jan.1,1984.' (4)Estimated transmission charges would be about $O ..30/MCF.Per telephone conversation with Mr.Harold Schmidt,VP Enstar. Wellhead Price Additional demand charge{l) Severance tax(2) Total (unescalated)(3) Transmission charge{4) Delivered to Anchorage Without LNG Export Opportunities f"-;, '-.i ',; "r Jl! 1:,:'.1 i,i~ [i I, :.., 'it_ t' l- II-.;"""( ~',i~~. t, t, 1.- I- f.1 ..~:.."'" f: t li ;.-.( ':.4 L, !,', " I r 1 $3.00/MCF $5000/MCF $3.85/MCF $5.85/MCF Wlth LNG Export opportunities Table 0-1.6 ESTIMATED 1983 BASE PRICES FOR NEW PURCHASES OF UNCOMMITTED AND UNDISCOVERED COOK INLET GAS (l)Based on oil prices of $34/bbl alld $2?lbbl. (2)Based on implementation of the Trans-Alaska Gas System (TAGS) total System,.lower tariff.Trans Alaska Gas System:Economics of an Alternative for North Slope Natura'!Gas,~eport by the ."Governor I s Economi c Committee on Nort~Natura 1 Gas,January 1983.See Exhibits Cl,C2 and page 18 and 46 of the .Marketing Study Secti on.(Costs shown in the report were stated in 1988 dollars and were converted to 1983 doll ars using the reports 1 assumedinfl ation rate of 7%/yr.) (3)Oelivered to LNG liquefaction facility.Transmission costs assumed to be negligible. Maxlmum Price to Producer(3) Less :(2)t Conditioning 0.34 0~34 r t u Liquefaction 0.95 0.95 Shipping 0.71 0.71 Subtotal 2.00 2.00 LNG Price -Japan(l) l, i.: i I. I ,t. I; i~, L L I,,lo_ t ,t., 1,·\ l' ~," :~' 1'\ ,~,'-'; " ':i' ,"~I ,t,; I"~.j Total System Phase I System Low High LO\1J High Tariff Tariff Tariff Tariff.. Estimated 1983 Btu(1 )LNG Price Per MM $5.85 $5.00 $5.85 $5 ..00 $5.85 $5.00 $5.85 $5.00 Less Costs:(2) Shipping 0.71 Oa71 0.71 0.71 0..71 0.71 0.71 0.71 Liquefaction 0.95 0.95 1.18 1.18 1.00 1.00 1.26 1 ..26 Q Subtotal $1.66 $1.66 $1.89 $1.89 $1.71 $1.71 $1.97 $1.97 Minimum i983 Price(3)$4".19 $3.34 $3.96 $3.11 $4.14 $3 ..29 $3.88 $3.03 , ConditioningCost~4)0.34 0.34 0..42 0 ..42 0.42 0.52 0.51 0.51 Pipeline Costs(S)2.04 2.04 2.7~2.82 2.82 3.86 3.86 3.86 Wellhead Price 1.81 0.96 0.75 (0.10)0.90 0.05 (0.49)(1.34) [ !" I,; r J,.I t. t~, fL t, ~,~j i i I.. I i. f I L I·, i .;"' tJ) Tat"le 0...1.7 ESTIMATED COST OF NORTH SLOPE NATURAL GAS FOR ELECTRIC GENERATION AT KENAI ASSUMING IMPLEMENTATION OF THE TRANS ALASKA GAS SYSTEM (TAGS) (1983 Dollars/MMBtu) (l)LNG prices are delivered pr-ices to Japan and are equivalent to $34/bbl oi 1 for the $5.85/MMBtu price and $29/bbl oil for the $5 ..00/MMBtu price. (2)Costs in the report are shown in nominal 1988 dollars which were con- verted to 1983 dollars using an inflation rate of 7%/yr. (3)Min'imum price TAGS would accept from utilities for purchase of gas at LNG gas conditioning facility. (4)For pipeline from North Slope to Kenai Peninsula. (5)Maximum price that TAGS would be able to pay North Slope producers. S?urce:Trans Alaska Gas System:Economics efan Alternative for North Slope Natural Gas,'Report by the Governor's Economic Committee on North ' "Slope Gas,January,1983.See Exhibits Cl and C2 and pgs 18 and 46 of the Marketing Study Section. ;............ I trr .I? Value Used $/MMBtu N.A. 4.00 . N.A. N.A. Estimated Cost $lMMBtu· 4.03-S.30 3.96-4.19 4.80-6.08 3.84-S.12 Table 0-1.8 ESTIMATED 1983 DELIVERED COST OF NORTH SLOPE NATURAL GAS FOR RAILBELT ELECTRICAL GENEHATION (1983 DollarslMMBtu) N.A.Not Avail able (l)Cost of $3.80/MMBtu in 1982$assuming a zero wellhead cost was estimated by Battelle.This was adjusted to 198:3$to prcq'ide the $4 .•03/MMBtu.The $5.30/MMBtu includes an assumed well head cost of $1.28/MMBtu. (2)Costs estimated using a linetback"approach.See Table 0 ...1.7. Value of $4~OO/MMBtu selected as reasonable value for thermal generation alternati qes analysis" (3)Costs estimated using capital and 08iM costs from Reference 3t. The cost of $4.80/MMBtu assumes a wellhead price of zero while the $6.08/MMBtu price assumes a wellhead price of $1.28/MMBtu. (4)Costs estimated using capital and O&M costs from Reference 31. These costs are "equivalent u costs for the gas would be burned on the North Slope and the electricity delivered to Railbelt load centers via an electric transmission line.The "equivalent"costs were determined by comparing the costs of the electri,c transmission line with the costs of the gas pipeline to Fairbanks.The $3,,84/MMBtu assumeS a wellhead price of zero and the $S.12/MMBtu a wellhead price of $1.28/MMTbu. Delivery Method ANGTS(l) TAGS(2.) Pipeline to Fairbanks(3) North Slope Generation(4) i t t i~ i I. t L f {:I ::.,.1. f,I ,~ t., ~<'!., ;! '~"" f s*,u ._...,''~:lr'.""'" i~--~L··:'.".f -..,.,.'.<,0..~~'"~;.,~.",.,.-w ,.?.•.•...'~',,"I.~',...:.'~'. J'....~"¥~\ .;i$, .",-~". ~~ "".I EA."]'~:f~~_-"1~e-.".~ .J~ Tebl e 0-1.9 (9leet 1 at'2) Fffi:iZCTEDCOO<Irl.ET \£LU£PD W\1l.M..6l\S ffiICES•In 1983lbl1 irS Per WBtu ---.- t .. 1~.~1.64 1.28 1.56 2.41 2.47 1.94 2.ffi 1.79 2.10 2.07 2.19 1.992.14 1.97 2.12 1.95 2.11 1.83 2.00 1.76 2-"02 1.13 2.00 1.65 1.92 1.63 1...00 1.59 1.87 1.57 1.79 1.53 1.79 1.52 1.78 1.51 1.76 1.48 1.7'4 - .-. 2.71 2~89 2.54 2.l3 2.47 1.97 'to!::..;;..ou 2~18 2",14 2.1i 2.20 2.23 ~t.. (IXR IXR 1m Ye~.~CIl)n;.~ ~::. 1003(1) 84 85 $(1) "Q7 88 89 19ro 91 92 93 94 95 96 97 98 99 20CiJ 01 02 03 04 ffi 00 07 00 00ano ~ t-·-:-~Ke.YiM ~::::~ C)-, '.''';''''"'••~'_'.....'..II .-_.•'~'''------_..)."'.-'v'.:'".&'"..1I~.,....,.·._--pil"IiIIll"!P~~!!! ;.'"I.:Q'":.....~.~.f _4:...r'y.~')-~~.~..."...-.~-:...(I:..J i(G.J .-':Jo ':';-..~..I "-:f ~,olt -.•0 of •.V"I:. •.'~••~I)l'~q ..It·_0 ~f .".'Po ••.....'lfj)...~...~....'p .-"""1-f.f Q or"ot ~".' •~....••'../l.o',b __,,',.• ....,.~...~..\........r r' D -i:: r:::;; o ,: I'" r-~.,,";)i~1 .-.< L,,,,ijiiiI!!IIl 0.87 0.96 1.00 1.17 1.lJ 1.44 j",,","'~' 1.54 1..62 1.71 1.79 1.89 1.00 ~ 2.73 2.73 ~ 2.73 2..73 2.73 2.73 2.73 2.73 2.73 2 "'7").;;; 2 ",,~,.liJ '1.73 -OX;/yr;,..1.-o/yr.·2.fJlJyr. ..~t,;--- .Coostcnt O1tnge Cases I:'-~-~ 7.61 8.40 6.89 6•.24 5.65 5.12 -.of?'}"9q ~,.~ ~ ~...'11 ---,-#'0(000 7073 7.81 7.00 7.97 8.ffi 8.13 , Refereoce Case (91errna1 Gl crt< - .NSDCase)......"- 5.00 5.20 5.33 5.47 5.00 5.74 5.89 6.04 6.19 6.34 6.44 6.53 6.63 6.73 6.83 6.93 7..M 7.14 7,,'6 7.]5 7.43 7.51 7..58 ~"~1 7.34 7.46 6.68 7 "~.tJJ 7.91 8.03 8.15 8.27 8.40 8.40 8.40 8.40 8.40 8..40 8.40 8.40 8.40 8.40 8.40 8.40 8.40 8.40 8.40 8.40 8.40 8.40 8.40 8.JOe.-.J 8.40 ~ Shenn&l Cl ark .Base ·Case·. Teb le D-1.9(9leet 2 of 2) mo.:ECTEC COO{IM..ET \tI:LLf-EM W\11.RJl fASPRlCES In 1003 fbll ars Per OOtu -,~ JC,,",~~r' -f_ lXR OCR au•I!.sox Spring 1~ /l!I""",,',,,", 5~81 5.37 5.93 6.00 3.00 1.18 1.47 6,.00 6.07 6.13 6.3) 6.•V 3.28 1.10 1.39 6.34 6.41 6.48 6.55 6.62 3.5n 1.10 1.32 6.•69 6.77 6.84- 6..92 6.99 J.74 1.10 1.25 7.07 7.15 7.23 7.31 7.39 3.99 1.10 1.18 7.47 7.55 7.63 7..72 7.00 4.25 1.10 1.127.89 (OCR ~~CIll it"'",,,'"• f~)Estimata:l .1~tyice of Cook Inlet gas ffOTI Tcble 0-2 ..5. (L)Pdditiona't damn:)charge of $0.35/r-M3tu ~lies fran 1986 fClrW"d ad is escalated by ,rice of oil chCllge. 2011 12 13 14 2015 16 17 18 19 lD20 21 22 23 24 2tYiS 26 27 28 '"J() c.:/ 203) '3"(,1 32 33 34- 2G35ro 37 ,&1 39 2000 YEAA.,.....- -,. r} l'll:::e5:,~ k:~ ;)iin""c",'~M'"".".T .."ft-'tl '$I~,.;,~-..-•.•...•,,,.~,......~_~~u .,.,.•'....• r~~,t~,~,.../(~.,.1~"'1'~~,~1:••»$.,~~~ c .. - Tcble D-1.10 (Sheet 1 of 2) PROJEC:ijJ fmlH SLCPE DELIVERBJ NAllRJlLGPS PRICES In 1983 I})llars Per MJBtu -.-.-~ :'" Refererx:e Case Consta-rt:Chgrge Cases {OCR OCR OCR IlU 5rennanCl irk ($rennan Cl irk ~ YEJlR ~Cll)~50;;,~1~Base Case NSD Case),~:fI ~~fu··-lj?fI.-2.fJYo/rr.. I98j(1}-4.(jf 4:00 4:00 .~--'.00 •~Jx) 198-1 3.31 3.14 3.32 3.48 3.82 3.82 4.00 4JXl 3.96 3.92 1985 3.13 2.00 3.40 3.73 I 3.64 3.64/4..16 4.00 3.92 3.84- ~fl36 3.09 2.81 3.05 3.98 3.64 3.54 4.00 1007 3.0.1 2.70 2.97 4.23 3.64 3.64 •4.00 1988 3.07 2.66 2.95 4.51 '3.64 ~5 z '~tf 4.00'•.,?Ib '. 1989 3.11 2.64 2.91-4.00 5.53 3.86 4.00 1900 3..15 2.48 2.9:>5.11 5.53 ~F3 (,4.59 4.00 3..73 3.47 1991 2.38 2.81 5.69 4.00 1992 2.34 2.78 5.86 l/tzt" 4.00 1993 2.24 2.66 6..Q:1.4.00 1994 2.20 2.61 6.22 4.00 1995 3.26 2,,15 2.59 6.34 6.41 4.61 5.07 4.00 3.55 3.14 I II 19%2.1~2.49 4.00 I 0 1~7 2.07 2.48 4.00 190J8 2.ffi 2.46 4.00 1999 2.04-2.44 4.00 2OX)3.59 2.01 2.42 7.39 7.43 5.35 5.60 4.00 3.37 2.84 :'.:> 2001 4.00 2002 4.00 2003 4.ffi 200II-4.00 2005 3.83 1.86 2,,29 7.81 8.82 6.20 6.18 4.00 3.21 2.56 2~4.00 2007 4.00 2003 4.00 200J 4.00 2010 4.00 1.73 2.16 8.24 10.48 7.18 6.83 4.00 3.05 2.32 2011 4.00 2012 4.00 2013 4.00 I (\ 2014 4.00 2015 4.)5 1.60 2.05 9.20 11.29 8.13 7.54 4.00 2.00 2.10 , I \' -,1".;;;:.'... _<,t "'-'~..=.W_'~·.,.W~i'f"_.-~eff l'_.'.",~-...~u ~-"'-~I!iiiillIRw:"._.~.,",."',._~ TOO1a 0-1.10 (Sheet 2 of 2) PROJECTED NffiTH Sl(FE DELIVERffi ,W\TlRPl &l\S PRHLS In 1983 [b11 ars Per '.M'43tu ~--------~--~- L o I .I I L "~~~~ ~t,~~.4J.r #~~ 2.26 1.26 o ,0 2.37 1.40 Q l/ 2.49 1.55 2.49 1.55 2.62 1.71 2.76 L89 ~r'Ji.'~;.-) -l.O/yr.-2J:g/yr ., t'"~ ~tt). 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4..00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 ,:.' l"'; c--''!!!"",~ 8 ..32 9~19 +2/yr 12.37 11.20 10.15 1.il!!'-,J 9.91 9.20 11 ..79 11.22 10.67 Reference Case Shennan C1 ark rtiO Case . ~~ 12.16 12.16 12.16 12.16 12.16 12.16 12.16 12.16 12.16 12.16 12.16 12.16 12.16 12.16 12.16 12.16 12.16 12 ..16 12.~6 12.16 ~ Shennan C1 a'k Base Case - <:::.\ --- ._~-----~-----------~._. .';<;:, ~~ ,-----'-.Y'"'": (l)Estimated 1983 p--ice of North Slope gas fr'an Teb 1e 0-1.8. (OCR IlR L ,~~.001 YEAA ~CIl)D,(50%S!Jri ng 19832016--- 2017 '2018 2019 2020 4.65 1.49 1.91-9.20 2021 2022 2023 2a24 2025 4.93 1.49 1.83 9.71 2026 2a27 2028 2029 2(3)5.29 1.49 1..73 10.26 2.031 2032 2033 2034 2035 5.641.49 1.64 10.84 2036 2037 2Ol3 2039 ID10 6.02 1.49 1.55 11.45 .--I,__~ r 100% 472,713 ..6 7341.7 239,27?..2 182,c:"):..i1 44,063,9 Total U.S. 1.3% Alaska 697.5 5,443.0 14 ..0 Percent of Total Type of Co a1 Total Anthra~ite Bituminous Subbituminous Lignite Table 0-2.1 DEMONSTRATED RESERVE BASE IN ALASKA AND THE UoS.BY TYPE OF COAL (values in millions of short tons) Source:Demonstrated Reserve Base of Coal in the Urited States on January 1,1980. t ~'~,j , I f '1 : I ( I [1 I·1,J 'i ,tJ 1It~~~ Source:Energy Resources Co .•1980. I ·1n t I 457 6,938 a / 862 2,700 3,377 Quant i ty (tons x.10 6 ) Table 0-2 ..2 Total Measured Indica\:ed Inferred Reserve Base Resources R.eserve/nesource Ty~ RESERVES AND RESOURCES OF THE NENANA FIELD < ~/Totals do not add due to rounding on measured and inf,1rred. i~ [ [1' [",; :...1., ~: L l' \,,-~ [ t ~,l;,I t1 ~j ~ I i I i, t, L l.,tc '., 26.1 6.4 3.6 47.2 15.5 1 .05 0.12 26.1 6.4 36.3 31.2 Weight P€rcent 7,950HigherHeating Val ue (B t u/ 1b) Proximate Analysis Hydrogen Carbon Oxygen Nitrogen Sulfur Chlorine Moisture Ash Ultimate Analysis, As Received (wt %) ~1o;sure Ash Vol ati le Matter Fixed Carbon Hazen Laborat&(y Analyses for fairbanks Municipal System. Table 0-2.3 PROXI~ATE AND ULTIMATE ANALYSIS OF NENANA FIELD COAL Source: ____________--r- ~-,: ", J I. I L [,J , J I . ,..J' f..'~J ~4 ;~ J [ E 1 [ I Ir, <) 7800 45.4 2.9 0.7 14.4 0.14 7.9 28.0 .. Diamond-Shamrock'£/ Alaska Coal Co. 7536 0.18 1.6 ..0 21.0 Battell eE../ Wat er f a 11 Searn L 7200 Table 0 ..2.4 ULTIMATE ANALYSIS OF BELUGA COAL 44.7 3 ..8 0.7 15.8 0.2 9.9 24,,9 Stanford2./ Research Institute Ana1 yses'---------------~~~-.;;..;;..~------------- a/Stanford Research Institute,1974 ~/Swift,Haskins,and Scott,1980 ~/Diamond Shamrock Corporation,1983 Higher He at;ng Value (Btu/lb) Moisture Ash Hydrogen Nitrogen Oxygen Sulfur Carbon Element! Compound .(w-t%) ~.p ...~ f:l,I l I I I Ij tJ L,j (·HII:J Heat Location .Rate f~Jty~ TaDle D-2.5 COAL FIRED GENERATING CAPACITY IN ALASKA I ! I II . I \. 1:7\'> 87 29 20 13 25 13,000- 22,000 13,300- 22,000 20,000 12,,000 13,200 N/A Healy Fairbanks Fairbanks Fairbanks Own,er ------------~-----:".:;::;. Source:Battelle,Vol VI~1982. Total u.s ..Air Force Ft.Wainwright Fairbanks Municipal Utility System University of Al ask a Golden Valley Electric Assn. L I l(,~ j f l rL 30.4 8.7 11.1 11.6 4.1 3.0 3.8 72.7 I Market Share 41.8 11.1 15.3 16.0 5.6 4.2 5.2 100.0 -Percent ag!.Mi n i on fansNation Table 0-2 ..6 PROJECTED NATIONAL SHARES OF JAPANE~y COAL MRRKET FOR IMPORTS IN THE YEAR 1990- AllOt h tF': To't a1 South AfrL~a USSR China United States Canada Australia a/lncl udes steam co al and meta11 urg;cal coal. Source:MRI.1982 t lJ t j l f J i fI .' i I,J I) t: [:~ •.J r;~;1 ",l ;" rl r.J f'1 -~-. J" t ShiEpingCost Value of Coal(S/ton)nlton)(Slm;r-="l......i-on-.;.:i3~t-uT-Value of Coal ~)- Table 0-2.7 THE VALUE OF COAL DELIVERED IN JAPAN BY COAL ORIGIN (Jan.1983 Dollars) Australia.~1 $45.00 10.50 $55.50 $2.49 South Africa b /37.50 15.30 52.80 2.37 Canad aC /45 .00 10.35 55 .35 .2.48 Nat i on of Coal Origination !/From Sherman H.Clark and Associate~~1983 b/from Diamond Shamrock Corp.,1983 ~/Assumes)1,160 Btu/lb per Japanese Specification in Swift,Haskins,and Scott,1980 .. ~t t, t i ~ i i"J 1"J I- II f ·1, . fr k. J of I o $0.51 $1.94 $2.45 $0.04 Hi gil $2.49 Low $0.55 $1.78 $2.33 $0.04 Value of Coal --"-($7MTI1 ion Btu) .........>..=::: th-.U Table 0-2.8 THE MARKET VALUE OF COAL FROM THE BELUGA FIELD FOB GRANITE POINT~ALASKA (Jan.1983 Dollars) Net Value of Coal in Japan Cost to T~ansport Coal~/ Net Value of Coal at Granite Point a/From Table D-2.7 b/S ee Swift~Haskins,and Scott (1980)analysis on Waterfall -Seam Coal~pp.7~5,7-6. c/Cost is $8.00/ton.Low value column reflects 7200 Btu/lb -coal and high value column reflects 7800 Btu/lb coal (see Tan 1 e D-2.4)• The Value of Coal in Japan~/ Price Discount Based up ~~the impact of ]ower q~'a 1 ity on plant capitalcos~s (J .•6%)b/ .- L r t t t t't 1 t t 1 l 1 L l t l L L L L f\. I Coa 1 Location "'\F"D13 ) Mine Site Ttonslyr) 10 mi 11 i on shi p 1 ..20-1 .70 7 ..7 mi 1 1 i on shi p 1.27-1 .65. 5 mi 1 1 ion mine 1 •16-1 0 74 Table 0-2.9 PRODUCTIO~COST ESTIMATES FOR BELUGA COAL IN 1983 DOLLARS !/A11 previous estimates escalated by the implicit price b/deflation series. --I Sou r ce :Sty 1 e s,1 98 3· %/source:Bechtel Report for H-a~W {Bechtel,i980}. --Source:DOE,1980. Source Di am on d A1 ask a.2.1 Bechtel£.I P1 ac er Ame.x£1 ~",,, r - $0.32 8.52 1.08 1.77 0.65 0.79 1.64 0,.35 $15.1.2 -·3;9-7- $1.90 ?2'"_..) 2.65 $28.52 33.52 39.70 ..C~ase 2 3,000,000 30 5.89 194 176 56 426 28.2 $186,321,000 $62.11 $353,450,000 $2.72 · 3.20 3.76 $0.60 9.19 1.11 3.05 1.24 1.22 2.96 --0 .a-5_. $40.85 47.99 56.40 $25.82 $19.72 ,-·6·.·1:0-·----- 1,000,000 30 5.93 81 74 ...a-3' 188 21~3 $101,041,000 Annual Ton$101.04 $183,027,000 MM·'Ut uJ (·a·) -.''-.~ Average Total Cost (Per Ton) Total Cash Costs Average Depreciation ··ea-se--l I Table 0-2.10 BELUGA AREA HYPOTHETICAL MINE SUMMARY OF SELECTED DATA Drainage Control and Reclamation Stripping Mining And Hauling Coal Caal Handling And Transporting Haul Road Construction And Maintenan ~e General Mine Services Supervision And Administration Production Taxes And Fees Tot al Tons Per Man~Shift (Average) Initial Capital Investment Initial Capital Investment Per Life Of Mine Capital Required (a)Assume~7.500 Btu/Lb. Source:Mining Cost Estimates,Beluga Area Hypothetical Mine, Paul Weir Company,June 27,1983~ Aver age Co alP r ices -(Per At~. At 15%R.O.R. At 20%R.,O.R. Note: g Production Rate Per Year (Tons) Mine Life At Fu·l ~roduction (Years) Average Stripping Ratio (BCY/Ton) Pe·r s o-n n el .('A v e·ra g-e ) Operatlng Mai nten anc e Salaried ~ I i ( I I 1 l' l Av~ra2eAnnual-0p~ra-ti o-g CO$t-s -(-per--Ton) Table 0-2.11 SOME PROJECTED REAL ESCALATION RATES FOR COAL PRICES Real Esc a 1 at "on Rate to 2010 -%Coal Bel ug a 2.1 Nen an a 2.0 Beluga 2.6 Nen an a 2.3 Bel ug a 2.5 Nen an a 2.7 I! - Forecastor Acres (1981)!t 1 Acres (1982 )£/ Battelle (1982)ai a/Secrest 'nd Swift,1982. !t/Diener!1981 • .s./Oiener,1982. i i I I ('"' 1 ;! .>.i _______--•..0=:-.____ 2.9 2,.3 1.6 2.6 Long Term Real Escalation Rate ..% o~:) ,x I1'11-"';"t •Coal Types New Coal Contracts and Spot Mar ket Co a1 Western Coal a / Western Lignite~/ Coal Exports New Coal Contracts Table D-2.12 COAL PRICE REAL ESCALATION RATES Sherman H. Cl ark Author DR! Sources:DRI.1983;Clark,1983. a/HV of 10,000 Btu/lb. tr/HV Of 7,500 Btu/lb. t ~ 1 i t I.~ 1 I. f -l _~r I . I rat es ) rates) rates) rates) rates) escalation escalation esca 1 at ion escal ation esc a la,t ;0 n (0 i 1 (oil (oil (oil (oil 0 ..09 0.15 0.18 0.21 0.23 $0.23 + 0.36 +=0.42 + =0.49 + 0.55 + Table D-2.13 Nenana = Willow::: Matan us k a Anchorage Seward = Transportation cost equations:(1983) Healy to: NENANA COAL TRANSPORTATION COSTS FROM HEALY TO GENERATING PLAN LOCATION (1983 $/MMBtu) Notes: Pl ant Location Year Nenana Wi1 low Matanuska Anchorage Seward 1983 0.32 0.51 0.60 0.70 0.78 1984 0.30 0 ..48 0.57 0.67 0.74 1985 0.30 0.48 0.57 0.67 0.75 1986 0.32 0.49 0.~8 0 ..67 0.76 1987 0.33 0.50 0.58 0.68 0.77 1988 0.33 0.50 0.59 0 ..69 0.78 1989 0.34 0.51 0.60 0.70 O~79 1990 0 ..34 0.52 0 ..61 0.71 0 ..80 1991 0 ..35 0.52 0.62 0.72 0.81 1992 0.35 0.53 0.63 0 ..73 0.82 1993 0 ..36 0.54 0.64 0.74 0.84 1994 0.36 0.54 0.64 0.75 0.84 1995 0.36 0.:15 0.64 0.75 0.85 1996 0.37 0.55 0.65 0.76 0 ..86 1997 0 .•37 0.55 0 ..65 0.76 0.86 1998 0 ..37 0.56 0.66 0 ..77 0.87 1999 0.37 0.56 0.66 0.78 0.88 2000 0.38 0.57 0.67 0.78 0.88 2001 0.38 0.57 0.67 0.79 0.89 2002 0.38 0.57 0.68 0.79 0.90 2003 0.39 0.58 0.68 0.80 0.90 2004 0.39 0.58 0.69 0.81 0.91 2005 0.39 0.59 Oa69 C.81 0.92 2006 0.40 0.59 0.70 0.82 0.92 2007 0.40 0.60 0.70 0.83 0.93 2008 0.40 0.60 0.71 0.83 0.04 2009 0.41 0.61 0.72 0.84 0.95 2010 0.41 0.61 0.72 0.85 0.95f L ~ I\, I I' I -I I',I I u Bel juga F;el d _.~~ With Exports (1.6%/yr) 1.86 1.89 1.92 1.95 1.98 2.01 2.05 2.08 2.11 2.15 2.18~ 2.21 2.25 2.29 2.32 2.36 2.40 2.44 2.48 2.51 2.55 2.60 2.64 2.68 2.72 2.77 2.81 2.86......-- Willow (2 ..2%/yr) 1.91 1.92 1.95 2.00 2.05 2.09 2.14 2.20 2.24 2.29 2.35 2.40 2.46 2.50 2.56 2.62 2.67 2.7£1 2.79 2.85 2.92 2.98 3.05 3.12 3.19 3.26 3.34 3.41 Nen an a (2.2%/yr) 1.72 1.74 1.77 1.83 1.88 1 ..92 1.97 2.02 2.07 2.11 2.17 2.22 2.27 2.32 2.38 2.43 2.48 2.55 2.60 2.66 2.73 2.79 2.85 2.93 2.99 3.06 3.14 3.21 Nen an a Fie "d C0 a1 De 1 i v ere d To Mine Mouth {2.6%lyr./ 1.40 1.44 1.47 1.51 1.55 1.59 1.63 1.68 1.72 1.76 1.81 1.86 1.91 1 ..85 2.01 2.06 2.11 2.17 2.22 2.28 2.34 2.40 2.46 2.53 2.59 2.66 2.73 2.80 Table 0-2 ..14 ESTIMATED DELIVERED PRlrES OF CDAL IN ALASKA BY YEAR (In 1981 S/Btu xIO G) Q 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 . 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Year i fr IC.~..!~.J t o F~l ~~I'~{\ g ~I ~~I r I I I I I I ! t' I l\rv IIn 11) j I I I Ii. I Location 6.87 7.46 6 ..23 7.02 Anchorage Fairbanks•Type Fuel Table D-3.1 PRICES OF TURBHilE AND DIESEL OIL F'OR ELECTRICAL GENERATION -1983 $/r~MBtu Diesel oil -No.11/ Turbine oil -No.1-26/ 1/'Based on (Nerage of pri ce quotes from Chevron and Tesoro Oi 1 Companies of.about $0.95/gal.for Anchorage and $1.03Igal.for Fairbanks (June 1983)the heating value is about 5.8 X 10 6 Btu/bbl. 2/Based on price quote by Tesoro Oil Comapny of $0.86/gal.in Anchorage and $0.97/gal.in Fairbanks (June 1983)the heating value is about 5.8 X 10 6 Btu/bbl. f.t fI, G..',f'~I./_• .,.-Q .. ---.~~~~.~~~1!111_- ,..,,,........,,,.,~.'"._'.~~~f'~'~"..-t::',;o:..","~"Y •.~.~"C<~~-'·"-,.·,;k··fI"...,...~·'·"'~il~'.'.~,~-"p::"~-., Tcble 0-3.2 PRtXECTED PRICES (f DIESEL JW)TlBBI~FlfL AT ~ FeR VAAIOOS OIL HUCE SCENPRIos¥-1983--2010 (1003 $/OOi:u) !?""---.-',....,.,:,~':i'~"'"~...~.~==,~~., (? -- 6.87 6.23 6..87 6.23 6.00 6.17 6.73 6.11 6.73 6.11 6.60 5.98 ,,)I 6.67 6..04 6.47 5.00 6.60 5.00 6.34 5.75 " 6.53 5.92 6.21 5.63 6.47 5.87 6.09 5.52 6.40 5.81 5.!:Xl 5.41 6.87 6.23 6.87 6.23 6.87 6.23 6.876.23 6.87 6.23 6.87 6.23 6.87 6.23 6.55 5.94 6.55 5..94 7.01 6.35 6.25 5.66 6.25 5.66 7.15 6.48 6.25 5.66 6.25 5,,66 7.29 6.61 6.25 5~66 6,,25 5.66 7.44-6.1'4 6..25 5.66 6.2>5..66 7.59 6.00 9..50 8.62 6.43 5.83 7./~,7..fYl. 9.50 8.62 6.63 6.01 7.89 7.168.78 7.97, 6.87 6.23 5.97 5..41 6.41 5.81 12.69 11.51 12.78 11.58 8.91 .8.00 9.62 8.72 6.87 6.23 5.79 5.25 4.87 4.42. 10.00 9.88 11ofYl.9.99 7.68 6.97 8.71 7.00 6.87 6.23 6.00 5.52 5.39 4.89 uSee Exhibit B Section 5.4 for JrOjected rates of choogein oil rr-ices. ~Prices fran Toole 0-3.1- lXR IXR IlR au SH:A Refermce '--.------GJnst~-Rates-,of .(h~., . ~iI1 .n 50X Spring 1983 Basocase Case +3Jyr.-"rR/yr.-=:n"r.'7yr~.:;;"';'--~_~I'I:llI""'/yr--.-"" /Year Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Ttxbine Diesel·TurbineDiesel·Turbine Diesel-Tt.rbine Diese1·Turbine fljesel Tlf'bine'----'-.,_........-....:za I'n _'•.• 6-=' c_ ..1J6.S7 6.23 6.87 6..23 6.87 6.23..',".·-1 Ji_L Nt 1984-5.69 5.16 5.39 4.89 5..70 5.17 1~5.:£4.00 4.00 4.51 5.84-5.D 1~5.31 4.81 4.82 4.37 5.23 4.74 1987 5.21 4.72.4.63 4.2)5.10 4.63 1989 4.57 4.15 5.00 4.59 1989 4.53 4.10 5.04 4.57 1~5..49 4000 4.25 3.85 4.99 4.52 1991 4.10 3.71 4.82 4.37 1992 4.01 3.63 4J7 4..32 1993 3.85 3.48 4.57 4.14 1994-3.78 3.42 4.48 4.00 1995 5.85 5.24 3.70 3.35 4.46 4..04 19S6 3.64 3.D 4..27 3.00 1997 3.55 3.21 4.26 3.00 1998 3.53 3.a>4.22 3.83 1999 3.50 3.20 4.a>3.81 2(00 6.24 5.52 3.45 3.15 4.15 3.76 ... r I I •CHICKALOON!~A y ELECTRIC ••••TRANSMISSION LINE••a ••••....... ••••• ')...-.•.. \_.OH.,.FI.iO~nS WITH GAS •GAS FIELDS •:•..••a•••:•:••••••••...•...'_.:::..<t:".••• ,"~.1'.........tQ~•• <1')",•• .e......."t-";r •• .•WEST FORK ...~..........---...... ............STERUNG . KENAI FIGURE 0-1.1 ........"lEWIS RiVER".···••••••• IVAN RiVER •••• If JS~ANSON RIViOR COMPLEX AT NtKISHKAAm. ~BEAVER CREEK COOK INLET GAS FIELDS MIDDLE GROUND SHOAL ---- MOQUAWKle, •NORTH FORK :;0;:, ••• CHICKALOON/SA Y ELECTRIC ••••TRANSMISSION LINE••••0 •••••....-.v .•.......•• I;O.Jl..FI(;~O$W.•ITt!GAS •GAS FIELDS._-.------' -<I •:•••.....••••:•••..•..••..••••••~<:v.••o \.~~.,_v •• r(l~". e...q.,e••• ...":;lI •• .•WEST FORK ..,.';.<1'••...._.~ •••-••••••STERUNG KENAI FIGURE 0-1.1 c .......- LEWIS.RiVER ••••• ••••• •• IVAN RIVER ..••.. JSWANSON RIVl:R COMPLEX AT • NtKISHKA. •BEAVER CREEK COOK INLET GAS FIELDS MIDDLE GROUND SHOAL MOQUAWKle, ~ KALGtN ISLAND ¥ &8 t L L I I I ~ C ~ I ~ I I r I lXR lXR OCR [lU SH:A Reference""---',--Constffllt -Rates-of -(hiJlge~tr1n .'.50:'~ing 1003 Basecase Case .+2-1yr..rJfTyr.'•.-1%l....yr~.:.;;..--=.--_....a;1P"P/yr---.- (ear Diesel Turb;neDiesel·Turb;ne Diesel·Tlriline Diesel-Turbine Diesel-Turbine Diesel-Tlrbine DieseT·T....rbineDiesel·Tlriline Diesel Tl.I"b-ineDiesel Tlri>ine..-.......:-.-.....,..-.- 3.72 3.37'14.16 12 ..84 18.02 16.33 11.97 10.85 11.73 10.63 6.87 6.23 5.24 4.75 3.~3.61 3.933.56 13.40 12.16 15.17 13.75 10.32 9.l>10.62 9.63 6.87 6.23 5..51 4.99 4.403.99 !)I ,'1r.~~:"~r.t";r",--'~-~~'"~-~~t=..,·_~--""~,~",---:~~,,'"':-:-''''''''''.t-''' --~~~~~~f'J"":!It ..JIliI8.filii ~~:.-.-.~"~. T<ble 0-3.2 POO:ECTED PRICES (F DIESFl JW ~~FlfL AT ~ FCR VAAlOOS OIL mICE SCE~I~'j"1!m-2010 (1003 $/MVBtu) ~"--..p-~~""~P"."r-,,"_~ 2.97 2.71 3.202.92 ~'-,...,..--~~ G ,nJl ~..~ll"VY)~,ir ",..:\AJC. .i.··!X)3 C'".".,~;_.2OJ4. :.t·..nE 6.66 5.81 ".'.~i~.:2007 "-..';<~.•\'2al3 ,-'~:;,_,-__1-~-,.$';,'"(!IllY f:/,:2()10 7.10 6.12 <~.... ';:) ,2) '"~,-~}''t.',.tt~l '1#'j~l • _ \) .,"t."D <..I " I I ! 1 I1, l~ 1 I I L f r l fi f I I~'-" III l n II ,- I'i ""~~j<.~"~~~~.".,.~••,._.--.:~ --~~~e1b,§~r'''':1iI ~&II ....... .~~.~--:¢-~ A1ISki Oil and ~!ConI.rvlt1on eo..1ls1on. Plrt 01 ~~;w1ll b.tlk~frOM K.nli Fiald. ,Partfcipant in exploration underwlY in 1980. lased on QeGolyer an~MacHoUghten res.rvi .sti••te 1ft 1'71. Uncertlin royalty stltuS.. Royalty gls. This figure ISStIN'thlt Tok)'O SIS Co.end Tokyo Electric Co.c.ontrlllCts w111b••t by III fr.tM Cook Jn1et field.In Ictua1ity.I significant port1on 11 lupp1184 ~y the Klftli field. Est.1l1\atecf gas IVlillbl,onblowdown. PALNG's lIt.st.st1Mlta Df the1rprevfously cc.1tttd rl.erVI 11 980 Icfl.u the 220 lost to (nit... Thh160 let is 151 gr.Iter thll1 thesLdof qultJt1t101 frc.the individual fitldl-.It is notkno-.n fr. which fi.lds thl tdd1tional 151 Bef would COfII. l~l(~l Iii (8) e') r ..~-r'~F'~' Petfte ChuglCh Collt.,.PM1l1pl/SOCAl Ahsta II<:0yerilb 10 Electric .Clrbonl Marlthon ARea UncCMM1ttt4 LNG .eserv,slLl !nstar Assoc..'l Ch ..1cll LN6 Rent,l Reserves Assoc. "w,r Crtttk 240 250(2).-..o......0 Be 1091 Riv.r 142 220 285 ,237 404....••...... Birch Hill 11 ...-...••......11 Cannery Loop iliA _..oo .-.....NlA (J) falls Creek 13 oo......••...oo 13 _... lvanR1vlr ft ......--......II lCf 'i Klldachlbunl tVA •oo ....oo .MIA .....oo ... Kenli 1,109 '251 ..(5)317 250 101 120 .. Lewis Riv.r 22 .......••....22 11(4) McArthur R1vtr 90 .....oo....-..-go •• Nfcol11 Creek 11 --....._.o...-11 •• :1Ii ...k_<I North Cook In1 It 151 27(1).......-110(7)..114 .- North fork 12 .-.....-....••12 -I I M.Midd1.Qround MIA .........-...IIA •• Sterling 23 ............-..23 •• I Stu.p lMI NlIt ...-..••..-NlA .....SWAnson Riv,r .._.....-....25'(')... Trii1 Ridgl MIA ...._......MIA ••Tyonek -MIA .0...oo.--_....•• Wut forl1l,t4 20 ......._...-.20 •• Total 3,541 151 Z8!5 ..377 JF.D 106 1.'54 760(') Nohs ESTIMATED'COOK INLET'NATURAL GAS'RECOVERABLE'RESERVES' AND COMMITMENT STATUS AS'OF'JANUARY 1,1982 (~'I \_, i FIGURE 0-1.2 I t~$~•......_,.__.__~__.._._._._.~..._..__-~~~~__----.,_.__~_-,---.'----.-.•----..---------~--------.-'.-..._._.__~_______.,_..__'..,_._I_.__~.~:_~J ."~"~""~'."'----'---'.~----_.- ____________________________u:-, Co I,:\ ! 1_~~IL"'-?4t{'IFL~ 1 •.\...-' I FI..Jt.R:0-1.3 ~.~ CUF OF H..AS<A SlOfJE , \-~ -~\....~_.J , \r-\-_.. 61 ,;.11 ,..- ,-'","r"67 I,.. r~ 21 --~~~Q!!,'!;'Sil e'·"'5iA ~c_''fi &;;1'1 .II\1II .. 16 rr-r'P"""~~.,~ ~,••.,SHADING DENOTE,S ~OFFSH2'RE AREAS ~.- AREAS OF ALASKA ASSESSED BY THE $OLfICE:u;s.DEPAAlMENT OF 1}£INTEAIOA U.S.G.S.FOR UNDISCOVERED RESOURCES GEa-OGICAl SLflVEY.OPtNTILE REPORT 82-666A,1&81. r=-" I I t I I I 1 ! I I ' I oZz <0-0 ....Wo..>:ea::::> W(J'J (J)ZWo 0::0 cnUJ <>0-....-1<<-I 0:::.') ::J:E....:::> <0 Zc t-W UJ .... -Ie( ~:s-~I- 0°OW oi- I:•- •lit •c••~)10 I• •! •~ I I t i .~> u I I I I I- .1- ell--4~T--r---.-!I I,'I II'...._UIlUUW L t. III f~~ti ~ ~ ~ ~ I I I I I t ! I, 1 t I t,I I I !I c: i II I J $52.3,x 10 6 200 KW $2.340/k. IS% 1.5 x 10 9 kwh $1.70/MMBtu ',750 Btu/kwh $0 "OO32/kwh 3.5% 35 year. -" UaitSiae Ua.it Capital Coat A••llahility ADnual Qea..ratl_ J'ua I eo.t 1leat.bte o •II Coat ...1 Co.t of Capital Icoaa.aic LiC. To,tal Annual Coat. ARft~1 Capital Coat: C -($2340/0)(200,000 kv)(CI.l;35,r8i 3.5%)-cap Almual 0 •II Coat: co..-(1.5 •10'kwh/yr.)($O.OO32/kvb)- Amt:..11 PMl Coat: c,-(l.S ~10'kvb/yr)(91S0 Btu/kvh)($1.70/106 Btu)-$24.'9 x 106 Coal Gene~ation COlt MAXIMUM DEREGULATED OOOK'INLET'GAS PRICES (BASED'ON SUBSTITUTABILITY OF'COAL-FIRED'UNITS) FIGURE 0-1.5 \, t r i ~ l L I I n , ~ ~ ~ I I I I !I I l..,.•.•. E"~'.....\ •!. I 1 I $52.3 x 10 6 $22 .6x 106 200 MW $Z.340/ltv '5% 1.5 ]I:10 9 kwh fl.70/MMlStu '.750 Btu/kwh $0.OO32/kwh 3.5% 3S ,ears hit Size Vllit Capital Coat .".ilability Aa\.,ual Geller.ti. 'fuel Coat Beat.a&te o •II Coat ".leoat of Capital Xcoec.ii:LiCe A",".!AI '~l eo.t : c,-(I.S ~la'lr.wb/yr)(9750 Btu/kwh)($1.70/106 Btu)•$24.9 x 106 Total Annual Coata ARIl~l Capital C().t: c -($2340/kw)(200.000 kv)(CU;35 yraj 3•.5%)•cap Aamual 0 ..II eoa t : Co6M-(1.5 x 10'bh/yr.)($O.OO32/kwb)- Coal Gene~ation Coct MAXIMUM DEREGULATED'COOK"INLET'GAS PRICES (BASED ON SUBSTITUTABILITY OF COAL~FIRED'UNITS) FIGURE 0-1.5 a.---__""""-"-------__----_......."..._-------------_--tL I I I t I I I ItII Ij t C ~ ~ I 50 'i I I I I I I 200~I I'I I I-t· I ~ 2010 r:.::3I C9J FIGURE 0-2.1 'tJ,,;, 200620001995 YEAR -~.--~~~.~!t··S 1990 -,-.._.~-~--._-_...,.....--~--------..----.-.-.----,..-..,---.-----..-.---------.-.--....•vc-<,.,.'-"'..r.·4i"w:::~*;J;-II.""~- Ir- PRESENT AND PROJECTED COAL IMPORTS IN JAPAt~·ANO$OUTH KOREA.1.980"2010 1986 ~-- SOUTH KOREA t--' 5.2" 30 ..YR.AVER~GE GROWTH RATE '1""".. 1980 , 160 ~.}--,------------f----------+-------i'-----------i~__::........~--~ JAPAN 2.1"I ,. .30-.YR."'VERA,GE GROWTH RAT.E 1 00 -I---------1!---~:::...-.--_+_-----__iI_-----_t_-------t_---------_+ -en ..JZ<0oI- o (.)-u..a:o I- Wrn~ t-a:Zo0a...-~j---~....., SOURCE:SHERMAN CLARK ASSOCIATES 1983 '-,-.-----:--".....""'~~-.......;.;.....,..----_._-------_.¥< ~t7irZt!Y":'iZt"':'T?M w jo'_~_~_,""""';'__,_;.;.,~~;...,_~",.-",~>~.~-,_.,",,,,~__.,__,,,,,,,_,,~~ (.',)....::.: <? l ~. I~ FIGURE £>-2._2 TAIWAN JAPAN 2000 YE~R - PRO·JEeTED COAL FIRED ELEOTRICITY GENERATION IN PACIFIC RIM COUNTRH:S.1980"'2000 CGWR/YRJ 1180 50.000 -I------:~-----------+-----------;:;;I1'~---+K-O:-R .......E-A-----------1 250,(D)"'""--------------I-----------------+--------------1 2DO.QOO-I-----------i-----,--.----t-------------; 150.000 -I--~------------4----------__..,L------+------------""'__1 GWR/YR --:~---------~--__,---------------___,.-~ r-------------------O ••-------- ~ ~ n ~ c ~ I I r ~I.. I I t r\. i) TAIWAN 200018iO YEAR TOTAL'COAL NEEDS FOR ELECTRIC'POWER' GENERATION IN PACIFIO'RIM NATIONS'.1980"2010'. 1880 20-l-----"1.~----:.,L---·----------~I---.---:.-----,,,---==:::::........--__+ ----.KOREA 10O+------------------4---------~--__; -- AVERAGE ANNUALaO-l------------.....;..:...:..A:.....::R:..:.;K~E.:;:.T.:::.G..:..R.:.:..O:.:...:W..::..T.:...:..H~~-----------------+JAPAN RATE =1'..3~- 11M----------.----I-------------~___+ 40+-----------:l~-----__.rL__+____----------------___+ .120~--------------"--------------""'------+TOTAL ,30.J----~------7'~------.--:1------------------4 .OJ..---------------------I--·----~:....-..,..-----------+ ...a 1 D-I-------+-~::.----------~C--___+ < zO 0°-&&.:j 0 I O+---------------------~I------------:.l~---------+-:.I (lL Zo ...50f--------------~----l'--------,c.-----------------__+ f rn D rJ rJ D ~ .~ I I !I I I ~I J II}.'I I II a ! I :a_Ir"'~',.._.~"jj.,.-..'.. .'"""\ FIGURE 0-2.4 t ~ 3320 MI. ..282 MI • ...3IMS. 4265 MI. 7291 MI .. 9095 MI. 9604 MI. TO-JAPAN FROM-ALASKA VANCOUVER U.S.WEST COAST AUSTRALIA SOUTH AFRICA U.S.GULF COAST U.S.ATLANTIC COAST [PANAMA CAN".l) ..*.-...... e.e.•••••e g..0 ........ .•.•~~•••.......1••••.·.1.·0_.\.\:,..~t. ·0 •••••••••••,......-\. ••\• "'} •••l•.'.'••.'",. Q ~ o (Ja O ()~. . ....,,- ••~'O )~;.-e>..,yO•••••,..rIJ ..• C\I~ r' DISTANCES FROM COAL PORTS'TO'JAPAN f-t t \J ..~··~.;sIE-:Jr_~:-,J c:::J -.....,~_....._-_._----~.. s::::\ ,.......'--,.'" ..ot ••-.#,; •ot·••4 ~.--L1'..._.__•"_.__~_.~_.~.---.:.... $3.~0 i I ~,. I $2.00,I 1--------t-------------J WESTE~N COAL 30 t/A AVERAGE=(j>10.000BTU/LB 2.;"iYR$1.001==~::=~=~~~~~~~=~:;;;;;~~~~::===:==jI30YAAVERAGE=WESTERN LIGNITE 2.3%/YA ..~500 BY BTUlLB ~ I .,.,." t-'~ii."""r=-"'lI.,'k~.."..__._~ r--"'I L ...._J 2100 C:'""J~ ,~......':::l~~r'7!Il-."1.J ...,...\1 2000 ~l..~.........:.·."...._..,d- YEAR (=-5 E3 1990 c~:::] 1980 .;-IIS!!!!!!!~.•~.,..,..-.,-;..-;-~.··~~~~lL~.~:-.J FIGURE:0-2.5' FORECAST REAL COAL PRICES FOR WESTERN COAL AND LIGNITE,1980-20 10;NEW CONTRACT AND SPOT MARKET STEAM COAL (1982DOLLLAR S) _w_""'"...--........__....'-..-._.--....,..........,...,.....'-'........~._'"""".~.,--_..--"'"......,-----~....~.•..,..,~,..'.•'-l"-"""~"'-~"~~-"~~":::-"';""'""'-~~--~~,..'~.--~~,~~".'-'~-·""·~~·~~'--""-"~~V.':·;-""""·--"-"""'''''''-:'·-_---'''~~·__~'''''''''·''·_'_.''''''·_'''-'-''-,~_._.__..."