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Alaska Railbelt Regional Integrated Resource Plan (RIRP) Study Draft Report December 2009
Alaska Railbelt Regional Integrated Resource Plan (RIRP)Study Draft Report December 2009 [=}1 BLACK &VEATCHBuildingaworldofdifference: 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 December 2009 DRAFT REPORT 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 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 DRAFT REPORT December 2009 ACKNOWLEDGEMENTS 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 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. Black &Veatch 2 , December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents 1.0 ->_Executive Summary...ceescccscecssccessceceesscesessesescsccsssssasessccnsnsensenessssesesceesessssssosssonsensesenses 1-1 1.1 Current Situation Facing the Railbelt Utilities...sescsssssseesseeeceneeseeneenseneenenes 1-1 1.2 --Project OVETVIEW .........eeeecesecessecenceeeseeeeceecescesseconsssssssecssssscnscoesesesssssssscseseceesesenaeeees 1-3 1.3._Evaluation Scenarios.............ccssscsscesssccessesessecsesececcsscssecsessesessseseceesesensnssesessseeesessanse 1-7 1.4 Summary of Key Input Assumptions..............ssssssssrecsssesssesesescessccssesscsssnsscsenscceseenee 1-8 1.5 Susitna AnalySis.......csccsssssssssccssssssseccssesssscssssesssecseseesssescosscesessorscsesssensensssscesseseeasers 1-8 1.6 Transmission AnalySis ..........cccsecccssssessseesseesesessessessscescseescecsanessscessssesesscesssussesesseoees 1-9 1.7 Summary of Results ..........ccssssscsescsssssscssecsssecssesesccesssessesscevsssssseseseessssessonesesensneees 1-11 1.7.1 Results of Base Cases........seessscscsesesesssssseresssesssersnserensssscasenssceneveseesnsess 1-12 1.7.2 Sensitivity Cases Evaluated...ceecsecsseeesseesscesesseseeensstecsseessseeeseseneese 1-14 1.7.3.Summary of Results -Economics and Emissions ............:ssssesssseseseseees 1-14 1.7.4 Results of Transmission AnalySis ...........scccsssssssesssssscceseceeseeesssssersceeeees 1-17 1.7.5 Results of Financial Analysis .............ssssccssssscsseessseseecesesecssessrsssneeeseseenee 1-20 1.8 Implementation Risks and Issues............cscsssscssccesessssecseesesesessessssssesceessecssesesensens 1-22 1.8.1 General Risks and Issues ..........essssssssssssssssecseesseseseeessesescecsssnsseesssssssaeennes 1-22 1.8.2 Resource Specific Risks and ISSues............:cssssssessseseesssssecssesesrsoseenssscesees 1-23 1.9 Conclusions and Recommendations ............cccecssssssecesssescesesssscceeseesecesessseeeseeesones 1-25 |e Mm ©0)0 C0)U6 1)(0)«(pn 1-25 1.9.2 -Recommendations ............ssccssceccsssecesscescesecessceeencecessetesseeccasecenssssaesossesoanss 1-28 1.10 Near-Term Implementation Action Plan (2010-2012)0...cesssssscsessscssesesssscereee 1-35 1.10.1 General Actions ........ee ccecessssceeseeeessceeceseeseasesecssssesesceseeessesseessesesssasesaees 1-36 1.10.2 Capital Projects...eeesessessecesseeseecsecessecesacsscseeetscssscsossosescnssensees Laseeeee 1-38 1.10.3 Supporting Studies and Activities .........cssssssscsssssssssssssssssssssessssssssssesssseeees 1-39 1.10.4 Other Actions............cscescssscsscceresseesscceecesseeesecesesssecscsssssessssaessesseesoeseessaees 1-40 2.0 Project Overview and Approach.........esseresasscceneadssseaceacensacensensncscenssaceaseaceaaeatesoneasees 2-1 Z.1 Project OVELVICW ......se eesscsesssssesesesessssoaseoeesnsessescessscnsessenssnecesscsecnsoesosesrsasessscenensesens 2-1 2.2 --Project Approach .......ecesessssesstesesesssessecoseseceecsessnecasssesesssasecusasscscecseseressersesneceeeeses 2-2 2.3.Modeling Methodology ...........sesscessessseessscessssssstsscessccssessssscessssesasseessesssccuscasesneeess 2-5 2.3.1 Study Period and Considerations............cseccscssssssscsssssssrecssscsssssessssensssseesees 2-5 2.3.2 Strategist and PROMOD®Overview.....cescsssessssssessssssessessssssssscensencsnesesseens 2-5 2.3.3 Benchmarking............ccsccsssesccesseessessossssssccessscaceesscesecsecssceeesssssesoessseseesonsenes 2-5 2.3.4 Hydroelectric Methodology...cscessessccsssccssesesssssssctsssesssssessnsecssserses 2-6 2.3.5 Evaluation Scenarios ..........scsssssscesesrsccseesssecssscesocessesssesessssessesosseesoseussenses 2-7 Black &Veatch TC-1 December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) 2.4 Stakeholder Input Process...eessseeeseessesscesessesesccsessaseeeesesessssccosesseseeseeaceneseeeses 2-8 2.5.Role of Advisory Working Group and Membership ...........cessssssssesesssecesaceeeesteneeees 2-9 3.0 Situational ASSESSMENE ........ce eeesescesceesseecseecsccesceosssecseensesecsscesenseeessessesessessseesosessecseessseeanees 3-1 3.1 Uniqueness of the Railbelt Region oe eseseeeessssscessesseeneesesesseseesseesssseecseeseseeeres 3-2 3.2 -_COSt ISSUES ...c.ceeesscsssssssseeesecsecsscsenecesenceesesceasceceesaesesecsnsenssesnsecsecsscesscstecsenesensesaseones 3-2 3.3 -_Natural Gas Issues..........ccscssscsessceseccsecsescessssesseseneesnessnesessseneesenssesesessssscseesesseenseseaes 3-6 3.4 Load Uncertainties...cesssssscsccesessscssscserssssccseceseceesnseasssecesseseesessacssecsneseonseseeens 3-10 3.5 Infrastructure [SSues ..........csseessessceeeecesesecssesacssscscnsessceesseeceeescenssssaeesseesceccssseesseeeeees 3-10 3.6 Future Resource Options...........cscsscssecssscssecessesecesesessecscceasescecaseessacssaesseeeseeseeeeaceees 3-11 3.7 -Political Issues ........cteesssscssssessccesccecnsosessccsccssscesseeseossssessescoessescesssescesenssoessessossesees 3-13 3.8 Risk Management Issues............csccssssccscceesesssssccssseseccesscsesessesesssecsescoessessesseessossesas 3-13 4.0 Description of Existing System ..........csscsssscsescssesssssssssecssesescssecsesesesesssessesescecseaeseseeeseaseeeses 4-1 4.1 Existing Generating RESOUICES .........essesceceseesesesceseceeseseeessseceecsoscessssnescsssssseseeesenee 4-] 4.1.1.Anchorage Municipal Light &Power ou...ecessessescessecsceseetessessesteceeeneaee 4-1 4.1.2 Chugach Electric ASsociation...............ccccccccssscesesessaceesscceesceeeesececeeessseesneeees 4-2 4.1.3 Golden Valley Electric Association «0.0.0...sesseecssecsecseceseeseeeasseeeesteeteees 4-2 4.1.4 Homer Electric Association...cssesescesscsecsessesesscesssescesessseeseesssessceesteees 4-3 4.1.5 Matanuska Electric Association ..........ccscsssccsscsssssseesssccsessseescoeseesseseeseeseees 4-3 4.1.6 Seward Electric System...cessssscssscesecssccesseseesssceseessecessseeseesecsnsseceoreses 4-3 4.1.7 Hydroelectric Resources..........ccscscssscssccscsssscssssssccssecesaeeseceesessecsaeeacesereone 4-3 4.1.8 Railbelt System...esesesssteesscessssscnsessccesceseesscssseseronsessesseneseeaeaseeaee 4-5 4.2 Committed Generating Resources ......ce eecsssssesesssssssssessesscessessseseseesesssessesseseesseeses 4-5 4.2.1 Southcentral Power Project 0...ee eeeeeseceeeeceneeeeseeeeecssesseesesesseeaversnseesseaes 4-5 4.2.2 MUL&P Units ee eescescccsescesecssesecsecssassscsssessceacseceececoessesoesenssesssesesasensens 4-5 4.2.3 Healy Clean Coal Project .....ec tesscsssssssssessssseescesssceseseseesssssscsessssessensees 4-7 4.2.4 HEA Units ooo eee eeeeeeseeeceeceseeecennccscescescesceseesseseeceacessenssesssessesssscceseeneneees 4-7 4.2.5 MEA Units...ee eseeeccesececceseececceseseeeesersceessessasseessseacssesssecessssencersceesenesess 4-7 4.2.6 City of Seward Diesels ......ce eesssssseccsesescccessesscensesceeesseeseeseceseoseaseneseesesss 4-7 4.3 -_Existing Transmission Grid .........tes scsseessesssesscsescessscesessssseseseaseeseeceesesseeessesenscease 4-8 4.3.1 Alaska Intertio .......cee eescssssecsccsreeseneenscssesscssnsscsseseseeensascsuseneonsssessesensenes 4-10 4.3.2 Southern Intertie 0...eee ecsseeeeceeeeesesesseeesecessscssesssesseessessesssseesesseeeees 4-10 4.3.3 Transmission LOSSES.........ccscsscsssessecssessreserssecssssssssssecessesssassonsnsscessesseasees 4-11 4A Must Run Capacity wc ecccscssssscscesscessesseesecssssssssssresscessessscecsesessssnsscsssssssesesssseses 4-11 Black &Veatch TC-2 December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) 5.0 Economic ParameterS...........cescccesesssccsscessssscssccscseseeessseecessecesesscssseesesesseasscsesesseesssevensseeeanesees 5-1 5.1 Inflation and Escalation Rates sssssssccsssssssssssssecsssessccssssseescssssssevssesesssssssessesssensessseseesss 5-1 5.2 -_Financing Rates...ccesscsssssssecscececesceseseeecsescescceeseseesesscesesssssscsacesssesssasoossoensenseees 5-1 5.3.Present Worth Discount Rate...........ecsssssscesssssssecesseeeseececesscscesssseessseeceeesoesssoesseeeees 5-1 5.4 Interest During Construction Interest Rate ...........cesssssseseeecseteseeeeeeeeseesesesesereceeeeonsees 5-1 5.5 Fixed Charge Rates .0........csssssssscesecescrecsesseesssecseesseeesssscsseesessscossessesonesonessscesssasoenses 5-1 6.0 Forecast of Electrical Demand and Consumption .....c..sssssssssssessesssessssessecssesnscssssssssssesscenseosss 6-1 6.1 Load Forecasts ........ccssscccsssseseseccesssscessscessenesscsaucessecsessessssscensssenesersesesseeesseseesuasesenenes 6-1 6.2 Load Forecasting Methodology ......ccsssssssssssesscssesscesssssesesessssssesessssesessseacseseacenesesssenes 6-1 6.3.Peak Demand and Net Energy for Load Requirements .............c:ccsssssssssesssesseveeneeeeees 6-1 6.4 Significant Opportunities for Increased Loads ..........es eessessesseceeesesessessescecsesseeseeeres 6-4 6.4.1 -Plug-In Hybrid Vehicles...eee cecesessscseseeseeseesecsscssoeseessaseenseassesaseesonees 6-4 6.4.2 Electric Space and Water Heating Load...sssseseseessesseecssesssteesseees 6-10 6.4.3.Economic Development Loads...ceeeeseceseceersesessesssessseesseesesssnsstensaeees 6-10 7.0 Fuel and Emissions Allowance Price Projections..........sscssscsesssssscsessesssersesccsesesecssesesassscenees 7-1 7.1 Fuel Price Forecasts .........:cssscsssccsssscssssseccsseeccncssesseceesanessceessnsecseeseeesesesssessnsasoeesonses 7-1 7.1.1 Natural Gas Availability and Price Forecasts............csssssssssscesseesesesseeseesees 7-1 7.1.2 Methodology for Other Fuel Price Forecasts .............sssscsssssesseceseseseeeseneees 7-9 7.1.3 Resulting Fuel Price Forecasts .0.........sssssscssrssesssssssssssesoeeeees sssesseseeseoesees 7-10 7.2 Emission Allowance Price Projections ..........ssssscssseseseseseseseseesenesesenensenenenesenseeeeesees 7-10 '7.2.1 Existing Legislation ..........csssssssscssseccsssccscsscessessscsssoesesesesecescsesecssoesesones 7-10 7.2.2 Proposed Legislation 0.0.0...seeesesecsssseseessseeesessesseessnsoseeseesessssessenesaness 7-10 7.2.3 Development of CO2 Emission Price Projection...........scscesseeeeeeeeoees 7-10 8.0 Reliability Criteria 0...ct esescescescsecseessesanscessssescessssssesessaseusesessasesesesseserssassessssasessnensenese 8-1 8.1 Planning Reserve Margin Requirement ...........scsscccssscssessecsssesseesescssssssessscssesereeseees 8-1 8.2 Operating Reserve Margin Requirements............:csscsssscsssssscscesescssesssevesseessersereeeees 8-1 8.2.1 Spinning Reserves 0.0...ceessssccssscesceseessscesscnscsssssessessesscsnssesesessnsesseesees 8-1 8.2.2 Non-Spinning Operating Reserves ..........escsssesessscssecseesersssescsesesesarseeesesees 8-1 8.3 Renewable Considerations.............sscsssscsscccsssscssencesssceecneseesnsessecesesessesecesecseceseseosaesoes 8-2 8.4 --_-Regulation...eeessssessscsscssessesessscssessesssonsossessassesseessseussssssseessessesecsneseesesseesesteenense 8-2 Black &Veatch TC-3 December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) 9.0 Capacity Requirements ...........ccsesscsscssccsecessesscessesssesecsecsseasssseseessceesessacecsesessessesseeessaeeseseenens 9-1 10.0 Supply-Side Options 0.0.0...eseessescceccesesscenctscessscesceceeseeseesessenensessenscecevacsecesesssseaseaeseeeteesers 10-1 10.1 Conventional Technologies ...........csssssssseccescsscsecssssssceecessscescscesecsacesseeseaesaseateesees 10-1 LO.L.L Untroduction oo...ee tscsecscseecnssnsesseseessescessesscessesseeneseecetssesessertensetseeenree 10-1 10.1.2 Capital,and Operating and Maintenance (O&M)Cost Assumptions.......10-1 10.1.3 Generating Alternatives Assumptions...............cescssseeccesssecesseseesseaeeensesees 10-1 10.1.4 Conventional Technology Options ..........cc eeesssseseeceecescssecseesscseesesseeeerse 10-5 10.2 Beluga Unit 8 Repowering........ee eessccsseseecsccssceeceecceceeceeeceneeesaeeratsetsaseeseesaeeseess 10-17 10.3.Renewable Energy Options...eeessessescceccseceesseeeecescecseesonescessessceaeessaneasenseeess 10-17 10.3.1 Hydroelectric Project Options...eeescsseecsecceecesssescessssecssessesecenseess 10-17 10.3.2 Ocean (Tidal Wave)...ccecsssssesseesscscesseccsscessesceseesaseseeesscesaesenensnseasenes 10-28 10.3.3 Geothermal Project Option...eesccessscesseeesesssetscsessecsseeseeeseeeses 10-32 10.3.4 Wind Project Options ...........ceeseeeseseeseenssassvsecesssvecsensseesersseessecsenenseseets 10-35 10.3.5 Modular Nuclear Project Option ...........essssecescsseeeeceeesetssencencessenesasensenes 10-40 10.3.6 Municipal Solid Waste .....cee es esssceeceseesecesseceseneecceesessesenecesssssssensenes 10-45 10.3.7 Central Heat and Powet.............cccsscseressssssesssesneeencessoneessseseesaceeseesseeeeesreas 10-45 11.0 Demand-Side Management/Energy Efficiency ReSOurces .........sssssssceeeeseeseeeseneeereerenseees 11-1 L110 Introduction...ee esessetseseeesseeceeeessessececesessseuseseesssseesssessssaaeecescessuseesasesessenessersenss 11-1 11.2 Background and Overview ...........sssssssscssseseesecsscssceeseseesesscceaceescessssucsacescsacsaseasenseees 11-2 11.2.1 Current Railbelt Utility DSM/EE Programs...............csssssscsssscsssccsseeseeeeees 11-2 11.2.2 Literature REViOW .00...ee essssesseeceesserececcnsseseesceacecseesssessessseseeasensseeseesenses 11-4 11.2.3 Characterization of the Customer Base .........scssssssesssessssssesessesseccsseecessecees 11-4 11.3 DSM/EE Potential...esccesecessessseccsssssssesssessessessesssscscesessssssseaseeseseacessessesseess 11-6 11.3.1 Methodology for Determining Technical Potential...eesseereseeeee 11-6 11.3.2 Intuitive Screening.............cesesssssseesecseeesesssscnseesscesscessecessceescesceaccnsessecsaees 11-6 11.3.3 Program Design Process..........ssssssssceseescecsseesssecceeeceeceecseseeseceassesseensesseess 11-7 11.3.4 Achievable DSM Potential from Other Studies...ee eeeeeeeeeseenseeeees 11-8 11.4 DSM/EE MeasuleS.......ce ceesceessscscssscssecsssseossessssesescnseeessscesesssseseeesecesassseaseeneaseaseese 11-8 11.5 DSM/EE Program Delivery .........ccscssscsessessessccssccsesscsseesssesssesseasesesssssscassessesenenee 11-16 Black &Veatch TC-4 December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) 12.0 Transmission Projects .........csscccsccessscessesecssssessssesssssssscsessescsceneseeseeeessesessseceaeeesenessenstenesnnes 12-1 12.1 Existing Railbelt System...ce eseseseccesssccessscssssnssserscseecesasecsecesseeeesesesseeseeeeenses 12-1 12.2 The GRETC Transmission Concept ..........:scssscesssesseesecessesessessesseessssssanssseeesseseeeneses 12-3 12.3.Project Selection Criteria ..........scscsesseseererees sessessesusscssseuesessesseessseseeeseeeeeseesneneeneeas®12-3 12.4 Summary of Transmission Analysis Conducted...ccccsccesccressceesceesecseecesessesenees 12-3 12.4.1 Cases Reviewed .........ccssssscsscessessecsessesssessessssncseceseessavessesseceeneseeseeeneeeeseeess 12-3 12.4.2 Results of 2060 Analysis 0.0.0.0...essssssecsecesssessessssessevssesesccsessreneneeeeeseeenes 12-3 12.5 Selected Projects .........cccscsssssssececessseesescesetevscsssesessscssssnseconssrsececesensseseseesssentesseeees 12-4 12.5.1 Priority 1 Projects .........csssscssesesseeesssessssesesssconesscesssesusssceseseessenseseeeeeeenes 12-4 12.5.2 Priority 2 Projects ..........essscssesssesessssecscesesssonsecsnseessessessscseeeesesssesseenseneses 12-7 12.5.3 Priority 3 Projects...eseesssseeecsersecssecssesessecsseessevessesssenseeessesesnseeenereass 12-9 12.5.4 Priority 4 Projects ..........eessssssssscesssessssseessesensessnsesssvseresssesseeessesseseressnens 12-12 12.5.5 Priority 5 Projects .......ccssscsscssesecssseecssessesssssesessssssstsacsnssseeeenesseesenseeeeees 12-16 12.5.6 Priority 6 Projects ..........ssscsssscseessssscscessesssessesssensceesssaneeesseesseensesssenstees 12-19 12.6 Summary of Transmission Projects .........:cscccssccsssssecsscesseversesecernssessessecsressesseseens 12-20 12.7 Other Reliability Projects...tees esssscssseessceserssscssessssesesesesoneeenseeeseesesesteeneesses 12-22 13.0 Summary of Results...eecsesssssseceecsecssescssssscesesssssessessssscnesessseneesceseeesessesseessesesensacenees 13-1 13.1 Results of Base Cases ........ccsesssesesssssessssssccssscssssssnsesssesasensessassessssceveceesserstesseecssenss 13-1 13.1.1 Results -DSM/EE Resources .........ccessssceesssceseescsssssesesscssscseeseseenseeenaeees 13-1 13.1.2 Results -Scenario 1A Base Case....csscssseessssssesssssesevesneesseseneesseeeesenses 13-2 13.1.3 Results -Scenario 1B Base Case...cescessscsssessesssnesseveceessceseseeesseeessenees 13-2 13.1.4 Results -Scenario 2A Base Case Results...........scessssesssessscssscsscsesscrneoee 13-3 13.1.5 Results -Scenario 2B Base Case Results ...........csccsssssssesseeseeeeseeseenrensreeees 13-3 13.2 Results of Sensitivity Cases ............cseccsssssssecsescsessssssscsssecessssessceesonesesseseesssesssesssseees 13-3 13.2.1 Sensitivity Cases Evaluated...cessssssssessesesenecerscsesseessessseseeesnesseeeas 13-3 13.2.2 Sensitivity Results -Scenario 1A Without DSM/EE Measures................13-4 13.2.3.Sensitivity Results -Scenario 1A With Committed Units Included.........13-4 13.2.4°Sensitivity Results -Scenario 1A Without CO2 Costs .......cescseeseeesreeee 13-5 13.2.5 Sensitivity Results -Scenario 1A With Higher Gas Prices ...........seeeee 13-5 13.2.6 Sensitivity Results -Scenario 1A With Fire Island ............ccseeteeeseeeeees 13-6 13.2.7 Sensitivity Results -Scenario 1A Without Chakachammni.............ccscceees 13-6 13.2.8 Sensitivity Results -Scenario 1A With Chakachamna Capital Costs Increased by 75%.......ssessessssssssencssesssssssvescessscssensssenecsescentensessensesaseagsenees 13-6 Black &Veatch TC-5 December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) 13.2.9 Sensitivity Results -Scenario 1A With Susitna (Lower Low Watana Non-Expandable Option)Forced 0.0...ce teesesssceseeeeeseeeerecesetenees 13-7 13.2.10 Sensitivity Results -Scenario 1A With Susitna (Low Watana Non- Expandable Option)Forced ...........esessessseesseeseeseeereetsscesseceresesaceeceeseeeeteees 13-7 13.2.11 Sensitivity Results -Scenario 1A With Susitna (Low Watana Expandable Option)Forced...essscsssessessceessscesscnesecesacesssensceeseasseneesees 13-7 13.2.12 Sensitivity Results -Scenario 1A With Susitna (Watana Expansion Option)Forced.........cssccsscssssscesestsesscesessssscscceseceseceasenceeeceacsesserseesecansereonees 13-8 13.2.13 Sensitivity Results -Scenario 1A With Susitna (Watana Option) FOr .......cssscsssessecesecesccessecesesscssesssscescesesecessesecceesscsesecsssceesaseresscsseseeeneneees 13-8 13.2.14 Sensitivity Results -Scenario 1A With Susitna (High Devil Canyon Option)Forced .00......es eseessseeeeceeneeeseeceeersceeeceecesesseeeseteseaeeneeeneees 13-8 13.2.15 Sensitivity Results -Scenario 1A With Modular Nuclear........00.......13-9 13.2.16 Sensitivity Results -Scenario LA With Tidal...escesssccseessseeereenneees 13-9 13.3 Summary of Results...seesscscesesssssoneseccssesecscoseesenesensecescsesseseeseesseesenssensessesseeses 13-9 13.3.1 Summary of Results -ECONOMICS ..0.....ees ceseessessssceceesceesenseeseersseeceesneeees 13-9 13.3.2 Summary of Results -Emissions...scesssssesecssceseceeceeeesacesencenseeseaeees 13-11 13.4 Results of Transmission AnalySis...........cccccsccsssccssscesssecsssresssccssseecseeceeeseeesseseseeeees 13-12 13.5 Results of Financial Analysis.............esssscsssescesscesesensescessscesssecesscesseessscesseeesescness 13-14 14.0 Implementation Risks and [Ssues..........csssssssssssesssscsecssscssscsssscsesssssosesssssasscesessesssseseseseeses 14-1 14.1 General Risks and Issues 00...ee esssessesecessesceesessesesecsescessssseecsecseseseseeeeeenseeseseaoees 14-1 14.1.1 Organizational Risks and IssueS....c.ccsssssssssssessesessssessssesssssessssesssssesserserss 14-1 14.1.2 Resource Risks and [ssues..........ssscssscssssessessseeseeseeeseseseses taeveasevaneseeosonses 14-4 14.1.3 Fuel Supply Risks and Issues ...........csssssscssecsscsceeseseesessecseesseseeceseeseesseseeses 14-4 14.1.4 Transmission Risks and Issues ...........scsscsssssessecssscsseseseessssscsessevscseeenseasees 14-5 14.1.5 Market Development Risks and Issues............esesccsscrsssseecsssccessssceeessesenees 14-5 14.1.6 Financing and Rate Risks and IssueS..........esses sseceseeeesesecseceeceeeeeneeeeees 14-6 14.1.7 Legislative and Regulatory Risks and Issues ...........csssssesessesseeceeeeeneeeeees 14-7 14.1.8 Value of Optionality 00...cesccscscescssssesectesenecessssesseseseesseseesescceessneses 14-7 14.2 Resource Specific Risks and Issues ............ssccssssscseseesscsscsceeseecensenssseeescsesteseeseseneeess 14-8 14.2.1 Introduction 0.0...cesscscsscsssesccscccsscesesssssesseceaneeascnsnseesesscsesssseessessessaesanss 14-8 14.2.2 Resource Specific Risks and Issues -SUMMALY ...........sccesessssescseesseeeeees 14-8 14.2.3.Resource Specific Risks and Issues -Detailed Discussion...............000 14-12 Black &Veatch TC-6 December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) 15.0 Conclusions and Recommendations .............esesessssccsesssecsseseseeeseessssesssaceesesevetssasseseeesentenets 15-1 |BasGi OX 0)0 Ved L115 (0)«|:SE 15-2 15.2 Recommendations...cesccsseeesscesseecessecscesscscescsnssssssssssesssecsscneseeceneeeesessseesseees 15-5 15.2.1 Recommendations -General ...0........eeeessesssessessecssscseesesseeseeseessssesseeneeees 15-5 15.2.2 Recommendations -Capital Projects .........cs cscsescscneesecssssceseesessonsseeees 15-10 15.2.3 Recommendations -Other ............esseesesseeessessseseseessessnesssssonessssseesvensees 15-11 16.0 Near-Term Implementation Action Plan (2010-2012)oo...ccecessssssecssssssssscsssstsessesneeeeeees 16-1 16.1 Gemreral Actions .........ccscsssseccesecssceeecscnceeseceseesceessaresessssesseecsecseossossesassessasecessressaeres 16-1 16.2 Capital Projects...ccccssscssesssssseccceeescessesensesessesesscaresasecesscessecessouseesseserssenseeaseneees 16-3 16.3 Supporting Studies and Activities...eee eseeecssescsesssesseesesesssessesseesesssesseestenss 16-4 16.4 Other Actions v0...eeesecssseccseecesessenetseseeescseesscesersssscsasossssssscsecssecscessueseeseeteseeeees 16-5 Appendix A Susitna Analysis Appendix B Transmission Stability Analysis Appendix C Financial Analysis Appendix D Existing Generation Units Appendix E Regionial Load Forecasts Appendix F Detailed Results -Scenario 1A Appendix G Detailed Results -Scenario 1B Appendix H_Detailed Results --Scenario 2A AppendixI Detailed Results -Scenario 2B Tables Table 1-1 Summary Listing of Issues Facing the Railbelt Region ............sessssssssscssesecereeseeesees 1-3 Table 1-2 Alternative Resource Options Considered ...........ccssecssssseesereccseessscesecossssssenseseseseecees 1-5 Table 1-3 HDR Analysis of Watana and High Devil Canyon Alteratives.......cesscssserserees 1-10 Table 1-4 Summary of Results -EcOnOMICS .......cesssssscsessecsceeesseccsesssesssensesseseensesseeecssseenenss 1-15 Table 1-5 Summary of Results -Emissions ...........sscsssssssccssssssessscssscescssesseeessseesstesseessenereees 1-16 Table 1-6 Recommended Transmission Projects ..........ssssssccssssccseccssscessscsssssesessssceeeseseveseseseoes 1-17 Table 1-7 Resource Specific Risks and Issues -SUMMATY .........cssssesscssesssesssesseesseeesseseeserees 1-24 Table 1-8 Resources Selected in Scenario 1B Resource Plan...esessscssecereessecessesesetseees 1-30 Table 1-9 Impact of Selected Issues on the Preferred Resource Plan........sesessseseersereesees 1-31 Black &Veatch TC-7 December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Tables (Continued) Table 1-10 =Projects Currently Under Development...ce eesesescescessesesesseseesseesereeesassetseeneeees 1-32 Table 1-11 |Near-Term Implementation Action Plan -General Action ............ccssssssecseseeneeees 1-36 Table 1-12 |Near-Term Implementation Action Plan -Capital Projects ...........essssccssecseeeeeees 1-38 Table 1-13 Near-Term Implementation Action Plan -Supporting Studies and Activities........1-39 Table 1-14.Near-Term Implementation Action Plan -Other Actions ...........ecccesseceeteceeseeeees 1-40 Table 3-1 Relative Cost per kWh (Alaska Versus Other States)-2007 .........ccsscssssssesessssseconees 3-4 Table 3-2 Relative Monthly Electric Bills Among Alaska Railbelt Utilities .......ssssssssssssssseene 3-5 Table 4-1 ML&P Existing Thermal Uniits...0.....0....ccsssccssssecssescscsccsssessecesseecessncessenssscesesessescesees 4-1] Table 4-2 Chugach Existing Thermal]UNnits.............csscsssssssssssssesssecsessscsseseessccessescesacssseessessees 4-2 Table 4-3 GVEA Existing Thermal Units...eee tesesseseescessceeceneseeesseeeaesasceetseseseeeessseseeeees 4-3 Table 4-4 HEA Existing Thermal Units..........ccsscsscsssccsscesssecsscsstscseessesseesesesesesesesncesesenecereenees 4-3 Table 4-5 Railbelt Hydroelectric Generation Plants 20.0.0...ccsscesscssecssssssessesessscsesesseseesercenastereees 4-4 Table 4-6 Hydroelectric Monthly and Annual Energy (MWh)).............cccssccsssssscessrsssseneescceecesens 4-4 Table 4-7 Railbelt Installed Capacity 0...sseesessecesseceeceeecsecsereeecsassessesecenscesessescessaneeeseseeaes 4-5 Table 4-8 Railbelt Committed Generating ReSOUrCES........ccc sscessesessesecseesseseseesensseseneeaeeneenes 4-6 Table 5-1 Cost of Capital and Fixed Charge Rates for the GRETC System...cesssssssseenees 5-2 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 ...........scsssesscesecsecseeees 6-4 Table 6-6 Electric Consumption for a PHEV33 PNNL Kinter-Meyer aseaceesceeseseensonceeacenseeoeseass 6-5 Table 6-7 Additional Annual Energy Required in the Alaska Railbelt Region from PHEVS.......ssscsesssssscsceescessecsesseessccescsssssecesesersccceessssacsecessssenscessessessceecssassesaneseeeecseseeees 6-5 Table 6-8 Hourly Distribution of PHEV Load on a Typical Day -Alaska Railbelt INT24(0)5 6-7 Table 6-9 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Energy Requirement...scssscsessscccecseesecerssesenssesoeeseeessesseseeseesecseeseeeese 6-9 Table 6-10 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Peak Demand...eesesssscseseecssecesenecesecsccneceasseceasessenscassscceenscesresnsenteeeee 6-9 Table 6-11 2007 Natural Gas Consumption for the State of Alaska...ceesescsessesseeeeseseessers 6-10 Black &Veatch TC8 December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Tables (Continued) Table 6-12 Calculated Railbelt System Energy and Demand by Customer Type for Electric Space and Water Heating 0.0...cesccssssssescsssssnsecsensecesesesensssseseecsenseeseeeeeees 6-10 Table 6-13 -Potential Economic Development Projects...ese cessssscssssesssetsesssecsesssnsesessessescenenes 6-11 Table 6-14 |GRETC's Winter Peak Large Load Forecast for Evaluation (MW)2011 - 20G0........sccccccstcccsencceccecssssccsecesscsncesscesssnssncezsneesseessecerensescescusesesoesesesscesesessnavessseseatens 6-12 Table 6-15 |GRETC's Large Load Net Energy for Load Forecast for Evaluation (GWh) 2011 -2060.0...eesescccssescerceneeecseceesesccssessnccrscseaceoseecsseseseccssassscrasssseasesssnacensseseseeesess 6-12 Table 7-1 Representative Risk-Based Metrics for Railbelt Natural Gas Demand Based on Historical Data and Known Changes in Gas Consumption ..........scsssseseseesseseeees 7-4 Table 7-2 Representative Forecasts of Railbelt Natural Gas Price According to Different Benchmarks ............cccsssccsssccssssscctsecsecesseeeseseesceesessescsescessessseesssesesasseusoeeeens 7-9 Table 7-3 Nominal Fuel Price Forecasts ($/MMBtu)..........cscccssesseseseeseseesssescesssassessesssseseonees 7-11 Table 7-4 CO.Allowance Price Projections ............:.sssessscceescessessseessscseessnssscesssssessssessneneeeeeees 7-13 Table 8-1 Railbelt Spinning Reserve Requirement ............ssccssscssscsssssessecesncenesnesceesssseeeeeeesens 8-1 Table 8-2 Quick-Start Units .....ceececsecsecessesseeseecesssessssescssecccssssscnsancnsssesssesssecsessecesensssnseseesens 8-2 Table 10-1 -Possible Owner's Cots........cssssssscssccstcessccssssscssscessesscssacesscnsseassseesseseseeesseeseserenees 10-2 Table 10-2.Nomnrecoverable Degradation Factors .............cssscssscessecssssssessscssssssscersseeesssesseeeeeees 10-6 Table 10-3 GELM6000 PC Combustion Turbine Characteristics ..........cccssessessecsessereeeeeen 10-8 Table 10-4 GE LM6000 PC Estimated Emissions..............cssccssscssrcssesceesscsesssesensesscsscnsesseeseenees 10-8 Table 10-5 ©GELMS100 Combustion Turbine Characteristics 00.0...csscssecsssrecseseseserseeeee 10-10 Table 10-6 GELMS100 Estimated Emissions............ccseescsesecesssscsseessesenseesescessssusssensssseseesoes 10-10 Table 10-7 GE 1x1 6FA Combined Cycle Characteristics 0.0.0.0...sssstssssesssscesserssesossecseeeeee 10-12 Table 10-8 GE 1x1 6FA Combined Cycle Estimated Emissions............csesssssssssseseesesseeeeeees 10-12 Table 10-9 GE2x1 6FA Combined Cycle Characteristics .........daneseseessceeceneeeeeeeseeescesssesaseeavens 10-13 Table 10-10 GE 2x1 6FA Combined Cycle Estimated Emissions..............ssssscssessserseseesesenees 10-13 Table 10-11 Subcritical PC Thermal Performance Estimates...........ccscssesesssssreetsesrsesseeseeteees 10-15 Table 10-12 Subcritical PC Estimated Air Emissions...............::ccsscssssessstssssesssesssserssesassenseuenees 10-15 Table 10-13 Capital Costs,O&M Costs,and Schedules for the Generating Alternatives (All Costs in 2009 Dollars).......ceessssssssssesesssesseusecssneeessessenessensecseesseesseessesenssees 10-16 Table 10-14 AEA Recommended Funding Decisions -Hydro.........eeesssessesesseesssesesesssseseerens 10-18 Table 10-15 Average Cost of Electricity per kWh for Susitna Project ...........csssssessssessesseeners 10-21 Table 10-16 HDR Analysis of Watana and High Devil Canyon Alternatives.........scesseseseers 10-22 Table 10-17 Average Annual Monthly Generation from Susitna Projects (MWh)...10-23 Table 10-18 Power Generation Time Estimates for Susitna Hydro Project.......cccsseseeeeneees 10-24 Table 10-19 Monthly Average and Annual Generation .........ccsscsscesseerseeecsseseenseeeseseesnseneens 10-25 Black &Veatch TC-9 December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Tables (Continued) Table 10-20 Glacier Fork Hydroelectric Project Average Monthly Energy Generation ..........10-27 Table 10-21 AEA Recommended Funding Decisions -Wind ou...eee esseseeeeseresseeeeseereeseees 10-36 Table 11-1 Current Railbelt Electric Utility DSM/EE-Related Activities...essseeeseeeeeeeee 11-2 Table 11-2.DSM/EE-Related Literature Sources...cs essseesssscesesesccseesesessssesscssasssesssssseseees 11-4 Table 11-3 --Railbelt Electric Utility Customer Base...esseetsceseeeecssseceeercesneseesesesceeneees 11-5 Table 11-4 Residential and Commercial DSM/EE Technologies Evaluated...........ccesesseeeee 11-10 Table 11-5 Input Assumptions -Residential DSM/EE Measures..........csssscscssersssseessesesnensess 11-12 Table 11-6 Input Assumptions -Commercial DSM/EE Measures ..........ceesscssesseseeseeeceeeeeeeeeee 11-13 Table 12-1 Summary of Selected Transmission Projects.......cccesseseesseceseseeseeseecsseneesseseereses 12-20 Table 13-1 Summary of Results -ECOMOMICS ..........ssssesescescesceseseesesecesssscesereeseeecasseseneseesansees 13-10 Table 13-2 Summary of Results -Emissions .0..........esscsssessssessesssesssesesseseeecseeessssseaseeseeeees 13-11 Table 13-3 Recommended Transmission Projects .........c.cessscesecesecseseececesessesesesseeseseeetecteeeeee 13-13 Table 14-1 Resource Specific Risks and Issues -SuMMAryY «0.0.0.0...esse eeeseseeeeseeeceeeeceeeeeeseeeeeees 14-9 Table 14-2 Resource Specific Risks and Issues -DSM/EE ........cccssssssesseesscsesseseetesssesscesnees 14-13 Table 14-3.Resource Specific Risks and Issues -Generation -Natural Gas...eseseeeeeeeee 14-16 Table 14-4 Resource Specific Risks and Issues -Generation -Coal .............cssccsssesecescensneesees 14-18 Table 14-5 Resource Specific Risks and Issues -Generation -Modular Nuclear............0000 14-19 Table 14-6 Resource Specific Risks and Issues -Generation -Large Hydro..............eessseeee 14-20 Table 14-7 Resource Specific Risks and Issues -Generation -Small Hydro...cesses 14-21 Table 14-8 Resource Specific Risks and Issues -Generation -Wind ............cscesssssssssecseceees 14-22 Table 14-9 Resource Specific Risks and Issues -Generation -Geothermal ..........eesececeseeee 14-23 Table 14-10 Resource Specific Risks and Issues -Generation -Solid Waste...eeeseseesees 14-24 Table 14-11 Resource Specific Risks and Issues -Generation -Tidal...etc teesseeeeeeeeeeeees 14-25 Table 14-12 Resource Specific Risks and Issues -Transmission................::sscessssssesseceeseeceeees 14-27 Table 15-1 Resources Selected in Scenario 1B Resource Plan...tessseseseseeceeesessessenseeteeeee 15-7 Table 15-2 Impact of Selected Issues on the Preferred Resource Plan...eesessesseeeeeeens a.15-8 Table 15-3 Projects Currently Under Development...eeeeseeesesceneeeeserersceenecsreceaceeaseneenss 15-9 Table 16-1 |Near-Term Implementation Action Plan -General Actions ............seesesesseeereeeenes 16-1 Table 16-2.Near-Term Implementation Action Plan -Capital Projects...ccsssssssssessseeseseeeee 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 ...sccssscsssssssssssssssseessesseecs 16-5 Black &Veatch TC-10 December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Figures Figure 1-1 Evaluation Scemarios.........cesessssscsscesesecsaceseeessescsccesseseessesessssassecsssnsacssesessossonsesenesooees 1-7 Figure 1-2.Impact of DSM/EE Resources -Base Case Load ForecaSt..........cscesesssscsecesereseseee 1-12 Figure 1-3 Results -Scenario 1A Base Case .........eesesssececcescsesseeeseresacnseecesescessesseessssseseeeseoses 1-13 Figure 1-4 Results -Scenario 1B Base Case.............ccccscssccesssscccssseccesssscecessteceescesesenseesacsesssaoees 1-13 Figure 1-5 Results -Scenario 2A Base Case ..........:ccccssssssccessecerseseereesecesnssssecsssesevssssesssceseseoees 1-13 Figure 1-6 Results -Scenario 2B Base Case...cssssscsssecesessesescesssecsscesscsssesecesesseeneeseseensees 1-14 Figure 1-7 Location of Recommended Transmission Projects.............ccsssccssceesseesecsceeseeeeeeeees 1-18 Figure 1-8 Required Cumulative Capital Investment for Each Base Case...........csessessesersseees 1-20 Figure 1-9 |Required Cumulative Capital Investment (Scenario 1A)Relative to Railbelt Utility Debt Capacity 0...scssssecssceecstececcneeecsssesceneessssccesescesesessceresseesseeseseeesonees 1-21 Figure 1-10 Comparison of Results -Scenario 1A Versus Committed Units Sensitivity CSC...ce seccssscccsscsesccceesscsesecceecseccnsceeesccoeseasscaceesesscssensscecscessssssnsaasenseeescesecenseesenseeeeess 1-27 Figure 1-11 Interplay Between GRETC and Regional Integrated Resource Plan............cesseeees 1-28 Figure 2-1 Project Approach Overview.........cecccsssssscessecesscesseecesseetscessscsseeseeessasseeseseeseseeasesasaeees 2-3 Figure 2-2 =Evaluation Scenarios............::ccsscsscssssccssscccessncsssncessccesteceesaceeseceesaecssctecaeceesseeeessasaeeeens 2-7 Figure 2-3 Elements of Stakeholder Involvement Process..............sscssecsesecesseessssesescssesosesesoseeees 2-8 Figure 3-1 Summary of Issues Facing the Railbelt Region...ee ese eeseeceseessesesesesesesseeeseeeenes 3-1 Figure 3-2 Chugach's Reliance on Natural Gas .........cscsssssessseseccsscecseceecesecssessesesssseeseessenseoes 3-8 Figure 3-3 Overview of Cook Inlet Gas Situation...ec ecceccstesseeeteesesessscseeeseessesseseseeesenaes 3-8 Figure 3-4 -Historical Chugach Natural Gas Prices Paid .............ssccssssecssscesseceseesnsessecesasessseeceees 3-9 Figure 3-5 |Chugach Residential Bills Based on 700 kWh Consumption.....0......esesssecseseseseeeeee 3-9 Figure 4-1 Railbelt Existing Transmission System as Modeled...esesssseceeesesereeseeeseeeseeees 4-9 Figure 6-1 US Daily Driving Patterns .00.....ee eee ccceeeceeceessccsssecsccessecnsseessessseesaessesseeoeneseonees 6-6 Figure 6-2 PHEV Daily Charging Availability Profile 2.0.0...ccessscsscccssseceensesscsseeeseceseeseseoeces 6-6 Figure 6-3 Hourly Distribution of PHEV Load on a Typical Day -Alaska Railbelt bXt24(0)|eee 6-8 Figure 6-4 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Energy Requirement............:ccccssscssssssssssesscscsssssescscsssessssseccesesessussessnseaeens 6-8 Figure 6-5 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt System's Peak Demand...........cescseccessscessscceessressesessseccsesesssseecsescseessoseccausssssosssesseseees 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 .............eee 7-3 Figure 7-3 Comparison of Natural Gas Price Forecasts Relevant to Railbelt Resource PIANS........csccssccssesesescecccssscesccsccnsccsseesscesccsseessaaesssssesseecessseeseesessseseresesceecsesessssessevenesoss 7-8 Black &Veatch TC-11 December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Figures (Continued) Figure 9-1 Scenario 1A Capacity Requirements Without DSM/EE....0.....essesesessesseeenseseeensees 9-2 Figure 9-2 Scenario 1A Capacity Requirements With DSM/EE..........sssssscssccsesecssesseessesenees 9-3 Figure 9-3 Scenario 2A Capacity Requirements Without DSM/EE uu...sescessseseesseenecneeseesees 9-4 Figure 9-4 Scenario 2A Capacity Requirements With DSM/EE..............esesesseerscsssseeeeersseeeasees 9-5 Figure 9-5 Scenario 1A Capacity Requirements Including Committed Units Without DSMIEE ......eeesesseeccssceseesecsesseecesescarsscsccassacsscessccessseesssscsacesessserecssosseesssseseassessseseseansees 9-6 Figure 9-6 Scenario 1A Capacity Requirements Including Committed Units With DSMIEE........cscssccsscsssessesesseeessceaceecsacesceseneseseetscsaussaseccnsesesscceassesssessessssessocasensacessensenes 9-7 Figure 10-1 Proposed Susitna Hydro Project Location wu...eescssessssscsecseesecesesessssevsnssseseees 10-19 Figure 10-2.Proposed Chakachamna Hydro Project Location ............sssssssscetesecteceesseeseeeeseeeses 10-25 Figure 10-3 Blue Energy's Tidal Bridge With Davis Turbine...ceteseeesssseetsetseenenseeens 10-29 Figure 10-4 Cutaway Graphic of a Mid-Range-Scale Vertical Axis Tidal Turbine..........0.......10-30 Figure 10-5 Proposed Layout of the Turnagain Arm Tidal Project..........sscssssesceeseseseesseeees 10-30 Figure 10-6 Turnagain Arm Tidal Project Monthly Generation 00.0.0...eesesseessesseeseetectereeeees 10-31 Figure 10-7 Simplified Binary Geothermal Power Plant Process .........s:ssssssssssseseessetseeesseeeee LQ-33 Figure 10-8 Simplified Geothermal Combined Cycle Power Plant Process ..........sseseseseees 10-33 Figure 10-9 Estimated Mount Spurr Project Development Plan...ee cesssecseesessseeseeseeeeeee 10-35 Figure 10-10 Visual Simulation of Fire Island Wind Generation Project....eeesseeseeeeeeeees 10-37 Figure 10-11 Preliminary Site Arrangement and Interconnection Route...eeeecssececeeeteeeee 10-38 Figure 10-12 Kenai Peninsula,Nikiski.......ee eeesseeceesecceeeeseseeasessseceeceeensseseseeseeacseseasseeseees 10-39 Figure 10-13 Simplified Hyperion Power Cycle Diagram ...........ceesssssssssesecssesssesesctesessessseesers 10-41 Figure 10-14 Requested Potential Advanced Reactor Licensing Application Timelines ...........10-43 Figure 10-15 NRC New Licensing Process and Construction Timelines for New Reactors......10-44 Figure 11-1 Common DSM/EE Program Development Process ..........c.:seessesesssseeseseeseeserseneeees 11-7 Figure 11-2 EPRI/EEI Assessment:West Census Region Results .........csssssscsssesserssecseeveeseseoss 11-9 Figure 12-1 -Railbelt Transmission System Overview..........scsssccscsssesseessseeceecesceeseesstessenseneeees 12-2 Figure 12-2.New Soldotna to University 230 kV Transmission Line.............ccccsescecseecessseeeeees 12-4 Figure 12-3 Soldotna to Quartz Creek 230kV Transmission Line Upgrade .........ec eeeeeeeeeeeeeees 12-5 Figure 12-4 Quartz Creek to University 230kV Transmission Line Upgrade............sssssesssneeeee 12-6 Figure 12-5 New Lake Lorraine to Douglas 230 kV Transmission Line ..........sssscecsseenessesoes 12-7 Figure 12-6 Douglas to Healy 230 kV Transmission Line Upgrade ............esessescecteeeeereeeeeeeees 12-8 Figure 12-7 New Douglas to Healy 230 kV Transmission Lime ............eesessessseeseesneeseseeseeseees 12-9 Figure 12-8 New Beluga to Pt.Mackenzie 230 kV Transmission Line.............sscssssssseeseeeeeees 12-10 Black &Veatch TC-12 December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Figures (Continued) Figure 12-9 Douglas to Teeland 230 kV Transmission Line Upgrade...........cscssesssssessseeeseees 12-11 Figure 12-10 Healy to Gold Hill 230 kV Transmission Line Upgrade .......cc cescesscsrsesessssseseees 12-12 Figure 12-11 Healy to Wilson 230 kV Transmission Line Upgrade.........cccscsccscssesssceseeeees 12-13 Figure 12-12 Soldotna to Bradley Lake 115 kV Transmission Line Upgrade .........cccsssseseeeeee 12-14 Figure 12-13 New Daves Creek to Seward 115 kV Transmission Line..........ccssssssesesesseeseee 12-15 Figure 12-14 New Eklutna to Lucas 230 kV Transmission Line ........cccsescssssssssesserseeresseeeees 12-16 Figure 12-15 Lucas to Teeland 230 kV Transmission Line Upgrade ..........scsessssssessersessnereneees 12-17 Figure 12-16 New Lucas to Teeland 230 kV Transmission Line.............:cssssessssscsscsssvsssssennseees 12-18 Figure 12-17 Pt.Mackenzie to Plant 2 Transmission Line Rebuild...escsessecsesecereeeeeeees 12-19 Figure 12-18 Project Location .........ccessssssseceseceesesseseesseseceessseecossesssseceseecnsssossesssesensusecssesneeenses 12-21 Figure 13-1 Impact of DSM/EE Resources -Base Case Load Forecast.........cssscsesesssssersesreeesees 13-2 Figure 13-2 Results -Scenario 1A Base Case oo....tcssccsecssssesesssscesscsssscsssssccsecnsesenssensessesseeeneees 13-2 Figure 13-3 Results -Scenario 1B Base Case...tessssssssesesessssessssesscsssseeseseeesesscnseneesseeesenses 13-2 Figure 13-4 Results -Scenario 2A Base Case ........cccssssssesceseteccnsccssesessenssesssssessessnseeceeseeseesess 13-3 Figure 13-5 Results -Scenario 2B Base Case........cesssscssssssssesssssesesssecsssssessessseseeessceseeessceeeeeneees 13-3 Figure 13-6 Sensitivity Results -Scenario 1A Without DSM/EE Measures............ssssseseseseees 13-4 © Figure 13-7 Sensitivity Results -Scenario 1A With Committed Units Included...eeeeee 13-4 Figure 13-8 Sensitivity Results -Scenario 1A Without CO2 Costs.....scecssessecssssssesscereseseees 13-5 Figure 13-9 Sensitivity Results -Scenario 1A With Higher Gas Prices.........cesssssssessseeseseeeees 13-5 Figure 13-10 Sensitivity Results -Scenario 1A With Fire Island...esessssecsssseeseeeeeeseeseeeees 13-6 Figure 13-11 Sensitivity Results -Scenario 1A Without Chakachamina .........ccsssssssessessseereeees 13-6 Figure 13-12 Sensitivity Results -Scenario 1A With Susitna (Lower Low Watana Non- Expandable Option)Forced ............:cssssssccssssseseseseecsceseesssseseesssaseuseeseeseesnssoeaseeseesees 13-7 Figure 13-13 Sensitivity Results -Scenario 1A With Susitna (Low Watana Non- Expandable Option)Forced .0.........esccesscessesecccesessesseeessesscesssecsssceaseesesssecsscassseeseseess 13-7 Figure 13-14 Sensitivity Results -Scenario 1A With Susitna (Watana Expansion Option) FOred 00....eesecsstsessesecessesesacescncsscesccsesensesssnsceseeesseesesenassceonsasessesseseseesocssconsasaesesseneccenes 13-8 Figure 13-15 Sensitivity Results -Scenario 1A With Susitna (Watana Option)Forced..............13-8 Figure 13-16 Sensitivity Results -Scenario 1A With Susitna (High Devil Canyon Option) FOrced .....cessssssccesssssssscccsecessccssccsessesesesseseescseseceseecesseesecceessosescessessessenssnsesensssassesensees 13-8 Figure 13-17 Sensitivity Results -Scenario 1A With Modular Nuclear ........ccsssesssseseseeeeeees 13-9 Black &Veatch TC-13 December 2009 DRAFT REPORT TABLE OF CONTENTS ALASKA RIRP STUDY Table of Contents (Continued) Figures (Continued) Figure 13-18 Sensitivity Results -Scenario 1A With Tidal oc cssssssscsseesssesesstesessesseesenenees 13-9 Figure 13-19 Required Cumulative Capital Investment for Each Base Case...ssessssssssesceeseessees 13-15 Figure 13-20 Required Cumulative Capital Investment (Scenario 1A)Relative to Railbelt Utility Debt Capacity 0....cccstesssseseesseceecessesssscesssesesscesassasssssssssacessessnenssaseatseeons 13-16 Figure 15-1 Comparison of Results -Scenario 1A Versus Committed Units Sensitivity CSC...sesccessscscesccetssesssseseeeessnsesseessecossessessesssesesecaseseacccasenseessessnesenseseescssesasessennsesees 15-4 Figure 15-2 Interplay Between GRETC and Regional Integrated Resource Plan..............:0000+15-5 Black &Veatch TC-44 ;December 2009 DRAFT REPORT 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). 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 ©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 e 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”¢GRETC initiative is the joint effort between e RIRP means "Railbelt Integrated Railbelt Utilities and AEA to unify Railbelt G&T- Resource Plan”e RIRP is 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 December 2009 DRAFT REPORT SECTION I 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: e 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. e Gas Supply Investments and Contracts -ML&P took a bold step when it purchased a portion oftheBelugaRiverGasField,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. e 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 address issues that are unique to the Railbelt region.. e 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. The evolution of the business and operating environment,and changes in the mix of stakeholders,presents new dynamics for the way decisions must be made.This changing environment poses significant challenges for the Railbelt utilities and,indeed, all stakeholders.In fact,it is not an overstatement to say that the Railbelt is at a historical crossroad,not unlike the period of time when the Railbelt utilities were. originally formed. Categories of issues facing the Railbelt utilities include: e Uniqueness of the Railbelt region Cost issues Natural gas issues Load uncertainties Infrastructure issues Future resource options Political issues Risk management issues 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 Table 1-1 provides a listing of the issues within each of these categories.A detailed discussion of these issues is provided in Section 3. Black &Veatch 1-2 'DRAFT REPORT December 2009 EXECUTIVE SUMMARY ALASKA RIRP STUDY SECTION 1 Table 1-1 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 e Potential major new loads Political Issues e Historical dependence on State funding e 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 ¢Operating and spinning reserve requirements Risk Management Issues e Need to maintain flexibility e Future fuel diversity e Aging infrastructure e 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 - 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. e Projections for Railbelt electrical capacity and energy growth,fuel prices,and resource options. e An analysis 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 RIRP Objective Function Minimize regional power supply costs,and maintain or improve current reliability,as opposed to minimizing power supply costs for any individual utility. Black &Veatch 1-3 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY reliably under open access tariffs,and with a postage-stamp rate for electric energy and demand for the entire Railbelt as a whole. 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 VvRIRP 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 Includes 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 ¢A comprehensive list of current and future generation and transmission power infrastructure 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 createGRETCwitha10-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.Each contractor has prepared a report summarizing their work,which are included in Appendices A through C. 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&Veatch in the Strategist®and PROMOD®modeling discussed below. Electric Power Systems,Inc.(EPS)evaluated the system stability of the transmission and generation plans developed. Black &Veatch 1-4 December 2009 DRAFT REPORT 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 e =Lighting e =Shell e Cooling/Heating Commercial e Water Heating e Office Loads e Motors e =.Lighting ¢=Refrigeration Simple Cycle Combustion Turbines e LM6000 (48 MW) e LMS100 (96 MW) Combined Cycle e 1x1 6FA (154 MW) e 2X1 6FA (310 MW) Coal Units e 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 e BQ Energy/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 =Tidal 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. Additional information regarding Black &Veatch's approach to the completion of this study is provided in Section 2. Black &Veatch DRAFT REPORT December 2009 SECTION It 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 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. Black &Veatch 14 December 2009 DRAFT REPORT 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 a Base Case Scenario 1A Scenario 1B b§ 3 Le 8Ss 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 o Scenario 1B -Force 50%Renewables 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)0000000Black &Veatch 1-7 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 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%Renewables0000 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. e 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. ©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. e Section 9 -Capacity Requirements,including the region's capacity requirements over the 50-year planning horizon. e 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. e 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 HDR was contracted by the AEA to:1)update previous cost estimates,energy estimates,and schedules that were developed in the 1980s,2)develop smaller-sized alternatives to better match the Susitna resource with the capacity and energy needs of the region,and 3)evaluate the resulting economics of the project. According to an earlier HDR report,dated March 16,2009',several project development alternatives were considered in the 1980s: e Watana.This alternative consists of the construction of a large storage reservoir on the Susitna River at a site named Watana,with an 885-foot-high rock filled dam,and a powerhouse containing six turbines with a total installed capacity of 1,200 MW.©Low Watana.This alternative consists of the Watana dam constructed to alower height of 700 feet, along with a powerhouse containing four turbines,with a total installed capacity of 600 MW. '"Susitna Hydroelectric Project.Project Evaluation.Interim Memorandum.Final;”Prepared for AEA by HDR and Northern Economics;March 16,2009. Black &Veatch 1-8 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY ©Watana/Devil Canyon.This alternative consists of the full-height Watana development,plus a second reservoir located downstream at a site called Devil Canyon.This downstream reservoir would re-regulate river flow and be impounded by a 646-foot-high concrete dam.The Devil Canyon powerhouse would have an installed capacity of 680 MW.After the FERC license is issued,these two dams and powerhouses would be constructed sequentially without delays.The combined Watana/Devil Canyon developments would have an installed capacity of 1,880 MW. e Staged Watana/Devil Canyon (low height Watana,plus Devil Canyon,plus full-height Watana). This alternative would ultimately result in the same configuration as the previous alternative,but the Watana dam would be initially constructed to the lower height and the Watana powerhouse would only have four out of the six lower-head turbine generators installed.The Watana construction crew would demobilize and move downstream to construct the Devil Canyon dam and powerhouse,then either demobilize again,delay further construction,or return upstream to complete the Watana dam to its full height and install the remaining two units.The staged capacity of Watana would increase from 600 MW to 1,200 MW for a total project capacity of 1,880 MW. ¢Devil Canyon.This alternative consists of the Devil Canyon dam,without Watana dam,with a Devil Canyon powerhouse containing four turbines,with a total installed capacity of 680 MW.Note that Devil Canyon was intended to be a regulating dam,paired with the Watana reservoir.Without the larger upstream Watana reservoir,the Devil Canyon alternative would have minimal storage for providing power in winter. As the RIRP process defined the future Railbelt power requirements,it became evident that lower-cost options,that were a closer fit to the needs of the Railbelt region,should be sought.HDR's revised Susitna alternatives are presented in Table 1-3.Each alternative is described below. e Lower Low Watana.This alternative is a lower dam and corresponding smaller project than the Watana option.The height of the dam is about 50 feet less than the original Low Watana project. e Low Watana (Non-Expandable).This alternative represents the same sized dam as the original Low Watana project except that the dam is constructed with a smaller base,essentially eliminating the option to increase its height in the future. e Low Watana (Expandable).This is the same alternative as the original Low Watana project. ©Watana.This is the same alternative as the original Watana project. e High Devil Canyon.This alternative is a dam between the original Watana and Devil Canyon projects.With this configuration neither the original Devil Canyon or Watana projects would be possible. In addition to developing smaller projects,HDR evaluated cost reduction measures for the original Low Watana (Expandable)and Watana alternatives.For the revised list of alternatives,only Low Watana (Expandable)and Watana allow for the ultimate development of the Susitna River comprised of High Watana and Devil Canyon. The detailed results of the HDR Susitna study are provided in Appendix A.This report provided the basis for the Susitna-related input assumptions that were used in the RIRP modeling. 1.6 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. Black &Veatch 1-9 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-3 HDR Analysis of Watana and High Devil Canyon Alternatives Low Watana : Lower Low (Non-Low Watana High Devil Watana Expandable)(Expandable)Watana Canyon Gross Head (ft)495 557 557 734 729 Net Head (Max Flow)481 543 543 729 707 (ft) Maximum Plant Flow 10,700 14,500 14,500 22,300 14,800 (cfs) Number of Units 3 4 4 6 4 Nameplate Capacity 380 600 600 1200 800 (MW) Firm Capacity (98%)170 245 245 380 345 (MW) Min.Capacity (MW)65 75 75 100 100 Average Annual 2,000 2,600 2,600 3,700 3,900 Energy Production (GWh) Dam Height*(ft)650 700 700 885 855 Cost (2008 $)$4,100,000,000 $4,500,000,000 |$4,900,000,000 |$6,400,000,000 $5,400,000,000 Maximum Pool 1,950 2,014 2,014 2,193 1,750 Elevation (ft) Minimum Pool 1,850 1,850 1,850 2,065 1,605 Elevation (ft) Tailwater Elevation 1,456 1,457 1,457 1,459 1,022 (Max Flow): (ft) Usable Storage (acre-1,536,200 2,704,800 2,704,800 3,888,500 2,254,700 ft) *Height of dam crest above foundation.Foundation elevation assumed to be 1,325”for Low Watana and 895'for High Devil Canyon as defined in the 1982 Acres feasibility study. **Cost estimated by R&M. Black &Veatch DRAFT REPORT 1-10 December 2009 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 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 assets 69 kV and above.These assets,over a transition period,would 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 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 projects to connect new generation projects to the grid (Generation Interconnections) e Transmission projects to upgrade the grid required by the new generation projects (Generation Upgrades) ¢Replacement projects that need to be done because of age and condition (Replacement) ®Upgrade projects to the grid to implement the GRETC concept,based on existing generation (GRETC) 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 Current RIRP Stud the RIRP analysis.We begin by Situation e Plan that economically providing a summary of the ©Limited redundancy schedules what,when, base case results for each of the a and where to build,based ..*Limited economies on available fuel andfourEvaluationScenarios.We of scale energy supplies then provide eae d *Dependence on *50-year time horizon RIRP summ of the economic an i:ary |fossil fuels ¢«Competes generation,Resultsemissionresutsforallbase.*Limited Cook Inlet transmission,fuel supply *Increased cases and sensitivity cases.This gas deliverability and DSM/energy DSM/energy is followed by a summary of the and storage efficiency options efficiency results of the transmission »Aging G&T |*Includes CO,regulation |*Increased analysis that was completed infrastructure "|©Includes renewable "|renewables and,finally,the results of the *Inefficient fuel use energy projects *Reduce financial analysis.More detailed |+Difficult financing *Arrives at a plan to build on natural gasinformationregardingthe*Duplicative G&T future infrastructure for to );.: -*IncreaseresultsoftheRIRPstudyisexpertiseratepayerstransmission provided in Section 13.«Considers fuel supply options and risks Black &Veatch 1-11 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.7.1 Results of Base Cases In this subsection,we provide summaries of the base 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 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 four Evaluation Scenarios.Detailed model output for each of the base cases are provided in Appendices F-I. 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 DSM/EE measures were selected forinclusionintheRIRPmodels,Strategist®and PROMOD®,as potential resources to be selected. Based upon the relative economics of these screened residential and commercial DSM/EE measures,they were selected at the maximum limits in each of the four Evaluation Scenarios.As discussed in Section 11, these maximum limits were based on technology adoption curves for DSM/EE studies from the BASS model;additionally,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. As can be seen in Figure 1-2,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. Figure 1-2 Impact of DSM/EE Resources -Base Case Load Forecast Oemand (MW)Energy Requirements (MWh) -Without DSM/EE -Without DSM/EE 4,400 With DSM/EE 8,000,000 |-With DSM/EE »7,000,0001,200 g 6,000,000 -<---4,000 _=[=:=5,000,000=800 e2®4,000,000&600 Fa8@ 3,000,000400&B 2,000,000200&1,000,000 0 berry xsc¥ereseeeeaesseregee288 0 A AA rere==2RRRARARNNRANARAANNSeRRSSSSSSESE8888 Year NNN NN NN NNN NNN NN NSN ON Year Black &Veatch 1-12 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.7.1.2 Results -Scenario 1A Base Case Figure 1-3 'Results --Scenario 1A Base Case Capacity By Resource Type =Ocean Tidal Energy By Resource Type1600wWind7000 WMuricipal Solid Waste] a Geothermal Hydro =Ocean TidalmPurchasePowermwWind==Fuel Oil z mMuricipal Solid Waste2mNuclearg GeothermatFfwCoal2Hydrofi]Natural Gas 3 Purchase Power :iu Fue!Oil -.mNuclear Y mCoat i Natural Gas. SERERRSEBSSFR 8228 Ove nee 2aua &22 eRRRARRRRARRRRRRReeeRS88828222222 1.7.1.3 Results -Scenario 1B Base Case Figure 1-4 Results -Scenario 1B Base Case 4600 Capacity By Resource Type 7000 Energy By Resource Type 1400 " Ocean Tidal Ocean TidalaWindwwind Municipal Sold Waste z |Muricipal Solid Waste =Geothermal 4 a Geothermal Hydro g Hydro mPurchase Power é =Purchase Power Fuel Oil 4 Fuel Oil mNuclear sNucear :wCoal sCoalJmNaturalGasBNatualGas t) -EEF ERBRRSBSABRBE $382883 1.7.1.4 Results -Scenario 2A Base Case Figure 1-5 Results -Scenario ZA Base Case Capacity By Resource Type3000 44000 Energy By Resource Type 2500 .mo 12000 ' Ocean Tidal |@ Ocean Tidal 2000 aWnd 40000 @ Wind =mMuricipal Sold Waste .Municipal Sof Waste| >Geothermal Fa 1 GeothermalHydroriHydroi+,s Purchase Power i @ Purchase Power°BE uel Oil =FuelOilmNuclear@Nuclear aCoal a mCoal sNatural Gas 2000 4 LP 3 ts {a NaturalGas t) EZERSSREESBBEFTERBRSERBSRRRRRARKRKRRRRKRKRARAKRAR Black &Veatch 1-13 December 2009 DRAFT REPORT ALASKA RIRP STUDY 1.7.1.5 Results -Scenario 2B Base Case Figure 1-6 Results -Scenario 2B Base Case 3500 Capacity By Resource Type 4000 Energy By Resource Type 12000 ™Ocean Tidal |-@ Ocean Tidal wWind 10000 =Win @ Municipal Solid Waste g mw Municipal Solid Waste! @ Geothermal &8000 ®Geothermal Hydro 8 Hydro.w Purchase Power uy @ Purchase PowerwFue!oil wi on +fa FuelOil .+|@ Nuclear a a +Ges Nuclear ie a :@Coa!.J."Hie coat ne L .pin @ Nata!Gas .'.7 24 @ NaturalGas A :ae 0 a seitsaoetas ezk 3 2a =seg rsXs tssgeskBSBSBSE §388 8 3SSSRSRES852228828geefSi82228822228 1.7.2 Sensitivity Cases Evaluated The following sensitivity cases were evaluated: 1.7.3 Scenario 1A Without DSM/EE Measures Scenario 1A With Committed Units Included Scenario 1A Without CO,Costs Scenario 1A With Higher Gas Prices Scenario 1A With Fire Island Scenario 1A Without Chakachamna Scenario 1A With Chakachamna Capital Costs Increased by 75% Scenario 1A With Susitna (Lower Low Watana Non-Expandable Option)Forced Scenario 1A With Susitna (Low Watana Non-Expandable Option)Forced Scenario 1A With Susitna (Low Watana Expandable Option)Forced Scenario 1A With Susitna (Low Watana Expansion Option)Forced Scenario 1A With Susitna (Watana Option)Forced Scenario 1A With Susitna (High Devil Canyon Option)Forced Scenario 1A With Modular Nuclear Scenario 1A With Tidal Summary of Results -Economics and Emissions In this subsection,we provide a comparative summary of the economic and emissions results for all of the base cases and sensitivity cases. 1.7.3. Table 1.Summary of Results -Economics 1-4 summarizes the economic results,including: Cumulative present value cost Average cost Renewable energy in 2025 Total capital investment Black &Veatch 1-14 DRAFT REPORT December 2009 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-4 Summary of Results -Economics Cumulative Renewable Present Value Average Cost Energy in 2025 Total Capital Case Cost ($000)(¢per kWh)(%)Investment ($000) Scenarios Plan 1A $12,924,812 4.60 49.17%$10,034,684 Plan 1B $12,916,210 4.59 54.78%$10,014,163 Plan 2A $20,977,580 4.29 53.57%$18,226,355 Plan 2B $21,506,536 4.40 55.55%$22,174,689 Sensitivities 1A Without DSM/EE Measures $13,261,877 4.40 51.10%$9,791,215 1A With Committed Units Included $13,863,265 4.93 32.03%$9,592,461 1A Without CO,Costs $10,401,631 3.70 14.36%$8,684,957 1A With Higher Gas Prices $14,944,729 5.31 61.94%$9,797,961 1A With Fire Island $12,964,719 4.61 54.78%$10,502,023 1A Without Chakachamna $13,273,472 4.72 22.80%$9,179,428 1A With Chakachamna Capital Costs Increased $13,273,472 4.72 22.80%$9,179,428 by 75% 1A With Susitna (Lower Low Watana Non-$15,208,996 5.41 54.70%$13,166,343 Expandable Option)Forced . 1A With Susitna (Low Watana Non-Expandable $14,898,313 5.30 60.18%$14,742,083 Option)Forced 1A With Susitna (Low Watana Expandable $15,437,027 5.49 60.18%$15,273,597 Option)Forced 1A With Susitna (Low Watana Expansion $15,943,324 5.67 61.58%$15,901,641 Option)Forced 1A With Susitna (Watana Option)Forced $16,281,157 5.79 61.82%$16,049,421 1A With Susitna (High Devil Canyon Option)$16,238,375 5.77 61.82%$16,016,000 Forced 1A With Modular Nuclear $12,590,556 4.48 49.05%$9,864,041 1A With Tidal $12,198,214 4.34 59.10%$10,051,986 Black &Veatch 1-15 December 2009 DRAFT REPORT EXECUTIVE SUMMARY ALASKA RIRP STUDY SECTION 1 1.7.3.2 Summary of Results -Emissions Table 1-5 summarizes the emissions-related results of all of the base and sensitivity cases.The following information is provided for each case: e CO,emissions e NO,emissions e SO,emissions DRAFT REPORT Table 1-5 Summary of Results -Emissions Icase CO,(tons)NO,(tons)SO,(tons) Scenarios Plan 1A 176,204,623,551 222,216,367 36,328,052 Plan 1B 169,439,541,486 216,377,884 33,078,058 Plan 2A 287,320,716,438 281,021,636 240,492,147 Plan 2B 250,459,659,924 245,372,307 74,838,100 Sensitivities 1A Without DSM/EE Measures 181,207,564,318 181,207,564,318 |181,207,564,318 1A With Committed Units Included 219,645,268,063 350,850,044 272,682,069 1A Without CO,Costs 222,613,806,040 294,549,974 382,983,114 1A With Higher Gas Prices 166,406,292,550 248116046.4 267852556.4 1A With Fire Island 166,934,231,133 223442326.3 38607718.2 1A Without Chakachamna 219,109,779,504 222,591,795 34,949,762 1A With Chakachamna Capital Costs 219,109,779,504 222,591,795 34,949,762 Increased by 75% 1A With Susitna (Lower Low Watana Non-158,703,320,276 209,771,548 35,377,946 Expandable Option)Forced 1A With Susitna (Low Watana Non-127,589,064,780 207,145,332 37,742,698 Expandable Option)Forced 1A With Susitna (Low Watana Expandable 127,589,064,780 207,145,332 37,742,698 Option)Forced 1A With Susitna (Low Watana Expansion 140,911,597,135 207,888,578 37,953,070 Option)Forced 1A With Susitna (Watana Option)Forced 138,140,275,780 208,616,774 39,419,567 1A With Susitna (High Devil Canyon 134,779,936,034 208,259,687 39,406,754 Option)Forced 1A With Modular Nuclear 162,857,677,754 223,697,768 37,028,776 1A With Tidal 153,908,430,292 212,576,692 33,361,540 Black &Veatch 1-16 December 2009 SECTION 1 EXECUTIVE SUMMARY 1.7.4 Results of Transmission Analysis Table 1-6 lists the recommended 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. ALASKA RIRP STUDY Table 1-6 Recommended Transmission Projects No.|Transmission Projects Type Cost ($000)Priority 1 Soldotna -University New Build (230kV)$161,250 1 2 Soldotna -Quartz Creek Upgrade (230kV)$84,000 1 3 Quartz Creek -University Upgrade (230kV)$112,500 1 4 Lake Lorraine -Douglas New Build (230kV)$46,200 2 5 Douglas -Healy Upgrade (230kV)$12,000 2 6 Douglas -Healy New Build (230kV)$252,000 3 7 Beluga -Pt.Mackenzie New Build (230kV)$67,700 3 8 Douglas -Teeland Upgrade (230kV)$37,500 3 9 Healy -Gold Hill Upgrade (230kV)$145,500 4 10 |Healy -Wilson Upgrade (230kV)$145,500 4 11 Soldotna -Bradley Lake Upgrade (115kV)$61,800 ©4 12 j Daves Creek -Seward New Build (115 kV)$28,000 4 13 |Eklutna-Lucas New Build (230kV)$13,300 5 14 |Lucas -Teeland Upgrade (230kV)$26,100 5 15 |Lucas -Teeland New Build (230kV)$26,100 5 16 |Pt.Mackenzie -Plant 2 Replacement (230kV)$32,200 6 Biack &Veatch 1-17 December 2009 DRAFT REPORT SECTION I EXECUTIVE SUMMARY ALASKA RIRP STUDY A diagram that shows the location of the recommended transmission system enhancements is shown in Figure 1-7, Figure 1-7 Location of Recommended Transmission Projects sae x Meet S2OKY zC1r 'a aC ee gsubyAS ARACA ARN ADRG2025 AULTSeFSWARO 5 eV The following issues result from our transmission analysis: e We were unable to complete a stability analysis based upon our recommended transmission system configuration prior to the development of this Draft Report.This analysis is required to ensure that the recommended transmission system expansions and enhancements result in the necessary stability to ensure reliable electric service over the planning horizon.The results of the stability analysis may result in some modifications to our recommended list of transmission projects.This analysis is currently underway by EPS and the results will be included in the Final Report. Black &Veatch 1-18 December 2009 DRAFT REPORT 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: o Providing reactive power (static var compensators --SVC) ©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) Several of these projects have been identified and discussed while others will result from the transmission reliability assessment to be done by EPS.Potential projects in this category include: o Substation capacitor banks Series capacitors SVCs Battery energy storage systems 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 much provide 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,the costs for each such system were included in the analysis. ©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 discussion 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 for 230 kV and review a transmission routing for the new Southern Intertie that would begin at the Soldotna 230 kV substation to Bernice Lake substation along the Kenai 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 University 230 kV substation. 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.0000Black &Veatch 1-19 December 2009 DRAFT REPORT SECTION I EXECUTIVE SUMMARY ALASKA RIRP STUDY 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. Figure 1-8 Required Cumulative Capital Investment for Each Base Case Cumulative Capital Investment -$25,000,000 --Scenario 1A -Scenario 1A $20,000,000 i f ,000,--Scenario 2A-«Scenario 2B _Z$15,000,000 a $10,000,000 f ee $5,000,000 ft $0 +CumulativeCapitalInvestment($000,000To 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 and federal financing resources with debt capital market resources. ¢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 C. 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 thereis no ability for a municipality or cooperative utility to independently secure debtfinancingwithoutcommittingsubstantialamountsofequityofcashreserves. 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 theRailbeltutilities,adjusted for inflation over time. Black &Veatch 1-20 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Figure 1-9 Required Cumulative Capital Investment (Scenario 1A)Relative to Railbelt Utility Debt Capacity $10,000,000,000 Capital Expenditures rs$7,500,000,000 $5,000,000,000 High Debt Capacity $2,500,000,000 So Low Debt Capacity $0 PUTTETTITTETETPTTrrrr rrr rrr rrr rryrrrrr rir iri i rirry. arm Oo MM FE AN YD Ot remem naAamtNNNNOMNYOSTPFFHoooOGDCOCOfFFGeeGeSFGSOSFGSS&S 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,and will have lower-cost access to debt capital than the utilities would have on their own. e 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 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 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 funding technique 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. o State Financial Assistance -State financial assistance could take a variety of forms;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 potentially lower cost of capital. Black &Veatch 1-21 December 2009 DRAFT REPORT SECTION I EXECUTIVE SUMMARY ALASKA RIRP STUDY e The overall objective of SNW's analysis was to identify ways to overcome the funding challenges inherent with large-scale projects and develop strategies that could be used to produce levelized power cost 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 would be immediately passed through to the ratepayers;the projects being financed in the second half of the 50-year period would be financed through "pay go”capital,as debt service coverage from previous years has grown to sufficient levels to allow the balance of the reserve 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,structured in a manner similar to the Bradley Lake 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). e Under the base case,the maximum fixed charge rate on the capital portion aloneis estimated to cost $0.13 per kWH,while theaverage fixed charge rate over the 50-year periodis $0.07 per kWh.In the alternative case,the maximum fixed charge rate on the capital portion aloneis $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 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,that would be a necessary next step towards achieving the goal of ensuring future reliable energy for the Railbelt region. 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 DSMEEE,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. 1.8.1 General Risks and Issues General issues and risks related to the implementation of the RIRP include the following: e Organizational,including: ©The lack of a regional entity with the responsibility for implementing the RIRP will lead to suboptimal solutions,resulting in higher costs,lower reliability and the inability to manage the successful integration of DSM/EE 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. Black &Veatch 1-22 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY 1.8.2 ALASKA RIRP STUDY o Fuel supply risks,including the future deliverability and price of natural gas. o 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. 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. 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 *Desired grid cannot be justified solely on economics *Siting and permitting issues Transmission Constraint Risks -the risk that the ability to move power from a 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 and legislative issues could affect the economic feasibility of specific resource options. Black &Veatch 1-23 DRAFT REPORT December 2009 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-7 Resource Specific Risks and Issues -Summary Relative Magnitude of Risk/Issue 3 z 3 =23 3 =3 2 3 2 -a2]%s e 4 A 4 o go c-]°io Z [4Ra2=2 at Pe2es=E 2.8 ey 323ge%5 s gs F a333Ses3£2 8 S 5 "Sp&re 5 a 2 a)5 og Resource me a AOo ie ag 4 BO ee a DSM/EE Moderate Limited N/A N/A N/A Limited -Moderate Moderate Generation Resources Natural Gas Limited Limited Significant |Moderate Limited Moderate Moderate Coal Limited Moderate-Limited Moderate -|Limited-|Moderate -ModerateSignificantSignificant|Significant |Significant Modular Nuclear Limited Significant Moderate Significant Limited Significant Significant Large Hydro Limited Significant N/A Significant }Significant |Significant Significant Small Hydro Moderate Moderate N/A Moderate Moderate Limited -Limited Moderate Wind Moderate Moderate N/A Limited Moderate Limited -Limited Moderate Geothermal Moderate Moderate N/A Moderate |Moderate-{Limited -Limited Significant |Moderate Solid Waste Limited Moderate-N/A Significant {|Moderate Limited -Limited- Significant Moderate Moderate Tidal Limited Significant N/A Significant |Moderate-|Moderate-|Moderate -Significant |Significant Significant Transmission Limited Significant N/A Moderate N/A Significant Moderate - Significant Black &Veatch 1-24 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 1.9 Conclusions and Recommendations 1.9.1 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 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.00000002.The 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 that may result from proposed Federal legislation. o The region's limited 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. 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.0000Black &Veatch 4-25 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 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 geotechnical conditions under which a large hydroelectric project could be built.Ifa 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. 5.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 did go down.The cost of Scenario 2B was 3.7 percent lower than Scenario 1A;Scenario 2B was 1.3 percent lower than Scenario 1B. 6.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; 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 1-10 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 12.5 percent higher than Scenario 1A.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. 7.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. 8.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 1-26 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Figure 1-10 Comparison of Results -Scenario 1A Versus Committed Units Sensitivity Case 3,000,000 ---Scenario 1A With Committed Units 2,500,000 -Scenario 1A Base Case 7 2,000,000 =me 1,500,000 ao 1,000,000 Zao.500,000 Pea AnnualCostofPower($000,000)<- TT TTT TTT ot Noon Xt DO Pd ©O@ ab ©&SW Ww NA OS ©©O&NINE ON OP OV LW OD mS or ok BPoo”LP ©PPP FF KK SF SF KF FF SH KY KY FH 9.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 place a maximum limit on the amount of these resources that can be developed. 10.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 adversely affect 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 1-11. Black &Veatch 1-27 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Figure 1-11 Interplay Between GRETC and Regional Integrated Resource Plan Current RIRP Study REGA Study Situation *Plan that economically |4 schedules what,when,+Limited redundancy and where to build,based *Limited iT ilabte fuel and 2,.ose energy suppies Proposed Future Situation *Dependence on *50-year time horizon RIRP GRETC +Robust transmission fossil fuels +Competes generation,Results Formation *Diversified fuel supply *Limited Cook Inlet transmission,fuel supply «Increased *System-wide power ratesgasdeliverabilityandDSM/energy OSM/energy ' and storage efficiency options efficiency «Spread risk »Aging G&T *Inctudes CO,regulation »Increased 1 *State financial assistance infrastructure *|.includes renewable ,renewables GRETC -Enabler >|«Regional planning +Inefficient fuel use energy projects +Reduce +Wise resource use ..dependence©Difficult financing »Arrives at a plan to build . =Duplcetive GAT future infrastructure for on natural gas noate large loadPee.minimum long-run costto +Increased Financing Optionsexpertiseratepayerstransmission *Technical resources «Pre-funding of capital .+Considers fuel supply requirements +_New technologies options and risks «Commercial bond market »State financial assistance (Bradtey Lake model) *Constuction-work-in-progress. 10-Year Transition Period 1.9.2 Recommendations 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. 2.The State should establish certain energy-related policies,including: o The pursuit of large hydroelectric facilities o DSMEEE 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 o System benefit charge to fund DSM/EE programs and or renewable projects Black &Veatch 1-28 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 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 base 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 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 1B resource plan during the first 10 years. Other projects selected in Scenario 1B after the first 10 years especially worthy of mention are the Mt.Spurr Geothermal Project in 2021 and Chakachamna Hydroelectric Project in 2025.Comparison of Scenarios 1A and 1B indicated they are identical until 2021 except for timing of the Anchorage LM6000 and the GVEA 1x1 7FA Combined Cycle.Scenario 1B selects Mt.Spurr in 2021;whereas, Scenario 1A delays it until 2030.The earlier selection of geothermal in Scenario 1B enhances its fuel diversity.Chakachamna is selected in 2025 in both scenarios.As indicted in Section 13,the cost difference between Scenarios 1A and 1B is only 0.07 percent,which is well within the noise of the models. Another important consideration of the selection of a preferred resource plan is consideration 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,Table 1-10 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? What is the effect if the committed units are installed? What if Chakachamna doesn't get developed? What would be the impact of the alternative Susitna projects? Should the Fire Island Wind Project be developed?0000There are several projects that are significantly under development that are considered in the preferred resource plan or in the sensitivity cases.These significantly developed projects include: o Healy Clean Coal Project (HCCP) ©Southcentral Power Project o Fire Island Wind Project o Nikiski Wind Project These projects are discussed in Table 1-10. Black &Veatch 1-29 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-8 Resources Selected in Scenario 1B Resource Plan Project Discussion DSM/EE Resources The full level of DSM/EE resources evaluated was selected based upon their relative economics. Anchorage and GVEA MSW|The RIRP selected these units in the first two years of the planning period.Units 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. Anchorage 1x1 6FA The RIRP selected this unit for commercial operation in 2013.This unit is Combined Cycle 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 The RIRP selected this project for commercial operation in 2015,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. Nikiski Wind The RIRP selected this project in 2017.It is being developed as an IPP project and is well along in the development process.The American Recovery and Reinvestment Act of 2009 (ARRA)potentially offers significant financial incentives if this project is completed by January 1,2013. These incentives could potentially improve its competitiveness.As a wind unit,it has no impact on planning reserves,but contributes to renewable generation. Anchorage LM6000 Simple |The RIRP selected this project in 2018.The unit can be dual-fueled,thusCycleCombustionTurbineprovidingfirmcapacityintheeventofanynaturalgasshortage.As a simple cycle combustion turbine unit,the lead time requirements are relatively short, leading to greater flexibility. GVEA 1x1 6FA Combined |The RIRP selected this project for commercial operation in 2020 in GVEA'sCycleserviceareaafternaturalgasisassumedtobeavailabletoFairbanks. Baseload natural gas-fired combined cycle energy in GVEA's service area relieves import requirements on the Intertie.As a conventional unit,its schedule can be coordinated with the schedule for natural gas availability in Fairbanks. Black &Veatch 1-30 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-9 Impact of Selected Issues on the Preferred Resource Plan Effect on Preferred Resource Issue Discussion Plan CO,The sensitivity case for Scenario 1A without CO,The preferred resource plan Regulation regulation selects the Healy Clean Coal Project instead |maintains the development of of Glacier Fork and Nikiski Wind in the first 10 years.Glacier Fork which has It also does not select Mt.Spurr.The sensitivity case significant uncertainty associated also delays Chakachamna until 2030.The sensitivity with it. case does not meet the 50 percent renewable target by 2025. Committed Installation of the committed units significantly The preferred resource plan Units increases the cost of Scenario 1A or 1B.The plan with |maintains the development of the committed units selects six wind units from 2019 Chakachamna which has through 2024 in response to CO,regulation.The plan significant uncertainty associated with the committed units eliminates Chakachamna and _|with it. does not meet the 50 percent renewable target by 2025. Chakachamna |Chakachamna could fail to develop because of licensing |The preferred resource plan or technical issues.Also,if the cost of Chakachamna maintains the development of were to increase to be equivalent to the alternative Chakachamna which has Susitna projects on a $/MW basis,it would not be significant uncertainty associated selected.The sensitivity case without Chakachamna for |with it. the first 10 years is identical to Scenarios 1A and 1B except the timing of Nikiski Wind and Glacier Fork are interchanged.The case does not meet the 50 percent renewable target by 2025 and is2.7 percent higher in cost than the preferred resource plan. Susitna None of the alternative Susitna projects are selectedin |The preferred resource plan the Scenarios 1A or 1B.The least cost Susitna option, which is Low Watana,is 15.3 percent more than the preferred resource plan and 12.2 percent more than the case without Chakachamna.The 50 percent renewable requirement can not be met without Susitna if Chakachamna is not available. recommends pursuing the development of a Watana project until there is resolution on the development potential for Glacier Fork and Chakachamna. Fire Island Fire Island was not in either Scenario 1A or 1B based on its total cost.When a sensitivity case was conducted,which included consideration for the benefits from the ARRA and the $25 million grant for interconnection from the State,the cost of the Fire Island case was essentially equal to Scenario 1A (0.3 percent higher),which is within the feasible range for a purchase power agreement.The plan with Fire Island includes the same units for the first 10 years as the preferred resource plan with minor differences in timing and includes Chakachamna in 2025. The preferred resource plan is virtually the same as the plan with Fire Island. Black &Veatch 1-34 DRAFT REPORT December 2009 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-10 Projects Currently Under Development Project Discussion Preferred Resource Plan Recommendation HCCP HCCP is completed and GVEA has Due to the operating cost risks associated with negotiated with AEA for its purchase.The project is part of the least cost scenario when CO,costs are not considered.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.HCCP adds further fuel diversity to the Railbelt,especially to GVEA who doesn't currently have access to natural gas,nor is there any other coal-fired generation included in the preferred resource plan.As a steam unit,HCCP improves transmission system stability. the possible enactment of CO,legislation, Black &Veatch does not recommend that HCCP be included in the preferred resource plan at this time.HCCP is currently being held in mothball status;Black &Veatch recommends that this condition be maintained for the foreseeable future until such time as it becomes clear whether CO,regulations are enacted and the resulting economic impact on the plant can be determined. 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.When these benefits are considered,the project comes close to being part of the least cost scenario.Since the project is an IPP project instead of direct utility ownership,there are other factors such as risk of performance which may result in additional benefits. 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. 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 1-32 DRAFT REPORT December 2009 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY In addition to these resources,Black &Veatch believes that 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. 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. 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 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 provided 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. 8. 9. Develop a comprehensive region-wide portfolio of DSM/EE programs. Generation projects: Generic Anchorage MSW Project Generic GVEA MSW Project Glacier Fork Hydroelectric Project Chakachamna Hydroelectric Project Susitna Hydroelectric Project Projects under development (HCCP,Southcentral Power Project,Fire Island Wind Project,and Nikiski Wind Project)000000Black &Veatch 1-33 December 2009 DRAFT REPORT SECTION 1 |EXECUTIVE SUMMARY 10. ALASKA RIRP STUDY Transmission and related substation projects,including the following Priority 1 and 2 projects (note: the timing and priority of these projects may change based on additional detailed analysis): ©Soldotna-University (new build) Soldotna-Quartz Creek (upgrade) Quartz Creek-University (upgrade) Lake Lorraine-Douglas (new build) Douglas-Healy (upgrade) Regional battery system for frequency regulation00000 1.9.2.3 Recommendations -Other Other actions,related to the implementation of the RIRP,that should be undertaken include: 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. The State Legislature should appropriate funds for the initial stages of the development of a regional DSMELEE 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 DSM/EE programs and renewable projects. 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. 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. Federal legislative and regulatory activities,including those related to emissions regulations,should be monitored closely. Black &Veatch 1-34 December 2009 DRAFT REPORT SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY 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 Supporting studies and activities 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 RIRP”.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 1-35 December 2009 DRAFT REPORT 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 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 Establish State energy-related policies regarding: o The pursuit of large hydroelectric facilities o DSMC/EE program targets o RPS (i.e.,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 The State should work closely with the Railbelt utilities and other stakeholders to establish the preferred resource plan,using the Scenario 1B resource plan as the starting point 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 these projects could actually be built 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 2010 2010-2011 2010 2010-2011 2010-2011 2010-2011 $6.8 million $0.2 million Not Applicable To be determined $0.1 million Not Applicable Black &Veatch DRAFT REPORT 1-36 December 2009 SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Table 1-11 (Continued) Near-Term Implementation Action Plan -General Actions Actions Category Description Timeline Est.Cost e The electric utilities,various State agencies,Enstar and 2010-2012 To be Cook Inlet producers need to work more closely together determined 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 ©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 Black &Veatch 1-37 December 2009 DRAFT REPORT 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 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: Generic Anchorage MSW Project Generic GVEA MSW Project Glacier Fork hydroelectric project Chakachamna Hydroelectric Project Susitna Hydroelectric Project Projects under existing development (HCCP, Southcentral Power Plant,Fire Island Wind Project, and Nikiski Wind Project) e Begin detailed engineering and permitting activities 2011-2016 Varies by associated with the transmission projects identified in project the initial years of the preferred resource plan, including: o Soldotna-University (new build) Soldotna-Quartz Creek (upgrade) Quartz Creek-University (upgrade) Lake Lorraine-Douglas (new build) Douglas-Healy (upgrade) Regional battery system for frequency regulationo0o0o000o0000 Black &Veatch 1-38 December 2009 DRAFT REPORT 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 millionStudiesandinitialstagesofthedevelopmentofaregionalDSM/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 a regional DSM/EE program measurement and 2012 $0.1 million evaluation protocol e 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 e¢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 ®Develop a regional frequency regulation strategy for non-2011 $0.5 million dispatchable resources , e Develop a regional standard power purchase agreements 2011-2012 |$0.2 million for IPP-developed projects ©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 1-39 December 2009 DRAFT REPORT 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 e Formaregional 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 e 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 e Aggressively pursue available Federal funding for 2010-2011 $0.2 million DSMIEE programs e Form aregional entity (if GRETC is not formed)or rely 2011-2012 Subject to on IPPs to identify and develop renewable projects that are decision included in the preferred resource plan regarding formation of GRETC e Monitor Federal legislative and regulatory activities,Ongoing Not including those related to emissions regulations Applicable e Aggressively pursue available Federal funding for 2010-2012 |$0.2 million renewable projects e Develop streamlined siting and permitting processes for 2010-2011 |$0.5 million transmission projects Black &Veatch 1-40 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY 10.0 SUPPLY-SIDE OPTIONS The purpose of this section is to summarize the input assumptions that Black &Veatch used related to the various supply-side resource options considered in the RIRP study.Information is provided for both conventional technologies and renewable resources. 10.1 Conventional Technologies 10.1.1.Introduction This subsection describes and characterizes various conventional supply-side technologies including General Electric (GE)LM6000 and LMS100 simple cycle units,GE 6FA combined cycle units and a 130 MW pulverized coal (PC)facility.In addition to greenfield developments,the option of repowering Beluga Unit 8 has been considered. 10.1.2.Capital,and Operating and Maintenance (O&M)Cost Assumptions The capital cost estimates developed in this report include both direct and indirect costs.An allowance for general owner's cost items (exclusive of escalation,financing fees,and interest during construction),as summarized in Table 10-1,has been accounted for in the cost estimates or provided as a percentage of total costs.The capital cost estimates were developed on an engineer,procure,and construct (EPC)basis. The O&M cost estimates were derived from proprietary Black &Veatch O&M estimating tools and representative estimates for similar projects.Costs are based on vendor estimates and recommendations,and estimated performance information.The cost estimates are divided into fixed and variable O&M.Fixed O&M costs,expressed as dollars per unit of capacity per year ($/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 Assumptions Unless otherwise discussed,the following general assumptions were applied in 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 10-1 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-1 Possible Owner's Costs Project Development e =Site selection study e Land purchase/rezoning for greenfield sites e -Transmission/gas pipeline right-of-way e Road modifications/upgrades e Demolition e Environmental permitting/offsets e Public relations/community development e -_Legal assistance e Provision of project management Spare Parts and Plant Equipment e¢Combustion turbine materials,gas compressors,supplies,and parts e Steam turbine materials,supplies,and parts e Boiler materials,supplies,and parts e _Balance-of-plant equipment/tools e =Rolling stock e Plant furnishings and supplies Plant Start-up/Construction Support @ Owner's site mobilization e O&M staff training e Initial test fluids and lubricants e Initial inventory of chemicals and reagents e Consumables *Cost of fuel not recovered in power sales e =Auxiliary power purchases e Acceptance testing e =Construction all-risk insurance Owner's Contingency Owner's Project Management Taxes/Advisory Fees/Legal Utility Interconnections 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 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 DRAFT REPORT 10-2 December 2009 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY 10.1.3.2 Combustion Turbine Capital Cost Assumptions e 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. e All of the combustion turbine configurations will include selective catalytic reduction (SCR)and a ,CO catalyst. e Standard sound enclosures will be included for the combustion turbines. e 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. e 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. e 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. e 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 e 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 systemformanagingparticulateemissions. e The subcritical PC plant will utilize an air cooled condenser for heat rejection. 10.1.3.4 Direct Cost Assumptions e Total direct capital costs are expressed in 2009 dollars. e Direct costs include the costs associated with the purchase of equipment,erection,and contractors' services. e 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. e 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. e 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 December 2009 DRAFT REPORT 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 construction 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 Estimates are provided based on a capacity factor of 75 percent. Simple cycle units will start 200 times per year. Combined cycle units 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. 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 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. Gross capacity factor was 75 percent. 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. Burden rate was 56 percent. Black &Veatch .10-4 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY e Staff supplies and material are estimated to be 5 percent of staff salary. e Estimated employee training cost and incentive pay/bonuses are included. e 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 December 2009 DRAFT REPORT 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 December 2009 DRAFT REPORT 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 through a 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 December 2009 DRAFT REPORT 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)93.5 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,3 NO,,Ib/MBtu 0.0108 SOQ»,lb/MBtu 0.0022 CO,,Ib/MBtu 115.1 CO,ppmvd at 15%O2 3 Emissions are at full load at 30°F,reflect operation on natural gas,and include the effects of SCR,water injection and CO catalyst. Black &Veatch 10-8 ;December 2009 DRAFT REPORT 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.The combined cycle alternative will be designed for supplemental duct firing (on natural gas only).Supplemental firing necessitates a larger steam turbine and changes to other plant components,leading to an increase in total capital cost and a decrease in plant efficiency in order to realize the additional output.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 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-5 GE LMS100 Combustion Turbine Characteristics Net Capacity Net Plant Heat Rate Ambient Condition camw)"?)(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)47.6 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%O2 3 NO,,Ib/MBtu 0.0108 SO),lb/MBtu 0.0022 CO),lb/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 December 2009 DRAFT REPORT 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. 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. 10.1.4.3,Coal Technologies The coal technology presented in this technology assessment includes a subcritical PC generating facility. This technology assessment provides estimates of the performance and cost for this 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 the advantage of being able to accommodate a single unit size of up to 1,300 MW,and the economies of scale can result in low busbar costs.PC units are relatively easy to operate and maintain. 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 ternperatures 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. Black &Veatch 10-11 December 2009 DRAFT REPORT 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 factorsNetcapacityandheatrateassumeoperationonnaturalgas.®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,,Ib/MBtu 0.0109 SO),lb/MBtu 0.0020 CO),lb/MBtu 115.1 CO,ppmvd at 15%O2 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 December 2009 DRAFT REPORT 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.Net capacity and net plant heat rate include degradation factorsNetcapacityandheatrateassumeoperationonnaturalgas.®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 CO2,lb/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 10-13 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY 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 December 2009 DRAFT REPORT 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)51.2 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.@Net capacity and heat rate assume operation on a bituminous coal and petcoke blend. Table 10-12 Subcritical PC Estimated Air Emissions” NO,,[b/MBtu 0.05 SO),Ib/MBtu 0.06 CO),Ib/MBtu 212 CO,Ib/MBtu 0.10 © PMo,[b/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 December 2009 DRAFT REPORT 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&M : Owner's Capacity Cost (S/kW-Variable |Construction |Scheduled ForcedEPCCostCostTotalCost|at 70°F ($/kW)yr)O&M Schedule Maintenan Outage Supply Alternative (SMillions)|(SMillions)|(SMillions)|(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.@Owner'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 maybe longer than those presented. Black &Veatch 10-16 December 2009 DRAFT REPORT 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.Renewable Energy Options 10.3.1 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,including: e Susitna -300 -800 MW,MEA Glacier Fork -75 MW,MEA Chakachamna -330 MW,Chugach South Fork/Eagle River -1 MW,MEA Fishhook -2 MW,MEA Grant Lake/Falls Creek -7 MW,Kenai Kenai Hydro,LLC Plants -20 Total 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 a5 MW generic hydro unit in the Kenai and a2 MW generic hydro unit in MEA's service area.The following subsections discuss further details of these proposed projects. 10.3.1.1 Susitna Project Description of Project Contained entirely within the Southcentral Railbelt region,the Susitna River is situated between the two largest Alaska population centers of Anchorage and Fairbanks.Figure 10-1 illustrates the proposed Susitna Hydroelectric Project location. Black &Veatch 10-17 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-14 AEA Recommended Funding Decisions -Hydro Grant Recommended |RecommendedProjectCost|Requested Funding Funding Project Name Applicant ($000)...($000).|._..Decision Amount .. 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.The project did not pass Stage 2 review or was excluded in Stage 3 review for geographical spreading. Black &Veatch DRAFT REPORT 10-18 December 2009 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-1 Proposed Susitna Hydro Project Location (Source:AEA) soa 4 t \ ' .. Black &Veatch 10-19 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY This hydroelectric project on the Susitna River has been studied for more than 50 years.In the 1980s,the project was studied extensively and a license application was submitted to the Federal Energy Regulatory Commission (FERC).The project was cancelled in 1986 due to a variety of reasons.In 2008,the Alaska State Legislature authorized the AEA to perform an updated evaluation of the project.That authorization also included this RIRP to evaluate the ability of this project and other sources of energy to meet the long-term energy demand for the Railbelt.HDR was contracted by AEA to update the cost estimates,energy estimates, and schedules and to evaluate the economics of the project. According to the HDR report dated March 16,2009,several project development alternatives were considered: e Watana.This alternative consists of the construction of a large storage reservoir on the Susitna River at a site named Watana,with an 885-foot-high rock filled dam,and a powerhouse containing 6 turbines with a total installed capacity of 1,200 MW. e Low Watana.This alternative consists of the Watana dam constructed to a lower height of 700 feet, along with a powerhouse containing four turbines,with a total installed capacity of 600 MW. e Watana/Devil Canyon.This alternative consists of the full-height Watana development,plus a second reservoir located downstream at a site called Devil Canyon.This downstream reservoir would re-regulate river flow and be impounded by a 646-foot-high concrete dam.The Devil Canyon powerhouse would have an installed capacity of 680 MW.After the FERC license is issued,these two dams and powerhouses would be constructed sequentially without delays.The combined Watana/Devil Canyon developments would have an installed capacity of 1,880 MW. e Staged Watana/Devil Canyon (low height Watana,plus Devil Canyon,plus full-height Watana). This alternative would ultimately result in the same configuration as the previous alternative,but the Watana dam would be initially constructed to the lower height and the Watana powerhouse would only have four out of the six lower-head turbine generators installed.The Watana construction crew would demobilize and move downstream to construct the Devil Canyon dam and powerhouse,then either demobilize again,delay further construction,or return upstream to complete the Watana dam to its full height and install the remaining two units.The staged capacity of Watana would increase from 600 MW to 1,200 MW for a total project capacity of 1,880 MW. e Devil Canyon.This alternative consists of the Devil Canyon dam,without Watana dam,with a Devil Canyon powerhouse containing four turbines,with a total installed capacity of 680 MW.Note that Devil Canyon was intended to be a regulating dam,paired with the Watana reservoir.Without the larger upstream Watana reservoir,the Devil Canyon alternative would have minimal storage for providing power in winter. Among these options the Watana/Devil Canyon alternative was found to be the most cost-effective per unit of energy (Table 10-15),while also providing a stable winter energy supply. Black &Veatch 10-20 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-15 Average Cost of Electricity per kWh for Susitna Project™ Cost per kWh ($2008)? . First 50 Second 50 Alternative Years Years Watana 0.22 0.01 Low Watana 0.20 0.01 Watana/Devil Canyon 0.14 0.01 Staged Watana/Devil Canyon 0.18 0.01 Devil Canyon 0.13 0.02 )"Susitna Hydroelectric Project.Project Evaluation. Interim Memorandum.Final;”Prepared for AEA by HDR and Northern Economics;March 16,2009. A primary assumption of the HDR report is that all power from these alternatives can be used at the time it is produced.With several of these alternatives exceeding the total load of the Railbelt,HDR was tasked with developing smaller-sized alternatives for Susitna.HDR's revised analysis is contained in Appendix A. HDR's revised Susitna alternatives are presented in Table 10-16.Each alternative is described below. «Lower Low Watana.This alternative is a lower dam and corresponding smaller project than.The height of the dam is about 50 feet less than the original Low Watana project. ¢Low Watana (Non-Expandable).This alternative is represents the same sized dam as the original Low Watana project except that the dam is constructed with a smaller base essentially eliminating the option to increase its height in the future. ¢Low Watana (Expandable).This is the same alternative as the original Low Watana project. ¢Watana.This is the same alternative as the original Watana project. High Devil Canyon.This alternative is a dam between the original Watana and Devil Canyon projects.With this configuration neither the original Devil Canyon or Watana projects would be possible._ In addition to developing smaller projects,HDR evaluated cost reduction measures for the original Low Watana (Expandable)and Watana alternatives.For the revised list of alternatives,only Low Watana (Expandable)and Watana allow for the ultimate development of the Susitna River comprised of High Watana and Devil Canyon. Mode of Operation All of the alternatives identified have significant storage capability which enhances their benefits to the Railbelt Utilities.Table 10-17 presents the average annual and average monthly generation from each of the alternatives. Black &Veatch 10-21 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-16 HDR Analysis of Watana and High Devil Canyon Alternatives Low Watana Lower Low (Non-Low Watana High Devil Watana Expandable)(Expandable)Watana Canyon Gross Head (ft)495 557 557 734 729 Net Head (Max Flow)481 543 543 729 707 (ft) Maximum Plant Flow 10,700 14,500 14,500 22,300 14,800 (cfs)' Number of Units 3 4 4 6 4 Nameplate Capacity 380 600 600 1200 800 (MW)_ Firm Capacity (98%)170 245 245 380 345 (MW) Min.Capacity (MW)65 75 75 100 100 Average Annual 2,000 2,600 2,600 3,700 3,900 Energy Production (GWh) Dam Height*(ft)650 700 700 885 855 Cost (2008 $)$4,100,000,000 $4,500,000,000 |$4,900,000,000 |$6,400,000,000 $5,400,000,000 Maximum Pool 1,950 2,014 2,014 2,193 1,750 Elevation (ft) Minimum Pool 1,850 1,850 1,850 2,065 1,605 Elevation (ft) Tailwater Elevation 1,456 1,457 1,457 1,459 1,022 (Max Flow) (ft) Usable Storage (acre-1,536,200 2,704,800 2,704,800 3,888,500 2,254,700 ft) *Height of dam crest above foundation.Foundation elevation assumed to be 1,325'for Low Watana and 895'for High Devil Canyon as defined in the 1982 Acres feasibility study. **Cost estimated by R&M. Black &Veatch DRAFT REPORT 10-22 December.2009 SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-17 Average Annual Monthly Generation from Susitna Projects (MWh) Alternative Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Lower Low 2,006,000 |127,000 |116,000 |127,000 |117,000 |101,000 |208,000 |270,000 |280,000 |256,000 |153,000 |123,000 |128,000Watana(non- expandable) Low Watana 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(non-expandable) Low Watana 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(expandable) 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 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 Canyon Low Watana 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(Expansion) Black &Veatch 10-23 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Capital Costs The estimated capital costs for the alternative Susitna projects are presented in Table 10-16.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. 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 damsin 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 10-18.The development schedules for the revised Susitna configurations were based on the Low Watana schedule for the Watana configurations and the Devil Canyon schedule for the High Devil Canyon configuration. Table 10-18 Power Generation Time Estimates for Susitna Hydro Project Generation of First Generation of Full Alternative Power (Years)*Power (Years)* Watana 15 16 Low Watana 14 15 Watana/Devil Canyon 15 20 Staged Watana/Devil Canyon 14 23 Devil Canyon 14 15 "From start of licensing. 10.3.1.2 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 10-2 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 10-19 shows the average monthly and annual energy that will be generated by the project. Black &Veatch 40-24 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-2 Proposed Chakachamna Hydro Project Location (Source:TDX) Table 10-19 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 Black &Veatch 10-25 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY 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. 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. 10.3.1.3 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 (msl);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 320 GWh.The estimated average monthly generation is presented in Table 10-20. Black &Veatch 10-26 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-20 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 $3,305 October 35,964 November 13,767 December .7,617 Annual Total (MWh)327,538 Note:Data based on USGS Gauge on Knik River. Mode of Operation As indicated in Table 10-20,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 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. Black &Veatch 10-27 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY 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. 10.3.1.4 Generic Hydroelectric ProjectsBlack&Veatch developed two small,generic hydroelectric project alternatives to represent several hydroelectric opportunities that have been identifiedin the Railbelt.The first hydroelectric project isa 5 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 a 2 MW project located in MEA'sarea.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. 10.3.2 Ocean (Tidal Wave) 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. Based on Black &Veatch's review of available information,we assumed that the proposed Turnagain Arm tidal project will serve as example to be considered as a potential supply-side alternative in this RIRP, 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.As a result,tidal energy will be considered as a sensitivity case in the evaluations.The following subsections discuss further details of the proposed project. 10.3.2.1 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 10-3 shows an array of vertical-axis tidal turbines stacked and joined in series across a marine passage. Black &Veatch 40-28 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-3 Blue Energy's Tidal Bridge With Davis Turbine (Source:Blue Energy) wr r CR Cee soa4BeeiThis 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 10-4 shows the configuration of a Davis tidal turbine. 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 10-5 depicts the proposed layout of the tidal plant. Black &Veatch 10-29 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-4 Cutaway Graphic of a Mid-Range-Scale Vertical Axis Tidal Turbine (Source:Blue Energy)r)napLeeageeha..wy:Samewe*?hel"gt2Figure 10-5 Proposed Layout of the Turnagain Arm Tidal Project Project Area Tidal Fences 2 Ss Control Building,Kenai Side |Gan o RatControlBuilding,Anchorage Side '., Transmission Line,Underwater 0 v4t"MonwpTransmission Une,On Land ANCHOR AGEfopeed"pF a reFigure 4 Black &Veatch 10-30 ; December 2009 DRAFT REPORT 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 10-6. Figure 10-6 Turnagain Arm Tidal Project Monthly Generation 3000.010.00 9.50 9.00 8.50 8.00 7.50 7.00 6.50 6.00 | 5.50 | 5.00 | 4.50 | 4.00 3.50 | 3.00 | 2.50 4 2.00 4 1.50 4 1.00 | 0.50 | -1000.0 0.00 | -0.50 J -1.00 | -1.50 4 -2.00 -r -2000.00.00 100.00 200.00 300.00 400.00 500.00 800.00 700.00 Time (hours) 2500.0 2000.0 1500.0 1000.0 -Velocity (m/s)500.0 --Power (MW)Power(MW)Velocity(m/s)0.0 -500.0 F -1500.0 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 or $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 lower than other projects that Black &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 December 2009 DRAFT REPORT 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. 10.3.3 Geothermal Project Option Description of ProjectOrmatTechnologies,Inc (Ormat)has approached the AEA for the potential development of a geothermal power plant project at Mount Spurr,whichis 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 combinedcyclepowerplantconfiguration. Figure 10-7 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 the steam 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 10-8 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 40-32 December 2009 DRAFT REPORT -SECTION 10 SUPPLY-SIDE OPTIONS Figure 10-7 ALASKA RIRP STUDY Simplified Binary Geothermal Power Plant Process (Source:Ormat) Btn bee gee etat road Sane Rye be taet ea ta seee Bite Tree eh ys phew8 a Donte ORMATESS POMAYEAeteee1Maaledie a ge a ee L __Production Watt _site q Hot CaoledGeorhermalGeothermalElasialFlutd Figure 10-8 Simplified Geothermal Combined Cycle Power Plant Process (Source:Ormat) Geotnermal i atnan ton {ire wed onves)/ [ine steam [turdine,is Jorsnclesasest in phe vapurzerpinenflawsta the praheater -Hot r Production Wall SY | ":Geathermal || ar aren Tr oe |ORMATS 9 PeSeePeoBlack &Veatch DRAFT REPORT 10-33 December 2009 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 capacity factor during its first commercial operation year and will experience approximately 1 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 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. 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/MWhin 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 scheduledmaintenanceactivities.For the purpose of this study,Black &Veatch assumed that the average availability factor of this proposed geothermal plant will be 95 percent. Schedule Figure 10-9 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 .December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-9 Estimated Mount Spurr Project Development Plan (Source:Ormat) (Nk.Sour =(esimnetiss DavalonmentEM}ee caer foe ae eo Lared sition 7 i 10.3.4 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.On the Railbelt,several of the utilities are examining wind power projects,including: e BQ Energy/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 10-21 shows each proposed wind project's name,applicant,estimated project cost,grant requested,and funding decision and amount recommended by AEA after two rounds of ranking and funding allocations conducted by AEA. Black &Veatch 10-35 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Table 10-21 AEA Recommended Funding Decisions -Wind Recommended Grant FundingProjectProjectCost|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: e Project size:Larger than 5 MW e Permitting:In place or in progress e Power Purchase Agreements (PPA):In place or in progress *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. 10.3.4.1 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 Fire Island Project.According to the JV,there is the potential to develop a wind generation plant with an estimated maximum output of 54 MW on Fire Island.Figure 10-10 illustrates a visual simulation of the proposed Fire Island wind generation project. Black &Veatch 10-36 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-10 Visual Simulation of Fire Island Wind Generation Project (Source:CIRI/enXco Joint Venture) "Di 1 ngStensear Ft Figure 10-11 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 will 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 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-11 Preliminary Site Arrangement and Interconnection Route (Source:CIRI/enXco Joint Venture) se,'”t ™ !. *X.we."SONCONe} Nee 2 Ne \ One S ae )\wa 4 ae 3 nNweyOWSextMN a oy .ety a . 2 AS ty ad Sj >. :NaN :aw : ¢*3s x . f os ,"y aN :Race 2DryeAd.Va x ,»*x "oo ;f ,>\BN ee ri :Nok.=.Nr a \hs SPEEE a a %re at L ve \_oy .&f y Pe an 7 oT ..8 AN Me SA -.mS >a ”let 4 'Ss y oo Sey SS 8 Pee aeeeeTLanen4.>.™th y eae re Ag 7 rhs .BN aoe at 7 ,axe wee oe oe wt ea . :™'ee = 7 se a 5 OY 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 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY e Initiated integration studies. e 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. 10.3.4.2 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 10-12). 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 of the proposed BQ Energy/Nikiski project. Details of the information contained in this document will be presented in the following subsections. Figure 10-12 Kenai Peninsula,Nikiski (Source:Kenai Winds LLC) Black &Veatch 10-39 December 2009 DRAFT REPORT 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 $2,333/kW in 2000$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 on 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. Reached consensus to interconnect the project with HEA. Submitted draft power sales term sheet to HEA and discussions around those terms are underway. 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. 10.3.5 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 will be 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 Asteam turbine generator. e Balance of plant mechanical,electrical,chemical,water,and inter-connection systems. Black &Veatch 10-40 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-13 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 10-13 Simplified Hyperion Power Cycle Diagram (Source:Hyperion Power Generation) Uranium HydrideFuedlModerator Heat Exchanger omer ;yéroger Steeage $elt Requation Hydrogen Exchange Cantrale Core Terperature i Pe Mode of Operation It is expected that the project will be designed and permitted for both load following and base load operations. Fuel Supply Although it is anticipated that the reactor design for this project can accommodate a variety of fuel compositions,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 December 2009 DRAFT REPORT 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 22.0 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 40-42 December 2009 DRAFT REPORT 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 NRC in early 2012 as part of Hyperion's plan to obtain a manufacturing license from NRC.A schedule (See Figure 10-14)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 NRC will have appropriate staffing level and capability to review licensing applications submitted by all applicants. Figure 10-14 Requested Potential Advanced Reactor Licensing Application Timelines (Source:NRC February 20,2008 Briefing Presentation Slide) Potential Advanced Reactor Licensing Applications An estimated schedule by Fiscal Year (October through September} }2008 |2009 |2010 |2011 |20412 |2013 |2014 |2045 |2016 |2017 | [Nenpcs ] H Participation &R&D Activities j censing Review ;Hearing> NGNP NRC Active if pshibadSDesign Apprevad Revi 4 rateerantieanticws +a .|#i '4 =|MRE Hyperion MansfacturingLicense Rev A |MuScate-Preeappte|rake Bhesigripy iH 4 c Prasanna iA fn I=pvaniiplatiar al 4 Legend: L NGNP Activities ae ey Cr Desiga-Approv:Y Hearing --_ |er ee-appicatiowiiewe:||oat Manufacturing Licens a |GurDesign:Gertiicatio 4 |REDArvirastriet -aaiocted NOTE:Schedules depicted for future activities represent nontinal assumed review durations based on submittal time franies in letters of intent from prospective applicants.Actual schedules will be determined when applications are docketed, Black &Veatch 10-43 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Figure 10-15 illustrates the Nuclear Energy Institute (NEI)latest understanding of the NRC's new licensing process.Figure 10-15 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 10-15 NRC New Licensing Process and Construction Timelines for New Reactors (Source:NEI website) @ArT)Cppurterntybor--TY Paws CoomaFHone Esrty Sita :Permit (TTD econ Orn WRC Review;weeficationiCevcioanent-APBonsbotApaveation (PLAT2716.43"mors)ot Dasign Plant Cansiruction?aa)Cerplication fer |wanes al=Verification ain ee Ore Commerstiat Operation .i j 1 1 4 a i A i ! 8 1 2 3 4 5 &?8 9 18 Ah) Time in Years ('estimate tor the first tary punts}January 2008 The NAC's new licensing process offers multiple opportunities for public input. Black &Veatch 10-44 December 2009 DRAFT REPORT SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY 10.3.6 Municipal Solid Waste 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 witha list of municipal solid waste projects proposed and operating in the US to identify project sizes with similar tons per day consumption.As a result,22 MW and 4 MW project capacities were developed for Anchorage and the Interior,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. 10.3.7 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 which will remove the specific need to be a FERC Qualifying Facility. Black &Veatch 10-45 December 2009 DRAFT REPORT SECTION I1 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 successfullyin various other jurisdictions and has received1 general regulatoryacceptance. 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 resultin the desired changesin consumption and load shape,and 3)identification ofof marketing approaches orprogramconceptstoachievethedesiredbehavioralchanges. 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 December 2009 DRAFT REPORT 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 DSM/EE Programs and Other Assistance/Information Offered Chugach Residential Other Assistance/Information Provides compact fluorescent light 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 HomeSense:$40 energy audit that includes energy saving tips and installation of energy efficient products at no additional cost. Builder$ense:rebate program for home builders who install electrical energy efficiency measures during construction. Business$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 41-2 December 2009 DRAFT REPORT SECTION 11 DSM/EE RESOURCES ALASKA RIRP STUDY Table 11-1 (Continued) Current Railbelt Electric Utility DSM/EE-Related Activities Utility DSM/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 e 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. e Information on CFL and old refrigerator disposal in the area. MEA Other Assistance/Information ¢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. ¢Provides a link to Energy Star®Home Energy Yardstick,a tool to analyze your energy usage. 'e 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/Information e Provides a link to Home Energy Saver,which is 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 December 2009 DRAFT REPORT 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 DSM/EE 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.ahfe.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 hitp://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 December 2009 DRAFT REPORT 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&Low Alaska Railbelt Utilities Cust.Population Population Pop.Cust.Cust .Cust. Schoolsinall Schools Income Centers Center(s)Pop.Centers _incity _Res in cit Fairbanks 34,540 37 4,076 North Pole 2,183 8 227GoldenValleyElectricAssociation]GVEA 42,866 ra)Delta Junction 942]36,395 6,008 463 61 9 98 Nenana 362)2 37 Anderson 274]1 28 Wasila 9,780]27 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 andAnchorageMunicipalLightandML8P 108,472 10 Anchorage 279,671)93,493 14,973 6 125 104 18,458 Power Homer 5,694 10 592 Soldotna 4,289 10 446 Homer Electric 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 TOTAL:234,809 82 359,039 205,611 28,584 614 268 226 26,397 Organization state cities Gaiden Valley Electric Association 5.6%18% Anchorage Muricipal Light &Power 40.9%§7.2% Matanuska Electric Association 2.9%40% Chugach Electric Association 0.0%0.0% Homer Ekctric Association 27%3.8% City of Seward Electric System 0.4%0.6% Total Pop in Railbelt §2.53%73.42% Sources:[Customer information Energy Velocity by Ventix Population data http:/Avww.census.gov/ Economic data:http:/Avww.census.gow/. Schools data http:/Avww.eed.state.ak.us/Alaskan_Schods/Public/ Black &Veatch 11-5 December 2009 DRAFT REPORT SECTION II 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 DSMW/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 DSM/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 December 2009 DRAFT REPORT SECTION I1 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 d). Q)GB) 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 L (4)G)(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 DSW/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 December 2009 DRAFT REPORT SECTION I1 DSM/EE RESOURCES ALASKA RIRP STUDY e 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]),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 in the Railbelt region. 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 December 2009 DRAFT REPORT SECTION 11 DSM/EE RESOURCES ALASKA RIRP STUDY Figure 11-2 EPRI/EEI Assessment:West Census Region Results Com-Lighting 5°.-pmnesmsicinieemaes Res-Electronics FS m 2030 Ind -Machine Drive I sasen ii m 2020 | 1 @ 2010 Com -Other Jpemminsaames Res-Cooling |pannaiss Com -Cooling Res -Appliances Res -Lighting Fr"j Ind -Lighting = Res -Water Heating = 0 )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/I)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: 1.Relevance to the regional weather patterns 2.Commercial availability 3.Incremental cost per kWh over standard options 4.Contribution to winter peak load reduction 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: e Measure life e Target kWh savings per customer e Target kW savings per customer e Incremental cost per installation Black &Veatch 11-9 December 2009 DRAFT REPORT SECTION 11 DSM/EE RESOURCES Table 11-4 Residential and Commercial DSM/EE Technologies Evaluated ALASKA RIRP STUDY a "* _- - Teezers Energy Star-Chest Resid-Applian Comm.High Bay 6L TSHO Camm a:Freezer NonWeather co Motore 1 to &HP NonWeathar Motor 15 1133 0.024 §57.60 replacing 400W HID NonWeather Ughting ors _.High Bay FluorescentResid-Applian Comm.rnin inhiClothesDryersNonWeatherce1414400.0 $6250 Motors 25 te 100 HP.NonWeather Motor 15 1,056.0 0.224 $331.90 ried Replacing 400W NonWeather Lighting 12 9610 02 $70.84 ..High Bay FluerescentRefrigeratore-Freezers.Resid-Applian Comm.Comm.angeEnergyStar-Top Freezer NonWWeather ce 12.790 0.0 $50.88 Motors 7,5 to 20 HP.NonWeather Motor 15 408.4 0.067 $149.85 fenlece 1 cower NonWeather Lighting 12 2,005.0 O05 $136.84Retrigerators-Freezere Resid-Applian LED Ext Signs Electronic Comm .Energy Star-Side by Side 12 1080 0.0 $50,88 Fistures (Retrofit Only)NeonWeat Lighting 156 201.0 0023 §33.00 CFL Fidure NonWeather Ughting 12 42006014 $21.70PumpandMotorSingleComminhtiComm.i.Speed 6940 04 §23.38 LED Ato Traffic Signats NonWea lighting 6 275.0 0.085 §49.50 CFL Screwin NonWeat lighting 2 2020 00 $8.29SmartStripplugoutlet184.0 00 $11.00 LED Pedestrian Signals NonWeat lighting 8 150.0 0.044 §77,00 Daylight Sensor controls Non.Lighting 12 14,800.0 3.8 $1,100.00 "Resid.Applian VFO HP 1.5 Process ight Comm-'atiFreezerrecyclingNonWeatherce1,551.0 02 $75.00 Pumping NonWeather Motor 15 1,623.4 0.343 $1,192.13 \Central Lighting Control NonWeather Lighting 12 11,500.0 28 §2,035.00.Resia-Applian [VFO HP 10 Process Comme Occupancy Sensors under =Comm-itt:Refrigerator recycling NonWeather ce 6 16720 02 $430.00 Pumping 'Weat Motor 15 10,7134 2288 §811.50 500 W NonWeather Lighting 10 3970 01 $79.20Rasid-WaterH VFD HP 20 Process Comm Comm iHeatPumpWaterHeatersNonWeathereater152,885.0 03 $242,50 Pp ng NorWeal Motor 15 21,643.1 4.871 $1,266.63 Low Watt T6 lampa.NonWeather Lighting 12 15.0 00 $3.43VendingEquipmentComm--Refriger Comm "Low Flow Showerheads 01 $36.76 Controller NonWeather ation 5 8000 0210 $78.76 {3 Lamp T5 replacing T12 NonWeather Ughing 12 994 0.0 $110.09 .Efficient Refrigeration Comm Refriger TT saatPipeWrapNonWeathereater6257000$2.08 Condenser NonWeather ation 15 120.0 0,118 $9.63 14 Lamp TSHO replacing T12 NonWeather Ughting 12 1910 60 $168.33ENERGYSTARCommercial,Resid.i :Comm--Refriger HPTS 4f 3 lamp,T12 to Comm "Holiday Lights.NonWeather lighting 10 106 00 $14,20 pal poor Freezers leas NonWeatl ation 12 520.0 0.059 §HB HPT NonWe lighting 12 1452 60 $75.99 ENERGY STAR CommercialResid-".Comm =Relriger IHPTS 4ft 4 lamp,T42 to Comm 5CFLfixturesNonWeatherlighting1278000$2475 eiDoor Freazers 20 to.NonWeather 12 $07.0 0,058 $330.00 PTS NonWeather lighting 12 169.7 6.0 $80.88 1 JENERGY STAR Commerciat ..Resid-'"'Comm =Refriger T12HO &ft 1 lamp retrofit te Comm aTorchiereFloorLampeNonWeatherLighting12164.0 00 $10.00 eat Door Refrigerators Weat a 12 905.0 0.103 §68.75 PTS Te 4h 2 |NonWeather Lighting 12 1740 0.0 $62.34 ENERGY STAR Commercial 5 5 7 Resid-7 Comm -Refriger T12HO &ft 2 lamp retrofit to Comm-aeLEDNightLightNonWeatherLighting1222000$650 onpeer Refrigerators 20 NonWeather ation 12 1,069.0 0.122 $275.00 PTS Ta 4f 4 tamp NonWeather Lighting 12 293.0 01 $80.88 Resid-[ENERGY STAR Ice Comm--Refriger Comm "CFL bulbs regular -Outside NonWeather Lighting 9 1916 0.0 §0.83 Machines less than 500 Ibs NonWeather ation 12 1,652.0 0.189 $330,00 T&48 3iamp NonWeather Lighting 12 1288 0.0 $107.38Resid.,ENERGY STAR Ice Comm =Refriger Comm.iCPLbulbsregularNonWeatherLighting944.1 0.0 §2.83 Machines 500 to 1000Ibe NonWeather ation 12 2,695.0 0,308 $825.00 TS 4 4iamp NoniWeal Ughling 12 1398 00 $113.90 5 ENERGY STAR Ice A:Resid-4 Comm -Refriger Comm iahtiCellingFaneWeatherShel15°47.8 «0.0 $151.25 Wachines more than 1000 NonWeather ation 12 6,048.0 0.690 $550.00 TS HO 8 ft 2 Lamp Weather Lighting 12 184.0 0.0 $124.92bs |CoolingDuctsealing20leakageResid-Comm .1 CommbaseWeatherShel1841.7 00 $143.70 Pumpe HP 1.5 Wea Motor 15 3020 0.064 $313.75 [Window Film Weather fHeatin 10 256.0 01 $84,60 a.\Cooling.Resid-Comm Refrigerant charging Comm 'iRoofInsulationWeatShell2041.7 0.0 $441,32 Pumps HP 10.NonWeather Motor 15 2.0140 0427 $116.30 correction Weather eatin 1 7124 #10 $21,10 i Cooling CoolingSetbackthermostat-Resid-:i Comm-=Water Comme.setback Wea natn 9 1521 0.0 $45.31 Pre Rinse Sprayers NonWeather ter 5S 1,396.0 0.116 §8.63 \VFD Fan Weather eatin 10 1,185.6 0.0 $42.89ExteriorHIDreplacementCoolingENERGYSTARSteamCommeWaterComm.iohti Comm-"Cookers 3 Pan NonWeather Heater 12 11,1880 26 $1,141.25 emo OW to 400W HID NonWeather Lighting 12 706.0 0.000 $585.20 IVFD Pump:Weather 'ent 10 3,9592 03 $41.01PlugLoadOccupancyComm.Office High Bay 3L TSHO Comm inbei Refrigeration Comm RefrigerSensorsDocumentStationsNonWeatherLoad*9030 01 §50.88 Replacing 250W HID NorWeather Uahting 12 448.0 0.103 $272.91 Commissioning NonWeather ation 9 9750 00 $37.28 HP Water Heater 101050 Comm Waler High Bay ALTSHO.Comm gs Strip curtains for walk-ine-Comm RefrigerMBHNonWeatherHeater1521,156.0 42 §1,100.00 |Replacing 400W HID NonWeather lighting 12 8820 0.200 $159.28 reazer NonWeat ation 4 6130 Of $77.00 Black &Veatch 11-10 December 2009 DRAFT REPORT 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: e 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 December 2009 DRAFT REPORT 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($)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 $45.31 Thermostat-Moderate Setback Black &Veatch 11-12 December 2009 DRAFT REPORT SECTION 11 DSM/EE RESOURCES ALASKA RIRP STUDY Table 11-6 Input Assumptions -Commercial DSM/EE Measures Rebate as %of Total per Incremental Incremental Unit ,a Equipment '|'Equipment'Rebate ©Administrative Vendor or Program Commercial Measures Cost (8)Cost Amount ($)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 1 to 5 HP $88.00 15%-$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 $400.00 715%$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 20ft3 ENERGY STAR $500.00 50%$250.00 $25.00 --$275.00 Commercial Solid Door Refrigerators-20 to 48 ft3 Black &Veatch 11-13 December 2009 DRAFT REPORT DRAFT REPORT SECTION 11 DSM/EE RESOURCES ALASKA RIRP STUDY Table 11-6 (Continued) Input Assumptions -Commercial DSM/EE Measures Rebate as %of Total perIncrementalIncrementalUnit Equipment Equipment Rebate Administrative Vendor or ProgramCommercialMeasuresCost(S)Cost Amount ($)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 Ibs ENERGY STAR Ice $2,000.00 25%$500.00 $50.00 -$550.00 Machines-More Than 1,000 Ibs 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 TSHO $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 Screw-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 Watt 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 T5HO Replacing $306.06 50%$153.03 $15.30 --$168.33 T12 Black &Veatch 11-14 December 2009 SECTION Il DSM/EE RESOURCES ALASKA RIRP STUDY Table 11-6 (Continued) Input Assumptions -Commercial DSM/EE Measures Rebate as %of Total per Incremental |Incremental ft.ee a.UnitEquipment|Equipment Rebate Administrative Vendor or Program Commercial Measures Cost (S)Cost Amount (S)Costs (10%)Other Costs Costs HPTS8 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 T12HO 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 4ft4Lamp $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 -$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 December 2009 DRAFT REPORT 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.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: "14,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 of electric space heating equipment and the general lack of air conditioning loads,the potentialfor DSM and energy programs are limitedfrom the perspective of the 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 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 workjointly with Enstar to develop DSM and energy efficiency programs that would be beneficial to both.This would create economies of scope 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 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY 12.0 TRANSMISSION PROJECTS The Railbelt transmission system currently 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. These utilities developed and operated independently of each other and were successful in providing reasonable service to businesses and residences.However with the changing economic environment which includes heighten environmental awareness,fuel cost volatility and availability,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 adequate transmission infrastructure to support joint economic and reliable operation.This section of RIRP focuses on the transmission projects that will be necessary for the Railbelt utilities to construct a reliable and unconstrained transmission system. The existing Railbelt utilities covers the Fairbanks area,the Anchorage area,and the Kenai peninsula and are interconnected between Fairbanks and Anchorage with the Northern Intertie while Anchorage and the Kenai are connected by the Southern Intertie.These existing facilities are discussed in Section 4. 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 weak transmission infrastructure interconnecting the utilities.This weak transmission interconnection results in the system operation being severely constrained by stability problems.As a result of being stability constrained, individual transmission projects constructed to increase transmission capacity cannot be fully loaded to their thermal limits and,in several instances,these additional investments could result in no additional transmission capability.This problem cannot be solved by the existing planning and development strategy of independent utility planning but must be tackled by an integrated development of the system. Black &Veatch 12-1 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Figure 12-1 ; Railbelt Transmission System Overview .i4 ra aoe i GVEA ony!SOT,2 Area Load pus 238 MW >vo a MEA 544AreaLoadNN?WS.HG MW Ne .i-«&, Y .PTS,,'}X 4 'wtseis €"1 an 7”: .Anchorage a :Area Load :wear ek412MWee oe Ve. - Kenai Area Load -HEA'SES . 97 MW Black &Veatch 12-2 December 2009 DRAFT REPORT SECTION 12 __.TRANSMISSION PROJECTS ALASKA RIRP STUDY 12.2.The GRETC Transmission Concept To address the problems faced by the Railbelt utilities,the Legislature is considering the formation of GRETC which would become the entity charged with developing and operating the integrated energy and transmission system.In developing projects for the integrated operation of the Railbelt transmission system the following criteria were adopted: e Transmission system to be upgraded over time to remove transmission constraints that currently prevent the coordinated operation of all the utilities as a single entity.This is projected to happen within 10 years of the base year of the study. e Study to include all the utilities'assets 69 kV and above.These assets,over a transition period,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. e Assumes that all utilities 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. 12.3.Project Selection Criteria 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 projects to connect new generation projects to the grid (Generation Interconnections - Category 1) «Transmission projects to upgrade the grid required by a new generation project (Generation Upgrades Category 2) Replacement projects that need to be done because of age and condition (Replacement -Category 3) Upgrade projects to the grid to implement the GRETC concept (GRETC -Category 4) 12.4 Summary of Transmission Analysis Conducted A transmission analysis was performed to review the projects described below to determine if the transmission projects,along with other projects related to the generating resources selected in this RIRP study for each of the four Evaluation Scenarios,and their related transmission interconnection. 12.4.1 Cases Reviewed Based on the GRETC transmission-related objective,the projects described below were used to develop cases for evaluating the performance of the Railbelt system in 2022 and in 2060.The 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. 12.4.2.Results of 2060 Analysis The objective of the transmission analysis,which included an N-1 contingency analysis of all transmission branches in the Railbelt with all the generating resources dispatched economically,to determine if any overloads of any of the transmission lines within the Railbelt system occur.The N-1 analysis resulted in overloads on several distribution transformers.These overloads are not on the transmission system and may be alleviated by changing transformer taps on these transformers. Black &Veatch 12-3 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY A reliability analysis to confirm that the Railbelt is not under any stability constraints still needs to be performed for the cases prepared (note:this stability analysis is currently being completed by EPS and the results will be available in time for the Final Report).This analysis may result in changes or additions to the projects identified for an unconstrained and robust transmission system. 12.5 Selected Projects The selected projects were placed in the categories outlined above and then prioritized in order identify projects that are needed immediately by the system to maintain current levels of service.The projects were selected to gradually move the system toward the GRETC concept of a robust transmission system that provides continuous service under N-1 contingencies and allows for the economic commitment and dispatch of generation throughout the Railbelt. 12.5.1 Priority 1 Projects Project 1 -Soldotna to University 230 kV Transmission Line (New Build) The Soldotna to University 230 kV project is a new 230 kV line between the Anchorage area and the Kenai. This 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 75 MW while the thermal limit for the existing 115 kV transmission line is approximately145 MW.Figure 12-2 presents the proposed project.More investigation isrequiredtodeterminedetailedtransmissioncharacteristicsandrouting.This is a GRETC Category 4 project. Figure 12-2 New Soldotna to University 230 kV Transmission Line '-PPEpcta-:"s GEMM ES i eluga Power Plant Anchora Yi ""y Beluga <>oe .on jP «Second KenalLeAf\.Intertie - Tyonek Mijonek _o¢ePyafF"aadiionon *aa ! i 00 Spade ay ' Lf it,. fogyPont = ”. wig Black &Veatch 12-4 December 2009 DRAFT REPORT ra,| ' .Soldotna J SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project 2 -Soldotna to Quartz Creek 230 kV Transmission Line (Upgrade) This project is the upgrade of the existing line between Soldotna and Quartz Creek.This line was constructed in 1959 and is in very poor condition,suffering from frost jacking.Homer had plans for the upgrade of this line and planned to reinsulate this line to 138 kV from the 115 kV at which it currently operates.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.Figure 12-3 presents the proposed upgrade.This project is a replacement (Category 3)project. Figure 12-3 Soldotna to Quartz Creek 230kV Transmission Line Upgrade oO Sokioma AEG T.ut 4 Quartz Creek a :Ae 4 ia oa on (yooOMAiiuMENSfhayI}sf }A |",oY A Ornenwe med wits Black &Veatch 12-5 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project 3 -Quartz Creek to University 230 kV Transmission Line (Upgrade) This is the section of the Southern Intertie owned by Chugach and was constructed in 1959.This section of the line is over 50 years old and is subject to avalanches.It will require significant rebuilding to keep it in service.The line is operated and maintained by Chugach and has a stability-limited capacity of approxi- mately 75 MW which limits the amount of generating reserves that may be shared between areas of the Railbelt.Figure 12-4 presents the proposed upgrade.This project is a replacement (Category 3)project. Figure 12-4 Quartz Creek to University 230kV Transmission Line Upgrade _JOT ne 9 enzig /-bP /ao SsS's,7"_/Betuga Power Piant wae 2Aor__Siti!oe pay ¥Beluga:2 fe,£University .¢. '-7 f yaaf.a'iroyea"Jewel Lak: :.7 ¢-_-| r '| Soldotna-SVC _-.. Pouartce |;1-Cooper CroAR Point:-=4 7 gePawing Fe |Soldotna AEG T Black &Veatch 12-6 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY 12.5.2 Priority 2 Projects Project 4 -Lake Lorraine to Douglas 230 kV Transmission Line (New Build) Currently,power from the Beluga power plant is transmitted to the Pt.Mackenzie substation at 230 kV,and then north from the Pt.Mackenzie substation over two 230 kV lines to the Teeland substation and,through submarine cables to the ML&P Plant 2.With the loss of the Pt.Mackenzie to Teeland line,the area between Teeland and Palmer experiences loss of load and low voltages.This line from a new Lake Lorraine substation to Douglas is proposed to address the single contingency outage caused by the loss of the Pt.Mackenzie to Teeland line.Figure 12-5 presents the proposed transmission line.This is a GRE\C Category 4 project. Figure 12-5 a: New Lake Lorraine to Douglas 230 kV Transmission Line an Sutton-Alpinear *a'\'Eklutnaaioe.yO es .Knik River<8 >, °toe Ne gues a :Y YW a ue AZGenWOOLAS Black &Veatch 12-7 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project 5 -Douglas to Healy 230 kV Transmission Line (Upgrade) The Alaska Intertie includes a 170-mile,345 kV transmission line between Willow and Healy and voltage control devices at Teeland,Healy and Fairbanks.The line was build with State grant funds,went into operation in 1985 and is operated at 138 kV.All of the operating and maintenance costs of the Intertie are paid for by the utilities (83.5 percent from energy transfers and 16.5 percent from reserve sharing). The 170-mile transmission line that runs between Willow and Healy is the state-owned portion of the 300 mile Anchorage to Fairbanks transmission system.It is insulated at 345 kV and operates at 138 kV.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 Intertie Operating Committee (IOC),set up by the Intertie Agreement anong AEA,GVEA,Chugach, ML&P and AEG&T (MEA and HEA),oversees the operation and maintenance of the line.The current agreement does not provide a mechanism for financing capital repairs or improvements to the line.Certain repairs have been postponed for a lack of a financing mechanism.Figure 12-6 presents the proposed transmission line.This is a GRETC Category 4 project. Figure 12-6 Douglas to Healy 230 kV Transmission Line Upgrade .'v4.PALGANKS »._- Black &Veatch 12-8 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY 12.5.3 Priority 3 Projects Project 6 -Douglas to Healy 230 kV Transmission Line (New Build) 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.Figure 12-7 presents the proposed new line.This isa GRETC Category 4 project. Figure 12-7 New Douglas to Healy 230 kV Transmission Line .>i 4:FAs GQaNan se ei)NOS,* Dew -.aSPNT tg ,Do iglas;Neg ey waite |o Black &Veatch 12-9 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project 7 -Beluga to Pt.Mackenzie 230 kV Transmission Line (New Build) The Beluga and Pt.Mackenzie substations are currently interconnected by two 230 kV transmission line and a one 138 kV line.Currently,when one of the 230 kV lines is out of service the Beluga generating station is derated.This project is the construction of an additional 230 kV line between Beluga and Pt.Mackenzie to address this problem.Figure 12-8 presents the proposed line.This is a Generation related Category 2 project. Figure 12-8 New Beluga to Pt.Mackenzie 230 kV Transmission Line Black &Veatch .12-10 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project 8 -Douglas to Teeland 230 kV Transmission Line (Upgrade)*The Douglas to Teeland line was originally constructed for operation at 138 kV and currently operates at 138 kV.Thisis an important line for the reliability of the Railbelt transmission system.Presently,thisis the only line connecting the Anchorage area to the Alaska intertie and to the Fairbanks area.With the construction of the Lake Lorraine to Douglas 230 kV line,an outage on the Teeland to Douglas line does not cause reliability problems in the Anchorage area on the MEA system.This line wil!be upgraded to 230 to facilitate the link between the Northern Intertie which will be operated at 230 kV and the Teeland to Lucas section of line which is also proposed for 230 kV operation.Figure 12-9 presents the proposed upgrade.This line is currently experiencing frequent outages consequently could be classified as a replacement category 3 project. Figure 12-9 Douglas to Teeland 230 kV Transmission Line Upgrade Willow Douglas dow L "leet rid iiElecticv4 rview ,o LRGsSAASPEAaA/, Black &Veatch 12-11 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY 12.5.4 Priority 4 Projects Project 9 -Healy to Gold Hill 230 kV Transmission Line (Upgrade) The existing Healy to Gold Hill 138 kV line was constructed and placed in service in 1968.This line serves as a Northern Intertie delivering economy power to Fairbanks from the Anchorage and Kenai area.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 insulated to 230 kV although it would be operated at 138 kV.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.This project is a replacement (Category 3)project. Figure 12-10 Healy to Gold Hill 230 kV Transmission Line Upgrade , TOOT oad Pres 2 =ata :TF 7 .FE RAS meal 4 : .ony ; wet Meleeee}oe eet oo DAAsenpee:wine 1 £: / cones ;OF nen Dame Dn ae Pasi We Race freee6 |Gold Hill eee ee?,. , A j am ee vee es _we mee Ee 4 ect eeeeoef7iiGoldenValleyElectricAssociation; wae ee cL mR Se eee ee Black &Veatch 12-12 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project 10 -Healy to Wilson 230 kV Transmission Line (Upgrade) The upgrade of the Healy to Wilson line for operation at 230 kV is needed to satisfy the N-1 reliability criteria for supply to the Fairbanks area.Operation of this line along with the previous Healy to Gold Hill line is a part of the phased development of a reliable 230 kV backbone of transmission facilities.Figure 12-11 presents the proposed upgrade.This is a GRETC Category 4 project. Figure 12-11 Healy to Wilson 230 kV Transmission Line Upgrade FE RTEFeBEE ERT al ea ol rome SE EE ae SY ASPROTEPPrefa.semeiaaitel |Oe be pe NnGoldHill©paveset}tre Para eeSeoe "b.Wilsoni Set ire 4 rol . ey sencetyesBee ae a mate i ca : Be rer '] ll '4aa q :BA rteetHed 1, 7 ow * f z 'Healy wan,™vw acre mt eer cen Ni sae ts Re fea abs ral WelsEA SABE OEM ae A be at OL Ce reee a fd Cee Pe,See eee Se 2)Seere 2 weedre wm oroee Con See ee:ae ad 12-13 December 2009Black&Veatch DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project 11 -Soldotna to Bradley Lake 115 kV Transmission Line (Reconductor/Upgrade) The Soldotna to Bradley Lake 115 kV line serves several distribution substations on the Kenai from Ski Hill, Kasilof,Anchor Point,Diamond Ridge,and Fritz Creek.he existing line is in poor condition and has a very small conductor size.The small conductor size on this line segment results in high impedance and limited capacity transfer along the line.Outage of the express Soldotna to Bradley Lake 115 kV line,results in low voltages and line overloads in the southern Kenai.This proposed project reconductors this section of line with larger conductor at the existing transmission line voltage.Figure 12-12 presents the proposed upgrade.This project is a replacement (Category 3)project. Figure 12-12 Soldotna to Bradley Lake 115 kV Transmission Line Upgrade Piva atChes-hetehtnnde-tnntarhiarenae aie nantoat yy Ny nv:|OO Bradley Lake Black &Veatch 12-14 December 2009 DRAFT REPORT SECTION 12 -TRANSMISSION PROJECTS ALASKA RIRP STUDY Project 12 -Daves Creek to Seward 115 kV Transmission Line (New Build) 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.he transmission line runs primarily through the Department of Forestry lands with sections along the Alaska Rail Road.The City of Seward is a full-requirements customer of Chugach and has a winter peak load of approximately 10 MW. This proposed project is anew 115 kV line from Daves Creek to SES in order to meet the N-1 criteria for the city of Seward.It should be noted,that while this proposed project meets the GRETC concept criteria,the project cost relative to the size of the load served may dictate that this project be postponed until load increases sufficiently to justify the capital expenditures.An interim approach could be to construct a 115 kV line from Lawing to Seward so that SES is supplied directly at 115 kV.In that instance,outages of the existing line from Daves Creek would be covered by using the city of Seward's existing and future diesel units as back-up.Figure 12-13 presents the proposed upgrade.This is a GRETC Category 4 project. Figure 12-13 New Daves Creek to Seward 115 kV Transmission Line ;|f "--.fi:Daves Creek|ot 2 - ae.f :i ;'i] Se Me Onartz Creek'Nee*"a Siet i . .:ws ,}ve!an ¢ fe Poe,aN a ': Kenai Peninsula -|of ren - ]'id ', \im '''\\.=f ; .ee ae a ;ie Sear Créek SO |:pe ::Mey a ren,o 5 etnnn yr ;i._arres)2 ¢é Le rae }.!oe \?ao eee Seward FO5fNernoea foo 8 'Lowe my oO:7 Jt oh A yy oe et'|ie ra 4 74 : °'AVIUK hi A _ Black &Veatch 12-15 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY 12.5.5 Priority 5 Projects Project 13 -Eklutna to Lucas 230 kV Transmission Line (New Build) The existing Eklutna to Lucas line needs to be rebuilt and this project satisfies this need.This project will be constructed and insulated to 230 kV standards and will be operated at 230 kV once the line from Teeland to Lucas is upgraded to 230 kV or a new 230 kV line from Teeland is brought into service.Figure 12-14 presents the proposed project.This is a GRETC Category 4 project. Figure 12-14 New Eklutna to Lucas 230 kV Transmission Line a,*_-.Do Me RRL ew Fs .Pbio Ait aoe eeae*4 °. Cae;33,emceefte>9 *aOnToTecland|=eisGiCa rereha Black &Veatch 12-16 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project 14-Lucas to Teeland 230 kV Transmission Line (Upgrade) The existing 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 Pt.Mackenzie to Teeland 230 kV line. This situation is greatly alleviated by the construction of Project 4 (Lake Lorrain to Douglas 230 kV line). However upgrade of this section of transmission line is required to satisfy the GRETC criteria of equal reliability under an N-1 outage criteria.Figure 12-15 presents the proposed upgrade.This project is a replacement (Category 3)project. Figure 12-15 Lucas to Teeland 230 kV Transmission Line Upgrade Cay aLreeeeeoa RS wef : :bh be TP, Black &Veatch 12-17 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Project 15 -Lucas to Teeland 230 kV Transmission Line (New Build) The new Lucas to Teeland 230 kV line is required to satisfy the N-1 criteria for reliability in the MEA area. Figure 12-16 presents the proposed upgrade.This is a GRETC Category 4 project. Figure 12-16 New Lucas to Teeland 230 kV Transmission Line Peaellkai .§.&-_ ae a a encnetFAT cebitnage Black &Veatch 12-18 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY 12.5.6 Priority 6 Projects Project 16 -Pt.Mackenzie to Plant 2 230 kV Transmission Line (Rebuild) The existing Pt.Mackenzie to MP&L 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 line is currently in reasonably good condition but is expected to be in need of replacement and repairs by 2025.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.This project is a replacement (Category 3) project. Figure 12-17 Pt.Mackenzie to Plant 2 Transmission Line Rebuild et |gt fae * bee ea [=i ae -: West Terminal Sa ie Tt N.'.tr 4 4 'PY EastTerminalmg ea eaeiLovineceySARi 4 « .wimhaear 'Pt.Mckenzie | 2 te ” s Plant2 peco ts Seer | Black &Veatch 12-19 December 2009 DRAFT REPORT TRANSMISSION PROJECTS ALASKA RIRP STUDY SECTION 12 12.6 Summary of Transmission Projects The list of transmission projects are presented in Table 12-1,and their locations are shown in Figure 12-18. Table 12-1 also includes the estimated costs for each of the listed projects.Note that this list does not include 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.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 Selected Transmission Projects No.|Transmission Projects Type Cost ($000)Priority 1 Soldotna -University New Build (230kV)$161,250 1 2 Soldotna -Quartz Creek Upgrade (230kV)$84,000 1 3 Quartz Creek -University Upgrade (230kV)$112,500 1 4 Lake Lorraine -Douglas New Build (230kV)$46,200 2 5 Douglas -Healy Upgrade (230kV)$12,000 2 6 Douglas -Healy New Build (230kV)$252,000 3 7 |Beluga-Pt.Mackenzie New Build (230kV)$67,700 3 8 Douglas -Teeland Upgrade (230kV)$37,500 3 "9 Healy -Gold Hill Upgrade (230kV)$145,500 4 10 |Healy -Wilson Upgrade (230kV)$145,500 4 11 |Soldotna -Bradley Lake Upgrade (115kV)$61,800 4 12 |Daves Creek -Seward New Build (115 kV)$28,000 4 13.|Eklutna -Lucas New Build (230kV)$13,300 5 14 |Lucas -Teeland Upgrade (230kV)$26,100 5 15 |Lucas -Teeland New Build (230kV)$26,100 5 16 |Pt.Mackenzie -Plant 2 Replacement (230kV)$32,200 6 Black &Veatch 12-20 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Figure 12-18 Project Location = ye - aoe ax«an? Naw soe' soiFALY226eeere A - .tyneeANFALMonma [ERacuavedqsey Black &Veatch 12-21 December 2009 DRAFT REPORT SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY 12.7.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 -SVC). e Providing or assisting with the provision of other Anciliary 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 transforms or substations) Several of these projects have been identified and discussed while others will result from the transmission reliability assessment to be done by EPS.Potential projects in this category include: Substation Capacitor Banks Series Capacitors SVCs Battery Energy Storage Systems 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. Projects that could facilitate or complement the implementation of other projects such as 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 Battery Energy Storage System (BESS)that could 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,the costs for each such system was included in the analysis in Section 13. Black &Veatch 12-22 December 2009 DRAFT REPORT 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 base 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 Base Cases In this subsection,we provide summaries of the base 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 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 four Evaluation Scenarios.Additional summary information on the results of each base case is provided at the end of this section.Detailed model output for each of the base cases are provided in Appendices F-I. 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 of these screened residential and commercial DSM/EE measures,they were selected at the maximum limits in each of the four Evaluation Scenarios.As discussed in Section 11, these maximum limits were 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 December 2009 DRAFT REPORT SUMMARY OF RESULTS ALASKA RIRP STUDY SECTION 13 Figure 13-1 Impact of DSM/EE Resources -Base Case Load Forecast Oemand (MW)Energy Requirements (MWh) -Without DSM/EE -Without DSM/EE 4,400 With DSM/EE 8,000,000 --With DSM/EE L 4,200 =7,006,000 4,000 <=_--=5,000,000=800 23©4,000,000 @ 600 Fa 8 &3,000,000 400 3B 2,000,00020051,000,000 ie]eRe oO eeeee TTT eT er °SSERSRERRSBSRBEEERS ES RSPR Ree aneeeyaaaRRREREERRRRRREREESESERSERE2RRREE82YearYear 13.1.2 Results -Scenario 1A Base Case Figure 13-2 Results -Scenario 1A Base Case Capacity By Resource Type =Ocean Tidal1600pacityByyP'Wea 7000 EnergyBy Resource Type 1m MuricipalSolidWaste}1400 ny,a Geothermal 6000 1200 -w Hydro ©Ocean Tidal=Purchase Power 000 Wind @ Fuel Oi z @ Municipal Sold Wasts| w Nuclear &4000 &Geothermal @ Coal 8 coo Hydro :@ Natural Gas.y @ Purchate Power 'wl 5 FuelOil we 2000 my @ Nuclear ':"mCosl .L 4000 @ NatralGas S258 9SRBELRRRRR °.< 13.1.3 Results -Scenario 1B Base Case Figure 13-3 Results -Scenario 1B Base Case 1600 Capacity By Resource Type 7000 Energy By Resource Type 6000 =Ocean Tidal @ Ocean Tidal |Wind |Wind =1 Municipal Solid Waste z w Municipal Sofid Waste =#Geothermal g ®Geothermal 2 Hyde 9 Hydro3aPurchasePowerFi@Purchase Power °Fuel Oi a |Ale FvtonjwNuciear-iB]@ Nuclear eco 7 -Aja Coal w Natural Ges <.@ Natural Gas ds SZERR 28523288828EERRRERSSESLERERE Black &Veatch 13-2 December 2009 DRAFT REPORT SECTION 13 SUMMARY OF RESULTS | ALASKA RIRP STUDY 13.1.4 Results -Scenario 2A Base Case Results Figure 13-4 Results -Scenario 2A Base Case 3000 Capacity By Resource Type e000 Energy By Resource Type 2500 pm 12000 a Ocean Tidal |Ocean Tidal2000Wind10000weWind=mMuicipal Solid Waste m Municipal Solid Waste nd 1a Geothermal a Geothermala.Hydro HydroaPurchasePowermPurchase Power°£QaFueioi fon fi FuelOil_qmNuclear oe ")qanuclear.mCoa}ae wCoal7mwNaturalGasiaay.@ NaturalGas 0 .. 0 =SE BR 9 o <&29 2 TF ERBRRRARBRBEESBBERBBERRSRESEZEE222222RRRRRSRSRRSRRAREER 13.1.5 Results -Scenario 2B Base Case Results Figure 13-5 Results -Scenario 2B Base Case 3800 Capacity By Resource Type 4000 Energy By Resource Type 3000 p=42000 ---4:im Ocean Tidal |a Ocean Tidal2500=Wind 10000 =Wind=BE Municipal Solid Waste|=@ Municipal Solid Waste;z 2000 =Geothermal &8000 ®Geothermal 8 Hydro 8 HydroPy1500«Purchase Power y mPurchase Power °wFuel Oi wi m@ Nuclear .wCoal . ;*\ 9]NaturalGas 0 ' 0 cEERSRARRRE 2228 SEERSLSBRBSERESRSBEREERSSS828323228288RRRESSSSSSSS88888s 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 Scenario 1A Without DSM/EE Measures Scenario 1A With Committed Units Included Scenario 1A Without CO,Costs Scenario 1A With Higher Gas Prices Scenario 1A With Fire Island Scenario 1A Without Chakachamna Scenario 1A With Chakachamna Capital Costs Increased by 75% Scenario 1A With Susitna (Lower Low Watana Non-Expandable Option)Forced Scenario 1A With Susitna (Low Watana Non-Expandable Option)Forcedeeeee#eeoe8#8e6°®Black &Veatch DRAFT REPORT 13-3 December 2009 SECTION 13 | SUMMARY OF RESULTS ALASKA RIRP STUDY Scenario 1A With Susitna (Low Watana Expandable Option)Forced Scenario 1A With Susitna (Low Watana Expansion Option)Forced Scenario 1A With Susitna (Watana Option)Forced Scenario 1A With Susitna (High Devil Canyon Option)Forced Scenario 1A With Modular Nuclear Scenario 1A With Tidal 13.2.2.Sensitivity Results -Scenario 1A Without DSM/EE Measures Figure 13-6 Sensitivity Results -Scenario 1A Without DSM/EE Measures Energy By Resource Type @ Ocean Tidal @ Wind wa Municipal Solid Waste: =Geothermal Hydro @ Purchase Power eg Fuel ol -+%@ Nucear +gacoa pe Natural GasCapacity(MW)ENERGY(GWh)13.2.3 Sensitivity Results --Scenario 1A With Committed Units Included Figure 13-7 Sensitivity Results -Scenario 1A With Committed Units Included 2000 Capacity By Resource Type 7000 Energy By Resource Type 1800 ' 60001600=Js Ocean Tidal Ocean Tidal1400aWindWind ="1m MunicipalSofidWaste!=mMuricipalSoldWaste=1200 #Geothermal z =Geothermal E 1000 Hydro 5 Mf tydo <|=Purchase Power &@ Purchase Power gs 800 1 Fue!Cit Fi +:Ja eva on 600 "im Nuclear _.gu Nudear Bmcoal ",Yacoa400@NaturalGas@Natural Gas 200 ¢o °0 E=E&SsaR &3 x 388 8 =sZFESRRBE BBE §3883 8 8ERRRSESR222222ERESRS82822222222 Black &Veatch 13-4 December 2009 DRAFT REPORT SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY |13.2.4 Sensitivity Results -Scenario 1A Without CO,Costs Figure 13-8 Sensitivity Results -Scenario 1A Without CO,Costs 1600 Capacity By Resource Type -e000 Energy By Resource Type 1400 i { 70001200yp#8 Ocean Tidal 6000 ”[es Ocean Taal "aWind -aWindz1000wsMuricipalSolidWaste!3 5000 mMuricipal Solid Waste280054000'1 Geothermal3efHydro fz]600 3 3000 :@ Purchase PowerFuel0} 400 2000 aNuclear pe ae Pe an .S acoal 200 1000 a aT a en NaturalGas °_Par 88988 : 8EEERRRRRRRETERESEZERRERZREEEEERERakadRRReseize222RRRRRRRRRRRARRRRR 13.2.5 Sensitivity Results --Scenario 1A With Higher Gas Prices Figure 13-9 Sensitivity Results -Scenario 1A With Higher Gas Prices 4800 Capacity By Resource Type 7000 Energy By Resource Type 6000 m Ocean Tidal »-|Ocean Tidal=Wind 5000 |Wind =@ Muricipal Solid Waste|€° wMuricipal Solid Waste >@ Geothermal é 4000 «GeothermaleHydro3Hydro§Purchase Power a 3000 Purchase Power °«mF uel 01 it Fuel Oil wNucear 2000 a@Nuclear ;-faCoal ae *@ acoal"J w NaturalGas 4000 .ma NatualGas 0 sPrPePRPSPFNRkReaese Pes Fe Black &Veatch 13-5 December 2009 DRAFT REPORT SUMMARY OF RESULTS ALASKA RIRP STUDY SECTION 13 13.2.6 Sensitivity Results -Scenario 1A With Fire Island Figure 13-10 Sensitivity Results -Scenario 1A With Fire Island Capacity By Resource Type 7000 Energy By Resource Type 4400 =Ocean Tidal =Ocean TidalWind.Wind =lm Municipal Solid Waste ={Muricipal Solid Waste| 2 t Geothermal >Geothermal a :Hydro g Hydro é "§)@ Purchase Power v 8 Purchase Power®t.fla Feel Ol ”=Fuel Oil27@|m Nuclear wNucear Coal y uCoal @ Natural Gas ",f wNatural Gas ° . ErnR 388523228 8 EZFERRRESRSRESETR RRRSEERESEZEELEZ222EEESRERZZR2E222222 13.2.7 Sensitivity Results -Scenario 1A Without Chakachamna Figure 13-11 Sensitivity Results -Scenario 1A Without Chakachamna 4800 Capacity By Resource Type 7000 Energy By Resource Type 6000 evenriaiaa 7 5000 *Ooven Tidal1MuricipalSolidWaste=4000 -4]m MunicipalSolidWastea=,4]3 Geothermal .ro "Zl Purchase Power i 3000 4 aw pothase Power©Fuel Ol!”*Fa Fustoi1@jm@Nuclear2000 Nudear <.g/t Coal ae +9m Natural Gas 1000 Netra!Guowad.a t) SEERRRESSBESERE RRR =g gRERRRRRREERRRREEGEeaRR8888282222 28 13.2.8 Sensitivity Results -Scenario 1A 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 the resource plan.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 13-11. Black &Veatch DRAFT REPORT 136 December 2009 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 13.2.9 Sensitivity Results -Scenario 1A With Susitna (Lower Low Watana Non-Expandable Option)Forced Figure 13-12 Sensitivity Results -Scenario 1A With Susitna (Lower Low Watana Non-Expandable Option)Forced 4800 Capacity By Resource Type 7000 Energy By Resource Type m Ocean Tidal a Ocean Tidat@WindaWind @ Muricipal Solid Waste e @Muricipal Solid Waste Geothemal a «Geothermal Hydro 5 Hydro mPurchase Power &Purchase Power Fuel Oil a eF uel OilmNuclearaNuclear Coal +cal]Coal mw Nateal Gas =Natural Gas 13.2.10 Sensitivity Results -Scenario 1A With Susitna (Low Watana Non-Expandable Option)Forced2011201420172020202320262029203220352038B-2041204420472050205320562059147013161922Figure 13-13 Sensitivity Results -Scenario 1A With Susitna (Low Watana Non-Expandable Option)Forced 2000 Capacity By Resource Type 7000 Energy By Resource Type 1800 1600 aveeniaines w Ocean Tidal Muricipal Solid Waste =aWind.&wMurcipalSofdWaste|Geothermal g=Geothermalvero@tyrawchasiwiaeolePowar3mPurchasePower Na Fuel Oilre.Nuclear .sural G : acoal.on wat as _.@ NaturalGas o 0Fa Ee 33588888ERRSSSRZEZER282 13.2.11 Sensitivity Results -Scenario 1A 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 13-13.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 December 2009 DRAFT REPORT SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 13.2.12 Sensitivity Results -Scenario 1A With Susitna (Watana Expansion Option)Forced Figure 13-14 Sensitivity Results -Scenario 1A With Susitna (Watana Expansion Option)Forced 2500 Capacity By Resource Type 7000 Energy By Resource Type . 6000 2000 nate Ocean Tidalarena.5000 =WindiMaricipalSoldWaste5somWiMaricipalSolidWaste®Geothermal 5 |Geothermal HydroaeeePower53000mPurchase Power =Fuel ol 2000 FuelOil m Nuclear i ---@ Nudear=Coal fone me "BCoal Im Natal Gas 1000 a NaturalGas 0 EEZeE SS §38 8 3 §88 8EFERBRSSRBREPERRREeekGheee2eh22282EekESSERE2882Bz=- 13.2.13 Sensitivity Results -Scenario 1A With Susitna (Watana Option)Forced Figure 13-15 Sensitivity Results -Scenario 1A With Susitna (Watana Option)Forced 3000 Capacity By Resource Type 7000 Energy By Resource Type 2500 3 Ocean Tidal @ Ocean Tidal 2000 =Wind m=Wind=&Muricipal Sold Waste i Muricipal Soid Waste 2 4500 8 Geothermal @ Geothermal H Hero a Pachace Power©1000 aa aaa a FurlOil "a =Nudear weet500fy° -=Coal Moo 'wy 'roy ae :g ®Natural Gas Neural Gas°i -a t)EZERRSSRSIRRELRI RSES SEERRE RS 3238 g22228882283222222ESERRESTEREEEEEee 13.2.14 Sensitivity Results -Scenario 1A With Susitna (High Devil Canyon Option)Forced Figure 13-16 Sensitivity Results -Scenario 1A With Susitna (High Devil Canyon Option)Forced 2500 Capacity By Resource Type 7000 -Energy By Resource Type 6000 So2000 @ Ocean Tidal =Ocean Tidal ¢=mmsneyf Vind .=Wind----}]m Municips!Sotd Waste|.Wi MunicipalSolidWaste|&1500 roe oP é 4000 =Geothermal d ald ri 3000 porches Peé|Purchase Power Zz ie Power Fuel Oil 8 FuelOil Ww Nuclear 2000 ee w Nuckar acca .mCoa Natal Gas to00 7 m NatalGas ''Fs . 0 EER88 288282222222 2 2 EEERRSRREREZEREE Black &Veatch 13-8 December 2009 DRAFT REPORT SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 13.2.15 Sensitivity Results -Scenario 1A With Modular Nuclear Figure 13-17 Sensitivity Results -Scenario 1A With Modular Nuclear Capacity By Resource Type 1200 Capacity(MW)Energy By Resource Type Ocean Tidal mWind mi Municipal Solid Waste} mm Geothermal Hydro m Purchase Power ENERGY(GWh)Ocean Tidal @Wind m@ Muricipal Solid Waste] a Geothermal Hydre mPurchase Power Fuel Oil aNuclear aCoal @ Natural Gas 13.2.16 Sensitivity Results -Scenario 1A With Tidal Figure 13-18 Sensitivity Results -Scenario 1A With Tidal Capacity By Resource Type moon Energy By Resource Type Capacity(MW)ne TT )ps Natural Gas Ocean Tidal mWind @ Municipal Solid Waste] §Geothermal Hydro. m Purchase Power a Fuel Oil m@ Nuclear mCoal ENERGY(GWh)«9 |@ Natural Gas mOcean Tidal mWind @ Municipal Solid Waste] Geothermal Hydro m@Purchase Power Fuel Oi! Nuclear mCoal 20322035F20382041204420472050205320562058201713.3.Summary of Results In this subsection,we provide a comparative summary of the economic and emissions results for all of the base and sensitivity cases. 13.3.1 Summary of Results -Economics Table 13-1 summarizes the economic results,including: *Cumulative present values cost °Average cost e Renewable energy in 2025 e Total capital investment Black &Veatch 13-9 December 2009 DRAFT REPORT SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY Table 13-1 Summary of Results -Economics Cumulative Renewable Present Value Average Cost Energy in 2025 Total Capital Case Cost ($000)(¢per kWh)(%)Investment ($000) Scenarios Plan 1A $12,924,812 4.60 49.17%$10,034,684 Plan 1B $12,916,210 4.59 54.78%$10,014,163 Plan 2A $20,977,580 4.29 53.57%$18,226,355 Plan 2B $21,506,536 4.40 55.55%$22,174,689 Sensitivities 1A Without DSM/EE Measures $13,261,877 4.40 51.10%$9,791,215 1A With Committed Units Included $13,863,265 4.93 32.03%$9,592,461 1A Without CO,Costs $10,401,631 3.70 14.36%$8,684,957 1A With Higher Gas Prices $14,944,729 §.31 61.94%$9,797,961 1A With Fire Island $12,964,719 4.61 54.78%$10,502,023 1A Without Chakachamna $13,273,472 4.72 22.80%$9,179,428 1A With Chakachamna Capital Costs Increased $13,273,472 4.72 22.80%$9,179,428 by 75% 1A With Susitna (Lower Low Watana Non-$15,208,996 5.41 54.70%$13,166,343 Expandable Option)Forced 1A With Susitna (Low Watana Non-Expandable $14,898,313 5.30 60.18%$14,742,083 Option)Forced 1A With Susitna (Low Watana Expandable $15,437,027 5.49 60.18%$15,273,597 Option)Forced 1A With Susitna (Low Watana Expansion $15,943,324 5.67 61.58%$15,901,641 Option)Forced 1A With Susitna (Watana Option)Forced $16,281,157 5.79 61.82%$16,049,421 1A With Susitna (High Devil Canyon Option)$16,238,375 5.77 61.82%$16,016,000 Forced 1A With Modular Nuclear $12,590,556 4.48 49.05%$9,864,041 1A With Tidal $12,198,214 4.34 59.10%$10,051,986 Black &Veatch 13-10 December 2009 DRAFT REPORT SUMMARY OF RESULTS ALASKA RIRP STUDY SECTION 13 13.3.2 Summary of Results -Emissions Table 13-2 summarizes the emissions-related results of all of the base and sensitivity cases.The following information is provided for each case: e CO,emissions e NO,emissions e SO,emissions DRAFT REPORT Table 13-2 Summary of Results -Emissions Case CO,(tons)NO,(tons)SO,(tons) Scenarios Plan 1A 176,204,623,551 222,216,367 36,328,052 Plan 1B 169,439,541,486 216,377,884 33,078,058 Plan 2A 287,320,716,438 281,021,636 240,492,147 Plan 2B 250,459,659,924 245,372,307 74,838,100 Sensitivities 1A Without DSMW/EE Measures 181,207,564,318 181,207,564,318 |181,207,564,318 1A With Committed Units Included 219,645,268,063 350,850,044 272,682,069 1A Without CO,Costs 222,613,806,040 294,549,974 382,983,114 1A With Higher Gas Prices 166,406,292,550 248116046.4 267852556.4 1A With Fire Island 166,934,231,133 223442326.3 38607718.2 1A Without Chakachamna 219,109,779,504 222,591,795 34,949,762 1A With Chakachamna Capital Costs 219,109,779,504 222,591,795 34,949,762 Increased by 75% 1A With Susitna (Lower Low Watana Non-158,703,320,276 209,771,548 35,377,946 Expandable Option)Forced 1A With Susitna (Low Watana Non-127,589,064,780 207,145,332 37,742,698 Expandable Option)Forced 1A With Susitna (Low Watana Expandable 127,589,064,780 207,145,332 37,742,698 Option)Forced 1A With Susitna (Low Watana Expansion 140,911,597,135 207,888,578 37,953,070 Option)Forced 1A With Susitna (Watana Option)Forced 138,140,275,780 208,616,774 39,419,567 1A With Susitna (High Devil Canyon 134,779,936,034 208,259,687 39,406,754 Option)Forced 1A With Modular Nuclear 162,857,677,754 223,697,768 37,028,776 1A With Tidal 153,908,430,292 212,576,692 33,361,540 Black &Veatch 13-11 December 2009 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY 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,would 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 projects to connect new generation projects to the grid (Generation Interconnections) e Transmission projects to upgrade the grid required by a new generation project (Generation Upgrades) Replacement projects that need to be done because of age and condition (Replacement) Upgrade projects to the grid to implement the GRETC concept (GRETC) 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 13-12 December 2009 DRAFT REPORT SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY Table 13-3 Recommended Transmission Projects No.|Transmission Projects Type .Cost ($000)Priority 1 Soldotna -University New Build (230kV)$161,250 1 2 Soldotna -Quartz Creek Upgrade (230kV)$84,000 1 3 Quartz Creek -University Upgrade (230kV)$112,500 1 4 Lake Lorraine -Douglas New Build (230kV)$46,200 2 5 |Douglas -Healy Upgrade (230kV)$12,000 2 6 Douglas -Healy New Build (230kV)$252,000 3 7 Beluga -Pt.Mackenzie New Build (230kV)$67,700 3 8 |Douglas -Teeland Upgrade (230kV)$37,500 3 9 Healy -Gold Hill Upgrade (230kV)$145,500 4 10 |Healy -Wilson Upgrade (230kV)$145,500 4 11 |Soldotna -Bradley Lake Upgrade (115kV)$61,800 4 12 |Daves Creek -Seward New Build (115 kV)$28,000 4 13 |Eklutna-Lucas New Build (230kV)$13,300 5 14 |Lucas-Teeland Upgrade (230kV)$26,100 5 15 |Lucas -Teeland New Build (230kV)$26,100 5 16 |Pt.Mackenzie -Plant 2 Replacement (230kV)$32,200 6 The following issues result from our transmission analysis: e We were unable to complete a stability analysis based upon our recommended transmission system configuration prior to the development of this Draft Report.This analysis is required to ensure that the recommended transmission system expansions and enhancements result in the necessary stability to ensure reliable electric service over the planning horizon.The results of the stability analysis may result in some modifications to our recommended list of transmission projects.This analysis is currently underway by EPS and the results will be included in the Final Report. 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: o Providing reactive power (static var compensators -SVC) 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) Several of these projects have been identified and discussed while others will result from the transmission reliability assessment to be done by EPS.Potential projects in this category include: o Substation capacitor banks o Series capacitors Black &Veatch DRAFT REPORT 13-13 December 2009 SECTION 13 SUMMARY OF RESULTS 13.5 ALASKA RIRP STUDY o SVCs o Battery energy storage systems o 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,the costs for each such system were included in the analysis. 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 discussion 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 for 230 kV and review a transmission routing for the new Southern Intertie that would begin at the Soldotna 230 kV substation to Bernice Lake substation along the Kenai 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 University 230 kV substation. 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. 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 13-19 summarizes the cumulative capital investment required for each of the four base cases. Black &Veatch 13-14 December 2009 DRAFT REPORT SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY Figure 13-19 Required Cumulative Capital Investment for Each Base Case Cumulative Capital Investment -$25,000,000 -Scenario 1A --Scenario 1A - $20,000,000 -Scenario 2A (---Scenario 2B $15,000,000 _-_ssosonce mz,Vi ee $5,000,000 fi CumulativeCapitalInvestment($000,000'$0 Da ne ene ae ee ee eeeeee ee ee -OwnH Mw Or MWe Or OW he DH YO HO KRM Or YO YO KM DDTrrercrNNNNNOYMOHYMWHOATFFTrwTFnonowwoobWOgoooooqoeoqooe90o0oe90e69dpUmWmlmlUCcUmMUCUCUUCONUCONUCOUCNIUUCUCUCUULUCNWCUCUDOULUCOHLCNH]OUCNMWCLCUCOUCDNNNNNNNNNNENNNNNNNNNNNNNNSN 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 and federal 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 C. 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 13-20 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 over time. Black &Veatch 13-15 December 2009 DRAFT REPORT SECTION 13 -SUMMARY OF RESULTS ALASKA RIRP STUDY Figure 13-20RequiredCumulativeCapitalInvestment(Scenario 1A)Relative to Railbelt Utility Debt Capacity $10,000.000,000 Capital Expenditures ri $7,500,000,000 i$5,000,000,000 ./Hizh Debt Capacity Low Debt Capacity $2,500,060,000 $0 +n 2020202320262029:2032203520382041Source: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,and will have lower-cost access to debt capital than the utilities would have on their own. e 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 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 balance of these two funding approaches appears to be the most effectivein lowering the overall cost of the RIRP,as well as spreading out the costs over a longer period of time. o Construction Workin Progress (CWIP)-CWIPis a funding technique 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. o State Financial Assistance -State financial assistance could take a variety of forms;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 potentially lower cost of capital. e The overall objective of SNW's analysis was to identify ways to overcome the funding challenges inherent with large-scale projects and develop strategies that could be used to produce levelized power cost 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 would be immediately passed through to the ratepayers;the projects being financed in the second half of the 50-year period would be financed through "pay go”capital,as debt service coverage from previous years has grown to sufficient levels Black &Veatch 13-16 December 2009 DRAFT REPORT SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY to allow the balance of the reserve 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,structured in a manner similar to the Bradley Lake 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). e 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.In the alternative case,the maximum fixed charge rate on the capital portion alone is $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 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 a necessary next step towards achieving the goal of ensuring future reliable energy for the Railbelt region. Black &Veatch 13-17 December 2009 DRAFT REPORT SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY Scenario 1A Year Unit Additions 2011 Anchorage MSW 2012 GVEA MSW 2013 Anchorage 1x1 6FA 2014 2015 Glacier Fork 2016 2017 Nikiski Wind 2018 2019 2020 GVEA 1x1 6FA 2021 Anchorage LM6000 2022 GVEA LMS100 2023 2024 2025 Chakachamna 2026 2027 2028 2029 2030 Mount Spurr 2031 2032 2033 2034 2035 2036 2037 GVEA LMS100 2038 2039 2040 2041 2042 GVEA 1x1 6FA 2043 2044 2045 2046 Mount Spurr 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 Anchorage LM6000 2058 2059 2060 Anchorage LM6000 Cumulative Present Worth Cost ($000) $12,924 812 Renewable Energy % In 2025 49.17% Total Capital Investment ($000) $10,034,684 Black &Veatch DRAFT REPORT 13-18 December 2009 SECTION 13 SUMMARY OF RESULTS Scenario 1B Year Unit Additions 2011 Anchorage MSW 2012 GVEA MSW 2013 Anchorage 1x1 6FA 2014 2015 Glacier Fork 2016 2017 Nikiski Wind 2018 Anchorage LM6000 2019 2020 GVEA 1x1 6FA 2021 Mount Spurr 2022 GVEA LMS100 2023 2024 2025 Chakachamna 2026 2027 2028 2029 2030 Kenai Wind 2031 2032 2033 2034 2035 2036 2037 Anchorage LMS100 2038 2039 2040 2041 2042 GVEA 1x1 6FA 2043 2044 2045 2046 Mount Spurr 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 Anchorage LM6000 2058 2059 2060 Anchorage LM6000 Cumulative Present Worth Cost ($000) $12,916,210 Renewable Energy % In 2025 54.78% Total Capital Investment ($000) $10,014,163 Black &Veatch DRAFT REPORT 13-19 ALASKA RIRP STUDY December 2009 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY Scenario 2A Year Unit Additions 2011 Anchorage MSW 2012 GVEA MSW 2013 Anchorage 1x1 6FA 2014 2015 Nikiski Wind 2016 2017 Anchorage LM6000 2018 Kenai Hydro 2019 2020 GVEA 1x1 6FA 2021 GVEA Wind 2022 Anchorage 1x1 6FA 2023 2024 2025 Chakachamna Low Watana (Non-Expandable) 2026 2027 2028 2029 2030 HEA 1x1 6FA Healy Clean Coat Project 2031 2032 2033 2034 2035 2036 2037 GVEA 2x1 6FA 2038 2039 2040 Anchorage 2x1 6FA 2041 2042 Mount Spurr 2043 2044 2045 2046 Mount Spurr 2047 2048 2049 2050 2051 HEA LM6000 2052 2053 2054 2055 2056 HEA LM6000 2057 2058 2059 GVEA LM6000 2060 Cumulative Present Worth Cost ($000) $20,977,580 Renewabie Energy % In 2025 53.57% Total Capital Investment ($000) $18,226 355 Black &Veatch DRAFT REPORT 13-20 December 2009 SECTION 13 SUMMARY OF RESULTS Scenario 2B Year Unit Additions 2011 Anchorage MSW Cumulative Present Worth Cost ($000) 2012 GVEA MSW $21,506,536 2013 Anchorage 1x1 6FA 2014 Fire Island 2015 Nikiski Wind 2016 Renewable Energy % In 2025 2017 Anchorage LM6000 §5.55% 2018 Kenai Hydro 2019 2020 GVEA 1x1 6FA 2021 GVEA Wind Total Capital Investment ($000) 2022 Anchorage 1x1 6FA $22,174,689 2023 2024 2025 Chakachamna Low Watana (Expandable) 2026 2027 2028 2029 2030 Mount Spurr 2031 2032 2033 2034 Anchorage 1x1 6FA 2035 2036 2037 2038 2039 2040 GVEA 2x1 6FA Low Watana Expansion Mount Spurr GVEA Wind (2) 2041 2042 2043 2044 2045 2046 HEA 1x1 6FA 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 Kenai Wind Healy Clean Coal Project 2058 2059 2060 ALASKA RIRP STUDY Black &Veatch DRAFT REPORT 13-21 December 2009 SECTION 13 SUMMARY OF RESULTS Scenario 1A Without DSM/EE Measures Year Unit Additions 2011 Anchorage MSW Cumulative Present Worth Cost ($000) 2012 GVEA MSW Healy Clean Coal Project $13,261,877 2013 Nikiski Wind 2014 Glacier Fork 2015 Anchorage 1x1 6FA 2016 Renewable Energy % In 2025 2017 Kenai Wind 51.10% 2018 Anchorage LM6000 2019 2020 GVEA 1x1 6FA 2021 Anchorage 1x1 6FA Total Capital Investment ($000) 2022 Kenai Hydro $9,791,215 2023 2024 2025 Chakachamna 2026 2027 2028 2029 2030 Mount Spurr 2031 2032 2033 2034 2035 2036 2037 Mount Spurr 2038 2039 2040 2041 2042 Anchorage 1x1 6FA 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 DRAFT REPORT 13-22 December 2009 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY |Scenario 1A With Committed Units Included Year Unit Additions Anchorage MSW Seward 1&2 Cumulative Present 2011 Healy Clean Coal Project Worth Cost ($000) GVEA MSW MLP LM2500 $13,863,265 2012 Nikiski 2013 HEA Frame Southcentral Power Project MLP 6000 2014 HEA Aero 2015 Eklutna Generation Renewable Energy % 2016 In 2025 2017 Glacier Fork 32.03% 2018 2019 Nikiski Wind 2020 Kenai Wind Total Capital 2021 Kenai Wind investment ($000) 2022 Kenai Wind $9,592,461 2023 GVEA Wind 2024 GVEA Wind 2025 Anchorage 1x1 6FA 2026 2027 2028 2029 2030 Mount Spurr 2031 2032 2033 2034 2035 2036 2037 Mount Spurr 2038 2039 2040 2041 2042 GVEA 1x1 6FA 2043 2044 2045 2046 Fire Island 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 Anchorage LMS100 2058 2059 2060 GVEA LM6000 Black &Veatch 13-23 December 2009 DRAFT REPORT SUMMARY OF RESULTS ALASKA RIRP STUDY SECTION 13 |Scenario 1A Without CO2 Costs | Year Unit Additions 2011 Anchorage MSW Cumulative Present Worth Cost ($000) 2012 GVEA MSW Healy Clean Coal Project $10,401,631 2013 2014 2015 Anchorage 1x1 6FA 2016 Renewable Energy % In 2025 2017 14.36% 2018 2019 2020 Anchorage LMS100 2021 Anchorage 1x1 6FA Total Capital Investment ($000) 2022 GVEA LM6000 $8,684,957 2023 2024 2025 2026 Chakachamna 2027 2028 2029 2030 2031 2032 Anchorage LMS100 2033 2034 2035 2036 2037 2038 2039 2040 GVEA 1x1 6FA 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 GVEA LMS100 2052 2053 2054 2055 2056 2057 2058 2059 Anchorage LM6000 2060 Black &Veatch DRAFT REPORT 13-24 December 2009 SECTION 13 SUMMARY OF RESULTS Scenario 1A With Higher Gas Prices _| Year Unit Additions 2011 Anchorage MSW Cumulative Present Worth Cost ($000) 2012 Nikiski Wind $14,944,729 2013 Anchorage 1x1 6FA 2014 Glacier Fork 2015 GVEA Wind 2016 Renewable Energy % In 2025 2017 Kenai Wind 61.94% 2018 Mount Spurr Healy Clean Coal Project 2019 2020 Mount Spurr 2021 Anchorage LM6000 Total Capital Investment ($000) 2022 GVEA 1x1 6FA $9,797,961 2023 2024 2025 Chakachamna 2026 2027 2028 2029 2030 GVEA MSW 2031 2032 2033 2034 2035 2036 2037 GVEA LMS$100 2038 2039 2040 2041 2042 GVEA LMS100 2043 2044 2045 2046 Anchorage LM6000 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 GVEA LMS100 2058 2059 2060 Anchorage LM6000 ALASKA RIRP STUDY Black &Veatch DRAFT REPORT 13-25 December 2009 SUMMARY OF RESULTS ALASKA RIRP STUDY SECTION 13 |Scenario 1A With Fire Island 4 Year Unit Additions 2011 Anchorage MSW Cumulative Present Worth Cost ($000) 2012 Fire Island $12,964,719 2013 GVEA MSW 2014 Nikiski Wind 2015 Anchorage 1x1 6FA 2016 Renewable Energy % In 2025 2017 Glacier Fork 54.78% 2018 Anchorage LM6000 2019 2020 GVEA 1x1 6FA 2021 Kenai Wind Total Capital Investment ($000) 2022 GVEA LMS100 $10,502,023 2023 2024 2025 Chakachamna 2026 2027 2028 2029 2030 Mount Spurr 2031 2032 2033 2034 2035 2036 2037 GVEA LMS$100 2038 2039 2040 2041 2042 GVEA LMS$100 2043 2044 2045 2046 Mount Spurr 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 GVEA 1x1 6FA 2058 2059 2060 Black &Veatch DRAFT REPORT 13-26 December 2009 SECTION 13 SUMMARY OF RESULTS Scenario 1A Without Chakachamna | Year Unit Additions 2011 Anchorage MSW Cumulative Present Worth Cost ($000 2012 GVEA MSW $13,273,472 2013 Anchorage 1x1 6FA 2014 2015 Nikiski Wind 2016 Renewable Energy % In 2025 2017 Glacier Fork 22.80% 2018 Anchorage LM6000 2019 2020 GVEA 1x1 6FA 2021 Kenai Wind Total Capital Investment ($000) 2022 Anchorage 1x1 6FA $9,179,428 2023 2024 2025 GVEA LMS100 2026 2027 2028 2029 2030 GVEA 1x1 6FA 2031 2032 2033 2034 Anchorage 1x1 6FA 2035 2036 2037 2038 2039 2040 2041 2042 MEA LMS100 2043 2044 2045 2046 Mount Spurr 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 MEA LMS100 2058 2059 2060 Mount Spurr ALASKA RIRP STUDY Black &Veatch DRAFT REPORT 13-27 December 2009 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY {Scenario 1A With Chakachamna Capital Costs increased by 75%J Year Unit Additions 2011 Anchorage MSW 2012 GVEA MSW 2013 Anchorage 1x1 6FA 2014 2015 Nikiski Wind 2016 2017 Glacier Fork 2018 Anchorage LM6000 2019 2020 GVEA 1x1 6FA 2021 Kenai Wind 2022 Anchorage 1x1 6FA 2023 2024 2025 GVEA LMS100 2026 2027 2028 2029 2030 GVEA 1x1 6FA 2031 2032 2033 2034 Anchorage 1x1 6FA 2035 2036 2037 2038 2039 2040 2041 2042 MEA LMS100 2043 2044 2045 2046 Mount Spurr 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 MEA LMS100 2058 2059 2060 Mount Spurr Cumulative Present Worth Cost ($000) $13,273,472 Renewable Energy % In 2025 22.80% Total Capital Investment ($000) $9,179,428 Black &Veatch DRAFT REPORT 13-28 December 2009 SECTION 13 SUMMARY OF RESULTS |1A With Susitna (Lower Low Watana Non-Expandable Option)Forced Year Unit Additions 2011 Anchorage MSW 2012 GVEA MSW 2013 Anchorage 1x1 6FA 2014 Nikiski Wind 2015 Glacier Fork 2016 2017 Kenai Wind 2018 Anchorage LM6000 2019 2020 GVEA 1x1 6FA 2021 Anchorage LM6000 2022 Mount Spurr 2023 2024 2025 Kenai Wind Lower Low Watana 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 Anchorage 1x1 6FA 2038 2039 2040 2041 2042 Mount Spurr 2043 2044 2045 2046 GVEA LM6000 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 Anchorage LMS100 2058 2059 2060 GVEA LM6000 Cumulative Present Worth Cost ($000) $15,208,996 Renewable Energy % In 2025 54.70% Total Capital Investment ($000) $13,166,343 ALASKA RIRP STUDY Black &Veatch DRAFT REPORT 13-29 December 2009 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY [Scenario 1A With Susitna (Low Watana Non-Expandable Option)Forced | Year Unit Additions 2011 Anchorage MSW 2012 GVEA MSW 2013 Anchorage 1x1 6FA 2014 Nikiski Wind 2015 Glacier Fork 2016 2017 Kenai Wind 2018 Anchorage LM6000 2019 2020 GVEA 1x1 6FA 2021 Anchorage LM6000 2022 Mount Spurr 2023 2024 2025 Low Watana (Non-Expandable) 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 Chakachamna 2038 2039 2040 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) $14,898,313 Renewable Energy % In 2025 60.18% Total Capital Investment ($000) $14,742,083 Black &Veatch DRAFT REPORT 13-30 December 2009 SECTION 13 SUMMARY OF RESULTS ALASKA RIRP STUDY |Scenario 1A With Susitna (Low Watana Expandable Option)Forced Year Unit Additions 2011 Anchorage MSW 2012 GVEA MSW 2013 Anchorage 1x1 6FA 2014 Nikiski Wind 2015 Glacier Fork 2016 2017 Kenai Wind 2018 Anchorage LM6000 2019 2020 GVEA 1x1 6FA 2021 Anchorage LM6000 2022 Mount Spurr 2023 2024 2025 Low Watana (Non-Expandable) 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 Chakachamna 2038 2039 2040 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) $15,437,027 Renewable Energy % In 2025 60.18% Total Capital Investment ($000) $15,273,597 Black &Veatch DRAFT REPORT 13-31 December 2009 SECTION 13 SUMMARY OF RESULTS |Scenario 1A With Susitna (Low Watana Expansion Option)Forced Year Unit Additions 2011 Anchorage MSW 2012 GVEA MSW 2013 Anchorage 1x1 6FA 2014 Nikiski Wind 2015 Glacier Fork 2016 2017 Kenai Wind 2018 Anchorage LM6000 2019 2020 GVEA 1x1 6FA 2021 Anchorage LM6000 2022 Mount Spurr 2023 2024 2025 Kenai Wind Low Watana (Expandable) 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 GVEA Wind 2038 2039 2040 Low Watana Expansion 2041 2042 2043 2044 2045 2046 Fire Island 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 2058 2059 2060 Mount Spurr Cumulative Present Worth Cost ($000) $15,943,324 Renewable Energy % In 2025 61.58% Total Capital Investment ($000)_ $15,901,641 ALASKA RIRP STUDY Black &Veatch DRAFT REPORT 13-32 December 2009 SECTION 13 SUMMARY OF RESULTS Scenario 1A With Susitna (Watana Option)Forced i Year Unit Additions 2011 Anchorage MSW Cumulative Present Worth Cost ($000) 2012 GVEA MSW $16,281,157 2013 Anchorage 1x1 6FA 2014 Nikiski Wind 2015 Glacier Fork 2016 Renewabie Energy % In 2025 2017 Kenai Wind 61.82% 2018 Anchorage LM6000 2019 2020 GVEA 1x1 6FA 2021 Anchorage LM6000 Total Capital Investment ($000) 2022 Mount Spurr $16,049,421 2023 2024 2025 Watana Kenai Wind 2026 2027 2028 2029 2030 Kenai Wind 2031 2032 2033 2034 2035 2036 2037 Fire Island 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 2058 2059 2060 Mount Spurr ALASKA RIRP STUDY Black &Veatch DRAFT REPORT 13-33 December 2009 SECTION 13 SUMMARY OF RESULTS Scenario 1A With Susitna (High Devil Canyon Option)Forced Year Unit Additions 2011 Anchorage MSW Cumulative Present Worth Cost ($000) 2012 GVEA MSW $16,238,375 2013 Anchorage 1x1 6FA 2014 Nikiski Wind 2015 Glacier Fork 2016 Renewable Energy % In 2025 2017 Kenai Wind 61.82% 2018 Anchorage LM6000 2019 2020 GVEA 1x1 6FA 2021 Anchorage LM6000 Total Capital Investment ($000) 2022 Mount Spurr $16,016,000 2023 2024 2025 Kenai Wind High Devil Canyon 2026 2027 2028 2029 2030 Kenai Wind 2031 2032 2033 2034 2035 2036 2037 Mount Spurr 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 DRAFT REPORT 13-34 December 2009 SECTION 13 SUMMARY OF RESULTS Scenario 1A With Modular Nuclear Year Unit Additions 2011 Anchorage MSW Cumulative Present Worth Cost ($000) 2012 GVEA MSW $12,590,556 2013 Anchorage 1x1 6FA 2014 2015 Nikiski Wind 2016 Renewable Energy % In 2025 2017 Glacier Fork 49.05% 2018 2019 2020 GVEA 1x1 6FA 2021 Anchorage LM6000 Total Capital Investment ($000) 2022 GVEA LMS100 $9,864,041 2023 2024 2025 Chakachamna Anchorage Nuclear 2026 2027 2028 2029 2030 Mount Spurr 2031 2032 2033 2034 2035 2036 2037 Mount Spurr 2038 2039 2040 2041 2042 Anchorage 1x1 6FA 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 GVEA LMS100 2058 2059 2060 Anchorage LM6000 ALASKA RIRP STUDY Black &Veatch DRAFT REPORT 13-35 December 2009 SUMMARY OF RESULTS ALASKA RIRP STUDY SECTION 13 j Scenario 1A With Tidal | Year Unit Additions 2011 Anchorage MSW Cumulative Present Worth Cost ($000) 2012 GVEA MSW $12,198,214 2013 Anchorage 1x1 6FA 2014 Nikiski Wind 2015 2016 Renewable Energy % In 2025 2017 Glacier Fork 59.10% 2018 Anchorage LM6000 2019 2020 GVEA 1x1 6FA Turnagain Tidal 2021 GVEA LM6000 Total Capital Investment ($000) 2022 Mount Spurr $10,051,986 2023 2024 2025 Chakachamna 2026 2027 2028 2029 2030 Kenai Wind 2031 2032 2033 2034 2035 2036 Anchorage 1x1 6FA 2037 2038 2039 2040 2041 2042 Anchorage LMS100 2043 2044 2045 2046 Mount Spurr 2047 2048 2049 2050 2051 2052 2053 2054 2055 2056 2057 Anchorage LMS100 2058 2059 2060 GVEA LM6000 Black &Veatch DRAFT REPORT 13-36 December 2009 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 resource type including transmission,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 e Resource e Fuel Supply e Transmission e Market Development e Financing and Rate e Legislative and Regulatory e 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 *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 December 2009 DRAFT REPORT 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: e 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. e A regional entity improves the opportunities to obtain the benefits of economies of scale in generation,transmission,and DSW/EE projects and programs. e The formation of a regional entity could lead to a reduction in the required levels of reserve margins over time. e 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. e 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. e A regional entity is in a better position to manage risks which is particularly important given the current circumstances in the Railbelt region. e 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. e 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 branding by individual Railbelt utilities. e Asingle 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. e 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). e 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 December 2009 DRAFT REPORT 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 regional solution. 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 deliverDSM/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. e The concentration 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 December 2009 DRAFT REPORT 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 Railbeit 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 pipeline. transmission rates that will be paid to move gas to the Railbelt region will be significantly higher than the relatively low transportation rates that are imbedded in the delivered cost of gas from Cook Inlet suppliers under existing contracts. Black &Veatch 14-4 December 2009 DRAFT REPORT 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. e 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 gain acceptance on their projects,including the negotiation of power purchase agreements under varying terms and conditions and dealing with various generation interconnection requirements.The region would likely benefit Black &Veatch 14-5 December 2009 DRAFT REPORT 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 December 2009 DRAFT REPORT 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 OptionalityOptionalityrepresentstheabilityto make other choices once an initial choice has been made.Given the large fixed cost commitments associated with generation and transmission projects,any optionalityin 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 flexibilitythe region will have to react to future price andavailabilityproblems. 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 :December 2009 DRAFT REPORT 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: *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. Black &Veatch 14-8 December 2009 DRAFT REPORT IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY Table 14-1 Resource Specific Risks and Issues -Summary Relative Magnitude of Risk/Issue a 3 zz 2 =3 3 2 2 =%me g az e P| °a >=}om |-0 cy ==7)Fu 30 p>eby]£i)=&@ &|i=& =se Ge 3 5 ef 3 a83g2a525g23=33aeoe2i)>s s ©=bo "En oe no &Fj =.2 fo)A oo Resource mm KAO fa mo B&O ey SS md DSM/EE Moderate Limited N/A N/A N/A Limited -Moderate Moderate Generation Resources Natural Gas Limited Limited Significant Moderate Limited Moderate Moderate Coal Limited Moderate-Limited Moderate -Limited-|Moderate -ModerateSignificantSignificant|Significant |Significant Modular Nuclear Limited Significant Moderate Significant Limited Significant Significant Large Hydro Limited Significant N/A Significant |Significant |Significant Significant Small Hydro Moderate Moderate N/A Moderate Moderate Limited -Limited Moderate Wind Moderate Moderate N/A Limited Moderate Limited -Limited Moderate Geothermal Moderate Moderate N/A Moderate |Moderate-|Limited -Limited Significant |Moderate Solid Waste Limited Moderate-N/A Significant Moderate Limited -Limited- Significant Moderate Moderate Tidal Limited Significant N/A Significant |Moderate-|Moderate-|Moderate -Significant |Significant Significant Transmission Limited Significant N/A Moderate N/A Significant |Moderate - Significant Black &Veatch 14-9 December 2009 DRAFT REPORT 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 December 2009 DRAFT REPORT IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY e 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. e 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 the world. e 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. e 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 December 2009 DRAFT REPORT IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY 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. 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: DSM/EE Generation Natural gas Coal Modular nuclear Large hydro Small hydro Wind Geothermal Solid waste Tidal Transmission9000000000 This 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 December 2009 DRAFT REPORT 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 DSMLEE 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 DSM/EE pilot programs throughout the Railbelt region Black &Veatch DRAFT REPORT 14-13 December 2009 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 e Notapplicable e Notapplicable Environmental ¢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 DSMEEE 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 ¢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/EE programs 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 ¢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 DRAFT REPORT 14-14 December 2009 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 December 2009 DRAFT REPORT 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 Risk/Issue Category Description Primary Actions to Address Risk/Issue 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 ¢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 DRAFT REPORT 14-16 December 2009 SECTION 14 IMPLEMENTATION | RISKS AND ISSUES Table 14-3 (Continued) ALASKA RIRP STUDY Resource Specific Risks and Issues -Generation -Natural Gas Resource:Generation -Natural Gas Risk/Issue Category Description Primary Actions to Address Risk/Issue Environmental Risk of accident Continue efforts to enforce safety and operational regulations Transmission Constraints Proper location of gas-fired generation resources mitigates transmission -constraints 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 Consider State assistance for new gas-fired generation projects that replace old,inefficient natural gas plants Regulatory/Legislative Potential future environmental regulations related to emissions, including carbon and other emissions Monitor Federal legislative and regulatory activities related to emission regulations Monitor technological developments regarding carbon capturing technologies (e.g.,carbon sequestration) Black &Veatch DRAFT REPORT 14-17 December 2009 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 ---=se Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential Not applicable ¢Notapplicable Project Development Development of a coal project would be e Learn from the experiences of a new effort for Alaska others 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 e Require that all proposed plant locations also include transmission infrastructure analyses and costs as part of any approval processFinancingForlargerprojects,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 Regulatory/Legislative Potential future environmental e Monitor Federal legislative and regulations related to emissions,regulatory activities related to including carbon and other emissions emission regulations Potential regulations of regarding ash e Monitor technologicaldisposaldevelopmentsregarding carbon capturing technologies (e.g.,carbon sequestration) e Implement appropriate design to mitigate environmental impacts Black &Veatch 14-18 December 2009 DRAFT REPORT IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY 14.2.3.2.3 Generation Resources -Modular Nuclear Table 14-5 Resource Specific Risks and Issues -Generation -Modular Nuclear Resource:Generation -Modular Nuclear Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential e Resource potential would be very large,e Monitor development and licensing but technology not demonstrated of technology Project Development e Significant permitting challenges exist e Work closely with resource for modular nuclear agencies to identify permitting e Public acceptability of modular nuclear requirements is unknown e Develop public outreach program e Potential for construction cost overruns to better determine public is significant acceptability of modular nuclear ¢Technology not fully developed e Implement best practices related to management of construction costs e Support research and development of technology and pilot projects Fuel Supply e Notapplicable e Not applicable Environmental e Environmental impacts of modular e Work closely with resource nuclear may not be significant,but -agencies to identify environmental public perception about environmental issues impacts may be very significant e Conduct necessary studies to address resource agencies'issues and data requirements Transmission Constraints |¢The small size of the modular nuclear e Require that all proposed plant projects should not pose transmission locations also include transmission constraints infrastructure analyses and costs as part of any approval process Financing e =The lack of technology demonstration e Formation of a regional G&T entity at this small size may create concerns in (e.g.,GRETC)would provide the financing community greater financial capabilities e Costs per kW may be significant e Consider alternative forms of State assistance reduce resistance to finance e Aggressively pursue available Federal funding Regulatory/Legislative e NRC licensing is uncertain e Monitor NRC licensing process Black &Veatch 14-19 December 2009 DRAFT REPORT 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 e 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 Not applicable Not applicable 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 ¢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 DRAFT REPORT 14-20 December 2009 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 Not applicable Not applicable 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 Railbeit 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 e Aggressively pursue available Federal funding for renewable projects Regulatory/Legislative Regional commitment to renewable Establish State RPS targets resources is uncertain Develop State policies regarding RECs and Green Pricing Black &Veatch 14-21 December 2009 DRAFT REPORT 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:GenerationWind - 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 wind projects Lack of standard power purchase agreements for projects developed by IPPs Establish a regional entity (e.g.,GRETC)or rely on IPPs to identify and develop wind projects Develop regional standard power purchase agreements Develop regional competitive power procurement process to encourage IPP development of projects Fuel Supply Not applicable Not applicable 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 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 e Aggressively pursue available Federal funding for renewable projects Regulatory/Legislative Regional commitment to renewable e Establish State RPS targets resources is uncertain ©Develop State policies regarding RECs and Green Pricing Black &Veatch 14-22 December 2009 DRAFT REPORT SECTION 14 IMPLEMENTATION RISKS AND ISSUES 14,.2.3.2.7 Generation Resources -Geothermal Table 14-9 ALASKA RIRP STUDY Resource Specific Risks and Issues -Generation -Geothermal Resource:Generation -Geothermal Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential Total economic resource potential is unknown Complete regional economic potential assessment,including the identification of the most attractive sites Project Development Ineffectiveness and inefficiencies associated with six individual utilities developing geothermal projects Lack of standard power purchase agreements for projects developed by IPPs Infrastructure needs to support construction are likely significant Establish a regional entity (e.g.,GRETC)or rely on IPPs to identify and develop geothermal projects Develop regional standard power purchase agreements Develop regional competitive power procurement process to encourage IPP development of projects Explore if synergies can be achieved for infrastructure with hydro projects Fuel Supply Not applicable Not applicable 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 Expand Railbelt transmission network Require that all proposed plant locations also include transmission infrastructure analyses and costs as part of any approval process Financing Cost per kW can be significant e Aggressively pursue available Federal funding for renewable projects Regulatory/Legislative Regional commitment to renewable Establish State RPS targets resources is uncertain Develop State policies regarding 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 December 2009 DRAFT REPORT IMPLEMENTATION RISKS AND ISSUES ALASKA RIRP STUDY SECTION 14 14.2.3.2.8 Generation Resources -Solid Waste Table 14-10 Resource Specific Risks and Issues -Generation -Solid Waste a :ee Resource:Generation -Solid Waste Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential Total economic resource potential is unknown 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 Establish a regional entity (e.g.,GRETC)or rely on IPPs to identify and develop solid waste projects Develop regional standard power purchase agreements Develop regional competitive power procurement process to encourage IPP development of projects Fuel Supply See Resource Potential Not applicable 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 Expand Railbelt transmission network 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 Establish State RPS targets resources is uncertain Develop State policies regarding Potential future environmental RECs and Green Pricing regulations related to emissions,¢Monitor Federal legislative and including carbon and other emissions regulatory activities related to emission regulations Black &Veatch 14-24 December 2009 DRAFT REPORT 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 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 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 Establish a regional entity (e.g.,GRETC)or rely on IPPs to identify and develop tidal projects Develop regional standard power purchase agreements Develop regional competitive power procurement process to encourage IPP development of projects Work closely with resource agencies to identify permitting requirements Develop public outreach program to better determine public acceptability of tidal 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 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 Expand Railbelt transmission network Complete required studies to ensure the ability to integrate large tidal projects into the transmission grid 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 _ Black &Veatch DRAFT REPORT 14-25 December 2009 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 .---:---Deseription ==-Primary Actions to Address Risk/Issue Financing e Financing requirements of a large tidal e 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 *Develop State policies regarding RECs and Green Pricing Black &Veatch 14-26 December 2009 DRAFT REPORT 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 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 Establish a regional entity (e.g.,GRETC)to identify and develop transmission projects 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 Pursue statewide permitting by GRETC Transmission Constraints Not applicable 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 Consider alternative forms of State assistance for transmission projects Regulatory/Legislative Siting and permitting issues are potentially significant Develop streamlined siting and permitting processes for transmission projects Black &Veatch DRAFT REPORT 14-27 December 2009 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. 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 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. Black &Veatch 15-1 December 2009 DRAFT REPORT CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY 15.1 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: [e)0000000°o A transmission network that is isolated and has limited total transfer capabilities and redundancies. The inability of the region to take 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. Duplicative and diffused generation and transmission expertise among the Railbelt utilities. 2.The key factors that drive the results of Black &Veatch's analysis include the following: e) [e) ° The risks and uncertainties that exist for all alternative DSM/EE,generation,and transmission resource options, The future availability and price of natural gas. 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. Potential future CO,prices that may result from proposed Federal legislation. The region's limited 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. The ability of the region to raise the required financing,either by the utilities on their own or through a regional G&T entity. Whether the Railbelt utilities develop a number of currently proposed projects that were selected outside of a regional planning process. 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. o Greater reliance on DSM/EE and renewable resources and a lower dependence on natural gas. o Amore robust transmission network. o More effective spreading of risks among all areas of the region. o 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. Black &Veatch 15-2 December 2009 DRAFT REPORT CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY 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 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. 5.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 did go down.The cost of Scenario 2B was 3.7 percent lower than Scenario 1A;Scenario 2B was 1.3 percent lower than Scenario 1B. 6.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; 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 15-1 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 12.5 percent higher than Scenario 1A.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. 7.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. Black &Veatch 15-3 December 2009 DRAFT REPORT CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY Figure 15-1 Comparison of Results -Scenario 1A Versus Committed Units Sensitivity Case 3,000,000 -Scenario 1A With Committed Units .a2,500,000 -Scenario 1A Base Case Twa2,000,000 = 1,500,000 -- 4,000,000 aa500,000 Pea AnnualCostofPower($000,000)_-_ 0 7 qT qT qT qT v qT T TT T T T T T T T T T qT T UJ qT T v v qT +v T ly v T t v Uy 1 TT T T T T T ¥T T qT 1 nd DP PP od oD oH wd De wh DS PP LP PDPPPPKKKKSFSFHFYFFYTFKFSFLYFH 8.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. 9.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 place a maximum limit on the amount of these resources that can be developed. 10.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 adversely affect 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 15-2. Black &Veatch .15-4 December 2009 DRAFT REPORT CONCLUSIONS AND ALASKA RIRP STUDY Figure 15-2 Interplay Between GRETC and Regional Integrated Resource Plan Current IRP Stud REGA Study Situation «Plan that economically chedules what,when,*Umited redundancy ond where to build,based"ote cneraysupptes Proposed Future Situation *Dependence on «SQ-year time horizon RIRP GRETC *Robust transmission fossil fuels =Competes generation,Results Formation »Diversified fuel supply «Limited Cook Inlet transmission,fuel supply +Increased +System-wide power ratesgasdeliverabilityandDSM/energy DSM/energyandstorageefficiencyoptionsefficiency *Spread risk *Aging G&T ©Includes CO,regulation ©Increased «State financial assistance infrastructure -,Includes renewable >|renewables -GRETC -Enabler }-*Regional planning+Inefficient fuel use energy projects *Reduce +Wise resource use .n d id"oeamuena |soimgurinnas ||Sones f *gant tar ometioe.minimum long-run cast to *Increased Financing Optionsxpertiseratepayerstransmission *Technical resources *Pre-funding of capital .*Considers fuel supply requirements =New technologies options and risks ©Commercial bond market ©State financial assistance {Bradley Lake model) «Construction-work-in-progress 10-Year Transition Period 15.2 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 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. 2.The State should establish certain energy-related policies,including: o The pursuit of large hydroelectric facilities o DSMC/EE 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 o System benefit charge to fund DSM/EE programs and or renewable projects Black &Veatch 15-5 December 2009 DRAFT REPORT CONCLUSIONSAND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY 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 base 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 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 1B resource plan during the first 10 years. Other projects selected in Scenario 1B after the first 10 years especially worthy of mention are the Mt.Spurr Geothermal Project in 2021 and Chakachamna Hydroelectric Project in 2025.Comparison of Scenarios 1A and 1B indicated they are identical until 2021 except for timing of the Anchorage LM6000 and the GVEA 1x1 7FA Combined Cycle.Scenario 1B selects Mt.Spurr in 2021;whereas, Scenario 1A delays it until 2030.The earlier selection of geothermal in Scenario 1B enhances its fuel diversity.Chakachamna is selected in 2025 in both scenarios.As indicted in Section 13,the cost difference between Scenarios 1A and 1B is only 0.07 percent,which is well within the noise of the models. Another important consideration of the selection of a preferred resource plan is consideration 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? What is the effect if the committed units are installed? What if Chakachamna doesn't get developed? What would be the impact of the alternative Susitna projects? Should the Fire Island Wind Project be developed?0000There are several projects that are significantly under development that are considered in the preferred resource plan or in the sensitivity cases.These significantly developed projects include: o Healy Clean Coal Project (HCCP) o Southcentral Power Project o Fire Island Wind Project o Nikiski Wind Project These projects are discussed in Table 15-3. In addition to these resources,Black &Veatch believes that 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. Black &Veatch 15-6 December 2009 DRAFT REPORT CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY Table 15-1 Resources Selected in Scenario 1B Resource Plan Project Discussion DSM/EE Resources The full level of DSM/EE resources evaluated was selected based upon their relative economics. Anchorage and GVEA MSW|The RIRP selected these units in the first two years of the planning period.Units 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. 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 The RIRP selected this project for commercial operation in 2015,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. Nikiski Wind The RIRP selected this project in 2017.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 potentially improve its competitiveness.As a wind unit,it has no impact on planning reserves,but contributes to renewable generation. Anchorage LM6000 Simple Cycle Combustion Turbine The RIRP selected this project in 2018.The unit can be dual-fueled,thus providing firm capacity in the event of any natural gas shortage.As a simple cycle combustion turbine unit,the lead time requirements are relatively short, leading to greater flexibility. GVEA 1x1 6FA Combined Cycle The RIRP selected this project for commercial operation in 2020 in GVEA's service area after natural gas is assumed to be available to Fairbanks. Baseload natural gas-fired combined cycle energy in GVEA's service area relieves import requirements on the Intertie.As a conventional unit,its schedule can be coordinated with the schedule for natural gas availability in Fairbanks. Black &Veatch DRAFT REPORT 15-7 December 2009 CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY Table 15-2 Impact of Selected Issues on the Preferred Resource Plan Effect on Preferred Resource Issue Discussion Plan CO,The sensitivity case for Scenario 1A without CO,The preferred resource plan Regulation regulation selects the Healy Clean Coal Project instead |maintains the development of of Glacier Fork and Nikiski Wind in the first 10 years.Glacier Fork which has It also does not select Mt.Spurr.The sensitivity case significant uncertainty associated also delays Chakachamna until 2030.The sensitivity with it. case does not meet the 50 percent renewable target by 2025. Committed Installation of the committed units significantly The preferred resource plan Units increases the cost of Scenario 1A or 1B.The plan with |maintains the development of the committed units selects six wind units from 2019 Chakachamna which has through 2024 in response to CO,regulation.The plan significant uncertainty associated with the committed units eliminates Chakachamna and |with it. does not meet the 50 percent renewable target by 2025. Chakachamna |Chakachamna could fail to develop because of licensing |The preferred resource plan or technical issues.Also,if the cost of Chakachamna maintains the development of were to increase to be equivalent to the alternative Chakachamna which has Susitna projects on a $/MW basis,it would not be significant uncertainty associated selected.The sensitivity case without Chakachamna for |with it. the first 10 years is identical to Scenarios 1A and 1B except the timing of Nikiski Wind and Glacier Fork are interchanged.The case does not meet the 50 percent renewable target by 2025 and is2.7 percent higher in cost than the preferred resource plan. Susitna None of the alternative Susitna projects are selected in The preferred resource plan the Scenarios 1A or 1B.The least cost Susitna option,|recommends pursuing the which is Low Watana,is 15.3 percent more than the development of a Watana project preferred resource plan and 12.2 percent more than the |until there is resolution on thecasewithoutChakachamna.The 50 percent renewable |development potential for Glacier requirement can not be met without Susitna if Fork and Chakachamna. Chakachamna is not available. Fire Island Fire Island was not in either Scenario 1A or 1B based The preferred resource plan is on its total cost.When a sensitivity case was virtually the same as the plan with conducted,which included consideration for the Fire Island. benefits from the ARRA and the $25 million grant for interconnection from the State,the cost of the Fire Island case was essentially equal to Scenario 1A (0.3 percent higher),which is within the feasible range for a purchase power agreement.The plan with Fire Island includes the same units for the first 10 years as the preferred resource plan with minor differences in timing and includes Chakachamna in 2025. Black &Veatch 15-8 December 2009 DRAFT REPORT CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY Table 15-3 Projects Currently Under Development Project Discussion Preferred Resource Plan Recommendation HCCP HCCP is completed and GVEA has Due to the operating cost risks associated with negotiated with AEA for its purchase.The project is part of the least cost scenario when CO,costs are not considered.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.HCCP adds further fuel diversity to the Railbelt,especially to GVEA who doesn't currently have access to natural gas,nor is there any other coal-fired generation included in the preferred resource plan.As a steam unit,HCCP improves transmission system stability. the possible enactment of CO,legislation, Black &Veatch does not recommend that HCCP be included in the preferred resource plan at this time.HCCP is currently being held in mouthball status;Black &Veatch recommends that this condition be maintained for the foreseeable future until such time as it becomes clear whether CO)regulations are enacted and the resulting economic impact on the plant can be determined. 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.When these benefits are considered,the project comes close to being part of the least cost scenario.Since the project is an IPP project instead of direct utility ownership,there are other factors such as risk of performance which may result in additional benefits. 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. 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 15-9 DRAFT REPORT December 2009 CONCLUSIONS AND SECTION 15 RECOMMENDATIONS ALASKA RIRP STUDY 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. 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: ©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. ©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 provided 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. 2. Develop a comprehensive region-wide portfolio of DSM/EE programs. Generation projects: Generic Anchorage MSW Project Generic GVEA MSW Project Glacier Fork Hydroelectric Project Chakachamna Hydroelectric Project Susitna Hydroelectric Project Projects under development (HCCP,Southcentral Power Project,Fire Island Wind Project,and Nikiski Wind Project) Transmission and related substation projects,including the following Priority 1 and 2 projects (note: the timing and priority of these projects may change based on additional detailed analysis): o Soldotna-University (new build) Soldotna-Quartz Creek (upgrade) Quartz Creek-University (upgrade) Lake Lorraine-Douglas (new build) Douglas-Healy (upgrade) Regional battery system for frequency regulationo0o00o000000000 Black &Veatch 15-10 December 2009 DRAFT REPORT CONCLUSIONS AND SECTION I5 RECOMMENDATIONS ALASKA RIRP STUDY 15.2.3.Recommendations -Other Other actions,related to the implementation of the RIRP,that should be undertaken include: 1. 12. 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 DSMLEE 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 DSM/EE programs and renewable projects. 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. .Develop a regional frequency regulation strategy for non-dispatchable resources. 11.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. Federal legislative and regulatory activities,including those related to emissions regulations,should be monitored closely. Black &Veatch 15-11 December 2009 DRAFT REPORT 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: e 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. 16.1.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 $6.8 million 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 |$0.2 million ©The pursuit of large hydroelectric facilities o DSMF/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 Not and other stakeholders to establish the preferred resource Applicable plan,using the Scenario 1B resource plan as the starting point e Glacier Fork,Chakachamna and Susitna should be 2010-2011 To be pursued further to the point that the uncertainties determined regarding the environmental,geotechnical and capital cost issues become adequately resolved to determine if any of these projects could actually be built ¢Develop a public outreach program to inform the public 2010-2011 $0.1 million regarding the preferred resource plan,including the costs and benefits Black &Veatch 16-1 December 2009 DRAFT REPORT SECTION 16 NEAR-TERM IMPLEMENTATION ACTION PLAN (2010-2012) ALASKA RIRP STUDY Table 16-1 (Continued) Near-Term Implementation Action Plan -General Actions Actions Category Description Timeline Est.Cost e The State Legislature should make decisions regarding the |2010-2011 Not level and form of State financial assistance that will be Applicable 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 e The electric utilities,various State agencies,Enstar and 2010-2012 To be Cook Inlet producers need to work more closely together determined 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 Black &Veatch 16-2 December 2009 DRAFT REPORT NEAR-TERM IMPLEMENTATION SECTION 16 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 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 Generic Anchorage MSW Project Generic GVEA MSW Project Glacier Fork hydroelectric project Chakachamna Hydroelectric Project Susitna Hydroelectric Project Projects under existing development (HCCP, Southcentral Power Plant,Fire Island Wind Project, and Nikiski Wind Project) e Begin detailed engineering and permitting activities 2011-2016 Varies by associated with the transmission projects identified in project the initial years of the preferred resource plan, including: Soldotna-University (new build) Soldotna-Quartz Creek (upgrade) Quartz Creek-University (upgrade) Lake Lorraine-Douglas (new build) Douglas-Healy (upgrade) Regional battery system for frequency regulation00000000000 Black &Veatch 16-3 December 2009 DRAFT REPORT NEAR-TERM IMPLEMENTATION SECTION 16 ACTION PLAN (2010-2012) ALASKA RIRP STUDY 16.3 Supporting Studies and Activities Table 16-3 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 a regional DSM/EE program measurement and 2012 $0.1 million evaluation protocol e =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 e 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 agreements 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 16-4 December 2009 DRAFT REPORT SECTION 16 NEAR-TERM IMPLEMENTATION 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 DSMEEE programs Form a regional entity (if GRETC is not formed)or rely 2011-2012 Subject to on IPPs to identify and develop renewable projects that are decision included in the preferred resource plan regarding formation of GRETC Monitor Federal legislative and regulatory activities,Ongoing Not including those related to emissions regulations Applicable 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 Black &Veatch 16-5 December 2009 DRAFT REPORT APPENDIX A SUSITNA ANALYSIS ALASKA RIRP STUDY APPENDIX A SUSITNA ANALYSIS Black &Veatch A-1 December 2009 DRAFT REPORT Suiting2Hydroelectric a ed 3 po coeeeNhedheebegeace HNL PodSusitnaHydroelectricProjectoO oeConceptualAlternativesDesignReport:va .wTI,i Meantor +|.} .a eeeeFinalDrafteeeeennter-;oid !4 7 bejav:.goose . : .Lathe :ys . fark,;,pend opt.\a4 are a fe wt ge ' _ :''a oe Ry Apt +ay ::3 eau [>Laxe wee.fii.:we vot |oe \ee ''anf p en eet ee. i ec ,*,. . { hed a ry ad PA annrd ¥eee are ek ew te leg ETwren7PyesemanOYaTanayy7)'po :{ ,1 :.''roe,:1 -.i f i ,7 4hae"Tsusena re 'a4 ine "”a ree /3 Mote : "So .? :3!ahs i _. - .a -Bate '.on CY a ,os ran TY 4 . ::te oe Prey ared for:ct wae !.ed ee a oe --oo co 'Alaska Energy Authority.Ss mo a ,% .2 "bs 813 West Northern Lights Boulevard <* :t *!ae .°Y eo s Anchorage,Alaska 99503,ve oa 'x Te Ta,i*.wa ve C ji tr Bs or -te ma wos pea :"4 ":idee.LP.re/ 3 .oy 'von.ase|ar ee ,5 .apt"yy ;.Buy bade |Pa . : .cae ee os 7 =|«Prepared by:f 4 Pute oF B al ' .: a ce ne .-: :ioe :Z a)..ei Ye aa 7 at HDR Alaska,Inc.:lot.a ey ee eee bose ye mvtoo BR;:rhea.4 a my A :an -wn at 2525CStreet,Suite 3054-.on i aS .ro Anchorage,AK 99503 boty :aoLn-oecateeehe.-November 23,2009 t,.aofwwwee.a.2Bot7 HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report Contents 1 =Executive Summary 2 Background . 5 2.1 Project Scope...eeesseeeccsseesseeeesssssessssscseseaessesseessnsessessssaseessseasanseeueceseeooess daceseececeesesesseeneseee 5 3s"Preliminary Energy Estimate 6 3.1 Hydrologic Analysis.........csesessescecececesreseesseseesscssensacsesssesseneesnssecesesssetsessessesunsseesesassusessseessens 6 3.2 Evaluation of Firm Winter Capacities and Average Annual Energy .........:esccsssssserseeeteeeeees 7 3.3.Model Assumptions and Data Sources ........cccssssssssesceesssessscescnasssssacesseeesesceesssscrsenesceeeesenesees 8 3.4 Model Operationn......ieesssscesesesecseesscessecececsssccseessassnassesssesovessessccssssnasscesuneseteasenseensteseesensens 9 4 Estimates of Probable Project Development Costs 13 4.1 Original Cost Estimate 0.0...cssescssssessessseessersesesscesssssesssaasscsseasacsesossenesecesseneesseesaeeseenantenes 13 4.2 Expandability .2000.ec eescssscssceteessesssccesssecsessssesessesssseesscessesenensaneseeearsseeeseseassseesesesseceeenneneces 13 4.3 QUANTITICS 0...eee secsessssseeetesecesscenetsresnennecseceneeneeseerescessceessesoesesesouaesssseasasessussarsanseausonasenasenserses 14 4A Umit Costs....cesssccssecssnssentsesesecsecesceeressessceneenssceasceessassesessssausssesersessassecssansassceassuscesatecsoeesareseas 15 4.5 Indirect Costs....ecseccssccstsecesssesssccsesscssesseseerssesscesesessssnssseseesessucnaeseensnneeseusassesseseesenteneeseesenens 16 4.6 Interest During Construction and Financing Costs «0.0...essssssssesssseesscessnsecesesensncenssassseerens 16 4.7 Changes from 1983 Design...esescersecsssseseessesesesesenssscssussnessncessasersoosseesannessaseraaceesseseneeees 16 A.T.1 CAMs wo.eeeeeesccesseececeeecesccssceuussccnessenssssssconessnerstssscuscesusssnsgsosesaeeaseenersoeustesseseauessvesseesenes 16 4.7.2 ACCESS ...eeesecescscessceectececsssestesocssseosescsasssessscnsnsusarssnsasssessocssessensussenstasatesteaneteseeseneonseneay 16 4.7.3 TYranSMisSiOn ........sssscecsceecsscetsceesseeseesecesceesecesecesersssecseassssscesenessacsesenseassnssesaaassneeneeereed 17 4.8 COMCIUSIONS .........sccscsesssessssesssccesecsensasecsesonesnsenseeseeseesssersoneescoeresscessuensessesesaneessesasaeseeseessoueneoes 17 5 Project Development Schedule 19 6 Project Development Issues 21 6.1 Engineering ......cee sescssssssessesessenssessesesscasscesessessnsssesecesseusssesscassoeesscesseesssnsessessceersererseseseneees 21 6.2 Siltation ........sscscssscscccssssesssecnessseeensesssecessessceeeseacescecesceeeseensenetssseeosssesaosssnacsaessscssssenecouasseseneeeeoae 21 6.3 SeiSIMICity 0.2...eeseeeeeeeceeoceeeenecsessoesescesesooensessesseaeessacsansseseccesscsussesnenssutsassseserscesorssesseesseeseeeses 21 6.4 Climate Change .........cceecseccssssceesceseecoeeoseceesecsessaessaessseasssansrssesscuecasssessacessssoeanseasssnnesseuseeeses 21 6.5 Environmental Issues ........csscesssssssescessecesscessscesssesenseeessceeesseeessessesssuscessaesscersstseeseesseeenensensaes 21 6.5.1 Fisheries Impacts ........ccccsesscssssssessscnsnsssessssseseessssssssenessaessseasesseesssseeeesesestssanseseeeseneess 22 6.5.2 Botanical Impacts 0.0...eeccessesceseesesssssessscesasssessesseseaseesssessessseensssenstssesasesscesessarenates 22 6.5.3 Wildlife Impacts 200...ceceseseecesecesereceeeseesecesscessseseessuensseusesausanessesonssasenesseeseaesuaneasersees 23 6.5.4 Cultural Resource Impacts ..........ccsesssseesseeseseesssessessesseeesseeesseeonsesassssssesseesaseasonreseesees 23 6.5.5 Carbon Emissions ..........ccscsccccssssossssssceessessassesensessesessccevesecsonsconaesenesscessceesassesnensseeseess 23 7 References 25 11/23/2009 i Final Draft HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report Tables Table 1 -Susitna SUMIMAry...........escssccesseecceseccesseccescesssesssessseseseeesessesseesssssecesencessnsenscensesseeseesaes 2 Table 2 -Summary of Susitna Project Altermatives............cccccsscsssccessccscesssessscssecssscesseeenesessesssensees 9 Table 3 -Firm Capacity and Energy Estimates 0.0....cscesscssseeccesceesessceceesseeseesseseseseesassassesesasees 10 Table 4 -Estimated Total Fill Volumes...ec csececssecssccsscesscessrccsseseccessceseeesecesseeesassassseersnes 14 Table 5 -Watana Water Conduit and Powerhouse Size Parameters ............sscsscsssssesscsseseeeseeens 15 Table 6 -Alternate Project Configuration Cost Summary Table (Millions of US Dollars).........18 Table 7 -Power Generation Time Estimates «0.00.0...cssssssccsscsssesseeceencessenesssseteeseesacessessessenseseseens 20 Figures Figure 1 -Susitna River Hydrologic Variation ..............ssssccsssesssscsssesseecesessacessesaeseesseesecserseaseeess 7 Figure 2 -Firm Capacity........cccsscssssscccssscesssscesscscssssessacssessccesseeeseessacesessseseceeessesseeeesacsansensenssenss 11 Figure 3 -Watana Dam Configurations...........ccscccssesccsserccesccescccecsesecesssencesseseaecescessceeseesscseseeesacs 13 Figure 4 -Proposed Access Route .........cssccesssceseecstsseesessscnensceseesesecensesseneeesceasssssecesscesscensenseeasens 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-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. «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 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). The results of this study are summarized in Table 1. Table 1 -Susitna Summary .Firm .ScheduleDamUltimateCapacityConstructionEnergy(years from*.s.>Alternative Dam Type "(fee).Capacity 98%G banal 2)(GWh/yr)start of(MW)(MW),licensing) Lower Low Rockfill 650 390 170 $4.1 2,100 13-14Watana Low Watana Non-Rockdill 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 |ggsiga6 |1,880 |710 $9.6 7,200}15-20CanyonArch Staged )Watana/Devil RocknConerete |35/646 |1,880 710 $10.0 7,200 15-24 Canyon 11/23/2009 2 Final Draft ADR 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 HIDR Alaska Susitna Hydroelectric ProjectConceptualAlternativesDesignReport 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 capacityof680MW. «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 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 installedcapacityof390MW.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.Asa 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 A ING35,000 \3 .i&30,000 IN LNZ25,000 -ISA,AS20,000 th ”Sor sf -F ft fi goge SNS 3 .|0 A NYS$10,000 -- -7 Va = 5,000 +PS 0 T T T T T T T ¢T T "FT 5 OCT 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.|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 HDR 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 |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 HDR Alaska Susitna Hydroelectric Project 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 :FLowerLow(Both (Both -Devil Canyon High DevilAlternatives)Alternatives)y Dam Type Rockfill Rockfill Rock tt 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 Pool Elevation (ft)1850 1850 2065 1405 1605 Tailwater Elevation (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 Alternative Firm Winter Capacity 98%Winter Average Annual Energy (MW)Capacity (MW)Production (GWh) 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 1400-1300 --4 se Watana and Devil Canyon -™.1200 Lf men Watana a <High Devil Canyon oe110077-<Low Watana 1000 4-]=eeLowerLowWatana SK9004-4]=®-Devil Canyon =800 =700 z 600 +- S =< iat 500 E 400 iz 300 200 °100 0 T 7 T T T LJ LU 30%40%50%60%70%80%90%100% %Exceedance Figure 2 -Firm Capacity 11/23/2009 11 Final Draft FIDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 11/23/2009 12 Final Draft ADR 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 LOWWATANA-NON-EXPANDABLE =-LOWER..--Pity LOWVWATANAHEIGHT(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 a headrace for every two units bifurcating into dedicated penstocks.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 |yceseatns |thant |WatanWatana 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 town facilities were no longer necessary due to advances in remote project operation.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 Se ee;sy "ft ,+,28.STEweDenali[ax 4 beeers Highway BS pee i ee cag Railroadr'min fie ”Cae Sow 4 earn<a «*APTN bs ee or+ORE,ss ONGoldCreek_FS see SOREPENPLRLOTIONcopperaaigke € 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 Line Line Item Name 'Low |"Nome |Watana |Watana watam Toe "Devt |Devil |Watana/DevilWatana|Expandable |Expandable yon Canyon*|Canyon Canyon 1A Engineering,Env.,and Regulatory (7%)$213 $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 *R&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 Alternative Generation of first power,|Generation of full power (years)*(years)* 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,some relevant information has likely been overlooked;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: »Impoundment 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,habitatmodification,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 HDR 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 ADR 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://www.eia.doe.gov/cneaf/electricity/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 HDR 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 TRANSMISSION APPENDIX B STABILITY ANALYSIS ALASKA RIRP STUDY APPENDIX B TRANSMISSION STABILITY ANALYSIS (Note:The transmission stability analysis is still being completed andtheresultswillbeavailablefortheFinalReport) Black &Veatch B-1 December 2009 DRAFT REPORT TRANSMISSION APPENDIX B :STABILITY ANALYSIS ALASKA RIRP STUDY APPENDIX B TRANSMISSION STABILITY ANALYSIS (Note:The transmission stability analysis is still being completed and the results will be available for the Final Report) Black &Veatch B-1 December 2009 DRAFT REPORT APPENDIX C FINANCIAL ANALYSIS ALASKA RIRP STUDY APPENDIX C FINANCIAL ANALYSIS Black &Veatch C-1 December 2009 DRAFT REPORT Verena os > SN te 4300ifthAvenue,Su1420Fi Seattle,Washington 98101 2882>(206)628-Phone (206)343-2103Fax 12/1/2009 Introduction 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 mitigate construction risk and lower capital cost prior to placing assets in service,and to extend the funding term of assets beyond the debt repayment terms available through a public offering of debt. 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 borrow 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 2 '2 é 2 -$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% 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. *Fitch Ratings,U.S.Public Power Peer Study,June 2009 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 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.What can be derived from this analysis is that the operating leverage of the six utilities would likely increase dramatically as capital spending, and the resulting debt burden,increase.With an increase in the operating leverage ratio would come increased scrutiny and ratings pressure from the rating agencies in order for the utilitiestomaintain investment grade credit rating metrics,an important factor for issuing debt in the capital markets or obtaining other forms of financing through 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 period,significant construction risk,or significant technological risk.These types of risk [jabesh MRS EE RR NS eas ee ee See eer | are associated with equity rates of return and are $10,000,000,000 rarely,if ever,borne by fixed income investors.- Capital Expenditures The graphic to the right helps to put into context >7,500,000,000 the scope of required RIRP capital investments aanrelativetotheestimatedcombineddebtcapacity#5,000,000,000 High Debt Capacity of the Railbelt utilities.The lines toward the ; $2,500,000,000bottomofthegraphrepresentourviewofthe Sj _tow Debt Capacity ___-bracketed range of additional debt capacity so -= collectively for the Railbelt utilities,adjusted for SSESRARSRARRsTsEygasgsainflationovertimeSRRRRRARASRARARAR 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 forma __ 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 independently 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,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. Ratepayer Benefits Charge.A ratepayer benefits charge is a charge levied on all ratepayers within the Railbelt system that will be used to 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 a 30-year bond issue,issued to fund construction at 7.00%interest. "Pay-Go”vs.Borrowing for Capital.There is a tradeoff between the benefits derived from a pay-go financing structure versus one for which all projects are bonded.The biggest 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. The biggest benefit in borrowing for capital,on the other hand,is that expenses are most effectively spread out over a period of 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 average 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 In Progress.Construction Work In Progress (CWIP)is a funding technique 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 online and generating power.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 and power is not yet being generated or sold.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 off the bonds.The use of CWIP in Alaska will most likely need to be vetted and approved by the Regulatory Commission of Alaska. 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 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. 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 or a new 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 in both scope of timing and access to capital.A second goal was to develop strategies that could be used to meet an objective of the RIRP of producing levelized power cost rates over the useful life of the assets being financed. A structure commonly used in the current capital markets would not meet that goal,as certain of the assets being financed would have longer useful lives than the longest maturing 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 will be 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 analysis created a detailed list of the capital costs and the related investments of 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 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: e 30-year debt repayment on all bond issues sold in the capital markets e 7.00%interest rate on all bond issues sold in the capital markets ¢Required debt service coverage ratio 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 fund balance is maintained throughout the 50-year RIRP and earns 3.00%interest,which is used towards paying 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 in the second half of the 50-year period are financed through "pay-go”capital,as debt service coverage from previous years has grown to sufficient levels to allow the balance of the reserve to pay for the projects as their construction costs come due. The base case model assumes that approximately $5.8 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 using 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,when approximately 75%of the capital projects in the plan 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 a financing structure that is similar to the Bradley Lake financing model,the State would 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.This analysis assumes that the $2.4 billion 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 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 Chakachamna take-out financing.The capital costs not bonded for come from the early rate surcharge that is applied from day 1 and "pay-go”capital generated from bond debt service coverage.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 $0.01 consumer benefit surcharge that is in place for the first 17 years. Summary,Next Steps,Conclusion.The RIRP presents a number of funding challenges,given the size and scope of the projects being contemplated.It has become evident through the financial modeling and the individual debt capacity analyses of this process that the utilities on their own would not be able to accomplish such an ambitious capital plan.The formation of a regional entity,such as GRETC,that would combine the existing resources and rate-base of the Railbelt utilities,as well provide an organized front in working to obtain private financing and the necessary levels of State assistance would be,in our opinion,a necessary next step towards achieving the goal of reliable energy for the Railbelt now and in the future. RIRP Plan 1A -Base Case Financial Model Alaska Regional Integrated Resource Plan Scenario Cash Flow Summary dollars in millions E PR Base Case 100%Fixed Rate Sources of Funds BONDS §,889 STATE (through construction)0 Infrastructure Tax through 2027 i) Other (use of coverage reserves)3,196 Total Source of Funds 9,085 Use of Funds Project(Construction 9,085 Payment of interest accrued 0 Reserve Funds 0 Issuance Costs 0 Capitalized Interest (through construction)0 Total Uses of Funds 9,085 Maximum Annual Debt Service Requirements BONDS 539 STATE 0 Ave.Annual Energy Requirement (GWhr)5,625 Target Debt Service Coverage (DSC)1.25% All-in Borrowing Cost 7.00% Escalation Factor (Inflation)2.50% Average Cost of Energy ($/per kWh)0.07 Assumptions Issuance Cost =2%of Par Amount Par coupons Debt service reserve funded at 10%of Bond Par Amount Bonds all assumed to be 30 years from date of issue Prepared by Seattle-North Securities Corp Re FONEa at ST a::PRE a Ng a erie perreer pees shes FF ¥ Year ve Other Unit Cost Copia =o Transmission ¥Total Capital ia Use of coverage balance #*,Bé Requirements 4 Requirements aed capital projects E |it ' 4]12/1/2011 1 506,496,362 -506,496,363 $886,736,5932|12/1/2012 -256,773,239 -256,773,239 :- 3}12/1/2013 -119,476,707 3,990,284 123,466,991 -- 4]12/1/2014 -122,463,625 52,942,550 175,406,275 {25,000,000}|$656,306,8805]12/1/2015 -2,435,356 191,310,564 193,745,920 .- 6]12/1/2016 33,699,203 22,466,161 255,989,420 312,154,784 -: 7]12/1/2017 26,865,753 74,229,623 117,965,769 219,061,145 (105,000,000)|$795,887,6768}12/1/2018 43,273,053 174,256,113 41,630,847 259,160,013 -: 9]12/1/2019 79,301,147 174,171,476 169,193,895 422,666,518 -: 10]12/1/2020 238,340,271 208,891,416 321,882,411 769,114,097 (190,000,000)|$2,454,911,92411]12/1/2021 481,536,897 21,500,060 282,636,456 785,673,412 .- 12|12/1/2022 652,793,164 -437,331,250 1,090,124,414 -- 13]12/1/2023 712,137,997 .464,423,300 1,176,561,297 (320,000,000)$1,095,198,53614]12/1/2024 141,426,155 .59,937,820 201,363,975 .- 15]12/1/2025 -.18,210,430 18,210,430 -- 16]12/1/2026 .-19,062,834 19,062,834 -- 17|12/1/2027 .88,657,273 .88,657,273 (485,500,231)|$: 18]12/1/2028 -208,125,424 :208,125,424 -- 19]12/1/2029 -188,717,535 .188,717,535 -- 20]12/1/2030 ..-.- 21}12/1/2031 --.-- 22|12/1/2032 ..... 23)12/1/2033 -”--- 24)12/1/2034 -2,260,136 2,260,136 (239,531,757)|$. 25]12/1/2035 .206,133,124 206,133,124 -- 26]12/1/2036 -31,138,497 31,138,497 -. 27)12/1/2037 --oy -- 28]12/1/2038 ----- 29)12/1/2039 -127,791,596 127,791,596 (699,805,525)]$- 30]12/1/2040 -299,994,339 299,994,339 -- 31]12/1/2041 -272,019,589 272,019,589 -- 321 12/1/2042 .-.-- 33]12/1/2043 :131,612,221 131,612,221 {720,727,822)]$: 34]12/1/2044 -308,963,361 308,963,361 :- 35)12/1/2045 -280,152,241 280,152,241 .- 36]12/1/2046 -.--- 37|12/1/2047 -..-- 38]12/1/2048 -.--. 39}12/1/2049 -.--- 40)12/1/2050 -.--- 41)12/1/2051 -.-.- 42|12/1/2052 -°--- 43]12/1/2053 ...-- 44)12/1/2054 --.(410,069,419)$- 45)12/1/2055 -35,525,625 35,525,625 -* 46]12/1/2056 -161,918,291 161,918,291 :- 47]12/1/2057 ----- 48]12/1/2058 -38,257,213 38,257,213 -- 49)12/1/2059 °174,368,290 174,368,290 -. 50]12/1/2060 -- . 12/1/2009 SenAanerWHRepayment of State GRETC Direct Debt Service -.;Energy per Year ; .spite.Year paid to bondholders DSRF Total Req {why}Eruel Rates ER 12/1/2011)$35,268,100 -$35,268,100 §,372 0.01 0.000 0.048 0.013 0.000)0.0712/1/2012 81,206,200 2,660,210 78,545,990 $,412 0.02 0.000 0.051 0.013 0.010)0.0912/1/2013 81,204,300 2,660,210 ©78,544,090 5,424 0.02 0.001 0.048 0.014 0.011 0.0912/1/2014 107,308,425 2,660,210 104,648,215 5,421 0.02 0.001 0.053 0.014 0.012 0.10 12/1/2015 141,306,550 4,629,130 136,677,420 5,167 0.03 0.002 0.067 0.013 0.012)0.1312/1/2016 141,309,000 4,629,130 136,679,870 5,147 0.03 0.002 0.070 0.014 0.013 0.1312/1/2017 172,958,250 4,629,130 168,329,120 $,129 0.04 0.002 0.066 0.014 0.014 0.14 12/1/2018 214,187,950 7,016,793 207,171,157 5,105 0.05 0.002 0,042 0.013 0.015 0.12 12/1/2019 214,190,100 7,016,793 207,173,307 5,085 0.05 0.002 0.045 0.013 0.016 0.1312/1/2020 311,827,975 7,016,793 304,811,182 5,068 0.08 0.002 0.044 0.012 0.017 0.15 12/1/2021 439,001,050 14,381,529 424,619,521 5,052 0.11 0.002 0.046 0.013 0.018 0.1812/1/2022 439,000,300 14,381,529 424,618,771 5,081 0.10 0.003 0.050 0.013 0.021 0.1912/1/2023 482,557,325 14,381,529 468,175,796 §,111 0.11 0.001 0.053 0.012 0.021 0.2012/1/2024 539,293,200 17,667,125 521,626,075 5,140 0.13 0.001 0.058 0.013 0.023 0.2212/1/2025 539,294,650 17,667,125 521,627,525 5,174 0.13 0.001 0.037 0.016 0.017 0.2012/1/2026 539,289,900 17,667,125 $21,622,775 $,207 0.13 0.001 0.042 0.014 0.020 0.2012/1/2027 539,284,300 17,667,125 521,617,175 $,241 0.12 0.002 0.044 0.014 0.022 0.21 12/1/2028 $39,290,400 17,667,125 §21,623,275 §,275 0.12 0.002 0.046 0.014 0.024 0.21 12/1/2029 539,297,250 17,667,125 521,630,125 5,309 0.12 0.003 0.049 0.015 0.027 0.22 12/1/2030 539,296,800 17,667,125 521,629,675 5,344 0.12 0,003 0.042 0.019 0.025,0.2112/1/2031 $39,293,550 17,667,125 $21,626,425 5,378 0.12 0.003 0.042 0.019 0.026,0.2112/1/2032 $39,293,500 17,667,125 $21,626,375 5,413 0.12 0.003 0.044 0.019 0.028 0.21 12/1/2033 $39,288,800 17,667,125 $21,621,675 5,447 0.12 0.003 0.046 0.019 0.031.0.22 12/1/2034 $39,293,450 17,667,125 521,626,325 5,482 0.12 0.003 0,048 0.020 0.034 0.22 12/1/2035 539,286,550 17,667,125 521,619,425 5,517 0.12 0.003 0.052 0.020 0.037 0.2312/1/2036 539,289,400 17,667,125 $21,622,275 5,553 0.12 0.001 0.054 0.021 0.041 0.2312/1/2037 539,287,350 17,667,125 $21,620,225 5,588 0.12 0,001 0.062 0.022 0.048 0.2512/1/2038 539,291,900 17,667,125 521,624,775 5,623 0.12 0.001 0.066 0.022 0.052 0.26 12/1/2039 539,293,600 17,667,125 $21,626,475 5,659 0.12 0.002 0.069 0.023 0.057 0.2712/1/2040 539,288,100 17,667,125 $21,620,975 5,695 0.11 0.002 0.072 0.023 0.062)0.2712/1/2041 539,290,450 17,667,125 521,623,325 5,731 0.11 0.004 0.075 0.024 0.067 0.2812/1/2042 458,083,350 17,667,125 440,416,225 5,767 0.10 0.004 0.073 0.022 0.069 0.2612/1/2043 458,087,900 17,667,125 440,420,775 5,803 0.09 0.004 0.077 0.022 0.075,0.2712/1/2044 458,086,400 17,667,125 440,419,275 5,839 0.09 0.004 0.080 0.033 0.082 0.29 12/1/2048 397,988,550 17,667,125 380,321,425 $,876 0.08 0.004 0.084 0,023 0.089 0.2812/1/2046 397,984,050 17,667,125 380,316,925 $,912 0.08 0.004 0.078 0.031 0.087 0.2812/1/2047 397,982,000 17,667,125 380,314,875 5,949 0.08 0.005 0.079 0.032 0.091 0.2912/1/2048 325,101,750 17,667,125 307,434,625 5,986 0.06 0.005 0.083 0.032 0,100 0.2812/1/2049 325,102,950 17,667,125 307,435,825 6,023 0.06 0.001 0.086 0.033 0.109 0.2912/1/2050 325,107,400 17,667,125 307,440,275 6,060 0.06 0.002 0.089 0.034 0.117 0.31 12/1/2051 100,294,000 17,667,125 82,626,875 6,098 0.02 0.002 0.094 0.035 0.122 0.27 12/1/2052 100,293,100 17,667,125 82,625,975 6,135 0.02 0.002 0.097 0.035 0.126 0.28 12/1/2053 100,291,100 17,667,125 82,623,975 6,173 0.02 0.003 0.102 0.036 0.131 0.29 12/1/2054 --6,211 -0.004 0.105 0.037 0.135 0.28 12/1/2055 --6,249 -0.005 0.108 0.038 0.140 0.29 12/1/2056 --6,287 -0.006 0.113 0.039 0.144 0.3012/1/2057 --6,326 -0.006 0.121 0.041 0.153 0.3212/1/2058 --6,364 -0.006 0,127 0.041 0.161 0.33 12/1/2089 :-6,403 -0.006 0.133 0.042 0.168 0.3512/1/2060 -6,442 -0.006]0.137]0.043 0.172 0.36 Prepared by Seattle-Northwest Securities Corporation 12/1/2009 raid MeeoFDSM(000s):7eae Ae stPomBKSeite CUR Teg merrierBtalCost(000s) PRRER 4 Fixed O&M Cost |paaae cost 00s)2 con om Met: ehaehiaeelete(eee RTL Re HeeCRS:oe pa Capital Fund:Y Pheed RateCharge for:$4PieSclaneeaitey,Revenuor ah fe LER ROG kebak*Revenue available after,Sag comesservice oy GRETC Direct Debt Service Coverage a) 1|42/4/20i4 651 259,482 39,359 30,852 .44,085,125 8,817,025 1.25 8,817,0252)12/2/2022 1,491 271,621 38,557 32,902 54,963 -98,182,488 19,636,498 1.25 28,453,5233]12/1/2013 3,063 258,329 42,181 31,820 56,995 -98,180,113 19,636,023 .1.25 48,089,5454]12/1/2014 5,878 282,641 42,195 32,212 63,421 -130,810,269 26,162,054 °1.25 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 1.25 83,420,9546|12/1/2016 12,759 373,704 37,978 35,083 68,216 :170,849,837 34,169,967 1.25 117,590,921|7|12/1/2017 11,891 352,673 38,010 36,043 73,346 -210,411,399 42,082,280 1.25 105,000,000 54,673,2018|12/1/2018 12,241 224,380 36,088 34,170 81,543 -258,963,946 $1,792,789 1.25 -106,465,9909}12/1/2019 12,657 244,337 34,987 35,596 86,958 -258,966,633 51,793,327 1.25 158,259,31740}12/1/2020 13,124 235,418 37,177 29,384 90,354 -381,013,977 76,202,795 |1.25 190,000,000 44,462,11244]12/1/2021 13,346 247,202 39,360 30,390 97,474 :530,774,401 106,154,880 1.25 150,616,99212|12/1/2022 14,024 267,038 41,731 29,426 110,165 -530,773,463 106,154,693 1.25-256,772,68513]12/1/2023 4,166 284,104 35,897 30,380 114,805 -585,219,745 117,043,949 1.25 320,000,000 53,815,63414]12/1/2024 3,313 297,843 36,104 33,632 125,785 :652,032,594 130,406,519 .1.25 184,222,15315]12/1/2025 4,222 201,105 57,389 29,739 90,619 -652,034,406 130,406,881 |1.25 314,629,03416]12/1/2026 5,342 227,331 57,967 16,925 107,681 -652,028,469 130,405,694 4.25 445,034,72847}12/1/2027 8,551 238,262 58,593 17,362 118,039 -652,021,469 130,404,294 1.25 485,500,231 89,938,79118|12/1/2028 13,323 247,810 59,207 18,257 130,862 -652,029,094 130,405,819 «1.25 -220,344,61019]12/1/2029 16,151 261,837 59,916 18,745 146,548 -652,037,656 130,407,531 «1.25 350,752,14120|12/1/2030 17,064 226,648 84,248 17,865 135,367 --652,037,094 130,407,419 1.25 481,159,56024)12/1/2031 14,951 224,691 84,983 15,652 140,642 -652,033,031 130,406,606 1.25 611,566,16622|12/1/2032 15,081 234,947 86,456 16,124 152,129 -652,032,969 130,406,594 1.25 741,972,76023)12/1/2033 15,919 243,713 87,902 16,762 166,550 -652,027,094 130,405,419 1.25 872,378,17924|12/1/2034 16,747 260,041 89,276 17,408 180,198 :652,032,906 130,406,581 1.25 239,531,757 763,253,00325|12/1/2035 18,111 279,793 90,794 18,296 200,974 -652,024,281 130,404,856 1.25 893,657,85926|12/1/2036 5,493 292,296 92,408 18,814 218,387 -652,027,844 130,405,569 1.25 1,024,063,42827|12/1/2037 7,019 335,171 97,112 19,787 257,520 -652,025,281 130,405,056 1.25 1,154,468,48428|12/1/2038 6,453 382,597 98,638 20,542 281,586 -652,030,969 130,406,194 1.25 1,284,874,67829|12/1/2039 8,848 368,539 100,317 21,287 306,519 -652,033,094 130,406,619 1.25 699,805,525 715,475,77230|12/1/2040 12,284 385,523 101,920 22,089 332,326 -652,026,219 130,405,244 1.25 845,881,01634)12/1/2041 18,825 403,233 103,660 22,861 361,453 -652,029,156 130,405,831 1.25 976,286,84732]12/1/2042 21,552 394,321 95,445 21,546 371,427 :550,520,281 110,104,056 1.25 1,086,390,90333|12/1/2043 22,199 412,100 97,223 22,392 404,276 :550,525,969 110,105,194 1.25 720,727,822 475,768,27534|12/1/2044 23,458 428,330 152,761 23,116 439,168 :550,524,094 110,104,819 1.25 585,873,09435]12/1/2045 22,134 449,075 101,037 23,977 476,267 -475,401,781 95,080,356 1.25 680,953,45036|12/1/2046 22,961 421,293 140,010 26,073 466,403 -475,396,156 95,079,231 1.25 776,032,68137|12/1/2047 24,452 424,059 142,963 26,511 490,408 -475,393,594 95,078,719 1.25 871,111,40038)12/1/2048 25,398 444,961 146,057 27,392 537,229 -384,293,281 76,858,656 1.25 947,970,05639|12/1/2049 -6,909 461,902 149,294 28,395 584,308 :384,294,781 76,858,956 1.25 1,024,829,01340|12/1/2050 8,724 477,627 152,489 29,313 630,743 -384,300,344 76,860,069 1.25 1,101,689,08244]12/1/2051 11,174 503,605 155,601 30,361 656,308 -103,283,594 20,656,719 1.28 1,122,345,80042|12/1/2052 9,139 520,728 158,955 31,315 676,369 -103,282,469 20,656,494 1.25 4,143,002,29443|12/1/2053 14,889 546,462 162,470 32,477 705,371 -103,279,969 20,655,994 1.25 1,163,658,28844]12/1/2054 22,880 $62,487 165,955 33,535 723,997 --3 0.00 410,069,419 753,588,86945|12/1/2055 27,949 579,273 169,720 34,785 749,388 ---0.00 753,588,86946|12/1/2056 30,133 605,200 173,255 35,877 774,023 ---0.00 753,588,86947)12/1/2057 33,288 647,750 180,086 37,668 822,050 ---0.00 753,588,86948)12/1/2058 33,226 682,788 182,230 38,924 862,251 ---0.00 753,588,86943]12/1/2059 31,309 716,554 186,278 40,624 900,505 .-:0.00 753,588,86950|12/1/2060}32,092]734,465],290,935]41,639 923,018 cee -ae :0.00 753,588,869_ Prepared by Seattle-Northwest Securities Corporation 12/1/2009 RIRP Plan 1A -Alternative Case Financial Model Alaska Regional Integrated Resource Plan Scenario Cash Flow Summary dollars in millions nr ¥-RIRP-PLAN A -s Alternative Scenario 100%Fixed Rate Sources of Funds BONDS 3,657 STATE (through construction)2,409 Infrastructure Tax through 2027 883 Other (Use of Coverage Reserves)2,135 Total Source of Funds 9,085 Use of Funds Project/Construction 9,085 Payment of interest accrued 0 Reserve Funds 0 Issuance Costs (') Capitalized Interest (through construction)0 Total Uses of Funds °9,085 Maximum Annual Debt Service Requirements BONDS 314 STATE 322 Ave.Annual Energy Requirement (GWhr)§,625 Target Debt Service Coverage (DSC)1.25X All-in Borrowing Cost 7.00% E:Factor (Inflation)2.50% Average Cost of Energy ($/per kWh)0.06 Assumptions Issuance Cost =2%of Par Amount Par coupons Debt service reserve funded at 10%of Bond Par Amount Bonds all assumed to be 30 years from date of issue Prepared by Seattle-Northwest Securities Corporation ''TotalCapital 'Year Requirements (less ;tig for capital projects.Capital Markets "BONDSJargehydro)|aig sik geese Be SeeeT 1]12/1/2011 1 506,496,362 -506,496,362 >$833,019,1822|12/1/2012 :256,773,239 -256,773,239 :-- 3|12/1/2013 .119,476,707 3,990,284 123,466,991 -:: 4)12/1/2014 .122,463,625 $2,942,550 175,406,175 .(15,000,000)!$470,031,7695]12/1/2015 :2,435,356 192,310,564 193,745,920 --- 6|12/1/2016 33,699,203 22,466,161 255,989,420 278,455,581 Fry405,375,640 -- 7)12/1/2017 26,865,753 74,229,623 117,965,769 192,195,392 -(75,000,000)!$522,012,5488}12/1/2018 43,273,053 174,256,113 41,630,847 215,886,960 -.- 9/12/1/2019 79,301,147 174,171,476 169,193,895 343,365,370 --: 10}12/1/2020 238,340,271 208,891,416 321,882,411 $30,773,827 -(120,000,000)|$999,656,77814]12/1/2021 481,536,897 21,500,060 282,636,456 304,136,516 .-- 42]12/1/2022 652,793,164 .437,331,250 437,331,250 ::. 13]12/1/2023 712,137,997 .464,423,300 464,423,300 .(180,000,000)]$229,188,96244]12/1/2024 141,426,155 .59,937,820 59,937,820 ::. 15]12/1/2025 .-18,210,430 18,210,430 *-- 16]12/1/2026 --19,062,834 19,062,834 -:- 17|12/1/2027 .88,657,273 .88,657,273 -(245,000,000)]$32,875,89548]12/1/2028 .208,125,424 .208,125,424 .-- 19]12/1/2029 .188,717,535 -188,717,535 --- 20]12/1/2030 .---:- 21)12/1/2031 ...--- 22]12/1/2032 --..-- 23]12/1/2033 ...-.- 24]12/1/2034 .2,260,136 2,260,136 -(239,531,757)|$t)25|12/1/2035 -206,133,124 206,133,124 :-- 26}12/1/2036 .31,138,497 31,138,497 --: 27]12/1/2037 ::.--- 28]12/1/2038 -..-.- 29]12/1/2039 .127,791,596 127,791,596 .(600,000,000)!$99,805,52530]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 .131,612,221 131,612,221 .(250,000,000)!$470,727,82234]12/1/2044 .308,963,361 308,963,361 :.- 35]12/1/2048 .280,152,241 280,152,241 --- 36]12/1/2046 ..--.. 37|12/1/2047 ..+|LOTT 2,409,373,640 -: 38]12/1/2048 ..--- .. 39]12/1/2049 .:.--- 40]12/1/2050 ..°:.- 44)12/1/2051 .-:--- 42|12/1/2052 ...--- 43)12/1/2053 ...--: 44)12/1/2054 ..:.(410,069,429)!$(0)45]12/1/2055 -35,525,625 35,525,625 ..: 46]12/1/2056 .161,918,291 161,918,291 --.- 47]12/1/2057 ...--- 48]12/1/2058 .38,257,213 38,257,213 --: 49]12/1/2059 .174,368,290 174,368,290 -:. 50]12/1/2060 ..-: 12/1/2009 Oona&wh=Year Repayment of State Sid to bondhameric DSRF Interest Earnings Total Requirements ne ewhi).ear aCOt 12/1/2011 -33,131,525 -33,131,525 5,372 0.010 0.01 0.000 0.048 0.013 0.000 0.08 12/1/2012 76,283,050 2,499,058 73,783,992 §,412 0.010 0.02 9.000 0.051 0.013 0.010)0.10 12/1/2013 76,281,650 2,499,058 73,782,592 $,424 0.010 0.02 0.001 0.048 0.014 0.011)0.1012/1/2014 94,980,800 2,499,058 92,481,742 $,421 0.010 0.02 0.001 0.053 0.014 0.012)0.11 12/1/2015 119,327,100 3,909,153 115,417,947 5,167 0.010 0.03 0.002 0.067 0.013 0.012)0.1312/1/2016 -119,327,000 3,909,153 115,417,847 5,147 0.010 0.03 0.002 0.070 0.014 0.013 0,14 12/1/2017 -140,091,050 3,909,153 136,181,897 §,129 0.010 0.03 0.002 0.066 0.014 0.014 0.1412/1/2018 :167,135,950 5,475,190 161,660,760 §,105 0.010 0.04 0.002 0.042 0.013 0.015 0.12 12/1/2019 -167,133,450 5,475,190 161,658,260 $,085 0,010 0.04 0.002 0.045 0.013 0.016 0.1312/1/2020 -206,891,825 5,475,190 201,416,635 $,068 0.010 0.05 0.002 0.044 0.012 0.017 0.14 12/1/2021 -258,677,150 8,474,161 250,202,989 5,052 0.010 0.06 0.002 0.046 0.013 0.018)0.1512/1/2022 -258,678,050 8,474,161 250,203,889 5,081 0.010 0.06 0.003 0.050 0.013 0.021 0.16 12/1/2023 :267,790,975 8,474,161 259,316,814 $,111 0.010 0.06 0.001 0.053 0.012 0.021 0.1612/1/2024 :279,659,600 9,161,728 270,497,872 5,140 0.010 0.07 0.001 0.055 0.013 0.023!0.17 12/1/2025 -279,668,350 9,161,728 270,506,622 5,174 0.010 0.07 0.001 0.037 0.016 0.017 0.1512/1/2026 :279,658,100 9,161,728 270,496,372 5,207 0.010 0.06 0.001 0.042 0.014 0.020)0.1512/1/2027 -292,456,550 9,161,728 283,294,822 5,241 0.010 0.07 0.002 0.044 0.014 0.022 0.1612/1/2028 -305,241,850 9,260,355 295,981,495 5,275 0.07 0.002 0.046 0.014 0.024 0.16 12/1/2029 -305,240,900 9,260,355 295,980,545 5,309 0.07 0.003 0.049 0.015 0.027,0.1612/1/2030 -305,242,800 9,260,355 295,982,445 5,344 0.07 0.003 0.042 0.019 0.025 0.16 12/1/2031 -305,244,200 9,260,355 295,983,845 5,378 0.07 0.003 0.042 0.019 0.026 0.16 12/1/2032 -305,245,000 9,260,355.295,984,645 5,413 0.07 0.003 0.044 0.019 0.028 0.16 12/1/2033 -305,243,000 9,260,355 295,982,645 5,447 0.07 0.003 0.046 0.019 0.031 0.17 12/1/2034 -305,243,900 9,260,355 295,983,545 5,482 0.07 0.003 0.048 0.020 0.034 0.17 12/1/2035 -305,240,600 9,260,355 295,980,245 5,517 0.07 0.003 0.052 0.020 0.037,0.1812/1/2036 -305,243,900 9,260,355 295,983,545 5,553 0.07 0.001 0.054 0.021 0.041)0.18 12/1/2037 -305,236,100 9,260,355 295,975,745 5,588 0.07 0.001 0.062 0.022 0.048 0.2012/1/2038 -305,237,750 9,260,355 295,977,395 5,623 0.07 0.001 0.066 0.022 0.052 0.21 12/1/2039 -309,204,550 9,260,355 299,944,195 5,659 0.07 0.002 0.069 0.023 0.057 0.22 12/1/2040 -314,375,350 9,559,772 304,815,578 5,695 0.07 0.002 0.072 0.023 0.062 0.2312/1/2041 -314,385,800 9,559,772 304,826,028 5,731 0.07 0.004 0.075 0.024 0.067 0.2412/1/2042 -238,098,800 9,559,772 228,539,028 5,767 0.05 0.004 0.073 0.022 0.069 0.22 12/1/2043 -256,818,500 9,559,772 247,258,728 5,803 0.05 0.004 0.077 0.022 0.075 0.2312/1/2044 -281,213,300 10,971,955 270,241,345 $,839 0.06 0.004 0.080 0.033 0.082)0.2612/1/2045 -238,156,850 10,971,955 227,184,895 5,876 0.05 0.004 0.084 0.023 0.089 0.2512/1/2046 -238,159,400 10,971,955 227,187,445 5,912 0.05 0.004 0.078 0.031 0.087!0.2512/1/2047 95,827,375 238,157,150 10,971,955 323,012,570 5,949 0.07 0.005 0.079 0.032 0.091)0.2712/1/2048 191,654,750 190,355,650 10,971,955 371,038,445 $5,986 0.08 0.005 0.083 0.032 0.100 0.3012/1/2049 191,654,750 190,357,950 10,971,955 371,040,745 6,023 0.08 0.001 0.086 0.033 0.109 0.31 12/1/2050 191,654,750 190,355,750 10,971,958 371,038,545 6,060 0.08 0.002 0.089 0.034 0.117 0.32 12/1/2051 191,654,750 98,815,900 10,971,955 279,498,695 6,098 0.06 0,002 0.094 0.035 0.122 0.31 12/1/2052 191,654,750 98,809,900 10,971,958 279,492,695 6,135 0.06 0.002 0.097 0.035 0.126 0.32 12/1/2053 191,654,750 98,809,900 10,971,958 279,492,695 6,173 0.06 0.003 0.102 0.036 0.131 0.3312/1/2054 191,654,750 77,824,800 10,971,955 258,507,595 6,211 0.05 0.004 0.108 0.037 0.135 0.33 12/1/2055 196,264,750 77,826,750 10,971,955 263,119,545 6,249 0.05 0.005 0.108 0.038 0.149)0.34 12/1/2056 201,172,050 77,826,500 10,971,955 268,026,595 6,287 0.08 0.006 0.113 0.039 0.144)0.35 12/1/2087 206,198,250 $2,247,150 10,971,955 247,473,445 6,326 0.05 0.006 0.121 0.041 0.153 0.37 12/1/2088 211,354,400 $2,246,350 10,971,955 252,628,795 6,364 0.05 0.006 0.127 0.041 0.161 0.3812/1/2089 216,638,400 $2,250,150 10,971,955 257,916,895 6,403 0.05 0.006 0.133 0.042 0.168)0.4012/1/2060 222,055,700 52,242,250 10,971,955 263,325,995 6,442 |0.05 0.006 9.137 0.043 0.172)0.41 Prepared by Seattle-Northwest Securities Corporation 12/1/2009 =Sowononswn=aa2aannObwhSERIEEEPZ IT IER SABYRTNNSERE RESUS Deane ccon:Poeceeny PpeenrererxedORMCost'|scant O&M+i Revenue available after';.Year 05M (000s)4}:Fuel Cost (000s)ye *4 CO?Cost (000s)+¢'seedania He Debt Service 'Use offaba'estaeneepapasie(0005)4)cont tono'Cost (0005)-¥Wee .'debt service4 coverageHeopsmanSEdnscatfikeeiaustaorhpoee8 SRE 12/1/2011 651 259,482 39,359 30,852 -53,717,410.47 41,414,406 8,282,881 1.25 8,282,881 12/1/2012 1,491 271,611 38,557 32,902 54,963 $4,120,733.86 92,229,991 18,445,998 1.25 26,728,879 12/1/2013 3,063 258,329 42,181 31,820 56,995 $4,241,323.99 92,228,241 18,445,648 1.25:45,174,527 © 12/1/2014 5,878 282,641 42,195 32,212 63,421 54,213,850.02 115,602,178 23,120,436 1.25 15,000,000 53,294,963 12/1/2015 10,455 361,674 35,055 35,819 65,306 51,673,819.94 144,272,434 28,854,487 1.25 82,149,450 12/1/2016 12,759 373,704 37,978 35,083 68,216 51,473,835.41 144,272,309 28,854,462 1.25:111,003,912 12/1/2017 11,891 352,673 38,010 36,043 73,346 51,287,518.63 170,227,371 34,045,474 1.25 75,000,000 70,049,38612/1/2018 12,241 224,380 36,088 34,170 81,543 51,052,273.99 202,075,949 40,415,190 1.25 -110,464,576 12/1/2019 12,657 244,337 34,987 35,596 86,958 50,849,002.21 202,072,824 40,414,565 1.25 150,879,141 12/1/2020 13,124 235,418 37,177 29,384 90,354 50,683,538.05 251,770,793 50,354,159 1.25 120,000,000 81,233,299 12/1/2021 13,346 247,202 39,360 30,390 97,474 50,524,635.70 312,753,736 62,550,747 1.25 143,784,047 12/1/2022 14,024 267,038 41,731 29,426 110,165 50,814,618.33 312,754,861 62,550,972 1.25 206,335,019 12/1/2023 4,166 284,104 35,897 30,380 114,805 51,106,167.59 324,146,018 64,829,204 1.25 180,000,000 91,164,222 12/1/2024 3,313 297,843 36,104 33,631 125,785 §1,401,295.01 338,122,340 67,624,468 1.25 158,788,691 12/1/2025 4,222 201,105 $7,389 29,739 90,619 51,736,787.37 338,133,278 67,626,656 1.25 226,415,346 12/1/2026 5,342 227,331 57,967 16,925 107,681 52,073,821.68 338,120,465 67,624,093 1.25 294,039,439 12/1/2027 8,551 238,262 58,893 17,362 118,039 52,412,432.40 354,118,528 70,823,706 1.25 245,000,000 119,863,145 12/1/2028 13,323 247,810 59,207 18,257 130,862 -369,976,868 73,995,374 1,25 193,858,518 12/1/2029 16,151 261,837 59,916 18,745 146,548 -369,975,681 73,995,136 1,25 267,853,655 12/1/2030 17,064 226,648 84,248 17,865 135,367 .369,978,056 73,995,611 1.25 341,849,26612/1/2031 14,951 224,691 84,983 15,652 140,642 -369,979,806 73,995,962 1.25 415,845,22712/1/2032 15,081 234,947 86,456 16,121 152,129 -369,980,806 73,996,161 1.25 489,841,38812/1/2033 15,919 249,713 87,902 16,762 166,550 -369,978,306 73,995,661 1.25 563,837,04912/1/2034 16,747 260,041 89,276 17,408 180,198 -369,979,431 73,995,886 1,25 239,531,757 398,301,178 12/1/2035 18,111 279,793 90,794 18,296 200,974 -369,975,306 73,995,061 1.25 -472,296,239 12/1/2036 5,493 292,296 92,408 18,814 218,387 -369,979,431 73,995,886 1.25 546,292,126 12/1/2037 7,019 335,171 97,112 19,787 257,520 -369,969,681 73,993,936 1.25 620,286,062 12/1/2038 6,453 352,597 98,638 20,542 281,586 -369,971,743 73,994,349 1.25 694,280,410 12/1/2039 8,848 368,539 100,317 21,287 306,519 coe 374,930,243 74,986,049 1.25 600,000,000 169,266,45912/1/2040 12,284 385,523 101,920 22,049 332,326 -381,019,473 76,203,895 1.25 :245,470,35412/1/2041 18,825 403,233 103,660 22,861 361,453 -381,032,535 76,206,507 1.25 321,676,86112/1/2042 21,552 394,321 95,445 21,546 371,427 -285,673,785 57,134,787 1.25 378,811,61812/1/2043 22,199 412,100 97,223 22,392 404,276 -309,073,410 61,814,682 1.25 250,000,000 190,626,30012/1/2044 23,458 428,330 152,761 23,116 439,168 .337,801,681 67,560,336 1,25 :258,186,63612/1/2045 22,134 449,075 101,037 23,977 476,267 -283,981,118 56,796,224 1.25 314,982,85912/1/2046 22,961 421,293 140,010 26,073 466,403 -283,984,306 56,796,861 1.25 371,779,72012/1/2047 24,452 424,059 142,963 26,511 490,408 -403,765,712 80,753,142 1.25 452,532,86312/1/2048 25,398 444,961 146,057 27,392 $37,229 -463,798,056 92,759,611 1.25 545,292,47412/1/2049 6,909 461,902 149,291 28,395 584,308 -463,800,931 $2,760,186 1.25 638,052,660 12/1/2050 8,724 477,627 152,489 29,313 630,743 -463,798,181 92,759,636 1.25 730,812,296 12/1/2051 11,174 503,605 155,601 30,361 656,308 -349,373,368 69,874,674 1.25 800,686,970 12/1/2082 9,139 520,728 158,955 31,315 676,369 -349,365,868 69,873,174 1.25 870,560,14412/1/2053 14,889 546,462 162,470 32,477 705,371 -349,365,868 69,873,174 1.25 940,433,317 12/1/2054 22,880 562,487 165,955 33,535 723,997 :323,134,493 64,626,899 1.25 410,069,419 594,990,797 12/1/2055 27,949 $79,273 169,720 34,785 749,388 -328,899,431 65,779,886 1.25 660,770,683 12/1/2056 30,133 605,200 173,255 35,877 774,023 -335,033,243 67,006,649 1.25 727,777,332 12/1/2057 33,288 647,750 180,086 37,668 822,050 -309,341,806 61,868,361 1.25 789,645,693 12/1/2058 33,226 682,788 182,230 38,924 862,251 -315,785,993 63,157,199 1.25 852,802,891 12/1/2059 31,309 716,551 186,278 40,624 900,505 -322,395,743 64,479,149 1.25 917,282,04012/1/2060|,_._,32,092 734,465 .190,935 41,639 |,923,018]329,157,493}65,831,499 1250 983,113,539, Prepared by Seattle-Northwest Securities Corporation 12/1/2009 APPENDIX D EXISTING GENERATION UNITS ALASKA RIRP STUDY APPENDIX D EXISTING GENERATION UNITS Black &Veatch D-1 December 2009DRAFTREPORT Detailed Existing Unit Tables Winter Summer [|Mioimum Full Load Net Plant Forced Rating Rating Capacity |Variable O&M |Fixed O&M (2009 |Heat Rate (BtwkWh-|Outage [Must Run}COZ Emission |NOx Emission |SO2 EmissionNameUnit|Primary Fuel]Startup Fuel (MW)(MW)(MW)(2009 S/MWh)$/kW-yr)HHV)Rate (%)-(Y/N)_|Rate (!b/mmBtu}}Rate (Ib Btu)|Rate (tb Retirement Date Anchorage ML&P -Plant 1 3 Natural Gas |Natural Gas 32 29.3 1 3.72 10.87 9,780 6.0 N 1148 0.44 0.000045 2037 Anchorage ML&P -Plant 2 5 Natural Gas Natural Gas 37.4 33.8 5 3.72 11.62 {4 Ll N 114.8 0.625 0.000045 2020 Anchorage ML&P -Plant 2 5/6 Natural Gas |Natural Gas 49.2 44.5 10 3.72 11.62 11 Ll N 114.8 0.625 0.000045 2020 Anchorage ML&P -Plant 2 7 Natural Gas Natural Gas 81.8 744 10 3.72 1.79 1,193 0.1 N 114.8 0.625 0.000045 2030 Anchorage ML&P -Plant 2 6 Natural Gas [Natural Gas 109.5 99.5 10 3.72 7.79 9,030 0.1 N 114.8 0.625 0.000045 2020 [Anchorage ML&P Plant 2 8 Natural Gas |Natural Gas 87.6 77.3 20 3.72 TAT 11,930 17 N 114.8 0.08 0.000045 2030 Winter Summer |Minimum Full Load Net Plant Forcd Must :SQ2 Emission Primary Rating Rating Capacity Variable O&M Fixed O&M (2009 |Heat Rate (Btu/kWh-|Outage Run |CO2 Emission |NOx Emission Rate Name Unit Fuel Startup Fue (MW)(MW)(MW)(2009 $/MWh)S/kW-yr)HHV)Rate (9%)|CYAN)|Rate (Ib/mmBtu)]Rate (lb/mmBtu)](lb/mmBtu)|Retirement Date! Bernice 2 Natural Gas |Natural Gas 19 19 3 1.23 6.15 14,673 2.0 N 115 0.32 0.000045 2014 Bernice 3 Natural Gas |Natural Gas 25.5 25.5 13 1.23 19.48 13,409 2.0 N 115 0.13 0.000045 2014 Bernice 4 Natural Gas |Natural Gas 25.5 25.5 13 1.23 19.48 13,741 2.0 N 115 0.13 0.000045 2014 Beluga 1 Natural Gas }Natural Gas 17.5 16 3 1.23 14.35 15,198 2.0 N 115 0.32 0.0002 2011 Beluga 2 Natural Gas {Natural Gas 17.5 16 3 1.23 14.35 14,851 2.0 N 115 0.32 0.0002 2011 Beluga 3 Natural Gas |Natural Gas 66.5 56 3 1.44 12.30 12,236 2.0 N 115 0.32 0.0002 2014 Beluga 5 Natural Gas |Natural Gas 65 54 3 1.44 12.30 12,537 2.0 N 115 0.32 0.0002 2017 Beluga 6 Natural Gas |Natural Gas 82 64 3 1.64 13.33 11,528 1.0 N 115 0.2 0.001 2020 Beluga 6/8 Natural Gas |Natural Gas 108.5 83 48 2.56 29.73 9,329 4.0 N 115 0.2 0.001 2014 Beluga 7 Natural Gas |Natural Gas 82 66 3 1.64 13.33 12,184 1.0 N 115 0.34 0.006 2021 Beluga 18 Natural Gas }Natural Gas 108.5 85 48 2.56 29.73 9,086 40 N 115 0.34 0.006 2014 International 1 Natural Gas |Natural Gas 14 13 3 1.23 14.35 16.379 2.0 N 115 0.32 0.002 2011 International 2 Natural Gas |Natural Gas 14 12.5 3 1.23 14.35 17,425 2.0 N 115 0.32 9.002 2011 International 3 Natural Gas |Natural Gas 19 16 3 1.23 14.35 15,116 2.0 N 115 0.32 0.002 2012 Winter Summer |Minimum .Forced Rating Rating Capacity [Variable O&M (2009]Fixed O&M (2009 |Full Load Net Plant Heat}Outage [Must Rug CO2 Emission [|NOx Emission |SO2 EmissionNameUnitPrimaryFuel]Startup Fuel (Mw)(MW)S/MWh)$/kW-yr)Rate (Btu/kWh -HHV}|Rate (%)|(Y/N)|Rate (b/mmBtu)]Rate (b/mmBtu)|Rate (b/mmBtu]Retirement DateZehnderGTIHAGODistillateFuelOtt19215.8 4 8.23 10.98 14,030 0.1 N 128 07 08 2030 Zehnder GT2 HAGO Distillate Fuet Oil 19.6 15 4 8.23 10.98 14,190 0.2 N 128 07 0.8 2030 North Pole CTL HAGO Distillate Fuel Oil 62.6 50 10 3.91 21.41 10,010 0.6 N 128 0.7 0.7 2017 North Pole GT2 HAGO Distillate Fuel Oil 60.6 48 10 3.91 21.41 9,720 0.5 N 128 0.7 0.7 2018 North Pole cc NAPHTHA Distillate Fuel Oil 65 54 38 3.20 224.56 6,620 0.4 N 114.8 0.76 0.0022 2042 Healy STI COAL Distillate Fuel Oil 27 26.5 20 3.30 208.60 13,870 0.7 Y 2ui 0.25 0.3 2022 DPP 1 HAGO Distillate Fuel Oil 25.8 23.1 4 8.23 10.98 13,210 0.3 N 128 0.7 0.12 2030 Winter [Summer |Minimum Forced [Must S02 Emission Primary Rating Rating Capacity |Variable O&M (2009 |Fixed O&M (2009 |Full Load Net Plant Heat]Outage Run |CO2 Emission |NOx Emission Rate Name Unit Fuel Startup Fuel](MW)(MW)(MW)$/MWh)$/kW-yr)Rate (BtwkWh -HHV)}Rate (%)|(Y/N)]Rate (b/mmBtu)|Rate (b/mmBtu}](b/mmBtu)[Retirement Datel Nikiski 1 Natural Gas |Natural Gas 42 38 3 6.63 4.82 12,170 1.0 Y 1148 0.13 0.000045 2026 APPENDIX E REGIONAL LOAD FORECASTS ALASKA RIRP STUDY APPENDIX E REGIONIAL LOAD FORECASTS Black &Veatch E-1 December 2009 DRAFT REPORT APPENDIX E REGIONAL LOAD FORECASTS ALASKA RIRP STUDY Table E-t GRETC's Winter Peak Load Forecast for Evaluation 2011 -2060 Winter Peak Demand (MW) 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 233.9 241.3 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 237.6 224.3 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 2448 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 9718 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 2111 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 .2174 220.4 10.4 1044.1 2043/2044 260.1 267.4 111.4 219.7 2214 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 1148 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 10.4 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 271.7 289.6 121.8 249.3 234.2 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 E-2 December 2009 DRAFT REPORT APPENDIX E REGIONAL LOAD FORECASTS ALASKA RIRP STUDY Table E-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 199.3 213.9 75.1 120.0 171.4 10.0 761.4 2012 199.3 215.3 15.9 124.1 172.3 10.0 768.5 2013 199.3 216.8 75.9 125.7 173.2 11.0 773.3 2014 199.3 218.2 75.9 127.4 174.1 11.0 777.2 2015 200.2 195.4 76.8 129.0 175.0 11.0 760.1 2016 200.2 196.9 17 130.6 175.9 11.0 764.9 2017 201.1 198.6 117 132.3 176.9 11.0 769.9 2018 201.9 200.1 78.5 133.9 177.8 11.0 775.5 2019 202.8 201.5 79.4 135.6 178.7 11.0 781.1 2020 202.8 203.0 79.4 137.2 179.6 11.0 785.0 2021 203.7 204.5 80.2 138.9 180.5 11.0 790.6 2022 204.6 206.0 81.1 140.5 181.4 11.0 796.3 2023 205.5 207.5 81.1 142.2 182.3 11.0 801.1 2024 206.4 209.0 82.0 144.6 183.2 11.0 807.6 2025 206.4 210.5 82.8 146.3 184.1 11.0 812.4 2026 207.3 212.0 83.7 147.9 185.1 11.0 818.1 2027 208.1 213.6 83.7 149.5 186.0 11.0 822.9 2028 209.0 215.1 84.6 151.2 186.9 11.0 828.6 2029 209.9 216.6 85.4 152.8 187.8 11.0 834.3 2030 210.8 218.1 86.3 154.5 188.7 11.0 840.0 2031 211.6 219.7 87.0 156.3 189.6 11.0 845.6 2032 212.4 221.2 87.7 158.1 190.5 11.0 851.2 2033 213.2 222.8 88.3 159.9 191.5 11.0 856.8 2034 214.0 224.3 89.0 161.7 192.4 11.0 862.5 2035 214.8 225.9 89.7 163.5 193.3 11.0 868.2 2036 215.6 227.5 90.4 165.4 194.3 11.1 873.9 2037 216.4 229.1 91.1 167.2 195.2 11.1 879.6 2038 217.2 230.6 91.8 169.1 196.2 11.2 885.4 2039 218.0 232.2 92.6 171.0 197.1 11.2 891.1 2040 218.8 233.8 93.3 172.9 198.0 11.3 896.9 2041 219.6 235.4 94.0 174.8 199.0 11.4 902.8 2042 220.4 237.0 94.7 176.7 199.9 11.4 908.6 2043 221.3 238.6 95.4 178.6 200.9 11.5 914.5 2044 222.1 240.3 96.1 180.5 201.8 11.5 920.4 2045 222.9 241.9 96.9 182.5 202.8 11.6 926.3 2046 223.7 243.5 97.6 184.5 203.8 11.7 932.3 2047 224.5 245.2 98.3 186.4 204.7 11.7 938.3 2048 225.4 246.8 99.1 188.4 205.7 11.8 944.3 2049 226.2 248.5 99.8 190.4 206.6 11.8 950.3 2050 227.0 250.1 100.5 192.5 207.6 11.9 956.4 2051 227.8 251.8 101.3 194.5 208.6 12.0 962.5 2052 228.7 253.5 102.0 196.5 209.6 12.0 968.6 2053 229.5 255.1 102.8 198.6 210.5 12.1 974.8 2054 230.3 256.8 103.6 200.7 211.5 12.1 980.9 2055 231.2 258.5 104.3 202.8 212.5 12.2 987.2 2056 232.0 260.2 105.1 204.9 213.5 12.3 993.4 2057 232.8 261.9 105.8 207.0 214.5 12.3 999.7 2058 233.7 263.6 106.6 209.1 215.5 12.4 1005.9 2059 234.5 265.3 107.4 211.3 216.4 12.4 1012.3 2060 235.3 267.1 108.2 213.4 217.4 12.5 1018.6 Black &Veatch E-3 December 2009 DRAFT REPORT APPENDIX E REGIONAL LOAD FORECASTS ALASKA RIRP STUDY Table E-3 GRETC's Annual Valley Load Forecast for Evaluation 2011 -2060 Annual Valley Demand (MW) Year CEA GVEA HEA MEA ML&P SES GRETC 2011 95.4 88.6 44.4 §3.2 91.0 4.4 413.5 2012 95.4 89.2 44.9 55.0 91.5 4.4 417.2 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 4.8 413.7 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 4.8 426.9 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 48.6 64.2 97.3 48 438.9 2025 98.8 87.2 49.0 64.9 97.7 48 441.4 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 4.8 447.0 2028 100.1 89.1 50.1 67.1 99.2 4.8 450.0 2029 100.5 89.7 50.6 67.8 99.7 48 453.1 2030 100.9 90.4 51.1 68.5 100.2 4.8 456.1 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 4.8 462.1 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 4.8 474.1 2037 103.6 94.9 54.0 74.2 103.6 4.8 477.2 2038 104.0 95.6 54.4 75.0 104.1 4.8 480.2 2039 104.4 96.2 54.8 75.9 104.6 4.8 483.3 2040 104.8 96.9 §5.2 76.7 105.1 4.8 486.4 2041 105.2 97.5 55.6 775 105.6 4.8 489.5 2042 105.5 98.2 56.1 78.4 106.1 4.8 492.6 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 4.8 498.8 2045 106.7 100.2 67.3 81.0 107.6 4.8 502.0 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 48 511.5 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 4.8 521.2 2052 109.5 105.0 60.4 87.2 411.2 48 524.4 2053 109.9 105.7 60.9 88.1 111.8 4.8 527.7 2054 110.3 106.4 61.3 89.0 112.3 48 530.9 2055 110.7 107.1 61.7 90.0 112.8 4.8 534.2 2056 411.1 107.8 62.2 90.9 113.3 48 §37.5 2057 111.5 108.5 62.7 91.8 113.8 4.8 540.8 2058 111.9 109.2 63.1 92.8 114.4 48 544.2 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 E-4 December 2009 DRAFT REPORT APPENDIX E REGIONAL LOAD FORECASTS ALASKA RIRP STUDY Table E-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 1,302. 2011 0 1,522.7 §54.5 771.2 1,162.8 64.6 5,377.8 1,303. 2012 2 1,532.1 557.1 801.9 4,168.3 64.8 5,427.4 1,305. 2013 0 1,543.0 560.2 811.1 1,173.8 65.0 5,458.1 1,307. 2014 5 1,553.2 564.0 820.9 1,179.3 65.3 5,490.3 1,311. 2015 4 1,333.5 568.1 831.9 1,184.9 65.6 §,295.3 1,315. 2016 6 1,344.4 §72.4 842.8 1,190.4 65.9 5,331.5 4,320. 2017 1 1,355.5 577.0 854.0 1,196.0 66.3 5,369.0 1,324. 2018 8 1,361.5 581.7 865.4 1,201.6 66.6 5,401.6 1,329. 2019 6 1,367.4 586.5 876.8 1,207.3 67.0 5,434.7 1,334. 2020 5 1,373.4 §91.2 888.3 1,213.0 67.4 5,467.8 1,339. 2021 4 1,379.5 596.1 900.1 1,218.7 67.8 5,501.6 1,344, 2022 3 1,385.5 601.0 911.7 1,224.4 68.1 5,535.0 1,349. 2023 2 1,391.6 605.9 923.2 1,230.1 68.5 5,568.6 1,354. 2024 3 1,397.7 610.7 934.8 1,235.9 68.9 5,602.3 1,359. 2025 2 1,403.8 615.5 946.4 1,241.7 69.3 5,636.0 1,364, 2026 2 1,410.0 620.4 958.0 1,247.6 69.7 5,669.9 1,369. 2027 3 1,416.2 625.3 969.7 1,253.4 70.0 5,703.9 1,374. 2028 4 1,422.3 630.2 981.3 1,259.3 70.4 5,738.0 1,379. 2029 5 1,428.5 635.1 992.9 1,265.3 70.8 5,772.0 1,384. 2030 5 1,434.7 640.0 1,004.7 1,271.2 71.2 5,806.3 1,389. 2031 6 1,440.8 645.0 1,016.7 1,277.1 71.6 5,840.8 1,394. 2032 7 1,447.0 650.0 1,028.7 1,283.0 72.0 5,875.4 1,399. 2033 7 1,453.3 655.0 1,040.9 1,289.0 72.4 §,910.2 1,404. 2034 8 1,459.5 660.0 1,053.1 1,294.9 72.7 5,945.1 1,409. 2035 9 1,465.7 665.1 1,065.4 1,300.9 73.1 5,980.1 1,415. 2036 0 1,472.0 670.2 1,077.8 1,306.8 73.5 6,015.3 1,420. 2037 1 1,478.2 675.3 1,090.2 1,312.8 73.9 6,050.6 1,425. 2038 3 1,484.5 680.4 1,102.8 1,318.8 74.3 6,086.1 1,430. 2039 4 1,490.8 685.5 1,115.4 1,324.9 74.7 6,121.7 1,435. 2040 5 1,497.1 690.7 1,128.1 1,330.9 75.1 6,157.4 1,440. 2041 7 1,503.5 695.9 1,140.9 1,336.9 75.5 6,193.3 1,445. 2042 8 1,509.8 701.1 1,153.7 1,343.0 75.9 6,229.3 1,451. 2043 0 1,516.2 706.3 1,166.7 1,349.1 76.3 6,265.5 Black &Veatch E5 December 2009 DRAFT REPORT APPENDIX E REGIONAL LOAD FORECASTS ALASKA RIRP STUDY 1,456.2044 2 14,5225 711.5 11797 1,3552 767 6,301.9 1,461 2045 4 1,528.9 7168 1,1929 1,361.3 77.1 6,338.4 1,466. 2046 6 1,535.3 722.1 1,2061 1,367.4 77.5 6,375.0 1,471 2047 8 1,541.7 727.4 41,2194 1,373.5 77.9 6,411.8 1,477. 2048 0 1,548.2 7328 1,2328 1,3797 783 6,448.8 1,482. 2049 3 1,554.6 738.1 1,2463 1,3859 787 6,485.9 1,487. 2050 5 1,561.1 743.5 1,259.9 1,392.4 79.1 6,523.2 1,492. 2051 8 1,567.5 7489 1,2736 1,398.3 79.5 6,560.6 1,498. 2052 0 1,574.0 754.4 1,287.4 1,4045 79.9 6,598.2 1,503. 2053 3 1,580.5 759.8 1,301.3 1,4107 803 6,635.9 1,508. 2054 6 1,587.1 765.3 1,3153 1,416.9 807 6,673.9 1,513. 2055 9 1,593.6 7708 1,294 1.4232 81.1 6,712.0 1,519 2056 2 1,600.1 776.3 13436 1,4295 81.5 6,750.2 1,524. 2057 5 1,606.7 781.9 1,357.9 1.4358 81.9 6,788.7 4,529. 2058 8 1,613.3 787.5 1,3723 1,442.1 82.3 6,827.3 1,535. 2059 1 1,619.9 7931 13868 1.4484 828 6,866.0 1,540. 2060 5 1,626.5 798.7 1,401.4 14547 83.2 6,905.0 Black &Veatch Es December 2009 DRAFT REPORT APPENDIX E REGIONAL LOAD FORECASTS ALASKA RIRP STUDY Table E-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 224.3 424.1 165.0 102.2 891.8 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 TAT8 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 T5T.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 569.2 1072.9 222.1 222.9 2009.3 2045/2046 571.1 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 582.1 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 E-7 December 2009 DRAFT REPORT APPENDIX E REGIONAL LOAD FORECASTS ALASKA RIRP STUDY Table E-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 5,377.8 2012 1,532.1 2,471.5 801.9 621.9 §,427.4 2013 1,543.0 2,478.8 811.1 625.2 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 9,371.1 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 E-8 December 2009 DRAFT REPORT APPENDIX F DETAILED RESULTS -SCENARIO 1A ALASKA RIRP STUDY APPENDIX F DETAILED RESULTS -SCENARIO 1A Black &Veatch F-1 December 2009 DRAFT REPORT Plan 1A P50 Summary Scenario 1 Plan 1A -P50 Natural Gas Forecast Renewable Annual Capital Cumulative Reserve Generation Fuel Costs Total O&M CO2 Costs |DSM Costs |Fixed Charges|Total Annual Present Value Year Additions Reti T Margin (%)}(%)($000)Costs ($000)($000)($000)($000)Costs ($000)($000)Beluga -1;Beluga -2;International -T; 2011 Anchorage MSW International-2 §2,28%14.44%$289,482 $70,211 $o $651 14,610 344,953 $344,953 2012 GVEA MSW International-3 44,38%14.97%$271,814 $71,458 $54,963 $1,491 16,442 415,965 733,708 2013 Anchorage 1x1 6FA 59.43%T4B5%$258,328 $74,001 $56,095|$3,063 51,650 444,037 1,121,545 Beluga -3;Beluga -6/8;Beluga -7/8; 2014 Bernice -2;Bernice -3 58.86%14.75%$282,641 $74,407 $63,421 $5,878 $51,650 $477,996 1,511,732 2015 Glacier Fork 40.52%18.40%$001,674 $70,874 $65,306 $10,455 $85,077 $593,386 1,964,424EklutnaSub;Lucas Sub;STEVENS;CANTWELL, 2016 Eklutna -Lucas Trans 53.35%21.39%$373,704 $73,061 $68,216 $12,759 $93,450 $621,189 2,407,323 Soldotna Sub;Quartz CR Sub;University Sub; STERLING;DAVES CR;HOPE;PORTAGE; 2017 Nikiski Wind Beluga -5;NP1 GIRDWOOD;INDIAN;Soldotna -University Trans}64.52%22.10%$352,673 $74,053 $73,346 $11,891 $127,807 $639,770 2,833,629 2018 NP2 Soldotna -Quartz Trans;Quartz -University Trans]40.11%21,90%224,380 $70,258 $81,543 $12,241 151.716 540,138 3,170,000 2019 33.87%21.84%244,337 $70,583 $86,958 $12,657 151,716 568,252 3,499,564 2020 GVEA 1x1 6FA Beluga -6,MLP 5;MLP 5/6;MLP 7/6 Lorraine Sub 45.52%21.78%235,418 $66,561 $90,354 $13,124 199,959 605,416 3,828,870 Douglas Sub;Healy Sub;Lake Lorraine -Douglas Trans;Beluga -Pt.Mackenzie Trans;Lawing - 2021 Anchorage LM6000 Beluga-7 Seward 42.12%21.58%$247,202 $69,750 $97,474 $13,348 $240,267 $668,038 4,168 467 Teeland Sub;Douglas -Healy Trans 1;Douglas - 2022 GVEA LMS100 Healy -1 Teeland Trans 42.80%21.45%$267,038 $71,157 $110,165 $14,024 $300,456 $762,840 4,530,886 2023 Soldotna -Sradley Lake Trans 38,70%21.32%$284,104 $66,277 $114,805 $4,166 $312,405 $781,757 4,877,996 Goldhill Sub;Wilson Sub;NENANA;ESTER; Douglas -Healy Trans 2;Healy -Goldhill Trans; 2024 Healy -Wilson Trans 37.59%21.23%$297,843 $69,735 $125,785 $3,313 $393,963 $890,639 5,247,579 COTTLE;HERNING;SHAW,LAZELLE;ONEIL, Pt,Mackenzie -Plant 2 Trans;Lucas -Teeland 2025 Chakacharnna:Chakachamna GVEA Aurora Purchase -Tier I Trans 1 76,50%49.17%$201,105 $87,127 $90,619 $4,222 $660,949 $1,044,021 5,652,469 026 Nikiski 87.15%48.61%227,331 $74,892 $107,681 $5,342 660,949 1,076,195 6,042,531 027 Lucas -Teeland Trans 2 68.05%48.59%298,262 $75,955 $118,039 $8,551 664,915 1,105,722 6,417,078 028 64.79%48.47%247,810 $77,464 $130,862 $13,323 664,915 1,134,374 6,776,192 2029 63.56%48.01%$261,837 $78,662 $146,548 $16,151 $664,915 $1,168,112 7,121,794 2030 Mount Spurr T DPP -6;MLP 7;MLP 8;Zen1,Zen2 48.45%53.80%$226,848 $102,113 $135,367 $17,064 $720,165 $1,201,357 7,453,979 2031 39.90%53.74%$224,691 $100,635 440,642 14,951 720,165 $1,201,084 7,764,362 2032 38.88%53.60%$234,947 $102,576 482,129 415,081 720,165 $1,224,899 8,060,191 2033 37.85%53.07%$249,713 $104 664 166,550 15,919 720,165 4,257,011 8,343,915 2034 36.85%$3,02%$260,044 106,684 180,198 16,747 720,165 1,283,835 8,614,736 2035 35.86%52.52%$279,793 109,090 200,974 18,114 720,165 1,328,134 8 876,573 2036 34.88%52.40%$292,296 111,222 218,387 $5,493 720,165 1,347,563 9,124,860 2037 GVEA LMS100 MLP 3 40.87%51,32%$335,171 116,899 $257,520 $7,019 $742,223 $1,458,832 9,376,065 2038 39.85%51.07%$352,597 $119,179 281,586 $6,453 $742,223 $1,502,037 9,617,788 2039 38.86%50.73%$368,539 $121,604 306,519 $8,848 $742,223 $1,547,733 9,850,571 2040 37.86%50.73%$385,523 $123,969 332,326 12,284 742,223 1,596,325 10,074,954 204 36.88%50.35%403,233 126,521 364,453 18,825 727,612 1,637,644 10,290,087 2042 GVEA 1x1 6FA NPCC 46.34%50.54%394,321 116,991 371,427 21,552 797,830 4,702,121 10,499,062 204:45.31%50.30%412,100 119,615 404,276 22,199 762,622 1,720,812 10,696,509 2044 44.27%50.15%$428,330 175,877 433,168 23,458 $762,622 1,829,455 40,892,691 2045 43.24%49.73%$449,075 125,015 476 267 22,134 $729,196 1,801,686 41,073,254 2046 Mount Spurr 47.41%54.97%$421,293 166,083 466,403 22,961 $794,230 $1,870,970 41,248,495 2047 46.38%54.74%424,059 169,474 490,408 24,452 745,861 $1,854,254 41,410,808 2048 45.35%54.64%444,961 173,448 537,229 $25,398 721,953 1,902,989 41,566,489 2049 44.35%54.18%461,902 177,686 584,308 $6,909 721,953 1,952,757 41,715,791 2050 43.33%54.01%$477,827 181,803 630,743 $8,724 673,710 1,972,607 41,856,744 2051 42.34%53.69%$503,605 185,961 656,308 $11,174 642,014 1,999,063 41,990,242 052 41.35%53.54%$520,728 190,271 $676,369 $9,139 599,775 1,996,281 12,114,833 053 40.38%53.11%$546,462 194,947 $705,371 $14,889 587,826 2,049,495 12,234,377 054 39.40%§2.92%$562,487 199,490 723,997 $22,880 506,268 $2,015,122 12,344,227 2055 38.44%52.65%$579,273 204,505 749,388 327,949 494,191 12,055,306 12,448,937 056 37.48%52.53%$605 200 209,132 774,023 30,133 494,194 2,412,879 12,549,529057.Anchorage LM6000 Cooper Lake 41.10%52.05%$647,750 217,754 822,050 $33,288 $511,175 2,232,016 12,648 851 058 38.33%51.14%682,788 224,154 862,254 33,226 $511,175 2,310,594 12,744,942 2059 37.38%§0.85%716,551 226,902 900.505 31,309 $511,175 2,386,444 12,837 696 2060 Anchorage [M6000 40.91%50.70%732,571 235,417 919,733 $32,092 $478 485 $2,398 297 12,924,812 Present Value of Costs 4,398,814 1,293,592 2,140,379 149,474 4,942,553 12,924,812 Rlack &Veatch Canfidentiz! Pian 1A P50 Summary Scenario 1 Plan 1A -P50 Natural Gas Forecast Annual Natural Gas Usage (mmBtu) Year Anchorage Interior Matanuska__Kenai__Total Railbelt 2011 34,619 0 0 4373 36,992 2012 33,318 0 QO 5128 38,446 2013 33,572 0 Q 3,787 37,359 2014 34,428 0 QO 3,376 37,804 2015 26,048 0 Q 3,543 29,590 2016 23,745 0 Oo 3,511 27,256 2017 24,434 0 QO 3,284 27,719 2018 21,998 9,776 0 3,436 35,209 2019 23,559 6,629 0 3,564 33,952 2020 18,456 11,030 O 3,482 32,969 2024 19,143 10,575 0 2,710 32,428 2022 19,054 11,786 0 2,745 33,585 2023 19,708 13,033 0 2,780 35,611 2024 48,101 14,546 6 2631 35,278 2025 8,928 12,863 0 940 22,732 2026 9,748 13,941 0 828 24,517 2027 10,366 13,994 °0 24,360 2028 10,363 14,177 V)t')24,541 2029 10,710 14,295 0 Qo 25,005 2030 5,976 14,576 t)Q 20,552 2034 7,360 12,707 te)0 20,066 2032 7,591 12,585 0 0 20,177 2033 7,685 12,881 0 0 20,56520347,870 13,076 0 ")20,746 2035 8,574 13,012 0 LY)21,587 2036 9,089 12,709 0 ts)21,797 2037 6,807 17,404 0 Q 24,211 2038 6,453 18,192 t*)0 24,645 2039 6,576 18,304 LY)i)24,97120408,595 18,616 (*)[)25,21120416,728 18,784 [)t')25,513 2042 6,195 17,944 0 0 24,135 2043 6,295 18,140 0 0 24,43620446,323 18,366 [)t')24,689 2045 6,520 18,454 0 0 24,974 2046 5,561 17,146 )0 22,706 2047 5,200 16,965 0 0 22,164 2048 5,201 17,274 iy 0 22,566 2049 §,382 17,463 0 0 22,845 2050 5,387 17,541 iy 9 22,938 2051 5,387 17,947 0 LY)23,334 2052 5,499 17,953 0 0 23,453 2053 5,615 18,264 i]C)23,879 2054 5,636 18,255 0 ty 23,891 2055 5,766 18,366 0 0 24,131 2056 §,889 18,456 0 t')24,325 2057 7823 17,454 0 0 25,278 2058 8,118 17,784 0 0 25,903 2059 8,480 17,939 [*)0 26,419 2060 9.436 16 882 Q 0 26,318 anisinnna Page 2 Plan 1A P50 Summary Scenario 1 Plan 1A -P50 Natural Gas Forecast Cash Flow per Generating Unit Addition Generating Unit CapitalAnchorageAnchorage1x1NikiskiGVEA1x1AnchorageGVEAChakachamna:Ch Mount Spurr GVEA Mount Anchorage Anchorage Cost CashYearMswGVEAMSW6FAGlacierForkWind6FALM6000LMS100kachTLMS100_GVEA 1x16FA Spurr LM6000 LM6000 Flow ($000) 2011 244,356 44,429 210,604 7,107 Q 0 t']0 [)0 0 0 0 0 506,4962012132,925 123,848 256,7732013119,477 119,477 2014 122,464 122,46420152,435 2,435 2016 22,466 33,699 56,165 2017 74,230 26,866 101,095 2016 174,256 43,273 217,5292019158,007 14,604 1,561 79,301 253,473202066,564 142,328 238,340 447,232 2021 21,500 481,537 503,037 2022 652,793 652,7932023712,138 712,138 2024 141,426 141,426 2025 2026 2027 88,657 88,6572028208,125 208,1252029188,718 188,7182030 2031 2032 2033 2034 2,280 2,2602035206,133 206,133203631,138 31,1382037 2038 2039 127,792 127,7922040290,994 299,9942041272,020 272,0202042 2043 131,612 131,6122044308,963 308,9632045280,152 280,1522046 2047 2048 2049 2050 2051 2052 2053 2054 2055 35,526 35,5262056161,918 161,9182057 2058 38,257 38,2572059174,368 174,3682060 Total 6 648,169 Black &Vez* >"--"dentia" Plan 1A P50 Summary Scenario 1 Plan 1A -P50 Natural Gas Forecast Cash Flow per Transmission Project Soldotna - Eklutna -'Quartz CRs University University Soldotna -Year _EklutnaSub Lucas Sub -STEVENS CANTWELL ___Lucas Trans Soldotna Sub Sub Sub STERLING DAVES CR HOPE PORTAGE GIRDWOOD INDIAN Trans Quartz Trans 20141 2012 2013 1,380 1,380 276 276 878 2014 13,294 13,294 2,659 2,659 6,541 1,414 1,414 849 283 283 283 283 283 283 9,122 2015 13,916 13,916 2,783 2,783 6,847 13,626 13,626 8,176 2,725 2,725 |2,725 2,725 2,725 2,725 87,890 4,871 2016 14,264 14,264 8,559 2,853 2,853 |2,853 2,853 2,853 2,853 92,004 46,929 2017 49,126 2018 2019 2020 2021 2022 2023 2024 2025 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 cee ew me ee .49R9NnG Page4 Plan 1A P50 Summary Scenario 1 Plan 1A -P50 Natural Gas Forecast Cash Flow per Transmission Project Year Quartz University Trans Lorraine Sub Douglas Sub _Healy Sub Lake Lorraine-Beluga-Pt.Douglas -Douglas -1% - Douglas Mackenzie Lawing -Teeland Healy Trans Teeland Bradley LakeTransTransSewardSub1TransTrans Goldhill Sub _Witson Sub NENANA ESTER 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 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 6,523 62,852 65,794 3,046 29,348 30,722 1,561 15,041 15,745 1,873 18,049 18,894 2,885 4,215 1,748 27,796 40,611 18,846 1,600 16,129 2,400 20,097 42,512 17,634 15,417 155,404 23,126 4,054 16,139 162,878 24,208 39,064 40,892 1,640 15,802 16,542 1,681 16,198 16,956 336 3,240 3,391 336 3,240 3,391 ¢&Veateh Cansidentiz' Plan 1A P50 Summary Cash Flow per Transmission Project Total Transmission Douglas -Healy -Project CapitalHealyTrans-Goldhill Healy -Pt.Mackenzie -Lucas -Teeland Lucas Teeland Cost Cash Flow Year 2 Trans Wilson Trans |COTTLE HERNING SHAW LAZELLE ONEIL Plant 2 Trans Trans 1 Trans 2 ($000) 2011 4,022 2012 4,024 2013 8,016 2014 56,971 2015 195,341 2016 260,021 2017 122,000 2018 45,667 2019 173,232 2020 327,563 2021 16,946 9,784 9,784 300,800 2022 163,271 94,269 94,269 345 345 345,345 345 2,233 1,799 441,720 2023 170,913 98,682 98,682 3,320 3,320 3,320 3,320 3,320 21,517 17,333 451,514 2024 3,476 3,476 3,476 3,476 3,476 22,524 18,144 1,890 $3,986 2025 18,210 22,260202619,063 23,11520274,054 2028 4,05620294,058 2030 4,06020314,06220324,064 2033 4,06620344,06820354,070 2036 4,07220374,07420384,07620394,07820404,08020414,08220424,08420434,08620444,08820454,09020464,00220474,00420484,09820494,09820504.10020514,10220524,10420534,10620544,10820554,11020564,11220574,11420584,11620594,11820604.120 Total 2,639,208 Black &Veatch Confidential Plan 1A P50 Summary Scenario 1 Plan 1A -P50 Natural Gas Forecast Summary of Cash Flows and Production Costs Total Total ing T weet Unit Capital Project Capital Fixed Energy Cost Cash Cost Cash Flow Total Capital Cost Cash DSM Costs Fuel Cost O&M Variable CO2Costs Requirements Year Flow ($000)($000)Flow ($000)($000)($000)($000)O&M($000)($000)__-After DSM (GWh)| 20141 506,496 4,022 $10,518 651 259,482 39,359 30,852 §,372 2012 256,773 4,024 260,797 1,491 271,811 38,557 32,902 54,963 5,412 2013 119,477 8,016 127,493 3,063 258,329 42,181 34,820 56,995 5,424 2014 122,464 56,971 179,434 5,878 282,641 42,198 32,212 63,421 5,421 2015 2,435 195,341 197,776 10,455 361,674 35,058 35,819 65,306 5,167 2016 56,165 260,021 316,187 12,789 373,704 37,978 35,083 68,216 5,147 2017 101,095 122,000 223,085 11,891 352,673 38,010 36,043 73,346 5,129 2018 217,529 45,667 263,198 12,244 224,380 36,088 34,170 81,543 5,105 2019 253,473 173,232 426,705 12,857 244,337 34,087 35,596 86,958 §,085 2020 447,232 327,563 774,784 13,124 235,418 37,177 29,384 90,354 5,068 2021 503,037 300,800 803,837 13,346 247,202 39,360 30,390 97,474 §,052 2022 652,793 441,720 4,094,513 14,024 267,038 41,731 29,426 110,165 §,084 2023 712,138 451,514 1,163,652 4,166 284,104 35,897 30,380 114,805 5,111 2024 141,426 63,986 205,412 3,313 297,843 36,104 33,631 428,785 5,140 2025 22,260 22,260 4,222 201,105 $7,389 29,739 90,619 §,174 2026 23,115 23,115 5,342 227,334 57,067 16,925 107,681 5,207 2027 88,657 4,054 92,711 8,551 238,262 58,593 17,362 118,039 5,244 2028 208,125 4,056 212,181 13,323 247,810 §9,207 18,257 130,862 §,275 2029 188,718 4,058 192,776 16,151 261,837 59,916 18,745 146,548 §,309 2030 4,060 4,060 17,064 226,648 84,248 17,865 135,367 §,344 2031 4,062 4,062 14,951 224,691 84,983 15,652 140,642 §,378 2032 4,064 4,064 18,081 234,947 86,456 16,121 182,129 5,413 2033 4,066 4,066 15,919 249,713 87,902 16,762 186,550 §,447 2034 2,260 4,068 6,328 16,747 260,041 89,276 17,408 180,198 5,482 2035 206,133 4,070 210,203 18,111 279,793 90,794 18,296 200,974 5,517 2036 31,138 4,072 35,210 §,493 292,296 92,408 18,814 218,387 5,553 2037 4,074 4,074 7,019 335,171 97,112 19,787 257,520 5,588 2038 4,076 4,076 6,453 352,597 98,638 20,542 281,586 5,623 2039 127,792 4,078 131,870 8,848 368,539 |100,317 21,287 306,519 5,659 2040 299,994 4,080 304,074 12,284 385,523 |101,920 22,049 332,326 5,695 2041 272,020 4,082 276,102 48,825 403,233 |103,660 22,861 361,453 5,731 2042 4,084 4,084 21,552 394,321 95,445 21,546 371,427 5,767 2043 431,612 4,086 135,698 22,199 412,100 97,223 22,392 404,276 5,803 2044 308,963 4,088 313,051 23,458 428,330 |152,761 23,116 439,168 5,839 2045 280,152 4,090 284,242 22,134 449,075 |101,037 23,977 476,267 5,876 2046 4,092 4,092 22,961 421,293 |140,010 26,073 466,403 5,912 2047 4,094 4,094 24,452 424,059 |142,963 26,511 490,408 5,949 2048 4,096 4,096 25,398 444,961 |146,057 27,392 537,229 5,986 2049 4,098 4,098 6,909 461,902 |149,291 28,395 584,308 6,023 2050 4,100 4,100 8,724 477,627 |152,489 29,313 630,743 6,060 2051 4,102 4,102 WATE 503,605 |155,601 30,361 656,308 6,098 2052 4,104 4,104 9,139 520,728 |158,955 31,315 676,369 6,135 2053 4,106 4,106 14,889 $46,462 |162,470 32,477 705,374 6,173 2054 4,108 4,108 22,880 562,487 |165,955 33,535 723,997 6,211 2055 35,526 4,110 39,636 27,949 579,273 |169,720 34,785 749,388 6,249 2056 161,918 4,112 166,030 30,133 605,200 |173,255 35,877 774,023 6,287 2057 4,114 4,114 33,288 647,750 |180,086 37,668 822,050 6,326 2058 38,257 4,116 42,373 33,226 682,788 |182,230 38,924 862,251 6,364 2059 174,368 4,118 178,486 31,309 716,581 |186,278 40,624 900,505 6,403 2060 4,120 _ 4,120 32,092 732,571 |193,496 41,921 919,733 6,442 Total 6,648,169 2,639,208 ||Total of Cash Flows &DSM 10,034,684 Plan 1A P50 Summary Scenario 1 Plan 1A -P50 Natural Gas Forecast:Cumulative Capacity and Energy by Resource Type Natural Gas Coal Nuclear Fuel Oil Purchase Power Hydro Geothermal 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)(MWh)(MW)(MWh)(MW)(MWh)(MW)(MWh)(MW)(MWh)(MW)(MWh)(MW)(MWh)(MW)(MWh)(MW)(MWh)(MW)(MWh) 2011 821 3.606 27 224 251 611 25 197 176 591 22 185 2012 758 3,621 27 212 251 61t 25 204 176 §93 26 219 2013 893 3.759 27 207 251 494 25 201 176 §91 26 219 2014 893 3.765 27 216 251 474 25 205 176 591 26 218 2018 703 2,980 27 211 251 934 25 205 251 649 26 220 2016 621 2,694 27 211 251 922 25 204 251 921 26 219 2017 703 2,755 27 213 251 800 25 200 251 919 26 218 15 49 2018 638 2,474 27 182 189 1,067 25 203 251 919 26 219 15 49 2019 638 2,677 27 177 128 826 25 210 251 919 26 219 18 49 2020 845 3,547 27 175 25 173 251 $21 26 219 18 49 2021 816 3,552 27 167 25 176 251 919 26 219 18 49 2022 831 3,584 27 167 25 162 251 919 26 219 15 49 2023 831 3,788 25 162 251 e186 26 219 15 49 2024 831 3,777 25 189 251 921 26 219 15 49 2025 831 2,278 25 184 581 2,537 26 185 15 49 2026 831 2,498 §81 2,524 26 197 18 49 2027 789 2,529 581 2,524 26 202 15 49 2028 789 2,554 §81 2,526 26 206 15 49 2029 789 2,598 581 2,518 26 204 15 49 2030 708 2,289 581 2,517 50 367 26 191 15 49 2031 §55 2,306 581 2,517 50 373 26 199 15 49 2032 555 2,330 581 2,524 50 375 26 201 15 49 2033 555 2,374 581 2,517 50 369 26 201 15 49 2034 555,2,395 581 2,517 50 384 26 202 15 49 2035 555 2,443 581 2,517 50 375 26 199 15 49 2036 555 2,458 581 2,523 50 379 26 201 15 49 2037 653 2,551 681 2,517 60 358 26 181 16 49 2038 621 2,581 581 2,517 50 362 26 180 15 49 2039 621 2,621 581 2,517 50 359 26 180 15 4g 2040 621 2,643 581 2,523 50 368 26 182 15 5020416212,685 581 2,517 50 369 26 183 15 4920427822,687 581 2,517 50 381 26 201 15 49 2043 719 2,725 581 2,517 50 382 26 204 16 49 2044 719 2,748 581 2,523 50 383 26 205 15 49 2045 719 2,794 581 2,517 50 382 26 204 15 49 2046 719 2,488 581 2,517 100 147 26 190 15 4920477192,524 581 2,517 100 752 26 191 15 49 2048 719 2,547 581 2,523 100 755 26 196 15 49 2049 719 2,592 581 2,517 100 752 26 195 15 49 2050 719 2,617 581 2,517 100 758 26 199 18 49 2051 719 2,659 581 2,517 100 758 26 198 16 49 2052 719 2,684 581 2,523 100 761 26 199 15 4920537192,737 581 2,517 100 758 26 200 15 4920547192,759 581 2,517 100 762 26 203 16 4920557192,800 581 2,517 100 764 26 204 15 492056+719 2,821 581 2,523 100 767 26 206 18 4920577662:876 581 2,517 100 763 26 204 15 4920587662,959 562 2,476 100 763 26 203 15 4920597683,036 562 2,476 100 763 26 204 15 49 2060 814 3.049 562 2,482 100 765 26 205 15 49 APPENDIX G DETAILED RESULTS -SCENARIO 1B ALASKA RIRP STUDY APPENDIX G DETAILED RESULTS -SCENARIO 1B Black &Veatch G1 December 2009 DRAFT REPORT Plan 1B P50 Summary Scenario 1 Plan 1B -P50 Natural Gas Forecast Renewable Annual Capltal Cumulative Reserve Generation Fuel Costs Total O&M CO2 Costs |DSM Costs |Fixed Charges!Total Annual Present Value Year Additions Retirements T Margin (%)(%)($000)Costs ($000)($000)($000){$000)Costs ($000)($000) Beluga -1;Beluga -2;Intemational -1; 2011 Anchorage MSW.Intemational -2 52.25%14.44%259,482 $70,211 $0 $651 14,610 $344,953 $344,953 2012 GVEA MSW.International -3 44.38%14.97%271,611 $71,458 $54,963 $1,491 16,442 $415,965 733,705 2013 Anchorage 1x1 6FA 59.43%14.85%$258,329 $74,001 $56,995 $3,063 51,650 $444,037 1,121,545 Beluga -3;Beluga -6/8;Beluga -7/8; 2014 Bemice -2;Bernice -3 59.86%14.75%$282,641 $74,407 $63,421 $5,878 $51,650 $477,996 1,511,732 2015 Glacier Fork 49.52%16.40%$361,674 $70,874 $65,306 $10,455 $85,077 $593,386 1,964 424 Eklutna Sub;Lucas Sub;STEVENS;CANTWELL;: 2016 Eklutna -Lucas Trans 53.35%21.39%$373,704 $73,061 $68,216 $12,759 $93,450 $621,189 2,407,323 Soldotna Sub;Quartz CR Sub;University Sub; STERLING;DAVES CR;HOPE;PORTAGE; 2017 Nikiski Wind Beluga -5:NP4 GIROWOOD;INDIAN;Soldotna -University Trans]54.52%22.10%$352,573 $74,053 $73,346 $11,891 $127,807 $639,770 2,833,629 2018 Anchorage LM6000 NP2 Soldotna -Quartz Trans;Quartz -University Trans|__45.87%21.99%212.428 71,986 $78,415 $12,241 $159,714 $534,783.3,166,665 2019 39.47%24.84%232,896 72,622 84,665 $12,657 $159,714 $562,554 3,494,077 2020 GVEA 1x1 6FA Beluga -6:MLP 5;MLP 5/6;MLP 7/6 Lorraine Subd 51.36%21.76%230,881 69,528 $89,035 $13,124 $207,956 $610,524 3,826,162 Douglas Sub;Healy Sub;Lake Lorraine -Douglas Trans;Beluga -Pt.Mackenzie Trans;Lawing - 2021 Mount Spurr T Beluga -7 Seward 48.32%28.54%$221,193 $90,139 $88,394 $13,346 $283,893 $696,965 4,180,463 Teeland Sub;Douglas -Healy Trans 1;Douglas - 2022 GVEA LMS100 Healy -4 Teeland Trans 48.95%28.22%$241,809 $92,589 $100,725 $14,024 $344,082 $793,229 4,557,321 2023 Soldotna -Bradley Lake Trans 44.82%28.17%$262,581 $87,894 $105,770 $4,166 $356,034 $816,442 4,919,831 Goldhili Sub;Wilson Sub;NENANA,ESTER; Douglas -Healy Trans 2;Healy -Goldhill Trans; 2024 Healy -Wilson Trans 43.66%28.25%$271,161 $91,934 $114,418 $3,313 $437,589 $918,415 5,300,940 COTTLE;HERNING;SHAW,LAZELLE;ONEIL; Pt.Mackenzie -Plant 2 Trans;Lucas -Teeland 2025 |Chakachamna:Chakachamna GVEA Aurora Purchase -Tier |Trans 1 82.53%54.78%$184,513 $108,782 $83,526 $4,222 $704 574 $1,085,618 §,721,962 2026 Nikiski 73.14%54.87%$205,066 $97,887 $97,554 $5,342 $704,574 $1,110,420 6.124.429 2027 Lucas -Teeland Trans 2 72.00%§5.08%214,480 100,034 106,679 $8,551 $708,540 $1,138,283 6,510,005 2028 70.69%54.45%225.018 101,569 119,253 $13,323 $708,540 $1,167,704 6 879,670 2029 69.42%54.66%$232,384 103,932 130,456 _$16,151 $708,540 $1,191,464 7,232,181 2030 Kenai Wind T Lines OPP -6;MLP 7;MLP 8;Zen1;Zen2 48.45%55.98%$212,384 $105,144 $128,803 $17,064 $730,742 $1,194,134 7,562,369 2031 39.90%55.22%$216,800 $104,025 $136,253 $14,951 $730,742 1,202,771 7,873,188 2032 38.88%55.42%226.804 106,142 147,492 $15,081 $730,742 1,226,267 8,169,346 2033 37.85%54.99%240,008 408,251 161,016 $15,919 730,742 1,255,937 8,452,828 2034 36.85%54.70%250,953 110,323 175,181 $16,747 730,742 1,283,945 8,723,672 2035 35.86%54.86%260,327 $112,651 $188 522 $18,414 730,742 1,310,352 8,982,003 2036 34.88%54.35%271,314 $114,664 $204 837 $5,493 $730,742 1,327,049 9,226 511 2037 Anchorage LMS100 MLP 3 40.91%53.50%304,912 $120,539 $236,634 $7,019 $739,587 $1,408,692 9,469,082 2038 39.80%53.18%$326,863 $122,735 $263,247 $6,453 $739,587 $1,458,885 9,703,864 2039 38.91%52.95%$339,440 $125,230 $284,924 $8,848 $739,587 $1,498,030 9,929,167 2040 37.90%§2.81%$356,936 $127,756 $310,255 $12,284 $739,587 1,546,818 10,146,593 041 36.92%52.36%$372,843 $130,285 $337,009 $18,825 $724,977 1,583,938 10,354,670 042 GVEA 1x1 6FA NPCC 46.38%$2.17%$375,263 $120,882 $354,595 $21,552 $795,195 1,667,487 10,559,392 043 45.35%51.88%$391,720 $123,539 $385,023 $22,199 $751,990 1,674,470 10,751,523 2044 44.31%51.78%$406,444 $179,924 $417,692 $23,458 $751,990 $1,779,507 10,942,348 045,43.29%51.29%$429,086 $129,138 $455,665 $22,134 $718,563 $1,754,585 41,118,194 046 Mount Spurr 47.45%56.60%$396,733 $170,550 $439,965 $22,961 $792,209 $1,822,419 41,288 884 047 46.42%§6.35%$416,466 $174,511 $481,308 $24,452 $743,841 $1,840,578 11,450,000 048 45.39%56.17%433,925 $178,618 $522,907 $25,398.$719,932 $1,880,780 11,603 864 2049 44.39%§5.76%450,614 $182,994 $568,618 $6,909 $719,932 $1,929,068 11,751,355 2050 43.37%55.45%471,834 $187,328 $620,936 $8,724 $649,488 $1,938,311 411,889,857 2051 42.38%55.19%$492,318 $191,528 $640,957 $14,574 $573,551 1,909,528 42,017,376 2052 41.39%§5.13%$511,218 $195,999 $662,943 $9,139 $531,313 1,910,611 12,136,620 2053 40.42%54.63%$547,084 $200,780 $697,021 $14,889 $519,363 1,973,137 12,251,711 2054 39.44%54.32%$559,204 $205,498 $717,024 $22,880 $437,805 $1,942,407 12,357,596 2055 38.48%§4.01%$579,035 210,498 744,567,$27,949 $425,729 $1,987,778 12,458 867 2056 37.53%53.87%$607,385 215.314 772,438 $30,133 $425,729 $2,050,999 12,556,522 2057 Anchorage LM6000 Cooper Lake 41.14%53.44%$627,469 224,032 794 568 $33,288 $442,712 $2,122,068 12,650,951 2058 38.37%52.58%660,255 $227,485 833,106 33,226 $442,712 $2,196,784 12,742,309 2059 37.42%52.27%700,522 $233,350 878,496 31,309 $442.71 $2,286,389 12,831,174 2060 Anchorage LM6000 40.95%§2.19%710.699 $242,055 890,927 32,092 465,27:$2,341,044 412,916,210 Present Value of Costs 4,237,240 1,391,971 2,050,030 49,474 5,087,496 12,916,210 Black &Veatch Confidential Plan 1B P50 Summary Scenario 1 Plan 1B -P50 Natural Gas Forecast Annual Natural Gas Usage (mmBtu) Year Anchorage interior M Kenai Total Railbelt 2011 34,619 9 0 4,373 38,992 2012 33,318 i)0 §128 38,446 2013 33,572 Qo 0 3,787 37,358 2014 34,428 i)QO 3,376 37,804 2015 26,048 0 QO 3,543 29,590 2016 23,745 0 Qo 3,511 27,256 2017 24,434 iy 0 3,284 27,718 2018 23,393 8,163 0 2,730 34,286 2019 24,971 5,570 0 3,003 33,544 2020 19,203 10,571 O 2,708 32,478 2021 16,406 10,193 0 2,276 28,875 2022 16,3841 11,490 0 2,317 30,187 2023 17,244 13,014 0 2,378 32,636 2024 15,447 14,287 QO 2,197 31,831 2025 8.435 11,845 0 635 20,014 2026 9,063 12,318 [)745 22,126 2027 9,181 12,748 0 0 21,926 2028 9,678 12,654 0 0 22,332 2029 9,444 12,687 0 0 22,134 2030 $,092 14,325 V1)0 19,437 2031 7,332 12,031 i))19,363 2032 7,244 12,234 t)0 19,478 2033 7,351 12,442 t'))19,703 2034 7,398 12,684 0 te)20,078 2035 7,345 12,736 te]i)20,081 2036 7,705 12,544 0 i]20,248 2037 11,431 10,600 t')0 22,031 2038 11,508 11,338 LY)[)22,846 2039 11,446 11,542 Q 0 22,988 2040 11,669 11,658 t)0 23,327 2044 11,760 11,813 t')Q 23,572 2042 9,695 13,263 )0 22,048 2043 9,811 13,383 0 Qo 23,193 2044 9,800 13,582 0 0 23,361 2045 10,257 13,559 0 0 23,817 2046 8,939 42,400 Q 0 21,338 2047 9,056 12,661 0 9 21,716 2048 9,291 12,658 0 0 21,949 2049 9,222 12,992 (+)0 .22,213 2050 9,564 13,031 Ly 0 22,595 2051 9,526 43,240 0 0 22,786 2052 9,494 13,461 Q 0 22,054 2053 10,093 13,489 )0 23,582 2054 9,915 13,758 0 0 23,674 2055 10,243 13,755 9 0 23,998 2056 10,351 13,954 0 0 24,305 2057 11,389 13,014 0 0 24,404 2058 1t,717 13,262 0 0 24,878 2059 12,063 13,676 0 0 25,739 2060 12,393 13,032"0 0 25,425 Pian 1B P50 Summary Scenario 1 Plan 18 -P50 Natural Gas Forecast Cash Flow per Generating Unit Addition Chakacham GeneratingAnchorageAnchorage1x1NikisktAnchoragMountna:Chakach Kenai Wind Anchorage GVEA 1x1 Anchorage Anchorage Unit Cash FlowYearMSWGVEAMSW6FAGlacierForkWinde@LM6000GVEA1x16FASpurrTGVEALMS100amnaTLinesLM60006FAMountSpurrLM6000tmeo00($000) 2011 244,356 44,429 210,604 7,107 °8 0 0 0 0 0 0 0 t'}506,4962012132,925 123,848 256,7732013119,477 119,477 2014 122,464 122,46420152,435 2,435 2016 22,466 |13,562 33,699 69,727 2017 61,811 74,230 26,866 162,906 2018 174,256 70,990 43,273 288,5202019158,007 166,652 1,561 79,301 405,5202020151,111 142,328 238,340 531,780 2021 21,500 481,537 503,037 2022 652,793 652,7932023712,138 712,138 2024 141,426 141,426 2025 2026 2027 2028 19,663 19,6632029181,395 181,3952030 2031 2032 2033 2034 2035 21,680 21,680203698,814 08,8142037 2038 2039 127,782 127,7922040299,994 298,9942041272,020 272,0202042 2043 131,612 131,6122044308,963 308,9632045280,152 280,1522046 2047 2048 2049 2050 2051 2052 2053 2054 2055 35,528 35,5262056161,918 161,9182057 2058 38,257 38,2572059174,368 174,3682060 Total 6,627,647 Plan 18 P50 Summary Scenario 1 Plan 1B -P50 Natural Gas Forecast Cash Flow per Tr I 1 Project Year Eklutna Sub Lucas Sub STEVENS CANTWELL Ekiutna- Lucas Trans Sub Quartz CR Sub University Sub STERLING OAVES CR HOPE PORTAGE GIRDWOOD Soldotna - University Soldotna - INDIAN Trans Quartz Trans 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 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 1,380 13,294 13,916 1,380 13,294 13,916 276 2,659 2,783 276 2,659 2,783 679 6,541 6,847 1,414 13,626 14,264 1,444 13,626 14,264 849 8,176 8,559 283 2,728 2,853 283 2,725 2,853 283 2,725 2,853 283 2,725 2,853 283 2,725 2,853 283 2,725 2,853 9,122 87,890 92,004 4,871 46,929 49,126 Black &Veatch Confidential Plan 1B P50 Summary Scenario 1 Plan 1B -P50 Natural Gas Forecast Cash Flow per Transmission Project Year Quartz - University Trans Lorraine Sub Douglas Sub__Healy Sub Lake Lorraine - Douglas Trans Beluga -Pt. Mackenzie Trans Lawing - Seward Teeland Sub Douglas- Healy Trans 1 Douglas - Teeland Trans Bradley Lake Trans Goldhill Sub Wilson Sub NENANA ESTER 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 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 6,523 62,852 65,704 3,046 29,348 30,722 1,561 15,041 15,745 1,873 18,049 18,894 2,885 27,796 29,097 4,215 40,611 42,512 1,748 16,846 17,634 1,600 15,417 16,139 16,129 155,404 162,678 2,400 23,126 24,208 4,054 39,084 40,892 1,640 15,802 16,542 1,681 16,198 16,956 336 3,240 3,391 336 3,240 3,391 Plan 18 P50 Summary Cash Flow per Trar 1 Project TotalDouglas-Healy -TransmissionHealyTransGoldhillHealy-Pt,Mackenzie -Lucas -Teeland Lucas-Teeland Project CashYear2TransWilsonTrans_COTTLE HERNING SHAW LAZELLE ONEIL Plant 2 Trans Trans 1 Trans 2 Flow ($000) 2011 4,02220124,02420138,016 2014 §6,9712015195,341 2016 260,021 2017 122,000 2018 45,6672019173,2322020327,563 2021 16,946 9,784 9,784 300,800 2022 163,271 94,269 94,269 345 345 345 345 345 2,233 1,799 441,7202023170,913 98,682 98,682 3,320 3,320 3,320 3,320 3,320 21,517 17,333 451,514 2024 3,476 3,476 3,478 3,476 3,476 22,524 18,144 1,890 63,986 2025 18,210 22,260202619,063 23,11520274,05420284,05620294,05820304,06020314,06220324,06420334,06620344,06820354,07020364,07220374,07420384,07620394,07820404,08020414,08220424,08420434,08620444,08820454,09020464,09220474,09420484,09620494,09820504,10020514,10220524,10420534,10620544,10820554,11020564,11220874,11420584,11620594,11820604,120Totat2,639,208 Black &Veatch Canficential Dina ©Unntals Rantidantind Plan 1b rou summary Scenario 1 Plan 16 -P50 Natural Gas Forecast Summary of Cash Flows and Production Costs Totat Total ting T it Fixed Energy Unit Cash Flow Project Cash DSM Costs Fuel Cost O&M Variable CO2Costs Requirements Year ($000)Flow ($000)Total Cash Flow ($000)($000)($000){$000)O&M ($000)_($000)__After DSM (GWh) 2011 506,496 4,022 510,518 651 259,482 39,359 30,852 5,372 2012 256,773 4,024 260,797 1,491 271,611 38,557 32,902 54,963 5,412 2013 119,477 8,016 127,493 3,063 258,329 42,181 31,820 56,995 5,424 2014 122,464 56,971 179,434 5,878 282,641 42,195 32,212 63,421 §,421 2015 2,435 195,341 197,776 40,455 361,874 35,055 35,819 65,306 5,167 2016 69,727 260,021 329,748 12,759 373,704 37,978 35,083 68,216 5,147 2017 162,906 122,000 284,906 11,891 352,673 38,010 36,043 73,346 §,129 2018 288,520 45,667 334,186 12,241 212,428 39,140 32,846 78,415 5,105 2019 405,520 173,232 578,752 12,857 232,896 38,040 34,561 84,665 §,085 2020 531,780 327,563 859,342 13,124 230,881 40,230 29,298 89,035 5,068 2021 503,037 300,800 803,837 13,346 221,193 59,307 30,833 88,304 §,052 2022 652,793 441,720 1,094,513 14,024 241,809 62,177 30,413 100,725 5,0812023712,138 451,514 1,183,652 4,166 262,581 56,853 31,041 105,770 5,111 2024 141,426 63,986 205,442 3,313 271,161 57,585 34,349 114,418 5,140 2025 22,260 22,260 4,222 184,513 79,406 29,376 83,526 5.174 2026 23,116 23,115 §,342 205,086 80,535 17,351 97,551 5,207 2027 4,054 4,054 8,551 214,480 81,725 18,306 106,679 5,241202819,663 4,056 23,719 13,323 225,018 82,917 18,652 119,253 5,2752029181,395 .4,058 185,453 16,151 232,384 84,218 19,713 130,456 5,309 2030 4,060 4,060 17,084 212,381 84,248 20,896 128,803 5,344 2031 4,062 4,062 14,951 216,800 84,983 19,042 136,253 5,37820324,064 4,064 15,081 226,804 86,456 19,686 147,492 §,413 2033 4,066 4,066 15,919 240,008 87,902 20,349 161,016 5,447 2034 4,088 4,068 16,747 250,953 89,276 21,047 175,181 5,482 2035 21,680 4,070 25,750 18,111 260,327 90,794 21,856 188,522 5,517 2036 98,814 4,072 102,886 §,493 271,314 92,408 22,256 204,837 5,55320374,074 4,074 7,019 304,912 97,116 23,423 236,634 §,588 2038 4,076 4,076 6,453 326,863 98,642 24,092 263,247 5,623 2039 127,792 4,078 131,870 8,848 330,440}100,321 24,909 284,924 5,6592040299,994 4,080 304,074 12,284 356,936 |101,925 25,831 310,255 §,695 2041 272,020 4,082 *276,102 16,825 372,843 |103,664 26,620 337,009 §,73120424,084 4,084 21,552 375,263 95,450 25,432 354,595 5,7672043131,612 4,086 135,698 22,198 391,720 97,228 26,311 385,023 5,8032044308,963 4,088 313,051 23,458 406,444]152,766 27,158 417,692 5,8392045280,152 4,090 284,242 22,134 429,086 |101,042 28,096 455,665 5,87620464,092 4,082 22,961 396,733 |140,014 30,536 439,965 §,91220474,094 4,094 24,452 416,466 |142,967 31,544 481,308 5,94920484,096 4,096 25,398 433,925 |146,061 32,557 522,907 5,98620494,098 4,098 6,909 450,614 |149,296 33,699 568,618 6,023 2050 4,100 4,100 8,724 471,834 |152,494 34,834 620,936 6,06020514,102 4,102 11,174 492.318 |155,605 35,923 640,957 6,09820524,104 4,104 9,139 511,218 |158,960 37,039 662,943 6,13520534,106 4,106 14,889 $41,084 |162,475 38,305 697,021 6,17320544,108 4,108 22,880 559,201 |165,960 39,536 717,024 6,211205535,526 4,110 39,636 27,949 579,035 |169,725 40,774 744,567 6,2492056161,918 4,112 168,030 30,133 607,385 |173,260 42,054 772,438 6,28720574,114 4,114 33,288 627,469 |180,091 43,941 794,568 6,326205838,257 4,116 42,373 33,226 860,255 |182,235 45,250 833,106 6,3642059174,368 4,118 178,486 31,308 700,522 |186,283 47,067 878,496 6,40320604.120 _4120 32,092 710,699 |193,500 48 554 890,927 6442 Total 6,627,647 2,639,208 ||Total of Cash Flows &DSM 10,014,163 Plan 18 P50 Summary Scenario 1 Pian 1B -PSO Natural Gas Forecast:Cumulative Capacity and Energy by Resource Type Natural Gas Coal Nuclear Fuel Oil Purchase Power Hydro mal 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)(MWh)(MW)(MWh)(MW)(MWh)(MW)____(MWh)(MW)(MWh)(MW)(MWh)(MW)(MWh)(MW)(MWh)(MW)(MWh)(MW)(MWh) 2011 821 3.606 27 224 251 611 25 197 176 591 22 18520127583,621 27 212 2541 611 25 204 176 503 26 21920138933,759 27 207 251 494 25 201 176 581 26 219 2014 893 3,765 27 216 251 474 25 205 176 581 26 24820157032,980 2?211 251 934 25 205 251 640 26 220 2016 621 2,694 27 211 251 922 25 204 251 921 26 219 2017 703 2,755 27 212 251 802 25 199 254 919 26 218 15 49 2018 686 2.654 27 178 189 911 25 189 251 919 26 219 5 4920196862,840 27 175 128 699 25 196 251 919 26 219 15 4320209753,558 27 175 25 171 251 921 26 219 15 49 2021 816 3,186 27 167 28 172 251 019 50 383 26 219 15 49 2022 831 3,230 27 167 25 160 251 918 50 376 26 218 15 4920238313,425 25 156 251 019 50 382 26 219 45 49 2024 831 3,402 25 182 251 921 50 392 26 220 18 49 2025 831 1,985 25 168 581 2.517 50 344 26 177 15 4920268312,163 581 2,517 50 355 26 190 15 4920277702,165 §31 2.517 50 382 26 194 15 4920287702,216 581 2,524 50 356 26 195 15 4920297702,220 531 2,517 50 391 26 198 15 4920307702.144 581 2.517 50 379 26 207 45 14820315552,214 581 2,517 50 357 26 203 45 1482032§55 2,218 581 2,524 50 378 26 206 45 1482033§55 2,259 581 2,517 $0 378 26 207 45 14820345552,293 581 2,517 50 379 26 208 45 14820355552,300 581 2,517 50 406 26 210 45 1482036§55 2,348 881 2,524 50 383 26 215 45 14820376532.416 581 2,517 50 376 26 196 45 14820386212,450 581 2,817 50 376 26 195 45 14820396212,482 581 2,517 50 379 26 198 45 14820406212,509 581 2,524 50 379 26 199 45 15120416212,554 581 2,517 50 379 26 200 45 14820427822,586 581 2,517 s0 380 26 205 45 14820437192,622 581 2,517 $0 380 26 205 45 14820447192,648 581 2,524 50 382 26 209 45 14820457192,695 581 2,517 50 381 26 205 45 14820467192,384 581 2.517 100 753 26 191 45 14820477192,417 581 2,517 100 755 26 193 45 14820487192,444 581 2,524 100 787 26 193 45 14820497192,487 §81 2,517 100 758 26 193 45 14820507192,524 581 2,517 100 787 26 196 45 14820817192,558 581 2,517 100 760 26 196 45 14820527192,579 581 2,524 100 766 26 200 45 14820537192,629 581 2,517 100 761 26 200 45 14820547192,668 581 2,517 100 761 26 200 45 14820557192,705 581 2,517 100 760 26 200 45 14820567192,733 581 2,524 100 763 26 202 45 14820577662.779 58 2,517 100 762 26 201 45 14820587662,856 §62 2,476 100 764 26 203 45 14820597662,936 562 2,476 100 762 26 203 45 14820608142,942 562 2,482 100 766 26 207 45 148 Black &Veateh Confidentiat APPENDIX H DETAILED RESULTS -SCENARIO 2A ALASKA RIRP STUDY APPENDIX H DETAILED RESULTS -SCENARIO 2A Black &Veatch H-1 December 2009 DRAFT REPORT Plan 2A P50 Summary Black &Veatch Confidential Scenario 1 Plan 2A -P50 Natural Gas Forecast Renewable [Annual Capital Cumulative Reserve |Generation Fuel Costs Total O&M CO2 Costs |DSM Costs |Fixed Charges]Total Annual|Present ValueYearAdditionsRetirementsTMargin(%)(%)($000)Costs ($000)($000)($000)($000)Costs ($000)($000) Beluga -1;Beluga -2;International -7; 201 Anchorage MSW intermational -2 §2.28%14.44%260,358 70,369 $o $est $14,610 $345,988 $345,988 01 CVER SW Intemational-3 TER T3I%iL)1 498 355 007 Tat 316 4aT S4T6.708 735,455 01 Anchorage Ixt OFA LEELA 14.85%PEERY 75,065 LAP i i S405 5 T2450Beluga-5,Beluga -6/8,Beluga -776, 2014 Bemice -2;Bemice -3 59.86%14.75%$283,259 $74,513 $63,458 $5,878 $81,650 $478,758 4,515,314 2015 lhisk Wind [18.23%3571 727 377500|;;';953, 2016 Ektutna -Lucas Trans 44.38%16.17%$421,956 $72,673 $72,757 $12,759 $63,773 $643,918 2,412,922SoldotnaSub;Quartz CR Sub;University Sub;STERLING;DAVES CR;HOPE;PORTAGE; GIROWOOD;INDIAN;Soldotna -University 2017 Anchorage LM6000 Beluga -5;NP1 Trans 51.21%16.00%$357,766 $74,665 $79,202 $11,891 $101,993 $625,518 2,829,730oldoma-Guarz Vans,Quartz -University 2018 Kenai Hydro NP2 Trans 37.38%18.30%236,089 $71,320 $85,281 12,241 $133,764 $538,696 3,165,203 2019 3O.5IK TS.1E%259,f 5on 155 To.837 STITT 3570572 yaaret«|[2020|CVEATxTOFA|Beluga-6,MIPS,MIP 5S,MLP 776 'Torraine Sub TER TE.TT%254 85 BEE 518 387 258 13,124 $182,007 LER "S.85T 077DouglasSub;Healy Sub;Lake Lorraine -Douglas]Trans;Beluge -Pt.Mackenzie Trans;Lawing2021GVEAWindTLinesBeluga-7 Seward 33.45%18.98%$279,867 $71,898 $107,723 $13,346 $243,232 $715,865 4,195,687 z Teeland Sub;Douglas -Healy Trans T;Douglas - 2022 Anchorage 1x1 6FA Healy -1 Teeland Trans 41.38%18.86%$268,054 $73,804 $110,585 $14,028 $329,540 $795,977 4,573,849 2023 Soldotna-Gradiey Lake Trans 37.20%TECK 3268,157 38 id $4,166 S347 185 AER 7537478GoldhdlSub;Wilson Sub;Douglas-Healy Trans 2;Healy-Goldhit Trane: 2024 Healy-Wilson Trans 36.19%18.67%$312,504 $71,423 $130,868 $3,313 $423,047 $941,154 5.328,023 2halowh ar ZOTILE: Low Watana (Non-Pt.Mackenzie-Plent2 Trans:Lucas -Teeland025Expandable)GVEA Aurora Purchase -Tier!Trans 1 54.38%§3.57%299,758 144,483 432,528 $4,222 1,458,323 2,009,311 107,269 026 ikiskt TETK_|%338,2350_f 155,016 $5,342 1,458,323 2,064,571 055 564[2027 Tucas -Teeland trans 2 O3%BTA0%LAE 05,657 171,028 38557 7,482,289 2,108,199 569,587[2028 T32%BE20%378,415 T1862 769,555 T3325 1,462,289 2,149,524 250,372 029 TEG3%00%6,220 174,036 209,135 T6181|$1,462,289 2,187,831 6.897 67. 203 HEA 1x1 6FA;HCCP.DPP -6:MLP 7,MLP 8;Zen1;Zen2 48.67%52.69%340,326 134,134 219,911 17,064 1,530,136 2,241,572 9,517.48 203 CERILS PEI 355,555 To3ol?234,938 74,087 7 530,156 2,250,301 70,099,787 ' 203:a2 58%32.70%355,187 138.025 254,000 75,087 1,530,131 2,200,407 10,652,045 203 TT 90%BESET SLARZEI TU er PRs)RIED 7330.15 2,353,920 T7847 203 Te LYRE 388,178 14 5 258,505,16,147 1,530,106 RIPE T7680)203:BOREL LFArL 406,177 14,555 325,551 TETTT 1,526,587 2,418,580 12,157,022 03 35.94%Liviu 428,010 147,309 349,408 |$5,455 1,526,087 |$2,450,098 12,608,598__|03 GVER xT OFA MURS BO.12%RIF Pis 459,155,327 370,500 37,015 1,626,955 |$2,623,966 13,060,433 038 Bo 38%RLV 3470 538 137 86a 401 232 T6485 7,626,555 2,663,040 Te#58507 |LER :RK TAT ST 35,404|$8848 J ,626,555_FRALPALS4'Anchorage o&xt OFA 35.0T%BLAIS $a78,145 188,134 785,108 12,284 7,735,055 3,506,926 in 40|523 4 :$907,504 TST.3T $837,506.78.825 7,691,016 3,646,864 14.884,601 r 'Mount SpurrT WCE TT 4Th aTT%3405 575 218 200.S885 507 31855 1,755,687 |$3,010,065 75,348 197 4 3O5E%WOOK [|_$934 11E 200,216 954,22,19 7,720,480 3,852,346 15,790,220 2044 20%030%966,332,202,7,051,028 25,458.1,720,480 4,073,958 16,227,087204'30.05%1.18%TT 0S 555 230,007 106,400 22,134 1,720,480 4,084,785 16,636,460 046 'Mount Spurr 32,14%62%$593,505 274,059 1,147,871 22,061 1,794,126,4.232,416 T7,032,882 04 31.69%66%1,026,508 280,221 7,256,143 24,482 1,763,708 4,331,630 17,412,053 048 RiPsLS T535%7,064,200 266,875 7,537,040 25,398 7,751.93 4,446,107 17,775,784|2049 30.78%541%T091,6tT 293,225 7 430,931 6,909 1,731,935 4,560,561 78.126 475 050 30.32%330%T 125 310 300,067 T 548,719 $8,720 7,683.69 4,670.51 18.458 206805HEATMEOO02.24%43.20%1,179,794 310,493 1598077 [Stara 1,670,063 4,769.62 18,776,724 05 7.78%T325%SEIESEES ATE 7,643,088 $5,135 7,563,85 TRARY 75,074,550205:Tek BIT 7,251,260 34 od 1,679,809 T4889 1,577.90 4842,S78 19,356,999205)30.86%43.00%T2oT.eor 332,007 1,726,854 20,88 7,490,347 4,864,066 19,622,152205!30.41%CALL 7325.06)330,736 1,775,065 27 049 1.478.274 4,946,106 10,874,138 2056 THEA LMG008 32.20%42.81%80 337,137 1,856.104 30,133 7,498,709 |$5,103,181 0,117,119 2057 Cooper Lake 31.52%a265%1 428 428 355,909 1,882,468 35,288 1,494,743 |$5,197,631|20,040415205830.43%T38%1400487 365,095 7,939,044 33,026.7,450,743 _[$5,309,805 20,569,236 2059 GVEATMCOOS 32.24%RIK (ASEAR?}376,081 RAE 31,509 1,516,753 _|$5,397,998 20,779,039 2060 31.78%T2ATK 1370585 385,434 2,026,812 30,090 |$1,448,906 |$5,465,829 Present Value of Costs 5,943,887 1,612,385 3,698,219 49,478 9,573,616 Plan 2A P50 Summary Scenario 1 Plan 2A -P§0 Natural Gas Forecast Annual Natural Gas Usage (mmBtu) Year h (interior __Matanuska__Kenai_Yotal Railbelt 2011 34,642 0 0 4,355 38,997 2012 33,307 Qo 0 5,154 38,461 2013 33,591 Q O 3,844 37,435 2014 34,526 tC)0 3,283 37,809 2015 26,101 Q 0 3,503 29,604 2016 25,006 0 0 3,607 28,613 2017 28,408 o 0 3,267 34,675 2018 25,571 8,739 Oo 3,161 37,470 2019 27,313 6,147 0 3,327 36,787 2020 21,890 11,067 Oo 2,982 35,939 2021 23,522 9,237 0 3,197 35,956 2022 23,726 7,621 0 2212 33,560 2023 25,897 7,531 0 2,463 35,891 2024 27,011 6,837 0 2,638 36,486 2025 23,009 8,312 0 2,057 33,378 2026 24,508 8,943 0 1,506 34,957 2027 25,626 9,387 0 6 35,013 2028 25,756 9,449 0 0 35,205 2029 26,089 9,332 i)Go 35,421 2030 17,655 8,368 Oo 3,717 29,740 2031 18,262 7,249 o 3,633 29,144 2032 18,158 7,297 0 3,821 29,275 2033 18,222 7,412 Oo 3,947 29,580 2034 18,205 7,472 0 4,134 29,811 2035 18,455 7,517 0 4,058 30,030 2036 18,521 7A29 0 4542 30,192 2037 17,100 11,094 O 4,158 32,353 2038 16,295 10,970 Oo 4,802 32,067 2039 18,250 11,549 0 4,957 32,756 2040 34,345 16,904 0 4,959 56,208204133,860 16,745 0 5,054 55,659 2042 32,880 16,172 0 4,595 53,647 2043 32,990 16,268 0 4678 53,936 2044 33,086 16,281 0 4,805 54,173 2045 33,199 16,293 0 4,784 54,277 2046 31,751 16,055 0 4225 $2,032 2047 31,729 16,196 0 4,197 $2,123 2048 31,755 16,230 0 4433 52,418 2049 31,534 16,449 0 4,399 62,363 2050 31,689 16,510 O 4,386 $2,585 2051 26,799 16,139 Oo 8,131 $3,070 2052 28,958 16,168 0 8,088 $3,214 2053 28,755 16,334 0 7,942 $3,032 2054 28,690 16,490 0 8,004 $3,183 2055 28,725 16,628 0 7,971 53,324 2056 28,238 16,432 0 9,268 53,935 2057 28,277 16,565 0 9,107 $3,949 2058 28,529 16,641 Oo 9,081 $4,251 2059 27,218 18,803 0 8,380 54,398 2060 27,294 18,975 os 581 54.847 Plan 2A PSO Summary Scenario 1 Plan 2A -P50 Natural Gas Forecast Cash Flow per Generating Unit Addition Chakacham Low Watana GeneratingAnchorageAnchoragetx1AnchoragKenaiGVEAWindAnchorage1x1na:Chakach {Non-GVEA 2x1 Anchorage Mount Mount HEA HEA GVEA Unit CashYearMSWGVEAMSWGFANikisk!Wind e LM6000_Hydro GVEA 1x16FA_T Lines 6FA amna Expandable)HEA 1x16FA HCCP SFA 2x1 6FA SpurrT Spurr __M6000 LM6000 LM6000__Flow ($000) 2011 244,356 44,429 210,604 L)184 6 ()0 48,624 O]99,809 0 0 0 °Q 6 0 648,0062012132,925 188 32,371 165,48520132,318 193 30,231 32,742 2014 21,384 198 41,025 62,606201513,201 13,800 43,102 70,133 2016 60,303 43,313 33,699 503,963 611,279 2017 13,846 74,230 26,866 529,476 644,218 2018 174,256 43,273 711,878 $29,4072019158,007 26,242 77,987 79,301 840,242 1,181,7792020242,080 183,078 238,340 882,779 1,846,277 2021 166,006 481,537 721,781 1,369,324 2022 $52,793 788,321 1,411,1142023712,138 796,711 1,508,849 2024 149,426 39,033 180,459 2025 2026 2027 95,020 95,0202028223,063 223,0632029202,262 202,2622030 2031 2032 2033 2034 265,427 265,4272035529,187 $29,1572036175,050 175,0502037285,836 285,8362038$69,844 569,8442039188,510]119,234 307,7442040279,906 278,9062041253,804 253,8042042 2043 131,612 131,6122044308,963 308,9632045280,152 280,1522046 2047 2048 2049 30,634 30,6342050139,622 139,6222051 2052 2053 2054 4659 34,6892055157,969 157,9692056 2057 97,324 37,3262058 170,115 170,1182059 2060 Total 14,839,640 Rlark &Veatch Canfictential Plan 24 rou oummary Scenario 1 Plan 2A -P50 Natural Gas Forecast Cash Flow per Tr ission Project Soldotna-Eldutna -Soldotna Quartz CR ss University University Soldotna -Year EklutnaSub LucasSub STEVENS CANTWELL ___Lucas Trans Sub Sub Sub STERLING DAVESCR HOPE PORTAGE __GIRDWOOD INDIAN Trans Quartz Trans 2011 2012 2013 1,380 1,380 276 278 679 2014 13,294 13,294 2,659 2,659 6,541 1,414 1,414 849 283 263 283 283 283 283 9,122 2015 13,016 13,916 2,783 2,783 6,847 13,626 13,626 8,176 2,725 2,725)2,725 2,725 2,725 2,725 87,890 4,871 2016 14,264 14,264 6,589 2,853 2,853]2,853 2,853 2,853 2,853 $2,004 46,929 2017 49,126 2018 2019 2020 2021 2022 2023 2024 2025 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 2058 2056 2057 2058 2059 2060 Plan 2A P50 Summary Scenario 1 Plan 2A -P50 Natural Gas Forecast Cash Flow per Tr Project Year Quartz = University Trans 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 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 8,523 62,852 65,794 Lorraine Sub 3,046 29,348 30,722 Douglas Sub__Healy Sub 1,561 15,041 15,745 Lake Lorraine - Douglas Trans Beluga -Pt. Mackenzie Trans Lawing - Seward Teeland Sub Douglas - Healy Trans 1 Douglas - Teeland Trans Soldotna - Bradley Lake Trans Goldhill Sub_Wilson Sub NENANA ESTER 1,873 18,049 18,894 2,885 27,796 29,097 4,218 40,611 42,512 1,748 16,846 17,634 1,600 18,417 16,139 16,129 155,404 162,678 2,400 23,126 24,208 4,054 39,064 40,892 1,640 15,802 16,542 1,681 18,198 16,956 336 3,240 3,391 336 3,240 3,391 Black &Veatrh Confidential Plan 2A P50 Summary Cash Flow per Tr isston Project Total Douglas -Healy -Healy -Transmission Healy Trans =Goldhill Wilson Pt.Mackenzie-Lucas -Teeland Lucas-Teeland Project Cash Year 2 Trans Trans COTTLE HERNING SHAW.LAZELLE ONEIL Plant 2 Trans Trans 1 Trans 2 Flow ($000) 2044 4,022 2012 4,024 2013 8,016 2014 56,971 2015 195,341 2016 260,021 2017 122,000 2018 45,667 2019 173,2322020327,563 2021 16,946 9,784 9,784 300,800 2022 183,271 94,268 94,269 345 345 M45 345 345 2,233 1,799 441,720 2023 170,943 98,682 $8,682 3,320 3,320 3,320 3,320 3,320 21,517 $7,333 454,514 2024 3,476 3,476 3,476 3,476 3,476 22,524 18,144 1,890 63,986 2025 18,210 22,260202619,063 23,11520274,05420284,05620294,058 2030 4,06020314,06220324,06420334,06620344,06820354,07020364,07220374,07420384,07620394,07820404,08020414,08220424,08420434,08620444,08820454,09020464,09220474,09420484,09620494,09820504,10020514,10220524,40420534,10620544,10820554,110205644t22087ania2058aie2059AA820604,120 Total 2,639,208 Black &Veatch Confidential Pian 2A P50 Summary Scenario 1 Plan 2A -P50 Natural Gas Forecast Summary of Cash Flows and Production Costs Total Total Generating Transmission Fixed EnergyUnitCashFlow=Project Cash DSMCosts FuelCost O&M Variable CO2Costs RequirementsYear($000)Flow ($000)Total Cash Flow ($000)($000)($000)($000)__O&M ($000)($000)__After DSM(GWh) 2014 648,006 4,022 652,028 651 260,358 30,389 31,010 §,3722012165,485 4,024 169,500 1,491 272,270 38,587 32,942 55,007 $412201332,742 8,016 40,758 3,063 259,542)42,184 31,884 $7,126 §,424 2014 62,606 56,971 119,877 5,878 283,259 42,198 32,318 63,458 $,421201570,133 195,341 265,473 10,485 371,427 34,169 37,491 65,846 5,167 2016 611,279 260,021 871,300 12,759 421,956 34,186 38,487 72,787 8,147 2017 644,218 122,006 766,217 14,891 357,768 |37,252 37,412 79,202 §,t29 2018 929,407 45,667 975,074 12,241 236,080)35,664 35,656 85,281 $,10520191,181,779 173,232 1,355,011 12,657 258,712]34,484 37,482 $2,493 8,08520201,546,277 327,563 1,873,840 13,124 254,585]38,561 31,456 97,226 §,068 2021 1,369,324 300,800 1,670,123 13,346 279,567 35,538 36,360 107,723 §,052 2022 1,414,114 441,720 1,852,834 14,024 268,084]38,382 36,422 110,555 §,08120231,508,849 451,514 1,960,363 4,166 288,154 32,533 36,352 116,267 $111 2024 180,459 63,986 244,445 3,313 312,504 33,012 38,412 130,866 5,140 2025 22,260 22,280 4,222 299,758 |74,984 39,499 132,528 5,174202623,115 23,118 §,342 338,230 76,010 31,680 155,016 §,207202795,020 4,084 99,074 8,551 357,036 76,997 32,900 171 026 $2412028223,063 4,056 227,119 13,323 372,418 78,147 33,815 189,535 5,2782029202,262 4,058 206,320 16,159 386,220)79,319 aa?209,135 $5,309 2030 4,060 4,060 17,064 340,326 |102,693 31,441 219,911 5,34420314,062 4,062 14.951 339,059 |103,727 29,589 234,938 5,37820324,064 4,064 15,081 355,167]105,800 30,822 284,020 §.41320334,066 4,086 15.919 373,744 |107,309 31,458 275,359 5,4472034265,427 4,068 289,498 16,747 368,176 |109,187 32,259 295,963 $4822035529,157 4,070 §33,227 18,111 406,177)149,071 33,483 323,351 5.5172036175,050 4,072 179,122 5,493 422,212]143,028 34,280 349,498 §,5532037285,836 4,074 289,810 7,019 459,136]120,069 35,258 375,530 5,5882038569,844 4,076 $73,920 6,453 470,538 |121,912 35,95 401,232 §,6232039307,744 4,078 311,822 6,848 496,692 |124,018 37,308 439,404 5,6892040279,906 4,080 283,986 12,284 878,145]131,284 86,850 783,108 5,6952041253,804 4,082 257,886 18,825 907,904 |133,488 $7,826 837,806 $,73120424,084 4,084 21,552 689,979 |185,239 60,061 883,527 5,7872043131,612 4,086 135,698 22,199 934,716 |158,357 61,860 954,735 §,8032044308,963 4,088 343,051 23,458 986,688 |268,631 63,681 1,031,028 $,8392045280,152 4,090 284,242 22,134 |1,003,833 |164,911 65,326 1,108,402 5,87620464,092 4,092 22,961 993,399]208,292 68,767 1,147,871 §,91220474,094 4,094 24,452]1,026,508 |209,703 70,817}1,236,743 $§,94920484,096 4,096 25,398]1,064,256]214,230 72,845 1,337,640 $5,986204930,634 4,098 34,732 6,909 |1,091,617 |218,858 74,368 1,436,931 6,0232050139,622 4,100 143,722 6,724]1,129,310]223,607 76,460 |1,548,719 6,06020514,102 4,102 41,174]1,179,794]231,528 78,885 1,898,177 6,09820524,104 4,104 9,139}1,218,113]236,525 81,054 1,643,288 6,13520534,106 4,106 14,889 |1,251,262 |241,633 82,881 1,679,803 6,173205434,659 4,108 36,767 22,880}1,291,897]246,876 85,212 1,726,854 62112055157,969 4,110 162,078 27,949 |1,328,087 |252,249 87,486 1,775,083 6.24920564.112 4412 30,133 |1,387,098 |260,817 90,320 1,836,104 6,287205737,324 4,114 41,438 33,288 |1,426,422!266,451 92,459 1,882,468 6,3262058170,115 4.116 174,231 33,226 |1,477,497 |270,507 94,588 1,939,244 6,364205941184,118 31,309]1,517,122 |279,428 96,653;1,956,733 6,40320604,120 4,120 32,092 |1,572,385 |285.487 99,967]2.026.812 6.442Total14,839,840 2,639,208 |iT otal of Cash Flows &DSM 18,226,355 Plan 2A Poo Summary Scenario 1 Plan 2A -P50 Natural Gas Forecast:Cumulative Capacity and Energy by Resource Type Natural Gas Coal Nuclear Fuel Oil Purchase Power Hydro Geothermal 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){GWh)(MW)(GWh)(MW){GWh)(MW)(Wh)(MW)(Gh)(MW)(GWh)(MW){GWh)(MW)(GW MW)(GWh) 2011 821 3,606 27 224 254 612 25 187 176 §91 22 185 2012 758 3,622 27 212 254 613 25 204 176 §93 26 219 2013 893 3,764 2 207 251 494 2 202 176 §91 26 219 2014 893 3,774 27 216 251 475 25 206 176 591 26 218 2015 703 2,978 27 att 251 967 2 205 176 591 26 220 18 49 2016 621 2,863 a 214 251 1,057 25 207 176 §93 26 219 15 49 2017 754 377 27 ran 254 750 25 197 176 $91 26 218 15 49 2018 686 2,928 27 V77 189 981 26 196 181 611 26 220 18 49 2019 686 3,118 2 176 128 768 25 205 181 611 26 219 15 49 2020 975 3,921 27 175 25 179 161 613 26 219 15 49 2021 816 3,793 27 167 25 141 181 61 26 219 65 214 2022 888 3,826 2?167 25 144 181 6t1 26 218 65 214 2023 888 4,018 25 139 181 611 26 220 65 214 2024 888 4,031 25 142 181 613 26 219 65 214 2025 888 3,748 25 144 1,111 4,353 26 212 65 213 2026 888 3,906 1,111 4,370 26 214 6s 214 2027 846 3,939 1411 4,372 26 214 65 214 2028 846 3,969 1,111 4,384 26 215 85 214 2029 846 4,002 1,911 4371 26 215 65 214 2030 999 3,719 $3 348 1,411 4,367 26 210 85 213 2031 765 3,676 53 358 1,911 4,398 26 215 65 21320327653,692 $3 362 1,441 4411 26 215 65 ,21420337653,735 33 361 1,111 4,400 26 215 65 21420347653,776 §3 350 1,411 4,401 26 215 65 21420357653,799 53 372 1144 4,402 26 216 65 21420367653,824 §3 370 1414 4,431 26 246 65 21420371,090 4,012 §3 269 1,114 4,382 26 205 65 21420381,058 4,005 53 271 1,419 44 26 205 65 2t420391,058 4077 53 271 1114 4,374 26 208 65 21420401,369 7,239 §3 339 1404 4,429 26 217 65 21820411,369 7.198 53 339 1,111 4,434 26 216 65 21320421,369 6,799 53 388 111 4,448 50 383 26 217 85 21320431,305 6,840 §3 389 1,114 4,449 50 383 26 217 65 21420441,305 6,865 83 390 1,114 4,461 50 384 26 218 6s 21420451,305 6,893 §3 388 4,111 4,450 50 383 26 217 6s 21420461,305 6,607 53 387 1111 4,450 100 766 26 217 65 21420471,305 6,616 53 3a8 1,111 4471 100 766 26 217 8s 21320481,305 6,651 53 391 1,414 4,483 100 768 26 218 65 21420491,308 6,650 $3 389 1,111 447i 100 766 26 217 65 21420501,305 6,676 53 389 1,114 4,472 100 766 26 217 85 21420511,353 6,727 53 387 1,111 4,475 100 766 26 217 66 21420521,353 6,747 $3 389 1414 4,508 100 768 26 218 65 2420531,353 6,728 83 388 1,114 4,496 100 766 28 218 85 21320541,363 6,747 53 390 114 4,498 100 766 26 218 85 21420551,383 6.768 53 392 1,414 4,498 100 766 26 217 65 21420561,400 6,796 83 390 1,111 4,509 100 768 28 218 65 21420871,400 6,793 53 396 1,111 4,497 100 766 26 218 6s 21420581,400 6,631 53 390 1,092 4,481 100 766 26 218 65 21320591,448 6,935 53 336 1,092 4,482 100 766 26 217 65 213206014486.998 §3 346 1,082 4439 400.768 26 218 65 214 APPENDIX I DETAILED RESULTS -SCENARIO 2B ALASKA RIRP STUDY APPENDIX | DETAILED RESULTS -SCENARIO 2B Black &Veatch -1 December 2009 DRAFT REPORT Plan 2b rou ournmary Scenario 1 Plan 2B -P50 Natural Gas Forecast Renewable Annual Capital Cumulative Reserve |Generation Fuel Costs Total O&M CO2 Costs |DSM Costs Fixed Charges |Total Annual Present ValueYearAdditionsI:Tr Margin (%)(%)($000)Costs ($000)($000)($000)($000)Costs ($000)($000) Beluga -1;Beluga -2;International -1; 2011 Anchorage MSW.International -2 52.25%14.44%$260,358 $70,369 so $651 $14,610 $345,988 $345,988 2012 GVEA MSW International -3 44.38%14.97%$272,270 $71,498 $55,007 $1,491 $16,442 $416,709 735,435 2013 Anchorage 1x1 6FA 59.43%14.85%$259,547 $74,105 $57,126 $3,063 $51,650 $445,490 1,124 544 'Beluga -3;Beluga -6/8;Beluga -7/8; 2014 Fire Island Bemice -2;Bemice -3 59.86%17.98%$273,555 $83,437 $61,078 $5,878 $64,189 $488,136 1,523,008 2015 Nikiski Wind 40.77%19.61%$382,707.$81,380 $64,204 $10,455 $67,938 $606,684 1,985,844 Eklutna Sub;Lucas Sub;STEVENS;CANTWELL; 2016 Eklutna -Lucas Trans 44.38%19.51%$431,075 $82,606 $70,975 $12,759 $76,311 $673,726 2,466,201 Soldotna Sub;Quartz CR Sub;University Sub; STERLING;DAVES CR;HOPE;PORTAGE; 2017 Anchorage LM6000 Beluga -5:NP4 GIRDWOOD;INDIAN;Soldotna -University Trans|__51.21%19.31%$364,436 $84,840 $76,965 $11,891 $114,532 $652,664 2,901,098 2018 Kenai Hydro NP2 Soldotna -Quartz Trans;Quartz -University transl 37.38%19.59%232,365 $814,110 $84,108 $12,241 146 302 $556,123 3,247,424 2019 30.93%19.44%256 968 $82,207 $90,747,$12,657 146 302 $588,882 3,590,159 2020 GVEA 1x1 6FA Beluga -6;MLP 5;MLP 5/6;MLP 7/6 Lorraine Sub 42.75%19.39%246.614 $78,639 $94,352 $13,124 194,545 $627,270 3,931,352 Douglas Sub;Healy Sub;Lake Lorraine -Douglas Trans;Beluga -Pt.Mackenzie Trans;Lawing - 2021 GVEA Wind T Lines Beluga -7 Seward 33.45%22.21%$274,334 $83,104 $105,003 $13,346 $255,870 $731,658 4,303,290 Teeland Sub;Douglas-Healy Trans 1;Douglas -2022 Anchorage 1x1 6FA Healy -1 Teeland Trans 41.38%22.07%$263,230 $84.688 $108,760 $14,024 $342,079 $812,781 4.689 436 2023 Soldotna -Bradley Lake Trans 37.29%21.96%$281,217 $80,207 $113,278 $4,166 $354,028 $832,895 §,059.252 Goaldhill Sub;Wilson Sub;NENANA;ESTER; Douglas -Healy Trans 2;Healy -Goldhill Trans; 2024 Healy -Wilson Trane 36.19%21.85%$306,178 $82,931 $127,784 $3,313 $435,586 $955,792 5,455,871COTTLE;HERNING;SHAW;LAZELLE;ONEIL;: Ch vamna:Chak 1a;Low Pt.Mackenzie -Plant 2 Trans;Lucas -Teeland 2025 Watana (Expandable)GVEA Aurora Purchase -Tier {Trans 1 54.38%§5.55%$294,372 $126,218 $129,792 $4,222 $1,570,454 $2,125,059 6,280,0062026Nikiski48.64%55.57%$331,438 $419,350 151,736 $5,342 $1,570,454 $2,178,321 7,069,529 2027 Lucas -Teeland Trans 2 48.03%55.38%348,979 $121,920 166,882 $8,551 $14,574,420 $2,220,753 7,821,775 2028 47.32%55.26%363,890 $124,168 184,842 $13,323 $1,574,420 $2,260,644 8,537,437202946.63%54.96%380,452 $126,972 204,902 $16,151 $1,574,420 $2,302,898 9,218,782 2030 Mount Spurr T OPP -6;MLP 7;MLP 8:Zen1;Zen2 37.15%59.09%$346,242 $153,478 $194,420 $17,064 $1,629,671 $2,340,875 9 866,053203131.78%58.97%$306,502 $147,044 $189,427 $14,951 $1,629,671 2,287,595 10,457,211203231.17%58.88%320,180 $150,165 $204 499 15,081 $1,629,671 2,319,596 11,017,424 2033 30.55%58.56%338,446 $153,381 $222,741 15,919 $1,629,671 2,360,158 11,550,1432034Anchorage1x16FA41.03%58.27%353,066 $160,337 $241,259 16,747 $1,676,267 2,447 676 12,066,4722035,40.38%58.07%$369,769 $163,741 $261,881 $18,111 $1,672,517 $2,486,019 12,556,583 2036 39.72%58.16%$383,256 $166,992 $282,388 $5,493 $1,672,517 2,510 647 13,019,167 2037 MLP 3 36.79%57.86%$402,705 $170,429 $308,510 $7,019 $1,672,517 2,561,181 43,460,191203836.15%57.68%$422,744 $173,677 $336,820 $6,453 $1,672,517 2,612,214 13,880,575 2039 35.53%57.49%$440,059 $177,433 $365,280 $8,348 $1,672,517 $2,664,138 14,281,267 GVEA 2x1 6FA;Low Watana Expansion;Mount Spurr:GVEA 2040 Wind;GVEA Wind 50.50%51.80%$692,498 $236,189 $584 608 $12,284 $2,285,069 $3,812,648 14,817,18404149.99%51.76%$715,631 $243,654 $628,153 318,825 $2,240,829 $3,847,089 15,322,565 042 NPCC 46.20%52.35%$730,425 $234,147 $668,307 $21,552 $2,231,195 $3,885,627 15,799,61504345.70%52.29%$755,482 $239,485 $719,192 $22,199 $2,195,987 $3,932,344 16,250,817204445.19%§2.22%$782,795 $244,596 $778 464 $23,458 $2,195,987 $4,025,300 16,682,468204544.69%52.27%$807,993 $251,057 $832,694 $22,134 $2,195,987 $4,109,865 17,094 3562046HEA1x16FA§2.00%50.84%$904,427 $252,763 $969,174 $22,961 $2,267,143 $4,416,468 17,508,016204751.48%52.01%$916,925 $267,944 $1,024,440 $24,452 $2,236,725 $4,470,485 17,899,342204850.95%52.17%$947,077 $275,682 $1,103,569 $25,398 $2,204,954 $4,556,681 18,272,119204950.44%52.00%$974,659 $281,078 $1,189.631 $6,909 $2,204,954 $4,657,231 18,628,196 2050 49.91%51.87%$1,008 376 $286,979 $1,283,724 $8,724 $2,156,712 $4,744,515 18,967,215 2051 49.39%51.99%$1,044.939 $294,822 $1,316,394 $11,174 $2,125,016 $4,792,346 49,287,250205243.87%51.82%$1,085,401 $300,696 $1,360,974 $9,139 $2,038,807 $4,795,014 19,586,514205343.35%51.80%$4,116,129 $307,933 $1,391,652 $14,889 $2,026 858 $4,857,461 19,869,843205447.83%51.73%$1,155,170 $315,385 $1,434,580 $22,880 $1,945,300 $4.873.315 20,135,5002055ATI51.68%$1,183,067 $322,592 $1,474,071 $27,949 $1,933,223 $4,940,902 20,387,222205646.80%$1,.65%$1,234,094 $330,474 $1,520,808 $30,133 $1,933,223 $5,048,729 20,627,6092057KenaiWindTLines;HCCP.Cooper Lake 48.88%52.23%$1,227,672 $386,906 $1,631,733 $33,288 $2,000,305 $5,279,904 20,862,558205847.43%$1.84%$1,275,343 $447,650 $1,688,272 $33,226 $2,000,305 $5,444,797 21,088,993205945.91%51.91%$1,328,968 520,981 $1,751,131 $31,309 $2,000,305 $5,632,694 21,307,918206046.40%51.85%$1,371,236 415,869 $1,804,374 $32,092 $1,844 382 $5,467,953 21,506 536 Present Value of Costs 5,597,703 1,745,487 3,172,881 149,474 10,840,992 21,506,536 Black &Veatch Confidential anraionna Black &Veatch Confidentia! Plan 2B P50 Summary Scenario 1 Plan 2B -P50 Natural Gas Forecast Annuat Natural Gas Usage (mmBtu) Year Anchorage interior Matanuska___Kenai__Total Railbelt 2011 34,642 Qo 0 4,355 38,097 2012 33,307 0 0 5,154 38,481 2013 33,591 )Oo 3,844 $7,435 2014 32,839 0 Oo 3,143 35,682 2015 24,004 ]O 3,558 27,652 2016 23,104 o 0 3,670 26,774 2017 26,302 0 0 3,383 29,686 2018 24,028 9,305 Oo 3,315 36,649 2019 25,801 6,446 Oo 3,454 36,699 2020 20,176 11,228 0 3,210 34,614 2021 21,611 9,643 oO 3,329 34,582 2022 22,520 7,782 0 2,584 32,883 2023 24,255 7,847 0 2,713 34,816 2024 25,223 7,279 O 2,905 35,407 2025 21,648 8,493 O 2,411 32,553 2026 23,281 9,069 QO 1,763 34,114 2027 24,453 9,560 [')0 34,013 2028 24,555 9,619 Qo 0 34,174 2029 24,817 9,621 0 QO 34,438 2030 17,601 10,848 L')0 28,450 2031 17,519 9,969 Qo te]27,488 2032 17,568 10,016 0 )27,584 2033 17,923 10,050 LY)0 27,873 2034 19,542 8,734 Q Q 28,275 2035 19,785 8,767 Qo 0 28,552 2036 20,103 8,493 9 0 28,596 2037 19,944 9,148 )0 28,080 2038 19,945 9,603 )0 29,548 2039 20,115 9,698 Q Qo 20,812 2040 29,569 15,691 0 0 45,261 2041 29,536 15,700 0 0 45,236 2042 29,524 15,122 0 9 44,646 2043 29,586 15,112 9 0 44,697204429,680 15,306 Q t)44,986 2045 29,643 15,185 Qo oO 44,828 2046 25,965 16,217 0 6,456 48,638 2047 26,012 16,337 0 6,456 47,804 2048 26,063 15,270 QO 6,548 47,880 2049 26,017 15,321 0 6,672 48,010 2050 26,141 15,426 0 6,666 48,233 2051 26,260 18,342 0 6678 48,280 2052 26,426 15,569 0 6,701 48,697 2053 26,382 15,462 QO 6,732 48,576205426,477 15,565 Oo 6816 48,858 2055 26,538 15,600 0 6,838 48,976 2056 26,640 18,703 6 6,981 49,324 2057 26,346 13,573 QO 6,564 46,482 2058 26,575 13,620 Oo 6,780 46,974 2059 26,841 13,797 Oo 6,928 47,565 2060 26,894 13,917 0 6,944 47,755 Plan 2b cw wunimary Scenario 1 Plan 2B -P50 Natural Gas Forecast Cash Flow per Generating Unit Addition Chakacham Generating Anchorage Anchorage 1x1 Nikiski Anchorag GVEA 1x1 GVEA Wind T Anchorage na:Chakach LowWatana Mount Anchorage Unit Cash Flow Year MSW GVEA MSW 6FA Fire Island Wind eLM6000_Kenai Hydro GFA Lines 1x1 6FA amna (Expandable)SpurrT 1x16FA_GVEA 2x1 6FA {$000) 2011 244,356 44,429 210,604 Qo 184 0 0 LY)52,846 Li)i]9 652,328 2012 132,925 29,614 188 35,248 497,976 2013 273,194 2,318 193 32,818 308,623 2014 21,384 198 44,671 66,253 2015 13,231 13,800 46,933 73,964 2016 60,303 13,313 33,699 548,760 656,075 2017 13,646 74,230 26,866 576,541 691,282 2018 174,256 43,273 775,156 992,685 2019 158,007 26,242 77,987 79,301 914,930 1,256 4672020242,080 183,078 238,340 961,248 1,624,747 2021 166,006 481,537 785,939 1,433,482 2022 652,793 825,728 1,478,521 2023 712,138 867,530 1,579,668 2024 141,428 42,503 183,929 2025 8,390 2026 14,874 2027 88,657 104,2852028208,125 222,720 2029 188,718 208,523 2030 20,808 2031 104,885 348,181 2032 246,219 501,832 2033 223,259 566,930 2034 405,6402035426,1762036348,4512037285,836 765,4162038569,844 1,300,6972039488,510 1,185,174 2040 20441 2042 2043 141,0582044331,1382045300,2592046 2047 2048 2049 2050 2051 2052 2053 2054 2055 38,3002056353,3242057 2058 2059 2060 Total 418,788,173 Dlnale ©Vande Aeemdanstnt antninans Plan 2B P50 Summary Scenario 1 Plan 26 -P50 Natural Gas Forecast Cash Flow per Transmission Project Year EW na Sub Ekdiutna - Lucas Sub STEVENS CANTWELL Lucas Trans Sub Quartz CR Sub University Sub STERLING DAVES CR HOPE PORTAGE GIRDWOOD INDIAN Soldotna - University Trans Soldotna - Quartz Trans 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 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 2058 2057 2058 2059 2060 1,380 13,294 13,916 1,380 13,294 13,916 276 2,659 2,783 276 2,659 2,783 679 6.541 6,847 1,414 13,626 14,264 1,414 13,628 14,264 849 8,176 8,559 283 2,725 2,853 283 2,725 2,853 283 2,725 2,853 283 2,725 2,853 283 2,725 2,853 9,122 87,890 92,004 4.871 46,929 49,126 Black &Veatch Confidential animinnnn Plan 28 P50 Summary Scenario 1 Plan 2B -P50 Natural Gas Forecast Cash Flow per Transmission Project Year Quartz - University Trans Lorraine Sub __Douglas Sub__Healy Sub Lake Lorraine - Douglas Trans Beluga -Pt. Mackenzie Trans Lawing - Seward Teeland Sub Douglas-Douglas-Soldot Healy Trans 1 Teeland Trans Bradley Lake Trans Goldhill Sub__Wilson Sub NENANA ESTER 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 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 6,523 62,852 65,704 3,048 29,348 30,722 1,561 15,041 15,745 1,873 18,049 18,894 2,885 27,796 20,097 4,215 40,611 42,512 1,748 16,846 17,634 1,600 45,417 16,139 16,129 155,404 162,678 2,400 23,126 24,208 4,054 39,064 40,892 26,266 1,681 16,198 16,956 336 3,240 3,391 336 3,240 3,391 Plan 2B P50 Summary Cash Flow per Transmission Project Total Douglas -Healy -TransmissionHealyTrans-Goldhill Healy -Pt.Mackenzie -Lucas -Teeland Lucas-Teeland Project CashYear2TransWilsonTrans-COTTLE HERNING SHAW LAZELLE ONEIL Plant 2 Trans Trans 1 Trans 2 Flow ($000) 2011 30,28820124,02420138,016 2014 56,9712015195,341 2016 260,021 2017 122,000 2018 45,6872019173,2322020325,922 2021 16,946 9,784 9,784 284,997 2022 163,271 94,269 94,269 345 345 345 345 345 2,233 1,799 425,1782023170,913 98,682 98,682 3,320 3,320 3,320 3,320 3,320 21,517 17,333 454,514 2024 3,476 3,476 3,476 3,476 3,476 22,524 18,144 1,890 83,986 2025 18,210 22,260202619,063 23,11520274,05420284,05620294,05820304,06020314,06220324,06420334,06620344,06820354,07020364,07220374,07420384,07620394,078 2040 4,08020414,08220424,08420434,08620444,08820454,09020464,09220474,09420484,09620494,09820504,10020514,10220524,10420534,10620544,10820554,11020564,11220574,11420584,11620594,11820604,120Total2,631,489 Black &Veatch Confidential sAhiaennns Plan 2B P50 Summary Scenario 1 Plan 2B -P50 Natural Gas Forecast Summary of Cash Flows and Production Costs Total Total ti T issi Fixed Energy Unit Cash Flow Project Cash OSM Costs Fuel Cost O&M Variable CO2Costs Requirements Year ($000)Flow ($000}Total Gash Flow ($000)($000)($000)($000)O&M ($000)_($000)__After DSM (GWh) 2011 652,328 30,288 682,615 651 260,358 39,359 31,010 5,372 2012 197,976 4,024 202,000 1,491 272,270 38,557 32,942 55,007 §,412 2013 308,623 8,016 316,639 3,063 259,547 42,221 31,884 $7,126 5,424 2014 66,253 56,971 123,224 5,878 273,555 49,543 33,894 61,078 §,421 2016 73,984 195,341 269,305 10,455 382,707 41,702 39,678 64,204 5,167 2016 656,075 260,021 916,097 12,759 431,075]41,929 40,677 70,975 §,147 2017 691,282 122,000 813,282 11,891 364,436 45,164 39,676 76,965 5,129 2018 992,685 45,667 1,038,352 12,241 232,365 43,774 37,336 84,105 5,105 2019 1,256,467 173,232 1,429,699 12,657 256,968 42,797 39,410 90,747 5,085 2020 1,624,747 325,922 1,950,669 13,124 246,611 45,106 33,533 94,352 5,068 2021 1,433,482 284,997 4,718,479 13,346 274,334 44,273 38,831 105,003 §,052 2022 1,478,521 425,178 4,903,698 14,024 263,230 47,337 37,354 108,760 5,081 2023 1,579,668 451,514 2,031,182 4,166 281,217 41,708 38,499 113,278 5,111 2024 183,929 63,986 247,915 3,313 306,178 42,443 40,488 127,784 5,140 2025 8,390 22,260 30,650 4,222 294,372 84,625 41,593 129,792 5,174 2026 14,874 23,115 37,989 §,342 331,438 85,893 33,457 151,736 5,207 2027 404,285 4,054 108,339 8,551 348,979 87,127 34,792 166,882 5,241 2028 222,720 4,056 226,776 13,323 363,890 88,556 35,612 184,842 5,276 2029 208,523 4,058 212,581 16,151 380,452 89,960 37,012 204,902 5,309 2030 20,808 4,060 24,868 17,064 348,242}115,038 38,440 194,420 5,344 2031 348,181 4,062 352,243 14,051 306,502}116,478 30,566 189,427 §,378 2032 501,832 4,064 505,896 15,081 320,180 |118,699 31,466 204,499 5,413 2033 566,930 4,066 570,996 15,919 338,448 |120,903 32,478 222,741 5,447 2034 405,640 4,068 409,708 16,747 353,068 |127,055 33,282 241,259 5,482 2035 426,176 4,070 430,246 18,111 369,769 |129,408 34,333 261,881 5,517 2036 348,451 4,072 352,523 5,493 383,256 |131,860 35,132 282,388 5,553 2037 765,416 4,074 769,490 7,019 402,705|134,143 36,286 308,510 5,588 2038 1,300,697 4,076 1,304,773 6,453 422,744 |136,469 37,208 336,820 5,623 2039 4,185,174 4,078 1,189,252 8,848 440,059 |139,066 38,367 365,280 5,659 2040 4,080 4,080 12,284 892,498 |169,875 68,314 564,608 5,69520414,082 4,082 18,825 715,631 |173,133 70,518 628,153 §,73120424,084 4,084 21,552 730,425 |162,502 71,645 668,307 §,767 2043 141,058 4,086 145,144 22,199 755,482 |165,930 73,855 719,192 5,8032044331,138 4,088 335,226 23,458 ||782,795|169,534 75,062 778,464 5,839 2045 300,259 4,090 304,349 22,134 807,893 |173,122 77,935 832,694 5,876 2046 4,092 4,092 22,981 904,427 |180,721 72,043 969,174 5,912 2047 4,094 4,094 24,452 916,925 |184,549 83,394 |1,024,440 5,949 2048 4,096 4,096 25,398 947,077 |188,528 87,158 |1,103,569 5,98620494,098 4,008 6,908 974,859 |192,497 88,580}4,189,631 6,023 2050 4,100 4,100 8,724]1,008,376 |196,620 90,359]1,283,724 6,060 2051 4,102 4,102 41,174 |1,044,939 |200,837 93,986 |1,316,394 6,098 2052 4,104 4,104 9,139]1,085,401 |205,228 95,468 1,360,971 6,135 2053 4,106 4,106 14,889 |1,116,129]209,610 98,323]1,391,652 6,173 2054 4,108 4,108 22,880]1,155,170]214,161 101,224]1,434,580 6211 2055 38,300 4,110 42,410 27,949 |1,183,067 |218,826 103,767 |1,474,071 6,2492056353,321 4,142 357,433 30,123 |1,234,091 |223,662 106,812]1,520,808 6,287 2057 4,114 4,114 33,288 |1,227,672 |266,691 120,218}=1,631,733 *6,326 2058 4,116 4,118 33,226 |1,275,343 |324,455 123,195 1,688,272 6,364 2059 4,118 4,118 31,308 |1,328,068 |393,284 127,698 1,751,131 8,403 2060 4.120 4.120 32,092 |1,371,236 |283.328 132 542 1,804 374 6 442 Total 18,788,173 2,631,489 |Total of Cash Flows &DSM 22,166,970 Plan 2B P50 Summary Scenario 1 Plan 2B -P50 Natural Gas Forecast:Cumulative Capacity and Energy by Resource Type Natural Gas Coal Nuclear Fuel Oil Purchase Power Hydro Geothermal 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)(GWh)(MW){GWh)(MW)(GWh)(MW){GWh)(MW)(GWh)(MW)(GWh)(MW)___(GWh)(MW)(GWh)(MW)(GWh) 2014 821 3,606 27 224 251 612 25 197 176 591 22 185 2012 758 3,622 27 212 251 613 25 204 178 803 26 219 2013 893 3,764 27 207 251 494 25 202 178 591 26 219 2014 893 3,600 27 218 251 473 25 205 176 501 26 218 54 17720157032,728 a7 214 251 1,036 25 208 176 58 26 220 69 227 2016 703 2,623 27 216 251 4,115 25 211 176 $93 26 219 69 228 2017 751 2,936 27 214 251 807 25 199 176 591 26 218 69 227 2018 686 2,703 27 180 189 1,025 25 200 181 611 26 220 69 22720196862,908 27 176 128 801 25 206 181 611 26 219 69 22620201,057 3,747 27 175 25 179 181 613 26 219 69 228 2021 816 3,619 27 167 25 141 181 614 26 219 119 392 2022 888 3,648 27 167 25 1441 181 611 26 218 119 39220238883,839 28 139 184 611 26 220 119 392 2024 888 3,856 25 142 181 613 26 219 119 392 2025 888 3,871 25 143 4,411 4,353 26 212 119 39120268883,728 4,411 4,370 26 214 119 39220278463,762 1,114 4,372 26 214 19 39220288463,792 4,111 4,384 26 215 119 39220298463,821 1,111 4,371 26 215 119 392 2030 846 +3,448 1,114 4,389 50 382 26 210 119 39020316123,429 1,411 4,398 sO 382 26 212 119 39120326123,441 1,141 4,410 50 383 26 214 119 392 2033 612 3,493 1,171 4,399 50 382 26 212 119 39220347653,589 1,111 4,400 50 380 26 208 119 39220357653,629 4,114 4,402 50 380 26 207 119 39220367653,641 1,191 4,431 50 382 26 .210 119 39120377653,680 1419 1)°4,420 50 381 26 210 19 39220387333,704 1,111 4,422 50 381 26 210 119 39220397333,740 :1,114 4,423 50 381 26 21 119 392 2040 1,058 5,560 1,744 4,937 100 768 26 208 219 68920411,058 5,553 |-1.711 4,936 100 766 26 206 219 69720424,058 5,468 .4,711 5,013 100 766 26 213 219 70920439955,470 1,711 $022 100 766 26 212 219 71120449955,513 4,711 5,050 100 768 26 213 219 70020459955,490 4,714 §,049 100 768 26 212 219 72020464,149 6,094 4,711 5,076 100 766 26 216 219 52420471,149 5,960 1,711 5,076 100 766 26 213 219 69720481,149 5,969 1,711 5,097 100 768 26 214 219 72320491,149 5,985 1,711 §,100 100 766 26 213 219 71020501,149 6,021 1,714 §,113 100 768 26 213 219 69920511,149 6,018 4,714 5,126 100 766 26 213 219 72020521,149 6,076 1,711 5,151 100 768 26 214 219 70120531,149 6,063 1,711 $,153 100 .766 26 214 219 70920541,149 6,101 1,714 5,181 100 766 26 214 219 71120554,149 6114 1,711 5,174 100 766 26 214 219 71020861,149 6,158 714 5,196 100 768 26 214 219 71120571,149 5,747 53 356 1,711 §,204 100 766 26 211 249 79920581,149 5,811 53 387 1,692 §,172 100 768 26 211 249 79620591,149 5,886 53 359 1,892 6,192 100 766 26 212 249 80520601,149 5,911 53 364 1,692 5,168 100 768 26 212 249 821 Black &Veateh Confidential