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a " o c' ,0 Q (,~ 'f,', '-' r') i7 \1 {) n (i~"';oTF ~:dJ ti ': f; f1A'"',',',,~\; "~H'J ",;, ,'..,.,"';-"-..,"'--,......"__'.._H"_~...,~;::.,.<._.~_.....,~~_ .0 '.1 !,j ., / ~POWE~.AUTHoF \' I Please Return To, DOCUMENT CONTROL ~rnJ~OO~lA;~@rID&®©@ Susitna Joint Ve'nture "Document Number i'il' 1','~,',.,',,,",I',, j \ ;,"~,',!";I,',,.'I'c: •-~'olt ' . ~1!llj~fljl{ClfJ) .aJ$lTNA JOINT VENTURE SEPTEMBER 1983 DRAFT . SUSITNA HYDROELECTRIC PROJECT ECONOMIC ANDF·INANCJAl UPDATE .---ALASKA POWER ,AU1-HORITY _______ Wi\I I I' il·~",I ......~ I I I <I I I I '·'1 I ~, ",:.0 .J TO THE .'t"....,'-..i:l:; SUBMITTED BY SEPTEMBER 1983• :ECONOMIC AND FINANCIAL UPDATE HARZA-EBASCO SUSITNA JOINT VENTURE ALASKA POWER AUTHC>RITY \,,, 'SUSITNAHYDROElECTRIC PROJECT I I.., ~I":.1,,-.. ll"·~.f > II"J ;, '-~ ~--j 'I-' I , 1 ;. I , ",~-! :1',I, I,"-""' Il~ r " I 'I",! ~;, ,I I , ,, .' I .'l;.,,""":", "ie'" I' I f,·..~ " L~ 'TABLEOFJCOt\ITENTS ~ ,a .......- I, i.,( ~.'.h: i,; •I; I· I I I :I, I r .I I . I I I I I I TABLE OF CONTENTS SEPTEMBER 1983 1-1 1-1 1....3 1-5 1-7 2-1 2-2 2-2 2-3 2-4 2 ....10 2-11 2-11 2'-12 2-12 2-12 2 ....13 2-15 2-16 2-22 2-24 Anchorage-Cook Inlet Area Fairbanks-Tanana Valley Area The Petroleum Revenue Forecasting Model 2-5 The ~1an-in-the-Arctic Program (MAP) Economic Mod el 2-6 The RailbeltElectricity Demand (RED)Model 2-7 The Optimized Generation Planning (OGP)Model 2-9 Alaska Department of Revenue (DOR) Forecast (June 1983) Data Resource Incorporated (DRI)Forecast (Summer 1983) u.S.Depal:'trnent of Energy (DOE)Forecast (First Quarter 1983) Sherman H.Clark Associates -No Supply D"~ruption (May 1983) Othar Oil Price Forecasts Introduction History and Current Status Scope and Methodology and Oil Price Scenarios Contents of this Report Acknowledgements Introduction The Interconnec ted Rail bel t Marke.t 2.2.1 2.2.2 Methodology for Power Market Forecast 2.3.1 2.3.2 -i- Future Oil Prices and State Revenues Oil Price Forecasts 2.3.3 2.3.4 2.5.1 2.5.2 2.5.3 2.5.4 2.5.5 Selection of Oil Price Forecasts Power Market Forecast Comparison with PreVious Forecasts and Utility Forecasts Sununary Introduction ECONOMIC AND FINANCIAL UPDATE SUSITNA HYDROELECTRIC PROJF"T Page 1.1 1.2 1.3 1.4 1.5 Power Market Forecast 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8 2.9 1.0 2.0 J I 'I-."1".;, •"" r _'•• t I:'~. I I, \...-,., I 11'-'!, I',N .., I~... Ii" ~" "I'" _.,;1<_ 1,' t " I I I I I 4,~1 Introduction 4.2 Natural Gas-Fired Options 3--10 3-"5 3-6 3-2 3-3, 3-3 3-5 3--11 3~12 3-13 3-7 3-7 3-7 3-8 3-9 3-10 3~..1 3-1 3-6 Page 3-14 3-15 3-16 3-16 3-17 3-17 4-1 4-1 4--A 4-·8 4'-10 Cultu.ral Resources Socioeconomics Recreation Aesthetics Land Use Project Alternatives -i1- Cook Inlet Gas Availability Cook Inlet Gas Consumption Cook Inlet Gas PriCe North SloPe Gas Watana Development Devil Canyon Development ConstructiC41 Cost Estimates Operation and Maintenance Costs Simulation Model Hydrology Reservoir .Data Turbine and Generator Data Reservoir OperatioIl Constraints Power and Energy Production Aquatic Terrestrial Dcial Sciences 3.6.3.1 3.6.3.2 3.6.3.3 3 ..6.3.4 3.6.3.5 3.6(13.6 Natural Gas Availability and Cost in Alaska 4.2.1.1 4.2.1.2 4.2 ..1.3 4.2.1.4 3.2.1 3.2.2 3.4.1 3.4.2 3.5.1 3.5.2 3.5.3 3.5.4 3.5.5 3.5.6 3.6.1 3!Q!2 3.6.3 TABLE OF CONTENTS (contYd) 4.2.1 Update o·f the Susitna Project 3 •.1 Introduction 3.2 Description of the Susitna Project 3 ..3 Design Improvements 3.4 Cost Estimates 3 ..5 Reservoir Operation Studies 3.6 Environmental Status Update Non-Susitna Generation Alternatives 3.0 4.0 :1:';;.r· •••• ",/ I I · ,t I I I I I I I I I I··.·.'.···.1 """"" I I I I ,I 5-2 5-3 p.age 4-13 4-25 4-26 4-17 4-22 4-28 4-13 4 "J .... -.l':::> 4....17 5 1 5 2 5-2 5 ....4 5-4 5 ....4 5-7 5-6 5-6 5-6 5-7 5 7 5 8 5 ....10 5....10 5-11 Simple Cycle Combustion Turbines Combined Cycle Combustion Turbines TABLE OF CONTENTS (cont-d) Natural Gas-Fired Power pI ants 4.2 ..2.1 4.2.2 ..2 Coal Avai13bility and Cost in f..laska Coal-Fired Powerplants Planned System Additions 1992 System Susitna Al'~ernativt~ Non-Susitna Alternatives Reliability Evaluation Conventional Hydro Scheduling Thermal Unit Commitment OGPOptimization Procedure Transmission System Expansion Associated wi th Generation Sys tem Expansion 1993-2020 Generation E-x:pansion Comparison of Expansion Plans undet the DOR Mean Scenario Expansion Plans under the SHCA-NSD Scenario 4.2.2 4~,3.1 4.3.2 5.3.1 5.3412 5.4.1 5.4.2 5.5,,1 5.5.2 5.5.3 5.5.4 5.6.1 5 ..6.2 4.3 Coal-Fired Options --iii- 4.4 Chakachamna Hydroelectric Development 4.5 Environmental Considerations References and Bibligraphy System Expansion Programs 5.1 Introduction 5.2 The Existing Railbelt Systems 5.3 1983-1992 Generation Expansi.on 5 ..4 Generation AI ternatives 5~5 FOPmQ1ation of E~pansion Programs 5.6 1993-2020 System Expansion 5 ..7 Review of Expansion.Programs 5.0 I I 'I··.' ?f I fl··.......·'······ '~. 'f;. I I ..•....-..:-....i, , I·· ··.·.··'·· < I I I ·I··~···.·....,t "..',"" I I I .1'.~ "",' I 6-11 6-12 6-6 6-7 6-7 6-10 6-11 Pa~ 6-1 6-1 6-4 6-6 6-6 6-7 6-8 6-7 6-1 6-13 6-17 6-18 6-18 6-19 6-21 6-22 6-24 7-1 7-2 7-2 7-4 7-5 Oil Pl:ice:s Capital Cost Estimate Real Interest Rate Availability of Cook Inlet Gas Real Escalation of Fuel Costs State Equity Contributions Revenue Bonds Revenue Sources Revenue Uses Assumptions Under Alternative Operating Budget Scenarios Results of SAGE Model Analysis -iv- Project Downsizing Cost Estimates ofAl ternative Watana Developments Development Sequence Introduction Economic Criteria and Parameters Life Cycle Analysis Internal Rate-of-Return (Interest Rate Threshold) Analysis Threshold Determination Sensitivity Analysis 6.5 ..1 6.5.2 6.5.3 6.6.1 6.6.2 6.8.1 6.8.2 6.11 ..1 6.11.2 6.11.3 6.11.4 7.2.1 7.2.2 6.1 6.2 6.3 6 ..4 6.5 TABLE OF CONTENTS (cont'd) 6.6 6.7 Cost of Power Analysis 6.8 Project Funding 6.9 Cost of Power 6.10 Interest Rate Sensitivity 6.11 SAGE Model Alternative Susitna Development Schemes 6.12 Summary 7.1 Introduction 7.2 Development Alternatives 6.0 Economic and Cost of Power Analyses 7.0 Iif.'.' .'J.;: I··"';'·.·.'..··r: " I ·I·.·."~.··l..'.k I 'I'·········..' j,-.,.~, I I·".·".'j .~ ;J •-~ Ii I I' I I I I·.·:.·.·.·:•f:. '.", I I•;\.~ I. '.'.'•r ~"'" .11 ~~..I Threshold Determination Page 7-18 7-19 7-7 7-8 7-10 7-18 7-16 7-17 7-20 7....15 7-16 7-20 7-21 7-12 7-1 ff. 7-14 7....19 7-20 7-22 7~22 7-25 7-25 7-26 7-27 7-28 7-29 7-30 7-30 7-32 7-37 Area Inundated Borrow Material Needed Aesthetic and Land Use Impacts Comparison of Expansion Plans under the DOR Mean Scenario Expansion Plan under the SHCA-NSD Scenario Timing of Devil Canyon Development Net Benefits Benefit Cost Ratios Net Benefit as a Percent of Initial Investment Delay of Watana Operation Project Sequence I - -v- 7.1:.1.1 7.15.1.2 7.15!!1.3 Oil Prices Capital Cost Estimate Downstream Flows Downstream Impacts on Aguatic and Riparian Resources Regional Socioeconomic Impacts of Watana AI ternatives 7.5.1 7.5.2 7.5.3 7.7.1 7.7.2 7.7.3 7.9.1 7.9.2 Sensitivity Analysis Other Expansion Programs Economic Analysis Base Load and Load Following Operations Reservoir Operation Studies System Expansion Programs TABLB OF CONTENTS (cont'd) Internal Rate-af-Return (Interest Rate Threshold) Analysi.s 7.10.1 7 ..10.2 SUfiIIIlary Cost of Power Analysis Interest Rate Sensitivity Sage Model Environmental Considerations 7.15.1 Area Upstream of Devil Canyon 7.15.2 7.15 •.3 7.15.4 7.3 7.4 7.5 7.6 7.7 7.8 7.9 7.10 7.11 7 .12 7.13 7.14 :.15 I' I I ·I.·.···.·~·.i..,1 1·· ..·.~"1···.'.1 .! ~~i .1'''''''''··.."i :, '";, I •.·1.·"'···.··.·. .'1, !, ~I I I I I,. •• ,I I I"',.;" I 7...37 7-38 7-42 7....44 Aquatic Ecosystem Implications Botanical Wildlife Resource Implications Socila Science Implications ....vi... TABLE OF CONTENTS (contrd) Environmental Aspects of Load Following Operation 7915.5.1 7.15.5 ..2 7.15 ..5.3 7.15 ..5 I' J 11.\.,Il I ··I···'~.··.·.·.;''1 I,. I} I I····."··'t I .. '1·'..~;.•. ','"" I I I I I .•.'.'.... I ."""""; I ..1....1 ..:{ i...)! I , • Ii I'.''....1.'. .,~ '. I"","'.·,···..···lj. ~~ I '1"',··\,·. .j,. I I I 'I I I I I .1....1 _._.l "."'"' :1. I \,.,•• I Table No. 1 ..1 3.1 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 6.1 6.2 6.3 6.4 6.5 6.6 6.7 LIST OF TABLES Title Oil Price Scenarios Used in the Update Susitna Project Data "CaseC"Flow R.equirements at Gold Creek Efficiencies of Combustion Turbine Units Effic.iencies of 75-~v Gas Turbines .in the Anchorage Area Under Full and Part Load Heat Rates for Various Size Combined Cycle Units Efficiency Characteristics of Combined Cycle Units at Full and Part Load Estimated Beluga Field Coal Costs Wlthout Exports Typical Operating Conditions of Coal-P.ired Units Constraints on Operating Coal-Fired Units at Part Load Efficiency Characteristics of Coal-Fired Units at .Full and Part Loads Summary of Life Cycle Analysis Sensit.ivity Analysis of Cook Inlet Gas 2050 Cummulative Present Worth Sensitiv.ity Analysis of ,Real Escalation of Fuel Costs Beyond 2020 First-Year Wholesale Cost of Power Under Non-Susitna Expansion Plans Funding Requirements to Equate First Year Wholesale Cost of Power to the Non-Susi tna Alternative Sage Model Assumptions Under Alternative Operating Budget Scenarios Special Capital .A'~ailable for Susitna Project --vii- Ci Page 1-4 3-8 3-9 4--14 4-14 4-16 4-17 4-21 4-23 4-24 4-24 6-4 6==8 6-10 6-14 6--16 6--21 6-23 7-9 7-5 7-4 7-14 7-15 7-17 7-17 7-18 7-19 7-20 7-21 7-22 7-28 7-31 --viii- - Net Benefit as Percent of Initial Watana Construction Cost Summary Cost Estima.tes of Alternative Initial Watana Developments LIST OF TABLES (cant'd) Comparison of Present Worth Costs 1993-2050 for Base Load and Load Following Operations Optimmn Timing of Devil Canyon Development Alternative Developments Title Watana Reservoir Elevation and Power Potential Net Benefits,1993-2050 Benefit Cost Ratios Internal Rate-of-Return,Category 1 Cost with Base Loading Threshold Analysis for Percent Increase ill Initial Watana Project Cost Delay of Watana Operation,2050 Cumulative Present Worth Project Sequence,2050 Cumulative Present Worth Funding Requirements to Equate First Year Wholesale Cost of Power to the Non-Susitna Alternative Environmental Characteristics of Alternative Watana Developments Average August and December With....Project Flows at Gold Creek 7.5 7 ".4, 7 ..1 7.3 7.6 Table No. 7.7 7.8 7.9 7.10 7.11 7.12 7.13 7.14 7.15 ). t I IJ···.....•.p.,9).1 I I,: II~~..··':I I I I I I I I I J I I DOR Mean Scenario -Sl,nmna.ry of Input and Output Data SHCA-NSD Scenario -SUT1Jmary of Input and Output Data -ix- Alternative RailbeltPopulation Forecasts Alternati.ve Electric Energy Demand ForecaRt.s LIST OF EXHIBITS Title Relationship of Planning Models and Input Data Al terna tive Railbel t Households Forecast ... Alternative State General Fund Expenditure Forecasts MAP Model System Governor 1 S Checltlist -September 1983 Update Oil Price Foreca~·'s Alternative Oil Pricl.Projections Location Map Showing Transmission Systems RED Information Flows Alternative Electric Peak Demand Forecasts Simulation Case:AI<Department of Revenue,J"ne 1983 Mean,State Petroleum Revenues Simulation Case:AK Department of Revenue,June 1983 Mean,State GovermnentExpenditures Simulation Case:AI<Department of Revenue,June 1983 Mean,Population Simulation Case:.AK Department of Revenue,June 1983 Mean,Employment Si.mulation Case:AK Depart~~nt of Revenue,June 1983 Mean,Households DOR Mean Scenario-Residential Use Per Household 1 ..1 2.6 2.5 2.2 2.4 2.1 2.7 2.3 2.8 2.9 2.10 Exhibit No. 2.11 2.12 2.14 2.13 2.15 2 ..16 2.18 r~· ."":"r I I I~ I '. 11 ..',- J I I l I , ..~. I I I I I I I I I 1_' '". I r ,I--~ I ,_1 •~. ,., I l I I I I I I I I '1.- 1 ,.,....:'. I Exhi.bit No. 2.20 2.21 2.22 2.23 2.24 2.25 2.26 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 LIST OF EXHIBITS (cont'd) Title DOR Mean Scenario -Business Use Per Employee DOR Mean Scenario -Breakdown of Electric.ity Projections (2 sheets) DOR Mean Scenario -Projections of Peak and Energy Demand List of Previous Railbelt Peak and Energy Demand Forecasts (Medium Scenario) Railbelt Utilities Forecast Chugach Electric Association,Inc.Projections of Total System Energy Requirements Summary of Population)Energy and Peak Demand Projections under the DOR Mean and SHCA-NSD Scenarios for September 1983 Update Susitna Project -Layouts with Design Refinements (Category 1)Cost Estimates SusitnaProject -Watana 2185 Cost Estimates (Category 1),Four and Six Unit Powerplants Watana A-2185 UGPH Fill Dam,Underground Powerhouse (6 Units),Genr>t'al Plan Susitna Project -Operation and Maintenan'.:e Cost Estimates Area and Volmne Versus Elevation -Watana Reservoir Area and Volmne Versus Elevation -Devil Canyon Reservoir Powerplant Data -Watana Power and Energy Production -Watana 2185 -DOR Mean Forec.ast -x.... l_~- Existing and Planned Railbelt Hydroelectric.Generation Total Gener,ating Capacity within the Railbelt System, 1983 -xi- Chakachamna Hydroelectric Project Title Thermal Plant Operating Parameters and Costs Environment Rela.ted Facility Characteristics for Alternative Power Generation Options Estimated Cumulative Consumption of Cook Inlet Natural Gas Reserves Susitna Hydroelectric Project SHCA-Nsn Scena.rio Fuel Costs Qualita.tive Ranking of Environmental Impacts Associated with Alternative Projects DOR Mean Scenario Fuel Costs Optimized Generation Plann.ing (OGP)Progra:rn Information Flows Non ....Susitna Plant Operating Parameters and Costs LIST OF EXHIBITS (C.ont'd) Expansion Plan Yearly MWAdditions ....DaR Mean LOad Forecast....Non-Susitna Al ternatives Expansion Plar Yearly MW Additions ....DOR Mean Load Forecast-...usitna Alternatives Year 2020 Railbelt System Generation Mix'"nOR Mean Load Forecast Thermal Alternative -Energy Demand &Deliveries SusitnaAlternative ....Energy Demand &Deliveries Year 2020 Railbelt System Generation Mix'"SHCA....NSD Load Forecast 4.5 4.1 4.2 4.3 4.4 4.7 Exhibit No. 5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8 5.10 5.9 5.11 r I-'~' :'; ,,I I I~~'i •fit .' 'I'~"'::\ • \I I I :. I I I ,.';1 IL. I I I --xi i- Susitna Project -Watana 2100 Cost Estimate Susitna Project -Wa ta:;'l:l 2000 Cost Estimate Susitna Project -Watana 1900 Cost Estimate 6.1 Principal Economic Parameters 6 ..2 Wholesale Cost of Power For Non-Sus~tna Cases 6.3 1993 Wholesale Cost of Power vs.State Equity Contribution, DOR Mean Case 7.1 Susitna Watana 2185 Cost Estimates (Category 1),Four and Six Unit Powerplants Exhibit No.Title 6.6 Wholesale Cost of Power for Watana 2185,DOR Mean (with $2.57 Billion State Equity Contribution) 6.7 Effect of Interest Rate on Wholesale Cost of Power 6.4 1993 Wholesale Cost of Power vs.State Equity Contribution, SHCA-NSD Case LIS T OF EXHIB ITS (cont'd) 6.5 Wholesale Cost of Power (Watana 2185) 6.8 SAGE Model --Special Capital Availability 7.2 Watana A-218S UG.J?HFill Dam -Und.erground Powerhouse (4 Units),General Plan 7.3 VJatana A-2100 UGPH Fill Dam ..,.Underground Powerhouse (4 Units),General Plan 7.4 Watana C....2000 UGPH Fill Dam-Underground Powerhouse (4 units),General Plan 7.5 Watana D-1900 UGPH Fill Dam -Underground Powerhouse (4 Units),General Plan 7.6 7.7 7.8 7.9 Susitna Project Cost Estimate --Devil Canyon Preceding Watana Alternatives 7.10 Typical December Weekday Hourly Load Variation ·Il...."··~.•·... '..;. I 1'7.;) ,.: .I.···~·.· ..' I'.''''·'., .:'~-.' I I I· ...· .-.j . ·1.·.··""'·.··· f ';(4" l- ,~ "•.'1." "". ~~- I I I I I I '. I I..i l .., ./ 'Ii.' 7.13 Susitna.Alternatives Expansion Plan Yearly MW Additions ....DOR Mean Load Forec.ast .... Susitna Alternatives -L/Dad Following o Ex?ansion Plan Yearly MW Additions --DaR Mean Load Forecast __ Susi tIla A1 ternatives --Bas-Je Loading Year 2020 Railbelt System Generation Mix -DaR Mean Load Forecast Year 2020 Railbelt System Generation Mix --SCHA....NSp Load Forecast Rate of Return Analysis Present Worth Analysis 1993 Wholesale Co~::::)f Power VS •State Equity Contribution- DOR Mean Case Wholesale Gost of rOWer (Watana 2185) 1993 Wholesale Cost of Power V5.State Equity Contribution .... SHCA-NSD Cese LIST OF EXHIBITS (cont'd) 7 .11 Power and Energy Production -Watana 2185 --DaR Mean Forecast 7.12 Power and Energy Production ....Watana2000 ....DDR Mean Forecast 7.14 Conventional Hydro Scheduling Tnith OGP Mode.l 7.15 Expansion Plan Yearly MW Additions --DaR Mean Load Forecast, Non--Susitna Alternatives Exhibit No.Title 7.17 7.16 7.18 7.19 7.20 7021 7.22 7.23 7.24 t!.' "~ ~ I .1' I I I I II·.···.:'. ,f . .•..:..•. "<: I I • I I I I I f:. ;; I: Iy~:.., I II' "I r l ;l I I I I I.i,.,.,. I I I I Exhibit No. 7.25 7.26 7.27 7.28 7.29 7.30 7.31 LIST OF EXHIBITS (cont'd) Title Wholesale Cost of Power for Watana 2000. Wholesale Cost of Power for Watana 2185 DOR Mean (with $2.57 Billion State Equi ty Contribution Wholesale Cost of Power for Watana 2000 DOR Mean (with $1.85 Billion State Equi ty Contribution) Effect of Interest Rate on Wholesale Cost of Power Sage Model -Special Capital Availability Watana Reservoir Area.s Under Alternative Development Concepts August and December Flow Duration Curves,Natural and 'With Project Conditions -xiv- - i) 1.0INTRODL1CT!ON J.- ,; I, 'I';J II I I' I' I I I 'I I, I I, ,I. I I.,... ' .....•.. I ·,1,··.1..·.u" ·1,,',.,··,··,···. "','," , I I ·, .".~~ .../ .11 I. ···"·:· •• , 1< • '..•........,'+:' ,·l • I 'i I I I I '. I ·1 I I 1.0 INTRODUCTION 1.1 INTRODUCTION 1\.n update of the Susitna Project has been accomplished.The study yTas conducted to assess the effect of oil prices and the corresponding outlook on the State's economy on the feClsibility of the Susitna Pt'oj- ect.The primary purposes of the update have been: a"To provide an in-depth assessment {'the economics of the projec.t and the cost of power therefrom.,and b.To determine if the currently proposed project should be modified to sui t the current economic and financial conditions. In this Chapter,a brief review of the history of the Susitna Project is given"Then,the current status of the Project is described includ- ing the scope and methodology for-this update;and,a short discussion of the oil price projections is pro'trided"Finally,a synopsis of the contents of the report is given. 1.2 HISTORY AND CURRENT STATUS The Susitna Project as presented in theFERC License Application con- sists of a two--dam development on the Susitna River at the Watana and Devil Canyon sites.The first development would beat Watana with 1020 MW of installed capa.city and 3500 million kWh average annual energy production to be placed in service in 1993.The second development would be at Devil Canyon with 600MW rJf installed capacity and,3 500 million kWh average annual energy production to be placed in service in 2002. 1 ....1 I. '···'.·...·.' I~ I~ I I .' '·1'····' ,. I 'I I I I I I I ·1-.·.····.···"f "1 The studies lea.ding to the present concept began in 1948 by the U.S. Bureau of Reclamation~The Susitna Project was identified as a very attractive project because of its location midway between Anchorage and Fairbanks.Subsequently,the Department of the Interior and the U.S. Corps of Engineersperfot'med numerous studies which resulted in the selection of the Watana and Devil Canyon dam sites as favorable for the development of the Upper Susitna Rive.r 0 The Power Authority took over the studies of the Susitna Project,and completed a comprehensive feasibility study during the period 1980- 1982.Based on that study,the Legislature directed the Power Authori~ ty to file a jj'ederal Energy Regulatory Commission (PERC)License Appli- cation for the entire project and to begin design of the initial phase of the project (Watana). The License Application was filed February 28,1983,and was subse- quently revised,as requested by the FERC.The revised License Appli- cation,which upda.ted the future power demand forecast and the economic. analysis,was accepted by the FERC for processing on July 29,1983. After filing the FERC License Application,the Power Authority Board expressed concerns regarding the Sta te's ability to pay for the Susi tna Project E!Also,qr 'estions were raised at the Alaska Senate State Af- fairs Committee Hearing in February 1983 regarding l\roject economics and financial viability.Suggestions were made that a smaller-scale project might better sui t current cc'nditions.Governor Sheffield through the Power Authority direc ted that a.n assessment of crucial assumpti<:'ns affecting project feasibility be condueted. This September 1983 update is designed to respond to the concerns ex- presse4 in the State.Key variables af.fecting project economics and fj.rlancing.'have been reviewed and revised where appropriate.Exhibit 1.1 provides the basic data,asstJ.In.pt:ions,andresult£developed from this 1-.2 I' .1'-·.·',- +.•' I I' I I l I- I I I I I I I,....': .......{ I • update.The exhibit has been prepared in the form and detail directed by the Power Authority. Apart from the economic and financial update,parallel engineering and environmental studies have been in progress providing further refine- ments and improvements in project design and mitigation of adverse impac.ts..Specific results of these refinements have been incorporated in the updated studies. 1.3 SCOPE AND METHODOLOGY AND OIL PRICE SCENARIOS The update has been accomplished starting with oil pric.e projections because the State's economy and the electric power demand are linked to oil prices.Oil prices directly affect State revenues and the State t s ability to finance the project. In April 1983 when the License Application revision began,a methodo- logy was developed which permitted tracing the price of oil through all pertinent variables and parameters including the electric power demand, alternative costs of fuel,and financing capability of the State.This methodology is briefly described in Chapter 2 of this rep.ol.'t. While the economic and financial forecast has been specifically tied to the future price of oil,the oil price projection itself is subject to a great deal of uncert&inty since there is a wide variation among experts in forecasting the trajectory of oil prices.Bec~use of the impIlcations on the feasibility of the Sus.i tna Project ,several 01.1 prlce foreca.sts have been considered and economic and cost of power analyses have been performed for two forecasts in this update. The Alaska Department of Revenue (DOR)ma.kes petroleum revenue projections to produce a probability distribution of future revenue. Estimates of future revenue $a.re made on a quarterly basis and are used 1-3 Table 1 ..1 SHCA-NSD 28.95 30.49 36.40 50.39 1.4 2.0 DOR:tvlean 28.95 25.13 27.45 32.42 ....0.3 0.4 1983 1993 1999 2010 Annual Growth 1983-1999 -% Annual Growth 1983-2010 ....% OIL PRICE SCENARIOS USED IN THE UPDATE (in 1983 $per barrel) 1-4 published DOR forecasts extend to 1999..Beyond 1999,the DOR Mean prices have been extended at a growth rate of 1.5 percent annually. annual growth rates shown in Table 1.1 are lower than the fiscal by the Sta.te Office of Management and Budget in developing budgets. Because the revenue pr6jections are used in the State budgeting proc- ess,the Board of Directors of the Alaska Power Authority designated theDOR Mean oil price forecast for use in the evaluation of the pr6jeCt in this update.The DOR Mean forecast is from the DOR June 1983 Quarterly Report. In the July 1983 FERC License AilP1ication,the Sherman H.Clark Associa.tes ....No Supply Disruption (SHCA-NSD)forecast,developed by an energy consultant,was adopted as the Refer.ence Case.To permit establishing a link between the License Application an.d this September 1983 Update,an analysis based on the SHCA-NSD oil price forecast is also included.The DOR Mean and SHCA-NSD oil price projections are summarized in Table 1.1. The oil The 1';(',,-1 •••• I: I' I' I' I' I' I~ Ii I I I I I ,I",',·: '....! • I I 1-5 year 1983 Power Authority planning g~lideline of 2 .5 percent per year growth in oil prices~ This report is organized into seven cha.pters.Chapter 2 provides a description of the electric power demand forecast.This Chapter has drawn largely from the work performed in connection with the July 1983 revision of the License Application..It introduces June 1983 DOR forecast of oil prices.Chapter 2 also provides a description of the computer models and the methodology used in t~-ing the oil pri.ce forecasts to electric power demand forecasts,economic analysis and financial analysis. Chapter 3 provides a description of the project contained in the FERC License Application.It summarizes the proposed refinements in design and cost estimates of the current Watana 2185 project wh~c.h is the su1)jec t of ano thar Ilarza-Ehaseo R,~port "Sus Una Hydroal ec tric Pr oj aet ,J /...IJ,J1> Review and Update of Conceptual Design"November 1983.The chapter ~ describes the physical characteristics,cost estimates ,and power and energy production of the Watan'i Project.This chapter also provides a review of the status of the environmental issues. 1.4 CONTENTS OF THIS REPORT Chapter 4 reviews and updates the non-Susltna generation alternatives which are attractive and could be competitive sources of generation. The costs and.performance characteristics of these generation a1 terna- tives are updated and revised from previous studies to reflect the latest available information.The chapter also contains a summary description of the availability and cost of natural gas and coal for use in the fossil--fuel power plants .. Chapter 5 describes the various ways that the demands of the future electric power system can.be met,cost effectively,with and without I I I I I I I I I· '~...; . I I • '. I I I I I I I I I I I I, I I, I I I Ii the Sus!tna Project..The sizes,types and number of powerplants and the installation schedules are developed.The annual costs of con- structing,operating and maintaining each supply alternative are pre- sented. In Chapter 6,the economic and cost of power analyses are described .. 'JL'he economic analysis compares the alternative system expansion pro- :grams using a life cycle approach.A threshold analysis and sensi ti- vity analysis of the key variables are also included in the analysis .. The cost of power analysis identifies the wholesale cost of power wi th various levels of State eqUity contributions.In addition,the afford- ability of the Susitna Project is assessed by comparing the availabi-- li,ty of capital for Susitna under various State operating budget levels wi th construction cash flow requirements. Chapter 7 presents the al ternative concepts of the Watana and Devil Canyon developments.The Chapter describes the Watana project wi.th the reservoir lowered to elevations 2100,2000,and 1900.The chapter then describes an improved mode of operation for the Susi tna project that: would provide greater l..'eliability of service to the electric system and a ttendant economic benefi ts •Also,environmental implications related to the above changes are discussed.The economics of th.::Watana Devel- opme.nt constructed to the various reservoir elevations and wi th dif-- ferent generation capacities are also discussed.The effect that low-- t:!ring the Watana Dam has on the upfront State appropriation of part of the construction cost is illustrated by comparing the required State equity contribution for the T\Tatana 2185 project With a lower Watana 2000 project. 1--6 1 I ,I I I I I I I I 1.5 ACKNOWLEDGEMENTS The preparation of this report has been guided by the Power Av.thority staff,special assistants to the Power Authority Board of Directors, and by the Office of l1anagement and Budget • R.W.Beck &Associates,Inc.assisted Harza-Ebasco in the performance of the cost of power analysis. 1-7 2.0 0.5 0.5 -1.4 2.0 1.4 1.4 -0.3 2.0 2.0 2.0 0.5 1.5 2.2 2.2 -1.5 0.7 0.0 Exhibit 1.1 Page 1 of 4 GOV ERNOR'S CH ECI<L .1 ST September 1983 Update (J~nuary 1983 price level) REV I SED FERC LICENSE APPLICATION SHCA-NSDDQR Mean (REFERENCE CASE)UPDATE THRESHOLO(aOPDATE THRESHOLD(a) (change)(change) 0.0 28.95 25.13 27.45 33.35 37.62 o -26.86 28.95 30.49 36.40 50.39 64.48 28.95 30.49 36.40 50.39 64 e 48 38 (e) 46 (c) 52 (e) 65 (c) 65 (c) 1982 FEAS I B I LITY STUDY I I I ". I OIl PI'lce Forec~st(l:»_$/1:>1:>1 1983 ·1-.-.:::~ 2010 2020ILongTerm 011 Prlce Growth ...%/yr 198~-1993 1983-1999 • .,1983-2010 .••.~..1983-2020 of Energy Generatton -GWh/yrProjectionI~::; 2010 2020 I Long Tel'm Lo.d Growth Rote ~~/yr 1983-1993 1983-1999I1983-2020 3,402 5,126 8,414(d) 3,027 4,321 6,280 8,0.39(d) 3.6 2.7 2.7 3,088 4,397 6,444 8,312(d)(e) 3.6 2.7 2.7 (e) 3,088 4,167 5,945 7,50S(d)0.0 3.0 2.5 2.4 0.0 0.0 0.0 4.00 4.00 4.18 4.85 7.58 Available through (h) 2006 (h) -5.04(£1) 3.02 2.45 3 0 61 2.68 4.43(f)-1.46(g)2.97(f) 4.22 5.04 6.97 8.92 12.62 AVa liable through 2006 3.02 3.61 5.00 6.39 9.05 Linked With oil price growth 4.22 5.04 6tf 97 8.92 12.62 Assumed un I tmlted 3.2 4.7 6.2 6.2 6.2 NA NA Ntl NA NA Assumed un I I mtted (b)-S/MMBtuCook Cook Inlet Gas Avallabt I tty Forecast North S lope Gas PrJ ce Forecast (t)-S/t+1Btu 1993 1999 2010 2020 ;;050 I Inlet Gas PrIce Forec~st 1993 1999 2010 2020 I Cook ~:::t s.s PI'lce GI'oWfh ~~ I I I ••North Slope Gas Aval labl I tty Forecast (f>NA Assumed unll Hltted Avat lable In 2007 <J) Available In 2007 (J) .1,..... I ..~ GOVERNOR'S CHECKLIST September 1983 Update (January 1983 price level) Exhibit 1.1 Pafle 2 of 4 2.3 2 ..3 0.0 1.3 1.3 0.0 1.2 1.2 (h)0.0 0.0 (1<)(I<)(h)(k)(h) 3,750 (0)3,338(p)+50%3,338(p)+5%1,620 (0)1,554 (n)1,554 0.0 0.0 0.0 (m)0.0 0.0 0.0 0.0 em)0.0 0.0 0.0 0.0 (m)0.0 0.0 REVISED FERC LICENSE APPL ICAT ION (REfERENCE CASE) 1.9 1.72 1.72 1.802.4 2.17 2.17 1.80 3.1 2.57 2.57 1.80 2.84 2.84 (h)1.80 0.0 1.5 1.86 1.86 1.802.0 2.17 2.17 1.80 2.7 2.57 2.57 1.80 2.84 2.84 (h)1.80 0.0 2.9 1..6 1.6 0.02.2 1.3 1..3 0.0 1.2 1.2 (h)0.0 0.0 Assumed Un Hmfted Unlimited em)Un limited (m) 3.0 3.0 3.5 +1 .9 3.5 +0.23.0 3.0 3.5 +12.0 3,,5 +1.47.0 7.0 6.5 NA 6.5 0.0 (k) 1982 FEAS I BlllTY STUDY 3,805 (0) 1,535 (0) l .~ 1982 to 1985 1.1 1986 to 1992 :1,0 1993 on 2.0 Nenana Coal PrIce Forecast (b)-S/r41Btu 1983 1993 2010 2020 Nenana Coal Price Growth -J/yr 1983-1993 1983-2010 1983 ..2020 Nenana Coal Availability Forecast Beluga Coal Price Forecast (b)(1)-$/MMBtu 1983 1993 2010 2020 BellJga Coal Price Growth -%/yr 1983-1993 1983-2010 1983-2020 Be I uga Coa I Ava I lab f II ty Forecast Real DlscQunt Rate (%) Real Interest Rate (J) General tnf tatlon Rate (%) SusJtna Construction Cost - $x 106 WatarlC! Devi I Canyon CapItal COst Escalation Rate .-% I I I I I I I I I • 'i .<.,# I I I I I I I I (f)F~recast 0 I so represents prJ ces of g~s from some other source such as Cookl n let,end ref I ect I ncreasecf pr fees due to higher exp loratlon end dovelopment costs end assocI ated rtsks. (8)Approximate ..The threshoJd value woul(f be greater. (h)No threshold va~ue,because of substItutIon posstbllltfes. SHCA-NSD DOR Mean UPDATE THRESHOLD UPDATE THRESHOLr (change)(chall:;Je) REV I SED FERC LICENSE APPLICATION (REFERENCE CASE) Probably yes since interest rate Is assumed to be 10% 1993 1993 1993 ~.A 1993 W\2002 2002 2002 NA 2006 NA 1.17 1.33 1.28 NA 1.03 NA 1.9 (q)(r)1.9 (q)(r)1.7/2.1 (s)NA 1.5/2.3 (s)NA 14.7 (r)13.6 (r)10.2/8.4 (s)NA 11.6/7.6 (s)NA 1982 FEAS I 8 I L ITY STUDY GOVERNOR1S CHECKLIST September 1983 Update (January 1983 price level) Project Tt mI ng Watana Dev 11 Canyon fRl5 Tax Exempt ion Beneflt/CostRatlo State Equl+y Contribution (1983 $billions) Wholesale Cost of PoWer (cents per kWh) In determining the threshold paInts for prices of all and natural gas,the values under the 000 Mean scenario are used,since the beneflf-cost ratio for that scenarIo is 1.03 or very nearly 1.00.. NAt.Not Appllcabls ExhibIt 1.1 Page 3 of 4 (C!I)The threshold point Is that point tor each variable at which the Suslfna Project has a benefit/cost ratio equal to 1:00,holding all other variables constant.The column shows the amount of change which must occur in each varIable before the threshold point is reached. (b)1982 FeaslbJ'ity StUdy fuel costs were inflated to J~IOUary 1983 price leval using the U.S.GNP Index of 6.0%. (c}Based on 2.0%average annual growth rate until 2010,and 0%thereafter as reported In Fobruary 1983 Exhibit 0 p.0-4-22. (d)Last year of generation expansion planning studIes .. (e)A large decrease of that variable would bEl required to arrive at the threshold value. (f)Gas pr ice in 2006,t'th i ch was assumed to be the 'ast year of Cook In let gas ava II ablll ty. I I I I I I I I I I , .~. I I I I I I I (0)January 1982 costs escalated to Jl':lnuary 1983 usIng a 4.3 percent f'actor. I I I I I I I I I I ,I I 'J I I fl·....•• 1 1 Exhlbl·'1.1 PaIge 4 'of 4 GOVERNOR'S CHECKLIST September 1983 Update (January 1983 prlcet level) (J)UnavailabIlity of N(')rth Slope gas,When Cook Inlet gas Is depleted,could Cl:$U$&major supply problems to the thermal alternatIves.N?threshold value Is available. «()1982 Feaslbl I tty Study up t~200 MW of coal-fired st~am plant~\Revised FERC LIcense zsnd 1983 Update up to 400 MW of coa I ..f (red steam plant. (t }Assume Beluga f!eId developed for export mar'ket,but pr I cessol d for local needs Independent of opportun lty pr ice. (I'll)t.lq~-:dlrabll~ty of Beluga coal could cause rri'aJor supply dIsruptIon to the +hel"'""al al te,"'natlves. (n)A large Increase would be requIted to arrhe at the threshold value. (p)ConstructIon cost for lnttlal four-unit InstallatIon.ConstructIon cost for six-unit Inst,llatfon is estimated at $3,432 mtl non,or 2.8%hlgher .. (q)lnfl.,ted from 1982 to 1983 usIng U.S.GNP Ihdex of 6.0%. (r)COal expansion plan. (s)COal expansion plan/Gas and Coal expansion plan. ."l'D -;J . .•J 2.0 POWER MARKET FORECAST ,r D o I·· ····,..I1. 1. tr r I , f ':."~.... I ;:1-l',.'. fl",t, j ~ -I:;i , f ~I"t;, j, 1 I],i.,. 1 ' 1 I.·'I.••.• 1 '., ',f..•"'1-',,:~,: 'IAt-, ,I .1,-,. I" 1., ,I .1,~ ",'1. IIrr.:,', I I I I I 'I I I I I I.•'....'Ii I I.irJ j '.''"~.. I,j;~~ I I I···'···'··....'·'··.•.." '·'·'1·..'· '1 ; 2.0 POWER MARKET FORECAST 2.1 INTRODUCTION This chapte.r presents an update of the power market forecasts which were described in Exhibit B of theFERCLicense Application.Electric power demand forecasts have been developed for the Railbelt market that will be served by 'the Susitna Project.The forecasts begin ft:om the year 1983 and extend to 2010,a period during which resources of the Susitna Project will be developed. Themagni tude of the future power demand depends ona number of fac- tors,the primary one being the price of oil which affects the revenue to the State and the State's economic.activity.To account for a range of world oil pr.ice projections,demand forecasts are developed for the DOR-Mean and SHCA-NSD oil price scenarios.The SHCA-NSD scenario was used as the Reference Case for the License Application. In addition to world ~il price,the influence of energy conservation and the relative costs:of alternative forms of energy are also impor- tant and have been factored into the forecasts • The following sections desc.ribe the interconnected Railbe1 t marke t,the basic approach used to develop the forecasts:>the variables andassurnp- tions in the forecasts,and finally the results of the forecasts and their significance.A summary of the power market forecasts is given at the end of this Chapter 9 The resulting forecasts are then utilized .in the development of the system expa.nsion programs described in Chapter 5. 2-1 2.2 THE INTERCONNECTED RAILBELTMARKET 2-2 The existing transmission system of the Anchorage-Cook Inlet area ex- tends north to Willow and consists of a network of 115-kV and 138-kV lines wi th interconnection to Palmer.The Fairbanks-Tanana system eij',tends south to Healy over a 138-kV line.The Intertie Which is being built by the Ala.ska PoWer Authority to connect Willow and Healy will operate initially at 138-kV.The existing transmission system in the Railbelt region is illustrated on Exhibit 2.1 • The Railbelt region ,contains two principal electrical load centers: the Anchorage-Cook Inlet area and the Fairbanks-Tanana Valley area ~ These two load centers will comprise the interconnected Railbeltmarket when the Intertie currently under construction by the Alaska Power Author!tyis completed.The Glennallen Valdez load center is not planned to be interconnected nor to be served by the Susitna Project. o MunicipalitY'of Anchorage-Municipal Light &Power Department (AMLP) o Seward Electric System (SES) o Chugach Electric Association,In.c I'(CEA) o Homer Electric Association,Inc.(REA) o Matanuska Electric Association,Inc.(MEA) o Alaska Power Administration (APAd) o Elmendorf Air Force Base -Military o Fort Richardson.-Military 2.2.1 Anchora.ge-Cook Inlet Area The Anchorage-Cook Inlet area has two municipal utilities,three rural electric cooperative associations (REAs),the Federal Power Administra- tion,and t wOll1ili t ary installations,as follows.: I ··1· ·.'·.·· ."' I I I "1..t..'· .." I I I I 1..1 ..,.,.A I I I I· 1. J ,,' I ,...•'•..,•••1,1'.'.'J •.•~'l r:l If . 1.1 .·1.····.·..'···1 .~ '·1II . II .1:. ,~i 4.~i ,) [1 r.J Inc~and Fairbanks Municipal generation,transrnission J and 2 ....3 Associa.tion" a.nd operate MfLP and CEA are the,two principal utilities serving the Anchorage-Coc)k Inlet Area.All of these organizations"wi th the exception of MEA" have electrical generating facilities.MEA buys its power from CEA. HEA and SES have relatively small generating facilities that are used for standb)7 operation..They also purchase power from CEA.The exist- ing generation system.is described in Chapter 5..The total installed capacity was 873MW in 1982.The Anchorage....Cook Inlet area is almost entirely dependent on natural gas to generate electricity..About 92 percent of the total capacity is provided by gas-fired units.The remaining are hydroelectric units and oil-fired diesel units. a Fairbanks Municipal Utilities System (FMUS) a Golden Valley Electric Association,Inc.(GVEA) a University of Alaska"Fairbanks a Eielson Air Force Base -Military a Fort Greeley -Military o Fort Wainwright -Military In 1982,the electricity generation by the Anchorage-Cook Inlet utili- ties was 2,,446 GWh"with a peak demand of about 472 MW.Between 1976 a.nd 1982,the demand lIas increased at an average annual growth rate of 7 ..1 percent. 2.2.2 Fairbanks-Tanana Valley Area The Fairbanks-Tanana Valley area is currently served by an REA coopera- tive,a municipal utilIty"a university"and three military installa- tions as follows: Golden Valley Electric Utilities Systern own I I I I I I I I ,I.·.·1.,.~ I I I I I 11...J I I I I 2-4 purchases,of the The growth in the In 1982,the totctl energy generation,including utilities was 491 GWh,wi th a peak demand of 94 MW. past six years has averaged less than one percent. 2.3 METHODOLOGY FOR POWER MARKET FORECAST (l dist.ribution facilities.The Universi ty and military bases maintain their own.generation and distribution facilities.Fort Wainwright is interconnected with GVEA and FMUS and is providing both utilities wi..th secondary energy.The e:g:isting generation system is described in Chapter 54'The total installed capacity was 351 MW in 1982.A large portion of the total installed capacity consists of oil-fired combustion turbines (57 percent)and coal steam turbines (30 percent). The remaining capacity is provided by diesel units. In general,the petroleum revenue forecasting model produces alter- native State revenue forecasts based upon petroleum price forecasts .. MAP converts these revenue projections plus additional data into pro.... The power market forecast is based on broad econometric and end-use. approaches.rather than individual utili tyforecasts which were devel- oped for their own generation planning.As in the FERC Idcense Appli~ cation,four computer models provided the method010gy for developing the updated power market forecast and the SUbsequent assessment of alternatives.These models are the petroleum reVenue model.opera.ted by the Alaskan Dep~i:tment of Revenue (DOR),the Man-in-the--Arctic Program (MAP)operated by the Institute of Social and Economic Research (ISER), the Railbelt Electric Demand (RED)model of Battelle Pctcific Northwest, and the Optimized Generation Planning (OGP)model of General Electric Co.(GE).The relationship between the models and thei:,principal input and output data are shown on Exhibit 2.2 which also shows the role of financial analysis in the selection of generation expansion plans .. I I I I I.'.'; , ·Ii·· ,.1 I I I I I I I •••••...1.-:.,"" I I 1\ ,:~•"" I I -t -- 2-5 jections of economic conditions including population,housing,and employment.The RED mod.el then uses the MAP model output plus addi- tional data to produce an electricity load and peak demand forecast for the Railbelt Region.Results of the RED model plus investment,fuel, and ope.rating cost data then are input toOGP to produce optimized generation expansion plans and cost of power estimates.A complete description of these models is presented in Exhibit B of the FERC License Application"A summary description is presented in the follow.... ing paragraphs. 2.3.1 The Petroleum Revenue Forecasting Model PETREV is an economic accounting model that utilizes a probability dis- tribution of possible values for each of the factors that affect State petroleum revenues to produce a range of possible State royal ties and production taxes.The principal factors influencing the level of petroleum revenues are petroleum production rates,mainly on the North Slope,the market price of petroleum,and tax and royalty rates appli- cable to the wellhead value of petrol.eum • Petroleum revenues consti tute approximately 85 percent of the incoming cash flows of the State of Alaska.For this reason,projections of the most important sources of State revenues are generated by a specialized model.The PETREV model genei'ates 17-year State revenue forecasts based upon alternative world oil price forecasts. Due to the many uncertainties involved in forecasting revenues,the forecasting model projects a range,or frequency distribut:i,on,of State petroleum revenues by Year,so that for each year a forecasted petro- leUJIl revenue figure may be selected based on a given cumulative fre- quency of occurrence.The model accomplishes this by iteratively selecting a set of in,put variable values from among alternative values and computing a.petroleum revenue figure for each time period.Each • <' ;\.: ~. I .1..;·\···.·.f 'i I , >' ••..j .-.,,:,' I j .~.,-." I I I I I I I I I I I ··1."'.'.· I ! 2-6 2.3.2 The Man-in-the-Arctic Program (MAP)Economic Model projection is computed using a se t of a.ccounting aqua tions that esti- mate royalties and production taxes from each State oil and gas lease for each time period ~By selecting the average value of all input data the model produces an average petroleum revenue forecast. Because of uncertainties in projecting petroleum prices and their importance in developing alternative geoarationplans and load fore- casts ,it is necessary to examine the implications of several dif- ferent world oil price projections in addition to the price projections developed by the DOR.This need is accommodated by DOR through a petroleum revenue sensitivity accounting model referred to by DOR as MJSENSO.This sens 4 tivity accollUting model,which is in effect a sub- model of the PETREV model,utilizes the account,lng equa ticns and aver- age values for all input variables other than world oil prices from PETREv,to cOlllpute an adjustment to PETREV's average petroleum revenue forecasts based on different assumed world oil price forecasts.By executing the sensi tivi ty model wi th the a1 terna.tive petroleum price projections,alternative petrole.um revenue projections are developed for use in projecting State economic activity in the MAP model • The',AP model is a computer-based ec.onomic modeling system 'that simu- lates the behavior of the economy and the population of the State of Alaska and each of twenty regions of the State corresponding closely to the Bureau of CenSU3 divisions.The Raflbel t consists of six of these regions.The MAP model develops Railbelt socle-economic activity forecasts to the year 2010.Input from theMJSENSO model a.re extra- polated from 1999 to 2010,using the average annual rate of change of the period 1996-1999. The MAP model functions as three separate but linked sub-mOdels:the scenario ge:ne'tator sub-model,the economic sub-model,and the regional- ••''f.,! l: I ••..••1·',Il( I I '1:; >,'~ I I I, .t~; 1';/ ~~ I, J I I i I"~J ..1'.···'·1..•", j I I. ·····".·····••i ·1;.···....1.t .~ I I I II.'.··..',.·<" ~: I:·~. ,f :ot I I I I ',·1. '·.•..•...', Ii ~{' I I Ii I I I J~) I IJ.....,.,,.;.,,,... ization sub-model,as illustrated on Exhibit 2.3.The scenario genera- tor sub-model enables the user to quantitatively define scenarios of development ill exogenous industrial sectors;i.e.,sec.tors whose devel..... opment is basic to the economy rather than supportive.Examples of such sectors are petroleum production and other mining,the federal government,and tourism.The scenario generator sub--model also enables the user to implement assumptions concerning State revenues from the MJSENSOmodel.The economic sub-model produces statewide projections of numerous economic and demographic factors based on quantitative rela tionships between elements of the Alaskan economy such as employ- ment in basic industries,employment in non-basic industries,state revenues and spending,wages and sa.laries,gross product,the consumer price index,and population.The regionalization sub-model enables the user to disaggregate the statewide projections of population,employ- ment,and households to each of the 20 separate regions of the state J using data on historical and current economic condi tions and assump- tions concerning basic.industrial development. 2.3.3 The Railbelt Electricity Demand (RED)Model The Railbelt Electricity Demand (RED)Model is a p:1rtial end-use - econometric model that projec.ts both electric energy and peak load demand in the Anchorage-Cook Inlet and Fairbanks-Tanana Valley load centers of the Rsilbel t for the period 1983-2010.The RED model is de- signed to forecast annual elec tricity consumption for the residential, commercial,small industrial,government,large industrial ..and miscel- laneous end-use sectors of the two load centers of the Railbelt region. The model is made up of seven separate but interrelated modules,each of which haS a discrete comput:ILng function wi thin the model.They are the uncertainty,housing ,residential consumption,business consump- tion"program-induced conservation,miscellanecusconsumption,and peak demand rnodule~>.Exhibit 2.4 shows the basic relationship among the seven modules., 2--7 I I 'I.; .I fl.I .•.¥~ I I '·;.1.·;......", I...~ i I I I I I I•J I I: I I The model may be operated probabilistically,whereby the model produces a frequency distribution of projectioI;\S where each projection is based on a different II randomly selected set of input pa.rameters.The model may also be operated on a deterministic basis whereby only one set of forecasts is produced based on a single se t of input variables"When operated probabilistically,the RED model begins wi th the Uncertainty Module,which selects a trial set of model parameters to be used by other modules.These parametern include price elastici ties,appl.iance saturations,end-use consumPtion J and regional load factors. Exogenous forecasts of population,economicactivi ty,l and retail prices for fuel oil,gas and electricity are used with the trial par'ameters by the Residential Consumpti.onand Business Consumption Modules to produce forecasts ofelet.trici ty consumption.These forecasts,along with addi t ...onal trial parameters ,are used in the Program-Induced Conserva- tion f:fodule to simulate the effects of go\~ernment programs that subsi- dize g;r mandate the market penetration of certain technologies that reduce the need for power.This program-induced component of conserva- tion is in add!tion to tnose savings that would be achieved through normal consumer reaction to energy prices. The consumpt.ion forecasts of residential and business (commercial, small industrial,and government)sectors are then adjusted to reflect these additional savings.The revised forecasts are used to estimate future miscellaneous consumption and total sales of electricity..These forecasts and sepa.rate assv~ptions regarding future major'industrial loads are used along with a trial system load factor to estimate peak demand • After a complete set of projections is prepared,the model begins pre- paring another set by returning to the 'Uncertainty Module to select a new set of trial parameters.After se',eral sets of projections have been prepared,they ~re formed into a freque.ncY distribution to allow 2 ...8 C\ 2.3.4 The Optimized Generation Planning COGP)Model the user to determine the probability of occurrence of any given load forecast •When only a single'set of projections is needed,the model is run in Certainty-Equivalen.:Mode whereby a specific default set af parameters is used and only one trial is run. Th1e RED model produces projections of electricity consumption by load cent.ers and sectors at 5-year intervals.A linear interpolation is performed to obtain yearly data.The outputs from the RED model runs are used by the ()ptimized Generation Planning (OGP)model to plan and dispatch electric generating capacity for each year. 2-9 The OGP model uses the output from the RED model plus data character- izing the units in the existing electricity generating system.It also uses investment and operating cost data plus operating characteristics (e.g.,heat rate,forced and scheduled outage rates)for new power plants to forecast the most cost-effective electricity generation sys-- tern.In addition to these variables,it requires the 'User to make a specific assumption concerning the required reliabi:.",ty of the system, taken as the loss"'of--load probability (LOLP)of 1 day in 5 years for the Susitna studies. The first calculation in selec tingthe generatin.g capac!ty to install in a future year is the reliability e\Tal uation using LOLP c.ri teria .. This answers the questions of "how much"capacity to add and "when"it should be installed.A production costing simulation is also done to determine the operating costs for the generating syste.m with the given unit additions.Finally~an investment cost analysis of the capital costs of the unit additions is performed.The operating and investment costs help to answer the question of "what kind"of generation to add to the system .. I •I I I I I I l, I I ·.1:·;·...! .'~, ·1·.i,_-"'5 I I I·~",,J I I I I I 2 .4 FUTURE OIL PRICES AND STATE REVENUES i3ecause of the influence of OPEC,with most oil reserves in the ind us- trial countries being depleted,it is likely that the upwat>d move :1.n price could precede the transition period long be.fore the petroleum reserve is eXhausted,and in fact would enter into a "what theruarket will bear"si tua tion.Ultimately,the world oil price should reach the cost of its substitute synthetic fuel. ForecastingfutlIre oil prices is a diffic1I1t and controversial task. However,oil price projections are required in the methodology used in 'this economic and fin.ancial update.Since the Alaska Department of Revenu-e oil price foreCast represents the State vietV'of oil prices,it has been relied upon in this update as di.rec.ted by the Power Authority. In addition,other oil price forecasts have also been considered since oil price forecasts have a prOfound influence on the economic and financial viability of the Susitna Project. 2-10 _.T There is generally a wide range.of strong positions regarding the 10ng- term trends in the supply and demand of oll and i t$prices.At this time,the general consensus is that oil priLces will remain flat or trend downward in real terms for the next few years due to an excess of production capacity.The degree and duration of this sf tua tion wi.11 depend upon the vigor of the world economic;recovery,the longer term. world ec;onomic growth~the success of conservation efforts,and the influence of Ol?EC setting oil prices •Most forecasters predict that oil production will peak at about year 2000,give or take 10 years;and free world oil demand will surpass the peak that was reached in 1979. By that time,the cost of synthe.tic fuel oil would be the basis for marginal pricing of oil,and the world price can be expected to rise over time to the cost of alterna tive fllel oil.This type of price trajectory should prevail under normal free market conditions. I ,., ,., II 1111....•I fl I...·! ~ t I I I I I I .1. 1.' ••••• •••.~ I I I (I I 2.5.1 Alaska Department of Revenue (DOR)Forecast (June 1983) 2.5 OIL PRICE FORECASTS DOR's forecasts of oil prices are on a monthlY basis for the first two years and by quarters for the next three years •Beyond the first five years,DOR forecasts a fixed escalation rate in oil prices for each probability point.The mean or average oil pric.e for each period is determined from the composite frequency distribution. nOR forecasts future petroleum revenues over a 17-year period to assist in the preparation of state budgets.These forecasts are updated on a quarterly baSis •In developing the revenue forecast,a number of State employees of the Office of Management and Budget,Department of Natural Resources j and DOR each develop one to ten scenarios of futur.world oil prices j and assign a subjective probability to each scenario. Using the Delphi method,DOR.aggregates these individuals'forecasts and develops a probability de.nsity function using a computer model iJ The individual probability density functions are then aggregated by the model to produce a composite probability distribution of future world oil prices. A detailed review of oil price forecasts was presented in Volume 2A of the License Application.In this section~the current update of some of these forecasts is presented"The June 1983 Alaska Department of Revenue (DOR)forecast is first presented.For comparison purposes, the Summer 1983 Data Resources Incorporated (DR!)forecasts,the u.S. Department of Energy (DOE)forecasts,and the May 1983 Sherman H.Clark Assotiates -No Supply Disruptiop.Case (SHCA-NSD),which was used as the Reference Ca.se in the FERC License Application,are also presented. In addition,oil price forecasts by several other nationally known organizations are presented.These forecasts are summarized on Exhibit 2.5,and displayed on Exhibit 2.6. T - '1-.:1 ... I I \1,·.~~.. \ I \1 'I I I I I I I I I I I I I ~ 1 •.•......••1 .' f I I 11 I ,I ·I!,, Iij 'I I 1···.\...1 I I I '. I I I I The 17-year projections of the mean oil price (June 1983)developed by DOR are presented 011 Exhibit 2.5.Under the Mean scenario,the crude oil real price is expected to decrease until 1987 to $23.90 per barrel (bbl);then,the real price would increase to $27.45/bbl in 1999. After 1999,the last year of the DOR projections,the price of oil is assumed to escalate at 1.5 percent,the average annual growth rate of 'the period 1994-1999.Hence,with a 1999 price of $27.45/bbl,the 2010 oil price,would be $32.42/bbl.The October 1983 DOR Mean oil price, estimate for 1999 is $29.25 /b'b1 which is about 6.5 percent greater than the June 1983 forecast. 2.5.2 Data Resource Incorporated (DRI)Forecast (Summer 1983) The 1983--2005 projections of crude 01,1 price developed by DRI are pre- sented on Exhibit 2.5.Crude oil prices are expected to remain low in the near term,before beginning rapid escalation in the latter half of the 1980's.Then,real price increase averages about 3.0 percent in the 1990's,and 1.6 percent for the period 2000-2005.The200S real price is expected to be $49.47 per baI'rel. 2.5.3 U.S.Department of Energy (DOE)Forecast (First Quarter 1983) The Policy group of the u.S.Department of Energy has developed,during the first quarter of 1983,projections of crude oil price which will be presented in the National Energy Plan report.These projections are presented on Exhibit 2.5..Real prices are expected to decrease until the mid 1980's,and increase rapidly a.fter 1990.The 2010 real price would vary bet~een $65.60 and $102.40 per barrel. 2.5.4 Sherman !i.Clark Associates ...No Supp.ty Disrupt,ion (May 1983) The 1983 ...2010 projections of crude oil price developed by SHCA are pre- sentedonExhibi t 2.S.The real price of oil is expec.ted to decrease 2 .....12 (; 2.5.,5 Other Oil Pric.e Forecasts o Stanford Research Institute Prices down until 1985,then constant at $25/bb1 (1983), until 1990,then 1 percent increase to present level in 2000. Done wi tho ut mod el s • Price wi thout 2-13 Standard Oil of California Prices flat through 1980's,rise sloW'ly in 1990's. anyWhere betWeen $35 and $50/bbl (1983).Done models. r Rand Corpora.ti.on No big increases before the end of the century.:Prices 'Will stay the same or decline in the next few years,then slowly increase after that"No models are used.: o o to $26.30 in 1983,and remain at that level until 1988.From 1988 to 2010,price increasec at a 3.0 percent annual rate.A special analysis Was done by SHCA to project c.rude oil price to 2040.After 2010,the rate of price escalation is projected to taper off a.s the oil price a.pproaches the price that will bring forth supplies of a1 ternative f~tels • In addition to the oil price forecasts discussed above,the Power Author!ty solicited fort~casts from a total of seventeen other sources. These sources comprise research organizations,universities,and oil companies who have the e,cpertise to perform oil price forecasts"Ten of the seventeen sources contacted had no forecast available or did not supply oil price data 0 The forecasts obtained from the remaining seven sources are presented on Exhibit 2.5 and summarized below: I , i III 'ii,,"1':; I I .'.',,J ..." I I ,.", '."~,.,f,: I I I I I I I I'"',,,'3 I I World Bank 1985 price is at$34.94/bbl (1983),1995 it is at )l~6.07/bbl.. Done partially with models. State of Alaska ,DeED Forecast of AlaSka.'s Development Delphi)Panel 79 percent of the Delphi Panel believe that prices will be at or above.their present level by 2000;51 percent believe they will be higher..Only 8 percent believe they will be lower. reaching 2-14 1985 and then rise slowly, Done partially with models. '}"""--:"" ....:......,~ .~fl Booz-Allen &Hamiltou (for DNR) Three different forecasts are used.The strong economy scenario leadS to a price of $37/bb1 (1983)in 1990, $50.9/bb1 in 2000,and $73.l/bbl in 2001.The weaker economy scenario has prices at $29.7/bbl in 1990,$36.O/bbl in 2000, and $48.8/bbl in 2010.The third scenario comes from the Governor's Office,and aSSUfles prices will stay constant at $29.7/bbl throughout the period .• Chase Econometrics Prices fall until $34.98/bb1 in 2000. o o o o I 'I·-..~.·.~.... I '. I,. I I I '. I I '. I I I I I I if ~.. Phillips Exxon Gulf Congressional Budget Office Council of Economic Advisors Petroleum Industry Research Foundation National Petroleum Council l\merican Petroleum Institute Brookings Wharton Econometrics Al though most forecastere-predic.t that oil prices will fall or remain constant in real terms until around 1985,modEst real price ~.ncreases are predicted by each expert. o Contacted but no forecast available: The assumptions about world conditions :t.n most of the forecasts are qui te similar.Economic growth rates are in the 3 percent r-ange,wi th inflation around 6 percent.Most assume that the majority of changes in consumption brought about by conservation are permanent,and that the amount of energy required per unit ,of Gross National Product (GNP) is going to continue to decrease.Supply is assumed by most to be greate'r than demand through 2000;even though consumption '\Yill rise somewhat,oil's share of the energy market is se€n as decreasing by all the experts,with coal picking up most of this market.Most see OPEC oil as the marginal supply,and also as a ,major determinant of oil pric~.Given the disparity 1n function and c.oncernsamong the forecasters,the similarities in the underlying assumptions and general forecast trends are renIal"'kable. The est:tmates of future 'World 011 prices presented above illustrate the different views and outlooks on the 'World economy by various fore-- 2.6 SELECTION OF OIL PRICE FORECASTS I I I I......', ..1', :. I •• I I I··:..'7 ..' '. I I I I I I I.,..•.·.I~.·'.. .1. ,,'r ,.. i, "1'"I".."f! ,,~''.,':~:~I \i 2-15 The assumptions about world conditions in most of the forecasts are qui te similar •Economic growth rates are in the 3 percent range"with inflation a.round 6 percent •Most aSsume that the majority of changes in consumption brought about by conservation are permanent,and that the aIIlount of energy required per unit of Gross National Product (GNP) is going to continue to decreane.Supply is assumed by most to be greater than demand through 2000;even though consUlIlption Will rise somewhat,oil's share of the energy market is seen as decreasing by all the experts,with coal picking up most of this market..Most see OPEC oil as the marginal supply,and also as a major detenninant of oil price.Given the disparity in functiol1 and concerns among the fore,caste,rs ~the similarities in the underlying assumptions and general forecast trends are remarkable .. Congressional Budget:Office Council of Economic Advisors Petroleum Industry Research Foundation National ~etroleum Council American Petroleum Institute Gulf o Contacted but no forecast available: Phillips Exxon Brookings Wharton Econometrics Although mos ...forecasters predict that oil prices will fall or remain constant in real terms until around 1985,modest real price increases are predicted by each expt-.'rt • The estimates of future WOrld oil pt'ices presented above illustrate the different vi.ewsand outlooks on the world economy by various fore'" 2.6 SELECTION OF OIL PRICE FORECASTS I I.•"" ....'} ,I I ,I I I .•....'•.......', I I •'.......•' I .. • I I I '1· "·'" I·"·'.'··.. casters.The range of forecasts is graphically displayed on Exhibit 2.6. To asSess the ilnpa.ct of future oil prices on.the demand for electric energy in the Railb!.lC,the broad range of forecasts has been analyzed and evaluated.Although it is possible that anyone of the scenarios could occur in the future,some presently seem to be more probable than others.OPEC Seems to be holding the line on.their new benchmark price of $29.90/bbl and the Un!ted States economy is recovering from the 1981-82 recession at a stronger real rate of growth than recently pre- dicted by many economists. In.this update study,the DORMean as well as the SHCA-NSD oil price forecasts are tested.The DOR Mean forecast is used because it relates Susitna feasibility to State revenUe projections. 2-16 The use of the DOR Mean and SHCA-NSD forecasts p.r.~ovides a good basis for assessing the State's economy,the Railbelt:electricity demand,and the eeO.iomic and finartcia1 viability of the Susitna Project. The SHCA-NSn c~se has also been studied to provide a link between this Update and theFERC License Application..IR~pection of Exhibit 2.6 shows that for 1990 two forecasts are lower tha.Ii the SHCA-NSD and ten are higher;in 1995 six forecasts are lower ,and six forecasts highe.r; and for the yea1'2000,seven foreca.sts are lower with five higher.In the ea:rly years (1983-1990)of the projections,the SHCA-NSD forecast is in the:::low range,and in the later years (1995<'-2010)the SHCA-NSD forecast is in the middle of the range of forecixats illustrated. Ex~ibits 2.7 and 2.8 summarize the inp1.:1t and output data for the DOR Mean and SHCA-NSD forecasts over the period from 1983 to 2010.His- 2~7 POWER MARKET FORECAST -------------------------........,"'""- I I. ''''.·' .~'.:. \ I··.·'.·· .~. I I I I I I I I I I I I I I I I····) t ,C'~'.' I I I I I I I I I I":.' j '. I I I I I I I I, 'j I torical data and projections of general fund expenditures ,population, household,energy demand,and peak demand are displayed on Exhibits 2.9 through 2.13. In 2010,the State General Fund Expenditures,in CUrrent dollars,are expected to be $11.8 billion under the DaR Mean forecast and $18.0 billion under SHCA-NSD.The Rail bel t population is expected to increase from 319,767 in 1983 to 506,548 under DOR Mean and to 533,218 under Sl1CA-NSD for the year 2010.The corresponding number of house.... holds woule!iilcrease from 111,549 in 1983 to 185,477 and 195,652,for the DaR and SHCA-NSD forecasts,respectively.As ahown on Exhibit 2.12,the 2010 electric energy consumption would be 5,404 GWh for DaR Mean and 5 ;85 8 GWh for SHCA-NSD.The corresponding average annual gl:'o,\yth rate over the period 1983-2010 would vary between 2.4 and 2.8 percent.The peak dema'1d is expected to increase from 580 MW in 1983 to 1,122 MW under DOR Mean and 1,217 MW under SHCA....NSD for the year 2010. Similar projections for the SHCA-NSD forecast are presented in Exhibi t B of the FERC License Application.Detailed projections of State reve- nues,economic conditions,and electric energy demand are presented on Exhibits 2.14 through 2.21 for the.DaR Mean scenario. Exhibit 2.14 presents the DOR Mean projections of State petroleum reve- nues from each of the primary revenue sources through the year 2010. The first two columns of this exhibit contain projected royal ties and severance,or production taxes,respectively.These projectiortsare in nominal dollars,reflecting an annual change in the conSU1ller price index of 6.5 percent"The projections of royal ties and sever'~"1ce taxes through the year 1999 were produced b:r the Department of Revenue's pet.roleum l:'evenLteforecastillg model system,adjusted ft)r minor differences in the future assumed rate of inflation.Projections £Ol:' 2 ....17 '::1 2-18 Exhibit 2.14 also presents projections of State petroleum revenues derived from corporate income ta2Ces,property taxes ,lease bonuses,and federal shared royalties.Future revenues from these sources,estimat- ed by the Institute of Social and Economic Research,were used along with the projections of royal ties and severance taxes as input to the MAP economic sub-model. the year 2000 through 2010 were extrapolated using the ave,rage annual rate of change between the years 1996 through 1999. E2Chibit 2.15 presents projections of several important components of the State's fiscal structure.These components include tmrestricted general fund expenditures ,the balance in the general fund,permanent fund dividends,State personal income tax revenues,level of outlays for subsidies,and the percentage of Permanent Fund earnings that are reinvested..The exhibi t shows that dividends from the Permanent Fund continue to be disbursed through the year 1987,at which time the pro- gram is halted.A State personal income tax :ts relnstituted in the year 19 89 in order to augment revenues.State subsidy progi'ams are terminated after the year 1987,and reinvestment of Permanent Fund dlvidends ends after 1989.The subsldy programs that may be affected include,for eitample,mortgage subsidies,student loans ana AIDA lndus- trial development loans. Each of these measures is assumed to occur in order to permi t Sta te expenditures to grow as closely as possible in proportion to the rate of population growth ,taking into account the effects of inflation. However,while th2se fiscal measures (ire assumed to be implemented, petroleum revenUeS are projected to contlnue to provide the largest share of State expenditures.In the year 2010,they w.Lll account for approximately half of the total unrestricted general fund eitpel1ditures, i.e ..,those expenditures not funded by revenues dediCated to specific functions. ji I I I I I I I I I 1.1,~ I I I I I I I I I ,• area!> - 2-19 i - Exhibit 2.18 presents projections of households for the State,the Railbel t,the Anchorage area and Fairbanks area.In contrast to pro- jected employntent,households are projected to increase faster than population.Statewide households are projected to increase by 63 per- cent by the year 2010,compared to a 62 percent increase in the Rail- belt,a 66 percent rise in the Anchorage area,and a 58 percent increase in the Fairbanks area. The growth of employment,shown on Exhibit 2.17 is uniformly lower than that of population.While statewide non-agricultural wage and salary employment is projected to grow by 53 percent during the next 27 yea:r:s,to tal State employment is forecasted to increase by only 47 percent.Again,the Railbelt is projected to e~perience a higher employment increase,rising by 52 percent,with the :.nchorage area growing by 55 percent compared to 43 percent growth in the Fairbanks E~hibit 2.16 pre()ents the DOR Mean population projections for the State,Railbe1t,Anchorage-Cook Inlet area,and Fairbanks-Tanana Valley area.Railbelt population is projected to grow by approxima.te1y 58 percent between 1983 and 2010,from 319,767 to 506,548.In the Rail- belt,the Anchbl.-age area is projected to grow by 61 percent,compared to the projected growth in Fairbanks of 49 percent .. The effects of demand elasticity are computed by adjusting the average consumption per household for conservation and fuel substitution,as ShbWU on Exhibit 2.19.In the Anchorage area,the average consumption per household is expected to decrease from about 13,699 kWh in 1980 to 12,582 kWh in 2000,due mainly toche real increase bf electricity price which will continue to cause some conversion from electric space heating tb substitute fuels.After 2000,the consumption is expected to increase to about 12,760 kWh by 2010.In the Fairban.ks area,the average household c.onsumption is expec ted tb increase from 11,,519 kWh I I I , J I I I ,. I I - I"'.'.,'~.' , I I 1·1..·•,. I I o in 1980 to 14,526 kWh in 2010,or about all average annual growth rate of 0.8 percent.This increa.se is due to the stabilization of electric-' i ty prices,while the prices of substitute fuels are increasing.The projected consumption in year 2000 is similar to the 1975 average con- sumption. 2-20 A breakdown of electric energy demand projections by customer cate~ gories,based on the underlying projections of average consumption per household and per employee presented in the previous paragraphs,is presented on Exhibit 2 ..21.Exhibi t 2.21 also shows miscellaneous sector which includes street lighting,second (recreation)homes,and. vacant houses..It corresponds to about one percent of the total energy demand.The exogenous industrial loads include the large industrial customers which are located in the Homer Electric Association,Inc Cl (HEA)service area,and an estimate of the amount of electricity that could be provi.ded by the ut:~lities to the military installations. These e~ogen()us loads would increase from about 108 GWh in 1983 to 315 The emplo}TJDent forecasts obtained from MAP are used in the RED Business Consumption module to derive the electric demand in the commercial- government-small industry sector.Exhibit 2 ..20 summarizes the "busi- ness use"per employee projections.The consumption projections were obtained from a forecast of predic ted fleor space per employee,and an econometrically derived electricity consumption per square feot,which is then adjusted for price impacts.The floor space per employee is expected to increase by 10 percent in Anchorage and 15 percent in Fair- banks to approach the current national average by the year 2010.As a resul t,i.n the Anchorage area,the average consumption per employee is expected to increase from about 8,407 kWh in 1980 to 11,170 kw'h in 2010,at an average annual rclte of 1 ..0 percent.In the Fairbanks area, the consumption per employee is expec.ted to increase from 7,496 kWh in 1980 to 9,670 kWh in 2010,at an average annual growth rate of 0.8 percent. I I I I I I .11 II I I I I I I I I I I I I GWh in 2010 for the Ancho'=age....Cook Inlet area,and from 0 to 50 GWh in the Fairbanks ....Tanana Valley area.A detailed discussion of the industrial and military loads are presented in the following paragraph" 2 ...21 The large industrial projections were based on work by Burns & McDonnell in their preparation of the 1983 Power Requirements Study for HEA.Those projections indicate that electrical demand .isexpected to increase from 100 GWhin 1982 to 142 GWh in 1990 and 158 GWh in 1995. An annual growth rate of 3.5 percent was assumed after 1995 • Discussions were held with representatives of the two military instal... lations (Fort Richardson and .Elmendorf)of the Anchorage....Cook Inlet Area,and the three military installations (Fo~·t Wainwr.i,ght,Fort Greely,and Eielson)of the Fairbanks....Tanana Valley Area to obtain information on historical and projected electricity consumption.A continuation of the annual militar)t electricity demand of 150 GWh is expe{!.ted in each area.Existing power contracts and exchanges with the utilities were reviewed and estimates of the amount of elec.tricity that could be provided by the utilities were discussed,recognizing that continued operatfon of military generatil1g facilities for heating pUr- poses is expected.For the purpose of load fo!'ecasting,it was assumed that one-third of the total military elec tric.al demand in eat h area,or 50 GWh,would be provided by the utilities.The load demand would increase linearly from 0 GWh in 1985 to 50 GWh in 1990 in each area, and remain at 50 GWh thereafter~ Finally,Exhibit 2.22 summarizes the annual peak and ;nergysales pro- jections for each load center and for the total system.The average annual growth rate of electricity demand i.s expe.cted to sloVlly Jectease from about 5,,6 pe=c.ent during the period 1980-1985 to 1.8 percent during the period 1995-2000.After 2000,the demand is ~pected to increase at an average an,nual rate of 2.1 percent until 2005,and 2~6 perc.entforthe period 2005-2010 .. I I I I I I I I I I I I I I.~i. ..... I ·1";, "'" I I I 2-22 2 ..8 COMPARISON WITH PREVIOUS FORECASTS AND UTILITY FORECASTS 1"'- Two se,ts of previousforeca.sts nave been used in the early stages of the Susi tna.Hydroelectric Project studies in addition to the power market forecasts presented in de tai 11.in this section.In 1980,the Institute for Social and Economic Research (ISER)prepared economic and accompanying end-use electric energy demand projections for the Rail- bel t..Th.ese forecasts were used in several portions of the Susi tna Feasibility Study,including the Development Selection Study. In 1981 and 1982)Battelle Pacific Northwest Laboratories produced a series of load forecast,~for the Railbelt)as shown on Exhibit 2.23. These forecasts were developed as a part of the RailbeltAlternatives Study completed by Battelle under contract to the State of Alaska. Battelle's forecasts were based on updated economic projections pre- pared by ISER and some revised end-use models developed by Bat.telle which took i,to account price sensitivity and several other factors not included in the 1980 projections.The December 1981 Battelle forecasts were used in the optimization studies for the Watana and Devil Canyon developments which were completed early in 1982.The 1981 forecast reflected a projec.tion of world oil nominal prices of $27.45/bbl in July 1981 to $31 ..45/bbl in July 1982,with first quarter prices increasing from$36.35/bbl to$44.65/bbl over the next three fiscal years)and then from $53.22/bbl in the sixth fiscal year to $157 ..60/bbl in the subsequent seventeenth fiscal year. These previous forecasts were made for three electric load cen~~Z:D:the Anchorage-Cook Inlet area.;the Fairbanks-Tanana.Valley are0;and the Glennallen-Valdez ~rea.When these studies were undertaken,it was not decided whether the Glennallen-Vald~z area would be included in the intertied Railbelt electrical system.The decision was subsequently made,based on economics,that the Glennallen-Valdez area would not be initially included in the interconnected atea •Therefore,the updated I I I I I • I I,. I I,. I I I I I I I 2-23 Exhibit 2.23 provides a summary campa/rison of these power market fore- casts used in e(...lier studies.While these forecasts are not precisely consistent in the definitions of the market area or in the assumptions relating to the current load forecasts,the comparison does provide insight to the change in perception of future growth rates during the time that the various sets of forecasts were developed.The ISER fore- cast projected an average annual growth rate of about 4.0 percent for the period 1980 to 2010"The Battelle 1981 forecast projected an average annual growth rate of about 3.5 percent over the same period. 111e DOR Mean shows a 2.4 percent average annual growth rate. electric load forecasts presented herein do not consider the power requirements of this load center. In addi tion to the ISER and Battelle forecasts performe..!for the pur- pose of planning the Susitna Hydroelec.tric Project,the Railbelt utili- ties annually produce forecasts for their own respectivEl markets. Exhibit 2.24 summarizes the projections made by the utilitie~..in early 1983,for the period 1983-2001..The average annual growth rate is expected to decrease slowly from about 6.0 percent for the period 1983- 1990 to 4.5 percent for the period 1991-2001.The total energy gene.ra- tion is expected to be 7,662 GWh in year 2001,which is about 75 per- cent greater than the DOR Mean projections. A power requirements study was recently performed by Burns &McDonnell for Chugach Electric Association,Inc.The results are summarized in Exhibit 2.25.Three forecasts were developed:low,moderate ~and high for the period 1983-1997 •The Burns &McDonnell projections confirm the forecast made previoualy by the utility.Under the moderate forecast,energy demand for the year 1997 is 3,467 GWh,while the utility projection wasS,428 GWh.The average annual growth rate of electricity demand is expected to vary be.tween 3 ..9 and 6.2 percEut for the period 1983-1997.The average annual growth rate of the moderate I I I I I I I I I I I I I I I I I I I I I I I I 'I I I I I I I I I I I I' I forecast is about twice the growth rate of theDOR Mean project.ion for the Anchorage-Cook Inlet area. 2•9 SUMMA...~y Exhibit 2.26 provides a summary of the DOR Mean and SHCA-NSD power demand forecasts • A comparison wi th the current forecasts of the Rail- belt utilities i.ndicates that the update forecasts are substantially lower.For instance,under the SHCA-NSD scenario"the forecasted 1990 energy demand is 3,737 GWh,compared with 4,678 GVlh forecast by the Railbe1tutilities.It is not possible at this point to establish the .reasons for the differenc.e.,since the forecasting techniques are lik~ly to be different.In any case,the utilities'forecasts are likel~r'to be more accurate on a near-term basis,since their forecasts are helt"~'.... 11 influenced by recent trends.On the other hand,the forecasts usirig the ~-AP and REDMod~ls take a fundamental approach with the primary Objective of developing a reliable forecast on a long-term basis.I~ any case,the use of these lvwer forecasts is a conservative approach in analyzing the economic feasibility of the Susitna Project. 2-24 '1 -..-----------------OiL PRICE FORECASTS (1983 $/bbl except as noted) Ave.\age Average Average Average AverageRateofRateofRateofRateofRateefYearChange.Year Change Year Change Year Change Year Change Year1985PerYear1990PerYear1995PerYear2000PerYear2005PerYear2010-.-..._-(%)(%)(%)(%)(%) nOR Mean 24.83 -0.4 24.39 1.1 25.79 1.5 27.87 1.5 30.06 1.5 32.42 SBCA-NSD 26.30 1.2 27.90 3.0 32.34 3.0 37.50 3'..0 43.47 300 50.39 DRl*27.77 4.0 33.85 3.2 39.58 2.9 45071 1.6 49.47 NA NA DOE Low*23.80 3.2 27.00 7.4 39.70 3.9 48.20 3.7 57.70 2.6 65.60 j DOE Mld-Range*25.90 4.3 31.9(>7.8 46 ..50 4.3 57.40 6.4 72 .2(~1.3 83.60 If I DOE High*26.80 6.2 36.20 8.0 53 ..10 5.3 68 ..80 5·,,9 91,,50 2 ..3 102 ..40 SRI*25 ..00 000 25,,00 1 ..0 26.27 1 ..0 27 ..61 Standard Low**29 ..00 0.0 29 ..00 1.9 31 ..86 1 ..9 35.00StandardHlgh*~29.00 0 ..0 29 ..00 5 ..6 38 ..00 5.6 50 ..00 Rand**29 ..00 0 ..0 29 ..00 0 ..7 30 ..00 0.7 31.00 BAH High**33.92 1.8 37.10 3.2 43.50 3.2 50.90 4.5 63.60 2.8 73.10BAHMedium**29 ..70 0.0 29 ..70 1.4 ~1.80 2.5 36.00 3.3 42 ..40 2.8 48.801SAHLc:**32.90 -2.0 29.70 0.0 29.70 000 29.70 0.0 29 ..70 0.0 29,,70 World Bank**34.94 3 ..5 41 ..57 2 ..0 46.07 Chase 27.41 3.0 31.86 1.1 33,69 0.8 34.98Econometrics** *1982 $lbbl **Solicited Forecasts by the Alaska Power Authority m X :I:-[XJ -t ~ <.n 70 10 t----+----""'""""'i------+-----+---~------I 20 t----+--------+--------f-----t------------4----~ ". ..J-~40 t----+---~-+-____.::I"q_-~:..--_-I---~~-+---__I o Wo~o~~~~ Q..30".,a~~~~.~~~~:l-==~~-~-~~ C ~---BAH LOW.-~~ ..J SfH a:o OORMEAN \JUNE ,983) ~ BAH BOOZ,AlL~N,HAMllTON CHASE CHASE ECONOMETRICS DOE DEPT.OF ENERGY DOR DEPT.OF REVENUE DRI DATA RESEARCH INSTITUTE RAND RAND CORPORATION STAN STANDARD OIL OF CALIFORNIA SRI STANFORD RESEARCH INSTITUTE •60 t--_W+8__W_O_R_LD_........BA_N_K ~I__-----~'--___.l~4_---____4-.Q.c, ~ (') ~SOt---+-----+------+--~-~~----+---~.-61 ..... r 1 I I>; "I I I I I I I 1 I I Il.",..,'i I Ol..-----'----------a.-----.JI....-------.......----L.-------..J •18831985 1990 1995 2000 2005 2010 YEAR I ALASKA POWER AUTHORITY SUSlTNAHYDAOElECTAICPROJECT UPDATE I ALTERNATIVE OIL PRICE PROJECTIONS.1 SEPTEMBER 1983~j ~------------.--...------.......-..........------------------..........----I ----------.....~". :t ...----.•"-.. ~.'.,-- DOR-MEAN SCENARIO SUMMARy OF INPUT AND OUTPUT DATA Item Description 1983 1985 1990 1995 2000 2005 2010- World Oil Price (1983$/bbl)28.95 24.83 24.39 25.79 27.87 30.06 32.42 7.75 6.54 6.43 6.80 7.34 7.92 8.541.73 2.00 2.81 3.40 3.58 3.76 3~96 Energy Price Used by RED (1900$) Heating Fuel Oil-Anchorage f$/MMBtu) Natural Gas-Anchorage ($IMMBtu) State Petroleum Revenues!/(Nom.$x10 6 ) Production Taxes Royalty Fees State G~neral Fund Expenditures (Nom.$x10 6 ) State Population State Employment Railbelt Population Railbelt Employment Railbelt Total Number of Households 1,5l2 1,451 3 H 288 457,836 243,067 319,767 159,147 111,549 1,451 1,450 3,700 490,373 258,634 341,839 169,392 120,219 1,723 2,092 5,390 543,901 254,232 380,344 183,738 135,554 1,444 2,048 6,106 581,710 296,942 404,351 192,881 145,532 1,394 2,238 7,306 614,.105 310,315 430,823 204,424 156,234 1,472 2,588 9,214 653,359 329,544 463,623 220,479 169,098 1,555 2,993 11,830 706,582 357,253 506,548 214,809 185,477 Railhel tElectt'icity Consumption (GWh) Anchorage Fairbanks Total Railbel t Peak Demand (MW) 2,325 2,567 2,930 3,159 3,459 3,844 4,3874815366707518259141,0292,.006 3,102 3,600 3,910 4,284 4,757 5,417 580 641 749 814 891 988 1,125 11 Petroleum re'\1'enues also include corporate income taxes,oil and gas property taxes,lease bonu.ses,and federal shared royalties. m X :I:-m--f N ~ ..,,•"•'4 • ".,.•.r "~t- ". 0 RailbeltElectricity Consumption (GWh) Anchorage 2,326 2,561 3,045 3,371 3,662 4,2.07 4,735Fairbanks4825356918008809861,123Total2,008 3,096 3,737 4,171 4,542 5,093 5,858 Railbelt Peak Demand (MW)579 639 777 868 945 1,059 1,217 1/Petroleum revenues also include corpo.rate income ta.xes,oil and gas property taxes,lease bOlluses,and federal shared royalties. ItetnDescription 1983 1985 1990 1995 2000 2005 2010~- World Oil Price (1983$!bbl)28.95 26.30 27.90 32.34 37.50/43.47 50.39 - m X ::t:-CD-...., r-.Jm •• 2,421 4,689 17,975 744,418 376.,169 533,218 255,974 195,652 - 2,150 3,799 13,035 686,663 345,101 486,851 231,584 177,849 --\ 1,910 3,078 9,714 644,111 325,186 451,561 214,542 163,913 - 1,868 2,651 7,729 608,810 313,954 423,460. 204,668 152,463 -.. 2,032 2,480 5,577 554,634 293,689 389?026 190,883 138,640 1,561 IJ555 3,700 490,146 258,396 341,613 169,197 120,140 •....._..~....,., t .~""',.'.." SHCA-NSD SCENARIO 7.75 6.45 6.84-7.93 9.19 10.65 12.35L,,73 1.95 2.88 4.05 4.29 4.96 5.38 - 1,474 1,4!17 3,288 457,.836 243,067 319,767 159,147 111,549 ......•. fl . SUMMARy OF INPUT AND OUTPUT DATA ---•.~.-!I..............'...-- Energy Price Used oyRED (1980$) Heating Fuel Oi1-Anchorage ($!MMBtu) NaturalGaa -Anchorage ($lMMBtu) State Petroleum Revenuesl!(Nom.o $x10 6) Production Taxes Royalty Fees State General Fund Expenditures (Nom •.$x10 6 ) State Population State Employment Rai1belt Population Railhel t Employment Railbelt Total Number of Households - ? ~ t~b·t~~'1W'.~',..~~ J t J,, 1 EXHIBIT2.9 2Q05~2010 o'f '~, ~. "l 191.7%........209.4%........ 1995 YEAR 2000 "t / / PRO~CTIOt S SHGA-N~/ ~OR ME~ /"~V /""'"~~ ~~ ~ ~ HtSTORICAL 2·- 2 1985 1990 8 .NOTE:PE,qCENT AGES ARE AVERAGE .ANNUAL GROWTH RATES FOR .&YEAR PERIODS .6 12 10 16 14 20 18 24 22 1960 1965 197Q 1975 1980 1985YEAR ALASKA POWER AUTHORITY SUSITNAHYDROELEClRIC PROJECT UPDATE ALTERNATIVE ST,ATEGENER.ALFUN'D· EXPENDITURE FORECASTS ·I SEPTEMBER 1983 ---.J .28 26 CJ') wa::::>t-.- C Z W 0- X W Cz::> LL. ...J c(a; wzw (!) W I-«I-en r-----------.............----------------------------"I I I I I I I I I '. I I I I I I, I I I"'oj 1985 20'10 198019701975 YEARS &_0 1965 1990 1995 PROJECTIONS HISTORICAL 3.3 % 0+-----.....+-----+----+----+----....( 1960 400 -I----+--=--~~+------+-----I-----~ 3001985 NOTE:PERCENTAGES ARE ANNUAL GROWTH RATES FOR 5-Y AR PERIODS 600 +------+------+--------+------+.-------1 EXH IBIT 2.10 100 -t-----+-.....--------+-------+--......---I-------~ 700 .........----r-----"T'-----r------..,...-------,. ALASKA POWER AUTHORITY SUSfTNA HYDROELECTRIC PROJECT UPDATE A L TERNA TIVERAI LBELT POPULATION FORECASTS SEPTEMBER 1983 zo-t-<...J :J Q.o 0-.... ..J Wco ..J--<.200 .......------+-----~rtlfIIC"---------+----~--........ja: I I I I I I '. J il I '. I I I -. I I I I ~--~--------------- 0+I..,I -I I I ---i lA60 1965 1970 1975 1980 1982 1985 rn X ::I: tolgl I SHCA ...NSO OOR ..MEAN 2010 NOTE:PERCENTAGES AHE AVERAGE ANNUAL GROWTH RATES FOR5-YEAH PERIODS 20'05~2000 YEARS HISTORICAL 19951990 YEARS ALASKA POWER AUTHORITY SUSITNA I-fYDROELECTRICPROJECT UPDATE ALTERNATIVE RAILBEL T HOUSEHOLDS FORECASTS SEPTEMBER 1983 ~PROJECTIONS ----.-..--,----~,.- -------~'''':''..... ""-3.8%- Hl85 100~I I 25 I I I I I I 75 t------..~<r ~((5 0 1 I ..---5 .1'/0 •I J.~.5 .1"/';::;;:"'""1'. _3.8%=t:::---•.I I "i I t rno ..J 125o I w rn ::>o I l- -' W OJ ..J 225 200 -C/)175oz<: C/) :;) ~150 b (j I I ' fi I 1185 ..... f\,) NOTE:PERC~NT.AGES.ARE AVERAGE ANNUAL GROWTH RATES FOR 5-Yf:AR PERIODS m X :I:-to -t I'\) c.,......._-~""="~'-"'='~'•..---- 1980 1982 .. 1975 (--.~ YEARS PROJECTIONS 1970 ----.. 1965. ;ft! ALASKA POWER AUTHORITY SUS·ITNAHYDROELECTRIC PROJECT UPDATE ALTERNATIVE ELECTRIC ENERGY DEM.ANDFORECASTS SEPTEMBER 1983 ".....~. c--I 1960 6.000 --l 'I ,I I ~SHCA-NSO COR MEAN 3.000 -of I -4 YEARS ~,~ 1985 1990 1995 2000 2005 2010 I I 1 ~.1.HISTORICAL MOO "i I 1-.i _","10""'"I I I ,•.~ t.ooo-l I ~-,~-~ 7.000.I I I T - •G z Q~4,QOO 1.~~~tn..-t~1 7 '·---..----1----~ C!) CI: W Z UJ ~5.000 ~I I I --r ;iiJIP ~.,.I ~ C!)....., ....~~-,,~~J'•.~.'.'-t .........,,~,.."',..,,..-.'. ~ I r::f. c 2010 NOTE:PERCENTAGES ARE- AVERAGE ANNUAL GROWTH RATES FOR 5 u YEAR PERIODS m X :I:-OJ--f l'.).--~ &.6 2000 ~.O· 19951990 YEARS .., ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE AL TERNA TIVEELECTRIC PEAK' DEMAN>DFO.RECASTS SEPTEMBER 1983 200 I •=z I I I t _1.£......~_ YEARS 14400'T"I I I = ,'1 I PRO,JEC·:10NS.J I ....d SHCA~..NSO1200.~1 ,,-.---,•..I ~I . I I DOR-MEAN 400 I I I ...-._.---,--~I I 1000 t I /I f-l::sa I ,.-=:-I 01 f t't 'if 1960 1965 1970 1915 1980 1982 1985 , tI " "'-:1c~~eou I t~Iw,c I~t~600 I a..1985 -•2 .~ I.,.,_ ~..-~'..-j . .-...'.'.__~.~",t_.,J .:.__.,,'_ o •_~~~<f!h'~I.:J ,I EXHIBIT 2.14 3510.~50 3020.891 2815.132 2988.427 3209.052 3423.909 3367.283 3679.162 3902.144 3816.821 3821.384 3964.902 4066.910 3922.448 3834.146 4055.615 4201.664 4253.129 4407.262 4510.521 4743.270 4926.188 S120.023 5325.602 3543.797 5775.559 ~021.910 6283.969 6562.941 TOTAL TO GENERAL FUHD (NET OF PERMANENT FUND CONTRI- BUTION) 3960.200 3395.811 3163.128 3358.302 3609.693 3853.240 3824.235 4179.980 4432.742 4332.672 4339.115 4502.324 4615.305 4443.250 4340.723 4585.906 4747.305 4806.348 4976.703 5156.723 5346.701 5541.363 5759.457 5983.824 ~221.355 6473.016 6739.848 7022.980 7323.641 TOTAL INCLUDING BONUSES AND FEDERAL SHARED ROYALTIES 142.700 148.600 153.200 158.000 163.456 169.101 174.940 180.981 187.231 193.697 200.385 207.305 214.464 221.870 229.532 237.458 245.658 254.141 262.911 211.996 281.389 291.106 301.158 311.558 322.317 :i33.447 344.962 356.874 369.198 668.900 235.622 246.073 270.000 288.900 311.916 336.572 364.246 399.675 459.687 506.563 562.968 622.593 693.756 751.489 813.035 898.521 960.344 1041 ..998 1130.593 1226.721 13')1.022 1444.191 1566.983 1700.214 1844.773 2001.625 2171.812 2356.468 STATB PETROLEUM REVENUES *••*.M***~.*••********** (MILLIOJiI $) *******~.** 1590.000 1511.729 1371.872 1450~802 1554.771 1654.900 1484.916 1631.482 1723.442 1615.883 1559.445 1582.365 1584.669 1444.414 1333.398 1414.253 1420.565 1319.000 7.394.021 .1409.361 1424.863 1440.536 1456.381 1472.401 1488.596 1504.970 1521,524 1538.260 1555.18). S8VERANCE CORPORATE PROPERTY TAXES INCOME TAXES TAXES 1530.000 1450.820 1356.917 1449.808 1574.577 1689.480 1799.450 1974.123 2092.330 2032.379 2041.312 2116.6&:' 2159.517 2048.210 1990.301 2084.163 2144.563 2173.862 2237.762 2303.776 2311.737 2441.703 2513.734 2587.889 2664.231 2742.826 2823.7~,9 2907.040 2992.797 ROYALTIES ----------------,--,-------------:_-----------------_......~--.....------- T- 1982 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 SOURCE:!AP HODEL OUTPUT rILES 88.23 ANDHER.23 VARIABLES:RPRY.RPTS,R'l'CSPX,iPPS.RP9S,AND 1lP9SGF .. I I :1 I I ·Is .<.,,,.,H: I I I I I,. I I 1'\<I;~: 11, ..'~ I. ""· .'1I I I.·..'·······•.····. j,; I ';~ 0.000 0.500 0.500 0.500 0.500 0.500 0.500 0.500 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0 ..000 0.000 0.000 0.000 0 .•000 0.000 0.000 0.000 PIReEN'!'OF PBRKAHENT FUND EARNINGS RIIHVESTID 634.000 500.000 350.000 300.000 200.000 100.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 217.174 444.067 489.953 541.554 594.960 631.101 672.065 722.809 18.1.378 844.131 910.612 983.385 1062.438 1148.529 1244.121 1348.620 1461.278 1583.202 1714.895 1857.048 2008.690 2172.465 425.000 152.608 196.668 222.540 250.679 281.617 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 O.uOO 0.000 0.000 0.000 0.000 PER!lANENT STATE STATE FUND PEiSOHAL SUBSIDY DIVIDENDS INCOME TAX PROGRAMS STATI GOVERNMENT EXPENDITURES ****~~~*~~*~*~*************** (KILLION $> ~**$liJl:**~*** GBNERAL FUND BALANCE 399.200 521.801 409.699 190~332 190.320 190.316 190.313 22.027 108.285 108.305 108.320 108.340 108.355 108.379 108.402 108.426 108.449 108.465 108.477 108.500 108.523 108.547 108.570 loe 594 108.625 108.660 108.691 108.727 108.766 UNRE- STRICTED GENERAL FUND EXPENDI- TURES 4601.891 3287.977 3389.657 3699.574 3733.185 3999.295 3994.070 4746.605 5390.395 5527.559 5643.840 5938.184 6141.148 6106.457 6141.340 6498.758 6789.93.4 6991.496 7305.895 7640.316 7994.613 8373.992 8781.945 9214.430 9674.970 10164.960 10686.680 11241.370 11830.010 EXHIBIT 2.15 SIJM.ATION CASE:U DEPA.RlHEHr OF UV!NUE,JUNE 1983 !lEAN 1982 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 SOURCE:HAP HODEL OUTPUT PIL£SH2.23AND HER.23 VARIABLES:EXGrS!!,BALGF,BXTRNS,JtTIS.EXSOBS.AHD EXPFUIC I I I I I I I I I I I • I I I I I I I SIKUJ:.ATIOH CASE:AI:DIPARnwn .OF RBVENUE,JUNE 1983 lION EXHIBIT 2.16 67.277 68.711 7~.523 72.360 74.004 75.497 76.206 71.400 79.231 19.990 80.868 82.071 83.652 83.957 84.681 85.721 86.640 87.559 88.616 89.744 90.81fJ 92.024 93.264 94.580 95.997 97.477 99.048 100.682 10.2.413 239.830 251.057 259.618 269.479 217.869 282.350 286.345 293.177 301.114 302.869 312.070 314.824 317.521 320.394 324.160 328.994 $33.205 337.600 342.207 346.930 351.855 357.275 362.995 369.043 375.466 382",151 389.233 396.407 404.135 307.105 319 ..767 330.201 341.839 351.873 357.846 362.552 370.576 380.344 382.859 392.937 396.894 401.173 404.351 408.841 414.714 419.844 425.158 430.823 436.674 442.731 449.299 456.259 463.623 471.462 419.628 488.280 497.089 506.548 437.175 457.836 473.752 490.373 505.292 516.310 524.023 532.751 543.901 548.656 565.792 513.417 577.042 581.710 587.896 594.829 601.122 607.410 614.105 620.790 627.799 635.795 644.315 653.359 662.935 673.061 683.805 694.797 706.582 -~~-----~------~--~~~~-------~------~--~ POPULATION *****-**** (THOUSANDS) **-******** GREATER GREAtER STATE RAILBELT ANCHORAGE PAIRBANKS 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 SOURCE:MAP 80DIL OUTPut'ILES 81.23 AND 88R.23 VARIABLES:POP.P.IR.P.AG.ANDP.FG ,·.1··".·! ",. I I,.~ I I I I I I I I I •• ;,...• I .1. ··.···•.'~1 I I I I SIMULATION CAS!:AJC DBPAR'rftl$NT OF RBVEHUE,JUNE 1983 MEAN SOURCE:.HAPHODEL OUTPUT rILBSHB.23 AND HER.23 VARIABLES:EK97,1If99,M.li,H.AG,AND K.FG EXHIBIT 2.17 33.500 33.927 34.406 35.569 36.383 36.900 36.998 37.346 37.818 38.147 38.738 39.249 39.475 39.699 39.980 40.417 40.831 41.212 41.675 42.171 42.693 43.236 43.861 44.539 45.272 46.051 46.869 47.738 48.626 120.533 125.221 127.852 133.823 138.003 139.640 140.685 143.048 145.921 146.042 151 ..42~' 152.012 151.853 153.181 154.720 156.867 158.733 160.651 162.749 1\)4.921 167.256 169.909 ],72.815 :!.75 .941 179.276 182.776 186.460 190.2.06 194.183 154.033 159.147 162.258 169.392 174.385 176.540 177.683 180.394 183.738 184.190 190.167 191..261 1.91.327 192.881 194.700 197.284 199.564 201.863 204.424 207.092 209.949 213.146 216.676 220.479 224.548 228.827 233.329 237.944 242.809 RAILBBLT GR~~TER GREATER TOTAL ANCHORAGE FAiRBANKS TOTAL TOTAL DfPLOYKENT ********** ('1'~OUSANDS) *********** STATE TOTAL 231.984 243.067 246.983 258.634 267.182 272.616 275.202 278.393 284.232 282.955 297.053 296.787 295.727 296.942 299.449 302.636 304 ..927 307.409 310.315 313.186 316.348 320.429 324.804 329.544 334.571 339.834 345.536 351.107 357.253 1,92.903 202.237 205.902 216.836 224.846 229.926 232.340 235.306 240.777 239.563 252.777 252.503 251.478 252.580 254.883 257.812 259.885 262.116 264.791 267.483 270.447 274.272 278.371 282.812 287.521 292.496 297.787 303.001 308.751 STATE NON-AG WAGE AND SALARY --~~~~~---~~~--~-~-------~---~~--------~,---~------1982 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 I-'.•. ..'~ I jl I I I • I I I I I I I~ ·1 .,,1 I IJ,:; I I I·~~.·.·.'·.OJ "'I SIMULATION CASE:.AI:DEPUTKENT OFUVENUE,JUNE 1983 !lEAN SOURC!:1fAP IIODEL OUTPUT FILES HE.23 AND HER ..23 VARIABLES:HH,HH.IR,HH.AG,AND 9H.FG EXHIBIT2.18 22.894 23.511 24.246 24.991 25.657 26.265 26.597 27.018 27.798 28.124 28.512 28.996 29.625 29.783 30.095 30.524 30.903 31.282 31 ..711 32.166 32.621 33.081 33.573 34.091 34.645 35.221 35.828 36.458 37.123 -- 83.678 88.038 91.425 95.228 98.501 100.369 102 ..088 104.705 107.757 108.516 112.182 '..13.368 114.527 115.749 117.303 119.242 120.933 122.691 124.'>23 126 ..~93 128.335 130.454 132.674 135.007 137.473 140 ..025 142.717 145.435 148.354 HOUSEHOLDS *.*~Ut*~**~ (THOUSANDS) *********** 106.572 111.549 115.671 120.219 124.159 126.633 128.~:'j 131.783 135.554 136.701 140.694 142.364 144.152 145.532 147.398 149.766 151.836 153.972 156.234 158.559 160.956 163 ..535 166.246 169.098 172.118 175.246 178.545 181 ..894 185.477 GREATER GREATER RAILBEL!ANCHORAGE FAIRBANKSSTATE 145~4S3 153.141 159.154 165.377 170.988 175.232 178.319 181.739 185.983 188.025 194 ..310 197.343 198.998 201 ..001 203.519 206.291 208.842 211.390 214.073 216.749 219,,531 222.645 225.935 229.400 233 ..044 236.874 240.913 245.036 249.1128 ----~-~-~-~~-------~~------------~-----~1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 lq99 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 I I il I I I I I I I I I I I I I I I I'.·'····j 1980 2466 5740 3314 11519 11519 1985 2536 6179 3607 12322 12150 1990 2606 6447 3864 12916 12688 1995 2676 6658 4043 13377 13175 2000 2746 6793 4312 13851 13722 2005 2816 6852 4507 14175 14149 2010 2886 6892 4656 14434 14526 / EX H18 IT2.~19 13699 12851 12549 12544 12582 12628 12758 After Adjustment Total (kWh) 13699 13132 12830 12730 12759 12839 12976 r 5089 4821 4598 4511 4460 . 4419 4440 6500 6151 6022 5958 5989 6060 6126 Anchorage-Cook Inlet Area Fairbanks-Tan?na Valley Area DOR MEAN SCENARIO RESIDENTIAL USE PER HOUSEHOLD 2110 2160 2210 2260 2310 2360 2410 Before Conservation Adjustment and Fuel Substitution Small Appliances Large Appl.:l.ances Space Heat Total (kWh)(kWh)(kWh)(kWh) 1980 1985 1990 1995 2000 2005 2010 I I •• I I .I.!:...J • I I :. I"'··'~h I I I I ·1.·. ·.'1·"j I I I" '.1.'.J ~,~ h. ....~~-~ DOR MEAN SCENARIO BUSINESS USE PER EMPLOYEE 1900 8,407 7,496 8,407 7,496 1985 9,585 7,974 9,,225 7,907 1990 10,184 8,277 9,570 8,235 1995 10,646 8,572 9,877 8,.569 2000 11,187 8,879 10,199 8,901 2005 11,842 9,225 10,592 Q ·)63J'~'--~_ 2010 12,648 9,618 11,168 9,670 m X :::t: 01 -f 1\)' k:>o "M-Ii.;¥"..,....·tIiiiiIIIIilIft ....~.,.,$'.'..•~~.1111 _ After Adjustments Anchorage-Fairbanks- Cook Inlet Area Tspt":la Valley Area (kWh)--(kWh) '•.....':""J--=-',~III..·....•.l~~.,..,I .....a... Befor{:Conservation Adjustmer~t and Fuel Substitution Anchorage-Fairbanks- Year Cook Inlet Area Tanana Valley Area (kWh)(kWh) .~illY ...lIB o '''0 , f'~..-...a__.1 •. 3.<:,:. I I I I I . :1:.-.~'~.. I • "":1 :,:i< .·._'1 I I I··.···'... I I I •'.J.,','I ••~'1 I I Iii." .....'. EXHIBIT 2.21 Page 1 of 2 DOR MEAN SCENARIO BREAKDOWN OF ELECTRICITY PROJECTIONS (G~m) ANCHORAGE -COOK INLET AREA RESIDENTIAL BUS I t.I"E SS MISCELLANEOUS EXOG.INDUSTRIAL YEAR PROJECTIONS PROJECTIONS PROJECTIONS LOAD PROJECTIONS TOTAL 1983 1101.05 1090.'57 25.34 108.24 2325.2019841141.55 1162.31 25.69 116.32 2445.87 1985 1182.06 1234.04 26.04 124.40 2566.54 1986 1208.06 1266.57 26.66 137.89 2639.1719871234.05 1299.09 27.28 151.38 2711.8119881260.05 1331.61 27.91 164.88 2784,.4419891286.05 1364 ..13 28.53 178.37 2857.08 1990 13121105 1396.65 29.16 191.86 2929.72 1991 1331 ..76 1419.09 29.60 195.13 2975.5719921351.46 1441.52 30.05 198.40 3021.4319931371.17 1463.95 30.50 201.66 3067.29 1994 1390.88 1486.39 30.94 204.93 3113.14 1995 1410.59 1508.82 31.39 208.20 3159.00 1996 1433.98 1538.95 32.00 214.14 3219.0619971457.36 1569~O8 32.60 220.08 3279.13 1998 1480.75 1599.22 33.21 226.02 3339.1919991504.14 1629.35 33.81 231.9n 3399.26 2000 1527.52 1659.48 34.42 231.90 3459.32 2001 1555.52 1700.63 35.12 244.96 3536.23 2002 1583.53 1741.77 35.81 252.02 3613.1320031611.53 1782.92 36.51 259,,08 3690.04 2004 1639.53 1824.06 37.21 266.14 3766.95 2005 1667.53 1865.21 37.91 273 ..20 3843.85 2006 1705.45 1926.63 38.96 281.58 3952.62 2007 1743.36 1988.05 40.00 289.96 4061 .38 2008 1781.28 2049 .47 41 .05 298.34 4170.14 2009 1819.19 2110.89 42.10 306.72 4278.90 2010 1857.11 2172.31 43~14 315.10 4387 ..66 EXHIBIT 2.21 Page 2 of 2 DORMEAN SCENARIO BREAKDOWN OF ELECTRICITY PROJECTIONS (GWH) FAIRBANKS -TANANA VALLEY AREA RESIDENTIAL BUSINESS MISCELLANEOUS EXOG.INDUSTRIAL YEAR PROJECTIONS PROJECTIONS PROJECTIONS LOAD PROJECTIONS TOTAL-. 1983 219.25 255.53 6.67 0.00 481 •.45 1984 233.54 268.33 6.63 0.00 508.50 1985 247.82 281.13 6.60 0.00 535.55 1986 258.62 287.22 6.60 10.00 562.45 1987 269.42 293.32 6.61 20.00 589.35 1988 280.22 299.41 6.62 30.00 616.25 1989 291.03 305.50 6.63 40.00 643.16 1990 301.83 311.60 6.64 50.00 670.06 1991 312.09 317 ..40 6.81 50.00 686.30 1992 322.36 323.20 6.98 50.00 702.54 1993 332.63 329.00 7.15 50.00 718.78 1994 342.90 334.80 7.32 50.00 735.02 1995 353,,17 340.61 7.49 50.00 751.26 1996 361.48 346.80 7.64 50.00 765.91 1997 369.79 352.99 7.79 50.00 780.56 1998 378.10 359.18 7.94 50.00 795~22 1999 386.41 365.37 8.09 50.00 809.87 2000 394.72 371.56 8.24 50.00 824.52 2001 404.00 379.93 8.40 50.00 842.34 2002 413.28 388.31 8.56 50.00 860.15 2003 422.56 396.69 8.72 50.00 877.97 2004 431.84 405.06 8.88 50.00 895.78 2005 441.12 413 ..44 9.04 50.00 913.60 2006 452.38 425.03 9.31 50.00 936.72 2007 463.65 436.62 9.57 50.00 959.84 2008 474 ..92 448.21 9.83 50.00 982.97 2009 486.19 459.80 10.10 50.00 1006.09 2010 497.45 471.39 10.36 50.00 1029.21 I I I I I I I···.~··; I I I I I I I I I I I DOR MEAN SCENAR.IO PROJECTIONS OF PEAK AND ENERGY DEMAND Energy Demand (GWh)Peak Demllnd (MW)ANCHORAGE -FAIRBANKS -ANCHORAGE ..FAIRRANKS-COOK INLIo:!TANANAVAl,t'n COOK INLET TANANA VALLU Load Factol'ttAR AREA a\REA TOTAL AREA AREA TOTAl.%-- 1983 2325 481 2806 469 109 579 S5.319842445508295449411661055.3 1985 2566 535 3102 518 122 640 55.J 1986 2639 562 ,3201 533 128 662 55.2198727115ft9330154913468355.119882784616340056414010555.019892857643350058014672754.9 1990 2929 670 3599 595 152 748 54.9 1991 2975 686 3661 605 156 761 54.919923021702372361416017454.919933067718378662316478754.9199431137353848632167MO54.9 1995 3159 751 3910'642 171 813 54.9 1996 3219 765 3984 654 174 829 54.919973279700405966617884454.919983339795413467818185954.919993399809420969018487554.9 2000 3459 824 4283 702 188 890 54.9 2001 3536 842 4378 718 192 910 54.·920023613860447373319692954.920033690817456874920094954.92,004 3766 P95 4662 764 204 969 54.9 2005 3843 913 4757 700 208 91'B 54.9 2006 3952 936 4889 601 213 1015 54.9200740619595021823219104355.0200841709825153845224107055.02009427810065284867229109755.0 2010 4388 1029 5417 890 235 1125 55.0 m X ::I:-OJ -I f\J. f\J f\J ..-~-'MBl!!IIi'~",~l1li1.,"",,1 ..;~t~~;~ ..~'1Mf,·; ~~..tI!IM...~~~~~~D!~~ () .' 1 'l1li-~--~.~~II.,'r:~:..i!1111-.......~._:-~,',.,~',",',......-,MIIJ'.. (MEDIUM SCENARIO) ~,',',~~~ LIST OF PREVIOUS ;, l1li RAIL BELT PEAK AND ENERGY DEMAND FORECASTS 11M!IJII!--~mIIfQ~",~ 31 Table B.12 and B.13 of Battelle Volume 1..Exeludea military and industrial self-supplied electricity. 1/Table 5.6 -Acres Feasibility Report -Volum~~1.Includes 30%of military loads,and excludes induatrial self-supplted electricity. 2/Table 5.7 ...Acres Feasibility Report..,Volume 1.Excludes military and industrial self-supplied electricity. Note:The ISER and Battelle forecasts are for the An.:::horage -Cook Inlet area,Fairhanks-Tanana.Valley area, and Glennallen -Valdez area. 4/Page XV of Battelle Volume 1.Excludes military and industrial self-supplied electri~:tty. Il!iY~~~i m X::r:-OJ-...."'" NeN ••••,•••."c :,.~,-...I '"".,.-f ~ t .J '.'"~:,1 f~•flo .....\• •,"'; II. m X::z:-to---t I\J. f\) .~ ••!lIE1111',.~."'"!Ill-'Mr;lII!J~","""'.._'F 1 .~M. RAILBELT trrILITIES F'ORECAST ,MOiIfjJJ ."'._,'*0:"'" .....~M!...-~~,'1RlI RAIL BELTAML&P (1)CEA (1)(2)F~IU (1)GVEA (1)TOTAL (3)-Winter Winter Winter Winter WinterEnergyPeakEnergyPeakEnergyPeakEnergyPeakEnergyPeakYEAR(GWH)(MW)(GHW)(r-tWl JGW)(MW)(GHtV)..(MW)(GHW)(t1W) 1983 717 140 1854 384 147 29 387 74 3105 627198478611521966408153304168133216721985844162207943216132447B9353171619869151742192457165324809737527611987105319723044P16.8 33 516 107 3974 80719881126209241750S17234fiD311342008501989120022125305291753565312041}43 8941990127023226425541~3 36 653 128 4678 9401991127023227545781903870613649209841992132224!.2867 602 198 39 764 145 5151 102819931375251297962620641825154538610731994143126130916512144289416456301118199514892723203675225459671745884116619961549283331569923747104618561471215199716212943428723249491131197642912641998169'7 306 3540 747 262 52 1223 209 6722 1415199917753183652771275-54 1323 222 7025 13672000185833137647952815614322367335141920011944344387582029558154825176621474 NOTES: (1)CEA forecast includes Matanuska Electric Assoc.,HODler Electric Assoc,.,&Seward Electric requirements • (2)Eklutna is included inAML&P &CEA. SOURCE:ALAS~'\POWER ADMINISTRATION,March 1983 AML&P =Anchorage Municipal Light &Power CEA :=Chugach Electric Association F11U=Fairbanks Municipal Utilities System GVEA =Golden Valley Electric Association,Fairbanks Area 1II1!.~'~j .1: ".::..l..~'.'.l\I~...'i \, :1 ., I., I I ,r,,, ..tJ I IJ I I I I I I I I I I I I i EXHIBIT 2.25 CHUGACH ELECTRIC ASSOCIATION,INC. PROJECTIONS OF TOTAL SYSTEM ENERGY REQUIREMENTs!.! Low Moderate High Year Energy Peak Energy Peak Energy Peak (GWh)(MW)(GWh)(MW)(Gwh)(MW) 1983 1,817 412 1,868 426 1,879 429 1984 1,942 432 2,050 463 2,081 469 1985 2,059 451 2,265 50l 2,299 510 1986 2,189 470 2,473 533 2,614 575 1987 2,281 491 2,642 568 2,935 654 1988 2,365 513 2,003 606 3,283 745 1989 2,445 535 2,962 646 3,664 850 1980 2,523 559 3,121 689 4,087 974 1991 2,582 575 3,167 699 4,150 978 1992 2,651 591 3,207 706 4,164 969 1993 2,725 606 3,251 713 4,187 961 1994 2,ro2 623 3,299 721 '+,220 954 1995 2,884 639 3,350 729 4,261 946 1996 2,982 660 3,406 738 4,315 938 1997 3,103 680 3,467 747 4,381 931 1/Includes Matanuska Electric Association)Homer Electric As$ociation, and Seward Electric system .. Source:Power Requ.irements Study,1983,by Burns &McDonnell Exhibit 2.26 2010 5,404 1,122 5,858 1,211 506,548 533,218 890 945 2000 4,281 4,542 430,823 451,561 777 749 1990 3,599 3,737 380,344 389,026 SUMMARY OF POPULATION,ENERGY AND PEAK DEMAND PROJECTIONS UNDER THE DOR MEAN AND SHCA-NSD SCENARIOS FOR SEPTEMBER 1983 UPDATE EXHIBIT 2.26 Energy Demand (GWb)(b) Population DOR-MEAN Scenario (a) Peak Demand (MW) SRCA-NSD Scenario Energy Demand (GWh)(b) Population Peak Demand (MW) (a)DOR Mean forecast is from the June 1983 DOR quarterly report. (b)All projections at consumption level,excluding military and self generations that Cannot be supplied by Susitna or Railbelt utili ties. I I. ··.·"·· j -~- if I ILt.•.' :\ I I ,I<.f.> I ··I···.·~·...·· :~.;I ~'.J I 1. :...•. 1 . '1 rl'l.I,I ! I I I •••• I ·Ii •..."•.•;''''... ! !>,' I··. · r :.•...•..'•..'•.••.••.') ~ ~ ,./\~,. I-··'~;;.'.··.··'.'<;.,''~~~,' .,{, "-<.ir "'<"'h' 7!~~ , 3.0 UPDATE OF THE SUSITNAPROJECT .t - (."_.~.,..,, ifII. .1 I: I I ,I ) ~I' I .1 I I I I I ·I·~ j ·1.···.1 'j I··~···il t :J; I II II .1 I..~I11 I I I 11 ;1".~..;: '··.1'.".·. ..J.1 \, 3.0 UPDATE OF THE SUSITNAPROJECT 3.1 INTRODUCTION This Chapter presents an update of the Susitna.Projectas proposed in the FERCLicense Application incorporating the design refinements and corresponding revisions in estimated project costs that resulted from recent studies.Details on the refinements to conceptual design are contained in the report "Review and Update of Conceptual Design", November 1983. Using the recommended design concepts,the estimated costs and power and energy production are developed • Improved ways the project can be operated are descr.ibed.Theresults are incorporated in the studies of alternative system expansion pro- grams to meet future Raitbel t demand in Chapter 5.Economic a':lalyses and cost of power ~l.re given in Chapter 6. 3.2 DESCRIPTION OF THE SUSITN5.PROJECT The Susitna Hydroelectric Project will comprise two major developments on the Susitna River some 180 miles north and east of Anchorage, Alaska.The first phase of the project will be the Watana Development which will incorporate an earth and rockfill dam togethel-wt th asso- ciated d.iversion,spillway outlet facilities ~power facili,ties,and a tra.nsmission system.The second phase will include the Devil Canyon concrete arch dam with associated diversion,spillway outlet facili- ties,power facilities,and an integrated transmission system. 3-1 ...,J.- I Ali) f ~. I I I It ·11"·~;·1,! I ·I~:~.,i I ,I'· , :"" .••f,' j ,~: 3 ..2.1 Watana Development The Watana Dam Cal'l provide a reservoir approxilllately 5/,miles long, witu a surface area of 38,000 acres,and a gross storage capacity of 9,600,000 acre-feet at El.2185 t the normal maximui11 ope.rating level. The minimum operating level of the reservoir for the El.2185 develop- ment would be EI.2065,providing an active storage volume during normal operation of 3,700,000 acre-feet. The dam will be a zoned embankment structure wi th a central impervious core.The nominal crest elevation of the dam will be El.2205,wi.th a maximum height of 885 feet above the foundation and a crest length of 4,100 feet. The power intake will be located on the north bank with an approach channel excavated in rock.From the intake structure,concrete-lined penstocks will lead to an underground powerstation hOUSing si.x 170-MW generating units. Low level outlet facilities will be provided to assure that downstream flow requirements can be met wi thout power releases and to provide discharge capacity for frequent floods. The main spillway,also located On the north bank,will consist of a gated ogee control structure and an inclined contrete chute and flip bucket designed to pass a maximum discharge of 118,000 cis at the maxi- mum normal pool level.The spillway 'Will proVide sufficient capacity to permit diScharge of the Probable Ma~imt~Flood (PMF)with the reser- voir surcharged to elevation 2201. 3-2 I··',~'.· ..~~,'!t ~; .1....11..' *~ I ·1""··..'··· I , I.,· '.~. 1 ;'t r 11 '1'·t.~1 I. ·...·.'.'· ''i 'I I I) I II '.1 .I~'.·.'" 3.2.2 DevilCanyon.Development The Devil Canyon Dam will form a reservoir approximately 26 miles long wi th a surface area of 7,800 acres and a gross storage capacity of 1,100,000 acre-feet at El.1455,the normal maximum operating level. The operating level of the Devil Canyon reservoir controls the ta.il- watet'level of the upstream Wata.na development.The minimum operating level of the reservoir will be El.1405,providing a live storage of 350,000 acre-feet during normal re:servoir operatio/n. The dam will be a thin arch concrete structure wi th a crest level of El.1463 and maximum height of 646 feet.It will be supported by ma:;s concrete thrust blocks on each abutment.Adjacent to the thrust bloc\t, an earth and rockfill saddle dam will provide closure to the south bank. The power intake on the north bank will consist of an approach channel excavated in rock leading to a reinforced concrete gate structure. Conc,rete-line'd penstock tunnels will lead from the intake structure to an underground powerstation housing four 150-MW units. Outlet factI!ties will be IDea ted in the lower part of the main dam to assure that downstream flow requirements can be met without power releases and to provide capacity for discharge of frequent floods.The spillway facilities are designed to pass the 10,000--year flood wi thoui: reservoir surcharge above normal maximum elevation of 1455.The reser- voir will surcharge to elevation 1463 during the Probable Maximum Flood event. 3.3 DESIGN IMPROVEMENTS The initial engineering effort by the Harza-Ebasco Joint Venture was a detailed review of the design concept and cost estimates for the Watana 3-3 1 3-5 3~4 COST ESTIMATES Construction Cost Estimates3~4.1 Category Z -Potential Refinements Relict channel treatment Outlet facilities Emergency release facilities SF-6 SWitchgear Transformer locations for underground powerstation Transmission circuits At the October 14,1983 Board Meeting the Power Authority Board of Directors direc.ted further study on the Relict Channel treatment and other design refinements that will not delay the FER.C licensing pro- cess ~These studies have been initiated;however,the results are not available for inclusion in this update ~ Exhibit 3~1 shows the estimated costs for the Watana.and Devil Canyon Developments Vlhich incorporate the Category 1 refinements o~y ~For the Watana development,the construction cost estimate can be reduced from $3,828 million for the layout shown in the License Application to $3,432 million (1983 do1 1 ars),a sa.ving of $396 million~For the Devil Canyon Development,tht~construction cost estimate can be reduced from $1,577 million to $1,552 million (1983 dollars),a saving of $25 mil- lion~ The installed capacity of the Watana Project is 1020 MW in the License Application~It is provided in six units)each rated at 170 MW"The fifth and sixth units provide no additional energy production..They are availa.ble:for peaking uSe and Spinning reserve but do not provide significant economic benefit in view-of the reduced load growt.h.Cost reduction of the initial project amounting to $94 million (January ·I····! "I I .1 .111 11 Ii Ii I I 11 Ie I..' ',.,'; I I :{ :' '•.:,' I I I I } I , '.'1~ I·e; .'i " i "· •,"I t 3 ..5 RESERVOIR OPERATION STUDIES 3 ..6 Operation and Maintenance Costs3.4.2 1983)can be achieved with the postponement of installing these two units,as shown on Exhibit 3.2.Exhibit 3.3 shows the general plan of the Watana 2185 development w'"i th Category 1 refinements. 1.Watana (first five years),$8.5 million per year 2.Devil Canyon addition (first five years),$2.5 million per year 3.Eventual anr;.ua.l cos t,$7.3 million per year The operation and maintenance costs account for the personnel,equip- ment,materials,and facili ties required to operate the generating plant and to maintain all of the structures and machinery.Under changing project conditions over time,the following estimated costs cover the various periods of the project life: These costs,as all other costs presented here,are at January 1983 level~,"'lbe components of these figures appear or.Exhibi t 3.4 .. In the present License Application,the initial Watana project would operate on base in order tJ.;maintain nearly uniform discharge from the powerplant.When Devil Canyon comes cn line,Watana would operate in a loaq following mode,while Devil Canyon operates on base. Operation studies were performed to estimate the power and energy pro- duction capability of the Susitna Project under the above operation assumptions. I 1'\ 't I'~~ ..~ I I •Ili IJ '11 ~..t ,Ii.,J, .1 I I 11 •••• I I I I I 11 I 'j Simulation Model Hydrology3.5.2 A dual-reservoircomput.er simulation program was developed during the 1982 Susi tna Project Feasibility Study.This program was modified to i-ncorporate some desired improvements.Major changes related to the use of a variable tailwater rating,and variable turbine capacity and efficiency as a function of head ..Minor change~in data input.re.quire- ments and output format were also implemented. Thir'cy-two years of streamflow data.t as provided in the 1982 feasibili- ty report for the Watana,Devil Canyon,and Gold Creek sites,were re- viewed and accepted for use in the analysis..These data included an adjustment to the 1969 drought.Subsequently,another year of flow data beca.me available and was incorpora.ted.The project operation is simulated.on a monthly basis for an historical streamflow period of 33 years (Water Years 1950"'1982). The adjustment to the 1969 drought was !dade to reflect a 3D-year recur- rence interval,instead of the ap!/!'oxim~tely 1000-year recurrence of the natural flow event..The effect of this adjustment on average ener- gy production from the pt'oject for the 33-year simulation was .:!nalyzed .. USe of the adjusted 1969 flows increases the annual energy production by about one percent over that computed using the 1969 natural flows. 3 ..5 ..3 Reservoir Data Area and volume versus elevation relations for the lvatana and Devil Canyon damsites are given on Exhibits 3 ..5 and 3 ..6..At the Watana nor- mal maximum pool elevation of 2185,the reservoir surface area is about 38,000 acres,arid the gross storage volume Is 9.6 million acre-feet. At the Devil Canyon normal nlaximum pool elevation of 1455,the reser'" I··'~·If I 11 I I.l\.,IU I\t ~' I I. ·..,~·,i1 I I 1':1 ''1. ...'; I I ".'.'."'.',.',..' 1 .'", j '1 I I it-.1- '.j { .~ 'f 'I.'"4 ,fl'(I 3-8 voir surface at;ea is about 7,800 acres,wi th a gross storage volume fixed by shown in Initial Installed Capacity (December) (MW) Rated Head (ft) Initial No. of Units Draw- down (ft) The.active storage volumes are Nor.Max. W.S.Elev. (ft"lIls1) Watana .2185 120 4 680 680 Devil Canyon 1455 100 4 590 600 Development SUSITNA PROJECT DATA the n.ormal maximum reservoir elevations and drawdowns an Table 3.1 of 1.1 million acre-feet .. Table 3.1 .. The Operating characteristics for the Watana and Devil Canyon power- plants are summarized on Exhibit 3.7 based on the rated net head.In all cases,generator and transformer efficiencies of 98 and 99 percent, respectively,were used to compute the overall plant efficiency.A head loss percenta.ge of 1.5 pey':qnt of gross head was used for both Watana and Devil Canyon powerplants .. 3.5.4 Turbine and Generator Data I I I.~.··.) ____.'1/' I .1·.··,··'..1\·'··.~'.' 'J I 1..1 '.•..~.0,.,: I I·,,·......·.···.I ~ ~""·'.•"1f ..··"'·-'~'"'-~~"'I"----<""'V',"~ 1 Ope.ra'tion Simulations were made for a wide range of Month Flow Month Flow October 5000 April 5000 Nr;Jvember 5000 May 6000 :December 5000 June 6000 January 5000 July 6480 (b) February 5000 August 12000 March 5000 September 9300 (b) 3-9 "CASE Ctt FLOW REQUIREMENTS AT GOLD CREEK,cfs (a) Table 3.2 3.5.5 Reservoir Operation Constraints During the early ye.ars of operation,energy generation from the Susitna Project could be limited by the system demand..Beyond some high demand level,the physical limits of the project machinery and water supply will control. system demand levels (4000-8000 GWh!year)to establish the relation of system demand to energy production from the project • The project is operated to meet a minimum monthly flow requirement,at the Tnouth of Gold Creek,denoted as "Case CIt in the License Application and shown in Table 3.20 (a)As discussed in the license application,the "Case C"flow scenario was selected as the project operation flow regime considering both project and envi roIl!'ten tal interests. (b)Flows change by 1000 cis per day from 6000 On July 25 to 12,000 On August 1 and from.12,000 on September 14 to 6000 on September 21. I I I I( -.:!Itt .1"'·'f >, I I; 1·'1.1.Ii •• I..;.~.'~ -:ti I 3 ..6 ENVIRONMENTAL STATUS UPDATE 3-10 ~r' Power and Energy Production3.5.6 The reservoir rule curve is the list of monthly target reservoir eleva- tions to control the reservoir drawdown.A low rule curve maximizes drawdown and average energy production,but tends to minimize the firm energy production in the critical water period.A high rule curve would have the opposite effect.'£he selected Watana rule curve is de- veloped to maximize average energy generation while at the same time maintaining a high level firm energy.The Devil Canyon operating rule is to keep the.reservoir as £'\.:1-1 as possible in all cases. . Exhibit 3.8 summarizes the power and energy production for Watana2185 and Devil Canyon under the DORMean load forecast for the year 2020. The power and energy estimates are based on the modes of operation and constraints discussed previously. Energy production (GWh)and project capability (MW)are estimated from reservoir operation studies.The studies considered the energy demands for the period 1993 through 2020,for the DOR Mean and SHCA-NSD load forecasts. This section presents an update of the status of the principal environ- mental issues related to the Susitna Project,and the activities being conducted to resolve them. A full range of environmental studies has been continued since the filing of the FERC License Applica..tion in February 1983.The objec- tives of these studies have been to refine the assessment df impacts as identified in Exhibit E of the License Application and to assist in the licensing process by responding to FERCinquiries to As of this time, responses have been prepared and provided to FERC on 230 questions or '...1. 1 f'.' •~/i; t I I ··1···~"·1.•..•If , ·I··~.··~..·•~,.... I:' I 'I''1.'.~ _"i I; I I Iff ,~ "...,,:1 11 •..1) 3 ....11 T-'-----:""'''' ing • requests for clarification and supplementary information.At this time,all inquiries from FERC have been addressed.In addition,a list of~pprb~imately 300 issues and questions has been compiled from a c:.omprehensive revi~w of all state and federal agency comments received by the Alaska Power Authority during the last four years.Many of these issues were addressed in Exhibit E It Work on others is continu- Continuing environmental activities relate to the refinement and quantifi~ation,if possible,of impacts and the development of mitiga.... tion programs tailored to specific project needs.These activities cover all aspects of potential project impacts and are briefly dis- cussed below'under the major headings of aque.tic,terrestrial and social science programs. In addition to preparation of written responset:~FERC personnel were conducted on a tour of the Susitna basin and related areaS during the Vleek of August 21-27 so that they could better evaluate the project based on first-hand information~ 3.6.1 Aquatic The key environmental issue related to the aquatic resources focuses on the effects of the al teredflow re5:I.rne on the aquatic ecosystem in the Susitna River..The Susitna Hydroelectric Project will also alter the water temperature regimes,turbidity and other water quality parameters such as dissolved gas and suspended solids concentrations downstream from the reservoirs. The effect of the altered flows on anadromous a.nd resident fish popula- tions is the major focus of present studies..The priT.icipal concerns are potential al terations to spawning habitats of salmon,access to the spawn.ing habi tats,and juvenile reating habitats.These questions are I. ·.··.········:·.n;, '1'.·..llI I I··...··.'·'.."I~1 I .••···....t .•!i j I 11t:IJ .1..··.·:··.p.'1! I I I quality expected turbidi ty and other water through comparisons of the 3 ...12 changed allswered related to are being Studi~s will be also conducted to address.questions.of navigability throughout the Sus.i tna River and of the effects.to various Susttna River user groups. Mos.t of the effort to quantify the effects.has been directed toward tho se habitat types.found in the Devil Canyon to Talkeetna reach of the Susitna River.Additionally,preliminary studies.are being conducted in the reach between Talkeetna and Cook Inlet.Thes.e 1a tter s.tudies will be used to develop a more detailed quantification,to the extent poss.ible,of the effects of the Susitna Hydroelectric Project on the aquatic reBources in the lower reach of the Sus.itna River. be.ingaddressed through a series of mathematical models designed to quantify the expected changes in flow and fish habitats.Both physical and biological data are being collected to calibrate the predictive models and to relate the phys.ical changes in habitats to the biological impacts.Five maj or habitat types have been identified which are important to the fish and which will be affected by the altered flows. These are the mainstem of thE Susitna River,s.ide channels,side sloughs.,upland sloughs and tributary mouths. Questions pa.rameters It is antici..pa ted that the project will a1 ter the temperature regimes of the Susi tna River 0 1'0 address.the potential effects of the a1 tered temperature regime,it is necessary to estimate what changes will occur.'I'his is being accomplished through a series of mathematical models concerning water temperature in the reservoirs and in the river downstream.As a part of this analysis,a mathematicalll10del is also being used to address questions related to ice processes in thereseI'''' voirs and river. I 'I·'.··:· 'i; .,•.•...•1•.•."., I I I'·,, .~;...~:i ,J I I, •l.··.l..f:~ I"'.'.'.',:1 I I··.·~··.·,·,.:{, ..{ 11·J: I•.""'~.•'.".'." '1 1····"'·-····'.'J! '(I "j •-. 'f , ; II I,!',. J 1'.1.' .t J ·1·...·.· .......} I, .',")"'.,'.'.. :"", ;\ i c.hanges with observed changes at other comparable.hydroelectric proj- ects in Alaska and elsewhere. 3.6.2 Terrestrial No single outstanding concern has bee.n identified as a key terrestrial issue.Rather,continuing terrestrial studies are aimed at more detailed evaluation and refinement of project impac t asseSSments and of proposed ml.'tigation plans as discussed in the License Application. Many of th~present studies were developed to contribute to modeling efforts designed to evalua te loss of habitat (lost moose carrying capacity and changes in moose population due to changes in carrying capacity),predator-prey ratios,hunting pres.sure,and other factors .. Components of these modeling efforts include browse inventories,plant phenology studies.,more precise mapping of forage areas,moose cen- suses,and studies of the importance of mooSG movements,and the importance of predation by wolv~s and bears in controlling moose numbers.OUtput from.the studies will facilitate the development of mitigation programs commensurate with project impacts. Other studies underway include monitoring movements and habitat use of moose in the riparian zone downstream of Devil Canyon;monitoring the movements and herd size of caribou in the project area;analysis of the use of the Jay Creek mineral lick by Dall Sheep;studies on bear and wolf movements and habitat use;and raptor studies,partlc.ularly directed at project effects on golden and bald eagles.Beaver surveys and modeling efforts fo!'the riparian zone from Devil Canyon to Talkeetna are being conducted to determine the likely effects of altered downstream flow regimes.More stable flows following project construction may improve ha.bitat conditions for beaver and result in increased popu!a tions and increased numbers of beaver dams and other structures.This,in turn,could decrease the value of the area as spawning habitat for salmon. 3-13 3 ....14 The second main activity of the cultural resources subtask FY 1984 is a reevaluation of the Susitna archeological program in light of a review of current procedures and schedule,and the rule of the Advisory Coun- cil on Historic Preservation.Part of this ree.val ua tion will include an analysis of whether the project area should be considered individu- ally,or whether the project area should be considered as an archeo- logical district.FolloWing this reevaluation,Harza.-Ehasco will pre- pare and submit a position paper summarizing their recommendations to the Power Authority for review.Meeting(s)will then·be held with the Advisory Council on Historic Preservation and other agencies,as appro- priate.,to develop a concensus on the contill,Ued direction of the Susi tna arch.eological program.FollOWing these meeting s,the cultural resourceS mitiga.tion program will be reevalua ted and upda.ted as 3.6.3 Social Sciences The.social science program comprises six subtasks:cultural resources, socioeconomics,recreation,aesthetics,land use,and project alterna- tives.The following discussion briefly outlines the sta tUB of each subtask in FY 1984 and thepr.incipal focus of each subtask for FY 1985. 3.6.3.1 Cultural Resources.The final report on the 1983 field season is currently being prepared by the University of Alaska Museum.Field work in 1983 included continued reconnaissance surveying (for the purpose of identifying historic and archeological sites)of the pro- posed dam..sf tes,impoundment areas,and borrow sites.In addition, limited systema.tic testing of identified sites was conducted.Further- more,sensit.ivity mapping showing archeological potential was completed for the proposed railroad,access road,transmission line.,and Phase I Recreation Plan. 11 t I., I I I, I I I, r r 1-·,,, t I I I; I It required.In addition,an appropriate level-of-effortmll be devel- oped for the FY 1985 field program. 3.6.3.2 Socioeconotnics.The principal thrust of the socioeconomic subtask in FT 1984 is to revise the projections of the socioeconomic baseline and "wi.th project"conditions and to update the mitigation plans based on the revised projections.In order to more accurately describe existing socioeconomic conditions in the communities of Cantwell,Talkeetna,and Trapper Creek,surveys of households, businesses,and public sector employees are being cbnducted in those comulUnities.In addition,a survey of workers on the Anchoragel Fairbanks Intertie Project has been completed to help validate assump- tions regarding worker characteristics used to iorecast project-related impact£=- It is widely recognized that several additional socioeconomic-related issues must be addressed in order to more accurately forecast socio- economic impacts and to develop a meaningful mitigation plan.These issues include further definition of:worker shift and rotation schedules;how workers will be transported to and from the project site;worker hiring program;type of housing,facilities,and amenities at the construction camp and permanent village;the project access route;and whether or not a permanent village is a viable option. Currently,these issues are scheduled to be examined in early FY 1985 prior to the next round of household,husiness,and public sector surveys .. The socioeconomic subtask for FY 1984 and 1985 will also be directed to address the potential impacts of the project on users of fish and wildlife resources.The household and business surveys (to be conducted in the fall of 1983 and 1984)are designed to gather baseline information with regard to the importance of fish and wi.ldlife 3-15 3.6.3.4 Aesthetics.The principal activity in the aesthetics subtask in !i'Y 1984 is to update the Aesthetics }1itigationPIan.The thrust of the update,which will recommend steps necessary to implement the aesthetics mitigation program,will be to outline the structure and approach of the Interdisciplinary Design Team.The main aesthetics subtask activities in FY 1984 will include mobilizing the Interdis- (.:iplinary Design Team and reevalua ting the Ioca tion and design of the construction camps and permanent townsite. 3.6.3.3 Recreation.The primary objective of the recreation subtask in FY 1984 is to prepare a Recreation Plan Implementation Report.This report will outline the sched\lle and steps required to implement Phase I of the Recreation Plan as identified in Chapter 7,Exhibit E of the License Application.An important element of this report ",Till bea plan of action for resolving necessary policy and management issues, such as what proj ec t areas and facilities will be open to the public; worker policies regarding access and use of recreation resources;and control by landowners and landmanagers.FY 1985 ac tivi ties for the recreation subtask will focus on tasks identified in the Recreation Plan Implementation Report that will be necessary to keep the licensing process on schedule. resources to households and businesses in Cantwell,Talkeetna,and Trapper Creek.In addition,a survey of guides and lodge operators and a survey of users of project area fish and wildlife resources will be conducted in FY 1985 in o.rder to more accurately assess the project's potential impacts on fish and wildlife resource user groups .. 3-16 if,I( 11 I, I I, I I I I r~ 'I",'..··".: i' I fl·";!. t ..., \ I ·1,..'i.~, \1 I···.··.·.'1 "., I I I I I I .'I:r ,~". I I I 3.6.3.5 Land Use.In FY 1984,the land use subtask will focus.on the upda.te of the License Application.As part of this work,the lan~use and land status information presented in Chapter 9 will be updated.In addition,land use issues will be reexamined in order to outline appro- priate land use subtask work for Ii'Y 1985. 3.6.3 .6 Project Alternatives.The thrust of the project alternatives subtask in FY 1984 and 1985 will be to develop and update a matrix that displays differential impacts between alternative project locations, designs,and energy sources. 3-17 ,r-'-:~' WATANA EXHIBIT 3.1 65 22 80 10 16 7 1 292 34 15 63 25 14 40 55 42 14 11 119 105 5 176 4 173 1150 1323 164 14~7 1552 DEVIL CANYON 51 72 54 111 17 3 752 110 36 113 72 12 31 16 79 21 14 214 405 5 325 29 382 2543 2925 366 3291 141 3432 SUSITNA PROJECT LAYOUTS WITH DESIGNREFlNEUENTS (Category 1) COST ESTIMATES (Millions of Dollars) ITEM Land and Land Rights Powerhouse Reservoir Clearings Diversion Tunnels U/S Cofferdam DIs Cofferdam Main Dam Relict Channel or Saddle Dam Outlet Facilities Main Spillway Emergency Spillway Power Intake Surge Chamber Penstocks Tailrace Waterwheels,Turbines &Generators Accessory Electrical Equipment Mise.Power Plant Equipment Roads,Rail &Air Fac::tli ties Transmission 1-'lant General Plant Construction Facilities Mitigation SUBTOTAL Contingency Allowance (15%) Total Construction Cost Engineering &Administration (12.5%) Total Cost -Jan '82 Price Levels Escalation to Jan '83 (4.3%) Total Cost -Jan '83 Price Levels I,! J ·Ik.'.'~ j ~I 'I•..A'.' I .1 I'.:,'.. j "I I .1 I 4-UNIT 6-UNIT POWERPLANT POWERPLANT EXHIBIT 3.2 51 51 57 72 54 54 III III 17 17 3 3 773 752 110 110 36 36 118 113 55 72 8 12 23 31 14 16 53 79 14 21 12 14 214 214 405 405 5 5 317 325 29 29 2482 2543 367 382 2849 2925 352 366 3201 3291 137 141 3338 3432 SUSITNAPROJECT WATANA 2185 COST ESTIMATeS (Category 1) FOUll AND SIX UNITPOWERPLANTS (Millions of Dollars) ITEM Land and Land Rights Powerhouse Reservoir Clearings Diversion Tunnels Uls Cofferdam DIs Cofferdam Main Dam Relict Channel or Saddle Dam Outlet Facilities Main Spillway Emergency Spillway Power Intake Surge Chamber Penstocks Tailrace Waterwheels.Turbines &Generators Accessory Electrical Equipment Misc.Power Plant Equipment Roads,Rail &Air Facilities Transmission Plant General Plant Construction Facilities Mitigation SUBTOTAL Coutingency Allowance (15%) Total Oonstruction Cost Engineering &Administration (12.5%) Total Cost .".Jan'82 Price Levels Escalation to Jan '83 (4.3%) Total Cost -Jan '83 Price Level$ I J , J f j \, I I. I I .~.. I I l \ J \ \ \. l I I I \ \ , \\ i \ \ \ I I II,I I I I ;J "/J i f 1 I 'I :I f\.I',\.\ \ \';1, \"'" I . , J i"i;t '\:s:tit>~\~ ~..~ ,\..~i !'{ .' '# 'lij • I \ j.'~1 ..J j' .I \,I \'.1 \II't."".i.\I \\,~\I \'\I ~I I~\I ~N ~f'")I ..I'16 :\1 I J \I\<:.J I !\,I t \i \\,\"'t.'-. \ .:.£1\ ' " I !I'/,,.f' ,I I I I I II J).,. I III1 I \.' I \\~.'~:~".'• t•I I I iI ;)....1IvJ.J J I B3/40/1 2/Includes annual maintenance services,ma.jor maintenance overhaul,helicopter service,and road maintenance. 1/For first 5 years or operatitH10r each development;total of 10 years. m X :t:-txJ--I eN ~ .1iiiiiiiai ,J_,':iii [1010 1~65 895 6870 7280 1050 1000 3460 r~ i;~'" 990 180 1050 "11iiiiiiiIiiiiiL~ :Eventual Project - 285 Labor Expenses Subtotal 2740 .t"WIIIIiiiIl~ 480 455 310 140 2370 1125 2510 tlBl.t:III 55 480 500 ·rrMI 625 400 Devil Canyon 1/ Labor Expense'Subtota~ .~..~- 805 900 480 4290 8040 1000 1045 8520 Subtotal 1/ -!!II 900 990 180 SUSITNA HYDROgLECTRICPROJE(.I~ OPERATION ANDMA1NTENANCE COST ES'.!"}'JfATES ($10001 yr) Expenses Watana - 625 Labor IlJJc-.@ttl Escalation to 1983 dollars (6%) r:~ Power and Transmission 3300 2/Contracted Services Contingency (15%) Townsite Operations Enviro:nmentalMi tiga tion 'rotal,January 1982 dollars Total,January 1983 dollars ~~!~l!~~'.f:"'~ o o ~'",-~(jiJti_t ~I f AREA AND VO.l.llJME VERSUS ELEVATIOl\J WATANA RESERVOIR I 'I"f :t,,: I I I ·'1, ~-. I Il~J Elevation (ft .mgl) 1460.0 1500.0 1550.0 1600.0 1650.0 1700.0 1750.C 1800.0 1850.0 1900.0 1950.0 2000.0 2050.0 2100.0 215Q.0 2200.0 2250 ..0 Volume (acre-feet) o. 3000. 34000. 127000. 292000. 532000. 870000 .. 1318000. 1877000. 2546000. 3330000. 4248000. 5341000. 6645000. 8189000. 10017000. 12212000. Area (~c:res) o. 150. 1100. 2620. 3990. 5620. 7860. 10010. 12270. 14490 .. 16880. 19850. 23870. 28290. 33940. 39730. 48030. EXHIBIT 3.5 AREA A:~VOLUME VERSUS ELEVATION DEVIL CANtON RESERVOIR EXHJB!T3.6 o. 70. 190. 400. 654. 955. 1360. 1860. 2490. 3565. 5480. 7600. 9560. Area (acres) Volume (ac re-feet) o. 2000. 7000. 25000~ 49000. 65000. 132000" 195000. 292000. 456000. 707000. 1048000. 1484000. Elevation (ft.,msl) 900.0 950.0 1000.0 1050.0 1100.0 1150.0 1200.0 1250.0 1300.0 1350.0 1400.0 1450.0 1500.0 I I ~ ~ ~ 11i1 II, 1:.......',,~". II I 14J I} I fa"~::.'.," [I:IIlO:;:teL.v..... I " } "-< I I ·I!~ .";:j: -~~ 'It"""~J I I " !,.,. .~f."f.J III!l IJ !J ~".•:.1..•'I ,i "" Net Head (%Rated)(Feet) 0.750 51000 0.800 544.0 0~850 578 ..0 Ott900 612.0 0.950 646.0 1.000 680.0 1.030 700.4 1.060 720.8 1.10t}748.0 1.150 782.0 POWERPLANT DATA WATANA Foul"Unit Plant Capacity (}m;(%Rated) 470 •.2 0.650 517.9 0.716 567.1 0.784 617.8 0.854 669.9 0.926 723.4 1 ..000 755.9 1.04,'5 789.2 1.091 834.8 1.154 891.9 1.233 Efficienc.y Turbine Plant 0.880 0.854 0.888 0.862 0.89/+0.867 0.900 0.873 0.905 00878 0.910 0.883 0.908 0.881 0.906 0.879 0•.903 0.876 0.900 0.873 EXHIBIT 3 ..7 A•••&.'....:'".~•,.V v . ...·V.'.I '.•I .~~..• \,•-......~I • (a)Corresponds to monthly plant capacity output that produces the total estimated monthly energy available. (b)Corresponds to four unit capability and is based on monthly net head and turbin~eff.iciency .. MONTH WATANA ALONE DEVIL CANYON WATANA AFTER DEVIL CANYON Capa-Average Reliability Capa-Average Reliability Capa-Average Reliability bility(a)Ent!rgy Energy bility(a)Energy Energy biiity(b)Energy Energy (MW)(GWh)(GWh)(Ml'1)(GWh)(<iWh).(MW)(GWh)(GWh.) Jan 464 345 .290 449 334 239 700 366 247 Feb 425 286 225 451 303 215 674 323 219 Mar 355 264 182 402 299 213 -649 310 212- Apr 338 243 158 379 273 273 625 263 104 May 306 228 139 359 267 188 621 211 95 Jun 261 188 60 35l.255 201 656 180 180 Jul 290 216 82 321 239 200 708 179 133 Aug 464 345 314 320 23R 219 747 2.62 180. Sep 393 283 274 357 257 257 766 249 249 Oct 404 301 191 336 250 203 765 343 30~ NoV'553 398 287 428 308 224 749 348 236 Dec 539 400 362 482 359 256 726 402 269 POWER AND ENERGY PROnUCTION WATANA 2185 DOR Mean Forecast Year 2020 Demand Level m X :J:-OJ--f CN 00 ........~iii1..""'.$..;,:' t ciii····_c-'.. t,:'.__'iiii;- ~',--,'--'," F·.~·-=.··"".t'J-..~jC~]""iiiiiiiiiiilr..-r_.....~.. {:,' '''~.\dO ~~.~r?lllL~_~-~-~tkYr~;I ~,,!;;;r:-.<__,",_.,._._~_:lL~[li.!J~l~~~:~("'aR! :l."",':.;,.-.:<: {) tl c;;- ~, ~::;::;;:::;:.:-. 1~~«l;i''-.#:.~. ;,I ~I i! 'I: ;1 11: ~.' £ I I I ,I ,,I ~:".',~ • J I I I'7 J • ~ I 4.0 NON-5U5ITNA GENERATION ALTERNATIVES I i'.j (J 4 ,.0 NON-SUSITNA GENERATION ALTERNATIVES 4.1 INTRODUCTION 4 ....1 Numerous alternative technologies and systems exist that could be used to generate electricity for the Railbelt Region either as substitutes for or complements to the Susitna Project II The more attractive al ter- natives include natural gas""fired combust:ion turbines and combined cycle power plants,and coal-fired steam turbines.In addition,the ChakachamnaHydroelec.tric P.roject is an alternative to Susitna.These al ternatives have been identified from previous studies and have been re-analyzed for this Update. The application of any thermal powerplant al ternativedepends on elec- trici ty demand and the availability and price of fuels to meet Railbelt generation needs.These were analyzed most recently in Appendix D....l to Exhibi t D of the July 1983 revised FERC License Application for the Susi tna Project.This Chapter provides a summary description of the studies contained in that doc.ument.In addition,recently completed studies by the Power Authority on the Chakachamna Hydroelectric Project and on the use of North Slope Gas for the Railbelt have been incorpo.... rated. The generation alternatives discussed in thi.$Chapter are used in the formulation of system expansion plans described in Chapter 5. 4.2 NATURAL GAS-FIRED OPTIONS Natural gas is the fuel currently used for 66 percent of the electrici.... ty genetating capao".ty i.n the Railbelt Region,and its use provides the region w:tth74 percent of the electrical en.ergy consumed.AssesSments of thermal alternati.ves,therefore,logically begin wi th gas-fited opt.ions. f·I···'··.•..... ,.': \ fl".;... !.~' tr . \1 J il'·,I 1 • 'I'~:I i ( i.,.J It..i',,' ·1"'.'.!; \t-"J •""i it Ii~'\"..... 1 ') :.1··1'.···· •• I .'1..: I ,I I·:..; 1,' I·.•.·•.··.·.·• 't'i., I I 4.2.1 Natural Gas Availability and Cost in Alaska 4.2.1.1 Cook Inlet Gas Availal)ility.Estimates of natural gas re- sources in the Cook Inlet area have been made by the Alaska Department of Natural Resources (DNR;Early 1983),the Alaska Oil and Gas Conservation Commission (OGCC;January 1982)and the United States Geological Sur.vey (USGS:1980,-Circular 860).The estimates are sum- marized under identified and undiscovered resource classifications. Identified gas resources are those resources whose loca tionis known from wells drilled and whose quantity is estimated by flow rates and specific geologic data.Undiscovered gas resources are resources that are located outside of known fields and whose volume is estimated using geological information. The Alaska Oil and Gas Conservation Commission estimates identified gas resources.The OGCe makes an annual estimate by field and the results are published in theit Statistical Report.Gas volume is estimated using initial well head pressure,changes in well head pressure caused by production,drill cores,and field size obtained from seismic data. The.OGCC's estimate of identified Cook Inlet gas resources as of January 1982 is 3.59 TCF.Cook Inlet proven reserves as of January 1983 are taken as 3.5 TCF. The Alaska De.partment of Natural Resources developed an estimate in early 1983 of undiscovered gas resources .in the Cook Inlet Area.The DNR method used was a "Play Approach"which determines the amount of hydrocarbon in a "play"or prospect through use of reservoir engineer- ing equations taking geologic risk factors into account.Inputs for variables are in the form of estimated probabili.ty distributions,and Monte Ca.rlo methods are used to develop a probability distribution for the amount of hydrocarbons. 4-2 4-3 The Cook Inlet area analyzed by the USGS waslarge.r than the Cook Inlet basin analyzed in the DNR estimate.The larger amount consisted mostly time of estimate, area analyzed,and estimating method employed. 1) 2) 3) The DNR estimates undiscovered gas resources for:l)tota.l gas in place,and 2)economically recover.able gas.The estimates are in the form of a cumulative probability distribution with a quantity of gas Versus the probability that the amount found will be at least that quantity.The average or expected value is ~lso presented.The ex- pected value of total gas in place was estimated to be 3.36 trillion cubic feet (TeF)and the average or expected value for economically recoverable gas was 2.04 TCF. In the USGS estimates of Cook Inlet undiscovered resources,a direct subjective method was used,in which the gas resources are estimated by a team of experts.Geological information and results from other methods (e.g.volumetric-yield,play analysis,etc.)are reviewed and weighed by the experts using Delphi techniques.The mean Qr weighted average quantity of undiscovered gas was estimated as 5.72 TCF. The economically recoverable expected value of 5.72 TCF from the USGS estimate is considerably larger than the comparable value.of 2,,04 TCF from the DNR estimate.The reasons for this difference are unknown but development of the estimates differs in at least three major areas • These are: The USGS es timate was made using data available in 1980.While no exploration for non-associated gas occurred during the 1980-82 period, oil exploration continued so that the DNR has information that was not available to the USGS in 1980 • I I ,I I I I I.··.···•·· .' I I \.·1'>..~ -_:". II • I'.:;,..:' I "I, .... I I I I I I I l I I I I of addi,tional onshore areas on the,Seward Peninsula and to the wes t and north of Cook Inlet • The estimating methods used by the USGS and DNR were different.The USGS used a direct subjective method while the DNR used a play analysis approach.Both methods requil'e a considerable amount of subjective probability input as to the existence and quantity of recoverable gas. The meth()ds differ in that the play approach begins wi.th each indi'" vidual potential hydrocarbon prospect and builds up to a total estimate for the area while t in the direct subjective method,the total amount of hydrocarbon is estimated in aggregate after reviewing all informa- tion on the area. The best estimate of undiscovered gas resources appears to be that developed by the DNR.The USGS 1980 es tIma te is out of da te and the method empl()yed is probably not as reliable as that used by the DNR. The expected value for undiscovered gasi,s taken as 2.0 TeF with an approximate probability of occurrence of 0.45. 4.2.1.2 Cook Inlet Gas Cm.i3umption.Cook Inlet gas is used for household heating t commercial applications,LNG and ammonia/urea producti()n t and for electricity generation.Of the 3.5 TCF,some 1.9 TCF are committed by contract to the existing users,and about 1.6 TeF remain uncommltted.In addition to these 3.6 'rCF of proven reser.ves,there are estimc.~ed undiscovered reserves;of which about 2.0 TCF are considered to be economically recoverable. The future consumption of Cook Inlet gas depends on the gas n.eeds 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 by the late 1990's.In addition,there may not be sufficient gas for electrical generatIon beyond some point 4-4 Gas used in field operations and the residual,·'OtherSales u vary from year to year but together are estimated to average about 25 BCF!yr. Oller the period 1983 to 2010 based on historical use. because of higher pri()riti~s accorded other uses,either throl1gh contract or by order of regulatory agencies such as the Alaska Public Utilities Commission~To estimate the quantity of Cook Inlet gas avai1ablefor electrical generation,the requirements and priorities of the major users art?discussed below and summarized on Exhibit 4.1~ 4 ....5 of the Qorementioned needs,there is still a gas remaining that cC'uld be used for electrical for a number of years.Chugach Electric. After satisfyi.ng all considerable amount of generrtion,at least At present,Enstar has ennugh gas under contract to serve its retail customers l,mtil after the year 2000,but since Enstar also sells gas to the military,Chugach Electric.Association,and Anchorage Municipal Light and Power for electric generation,it may hav~to seek additional reserves in order to meet the needs of those larger customers.It is assumed,however,that Enstar will be able to acquire sufficient gas to meet the needs of its retail customers (including new Matanuska Valley customers).Further,it is reasonable to assume that those customers' needs will have priority over the uSe of gas for electrical generatj,on .. Retail use is es timated to increa.se from about 19 BCF in 1983 to 52 BCF in 2010. Phillips/Marathon LNG currently has 360 BCF of gas tmder contra.ct and Collier Chemical has 377 BCF.It is highly probable that both entities will obtain enough of the uncommitted gas resources to meet thei'!'needs through 2010.The reason is that both Phillips!Harat.hon LNG and Collier are established,economically viable facilities~They are also owned by Cook Inlet gas producers who control'part of the uncommitted reserves~I?hillips!Marathon LNG and Collier are therefore estimated to consume 62 BCF and 55 BCF respectively per year from 1983 through 2010. I 11·1··;···· i·•• ~.... I I I I I I I I I I I I, ~I I I I I I.!W I I I I I I I ra~ Association has 285BOF committed through contract and Ens.tar has 759 BOF contracted,some of which will be sold to Anchorage Municipal Power and Light.and Chugach Electrical Association for electrical generation. Assuming tha.t the Anchorage/Fairbanks intertie is completed in 1984-85~ the electrical requirements of both cities could be met (at least in part)with generation using Cook Inlet gas. An estimate of the quantities of Cook Inlet gas that would be required to meet all Railbelt electrical requirements was made using the estimated load and energy forecast (DOR Mean)for the Railbel t area. Estim.ated generation from the existing Eklutna and Cooper Lake hydro- electric units,and the proposed Grant Lake and Bradley Lake hydro- electric units~was subtrac ted,as well as generation from the existing Healy coal-fired unit.The estimated annual gas requirements for power generation increase from 27 BCF in 1983 to .35BCF in 2010. The forecast annual and cumulative use of gas for ea.ch of the major tiset's.,and the total use of gas for the Railbelt,is shown in Exhibit 4.1.The remaining proven and undiscovered (mean Or expected quantity) gas resOUrces are also shown!As can be seen,proven reserves (3.5 TCF)will be exhausted by 1998 and proven plus economically recoverable undiscovered resources will be exhausted in about 2007.!nspectionof the Total Cumulative Gas Use column shows that currently committed reserves (1.9 TCF)will be exhausted in 1992. The data indicates that relying on gas-fired electrical generation to prOVide the Rail belt's needs is problematic because it depend s on the future availability of uncommitted proven and undiscovered reserves for electrical generation. Tile uncommitted proven reserves and any undiscovered resources could be acquired byes tablisl1ed entities orenti ties not shown in Exhibit 4.1, reducing the availability of Cook Inlet gas for electric generation. 4-6 ·1'-,'.'p'""".'.";"".,"'".......','"1 ..,..,:,- Known potential purchasers for the uncommitted recoverable and undis- covered Cook Inlet gas reserves,are Pacific Alaska LNG Associates and whoever would own and operate the proposed Trans-Alaska Gas System (TAGS). o 4-7 T The~roposed Pacific Alaska LNG (PALNG)project was initiated about ten yearS ago,but has been repeatedly delayed due to difficulties in obtaining final regulatory approval for a terminal in California.The project has also had difficulty in contracting for sufficient gas re- serves .1n order to obtain Federal Energy F.egulatory Commission (FERC) approval of the project.At one time ,PALNG had 980 BeF of recoverable reserves under contract.The contracts expired in 1980,but producers did not give wri tten notice of termination so the contrac ts have been in limbo.Recently,however,Shell Oil Company sold 220 BCF of gas that was formerly committed toPALNG to Ens tar Natural Gas Company. This i'educed reserves committed to the PALNGproject to 760 BCF. Implementation of the project would depend primarily on the availabili- ty and price of al ternative sources of natural gas for the lower forty-- eight market,and particularly for the Ca.lifornia market.r"~)n all factors are considered,it does not appear that the PALNG project Will be implemented prior to 1995.The recoverable reserves orig1.nally committed to PALNG can probably be acquired by other purchasers such as Chugach Electric Association anG Enstar. The proposed TAGS project would build a natural gas transmission line from PrUdhoe Bay 011 the North Slope to the Kenai Peninsula (near Nikishka.)•The gas from the North Slope would be liquefieda.nd sold to Japan and other Asian countries..The proposed project is an al tel'-- native method of bringing North Slope gas to market. I f I I J 1 f I i• i .1..1 ,I I·:..... -.~. I I I II...·.'.·.,\.. '~ 'I '. I I I I I I :1 If the project Were implem.ented,Cook Inlet gas producers might be able to sell their gas to Trans Alaska Gas Sys tem for liquefaction and sale to Asia.Sale will depend on the capacity of the liquefaction plant and the market for .LNG.The price paid by TAGS to Cook Inlet producers might be high enough to outbid cornpe ting purchasers,since the Cook Inlet gas would not be burdened with the costs of the transmission line from Prudhoe Bay (although shorter transmission and gathering lines W011ld probably be required). 4.2.1 ..3 Cook Inlet Gas Price.If current and future Railbelt electrical requirements are to be met with gas generation,new purchases of uncommitted Cook Inlet gas and future purchases of undiscovered resources will be required •The price that will have to be paid for these additional gas resources is important in the evaluation of thermal a1 ternatives versus the Susitna hydroelectric alternative. The actua.l price that would be agreed upon for uncommitted gas between producers and the utilities is difficult to predict but an indicction is provided by the recent Enstar/Shell and Enstar/Marathon contracts for uncommitted gas resources.Under the agreements,the wellhead price is $2.32/MMBtu wi th an additional demand charge of $0.35/MMBtu beginning in 1986.Severance tax is estimated at $0.15/MMBtu.A fixed pipeline charge of about $O ..30/MMBtu is additional for pipeline delivery to Anchorage.The pipeline delivery charge from Beluga of $0.30/MMBtu would not be incurred if the gas is used at Beluga to gener.ate electricity.This price could be a reasonable basis provided there is no competition .and there continues to be a plentiful gas supply that can be obtained at low costs-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 - 4 ....8 I .-:: - It can be seen that pricing Cook Inlet gas involves many complex issues.For this analysis,the Enstar gas price has been chosen because it .is tied to the price of oil and reflects recent thinkin.g in natural gas pricing"In spi te of this,gas is priced at about 40%of heating oil price,which would make gas very competitive where the two fuels are substitutable.Further this price was negotiated last year when the oil price was softening,the development of ANGTS and TAGS were becoming less certain:1 and PALNG was not going forward.Further- more,uncommitted proven reserves were still pl'antiful,and the producer's cost of proven reserves was negligible since such reserves were disc.overed in conjunction wi th oil exploration and production years ago. The p-rice.p-roducers might be able to obtain if LNG export opportunities exist might then become important.A method that can be used to estimate wellhead prices for LNG export is to begin wi th the marke t price fer delivered LNC and then subtract shipping,liquefaction, conditioning,and transmission costs to arrive at the maximum wellhead price.The estimated,netback,wellhead price of Cook Inlet gas for LNG export would.vary depending on the average price of oil delivered to Japan.Based on $34/bbl and $29/bbl oil the maximum price that cnula be paid.to producers is $3.00-$3.85/MCF.Thesepricee al"e higher than the estimated prices 'Where no LNG export opportunities e','{ist" Therefore,if LNG opportunities did exist,the price of Cook Inlet gas for electrical gen.eration would be higher than the price assumed since the utilities liould have to outbid potential LNG exporters. 4 ....9 The gas price sittlation could change in the ftlture for the purchase of additional gas II Uncommitted proven reserves would be exhausted (by 1998)and economically discovered reserves must be brought into produc- tion Ichrough exploration and development that would involve risk and substantially higher cost with all the costs allocated to gas.The demand for gas would also increase :resulting in greater competition. With time,it is likely that natural gas price might mOVe closer to the '. I I I I I~-., I I I I I I I ! I I I I 1,.1 '. fl I I '. I I I I I I I I I I I I ~ oil price than the approxima.tely 40%relationship established under the current Eustar contract. The above.considerations would see'tl1 to lead to a higher incremental gas price in future years for the remaining uncomtnitted reserve,and for the undiscovered reserves than the gas price under the Enstar contrac.t. Therefore,the Enstar pricing approach used would tend to fayor the ther'm al alternatives,resulting in a conservative approach to the analysis of the Susitna Project. The method used to project future prices of natural gas was to cOrre- la.te the gas price with the world price of oil.'The method was select- ed since the two fuels can be substituted in many cases and because the terms of the current Enstar contract provide for escalation of gas prices based on the price of No.2 fuel oil on the Kenai peninsula .. Na tural gas prices and real escalation rates for the DOR L.ean and SHCA- NSD oil prices are shown on Exhibits 4 ..2 and 4·.3,respectively. 4.2.1.4 North Slope Gas.The vast reserves of natural gas in the North Slope could be moved closer to the Railhel tif either the proposed Alaska Na tura.IGas Transportation System (ANGTS)or the Tra.ns Alaska Gas System (TAGS)is built.The ANGTS project would deliver North Slope gas to the lower forty-eight states by means of a large diatneter pipeline travers:r.ng Central Alaf,;ka and Canada.The line route is suah that it would be possible to construct a lateral line to Fairbanks .. The.TAGS project proposes to deliver gas to the Kenai Peninsula for liquefaction and export as LNG princ.:tpally to Japan.The development of either ANGTS or TAGS depend s on favorable prices of world oil or natural gas in the loW'~r forty-eight states.At the current prices &nd nea.r-term outlook under the DOR Meanoi!priceprojectiorls,it is unlikely that "'ither ANGTS or TAGS could move forward. 4-10 J I I ,I I I I I I I I I I I I~.~........•". ••1..1 \ .,j I I I !~l••.....I ;, _~~l- Even with ANGTS ox TAGS,natural gas from the North Slope would not be inexpens5.veif transported to either Fa.irbanks or the Kenai peninsula. The purchase price of such natural gas must include the costs of tra.fisporting it to the point of use and of conditioning. ANGTS prices for the Fairbanks area would be $4 ..03-$6.32!MMBtu in 1983 dollars in the first year of pi.peline operation as estimated by Ba ttelle.The General Accounting Office's (GAO)most recent first yea.r estimates are $2.80-$5 ..10!MMBtu in 1983 doll~t"3 in Fairbanks on a delivered ba~is.Previous GAO estimates were $4.88-$7.18/MMBtu in 1983 dollars..These ranges are driven by the assumed wellhead price .. Assuming the TAGS line,prices ~ould be $3.03-$4.l9!H~mtuin,1983 dollars;however,the $3 ..03 value is not realistic since it assumes a negative wellhead price. These ranges converge to a price of about $4.OO!MMBtu for North Slope gas delivered to the Railbelt and this value is assumed to be realistic provided that e>;ither TAGS or ANGTS could be built. In the absence of ANGTS and TAGS,two et'.~rgy development scenarios utilizing North Slope gas have been analyzed in a recently completed Power Au~hority report.These include (1)power generation at the North Slope.via simple cycle Co!:aDustion turbines wi th attendant elec- tric.al transmission from the North Slope to Fairbanks and then on to Anchorage and (2)electric power generation at Fairbanks using combined cycle plants with transmission line construction from Fairbanks to AnChorage..The first alternative would require the construc.tion of two 450 mile 500-kV transmission lines from the North Slope to Fa.irbanks .. The second a1 terna:cive wo~ld require transpor.tation of gas to Fairbanks from.the North Slope by mea,us of a 22 inch diameter,high presSure pipeline and a ga.s Cbtidit:Loni.ng facility on the NQrth Slope .. o 4"'12 '1',.'~"";";"-"".""':l",_0"Ii, _.\C_i.'~ ~"\.. North Slope gas could also be made available at Fairbanks via a 22-inch diameter gas pipeline.The pipeline design flow is 383 million cubic feet per day (MMCFD),a volume of gas sufficient to prodUCe approxi- m;;itely 1400 MW of electr~cal power,and satisfy the projec.ted residen- t.ial!commercial natural gas demand in the Fairbanks area to the year 2010. The North Slope power generati.on scenario is not economicallyattrac- tive and is subject to many reliability uncertainties.The study determined that the capital investment requirements for the construction of 1400 MW of generating capacity and transmission lines (approximately the new capacity required to satisfy the Railbelt's electrical demand.in the year 2010)would amount to $4.2 billion (1982 deIlars).Total oper&tion and maintenance costs for the system would amount to a to tal of $1.1 billion for the years 1993 through 2010.In addition to these high costs,the scenari.~is subject to some severe technica -uncertainties which would require much more detailed study to determine project feaSibility. Utilizing the capital investment estimates cited in the Power Authority report for the pipelJ.t1e and its associated gas conditioning facilities ($5.8 billion)~and assuming that capi tal and operation and maintenance costs would increase at the rate of inflation,a levelized price of abl)ut $9.90!MMBtu was calculated for the gas.Other assumptions util- ized in this analysis include:1)private ownership by the e.nergy industry,2)a well head price of $1.00!MMBtu,subject to a 12.5 per- cent royalty,3)a real discount rate of 10.0 percent and a capItal cost esc.alation rate of 3.5 percent,and 4)a pipeline and condition·- ing facilities life of 30 y\~ars.If o'Wllership and financing of the pipeliYJ.e by the State of Alaska is assumed,the real discount rate would be 3.5 percent and the levelized delivered price of the ga$J would be about $7.20!MMBtUc,Neither cost is competit.ive~,making the pipeline to Fairbanks scenario uneconomical. I I I,·.··:.'," I tl I "I I I I I I I I I I I I '; I I ,I ••••••••'. I, f·'.'", -~ 'I,.•.:" ...Ji I i.~~ ,,1 I I ,..<~ I I I Ii I :Ii~ I I .~I.•.•.~ .. For ~lorth Slope gas tClenter the marketplace,then,natural gas prices will have to rise considerably.There at'e several alternative plans for bringing thi$gas to the marketplace,however,they involve sub- stantial capital i.nvestments in pipeline and gas cond!tioning facili- tles. 4.2.2 Natural Gas...Fired Powerplants-"------------_._-----..:....-,.._"-- Natural gas can be used in the folloW'ing types of thermal powerplants: simple cycle combustion turbines (SCCT),combined cycle combustion turbines (CeeT),and steam turbines..The SCCT and CCCT alternatives are preferred because natural gas-fired otea.m turbine plants are only economical at very large unit sizes (i.e.,substantially larger than 200MW)•In th~sizes appropriate for the Railbel t needs,they are m.ore co~tl~r and less efficient than the eCCT. I;.2 .2 .1 Simple Cycle Combustion Turbines.The simple cycle combustion •"""...! turbine (SCCT)is a well provi::;n system for electricity generation that can be used to meet both baseload and peak demand requirements.Natu- ral gas and air under pressure are combusted with the resulting products of combustion being expanded across the turbine.The unit is characterized by rapid start-up capability with no need for cooling. The combust jon turbine is fac tOry manufae tured and supplied in compo- nents that are assembled at the site.These characteristics result in ecf.omiesof mass production.Technical efficiencies under standard ISO rating (sea level and 59°F air inlet conditions)are given in Table 4~1. 4-13 Table 4.2 Table 4.1 EFFICIENCIES OF COMBUSTION TURBINb UNITS 100 83 67 52 38 13,575 12,343 11-;755 Fuel Consumption as a Percent of Full Load Fuel Consumption Full Load Heat Rate,Btu/kWh 4-14 11,650 12,092 13,008 15,145 22.,141 Heat Rate (Btu/kWh) EFFICiENCIES OF 75--MW GAS TURBINES IN THE ANCHORAGE AREA UNl)ER FULL AND PART LOAD 25 37 75 Unit Size (l-fi4') Load (%) 100 80 60 40 20 The 75-MW unit size is chosen because it can be utilized effectively in the interconnected Railhel t system and it is less costly on a per kilowatt basis than the small units. The sfficiency of the 75-MW machine has been estimated on the basis of Anchorage area conditions under full and part load.This efficisncy is somewhat better than when running at ISOcondi tionsbecause lower air ~nlet tempera.tures improve the performance of the machine.These efficiency values are presented in Table 4.2 I' I ,! 'I 'I I I I I"',~ I 'I I I I I ,·1,,- I ,I··.: ...,..... 4-15 " 4.2.2.2 Combined Cycle Combustion Turbines.The combined cycle combustion turbine (CCGT)makes use of the high-temperature (l0000F) combustion turbine exhaust It In the CCCT system;j the exhaust is ducted to a waste heat boiler or heat recovery steam.generat:~r (HRSG).The steam pressure is then.raised (typical conditions might be 850 psig!950°F)and the steam is expanded in a conventional fJteam turbine to produce additional power. The maximum generating capability is estimated at 84 MW under the ambient conditions (sea level and 33 OF annual average temperature). The data above demonstrate that the large combustion turbine is a reasonably efficient machine when operating at or near full load.Its efficiency suffers substantially,however,when it is operated at less than 80 percent of nameplate capacity. Capi tal and operation and maintenance costs of combustion turbines are summariz,ed on Exhibit 4.4.The capital cost is estimated using the bid-line item costs from the Power Autho ri ty'S Feasibility Level Assessment -Use of North Slope Gas for Heat and Electricity in the Railbelt,dated September 1983. Like the SCCT,the CCCT system exhibi ts both technical and economic gains from scale..These gains from scale are derived,to a large extent,from the SCCT units since a typical configuration would involve two SCCT's and one HRSG plus turbine system.Typical technical gains from scale are shown in Table 403. II r~ f I"'"'" [ [ I"'~..I, .' I I I I I I·.~,"·,',i.I,. i I I I I '~~ Table 4.3 9,720 9,270 8,350 Heat Ratea~ISO Conditions ('1tu/kWh) 49 103 220 System Size (MW) 4-16 HEAT RATES FOR VARIOUS SIZE COMBI~~D CYCLE UNITS Because of both the technical and economic gains from scale available at the 220-MW (ISO conditions,Nominal Rating)size,and because of the assumed interconnection in the Railbel t Region,this mit was chosen for analysis. The 220-MW (ISO Rat:!.Ilg)Ceet tInit was CalctIlated to have a capacity of 237 MW and a heat rate (HHV based)of 8,280 Btu/kWh in.the Railbelt Region of Alaska,when operating at full load.When.operating under part load (below 70 percent)the steam turbine w'ould have to be shut down and the boiler kept Warm for hot start-up.Under such conditions,down to a 32 percent load,the SCCT heat rate would govern. Thus the raub of maximum and minimum efficiencies are as show-n in Table 4.4. r r-' f " " r Ii r J I I, I. I I I I :1 J ; 4.3 COAL-FIRED OPTIONS 100 45 Fuel Consumption as a Percent of Full ~oad Fuel Consumption 8,280 11,650 Heat Ratf: (Btu/kWh;HHV ··:-'Ba""'""s-e-:'d-:-') EFFICIENCY CHARACTERISTICS OF COMBINED CYCLE UNITS AT FULL AND PART LOAD Load (%) 100 32 4.3.1 Coal Availability and Cost in Alaska 4-17 Table 4.4 Coal-fired generation.is another viable thermal alternative for the Railbelt Region of Alaska 0 Coal currently supports 8.3 percent of the utility power generation capacity,and it is used to generate 13.5 percent of the electrical energy supplied to consumers in the Railbel t Region. The CCGT has a thermal efficiency of 41 percent when operating at full load,compared to the SCCT efficiency of 29 percent under the same condi tions •The CCCT demonstrates the classic case of trading capital costs for efficie1.tcy.Capital and operation and maintenance cost estimates for a 237-MW unit are summarized on Exhibit 4.4.The capital cost is taken from bid-line item costs of the North Slope Gas Studies. 'rhere are three major deposits of coal in Alaska:the Nenana Field, the Kukpowruk Field,and the Beluga Field.There are additional smaller deposits in the ',lcin!ty of Nome,lnMa tanuska ~and on the Kenal Peninsula.These fields contain 130 billion tons of coal 1 'I I I I I I ii'L.,·~,· .1 & I l"~ I I . I 'J r\] I I I I I I I,, .1 j, .:;.'""'~ I It I I I I I I I I I .~'.,ii~ ,j ,.''4 resourcesartd 6 billion tons of coal reserves.The Nenana and Beluga fields are the most important as the other deposits have problems that preclude effective 'exploitation on a large scale. The Nenana Field has a total resource of 7 billion tons and a reserve baSel of 457 m.illion tons.The Beluga Field has identified resources of 1.8 to 2.4 billion tons of coal.Both fields are characterized by thick seams (i.e.greater than 10ft.).and low stripping ratios (i.e.4-6)and have modest quality coal with 7500-7800 Btu/lb.Other characteristics of the coals include 0.1-0.2 percent sulfur,7-8 percent ash,greater than.25 percent moisture content,and Hardgrove grindability of about 30-35. Coal production in the Nenana field is at the Usibelli Coal Co.mine at Healy and current production is 830,OOIJ tons/yr.Currently the coal produced at this mine is sold to the Fairbanks Municipal Utility System,the Golden Valley Electric Association,the University of Alaska at Fairbanks,and the U.S.Department of Defense.'~his produc~ tion would increase to 1.7 million tonsjyr if the Suneel exports to Korea,currently under negotiation,commence at full scale,The mine could be expanded further to about 4.0 million tons/yr in support of electric power generation. The current Usibellj.mine uses a drag line and front end loader base.d production system.Capacity utilization rates have sufficient room to support the increase in capacity to 1.7-2.0 miJ.lion tonslyr.The system would be duplicated to achieve the second doubling in capacity. 'The Beluga Fiel d is not being mined at the present time.However,the deposi ts are in reasonable proximity to tidewater and therefore have access to the Pacifi...Rim markets.The Beluga Field represents an export opportunity,and both Diamond Alaska Coa.l Co.and Placer Amex have plans for development.The Diamond Alaska Coal Co.design will 4-18 I I I 1',1.j ,R.\-"'~ 'I.··.....···,, ~I I 1~"4.,,I ~~ ·1 I .1'..11• I I ·1..··',·'..·'\ ,I I I II produce 10 million tons!yr of coal while the Placer Amex project is sized at 5 million tonsl-yl-'.These facilities are designed to serve the growing market of Japan,Korea,Taiwan,and other Asian nations.They would be on-line in 1988,and thay could serve domestic as well as foreign markets. While the Pacific Rim market 1s growing,the lack of infrastructure creates major risks in projecting the development of a large Beluga mine.If the export mines do not develop,a small scale coal mine could be developed for the domestic market.Such a development would in1;01ve a1 tering the production technologies to meet the reduced capac- ity requirements. Coal pric.e is influenced not only by production.costs but also by available markets,coal quality,and mining conditions.The results of investigations concerning these considerations are summarized below. For the purposes of the expansi.on planning analysis,it is a~sumed that up to 400 MWofcoal-fired steam units would be located near the community of Nenana.The plant would not be located at Healy coal field due to the mine's proximity to the Denali National Park.A m:!.ne- mouth price.of $1.40!MMBtu in 1983 dollars was estimated for Nenana coal ba.sed on current contracts with Golden Valley Electric Association arid Fairbanks Municipal Utility SYstem adjusted for changes in produc- tion levels and new land reclamation regulations.Transportation costs to Nenana are es timated to be $0.32/MMBtu in 1983 dollars.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 Btuflb.Besides this 400 MW installed at Nenana~it is assumed t~at all other coal.... fired units would be mine-mouth u~its installed at Beluga. 13eluga.field production costs are estim.a.ted to be $1.70/MMBtu,and the market value of the c.oal FOB Granite Point is estimated to be 4 ....19 -'1 .}, Agreements between (~oaJ.suppliers and electric utilities for the sale/purchase of coal are usually under long-term contracts which include a bas.e price for the coal with an escalation clause • $1.86!MMBtu.Both costs include the cost of developing an infrastruc- ture,assume 10 million tons/yr of production,and assume that an export market develops. Several escalation rates have been estimated for utility coal in Alaska and .in the lower forty....eight states,and they range from 2.0-2.7 per- cent per year (real).Severa!more generic rates have also been develo~.~d by Sherman H.Clark and Associat~'3 and by Da ta Resources Inc. (DRI)•Because the forecasts of DRI and Sherman H.Clark are based upon supply-demand factors,they were applied to the base contract price of coal.The 2.6 percent real rate of increase used by DRI and Sherman H..Clark is applied to the mine-mouth price of Nenana Field coal as this mine is used principally to supply domestic markets.The escalation rates apply to prices before transport.Transportation costs over time are assumed to increase at 0.9 percent per year..The overall real composite rate of escalation :tncluding transportation far coal consumed in a generating plant located at Nenana is estimated at 2.3 percent per year. For the July 1983 License Application.reVision,both Nenana and Beluga coal prices were assumed to escalate to the date a given generating unit entered operation.At that time,the co~.l price for that unit was a.ssumed to remain constant in real terms until the \b."1.it was replaced • Using this approach,the average coal.pr.ice escalatior'rate£or the An escalation rate of 1.6 percent per year of the price of Beluga cQal is based on escalation rates developed by DRI and Sherman H.Clark for coa.l exported to Pacific Rim countrieso11D ,I I..I:..• I ',I i····~.·..···..f t I..';·."..~. 'f I';'·.I ~ I •."..~.•..~.•1 Ii I I..·..····".. 1 1 I I I I 3,,20 2.23 Coal Cost ($!MMBtu) 200 600 Power Plant Capacity Served (MW) ESTIMATED BELUGA FIELD COAL COSTS WITHOUT EXPORTS 1,000,000 3,OOO,OOC Mille Produc- tion Rate (tQns/yr)" Table 4.5 4-21 SHCA-NSD all therm,al generation a1 ternative was about one percent per year .. In the current expansion plan studies for the SHCA-NSD forecast,Beluga and Nenana coal prices were.escalated at their stated rates tmtil 1993; the first:year of coal plant operation.At this date the cost from either source is equal to $2.17!MMBtth For the remainder of the study horizon (1993-2050),a coal price escala.tion rate of one percent per year is used • For the DOR Mean forecast an average 1983 coal price of $1.80!MMBtu is used and zero real price escalation is assumed..Coal prices Ci.':ld real escalation rates for DOR Mean and SHCA-NSD are shown on Exhibi.ts 4.2 and 4.3. Wi thout export market development,the Beluga Field could be develeped to Serve domestic needs.Under such circtiItistances the costs of Eel\tga coal have been estimated as shown in Table 4.5. These costs include the expenditures required for infrastructure developments at the totally undeveloped Beluga Field.The cost of coal is su.bstantiall'>,higher than the $1.70 to 1.86/MMBtu cost associated I U I I I I I .1'..1 . .,1 I'..\ I I I I,......•'....'I I I ·I..·::!·'f·' ; ,I 4.3.2 Coal-FiredPowerplants 4-22 ~ (,T' There are several technologies potentially available for converting coal into electricity including the traditional coal-fired steam turbine system,and coal gasification feeding a combined cycle combustion turbine. wi th an.export market production of ten million tons per year because of the smaller size mine development. The steam turbine system is the most favorable of theseal ternatives 0 The gasification -combined cycle unit is not included for three reasons:(1)the technology is not yet proven and commercially available,and the commercialization time frame is tIDcertain;(2)the capi tal costs are 60 percent higher than that of a compa.rable steam turbine sys tem;and (3)despi te the 60 percent increase in capital cost,the efficiency increase is less than five percent.However,the integration of a coal gasifier wi thcombined-cycle technology would allow use of abundant Alaska coal resources when Cook Inlet gas reserves are depleted.Future studies should include review of the coal-gasification alternative • The coal-fired steam turbine system is a well proven technology.It involves burning coal under a boiler and raising high pressure steam (e.g.1450 -2400 psig/950 -1005°F)0 This steam is expanded in a high pressure (HP)turbine and,in larger systems,exhausted from the HP turbine at an intermediate 'f>ressure and temperature (e.g.595 OF),and reheated in the boil~r to 1005°F.Reheated steam is expanded in the intermediate pressure and low pressure turbines arid then condensed to watt::r using air or water coolers whereupon the cycle is repeated. 'I". ....'"".' '..'I\ I'.!1..,. ··1·••• ····\·.·",{r f I~ ·1'··.l IJ IJ 1.••.•..lJJ.~~ I I":'..; ¥ I., I"..'I ,I I I ··I·~'·f.1 Ii.:..11.II 9,,750 That is a station 10,100 100 150 200 1450 1800 2400 950 950 1000 4 7 7 10,500 Full Load Heat Rate - Btu-kWh Feedwater Heaters Unit Size -MW Table 4.6 4-23 TYPICAt OPERATING CONDITIONS OF COAL-FIRED UNITS ,'1'"~"~....b.t ,-. C' ~ There are substantial technical gains from scale in coal-fired tmits. Typical operating conditions and efficiencies as a function of unit size are shown in Table 4.6 .. Steam Conditions -psig -of There are capital cost gains from scale in coal fired power plants that parallel the technical gains from scale.These economies of scale, plus the technical gains previously discussed,indicate that the 200-MW unit is the most cost effective and appropriate for an interconnected system.Further,the 200-MW size is about the minimum size for using the most efficient subcritical 2400 psig/lOOO°F steam conditions. 1he coal steam turbine system is reasonably effic:tent wi th a fully loaded net station heat rate of 9,750 Btu/kWh. efficiency of 35 percent;,Partial load efficiencies are somewhat lower than full load efficieficies. Coal fired units have been operated at levels considerably below 100 perc.ent with several units being cyc,led down to 25 percent of load. The operating cons traintsassociated.With load cycling are shown in Table 4.7. I I I, I,.,,··,··,,]\ j I ,-: .''\, I, I...·..'···...'~ I I,...r...'.'J I 'I·· '""'.. ...J ~ 't I.','~· '1 ".') ..~, 1·.. ·· \ .1 4 ,I I, '·"'\,.. 'f.f ; I ~l Table 4.7 100 78 55 Fuel Consumption as a Percent of Fuel Consumption Under Fully Loaded Conditions Limiting Constraint Pulverizers,with a2:1 turn down ratio must be taken off line,limiting the ability of the unit to return to full load if load is reduced below 50 percent Auxil:ary fuel must be used in the boiler for flame stabilization below 30 percent load 9,750 10,160 10,710 CONSTRAINTS ON OPERATING COAL-FIRED UNITS AT PART LOAD Heat Rate (Btu/kWh) EFFICIENCY CHARACTERISTICS OF COAL-FIRED UNITS AT FULL AND PART LOADS 50% 30% (%) LOad I 4-24 Table 4.8 100 75 50 Percent of Full Load Level Efficiencies and fuel consumption rates to 50 percent of full load are shown in Table 4.8. These data demonstrate that there is a significant loss in.efficie~cy as part loads are served;however)the degradation in efficiency for a steam turbine is less thall the loss of efficiency associated wi th a combustion turbine. .·I'···~..··.(it ~. I I I •••..~. ......~ I ·1·:'''·:...; .1"·.··".···.···if I, ·I··~.,· ) \' I I I '..1;}.i 1....1.•..'f, I, .'"••~ I .••'.~,i ·.I'r.\Ii I II I·~·t I 11 1'·'.1,~ ~~{ i."·.l~! 1\ ·1·.·······'··d I .1•1 '.;..,I If 'i ...r. I':·'·.·";\ 1 I I ·1····'··...·.··.,1 d i II~aJ ~ Capi tal and t,peration maintenance cost estimates are summarized on Exhibit 4.4..The capi tal costs are from the July 1983 revision of the FERC License Application and are updated to January 1983 price levels using the Marshall and Swift equipment cost indices and CE Constrl.!ction Labor index. 4.4 CHAKACHAMNA HYDROELECTRIC DEVELOPMENT Chakachamna Lake iB located on the west side of Cook Inlet,about 85 miles West of Anchorage.The project concept includes diversion of w.!ter from Chakachamna Lake vi.a a tunnel to a powerplant on the McArthur Ri.ver.Project plans and evalua ti.on are in a Power Authority repo ...:t titled,"Chakachamna Hydroelectric Project ....Int~ri.m Feasib1~ity Assessmemt Report"dated March 1983. The study eval\U1 ted themElri ts of developing the pow€.r potential by diversion of water southeasterly to the McArthur River via a tunnel a.bout 10 mi.les long,or easterly down the Chakachatna Valley either by a tunnel about 12 miles long or by a dam.and tunnel development. The construction ofa dam in the Chakachatna River canyon, apprOXimately 6 miles downstream from the lake outlet,W'~s fou..;d to be unattractive.While the si.te is topographically sui table,the foundation conditions in the river valley and left abutment are poor. Constructi.on of the 12 mile Chakachatna Valley tunnel alternative, running more or less parallel to the river in the right wall of the valley,would not devel"p equivalent pOWer and energy c:apab.il:ity at comparable costs to the MCArth~.lr tunnel al ternative. Two alignments were studied for the MoArthur tunnel.'lbe first cotlsidered the shortest distance tha.t gave no opportun.ity fOr any intermediate points of access during construotion.The second 4....25 'fo",j ~ o Q TeI- I 4-26 alignment was about a mile longer,but gave additional points of access,thus reaucing the time required for construction of the tunnel. Cost comparison.s nevertheless favored the shorter 10-m ile,24-foot diameter tunnel. 4.5 ENVIRONMENTAL CONSIDERATIONS The recommended scheme,designated Alternative E,includes a dam and provisions for fish passage at the Chakachamna Lake outlet ,an intake, 10 miles of power tunnel,and a powerplan t on the McArthur River.The project would have an installed capacity of 330 NW,average annual energy generation of 1,590 GWH and is estimated to cost $1,438 million in 1983 dollars.The project costs and power and energy capabilities are shown on Exhibit 4.5. The environmental and socioeconomic effects of the above-described Non-Susitna generation alternatives are substantial and extremely varieo...Exhibit 4.6 presents a summary of some of the environment- related facility characteristics of these alternatives.Based upon these data,relative environmental impacts by category for given loca'" tions and technology optiorlsare summari zed on Exhibit 4.7 • It is apparent that there is no single superior proje~t alternative in terms of minimizing environmental impacts in all ca.tegories.Rather J many impac.ts are a functi.on of specific site selection,deta.iled The ranking values ~rl thin one category are 'illlweighted with respect to atlothe.r category.For example,a moderate impact to water resources may he more significant than a high impact to aesthetics..To further differentiate between alternatives from an environmental standpoint 'Would require a subjectlve we.ighting of factors between categories,an involved process which requires input from all parties who have an interest in or-who may be affected by project development. I · ..\.'; ,'J ·1.···.····...'· ..:t';, ,) 1···········'·.·i', J ! IJ· .':•.5.';.'I, ,.~ 1151 I " .... '-.J ,,- 11 Ii I I 1.~1.,IJ' Compliance ~~th 4-27 engineering,and extent of mitigative measures. regulatory cri teria and good engineering design should minimize most impacts • • > .\'.,;j.' :n...,> I I I .1'::.1....' .{ I....~'1' I...·~~..If 1·'.·.\.'.'~l, I I frl.I:j; .•".".:.) J " o 4-28 Assessment of the Feasibility of Utilization Northwestern Alaska for Space Heating and Volume III.For APA. l-~ Alaska Oil and Gas Conservation Commission,1981 Statistical Report. REFERENCES AND BIBLIOGRAPHY Arthur D.Little,Inc.1983.Long Term Energy Plan,Appendix B.DEPD, Anchorage,Alaska. Bechtel Incorporated,1980.Executive Summary,Preliminary Feasibility Study,Coal Export Program,Bass-Hunt-Wilson Coal Leases,Chi tna River Field,Alaska. Averitt,P.1973.Coal in United States Mineral Resources. U.S.Survey Professional Paper 820.,U.S~Government Printing Office, Washington D.C. Battelle Pacific Northwest Laboratories.Railbelt Electric Power Alternative Study:Fossil Fuel Availability and Price Forecasts, Volume VII. Clark,Sherman H.and Associates,1983.Evaluation of World Energy Developments and Their Economic Significance,Vol.11.MenlbPark,CA. Barnes,F.1966.Geology and Coal Resource.s of the Beluga"Yentna Region,Alaska.Geological Survey Bulletin 1020-C.U.S.Government Pr.inting Office,Washington D.C. Beluga Coal Company and Di.amond Alaska Coal Company.1982.Overview of Beluga Area Coal Developments .. Battelle Pacific Northwest Laboratories.1982 •Exist.ing Generation Facilities and Planned Additions for the Rail bel t Region of Alaska Vol VI.Richland,WA. Barnes,F.1976.~Coal Resources in Alaska.USGS Bulletin 1242-B. Coal Task Force.1974.Coal Task Force Report,Project Independence Blueprint.Federal Energy Administration,Washington D.C..,November. Dames and Moore.1980.Assessment of Coal Resources of Northwest Alaska -Phase I,Volume I.Fot'Alaska Power Authority. Dames and Moore.1981a. of Coal Resources of Electricity.Phase II~ Dames and Moore.1981 b.Assessment of Coal Resources of Northwest Alaska.Phase It..Volume III.For APA. .I·""·~······,~ ..~ I ·1·.·······' .j '11..~t "~.'t 1·_·-·...··\l f:r'J, I··-··~·l.·'~.r '.IJ...•"~<'.. ~ I , •• 1...·'1' "'{ i· j I ,ll ,'_;L, IJ I "\• NCA,Coal Data 1979/1980. Development of Surface Mine Cost McLean,VA. 1980. c 4-29 Letter from Mr.Ross G•Schoff,State Geologist,Dept •of NaturalResourc~s,Division of Geological and Geophysical Surveys,to Mr. Eric P.Yould,Executive Director,Alaska POwer Authority., February 1,1983. Eba.sco Services Incorporated.1982.Coal-Fired Steam....ElectricPower Plant Alternatives for the Railbelt Region of Alaska.Vol Xllo Battelle Pacific Northwest Laboratories,Richland,WAD For APA. Heye,C.1983.Forecast Assumptions in Review of the U.S.Economy.D~ta Resources,Inc. Ebasco Services Incorporated.1983.Use of North Slope Gas for Heat and Electricity in the Railbe1t.Bellevue,l~A.For APA. Kaiser Engineers.1977.Technical and Economic Feasibility Surface Mining Coal Deposits North Slope of Alaska.For USBM..Oakland,CA. Joyce,Thomas J.,"Future Gas Supplies",Gas Energy Review,American Gas Assn.,Vol.7,No.10,July/August 1979,p.8. Energy Resources Co.1980.Low Rank Coal Study:National Needs for Resource Development,Vol.2.Walnut Creek,CA.(For U.S.OOE, Contract DE-ACIB-79FC10066). Integ-Ebasco 1982.Project description.BOO MW Hat Creek Plant • Ebasco Services Incorporated,Vancouver,13.C. Dean,J.and K.Zollen.1983 Coal Outlook.Data Resources,Inc. r-emonstrated 'Reserve Base of Coal in the United States of January 1,1980.u.s.Department of Energy,Washington,D.C. Levy,B.1982.The Outlook for Western Coal 1982-1985.CoalMining and Processing.Jan.1982. McLean Research Institute.1980. Estimate Equations.Fol.U.S.DOE. MRl 1982.Future Energy Demand and Supply in East Asia.Mitsubishi Research Institute,Toyko,Japan (For Arthur D.Little,Inc.) National Coal Association. Washington,D.C. Olsen,M",et.ale 1979.Beluga.Coal Field Development:Social Effects and Management Alternatives.Battelle Pacific Northwest Laboratories,Richland,WA. I 1·.··\··, l't- 1·1·..·,'.',II '! I'•.~ I.·· ···'··-\\ i If, I I .. I', I- n":'IJ Beluga AreaEstlmatesCost 4-30 ]983.Mining Chicago,IL. Secrest,T.and W.Swift.1982 Railbelt Electric Power Alternatives Study;Fossil Fuel Availability and Price Forecasts.Battelle 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 .. Scott,J.et.ale 1978.Coal Mining.Th~National Research Council/Na.tional Academy of Sciences,Washington,D.c. Stanford Research InStitute,1974.The Potential For Developing Alaska Coal For Clean Export Fuels •Menlo Park,CA.(For the Office of Coal Research). Sta.te of Alaska,Dept.of Natural Resources,Division of Mineral & Energy Management,Historical &Projected Oil &Gas Consumption, Jan.,1983. Sweeney,et .a.l.,November 1977.Natural Gas Demand &Supply to the Year 2000 in the Cook Inlet Basln of the South-Central Ala.ska, Stanford Research Institute,Table 18,Page 38. U.S.Department of Energy.1980.Transportation and Market Analysis of Alaska Coal.USDOE Seattle,WA. Pa ul Welr Company, Hypothetical Mine. I I' I·•..';''f I '1...1 .'1 !. Ii .,:,' I Ij,Ii I ,fftI, • ~~~: m X J:-to--I '!'-... 'Itl} ..... •• MIl-~',-,J"~~""'~'''''''r~- Total Remaining Reserves Cumulative Proven Plus Gas Use Proven Undiscovered --I~.·Ibl!~~- Electric Generation Field Opera-~xpansion Total Retail tions &Planning Gas Sales Other Sales Military Studles(b)Use -~ ESTIMATED CUMULATIVE CONSUMPTION OF COOK INLET NATURAL GAS RESERVES (a) (billion cubic feet) @If# Collier Ammonia/Urea•._-- •p Phillips/ 1>latathon Year LNG/Plant 1983 62 55 19.2 25 5 27.1 193,,3 1.93.3 3157.6 5197.61984625519.8 25 5 28.8 195.6 388.9 2962.0 5002 ..01985625520.5 25 5 30.4 197.9 586.8 2764.1 4804.11986625522.8 25 5 29.1 198.9 785.7 2565.2 4605.21987625523.6 25 5 30.3 200.9 986.6 2364.3 4404.31988625524.4 25 5 27.5 198.9 1185.5 2165.4 4205.41989625525.3 25 5 28.7 201.0 1386.5 1964.4 4004.4J.990 62 55 26.1 25 5 29.8 202.9 1589.4 1761.5 3801,,51991625527.1 25 5 30.4 204.5 1793.9 1557.0 3597.01992625528.0 25 5 31.2 206.2 2000.1 1350.8 3390.R1993625529..0 25 5 31.0 207.0 220701 1143.8 3183.81994625530.1 25 5 31 ..7 208.8 2415.9 935.0 2975.01995625531.1 25 5 32 ..3 210.4 2626.3 724.6 2764.61996625532.2 25 5 33.0 212 ..2 2838.5 512.4 2552.41997625534.4 25 5 33.8 215.2 3053.7 29782 2337.21998625534.6 25 5 34.4 216 ..0 3269.7 81.2 2121.21999625535.8 25 5 35.1 21709 3487.6 (136.7)1903.22000625537.0 25 5 35.9 219.9 3707.5 1683.32001625538.3 25 5 36.8 222~1 3929.6 1461.22002625539..7 25 5 38.8 225.5 4155.1 1236.02003625540.1 25 5 39 ..7 226 ..8 4381.9 1009.22004625542.6 25 5 40~7 230.2 4612.2 778.22005625544.1 25 5 42.6 233.7 4845 ..9 544.22006625545.6 25 5 31.6 224.2 5070.1 320.02007625547.2 25 5 32.9 277.1 5297.2 92.92008625548..9 25 5 34.2 230.1 5527.3 (137.2)2009 62 55 50.6 25 5 34.6 232.2 5759.52010625552.4 25 5 35.9 235.3 5994.8 (a)Estimates of Natural gas consumption,with the exception of electric generation from expansion planning studies,proven and proven plus economically recoverable undiscovered reserves taken from Table D.1.3,Appendix,D-1,Exhibit D,Jtlly 1983. (b)OGPfuel use summary for DOR MEAN Coal/Gas expansion plan with limited gas. -~.-::1 t!;IQ,~",.,."-~h-,".',. ..,.AI'..,~.--.. h ~' ¥ If ~'llt,.'.~ff'~:l"~i - m X :I:-to --f ~ I'J - 0.0 0.0 0.0 0.0 0 ..0 0.0 ~c ~;,.:.-....",,:..,........•~-4+.'-"'?'{'",:"'-,:.;<,~;",~~"", Aver~ge Rate of Change Per Year (%) Cdal 1.80 1.80 1.80 1.80 1.80 1 ..~0 Cost ($!Mt{Rtu) 1.80 l§l~.~.- Average Rate of Change Per Year (%) 0,,0 ~J¥! 1.5 1 ..5 4.00 4.00(c)0.0 1 ..5 1.5 4.18 4.8,5 7.58 5.63 jlJ:~ll§ Cost ($!MMJUu) 4.00 North Slope Gas--. ~~~' 1.5 1.5 1.5 1.5 1.5 -0.1 kSM£i'~..;..:.", Average Rate of Change Per Year (%) DOR MEAN SCENARIO FUEL COSTS (J~nuary 1983 price level) m!'!S Cook Inlet Gas 2.72 2.45 3.15 5 ..72 3.66 4.25 Cost ($/MMBttt) 2.47 ~~ 1.5 1.5 1.5 1.5 -1.4 1.S(b) Average Rate of Ch~nge Per Year (%) @;}~ 58.80 32.42 37.62 43.66 ..-....~;~;) Crude Oil Year Cost ($/bbl) 1983 28.95 (a) 1993 25.13 2000 27.87 2010 2020 2030 2050 (a)Firs t year of expansion planning and economic analysis. (b)Average rate of change in crude oil price las!:five years of forecast. (c)Unti1 2007 .........-~~.i ..~,..~. :~._~,.'J' 1'.'::"'-£'11i~li.:irlWi¥S>'-l' i I \,. ~} ... m X :I:-CD--{, ~w 'IJII- % 2.3/1.6 L.O 1.0 r.o 1.0 1.0 ~ Average Rate of Change Per Year- i!iilJ Coal 2.17 2.33 2.84 2.57 3.13 3.82 1;_: Cost-($/MMJJtu) 1.72/1.86 ,\ ..~~; Average Rate of Change Per Year % North Slope Gas Cost ($IMHBtu) Average Rate of Change Per Year % SHCA -NSD SCENARIO FUEL COSTS (January 1983 price level) Cock Inlet Gas C!l%reM_~l~~~.~t.'!1@;_ Cost-($/MMBtu) ~'"-S~ Average Rate of Change Per Year % ti!it£~ Cost-($/bbl) Crude Oil ~~~...-.~.'" Flrstyear of economic analysis. Yea.r 1983 28.95 2.47 4.00 1993(a)30.49 0.5 2.0 0.5 3.02 4.22 3.0 3.0 3.0200037.50 3.71 5.19 3.0 3.0 3 ..0201050.39 5.00 6.97 2.5 2.5 2 ..5202064.48 6.39 8.92 1.5 1.5 1.5203074.84 7.41 10.35- 1 ..0 1.0 1.0205091.32 9.05 12.63 (a) .--.,.~~.'~~~ -.~. •• ~..:~;,~~,..........-~~-"-' f leI EXH\BIT 4.4 20 1 1 8.0 8.0 500 510 4.90 2.70 30 2 2 604 625 10.0 8.0 1.69 7.25 Combined Combustion Cycle Turbine 237 84 8,280 11,650 5 30 3 8.6 5.7 12.0 8.8 3.2 8.0 7.0 3.2 2,175 2,370 0.6 17.00 Coal-fired 200 9,750 r ..~ Outa.ge Rates,Percent of Time Characteristi cs Nameplate Capacity -MH Heat Rate -Btu/kWh THERMAL PLANT OPERATING PAlUL~TERS AND COSTS (a) . Scheduled (Immature) Scheduled (Mature) Constructioil.Period,yrs Forced (Immature) Forced (Mature) Immature Period -yrs Unit Construction.Costs -$/kW Unit Investment Cost (b)-$/kW Operation and Maintenance Costs Variable O&M costs-mills/kWh Fixed O&M Obsts -$/kW/yr Economic Life -Years (a)January 1983 price level (b)Inclu.des interest during construction at 3•.5 percent interest, escalation not included. I I I~.'.·.~J •• I II ,.,rr ~ .1·'········.1.'t.; ,) -...;,; I i IJ EXHIBIT 4.5 179 170 153 137 231 330 330 330 330 275 179 195 Maximum Plant Rating MW 330 2.0 177 168 150 135 124 120 118 124 136 155 177 193 1,269 127 1,396 4,230 Minimum Plant Rating M'''; 133 114 113 98 92 86 88 92 98 115 128 144 Firm Energy GWh 1,301 -_\..,.. .:4 ••·; 133 114 113 98 94 96 138 228 179 126 128 144 Average Energy GWh 1 J591 Month CHAKACHAMNA HYDROELECTRIC PROJECT DATA(a) January February March April May June July August Septem.ber October November December Total Op1erat1on and Maintenance Cost - $millipn Total Capital Cost Including Transmission (a)..$million Installed Capacity -MW Total Capital Cost -$!kW Monthly Power and Energy Production: IDC - $million Total Capital Cost - $million (a)Chakachamna Hydroelectric Project Interim Feasibility Assessment Report,Bechtel Civil &Minerals,Inc.,Alternative E,:March 1983 .. 1· ·····;··1.....1 } I,"'·'}il,[ J I (,,-', ..:t \ I ,~ [ "I) ,f, IJ IJ I I.,.-? .~ _I m X J:-to--f .c:a.en -;- --- 1.64 millIon (ave) 1,220 1-2 .. ~~: 40 1.64 million 70 (ave) 15 25 120-175 40 mI,road 500-aoo 200 ... 40 70 15 25 50G-aoo 200 -;\~f~:'~l 200 100-200 200 200 50-150 130-150 130-150 90-140 120-175 5 mII6\~ 100-200 -,~,: 50 115-200 140-200 60-9Q!! 5 25-50 ~!..v~·,'"·~........j ____bQCatlon/Technology 8J&L~ 28& ~~~ tbne tbne Infrequent Infrequent 2StY 25 25--50 50 500 500 109 109 0·°61 O.O~I 8/al a/e/Negllg Ibleo.~O.~at al al 810.6 0.6 cl cl cl cl 50 50 50 50 Bel uga N9mma flbrth slope Fa Irbanks Kena'Bel u.ga Chakachamna (Coal Fired)(Coal FIred)~t.Gas)(Net.Gas)(Nat.G8s)~at.Gas)(Hydro) .-.~;-~~~, Btu) Btu) Btu) ?M.!,;-"'"..,.."....--..,-~ (I b/lO~ (lb/106C1b/lO ENV IRONMENT RELATED FACI L1TY CHARACTERISTICS FOR ALTERNATI VE POWER GENE RAT I ON CPT!ONS .~~.f!~j #~~ Air Environment Bnlsslons Part leu late Matter Sulfur Dioxide NI tregen Oxides Environmental Factor Plant Discharge Requirements (gpm) Proces s Water Coa j PI Ie Runoff Demlnerall zer SfreemGenerators Treated SanJtary Waste Floor Drains Physical Effects-(max.struc.height ft.) Water Environment Plant Water RequIrements (gpm) Wl!lter Inject Ion other Lend Env I roment Ednd Requlrem~mts (ec.res) Plant ConstruCTion Camp 5011 d WesfeOJ sposal Socfoeconan IcEnvlronment -COnstruct Ion Workforce,peak (personnel) Operating Workforce (personnel) a/Below Stl!lndl!lrds bl Assumes 70%Reduction cl Emissions vl!lrJable within standerds.Dry control techniques would be used to meet calculated No x standard of 0.014 percent of toTal vol urne ofgl!lseous emissIons.Th Is Vl!ll lie eel culated based upon new source performance standards,facJ II ty heat rate endunItsIze. d/Dry Cool ~ng.wet Coo!lng =1,947 gpm el I nc,(udes SW Itchyard ~::."'_~•...J~~~~ !-".,..,~ ......-•.'~,..,.,.,...•, ..-.....~•'••0 ..c..".".'.'.. '.".-"'".,......~..~e'_',,;.:..:,,"'""_.....•0 '~¥'.,.-_,~ ..- ~..•,'-'__'>o'.'~"t ~._."...-~..z:;;':~.:.l.'.:..j ~.~t'*]j~.i>a.~ I 11 $0 -:---:~~~, "I,~'"'~~. Befuga Chakachamt~s (Nat.Gas)(Hydro)_ iJII",",f 'y''''.~~,~J.4!@'!1 Kenai/Nikiski (llat.Gas) ~-'-_i .....-..'.;,.--._'".;_~:.Iit.};H~;&Jt North Slope Fairbanks (Nat.Gas)(Nat.Gas) ,~._.....,..""."'~;.;.4~ik2I'...~.-....~-----"'~ Nenarla (Coal Fired) 'JIJlIIIlW,r:::;~~ij2 fjf_.._--....--..".~ 2 4 2 3 1 1 0 3 1 1/2 0/2 0/2 2 4 0 0 1/2 0/2 1/2 0 4 2.2 I/.3 0/3 0/3 1 2 4 1 1/2 0/2 1/2 3 3 :3 2 1/4 1/3 1/3 2 '3 Beluga (Coal Fired) ~,,,,.~--'..<.....;.~) Location/technology QUALITATIVE RANKING OFENVIROt~NTAL IMPACTS ASSOCIATED WITH ALTERNATIVE PROJECTS ~~".<,.'~"'",,'-~~~~-:~'":) ~~"""..- m>< ::I: r.o -f ,f.:lr. ~ NOTE:In case where two numbers appear,the first number refers to the power plant only,while the second number incorporates secondaryaupport facility impacts (e.g.,gas line,transmission line). Key:0·...no impact 1 -low impact 2.-moderate impact 3-high impact 4-severe impact Aesthetics Socioeconomics Mr Resources Aquatic.Ecology Terrestrial Ecology Water Resources Environmental Category JR#"~!\ +''''''_C''-., 1 I l' .,. V;lWtllt'ilti$i".'Ui;;ill J ' ~, 'a t ---.. 1 ..._ 5.0 SYSTEM EXPANSION PROGRAMS It J, .~ ( •I' rI I I~- I, I I I 1\ I. Ii 'ti' l Ji, " 5.1 INTRODUCTION 5-1 The studies are performed using a computer program developed by General Electric titled "Optimized Generation Planning"(OGP).The input data. on the Susi tna Project and the thermal al ternatives are described in Chapters 3 and 4.A supplement to this report contains computer output from the OGP program.for selected DOR Mean expansion programs analyzed in this update. 'The objective of the expansion studies is to develop long-term power supply plans for the Railbelt electrical generation system with and wi thout the Susitna Hydroelectric Project.Power Supply programs are developed for electric power demand forecasts based on DOR Mean and SHCA-NSD oil price forecasts.With these oil price scenarios)the lola tana Project would enter service in 1993 and practically all of the Susitna Project potential would be absorb~d in the sys temby about the year 2020. 5.0 SYSTEM EXPANSION PROGRAMS The power supply programs are developed using econom.ic planning crite.- ria such as discount ra~'es,planning horizon,etc.that are described in Chapter 6.In turn,the power supply programs provide annual and present 'Worth costs of alternative power supply programs.These re- sultsare used in the economic analysis using a li.fe cycle approach described in Chapter 6~ In this Chapter)the existing system is first described.Next the syst~m expansion from 1983 to 1992 is addressed.Then the criteria for system expansion from 1993 are discussed.The year 1993 is the first year that theSusitnaProject is considered to be operational.The OGP computet m.ade1 i.s described briefly.Alterua tive expa.nsion programs which result from the study are then presented and discussed .. 11 .11_"_of III\.j.•.•'c'•., Ill..J.-; _II,·...1 , .1 .•J I ,II ...'i' fl',.•.1.·.·.,·ff~ H j1 1 I 'I J I I " ') ,I 1 1,1 L 1"II I; It~i _t' ;",..","1,., " d ...,! _....'_..'"--~ 5-2 5.3.1 planned System Additions The two major load centers of the Railbeltregion are the Anchorage- Cook Inlet area and the Fairbanks-Tanana V-':llley area,which at present operate indepe~1dently..Exhibit 5.1 summarizes the total generating capaci,ty within the Railbelt system in 1983.The total Railbelt in- stalled capaci ty amounts to 1123 MW excluding installations not avail- able for public service at military bases.The 1123 HW consists of 1077 MW of thermal generation fired by oil,gas,or coal plus the Ek- lutna and Cooper Lake hydroelectric plants totaling 46 MW.Average annual and firm.energy estimates for the Eklutna and Cooper Lake hydro- electric projects are shown on Exhibit 5.2. The Power Authority has begun the construction of an Intertie connect- ing the Anchorage and Fairbanks load centers with a single circuit transmission line between Willow and Healy scheduled for completion in 1984.The line will initially be energized at 138 kV,but can be operated at 345 kV as the loads grow in Anchorage and Fairbanks ~The completion of the Intertiewil1 improve the reliability of service of both load centers and provide economy exchange .. .5.2 THE EXISTING RAItBELT SYSTEMS 5.3 1983 -1992 GENERATION EXPANSION Two hydroelectric projects are assuTaed to be added to the Railbel t system prior to 1990:the Bradley Lake Hydroelectric Project wi th 90 MU of generating capacit)'and 347 GWh of average .:1nnualenergy,ahd the Grant Lake Project with 7 MW of generating capacity and 25 GWh of annual energy.The average annual and firmenergyestima.tes for the Bradley Lake a.nd Grant Lake Projects are shown on Exhibit 5 ..2. I I I I.·'.'··.··.·.·.'t!, 1'\.; 11 -Bl' IIf',...._,-:., I;,) ,'j "1·'1..' "J I~'t.,..' II ~ Ii Ii I..,t, ......,.. •'! ,.~i'"..~,· I".';,'.j I :: '1.\ ._, 181 254 317 59 143 954 5-3 ~- Oil-fired combustion turbines Natural gas combustion turbines Natural gas combined cycle plants Coal-fired steam plants Hydroelectric plants Total installation irt M"ri F1airbanks Municipa:Utility System is considering the addition of ;:.. 25-30 MW cogeneration unit to ~place Chena Units 1,2 and 3,and Chugach Electric Association is studying the feasibility of a 34-MW combustion turbine at Berni Lake and an 80-MW combustion turbine at the Beluga Power Station.These plans appear te,be moving forward but have not been finalized and are not included as part of the 1992 Rail- belt systeru. Other than these plants and the Intertie,no major generation is con- sidered to be inst ;\lled since the.Railbelt utilities would have fac"" tored Susitna or its alt3rnatives into their resource planning,and any new additions would likely be limited. 5.3.2 1992 System o The Railbelt system is assumed to be identical prior to 1993 under the Susitna and Non-Susitna expansion programs • After allowance for the retirement of oil and gas-fired units and addi- tions of new capacity in the period 1983 to 1992 ,the generation system capacity (MW)at the time of the introduction of Susit~'la Cor its alternatives)is considered to be as follows: Should it become desirable,scheduled :"etirements of the exi.sting plants could be delayed so that sufficient capacities would be 8'.~il- 1\ ; •.1 .'., I I'~l .! 'I ~;It'1 1'\1t ).,.:, .~~J Ii IE.;].'J~...,) 'e" f: ~:rl~ h II .•.I!'" ·Il \1~":J1:\ f' !'j!I I Il..·-}.,,Ii ·1,.··.·".'"J I..·.'.··~~ ~, 5-4 5.4.2 Non-Susitna Alternatives Study of the Susitna Project,which is described in Chapter 3,has been directed at the .-levelopment of long-term power supply plans for Watana and Devil Canyon,including investigation of the timing of the Devil Canyon development.Exhibit 5.3 summarizes pertinent da ta and con- struction and investment costs for the Susitna project.The investment costs include interest during construction computed at 3.5 percent using estimated construction cash flow distributions. 5.4 •.1 Susitna Alternative able to meet the system demand in 1993 When the first units fromWatana 5.4 GENERATION.ALTERNATIVES ente.r ser'lJice .. The major portion of the current generatingcapabili ty in the Rail bel t is natural gas with ~ome hydroelectric ...coal"and oil-firedinstalla- tions.Chapter 4 describes natural gas-fired and coal-fired generation sources which could be attractive alternatives in the Railbelt. In addition"the Chakachamna Hydroelectric Projec.t is discussed.Ex- hibit 5.4 summarizes operating charac teristics and costs of the Non- Susitna alternatives selected for the power supply plaT'),studies. 5.5 FORMULATION OF EXPANSION PROGRAMS Capacity expansion studies c.over three major functions:(1)reliab.ili- ty evaluation;(2)electricity production simulation;and,(3)capacity expansion optimization.Expansion optimiza tion analyses provide a systematic means to evaluate the timing,type"and syStem costs of new capacities. 1'.'.'1..,:~ I I I"".···.'.····.'·II I "' It 11; ~;' Ip "'>4-.._" The plans are structured based on the following criteria and optimized with the procedures of the OGP model • "r ~"'"""'''"''"'''''''-'''''''-''.''---'-~::l-I'''-:~:',';,~,_,r.!,·i.o:'~:.:\, ~,-,~_._--'..,.. 5-5 r-"__li' In developing an optimal plan,the program considers the existing and committed un.i ts (planned and under cons truction)available to the sys- tem and the operating characteristics of these units.Then the program considers the given load forecast and operation criteria to determine the need for additional system capaci ty based on specific reliabili ty criteria.This determines how much capacity to add and when it should be installed.If a need exists,the program will consider additions from a list of alternatives and select the available unit best fitting the system needs..Unit selection is made by comp1.1ting production costs for the system for each alternative included and comparing the results. The unit resulting in the lowest system production costs is selected and added to the system.The OGPmodelfng procedure contains seve:r:-al key elements which are discussed below. 1)The existing system and planned additions 2)Susi tna and Non-Susi tna al ternati,"'es 3)Cost and characteristics of future additions 4)Fuel availability subject to limitations of reserves 5)Fuel cost and escalation 6)Generation system reliability 7)System operation The General Electric Optimized Generation Planning (OGP)model was used to develop the power supply plans •This program was used in the earli- er feasibility and License Application studi.es,and the specific Rail- belt system data base has been suff.iciently developed.Exhibit 5.5 outlines the procedure used by OGP to determine an optimum generation expansion plan. (.. I I~~\ Ij~r ~I!s I; I·~;' ,[ ,J -*'"~ If, I, I I't t ....;.".,.1 II '.i. ·1",'. ':1;)~ I I.~."i, ~~ 5-6 ,.""",,·0""'_'•--'-1 5.5.1 Reliability Evaluation The Loss of Load Probability (LOLP)method is used in the OGP program to determine when additional capacities are needed.The LOLP approach is concerned with the probability that cumulative system capacity after forced outages 'Would result in a deficiency in available capacity to meet the sys tem load.Sensi tivi ty analyses were conducted for one day in ten y~ars,one day in five years and one day in three years to re- late the I,OLP to reserve margin.The results indicated that reserve margins in the 30 to 40 percent range cou~d be achieved 'tv!th an LOLP of 0.20 days per.year or one day in five years,for the Railbelt utili- ties.Reserve margins in this range are considered to be satisfactory for the Railbelt. 5.5.3 Thermal Unit Commitment 5.5.2 Conventional Hydro Scheduling In the simulation,the initial Watana project is operated on base in order to maintain nearly uniform discharge from the powerplant.When Devil Canyon comes online,Watana is opexated in a load following mode, while Devil Canyonopera:::.es on base..Under base loading,constant plant ratings are specified that correspond to the plant capacity out- put that produces the total energy generation estimated to be available .. After modifications for hydro and unit maintenance,the remaining loads are served by the thermal units on the system..The units are committed to minimize the operating costs..The operating costs are calculated from the fuel and variable O&M costs and inl!~t-output curve for ea.ch uni t..Fi~ed O&M costs do not affect the order in which units are com- mitted,but are included in the total production cost. f I....~.j 11...)1~ I 11 .,~\ I Ii I; J} I I I I··...·.···..··'·':\ 1 "~ ,-/ I II I 1·4.J 1:1 r..1: The unit commitment logic determines how many units will be on-line each hour and which units are committed in order of their full load energy costs starting with the least expensive. 5.5.4 OGPOptimization Procedure For the year under study,a system relia.bility evaluation is performed to compute the need for installing additional generating capacity.If the capa.cityis sufficient to maintain the desired once in 5 year LOLF, the program calculates the annual production and investment costs and proceeds to the next year. If addi tiona!capac!ty is needed,the program \V'ill add units from a list of available additions until the reliability index is met.For a combination of units the program calculates annual costs and selects the most economi:21 installation. The OGP logic utilizes a look-ahead feature that dev'elop~,annual costs over a la-year period for combinations of 11ni ts toconpute j.f unit additions beyond reliability requirements reduce system costs.If a generating unit is selected,the reliability and costing calculations are repeated for the chosen alternative. 5.6 1993-2020 SYSTEM EXPANSION 5.6.1 Transmission System Expansion Associated with Generation System Expansion Transmission system expansion associated with the Susi tl1aProject has been studied in detai.l,and the costs have been estimated and included as part of thepl"1ject. 5-7 -I'_....-'."'- '.~ 5 ....8 5.6.2 1993 -2020 Generation Expansi01! $220 million $117 million Coal-fired and/or combined cycle plants at Beluga: Goal-fired plant at Healy A preliminary review of the year....by-year transmission requirements for several specific Non-Susitna gene.ration expansio'd programs indicated that the simplifit;'\d cost estimates for the Non=Susi tna transmission system were reasonably in line w-.j th,out slightly lower than,detailed year-by-year estimates. Using OGP,j"!ternative expansion programs \Vere developed for the period from January 1993 to December 2020 to establish the least-cost system expansion programs for that period for both the Susitna and the Non- Susitna cases.The alternative expansion programs were tested for the DOR Mean and SHCA-NSD oil price scenarios.With these oil price scena- rios,the Watana Pr.)ject would enter service in 1993 and practically all of the SusitnaProject potential would be absorbed in the system by about the year 2020. To simplify the analysi3,the following transmission system costs are added to coal-fired steam and combined cycle combustion turbines. Transmission system e:g:pansion associated with the Non-Susi tna al terna- tives is to be added as a separate item to the Non-Susitna alternatives depending on how the generation.system expansion takes place. These costs provide for new lines to the existing transmission sys tem and for increasing capacity within the present transmission system. In the Non-Sus!tna cases,coal-fired and gas....fired generation and the Chakachamna Hydroelectric Project were tested.Four basic supply plans were develQped for each load forecast as follows: I 1','1;J "i< I) I (,' ';._'~ I In addi tian,the Gas (inc.luding natural gas--fired combined cycle and combus- tion turbine) Coal (including coal-fired steam plant and natural gas....fired combustion turbines) Gas and Coal (including natural gas-fired combined cycle, coal-fired steam plant,and combustion turbines) Chakachamna Hydro (including coal,comb~ned cycle and combus- tion turbines). o o o o operation and maintenance of all generating units. The annual costs from 1993 through 2020 are developed by the OGP model and are converted to a present worth in 1983.The long-term system costs (2021-2050)are estimated from the 2020 annual cests,wi th ad- justments for fuel escalation,for the 30....year period.The Susitna and Non-Susitna expansion plans are compared on the basis of the sum of the pr.esent worths from 1993 to 2050. 5-9 For the supply plans,proven and economically recoverable undiscovered t'eserves of natural gas from Cook Inlet are considered depleted by about 2007.At that time natural gas for electricity generation is considered to be available from additional higher--cost undiscovered Cook Inlet reserves or from the North Slope wi th ANGTS or TAGS..An analysis is also performed for a case in which natural gas supply at a higher cost from North Slope is available by means of a 22 inch dia- meter,high pressure pipeline to Fairbanks.A detailed discussion of natural gas resources and prices are contained in Chapter 4. The total costs for the planning period include all costs of fuel and production cost includes the annualized investment costs of any plants and transmission facilities added during the period.Costs common to all the al ternatives are excluded.These would be investment costs of facili ties in serving prior to 1993,and administra tive and customer services costs of the utiliti.es. If~ ( -'i ,Ii ,--~ ~j !·....•i·.1 1 I;;,, 11\.- I I I .(•....'.. I' I I M·' i,\."I, IfI.~ 5.7 REVIEW OF EXPANSION PROGRAMS 5.7.1 Comparison of Expansion Plans under the DOR Mean Scenario Exhibit 5.6 shows the expansion plan yearly MW additions for the Non- Susitna alternatives and Exhibit 5.7 shows similar information for the Susi tna a1 terna tive.Exhibit 5.8 summari zes the generation mix,re- serve margin,loss of load probability (LOLP),economic costs of power in $/MWh,and cumulative present worth of sys tem costs for the years 2020 and 2050. Exhibit 5 ..8 shows the Non-Susitna plans,with a com.bination of gas .... fired combined cycle and coal-fired steam as being the o~timum Non-- Susitna plan~Reference to Exhibit 5.6 shows this plan beginning with a two....uni t combined cycle plant in 1993 followed by installation o:f combustion turbines until 2005.After 2005,coal-fired plants are added and additional combustion turbines are brought on line to replace those added in earlier years.This plan was developed by OGP through its own internal optimization process Which compares the po onomic ad- vantages of various mixes including combined cycle.,combus cion turbine and coal-fired al ternatives.To ensure that the plan is indeed supe- rior to any other thermal alternative,the OGP program was tested with the use of a coal-fired plant in 1993,and further tested wi th the use of only gas-fired generation..These expansion plans are found to be less economical since they result in higher cumulative present "Worths for the period 1993-2050. The Chakachamna Project was also tested as one of the Non-Susitna.al-- ternatives,and it was found to have a cumulative present worth greater than the optimum Non-Susitna plan_The 195 MW capability of the Chaka- chamna Hydroelectric Project,as shown in Exhibit 5.6,is based on the project's average energy generation in the month of December,which is the Railhel t area peak demand month and the month used by OGP for out- put reporting purposes. 5-10 5-11 Exhibits 5.9 and 5.10 compare the contribution of energy production be- tween a Non-Susi tna plan and the Susi.tna plan"As shown by these two exhibits,the Rai.lbelt system will continue to be dominated by oil and gas-fired gene.ration over the next 10 years.By 1993 a very large share of the gas and oil-fired generation can be replaced wi th Susi tua in operation.Otherwise)natural gas will continue to be the principal source of fuel for the Rail bel t through the end of this century and beyond. 1 5.7.2 Expansion Plans under the SHCA-NSD Scenario For the gas!coal a1 ternative,the OGP ,program selected a mix of natural gas-fired combined cycle plants,coal-fired steam,and combustion tur- bines.However,a substantially greater amount of coal-fired steam installation is added,and the only addition of a natural gas-fired combined cycle plant would be in the year 1993. Exhibi t 5.11 shows the Susi tna and Non-Susi tna expansion plans to meet the forecast load under the SHCA-NSD oil price scenario.The exhibit provides the generation mix in the year 2020 for the alternative supply plans,reserve margin,and present worth costs. The results of this analysis indicate that if oil prices and load growths sh()uld exceed the SHCA-NSD scenario,the logical ~ho:tce for the Non-Susitna 1993 installation would be.a coal-fired .steam.plant. Again,to ensure that the OGP has made the correct selection,a coal expansion ,rogram Was tested.The coal expansion program would result in slightly lower cumulative pr'esent worths than the gas!coal program. However,the coal alternative appears to have much less reserve,conse- quently these two alternative expansion plans are considered nearly equal.The gasl co;:1.1 expansionplan is selected for comparison pur- poses. I ~I I·~." I I I""·".·.•·.i ! I I 5-12 The Susitna alternative is clearly favored over the Non-Susitna al ter- natives for the SHCA-NSD forecast scenario. 1- The.Chakachamna Hydroelectric Project appears to be c.ompetiti,\Te ~"'hen compared wi th the all-thermal supply plans under the SHCA-NSD case, while the project is marginal under the DOR Mean Scenario.The results appear to be reasonable in view of the higher cost of fuel ooder the SHCA-NSn case,and a hydroelectric project would therefore become more attractive. I I I [" J I I 's I I I( II I..'!·· .~. i I I I I (a)Installed capacity as of 1982 at O°F (b)Excludes National Defense installed capacity of 101.3 ~'l EXHIBIT 5.1 1122.8 (b) Railbelt Utility Installed Capacity (a) Anchorage Municipal Light 311.6 &Power Department Chugach Electric Association 463.5 Golden Valley Electric Association 221.6 Fairbanks Municipal Utility System 68.5 MatanuskaElectricAssociation 0.9 Homer Electric Association 2.6 Seward Electric System 5.5 Alaska 1?ower Administration 30.0 University of Alaska 18.6 TOTAL GENERATING CAPACITY WITHIN THE RAIL BELT SYSTEM -1983 in Megawatts eEA GVEA AMLP FMUS SES MEA REA Uof A APA TOTAL o Abbreviations I ·I'~,i': ,~. I '; r: I I I ! I I I',$> " I I I I I,>J J 'f I'·~ •",Ii m X :I: OJ ~ U1 ~ ...'... 486 Total -~ 19 .1'.. 315 ..~ 34 -~ Firm Energy-GWh 118 Eklut-Cooper Bradley Grant ua (a)Lake (a)Lake (a)(b)Lake (b) .. 568 aM ~....~ 25 .~~, 347 EXISTING AND PLANNED RAItHELT HYDROELECTRIC GENERATION .......'~'ibiS 42 .;r~'!l: Average Energy-GWh 154 Eklut-Cooper Bradley Grant na (a)Lake (a)Lake (a)(b)Lake (b)Total (30 MH)(16MW)(90 ~IW)(7MW)(143 MW) ~~l'''~,,:"~~ (a)Source:1982 Feasibility Study. (b)Assumed to be scheduled on litle in 1988. Month Total Jan 14 4 31 2 51 13 4 35 2 54Feb1232824512332249 ••~tt"§~j!lIii Mar 12 3 28 1 44 9 3 24 1 37 I Apr 10 3 23 2 38 10 3 26 1 40IMay1232624311331146June12327244R221233July134302499322236 Aug 14 4 32 3 53 8 2 23 1 34Sept133283479223237Oct14431251Q325138~ Nov 14 4 31 2 51 B 2 22 2 34Dec1443225212321248 m X:r:-0:1--f (11 W ·lIS••.. 5547 .~ Cost ....... ~~.. 4892 Construction (c)Investment (d) ($Million)($Million) ~~~.. 5120 r~4i~~akt~. 6820 Energy Production Average (b)ReliabilitY (GWh)(GWh) ~~~ SUSITNA HYDROELECTRIC PROJECT 1752 It.;!.~#-,~.---.:~~.~~- 1398 Installed Capacity (a) Initial Ultimate (Ml-l)(MW) .,~~§@@J·I....~""....._,.-,..,1!§4 Single Project Watana2185 724 1088 3500 2265 3338 3785 Devil Canyon 501 501 2260 2005 1554 1762 Combined Pro ject Watana 2185 f- Devil Canyon fh)Based on 4-unit powerstation,with system demand constraints fc)January 1983 price level (a)Average plant capability in megawcitts for December (d)Includes interest during construction at 3.5 percent interest and an 8-year construction period;no real escalation of construction cost was included. :~...0••_•••\ gU)'4, '. t I '" Zlllt~.,~~ Ji II~. m>< :I: CD -f U1. .$:II. aMall18 1 •"' ~.~ 1.26 (a) 330 ~A Chakachamna Hydroelectric Project ~ 4.90 2.70 84 11,650 tM.4M Combustion Turbine 00i 1.69 7.25 237 ~,2RO '4...J!;..,J!\..~,..",.w.~..,_..._.."..-....,..•.-~ 0.6 17.00 200 9,750 12.0 8.8 3.2 8.0 7.0 3.2 8.6 10.0 8.0 5.7 8 ..0 8.0 3 2 1 5 2 1 6 2.,175 604 500 3,847 2,370 625 510 4,230 Combined Coal-fired Cycle ~}!a~ NON-SUSITNA PLANT OPERATING PARAMETERS AND COSTS(a) fI§I#x~~! Characteristics Nameplate Capaeity -~~ Heat Rate -Btu!ktijJ Outage Rates,Percent of Time Scheduled (Immature) Scheduled (tfature) Forced (Immature) Forced (Mature) Cortstruction Period,yrs Operation and Maintenance C-"'\sts Unit Construction Costs -..$!kW Immature Period -yrs Unit Invea,tment Cost (b)-$/kW Variable O&M costs -mills/kWh Fixed O&M Costs -$/kW!yr fe)Based on average annual energy generation of 1,591 GWh (a)January 1983 price level (b)Includes interest during construction a.t3.5 percent for the construction periods shown;no real escalation of construction cost included. .",,1$~1t~".......'-~-~.~; ,'r t I '....,r n~~''-.; ~....I EVALUATE RELIABILITY..,.1.-.....-..................----------__...-------------11 -~ STU~ ALL YE~ ~l EXHiBIT'5.5 FUTURE ECONOMICS ~, OPERATING GUIDELINE ~ _____S_T_U__O_Y_D_A__T_A_..........] I• GENERATION SYSTEM - I --.- - SELECT UNIT SIZES &TYPES CHOOSE LOWEST COST ADDITIONS &CALCULATE CURRENT YEAR'S COSTS OPTIMIZED GENERATION PLANNING lOGP) RESULTANT OPTIMUM EXPANSION PATTERN ---{O~.•..::J. &DOC UM I:NT AT ION 0 F N EAR ...OPT 1M UM P LAN S .. CALCULATE OPERATING &INVESTMENT COSTS USING "LOOK-AHEAD" I I EXISTING UNITS & ALLOWABLE TECHNOLOGIES ............-----~------~------------..." HOURL Y BASED PEAKS &ENERGIES I LOAD ______....F O_R_E_C_A_S_T................ I-;." ALASKA POWER AUTHORITY SUStTNA HYDROELECTRIC PROJECT UPDATE OPTIMIZED GENERATJONPLANNING (OGP) PROGRAM INFORMATIONFLQVVS SE·PTEMBER1983 i EVALUATE ALL CHOICES WITH ·LOOK~AHEAD· ~.•'<1....~: i·.\ .1···.··'.··I:I,1' .$1 11 I I I I I ;1 I I...~~~ I·' .i\'~ 11 I 1·1 j 1 I I .j v:.·.>l-••> .-....,;.: •1';:G'\-~'.Ii '"G'~~..'\• •....~.\~'r'"",(~,-t l • ,~ir'...••• POOL TOTAL COMBUSTION COMBINED TOTAL (8)COMBUSTION TOTAL (8)COMBUSTION COMBINED TOTAL (a)YR PEAK ENERGY COAL TURBINE CYCLE CAPABILITY COAL TURBINE CAPABILITY COAL TURBINE CYCLE HYDRO CAPABILITY1MWf----(MWflGWh)(MW)(MW)(MW)~MW)(MW)(MW)(MW)(MW)(MW)(MW)(MW) .~ m X ::I: OJ -l 0'1en r,'•.4!i.'•........".".~.....~!. 1411 1495 1424 1504 1522 1496 1496 1579 1579 1605 1605 1605 1821 1821 182l 182l 1821 182l 1816 2099 2015 2015 2002. 20e6 2086 2086 2170 2110 ~~~~"-,..·",;"",,-~·_-,-"""":'--;_-:::::J~~,·;;',,..j";~~";_';~:;;(~':~~C:':':" 195 f!U#t\S!!1 237 237 CHAKACHAMNA ~. 84 84 84 84 84 84 168 84 168 252 84 l!S'!J! 200 400 ~--,;; 1295 1295 1308 1304 1322 1296 1380 1379 1.319 1405 1405 1489 1468 1669 1669 1669 1669 1669 1724 1714 1714 19M 1817 1817 190i 1901 1901 2101 }.,.4!f.l '-~lr'-"""__"""; COAL ONLY 84 84 84 84 84 168 ... .c:...:~.~ 400 :~~]' 200 200 168 200 84 168 84 200 ~j;J&~ EXPANSiON PLAN YEARLY Mw ADDITIONS OCR MEAN LOAD FORECAST NON-SUSiTNA ALTERNATIVES 1369 ;369 1,382 1378 1396 1310 1454 1453 1453 1419 1419 1563 1542 1742 1742 1742 1142 1742 1797 1820 1820 1820 1891 1891 2001 2007 2007 '2091 ~lC:::S} ~t::=,~·-_~_:~) 474 84 84 84 84 84 OPnMLMNON-SUS ITNA 84 M 168 168 84 \t~,\ ~~-""--"~ ~·kJ..~S;:"C._..~ 200 200 200 200 ~L~'L_J~-tt""~A'~_~',.,', (a)IncludosexlsfJnggeneratlon pl~nt Jess retirement. PSL*! _.,.,',.~-,;,.... (J Of, I 93 867 4167 94 882 4237 95 696 4306 96 913 4367 97 929 4467 98 946 4548 99 963 4629 0 979 4709 1 1001 4813 2 1022 4916 3 1043 5019 4 1064 5122. I 5 1086 5225 J 6 1115 5369 1 1145 5513 8 1175 5657 9 1205 5801 10 1234 5954 11 1263 6085 12 1292 6229 13 1323 6376 14 1354 6526 15 B:;8 6680 16 1418 6831 17 1451 6999 18 1485 1164 19 1520 7333 20 1555 7505 ~ lJ o I o I I ."~~!I -{I "i ,,*9 _,'::·~:~,);:h':'''I:.;.''9'.!i.);::;'i}>::''-.\liJ::f'i.>;'(/_:..~:-:.:'''-'F ~"_,'.~:,."'C.'"\.,.........,'j.;",,,::I!'i''lUid''''''X::::!?I;'''''''F<Iit>'''~''''~>_'... EXHIBIT 5.1 ..,--'--....."..,..,~'". ~.....J o j EXPANSION PLAN YEARLY MW ADDITIONS DOR ~~LOAD FORECAST SUSITNAALTEP~ATlVE o WATANA 2185 +DEVIL CANYONBASELOADING POOL TOTAL COMBUSTION COMBINED TOTAL Ca)YR PEAK ENERGY TURBINE CYCLE SUSITNA CAPABILITY(MW)(GWh)(Mv)(MW)n°!W)(MW) 93 867 4167 539 lh3394882423714329589643061362969134387841358979294467129298946454884135099963462913500979470913491100148138414332102249168413753104350198414594106451221459510865225143861115536963220707114555132070811755657207091205580120701012345945~O7011126360851925121292622938178513132363761785141354652617851513856680177216141868378417721714516999~4 18561814857164841856191520733318562015557505841940 (a)InclUdes existing generation plant less retirements. I m- e lJ m ~l }l ,,). ...........f [ ,,-I: ?I :.t! f1i [ .,'1 ,'.:-.:' ['" ".\, .:0 f':[1 l~'· •I:~'t t,} i £'~'t: "~'",:-"", ft,t.i I 'f]l I Capacity-MW Coal CT CCCT Hydro Susitna Chakachamna Total 2020 Reliability Peak Demand :%Reserve LOLP -D!Y Total Economic Cost 1993 $!MWh 2010 $!MWh 2020 $MWh Million Dollars 2020 Cost Cum 2020 P.w. Cum 2050 P.w. m X:r:-OJ--i 0'1en rna'-L'Wcti~,,",,,0',-'.,.,: LYX9--------- Watana 2185 eii.:;:Wtt:l ,>....-,,_.·,_'.-..-,.i·~.·._"-__~;•".«.-..~_........._~,~,_ \~!3ti LUE3 .~\~#..,!i!l'->,•.~•.) LNN5 C"-''"4_,:.....:.J,~',...-__~:__.:.J Gas Only LUF5 J '~:,._1,".-.'""';'"""_.,.~,~It''''-""",.-,,;cJ Year 2020 Railbelt System Generation Mix DORMean Load Forecast LUNl 800 0 1200 600 0 672 756 756 756 588 474 1185 0 474 0 143 143 143 143 143 0 0 0 0 1209 0 0 0 195 0--__l ,--------.- 2089 2084 2099 2168 1940 1555 1555 I 1555 1555 1555 34.5'34.1 35.1 39.5 24.8 0.082 0.183 0.053 0.160 0.036- 30.84 30.84 38.34 37072 49.15 46.78 47082 46.89 48.60 45.25 50.33 56.02 50.98 51.83 40.55 377.7 420.4 382.6 38900 I 304.3 2844 2929 3077 3128 3142 4890 5446 5070 5227 4744 Optimum Gas/Coal I ..,...--+-,NON~~USI!!!-•I --..b SUSI~A-Baae Loading I Coal Only I Chakachamna I ----~--,------~ ~l,~."'-:';~.;,1 .~,<"~~'-~7,J OGP ID ~'tl'-:'".:'-.:]l"_"A, -,';';'<"',,<,.-"f '" (-,:,j I I 2020 COAL-FIRED EXISTING &PLANNED HYDRO 2000 YEAR DOR MEAN LOAD FORECAST ___ 6 4 2 ALASKA POWER AUTHORITY SUSITNAHYDROELECTRIC PROJECT UPDATE THERMAL ALTERNATIVE -ENERGY DEMAND &DELIVERIES SEPTEMBER 198'3 EXHIBIT 5.9 I:.~8 C) ooo,.... zo-f-«c:wzw C) >-C) a:wzw '.,:<1.1.~J ! t ~ ~1~{'t If'j If!'. .~i fi ~<) In --.'~ Ifl~ I,"".)\~; v...J. [~~ '-1........., f:ItJ WATANAAND DEVIL CANYON 2185' WATANA ....".. 4 2 8 EXHIBIT'5.10 6 DOR MEAN LOAD FORECAST----, ~----......EXISTING AND PLANNED HYDROO-r-----------t------__-t-----t-----I 1980 2000 2020 YEAR o ALASKA POWER.AUTHORITY SUSITNAHYDROELECTRIC PROJECT UPDATE SUSITNA ALTERNATIVE-ENERGY DEMAND &DELIVERIES SEPTEMBER 1983 ~.dm.......!!!ItP_r ···,·t"..... i !.cII~I , ! j C) f 0 I 0 0,... I f z 0-t l- I «I a:w y ztw ~ ~>-{CJia:w r Zi·u.J, f· I't f, P It r I f; L m X ::I:-OJ--f 01. ...:.- ,) Lt79 l~atana 2185 SUSITNA -Rase Loading ~"-",.,J LOG9 Chaka'chamna "l.,..'<,·..;....,"·.·..c·~~~._...,..;·__; r~~_,>_.,.'~'J~. ;'-.....-....) LNM9 Coal Only ~-"'\f~.\1('I.....,"'''" -LRA9 0 1400 1200 0 756 672 84 588 1422 0 711 237 143 143 143 143 0 0 0 1223 0 0 195 0 232r--~ 2215 2333 2191 1724 1724 1724 1724 34.7 28.6 35.4 27.1 0.124 0.077 .0.082 0.085,- 35.48 40.18 38.64 48.53 72.90 55.06 52.23 40.69 91 ..01 61..72 59.05 43.83--- 756.5 513.0 516.6 364.3 4448 3931 3844 3373 8945 t 6758 6666 5325 Gas Only 1"1".-'''''1 ~.........,--';--.--- Year 2020 Ra:tlbelt System Generation Mix SHCA-NSD Lo~d Forecast 2437 1400 of 420 474 143 o o 1724 41.5 0 ..025 35.48 59.95 63.65 Gas/Coal LN61 ~~l~t J ~_..J 529.0 3878.1 6795.0 NON-SUSITNA I ·t-•----------- I . -.--I .._.··t ~r3'op'!".c '..;..~.'.'::.'_;.',.;__~..'..'.f' OGP ID Capaci t1 -MW Coal CX CCCT Hydro Susitna Chakachamna Total 2020 Reliability Peak Demand %Reserve LOLP ....D/Y Total Economic Cost 1993 $/MWh 2010 $!MWh 2020 SlMWh Million Dollars 2020 Cost Cum 2020P.l{. C'.1m 2050 P.w. I I t -to -t·I·I ~t·}~··~ t .(:)- t ..~;",j4e;, ;,~ t I :1 6.0 ECONOMIC . AND COST OF POWER AN,t\l YSES .{. I~,; I' II I I, ;1, I I..··,.··fL I 'I I I 1'1 I I J 6-1 6.0 ECONOMIC AND COST OF POWER ANALYSES The economic analysis compar~s the Non~Susitnaand Susitna system expansion programs using a life cycle approach based on the results of the study describ~d in Chapter 5.Threshold and sensitivity analyses of the key variables were also conducted.Using the same expansion programs,th~cost of power analyses determines the wholesale cost of Susitna power for various levels of state equity contribution.In addition,the affordability of the project is addressed by comparing estimated available funds for State capital projects wi th construction cash flow requirements of the Susitna Project. 6.1 INTRODUCTION 6.2 ECONOMIC CRITERIA AND PARAMETERS The economic analysis was performed using a life-cycle approach which is customary for studies of major capi tal intensive projects.For hydroelectric projects,the service life is typically 50 years.Since the Devil Canyon Project would be in operation around year 2002,the costs of Susi tna generation plans hav~been com.pared with the costs of Non-Susi tna a1 ternatives over a planning period extending to 2050. Since Susi tna power would come on line in 1993,the sys tem generation costs wer~assumed to be the same for all alternatives between now and 199.3.Hence,the economic analysis was conduct~d by comparing the costs of the alternative expansion progl:ams over the period 1993-2050. To fully utilize the total potential of the Susitnahydropower re- sources ,it was necessary to extend the electrical dem.and projections until 2020.This was done by extending the 2010 proj~c.tions obtained from the RED model ,using the ·av~rage annual growth rate of the period 2000...2010.Then,the Optimized Generation Planning (OGP)model deter- mined the total production costs of alternative plans on a year by year I) I' I; I: [~ I~ I I) ----~ I I 6--2 •W 11,'.1 basis,for the period 1993-2020.These costs include the annualized in- vestment costs of any generation and transmission facilities that are added during that period,total system fuel costs,and operation and maintenance costs.Thei::t>:;ts of facilities which are commOn to all alternatives have not been included in the economic analysis.For the period 2021-2050,it was assumed that the production costs of the final study year (2020)would simply recur for an addi tiona130 years,with the fuel costs adjusted to take into account real fuel price.escala- tion. Exhibit 6.1 summarizes the principal economic parameters that were used in the economic analysis.The economi.c life of each generating plant type used in the economic analysis is based on 20 years forcombl.1sti.on turbines,30 years for combined cycle and steam turbines,and 50 years for hydroelectric plants.Transmission lines have an economic life of 40y~ars" The economic analys.is was performed for the DOR Mean and ,SHCA-NSD scenarios.For each oil price forecast,electric load forecasts were developed and are presented in Chapter 2.The Susitna Project and Non- Susitna al ternatives are presented in Chapters 3 and 4,respectively. Chapter 5 presents the system expansion programs which form the basis :::t::e$:C::O:::t:na::t.~based on a 3.5 percent dbconnt rate, determines the ;,,;;_~i,e~~~~and benefi t-costratios.An internal rate of return analysis was performed,followed by a threshold determination of the oil price v."'hich would bri.ng the cumulative present worth of the Susitna alternatives equal to that of the thermal a1 ternative.A similar threshold analysis was done for the Watana construction cost estimate and real interest rate.Finally,a sensi tivi ty analysis was performed to analyze the effects of the availability of Cook Inlet gas and real escalation of fuel costs. I' I: I: I" I I .,' j ' I··.·.'~: '.f .•....,'.' ','..... .' I I~! I " .•'"1.• ,t I· '..··.•.· ...':', I I I I.·······~ ,~ I~; I I : " .....,1. ':, I I 1\ I: Discount rates are used to discount future costs to the present,recog- nizing cash flows occurring in different time periods of the planning horizon.A real rate of 3.5 percent was used as the base case discount rate for the period 1983-2050.Interest rates are applied,during the construction period,to the disbursement payments to compute the annual investment costs of each alternative. Based on present trends in construction costs,no real capital cost escalation was assumed fO;17either the hydroelectric or thermal plants. The costs directly related to the consumption of fuel oil for vehicles, construction eq~dpment,heating,on-site electric power generation, etc.were estimated at about 6 percent of the total construction costs. As shown on Exhibit 2.6,the price of oil is expected to remain below the 1983 price until 1991 for the SHCA-NSD Scenario,and until 2002 for the DOR Mean Scenario.As a result~the construction costs are not expec ted to chang.e due to fuel prices. Exhibit 6.1 gives the annual fixed carrying charges (interest,depre- ciation,and insurance)for each alternative.An annual insurance cost equal to 0.25 percent of the total investment cost was used for the thermal plants and the transmission lines.An annual insurance cost of 0.10 percent was used for the hydro plants. Studies on fuel availability and costs are.described in Chapter 4. Exhibits 4.2 and 4.3sumIIlarize the fuel costs which were used for each scenario.In brief,a 1983 estimated base price of $l.80/MMBtu was used for coal-fired generation,$2.47/MMBtu for gas-fired generation from Cook Inlet gas,and $6.23/MMBtu for oil-fired generation,all for fuel to be utilized for the year 1993 and thereafter.The price of coal is based on the mi.ne-mouth price of Nenana coal adjusted for transportation to Healy and estimates of production costs for a mine- mouth coal opet'ation at Beluga.The natural gas price is based on the 6 ....3 Table 6.1 1.03 1.28 Behefit! Cost Ratio Net Benefits 1,470 .1iI 4890 4744 6795 5325 2046 1602 2917 1952 SUMMARY OF LIFE CYCLE ANALYSIS 1983 Present Worth of System Cost -$million 1993-2021-1993- 2020 2050 2050 2844 3142 3878 3373 most recent contracts ehtered into by Enstar.The base prices were escala.ted by real fuel escalation rates to 1993 and from 1993 to 2050 as discussed in Chapter 4.The analysis has been performed.wi th Cate- gory I cost estimates for Susitna. The life cycle analysis is performed by comparing the cumulative present worths of the annualized investment and production costs for the period 1993-2050 between the Susi tna and Non-Susi tua al ternati'tTes. Table 6.1 summarit2S the life cycle analysis. 6.3 LIFE CYCLE ANALYSIS 6-4 Oil Price Forecast DOR Nean Non-Susitna Susitna SHCA-NSD Non-Susitna Susitna The net benefi t of the Susi tna al ternative is determined by taking the difference between its cumulative present 'Worth cost and that of the Non-Susitna expansion alternative.The least-cost thermal system, developed in Chapter 5,is used for this purpose.For each oil price Ii .1.,·........l~.••;.": 'I~ I I I I~"l/JIIItj, I•.·." ,,,,;1 11 '.. J.i. '.",' I' I' IS' I' I•..,;.'"~\ If I'..···.·"·.·>i; ,~ cast • forecast..,there is a different optimum thermal sys tem expansion pro- gram. 6-5 m d;(J Duri.ng the 1993 to 2020 study period under the DOR Mean,the 1983 pres- ent worth for the Susitna al ternative is $3,142 million.The annual production cost in 2020 is $304 million.The present worth of this annual cost,which varies only by fuel cost escalation for the period 2021 to 2050,is $1,602 million.The resulti.ng total present worth of the Susitna plan is $4,744 billion • The Non-Sus!tna plan has a 1983 present worth cost of $2,844 million for the 1993 to 2020 period with a 2020 annual cost of $378 million. The total long-term cost has a present worth of $4,890 million.There- fore,the net economic benefi·t of adopting the Susi tna plan is $146 million. For the SHCA-NSD forecast the net economic benef!t of adopting the Susitna alternative is $1,470 million.The July 1983 License Applica- tion estimated net economic benefi t of Sus:l tna at $1,827 million.The variation is due to reformulation of the thermal alternative to include gas-fired generation in the early years of the study period and a change in diSCOunt rates from 3.0 percent in the License Application to 3.5 percent in this update. Benefit-cost ratios,as shown in Table 6.1,are determined by taking the ratio of cumulative present Worths of the Susj.tna alternative and t11at of the least....cost thermal al ternative.The benefi t--cost ratios are 1.03 for the DOR Mean and 1.28 under the SHCA-NSD oil price fore- I! I•.-1., I: I • ···.1 ..1,\1 t '.0::~ I ..!.'~"I ~~: I I' I; 1\' I: •···i....../ I; 6.5 THRESHOLD DETERMINATION 6-6 1""""'., 6.5.1 Oil Prices o~ The internal rate of return of the Susitna Project is about 3.7 percent under the DORMean forecast and 5.4 percent under the SHCA-NSD fore- cast.The internalrate-of-return analysis provides a means to iden- tify the project that maximizes return on investment.'!his analysis is equivalent to a threshold determination of the discount rate. The internal rate-of-return for investing in Susitna is the discount rate at which the cumulative present worth of the Susitna alternative becomes equal to the optimum Non-Susitna expansion program.In this analysis,the optimized expansion plans,defined by the OGP model under a 3.5 percent discount rate,were kept the same.The new discount rate was used,as previously,to aggregate annual cash flows occurring dur- ing the period 1993-2050. World oil price greatly influences the economics of the Susitna Project"Therefore it is useful to identify the oil price at which point the cumulative present worth of the Susi tna Project is equal to that of the thermal al ternative,meaning that there is no longer any economic incentive to select one al ternative over the other.On in- spection of the net benefits,the threshold oil price is very near the DOR Mean oil price forecast. 6.4 INTERNAL RATE-OF-RETURN (INTEREST RATE THRESHOLD)ANALYSIS It is impo,;tant to recog~ize that the DORMean oil price forecast shows a price tl'ajectory that is not a single value,nor has a constant rClte of change.The critical price is,however,$27.45 per barrel (in 1983 dollars)estimated for 1999.This price has been 8:ssumed to ~scalate at 1.5 percent .for the years beYOnd 1999.The Sus'!tna Pro,lect would I,·.·.' (,~ I~ I~ I~ I I !' I I 11 !. I I I I 1,1 I economically break ever..(i.e.earn a real return of 3.5 percent)if the oil price would be slightly lowe.r than the forecasted level of $27.45 per barrel in 1999,and escalate at a 1.5 percent real rate after 1999. I' 11 I'" 'i, I' I··.·..····.".·. .' I,; W,'.•.. ...,~ I I I I, I. I I ,.fl··'.~.....~ I 1 6.5.2 Capital Cost Estimate A threshold determination has been made for the capi tal cost estimate of the Watana Project.In such a determination,the threshold JX)intis the change in the estimated cost of the initial Wat!:lTla Development that would cause the break-even point to be re~~~c;;~.The results indicate that 5 and 50 percent increases in the estimated cost of the Watana Development would be required before the threshold point is reached for the DOR Mean and SHCA-NSD fbrecasts,respectively. 6.5.3 Real Interest Rate The real (inflation free)intereat rate,used to calculate interest during conatructioll,is a variable separate from the real discount rate which is used to discount net benefi ts over the li.fe of a project.The real interest rates would have to be 4.9 and 15.5 percent for the DOR Mean and SHCA-NSD forecasts,respectively,in order for the threshold point to be reached. 6.6 SENSITIVITY ANALYSIS 6.6.1 Availability of Cook Inlet Gas In the basic analysi.s ,it is assumed that Cook Inlet gas proven reserve and economically recovel:'llble undiscove.red gas would be depleted by 2007.Ei ther new gas would have to be discovered in the Cook In.let area,probably at a much higher price,or North Slope gas would have to be transported to the Railbelt.The outcQme or the two Pbssibilities 6-7 I -- DORMean 5,173 o Base C~)Available until 2007,then at $4.OO/liMB .:u Available until 2007,then at $7.00/MMBtu Table 6.2 6-8 SENSITIVITY ANALYSIS OF COOK INLET GAS 2050 CUMULATIVE PRESENTWORTlI (1983 $million) depends on worl~.oil prices.If world oil prices increase sufficiently to allow the rievelopment of either ANGTS or TAGS,North Slope natural gas could be made available to the Railbelt market at the estim.ated price of $4.00 per MMBtu (Cha.pter 4)..HOwe'Ter if the world oil prices sbould remain at or below thfl present day price of $29 per barrel,it ~ould be unlikely that either ANGTS or TAGS would go forward.In the event that additional gas cannot be obtained from Cook Inlet,a much higher cost for natural gas from North Slope would then occur.In Chapter 4,the estimated cost of natural gas from the North Slope via a small pipeline has been estimated in the range of $7.00 to $9.90 per mmtu.A sensitivity analysis has therefore been performed for gas obtainable at $7.00 per M!{Etu from 2007.The results are summarized in Table 6.2.The $7.00 perMMBtu natural gas price would increase the present worth of the Non-SuSitna alternative by about $283 million. 6.6.2 Real Escalation of Fuel Costs The present worth of the system costs includes all costs of fuel and operation and maintenance of all generating uti,its.In addition,the costs include the investm.ent costs of any plants and t:ransmission fa- cili ties added dqr:tng the 199.3,to:1020 period.The long-term system costs (2021-2050)~r$estim.ated from the 2020 annual costs,with adjustment fol:'real escalation of fuel costs,for the 30-year period. I I' I, 'I".:'..' I: I, I·, ..'t 'I····.,t., I' j 1:\ .....'>' I; I 1"- ~, I I, I I I• o Power Authority guideline in conducting an economic analysis calls for the escalation of fuel oil over a given planning horizon,wi th the price of fuel oil then remaining constant for the remaining study period beyond the planning horizon.The real price oil escalation was 2.5 percent for the 1983 fiscal year,and the planning horizon is 20 years.The methodology used for the Susitna Project ha:S'been more sophisticated because of the magnitude of thel'roject -including two developments --in relation to the size of the system.This requires the projection of oil prices over a long period of time..For this reason, and because specific oil prices and scenarios have been projected over the long-term,fuel cost escalation over the entire study period has been considered. 6-9 The Susitna,l'rojec t would supply about 80percel1t of the Rail bel t area electrici ty requirements initially and through the year 2020 wi th both Watana and Devil Canyon constructed.Therefore,long term forecasts of fuel prices and escalation rates are necessary to determine project economics.Several oil price forecasts were reviewed and a special analysis of long-term oil prices was prepared during the revision of the License Application to support the estimation of the long--term system costs (2021-2050). A sensitivity analYsis ~s conducted to compare the net benefits of the Susitna alternative mth 'tne Non-Sus!tna a1 ternat!ve when no allowance was provided for real escalation of fuel costs.The results are sum- marized:1.n 'rable6 •.3. I I I I,··.·'·.,J I, I I I I. III, ,I··:,1 'Ij [" I J; .......~ Table 6.3 1353 6603 5250 o 2725 1877 6 795 ~if'.,, 5325 "1470 6-10 1•---'''''0", ','~ 2046 4890 .41~1945 4789 1602 4744 146 1597 4739 50 2917 1952 Present Worth of System Costs (1983 -$million) --With Fuel Escalation Without Fuel EscalatiOn- 2021-1993-Net 2021...1993...Net 2050 2050 Benefit 2050 ?050 Benefit SENSITIVITY ANALYSIS OF REAL ESCALATION OF FUEL COSTS BEYOND 2020 1993- 2020 Oil Price Forecast Non-Susitna 3878 Susitna 3373 SHCA-NSD 6.7 COST OF POWER ANALYSIS The financial condition of the State is the single most important factor in determining the financial feasibility and cost of power from the Susitna Project.Petroleum revenues provide about 90 pet'cent of the State income and directly affect the capability of the State to make an equity contribution.The issue has been examined by the Office of Management and Budget and there appears to be a large difference in net revenues available for capital projects under various fiscal scenarios. DaR Mean Non-Susitna 2844 Susitna 3142 The follovTing discussion provides a preliminary analysis of the financ- ing needs and options for the construction of the Susitna Project. Several important and interrelated issues must be resolved before a suitable financing plan can be finalized.These are: r r ·1,.··· .\ I' I I I I I I :1 6-11 6.8 PROJECT FUNDING Financing terms;including inflation rates and interest rates)and tax exempt status of the bonds Size of the State etiuity contribution . Target cost of power o o o The 100 percent debt approach is designed to reflect the wholesale cost of power for purposes of broad comparison with al ternative power options. Two financing approaches were considered in project funding;1)one hund red percent revenue bond financing and 2)up front Sta te appropria"~ tion for part of the cost)wi th the remainiTlg financing requirements met by revenue bond issues. o Affordability of the Susitna Project In performing this study)R.W.Beck &Associates)Inc.developed the relative annual costs of Wholesale power under a1 ternative ranges of debt/egui tycombinations,based on cash flow foreca.sts provided by Harza-Ebasco.Their analysis is documented in a separate report entitled "Susitna Financial Analysis",dated September 23,1983 and subsequently revised November 9)1983. 6.8.1 State Equity Contributions State equi ty contributions and revenue bond s combine to provide the needed fund s to build the Wa tana Development.A range of State equi ty contributions has been.studied..The State equity contributions will oover the construction.disbursements for the first five to six years, with revenue bonds being used to complete construction. I 'I: I ,I, I I , •••••• I I Ii ,,~ I r I I I': ,I ::I.·····.·".··.~.·· •1. I. ··.··.·"-" "••'I',..~. I r I I~. I I I J I I I I: I In the early stages of project development (1986-1988)the Watana Dam would not actually be under construction and only access and site prep- Etration would be i11 progress..To ensure that revenue bond financing is available in the final stages of construction (-1989-1993),earlier State egui ty contributions should be at appropriate levels to provide security to potential investorS)and reduce the total amount of borrow- ing.Reduced borrowing would also lower the price of Watana power in the early years of operation and enhance the competitive position of Susi tna versus thermal power sources,which have much lower capi tal costs,though higher and escalating operating (including fuel}costs. 6 ..8.2 Revenue Bonds The financial projections which follow have been based upon Lhe assump- tion of a 10 percent rate of interest for bonds.The 10ng-terminf1a- tion rate assumed at this time is 6 ..5 percent. In this analysi.s:t the bonds are issued SO they fund their own inter'est costs for the first 24 months the bonds are outstanding.During the construction period,interest expense of previously issued bonds,to the extent not capi talized,is paid from proceeds of subsequent bond issues •Debt service for each revenue bond issued is structured so interest-only payments are made for the first 24-monthperiod subse'" quent to the commercial operation date of Wata.na.After the ln1.tia1 24-month period,debt service is leve1ized (including principal pay_ ment)ovel,'a 30-year period.Commencing with commercial o)?eration~ debt service expense less L'lvestment earnings on various revenue funds is paid by rf!venues from power sales. The revenue bonds areassu11led to have the following characteristics: ,.. 6-12 na. Financing expense equal to three percent of principal amount. Reserve and contingency fund is equal to one years capital renewal requirements. Debt service reserve account is equal to one years levelized 30-year debt service. Working capi tal fund is equal to 15 percent of one years opera.ti,on cost plus 10 percent of one years revenue require ments. 2. 2. 6-13 '1'--.,. -.". The reserve and contingency fund and the working capital fund are fully funded regardless of the level of St<;lte equi ty contributions to Wata- 1.:Haximum bond iss'ue of $400,000 ,000. The reserve,contingency and working capital funds and debt service reserve account are established according to the following criteria: 3.Coupon,long-and short-term interest rates are all equal~ 6 .9 COST OF POWER Railbelt costs of electricity are estimated to determine what the wholesale.cost of power will be for various levels of State equity contribution.The costs are shown in nom.inal dollars unless otherwise indicated and are based On a 6.5 percent annual inflation rate. The cost of power with the thermal alternatives was computed from OGP output summaries,with an investment cost adjustment for capital re-- newals.The wholesale costs include fuel costs for new and existing generating units,capi tal costs for ne~T generating units,capi tal costs for new transmission facilities required,and operation and maintenance expenses on new and existing faciliti€!s.The costs do not include fixed costs for existing generation,transmission and distribution facil.itles,and overhead expenses associated with administration, I I I J I I I~. I I '.'.' • I 7.6 8.4 Coal Gas/Coal 11.6 10.2 1 L DOR Mean SHCA-NSD The first year cost is dependent on the thermal expansion plan and future oil prices.The initial cost of power for the combined cycle plant in the gas/coal plan is much lower because of its lower invest- mentcosts when compared with the coal-fired powerplant;however,the long-term system costs do not vary significantly. Depending on whether a coa.l-fired plant or a combined-cycle plant is bUilt in 1993,the first year cost of power would be much different,as shown on Exhibit 6.2 for DOR Mean caSe.The upper curve represents the caSe where a coal-fired plant would be bUilt in 1993 while the lower curve would have the natural-gas combined cycle plant constructed in 1993.Table 6.4 summarizes the first-year wholesale cost of power under the DORMean and SHCA-NSD caSes. FIRST-YEAR WHOLESALE COST OF POWER UNDER NON-SUSITNAEXPANSIONPLANS (Nominal cents/kWh) Table 6.4 6-14 customer service,indirect engineering and labor or other utility opera tions. The expansion planning analyses in the 1982 Feasibility Study and the FERC License revision in July 1983 provided coal expansion programs wi th first year costs of 14.7 and 13.6 cents/kWh,respectively..These cOsts are higher than the estimated costs of the present coal plans and substantial1.y highexo than the costs of the plans with a mix of natural gas-fired combined cycle and coal-fired steam plants.The differences are due to xoeductionsin the current estimates of construction and fuel I r I I I I I I I I I I I I "I ••.~ .\ r I '1,.••. .,~. ! I I I I I I I I .11 ~.., I costs and a change in inflation rateassnmptions from 7 ..0 percent in the feasibi.li ty and license studies to 6.5 percent in this update.The gaslcoal plans have resul ted from a reformula.tion of the previous ther- mal al ternatives to include gasr-fired generation in the early years of the study period • For the Susitna alternative t the cost of power was also estimated starting wi th the OGP output.The cost of power estimates were made for a range of State equi ty contributions.State equi ty contributions are used to cover expenditures in early years of construction ari revenue bopds are used to complete funding requirements.The equi ty and bonding requirements were determined for the Susitna portion of the expansion plan investment costs wi th adjustments for capital renewals. The terms for ~ssuance of the revenue bond s have been described in an earlier section..The remaining investment costs,fuel costs,and operation a,ndmaintenance costs are taken from the OGP computer out- put. Exhibits 6.3 and 6.4 show the relationship between State equity contri- bution and the 1993 wholesale cost of power for the DOR Mean and SHCA- NSD cases.Also shown are the coal and gas!coal thermal wholesale cost of power.The exhibits demonstrate that the State equi ty contribution required to match the coal and gas!coal costs of power vari~s consid- erably. State equity contribution proVides the means to bring the 1993 whole- sale cost of Susitna power to the level of the alternative thermal system cost.A determination of the amount of State equity contribu- tion that will equa te the wholesale cost of Susi tna power wi th the first year cost of the al ternative thermal expansion programs was detei.:'1D.ined.Table 6.5 summarizes the funding requirements to equa te the wholesale cost of power under t.he DOR Mean and SHCA-NSD cases. 6-15 J -->;,,~ 5 ..69 5.79 3.67 3.73 2 ..41 2.79 1 ..40 1.62 Gas!Coal Thermal 2 ..27 2...11 3 ..28 3 ..00 State Revenue Equity Bonds Total 6.28 6.10 4.07 3 ..96 __f~ 4.32 3.80 2 ..62 2.29 Revenue Bonds Total Coal Thermal 1 ..96 2.30 1.45 1.67 State Equity NOMINAL $ DOR Mean SHCA-NSD 1983 $ DaR Mean SHCA-NSD Table 6 ..5 6-16 FUNDING REQUIREMENTS TO EQUATE FIRST YEAR WHOLESALE COST OF POWER TO THE NON-SUSITNA ALTERNATIVE (Nominal $Billion) Table 6.5 shows that State equity requirements are sensitive to the thermal alternatives.The first year cost of power of the gas!coal expansion plan is much lower than the coal plan (Table 6.4).The.re- fore.,the Sta.te equi ty necessary to equate first year costs of the Susitna expa.nsion program to the first year costs of the gas!coal al- ternative is higher than for the coal plan.The natural gas-fired plan is sensitive to changes in oil price and depletion of natural gas re- serves •Increased oil prices or gas supply contraints could increase the ~"sts of the gas!coal plan and reduce State equity required to equate first year costs of power. In addition,required State equity as a percentage of total funding is 60 percent under the ga.s!coal plan and 30 percent under coal plan for the DORMean case.Under the SHCA-NSD case State equity as a percent of total funding is 52 and 38 percent for the gas!coal and coal plans, respectively. Long-term debt requirements would be substantially reduced by the amounts of State equity contribution required,thereby,providing se- curity to potential investors in the revenue bonds. f J f f I; ...~ f , r .~ ~ r, I! f 1 6.10 INTEREST RATE SENSITIVITY Change in oil price from the DOR Mean to SHCA-NSD forecast would require additional equity under the coal plan and reduced equity requirements under gas/coal planG The funding requirements in 1983 dollars are also shown in Table 6.5 • In the 1982 Feasibility Study and the FERC License revision the State equi ty contribution required to equate first year costs of power wi th the recommended coal expansion plans was $1.9 billion.This level of equi ty contribution is about in the middle of the range of equity con- tributions shown in Table 6.5 for the thermal alternativesc 6 ...17 Exhibit 6.5 shows the cost of power over time for the DORMean oil price sCQnario.Under the Non-Susi tna gas!coal case,the cost of power will rise over time due to inflation and real cost increases in fuel. Under the Susitna case,the cost ot'power will be much less susceptible to inflationary cost increases.Consequently in later years,the wholesale cost of power from the Susitna plan could be less than half of the best thermal option.Exhib.it 6.6 tab.ulates the annual costs and the annual wholesale cost of power for the SusitnaProject under the DOR Mean case for both the $3,280 million state equity contribution and 100 percent debt service analyses. The interest rates an revenue bonds mIl greatly influence the cost of power.Exhioit 6 ..7 shows the range of power cost for different inter- est rates,assuming a State equity contribution of $3,280 million for the WatanaProject.Interest rates from eight percent and twelve per- cent have been used to illustrate the effect on cost of power when compared against the base case of ten percent.First year (1993)power costs would be 6.4,7.6,and 8.6 cents per kWh With interest rates at eight,ten and twelve percent,respe.ctivelY.SInce nominal interest contains two principal components ,with the first component reflecting I'..'.1fC., I I I I I I If I i ,,",',' II tion. 6.11.1 Revenue Sources c.\ 6··18 '1-·---"--·~,:) Oil and Gas:Included in the oil and gas revenues are forecasts------......... of income tax fro!'llpetroleum corporations,severance taxes from oil a.nd gas production a.rtd conservation,oil and gas property The SAGE Model is used by the Office of Management and Budget as a tool for fiscal planning.The fiscal module of the model employs a revenue forecast and various e:Kpenditure assumptions to assess ","bethel,"revenue shortfalls or surpluses can be expected,the effect of the State s spending limit,and other fiscal issues.AI though the SAGE Model typi- cally uses the 17--year revenue forecast provided by the Alaska Depart- ment of Revenue,other revenue forecasts can also be used. real interest on mone;l,and the second component reflecting inflation- ary expectations J interest rates vary substantially from time to time depending on economic conditions.The State,by"making its equi ty contribution up front,can provide a Significant period of time during which the revenue bonds can be sold at favora.ble rates. 6.11 SAGE MODEL The SAGE sources and uses of State funds report provides three types of information:1)annual revenue sources,2)annual revenue uses,and 3) expenditure assumptions.Revenue sources j;clude only general fund unrestricted revenues,meaning that restric ted federal dollars are e:Kcluded,as are the constitutionally-required Permanent Fund contribu- tions.Data on revenue SOurces and uses are presented in both nominal and consta.nt terms.FollOWing is a.breakdown of each type of informa- A description of each type of r2venue SOUrce follows: J .1.1 .l I I I I I I I .11.'l .~ I I 'I taxes,and State resource revenues from bonus sales,rents,and royalties. Other:'Ihis includes all general fund taxes and fees that are collected by the State which are not included under "Oil and 6...,19 Investment:General fund investment ea.rnings are included in this line item .. General Fund Fot'ward:This category is unappropriated funds which have been brought forward from the previous fiscal year. Gas." FF to GF:This includes Permanent Fund income Which is deposited in the general fund.A statutory change would be required.Cur- rently,AS 31.i3.i45 requires that income be used for inflation proofing the Permanent Fund and that the balance go to an undis- tributed income account of the Permanent Fund. Total:This is the total 6f all the reVenue sources for a speci- fic.fiscal year • Operating budget Cap'!ta.lbudget Logns programs Supplementals!new legislation 6.11 ..2 Revenue Uses Revenue uSes include.ac tual appropriat.ions for the current fiscal year and forecast:appropriations for future fiscal years.The revenue uses (or expenditures)for the Sage Model include: I.t ..: I I I I I .1...,·',·.··.'1\! I 6 ....20 o Debt service General fund appropriations to the Permanent Fund Special Capital Special Capital represents a hypothetical rather than actual r~venue use.Its purpose is to provide an account ror determining the amoUnt of State rev-enue that could be set aside for major pl'ojects,such as the proposed Susitna Project,given certain fiscal condltions.These fiscal conditions can be varied. For the Susitna Update,the SAGE Model has been programmed to determine the difference between the Department of Revenue 50th percentile revenue forecast and an adjusted 30th percentile revenue forecast. These revenues are then allocated to Special Capi tal.If the.30th percentile forecast is greater than other revenue uses,the difference is also added to Special Capi tal.If the 30th percentile forecast has insuffi.cient revenues for all other revenue uses,these revenue uses are proportionately redtlced.In essence,the 30th percentile revenue forecast becomes a ceiling for all other revenue uses.~fhe purpose of thi.s programming is to explore the possi.bility of saviTlg revenue for Susitna by setting aside the difference between the 30th percentile forecast and t.he more likely 50th percentile forecast. Output data for the SAGl5 Model includes annual growth rates for the operating and capital bUdgets as well as total appropriations.These growth rates illustrate when the 30th percentile cei.ling becomes effec- tive and to what degree it changes each growth rate. 1l he 30th percentile revenue forecast used by the SAGE Model is not identical to the Department of Revenue 30th percentile fOrecast.It represents the spread that is expected to occur between the 50th per- centile forecast (which is assumed to be the most likely long-range revenue estimate)and the 30th percentile forecast in each year.This I I I I I I I I I I 6-21 Percentage Adjustment to Real Operating Budget Base+2 °,'2-- 6.00 6.00 6 ..00 9.00 9,,00 9.00 8.54 8.54 8.54 -14.76 -13.36 -11.98 -17.40 -17.40 -17.40-1.22 -1.21 -1 .20 SAGE MODE!.ASSIJMPTIONS UNDER ALTERNATIVE OPERATING BUDGE T SCENARIOS Variable Average growth rate for the Anchorage Consumer Price Index (CPl) Average rate of return on the Permanent Fund Ave.rage rate of return on the general fund balance Average growth/decline in loan programs Actual debt service Average population growth rates Table 6.6 6.11.3 Assumptions Under Alternative Operating Budget Scenarios The SAGE Model Was run under three different fiscal scenarios to test the sensitivity of available capital for Susitna to Spending levels in the operat:1.ngbudget.The three operating budget growth levels tested are a +2,°and -2 percent real annual rate of growth from a fiscal year 1985 base of $1 ,925 million.Other assumptions used to determine the alternative revenue uses and Special capi tal available for Susitna are shown in Table 6.6. has the effect of reducing the difference between the 30th and 50th percentile forecasts as it appears in the Department of Revenue published reports. The assumptions used for each SAGE run are presented in the output summary data tables in two ways:1)the value used for each assumption I I I I I I I ~~ I .1··'....'··· ••••• I I· i J I I I I ,~d '..~ I I . 1. ·'..,u, ~r'I I I I I I I I and 2)how these assumptioI.tsaffect the growth rates for the operatin.g and capi tal budgets and supplem.ental appropriations.In the case of the Susitna Update,the assumptions are consistent wi th those being u8e1 by the Office of Management and Budget for current fiscal plan- ning. 6.11.4 Results of SAGE MOdel Analysis Xhe Sage model was used to provide some insight into the question of afford ability to the Sta.te of Alaska of the level of equi ty contribu- tions't Table 6.7 shows yearly (1985 through 1998)estimates of capital available for Susitna taken from Sage Model output. The capital estimates indicated that in early years there are consid- erable amoun.ts of capital available under all three operating budget growth assumptions wi th greater amounts of capi tal available under the o and -2 percent real growth rate assumptions.In later years the level of capi;"al estimates reduces substantially due to the downward trend in current long-term revenue forecasts.Also,the OMB has indi- cated that in later years the ca?!tal estimates would in all probabili- ty be used to support regular capi tal and operating budget e~pendi- tures • 6-22 ---...-"1. I···.···.. ~ \ I 11 111 I I I I I I-.....,"l"K II .A Ta.ble 6.7 SPECIAL CAPITAL AVAILABLE FOR SUSITNA PROJECT ($Million -Nominal) Percentage Adjustment to Real Operating Budget Base Year +2 0 -2 1985 722 722 722 1986 523 601 677 1987 531 656 776 1988 262 439 607 1989 437 673 892 1990 333 635 911 1991 177 177 489 1992 168 168 273 1993 164 164 164 1994 161 161 161 1995 146 146 146 1996 134 134 134 1997 139 139 139 1998 136 136 136 Exhibit 6.8 shows a bar chmct of estimated Watana construction cash flow requirements and capi tal available for the Susi tna Project ~or the three operating budget growth scenarios"The Susitna expenditures are in nominal dollars,and real escalation and interest during construc- tion are not included.The charts shoW'that in the early years>annual Watana construction expenditures are about $400 million and increase to a mai{imum of about $1,000 million in 1991 and trend down to 1993 when the construction is completed and the project is on line.The esti- mates of ca.p!tal availability generally have a trend that is in reverse to the construction cash flo"W r-.::quirements. To ensure that revenue bond financing is available,the costs of power studies have assumed that State capital contribution will cover the construct.....:>nexpenditures in the early yea.rs of construction.In addi- tion,the amount of Sta.te capital contribution that equa tes the first 6-23 ~~'ii'"jll t\, ltit',..~~.:.'.,;i It".. I'~ revenuehonds. o 6-24 ',;: _.,I1 ..i; ''''~J ",'i,~:~)" year wholesale cost of power of the Susi tna and DOR Mean gasl coal alternatives is $3,280 million.This is the maximum State equi ty con- tr ~:.,.ution.Under the coal e15:pansion plan the State equi ty contribution requirements 'Would be much lower..The accumulation of cons true tion expenditures in the first four years of construction (1986 through 1990)plus expenditures of about $525 million in 1991 equals the $3,280 million State capital contribution,as show on Exhibit 6.8.The remaining construction expenditures (1991 through 1993)would be met by Inspection of Exhibit 6.8 indicates that,under the 2 percent operating budget growth rate scenario,available special capital would fall short of expenditures required in 1988 through 1991.With real growth in the operating budget of 0 and -2 percent,construction expenditures are met or exceeded by estimates of available capi tal except in the years 1990 and 1991.If surpluses in earlier years were reserved,the construc- tion expenditures could be met under the operating budget growth pro- jections of 0 and ...2 percent.However,if surpluses in earlier years 'Were reserved these construction expenditures eould be met. The Susi tna ptJwer cost.should be set at a level to assure adequate coverage of the debt service,"work:tng capi tal.,reserve,and operating and maintenance costs.It should b~priced to ensure the markGtahility of Susitna energy once the project is built..i,[he rate level and pric- ing otructu-re should be;designed to motivate the utilities to put'chase the maximum amount of energy.If the.incremental rates are se t too high,it.may cause the utilitie~to take only the minimum unde~a take- or~pay c,ontract arrangPUlettt.Therefore the rate structure should be set to providesorne flexibility to promote l1.ia't{imum use.If necessary, small s'-2bsidies might .even be ~ntroduced for a few years .. 6.12 SUMMARY I n~".'1.• '.''J I' I I I I ;·1··.·.···. '..~. \ 1'.'..-.: :\ 6-25 In addition to the above lssues,other financing options could also influence project viability.Some interests have suggested alternative innOvative financing schemes that would improve,the financial market-- ability of the project.This subject is currently under study by others and should be explored further;ithaa not been treated in this update" Financing terms also hold a key to the size of the State egui ty con- tl:'ibutions and electricity rate level since interest rate is the domi- nant factGr in determining the magnitude of the debt service.Interest rate is in turn affected by the tax exempt status of the bonds. It had been previously postulated that future electricity power demand would have a major influelJ.ce on the economic and finan.cial viability of the SU$itna Project.While this still holds true,it appears that in the range of the forecasts between DOR Mean at'J SHCA--NSD it is not as crucia.l as previously thought. Different utilities have different needs for Susitna power..The Anchorage utilities are in need of capacity whereas the Fairbanks util- ities ai"e more concerned wi th obtaining sufficient energy to repla.ce oil generation. The affordabil;i.ty of the Susi~~na project is dependent on estimates of long-term revenue and spending levels and appropriate capital set aside to meet construction,expenditures in the early years of Susitna d evelo pment • .For this'prelimit'iary evaluation,the cost of power has been estimated in r~la~ion to State egui ty contt"ibut:tons.This is the first step towards thl;analy~ls of poWer marketing and setting electricity rates. Policy decisioIls are.needed on spec:t.fic issues prior to finalizing aI 11 I I I; I 6-26 financing plan.Rate design and marketing to electric utilities can then proceed. r" r f' r I, "I, I I f I,. .1· J'~. "~ j,~~ -'...;...~;l PRINCIPAL ECONOMIC PARAMETERS EXHIBIT 6.1 20 years 30 years 30 years 50 years 40 years r-,-' Combustion turbines: Combined cycle turbines: Steam turbines Hydroelectric Projects Transmission Lines All costs in January 1983 dollars Base year for present worth analysis:1983 Long-term planning horizon:1983 to 2020 Discouut Rate:3.5percent E~onomic Life of Projects: Inflation Rate:Opercent Annual Fixed Carrying Charges 1. 2. 3. 4. 5. 6. 7. "I',j ~I I JJ I 41 :1 I'...···i . I I I I · r '\r.~., '. I.,".~J :l 1. il 'I ~I : m X J: OJ -i 0). N -MIl 20202015 ~"'~I-r.-_,~(".~.~~1l ,!'MIll ;~.'".'• 2010 ~W!i:r-........'u~~ 2005 YEAR ~ 2000 r~t~ ALASKA POWER AUTI,ORITY SUSITNAHYDROELECTRIC PROJECT UPDATE WHOLESALE.COST OF POWER FOR NON-SUSITNA CASES SEPTEMBER 1983 1993 1995, I I , -DOR MEAN FORECAST J /A.r-. ".""""I'-/-"fill'"~ ~" r~..-----r-' "- ....,.,.A'./,~--...-----,..--:.--,~,/ .,."...-,,'-----1-----...---.,-.---.i----"'""----.-..---_..-......-.,...----..--, I I I I I J J I I ,I I ,I I I I I I I I I - ---WITHOUT SUSITNA:COAL, - - -...-WITHOUT SUSITNA:GAS/COAL s:::. ~.70oX .........-e-. 60• 0: 50W ~ 0 40a. fJ.. 0 30 t-en 200 0 W 10..J«en 0w -'0 J: .~ L_~t~·,~~~ r,:::: .;f/II I) I f ••~'\k1O"m2':!1'.£t,!.,Zt " 4 EXHIBIT 6.3 3 " 21 $BILLtON eQUITY CONTRIBUTION NOMINAL ~ ~r-WATANA 2185 / I 1<COAL :!Ii ~,~ GAS/COAL ~'...~ 2 o o 16 18 20 4 ('I) 0)en...14 2-a::w3:.s:.12 03: D.ll:: U-tl:o uJ 10 ....0- Cl)CIJ 01-uZ w w 8..Ju ~ W ..J 6o ::t ~ ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE 1993 WHOLESALE COST OF POWER VS.STATE EQUITY CONTRIBUTION DOR MEAN CASE SEPTEMBER 1983 J~ Ii -'~''"''''''~ II ·1'-~; I I I I I I " J - I ..!t.:~..~ ALASKA POWER AUTHORITY SUS ITN A HYDA 0 ElEC T RIC PR OJE C TU PO AT E 1993 WHOLESALE COST OF POWER VS.STATEEQUITY CONTRIBUTION SHCA~NSDCASE SEPTEMBER 1983 4 EXHIBIT 6.4 321 $BILLION EQUITY CONTRIBUTION NOMINAL "-"II ~-".."~" ,0-' ~ .~1 "~ ~, rWATANA 2185 / ~K COAL "- J GAS/COAL ~, ~ 2 o o 4 20 18 16 ::rw~or;12 O~o...Jl:: u..tt:Ow i-a.10 (1)(1) Ot- uZ ~"~8 <t (I)w5 6 ::t: ~" I I I I1>.'-.:..•...1 I I 1\ """ I II Ii '1 I,j ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE I WHOLESALE COST OF POWER.I (WATANA 2185) :'SEPTEMBER 1983 '---f I 1 · I I I I I·I·"1 I I I I II j I r ·1 I I t I III I m X:r: OJ--f 0) 01 ,. ~..~>~"-,.j' ....:--.....<....r""•..,:Lilli 2020 ,,/ ",'" -", ,~ ,,"- / ./" ~. 2015 [@!, $0 2010 ~dW·lW~.....:,.,,... I INTEREsrlAATE 10% V·...-- ,""....- ~..\ 2005 YEAR r--(~~ 2000 ~~c.f'1iIIiI!...........""'.;;..;:;,;;j! ._...-""'('l ,I._---+--..........-.---Y ....S2.21BILLION .................... 1993 1995 f~~"_"_'''-~l.".~~~J .......----WITHOUT SUSITNA:GAS!COAL ---WITH SUSITNA K.,-.-.".".-- --t-i I I I I //STATE EQUITY-- ;:CONTRIBUTION (1.983$) .JI'I __-"""" 70 .t ..I -r r j I DOR MEAN FORECAST WATANA2185 ~o - 50 - 40 - 30 - 20 - 10 - 0 j"IJJM ~~~~ r:. .~ .:Jt:......... ~ •a:w 3:oa. IJ..o t- CI'J .0o W -J<enw ...Jo J:;: D "'Om I»X~::z; -'&3o --h-l "'enm MIl.111).f.IB':'!8L~-;;::--_~..~..-,~->~~;~~i~~'{)~:~t~r"'$~l1I/lW\r..-,\~_,-':;,;",_'..;.'~L.;::,:,'._,4 ALASKA POWER AUTHORITY SUSITINA HYDROELECTRIC PROJECT UPDATE WHOLESALE COST OF POWER FOR WATANA 2185 DOR.MEAN (WITH $3.28 BILLION STATE EQ.UITY CONTRI.BUTION) SEPTEMBER 1983 $3.28 BilLION STATE EQUITY CONTRIBUTiON IN NOMINAL DOLLARS. ALL COSTS ~N NOMINAL DOLLARS. .~) ~ I 2185 ltVtl 3.280 Equity 1.101 COD 2006 M«.W.COSTS IN~:lLl~• =--==., t ;'rt'W£it --""==--==I "$•• TotllEnern Entr'lY'06'aGP Debt Strvh:e LESS:Debt StryiCf LESS:Filii)Cipital aGP Cost HI'J(IIf YHi'flMi)len Losns If(l.JES1l£NT SUSIlM COST WAlAMA EARMIt«iS l£'f'IL'S CANYlJC EMMItIJS Dfbt Service RtntlRl~FUt)OPtr.~"-in.TOTAL (e/kl.n---- 1m 4166.90 4041.89 724.00 724JlO 141.37 29.97 211.40 18.72 44.70 34.00 308.82 7.64 1994 4231.00 4109.89 124.00 724.00 241.37 19.97 111.40 19.94 4a.60 36.30 316.24 7.69 1m 4306.00 4116.82 724.00 12VJO 256.04 29.97 'Zl6.07 21.23 54.40 38.40 340.10 8.14 1996 ~381.O'J 4255.39 735.60 724.00 256.04 .19.97 237.67 2'5.54 60.90 41.00 365.U 8.~ 1m W6.~4332.89 m.w 124.00 2'56.04 29.97 237.67 27.20 67.00 40.80 373.47 8.62 1998 1,547.90 44l!.46 748.90 724.00 2'56.04 29.97 250.87 32.28 76.10 44.to 403.35 9.14 1m 4619.20 4490.32 748.00 724.00 256.04 19.97 2'50.87 ~.38 90.10 41.40 422.7S 9.41 2000 .ficJ9.00 4567.13 743.80 124.00 256.04 29.97 2'50.87 3&.61 10t.50 50.80 439.78 9.63 2001 4813.00 4b68.6t 164.80 72~.00 256.04 19.97 266.87 43.00 116.40 55.30 481.51 to.31 2002 49IS.90 4768.42 781.80 724.00 256.04 1!1.97 283.87 50.06 131.60 57.90 523.43 10.98 ::::!'I 2003 ~19.10 4&8.53 199.90 724.00 2'56.04 '19.91 301.97 57.~149.~63.10 572.92 11.17 2004 SI'Zl.OO 4%8.34 199.90 724.00 256.04 29.97 ~1.97 61.61 170.80 61.80 60'1.18 12.12 2005 5224.80 ~.06 799.90 724.00 2Sh.04 29.97 :301.97 65.62 194.40 11.90 633.89 12.51 2006 5369.00 5207.93 1564.10 1488.20 256.04 21.97 818.n 93.66 1027.08 87.31 0.00 74.00 1188.39 22.82 2007 5513.00 5347.61 1564.10 1488.20 2'56.04 1!1.97 832.17 93.66 1040.48 92.99 0.00 78.00 1212.21 22.67 ~5657.00 5481.1!i 1564.Ii)1488.20 256.04 29.97 882.76 93.66 1091.07 99.03 0.00 83.90 12?~.OO 23.22 2009 5001.00 5626.97 1564.to 1488.20 256.04 19.97 882.76 93.66 1091.07 105.47 0.00 89.30 1285.84 22.~ I ~I 2010 5;45.00 S7U.6S 1564.10 1488.20 256.04 21.97 882.76 93.66 1091.07 112.32 0.00 83.50 1286.89 22.32 2011 ~.OO 5'902.45 1564.10 1488.20 2'56.04 1!1.97 882.76 93.66 1091.07 119.62 0.00 83.00 1293.69 21.92 l 2012 6229.00 6042.13 15M.10 1400.20 256.04 t"1.97 QQ2.76 93.66 i091.07 U9.39 0.00 80.SO 1290.96 21.37 J 2013 631'6.00 6194.72 1564.10 1488.20 25b.{14 1!1.97 882.76 93.66 1091.07 135.68 b.OO ~.70 1312.4S 21.22 ,(>;2014 6526.00 6330.22 1564.10 1488.20 251h04 29.97 882.76 93.66 1091.01 144.50 16.70 n7ol)1344.57 21.24 2015 6600.00 11.479.60 1564.10 1400.20 2'56.04 1!1.'n 882.76 93.66 1091.07 153.89 16.70 96.60 13:58.26 20.96 2016 6837.10 6631.~1593.50 1400.20 2'56.04 29.?7 882.76 93.66 1120.47 174.20 35.10 103.90 1433.67 21.62 2017 6999.00 6139.03 1637.30 1488.10 a.04 19.97 882.76 93.66 1164.27 196.49 58.70 123.90 1533.26 22.S8 2O!8 7163.90 b948.98 1670.70 1400.20 256.04 29.97 882.76 93.66 1197.67 220.94 103.60 123.60 1645.81 23.68 2019 7333.•00 7113.01 1670.70 1488.20 256.04 29.97 00'1.76 93.66 1197.67 235.30 In.50 135.70 1746.17 24.55 2020 ~.9Q 7279.7'5 1723.SO 1488.20 256.04 29.97 882.76 93.66 12'"JO.47 263.85 194.60 153.10 1962.02 26.95 - -om l»Xcg::I: !'.)iii o ---f r.J0) CD !liltl1li'-~~--[fIli.~~:'...~ ~'""~~:.~~r~1:,,,....c ~,,,J_'Uet..';:;-,,"._.~"::"~~i/... r..~.~¥.:-.-'-~_...,..--i"........_,..:..,~l._-,.,.;.,;.,._<-:# rDIiB~_.~" ALL COSTS IN NOMINIAL DOLLARS. ALASKA POWER AUTHORITY SUSITNA HYDROElECTR:IC PROJECT UPDATE WHOL,ESALE ICOST OF POWE~FORWATANA2'185DOIR MEAN '.(WITH ONE HfUNDREDPERCENT REVENUE BOND FIN,ANCING)I SEPTEMBER 1983 '. ~l 'I 2185 level o E"uih-flO'%coo 2006 IM«JAL COSTS 1M "ILlll1f • ====::a=J i 1__=_:::c=::=:::::a_S:=3 ==2:asz:::L_........:1M ~=&S:t1::~~=r=r==-=======_1 .i •aa,a:est...•Totll Entl'n E""lY OGP OGP Dtbt Service lESS;DtbtService LESS;Finll Cl"U11 OGP Cost HI'I(Y4 -;:\I Year (QIt)l.u Losses INlJESnDT SUSIN\COST MATANA F.MMltGS WJiL'5 ·CNMM EMMltt1S Debt Service ReneRh Fuel OPer.'"-in.TOTM.lCIk\If)------- 1m 4166.90 4041.fW 724.00 724.00 799.83 90.69 709.14 18.72 44.70 34.00 806.56 19.96 1994 4237.00 4109.89 724.00 724.00 799.83 90.69 709.14 19.94 48.60 36.30 813.98 19.81 1m 4306.00 41;6.92 724.00 724.00 848.45 90.69 751.76 21.23 54.40 38.40 871.79 20.8/ 1996 4387.00 4255.39 735.60 724.00 848.45 90.69'769.36 2S.S4 60.90 41.00 896.80 21.07 1997 4466.90 4332.89 735.60 n4.00 848.45 90.69 769.?b 27.20 67.80 40.80 SIre.16 20.89 1998 4547.9G 4411.46 748.80 724.00 848.45 90.69 782.":.,32.28 76.10 44.10 935.04 21.20 1999 4629.20 4490.32 748.80 724.00 848.4:5 90.69 782.56 34.38 90.10 47.40 954.44 21.26 2000 4709.00 4567.13 748.80 124.00 848.4:5 90.69 782.56 36.61 tOI.50 5O.0C'971.47 21.27 2001 4813.00 4b6S.6t 764.00 724.00 848.45 90.69 798.56 .43.00 116.40 55.30 1013.26 21.70.:;. 4915.90 4768.42 781.90 724.00 90.691:)~2002 848.45 815.56 50.06 131.60 ~.90 1055.12 22.13 2003 5019.10 4868.53 799.90 724.00 848 ...'5 90.69 033.66 57.85 149.90 63.10 1104.51 22.61 2004 5122.00 4968.34 799.90 724.00 848,"5 90.69 833.66 61.61 170.90 67.80 1133.87 22.82 2005 5224.90 5068.06 799.90 724.00 848.45 90.69 833.66 65.62 194.40 11.90 1165.58 23.00 2006 5369.00 5207.93 1564.10 1488.20 ~.45 90.69 S18.n 93.66 15S8.n 87.31 0.00 74.00 1120.08 33.03 2001 5513.00 5347.61 1564.10 1400.20 848.45 90.69 932.17 93.66 1~2.17 92.99 0.00 78.80 1743.96 32.61 I 2008!5b57.00 5487.i!I 1564.10 1488.20 848.45 90.69 BB2.76 93.66 1622.76 99.03 0.00 83.90 1005.69 32.91~li~e_A~I~dbP l~_ltliLJr;;~~2009 ~1.00 5626.97 1564.10 l498.20 848.45 90.69 002.76 93.66 1622.76 105.47 0.00 89.30 1817.53 32.30 I 2010 S945.00 5166.65 1564.•10 1488.20 848.45 90.69 882.76 93.66 1622.76 1t2.32 0.00 83.50 1818.58 31.54 I 2011 6005.00 5902.45 1564.10 1488.20 848.45 90.69 882.76 93.66 1622.76 119.62 0.00 83.00 Um.38 30.93 ,I 2012 6229.00 6042.13 1564.10 1488 •.20 849.45 90.69 882.76 '93.66 1622.76 119.39 0.00 80.50 Utn.65 30.17 2013 6316.00 6181 72 1564.10 1488.20 848.45 90.69 882.76 93.66 1622.76 135.68 0.00 85.70 1844.14 29.82 2014 6526.00 b330.22 1564.1~1488.20 84B.45 90.69 882.76 93.66 1622.76 144.50 16.70 92.:;0 1976.26 29.64 201:5 66SO.00 6419.MJI t564.10 1488.20 848.45 90.69 882.76 93.66 1622.76 153.99 16.70 96.60 1889.9S 29.17 2016 6837.10 6631.95'1593.50 1400.20 848.45 90.,69 982.76 93.66 1652.16 174.20 35.10 103.90 1965.36 29.63 2017 6999.00 6789.0'3 1637.30 14&1.20 848.45 90.:69 uJ2.76 93.66 1695.96 196.49 58.70 1t3.80 2064.95 30.42 2918 7163.90 694a.~e 1670.70 1488.20 848.45 90.'69 882.76 93.66 1729.36 220.94 103.60 123.69 ~ln.50 31.34 2019 1333.00 7113.()1 1670.70 1488.20 848.45 90.69 882.76 93.66 1729.3b 235.30 In.50 135.70 22T1.86 32.02 2ClLO 7504.90 Tl19.:15 In:MiO 14a8.20i 948.45 90.69 882.76 93.66 1182.16 21.3.85 294.60 153.10 2493.71 34.26 h;\lj1Wi.[·:a....(@(~ m X::r: to--t C> ~ L~:'·.~ .. r~L~--.--,",>~JL~'~{.' L.-._"~r!~e".~ - ~<'''''""",-'--'-'..- r.....J..·~.c.w".J~._",,J~'~,"-.:..";',} r:C;~1f~1' L,~ ~t~_",;~~,~'J1"-""""'1~-,-'.-,--"._,.,-'" AlASKAPOVfER AUTHORITY SUS'1-NA H'YDROELEC1RIC PROJECT UPDATE EFFECT OF IN'·ERESl~RATE ON WHOLESALECOSTOFp·OWER .SEPTEMBER 1983 r::~l~f~lO'""",_,:,,,.). OIL.....J........ I 1995 2000 2005 2010 2015 2020 ...,." YEAR 3Gl r--r"-C----c--c--~1 IIDOR MEAN.FORECAST WATANA2t85 r""",_I( ".:-----,"'.... J:.::~25 0: i.U Q. Cf) I- Z ~20 I'~I··••~.······• .". a::•'".' W :'" ..'.., ,...,,.......,' O '........,~ 1 ...., <1. 5 .........••••'.....'~~o --~~......~.,-----_=j~l_-------L-.....-----... U 10 I I w :~~~~~t~~::;::~::~::;~~~~~§~j~--------~[~-;;t •I rn w ,--~,-,' ..J ----...-...-------- .~.51 ~-I,---~~-I I ---~i I I I -----8% •••II ••C··",··"10% .........-12% r~L,'",,~~c \~ ,r ;. m X :I:-OJ--I 0) ~ CD CJ ._- '"""""""""'"L~..~lL,6') ,.'"-f.........'"....,_~< L.."'j I .jlSJ,-1.--II-~ t~'J ,,i ......_ 1--1·....--..___ .-II.-J I.-lt ;.•.7 ..•to 11 .2 1JJ YEAR 1--- \~.""i .1 ..~j ~- REAL RATE OF GROWTH OF OPERATING BUDGET -2'1 ~WATANA fl.21115 ::;r..,.._....._r--_.,....~$3:.r:;:·2:.:.IO::..:.;;M;.:IL:;;;L;;,;IO;;;.N;;,.U:.;P~F~R;.;;;O~N.:.T.:;f.:;OU.:;;;';.;.1'~Y..J 1200i i.. ~,....--""I\n'lt"a ----_.•'U-t1r---' f 100 •• !~IOOI-S--.__· ~ I&. 1II4CO ~ ~-t,'e _. ..J ~0 ~Ifi ~ t,'.1 1--- (~ \}~ 1- --t............ r~"",, :-.t...-t..- r-'.I ...-t.~ ,~ j ~ r"$lil!!!'l!"'''rI- REAL RATE OF GROWTH OF OPERATING BUDGET 0" ~WATANAEI.211lS ::;130280 ....,LtlOIil UPFRO~T EOUITY ='200 _...~....__._.~ ~'....--._---.11·.'-f:ll-a _._....-'--Jal-..fU--l---J f 100 -...-"----- ! ~IOOE'~-- ""IIII400., 3 ~200 e ..J ~O__....~...............I.olIIII.....................-.......M;.a......I.-~ ~ ~-i-.~• ..-+-- --I--: l~...,,J r··-··'·~f '!.".-'~" ~~L ~''f NOTE: UPFRONT EOUrrV r-HaWN 1$n~E MAXIMUM.UNDER THE COAL EXPANIION 'LAN THE tWfl'lONT EOUITY CONTRIBUTION WOULD 8E LOWER. LEGEND I MOE MOOEL -ftCIAL ~ITAL AVAILAILE n WA.TANA,EI.~.ESTIMATED CONITRUCT1ONUEXptNOITURUMErIYEOUITY P.l WATANAEI.2111G EITIWATED CONIT"UCT'ON t;1 lX'lMDtTUfll._1'IYfIIEVINUE IONOI ALASKA POWER AU"YHORITY SUSITNAHYDROELECTRIC PROJECT UPDATE SAGE MODEL SPECIAL CAPITAL AVAILABILITY S,EPTEMBER 1983 a·~WATANA £1.2185 ::;,$3.28Q MILLION UPFRONT EOUITY ..J1200 ,~r~.IJ'-_..-····4--ti '01O")-..-'.".-.---af .... ! ~IOO t I I !-I--Il-ra-.:.II III I R--f-4I--H:UI ....J- ~c2llO .~ ..J ~O..........__~-~I.--'~................~__.~.......~.. -It 110 t3aVEAR REAL RATE OF SROWTH OF OPERATING BUDGET+2" .-. fl,..'!';r_f ,'C-"--i' ~'..".,d.'..~. .1 "(} i.e 1 i_'!t"'*",.l~"i!J5'cJ "~~., ,j: ,_'_-',,,",' (j 'I 4 ~ ~'r .',',-',_-',.i\.';'t-:>:", tt;f ............"." ; 7.0 ALTERNATIVE SUSITNA DEVELOPMENT SCHEMES u .L I:, &I" .~; ~ 1* I I IffJI~l",.•.. ·11.'.J II] JJJ 1:(~} ~'fl ..-f t,--.J 7.0 ALTERNATIVE SUSITNA DEVELOPMENT SCHEMES 7 ,,1 INTRODUCTION The studies discussed in Chapters 3 through 6 present an update of the Susitna Project as submitted in the July 1983 License Application. This Chapter presents alternative concepts of the Wa tanaand Devil Canyon Developments.These alternative concepts would ed ther change the power and energy production of the developments,or would change the way the projects would be operatr.-d.The primary focus is On a lower 1Vatana 'Dam. Recommended design refinements have been introduced which do not change the project performance nor its energy production,but do permit capi- tal cost savings.The Category 1 costesti.mate,based on the L-ecom- mended refinements of the Susitna Proj~ct design,has been used for the analysis in the previous chapters.The cost estimate under Category 2 refinement offers potential for further (;ost savings and is analyzed in this Chapter to teE't the sensitivity of construction costs. Improved ways the project can be operated for power purpose.s are described •Estimated costs,power and energy production,and associated environmental implications 3re then presented"The results are incorporated in the studies of alternative system expansion programs to meet future Rail bel t demand.Economic and cost of power analyses are also performed. The purpose of these studies is to determine how the economics of the proposed project compare with alternative development concepts under the new economic,outlook of the State.These development concepts have not been endo]~sed by the Power Authority. 7-1 7-2 7 ..2 DEVELOPMENT AL'rERl.:1ATIVES 1;,reversal in the sequence of development,with Devil Canyon preceding Watana. Load following (rather than base load)operation of the project. Sizing of the Watana Project including its reservoir elevation and installed capacity. o o o .'i~.~' ,'.\~ " A detailed review of the design concept and cost estimates for the Watana and Devil Canyon Developments and their associated access and transm:Lssion facilities as presented in the FERC License Application has been completed..The review process led to the identification of some design refinements that are clearly favorable based oncost and safety considerations.The recommended design refinements have been reviewed and accepted by the Alaska Power Authority and are included in the si-udies With the exception of relict channel treatmente For purposes of the analysis of optimi:z;ation Qfthe Susi tna Project, the following issues were examined. This section explains the features of the,Sus!tnaProject for each of the alternative conditions analy:z;ed.The estimated construction cc~sts are also provided. 7.2 fJ I Project Downsi:z;ing Project downsiZing to better match the cut'rent econotl1:.c and electric demand L,"t'ojections can be achieved in sPveral ways 1I '!'hese include reduction ininstal::'ed capacity,reduction in transmission line Voltage and number of circui ts in view of the lower lOad growth and installed ,1~ ) fi"'" ',,",_1 .,"<f ,.,.j ,~,'.\'f"..~<{ 1 j I Df .11"I I ,~""',-",,, 1, J ~11 "·1 } I '•..,'• ."~. II~~, c-.. I The most significant cost reduction can be achieved by reducing the height of the Wa t-ana Dam and related installed capacity,with c.orre- sponding r.eduction in energy production. generating capacity,and reduction in the height of the Watana Dam with corresponding reduction in the energy generation potential. Reduced load growth and installed capacity have made it possible to reduce the transmission voltage levels from Susitna to Fairbanks.The cost savings are already included in the design refinements .. 7 --3 The proposed reservoir elevation of 2185 is near the limiting elevation dictated by the damsite and by the reservoir conditions.Therefore, the chosen alternatives of reservoir elevations are all lower than the one originally proposed.In order to be assured of bracketing the optimum elevation,the range of elevations studied included a minimum elevation of 1900.The discrete reservoir elevations analyzed are: El.2185 (original),2100,2000,and 1900,as sho~in Table 7.1.The initial installations call for four units,and the ultimate installa- tions would have six units. The installed capacity of the Watana Project as presented in the Licence Application is 1020 MW.It is provided in six units,each rated at 170 MW.The fifth and sixth units provide no additional energy production.They are available for peaking use and spinning reserve but do not provide significant economic benefit in view of the reduced load growth.Cost savings amounting to $94 million (January 1983)can be achieved with the postponement of installing these two units,as shown on Exhibit 7.1. I'lllfJ!I ,"t".I.Ol II \"> \~..:;" 1••..'...·.·.·...1.••'"jl'~•.•.:t.'.'~.1 ,'~~_J WATANA RESERVOIR ELEVATION AND POWER POTENTIAL Table 7.1 Energy Production Average Firm (GWh)(GWh) Installed Capacity (December) Initial Ultimate (~ll¥)(~) 3740 680 1020 3500 3400 3315 585 880 3050 2800 2370 475 710 2500 2150 1675 380 570 1950 1400 Active Storage Capacity (1000 at) 2185 2100 2000 1900 Watana Reservior Elevation (ft ,msl) In order to provide a consistent representation of the Watana Develop- ment under the alternative reservoir elevations ,the other major ele- ments of the devslopment are kept as similar as possible in the layouts of tbe alternatives.In general,the axis of the dam is maintained at the same site and the various water release features (diversion tunnel, outle.t facilities,emergency release facilities,and main spillway)are kept on tile right abutment.Exhibits 71)2,7.3,7.4,and 7.5 show the general project arrangements for the four dan.heights. 7-4 7.2.2 Cost Estimates of Alternative Watana Developments Construction costs of the al ternative Watana developments have been estima ted at the January 1983 price level.The red uctions in excava- tj.on,fill,and conc:J:'ete quantities result in lower construction costs .. There are consequential reductions in the cost estimates of some of the support features for the lower reservoir al ternatives.For example, the decrease in the quantities required for the construction of the dam permits a reduction in the construction time schedule.This in turn permits reductions in the cost of operating the construction camp and maintenance of the access'roads.Where a reduction of.peak personnel requirements can be expected ,there would be a comparable reduction in ril.·t.·...•..!~~ 't.~1~'j N· . .'~'..j I .J ~., :"\~I 1]..1......'J"I "'..;] ·1···.\.1 I 1....1. ,,\ ""l I I 3338 2996 2637 2414 Category 1 Cost Estimate ($Mil1ion) t .Ii- 7-5 ,mtri 2185 2100 2000 1900 Reservoir Elevation (; The recent reduction in the forecast rate of growth of the demand for electric power has raised a question about the proposed sequence of development of the Susitna Project..TIle possibility of constructing Devil Canyon first might be attractive,because of its lower construc- tioncost than Watana. the maJtimum capacity and cost of the construction camp.TIle Category 1 cost estimates for the three lower reservoir elevations appear on Exhibits 7.6 through 7.8 and are summarized in Table 7.2 below. Table 7.2 SUMMARY COST ESTIMATES OF ALTERNATIVE INITIAL WATANA DEVELOPMENTS 7.2 ..3 Development Sequence The costs of operation and maintenance were discussed in Chapter 3. They were assumed to be unchanged for the lower reservoir al terna- tives. If the Devil Canyon Development precedes the construction of Watana, the diversion capacity for Devil Canyon would be doubled from 36,000 cfs to 72,000 cfs by providing a second diversion tunnel. The cofferdams are revised to provide additional freeboard reqtlired on the Upstream cofferdam to resist damage from ice floes in the river. There Would also be a requirement for increased spillway capacity and I "II,· >J ~",,,,,ltl' l.t ...1 'i -',:,[ I I ~,,':1,'\.,1"-1..~\,., y; ,J ~".~-'-,',i!, I, '.J Additionala.djustments include a greater cost for the temporary build- ings in the construction camp but a higher salvage value due tothe.ir use later at Watana. ..~ 7-6 --"'J-'-.. , The greater drawdown required in operation of the single reservoir will require additional costs for the deeper intake structure for the pen- stocks. If Devil Canyon 'is constructed first,the road access could be from the west with a road along the north bank of the Susi tna River.The road would originate at Hurricane..A bridge would be required to provide ac~ess to both banks.The railroad spur originating near Gold Creek and running along the south bank would remain as previously planned. this is provided by increasing the spillway capacity to discharge the PMF through the Devil Canyon reservoir without the moderating effect of theWatana reservoir. The smaller reservoir requires consideration as to accumulation of sediment which would otherwise be trapp.ed in the Watanareservoir.The Devil Canyon reservoir,with 100 feet of drawdown,will still have some 450,000 acre-feet of dead storage.This will accommodate the estimated sediment inflow of 5,000 acre-feet per year for the life of the Project. The changes in costs for Wata.na under this scenario concern access and the construction camp e The access to Wa tana would ,be from Devil Canyon along the road already proposed for connecting the two developments but designed for heavier construction usage.The road from the Denali Highway would be eliminated.The camp buildings would be provided,in some cases,from those tha t would become surplus at the Devil Canyon camp.This saving Would be offse t to sOme degree by the lower salvage value. 1.'.·;'·'····.1. it, ~\...i,J I. f.'.'.~l..J I I I ••..,~ I ••..", '.".-t" I .,•....J.. i"'. ,,~; ~.~"-'~, '.", I , J J The cost estimates for Watana and Devil Canyon constructed in reverse sequence appear on Exhibit 7.9.These costs are used in the economic evaluation of the construction sequence • 7.3 •BASE LOAD AND LOAD FOLLOWING OPERATIONS The Susitna Project has the capability to serve the bulk of the Rail- bel t utility system for many years to come after Watana first enters service.The quality and reliability of service of the electric sys tem will be determined by the ability of the Susitna Project to serve the loads.A typical December weekday daily load curve is shown on Exhibit 7.10. In the present License Application,the Watana plant initially would operate on base to maintain nearly uniform discharge from the power- plant.The Watana Proj ect would al so be utilized for spinning reserve, which would require that it follow load to some extent.When Devil Canyon comes on line,Watana would change to a peaking operation,while Devil Canyon operates on base. The ultimate aim should be for the Susitna Project to have the flex i'- bility to follow loads,regulate frequency and voltage,provide spin- ning reserve,and react to system needs under all normal and emergency conditions.The project should be dispatched to minimize thermal operatie;,n and fuel costs.Realization of the aim is dependent on envil'':lnmental impacts downstream and on the timing of completion of the Watana and Devil Canyon plants. Since the Susitna Project 1s capable of meeting 80 percent of the energy needs at least initially,some of the other generating plants which would normally be connected and synchronized to load would be in cold reserve.Consequently,it would be desirable for the Susitna 7-7 - The Susitnd Project has the capability to serve the bulk of the Rail- belt utility system for many years to come after Watana first enters service.The quality and reliability of service of the electric system will be determined by the ability of the Susitna Project to serve the loads.A typical Dec.ember weekday daily load curve is shown on Exhibit 7.10. 7-7 The cost estimates for Watana and Devil Canyon constructed in reverse sequence appear on Exhibit 7.9.These costs .;1re used in the economic. evaluation of the c.onstruction sequencl? The ultimate aim should be for the Susitna Project to have the flexj.- bility to follow loads,regulate frequency and voltage,provide.spin- ning reserve,and react to system needs under all normal and emergency conditions.The project should be dispatched to minimize thermal operation and fuel costs.Realization of the aim is dependent on enviroIlmental impacts downstream and on the timing of completion of the l'la tana and Devil Canyon plants. 7.3.BASE LOAD AND LOAD FOLLOWING OPERATIONS In the prese.n.t License Application,the Watana plant initially would operate on base to maintain.nearly uniform discharge from the power- plant.The Watana Project would also be utilized for spinning reserve, which would require that it follow load to some extent.When Devil Canyon comes on line,Watana would change to a peaking operation,while Devil Canyon operates on base. Since the Susitna PrQject is capable of meeting 80 percent of the energy needs at least initially,some of the other generating plants which would normally be connected and synchronized to load would be in cold reserve.Consequently,it would be desirable for the Susitna ~'...•. 'it 1 I If.J.·J!j Ii.·•.!rl I il I I , I'; ".:~_. I I I I}PI'; Project to f.ollow load as closely as practical as it fluctuates on an hourly and seasonal basis. Alternatively,Susitna Project flow release limitations can be designed to the extent that the resulting operation would meet both the power system needs and downstream flow regulation requirements.Apossible approach would be to place some limitations on the magnitude,rate,and duration of the change In fluctto,Jtions. The above de.finitions of project operation are ir:..tended to provide some estimate of the value of Susitna Project under two extreme cases of operating flex.ibility with the OGP model.In actual operation,it is neither practic.al to operate in the stric t base load mode nor accepta- ble -from the environmental otandpoint -to operate in the unrestrict- ed load following mode. Project operation should be analyzed on a real time basis using small time increments.Such analysis can provide insight into the infl uence of power operation on flow regime,while the restrictions of flow fluc- tuations can also be factored to determine the degree of Susitna oper- ating flexibility.These analyses should be made using the instream hydraulic models to evaluate downstream impacts. 7.4 RESERVOIR OPERATION STUDIES Operation studies were performed for the a1 ternative developments to estimate their power and energy production capability under base load and load following operation modes.The computer simulation program, reservoir and streamflow data,turbine and generator data,and reser- voir operation constraints used in the operation studies is described in Chapter 3. 7-8 Table 7.3 Initial Installed Capacity (December) (MW) Rated Head (ft) Initial No. of Units 7-9 Draw- down (ft) ALTERNATIVE DEVELOPMENTS Nor.Max. W.S.Elev. (ft.msl) Four Watana elevations; Four Watana elevations,followed by Devil Canyon;and Estimates of energy production and dependable capacity from the al ter- native developments were made.The studies considered the energy demands for the period 1993 through 2020,for the DOR Mean and SHCA:NSD loa.d forecasts.The alternative developments are as follows: a) b) c)Devil Canyon,followed by four a1 ternative Watanaelevations. Table 7.3 summarizes the alternative developments considered. Developments 1 •Watana 2185 120 4 680 680 2.Watana 2100 150 4 600 585 3.Watana 2000 1.50 4 500 475 4.Watana 1900 150 4 400 380 5.Devil Canyon 1455 100 4 590 600 Exhibits 7.11 and 7.12 summarize the pOwer and energy production for Watana 2185 and 2000 under the DOR Mean forecast scenarios with load following operation for the year 2020.Similar information was presented for Watana 2185,with base loading operation,in Chapter 3. f I ,, .,..1 I "i t ,.} 1,\ ",lrt IIP:·:- 7.5 SYSTEM EXPANSIDN PROGRAMS Alternative long-term power supply plans for the Railbeltwith Watana (Elev.2185)and Devil Canyon and the Non-Susitna alternatives were discussed in Chapter 5.In the studies,coal-fired and gas-fired thermal generation and the Chakachamna Hydroelectric Project were com- pared to the Susitna Project for the DORMean and SHCA-NSD oil price forecasts.The resul ts of these studies are repeated in this Chapter for comparison with the Susitna alternatives. Study of the long-term power supply plans for the Susitna al ternatives has been directed at the development of supply plans for the range of Watana reservoir elevations under consideration and analyzing the effec t of the Project's ability to follow load wi th no res tric tions in flow fluctuations.In addition,power supply plans with Devil Canyon preceding Watana are formulated.In all these cases,only four units at Watana are considered.Exhibit 7.13 summarizes pertinent data and construction and il"vestment costs for the Susitna alternatives.The investment cost includes interest during constructj,on computed at 3.5 percent using estimated construction cash flow distributions. The General Electric Optimized Generation Planning (OGP)model was used to develop the power supply plans and the plans are structured based on the following cri teria.discussed in Chapters 3,4,5 and in this Chap- ter.The model is,however,limited in its capability to analyze in detail the performance of the hydroelectric plants to (a)minimum plant rating and (b)maximum plant rating- The power and energy available from the Susitna alt<?t'natives is divided into two types;minimum rating and maximum rating _Under minimum rat.... ing,energy that must be produced is accounted for by subtracting a constant capac!ty from every hourly load in the month as shown on Exhibit 7 .14~This capacity value is referred to a.s the plant minimum 7-10 .,-,.'.- 11'~ rating.After dis'patching base load energy,the program uses the plant maximum capacity rating and remaining available energy of the hydro unit,if any,to reduce peak loads.as much as possible. The plant minimum and maximum ratings can be used to simulate base load opetation or load.following or a combination of both.Strict base loading is accomplished by specifying minI.mum plant ratings that corre- spond to plant capacity that useS the total estimated energy genera- tio.n.On the other hand,unres tricted load following is simulated by specifying maximum plant ratings that correspond to the hydroelectric projects capability and the estimated energy is used to reduce peak loads. Several expansion plan:;for Susitna alternatives were tested including the Watana Developmen.t at four different reservoir elevations,the installation date of TJevil Canyon,and project operation under base and loa.d following modes.Depending on the height of the Watana dam and mode of operation,the project would provide different amounts of capacity and energy..Therefore,the generation mix and C.osts of resulting expansion plans vary. In the caSe of Watana operating in the base loading mode,the Watana Developm.ent (prior to Devil Canyon)is dispatched as shown on the left diagram of Exhibit 7.14.In this application,the plant mini!;~,=rating corresponds to the plant capo\city that uses the total estimated energy production but not the maximum generating capacity-After the instal- lation of the Devil (;anyon De\T\~lopment,the Susi tna Project is operated a.s shown in the far right diagl.am with l~atana operating at maximum rating and Devil Canyon operating at minimum rating,thereby providinb full utilization of Watana generating capac!by and fu.ll use of energy (diagram is not tosc.ale.) 7-11 ---1 ,. 7-12 o o .......'"T.. The annual costs from 1993 through 2020 are developed by the OGP model and are converted to a present worth in 1983.The long-term sys tem costs (2021-2050)are estimated from the 2020 annual costs,With ad- justments for fuel escalation,for the 30-year period.The Susitna and Non-Susitna expansion plans are compared on the basis of the sum of the present:worth of costs from 1993 to 2050. The total costs for the planning period include all costs of fuel and operation and maintenance of all generating units.In addition,the production cost includes the annualized investment costs of any plants and transmission facilities added during the period.Costs common to all the alternatives are excluded.These would be investment costs of facilities in service prior to 1993,and ;:u1 ministrative and customer services costs of the utilities. Load following is depicted in thE!middle diagram.Wi.th this dispatch both the maximum plant ra.tings and the estimated energy production would be fully utilized.With the hydroelect.ric project operating in the load following mode,thermal capacity requirement can be minimized) and thermal plant output can be nearly uniform,substantially reducing cycling and spinning reserve duties and therefore system costs. 7.5.1 Comparison of Expansion Plans under the .oOR Mean Scenario Exhibits 7.15,7.16 and 7 .17 present the capacity additions With the DOR Meen load fore~a.st for the Susi tna and Non-Susitna a1 ternatives. Exhibi t 7.18 summarizes the generation mix,reserve margin,loss of load probabil1 ty (LOLP),economiC costs of power in $!MWh,and cumula- tive present worth of system costs for the years 2020 and 2050. Most of the expansion plans show reserve margins tn th.e range of 30 to 40 percent.The range of reselve margin would appear to be high by Ii.iJ fl.'.,'It, 1..1#tt I I~' JU! usual standards.However,the Railbelt load has a fairly long winter peak and the load factor is also relatively high. Exhibit 7.18 also shows the Non"'Susitna plan with a combination of gas- fired combined cycle and coal-fired steam ~lS being the optimum plan. Reference to Exhibit 7.15 shows this plan to beginwi.th a two--unit com1ined cycle plant in 1993.This plan was developed by OGP through its own internal optimization process.To ensure that the plan is superior to any other thermal alternative,the OGP program was tested with the uSe of a coal-fired plant in 1993,lnd further tested with the use of only gas-fired generation.These e.."Cpansion plans are found to be less economical since they result in higher cumulative present worths for the period 1993-2050. The Chakachamna Project was also tested as one of the Non-Susitna al ternatives,and it was found to have a cumulative present worth of costs greater than the optimum Non-Susitna plan. Exhibit 7.16 shows three alternative expansion plans for Watana 2185, 2100 and 2000 under the base loading case.Exhibit 7.17 shows the corresponding plans if the Susitna Project is to operate in the load following mode,which would require fewer combustion turbines or combined cycle plants to be built ill the planning period.A comparison of the present worth costs shows there is a clear economic a.dvantage if the Susi tna Project.can be operated in the load following mode.This is illustrated in Table 7.4 for the DOR Mean case.However,the economic analysis has not factored the effects on the environment under the 1o a <;1 following mode. 7-13 ••It _,-.. Table 7.4 7.5.3 Timing of Devil Canyon Development For the Non-Susi tna al ternative,a mix of natural gas-fired COlIlbined cycle plants,coal-fired steam,and combustion turbines is selected. {I\I. 4888 4664 4552 4593 Load Following Operation 5191 4892 4797 4744 Base Load Operation 7 ....14 l-~'"~ Watana 1900 Watana 2000 Watana 2100 Watana 2185 COMPARISON OF PRESENT WORTH COSTS 1993-2050 FOR BASE LOAD AND LOAD FOLLOWING OPERATIONS (1983 -$million) Exhibi t 7 .19 shows the Susi tna and Non-Susi tna expansion plans to meet the foreca.st load under the 8HCA-NSD oil price scenario.For each alternative supply plan,the generation mix;in the year 2020,reserve margin,and present worth of costs"are shown. For the Susi tna alternatives,a comparison of the generation mix and present worth of costs also shows there is a clear economic adva11tage if the Project can be operated in the load following mode excluding the consideration of envirornnental impact as discussed in a later section of the Chapter. The optimum timing of the Devil Canyon Development was established by a process of iteration.The results are shown in Table 7.5. 7.5.2 E'Xp\:msion Plan under the SHCA-NSD Scenario l<~ ~.:,,,I,, j Table 7.5 7.6 OTHER EXPANSION PROGRAMS OPTIMUM TIMING OF DEVIL CANYON DEVELOPMENT 2002 2000 1998 1996 2006 2005 2003 2002 Devil Canyon On-Line Date DOR Mean SCHA-NSD 7-1.5 C__;I~-~ ,I.,j C,,, 2185 2100 2000 1900 Watana Elevation a Sequence of construction of Watana and Devil Canyon .. a Timing of Watana Development o Availability a.nd pt'ice of Cook Irtlet gas Thus,the timing of the Devil Canyon Development ca~ld differ by four to six years depending on the eventual outcome of the oil price Scenar- io.In other words,if the initial Watana 21.85 Development Were built, Devil Canyon would be need~1 in 2002 under the SHCA-NSD case,but the plant would not be needed until four years later if the DOR Mean oil price scenario should prevail. Other generation expansion programs and casts are developed for pllr- poses of sensitivity analyses and further optimization.These include the following: The studies have been performed uSing the established criteria and the results a.re presented belo~. I I I B I ' "·1 j 111 J] i'·; 1, '... , -1 ,;~' ....'; U L",;.1: 1 h III[I ~ ~l~,~ F",,;. .f I··,:';..: ~. I·, :~ !4.J 't""\"~',i \') ~, f'~ ;~ ., I')," .J i~~' iJ 7.7 ECONOMIC ANALYSIS A life cycle analysis is perfol:'1Iled by comparing the present worth of the annualized investment and production costs for the period 1993-2050 of the Susitna alternatives &lld Non-Susitna alternatives. The analysis has been performed for the Category 1 cost estimate which includes the recommended refinements of the Susitna Project design. Since load following operation with the SUBitna Project is an important facto!'in serving the Rail belt electric system,and the License Appli- cation currently indicates that the project will be operated as a base- load facility,both modes of operating are presented.The analysis illustrates the difference in the economlcs of the project depending on opel"ation mode.By way of comparison ~the difference in the present worths of the same project operated in the two modes provides a measure of the val1H~of load-following operation. The following paragraphs describe the ne.t benefi ts,benefit/cost ratios,and net benefits as a function of initial investments,between the Susitna and Non"'Susitna alternativeso 7.7.1 Net Beneflts The "net beneflt"of a.Susi tna project is determined by taking the difference between the cumulative present worth of costs of the Susitna expansion plan and that of a Non-Susi tna expansion alternative.The net benefits for the W'atana alternatives are summarized in Table 7.6 for various dam elevations •Watana 1900 is less c.ompeti tive and not shown in the table.Exhibit 7.20 illustrates the net benefits for all Watana alternatives. 7-16 Table 7.7 Table 7.6 \) -2 1,041 226 1,342 1.00 1.18 1 ..03 1.25 93 1,311 ()~§) 1,503 1.02 1.24 1.07 1.28 2185 2100 2000 1.03 1.28 1.06 1.31 Watana Elevation 2185 2100 -......-~2:-:0:-::-0~0 <lIDtJ.,410.:::> 297Q,~ I"'. Category 1 Cost withL2.~r~Following DOR Hean SHCA-NSD gategory 1 Cost with Base I;oading DOR Mean SHCA-NSD 7.7.2 Benefit Cost Ratios Watana Elevation NET BENEFITS,199"-2050 (1983 -$milliou) BENEFIT COST RATIOS Benefi t-cost ratios,as shown in Table 7.7,are determined by taking the ratio of cumulative present worths of the Susitna ,1dternative and that of the least"'cost Non-Susi.tna al ternative for the period of 1993 ... 2050.The benefi t-cost ratio tends to increase wi th a higher Watana reservoir elevation and a more optimistic oil pr:ice scenario. 7"'17 Category 1 Cost with Base Loading DOR Mean SIlCA-·NSD Category 1 ..Cost with Load ]'allowing DOR Hean SHCA"'NSD WatanaElevation D 8.6 50.9 0.0 39.5 11.3 50.2 3.1 43.7 2185 2100 2000 8.9 48.9 4.4 44.0 Net benefits and benefit cost ratios tend to increase with the higher Watana reservoir elevation,due in part to the adoption of the planning period to 2020 when the total resource for the high Watana project is utilized.With a smaller Watana dam,it is necessary to add some thermal plants for the system.to meet the forecast load to 2020.The addition of thermal generation tends to obscure the net benefit in terms of the initial capital investment of the Watana Project.Net benefit as a function of initial capit:11 cost is shown in Table 7.8. Table 7.8 7.7.3 Net Bertefit as a Percent of Initial Investment NET BENEFIT AS PERCENT OF INITIAL WATANA CONSTRUCTION COST Category 1 Cost with Base Loading DOR Hean SHCA-NSD 7-18 Category 1 Cost with Load Following DOR Mean SH.CA ....NSD 7.8 INTERNAL RATE ....OF-RETURN (INTEREST RATE THRESHOLD)ANALYSIS The table illustrates that the net benefit as a function of initial construction cost is 10Yl under the DOR Mean scenario.However,the value is high indj:~ating the Susitna Project to be very attractive under the SHCA-NSD scenario. The internal rate-of-return for investing in Susi tna is the discount rate at which the cumulative present worth of the Susi tna alternative becomes equal to the optimum Non-Sus!tna expansion program.The [ .1 \ ,J E.~. i·'{..f: i;,I SHCA-NSDDORMean Watana 2185 3.7%5.4% Watana 2100 3.6%5 ..3% Watana 2000 3.5%5.0% --,~ INTERNAL RATE-OF-RETURN CATEGORY 1 COST WITH BASE LOADING 7-19 Table 7.9 results of the internal rate-of-return analysis are presented in Table 7.9 and illustrated in Exhibit 7.21 for the SHCA-NSD only. The "in.ternal rate-of-return"analysis provides a means to identify the project that maximizes investment.The optimum rate of return is obtained for Watana Elevation 2185.This analysis is equivalent to a threshold determination of the discount rate • 7.9 THRESHOLD DETERMINATION 7.9.1 Oil Prices World oil price greatly influences the economics of the Susitna Proj- ect.Therefore it is useful to identify the oil price at which point the cumulative preaent worth of the Susi tna al ternative is equal to tha t of the optimum Non-Susi tna al ternative,mean.ing that there is no longer any economic incentive •Inspection of the net benefits indi- caLes that the threshold oil price is very near the DOR Mean case .. With improvements in project operation the threshold oil price would be lower than the DOR Mean case. E·~~ \.C 1 .. ;'..1 T.t } i ../ .U [,.' §.:f: "" ,[ L ,l I I I I IJ 7-20 SHCA-NSD Base Load Loading Following 4,9 10.0 49.6 55.0 3.5 13.5 49.3 56.5 0.0 10.3 45.0 58.0 DOR Mean Watana 2185 Watana 2100 Watana 2000 Base Load Loading Following Table 7.10 THRESHOLD ANALYSIS FOR PERCENT INCREASE IN INITIAL WATANA PROJECT COST (CATEGORY 1 COST)-% 7.9.2 Capital Cost Estimate A threshold determination has also been made for the capital cost esti-- mate of the WatanaProjectas shown in Table 7.10.This has been don~~ for the SHCA-NSD and DOR Mean oil price scenario for the Category 1 case threshold point..In such a determination,the threshold point is the change in the estimated cost of the initial Watana Development that would cause the break-even po.int to be reached.A substantial increase in the estimated cost of the Watana Development would be requi.red before the threshold point is reached for the SHCA-NSD scenario. 7.10 SENSITIVITY ANALYSIS 7.10.1 DelayofWatana Operation A sensitivity analysIs was done to analyze the impacts of delaying Watana ope.ration until 1996 J under the DOR Mean and SHCA-NSD scenarios. The year 1996 was selected because a three-year delay would permit the addition of two combined cycle gas turbine units in 1993 J which is the best thermal option.The OGP model was rerUn for Watana E:.i~vations 5,453 5,580 In all 5,164 5,320 SHCA-NSD Watana Elevation 2185 2000 4,892 5,325 4~877 5,481 ~._~- /- 4,740 4,693 DOR Mean Watana Elevation 2185 2000 4)744 4,793 4,629 4,658 ,... DELAY OF WATANA OPERATION 2050 CUMULATIVE PRESENT WORTH (1983 -$million) 2185 and 2000 with base loading and load following.The 2050 cumula- tive present worths are presented in the Table 7.11.The results indi- cate that there is all economic disadvantage with the delay under the SHCA-NSD scenario and no significant difference under the DOR Mean condition. Table 7.11 7-21 Category 1 Cost with Base Loading Watana in 1993 Watana in 1996 Category 1 Cost with Load Following Watana in 1993 Watana in 1996 7.10.2 Project Sequence WatanaElevations 2185 and 2000 for the DOR Mean scenario. Table 7.12 summarizes the 2050 cumulative present worth of theWatana- Devil Canyon sequence compared to the Devil Canyon-Watana sequence for cases,the present worth analysis shoW's construction of Devil Canyon first is less favorable than construction of Watana first. " "1 j;: ."J [:-\ ,) ~1.1 ~ItJ '~".,':1 'lj 1 , Ij~ j I 1,; ,":1 .'1"j ~:~"':i 1:. >l I 1 J I I i .,',,*,-,I1';l~'J II 4,892 4,982 4,664 4,792 Watana Elevation 2185 2000 4,744 4,897 4,593 4,689 Category 1 Cost with Base Loading Watana First Devil Canyon First Category 1 Cost with Load Following Watana First Devil Canyon First 7 ..11 SUMMARY ,.""\''.-"\u ! PROJECT SEQUENCE 2050 CUMULATIVE PRESENT WORTH (1983 -$million) 7-22 Table 7.12 Net benefits are generally greater w""ith higher Watana dam elevations. Load following operations have greater ec')nomic impacts on smaller projects.Any of the projects are at or near the threshold under the DOR Mean scenario.The thresholdWatana construction cost is 50 to 60 percent above thf'3stimated cost for the SHCA-NSDscenario.The delay of Watana operation from 1993 to 1996 does not affect the economics significantly under the DOR Mean scenario. 7.12 COST OF POWER ANALYSIS The results of the economic analyses indicate that between the ranges of Watana 2185 and Watana 2000,there is no material influence on proj- ect economics;however,below Watana 2000 the economic benefits decrease significantly. 1"-1; .':~ ;.~,-I 1., 'I].....J i ;J I 11 I lJ ilJ f t.i 7-23 For thi.s'reasOIl,the cost of power analysis is performed for only two Watana dam heights--the Watana 2185,and Watarta 2000 operated in a load folloWing mode.Cost of power studies for Watana 2185 were discussed in Chapter 6 and are repeated here for comparison purpos(es.The financing approach and assumpt.ions considered in the evalua tion of project funding are the same as discussed in Chapter 6.'!he estillla.ted construction costs are $3,338 million (1983 $)forWatana 2185 and $2,637 million for Watana 2000.Obviously,the di.fference in capital cost requirements would influence th~amount of State equity contri..... bution. The cost of power estimates were made for a range of State equity con..... tributions including a determination of the amount of State equi.ty contribution that will bring the wholesale cost of.Susitna power equal to the first year cost of the alternative Non-Susitna expansion program.The results are summarized in Table 7.13 for the DOR Mean ano SHCA-NSD cases. l 1 1-:\ ....':i ':j I (...1 :~-:.t..••'.3 Ifl IfJ ,..·1;·:·..·~.~. '.'.'".-{.-i,,1' 5.21 5.01 4.67 4.70 2 ..96 2.97 2.32 2.45 4.01 3.44 1.35 1.42 Watana 2000 Load Following 1.20 1.57 2.35 2.25 1.61 1.55 Equity Revenue State Bonds Total 6 ..28 6 ..10 5.69 5.79 3.67 3073 4.32 3.80 2,,41 2.79 1 ..40 1..62 _...__.. Watana 2185 Base Loading 1.96 2.30 3.28 3 ..00 1.45 2.62 4.07 0.88 2.46 3.3410672.29 3.96 1.12 2.03 3.15 2.27 2.11 Equity Revenue State Bonds Total FU~~INGREQUIREMENTS TO EQUATE FIRST YEAR WHOLESALE COST OF POWER TO THE NON-SUSITNA ALTERNATIVE (In $Billion) DOR Mean SHCA-NSD DOR Mean SHCA-NSD DOR Mean SHCA-NSD DOR }lean SHCA-NSD Gas/Coal Thermal Gas/Coal Thermal 1983 $ Coal Thermal Table 7.13 7""24 NOMINAL $ Coal Thermal With reference to Table 7.13,State equity revenue bond requirements would be much reduced with a lower Wa tana dam height.Exhibits 7.22 and 7 .23 show the State equity contribution required to match the first year cost of a thermal system served by a combination of natural gas- fired and coal-fired powerplants.The State equity contribution would be much less if the obj ective is to match the first year cost of a coal-fired thermal system • T1"'2 State equity contribution provides the means to bring the first year wholesale cost of Susitna power down to the level of alternative I I ( 1I.oj :.",,} I't; I f f.) [3 f;1 'iI., ;II."'Ii I.; ••..,..,.1 f r' t,," Ii"k""1 L Q " .j~:I tt.·! ":! ! [~ t··'! :~ , L f ,'J ~' I.,'." L l;: ":'. L thermal system cost.It will also stabilize the future cost of power. This is illustrated in E~hibits 7.24 and 7.25 showing the cost of power over t~o>;e for the DOR Mean.oil price.scenario.In later y~ars j whole- sale cost of power from Susitnawith Watana Elevation 2000 would be about 30 percent higher than the Watana 2185 development,but would still be less than half that of the best thermal option" Exhibits 7.26 and 7.27 show tabulated data for the DOR Mean analysis on annual costs and wholesale cost of power for Watana 2185 and Watana 2000 projects,for the State equi ty contribution that equates Susi tna and Non-Susitna first year costs and 100 percent debt service cases. 7.13 INTEREST RATE SENSITIVITY The interest rates on revenue bonds will greatly influence the cost of powe:co Exhibit 7.28 shows the range of power costs for different in- terest rates,assuming a State equity contribution of $1 ,610 million (1983 dollars)for the Watana 2000 project.Interest rates from eight percent and twelve percent have been used to illustrate th~effect on cost of power when compared against the base case of ten percent. First year (1993)power costs would be 6 ..4:J 7.6,and 8.8 cents per kWh with interest rates at eight,ten and twelve percent)respectively. 7 .14 SAGE MODEL Exhibit:7,,29 shows a bar chart of estimated Watana construction cash flows for the 2185 and 2000 projects and special capi tal available for Susitna under the ttree operating budget growth scenarios (f2%,0%,and -2%)as estimated from SAGE Model runs. Inspection of Exhibit 7.29 indicateS that II with the same on-line date (1993),the Watana2000 project expenditures would not begin until 1987.III addition,with real growth in the operating budget of 0 and - 7-25 -1--,,,,,,-·'" i11<'1'; -.:'~1 .)~ 1 r~ II'! I t; Ii f -"., .; L t; 2 percent,construction expenditures are met or exceeded by estimated available capital eJecept in 1990 and 1991 under the 0 percent scenprio. However,if surpluses in earlier years were reserved,the 1990 capi tal requirements could.also be.met.The 2 percent operating budget growth rate scenario yields available Susi tna capi tal estimates that would fall short of construction expenditures .in 1988 through 1991.If sur- pluses in earlier years were res(~rved,.these construction expenditures could be met under all the operating budget growth rates for the Watana .2000. Since the expenditures fo'1.'the Watana 2000 project are significantly less than the 2185 project,total upfront capital rEquirements are much less ($2,350 versus $3,280 million)and annual construc~ion expendi- tures are more in line 'With estimated special capital available.The upfront capital requirements used in these comparisons are the maximum. Under the coal expansion plan the capital requirements would be m'lch less. 7 .15 ENVIRONMENTAL CONSIDER,.4..TIONS The environmental implications of the alternative development concepts considered during the 1983 Update.and Optimization Studies have been evaluated throughout the course of the studies.A summary of these implications is presented in this section.A more comprehensive environmental evaluation of the alternative schemes is contained ina supplemental environmental report. Exhibit Eof theFERC ticense Application,as filed on February 2 8, 1983,considered .all aspects of construction and opera.tion of the proj- ect,as proposed,in relation to probable impacts on the physical, biological,and social resources of the affected region.Changes from the License Application.in the size or configuration of project fea- tures or sequence·of construction would resu1 tin slightly different 7-26 I ".,.- tJ [" ",,-.," I • .'J ~"l.".J; ~13 r·t ;;-,~,.'( 1'1 ,,,'fi 1-:1 ".":,(t I [1(J 7-27 1 less area inundated; less borrow material needed; 1 to 2 years reduction in construction tim~; more m.odest remedial measures to seal the relict channel; and o o o o 7.15.1 Area Upstream of Devil Canyon project impacts as compared to those discussed in Exhibit E.This section presents a discussion of the relatlve impacts of the '~esigll and operational alternatives considered in the present study.The develop- ment concepts will differentially impact the region upstream of Devil Canyon through construction and inundation effects (e.g.,size of reservoir,construction time,manpower requirements,etc ..)and will differentially affect the river downstream from Devil Canyon through different seasonal flow release pa tterns.'!his discussion is designed to highlight the differential impacts of the alternatives and to assist in their overall evalua tion.It is not intended to present a compre- hensive discussion of all potential impacts of each of the a1 terna- tives.A comprehensive evaluation of the project as described in tbe License Application is contained in Exhibit E.Comparable detailed analys~s will be made only for those alternatives that may be selected for future detailed study. The majority of the anticipated impac ts on terrestrial and aqua tic resources resulting from the construction and operation of the two dam project ,as described in the License Application,are related to the first phase of development,the Watana 2185 dam and l'''eservoir.The relative impacts of the proposed Watana alternatives are therefore compared to those for the base case Watana 2185 development as dis- cussed in Exhibit E.Projects with loW'er normal maximum water surface elevations at the Watana si te (e.g.2100,2000,or 1900 feet)would result in: I t f It: II~l t 1..···\"\ 11 [. ...'..!....:',) j 7-28 1900 14,500 39 11 2000 19,800 44 14 2100 28,300 49 18 2185 38,000 54 24 ENVIRONMENTAL CHARACTERISTIOS OF ALTERNATIVE WATANA DEVELOPMENTS Each of these potential changes would result in a reduction of direct impacts to the resources of the project area.The most significant changes from an environmental standpoint are the extent of area inun- dated,therequireme.nts fQr exca.vation of materials from borrow areas, and the less inherent capacity for regulation of downstream flows. a less inhe'rent capacity for flood ~ontrol and less regulation of downstream flows. Table 7.14 7.15.1.1 Area Inundated.At lower normal maximum reservoir elevations,the length of the reservoir would be shorter and the area inundated would be less than for the reservoir at elevation 2185 (Exhibit 7.30 and Table 7.14).Less area inundated means less impa.ct on the terrestrial,aquatic,and other (recreational,archaeological, etc.)resources of the region. Alternative Elevation (ft,msl) Reservoir Area (acres) Susitna River Miles Inundated Length of Major Tributaries Inundated (stream Illiles) ~1uch of the area to be inundated by the Wa tana development,particu'" larly the south-facing slopes,is important as a source of early spring foods for mO.ose and bear,and as calving areas for moose.A reduction in the reservoir area,particUlarly in the length of mainstemand i J !.~, Ii t'!" j ,.; .."J I,j,,.; .<:,::':"r t'.~ '"'.1 ·P::.\1~,1 1 .~ I I 1'1., ,.":r r1 .•-. t ..,':r .\ :J I 1 tl !I, If f () Ii "IlJ I , ,, '.i.;,J 'I.···1.".\_._,J I t 1 1; 't .',; l :,_.t,,;; tributary stream inundated and the narrower reservoir width associated with the lower lVatana developments,would reduce the magnitude of these impacts on the carrying capacd ty of the area for big game species,and would also reduce the potential for interference wi th movements and the possibility fOr big game fatalities during river crossing attempts.A reduction in the extent of inundation along Watana Creek may be parti- cularly beneficial for maintenance of wildlife habitat. With the reservoir at elevation 2185,up to 42 percent of the surface area of the Jay Creek mineral lick would be.inundated by the Watana impoundment.This lick appears to be an important nutrient source for the Watana Hills Dall Sheep population.The lick extends from eleva- tion 2000 to 2450,so at lower elevations of the reservoir,less of the lick area would be inundated or it might be totally avoided (e.g.,at elevation 1900). The primary long-term impact of the reservtiit"on aquatic resources is the loss of clear water tributary spawning habitat that currently supports a substantial population of graYling.Fu~ure aquatic habitats wi thin the reserv~ir area are not expected to support a significan~ grayling population.In addition,some loss of burbot and whltefish spawning area is expected in mainstem habitats.The lower surface elevations of the reservoir would inundate few~r stream miles of main.... stem and clearwater tributary habitat and thereby reduce impacts to aquatic resOurces. 7.15.1 .2 Borrow Material Needed.The report on Recommended Design Refinementc;indicates that the modified design for the Watana embank- ment requires 10%less fill material than is discussed in Exhibi t E. At lower dam elevations of 2100,2000,o:c 1900,requirements for fill material are 26.,55,and 70 percent less,respectively,than the rea~i t'ements for the modified 2185 design.For theelevatioll.1900 development,the.requirements fat'rock excavated frOm an upland quarry 7-29 ,- 11 ,..1\ :1 <ij~ t 1]'ifI;,) ,f1 r~f 'I""j 'I':'?J ill ·1 tJ t I 11" t~, tJ .{,: .'.,,.J. I !I; [ ,J .,':.,:-:1 are 96 percent less than the modified 2185 design.Requirements for impervious fill (from an upland site)and sand and gravel (from the river channel and ripa.rian areas)are 69 and 77 perceI'lt less,respec- tively,for the 1900 alternative than for the 2185 modified design. The smaller requirements for sand and gravel,which will be obtained from the Susi tna River at the mouth of Tsusena Creek,will limit the extent and duration of turbidity and sedimentation in the river down- stream during construction.Also,the impacts to the existing riparian hahi ta t in the area will be less than for the higher dam a1 ternative. The smaller requirements for material from the rock quarry and the borrow area for impervious fill will lead to less disturbance to sur- rounding lands,including less traffic on the haul roads,less blast- ing,and less overall generation of dust. 7.15.1.3 Aesthetic and Land Use Impacts.The lower alternative reser- voir elevations will inundate significantly fewer acres.and stream miles than the project as described in the License Application.The total magnitude of impacts on land use,recreation,aesthetic,and arc.haeological resources in the area will also be less significant. Although development will increase the potential for access to the area,the lower reservoir al ternatives will result in larger areas remaining in primitive "before project"condition • 7.15.2 Downstream Flows Downstream flow regimes following project construction will be altered from natural conditions,wi th marked increases in winter flows a.nd dec.reases in summer flows..Table 7.15 summarizes average August and December flows for three demand scenarios and each a.l ternative da.m elevation for the Watana Development.The first power demand scenario assumes a year 2000 demand of 4709 GWh.(DOR Mean forecast).Under this scenario,only tl"le Watana Development would be in operation_Toe second scenario assumes both Devil Canyon 1455 plus one of the Wa~~a.na 7-30 I·_. I). j ~ jf: I'; j 1'1 I 11 I [. I f I r~ I" {: I !~, l L~ I 1::, [J al ternatives are in operation and presents flows at Gold Greek as they would occur for a year 2010 power demand of 5945 GWh.The third scenario presents )rear 2020 flow'S for an increased power demand of 7505 GW"1l.These three scenarios characterize the project outflows over the life of the project. Table 7.15 AVERAGE AUGUST AND DECEMBER WITH-PROJECT~"lLOWS AT GOLD CREEK Demand Level (GWh)and Month Watana Demand 4709 GWh Demand 5945 GWh Demand 7500 GWhAlterna.tive Aug.Dec ..Aug ..Dec.Aug.Dec.(cfs)(Cfs)(cfs)(cfs)(cfs)(cfs) 2185 12,680 11,146 1 8,436 9,430 12,678 10,979210013,755 10,689 16,050 9,796 13,548 11,274200015,900 8,697 19,020 9,264 17,424 8,906190022,017 7,802 21,057 7,058 20,363 7,054 Natural 22,017 1,825 22,017 1,825 22,017 1,825 Monthly flow dura.tion curves for August and December for each dam height and each power demand level are shown on E~hibit 7.31.December flows are greatly increased Compa.red to natural condi tions for all dam heights and power demand scena.rios.In genera.l,December flows are grea.ter at greater dam heights.Conversely,August flows at Gold Creek are less w'ith greater dam heights. Depending on the dam elevation and power demand scenario ,average August flows may be decreased from a natu.ral flow o£22,017 cfs to a low of 12,678 cfsfor the fu.lly loa.ded two development project (year 2020 demand of 7505 GWh)..Average December flows are increased from a natural flow of 1825 cfs to a range of 7000 to 11,.300 cfs.For indi- vidual years ou.t of the 33 year period of record,a.verage monthly December flow may exceed 14,000 cfs.August flows are mai.ntained at a 7 ...31 j _...... fl··:: .~.-'. ','f' 1,"11:· f._.'.-£ i-I j 1:\ !j ", ',__.1 Ii "'":' I i \ ; o,f,' I 1 f: I I i I t.\ I minimum of 12 50 000 cfs in a.ccordance with the "Case C"Scenario even though operation solely for power production would have resulted in less than 12,000 cfs at Gold Creek.Further downstream,these marked differences between natural and with-project flows diminish due to tributary inflow,and seasonal flow patterns more L~arly approach the pre-project pattern. 7.15.3 Downstream Impacts on Aqt~.atic and Riparian Resources If impacts are defined as changl~s from natural conditions,the lowest elevation dam would have the least impact in that it has the least change from natural flow conditions and would be le::lst likely to result in long-term changes to fishery habitat anc fish populations downstream and to downstream riparian vegetation that serves as important mOose habitat. Downstream impacts of project operatj.on on aqua,tic resources would occur primarily as a result of changes in the flow aiid water quality regimes..Flows deviate most from natural conditions at higher dam heights.Downstream turbidities would decrease from natural conditions in spring and summer and increase in the winter under all alternatives. With-project temperatures during operr,ltion would be similar to natural conditions in spring and summer but would increase over natural cendi.... tions in the winter.Changing the dam height should not substantially change dO"7I1stre r ;,m temperatures and turbidities. Secondary environmenta.l effects of altered downstream flows are less severe at lower dam heights because average monthly flows are clos~r to natural conditions at lower dam heights.For e~ample,mainstem veloci- ties and depths in spring and Summer would i.ncrease (and thereby become more similal:'to natural conditions)at lowel:'dam heights.Conse- quently,the magnitude of impacts to downstream aquatic resources would l.ll:ely increase for higher normal ma~d1Ilum reservoir elevations because 7 ....32 .,.~-/'\ '-")~r" tion~'• the downstream flow regimes have greater deviations from natural condi- 7 .....33 Access for salmon and resident fish to spawning areas in tributaries and sloughs was identified as a critical issue in Exhibit E.The ease of access to tributaries and f!ldughs decreases under low flow conditions.Access problems will potentially be most significant with the Watana 2185 alterna-- tive since project flows during the summer are generally the lowest of all alternativep" Project opet'ation in the spring and st'IDmer could impact the loea tion a~d availability of spawnirl,~habi ta t in the main-- stem,side channe.ls and sloughs.Reduced flows in the main-- ~tem and side channels may have both positive and negative effects on spawning habitat,but changes would more likely be positive because relativelY little spawning occurs in these areas under present conditions.The wi th-project reduction in the magnitude and frequency of flood events may decrea.se 1.Unusually high,low or unstable flows can slow or even halt upstream migrations of salmon.A reduction in the magnitude and frequency of flood flows that would result from the higher dam al ternatives could reduce disruptions in upstream migrations-On the other hand,lower dam heights have higher average flews during the summer tfuich more nearly equal natural flows and could likeWise facilitate upstream move- ment.~~net advantage of one factor over the other is under investigation. 2. 3. During the spring and summer,the potential impacts on downstream fish- ery resources of the Watana project alternative are as follows. t bJ t., t l· t t I II'.;." I r I t I I r;> 1.;"" I [ I ( I·" I~, During fall and winter,potential impacts include: 7-34 The increased staging downstream of the ice front might pro- vide more overwintering habitat in s.ome areas for resident and a.nadromous species if wetted perimeter and depths increase under the ice as a result of increased wi.nter flows. disruptions to existing spawning r "itat and the more stable water depths may add new spawning habitat in these areas. 4.Changes in the quality and quantity of rearing habitat for resident and juvenile anadromous species may result from project operation.Losses of rearing habitat will occur if lower flows cause depths to be reduced making areas too shallow for fish to use or reducing the extent of quiet, backwater areas.Increases in rearing habitat could result from the reduced velocities,turbidities and scour of the substrate associated with the reduction of flood flows.Net gain or loss of rearing habitat has yet to be quantified. Greater change,whether positive or negative,in habitat should occur at higher dam heights since mains tern depths and flows will be more reduced. 1.The higher winter flows under project conditions,compounded by increased river stage due to ice formation,will increase the-,;potential of overtopping the berms at the upstream ends of sOme sloughs.'Iheintroduction of cold mains tern flows and possible scouring of the subs trate resulting from over- topping could result in slowed development rate of fish eggs or eggs CQuid be killed due to thermal sho ck or physical destruction.The probability of sloughs being overtopped because of increased ice staging will be less at successively lower dam heights. 2. I t ·r''''·-.·.·.'·'''·; 1,-,' f I'·.·""'··.,····:·I ,:, t ' I I~ I 1'""".'-., 3<0'-' i I I ("', If It if, I ( 7-35 I ..".< inhibited upstream migration of adult salmon due to unstable flow conditions,which may reduce survival and spawning success of some fish; The types 'of impacts expected during reservoir filling \,;Tould be com- parable to those during operation.During filling,flows at Gold Creek would be reduced during the spring and summe:t:'whereas largely natural flows would occur in winter.The mai~ef£ect that.lower dam heights have on the magnitude of the impacts is that the impacts will occur for a shorter period of time for the lower dam heights,since the lower dam reduces the time necessary to fill the reservoir.Adverse temperature effects expected during the second open water season of filling for the Watana 2185 development may be reduced for the Watana 2000 and 1900 alternatives.The lower reservoirs would be filled more quickly and thus permit the multiple level release facilities to be ope.rated earlier and thereby avoid most of the impacts related to release of colder waters, Warmer water temperatures ups.tream of the ice front could enhance the sllrvival of overwintering fish by reducing mor- talities due to freezing. Two potential operational modes were considered for tbeproject,re.... gardless of reservoir elevation.Base load operation results in daily and weekly regulation of flows downstream of the project,With unrestricted load following operation,hourly and daily discharges would vary significantly.These flow fluctuations would decrease with distance dOW11stream because some attenuation of the flow extremes would occur.AI though information is not available to evaluate the effects of daily flow fluctuations downstream,the following types of impacts may be expected: 1) t ,l l 1 I .I.l~I~t • f t I' II f I, l ··I·.· ··.····"!.···.···. l'... I.'.','~..- I I I,' I f~ .1····I··~;.:1j.."......, t r I 11 II,i i IJ I 11 11.i I.',"':-''1o,j t .~ t ~jIJ I '",.t I I,;,. ~ 2)reduced growth and survival of rearing anadromous and resident spc:;ci~s because of changing amounts of suitable habitat;and 3)decreased survival of eggs as a result of impacts caused by daily watering and dewatering of the redds during incubation. Because daily changes in discharge and stage during the winter would be greater for the lower dcun alternatives,impacts of daily flow fluctua- tions would be more severe for these alternatives. Downstream flow alterations and fluctuationsto."'ill also impact terres- trial,particularly riparian,resources.The higher winter flows, lower-summer flows,and lack of ice scouring with project operation, particularly in the reach be tween Talkeetna and Devil Canyon,would result in the stabilization of the river banks and the succession to climax forest of some areas now subject to vegetative rec~ssion. Although moose habitat may be improved for 10-20 years,the lack of flooding and ice scouring events will eventually result in the decreased availability of good moose habitat along the ri.ver downstream to Talkeetna,and also inhibit movements of moose and other big game to islands or across the river during cold weather.The more stable year-- round flows and reduced spring and summer flooding of food caches and other beaver structures will result in :i.mproved downstream habitat for beaver and muskrat.This,in turn,may ;'lave secondary adverse impacts on fishery resources. As with other downstream resources,the relative extent of impacts of the Watana alternatives will be dependent on the extent of change of downstream flow.Thus,the lowest elevation dam generally has the least impact in that it m.ost nearly represents natural or pre-project conditions a.nd would be least likely to result in long....term changes to riparian habitat.Changes that do occur will be most severe in the reach between Devil Canyon and Talkeetna.Downstream of the confluenoe 7 ....36 rivers. 7-37 _..__10;. of the Susit.na,Chulitna and Talkeetna Rivers,changes in flow regimes due to project operation will be moderated due to inflow from the other 7.15.4 Regional Socioeconomic Impacts of Watana Alternatives Differential impacts of the alternative Watana developments will result primarily frOm differences in associated labor requirements.With no significant differences in peak work force requirements of the alterna- tives,project-related population,employment and income,housing, services and facilities,and fiscal impacts will be similar to those described in Exhibit E of the License Application.Differential effects related to the vlatana alternatives will result from the shorter construe tion schedules for the lower developments,with resultant shorter duration of peak requirements for housing and other facilities and services. 7.15.5 Environmental Aspects of Load Following Operation The en\rironmental implications of operating the Susi tna Hydroelectric Project on a load following basis are highly dependent upon the magni- tude of discharge variati(ns during a 24-hour period and the season in which these variations occur.The most significant effects of load following are expected to occur wi thin the aqua tic ecosys tem as simi- 1arly encountered at other hydroelectric projects operated on a load following or peaking basis.The effects to the terrestrial sYstem are primarily those which would occur within the daily inundation zone,the associated riparianhabi tats along the river margins.,and in theflood-- plains.In addition,load following could result in potential impacts to cultural,aesthetic and recreation resources and socioeconomic activities.A discussion of the potential impacts is presented below for each aspect. t . I ! L" I n I r If 1 t I r r The rate of change of discharge; made; River channel morphology;and Attenuation of the change in discharge downstream from the dams. 3. 4. 5. 7-38 2..The base flow from which increase to the maximum flow is 1.The magnitude of the change in discharge during the 24-hour period; 1.Stranding or isolation of fish,primarily juveniles,when the water surfac.e elevation recedes; 7.15.5.1 Aquatic Ecosystem Implica.tions..The magnitude of the expect- ed effects of load following on the aquatic ecosystem is dependent on several hydraulic characteristics and the life stages of the a.quatic species present in the river.The hydraulic characteristics which will determine the rnagni tude of effects include: The following discussion outlines the types of effects that have been experienced a.t other hydroelectric fac.ilities as well as some aspects which are associated wi th specific features of the Susi tna River.It also assumes that the load following operation Will occur at both the Watana and Devil Canyon facilities. The potential effects to the fisheries and aqua tic resources due to load following operation include: r";·c; ':' r' { f t 1 J 1 I[ 1 I J r 7-39 .12'i'tt· Changes in ice process Which indirectly affect aquatic resources;and Short-term rapid changes in availability and distribution of various habitat typ~s; Delay or inhibition of upstream movement of adult salmon; Inundation of incubating ~ggs with cold water in otherwise somewhat protected area (~.g.,overtopping of upstr~am because of side sloughs); Dewatering and freezing of inG.ubating eggs; Potential increases in bank erosion due to bank instability. 2. 3. 5. 7. 4 .. 6. Stranding of fish could be significant in areas where fish remain in pools isolated from the main current as waters recede.These fish also become more susceptible to predation and dessication when the habitat dewaters due to water seepage out of the pool through the gravels. Juvenile salmon are particularly succeptible because they frequently utilize shallow,near-shore access for rearing (ADF&G). In addition to the potential for fish stranding,habitats utilized by juvenile salmon for rearing may be seriously disrupted by constantly changing mainstem discharges.Studies to date (ADF&G,1983)indicate that,at least in some areas,the availability of rearing habitats utilized by juvenile salmon is corr~lated with discharge.With con- stantly changing discharg~s in the river,the ability of juvenile sal.... man to maintain themselves in a specific area may not be possible because of the daily disappearance of habita.t or significant changes in water velnci ty.In other areas,juveniler~a.r.ing habitat appears to be unaff~cted by mainstem discharge and,the.refore,may not be signif1- tL. f f f { I r t r I r II I r I r i r I r t r I { f cantly affected by constant changes in water surface elevation..This too,is highly dependent upon the daily range of discharge fluctuation and water surface elevation .. Daily load following changes in discharges may inhibit upstream migra- tion of adult salmon to the various spawning habitats.Data collected by ADF&G over the past three.years (ADF&G 1982,ADF&G 1983,and pers. comm.)show that during periods of rapidly rising discharges due to stann events,upstream.movement of adult salmon nearly ceases.As the flood peaks and discharge declines,movement of salmon re:sumes.Daily fluctuation in discharge could delay movement of adult salmon to the spawning areas. Beyond the.potential delay in upstream migration of adult salmon,daily discharge variation could eliminate mainstem areas as viable spawning and incubation areas for salmon due to the constant dewatering and potential freezing of the suitable sites.Associated with this,suita- ble spawning areas in side sloughs and side channels may be rendered unsui table if there is daily overtopping of the upstream berms with mainstemwater. The above concerns are most commonly associated with river reaches immediately below hydroelectric projects and are generally attenuated further downstream.Upstream of the confluence of the Chulitna and Talkeetna Rivers,little attenuation of the daily fluctuation is anticipa ted in the Susi tna River because of the steep gradient in the upstream reach.Downstream of the confluence area,some attenuation is expected because of the lower gradient and the effect of inflow from the major tributaries.The attenuation will be greatest during the open water season when flows are highest from the tributaries.How- eVer,when tributary flo'W is low,as in the winter months,daily fluc'" tuation in the Susitna River downstream of the Chulitna and Talkeetna Rivers will be m.ore significant. 7-40 [ f r fl I L. Potential effects of load following during the ice covered period could possibly be more significant than during the open water se~son, although less directly observable.Under load following conditions, the ice processes become somewhat more complex than without the project or under base load operation of the project.In open water areas, daily changes in discharge during the winter may result in considerable build up of ice along the banks of the river.This would occur as a result of exposure of the river bank during water level changes.The implication to the fishery involves stranding of juvenile fish and freezing of incubating eggs in the spawning areas. At the leading edge of the ice cover area,daily flow variation could cause periodic flooding of floodplain areas and could result in signif- icant ice jams.Increased flooding is associated with the increased water surface elevations which are observed during the development of the ice cover tmder current conditions"Additionally,the mechanical action of discharge variation may tax the integrity of the ice cover" If the integrity of the ice cover is compromised,mechanical breakup would occur as the ice cover rides the changing water elevation as observed in the Peace River in Canada.In addition,downstream movement of the ice could fonn ice jam.s similar to what occurs during breakup under existing conditions which,in turn,could cause flooding. The increased flooding could affect overwintering habitats for juvenile salmon and resident fish through scouring of bed materials,inCreased veloci ties in sui table habits and decreased temperatures resulting from cold mainstem water inundation of wanner groundwater. Min ind.za tion or avoidance of all potential effects may be achieved through limitation of the range of daily flow changes and the rates of change,both on the ascending portions and receding portions of the hydrograph.The best method of defining acceptable discharge ranges 7--41 I r I r I f I 1 I [ f t r I f 1 would be to define the maximum acceptable range of water surface elevf...... tiollchange. 7.15.5.2 Botanical and Wildlife Resource Im.plications.The downstream effects of winter daily flow fluctuations may include impacts on moose movements,decreased beaver over-winter survival,and riparian habi ta t changes.These effects would mainly occur in the ice-covered portions of the river downstream of the vicinity of Talkeetna.Below the Talkeetna area,floW'attenuation and dilution by major tributaries would likely reduce the effects to inl:;1gnificant levels.It should be em.phasized that until further hydrologic and hydraulic e.valoo tions are completed,assessments of the effects of daily flow fluctuations on botanical and wildlife resources are preliminary in nature. Daily flow fluctuations may create a m.ore irregular and broken ice surface,the:t"eby making river crossings by moose more difficult and hazardous.As a result,moose movements and habitat use along the ice- covered portion of the river would be more restricted and the potential for accidents at-o.exposure to wolf predation would be increased. Daily flow fluctuations may also reduce overwinter survival of beavers due to the entrapment of greater portions of food caches in ice and/or the uprooting and washing downstream of food caches..This latter mechanism may also negatively affect beavers upstream of the ice- covered portions of the river but the lack of ice cover may overshadow the negative effect in this area. The extent of ice damage to riparian vegetation may be increased due to the greater ice movement and thickness resulting from daily flow fluc- too tions.As a result,the unvegetated floodplain may be'Ylidened and the stage of plant succession maybe retarded along many shoreline areas,at least initially.A widerunvegetated floodplain is likely t.o 7-42 1-'-I'_..._..... 7--43 7 .15 .5 .3 Social Science Implications.The implications of load following on cultural,socioeconom.ic,recreation,aesthetic,and land use resources cannot be accurately determined until additiona.l hydro- logic and hydraulic studies are conducted and until the results of those studies are factored into an analysis of load following impacts on aquatic and terrestrial resources. resul t in the long term as well.It is not clear,however,wi thout further evaluation,whether the long--term.net result would be tD increase or decrease the availability of early successional vegetation. The resultant long...term effects of these riparian habitat changes on moose and other wildlife are al so tUlclear • In general,based on available information,it is anticipated that load following may decrea.se bank stability,thereby increasing bank erosion. If this occurs,additional archeological and!or historic sites could be eliminated.In addition,increased erosion and fluctuations of the river level could potentially reduce the aesthetic quality of affected areas.Furthermore,individuals and businesses relying on fish and wildlife resources for flood,recreation,cultural,andlor commercial activities (including hunters,-trappers,guides,and lodge o'Wners) could be negatiVE!ly affected if load follow-ing reduces the magnitude of available fish and wildlife resou.rce.s in the project area and if load following makes navigation of the river (by boat during ice--free months and by snowmobile during the winter)more difficult or hazardous. Moreover,if load following increases the likelihood of ice jams and flooding dO'Wnstream,the chances of economic losses due to flooding would increase. ... l r r r r [ I I r I r I [ 1 , 4-UNIT 6-UNIT POWERPLANT POWERPLANT SUSITNA PROJECT WATANA2185 COST ESTIMATES (Category 1) FOUR AND SIX UNIT POWERPLANTS (Millions of Dollars) .(;: EXHIBIT 7.1 51 72 54 III 17 3 752 110 36 113 72 12 31 16 79 21 14 214 405 5 325 29 2543 141 3432 . 382 2925 366 3291 51 57 54 III 17 3 773 110 36 118 55 8 23 14 '-3.) 14 12 214 405 5 317 29 2482 367 2849 352 3201 137 3338 •.-_..~,..-.._--..•'"...I'",,' o.......l.;;,.1/ ITEM Land and Land Rights Powerhouse Reservoir Clearings Diversion Tunnels uls Cofferdam DIs Cofferdam Main Dam Relict Channel or Saddle Dam Outlet Facilities ~lain Spillway Emergency Spill~ay Power Intake Surge Chamber Penstocks Tailrace Waterwheels,Turbines &Generators Accessory Electrical Equipment Misc.Power Plant Eqqipment Roads,Rail &Air Facilities Transmission Plant General Plant Construction Facilities Mitigation SUBTOTAL Contingency Allowance (15%) Total Construction Cost Engineering 6<Administr:'a tion (12.5%) Total Cost -~3n '82 Price tevel~ Escalation to ;;an '83 (4.3%) Total Cost -Jan '83 Price Levels r r f r r I 1 I . I f ,\1III \ \ I I I ( \ ~.. I ! \\fII\ " III8 !~~~\\III\J, \ , -' ~-,I"-0::1l:cIX1\.lJIIII ",I Oi/\1:t~.~I" Ij f,I •.,:"....:A I ';" , \ I I I I '~I.' I I I \ \\IIII 'f. l' I I I \ 'f, \ \ ., \ \ \ \ \ \\'~. I ! \ \ ~..'.t~l I I , \., \ {, I II I .. I /'/ ,1.1 1/' / o' \ \ \ J \ \ I ( I 1, \ \ \ \\,, \ J i; I ,I I I I:\, \ I I I I i I I .' 'I \ / I I •I 1 \ \. I I I i I l< I "I~~\I,I;~\\,,1 \\..I §~I 1S)I ..~IN1N1I\I I \\I1I(\\I,I \\'."\\ \...'~"-,....... '. ~. .....,\ -""""'\" ......'. " \t \,\I ' , \\I l I I I I 1 I I I, (I I I I \ \ \ \\\ ,. rt, \ \,.'"\.\\\\\\\\\.,"'\,~ I \ \ \\. \ \ =l '\ \I" ;1 '(.r''\ \ \ ,j" I .\ I ".. .' • , I. I" '~, I • \ \ I I ~'.{ '. .I~l:,:, t ! ! !I I r J .I, I I I j I;~ 'i,. ,\\\1 ~l'l ~I~I '"fN'.Ij !I\ \ \. \ I.. " \ =/~,f'I.I'".. .: I \ I ,,I ,. '. I \ t \, ., -l-."..' J ,'.'"(.'", ·i I i 't" I' \.'..•fl J ,, J' I I I, •~I'/,/': I lf:If I ! II II f '~ I ~ 1m l,fJ IB I r~ I};'] I•·ii; ~f; I~} E'~~' '.f'l,ir; I I I~ I ii I Ij\J 4 I ('I~,~ EXHIBIT 7.6 51 57 41 104 17 3 549 110 36 129 COST 76 8 21 13 49 14 12 214 405 5 272 29 124 2996 2215 335 2550 321 2871 Land and Land Rights Powerhouse Reservoir Clearings Diversion Tunnels U/S Cofferdam D/SCofferdam Main Dam Relict Channel or Saddle Dam Outlet Facilities Main Spillway Emergency Spillway Power Intake Surge Chamber PenstocY..s Tailrace Waterwheels,Turbines &Generators Accessory Electrical Equipment Misc.Power Plant Equipment Roads,Rail &Air Facilities Transmission Plant General Plant Construction Facilities Mitigation SUBTOTAL SUSITNA PROJECT W!TANA 2100 COST ESTI¥ATE (Millions of Dollars) ITEM Contingency Allowance (15%) Total Construction Cost . Engineering &:Administration (12.5%) Tot.~l Cost -Jan '82 Price Levels Escalation to Jan '83 (4.3%) Total Cost -Jan v83 Price Levels I I I EXHIBIT 7.7 COST 51 55 30 100 17 3 353 110 35 128 61 8 20 12 43 13 12 214 405 5 243 29 109 2637 296 2244 284 2528 1948 SUSITNA PROJECT WATANA 2000 COST ESTIMATE (Millions of Dollars) ITEM Land and Land Rights Powerhouse Reservoir Clearings Diversion Tunnels u/S Cofferdam DIs Cofferdam Main Dam Relict Channel or Saddle Dam Outlet Facilities Main Spillway Emergency Spillway Power Intake Surge Chamber Penstocks Ta.ilrace Waterwheels,Turbines &Generators Accessory Electrical Equipment Misc.Power Plant Equipment Roads,Rail &Air Facilities Transmission Plant General Plant Construction Facilj.ties Mitigation SUBTOTAL Contingency Allowance (15%) Tota.l CongtructioIl Cost Engineering &Administration (12.5%) Total Cost -Jan '82 Pric~Levels Escalation to Jan f83 (4.3%) T.otal Cost -Jan '83 Price Levels II lE l~ IfI II I U .·1..~~J..( ::J II'! I fJ " i? f I t••tIe lt~ I t'i l....."."t I 11~.:':f I l " J.:JJ I ~.if~ I ~j EXHIBIT 7.8 99 caST 51 52 21 102 17 3 238 110 35 130 51 7 19 10 38 13 12 214 405 5 215 29 1778 2414 275 2053 262 2315 ..........._-", ITEM SUSITNA PROJECT WATANA 1900 COST ESTIMATE (Millions of Dollars) Contingency Allowance (15%) Total Construction Cost Engineering &Administration (12.5%) Total Cost ...Jan '82 Price Levels Land and Land Rights Powerhouse Reservoir Clearings Diversion Tunnels u/s Cofferdam DIs Cofferdam Main Dam Relict Channel or Saddle Dam Outlet Facilities Main Spillway Emergency Spillway Power Intake Surge Chamber Penstocks Tailrace Waterwheels,Turbines &Generators Accessory Electrical Equipment Misc.Power Plant Equipment Roads,Rail &Air Facilities Transmission Plant General Plant Construction Facilities Mitigation SUBTOTAL Escalation to Jan '83 (4.3%) Total Cost -Jan '83 Price Levels ••••~..,.,.• .~.t'9 t:t> i m X ::t:-OJ -I..... Co !!II/W'MII,'~"~~ ~~-~ 1!1>~~',~~,~-~.~I'::::!,~~. 1,763 1,900 ~\,...;:~:.';:.~1 1,987 2,000 ~~..:~--~ ~ ~)~ .....J'''',...,....,.,..-' ~ Watana Alternatives 2,100 2,311 ~ ~ 2,,185 2,644 ~ l..... ~: ~-::> Devil Cany~ 1,445 1,891 ~.....1""""" SUSITNA PROJECT COST ESTIMATE DEVIL CANYON PRECEDING HATANA ALTERNATIVES (Million Dollars) ~ "!oi~::;roc;t,.f!P:4!lAt:;;r, ~.;...~ TOTAL CONSTRUCTION COSTS - Jan.1983 Prices Reservoir Elev. ~ 4;-,-:~~~~c.."') .---....--~..~ ~ h'""~-::...."" ~~'ilii!i"1'\i;',,·,··..·t'a<.·:···t;;·r'·ir~-;·<',,"<""'·•.i'....""",~~~~,..W;;;t'.·I;;,¢ji',~,'<i'l,~~\l(·~~·,'i14~;,~.w,(!'...$'~..~0,~iIIlltfJllIk4~) ,.,"."''0'. "'\H ..._.........~ ~ J -~.,.--:;:-~-.-~ 16 20 241284 /~~ V .~\- I \ I \ ~J o o 10 EXHIBIT 7.10 20 50 60 40 70 30 80 90 100 ALASKA POVvER AUTHORITY SUSITNAHYDROELECTRIC PROJECT UPDATE TYPICAL DECEMBER WEEK.DAY HOURLY LOAD VARIATION SEPTEfvlBER 1983 Q <:o ...J ~« I Wa... u..o I- Z Woa:wc. • m X J:-txI--i "•-....& ~!!SI • ve • ::~~ ~.- ~",·.c'·"·';:'~w,;,..,,~_ t"!t~'~6c·,~~i~~.-.~',,;,;.~_:..... ~""""-"~~J ~"""'~.....~~~~~.:~~~-~ POWER AND ENERGY PRODUCTION WATANA 2185 (Load Following Operation) DORMean Forecast Year 2020 Demand Level .l"""""" "c::'-~'7"r:';'0"",h ,>,.,••,~...,I,."b;L;;'!:"'I;u A""".4,,·,;;,,;.....~"'i?"""'+;;k\-~~I:>?~..'''''''''''''''',~Ii;jj::'"'~~i('A .~.t£}.U21IlUUJilJAiiO iUi!i$@ ideM ~ '~"4:,- .1"'-""'"" \.a...~'....-\'f ~.•~'•. e ••:,,;r ,-.,, ~r"....'"..... ,~.:......, ''M''''''''l;L..:..::;.;:;.:':';(:::,> (a)Corresponds to four unit capability and is based onrnonthly net head and turhine efficiency. l' i,! ;MONTH WATl\NA ALONE DEVIL CANYON WATANA AFTER DEVIL CANYONJ Cap a-Ailerage Reliability 'Capa-Average Reliability Capa-Average Reliabilitybility(a)Energx.Energy bility(a)Energy Energy bility(a)Energy Energy(MW)(GWh)(GWh)(ttW)(GWh)(GWh)(MW)(GWh)(GWh) Jan 699 3l~5 290 667 334 239 700 366 247 Feb 676 286 225 667 303 215 674 323 2iS Mar 655 264 182 668 299 213 649 310 212 1'1:Apr 634 21~3 158 665 273 273 "625 263 10l~..~ May 630 228 139 663 267 188 621 211 95 Jun 664 188 60 665 255 201 656 180 180 l)Jut 714 216 82 669 239 200 708 179 133 Aug 747 345 314 654 238 219 747 262 180 Sep 765 283 274 642 257 257 766 249 249 Oct 766 301 191 655 250 203 765 343 308 Nov 749 398 287 667 308 224 749 348 236 Dec 724 400 362 667 359 256 726 402 269 .P&"11K_.BT".~~~~<~i~,~~~, m X :I:-to-.-i -...J.-'" ~~:-;~~ ~~~ r!'!PJ ;~ ~.~.~-.,.~_:~ ~~ ~,-<~"..,=,;;','-'.''''.'~.'..i!''''''-1!"" ~~ :""?:"'" )":'4.,,.''l-"""~"""~.,~"',. ,~--- .-..-...... ~ ......--...-- POWER AND ENERGY PRODUCTION WATANA 2000 (Load Following Operation) DOR Mean Forecast Year 2020 Demand Level ~ -,..........- .~. ~I .,,-_......• ~ .,~ .~ 1""'.r"'" !If;"-,-""";•.,':;::~":l ~~"";"""'; (a)Corresponds to four unit capability and is based on monthly net head a.nd turbine efficiency. ~~ "'" ~~~:'i'< ~ ....~..~~ MOti"'TH WATANA ALONE DEVIL CANYON WATANA AFTER DEVIL CANYON Capa-Average Reliability Capa-Average Reliabi1ity Capa-Average Reliabilitybility(a)Energy Energy hi1ity(a)Energy Energy bilitll.(a)Energy Energy(MW)(GWh)(GWh)(MW)(GWh)(GIill)(HW)(GWh)(GWb) Ja.n 470 167 163 669 261 229 457 197 167 Feb 444 127 lt2 669 21l~210 423 153 144 Mar 420 124 III 669 208 208 391 139 114~)11 l .11 Apr 395 114 103 664 198 198 363 112 20 May 388 189 91 659 286 180 360 151 151 Jun 426 261 55 663 296 190 416 158 158 Ju1 490 263 202 667 284 186 498 185 70 Aug 534 309 251 661 276 228 544 236 198 Sep 555 272 2.09 657 282 2.69 560 236 11~3 Oct 553 202 123 663 267 189 553 236 236 Nov 533 211 164 668 281 210 .528 232 171 Dec 501 231 230 668 291 243 494 232 189 .• .~If ~". .'.'<• •<•\'.••••••.'0 J.'~•• '... .....'-......-..""t.~,,~_.€~.~:';~.; m X::r:-o:J---I -...J.... CN Cost Construction (c)Investment (d) ($Million)($~fillion) ~~~~.............~~ rZ;L"'""';"';'~"l rn~,~~••~.,~l,~;;~".;~..";"'fo$~4'>""'~~\:..i'r.:....:.:.,..·.~"""-.>-o',:=.:,~l ~,.,..'.~.~~;J ,,,-<,",,~r:,-u~ _""'Ii,_ ,.~,...,;.c;:; ~...............- Energy Production Ave,rage (b)Reliability (GWh)(GHh) SUSITNA ALTERNATIVES ~:.r~ Installed Capacity (a) Initial Ultimate (MW)(MW) ,':_,.;1-_ ~~.~ ~ ?'c lola tana 2185 724 1088 3500 2265 3338 3785Watana21006139203005224029963397Watana20005017482470181526372948Watana19004066091880150524142699DevilCanyon5015012260200515541762 (h)Based on 4--unit powerstation,with system demand constraints __Si_~gle Project Cd)Includes interest during construction at 3.5 percent interest;no real escalation of const.ruction cost was included. (a)Average-plant capability in megawatts for December (e)January 1983 price level ~-......,-~ ,~~•••••.",•••••w·,,,,,,,"',·1111·.'."··,··e.·".!!,*",3.%$£tiiifJi6.M4,~flilSZ;''"PiW.ji#.'''.i.If.~~1);'''.JQAq 1£4""c t $2.•".'1 ••$2£,13.1111 a ..- Combined Project Watana 2185 + Devil Canybn 1398 1752 6820 5120 4892 5547Itf,.; J I!'Watana ,2100 + Devil Canyon 1274 1572 6240 4900 4550 5159 Watana 2000 + Devil Canyon 1162 1410 5410 4300 4191 4710 Watana 1900 + Devil Canyon 1066 1269 1.650 3835 3968 4461 m X :t: OJ -i ....... -olio ~ 16 20 24 INITIAL LOAD ,...........~~ MODIFIED LOAD 4 8 12 HOUR C:OMB1NED BASE LOADING AND LOAD FOLLOWU'JG ~«o ...J PLANT MAXIMU~ RATINC.:l 3: ~ljPjPjP ••s»»».,r,."s;,••",,1 PLANT MIN RATINIG _.v«o:r««f««4««Q«'·'cq<~ 2024 ~O INITIAL LQAD 16 ~~~~~ MODIFIED LOAD ----...-~~~~~.~.,IF'..._.;~f--_••J ~.~r>~~.r~'-~;~:~:!,ti';4-.__~;:~:,.;.:l '._t-":"7~-.~_~~~."t~' 4 8 12, HOUR LOAD FOLLOWING ~~~ ~ o - PLANT MAXIMUM RATING ..--,----"- '1:l "."',"...-...,. " .INITIAL LOAD ~~ fT~ SEPTErvlBER 1983 MODIFIED LOAD ALASKA POWER AUTHORITY SUSITNAHYDROELECTRICPROJECT UPDAlTE COrlVENTIONAL HYDRO SCHEDULING WITH OGP MODEL 4 8 12 16 20 24 HOUR BA.SE LO.ADING o«o l~---~~'~'/(;~/:~h7n"7""'~~~>'s,>~, >,."II Mjt --»,- ~~ PLANT MINIMUM RATING D ,I m X ::I: CD--J.....-01 ~~~~_'~:~,:L-'~~~";:_:~1m~·.~.~".~4...."'~ *"'k\J~ ~ ~~,._~r ~'...........~~~~~~ """''''''''''''''--~~"t --~~-~ ~.... ~~ '-,.,~~--- ~-.-. (a)lncl udesf)xlstfflfJ generlttlofl pl21flt'lessretlremeflt. ~~-~~-~~, E~ANSION PLA~N YEARLY MW ADDITIONS DOR MEAN LOAD FORECAST NON-SUSITNA ALTERNATIVES OPTIMUM NWN-SUS ITNA COAL ONLY CHAKACHAMNA- POOL TOTAL COPollUSTION COMBINED TOTAL Ue)COf43UST'ON TOTAL (e)COMBUSTION COMBINED TOT~\L(e) YR PEAK ENERGY CO~IL TURBINE CYCLE CAP AB I UTY COAL TURBINE C1lPABIILlTY CO/~L TURl91NE CYCLE HYDRO C,lpABIILITY (M\lO (GWh)(MW/l (MW)(MW)(MW)(MW)(MW)(MI~)00if -(M~rr--(MW)(MW)(M~) 93 867 4167 474 1369 400 1295 84 237 195 141 '1948824237136912958lt149!5958964306841382841308142496913438784137884130416U150497929446784139684132284\1522989464548137012961496 99 963 4629 84 1454 84 1380 1496 0 979 4709 1453 1379 84 1579 1 loOt 4813 1453 1379 1579 2 1022 4916 168 1479 168 1405 168 1605 111 ,3 104:5 5019 1479 1405 1605 4 1064 5122 84 1563 84 1489 1605 5 1086 5225 1542 1468 237 1821 6 1115 5369 200 1742 200 t669 H321 7 1145 5513 1742 1669 1821 8 1175 5657 1742 1669 1821 9 120~5801 1742 1669 1621 to 1234 5954 1742 1669 1821 11 1263 6085 200 1797 200 1724 200 1076 12 1292 6229 200 1820 168 1714 400 2099 13 1323 6376 1820 1714 2015 14 1354 6526 1820 200 1914 84 2015 15 1358 6680 168 1891 1817 2002 16 1418 6837 84 1891 84 1817 252 2086 17 1451 6999 200 2007 168 1901 84 2086 18 1485 7164 2007 1901 2086 19 1520 7333 84 2007 84 1901 84 2170 20 1555 7.505 84 2091 200 2101 84 2170 ".I ..P 8. .•.~.I,'.••"_•0.".• m X:r:-tr.J -i '".-0') .~~. 2006 1205 1205 1218 1214 1385 1359 1359 1442 1442 1468 2053 2053 2032 2032 2032 2032 2032 2032 1876 1698 1782 1782 1769 1769 2006 2006 2006 2006 c~4 585 311 TOTAL (8) SU~ITNA CAPABILITY (MW)(MW) ~'":"1 237 ~_. ,......~<~••,~~'..•..: WATANA 2000 +DEVIL CANYON BASE LOADING 84 84 84 84 84 84 237 84 504 474 896 168 ~..,t~:':;::·:t.1~_·*....';f.:.,._l .....""'-, 2056 B53 1352 1282 1278 1296 1354 1354 1353 1353 1685 1685 1685 2272 2272 2272 2272 2272 2272 2163 1985 1985 1985 1972 1972 1972 1972 2056 20.56 --...." 36 459 608 1103 TOTAL (8)COMBUSTION COMBINED SUSlTNA CAPABILITY TURBINE CYCLE-.(MW)(MW)(MW~;(MW) q;(tIii'f,~ 474 .::. ~,~\l!I WATANA 2100 +OEVIL CANYON BASE LOADING 474 84 84 84 84 84 84 84 ~.....----.~.~~-~"'-'---'-'-'.~.........~~-- 336 COMBUSTION COMBINED TURBINE CYCLE (MW)(MW) -- E)(P ANS ION PLAN YEARLY MW ADD IT IONS DOR MEAN LOAD FORECAST SUSITNA ALTERNATIVES 1940 1433 1432 1362 1358 1292 1350 1350 1349 1433 1375 1459 1459 1438 2070 2070 2070 2070 2070 1952 1785 1785 1785 1772 1772 1856 1856 1856 1940 38 539 632 .....~................ 1209 ~'~ o ~.~ "'".Y~ COMBINED TOTAL (8) CYCLE SUSITNACAPABI L1TY (MW)(MW)(MW) ............- WATANA 2185 +DEVIL CANYON BASE LOADING 84 84 84 84 84 84 84 84 84 588 COMBUSTION TURBIN[ (MW) 4167 4237 4306 4387 4467 4548 4629 4709 4813 4916 5019 5122 5225 5369 5513 5657 5801 5954 6085 6229 6376 6526 6680 6837 6999 7164 7333 7505 867 882 896 913 929 946 963 979 1001 1022 1043 1064 1086 1 t 15 1145 1175 1205 1234 1263 1292 1323 1354 1358 1418 1451 1485 1520 1555 POOL IOTAL PEAK ENERGY-(MW)(GMh) ,"""'m...,.., <..': fa)Incl udes existing generatIon p I~nt less ret Irernents. 'tR 93 94 95 96 97 98 99 o 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 2020MW ~-~~~ l~ "t"hM m'._""'..•.2 l.)Jb>;Si.~~"""U$lib ,...,-*J!li\i"'ii~lI $...--IIU •a :_,-".$SlIW"'"2».1..-~.,.'~'~.-..~.S¥JU n L&"••11 1 l., ~~~..~,~~~~~...............~~~ (al loci udes extsrlnggenera1"lon p 1c!O+less retirements. m X:r: CD -t.......-...... ~ 13ft5 1394 1324 1236 1254 1312 1312 1311 13fl 1406 2012 2012 2051 2051 2051 2051 2051 2051 1901 1723 1723 1807 1818 1878 2031 1947 2031 2031 ~ 501 666 ~':.-'_;~~~_i~~.:1 TOTAL (e) SUS ITNA eN'AS III TY (MW)(MW) -. <,..."...:"~j 2Y1 231 COMBINED CYCLE-(MW) WATANA2000 +DEVIL CANYON lOAD FOLLOWING !"""""~t.<,.'1-';':;;'0 ,,"_~ 84 84 84 84 84 COMBUStION TURBINE (MW) "e~~ /"fi-,'1I'-*;'-"~';';' ~ F.;t·:'...:,',.,,,-J 1501 1506 1436 1348 1282 1256 1256 1339 1339 1434 1434 1434 2090 2090 2090 2090 2090 2090 1929 1751 1151 1835 1822 1906 1906 1990 1990 2014 TOTAL (8) CNJABI L1TY (MW) ~~.'I\~,,~ 617 613 2"57 COMBINED CYCLE SUSITNA (MW)(MW) ~~ -"'rllii,I $II,;,"..,:J@ 84 84 84 -84 168 -- WATANA 2100 +DEVil CANYON lOAD FOLLOWING EXPANSION PLAN YEARLY MW ADOIT10NS DORMEAN lOAD FORECAST SUS ITNA AlTERNATI VES COMBUSTION TURBINE (MW) ~ 1618 1611 1541 1459 1393 1361 1361 1366 1366 1392 1392 1392 1455 2140 2140 2140 2240 2140 1995 1801 1801 1801 1812 1812 1956 1956 2040 2040 -- TotAL (8) CAPABILITY (MW) 'C--~...,--- ~, L ,...,..,- 124 685 84 84 84 84 168 WATANA 2185 +DEVIL CANYON LOAD FOllOW ING COMBUSTION TURBINE SUSITNA (MW)(MW) ~'~~ 4161 4231 4306' 4387 4461 4548 4629 4109 481:3 4916 5019 5122 5225 5369 5513 5651 5801 5945 6085 6229 6316 6526 6680 6631 6999 1164 1333 1505 ~j!~ 861 882. 896 913 929 946 963 919 1001 1022 1043 1064 1086 1115 1145 1115 1205 1234 1263 1292 1323 1354 1385 1418 1451 1.485 1520 1555 POOL TotAL PEAK ENERGY-(MW)(GWh) YR 93 94 95 96 91 98 99 o 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 11 18 19 20 -~~- 1 ifiJ m X :I:-00--f ".-ex> ~~.!:'i'I*":"'1~~':;.:.1 ~~)."':.;:i,~",,4£'.'.:,.~.'llL£",,"l __v"''''''4'r C W1llu4fli>t"~ .....""..,,',.,,\ ".-'"'~~""'-1It}!1':~~~-~~ ~~.~~~~~,""""""'\~,:J',~,~ ~,;-,~-.'lI;i ...\:'~~£.AL:~s-.~;.:;."_...a:=~ ~~~~~~~~".,--~r' ~.,'. NON-SUS ITNA SUSlTNA -Bese Loed lnQ SUSITNA -LOM Fo I low 1"9.. Gas/Co~1 Gas Coal Chakllchamna "ataM Watenll Watllnll Wata"a Watana Watanll Watan~Watana Only Only 2165 2100 2000 1900 2185 2 tr10 2000 1900 LUN1 LUF5 LNN5 LUE3 LYX9 LS59 LS61 LL73 LK19 LK21 UH9 l<1013- BOO 0 1200 600 0 0 0 0 0 0 0 (j 672 756 756 756 588 336 504 504 504 420 252 168 474 1185 0 474 0 474 474 711 0 237 474 711 143 143 143 143 143 143 143 143 143 143 143 143 0 0 0 0 1209 1103 885 701 1393 1274 1162 1061 0 0 0 193 0 Q 0 0 0 0 0 0 2089 2084 2099 2168 1940 2056 2006 20!1J 2040 2074 20:51 2083 1555 1555 1555 1555 1555 15.55 1555 1555 1555 1555 1555 1555 34.5 3'4.1 35.1 39.5 24.8 32.2 29.0 32.4 31.2 33.4 30.6 34.0 0.082 ~h183 0.053 0.160 . 0 ..036 0 ..160 0.121 0.086 ---- 30.84 30.84 38.34 37 ..72 49.15 46 •.75 45.55 47.08 47.49 45.40 43",20 45.26 46.78 47.62 46.89 48 ..60 45.25 4/5.90 44.58 46.20 44 •.10 42.66 42.83 43.85 50.33 56.02 50.98 51.83 4,0.55 41.01 42.90 46.40 40.08 39.95 41.28 43.49 377.7 420.4 382.6 389.0 304.3 307.8 322.0 348.2 300.8 299.8 309.8 326.4 ,2844 2929 3077 3128 3142 3167 ~159 3295 30tl 2964 2996 3111 •4890 5446 5070 5227 4744 4797 4892 5191 4593 4552 4664 4888 :-- l_ YEAR 2020 RA I LBELT S)STEM GENERAT I ON MI X OOR MEAN LOAD FORECAST QGt 10 C8pac Ity-MW Coal CT cccr Hydro Susltna Chaka..::h!lmna Tot~f 2020 Rellabl J Ity Peak Demand J Reserve LOCP -DIY Total Economic Cost 1993 S/MWh 2010 S/MWh 2020S/MWh MJ 11tonDot htrs 2020 Cost Cum 2020 PoW. Cum 2050 P.W ~~,,,,,,,~,~~~~~ ~,,J ".'.'"~.<! ••' • •,~..~'.c ,.'-,.• "-'-~ ;'\ 'J -..) 4';~.W -<: ....,...•.f.f':;.11 ; "lA'<S-.~.....6~,t{"'.,.'",'...,. •~.....is •~.~•\~,IT'}'..,.,s.:"=-_.1 •"• .lJ • •'"''-"•il',,'41§f ":..;,. m X :I:-tD -f "'"....co ~'~~'I\v~~.;i~"-..,....J "'-,,~'!-,."'~'"'~-,<~ ~...........~~....,...... ~;~ '!ilo.'....;.,..~. "'-"~~~~ ';l,l ~tiff:"i';,~.:!"~~~~~ YEAR 2020 RAILBELT SYSTEM GENERATION MIX S~A-NSD LOAD FORECAST ~~"~.Q~') t-o-- NO~SUSITNA SUSITNA -Base LoadIng ~TNA -toed Following Gbs/Coll'l Ges Only .cOl'I Only Cha kachl'111nl'Wefena Wl'tanl'Wetl'n8 Wetl'ne Wetllne WlJtane Wl'tene Wetene 2185 2100 2000 1900 2185 2100 2000 1900 I l~i t1'lA9 I U~9 LOG9 Ll79 lKBl LLA5 LLB3 LtW9 001 LK27 LlW3 r .- 1400 0 1400 1200 0 200 200 400 0 0 400 400 420 156 672 84 588 588 336 420 504 504 168 336 474 1422 0 711 231 231 711 711 2'57 474 474 474 14S 143 143 143 143 143 143 143 143 143 143 143 0 ,0 0 0 1223 1095 885 701 1387 1273 1162 1061 0 0 0 195 0 0 °0 0 0 0 0.,--2431 2321 2215 2333 2'191 2263 2215 2375 2Z7 2394 2347 2414 .I 1124·1724 1724 1724 1724 .124 1724 ,"24 1724 1724 1724 1751 f , 41.5 I 34.7 28.6 '55.4 f, 27.1 31.3 32.0 ,37,3 46.3 38.9 ,36.1 40.0, 0.025 '.-P&124 0",,077 0 ..082 L.0.085 0.019 0.085 0.025 -----";:-~"--~-. 35.48 35.4b I 40.18 36.64 48.53 47.60 47.56 49.06 46.10 45.53 44.26 47.67 ~9.95 72.90 55.06 52.23 40.69 42.91 44.27 51.58 39.6~38.95 42.69 46.67 6.3.65_91.01 61.72 59.05 43.83 46.43 49.69 57.35 43.2~45.38 47.32 53.561-00--, 52.9.0 756 .•5 513.0 516.6 364.3 385.9 413.0 476.7 359.3 377...2 393.3 445.2 3878.1 4/,48 3931 3844 3373 3422 3518 3949 3240 3253 3354 3784 6795.0 8945 I 6158 6666 5225 5484 5754 6528 5164 5292 5453 6187 ,~-.I f __ Ob"ID Cl!IJ."-aclty -MW CotJl CT ccer Hydro Susltril!l Ch~kechl!lmne Tote I 2e20 Re Ii eb I I tty PetJkOemand %Reserve LOlP -DIY Totti I EconomIc Cost 1993 S/MWh 20toS/MWh 2020S/MWh M~.I J Ion Do f Jers 2020'CoST Cum 2020 p.w. Cum 2050 P.W. ~~...~..~~~~"~~~~~i,iO'~~~~.~ o "....cJo._""•"fp.•,~, •~..'I:"."\y.,,'~."...!Qk ••otl •-...)-'~..,N\;a."3 ,..'••.J ,~...•• •••.•.•......,.....I ..'.-'"•••• •.•..6.'.'..'-"•~~,'"J-•."•., .""•.....'./'.•c;.>-., •'.,•...'.•~..',. N ;;~.".~,,,,......""~v.._••"""".~..-.,.'",'.....-<.l '.\;'."•.'"."'f'..\';"•Ir t.·....·',,···f.1Io )0 • •t •I ,,'!I/,~(-'....""""",,,,,..~.:.',...,,"'~ Lf>0 ..' m X::r.:-OJ -t ..... ~o .~~~ ~r"~""~~~~~"I~'::"_J '_"_1 f >,_1 ..._:i,·~1"•.~' f:,.ec'~ ~~~"~................ ~~~~".~. ~ ~~~ . I 1 ~"SHCA-NSD...........=:::;;:::::o...l_---=~..I SEPTEMBER 19,83 1900 2000 2100 2185 WATANA ELEVATION (FEET) ALASKA POWER AUTHORITY SUSITNA HYOAOEl·ECTRIC PROJECT UPDATE PRESE'Nl'WORTH ANALYSIS -,.,_.i- ..............JiiI . o I •••DOA-MEAN I .I I 0I ;~~~ 1500 2000r' •••••LOAD FOLLOWING ---BASE LOADING -5001 I I I -1000 'I ._,'!I , 0)500 t"I I--U. W ZtJJ to I- UJ Z ~ 6«)- ~.1000 r I .•.-...J -J-:E, ""'" ~:w..~.-.-....~ 'l~' , !,; .rr, ,,~"'I L·~_.:..~;~~t~~!<...i!<¥Ri.~...~~,1':';:'~~"''''',"f,dl<'''""~,'''''''''"''''''_:<i:M ...!¥.~·;w,~~.5 hi ,e5O.WEi.$.P4dett 'lp*,il J,:,I'1'ffSHI:;:d'flJtiI!MM!UJdaM.:.U. 0:: ':~ o .0 (} 218520002100 WA TANA ELEVATION (FEET) 1900 I DISCOUNT RATE 3.5% ~,... _. I;J' 5.0% ----, .~6.0% ~ ~ ","----,, EXHIBIT 7.21 ALASKA POWER AUTHORITY SUSfTNA HYDROELECTRIC PROJECT UPDATE AATE OF RETURN ANAL YSIS 2000 --1000 1500 C)z 0 ~<69'0 z 1000..J 0OJ:Jen...J<::ECD I '-oJ Ien en 500t-t- C/')u::0 w U Z,....,W Q I"Q en ,z ,--0WIZ«( () J:en '-oJ -500 SEPTEMBER 19831.......--""""'----------...... I! l~ I~ ![1 lID t fj ;.,{i ,I ·....,,·~1 ,1 '. 4 If''1 ",~! ~ ,j I ,11 (' :i f t'.,i;1 .. )1 . d I t It: !L I I f' 1 l- f' I .~ 432 WATANA 2185 1 WATANA 2000 o '------.r..---A.-_-'------IL--..-...I-__-""'---~__...... o $BILLION EQUITY CONTRIBUTION NOMINAL 21----i------~-----+-______jf------+---+---+-----I 41----+.--+----+--------+------+--+------+-----1 EXHIBIT 7.221 18 I--~----I------+---+----+----t----+-----I ~...14 1-----..::1 ~-4-~I---+------+----+---+------tz-a:w~..c 12 CO AL --~........-4--:l1Ilk+-------+--t-----+---t 03: a.~ u..a: o w 10 1------4-----.+-----+-:::IIIIlk---"""'i---..-0. U)CI) 0"-uZ ~~8 GAS/COAL -+---------j~IlI::-f---~---_+__-----t ~ W5 6 D---~---+--~-I---+__---74:...-~------_+__~_I ::I: ~ ALASKA POWER AUTHORITY SUSiTNA HYDROELECTRIC PROJECT UPDATE 1993 WHOLESALE COST OF POWER VS~ST ATE EQUITY CONTRIBUTION DOR MEAN CASE .......J......-........-...~_<E_.P_T_E_M_'B_.E_R__1 9_.8_3 -------_...--1 ':'1 ( ,I i ! rl i f; iJ I P~L·r·..'1ii1., '.j.'.••.'I..f!~!~ -'..1........,f·J.•...~,.1 :f" I f' I."i~, i I 1 ft•..i If : !.fr L J 1 I l~) I j I f II I I 432 WATANA 2185 1 WATANA 2000 IE.XHIBIT 7.23 4 I---~~---+---+-------+---.......f-------+---__+__-_I 2 I--------I~----+------+---+--.......f--...._f__----+--__i $BILLION EQUITY CONTRIBUTION NOMINAL o .1...-_&...---'_---&._---'-_---'----'----'---' o 16 ir---I....3ik---+---+---i---+---+---t-----i 18 ~~----+-------+---+--=---t---+---t-----i ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC P,ROJECT UPDATE 1993 WHOLESALE COST OF POWE.R YS.STATE EQUITY CONTRIBUTION SHCA-NSD CASE SEPTEMBER 1983.,. I ! }~ ..[~;.,I,;, IE 1f.J .".r'.t I r J i I ! Ii I {, I 1: I Ii ' J I I t I (;J I I I m X :J: to --I '"~ ~ A• 2020 • --.,"7""-"j ~~,'~~"~J ,',~,~_:~,"',.~---~."i~_'4 _,- • 2015 ~"""'~"""'" -~ 2010 ~-"_<om.~~~toP~...~:~ 2005 YEAR "II'f,,;e"""~fl ~---""",~~~,~~"""""",,~-~~ ~'-~ 2000 ALASKA,POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE WHOLESALE COST OF POWER (WATANA 2185) SEPTEMBER 1983 ,~.---~.-"-....,:....--.-'---...:......4:..•..-.;;.-._-,~,··..---.....;~1 '~;~:;;iz:~;;::=;;Z=::s::::z2=::::==l.=cS2_;.i..2.=.;...~~~.;.......~:,j~li£$~::~i~....:..:..4:.._,;:...__.:.:.i::..;.......~"'~~;.•.:;:;,;..:::-..::.s..-----'~L,_~_,..ti 1993 1995 .....- -WITHOUT SUSITNA:GAS/COAL WITH SUSITNA ~..-.~.-r:~''i~", j , ~~~~ ,I I--DOR MEAN FORECAST WATANA2185 ,,",,,, ,-'-~I ",ii""-.,.,...""..,... I'STATE eQUITY -/'CONTRIBUTiON (1983$: ~~I"-V ----""."""$0 ~-"I "~~,..,...---S 2.27 BILLION-",.---------1------- -INTEREST R,ATE 10" I ,,I I ,I I I ,,,,,,I ,I ,,, ~~,- 't :t ''''~''I '..~.,'~'~·~~.:~:I;ld·.;~W_'.'~'·I·i.~~n.~,.I;.I.I.·~~~_~_~"I~~·.~..~-~.~~~tl·~~,.~.·~5~4~~',.~A'E~a~,.~~~az,._nM~~~'~~~'~"~_~~~'~i~~aO-.ft.__~_~~~n~~~-~..~"·~M.~--~P_~_._~.~_.H~~'~~1~iMZt;'__4U~W_A.i;I•.l Ui.$.MPgAq,~,~ ••.?•~.""Vfit"•'!'~,~....• "........~III --... A _. • m X :J: ~ txJ -t "N U1 • ",'1"~~:r""'II.,•. .~-,_..e',"_."., ......,..,."..." '/-~ ._,'._"J. -;.~- • --,,,-,'-{ 2020 ., '.--....~ ~.~~.--....,-------..~. 2015 "'-"'--.~~.J_M,~ 2010 ~;.tj"••.~._.....~.';·4~'_'''~J1~ 2005 YEAR ~;:7~~;r 2000 ~~--..,~~~ "~~, ALASKA POVJER AUTHORITY SUSITNAHYDROELECTRIC PROJECT UPDATE.. WHOLESALE COST OF POWER FOR WATANA2000 SEPTEMBER 1983 _"__"~':t WITHOUT SUSITNA:GAS/COAL -----WITH SUSITNA 1993 1995 r- ,I--DOR MEAN FORECAST WATANA 2000 ,--.-*',- -/' ---.... .STATE EQUITY ,.-",-CONTRIBUTION (1983$).."",...,- .~ r$O ~~~-~,j ~~~~ /,,----~-~,.. ...'P'....:,t ---,'P'$1.61 / BILLION---....---: -#INTEREST RATE a 10% I I I,I I I I I I I I I I I I . I I I I I I .-.~~ • ~ ~"''''_."_~._c_~~"~_<",",,~_,,....~~.",;,,;;~,,,_._.,,,;',,,,.~_._,,_..~...._...",~,;,~_';';"...,:~-_....,.~~__.".~~".<.._~',~.;...._."'_'_'.~~,.--..,-:........,-.".__ ~""....-..-.---------~--------------------------------.----------------,.I • COo .'a J*~()&I •i.6.""•f "&... •'.~'~,._(ll " ,.~-<.~----'--",. "';'~~C~''~·-..,~o""''-,-.--.·."'•',,!}.:.,.>,...1.&':·1i·....k~·"·'.IIJ.lJlltr!j'lt~!".r...A'N"~"...;>~,,··~'"·;lt~~....-'-;"'-"" s:: ~ .Jt: "(;. 70, # 'I a: 60 0 W ,~ 0 50~ LL I fill a 40.... tI) 300 0 W 20..J< 10U) W ..J 0 0:I: ,~ ---,--",--;;;-;--::--=,;. "'Om DI X~J: '-'0; o -....-f.....,,, ~m "'!".,",~";~~~~_:~ ~.~"~ --, ...~-~ ~ ~" ~-iH;~i ~......... ~"':-~ ~.........---.. f!'_d;;J':!;;,_ ~~~~ ~"'r:,,'''''''*-'"''''' ~~~ ALASKA POWER AUTHORITY SUSrrNA HYDROELECTRIC PROJECT UPDATE WHOLESALE COST OF POWER FOR WATANA2185DORMEAN (WITH $3.28 BILLION STATE EQUITY CONTRIBUTION) SEPTEMBER 1983 $3.28 BILLION STATE EQUITY CONTRIBUTION IN NQMINAL DOLLARS. ALL COSTS IN NOMINAL DOLLARS. ---'--- ,2165 Level 3.280 Equity ttm coo 2006 rww..C1lSTSIN "lLLI(It •._~z=_=~..::==-,¥£Xi" T.tllEnerty EIIIIJY OGP OSP Debt Service LESS:Debt Service LESS:Filll1 et,itd OGP ~ Costl't\''1QIt Vflr UMn ltU losses IItYESTlOT SUSl""COST WAlAMA EMHIIIJS 'lEVIt'S CANYr.Jl EMNlr~D!bt Snvict RenftAls Fu~'O!oer.""'in.TOirt.1COOIf)-.-~,--..--1m 4166.~4041.89 124.00 724.00 241.31 29.91 211.40 18.12 ".70 34.00 308.82 7.64 1994 4237.00 4109.89 724.00 124.00 241.37 'lJ.97 211.4Q 19.94 48.60.,36.30 316.24 7.69 1995 4~.OO 4176.82 724.00 724.00 256.04 'lJ.97 226.0;21.23 54.40 33.40 340.10 8.14 1996 4381.00 4255.39 735.60 124.00 256.04 'lJ.'f1 '137.61 25.54 60.90 41.0('1 365.il 8.58 1m 4466.90 4332.89 735.60 724.00 256.04 7!}.97 £37.67 27.20 67.00 40.80 373.47 8.62 1998 4547.90 44U.46 748.90 124.00 256.04 29.97 250.87 32.28 76.10 44.10 403.35 9.14 1m 4629.20 4490.32 748.00 724.00 2'56.04 29.91 250.87 34.38 90.10 47.40 "22.1'5 9.41 2000 4709.00 4~7.73 748.80 124.00 256.04 Z!I.97 250.87 36.61,101 •.50 50.80 439.78 9.63 2001 4813.00 4668.61 764.00 124.00 256.04 29.97 2b6.S7 43.00 116.40 55.30 481.57 10.31 2002 491~.90 47~e.42 781.80 724.00 256.04 29.97 183,87 50.06 131.60 57.90 523.43 10.98 2003 SOt'1.10 4968.53 799.90 124.00 251>.04 "tI.97 001.97 57.85 149.90 63.10 572.82 H.77 2004 SI22.00 4968.34 799.90 724.00 256.04 'J!1.97 301.97 61.bl liO.80 67.80 MYJ..18 12.12 200S 522".80 ~.06 799.90 724.00 256.04 'J!1.97 301.97 65.62 194.40 71.90 633.89 12.':S1 2006 S31}'.00 5207.93 1564.10 1400.20 256.04 ~.97 818.77 'J3.b6 1027.08 87.31 0.00 74.00 1188.39 22.82 2007 ~t~.OO 5347.61 15M.10 1488.20 256.b4 19.97 832.17 93.b6 1040.48 92.99 0.00 78.00 1212.27 22.67 2008 ~.OO 5481.29 1564.10 1488.20 251>.04 29.97 982.76 93.66 1091.07 99.03 0.00 83.90 1274.00 23.22 2009 5801.00 5626.97 1504.10 1488.20 256.04 19.97 882.76 93.b6 1091.07 IOS.47 0.00 89.30 1285.84 22.85 2010 S94S.00 5766.6S 15M.10 1488.20 256.04 'lJ.91 882.76 93.M 10'91.07 112.32 0.00 83.50 1286.89 22.32 2011 6005.00 590'1•.45 1564.10 1488.20 256.04 29.97 882.76 93.66 1091.01 119.62 0.00 83.00 1293.69 21.92 2012 0229.00 6042.13 1564.10 1488.20 256.04 19.97 882.16 93.66 1~I.07 119.39 0.00 90.'50 1290.96 21.31 2013 6376.00 6184.72 1564.10 1488.20 256.04 'lJ.9i 882.76 93.b6 1091.07 135.69 0.00 85.70 1312.45 21.22 2014 6S26.00 6330.22 1564.10 1488.20 256.04 19.97 882.76 93.66 1091..07 144.50 16,70 92.30 1344.57 21.24 . 2015 WIO.00 6479.60 1564.to 1488.20 256.04 29.97 882.76 93.66 1091.07 153,99 16.70 96.60 1358.26 20.96 2016 6831.1()6631.99 1593.50 1488.20 256.04 29.97 882.76 C)'J.b6 1120.47 174.20 35.10 103.90 1433.67 21.62 1017 6999.00 6789.03 1637.30 1488.20 256.04 29.97 882.76 93.M 1164.27 196.49 58.70 113.80 1533.26 22.~ 201e 7163.90 6948.98 1670.70 1488.20 256.04 29.9'1 892.16 93.66 1197.67 220,94 103.60 123.60 1645.81 23.68 2019 7333.00 7113.01 1670.70 1400.20 256.04 19.97 882.76 93.66 t197.61 235.30 177.50 135.70 1746.17 24.5'S 2020 7504.9<1 7279.1rJ 1723.~1489.20 256.64 'lJ.97 882.76 93.b6 1250.47 21.3.85 194 ..60 153.to 1962.02 26.9'5 ~ -'-'~',-,--,,>"';,,",,----",~~~,,..,-,;"'';:''':'---',,'-----'~-.,..;,;.,.;";...;,;".,..-~~,..,,.;...,~~,.."'-----':"_..,...'"-,,,,,,",,,-~,,,,.~--~<-.,...,..,-~~''''''''''''~ ,-,t 1 } ; '1 1 i, , 1 ~""~''''''-'''P';,'--1 _,,:"":~-C<'l L __·~'A""""zi\!ilidllIMfi_.t~}'~'H\!*''1!Y'iOt~~,·"~",'C ~'""-"""'~~,~""""'7', ,~ • tti''r¢;yWm!l:faiWl'itrYiW1t. I i !~ t :$: .•'.r _.0 •~•'._'.,.,.'l . ",<'"-'"'..---l.'...:.'6'....",..f:'C r:;'J \...,~:.•.._• ....~I;, Tota'EntrfY E!lIrIY OliP OGP Dtbt Strvi~e LESS:Debt Service LESS:FiM'Ci,itll OGP Cost HI'Kill Y8I'ClMJ)le~:;loufJ UNESTI£MT Sl'SIlM COST WATANA EARHIl«;S ffIIIVS CNM*EMHlf«jS I)q:bt Strvice Renewls FUll OPtr.tr "'in.TOTIl.CC/kiIf)-1993 .166.90 4041.89 724.00 724.00 199.83 90.69 7",.14 18.72 44.70 34.00 906.56 19.96 1994 4V'].00 4109.89 724.00 124.00 799.83 ?O.69 709.14 19.94 48.60 36.30 813.98 19.Eil 1995 ~:m<~4176.82 724.00 724.00 849.45 90.69 157.76 21.23 54.40 38.40 871.79 20.81 1996 4387.00 4255.39 735.60 724.00 848.45 90.69 769.36 25.54 60.90 41.00 996.80 21.07 1997 4466.90 ~332.89 735.60 724.;00 848.45 90.69 769.36 27.20 67.80 40.80 905.16 20.89 1999 4M7.f\)4411.46 748.00 724.00 849.45 90.69 782.56 32.28 76.10 44.10 ~.04 21.20 1999 4629.lO 4490.32 748.80 724.00 848.45 90.69 782.56 34.38 90.10 47.40 954.44 21.2t. 2000 4709.00 4567.73 748.80 724.00 848.45 90.69 782.~36.61 101.50 50.80 .971.47 21.21 2001 4813.00 4668.61 764.80 724.00 848.45 90.69 798.56 .43.00 116.40 5'5.30 1013.20 21.70 2002 4915.';0 4768.42 731.90 724.00 848.45 90.69 815.50 w.06 131.60 57.90 1055.12 22.13 2003 5019.10 4868.53 79'1.90 724.00 849.!S 90.69 833.66 57.85 149.90 63.10 1104.51 22.69 2004 5122.00 4968.34 799.90 724.00 848.45 90.69 833.66 61.61 170.80 67.80 1133.87 22.82 2005 5224.00 S068.ot.199.90 724.00 848.45 90.69 833.66 bS.62 194.40 71.90 1165.58 23.00 2006 5369.00 5207.93 1564.10 1489.20 848.45 90.69 818.77 93.66 15fJe.77 87.31 0.00 74.00 1720.08 33.03 1JXj7 S513.'()()5347.61 1564.1«'1488.20 848.45 90.69 832 •.17 93.66 1572.17 92.99 0.00 78.80 1743.96 32.61 !~I 2008 5657.00 ~.29 1564.10 1488.20 848.45 90.69 882.76 93.66 1622.76 99.03 0.00 83.90 t~.69 32.91 "" 2009 S801.00 5626.97 15t.4.10 1488.20 848.45 90.69 882.76 93.66 1622.76 105.47 ~.OO e9.~1817.53 32.30,2010 S9.~.00 5766.65 !'S64.10 1488.20 848.45 90.69 002.76 93.66 1622.76 112.32 ".00 83.50 1818.58 31.54 2011 66&5.00 5902.4~1564.10 1488.20 848.45 90.69 002.76 93.66 1622.76 U9.62 0.00 83.00 1825.39 30.93 2012 6229.00 6042.13 1564.10 1488.20 848.45 90.69 882.76 .93.66 1622.76 119.39 0.00 80.50 1822.65 .SO.17 2013 6376.00 618-1.72 15M.to 1488.2<.1 848.45 90.69 882.76 93.66 1622.76 135.68 0.00 85.70 1844.14 29.82 tal4 6526.00 6330.22 1564.10 1488.20 848.45 90.69 882.76 93.66 1622.76 14~.50 16.70 92.30 1876.26 29.64 .2015 6680.00 6419.60 1564.10 1488.20 848.45 90.69 882.76 93.66 1622.76 153·.89 16.70 96.60 1989.95 'J!I.17 2016 6&37.10 6631 •.99 1593.50 1488.20 Wl.45 90.69 882.76 93.66 1652.16 174.20 35.10 103.90 1965.36 29.63 2017 6999.00 6789.03 1637.30 1488.20 848.45 90.69 882.76 9'3.66 1695.96 196.49 58.70 113.00 2064.95 31>.42 2018 7163.90 69~.98 161'0.70 1488.20 848.45 90.69 002.76 9'3.66 1729.36 220.94 103.60 123.60 2177.50 31.34 2019 7333,00 7113.01 1670.70 1488.20 848.45 90.69 882.76 93.66 17'J!1.36 235.30 177.50 135.70 2271.86 32.02 7:02Q 7S04.90 1279.75 1123.50 1~.20.848.45 90.69 882.76 9'3.66-1782.!6 263.85 294.6C 153.10 249'J.71 34.26 "TJmQlx 'g:t: ""0;0-....~"'.....N 0) ~~,..~ ..._""."".,----.......,'~~.)J".~','--.;;~_~-t~)':~_,~; """..__~•vi ~.;oo",-,-"".,,;-'" INOt.COSTS IN lULU ...t ~~~~a ---~~ too 1006!10%. ","""".";",-.,,,,,,~..........,.,""_"":•.-',,~'"_'."-".7·.':._~",""'"""~"'>:'~--"":J"o *.~,-"';&.,.-....~-tilr"i'.h"C"·~~~ 2185 l4!vt' o E"uitv ~"._~.~.,,"•.~,_-"~,,,_,_.""'.•--'-....=-<........-...._.,.....;.""".;,..j_.._:_....:..._,._....L_...:J...;:"';:!/..,_.,.._._.c&i"'-,~;..••.,..".••·~:::lIlQ:':::-,~~:.....:i;;:...,c;..Jt.__"""~:...,.,;,.....:2;:.....~,,;;....4~..,;;.t::.:~..£......:.~_.k>~""fJ.~.~i. ~--~ -rr-. _L,.~4'!"#$''.'1 ";""4,,,,,.'d·"'·....,·jM.'""*'>~....~,"...'.~---.~I~(~~'t··r.~4111IJ_~.IS •••..,rWi '":PiSS '.¥lIO.a Jl.Ph~qi;JIiJ.p. AlASKAt POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE W.HOLESALE C·OST OF POWER FOR WATANA 2·185 DORMEAN (WITH ONE HUINDRED PERCENT REVENUE BOND FINANCING) SEPTEMBER 1983 ALLCOSTSfN NOMINAL DOLLARS. ..~I _0 •..~_...'~-=--.......-..-------•"'.«.. :'t"$~ '1:ImGlXcg~ ..r,tc o -....-t l')-..J N ,..,J ~.--f·~--, -~----..-~~ "'-~"'-,..--~ ~.~~~ ~':iI..~~•.'",,"i_ -,,-"'-..-....."'".."",,_.=.,1-/,",,-.,..."",,"'••_i "'lr··""...."".."""""",.......'0,1 '~*'"dll ,--....,-.UtyIiI',UE ...},J,A.U;!lI!'IlI 1\ ~~..-..--- ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE WHOLESALE COST OF POWER FOR WATANA 2000 DORMEAN (WITH $2.35 BILLION STATE EQUITY CONTRIBUTION) SEPTEMBER 1983 $2.35 BILLION.,STATE EQUITY CONTRIBUTION IN NOMINAL DOLLARS. ALL COSTS IN NOMINAL DOLLARS. ~~~:------.: 2000 Level 2.35B E'Iuitv tlO1 COO 2003 ANMUftL COSTS IN HIllION t sa 1.L::::Z::::::'":I .»::=c::s ex KasL&Z&.................t.&&:&::a::Iaaz::U::Z::.::a::aa;i • Tot.l Entl'JY EI'lIrJY OGP OGP Dtbt StrviCt LESS:DtbtStrvict LESS:fin.l CaP it11 OGP Cost I'tl'·kIIf I YOI'((Mi)len luSts IN'JES1lEKT SUSITNA COST YAlANA ElRfIl'IJSlEVIL'S cr«f(Jf EAflMIPm D!bt Stl''iice RflltlAls Fuel OPtl'.'Klin.TOTM.(C/lQIft.-----, 1m 4167.10 M)42.09 563.90 563.90 224.02 ~.47 195.55 14.44 63.50 36.20 '¥J9.69 7.66 1994 42".,6.90 4109.79 563.90 5b3.90 232.03 28.47 203.56 15.313 12.70 38.90 :m.54 8.04 1995 4005.90 4176.72 563.90 563.90 246.14 28.47 217.67 16.38 84.00 41.00 359.05 9.60 {)•1996 4387.00 42'55u 39 515.ZQ 563.90 246.J4 28.47 219.27 20.37 92.40 44.00 396.04 9.07 1m 4467.00 4332.99 581.90 563.90 246.14 28.47 241.67 24.80 lOll.3/,)44.90 417.67 9.64 1998 45t7.90 4411.-46 ~7.90 563.90 246.14 28.47 241.67 26.42 124.00 48.20 440.19 9.98 1999 4619.00 4490.13 587.90 UJ.90 2~.14 28.41 241.67 31.66 137.70 51.60 462.63 10.30 2000 4109.00 4S67.73 602.90 563.90 246.14 28.47 756.67 33.12 153.60 56.10 500.09 10.95 "iI'2001 4813.00 4668.61 602.90 563.90 246.14 28.47 751J.67 35.91 179.60 60.60 532.79 1t.41 2002 4916.00 4768.52 656.20 563.90 246.14 28.47 309.97 52.f1 182.60 66.90 612.44 12.M 2003 5019.00 4868.43 1288.90 1196.60 246.14 28.47 679.84 77.51 911.30 70.83 21.90 68.00 1072.03 22.02 2004 5122.00 4968.34 1288.90 1196.60 246.14 28.47 688.69 77.51 921.15 75.~23.90 72.50 1092.99 22.00 2005 5225.00 5068.25 1288.SO H9~.60 246.14 28.47 73/,).56 17.51 963.02 00.34 40.80 76.50 1160.66 22.90 I ~I 2006 5369.00 5207.93 1288.90 1196.60 240.14 28.47 730.56 17.51 963.02 85.57 44.90 81.56 1174.99 22.56 2007 5513.00 5347.61 1288.90 1196.60 246.10\28.47 73/,).56 n.51 963.02 91.13 54.10 77.'!JJ 1l85.~22.11 f t 2008 5657.00 5487.~1288.90 1196.60 246.14 28.47 730.56 17.51 963.02 97.05 90.60 63.60 1224.27 22.31 2009 5001.1)0 5626.97 1288.90 tl96.60 246.14 28.47 130.56 D.51 963.02 103.36 88.20 89.10 1243.68 22.10 2010 5945.00 S766.6S 1200.90 1196.60 246.1<\28.47 730.56 77.51 963.02 110.00 tlO.30 95.70 1279.10 22.18 2011 6005.00 5024.85 1288.90 1196.60 246.14 18.47 73/,).56 17.51 963.02 tl7.23 130.10 96.90 1301.2S 22.44 2012 6229.00 6642.13 1320.80 1196.60 246.14 28.47 730.56 77.51 994.92 132.86 168.20 99.40 1395.38 23.09 2013 6376.00 6184.72 1354.90 1196.60 246.14 28.47 730.:.'>77.51 1028.92 150.02 2t4.00 109.30 1502.24 24.19 2014 652~.10 b330.32 1354.00 1196.60 246.14 28.47 730.56 17.51 1028.92 159.77 250.40 tl7.90 1556.99 24.60 20tS 6690.10 6479.70 1:m.80 1196.w 246.14 28.47 730.56 17.51 1028.92 170.16 m.90 126.Ew.)1623.'is 25.06 2016 6836.90 6631;79 1471.70 1196.60 246.14 28.47 73/,).56 17.51 U45.82 216.1b 321.'90 144.20 1828.68 27.57 2017 6991.20 6789.22 1503.00 11~().60 246.1"28.47 730.56 77.51 1171.12 241.62 370.50 155.20 1944.64 28.64 2018 1163.90 6948.99 1503.00 1196.60 246.14 28.47 730.56 77.~1 1171.12 2'51.54 446.00 167.90 2i>48.56 19.48 2019 733UJO 7112.91 1552.60 1196.60 246.14 28.47 730.56 71.51 1226.72 286.72 518.40 183.3/,)2215.14 31.14 2020 75CJ5.00 TJ:r1.85 1590.~1196.60 2%.14 28.47 730.56 77.51 1264.62 318.61 623.70 199.00 24f>5.93 33.05 ~]:;;'·;:>i';:'~"'r';;':;>"I·'.............•....••..~"lM4"h''''\""._~iIIWJtWii·".......•...•+0.,.,,(9 ~.~F ..•.'....' "UrnDlXcg::t: ~03 0--+o-t ~""J;...,...... ~--.~""-~',..:,:~-i}:,,:·'--,·~tIr"""">,:\'~..",.......".~;,..-.':~:. ~ ~...."'_i:';"""";,~.>.·t-v..... LLittt)J.,.,.:t~~~'·''''il''''j'''''<,'''',''..•.,-"..,.""-,\...=-~..'0".>'·""~~__f ,,,,,,,~'41._I $it I!I w;a 1.it JZfQ.t\lbC4t;g_ ~ ALASKA POW!ERA'JTH,OFH1"~1 SUSITNA HYDROELECTRI'C PRo,JEer UPDATE WHOLESALE COST OF POWER FOR WATANA 2000DOR MEAN (WIT.HONEHUNDR.EDPERCENIT REVENUE BOND FliNANCING) SEPrEM:SER 1983 ALL COSTS IN NOMINAL DOLLARS. .~t"'''•£.•il".'-•~., ?. ••~'",.••..••','-,• •I <>V ""~.,-" (>....;.,••~.'_______.;7c.-" 2000 Leyel OE".,itv @10l COD 2003 rHIJt1..COSTS IN ttllUf*• ==-:::a:ss::::a T cr=-,•• Totd £nun EntrIY OGP OGP Debt Servin LESS;Debt Service LESS;Fin;.l (Al'itil OGP Cost per KYt Ym (QIt)lIs$Losses INYESnDT &JSl~·COST ""lANA EMNlt«;S lEVIt'S CANYIJt EARN IIllS Debt SeryiCf Renf¥ils FUflOPfr.II ttlin.TOltt.CtIKYI) 0 I I 1m 4161,10 4042.09 ~.90 ~.9O 614.08 71,10 542,98 14,44 113.50 36;20 651.U 16.26'li':. 1994 4236.90 4109.79 563.90 563.Cj()624.13 71.10 553.03 t~.38 72.70 38.90 680.01 16.55 1995 4305.90 4176.72 563.90 SbJ.90 6b2.07 '11.10 590.97 16.38 84.00 41.00 732.'35 17.53 1996 4387.00 4255.39 575.50 563.90 662.07 71.10 602.51 20.31 12,40 44.00 759.34 17.84 1997 4461.00 4332.99 587.~563.90 .61,,2.07 71.10 614.m 24.80 106.30 44.90 790.91 t8.~ 1998 4547.90 ;~11.46 ~7·~563.90 662.07 71.10 614.97 26.42 124,00 48.10 813.59 18.44 1999 4b29.00 4490.13 5P'/.90 ~.9a 662.07 71.10 614.97 31.66 137.70".51.60 tm.93 18.62 "I 2000 4709.00 4567.73 602.90 563.90 662,07 71.10~629.en 33.72 153.60 56.10 873.39 19.12 ~;2001 4813.00 4668.61 602,90 563.90 6602.07 71.10 629.m 35.91 179.60 60.60 906.08 19.41 I 2002 4916.00 4768.52 656.20 563.90 662.07 71.10 683.27 52.m 182.60 66.90 98'5.74 20.67 J'2003 :5019.00 4868,43 12813.90 tt96.ro 662.07 71.10 678.84 77.51 1284.60 70.83 21.90 lIS.GO 1'445.33 29.69./I 2004 5122.00 4968.34 128B.9n 1196.60 662.07 71.10 688.69 77.51 1294.45 75.44 23.90 72.50 1406.29 29.51.~~ I I 2005 5225.00 5068.25 1?88.9O 1196.60 :062.07 71.10 730.56 77.51 1336.32 00.34 40.80 76.50 1533.96 30.27 ~ IT''Ii 2006 53!l9.00 5207.93 1200.90 1196.60 662.07 71.10 730.56 77.51 1336.32 85.51 44.90 81.50 1548.29 '8.73 2007 5513.00 5347.61 1200.90 tt96.6O 662.07 71.10 730.56 77.51 1336.32 91.13 54.10 77.'!JJ 1559.05 29.15 2008 S57.00 5487.29 1288.90 1196.60 662.07 71.10 730.56 77.51 1336.32 97.05 00.60 83.60 15m.51 29.U 2009'5901.00 ~26.97 1200.90 11'96.60 662.07 71.10 m.56 77,51 133b.32 103.36 88.20 89.10 1616.98 28.74 1010 :5945.00 5766.65 1288.90 tl96.60 662.01'71.11)730.56 77.51 1336.32 110.08 110.30 95.70 1652.40 28.65 2011 6005.00 582~.85 1288.90 U96.60 662.07 71.10 m.56 77.5t 133b32 tl7.23 130,10 96.90 1680.55 28.85 1012 6229.00 6042.13 1320.sa tl96.6O 662.07 71.10 730.56 77.51 1368.22 132.86 168,20 99.40 1768.69 1!/.27 2013 6316.00 6184.72 1354.80 1196.60 662.07 71 •.10 730.56 77.51 1402.22 150.02 214.00 109.30 1875.54 30.33 2014 6526.10 6330.32 1354.80 'U96.60 662.01 11.10 730.56 77.~1 1402.22 159.77 250.40 117.90 1930.29 30.49 2015 6680.10 M79.10 1354.00 1196.60 602.07'n.to 130.5.6 77.51 1402.22 170.16 297.90 126.80 1997.08 30.82 1016 683b,;9()6631.79 .1471.70 1196.60 662.01'11.10 130.56 77,51 1519.12 211\.76 321.90 144.20 2201.98 33.20 \1 I 2011 6999.20 6789.22 1503.00 1196.60 662.01'71.10 730.56 n.Sl 1550.42 241.82 370.50 155.20 2317.94 34.14 2018 1163.96 6948.98 1503.00 U96.lh 662.OJ'71.10 730.56 77.51 1550.42 257.54 446.00 167.90 2421.86 34.85 2019 1332.90 7lt2.91 J552.6O lt96.6O 662.0'l'71.10 1~.56 77.51 1600.02 286.72 518.40 183.30 ZJ98.44 36.39 1020 7.::i05.00 7279.85 1590.SI.l 1196.60 662.01'71.10 730.56 77.51 1637.92 318.61 623.70 199.00 2779.23 38.18 1S'i(~J$j;lju!;:#f-i~~,-.".-,,''...'__.."'.'__.,...,...;.:,_._._......~..;,.,..,;.~,..,.-W._,;..;';.,.:~~<__.,:,..."'...,;.;..,..~,_..-__~~~...;~.~~_.~-'--~,......;.........._;.;._~~~.:......~_~.:...!!!.~E::..2~t£._.:.-..~.:...._.....d~_...:..~2::..:...i..~======~_~ .'~ Q.'r •~,•I r .~. ::;'.'"..',.~'. m X ::I: 00 -i ........ I'.) 00 """--,~~'•.1 ·..·f to,,I ~~ 20202015 --"~,r 2010 ~-~-'~ 2005 YEAR ~ 2000 ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDA TE EFFECT OF INTEREST RATE ON WHOLESALE COST OF POWER SEPTEMBER 1983 •••l •••~••-10% ----8% I«12% aLl 1993 lS95 40,t I r r 1 I .c DOR MEAN FORECAST WATANA 2000 ~~I ~ II:z:/UU ._ ~..~W ./A I-V ....Z ........" UU -•••~.,".~,-.......,I.~~~~,25 I ••••~r .a::..~; •••I..' I'.•••••-_-••••t""~.....-- ~.,-o 20 :~'"I I~Ji ,,..------------~;~-;o :, I-15 J ~II II Ien;"~iIo.1o.~•.,.IUJ-•••••., -'10 . .•••••_..."--+-~I«.•........;;.......--I,."--.......... 'JJ "",,"'"W .--__... ..oJo 5 .,~I I I IJ: ~ \L, r-:c~"P""=- ~~~~ I _,_.1 '0 ,.,~'.-c uc;-.; :~-l _#0 ,,__,'_________________-_------------!'',''~""_'~..,1'1~'•.ii~•.i,..••••.Ii.F",l\tiiJIIi·~".~I.I.gliilllJ)"liiAlil.IIi,!I!II;i'fl;;::;~.,iii$iii1.•iJ''''\i':i,~1i't'·;I'>,,,,,,,;••,•.,...,..,...,....."......._,_........&Mt¥44 .,.......41••••\$"..bU..•"b.-.,.'Vn '".,'.'...fX 4 U a.2 •ssp ~1&9"'''' I".;. '=" mx ~.~ teal ClIo.- ....-1 0-"'"......r-.., I'JCO ~/:·0-·<'4.·-"'~ ~ .__..+- ~ ~.o<•••+-I I •.....-l..--~--, t .- ,....,...--¥l!=.-.t..-.-. ..4N,r~1 I I '- _.~..._...- -1---- 'r·..·"..,,-·,,·'"..JI.-~ C'· REAL RATE OF GROWTH OF OPERATING BUDGET -21J, ~WATANA E1.21853120013.280 MILLION UPFROHT EQUITY i'".. It;1000··-.. wa ..-~'" ff.'JO ~ ~ §1OO1-a-8 SIt llCo::;400...j .....~. C 200 -.- ~-... ~OIo..l~~"'~"'-'-~-L..-I-~IIIL.....I"'''''.Ml''....a~....";;;16..,II II 10 C3 YEAR - f·- f..-- 1-- ~ ~_. t-~L I---MI I .• .- ~ ._-..+--- ~.'" ~ REAL RATE OF GROWTH OF OPERATING BUDGET 0" ~~WATANA£1.2111!i ::;13.280 MILLION UPFRONT EQUITY :!1200 iii' :Itit •• ~1~--._.-.._.f\. a -.---....-.1 \ flO\)".--.~. .~... ~ICO II:o ::;4001-...,....... j c2O!O .~... ;!O'Io..I~~IL.I~I...o~__~.................I~I--"IIa-~IL... ~ t.::> .-'-- "It~>c_;:>IOio~" ~-..-_...................... ........---- ~ \1.;1\ ;i~jiji'li~d.;e,,!,~-:'.";$.t,~:ql:/-"""'''''+;It ,-4.......'''.''q '~A¥"...'.'1""'"'----::5-......iC$i('Sil .Ii *OUI,44 bill JR •••lal 1,)0":""'::~~..~-~~..•.'R ,~- \) ~~ f.~r-tl··_.-I~··- ~.-.-~.-t- "".,Rl II tQ .,.2 t3 YIEAR ~ ---:c-.-c;-;---,.......~.•._.,..-.-._""-~-.-:s. LEGEND I SAllE MOOEL ....ECIAl CAPITAL AVAlLA8LE n WATA'jA EI.21.ElTlrilATED CONITROOTtONUEXPENDITURESMEl"BY EOUITY P.:l WAT""AE'.21.ElTtMATED CONITRlICnON~E)(I"EHDITURElt..tET av REVENUE IOHDI REAL RATE.OF GROWTH OF OPERATING BUDGET-t2t)(, ALASKA POWER AUTHORITY SUSITNAHYDROElECTRIC PROJECT UPDAT.E SA.GEMODEL SPECIAL CAPITAL AVAILABILITY SEPTEMBER 1983 NOTE. upFRONr EOOI.TY SHOWN II THE MAXIMUM.UNDER THE COAt. EXPANSI~PLAN THE UPfRONTEQUITY cmlTnnlUTION WOULD BE LOWER. z0'WA'rANA EI.218531200$3,280 MILLION UPFROfj'j'EQUITY i•Ji'·~~-~~.t\r~ f ~... .~.001--.I 4- ! "'-lit'"..Aj 4lf1-+~Ill, c2liO ~ .Ji!O .....__,.........._.tioG1-a •--.-- ! ') I I (~ " , w •.',-•..,..,.....,~ ~~,. m X -oJ: Q)-tOto ctI -1\,)-1 0 ...... -+t •N l'JCD ~ II..;..,II II YEAR• ~I'''~' (; ..11 REAL RATE Of'QIIK)WTH OF OpeRATING IIUDGIT-n \$2.350 MILLION UPFRONT EOUITY \ \ \ \17 \1/ ~ ~ I "I 2:o:; ~1200 i tit I lj1000 IIIaflOG ~t:5- ~1Il-~ ~-C -Ij..•.. WATANAEI.~ II 81 .,II YEAR .. REAL RATE OF GROWTH OFOPERATINQ BUDGETO" •II 17 '~~:"'---""'_~~"""'~'"''''-''~''_~...\Cc,_"'.........~'",*'U'.U llh....fUiI.......··r..:§r t~ilI;;"f. UPFRONT EOUITY ~ 1\ \I~ \I~ \II [i \1/~ 1/ . ,-I I I I I .I zo:::; ~1200 i.. I t 'OOOaflOG ! ~106 ~w.- ~!200 ~ ~0 ~sa NA EI.2OOO .,a.... YEAR E'I ~~ ,."".,.c<.r'~~'O.'~,,.iW:t~~~,"";;;:lCl"'i:,,,,,,",'~J>,<>,, ,......._.....--........W'•• UrfRONTEOUITV 1\ \ \ \ '-\ \ . i I I i I I I, ALASKA POWER ',\UTHORITY SUSITNA HYDROELEC.TAIC PROJECT UPDATE SAGE MODEL SPECIAL CAPITAL AVAILABILITY SEPTEMBER 1983 NOTE: Uf'fRONt tOUITY IH(MM'l'tHl MAXIIaJII.lJIKKftTHE COAL E)(PANItON PlAN TMllJiI'Ilttmrr iOlMTV COWTJItI8U"f'" WOULD ,BE LOWER. U:OENO: I IAQC:~L-"CIAL CAPlTAL~VAI~t.E OWATAWAEI.21*U'fIllilATED coroIITJUJCTION ,E)(.P£Nf)Il'URU MlEi.V lCUITV 'r;I WAtAAA II.'X.UT,;MTID CONITRUCl'IQN ~EXPfIlliDlTUMI MU av MIWMM ... REAL "ATE OF GROWTH OF OPI~AT'"IUOQET+~" .•~........1200I•I ti'!JlO I.i ... ~..~c2lO :~ ~.0i ....11 ~._: ~,----:-.,,_...~~-...,..,.........----_.---,."....;-~~-------~:,.,.~.....,,;~~~,;.,...~"-._-...__..,,..";._.,..,..,-"....._..;-..-_._-~-.;."--;.....,; .~ ,__J Ji, J ~.;c - t ... 'to 01.iO.,.,,"''t...':-":,.'.~•.)-J ".t'-• '"-0,..•'0;f .q :Gi '••0 ,.~".o?.....~~..f ~}_ <:.1 .lI~•'-""tt-.....•~'•.;.I J aI.Ie)\f..~".~~...'As ..~"i ?\.,,~-_~i ,.. o_,~.,._--'_>"_~__'.._--~_'._,_,__."_,_~~_,_..,...~._".,........~"'"""_.,',-,--_..___'..._~..:"._,..;,..>:,.~,._.:...,'____"JI<.._Il,.,,"', ~ m X :J: MI 54 =-=,:"""n ~ 28.300 14,500 19,800 ---'--~~ c_'"_......,_~·~".._·.."'».,...".,.,•.~.__.__._,,_.~ AREA IN ACRES: "38,000 , RESERVOIRELEVATIOt.J:2185 --,-2100 F 2000/~-1900, ,..---. ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT UPDATE .WATANARESERVOIR AREAS UNDER ALTERNATIVE DEVELOPMEN·T CONCEPTS ~ WATANA DAM -~ ~·,.._.__....,.'_.;.."'__<"-....".n"_..,.,•_'__;..:..._'_._._."-<".~.~.__..,_ I ) ~ 4 1, 0. I I J /~ "."4';"_"l•.~ WATAHA ANO DEV'"CANYO .. YfA".020 ·t'OlOW" ffiEl'(IY DEMAND 35 _TAHA AfiC)DEVIL CMlYON ftA"20 '0 114$GWh IHGE..-,DEUAND so NATURAL,t002000 21002U5 NATVRAI..UOO 2000 2'002185 PROJECT ELEVATION PROJECT ELEVATION AUGUST 1o-L--r--....-~r--.....,."--.---.........--r---r--r--~-...,....._--I.-r-..,--r--...,..-,- HATU AL tico 2000 210(1 2185 PROJECT ELEVATION DE CeP-.1B ER 4 a..ATANA 0 ....Y *'_"_.......-. YlA".OOO .'01 OW" fNE"GY DlMA..D a 35' Ii Jlt...... II: Q 26 i5%o .joo l-e •2o ."... o..a.-.......--..--.--~.........,......._............--r---,..---..,...._...---'--r--r----,.-..,..--r- "ATU~AL 1100 '000 2100 2"6 "ATUftAL'IOO .000 Z!OO 21.5 "ATU"AL "002000 2100 '"5 _15 HI 95 "0.. I(•L !! ~10 to all t: U (:) ..to "~$•• ~ -'L t. '''O''IOT ELEVATION '''O.llCT ELEVATION PROJECT ELEVATION EXHIBIT 7.31 -fto..• -30... U- ALASKA POWER AUTHORITY SUSITNAHYDROELECTRICPROJECT UPDATE AUGUS1-AND DECEMBER FLOW DURATION CURVES NATURAL AND WITH PROJECT CONDITIONS SEPTEMBER 1983 ,.~ I