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Home My WebLink AboutAlaska Railbelt Regional Integrated Resource Plan (RIRP) Study Final Report February 2010 OriginalAlaska Railbelt Regional Integrated Resource Plan (RIRP)Study Final Report es February 2010 =)BLACK &VEATCH ,Building a world of difference? DISCLAIMER ALASKA RIRP STUDY DISCLAIMER STATEMENT In conducting our analysis and in forming the recommendations summarized in this report,Black & Veatch Corporation (Black &Veatch)has made certain assumptions with respect to conditions,events, and circumstances that may occur in the future.In addition,Black &Veatch has relied upon information provided by others.Black &Veatch has assumed that the information,both verbal and written,provided by others is complete and correct;however,Black &Veatch does not guarantee the accuracy of the information,data,or opinions contained herein.The methodologies we utilized in performing the analysis and developing our recommendations follow generally accepted industry practices.While we believe that such assumptions and methodologies,as summarized in this report,are reasonable and appropriate for the purpose for which they are used,depending upon conditions,events,and circumstances that actually occur but are unknown at this time,actual results may materially differ from those projected.Such factors may include,but are not limited to,the ability of the Railbelt electric utilities and the State of Alaska to implement the recommendations and execute the implementation plan contained herein,the regional and national economic climate,and growth in the Railbelt region. Readers of this report are advised that any projected or forecasted financial,operating,growth, performance,or strategy merely reflects the reasonable judgment of Black &Veatch at the time of the preparation of such information and is based on a number of factors and circumstances beyond our control.Accordingly,Black &Veatch makes no assurances that the projections or forecasts will be consistent with actual results or performance. Any use of this report,and the information therein,constitutes agreement that:1)Black &Veatch makes no warranty,express or implied,relating to this report,2)the user accepts the sole risk of any such use,and 3)the user waives any claim for damages of any kind against Black &Veatch.The benefit of such releases, waivers,or limitations of liability shall extend to the related companies,and subcontractors of any tier of Black &Veatch and the directors,officers,partners,employees,and agents of all released or indemnified parties. Black &Veatch i February 2010 -ACKNOWLEDGEMENTS ACKNOWLEDGEMENTS The Black &Veatch project team would like to thank the following individuals for their valuable contributions to this project. Alaska Energy Authority Steve Haagenson,AEA Executive Director Jim Strandberg,Project Manager Bryan Carey,Project Manager David Lockard,Geothermal and Ocean Energy Program Manager ALASKA RIRP STUDY Doug Ott,Hydroelectric Program Manager James Jensen,Wind Program Manager Jim Hemsath,Deputy Director,Development Christopher Rutz,Procurement Manager Sherrie Siverson,Administrative Assistant Railbelt Utilities (numerous management personnel from the following Railbelt utilities) Anchorage Municipal Light &Power Chugach Electric Association City of Seward Electric System - Advisory Working Group Members Norman Rokeberg,Retired State of Alaska Representative,Chairman Chris Rose,Renewable Energy Alaska Project Brad Janorschke,Homer Electric Association Carri Lockhart,Marathon Oil Company Colleen Starring,Enstar Natural Gas Company Debra Schnebel,Scott Balice Strategies Jan Wilson,Regulatory Commission of Alaska Golden Valley Electric Association Homer Electric Association Matanuska Electric Association Jim Sykes,Alaska Public Interest Research Group Lois Lester,AARP Marilyn Leland,Alaska Power Association Mark Foster,Mark A.Foster &Associates Nick Goodman,TDX Power,Inc. Pat Lavin,National Wildlife Federation -Alaska Steve Denton,Usibelli Coal Mine,Inc. Tony Izzo,TMI Consulting Additional Individuals That Provided Substantive Input to Project Alan Dennis,Alaska Department of Natural Resources Bob Butera,HDR,Inc. Bob Swenson,Alaska Department of Natural Resources David Burlingame,Electric Power Systems, Inc.(EPS) Dick Schober,Seattle-Northwest Securities Corporation Harry Noah,Alaska Mental Health Lands Trust Office Harold Heinze,Alaska Natural Gas Development Authority Jeb Spengler,Seattle-Northwest Securities Corporation Joe Balash,Alaska Governor's Office Ken Fonnesbeck,HDR,Inc.' Ken Vassar,Birch,Horton,Bittner,Cherot Kevin Banks,Alaska Department of Natural Resources Mark Myers,Alaska Department of Natural Resources Paul Berkshire,HDR,Inc. Stephen Spain,HDR,Inc. Black &Veatch ii February 2010 PURPOSE AND LIMITATIONS OF THE RIRP ALASKA RIRP STUDY Purpose and Limitations of the RIRP e The development of this RIRP is not the same as the development of a State Energy Plan;nor does it set State policy.Setting energy-related policies is the role of the Governor and State Legislature.With regard to energy policy making,however,the RIRP does provide a foundation of information and analysis that can be used by policy makers to develop important policies. Having said this,the development of a State Energy Policy and or related policies could directly impact the specific alternative resource plan chosen for the Railbelt region's future.As such,the RIRP may need to be readdressed as future energy-related policies are enacted. e This RIRP,consistent with all integrated resource plans,should be viewed as a "directional”plan.In this sense,the RIRP identifies alternative resource paths that the region can take to meet the future electric needs of Railbelt citizens and businesses;in other words,it identifies the types of resources that should be developed in the future.The granularity of the analysis underlying the RIRP is not sufficient to identify the optimal configuration (e.g.,specific size,manufacturer,model,location,etc.)of specific resources that should be developed.The selection of specific resources requires additional and more detailed analysis., e The alternative resource options considered in this study include a combination of identified projects (e.g.,Susitna and Chakachamna hydroelectric projects,Mt.Spurr geothermal project,etc.),as well as generic resources (e.g.,Generic Hydro -Kenai,Generic Wind -GVEA,generic conventional generation alternatives,etc.).Identified projects are included,and shown as such,because they are projects that are currently at various points in the project development lifecycle.Consequently,there is specific capital cost and operating assumptions available on these projects.Generic resources are included to enable the RIRP models to choose various resource types,based on capital cost and operating assumptions developed by Black &Veatch.This approach is common in the development of integrated resource plans. Consistent with the comment above regarding the RIRP being a "directional”plan,the actual resources developed in the future,while consistent with the resource type identified,may be:1)the identified project shown in the resource plan (e.g.,Chakachamna),2)an alternative identified project of the same resource type (e.g.,Susitna);or 3)an alternative generic project of the same resource type.One reason for this is the level of risks and uncertainties that exist regarding the ability to plan,permit,and develop each project.Consequently,when looking at the resource plans shown in this report,it is important to focus on the resource type of an identified resource,as opposed to the specific project. e The capital costs and operating assumptions used in this study for alternative DSM/EE,generation and transmission resources do not consider the actual owner or developer of these resources.Ownership could be in the form of individual Railbelt utilities,a regional entity,or an independent power producer (IPP). Depending upon specific circumstances,ownership and development by IPPs may be the least-cost alternative. e As with all integrated resource plans,this RIRP should be periodically updated (e.g.,every three years)to identify changes that should be made to the preferred resource plan to reflect changing circumstances (e.g.,resolution of uncertainties),improved cost and performance of emerging technologies (e.g.,tidal), and other developments. Black &Veatch iti February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents 1.0 Executive Summary...scssseesscecsssscecessecceessesssssssscsessessessssscesssesessesesssessaceesssessesessacesseees 1-1 1.1 Current Situation Facing the Railbelt Utilities...csssesssssssseecssesesssesssssseseeers 1-1 1.2 -Project OVETVIEW .....es esssssssecessessssesscssessssesssessessessesssntensessecaeseesesseassessrsneeuescentscesacsees 1-3 1.3.Evaluation Scenarios........cssscssssssssscssssscsscecsccsessessesssssscessesessenssessceesesaeesessesaesesarsneeees 1-7 1.4 Summary of Key Input Assumptions........s.ssssessesscssesessessessssesseseseensesssesssensseeseeneeess 1-8 1.5 -_-Susitna Analysis...cesscsssccsssscessscescssesessseccecssseesecsssssesesseassussessesseecsesscssceeeaceaseace 1-8 1.6 Transmission AnalySis.........ccccscsscsssesscesessessesssssesscsscencesseseaeessescsteatsacestesassnesseensees 1-11 1.7 Summary of Results...cceesesesssssececescsccsseceessececesecsceecacsceesersessesesseeseseceossessaees 1-12 1.7.1 Results of Reference Cases .......sccessssssssscsscssssssssssssceesecssessessssssecsceeeesscens 1-13 1.7.2 Sensitivity Cases Evaluated ..........cccsccsssscssscssscsssessssccesssccsscsescserssaeesnessnees 1-16 1.7.3.Summary of Results -Economics and Emissions ...........csccsscsescssreesersenee 1-16 1.7.4 Results of Transmission Analysis ...........scsesscseecscessesssseecescseseseeeeseseeseees 1-19 1.7.5 Results of Financial Analysis .............csccsssccssecsscsssesseseesseceesesseecessereseneees 1-22 1.8 Implementation Risks and Issues............sesssssssssesssceecsesesesseessssessesseneescesseasensessasenee 1-26 1.8.1 General Risks and ISSues .........sessscessesceseesessesesessescescsereesseseseeserecseeeseenes 1-26 1.8.2 Resource Specific Risks and Issues...csesssssssssssssssssscsessscecessnsecesens 1-27 1.9 Conclusions and Recommendations ..........eesscceesssescesssssessseseeseseesseesessseseasenseeseesens 1-29 1.9.1 Conclusions 0...eee eeeeeceeseecesesseseseecssssscesesseseesesesseesesseceesensessesessessseroe 1-29 1.9.2 Recommendations .0......eee eseeesscssssesssseeceessesecsesssssesscseseseesessenssaseecseses 1-33 1.10 Near-Term Implementation Action Plan (2010-2012)oes eesssecseteecreesesecesees 1-40 1.10.1 General Actions 0...eeceseeseseesssseesessecsesescesssecssssssessrssessesssessasseceeserees 1-41 1.10.2 Capital Projects...cssssscsssscssscnssessscsssscrssssssssesssssssssescssseeseeseasseasensens 1-43 1.10.3 Supporting Studies and Activities 0.0...cecscssessseeseesssssssssssssessneseseseees 1-44 1.10.4 Other Actions..........ccscssescsscessesseecenceceeecscescerseeeassseesseesessessassavassssceseesvensees 1-45 2.0 Project Overview and Approach....ccsssssssssssssesssscrseestsssscssssssssssesessnsrsesensentsessecerensenesseeees 2-1 2.1 Project OVErViW ......cccccssecssessssesssecssccnssesssssessssseesessseesessseseesnsesensesaeesesessaeeseseseeseeees 2-1 2.2 Project Approach...esssssssssesesseesesesessssssssavasssssseoecesssncaeessensenssneaessesesssseseeenesseones 2-2 2.3.Modeling Methodology 0...esssssssesssscessesceccecscssssscsevscsessssesssssesenseasensssenseaesnsensetens 2-5 2.3.1 Study Period and Considerations.........c.cssessesssssesssseessssssssessesseessneeeesseneenes 2-5 2.3.2 -Strategist®and PROMOD®Overview......csssssssssssessssecesssescsseseesitensneceseretets 2-5 2.3.3 Benchmarking...eessssscsscescessscessscscessescencnssssssssescsssesensnsnseeseesseneeeeaees 2-5 2.3.4 Hydroelectric Methodology....cccssssseeeeenessseessessseseeetssesesssaseeeseses 2-6 2.3.5 Evaluation Scenarios ........ccscsscscssceecssceeseesesecsessscssnsssssesesnesseneensessesnecsscnneees 2-7 2.4 Stakeholder Input Process...ssssssesssssssseesssssssessessenseeeeneseseseeseserseesensssersssesesaeensens 2-8 2.5 Role of Advisory Working Group and Membership .........cccssesesessesnetsenenerseeeeeteeees 2-9 Black &Veatch TC-1 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) 3.0 Situational ASSeSSMent ............csccsscesssesssccssecescecesecssesessassesevsccusssssuseeeeasseesssessnenenaeessaseaeeseaeees 3-1 3.1 Uniqueness of the Railbelt Region .......cessssessesscenessetesesesnennenererserasseseanscnssreseeaes 3-2 3.2 -COSt ISSUES ooo...ceesccsssssesssecsscessaceseseesececsacesassecsssscvssesssssesecesaressessntsesaeeenseeesassssensnesnes®3-2 3.3 -Natural Gas ISsues.........ccscceccssccessesscceeseeeseessossacsssscnessssesesesesessnessseesscsaeeeeesnaeresnoreseses 3-6 3.4 Load Uncertainties 00....cccscssccssccssesseessessssessssscusesscseeseeesnecseenatenaesaeessesnasenaeesessees 3-10 3.5 Infrastructure ISSues........sscssscscescccesesccnsesessescessssscsessssssseseeseesecseessessessseseesesseosenes 3-10 3.6 Future Resource Options........ccsccssssssssssssssssessenseseessessesssssssessessecssensessessseneeeseanensoes 3-11 3.7 -Pollitical [SSUeS ..........sscssessscsscecccetsesccesccssssssensesseenccscsssesscesssesssesasnsecesseseeeseesaeeansneenees 3-13 3.8 Risk Management ISSues.........ceccsssssssecsssessesessesscssesseseesssssssssacsesseessesseesensensaneoes 3-13 4.0 Description of Existing System .......ccscscsssssssccsssesseeesserseneesssenesssscesessesassnsnesenaseesseeeesenaces 4-] 4.1 -_Existing Generating Resources ........ccssccsssscsesssssssesssesssceeseesresseseneseseeensnessenreneneenenees 4.] 4.1.1 Anchorage Municipal Light &Power ........csssssesssessesssssseseeseesesseeeeeeneesees 4-] 4.1.2 Chugach Electric Association...cscsssssssssssssssessssessseessesseeessesseseesesessessees 4-2 4.1.3 Golden Valley Electric ASSOCIatION 0.0...eceeseseesseeseseeeeeeeseeseensenseeeserenens 4-2 4.1.4 Homer Electric Association...ceesesscssssssseesssssssssssecsssesseneeseensseeeereseeeses 4-3 4.1.5 Matanuska Electric ASSOCiIatiON 0.0...eeeescessessesssseseessesesssaseseeeeserseessenees 4.3 4.1.6 Seward Electric System...eseseeecsesseessessseessessssssscsecenseesenteneeseseaeseeseeeees 4-3 4.1.7 Hydroelectric Resources...cessesssssecssscsssssessssssssssessssssessssesenesseeeeseneenees 4-3 4.1.8 Railbelt System...ee eeeeesssesssssssesssceseescesssesscseseessassseeseeeneeseeseesesseseess 4-5 4.2 Committed Generating Resources ........cssesscsssseseeesecensesesssecsssseeessessssseeessreneseesentes 4-5 4.2.1 Southcentral Power Project ......ccceeseccescceceeeeeeeeeseeseseeceeccsesessessessessaseessess 4-5 4.2.2 ML&P Units...cececssesscesecscesecccscsnsescecceasenseesseesetecessvenssssessesaesussasseseaseasass 4-5 4.2.3 Healy Clean Coal Project .........cccccssessccseceseeseneeeseccesceceaseeseeseascossossavseeenaes 4-7 4.2.4 HEA Units 0...cceccscceccessscssccscenesecseeeseseesceseeseenesecsacesseseeeeceeeesassnssasaassaoess 4-7 4.2.5 MEA Units...ccccccccscsececsnsecseecsacecesecesscesenacceceeeesonecesaceceeneasenenenseasesees 4-7 4.2.6 City of Seward Diesels ..........cessecsctscsesscesenesssnecsesseessesenserseooressseseseasees 4-7 4.3 _Existing Transmission Grid oo...ccscssscssccessstscescesesesceacesescncenssseseeseeeseeeseesesenaseesees 4-8 4.3.1 Alaska Intertic 0.0...cecsescssessesesecescssccecsnsseesetsececcsceseeenessceeceanseatenssesseets 4-10 4.3.2 Southern Intertio 0...esseesssssessesecsessccesessasenssecessesesseecsesssenseeneessseeesees 4-10 4.3.3 Transmission LOSS€S..........cccssscsssssscsseseesecescesscesecesaesscesaceaaecaceseeesesenesnaeease 4-11 44 Must Run Capacity oo...ccscccssssscsesssscsecseessccsecsccsesesesenesaeessessessseseaceneesseceneseaesaes 4-1] 5.0 =Economic Parameters...essssssssccsssesseeessscessvscssessesssscceeceessseseeeasenssacssessesscseeeeeesseseseesensenes 5-1 5.1 Inflation and Escalation Rates .......:csccsscsssssescsscsccsscsscessssessessessceeesscesceneenseessessesnesnees 5-1 5.2 Financing Rates...csesssescessescessssssssssssscssseescsssesesseesseecescseensenesassasensessessesteneeenes 5-1 5.3 Present Worth Discount Rate..........ccccsssssssscesesessessssessssessesesesssessssessessesessesneareneseeres 5-1 Black &Veatch TC-2 February 2010 TABLE OF CONTENTS 6.0 7.0 8.0 9.0 10.0 ALASKA RIRP STUDY Table of Contents (Continued) 5.4 Interest During Construction Interest Rate .........ccsssssesssssscesssseseescsessssessesseseessecenees 5-1 5.5 Fixed Charge Rates .........ccsssssscssssesssssessseessessessssssesseassecseseeseesesasssensssenssesecensesaesaeanees 5-1 Forecast of Electrical Demand and Consumption ..........ccesessssesceesseseeececsacsecsceaceesesasenesesees 6-1 6.1 Load Forecasts 00...eeessssssssesssceccscseesesseessssseseaesseceeesensesesesceeesesseasscsencesseseneasaseeseseeeees 6-1 6.2 Load Forecasting Methodology .....s.scssssssssssssssssessessssessssesssesssessesescesssesessesesesceseseseases 6-1 6.3 Peak Demand and Net Energy for Load Requirement .............:csscssessssceseesceeeesereees 6-1 6.4 Significant Opportunities for Increased Loads ..........cssssssececeeceseeceeseceseesessensseesessees 6-4 6.4.1 Plug-In Hybrid Vehicles...sesssssceeceecsccscceesensessesecscesssecensenceneesseaees 6-4 6.4.2 Electric Space and Water Heating Load...sesstosstessesssessasesesseseees 6-10 6.4.3 Economic Development Loads...eeessesssseeeeesseeceeeeeceeseeeeeececeeeeeseesees 6-10 Fuel and Emissions Allowance Price Projections...........scssessessessessesceseceeseseeeeeceeseeeeneeseeeseees 7-1 7.1 Fuel Price Forecasts .0......ccccsssssscsssssscssceeneesessencesseessceseesessecseseeesansaccesecsseseeesesseereesenes 7-1 7.1.1.Natural Gas Availability and Price Forecasts....sssssssersesseseesseseeneees 7-1 7.1.2 Methodology for Other Fuel Price Forecasts ..0.........cssscssssscesessesseteneeessenes 7-9 7.1.3 Resulting Fuel Price Forecasts 2.0.0...seeesceeseesecescceeeeesseecetecteseseaesesseeseees 7-10 7.2 Emission Allowance Price Projections .......cccssssscssssssscsseessessenssssteseesensesssseseeneeeens 7-10 7.2.1 Existing Legislation...sessssscsscsssessnecsecsecesesesessescsesssesseesescsssssessesenese 7-10 7.2.2 Proposed Legislation ........cs csssssscsessesesessssscessscsseesssesssscsasssvscsesessesseseseeenss 7-10 7.2.3 Development of CO2 Emission Price Projection...cscs 7-10 Reliability Criteria 0.0...esescessescesssseececersressccsessesscosscssssusssesssssssscsssssessossesesssseseessaeeeesaneateas 8-1 8.1 Planning Reserve Margin Requirements ............essscessssssesssscsensssssseetssssnsssenseseneeen 8-1 8.2 Operating Reserve Margin Requirement.........cccscssscscssesseessesseessssesssssseseeeerenees 8-1 8.2.1 Spinning Reserves .........ceccssessscssessssssscssesssesesscescsesssneceeeeeseseesseseeeresseeseeeees 8-1 8.2.2 Non-Spinning Operating Reserves ..........sssssscssesssesseeeeseseeessesssessenesseeneees 8-2 8.3 -_Renewable Considerations...........ssssesssessesssesesessseseceneseseerscscsceesassssasessecessasesassnassseses 8-2 8.4 --_--Regulation .....cicccsscssscsssssesesscenseceseceseeeesressrssstesseaseesenseenneceseescsesssseagenseeeseeseaeeeess 8-2 Capacity Requirement ...........scsssesssssssssscsssscssssrsssssssssessessesseseesessscesessesensssenenenensonesenecesesses 9-1 Supply-Side Options 0.0...sssessssssssssssssssessssseesesesesssseneeeenesesssressssenesesneasarenensesseseeeneaneees 10-1 10.1 Conventional Technologies 0.0...esscssccsssssssseesssssesssesesseeeseeceseeneennentecseessesessneees 10-1 10.1.1 Introduction sssucsusenuessusssessussussuecsscssssusssnssssenscssscsusesscasceascauccsssesesseearecueeesees 10-1 10.1.2 Capital,and Operating and Maintenance (O&M)Cost Assumptions.......10-1 10.1.3 Generating Alternatives ASSUMPIONS ........cccscsseeseeeeteeeseeesseesesensenseseenes 10-1 10.1.4 Conventional Technology Options....icssssssssecssereeseseeetseeseseneneneesenes 10-5 10.2 Beluga Unit 8 Repowering.........csscsssssssecsseresssesesssesnsssesseeeeaceceseseseersnensceseesssenes 10-17 10.3 GVEA North Pole 1x1 Retrofit...cee cscsesscsscesesscreseseneessessensesacenesseseesesenenases 10-17 Black &Veatch TC-3 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) 10.4 Renewable Energy Options..........csscsessssssessserssssssssscseseecseeeseeeareceeesseceeseneeeesenes 10-17 10.4.1 Hydroelectric Project Options .......ccccssseessseessseessnseneetseeeseeseseseeeeteesees 10-17 10.4.2 Ocean (Tidal Wave)Project Option ......ccceesseseseeteeeeeteeeeensesnsnenenees 10-27 10.4.3 Geothermal Project Option....cssssssssssessssssseesseseseenseseteeeeesseeesneneeees 10-32 10.4.4 Wind Project Options ......ec ceescsesseescssscstesseeesessenseeeeseneenseesessesseneneees 10-35 10.4.5 Modular Nuclear Project Option ....ccc cessesscsseesssesssseseseeseeseeseeseeeeseees 10-40 10.4.6 Municipal Solid Waste Project Options .......ccesscecssesesenseseseenseneeeenes 10-45 10.4.7 Central Heat and Power...ccc cceusesssseecsesssseessscessssessaseeneseesseeenenseneses 10-45 11.0 Demand-Side Management/Energy Efficiency Resources .........cesssscsssessesersrssscessesessseseees 11-1 L1.1 Introduction...ccc ceescssessescescesceeseseeesceeesecessenseeessscescsssessssssuscssacsescesessseesseseasavaesees 11-1 11.2 Background and Overview .......cssssssscssecsessscseesesssecsesssscsscsscessscsssssesssessssensesseseeseess 11-2 11.2.1 Current Railbelt Utility DSM/EE Programs...ceceesseseseecessscseesesseeeeees 11-2 11.2.2 Literature REVIOW ...ceccsssesssssssseesesssessessseesseesssesssesssessseessessesssesssesssessseessees L 1-4 11.2.3 Characterization of the Customer Base 0...cccscscsssssesseseeresseneesseeaees 11-4 11.3.DSM/EE Potential...eeesssecssssecessecnecensesseseceseesecseseesesssesseeseessesssaseesseseeeoanss 11-6 11.3.1 Methodology for Determining Technical Potential...ee eeeseeeeeees 11-6 11.3.2 Intuitive Screening...cescesssesscesececeeccseesesenesecsssesesesceceaeseanseaseaseesesees 11-6 11.3.3 Program Design Process ..........::ssccssescesseressesseecsesseeseesecescesnssseseeeessesseeaeeses 11-7 11.3.4 Achievable DSM Potential from Other Studies 0...cesssessseeseeeeeneseneees 11-8 11.4 DSM/EE Measures.........ccsescsscsssecsessscscesssesseceessenenoneaceseseesssessasesesseseaasenseaseeseasonses 11-8 11.5 DSMV/EE Program Delivery ...........cscsccsssecesrcesssccsecenscessscccssncesscesesasesssetsaeeenseaeees 11-16 12.0 Transmission Projects ........ccccccccssssscescssecsscesessecssscucesaeesecesaceenssseeeaseaseseeenaeeceeseeesaneassaseneees 12-1 12.1 Existing Railbelt System...cee csseccsccesseesseeseecesteessecseeentceereceseecseesseseecsaseess 12-1 12.2 The GRETC Transmission Concept ...........ccsscsssssssessscsessessessscssecseeesseessessnesnseseasenes 12-3 12.3 Project Categories oo...eesessesseeccesctecessecescesesssesssecscesessescensecsacesesecsseaeeseeeaesaeenes 12-4 12.4 Summary of Transmission Analysis Conducted 0.0...cccssssesscesecceessesseeesseeseseeees 12-4 12.4.1 Cases Reviewed...cccscsssssesscsscessssecesesecssesescsesetsseesssessescensseceresssarsssesees 12-5 12.4.2 Results of 2060 AnalySis 0.0.0....csessscsccssecsssercescesccenceescsseceesessnessesasesseenens 12-6 12.5 Proposed Projects.......ccsssccccssssessssessecesseececseesseesececaccessesssssecsessesssssserssssassssesassesaees 12-6 12.6 SUSHIL eee eeseeeeseseseteneeaseceesssscnsesesesesssccassessesesscsssssesesscsesesacsssacaesseseseeaeacsneses 12-26 12.7 Summary of Transmission Projects ..........cssssssssesscsessssssssscssesessssesecsnessesesessessesss 12-27 12.8 Other Reliability Projects...essssssscscssessesesesesssssscsssssessessssesseseesseesseeeesersseces 12-30 12.9 Projects Priorities...ceeesecseseseesseseseesessceecssessssescsecseessssssssesseseeseseeeatsnesueseeacseesenss 12-31 Black &Veatch TC-4 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) 13.3 Summary of Results..........cscssssscsesssscsssscsscssessessestesssssessessscessssessesssavsesssceuscsessuse 13-11 13.3.1 Summary of Results -ECONOMICS ..........:ccsscesssscsssescesseseessssssesseeesesscessees 13-11 13.3.2 Summary of Results -Emissions............ceesccsscssssssesssesessesssecessesseseseneees 13-11 13.4 Results of Transmission AnalySis.........cccccsccsssssscssssesscsscetssessestessscesecsseeesscsceseseees 13-11 13.5 Results of Financial Analysis...sesssssscesscceseescessenessscececsseesssecescseceesasersecenes 13-16 14.0 Implementation Risks and [Ssues..........ccssssccssceccescsssssenssncssscessocsnsssssssesearenenseaeeaceanenseeecenes 14-1] 14.1.General Risks and Issues .0........csssscssessssesssccssssessscessecesceecsecssesescessssssssenssesasessecnasess 14-1 14.1.1 Organizational Risks and Issues..........cscsccsscsssesscesesscssessesecsecsaesescseceeees 14-1 14.1.2 Resource Risks and Issues..........scssssscsssssesseceecencsssssesscacencscesesseeseesseresenes 14-4 14.1.3 Fuel Supply Risks and Issues ..........cssscssssscessesceseesesssseensasesesssereceeeseeseenses 14-4 14.1.4 Transmission Risks and Issues ............scsssssccssessssssessescesseccssenceetseserseceenees 14-5 14.1.5 Market Development Risks and Issues.............eessssssesetceeeeeeereeesereereeeeeaes 14-5 14.1.6 Financing and Rate Risks and Issues....cesscscsecscscescsececeerseeecesesenseees 14-6 14.1.7 Legislative and Regulatory Risks and Issues ............ccssccsccscssestecscesseereees 14-7 14.1.8 Value of Optionality 0...eesseeseessessnceesessssetesssenssecsescestsnssassessesseees 14-7 14.2 Resource Specific Risks and Issues ........cscssscsscsssssssccsecsscscesssscsscscesetectatsecencesesenenss 14-8 14.2.1 [ntroduction wo...scsessesseseescesrencesseecscssceeecenseeceasssescesessssesseeeessassaeeeesees 14-8 14.2.2 Resource Specific Risks and Issues -SUMMALY ..........sccscseeseseeseeseereeees 14-8 14.2.3.Resource Specific Risks and Issues -Detailed Discussion................0000 14-12 15.0 Conclusions and Recommendations ............:cccsccsssceseceeseeseseescseeresssaseserscsseasseesssevscevsaseneneeoes 15-1 15.1 Conclusions ........cccccssssscscescssscercsccssceecsessceeseaceassesneneecaeseasesseseeaesseesnesessasosessesoeeeonees 15-2 15.2 Recommendations...cceecesceeseeeessseseseecssesscsensccsssssesessesesoescessessssscessessssearesesenss 15-6 15.2.1 Recommendations -General .......ec essssscsscssesscsssseceesesessessesessassaverscase 15-7 15.2.2 Recommendations -Capital Projects 0...csssssssssssesscsesscesserssenserereeees 15-11 15.2.3 Recommendations -Other...escscsseseecsesssecsecnescseseessesscsssseesseeseeseeeees 15-12 16.0 Near-Term Implementation Action Plan (2010-2012)sevuesessusessensnusesecensassesseetsssnssecnesssecee 16-1 16.1 .Gerneral Actions .......cecssscssscsrccscessecscesssveccososeusesssassssssesssssseseeenseneeesaneensessseseeenees 16-1 16.2 Capital Projects...cssescecsecescesccesesscsscseesccssesesscsccesscssseessstonssaneeeereseeneeseenecseensenss 16-3 16.3 Supporting Studies and Activities...cesssssssssessssseesseseessessesssesesessssssssssesesesseess 16-4 16.4 Other Actions .........cccsscsssssccsecsscecessccsseseeeneasessecosscosessnssssessssaceecaesencessaceenseeseenerenes 16-5 Black &Veatch TC-6 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) 13.0 Summary of Results...sesssssssssscssssssscsessesssesseesssseecssseseessssaeseesceecsessesasisoseseessaceraseeses 13-1 13.1 Results of Reference Cases....ccccscsccscscsessessecssssesssssssessseeseceeseneeceessessessresseseseneeees 13-1 13.1.1 Results -DSM/EE Resources.....esssssesesecssesscseeessecsecseessssasensesesseseessees 13-1 13.1.2 Results -Scenarios 1A/1B Reference Cases ......ccsesesesssetesteseeeseereceseees 13-2 13.1.3 Results -Scenario 2A Reference Case Results .......cicessssscseseereereneeeees 13-3 13.1.4 Results -Scenario 2B Reference Case Resullts.........cscsscsseseesressesrsseenees 13-3 13.2 Results of Sensitivity Cases ........csssssssssssssecscecseescnsenssessececsessssesssseseesesevenssssnasseseeees 13-3 13.2.1 Sensitivity Cases Evaluated...cesssssssscssstsssssssseresseesseseeseenssaeseeenees 13-3 13.2.2 Sensitivity Results -Scenarios 1A/1B Without DSM/EE Measures........13-4 13.2.3 Sensitivity Results -Scenarios [A/1B With Double DSM/EE MEASULES.......ssscesesssssccessesscesccessecsceeeseesesssesssesssoneesdsessesscssceusssssnsenseesseseenees 13-4 13.2.4 Sensitivity Results -Scenarios 1A/1B With Committed Units 1Gee)UK (<16 13-5 13.2.5 Sensitivity Results -Scenarios 1A/1B Without CO2 Costs...13-5 13.2.6 Sensitivity Results -Scenarios 1A/1B With Higher Gas Prices...............13-6 13.2.7 Sensitivity Results -Scenarios 1A/1B Without Chakachamna................13-6 13.2.8 Sensitivity Results -Scenarios 1A/1B With Chakachamna Capital Costs Increased by 75%......sssccsssssccssseseceecesesssscecceesssesessesssessesssesersessesennoes 13-6 13.2.9 Sensitivity Results --Scenarios 1A/1B With Susitna (Lower Low Watana Non-Expandable Option)Forced 0.0...ccsssccscssesseesscsevsessssscrseees 13-7 13.2.10 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Non-Expandable Option)Forced ........ccesesssseeeeeeesecseseesesseeessceseeseeseeees 13-7 13.2.11 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Expandable Option)Forced..........cccsssssersssessessesessessseeseseesssseescsessssscerenses 13-7 13.2.12 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Expansion Option)Forced...secssssscsssssssssessssesessssssssasssesessassecessssessers 13-8 13.2.13 Sensitivity Results -Scenarios 1A/1B With Susitna (Watana Option)Forced.........vacesceeesacsacenssesncesecsecacesesceaeaecsesssconsenesceneseaeeasesaseesenses 13-8 13.2.14 Sensitivity Results -Scenarios 1A/1B With Susitna (High Devil Canyon Option)Forced ..........cesesceseesessscssesceccsseseesseecesceesseceseeeeeeceeceacens 13-9 13.2.15 Sensitivity Results -Scenarios 1A/1B With Modular Nuclear.................13-9 13.2.16 Sensitivity Results -Scenarios 1A/1B With Tidal...eceeseeseeees 13-10 13.2.17 Sensitivity Results -Scenarios 1A/1B With Lower Coal Capital ANd Fuel Costs...esesscsssscesceesssenccecessseeesseeesscseeseesnsseseassseeseesensensensenenes 13-10 13.2.18 Sensitivity Results -Scenarios 1A/1B With Federal Tax Credits for Renewables........ssssccssssssscsssccsecsessssessecessssssssceassessessssesscsesseesassasseseceacaes 13-10 Black &Veatch TC-5 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Appendix A Susitna Analysis Appendix B_Financial Analysis Appendix C Existing Generation Units Appendix D Regional Load Forecasts Appendix E Detailed Results -Scenarios 1A /1B Appendix F Detailed Results -Scenario 2A Appendix G Detailed Results -Scenario 2B Tables Table 1-1 Summary Listing of Issues Facing the Railbelt Region...et eeeeseeeeeeeceereeneeeeees 1-3 Table 1-2 Alternative Resource Options Considered ...........cescssescssesecesssessscesessessseseeseessessenees 1-5 Table 1-3 Susitna SUMIMALY .........csccsscsccessescseccestcscssesscsseseccsecsescsscesesacentscaecansenseseseeeseeeseeseeeeas 1-10 Table 1-4 Summary of Results -EcOmOMICS «00.0.0...sesssecesceecceeeesecsesessesceceseesssssessesansaeaesesees 1-17 Table 1-5 Summary of Results -Emissions ...........scccscssccssesccsscsscsssssessecsceseeesseseeeesssaseeseeeenees 1-18 Table 1-6 Summary of Proposed Transmission Projects ........cscssssssessescecsserecseeeeeeeeesseeersesaeees 1-19 Table 1-7 Resource Specific Risks and Issues -SUMMATY .........scssessecssesseeseeseeseeeesesesteereares 1-28 Table 1-8 Resources Selected in Scenario 1A/1B Resource Plan...eesessceeeesessceeeseeesene 1-35 Table 1-9 Impact of Selected Issues on the Preferred Resource Plan...scscssesssssesesseseseees 1-36 Table 1-10 Projects Significantly Under Development .......ec ccecsessseseesssstcessesssseesseessessasvens 1-37 Table 1-11 |Near-Term Implementation Action Plan -General ACtions .......csccccsssscssersseserseeses 1-41 Table 1-12 |Near-Term Implementation Action Plan -Capital Projects 0...sesssenseesseseseees 1-43 Table 1-13 Near-Term Implementation Action Plan -Supporting Studies and Activities........1-44 Table 1-14 |Near-Term Implementation Action Plan -Other Actions.........ccsssssssscssssossseseneees 1-45 Table 3-1 Relative Cost per kWh (Alaska Versus Other States)-2007 .......csssssscssssesssetsreeres 3-4 Table 3-2 Relative Monthly Electric Bills Among Alaska Railbelt Utilities............ccssessesees 3-5 Table 4-1 ML&P Existing Thermal Units.............csssscsssesceesscssseesscsssscssssssscsssssscseeesssessseaseenaees 4-] Table 4-2 Chugach Existing Thermal]Units...tcsssscssssssssssesssssssscsesesssenensssesseessnsseseeesnensees 4-2 Table 4-3 GVEA Existing Thermal Uniits..........cccssssessssesessscsssssscsssenssssscssssseseessetsecesseeerseeneenees 4-3 Table 4-4 HEA Existing Thermal]Units...cccssssesssssesssscsssscestsccesssseseseeessessenssessenssesseaeeaeeees 4-3 Table 4-5 Railbelt Hydroelectric Generation Plants .0......csssssssssceesseeresesescesensenesnenesessssaseees 4-4 Table 4-6 Hydroelectric Monthly and Annual Energy (MW))..........ssssseececensererereraseseenecees 4-4 Table 4-7 Railbelt Installed Capacity 0...eesssesssssssscssscsssscssesesseeesssseessesssneeseessenesesssseeneeners 4-5 Table 4-8 Railbelt Committed Generating ReSOUrCES.........ssssessssssesseseseesesseseeneneenseeeteenesenenees 4-6 Table 5-1 Cost of Capital and Fixed Charge Rates for the GRETC System.......cccsccssseseereserees 5-2 Black &Veatch TC-7 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Tables (Continued) Table 6-1 GRETC's Winter Peak Load Forecast for Evaluation (MW)2011 -2060.............6-2 Table 6-2 GRETC's Summer Peak Load Forecast for Evaluation (MW)2011 -2060.............6-2 Table 6-3 GRETC's Annual Valley Load Forecast for Evaluation (MW)2011 -2060............6-3 Table 6-4 GRETC's Net Energy for Load Forecast for Evaluation (GWh)2011 -2060..........6-3 Table 6-5 Projected PHEV Penetration in the American Auto Market ......cccseceeesseeeeeeeerenes 6-4 Table 6-6 Electric Consumption for a PHEV33 PNNL Kinter-Meyer .......scsssssssssssssesssseseenses 6-5 Table 6-7 Additional Annual Energy Required in the Alaska Railbelt Region from PHEVS.....ccscsscssssessescssescsscsesscsccsceecscsseecesescesssesacecsnesesseuseaesaueassnsscsassceussavessessusessesesess 6-5 Table 6-8 Hourly Distribution of PHEV Load on a Typical Day -Alaska Railbelt REGION .....ccsscssccscesssssscersssssecessssesseccesesescessssssesssscssecssusssssessensseseeseessesnseeneeeatentesseeseenes 6-7 Table 6-9 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Energy Requirement.......cccsssessessscssccsscsssessssscssnseesessessnsessssesesceseseesesensees 6-9 Table 6-10 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Peak Demand....scesesseccssesssseseesssscenscseeeesscsssessessscsssssessevsuensesnsessereeees 6-9 Table 6-11 |2007 Natural Gas Consumption for the State of Alaska (Source:EIA)........ccece 6-10 Table 6-12.Calculated Railbelt System Energy and Demand by Customer Type for Electric Space and Water Heating ...........cccccescecseccessescceeseeceeeeeetecsceetseessessseeeasses 6-10 Table 6-13 Potential Economic Development Projects...csscsssssssssssescsesssssssssesssssseseneeesees 6-11 Table 6-14 GRETC's Winter Peak Large Load Forecast for Evaluation (MW)2011 - 2060...eeesseseencescscesseecscencssesseceecenesessecescsaeseeesasscesscesecesssseeesoassssecoasaneesensaseesessessesess 6-12 Table 6-15 ©GRETC's Large Load Net Energy for Load Forecast for Evaluation (GWh) ZOL1 -2060 oe cescscecsssesessssseeseccssssssnscssssssessesscesessesesssssceseassassseseessassccasensecsesase 6-12 Table 7-1 Representative Risk-Based Metrics for Railbelt Natural Gas Demand Based on Historical Data and Known Changes in Gas Consumption .......csccssersssssereneeens 7-4 Table 7-2 Representative Forecasts of Railbelt Natural Gas Price According to Different Benchmarks...ees ecsescssseceeeseecencssesececcesenseeessaseeceseesaceessaseseeseeesceeseaseeees 7-9 Table 7-3 Nominal Fuel Price Forecasts ($S/MMBtu)........ccscccccssssscesescescsessescsesessacsessssessseseees 7-11 Table 7-4 COz Allowance Price Projections ..........sccssesccsscsssssssssessssescesecsessessseessesessesessesesaes 7-13 Table 8-1 Railbelt Spinning Reserve Requirement ..........cccscssssssssssesscscsssssssscscsseseesesneaeseeseceeaes 8-1] Table 8-2 Quick-Start Units ........ccscscscesseseesesssessescsscesessesssasecseeeseesesessscaceesecssessessausessesenseasanses 8-3 Table 10-1 -Possible Owner's Costs.........ssssssssssssssssscssscsssssssscsessseseecsessessesescatecssesecessustensaceasesses 10-2 Table 10-2 Nonrecoverable Degradation Factor ......ccccssecscsssssesssessssesssssscsssesssssssescescseassssscses 10-6 Table 10-3 GELM6000 PC Combustion Turbine Characteristics ...........cscscssssssssssessseeseescees 10-8 Table 10-4 GELM6000 PC Estimated Emissions.........ccccsscsssssscssesesssssssessssesesesssessssassssencevenes 10-8 Table 10-5 GELMS100 Combustion Turbine Characteristics .........cccccccscsssssssssscsscecssssesesseees 10-10 Black &Veatch TC-8 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Tables (Continued) Table 10-6 GELMS100 Estimated Emissions............csessssecessscssccsseeesccssscsscosesecessesseesssssasses 10-10 Table 10-7 GE1x1 6FA Combined Cycle Characteristics 00.0.0...scessesssseseesssscssesesseecessuceevens 10-12 Table 10-8 GE1x1 6FA Combined Cycle Estimated Emissions...........ccesssssssssssssesesseoseneee 10-12 Table 10-9 GE 2x1 6FA Combined Cycle Characteristics 0....cceescssseecsccscsessesessssesoesonees 10-13 Table 10-10 GE2x1 6FA Combined Cycle Estimated Emissions..............:ssceccsscecsssssecseeseeseses 10-13 Table 10-11 Subcritical PC Thermal Performance Estimates........ssssssssessesssssessssssessssssescseenees 10-15 Table 10-12 Subcritical PC Estimated Air Emissions...cisessssscsesssscsscsesssssssscsessesersssesesenens 10-15 Table 10-13 Capital Costs,O&M Costs,and Schedules for the Generating Alternatives - (Al Costs in 2009 Dollars)0...sesssssssssssessssscsssssssssssssesesssesssensesseeseeseeseseenneees 10-16 Table 10-14 AEA Recommended Funding Decisions -Hydro...eecesssesestssenetecseeerseeees 10-18 Table 10-15 Susitna Summary ou...eeeeesesseeceecsecsesceeeesecsesssseesenssssesssssscorecsesesesesesasenessensessens 10-21 Table 10-16 Average Annual Monthly Generation from Susitna Projects (MWh)........ceesee 10-23 Table 10-17 Monthly Average and Annual Generation.......ccsscsescsreressssscensssseeesesnensrseceeseees 10-25 Table 10-18 Glacier Fork Hydroelectric Project Average Monthly Energy Generation...........10-26 Table 10-19 AEA Recommended Funding Decisions -Wind.........cssssesersssersnseessseseeeeeesanens 10-36 Table 11-1 |Current Railbelt Electric Utility DSM/EE-Related Activities ........cccscssssesseeeeeees 11-2 Table 11-2 DSM/EE-Related Literature Sources 00...ssssessessssssssesssssseeerecesesnesesesnesneseeaenees 11-4 Table 11-3 Railbelt Electric Utility Customer Base...tsssescsscstseesesseseneerssnenseseesaseesenenees 11-5 Table 11-4 Residential and Commercial DSM/EE Technologies Evaluated.........cscccessesees 11-10 Table 11-5 Input Assumptions -Residential DSM/EE Measures.........ssessseceeesssecserceeessseseees 11-12 Table 11-6 Input Assumptions -Commercial DSM/EE MEeasufes........ccsssssecssssseeeserereceessenees 11-13 Table 12-1 Summary of Proposed Transmission Projects .......sssscssssssresesssseseeseseseesessenseeessees 12-27 Table 13-1 Summary of Results -ECONOMICS .........cssssesssseseseseseeseeesesereesneseesenerenteessssesssasoes 13-12 Table 13-2.Summary of Results -Emissions ..........ssscssssssssssssessssssceneesesensnsceesessseessesorcenesseees 13-13 Table 13-3 Summary of Proposed Transmission Projects .......:cssccesseserecesereeeesensseneeesseeseees 13-14 Table 14-1 Resource Specific Risks and Issues -SUMMALY ..........eeceseesssseeeeetcseeeetaseesseteeneenees 14-9 Table 14-2 Resource Specific Risks and Issues -DSMI/EE .......scsssssssssesesceessstseetsnsvscsesenensaees 14-13 Table 14-3 Resource Specific Risks and Issues -Generation -Natural Gas ........ssssssessssessees 14-16 Table 14-4 Resource Specific Risks and Issues -Generation -Coal...sssssssecreresssseseseesees 14-18 Table 14-5 Resource Specific Risks and Issues -Generation --Modular Nuclear............0+0 14-19 Table 14-6 Resource Specific Risks and Issues -Generation -Large Hydro...14-20 Table 14-7.Resource Specific Risks and Issues -Generation -Small Hydro........sssssssseeees 14-21 Table 14-8 |Resource Specific Risks and Issues -Generation -Wind «0...ssssseesssseeneseeseseees 14-22 Table 14-9 |Resource Specific Risks and Issues -Generation -Geothermal ...........ssesssssssere 14-23 Black &Veatch TC-9 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Tables (Continued) Table 14-10 Resource Specific Risks and Issues -Generation -Solid WasSte........ssssesesseseres 14-24 Table 14-11 Resource Specific Risks and Issues -Generation -Tidal........cccssssseseseseeseneeeees 14-25 Table 14-12 Resource Specific Risks and Issues -Transmission.........csscssssseeseeresseseeessseneees 14-27 Table 15-1 |Resources Selected in Scenario 1A/1B Resource Plan...csssssssssssetsetseseneeeeees 15-8 Table 15-2 Impact of Selected Issues on the Preferred Resource Plan.......sssesescsssseesceesecnenees 15-9 Table 15-3 --Projects Significantly Under Development ............ccsssssssssessseesessressersenseseneeerees 15-10 Table 16-1 |Near-Term Implementation Action Plan -General Actions ..........scsesereeeseeesreneens 16-1 Table 16-2 Near-Term Implementation Action Plan -Capital Projects .........scscssseseseeesereneees 16-3 Table 16-3 Near-Term Implementation Action Plan -Supporting Studies and Activities........16-4 Table 16-4 Near-Term Implementation Action Plan -Other Actions.........sssscscseresssseeseees 16-5 Figures Figure 1-1 Evaluation Scemarios.........ccsccscsssccscssesssscscessscccesenseccessecseesesecsesssseasseesesscsesossscsssessasees 1-7 Figure 1-2.|Comparison of Project Cost Versus Installed Capacity .........cscsssssessssssessseessesssees 1-11 Figure 1-3 Impact of DSM/EE Resources -Base Case Load Forecast.......ssssscscssssensesrereseee 1-14 Figure 1-4 -Results -Scenarios 1A/1B Reference Cases...esesssssscessceseessensesseeseseesseseeeees 1-15 Figure 1-5 -_Results -Scenario 2A Reference Case...ssessssssecssesseseescescssssssesecseseeesesnesseasenes 1-15 Figure 1-6 -Results -Scenario 2B Reference Case oc essssesseteceeessesscsesseeseesceeeeesessesseenssess 1-15 Figure 1-7 -Location of Proposed Transmission Projects (Without Susitna).......cc ceceseeeeee 1-20 Figure 1-8 |=Required Cumulative Capital Investment for Each Base Case.........csssssessseeseeees 1-23 Figure 1-9 |Required Cumulative Capital Investment (Scenarios 1A/1B)Relative to Railbelt Utility Debt Capacity 0.0...cc csesssssesssssesecsnsecesseneesecsesscceceenseneneeeessasecees 1-24 Figure 1-10 Cumulative Present Value Cost -Selected Reference and Sensitivity Cases.........1-30 Figure 1-11 Annual Wholesale Power Cost -Selected Reference and Sensitivity Cases ..........1-30 Figure 1-12 Comparison of Results -Scenario 1A/1B Versus Committed Units SeMSitivity Case...cssccssssssssecescssssssssssessssssssseesscesesssesesseceeseesssesessecsusssessesseseessceess 1-32 Figure 1-13.Interplay Between GRETC and Regional Integrated Resource Plan.............0000 1-33 Figure 2-1 Project Approach OVEerview.........cssssssssssssssssssssesscssscsessssesssesssesnssssnsssecscscnsesseesssneneess 2-3 Figure 2-2 --_Evaluation Scenarios........ccccsccscsscesscsceseesecsesetescesesscesessesasscesececesscsesesseseusneatssssaeesssees 2-7 Figure 2-3 Elements of Stakeholder Involvement Process.........csscsssssscssesessessesseseeeseestsceseessenees 2-8 Figure 3-1 Summary of Issues Facing the Railbelt Region ..........ccssssssssssessesseressssssseseesesseseeeeees 3-1 Figure 3-2.Chugach's Reliance on Natural Gas .........cccssssssssssssscssssessecscssssesssesesseceases sevseeeeeeeeeees 3-8 Figure 3-3 Overview of Cook Inlet Gas Situation...ccesccsccsssesccscsssssssessssesssssscssescsssscssssssseess 3-8 Black &Veatch TC-10 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Figures (Continued) Figure 3-4 -_Historical Chugach Natural Gas Prices Paid ........cccsssssssssssesssssscssesesesessecsceceeesssesens 3-9 Figure 3-5 Chugach Residential Bills Based on 700 kWh Consumption.........ccccsscscssssessesessees 3-9 Figure 4-1 --Railbelt Existing Transmission System as Modeled.......scsscssssscsssscsssssesesscsseesseeseens 4-9 Figure 6-1 US Daily Driving Patterns ..........c.cccssessssesesscsessesssscesssesessssesssceecsessesaeseceessesseseesesneees 6-6 Figure 6-2.PHEV Daily Charging Availability Profile ............ccssssscsssscssssesessssessscessesseenencssees 6-6 Figure 6-3 Hourly Distribution of PHEV Load ona Typical Day -Alaska Railbelt REGION...sceessecesssceceseesssscessscecseessessssscssseesscesssscusesseesessscuceseeeecusnesaceasaneesseeseeeeass 6-8 Figure 6-4 =Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Energy Requirement............:ccsccscssssescerscsscssesssssessecssenessnceneeeaeesseeseeseeeacees 6-8 Figure 6-5 -Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Peak Demand...ee essssssseeeescsseecoesescessetssesessssseeecsecesecessssseessessosssaseseens 6-9 Figure 7-1 Results of a Risk-Based Gas Supply Model Simulation for the Year 2017 ..............7-2 Figure 7-2.|Schematic Summary of the Probabilistic Gas Supply Forecast Model .............-.ee0 7-3 Figure 7-3 -Comparison of Natural Gas Price Forecasts Relevant to Railbelt Resource PLANS...cssesescsecssessesssssevsceseseessesseccecessecessesceesensesessececssseasecessssessassnsssessoesssseeeasensesoases 7-8 Figure 9-1 Scenario 1A Capacity Requirements Without DSM/EE uu...ccc csscsscseeseeseeeseossensees 9-2 Figure 9-2.Scenario 1A Capacity Requirements With DSM/EE.......csseseesseees sereeeneeseesseeceeasane 9-3 Figure 9-3 Scenario 2A Capacity Requirements Without DSM/EE .........esessesseseeceeeeeresseesoes 9-4 Figure 9-4 Scenario 2A Capacity Requirements With DSM/EE............cscesssesssceeseetersesesesessesees 9-5 Figure 9-5 Scenario 1A Capacity Requirements Including Committed Units Without DSMLEE.........ssccssssssssessscescscessecescesssassccseeasecesesenssesessusecsseecssscesssssecscoscsesessassensesansessnses 9-6 Figure 9-6 |Scenario 1A Capacity Requirements Including Committed Units With DSMLEE.......sccscsssccsssscsssssccscssceesssesccsceesscesceacaescsscesesassasseasscesssseeeasessessasscesssasansesonsanves 9-7 Figure 10-1 Proposed Susitna Hydro Project Location (Source:HDR)).......cssssssessesssessseeees 10-19 Figure 10-2.Comparison of Project Cost Versus Installed Capacity .......cccsssssssssesssseeeeesenees 10-22 Figure 10-3 Proposed Chakachamna Hydro Project Location (Source:TDX)........sssssseseeene 10-24 Figure 10-4 Blue Energy's Tidal Bridge With Davis Turbine (Source:Blue Energy)...........+.10-28 Figure 10-5 Cutaway Graphic of a Mid-Range-Scale Vertical Axis Tidal Turbine (Source:Blue Energy).......scsssscsssscssssssssssssssssssesseeessssesesessesssesssssseersnssessenesenecses 10-29 Figure 10-6 Proposed Layout of the Turnagain Arm Tidal Project (Source:Little Susitna Construction Co.and Blue Energy of Canada).........scscssssssssesssessssseesseseeseeeeees 10-30 Figure 10-7 Turnagain Arm Tidal Project Monthly Generation ..........s.sssssssssssesserseeseesseneensenes 10-31 Figure 10-8 Simplified Binary Geothermal Power Plant Process (Source:Ormat).........seeeeees 10-33 Figure 10-9 Simplified Geothermal Combined Cycle Power Plant Process (Source: Ormat.....ccccsssscressecscssescnsenenseesesssesessssssnssecesesuessensarsessesesusearseeesaeecnensegs Vesseneeneesseeeee 10-33 Black &Veatch TC-11 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Figures (Continued) Figure 10-10 Estimated Mount Spurr Project Development Plan (Source:Ormat)........scese 10-35 Figure 10-11 Visual Simulation of Fire Island Wind Generation Project (Source: CIR]/enXco Joint Venture)...cccccssssccsssssssessecsceseeeetseeescessesssscsscssssesseenssseseeases 10-37 Figure 10-12 Preliminary Site Arrangement and Interconnection Route (Source: CIRI/enXco Joint Venture).......ccscscccssssscercesceeceeseeeserseceesenssseesessesesssenssenssassesaess 10-38 Figure 10-13 Kenai Peninsula,Nikiski (Source:Kenai Winds LLC).....ccc cssessseeeseeseseeees 10-39 Figure 10-14 Simplified Hyperion Power Cycle Diagram (Source:Hyperion Power GeNeration)......cscscesscssscseeseeseccestcecesetseeeecessessessesensesaesessasossssecsscassssssssaceeseeseeseees 10-41 Figure 10-15 Requested Potential Advanced Reactor Licensing Application Timelines (Source:NRC February 20,2008 Briefing Presentation Slide)...sess 10-43 Figure 10-16 NRC New Licensing Process and Construction Timelines for New Reactors (Source:NET website)...csesssscssssssssssessssssssssssssessescssssssssssssesneasessssesaaseessese 10-44 Figure 11-1 Common DSM/EE Program Development Process seuseeccansvsecssnevecessssstsssssasuusessasees 11-7 Figure 11-2.EPRI/EEI Assessment:West Census Region Results 0.0...csescsscecsesesseesessenseeses 11-9 Figure 12-1 -Railbelt Transmission System OVerVview......sssescsssssesssesesseerereereneneeesteneeneeasensereees 12-2 Figure 12-2.Bernice Lake Power Plant to International 230 kV Transmission Line (New Build).......ccseeescsscescsesecceccssecessscessecsceseetseseesnescescesesseatceseasscessescaceasaceeeseaenseansensseues 12-7 Figure 12-3 Soldotna to Quartz Creek 230kV Transmission Line (Repair and Replacement)..........ccscsscsscsssssscesccsrcssccscesseesesssscooescnsessssasceasonsesersacensscacenseeseesnsonesenes 12-8 Figure 12-4 Quartz Creek to University 230kV Transmission Line (Repair and Replacement).........ees eeesescescesseeesseecesceseessesseseescesseseececceesseeseesesesesesseassseeseesnsesesees 12-9 Figure 12-5 Douglas to Teeland 230 kV Transmission Line (Repair and Replacement).........12-10 Figure 12-6 Lake Lorraine to Douglas 230 kV Transmission Line (New Build)...............006 12-12 Figure 12-7 Douglas to Healy 230 kV Transmission Line (Upgrade)...........csscssseceseesresseeserees 12-13 Figure 12-8 Douglas to Healy 230 kV Transmission Line (New Build)..............cccsscessereseeseee 12-14 Figure 12-9 _Eklutna to Fossil Creek 230 kV Transmission Line (Upgrade).............:.sessesesees 12-15 Figure 12-10 Healy to Gold Hill 230 kV Transmission Line (Repair and Replacement)...........12-16 Figure 12-11 Healy to Wilson 230 kV Transmission Line (Upgrade)........csssssescssssesessssseesesesees 12-17 Figure 12-12 Soldotna to Diamond Ridge 115 kV Transmission Line (Repair and Replacement).0.......eseeessssssesssceseseessssscssssseseseseesensesesseessessseesssaeseseseseesessseesseeseeasees 12-18 Figure 12-13 Lawing to Seward 115 kV Transmission Line (Upgrade).......s.cscscsssesssssescssssseesees 12-19 Figure 12-14 Eklutna to Lucas 230 kV Transmission Line (Repair and Replacement)..............12-20 Figure 12-15 Lucas to Teeland 230 kV Transmission Line (Repair and Replacement).............12-21 Figure 12-16 Fossil Creek to Plant 2 230 kV Transmission Line (Upgrade)........sscsssssssseeeees 12-22 Figure 12-17 Pt.Mackenzie to Plant 2 230 kV Transmission Line (Repair and Replacement).....ccesssscssssssescsseessseceseccseescsessssceessesssesseseseesesesecsusesscesasseessecscseses 12-23 Black &Veatch TC-12 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Figures (Continued) Figure 12-18 Bernice Lake to Soldotna 115 kV Transmission Line (Rebuild)............ccssssseeseee 12-24 Figure 12-19 Bernice Lake to Beaver Creek to Soldotna 115 kV Transmission Line (Rebuild)oo.eesceseccscesesscecessesecessesssssssescesssessescsesesesssasscesessacssressauseseseeseeees 12-25 Figure 12-20 Susitna to Gold Creek 230 kV Transmission Line .........ccscsssesesessessessscssseseecserees 12-26 Figure 12-21 Location of Proposed Transmission Projects (Without Susitna).........cccssssssseeees 12-28 Figure 12-22 Location of Proposed Transmission Projects (With Susitna)..........ccsscsssssseeseeees 12-29 Figure 13-1 Impact of DSM/EE Resources -Base Case Load Forecast.......cssssscccssecssssssssssscess 13-2 Figure 13-2 Results -Scenarios 1A/1B Reference Cases.......cssssssssssssccsssesessscsescsssseeseseeeenes 13-2 Figure 13-3 Results -Scenario 2A Reference Case.........sssssssssscessscsssssscsssssssscesssssescescasscsaessees 13-3 Figure 13-4 Results -Scenario 2B Reference Case .........cccesscsssessssssssssssessessssessssssenessesessosrecssess 13-3 Figure 13-5 Sensitivity Results -Scenarios 1A/1B Without DSM/EE Measures ...........ccseeee 13-4 Figure 13-6 Sensitivity Results -Scenarios 1A/1B With Double DSM/EE Measure................13-4 Figure 13-7 Sensitivity Results -Scenarios 1A/1B With Committed Units Included................13-5 Figure 13-8 Sensitivity Results -Scenarios 1A/1B Without CO2 Costs ........scscseseesrescessesnees 13-5 Figure 13-9 Sensitivity Results -Scenarios 1A/1B With Higher Gas Prices ..........cssscsscerserseees 13-6 Figure 13-10 Sensitivity Results -Scenarios 1A/1B Without Chakachamna.............csccsseeceeees 13-6 Figure 13-11 Sensitivity Results -Scenarios 1A/1B With Susitna (Lower Low Watana Non-Expandable Option)Forced...csessescsssssssessesscssseseesessecessecsssssessesesseseseeses 13-7 Figure 13-12 Sensitivity Results --Scenarios 1A/1B With Susitna (Low Watana Non- Expandable Option)Forced...eeesceseessesecsecessssecssssssssesssssssesecsesseessesessesessaeesees 13-7 Figure 13-13 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Expansion Option)Forced .......csccsscssessesseesessccsesssssessssssssasssssesssreseassessssensseseaees 13-8 Figure 13-14 Sensitivity Results -Scenarios 1A/1B With Susitna (Watana Option)Forced.......13-8 Figure 13-15 Sensitivity Results -Scenarios 1A/1B With Susitna (High Devil Canyon Option)Forced 0...seessssesesssscssessssssseessessossssssecessssssssssnsssssssensnavessseecesssseseeeseneteeee 13-9 Figure 13-16 Sensitivity Results -Scenarios 1A/1B With Modular Nuclear.........:cssssssreccseees 13-9 Figure 13-17 Sensitivity Results -Scenarios 1A/1B With Tidal...seeseseesesecsesseaeeneenenes 13-10 Figure 13-18 Sensitivity Results -Scenarios 1A/1B With Lower Coal Capital and Fuel COStS....scsscsssssssescesecssccenccsncentsescensseeesscenessaeecsescsusssasosevsssnssosessusetsnsssssnseseteneseereneeeee 13-10 Figure 13-19 Sensitivity Results -Scenarios 1A/1B With Federal Tax Credits for Renewables ........scssccsssssescssssscssscsssceeesencessesseseassessccsssscssccesesssscsesatsseeseeseesseneesensones 13-10 Figure 13-20 Required Cumulative Capital Investment for Each Reference Case ........sssseee 13-16 Figure 13-21 Required Cumulative Capital Investment (Scenarios 1A/1B)Relative to Railbelt Utility Debt Capacity 00...esessecssssssssssssssssssscscssseeseesseneseesnsnsnessssnaces 13-17 Black &Veatch TC-13 February 2010 TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Figures (Continued) Figure 15-1 Cumulative Present Value Cost -Selected Reference and Sensitivity Cases.........15-3 Figure 15-2.Annual Wholesale Power Cost -Selected Reference and Sensitivity Cases ..........15-3 Figure 15-3 Comparison of Results -Scenario 1A/1B Versus Committed Units SeMSitivity Case...cccescssssssesccesssceseessececssesesssesssessessessosescsesesessesseseesssassessaseoerenes 15-5 Figure 15-4 Interplay Between GRETC and Regional Integrated Resource Plan...15-6 Black &Veatch TC-14 February 2010 ACRONYM LIST ALASKA RIRP STUDY ACEEE American Council for an Energy Efficiency Economy ACESA American Clean Energy and Security Act of 2009 AEA Alaska Energy Authority AHFC Alaska Housing Finance Corporation AIDEA Alaska Industrial Development and Export Authority APA Alaska Power Authority ARRA American Recovery and Reinvestment Act of 2009 Bef Billion cubic feet BESS Battery energy storage system CCS Carbon capture and sequestration CFL Compact fluorescent light C/I Commercial and industrial CO,Carbon dioxide COLA Construction and operation license application CTG Combustion turbine generator CWIP Construction-work-in-progress DPP Delta Power Plant DR Demand response DSM/EE Demand-side management/energy efficiency EEI Edison Electric Institute EIA Energy Information Administration EPA Environmental Protection Agency EPRI Electric Power Research Institute EPS Electric Power Systems,Inc. FERC Federal Energy Regulatory Commission FGD Flue gas desulfurization GE General Electric GHG Greenhouse gas GRETC Greater Railbelt Energy &Transmission Company G&T Generation and transmission GVEA Golden Valley Electric Association HAGO High atmospheric gas oil HCCP Healy Clean Coal Project HDR HDR,Inc. HEA Homer Electric Association HHV Higher heating value HPC High-pressure compressor HPT High-pressure turbine HSRG Heat recovery steam generators Hz Hertz IP Intermediate-pressure IPP Independent power producers AL-1 February 2010Black&Veatch ACRONYM LIST ALASKA RIRP STUDY IRS Interconnection requirements studies JV Joint venture kV Kilovolt KW Kilowatt kWh Kilowatt-hour LEEP Lighting Energy Efficiency Pledge LNG Liquefied natural gas LP Low-pressure LPT Low-pressure turbine MEA Matanuska Electric Association ML&P Anchorage Municipal Light &Power MMBtu Million British thermal units MMcf/d Million cubic feet per day MSW Municipal solid waste MW Megawatt NO,Nitrogen oxides OEM Original equipment manufacturer O&M Operations and maintenance PC Pulverized coal PHEV Plug-in hybrid vehicles PPA Power purchase agreement PPM Part per million REC Renewable energy credits REGA Railbelt Electrical Grid Authority RIRP Railbelt Integrated Resource Plan ROW Right-of-way RPM Revolutions per minute RPS Renewable portfolio standard SBC System benefit charge SCR Selective catalytic reduction SES City of Seward Electric System SILOS Shed in lieu of spin SNW Seattle-Northwest Securities Corporation SO,Sodium oxides SVC Static var compensators TOU Time-of-use ULSD Ultra-low sulfur diesel USDA-RUS United States Department of Agriculture/Rural Utilities Service WGA Western Governor's Association Black &Veatch AL-2 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.0 EXECUTIVE SUMMARY In response to a directive from the Alaska Legislature,the Alaska Energy Authority (AEA)was the lead State agency for the development of a Regional Integrated Resource Plan (RIRP)for the Railbelt Region.This region is defined as the service areas of six regulated public utilities,including:Anchorage Municipal Light & Power (ML&P),Chugach Electric Association (Chugach),Golden Valley Electric Association (GVEA),Homer Electric Association (HEA),Matanuska Electric Association (MEA),and the City of Seward Electric _ System (SES).A seventh utility,Doyon,is interconnected to the Railbelt system serving the military bases of Fort Greely,Fort Wainwright,and Fort Richardson,but is not included in this RIRP. The purpose of this document is to provide the results of the RIRP study.This section includes the following subsections: e Current Situation Facing the Railbelt Utilities e Project Overview e Evaluation Scenarios e Summary of Key Input Assumptions e Susitna Analysis e Transmission Analysis e Summary of Results e Implementation Risks and Issues e®Conclusions and Recommendations e Near-Term Implementation Plan (2010-2012) Some Definitions Three Discrete Tasks ©REGA means "Railbelt Electrical e REGA study determined the business structure Grid Authority”for future Railbelt generation and transmission e GRETC means "Greater Railbelt (G&T) Energy &Transmission Company”e GRETC initiative is the joint effort between e RIRP means "Railbelt Integrated Railbelt Utilities and AEA to unify Railbelt G&T Resource Plan”e RIRPis the economic plan for future capital investment in G&T and in fuel portfolios that GRETC would build,own and operate 1.1 Current Situation Facing the Railbelt Utilities The Railbelt generation,transmission,and distribution infrastructure did not exist prior to the 1940s.At that time,citizens in separate areas within the Railbelt region joined together to form four cooperatives (Chugach, GVEA,HEA,and MEA)and two municipal utilities (ML&P and SES)to provide electric power to the consumers and businesses within their service areas.Collectively,these utilities are referred to as the Railbelt utilities. Black &Veatch 1-1 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY The independent and cooperative decisions made over time by utility managers and Boards,as well as the State,in a number of areas have significantly improved the quality of life and business environment in the Railbelt.Examples include: The evolution of the business and operating environment,and changes in the mix of Infrastructure Investments -the State and the Railbelt utilities have made significant investments in the region's generation and transmission infrastructure.Examples include the Alaska Intertie and Bradley Lake Hydroelectric Plant. Gas Supply Investments and Contracts -ML&P took a bold step when it purchased a portion of the Beluga River Gas Field,a decision that has produced a significant long-term benefit for ML&P's customers and others within the Railbelt.Additionally,Chugach was able to enter into attractive gas supply contracts.These decisions have resulted in historical low gas prices which have significantly offset the region's inability to achieve economies of scale in generation due to its small size. Innovative Solutions -GVEA's Battery Energy Storage System (BESS)is one example of numerous innovative decisions that have been made by utility managers and Boards to addressissuesthatareuniquetotheRailbeltregion. Joint Operations and Contractual Arrangements -over the years,the Railbelt utilities have joined together for joint benefit in terms of coordinated operation of the Railbelt transmission grid and have entered into contractual arrangements that have benefited each utility. stakeholders,presents new dynamics for the way decisions must be made.This CurrentchangingenvironmentposessignificantchallengesfortheRailbeltutilitiesand,indeed,Situation all stakeholders.In fact,it is not an overstatement to say that the Railbelt is at a *Limited redundancy historical crossroad,not unlike the period of time when the Railbelt utilities were +Limited economies originally formed.of scale ¢Dependence on Categories of issues facing the Railbelt utilities include:fossil fuels e Uniqueness of the Railbelt region *Limited Cook Inlet gas deliverability and storage *Aging G&T Cost issues Natural gas issues Load uncertainties infrastructure Infrastructure issues +Inefficient fuel use Pale Neeuce options *Difficult financing olitical issues -.¢Duplicative G&TRiskmanagementissuesexpertise Table 1-1 provides a listing of the issues within each of these categories.A detailed discussion of these issuesisprovidedinSection3. Black &Veatch 1-2 February 2010 SECTION 1 EXECUTIVE SUMMARY Table 1-1 ALASKA RIRP STUDY Summary Listing of Issues Facing the Railbelt Region Uniqueness of the Railbelt Region e Size and geographic expanse e Limited interconnections and redundancies Load Uncertainties e Stable native growth ¢Potential major new loads Political Issues Historical dependence on State funding Proper role for State Cost Issues e Relative costs -Railbelt region versus other states e Relative costs -among Railbelt utilities e Economies of scale Infrastructure Issues e Aging generation infrastructure e Baseload usage of inefficient generation facilities e Operating and spinning reserve requirements Risk Management Issues Need to maintain flexibility Future fuel diversity Aging infrastructure Ability to spread regional risks Natural Gas Issues e Historical dependence e Expiring contracts e Declining developed reserves and deliverability e Historical increase in gas prices e Potential gas supplies and prices Future Resource Options e Acceptability of large hydro and coal e Carbon tax and other environmental restrictions e Optimal size and location of new generation and transmission facilities e Limited development - renewables e Limited development - demand-side management/energy efficiency (DSM/EE) programs 1.2 Project Overview The goal of this project is to minimize future power supply costs,and maintain or improve on current levels of power supply reliability, through the development of a single comprehensive RIRP for the Railbelt region.The intent of the RIRP project,as stated in the AEA request-for-proposal,is to provide: e Anup-to-date model that the utilities and AEA can use as a common database and model for future planning studies and analysis. e Anassessment of loads and demands for the Railbelt electrical grid for a time horizon of 50 years including new potential industrial demands. RIRP Objective Function supply costs,and maintain or improve current reliability,as opposed to minimizing power supply costs for any individual Minimize regional power utility. e Projections for Railbelt electrical capacity and energy growth,fuel prices,and resource options. e Ananalysis of the range of potential generation resources available,including costs,construction schedule,and long-term operating costs. Black &Veatch February 2010 EXECUTIVE SUMMARY ALASKA RIRP STUDY SECTION 1 e Aschedule for existing generating unit retirement,new generation construction,and construction of backbone transmission lines that will allow the future Railbelt electrical grid to operate reliably under a transmission tariff which allows access by all potential power producers,and with a postage-stamp rate for electric energy and demand for the entire Railbelt as a whole. e A long-term schedule for developing new fuel supplies that will provide for reliable,stable priced electrical energy for a 50-year planning horizon. A short-term schedule that coordinates immediate network needs (i.e.,increasing penetration level of non-dispatchable generation,such as wind)within the first 10 years of the planning horizon,consistent with the long-term goals. A short-term plan addressing the transition from the present decentralized ownership and control to a unified G&T entity that identifies unified actions between utilities that must occur during this transition period. A diverse portfolio of power supply that includes,in appropriate portions,renewable and alternative energy projects and fossil fuel projects,some or all of which could be provided by independent power producers (IPPs). Current Situation Limited redundancy Limited economies of scale Dependence on fossil fuels Limited Cook Inlet gas deliverability and storage Aging G&T infrastructure Inefficient fuel use Difficult financing Duplicative G&T expertise ¥vRIRP Stud Plan that economically schedules what,when, and where to build,based on available fuel and energy supplies 50-year time horizon Competes generation, transmission,fuel supply and DSM/energy efficiency options Considers CO,regulation Includes renewable energy projects Arrives at a plan to build future infrastructure for minimum long-run cost to ratepayers Considers fuel supply options and risks e Acomprehensive list of current and futuregenerationandtransmissionpowerinfrastructure projects. The alternative resource options considered in the RIRP analysis are shown in Table 1-2. Black &Veatch conducted the REGA study for the AEA and the final report was released in September 2008. That study evaluated the feasibility of the Railbelt utilities forming an organization to provide coordinated unit commitment and economic dispatch of the region's generation resources,generation and transmission system planning,and project development.As a result of that study,legislation was proposed to create GRETC with a 10-year transition period to achieve these goals.This RIRP is based on the GRETC concept being implemented from the beginning of the study's time horizon. Black &Veatch had primary responsibility for conducting this Railbelt RIRP.In addition to Black &Veatch, three other AEA contractors (HDR Inc.,Electric Power Systems,Inc.,and Seattle-Northwest Securities Corporation)played important roles in the development of the RIRP. HDR updated work from the mid-1980s on the Susitna Hydroelectric Project and developed the capital and operating costs,as well as the generating characteristics,for several smaller-sized Susitna projects.HDR'sworkwasusedbyBlack&Veatchin the Strategist®and PROMOD®modeling discussed below.HDR's report summarizing the results ofits workis provided in Appendix A. Electric Power Systems,Inc.(EPS)assisted in the evaluation of the region's transmission system. Black &Veatch 1-4 February 2010 SECTION 1 EXECUTIVE SUMMARY Table 1-2 ALASKA RIRP STUDY Alternative Resource Options Considered Demand-Side Management/Energy Efficiency (DSM/EE)Measure Categories Conventional Generation Resources Renewable Resources Residential e Appliances e Water Heating ¢=Lighting e =Shell e Cooling/Heating Commercial e Water Heating e Office Loads «Motors e =Lighting ¢Refrigeration ¢Cooling/Heating Simple Cycle Combustion Turbines e LM6000 (48 MW) e LMS100 (96 MW) Combined Cycle e 1x1 6FA (154 MW) e 2X1 6FA G10 MW) Coal Units ®Healy Clean Coal e Generic -130 MW Hydroelectric Projects e =Susitna e Chakachamna e Glacier Fork e Generic Hydro -Kenai e Generic Hydro -MEA Wind *BQEnergy/Nikiski e Fire Island e Generic Wind -Kenai e Generic Wind -GVEA Geothermal e =Mt.Spurr Municipal Solid Waste e Generic -Anchorage e Generic -GVEA Other Resources Included in Sensitivity Cases e Modular Nuclear e =6Tidal Seattle-Northwest Securities Corporation (SNW)developed the financial model used to determine the overall financing costs for the portfolio of generation and transmission projects developed as part of this project,and evaluated the impact of some financial options that could be used to address financing issues and mitigating related rate impacts.The results of SNW's analysis are provided in Appendix B. Additional information regarding Black &Veatch's approach to the completion of this study is provided in Section 2. Black &Veatch 1-5 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Purpose and Limitations of the RIRP e The development of this RIRP is not the same as the development of a State Energy Plan;nor does it set State policy.Setting energy-related policies is the role of the Governor and State Legislature.With regard to energy policy making,however,the RIRP does provide a foundation of information and analysis that can be used by policy makers to develop important policies. Having said this,the development of a State Energy Policy and or related policies could directly impact the specific alternative resource plan chosen for the Railbelt region's future.As such,the RIRP may need to be readdressed as future energy-related policies are enacted. e This RIRP,consistent with all integrated resource plans,should be viewed as a "directional”plan.In this sense,the RIRP identifies alternative resource paths that the region can take to meet the future electric needs of Railbelt citizens and businesses;in other words,it identifies the types of resources that should be developed in the future.The granularity of the analysis underlying the RIRP is not sufficient to identify the optimal configuration (e.g.,specific size,manufacturer,model,location,etc.)of specific resources that should be developed.The selection of specific resources requires additional and more detailed analysis. e The alternative resource options considered in this study include a combination of identified projects (e.g., Susitna and Chakachamna hydroelectric projects,Mt.Spurr geothermal project,etc.),as well as generic resources (e.g.,Generic Hydro -Kenai,Generic Wind -GVEA,generic conventional generation alternatives, etc.).Identified projects are included,and shown as such,because they are projects that are currently at various points in the project development lifecycle.Consequently,there is specific capital cost and operating assumptions available on these projects.Generic resources are included to enable the RIRP models to choose various resource types,based on capital cost and operating assumptions developed by Black &Veatch.This approach is common in the development of integrated resource plans. Consistent with the comment above regarding the RIRP being a "directional”plan,the actual resources developed in the future,while consistent with the resource type identified,may be:1)the identified project shown in the resource plan (e.g.,Chakachamna),2)an alternative identified project of the same resource type (e.g.,Susitna);or 3)an alternative generic project of the same resource type.One reason for this is the level of risks and uncertainties that exist regarding the ability to plan,permit,and develop each project.Consequently, when looking at the resource plans shown in this report,it is important to focus on the resource type of an identified resource,as opposed to the specific project. e The capital costs and operating assumptions used in this study for alternative DSM/EE,generation and transmission resources do not consider the actual owner or developer of these resources.Ownership could be in the form of individual Railbelt utilities,a regional entity,or an independent power producer (IPP). Depending upon specific circumstances,ownership and development by IPPs may be the least-cost alternative. e As with all integrated resource plans,this RIRP should be periodically updated (e.g.,every three years)to identify changes that should be made to the preferred resource plan to reflect changing circumstances (e.g.,resolution of uncertainties),improved cost and performance of emerging technologies (e.g.,tidal),and other developments. Black &Veatch 16 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.3.Evaluation Scenarios Black &Veatch,in collaboration with the Advisory Working Group that was assembled by the AEA for this project,developed four Evaluation Scenarios;Black &Veatch then developed a 50-year resource plan for each of these Evaluation Scenarios. The primary objective of these Evaluation Scenarios was to evaluate two key drivers.The first driver was to look at what the impacts would be if the demand in the region was significantly greater than it is today;of primary interest was to see if higher demands would result in greater reliance on large generation resource options and allow for more aggressive expansion of the region's transmission network. The second driver was to determine the impact associated with the pursuit of a significant amount of renewable resources over the 50-year time horizon. As aresult,Black &Veatch evaluated the four Evaluation Scenarios shown in Figure 1-1. Figure 1-1 Evaluation Scenarios %Base Case Scenario 1A Scenario 1B § | 3} LL Ks3 High Growth Scenario 2A Scenario 2BCase Least Cost Force 50% |Level of Renewables by 2025 (Energy) The key assumptions underlying each Evaluation Scenario include: e Scenario 1 -Base Case Load Forecast Current regional loads with projected growth All available resources -fossil fuel,renewables,and DSM/EE Probabilistic estimate of gas supply availability and prices Deterministic price forecasts for other fossil fuels Emissions including CO,costs Transmission system investments required to support selected resources Scenario 1A -Least Cost Plan Scenario 1B -Force 50%Renewables00000000 Black &Veatch 1-7 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY e Scenario 2 --Large Growth Load Forecast o Significant growth in regional loads due to economic development efforts or large scale electrification (e.g.,economic development loads,space and water heating fuel switching,and electric vehicles) Base case resources,fuel availability/price forecasts and CO,costs Transmission system investments required to support selected resources Scenario 2A -Least Cost Plan Scenario 2B -Force 50%Renewablesoo00 1.4 Summary.of Key Input Assumptions The completion of this RIRP required the development of a large number of assumptions in the following categories: e Section 4-Description of Existing System,including information on existing generation resources, committed generation resources,and the existing Railbelt transmission network. ®Section 5-Economic Parameters,including inflation rates,financing rates,present worth discount rate,interest during construction rate,and fixed charge rates. e Section 6 -Forecast of Electrical Demand and Consumption,including 50-year peak demand forecasts and net energy for load requirements. e Section 7 -Fuel and Emissions Allowance Price Projections,including price forecasts for various fuels and emission allowance price projections. e Section 8 -Reliability Criteria,including the region's planning and operating reserve margin requirements. ®Section 9 --Capacity Requirements,including the region's capacity requirements over the 50-year planning horizon. ¢Section 10-Supply-Side Options,including an overview of the supply-side resource option input assumptions used in this study,including both conventional technologies and renewable energy options. e Section 11-DSM/EE Resources,including a summary of the methodology and assumptions that Black &Veatch used to evaluate potential DSM/EE measures. ¢Section 12 -Transmission Projects,including an overview of the transmission projects required to improve the overall reliability of the region's transmission network and connect the generation resources included in the alternative resource plans that were developed as part of this project. 1.5 Susitna Analysis A hydroelectric project on the Susitna River has been studied for more than 50 years and is again being considered by the State of Alaska as a long term source of energy.In the 1980s,the project was studied extensively by the Alaska Power Authority (APA)and a license application was submitted to the Federal Energy Regulatory Commission (FERC).Developing a workable financing plan proved difficult for a project of this scale.When this existing difficulty was combined with the relatively low cost of gas-fired electricity in the Railbelt and the declining price of oil throughout the 1980s,and its resulting impacts upon the State budget,the APA terminated the project in March 1986. In 2008,the Alaska State Legislature authorized the AEA to perform an update of the project.That authorization also included this RIRP project to evaluate the ability of this project and other sources of energy to meet the long term energy demand for the Railbelt region of Alaska.Of all the hydro projects in the Railbelt region,the Susitna projects are the most advanced and best understood. Black &Veatch 1-8 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY HDR was contracted by AFA to update the cost estimate,energy estimates and the project development schedule for a Susitna River hydroelectric project.The initial alternatives reviewed were based upon the 1983 FERC license application and subsequent 1985 amendment which presented several project alternatives: Watana.This alternative consists of the construction of a large storage reservoir on the Susitna River at the Watana site with an 885-foot-high rock fill dam and a six-unit powerhouse with a total installed capacity of 1,200 MW. Low Watana Expandable.This alternative consists of the Watana dam constructed to a lower height of 700 feet and a four-unit powerhouse with a total installed capacity of 600 MW.This alternative contains provisions that would allow for future raising of the dam and expansion of the powerhouse. Devil Canyon.This alternative consists of the construction of a 646-foot-high concrete dam at the Devil Canyon site with a four-unit powerhouse with a total installed capacity of 680 MW. Watana/Devil Canyon.This alternative consists of the full-height Watana development and the Devil Canyon development as presented in the 1983 FERC license application.The two dams and powerhouses would be constructed sequentially without delays.The combined Watana/Devil Canyon development would havea total installed capacity of 1,880 MW. Staged Watana/Devil Canyon.This alternative consists of the Watana development constructed in stages and the Devil Canyon development as presented in the 1985 FERC amendment.In stage one"the Watana dam would be constructed to the lower height and the Watana powerhouse would only have four out of the six turbine generators installed,but would be constructed to the full sized powerhouse.In stage two the Devil Canyon dam and powerhouse would be constructed.In stage three the Watana dam would be raised to its full height,the existing turbines upgraded for the higher head,and the remaining two units installed.At completion,the project would have a total installed capacity of 1,880 MW. As the RIRP process defined the future Railbelt power requirement it became evident that lower cost hydroelectric project alternatives,that were a closer fit to the energy needs of the Railbelt,should be sought. As such,the following single dam configurations were also evaluated: Low Watana Non-Expandable.This alternative consists of the Watana dam constructed to a height of 700 feet,along with a powerhouse containing four turbines with a total installed capacity of 600 MW.This alternative has no provisions for future expansion. Lower Low Watana.This alternative consists of the Watana dam constructed to a height of 650 feet along with a powerhouse containing three turbines with a total installed capacity of 3830 MW.This alternative has no provisions for future expansion. High Devil Canyon.This alternative consists of a roller-compacted concrete (RCC)dam constructed to a height of 810 feet,along with a powerhouse containing four turbines with a total installed capacity of 800 MW. Watana RCC.This alternative consists of a RCC Watana dam constructed to a height of 885 feet, along with a powerhouse containing six turbines with a total installed capacity of 1,200 MW. The results of this study are summarized in Table 1-3 and a comparison of project size versus project cost is shown in Figure 1-2. Black &Veatch 1-9 February 2010 SECTION 1 EXECUTIVE SUMMARY *ALASKA RIRP STUDY Table 1-3 Susitna Summary Firm 2008 Schedule Dam Ultimate Capacity,|Construction (Years from Height Capacity |98%Cost Energy Start of Alternative Dam Type (feet)(MW)(MW)(5 Billion)(GWh/yr)|Licensing) Lower Low Watana |Rockfill 650 380 170 $4.1 2,100 13-14 Low Watana Non-Rockfill 700 600 245 $4.5 2,600 14-15 expandable Low Watana Rockfill 700 600 245 $4.9 2,600 14-15 Expandable Watana Rockfill 885 1,200 380 $6.4 3,600 15-16 Watana RCC RCC 885 1,200 380 $6.6 3,600 15-16 Devil Canyon Concrete Arch |646 680 715 $3.6 2,700 14-15 High Devil Canyon |RCC 810 800 345 $5.4 3,900 13-14 Watana/Devil Rockfill/Concr |885/646 1,880 710 $9.6 7,200 15-20 Canyon ete Arch Staged Rockfill/Concr |885/646 1,880 710 $10.0 7,200 15-24 Watana/Devil ete Arch Canyon Black &Veatch 1-10 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Figure 1-2 Comparison of Project Cost Versus Installed Capacity $12.0 mot .-+-ae -a Le .- | $10.0 --on - Watana/DevilCanyon & =$30!c i 2 | =| a WatanaRCC 4'Watana3$6.0 4 atan Py i A High Devil Canyon 3 ' Low Watana Expandable A Law \Watana Non- &$4.0 -LowerLowWatana A expandable A Devil Canyon $2.0 + $0.0 0 200 400 609 800 1000 1260 1400 1600 1809 2000 Installed Capacity (MW) In all cases,the ability to store water increases the firm capacity over the winter.Projects developed with dams in series allow the water to be used twice.However,because of their locations on the Susitna River,not all projects can be combined.The Devil Canyon site precludes development of the High Devil Canyon site but works well with Watana.The High Devil Canyon site precludes development of Watana but could potentially be paired with other sites located further upstream. The detailed results of the HDR Susitna study,except for the detailed appendices,are provided in Appendix A.One of the appendices contained within the HDR report (Appendix D),which is not included in Appendix A of this report,addresses the issue of the potential impact of climatic changes on Susitna's resource potential;this appendix can be viewed in the full HDR report which is available on the AEA web site. 1.6 Transmission AnalysisAnimportantelementofthisRIRP was the analysis of transmission investments required to integrate the generation resources in each resource plan,ensure reliability and enable the region to take advantage of economy energy transfers between load areas within the region. The fundamental objective underlying the transmission analysis was to upgrade the transmission system over a 10-year period to remove transmission constraints that currently prevent the coordinated operation of all the utilities as a single entity. Black &Veatch 1-11 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY The study included all assets 69 kV and above.These assets,over a transition period,may flow into GRETC and form the basis for a phased upgrade of the system into a robust,reliable transmission system that can accommodate the economic operation of the interconnected system.The transmission analysis also assumed that all utilities would participate in GRETC with planning being conducted on a GRETC (i.e.,regional) basis.The common goal would be the tight integration of the system operated by GRETC. Potential transmission investments in each of the following four categories were considered: e Transmission systems that need to be replaced because of age and condition (Category 1) e Transmission projects required to improve grid reliability,power transfer capability,and reserve sharing (Category 2) e Transmission projects required to connect new generation projects to the grid (Category 3) *Transmission projects to upgrade the grid required by a new generation project (Category 4) In developing the transmission system,reliability remains a significant focus.Redundancy is one way to increase reliability,but may not be the only way to improve or maintain reliability. The results of Black &Veatch's transmission assessment are discussed later in this section. 1.7 Summary of Results The purpose of this subsection is to summarize the results of the RIRP analysis.We begin by providing a summary of the base case results for each of the four Evaluation Scenarios.We then provide a comparative summary of the economic and emission results for all base cases and sensitivity cases.This is followed by a summary of the results of the transmission analysis that was completed and,finally,the results of the financial analysis.More detailed information regarding the results of the RIRP study is provided in Section 13. Current Situation Limited redundancy Limited economies of scale Dependence on fossil fuels Limited Cook Inlet gas deliverability and storage Aging G&T infrastructure *Inefficient fuel use Difficult financing Duplicative G&T expertise RIRP Study «Plan that economically schedules what,when, and where to build,based on available fuel and energy supplies ¢50-year time horizon *Competes generation, transmission,fuel supply and DSM/energy efficiency options *Considers CO,regulation Vv«Includes renewable energy projects ¢Arrives at a plan to build future infrastructure for minimum tong-run cost to ratepayers *Considers fuel supply options and risks AdRIRP Results Increased DSM/energy efficiency Increased renewables Reduced dependence on natural gas Increased transmission Black &Veatch 1-12 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.7.1 Results of Reference Cases In this subsection,we provide summaries of the reference case results for each of the following four Evaluation Scenarios: e Scenario 1A -Base Case Load Forecast -Least Cost Plan e Scenario 1B -Base Case Load Forecast -Force 50%Renewables e Scenario 2A -Large Growth Load Forecast -Least Cost Plan *®Scenario 2B -Large Growth Load Forecast -Force 50%Renewables Our analysis shows that Scenarios 1A and 1B result in the same resources and,consequently,the same costs and emissions.In other words,the cost of achieving a renewable energy target of 50 percent by 2025 (Scenario 1B)is no greater than the cost of the unconstrained solution (Scenario 1A).This result applies only if a large hydroelectric project is built.Hereafter,we will refer to Scenarios 1A and 1B together. We begin with a summary of the impact that DSM/EE measures have on the region's capacity and annual energy requirements.This is followed by summary graphics and information for each of the Evaluation Scenarios.Detailed model output for each of the reference cases are provided in Appendices E-G. 1.7.1.1.DSM/EE Resources As discussed in Section 11,Black &Veatch screened a broad array of residential and commercial DSM/EE measures.Based on this screening,21 residential and 51 commercial DSMW/EE measures were selected forinclusionintheRIRPmodels,Strategist®and PROMOD®,as potential resources to be selected. Based upon the relative economics and savings of these screened residential and commercial DSM/EE measures,from the utility perspective,all of the residential and commercial DSM/EE measures were selected in each of the four Evaluation Scenarios.As discussed in Section 11,the penetration of the measures was based on technology adoption curves for DSM/EE studies from the BASS model;additionally,DSM/EEmeasuresaretreatedbyStrategist®and PROMOD®as a reduction to the load forecast from which the alternative supply-side options are considered for adding generation resources. As can be seen in Figure 1-3,DSM/EE measures result in a significant impact on the region's capacity and energy requirements.After the initial program start-up years,DSM/EE measures reduce the region's capacity requirements by approximately 8 percent.A similar level of impact is also shown for annual energy requirements. Black &Veatch 1-13 February 2010 SECTION I EXECUTIVE SUMMARY Figure 1-3 Impact of DSM/EE Resources -Base Case Load Forecast ALASKA RIRP STUDY Demand (MW)Energy Requirements (MWh) -Without OSMW/EE «.000 000 -Without DSM/EE 1,400 With DSM/EE 000,-With DSM/EE =7,000,0001.200 =- -=6,000,0001,000 =_--=oe -=5,000,000=800 £2 ©4,000,000®600 g%3,000,000a"440058 2,000,000 2200"4 4,000,000 ee ee 0AAASORISASEASONEDAGSAASSOEcere ce eeenmnees renee ooo cee oe cee eeeeeeeeeewrrrNNNNNOOOO©wow 0)wr Fm OM HOY DWN HO wD &band ly oaERRRSSRE222222822ESSHSRSSRSSEPTERSEREYeareeeNNverear It should be noted that this study did not include an evaluation of innovative rate designs (e.g.,real-time pricing and demand response rates),nor did it consider the potential benefits of a Smart Grid,and the associated widespread implementation of smart meters.These options could result in even greater reductions in peak demand and annual energy usage. A Note Regarding DSM/EE Resources This RIRP demonstrates the economic potential of DSM/EE resources. Due to limited Alaska-specific DSM/EE-related data and experience,Black &Veatch limited the amount of DSM/EE resources included in the preferred resource plan., Additional analysis,both by Black &Veatch as part of this study and by others,along with the experience of other utilities throughout the US,suggest that additional levels of DSM/EE resources may be economic. However,given the lack of Alaska-specific data and experience,additional data gathering and analysis is required before the optimal level of DSM/EE resources can be determined. Furthermore,the isolated nature of the Railbelt coupled with severe weather conditions,dictates caution with regard to the ultimate reliance on DSM/EE resources. Additionally,the limited penetration of electric space heating in the Railbelt region affects the ultimate level of DSM/EE savings. To develop the full potential of DSM/EE resources,it will be necessary to collect baseline end-use saturation,customer and vendor information,as well as address the reduction in utility margins that result from the implementation of DSM/EE programs. Additionally,Black &Veatch believes that a regional approach to the development of DSM/EE programs(e.g.,GRETC)will be more successful than if the six Railbelt utilities develop independent DSM/EE programs. Black &Veatch 1-14 February 2010 SECTION 1 EXECUTIVE SUMMARY 1.7.1.2 Results -Scenarios 1A/1B Reference Cases ALASKA RIRP STUDY Figure 1-4 Results -Scenarios 1A/1B Reference Cases 2000 Capacity By Resource Type 7000 Energy By Resource Type "pOcean Tidal wWind anenneiians <Municipal Sold Waste _.Murielal Sot Waste =Geothermal FA #Geothermal £|Hydro >siHydroaiqwPurchasePower4@Purchase Power é nF vel Ol Zz mF vel Oil Nuclear 2000 @Nucear y wCoal BCoal ay Natural Gas 1000 j m Nanral Ges |=» eon EEERRRASRBSETERRSSB FFESRRSSHRETRRB SBRBRRERSRRRRRRSRSRRSRRRRESRERSRRRARRERR 1.7.1.3 Results -Scenario 2A Reference Case Figure 1-5 Results -Scenario 2A Reference Case 3500 Capacity By Resource Type 14000 Energy By Resource Type 3000 mA ©Ocean Tidal 12000 enasanTidal 2500 wWind 40000 mWind =@ Municipal Solid Waste Municipal Solld Waste=a Geothermal 8000 s =Hydro z =Hydro a mPurchase Power j 6000 wPurchase Power a .ert)m Fuel Oil @Fuel Oil wNuclear 4000 wNucear mCoal mcoal m Natural Gas 2000 @ Natural Gas >0 § 1.7.1.4 Results -Scenario 2B Reference Case Figure 1-6 Results -Scenario 2B Reference Case 3600 Capacity By Resource Type 44000 €nergy By Resource Type 3000 _%Ocean Tidal 12000 p -al _ 2500 en |SokdWi 10000 =Wind =Municipal Sold Waste =<MunicipalSoldWaste =000 a@ Geothannai :8000 8 Geothermal &»Hydro a =Hydro<4500 m Purchase Power =000 F Power<Fuel Oi Fe Fuel Oi 1000 wNuclear wNuclear wCoal : acoal 500 Natural Gas iy Lm Natal Gas 0 February 2010Black&Veatch SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY A Note Regarding Emerging Technologies e Inthe economic analysis underlying this RIRP,Black &Veatch used current cost and performance assumptions for all generation technology options considered.This was done because of the inherent difficulty in predicting the future cost and performance of technologies,particularly emerging technologies (e.g.,on-shore and off-shore wind and tidal). e Recent improvements in wind-related costs and performance demonstrate the potential for emerging technologies.Conversely,the cost and performance of conventional resource technologies are stable at best and not likely to improve. e Further development of tidal power should be encouraged due to its resource potential in the Railbelt region.Although this technology is not commercially available,in Black &Veatch's opinion,at this point in time,it has the potential to become economic within the planning horizon. ¢These diverging cost and performance trends are one reason why this RIRP needs to be updated periodically;by so doing,emerging technologies can be added to the region's preferred resource plan as their costs and performance improve. 1.7.2 Sensitivity Cases Evaluated The following sensitivity cases were evaluated: e Scenarios 1A/1B Without DSM/EE Measures Scenarios 1A/1B With Double DSM/EE Measures Scenarios 1A/1B With Committed Units Included Scenarios 1A/1B Without CO,Costs Scenarios 1A/1B With Higher Gas Prices Scenarios 1A/1B Without Chakachamna Scenarios 1A/1B With Chakachamna Capital Costs Increased by 75% Scenarios 1A/1B With Susitna (Lower Low Watana Non-Expandable Option)Forced Scenarios 1A/1B With Susitna (Low Watana Non-Expandable Option)Forced Scenarios 1A/1B With Susitna (Low Watana Expandable Option)Forced Scenarios 1A/1B With Susitna (Low Watana Expansion Option)Forced Scenarios 1A/1B With Susitna (Watana Option)Forced Scenarios 1A/1B With Susitna (High Devil Canyon Option)Forced Scenarios 1A/1B With Modular Nuclear Scenarios 1A/1B With Tidal Scenarios 1A/1B With Lower Coal Capital and Fuel Costs Scenarios 1A/1B With Federal Tax Credits for Renewables 1.7.3.Summary of Results -Economics and Emissions In this subsection,we provide a comparative summary of the economic and emissions results for all of the reference cases and sensitivity cases. 1.7.3.1 Summary of Results -Economics Table 1-4 summarizes the economic results,including: ¢Cumulative present value cost (from the utility perspective) e Average wholesale power cost (from the utility perspective) e Renewable energy in 2025 e Total capital investment Black &Veatch 1-16 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-4 Summary of Results -Economics Cumulative Average Renewable Present Value Wholesale Energy in |Total CapitalCostPowerCost2025Investment Case ($000,000)(¢per kWh)(%)($000,000) Scenarios Scenario 1A $13,625 17,26 62.32%$9,087 Scenario 1B $13,625 17.26 62.32%$9,087 Scenario 2A $20,162 19.75 42.64%$14,111 Scenario 2B $21,109 20.68 65.83%$18,805 Sensitivities 1A/1B Without DSM/EE Measures $14,507 17.40 67.10%$8,603 1A/1B With Double DSM $12,546 15.89 65.15%$8,861 1A/1B With Committed Units Included $14,109 17.87 46.84%$8,090 1A/1B Without CO2 Costs $11,206 14.20 49.07%$8,381 1A/1B With Higher Gas Prices $14,064 17.82 61.95%$9,248 1A/1B Without Chakachamna $14,332 18.16 38.06%$7,719 1A/1B With Chakachamna Capital Costs $14,332 18.16 38.06%$7,719 Increased by 75% 1A/1B With Susitna (Lower Low Watana $15,228 19.29 61.01%$12,421 Non-Expandable Option)Forced 1A/1B With Susitna (Low Watana Non-$15,040 19.05 63.01%$15,057 Expandable Option)Forced 1A/1B With Susitna (Low Watana $15,346 19.44 63.01%$15,588 Expandable Option)Forced 1A/1B With Susitna (Low Watana $14,854 18.82 66.90%$14,069 Expansion Option)Forced 1A/1B With Susitna (Watana Option)Forced $15,683 19.87 70.97%$13,211 1A/1B With Susitna (High Devil Canyon $14,795 18.74 66.92%$11,633 Option)Forced 1A/1B With Modular Nuclear $13,841 17.53 60.51%$9,105 1A/1B With Tidal $13,712 17.37 65.52%$9,679 1A/1B With Lower Coal Fuel and Lower $13,625 17.26 62.32%$9,087 Coal Capital Costs 1A/1B With Tax Credits for Renewables $12,954 16.41 67.56%$9,256 1-17 February 2010Black&Veatch SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.7.3.2.Summary of Results -Emissions Table 1-5 summarizes the emissions-related results of all of the reference and sensitivity cases.The following information is provided for each case: e CO),emissions e NO,emissions e SO,emissions Table 1-5 Summary of Results -Emissions co,NO,so, Case ('000 tons)('000 tons)('000 tons) Scenarios Scenario 1A 80,259,047 124,215 21,768 Scenario 1B 80,259,047 124,215 21,768 Scenario 2A 152,318,066 133,642 24,476 Scenario 2B 125,498,202 140,897 26,348 Sensitivities 1A/1B Without DSM/EE Measures 88,181,350 139,179 30,605 1A/1B With Double DSM 69,324,920 131,299 18,994 1A/1B With Committed Units Included 91,212,598 136,946 16,482 1A/1B Without CO2 Costs 100,753,030 134,031 23,960 1A/1B With Higher Gas Prices 78,323,066 121,700 25,232 1A/1B Without Chakachamna 105,643,650 133,577 25,700 1A/1B With Chakachamna Capital Costs Increased by 75%105,643,650 133,577 25,700 1A/1B With Susitna (Lower Low Watana Non-Expandable 82,328,762 127,921 22,124 Option)Forced 1A/1B With Susitna (Low Watana Non-Expandable Option)69,133,553 124,640 19,620 Forced 1A/1B With Susitna (Low Watana Expandable Option)Forced 69,133,553 124,640 19,620 1A/1B With Susitna (Low Watana Expansion Option)Forced 67,724,563 136,906 23,589 1A/1B With Susitna (Watana Option)Forced 70,966,059 111,307 19,171 1A/1B With Susitna (High Devil Canyon Option)Forced 71,853,368 121,538 19,909 1A/1B With Modular Nuclear 79,664,701 126,881 22,787 1A/1B With Tidal 75,598,948 121,306 21,067 1A/1B With Lower Coal Fuel and Lower Coal Capital Costs 80,259,047 124,215 21,768 1A/1B With Tax Credits for Renewables 74,046,352 129,384 18,832 Black &Veatch 1-18 February 2010 SECTION 1 EXECUTIVE SUMMARY 1.7.4 Results of Transmission Analysis ALASKA RIRP STUDY Table 1-6 lists the proposed transmission system expansions and enhancements that resulted from our transmission analysis.More detailed information on each of the identified transmission projects is provided in Section 12. Black &Veatch Table 1-6 Summary of Proposed Transmission Projects Project No.Transmission Projects Type Cost ($000) A Bernice Lake -International New Build (230 kV)227,500 Soldotna -Quartz Creek R&R (230 kV)126,500 Cc Quartz Creek University R&R (230 kV)165,000 D Douglas -Teeland R&R (230 kV)62,500 E Lake Lorraine -Douglas New Build (230 kV)80,000 F Douglas -Healy Upgrade (230 kV)30,000 G Douglas -Healy New Build (230 kV)252,000 H Eklutna -Fossil Creek Upgrade (230 kV)65,000 I Healy -Gold Hill R&R (230 kV)180,500 J Healy -Wilson Upgrade (230 kV)32,000 K Soldotna -Diamond Ridge R&R (115 kV)66,000 L Lawing -Seward Upgrade (115 kV)15,450 M Eklutna -Lucas R&R(115 kV/230 kV)12,300 N Lucas -Teeland R&R (230 kV)51,100 O Fossil Creek-Plant 2 Upgrade (230 kV)13,650 P Pt.Mackenzie -Plant 2 R&R (230 kV)32,400 Q Bernice Lake -Soldotna Rebuild (115 kV)24,000 R Bernice Lake -Beaver Creek -Soldotna |Rebuild (115 kV)24,000 S Susitna Transmission Additions New Build (230 kV)57,000 1-19 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY A diagram that shows the location of the proposed transmission system enhancements is shown in Figure 1-7. This graphic shows the proposed transmission projects if the Susitna hydroelectric project is not developed.A similar graphic of proposed transmission projects if Susitna is built is provided in Section 12. Figure 1-7 Location of Proposed Transmission Projects (Without Susitna) Es EALY 239 kV New230kVDOUGLAS 230 kV 1 ;Brg LANO os SATS TERMINAL |[TERMINAL 3 I SOLD OTNA NUARTZ CK av 30 kV The following issues result from our transmission analysis: *a TT FORK2017|a ata FEKLoe30 kV [s! Sai e We were unable to complete a stability analysis based upon our proposed transmission system configuration prior to the completion of this project.This analysis is required to ensure that the proposed transmission system expansions and enhancements result in the necessary stability to ensure reliable electric service over the planning horizon.This analysis should be completed as part of the future work to further define,prioritize,and design specific transmission projects. Black &Veatch 1-20 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY e In addition to the transmission lines listed above,other projects were considered that could contribute to improving the reliability of the Railbelt system.These projects generally fall into one or more of the following categories: ©Providing reactive power (static var compensators -SVCs) o Providing or assisting with the provision of other ancillary services (regulation and/or spinning reserves) ©Assistance in control of line flows or substation voltages o Assistance in the transition and coordination of transmission project implementation (mobile transforms or substations) o Communications and control facilities Several of these projects have been identified and discussed while others will result from the transmission reliability assessment.Potential projects in this category include: o Substation capacitor banks Series capacitors SVCs Battery energy storage systems (BESS) Mobile substations that could provide construction flexibility during the implementation phase e Projects that could facilitate or complement the implementation of other projects (e.g.,wind),were of particular interest during project discussions.These projects,if implemented,could smooth the transition and adoption by the utilities of the GRETC concept.One such project was the BESS that could provide much needed frequency regulation and potentially some spinning reserves when non-dispatchable projects,such as wind,are considered.A BESS was specified that could provide frequency regulation required by the system when wind projects were selected by the RIRP.The BESS was sized in relation to the size of the non-dispatchable project to be 50 percent of the project nominal capacity for a 20-minute duration.Although the performance of the BESS has not yet been analyzed as part of the stability analysis,the costs for each such system were included in the analysis. Other options (e.g.,fly wheel storage technologies and compressed air energy storage)that could provide the required frequency regulation should also be considered. e Itshould be noted that if the need for frequency regulation is driven in part by an IPP-sponsored | renewable project,policies will need to be adopted to allocate an appropriate portion of the regulation costs to those projects. e The Fire Island Wind Project is a 54 MW maximum output wind project.Each wind turbine will be equipped with reactive power and voltage support capabilities that should facilitate interconnection into the transmission grid.Current plans are to interconnect the project to the grid via a 34.5 kV underground and submarine cable to the Chugach 34.5 kV Raspberry Substation.There has been some discussions regarding the most appropriate transmission interconnection for the Fire Island Project and detailed interconnection studies have not been completed.The timeframe for implementing this project in order to qualify for available grants under the American Recovery and Reinvestment Act of 2009 (ARRA)could preclude more detailed transmission studies and consideration of alternatives to the currently proposed 34.5 kV interconnection.An option to consider if Fire Island is constructed is to lay cables from Fire Island to Anchorage insulated for230kVandreviewatransmissionroutingforthenewtransmissionconnectiontotheKenaipeninsulathatwouldbeginattheInternational230kVSubstationtoBerniceLakeSubstationalongtheKenai cost line then via submarine cable across the Cook Inlet to Fire Island.The interconnection would then use the 230 kV submarine cable previously laid over to the Anchorage coast then into the International 230 kV Substation.0000Black &Veatch 1-21 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY ¢The recommended transmission system expansions and enhancements can not be justified based solely on economics.However,in addition to their underlying economics,these transmission projects are required to ensure the reliable delivery of electricity throughout the region over the 50-year planning horizon and to provide the foundation for future economic development efforts. The proposed projects identified in Section 12 are not presented in any specific order or priority.It was felt that the information currently available,as well as the uncertainty which exists surrounding the selected generation plans,did not permit a more definitive prioritization of projects.This does not mean,however,that all the projects in the list have the same impact on the reliability of the Railbelt system,or that the projects are equally important to each utility.In several instances the projects were in extremely poor physical condition and were scheduled to be repaired or rebuilt to prevent the lines from literally falling to the ground.To facilitate the immediate repairs to these lines,the projects that should be addressed within the next five years because of their potential impact on the reliability of the system have been identified.Additionally,some of the projects will need to be evaluated and specified further and funds have been identified to facilitate the studies that are required to further identify and schedule the transmission improvements that will be required. The following projects and studies have been identified for priority attention (i.e.,to be completed within the next five years)because of their immediate impact on the reliability of the existing system.All of the projects will require detailed system feasibility studies prior to actual implementation. Soldotna to Quartz Creek Transmission Line ($126.5 million -Project B) Quartz Creek to University Transmission Line ($165.0 million -Project C) Douglas to Teeland Transmission Line ($62.5 million -Project D) Lake Lorraine to Douglas Transmission Line ($80.0 million -Project E) SVCs ($25.0 million -Other Reliability Projects) Funds to undertake the study of the Southern Intertie ($1.0 million) Funds to investigatethe provision of regulation that will facilitate the integration of renewable energyprojectsintotheRailbeltsystem($50.0 million,including cost of BESS -Other Reliability Projects)NAYRPYNSThe total estimate costs necessary for transmission projects during the initial five years of the RIRP is $510 million in 2009 dollars. 1.7.5 Results of Financial Analysis It will be difficult for the region to obtain the necessary financing for the DSM/EE,generation and transmission resources included in the alternative resource plans that were developed.The formation of a regional entity with some form of State assistance will help meet this challenge. Figure 1-8 summarizes the cumulative capital investment required for each of the four base cases. Black &Veatch 1-22 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Figure 1-8 Required Cumulative Capital Investment for Each Base Case Cumulative Capital Investment $20,000,000 = 3 $18,000,000 -Scenario 1A/1B _-_-_-_--_-_-- --Scenario 2A$16,000,000 f. - Scenario 2B A$14,000,000 $12,000,000 7 oO$10,000,000 7$8,000,000 we $6,000,000 $4,000,000 LZ$2,000,000 A$0 leCumulativeCapitalInvestment($To assist in the completion of the financial analysis,AEA contracted with SNW to: e Provide a high-level analysis of the capital funding capacity of each of the Railbelt utilities. e Analyze strategies to capitalize selected RIRP assets by integrating State (which could include loans, State appropriations,Permanent Fund,State moral obligation bonds,etc.)and federal (e.g.,USDA-RUS)financing resources with debt capital market resources. e Develop a spreadsheet model that utilizes inputs from this RIRP analysis and overlays realistic debt capital funding to provide a total cost to ratepayers of the optimal resource plan. The results of the financial analysis completed by SNW are provided in Appendix B. Important conclusions from SNW's report include: e The scope of the RIRP projects is too great,and for certain individual projects,it is reasonable to conclude that there is no ability for a municipality or cooperative utility to independently secure debt financing without committing substantial amounts of equity of cash reserves. e Figure 1-9 helps to put into context the scope of the required RIRP capital investments relative to the estimated combined debt capacity of the Railbelt utilities.The lines toward the bottom of the graph represent SNW's estimate of the bracketed range of additional debt capacity collectively for the Railbelt utilities,adjusted for inflation and customer growth over time. Black &Veatch 1-23 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Figure 1-9 Required Cumulative Capital Investment (Scenarios 1A/1B)Relative to Railbelt Utility Debt Capacity $10,000,000,000 Capital Expenditures a i: ©7,500,000,000 $5,000,000,000 Hizh Debt Capacity 62,500,000,000 Sf Low Debt Capacity SO TTTTPETRPTPTTTPPrrrrr rr rrr rrr rr rrr rrr re rrr rrr rrr) wer h Oo MYO NN YM DO Fr TR OM ODAoANANNNOMOOOFfFerHeHeYooDpoOOFOFFPFRPRPOeFPOeFPoOfoOohL6DNNNNANNNNNNNNNNNAN Source:SNW Report included in Appendix C. e A regional entity,such as GRETC,with "all outputs”contracts migrating over time to "all requirements”contracts will have greater access to capital than the combined capital capacity of the individual utilities. e There are several strategies that could be employed to lower the RIRP-related capital costs to customers,including: ©Ratepayer Benefits Charge -A charge levied on all ratepayers within the Railbelt system that would be used to cash fund and thereby defer borrowing for infrastructure capital. o "Pay-Go”Versus Borrowing for Capital -A pay-go financing structure minimizes the total cost of projects through the reduction in interest costs.A "pay-go”capital financing program is one in which ongoing capital projects are paid for from remaining revenue after operations and maintenance (O&M)expenses and debt service are paid for.A balance of these two funding approaches appears to be the most effective in lowering the overall cost of the RIRP,as well as spreading out the costs over a longer period of time. o Construction Work in Progress (CWIP)-CWIP is a rate methodology that allows for the recovery of interest expense on project construction expenditures through the base rate during construction,rather than capitalizing the interest until the projects are on-line and generating power.It should be noted that this rate methodology is sometimes criticized for shifting risks forshareholderstoratepayers;however,in the case of a public cooperative or municipal utility,the "shareholders”are the ratepayers. Black &Veatch 1-24 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY o State Financial Assistance -State financial assistance could take a variety of forms as previously noted;for the purposes of this project,SNW focused on State assistance structured similarly to the Bradley Lake project.The benefits of State funding include:repayment flexibility,credit support/risk mitigation,and potential interest cost benefit. It should be noted that the economic comparison of resource options (using Strategist™and PROMOD™)does not assume any of these financing strategies,including any State grants of Federal tax credits,with the exception of the Federal Tax Credits for Renewables Sensitivity Case. e The overall objective of SNW's analysis was to identify ways to overcome the funding challenges inherent with large-scale projects,including the length of construction time before the project is' online and access to capital markets,and to develop strategies that could be used to produce equitable rates over the useful life of the assets being financed.With these challenges in mind,SNW developed separate versions of its model to capture the cost of financing under a "base case”scenario and an "alternative”scenario.The base case financing model was structured such that the list of RIRP projects during the first 20 years would be financed through the capital markets in advance of construction and that the cost of the financing in the form of debt service on the bonds would immediately be passed through to the ratepayers;the projects being financed over the balance of the 50-year period would be financed through cash flow created through normal rates and charges ("pay-go”),once debt service coverage from previous years has grown to levels that create cash flow balance amounts sufficient to pay for the projects as their construction costs come due.The alternative model was developed with the goal of minimizing the rate shock that may otherwise occur with such a large capital plan,and levelizing the rate over time so that the economic burden derived from these projects can be spread more equitably over the useful life of the projects being contemplated. e In both the base and alternative cases,SNW transferred the excess operating cash flow that is generated to create the debt service coverage level,and using that balance to both partially fund the capital projects in the early years and almost fully fund the projects in the later years.In the alternative case,SNW also included:1)a Capital Benefits Surcharge ($0.01 per KWH)over the first 17 years,when approximately 75 percent of the capital projects will have been constructed,and 2)State assistance as an equity participant,structured in a manner similar to the Bradley Lake financing model (SNW assumed that the State would provide a $2.4 billion zero-interest loan to GRETC to provide the upfront funding for the Chakachamna project,only to be paid back by GRETC out of system revenues over an extended period of time,and following the repayment of the potentially more expensive capital market debt). ©Under the base case,the maximum fixed charge rate on the capital portion alone is estimated to cost $0.13 per kWH,while the average fixed charge rate over the 50-year period is $0.07 per kWh. e In the alternative case,the maximum fixed charge rate on the capital portion alone is estimated to cost $0.08 per kWH,while the average fixed charge rate over the 50-year period is $0.06 per kWh,not including the $0.01 consumer benefit surcharge that is in place for the first 17 years. °*While the average rates between the two cases are essentially the same,the maximum rate in the alternative case is much lower,showing the ability of innovative financing tools and ratemaking methodologies to overcome the funding challenges and provide equitable rates over the 50-year period. Black &Veatch 1-25 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY e The formation of a regional entity,such as GRETC,that would combine the existing resources and rate base of the Railbelt utilities,as well as provide an organized front in working to obtain private financing and the necessary levels of State assistance,would be,in SNW's opinion,a necessary next step towards achieving the goal of reliable energy for the Railbelt region now and in the future. 1.8 Implementation Risks and Issues There are a number of general risks and issues that must be addressed regardless of the resource future that is chosen by stakeholders,including the utilities and State policy makers.Additionally,each alternative DSMFEE,generation and transmission resource type has its own specific risks and issues.Section 14 includes a detailed discussion of these general and resource-specific implementation-related risks and issues. e Risk is an inherent element of any long-term integrated resource plan.This RIRP is not different. e Risks associated with fuel supply,project development,operations,environmental,transmission, regulatory,and so forth,all affect the region's optimal future resource path.These risks are identified and discussed in this report. e In many ways,this RIRP is the beginning of a journey;hard work is required to address these risks and make the difficult policy choices necessary to secure a reliable energy future. A Note Regarding Risks 1.8.1 General Risks and Issues General issues and risks related to the implementation of the RIRP include the following: ©Organizational,including: The lack of a regional entity with the responsibility for implementing the RIRP will lead tofe) suboptimal solutions,resulting in higher costs,lower reliability and the inability to manage the successful integration of DSWEE and renewable resources into the Railbelt system. o To date,the Railbelt utilities have not been able to take full advantage of economies of scale for several reasons.Absent taking a regional approach to future resource planning and development, this reality will continue. o Fuel supply risks,including the future deliverability and price of natural gas. co Risks resulting from the inadequacy of the current regional transmission network. o Market development risks and issues,including the need to implement a competitive power procurement process to encourage the development of generation projects by IPPs,and the potential for large load increases. o Financing and rate issues,related to the ability of the region to finance the capital investments identified in the RIRP and the need to mitigate the rate impact of those investments. o Legislative and regulatory issues,including the potential impact that a State Energy Plan and the passage of energy-related policies could have on the RIRP. Black &Veatch 1-26 February 2010 SECTION 1 EXECUTIVE SUMMARY 1.8.2 Resource Specific Risks and Issues Table 1-7 provides Black &Veatch's assessment of the relative magnitude of various categories of risks and issues for each resource type,including: Resource Potential Risks -the risk associated with the total energy and capacity that could be economically developed for each resource option. Project Development and Operational Risks -the risks and issues associated with the development of specific projects,including regulatory and permitting issues,the potential for construction costs overruns, actual operational performance relative to planned performance,and so forth.This category also includes non-completion risks once a project gets started,the risk that adverse operating conditions will severely damage the facilities resulting in a shorter useful life than expected,and project delay risks. Fuel Supply Risks -the risks and issues associated with _the adequacy and pricing of required fuel supplies. Environmental Risks -the risks of environmental- related operational concerns and the potential for future changes in environmental regulations. Transmission Constraint Risks -the risk that the ability to move power froma specific generation resource to where that power is needed will be inadequate,an issue that is particularly important for large generation projects and remote renewable projects. Financing Risks -the risk that a regional entity or individual utility will not be able to obtain the financing required for specific resource options under reasonable and affordable terms and conditions. Regulatory/Legislative Risks -the risk that regulatory ALASKA RIRP STUDY Fundamental RIRP-Related Risks and Uncertainties General «Regional implementation of RIRP elements *Financial capability of Railbelt utilities DSM/Energy Efficiency (DSM/EE) «Lack of Alaska-specific information *Total achievable resource potential *Long-term reliability of savings «Funding source Generation Resources -Conventional *Natural gas supplies,deliverability and prices «Future emissions regulations (including CO,) Generation Resources -Renewables *Total economic resource potential *Optimization of potential sites *Project completion risks associated with large hydro and tidal »Integration of non-dispatchable resources *Environmental and permitting issues Transmission *Adequacy of backbone grid to move power and ensure reliability *Generation site-specific interconnections ¢Siting and permitting issues and legislative issues could affect the economic feasibility of specific resource options. Price Stability Risks-the risk that wholesale power costs willincrease significantly as a result ofchangesinfuelpricesandotherfactors(e.g.,CO,costs). Black &Veatch 1-27 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-7 Resource Specific Risks and Issues -Summary Relative Magnitude of Risk/Issue Project Resource Development Transmission Regulatory/ Potential and Operational Fuel Supply Environmental Constraint Legislative |Price StabilityResourceRisksRisksRisksRisksRisksFinancingRisksRisksRisks DSM/EE Moderate Limited N/A N/A N/A Limited -Moderate Limited Moderate Generation Resources Natural Gas Limited Limited Significant Moderate Limited Moderate Moderate Significant Coal Limited Moderate-Limited Moderate -Limited -Moderate -Moderate Moderate Significant Significant Significant Significant Modular Nuclear Limited Significant Moderate Significant Limited Significant Significant Significant Large Hydro Limited Significant Limited Significant Significant Significant Significant Limited Small Hydro Moderate Moderate Limited Moderate Moderate Limited -Limited Limited Moderate Wind Moderate Moderate N/A Limited Moderate Limited -Limited Limited - Moderate Moderate Geothermal Moderate Limited -N/A Limited -Moderate -Limited -Limited Limited Moderate Moderate Significant Moderate Solid Waste Limited Moderate-N/A Significant Moderate Limited -Limited-Moderate Significant Moderate Moderate Tidal Limited Significant N/A Significant Moderate -Moderate -Moderate -Limited - Significant Significant Significant Moderate Transmission Limited Significant N/A Moderate N/A Significant Moderate -N/A Significant Black &Veatch 1-28 February 2010 SECTION 1 EXECUTIVE SUMMARY 1.9 1.9.1 ALASKA RIRP STUDY Conclusions and Recommendations Conclusions The primary conclusions from the RIRP study are discussed below. 1.The current situation facing the Railbelt utilities includes a number of challenging issues that place the region at a historical crossroad regarding the mix of DSM/EE,generation,and transmission resources that it will rely on to economically and reliably meet the future electric needs of the region's citizens and businesses.As a result of these issues,the Railbelt utilities are faced with the following challenges: o A transmission network that is isolated and has limited total transfer capabilities and redundancies. The inability of the region to take full advantage of economies of scale due to its limited size. A heavy dependence on natural gas from the Cook Inlet for electric generation. Limited and declining Cook Inlet gas deliverability. Lack of natural gas storage capability. The region's aging generation and transmission infrastructure. A heavy reliance on older,inefficient natural gas generation assets. The region's limited financing capability,both individually and collectively among the Railbelt utilities. o Duplicative and diffused generation and transmission expertise among the Railbelt utilities.O000000The key factors that drive the results of Black &Veatch's analysis include the following: o The risks and uncertainties that exist for all alternative DSM/EE,generation,and transmission resource options. o The future availability and price of natural gas. o The public acceptability and ability to permit a large hydroelectric project which is a greater concern,based upon Black &Veatch's discussions with numerous stakeholders,than the acceptability and ability to permit other types of renewable projects,such as wind and geothermal. o Potential future CO,prices,which would impact all fossil fuels,that may or may not result from proposed Federal legislation. o Theregion's existing transmission network,which limits:1)the ability to transfer power between areas within the region to minimize power costs,and 2)places a maximum limit on the amount of non-dispatchable resources that can be integrated into the region's transmission grid. o The ability of the region to raise the required financing,either by the utilities on their own or through a regional G&T entity. o Whether the Railbelt utilities develop a number of currently proposed projects that were selected outside of a regional planning process. Figures 1-10 and 1-11 graphically demonstrate how the results of the various reference and sensitivity cases are impacted by these important uncertainties.Figure 1-10 shows the cumulative present value cost for each year over the 50-year planning horizon;similarly,Figure 1-11 shows the annual wholesale power cost (cents/kWh)in 2010 dollars.In both cases,we have shown selected reference and sensitivity cases to highlight how dependent the results are to these key uncertainties. Black &Veatch :1-29 February 2010 SECTION 1 Figure 1-10 Cumulative Present Value Cost -Selected Reference and Sensitivity Cases CumulativePresentValueCost($000)$16,000,000 $14,000,000 $12,000,000 $10,000,000 $8,000,000 $6,000,000 $4,000,000 $2,000,000 Year a=Plan 1A/1B --1A/1B With Double DSM/EE Programs =-1A/1B With High Gas Prices -- 1A4/1B Without CO2 Taxes mn om 1A/1B With Susitna (Low Watana Expansion)-----1A/1B With Committed Units --1A/1B Without DSM/EE Programs --=1A/1B Without Chakachamna Figure 1-11 Annual Wholesale Power Cost -Selected Reference and Sensitivity Cases WholesalePowerCost(cents/kWh)-2010Dollars25.00 20.00 EXECUTIVE SUMMARY ALASKA RIRP STUDY 5.00 D000TTTTot RS KPO DD PP Ph oP oP OP ch oP Br WO WO MS FP PP A ODPPPPPMKLKKKKKKKKKKKKKSKKSS Year --Plan 1A1B --Plan2A --1A/1B With Double DSM/EE Programs ---1A/1B Without DSM/EE Programs --1A/1B With High Gas Prices -1A/1B Without CO2 Taxes --1A/1B Without Chakachamna --1A/1B With Susitna (Low Watana Expansion) ---1A/1B With Committed Units Black &Veatch 1-30 February 2010 SECTION 1 , EXECUTIVE SUMMARY ALASKA RIRP STUDY As can be seen in Figure 1-10,which shows cumulative net present value costs over the 50-year planning horizon,the 1A/1B With Susitna (Low Watana Expansion),1A/1B With no DSM/EE Programs,1A/1B Without Chakachamna,1A/1BWith Committed Units,and 1A/1B With High Gas Prices Sensitivity Cases are all higher cost than Scenario 1A/1B,in descending order.The 1A/1B With Double DSM/EE Programs and 1A/1B With No CO,Taxes Sensitivity Cases are lower cost that Scenario 1A/1B. Figure 1-11 shows how significant the uncertainty regarding CO,taxes is with regard to the results. It also shows the economic value of achieving higher DSM/EE savings that were assumed in the Scenario 1A/1B Reference Case if those savings can be achieved.Also,shown is the fact that the other sensitivity cases are higher cost than Scenario 1A/1B. 3.The resource plans that were developed as part of this study for each Evaluation Scenario include a diverse portfolio of resources.If implemented,the RIRP will lead to: o The development of a resource mix resulting from a regional planning process. Greater reliance on DSM/EE and renewable resources and a lower dependence on natural gas. A more robust transmission network.. More effective spreading of risks among all areas of the region. A greater ability to respond to large load growth should these load increases occur.Stated another way,the implementation of the RIRP will provide a stronger foundation upon which to base future economic development efforts. 4.The cost of this greater reliance on DSM/EE and renewable resources is less than the continued heavy reliance on natural gas based upon the base case gas price forecast that was used in this analysis.This result is achievable if the region builds a large hydroelectric project.There are uncertainties,at this point in time,regarding the environmental and/or geotechnical conditions under which a large hydroelectric project could be built.If a large hydroelectric facility can not be developed,or if the cost of the large hydroelectric project significantly exceeds the current preliminary estimates,then the costs associated with a predominately renewable future would be greater than continuing to rely on natural gas.00005.Our analysis shows that Scenarios 1A and 1B result in the same resources and,consequently,the same costs and emissions.In other words,the cost of achieving a renewable energy target of 50 percent by 2025 (Scenario 1B)is no greater than the cost of the unconstrained solution (Scenario 1A).This result applies only if a large hydroelectric project is built. 6.Scenarios 2A and 2B were evaluated to determine what the impact would be if the demand in the region was significantly greater than it is today.In fact,the per unit power costs were not less than Scenario 1A/1B due to the cost of Susitna which was the resource chosen to meet this additional load. 7.Additionally,the implementation of a regional plan will result in lower costs than if the individual Railbelt utilities continue to go forward on their own.While the scope of this study did not include the development of separate integrated resource plans for each of the six Railbelt utilities,we did complete a sensitivity analysis to show the cost impact if the utilities develop their currently proposed projects (referred to as committed units)that were selected outside of a regional planning process.The Railbelt utilities are moving forward with these projects due to the existing uncertainty regarding the formation of GRETC.While this sensitivity case does not fully capture the incremental cost of the utilities acting independently over the 50-year planning horizon,it does provide an indication of the relative cost differential.Figure 1-12 shows the resulting total annual costs of the two different resource plans.In the aggregate,the cost of the Committed Unit Sensitivity Case was approximately Black &Veatch 1-31 February 2010 SECTION I EXECUTIVE SUMMARY ALASKA RIRP STUDY 5.6 percent,or $484 million on a cumulative net present value cost basis,higher than Scenario 1A/1B. The main conclusion to draw from this graphic is that there are significant cost savings associated with the Railbelt utilities implementing a plan that has been developed to minimize total regional costs,while ensuring reliable service,as opposed to the individual utilities working separately to meet the needs of their own customers. Figure 1-12 Comparison of Results -Scenario 1A/1B Versus Committed Units Sensitivity Case $16,000,000 $14,000,000 : = $12,000,000 --$10,000,000 $8,000,000 $6,000,000 Za $4,000,000 a $2,000,000 p>CumulativePresentValueCost($000)[--Plan 4A/18 --1A/1B With Committed Units | 8.There are a number of risks and uncertainties regardless of the resource options chosen.For example: 1)there is a lack of Alaska-specific data upon which to build an aggressive region-wide DSM/EE program,2)the future availability and price of natural gas affects the viability of natural gas generation,and 3)the total economic potential of various renewable resources is unknown at this time.In some cases,these risks and uncertainties (e.g.,the ability to permit a large hydroelectric facility)might completely eliminate a particular resource option.Due to these risks and uncertainties, it will be important for the region to maintain flexibility so that changes to the preferred resource plan can be made,as necessary,as these resource-specific risks and uncertainties become more clear or get resolved. 9.Significant investments in the region's transmission network need to be made within the next 10 years to ensure the reliable and economic transfer of power throughout the region.Without these investments,providing economic and reliable electric service will be a greater challenge. 10.The increased reliance on non-dispatchable renewable resources (e.g.,wind)will require a higher level of frequency regulation within the region to handle swings in electric output from these resources.An increased level of regulation has been included in Black &Veatch's transmission plan. Even with this increased regulation,however,the challenges associated with the integration of non-dispatchable resources will ultimately place a maximum limit on the amount of these resources that can be developed. Black &Veatch 1-32 February 2010 SECTION 1 EXECUTIVE SUMMARY 11.The implementation of the RIRP does not require that a regional generation and transmission entity (e.g.,GRETC)be formed.However,the absence of a regional entity with the responsibility for implementing the RIRP will increase the difficulty of the region's ability to implement a regional plan and,in fact,Black &Veatch believes that the lack of a regional entity will,as a practical matter,mean that the RIRP will not be fully implemented.As a consequence,the favorable outcomes of the RIRP discussed above would not be realized.The interplay between the formation of a regional entity and the RIRP is shown in Figure 1-13. Current Situation ¢Limited redundancy «Limited economies of scale *Dependence on fossil fuels *Limited Cook Inlet RIRP Study ©Plan that economically schedules what,when, and where to build,based on available fuel and energy supplies +S0-year time horizon «Competes generation, transmission,fuel supply Figure 1-13 REGA Study ALASKA RIRP STUDY Interplay Between GRETC and Regional Integrated Resource Plan Proposed RIRP Results «Increased DSM/energy efficiency ¢Increased tenewables *Reduced dependence on natural gas *Increased transmission GRETC Formation t Financing Options ©Pre-funding of capital gas deliverability and DSM/energy and storage efficiency options «Aging G&T «Considers CO,regulationinfrastructure*Includes renewable «Inefficient fuel use energy projects *Difficult financing °Arrives at a plan to bud +Oupicative G&T future infrastructure forestiseminimumlong-tun cost tooPratepayers *Considers fuel supply options and risks 1.9.2 Recommendations requirements Future Situation ¢Robust transmission ¢Diversified fuel supply ©System-wide power rates: ¢Spread risk |GRETC Enabler ft. +Wise resource use State financial assistance Regional planning *Respond to large load growth *Technical resources *New technologies *Commercial bond market *State financial assistance (Bradley Lake model) *Construction-work-in-progress: 10-Year Transition Period This subsection summarizes the overall recommendations arising from this study,broken down into the following three categories: e Recommendations -General e Recommendations -Capital Projects e Recommendations -Other 1.9.2.1 Recommendations -General The following general actions should be taken to ensure the timely implementation of the RIRP: 1.The State should work closely with the utilities and other stakeholders to make a decision regarding the formation of GRETC and to develop the required governance plan,financial and capital improvement plan,capital management plan and transmission access plan,and address other matters related to the formation of the proposed regional entity. Black &Veatch 1-33 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 2.-The State should establish certain energy-related policies,including: o The pursuit of large hydroelectric facilities o DSMEE program targets o RPS (ie.,target for renewable resources),and the pursuit of wind,geothermal,and tidal (which will become commercially mature during the 50-year planning horizon)projects in addition to large hydroelectric projects;the passage of an RPS would be meaningful as a policy statement even though the preferred resource plan would achieve a 50 percent renewable level by 2025, o System benefit charge to fund DSW/EE programs and or renewable projects 3.The State should work closely with the Railbelt utilities and other stakeholders to establish the specific preferred resource plan.In establishing the preferred resource plan,the economic results of the various reference cases and sensitivity cases evaluated in this study should be considered,as well as the environmental impacts discussed in Section 13 and the project-specific risks discussed in Section 14. 4.Black &Veatch believes that the Scenario 1A/1B resource plan should be the starting point for the selection of the preferred resource plan as discussed below.Table 1-8 provides a summary of the specific resources that were selected,based upon economics,in the Scenario 1A/1B resource plan during the first 10 years. A project selected in Scenario 1A/1B after the first 10 years especially worthy of mention is the Chakachamna Hydroelectric Project in 2025. Another important consideration in the selection of a preferred resource plan is evaluation of the sensitivity cases evaluated,as presented in Section 13.Issues addressed through the sensitivity cases and considered in Black &Veatch's selection of a preferred resource plan include the following and are discussed in Table 1-9.Following that discussion, o What if CO,regulation doesn't occur? o What is the effect if the committed units are installed? o What if Chakachamna doesn't get developed? o What would be the impact of the alternative Susitna projects? There are several projects that are significantly under development and included in the preferred resource plan.These significantly developed projects include: o Healy Clean Coal Project (HCCP) o Southcentral Power Project oO Fire Island Wind Project o Nikiski Wind Project These projects are discussed in Table 1-10. In addition to these resources,Black &Veatch believes that Mt.Spurr,Glacier Fork,Chakachamna and Susitna should be pursued further to the point that the uncertainties regarding the environmental, geotechnical and capital cost issues become adequately resolved to determine if any of the projectscouldactuallybebuilt. Black &Veatch 1-34 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-8 Resources Selected in Scenario 1A/1B Resource Plan Project Discussion DSMIEE Resources The full level of DSM/EE resources evaluated was selected based upon their relative economics.Sensitivity analysis indicates that even greater levels of DSM/EE may be cost-effective.The lack of Alaska-specific DSM/EE data causes the exact level of cost-effective DSM/EE to remain uncertain. Nikiski Wind The RIRP selected this project in the initial year.It is being developed as an IPP project and is well along in the development process.The ARRA potentially offers significant financial incentives if this project is completed by January 1,2013.These incentives could further improve its competitiveness.As a wind unit,it has no impact on planning reserves,but contributes to renewable generation. HCCP HCCP is completed and GVEA has negotiated with AIDEA for its purchase.This project was selected in the initial year of the plan. Fire Island Wind Project The Fire Island Wind Project is being developed as an IPP project with proposed power purchase agreements provided to the Railbelt utilities.The project may be able to benefit significantly from ARRA and the $25 million grant from the State for interconnection,This project was selected in 2012. Anchorage 1x1 6FA Combined Cycle The RIRP selected this unit for commercial operation in 2013.This unit is very similar in size and performance to the Southcentral Power Project being developed as a joint ownership project by Chugach and ML&P for 2013 commercial operation. The project appears well under development with the combustion turbines already under contract.The project fits well with the RIRP and the joint ownership at least partially reflects the GRETC joint development concept. Glacier Fork Hydroelectric Project The RIRP selected this project for commercial operation in 2014,the first year that it was available for commercial operation in the models.Of the large hydroelectric projects,Glacier Fork is by far the least developed.Glacier Fork has very limited storage and thus does not offer the system operating flexibility of the other large hydroelectric units.There is also significant uncertainty with respect to its capital cost and ability to be licensed.Because it has such a minimal level of firm generation in the winter,it does not contribute significantly to planning reserves,but does contribute about 6 percent of the renewable energy to the Railbelt.Detailed feasibility studies and licensing are required to advance this option. Anchorage and GVEA MSW Units The RIRP selected these units in 2015 and 2017.Historically,mass bum MSW units such as those modeled,have faced significant opposition due to emissions of mercury,dioxin,and other pollutants.Other technologies which result in lower emissions,such as plasma arc,are not commercially demonstrated.The units included in the RIRP are relatively small (26 MW in total)and are not required to be installed to meet planning reserve requirements,but their base load nature contributes nearly 4 percent of the renewable energy.Detailed feasibility studies would be required to advance this alternative. GVEA North Pole Retrofit The retrofitting of GVEA's North Pole combined cycle unit with a second train using a LM6000 combustion turbine and heat recovery steam generator was selected in 2018 coincident with the assumption of the availability of natural gas to GVEA.The retrofit takes advantage of capital and operating cost savings resulting from the existing installation. Black &Veatch 1-35 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-8 (Continued) Resources Selected in Scenario 1A/1B Resource Plan Project Discussion Mt.Spurr Geothermal Project The first unit at Mt.Spurr was selected in 2020.Mt.Spurr's developer,Ormat, currently has commercial operation scheduled for 2017.Significant development activity remains for the project including verifying the geothermal resource.Mt. Spurr will also require significant infrastructure development including access roads and transmission lines.This infrastructure may correspond to similar infrastructure development required for Chakachamna which is selected in 2025 in the RIRP.As the implementation of the RIRP unfolds,there will likely be the need to adjust the timing of the resource additions following the implementation of the initial projects. Table 1-9 Impact of Selected Issues on the Preferred Resource Plan Issue Discussion CO,Regulation The sensitivity case for Scenario 1A without CO,regulation selects the Anchorage LMS 100 project instead of Fire Island and Mt.Spurr in the first 10 years. Committed Units Installation of the committed units significantly increases the cost of Scenario 1A/1B.In addition to the committed units,this plan selects five wind units from 2016 through 2024 in response to CO, regulation.The plan with the committed units eliminates Chakachamna and does not meet the 50 percent renewable target by 2025. Chakachamna Chakachamna could fail to develop because of licensing or technical issues.Also,if the cost of Chakachamna were to increase to be equivalent to the alternative Susitna projects on a GWh basis,it would not be selected.The sensitivity case without Chakachamna for the first 10 years is identical to Scenario 1A/1B,The case does not meet the 50 percent renewable target by 2025 and is 5.2 percent higher in cost than the preferred resource plan. Susitna None of the alternative Susitna projects are selected in the Scenario 1A/1B resource plan.The least cost Susitna option,which is Low Watana Expansion,is 15.3 percent more than the preferred resource plan and 9.0 percent more than the case without Chakachamna.The 50 percent renewable requirement can not be met without Susitna if Chakachamna is not available. Black &Veatch 1-36 February 2010 SECTION 1 EXECUTIVE SUMMARY Table 1-10 ALASKA RIRP STUDY Projects Significantly Under Development Project Discussion Preferred Resource Plan Recommendation HCCP HCCP is completed and GVEA has negotiated with AIDEA for its purchase.The project is part of the least cost scenario.While CO,regulation has been assumed in the RIRP,those regulations are not in place and there is no absolute assurance that they will be in place or what the costs from the regulations will be.HCCP adds further fuel diversity to the Railbelt,especially to GVEA who doesn't currently have access to natural gas.As a steam unit,HCCP improves transmission system stability. Black &Veatch recommends that HCCP be included in the preferred resource plan. Southcentral Power Project The Southcentral Power Project is well under development with the combustion turbines purchased.The timing and technology are generally consistent with the preferred resource plan.The project will improve the efficiency of natural gas generation in the Railbelt and permit the retirement of aging units. Black &Veatch recommends the continued development of the Southcentral Power Project as part of the preferred resource plan. Fire Island Wind Project The Fire Island Wind Project is being developed as an IPP project with proposed power purchase agreements provided to the Railbelt utilities.The project may be able to benefit significantly from ARRA and the $25 million grant from the State for interconnection.This project is part of the least cost plan and provides renewable energy to the Railbelt system.Issues with interconnection and regulation will need to be resolved. Subject to the successful negotiation of a purchase power agreement and successful negotiation of the interconnection and regulation issues,Black &Veatch recommends that it be part of the preferred resource plan in a time frame that allows for the ARRA benefits to be captured. Nikiski Wind Project The Nikiski Wind Project is an IPP project like Fire Island and has the same potential to benefit from ARRA.It is also part of the least cost plan. Like Fire Island,subject to successful negotiation of a purchase power agreement and successful negotiation of the interconnection and regulation issues,Black &Veatch recommends that it be part of the preferred resource plan in a time frame that allows for the ARRA benefits to be captured. Black &Veatch 1-37 February 2010 SECTION I EXECUTIVE SUMMARY ALASKA RIRP STUDY In the case of the Mt.Spurr Geothermal Project,exploration should continue to determine the extent and characteristics of the geothermal resource at the site. In the case of Susitna,the primary focus should be on completing engineering studies to optimize the size and minimize the costs of the project.In the case of Glacier Fork and Chakachamna,the additional work should look for "fatal flaws”. Additionally,further analysis needs to be completed relative to integrating wind and other non- dispatchable renewable resources into the transmission network. 5.The State and Railbelt utilities should develop a public outreach program to inform the general public regarding the preferred resource plan,including the costs and benefits. 6.The State Legislature should make decisions regarding the level and form of State financial assistance that will be provided to assist the Railbelt utilities and AEA,under a unified regional G&T entity (i.e.,GRETC),develop the generation resources and transmission projects identified in the preferred resource plan. 7.The electric utilities,various State agencies,Enstar and Cook Inlet producers need to work more closely together to address short-term and long-term gas supply issues.Specific actions that should be taken include: o Development of local gas storage capabilities with open access among all market participants as soon as possible. o Undertake efforts to secure near-term LNG supplies to ensure adequate gas over the 10-year transition period until additional gas supplies can be secured either in the Cook Inlet,from the North Slope or from long-term LNG supplies. o The State should complete a detailed cost and risk evaluation of available long-term gas supply options to determine the best options.Once the most attractive long-term supplies of natural gas have been identified,detailed engineering studies and permitting activities should be undertaken to secure these resources. o Appropriate commercial terms and pricing structures should be established through State and regulatory actions to provide producers with the incentive to increase exploration for additional gas supplies in the Cook Inlet or nearby basins.This action is required to provide the necessary long-term contractual certainty to result in additional exploration and development. 1.9.2.2 Recommendations -Capital Projects Efforts should be undertaken to begin the development,including detailed engineering and permitting activities,of the following capital projects,which are included in Black &Veatch's recommended preferred resource plan. 1.Develop a comprehensive region-wide portfolio of DSM/EE programs. 2.Generation projects: o Projects under development (HCCP,Southcentral Power Project,Fire Island Wind Project,and Nikiski Wind Project) Glacier Fork Hydroelectric Project Generic Anchorage MSW Project Generic GVEA MSW Project GVEA North Pole Retrofit Project Mt.Spurr Geothermal Project Chakachamna Hydroelectric Project Susitna Hydroelectric ProjectO000000 Black &Veatch 1-38 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Transmission and related substation projects,including the following projects which have been identified for priority attention because of their immediate impact on the reliability of the existing system.These projects are estimated to be required within the next five years. Soldotna to Quartz Creek Transmission Line ($84 million -Project B) Quartz Creek to University Transmission Line ($112.5 million -Project C) Douglas to Teeland Transmission Line ($37.5 million -Project D) Lake Lorraine to Douglas Transmission Line ($80 million -Project E) SVCs ($25 million -Other Reliability Projects) Funds to undertake the study of the Southern Intertie ($1 million) Funds to investigate the provision of regulation that will facilitate the integration of renewable energy projects into the Railbelt system ($50 million,including cost of BESS -Other Reliability Projects)00000001.9.2.3 Recommendations -Other Other actions,related to the implementation of the RIRP,that should be undertaken include: 1.The State Legislature should appropriate funds for the initial stages of the development of a regional DSMEE program,including 1)region-wide residential and commercial end-use saturation surveys, 2)residential and commercial customer attitudinal surveys,3)vendor surveys,4)comprehensive evaluation of economically achievable potential,and 5)detailed DSM/EE program design efforts. Develop a regional DSM/EE program measurement and evaluation protocol. If GRETC is not formed,some type of a regional entity should be formed to develop and deliver DSM/EE programs to residential and commercial customers throughout the Railbelt region,in close coordination with the Raitlbelt utilities. Likewise,if GRETC is not formed,some type of a regional entity should be formed to develop the renewable resources included in the preferred resource plan. Establish close coordination between the Railbelt electric utilities,Enstar and AHFC regarding the development and delivery of DSM/EE programs. Aggressively pursue available Federal funding for DSM/EE programs and renewable projects. Further development of tidal power should be encouraged due to its resource potential in the Railbelt region.Although this technology is not commercially available,in Black &Veatch's opinion,at this point in time,it has the potential to be economic within the planning horizon. The State and Railbelt utilities should work closely with resource agencies to identify environmental issues and permitting requirements related to large hydroelectric and tidal projects,and conduct the necessary studies to address these issues and requirements. Complete a regional economic potential assessment,including the identification of the most attractive sites,for all renewable resources included in the preferred resource plan. .Develop streamlined siting and permitting processes for transmission projects. 11. 12. Develop a regional frequency regulation strategy for non-dispatchable resources. Develop a regional competitive power procurement process and a standard power purchase agreement to provide IPPs an equal opportunity to submit qualified proposals to develop specific projects. Black &Veatch 1-39 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 13.Federal legislative and regulatory activities,including those related to emissions regulations,should be monitored closely and influenced to the degree possible. 14.Monitor the licensing progress of small modular nuclear units. 1.10 Near-Term Implementation Action Plan (2010-2012) The purpose of this subsection section is to identify our overall recommendations regarding the near-term implementation plan,covering the period from 2010 to 2012.Our recommended actions are grouped into the following categories: ¢General actions ¢Capital projects e Supporting studies and activities e =©Other actions In many ways,this near-term implementation plan shown in Tables 1-11 through 1-14 serves two objectives. First,it identifies that steps that should be taken during the next three years regardless of the alternative resource plan that is chosen as the preferred resource plan.Second,it is intended to maintain flexibility as the uncertainties and risks associated with each alternative resource plan become more clear and or resolved. Black &Veatch 1-40 February 2010 SECTION 1 EXECUTIVE SUMMARY 1.10.1 General Actions Table 1-11 Near-Term Implementation Action Plan -General Actions ALASKA RIRP STUDY Actions Category Description Timeline Est.Cost General Actions e The State should work closely with the utilities and other 2010 stakeholders to make a decision regarding the formation of GRETC and to develop the required governance plan, financial and capital improvement plan,capital management plan and transmission access plan,and address other matters related to the formation of the proposed regional entity e Establish State energy-related policies regarding:2010-2011 o The pursuit of large hydroelectric facilities o DSM/EE program targets o RPS (ie.,target for renewable resources),and the pursuit of wind,geothermal,and tidal projects o .System benefit charge to fund DSM/EE programs and or renewable projects e The State should work closely with the Railbelt utilities 2010 and other stakeholders to establish the preferred resource plan,using the Scenario 1A/1B resource plan as the starting point ©Mt.Spurr,Glacier Fork,Chakachamna and Susitna should |2010-2011 be pursued further to the point that the uncertainties regarding the environmental,geotechnical and capital cost issues become adequately resolved to determine if any of these projects could actually be built e Develop a public outreach program to inform the public 2010-2011 regarding the preferred resource plan,including the costs and benefits e The State Legislature should make decisions regarding the |2010-2011 level and form of State financial assistance that will be provided to assist the Railbelt utilities and AEA,under a unified regional G&T entity (i.e,GRETC),develop the generation resources and transmission projects identified in the preferred resource plan $6.8 million $0.2 million Not applicable To be determined $0.1 million Not applicable Black &Veatch 1-41 February 2010 SECTION 1 EXECUTIVE SUMMARY Table 1-11 (Continued) Near-Term Implementation Action Plan -General Actions ALASKA RIRP STUDY Actions Category Description Timeline Est.Cost The electric utilities,various State agencies,Enstar and Cook Inlet producers need to work more closely together to address short-term and long-term gas supply issues; specific actions that should be taken include: [o) 3° Development of local gas storage capabilities as soon as possible Undertake efforts to secure near-term LNG supplies to ensure adequate gas over the 10-year transition period until additional gas supplies can be secured The State should complete a detailed cost and risk evaluation of available long-term gas supply options to determine the best options;once the most attractive long-term supplies of natural gas have been identified, detailed engineering studies and permitting activities should be undertaken to secure these resources Appropriate commercial terms and pricing structures should be established through State and regulatory actions to provide producers with the incentive to increase exploration for additional gas supplies in the Cook Inlet or nearby basins 2010-2012 To be determined Black &Veatch 1-42 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.10.2 Capital Projects :Table 1-12 Near-Term Implementation Action Plan -Capital Projects Actions Category Description Timeline Est.Cost Capital Projects e Develop a comprehensive region-wide portfolio of 2011-2016 |$34 million DSM/EE programs within first six years e Begin detailed engineering and permitting activities 2011-2016 Varies by associated with the generation projects identified in the project initial years of the preferred resource plan,including: o Projects under development (HCCP,Southcentral Power Project,Fire Island Wind Project,and Nikiski Wind Project) o Glacier Fork Hydroelectric Project o Generic Anchorage MSW Project o Generic GVEA MSW Project o GVEA North Pole Retrofit Project o Mt.Spurr Geothermal Project o Chakachamna Hydroelectric Project o Susitna Hydroelectric Project ©Begin detailed engineering and permitting activities 2011-2016 Varies by associated with the transmission projects identified in the project initial years of the preferred resource plan,including: o Soldotna to Quartz Creek Transmission Line o Quartz Creek to University Transmission Line o Douglas to Teeland Transmission Line o Lake Lorraine to Douglas Transmission Line o SVCs o Funds to undertake the study of the Southern Intertie o Funds to investigate the provision of regulation that will facilitate the integration of renewable energy projects into the Railbelt system Black &Veatch 1-43 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.10.3 Supporting Studies and Activities Table 1-13 Near-Term Implementation Action Plan -Supporting Studies and Activities Actions Category Description Timeline Est.Cost Supporting e The State Legislature should appropriate funds for the 2010-2011 $1.0 million Studies and initial stages of the development of a regional DSM/EEActivitiesprogram,including 1)region-wide residential and commercial end-use saturation surveys,2)residential and commercial customer attitudinal surveys,3)vendor surveys,4)comprehensive evaluation of economically achievable potential,and 5)detailed DSM/EE program design efforts e Develop aregional DSW/EE program measurement and 2012 $0.1 million evaluation protocol ©The State and Railbelt utilities should work closely with 2010-2011 |$0.2 million resource agencies to identify environmental issues and permitting requirements related to large hydroelectric and _tidal projects «Conduct necessary studies to address resource agencies'2011-2012 To be issues and data requirements related to large hydroelectric determined and tidal projects e Complete a regional economic potential assessment,2010-2012 |$1.5 million including the identification of the most attractive sites,for all renewable projects included in the preferred resource plan e Develop a regional frequency regulation strategy for non-2011 $0.5 million dispatchable resources e Develop a regional standard power purchase agreement 2011-2012 |$0.2 million for IPP-developed projects e Develop a regional competitive power procurement 2011-2012 |$0.2 million process to encourage IPP development of projects included in the preferred resource plan Black &Veatch 1-44 February 2010 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.10.4 Other Actions Table 1-14 Near-Term Implementation Action Plan -Other Actions Actions Category Description Timeline Est.Cost Other Actions Forma regional entity (if GRETC is not formed)to 2010-2011 Subject to develop and deliver DSM/EE programs to residential and decision commercial customers throughout the Railbelt region,in regarding close coordination with the Railbelt utilities formation of GRETC Establish close coordination between the Railbelt electric 2010-2011 |$0.2 million utilities,Enstar and AHFC regarding the development and delivery of DSM/EE programs Aggressively pursue available Federal funding for 2010-2011 |$0.2 million DSMI/EE programs Forma regional entity (if GRETC is not formed)and 2011-2012 Subject to encourage IPPs to identify and develop renewable projects decision that are included in the preferred resource plan regarding formation of GRETC Further encourage the development of tidal power Ongoing To be determined Monitor,and influence to the degree possible,Federal Ongoing Not legislative and regulatory activities,including those related applicable to emissions regulations Aggressively pursue available Federal funding for 2010-2012 |$0.2 million renewable projects Develop streamlined siting and permitting processes for 2010-2011 |$0.5 million transmission projects Monitor the licensing progress of small modular nuclear Ongoing Not units applicable 1-45 February 2010Black&Veatch PROJECT OVERVIEW SECTION 2 .AND APPROACH ALASKA RIRP STUDY 2.0 PROJECT OVERVIEW AND APPROACH This section provides an overview of the RIRP and Black &Veatch's approach to the completion of this study. 2.1 Project Overview In response to a directive from the Alaska Legislature,the AEA was the lead agency for the development of this RIRP for the Railbelt region.This region is defined as the service areas of six regulated public utilities that comprise the region,including:Anchorage ML&P,Chugach,GVEA,HEA,MEA,and SES. The goal of this project is to minimize future power supply costs and maintain or improve on current levels of power supply reliability through the development of a single comprehensive RIRP for the Railbelt region. The intent of the RIRP project is to provide: e Anup-to-date model that the utilities and AEA can use as a common database and model for future planning studies and analysis. e Anassessment of loads and demands for the Railbelt electrical grid for a time horizon of 50 years including new potential industrial demands. Projections for Railbelt electrical capacity and energy growth,fuel prices,and resource options. e Ananalysis of the range of potential generation resources available,including costs,construction schedule,and long-term operating costs. e A schedule for existing generating unit retirement,new generation construction,and construction of backbone redundant transmission lines that will allow the future Railbelt electrical grid to operate reliably under a transmission tariff which allows access by all potential power producers,and with a postage-stamp rate for electric energy and demand for the entire Railbelt as a whole. e A long-term schedule for developing new fuel supplies that will provide for reliable,stable priced electrical energy for a 50-year planning horizon. e A short-term schedule that coordinates immediate network needs (i.e.,increasing penetration level of non-dispatchable generation,such as wind)within the first 10 years of the planning horizon with the long-term goals. e A short-term plan addressing the transition from the present decentralized ownership and control to aunifiedG&T entity that identifies unified actions between utilities that must occur during this transition period. e A diverse portfolio of power supply that includes,in appropriate portions,renewable and alternative energy projects and fossil fuel projects,some or all of which could be provided by IPPs. e A comprehensive list of current and future generation,transmission and electric power infrastructure projects. Black &Veatch 2-4 February 2010 PROJECT OVERVIEW SECTION 2 AND APPROACH ALASKA RIRP STUDY Black &Veatch conducted the REGA study for the AEA,which evaluated the feasibility of the Railbelt utilities forming an organization to provide coordinated unit commitment and economic dispatch of the region's generation resources,generation and transmission system planning,and project development for the Railbelt.As a result of that study,legislation was proposed to create GRETC,with a 10-year transition period in to achieve these goals.This RIRP is based on the GRETC concept being implemented from the beginning of the study's time horizon. Black &Veatch had primary responsibility for conducting this Railbelt RIRP.In addition to Black &Veatch, three other AEA contractors (HDR,EPS,and SNW)played important roles in the development of the RIRP. HDR updated work from the mid-1980s on the Susitna Hydroelectric Project and developed the capital and operating costs,as well as the generating characteristics,for several smaller sized Susitna options.HDR'sworkwasusedbyBlack&Veatch in the Strategist®and PROMOD®modeling discussed below.HDR's report summarizing the results of its work is provided in Appendix A. EPS assisted in the evaluation of the region's transmission system. SNW developed the financial model used to determine the overall financing costs for the portfolios of generation and transmission projects developed as part of this project,and evaluated the impact of some financial options that could be used to address financing issues and mitigating related rate impacts.The results of SNW's analysis are provided in Appendix B. 2.2 Project Approach The RIRP study process for the Railbelt system consisted of three key stages:data collection,optimal generation expansion along with integrated transmission expansion planning and production cost modeling, and report writing and documentation.Throughout this process,data related to alternative demand-side, supply-side,and transmission resource options were compiled,reviewed,screened for appropriateness,andmodeledusingVentyx's Strategist®and PROMOD®optimal generation expansion and production cost models.Model inputs and assumptions take into consideration possible sensitivity cases and any considerations unique to the six utilities to derive the least-cost plan for the Railbelt region's electric system. To complete this study,the Black &Veatch project team,in collaboration with the other aforementioned AEA contractors,completed the tasks shown in Figure 2-1. Black &Veatch 2-2 February 2010 PROJECT OVERVIEW SECTION 2 AND APPROACH ALASKA RIRP STUDY Figure 2-1 Project Approach Overview Task1 -Collect Data -Existing4ReportsandDocuments Task 2 -Attend and Assist in Initial Technical Workshop Task 3 .Collect Data -Current €Information from StakeholdersTask4-Participate in Advisory4WorkingGroupMeetings Task5 -Develop Resource Plan4Scenarios Task 6 -Present Resource Plan Scenarios Task?-Develop Regional IntegratedCResourcePian Task 8 -Present Scenarios and Plans to Stakeholders <Task 9 -Develop Draft Report\ Task 10 -Develop Final Report Task 1 -Collect Data -Existing Reports and Documents Black &Veatch issued data requests to the six Railbelt utilities to update and add to the data previously obtained in the REGA study.These data included existing generating resources and operating data,load and energy requirements,transmission characteristics,purchase power transactions,and DSM/EE programs. Task 2 -Attend and Assist in Initial Technical Workshop Black &Veatch worked with the AEA to sponsor a Technical Workshop near the beginning of the project to obtain information and input from the various regional stakeholders and to enable the.development of scenarios for evaluation which provided the basis for the assessment of future fuel supply,generation,and transmission resource alternatives for the Railbelt. Task 3 -Collect Data -Current Information From Stakeholders Black &Veatch collected additional information from other regional stakeholders,including producers, ratepayer groups,and representatives from project developers,as well as the DSM/EE,environmental and renewables communities. Black &Veatch 2-3 February 2010 PROJECT OVERVIEW SECTION 2 AND APPROACH ALASKA RIRP STUDY Task 4 -Participate in Advisory Working Group Meetings Black &Veatch participated in five meetings with the Advisory Working Group that was formed for the project.The role of this Advisory Working Group is described later in this section. Task 5 -Develop Resource Plan Scenarios This task involved the following activities: Subtask 5.1 -Development of Economic Parameters Subtask 5.2 -Development of Regional Load Forecast Subtask 5.3 -Development of Fuel Price Forecasts Subtask 5.4 -Development of Reserve Criteria Subtask 5.5 -Evaluation of Conventional Supply-Side Alternatives Subtask 5.6 -Evaluation of Hydro Projects Subtask 5.7 -Evaluation of Wind and Other Renewable Projects Subtask 5.8 -Evaluation of Transmission System Expansions Subtask 5.9 -Evaluation of Generation Unit Retirements Subtask 5.10 -Evaluation of DSM/EE Measures Subtask 5.11 -Scenario Mapping Subtask 5.12 -Benchmarking Analysis Task 6 -Present Resource Plan Scenarios Black &Veatch made a presentation to the RIRP Advisory Working Group and AEA explaining the resource scenarios and describing the recommended Evaluation Scenarios. Task 7 -Develop Regional Integrated Resource Plan Black &Veatch then developed alternative resource plans for each of the four Evaluation Scenarios,based upon the results of Task 5. Task 8 -Present Scenarios and Plans to Stakeholders Black &Veatch presented its preliminary results,conclusions and recommendations to interested parties at a second Technical Conference that was held in December. Task 9 -Develop Draft Report Black &Veatch prepared a Draft Report that was provided to the AEA and made available to interested parties for review and comment. Task 10 -Develop Final Report Black &Veatch prepared a Final Report that incorporated comments received on the Draft Report. Black &Veatch 2-4 February 2010 PROJECT OVERVIEW SECTION 2 AND APPROACH ALASKA RIRP STUDY 2.3 Modeling Methodology 2.3.1 Study Period and Considerations The evaluation timeframe consists of a 50-year study period from 2011 through 2060.Evaluations were conducted in nominal dollars with the annual costs discounted to 2011 dollars for comparison using the present worth discount rate discussed in Section 5.After evaluating the seasonal month definitions of the utilities,Black &Veatch defined the summer season as May 1 through October 31,and the winter season as November 1|through April 30. The 50-year planning period presented challenges to reduce the running time for the Strategist®model to acceptable levels.Several techniques were used including bracketing years and pre-screening alternatives toreducethenumberofalternativesincludedintheStrategist®runs to reduce run time to a target level of approximately 24 hours per run. For comparison purposes,existing project capital costs are not carried forward.Only new generation, transmission,and DSM/EE costs,as well as system fuel,O&M and emission allowance costs,are consideredwhencomparingthevariousexpansionplanscenarios. 2.3.2 Strategist?and PROMOD®Overview For the RIRP Study,Black &Veatch used Ventyx's Strategist®optimal generation expansion model toevaluatethevariousalternativesandscenarios.The Strategist®model is capable of evaluating a large number of plans with generating,transmission,and DSMW/EE alternatives by using probabilistic dispatch,dynamic programming,and elimination of factors that typically are not taken into account when comparing thousands (or millions)of plans,such as ramp-up and ramp-down rates and start-up energy and start-up fuel costs. The model utilizes a typical week methodology and evaluates the relative economics between all possible plans within a given set of criteria and minimizes utility costs through optimization.The model checks all feasible combinations in every year of the study period using dynamic programming.At the end of the study period,the model traces back through the matrix of feasible states to find the plans with the best financial or other operational criteria (cumulative present worth cost in this case)and ranks these plans according to this criteria.The plans that are shown to be most promising from an economic standpoint are then input intoVentyx's hourly chronological model,PROMOD®,for additional analysis with this more detailed production costing model. PROMOD*®performs unit commitment and economic dispatch under a wide array of operation constraints along with detailed transmission simulation.The model develops hourly generation,production costs,and fuel consumption for generating units utilizing detailed operating characteristic inputs.Hours on-line and start-up hours are also calculated.Transmission line information such as hourly flow and constraints are available for output along with unserved energy.Debt service (i.e.,return on investment and depreciation)forcapitaladditionsareaddedexternallytotheoperatingcostsdevelopedbyPROMOD®. 2.3.3.BenchmarkingWiththeuniquenessofthe Railbelt electric system,it was important that Black &Veatch benchmark themodels'production costing against an actual year in order to validate the models'abilities to appropriatelymodelthecharacteristicsoftheRailbelt.The benchmarking exercise was based on 2008 actual data as that was the most recent year with complete generation,transmission,and purchases and sales data to benchmarkagainst.Actual 2008 data was gathered from the utilities regarding generating unit performance,outages,andcosts,as well as information on purchases and sales of economy energy and corresponding costs. Black &Veatch 2-5 February 2010 PROJECT OVERVIEW SECTION 2 AND APPROACH ALASKA RIRP STUDY The goal of the benchmarking effort was to model system inputs and validate the outputs against actual values for 2008 for each utility.Outputs to be validated were generating unit capacity factors,hydroelectric generation amounts,generation costs,economy energy purchases and sales,and resulting costs.Wheeling rates,fuel costs,operations and maintenance (O&M)costs,and other costs were input on a per unit basis. Scheduled and forced outages were input directly to reflect actual unit availability. Accurately benchmarking the Railbelt's hydroelectric generation was important to validate the models.Much of the Railbelt system in 2008 was powered by combined cycle and simple cycle turbines.With most of the scheduled maintenance on combined cycles occurring in the summer months due to high electric demand in the winter,less-efficient,more costly combustion turbines must be used for generation.When total system costs begin to rise,hydroelectric storage units can be used to generate a portion of the Railbelt's requirements. The fact that storage water for hydro is finite must also be taken into account.Water levels in hydroelectric reservoirs have minimums and maximums.The model was set up to limit the amount of generation available in each month to avoid exhausting all of the available water in one month and not having enough remaining in other months. Overall,the benchmarking process verified that the models adequately reflect operation in the Railbelt for purposes of the RIRP.While the models have limitations in their modeling of the Railbelt system,they also have other benefits for their use in this study. 2.3.4 Hydroelectric MethodologyStrategist®treats hydroelectric generation as a load modifier,while PROMOD®offers the option of treatinghydroelectricasaloadmodifierordispatchingit.In Strategist®hydroelectric generating units are dispatched one at a time.Each unit has a maximum and minimum capacity level at which it operates.Each unit can also be given a monthly total energy that is available.The utility's overall load is reduced by the minimum hydro generation available in each hour.The difference between the total hydroelectric energy in the month and the minimum hydro energy is the energy available for peak shaving.Capacity available for peak shaving is the difference between the maximum and minimum capacities of the unit.The resulting load shape is then met by unit dispatch of other available resources. Black &Veatch provided the model with the monthly energy limits for hydroelectric units and allowed the model to perform the load modifications.These limits were calculated from the average monthly historical generation of the units provided by the utilities.Providing monthly energy limits for each hydroelectric unit prevents the model from taking an unrealistic amount of water from the reservoirs,but still allows for variance throughout the year.The amount of baseload energy to be met will be reduced,thereby allowing some units to be shut down,or run minimally.This methodology will also lower the amount of load to be met by less-efficient thermal units and lowers production costs.Peak load reduction will also work to reduce the amount of units that need to be started to handle peak times. There are several factors that drive hydroelectric generation in the Railbelt system.Summer maintenance outages on other generating units can increase the amount of hydroelectric generation necessary to reducesystemcosts.Limitations on the deliverability of natural gas in the winter for thermal generating units canalsodrivetheuseofhydroelectricgenerationintheregion.As the system ages,the correlation betweenhighersystemcostsandgeneratingunitmaintenancewillbereducedaslessefficientunitswillberetired and replaced.With multiple factors influencing hydroelectric generation in the Railbelt region,Black &VeatchbelievesthattheloadmodificationtechniqueisanappropriatemethodtomodelhydroelectricgenerationintheRailbelt.Modeling assumptions specific to each hydroelectric unit are presented in Section 4. Black &Veatch 26 February 2010 PROJECT OVERVIEW SECTION 2 AND APPROACH ALASKA RIRP STUDY PROMOD?*offers the additional modeling feature that,on a weekly basis,PROMOD®will dispatch available hydro energy at the times when avoided thermal unit costs are greatest.This feature was used in thePROMOD®modeling., 2.3.5 Evaluation Scenarios Black &Veatch,in collaboration with the Advisory Working Group,developed four Evaluation Scenarios for this project.Black &Veatch then developed a 50-year resource plan for each of these Evaluation Scenarios. The primary objective of these Evaluation Scenarios was to evaluate two key drivers.The first driver was to look at what the impacts would be if the demand in the region was significantly greater than it is today;of primary interest was to see if higher demands would result in greater reliance on large generation resource options and allow for more aggressive expansions of the region's transmission network. The second driver was to determine the impact associated with the pursuit of a significant amount of renewable resources over the 50-year time horizon. As aresult,Black &Veatch evaluated the four Evaluation Scenarios shown on Figure 2-2. Figure 2-2 Evaluation Scenarios a Base Case Scenario 1A Scenario 1B > 3} LL 38 HighGrowth |scenario 2A Scenario 2BCase Least Cost Force 50% Level of Renewables by 2025 (Energy} Black &Veatch 2-7 February 2010 PROJECT OVERVIEW SECTION 2 AND APPROACH ALASKA RIRP STUDY The key assumptions underlying each Evaluation Scenario include: e Scenario 1 -Base Case Load Forecast 00000000Current regional loads with projected growth All available resources -fossil fuel,renewables,and DSM/EE Probabilistic estimate of gas supply availability and prices Deterministic price forecasts for other fossil fuels Emissions including CO,costs Transmission system investments required to support selected resources Scenario 1A -Least Cost Plan Scenario 1B -Force 50%Renewables e Scenario 2 -Large Growth Load Forecast [e)0000Significant growth in regional loads due to economic development efforts or large scale electrification (e.g.,economic development loads,space and water heating fuel switching,and electric vehicles) Base case resources,fuel availability/price forecasts and CO,costs Transmission system investments required to support selected resources Scenario 2A -Least Cost Plan Scenario 2B -Force 50%Renewables 2.4 Stakeholder Input Process One of the AEA's directives to Black &Veatch,related to the completion of this project,was to proactively solicit input from a broad cross-section of the Railbelt region's stakeholders.Elements of the stakeholder involvement process are summarized in Figure 2-3. Figure 2-3 Elements of Stakeholder Involvement Process >Utility Stakeholders >Draft Report *Individual and Joint Meetings |«Data Gathering Presentation of Non-Utility Stakeholders Preliminary Results, Conclusions and «Face-to-Face Meetings Recommendations «Reference Documents to All Stakeholders Advisory Working Group Meetings if Final Report Public Presentations on Final Results, Conclusions and Recommendations Black &Veatch 2-8 February 2010 PROJECT OVERVIEW SECTION 2 AND APPROACH ALASKA RIRP STUDY As the first element of this public participation process,the AEA held a two-day Technical Conference near the beginning of the project.The purpose of this conference was to enable a number of industry participants to provide their views regarding the broad array of issues confronting the Railbelt utilities and to provide comments specific to the completion of this study.Approximately 100 individuals,including Black &Veatch project team members,participated in this conference. Additionally,Black &Veatch met with a number of non-utility stakeholders to provide them with the opportunity to present their input directly to the Black &Veatch project team members.These meetings were in addition to the meetings that Black &Veatch held with Railbelt utility representatives. Black &Veatch and the AEA also held several meetings with the Advisory Working Group that was assembled for this project.The role and membership of this Advisory Working Group is discussed in the next subsection. Additionally,the AEA held a second Technical Conference during which the Black &Veatch project team presented our preliminary results,conclusions and recommendations.Subsequent to that presentation,all stakeholders were provided the opportunity to review and comment on our Draft Report. 2.5 Role of Advisory Working Group and Membership Another important element of this project's stakeholder input process was the formation of an Advisory Working Group,assembled by the AEA,which provided input to the Black &Veatch/AEA project team throughout the study.This Group,which met five times during the course of the project,included the following members: *Norman Rokeberg,Retired State of Alaska e Jim Sykes,Alaska Public Interest Group Representative,Chairman e Lois Lester,AARP e Chris Rose,Renewable Energy Alaska e Marilyn Leland,Alaska Power Association Project e Mark Foster,Mark A.Foster &Associates e Brad Janorschke,Homer Electric Association ®Nick Goodman,TDX Power,Inc. Carri Lockhart,Marathon Oil Company e Pat Lavin,National Wildlife e Colleen Starring,Enstar Natural Gas Federation -Alaska Company e Steve Denton,Usibelli Coal Mine,Inc. e Debra Schnebel,Scott Balice Strategies ¢Tony Izzo,TMI Consulting e Jan Wilson,Regulatory Commission of .Alaska The Advisory Working Group provided input on a number of project-related issues,including the following: Project objectives,scope,and approach Evaluation Scenarios to be considered Input assumptions for each Evaluation Scenario Tax and legal issues Preliminary results,conclusions and recommendations Draft Report Black &Veatch 2-9 February 2010 SECTION 3 SITUATIONAL ASSESSMENT ALASKA RIRP STUDY 3.0 SITUATIONAL ASSESSMENT The purpose of this section is to discuss the myriad of issues facing the Railbelt electric utilities;the major categories of issues are shown on Figure 3-1.This discussion is largely drawn from the REGA study that was completed by Black &Veatch. Figure 3-1 Summary of Issues Facing the Railbelt Region Uniqueness b \of the Railbelt Natural Gas FutureIssues- Adopt New DirectionSrey?Infrastructure Issues Future Maintain Status Quo Resource Options Impact on Railbelt ?@ Power Costs ?Reliability @ Sustainability 2 Risks Businesses and Consumers Each of these issue categories is discussed below. Black &Veatch 3-1 SECTION 3 SITUATIONAL ASSESSMENT ALASKA RIRP STUDY 3.1 Uniqueness of the Railbelt Region ; In comparison to the business and operating environment of the utility industry in the lower-48 states,the Railbelt region is unique.The following presents a summary of the more significant issues that cause the uniqueness of the Railbelt region: Issue Description Size and Geographic First,the overall size of the Railbelt region is small when compared to other Expanse utilities or areas,The total combined peak load of all six utilities is approximately 870 MW.When compared to the peak loads of other utilities throughout the U.S.,a combined "Railbelt utility”would still be relatively small. As an example,many electric utilities have single coal or nuclear plants that exceed 900 MW of capacity (based on Energy Information Administration plant data,there are 100 generating units in the U.S.with nameplate capacity greater than 900 MW).This relative size,coupled with the geographic expanse and diversity of the Railbelt region,creates certain issues and affects the solutions available to the Railbelt utilities, Limited Interconnections |The Railbelt electric transmission grid has been described as a long straw,as and Redundancies opposed to the integrated,interconnected,and redundant grid that is in place throughout the lower-48 states.This characterization reflects the fact that the Railbelt electric transmission grid is an isolated grid with no external interconnections to other areas and that it is essentially a single transmission line running from Fairbanks to the Kenai Peninsula,with limited total transfer capabilities and redundancies. As a consequence,each Railbelt utility is required to maintain much higher generation reserve margins than elsewhere in order to ensure reliability in the case of a transmission grid outage.Furthermore,the lack of interconnections and redundancies exacerbates a number of the other issues facing the Railbelt region. 3.2 Cost lssues The following issues relate to the current cost structure of the Railbelt utilities. Issue Description Relative Costs -Railbelt |Alaska has the seventh highest cost of any state based on the total cost per kWh, Region Versus Other as shown in Table 3-1.Alaska's average retail rate was 13.3 cents per kWh;in States comparison,Hawaii was the highest ranked state at 21.3 cents per kWh and Idaho was the lowest at 5.1 cents per kWh.The U.S.average was 9.1 cents per kWh. Black &Veatch 3-2 February 2010 SECTION 3 SITUATIONAL ASSESSMENT ALASKA RIRP STUDY Issue Description Relative Costs--Among |ML&P's customers pay the lowest monthly electric bills in the region;GVEA's Railbelt Utilities residential customers pay the highest monthly bills.Chugach,MEA,Seward and Homer are in the middle. Table 3-2 provides a comparison of the monthly electric bills paid by the residential,small commercial and large commercial customers of each of the six Railbelt utilities.Monthly bills are shown for residential customers assuming average monthly usage of 750 kWh based upon the rates of each Railbelt utility. Also shown are the monthly bills paid by small commercial (10,000 kWh average monthly usage)and large commercial (150,000 kWh average monthly usage)customers. Economies of Scale The Railbelt utilities have not been able to take full advantage of economies of scale and scope.With respect to scale economies,there are several reasons that the region has been limited by scale constraints.First,as previously noted,the combined peak load of the six Railbelt utilities is still relatively small.Second, the Railbelt transmission grid's lack of redundancies and interconnections with other regions has placed reliability-driven limits on the size of generation facilities that could be integrated into the Railbelt region. Third,the fact that each utility has developed their own long-term resource plans has led to less optimal results (from a regional perspective)relative to what could be accomplished through a rational,fully coordinated regional planning process.Finally,the existence of six separate utilities,and their small size on an individual utility basis,has restricted their ability to take advantage of economies of scale with regards to staffing and their skill sets.For example,the development of six separate programs to develop and deliver DSM and energy efficiency programs is a considerably more difficult challenge than would be the case if there was one regional entity responsible for developing and delivering DSM and energy efficiency programs to residential and commercial customers throughout the Railbelt region. Black &Veatch 3-3 February 2010 SECTION 3 SITUATIONAL ASSESSMENT ALASKA RIRP STUDY Table 3-1 Relative Cost per kWh (Alaska Versus Other States)-2007 Average Retail Price Average Retail Price Name (cents/kWh)Name (cents/kKWh) Hawaii 21.29 North Carolina 7.83 Connecticut 16.45 Colorado 7.76 New York 15.22 Alabama 7.57 Massachusetts 15.16 Minnesota 7.44 Maine 14.59 New Mexico 7.44 New Hampshire 13.98 Oklahoma 7.29 Alaska 13.28 South Carolina 7.18 Rhode Island 13.12 Montana 7.13 New Jersey 13.01 Virginia 7A2 California 12.80 Tennessee 7.07 Vermont 12.04 Oregon 7.02 District of Columbia 11.79 Arkansas 6.96 Maryland 11.50 South Dakota 6.89 Delaware 11.35 Kansas 6.84 Florida 10.33 Iowa 6.83 Texas 10.11 Missouri 6.56 Nevada 9.99 Indiana 6.50 Pennsylvania 9.08 North Dakota 6.42 Arizona 8.54 Utah 6.41 Michigan 8.53 Washington 6.37 Wisconsin 8.48 Nebraska 6.28 Illinois 8.46 Kentucky 5.84 Louisiana 8.39 West Virginia 5.34 Mississippi 8.03 Wyoming 5.29 Ohio 791 Idaho 5.07 Georgia 7.86 US Average 9.13 Source:Energy Information Administration,"State Electricity Profiles,'DOE/EIA-0348,April 2009. 34 February 2010Black&Veatch SITUATIONAL ASSESSMENT ALASKA RIRP STUDY Table 3-2 Relative Monthly Electric Bills Among Alaska Railbelt Utilities Regulatory Fuel Cost Energy |Total Energy |Customer }Usage FactorRESIDENTIAL{|Adjustment Charge Charge Charge Charge (kWh)Typical Bill GVEA 0.05903 0.000274 |0.11153 0.170834 15 750 $143.13 Chugach 0.02478 0.000274 |0.09282 0.117874 8.42 750 $96.83 MEA 0.03084 0.000274 |0.09447 0.125584 5.65 750 $99.84 ML&P -0.00655 0.000274 |0.09476 0.088484 6.56 750 $72.92 Homer (North of 0.00078 0.000274 |0.12718 0.128234 11 750 $107.18 Kachemak Bay) Homer (South of 0.00078 0.000274 |0.13056 0.131614 1 750 $109.71 Kachemak Bay) City of Seward NA NA NA NA NA NA NA Average $104.93 Regulatory SMALL Fuel Cost Energy |Total Energy |Customer |Usage FactorCOMMERCIAL|Adjustment |Charge Charge Charge Charge (kWh)Typical Bill GVEA 0.05903 0.000274 |0.10957 0.168874 20 10,000 $1,708.74 Chugach 0.02478 0.000274 |0.08001 0.105064 18.26 10,000 $1,068.90 MEA 0.03084 0.000274 |0.07677 0.107884 5.65 10,000 $1,084.49 ML&P -0.00655 0.000274 |0.09182 0.085544 12.88 10,000 $868.32 Homer (North of 0.00078 0.000274 0.1181 0.119154 24 10,000 $1,215.54 Kachemak Bay) Homer (South of 0.00078 0.000274 j}0.11479 0.115844 40 10,000 $1,198.44 Kachemak Bay) City of Seward NA NA NA NA NA NA NA Average $1,190.74 Regulatory Usage LARGE Fuel Cost Energy |Total Energy |Customer Demand Factor Demand COMMERCIAL |Adjustment |Charge Charge Charge Charge Charge (kWh)Usage (kW)|Typical Bill GVEA 0.05903 0.000274 0.7835 0.137654 50 8.55 150,000 500 $24,973.10 Chugach 0.02478 0.000274 0.0462 0.071254 58.85 11.65 150,000 500 $16,571.95 MEA 0.03084 0.000274 |0.06004 0.091154 13.37 4.85 150,000 500 $16,111.47 ML&P -0.00655 0.000274 |0.05351 0.047234 44.15 11.85 150,000 500 $13,054.25 Homer (South of 0.00078 0.000274 0.11479 0.115844 40 6.73 150,000 500 $20,781.60KachemakBay) City of Seward NA NA NA NA NA NA NA NA NA Average $18,298.47 Black &Veatch 3-5 February 2010 SECTION 3 SITUATIONAL ASSESSMENT ALASKA RIRP STUDY 3.3.Natural Gas Issues The Railbelt utilities use Cook Inlet natural gas as a significant generation fuel source and have done so for decades;the future ability of the Railbelt region to continue to rely on natural gas is in question. Issue Description Historical Dependence _{Natural gas has been the predominant source of fuel for electric generation used by the customers of ML&P,Chugach,MEA,Homer and Seward.Additionally, customers in Fairbanks have benefited from natural gas-generated economy energy sales in recent years. For example,Figure 3-2 shows the current dependence that Chugach (as well as MEA,Homer and Seward as a result of their full requirements contracts with Chugach)has on natural gas-fired generation,based on 2007 statistics.ML&P has a similar level of dependence on natural gas. Expiring Contracts There are a number of inherent risks whenever a utility or region is so dependent upon one fuel source;risks with regard to prices,availability and deliverability. An additional risk faced by Chugach is the fact that its current gas supply contracts are expected to expire in the 2010-2012 timeframe. Chugach is currently working with its natural gas suppliers to renegotiate these contracts.Although those negotiations are have not all been finalized,it is expected that future natural gas prices paid by Chugach will increase once the existing contracts expire. Declining Developed An additional problem faced by the Railbelt utilities,due to their dependence on Reserves and natural gas,is the fact that existing developed reserves in the Cook Inlet are Deliverability declining as well as the current deliverability of that gas.This is shown in Figure 3-3. As can be seen in Figure 3-3,the population of the Anchorage,Mat-Su,and _ Kenai Peninsula areas has increased 170%from 1970 to 2005.At the same time,known reserves in the Cook Inlet have declined by 80%.As a result,one prediction is that gas supplies from known reserves will meet less than one-half of the residential and commercial demand for heating and electricity by 2017. This will have a significant impact on all Railbelt utilities,including ML&P as its owned gas supply is experiencing the same dynamics. Related to the decline in reserves is the decline in deliverability.Historically, deliverability of natural gas to electric generation facilities,and to residential and commercial customers in the Railbelt region for heating,was not a problem. However,deliverability is increasingly becoming an issue as the Cook Inlet gas fields age,reserves decline,and pressures drop. Consequently,the Railbelt region will not be able to continue its dependence upon natural gas in the future unless additional reserves are discovered in the Cook Inlet,new sources of supply become available from the North Slope,or a liquefied natural gas (LNG)import terminal is developed to supplement Cook Inlet supplies. Black &Veatch 3-6 February 2010 SECTION 3 SITUATIONAL ASSESSMENT ALASKA RIRP STUDY Issue Description Historical Increase in Railbelt residential and commercial customers are directly feeling the rise in Gas Prices natural gas prices that have occurred in recent years.These price increases are shown in Figure 3-4,which shows historical gas prices paid by Chugach. Figure 3-5 shows the resulting rise in Chugach's residential bills from 1994 to 2007.As can be seen,the fuel component of the customer's bill has increased significantly in recent years while the base rate component has remained roughly the same until very recently.With natural gas prices expected to continue increasing,Railbelt consumers and businesses will experience even greater electric prices in the future. Potential Gas Supplies |Regardless of the future source of additional natural gas supplies (whether new and Prices gas supplies from the Cook Inlet,gas from the North Slope,or imported LNG supplies),one reality can not be escaped:future gas supply prices will be higher. For additional gas supplies in the Cook Inlet to become available,prices will need to increase to encourage exploration and development.This results from the fact that oil and gas producers make investment decisions based upon expected returns relative to investment opportunities available elsewhere in the world. In the case of North Slope gas supplies,the cost,probability and timing of potential gas flows to the Railbelt region are unknown at this time. Nevertheless,given the construction lead times for a potential gas pipeline to provide gas from the North Slope,gas from that region is unlikely to be available for a number of years.Furthermore,if gas from the North Slope becomes available in the Railbelt region through either the Bullet Line or Spur Line,prices will be tied to market prices since potential natural gas flows to the Railbelt region will be just one of the competing demands for the available gas. Additionally,the pipeline transmission rates that will be paid to move gas to the Railbelt region will be significantly higher than the transportation rates that are imbedded in the delivered cost of gas from Cook Inlet suppliers under existing contracts. Black &Veatch 37 February 2010 SECTION 3 SITUATIONAL ASSESSMENT ALASKA RIRP STUDY Figure 3-2 Chugach's Reliance on Natural Gas 7% 93% ©Natural Gas-Fired @ Hydro Total Power Produced in 2007:2,628 gWh Source:Chugach Electric Association. Figure 3-3 Overview of Cook Inlet Gas Situation Population of Known Reserves Supply From Known Anchorage,Mat-Su,Down 80%Reserves Projected and Kenai Peninsula to Meet Half of up 170%Since 1970 Demand for Residential and 398,626 (In trillion cubic feet)Commercial Heating poverey -and Electricity a By 2017 '.(In billion cubic feet) 147,150 fe :95 ro 44 a oo All 2005 1970 2005 Discoveries Reserves Supply Demand Source:Alaska Department of Labor,Alaska Division of Oil and Gas,and Science Applications intemational Corporation. Black &Veatch 38 February 2010 SECTION 3 SITUATIONAL ASSESSMENT ALASKA RIRP STUDY Figure 3-4 Historical Chugach Natural Gas Prices Paid $6 5 S/S ChugachES oo LN LZ | ee es $- 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 Source:Chugach Electric Association. Figure 3-5 Chugach Residential Bills Based on 700 kWh Consumption 1994 -2007 $105 \ $95 JnJ $85 Za a =$75 6 Total i --Fuel and Power Re identialje$65 Production Expense $55 $45 Base Rate Revenue (A&G,O&M,customer expense,debt service costs and margins) $35 } 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Source:Chugach Electric Association. Black &Veatch 3-9 February 2010 SECTION 3 SITUATIONAL ASSESSMENT ALASKA RIRP STUDY 3.4 Load Uncertainties Load uncertainties are always an issue of concern for electric utilities as they make investment decisions regarding which generation resources to add to their system. Issue Description Stable.Native Growth With regard to native load growth (e.g.,normal load growth resulting from residential and commercial customers),Railbelt utilities have experienced stable growth in recent years.This stable native load growth is expected to continue in the years ahead,absent significant economic development gains in the region. Potential Major New There are,however,a number of potential significant load additions that could Loads result from economic development efforts.These potential load additions could result from the development of new,or expansion of existing,mines (e.g.,Pebble and Donlin Creek),continued military base realignment,and other economic development efforts or the enactment of policies that would result in increased electric loads (e.g.,gas to electric fuel switching,electric vehicles, etc.).Additionally,there will likely be a significant increase in Railbelt population if the proposed North Slope natural gas pipeline,and or the Spur Line or Bullet Line,is built. Any significant growth in Railbelt electric loads will lead to increased stress on the ability of the region's utilities to meet demand,particularly if this demand has to be met by one utility.This is particularly true given the fact that a significant portion of the Railbelt's electric generation facilities are approaching their planned retirement dates. 3.5 Infrastructure Issues The challenges faced by the Railbelt utilities are magnified by the aging nature of existing generation facilities in the region. Issue Description Aging Generation Approximately 67 percent of the existing generation capability within the Infrastructure Railbelt region is scheduled to be retired within 15 years.During this period, decisions relative to retirement,refurbishment,and life extension must be made. Replacing this capacity with more efficient capacity requires substantial new capital investment,which is offset by the lower cost of generation with better heat rates or when plants incorporate lower fuel cost resources, Baseload Usage of Another issue that is directly related to the aging nature of the existing Railbelt Inefficient Generation generation fleet is the fact that certain older,inefficient generation units are Facilities being used as baseload,or near-baseload,generation facilities,raising regional operating costs.Since the cost of energy production is a combination of fuel costs and heat rate,the combination of rising energy costs and more production from high heat rate units causes large increases in the cost of energy.As more high heat rate units operate more hours,the average cost of power increases even without a fuel cost increase.In addition,it is typical that as generation units mature past the mid-point of their average life there is a strong likelihood that heat rates will rise the further their age goes beyond the mid-point of the expected life. Black &Veatch 3-10 February 2010 SECTION 3 SITUATIONAL ASSESSMENT ALASKA RIRP STUDY Issue Description Operating and Spinning |Railbelt reliability criteria require spinning reserves equal to the largest Reserve Requirements _[operating unit and an operating reserve level of an additional 50%of the largest unit.In addition,the region's system target reserve margin is set at 30%.These reserve levels reflect the absence of interconnections,the relative operating impacts of limited resources and the necessity of maintaining reliability with the existing size of the system.Such high reserve margins affect total fuel and maintenance costs. 3.6 Future Resource Options There are several issues regarding the future resource options that will be available to meet demand within the Railbelt region. Issue Description Acceptability of Large {Much discussion has occurred in recent years about the future role that large Hydro and Coal hydroelectric and coal projects might play in meeting the electricity needs of the Railbelt region.Like other parts of the country and the world,the acceptabilityandeconomicsoflargehydroelectricandcoalfacilitiesareuncertain.Resolving the acceptability issues,and other related economic and environmental issues, associated with large hydro and coal will require the active involvement of the Governor and Legislature,as well as the Railbelt utilities and other stakeholders. Carbon Tax and Other |Another uncertainty facing the Railbelt utilities relates to the restrictions onEnvironmentalcarbonemissions,and the related economic impact,that might be imposed by Restrictions Federal and/or State legislation,as well as other environmental restrictions (e.g.,mercury limits)that will impact the technical and economic feasibility of various generation technologies.In the case of the imposition of carbon taxes, bills are currently working their way through the Federal legislative process,and additional bills may be introduced in the future.These bills each have different targets for the reduction of carbon emissions,and each will result in different levels of carbon taxes and/or different costs for the capturing and sequestering of carbon emissions.Depending upon the form of Federal and/or State carbon legislation ultimately enacted,the economics of fossil-fueled generation technologies could be significantly impacted. Optimal Size and Given the need to replace existing generation facilities and meet expected load Location of New growth,significant investments in new generation resources will be required.A Generation and very important issue that needs to be addressed by the Railbelt utilities is theTransmissionFacilities|optimal size and location of new generation and transmission facilities.This is, in fact,one of the factors driving the interest in the formation of a regional generation and transmission entity,and one of the primary reasons why this RIRP project was commissioned,When individual utilities make resource decisions that optimize the future resource mix for their own needs,the resulting regional resource mix will simply not be as optimal relative to the resource mix that result from a regional planning process.Additionally,decisions that will be made with regard to improving and expanding the Railbelt electric transmission grid will have a direct bearing of determining the optimal size and location of future generation resources. Black &Veatch 3-11 February 2010 SECTION 3 SITUATIONAL ASSESSMENT ALASKA RIRP STUDY Issue Description Limited Development-|Renewable generation technologies represent a significant opportunity for the Renewables Railbelt utilities relative to replacing aging generation facilities and meeting future load growth.To date,the Railbelt utilities have developed renewable resource technologies to a very limited degree,relative to the technical potential of these resources as well as relative to the level of deployment of these technologies in other regions of the country.While this limited use of renewable resources reflects,to a certain degree,the challenges of integrating such resources into a transmission-constrained grid and managing the power fluctuations on an individual utility basis,enhanced transmission infrastructure and regional coordination will create additional opportunities for renewables as part of the portfolio of resources. The issue of integrating technologies having variable outputs (i.e.,non- dispatchable resources),such as wind and solar,into a fossil-fueled grid presents substantial operational challenges including the determination of the optimal level of these resources. Additionally,an important issue related to the implementation of renewables that needs to be addressed is whether the development of renewable resources should be accomplished by the individual Railbelt utilities or whether a regional approach would result in the more efficient and cost-effective deployment of these resources. Limited Development -|Similar to the comments above related to renewable resource technologies,the DSM/EE Programs Railbelt utilities have limited experience with the planning,developing and delivering of DSM/EE programs.To date,the majority of efforts in the Railbelt region and the State as a whole have been focused on the implementation of home weatherization programs.These programs can significantly reduce the energy consumption within individual homes;however,given the limited saturation of electric space heating equipment and the general lack of air conditioning loads,the potential for DSM/EE programs are limited from the perspective of the Railbelt electric utilities.Notwithstanding this,additional opportunities do exist in this area. An implementation issue that needs to be addressed is whether the development and deployment of DSM/EE programs throughout the Railbelt region should be accomplished by the individual Railbelt utilities or whether a regional approach would result in more efficient and cost-effective deployment of these resources. Additionally,given the fact that the total monthly energy bills paid by residential and commercial customers in the Railbelt have increased significantly in recent years and given that natural gas is the predominant form of space heating within the majority of the Railbelt region,it may be appropriate for the electric utilities to work jointly with Enstar to develop DSM/EE programs that would be beneficial to both.This would create economies of scope for the region and reduce the delivery costs of DSM/EE programs. Black &Veatch 3-12 February 2010 SECTION 3 SITUATIONAL ASSESSMENT ALASKA RIRP STUDY 3.7 'Political Issues The following political issues impact the current situation in the Railbelt region. Issue Description Historical Dependence |The Railbelt utilities have been dependent upon State funding for certain on State Funding portions of the regional generation and transmission infrastructure,as well as for certain local infrastructure investments.Some of these investments have been made through the Railbelt Energy Fund;others have been direct appropriations by the Legislature.Regional State-funded infrastructure investments include the Alaska Intertie and Bradley Lake Hydroelectric Plant. Proper Role for State Historical State infrastructure-related investments have provided significant benefits to the residential and commercial customers in the Railbelt.Going forward,one question that needs to be answered is what the proper role of the State should be relative to the further development of the Railbelt region's generation and transmission infrastructure. 3.8 Risk Management Issues The following issues relate to risk management,which has become increasingly important for all utilities. Issue Description Need to Maintain As previously discussed,the recent increase in natural gas prices highlights the Flexibility dangers inherent with an over-reliance on one fuel source or generation technology.Just as investors rely on a portfolio of assets,it is important for utilities to develop a portfolio of assets to ensure safe,reliable and cost-effective service to customers.It also demonstrates the importance of maintaining flexibility. Future Fuel Diversity Fuel supply diversity inherently has value in terms of risk management.Simply stated,the greater a region's dependence upon one fuel source,the less flexibility the region will have to react to future price and availability problems. Aging Infrastructure The fact that the generation and transmission infrastructure in the Railbelt region is aging,and that a significant percentage of the region's generation units are approaching the end of their expected lives,adds to the challenges facing utility managers.That represents the "half empty”view of the situation.The "half full”views leads one to a more positive perspective that the region has an unprecedented opportunity to diversify its resource mix and improve the overall efficiency of its generation fleet. Ability to Spread The level of uncertainty facing the Railbelt region continues to grow,as do the Regional Risks risks attendant to utility operations.One important approach to risk management is to spread the risk to a greater base of investors and consumers so that the impact of those risks on individuals is reduced.Simply stated,the ability of the region to absorb the risks facing it is greater on a regional basis than it is on an individual utility basis. Black &Veatch 3-13 February 2010 DESCRIPTION OF SECTION 4 EXISTING SYSTEM ALASKA RIRP STUDY 4.0 DESCRIPTION OF EXISTING SYSTEM This section contains a general description of the generation and transmission resources currently in use in the Railbelt region.The existing system data was provided by the Railbelt utilities in response to data requests by Black &Veatch.Black &Veatch reviewed the data and,where necessary,applied judgment to the data to obtain a consistent set of existing system data for planning purposes.Detailed information on each existing generating unit is presented in Appendix C. 4.1 Existing Generating Resources 4.1.1.Anchorage Municipal Light &Power ML&P operates seven combustion turbines (Units 1-5,7,and 8)between two power plants,which operate on natural gas,and one steam turbine (Unit 6),which derives its steam from un-fired heat recovery steam generators (HRSGs).Units 1 and 2 are not available for normal dispatch,but are available if needed in an emergency.Unit 4 is dispatched on a normal,but infrequent basis.For this study,Units 1,2,and 4 were not modeled.ML&P's other units provide approximately 280 MW of generating capability.Combustion turbines 5 and 7 have HRSGs,which allow them to operate in a combined cycle mode with the Unit 6 steam turbine.Unit 5 is frequently cycled when used in combined cycle or simple cycle mode.Unit 5 or Unit 7 may be operated in simple cycle mode when the steam turbine is unavailable.ML&P's existing thermal units are shown in Table 4-1. Table 4-1 ML&P Existing Thermal Units Winter Rating Retirement Name Unit Primary Fuel (MW)Date Anchorage ML&P -Plant 1 1 Natural Gas 16.2 N/A Anchorage ML&P -Plant 1 20 Natural Gas 16.2 N/A Anchorage ML&P -Plant 1 3 Natural Gas 32 2037 Anchorage ML&P -Plant 1 4%)Natural Gas 34.1 N/A Anchorage ML&P -Plant 2 5 Natural Gas 37.4 2020 Anchorage ML&P -Plant 2 5/6 Natural Gas 49,2 2020 Anchorage ML&P -Plant 2 7 Natural Gas 81.8 2030 Anchorage ML&P -Plant 2 7/6 'Natural Gas 109.5 2020 Anchorage ML&P -Plant 2 8 Natural Gas 87.6 2030 Anchorage ML&P -Plant 2 6 N/A N/A 2030 Denotes units not included in modeling for this study. Black &Veatch 41 February 2010 DESCRIPTION OF EXISTING SYSTEM ALASKA RIRP STUDY SECTION 4 4.1.2.Chugach Electric Association Chugach operates 13 combustion turbines between three power plants (Bernice 2-4,Beluga 1-7,and International 1-3)which operate on natural gas and one steam turbine (Beluga 8)which derives its steam from HRSGs.Chugach has approximately 500 MW of generating capability.Chugach's existing thermal units are shown in Table 4-2. Table 4-2 Chugach Existing Thermal Units Winter Rating Retirement Name Unit Primary Fuel (MW)Date Bernice 2 Natural Gas 19 2014 Bernice 3 Natural Gas 25.5 2014 Bernice 4 Natural Gas 25.5 2014 Beluga 1 Natural Gas 17.5 2011 Beluga 2 Natural Gas 17.5 2011 Beluga 3 Natural Gas 66.5 2014 Beluga 5 Natural Gas 65 2017 Beluga 6 Natural Gas 82 2020 Beluga 6/8 Natural Gas 108.5 2014 Beluga 7.Natural Gas 82 2021 Beluga 718 Natural Gas 108.5 2014 International 1 Natural Gas 14 2011 International 2 Natural Gas 14 2011 International 3 Natural Gas 19 2012 4.1.3 Golden Valley Electric Association GVEA's generating capability of 278 MW is supplied by four generating facilities.The Healy Power Plant is a27 MW coal-fired unit located adjacent to the Usibelli Coal Mine.GVEA's 187 MW North Pole Power Plant is oil-fired and built next to the Flint Hills refinery.The oil-fired Zehnder Power Plant in Fairbanks can provide 39 MW.The Delta Power Plant (DPP),formerly the Chena 6 Power Plant,can produce 26 MW. GVEA's existing thermal units are shown in Table 4-3. Black &Veatch 42 February 2010 DESCRIPTION OF SECTION 4 EXISTING SYSTEM ALASKA RIRP STUDY Table 4-3 GVEA Existing Thermal Units Winter Rating Retirement Name Unit Primary Fuel (MW)Date Zehnder GTl HAGO 19,2 2030 Zehnder GT2 HAGO 19.6 2030 North Pole GT HAGO 62.6 2017 North Pole GT2 HAGO 60.6 2018 North Pole GT3 NAPHTHA 51.3 2042 North Pole ST4 STEAM 12 2042 Healy ST1 COAL 27 2022 DPP 1 HAGO 25.8 2030 4.1.4.Homer Electric Association HEA owns the natural gas Nikiski combustion turbine.During the summer months it can produce a maximum of 35 MW,whereas in the winter it provides 42 MW.This unit is shown in Table 4-4. Table 4-4 HEA Existing Thermal Units Winter Rating Retirement Name Unit Primary Fuel (MW)Date Nikiski 1 Natural Gas 42.0 2026 4.1.5 |Matanuska Electric Association MEA does not have any existing thermal units. 4.1.6 Seward Electric System The City of Seward currently has three diesel generators in operation,each with capacities of 2.5 MW,and one diesel generator with a capacity of 2.9 MW.In this study,these small existing diesel generators are not included since the City of Seward is a full requirements customer of Chugach and the existing diesels are mainly used for back-up. 4.1.7 Hydroelectric ResourcesCurrently,each of the utilities in the Railbelt region has full or partial ownership in existing hydroelectricgenerationfacilities.The hydroelectric generation plants include Bradley Lake (a 120 MW hydroelectricplantthatundernormalconditionsdispatchesupto90MWandprovidesanadditional27MWofspinningreserves),Eklutna Lake hydroelectric facility (maximum capacity of 40 MW),and Cooper Lake hydroelectric Black &Veatch 4-3 February 2010 SECTION 4 DESCRIPTION OF EXISTING SYSTEM ALASKA RIRP STUDY facility (20 MW of capacity).Table 4-5 gives the percent ownership,average annual energy,and capacity for each utility for each of the existing hydroelectric plants.In the existing system,hydroelectric capacity and energy allocations are based on percent ownership,but in the RIRP modeling runs,all hydroelectric generation is placed geographically such that capacity and energy enter the Railbelt system from the areas in which the projects are physically located.The annual and monthly energy is based on the average historical energy generated at each plant for the previous 9-10 years (depending on historical plant data provided)and is presented in Table 4-6. Table 4-5 Railbelt Hydroelectric Generation Plants Bradley Lake Eklutna Lake Cooper Lake Annual Spinning Annual Annual Percent Energy |Capacity |Reserves Percent Energy |Capacity Percent Energy |CapacityUtility|Allocation (MWh)(MW)(IW)Allocation |(\fWh)(MW)Allocation |(MWh)(MW) MEA 13.8 54,383 12.4 3.7 16.7 26,056 6.7 0 0 0 HEA 12 47,289 10.8 3.2 0 0 0 0 0 0 CEA 30.4 119,800 27.4 8.2 30 46,806 12 100 41,342 20 GVEA 16.9 66,599 15.2 4.6 0 0 0 0 0 ML&P 25.9 102,066 23.3 7 53.3 83,159 21.3 0 0 SES 1 3,941 0.9 0.3 0 0 0 0 0 Total 100 394,078 90 27 100 156,021 40 100 41,342 20 "The values for capacity and spinning reserves represent normal operation.The plant has a nameplate capacity of 126 MW with a nominal rating of 120 MW. Table 4-6 Hydroelectric Monthly and Annual Energy (MWh) Bradley Eklutna Cooper Month Lake Lake Lake January 28,688 11,153 3,696 February 29,448 10,653 3,421 March 31,737 12,374 3,967 April 28,829 12,039 3,687 May 28,643 10,094 3,854 June 31,586 13,425 4,072 July 35,372 14,547 4,361 August 37,881 17,954 3,328 September 37,728 17,494 3,388 October 37,654 14,102 2,421 November 34,152 11,452 2,198 December 32,360 10,734 2,951 Total 394,078 156,021 41,342 Black &Veatch 4-4 February 2010 DESCRIPTION OF SECTION 4 EXISTING SYSTEM ALASKA RIRP STUDY 4.1.8 Railbelt System Table 4-7 shows the resulting total capacity for each utility within the Railbelt region. Table 4-7 Railbelt Installed Capacity Thermal Bradley Eklutna Cooper Existing Lake Lake Lake Utility |Capacity |Capacity'?|Capacity |Capacity Total MEA 0 16.1 6.7 0 22.8 HEA 42 14.0 0 0 56.0 CEA 500.5 35.6 12 20 568.1 GVEA 278.1 19.8 0 0 297.9 ML&P 278.3 30.3 21.3 0 329.9 SES 0 1.2 0 0 1.2 Total 1,098.9 117 40 20 1,275.9 "The nameplate rating for Bradley Lake is 126 MW with 90 MW dispatchable and 27 MW available for spinning reserves under normal conditions. 4.2 Committed Generating Resources Committed generating resources are generating units planned by the individual Railbelt utilities and which are considered committed for installation by the individual Railbelt utilities.Table 4-8 summarizes the cost and performance estimates for the committed units.The cost and performance information was either provided by the individual Railbelt utilities or estimated by Black &Veatch.Cost information is presented in 2009 dollars.The following subsections briefly describe each of the committed units.The committed units are not included in the Reference Case Scenarios;this is discussed further in Section 13. 4.2.1 Southcentral Power Project The Southcentral Power Project,previously known as the South Central Alaska Power Project,is a 3x1 natural gas fired,combined cycle project that utilizes GE LM6000 combustion turbines for a total capacity of approximately 180 MW.Currently,the project is to be jointly owned by Chugach and ML&P with 70 percent of the capacity owned by Chugach and the remaining 30 percent to be owned by ML&P.For modeling purposes,the entire 180 MW is included in the Anchorage area,which is comprised of both Chugach's and ML&P's service areas.The capital cost for the Southcentral Power Project is approximately $370 million with an estimated 2013 commercial operation date.A significant portion of the cost of this unit has already been spent. 4.2.2.ML&P Units ML&P plans to add two units to its system by 2014.The addition of these units will allow ML&P to retiresomeofitsolder,less efficient units.In 2012,ML&P plans to install a GE LM2500 simple cycle combustion turbine with an estimated output of 30 MW.The capital cost associated with this unit is estimated to be $43 million in 2009 dollars.ML&P also plans to construct a GE LM6000 combined cycle plant for commercial operation by 2014.The output of this plant is estimated at 58 MW.The capital cost associated with this project is approximately $95 million in 2009 dollars. Black &Veatch 45 February 2010 SECTION 4 DESCRIPTION OF EXISTING SYSTEM ALASKA RIRP STUDY Table 4-8 Railbelt Committed Generating Resources"? Capital Fixed Commercia Cost Maximum Winter Full Load Heat |Variable O&M O&M 1 OnlinePlantNameArea($000)Capacity (MW)Rate (Btu/kWh)($/MWh)(3/kW-yr)Date Southcentral Power Project Anchorage 370,000 180 7,091 4.29 15.38 2013 ML&P 2500 Simple Cycle Anchorage 43,200 30 9,960 2.32 28.72 2012 MLP LM6000 Combined Cycle Anchorage 95,200 58 7,091 2.32 26.45 2014 Healy Clean Coal Project GVEA 95,000 50 11,090 8.44 79.53 2011/2014 HEA Aeroderivative HEA ®34 8,800 3.85 64.42 2014 HEA Frame HEA @ 42 11,500 3.08 79.07 2014 Nikiski Upgrade HEA @ 77 (34 incremental)10,000 2.91 4.83 2012 Eklutna Generation Station MEA 356,000 187 8,500 4.29 15.38 2015 Seward Diesel #N1 City of Seward 7,200 2.9 9,200 11.41 31.93 2010 Seward Diesel #N2 City of Seward 1,100 2.5 9,200 11.41 31.93 2011 ©2009 dollars HEA has requested that their cost estimates remain confidential while they are obtaining their bids. Black &Veatch 4.6 February 2010 DESCRIPTION OF SECTION 4 EXISTING SYSTEM ALASKA RIRP STUDY 4.2.3.Healy Clean Coal Project The Healy Clean Coal Project (HCCP)resulted from a nationwide competition held by the Department of Energy (DOE)to address the issues surrounding acid rain.The project is located adjacent to Golden Valley's current Healy 1 coal-fired power plant.HCCP utilizes a staged combustion process and other methods to minimize the formation of nitrogen and sulfur oxides.Construction and testing of the project was completed in December 1999,but issues were raised concerning the operations and maintenance cost,reliability,andsafetyoftheproject'. After several years of legal disputes,an agreement was reached for the sale of HCCP to GVEA.GVEA will pay $50 million for the plant "as is”and will have a line of credit up to $45 million to get the unit operating up to GVEA's standards and to integrate the plant into its system.For the RIRP,Black &Veatch has assumed the entire $95 million will be paid by GVEA.The project has an assumed commercial on-line date of 2011,but is expected to have poor reliability initially.GVEA will back up 100 percent of the plant's output with spinning reserve and its battery energy storage system (BESS)until plant reliability improves and settles by 2014.For modeling purposes,Black &Veatch has assumed a 50 percent forced outage rate for HCCP beginning in 2011 and decreasing linearly to the steady state forced outage rate of 3 percent in 2014. Because the HCCP is currently built,it is considered as an alternative in all the model runs except for the committed units case,where it is forced in along with the other committed units in this section. 4.2.4 HEA Units Currently,HEA is an all requirements customer of Chugach in that they receive all of their electric needs from Chugach.The existing agreement expires in 2014 at which time HEA plans to supply its own load.In order to reliably serve its customers at that time,HEA must have generation built or supply contracts to support its service area.HEA has indicated plans to upgrade one of its existing units and build two new units before becoming independent.In 2012,HEA plans to complete an upgrade of its existing Nikiski unit from simple cycle to a combined cycle configuration.The upgrade would add 34 MW to the power plant and bring the plant's capacity from 43 MW to 77 MW.HEA is also planning to construct a new simple cycle aeroderivative unit in 2014 with approximately 34 MW of capacity.HEA may purchase reserves instead of installing the aeroderivative.Also in 2014,HEA plans to build a simple cycle frame unit with approximately 42 MW of capacity. 4.2.5 MEA Units In a situation similar to that of HEA,MEA is currently an all requirements customer of Chugach and plans to be responsible for supplying their own load by 2015.In order to provide reliable service to MEA's customers,it must plan to build generation at that time.Currently,MEA's only source of power generation is the Eklutna hydroelectric power plant.MEA plans to build the Eklutna Generation Station in 2015 with an estimated 180 MW of natural gas fired capacity.Since the project is in the early stages of conceptualization, much of the unit's performance and cost information have been estimated by Black &Veatch and is similar to that of the Southcentral Power Project.The capital cost for this project was developed using the same $/kW amount as the Southcentral Power Project and is estimated at $370 million in 2009 dollars. 4.2.6 City of Seward Diesels The City of Seward currently has four diesel generators in operation totaling approximately 10 MW. Although these four generators have not been included in the existing RIRP modeling,the City of Seward's future diesel generators are being included in the committed units sensitivity case.The existing diesels were not included because Seward is a full requirements customer of Chugach and the existing diesels are primarily used for back-up.Seward plans to install two more diesel generators in 2010 and 2011.Generator #N1 is 'http:/Awww.aidea.org/PDF%20files/HCCP/HCCPFactSheet.pdf. Black &Veatch 4-7 February 2010 DESCRIPTION OF SECTION 4 EXISTING SYSTEM ALASKA RIRP STUDY scheduled to be installed in the spring 2010 with an output of 2.9 MW.The capital cost for #N1 is estimated at $7.2 million in 2009 dollars.Generator #N2 is scheduled to be installed in the spring 2011 with an output of 2.5 MW.Generator #N2 currently exists,but is not connected to the City of Seward's electrical system. The estimated cost for bringing #N2 to operation and for interconnection is $1.0 million in 2009 dollars. 4.3 Existing Transmission Grid For purposes of the RIRP study,the Railbelt transmission system is separated into four main load centers: GVEA or the interior,MEA,Anchorage comprised of Chugach's and ML&P's service areas,and the Kenai comprised of HEA and the City of Seward.Within each load center,energy is assumed to flow freely without transmission constraints.The existing transmission system of the Railbelt may be characterized as weak and in need of development.Power transfer between areas of the system is currently constrained by weak transmission links and stability constraints.Generating reserves cannot be readily shared between areas and project development activities are seriously affected. GVEA's service area is connected with 138 kV lines that supply Delta Junction,Fairbanks,and Healy. The interior and MEA load centers are interconnected via the Alaska Intertie and the Healy-Fairbanks and Teeland-Douglas transmission lines.The Alaska Intertie is a 345 kV (operated at 138 kV),170-mile transmission line that is owned by the AEA connecting the Douglas and Healy substations.The Healy- Fairbanks transmission line is a 230 kV,90-mile transmission line,operated at 138 kV,and runs from the Healy to the Wilson substations which deliver power from the Alaska Intertie directly into the city of Fairbanks.Another 138 kV transmission line also runs from Healy to Nenana to Goldhill and delivers power to Fairbanks.The 138 kV,20-mile Douglas-Teeland transmission line stretches between the Douglas and Teeland substations and connects the southern portion of the Alaska Intertie to the MEA load center.The current transfer capability of the Alaska Intertie and Healy-Fairbanks transmission lines is assumed to be 75 MW and 140 MW,respectively. MEA serves customers down the southern half of the intertie and south of the intertie through the towns of Wasilla and Palmer. The Anchorage load center consists of ML&P's,and Chugach's service territories.ML&P serves the load of the residents and businesses in the central core of Anchorage.Chugach also serves residents and businesses in Anchorage along with the area south of Anchorage,the City of Seward,and into the southern portion of the Kenai Peninsula.For modeling purposes,the City of Seward's load and generation have been placed in the Kenai peninsula to allow economic commitment and dispatch in accordance with GRETC. The MEA and Anchorage load centers are connected via two transmission lines.A 230 kV transmission line connects the Teeland substation to Chugach's Beluga plant in the western portion of the Anchorage load center.A 115 kV transmission line connects the Eklutna Hydro Project and runs through ML&P's area, continuing into Chugach's service territory.The current total transfer capability of these lines is assumed to be 250 MW when power is flowing north into MEA and 50 MW when power is flowing south into Anchorage. The Anchorage and Kenai load centers are connected via a 135-mile,115 kV transmission line,referred to as the "Southern Intertie,”which connects the Chugach system to that of the Kenai Peninsula.The current transfer capability of the Southern Intertie is assumed to be 75 MW when power is flowing north to Anchorage,and 60 MW when the flow is south into the Kenai. Black &Veatch 4-8 February 2010 DESCRIPTION OF SECTION 4 |EXISTING SYSTEM ALASKA RIRP STUDY The Kenai load center consists of HEA's and the City of Seward's service territories.The HEA service area includes the cities of Homer and Soldotna. Figure 4-1 shows the current Railbelt transmission transfer paths,four load centers,and existing transfer capability as modeled.Transfer capability varies depending on generating unit availability and performance as well as on direction of power flow between the areas.The transfer capabilities shown in Figure 4-1 represent the total MW transferable between the respective areas in the indicated direction with no transmission criteria violated.Major generating project additions requiring interconnection to the system are modeled as specific additional areas to appropriately account for transmission losses.Projects that require such areas are Susitna and Chakachamna hydroelectric,Mt.Spurr geothermal,and Turnagain Arm tidal.As transmission lines are added to the system throughout the planning period,transfer capabilities and transmission losses are modified. Figure 4-1 Railbelt Existing Transmission System as Modeled 6%Losses 0%Losses 8%Losses Black &Veatch 4-9 February 2010 DESCRIPTION OF SECTION 4 EXISTING SYSTEM ALASKA RIRP STUDY 4.3.1 Alaska Intertie The Alaska Intertie is a 170-mile long,345 KV transmission line between Willow and Healy that is owned by the AEA.The Intertie was built in the mid-1980s with State of Alaska appropriations totaling $124 million. There is no outstanding debt associated with this asset. The Intertie is one of a number of transmission segments that,when connected together,can move power throughout the network from Delta,through Fairbanks to Anchorage down to Seldovia in the south.This interconnected system of utilities,tied together with the Intertie is collectively termed the "Railbelt Electric Grid System.” The operation of the Intertie is governed by an agreement that was negotiated in 1985 between the predecessor of AEA,the Alaska Power Authority (APA),and four utility participants:ML&P,Chugach, GVEA,and AEG&T Cooperative,Inc.,which is comprised of HEA and MEA.All of the utility participants are connected to the Intertie and can move power on and off the Intertie. For example,GVEA uses the Intertie to purchase non-firm economy energy from ML&P and Chugach.As another example,the Railbelt Electric Grid System is used to transfer power from the Bradley Lake Hydroelectric Plant,which is located east of Homer just below the glacier-fed Bradley Lake.Each of the Railbelt utilities has rights for a specified percentage of the power output from Bradley Lake as shown in Table 4-5.GVEA owns a portion of the capacity and energy available from Bradley Lake,and it transmits this power north to its service area over the AEA Intertie.In practice,however,the GVEA's power from Bradley Lake is displaced by power sold by Chugach to HEA and Seward. Both functional operation of the transmission line,as well as arrangements for the collection of and expenditure of annual operations and maintenance funds,are a part of the agreement.The agreement also specifies a governance structure that consists of representatives from the participating utilities and AEA. The agreement specifies,through interconnection terms and conditions,how utilities are allowed access to the Intertie.Each utility is required to maintain spinning reserve to preserve the reliability of electrical supply throughout the network. 4.3.2 Southern Intertie The Southern Intertie consists of approximately 130 miles of 115 kV transmission line constructed some 50 years ago that connects the Anchorage area operated by the Chugach,and the Kenai peninsula operated by HEA.The Southern Intertie connects the Soldotna substation and the University substation by way of Quartz Creek,Daves Creek and several other load serving taps between Daves Creek and the University substation. The section from Soldotna to Quartz Creek is owned and operated by HEA while the section from Daves Creek to the University substation is owned and operated by Chugach. The HEA section of the Southern Intertie is in poor condition,routed through swampy terrain,and is consequently affected by frost jacking which pushes the poles out of the ground.The Chugach section of the intertie runs through areas susceptible to frequent avalanches.Several sections have been rebuilt;however, over 60 percent of the line's structures are in need of repairs.Although the thermal limit of the 115 kV line is considered to be approximately 145 MW,this intertie is limited to a transfer limit of approximately 75 MW by stability considerations.The intertie is currently used to transfer power from the jointly owned Bradley Lake Hydro Units to utilities in the Anchorage area.This line is considered essential to the development and operation of an integrated Railbelt transmission system. Black &Veatch 4-10 February 2010 DESCRIPTION OF SECTION 4 EXISTING SYSTEM ALASKA RIRP STUDY 4.3.3.Transmission Losses Existing transmission losses have been modeled between the four major load centers.The percentage of losses varies with the load on the transmission lines.Losses for each of the connections between the four load centers that are included in the models are illustrated in Figure 4-1 and represent a percentage of the total flow along the lines.The losses shown represent the losses applied to power flowing both north and south. 4,4 Must Run Capacity Must run capacity are units that are run to maintain the reliability of the Railbelt system regardless of whether they are the most economical generation available.Must run capacity can also result from purchase power contracts which require the utility to purchase the power at all times.Additionally,must run capacity can result from a generating unit not having the capability to be shutdown and started up in response to economic commitment and dispatch.Units are also required to run to maintain voltage and stability.The Railbelt Utilities have indicated the following three units are current must run capacity units and have been modeled as such. e =Nikiski through 2013 e Healy 1 e Aurora Purchase Power Black &Veatch 4-11 February 2010 SECTION 5 ECONOMIC PARAMETERS ALASKA RIRP STUDY 5.0 ECONOMIC PARAMETERS The economic parameters are those necessary for developing the expansion plans using Strategist®and determining the costs associated with those expansion plans.They include inflation,escalation,financing, present worth discount rate,interest during construction interest rate,and development of fixed charge rates. 5.1 Inflation and Escalation Rates Escalation rates have been developed for capital and O&M costs and are consistent with the general inflation rate.The same general inflation rate and escalation rates were used for all Railbelt utilities.For evaluation purposes,2.5 percent was used for annual general inflation and escalation. 5.2 Financing Rates The cost of capital was assumed to be 7 percent. 5.3 Present Worth Discount Rate The present worth discount rate was assumed to be equal to the cost of capital,of 7 percent. 5.4 Interest During Construction Interest Rate The interest during construction interest rate was assumed to be 7 percent. 5.5 Fixed Charge Rates Fixed charge rates were developed for new capital additions based on the cost of capital.The fixed charge rates were based on the assumption of using taxable financing,and further assumed 100 percent debt.In developing financing assumptions,Seattle Northwest Securities Corporation was consulted and a general consensus developed for purposes of estimating the cost of capital for evaluation purposes. The fixed charge rates include the following components in addition to debt amortization: e Issuance costs for debt -2 percent Property insurance -0.5 percent Property taxes -0.5 percent Debt service reserve funds -|year Earnings on reserve funds -7 percent Levelized fixed charge rates were developed for the following financing terms as appropriate.Table 5-1 summarizes these terms as modeled for the GRETC system: e Simple Cycle Combustion Turbines -25 years Combined Cycle Units -30 years Coal Units -30 years Hydro Units -100 years Wind -20 years Municipal Solid Waste -30 years Tidal -20 years Geothermal -25 years Generic Greenfield Nuclear -30 years Black &Veatch 5-1 February 2010 SECTION 5 ECONOMIC PARAMETERS Cost of Capital and Fixed Charge Rates for the GRETC System Table 5-1 Levelized Fixed Charge Rates (%) Financing Terms (Years)Cost of Capital (%)20 25 30 160 7.0 10.543 9.536 8.925 8.163 ALASKA RIRP STUDY The fixed charge rates were used for Strategist®to ensure that all alternatives for expansion plans were selected on a consistent basis.The 100-year term for hydro units,while longer than traditional financing,was .Selected based on the long life span of hydro units so that hydro units would be considered on this consistent basis by Strategist®. Black &Veatch 5-2 February 2010 FORECAST OF ELECTRICAL SECTION 6 DEMAND AND CONSUMPTION ALASKA RIRP STUDY 6.0 FORECAST OF ELECTRICAL DEMAND AND CONSUMPTION 6.1 Load Forecasts Load forecasts were provided by the utilities in response to a Black &Veatch data request.Since the RIRP Study has a 50-year planning horizon,load forecast data was extrapolated through 2060.The load forecast does not include incremental DSM/EE programs not inherently included in the utilities'forecasts. 6.2 Load Forecasting Methodology Each of the utilities provided load forecasts spanning different lengths of time that required extrapolation to develop annual peak and energy requirements for the GRETC electrical system over the 50-year study period. Typically,simple extrapolation of load forecasts is based on exponential growth by using the average annual percentage growth rate for the last 5 or 10 years.This potentially can lead to over forecasting when these percentage growth rates are applied over long periods of time.To compensate for this potential over forecasting,Black &Veatch extrapolated the load forecasts in two different ways and took the average of the two extrapolated forecasts as the forecast used in the RIRP.The first method of extrapolation was the typical approach of extrapolating at the average annual percentage load growth over the last 10 years of the forecast. The second method extrapolated the average annual increase in load over the last 10 years of the forecast.In addition to peak load forecasts,annual minimum load,or valley,forecasts were also developed for the GRETC system.The peak and valley demand and net energy for load requirements forecasts are provided in the following subsection;it should be noted that demand and energy forecasts do not include transmission losses between utilities. 6.3 Peak Demand and Net Energy for Load Requirements Tables 6-1 and 6-2 present the winter and summer peak demand forecasts for each utility as well as the coincident winter and summer peak demands for the GRETC system.The coincident peak demand forecasts were developed by combining all of the utilities'hourly load profiles for 2008 and calculating the 2008 coincident peak demands.The resulting coincident peak demands were compared to the 2008 non-coincident peak demands to develop coincident factors.These factors were applied seasonally to the noncoincident peak demand for both winter and summer months of the study period to develop the resulting coincident peak | demand forecasts for the GRETC system. Table 6-3 presents the annual valley demand forecasts for each utility and the coincident valley demands for the GRETC system.The valley demand forecasts for each utility were developed by taking the minimum load for each utility from the provided hourly load information for 2008.Valley demand forecasts for 2011 and beyond were calculated for each utility by applying the annual increase in peak demands to the valleys. A non-coincident value was calculated by summing up the minimum load for each utility and the result was compared to the coincident minimum load value for the GRETC system that was developed by taking theminimumloadfromtheGRETChourlyprofiletodevelopavalleycoincidentfactor.The resulting valleycoincidentfactorwasappliedtotheannualnon-coincident valley load for the GRETC system to develop a coincident valley demand forecast through 2060. The net energy for load requirements for the GRETC system were developed by taking the sum of all the utilities'individual energy requirements.The resulting net energy for load forecast is provided in Table 6-4. Black &Veatch 6-1 February 2010 FORECAST OF ELECTRICAL SECTION 6 DEMAND AND CONSUMPTION ALASKA RIRP STUDY Table 6-1 GRETC's Winter Peak Load Forecast for Evaluation (MW) 2011 -2060 Winter Peak Demand (MW) Year CEA GVEA HEA MEA ML&P SES GRETC 2011 233.9 238.1 87.0 146.0 188.0 9.5 869.3 2015 234.5 217.5 89.0 157.0 192.0 10.4 867.8 2020 238.1 226.0 92.0 167.0 197.0 10.4 896.3 2025 242.2 234.3 96.0 178.0 202.0 10.4 927.5 2030 246.9 242.8 100.0 188.0 207.0 10.4 959.0 2035 251.6 251.5 104.0 199.0 212.1 10.4 991.2 2040 256.3 260.3 108.1 210.4 217.2 10.4 1,024.1 2045 261.1 269.2 112.3 222.1 222.5 10.4 1,057.7 2050 265.9 278.4 116.5 234.2 227.7 10.4 1,092.0 2055 270.7 287.7 120.9 246.8 233.1 10.4 1,127.1 2060 275.7 297.3 125.4 259.7 238.5 10.4 1,163.0 Table 6-2 GRETC's Summer Peak Load Forecast for Evaluation (MW) 2011 -2060 Summer Peak Demand (MW) Year CEA GVEA HEA MEA ML&P SES GRETC 2011 160.6 191.4 75.1 91.1 167.2 10.0 668.0 2015 161.3 174.8 76.8 95.5 170.8 11.0 666.8 2020 163.4 181.6 79.4 95.0 175.2 11.0 688.7 2025 166.3 188.3 82.8 99.9 179.7 11.0 712.7 2030 169.9 195.2 86.3 105.9 184.1 11.0 736.9 2035 173.1 202.1 89.7 112.5 188.7 -11.0 761.6 2040 176.3 209.2 93.3 119.3 193.2 11.3 786.9 2045 179.6 216.4 96.9 126.4 197.9 11.6 812.7 2050 182.9 223.8 100.5 133.7 202.6 11.9 839.1 2055 186.3 231.3 104.3 141.3 207.3 12.2 866.0 2060 189.6 238.9 108.2 149.1 212.2 12.5 893.6 Black &Veatch 6-2 February 2010 FORECAST OF ELECTRICAL SECTION 6 DEMAND AND CONSUMPTION ALASKA RIRP STUDY Table 6-3 GRETC's Annual Valley Load Forecast for Evaluation (MW) 2011 -2060 Annual Valley Demand (MW) Year CEA GVEA HEA MEA ML&P SES GRETC 2011 95.4 88.6 44.4 53.2 91.0 4.4 413.5 2015 95.8 81.0 45.5 57.2 92.9 4.8 413.7 2020 97.1 84.1 47.0 60.9 95.3 4.8 426.9 2025 98.8 87.2 49.0 64.9 97.7 4.8 441.4 2030 100.9 90.4 51.1 68.5 100.2 4.8 456.1 2035 102.8 93.6 53.1 72.6 102.6 4.8 471.1 2040 104.8 96.9 55.2 76.7 105.1 4.8 486.4 2045 106.7 100.2 $7.3 81.0 107.6 4.8 502.0 2050 108.7 103.6 59.5 85.4 110.2 4.8 517.9 2055 110.7 107.1 61.7 90.0 112.8 4.8 534.2 2060 112.7 110.7 64.0 94.7 115.4 4.8 550.9 Table 6-4 GRETC's Net Energy for Load Forecast for Evaluation (GWh) 2011 -2060 Utility Net Energy for Load Forecast (GWh) Year CEA GVEA HEA MEA ML&P SES GRETC 2011 1,302.0 }1,522.7 554.5 771.2 1,162.8 64.6 5,377.8 2015 1,311.4 |1,333.5 568.1 831.9 1,184.9 65.6 5,295.3 2020 1,334.5 |1,373.4 591.2 888.3 1,213.0 67.4 5,467.8 2025 1,359.2 |1,403.8 615.5 946.4 1,241.7 69.3 5,636.0 2030 1,384.5 |1,434.7 640.0 1,004.7 1,271.2 71.2 5,806.3 2035 1,409.9 |1,465.7 665.1 1,065.4 1,300.9 73.1 5,980.1 2040 1,435.5 |1,497.1 690.7 1,128.1 1,330.9 75.1 6,157.4 2045 1,461.4 |1,528.9 716.8 1,192.9 1,361.3 7q7A 6,338.4 2050 1,487.5 |1,561.1 743.5 1,259.9 1,392.1 79.1 6,523.2 2055 1,513.9 |1,593.6 770.8 1,329.4 1,423.2 81.1 6,712.0 2060 1,540.5 |1,626.5 798.7 1,401.4 1,454.7 83.2 6,905.0 Black &Veatch 6-3 February 2010 FORECAST OF ELECTRICAL SECTION 6 DEMAND AND CONSUMPTION ALASKA RIRP STUDY The GRETC peak demand is projected to increase at an average annual rate of 0.6 percent and average annual GRETC system energy is projected to increase at 0.5 percent. Appendix D presents the annual forecasts for winter and summer peak demand,system valley,and net energy for load. 6.4 -Significant Opportunities for Increased Loads As discussed in Section 2,a scenario representing a significant increase in load was evaluated in addition to the base case load forecast.This section evaluates some potential increases in load that could lead to the large increase in load scenario;Black &Veatch is not predicting that these additional loads will occur (such prediction is outside of the scope of this project)but,rather,offers this discussion to illustrate some of the ways that the regional load could increase significantly. 6.4.1.Plug-in Hybrid Vehicles Energy security and climate change issues are driving change in the transportation sector now more than ever. With the potential of carbon legislation and the possibility of high gasoline prices returning ,there is an increased need to consider new advanced technology vehicles that hold the promise of considerably improving fleet energy efficiency and reducing fleet carbon footprint,such as plug-in hybrid vehicles (PHEV). According to a recent study conducted by the Transportation Research Institute at University of Michigan(UMTRI)',fleet penetration of PHEVs is expected to reach 1 percent of the national market by 2015, 2 percent by 2020,and 16 percent by 2040 (Table 6-5).Since these vehicles cost a lot more than their conventional counterparts,especially in the near term,their market viability depends heavily on government subsidies and incentives.This study assumes that appropriate government policy initiatives were instituted toenablesuccessfulmarketpenetration.Market penetration estimates from an ORNL study”predict that nationwide penetration will not surpass 25 percent (Table 6-5). Table 6-5 Projected PHEV Penetration in the American Auto Market PHEV Penetration Year (%) 2015 1 2020 2 2040 16 2060 25 1 "PHEV Marketplace Penetration:An Agent Based Simulation;”Sullivan,Salmeen,and Simon;July 2009.?"Potential Impacts of Plug-in Hybrid Electric Vehicles on Regional Power Generation;”Hadley and Tsvetkova; January 2008. Black &Veatch 6-4 February 2010 FORECAST OF ELECTRICAL SECTION 6 DEMAND AND CONSUMPTION ALASKA RIRP STUDY Given that the Alaska Railbelt region had 53 percent of all vehicles in the state in 2008 (338,943)°,that theaveragedailypersonalvehicletravelintheAlaskaRailbeltareais32miles/day*,and that the averagePHEV33(a vehicle capable of running 33 miles on a single charge)requires 0.35 kWh of energy per mile? (Table 6-6),it is assumed the Alaska Railbelt region could experience an increase in annual energy as shown in Table 6-7. Table 6-6 Electric Consumption for a PHEV33 PNNL Kinter-Meyer Specific Energy Vehicle Class Requirements (kWh/mile) Compact Sedan 0.26 Mid-size Sedan 0.30 Mid-size SUV 0.38 Full-size SUV 0.46 Average 0.35 Table 6-7 Additional Annual Energy Required in the Alaska Railbelt Region from PHEVs Additional Load from Year PHEVs (MWh/year) 2015 14,736 2020 31,242 2040 327,489 2060 679,391 PHEVs can be plugged in and recharged when they are not on the road,which according to Figure 6-1 occurs in the late evening or early morning. Consistent with the previous observation,a study conducted by EPRI/NRDC assumed that 70 percent of the charging would occur "off-peak,”when electric demand is relatively low (Figure 6-2).Rate designs,such asnightrates,and time-of-use rates,could provide electric customers with incentives to utilize "off-peak”charging. >Registered vehicles in 2008,including only pickups and passenger vehicles.Division of Motor Vehicles from the Alaska Department of Administration.*From interviews to local car insurance companies conducted by NORECON.°Pacific Northwest National Laboratory (PNNL).Kinter-Meyer. Black &Veatch 6-5 February 2010 FORECAST OF ELECTRICAL SECTION 6 DEMAND AND CONSUMPTION ALASKA RIRP STUDY Figure 6-1 US Daily Driving Patterns Percent of Trips by Time of Day Time of day Midnight-tem fb FE GG 9-10 an tG-11am 11 am -noon Nocn-|pm1-2pm 2-3pn3-49n 4-5pm poem 5-6pm6-7 pm 7-3pm3-9pn9-19¢n10-11pm11-midnighi 6 12 3 45 G6 7 8 9 Percart of trips SOURCE:The 2001 Naciona Houszhold Travel Survey,dai'y trip fe, US.Cepartment of Trarspertation. Figure 6-2 PHEV Daily Charging Availability Profile ChargingFractionPrteereteete123 4 S 6&6 7 8 F 10 EL 12 13 14 15 16 17 18.19 20 2b 22 23 24 Hour of Qay Black &Veatch 6-6 February 2010 SECTION 6 FORECAST OF ELECTRICAL DEMAND AND CONSUMPTION ALASKA RIRP STUDY Table 6-8 and Figure 6-3 show how the extra load from PHEVs would likely be distributed on a typical day. This high penetration of PHEVs scenario has the potential to increase the energy requirement of the Alaska Railbelt system by as much as 9.8 percent in 2060.Figure 6-4 and Table 6-9 illustrate these impacts. This high penetration of PHEVs scenario has the potential to increase the peak demand of the Alaska Railbelt system by as much as 5.5 percent in 2060.There would also be a shift in the peak hour from the 1 8th hour to the 22nd hour of the peak day by 2060.Figure 6-5 and Table 6-10 illustrate these impacts. Table 6-8 Hourly Distribution of PHEV Load on a Typical Day Alaska Railbelt Region Hour of Charging Typical Day Hourly Load (MW)Day Fraction(%)2010 |2015 |2020 |2040 |2060 1 10 0 40 |86 |89.7 |186.1 2 10 0 4.0 |86 |89.7 |186.1 3 9 0 3.6 |7.7 |80.8 |167.5 4 6 0 2.4 {5.1 |53.8 |111.7 5 4 0 1.6 |3.4 |35.9 |74.5 6 2 0 0.8 |1.7 |17.9 |37.2 7 1 0 0.4 |09 |9.0 |18.6 8 0.5 0 0.2 |04 |4.5 |9.3 9 0.5 0 0.2}04 |4.5 |9.3 10 1.5 0 0.6 |1.3 |13.5 |27.9 11 2.5 0 1.0 |2.1 |22.4 |46.5 12 2.5 0 1.0 |2.1 |22.4 |46.5 13 2.5 0 1.0 |2.1 |22.4 |46.5 14 2.5 0 1.0 |2.1 |22.4 |46.5 15 2.5 0 1.0 |2.1 |22.4 |46.5 16 1 0 0.4 |0.9 |9.0 |18.6 17 0.5 0 0.2 |04 |4.5 9.3 18 0.5 0 0.2 |04 |45 |9.3 19 2 0 0.8 |1.7 |17.9 |37.2 20 4 0 16 |34 |35.9 |74.5 21 6 0 2.4 |5.1 |53.8 |111.7 22 9 0 3.6 |7.7 |80.8 |167.5 23 10 0 4.0 |86 |89.7 |186.1 24 10 0 4.0 |8.6 |89.7 |186.1 Total 100 0 40 |86 |897 |1,861 Black &Veatch 6-7 February 2010 FORECAST OF ELECTRICAL SECTION 6 DEMAND AND CONSUMPTION ALASKA RIRP STUDY Figure 6-3 Hourly Distribution of PHEV Load on a Typical Day -Alaska Railbelt Region 200 1 ee CeeeeyAe 160 + 2015 =-2020 --2040 --2060140TF 120 F 100 F 80 | 60 |m-----\---\-----------------------------------J---f--------a 40 +Hour of Day SS NS --- 123 45 67 8 Q 1011 12 13 14 15 16 17 18 19 20 21 22 23 24 Figure 6-4 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Energy Requirement 8,000 5 Energy (GWh)@ Alaska Railbelt GWh +9.84% OAlaska Railbelt GWh -With PHEVs +§.32% +0.28%+0.57% 2015 2020 2040 2060 Black &Veatch 6-8 February 2010 FORECAST OF ELECTRICAL SECTION 6 DEMAND AND CONSUMPTION ALASKA RIRP STUDY Table 6-9 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Energy Requirement 2015 2020 .2040 2060 Alaska Railbelt GWh 5,295 5,468 6,157 6,905 Alaska Railbelt GWh -With PHEVs 5,310 5,499 6,484 7,584 Percent Increase 0.28 0.57 5.32 9.84 Figure 6-5 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Peak Demand 1,400 Load (MW)@ Alaska Railbelt Peak Load OG Alaska Railbelt Peak Load -With PHEVs +5.46% 1,200 +1.59%rs "000 +0.02%+0.05% 800 }--4 p-----BS fe----Bo d-----4 :-- 4 600 } 400 +--f yo f-----Pe yd -----]'|f-----4 --- 4 ." 200 ---f.#0 f-----Pe f-----f ys f-----4 -- 0 L _ 2015 2020 2040 2060 Table 6-10 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Peak Demand 2015 2020 2040 2060 Alaska Railbelt Peak Load 882.70 896.30 1,024.10 1,163.00 Alaska Railbelt Peak Load -With PHEVs 882.90 896.73 1,040.36 1,226.45 Percent Increase 0.02 0.05 1.59 5.46 Peak Hour 18 18 20 22 Black &Veatch 6-9 February 2010 FORECAST OF ELECTRICAL DEMAND AND CONSUMPTION ALASKA RIRP STUDY SECTION 6 6.4.2 Electric Space and Water Heating Load Another means of significantly increasing electric demand within the region would to encourage increased penetration of electric space and water heating.ENSTAR Natural Gas is the primary supplier of natural gas within the State of Alaska along with Barrow Utilities Electric Coop and Fairbanks Natural Gas.Natural gas consumption within the State is almost evenly distributed between residential,commercial and industrial customers.The Energy Information Administration (EIA)publishes statistics on natural gas on an annual basis.Table 6-11 provides a summary of 2007 data for the state of Alaska. Table 6-11 2007 Natural Gas Consumption for the State of Alaska (Source:EIA) Residential Commercial Industrial Customers Customers Customers Natural Gas Delivered (MMcf)19,840 18,760 19,750 For purposes of this discussion,it is assumed that 100 percent of the gas consumption within the State of Alaska applies to the Railbelt region,given that an estimated 97 percent or more of natural gas is consumed within the region.According to the American Gas Association,space and water heating accounts for approximately 85 percent of the natural gas application in the New England region for residential customers. It is assumed that a similar proportion is applicable to commercial customers.The percentage of industrial consumption related to space and water heating is negligible compared to other applications and,therefore,is not included in this study.Table 6-12 contains the calculated energy and demand if all residential and commercial space and water heating requirements were met through electricity,based on a 2007 heating value of 1,005 Btu/cf,published by the EIA for the State of Alaska.The energy and demand calculations assume that natural gas space and water heating are 85 percent efficient.Peak demand is based on the residential natural gas load factor for the state of 39 percent. Table 6-12 Calculated Railbelt System Energy and Demand by Customer Type for Electric Space and Water Heating Residential Commercial Customers Customers Calculated Space and Water Heating Energy,MWh 4,222,640 3,991,324 Calculated Space and Water Heating Demand,MW 1,243 1,174 6.4.3.Economic Development Loads Another opportunity for increased loads in the Railbelt is from large new industrial loads.Black &VeatchobtainedalistofpotentialeconomicdevelopmentprojectsfromtheAlaskaIndustrialDevelopment&ExportAuthority(AIDEA)presented in Table 6-13,as well as possible areas in which they might be located.For purposes of this study,Chugach's and ML&P's service areas have been combined as the Anchorage area.Forpurposesofloadforecasting,Interior loads were assumed to be in GVEA's service area.Loads in the Kenai area were assumed as occurring in HEA's area. Black &Veatch 6-10 February 2010 FORECAST OF ELECTRICAL SECTION 6 DEMAND AND CONSUMPTION ALASKA RIRP STUDY Table 6-13 Potential Economic Development Projects Potential Project Area Location Size (MW) Ore Processing Facility Anchorage 300 Internet Server Facility Anchorage 300 Coal Mine Anchorage 50 Subtotal -Anchorage Area 650 Gold Mine Interior 150 Mine Interior 200 Subtotal -Interior 350 Nitrogen/Urea Facility Kenai 50 Total 1,050 In addition to the loads identified in Table 6-13,the Pebble Mine is another potential large load estimated to be approximately 300 MW.While it appears likely that if it is developed,it will develop on-site power,there has been some consideration that it could be supplied by the Railbelt through HEA's system.Other potential large loads could be from electric compressors for the proposed natural gas pipelines from the North Slope. Many of these compressors,however,would likely be remotely located. It appears conceivable that a 1,000 MW of new load could potentially be developed in the Railbelt within the time frame of this study.Such new load would likely require specific policies to be implemented whether if from fuel switching or large industrial loads.For the purposes of creating a load forecast for the large load scenarios,new loads of 500 MW will be added in both 2025 and 2040,with 350 MW of each addition of new load being assumed in the Anchorage area and 150 MW of the new load being assumed in the Interior.For load forecasting purposes,the new load was assumed to have a 75 percent load factor.Tables 6-14 and 6-15 present the winter peak demand and net energy for load forecasts for the large load scenarios.Annual forecasts for the large load scenario are presented in Appendix D. Black &Veatch 6-11 February 2010 FORECAST OF ELECTRICAL SECTION 6 DEMAND AND CONSUMPTION ALASKA RIRP STUDY Table 6-14 GRETC's Winter Peak Large Load Forecast for Evaluation (MW) 2011 -2060 Large Load Winter Peak Demand (MW) Year GVEA |Anchorage MEA Kenai GRETC 2011 238.1 412.2 146.0 96.3 869.3 2015 217.5 417.1 157.0 99.2 867.8 2020 226.0 425.1 167.0 102.2 896.3 2025 384.3 734.0 178.0 156.2 1,398.3 2030 392.8 744.0 188.0 160.1 1,429.5 © 2035 401.5 753.5 199.0 164.1 1,461.4 2040 $60.3 1063.2 210.4 218.5 1,975.7 2045 569.2 1072.9 222.1 222.9 2,009.3 2050 578.4 1082.8 234.2 227.4 2,043.6 2055 587.7 1092.8 246.8 232.1 2,078.8 2060 597.3 1102.9 259.7 236.8 2,114.7 Table 6-15 GRETC's Large Load Net Energy for Load Forecast for Evaluation (GWh) 2011 -2060 Utility Large Load Net Energy for Load Forecast (GWh) Year GVEA Anchorage MEA Kenai GRETC 2011 1522.7 2464.8 712 619.1 5,377.8 2015 1333.5 2496.2 831.9 633.7 5,295.3 . 2020 1373.4 2547.4 888.3 658.6 5,467.8 . 2025 2389.3 4572.0 946.4 1013.3 8,921.0 2030 2420.2 4626.7 1,004.7 1039.7 9,091.3 2035 2451.2 4681.8 1,065.4 1066.7 9,265.1 2040 3473.5 6719.2 1,128.1 1424.6 12,745.4 2045 3499.9 6764.7 1,192.9 1450.9 12,908.4 2050 3532.1 6821.6 1,259.9 1479.6 13,093.2 2055 3564.6 6879.1 1,329.4 1508.9 13,282.0 2060 3602.9 6948.0 1,401.4 1540.7 13,493.0 Black &Veatch 6-12 February 2010 FUEL AND EMISSIONS SECTION 7 ALLOWANCE PRICE PROJECTIONS ALASKA RIRP STUDY 7.0 FUEL AND EMISSIONS ALLOWANCE PRICE PROJECTIONS 7.1 Fuel Price Forecasts 7.1.1 Natural Gas Availability and Price Forecasts - 7.1.1.1 Description of Risk-Based Assessment Methodology Risk-based forecasts differ from other types of forecasts by acknowledging the element of chance in the way that multiple factors can combine to produce a range of outcomes.For example,there might be a 60 percent chance that a gas field will produce 150 million cubic feet per day (MMcf/d)in a given year but only a 20 percent chance that it will produce 200 MMcf/d.Likewise,a new gas pipeline might be 25 percent likely to begin flowing gas at 200 MMcf/d in a given year but 55 percent likely to begin flowing at 250 MMcf/d two years later.In both cases,an analysis is required to convert the best estimates of chance into a mathematical formula that will support a risk-based forecast of what the total gas supply might be in a given year if the gas field and pipeline were considered together in the range of possible outcomes. For development of the RIRP,Black &Veatch's risk-based natural gas supply forecasts employed a model that considered performance prospects of each of several prospective gas sources and their variations over the 50-year planning horizon.The model was constructed using Palisade DecisionTools Professional 5.0 software.A decision-tree architecture was employed where each gas supply node was supported by a mathematical probability distribution function that described the node's annualized performance over the 50- year period.Monte Carlo methods were used to run gas supply simulations using alternative sets of assumptions about performance of each supply node.The purpose of the model was to run "what if”types of scenarios that would provide information about the aggregate supplies of gas in a specified year.The main gas sources included production from the Cook Inlet basin,importation of LNG from outside Alaska,and delivery of gas from the Alaska North Slope to the Railbelt by means of an instate pipeline.Variations among the model runs featured different sets of assumptions about the future capacity of Cook Inlet production,including possible enhancements,as well as the timing and volume throughput of LNG imports and the instate pipeline,respectively. Model runs analyzed individual years for the decade of 2010-2019.For the years 2020-2060,model runs were made by five-year intervals (for example,2020-2024,2025-2029,etc.). In evaluating results,attention was focused on probabilities for attainment of gas supplies at three benchmark levels: e P90:Gas capacity achievable with 90%probability e P50:Gas capacity achievable with 50%probability e P10:Gas capacity achievable with 10%probability Figure 7-1 illustrates the P90,P50 and P10 metrics from an actual gas supply model simulation.Clearly,as the gas capacity goes up,the probability for attaining that capacity goes down.Although conservatism might argue for using P90 values (the lowest of the three capacities)for all planning purposes,the P50 value is a reasonable choice for two primary reasons.First,P50 is easier to intuitively reference and visualize because it always falls near the middle of the range of possibilities.Second,P50 is the metric most comparable to "average expectation”forecasts that can be made with assumptions about average performance of gas sourceswhereprobabilitiesareignored.Indeed,P50 supply was the metric chosen for the reference price forecast. Black &Veatch 7-1 February 2010 FUEL AND EMISSIONS SECTION7 .ALLOWANCE PRICE PROJECTIONS ALASKA RIRP STUDY Figure 7-1 Results of a Risk-Based Gas Supply Model Simulation for the Year 2017 COMBINED SUPPLY 266.2 312.7 |5.0%5.0%|0.030 4 2017 P50 =288.6 0.025 ; 0.020 --P10 =306.6 0.015 4 P90 =271.5 - 0.010 + 0.005 A treNE0.000 Lexum paar SQY o Oo N vrWwN Results from the risk-based model forecasts comprised gas volumes,in annualized units of MMcf/d,that served as inputs into separate price forecasts.The price forecasts employed conventional methods from energy market analysis that used the interplay of supply and demand to predict a commodity value for gas that would be delivered at the Cook Inlet as if from the historical Cook Inlet gas production.Black &Veatch developed mathematical relationships for the commodity value using historical Alaska gas supply,gas demand and gas price data published by the U.S.Energy Information Administration as well as from additional research. To that commodity value,estimated transportation costs were added for any volume of gas that was obtained from a non-local source;namely,LNG imports or the instate pipeline.Black &Veatch conducted research to estimate reasonable transportation costs.LNG costs were based on market knowledge of the Asia-Pacific Basin LNG markets.Pipeline costs were based on previously published studies of instate gas pipelines,both for stand-alone direct lines from the North Slope to the Anchorage area and for lateral lines from a large pipeline that might carry gas from the North Slope to Alberta,Canada. The final price estimate,consisting of the commodity value and transportation adders,is equivalent to a "city gate”price that would be available to a high-volume buyer such as an electric utility or a gas distribution company.As used by the U.S.Energy Information Administration,a "city gate”price is the first point of sale for gas before it enters the wholesale markets.Ownership of gas beyond the "city gate”typically changes several times before it reaches residential consumers,with price increases at each change of ownership. Therefore,"city gate”prices are substantially lower that residential retail prices.Because the price forecasts used risk-based model gas supplies as input,separate prices were associated with P90,P50 and P10 supplies, respectively. Black &Veatch 7-2 February 2010 FUEL AND EMISSIONS SECTION 7 ALLOWANCE PRICE PROJECTIONS ALASKA RIRP STUDY 7.1.1.2 Gas Stakeholder Input Process Black &Veatch conducted multiple rounds of reviews with numerous stakeholders to discuss the construction of the gas supply forecast model,as well as preliminary results for supply and price forecasts.These stakeholders included State of Alaska officials;technical specialists and executives from the Railbelt electric utilities;technical specialists and executives from Enstar;producers;and independent,Alaska-based energy consultants. The gas stakeholder meetings were conducted over a three-month period and involved four different editions of the Black &Veatch gas supply forecast model.After each round of stakeholder meetings,Black &Veatch made changes to the gas supply forecast model in response to stakeholder feedback.The fourth version of the model was used to produce the results reported in this report. 7.1.1.3 Structure of the Natural Gas Decision Tree The gas supply and price forecasts considered a variety of possibilities but utilized only those that could be supported quantitatively with the necessary degree of mathematical precision.Specifically,model attributes were separated into factors that were modeled and factors that were not modeled as summarized in Figure 7-2 and discussed below. Figure 7-2 Schematic Summary of the Probabilistic Gas Supply Forecast Model (Tres rw nem mmm nr rr eter errs eos ewes ose wenenwerosrrrsrrn ° Natural Gas Decision Tree 1 1 '7 't 'Supply-Source Supply-Management 1 Railbelt Energy':Nodes Nodes Portfolio !'r)1 'Cook Inlet i Portfolio Scenarios' !Gas Production oeyeten ;1 |e Legacy .1 |*Base Case »Re-developed (assumed sufficient)1 [*Growth Case)|«New E&P '': H .i ?Demand 1 7 '''ox Siete Regional Pipeline '* }from Distribution H Regional Gas 'System H RequirementsNorthSlope(assumed sufficient) 1'1 I LNG Imports |”' 'with Storage .' H :ge)LNG Tricked Other Raitbeit Gas Production «| 'from North ;.5 \Sf ;(inactive)a;PS «Coalbed methane a!(inactive)»Nenana Basin 7 'wee ween ewe wow eae woe ee awe were wee wane ewan wee ewe wea Black &Veatch 7-3 February 2010 FUEL AND EMISSIONS SECTION 7 ALLOWANCE PRICE PROJECTIONS ALASKA RIRP STUDY 7.1.1.4 Decision Tree Input Assumptions 7.1.1.4.1 Gas Demand Black &Veatch reviewed publicly-available data on historical consumption of natural gas in the Railbelt region and re-calculated those data into mathematical functions that were compatible with the risk-based,gas supply forecast model.Sources included the U.S.Energy Information Administration,State of Alaska and Enstar.As shown in Table 7-1,adjustments were made for the fact that traditional consumers of gas are changing as the decade of 2000-2009 gives way to the decades of 2010-2019 and forward.For example,the decade of 2000-2009 included major use of gas by the Agrium fertilizer plant and by the Nikiski LNG plant (as exports to Japan).But the Agrium fertilizer plant ceased operations in 2007 and the Nikiski LNG exports are expected to end by March 2011.So going forward,the main consumers of gas are expected to be electric- utilities,and gas pipeline users (including space heating)plus oilfield operations.Accordingly,the P90,P50 and P10 metrics for gas demand reflect a significant downturn in risk-based demand in 2010-2019 followed by slow growth in the expected use of gas for power,heating and field operations. Table 7-1 Representative Risk-Based Metrics for Railbelt Natural Gas Demand Based on Historical Data and Known Changes in Gas Consumption Annualized Gas Demand (MMcf /d) Risk-Based Demand Metric 2000-2009 2010-2019 2020-2029 P90 (90%likely that this demand will occur)415 216 "252 P50 (50%likely that this demand will occur)524 245 257 P10 (10%likely that this demand will occur)632 275 262 It should be noted that the 2006-2009 decade was one of rapid change,both in gas demand and gas production.The curve-fitting approach needed to render demand data into a probability curve,as required for the probabilistic supply forecasts,displayed large spreads in key percentages in the decadal curve as a consequence of large year-to-year changes in the historical data there were used as input. 7.1.1.4.2 Gas Supplies 7,1.1.4.2.1 Cook Inlet Gas Production Prospects included a "legacy”component based on the expected future performance of historically known, producing gas reservoirs.A "re-developed”component represented additional performance that might be possible from "legacy”reservoirs through new or re-worked gas wells.Finally,a "New E&P”component represented geoscience-based estimates of discoverable,new gas reservoirs within the greater Cook Inlet region.After consulting subject matter experts among the Railbelt gas stakeholders,and reviewingpreviouslypublishedreportsaboutgasresourcesandreserves,Black &Veatch concluded that enhanced CookInletgasproductioncouldbemadetomeetP50gasdemandthrough2016withplausibleassumptionsabout re-working and re-investment.Enhanced Cook Inlet production was retained as a source in the gas supply model through 2039 but with significant performance decline after 2017. Black &Veatch 74 February 2010 FUEL AND EMISSIONS SECTION 7 ALLOWANCE PRICE PROJECTIONS ALASKA RIRP STUDY 7.1.1.4.2.2 Instate Gas Pipeline This supply node was predicated upon construction of a pipeline to deliver gas from the Alaska North Slope (Prudhoe Bay,Point Thomson)to the Anchorage area.Prospects included a stand-alone,direct line as well as a lateral from a larger pipeline that might carry gas into Canada and the USA Lower-48 states.After consulting subject matter experts among the Railbelt gas stakeholders,and reviewing previously published reports about possible instate pipeline projects,Black &Veatch concluded that an instate pipeline was plausible after 2018 and with a maximum capacity of 350 MMcf/d.Such an instate pipeline source was included in the gas supply model with ramp-up from 2018 through 2022 and maximum capacity thereafter. No attempt was made to analyze the economics of building smaller or larger pipelines.Although published descriptions of possible pipeline projects cover the range of about 50-500 MMcf/d capacities,the limit of 350 MMcf/d was chosen as the largest capacity likely to be built given the demand outlook (Table 7-1). 7.1.1.4.2.3,LNG Imports (With Storage) This supply node was premised on bringing LNG to the Cook Inlet through ocean tankers supplied from sources within the Asia-Pacific basin.Prospects included re-engineering the Nikiski export plant to become a receiving and storage facility or building a new receiving facility with associated storage. For a re-developed (i.e.,brownfield)Nikiski facility,storage capacity would be limited to the liquid equivalent of about 2,300 MMcf of gas.Although re-developed Nikiski could provide peak deliverability of 100 MMcf/d for short durations,total storage volume translated to annualized deliverability would be only about 6 MMcf/d.Black &Veatch research found that a plausible design for a new (i.e.,greenfield)LNG facility with tank storage might increase the total available storage to a liquid equivalent of 5,700 MMcf which would have an annualized deliverability equivalent of about 15 MMcf/d.But the latter facility likely would require a capital investment at least several times that of the re-developed Nikiski facility. A new receiving facility built with associated underground geologic storage (depleted oil or gas reservoir),in principle,could be made more scalable than for tank storage based on phased expansion of storage capacity through successive re-commissioning of depleted reservoirs.Because geologic-based storage typically scales in multiples of one billion cubic feet (1 Bcf =1,000 MMcf),the two limiting factors for the Cook Inlet would be how fast depleted reservoirs could be re-developed into storage (Bcf per unit time)and what practical limits would apply to ocean tanker-based deliveries (tanker deliveries per unit time).After consulting subject matter experts among the Railbelt stakeholders,researching performance characteristics of LNG ocean tankers,and reviewing previously published reports about possible gas storage projects,Black &Veatch arrived at a plausible order of magnitude for LNG imports with associated geologic-based storage.A reasonable lower-end estimate would be five (5)deliveries per year,by a tanker with 138,000 cubic meter (liquid)capacity,and as supported by an available (working gas)storage capacity of at least 15-20 Bcf to produce the equivalent of an annualized gas supply of 42 MMcf/d.A reasonable upper-end limit would be 12 deliveries per year,by a tanker with 150,900 cubic meter (liquid)capacity,and as supported by an available (working gas)storage capacity of at least 40-45 Bcf to produce the equivalent of an annualized gas supply of 106 MMcf/d.For the gas supply model,Black &Veatch used the 41 MMcf/d capacity limit,beginning imports and ramp-up in 2013,for the base case.But alternative simulations also were made using the 106 MMcf/d capacity limit. 7.1.1.4.3 Other Considerations Regional pipeline distribution systems,and gas storage not affiliated with LNG imports,were considered not to be performance bottlenecks so they were treated as non-issues in the gas supply model (Figure 7-2).Black &Veatch interviews with stakeholders led to the conclusion that the gas pipeline distribution system,at least in the Cook Inlet region,has sufficient capacity to handle new gas supplies without requiring significant Black &Veatch 745 February 2010 FUEL AND EMISSIONS SECTION 7 ALLOWANCE PRICE PROJECTIONS ALASKA RIRP STUDY capital investments.Also,published reports on geologic gas-storage prospects identified suitable volumes of reservoirs that could,in principle,be re-commissioned before the instate pipeline appeared in 2018 and ramped-up to maximum capacity in 2022.Gas storage required for earlier imports of LNG was treated as storage implicit in the import project and scaled as discussed above. Stakeholders suggested other possible sources of gas that Black &Veatch did not include in the gas supply model for lack of the necessary quantitative supporting information.Although such sources might become viable in the future,the performance data required to model their probabilities for performance were not available either through published or unpublished sources. First,overland trucking of LNG from the North Slope to Fairbanks was proposed.Although such a supply could be significant for residential space heating,the plausible scale of such deliveries is virtually immaterial to gas-fired power plants.Specifically,a 10,000-gallon LNG tanker truck delivered five (5)times per week for every week of the year provides a gas equivalent of less than 1 MMcf/d whereas a continuously-run, 100 MW gas-fired power plant would need about 20-30 MMcf/d.So given the emphasis of the current report on power generation,overland LNG trucking was not selected as a gas source in the supply simulations. Second,gas production from Railbelt geologic sources other than Cook Inlet has not been confirmed in publicly-available reports.The Nenana Basin was mentioned specifically by several stakeholders but Black &Veatch was not able to confirm whether gas had been proven or resources estimated through ongoing exploratory drilling activities. Third,gas production from coalbed methane was mentioned by a few stakeholders who did not provide supporting data.Black &Veatch researched available reports but could not confirm plausible projects that would deliver significant amounts of gas within the same timeframe as LNG imports or an instate gas pipeline. 7.1.1.5 Natural Gas Price Forecasts Black &Veatch approached the price forecast as: Price =Commodity Value (supply,demand)+Delivery Cost using the following main premises: Metric is a single,pooled Railbelt price as if for a single,unified consumer Focus on "city gate”price that would be a proxy for fuel procurement plans by electric utilities -not retail consumer prices Commodity value estimated from historical-empirical data regressions A premium adder included for Cook Inlet enhanced production All-in delivery and storage costs for imported LNG Tariffs for instate pipeline,North Slope to Anchorage For the commodity value,Black &Veatch analyzed historical supply,demand and price data for Alaska todevelopfiveempiricalrelationships,each with an individual strength of correlation.Those five modelrelationshipswerecombinedusingweightingfactorsproportionaltothestrengthsoftherespectivecorrelation coefficients. Black &Veatch 74 February 2010 FUEL AND EMISSIONS SECTION 7 ALLOWANCE PRICE PROJECTIONS ALASKA RIRP STUDY For the delivery cost,Black &Veatch reviewed publicly-available information on LNG ocean-tanker transportation and alternative proposals for Alaska instate pipeline projects.Although LNG transportation costs are well-established,Alaska pipeline projects remain incompletely defined and,therefore,carry larger associated uncertainties.Both for LNG and instate pipeline,anticipated costs fell within the range of $1.50- $2.00/MMBtu.In addition,Black &Veatch estimated that investments to realize the postulated enhancement to Cook Inlet production would require additional costs in the range of $0.25-$1.00/MMBtu. To develop the price forecast for a given year,Black &Veatch applied the P50 supply output from the risk- based gas supply forecast to the commodity value model.Then delivery adders were applied for all of the supply sources that were presumed to be operational in that year.The result effectively was a weighted- average cost of gas involving the various gas sources. 7.1.1.6 Summary of Results Black &Veatch selected two sets of gas supply simulations to illustrate the challenges that exist in providing suitable volumes of natural gas to Railbelt users,as follows: Base Case (used for Scenario 1A in the RIRP model) e Expanded Cook Inlet production,beginning in 2012,matched P50 demand but with decline toward a supply-demand deficit beginning in 2017 and with end of production as of 2039 e LNG imports began in 2013,and ramped-up to annualized equivalent of 41 MMcf/d,before ending in 2018 (when the instate pipeline appeared) e Instate pipeline began in 2018,with ramp-up to maximum capacity of 350 MMcf/d by 2022,and continued operation thereafter ©Met anticipated P50 demand (with P90 to P50 supplies)through 2060 ¢Performance sensitivities during 2018-2024 related to uncertainties in appearance and ramp-up of the instate pipeline Sensitivity Case (for comparison and contrast with Base Case) e Expanded Cook Inlet production as in Base Case e LNG imports began in 2013,with ramp-up to annualized equivalent of 106 MMcf/d,and continuous operation thereafter e No instate pipeline was available e Failed to meet anticipated P50 gas demand after 2018 e Performance sensitivities during 2017-2024 related to uncertainties in ramp-up of LNG imports Railbelt gas price forecasts derived from the P50 supply simulated in the Base Case are shown in Figure 7-3 along with alternative forecasts for comparison.Before 2018,the Railbelt forecast resembles projections of bi-lateral contracts executed in the Cook Inlet in 2008.But the Railbelt forecasts are higher than the subject contracts because of additional costs associated with importation of non-Alaska LNG as well as enhanced Cook Inlet production.After 2018,the Railbelt forecasts trend much higher under heavy influence of the transportation costs assumed for the instate gas pipeline.It should be noted that the bi-lateral contracts referenced have terms only through 2013 and 2017,respectively,and are predicated on Cook Inlet production as the sole source of gas.Also,the prices projected from those contract terms pertain to the "base tier”or "base load”price that is the lowest price available;both contracts provide for multipliers up to 130 percent of the base price for gas sold under peak-demand conditions.Finally,the price for "LNG Delivered in Japan”is considered an upper limit for the Railbelt price,including the supply-starved Sensitivity Case. Black &Veatch 77 February 2010 FUEL AND EMISSIONS SECTION 7 ALLOWANCE PRICE PROJECTIONS ALASKA RIRP STUDY Figure 7-3 Comparison of Natural Gas Price Forecasts Relevant to Railbelt Resource Plans -o-Forecast of Railbelt Gas (purchase price for electric utility) -'Forecast of LNG Delivered in Japan -®-Projection of ConocoPhillips-ENSTAR Contract (2008,terms through 2013) -t-Projection of Marathon-ENSTAR Contract (2008,terms through 2017) -@-Armstrong (North Fork)-ENSTAR contract (2009,floor &ceiling) 14 S 124 a 1 Tr=:as='ae”D 10 4 --@-7 bn re fi no ere eee r7yoeeiain 5 2f” &!g 8F pocosessasseescEfT| &6oO 1 Po po eee 4+T T t 2010 2015 2020 2025 2030 Gas pricing in the bi-lateral sales contracts referenced in Figure 7-3 utilize formulas that reference an assortment of non-Alaska price points with various provisions for floor and ceiling pricing.For the two contracts collectively,the reference price points include Alberta,Canada;the border of British Columbia, Canada with Washington state;the Oregon-California border;northern California;southern California;and Chicago,Illinois.Therefore,the Black &Veatch projections of those contract prices are based on forecasts of annualized prices at each of those reference price points. Black &Veatch used conventional market analysis methods to correlate historical prices at reference price points with historical prices at the Henry Hub,LA price point.Based on those correlations,individual forecast models were developed for each reference price point in order to accomplish the individualized price forecast for each reference point,based on Black &Veatch selection of a forecast for Henry Hub. From the price curves depicted in Figure 7-3,representative prices are summarizedin Table 7-2.For reasons discussed above,the Railbelt forecast prices fall between the Cook Inlet bi-lateral contracts from 2008 and the anticipated forward price in Japan. The "Forecast of Railbelt Gas”curve is the price corresponding to the P50 supply output from the Base Case described above.Projections for the ConocoPhillips and Marathon contracts were made by Black &Veatch using the price terms in the 2008 contracts which end in 2013 and 2017,respectively. Black &Veatch 78 February 2010 FUEL AND EMISSIONS SECTION 7 ALLOWANCE PRICE PROJECTIONS ALASKA RIRP STUDY Table 7-2 Representative Forecasts of Railbelt Natural Gas Price According to Different Benchmarks Natural Gas "City Gate”Price (SUS /MMBtu) as Delivered at Cook Inlet AK (unless noted otherwise) Price Reference 2011 2013 2015 2017 2019 2021 2023 LNG Delivered in Japan 8.02 9.61 10.89 11.69 |12.25 12.54 12.74 Forecast for Railbelt 6.30 7.12 7.70 8.08 9.03 11.21 12.43 Projection of ConocoPhillips-5.97 6.29 N/A N/A N/A N/A N/A Enstar Contract (Base Tier) Projection of Marathon-Enstar 6.29 6.63 7.00 7.49 N/A N/A N/A Contract (Base Load) The main conclusions from these gas supply analyses are as follows: e There are plausible scenarios for long-term supplies of natural gas in the Alaska Railbelt but they will require new capital investments that include enhanced production from the Cook Inlet,as well as importation of LNG from non-Alaska sources and or North Slope gas through an instate pipeline. e LNG imports are a useful supplement to Cook Inlet production but are not likely to supplant the higher capacity provided by an instate pipeline. e Both LNG imports and instate gas pipeline supplies will be more costly than historical production from the Cook Inlet and will necessitate significantly higher gas prices than in historical experience. 7.1.2 Methodology for Other Fuel Price Forecasts 7.1.2.1 Coal The price forecast for the RIRP study represents the EIA AEO2009!delivered industrial price (dollars per short ton)but with an energy conversion factor of 20.169 MMBtu/ton and with the low end of possible transportation costs.The energy conversion factor was chosen to resemble available assays of Alaska coal. In addition to the delivered price of coal,a minemouth coal price estimate was developed for the Healy plant and for a coal sensitivity analysis.The minemouth price is based on the delivered price less an estimate for delivery costs. 7.1.2.2 HAGO High Atmospheric Gas Oil (HAGO)was treated as materially equivalent to a sub-grade of Fuel Oil No.4. The price forecast adopted here represents a 75 percent multiplier applied to the ELA AEO2009*forecast for distillate fuel oil delivered for electric power and using an energy conversion factor of 0.139 MMBtu/gallon. 'EIA AEO2009.U.S.Energy Information Administration,Annual Energy Outlook 2009,March 2009.Available online at http://Awww.eia.doe.gov/oiaf/aeo/index.html. ?EIA AEO2009 (previously referenced). Black &Veatch 79 February 2010 FUEL AND EMISSIONS SECTION 7 ALLOWANCE PRICE PROJECTIONS ALASKA RIRP STUDY 7.1.2.3 Naphtha Naphtha was treated as materially equivalent to a sub-grade of jet fuel.The price forecast adopted hererepresentsa75percentmultiplierappliedtotheELAAEO2009°forecast for jet fuel delivered for aviation and using an energy conversion factor of 0.139 MMBtu/gallon. 7.1.2.4 Propane Propane is not currently used as a fuel for electric power generation in the Railbelt region.However,in response to a stakeholder request,propane was added for comparison as an alternative fuel.The price forecast reported here utilized an historical-empirical relationship developed for propane and natural gas in the Lower-48 states as applied to the natural gas price predicted for the Railbelt. 7.1.3 Resulting Fuel Price Forecasts Table 7-3 summarizes the resulting annualized prices predicted for hydrocarbon fuels from 2011 to 2060. Although seasonal variation of price can be expected to occur in response to demand swings,the prices represented here reflect a single average price for a given year. 7.2 Emission Allowance Price Projections 7.2.1 Existing Legislation Currently,there is no existing legislation in place that subjects electric generating units in Alaska to an emission allowance trading program for NO,,SO2,CO,or Hg emissions.As a result,no emission allowance costs are included in the economic evaluations other than for CO as discussed in the next subsection.Capital and operating costs are included for generating units in order for the units to meet expected emission limitations under the Environmental Protection Agency's Prevention of Significant Deterioration Program. 7.2.2 Proposed Legislation Currently,there is no proposed federal or state legislation that would subject electric generating units in Alaska to an emission allowance trading program for NO,,SO,or Hg.There have been a number of bills introduced in the U.S.Congress that would create an emission allowance trading program and corresponding emission reductions for CO,.The only bill that has passed either House of Congress is H.R.2454,the American Clean Energy and Security Act of 2009 (ACESA),which was passed in the House of Representatives in 2009.While it is unknown if H.R.2454 will ultimately be passed into law,after vetting the issue with numerous stakeholders in the RIRP process,it was decided that CO,allowance costs would be included in the economic evaluations for the RIRP.The development of those allowance costs is presented in the following subsection. 7.2.3 Development of CO,Emission Price Projection The CO,emission price projection used in this analysis is based upon price projections developed by the Energy Information Administration (EIA)and by the Environmental Protection Agency (EPA).The base price projection is presented in EIA report number SR-OJAF/2009-05,entitled Energy Market and Economic Impacts ofH.R.2454,the American Clean Energy and Security Act of 2009 (ACESA),dated August 4,2009. The EIA report considered the energy-related provisions in ACESA that could be analyzed using EIA'sNationalEnergyModelingSystem.The ACESA basic case was used for the CO,emission price projection for the years 2012 through 2030. 3 EIA AEO2009 (previously referenced). Black &Veatch 7-10 February 2010 FUEL AND EMISSIONS SECTION 7 ALLOWANCE PRICE PROJECTIONS ALASKA RIRP STUDY Table 7-3 Nominal Fuel Price Forecasts ($/MMBtu) Year j Natural Gas |Delivered Coal |Minemouth Coal |HAGO |Naphtha Propane 2011 6.30 2.94 2.18 12.98 13.77 9.05 2012 6.62 2.99 2.21 14,52 15.24 9.45 2013 7.12 3.02 2.24 15.26 16.16 10.08 2014 7.42 3.08 2.28 16.31 17.24 10.46 2015 7.70 3.19 2.36 17.23 18.11 10.81 2016 8.05 3.23 2.39 17.79 18.71 11.25 2017 8.08 3.29 2.44 18.23 19.25 11.29 2018 8.25 3.36 2.49 18.71 19.79 11.50 2019 9.03 3.43 2.54 19.29 20.45 12.49 2020 10.60 3.50 2.59 19.77 20.85 14.46 2021 11.21 3.55 2.63 20.26 21.33 15.23 2022 11.79 3.61 2.67 20.78 21.86 15.96 2023 12.43 3.67 2.72 20.98 22.09 16.76 2024 12.77 3.73 2.76 21.50 22.56 17.19 2025 13.06 3.80 2.81 21.98 23.09 17.56 2026 13.23 3.86 2.86 22.43 23.57 17.77 2027 13.30 3.93 2.91 22.98 24.03 17.86 2028 13.47 4.00 2.96 23.76 24.83 18.07 2029 13.53 4.07 3.01 24.38 25.50 18.15 2030 13.58 4.11 3.04 25.07 26.01 18.21 2031 13.72 4.24 3.14 25.82 26.79 138.39 2032 13.92 4,36 3.23 26.60 27.59 18.64 2033 14.00 4.49 3.33 27.40 28.42 18.74 2034 14.08 4.63 3.43 28.22 29,27 18.84 2035 14.21 4.77 3.53 29.07 30.15 19.00 2036 14.11 4.91 3.64 29.94 31.06 18.88 2037 13.93 5.06 3.75 30.84 31.99 18.65 2038 13.84 5.21 3.86 31.76 32.95 18.54 2039 13.59 5.37 3.98 32.72 33.93 18.22 2040 13.91 5.53 4.10 33.70 34.95 18.63 2041 13.96 5.69 4.21 34.71 36.00 18.69 Black &Veatch 7-11 February 2010 FUEL AND EMISSIONS SECTION 7 ALLOWANCE PRICE PROJECTIONS ALASKA RIRP STUDY Table 7-3 (Continued) Nominal Fuel Price Forecasts ($/MMBtu) Year |Natural Gas |Delivered Coal |Minemouth Coal |HAGO |Naphtha Propane 2042 14.17 5.86 4.34 35.75 37.08 18.95 2043 14.30 6.04 4.47 36.82 38.19 19.12 2044 14.59 6.22 4.61 37.93 39.34 19.48 2045 14.73 6.41 4.75 39.06 40.52 19.66 2046 14.94 6.60 4.89 40.24 41.73 19.92 2047 15.07 6.80 5.04 41.45 42.98 20.08 2048 15.37 7.00 5.19 42.68 44,27 20.46 2049 15.50 7.21 5.34 43.97 45.60 20.63 2050 15.64 743 5.50 45.29 46.97 20.80 2051 15.77 7.65 5.67 46.64 48.38 20.97 2052 16.08 7.88 5.84 48.05 49.83 21.36 2053 16.21 8.12 6.01 49.49 51.33 21,52 2054 16.34 8.36 6.19 50.97 52.87 21.68 2055 16.57 8.61 6.38 52.50 54.45 21.97 2056 16.80 8.87 6.57 54.08 56.09 22.26 .2057 16.93 9.14 6.77 55.70 57.77 22.43 2058 17.17 9.41 6.97 57.37 59.51 22.73 2059 17.30 9.69 7.18 39.09 61.29 22.89 2060 17.75 9.98 7.39 60.86 63.13 23.46 Black &Veatch 7-12 February 2010 FUEL AND EMISSIONS SECTION 7 ALLOWANCE PRICE PROJECTIONS ALASKA RIRP STUDY The EPA has also made an analysis of ACESA.EPA's CO,emission price projection is presented in a presentation,entitled EPA Analysis of the American Clean Energy and Security Act of2009 H.R.2454 in the 111th Congress,dated June 23,2009.The EPA report provides CO,emission prices for the years 2015, 2030,and 2050.The EPA analysis was used to develop CO,emission price projections for 2030 through 2050.Emission price projections from 2050 through 2060 were escalated at the general inflation rate of 2.5 percent annually.The CO,emission allowance price projections are presented in Table 7-4. Both the EIA and EPA analyses of H.R 2454 consider the development and deployment of carbon capture and sequestration (CCS). Table 7-4 CO,Allowance Price Projections Year $/ton 2012 18.41 2020 39.70 2030 103.78 2040 213.91 2050 440.89 2060 564.38 Black &Veatch 7-13 February 2010 SECTION 8 RELIABILITY CRITERIA ALASKA RIRP STUDY 8.0 RELIABILITY CRITERIA The purpose of this section is to discuss the reliability criteria that were used in this study. 8.1 Planning Reserve Margin Requirements Currently,the Railbelt utilities maintain a 30 percent reserve margin.For planning purposes,GRETC is assumed to be required to maintain a 30 percent reserve margin.As the GRETC transmission projects are implemented and experience is gained in the Railbelt with a more robust transmission system,it may be possible to reduce the 30 percent planning reserve margin which would further increase benefits under GRETC.This potential additional savings,however,is not modeled in this study. 8.2.Operating Reserve Margin Requirements 8.2.1 Spinning Reserves Spinning reserve requirements for the Railbelt system are based on the largest unit on-line.Currently, Chugach,GVEA,HEA,and ML&P share that spinning reserve requirement in relation to their largest units on-line.Table 8-1 presents the largest unit for each of the Railbelt utilities and shows their share of the largest unit. Table 8-1 Railbelt Spinning Reserve Requirements Capacity Percentage of Spinning Reserve Utility Largest Unit (MW)Largest Unit Requirement (MW) CEA Beluga 7/8 108.6 33.6 36.9 GVEA North Pole 2 62.6 19.4 21.2 HEA Nikiski 42.0 13.0 14.3 ML&P Plant 2 Units 7/6 109.6 34.0 37.2 Total 319.5 100.0 109.6 Spinning reserve requirements vary continuously based on the largest unit operating.Throughout the studyperiod,the spinning reserve requirements increase when new units become the largest unit on the system. Generally,any unit operating below its maximum load can contribute to the spinning reserve requirement.In addition,Bradley Lake can provide up to 27 MW of spinning reserves as shown in Table 4-5. GVEA also has a Battery Energy Storage System (BESS)which provides 27 MW of equivalent spinning reserves.GVEA currently employs Shed in Lieu of Spin (SILOS)for a portion of GVEA's spinning reserve responsibility.In this RIRP,SILOS is not considered for spinning reserve. Black &Veatch 8-1 February 2010 SECTION 8 RELIABILITY CRITERIA ALASKA RIRP STUDY 8.2.2 Non-Spinning Operating Reserves The Railbelt currently requires total operating reserves to be 150 percent of the spinning requirement.This results in an amount of non-spinning reserves up to 50 percent of spinning reserve capacity that may be provided by quick-start capacity in order to meet the operating reserve requirement.This non-spinning operating reserve is proportioned between the Railbelt utilities in the same proportions as spinning reserves. The units that qualify as quick-start units for meeting operating reserves are presented in Table 8-2. 8.3.Renewable Considerations Wind,solar,and tidal renewable technologies are not dispatchable;consequently,they are not counted toward planning or operating reserves. 8.4 Regulation Resources that are not dispatchable and subject to varying output due to factors that cannot be controlled such as weather (e.g.,variations in wind speed that result in variable wind power output),require additional regulating capacity in order to maintain system reliability when the wind does not blow or the sun does not shine.For evaluation purposes,it is assumed that 50 percent of the nameplate capacity of wind and solar resources will be required to be maintained as additional regulating capacity.Tidal resources,while not dispatchable,are more predictable,and for evaluation purposes,additional regulating capacity is not included. Black &Veatch 8-2 :February 2010 SECTION 8 RELIABILITY CRITERIA ALASKA RIRP STUDY Table 8-2 Quick-Start Units Winter Rating Name Unit (MW) Anchorage ML&P -Plant 1 3 32 Anchorage ML&P -Plant 1 4 34.1 Anchorage ML&P -Plant 2 5 37.4 Anchorage ML&P -Plant 2 7 81.8 Anchorage ML&P -Plant 2 8 87.6 Beluga 1 17.5 Beluga 2 17.5 Beluga 3 66.5 Beluga 5 65 Beluga 6 82 Beluga 7 82 Bemice 2 19 Bernice 3 25.5 Bernice 4 25.5 DPP 1 25.8 International 1 14 International 2 14 International 3 19 Nikiski 1 42 North Pole GT1 62.6 North Pole GT2 60.6 Zehnder GT 19.2 Zehnder GT2 19.6 Black &Veatch 8-3 February 2010 SECTION 9 CAPACITY REQUIREMENTS ALASKA RIRP STUDY 9.0 CAPACITY REQUIREMENTS When the 30 percent planning reserve criteria described in Section 8 is applied to the load forecasts presented in Section 6,the capacity requirements for the Railbelt are established.Comparing those capacity requirements to the existing generating units and their expected retirement dates results in the capacity addition requirements for the Railbelt.Figures 9-1 through 9-6 present the capacity requirements for the following cases. Figure 9-1 -Scenario 1A Capacity Requirements Without DSM/EE Figure 9-2 -Scenario 1A Capacity Requirements With DSM/EE Figure 9-3 -Scenario 2A Capacity Requirements Without DSM/EE Figure 9-4 -Scenario 2A Capacity Requirements With DSM/EE Figure 9-5 -Scenario 1A Capacity Requirements Including Committed Units Without DSM/EE Figure 9-6 -Scenario 1A Capacity Requirements Including Committed Units With DSM/EE Black &Veatch 9-1 February 2010 SECTION 9 CAPACITY REQUIREMENTS ALASKA RIRP STUDY Figure 9-1 Scenario 1A Capacity Requirements Without DSM/EE 1800 1600 1400 4200 1000 (MW)800 600 400 200 Load -8-30%Reserves "#-Existing Generation Capacity | Black &Veatch 9-2 February 2010 SECTION 9 CAPACITY REQUIREMENTS ALASKA RIRP STUDY Figure 9-2 Scenario 1A Capacity Requirements With DSM/EE 1800 1600 1400 1200 {AN e's1000\ente s \- A 2 orn"800 t "n°Nasa400 200 Se SS OtEttptty 2011 2018 2025 2032 2039 2046 2053 2060 Year --@ DSM Adjusted Load l=30%Reserves t=Existing Generation Capacity Black &Veatch 9-3 February 2010 SECTION 9 CAPACITY REQUIREMENTS ALASKA RIRP STUDY Figure 9-3 Scenario 2A Capacity Requirements Without DSM/EE 3000.0 2500.0 2000.0 (MW)aa 500.0 a a en) Year {=e=Load under Large Load Scenario @"30%Reserves under Large Load Scenario ir-Existing Generation Capacity | Black &Veatch 94 February 2010 SECTION 9 CAPACITY REQUIREMENTS ALASKA RIRP STUDY Figure 9-4 Scenario 2A Capacity Requirements With DSM/EE 3000 2500 -peceseeneeseees °-_ =1500 --f 1000 tr i;iene ee _ 1°an Se A See de es Ss a Dn ee ae ee ee ee 2011 2018 2025 2032 2039 2046 2053 2060 Year -*-DSM Adjusted Load under Large Load Scenario l=30%Reserves under Large Load Scenario t=Existing Generation Capacity Black &Veatch 9-5 February 2010 SECTION 9 CAPACITY REQUIREMENTS ALASKA RIRP STUDY Figure 9-5 Scenario 1A Capacity Requirements Including Committed Units Without DSM/EE 1800 -/YY41400 4200 ary 4000 \(mw)1j800 a) 600 400 200 Ceeaaaeeee 2011 2018 2025 2032 2039 2046 2053 2060 Year -eLoad -t-30%Reserves -t-Existing and CommittedGeneration Capacity 946 February 2010Black&Veatch SECTION 9 CAPACITY REQUIREMENTS 1800 1600 1400 1200 4000 (MW)800 600 400 200 ALASKA RIRP STUDY Figure 9-6 Scenario 1A Capacity Requirements Including Committed Units With DSM/EE iaeeSSGOSeeeeneeeeeeee) [=DSM Adjusted Load -f-30%Reserves t=Existing and CommittedGeneration Capacity Black &Veatch 9-7 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY 10.0 SUPPLY-SIDE OPTIONS The purpose of this section is to summarize the input assumptions that Black &Veatch used related to the various supply-side resource options considered in the RIRP study.Information is provided for both conventional technologies and renewable resources. 10.1 Conventional Technologies 10.1.1.Introduction This subsection describes and characterizes various conventional supply-side technologies including General Electric (GE)LM6000 and LMS100 simple cycle units,GE 6FA combined cycle units and a 130 MW pulverized coal (PC)facility.In addition to greenfield developments,the option of repowering Beluga Unit 8 has been considered. 10.1.2 Capital,and Operating and Maintenance (O&M)Cost Assumptions The capital cost estimates developed in this report include both direct and indirect costs.An allowance for general owner's cost items (exclusive of escalation,financing fees,and interest during construction),as summarized in Table 10-1,has been accounted for in the cost estimates or provided as a percentage of total costs.The capital cost estimates were developed on an engineer,procure,and construct (EPC)basis. The O&M cost estimates were derived from proprietary Black &Veatch O&M estimating tools and representative estimates for similar projects.Costs are based on vendor estimates and recommendations,and estimated performance information.The cost estimates are divided into fixed and variable O&M.Fixed O&M costs,expressed as dollars per unit of capacity per year ($/kW-yr),do not vary directly with plant power generation and consist of wages and wage-related overheads for the permanent plant staff,routine equipment maintenance and other fees.Variable O&M costs,expressed as dollars per unit of generation ($/MWh)tend to vary in near direct proportion to the output of the unit.Variable O&M include costs associated with equipment outage maintenance,utilities,chemicals,and other consumables.Fuel costs are determined separately and are not included in either fixed or variable O&M costs. 10.1.3 Generating Alternatives Assumptions 10.1.3.1 General Capital Cost AssumptionsUnlessotherwisediscussed,the following general assumptions were appliedin developing the cost and performance estimates: e The site has sufficient area available to accommodate construction activities including,but not limited to,office trailers,lay-down,and staging. All buildings will be pre-engineered unless otherwise specified. Construction power is available at the boundary of the site. The plant will not be located on wetlands nor require any other mitigation. Service and fire water will be supplied via on-site groundwater wells. Potable water will be supplied from the local water utility. Wastewater disposal will utilize local sewer systems. Costs for transmission lines and switching stations are included as part of the owner's cost. Black &Veatch 10-4 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-1 Possible Owner's Costs Project Development Site selection study Land purchase/rezoning for greenfield sites Transmission/gas pipeline right-of-way Road modifications/upgrades Demolition Environmental permitting/offsets Public relations/ecommunity development Legal assistance Provision of project management Spare Parts and Plant Equipment Combustion turbine materials,gas compressors,supplies,and parts Steam turbine materials,supplies,and parts Boiler materials,supplies,and parts Balance-of-plant equipment/tools Rolling stock Plant furnishings and supplies Plant Start-up/Construction Support Owner's site mobilization O&M staff training Initial test fluids and lubricants Initial inventory of chemicals and reagents Consumables Cost of fuel not recovered in power sales Auxiliary power purchases Acceptance testing Construction all-risk insurance Owner's Contingency Owner's Project Management Taxes/Advisory Fees/Legal Owner's uncertainty and costs pending final negotiation Unidentified project scope increases Unidentified project requirements Costs pending final agreements (e.g.,interconnection contract costs) Preparation of bid documents and the selection of contractors and suppliers Performance of engineering due diligence Provision of personnel for site construction management Utility Interconnections Taxes Market and environmental consultants Owner's legal expenses Interconnect agreements Contracts (procurement and construction) Property Financing (included in fixed charge rate,but not in direct capital cost) Natural gas service Gas system upgrades Electrical transmission Water supply Wastewater/sewer Financial advisor,lender's legal,market analyst,and engineer Loan administration and commitment fees Debt service reserve fund Black &Veatch 10-2 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY 10.1.3.2 Combustion Turbine Capital Cost Assumptions Combustion turbines will be fueled with natural gas as the primary fuel with an option provided for dual fuel with No.2 ultra-low sulfur diesel (ULSD)fuel oil as the backup fuel.The cost of fuel unloading and delivery to the site(s)is included. The LM6000 and the LMS100 will utilize water injection for primary NO,control when operating on fuel oil.The 6FA configurations will utilize dry low NO,burners when operating on natural gas and water injection when operating on fuel oil. All of the combustion turbine configurations will include selective catalytic reduction (SCR)and a CO catalyst. Standard sound enclosures will be included for the combustion turbines. Natural gas pressure is assumed to be adequate for the LM6000 and the combined cycle alternatives. Gas compressors will be included for the LMS100 combustion turbine.A regulating and metering station is assumed to be part of the owner's cost for each alternative. Demineralized water will be provided via portable demineralizers for simple cycle alternatives and will be supplied by a demineralized water treatment system for the combined cycle options. Both of the combustion turbine combined cycle configurations will utilize air cooled condensers for heat rejection. None of the combustion turbine configurations will utilize inlet cooling. Field erected storage tanks include the following: o Service/fire water storage tank. o Fuel oil storage tank (3 days storage capacity). o Demineralized water storage tank (3 days storage capacity). 10.1.3.3 Coal Facility Capital Cost Assumptions The PC plant will be equipped with an SCR for NO,control,an activated carbon injection system for mercury reduction,a dry flue gas desulfurization unit for sulfur reduction and a fabric filter system for managing particulate emissions. The subcritical PC plant will utilize an air cooled condenser for heat rejection. 10.1.3.4 Direct Cost Assumptions Total direct capital costs are expressed in 2009 dollars. Direct costs include the costs associated with the purchase of equipment,erection,and contractors' services. Construction costs are based on an EPC contracting philosophy. Spare parts for start-up are included.Initial inventory of spare parts for use during operation is included in the owner's costs. Permitting and licensing are included in the owner's costs. 10.1.3.5 Indirect Cost Assumptions General indirect costs,including all necessary services required for checkout,testing,and commissioning. Insurance,including builder's risk,general liability,and liability insurance for equipment and tools. Engineering and related services. Field construction management services including field management staff with supporting staff personnel,field contract administration,field inspection and quality assurance,and project control. Black &Veatch 10-3 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Technical direction and management of start-up and testing,cleanup expense for the portion not included in the direct cost constructiori contracts,safety and medical services,guards and other security services,insurance premiums,and performance bonds. Contractor's contingency and profit. Transportation costs for delivery to the jobsite. Start-up and commissioning spare parts. Allowance for funds used during construction and financing fees will be accounted for separately as part of the economic evaluations and,therefore,are not included in the capital cost or owner's cost estimates. 10.1.3.6 Combustion Turbine O&M Cost Assumptions O&M cost estimates are provided based on an assumed capacity factor of 75 percent. Simple cycle units are assumed to start 200 times per year. Combined cycle units are assumed to start 50 times per year. Location was considered to be a greenfield site. Plant staff wage rates are based on an operator rate of $93,200 per year. Burden rate is 56 percent. Staff supplies and materials are estimated to be 5 percent of staff salary. Estimated employee training cost and incentive pay/bonuses are included. Routine maintenance costs are estimated based on Black &Veatch experience and manufacturer input. Contract services include costs for services not directly related to power production. Insurance and property taxes are not included. The variable O&M analysis is based on a repeating maintenance schedule over the life of the plant. Variable O&M costs are estimated through at least one major overhaul. Combustion turbine combustion inspections,hot gas path inspections,and major overhauls are based on Original Equipment Manufacturer (OEM)pricing and recommendations. Steam turbine,generator,heat recovery steam generator and other balance of plant maintenance costs are based on Black &Veatch experience and vendor data and recommendations. SCR was included for NO,control for the simple cycle and combined cycle equipment. SCR uses 19 percent aqueous ammonia.Aqueous ammonia cost was estimated at $250/wet ton. Costs associated with a CO catalyst are included. Raw water costs are $0.77 per 1,000 gallons. Water treatment costs are included for water make-up and demineralized water where needed. Demineralized water treatment costs are $3.00 per 1,000 gallons. Station net capacity output is based on fired operation (duct burners)at annual average ambient conditions. The O&M analysis was completed in 2009 dollars. 10.1.3.7 Coal Facility O&M Cost Assumptions Fuel is pulverized coal. Net plant heat rate is 9,698 Btu/k Wh. O&M cost estimates are based on an assumed gross capacity factor of 75 percent. O&M cost estimates assume the unit will start 50 times per year. Location was considered to be a greenfield site. Plant staff wage rates are based on an operator rate of $93,200 per year. Black &Veatch 10-4 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Burden rate was 56 percent. Staff supplies and material are estimated to be 5 percent of staff salary. Estimated employee training cost and incentive pay/bonuses are included. Routine maintenance costs are estimated based on Black &Veatch experience and manufacturer input. Contract services include costs for services not directly related to power production. Insurance and property taxes are not included. The variable O&M analysis is based on a repeating maintenance schedule over the life of the plant. Variable O&M costs are estimated through at least one major overhaul. Steam turbine,generator,boiler and other balance of plant maintenance costs are based on Black & Veatch experience and vendor data and recommendations. SCR is included for NO,control. SCR uses anhydrous ammonia with an estimated cost of $800/wet ton. Powdered activated carbon is included for mercury control. Activated carbon costs are estimated to be $1,600/ton. Dry Flue Gas Desulfurization (FGD)is used for SO,control. Dry FGD uses lime with an estimated cost of $75/ton. A fabric filter system is included for particulate control. Raw water costs are $0.77 per 1,000 gallons. Water treatment costs are included for cycle make-up and service water where needed. Cycle make-up water treatment costs are $5.00 per 1,000 gallons. The O&M analysis was completed in 2009 dollars. 10.1.4 Conventional Technology Options The conventional technology supply-side options are discussed in this section.In addition to a general description,a summary of projected performance,emissions,capital costs,O&M costs,construction schedules,scheduled maintenance requirements,and forced outage rates have been developed for each option. The conventional technologies considered include simple cycle combustion turbines,combined cycle configurations and a PC coal generating plant. Although the combustion turbines and the combined cycle alternatives discussed herein assume a specific manufacturer and specific models (e.g.,aeroderivative and frame combustion turbines),doing so is not intended to limit the alternatives considered solely to these models.Rather,such assumptions were made to provide indicative output and performance data.Several manufacturers offer similar generating technologies with similar attributes,and the performance data presented in this analysis should be considered indicative of comparable technologies across a wide array of manufacturers. Power plant output and heat rate performance will degrade with hours of operation due to factors such as blade wear,erosion,corrosion,and increased tube leakage.Periodic maintenance and overhauls can recover much,but not all,of the degraded performance when compared to the unit's new and clean performance.The average degradation over the unit's operating life that cannot be recovered is referred to herein as nonrecoverable degradation,and estimates have been developed by Black &Veatch to capture its impacts. Nonrecoverable degradation will vary from unit to unit,so technology-specific nonrecoverable output and heat rate factors have been developed and are presented in Table 10-2.The degradation percentages are applied one time to the new and clean performance data,and reflect average lifetime aggregate nonrecoverable degradation. Black &Veatch 10-5 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-2 Nonrecoverable Degradation Factors Degradation Factor Unit Description Output (%)Heat Rate (%) GE LM6000 Simple Cycle 3.2 1.75 GE LMS100 Simple Cycle 3.2 1.75 GE 1x1 6FA Combined Cycle 2.7 1.50 GE 2x1 6FA Combined Cycle 2.7 1.50 10.1.4.1 Simple Cycle Combustion Turbine Alternatives Combustion turbine generators (CTGs)are sophisticated power generating machines that operate according to the Brayton thermodynamic power cycle.A simple cycle combustion turbine generates power by compressing ambient air and then heating the pressurized air to approximately 2,000°F or more,by burning oil or natural gas,with the hot gases then expanding through a turbine.The turbine drives both the compressor and an electric generator.A typical combustion turbine would convert 30 to 35 percent of the fuel to electric power.A substantial portion of the fuel energy is wasted in the form of hot (typically 900°F to 1,100°F)gases exiting the turbine exhaust.When the combustion turbine is used to generate power and no energy is captured and utilized from the hot exhaust gases,the power cycle is referred to as a "simple cycle” power plant. Combustion turbines are mass flow devices,and their performance changes with changes in the ambient conditions at which the unit operates.Generally speaking,as temperatures increase,combustion turbine output and efficiency decrease due to the lower density of the air.To lessen the impact of this negative characteristic,most of the newer combustion turbine-based power plants often include inlet air cooling systems to boost plant performance at higher ambient temperatures, Combustion turbine pollutant emission rates are typically higher on a part per million (ppm)basis at part load operation than at full load.This limitation has an effect on how much plant output can be decreased without exceeding pollutant emissions limits.In general,combustion turbines can operate at a minimum load of about 50 percent of the unit's full load capacity while maintaining emission levels within required limits. Advantages of simple cycle combustion turbine projects include low capital costs,short design and construction schedules,and the availability of units across a wide range of capacity.Combustion turbine technology also provides rapid start-up and modularity for ease of maintenance. The primary drawback of combustion turbines is that,due to the cost of natural gas and fuel oil,the variable cost per MWh of operation is high compared to other conventional technologies.As a result,simple cycle combustion turbines are often the technology of choice for meeting peak loads in the power industry,but are not usually economical for baseload or intermediate service. Black &Veatch 10-6 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY GE LM6000PC Combustion Turbine The GE LM6000PC was selected as a potential simple cycle alternative due to its modular design,efficiency, and size.It is a two-shaft gas turbine engine derived from the core of the CF6-80C2,GE's high thrust,high efficiency aircraft engine. The LM6000 consists of a five-stage low-pressure compressor (LPC),a 14-stage variable geometry high- pressure compressor (HPC),an annular combustor,a two-stage air-cooled high-pressure turbine (HPT),a five-stage low-pressure turbine (LPT),and an accessory drive gearbox.The LM6000 has two concentric rotor shafts,with the LPC and LPT assembled on one shaft,forming the LP rotor.The HPC and HPT are assembled on the other shaft,forming the HP rotor. The LM6000 uses the LPT to power the output shaft.The LM6000 design permits direct-coupling to 3,600 revolutions per minute (rpm)generators for 60 hertz (Hz)power generation.The gas turbine drives its generator througha flexible,dry type coupling connected to the front,or "cold,”end of the LPC shaft.The LM6000 gas turbine generator set has the following attributes: ¢Full power in approximately 10 minutes Cycling or peaking operation Synchronous condenser capability Compact,modular design More than 5 million operating hours More than 450 turbines sold Dual fuel capability The capital cost estimate was based on utilizing GE's Next-Gen package for the LM6000.This package includes more factory assembly,resulting in less construction time.Table 10-3 presents the operating characteristics of the LM6000 combustion turbine.Water injection and high temperature SCR would be used to control NO,to 3 ppmvd while operating on natural gas and on ULSD.Table 10-4 presents estimated emissions for the LM6000. GE LMS100 Combustion Turbine The LMS100 is a newer GE unit and has the disadvantage of not having as much commercial experience.As the LMS100 gains commercial acceptance,it will likely replace the use of two-unit blocks of LM6000s in the future. The LMS100 is currently the most efficient simple cycle gas turbine in the world.In simple cycle mode,the LMS100 has an approximate efficiency of 46 percent,which is 10 percent greater than the LM6000.It has a high part-load efficiency,cycling capability (without increased maintenance cost),better performance at high ambient temperatures,modular design (minimizing maintenance costs),the ability to achieve full power from a cold start in 10 minutes,and is expected to have high availability,though this availability must be commercially demonstrated through additional LMS100 experience. The LMS100 is an aeroderivative turbine and has many of the same characteristics of the LM6000.The former uses off-engine intercooling within the turbine's compressor section to increase its efficiency.The process of cooling the air optimizes the performance of the turbine and increases output efficiency.At 50 percent turndown,the part-load efficiency of the LMS100 is 40 percent,which is a greater efficiency than most simple cycle combustion turbines at full load. Black &Veatch 10-7 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-3 GE LM6000 PC Combustion Turbine Characteristics Net Capacity Net Plant Heat Rate Ambient Condition (Mw)?(Btu/kWh,HHV)"” Winter (-10°F and 100%RH)(Full Load)46.6 9,636 Winter (15°F and 68%RH)(Full Load)47.5 9,662 Winter (15°F and 68%RH)(75%Load)35.5 10,313 Winter (15°F and 68%RH)(50%Load)23.5 11,791 Average (30°F and 68%RH)(Full Load)47.6 9,741 Average (30°F and 68%RH)(75%Load)35.6 10,365 Average (30°F and 68%RH)(50%Load)23.6 11,828 Summer (59°F and 68%RH)(Full Load)39.9 10,058 RH =Relative humidity. Net capacity and net plant heat rate include degradation factors.Net capacity and heat rate assume operation on natural gas. Table 10-4 GE LM6000 PC Estimated Emissions” NO,,ppmvd at 15%O, NO,,lb/MBtu SO,,lb/MBtu CO»,Ib/MBtu CO,ppmvd at 15%O, and CO catalyst. Emissions are at full load at 30°F,reflect operation on natural gas,and include the effects of SCR,water injection Black &Veatch 10-8 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY There are two main differences between the LM6000 and the LMS100.The LMS100 cools the compressor air after the first stage of compression with an external heat exchanger and unlike the LM6000,which has an HPT and a power turbine,the LMS100 has an additional IPT to increase output efficiency. As a packaged unit,the LMS100 consists of a 6FA turbine compressor,which outputs compressed air to the intercooling system.The intercooling system cools the air,which is then compressed in a second compressor to a high pressure,heated with combusted fuel,and then used to drive the two-stage IP/HP turbine described above.The exhaust stream is then used to drive a five-stage power turbine.Exhaust gases are at a temperature of less than 800°F,which allows the use of a standard SCR system for NO,control. Table 10-5 presents the operating characteristics of the LMS100 combustion turbine.Standard SCR will be used to control NO,to 3 ppmvd while operating on natural gas.Water injection and SCR will be used to control NO,while operating on ULSD.Table 10-6 presents estimated emissions for the LMS100. 10.1.4.2 Combined Cycle Alternatives Combined cycle power plants use one or more CTGs and one or more steam turbine generators to produce energy.Combined cycle power plants operate according to a combination of both the Brayton and Rankine thermodynamic power cycles.High pressure (HP)steam is produced when the hot exhaust gas from the CTG is passed through a heat recovery steam generator (HRSG).The HP steam is then expanded through a steam turbine,which spins an electric generator. Combined cycle configurations have several advantages over simple cycle combustion turbines.Advantages include increased efficiency and potentially greater operating flexibility if duct burners are used. Disadvantages of combined cycles relative to simple cycles include a small reduction in plant reliability and an increase in the overall staffing and maintenance requirements due to added plant complexity. 1x1 GE 6FA Combined Cycle Alternative The 1x1 combined cycle generating unit would include one GE 6FA CTG,one HRSG,one steam turbine generator,and an air cooled condenser.The combined cycle unit will be dual-fueled,with natural gas as the primary fuel and ULSD as the backup fuel. The GE 6FA heavy-duty gas turbine is an aerodynamic scale of the GE 7FA.In the development of the turbine GE scaled a proven advanced-technology design and combined it with advanced aircraft engine cooling and sealing technology.The 6FA fleet has over two million operating hours logged with more than 100 units installed or on order.The 6FA gas turbine configuration includes an 18-stage compressor,six combustion chambers and a three-stage turbine.The shaft is supported on two bearings.The combustion system standard offering includes dry low NO,burners capable of multi-fuel applications. The HRSG will convert waste heat from the combustion turbine exhaust to steam for use in driving the steam turbine generator.The HRSG is expected to be a natural circulation,three pressure,reheat unit.Thecombinedcyclealternativewillbedesignedforsupplementalductfiring(on natural gas only).Supplementalfiringnecessitatesalargersteamturbineandchangestootherplantcomponents,leading to an increase intotalcapitalcostandadecreaseinplantefficiencyinordertorealizetheadditionaloutput.SCR and dry low-NO,,burners will be included to control NO,to 3 ppmvd while burning natural gas,and a CO catalyst will be included to reduce emissions.Water injection will be used for NO,control when burning ULSD. Black &Veatch 10-9 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-5 GE LMS100 Combustion Turbine Characteristics Net Capacity Net Plant Heat Rate Ambient Condition (Mw)?(Btu/kWh,HHV)"” Winter (-10°F and 100%RH)(Full Load)95.3 8,894 Winter (15°F and 68%RH)(Full Load)95.5 8,925 Winter (15°F and 68%RH)(75%Load)71.4 9,445 Winter (15°F and 68%RH)(50%Load)473 10,489 Winter (15°F and 68%RH)(Min Load)35.7 11,444 Average (30°F and 68%RH)(Full Load)96.0 8,963 Average (30°F and 68%RH)(75%Load)71.8 9,456 Average (30°F and 68%RH)(50%Load)AT.6 10,501 Average (30°F and 68%RH)(Min Load)36.3 11,415 Summer (59°F and 68%RH)(Full Load)97.4 9,041 RH =Relative humidity. "Net capacity and net plant heat rate include degradation factors.Net capacity and heat rate assume operation on natural gas. Table 10-6 GE LMS100 Estimated Emissions NO,,ppmvd at 15%O,3 NO,,lb/MBtu 0.0108 SO),lb/MBtu 0.0022 CO),Ib/MBtu 115.1 CO,ppmvd at 15%O,3 "Emissions are at full load at 30°F,and include the effects of SCR,water injection and CO catalyst. Black &Veatch 10-10 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY The steam turbine is based on a tandem-compound,single reheat condensing turbine operating at 3,600 rpm. The steam turbine will have one HP section,one intermediate-pressure (IP)section,and a two-flow low- pressure (LP)section.Turbine suppliers'standard auxiliary equipment,lubricating oil system,hydraulic oil system,and supervisory,monitoring,and control systems are included.A single synchronous generator is included,which will be direct coupled to the steam turbine. Table 10-7 presents the operating characteristics of the 1x1 GE 6FA combined cycle generating unit. Table 10-8 presents estimated emissions for the 1x1 GE 6FA combined cycle generating unit. 2x1 GE 6FA Combined Cycle Alternative The 2x1 combined cycle generating unit would include two GE 6FA CTG,two HRSGs,one steam turbine generator,and an air cooled condenser.The combined cycle unit will be dual-fueled,with natural gas as the primary fuel and ULSD as the backup fuel. The HRSG will convert waste heat from the combustion turbine exhaust to steam for use in driving the steam turbine generator.The HRSG is expected to be a natural circulation,three pressure,reheat unit.The combined cycle alternative will be designed for supplemental duct firing (on natural gas only).SCR and dry low-NO,burners will be included to control NO,to 3 ppmvd while burning natural gas,and a CO catalyst will be included to reduce emissions.Water injection will be used for NO,control when burning ULSD. The steam turbine is based on a tandem-compound,single reheat condensing turbine operating at 3,600 rpm. The steam turbine will have one HP section,one IP section,and a two-flow LP section.Turbine suppliers' standard auxiliary equipment,lubricating oil system,hydraulic oil system,and supervisory,monitoring,and control systems are included.A single synchronous generator is included,which will be direct coupled to the steam turbine. Table 10-9 presents the operating characteristics of the 2x1 GE 6FA combined cycle generating unit. Table 10-10 presents estimated emissions for the 2x1 GE 6FA combined cycle generating unit. 10.1.4.3 Coal Technologies The coal technology presented in this technology assessment includes a subcritical PC generating facility. Other coal technologies such as integrated gasification combined cycle (IGCC)or carbon capture and sequestration (CCS)could also be considered,but those technologies have not developed to a point where they have significantly penetrated the coal generation market.In addition,generating costs from these technologies generally exceed those of PC's.Therefore,this technology assessment provides estimates of the performance and cost for the PC alternative. Subcritical Pulverized Coal (PC)(130 MW) Coal is the most widely used fuel for the production of power,and most coal-burning power plants use PC boilers.PC units utilize a proven technology with a very high reliability level.These units have theadvantageofbeingabletoaccommodateasingleunitsizeofupto1,300 MW,and the economies of scale canresultinlowbusbarcosts.PC units are relatively easy to operate and maintain. Black &Veatch 10-11 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-7 GE 1x1 6FA Combined Cycle Characteristics Net Capacity Net Plant Heat Rate (Mw)?(Btu/kWh,HHV)"” Ambient Condition Fired Unfired Fired Unfired Winter (-10°F and 100%RH)(Full Load)161.3 120.8 7,814 7,581 Winter (15°F and 68%RH)(Full Load)153.7 118.1 7,770 7,307 Winter (15°F and 68%RH)(75%Load)®115.1 7,290 Winter (15°F and 68%RH)(50%Load)®76.6 8,288 Winter (15°F and 68%RH)(Min Load)”50.6 9,187 Average (30°F and 68%RH)(Full Load)®150.4 113.8 7,751 7,418 Average (30°F and 68%RH)(75%Load)112.7 7,426 Average (30°F and 68%RH)(50%Load)®75.4 8,047 Average (30°F and 68%RH)(Min Load)®48.5 9,531 Summer (59°F and 68%RH)(Full Load)143.0 110.6 7,768 7,282 RH =Relative humidity.Net capacity and net plant heat rate include degradation factors@Netcapacityandheatrateassumeoperationonnaturalgas.Part load performance percent load is based on gas turbine load point. Table 10-8 GE 1x1 6FA Combined Cycle Estimated Emissions"? NO,,ppmvd at 15%O2 3 NO,,!b/MBtu 0.0109 SO),[b/MBtu 0.0020 CO,,Ib/MBtu 115.1 CO,ppmvd at 15%O,3 Emissions are at full load at 30°F,reflect operation on natural gas, and include the effects of SCR and CO catalyst. Black &Veatch 10-12 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-9 GE 2x1 6FA Combined Cycle Characteristics Net Capacity Net Plant Heat Rate (Mw)(Btu/kWh,HHV)""” Ambient Condition Fired Unfired Fired Unfired Winter (-10°F and 100%RH)(Full Load)325.0 248.4 7,755 7,374 Winter (15°F and 68%RH)(Full Load)310.2 237.6 7,698 7,264 Winter (15°F and 68%RH)(75%Load)”229.8 7,366 Winter (15°F and 68%RH)(50%Load)®154.9 8,089 Winter (15°F and 68%RH)(Min Load)”99.4 9,335 Average (30°F and 68%RH)(Full Load)303.9 231.9 7,684 7,281 Average (30°F and 68%RH)(75%Load)227.6 7,283 Average (30°F and 68%RH)(50%Load)”151.7 7,996 Average (30°F and 68%RH)(Min Load)®99.6 9,277 Summer (59°F and 68%RH)(Full Load)289.2 222.9 7,698 7,224 RH =Relative humidity.'ONet capacity and net plant heat rate include degradation factors@Netcapacityandheatrateassumeoperationonnaturalgas.Part load performance percent load is based on gas turbine load point. Table 10-10 GE 2x1 6FA Combined Cycle Estimated Emissions” NO,,ppmvd at 15%O,3 NO,,lb/MBtu 0.0109 SO),lb/MBtu 0.0020 CO),Ib/MBtu 115.1 CO,ppmvd at 15%O,3 Emissions are at full load at 30°F,reflect operation on natural gas, and include the effects of SCR and CO catalyst. 10-13 February 2010Black&Veatch SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY New-generation PC boilers can be designed for supercritical steam pressures of 3,500 to 4,500 psig,compared to the steam pressure of 2,400 psig for conventional subcritical boilers.The increase in pressure from subcritical (2,400 psig)to supercritical (3,500 psig)generally improves the net plant heat rate by about 200 Btu/kWh (higher heating value [HHV]),assuming the same main and reheat steam temperatures and the same cycle configuration.This increase in efficiency comes at a cost,however,and the economics of the decision between subcritical and supercritical design depend on the cost of fuel,expected capacity factor of the unit,environmental factors,and the cost of capital. The subcritical PC generating unit characterized here includes a single steam turbine generator and subcritical PC boiler fueled by low-grade sub-bituminous coal.Air quality control systems include low-NO,burners, SCR for NO,control,dry FGD for SO,control,activated carbon injection for mercury control,and fabric filters for particulate control.Heat rejection is accomplished by an air cooled condenser. Table 10-11 presents the operating characteristics of the subcritical PC generating unit and Table 10-12 presents the estimated. 10.1.4.4 Conventional Technology Alternatives Capital Costs,O&M Costs,Schedule,and Maintenance Summary The estimated capital costs,O&M costs,schedules,forced outage,and maintenance assumptions for the conventional alternatives are summarized in Table 10-13.All costs are provided in 2009 dollars.The EPC cost is inclusive of engineering,procurement,construction,and indirect costs for construction of each alternative utilizing a fixed price,turnkey type contracting structure.Owner's costs were developed using the previously described assumptions,with site-specific cost additions or reductions as discussed previously.The assumed owner's cost allowance is representative of typical owner's costs,exclusive of escalation,financing fees,and interest during construction,which will be accounted for separately in the economic analyses. Owner's costs are specific to individual projects and may change from those presented in Table 10-13. Fixed and variable O&M costs are also provided in 2009 dollars.Fixed costs include labor,maintenance,and other fixed expenses excluding backup power,property taxes,and insurance.Variable costs include outage maintenance,consumables,and replacements dependent upon unit operation.Construction schedules are indicative of typical construction durations for the alternative technologies and plant sizes and represent estimated schedules from receipt of notice-to-proceed to commercial operation.Actual construction schedules will depend upon equipment delivery schedules,which are highly market driven,and therefore may be longer than those presented in Table 10-13.Actual costs may also vary from the estimates provided in Table 10-13. The annual average scheduled and forced outage assumptions for the generating alternatives are also presented in Table 10-13.The scheduled forced outages represent the average outage through a complete maintenance cycle. Black &Veatch 10-14 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA.RIRP STUDY Table 10-11 Subcritical PC Thermal Performance Estimates Net Capacity Net Plant Heat Rate Ambient Condition (Mw)?(Btu/kWh,HHV)"” Winter (-10°F and 100%RH)(Full Load)128.1 9,830 Winter (15°F and 68%RH)(Full Load)128.1 9,834 Winter (15°F and 68%RH)(75%Load)96.0 10,143 Winter (15°F and 68%RH)(50%Load)”64.0 12,030 Winter (15°F and 68%RH)(Min Load)512 12,246 Average (30°F and 68%RH)(Full Load)128.1 9,843 Average (30°F and 68%RH)(75%Load)96.0 10,109 Average (30°F and 68%RH)(50%Load)-64.0 11,734 Average (30°F and 68%RH)(Min Load)51.2 12,547 Summer (59°F and 68%RH)(Full Load)128.1 10,004 RH =Relative humidity. Net capacity and net plant heat rate include an applied 1.5%degradation factor. et capacity and heat rate assume operation on a bituminous coal and petcoke blend. Table 10-12 Subcritical PC Estimated Air Emissions? NO,,1b/MBtu 0.05 SO,,lb/MBtu ) 0.06 CO),lb/MBtu 212 CO,Ib/MBtu 0.10 PMyo,lb/MBtu 0.018 "Emissions are at full load at 30°F,reflect operation on sub- bituminous coal.All estimates are presented on the basis of HHV. Black &Veatch 10-15 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-13 Capital Costs,O&M Costs,and Schedules for the Generating Alternatives (All Costs in 2009 Dollars) Full Fixed Load Net Total O&MOwner's Capacity Cost (S/kW-Variable |Construction |Scheduled Forced EPC Cost Cost Total Cost |at 70°F (S/kW)yr)O&M Schedule Maintenan |OutageSupplyAlternative($Millions)”|($Millions)®|($Millions)|(MW)at 70°F |at 70°F |($/MWh)|(Months)ce (days)|(percent) GE LM6000 SC 49.71 12.43 62.14 49.2 1,263 64.41 3.85 21 10 2 GE LMS100 SC 100.54 25.14 125.68 99.2 1,267 32.5 3.08 24 10 2 1x1 GE 6FA CC w/Supplemental Firing 259.11 64.78 323.89 154.6 2,095 24.61 2.71 30 14 3 2x1 GE 6FA CC w/Supplemental Firing 409.20 102.30 511.50 312.3 1,638 16.12 2.61 30 14 3 130 MW sub-critical PC 688.30 206.49 894.79 130.1 6,878 100.89 2.59 62 16 5 EPC costs include SCR,CO catalyst,and dual fuel capability as applicable to each alternative.@Qwner's costs are specific to individual projects and may change from those presented.®)\Construction schedules will depend upon equipment delivery schedules,which are highly market driven,and therefore may be longer than those presented. Black &Veatch 10-16 February 2010 SECTION.10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY 10.2 Beluga Unit 8 Repowering Currently,Chugach Electric plans to retire its Beluga Generation Unit Number 8,which is the steam turbine unit at the Beluga 2x1 combined cycle facility,at the end of 2014.As an alternative to building new gas fired generation,Chugach identified an option that would include rebuilding Unit 8 and continuing to operate the Beluga Generation plant in combined cycle mode through the end of 2034.The rebuild would occur over a three year period from 2014 through 2016 with a total cost of $50 million. 10.3.GVEA North Pole 1x1 Retrofit GVEA identified an opportunity for a combined cycle retrofit at the existing North Pole combined cycle facility.The 1xi North Pole combined cycle facility was built to accommodate another 1x1 train and the steam turbine is already sized for a 2x1.The retrofit involves adding an LM6000 and a heat recovery steam generator to the existing facility.The new 1x1 combined cycle train has a maximum capacity of 64 MW and a full load heat rate of 8,270 Btu/kWh.The capital cost for the retrofit has a total cost of $83 million in 2009 dollars.The variable O&M for the unit is modeled at $2.19/MWh.Since the fixed O&M costs are already modeled in the existing North Pole combined cycle unit,they are set at $0/kW-yr for the retrofitted unit. 10.4 Renewable Energy Options 10.4.1 Hydroelectric Project Options Hydroelectric power is currently the Railbelt's largest source of renewable energy,responsible for approximately 9 percent of the Railbelt's electrical energy.Many of the State's developed hydro resources are located near communities in Southcentral,the Alaska Peninsula,and Southeast.Hydro projects include those that involve storage,both with and without dam construction,and smaller "run-of-river”projects.A number of potential hydro projects exist within or near the Railbelt region.The locations for the projects shown below represent either the service area in which the project is located or the transmission area shown in Figure 4-1 in which the project is interconnected to the Railbelt grid. e Susitna -380 -1,880 MW,MEA Glacier Fork -75 MW,MEA Chakachamna -330 MW,Chugach (Anchorage) South Fork/Eagle River --1 MW,MEA Fishhook --2 MW,MEA Grant Lake/Falls Creek -5 MW,Kenai 7 Other Small Hydro Projects in AEA's database In addition,the developers of several proposed hydro projects (each with $5 million or above estimated project cost)on the Railbelt have applied for grant requests from the AEA Renewable Energy Fund Grant Program,which was established by Alaska Legislature in 2008.Table 10-14 shows each proposed hydro project's name,applicant,estimated project cost,grant requested,funding decision and amount recommended by AEA after two rounds of ranking and funding allocations conducted by AEA. Based on review of the above information and discussion with stakeholders including the Railbelt Utilities, Black &Veatch assumed that the proposed Susitna,Chakachamna,and Glacier Fork projects will be considered as potential supply-side alternatives in this RIRP study along with a 5 MW generic hydro unit in the Kenai and a 2 MW generic hydro unit in MEA's service area.The following subsections discuss further details of these proposed projects. Black &Veatch 10-17 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-14 AEA Recommended Funding Decisions -Hydro Recommended Grant Recommended Funding Project Cost |Requested Funding Amount Project Name Applicant ($000)($000)Decision ($000) Grant Lake/Falls |Kenai Hydro,$26,924 $816 Full funding $816 Creek Hydro LLC Feasibility Study Fourth of July Independence $15,675 $7,838 Partial funding $20 Creek Hydro Power,LLC Reconnaissance Victor Creek Kenai Hydro,$19,860 $88 Full funding $88 Hydro LLC ; Glacier Fork Glacier Fork $330,000 $5,000 Partial funding $500 Hydro Hydro,LLC Archangel Creek |Archangel $6,420 $100 Not None Hydro Green Power,recommended LLC Nenana Healy GVEA $24,000 $2,200 Application None Hydro Phase II Withdrawn Note: 1.Project failed to get funding after the appropriation for Round 2 was limited to $25 million. 2.The project did not pass Stage 2 review or was excluded in Stage 3 review for geographical spreading. 10.4.1.1 Susitna Project Description of Project A hydroelectric project on the Susitna River has been studied for more than 50 years and is again being considered by the State of Alaska as a long term source of energy,In the 1980s,the project was studied extensively by the Alaska Power Authority (APA)and a license application was submitted to the Federal Energy Regulatory Commission (FERC).Developing a workable financing plan proved difficult for a project of this scale.When this existing difficulty was combined with the relatively low cost of gas-fired electricity in the Railbelt and the declining price of oil throughout the 1980s,and its resulting impacts upon the State budget,the APA terminated the project in March 1986.The project's location is shown in Figure 10-1. In 2008,the Alaska State Legislature authorized the AEA to perform an update of the project.That authorization also included this RIRP project to evaluate the ability of this project and other sources of energy to meet the long term energy demand for the Railbelt region of Alaska.Of all the hydro projects in the Railbelt region,the Susitna projects are the most advanced and best understood. Black &Veatch 10-18 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-1 Proposed Susitna Hydro Project Location (Source:HDR) eet ti CGP radh Og ]a 4 FNS gtd ,EpinBANds SFE Ge”EINEYetgue&,eh:="% a "CPt ag ,age :&of ..=bee ate |"OOF eo err7aU itymH ip arePgse .ae,«::.ci ay 7 oe .{4}!?””.;SO ae " a Black &Veatch 10-19 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY HDR was contracted by AEA to update the cost estimate,energy estimates and the project development schedule for a Susitna River hydroelectric project.The results of that study,except for the detailed appendices,are included in Appendix A (note:one of the detailed appendices in the HDR Report[Appendix D],which is not included in Appendix A of this report,addresses the issue of the potential impactofclimatechangesonSusitna's resource potential;this appendix can be viewed in the full HDR report which is available on the AEA web site). The initial alternatives reviewed were based upon the 1983 FERC license application and subsequent 1985 amendment which presented several project alternatives: e Watana.This alternative consists of the construction of a large storage reservoir on the Susitna River at the Watana site with an 885-foot-high rock fill dam and a six-unit powerhouse with a total installed capacity of 1,200 MW. e Low Watana Expandable.This alternative consists of the Watana dam constructed to a lower height of 700 feet and a four-unit powerhouse with a total installed capacity of 600 MW.This alternative contains provisions that would allow for future raising of the dam and expansion of the powerhouse. e Devil Canyon.This alternative consists of the construction of a 646-foot-high concrete dam at the Devil Canyon site with a four-unit powerhouse with a total installed capacity of 680 MW. e Watana/Devil Canyon.This alternative consists of the full-height Watana development and the Devil Canyon development as presented in the 1983 FERC license application.The two dams and powerhouses would be constructed sequentially without delays.The combined Watana/Devil Canyon development would have a total installed capacity of 1,880 MW. e Staged Watana/Devil Canyon.This alternative consists of the Watana development constructed in stages and the Devil Canyon development as presented in the 1985 FERC amendment.In stage one the Watana dam would be constructed to the lower height and the Watana powerhouse would only have four out of the six turbine generators installed,but would be constructed to the full sized powerhouse.In stage two the Devil Canyon dam and powerhouse would be constructed.In stage three the Watana dam would be raised to its full height,the existing turbines upgraded for the higher head,and the remaining two units installed.At completion,the project would have a total installed capacity of 1,880 MW. As the RIRP process defined the future Railbelt power requirement it became evident that lower cost hydroelectric project alternatives,that were a closer fit to the energy needs of the Railbelt,should be sought.As such,the following single dam configurations were also evaluated: e Low Watana Non-Expandable.This alternative consists of the Watana dam constructed to a height of 700 feet,along with a powerhouse containing four turbines with a total installed capacity of 600 MW.This alternative has no provisions for future expansion. e Lower Low Watana.This alternative consists of the Watana dam constructed to a height of 650 feet along with a powerhouse containing three turbines with a total installed capacity of 380 MW.Thisalternativehasnoprovisionsforfutureexpansion. e High Devil Canyon.This alternative consists of a roller-compacted concrete (RCC)dam constructed to a height of 810 feet,along with a powerhouse containing four turbines with a total installed capacity of 8300 MW. ¢Watana RCC.This alternative consists of a RCC Watana dam constructed to a height of 885 feet, along with a powerhouse containing six turbines with a total installed capacity of 1,200 MW. Black &Veatch 10-20 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY The results of this study are summarized in Table 10-15 and a comparison of project size versus project cost is shown in Figure 10-2. Table 10-15 Susitna Summary Schedule Firm 2008 (Years Dam Ultimate |Capacity,|Construction from Height |Capacity 98%Cost Energy Start of Alternative Dam Type (feet)(MW)(MW)($Billion)(GWh/yr)|Licensing) Lower Low Watana |Rockfill 650 380 170 $4.1 2,100 13-14 Low Watana Non-Rockfill 700 600 245 $4.5 2,600 14-15 expandable Low Watana Rockfill 700 600 245 $4.9 2,600 14-15 Expandable Watana Rockfill 885 1,200 380 $6.4 3,600 15-16 Watana RCC RCC 885 1,200 380 $6.6 3,600 15-16 Devil Canyon Concrete Arch 646 680 75 $3.6 2,700 14-15 High Devil Canyon |RCC 810 800 345 $5.4 3,900 13-14 Watana/Devil Rockfill/Concrete |885/646 1,880 710 $9.6 7,200 15-20 Canyon Arch Staged Rockfill/Concrete |885/646 1,880 710 $10.0 7,200 15-24 Watana/Devil Arch Canyon Black &Veatch 10-21 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-2 Comparison of Project Cost Versus Installed Capacity $12.0 - $10.0 =oe Watana/DevilCanyon A -$80- c 3 = 2 WatanaRCC £wotana256.0 Z A High Devil Canyon $Low Watane Expandable A Lowy Watana Non- a $4.0 LowerLlow Watana 4 expandable A Devil Canyon $2.0 $0.0 - 0 200 400 600 800 1000 1200 1400 1600 1800 2000 Installed Capacity (MW) In all cases,the ability to store water increases the firm capacity over the winter.Projects developed with dams in series allow the water to be used twice.However,because of their locations on the Susitna River,not all projects can be combined.The Devil Canyon site precludes development of the High Devil Canyon site but works well with Watana.The High Devil Canyon site precludes development of Watana but couldpotentiallybepairedwithothersiteslocatedfurtherupstream. Mode of Operation All of the alternatives identified have significant storage capability which enhances their benefits to the Railbelt Utilities.Table 10-16 presents the average annual and average monthly generation from each of the alternatives. Capital Costs The estimated capital costs for the alternative Susitna projects are presented in Table 10-15.For evaluation purposes,the capital cost for the Low Watana expansion to Watana is estimated as the difference in costs between Watana and Low Watana (Expansion)since it was not part of HDR's scope and they did not explicitly develop the cost for expansion. Black &Veatch 10-22 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-16 Average Annual Monthly Generation from Susitna Projects (MWh) Alternative Annual Jan Feb Mar Apr May Jun 'Jul Aug Sep Oct Nov Dee Lower Low Watana (non-2,006,000 127,000 116,000 127,000 117,000 101,000 208,000 270,000 28,000 256,000 153,000 123,000 |128,000expandable) Low Watana (non-2,617,000 182,000 166,000 183,000 176,000 119,000 241,000 334,000 378,000 315,000 157,000 180,000 |186,000expandable) Low Watana (expandable)2,617,000 182,000 166,000 183,000 176,000 119,000 241,000 334,000 378,000 315,000 157,000 180,000 |186,000 Watana 3,676,000 |280,000 |254,000 279,000 261,000 498,000 443,000 370,000 326,000 237,000 169,000 |275,000 |284,000 High Devil Canyon 3,891,000 |262,000 |235,000 257,000 247,000 287,000 382,000 468,000 522,000 467,000 251,000 |252,000 |261,000 Low Watana (Expansion)1,059,000 73,648 67,174 74,053 71,220 48,155 97,524 135,157 152,962 127,468 63,532 72,839 75,267 Black &Veatch 10-23 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY O&M Costs O&M costs include fixed and variable costs.Fixed O&M costs for the Susitna hydro projects vary based on the number of turbines,transformers,and dams in each specific project.A schedule and cost estimate of major maintenance items were provided by HDR through time. Schedule HDR provided development schedules for the original Susitna alternatives as shown in Table 10-15. 10.4.1.2 Chakachamna Project Description of Project TDX Power,Incorporated (TDX)is developing a hydro project on the Chakachamna River system.The proposed project will divert stream flow via a lake tap from the Chakachamna River to a powerhouse on the McArthur River via a 25 foot diameter power tunnel that will be approximately 10 miles long.The project will be located approximately 42 miles from Chugach's Beluga power generating facility.Figure 10-3 illustrates the proposed project's location.According to TDX,the proposed project will have an installed capacity of 330 MW,and will be able to generate approximately 1,600 GWh of electricity annually. Table 10-17 shows the average monthly and annual energy that will be generated by the project. Figure 10-3 Proposed Chakachamna Hydro Project Location (Source:TDX) .Par s fo f-:,-ye TE Sslia EehieMaGAaEUta3#4 re \.wr)f +ign.x (C -Fara ah oeelSeeenaeeeeeayeneeedaeeoF.th af "Pena ware hap tte reesenteeeneg .Se nn weed geod wf ot peeSan(2 CS BU eee PAZOneareedcneeyOeaeaeoeyeve,;"4 of -pr.i és 4 ' \art .dt .if 0 e eaanspeEfaalVeeG ming ; -4 ra 4 ve .oe fag?2 ie3we..3 i 8 =Pe to arias orm Ai ei Black &Veatch 10-24 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-17 Monthly Average and Annual Generation Month Generation (GWh) January 163 February 140 :March 138 | April 120 May 113 June 106 July 108 August 113 September 120 October 142 November 158 December 177 Total 1,598 | The project will not require the construction of a dam on the Chakachamna Lake,but fish gates will be installed at the outlet of the lake.The reservoir has approximately 16,700 acres of water surface at an elevation of 1,142 feet.Other facilities that will be constructed include fish passage facilities for adult migration and juvenile outmigration,a 42-mile transmission line from the project site to Chugach's Beluga substation,and site access. Mode of Operation It is expected that this project will be designed and permitted as a diverted flow type hydroelectric generating facility. Capital Costs According to TDX,the total capital cost of the proposed project will be approximately $1.6 billion in 2008 dollars or $5,100/kW in 2009 dollars.Transmission costs of $58 million are included in capital costs. O&M Costs O&M costs include fixed and variable costs.Fixed costs are independent of plant operation while variable costs are directly related to the plant operation. According to TDX,the total O&M cost for the proposed project will be approximately $10 million per year in 2008 dollars or $30/kW-Yr in 2009 dollars. For the purpose of this study,Black &Veatch assumes that the variable O&M costs will be zero,and the fixed O&M costs will be $30/kW-Yr in 2009 dollars. Black &Veatch 10-25 February 2010 SECTION 10 |SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Schedule Base on the schedule provided by TDX in their April 2009 presentation,TDX expects that the proposed hydro generating project could be available for commercial operations starting in 2017. 10.4.1.3 Glacier Fork Description of Project The proposed Glacier Fork project is a 75 MW hydroelectric project being developed by Glacier Fork Hydropower LLC on the Knik River,approximately 25 miles southeast of Palmer in the Matanuska-Susitna Borough. According to information provided by Glacier Fork Hydropower LLC,the project would consist of:1)a proposed 800-foot-long,430-foot-high dam;2)a proposed reservoir having a surface area of 390 acres and a storage capacity of 75,000 acre-feet and normal water surface elevation of 980 feet above mean low sea level (ms});3)a proposed 8,300-foot-long,12-foot diameter steel penstock;4)a proposed powerhouse containing three generating units having an installed capacity of 75 MW;5)a proposed tailrace;6)a proposed 25-mile- long,115-kilovolt transmission line;and 7)appurtenant facilities. The proposed Glacier Fork Hydroelectric Project would have an average annual generation of 330 GWh.The estimated average monthly generation is presented in Table 10-18. Table 10-18 Glacier Fork Hydroelectric Project Average Monthly Energy Generation Average Monthly Month Energy (MWh) Installed Capacity (MW)75 January 6,755 February 5,314 March 4,882 April 6,727 May 28,794 June 53,612 July 55,400 August 55,400 September 53,305 October 35,964 November 13,767 December 7,617 Annual Total (MWh)327,538 Note:Data based on USGS Gauge on Knik River. Black &Veatch 10-26 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Mode of Operation As indicated in Table 10-18,the Glacier Fork project is primarily a run-of-river project with the ability to provide firm capacity significantly reduced from its nameplate ratings during winter and spring.This reduced output during these periods was included in the Strategist®and PROMOD®modeling. Capital Costs The total capital cost of the proposed project will be approximately $4,400/kW,or $330 million,in 2009 dollars.Transmission costs are assumed to be $22.5 million (25 miles,115 kV @ $900K/mile)and are included in capital cost. Operation and Maintenance Cost . O&M costs include fixed and variable costs.Fixed costs are independent of plant operation while variable costs are directly related to the plant operation. The total O&M cost for the proposed project will be approximately $68/kW-Yr in 2009 dollars.For the purpose of this study,Black &Veatch assumed that the variable O&M costs will be zero,and the fixed O&M costs will be $68/kW-Yr in 2009 dollars. Schedule Based on information provided by Glacier Fork Hydropower LLC,the proposed hydro generating project could be available for commercial operations starting Fall 2014 at the earliest. 10.4.1.4 Generic Hydroelectric Projects Black &Veatch developed two small,generic hydroelectric project alternatives to represent several hydroelectric opportunities that have been identified in the Railbelt.The first hydroelectric project is a5 MW project located in the Kenai area.The project is assumed to have 20 GWh of average annual energy with a capital cost of $35 million in 2009 dollars.The other generic project is a2 MW project located in MEA's area.The MEA project is assumed to have an average annual energy of 7.5 GWh and a capital cost of $16 million in 2009 dollars. 10.4.2 Ocean (Tidal Wave)Project Option Alaska has a wide coastal area that allows for the consideration of renewable tidal resources.The Cook Inlet in particular offers a great potential for tidal projects since it has the fourth highest tide in the world with 25 feet (7.6m)between low tide and high tide.Also,it is located between Anchorage,Alaska's largest city,and Kenai,where a number of industries are located. Some institutions are already interested in taking advantage of this resource in this particular location and have started studies and licensing for tidal projects including the Turnagain Arm Tidal Electric Generation Project. There are several different technologies available for tidal projects.Based on Black &Veatch's review of available information,we assumed that the proposed Turnagain Arm tidal project would be representative of the technologies available,although it is Black &Veatch's opinion that tidal energy is not to the level of commercialization equivalent to other conventional and renewable alternatives considered in the RIRP.The ultimate selection of the optimal technology for Railbelt conditions will need to be based on additionalanalysis.As a result,tidal energy will be considered as a sensitivity case in the evaluations.The followingsubsectionsdiscussfurtherdetailsoftheproposedproject. Black &Veatch 10-27 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY 10.4.2.1 Turnagain Arm Description of Project Little Susitna Construction Co.and Blue Energy Canada filed an application for a preliminary FERC permit for the Turnagain Arm Tidal Project,to be developed in Cook Inlet. According to the preliminary permit application,the project calls for the use of Blue Energy's Tidal Bridge which will use the Davis Turbine to generate electricity with the movement of the tides.The Davis Turbine is a mechanical device that employs a hydrodynamic lift principle,causing vertically oriented foils to turn a shaft and a generator.Figure 10-4 shows an array of vertical-axis tidal turbines stacked and joined in series across a marine passage. Figure 10-4 Blue Energy's Tidal Bridge With Davis Turbine (Source:Blue Energy) aad r Tr New _-Tm cn a vo yy kee in 'wal p "ee °Rane |se de mov t "a!rT rr aerc:2 te.Lt Me.poe wot.-i i «ah : Black &Veatch 10-28 February 2010 SECTION 10.SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY This turbine is comprised of vertical hydrofoils attached to a central shaft transmitting torque to a generator. The kinetic energy from tidal flows can thus be harnessed and converted to electrical energy.Contrary to the traditional drag driven paddle wheel design,the Davis turbine rotor is designed to be lift driven,much like the modern wind turbines,thus allowing the blades to operate at a significantly higher efficiency.In order to further increase the efficiency of the turbine,the entire rotor assembly is housed in a thin-shell marine concrete caisson structure that channels the water flow and acts as a housing for the generator and electrical components.The shape of the caisson inner walls accelerate the velocity of the water flow through the turbine rotor by acting as a venturi and controls flow direction to provide more uniform turbine performance. In addition,the Davis turbine is designed to work through the entire tidal range with a typical cut-in speed of 1m/s.Figure 10-5 shows the configuration of a Davis tidal turbine. Figure 10-5 Cutaway Graphic of a Mid-Range-Scale Vertical Axis Tidal Turbine (Source:Blue Energy) The Turnagain Arm tidal project would be comprised of two tidal fences each eight miles long extending from Kenai to Anchorage,with minimum separation of five miles to allow the tidal force to recover its strength after going through the first fence.The tidal fence will have a service road across the top and connected to the land.Two control buildings would be required,one located near Possession Point in Kenai Borough and the other along Raspberry Road in Anchorage.They will be connected by a pair of transmission lines across the tidal fence and connect to the HEA grid on the Kenai side and to the Chugach grid on the Anchorage side.From there,the power can be moved throughout the Railbelt grid.Figure 10-6 depicts the proposed layout of the tidal plant. Black &Veatch 10-29 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-6 Proposed Layout of the Turnagain Arm Tidal Project legend A,Project Area - 8.Tidal Fences TAP ats a Control Building,Kenai Side Gan eRe0.-Contro!Building,Anchorage Side|0 .€.Transmission Line,Underwater oy F Transmission Line,On Land be 1 . . emgewe cee bt 3 bh.OT oon -3 : ,ANCHORAGE sf sem os .cove Pe wae a fio D eR.fees 1 Dot a:f",a mde :ea)we eis 3 i woe ce te ' a a foe woeSo$rm9i”onTy-he feevonekPeeeee VY "ey ,v xy3e:? a a, fo Figure4 Black &Veatch 10-30 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Mode of Operation Tidal energy while fairly predictable is very variable.Black &Veatch conducted a high level analysis of the monthly generation from the Turnagain Arm tidal project.That analysis is presented in Figure 10-7. Figure 10-7 Turnagain Arm Tidal Project Monthly Generation 10.00 3000.0 9.50 9.00 |2500.0 8.50 8.00 | 7.50 2000.0 7.00 | 6.50 il 4500.0 6.00 4 i i 5.50_5.00||1000.0 a A Pan-4.04 1 I}Ni z 2 4004 i]VERRAN ;Nh |y 5000 <---Velocity (m/s) 8 350 " $[Power (MW) 3.00 4 vated yy Wi Hy +0.0 2.50 2.00 1.50 -500.0 1.004 0.50 L -1000.0 0.00 -0.50| 100 |+-1500.0 -1.50 -2.00 +r -2000.0 0.00 100.00 200.00 300.00 400.00 _500.00 600.00 700.00 Time (hours) As discussed for the large Susitna options,the capacity of the Turnagain Arm tidal project significantly exceeds the Railbelt loads.For evaluation purposes,Black &Veatch modeled a 100 MW project with following $/kW cost. Capital Costs Capital costs of $2.5 billion in 2009 dollars for the 1,200 MW Turnagain Arm tidal project or approximately $2,100/kW are expected,including supporting infrastructure.Black &Veatch's experience with the development of similar projects indicates that the Turnagain Arm tidal project costs are significantly lowerthanotherprojectsthatBlack&Veatch has worked with.For evaluation purposes,Black &Veatch has used a capital cost of $4,200/kW. O&M Costs O&M costs include fixed and variable costs. Black &Veatch 10-31 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Fixed O&M Costs | Fixed O&M costs include labor,payroll burden,fixed routine maintenance,and administration costs.For the purpose of this study,the fixed O&M costs associated with the project are estimated to be $42 /kW-year in 2009 dollars. Variable O&M Variable O&M costs include consumables,chemicals,lubricants,major inspections,and overhauls of the turbine generators and associated equipment.Variable O&M costs vary as a function of plant generation.For the purpose of this study,Black &Veatch has assumed no Variable O&M costs for this project. Schedule Black &Veatch expects that the proposed tidal generating project will be available for commercial operations starting in 2020 at the earliest. 10.4.3.Geothermal Project Option Description of Project Ormat Technologies,Inc (Ormat)has approached the AEA for the potential development of a geothermal power plant project at Mount Spurr,which is located approximately 33 miles from Tyonek,Alaska. According to Ormat,there is the potential geothermal resource to develop a geothermal power plant project with an estimated maximum output of 50-100 MW at Mount Spurr. Depending on the specific resource conditions available at Mount Spurr,the proposed geothermal project option will likely be based on either a binary geothermal power plant configuration or a geothermal combined cycle power plant configuration. Figure 10-8 illustrates a simplified binary geothermal power plant process diagram.A geothermal fluid (brine,or steam,or a mixture of brine and steam)from an underground reservoir can be used to drive a binary plant.The geothermal fluid flows from the wellhead to heat exchangers through pipelines.The fluid is used to heat and vaporize a secondary working fluid in the heat exchangers.The secondary working fluid is typically an organic fluid with a low boiling temperature point.The generated vapors are used to drive an organic vapor turbine,which powers the generator,and then are condensed in a dry cooled or wet cooled condenser.The condensed secondary fluid is then recycled back into the heat exchangers by a pump while the geothermal fluid is re-injected into the reservoir. Figure 10-9 illustrates a simplified geothermal combined cycle power plant process diagram.A geothermal combined cycle is most effective when the available geothermal resource is mostly steam.The high-pressure steam from a separator drives a back pressure turbine.The low-pressure steam exits this turbine at a positive pressure and flows into the vaporizer.The heat of condensation of the low-pressure steam is used to vaporize a secondary working fluid and the expansion of these secondary fluid vapors drives the secondary turbine. The secondary fluid vapors are then condensed,and pumped back into the pre-heater and the geothermal fluid is re-injected into the reservoir. For the purpose of this study,Black &Veatch assumed that the proposed geothermal project can be developed in two 50 MW blocks. Black &Veatch 10-32 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-8 Simplified Binary Geothermal Power Plant Process (Source:Ormat) i aet : -: .oa Somaae]7 enemas -- Lege Sc eagtey pag tha geen,op ceetapiug'l Mpapedepeg )thew preg pcp de ree (rf2RISWERTMPSSETeeTOLPTETMeaadORMATSS Vien het Gevalia tial Thad fiewes on Her Vapeet2ee aner heny as he preecer FocaMkaiienicdids:antes)__..Productlon Watt 3 Geothermal Eid Figure 10-9 Simplified Geothermal Combined Cycle Power Plant Process (Source:Ormat) 5 sae wo be ."wetCoteRCTGeeORMATRER|SS : ST .ireyi {Geoitemmat t A weaam tweet 4Jihewedanves|t ihe Stoa-Tt j '[turdine,is iJeondensedinFs ]the vaponzer .jthenflawstaaetheermheaterze i7ifst $" o! Hot Geothermal tule Cooled Geothermal Black &Veatch 10-33 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Mode of Operation It is expected that the geothermal power plant project will be designed and permitted for baseload operations. Black &Veatch assumed that the proposed geothermal plant will be able to achieve 95 percent availability factor during its first commercial operation year and will experience approximately 0.5 percent output degradation annually for the following nine years until new wells are drilled to replace old wells.Black & Veatch also assumed that the estimated cost for drilling a new well to replace an old well will be approximately $2 million per well in 2009 dollars. Based on the above assumptions and for the purpose of this study,Black &Veatch assumed that the proposed geothermal plant will operate at an average capacity factor of approximately 90 percent for 30 years,with an estimated levelized well drilling and replacement cost of $20/kW-year. Capital Costs Ormat did not provide estimated capital cost data for review by Black &Veatch.For the purpose of this study,Black &Veatch assumed that the construction cost for the first block of the proposed geothermal project will be approximately $4,000/kW in 2009 dollars.Black &Veatch assumed that this cost includes engineering,procurement,and construction costs for equipment,materials,construction contracts,and other indirect costs.Black &Veatch assumed that owner's cost items such as land,contingency,etc.,will be approximately $1,000/kW in 2009 dollars,or 25.0 percent of the project construction cost.Therefore,it is anticipated that the total capital cost for the proposed project will be approximately $5,000/kW in 2009 dollars.The capital cost for the second block is assumed to be 10 percent less than the first block. O&M Costs O&M costs include fixed and variable costs. Fixed O&M Costs Fixed O&M costs include labor,payroll burden,fixed routine maintenance,and administration costs. Therefore,for the purpose of this study the fixed O&M costs associated with the project are estimated to be $300/kW-year in 2009 dollars. Variable O&M Costs Variable O&M costs include consumables,chemicals,lubricants,water,major inspections,and overhauls of the steam turbine generator and associated equipment.Variable O&M costs vary as a function of plant generation.For the purpose of this study,Black &Veatch assumed that the non-fuel variable O&M costs will be $2.00/MWh in 2009 dollars. Availability Factor Availability factor is a measure of the availability of a generating unit to produce power considering operational limitations such as unexpected equipment failures,repairs,routine maintenance,and scheduled maintenance activities.For the purpose of this study,Black &Veatch assumed that the initial availability factor of this proposed geothermal plant will be 95 percent. Schedule Figure 10-10 illustrates the estimated project development plan that Ormat presented to AEA on June 16, 2009.The plan indicates that the proposed geothermal project can be available for commercial operation by the end of 2016.For the purpose of this study,Black &Veatch assumed that the first proposed 50 MW geothermal generating units will be available for commercial operations starting in 2016. Black &Veatch 10-34 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-10 Estimated Mount Spurr Project Development Plan (Source:Ormat) Elisa)Developsooseeeeg t=ees Transmissionand interconnections Meee ) =Power Purchase Agreement 5 Land position T 10.4.4 Wind Project Options Alaska has abundant wind resources suitable for power development.Much of the best wind sites are located in the western and coastal portions of the State.The wind in these regions tends to be associated with strong high and low pressure systems and related storm tracks.Wind power technologies being used or planned in Alaska range from small wind chargers at off-grid homes or remote camps,to medium-sized machines displacing diesel fuel in isolated village wind-diesel hybrid systems,to large turbines greater than 1 MW. Alaska appears to also have significant potential for off-shore wind projects.Since off-shore wind projects are generally more expensive than on-shore projects,off-shore projects are not explicitly considered in this study. In the Railbelt,several of the utilities are examining wind power projects,including: e BQEnergy/Nikiski 15 MW,HEA Fire Island -54 MW,Chugach Eva Creek -24 MW,GVEA Delta Junction -50 MW,GVEA Arctic Valley -25 MW,Chugach Bird Point -10 MW,Chugach Alaska Environmental Power -15 MW,GVEA 63 Other Projects in AEA's Data Base In addition,the developers of several proposed wind projects in the Railbelt have applied for grant requests from the AEA Renewable Energy Fund Grant Program,which was established by Alaska Legislature in 2008.Table 10-19 shows each proposed wind project's name,applicant,estimated project cost,grant requested,andfundingdecisionandamountrecommendedbyAEAaftertworoundsofrankingandfundingallocations conducted by AEA. Black &Veatch 10-35 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-19 AEA Recommended Funding Decisions -Wind Recommended Grant Funding Project Project Cost |Requested Recommended Amount Name Applicant ($000)($000)Funding Decision ($000) Nikiski Kenai Winds,$46,800 $11,700 Partial funding $80 Wind Farm |LLC Kenai Kenai Winds,$21,000 $5,850 Partial funding $2,000 Winds LLC AVTEC Alaska $709 $635 Not recommended”None Wind Vocational Technical Center Delta Wind |Alaska Wind $135,300 $13,000 Not recommended”None Power,LLC Note: 1.The project did not pass Stage 2 review or was excluded in Stage 3 review for geographical spreading. Black &Veatch studied the details of each proposed wind project and applied the following screening criteria to determine which developments could be considered as a potential supply-side alternative in this RIRP study: ©Project size:Larger than 5 MW e Permitting:In place or in progress ¢Power Purchase Agreements (PPA):In place or in progress e Readiness:Prepared for construction by end of 2010 Based on the review of the above information,Black &Veatch assumed that the proposed Fire Island project and the proposed BQ Energy/Nikiski project be considered as potential supply-side alternatives in this RIRP study.The following subsections discuss further details of these proposed projects. 10.4.4.1 Fire Island Description of Project A joint venture (JV)of CIRI,an Alaska Native Corporation,and enXco Development Corporation (enXco)has approached AEA for the potential development of a wind generation project on Fire Island,which is located in Cook Inlet approximately three miles off Point Campbell in Anchorage,Alaska.On May 14,2009, the JV made a presentation to AEA to provide AEA staff with the latest status update of the proposed FireIslandProject.According to the JV,there is the potential to develop a wind generation plant with anestimatedmaximumoutputof54MWonFireIsland.Figure 10-11 illustrates a visual simulation of the proposed Fire Island wind generation project. Black &Veatch 10-36 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-11 Visual Simulation of Fire Island Wind Generation Project (Source:CIRI/enXco Joint Venture) uot Oe.ae ': .:"°7 } Be EE am aT ETA heen iit ae Se:ee i od +o tag.™t=ian rn ee eeamera",q :fags ae Ne eee Te Se .sek ”ae)a DADE ae." : s Mate es fet ag gdeeePaeTak" Aki 'A 1:'af meledetgoSENae5 4 y rE :f are 'PRN:We 4EI.weet gS "NN "A™ %i .ae i om ..¥>»on. aot OT ong M5,. 4StasanAewk.ine w,Nee Sy 8 aime A 'Awa OSE ; Figure 10-12 illustrates a preliminary site arrangement and interconnection route of the proposed wind project.The project will be based on installation of up to 36 GE 1.5 MW wind turbines.Each wind turbine will be equipped with reactive power and voltage support capabilities.The project is planned to be interconnected via 34.5 kV underground and submarine cables from an on-site 34.5 kV collector substation to Chugach's Raspberry substation.In addition,it is expected that the project will require the construction of a 5,000 square foot maintenance facility,approximately nine miles of gravel roads,and on-island housing facility for five maintenance staff. For the purpose of this study,Black &Veatch assumed that the proposed wind generation project will be developed as a 54 MW nameplate-rated project. Mode of Operation It is expected that the wind generation project will be designed and permitted for intermittent operations subject to wind resource availability at the project site. Capital Costs EnXco provided estimated installed capital cost of $3,100/kW including interconnection costs.Since providing the cost estimate,enXco has closed their Anchorage office and Black &Veatch has been unable to confirm if the $3,100/kW capital cost included benefits of the American Recovery and Reinvestment Act of 2009.In 2008 the Alaska Legislature appropriated $25 million for the construction of the proposed underground and submarine cable project to interconnect the proposed wind generation project to the Railbelt grid. Black &Veatch 10-37 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-12 Preliminary Site Arrangement and Interconnection Route (Source:CIRVenXco Joint Venture) *,"a ;\ars oo 4% 7 Neoe&a Nt ore 4Re.By ar *°Noy.sy ater SS Oo 'wf \'"s .s any Pcie AS wa 'AN a ¢ "7%%"hs oy « a"ia .Le nN rom '°an re !>"Be aes ? tae NLSysiggy.See ,gleeRyne -,*se .iS NO ON - :. ». s hgct 'a ,.Fwy'ral T =a hy x oy AasekSad>=p --rare. 'i tt N y hae ee RP ¢yan.aN ee Way.St NS "os a Tee SA Ags:a .%ay O&M Costs O&M costs include fixed and variable costs. Fixed O&M Costs Fixed O&M costs include labor,payroll burden,fixed routine maintenance,and administration costs. Black &Veatch assumed $122/kW-yr in $2009 for fixed O&M costs. Variable O&M Variable O&M costs include consumables,lubricants,and major inspections of the wind turbine generators and associated equipment.Variable O&M costs vary as a function of plant generation.AEA provided and estimate of $9.75/MWh in 2008 dollars for variable O&M costs for Fire Island.For the purpose of this study,Black &Veatch assumed that the non-fuel variable O&M costs will be $10.00/MWh in 2009 dollars. Capacity Factor According the JV's May 14,2009 presentation,the proposed wind generation plant will be able to achieve approximately 33 percent average capacity factor during its operating years. Schedule It is Black &Veatch understanding the proposed wind generation project has completed the following activities: e Reached consensus to interconnect the project with Chugach at 34.5 kV level in the June 2008 meeting with Chugach,ML&P,HEA,and GVEA. e Received proposals and met with potential construction contractors. e Submitted draft power purchase agreements (PPAs)to Chugach,ML&P,HEA,and GVEA. Black &Veatch 10-38 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY e Initiated integration studies. ©Received the U.S.Army Corps of Engineers permit approval for the proposed wind generation and related electricity transmission infrastructure project. According the JV's May 14,2009 presentation,the JV expects to begin site preparation work in 2009, complete the project design and site preparation in 2010,and begin erection of wind turbines in 2011.For the purpose of this study,Black &Veatch assumed that the proposed wind generation project will be available for commercial operations starting in 2012. 10.4.4.2 BQ Energy/Nikiski Description of Project The project,being developed by Kenai Winds LLC,is a 15 MW wind energy generation facility to be located in the Nikiski Industrial Area,in Nikiski,on the Kenai Peninsula,close to the Tesoro Refinery (Figure 10-13). There is very little supporting infrastructure required.Kenai Winds does not require new power lines (other than local collection system)and does not require new roads,ports,nor aircraft access facilities. There are several possible points of delivery in the area of the wind farm.The optimum location among those choices has not been selected,but HEA has agreed to purchase the full output of the Kenai Winds project. The developer applied for a grant from the AEA Renewable Energy Fund Grant Program and was approved, during Round 1,funding for $80,000 to complete development activities. On March 6,2009 the developer submitted Supplemental Information to its previous Request for Grant Application to provide AEA staff with the latest status update ofthe proposed BQ Energy/Nikiski project. Details of the information contained in this document will be presented in the following subsections. Figure 10-13 Kenai Peninsula,Nikiski (Source:Kenai Winds LLC) Black &Veatch 10-39 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Mode of Operation It is expected that the wind generation project will be designed and permitted for intermittent operations subject to wind resource availability at the project site. Capital Costs Capital costs are estimated to be $1,933/kWin 2009$with limited supporting infrastructure required. O&M Costs O&M costs include fixed and variable costs.O&M costs of $0.023/kWh in 2009 dollars based on AEA's analysis of non-rural projects. Capacity Factor According to the March 6,2009 document presented by Kenai Winds to AEA,preliminary review of the meteorological data available yields that the net capacity factor from the project is expected to be 28 percent. Schedule It is Black &Veatch understanding the proposed wind generation project has completed the following activities: e Received the US Federal Aviation Administration permit approval for the proposed wind generation. e Reached consensus to interconnect the project with HEA. e Submitted draft power sales term sheet to HEA and discussions around those terms are underway. e Initiated Interconnection Requirements Studies (IRS). According to the Kenai Wind's document dated March 6,2009,the developer is expecting to complete the project design and start site preparation by August 2009,and begin erection of wind turbines in November 2009.For the purpose of this study,Black &Veatch assumed that the proposed wind generation project will be available for commercial operations starting in 2010. 10.4.5 Modular Nuclear Project Option Description of Project Alutiiq has been marketing a new small,modular nuclear power plant.This alternative would be available for use at most sites.Alutiiq has approached Chugach for a specific application of repowering at the Beluga power plant site. The proposed nuclear project option is based on an advanced reactor design from Hyperion Power Generation (Hyperion)and Los Alamos National Laboratory.The project will consist of the following major ,components: e A single unit,self-regulating,reactor module with heat exchanger. e A uranium hydride fuel/moderator system. e A steam turbine generator. ¢Balance of plant mechanical,electrical,chemical,water,and interconnection systems. Black &Veatch 10-40 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-14 illustrates a simplified power cycle process of the proposed nuclear project.The reactor will be designed to operate at an optimum temperature of 550°C and produce approximately 68 MW of thermal output.The thermal output from the reactor will be converted to approximately 27 MW of electrical output through a steam turbine generator. Figure 10-14 Simplified Hyperion Power Cycle Diagram (Source:Hyperion Power Generation) Uranium Hydride Fue Moderator Steam Turbine eee 2 Heat Exchanger 6u0'e Rydrogen Storage Actnidea Seif Requation Hydrogen Exchange Storage Temperature SContralsCore Terrperature Mode of Operation . It is expected that the project will be designed and permitted for both load following and base load operations. Fuel SupplyAlthoughitis anticipated that the reactor design for this project can accommodate a variety of fuelcompositions,the initial reactor design and calculations were based on the use of uranium hydride. Depending on its use and mode of operations,each reactor is expected to last 7 to 10 years.The design proposed for this project does not allow for in-field refueling of the reactor.Each reactor will be sealed at the factory and transported to the project site for initial installation.When refueling is required after the anticipated 7-to 10-year period,a new reactor will need to be installed and the used reactor will need to be removed and transported back to the Hyperion factory for refurbishing and refueling. Black &Veatch 10-41 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY For the purpose of economic evaluation for this study,Black &Veatch assumed that the project will incur zero variable fuel cost.However,Black &Veatch assumed that the project's reactor will be replaced every seven years.It is assumed that the reactor replacement cost will be approximately $25.0 million in 2008 dollars. Capital Costs Generic Greenfield Capital Costs According to Hyperion's June 2008 "Brief for Public”presentation,General Atomics estimated that the construction cost for a 27 MW electrical output generic greenfield project will be approximately $37.0 million in 2008 dollars.Black &Veatch assumes that this cost includes engineering,procurement,and construction costs for equipment,materials,construction contracts,and other indirect costs.Black &Veatch assumes that owner's cost items such as land,contingency,etc.,will be approximately $8.0 million in 2008 dollars,or 22 percent of the project construction cost.Therefore,it is anticipated that the total capital cost for the generic greenfield project will be approximately $45.0 million in 2008 dollars or approximately $1,667/kW. Additional costs estimates provided by Chugach for small nuclear units include a 10 MW facility for $200 million or $20,000/kW and a 50 MW facility for $300 million or $6,000/kW.For evaluation purposes, Hyperion's cost estimates will be used in this study,but based on the other estimates,they appear to have the potential to be low. Specific Chugach Repowering Capital Costs Alutiiq provided a confidential rough cost for a Hyperion unit for repowering Beluga.Black &Veatch estimated the cost to connect the Hyperion unit to the Beluga steam turbine as well as an estimate of owner's cost.The total estimate cost of repowering the Beluga steam turbine is $39.6 million in 2009 dollars. Non-fuel O&M Cost Non-fuel O&M costs include fixed and variable costs. Non-fuel Fixed O&M Costs Non-fuel fixed O&M costs include labor,payroll burden,fixed routine maintenance,and administration costs. It is assumed that the project will have a full-time plant staff of 15 personnel consisting of a plant manager,an administrative staff,a nuclear safety officer,and 12 O&M personnel.Therefore,for the purpose of this study the non-fuel fixed O&M costs associated with the project are estimated to be $2.6 million per year in 2009 dollars. Non-fuel Variable O&M Costs Non-fuel variable O&M costs include consumables,chemicals,lubricants,water,major inspections,and overhauls of the steam turbine generator and associated equipment.Non-fuel variable O&M costs vary as a function of plant generation.For the purpose of this study,Black &Veatch assumed that the non-fuel variable O&M costs will be $2.56/MWh in 2009 dollars. Availability Factor Availability factor is a measure of the availability of a generating unit to produce power considering operational limitations such as unexpected equipment failures,repairs,routine maintenance,and scheduled maintenance activities.For the purpose of this study,Black &Veatch assumed that the average availability factor of this proposed nuclear plant will be 90 percent. Black &Veatch 10-42 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Schedule According to the February 20,2008 "Periodic Briefings on New Reactors”transcript and presentation Black &Veatch obtained from the Nuclear Regulatory Commission (NRC)website,Hyperion had submitted a letter of intent to NRC and met with the NRC in May 2007 to discuss the NRC licensing process.At the May 2007 meeting,Hyperion stated to NRC that Hyperion intended to submit a design certification application to the NRC in early 2012 as part of Hyperion's plan to obtain a manufacturing license from NRC. A schedule (See Figure 10-15)illustrating the requested application timelines based on NRC receipt of letters of intent from all potential advanced reactor license applicants was presented by NRC during the February 20, 2008 briefing.The schedule shows that the Hyperion manufacturing license review process will be completed by the end of 2015 based on the assumption that the NRC will have appropriate staffing level and capability to review licensing applications submitted by all applicants. Figure 10-15 Requested Potential Advanced Reactor Licensing Application Timelines (Source:NRC February 20,2008 Briefing Presentation Slide) Potential Advanced Reactor Licensing ApplicationsAnestimatedschedulebyFiscalYear(October through September} |zoos |2009 |2010 |2014 |20412 |2013 |2014 |2015 |2a0t6 |2087 | [NGNPLS l t NGNP NRC Active Participation &RED Activities J :|«hehe GNP Licensing Revi a Hearing> 'lt |PAM Pre-applcation Reviews =PBMR-D we Hon Revi b i¢RIS Testing Program Revie T aeeRIS Design Certification Reviews wi foshitra'4S Design Approva fu /i j 4 4 Legend: (UNGNPActivities]|ante Desiow Appr 3 (Of Hearing > Pir Pre-appication Revie |20 Manufacturing License [EE GhieeDesigr Certification »TEE REDAntractrsohew-Hevetoperert| NOTE:Schedules depicted for future activities represent nontinal assumed review durations based on submittal time frames in letters af intent from prospective applicants.Actual schedules will be determined when applications are docketed,* Black &Veatch 10-43 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-16 illustrates the Nuclear Energy Institute (NED)latest understanding of the NRC's new licensing process.Figure 10-16 indicates that the expected time frame to process a Combined Construction and Operation License Application (COLA)is 27 to 48 months.Assuming that Hyperion proceeds in parallel,the license should be issued coincident with the Manufacturing License.Based on information provided by Hyperion,engineering,prototype,and testing will take four years.Further,it was assumed that it will take three years to manufacture and install the unit from issuance of the license to manufacture.Thus,the first of the units will be available for commercial operation in 2020. Figure 10-16 NRC New Licensing Process and Construction Timelines for New Reactors (Source:NEI website) on Pinte Compnet cm Permit bib)oul ee : orn ee .my i ; : ,NRC Review!astApplication,oaDevelopmentApprovalofApplicationqi427to45°mortks)oH -tome n |Plant Construction)aiMyheolreatory,a al Verilication ain7ee Ore ; Commercial Operation 4 3 i 1 1 i a iN )J §1 2 3 4 5 6 ?3 9 10 11 Tine in Yoors ¢'2sumate tor the Fret drwy ols}Janusy 2009 The NRC's new licensing process offers multiple opportunities for public input. Black &Veatch 10-44 February 2010 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY 10.4.6 Municipal Solid Waste Project Options Generic municipal solid waste projects were considered for the Anchorage and Interior areas.Black &Veatch sized the projects based on an estimated amount of trash produced in each area on a tons per day basis.This estimate was developed by multiplying the number of residents in each area by an estimated average of 4.5 pounds of trash per day,per person.The resulting tons per day number was compared with a list ofmunicipalsolidwasteprojectsproposedandoperatingintheUStoidentifyprojectsizeswithsimilartons perdayconsumption.As a result,22 MW and 4 MW project capacities were developed for Anchorage and theInterior,respectively.' Black &Veatch assumed that the municipal solid waste projects would charge fees for taking the trash at a similar tipping fee rate currently charged by local landfills.Black &Veatch estimated capital costs of both projects to be $5,750/kW in 2009 dollars. It should be noted that previous studies have been conducted regarding the feasibility of municipal solid waste projects in the Railbelt region.Furthermore,while Black &Veatch did not specifically evaluate landfill gas to energy technologies,they warrant further consideration. 10.4.7 Central Heat and Power Central heat and power projects have not been explicitly modeled in this study.These projects are often developed by IPPs.If these projects meet the efficiency requirements to be certified as a Qualifying Facility (QF),then the existing utilities can be required to purchase the power from a central heat and power project at avoided costs.Since the qualification is very site specific,the development of specific projects to evaluate is beyond the scope of this study.It should be noted that under the GRETC concept,standard purchase power agreements will be available.The use of standard purchase power agreements will eliminate the specific need to be a FERC Qualifying Facility. Black &Veatch 10-45 February 2010 SECTION 11 DSM/EE RESOURCES ALASKA RIRP STUDY 11.0 DEMAND-SIDE MANAGEMENT/ENERGY EFFICIENCY RESOURCES 11.1.Introduction The purpose of this section is to summarize Black &Veatch's approach to the assessment of DSM/EE measures as part of the overall RIRP project.A very important element of any comprehensive integrated resource plan is the development of a portfolio of proposed energy efficiency and demand reduction programs that can contribute energy savings and winter peak load reductions,and then evaluate these potential programs relative to alternative supply-side electric generation options on a cost per kWh and per kW basis. Those demand-side resources that prove to be more cost-effective than supply alternatives are then typicallyincludedinintegratedresourceplanningmodelormodels(in this case,Strategist®and PROMOD®)as a reduction to the load forecast.The resulting lower forecast then serves as the basis from which the alternative supply-side options are considered for adding generation resources when and as needed. Black &Veatch has conducted a review of the Railbelt utilities'existing DSM/EE programs and developed a portfolio of potential DSM/EE measures for evaluation against supply-side alternatives.The costs and benefits associated with the DSM/EE measures are taken from existing data sources as described later in this section.Data on non-weather sensitive measures (e.g.,lighting,appliances)are directly transferred from existing nationally-known sources,and data on weather-sensitive measures are transferred from existing sources using a regression model that considers both heating and cooling degree days as an adjustment factor. This approach has been used successfully in various other jurisdictions and has received general regulatory acceptance. The design of DSM/EE programs involves three basic elements:1)identification of target customer segments and end uses with the capacity to reduce energy use,2)identification of technologies and behaviors that will result in the desired changes in consumption and load shape,and 3)identification of marketing approaches or program concepts to achieve the desired behavioral changes. The short time frame,budget and limited data availability for this study precluded a rigorous analysis of electric DSM/EE potential (i-e.,technical potential and maximum achievable potential)in the Railbelt region. However,Black &Veatch has made maximum use of existing data,augmented by interviews with a number of individuals,and employed industry-accepted data sources and analytical tools to produce a preliminary estimate of the cost-effective DSM/EE resources that exist within the Railbelt region. In the next subsection,we present some background information on the Railbelt utilities'current DSM/EE programs and the literature sources that we reviewed.We then present a summary and characterization of the customer base for energy efficiency and demand reduction by company and sector.An estimate of DSM/EE potential is presented in the next subsection,followed by a discussion of the DSM/EE technologies or measures considered,screened,and included in the RIRP modeling.We conclude with some comments regarding the delivery of DSM/EE programs. Black &Veatch 11-1 February 2010 SECTION 11 DSM/EE RESOURCES ALASKA RIRP STUDY 11.2 Background and Overview 11.2.1 Current Railbelt Utility DSM/EE Programs Black &Veatch conducted two investigations to assess the current level of energy efficiency program activity at the Railbelt utilities.First,inquiries were made to the six Railbelt utilities and,second,websites of the utilities were researched. Based upon the information gathered,Table 11-1 summarizes the current DSM/EE programs and related information offered by the Railbelt utilities. Table 11-1 Current Railbelt Electric Utility DSM/EE-Related Activities Utility Chugach Residential Other Assistance/Information DSM/EE Programs and Other Assistance/Information Offered Provides compact fluorescent light (CFL)bulb coupons. Refers to a 2008 Board of Directors policy to establish an energy efficiency and conservation program. Provides a calendar of events,workshops (sponsored by AHFC)and other activities (e.g.tours,fairs,contests,etc.)with links to the specific events. Provides tips for buying and using appliances,CO,detectors,heating and cooling, holiday lighting,insulation,lighting,water heating,and windows. Provides a tool to analyze accounts,which includes a table of costs for typicalapplianceusageandalinktotheEnergyStar®webpage's home energy yardstick which is a tool to analyze energy usage. Provides a variety of documents related to energy efficiency.. GVEA Residential Commercial Other Assistance/Information Home$ense:$40 energy audit that includes energy saving tips and installation of energy efficient products at no additional cost. Builder$ense:rebate program for home builders who install electrical energy efficiency measures during construction. BusinessS$ense:rebate program of up to $20,000 for commercial members who reduce their lighting loads through energy efficient lighting retrofit projects. Link to AHFC and University of Alaska Fairbanks-Alaska Cooperative Extension Service,energy and housing. Department of Energy document with tips and ideas on how to increase home energy efficiency and how to buy energy efficient products. Calculator to determine savings by replacing standard incandescent light bulbs with compact fluorescents. Black &Veatch 11-2 February 2010 SECTION II DSM/EE RESOURCES ALASKA RIRP STUDY Table 11-1 (Continued) Current Railbelt Electric Utility DSM/EE-Related Activities Utility DSMW/EE Programs and Other Assistance/Information Offered HEA Residential , e Information on WiseWatts program and incentives.. e Offers a Black &Decker Power Monitor for $50. e Line of credit for HEA customers from $200 to $5,000 for the purchase of approved energy-efficient electrical appliances and other approved merchandise.The repayment period can be from 6 to 36 months upon approved credit.There is an application fee of $35 at the time the loan closes. Other Assistance/Information ¢Touchstone Energy Savers:contains links to Touchstone Energy®tools,tips and resources designed to create greater home comfort and promote energy efficiency. Included on this page are an on-line home energy saver audit,information about stimulus package energy efficiency and weatherization programs,and a link to Alaska Building Science Network. e Offers advice on how to select new energy efficient appliances and products for homes and businesses.Also provides appliance usage tips to reduce energy consumption. ¢Information on CFL and old refrigerator disposal in the area. MEA Other Assistance/Information e Provides information on the benefits of Energy Star®appliances,including a link to the EnergyGuide label. e Provides information on how to save energy by managing monitor and PC power. e Provides energy saving tips,including heating and cooling,home electronics, lighting,and new energy efficient homes. e Provides a link to Energy Star®Home Energy Yardstick,a tool to analyze your energy usage. ©Provides links to the AHFC and Cold Climate Housing Research Center. ML&P |Commercial e Sponsor of Green Star's Lighting Energy Efficiency Pledge (LEEP)which encourages businesses to upgrade and retrofit their lighting..Participating businesses receive technical support and resources to help them achieve energy savings and Green Star promotes participating businesses. Other Assistance/InformationeProvidesalinktoHomeEnergy Saver,whichis the Department of Energy's freehomeenergyaudittoolaspartoftheEnergyStar®program. e Provides tips to reduce utility bills and provides links to the Municipality of Anchorage's low-income weatherization program and the AHFC Research Information Center. Black &Veatch 11-3 February 2010 SECTION 11 DSM/EE RESOURCES ALASKA RIRP STUDY 11.2.2 Literature Review AS previously stated,the Railbelt utilities have limited experience in the implementation of DSM/EE programs;likewise,there is limited Alaska-specific information available typically required to complete an evaluation of the resource potential and cost-effectiveness of DSWEE resources.To supplement the information available from the utilities,Black &Veatch relied on other Alaskan sources of information as shown in Table 11-2. Table 11-2 DSM/EE-Related Literature Sources Printed Materials Reviewed Websites Reviewed Alaska Energy Authority;Alternative Energy |ACEP -Alaska Center for Energy and PowerandEnergyEfficiencyAssistancePlanJuly1,|(University of Alaska); 2007 to June 30,2009;2009.http://www.uaf.edu/acep/publications/detail/index.xml. Alaska Energy Authority;Alternative Energy |Alaska Housing Corporation; &Energy Efficiency Update;2007.http://Awww.ahfc.state.ak.us/home/index.cfm. Alaska Energy Authority,et al.;Village End-|Alaska Energy Authority; Use,Energy Efficiency Projects Phase II.http://www.akenergyauthority.org/. Results -2007-2008;2009. Chugach Electric Association;End Use Cold Climate Housing Research Center (CCHRC); Model Results;1991.(provides residential http://www.cchre.org/default.aspx. and commercial end-use projections for Chugach,HEA,and MEA) Information Insights,Inc.;Alaska Energy Denali Commission;http://www.denali.gov/index.php. Efficiency Program and Policy Recommendations;2008. Information Insights,Inc.;Alaska Energy Municipality of Anchorage,Alaska; Efficiency Program and Policy http://(www.muni.org/OECD/energyEfficiency.cfm. Recommendations -Appendices;2008. Renewable Energy Alaska Project (REAP); http://alaskarenewableenergy.org/tag/energy-efficiency/. 11.2.3 Characterization of the Customer Base Table 11-3 provides a summary of the customer base for each of the six Railbelt utilities,including the total number of customers for each utility,as well as information on the numbers of customers in the largest population centers.This table also shows a breakdown of customers into residential,commercial and industrial sectors. This information was used in the analysis of potential penetration rates for various DSM/EE measures as discussed later. Black &Veatch 11-4 February 2010 SECTION 11 DSM/EE RESOURCES ALASKA RIRP STUDY Table 11-3 Railbelt Electric Utility Customer Base Total Number of Major Res.Comm.Ind.Number of Govt&LowAlaskaRailbeltUtilitiesCust.Population Population Pop.Cust.Cust Cust.Schoolsinall Schools income Centers Center(s)Pop.Centers _incity _Res in city Fairbanks 34,540 37 4,076 North Pole 2,183 8 227 Golden Valley Electric Association]GVEA 42,866 2 Delta Junction 0421 36,395 6,008 463 61 9 98 Nenana 352 2 37 Anderson 274 1 28 Wasila 9,780 a7 1,017 |Matanuska Electric Association MEA 53,503 20 Palmer 7,804]49,939 3,564 0 49 13 812 Houston 2,017 0 210 Chugach Electric Association &CEA andAnchorageMunicipalLightandML&P 108,472 10 Anchorage 279,671]93,493 14,973 6 125 104 18,458 Power Homer 5,691 10 592 Soldotna 4,289 10 4465 Homer Ekctric Association HEA 27,401 22 Kenai 7,686]23,811 3,563 27 29 Kachemak City 443 0 46 Seldovia 306 1 32 City of Seward Electric System CES 2,567 1 Seward 3,061]1,973 476 118 4 4 318 234,809 82 359,039 205,611 28,584 614 268 226 26,397 Organization State cities IGdden Valley Electric Association 5.6%)7.8%) Anchorage Municipal Light&Power 40.9%57.2% Matanuska Electric Association 2.9%40% Chugach Electric Association 0.0%0.0% Homer Electric Association 2.7%3.8% City of Seward Eleciric System 0.4%0.6% Total Pop in Railbelt 52.53%13.42% Sources:[Customer information Energy Velocity by Ventix Population data http:/Avwww.census.gov/ Economic data:http:/Avww.census.gov/ Schools data:http:/Avww.eedstate.ak.us/Alaskan_Schods/P ublic/ Black &Veatch 11-5 February 2010 SECTION I1 DSM/EE RESOURCES ALASKA RIRP STUDY 11.3 DSM/EE Potential The purpose of this subsection is to provide an overview of Black &Veatch's estimate of the potential for DSM/EE measures in the Railbelt region. 11.3.1.Methodology for Determining Technical Potential The general approach for developing an estimate of the DSM/EE technical potential consisted primarily of the following three steps: 1.Black &Veatch reviewed the universe of measures that are available in the marketplace to increase energy efficiency.This review included not only the limited DSM/EE program experience in Alaska but also a review of the DSM/EE program experience of other utilities throughout the U.S. 2.Black &Veatch eliminated non-electric energy savings measures since this study is focused on meeting the demand and energy requirements of the electric utilities within the Railbelt region. 3.Black &Veatch conducted an intuitive,or qualitative,screening of potential DSM/EE measures based on certain criteria,which are discussed below. 11.3.2 Intuitive Screening A universe of DSW/EE measures exists that provide energy savings over standard products that serve the same end uses.The majority of these measures are well proven in terms of their impact on electric demand and energy requirements based upon the experience of utilities in other regions of the country.To cull this list,Black &Veatch used a process to screen measures to identify those that are most appropriate for the Railbelt region.The primary objective of this effort was to select the most appropriate measures for further analysis. There is a considerable range of new products and technology options that are available for energy efficiency and demand reduction applications.Many of these are available today to consumers in the Railbelt region, while others are less prevalent or readily available.Black &Veatch examined a broad array of the most relevant technologies and measures for residential and commercial (non-residential)applications,and considered the extent to which each technology and measure makes sense for the Railbelt region. To ascertain which electric end-use measures would best provide energy efficiency opportunities for Railbelt electric customers,as well as help the Railbelt utilities meet their long-term energy and capacity planning goals,Black &Veatch felt that the initial step to aid in sifting through the number of measures would be to use an intuitive or qualitative technology screen.This process,first developed through the Electric Power Research Institute (EPRI)Customer Preference and Behavior Research Project in the 1980s,has been used by utilities across the nation as a first pass at the screening and ranking of DSM technologies. Numerous measures were considered for the residential and commercial sectors.Certain criteria were developed to gauge the relative value of each measure for the Railbelt region,including:1)the impact that each measure would have on the winter system load,2)a preference for conservation measures (rather than peak impacting),and 3)whether the measure is currently offered in the marketplace.The Black &Veatch team felt that a review of each measure within these descriptive criteria would aid in indicating which measures "rise to the top”as "best”candidates and,as such,should be investigated for possible program inclusion. Black &Veatch 11-6 February 2010 SECTION Il.DSM/EE RESOURCES ALASKA RIRP STUDY 11.3.3 Program Design Process Once this initial screening was completed,Black &Veatch then grouped similar,or related,DSM/EE measures into potential DSM/EE programs that were further evaluated within the RIRP models.This approach is consistent with the approach typically used by utilities to develop DSM/EE programs,as shown on Figure 11-1. Figure 11-1 Common DSM/EE Program Development Process (1)2).G3) IDENTIFY universe of SCREEN DSM Technologies >PACKAGE screened DSM DSM Technologies "|according to utility-specific Technologies into groupings criteria according to end-use applications and delivery approaches (4)6)(6) DESIGN DSM Programs based ,|ASSESS program costs and ,_|FINALIZE selected set of DSM on available budgets,best-practice "|benefits individually and in terms "|Programs for promotion,develop marketing techniques and policy of overall impact on company implementation schedules and considerations revenues plans Typically,utilities develop detailed DSM/EE program plans for each program selected for implementation. These DSM/EE program plans commonly include the following elements: Detailed description of the program--Derived from best practices from various sources. Reasons why the program would be successful in utility's service territory--Derived from a comprehensive market assessment and background research. Number of customers within the customer class/segment that are likely to adopt/use the proposed program--Derived from market assessments and surveys,with a percent or modeled participation estimate based on experience from other utilities with similar programs;informed by actual results from other utilities offering similar programs. Achievable energy savings--From a variety of sources,consistent with a technology assessment and published reports. Cost-effectiveness ratios/rating per individual program--Calculated using standard tests,such as the Total Resource Cost (TRC),Participant,Administrators (or Utility)Cost,or Ratepayer Impact Measure (RIM)Tests,applying appropriate avoided cost figures. Marketing plans which should include incentives,rebates and preferred distribution channels and how each reduces existing barriers to proposed program adoption/acceptance--Based on best practices from a variety of sources;incentive amounts based on examples from other companies. Detailed budget plans complete with explanations of anticipated increases/decreases in financial and human resources during the expected life of the program--Based on best practices from a variety of sources,over a designated time period for the program life. Black &Veatch 11-7 February 2010 SECTION 11 |DSM/EE RESOURCES ALASKA RIRP STUDY ®Recommended methodology or tracking tools for recording actual performance to budget-- Based on current standard practice using simple commercially available software. e Proposed program evaluations and reports--Based on current standard practice using a logic model approach. 11.3.4 Achievable DSM Potential from Other Studies There are several organizations that have estimated the potential for energy savings on a regional and statewide basis in recent years;most notably EPRI and the Edison Electric Institute (EPRI/EE]D),and the American Council for an Energy Efficient Economy (ACEEE).None of these studies,however,specifically and exclusively examined Alaska.However,one study by the Energy Efficiency Task Force of the Western Governor's Association (WGA)was conducted under the Clean and Diversified Energy Initiative and published in January 2006.The states included in the study were Alaska,Arizona,California,Colorado, Hawaii,Idaho,Kansas,Montana,Nebraska,Nevada,New Mexico,North Dakota,Oregon,South Dakota, Texas,Utah,Washington,and Wyoming.The study estimates achievable potential for three years (2010, 2015,and 2020)at 7,14,and 20 percent,respectively. Taking Ohio as an example of a state with relatively little prior DSM/EE program offerings,the ACEEE estimates a total achievable energy savings potential of 33 percent by 2025.Other higher end percentages are seen in Illinois (ACEEE 1998)with 43 percent achievable energy efficiency potential,and a regional studyfortheSouthwestthatrendered33percentenergysavingspotential.' The EPRI/EEI Assessment looked at the amount of energy savings deemed to be achievable in each of three time periods by sector and end use.The top 10 end uses did not vary considerably by region,and are shown on Figure 11-2 for the Western Census Region,which includes Alaska. The EPRI/EEI report also indicates a demand response potential of 88 MW based on a 2006 assessment for Alaska and Hawaii combined (note:there is no indication of whether this is from the summer or winter peak). These studies all provide comparative "top down”estimates from which to gauge the reasonableness of the estimates that Black &Veatch has derived from a "bottom up”assessment of DSM/EE potential inin theRailbeltregion. 11.4 DSM/EE Measures This section discusses the DSM/EE measures that are commonly considered in market potential studies of recent vintage.The standard approach to designing programs is to consider a wide range of measures,and then screen them by applying a set of criteria appropriate to the individual utility or region.The measures are then ranked and the most appropriate ones retained for modeling purposes. Since there are numerous combinations of technology replacement situations (e.g.,standard light bulbs with a 75 watt rating can be replaced with a compact fluorescent light bulb,CFL,using 15 watts;a standard 60 watt light bulb can be replaced with a 15 CFL,etc.),the modeling of measures only requires consideration of a representative group of measures in order to assess the potential benefits of promoting such measures in the region and service territory. 'US Department of Energy;National Action Plan for Energy Efficiency,Table A6-4 -Achievable Energy Efficiency Potential from Recent Studies;pages 6-16;July 2006. Black &Veatch 11-8 February 2010 SECTION 11 DSM/EE RESOURCES ALASKA RIRP STUDY Figure 11-2 EPRIY/EEI Assessment:West Census Region Results Com-Lighting m 2030 m 2020 @ 2010 Res-Electronics }-. Ind -Machine Drive -emsnnsestiaseimneril Com -Other Res -Cooling Com -Cooling oanInd-Lighting esmd 0 5 10 15 20 25 Annual Electricity Savings (TWh) Black &Veatch began this phase of the work by considering a large number of residential and commercial/ industrial (C/L)measures,As previously discussed,two initial screens (i.e.,removal on non-electric measures and intuitive screening)were applied to these lists. This shorter list of electric-only measures was then reduced based ona set of four additional screening criteria as follows: Relevance to the regional weather patterns Commercial availability Incremental cost per kWh over standard options Contribution to winter peak load reductionPRYNP This review and ranking of the measures resulted in an abbreviated list of 21 residential and 51 C/I measures for further analysis.Table 11-4 summarizes this abbreviated list of residential and C/I measures that was selected for further analysis.It also provides the following information for each DSM/EE measure: Measure life Estimated kWh savings per customer Estimated kW savings per customer Incremental cost per installation Black &Veatch 11-9 February 2010 SECTION 11 DSM/EE RESOURCES Table 11-4 ALASKA RIRP STUDY Residential and Commercial DSM/EE Technologies Evaluated reezers Energy Star-Chest Freezer 'Clothes Dryers. Retrigeratore-Freezers Resid-Ererty sareTonfs He Appliance 12.790 0.0 $50.88 Retrigerators-Freezers Resid-EnergyStar-Side by Side NonWeather pemance 12 1080 0.0 $50.88PumpendMotorSingle-Resid- S eve Appliance 10 6840 04 $23.38 Resid[Smart Strip plug outlet i Appliance §1840 0.0 $11.00 ,Resid .Freezer recyciing Noni Appliance 6 1,551.0 02 $75.00 Refrigerator recycing ree Appliance 6 1,6720 02 $130.00 eid-WaterHeatPumpWaterHeatersATESray,«615 (2,685.0 0.3 $242.50 .Resid-WaterLowFlowShowerheads«ASR a 12 S180 01 $36.76 Pipe Wrap pea eather eer 6 270 00 $209 ,Resid ,Hokey Lights Aeiveather wating 10 106 00 §14.20 CFL fotures Ronweather (tating 12 780 00 $2475 HorchiereFloorLampe Rosey Lighting 12 1640 0.0 $10.00 LED Night Light Re athe sting 12 20 00 $650 CFL bubbs regular Outside Rete Lighting 9 1916 00 5 0.63 CFL bubs regular Reine voting 8 M1 00 $283 Iceding Fane Resid Shel 15 478 00 $151.25 Duct sealing 20 leakage --Resid-uct Wen Shel 18 41.7 0.0 $143.70 Roof Insufation pee,Shh 2D TOD $441.22 Setback thermostat -Resid CoolingitiepollenWeether 9 1821 00 $4531 ENERGY STAR Sisam =Comm-Water Coca 3 Pan NorWeather He 12 11,1880 26 $1,141.25ater Pig Load Occupancy Comm Office D nt Stations 'NonV\log 5 SO 01 $S088 WoterHPWaterHeater101050=Comm.15 21,156.0 42 $1,100.00 JENERGY STAR CommercialSokdDoorRefrigerators=4comm =Refiigerat 19 gos a.103 $6875fessthan2083 ENERGY STAR Commercial Motors1teSHP IMotore25to100HP Comm-Motors 7.5 to 20 HP came Motor 15 4084 0.087 $149.85 LED Exit Signa Electronic Comme aFixtures(Retrofit Only)NonWeather Ushting 15 201.0 0.023 33.0$ LED Auto Ti Comm:LightxrafficSignalswong,Ughting 8 275.0 0.085 $LED Pedestrian Signals Ne ae Lighting 8 150.0 0.044 $77.00[VFOHP1.5 Process Comen-s $ lp.NoniWeather Motor 15 1,623.4 0.343 1,192.13 IVFD HP 10 Process Comm-le NonWesther Motor 15 10,7134 2286 811.50 IVFD HP 20 Process Comme PPumpingNonWeatherMotor1521,643.1 4.571 $1,266.63 [Vending Equipment Comm.-Refrigerat C 'NonWeather ion S 800.0 0210 $78.76 Efficient Refrigeration Comm -_-Refrigerat C NonW ion 15 1200 0.118 $9.63 ENERGY STAR Commercial fiSolidDoorFreezersssCOm™™-Rafrigerat 4 Son oso §41.25hasNonWeatherionin2073 JENERGY STAR Commercial jeokd Qoor Freezers 20 ts 48 NorWeather ion 12 507.0 «(0.058 $330.00 :y Comm --RefrigeralPeaRatgermlors20NonWeather;ton 12 1,069.0 0122 $275.00 ENERGY STAR ke Comm-=Refrigerat'nee Jets than500Ibe NonW.jon 12-«*1,852.0 0.489 $330.00ENERGYSTARkeComm--RefrigeratMachines500to1000}bs NonWeather ion «12 2095.0 0.308 $625.00 IENERGY STAR ke Comm:Rettmorethan1000AWestnesinn 12 6,048.0 0.690 $550.00 ey Pumps HP 1.5 viii Motor 15 3020 0.064 $313.75 Pumpe HP 10 ComeNonW Motor 15 2,014.0 0.427 $116.30 Comm-WaterPreRineaSprayersNonWeatherHealer 5 1360 0116 $9.63 Exterior HID replacement Commeabove250Wto40OWHIDNonwWeather Ushting 12 706.0 0.000 §$585.20 Pon sow HID Newne,Unhiing 12 490 0.103 $22291 React 400 HD NonWnner Uahing 12 8820 0200 $159.28 -erer-eere-re- High Bay 6L TSHO freplacing 400W HID High Bay Fluorescent JSLF32T8 Replacing 400W HID High Bay Fluorescent ISLF32T8 Double fixture replace 1000W HID: CFL Fidure CFL Screwin Daylight Senaor controls Low Watt T8 lamps. 3 Lamp TS replacing T12 beset Ughting 12 994 0.0 $11009 J Lamp TSHO replacing T12 pom Lighting 12 191.0 0.0 $168.33 Mere ommP.THZto Commner WOMting 12 1452 00 §75.99 Nore NTRPTIZte orther Uohting 12 1697 00 $8088 T12HOBR1amp retro!.PTB Te 4R 2 lamp ie See Veather lighting 12 1740 0.0 $6234 TIZHO &f 2Jamp retroft to Comm.HPS TS 4ft 4 lamp NonWeather 'ghting 12 293.0 0.1 §80.88 IT8 4h 3 temp come Lightng 12 1288 0.0 $107.38 78 4f 4 lamp Kamner Uohing 12 1398 00 $11250 Ta HO ah 2 Lamp Corner Waning 12 1840 00 $12492 a Comme Cooling!Window Fim wa Hers 10 2560 01 $8460 Refrigerant charging Comm.Cooling!ine sei 10 7124 1.0 $21.10 VFO Fan wr te 10 1,1856 00 $4289 Comm.Cooling!VED Pump Weer Feemy 10 39502 03 $41.01 com ther eee®3 3750 00 $3728 Strip curtains for walk-ins -Comm-RefrigerafreezerNonWeathertion 4 613.0 01 $7.00 Black &Veatch 11-10 February 2010 SECTION I1 DSM/EE RESOURCES ALASKA RIRP STUDY Tables 11-5 and 11-6 provide additional information regarding the input assumptions used in the evaluation of the residential and commercial DSM/EE measures,respectively.This information includes: *Incremental equipment cost Rebate as a percentage of incremental equipment cost Rebate amount Administrative costs Vendor or other costs Total per unit costs It should be noted that Black &Veatch did not complete a comprehensive cost-effectiveness evaluation of these measures using the traditional DSM cost-effectiveness tests (i.e.,TRC,Participant,Utility and RIM tests).Regional avoided costs are required to evaluate DSM/EE measure using these tests,and these avoided costs were not available when this evaluation was completed as part of this project.Rather,Black &Veatch achieved the cost-effectiveness assessment of these measures by including them directly in the RIRP models, which allowed for a direct comparison of the economics of DSM/EE measures relative to alternative supply- side alternatives. Furthermore,once the most appropriate technologies were screened,Black &Veatch estimated how many customers would adopt each technology each year in order to arrive at potential energy savings to be used in the RIRP modeling.Even though technologies are grouped into one or more program(s)for going to market, the application of a participation rate is done at the measure level.The number of customers available to adopt the technology was based upon the customer counts and appliance saturations discussed earlier.From this starting point,a set of technology adoption curves were applied that characterize the pattern of acceptance (or purchase)typical of products at different levels of marketing.For example,a high rebate amount for a product might be expected to achieve a high penetration in the early years,translating into a "steep”curve. On the other hand,a program that merely provides consumers with information about changing their behavior,but offers no monetary incentive,may result in an increase in related participation over time,but at a lower level and slower pace.To estimate maximum penetration rates for purposed of RIRP modeling, Black &Veatch used a series of technology adoption curves for DSM/EE studies from the BASS model. These curves are built from the original "S”shaped curve of product adoption and are a generally-accepted tool for characterizing consumer adoption patterns.Since Alaska is fairly new territory for DSM/EE programs,Black &Veatch assumed that the level of incentives required to move the market to adopt DSM/EE measures would average approximately 45 percent of incremental equipment costs. Black &Veatch 11-11 February 2010 SECTION 11 |DSM/EE RESOURCES ALASKA RIRP STUDY Table 11-5 Input Assumptions -Residential DSM/EE Measures Rebate as %of .Total per Incremental Incremental Unit Equipment Equipment Rebate Administrative Vendor or ProgramResidentialMeasuresCost(S)Cost Amount ($)Costs (10%)Other Costs Costs Freezers Energy $92.50 50%$46.25 $4.63 --$50.88 Star-Chest Freezer Clothes Dryers $150.00 50%$75.00 $7.50 --$82.50 Refrigerators-Freezers $92.50 50%$46.25 $4.63 -$50.88 Energy Star-Top Freezer Refrigerators-Freezers $92.50 50%$46.25 $4.63 --$50.88 Energy Star-Side by Side Pump and Motor Single $85.00 25%$21.25 $2.13 --$23.38 Speed Smart Strip Plug Outlet $40.00 25%$10.00 $1.00 -$11.00 Freezer Recycling $93.00 0%-- -$75.00 $75.00 Heat Pump Water Heaters $700.00 25%$175.00 $17.50 $50.00 $242.50 Refrigerator Recycling $93.00 0%---$130.00 $130.00 Low Flow Showerheads $31.60 100%$31.60 $3.16 $2.00 $36.76 Pipe Wrap $7.60 25%$1.90 $0.19 -$2.09 Holiday Lights $12.00 100%$12.00 $1.20 $1.00 $14.20 CFL Fixtures $45.00 50%$22.50 $2.25 -$24.75 Torchiere Floor Lamps $50.00 0%---$10.00 $10.00 LED Night Light $5.00 100%$5.00 $0.50 $1.00 $6.50 CFL Bulbs $3.00 25%$0.75 $0.08 --$0.83 Regular-Outside CFL Bulbs Regular $3.00 25%$0.75 $0.08 $2.00 $2.83 Ceiling Fans $275.00 50%$137.50 $13.75 --$151.25 Duct Sealing 20 Leakage $215.82 50%$107.91 $10.79 $25.00 $143.70 Base Roof Insulation $756.95 50%$378.48 $37.85 $25.00 $441.32 Setback $18.46 100%$18.46 $1.85 $25.00 $45.31 Thermostat-Moderate Setback Black &Veatch 11-12 February 2010 ALASKA RIRP STUDY Table 11-6 Input Assumptions -Commercial DSM/EE Measures Rebate as %of Total per Incremental Incremental Unit Equipment Equipment Rebate Administrative Vendor or Program Commercial Measures Cost (S)Cost Amount (S)Costs (10%)Other Costs Costs ENERGY STAR Steam $4,150.00 25%$1,037.50 $103.75 --$1,141.25 Cookers 3 Pan Plug Load Occupancy $185.00 25%$46.25 $4.63 --$50.88 Sensors Document Stations HP Water Heater 10 to 50 $4,000.00 25%$1,000.00 $100.00 --$1,100.00 MBH Motors I to 5 HP $88.00 75%$66.00 $6.60 $25.00 $97.60 Motors 25 to 100 HP $558.00 50%$279.00 $27.90 $25.00 $331.90 Motors 7.5 to 20 HP $227.00 50%$113.50 $11.35 $25.00 $149.85 LED Exit Signs Electronic $60.00 50%$30.00 $3.00 --$33.00 Fixtures (Retrofit Only) LED Auto Traffic Signals $90.00 50%$45.00 $4.50 -$49.50 LED Pedestrian Signals $140.00 50%$70.00 $7.00 -$77.00 VFD HP 1.5 Process $1,445.00 75%$1,083.75 $108.38 -$1,192.13 Pumping VFD HP 10 Process $2,860.00 25%$715.00 $71.50 $25.00 $811.50 Pumping VFD HP 20 Process $4,515.00 25%$1,128.75 $112.88 $25.00 $,266.63 Pumping Vending Equipment $195.50 25%$48.88 $4.89 $25.00 $78.76 Controller Efficient Refrigeration $35.00 25%$8.75 $0.88 --$9.63 Condenser ENERGY STAR $150.00 25%$37.50 $3.75 --$41.25 Commercial Solid Door Freezers -Less Than 20ft3 ENERGY STAR $400.00 75%$300.00 $30.00 --$330.00 Commercial Solid Door Freezers-20 to 48 ft3 ENERGY STAR $250.00 25%$62.50 $6.25 --$68.75 Commercial Solid Door Refrigerators-Less Than 20f3 ENERGY STAR $500.00 50%$250.00 $25.00 --$275.00 Commercial Solid Door Refrigerators-20 to 48 ft3 Black &Veatch 11-13 February 2010 SECTION 11 DSM/EE RESOURCES ALASKA RIRP STUDY Table 11-6 (Continued) Input Assumptions -Commercial DSM/EE Measures Rebate as %of Total per Incremental Incremental Unit ;Equipment Equipment Rebate Administrative Vendor or Program Commercial Measures Cost (S)Cost Amount ($)Costs (10%)Other Costs Costs ENERGY STAR Ice $600.00 50%$300.00 $30.00 --$330.00 Machines-Less Than 500 Ibs ENERGY STAR Ice $1,500.00 50%$750.00 $75.00 --$825.00 Machines-500 to 1,000 lbs ENERGY STAR Ice $2,000.00 25%$500.00 $50.00 --$550.00 Machines-More Than 1,000 lbs Pumps HP 1.5 $350.00 75%$262.50 $26.25 $25.00 $313.75 Pumps HP 10 $332.00 25%$83.00 $8.30 $25.00 $116.30 Pre Rinse Sprayers $35.00 25%$8.75 $0.88 --$9.63 Exterior HID Replacement $1,064.00 50%$532.00 $53.20 -$585.20 Above 250W to 400W HID Retrofit High Bay 3L TSHO $277.60 73%$202.65 $20.26 --$222.91 Replacing 250W HID High Bay 4LTSHO $289.60 50%$144.80 $14.48 --$159.28 Replacing 400W HID High Bay 6L TS5SHO $447.60 75%$335.70 $33.57 --$369.27 Replacing 400W HID High Bay Fluorescent $257.60 25%$64.40 $6.44 -$70.84 6LF32T8 Replacing 400W HID High Bay Fluorescent $497.60 25%$124.40 $12.44 --$136.84 8LF32T8 Double Fixture Replace 1,000W HID CFL Fixture $78.92 25%$19.73 $1.97 --$21.70 CFL Sciew-in $30.14 25%$7.53 $0.75 --$8.29 Daylight Sensor Controls $4,000.00 25%$1,000.00 $100.00 --$1,100.00 Central Lighting Control $3,700.00 50%$1,850.00 $185.00 --$2,035.00 Occupancy Sensors-Under $144.00 50%$72.00 -$7.20 --$79.20 500 W Low Wait T8 Lamps $6.24 50%$3.12 $0.31 _-$3.43 3 Lamp T5 Replacing T12 $200.16 50%$100.08 $10.01 "-$110.09 4 Lamp TS5HO Replacing $306.06 50%$153.03 $15.30 --$168.33 T12 Black &Veatch 11-14 February 2010 SECTION I1 DSM/EE RESOURCES ALASKA RIRP STUDY Table 11-6 (Continued) Input Assumptions -Commercial DSM/EE Measures Rebate as %of Total per Incremental Incremental Unit Equipment Equipment Rebate Administrative Vendor or Program Commercial Measures Cost (S)Cost Amount (S)Costs (10%)Other Costs Costs HPT8 4ft 3 Lamp,T12 to $138.16 50%$69.08 $6.91 --$75.99 HPT8 HPT8 4ft 4 Lamp,T12 to $147.06 50%$73.53 $7.35 -$80.88 HPT8 TI2HO 8ft 1 Lamp $113.35 50%$56.68 $5.67 -$62.34 Retrofit to HPT8 T8 4ft 2 Lamp T12HO 8ft 2 Lamp $147.06 50%$73.53 $7.35 --$80.88 Retrofit to HPT8 T8 4ft 4 Lamp T8 4ft 3 Lamp $130.16 75%$97.62 $9.76 $107.38 T8 4ft 4 Lamp $138.06 75%$103.55 $10.35 --$113.90 T8 HO 8 ft 2 Lamp $151.42 75%$113.57 $11.36 -$124.92 Window Film $153.81 50%$76.91 $7.69 -$84.60 Refrigerant Charging $38.36 50%$19.18 $1.92 3 $21.10 Correction VFD Fan $155.96 25%$38.99 $3.90 -$42.89 VFD Pump $149.14 25%$37.28 $3.73 -$41.01 Refrigeration $113.00 30%$33.90 $3.39 -$37.29 Commissioning Strip Curtains for Walk-$200.00 35%$70.00 $7.00 --$77.00 ins-Freezer Black &Veatch 11-15 February 2010 SECTION 11 DSM/EE RESOURCES ALASKA RIRP STUDY 11.5 DSM/EE Program Delivery As will be discussed in Section 13,the RIRP models selected all DSM/EE measures for inclusion in each of the four alternative resource plans,based upon the costs incurred and savings achieved from the utility persepctive.The successful implementation of these resources,however,is dependent on several factors. First,it is important that a comprehensive technical and achievable potential study be completed,including the comprehensive cost-effectiveness evaluation of the available DSM/EE measures and using Railbelt- specific information. Second,it is Black &Veatch's belief that a regional entity should be formed to develop and deliver DSM/EE programs on a regional basis,in close coordination with the six Railbelt utilities.This entity could be the proposed GRETC organization or another entity focused exclusively on DSM/EE programs. This was addressed in the REGA Study Final Report,which included the following observations regarding the potential deployment of DSM programs by the Alaska Railbelt utilities: "..,the Railbelt utilities have limited experience with the planning,developing and delivering ofDSM and energy efficiency programs.To date,the majority of efforts in the Railbelt region and the State as a whole have been focused on the implementation of home weatherization programs.These programs can significantly reduce the energy consumption within individual homes;however,given the limited saturation ofelectric space heating equipment and the general lack of air conditioning loads,the potential for DSM and energy programs are limitedfrom the perspective ofthe Railbelt electric utilities. An implementation issue that needs to be addressed is whether the development and deployment of DSM and energy efficiency programs throughout the Railbelt region should be accomplished by the individual Railbelt utilities or whether a regional approach would result in more efficient and cost-effective deployment ofthese resources.Additionally,given the fact that the total monthly energy bills paid by residential and commercial customers in the Railbelt have increased significantly in recent years and given that natural gas is the predominant form ofspace heating within the majority ofthe Railbelt region, it may be appropriate for the electric utilities to workjointly with Enstar to develop DSM and energy efficiency programs that would be beneficial to both.This would create economies ofscope for the region and reduces the delivery costs ofDSM and energy efficiency programs.”(pps.49-50) Third,the Railbelt electric utilities should work closely with Enstar and the AHFC with regard to the implementation of DSM/EE programs. These points are discussed further in Section 16. Black &Veatch 11-16 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY 12.0 TRANSMISSION PROJECTS The Railbelt transmission system included in this study consists of six independent utilities loosely interconnected by a transmission system that is constrained and inadequate to support interconnected operation envisioned by the GRETC concept of robust reliable service for all Railbelt utilities.One of the primary objectives of the current RIRP is to develop a transmission system that can support the economic development and operation of an integrated Railbelt system. 12.1 Existing Railbelt System The Alaskan transmission infrastructure is relatively new compared with other transmission and distribution facilities in the lower-48 states.In the 1940s,the Chugach,GVEA,HEA,MEA,ML&P,and SES systems were formed to provide electric service to consumers within their respective service areas.The Doyon service area which is not explicitly included in this study was established in 2007 to serve the loads of the US Army bases at Fort Greely,Fort Wainwright in Fairbanks and Fort Richardson in Anchorage. These utilities developed and operated independently of each other and were successful in providing reasonable service to businesses and residences.In 1984,the State of Alaska constructed the Anchorage- Fairbanks Intertie,and Chugach and ML&P strengthened their interconnection allowing improved operation and reliability among the utilities.In that same year,the State of Alaska and the Railbelt utilities established the Alaska Intertie Agreement.This agreement has served as the operating contract between all utilities for the past 25 years,but will expire within the next two years.Also,the expiration of the thirty-year power sales agreements between Chugach,MEA and HEA will terminate in 2014.Presumably,following the expiration of the current power sales contracts,each of the Railbelt utilities will assume the responsibility of planning the transmission system to serve its own requirements.However,the planning,repair,and construction of transmission facilities required to continue to provide economic and reliability benefits to all utilities does not fall under the responsibility of any of the specific Railbelt utilities.The expiration of the Chugach power supply contracts and the Intertie Operating Agreement leaves a void in the planning and operation of critical transmission assets required for inter-utility power transfers and reliability improvements.Changing generation plans may decrease the importance of transmission to a single utility,but the transmission will remain critical to the interconnected system.However,with the changing power supply conditions which include heightened environmental awareness,fuel cost volatility and availability,and the aging generation plants of the Railbelt,it became evident that investigation of a more coordinated approach of the Railbelt utilities to planning and operating together could provide significant benefits for the people of Alaska.The first obstacle to the goal of coordinated planning and operation is the lack of an entity that has the responsibility and authority for the planning and operation of the transmission system utilized to interconnect the systems of individual utilities.The second obstacle to coordinated generation planning and operations is the lack of an adequate transmission infrastructure to support joint economic and reliable operations.This section focuses on the transmission projects that may be necessary for the Railbelt utilities to construct a reliable transmission system that is capable of providing transfers of firm and economy energy transactions and also allow for the economic planning of firm generation capacity and reserves. The existing Railbelt utilities cover the Fairbanks area,the Anchorage area,and the Kenai Peninsula and are interconnected between Fairbanks and Anchorage via a single transmission line known as the Anchorage- Fairbanks Intertie,while Anchorage and the Kenai are connected by a single transmission line known as the Anchorage-Kenai Intertie.These existing facilities are discussed in Section 4. Black &Veatch 12-1 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY The existing Railbelt transmission system,as well as the loads supplied in each area,is presented in Figure 12-1.A significant issue affecting the existing Railbelt system results from the constrained transmission infrastructure interconnecting the utilities.This existing transmission infrastructure results in the system operation being severely constrained by stability and power transfer limits.As a result of being stability constrained,individual transmission projects constructed to increase transmission capacity cannot be fully loaded to their thermal limits and the economic sharing of reserves between utilities is also inhibited. This void cannot be filled by the existing planning and development strategy of independent utilities but should be tackled by an integrated development of the transmission system by an independent entity responsible for the planning,construction and operation of the interconnected system. Figure 12-1 Railbelt Transmission System Overview GVEA AreaLoal 238 WIW MEA Area Load '146 MIW N Anchotage |----Area Load - 412 hIW Kenai Aréa Load =Log a HEA'SES "97 MW Black &Veatch 12-2 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY 12.2 The GRETC Transmission Concept One of the goals of the current study is to facilitate the development of generation and transmission systems in the most economic and reliable manner possible.By coordinating the needs of all utilities,common problems such as aging generation,unequal reliability and more levelized power supply rate structures can be developed for the Railbelt region.By assessing the problems of the system as a whole,projects that may be more economic and offer a more stable rate structure for the entire Railbelt may be developed,bringing rate stability and a dependable power cost to the entire Railbelt region. In order to provide an organization capable of undertaking the needs of the Railbelt utilities,the Legislature is considering the formation of GRETC which would become the entity charged with planning,constructing, and operating the integrated energy and transmission system to serve the Railbelt utilities. The corporate identity of GRETC has yet to be determined.Several organizational structures have been evaluated and will require further study.The purpose of this study is not to identify the structure of GRETC as an organization,but to identify its role in the Railbelt electrical system.GRETC's role in the Railbelt system is envisioned as follows: Planning GRETC will serve as the entity responsible for performing system studies,analysis,and evaluation of transmission projects,and will be required to: e Develop plans to repair and replace (R&R)the existing transmission system as required to maintain the service and reliability of the existing system such that the future system will be at least no worse than the reliability and transfer capacity that exist today. e Develop plans to repair,replace and maintain the communication and control system required to ensure system reliability and economic operation. e Develop long-range transmission plans (LRTP)to identify transmission projects required over the next 50 years to provide the same or comparable reliability and service to all Railbelt utilities. e Develop generation and transmission plans such that at the completion of each plan,no single contingency within the GRETC system results in the loss of firm load. e Develop mid-range transmission plans (10-Year Plan,or TYP)to prioritize the transmission projectsidentifiedintheLRTPandR&R plans into a single plan that is consistent with the requirements of the Railbelt utilities and within the financing capability of GRETC. e Develop and maintain rolling Five-Year Plans (F YP)that identify the projects to be constructed within the next five years as outlined in the TYP.Develop project schedules,including permitting and right-of-way (ROW)schedules for long-term projects. e Develop design criteria for each project identified in the plan,develop the design,construction management,construction,and close-out schedules and budgets. e Administer design,construction management,and construction contracts associated with the projects. Operation e GRETC should be responsible for operation of the transmission and generation system required to deliver power between GRETC generation or GRETC delivery points to Railbelt utilities to ensurethateachutility,over the long-term planning horizon receives comparable service in terms of transmission reliability,access to reserves,and transmission costs. Black &Veatch 12-3 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY e GRETC should be responsible for the economic operation of the Railbelt generation system,ensuring that power throughout the Railbelt is produced in the most economical manner possible. e GRETC should be responsible for allocation of reserves to ensure system reliability is maintained at no worse than existing levels. In developing projects for the integrated operation of the Railbelt transmission system the following criteria were adopted: e The transmission system will be upgraded over time to remove transmission constraints that currently prevent the coordinated operation of all the utilities as a single entity.The transmission planning period is 50 years.The ability of GRETC to construct the transmission improvements identified in this study within any certain time period is unknown.The prioritization of the transmission projects and their subsequent schedule for construction cannot be completed in the scope of this study.As such,this study attempts to identify required transmission improvements for evaluation in future studies. e The study includes all the utilities'assets,69 kV and above,that are used to transmit power from a GRETC generator to the Railbelt system or between significant load areas.These assets,over a transition period,may flow into GRETC and form the basis for a phased upgrade of the system into a robust,reliable transmission system that can accommodate the economic operation of the interconnected system.Utility assets,69 kV and above,that are not used to transmit power between GRETC generation or between GRETC transmission delivery points may or may not be transferred to GRETC. e Generation assets not utilized by GRETC for power delivery,reserves or other uses may be retained by the individual utilities for their own uses such as emergency generation,load-side generation,load serving etc. e The study assumes that all utilities participate in GRETC with transmission and generation planning being conducted on a GRETC (i.e.,regional)basis.The common goal would be the tight integration of GRETC with the utilities for planning and operations as previously described. 12.3.Project Categories . The projects selected for consideration were based on the overall GRETC concept of developing a robust, reliable transmission system that can accommodate the economic operation of the Railbelt integrated system. Discussions were held with the utilities and a list of potential projects was developed for further consideration.The projects were classified in the following categories: e Transmission systems that need to be replaced because of age and condition (Category 1) ¢Transmission projects required to improve grid reliability,power transfer capability,and reserve sharing (Category 2) ¢Transmission projects required to connect new generation projects to the grid (Category 3) e Transmission projects to upgrade the grid required by a new generation project (Category 4) In developing the system,reliability remains a significant focus.Redundancy is one way to increase reliability,but may not be the only way to improve or maintain reliability as indicated in the analysis below. 12.4 Summary of Transmission Analysis Conducted A transmission analysis consisting of power system load flows and N-1 analysis was conducted to determinethedeficienciesoftheexistingsystem.In the existing transmission system,constraints preclude the economic development of large projects that are common to the entire Railbelt.Lack of transfer capacity andsinglecontingencyintertiespreventprojectsbeingdevelopedinanyoneareatoservefirmpowertotheentire region.Improvements to the power system required to alleviate overloads,transfer limitations and address Black &Veatch 12-4 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY N-1 contingencies under the existing generation and the generation configurations developed as part of this plan were identified as projects and evaluated in power flow studies to determine if the resulting system satisfied the main objectives and criteria set for the RIRP.Identified projects were evaluated to determine if the system could supply the projected load under economic generation dispatch without violating the transmission criteria of no loss of load or voltage violations under the N-1 criteria as well as to establish a redundant system with a 230 kV backbone through the Railbelt.Similar to the generation alternatives,this plan has identified possible projects that are required to meet the goals and objectives of GRETC. Prioritization and detailed development of the projects should be completed concurrent with the subsequent generation plan to provide a comprehensive and coordinated approach to serving the Railbelt utilities. 12.4.1 Cases Reviewed The base case for 2060 was evaluated with all the projects included,along with the load forecast for 2060 as developed for the RIRP.The generating resources selected by the RIRP for the different scenarios were also modeled for the respective cases.With each case developed,the generating resources were dispatched economically and several contingencies evaluated to determine if there were any constraints on the Railbelt transmission system.A review of the recent projects designed and constructed for the Railbelt utilities,has revealed that many projects have been designed at a higher voltage than the existing voltage of the line.In many cases,the circuits have been rebuilt to a higher voltage but placed back in operation at the same voltage awaiting an opportunity to increase the capacity of these circuits when appropriate.These lines,in many instances,have been insulated to operate at 230 kV from the existing 115 kV or 138 kV levels.To capture the benefits of increased transmission capacity,as well as to capture the benefits of standardizing transmission voltages at a specific level thus controlling operation and maintenance costs going forward,standardization of the Railbelt transmission grid at 230 kV was determined by Black &Veatch,EPS,and the Railbelt utilities to be appropriate.This key concept of developing a reliable transmission backbone for the Railbelt occasionally results in projects that are designed and constructed at a higher voltage but operated at a lower voltage until the transition to the higher voltage can be facilitated or justified This is particularly applicable in the repair and replacement of existing transmission facilities.Portions of the existing Railbelt transmission system are not recommended to be included in the 230 kV upgrade due to difficulties in obtaining ROW and other considerations.As a result,portions of the existing 115 kV system on the Kenai,ML&P and MEA areas would remain at 115 kV and portions of the Chugach and GVEA systems would remain at 138 kV throughout the life of this plan. In accordance with the ideals of GRETC,some of the existing transmission systems would not be incorporated into the GRETC system,but would remain with the local utility to own,operate and maintain for its own use. Since the repair and replacement of the existing transmission facilities is scheduled over many years,it is likely that that the initial portions of a transmission line replacement project will be operated at its existingvoltageformanyyearsuntiltheentiretransmissionlineisreplacedandajustificationtoconvertanyrequiredsubstationsandoperatethetransmissionlineatitsultimateconstructionvoltageiswarranted. The above analysis was based on load flow evaluations with consideration given to possible stability issues. The development of the final transmission plan will require more detailed studies,analysis and integrationwiththeselectedgenerationplan.The projects that are interrelated with generation scenarios will require evaluation concurrent with more detailed generation scenarios.Projects that are independent of generation scenarios can undergo detailed studies,including stability analysis and detailed evaluation prior to selection of the preferred generation scenario.The results of these future studies may result in some changes to the projects identified. Black &Veatch 12-5 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY 12.4.2 Results of 2060 Analysis The transmission analysis included normal and N-1 contingency analysis of all transmission branches in the Railbelt,with all the generating resources dispatched economically.The power flow analysis was evaluated to determine if any overloads or voltage violations of any of the transmission lines within the Railbelt system occur during both normal and N-1 conditions. Limited stability studies were completed to evaluate the ability of the Railbelt system to operate for select cases.As future studies refine transmission and generation projects,additional power flow and stability studies will be required to evaluate the requirements of the transmission system. 12.5 Proposed Projects Project A-Bernice Lake Power Plant to International 230 kV Transmission Line (Southern Intertie) (New Build -Category 2) The Bernice Lake Power Plant to International Substation 230 kV project is a new 230 kV line between the Anchorage area and the Kenai.The project commences at the ITSS substation,crosses Turnagain Arm via submarine cable and an overhead crossing of Fire Island and proceeds overhead along the coastline to the Bernice Lake Substation.The project is comprised of a total of 15 miles of submarine cable and 47 miles of overhead transmission line.The project is intended to follow the recommended route included in the Environmental Impact Statement managed by Chugach. The single transmission line between Anchorage and Kenai prevents the economic construction of generation in the Railbelt,and places constraints on both the amount of power that can be exported from the Kenai area and the amount of power that can be imported into the Kenai area. In addition to the export and import of energy to the Kenai,the ability to utilize reserves across this single transmission line is a severe restriction to the economic operation of the system as a whole.For instance,if the Bradley reserves are increased to 50 MW,the ability of the northern utilities to utilize these additional reserves is questionable since the transfer of these reserves requires transmission across the single tie-line that is already transferring real power to the northern utilities and the transfer of these reserves is beyond the stability limit of the transmission system. In order to meet the planning criteria that no N-1 contingency results in the loss of load from the GRETC system,without a second tie-line,the generation on the Kenai has to be severely constrained to limit power transfers into the Kenai area.This constraint increases both capital and operating costs for the Railbelt, forcing the location of new generation on the Kenai as well as new generation in the northern parts of the system to supply reserves that are not transferable across the existing transmission line. This project is the second intertie between the areas and is required to increase the transfer limit between the two areas.The current transfer limit between the areas is limited due to stability considerations to 75 MW. The steady-state limit is constrained to 105 MW (winter)due to voltage collapse while the thermal limit fortheexisting115kVtransmissionlineisapproximately185MW(winter)and 95 MW (summer).This projectisaCategory2projectrequiredforreliabilityandincreasedtransfercapability.Figure 12-2 presents the proposed project.More investigation is required to determine detailed transmission characteristics and routing.: Black &Veatch 12-6 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Figure 12-2 Bernice Lake Power Plant to International 230 kV Transmission Line (New Build) _}<>-x)3 ackennd A ee Lo Los 4 ennié apZz}rrokieeryeeFre4sO Black &Veatch 127 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project B -Soldotna to Quartz Creek 230 kV Transmission Line (Repair and Replacement -Category 1) This project is the upgrade of the existing 54-mile long,115 kV transmission line between Soldotna and Quartz Creek substations.This line was constructed in 1959 and is in very poor condition,suffering from frost jacking and age deterioration.The transmission line is a continuation of the Anchorage -Daves Creek line and results in the same stability and reliability constraints as the Project 1-line described above.Because of the importance of this intertie to the integrated operation of the Railbelt system,this line is proposed to be rebuilt for operation at 230 kV.The line would continue to operate at 115 kV until conversion to 230 kV operation is warranted.Figure 12-3 presents the proposed upgrade. Figure 12-3 Soldotna to Quartz Creek 230kV Transmission Line (Repair and Replacement) -Yor :w Crook a Black &Veatch 12-8 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project C -Quartz Creek to University 230 kV Transmission Line (Repair and Replacement -Category 1) This is the section of the existing 115 kV Kenai Intertie owned by Chugach and was constructed in 1959 and consists of two sections.The first section is from Quartz Creek to Daves Creek and is approximately 7.7 miles long.The second section is from Daves Creek to University and is approximately 68.2 miles long. Portions of this line have been upgraded over time however approximately 65 percent of this wood pole line is over 50 years old and is subject to avalanches and severe weather conditions.It will require significant rebuilding to keep it in service over the life of this plan.The line is considered a critical component of the transfer capability between the Anchorage and Kenai areas and is also required for reliability and reserve sharing.The current transfer limit between the areas is limited due to stability considerations to 75 MW.The steady-state limit is constrained to 105 MW due to voltage collapse while the thermal limit for the existing 115 kV transmission line is approximately185 MW in the winter and 95 MW in the summer.The line is recommended to be upgraded to 230 kV over the life of this plan to increase the stability limit transfer capability and reserve sharing between the areas.Figure 12-4 presents the proposed upgrade. Figure 12-4 Quartz Creek to University 230kV Transmission Line (Repair and Replacement) ors)war PE enaé f.”:moO.-J Nee SL ee mee pheelugaPowerPlantie'es2 f ee _al aa §Ska qng” ry4 "'een |University a7 "Jewel Lake ae tg i a kw YY Soldotna-SVC Sand Stertin i"woes amee | Black &Veatch 12-9 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project D -Douglas to Teeland 230 kV Transmission Line (Repair and Replacement -Category 2) The Douglas to Teeland line was originally constructed for operation at 115 kV and currently operates at 138 kV and serves as the final line section of the Anchorage-Fairbanks Intertie. The construction of the Lorraine-Douglas line described below and the upgrade of the Anchorage-Fairbanks Intertie to 230 kV requires the upgrade of this line section to 230 kV to form a transmission loop between Lorraine-Teeland and Douglas stations.The proposed loop will eliminate single contingency outages to the southern portion of the Intertie and permits higher transfer limits between load and generation areas.The line should be constructed following the completion of the Lorraine -Douglas line section to mitigate the impact of the line's construction on energy transfers between the Anchorage and Fairbanks areas.Figure 12-5 presents the proposed upgrade. Figure 12-5 Douglas to Teeland 230 kV Transmission Line (Repair and Replacement) Bs ,Willow -i./SCCe e fyaDouglasPa_/ e 9 t a(ver Fanaina dow Lakes fr <1 Electric¢ rview of AESip LESELREI, Black &Veatch 12-10 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project E -Lake Lorraine to Douglas 230 kV Transmission Line (New Build -Category 2) Pt.MacKenzie substation is a key component in the Railbelt transmission grid,serving as the hub of electrical power generated at Beluga and providing interconnections to all other utilities.Teeland substation currently serves as the sole terminus of the Anchorage-Fairbanks Intertie and also as the primary source of power for MEA's consumers in the Palmer-Wasilla area. The Pt.MacKenzie-Teeland transmission line is the heaviest loaded line in the Railbelt,often carrying over 200 MW during peak months.By comparison,the Anchorage-Kenai Intertie is constrained to no more than 75 MW during its peak loading and the Anchorage-Fairbanks Intertie is restricted to less than 85 MW.Under both summer and winter loading conditions,the loss of the Pt.MacKenzie-Teeland transmission line results in unstable conditions in the Anchorage-Kenai transmission system during certain generation conditions. This instability is in addition to the blackout of approximately 25 percent of the Railbelt consumers caused by the line outage.The unstable conditions could result in widespread blackouts from Fairbanks to Homer.In the worst case,the system will suffer a complete blackout,with a risk of damage to Railbelt generators. The construction of a new substation at Lake Lorraine,with a new transmission line to Douglas Substation provides a transmission loop between Pt.MacKenzie,Lake Lorraine,Teeland and Douglas substations will eliminate the largest single contingency in the Railbelt system.Following the completion of the Lorraine- Douglas line,the loss of any single transmission line in this loop will not result in widespread outages in the Fairbanks and Mat-Su areas. The construction of the Lake Lorraine-Douglas transmission line has a dramatic impact on the reliability of service to the Railbelt consumers.The elimination of a single point of failure for the entire electrical system in the summer conditions is achieved.In both winter and summer conditions,outages to all consumers in the Palmer -Wasilla areas and a significant number of consumers in the Fairbanks area by the failure of a single transmission line are eliminated.The stability margin for the winter conditions is improved,but unlike the summer conditions,the risk of system instability is not eliminated. This project will also require the upgrade of the existing SVCs at Teeland,Healy and Gold Hill.These SVCs were installed in 1984 as part of the original Intertie construction.The SVC components are no longer manufactured or available from third party vendors.Spare parts have been exhausted and replacement components cannot be obtained.Loss of the SVCs is critical to the operation of the Intertie and the economictransferofbothenergyandcapacitybetweenAnchorageandFairbanks.Figure 12-6 presents this proposed project. Black &Veatch 12-11 February 2010 SECTION 12 TRANSMISSION PROJECTS Figure 12-6 Lake Lorraine to Douglas 230 kV Transmission Line (New Build) fC-_|Sutton-Alpine§Corpo2Sadonamtroaapdtods\Nei ALASKA RIRP STUDY \innaingA 3 4 4 3 .: akes 7Fanmiponk yy MUR oe yy .+,af ' : ¥irc '<a' 4,EklutnaLTcomme'i Knik River =". ob Asem,SeesORE -" wo '. *"'LT aot &'.re awe"{me.7 io .La wad Black &Veatch 42-12 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project F -Douglas to Healy 230 kV Transmission Line (Upgrade -Category 2) The Alaska Intertie includes a 170-mile,345 kV transmission line between Willow and Healy and voltage control devices at Teeland,Healy and Gold Hill Substations.The line built with State grant funds,went into operation in 1985,and is operated at 138 kV. The line is the state-owned portion of the 300 mile Anchorage to Fairbanks transmission system.The Intertie allows GVEA to purchase lower cost energy from Anchorage and the Kenai generated from natural gas and the Bradley Lake hydroelectric project.Chugach and ML&P generate revenue from the sale of economy energy to GVEA.The line also allows reserves,both operating and non-operating to be shared between the northern and southern areas of the system. The ability to import power into the Fairbanks area is limited to the current stability limit of approximately 85 MW.Although stability aids could increase this power transfer capability,the amount of power transferred over the intertie would still be limited to approximately 85 MW as this is considered the maximum allowable import limit into the Fairbanks area to survive the N-1 contingency of the loss of the intertie. The proposed transmission line upgrade will allow power transfers to increase from the existing limit of approximately 85 MW and will eliminate the loss of load associated with an N-1 contingency and bring the Fairbanks GRETC area into compliance with the planning criteria following the completion of the second transmission line.Figure 12-7 presents the proposed transmission line. Figure 12-7 Douglas to Healy 230 kV Transmission Line (Upgrade) crit WHOL «Th. De "x tgl oeWi \wt |C: Black &Veatch 12-13 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project G -Douglas to Healy 230 kV Transmission Line (New Build -Category 2) An additional line between the Douglas and Healy substation is required to meet the reliability criteria for no loss of load for any N-1 condition and to increase the transfer capability between the northern and central portions of the Railbelt.The ability to import power into the Fairbanks area is limited to the current stability limit of approximately 85 MW over the single transmission line.Although stability aids could increase this power transfer capability,the amount of power transferred over a single intertie would still be limited to approximately 85 MW as this is considered the maximum allowable import limit into the Fairbanks area to ensure survival following the N-1 contingency loss of the intertie. The proposed transmission line will allow power transfers to increase from the existing limit of approximately 85 MW and will eliminate the loss of load associated with an N-1 contingency and bring the Fairbanks GRETC area into compliance with the planning criteria following the completion of the second transmission line.The proposed route would parallel the existing intertie.A significant portion,but not all of the right-of- way,of the existing intertie will accommodate an additional line.The exact routing and characteristics of the transmission line,along with any associated changes in compensation at the terminals of the line will be determined in future studies.Figure 12-8 presents the proposed new line.Ifthe preferred generation plan includes a Susitna option,this line configuration will change depending on the selected Susitna alternative. Figure 12-8 Douglas to Healy 230 kV Transmission Line (New Build) xe 7A.FALXBANKS (she De Black &Veatch 12-14 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project H -Eklutna to Fossil Creek 230 kV Transmission Line (Upgrade -Category 2) The Eklutna and Briggs substations are interconnected by a 230 kV double circuit line with one circuit used to supply multiple MEA distribution substations at 115 kV.The other circuit is not connected to local distribution substations and can function as a direct connection from Eklutna to Fossil Creek.From Fossil Creek the 230 kV line currently connects to the ML&P Plant 2 230 kV substation while the 115 kV line connects to the 115 kV substation at ML&P's Plant 2 generation plant.The construction of a 230 kV/115 kV substation at Fossil Creek would allow this line section to serve an express 115 kV line to Eklutna station while the tapped line would be used to serve local load.As part of the long range goals,the express feeder would be converted to 230 kV with a corresponding 230 kV/115 kV substation at Eklutna.This project, along with upgrade of the MEA 115 kV system (Projects M and N),will be part of a redundant 230 kV path from Beluga to Anchorage.This project includes the construction of a 230 kV/115 kV substation at Fossil Creek and Eklutna to serve the MEA 115 kV system.Figure 12-9 presents the proposed line from Eklutna to the Fossil Creek substation. This project will also require the construction of a 230 kV line section from ML&P Plant 2 to University station for N-1 contingencies at Plant 2 and to support the ML&P and Chugach 138 kV and 115 kV systems as described in other project summaries. The project may consist of a staged approach resulting in the 115 kV systems in the MEA area continuing to operate at 115 kV for many years while the infrastructure continues to develop. Figure 12-9 Eklutna to Fossil Creek 230 kV Transmission Line (Upgrade) Black &Veatch 12-15 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project I-Healy to Gold Hill 230 kV Transmission Line (Repair and Replacement -Category 1) The existing Healy to Gold Hill 138 kV line was constructed and placed in service in 1968.This line serves as one of two paths between Healy and Fairbanks and delivers firm and economy power to Fairbanks from the Healy,Anchorage,and Kenai areas.In 2007,the GVEA Long Range Planning Study recommended that this line be rebuilt in stages between 2017 and 2021.The study further recommended that this line should be upgraded to 230 kV although it would initially be operated at 138 kV.When the transmission plan is completed,the existing 138 kV line becomes the weak link in the transmission system and limits the ability to import power into Fairbanks following the N-1 loss of the Northern Intertie.This project is required to meet the GRETC concept of providing a reliable transmission system backbone throughout the Railbelt. Figure 12-10 presents the proposed upgrade. Figure 12-10 Healy to Gold Hill 230 kV Transmission Line (Repair and Replacement) 2 Oe Kemet hey q GoldHl eens 34g wd aks sfrtenewaeoDMsonat. ) tebibad,ne eet me aad sine 1 Golden Valley Electric Association : LA ' Year meena peneNeer meee rte =eager atoed fet md Pit ow [a rk eat lek Rell ek etn it sel tee tome id CranBOStees tebe aia a datetaete sty Los ae satind Beka a navel Black &Veatch 12-16 February 2010 SECTION 12 |TRANSMISSION PROJECTS ALASKA RIRP STUDY Project J -Healy to Wilson 230 kV Transmission Line (Upgrade -Category 2) The existing Healy to Wilson line was constructed in 2005 at 230 kV and presently operated at 138 kV.To increase the power transfer capability of the transmission system above its current limits,the line is required to be operated at 230 kV.Operation of this line along with the Healy to Gold Hill line at 230 kV is a part of the phased development of a reliable 230 kV backbone of transmission facilities.Figure 12-11 presents the proposed upgrade. Figure 12-11 Healy to Wilson 230 kV Transmission Line (Upgrade) "4 aF ee wegAis MoyGoldHilln,ahead eat «EE ted heemrewas LWilson "Botenné We tbe waleBM fee Pe ea aA ve Bee Om teensems } Black &Veatch 12-17 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project K -Soldotna to Diamond Ridge 115 kV Transmission Line (Repair and Replacement -Category 1) The Soldotna to Diamond Ridge 115 kV line serves several distribution substations on the Kenai from Ski Hill,Kasilof,Anchor Point,Diamond Ridge,and Fritz Creek and as part of a transmission loop from Soldotna Substation to Bradley Lake generation facility.The older of the two lines comprising the transmission loop is in poor condition and has a very small conductor size.The small conductor size on this line segment results in high impedance,high losses and limited capacity transfer over the line.Outage of the express Soldotna to Bradley Lake 115 kV line results in low voltages and line overloads in the southern Kenai and restricts the Bradley Lake project to an output of less than 60 MW in summer months.This proposed project will rebuild the line with larger conductor at the existing transmission line voltage.Figure 12-12 presents the proposed upgrade. Figure 12-12 Soldotna to Diamond Ridge 115 kV Transmission Line (Repair and Replacement) :ae p a cn WM ft «_|Diaper Sy Diamond Ride my ras en /rr rn Black &Veatch 12-18 February 2010 SECTION 12 TRANSMISSION PROJECTS Project L-Lawing to Seward 115 kV Transmission Line (Upgrade -Category 1) ALASKA RIRP STUDY The City of Seward is served by a 115 kV line from Daves Creek on the Kenai to the Lawing substation.The voltage is then stepped down to 69 kV and the line continues into the City of Seward.Most of the 69 kV line section was replaced and upgraded to 115 kV insulation,but left to operate at 69 kV.Some distribution stations and the short line to Spring Creek will need to be converted from 69 kV to 115 kV.The transmission line runs primarily through the Department of Forestry lands with sections along the Alaska Railroad.The City of Seward is a full-requirements customer of Chugach and has a winter peak load of approximately 10 MW.Figure 12-13 presents the proposed upgrade. Figure 12-13 Lawing to Seward 115 kV Transmission Line (Upgrade) ofnh ''-|Nee Daves Creek |4 'mons -'4 oa '4G|be ae aa {7neaa'.WO bd 10 "Ey he NY me 3 4 oywamsnenatmearyeJMCrartzCreek:y we Se'NW YZ )tan .'.,\,+in bt |nn 7aCraPaint”\a =7 'i ' 'rawwetLawingVytS\cq,-°_mrose |phy oy m4 -=-;on E .ve 4 ..{ Z ,i on ao,ae r '.ee - "ws F'Kenai Peninsula ..My oepouessinay(aaa Mae Creek 8 7)<a CS enn AG Me ard-boas i iN -oNe :; ;ae wot "tVe5aJeSewardSe,,Aare Soar3/aA f , os u oy .f -yew io ;if? te.Lt 4 io i ep Se 5 CO ar ou Black &Veatch 12-19 February 2010 SECTION 12 | TRANSMISSION PROJECTS ALASKA RIRP STUDY Project M -Eklutna to Lucas (Hospital Substation)115 kV/230 kV Transmission Line (Repair and Replacement -Category 1) The existing Eklutna to Lucas line was originally built as part of the Eklutna Project in 1955 and needs to be rebuilt due to the age and condition of the line.The line requires upgrading or an additional line to meet the requirements of the system over the life of this plan.The optimal construction of this project should be determined in conjunction with the preferred generation plan.The deficiencies of the system can be addressed in a number of different manners.An express 115 kV line similar to the Briggs-Eklutna line eliminates low voltage conditions and provides reliability improvements to meet the GRETC requirements. The express feeder should be insulated to 230 kV to serve as a possible tie to the Teeland station. Alternatively,the existing line could be rebuilt at 230 kV converting all of the MEA substations to 230 kV,or finally the express feeder could be built and operated at 230 kV with a corresponding 230 kV/115 kV substation in the Lucas or Hospital Sub area.The final configuration of the project should be determined in future studies following determination of the preferred generation plan.Figure 12-14 presents the proposed project. Figure 12-14 Eklutna to Lucas 230 kV Transmission Line (Repair and Replacement) ar mHsshy *%+:eeeeaeSeeehta fhoes. Black &Veatch 12-20 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project N -Lucas to Teeland 230 kV (115 kV)Transmission Line (Repair and Replacement -Category 2) The existing 115 kV Teeland to Lucas line serves several substations in the MEA area.This section of line is subject to low voltages and load loss with the single contingency outage of the Teeland 230 kV/115 kV transformer or the Teeland -Pt.MacKenzie 230 kV transmission line.The transmission contingency is alleviated by the construction of Project E (Lake Loraine to Douglas 230 kV line),but the construction of this line does not mitigate the loss of load and low voltage conditions experienced following the loss of the Teeland Transformer.There is currently a 138 kV/115 kV transformer that serves as a emergency replacement for the 230 kV/115 kV transformer,however,this transformer will be retired when the Intertie is converted to 230 kV.In order to alleviate low voltage conditions and loss of load in the MEA area for contingency operations,a new transmission line is required into the Lucas/Hospital Sub area of the MEA territory.The optimum selection of the line and its construction and operating voltage requires more detailed study than is possible in this analysis and will require coordination with other transmission projects and generation alternatives.This project should be evaluated as part of future transmission planning studies. Figure 12-15 presents the proposed replacement. Figure 12-15 Lucas to Teeland 230 kV Transmission Line (Repair and Replacement) Pow «sé tf, atl bsReenaSeEK'-aoe we * ae *epots?Tate Lucas.=?eaeee"Teeland x < ” _ 0 ting yn a,"diHRogeeOTAae|Eo e..ven,Be Carlet OME Sle gt -”°ee .'«ma vee "raa::ae re a Black &Veatch 12-21 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project O -Fossil Creek to Plant 2 230 kV Transmission Line (Upgrade -Category 2) This section of line consists of a double circuit 230 kV constructed line ,with one circuit operated at 230 kV and one circuit currently being operated at 115 kV.This project is required to enhance the reliability of the Anchorage and MEA areas.Operation of both circuits at 230 kV will require the construction of a 230 kV/115 kV substation at Fossil Creek and construction of a 230 kV line section from ML&P Plant 2 to University station.Alternatively,it may be possible to install a second transformer at ML&P Plant 2 and increase the transfer capacity of the AML&P 115 kV system.The exact configuration should be determined in future studies.Figure 12-16 presents the proposed upgrade. Figure 12-16 Fossil Creek to Plant 2 230 kV Transmission Line (Upgrade) on 3SeadFossilCreek Black &Veatch 12-22 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project P -Pt.Mackenzie (Lorraine)to Plant 2 230 kV Transmission Line (Repair and Replacement -Category 2) The existing Pt.Mackenzie to Plant 2 transmission line consists of two sections of 230 kV overhead transmission line and a section of underwater cable between the East Terminal and West Terminal stations. The overhead line is in reasonably good condition but the submarine cable is expected to be in need of replacement and repairs by 2025.At that time,the terminus of the transmission line will be Lorraine and AML&P Plant 2 stations.This circuit is critical to the reliability of the Railbelt system and is,therefore, scheduled as a GRETC replacement project.The project is presented in Figure 12-17. Figure 12-17 Pt.Mackenzie to Plant 2 230 kV Transmission Line (Repair and Replacement) *f o _ >PP ce pion”West Terminal wm-eee Eis. .je 'foNiyEastTerminal9$30 &.iS Ste cd Black &Veatch 12-23 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project Q -Bernice Lake -Soldotna 115 kV Transmission Line (Rebuild -Category 2) The 115 kV transmission line from Bernice Lake Power Plant to Soldotna Substation serves as the critical link between the proposed Southern Intertie,the existing Kenai intertie and the Bradley Lake power plant. The transmission line was constructed in 1971 and is expected to require significant reconstruction over the life of this plan.Further study should be undertaken before this line is upgraded to determine if 230 kV operation is required or is possible over the life of this plan.230 kV operation will require significant permitting and environmental effort and may not be warranted.The project is presented in Figure 12-18. Figure 12-18 Bernice Lake to Soldotna 115 kV Transmission Line (Rebuild) -_/boy,am a Pe4 _se PoetPlantSycannaWg _7oefAon-0 yonon_Aion -@*Meefi 4 '\"ON a XX a .7 , . f ''oC etki re/.y Bernice Lake Phy ewch |CAAA SAAT st «iedSoldotna-:GT_ae Black &Veatch 12-24 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project R -Bernice Lake-Beaver Creek -Soldotna 115 kV Transmission Line (Rebuild -Category 2) The existing 69 kV transmission line between Bernice Lake,Beaver Creek and Soldotna stations cannot be operated in parallel with the 115 kV transmission line between Bernice Lake and Soldotna due to the limited transfer capacity of the line and transient stability limitations.The 69 kV line is required to be upgraded to 115 kV to eliminate the single contingency loss of the existing 115 kV transmission line between Soldotna and Bernice Lake.HEA has rebuilt portions of the 69 kV line to 115 kV construction and Marathon Station is constructed to 115 kV construction. The project consists of upgrading the remaining portions of the 69 kV line to 115 kV and modifications to the stations at Bernice Lake,Beaver Creek and Soldotna.This line should not be considered for 230 kV operation.The project is presented in Figure 12-19. Figure 12-19 Bernice Lake to Beaver Creek to Soldotna 115 kV Transmission Line (Rebuild) i Jo Pf ht SORESBeeOOMYPeeAS'My Beluga Power Plant .is pari 7 tee,;ey 7 ff?oe aeVive,mm f L-rea pe =opeas|Pad JMERe SR MicwiaiefaAttyonex_x 7 ms TAS.::Woedel]Saitinten ="7 -_+7 Soldotna ..Sita i figt' KASHON om. Black &Veatch 12-25 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY 12.6 Susitna Project S -Susitna Transmission Additions (New Project -Category 3) The Susitna transmission interconnection configuration will depend on the selected generation site at Susitna. The Watana option consists of two 230 kV transmission lines connecting the Susitna substation to the new 230 kV Gold Creek substation,one transmission line from Sustina to Healy Substation,one additional 230 kV transmission line from the Gold Creek substation south to the Douglas 230 kV substation,and one line 230 kV transmission line from Douglas to Pt.MacKenzie Substation.The Gold Creek substation is approximately 33 miles from the Susitna substation and is the terminating point for the two 230 kV lines from Susitna as well as a switching station for the Douglas to Healy tie lines and the connecting point for the Gold Creek to Douglas 230 kV line that will transport power from the Susitna plant into the southern regions of the Railbelt.The capital cost for the Susitna substation,the two 230 kV transmission lines from Susitna to Gold Creek,and the Gold Creek substation are included in the capital cost for the Susitna projects.The capital cost for the Douglas to Lake Lorraine 230 kV transmission line is included as the incremental cost making the Douglas to Lake Lorraine 230 kV transmission line described in Project E a double circuit line.The Susitna to Gold Creek lines and the Gold Creek to Douglas line are presented in Figure 12-20.The Douglas to Lake Lorraine 230 kV transmission line is shown in Figure 12-6.Project S is not required if the Susitna project is not constructed. If the Devils Canyon site is selected,three lines between Susitna and Gold Creek are required;however,the second Intertie between Gold Creek and Healy would replace the Susitna-Healy line. Figure 12-20 Susitna to Gold Creek 230 kV Transmission Line Healy Susitna Gold Creek . "s.Matanuska-Susitna aetonwaaay Black &Veatch 12-26 February 2010 TRANSMISSION PROJECTS ALASKA RIRP STUDY SECTION 12 12.7 Summary of Transmission Projects The list of transmission projects is presented in Table 12-1,and their locations are shown in Figures 12-21 and 12-22.Table 12-1 also includes preliminary cost estimates for each of the listed projects.Note that this list does not include a description of the associated distribution substations that would need to be upgraded to accommodate the new voltage levels of the transmission projects.The cost of these projects are however included in the total cost for each scenario and-is also shown in the table below.While the details of GRETC are not yet developed to a point that determines whether these distribution substations would be a part of the GRETC system or part of the individual utilities distribution systems,they are a necessary cost resulting from the development of the GRETC system and have been included in the economic evaluations.All the transmission projects presented in this section were evaluated by a transmission load flow analysis to determine how the Railbelt system performed with these projects along with the economic dispatch of the selected generating resources in the RIRP. Table 12-1 Summary of Proposed Transmission Projects Project No.Transmission Projects Type Cost ($000) A Bernice Lake -International New Build (230 kV)227,500 B Soldotna -Quartz Creek R&R (230 kV)126,500 Cc Quartz Creek -University R&R (230 kV)165,000 D Douglas -Teeland R&R (230 kV)62,500 E Lake Lorraine -Douglas New Build (230 kV)80,000 F Douglas -Healy Upgrade (230 kV)30,000 G Douglas -Healy New Build (230 kV)252,000 H Eklutna -Fossil Creek Upgrade (230 kV)65,000 I Healy -Gold Hill R&R (230 kV)180,500 J Healy -Wilson Upgrade (230 kV)32,000 K Soldotna -Diamond Ridge R&R (115 kV)66,000 L Lawing -Seward Upgrade (115 kV)15,450 M Eklutna -Lucas R&R(115 kV/230 kV)12,300 N Lucas -Teeland R&R (230 kV)51,100 oO Fossil Creek -Plant 2 Upgrade (230 kV)13,650 P Pt.Mackenzie -Plant 2 R&R (230 kV)32,400 Q Bernice Lake -Soldotna Rebuild (115 kV)24,000 R Bernice Lake -Beaver Creek -Soldotna |Rebuild (115 kV)24,000 S Susitna Transmission Additions New Build (230 kV)57,000 Black &Veatch 12-27 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Figure 12-21 Location of Proposed Transmission Projects (Without Susitna) [WwesT1.LTERMINAL|AGSTTManBlack &Veatch 12-28 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Figure 12-22 Location of Proposed Transmission Projects (With Susitna) 'GLACIEREXLUTNAFORK2017 y Psa]we Tal DOUGLAS a53 KV Ne iki,TRELAND 230 '¢ a ¢[rotsa cx |o.¢eeoe,¢oss 7 5LELORAINElxfest]e EAST weEST LPewSu,TERMINAL TERMINAL ANALP TAR Nt SALA SEO THR 2221 Io4 o tot 5 SRRATIONAL VUARWERSITY &BT MACK INTERNATIONAL Ee Slieadiond F:<Sr}---1 oS BE he &Ban .DAVES OK DAVESOtPT.>330 ev Com sisty i i LAWWOREAZOF+15158KFyaOARTSORBERNICE0eV23ev2LAKE2332jo,5+3 ic} Black &Veatch 12-29 February 2010 SECTION 12 . TRANSMISSION PROJECTS ALASKA RIRP STUDY 12.8 Other Reliability Projects In addition to the transmission lines presented in this section,other projects were considered that could contribute to improving the reliability of the Railbelt system.These projects generally fall into one or more of the following categories: e Providing reactive power (static var compensators -SVCs) e Providing or assisting with the provision of other ancillary services (regulation and/or spinning reserves) e Assistance in control of line flows or substation voltages e Assistance in the transition and coordination of transmission project implementation (mobile transformers or substations) e¢Communications and control facilities Several of these projects have been identified and discussed while others will result from the transmission reliability assessment.Potential projects in this category include: Substation capacitor banks Series capacitors SVCs BESS Mobile substations that could provide construction flexibility during the implementation phase Many of the projects listed will be proposed and reviewed during the reliability evaluation phase,while others may be identified only when more detailed design and specification of the transmission projects are undertaken.Where preliminary information indicates that these projects will be required as part of the projects identified above,their estimated costs have been included in the project cost in Table 12-1,The cost for any additional projects will be developed during the reliability analysis conducted as part of the implementation. The Railbelt system currently has several SVCs deployed across the system to assist in the operation of the system and to assist in the stable transfer of power between areas.These were installed several years ago and are considered critical to the stable operation of the system.Further analysis of the projects outlined in Section 12.5 is expected to result in potential changes to these projects,as well as a requirement for several more SVCs at locations to be identified by the stability analysis.Additionally,the currently deployed SVCs are in need of repairs if they are to continue in service and provide the reliability functions they were designed to provide.It is estimated that the repair or replacement of these existing SVCs would cost a total of approximately $25 million. Projects that could facilitate or complement the implementation of other projects (e.g.,wind)were of particular interest during project discussions.These projects,if implemented,could smooth the transition and adoption by the utilities of the GRETC concept.One such project was the BESS that could provide much needed frequency regulation and potentially some spinning reserves when non dispatchable projects,such as wind,are considered.Specific stability and regulation studies will be required to determine the best methods of integrating the wind generation. A BESS was specified that could provide frequency regulation required by the system when wind projects were selected by the RIRP.The BESS was sized in relation to the size of the non-dispatchable project to be 50 percent of the project nominal capacity for a 20-minute duration.For evaluation purposes,a27 MW BESS which would provide 50 percent of 54 MW Fire Island project is estimated to cost approximately$50 million.Although the performance of the BESS has not yet been analyzed as part of the stability Black &Veatch 12-30 February 2010 SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY analysis,the cost for the system was included in the analysis in Section 13.Other options (e.g.,fly wheel storage technologies and compressed air energy storage)that could provide the required frequency regulation should also be considered. It should be noted that if the need for frequency regulation is driven in part by an IPP-sponsored renewable project,policies will need to be adopted to allocate an appropriate portion of the regulation costs to those projects. The GRETC system will require upgrades to the communication and control systems of the existing facilities in order to operate as a unified grid.Communication for pilot relaying between Anchorage and Fairbanks as well as communication upgrades to the Anchorage -Kenai system will be required for protective relaying and control.The individual utilities have their own communication and control systems.The alternatives and costs for implementing the necessary communication and control systems for GRETC operation were discussed in the REGA study.Those costs which are considered necessary administrative costs for implementing GRETC are not included in the costs in Table 12-1. 12.9 Projects Priorities The proposed projects presented in Section 12.5 are not presented in any specific order or priority.It was felt that the information currently available,as well as the uncertainty which exists surrounding the selected generation plans,did not permit a more definitive prioritization of projects.This does not mean,however,that all the projects in the list have the same impact on the reliability of the Railbelt system,or that the projects are equally important to each utility.In several instances the projects were in extremely poor physical condition and were scheduled to be repaired or rebuilt to prevent the lines from literally falling to the ground.To facilitate the immediate repairs to these lines,the projects that should be addressed within the next five years because of their potential impact on the reliability of the system have been identified.Additionally,some of the projects will need to be evaluated and specified further and funds have been identified to facilitate the studies that are required to further identify and schedule the transmission improvements that will be required. The following projects and studies have been identified for priority attention because of their immediate impact on the reliability of the existing system.All of the projects will require detailed system feasibility studies prior to actual implementation.Estimated costs for these studies are included as part of the project costs estimates in Table 12-1.The following projects are estimated to be required within the next five years. Soldotna to Quartz Creek Transmission Line ($126.5 million -Project B) Quartz Creek to University Transmission Line ($165.0 million -Project C) Douglas to Teeland Transmission Line ($62.5 million -Project D) Lake Lorraine to Douglas Transmission Line ($80.0 million -Project E) SVCs ($25.0 million -Other Reliability Projects) Funds to undertake the study of the Southern Intertie ($1.0 million) Funds to investigate the provision of regulation that will facilitate the integration of renewable energy projects into the Railbelt system ($50.0 million,including cost of BESS -Other Reliability Projects)NAWPYWNSEThe total estimate costs necessary for transmission projects during the initial five years of the RIRP is $510 million in 2009 dollars. Black &Veatch 12-31 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 13.0 SUMMARY OF RESULTS The purpose of this section is to summarize the results of the RIRP analysis.We begin by providing a summary of the reference case results for each of the four Evaluation Scenarios,followed by a summary of the results for the various sensitivity cases that were evaluated.We then provide a comparative summary of the economic and emission results for all cases.This is followed by a summary of the results of the transmission analysis that was completed and,finally,the results of the financial analysis. 13.1 Results of Reference Cases In this subsection,we provide summaries of the reference case results for each of the following four Evaluation Scenarios: e Scenario 1A -Base Case Load Forecast -Least Cost Plan e Scenario 1B -Base Case Load Forecast -Force 50%Renewables e Scenario 2A -Large Growth Load Forecast -Least Cost Plan e Scenario 2B -Large Growth Load Forecast -Force 50%Renewables Our analysis shows that Scenarios 1A and 1B result in the same resources and,consequently,the same costs and emissions.In other words,the cost of achieving a renewable energy target of 50 percent by 2025 (Scenario 1B)is no greater than the cost of the unconstrained solution (Scenario 1A).This result applies only if a large hydroelectric project is built.Hereafter,we will refer to Scenarios 1A and 1B together. We begin with a summary of the impact that DSM/EE measures have on the region's capacity and annual energy requirements.This is followed by summary graphics and information for each of the Evaluation Scenarios.Additional summary information on the results of each reference case is provided at the end of this section.Detailed model output for each of the reference cases are provided in Appendices E-G. 13.1.1 Results -DSM/EE Resources As discussed in Section 11,Black &Veatch screened a broad array of residential and commercial DSM/EE measures.Based on this screening,21 residential and 51 commercial DSM/EE measures were selected forinclusionintheRIRPmodels,Strategist®and PROMOD®,as potential resources to be selected. Based upon the relative economics and savings of these screened residential and commercial DSM/EE measures,from the utility perspective,all of the residential and commercial DSM/EE measures were selected in each of the four Evaluation Scenarios.As discussed in Section 11,the penetration of the measures was based on technology adoption curves for DSM/EE studies from the BASS model;additionally,as discussed,DSM/EE measures are treated by Strategist®and PROMOD®as a reduction to the load forecast from which the alternative supply-side options are considered for adding generation resources. Since the maximum allowed level of DSM/EE resources were selected in each of the four Evaluation Scenarios,we summarize the resulting impact on the Base Case Load Forecast for Scenario 1A in the following graphic. As can be seen in Figure 13-1,DSM/EE measures result in a significant impact on the region's capacity and energy requirements.After the initial program start-up years,DSM/EE measures reduce the region's capacity requirements by approximately 8 percent.A similar level of impact is also shown for annual energy requirements. Black &Veatch 13-1 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY Figure 13-1 Impact of DSM/EE Resources -Base Case Load Forecast Demand (MW)Energy Requirements (MWh) -Without DSM/EE 3.000.000 -Without DSM/EE 1,400 With DSM/EE _-With DSM/EE =7,000,000 6,000,000 1,000 =€_-<--=oo 2 5,000,000=800 é2;4,000,000 S 600 a 5 3,000,000aa 400 3 2,000,000 [4200W 4,000,000 OT 0 ; TSE RRSRISSEESEREB ee Pee EeeRRRRRRARRRRRKRRKKRARASEERERSSRSSSSETELERS Year ee NN Ser TTear It should be noted that this study did not include an evaluation of innovative rate designs (e.g.,real-time pricing and demand response rates),nor did it consider the potential benefits of a Smart Grid and the associated widespread implementation of smart meters.These options could result in even greater reductions in peak demand and annual energy usage. 13.1.2 Results -Scenarios 1A/1B Reference Cases Figure 13-2 Results -Scenarios 1A/1B Reference Cases 2000 Capacity By Resource Type 7000 Energy By Resource Type 1800 1 ®Ocean Tidal S0001600FiWnt.'@ Ocean Tidal14004 'ci 5000 wWind =@ Municipal Solid Waste -Municipal Sold Waste=1200 &Geothermal =4000 a Geothermal 2 1000 t Hydro 5 4 Hydro.a 800 @ Purchase Power ©5000 @ Purchase Power °o B Fue!Oil é @ Fue!Ol 800 Bm Nuclear 2000 w Nucisar 400 "i wCoal ;mCoal200qeNaturalGas@Natral Gas °20172020202320262029203220352038204120442047205020532056- r=N 202020232050205320562059Black &Veatch 13-2 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 13.1.3 Results -Scenario 2A Reference Case Results Figure 13-3 Results -Scenario 2A Reference Case 3500 Capacity By Resource Type 4000 Energy By Resource Type 3000 Ocean Tidal2500BWind eaTidal 83Capacity(MW)3@ Municipal Solid Waste a Geothermal Hydro Purchase Power Fuel Oil mNuclear Coal m Natural Gas 201120142017202020232026202920322035203820442044205020532056205913.1.4 Results -Scenario 2B Reference Case Results i Muricipal Solid Waste ' Hydro Purchase Power wCoal @ Natural Gas Figure 13-4 Results -Scenario 2B Reference Case Capacity By Resource Type CAPACITY(MW)@ Ocean Tidal a Wind m Municipal Solid Waste @ Geothermal +Hydro m Purchase Power a Fuel Oil mNuclear mCoal w Natural Gas ENERGY(GWh)Energy By Resource Type pear @ Ocean Tidal Wind w Municipal Solid Waste @ Geothermal .Hydro Power Fuel Oil wNuclear uCoal @ Natural Gas 13.2 Results of Sensitivity Cases In this subsection,we list the various sensitivity cases that were evaluated.We then provide graphics that summarize the results for each sensitivity case.Additional summary information on the results of each sensitivity case is provided at the end of this section. 13.2.1 Sensitivity Cases Evaluated Scenarios 1A/1B Without DSM/EE Measures Scenarios 1A/1B With Double DSM/EE Measures Scenarios 1A/1B With Committed Units Included Scenarios 1A/1B Without CO,Costs Scenarios 1A/1B With Higher Gas Prices Scenarios 1A/1B Without Chakachamna Scenarios 1A/1B With Chakachamna Capital Costs Increased by 75% Scenarios 1A/1B With Susitna (Lower Low Watana Non-Expandable Option)Forced Scenarios 1A/1B With Susitna (Low Watana Non-Expandable Option)Forced Black &Veatch 13-3 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY e Scenarios 1A/1B With Susitna (Low Watana Expandable Option)Forced e®Scenarios 1A/1B With Susitna (Low Watana Expansion Option)Forced e Scenarios 1A/1B With Susitna (Watana Option)Forced e Scenarios 1A/1B With Susitna (High Devil Canyon Option)Forced e Scenarios 1A/1B With Modular Nuclear *Scenarios 1A/1B With Tidal e Scenarios 1A/1B With Lower Coal Capital and Fuel Costs e Scenarios 1A/1B With Federal Tax Credits for Renewables 13.2.2 Sensitivity Results -Scenarios 1A/1B Without DSM/EE Measures Figure 13-5 Sensitivity Results -Scenarios 1A/1B Without DSM/EE Measures 2000 Capacity By Resource Type 3000 Energy By Resource Type Ocean Tidal 7000 GooneWind_ @ Ocean Ti me Muricipal Sold Waste _"me Ss Msipa oka wasteaie3=Geothermal @ Purchase Power 8 .areas Power"9 @ Fue!oil 2 Fuel Off @ Nuclear @ Nuclear 5,©w Coal +9 a Coal'ym Natural Gas iW mNatral Gas 13.2.3 Sensitivity Results -Scenarios 1A/1B With Double DSM/EE Measures Figure 13-6 Sensitivity Results -Scenarios 1A/1B With Double DSM/EE Measures 2000 7000 Energy By Resource Type 1800 1600 @ Ocean Tidal 8000 @Wind 8 Ocean Tidal a”@ Municipal Solid Waste 5000 =ae Wind 3200 Geothermal =im Muricipal Solid Waste Zo00 Hydro #1000 =Geothermal i i=Purchase Power 3 .chase Power300©Fuel Oil Fs 000 «Fuel Ol600veg@Nuclear2000aj @ NuclearaCoal"A aco:400 :a Netralces as im Shewracos2001000ons 9 oa a ALOZEEESKSRRERERBETESRES'oe es 8 "sn >BREEERREEE EERE EEE SERSREREREELRERES Black &Veatch 13-4 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 13.2.4 Sensitivity Results -Scenarios 1A/1B With Committed Units Included Figure 13-7 Sensitivity Results -Scenarios 1A/1B With Committed Units Included 2500 Capacity By Resource Type |6000 Energy By Resource Type a Ocean Tidal §000mWind @ Ocean Tidal z Municipal Sos Waste -4000 wihontpal Sota Wet =uw Geothermal =5G al 5 =Hydro =3000 u Hydro <ie Purchase Power 2 isPurchase PowerbsaFuelOilamFvelOil m Nuclear 2000 Nuclear aCoal aCoal mNatural Gas 1000 @Natral Gas 0 13.2.5 Sensitivity Results -Scenarios 1A/1B Without COz Costs Figure 13-8 Sensitivity Results -Scenarios 1A/1B Without CO,Costs 2000 Capacity By Resource Type 7000 Energy By Resource Type 'Ocean Tidal D Ocean TidalmWind@Wind =m Municipal Solid Waste -MunicipalSolidWaste =@ Geothermal =a Geothermal £Hydro 5 %Hydro. 2 @Purchase Power =mPurchase Power é Fuel Oit FA FuelOf w Nuclear wNuclear aCoal =Coa Natural Gas 2 NaturalGas er rw hb aooanweorwrwverheoOMOODODBSasSSsSsSssegeegeqsgssess8NNNNNNNNNNNNNNSN Black &Veatch 13-5 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 13.2.6 Sensitivity Results -Scenarios 1A/1B With Higher Gas Prices Figure 13-9 Sensitivity Results --Scenarios 1A/1B With Higher Gas Prices 2000 Capacity By Resource Type 7000 Energy By Resource Type 1800 |1600 ©Ocean Tidal 8000 Dcean Tidal=.Wind sw '="im Municipal Sold Waste =Municipal Sold Waste=1 8 Geothermal =Geothermal By *Hydro 5 v HydroFA1PurchasePoweri@Purchase Power 3 m Fuel Oil Fi Fuel Oi @ Nuclear aCoa ay G Natural Gas 13.2.7 Sensitivity Results -Scenarios 1A/1B Without Chakachamna Figure 13-10 Sensitivity Results -Scenarios 1A/1B Without Chakachamna 2000 Capacity By Resource Type 7000 Energy By Resource Type 1800 [Ag |ova0 1 oe Sear=1400 @ Municipal Sold Waste _S000 a MuricipalSoldWaste=1200 &Geothermal F 000£1000 P Hydro 5£800 im Purchase Power ©3000é8FuelOilz600"Hw Nuclear 2000 =Coal @ Natural Gas @ Natural Gas :ran ;; :,a ewrtnr Oo MO DO nNwMweewtn Oo MYM wo DD =e +s Oo -&2 2eeeRANKonaowowSER8RBRREZREPEREESResss8seggs8888888RRRRRRESRRRF222888 13.2.8 Sensitivity Results --Scenarios 1A/1B With Chakachamna Capital Costs Increased by 75% When Chakachamna's capital costs are increased by 75 percent,it is no longer selected as a resource in theresourceplan.As a result,the results of this sensitivity case are the same as the Scenario 1A Without Chakachmna Sensitivity Case above.Consequently,the resulting breakdown of capacity and energy generated by resource type is the same as the graphs shown in Figure 13-10. Black &Veatch 13-6 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 13.2.9 Sensitivity Results -Scenarios 1A/1B With Susitna (Lower Low Watana Non- Expandable Option)Forced Figure 13-11 Sensitivity Results -Scenarios 1A/1B With Susitna (Lower Low Watana Non-Expandable Option) Forced 2000 Capacity By Resource Type 7000 Energy By Resource Type 1800 |4600 L/\.m Ocean Tidal 8000 Ocean TidammwOceanTidal 1400 IX fyi 5000 .aWind =el :+|SMoricipal Solid Waste .Municipal Solid Waste=1200 =ae =.z 4000 :GeothermalB100F:=Hydro 5 300 we -mPurchase Power Fd 3000 fe Purchase Power é i FA sF uel Oil600wNucear 400 2000 "9 acoa .@ w Natral Gas2001000; 0 es: er tTnoanmo annwvwoaer sR EON DY D o . ST roanan dn HHO OFT TF HL OG <=RRRRERRRRRRARRAR RA EERRSSSSEBSZE8888ANNNNONONNNNONAANOONON 13.2.10 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Non-Expandable Option)Forced Figure 13-12 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Non-Expandable Option)Forced Capacity By Resource Type2000pacityByyp |7000 Energy By ResourceType 1800 11600L/|;\}@ Ocean Tidal 6000 ° -__/Wind _Ocean Til=400 }.Municipal Solid Waste 5000 Coe .aWird|=.= :|Muricipal Solid Waste=1200 ™Geothermal 3 2 =4 :4000 at Geothermal®1000 f 1 Hydro =: a 800 |'Purchase Power &3000 yrs Purchase Power °o mFuel Oil fi -Fuel Of 600 '. q Nuclear 2000 wNuclear 400 uCoal mCoal 200 ;...Natural Gas 4000 gs mag ©Natral Gas ;os,7 am ae EEERRESSRRBETERSRS TRE RSRRAEBSBESTSRRESRRRRRRRRRARRARRRR2288288822282322222 13.2.11 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Expandable Option)Forced In this sensitivity case,we forced the Susitna (Low Watana Expandable Option)to be selected,in a similar manner to the Susitna (Low Watana Non-Expandable Option)Sensitivity Case immediately above. Consequently,the resulting breakdown of capacity and energy generation by resource type is the same as the graphs shown in Figure 13-12.However,the total cumulative prevent value,average unit cost,and total capital requirements for this sensitivity case are higher;this results from the fact that the only difference between this and the Susitna (Low Watana Non-Expandable Option)Sensitivity Case is that capital costs associated with this option are $400 million higher to preserve the option of future expansion. Black &Veatch 13-7 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 13.2.12 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Expansion Option) wa Ocean Tidal eWind tm Municipal Solid Waste #Geothermal Hydro i Purchase Power @ Fuel Oi) @ Nuclear Coal @ Natural Gas Forced Figure 13-13 Sensitivity Results -Scenarios 1A/1B With Susitna (Low Watana Expansion Option)Forced 2500 Capacity By Resource Type |7000 Energy By Resource Type 2000 @ Ocean Tidal 8000 [--mie 5000 \.|@ MunicipalSolidWaste ;=1500 v\-#Geothermal =, =4000 z r Hydro =='@ Purchase Power id&1000 Bs,m Fuel Oif Fa a m Nuclear 500 a Coal Natural Gas rte &a s free Pee yl Pes eke 0 ces eee es annais 5 *"h " wr wFTnronm oOo On wwoeerwrn OM O DD an ©@ er tT a 8SSSRSSSSSsssssgesREERRR28888 13.2.13 Sensitivity Results -Scenarios 1A/1B With Susitna (Watana Option)Forced Figure 13-14 Sensitivity Results -Scenarios 1A/1B With Susitna (Watana Option)Forced 3000 Capacity By Resource Type 7000 Energy By Resource Type 500 -#Ocean Tidal =Ocean TidalwWind;5000 m Windge2000sSolidWaste -1 Muricipal Sofid Waste=&Geothermal =4000 w Geottermal =1500 ”Hydro >B Hydroipv"i Purchase Power &3000 @ Purchase Power ©1000 BY @ Fuel Oi é m Fuel Oil a"=or 1 Natural Gas to00 fe og t r @ NaturalGaseeehae EF ERRRRERRSETEBRBRSB nn onecane ben 8 @RRRARRSRRRARESEESSERRERERREZEEERE Black &Veatch 13-8 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 13.2.14 Sensitivity Results -Scenarios 1A/1B With Susitna (High Devil Canyon Option) Forced Figure 13-15 Sensitivity Results -Scenarios 1A/1B With Susitna (High Devil Canyon Option)Forced 2500 Capacity By Resource Type 2000 Capacity(MW)gso@ Ocean Tidal Wind m Municipal Solid Waste 8 Geothermal +Hydro m Purchase Power m Fuel Oil gm Nuclear BCoal @ Natural Gas 2011201420172020202320262029203220352038204120442047205320562059ENERGY(GWh)Energy By Resource Type Ocean Tidal aWind @ Municipal Soid Waste @ Geothermal 4 Hydro @ Purchase Power w Fuel Oil Nuclear mCoal @ Natal Ges 2059et13.2.15 Sensitivity Results -Scenarios 1A/1B With Modular Nuclear Figure 13-16 Sensitivity Results -Scenarios 1A/1B With Modular Nuclear 2000 Capacity By Resource Type 1 7000 Energy By Resource Type 1800 mM Ocean Tidal 8000 :'om eWind a .Ocean Tidal=1400 m Municipal Solid Waste 5000 ----.Wind =120 ws Geothermal g «ooo aricipal Std eum2100fe»Hydro =Hydro =w Purchase Power =5000 |Purchase Powero800FuelOitaSFuelOl600Nuclear2000mNuclear 400 Coal whe aCoal 200 @ Natural Gas 4000 ey '@ Natural Gas 0 ai hes " RRRRSRRSRRRRSSSRSRS £288 2223233 g Black &Veatch 13-9 February 2010 SUMMARY OF RESULTS ALASKA RIRP STUDY SECTION 13 13.2.16 Sensitivity Results -Scenarios 1A/1B With Tidal Figure 13-17 Sensitivity Results -Scenarios 1A/1B With Tidal 2000 Capacity By Resource Type !7000 Energy By Resource Type r Ocean Tidal a Wind @ Ocean Tidal .,Wind =Ww Municipal Solid Waste _ta Municipal Solid Waste =§Geothermal 5 &Geothermal 2 Hydro =«HydroAmPurchasePowerg@Purchase Power 6 Fuel Oil FA 1m Fuel Oil m Nuclear w Nucear uw Coal ga Coal @ Natural Gas Natural Gas 201720142017202020232026202920322035&.2038204420472050204120532056205913.2.17 Sensitivity Results --Scenarios 1A/1B With Lower Coal Capital and Fuel Costs Figure 13-18 Sensitivity Results --Scenarios 1A/1B With Lower Coal Capital and Fuel Costs 2000 Capacity By Resource Type _7000 Energy By Resource Type 1800 |Ag |y*\_|Ocean Tidal 8000 ! wWind @ Ocean Tidal_Rl |m Municipal Solid Waste -synpa Solid Wastez@Geothermal58Geothermal =f Hydro 5 +Hydro i @ Purchase Power &@ Purchase Power é a Fuel Oil FA Fuel Oit @ Nuclear @ Nucear a Coal mCoal @ Natural Gas@NaturalGas "FR SOME DRAH DE TRH ODM ©@cereTFTNRnnNnnwnmnnerseFHHDHMHeosgc89598589959800902503GBSSNNNNNNNANAAAAARNAANASN 13.2.18 Sensitivity Results -Scenarios 1A/1B With Federal Tax Credits for Renewables Figure 13-19 Sensitivity Results --Scenarios 1A/1B With Federal Tax Credits for Renewables 2000 Capacity By Resource Type 7000 1800 Ocean Tidal aWind 6000 --'=Ocean Tidal @ Municipal Solid Waste m Wind ©Geothermal 5000 @ Municipal Solid Waste -Hydro =1 Geothermal @ Purchase Power &00 *aie PmFuelOil2s:Fuel on owerwNuclearZz@Nuclear mw Coal mCoal @ Natural Gas 2000 @ Natural Gas 1000 Black &Veatch 13-10 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 13.3.Summary of Results In this subsection,we provide a comparative summary of the economic and emissions results for all of the reference and sensitivity cases. 13.3.1 Summary of Results -Economics Table 13-1 summarizes the economic results,including: e Cumulative present value cost (from the utility perspective) e Average wholesale power cost (from the utility perspective) e Renewable energy in 2025 e Total capital investment 13.3.2 Summary of Results -Emissions Table 13-2 summarizes the emissions-related results of all of the reference and sensitivity cases.The following information is provided for each case: e CO,emissions e NO,emissions e SO,emissions 13.4 Results of Transmission Analysis An important element of this RIRP was the analysis of transmission investments required to integrate the generation resources in each resource plan,ensure reliability and enable the region to take advantage of economy energy transfers between load areas within the region. The fundamental objective underlying the transmission analysis was to upgrade the transmission system over a 10-year period to remove transmission constraints that currently prevent the coordinated operation of all the utilities as a single entity. The study included all the utilities'assets 69 kV and above.These assets,over a transition period,may flow into GRETC and form the basis for a phased upgrade of the system into a robust,reliable transmission system that can accommodate the economic operation of the interconnected system.The transmission analysis also assumed that all utilities would participate in GRETC with planning being conducted on a GRETC (i.e.,regional)basis.The common goal would be the tight integration of the system operated by GRETC. Potential transmission investments in each of the following four categories were considered: e Transmission systems that need to be replaced because of age and condition (Category 1) ¢Transmission projects required to improve grid reliability,power transfer capability,and reserve sharing (Category 2) ¢Transmission projects required to connect new generation projects to the grid (Category3) e Transmission projects to upgrade the grid required by a new generation project (Category 4) Table 13-3 lists the recommended transmission system expansions and enhancements that resulted from our transmission analysis.Detailed information on each of the transmission projects listed in the following table is provided in Section 12. Black &Veatch 13-14 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY Table 13-1 Summary of Results -Economics Cumulative Average Renewable Present Value Wholesale Energy in Total Capital Cost Power Cost 2025 Investment Case ($000,000)(¢per kWh)(%)($000,000) Scenarios Scenario 1A $13,625 17.26 62.32%$9,087 Scenario 1B $13,625 17.26 62.32%$9,087 Scenario 2A $20,162 19.75 42.64%$14,111 Scenario 2B $21,109 20.68 65.83%$18,805 Sensitivities 1A/1B Without DSM/EE Measures $14,507 17.40 67.10%$8,603 1A/1B With Double DSM $12,546 15.89 65.15%$8,861 1A/1B With Committed Units Included $14,109 17.87 46.84%$8,090 1A/1B Without CO2 Costs $11,206 14.20 49.07%$8,381 1A/1B With Higher Gas Prices $14,064 17.82 61.95%$9,248 1A/1B Without Chakachamna $14,332 18.16 38.06%$7,719 1A/1B With Chakachamna Capital Costs $14,332 18.16 38.06%$7,719 Increased by 75% 1A/1B With Susitna (Lower Low Watana $15,228 19.29 61.01%$12,421 Non-Expandable Option)Forced 1A/1B With Susitna (Low Watana Non-$15,040 19.05 63.01%$15,057 Expandable Option)Forced 1A/1B With Susitna (Low Watana $15,346 19.44 63.01%$15,588 Expandable Option)Forced 1A/1B With Susitna (Low Watana $14,854 18.82 -66.90%$14,069 Expansion Option)Forced 1A/1B With Susitna (Watana Option)Forced $15,683 19.87 70.97%$13,211 1A/1B With Susitna (High Devil Canyon $14,795 18.74 66.92%$11,633 Option)Forced 1A/1B With Modular Nuclear $13,841 17.53 60.51%$9,105 1A/1B With Tidal $13,712 17.37 65.52%$9,679 1A/1B With Lower Coal Fuel and Lower $13,625 17.26 62.32%$9,087 Coal Capital Costs 1A/1B With Tax Credits for Renewables $12,954 16.41 67.56%$9,256 Black &Veatch 13-12 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY Table 13-2 Summary of Results -Emissions ne -CO,.NO,.80, Case -('000 tons)('000 tons)('000 tons) Scenarios Scenario 1A 80,259,047 124,215 21,768 Scenario 1B 80,259,047 124,215 21,768 Scenario 2A 152,318,066 133,642 24,476 Scenario 2B 125,498,202 140,897 26,348 Sensitivities 1A/1B Without DSM/EE Measures 88,181,350 139,179 30,605 1A/1B With Double DSM 69,324,920 131,299 18,994 1A/1B With Committed Units Included 91,212,598 136,946 16,482 1A/1B Without CO2 Costs 100,753,030 134,031 23,960 1A/1B With Higher Gas Prices 78,323,066 121,700 25,232 1A/1B Without Chakachamna 105,643,650 133,577 25,700 1A/1B With Chakachamna Capital Costs Increased by 75%105,643,650 133,577 25,700 1A/1B With Susitna (Lower Low Watana Non-Expandable $2,328,762 127,921 22,124 Option)Forced 1A/1B With Susitna (Low Watana Non-Expandable Option)69,133,553 124,640 19,620 Forced 1A/1B With Susitna (Low Watana Expandable Option)Forced 69,133,553 124,640 19,620 1A/1B With Susitna (Low Watana Expansion Option)Forced 67,724,563 136,906 23,589 1A/1B With Susitna (Watana Option)Forced 70,966,059 111,307 19,171 1A/1B With Susitna (High Devil Canyon Option)Forced 71,853,368 121,538 19,909 1A/1B With Modular Nuclear 79,664,701 126,881 22,787 1A/1B With Tidal 75,598,948 121,306 21,067 1A/1B With Lower Coal Fuel and Lower Coal Capital Costs 80,259,047 124,215 21,768 1A/1B With Tax Credits for Renewables 74,046,352 129,384 18,832 Black &Veatch 13-13 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY Table 13-3 Summary of Proposed Transmission Projects 'Project : : 'No.Transmission Projects Type Cost (S000)- A Bernice Lake -International New Build (230 kV)227,500 Soldotna -Quartz Creek R&R (230 kV)126,500 Cc Quartz Creek -University R&R (230 kV)165,000 D Douglas -Teeland R&R (230 kV)62,500 E Lake Lorraine -Douglas New Build (230 kV)80,000 F Douglas -Healy Upgrade (230 kV).30,000 G Douglas -Healy New Build (230 kV)252,000 H Eklutna -Fossil Creek Upgrade (230 kV)65,000 I Healy -Gold Hill R&R (230 kV)180,500 J Healy Wilson Upgrade (230 kV)32,000 K Soldotna --Diamond Ridge R&R (115 kV)66,000 L Lawing Seward Upgrade (115 kV)15,450 M Eklutna -Lucas R&R(115 kV/230 kV)12,300 N Lucas -Teeland R&R (230 kV)51,100 O Fossil Creek -Plant 2 Upgrade (230 kV)13,650 P Pt.Mackenzie -Plant 2 R&R (230 kV)32,400 Q Bernice Lake -Soldotna Rebuild (115 kV)24,000 R Bernice Lake -Beaver Creek -Soldotna |Rebuild (115 kV)24,000 S Susitna Transmission Additions New Build (230 kV)57,000 Black &Veatch 13-14 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY The following issues result from our transmission analysis: We were unable to complete a stability analysis based upon our proposed transmission system configuration prior to the completion of this project.This analysis is required to ensure that the proposed transmission system expansions and enhancements result in the necessary stability to ensure reliable electric service over the planning horizon.This analysis should be completed as part of the future work to further define,prioritize,and design specific transmission projects. In addition to the transmission lines listed above,other projects were considered that could contribute to improving the reliability of the Railbelt system.These projects generally fall into one or more of the following categories: o Providing reactive power (static var compensators -SVCs) o Providing or assisting with the provision of other ancillary services (regulation and/or spinning reserves) o Assistance in control of line flows or substation voltages o Assistance in the transition and coordination of transmission project implementation (mobile transforms or substations) o Communications and control facilities Several of these projects have been identified and discussed while others will result from the transmission reliability assessment.Potential projects in this category include: Substation capacitor banks Series capacitors SVCs BESS Mobile substations that could provide construction flexibility during the implementation phase Projects that could facilitate or complement the implementation of other projects (e.g.,wind),were of particular interest during project discussions.These projects,if implemented,could smooth the transition and adoption by the utilities of the GRETC concept.One such project was the BESS that could provide much needed frequency regulation and potentially some spinning reserves when non-dispatchable projects,such as wind,are considered.A BESS was specified that could provide frequency regulation required by the system when wind projects were selected by the RIRP.The BESS was sized in relation to the size of the non-dispatchable project to be 50 percent of the project nominal capacity for a 20-minute duration.Although the performance of the BESS has not yet been analyzed as part of the stability analysis,the costs for each such system were included in the analysis. Other options (e.g.,fly wheel storage technologies and compressed air energy storage)that could provide the required frequency regulation should also be considered. The Fire Island Wind Project is a54 MW maximum output wind project.Each wind turbine will be equipped with reactive power and voltage support capabilities that should facilitate interconnection into the transmission grid.Current plans are to interconnect the project to the grid via a 34.5 kV underground and submarine cable to the Chugach 34.5 kV Raspberry Substation.There has been some discussions regarding the most appropriate transmission interconnection for the Fire Island Project and detailed interconnection studies have not been completed.The timeframe for implementing this project in order to qualify for available grants under the ARRA could preclude more detailed transmission studies and consideration of alternatives to the currently proposed 34.5 kV interconnection.An option to consider if Fire Island is constructed is to lay cables from Fire Island to Anchorage insulated for 230 kV and review a transmission routing for the new transmission connection to the Kenai peninsula that would begin at the International 230 kV Substation to Bernice Lake Substation along the Kenai cost line then via submarine cable across the Cook Inlet to Fire00000 Black &Veatch 13-15 February 2010 SECTION 13 SUMMARY OF RES ULTS ALASKA RIRP STUDY Island.The interconnection would then use the 230 kV submarine cable previously laid over Anchorage coast then into the International 230 kV Substation. to the e The recommended transmission system expansions and enhancements can not be justified based solely on economics.However,in addition to their underlying economics,these transmission projects are required to ensure the reliable delivery of electricity throughout the region over the 50-year planning horizon and to provide the foundation for future economic development efforts. 13.5 Results of Financial Analysis It will be difficult for the region to obtain the necessary financing for the DSM/EE,generation and transmission resources included in the alternative resource plans that were developed.The formation of a regional entity with some form of State assistance will help meet this challenge. Figure 13-20 summarizes the cumulative capital investment required for each of the reference cases. Figure 13-20 Required Cumulative Capital Investment for Each Reference Case Cumulative Capital Investment $20,000,000 ----Scenario 1A/1B --$18,000,000 --Scenario 2A LO.$16,000,000 -scenario 28 A$14,000,000 - $12,000,000 [L.$10,000,000 VA$8,000,000 -> $6,000,000 [_/f $4,000,000 LZ CumulativeCapitalInvestment($000'$2,000,000 W224_-$0 TTT T 1 +++FT T |OT TY TY T 0 D)D +ov T F 0 ov YY tT bY D UP FF C FP T f fT T TT TT TF TfSL2PeEZFRARCARRAABBSREBHER<FEEPERBBSEoOoooc9cjcooooooqoe0oe9djdlked807.9030O093806C0%0OUCUOMDUCODUUCOWC COCONNNNNNNNNNNNNNNNNNNNNNNN Year 2059|To assist in the completion of the financial analysis,the AEA contracted with SNW to: e Provide a high-level analysis of the capital funding capacity of each of the Railbelt utilities. e Analyze strategies to capitalize selected RIRP assets by integrating State (which could include loans, State appropriations,Permanent Fund,State moral obligation bonds,etc.)and federal (e.g.,USDA- RUS)financing resources with debt capital market resources. e Develop a spreadsheet model that utilizes inputs from this RIRP analysis and overlays realistic debt capital funding to provide a total cost to ratepayers of the optimal resource plan. The results of the financial analysis completed by SNW are provided in Appendix B. Black &Veatch 13-16 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY Important conclusions from SNW's report include: The scope of the RIRP projects is too great,and for certain individual projects,it is reasonable to conclude that there is no ability for a municipality or cooperative utility to independently secure debt financing without committing substantial amounts of equity of cash reserves. Figure 13-21 helps to put into context the scope of the required RIRP capital investments relative to the estimated combined debt capacity of the Railbelt utilities.The lines toward the bottom of the graph represent SNW's estimate of the bracketed range of additional debt capacity collectively for the Railbelt utilities,adjusted for inflation and customer growth over time. Figure 13-21 . Required Cumulative Capital Investment (Scenarios 1A/1B)Relative to Railbelt Utility Debt Capacity $10,000,000,000 Capital Expenditures /$7,500,000,000 a$5,000,000,000 /Hizh Debt Capacity $2,500,000,000 Low Debt Capacity "$0 EE arn om SANMHontTNOSoM oTaataANNANOSASMHTSTTHmHooocoogcccoeoecmeSPSeeoeSNNNNNNNNNNNNNNNNAN Source:SNW Report included in Appendix C. A regional entity,such as GRETC,with "all outputs”contracts migrating over time to "all requirements”contracts will have greater access to capital than the combined capital capacity of the individual utilities. There are several strategies that could be employed to lower the RIRP-related capital costs to customers,including: o Ratepayer Benefits Charge -A charge levied on all ratepayers within the Railbelt system that would be used to cash fund and thereby defer borrowing for infrastructure capital. o "Pay-Go”Versus Borrowing for Capital -A pay-go financing structure minimizes the total cost of projects through the reduction in interest costs.A "pay-go”capital financing program is one in which ongoing capital projects are paid for from remaining revenue after O&M expenses and debt service are paid for.A balance of these two funding approaches appears to be the most effective in lowering the overall cost of the RIRP,as well as spreading out the costs over a longer period of time. o Construction Work in Progress (CWIP)-CWIP is a rate methodology that allows for the recovery of interest expense on project construction expenditures through the base rate during construction,rather than capitalizing the interest until the projects are on-line and generating power.It should be noted that this rate methodology is sometimes criticized for shifting risks from shareholders to ratepayers;however,in the case of a public cooperative or municipal utility, the "shareholders”are the ratepayers. Black &Veatch 13-17 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY o State Financial Assistance -State financial assistance could take a variety of forms as previously noted;for the purposes of this project,SNW focused on State assistance structured similarly to the Bradley Lake project.The benefits of State funding include:repayment flexibility,credit support/risk mitigation,and potential interest cost benefit. It should be noted that the economic comparison of resource options (using Strategist™and PROMOD"™)does not assume any of these financing strategies,including any State grants or loans,or federal tax credits,with the exception of the Federal Tax Credit for Renewables Sensitivity Case. e =The overall objective of SNW's analysis was to identify ways to overcome the funding challenges inherent with large-scale projects,including the length of construction time before the project is online and access to the capital markets,and to develop strategies that could be used to produce equitable rates over the useful life of the assets being financed.With these challenges in mind,SNW developed separate versions of its model to capture the cost of financing under a "base case”scenario and an "alternative”scenario.The base case financing model was structured such that the list of RIRP projects during the first 20 years would be financed through the capital markets in advance of construction and that the cost of the financing in the form of debt service on the bonds,would immediately be passed through to the ratepayers;the projects being financed over the balance of the 50-year period would be financed through cash flow created through normal rates and charges ("pay-go”)capital once debt service coverage from previous years has grown to levels that create cash flow balance amounts sufficient to pay for the projects as their construction costs come due.The alternative model was developed with the goal of minimizing the rate shock that may otherwise occur with such a large capital plan,and levelizing the rate over time so that the economic burden derived from these projects can be spread more equitably over the useful life of the projects being contemplated. e In both the base and alternative cases,SNW transferred the excess operating cash flow that is generated to create the debt service coverage level,and used that balance to both partially fund the capital projects in the early years and almost fully fund the projects in the later years.In the alternative case,SNW also included:1)a Capital Benefits Surcharge ($0.01 per KWH)over the first 17 years,when approximately 75 percent of the capital projects will have been constructed,and 2)State assistance as an equity participant,structured in a manner similar to the Bradley Lake financing model (SNW assumed that the State would provide a $2.4 billion zero-interest loan to GRETC to provide the upfront funding for the Chakachamna project,only to be paid back by GRETC out of system revenues over an extended period of time,and following the repayment of the potentially more expensive capital markets debt). ¢Under the base case,the maximum fixed charge rate on the capital portion alone is estimated to cost $0.13 per kWH,while the average fixed charge rate over the 50-year period is $0.07 per kWh. e In the alternative case,the maximum fixed charge rate on the capital portion alone is estimated to cost $0.08 per kWH,while the average fixed charge rate over the 50-year period is $0.06 per kWh,not including the $0.01 consumer benefit surcharge that is in place for the first 17 years. e While the average rates between the two cases are essentially the same,the maximum rate in the alternative case is much lower,showing the ability of innovative financing tools and ratemaking methodologies to overcome the funding challenges and produce equitable rates over the 50-year period. e The formation ofa regional entity,such as GRETC,that would combine the existing resources and rate base of the Railbelt utilities,as well as provide an organized front in working to obtain private financing and the necessary levels of State assistance,would be,in SNW's opinion,a necessary next step towards achieving the goal of reliable energy for the Railbelt region now and in the future. Black &Veatch 13-18 February 2010 SECTION 13 SUMMARY OF RESULTS Plan 1A/1B Year Unit Additions 2014 Nikiski Wind Healy Clean Coal Cumulative Present Worth Cost ($000) 2012 Fire Island $13,624,595 2013 Anchorage 1x1 6FA 2014 Giacier Fork 2015 Anchorage MSW 2016 Renewable Energy % In 2025 2017 GVEA MSW 62.32% 2018 GVEA 1X1 NPole Retrofit 2019 2020 Mount Spurr 2021 Anchorage 1x1 6FA Total Capital Investment ($000) 2022 Mount Spurr $9,086,710 2023 2024 2025 Chakachamna 2026 2027 2028 2029 2030 Kenai Hydro 2031 2032 2033 2034 2035 2036 2037 GVEA LMS100 2038 2039 2040 2041 2042 GVEA 1x1 6FA 2043 2044 2045 2046 Anchorage LM6000 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 GVEA LMS100 2058 2059 2060 ALASKA RIRP STUDY Black &Veatch 13-19 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY Plan 2A Year Unit Additions Nikiski Wind Cumulative Present 2011 Healy Clean Coal Worth Cost ($000) 2012 Fire Island $20,162,223 2013 Glacier Fork 2014 Anchorage MSW 2015 Anchorage 1x1 6FA Renewable Energy % 2016 In 2025 2017 Kenai Wind 42.64% 2018 GVEA 1X1 NPole Retrofit 2019 2020 Mount Spurr Tota!Capital 2021 Anchorage 1x1 6FA Investment ($000) 2022 Mount Spurr $14,110,777 2023 2024 Anchorage 2x1 6FA Anchorage LM6000 2025 Chakachamna 2026 2027 2028 2029 GVEA 2x1 6FA 2030 GVEA Wind 2031 2032 2033 2034 2035 2036 2037 GVEA LMS100 2038 2039 Anchorage 2x1 6FA GVEA 1x1 6FA 2040 GVEA 2x1 6FA 2041 2042 GVEA Wind 2043 2044 2045 2046 GVEA Wind 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 HEA LMS100 2058 2059 2060 HEA LM6000 Black &Veatch 13-20 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY |Plan 2B | Year Unit Additions Nikiski Wind Cumulative Present 2011 Healy Clean Coal Worth Cost ($000) 2012 Fire Island $21,108,823 2013 Glacier Fork 2014 Anchorage MSW 2015 Anchorage 1x1 6FA Renewable Energy % 2016 In 2025 2017 Kenai Wind 65.83% 2018 GVEA 1X1 NPole Retrofit , 2019 - 2020 Mount Spurr Totai Capital 2021 Anchorage 1x1 6FA Investment ($000) 2022 Mount Spurr $18,804,578 2023 2024 Chakachamna GVEA Wind 2025 Low Watana (Non-Expandable) 2026 2027 2028 2029 2030 GVEA Wind 2031 2032 2033 2034 2035 2036 Anchorage 2x1 6FA 2037 Kenai Wind 2038 2039 Anchorage 2x1 6FA Kenai Wind 2040 GVEA 2x1 6FA 2041 2042 GVEA Wind 2043 2044 2045 2046 GVEA LM6000 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 Anchorage LMS100 2058 2059 2060 Black &Veatch 13-21 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B Without DSM/EE Measures Year Unit Additions 2011 Nikiski Wind Healy Clean Coal Cumulative Present Worth Cost ($000) 2012 Fire Island $14,506,801 2013 Anchorage 1x1 6FA 2014 2015 Kenai Wind 2016 Renewable Energy % In 2025 2017 GVEA MSW 67.10% 2018 Chakachamna Glacier Fork 2019 2020 Anchorage MSW 2021 Mount Spurr Total Capital Investment ($000) 2022 Mount Spurr $9,791,215 2023 2024 2025 GVEA 1X1 NPole Retrofit 2026 2027 2028 2029 2030 Anchorage 2x1 6FA 2031 2032 2033 2034 2035 2036 2037 GVEA LM6000 2038 2039 2040 2041 2042 Anchorage LMS100 2043 2044 2045 2046 GVEA LM6000 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 GVEA 1x1 6FA 2058 2059 2060 ALASKA RIRP STUDY Black &Veatch 13-22 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B With Double DSM/EE Measures Year Unit Additions 2011 Nikiski Wind Healy Clean Coal Cumulative Present Worth Cost ($000) 2012 Fire island $12,545,859 2013 2014 Anchorage MSW 2015 Anchorage 1x1 6FA 2016 Renewable Energy % In 2025 2017 Glacier Fork 65.15% 2018 Mount Spurr 2019 2020 Mount Spurr 2021 GVEA 1X1 NPole Retrofit Total Capital Investment ($000) 2022 Anchorage LMS100 $8,860,649 2023 2024 2025 GVEA MSW Chakachamna 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 GVEA LMS100 2038 2039 2040 2041 2042 GVEA 1x1 6FA 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 2055 GVEA LMS100 2056 2057 2058 2059 2060 HEA LM6000 ALASKA RIRP STUDY Black &Veatch 13-23 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 1A/1B With Committed Units Included } Year Unit Additions Nikiski Wind Seward 1 Cumulative Present 2011 Healy Clean Coal Worth Cost ($000) Fire Island MLP LM2500 $14,108,513Nikiski 2012 Seward 2 2043 HEA Frame South Central PP MLP LM6000 CC GVEA MSW 2014 HEA Aero 2015 Ekiutna Generation Renewable Energy % 2016 Kenai Wind In 2025 2017 46.84% 2018 2019 Kenai Wind 2020 Mount Spurr T Total Capital 2021 Kenai Wind Investment ($000) 2022 GVEA Wind $9,086,710 2023 Mount Spurr 2024 Kenai Wind 2025 Anchorage LMS100 2026 2027 2028 2029 2030 GVEA Wind 2031 2032 2033 2034 2035 2036 GVEA 1X1 NPole Retrofit 2037 2038 2039 2040 Anchorage 1x1 6FA 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Anchorage LMS100 2051 2052 2053 2054 2055 2056 2057 2058 2059 GVEA LM6000 2060 Black &Veatch 13-24 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B Without CO2 Costs Year Unit Additions 2011 Nikiski Wind Healy Clean Coal Cumulative Present Worth Cost ($000) 2012 $11,205,673 2013 Anchorage 1x1 6FA 2014 GVEA MSW Glacier Fork Anchorage MSW 2015 2016 Renewable Energy % In 2025 2017 49.07% 2018 GVEA 1X1 NPole Retrofit 2019 2020 Anchorage LMS100 2021 Total Capital Investment ($000) 2022 $8,381,277 2023 2024 2025 Chakachamna 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 GVEA 1x1 6FA 2038 2039 2040 2041 2042 Anchorage LMS100 2043 2044 2045 2046 GVEA LM6000 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 Anchorage LMS100 2058 2059 2060 GVEA LM6000 ALASKA RIRP STUDY Black &Veatch 13-25 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B With Higher Gas Prices Year Unit Additions 2011 Nikiski Wind Cumulative Present Worth Cost ($000) 2012 Anchorage 1x1 6FA $14,064,201 2013 2014 Glacier Fork GVEA MSW 2015 Anchorage MSW 2016 Renewable Energy % In 2025 2017 Kenai Wind 61.95% 2018 Mount Spurr 2019 2020 Mount Spurr 2021 Anchorage 1x1 6FA Total Capital Investment ($000) 2022 Anchorage LM6000 $9,248,373 2023 2024 2025 Chakachamna Kenai Wind 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 GVEA LMS100 2038 2039 2040 2041 2042 GVEA 1x1 6FA 2043 2044 2045 2046 Kenai Hydro 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 GVEA LMS100 2058 2059 2060 Anchorage LM6000 ALASKA RIRP STUDY Black &Veatch 13-26 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B Without Chakachamna Year Unit Additions 2014 Nikiski Wind Healy Clean Coal Cumulative Present Worth Cost ($000) 2012 Fire Island $14,331,969 2013 Anchorage 1x1 6FA 2014 Glacier Fork 2015 Anchorage MSW 2016 Renewable Energy % In 2025 2017 GVEA MSW 38.06% 2018 GVEA 1X1 NPole Retrofit 2019 2020 Mount Spurr 2021 Anchorage 1x1 6FA Total Capital Investment ($000) 2022 Mount Spurr $7,719,034 2023 2024 2025 GVEA LM6000 2026 2027 2028 2029 2030 Anchorage 2x1 6FA 2031 2032 2033 2034 2035 2036 2037 Anchorage LMS100 2038 2039 2040 2041 2042 Anchorage LMS100 2043 2044 2045 2046 HEA LM6000 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 GVEA 1x1 6FA 2058 2059 2060 ALASKA RIRP STUDY Black &Veatch 13-27 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 1A/1B With Chakachamna Capital Costs Increased by 75% Year Unit Additions 2011 Nikiski Wind Healy Clean Coal 2012 Fire Island 2013 Anchorage 1x1 6FA 2014 Glacier Fork 2015 Anchorage MSW 2016 2017 GVEA MSW 2018 GVEA 1X1 NPole Retrofit 2019 2020 Mount Spurr 2024 Anchorage 1x1 6FA 2022 2023 Mount Spurr 2024 2025 GVEA LM6000 2026 2027 2028 2029 2030 Anchorage 2x1 6FA 2031 2032 2033 2034 2035 2036 2037 Anchorage LMS100 2038 2039 2040 2041 2042 Anchorage LMS100 2043 2044 2045 2046 HEA LM6000 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 GVEA 1x1 6FA 2058 2059 2060 Cumulative Present Worth Cost ($000) $14,331,969 Renewable Energy % In 2025 38.06% Total Capital Investment ($000) $7,719,034 Black &Veatch 13-28 February 2010 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY |1A/1B With Susitna (Lower Low Watana Non-Expandable Option)Forced Year Unit Additions 2011 Nikiski Wind Healy Clean Coal 2012 2013 2014 Glacier Fork Anchorage MSW GVEA MSW 2015 Anchorage 1x1 6FA 2016 2017 2018 GVEA 1X1 NPole Retrofit 2019 2020 Mount Spurr 2021 Anchorage 1x1 6FA 2022 Mount Spurr 2023 2024 2025 Lower Low Watana 2026 2027 2028 2029 2030 MEA Hydro 2031 2032 2033 2034 2035 2036 2037 Anchorage LM6000 2038 2039 2040 2041 2042 GVEA 1x1 6FA 2043 2044 2045 2046 Kenai Hydro 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 Anchorage 1x1 6FA 2058 2059 2060 Cumulative Present Worth Cost ($000) $15,228,141 Renewable Energy %In 2025 61.01% Total Capital Investment ($000) $12,420,673 Black &Veatch 13-29 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B With Susitna (Low Watana Non-Expandable Option)Forced Year Unit Additions 2011 Nikiski Wind Healy Clean Coal 2012 2013 2014 Glacier Fork Anchorage MSW GVEA MSW 2015 Anchorage 1x1 6FA 2016 2017 2018 GVEA 1X1 NPole Retrofit 2019 2020 Mount Spurr 2021 Anchorage 1x1 6FA 2022 Mount Spurr 2023 2024 2025 Low Watana (Non-Expandable) 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 Chakachamna 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 2058 2059 2060 Cumulative Present Worth Cost ($000) $15,039,926 Renewable Energy % In 2025 63.01% Total Capital Investment ($000) $15,056,672 ALASKA RIRP STUDY Black &Veatch 13-30 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B With Susitna (Low Watana Expandable Option)Forced Year Unit Additions 2011 Nikiski Wind Healy Clean Coal 2012 2013 2014 Glacier Fork Anchorage MSW GVEA MSW 2015 Anchorage 1x1 6FA 2016 2017 2018 GVEA 1X1 NPole Retrofit 2019 2020 Mount Spurr 2021 Anchorage 1x1 6FA 2022 Mount Spurr 2023 2024 2025 Low Watana (Expandable) 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 Chakachamna 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 2058 2059 2060 Cumulative Present Worth Cost ($000) $15,345,647 Renewable Energy % In 2025 60.18% Total Capital Investment ($000) $15,588,186 ALASKA RIRP STUDY Black &Veatch 13-31 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B With Susitna (Low Watana Expansion Option)Forced | Year Unit Additions 2011 Nikiski Wind Healy Clean Coal 2012 2013 2014 Glacier Fork Anchorage MSW GVEA MSW 2015 Anchorage 1x1 6FA 2016 2017 2018 GVEA 1X1 NPole Retrofit 2019 2020 Mount Spurr 2021 Anchorage 1x1 6FA 2022 Mount Spurr 2023 2024 2025 Low Watana (Expandable) 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 Low Watana Expansion 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 2058 2059 2060 Cumulative Present Worth Cost ($000) $14,854,377 Renewable Energy % In 2025 66.90% Total Capital Investment ($000) $14,068,673 ALASKA RIRP STUDY Black &Veatch 13-32 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B With Susitna (Watana Option)Forced Year Unit Additions 2011 Nikiski Wind Healy Clean Coal Cumulative Present Worth Cost ($000) 2012 Fire Island $15,682,774 2013 2014 Glacier Fork Anchorage MSW 2015 Anchorage 1x1 6FA 2016 Renewable Energy % In 2025 2017 GVEA MSW 70.97% 2018 GVEA 1X1 NPole Retrofit: 2019 2020 Anchorage LM6000 2021 Anchorage 1x1 6FA Total Capital Investment ($000 2022 GVEA LM6000 $13,210,718 2023 2024 2025 Watana 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 2058 2059 2060 ALASKA RIRP STUDY Black &Veatch 13-33 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B With Susitna (High Devil Canyon Option)Forced Year Unit Additions 2011 Nikiski Wind Healy Clean Coal Cumulative Present Worth Cost ($000) 2012 $14,794,958 2013 Anchorage 1x1 6FA 2014 Glacier Fork;GVEA MSW 2015 Anchorage MSW 2016 Renewable Energy % In 2025 2017 66.92% 2018 GVEA 1X1 NPole Retrofit 2019 2020 Mount Spurr 2021 Anchorage 1x1 6FA Total Capital Investment ($000) 2022 GVEA LM6000 $11,633,307 2023 2024 2025 High Devil Canyon 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 2058 2059 2060 ALASKA RIRP STUDY Black &Veatch 13-34 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B With Modular Nuclear Year Unit Additions 2011 Nikiski Wind Healy Clean Coal Cumulative Present Worth Cost ($000) 2012 Fire Island $13,841,100 2013 Anchorage 1x1 6FA 2014 Glacier Fork 2015 Anchorage MSW 2016 Renewable Energy % In 2025 2017 GVEA MSW 60.51% 2018 GVEA 1X1 NPole Retrofit 2019 2020 Mount Spurr 2021 Anchorage 1x1 6FA Total Capital Investment ($000) 2022 Mount Spurr $9,105,176 2023 2024 2025 Chakachamna . Kenai Wind Anchorage Nuc 2026 2027 2028 2029 2030 Kenai Hydro 2031 2032 2033 2034 2035 2036 2037 GVEA LMS100 2038 2039 2040 2041 2042 Anchorage LMS100 2043 2044 2045 2046 Anchorage LM6000 2047 2048 2049 2050 2091 2052 2053 2054 2055 2056 2057 Anchorage LMS100 2058 2059 2060 Anchorage LM6000 ALASKA RIRP STUDY Black &Veatch 13-35 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B With Tidal Year Unit Additions 2011 Nikiski Wind Healy Clean Coal Cumulative Present Worth Cost ($000) 2012 Fire Island $13,712,483 2013 Anchorage 1x1 6FA 2014 Glacier Fork 2015 Anchorage MSW 2016 Renewable Energy % In 2025 2017 GVEA MSW 65.52% 2018 GVEA 1X1 NPole Retrofit 2019 2020 Mount Spurr 2021 Anchorage 1x1 6FA Total Capital Investment ($000) 2022 Mount Spurr $9,679,006 2023 2024 2025 Chakachamna Turnagain Tidal Arm 2026 2027 2028 2029 2030 Kenai Hydro 2031 2032 2033 2034 2035 2036 2037 GVEA LMS100 2038 2039 2040 2041 2042 GVEA 1x1 6FA 2043 2044 2045 2046 Anchorage LM6000 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 GVEA LMS100 2058 2059 2060 ALASKA RIRP STUDY Black &Veatch 13-36 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B With Lower Coal Capital and Fuel Costs Year Unit Additions 2011 Nikiski Wind Healy Clean Coal Cumulative Present Worth Cost ($000)_ 2012 Fire Island $13,624,595 2013 Anchorage 1x1 6FA 2014 Glacier Fork 2015 Anchorage MSW 2016 Renewable Energy % In 2025 2017 GVEA MSW 62.32% 2018 GVEA 1X1 NPole Retrofit 2019 2020 Mount Spurr 2021 Anchorage 1x1 6FA Total Capital Investment ($000) 2022 Mount Spurr $9,086,710 2023 2024 2025 Chakachamna 2026 2027 2028 2029 2030 Kenai Hydro 2031 2032 2033 2034 2035 2036 2037 GVEA LMS100 2038 2039 2040 2044 2042 GVEA 1x1 6FA 2043 2044 2045 2046 Anchorage LM6000 2047 2048 2049 2050 2054 2052 2053 2054 2055 2056 2057 GVEA LMS100 2058 2059 2060 ALASKA RIRP STUDY Black &Veatch 13-37 February 2010 SECTION 13 SUMMARY OF RESULTS 1A/1B With Federal Tax Credits for Renewables | Year Unit Additions 2011 Nikiski Wind Healy Clean Coal Cumulative Present Worth Cost ($000) 2012 Fire Island $12,953,856 2013 Anchorage 1x1 6FA 2014 Glacier Fork 2015 Anchorage MSW 2016 Renewable Energy % In 2025 2017 Kenai Wind 67.56% 2018 Mount Spurr 2019 2020 GVEA 1X1 NPole Retrofit 2021 Anchorage 1x1 6FA Total Capital Investment ($000) 2022 Mount Spurr $9,256,012 2023 2024 2025 GVEA MSW Chakachamna 2026 2027 2028 2029 2030 Kenai Hydro 2031 2032 2033 2034 2035 2036 2037 GVEA LMS100 2038 2039 2040 2041 2042 GVEA 1x1 6FA 2043 2044 2045 2046 Anchorage LM6000 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 GVEA LMS100 2058 2059 2060 Kenai Wind ALASKA RIRP STUDY Black &Veatch 13-38 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY 14.0 IMPLEMENTATION RISKS AND ISSUES In this section,Black &Veatch identifies a number of general risks and issues that must be addressed regardless of the resource future that is chosen by stakeholders,including the utilities and State policy makers. This is followed by a discussion of the risks and issues associated with each alternative generation resourcetypeincludingtransmission,and the actions that should be taken to address these resource-specific risks and issues. 14.1.General Risks and Issues In this subsection,Black &Veatch identifies and discuss a number of general issues and risks that relate to the implementation of this RIRP.These general issues and risks are grouped into the following categories: e Organizational Resource Fuel Supply Transmission Market Development Financing and Rate Legislative and Regulatory Value of Optionality 14.1.1 |Organizational Risks and Issues As previously discussed,the four resource plans that have been developed as part of this project focus on the Railbelt region as a whole.In other words,the four alternative resource plans were developed on a comprehensive regional basis to minimize costs,while maintaining adequate reliability,rather than for the individual utilities. 14.1.1.1 Regional Implementation The possible formation of a new Railbelt regional generation and transmission entity (i.e.,GRETC)is under consideration.The functional responsibilities of this new regional entity would include: e Independent,coordinated operation of the Railbelt electric transmission system e Region-wide economic commitment and dispatch of the Railbelt's generation facilities e Region-wide resource and transmission expansion planning e Joint identification,planning and development of new generation and transmission facilities for the Railbelt region The existing Railbelt utilities would retain the responsibility for providing traditional distribution and customer services,such as moving power from transmission/distribution substations to individual customers, meter reading,turn-ons/offs,billing and responding to customer inquiries, Black &Veatch 14-1 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY Taking a regional approach to economic dispatch and system operation,integrated resource planning,and project planning and development will most likely lead to better results than the current situation of six individual utilities working separately to meet the needs of their own residential and commercial customers without full regard to the benefits of coordination of activities among the utilities,provided that the regional entity has the appropriate governance structure,and financial and technical expertise.Additional benefits of a regional entity will likely include: A regional entity,with rational regional planning,would enable the region to identify and prioritize projects on a regional basis and it puts the State in a better position to evaluate,award and monitor funding. A regional entity improves the opportunities to obtain the benefits of economies of scale in generation,transmission,and DSM/EE projects and programs. The formation of a regional entity could lead to a reduction in the required levels of reserve margins over time. A regional entity is better able to integrate non-dispatchable resources,such as wind and solar,given the impact of these resources on system operation and reliability. With regard to project development,the concentration of staff within one organization will increase the ability to make timely and effective mid-course corrections,as required. A regional entity is in a better position to manage risks which is particularly important given the current circumstances in the Railbelt region. A regional entity could also result in other cost savings,including: o The region would need to develop only one regional Integrated Resource Plan,as opposed to three or more Integrated Resource Plans,every three to five years. o Legal and consulting expenses can be reduced as more issues are addressed on a regional basis versus on an individual utility basis. o Total staffing levels in certain areas on a regional basis can likely be reduced. o Better access to lower cost financing due to the overall financial strength of the regional entity relative to the six individual utilities. A regional entity would be responsible for development and implementation of a single region-wide DSM/EE program-related communications and outreach effort,thereby ensuring consistency of message and procedures for participation,along with the attendant cost efficiencies involved.This would help avoid confusion and facilitate use of mass marketing,while still enabling co-branding with individual Railbelt utilities. A single point of contact for DSM/EE activities for the region would make program administration and evaluation much easier.All data would be housed in a central DSM/EE tracking system for ease of tracking progress towards the achievement of goals,reporting on individual entities or total,and tracking performance of vendors. The formation of a regional entity can increase the flexibility of the region to respond to major events (e.g.,a large load increase,such as a new or expanded mine). A regional entity would be in a better position to work with Enstar Natural Gas Company and the gas producers to address the region's energy issues in a more comprehensive manner. Black &Veatch 14-2 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY This study was undertaken largely on the premise that such a regional entity would be formed to implement the chosen RIRP.While it is not an absolute requirement that a regional entity be formed to implement the RIRP,such implementation would be considerably more difficult if it is left up to the six individual Railbelt utilities,as they are required under their own governance policies to focus on identifying and implementing the best solutions for their own members and customers,as opposed to focusing on the most optimal regionalsolution. It is Black &Veatch's belief that the formation of a regional entity is critical to implementing many of the recommendations of this report,whether the regional entity is the proposed GRETC or a different,but similar, regional entity.Black &Veatch also believes that the formation of this entity should occur as quickly as possible;delay will only make the challenges greater and,if the regional entity is not formed now,decisions will need to be made by individual utilities and these decisions will not result in optimal results from a regional perspective.Suboptimal solutions result in higher costs,lower reliability and the inability to manage the successful integration of DSM/EE resources and renewable resources into the Railbelt system. 14.1.1.2 Achieving Economies of Scale The Railbelt utilities,to date,have not been able to take full advantage of economies of scale for several reasons.First,as previously noted,the combined peak load of the six Railbelt utilities is still relatively small. Second,the Railbelt transmission grid's lack of redundancies and interconnections with other regions has placed reliability-driven limits on the size of generation facilities that could be integrated into the Railbelt region. Third,the fact that each utility has developed their own long-term resource plans has led to less optimal results (from a regional perspective)relative to what could be accomplished througha rational,fully coordinated regional planning process.Finally,the existence of six separate utilities,and their small size on an individual utility basis,has restricted their ability to take advantage of economies of scale with regards to staffing and their skill sets.For example,the development of six separate programs to develop and deliver DSM/EE programs is a considerably more difficult challenge than would be the case if there was one regional entity,with the responsibility for developing and delivering DSM/EE programs to residential and commercial customers throughout the Railbelt region. In addition to the benefits of scale related to generation and transmission resources,there are benefits associated with staffing,including: e The concentration of staff would likely lead to more sophisticated generation and transmission planning,resulting in better regional resource planning decisions. e Better coordination is possible if all regional employees with generation and transmission responsibilities are part of one organization. e Depth of bench -it is easier to take advantage of the depth of everyone's skills and expertise when everyone works for one organization,and greater specialization can occur. e The concentration of staff increases the ability of the regional entity to keep abreast of new technologies (e.g.,renewables)and industry trends.©Theconcentration of staff also increases the ability of the Railbelt region to develop and support the delivery of cost-effective renewables and DSM/EE programs. Black &Veatch 14-3 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY 14.1.2 |Resource Risks and Issues There are a myriad of risks and issues associated with the implementation of specific resource options, whether DSM/EE,generation,or transmission.General areas of risk are discussed below and resource specific issues and risks are discussed in the next subsection. 14.1.3.Fuel Supply Risks and Issues Natural gas has been the predominant source of fuel for electric generation used for the customers of Chugach,ML&P,MEA,Homer and Seward.Additionally,customers in Fairbanks have benefited from natural gas-generated economy energy sales in recent years. There are a number of inherent risks whenever a utility or region is so dependent upon one fuel source including risks related to prices,availability and deliverability.An additional risk faced by Chugach is the fact that its current gas supply contracts are expected to expire in the 2010-2012 timeframe.An additional problem faced by the Railbelt utilities,due to their dependence on natural gas,is the fact that existing developed reserves in the Cook Inlet are declining as well as the current deliverability of that gas. Consequently,the Railbelt region will not be able to continue its heavy dependence upon natural gas in the future unless enhanced gas supplies become available.Those enhanced supplies could include additional reserves discovered in the Cook Inlet,new reserves discovered in basins within or near the Railbelt region, North Slope gas delivered by an interstate pipeline,or a LNG import terminal with access to LNG suppliers outside Alaska. Historically low prices for natural gas in the Cook Inlet region have been rationalized in some cases as a consequence of "stranded gas”in supply that exceeds the available market outlets.But in fact the export of LNG to Japan,where premium prices are assured,has provided the most significant market outlet and has made the "stranded gas”argument unconvincing.Indeed,the LNG export outlet has served as much of the financial incentive for producers to continue gas production from Cook Inlet. Whether new gas supplies from the Cook Inlet become available or gas from the North Slope is brought to the Railbelt region,one reality can not be escaped:future gas supply prices will be higher than in past experience. For additional gas supplies in the Cook Inlet to become available,prices will need to increase to encourage exploration and production,and to help offset losses if LNG exports come to an end.This results from the fact that oil and gas producers make investment decisions based upon expected returns relative to investment opportunities available elsewhere in the world. In the case of North Slope gas supplies,the cost,probability and timing of potential gas flows to the Railbelt region are unknown at this time.Nevertheless,given the construction lead times for a potential gas pipeline to provide gas from the North Slope,gas from that region is unlikely to be available for a number of years.Furthermore,if gas from the North Slope becomes available in the Railbelt region through either the Bullet Line or Spur Line,prices will likely be tied to market prices since potential natural gas flows to the Railbelt region will likely be just one of the competing demands for the available gas.Additionally,the pipelinetransmissionratesthatwillbepaidtomovegastotheRailbeltregionwillbesignificantlyhigherthantherelativelylowtransportationratesthatareimbeddedinthedeliveredcostofgasfromCookInletsuppliersunderexistingcontracts. Black &Veatch 14-4 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY 14.1.4 Transmission Risks and Issues As previously noted,the Railbelt electric transmission grid has been described as a long straw,as opposed to the integrated,interconnected,and redundant grid that is in place throughout the lower-48 states.This characterization reflects the fact that the Railbelt electric transmission grid is an isolated grid with no external interconnections to other areas and that it is essentially a single transmission line running from Fairbanks to the Kenai Peninsula,with limited total transfer capabilities and redundancies. As aresult of the lack of redundancies and interconnections with other regions,each Railbelt utility is required to maintain higher generation reserve margins (reserve margins reflect the amount of extra capacity beyond the peak load requirement that a utility needs to assure reliable system operation in the event that a generating units fails)and higher spinning reserve requirements (spinning reserve represents the amount of capacity that is available to serve load instantaneously if an operating generator disconnects from the grid) than elsewhere in order to ensure reliability in the case of a generation or transmission grid outage. Furthermore,the lack of interconnections and redundancies exacerbates a number of the other issues facing the Railbelt region,such as:, e The requirement for larger regulating reserves (regulating reserves are extra capacity that are required to be synchronized and on-line and are able to adjust output both up and down in real-time as load fluctuates).This maintains stable frequency performance. ¢The requirement for enough units on-line that can influence the rate of change of frequency when the balance between real-time load and real-time generation is out of balance.The lack of other interconnected units result in a lower system inertia and,consequently,a much more rapid fluctuation rate for frequency.This issue assumes greater importance when high penetration of non-dispatchable generation (e.g.,wind)is being considered in the system. e The lack of interconnection coupled with the relatively small size of the Railbelt system also results in smaller unit sizes than would otherwise be considered.This means that the full benefit of economies of scale will not be available and possibly more limited potential for jointly developed larger projects., ¢Benefits of more economic system operation based on the potential for diversity of operation and wider power marketing transactions,as well as higher operation load factors for generators. e Environmental benefits of system interconnection could result in reductions,through inter-regional commitment and dispatch,of greenhouse gas (GHG)emissions from electricity production in thermal plants.The value of the avoided emissions may be expressed as the total reduction in GHG times the cost of the emissions. 14.1.5 Market Development Risks and Issues 14.1.5.1 Competitive Power Procurement An important market development-related issue relates to the ability of IPPs,or non-utility generators of electricity,to enter the market.To date,the level of IPP penetration is the Railbelt region has been minor. The most significant activity is the current efforts by Cook Inlet Regional,Inc./enXco to develop the Fire Island wind farm.Additionally,other activities include those by Ormat to develop the Mt.Spurr geothermal project.Other IPP development activities are either for smaller projects or are not as far along in the development process.However,none of these current activities are guaranteed to succeed.There are a number of reasons for lower IPP activity in the Railbelt region than has occurred in other regions of the country.Not the least of these reasons is the fact that IPPs must work with individual utilities to gainacceptanceontheirprojects,including the negotiation of power purchase agreements under varying terms andconditionsanddealingwithvariousgenerationinterconnectionrequirements.The region would likely benefit Black &Veatch 14-5 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY from the adoption of policies that attract IPP development of project alternatives under the resource addition parameters established by the RIRP.One such policy would be the development of a competitive power procurement policy that would establish a "level playing field”for IPP-proposed projects.Under competitive procurement,IPP developers would be able to bid projects that offer economic benefits to the grid against other economic options.This assures that the combination of resources selected would be the most economic options for customers. 14.1.5.2 Load Growth With regard to native load growth (e.g.,normal load growth resulting from residential and commercial customers),Railbelt utilities have experienced limited,stable growth in recent years.This stable native load growth is expected to continue in the years ahead,absent significant economic development gains in the region. There are,however,a number of potential significant,discrete load additions that could result from economic development efforts.These potential load additions could result from the development of new,or expansion of existing,mines (e.g.,Pebble and Donlin Creek),continued military base realignment,other economic development efforts and or State policy decisions.Additionally,there will likely be a significant increase in Railbelt population if the North Slope natural gas pipeline,and or the Spur Line or Bullet Line,is built. Where large discreet load additions occur,there will be associated changes in both generation and transmission infrastructure to maintain system reliability.Under a consolidated integrated resource plan the discreet additions would be coordinated with other regional reliability projects to minimize costs and to optimize system considerations such as the size,timing and location of new resources. 14.1.6 Financing and Rate Risks and Issues 14.1.6.1 Financing As noted above,the Railbelt utilities face a very significant challenge in terms of their ability to finance the future.Traditional means of financing by the Railbelt utilities going forward independently simply are inadequate given the capital investment requirements over the next 50 years that result from each of the four alternative resource plans.Essentially,the existing net cash flow for the individual utilities would not provide sufficient debt coverage ratios to support investment grade debt financing for large,multi-year construction projects.Even for a regional entity,the available net cash flow to support such projects would be difficult without State assistance. 14.1.6.2 Rate Design In addition to the challenge associated with securing the required financing,that capital investment will need to be recovered through rates,thereby resulting in higher monthly bills for residential and commercial customers.While the need to recover capital investments is a reality,innovative rate design options (e.g.,Construction-Work-in-Progress -CWIP)are available to smooth out these rate increases over time so that they are more affordable to residential and commercial customers.CWIP also helps to address the cash flow issues associated with financing new projects. Black &Veatch 14-6 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY 14.1.7 Legislative and Regulatory Risks and Issues 14.1.7.1 State Energy Policy The development of a RIRP is not the same as the development of a State Energy Plan;nor does it set State policy.Setting energy-related policies is the role of the Governor's office and State Legislature.With regard to energy policy making,however,the RIRP does provide a foundation of information and analysis that can be used by policy makers to develop important policies. Having said this,the development of a State Energy Policy and or related policies could directly impact the specific alternative resource plan chosen for the Railbelt region's future.As such,the RIRP may need to be readdressed as future energy-related policies are enacted. 14.1.7.2,Regulatory Commission of Alaska While it is not within the scope of this RIRP to address the level and quality of regulation for either the individual utilities or GRETC,the level and quality of regulation impacts current and future investment decisions by both the electric and natural gas industries. 14.1.8 Value of Optionality Optionality represents the ability to make other choices once an initial choice has been made.Given the large fixed cost commitments associated with generation and transmission projects,any optionality in a resource plan adds value.As previously discussed,the recent increases in natural gas prices highlight the dangers inherent from an over-reliance on one fuel source or generation technology.That is,given the sunk cost of generation from gas fired resources,there is little option for reducing costs as gas prices rise.Just as investors rely on a portfolio of assets to manage risk,it is important for utilities to develop a portfolio of assets to ensure safe,reliable and cost-effective service to customers.It also demonstrates the importance of maintaining flexibility. In this context,maintaining flexibility has two dimensions.The first dimension of flexibility relates to future generation resources and fuel supplies.Any future resource path should be chosen only if it is likely to enhance the region's ability to maintain and improve the region's resource asset portfolio flexibility. The second dimension of flexibility relates to the ability to adjust to changing State and Federal policies, whether they are related to a State Energy Plan,carbon emissions regulations,support of the North Slope gas pipeline and or the Bullet or Spur Lines,and so forth.Resource decisions being made by utility managers are increasingly driven or influenced by energy policy makers. Fuel supply diversity inherently has value in terms of risk management.Simply stated,the greater a region's dependence upon one fuel source,the less flexibility the region will have to react to future price and availability problems. The level of uncertainty facing the Railbelt region continues to grow,as do the risks attendant to utility operations.One important approach to risk management is to spread the risk to a greater base of investors and consumers so that the impact of those risks on individuals is reduced.Simply stated,the ability of the region to absorb the risks facing it is greater on a regional basis than it is on an individual utility basis. Black &Veatch 14-7 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY Additionally,maintaining flexibility is important.In that regard,even after a particular resource plan has been adopted,it is important to pursue activities that maintain the viability of other resource options; therefore,the region can modify it resource plan,as required,as the issues and risks associated with the selected resource plan become better known 14.2.Resource Specific Risks and Issues 14.2.1 Introduction The purpose of this section is to identify the primary issues and risks associated with the development of the following resource options: e DSM/EE e Generation resources,including natural gas,coal and modular nuclear,as well as renewable resources including large and small hydro,wind,geothermal,solid waste and tidal e Transmission resources 14.2.2 Resource Specific Risks and Issues --Summary The following table provides Black &Veatch's assessment of the relative magnitude of various categories of risks and issues for each resource type,including: e¢Resource Potential Risks -the risk associated with the total energy and capacity that could be economically developed for each resource option. e Project Development and Operational Risks -the risks and issues associated with the development of specific projects,including regulatory and permitting issues,the potential for construction costs overruns,actual operational performance relative to planned performance,and so forth.This category also includes non-completion risks once a project gets started,the risk that adverse operating conditions will severely damage the facilities resulting in a shorter useful life than expected,and project delay risks. e Fuel Supply Risks -the risks and issues associated with the adequacy and pricing of required fuel supplies. e Environmental Risks -the risks of environmental-related operational concerns and the potential for future changes in environmental regulations. e Transmission Constraint Risks -the risk that the ability to move power from a specific generation resources to where that power is needed,an issue that is particularly important for large generation projects and remote renewable projects. e Financing Risks -the risk that a regional entity or individual utility will not be able to obtain the financing required for specific resource options under reasonable and affordable terms and conditions. e Regulatory/Legislative Risks -the risk that regulatory and legislative issues could affect the economic feasibility of specific resource options. e Price Stability Risks -the risk that wholesale power costs will increase significantly as a result of changes in fuel prices and other factors (e.g.,CO,costs). Black &Veatch 14-8 February 2010 SECTION 14 IMPLEMENTATION RISKS AND ISSUES ALASKA RIRP STUDY Table 14-1 Resource Specific Risks and Issues -Summary Relative Magnitude of Risk/Issue "Project an -Co,° -Resource Development :.Transmission Regulatory/ Potential and Operational Fuel Supply Environmental Constraint Legislative Price Stability Resource Risks Risks Risks Risks Risks Financing Risks Risks Risks DSM/EE Moderate Limited N/A NIA N/A Limited -Moderate Limited Moderate Generation Resource Natural Gas Limited Limited Significant Moderate Limited Moderate Moderate Significant Coal Limited Moderate-Limited Moderate -Limited -Moderate Moderate Moderate Significant Significant Significant Significant Modular Nuclear Limited Significant Moderate Significant Limited Significant Significant Significant Large Hydro Limited Significant Limited Significant Significant Significant Significant Limited Small Hydro Moderate Moderate Limited Moderate Moderate Limited -Limited Limited Moderate Wind Moderate Moderate N/A Limited Moderate Limited -Limited Limited - Moderate Moderate Geothermal Moderate Limited -N/A Limited -Moderate -Limited -Limited Limited Moderate Moderate Significant Moderate Solid Waste Limited Moderate-N/A Significant Moderate Limited -Limited-Moderate Significant Moderate Moderate Tidal Limited Significant N/A Significant Moderate -Moderate -Moderate -Limited - Significant Significant Significant Moderate Transmission Limited Significant N/A Moderate N/A Significant Moderate -N/A Significant Black &Veatch 14-9 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY The following provides some commentary related to the basis for these qualitative assessment of resource specific risks and issues: e Resource Potential Risks Resource potential risks are deemed to be moderate for some of the renewables resource options primarily due to the fact that enough resource potential studies have not been completed to provide a high degree confidence in the amount of energy capacity and energy that could be provided by these different resource options.For other renewable resource options,initial studies indicate significant resources are available,but more detailed studies have not been conducted to ensure that these large potential resources can actually be converted into renewable generation.Based upon the studies that have been completed,there is a solid foundation for believing that each of these different forms of renewable resources offers the potential for relatively significant capacity and energy within the Railbelt region.However,additional studies must be completed to identify the most attractive locations and to firm up the resource potential estimates for each type of renewable resource technology. Resource potential risks and issues are relatively lower for natural gas,coal and modular nuclear,as well as for additional transmission resources. Resource potential risks associated with DSM/EE programs are more commonly related to the reliability,or lack thereof,of the resource in that it is less under the control of the utility and relies more on mass market decision-making and/or behavior. e Project Development and Operational Risks Project development and operational risks and issues are significant for modular nuclear,large hydro, tidal,and transmission.They are also fairly significant for coal and solid waste.In the case of large hydro,these risks are significant due to the stringent environmental and permitting issues that would need to be addressed.Additionally,the potential for significant construction cost overruns is significant for large hydro. Tidal power represents an option with significant potential in the Railbelt.However,this technology has not been widely commercialized and there are significant environmental and permitting risks and issues associated with this technology. In the case of transmission,project development risks are deemed significant due to NIMBY concerns and the rough terrain and difficult construction conditions that exist. Coal,solid waste,and modular nuclear face NIMBY concerns as well as permitting and licensing concerns. The project development-related risks are believed to be lower,or moderate,for the other types of renewable resources,including small hydro,wind,and geothermal;they are even lower,or minimal, for DSM/EE resources,and generation resources that are fueled by natural gas and other fossil fuels. Black &Veatch 14-10 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY Fuel Supply Risks Fuel supply-related risks are very significant for natural gas generation resources.They are generally limited for generation options that rely on other fossil fuels,and they do not apply to DSM/EE and the various renewable resources. Environmental Risks Environmental-related risks are believed moderate for natural gas generation,and moderate to significant for other fossil fueled generation options.Future carbon restrictions represent an important risk for all generation resources that rely on fossil fuels and are very significant in the case of coal. Environmental-related risks are shown as significant for modular nuclear,large hydro options,solid waste,and tidal power due to their potential environmental impact. They are believed to be moderate for small hydro and geothermal,and limited for wind based,in large part,on experience with these technologies in other regions of the country and elsewhere in theworld. Transmission Constraint Risks Existing transmission constraints are significant for large hydro because the current transmission network is insufficient to move large amounts of capacity and energy throughout the region which would be required for any large hydro project to be economic. Transmission constraints also represent a moderate to significant issue for geothermal and tidal, depending upon the ultimate amount of these resources developed within the region. They are believed to be moderate with regard to small hydro,wind,and solid waste due to the typical size of these projects and the fact that they can generally be developed throughout the Railbelt region, thereby reducing the need to have transmission to move the related capacity and energy from one area of the Railbelt region to another. Transmission constraints are deemed limited for natural gas-fuel generation,again due to the typical size of these projects and the fact that they can be located throughout the Railbelt region,and they do not exist with regard to DSM/EE resources due to the distributed nature of these resources. Financing Risks Financing risks and issues are significant for any large scale resource option including coal,modular nuclear,large hydro,and transmission resources.They are moderate for natural gas generation. Financing risks are limited to moderate for most of the renewable resources (e.g.,including small hydro,wind,geothermal,solid waste and tidal)depending upon the actual size of the projects developed;likewise they are limited to moderate for DSM/EE resources. Black &Veatch 14-11 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY e Regulatory/Legislative Risks Regulatory and legislative risks and issues are limited for smaller-scale renewable resources, including small hydro,wind,geothermal,and solid waste. They are moderate for DSM/EE resources,primarily due to the fact that regulatory (and potentially legislative)changes would be required to eliminate the disincentive that exists under the current regulatory framework for utilities to encourage customers to use less electricity.They are also believed to be moderate for natural gas and other fossil fueled generation resources. Regulatory and legislative risks and issues are believed to be significant for modular nuclear and large hydro,and moderate to significant for tidal and transmission resources. e Price Stability Risks Price stability risks and issues are limited for DSM/EE programs,small and large hydro,and geothermal;limited to moderate for wind and tidal.They are moderate for coal and solid waste,and significant for natural gas and modular nuclear. More detailed information related to the risks and issues associated with each type of resource options is provided in the following subsection. 14.2.3.Resource Specific Risks and Issues -Detailed Discussion This section provides more detailed information related to the risks and issues associated with each of the following types of resource options: e«DSM/EE e Generation Natural gas Coal Modular nuclear Large hydro Small hydro Wind Geothermal Solid waste Tidal e Transmission900000.0000This section consists of a series of tables that identifies the most significant risks and issues for each type of resource options,broken down by the major risk/issue categories discussed in the previous section.These tables also identify the primary actions that should be taken to address these risks and issues. Black &Veatch 14-12 February 2010 SECTION 14 IMPLEMENTATION RISKS AND ISSUES 14.2.3.1 DSM/EE ALASKA RIRP STUDY Table 14-2 Resource Specific Risks and Issues -DSM/EE .Resource:DSM/EE -. Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential Total economic resource potential is unknown General lack of Alaska-specific data to determine economic resource potential, including end-use saturations,measure persistence,weather sensitive impacts, and cost-effectiveness Reliability is a key concern with DSM since utilities have less control over its acquisition and management Establish Alaska-specific baseline information through the completion of region-wide residential and commercial end-use saturation surveys and customer attitudinal surveys Complete comprehensive economically achievable potential study that includes a detailed cost- effectiveness evaluation of all feasible DSM/EE measures Complete vendor surveys to determine availability and relative costs of DSM/EE measures in the Railbelt region Develop regional DSM/EE program measurement and evaluation protocols Focus programs on hard-wired technology replacements rather than behavioral based savings If demand reduction is a goal,focus DSM programs on peak load reduction program strategies that can be dispatched or under greater control by the utility Project Development Ineffectiveness and inefficiencies associated with six individual utilities developing their own DSM/EE programs Ineffectiveness and inefficiencies associated with lack of coordination between the electric utilities,Enstar, and AHFC Lack of customer awareness regarding DSMEEE options and economics Establish a regional entity (e.g.,GRETC or independent third party)to develop and deliver,in coordination with the six Railbelt utilities,DSM/EE efficiency programs to all customers in the Railbelt region Develop and implement regional DSMEEE programs in close coordination with Enstar and AHFC Develop public outreach program to increase awareness of DSM/EE options Develop and learn from near-term DSMEEE pilot programs throughout the Railbelt region Black &Veatch 14-13 February 2010 SECTION 14 IMPLEMENTATION RISKS AND ISSUES Table 14-2 (Continued) ALASKA RIRP STUDY Resource Specific Risks and Issues --DSM/EE Resource:DSM/EE Risk/Issue Category Description Primary Actions to Address Risk/Issue Fuel Supply ¢Not applicable e Notapplicable Environmental e Not applicable e Notapplicable Transmission Constraints |®Not applicable *Not applicable e eFinancingLackoffundingsourceforinitial activities (e.g.,collect baseline information and consumer education) required to build a viable and successful DSM/EE program Lack of stable source of long-term financing for DSM/EE program Legislature should appropriate funds for the initial development of a regional DSM/EE program, including 1)region-wide residential and commercial end-use saturation surveys,2)customer attitudinal survey,3)vendor surveys,4)comprehensive evaluation of economically achievable potential,and 5)detailed DSMEEE program design efforts e Increase State funding of low income weatherization and residential and energy audit (both residential and commercial) program e Aggressively pursue available Federal funding for DSM/EE programs e Consider implementation of a System Benefit Charge,or SBC, (i.e.,a surcharge on customer bills that would be dedicated to the funding of DSM/EE programs)to provide for the long-term funding of DSM/EEprograms Regulatory/Legislative The implementation of DSM/EE reduces energy sales and,therefore, reduces the ability of utilities to recover costs under current rate design principles Lack of innovative rate structures in the Railbelt region,such as time-of-use (TOU)and demand response (DR)rates Lack of strict building codes and enforcement of those codes Lack of State leadership related to DSM/EE e Implement a decoupling mechanism so that a regional entity and or the individual Railbelt utilities can still recover their costs even with lower sales e Allow utilities to develop pilot programs to test the effectiveness of TOU and DR rates e Establish more stringent residential and commercial building codes that lead to lower energy use in new homes and buildings and increase the enforcement of those building codes Black &Veatch 14-14 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY Table 14-2 (Continued) Resource Specific Risks and Issues -DSM/EE Resource:DSM/EE Risk/Issue Category Description Primary Actions to Address Risk/Issue Regulatory/Legislative e Establish State targets for DSM/EE(Continued)savings based on the economics of the programs e Establish State goals for reducing energy usage at State facilities e Develop and implement programs to increase energy efficiency in State buildings and schools Black &Veatch 14-15 February 2010 SECTION 14 IMPLEMENTATION RISKS AND ISSUES 14.2.3.2 Generation Resources 14.2.3.2.1 Generation Resources -Natural Gas Table 14-3 ALASKA RIRP STUDY Resource Specific Risks and Issues --Generation -Natural Gas Resource:Generation -Natural Gas Primary Actions to Address Risk/IssueRisk/Issue Category Description Resource Potential See Fuel Supply See Fuel Supply Project Development Development risks are well known and Not applicable understood Fuel Supply Near-term adequacy and deliverability of natural gas supplies appear inadequate Several long-term gas supply options exist but the relative risks and economics of those options have not been fully assessed e Electric utilities need to work closely with the State,gas producers and Enstar to ensure the adequacy of near-term gas supplies e Current LNG export agreement should not be extended and the related gas should be used for the needs of Railbelt gas and electric customers,although the loss of the LNG export outlet might require the Cook Inlet gas price to be re-set e Short-term imported LNG gas supplies should be secured to serve as transitional gas supply option e Local gas storage capabilities should be developed as soon as possible e The State should complete a detailed risk and cost evaluation of available long-term gas supply options to determine the best option e Once the most attractive long-term supplies of natural gas have been determined,detailed engineering studies and permitting activities should be undertaken e Appropriate commercial terms and pricing structures should be established to provide producers the incentive to increase exploration for additional Cook Inlet gas supplies e State should consider providing incentives to encourage additional exploration for Cook Inlet gas supplies Black &Veatch 14-16 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY Table 14-3 (Continued) Resource Specific Risks and Issues -Generation -Natural Gas Resource:Generation -Natural Gas Risk/Issue Category Description Primary Actions to Address Risk/Issue Environmental e Risk of accident e Continue efforts to enforce safety and operational regulations Transmission Constraints |*Proper location of gas-fired generation ¢Require that all proposed plant resources mitigates transmission locations also include transmission constraints infrastructure analyses and costs as part of any approval process Financing e For larger projects,financing can be e Formation of a regional G&T entity difficult given the financial strength of (e.g.,GRETC)would provide the Railbelt utilities greater financial capabilities e -Consider State assistance for new 2 gas-fired generation projects that replace old,inefficient natural gas plants Regulatory/Legislative e Potential future environmental e Monitor Federal legislative and regulations related to emissions,regulatory activities related to including carbon and other emissions emission regulations e Monitor technological developments regarding carbon capturing technologies (e.g.,carbon sequestration) Black &Veatch 14-17 February 2010 . SECTION 14 IMPLEMENTATION RISKS AND ISSUES 14.2.3.2.2 Generation Resources -Coal Table 14-4 ALASKA RIRP STUDY Resource Specific Risks and Issues -Generation -Coal Resource:Generation -Coal Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential Not applicable Not applicable Project Development Development risks are generally known and understood Not applicable Fuel Supply Not applicable Not applicable Environmental See Regulatory/Legislative Not applicable Transmission Constraints Location of new facilities can add to transmission constraints Expand Railbelt transmission network Require that all proposed plant locations also include transmission infrastructure analyses and costs as part of any approval process Financing For larger projects,financing can be difficult given the financial strength of the Railbelt utilities Formation of a regional G&T entity (e.g.,GRETC)would provide greater financial capabilities Regulatory/Legislative Potential future environmental regulations related to emissions, including carbon and other emissions, and coal mining Potential regulations of regarding ash disposal Monitor Federal legislative and regulatory activities related to emission regulations and coal mining Monitor technological developments regarding carbon capturing technologies (e.g.,carbon sequestration) Implement appropriate design to mitigate environmental impacts Black &Veatch 14-18 February 2010 SECTION 14 IMPLEMENTATION RISKS AND ISSUES 14.2.3.2.3 Generation Resources -Modular Nuclear Table 14-5 ALASKA RIRP STUDY Resource Specific Risks and Issues -Generation -Modular Nuclear Resource:Generation -Modular Nuclear Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential Resource potential would be very large, but technology not demonstrated ¢Monitor development and licensing of technology Project Development Significant permitting challenges exist for modular nuclear Public acceptability of modular nuclear is unknown Potential for construction cost overruns is significant Technology not fully developed e Work closely with resource agencies to identify permitting requirements - e Develop public outreach program to better determine public acceptability of modular nuclear e Implement best practices related to management of construction costs e Support research and development of technology and pilot projects Fuel Supply Not applicable e Notapplicable Environmental Environmental impacts of modular nuclear may not be significant,but public perception about environmental impacts may be very significant ¢Work closely with resource agencies to identify environmental issues e Conduct necessary studies to address resource agencies'issues and data requirements Transmission Constraints The small size of the modular nuclear projects should not pose transmission constraints e Require that all proposed plant locations also include transmission infrastructure analyses and costs as part of any approval process Financing The lack of technology demonstration at this small size may create concerns in the financing community Costs per kW may be significant e Formation of a regional G&T entity (e.g.,GRETC)would provide greater financial capabilities ©Consider alternative forms of State assistance reduce resistance to finance e Aggressively pursue available Federal funding Regulatory/Legislative NRC licensing is uncertain ¢Monitor NRC licensing process Black &Veatch 14-19 February 2010 SECTION 14 IMPLEMENTATION RISKS AND ISSUES 14.2.3.2.4 Generation Resources -Large Hydro Table 14-6 ALASKA RIRP STUDY Resource Specific Risks and Issues -Generation -Large Hydro -Resource:Generation -Large Hydro Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential Both Susitna and Chakachamna sites are adequate to play a major role in meeting the region's future electric capacity and energy requirements e Not applicable Project Development Significant permitting challenges exist for large hydro projects Public acceptability of large hydro is unknown Potential for construction cost overruns is significant Infrastructure needs to support project construction are significant ®Work closely with resource agencies to identify permitting requirements e Develop public outreach program to better determine public acceptability of large hydro e Implement best practices related to management of construction costs Fuel Supply Potential impact of climate change e Monitor water flows Environmental Environmental impacts of large hydro projects are potentially significant Work closely with resource agencies to identify environmental issues e Conduct necessary studies to address resource agencies'issues and data requirements Transmission Constraints Location of new facilities can add to transmission constraints Integration of large hydro facility into Railbelt transmission grid poses challenges e Expand Railbelt transmission network e Complete required studies to ensure the ability to integrate large hydro projects into the transmission grid Financing Financing requirements of a large hydro project are greater than the combined financial capabilities of the Railbelt utilities e Formation of a regional G&T entity (e.g.,GRETC)would provide greater financial capabilities e Consider alternative forms of State assistance for large hydro projects Regulatory/Legislative Potential future environmental regulations related to large hydro projects Regional commitment to large hydro is uncertain e Monitor Federal activities related to large hydro projects e Determine State policy regarding the desirability of large hydro projects e Establish State Renewable Portfolio Standard (RPS)targets e Develop State policies regarding Renewable Energy Credits (RECs) and Green Pricing Black &Veatch 14-20 February 2010 SECTION 14 IMPLEMENTATION RISKS AND ISSUES 14.2.3.2.5 Generation Resources -Small Hydro Table 14-7 ALASKA RIRP STUDY Resource Specific Risks and Issues -Generation -Small Hydro Resource:Generation-Small Hydro Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential Total economic resource potential is unknown Resource potential may be constrained by Railbelt regional system regulation requirements Complete regional economic potential assessment,including the identification of the most attractive sites Develop regional regulation strategy for non-dispatchable resources Project Development Ineffectiveness and inefficiencies associated with six individual utilities developing small hydro projects Lack of standard power purchase agreements for projects developed by IPPs Infrastructure needs to support construction may be significant Establish a regional entity (e.g.,GRETC)or rely on IPPs to identify and develop small hydro projects Develop regional standard power purchase agreements Develop regional competitive power procurement process to encourage IPP development of projects Fuel Supply Potential impact of climate change Monitor water flows Environmental Site specific environmental issues including impact on fish Comprehensive evaluation of site specific environmental impacts at attractive sites Transmission Constraints Location of new facilities can add to transmission constraints Integration of non-dispatchable resources into Railbelt transmission grid poses challenges Expand Railbelt transmission network Require that all proposed plant locations also include transmission infrastructure analyses and costs as part of any approval process Develop regional strategy for the integration of non-dispatchable resources Financing Cost per kW can be significant Aggressively pursue available Federal funding for renewable projects Regulatory/Legislative Regional commitment to renewable resources is uncertain Establish State RPS targets Develop State policies regarding RECs and Green Pricing Black &Veatch 14-21 *February 2010 SECTION 14 IMPLEMENTATION RISKS AND ISSUES 14.2.3.2.6 Generation Resources Wind Table 14-8 ALASKA RIRP STUDY Resource Specific Risks and Issues -Generation -Wind Resource:Generation -Wind Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential Total economic resource potential is unknown Resource potential may be constrained by Railbelt regional system regulation requirements e Complete regional economic potential assessment,including the identification of the most attractive sites *Develop regional regulation strategy for non-dispatchable resources Project Development Ineffectiveness and inefficiencies associated with six individual utilities developing wind projects Lack of standard power purchase agreements for projects developed by IPPs e Establish a regional entity (e.g.,GRETC)or rely on IPPs to identify and develop wind projects e Develop regional standard power purchase agreements ®Develop regional competitive power procurement process to encourage IPP development of projects Fuel Supply Not applicable e Notapplicable Environmental Site specific environmental issues Comprehensive evaluation of site specific environmental impacts at attractive sites Transmission Constraints Location of new facilities can add to transmission constraints Integration of non-dispatchable resources into Railbelt transmission grid poses challenges e Expand Railbelt transmission network e Require that all proposed plant locations also include transmission infrastructure analyses and costs as part of any approval process ©Develop regional strategy for the integration of non-dispatchable resources Financing Cost per kW can be significant e Aggressively pursue available Federal funding for renewable projects Regulatory/Legislative Regional commitment to renewable resources is uncertain e Establish State RPS targets Develop State policies regarding RECs and Green Pricing Black &Veatch 14-22 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY 14.2.3.2.7 Generation Resources -Geothermal Table 14-9 Resource Specific Risks and Issues -Generation Geothermal -Resource:Generation -Geothermal ; Risk/Assue Category Description Primary Actions to Address Risk/Issue Resource Potential e Total economic resource potential is e Complete regional economic unknown potential assessment,including the identification of the most attractive sites Project Development e Ineffectiveness and inefficiencies e Establish a regional entity associated with six individual utilities (e.g.,GRETC)or rely on IPPs to developing geothermal projects identify and develop geothermal e Lack of standard power purchase projects agreements for projects developed by ¢Develop regional standard power IPPs purchase agreements e Infrastructure needs to support e Develop regional competitive construction are likely significant power procurement process to encourage IPP development of projects e Explore if synergies can be achieved for infrastructure with hydro projects Fuel Supply e Not applicable ¢Not applicable Environmental e Site specific environmental issues «Comprehensive evaluation of site specific environmental impacts at attractive sites Transmission Constraints |Location of new facilities can add to e Expand Railbelt transmission transmission constraints network e Require that all proposed plant locations also include transmission infrastructure analyses and costs as part of any approval process Financing e Cost per kW can be significant e Aggressively pursue available Federal funding for renewable projects Regulatory/Legislative e Regional commitment to renewable e Establish State RPS targets resources is uncertain e Develop State policies regarding e Potential future environmental RECs and Green Pricing regulations related to emissions,e Monitor Federal legislative and including carbon and other emissions regulatory activities related to emission regulations Black &Veatch 14-23 February 2010 SECTION 14 IMPLEMENTATION RISKS AND ISSUES 14.2.3.2.8 Generation Resources --Solid Waste Table 14-10 ALASKA RIRP STUDY Resource Specific Risks and Issues -Generation -Solid Waste Resource:Generation -Solid Waste Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential Total economic resource potential is unknown e Complete regional economic potential assessment,including the identification of the most attractive sites Project Development Ineffectiveness and inefficiencies associated with six individual utilities developing solid waste projects Lack of standard power purchase agreements for projects developed by IPPs e Establish a regional entity (e.g.,GRETC)or rely on IPPs to identify and develop solid waste projects e Develop regional standard power purchase agreements e Develop regional competitive power procurement process to encourage IPP development of projects Fuel Supply See Resource Potential Not applicable Environmental Site specific environmental issues e Comprehensive evaluation of site specific environmental impacts at attractive sites Transmission Constraints Location of new facilities can add to transmission constraints e Expand Railbelt transmission network e Require that all proposed plant locations also include transmission infrastructure analyses and costs as part of any approval process Financing Cost per kW is very significant e Aggressively pursue available Federal funding for renewable projects Regulatory/Legislative Regional commitment to renewable resources is uncertain Potential future environmental regulations related to emissions, including carbon and other emissions Establish State RPS targets Develop State policies regarding RECs and Green Pricing e Monitor Federal legislative and regulatory activities related to emission regulations Black &Veatch 14-24 February 2010 SECTION 14 IMPLEMENTATION RISKS AND ISSUES 14,.2.3.2.9 Generation Resources -Tidal Table 14-11 ALASKA RIRP STUDY Resource Specific Risks and Issues -Generation -Tidal Resource:Generation -Tidal Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential Total economic resource potential is unknown Resource potential may be constrained by Railbelt regional system regulation requirements e Complete regional economic potential assessment,including the identification of the most attractive sites e Develop regional regulation strategy for non-dispatchable resources Project Development Ineffectiveness and inefficiencies associated with six individual utilities developing tidal projects Lack of standard power purchase agreements for projects developed by IPPs Significant permitting challenges exist for large hydro projects Public acceptability of tidal is unknown Potential for construction cost overruns is significant Technology not fully developed e Establish a regional entity (e.g.,GRETC)or rely on IPPs to identify and develop tidal projects e Develop regional standard power purchase agreements e Develop regional competitive power procurement process to encourage IPP development of projects ®Work closely with resource agencies to identify permitting requirements e Develop public outreach program to better determine public acceptability of tidal e Implement best practices related to management of construction costs ¢Support research and development of technology and pilot projects Fuel Supply Not applicable Not applicable Environmental Environmental impacts of tidal projects are potentially significant Work closely with resource agencies to identify environmental issues e Conduct necessary studies to address resource agencies'issues and data requirements Transmission Constraints Location of new facilities can add to transmission constraints Integration of large tidal facility into Railbelt transmission grid poses challenges Integration of non-dispatchable resources into Railbelt transmission grid poses challenges e Expand Railbelt transmission network e Complete required studies to ensure the ability to integrate large tidal projects into the transmission grid e Require that all proposed plant locations also include transmission infrastructure analyses and costs as part of any approval process e Develop regional strategy for the integration of non-dispatchable resources Black &Veatch 14-25 February 2010 IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY Table 14-11 (Continued) Resource Specific Risks and Issues -Generation -Tidal Resource:Generation -Tidal Risk/Issue Category Description Primary Actions to Address Risk/Issue Financing e Financing requirements of a large tidal ¢Formation of a regional G&T entity project are greater than the combined (e.g.,GRETC)would provide financial capabilities of the Railbelt greater financial capabilities utilities ; e Consider alternative forms of State assistance for large tidal projects e Aggressively pursue available Federal funding for renewable projects Regulatory/Legislative e Regional commitment to renewable e Establish State RPS targets resources is uncertain e Develop State policies regarding RECs and Green Pricing Black &Veatch 14-26 February 2010 SECTION 14 IMPLEMENTATION RISKS AND ISSUES 14.2.3.3.Transmission Table 14-12 ALASKA RIRP STUDY Resource Specific Risks and Issues -Transmission Resource:Transmission Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential "Resource potential”is not limited; issue is determining the most appropriate projects,voltage,and siting e Implement transmission plan included in this RIRP Project Development Ineffectiveness and inefficiencies associated with six individual utilities developing transmission projects Potential for construction cost overruns is significant e Establish a regional entity (e.g.,GRETC)to identify and develop transmission projects e Implement best practices related to management of construction costs ®Centralize all siting and permitting at the State level Fuel Supply Not applicable Not applicable Environmental Potential for local environmental issues e Pursue statewide permitting by GRETC Transmission Constraints Not applicable e Not applicable Financing Financing requirements of transmission projects are significant Formation of a regional G&T entity (e.g.,GRETC)would provide greater financial capabilities e Consider alternative forms of State assistance for transmission projects Regulatory/Legislative Siting and permitting issues are potentially significant e Develop streamlined siting and permitting processes for transmission projects Black &Veatch 14-27 February 2010 CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY 15.0 CONCLUSIONS AND RECOMMENDATIONS This section provides an overview of the conclusions and recommendations resulting from the RIRP study. Purpose and Limitations of the RIRP e The development of this RIRP is not the same as the development of a State Energy Plan;nor does it set State policy.Setting energy-related policies is the role of the Governor and State Legislature.With regard to energy policy making,however,the RIRP does provide a foundation of information and analysis that can be used by policy makers to develop important policies. Having said this,the development of a State Energy Policy and or related policies could directly impact the specific alternative resource plan chosen for the Railbelt region's future.As such,the RIRP may need to be readdressed as future energy-related policies are enacted. «This RIRP,consistent with all integrated resource plans,should be viewed as a "directional”plan.In this sense,the RIRP identifies alternative resource paths that the region can take to meet the future electric needs of Railbelt citizens and businesses;in other words,it identifies the types of resources that should be developed in the future.The granularity of the analysis underlying the RIRP is not sufficient to identify the optimal configuration (e.g.,specific size,manufacturer,model,location,etc.)of specific resources that should be developed.The selection of specific resources requires additional and more detailed analysis, e The alternative resource options considered in this study include a combination of identified projects (e.g.,Susitna and Chakachamna hydroelectric projects,Mt.Spurr geothermal project,etc.),as well as generic resources (e.g.,Generic Hydro -Kenai,Generic Wind -GVEA,generic conventional generation alternatives,etc.).Identified projects are included,and shown as such,because they are projects that are currently at various points in the project development lifecycle.Consequently,there is specific capital cost and operating assumptions available on these projects.Generic resources are included to enable the RIRP models to choose various resource types,based on capital cost and operating assumptions developed by Black &Veatch.This approach is common in the development of integrated resource plans. Consistent with the comment above regarding the RIRP being a "directional”plan,the actual resources developed in the future,while consistent with the resource type identified,may be:1)the identified project shown in the resource plan (e.g.,Chakachamna),2)an alternative identified project of the same resource type (e.g.,Susitna);or 3)an alternative generic project of the same resource type.One reason for this is the level of risks and uncertainties that exist regarding the ability to plan,permit,and develop each project.Consequently,when looking at the resource plans shown in this report,it is important to focus on the resource type of an identified resource,as opposed to the specific project. ¢The capital costs and operating assumptions used in this study for alternative DSM/EE,generation and transmission resources do not consider the actual owner or developer of these resources.Ownership could be in the form of individual Railbelt utilities,a regional entity,or an independent power producer (IPP). Depending upon specific circumstances,ownership and development by IPPs may be the least-cost alternative. ¢As with all integrated resource plans,this RIRP should be periodically updated (e.g.,every three years)to identify changes that should be made to the preferred resource plan to reflect changing circumstances (e.g.,resolution of uncertainties),improved cost and performance of emerging technologies (e.g.,tidal), and other developments. Black &Veatch 15-1 February 2010 SECTION 15 CONCLUSIONS AND RECOMMENDATIONS Figure 15-1 ALASKA RIRP STUDY Cumulative Present Value Cost -Selected Reference and Sensitivity Cases $16,000,000 $14,000,000 $12,000,000 $10,000,000 $8,000,000 $6,000,000 $4,000,000 CumulativePresentValueCost($000)$2,000,000 $0 =m Plan 1A/1B ae = 1A/1B With High Gas Prices --=1A/1B With Susitna (Low Watana Expansion) --14/18 Without CO2 Taxes 1A/1B With Committed Units ---1A4/1B With Double DSM/EE Programs wa 1A/1B Without DSM/EE Programs --1A/1B Without Chakachamna Figure 15-2 Annual Wholesale Power Cost -Selected Reference and Sensitivity Cases 25.00 20.00 15.00 10.00 4 WholesalePowerCost(cents/kWh)-2010Dollars§.00 0.00 yp a YON KL WD Ph gD od oo ho PP POPPPGPPPPPKKKKKKSSPPPKLLKSKL Year a=Plan 1A/1B --Plan2A +----1A/1B With Double DSM/EE Programs -1A/1B Without DSM/EE Programs --1A/1B With High Gas Prices --1A/1B Without CO2 Taxes -1A/1B Without Chakachamna --1A/18 With Susitna (Low Watana Expansion) --1A/1B With Committed Units Black &Veatch 15-3 February 2010 CONCLUSIONS AND SECTION 15 .RECOMMENDATIONS 15.1 ALASKA RIRP STUDY Conclusions The primary conclusions from the RIRP study are discussed below. 1.The current situation facing the Railbelt utilities includes a number of challenging issues that place the region at a historical crossroad regarding the mix of DSW/EE,generation,and transmission resources that it will rely on to economically and reliably meet the future electric needs of the region's citizens and businesses.As a result of these issues,the Railbelt utilities are faced with the following challenges: o A transmission network that is isolated and has limited total transfer capabilities and redundancies. The inability of the region to take full advantage of economies of scale due to its limited size. A heavy dependence on natural gas from the Cook Inlet for electric generation. Limited and declining Cook Inlet gas deliverability. Lack of natural gas storage capability. The region's aging generation and transmission infrastructure. A heavy reliance on older,inefficient natural gas generation assets. The region's limited financing capability,both individually and collectively among the Railbelt utilities. o Duplicative and diffused generation and transmission expertise among the Railbelt utilities.o00aq0000The key factors that drive the results of Black &Veatch's analysis include the following: o The risks and uncertainties that exist for all alternative DSM/EE,generation,and transmission resource options. ©The future availability and price of natural gas. o The public acceptability and ability to permit a large hydroelectric project which is a greater concern,based upon Black &Veatch's discussions with numerous stakeholders,than the acceptability and ability to permit other types of renewable projects,such as wind and geothermal. o Potential future CO,prices,which would impact all fossil fuels,that may or may not result from proposed Federal legislation. o The region's existing transmission network,which limits:1)the ability to transfer power between areas within the region to minimize power costs,and 2)places a maximum limit on the amount of non-dispatchable resources that can be integrated into the region's transmission grid. o The ability of the region to raise the required financing,either by the utilities on their own or through a regional G&T entity. o Whether the Railbelt utilities develop a number of currently proposed projects that were selected outside of a regional planning process. Figures 15-1 and 15-2 graphically demonstrate how the results of the various reference and sensitivity cases are impacted by these important uncertainties.Figure 15-1 shows the cumulative present value cost for each year over the 50-year planning horizon;similarly,Figure 15-2 shows the annual wholesale power cost (cents/kWh)in 2010 dollars.In both cases,we have shown selected reference and sensitivity cases to highlight how dependent the results are to these key uncertainties. Black &Veatch 15-2 February 2010 CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY As can be seen in Figures 15-1,which shows cumulative net present value costs over the 50-year planning horizon,the 1A/1B With Susitna (Low Watana Expansion),1A/1B With no DSM/EE Programs,1A/1B Without Chakachamna,1A/1BWith Committed Units,and 1A/1B With High Gas Prices Sensitivity Cases are all higher cost than Scenario 1A/1B,in descending order.The 1A/1B With Double DSMW/EE Programs and 1A/1B With No CO,Taxes Sensitivity Cases are lower cost that Scenario 1A/1B. Figure 15-2 shows how significant the uncertainty regarding CO,taxes is with regard to the results. It also shows the economic value of achieving higher DSM/EE savings that were assumed in the Scenario 1A/1B Reference Case if those savings can be achieved.Also,shown is the fact that the other sensitivity cases are higher cost than Scenario 1A/1B. 3.The resource plans that were developed as part of this study for each Evaluation Scenario include a diverse portfolio of resources.If implemented,the RIRP will lead to: o The development of a resource mix resulting from a regional planning process. Greater reliance on DSM/EE and renewable resources and a lower dependence on natural gas. A more robust transmission network. More effective spreading of risks among all areas of the region. A greater ability to respond to large load growth should these load increases occur.Stated another way,the implementation of the RIRP will provide a stronger foundation upon which to base future economic development efforts. 4.The cost of this greater reliance on DSM/EE and renewable resources is less than the continued heavy reliance on natural gas based upon the base case gas price forecast that was used in this analysis.This result is achievable if the region builds a large hydroelectric project.There are uncertainties,at this point in time,regarding the environmental and/or geotechnical conditions under which a large hydroelectric project could be built.If a large hydroelectric facility can not be developed,or if the cost of the large hydroelectric project significantly exceeds the current preliminary estimates,then the costs associated with a predominately renewable future would be greater than continuing to rely on natural gas.00005.Our analysis shows that Scenarios 1A and 1B result in the same resources and,consequently,the same costs and emissions.In other words,the cost of achieving a renewable energy target of 50 percent by 2025 (Scenario 1B)is no greater than the cost of the unconstrained solution (Scenario 1A).This result applies only if a large hydroelectric project is built. 6.Scenarios 2A and 2B were evaluated to determine what the impact would be if the demand in the region was significantly greater than it is today.In fact,the per unit power costs were not less than Scenario 1A/1B due to the cost of Susitna which was the resource chosen to meet this additional load.. 7.Additionally,the implementation of a regional plan will result in lower costs than if the individual Railbelt utilities continue to go forward on their own.While the scope of this study did not include the development of separate integrated resource plans for each of the six Railbelt utilities,we did complete a sensitivity analysis to show the cost impact if the utilities develop their currently proposed projects (referred to as committed units)that were selected outside of a regional planning process.The Railbelt utilities are moving forward with these projects due to the existing uncertainty regarding the formation of GRETC.While this sensitivity case does not fully capture the incremental cost of the utilities acting independently over the 50-year planning horizon,it does provide an indication of Black &Veatch 15-4 February 2010 CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY the relative cost differential.Figure 15-3 shows the resulting total annual costs of the two different resource plans.In the aggregate,the cost of the Committed Unit Sensitivity Case was approximately 5.6 percent,or $484 million on a cumulative net present value cost basis,higher than Scenario 1A/1B. The main conclusion to draw from this graphic is that there are significant cost savings associated with the Railbelt utilities implementing a plan that has been developed to minimize total regionalcosts,while ensuring reliable service,as opposed to the individual utilities working separately to meettheneedsoftheirowncustomers. Figure 15-3 Comparison of Results -Scenario 1A/1B Versus Committed Units Sensitivity Case $16,000,000 $14,000,000 ------ $12,000,000 5 $10,000,000 +:-7 $8,000,000 a ; $8,000,000 :aa : $4,000,000 $2,000,000 ra+10]se ones en nS ee ee ee aCumulativePresentValueCost($000)[-Plan 1A/1B --1A/1B With Committed Units | 8.There are a number of risks and uncertainties regardless of the resource options chosen.For example: 1)there is a lack of Alaska-specific data upon which to build an aggressive region-wide DSM/EE program,2)the future availability and price of natural gas affects the viability of natural gas generation,and 3)the total economic potential of various renewable resources is unknown at this time.In some cases,these risks and uncertainties (e.g.,the ability to permit a large hydroelectric facility)might completely eliminate a particular resource option.Due to these risks and uncertainties, it will be important for the region to maintain flexibility so that changes to the preferred resource plan can be made,as necessary,as these resource-specific risks and uncertainties become more clear or get resolved. 9.Significant investments in the region's transmission network need to be made within the next 10 years to ensure the reliable and economic transfer of power throughout the region.Without these investments,providing economic and reliable electric service will be a greater challenge. Black &Veatch 15-5 February 2010 CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY 10.The increased reliance on non-dispatchable renewable resources (e.g.,wind)will require a higher 11. level of frequency regulation within the region to handle swings in electric output from these resources.An increased level of regulation has been included in Black &Veatch's transmission plan. Even with this increased regulation,however,the challenges associated with the integration of non- dispatchable resources will ultimately place a maximum limit on the amount of these resources that can be developed. The implementation of the RIRP does not require that a regional generation and transmission entity (e.g.,GRETC)be formed.However,the absence of a regional entity with the responsibility for implementing the RIRP will increase the difficulty of the region's ability to implement a regional plan and,in fact,Black &Veatch believes that the lack of a regional entity will,as a practical matter,mean that the RIRP will not be fully implemented.As a consequence,the favorable outcomes of the RIRP discussed above would not be realized.The interplay between the formation of a regional entity and the RIRP is shown in Figure 15-4. Figure 15-4 Interplay Between GRETC and Regional Integrated Resource Plan 45.2 Current RIRP Study |REGA StudySituation*Plan that economically .Lim schedules what,when,Umited redundancy and where to build,based *Limited economies on available fuel and *:of scale energy supplies Proposed Future Situation ©Dependenceon *$0-year time horizon RIRP GRETC +Robust transmissionfossilfuels«Competes generation,Results Formation *Diversified fuel supply *Limited Cook Inlet fansmission,fuel supply *Increased ¢System-wide power ratesgasdeliverabilityandDSM/energy OSM/energyandstorageefficiencyoptions@fficiency As ©Spread risk *Aging G&T *Considers CO,regulation +Increased es ieee!ae «State financial assistance infrastructure 7).Includes renewable [-*}renewables Ke GRETC.-Enabler:*Regional planning *Inefficient fuel use energy projects ©Reduced =Wise resource use ©Difficult financing +Arrives at a plan to build seed gas t +Respond to large toad *Duplicative G&T future infrastructure for ...growthrthminimumlong-un cost to «increased Financing Optionsexpertiseratepayerstransmission *Technical resources .¢Prefunding of capital . *Considers fuel supply requirements ¢Newtechnologies options and risks ¢Commercial bond market *State financial assistance (Brady Lake model} ©Construction-work-in-progress ea |0-Year.Transition Period?:: Recommendations This subsection summarizes the overall recommendations arising from this study,broken down into the following three categories: Recommendations -General Recommendations -Capital Projects Recommendations -Other Black &Veatch 15-6 February 2010 CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY 15.2.1 Recommendations -General The following general actions should be taken to ensure the timely implementation of the RIRP: 1.The State should work closely with the utilities and other stakeholders to make a decision regarding the formation of GRETC and to develop the required governance plan,financial and capital improvement plan,capital management plan and transmission access plan,and address other matters related to the formation of the proposed regional entity. The State should establish certain energy-related policies,including: o The pursuit of large hydroelectric facilities o DSM/EE program targets o RPS (i.e.,target for renewable resources),and the pursuit of wind,geothermal,and tidal (which will become commercially mature during the 50-year planning horizon)projects in addition to large hydroelectric projects;the passage of an RPS would be meaningful as a policy statement even though the preferred resource plan would achieve a 50 percent renewable level by 2025. o System benefit charge to fund DSM/EE programs and or renewable projects The State should work closely with the Railbelt utilities and other stakeholders to establish the specific preferred resource plan.In establishing the preferred resource plan,the economic results of the various reference cases and sensitivity cases evaluated in this study should be considered,as well as the environmental impacts discussed in Section 13 and the project-specific risks discussed in Section 14. Black &Veatch believes that the Scenario 1A/1B resource plan should be the starting point for the selection of the preferred resource plan as discussed below.Table 15-1 provides a summary of the specific resources that were selected,based upon economics,in the Scenario 1A/1B resource plan during the first 10 years. A project selected in Scenario 1A/1B after the first 10 years especially worthy of mention is the Chakachamna Hydroelectric Project in 2025. Another important consideration in the selection of a preferred resource plan is evaluation of the sensitivity cases evaluated,as presented in Section 13.Issues addressed through the sensitivity cases and considered in Black &Veatch's selection of a preferred resource plan include the following and are discussed in Table 15-2.Following that discussion,Table 15-3 provides a discussion regarding specific projects currently under development and their impact on the preferred resource plan. o What if CO,regulation doesn't occur? o What is the effect if the committed units are installed? o What if Chakachamna doesn't get developed? o What would be the impact of the alternative Susitna projects? There are several projects that are significantly under development and included in the preferred resource plan.These significantly developed projects include: o Healy Clean Coal Project (HCCP) ©Southcentral Power Project o Fire Island Wind Project Oo Nikiski Wind Project These projects are discussed in Table 15-3. Black &Veatch 15-7 February 2010 SECTION 15 CONCLUSIONS AND RECOMMENDATIONS ALASKA RIRP STUDY Table 15-1 Resources Selected in Scenario 1A/1B Resource Plan Project -Discussion DSM/EE Resources The full level of DSM/EE resources evaluated was selected based upon their relative economics.Sensitivity analysis indicates that even greater levels of DSM/EE may be cost-effective.The lack of Alaska-specific DSM/EE data causes the exact level of cost-effective DSM/EE to remain uncertain. Nikiski Wind The RIRP selected this project in the initial year.It is being developed as an IPP project and is well along in the development process.The ARRA potentially offers significant financial incentives if this project is completed by January 1,2013.These incentives could further improve its competitiveness.As a wind unit,it has no impact on planning reserves,but contributes to renewable generation. HCCP HCCP is completed and GVEA has negotiated with AIDEA for its purchase.This project was selected in the initial year of the plan. Fire Island Wind Project The Fire Island Wind Project is being developed as an IPP project with proposed power purchase agreements provided to the Railbelt utilities.The project may be able to benefit significantly from ARRA and the $25 million grant from the State for interconnection.This project was selected in 2012, Anchorage 1x1 6FA Combined Cycle The RIRP selected this unit for commercial operation in 2013.This unit is very similar in size and performance to the Southcentral Power Project being developed as a joint ownership project by Chugach and ML&P for 2013 commercial operation. The project appears well under development with the combustion turbines already under contract.The project fits well with the RIRP and the joint ownership at leastpartiallyreflectstheGRETCjointdevelopmentconcept. Glacier Fork Hydroelectric Project The RIRP selected this project for commercial operation in 2014,the first year that it was available for commercial operation in the models.Of the large hydroelectric projects,Glacier Fork is by far the least developed.Glacier Fork has very limited storage and thus does not offer the system operating flexibility of the other large hydroelectric units.There is also significant uncertainty with respect to its capital cost and ability to be licensed.Because it has such a minimal level of firm generation in the winter,it does not contribute significantly to planning reserves,but does contribute about 6 percent of the renewable energy to the Railbelt.Detailed feasibility studies and licensing are required to advance this option. Anchorage and GVEA MSW Units The RIRP selected these units in 2015 and 2017.Historically,mass burn MSW units such as those modeled,have faced significant opposition due to emissions of mercury,dioxin,and other pollutants.Other technologies which result in lower emissions,such as plasma arc,are not commercially demonstrated.The units included in the RIRP are relatively small (26 MW in total)and are not required to be installed to meet planning reserve requirements,but their base load nature contributes nearly 4 percent of the renewable energy.Detailed feasibility studies would be required to advance this alternative. GVEA North Pole Retrofit The retrofitting of GVEA's North Pole combined cycle unit with a second train using a LM6000 combustion turbine and heat recovery steam generator was selected in 2018 coincident with the assumption of the availability of natural gas to GVEA.The retrofit takes advantage of capital and operating cost savings resulting from the existing installation. Black &Veatch 15-8 February 2010 SECTION 15 CONCLUSIONS AND RECOMMENDATIONS ALASKA RIRP STUDY Table 15-1 (Continued) Resources Selected in Scenario 1A/1B Resource Plan Project Discussion Mt.Spurr Geothermal Project The first unit at Mt.Spurr was selected in 2020.Mt.Spurr's developer,Ormat, currently has commercial operation scheduled for 2017.Significant development activity remains for the project including verifying the geothermal resource.Mt. Spurr will also require significant infrastructure development including access roads and transmission lines.This infrastructure may correspond to similar infrastructure development required for Chakachamna which is selected in 2025 in the RIRP.As the implementation of the RIRP unfolds,there will likely be the need to adjust the timing of the resource additions following the implementation of the initial projects. Table 15-2 Impact of Selected Issues on the Preferred Resource Plan Issue Discussion | CO,Regulation The sensitivity case for Scenario 1A without CO,regulation selects the Anchorage LMS 100 project instead of Fire Island and Mt.Spurr in the first 10 years. Committed Units Installation of the committed units significantly increases the cost of Scenario 1A/1B.In addition to the committed units,this plan selects five wind units from 2016 through 2024 in response to CO, regulation.The plan with the committed units eliminates Chakachamna and does not meet the 50 percent renewable target by 2025, Chakachamna Chakachamna could fail to develop because of licensing or technical issues.Also,if the cost of Chakachamna were to increase to be equivalent to the alternative Susitna projects on a GWh basis,it would not be selected.The sensitivity case without Chakachamna for the first 10 years is identical to Scenario 1A/IB.The case does not meet the 50 percent renewable target by 2025 and is 5.2 percent higher in cost than the preferred resource plan. Susitna None of the alternative Susitna projects are selected in the Scenario 1A/1B resource plan.The least cost Susitna option,which is Low Watana Expansion,is 15.3 percent more than the preferred resource plan and 9.0 percent more than the case without Chakachamna.The 50 percent renewable requirement can not be met without Susitna if Chakachamna is not available. Black &Veatch 15-9 February 2010 SECTION 15 CONCLUSIONS AND RECOMMENDATIONS Table 15-3 ALASKA RIRP STUDY Projects Significantly Under Development Project Discussion Preferred Resource Plan Recommendation HCCP HCCP is completed and GVEA has negotiated with AIDEA for its purchase.The project is part of the least cost scenario.While CO,regulation has been assumed in the RIRP,those regulations are not in place and there is no absolute assurance that they will be in place or what the costs from the regulations will be.HCCP adds further fuel diversity to the Railbelt,especially to GVEA who doesn't currently have access to natural gas.Asa steam unit,HCCP improves transmission system stability. Black &Veatch recommends that HCCP be included in the preferred resource plan. Southcentral Power Project The Southcentral Power Project is well under development with the combustion turbines purchased.The timing and technology are generally consistent with the preferred resource plan.The project will improve the efficiency of natural gas generation in the Railbelt and permit the retirement of aging units. Black &Veatch recommends the continued development of the Southcentral Power Project as part of the preferred resource plan. Fire Island Wind Project The Fire Island Wind Project is being developed as an IPP project with proposed power purchase agreements provided to the Railbelt utilities.The project may be able to benefit significantly from ARRA and the $25 million grant from the State for interconnection.This project is part of the least cost plan and provides renewable energy to the Railbelt system.Issues with interconnection and regulation will need to be resolved. Subject to the successful negotiation of a purchase power agreement and successful negotiation of the interconnection and regulation issues,Black &Veatch recommends that it be part of the preferred resource plan in a time frame that allows for the ARRA benefits to be captured. Nikiski Wind Project The Nikiski Wind Project is an IPP project like Fire Island and has the same potential to benefit from ARRA.It is also part of the least cost plan. Like Fire Island,subject to successful negotiation of a purchase power agreement and successful negotiation of the interconnection and regulation issues,Black &Veatch recommends that it be part of the preferred resource plan in a time frame that allows for the ARRA benefits to be captured. Black &Veatch 15-10 February 2010 CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY In addition to these resources,Black &Veatch believes that Mt.Spurr,Glacier Fork,Chakachamna and Susitna should be pursued further to the point that the uncertainties regarding the environmental, geotechnical and capital cost issues become adequately resolved to determine if any of the projects could actually be built. In the case of the Mt.Spurr Geothermal Project,exploration should continue to determine the extent and characteristics of the geothermal resource at the site. In the case of Susitna,the primary focus should be on completing engineering studies to optimize the size and minimize the costs of the project.In the case of Glacier Fork and Chakachamna,the additional work should look for "fatal flaws”. Additionally,further analysis needs to be completed relative to integrating wind and other non- dispatchable renewable resources into the transmission network. 5.The State and Railbelt utilities should develop a public outreach program to inform the general public regarding the preferred resource plan,including the costs and benefits. 6.The State Legislature should make decisions regarding the level and form of State financial assistance that will be provided to assist the Railbelt utilities and AEA,under a unified regional G&T entity (i.e.,GRETC),develop the generation resources and transmission projects identified in the preferred resource plan. 7.The electric utilities,various State agencies,Enstar and Cook Inlet producers need to work more closely together to address short-term and long-term gas supply issues.Specific actions that should be taken include: o Development of local gas storage capabilities with open access among all market participants as soon as possible. o Undertake efforts to secure near-term LNG supplies to ensure adequate gas over the 10-year transition period until additional gas supplies can be secured either in the Cook Inlet,from the North Slope or from long-term LNG supplies. o The State should complete a detailed cost and risk evaluation of available long-term gas supply options to determine the best options.Once the most attractive long-term supplies of natural gas have been identified,detailed engineering studies and permitting activities should be undertaken to secure these resources. o Appropriate commercial terms and pricing structures should be established through State and regulatory actions to provide producers with the incentive to increase exploration for additional gas supplies in the Cook Inlet or nearby basins.This action is required to provide the necessary long-term contractual certainty to result in additional exploration and development. 15.2.2 Recommendations -Capital Projects Efforts should be undertaken to begin the development,including detailed engineering and permitting activities,of the following capital projects,which are included in Black &Veatch's recommended preferred resource plan. 1.Develop a comprehensive region-wide portfolio of DSM/EE programs. 2.Generation projects: o Projects under development (HCCP,Southcentral Power Project,Fire Island Wind Project,and Nikiski Wind Project) Black &Veatch 15-11 February 2010 CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY Glacier Fork Hydroelectric Project Generic Anchorage MSW Project Generic GVEA MSW Project GVEA North Pole Retrofit Project Mt.Spurr Geothermal Project Chakachamna Hydroelectric Project o Susitna Hydroelectric Project000000 Transmission and related substation projects,including the following projects which have been identified for priority attention because of their immediate impact on the reliability of the existing system.These projects are estimated to be required within the next five years. Soldotna to Quartz Creek Transmission Line ($84 million -Project B) Quartz Creek to University Transmission Line ($112.5 million -Project C) Douglas to Teeland Transmission Line ($37.5 million -Project D) Lake Lorraine to Douglas Transmission Line ($80 million -Project E) SVCs ($25 million -Other Reliability Projects) Funds to undertake the study of the Southern Intertie ($1 million) Funds to investigate the provision of regulation that will facilitate the integration of renewable energy projects into the Railbelt system ($50 million,including cost of BESS -Other Reliability Projects)000000015.2.3 Recommendations -Other Other actions,related to the implementation of the RIRP,that should be undertaken include: 1.The State Legislature should appropriate funds for the initial stages of the development of a regional DSMEEE program,including 1)region-wide residential and commercial end-use saturation surveys, 2)residential and commercial customer attitudinal surveys,3)vendor surveys,4)comprehensive evaluation of economically achievable potential,and 5)detailed DSM/EE program design efforts. Develop a regional DSM/EE program measurement and evaluation protocol. If GRETC is not formed,some type of a regional entity should be formed to develop and deliver DSMEEE programs to residential and commercial customers throughout the Railbelt region,in close coordination with the Railbelt utilities. Likewise,if GRETC is not formed,some type of a regional entity should be formed to develop the renewable resources included in the preferred resource plan. Establish close coordination between the Railbelt electric utilities,Enstar and AHFC regarding the development and delivery of DSM/EE programs. Aggressively pursue available Federal funding for DSMW/EE programs and renewable projects. Further development of tidal power should be encouraged due to its resource potential in the Railbelt region.Although this technology is not commercially available,in Black &Veatch's opinion,at this point in time,it has the potential to be economic within the planning horizon. The State and Railbelt utilities should work closely with resource agencies to identify environmental issues and permitting requirements related to large hydroelectric and tidal projects,and conduct the necessary studies to address these issues and requirements. Complete a regional economic potential assessment,including the identification of the most attractive sites,for all renewable resources included in the preferred resource plan. Black &Veatch 15-12 February 2010 CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY 10.Develop streamlined siting and permitting processes for transmission projects. 11.Develop a regional frequency regulation strategy for non-dispatchable resources. 12.Develop a regional competitive power procurement process and a standard power purchase agreement to provide IPPs an equal opportunity to submit qualified proposals to develop specific projects. 13.Federal legislative and regulatory activities,including those related to emissions regulations,should be monitored closely and influenced to the degree possible. 14.Monitor the licensing progress of small modular nuclear units. Black &Veatch 15-13 February 2010 NEAR-TERM IMPLEMENTATION SECTION 16 ACTION PLAN (2010-2012) ALASKA RIRP STUDY 16.0 NEAR-TERM IMPLEMENTATION ACTION PLAN (2010-2012) The purpose of this section is to provide Black &Veatch's recommended near-term implementation plan, covering the period from 2010 to 2012.Our recommended actions are grouped into the following categories: General actions Capital projects Supporting studies and activities Other actions ' In many ways,the near-term implementation plan shown in the following tables serves two objectives.First, it identifies the steps that should be taken during the next three years regardless of the alternative resource plan that is chosen as the preferred resource plan.Second,it is intended to maintain flexibility as the uncertainties and risks associated with each alternative resource become more clear and or resolved. 16.4 General Actions Table 16-1 Near-Term Implementation Action Plan -General Actions ..Actions Category"Description 'Timeline .Est.Cost General Actions ®The State should work closely with the utilities and other 2010 stakeholders to make a decision regarding the formation of GRETC and to develop the required governance plan, financial and capital improvement plan,capital management plan and transmission access plan,and address other matters related to the formation of the proposed regional entity e Establish State energy-related policies regarding:2010-2011 o The pursuit of large hydroelectric facilities o DSMEE program targets o RPS (ie.,target for renewable resources),and the pursuit of wind,geothermal,and tidal projects o System benefit charge to fund DSM/EE programs and or renewable projects e The State should work closely with the Railbelt utilities 2010 and other stakeholders to establish the preferred resource plan,using the Scenario 1A/1B resource plan as the starting point e Mt.Spurr,Glacier Fork,Chakachamna and Susitna should |2010-2011 be pursued further to the point that the uncertainties regarding the environmental,geotechnical and capital cost issues become adequately resolved to determine if any of these projects could actually be built $6.8 million $0.2 million Not applicable To be determined Black &Veatch 46-1 February 2010 SECTION 16 NEAR-TERM IMPLEMENTATION ACTION PLAN (2010-2012) Table 16-1 (Continued) Near-Term Implementation Action Plan -General Actions ALASKA RIRP STUDY Actions Category Description Timeline Est.Cost Develop a public outreach program to inform the public regarding the preferred resource plan,including the costs and benefits The State Legislature should make decisions regarding the level and form of State financial assistance that will be provided to assist the Railbelt utilities and AEA,under a unified regional G&T entity (i.e.,GRETC),develop the generation resources and transmission projects identified in the preferred resource plan The electric utilities,various State agencies,Enstar and Cook Inlet producers need to work more closely together to address short-term and long-term gas supply issues; specific actions that should be taken include: o Development of local gas storage capabilities as soon as possible o Undertake efforts to secure near-term LNG supplies to ensure adequate gas over the 10-year transition period until additional gas supplies can be secured o The State should complete a detailed cost and risk evaluation of available long-term gas supply options to determine the best options;once the most attractive long-term supplies of natural gas have been identified, detailed engineering studies and permitting activities should be undertaken to secure these resources o Appropriate commercial terms and pricing structures should be established through State and regulatory actions to provide producers with the incentive to increase exploration for additional gas supplies in the Cook Inlet or nearby basins 2010-2011 2010-2011 2010-2012 $0.1 million Not applicable To be determined Black &Veatch 16-2 February 2010 SECTION 16 NEAR-TERM IMPLEMENTATION ACTION PLAN (2010-2012) ALASKA RIRP STUDY 16.2 Capital Projects Table 16-2 Near-Term Implementation Action Plan -Capital Projects Actions Category Description Timeline Est.Cost Capital Projects |¢Develop a comprehensive region-wide portfolio of 2011-2016 |$34 million DSMEEE programs within first six years e Begin detailed engineering and permitting activities 2011-2016 Varies by associated with the generation projects identified in the project initial years of the preferred resource plan,including: o Projects under development (HCCP,Southcentral Power Project,Fire Island Wind Project,and Nikiski Wind Project) o Glacier Fork Hydroelectric Project o Generic Anchorage MSW Project o Generic GVEA MSW Project o GVEA North Pole Retrofit Project o Mt.Spurr Geothermal Project o Chakachamna Hydroelectric Project o Susitna Hydroelectric Project e Begin detailed engineering and permitting activities 2011-2016 Varies by associated with the transmission projects identified in the project initial years of the preferred resource plan,including: ©Soldotna to Quartz Creek Transmission Line ($84 million Project B) o Quartz Creek to University Transmission Line ($112.5 million -Project C) o Douglas to Teeland Transmission Line ($37.5 million -Project D) o Lake Lorraine to Douglas Transmission Line ($80 million -Project E) o SVCs ($25 million -Other Reliability Projects) o Funds to undertake the study of the Southern Intertie ($1 million) o Funds to investigate the provision of regulation that will facilitate the integration of renewable energy projects into the Railbelt system ($50 million, including cost of BESS -Other Reliability Projects) Black &Veatch 16-3 February 2010 SECTION 16 NEAR-TERM IMPLEMENTATION ACTION PLAN (2010-2012) 16.3 Supporting Studies and Activities Table 16-3 ALASKA RIRP STUDY Near-Term Implementation Action Plan -Supporting Studies and Activities .Actions Category Description Timeline Est.Cost Supporting e Studies and Activities The State Legislature should appropriate funds for the initial stages of the development of a regional DSM/EE program,including 1)region-wide residential and commercial end-use saturation surveys,2)residential and commercial customer attitudinal surveys,3)vendor surveys,4)comprehensive evaluation of economically achievable potential,and 5)detailed DSM/EE program design efforts Develop a regional DSM/EE program measurement and evaluation protocol The State and Railbelt utilities should work closely with resource agencies to identify environmental issues and permitting requirements related to large hydroelectric and tidal projects Conduct necessary studies to address resource agencies' issues and data requirements related to large hydroelectric and tidal projects Complete a regional economic potential assessment, including the identification of the most attractive sites,for all renewable projects included in the preferred resource plan Develop a regional frequency regulation strategy for non- dispatchable resources Develop a regional standard power purchase agreement for IPP-developed projects Develop a regional competitive power procurement process to encourage IPP development of projects included in the preferred resource plan 2010-2011 2012 2010-2011 2011-2012 2010-2012 2011 2011-2012 2011-2012 $1.0 million $0.1 million $0.2 million To be determined $1.5 million $0.5 million $0.2 million $0.2 million Black &Veatch 16-4 February 2010 NEAR-TERM IMPLEMENTATION SECTION 16 ACTION PLAN (2010-2012) ALASKA RIRP STUDY 16.4 Other Actions ; Table 16-4 Near-Term Implementation Action Plan -Other Actions Actions Category Description Timeline Est.Cost Other Actions Forma regional entity (if GRETC is not formed)to 2010-2011 Subject to develop and deliver DSM/EE programs to residential and decision commercial customers throughout the Railbelt region,in regarding close coordination with the Railbelt utilities formation of GRETC Establish close coordination between the Railbelt electric 2010-2011 |$0.2 million utilities,Enstar and AHFC regarding the development and delivery of DSM/EE programs Aggressively pursue available Federal funding for 2010-2011 |$0.2 million DSM/EE programs Forma regional entity (if GRETC is not formed)and 2011-2012 Subject to encourage IPPs to identify and develop renewable projects decision that are included in the preferred resource plan regarding formation of GRETC Further encourage the development of tidal power Ongoing To be determined Monitor,and influence to the degree possible,Federal Ongoing Not legislative and regulatory activities,including those related applicable to emissions regulations Aggressively pursue available Federal!funding for 2010-2012 |$0.2 million renewable projects Develop streamlined siting and permitting processes for 2010-2011 |$0.5 million transmission projects Monitor the licensing progress of small modular nuclear Ongoing Not units applicable Black &Veatch 16-5 February 2010 APPENDIX A SUSITNA ANALYSIS ALASKA RIRP STUDY APPENDIX A SUSITNA ANALYSIS Black &Veatch A-1 February 2010 Susitnaa Hydroelectric Project ee4ed|Ss .oad ..Conceptual Alternatives Design Report.eo OE pe Final Draft nna en ee-sos zi 'Derstrara S ° foo .x a weeIPlusoe"ae x ---: 'eu °!'prepared for:re roAlaska EnEnergy Authority.2 enters 813 WestNorthern Lights BoulevardBoat"Anchorage,Alaska 99503 4 Prepared by: HDR Alaska,Inc. For ALASKA on --2525CStreet,Suite 305 Anchorage,AK 99503 November 23,2009 Susitna Hydroelectric ProjectHDRAlaska Conceptual Alternatives Design Report Contents 1 Executive Summary sane 1 2 Background 5 2.1 Project SCOPC......eccscsssssscssesssessessecersesecssesssseeteecsersecseesserseessenseessesesessessesasssesssasseessevsestssitenesees 5 3.'Preliminary Energy Estimate 1 6 . 3.1 Hydrologic Analysis...cesssssesccscccssessscessssesscanescessesssessscacscesseseeceeterssonerssseeesseeseasssessessenanserse 6 3.2 Evaluation of Firm Winter Capacities and Average Annual Energy ..........csssscsessssessteseoeseoees 7 3.3 Model Assumptions and Data Sources......sssssscscsssscsesssssssssccensssssetseetetsseaestetseteneestaeseseesete 8 3.4 Model Operation...csccssscssseccsscssesccsssssssssssecseesscssssesssssesssseesacessesesetseseensesssnsseenatsesesseteerseseses 9 4 Estimates of Probable Project Development Costs .......scssscssssssssessssecseccssscscsocssecseescessesecsssssonnes 13 4.1 Original Cost Estimate 0.0....ccsscsssssccscesesssceseseessccseeesesaesseceeesacseescsssnsatosessseseneseatensaseseasenenees 13 4.2 Expandability ...........csssscesssssssssessssessersssssesesssseessnesssnssessesesnenescsseseetsaessesessesecsestaceaseteesateeesoee LS 4.3 QUANTITIES ooo.eececessesssecsnscsnccssssseesesesnssnsesasceucessecensessesesusenssensceuscenasesnssenesseatseaseceuernsees 14 4.4 Umit Costs cee ecseesescesessesseteceecesecanencenscsssececsassasssssceeseesassqeeeseseaseesseessesssseseeesenseeeessecsseesseses 15 4.5 Indirect Costs...sesessssesseseessesecessesseseessenessensecnsseensesecusaecaeenssnsnssssesenceneenssesneasensenasesnssessesstaes 164.6 Interest During Construction and Financing Costs ......cssssssssssssssecsscsessessceesssesessesssesesreneas 16 4.7 Changes from 1983 Design .........sescesessssecescersesessecenerssonensseeceeesseesscesessseaaseesesssseeeseaseesseraaes 16 4.7.1)Camps «oe eseesesceesesccsatececcescenecacenseccecssserssatacsnsonseseasenssaseseseensaseeseessasouseqeonseasneesaseaeseeete 16 4.7.2 ACCESS oo.sesessceseeseceeceessseseessesceeseesenssnescscsaecassaseacuasssgecesesseaessseaseeeecesecersesseseceesaseeseasenes 16 4.7.3 Transmission .......scscscssssscscsessecsesescessesscscssensenssatenescensssssessenseassanseesnssenenssesensenaeeetenseeers 17 4.8 COMCIUSIONS «02...sssssesssseseescssssrsencesssasseessssnesnsessausesnssssceesacssesseatensesssnsagocsessesnenessseaesasenssseeseoees 17 5 Project Development Schedule 19 6 Project Development Issues 21 6.1 Engineering oe seesssesesceseeceecsscenescssecsnsesescssnscsccssucssecescsssasecseessacesssnseuaesseaeeaesseasseeasnecsees 21 6.2 Sitation eee eesessssescecensesssecenecssescseesssescscennecesssessneseessesseseenacaeseesesaesscsenseassacsasnasensesneereres 21 6.3 Seismicity ee cccseesseesseesssesseeeessssccnensssensenssnesssessscseeseeseasssaeseesessesessensesseassusansnassetsnsenssenaees 21 6.4 Climate Change .......ceecssesssseccescssssesessessenscsssssensstesesacsessesesseseseesassteseassesseeseesceeeoesassssecnseesees 21 6.5 Environmental Issues .0...cc ceeeccssessecessecsecesesessecesseevsnscesesecessessenessessscenssnesesacensseesessencensaseesaes 21 6.5.1 Fisheries Impacts ...........-csscssssssseessesssesssessesenessenescenescesssessecessseceessesacsuseesseesensenenssesaas 22 6.5.2 Botanical Impacts oes eeceesssssesccescscssensesesssesssecsacsessesensesensessersesssescaesesoeseesenseceneses22 6.5.3 Wildlife Impacts ...ccecsscscssssseesesessecsssecssessscessesenenessesesessecesseessesseesecessesssaseeseseessessees 23 6.5.4 Cultural Resource Impacts...ecsssseccecsscesesssescessessseescnesetsneeseassceessseessesenseseecsenseessees 23 6.5.5 Carbon Emissions ..........cesssssssssssscssccseetsesssscesecesseesssssenessenescsassessesnssesseseseeseesseasensaeesees 23 7 References 25 11/23/2009 i Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report Tables Table 1 -Susitna SUMMAryY..........ccsssssssssssessrsccesecescsececsssssesscecesessessncensaesseesseasenesesasseeaseneecacsens 2 Table 2 -Summary of Susitna Project Altermatives..........csscssssecessssssessessecceseresssnsesseeececeseseessesenees 9 Table 3 -Firm Capacity and Energy Estimates .........csccscsccssssccssssesseeensssessncsssscsacsesecseceneessneneeses 10 Table 4 -Estimated Total Fill Volumes..........cccsscssscsessecsecssssecsessessesescsecssseseseesacsessasesasensecseeasss 14 Table 5 -Watana Water Conduit and Powerhouse Size Parameters ........ssssssssssssesssesssscssssceeseees 15 Table 6 -Alternate Project Configuration Cost Summary Table (Millions of US Dollars).........18 Table 7 -Power Generation Time Estimates ..........ccssssscsscsecsseecessceceeessseseesssnscsesessccessecesesceasoneees 20 Figures Figure 1 -Susitna River Hydrologic Variation........sssssscsssssssssssessscsesessscsssessesssssseessssssesesssesees 7 Figure 2 -Firm Capacity ......cscsssssscscsscscsssessesssncsecssssesesssessecessssssscssersescseseeasesessenesesscesseesasaseeseee 11 Figure 3 -Watana Dam Configurations.............ssesssessesssssssesenseeccnsscenscstseceeesensenesseecsesaceececesseoens 13 Figure 4 -Proposed Access Route.........cssscssssscssesessssssssesencscscssscscescsceasersscencssensanesesasscsnsesessersess 17 Appendices Appendix A Energy Analysis Input and Results Appendix B Detailed Cost Estimates Appendix C Detailed Schedules Appendix D Climate Change Analyses 11/23/2009 ii Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 1 Executive Summary A hydroelectric project on the Susitna River has been studied for more than 50 years and is again being considered by the State of Alaska as a long term source of energy.In the 1980s,the project was studied extensively by the Alaska Power Authority (APA)and a license application was submitted to the Federal Energy Regulatory Commission (FERC).Developing a workable financing plan proved difficult for a project of this scale.When this existing difficulty was combined with the relatively low cost of gas-fired electricity in the Railbelt and the declining price of oil throughout the 1980s,and its resulting impacts upon the State budget,the APA terminated the project in March 1986. In 2008,the Alaska State Legislature authorized the Alaska Energy Authority (AEA)to perform an update of the project.That authorization also included a Railbelt Integrated Resource Plan (RIRP)to evaluate the ability of this project and other sources of energy to meet the long term energy demand for the Railbelt region of Alaska.Renewable hydroelectric power is of particular interest to the railbelt because of its potential to provide stable power costs for the region.Of all the renewable resources in the railbelt region,the Susitna projects are the most advanced and best understood. HDR was contracted by AEA to update the cost estimate,energy estimates and the project development schedule for a Susitna River hydroelectric project.This report summarizes the results of that study.The initial alternatives reviewed were based upon the 1983 FERC license application and subsequent 1985 amendment which presented several project alternatives: «Watana.This alternative consists of the construction of a large storage reservoir on the Susitna River at the Watana site with an 885-foot-high rock fill dam and a six-unitpowerhousewithatotalinstalledcapacityof1,200 megawatts (MW). *»Low Watana Expandable.This alternative consists of the Watana dam constructed to a lower height of 700 feet and a four-unit powerhouse with a total installed capacity of 600 MW.This alternative contains provisions that would allow for future raising of the dam and expansion of the powerhouse. *Devil Canyon.This alternative consists of the construction of a 646-foot-high concrete dam at the Devil Canyon site with a four-unit powerhouse with a total installed capacity of 680 MW. «Watana/Devil Canyon.This alternative consists of the full-height Watana development and the Devil Canyon development as presented in the 1983 FERC license application. The two dams and powerhouses would be constructed sequentially without delays.The combined Watana/Devil Canyon development would have a total installed capacity of 1,880 MW. *Staged Watana/Devil Canyon.This alternative consists of the Watana development constructed in stages and the Devil Canyon development as presented in the 1985 FERC amendment.In stage one the Watana dam would be constructed to the lower height and the Watana powerhouse would only have 4 out of the 6 turbine generators installed,but would be constructed to the full sized powerhouse.In stage two the Devil Canyon dam and powerhouse would be constructed.In stage three the Watana dam would be raised to 11/23/2009 1 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report its full height,the existing turbines upgraded for the higher head,and the remaining 2 units installed.At completion,the project would have a total installed capacity of 1,880 MW.) As the RIRP process defined the future railbelt power requirement it became evident that lower cost hydroelectric project alternatives,that were a closer fit to the energy needs of the railbelt, should be sought.As such,the following single dam configurations were also evaluated: «Low Watana Non-Expandable.This alternative consists of the Watana dam constructed to a height of 700 feet,along with a powerhouse containing 4 turbines with a total installed capacity of 600 MW.This alternative has no provisions for future expansion. «Lower Low Watana.This alternative consists of the Watana dam constructed to a height of 650 feet along with a powerhouse containing 3 turbines with a total installed capacity of 390 MW.This alternative has no provisions for future expansion. «High Devil Canyon.This alternative consists of a roller-compacted concrete (RCC)dam constructed to a height of 810 feet,along with a powerhouse containing 4 turbines with a total installed capacity of 800 MW. *Watana RCC.This alternative consists ofa RCC Watana dam constructed to a height of885feet,along with a powerhouse containing 6 turbines with a total installed capacity of 1,200 megawatts (MW). The results of this study are summarized in Table 1. Table 1 -Susitna Summary "oe Lo ee ES Dam'Ultimate |:Firm ©Construction ||Schedule"--Alternative--|.Dam Type ae Height Capacity Cap acity,"2 Cost.3:|'Energy (years from :Cp ee ree Pe -feet of 98%eed $Billio:(GWh/yr)|*.startof ...See ot 7 eed ™"[>(IW)Af ton)2 |Meensing)- Lower Low Rockfill 650 390 170 $4.1 2,100 13-14Watana Low Watana Non-Rockfill 700 600 245 $4.5 2,600 14-15expandable Low Watana Rockfill 700 600 245 $4.9 2,600 14-15Expandable Watana Rockfill 885 1,200 380 $6.4 3,600 15-16 Watana RCC RCC 885 1,200 380 $6.6 3,600 15-16 Devil Canyon Concrete Arch 646 680 75 $3.6 2,700 14-15 High Devil Canyon RCC 810 800 345 $5.4 3,900 13-14 Watana/Devil Rockfill/Concrete 885/646 1,880 710 $9.6 7,200 15-20CanyonArch StagedWatana/Devil RocklvConerete |ga5/646 |1,880 |710 $10.0 7,200]15-24 Canyon 11/23/2009 2 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report In all cases,the ability to store water increases the firm capacity over the winter.Projects developed with dams in series allow the water to be used twice.However,because of their locations on the Susitna River,not all projects can be combined.The Devil Canyon site precludes development of the High Devil Canyon site but works well with Watana.The High Devil Canyon site precludes development of Watana but could potentially be paired with other sites located further upstream. Development of any of the alternatives for the Susitna River will require careful consideration of many factors.Environmental issues,climate change and sedimentation are discussed in this report and the risk associated with these issues is considered manageable.An updated evaluation of seismicity has been done by others and this risk is also considered manageable. Hydroelectric power has many economic and environmental benefits including long-term rate stabilization.Because the cost of the water (fuel)is essentially free and maintenance costs are minimal,the cost per kilowatt hour is driven largely by the project finance terms and is not subject to fluctuations in fuel cost. 11/23/2009 3 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 11/23/2009 4 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 2 Background The Susitna River has its headwaters in the mountains of the Alaska Range about 90 miles south of Fairbanks.It flows generally southwards for 317 miles before discharging into Cook Inlet just west of Anchorage.Contained entirely within the south central Railbelt region,the Susitna River is situated between the two largest Alaska population centers of Anchorage and Fairbanks. The Bureau of Reclamation first studied the Susitna River's hydroelectric potential in the early 1950s,with a subsequent review by Corps of Engineers in the 1970s.In 1980,the Alaska Power Authority (APA;now the Alaska Energy Authority)commissioned a comprehensive analysis to determine whether hydroelectric development on the Susitna River was viable.Based on those studies,the APA submitted a license application to the Federal Energy Regulatory Commission (FERC)in 1983 for the Watana/Devil Canyon project on the Susitna River.The license application was amended in 1985 for the construction of the Staged Watana/Devil Canyon project at an estimated cost of $5.4 billion (1985 dollars). Developing a workable financing plan proved difficult for a project of this scale.When this existing difficulty was combined with the relatively low cost of gas-fired electricity in the Railbelt and the declining price of oil throughout the 1980s,and its resulting impacts upon the State budget,the APA terminated the project in March 1986. At that point,the State of Alaska had appropriated approximately $227 million to the project from FY79-F Y86,of which the project had expended $145 million to fund extensive field work, biological studies,and activities to support the FERC license application.Though the APA concluded that project impacts were manageable,the license application was withdrawn and the project data and reports were archived to be available for reconsideration sometime in the future. In 2008,the Alaska State Legislature,in the FY 2009 capital budget,authorized the AEA to reevaluate the Susitna Hydro Project as it was conceived in 1985.The authorization also included funding a Railbelt Integrated Resource Plan (RIRP)to evaluate various sources of electrical power to satisfy the long term energy needs for the Railbelt portion of Alaska.A Susitna River hydroelectric project could play a significant role in meeting these needs. 2.1 Project Scope The scope of this study was to collect and review pertinent information from the original studies and license application from the 1980's and re-estimate the project energy,costs and development schedule. The initial 1982 FERC license application and subsequent 1985 amendment analyzed several project alternatives: »Watana.This alternative consists of the construction of a large storage reservoir on the Susitna River at the Watana site with an 885-foot-high rock fill dam and a six-unit powerhouse with a total installed capacity of 1,200 megawatts (MW). =Low Watana Expandable.This alternative consists of the Watana dam constructed to a lower height of 700 feet and a four-unit powerhouse with a total installed capacity of 600 MW.This alternative contains provisions that would allow for future raising of the dam and expansion of the powerhouse. 11/23/2009 5 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report *Devil Canyon.This alternative consists of the construction of a 646-foot-high concrete dam at the Devil Canyon site with a four-unit powerhouse with a total installed capacity of 680 MW. «=Watana/Devil Canyon.This alternative consists of the full-height Watana development and the Devil Canyon development as presented in the 1983 FERC license application. The two dams and powerhouses would be constructed sequentially without delays.The combined Watana/Devil Canyon development would have a total installed capacity of 1,880 MW. s Staged Watana/Devil Canyon.This alternative consists of the Watana development constructed in stages and the Devil Canyon development as presented in the 1985 FERC amendment.In stage one the Watana dam would be constructed to the lower height and the Watana powerhouse would only have 4 out of the 6 turbine generators installed,but would be constructed to the full sized powerhouse.In stage two the Devil Canyon dam and powerhouse would be constructed.In stage three the Watana dam would be raised to its full height,the existing turbines upgraded for the higher head,and the remaining 2unitsinstalled.At completion,the project would have a total installed capacity of 1,880 MW. As the RIRP process defined the future railbelt power requirement it became evident that lower cost hydroelectric project alternatives,that were a closer fit to the energy needs of the railbelt, should be sought.As such,the following single dam configurations were also evaluated: *Low Watana Non-Expandable.This alternative consists of the Watana dam constructed to a height of 700 feet,along with a powerhouse containing 4 turbines with a total installed capacity of 600 MW.This alternative has no provisions for future expansion. «Lower Low Watana.This alternative consists of the Watana dam constructed to aheightof650feetalongwithapowerhousecontaining3turbineswithatotalinstalledcapacityof390MW.This alternative has no provisions for future expansion. «High Devil Canyon.This alternative consists of a roller-compacted concrete (RCC)dam constructed to a height of 810 feet,along with a powerhouse containing 4 turbines with a total installed capacity of 800 MW. «.Watana RCC.This alternative consists of a RCC Watana dam constructed to a height of 885 feet,along with a powerhouse containing 6 turbines with a total installed capacity of 1,200 megawatts (MW). Preliminary energy,cost,and schedule estimates for the analyzed alternatives are described in the following sections. 3 Preliminary Energy Estimate 3.1 Hydrologic Analysis At the time the original study was issued in 1983 the hydrologic record contained data from 1950 to 1981.To develop an updated energy estimate for the Susitna hydroelectric project alternatives,a synthesized hydroelectric record for each site was created by a drainage area proration of daily flow data from United States Geological Survey (USGS)gage 1529000 at 11/23/2009 6 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report Gold Creek.USGS gage 1529000 has a period of record from water year 1950-1996 and 2002- 2008. The hydrology of the upper Susitna Basin is dominated by melt water from snow and glaciers in the spring and summer,and substantial freezing during the winter months.As a result,a majority of the flow occurs between mid-April and mid-October.The following figure shows the average monthly flow at the Watana dam site for each year of record. 45,000 - 40,000 35,000 . 30,000 - 25,000 - 20,000 -iin 15,000 -yj Z10,000 -\-y,'2 5,000 --™4AverageMonthlyFlow,cfsOCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP Figure 1 -Susitna River at Watana Hydrologic Variation The manner in which precipitation and runoff might be affected by the impacts of either natural variability and/or potential climate change is discussed at the end of this report. 3.2 Evaluation of Firm Winter Capacities and Average Annual Energy The amount of energy that can be produced from hydroelectric projects is a function of the amount of available water and in the case of storage projects,how the available water can be regulated (systematically released).For the RIRP evaluation process,in addition to the average annual energy,the firm capacity attainable during winter months is of particular importance.For hydroelectric projects,the firm capacity is almost always lower than the installed generation capacity for a project.For the purposes of this study work,firm capacity is defined as: "The amount of power the project can generate on a continuous basis from Nov.1 through April 30 with 100%reliability”. The firm capacity is always driven by low periods in the hydrologic cycle.Since the hydrologic cycle varies,it is also desired to know at what level of reliability the project can generate at levels higher than the firm capacity.It should be noted that this is only one manner of regulation.The water can be regulated in a variety of different means in order to achieve other objectives,such as peaking,spinning reserve or backup capacity. For this study,the average annual energy and winter plant capacities for the alternatives were estimated using a HDR proprietary energy modeling software tool customized for this particular 11/23/2009 7 Final Draft ADR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report purpose (Computer Hydro-Electric Operations and Planning Software or (CHEOPS)).Major assumptions used in the modeling efforts are presented below. 3.3 Model Assumptions and Data Sources Inflow hydrology was based upon USGS gage #1529000 located at Gold Creek on the Susitna River and scaled by a drainage area correction factor representing each of the dam sites. Reservoir capacity and area curves for the Watana and Devil Canyon alternatives were based on information presented in the 1985 FERC application.For the High Devil Canyon project this data was derived from USGS topographical data. Tailwater curves for the Watana and Devil Canyon projects were obtained from the 1985 FERC application and estimated for High Devil Canyon. Operating reservoir levels were obtained from the 1985 FERC application for the Watana,Low Watana and Devil Canyon projects,from the 1982 Acres feasibility study for the High Devil Canyon project,and estimated for the Lower Low Watana project. Environmental flow release constraints were as presented in the 1985 FERC application and scaled according to drainage areas for the various sites. Evaporation coefficients were obtained from the 1985 FERC application.Total reservoir evaporation was estimated in the 1985 FERC application to be between one (1)and three (3)inches per month in summer,with negligible evaporation during winter months. Equipment performance was based on vendor data obtained in 2008 specifically for the Watana and Devil Canyon projects and was assumed to be representative for the other projects. Headloss estimates were based on the water conveyance design from the 1985 FERC application for the Watana and Devil Canyon alternatives and the 1982 Acres feasibility study for the High Devil Canyon alternative. The reservoir was assumed to start full at the beginning of the simulation and was allowed to fluctuate over the remaining period of the simulation. Generation from Nov.1 to April 30,"winter,”was at a constant capacity level ("block loaded”). Generation from May I to Oct.31,"summer,”was to maximize energy with the objective of the reservoir being full on Nov.1. Rule curves for summer target reservoir elevations were developed for each alternative using a mass balance approach.The ratio of the average monthly inflow volume to the average annual inflow volume during each of the reservoir filling months were used to set target elevations for the reservoir. Energy losses of 1.5 percent for un-scheduled outages and 2 percent for transformer losses were applied to the total generation. Active storage remained constant over the simulation period.Dead storage in the reservoirs was assumed to be sufficient to contain sedimentation loads. 11/23/2009 8 Final Draft Susitna Hydroelectric ProjectHDRAlaska Conceptual Alternatives Design Report *No ramping rate restrictions were imposed on either reservoir drawdown or downstream flow. To determine the firm capacity for the combined Watana and Devil Canyon projects,the regulated flow from Watana was assumed to pass unregulated through Devil Canyon with the Devil Canyon pool at maximum operating level. Key input parameters related to energy generation are shown in Table 2 below. Table 2 -Summary of Susitna Project Alternatives ” ;Low Watana -.Watana'.Oe Wisk Devil | tower how ".@oth..(Both Devil Canyon epee :2 i an -Alternatives)pe Alternatives)fee ee PS Dam Type Rockfill Rockfill Rocce Concrete Arch RCC Dam Height (ft)650 700 885 646 810 Gross Head (ft)495 557 734 605 729 Net Head (Max Flow)(ft)481 543 729 598 707 Maximum Plant Flow (cfs)10,700 14,500 22,300 14,000 14,800 Number of Units 3 4 6 4 4 Nameplate Capacity (MW)390 600 1200 680 800 Maximum Pool Elevation (ft)1951 2014 2193 1456 1751 Minimum Poo!Elevation (ft)1850 1850 2065 1405 1605 Tailwater Elevation 7 (Max Flow)(ft)1456 1457 1459 851 1022 Usable Storage 1,536,200 2,704,800 3,888,50 310,000 |2,254,700(acre-ft) 3.4 Model Operation For each alternative,54 years of daily inflow data was used to determine each alternative's ability to meet a range of winter energy production targets and maximize summer generation. For each day from November through April the flow through the powerhouse was limited to the amount necessary to satisfy a prescribed capacity demand given the available head, environmental flow constraints,and reservoir operational restrictions.During the months of May through September energy production each day was maximized if the reservoir elevation was above the target rule curve.If the reservoir elevation was below the target rule curve then' generation was limited to the amount that would allow the downstream environmental!flow constraints to be met.The simulation was repeated at various increasing winter load demands until the maximum firm capacity was determined. To better quantify the effect of storage and extreme low water years on the firm winter capacity, winter load levels in excess of the firm capacity were also evaluated.The results of this analysis 11/23/2009 9 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report are expressed as a capacity at a given percent exceedance level.For example,a project might have a firm capacity of 250 MW at a 100%exceedance level and a firm capacity of 300 MW ata 98%exceedance level.This would mean that the project could provide 250 MW 100%of the time in the winter over the simulation period or 300 MW 98%of the time over the winter.The large change in firm capacity between the 100%exceedance level and the 98%exceedance level for all alternatives is primarily due to a single low water year in 1970. The resulting firm capacities and average annual energy production estimates are presented in Figure 2 and partially summarized in Table 3.Detailed input assumptions and results of these energy analyses are provided in Appendix A of this report.The average annual energy production was relatively constant over the range of winter power demand levels that were modeled. Table 3 -Firm Capacity and Energy Estimates Alterna tiv e oe Firm Winter Capacity 4 98%Winter."Average Annual Energy © Lower Low Watana 100 170 2,100 Low Watana (both alternatives)*150 245 2,600 Watana (both alternatives)**250 380 3,600 Watana/Devil Canyon ***470 710 7,200 Devil Canyon 50 75 2,700 High Devil Canyon 250 345 3,900 *-Low Watana Expandable and Low Watana Non-Expandable have the same energy characteristics.**Watana Rockfill and Watana RCC have the same energy characteristics. ***Watana/Devil Canyon and the Staged Watana/Devil Canyon have similar energy characteristics. 11/23/2009 10 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 1300 -44 "=Watana and Devil Canyon ™S™1200 tr Watana ™.4 e=Qee High Devil Canyon ay1100--|gene Low Watana "A1000 +-]ompeme Lower Low Watana Sx900+4 =e Devil Canyon a =800 =700 =600 ri=ry o s 500 E 400 iz 300 200 100 :o . (0)qT t T v qT t 30%40%50%60%70%80%90%100% %Exceedance Figure 2 -Firm Capacity 11/23/2009 ll Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 11/23/2009 12 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 4 Estimates of Probable Project Development Costs 4.1 Original Cost Estimate In 1982 the cost for developing the complete full Watana/Devil Canyon project was estimated to be $5.0 billion (1982 dollars).In 1985 the cost for developing the staged Watana/Devil Canyon project was $5.4 billion (1985 dollars). The Devil Canyon and High Devil Canyon alternatives were as envisioned in the 1980's.The four rockfill Watana Dam configurations considered in this evaluation are depicted in Figure 3 below. 1000 HEIGHT(feet)Figure 3 -Watana Dam Configurations The estimates for the Watana,Low Watana-Expandable,Devil Canyon and Staged Watana- Devil Canyon alternatives were developed in depth in a March 2009 Interim report and were revised to reflect changes primarily in transmission,access and camp costs.Using this information as a base,new estimates were made for the development costs of the Low Watana Non-Expandable and of the Lower Low Watana alternatives.Cost estimates of $5.4 billion for the High Devil Canyon RCC and $6.6 billion for the Watana RCC alternatives were provided by a separate contractor using similar assumptions and are presented here for completeness of information.The following discussion details the basis for the cost estimates for the Watana embankment projects,the assumptions that were used in creating those estimates,and provides a summary of the projected construction costs. 4.2 Expandability The Low Watana alternative,as proposed in previous studies,included provisions for eventual expansion of the dam from 700 feet to a height of approximately 885 feet and an increase in powerhouse capacity from 800 MW to 1200 MW.The most notable of these provisions are the design of the dam cross section and construction of the powerhouse and water conduits to their ultimate capacity.The two non-expandable alternatives contain no provisions for future expansion. 11/23/2009 13 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report For the Low Watana Expandable alternative the dam cross-section is expanded on the upstream side to provide the opportunity to later raise the dam.This results in additional fill material due to the wider base.The powerhouse,powerhouse equipment,and water conveyance scheme would be built to house six units,but only four turbines would be initially installed. For the Low Watana Non-expandable alternative the cross-section is narrower and does not accommodate expansion of the dam at a later time.Similarly the powerhouse and water conduit features are sized for only four turbine/generator units instead of six. 4.3 Quantities Quantities for the construction cost estimates were based upon detailed estimates developed as part of the 1982 Acres feasibility study for the full sized Watana project and the Devil Canyon project.To estimate the quantities of the smaller Watana alternatives,the full sized Watana quantities were scaled based on the size of the development.As part of a separate report, quantities were developed for the High Devil Canyon alternative based upon a new conceptual design using RCC construction. Table 4 summarizes the embankment fill volumes that were used for the cost estimates.The dam heights and fill volumes of the Watana and Low Watana Expandable configurations were adopted directly from the 1985 FERC application.The embankment volumes for the Lower Low Watana and Low Watana Non-Expandable alternatives were estimated assuming a 2:1 side slope on the downstream portion of the dam and a 2.4:1 side slope on the upstream portion of the dam as were assumed for the other alternatives.Volume changes were limited to the rock-fill and riprap portion of the dam only.The concrete volumes for the Devil Canyon,Watana RCC, and High Devil Canyon alternatives are shown for comparison. Table 4 -Estimated Total Fill Volumes 'Alternative |Type,|Total Fill Volume(cy)* Watana Rockfill 61,000,000 Low Watana Expandable Rockfill 32,000,000 Low Watana Non-Expandable Rockfill 22,000,000 Lower Low Watana Rockfill 17,000,000 Devil Canyon Concrete Arch 1,300,000 Watana*RCC 15,000,000 High Devil Canyon*RCC 11,600,000 *R&M,2009. The quantity estimates for the water conduit layouts and powerhouses for all alternatives were based on the 1985 layout as opposed to the 1983 layout.The 1983 arrangement used a separate penstock for each unit with a very long conveyance scheme.The 1985 arrangement employed aheadraceforeverytwounitsbifurcatingintodedicatedpenstocks.The total length of 11/23/2009 14 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report conveyance was less than half that of the 1983 design.To maintain consistency with the energy model,and to further refine the cost estimates,the 1985 configuration was used for this study. Table 5 summarizes the design features that were assumed in each estimate.The powerhouse and water conveyance systems for Watana and the Low Watana Expandable alternatives were designed to service six units as contemplated in 1983.However,the water conduit layout reflects the 1985 arrangement with three headraces bifurcated into six penstocks and discharged into two tailraces.Low Watana Non-Expandable was assumed to be built to accommodate a four-unit powerhouse with two headraces,four penstocks and a single tailrace.Lower Low Watana was designed for a three-unit powerhouse with one headrace,three penstocks,and one tailrace.The diameters of the water conduits were sized to be consistent with the 1985 design. The powerhouse structures were also scaled accordingly. Table 5 -Watana Water Conduit and Powerhouse Size Parameters em |tow |ene)amnanaare |WatanPoSeagfeWatamapeme Number of Units 3 4 4 6 Unit Size MW)130 150 150 200 Plant Nameplate Capacity (MW).390 600 600 1200 #of Headraces 1 2 3 3 Headrace Diameter (ft)24 24 24 24 #of Penstocks 3 4 6 6 Concrete Lined Penstock Diameter (ft)18 18 18 18 Steel Penstock Diameter (ft)15 15 15 15 #of Tailrace Tunnels 1 1 2 2 Tailrace Diameter (ft)34 34 34 34 4.4 Unit Costs U.S.Cost,a company specializing in creating cost estimates for large capital infrastructure projects,developed unit prices for the materials detailed in the 1982 estimate in 2008 dollars. This cost data was used to develop the estimates presented in the Interim Report and the same pricing was used in this study.Lump sum items were inflated using a construction cost index. For the water-to-wire turbine-generator equipment estimates,budget pricing for the Watana alternative was requested directly from manufacturers.The water-to-wire equipment includes turbines,generators,turbine shutoff valves,and other miscellaneous mechanical and electrical equipment,including installation costs.The equipment costs for other smaller alternatives were developed by scaling the Watana vendor quotes on a per kilowatt basis. 11/23/2009 15 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 4.5 Indirect Costs A contingency of 20 percent was added to the direct construction costs to reflect level of design and uncertainty in the project. Project licensing,environmental studies and engineering design were estimated at 7 percent of direct construction costs.Construction management was estimated at 4 percent of the direct 'construction costs,and has been included as a separate line item. 4.6 Interest During Construction and Financing Costs Costs associated with interest during construction and project financing are not included in the estimates. 4.7 Changes from 1983 Design The camps,access roads and transmission,infrastructure assumptions used in the 1983 configuration have been modified as discussed below. 4.7.1 Camps Reductions were made in the scale of the permanent and construction camps needed to accommodate the workers.These changes were made based on the fact that permanent townfacilitieswerenolongernecessaryduetoadvancesinremoteprojectoperation.It was also assumed that due to modern construction methods,the number of construction personnel could be reduced.It was assumed that 750 people would need to be housed for the Lower Low Watana arrangement,825 people for Low Watana and 900 people for Watana.In 1983 it was originally assumed that housing would be provided for 3000 people plus families.Budget pricing for the construction camp was provided by vendors. 4.7.2 Access For all the Watana alternatives,access is assumed to be via the Denali Highway from the north as shown in Figure 4.The route would include the upgrade of 21 miles of the Denali Highway to a construction grade road and the construction of approximately 40 miles of new road to the - Watana site.The price per mile of new road has been assumed at $3M/mile which is the current budgetary estimate of the Alaska Department of Transportation and Public Facilities for the road to Bettles and Umiat from the Dalton Highway which is similar in nature to the road that would be required for a Susitna project.Upgrading of the Denali Highway has been assumed to be $1M/mile and local site roads have been estimated at $750k/mile. 11/23/2009 16 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 3 Denali a!4a = vee ee i Aan <reeskee Figure 4 -Proposed Access Route For the Devil Canyon and High Devil Canyon alternatives,rail access was assumed and will originate on the Parks Hwy near MP 156 and proceed upstream on the south side of the river. 4.7.3 Transmission A separate study (EPS,2009)has investigated the transmission lines and interconnection requirements for the entire Alaska railbelt region as part of the RIRP process and the results are incorporated here at the direction of the AEA.This study estimates that a transmission line from the project site to the substation at Gold Creek would cost approximately $4.5M/mile. Substation costs are estimated at $16M per location.No costs have been assumed to increase or modify the regional transmission grid beyond the Gold Creek substation. 4.8 Conclusions The approach,methodology and assumptions previously described resulted in the estimated project costs detailed below in the summary table. 11/23/2009 17 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report Table 6 -Alternate Project Configuration Cost Summary Table ($Millions) "FERC ne]|Gta [Em |wating |atnn Maem |et |Det]ent |watt DevoesPeEeP|Watana |Expandable'|Expandable Jo 0000000)J 07 [S22 |Canyont |Canyon |©Canyon NA Engineering,Env.,and Regulatory (7%)$233 $236 $259 $338 $342 $191 $281 $501 $528 330 Land and Land Rights -$121 $121 $121 $121 $121 $52 $121 $173 $173 331 Power Plant Structure Improvements $93 $115 $159 $159 $159 $165 $159 $324 $325 332.1-.4 Reservoir,Dams and Tunnels $1,415 $1,538 $1,718 $2,424 $2,307 $900 $1,803 $3,324 $3,485 332.5-.9 Waterways $590 $590 $677 $677 $558 $415 $552 $1,093 $1,191 333 Waterwheels,Turbines and Generators $213 $297 $297 $475 $487 $295 $487 $770 $834 334 Accessory Electrical Equipment $29 $41 $41 $72 $57 $38 $57 $110 $119 335 Misc Power Plant Equipment $17 $21 $32 $32 $32 $29 $32 $61 $61 336 Roads,Rails and Air Facilities $232 $232 $232 $280 $584 $535 $490 $388 $394 350-390 Transmission Features $177 $224 $224 $353 $322 $99 -$119 $481 $481 399 Other Tangible Property $12 $16 $16 $20 $12 $16 $12 $36 $42 63 Main Construction Camp $150 $180 $180 $210 $244 $180 $189 $390 $440 71B Construction Management,4%$122 $135 $148 $193 $195 $109 $161 $286 $302 Total Subtotal $3,384 $3,746 $4,104 $5,354 |$5,420 $3,024 $4,463 $7,937.$8,375 Total Contingency $676 $749 $821 $1,071 |$1,155 $605 -$954 $1,587 $1,675 Total (Millions of Dollars,rounded)$4,100 $4,500 $4,900 $6,400 $6,600 $3,600 $5,400 $9,600 $10,000 *RE&M (2009) 11/23/2009 18 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 5 Project Development Schedule Updated schedules were developed for each of the project alternatives.These schedules extend from approval,through licensing,design,construction,and commissioning.The primary purpose of these schedules is to provide timelines for cash flow and estimated energy revenue to determine economic feasibility.These schedules assume that: Construction times are based on 1983 FERC license application. The licensing process from start to FERC order is estimated at 7 to 10 or more years.We have set a reasonable target of 8 years for the proposed project analysis,provided that the effort is begun immediately,ambitiously,fully funded,and conducted in parallel with environmental studies,engineering,and with active public outreach and cooperation by stakeholders. The FERC License Application will be based on the 1985 application,updated to reflect more than 20 years of regulatory changes and changes in engineering and construction methods. Any new environmental studies will be based on data acquired during the studies in the 1980's,updated to reflect present site conditions,public interests,wildlife,and recreational needs. Construction will begin immediately upon issuance of the license. Roads and staging will be state permitted outside the FERC project and will begin several years before FERC license,including pioneer and permanent roads,airports,bridges, construction camps and staging areas.Building facilities in advance of the project license is the most effective way to trim the projected timeline although there is some uncertainty whether permits could be obtained to construct these facilities before the project license is issued.The schedule for each of the project alternatives would be extended by one to two years if this assumption is not valid. Construction of diversion dams and tunnels will begin on issuance of the license,with upstream and downstream coffer dams and tunnels to divert the Susitna River during construction of main dams at Watana/Devil Canyon. Spillway construction will follow diversion dam and tunnel construction,and will include site preparation,approach channels,control structures,gates,stoplogs,chute,and flip buckets for main and emergency spillways.. Dam construction at Watana will follow site preparation,grouting,and installation of a pressure relief system. The main dam construction at Devil Canyon will include a thin-arch concrete dam, preceded by site preparation,foundations,abutments,and thrust blocks.Rock-fill saddle dam construction will follow grouting and pressure relief system. The powerhouse and transmission will include power intake,tunnels/penstock,surge chamber,tailrace,powerhouse,turbine/generators,mechanical/electrical systems, switchyard,control buildings,and transmission lines. 11/23/2009 19 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report *Reservoir filling will be based on the latest hydrologic data for inflow and turbine data for outflow. «Devil Canyon construction will commence immediately upon completion of Watana for the Watana/Devil Canyon alternative. Table 7 -Power Generation Time Estimates i Alternative.;a ;-by ae Generation of first power ae Generation of full power.|Cp ee a years ee QearsyRe Lower Low Watana 13 14 Low Watana (both alternatives)14 15 Watana (both alternatives)15 16 Devil Canyon 14 15 High Devil Canyon 13 14 Watana/Devil Canyon 15 20 Staged Watana/Devil Canyon 15 24 *From start of licensing 11/23/2009 20 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 6 Project Development Issues Development of a hydroelectric project on the Susitna River would face a variety of issues over their design lifetime.The design lifetime for a modern dam is greater than 100 years.The following discussion is not intended to be all inclusive but rather highlight the likely major areas of concern. 6.1 Engineering The projects being contemplated for the Susitna River would be on the larger end of the scale in the world in terms of size of the dams.Projects of this size have not been undertaken in the United States for many decades.As such,a major engineering effort will be required. 6.2 Siltation Rivers,by nature,transport the products of erosion to the oceans.Dams interrupt this flow of material.Given time the effective amount of storage in the reservoir behind the dam can diminish.The alternatives investigated here have been designed with dead storage to accommodate bedload and it is not expected that siltation will have any detrimental affect on the energy projected energy production of any of the projects during their design lifetime. 6.3 Seismicity Seismic (earthquake)events have the potential to effect hydroelectric projects.The main areas of concern are damage from ground shaking,opening of faults along the dam axis,landslides and settlement,and the creation of large waves in the reservoir.The previous studies on seismicity have concluded that these concerns can be designed for and therefore do not pose a significant threat.New analytic methods are now available to evaluate more complex seismic situations and these evaluations,along with the most stringent safety factors would be incorporated into a modern project design (R&M,2009). 6.4 Climate Change There has been much discussion about climate change and what the effects of climate change will be on river flows.Analyses of the potential affects of climate change on the Susitna River are included in Appendix D.The annual runoff from the Susitna River basin shows remarkable balance during very disparate climate regimes.The analyses support the consistent supply of water from the basin precipitation to support hydro-power generation regardless of the climate fluctuations.While global climate models suggests additional warming may impact the Arctic and Alaska,it seems very unlikely that these impacts will cause an unbalance in the runoff production of the basin.© Based on this,there is no conclusive evidence to suggest that runoff will be statistically different in the next 50 years from what it has been in the last 50 years. 6.5 Environmental Issues After the Susitna project was discontinued in 1986 a database of 3,573 documents was created. In September 2008,the 87 most-relevant documents were scanned into HDR's files,of which 18 11/23/2009 21 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report of the most relevant environmental documents were summarized.A synthesis of the 7 most- pertinent documents was completed.Because not all of the documents were summarized,somerelevantinformationhaslikelybeenoverlooked;however,most information was included in the synthesis. These documents contain information on potential impacts of the proposed project and mitigation proposals for those impacts.Specifically,the documents deal with fisheries resources, botanical resources,wildlife resources,and cultural resources in the potential project area.The documents divide the Susitna River Basin into 4 geographic regions: «Jmpoundment zones «Middle Susitna River =Lower Susitna River «Access roads and transmission lines The potential impacts and mitigation options are discussed for each category in each geographic region as much as possible.It is important to note that not all categories will be impacted in all geographic regions.Mitigation for the proposed impacts is divided into the following categories: avoidance,minimization,rectification,reduction,and compensation.Avoidance is always the preferred mitigation,though it is not usually feasible.Compensation is the only mitigation option for many of the impacts. 6.5.1 Fisheries Impacts The fisheries resources have the highest potential to be impacted by the project.Most of the potential impacts will occur in the middle Susitna River.There will be impacts due to changes in water quality,thermal activity,the water's suspended sediment load,reservoir draw-down fluctuations,impoundment zone inundation,flow regime,and lost fish habitat.Not all impacts to fish populations will be negative.For example,the increase in winter water temperatures could lead to the creation of more overwintering habitat and thus greater fish survival;however,the cooler spring water temperatures will slow fish growth. In the Watana impoundment zone,51 river miles will be inundated and transformed into reservoir habitat.An additional 27 miles of tributary streams and 31 lakes will be inundated. In the Devil Canyon impoundment zone 31 miles of the main river channel will be inundated and an additional 6 miles of tributary streams will be impacted. Mitigation for these impacts was proposed by compensation through land acquisition,habitat modification,and reservoir stocking. 6.5.2 Botanical Impacts The project area contains 295 vascular plant species,11 lichen genera,and 7 moss taxa.Low Watana inundation will permanently remove 16,000 acres of vegetation.Devil Canyon inundation will permanently remove 6,000 acres of vegetation.Watana inundation will permanently remove an additional 16,000 acres of vegetation.There will be a total of 38,000 acres of vegetation permanently removed.Most of the vegetation inundated will be spruce forest. An additional 836 acres of vegetation will be permanently removed due to access road 11/23/2009 -22 Final Draft ADR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report construction.In the transmission corridor affect on vegetation will be minimal due to intermittent placement of control stations,relay buildings,and towers. There will be limited botanical impacts downstream from the reservoir(s).These involve changes to the vegetation due to a more stable environment.Due to flow regulation there will no longer be major flooding events,which destroy the riparian vegetation;instead;rather,there will be succession of the riparian vegetation and colonization of new floodplains.The increase in winter water temperatures will decrease the amount of ice scouring that occurs,which will result in effects similar to those caused by the decrease in flooding. Botanical resource mitigation will consist largely of compensation for permanently removed vegetation. 6.5.3 Wildlife Impacts Within the Susitna River Basin there are 135 bird species,16 small-mammal species,and 18 large-mammal and furbearing species.There are currently no known listed endangered species in the project area.There will be 5 classes of potential impacts to terrestrial vertebrates: Permanent habitat loss,including flooding of habitat and covering with gravel pads or roads. Temporary habitat loss and habitat alteration resulting from reclaimed and revegetated areas such as borrow pits,temporary right of ways,transmission corridors,and from alteration of climate and hydrology. Barriers,impediments,and hazards to movement. Disturbances associated with project construction and operation. Consequences of increased human access not directly related to project activities. Mitigation for the proposed impacts involve mostly compensation since there will be permanent habitat loss for most species., 6.5.4 Cultural Resource Impacts Within the proposed project area,297 historic and prehistoric archaeological sites were located. An additional 22 sites were already on file.Sites located within 500 feet of the reservoir's maximum extent may be indirectly impacted due to slumping from shoreline erosion.Indirect impacts may also result from vandalism due to increase in access to the sites.The project has the potential to impact 140 sites.None of these sites will occur in the proposed road corridor or transmission lines.The majority of these sites are relatively small prehistoric sites. Mitigation for the lost cultural resources will mostly occur through data recovery.Preservation would also be used for some sites.Options to consider include construction of protective barriers to minimize erosion,controlled burial,or fencing of the site to restrict access. Currently,there are a variety of federal,state,and local land use plans that encompass the Susitna Basin. 6.5.5 Carbon Emissions According to the United Nations working group on carbon emissions from freshwater reservoirs the worst case carbon emissions from a reservoir in a boreal climate is 6.7 grams per square meter per year (United Nations,2009).For the Watana/Devil Canyon alternative this equates to 11/23/2009 23 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 465,000 metric tons of carbon per year or 0.065 metric tons per MWhr.The US Department of Energy reports the average carbon emissions due to electric generation for the State of Alaska tobe0.626'metric tons per MWhr.Operation of the Susitna project has the potential to eliminate up to 4 million metric tons of carbon production per year. 'http://Awww.eia.doe.gov/cneaffelectricity/st_profiles/alaska.html 11/23/2009 24 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 7 References Acres 1981.Susitna Basin Development Selection.Task 6 Development Section.Subtask 6.05 Development Section Report.Appendix F Single and Multi Reservoir Simulation Studies. Acres 1981.Susitna Hydroelectric Project.Task 6 Development Section.Subtask 6.05 Development Section Report.Plate 6.4.High Devil Canyon Layout. Acres 1982.Susitna Hydroelectric Project Feasibility Report.Volume 2 Engineering and Economic Aspects.Section 12 Watana Development. Acres 1982.Susitna Hydroelectric Project Feasibility Report.Volume 2 Engineering and Economic Aspects.Section 16 Devil Canyon Development. Acres 1982.Susitna Hydroelectric Project Feasibility Report.Volume 2 Engineering and Economic Aspects.Section 11 Access Plan Selection. Acres 1982.Susitna Hydroelectric Project Feasibility Report.Volume 2 Engineering and Economic Aspects.Section 16 Cost Estimates. Acres 1982.Susitna Hydroelectric Project Feasibility Report.Volume 6.Appendix C Cost Estimates Final Draft. Acres 1982.Susitna Hydroelectric Project Feasibility Report.Volume 1 Engineering and Economic Aspects Sections 17 Development Schedules. Entrix,1985.Impoundment area impact assessment and mitigation plan.Susitna Hydroelectric Project Impact Assessment and Mitigation Report No.2.Entrix,Inc.,Under contract to Harza-Ebasco Susitna Joint Venture.Prepared for the Alaska Power Authority. EPS 2009.Susitna Hydro Transmission Study.Report to AEA dated October 22,2009 Harza Ebasco.1985.Introduction to the Amendment to the License Application before the Federal Energy Regulatory Commission.Chapter III Project Description. Harza Ebasco.1985.Susitna Hydroelectric Project Draft License Application.Volume 1.Exhibit A Project Description.Sections 1-15. Harza Ebasco.1985.Susitna Hydroelectric Project Draft License Application.Volume 15. Exhibit F Project Design Plates. Harza Ebasco.1985.Susitna Hydroelectric Project Draft License Application.Volume 16. Exhibit F Supporting Design Report. Harza Ebasco.1985.Susitna Hydroelectric Project Draft License Application.Volume 2.Exhibit B Project Operation and resource Utilization.Section 3 Description of Project Operation. Harza Ebasco.1985.Susitna Hydroelectric Project Draft License Application.Volume 2.Exhibit B Project Operation and resource Utilization.Section 4 Power and Energy Production. Harza Ebasco.1985.Susitna Hydroelectric Project Draft License Application.Exhibit D Project Costs and Financing.Section 1 Estimates of Cost. 11/23/2009 25 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report Harza Ebasco.1985.Susitna Hydroelectric Project Draft License Application Exhibit C Proposed Construction Schedule. Harza Ebasco.1985a.Susitna Hydroelectric Project Draft License Application Volume 9 Exhibit E Chapter 3 Sections 1 and 2 -Fish,Wildlife and Botanical Resources. Harza Ebasco.1985b.Susitna Hydroelectric Project Draft License Application Volume 10 Exhibit E Chapter 3 Section 3 -Fish,Wildlife and Botanical Resources. Harza Ebasco.1985c.Susitna Hydroelectric Project Introduction to the Amendment to the License Application. Harza Ebasco.1985d.Susitna Hydroelectric Project Draft License Application Volume 11 Exhibit E Chapter 3 Sections 4,5,6 &7 -Fish,Wildlife and Botanical Resources. Harza Ebasco.1985e.Susitna Hydroelectric Project Draft License Application Volume 12 Exhibit E Chapter 4,5,and 6.-Cultural Resources,Socioeconomic Resources,and Geological and Soil Resources. R&M 2009.Susitna Project.Seismic Setting Review and Geologic and Geotechnical Data Reports Review.Memo to AEA dated July 2,2009 R&M 2009.Susitna Project.Watana and High Devil Canyon RCC Dam Cost Evaluation.Final Report dated November 16,2009. United Nations Educational,Scientific and Cultural Organization.Scoping Paper:Assessment of the GHG Status of Freshwater Reservoirs.April 2008 U.S.Cost 2008.1982 to 2008 Cost Estimate for Susitna Hydroelectric Project.| Woodward-Clyde Consultants.1984.Susitna Hydroelectric Project:Fish Mitigation Plan. Prepared for the Alaska Power Authority. 11/23/2009 26 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report Appendix A: Energy Analysis Input and Results For the purposes of this submittal,the appendices have been attached as PDFs. 11/23/2009 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report Appendix B: Detailed Cost Estimates For the purposes of this submittal,the appendices have been attached as PDFs. 11/23/2009 Final Draft ADR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report Appendix C: Detailed Schedules For the purposes of this submittal,the appendices have been attached as PDFs. 11/23/2009 Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report Appendix D: Climate Change Analyses For the purposes of this submittal,the appendices have been attached as PDFs. 11/23/2009 Final Draft APPENDIX B FINANCIAL ANALYSIS ALASKA RIRP STUDY APPENDIX B FINANCIAL ANALYSIS Black &Veatch B-1 February 2010 MONE Spat gh ntCarsGyAS Pi 1Baedeeanettertad¥Ret RaeNestedaayhkSrnetihthSMTee SE PHB Se ca PORPeratEA EASheeRBulanwef Rare eave MY SNW 1420 Fifth Avenue,Suite 4300 Seattle,Washington 98101 Phone:(206)628-2882 Fax:(206)343-2103 2/3/2010 Intreduction The Regional Integrated Resource Plan (RIRP)is a 50-year,long-range plan tasked with identifying the optimal combination of generation and transmission capital improvement projects in the Railbelt region of Alaska.The objectives of the financial analysis portion of the plan are threefold: 1.Provide a high-level analysis of the capital funding capacity of each of the Railbelt utilities,given their current financial condition and assuming that each utility will borrow on its own,rather than utilizing a joint-powers structure or receiving assistance from the State of Alaska. 2.Analyze strategies to capitalize selected RIRP assets by integrating State and federal financing resources with debt capital market resources.Specifically,we look at ways to utilize State funding to: e mitigate construction risk, ¢lower capital cost prior to placing assets in service,and *extend the debt repayment term beyond terms available in the debt capital markets. 3.Develop a spreadsheet-based model that utilizes inputs from the RIRP model,including total capital requirements,demand-side management (DSM),fuel cost,COz cost,and operation and maintenance cost (O&M),and overlays realistic debt capital funding to provide a total cost to ratepayers of the optimal resource plan. Railbelt Utility Capital Capacity The non-profit organizational structure of generation and transmission (G&T)and distribution cooperatives makes it difficult for these entities to produce operating margins and build equity to the levels needed to access the public debt markets.Rate setting is designed to recover operating cost with moderate margins,and any capital in excess of minimal reserves is returned to coop members.Nevertheless,some coops,including Chugach Electric,are able to maintain coverage margins sufficient to secure investment grade credit ratings and utilize the debt capital market to fund asset expansion.Likewise,municipal governments face a similar rate-setting challenge in the form of political pressure to keep rates at levels just sufficient to cover operations and maintain net plant and equipment.In the following sections,we take a look at several key financial measures of coop and municipally owned utilities and utilize these measures to estimate the remaining debt capacity of each of the Railbelt utilities. To develop the framework for this analysis,we retrieved the publicly available financial reports from each utility's website and the annual filings from the Regulatory Commission of Alaska's website.Using these reports,we summarized each of the utilities'current outstanding debt obligations,company equity,total assets and total plant.We used these figures to derive several important financial ratios,discussed in detail below,that are used by the investment community as well as the nationally recognized rating agencies (Moody's,Standard &Poor's,and Fitch)to determine the ability of each organization to manage its current and/or future debt obligations.It's important to point out that,while no single financial ratio by itself is an accurate determinant of a utility's ability to incur additional debt for capital projects,an analysis of a sampling of several ratios in conjunction with other non-financial metrics (e.g.,demand growth,rate-setting authority, political climate,etc.)helps to create some guidelines for how much debt could reasonably be considered and issued in the capital markets. Debt to Equity Ratio.The debt to equity ratio (or debt as a percentage of total capitalization)is derived by dividing a utility's total debt by its net capital.The rating agencies have developed median debt to equity ratios for each of the different types of utility organizational structures.For example,a G&T cooperative can expect to have a higher debt ratio percentage than a retail power distributer due to the need to finance large and relatively expensive generation and transmission assets.A summary of these utility medians for debt to equity is provided in the following table: -2008 Median Debt to Capitalization %By Utility System Type G&T Coop 82% Municipal Wholesale 93% Retail Self Generating 60% Retail Power Purchaser (Distribution)40% Source:Fitch U.S.Public Power Peer Study,June 2009 The table below calculates the remaining debt capacity for each of the Railbelt utilities under varying debt to equity ratios to derive a total debt capacity amount given existing equity capitalization.Debt to equity capitalization for this analysis ranges from 40%to 80%. Railbelt Utility Additional Debt Capacity Based on Current Debt to Equity Ratios Existing Debt , as of 12/31/2008"40%60%70%80% ML&P $159,405,791 -$175,744,945 $362,920,220 730,502,349 Chugach 354,383,506 --9,355,443 260,137,205 MEA 89,128,488 -48,090,737 129,409,217 277,237,086 HEA 148,257,837 ---99,152,015 GVEA 301,670,508 ---131,081,336 Seward é z z z 5 -$223,835,682 $501,684,880 $1,498,109,991 (1)2008 Annual reports and 12/31/2008 Annual!Reports to the Regulatory Commission of Alaska (2)The City of Seward was not included in this analysis due to lack of information regarding their Electric Enterprise Fund Our analysis found that the debt-to-capitalization ratio for each of the utilities is close to or higher than the median ratio for its organizational type.There does appear to be some additional bonding capacity available for each of the utilities under a G&T cooperative-type structure when compared to the Fitch median ratio of 82%.However,given the utilities'existing debt burdens and current conditions in the financial markets,which have made it more difficult for lower rated power utilities to access capital,it is not clear that the six utilities could support debt capitalization much above 70%.Fitch Ratings specifically mentions that higher debt capitalization percentages can result in negative ratings pressure going forward'.At approximately 70% *Fitch Ratings,U.S.Public Power Peer Study,June 2009 debt capitalization,the six utilities together could support between $500 and $700 million of additional debt. At 80%,available additional debt capacity for the six utilities combined increases to approximately $1.5 billion. This analysis does not include the City of Seward's capacity.Given its Electric Enterprise Fund asset base of $26 million (as of 2007),the overall borrowing capacity number would not change by a significant amount if the City of Seward were included. Debt to Funds Available for Debt Service.An important measure of operating leverage is the Debt to Funds Available for Debt Service ratio (Debt/FADS).This ratio measures a utility's ability to handle its current fixed debt burden based on annual operating cash flow.A lower Debt/FADS ratio indicates either a low overall debt burden or a high operating cash flow,with the opposite being true for a higher Debt/FADS ratio.In the"A”rating category and higher,all but one G&T wholesale system rated by Fitch Ratings had a Debt/FADS ratio higher than 8.8 in 2008.For comparison purposes,the average (and median)Debt/FADS ratio for the Railbelt utilities in 2008 was approximately 8.4,with the highest being 13.66.The operating leverage of the six utilities would increase dramatically as capital spending and debt burden increase.An increase in the operating leverage ratio would cause ratings pressure for utilities maintaining a public credit rating and increased scrutiny by creditors including commercial banks and cooperative banks such as CFC or CoBank. RIRP Capital Requirements Relative to Railbelt Utility Debt Capacity.The preceding debt to equity and Debt/FADS discussions do not take into consideration several additional factors that are relevant to the collective debt capacity of the Railbelt utilities.These factors can impact debt capacity both positively and negatively and include amortization of existing utility debt,the level of new debt required to maintain distribution infrastructure,and potential rate increases. While these factors are influential,they do not have sufficient positive impact to alter our opinion that the utilities individually do not have the capital capacity to fund the projects recommended by the RIRP.The scope of the RIRP projects is too great,and for certain individual projects,it is reasonable to conclude that there is no ability for a municipality or coop to independently secure debt financing without committing substantial amounts of equity or cash reserves.Specifically,these individual projects would include any that require large capital investment and have any of the following characteristics:exceptionally long construction =Saperiod,significant construction risk,or significant technological risk.These types of risk |$10,000,000,000 - i|: ;Capital Expenditures AS$7,500,0C0,000 | | i $5,000,000,000 $2,500,000,000 are associated with equity rates of return and are rarely,if ever,borne by fixed income investors. The graphic to the right helps to put into context the scope of required RIRP capital investments relative to the estimated combined debt capacity of the Railbelt utilities.The lines toward the bottom of the graph represent our view of the so+bracketed range of additional debt capacity collectively for the Railbelt utilities,adjusted for inflation and 'customer growth over time. Railbelt Utility Debt Capacity Conclusions.The REGA study completed in 2008 concluded that the most cost effective approach to funding necessary Railbelt generation and transmission assets was to form a regional G&T.While SNW was not asked to validate this conclusion,we are of the opinion that a regional entity such as GRETC,with "all outputs”contracts migrating over time to "all requirements”contracts,will have greater access to capital than the combined capital capacity of the individual utilities.To be clear,our conclusion should not be interpreted to mean that a regional G&T agency would be able to execute the RIRP capital plan independent of any State or federal assistance;however,a regional G&T agency will have lower- cost access to debt capital than the utilities would have on their own.This is primarily due to two factors:(1) a regional G&T entity will eliminate the rate pressure/competition that naturally exists under the current Railbelt construct of each of the 6 utilities independently providing generation and transmission services to their customers,and (2)a regional G&T entity executing a utility-approved comprehensive RIRP plan with strong power purchase agreements will be better positioned with the rating agencies and private investors. Strategies to Lower Capital Cost of RIRP to Ratepayers As previously noted,the scope of the RIRP is significant.The complexity of the overall capital plan and the size and construction duration of various projects within the plan will necessitate some amount of "equity” capital from ratepayers and/or the State of Alaska.Furthermore,equity capital,in the form of a ratepayer benefits charge or State financial assistance through either loans or grants,is the most efficient source of funding available to GRETC for the RIRP.Capital accruing from the State in the form of grants or from existing ratepayers in any form needs to be balanced with long-term debt capital so that future rate payers who will benefit from the RIRP assets share the cost of funding these assets.The following sections discuss various sources of equity capital funding and methods for involving the State in the execution of the RIRP. Ratepayer Benefits Charge.A ratepayer benefits charge is a charge levied on all ratepayers within the Railbelt system that will be used to cash fund and thereby defer borrowing for infrastructure capital.A rate surcharge that is implemented prior to construction allows for partial "pay-go”funding of capital projects and reduces the overall cost of the projects by reducing the amount of interest paid for funding in the capital markets.For example,the potential interest cost savings that could be realized if GRETC were to fund some portion of a $2 billion project through rates rather than entirely upfront through bond proceeds are shown in the table below: .$2 billion project Rate Surcharge interest Cost Reduction " Through Construction Funded With Bonds $500 million $1.5 billion $1.2 billion $1.0 billion $1.0 billion $2.4 billion (1)Assumes 30-year debt to fund construction at 7.00%interest. "Pay-Go”vs.Borrowing for Capital.A "pay-go”capital financing program is one in which ongoing capital projects are paid for from remaining revenue after maintenance and operations (M&O)expenses,and debt service are paid for.As will be discussed in further detail later,we have assumed that any bonds sold in the capital markets will require generation of a 1.25 times debt service coverage ratio.Covenanted coverage would likely be lower than 1.25 times.The cash generated in excess of M&O expense and debt service expense ("coverage”)will be used to fund reasonable reserves with the balance going towards ongoing capital projects. For example,in years where debt service on outstanding bond issues is the highest,the 1.25 times debt service coverage ratio creates additional reserves in the amount of nearly $130 million above what is required to pay operating expense and debt service. There is a tradeoff between the benefits derived from a pay-go financing structure versus one for which all projects are bonded.The benefit to ratepayers and GRETC in the pay-go structure is that it minimizes the total cost of the projects through the reduction of interest costs.On the other hand,the benefit of borrowing for a portion of capital needs is that expenses are spread out over time,and the cost of the debt can be structured to more closely match the useful life of the assets being financed.This is particularly important for some of the larger hydro-electric projects,where the useful life would likely exceed 50 years;these projects have large upfront costs that would be cost-prohibitive if funded entirely through rates.A balance of these two funding approaches appears to be most effective in lowering the overall cost of the project as well as spreading out the costs over a longer period of time. Construction Work Iu Progress.Construction Work In Progress (CWIP)is a rate methodology that allows for the recovery of interest expense on project construction expenditures through the rate base during construction,rather than capitalizing the interest until the projects are completed and operating.This concept is important:the overall cost of the projects is significantly reduced through the immediate payment of interest on construction borrowing,versus the alternative of borrowing an additional sum just to pay for the interest while the project is still under construction.The benefit to ratepayers of the CWIP concept is that it significantly lowers both the overall cost of the project as well as the future revenue requirements needed to pay debt service.The use of CWIP in Alaska will most likely need to be vetted and approved by the Regulatory Commission of Alaska. Both CWIP and pay-as-you-go funding rely on ratepayers to advance dollars for capital projects and thereby convey some project risk to ratepayers.If for example,a generation project were not completed for any reason ratepayers would have paid for a portion of the project even though the asset never produced power.SNW believes that ratepayers in a typical municipal utility structure generally incur this risk regardless of rate setting policies or methodologies.The ability to shift project risk to creditors is both limited and expensive and may not be appropriate for the "System”envisioned by GRETC.Under an Investor Owned Utility (IOU) structure,shareholders are responsible for bearing some of this risk,however shifting risk to shareholders requires higher equity rates of return to those investors.GRETC is not presently contemplated to be structured as an IOU. State Financial Assistance.State financial assistance could take a variety of forms,but for the purpose of this report,we will focus on State assistance structured similarly to the Bradley Lake project.State financial assistance offers GRETC a number of advantages not available through traditional utility enterprise bond funding or project finance.Similar to a ratepayer benefits charge,State funding,whether in the form of a grant - or loan,can be utilized to defer higher cost conventional revenue bond funding.Obviously a grant from the State provides the cheapest form of capital to GRETC,but even when structured as a loan,State assistance can dramatically lower GRETC's overall cost of capital.State funding in the form of a loan has three significant advantages when compared to revenue bonds or a loan from a commercial lender.The advantages of State funding include: 1.Repayment flexibility.State funding can be utilized to extend debt repayment beyond the term maturities available in the public or commercial debt capital markets.Additionally,a State loan can easily be restructured or deferred to achieve system rate objectives. 2.Credit support/risk mitigation.State funding can be used to mitigate project construction risk.This is particularly relevant for projects with extended construction timelines,such as large hydro- electric projects.Risk mitigation is also relevant in situations where permitting is an issue or anew technology is being used.Generally,fixed income investors will not accept significant construction and permitting risks inherent with the large-scale projects included in the RIRP without some form of support from the State. 3.Potential interest cost benefit.State funding can provide a lower cost source of capital.The State's high investment grade credit rating allows it to borrow for less than even the most secure utility enterprise.Assumptions as to the form of State assistance in the financial model are discussed in greater detail below;however,the terms of any loan,agreement,or grant between the State and GRETC will need to be further researched and developed in the next stage of the GRETC formation process. RIRP Financial Model Summary Results The development of the RIRP financial model took into account several different goals and objectives.The first goal was to identify ways to overcome the funding challenges inherent with large scale projects,including the length of construction time before the project is online and access to the capital markets.A second goal was to develop strategies that could be used to meet an objective of the RIRP of producing equitable rates over the useful life of the assets being financed.Structures commonly used in the current capital markets would not meet this goal,as certain of the assets required to be financed have longer useful lives than the longest term capital markets transaction could bear.With these challenges in mind,we developed separate versions of the model that would capture the cost of financing under a "base case”scenario and an "alternative”scenario, both of which are described in greater detail below. Major Assumptions (Black &Veatch Inputs).The input assumptions for the RIRP financial model were developed around outputs from the Black &Veatch PROMOD/Strategist modeling analysis.The results created a detailed list of the capital costs for the projects chosen over the 50-year RIRP time horizon.The results show both generation unit costs as well as required transmission development costs associated with the 6 selected projects.Other assumptions used from the Black &Veatch PROMOD analysis include associated fuel costs,fixed and variable O&M,CO:charges,and forecasted energy load requirements by year,including DSM energy use reductions. Major Assumptions (Financing Model Inputs).The assumptions used for capital markets transactions within the financing model are all market-accepted structures for an investment grade utility,cooperative,or joint action agency.Below is a summary of the major structuring assumptions used for both financing scenarios: ¢30-year debt repayment on all bond issues.sold in the capital markets ¢7.00%interest rate on all bond issues sold in the capital markets e Rate generated debt service coverage of 1.25X e Allenergy generation developed is used or sold ¢Debt Service Reserve Fund (DSRF)for each bond issue funded at 10%of bond issue par amount.The DSRF balance is maintained throughout the 50-year RIRP and earns 3.00%interest,which is used to pay debt service on an annual basis. Base Case Model:Specific Assumptions.The base case financing model was structured such that the list of generation and transmission projects would be financed through the capital markets in advance of construction and that the cost of the financing in the form of debt service on the bonds would immediately be passed through to rate payers (see "Construction Work in Progress”herein).Bond issues are assumed to be sold prior to the required project funding dates,and staggered in approximately three-year intervals over the first 20-years,when the majority of the large capital projects and transmission projects are scheduled.The projects being financed over the balance of the 50-year RIRP period are financed through cash flow created through normal rates and charges ("pay-go”).The pay-go approach works once debt service coverage from previous years has grown to levels that create cash reserve balance amounts sufficient to pay for the projects as their construction costs come due. The sources of funds for the projects included in the RIRP under the base case model are as follows: RIRP Plan 1A ;Base Case Sources ofFunds :(dollars in millions). Bonds $5,889 State Funds so Infrastructure Tax so Pay-Go $3,196 The base case model assumes that approximately $5.9 billion of bonds are sold over the RIRP time horizon through five different bond sales ranging in size from $656 million to $2.5 billion.The maximum fixed charge rate on the capital portion alone is estimated to cost $0.13 per kWh,while the average fixed charge rate over the 50-years is $0.07 per kWh. Alternative Model:Specific Assumptions.The alternative model was developed with the goal of minimizing the rate shock that may otherwise occur with such a large capital plan,and levelizing the rate over time so that the economic burden derived from these projects can be spread more equitably over the useful life of the projects being contemplated.Similar to the base case scenario,the first method used was to transfer the excess operating cash flow that is generated to create the debt service coverage level,and use that balance to both partially fund the capital projects in the early years and almost fully fund the projects in the later years.The second method used was the implementation of a Capital Benefits Surcharge that is applied to rate payers starting the day GRETC is formed.For this analysis,it was assumed that a $0.01 rate surcharge would be in place for the first 17 years,during which time approximately 75%of the capital projects in the plan will have been constructed.The third method used to spread out the costs over a longer time period was the use of the State as an equity participant in the execution of the RIRP capital funding plan.In a financing structure that is similar to the Bradley Lake financing model,the State would provide the upfront funding for any large hydroelectric projects,to be paid back by GRETC out of system revenues over an extended period of time,and following the repayment of the potentially more expensive capital markets debt.This analysis assumes that a $2.4 billion hydroelectric project is financed througha zero interest loan to GRETC that is then paid back through a 30-year capital markets take-out bond issue in 2047. The sources of funds for the projects included in the RIRP under the alternative case model are as follows: RIRP Plan 1A:Alternative Case Sources of Funds .(dollars in millions)© Bonds $3,657 State Funds $2,409 Benefit Surcharge $883 Pay-Go $2,135 The alternative model assumes that $5.9 billion of bonds are sold over the RIRP time horizon through nine different bond sales ranging in size from $32 million to $2.4 billion,which includes the $2.4 billion take-out financing to repay the State for front-funding of hydroelectric assets.The capital costs not bonded for come from the rate surcharge that is applied from day one and cash flow generated from rates and charges after operations and debt service (pay-go capital).The maximum fixed charge rate on the capital portion alone is estimated to cost $0.08 per kWh,while the average fixed charge rate over the initial 50-year period is $0.06 per kWh,not including the $0.01 consumer benefit surcharge that is in place for the first 17 years.While the average fixed cost is not significantly different between the base case and alternative scenarios,the difference between the two maximum rates are significant.The lower maximum rate in the alternative scenario benefits the rate payers by smoothing out the rates over a period of time that more closely matches the useful life of the RIRP assets. Summary,Next Steps,Conclusion.The RIRP presents a number of funding challenges,given the size and scope of the projects being contemplated.It has become evident through the financial modeling and the individual debt capacity analyses of this process that the utilities on their own would not be able to accomplish such an ambitious capital plan.The formation of a regional entity,such as GRETC,that would combine the existing resources and rate-base of the Railbelt utilities,as well provide an organized front in working to obtain private financing and the necessary levels of State assistance would be,in our opinion,a necessary next step towards achieving the goal of reliable energy for the Railbelt now and in the future. 'RIRP Plan 1A -Base Case Financial Model -. oe b ..Ks 3 : x.2ah :Pen f :GAS Year bie? "e 'i .'Hak 4 ,"F :'nulreme -.e =Fe OF Ci .PoP s We BONDS ABs Alaska Regional Integrated Resource Plan 3 ar a Se 2a)ay 2s Mca D Fant?aes thes io Cash Flow y dollars in mitions 4)12/1/2012 1 506,496,362 -$06,496,363 5 886,736,5932]12/1/2012 .256,773,239 bd 256,773,239 -- 3)12/1/2013 .119,476,707 3,990,284 123,466,991 -- Base Case 4]12/1/2014 .122,463,625 52,942,550 175,406,175 (25,000,000)!$656,306,880100%Fixed Rate 5]12/1/2015 -2,435,356 191,310,564 193,745,920 -- Sources of Funds 6]12/1/2016 33,699,203 .22,466,161 255,989,420 312,154,784 .- BONDS 5,889 7]12/1/2017 26,865,753 74,229,623 117,965,769 219,061,145 (105,000,000)]$795,887,676STATE(through construction)t)8]12/31/2018 43,273,053 174,256,113 41,630,847 259,160,013 -- Infrastructure Tax through 2027 Q 9}12/1/2019 79,301,147 174,171,476 169,193,895 *422,666,518 -- Other (use of coverage reserves)3,196 10}12/1/2020 238,340,271 208,891,416 321,882,411 769,114,097 (190,000,000)]$2,454,911,924TotalSourceofFunds9,085 11)12/2/2021 481,536,897 21,500,060 282,636,456 785,673,412 .- 12/1/2022 652,793,163 bd 437,331,250 1,090,324,414 -- Use of Funds 12/1/2023 712,137,997 -464,423,300 1,176,561,297 (320,000,000)]$1,095,198,536Project/Construction 9,085 12/1/2024 141,426,155 -59,937,820 201,363,975 -- Payment of interest accrued o 12/1/2025 -.-18,210,430 18,210,430 -- Reserve Funds 0 12/1/2026 -.19,062,834 19,062,834 -- Issuance Costs o 12/1/2027 -88,657,273 oa 88,657,273 (485,500,231}]$- Capitalized Interest (through construction)oO 12/1/2028 -208,125,424 .208,125,424 -- Total Uses of Funds 9,085 12/1/2029 -188,717,535 .188,717,535 .- 12/1/2030 --.-- Maximum Annuat Debt Service Requirements 12/1/2031 -...- BONDS _$39 12/1/2032 --.-- STATE 0 12/1/2033 --.-- 12/1/2034 -2,260,136 2,260,136 (239,531,757)|$- 12/1/2035 -206,133,124 206,133,124 .- Ave,Annual Energy Requirement (GWhr)5,625 12/1/2036 -31,138,497 31,138,497 -- Target Debt Service Coverage (DSC)1.25K 12/1/2037 -.-.. All-in Borrowing Cost 7.00%12/1/2038 -.... Escalation Factor (Inflation)2.50%12/1/2039 -127,791,596 127,791,596 -{699,805,525)}$. Average Cost of Energy {$/per kWh)0.07 12/1/2040 -299,994,339 299,994,339 -- 12/1/2041 -272,019,589 272,019,589 ->12/1/2042 -°.-- 12/1/2043 -131,612,221 131,612,221 {720,727,822)|$- Assumptions 12/1/2044 -308,963,361 308,963,361 .- Issuance Cost =2%of Par Amount 12/1/2045 -280,152,241 280,152,242 -- Par coupons 12/1/2046 -. . --- Debt service reserve funded at 10%of Bond Par Amount 12/1/2047 «.-<- Bonds all assumed to be 30 years from date of issue 12/1/2048 --.-. 12/1/2049 .-.-. 12/1/2050 -.--- 12/1/2051 ::.-- 12/1/2052 ...-- 12/1/2053 --.-- 12/1/2054 ..._(410,069,419)]$: 12/1/2055 :35,525,625 35,525,625 "os - 12/1/2056 -161,918,291 161,918,291 -- 12/1/2057 ....- 12/1/2058 .38,257,213 38,257,213 .- 12/1/2059 -174,368,290 174,368,290 -- 12/1/2060 -.. Prepared by Seattle-Northwest Securities Corporation 12/1/2009 =a.= OOPNAMAWNameraanNOWOHAYWN18 Year Repayment of State saad te bontheties .DSRF Interest Earnings Total Requirements ernie ear 12/1/2011]$$35,268,100 -$35,268,100 $,37212/1/2012 81,206,200 2,660,210 78,545,990 5,41212/1/2013 81,204,300 2,660,210 78,544,090 $,42412/1/2014 107,308,425 2,660,210 104,648,215 $,42112/1/2015 141,306,550 4,629,130 136,677,420 5,16712/1/2016 141,309,000 4,629,130 136,679,870 $,14712/1/2017 172,958,250 4,629,130 168,329,120 §,12912/1/2018 214,187,950 7,016,793 207,171,157 5,10512/1/2019 214,190,100 7,016,793 207,173,307 5,08512/1/2020 311,827,975 7,016,793 304,811,182 5,06812/1/2021 439,001,050 14,381,529 424,619,521 §,05212/1/2022 439,000,300 14,381,529 424,618,771 5,08112/1/2023 482,557,328 14,381,529 468,175,796 $,11112/1/2024 $39,293,200 17,667,125 521,626,075 5,14012/1/2025 539,294,650 17,667,125 $21,627,525 $,17412/1/2026 539,289,900 17,667,125 $21,622,775 §,20712/1/2027 $39,284,300 17,667,125 521,617,175 §,24112/1/2028 $39,290,400 17,667,125 $21,623,275 §,27512/1/2029 539,297,250 17,667,125 521,630,125 $,30912/1/2030 539,296,800 17,667,125 521,629,675 $,34412/1/2031 539,293,550 17,667,125 521,626,425 5,37812/1/2032 539,293,500 17,667,125 521,626,375 $,41312/1/2033 539,288,800 17,667,125 521,621,675 $,44712/1/2034 $39,293,450 17,667,125 521,626,325 5,48212/1/2035 539,286,550 17,667,125 521,619,425 5,51712/1/2036 $39,289,400 17,667,125 521,622,275 §,55312/1/2037 $39,287,350 17,667,125 521,620,225 $5,58812/1/2038 539,291,900 17,667,125 $21,624,775 $,62312/1/2039 539,293,600 17,667,125 521,626,475 5,65912/1/2040 539,288,100 17,667,125 $21,620,975 5,69512/1/2041 539,290,450 17,667,125 $21,623,325 §,73112/1/2042 458,083,350 17,667,125 440,416,225 8,76712/1/2043 458,087,900 17,667,125 440,420,775 5,80312/1/2044 458,086,400 17,667,125 440,419,275 5,83912/1/2045 397,988,550 17,667,125 380,321,425 5,87612/1/2046 397,984,050 17,667,125 380,316,925 $,91212/1/2047 397,982,000 17,667,125 380,314,875 5,94912/1/2048 325,101,750 17,667,125 307,434,625 5,98612/1/2049 325,102,950 17,667,125 307,435,828 6,02312/1/2050 325,107,400 17,667,125 307,440,275 6,06012/1/2051 100,294,000 17,667,125 82,626,875 6,09812/1/2052 100,293,100 17,667,128 82,625,975 6,13512/1/2053 100,291,100 17,667,125 82,623,975 6,17312/1/2054 ..6,21112/1/2058 --6,24912/1/2056 --6,28712/1/2057 --6,32612/1/2058 --6,36412/1/2059 -:6,40312/1/2060 -6,442 Prepared by Seattle-North Securities Cosp 42/1/2009 Jt ---es ee 3 ;<4PheedO&M Cost |Variable O&M re =:ve.Year a 000s)7 Cott (000s)Cost (000s) mF em herd a Rees "a 4112/1/2011 651 259,482 39,359 30,852 -44,085,125 $817,025 °8,817,025 -2)12/1/2012 2,491 .271,611 38,557 32,902 54,963 -98,182,488 19,636,498 ,28,453,523 -3]12/1/2013 "3,063 258,329 42,182 31,820 56,995 98,180,113 19,636,023 48,089,545 °4)12/1/2014 5,878 :.282,641 42,195 32,222 63,421 130,810,269 26,162,054 |25,000,000 49,251,5995]12/1/2015 10,455 *361,674 35,055 35,819 65,306 170,846,774 34,169,355 |83,420,9546]12/1/2016 12,759)°..°373,704 37,978 35,083 68,216 170,849,837 34,169,967 :117,590,921 -7)12/1/2017.14,892 352,673 38,010 36,043 73,346 210,411,399 42,082,280 |205,000,000 -54,673,2018]12/1/2018 12,241 |224,380 36,088 34,170 81,543 258,963,946 $1,792,789 !-106,465,9909]12/1/2019]12,657 244,337 34,987 35,596 86,958 -.258,966,633 52,793,327 |158,259,317 |40|12/1/2020 13,124 235,418 37,377 29,384 90,354 *+381,013,977 76,202,795 ;190,000,000 44,462,112 .44]12/1/2021 13,346 .247,202 39,360 ,30,390 |.97,474 530,774,401 106,154,880 ,.150,616,99212|12/1/2022 14,024 +2 267,038 41,732 fo:29,426 110,165 -530,773,463 106,154,693 |:256,772,685 °43]12/1/2023 .4,166 +284,104 35,897 is ++30,380 +224,805 *$85,219,745 117,043,949 |320,000,000 53,815,634:14]12/1/2024).,3,313 '297,843 36,104 >33,631 .125,785 652,032,594 130,406,519 ..184,222,1531512/1/2025]4,222 |"=".201,208 $7,389 29,739 90,619 652,034,406 130,406,881 ;314,629,03416|12/1/2026 $342]+227,331 57,967 16,925 407,681 *652,028,469 130,405,694 ,445,034,72847|12/1/2027]855%238,262 $8593] :47,362 118,039 652,021,469 130,404,294 |485,500,231 89,938,79118]12/1/2028 13,323 247,810 59,207 *18,257 130,862 652,029,094 130,405,819 ::.220,344,61019]12/1/2029 16,151 ”»261,837 59,936 oi 7 38,745 146,548 652,037,656 130,407,531 |350,752,141 °20)12/1/2030]-*17,064 "+226,648 84,248 .17,865 135,367 652,037,094 130,407,419 |481,159,56021}12/1/2032 24,951].224,691 84,983 15,652 140,642 652,033,031 130,406,606 .611,566,1662212/1/2032]-15,081]....234,947 86,456 16,122 152,129 652,032,969 >130,406,594 741,972,76023]12/1/2033]-|.15,919 249,713 87,902 +16,762 166,550 652,027,094 130,405,419 872,378,17924]12/1/2034 16,747 "+260,042 89,276 +,|17,408 180,198 652,032,906 130,406,581 :239,531,757 763,253,00325)12/1/2035 18,111 279,793 90,794 om 98,296 .+200,974 652,024,281 130,404,856 ::893,657,85926]12/1/2036 §,493 |.” ©.292,296 92,408 18,814 ”218,387 652,027,844 "-130,405,569*1,024,063,42827|12/1/2037 °°7,019 -935,171 97,112 <19,787 257,520 652,025,281 «130,405,056 1,154,468,48428]12/1/2038 :>6,453 +#352,597 -*98,638 +£20,542 281,586 652,030,969 130,406,194 :1,284,874,67829]12/1/2039 8,848 ".)368,539 100,317 2 7.24,287 306,519 652,033,094 130,406,619 *699,805,525 715,475,77230]12/1/2040 12,284 /385,523 101,920]*22,049 332,326 652,026,219 130,405,244 |845,881,01631]12/1/2041 .18,825} | 403,233 103,660 22,861 .361,453 652,029,156 130,405,831 |976,286,84732]12/1/2042].°.21,852 394,321 95,445 on,21,546 _371,427 $50,520,281 110,104,056 : .1,086,390,90333]12/1/2043]-2.22,199 -,412,100 97,223}22,392 S,,404,276 550,525,969 *120,105,194 720,727,822 475,768,27534]12/1/2044)-23,458 :428,330 152,761 (723,116 [>.-439,168 «$50,524,094 ©220,104,819 :585,873,09435!12/1/2045 22,134 449,075 .101,037 123,977 |-.476,267 i)475,401,781 .)95,080,356;680,953,45036]12/1/2046 ”22,961 »421,293 140,010 "26,073 466,403 475,396,156 +95,079,232 776,032,68137]12/1/2047]*24,452 424,059 *142,963 26,512 -490,408 475,393,594 95,078,719 871,111,40036]12/1/2048 +,25,398 "444,964 146,057 <7.27,392 -$37,229 "384,293,281 76,858,656 |947,970,05639]12/1/2049 os 6,909 >461,902 *149,291 28,395 584,308 .384,294,781 76,858,956 1,024,829,01340]12/1/2080 +9728]t+.477,627 152,489 29,313 ..630,743 384,300,344 76,860,069 '1,101,689,08244/12/1/2051 *44,174 *503,605 155,601 .30,361 656,308 "103,283,594 20,656,719 ;1,122,345,80042]12/1/2052 9,139 $20,728 |158,955 "12 31,315 +.»676,369 |«103,282,469 20,656,494 1,143,002,294 '43{12/1/2053 14,889 "S $46,462 *162,470 "4 32,477 *705,371 103,279,969 *20,655,994;1,163,658,28844]12/1/2054 *22,880 .$62,487 -*165,955 33,535 723,997 ces :.|410,069,419 753,588,86945)12/1/205S}--”_--27,949 $79,273 169,720 34,785 749,388 .-:753,588,86946]12/1/2056 "30,133 "7,608,200 173,258 vas,35,877 774,023 -.4 .753,588,869"47|12/1/2057 "33,288 *647,750 180,086 37,668 822,050 --4 753,588,86948|12/1/2058 33,226 682,788 182,230 38,924 862,251 .-4 753,588,86949]12/1/2089 .34,309 "746,552 186,278 -40,624 900,505 .-4 753,588,86950]12/1/2060|_32,082 -:734,465 .,190,935 41,639].923,018 2 -4 ._753,588,869 | Prepared by Seattle-Northwest Securities Corp 12/1/2009 RIRP Plan 1A -Alternative Case Financial Model Year Alaska Regional Integrated Resource Plan Scenario Cash Flow Summary doliarsin millions 4)12/1/2011 1 506,496,362 -506,496,362 -$833,019,1822}12/1/2012 -256,773,239 .256,773,239 --- r AAe 3}12/1/2013 -119,476,707 3,990,284 123,466,991 --- Alternative Scenario 4]12/1/2014 -122,463,625 52,942,550 175,406,175 -(15,000,000)$470,031,769100%Fixed Rate 5/12/1/2015 -2,435,356 191,320,564 193,745,920 --- Sources of Funds 6}12/1/2016 33,699,203 22,466,161 255,989,420 278,455,581 Pree 2,400,375,640):- BONDS 3,657 7)12/1/2017 26,865,753 74,229,623 117,968,769 192,195,392 -(75,000,000)|$§22,012,548STATE(through construction)2,409 8]12/1/2018 43,273,053 174,256,113 41,630,847 215,886,960 --- Infrastructure Tax through 2027 883 9]12/1/2019 79,301,147 174,171,476 169,193,895 343,365,370 ---Other (Use of Coverage Reserves)2,135 10]12/1/2020 238,340,271 208,891,416 321,882,411 $30,773,827 -(120,000,000)|$999,656,778TotalSourceofFunds9,085 11]12/1/2021 481,536,897 21,500,060 282,636,456 304,136,516 --- 12]12/1/2022 652,793,164 -437,331,250 437,331,250 --- Use of Funds 13]12/1/2023 712,137,997 .464,423,300 464,423,300 . ::(180,000,000)|$229,188,962Project(Construction 9,085 14]12/1/2024 141,426,155 :59,937,820 $9,937,820 - , .-Paymentofinterest accrued o 18]12/1/2025 :-18,210,430 18,210,430 --. Reserve Funds o 16]12/1/2026 ::19,062,834 19,062,834 ---Issuance Costs 0 :17|12/1/2027 -88,657,273 -88,657,273 .(245,000,000}]$32,875,895CapitalizedInterest(through construction}oO 18|12/1/2028 -208,125,424 -208,125,424 -..Total Uses of Funds 9,085 19]12/1/2029 -188,717,535 :-:188,717,535 -.- 20}12/1/2030 ---- :-- Maximum Annual Debt Service Requirements _21)12/1/2031 ---.-.. BONDS 314 22)12/1/2032 -.....STATE 322 23}12/1/2033 --.-.- 24}12/1/2034 :2,260,136 2,260,136 .(239,531,757)$025]12/1/2035 -206,133,124 206,133,124 -:-- Ave.Annual Energy Requirement (GWhr)5,625 26|12/1/2036 .31,138,497 31,138,497 ; --- Target Debt Service Coverage (DSC)4.25X 27|12/1/2037 --:. -... All-in Borrowing Cost 7.00%28]12/1/2038 -..... Escalation Factor (Inflation)2.50%29)12/1/2039 -127,791,596 127,791,596 -(600,000,000)]$99,805,525AverageCostofEnergy($/per kWh)0,06 30}12/1/2040 -299,994,339 299,994,339 -:- 31}12/1/2041 -272,019,589 272,019,589 --. 32}12/1/2042 .-.”-- 33]12/1/2043 -131,612,222 131,612,221 -(250,000,000)$470,727,822Assumptions34}12/1/2044 .308,963,361 308,963,361 -- ; - Issuance Cost =2%of Par Amount 351 12/1/2045 -280,152,241 280,152,241 ---Par coupons 36]12/1/2046 --..:- Debt service reserve funded at 10%of Bond Par Amount 37]12/1/2047 --- POESEST.2,409,373,640 |-- Bonds all assumed to be 30 years from date of issue 38]12/1/2048 --.--- 39}12/1/2049 ----:. 40}12/1/2050 -.-.-- 44|12/1/2051 .. ; -... 42|12/1/2052 .- ...-- 43]12/1/2053 -- :e : -: , - 44)12/1/2054 ----{410,069,419)]$(0)45]12/1/2055 -35,525,625 35,525,625 --- 46]12/1/2086 -161,918,251 161,918,291 --- 47|12/1/2057 -.---. 48)12/1/2058 -38,257,213 38,257,213 Loe - 49]12/1/2059 . -174,368,290 174,368,290 - : -- 50]12/1/2060 --:--.- Preparedby Seattle-NorthwestS:ities Corporati 12/1/2009 =OOMNDHRON2-a=aon14 =a16)aanomNNNKNARUNADSNNanod28 Year 12/1/2011 12/1/2012 12/1/2013 12/1/2014 12/1/2015 12/1/2016 12/1/2017 12/1/2018 12/1/2019 12/1/2020 12/1/2021 12/1/2022 12/1/2023 12/1/2024 12/1/2025 12/1/2026 12/1/2027 12/1/2028 12/1/2029 12/1/2030 12/1/2031 12/1/2032 12/1/2033 12/1/2034 12/1/2035 12/1/2036 12/1/2037 12/1/2038 12/1/2039 12/1/2040 12/1/2041 12/1/2042 12/1/2043 12/1/2044 12/1/2045 12/1/2046 12/1/2047 12/1/2048 12/1/2049 12/1/2080 12/1/2051 12/1/2052 12/1/2053 12/1/2054 12/1/2055 12/1/2056 12/1/2057 12/1/2058 12/1/2089 12/1/2060 Prepared by Seattle-Northwest Securities Corporation Repayment of State seeyaid to Londhokiere DSRF Interest Earnings Total Requirements marinear $-33,131,525 -33,131,525 §,37276,283,050 2,499,058 73,783,992 5,41276,281,650 2,499,058 73,782,592 5,42494,980,800 2,499,058 92,481,742 $421119,327,100 3,909,153 115,417,947 5,167 -119,327,000 3,909,153 115,417,847 8,147 -140,091,050 3,909,153 136,181,897 5,129 :167,135,950 5,475,190 161,660,760 5,108 -167,133,450 5,475,190 161,658,260 5,085 -206,891,825 $5,475,190 201,416,635 5,068 -258,677,150 8,474,161 250,202,989 $,052 :258,678,050 8,474,161 250,203,889 5,081 -267,790,975 8,474,161 259,316,814 5,111 -279,659,600 9,161,728 270,497,872 5,140 :279,668,350 9,161,728 270,506,622 $,174 -279,658,100 9,161,728 270,496,372 5,207 -292,456,550 9,161,728 283,294,822 $,241 -305,241,850 9,260,355 295,981,495 5,275 -305,240,900 9,260,355 295,980,545 5,309 -305,242,800 9,260,355 295,982,445 5,344 -305,244,200 9,260,355 295,983,845 5,378 :305,245,000 9,260,355 295,984,645 5,413 -305,243,000 9,260,355,295,982,645 5,447 .305,243,900 9,260,355 295,983,545 §,482 -305,240,600 9,260,355 295,980,245 5,517 -305,243,900 9,260,355 295,983,545 5,553 -305,236,100 9,260,355 295,975,745 5,588 -305,237,750 9,260,355 295,977,395 5,623 -309,204,550 9,260,355 299,944,195 5,659 -314,375,350 9,559,772 304,815,578 5,695 -314,385,800 9,559,772 304,826,028 5,731 -238,098,800 9,559,772 228,539,028 5,767 -256,818,500 9,559,772 247,258,728 5,803 :281,213,300 10,971,955 270,241,345 5,839 -238,156,850 10,971,955 227,184,895 $,876 -.238,159,400 10,971,955 227,187,445 $,91295,827,375 238,157,150 10,971,955 323,012,570 5,949191,654,750 190,355,650 10,971,955 371,038,445 5,986191,654,750 190,357,950 10,971,955 371,040,745 6,023191,654,750 190,355,750 10,971,955 371,038,545 6,060191,654,750 98,815,900 10,971,955 279,498,695 6,098191,654,750 98,809,900 10,971,955 279,492,695 6,135191,654,750 98,809,900 10,971,955 279,492,695 6,173191,654,750 77,824,800 10,971,955 258,507,595 6,211196,264,750 77,826,750 10,971,955 263,119,545 6,249201,172,050 77,826,500 10,971,955 268,026,595 6,287206,198,250 52,247,150 10,971,955 247,473,445 6,326211,354,400 52,246,350 10,971,955 252,628,795 6,364216,638,400 $2,250,150 10,971,955 257,916,595 6,403222,055,700 $2,242,250 10,971,955 263,325,995 6,442 Year i:Cost (000s)¥me atin.=9 debt serviceTrimtd fi GRETC Direct Debt Service Coverage a[i2fijzoit 651 755,482 39,359 30,852 >33,717 410.47 s 2]12/1/2012 1,494 271,611 38,557 32,902 54,963 |-£4120°733.86 02229881 1Ba4s'958,125)8,282,881. 3)12/1/2013 3,063 258,329 42,181 31,820 56,995 |$4,241,323.99 92,228,241 18,445,648 138!26,728,879;4]12/1/2014 5,878 282,661 *42,195 32,212 63,421 |»$4,213,850.02 115,602,178 -23,120,436:ra 45,174,527; 5|12/1/2015 10,455 361,674 35,055 35,819 65,306 |.-$1,673,819.94 144,272,434 28,854'487 |et 15,000,000 53,294,963|6|12/1/2016 42,759 373,704 37,978 35,083 68,216 |$1,473,835.41 444,272 309 se tea ten 3255 82,149,450'7|12/1/2017 11,891 352,673 38,010 36,043 73,346 |51,287,518.63 170,227,371 34,045,474|325,"141,003,922;a|12/1/2018 12,241 224,380 36,088 34,170 81,543}$1,052,273.99 202,075,949 40,415,190 ;tas neon eaters. 9}12/1/2019 12,657 244,337 .34,987 35,596 86,958 |©50,849,002.21 202,072,824 40,424;'565 135}.ers 10]12/1/2020 13,124 235,418 37,177 29,384 90,354} 50,683,538.05 251,770,793 "50,354,159|toe,150,879,141|11]12/1/2022 -13,346 247,202 39,360 30,390 97,474 |50,524,635.70 "312,753,736 62,550,747j tas 420,000,000 32,233,299 12}12/1/2022 _14,024 .*267,038 "44,731 23,426 110,165 |"50,814,618.33 312,754,861 62 Soon.D8.eee ong: 13)12/1/2023 4,166 ».284,104 "38,897 30,380 114,805 |-52,106,167.59 324,146,018 64,829,204 |18 206,335,019 14}12/1/2024 3,313 *297,843 |36,104 33,631 125,785 |-51,401,295.02 338,122,340 67,624,468 :18.#801000,000 oe gen 22218)12/1/2025 4,222 _204,105 57,389 29,739 90,619 |.$2,736,787.37 338,133,278 67,626,656 |128.ene seg 16}12/2/2026 5,342 -227,331 ©57,967 16,925 107,681 |.$2,073,821.68 338,120,465 67,624,093 |8.penne 47|12/1/2027 8,551 238,262 _58,593 37,362 318,039 |52,412,432.40 354,118,528 70,823,706 |38 88 48]12/1/2028 13,323 _207,830 59,207 18,257 430862).-369,976,868 73,995,374:ws,noone sorte ets 49}12/1/2029 16,151 261,837 -59,916 18,745 146,548 co 369,975,681 --73995,136.te 193,858,518,20}12/1/2030 17,064 226,648 84,248 17,865 135,367 .369,978,086 73,995,611 |425 267,853,655 21)12/1/2031 44,951 224,691 84,983 15,652 140,642 -369,979,806 J3'998.961 125;341,849,266 22)12/1/2032 15,081 234,947 -86,456 16,121 152,129 "-369,980,806 73,996,161 |125)415,845,227| 23)12/1/2033 -15,919 249,713 "87,902 16,762 "466,550 »-369,978,306 73,995,661 |res -499,841,388 2a}42/1/2034 16,747 260,041 89,276 17,408 -190,198 :*369°979,431 73,995.88 re 563,837,049|25]12/1/2035 18,111 279,793 90,794 18,296 200,974 369,975,306 53,995,061:125 239,530 757 398,301,178 26]12/1/2036 5,493 -292,296 >92,408 18,814 218,387 vs 369,979,431 -73,995,886.125 .seven ate 27|12/1/2037 7,019 335,172 97,112 19,787 257,520 oor "|369,969,681 73,993,936|125 546,292,126; 28]12/1/2038 6,453 352,597 98,638 20,542 ">281,586 * >,369,971,743 73,994,349 133 : 620,286,062 2a|12/1/2039 +8,848 *368,539 -100,317],21,287{=306,519 ."|374,930,243 74,986,049 -hee 694,280,410 30|12/1/2040 12,284 385,523 101,920 22,049 332,326 :"381,019,473 76,203,895 |r S|.600,000,000 169,266,459| 34]12/1/2041 18,825 "403,233 -103,660 22,861 +361,453 _381,032,535 |76-206 507 'tae!245,470,354 92]12/1/2042 21,582 394,324 95,445 21,546 ©374,427 a _)285,673,785 |-§7134.957 te -|,321,676,861 33]12/1/2043 22,199 .412,100 :97,223 22,392 404,276 .309,073,410 61814682 |125!> .+378,811,618 34{12/1/2044 _23,458].428,330 152,761 23,136 439,168 337,801,681 *67,560,336.ee 50,000,000 *190,626,300 35)12/1/2045 22,134 449,075 301,037 23,977 476,267 283,981,118 -56,796,226 12s!.",258,186,636-981,796,224 |.314,982,85936]12/1/2046 22,962 421,293 140,010 26,073 .466,403 283,984,306 56,796,861|125.779, 37]12/1/2047 *24,452 424,059 _142,963 26,511 .490,408 403,765,712 80,753,142 :125"371,779,720 38)12/1/2048 25,398 444,961 146,057 27,392 537,229 463,798,056 92,759,611 |125,$52592.863 39]12/1/2049 6,909 *461,902 149,291 28,395 584,308 .-463,800,931 92,760,186 |125)545,292,474-40|12/1/2050 :8,724 "477,627 152,489 29,313 630,743 |"463,798,181 92,759,636.125°ee 41]12/1/2051 14,174 '.$03,605 -155,601 30,361 .656,308 |>*349,373,368 69,874,674 si -730,812,296: 42]12/1/2052 9,139 520,728 158,955 31,315 :676,369 Le 349,365,868 69,873,174 ;125!800,686,970: 43)12/1/2053 14,889 546,462 362,470 32,477 705,371 Se "349,365,868 "69,873,374|128:870,560,144 44]12/1/2054 22,880 $62,487 165,955 33,535 723,997 -323,134,493 64,626.89:125!410,069,429 940,433,317. 45]12/1/2055 27,949 579,273 -169,720 34,785 749,388 I .328809.431 66888 |125/ .410,069,$94,990,797. 46]12/1/2056 30,133 "605,200 373,255}..35,877](774,023 :335,033,243 67006649:pet 660,770,683 47]12/1/2087 33,288 647,750 180,086 37,668 822,050 -309,341,806 61,868,361.125".Leben 4a]12/1/2058 33,226 682,788 182,230 38,924 *962,251 >”315,785,993 63,157,199 |125:eee.|49]12/1/2089 31,309 716,552 _186,278 40,624 900,505 -322,395,743 64,479,149 |125!ory ser'ocn'50|12/1/2060 32,092 734,465 190,935 41,639 923,018 .:|329,157,493 _65,831,499 125%00 |983,113,539. Prepared by Seattle-Northwest Securities Corporation 12/1/2009 APPENDIX C EXISTING GENERATION UNITS ALASKA RIRP STUDY APPENDIX C EXISTING GENERATION UNITS Black &Veatch C-1 February 2010 Detailed Existing Unit Tables _Winter Sumoer Full Load Net Plant ForcedMinimumos 5 . a : :cq :.PF:Rating Rating.|Capacity |Variable O&M |Fixed O&M (2009 |Heat Rate (BtwkWh-|Oulage |Must Run]CO2 Emission |NOx Emission |SO2 EmissionNameUnitPrimaryFuel}Startup Fue?(MW)(MW)(MW)(2009 S/ATWh)SAW -y 7)HIty)Rate ("%)(YAN)J Rate (h/mmBtu)[Rate (th/mmBtu)[Rate (ib/mmBtuy Retirement DateAnchorageML&P -Plant 1 3 Natural Gas Natusal Gas 32 29.3 i 3.72 10.47 9,780 6.0 N has 0.44 0.000045 2037 Anchorage ML&P -Plant 2 5 Natural Gas |Natural Gas 374 33.8 5 3.72 1.62 14 7m N 148 0.625 0.000045 2020 Anchorage ML&P Plant 2 516 Natural Gas J Natural Gas 49.2 44.5 lu 3.72 1.62 i i N 114.8 0.625 0.000045 2020 Anchorage ML&P -Plat 2 7 Natural Gas J Natural Gas B18 744 10.3.72 Az)1,193 0.1 N 114.8 0.625 0.000045 2030 Anchorage ML&P -Plant 2 V6 Natural Gas Natural Gas 109.5 99.5 10 3.72 7.79 9,030 01 N nas 0.625 0.000045 2020 Anchorage ML&P -Plant 2 &Nanual Gas Natural Gas 87.6 773 20 3.72 TAT 14.930 17 N 14s 0.08 0.000045 2030 .Winter Summer |Minimum :Full Load Net Plant Forcd Must :S$O2 Emission .Primary Rating Rating Capacity Variable O&M Fixed OGAE (2009 Meat Rate (DavkWhe-|Outage Rua COZ Emission [|NOx Emission Rate Name Unit Fuel Startup Fueg ©(MV){MEAW)©(MAY)(2009 S/MAWh)©SUKWeyr)-.HV)Rate (%)(VIN)TRate (bimmBta)ftate (ib/damBtuy Ob/mmBtuy [Retirement Date Hemice 2 Natural Gas §Natural Gas 19 19 3 4.23 6.15 14,673 2.0 N 11s 0.32 0.000045 2014 Remice 3 Natural Gas }Natural Gas 25.5 25.5 13 1.23 19.48 13,409 2.0 N Hs 0.13 0.000045 2014 Bernice 4 Natural Gas §Natural Gas 25.5 25.5 13 1.23 19.48 13,741 2.0 N 115 0.13 0.000045 2014 Beluga 1 Natural Gas }Natural Gas 17.5 16 3 1.23 14.35 15,198 2.0 N ils 0.32 0.0002 2011 Beluga 2 Natural Gas j Natural Gas 17.5 16 3 1.23 14.35 14,851 2.0 N 115 0.32 0.0002 2011 Beluga 3 Natural Gas J Natural Gas 66.5 56 3 1.44 12.30 12,236 2.0 N 115 0.32 0.0002 2014 Heluga 5 Natural Gas |Natural Gas 6S 54 3 1.44 12.30 12,537 2.0 N lis 0.32 0.0002 2017 Beluga 6 Natural Gas |Natural Gas 82 64 3 1.64 13.33 11,528 1.0 N WS 0.2 0.001 2020 Beluga 6/8 Natural Gas |Natural Gas 108.5 83 48 2.56 29.73 9,329 4.0 N 15 0.2 0.001 2014 Beluga 7 Natural Gas |Natural Gas 82 66 3 1.64 13.33 12,184 1.0 N 115 0.34 0.006 2024 Beluga V8 Natural Gas |Natural Gas 108.5 85 48 2.56 29.73 9,086 4.0 N 115 0.34 0.006 2014 International 1 Natural Gas |Natural Gas 14 13 3 1.23 14.35 16,379 2.0 N 5 0.32 0.002 2011 {International 2 Natural Gas |Natural Gas 14 12.5 3 1.23 14.35 17,425 2.0 N ils 032 0.002 2041 laternational 3 Natural Gas }Natucal Gas 19 16 3 1.23 14.35 15,116 2.0 N Ms 0.32 0.002 2012 Winter Summer Mioimurn .Fored .Rating Rating Capacity [Variable O&M (2009)Fixed O&M (2009 J Full Load Net Plant Heath Outage [Must Runt CO2 Emission |NOx Emission |SO2 Emission Name ,plait Primary Fucl[Startup Foct .(MW)|(MW)(MAW)|S/MWh)»SAWesyr)Rate (BtuskWh -HUV)Ff Rate (%)(YAN)|Rate (b/mmBtu)]Rate Ab/mmBru Nate (Ib'mmBtusctirement DateZchnderGTtHAGODistitfateFuctOil19.2 15.8 4 8.23 10.98 14,030 0.1 N 07 0.8 2030 Zehnder Gt2 HAGO Disullate Fuel Oul 19.6 15 4 8.23 10.98 14,190 0.2 N 128 07 O8 2030 North Pole GTl HAGO Dastillate Fuel Oil 62.6 50 10 3.91 2141 10,010 0.6 N 128 0.7 0.7 2017 North Pole GT2 HAGO Distllate Fuct Oil 60.6 48 10 3.91 2b4l 9,720 0.5 N 128 0.7 0.7 2018 North Pole ce NAPHTHA Disuliate Fuct Oil 65 54 38 3.20 224.56 6,620 0.4 N 114.8 0.76 0.0022 2042 ticaly STl COAL Distillate Fuct Oi!27 265 20 3.30 208.60 13,870 0.7 Y 2it 0.25 03 2022 PP i HAGO Disuillate Fuel Ou 25.8 23.1 4 8.23 10.98 413,210 03 N $28 0.7 0.12 2030 Winter Summer P Nininan wees :::wos Forced ToMust 7.:. SO2 Emisston Primary Rating Rating Capacity |Variable O&M (2009 |Fixed O&M (2009 |Full Load Net Plant lleat{Qutage-Run CO2EmIsion |NOx Enisslon ||Rate : Name Unit Fuel Startup Fuel (ATW)(MW)>(MW)S/MWh)S/AW-yr)-Rate (RiwkWh-HEV)=Rate (%)(VIN)PRate (him Btu)late Ub/immBeud Ob/mmBta)[Retirement Date Nikiski 1 Natural Gas |Natural Gas 42 38 3 6.63 4.82 12,170 1.0 Y 14.8 0.13 0.000045 2026 APPENDIX D REGIONAL LOAD FORECASTS ALASKA RIRP STUDY APPENDIX D REGIONAL LOAD FORECASTS Black &Veatch D-1 February 2010 REGIONAL LOAD FORECASTSAPPENDIXD ALASKA RIRP STUDY Table D-1 GRETC's Winter Peak Load Forecast for Evaluation 2011 -2060 Winter Peak Demand (MIW) Year CEA GVEA HEA MEA ML&P SES GRETC 2010/2011 233.9 238.1 87.0 146.0 188.0 9.5 869.3 2011/2012 233.9 239.6 88.0 151.0 189.0 9.5 877.5 2012/2013 233.9 2413 88.0 153.0 190.0 10.4 883.0 2013/2014 233.9 242.9 88.0 155.0 191.0 10.4 887.4 2014/2015 234.5 217.5 89.0 157.0 192.0 10.4 867.8 2015/2016 234.9 219.2 90.0 159.0 193.0 10.4 873.3 2016/2017 235.5 221.1 90.0 161.0 194.0 10.4 879.0 2017/2018 236.5 222.7 91.0 163.0 195.0 10.4 885.4 2018/2019 237.6 2243 92.0 165.0 196.0 10.4 891.8 2019/2020 238.1 226.0 92.0 167.0 197.0 10.4 896.3 2020/2021 238.6 227.6 93.0 169.0 198.0 10.4 902.7 2021/2022 239.7 229.2 94.0 171.0 199.0 10.4 909.1 2022/2023 240.7 230.9 94.0 173.0 200.0 10.4 914.6 2023/2024 241.7 232.6 95.0 176.0 201.0 10.4 922.1 2024/2025 242.2 234.3 96.0 178.0 202.0 10.4 927.5 2025/2026 242.8 236.0 97.0 180.0 203.0 10.4 934.0 2026/2027 243.8 237.7 97.0 182.0 204.0 10.4 939.6 2027/2028 244.8 239.4 98.0 184.0 205.0 10.4 946.1 2028/2029 245.9 241.1 99.0 186.0 206.0 10.4 952.5 2029/2030 246.9 242.8 100.0 188.0 207.0 10.4 959.0 2030/2031 247.9 244.5 100.8 190.2 208.0 10.4 965.4 2031/2032 248.8 246.2 101.6 192.4 209.0 10.4 971.8 2032/2033 249.7 248.0 102.4 194.6 210.0 10.4 978.3 2033/2034 250.7 249.7 103.2 196.8 211.1 10.4 984.7 2034/2035 251.6 251.5 104.0 199.0 212.1 10.4 991.2 2035/2036 252.5 253.2 104.8 201.3 213.1 10.4 997.7 2036/2037 253.5 255.0 105.6 203.5 214.1 10.4 1004.3 2037/2038 254.4 256.7 106.4 205.8 215.2 10.4 1010.9 2038/2039 255.4 258.5 107.3 208.1 216.2 10.4 1017.4 2039/2040 256.3 260.3 108.1 210.4 217.2 10.4 1024.1 2040/2041 257.3 262.0 108.9 212.7 218.3 10.4 1030.7 2041/2042 258.2 263.8 109.7 215.0 219.3 10.4 1037.4 2042/2043 259.2 265.6 110.6 217.4 220.4 10.4 1044.1 2043/2044 260.1 267.4 111.4 219.7 221.4 10.4 1050.9 2044/2045 261.1 269.2 112.3 222.1 222.5 10.4 1057.7 2045/2046 262.0 271.1 113.1 224.5 223.5 10.4 1064.5 2046/2047 263.0 272.9 114.0 226.9 224.6 10.4 1071.3 2047/2048 264.0 274.7 114.8 229.3 225.6 10.4 1078.2 2048/2049 264.9 276.5 115.7 231.8 226.7 10.4 1085.0 2049/2050 265.9 278.4 116.5 234.2 227.7 10.4 1092.0 2050/2051 266.9 280.2 117.4 236.7 228.8 104 1098.9 2051/2052 267.8 282.1 118.3 239.2 229.9 10.4 1105.9 2052/2053 268.8 284.0 119.1 241.7 231.0 10.4 1112.9 2053/2054 269.8 285.8 120.0 244.2 232.0 10.4 1120.0 2054/2055 270.7 287.7 120.9 246.8 233.1 10.4 1127.1 2055/2056 2717 289.6 121.8 249.3 234.2 10.4 1134.2 2056/2057 272.7 291.5 122.7 251.9 235.3 10.4 1141.4 2057/2058 273.7 293.4 123.6 254.5 236.4 10.4 1148.5 2058/2059 274.7 295.3 124.4 257.1 237.4 10.4 1155.8 2059/2060 275.7 297.3 125.4 259.7 238.5 10.4 1163.0 Black &Veatch D2 February 2010 APPENDIX D REGIONAL LOAD FORECASTS ALASKA RIRP STUDY Table D-2 GRETC's Summer Peak Load Forecast for Evaluation 2011 -2060 .Summer Peak Demand (MW) Year CEA GVEA HEA MEA ML&P SES GRETC 2011 160.6 191.4 75.1 91.1 167.2 10.0 668.0 2012 160.6 192.6 75.9 94.1 168.1 10.0 674.3 2013 160.6 193.9 75.9 95.0 169.0 11.0 678.5 2014 160.6 195.2 75.9 95.5 169.9 11.0 681.9 2015 161.3 174.8 76.8 95.5 170.8 11.0 666.8 2016 161.3 176.2 717 95.4 1717 11.0 671.0 2017 162.0 177.7 717 95.3 172.6 11.0 675.4 2018 162.7 179.0 78.5 95.1 173.5 11.0 680.3 2019 163.4 180.3 79.4 95.0 1743 11.0 685.3 2020 163.4 181.6 79.4 °95.0 175.2 11.0 688.7 2021 164.2 182.9 80.2 94.9 176.1 11.0 693.6 2022 164.9 184.3 81.1 96.0 177.0 11.0 698.6 2023 165.6 185.6 81.1 97.1 177.9 11.0 702.8 2024 166.3 187.0 82.0 98.7 178.8 11.0 708.5 2025 166.3 188.3 82.8 99.9 179.7 11.0 N27 2026 167.0 189.7 83.7 101.1 180.6 11.0 N77 2027 167.7 19L.1 83.7 102.3 181.5 11.0 722.0 2028 168.4 192.4 84.6 103.5 182.3 11.0 726.9 2029 169.2 193.8 85.4 104.7 183.2 11.0 719 2030 169.9 195.2 86.3 105.9 184.1 11.0 736.9 2031 170.5 196.5 87.0 107.2 185.0 11.0 741.8 2032 W712 197.9 87.7 108.5 185.9 11.0 746.8 2033 W718 199.3 88.3 109.8 186.8 11.0 751.7 2034 172.4 200.7 89.0 1111 187.7 11.0 756.7 2035 173.1 202.1 89.7 112.5 188.7 11.0 761.6 2036 173.7 203.5 90.4 113.8 189.6 Wi 766.7 2037 174.4 204.9 91.1 115.2 190.5 il TILT 2038 175.0 206.3 918 116.6 191.4 11.2 776.7 2039 175.7 207.8 92.6 117.9 192.3 11.2 781.8 2040 176.3 209.2 93.3 119.3 193.2 11.3 786.9 2041 177.0 210.6 94.0 120.7 194.2 11.4 792.0 2042 177.6 212.1 94.7 122.1 195.1 114 797.1 2043 178.3 213.5 95.4 123.5 196.0 115 802.3 2044 179.0 214.9 96.1 124.9 196.9 11.5 807.5 2045 179.6 216.4 96.9 126.4 197.9 11.6 8127 2046 180.3 217.9 97.6 127.8 198.8 11.7 817.9 2047 180.9 219.3 98.3 1293 199.8 11.7 823.2 2048 181.6 220.8 99.1 130.7 200.7 11.8 828.4 2049 182.3 222.3 99.8 132.2 201.6 11.8 833.7 2050 182.9 223.8 100.5 133.7 202.6 19 839.1 2051 183.6 225.3 101.3 135.2 203.5 12.0 844.4 2052 184.3 226.7 102.0 136.7 204.5 12.0 849.8 2053 184.9 228.2 102.8 138.2 205.4 12.1 855.2 2054 185.6 229.8 103.6 139.7 206.4 12.1 860.6 2055 186.3 231.3 104.3 1413 207.3 12.2 866.0 2056 186.9 232.8 105.1 142.8 208.3 12.3 871.5 2057 187.6 234.3 105.8 144.4 209.3 12.3 877.0 2058 188.3 235.8 106.6 145.9 210.2 12.4 882.5 2059 189.0 237.4 107.4 147.5 211.2 12.4 888.1 2060 189.6 238.9 108.2 149.1 212.2 12.5 893.6 Black &Veatch February 2010 REGIONAL LOAD FORECASTSAPPENDIXD ALASKA RIRP STUDY Table D-3 GRETC's Annual Valley Load Forecast for Evaluation 2011 -2060 Annual VaHey Demand (MW) Year CEA GVEA HEA MEA ML&P SES GRETC 2011 95.4 88.6 444 53.2 91.0 44 413.5 2012 95.4 89.2 449 55.0 91.5 44 417.2 2013 95.4 89.8 44.9 55.8 91.9 48 419.7 2014 95.4 90.4 44.9 56.5 92.4 48 421.7 2015 95.8 81.0 45.5 57.2 92.9 48 413.7 2016 95.8 81.6 46.0 58.0 93.4 4.8 416.3 2017 96.3 82.3 46.0 58.7 93.9 4.8 418.9 2018 96.7 82.9 46.5 59.4 94.4 48 421.9 2019 97.1 83.5 47.0 60.2 94.8 48 424.9 2020 97.1 84.1 47.0 60.9 95.3 48 426.9 2021 97.5 84.7 47.5 61.6 95.8 48 429.9 2022 98.0 85.3 48.0 62.3 96.3 48 433.0 2023 98.4 86.0 48.0 63.1 96.8 48 435.4 2024 98.8 86.6 48.5 64.2 97.3 48 438.9 2025 98.8 87.2 49.0 64.9 97.7 48 4414 2026 99.2 87.8 49.5 65.6 98.2 48 444.5 2027 99.7 88.5 49.5 66.4 98.7 48 447.0 2028 100.1 89.1 50.1 67.1 99.2 48 450.0 2029 100.5 89.7 50.6 67.8 99.7 48 453.1 2030 100.9 90.4 SL1 68.5 100.2 48 456.1 2031 101.3 91.0 51.5 69.3 100.7 48 459.1 2032 101.7 91.7 51.9 70.1 101.1 48 462.1 2033 102.1 92.3 52.3 70.9 101.6 48 465.1 2034 102.5 93.0 52.7 717 102.1 48 468.1 2035 102.8 93.6 53.1 72.6 102.6 4.8 471.1 2036 103.2 94.3 53.5 73.4 103.1 48 474.1 2037 103.6 94.9 54.0 742 103.6 48 477.2 2038 104.0 95.6 54.4 75.0 104.1 48 480.2 2039 104.4 96.2 54.8 75.9 104.6 4.8 483.3 2040 104.8 96.9 55.2 76.7 105.1 48 486.4 2041 105.2 97.5 55.6 T15 105.6 48 489.5 2042 105.5 98.2 56.1 78.4 106.1 48 492.6 2043 105.9 98.9 56.5 79.2 106.6 4.8 495.7 2044 106.3 99.5 56.9 80.1 107.1 48 498.8 2045 106.7 100.2 57,3 81.0 107.6 48 502.0 2046 107.1 100.9 57.8 81.8 108.2 48 505.2 2047 107.5 101.6 58.2 82.7 108.7 48 508.3 2048 107.9 102.3 58.6 83.6 109.2 4.8 511.5 2049 108.3 102.9 59.1 84.5 109.7 4.8 514.7 2050 108.7 103.6 59.5 85.4 110.2 4.8 517.9 2051 109.1 104.3 60.0 86.3 110.7 48 521.2 2052 109.5 105.0 60.4 87.2 111.2 48 524.4 2053 109.9 105.7 60.9 838.1 1118 4.8 527.7 2054 110.3 106.4 61.3 89.0 112.3 4.8 530.9 2055 110.7 107.1 61.7 90.0 112.8 48 534.2 2056 1111 107.8 62.2 90.9 113.3 48 537.5 2057 111.5 108.5 62.7 918 113.8 48 540.8 2058 1119 109.2 63.1 92.8 114.4 4.8 544.2 2059 112.3 109.9 63.6 93.7 114.9 48 547.5 2060 112.7 110.7 64.0 94.7 115.4 48 550.9 Black &Veatch 0-4 February 2010 APPENDIX D REGIONAL LOAD FORECASTS ALASKA RIRP STUDY Table D-4 GRETC's Net Energy for Load Forecast for Evaluation 2011 -2060 Utility Net Energy for Load Forecast (GWh) Year CEA GVEA HEA MEA ML&P SES GRETC 2011 1,302.0 1,522.7 554.5 7112 1,162.8 64.6 5,377.8 2012 1,303.2 1,532.1 557.1 801.9 1,168.3 64.8 5,427.4 2013 1,305.0 1,543.0 560.2 811.1 1,173.8 65.0 5,458.1 2014 1,307.5 1,553.2 564.0 820.9 1,179.3 65.3 5,490.3 2015 1,311.4 1,333.5 568.1 831.9 1,184.9 65.6 5,295.3 2016 1,315.6 1,344.4 572.4 842.8 1,190.4 65.9 5,331.5 2017 1,320.1 1,355.5 577.0 854.0 1,196.0 66.3 5,369.0 2018 1,324.8 1,361.5 581.7 865.4 1,201.6 66.6 5,401.6 2019 1,329.6 1,367.4 586.5 876.8 1,207.3 67.0 5,434.7 2020 1,334.5 1,373.4 591.2 888.3 1,213.0 67.4 5,467.8 2021 1,339.4 1,379.5 596.1 900.1 1,218.7 67.8 5,501.6 2022 1,344.3 1,385.5 601.0 911.7 1,224.4 68.1 5,535.0 2023 1,349.2 1,391.6 605.9 923.2 1,230.1 68.5 5,568.6 2024 1,354.3 1,397.7 610.7 934.8 1,235.9 68.9 5,602.3 2025 1,359.2 1,403.8 615.5 946.4 1,241.7 69.3 5,636.0 2026 1,364.2 1,410.0 620.4 958.0 1,247.6 69.7 5,669.9 2027 1,369.3 1,416.2 625.3 969.7 1,253.4 70.0 5,703.9 2028 1,374.4 1,422.3 630.2 9813 1,259.3 70.4 5,738.0 2029 1,379.5 1,428.5 635.1 992.9 1,265.3 70.8 5,772.0 2030 1,384.5 1,434.7 640.0 1,004.7 1,271.2 71.2 5,806.3 2031 1,389.6 1,440.8 645.0 1,016.7 1,277.1 716 5,840.8 2032 1,394.7 1,447.0 650.0 1,028.7 1,283.0 72.0 5,875.4 2033 1,399.7 1,453.3 655.0 1,040.9 1,289.0 72.4 5,910.2 2034 1,404.8 1,459.5 660.0 1,053.1 1,294.9 72.7 5,945.1 2035 1,409.9 1,465.7 665.1 1,065.4 1,300.9 73.1 5,980.1 2036 1,415.0 1,472.0 670.2 1,077.8 1,306.8 73.5 6,015.3 2037 1,420.1 1,478.2 675.3 1,090.2 1,312.8 73.9 6,050.6 2038 1,425.3 1,484.5 680.4 1,102.8 1,318.8 74.3 6,086.1 2039 1,430.4 1,490.8 685.5 1,115.4 1,324.9 747 6,121.7 2040 1,435.5 1,497.1 690.7 1,128.1 1,330.9 75.1 6,157.4 2041 1,440.7 1,503.5 695.9 1,140.9 1,336.9 75.5 6,193.3 2042 1,445.8 1,509.8 701.1 1,153.7 1,343.0 75.9 6,229.3 2043 1,451.0 1,516.2 706.3 1,166.7 1,349.1 76.3 6,265.5 2044 1,456.2 1,522.5 TLS 1,179.7 1,355.2 76.7 6,301.9 2045 1,461.4 1,528.9 716.8 1,192.9 1,361.3 771 6,338.4 2046 1,466.6 1,535.3 722.1 1,206.1 1,367.4 715 6,375.0 2047 1,471.8 1,541.7 727.4 1,219.4 1,373.5 77.9 6,411.8 2048 1,477.0 1,548.2 732.8 1,232.8 1,379.7 78.3 6,448.8 2049 1,482.3 1,554.6 738.1 1,246.3 1,385.9 78.7 6,485.9 2050 1,487.5 1,561.1 743.5 1,259.9 1,392.1 79.1 6,523.2 2051 1,492.8 1,567.5 748.9 1,273.6 1,398.3 79.5 6,560.6 2052 1,498.0 1,574.0 754.4 1,287.4 1,404.5 79.9 6,598.2 2053 1,503.3 1,580.5 759.8 1,301.3 1,410.7 80.3 6,635.9 2054 1,508.6 1,587.1 765.3 1,315.3 1,416.9 80.7 6,673.9 2055 1,513.9 1,593.6 770.8 1,329.4 |1,423.2 81.1 6,712.0 2056 1,519.2 1,600.1 716.3 1,343.6 1,429.5 81.5 6,750.2 2057 1,524.5 1,606.7 781.9 1,357.9 1,435.8 81.9 6,788.7 2058 1,529.8 1,613.3 787.5 1,372.3 1,442.1 82.3 6,827.3 2059 1,535.1 1,619.9 793.1 1,386.8 1,448.4 82.8 6,866.0 2060 1,540.5 1,626.5 798.7 1,401.4 1,454.7 83.2 6,905.0 0-5 February 2010Black&Veatch APPENDIX D REGIONAL LOAD FORECASTS ALASKA RIRP STUDY Table D-5 GRETC's Winter Peak Large Load Forecast for Evaluation 2011 -2060 Large Load Winter Peak Demand (MW) Year GVEA Anchorage MEA Kenai GRETC 2010/2011 238.1 412.2 146.0 96.3 869.3 2011/2012 239.6 413.2 151.0 97.2 877.5 2012/2013 241.3 414.2 153.0 98.2 883.0 2013/2014 242.9 415.1 155.0 98.2 887.4 2014/2015 217.5 417.1 157.0 99.2 867.8 2015/2016 219.2 418.1 159.0 100.2 873.3 2016/2017 221.1 420.1 161.0 100.2 879.0 2017/2018 222.7 422.1 163.0 101.2 885.4 2018/2019 224.3 4241 165.0 102.2 891.8 2019/2020 226.0 425.1 167.0 102.2 896.3 2020/2021 227.6 427.1 169.0 103.2 902.7 2021/2022 229.2 429.0 171.0 104.2 909.1 2022/2023 230.9 431.0 173.0 104.2 914.6 2023/2024 232.6 433.0 176.0 105.2 922.1 2024/2025 384.3 734.0 178.0 156.2 1398.3 2025/2026 386.0 736.0 180.0 157.2 1404.7 2026/2027 387.7 738.0 182.0 157.2 1410.2 2027/2028 389.4 740.0 184.0 158.2 1416.6 2028/2029 391.1 742.0 186.0 159.2 1423.1 2029/2030 392.8 744.0 188.0 160.1 1429.5 2030/2031 394.5 745.9 190.2 160.9 1435.8 2031/2032 396.2 747.8 192.4 161.7 1442.2 2032/2033 398.0 749.7 194.6 162.5 1448.6 2033/2034 399.7 751.6 196.8 163.3 1455.0 2034/2035 401.5 753.5 199.0 164.1 1461.4 2035/2036 403.2 755.4 201.3 165.0 1468.0 2036/2037 405.0 757.4 203.5 165.8 1474.5 2037/2038 406.7 759.3 205.8 166.7 1481.1 2038/2039 408.5 761.2 208.1 167.6 1487.7 2039/2040 560.3 1063.2 210.4 218.5 1975.7 2040/2041 562.0 1065.1 212.7 219.3 1982.3 2041/2042 563.8 1067.1 215.0 220.2 1989.0 2042/2043 565.6 1069.0 217.4 221.1 1995.7 2043/2044 567.4 1071.0 219.7 222.0 2002.5 2044/2045 $69.2 1072.9 222.1 222.9 2009.3 2045/2046 STL 1074.9 224.5 223.8 2016.1 2046/2047 572.9 1076.9 226.9 224.7 2022.9 2047/2048 574.7 1078.9 229.3 225.6 2029.8 2048/2049 576.5 1080.8 231.8 226.5 2036.7 2049/2050 578.4 1082.8 234.2 227.4 2043.6 2050/2051 580.2 1084.8 236.7 228.4 2050.6 2051/2052 $82.1 1086.8 239.2 229.3 2057.6 2052/2053 584.0 1088.8 241.7 230.2 2064.6 2053/2054 585.8 1090.8 244.2 231.1 2071.7 2054/2055 587.7 1092.8 246.8 232.1 2078.8 2055/2056 589.6 1094.8 249.3 233.0 2085.9 2056/2057 591.5 1096.8 251.9 234.0 2093.0 2057/2058 593.4 1098.9 254.5 234.9 2100.2 2058/2059 595.3 1100.9 257.1 235.8 2107.5 2059/2060 597.3 1102.9 259.7 236.8 2114.7 Black &Veatch D-6 February 2010 APPENDIX D REGIONAL LOAD FORECASTS ALASKA RIRP STUDY Table D-6 GRETC's Large Load Net Energy for Load Forecast for Evaluation (GWh) 2011 -2060 Large Load Net Energy for Load Forecast (GWh) Year GVEA Anchorage MEA Kenai GRETC 2011 1,522.7 2,464.8 771.2 619.1 $§,377.8 2012 1,532.1 2,471.5 801.9 621.9 5,427.4 2013 1,543.0 2,478.8 8111 625.2 5,458.1 2014 1,553.2 2,486.9 820.9 629.3 5,490.3 2015 1,333.5 2,496.2 831.9 633.7 5,295.3 2016 1,344.4 2,506.0 842.8 638.3 5,331.5 2017 1,355.5 2,516.2 854.0 643.3 5,369.0 2018 1,361.5 2,526.4 865.4 648.3 5,401.6 2019 1,367.4 2,536.9 876.8 653.5 5,434.7 2020 1,373.4 2,547.4 888.3 658.6 5,467.8 2021 1,379.5 2,558.1 900.1 663.9 5,501.6 2022 1,385.5 2,568.7 911.7 669.1 5,535.0 2023 1,391.6 2,579.4 923.2 674.4 5,568.6 2024 1,397.7 2,590.2 934.8 679.6 5,602.3 2025 2,389.3 4,572.0 946.4 1,013.3 8,921.0 2026 2,395.5 4,582.8 958.0 1,018.6 8,954.9 2027 2,401.7 4,593.7 969.7 1,023.8 8,988.9 2028 2,410.5 4,610.1 981.3 1,030.0 9,032.0 2029 2,414.0 4,615.7 992.9 1,034.4 9,057.0 2030 2,420.2 4,626.7 1,004.7 1,039.7 9,091.3 2031 2,426.3 4,637.7 1,016.7 1,045.1 9,125.8 2032 2,435.2 4,654.1 1,028.7 1,051.3 9,169.4 2033 2,438.8 4,659.7 1,040.9 1,055.8 9,195.2 2034 2,445.0 4,670.7 1,053.1 1,061.3 9,230.1 2035 2,451.2 4,681.8 1,065.4 1,066.7 9,265.1 2036 2,460.2 4,698.3 1,077.8 1,073.1 9,309.3 2037 2,463.7 4,704.0 1,090.2 1,077.7 9,335.6 2038 2,470.0 4,715.1 1,102.8 1,083.2 9371.1 2039 2,476.3 4,726.2 1,115.4 1,088.7 9,406.7 2040 3,473.5 6,719.2 1,128.1 1,424.6 12,745.4 2041 3,474.5 6,719.6 1,140.9 1,428.3 12,763.3 2042 3,480.8 6,730.9 1,153.7 1,433.9 12,799.3 2043 3,487.2 6,742.1 1,166.7 1,439.6 12,835.5 2044 3,498.9 6,764.2 1,179.7 1,447.0 12,889.9 2045 3,499.9 6,764.7 1,192.9 1,450.9 12,908.4 2046 3,506.3 6,776.0 1,206.1 1,456.6 12,945.0 2047 3,512.7 6,787.4 1,219.4 1,462.3 12,981.8 2048 3,524.6 6,809.5 1,232.8 1,469.8 13,036.8 2049 3,525.6 6,810.1 1,246.3 1,473.8 13,055.9 2050 3,532.1 6,821.6 1,259.9 1,479.6 13,093.2 2051 3,538.5 6,833.0 1,273.6 1,485.4 13,130.6 2052 3,550.4 6,855.3 1,287.4 1,493.0 13,186.2 2053 3,551.5 6,856.0 1,301.3 1,497.1 13,205.9 2054 3,558.1 6,867.5 1,315.3 1,503.0 13,243.9 2055 3,564.6 6,879.1 1,329.4 1,508.9 13,282.0 2056 3,576.5 6,901.5 1,343.6 1,516.6 13,338.2 2057 3,577.7 6,902.3 1,357.9 1,520.8 13,358.7 2058 3,584.3 6,913.9 1,372.3 1,526.8 13,397.3 2059 3,590.9 6,925.6 1,386.8 1,532.8 13,436.0 2060 3,602.9 6,948.0 1,401.4 1,540.7 13,493.0 Black &Veatch D7 February 2010 APPENDIX E DETAILED RESULTS -SCENARIOS 1A /1B ALASKA RIRP STUDY APPENDIX E DETAILED RESULTS -SCENARIOS 1A/1B Black &Veatch E-1 February 2010 Plan 1A_18P50Summary Black &Veatch Confidential Scenario 1A/1B Plan -P50 Natural Gas Forecast Annual Capital Present Value ofReserveRenewableTotalO&M Costs Fixed Charges |Total Annual |Annual Costs |Cumulative Present!Year.Additions Retirements.Margin (%)Generation (%)__|Fuet Costs ($000)($000)C02 Costs ($000)|DSM Costs ($000)(3000)Costs ($000){$000)Value ($000)Beluga-f;Beluga-2;International-4;2011 Nilislg Wing,HECP.i 1-2 %11.92%$351.208 378,494 $1,102 $651.$12,326 $444,378 $444,376 $444 3782012FireIslandjota247.47%45.18%3.9;$86,269 $54,767 $1.49)$40,350 A217 7 51,0842013151GFA.$251%|14.98%$330,019 483.259 $37,514 $3,063.$73,555 $554,413 4842535 1,435,329 Beluga -3,Beluga -6/8;Beluga -7/3;2014 Glacier Fork.Bernice -2,Bernice -2 TS2%15.9496 $339,919 $90,226 363,386 $5,878 $108,169 $607,578 455,965 1.931.254 2015 |AnchorageNSW.$5.23%242%$342.65 $07,384 $82,082 10,455 134,358 $639 938 489 20 2.419.500201ay3382711.68 94:12.559 170,907.$724,717 $16.71 2.536.213201GVEAMSWBeluga-5.NPS 62.91%24.55%$357.899 369.41)$74,333 19,891 199,955 $733,532 458.81 3,425,030204EA1X1NPoleRewoftHPZ5430%4.63%$2 5 12.241 2177 $563,688 413.31 23834120147.95%4.62%$295,519 82,983 $87,105 12,657 21177!$690,338 401,78:240,1242021MountSpurrBeluga-6,WLP.8;43 22%:]4 1 |_$88.427 13,124 273,43 $779,954 424,24 664%202 143 6FA Beluga-7.35.994 460%$310,524 108,747 $93,910 $13.35 342,86 $867,638 441,089 105,4542022hloyntSpuryHeals-1 31,09%$297,025 126,402 393,170 $14,024 391,77,$525,399 432,648 545,10.2023 45,.06%38.33%$325.599 $123,469 $97,048 $4,166 3 3 $945,547 419.879 964 932202445,53%38.18%$340582_|$126,429 $09.07).$3,313 433745 $1,013,242 420,460 $365.44 2025__|¢Ghakachamns |GVEA Autora Purchase -Tier |55%82.32%$220,174 3133.656 $4 222 $693 340 $1,132,337.439,140.824,5812026Nuhuski9.13%62 52%$234,402 129 355 $28,153 $5.42 $693,340 $1,150,593,417,930 241,6112027FY$227,330 132.294 $695,689 7 392,382 33.93)2028 2.66%§.3.05 $230,300.433,279 3103.224 $53,323 $695,669 $1,177,615 372.666 9. 2029 137%.G1.63%$242,192 338.036 $118,165.$16,151 $595,689 $1210.233 358,064 $364,923 2030 Kena ttydro DPP-6.MIP7.MLP 8 Zenit,Zen2 |50.97%|1 |ss7.064 |$700,698 $1,153 000 316,014 8683737 2031 42.40%82.03%$192.346 $139,762 $120.88;14 954 $697,301 $1.165.243.RPA!24.85) 2032 41.35%S2.58%$191,723 142.929 $123.15:13,051 $577,251 $1,156,195 279,233 264,095203340,3246 63,83 £199,354 146,152 141,84 15.919 J $677,231 $5,189,522 266.459 330,554Y203461.50%$203.12 343,310 154.23.16,747 $677.2 5,200,669 S3277 783,831 2035 33.23%§1,85 C)132.770 165,334 16,444 $677.2!1,318,54 49,232 10,024.06203637.29%61.55%$207 66:$36,125 183,109.$5,433 $677 2:1223 64!26,560 10,250.622037GVEALMS109BPD43.27%64%7 162.824 37.019 $703.24 ¥290,05 22.141 10,472,764 2038 42.23"Oz 186.071 217,232 $6,453 $703.248 1,341,40:11.045 10,683,809 2039,41.22%$9.75%$230,127 470,053.235,833 $8348 $703,258 1,348,103 02.759 10,836,55320449.20 $243,640 173,619 $259,739 $12.284 $793,248 1,392,529 195,733 4 30!20:33.21%$0.34%$253,301 577,608 $275,956 318.825 $694,319 1,424,033 187,072 1,269,37720.GYEA 1x1 GFA NPCe 48.85 59.27%$276,559 a 309,508 21552 9 1.335.951 186,538 457,9120.47595 39,37 FY 173,713 335,505 22199 $723,148)1,543,512 A77104 635,0120446,559 39,21 $300,081 231,589 263,392 23.453 $690,57 1,609,095.172,551 807 57!20:45,51 6 $317,604 181,983 393.339 22.434 $667.38:1,544.446 8,792 456 36:20:Anchorage 1143000 45.40%38.33%.$337,809 189,592 429.301 22,961 $543 804 3,623,455 $2,059 118 422047|48.35%S1.9¥A $353.295.194,064 $464.661 24.452 $614.72 4,851,218 44,540 252.9520447.31%57.73%$370.07 483,719 $505,529 25.398 $507 93.1,702,617 39.289 12,402,250|204 203,794 $546,949 $5,909.$602.53 1,747,070 33,575 12535825 |2050 43,25.57.17%$405,470 299,359 $595.965 $8,724 $541,280 1,759,839 25.749 IZ 651,574 2051 44.20%57.05%$420.22)253,074 $518,838 $49,574 $475,850 1,733,156 15,741 12,777,315 2052 43.25%Fi 218,592 $522.66)$9.139 $22939 1721668 |107,452,834,767|2053 22%$6.11%$403,378 $223,819 Eyal $14.859 $419,346 u7eaiagTOyog3ss 298924|2054 41.28%55.98%$491.702 $229.397.392 22.889 $350,956 1.896.925|A 13,037,625 2055 55.65%$503,136 $235.076 717,342 vi 1 8.$4739 13,182,364 2056 74!30,33 $376,209 1,914.03:91.134 13,273,493 2057 GVEA LMS 100 Cooper Lake.47514 34.03%$535,511 290,156 787.839 33.289 436.531 2,073.32:92.260 13,725,758 2058 44.75%53.85%$515.490 234.038 $227.882 33.229 416,531 $2,149.17;$9,379 $ 2059 4371%S$.884_A547.395 26 1.068 $692.589_$31.302 416.531 $2.213.594 |85.244 541,978.2060 42.73%$2.02 $477,422 2 $502,559 $33,092 41,5;0,96 83217 624,595]Present Vaiue of Costs 4.547 973 750,430 41 921 235 149,474 255,484 Grand Total 624,595] 2/18/2010 Page 1 Black &Veatch Confidential Scenarlo 1A/1B Plan -P50 Natural Gas Forecast Ptan 1A_1B P50 Summary Annuat Natural Gas Usage (mmBtu) 33,720 34,553 31,457 30,004 16,267 10,081 10,303 10,646 10,638 10,465 5.914 7,982 7,325 7,524 7.679 7,708 oeeeeA@QOSOCEOHDEOCEOGCHAGCLCOFOCCOCOOCCEOOeAAO8EGAeSCeOoeaeeocoeco228 TerrrrrrerterittttereesAnchorage Interfor.Matanuska Kenal___Total Ralibeit 38.024 36,483 Mave 34.146 ASN 24,630 18,044 16.819 18,880 18,027 18.687 201872010 Page 2 Plan 1A_1B P50 Summary Scenario 1A/1B Plan -P50 Natural Gas Forecast Cash Flowper Generating Unit A i Generating UnitAnchorageGVEA1X1Anchorage1x1Chakachamna:Chakac =Kenal Anchor GVEA =Capital Cost CashYear__Nikiski Wind HCCP Flretsland Anchorage txt 6FA_Glacier Fork Msw GVEA MSW__NPole Retrofit Mount Spurr T GFA Mount Spurr hamna Hydro_GVEA LMS100 GVEA 1xf 6FA Lmsoco Lésico Flow ($000) 2014 30.468 99,609 175,454 210.604 127,935 Q 0 0 °°)0 0 o o °644.2702012932,925 118,563 40,740 290,2282013119,477 95,638 215,114 2014 06,719 9,000 95,719 2015 24,927 18,083 39,210201819,157 42,450 33,699 95,308201738,492 72,765 26,866 138,1232018170,818 76,085 43,273 290,1772019154,889 178.613 68,804 79,301 481,6072020161,957 161,539 238,340 564,8162021146,457 461,537 627,9942022652,793 852,7932023712,138 247 712,3852024141,426 253 141,680 2025 260 2602026256266202716,560 18,560202817,905,17,905202918,353 18,3532030 2031 2032 2033 2034 2.260 2.2602035206,133 206,133203631,138 31,1382037 20382039 127,792 127,7922040299.994 299,9942041272,020 272,0202042 20432044 27,078 27,0762045123,405 923,4052046 2047 2048 2049 2050 205 2052 20533054 3.703 3.7032055337,773 337,7732058$1,024 51,0242057 2058 2059 2060 an<-085] Black&Veatch Confidential 2HBr2030 Page 3 Black &Veatch Confidential Pian 1A_1B P50 Summary Scenario 1A/1B Plan -P50 Natural Gas Forecast Summary of Cash Flows and Production Costs Total Generating Total Transmission Fixed EnergyUnitCapitalCostProjectCapitalCostTotalCapitalCostDSMCostsFuelCostOaMVartableCO2CostsRequirements AfterYearCashFlow($000)Cash Flow ($000)Cash Flow ($000)($000)($000){$000)___O&M ($000)$000)OSM (GWh) 201 844,270 70.848 724,198 os 351,806 43,705 34,600 9.102 S3722012290.228 3.365 293,503 1,491 350,207 46,397 37,999 64,767 $422013205,104 61,272 266,387 3.063 320,018 $2,199 36,086 07,614 $424 2014 85,719 228,408 324,128 6,678 338,018 53,317 36,008 03,300 $42) 2018 39,210 '314,097 399,307 10,458 340,650 30.087 62,082 8,16?2016 95,308 129,804 225,419 12,739 382,711 40,617 68.849 6.1472017138,123 8.812 146,935 11,691 357,860 40,354 74,393 S1202018280,177 97,549 387,726 12.241 276.253 35.68 80,965 6,1052019481,607 214,870 690,177 12,657 205.815 38,386 97,406 $0082020$61,816 168,433 728.249 13,124 302.861 9746 80,427 $0682021827,994 73.715 701,700 13,348 310,624 93,010 6.0822022652.793 195,732 840,525 14,024 207,025 90,170 8,0812023712,385 205,995 918,380 4,186 326,600 7 07,049 it2024141,680 23,643 165,923 3,353 340,682 42,770 100.073 $140 2025 260 10.784 11,034 4,222 220,174 92,383 75.046 S174202626619,269 11,655 5,42 294,402 29,928 40,150 8,207202718,560 18,560 8,554 227,390 22.017 4,62 S24t202817,905 17,605 13,323 230,300 .22.017 103,224 $278202818,353 18,353 16,151 242,102 |194.041 23.496 6,308200o17,064 185.038 |414.068 23,286 140.881 $3442021°14,951 192,346 |147,757 22.008 120,883 sare2032015,081 191,723 |120,236 22,756 120,151 $432033615,016 100,354 |122,661 23.490 141,847 $44720%2.260 2,260 16,747 203,927 |128.061 24,200 154.233 4822035206,133 206,133 16,115 206.017)127.634 25,136 188.304 85720363,138 94,938 5.493 207,662)130,350 25,766 183,108 $3892037o7,018 217,083]136.144 26,490 200,100 $988203866,453 218,402 |138.807 27 264 217.2392 $82)2039 127,702 127,792 8.048 230,927 |141.681 28,402 235,033 $6392040299,994 290,094 12,284 243,640 |144,478 20,143 250,739 3.6082041272,020 272,020 18,825 293,301]147,408 30,200 270.086 Sat2042o21.952 276,850}140,448 20,202 209,su8 S7672043022.190 288.608 |143,61)30,200 335,808 $803204427,078 27,076 23,488 300,081 |200,404 31,148 303,392 Bey2045123,405 123,405 22,134 317,604]149.001 31,001 WS.H9 3are2048022,961 397,608]166,421 33,170 429.01 S8122047o24.452 353,295 |159.669 M198 404,681 $9492048025,308 370.037 |163.510 35,210 605,520 $086204906,008 386,466 |107,227 907 646.049 6.02)2050 0 8724 405,470 |170,958 Wait 608.088 6.0602051Qo11,474 . 4 38,482 616,838 6.008205200,139 30,965 632.661 6.1382053014,689 41,204 617320543,703 3.703 22,880 42.648 ean205597,773 337,773 27,849 44,020 6.209205651,024 51,024 90,133 43.200 2872057o33.286 ar 247 69262058o33,226 48,934 6.3642059°34,300 E 60.651 6,4032060-_°32,092 §77.420 |215.317 62.022 6.442Total6.524.085 4,815,317 {Total of Cash Flows q 9.086.710 2418/2010 Page 6 Black &Veatch Confidential Plan 1A_18 P50 Summary Scenario 1A/1B Plan -P50 Natural Gas F ts C lative Capacity and Energy by Resource Typsa Natural Gas Coal Nuctear Fuel Off Purchase Power Hydro Municipal Solid Waste Wind Ocean Tidal Capacity Energy Capacity Energy Capacity Energy Capacity Energy Capacity Energy Capacity Energy Capacity Energy Capacity Energy Capacity Energy Capacity EnergyYear___(MW){Gwh){MW)(Gwn)iM'[GWh,(Mw)Gwh]M [GWh)(MW {GWh}(Mw){GWh)imwy (awh)(mW)(Gwh)(avy,{GWh) 2011 1,104 3542 a0 435 251 $80 25 210 176 591 5 49 2012 4.258 3.425 cy 493 251 501 25 215 176 593 69 220131.195 3,499 80 558 351 384 25 213 176 591 69 228 2014 1176 3,354 i)630 251 380 3 213 254 oo 69 227 2015 1,178 2.432 80 618 254 619 25 212 251 919 22 163 69 2272016822248a062525170325213251921221636922820176222.308 60 el yi 5)692 25 212 251 gig 2 168 69 22720188212441#0 $54 189 504 25 212 251 919 28 195 69 227 2019 821 2.443 0 $63 189 563 25 212 255 919 2 193 69 22620201,103 2,567 20 587 25 2u 254 921 50 403 26 192 £9 228 2021 907 2.595 80 $80 25 208 251 a9 50 402 28 190 69 227 2022 625 2.250 80 $43 25 204 251 19 100 800 26 166 63 22720237432,450 80 4 25 205 251 e190 100 902 26 187 69 2272024743245253ma252062519211008032618869227 2028 743 1.285 ES]278 28 174 sat 2.528 100 651 28 107 69 228 2026 743 1,448 53 292 581 2.519 100 680 26 119 69 22720277011441532855012.518 100 708 26 140 69 227 2028 701 1,456 EX]282 sat 2,525 100 rk)26 132 69 227 2028 701 1,537 59 282 5a 2517 100 88 28 136 69 22720307011,387 sy 323 586 2:37 100 797 2 154 69 22820315311.507 33 325 588 2,538 100 719 28 139 69 22820324871,478 33 327 536 2.544 100 765 268 182 69 228 2033 437 1540 Es]327 586 2.537 100 746 26 147 69 22720344871,872 Eh)330 $88 2,538 100 739 26 153 69 227 2035 467 1,568 E+y 328 586 2,538 100 783 2 At 69 22720385621.508 $3 ™O 588 2,544 100 768 28 163 6 22720375641676$3 nT 5868 2.537 109 752 26 153 69 2272036$32 1676 33 nN?586 2.537 100 783 28 162 69 227 2039 532 1,700 53 320 586 2,537 100 808 26 147 69 22720405321,740 83 323 588 2544 100 mr 2 164 69 23120416931,743 33 324 $668 2,537 100 a3 28 161 69 226 2042 693 1.651 3)303 $86 2,537 100 164 26 165 69 22720436301,859 5]305 508 2.537 100 787 26 169 69 22720446301,880 83 308 586 2.544 100 792 28 168 69 22820456304,935 83 297 586 2537 100 789 28 71 69 22720486781,996 3 278 $86 2,537 100 780 28 174 69 227 2047 ore 2.039 53 277 586 2,537 100 765 26 168 69 22620486782.069 53 275 586 2,544 100 781 28 170 69 228 2049 e74 2,100 3 2n $88 2,537 100 12 2 158 69 227205067a2.149 83 264 586 2.537 100 793 26 172 69 22720516732,172 53 265 $86 2.537 100 792 26 187 69 227 2052 678 2.208 $3 284 588 2.544 100 as 26 162 69 227 2053 678 2.259 83 273 586 2,537 100 786 26 175 69 22720546782.261 sy 278 506 2,537 100 798 26 176 eo 227 2055 678 2319 83 278 $66 2537 100 798 28 75 63 22720566782MaES)283 586 2844 100 74 24 197 69 228 2057 775 2.441 3 248 se68 2,537 100 813 26 148 69 227 2058 775 2522 83 an 567 2,498 100 783 26 172 69 22620597752577s32525672,496 400 623 26 154 69 2272060Us2.523 HY 282.S81 109 13 28 150 63.228 271872010 Page7 APPENDIX F DETAILED RESULTS -SCENARIO 2A ALASKA RIRP STUDY APPENDIX F DETAILED RESULTS SCENARIO 2A © Black &Veatch F-4 February 2010 Ptan 2A PSO Summary Scenario 2A Plan -P50 Natural Gas Forecast Renewable Present Value CumulativeReserve|Generation Fuet Costs Total O&M CO2 Costs |DSM Costs]Fixed Charges |Total Annual]of Annual Present ValueYearAdditionsRetirements.Margin (%)1 (4b {$G00}Costs ($000)($000)$00)48000)Costs ($000)|Costs ($000)($000)Beluga1;Beluga -2.Intemational-1;2011 Nekislo Wing,HECP f 'oA |__4192%|$351.604 |$7524 J $1,108 654 $12:326 $444,208 444 $444 2082012.Fue Island js atonal -3 47 AT%45.18%$350,422 $85,221 $51843 $1494 $49350 $543,330 507,785 $51,933201344.38%14.93%$353,525 $95,731 $50,377 $3,053 $40,350 $553 045,483,95 LA35,.044Belugs-3,Beluga -6/8,Beluga -7/5;.2014 Glacier Fork,Anchorage MSW Bemice -2,Bernice-3 56.45%18.90%.$349.08},$86,281 $66,100 $5,876 $28,695 $596 037 486 543 1,921,5872015,1x1 GFA F223 24.72%$254 257 351.434|$62.615 $10,455 $132,747 $647,538 4S4 004 2415591 2016 E221 |24.60%|_$380510 |$99.445 |_§69555 |siz7so |ss72296 |s7agses |$23.022 |2938612| 2017 Kenai Wing Betugs -5,NPL SQ4Z%E14 $972,476 $92,329 $74,394 4.831 $216,010 $767,700.S11 55t 3,450,163, 2018 GVEA1X1NPole Retrofit NPQ $3.61%aI 332.241 $227,803 $581 525 424419 3.074 S832019Prayee289%$295 432 $39,310 $87,223 S12.657 7,80.$710,424 413,506 228 0892020MountSpurrBeluga-6:MLP5:MLP 5/6,MLP 7/6 45.73%HA1E%$304,731 $105,371 $23,752 $13,124 $239,455 $801,433 435,927 4724 016 202 ix)GFA Gehna-7 55.49%|32.84%s312537_|sioeess|so4579 $13.346 $350 835 $899.33 452 $76.10 2022 Mont Sout Healy -1 39.74%3,1 $96,528 $14,024 407,79;$945,400 449,153 $625,269202345.37%39.54%$327,794 $126,766 $97,214 $4,165 $491,399 $257,329 423506 6,054,766 2024 45.20%|__30.59%$343.34]_|$120.39|$109.253 1}$3.319 $449,779 $1,035 816 423.827 6484593 Anchorage 2x1 6FA;Anchorage LM6000!2025 Chakachamng Gi GVEA AgoraPurchgsg-Tit |41.74%42 64%$493,914 199.674 $4222 793.649 1,640 635.373 '2026,Luhighg BER Ag 3ih 29.070 179.677 183.279 $5,342 63!1,591,014 $12 902 T3353202735,49%42.59%$520,677 197,039 $9551 193.937 1,705,032.|877.55)311,4212028HE42%$533.295.187,338 219,018 $13,323 795,997 1,745.97,$53,639 65,1202934.21%41,95%$539,559 _}$190 662.24 316,151 795 937 1,783 67:527,726 392,8272030GVEA241GFA,GVEA Wind PPP -6 NLP 7;MLP Ss Zent:Zend 43.53%|$509,933.198.465 245.17.054|$916,939 1,639 839 52259 915,3832031,3.40'201.504 270.945 14.954 15,59;1.326 0546 437,739.413.123203243.61%534,763 205.834 291,795.$5,08¢|$695.54:1,950,075.458 554 £81 676203343.19%210.376 316.985 35,919 835 54:1,980,479 447,03.23 655,2034 4276 EE 214 842 343 029 16,747 895 54 2 021,323.495,332 55.0772035,43.93 $555 S34 219.480 368.059 16314 B99 54.2.057.407 [405615 £063920363.35%85%$550,665.224.259 |$402 574 $5,493 BF.533 5-4 54 B19 545.5002037GVEALMS10)NLP 3 40.23%92 $545,121 221,752.422.523 37.019 $904 1142.954 064 Ea2038,FD 58%43.47%547 828 236,66)454 017 $5,453 $904 149,783 $5,995.255 $3203933.54%43.26%$570,844 241,786.4:$8,843 $904.2,217.08.133454 258,984 Anchorage 2xf 6FA:GVEA 1x1 GFA;204 GVEA 2u]GFA,A3 74%2)RAI 278.383 |$819,820 $2,284 1,190,019 256 208,457 702 14046 65620431.09%$955,052 293.245.$676 847 18.825 $1,141,081 346.04 439569 4456 24204GVEAWingLece39.49%|20%$936,004 231,841 $929.314 ss2_[$4 222216 443.92.423.558 903.604|204 22.23%1034.87)235,390 1,005,832 2.359 $1222.21 73,42)4 18 319,82:204 53%32.05%1,075,353 491879 1.092 555 458]$3973.87 'S711 402.893 7227120431.99%1,109,371 220.374 1.161.219 134.529,81 22,91 373,108 095 82.204 GYEA Wing 33.53 1.151.293J$316 6.43 1.258.017 22.951.3.4.44,47 3.893591 264,685 460509|204 2 33.00%1,199,168 323.205 4,347,332 24452 VANZ471 4.002.728 350.33 $10.29)_J204G3.07 1.239.185 221.199 1.461 $49 3398 4,105 678 _|403 340.03,151,493|204 36.15:3.27 1.269.655 338000 "T 1.ssoso4 {$5909 94,105,679 ey]327.223 478,72220505285%1.313.929 315,174 1673485||$396,132 454 309.93;CT20542.5 |Ye 1.350.215,352585 1 23)$11,474 2.70 cE 020 99420522.77%1.411.933 361.3 A773,167 3!4.435 37:27561 357,41020532.61%1.448,204 39777 1,813,619.44,88:374,199 4519.6!362 8 621,037.2054 49%493,727 277.87!198.893 22.539,535,017 4 603.9)£097.16.272008206832%2.40%1544239 326.27 1.912.02,2LS49 1AI53 46378:HOT 19.103 05 |2056 285%239%4 ie 32,1.974,74,a2 3:475 1,4 26.232057HEALISS100CcocsLeke131.654 50g 407,185.2,040,275 32.289 93.604 4.931 19,ASST2058041.721.950 415 114 3 95.604|$5.08)1 19765086|2069 125!$775,748.423.170 £85 31,309 EOS $5,197 9)19,967,1332060HEALAtGO001.66%1876 300 437 664 20 E56 32,032 34 S60 5 37137 195 11 20,162 223 Present Value of Costs 7,215,425 198,157 3,949,357 49.474 649,800 =Grand Total 22,382,223 Black &Veatch Confidential 2A a2010 Black &Veatch Confidential Plan 2A PSO Summary Scenario 2A Plan -P50 Natura!Gas Forecast Annual Natural Gas Usage (mmBtu) Year Anchorage Interior Matanuska __Kenat__Total Rallben 2011 31725 o @ 4H?38.073201231,564 0 Oo 8.343 6.907201331,008 0 Oo $402 waz 2014 20,719 o Oo 4652 34.370 2016 22,335 o O 263 nee 2016 21.242 ty @ 2901 M19 2017 22.338 °QO 163 72.970 2018 19,208 0.383 oO «rat 20201919,347 0.632 Qo 1740 29.625202015,697 0.368 Oo 4731 wie 2021 16,408 7538 1819 was 2022 14.499 7.039 @ 143 F2.9F0202318.391 am Oo 1,464 24.686 2024 19.768 7.48 Q@ 15139 am 2025 27,374 7.039 oO 1,942 38.755202628,989 7.671 90 wor 37.8662027'29.128 7.698 oO 0 wer202829.273 7,720 0 ]36.992202829.637 Tat o i)37491203021.658 14.225 °o 301203125.208 10,532 °°4203226.811 10,899 o 0 3510203326.214 10,719 e ]4934203426.659 10,665 °o wae203526.479 10,796 o Q 7.275203626.898 10,928 0 o 37.824203722,328 15,185 o C)37.610203822,254 15,408 o o 37.660203922,848 19,324 -0 °wae 2040 38.623 24,998 o i]6212041'36.747 24,267 ty 6 60014204238.457 24,128 i)o $9,535204336.422 24,438 9 o $9,860204435.569 24,571 a °60,140204535.440 24,094 °°mon204636.415 23,834 0 °60,249204736,424 24,167 @ Qo 0,20820486.458 24,321 i)6 warns204936.065 24,284 o °osn2050W13424,399 °°60.935205136.2786 24,487 °o 60,Te4205236,860 24.320 o o 61,170206336.228 24,613 Qo °wat'2054 36,437 24.627 0 °61,004'2055 36.287 24,797 0 o $1,053205636.722 24,654 0 LJ 61.3762057YS24SOo179761.661205835.362 24558 QO 2472 eH?2059 4.939 25,059 0 240 824206033.668 24,847 Oo Sas 64120 28/2010 Page 2 Plan 2A PSO Summary =:Scenario 2A Plan -P50 Natural Gas Forecast a Cash Flow per Generating Unit Addition GVEA 1X1 , GVEA *GeneratingAnchorageAnchorage1x1KenaiWindT NPole Anchorage tx1 a Wind T GVEA Anchorage 2x1 GVEA 1x1 GVEA 2xi GVEA GVEA HEA HEA Unit Cash FlowYear__Nikisid Wing HCCP Firelstand__Glacler Fort MSW SEA Lines Retrofit Mount Spurr T SFA Mount Spurr SFA LMé000 kachamna GVEA 2x16FA Lines LMS100 SFA SEA SFA Wind Wind LMS100 LMso00 $900) 211 30.468 99,809 175,454 127,935 39,746 °o 9 o i)o a o o o o 0 (]o a 473.4932012118,563 93,305 65,608 275,4762013119,477 84,604 154.017 358,008 2014 139,655 139,655,2015 ADST?18.083 31.660 2016 125,247 42.450 33,659 201.296 2017 38,492 72.765 26.868 138.1232018170,818 76.085 43.273 290,17729154,889 178.613 68,804 .79.01 481,6072020161,957]161.519 239,340 $61,816 021 148,457 481,537 627.994 2022 197,360 652,793 850,1832023393,456 16,120 712,133 1,121,756 2024 130,159 T3414 141,426 345,059 2025 20262027 223,295 23252028445,161 32,772 477,9332029147,263 |302,323 449,5882030 2031 2032 20332034 .2260 22602035206,133 206,13320363413831,1382037285,636]121,634 285,835 693,306203869,844]285.539 $69 844 1,425,2272039988,510]258,912 188,510 635,931 41,925 41,9252041986,759 326,7592042 20432044 46,778 46.2782045426,910 426,910 2046 247 2048 2043 2050 2051 (2062 pon :3.703 3.70320587,773 337,7732056$1,024 $1,024 aos 33.257 38.2572069174,368 174,368 2060 Tei)Total Black &Veatch Confidential 2ne2010 Page3 Black &Veatch Confidential Pian 2A PSO Summary Scenario 2A Plan -P50 Natural Gas Forecast 'y_of Cash Flows and P;Costs Total Total Generating Transmission Fixed EnergyUnitCashFlowProjectCashTetalCashDSMCostsFuelCostO&M ble =CO2Cests RequirementsYear{so00)Flow ($000)__Flow ($000){000}(sooo){$000}_©&M ($000)_{$000)__After OSM {GWh) 2011 473,13 76,548 683,240 t 1b]43,786 HIM 4,100 63722012276,476 3,366 278,041 4,401 360,422]49,297 97,688 Gaeta 84122013358,008 61.272 409,370 3,089 903.625)48328 wa ea S434 2014 139,655 228,400 348,061 349,083]40484 wan 4,100 Gan201531,660 314,007 345,757 4.267)48,327 30,1aF 02618 61ar 2016 261,396 129,404 331,201 30.010)|40.775 «670 19.005 O147 2017 oei2 146,995 49,005]O72.47H)49,089 aan Paste 6.129 2018 07,649 387,726 42.341 RPO 385)|47.413 3.682 @0.031 8.1082019214,870 46177 12,667 206.482)48 $06 ar 87.228 6.0882020106,433 728,249 $9.024)WOL7I1]04.626 ah)84.762 Boxe 202%627,004 TLS 701,709 $3,348 392,037]64,380 41,800 aan $062 2022 650,153 195,732 1,046,665 14,024 TO7.044/6.608 42,080 oa.638 8.08120231921,716 26,995 V.927,711 456)Tea)ata 44 Oras Bt 2024 345,009 23,643 368,702 an HUM)83,680 4.401 109,283 S140 2025 10,784 10,764 422 493.014)136.000 §6.cat 188,584202691,209 41,280 6.éM2 820.070]138,121 ANOS 183.2792027223,295 223,295 0.5651 820,677]140,707 42,062 197,0362028477,933 477,933 13,323 33.205]143,240 4,068 219,0182029449,588 449,688 18,161 630,669]146.007 AL 122030617,064 $00,936)1874823 45,642 2453852031014,081 623,401]188.090 16,405 270.6432032°16,081 631,763)150,176 ati 291,7062033°15.919 841,607]161,218 49,188 396.98520342.260 2.280 16.747 GS4169]164.248 80.89 343,0232035(208,133 206,133 *10,411 656.684)167.467 82.013 44,669203831,136 34138 6,493 60.608]170.651 83,418 402,6742097693,306 699,7,018 640121)177,317 8446 422,62320381.425,227 1,426,227 6453 $47,626]180,675 05,05 454,0172039636,931 635,031 oon 670,644)184,232 87.66 400,784 2040 41,925 41,026 12.284 955,710]202018 76,368 819,8202041386,769 306,759 18.628 066.042)208,701 TT S44 876,6472042021,852 995,004]195.860 86,261 229,3142043o22,199{1,034,873)199.434 88.489]1,005,632204446.278 46.278 23.458]1,076,985]310.643 $1,236]9,082,5662045426,910 426910 22,134]1,109,371]207,643 02.031]3.161.2192046oO22,981!1,151,293]211.768 106,075]1,288,0172047a24,452]1,190,168]216,064 SO7,221)1,347,9322048o25300]1.290,185)220.612 410,5at 1,461.9204906909]1.260.655)226,244 112,636]1,650,5942060o€724]1,353,029]220.911 198,263]1,673,4852051Q41,9741 1,360.215]234,621 118,065]1,720.9332062Q8.190]1,411,833)239,468 121,688)«1.775.1672053o14.889)1,448,204;244515 124,261 1,813.6920643,703 3,703 22,880)1,499,727}249.622 128,054]1,868,8032055337,773 937,773 27.849 1,544,239]256.048 131,223]1,919,0222056$1,024 $1,024 0.133 1,697,860]260,323 136.000]1,971,7422057]33.288]1,654,506}269,102 138,083)2.040.275205836.257 38.257 33.228]1,721,950]273,035 142,003]2.114.2552069174,368 174,368 31.09]1,775,743)276.917 14,451]2.170.8862060032092]1.876200]288.084 149.500]2.290.856Totalt1.548,152 1.815,317 [Total of Cash 14.110,777 2ie2010 Back &Veatch Confidential Plan 2A PSO Summary 'Scenario 2A Plan -P50 Natural Gas Forecast:Cumulative Capacity and Energy by Resource Type Natural Gaz Coal Nuclear Fuel Of Purchase Power Hydro Geothermal Municipal Solid Waste 'Wind Ocean Tidal Capacity Energy Capacty Energy Capacity Energy Capacity Energy Capacity Energy Capacty Energy Capacity Energy Capacity Energy Capacty Energy Capacity Energy 2011 1,104 aus x”as 2 376 P=]210 176 501 1S "420121,104 3.427 a a3 21 502 a 215 176 593 69 za20131,041 3,378 a ES)a1 4H a 24 176 Sat 69 26 2014 1176 3.45 rg on a 423 a 214 1 Gag 2 163 69 zz215.176 2433 eo 619 a1 oo a 212 b-)]og 2 163 689 2 2016 822 2329 0 25 at Ta P=)214 y-3)921 22 163 6 228 2017 22 2.299 6 616 a1 656 Bs 212 a 919 2 158 E 326 2018 B21 23at Ls)2 189 1B a 213 y=]919 2 166 9 32620198212.401 a S76 189 57a a 213 251 919 2 163 so 3520201,103 2.588 a 597 P=)210 P-))921 SO 403 22 163 =)327 2021 907 2583 a 8 Ba 209 251 919 so 401 2 161 b:)326 2022 625 2241 a c=]a Pit]251 919 100 738 22 156 99 32620237432450a372a206a1sto1007997415899326 2024 1,100 24az 3 2 r]207 251 921 100 812 2 159 38 326 2026 1.01 4281 8 xs)3 212 $61 2.517 100 802 22 160 99 32820261,101 4516 53 wo sat 2517 100 790 2 2 ]32620271.059 4539 3 M4 581 2517 100 a6 a 161 »32620281.059 4562 3 MS sa 2.524 100 B06 2 169 Bo 33820291,384 4624 a Mo $61 2517 100 603 2 14 we 32620301,384 asin Ex]26 S81 2517 100 Te 2 157 149 48920311214asi8235set25171007347416114948320321,150 4509 EX]21 S8t 2824 100 12 22 172 149 gt20331,199 46H 3 Peo)”$84 2517 100 902 22 16 149 49120341,150 4704 8 206 Sat 2517 100 785 22 180 149 43020351,150 4697 s 4 sat 2517 100 816 74 162 149 45020361,245 4,738 83 268 Ser 2524 100 613 22 182 149 49020371.247 4812 3 28 Sat 2517 100 787 22 175,149 49120381,215 4.639 3 Fo]sat 2517 100 ars 22 160 149 43120392014870s26Sat25171003072160143431 2040 2011 8.001 3 272 Sa 2.524 100 805 2 163 143 49320412.011 7943 3 276 681 2517 100 600 2 162 149 49920422.011 77a 53 276 sat 2517 100 805 22 163 199 65320431,848 7,764 3 283 $at 2517 100 a3 22 163 199 6S204414,948 7.803 sa 276 Sat 2524 100 804 z2 182 199.56204519481778syasat2517100ri)22 158 199 6552046TB7,698 s 282 $81 2517 100 827 22 WwW 249 820204719487,706 3 276 sa 2517 yoo a02 22 147 349 81720481,944 7.761 8 za 561 2,524 100 804 22 163 249 e2220494,948 7,724 LX)a9 Sst 2517 100 a28 22 174 29 20206019487,744 s a Sat 2517 100 802 22 162 ri]82020511,948 7.767 $3 251 Sat 2617 100 731 22 151 249 82020521,548 7.822 Lx)248 set 2524 100 a a2 163 243.62120831,948 7,765 3 Pos)sat 2517 100 ou 22 168 249 Bi720641,948 7,730 83 261 581 2517 100 604 22 162 249 82020551.948 7789 83 24 sat 2,517 100 738 2 169 249 B2020561948T0Al3280Sat2524109iz2216224982120672.048 7,748 s 260 Sat 2507 100 734 22 162 249 82020582087,02 3 2e3 562 2478 100 au 2 167 249 8720692.093 7.761 s 20 $62 2.476 100 758 2 148 249 872060]2.093 2725 53 304 562 2.492]{90 205 22.363 243 821 2A8/2010 APPENDIX G DETAILED RESULTS -SCENARIO 2B ALASKA RIRP STUDY APPENDIX G DETAILED RESULTS -SCENARIO 2B Black &Veatch G-1 February 2010 Black &Veaich Confidential Plan 28 PSO Summary Scenario 2B Plan -P50 Natural Gas Forecast Present ValueReserve|Renewable |FuelCosts |TotalOZM |CO2Cosis |OSM Costs [Annual Capital Fixed Total Annual}of Annual [Cumulative PresendYearAdditionsRetirementsMargin(h)|Generation (%(3000)Costs ($000){$000}(8000)Gharges ($000)_|Costs ($000)|Costs ($000)|Value ($000)Sehiga-1,Baliga-2;Intemational-1201didass1Wand,HEGP ri S502%J 192%5954499)$78 St $9 S6St a $442,967|_$442087__$442.9872012Fire(sang 3 42.47%15.16%$350.910 354.959 $1491 $10.350 $553.041 508 262 953,239201344,14.98%$373571 $96,176 $59 959.$3,063 $49,359 $564,169 437,716 1,343,963Beluga-3;Beluga-6/8,Beluga-782014GlacierFork,Anchorage MSW.Bernice -2,Bernice -3 2,$5878 $28,695 $603,197 492.3469 936 35; 2015 A tat GFA 55.22 472%355 88t 47,506.$62659 10.458 $132747 649 288 455,339 431,69120$2.21 50%321,713 9,45 59.67!12.759 $172.296 735,900 [524.686 A377[20 Kenai Wind Bohiga -5,NPI $0.52 14%397.238 $92:343 $73,635 W691 $216.01 753,117 £00.50 456 87820GVEA1X1MPcteReticel1P2$3.9 26.11%275,319 05 1224 22 581408 4.358 $31,2352041425.89%296,301 $96,307 $87,426 42,65.227,$0.710,49.28!2347502020SpurrBehgs-G LPS MUP Se MP7 |45,7,15%313,055)3104598 585 13,12 289.455 808.8.9.93 7346392021tutGFABeluga-7 49%34%319.829 107,286 T $35.077 133:358,636 494 4:467 1893782022MourdSpatHeaby>t 50.51%39.73%303,445 126,760 £95 14024 $497,797 $5387 E073.640,109 2023 45.37%29.57%338,009 123,56]$101,620 $4,156 411,390 $978,146 435.39 074.418202443.20%33.43 354,559 125.350 Z $3313 449,770 $1,044,742 433,535 507,949ChakachamnaChakachamna;GVEA2028owbe GVEA Aurore Purchase -Thest |59.97%65 83%3:$177,358 $109,663 $4222 $1,387.37 005 906 177 925 205 8742026,Nikisky $4.19%70%355.930 $168 28:129,654 $5342 337,036 €25 4179)G27 6642027$356%|65 52%354 563 $171 85 141,938 A554 383,72¢065,869 93,77 727,4432028$2.92%41%362 315 $175.66:196,239 $53,323 389.731 937 265 3.98 391,3892029)S211%65.12%379.599|$179.71 173.199 $16,151 352 129.98)630,185 10.021 5442030GVEAVindQPP-6,MUP 7,MLP 8:Zent,Zend 93%%324.024 $188.512 170,425 17,064 $5,426.24 154 10 609.72020315566.21%287,389 $165,763 [$157,924 14.95 4,42 2078 872_|537,220 594203293%[66.42%251.077 190,378 181,409 o 9,492.79.2.089.731 2 49 465:2033,»56.03%234.120 194 462 195.275.15.91 1,492 72.2.102 569.47457 2404)2034 31.63%|56 200,568,198,861 213.089 16,74 1,492,764 2.192.079 449,754 73,794203531.08%[65.94%1$203,534 228.679 18.4 1.492.794 $2,157,041 435 353 $99.08203630.47 65.43%204372 201945.235.012 493 1,492,794 $2.199516 T399.732)338,7792037age221analMUP2493$221,779 $204.17 37.019 $1.512696|25 405,916 1},905,69420384995%£492%$335.376 $226,742 |$306,679 $5,453 $1,512,698 $2.325.139 334.324 1419909203943.25%$4,45%$395.21 mn 3335718 |$1,912 593 $2449.16 251649 14557.685|Anchorage 2x1 GFA,Kane Wind,GVEAT204DELSEA 42.24%49.31%S720.1.757.343 4 122 1$.037,787__|204 41.75%49 68%$749.30 795.228 $18,025 1.749.414 3.453,729 455.303 15,433,090]20.GVEA Vénd NPCS 39.00%1 50.21%£75458.150.709 $21,952 1,789,549 2592529 431 68 15.937,1204752%50.65%33 4.064 22.199 1.769.549 2.673924 431,550 18.355,72047.04%|50.66%$915.7 970,109 23.458 1,741.20.2.729 652 334.948 16159653|204 57%4 4452.178 $297701 22.134 1659.22:2.760.851 PIE910 17,335.56204GVEALM500945%0.01%1.920.949 22.931 1,633.6.3.949.823 32.365 17,497,9302047.1.096.449 4452 1812.63 $3.954351 345.148 17,844.075{204 351%49.97%$957,221 1.185.769 25.399 1,609 64:$4.079,038 222.701 19.477,77720427.01%|273 $90 832 4.194.007 20,661 499,4972050,455%471%$1,024.43 1.376.933 24.502.675 4237,023 278 801.19.2051 ¥.00%49.82%LOGI 1.418.126 1 $t1t74 433.244 253.649 84,06 985.25:2052 25.41%49.47%1.108,19:1464 B12 9.139 394.333 4 304.318 g68,63 353 83.2053 35.14%42.47%.RELEN 1.496.925 14.059 380.749 4.37.|255.15.609.04205434.56%49.25%.17197 1.515.999 22 839 1,342,360 4.445.327 42.32 19.6512055319%49.25%1,223.02 1.593.720 27,943 1.329.430 4538,657 34 239 20.08220563.22%49:23 1.252.068 1.690.623 30.132 1.323.430 4.695.516 3 0.303,2057 |AnchorezeUMS109 Coopys Lake 9%40.4 1.372.441 4 12.288 1.343.633 4.786.652 999 20.518,32:2058 rt 40.5)1972S 1,795,190 32.224 1343.53 4.960.497 |206.295 20.722.6192059)2.04%48.51%41.430714 54 1 $3139 1.343.623 pe |e ie2060557%48.39%7 $32 052 425 108.923 Present Value of Costs LT 8024,435 2,107,805 149,474 Grand Total 21,108,523 t 2na2010 Black &Veatch Confidential Plan 28 PSO Summary Scenarlo ZB Plan -P50 Natural Gas Forecast Annual Natural Gas Usage (mmBtu) Snterior Matanuska __KenalYear 2011 2012 2013 2004 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2028 2030 2H 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2048 2047 2048 2049 2050 2051 2082 2053 2084 2055 '2056 2057 2058 2059 2060 1.623 B60COCCECDOGDOGCDGoEeEDDOeeSCoo2zjaecaeceeccaccanoceccoooeCreeree2)Total Ralibelt 2/18/2010 Page 2 Scenario 26 Plan -P50 Natural Gas Forecast Pian 2B PSO Summary Cash Flow per Generating Unit Addition GVEA 1X1 GVEA GeneratingAnchorageAnchorage1x1KenalWindT=NPole rage tx Chakachamna:Ch Wind T Low Watana (Nor 2x1 Kenai Anchorage GVEA2x}«GVEA GVEA Anchorage Unit Cash FlowYear_NikiskiWind _HCCP Glacier Fork SFA Lines Retrofit __Mount Spurr T SFA Mount Sj akachamna Lines Expandable)GVEA Wind SFA Wind 2x16FA__KenaiWind SFA.Wind Lasooe LMs100 {$000)eS peceror mount Spurr _-skachamna__Lines_--y -r 2011 0,468 99,809 175.454 127,035 39.748 9 0 0 °o o 48,624 oe o 9 Q °522.0362012116.563 93.305 65,608 32,371 307,8472013119,477 4604 154.017 30.291 348,3292014139.655 44,028 180,68020151357716,003 43,102 74,7612016125,247 42,450 33.699 $03,963 705,359201734,492 72.785 26.888 520,478 47,5992018170.618 76,088 43.273 711,876 1,002,0552019184,689 176,613 ;79,301 840,242 1,321,6492020161,957 161.519 338.340 882.779 1,444,5962021148,457 481,537 721,764 1,349,7752022652,793 758,321 14111142023712,130 |28.968 P0671 1,537,8152024141,426 |267.219 39.033 447,6702025 2026 2027 2028 31,974 31,1742028287,577 287,5772030 2031 2032 20332034 288.427 265,4272035$29,157]22233 $51.3307036175,060 |205,103 380,1532037285.806 288 830 S71.8722038$69,644 23.943 569,044 1,163.631203916510]220.874 188.510 597.803204041.925 419252041366,759 308,7592042 20432084 27076 27,0762045$23,405 123,4052046 2047 2048 2049 2050 2051 '2052 boo 3,703 3.7032058337,773 .ne 51,024 $1,0242057 2058 2059 -Teezocey Black &Veatch Confidential 28/2010 Black &Veatch Confidentlal Plan 2B PSO Summary Scenario 2B Plan -P50 Natural Gas Forecast Summary of Cash Flows and Production Costs Total Totat Generating Unit Transmission Fixed EnergyCashFlowProjectCashFlowDSMCostsFuelCost=O8M =Variable «=CO?Costs «RequirementsYear(000)$000)Totat Cash Flow ($600)($000){s000){8000)__O&M {$000)(8000)After DSM (GWh} 2011 22.038 eens ast 341,403 42.76 $4722012311,212 1.491 woe 46,3972013439,001 308)373.671 ale 2014 400.08 S078 335.4552015346.500 10,4852016098,164 92,7662017eraan11,60120181.0699,004 Wat20194,636,418 12,00720201,611,020 12,12420214.423,480 we20229,009,041 aout2023PAAR3|410202488PRE)110,768 2025,10,784 10,764 4222 108,686202614,280 W289 $322 120.004202709ate202831,176 0 HA a720292Br677aaerer?with 2030 Vl)Ly 1,0642071oQ14812032LJL]15,0812033a)15,0182034268,427 °o 268,427 16,7472035$51,390 Q 651,990 tet2036200,163 i)O18 san i2037671,672 °871672 Tato 284,91720381,163,631 °1,169,691 6.459 34.870203997.893 °897,803 ase 390,719 2040 41925 o 41928 04.351 658.141 12,283204106,759 °386,759 BT 704,728 12.9012042e906.468 700,700 12,3372043Qeowe804,064 12,979204427,076 Q 2?,oTe 100,683 870,100 12,4272045123,405.o 123,408 103.612 997,701 12,4462046o9°106.288]1,020,649 12,4922047@012,51920480aF12.8742049°°A 12.603205009A12,6302054QLt]12,0082082i)a 5 #27232053aaR12,74)2054 3,703 a 4,703 ,12.7012055n7779Q397.773 ,V2.a18205661,024 o $1,074 i 12.8752087o9A.12,09620s89C,)12.0342059QQf150,604]1,820,864 12,9732060aa32.092 |9.490.273 |287.872 165.003 1,879.232 13.030i--Total 4.875.203 [Total of Cash Flows &18.804 578 282010 Page 5 Pian 26 PSO Summary Scenario 2B Plan -P50 Natural Gas Forecast:Cumulative Capacity and Energy by Resource Type Natural Gas Coal Nuclear Fuel O8 Purchase Power Hydro.Geothermal Municipal Solid Waste Wind Ocean Tidal Capacity Energy Capacity Energy Capacity Energy Capacity Energy Capacity Energy Capacity Energy Capacty Energy Capacity Energy Capacity Energy Capacity Energy att 1,104 3847 8 43s 21 578 a 210 176 591 1s By]2012 1,104 3.424 Ly 434 |3B 25 176 593 eo 2320131,041 3,60 L)367 a $12 3 214 176 591 69 226 24 1.176 3.140 6 e43 a1 a Bs a4 a1 64g 2 163 Ls)2720151,976 2434 Ll 620 Bi 638 3 212 21 919 2 163 69 zy20168222.323 Lo]825 zl 726 3 214 y-)]921 2 163 69 yz)2017 822 2,358 8 815 31 2 a 212 aI a9 y74 159 9 32620188212.383 Ly 562 189 618 3 23 mI 19 2 166 39 32620196212,399 we Sat 189 576 "a 213 a 910 Zz 163 99 32520201,103 2.594 6 S74 3 190 at 921 so 403 2 162 99 32720219072.611 Le]552 a 178 ¥3]910 50 a 2 161 s 3262022e2562.274 ©$42 a3 175 a 919 100 eT 2 157 9 32620237432,458 a 398 2 167 2st 919 100 600 2 159 9 32620247432.505.33 381 3 155 a 921 100 ou 2 151 99 326 2025 74 2,303 83 322 er]188 405 100 2 198 149 4892026Tas2,485 53 2 4,450 100 788 2 155 149 49120277012519ES]Ma 4a 100 738 22 153 149 491202870125483Re]4486 100 798 2 155 149 412029Tot2.583 ES)a4 4451 100 002 2 184 149 4902030702.418 33 5 4453 100 795 R 146 199 320315312.402 33 354 4.475 100 Tr 22 138 199 65320324872.401 $3 380 4.484 100 802 2 148 199 6562033a72,408 33 30 4,480 100 792 2 144 199 655203448?2,446 3 M7 4,476 100 785 22 144 199 6552035,ar 2.450 33 xt 4488 100 819 2 147 199 6552036™m 2.455 53 370 4.487 100 a1 2 153 199 654a7bits2.687 s3 Ra 4497 100 687 2 103 229 TS420387452,689 33 44 aan 100 rela 2 114 279 TS420391,360 2,753 83 346 4482 100 71S 2 110 229 TS4 2040 1,380 5.850 Ss *4.495 100 768 2 155 ze 86720441.380 5,805.33 363 4496 100 834 2 181 29 85020421,380 $732 33 375 4sio 100 ™2 144 ce)1,0142043AM?5,687 33 7 4513 100 816 2 158 we 1,0182044a7B10333794327100we2174wm4,019204513178.785 $3 376 4517 100 807 2 144 x»1,01720461,364 $822 33 374 ase 100 7468 2 +70 we 1,017204713646a13333784510080122184sos4,01420481,364 5.874 $3 77 4547 400 802 2 $46 308 1,01920491,364 5.068 53 374 4535 100 809 2 172 300 1,01620501,364 5,890 33 5 4537 100 B04 2 100 wo 1,018205113645.918 83 376 asa 100 627 2 157 we 1,01720521,364 5,984 EX)a5 4565,100 788 2 154 309 1,01920531,364 5,062 33 yu7 4556 100 601 2 464 wo 1,01420541,364 6,012 s3 380 4589 100 602 2 461 woo 1,0182065S1,384 6.045 83 378 4561 100 eot 2 161 wo 1,01820561.64 6,069 s3 376 4s7?100 704 2 176 wos 1,01920571,482 6.087 33 379 4660 100 a8 2 146 me 1,01720581,462 e145 Lx}381 4504 100 Tr 22 176 300 1,01420591,462 @231 83 32 4847 100 aoa 2 161 309 1,014£2060 lA 2,BSN nt a es ed a £2 12 202)O12 Black &Veatch Confidential 2/18/2010