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HomeMy WebLinkAboutAK-BC Intertie Feasibility Study SE Alaska Final Report September 2007/ZALASKA€--ENERGY AUTHORITY AK-BC Intertie Feasibility,,aeStudySEAlaskawi Stain Final Report September 2007nTAGE Hatch Acres Corporation Dryden and La Rue,Inc. Hardy Energy Consulting Hatch Acres Corporation Suite 101,6 Nickerson StreetHATRHARAESsant Tel.206 352 5730 ¢Fax:206 352 5734 *www.hatchenergy.com September 18,2007 H-324582 Mr.James Strandberg Project Manager The Alaska Energy Authority 813 West Northern Lights Blvd. Anchorage,AK 99503 Dear Jim : Subject:Final Report -AK-BC Intertie Feasibility Study SE Alaska We are pleased to submit our Final Report for this project.This report represents our fourth and final deliverable under Contract #AEA-07-008. Our contract with AEA calls for this report to have been submitted by April 30",2007.As agreed with AEA, submission of the report was deferred to allow the AEA to assemble internal and stakeholder comments on our Draft Final Report dated April 5,2007.In preparing this Final Report,we have incorporated our responses to the AEA's comments of August 14"in our Draft Final Report.We would like to make specific note of the fact that in accordance with our scope of work we have not updated the Draft Final Report to reflect information on any new developments in the electricity sectors of SE Alaska ,British Columbia or the Lower 48 States during the period April 6",2007 to the present. The purpose of this report is to provide a detailed description of the analysis we carried out in the study.In accordance with our contract,this study focuses on the hydro projects that could be developed and the proposed electrical transmission system that would interconnect presently isolated load centers within Southeast Alaska and interconnect Southeast Alaska with Northwest British Columbia.These projects would provide the opportunity to reduce present and projected diesel generation,to coordinate the operations of the region's hydro plants to make the most efficient use of the water resources,to increase system reliability and to receive revenue from the export of power,thus creating important enabling conditions for new economic development within the study area. In preparing this report we have described the information we have obtained and have outlined the results of the analyses that we have carried out in our work under the Contract based on this available information.We have indicated the areas where additional information or more refined analysis will be desirable during Phase I!of the study or as part of other subsequent work on the projects that have been considered as part of this study.We note that while the word "feasibility”is included in the name of the project,the cost estimates provided in this report are based on existing studies,documents and other available information which generally are not based on feasibility level investigations. lf you have questions on any of the information or results included in this report,please give us a call and we will be pleased to assist. Yours very truly, VEC adn Robert Griesbach,P.Eng.,CMC Project Director Hatch Acres Corporation Cover Letter_Final Report.Doc Hatch Acres Corporation HATGH AGES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report PROJECT REPORT PR-324582 Rev.0,Page 1 September 18,2007 Alaska Energy Authority AK-BC Intertie Feasibility Study SE Alaska Final Report If you disagree with any information contained herein,please advise immediately. AK-BC Alaska Final Report 18-09-07.Doc Hatch Acres Corporation HATGH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Report Disclaimer This report has been prepared by Hatch Acres Corporation (Hatch Acres)for the sole and exclusive use of The Alaska Energy Authority (the "Client”)for the purpose of providing the AK-BC Intertie Feasibility Study SE Alaska;and shall not be (a)used for any other purpose,or (b)provided to, relied upon or used by any third party. This report contains opinions,conclusions and recommendations made by Hatch Acres,using its professional judgment and reasonable care.The report,desk analysis associated with preparation of the report,and an accompanying model were prepared solely for the purposes described in this report,and are based on information available to Hatch Acres as of April 5,2007 the date of submission of the Draft Final Report supplemented by information provided in the Client's comments on the Draft Final Report which were provided to Hatch Acres on August 14,2007.Use of or reliance upon this report by the Client is subject to the following conditions: (a)the report being read in the context of and subject to the terms of the Contract between Hatch Acres and the Client dated November 1,2006 (the "Agreement”),including any methodologies, procedures,techniques,assumptions and other relevant terms or conditions that were specified or agreed therein; (b)the report being read as a whole,with sections or parts hereof read or relied upon in context; (c)the conditions may change over time [or may have already changed]due to natural forces or human intervention,and Hatch Acres takes no responsibility for the impact that such changes may have on the accuracy or validity or the observations,conclusions and recommendations set out in this report;and (d)the report is based on information made available to Hatch Acres by the Client or by certain third parties and unless stated otherwise in the Agreement,Hatch Acres has not verified the accuracy,completeness or validity of such information,makes no representation regarding its accuracy and hereby disclaims any liability in connection therewith. The report includes input and output sheets for a computer-based model that was prepared as part of Hatch Acres work on the project for use as a calculation tool.The foregoing provisions also apply to this computer-based model.At such time as the digital files for this computer-based model are provided,Hatch Acres takes no responsibility for the assumptions used or procedures followed with respect to the use of this computer-based model by staff of the Client or by third parties. Hatch Acres Corporation PR324582.Rev.0,Page 2 AK-BC Alaska Final Report 18-09-07.Doc BATU AGH Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table of Contents Covering Letter Disclaimer Table of Contents List of Acronyms Executive Summary 1.INTRODUCTION .......ccccssccecssscsssorosesoncsessceesasssssssnssesnsconsccascnacanscosesossecescecccesscessoeccuseesvecseees 24 1.1 Study Area and Energy Sector of ECOMOMY.........essscsscssessscscsssecessscesessssesesesseeesssenseeeses 24 1.2 Purpose of this REPOrt ..........cccccccsccsesessecesseecseeeeseeceesseecessasesseesensesesueeceresceseseeseeaensaeenses 27 1.3.Policy ISSUCS........cc:cccessccestcceescecseecscecensecnscecsceesceeseeseceseeersseeseesesesausessseecosesseesseessaeenees 29 1.3.1 Joint Planning and Operations ..........csccssssccetesssceceesseteaseesseevssecsessscessessssssssssacsescesseeesseeerees 29 1.3.2 Markets and Market Structure .........cccccssccssssccsssseccecssesessseeeeesesaceessaneeesesseenessseeesesseaosesseags 29 1.3.3 Regulatory ISSUCS...........ccsccsssscsstssseccerecesseecesnerenseeseneessceonseeeesseesessecssassecesenersseseesaessaseseeeee 30 1.3.4 Gemeration RESOUICES ........ccsscscccscsessescesteneececesesesseessceeseesossenesesensesnseduussvasesnsanesenesoesansesees 30 1.3.5 Load Mamagement...........cc:cccccccsssccsssessscesseccsseesssccesssesseeessaseesceescnecseeeeresasessscoseesssasossnseones 30 1.4 Contractual Background ........:cccsccsesccssceesscessccesseeseseecesceeecsecererseesssesecssecnsessseecessaseesees 30 1.5 Overview Of Phase |........cccsscsccssssccessrsesessscecsssscecesssseecessaaesecnsoneceesaaeeecesaeeesesneessesseeeons 31 1.6 Study Approach and ASSUMPTHIONS...........cccsscccescseeccesssscceessneeecsssseeeeeessecoeserseusssesesenseeeees 31 1.7.Phase Il -Development Assistance for AK-BC Intertie Project .............sseceeesseesessseeseenes 32 1.8 SE Alaska Market ..........c:ccccssssscsssssecescsseseseececesssceeseseoeeceeseaececsssneessesnnececesseaeeseaeeeeesseesoes 33 1.9 External Market and Market Structures ............:ccccccsssssceccecceesesssnceseececesssneeeceseeseasaaeeseves 33 1.10 Regulatory ISSUCS ........cccccsscccssscestecesnceessecsececsneeesseeceseeeeeseeessceescaceeseeeosssesesueeseeeseneasenee 34 1.11 Transmission Line Costs and ISSue@s ............ccccccccceessssscceceeceesesesceeeceseccessencceenecoesseaneeeeeoees 35 1.12 Power Generation Costs and ISSUCS..........::scccssssceceescccecessrceeessescecsssacessessacseeesaeeeeseseeaes 36 1.13 Development Scenarios Evaluated 00...ce seccssseeseecseeeeeessseesensseeecesessssseseesseceseusesenanees 36 1.14 Phase Il --Development Assistance for AK-BC Intertie Project 0.0.0...eeessesseeeseeseeeeees 37 2.BUSINESS STRUCTURES ..........ccccssssssssssssssssssssseccssccsccesscossesccesscsesssscssesscsscsssescessacscesscessensoses 41 2.1 OVOIVICW 00...cesesssssssssecccceccctensacessessesecersseneecsecacececacessreseeseeecenenscresseeeseesessscesensansnesseserees 41 2.1.1.Options Removed from Further Consideration ..........::cscssesesseecescrsrerereeceseeeeesesesseresessesees 42 2.1.2 Business Structures Selected for Further Analysis ........:cssccsssscssrsessscesscseetenesenecsesserereneeoeers 43 2.1.2.1 Transmission Cooperative Business Structure for SE Alaska..........:.cccsseesseesterseeeeseeee 43 2.1.2.2 Unified System Operator ..........cccsccessccsecesscccsscccesaccnaccssssessceneccseaseasesseaseseasossecesneees 45 2.1.2.3.Power Marketing Oversight Unit ............::cccssccsscccssscesseceseceesceereseerssssosseoossaseseeesneees 47 2.1.2.4 State OWeSHIP ou...ccessecssesecsscesccesnasceensncecsenseeetsnsecesesseseceescesesensseeeteeserenesadeneses 47 2.2 Regulatory Considerations ...........::ccsscccessseccessscecessnececseseaeceesseceeessccesceseeecesseueensesseseess 49 2.2.1 OVOLVIOW .oeeecccccscsssncctccctcesececececsensesssaasanaaaaananeasasonsesecdeeesesssesesseesesessesesessoesesesensssnsssesesuse 49 2.3 Transmission Element of Business Structure ............:cccsscsssscsescsecssceccececeesecseeeteeteeereeonenses 49 2.3.1 Transmission System Segments -Alaska.........csccsccssesseeressecseeeceseeseeeaceeceaceaetereeeseaserenseesaaea 49 2.3.2.Interconnection and Future Arrangements With BCTC .........:ccsscesceersceetessetsncesecreceeeeeeneenees 50 2.4 Generation Element of Business Structure.........cccccccsccecssssscccessecceesseeeesesseceeessnseeseesaeeeees 50 2.4.1.Generation Resources Identified for Export.........c.cccccsssccsessececesssccececeeeecseeeeestssaeeseneneeseneners 50 Hatch Acres Corporation PR324582.Rev.0,Page 3 AK-BC Alaska Final Report 18-09-07.Doc HATGH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 3.SOUTHEAST ALASKA MARKET ........ccscccsssscssccscssnsrcsnscnscssssceccnsccereneesncses 53 3.1 OVOIVIOW vo eeeecccececceceneceseeccceceecssecscesensnssecnsccseceeecsesssseseeeeuseessessessacesevesersesesssnssenasanenene'53 3.2 Loads and ReSOUICES .......ccsccscceccececescnescsncsccescccnseneccascceececeeecoeecessesseesesessnsssnsersasessoesenee 54 3.2.1 Current Loads and ROSOUICES .........ccsccssscesereceescesseceesanecesneesnssensnaseeeasseesconssssssssesscsnseesecseenes 54 3.2.2 Projected LOAdS .........ccesccscssccssessessesecnersessetsecesseneesneeaesaseseessesssssesssusesssssseeseesseenseasesensenseneed 60 3.2.3 Forecast Parameters -Reference Case ........ccccsscccesescccesssncetsenecetersssesessneasensneserseeeesesneeeseens 64 3.2.4 Monthly Sales Patterns 0.0...cc eecsseseeseeseeesssessesescsasssucssssseesseesessenseesseenaseseressesnneessasenenees 65 3.2.5 Forecast SUMMALY ..........ccccccescccessececeteceescnceeesnseeeteesssseesseeseeessueeessssasessseeeessesseseesesseseeneeeeeses 81 3.2.6 Sensitivity AMAalySis ..........ccceecsesesssceseceeersseessscsesssssscsacsuessrscssesssssssenaesneecetasassnenenseensoneeeeey 82 4,EXTERNAL MARKETS AND MARKET STRUCTURES ..........:ccccssscssssssessssceccccccssncccccecscseseseseose 88 AL OVOIVIOW Loiceccccccccccccsecsessensesseseeceneneeccuaccacanucenasneseseeeeeeseoeaeseseseeseneeeseasereueeneneeeesecesereeeea 88 4.1.1 Wholesale Market Prices ..........ccccccsssscesssscessccesnceseneeenseaesaceeseaseoseessrsessussssacscnscassnsnenseenees 88 4.1.2 Global Power Prices ....c..cccssccccsesesesssssessscccesseceeescscessesaneeecesnaeeeesoaeessssuaesesssencnsseesseesseesnssnees 88 4.1.3.Implications for British Columbia &Pacific Northwest Markets ........c:cscsessscseeseeeseeretesees 89 4.1.4 Recent Policy Changes ........cc:cccesesssssssessseccssseesecersneeensesessaessseasessessnsessssssnsesssnssessaraseereeeee 89 A.1.5 Levelized Hydro Cost ........cscesscsccsseecsseececccescesscecreceesccseessessssecssessscnsusssersasseesesseneaseneesseees 89 4.1.6 Power Marketing Oversight Unit...eceeseeeeceereesessseseseesescsssesasesacstecnnsesseesessseceneesasees 90 4.2 British Columbia Market...........cccccsccssssccsssececcseseceessscceessnsesessssssssesssusesssseessesesaeeceneeeeeens 90 4.2.1 BC Energy Plan.u......ccccscsssssssccetssscesteececcseeeseccnecsnnsosessneeesacessecssscesesseesssssssosseensnenasenseasseesees 90 4.2.1.1 Energy Conservation and Efficiency 0.0...eeseescesecsseesscessceesessesesscneressenneenseeeeeensees 91 4.2.1.2 -Electricity Policies .........ccsccsscecssseeceseceeseeeecnceeeeseneceserssensssesssseuaeseessseenssseessseseseeeneaes 91 4.2.2 BC HYCLr0.....ccescsssesscssccseseteccnnsceessceetensereneesseesssenscessssnsucnssvsseesseseesesesssessasenssenesssaseeasnanes 93 4.2.2.1.BC Hydro Call for Tenders -Electricity Purchase AgreeMent .........:sccscesestesesenrenes 94 4.2.2.2 Load/RESOUrCE GaP ....cccceecsccesceccsentccecenceccecnenseressuaceesseceereneneeeceesasesessssesssesevesseeseees 95 4.2.3 POWETOX .....cccceceseseeesssensnesersnsnenensnecneaeecesetceeseceseeseeseseosesessssssenseeeeseeeseseseneneeanansesenaseuaeeasonnae 97 4.3 Lower 48 Market .........cccccccsssscccssssscceesscesessecccscsececesssrecesseceeeecssseeeessneeesssseessecessnssceeenaeees 97 4.3.1 Pacific Northwest ..........:ccscccssccsescessessssceescecssecssaecseacessacesenseteaessssesosseeesesesensesessssesssscessenses 97 43.2 California ......cccccsccccssssscesstsccesssssceecseseeeecencuaeeessaeeseesaeeeeeseeeereseeeesssseasessseeeacessaseesaeeeeseeenea 98 4A Market Opportunities 0.0.0...ccecccsecesesesecsseecescnseecesessesssenssecuecneseesseeseesenseeeeesenaeesesseeeeees 98 A.A.1 Marketing CHOICES ........:ccesscesscscceseesessecceteceseecseeceecenseeseeesecesssesssssssesuessecestesseenssseasenseenseas 98 4.4.1.1 Energy Export ....cece secceccssssseessesssssnneseessnsnssnsesenssessseeeeecesssesneseeseesesnananeseeseognennes 98 4.4.1.2 Firrning for BC Wind occ eeeesesececseerscecneecnsceeeeesessasessevssssuessesseeeeeecessosssenaeenseenaees 98 4.4.2 Market Projections .........ccccsccccsssessssstsceseecerenseeesensaneesessaaseesseceseonaeasessassssneeseesneecneeqaseassaeeae 98 5.REGULATORY ISSUES .........cssscssccsssscccccccsssssseccsccasescconsnsesscconcessessscecsesceccosessccsacenssssceceeseseses 101 5.1 OVEIVIOW ...ceeececesscsececceecceeccccesseessecsscssnncasccsacascesecessecsesesseessecssoessesceecsosseenenenecsseneeaees 101 5.2 SE Alaska Transmission System ............ssscccceessssssceeecscsessssneesescessscseseusvensssneeeeseesensenea 103 5.2.1 Jurisdiction and Regulation ..........csccsccsscsesssccceccessseecestesseessseseeseneosenessssssssesessesssssseneneenees 103 SiQ.V.1 -OVOrVIOW oo.cccscsssssccecesssssnacceessracceeceesescceaeeaseescesssacesoessesossaeeesssesensaeucesensessceeeesene 103 5.2.1.2 Regulatory Commission of Alaska........cccssccssccesceeeseseetecereceesreceeseneesseesaressaseseeeanonses 104 5.2.1.3.Federal Energy Regulatory COMMISSION ............:cccsecceesseeseeceseeetseeveseccssesssceneesenteees 106 5.2.1.4 Determination ofJurisdiction over the AK-BC Intertie .............cccsscscccseesserrereeseseenees 108 5.3.Permitting and Related Approvals -Transmission ..........ssccsesscsssscssrssessseessetenseeereeeens 108 5.3.1 Federal and State of Alaska........ccccccsssccsssesccesseceessseneeseessneestseeesesssueseesseesessnsutasesseeeenseeess 108 5.3.1.1.National Environmental Policy Act (NEPA)ProcesS..........:scsssccsssscsssssssscssesestereeesees 109 5.3.1.2 -Presidential Permit...........cccccccscesssssstessssecetececennecsseecseeesseeasssesosesssnseasssesesssseneeeeseees 109 5.3.1.3 Export Authorizations .........ccccssscssesccscecseeeceneceseceeseeesstceesasessasessenersssrecsaseseeasenstents 111 5.3.1.4.Special Use Authorization for Occupation and Use of Federal Lands..............:000 111 Hatch Acres Corporation PR324582.Rev.0,Page 4 AK-BC Alaska Final Report 18-09-07.Doc HATGH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 5.3.1.5 Other Federal Review &Approvals..........esceecesressssscsssssecesseesesessensesenneneeesenenseens 115 5.3.2 British Columbia ............ccccccsscccsecscecensncssneceesseaceesesaeconsnaeenssnssacsssseeesssuseensnsesecesneeessaaeeees 117 5.3.2.1 The National Energy Board ............cccccsscccssssceteeessnesessecsseessseessssssssessseceaseeneneresseees 117 5.3.2.2 System Planning,Interconnection and Operations .........cccsccecsesscesesececseeeneeseesesees 118 5.3.2.3 Siting ReQuireMents...............:scssssecsssesesssssssensssrecesssseccesseeeesesssesesesseeessnnsesesanereenens 119 5.4 Permitting and Licensing -Hydro &Tidal Energy Generation Projects...........sccccsseeees 121 5.4.1 Federal Aencies ........ccccccssccssecececeeseeessseessocesseseesessssssesscacsscucnnscensecsrecssesessueessaeesseereanees 121 5.4.1.1 Federal Energy Regulatory COMMISSION ..............:seesseresseseesesesesssssscnsceassenenserenseees 122 5.4.1.2 US.Forest S@rviCe........ccesssssccccssssenccceccersceceeeessessnecaeeececsensseuseseseseseusrecsverseseeeeesenens 127 5.4.1.3 U.S.Fish and Wildlife Service and National Marine Fisheries Service.........:.sc000 128 5.4.1.4 U.S.Army Corps of Engineers..........cccccsssssececcesesscncesserssseseeeeeceessnnseceseeesesnannaeeteees 128 5.4.1.5 Advisory Council on Historic Preservation..........ccccssssssssessesesseseenseeesaeeseeneeenensenes 129 5.4.2 State Of Alaska......cccccccsscccsssscccesonecceseecesneceseeneeeeeseeeeeseseeaeessaeeseensusesessnesseeeesseceeaseseeeeeenese 129 5.4.2.1.Alaska Department of Environmental Conservation ..........cscssssscssssrnetsesesenesennees 129 5.4.2.2.Alaska Department of Fish and Game and Department of Natural Resources..........129 5.4.2.3 State Historic Preservation Officer .........:ccscccsscssseeeseeceseneresseesaeessnsesesesesesseseeseenreess 130 5.4.2.4 Proposed State of Alaska Hydro Licensing Program ..........:-sssssescsesesesseeseetserenaes 130 5.5 Permitting and Licensing -Other Renewable Energy Generation Projects........s:ssee 132 6.TRANSMISSION LINE COSTS AND ISSUES ......sevsececsesscsesescsceees soseceeesessscscecerenee seececeeseeeaees .134 6.1 OVEIVIOW oo.ecececcccccccesccecceeceeccecesensestessesanaaecnseenecasessseeseeossoeceesenscesssessssseneesensaneeeaeaaeaes 134 G.1.1 Cost Estimates 0.0...cescsssscccccecssenennecessnsececeeseesescaenseseccesnsseesesenssessusessccesncesesessenseeeenessees 134 6.2 Swan-Tyee INtertie .......ee cecsseeneeecescesseeeetecneceseceeececeescsssssssseesseesseeeeeseeesenseseseeseenenees 138 G.2.1 OVOIVIOW 20a eeeeeesccccecsccceennceretsteeecsneeereneesensneeeeesedeeeessesasesesaaesonusesessssevensusecensueseeenaeserenseees 138 6.2.2 Corridor and Facilities:Swan-Tyee Intertie (STI)...cecccscsccsseessseeeseseresecteseneosenesneeens 138 6.2.3 Construction Cost and Schedule ........cccessssssescceceececeeseeeneeeersseeeneeesrecsesseeessassresssssseeseres 139 6.2.4 Arnmual O&M Costs ......ccccesccsssscsecserecstsssssnecscaceesnsoennssesaeeccescconecesneseseecesesssseneceecaserensaeen 140 6.2.4.1 General vo...cccesesccceceeccenenaceccssssaceccescenensanesescesesensceeeseescssaneseeeroessauaeeuesensseueaseoss 140 6.2.4.2 -LIM@ ACCESS ......cscceesecceessncceeesrseenneeetenseceerersueassnseeasesseeeeesssesrasseesseseaseseseeneeeeesseseeeaea 140 6.2.4.3 Facility Inspection and Maintenance Program.........ccssccssstecseessssssssesesessssereeseeeesees 141 6.2.4.4 -Ammlal O&M....cscccccsssccsssssscccssrecsesacecesssecssnecersnsaeescnsaeesessneeesecdaseesessessonsecesessseasenea 141 6.2.4.5 Catastrophic Failures .........cs ceescecsssscessesesescsnscsssessssssensesssseesseesessesenseasneceseeeeesneees 142 6.2.5 Regulatory Considerations..........cccsccscssessreeseescesseeesseseeceeeseaeessaseecensesssssaeessasenseseserenseess 142 6.2.6 Map ....ccsssecccceccsserceceeeesseesssassoereesnaeeeeceserseeesasseessseususessesesnsareneseeesseeaeeseceseananeneseseesaaueaeauaes 142 6.3 AK-BC Intertic ..............ccccccccccecccecssssscsseteeseeccecceeconeoesssereseesessessscusuncuusceseeseseseeseeseuepeens 142 6.3.1.Description of Proposed Corridor and Facilities AK-BC Intertie........ee eee eseseteeeeceenees 143 6.3.1.1 Overview of Information Presented in the Energy Export Report...ccsssecessesenes 143 6.3.1.2 Review of Proposed Corridor and Facilities and Recommendations for Further INVEStIQAtION .........cecsccccesencceettcceetseeceessrseerensneetecendecsesdsessoseaeesesseeevessssssessaeeeeeaaeeeesees 144 6.3.2 Construction Cost and SChedule.........cccccscccesccceseeesseesenersscsesseesesscsssescssensseensnseseeseseeeoess 145 6.3.2.1.Overview of Information Presented in the Energy Export Report..........csesseeseeeneees 145 6.3.2.2 Update Cost Estimate and Schedule...ese eecsessssssecesetcosssesssesessessseseneneesseoenes 146 6.3.2.3 British Columbia Segment ............:cccssccssccccsseestsecscececoetecsteesseesesasesneesseseeseesessereeees 148 6.3.3 Anmual O&M Costs ........ccccccssscccessscecsnecesesseneessaneeconsaneesesncesesenenesseseaessessaseesesseensnsasscenssens 149 6.3.3.1 Overview of O&M Costs Presented in the Energy Export Report ........esssssesesseees 149 6.3.3.2.Review and Update to the Energy Export Study O&M COStS .........escceeceesesseteseeeseeees 150 6.3.4 Wheeling Tariff Costs ........ccccscscsscssssnecseressccscesecesceseeseeeeeeeeessesssseeesecsuseesesssssessneseseneaees 151 6.3.5 Regulatory Approval Costs and Schedule .0.........ccescsccsecccereseeeeseecessesssessvesessseesssesnseseensess 151 6.3.6 MAD ....ccessscsccccsscnnrtaceccessensccecetrecsseeeasceesssesaeaeeecossssnsseeeusscssssusacsesacseuaeeasecsenseeseeeessenseneaaaenes 152 6.4 Other Potential Segment .............ccssscccesseceessseecesssecescneeesessacsecesaceessonseeeeesesssnseneeeess 153 6.4.1 Thomas Bay Transmission ........cccccscsessscenscesssceceoserscecsccesasonsesseeeseessssssssscessseessuseesesesaeennes 153 Hatch Acres Corporation PR324582.Rev.0,Page 5 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 6.4.2 -Petersburg tO Kak...cccccsssscscssssstecsssenscererscessecerseeeescsesesscecssssuseessssusssaseesseseussensessnaensess 154 6.4.3 Metlakatla to Ketchikan .........ccccsssccssseetsscesseececeeeeeseeseretsnesssesnsecerssdsasassaseeseessssesesessenees 155 6.4.4 6.4.4 Other Transmission Segment ..........::scccssccccsesecceeesseesesssssessseasevevsesecesssssosnseeesenseeess 155 6.5 Load Flow Studies in SE Alaska..........cccessscccccsssssseecececeesstssaneeseceesssceeecessessnceeeeessesseseees 155 6.5.1 New Transmission and Generation Facilities ..........:cccccccsscesscecesnccesecetessesssssseesossesesenesaes 156 6.5.2 Load Flow for Year 2011 .......ccccsccsssscsssesetecssseesseeressscstaceessceneecsssecenaeesstacesaasessaaeseeeseneeseees 158 6.5.3 Load Flow for Year 2021 ........ccscssssccssscsssecesscesseecesscesssaecssecnsseeessneecsesessnensuacessuscsseaseseeennes 159 6.5.4 Load Flow for Year 2021 with Exports ...........::ccssccssssessescsscesesseesesrsereeesessesssascseaessnasesneseens 159 6.5.5 Load Flow for Year 2031 without Exports ..........c:cccsscssssscsscececessecesaceessegesseseeseeecseeeesaseones 159 6.5.6 COMCTUSIONS .........:.ccsssccessceseecesssccescccecssacessceccseseseacecceesessassssseceseoseeeesnessneesssesssnesaseeessees 160 6.6 British Columbia SeQMent ..........ccssscccccsssseeseecessesssrsceccevsesssesseusnsnssseesssesereeeeseeeeeeeeseea 160 G.6.1 OVEFVIOW ....ceeccccceccccesesescecessenssesensesnceesenecesanasesssseecnsnssesessesesesesusoeescgecesesnscesesasssasaneneneeeeses 160 6.6.2.Description of Segments and Potential Interconnection LOCations ..........cseseessteseseeeoeeens 161 6.6.2.1 -Northwest Transmission Line........:..csscsescessssecsssccerererseesereneteecesecessesseersnessasessseeusasen 161 6.6.2.2 Interconnection to AK/BC Bordet......cccesesccssccsreretetseetorersneeseceseesnessnersueesenssessusanes 164 GC.6.3 MAPS ....cececcccccesssssresccesessrteceeceeeenstacesecssssseaseeesenscaeaseeesossssnesssesscsseseaseeececeesausaeueconeseseusessanee 164 7.POWER GENERATION COSTS AND ISSUES........s00008 stecececeesssscssscssssososones steeeeeceeeasssccsscsseces 171 7.1 OVOIVIOW ...ccc ccceesesecccnenesscceccussssceccenececeececcesseeceeacaneeesesseneseaeeeesscsceseesseseceeaessersenseeeetes 171 7.2 Potential Power Project Development.............ccsccccsseccsseecesseeeesceecseeessseeeseeecosseanessaceseees 171 7.2.1 Existing,potential retirements,and planned new projects (capital and O&M costs)..........171 7.2.1.1 -Existing Hydropower Projects ..........:ccsscscseeceseeeeenetencesceseneceesesessseesusesseseesseaseeesnenee 171 7.2.1.2 Existing Diesel Facilities ....0.....ccccsccsseccesscerenecesceeeseteesscenessceseeessseeesteeasesensenenenteeas 173 7.2.1.3 Potential RetireMents............ccccsscccssescccssscecessseeeerssensesetaneessesseeeseseasesssesassessasesessaeees 173 7.2.1.4 Potential New Hydropower Projects ...........ccsceesceeessessseessscsesesesesersessrssneanenenatees 173 7.2.1.5 Potential Wind,Tidal and Geothermal Projects ............::ccssssesceceseessecessesssceeeeneneree 174 7.2.2 Generation Potential at New Project .........::ccsccesscesssscseccscescesnessneecssessesetesorercenaseatenanene 175 7.2.2.1 New Hydropower Generation ...........cccccsscccsssscesscceseeceseeerseeeeaseesseesseacossesseneesssesnes 175 7.2.3 COSt Of POWEF.......cccccescccesscccsescseccsessecessceccsssseecsesaceusnaneeeseneasesecsesereneeseecesenesesesseesessesooenes 177 7.2.3.1 New Hydropower Costs .......:cccsscccsssssscsssssceessseccesessceessecaeesesneecesseeesessceeesecseeerseenass 177 7.3 Potential Power Project Not Proposed For Interconnection Within SE Alaska...............180 8.COMPARATIVE ANALYSIS OF DEVELOPMENT .......ccccsccccseeccccrscsessscees secccecesesesscescesoscssenenes 182 B.1 OVOIVIOW .....cecccescsceecccccsccccececsanssseceseecscecscnscansaucscnscescesesecneceaczensscseeeereecesenensacaesseessesens 182 8.2 Description of the Economic Analysis Methodology ............::ccscccceeceeeseetecseerenceeesseenees 182 8.2.1 Least Cost Plan without Exports ............:csscccssscessecssssesssceesseeeseeeessaeceeecnnessasereneeseseeaessesess 183 8.2.1.1 Formulation of Generation Alternatives ...........ccccscccsssscccsssscessssecessterecessseseeesseeeeess 185 8.2.1.2 Modeling of Generation Alternatives ...........cccccssccssssssscseesecessneeesesestaeesnescnseseneetenes 185 8.2.1.3 Evaluation of Generation Alternatives ..........c::cccsssccccssncceceseceeenseeesseneeeseaneeersneeeeoes 185 8.2.2 Least Cost Plan with Exports ..........c:cccsccsssscssssccessecessessoteessecessnceesscesnaeecsaeeessesesneeonoeeeeceeeens 185 8.2.3 Sensitivity Analysis ...........cccccccsscesccesscsssccssssccnseessssesseseesencesusesseaseseaeecsaeessasessneesnosereeeeenss 186 8.2.4 Outline of the Planning Too!Used .0........ce esesesecseeseeceserseeseceneeeeesesnessesesessonsosseseeseeesess 186 8.3 Existing Generation and Transmission Infrastructure ..........::cccsssscceesssccecssseccessnsecssessees 192 8.3.1 Hydro Generation ..........cccccsscessccssscessccssecessscscsseeesnsesseeeesssesseeseseaeenssessaesesassssusessesoosensones 192 8.3.2 Diesel Germeration ...........cccscccsssecssscessecessecesnccsenscsssacesacessscessaaeceeasensaeeenaesenesessneesonareseaesees 193 8.3.3 Existing TransSMissiOn ........:.cccccccsessecsceresseescsecessesesssseaaececsonssseueceecossesseuseassesessseessasesseasnees 194 8.4 Planning Parameters ...........cccccssccceececessecesccceseccessceeecseeeescesessceesseesesseesssseseensessneessseesens 194 8.4.1 Planning HOriZON .........ccsccesccssscecescesssscssceescacessacecsseeceseccnseeceoeeesteeeessastsasesasasessasesnesonaees 194 B.4.2 -ROSCPVE oo.cccccccccecsccecscsesccssesceescstsesesssaausauacaacanaaaanenacseagegsecssseeseeesseseessscesesessesssseseseseneneened 195 8.4.3 Unserved Energy .........cccssccssssssssecsscesseeesseesssccesscecssacessscevsccessneecsaecnaeessssssssesessesesseesesaesens 195 Hatch Acres Corporation PR324582.Rev.0,Page 6 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 8.4.4 Emergy LOSSCS 0.0...eee eesscecesescecesneecsssssesssnseueseeesceeseeeeeseaeesesseaeensssesessesseseseneesenenaeeseneeeees 195 8.4.5 DisCOUNE Rat@..........ceecessssstecceeseseceesesessssceeessssssesusesevseseserecsccaceeseeaaeseseenensseneeenereseeeaneeees 195 8.4.6 -Escalation.......sccssessssssccseccsscssscesessscsscesseneesecesscceeeensconessssssesesssesssesenssnsesessseesseseasoesnanas 195 8.4.7 Reference Year for Present Value Analysis .........:.ccsccsscccessscesescsceeeeccaeeesassescssnesessesessesesees 195 8.4.8 Capital and O&M Costs of Transmission Lines 20.00...csesesseeeesscsssesessesssssssssensessenseeneenaes 196 B.4.9 Fuel Prices.......c.:ccssccssscssssseessecsssecesnsssnscssecessncceseeesseaseasecsesdsssseossascssesossesossessusessesessnseseees 196 8.4.10 Cost of Energy from Swan Lake and Tyee Lake Hydros............seeseeeeseeseceereeereeeeetseessvees 197 8.4.11 Cost to Society of Greenhouse Gas and Other EMissions..........csssssecssecsssecseeeeseeeeseenees 197 8.4.12 OWMESSNID.....ccccssccesscesssessssccsssscessceraccsacscssaceeseecssceeseeenessssesassessessssesessescsessesessseassaneaconse®197 8.5 Development Projects COnsidered .........::.csccsssccececeseceseceececeeceeseeesesesseessacsasceeescneesnaseees 197 B.5.1 Hydro Projecto...cecesseseecceeccsssseenerssssecesessessnssceseeacessscssetesecesesssuaeesccesesneaesesseeesnsnueeess 198 B.5.2 Diesel Units...ccsscssssssssecssccsssessacteeeeccsecesceseceeeeeeecsseoneesseessaseseesersesssresessusssesesensneeneees 199 B.5.3 TrAMSMISSION ........ceccccecessessecceeeseeseneceseeessecseeecasceseeensesessesusescsavseeeasseucecereseueeeeseseespaneeeeeee 199 8.6 Capacity and Energy Balances ..........:ccescceccssseceeeseecceesseeecceeuseessesseasensssseceesseeneasseseees 200 B.6.1 Kak.cc cccccccssscccsssscscsssssccscsceccssnaeecsensesscsucessauaeessesaceceeaceseneneeesessaeeseessaceonseseseassuseeeseenee 200 8.6.2 Petersburg and Wrangell ..........ccsccsssscssscesscesssesecseceseeeeecseetscersnersceeseseseessessaeseasessuseeesens 200 8.6.3 Ketchikan and Metlakatla ...........ccccccsccssssesssnecssneesnaceeeeeesseesssseeesseecseesosessseensnsseseneseneeesns 201 8.6.4 -POW.eeeeesesscecscsensccaccccececacececeeeeeeeeeseeessesseeessanneseneuesdasasaeasasceasaseneesscuseescuseeseasesesesesentere 201 8.6.5 SE Intertie Development Scenarios Considered to Date ..........cesssscssssseesseersasenrereneeseenees 201 8.6.6 SE Intertie Segments Currently Under Development with Federal Funds to Date ..............201 8.7 Development Scenarios in SE Alaska without Exports ..........sccscsseseeesessseesceseeeerssesenes 202 8.7.1 Generation Expansion Scenarios for the Tyee REBiION 2.0.0...ssesesesseecsseeeeserneneueresensenens 202 8.7.2.Generation Expansion Scenarios for the Swan R@giON ..........eeesecetsssssseeeessecesserteeennsnseeees 203 8.7.3.Generation Expansion Scenarios for the POW Region ...........::csseresesteesseesssecessessneeeeseeres 204 8.7.4 Connection of the Swan and Tyee Regions ..........:ccccssccccesseeccesscceersscecerseeeecesssasesesaseseseaeas 205 8.7.5 Connection of the POW Region to Other Regions ..........::.sccecesececeseeesceseesesesesersenerreesaesaes 206 8.8 Development Scenarios in SE Alaska with Exports 0.0.0....ceseeesscessesessescsseserseseoneneeses 207 8.9 Items Not Included in Economic AnalySis ..........::ccccsscceeeesseceessscceceseeerecsseeeeesesaeeeersaseese 208 8.10 Sensitivity Analysis ...........:ccccssssccccsssccessceccssnsesesnsaeeeecsceesensnseecessseeesoesesseaearereusenseeeess 209 8.10.1 Low and High Load Growth ........:ccscccsssccssccssecesecesaceessesceseeeseceresdasesaseeseessssesceseeseereseanenes 209 8.10.2 Capital and O&M Costs INCreaSe......sees ceseessseceensesnsecessenesceersrsesasecassscesreeensrerereeesnese 2108.10.3 Fuel PriceS......cccscccssesssessssesssssscssscesssescssecssssenseseesesersecessesneseestenerseeeneesseesseessuscsessseseasesanes 210 8.10.4 Export Price and Capital Repayment Period .........:...:::sccsseceseeseeceeeceeeeseeesseeeteeseeesetssaseasones 210 8.10.5 Discount Rate..........ccccssscccssscecccssreecessecsessneeessseseeessssecesssucesssseeesesssssensssusscesseasceseueaseneneees 211 8.11 Estimated Avoided EMissions...........:ccccssssscccesseensceeseeteeseeeececescasseseseesseeseseesesccenseeenee 211 B.11.1 Emission Factors......ccccccccssssnecccecesessseeeceseseeasaescesesssneceeascossnsseeeeeesssssscuaeeeesossesnsnereeeeeesesnees 212 8.11.2 Electricity Required for Conversion of Oil Fired Heating Furnaces.........ccsssscscsesessseeesescees 212 8.11.3 Estimated Avoided Emissions.........c:ccsscccsscessssssssessssessceesssesscnseeseceeseeessasesssasossuseosecesneesens 213 9.CONCLUSIONS AND RECOMMENDATIONS .......csssscescssccosccrccoecoee saeesessesaceeaves 244 9.1 OVELVIOW oe eeceeesetsceacecececceceecceceeececenecenseseeecssesenaanccaecsecseceeceneceedeeeesecseoseseseavseesseesenees 244 9.2 COMCIUSIONS ........:ccssssccceessescesssececssseeecssacecsesseceessesaeecssanecsesssaesecseseeecesescasesesneeseesnuenes 244 9.2.1 Proposed Transmission and Generation Projects ...........::cssscccsccesesscesescosseesseesessesesseesesesee 244 9.2.1.1 Swan-Tyee Intertie (STI)0...es eesccsssssecessscecvsneccesssssssessssseessseesscssusscceeaeeceseeaseeenes 244 9.2.1.2 Other Line Segments in SE Alaska..........c:ccccsscsseecssesesrceceseececeeeesenessnaesssuaesenassensoues 245 9.2.1.3 AK-BC Intertie.......cc eesensscsssessceeeseecesacanacecnecceeceeeeesaeeseresescescesesauansoasscseseeersnsanes 245 9.2.1.4 Power Generation ............c:ccceesccessecceesseetenrececenseeeseceeseresssceesssesesssssaeerersaeeressesseesee 245 9.2.1.5 Un-quantified Benefits Resulting From Interconnected Electric Transmission SYSCOIN...cceccccesssennescesserersececcecessucceeceessessaseeesecsssseesseesssscssseeaesscsesseuseueeeceneneseeenateese 246 Hatch Acres Corporation PR324582.Rev.0,Page 7 AK-BC Alaska Final Report 18-09-07.Doc HATGH ACRES 9.2.2 Business Structures,Southeast Alaska Market,External Market,and Regulatory Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report ISSUES vicceeecccccccccusesssessesccecceescaessseeseeeeeeeeeeeeeaneeeneeeeeseeeeeseaeeaeneeeeeseeeeesdseaueaeeeeseereeseseeeeeeseese 246 9.2.2.1 Business StructUres ...........cc ccccccceceecsseeecsessesersesesceeeeeeauanauauaaeeceesaeseuscssecaseseseeeeeeeenens 246 9.2.2.2 Southeast Alaska Market............cccccccsecscsesesesesssssnsssssscsacseususcuscescsagereeeecsasoeseesessoseees 247 9.2.2.3 External Markets .........:cccssscccssssccessscesssscessssescesceneeenseseeessnacenessneessesesarsessessossesensenees 247 9.2.2.4 Regulatory ISSUCS .......:ccscccscercserescetecesesteeceneereecesesssuvesesssscssscnesessesensessesssesseesenesaess 247 9.3 RECOMMENATIONS .......cccccccccccccccccessesssessssceesscenauseeassesecsecccsceeceeseceeesseeseecetecerentensseseeuona 248 9.3.1.Phase II AK-BC Intertie Feasibility Study Tasks ............:cccssecsseesecesrereeeresesseeteseesssesuesseesseaes 248 9.3.1.1 Overarching Issues and Tasks .........:ccsccseccessssssscceseececerecetessaeessssessssnsnseesseeeeneesesaees 248 9.3.1.2 Business StrUCtUre...........ce ccecccccescesecececsesssescscssncnsasnsnsccesccessseeaseaeseneneesesseasssssessenens 248 9.3.1.3 Southeast Alaska Market.........ccccccsssssccscssssscccsusssscccecsevesccosereasscuavascceensocensensosesseuanses 248 9.3.1.4 -External Markets ......cccccssccscsssssccsssccsseserecseececssssecsesnsecesnausecsceeeceseceesrsoseetenseeceteeeaas 249 9.3.1.5 Regulatory ISSUCS .........cscseeeeeseresscesenoesseeveesnsnssssssucsssesnsesaseeerssesessesessseseeeeessneeeaness 249 9.3.1.6 Transmission Line Costs and ISSUCS..........cccccccesssccssseeecssccecessnceceecnaeeseeeseneeesseaceosnsas 249 9.3.1.7 Power Generation Costs and ISSUES ...........ccsccccecessesssecsecsssecceceeecenecceseeoesosessanseseess 249 9.3.1.8 Computer MOdel ........ccsccssssssecreseeceeteesseseereneeseceneesssssrsessesssessessseessuecarseesonsreeeenaes 250 9.3.2 Actions for AEA with Assistance by Contractor ...........cesescsssssesscsssscesssssesascesceneseneeeeeeenees 250 9.3.2.1 Proposed Business Structure ..........cccsscceseccesesesesessncecseeecsnsceseessssusenssuseseecssresereeessaees 250 9.3.2.2 Determine Level of State/Federal JUrisdiCtion..........:cscccssstscestcetseeeereressnsossesonseceonees 251 9.3.3.Monitor Actions by 3 Parties and Consider Need for Additional Independent AMAIYSES!...cssccssscessccrseessessceeseceseccceecsseeconseeeseessaesseessesseesseesseseessnsaseeesseesseonseessaessecnecnsegees 251 10.BIBLIOGRAPHY ............66 soeeeseeenssanssssanssesancces shenessscessesssasesces sovescseenaccccessccccsconessessssscossssses 253 11.LIST OF PREPARERS .........sssscccossssssscccescsees seenessscenssccenesscansecoes donsssceneceasssscosecees eeeesccssssecsecees 259 Hatch Acres Corporation PR324582.Rev.0,Page 8 AK-BC Alaska Final Report t8-09-07.Doc HATH ACRES Table 1.1-1 Table 1.1-2 Table 1.1-3 Table 1.1-4 Table 1.1-5 Table 3.2-1 Table 3.2-2 Table 3.2-3 Table 3.2-4 Table 3.2-5 Table 3.2-6 Table 3.2-7 Table 3.2-8 Table 3.2-9 Table 3.2-10 Table 3.2-11 Table 3.2-12 Table 3.2-13 Table 3.2-14 Table 3.2-15 Table 3.2-16 Table 3.2-17 Table 3.2-18 Table 3.2-19 Table 3.2-20 Table 3.2-21 Table 3.2-22 Table 3.2-23 Table 3.2-24 Table 3.2-25 Table 3.2-26 Table 3.2-27 Table 3.2-28 Table 5.1-1 Table 5.4-1 Table 5.5-1 Table 6.1-1 Table 6.1-2 Table 6.2-1 Table 6.2-2 Table 6.2-3 Table 6.2-4 Table 6.3-1 Table 6.3-2 Table 6.3-3 Alaska Energy Authority -AK-BC intertie Feasibility Study SE Alaska Final Report List of Tables SE Alaska -Geographic Areas,Communities and Electric Utilities 0.0.0...25 SE Alaska -Existing (E)and Proposed (P)Transmission Line Segments .............6+25 SE Alaska -Existing (E)and Proposed (P)Generation ..........ccescsessscessssenseeesereesees 26 Northwest BC -Proposed Transmission Line S€gMent..........::ccccecseceessreeeeeseneesens 26 Northwest BC -Proposed Generation ............:scssscsssssssssccesaccesssessseeeeseeeensesessnees 27 Ketchikan -Annual Sales and Generation.............:sesssesssssesssecssresereeceereessesenenees 54 Petersburg -Annual Sales and Generation............cccccsseessescessscsesssseseeseeesessesenseees 55 Wrangell -Annual Sales and Generation.............cssssscssceesesseneeseecesssenesesesseensnaeees 56 Kake -Annual Sales and Generation ...........::cccsccseceeeccesneessesesneessesenascnsccssoessenanes 57 Metlakatla -Annual Sales and Generation ..........::cesscecsseecesseeesseceseseeeresesnesessasene 57 Craig,Thorne Bay,Klawock and Hollis --Annual Sales and Generation..............58 Hydaburg -Annual Sales and Generation..........ccccccssssssessssssreeseceeseesseseeeseeeeneees 59 Coffman Cove -Annual Sales and Generation ..........cesecsssscsscsscesssecessesceseeseserenee 59 Naukati Bay -Annual Sales and Generation ...........csessccsssscessecsssesssnesceeessesseeesees 60 Whale Pass -Annual Sales and Generation ........::ccssccceseceeesceereceesseessessesssenevseeens 60 Annual Electric Heating Requirement ..........:ccccscccceeseceeeessecesesresessssseasessuceseasaees 64 Anticipated Commercial Electric Heating COnVersiOns .........cscccsssssseeeeteesseeeesnees 64 Principal Forecast Parameters -Reference Case ........cscccscscessecssesesseseeereseeseeeseees 65 Monthly Sales Distribution -Ketchikan .........ceeseeseeeecssssessessesscesesecsesesenseeseeenes 67 Monthly Sales Distribution -Petersburg ............:cccessesessscsesssesseseseesecsseteseeesseeeess 68 Monthly Sales Distribution -Wrangell...........cccescssscessscssseesssrssseeessnesssseseeseeeeenes 70 Monthly Sales Distribution -Kake .........ceeeeecsecessscessecseeseseesseeceeseseeesseessesenseenees 71 Monthly Sales Distribution -Metlakatla.........ce ceecsssesestesseeessesseeceseasnnseseeseeeeeees 72 Monthly Sales Distribuion -Craig/Klawock/Thorne Bay/Hollis..........:ccccceseeeeeeee 74 Montly Sales Distribution -Hydaburg «00.0.0...ec eeeeeeesecesseessessssssssessccsssesecsaeeenenes 75 Monthly Sales Distribution -Coffman Cove......ccsessssssscessecesscssssssssssscssesenesenes 77 Monthly Sales Distribution -Naukati Bay...eee seeectseresceeetsssseessseersesenesenes 78 Monthly Sales Distribution -Whale Pass ..........::cssccssccssssesscesseseesorsssssssesenseereees 80 Net Generation -Reference Case ........c.ccccccsssseceessnceeeeseeesesceeeccssseeeosseeensseeeeeeeens 81 Principal Forecast Parameters -LOW Case.......cesessscsscessscsssccsssssssrssscnseseeessssseneees 82 Principal Forecast Parameters -High Case.........sesceccescesssseesssseessessesseesneeneeenees 83 Net Generation -LOW Case.........c:cccssscsccccccccccccecceecceeseceseserssessessssnssonssessceesseesones 84 Net Generation -High Case.........cccesssccssccesesceseceeeseecesseesessesesseceeeseesseseeseeecseteres 85 Typical Licensing and Permitting Requirement ...........cc:ccssecscssseeesseseeeseseeeneees 101 List Of PUDIIC LAWS ......cesccesscessseesssccessecseeeesseessaeeeseccecseeeronsecesscesssseassesareescseeees 126 Renewable Energy Project Requirement ..........cescssessssecsscccsssesseescessneseeeseeeees 132 SE Alaska -Existing (E)and Proposed (P)Transmission Segment ...........:sesesees 136 Transmission Segments with Estimated Costs ........:eseccesssesessescssesssseesesssceseasenees 137 STI Construction COSt ........c cc cssssssccceeececscceeeeteessesseesseessesssssnsaneunnseneanescarscesseeseness 139 STI Construction Schedule ..........cccsscccsseecsseeceeneceeeeeeraeercneeeessesosssesesreseneesenerees 140 STI Estimated Annual O&M Costs (2006$).........cssecccsssecceecssecceenstcesecsseeeeesseeeoeee 141 STI Estimated Catastrophic Failure Costs (2006$)..........:ceseeccceseeseseeasenseesasonsees 142 AK-BC Intertie Segments -Location and Length ..............scesecesesseseeseeeeseseoneeeeees 143 Estimated Cost of AK-BC Intertie -Tyee Lake to Border ............::eecccseceeeeeereeeeeee 147 Summary of AK-BC Intertie Estimated O&M Costs.......ccesscsscssseescnscesscorseneens 150 Hatch Acres Corporation PR324582.Rev.0,Page 9 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES Table 6.3-4 Table 6.6-1 Table 6.6-2 Table 7.2-1 Table 7.2-2 Table 7.2-3 Table 7.2-4 Table 7.2-5 Table 8.1 Table 8.2 Table 8.3 Table 8.4 Table 8.5 Table 8.6 Table 8.7 Table 8.7-1 Table 8.7-2 Table 8.7-3 Table 8.7-4 Table 8.8 Table 8.8-1 Table 8.9 Table 8.10 Table 8.11 Table 8.12 Table 8.13 Table 8.14 Table 8.15 Table 8.16 Table 8.17 Table 8.18 Table 8.19 Table 8-20 Figure 1.1-1 Figure 1.1-2 Figure 3.2-1 Figure 3.2-2 Figure 3.2-3 Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Regulatory Approvals,Schedule and Cost ..........:sessscesssecesssecsseecssesesereesersceenees 152 Estimated Cost -Skeena to Iskut (September 8,2006).............::cccesseeesesseeseeseeees 163 Project Schedule -Development Milestones «0.0.2....:ccsessessssseesseessecesseceerneoees 163 Existing Hydropower Project .........::cccssccsseccceseceseeecesnecesseeesseereesesoessseesuaeonseeese 171 Potential Hydropower Projects ........::cccssceescceseseecssecceseceesseeserseeseseesessaseesaesnseesees 174 New Hydropower Generation .........ccsecsesesseceeeessccesesseesccssesecscsssesseesesascnsesenes 176 New Hydropower Cost ASSUMptiONs ...........esscecesseeeesseeessscessesseeeseneeesseeenseasenees 178 Comparative Costs -New Hydropowe @..........:sscsssssecsssseesssesesrsssnessceesesenssesseese 179 Generation Capability of Existing Hydro Plants..........0..cceeeceessesseenereereesereensens 217 Characteristics of Existing and Committed Diesel Units...eee eens 218 Characteristics of Existing Diesel Units in Prince of Wales......0....eee eees 220 Determination of Fuel Prices..........ccccccccsccsesenecsseeceneceeessaeeceeseeecesseraeecearenneeneeees 222 Generation Capability of Candidate Hydro Plants..............eeesesccseeseseeeeeeeeeeeees 223 Comparison of Candidate Hydro Project Unit Cost...cee ceeeeseeecseeeeeeereeenes 225 Characteristics of Candidate Diesel Units.........0..ccccccccccecceeseeeseeeeeeeeeeeeeeeneneeees 226 Cost of Expansion for the Tyee Region...........:.::::ceeeeeeeeeeeeteeeesesnenneasssnseeeaeenees 203 Cost of Expansion for the Swan Region...........seccecsecseceereereececetereeseseseescscsescees 204 Cost of Expansion for the POW RegiONn............:cccececceeeeseeereeeceoeeeeeeeaauaeeneneeeees 205 Cost of Expansion for the Swan Tyee RegiOns...............es eeeesscsssentenenetereeneaeneees 206 Capacity and Energy Balance with only Local Resources,Reference Forecast, KAKO...ccccceeeecccceeeccccecseesceceeeusececeececssesssecssseccssececsseessseeecaseeseessessersersueeteneesseasenaes 227 Benefits of Power Exports...........cccccccessessssseeceesecceeecceccnauaeseeteecececeeeeeaaaueneserees 208 Capacity and Energy Balance with only Local Resources,Reference Forecast, Petersburg and Wrangell.........cccccccccccscescceseeeseseeeesceseeeseesceceeceseaeeneeetesenetateeseeaeeaes 228 Capacity and Energy Balance with only Local Resources,Reference Forecast, Ketchikan and Metlakatla...........cccccccccccssessessesserecescecsesseceecaecaeeseceeceesseeeseeeneenes 229 Capacity and Energy Balance with only Local Resources,Reference Forecast, POW...eccccccccccccecenscucecseeescesenscaesescussauaaeaeecesesesusaaeeneeseaeceeseenssececeesessensuneeresesesenaas 230 Unit Additions,Reference FOrecast...........ccccccccccsssssecsssccescsecesseeeceeeensaeseenaeeeneeees 231 Unit Additions,Low Load Forecast...........c:ccccccccccsssceccceeeseeceeescssececsueeensesensaeeaes 232 Unit Additions,High Load Forecast.........c:cccecccsscessccssscecseeesseeeeeecseceseeasenteaeeeeeaes 233 Summary of Results,Load Growth Sensitivity .....0....cccccecseseeseeeeesteeeteeneeenesnrees 234 Summary of Results,Capital and O&M Costs Sensitivity...ee eeeeeeeeeeeeeeee 235 Summary of Results,Sensitivity to Changes in Fuel Price...cc eeseseseeeeeneenes 236 Summary of Results,Sensitivity to Export Price and Repayment Period...............237 Estimated Emissions for Cases without Conversion of Oil Fired Furnaces...........238 Estimated Emissions for Cases without Conversion of Oil Fired Heating FUIMACES.......cccceescccneeecceeeeecaeeeeccsceeeeceeseesceeeeeceeeceeeeecneneeeaereeaneecenseseeennescsunes 239 List of Figures AK-BC Intertie Feasibility Study Area...ccc cecessecesseeseecsseeeanecesersresssessesenssceesees 38 Southeast Alaska and BC Transmission Syst@m..........csccccssccessscessseeesrecceseeceeeeeeenees 39 Electricity Price Threshold for COnversiOn..........ccsccssscccsscccsseceeseeceeeceeneceeteceetseeess 62 Relationship Between Heating Load and Heating Degree DayS.............::ceseceseeees 63 Heating Degree Days -Southeast Alaska..........cccccscccsssccesseeesrneeeseeceecersaceseseeenees 66 Hatch Acres Corporation PR324582.Rev.0,Page 10 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Figure 3.2-4 Figure 3.2-5 Figure 3.2-6 Figure 3.2-7 Figure 3.2-8 Figure 3,2-9 Figure 3.2-10 Figure 3,2-11 Figure 3.2-12 Figure 3.2-13 Figure 3.2-14 Figure 5,4-1 Figure 6.5.1 Figure 6.5.2 Figure 6.5.3 Figure 6.5.4 Figure 7.2-1 Figure 8.2-1 Figure 8.2-2 Figure 8.1 Figure 8.2 Figure 8.3 Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Seasonal Consumption Patterns -Ketchikan 20.0.0...escsssesessesescceeecseeeseseensenseeenee 67 Seasonal Consumption Patterns -Petersburg ........csscsscssscsssccssssssesreessecnneeeseeeees 68 Seasonal Consumption Patterns -Wrangell .........ceecesssssssesssescereecssseserseerseeenee 69 Seasonal Consumption Patterns -Kake@........essscccssssscessssscseesssesessneecensseeeseseeees 71 Seasonal Consumption Patterns -Metlakatla .......ce cessssscesccsseesreccreseseesseeeseeeees 72 Seasonal Consumption Patterns -Craig/Klawock/Thorne Bay/Hollis «00.0...73 Seasonal Consumption Patterns -Hydaburg ............ee eeceeeseseessscesscceeseseeneeeeseseeee 75 Seasonal Consumption Patterns -Coffman Cove .....c.ccceccsecssssresessecsssseessesesseeeees 76 Seasonal Consumption Patterns -Naukati Bay...........cceccssccsesssseeeeeseseesereesteeens 78 Seasonal Consumption Patterns -Whale Pass.........c.scsssesssssessssnsseneseeessesceesceevesees 79 Net Generation Forecast -All Sensitivities ..........cc.scessseceeseeeesensecensessssecesseeeeees 86 ILP Licensing Process and Schedule 0.0...eessesssseessesessssesseesssecsseeesereesenserenes 125 2011 Peak Demand..........cecccccccccessesecssecssenecseeeseceeecaeceeesieceeeeneensecsseaeseeesaesnrersaees 164 2021 Peak Demand..........ccccccccesccssecsccesseecseececeesseeeeeeeseeecneeteereaeessseseeseenesesessaeena 165 2021 Peak Demand,Export.........ccceeccceseeecseeecreeersecseeenaeseeeseseceseeeneesesseaseenaerages 166 2031 Peak Demand...........cccccccccccscccessceeeeteesereeeenecesseaeeseneeeenieenseeecesnnertetensseeseeeseees 167 Map of SE Alaska Existing and Potential Hydropower Projects..........csscsssseeees 172 Exhibit 8A -Scenario Definition Page............ees sceccceessenererersesssseeceoesessseesesereess 190 Sample Output Under Average Hydrological Conditions .........eesseesesseeeeeeeeee 191 Annual Energy Generation Without STI...ec ceeeeceeseeee cee eceeeeeseeeeeeseeseeeraeeees 240 Annual Energy Generation With STI...ccc eeeesseceeeesseeerseeneesresetseereesesesssessenens 241 Export Energy Under Average Hydrologic Conditions............ccccceceseeseeneeeeees 242 Hatch Acres Corporation PR324582.Rev.0,Page 11 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES_RETTTT TEETHeenentmnttUNttemeteteneH Appendix A Appendix B Appendix C Appendix D Appendix E Appendix F Appendix G Appendix H Appendix | Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska List of Appendices Maps Business Structures Markets and Market Structures Regulatory Transmission Power Generation Development Scenarios and Model Loads and Resources SEC Mid-Winter Meeting Presentation Final Report Hatch Acres Corporation AK-BC Alaska Final Report 18-09-07.Doc PR324582.Rev.0,Page 12 ACHP ACMP ADEC ADFG ADNR AEA AEL&P AK AK-BC AK/BC Border ANCSA ANILCA AP&T AS BA bbl BC BC Hydro BCTC BCUC BO BPA CAA CAISO CCCT CEA Agency CEAA CEQ Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska List of Acronyms and Terms Advisory Council on Historic Preservation Alaska Coastal Management Plan Alaska Department of Environmental Conservation Alaska Department of Fish and Game Alaska Department of Natural Resources Alaska Energy Authority Alaska Electric Light &Power Alaska Alaska-British Columbia Alaska/British Columbia Border Alaska Native Claims Settlement Act Alaska National Interest Lands Conservation Act Alaska Power &Telephone Company Alaska Statute Biological Assessment billion barrels of oil British Columbia British Columbia Hydro and Power Authority British Columbia Transmission Corporation British Columbia Utilities Commission Biological Opinion Bonneville Power Administration Clean Air Act California Independent System Operator Combined cycle combustion turbine Canadian Environmental Assessment Agency Canadian Environmental Assessment Act Council on Environmental Quality Final Report Hatch Acres Corporation AK-BC Alaska Final Report 18-09-07.Doc PR324582.Rev.0,Page 13 BATU AGES CFR CIFT COE Contract CPCN CPV CWA CZMA DOC DOD DOI DOT or DOT/PF DSM EA ECPA EIA EIS EMA EPA EPAct 2005 ESA F or FY FDPPA FERC FLPMA FPA FSH FWS GHG G&T Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Code of Federal Regulations Cost of Incremental Firm Energy Corps of Engineers The contract between AEA and Hatch for this project Certificate of Public Convenience and Necessity Cumulative Present Value Clean Water Act Coastal Zone Management ACt Department of Commerce Department of Defense Department of the Interior Alaska Department of Transportation and Public Facilities Demand Side Management Environmental Assessment Electric Consumers Policy Act,1986,amended the Federal Power Act Energy Information Administration Environmental Impact Statement Environmental Management Act (CA) Environmental Protection Agency Energy Policy Act of 2005 Endangered Species Act Fiscal Year The Four Dam Pool Power Agency Federal Energy Regulatory Commission Federal Land Policy &Management Act ; Federal Power Act Forest Service Handbook Fish and Wildlife Service Greenhouse gas Generation and Transmission Final Report Hatch Acres Corporation AK-BC Alaska Final Report 18-09-07.Doc PR324582.Rev.0,Page 14 HATGH AGEN Gwh Hatch HFO IGCC ILP lOU IPEC IPL IPP IRC IRS ISO JAA kcm KPU kV KW kWh KWETICO LLC Lower 48 LUD MoE MOU MP MP&L MW MWh NEPA NERC Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Gigawatt hours Hatch Acres Corporation doing business as Hatch Energy heavy fuel oil Integrated Gasification Combined Cycle Integrated Licensing Process Investor-owned utility Inland Passage Cooperative Inc. International Power Line Independent Power Producer Internal Revenue Code Internal Revenue Service Independent System Operator Joint Action Agency Thousand circular mils Ketchikan Public Utilities Kilovolts Kilowatts Kilowatt hours Kwaan Electric Transmission Intertie Cooperative,Inc. Limited Liability Corporation The contiguous US states Land Use Designation Ministry of Environment (BC) Memorandum of Understanding Market Participant Metlakatla Light &Power Megawatts Megawatt hours National Energy Policy Act North American Electric Reliability Council Final Report Hatch Acres Corporation AK-BC Alaska Final Report 18-09-07.Doc PR324582.Rev.0,Page 15 HATCH ACER Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report NESC National Electric Safety Code NFMA National Forest Management Act NFS National Forest System NHPA National Historic Preservation Act NMFS National Marine Fisheries Service NTL Northwest Transmission Line NOAA National Oceanic and Atmospheric Administration OATT Open Access Transmission Tariff OHMP Office of Habitat Management and Permitting (DNR) OPMP Office of Project Management and Permitting (ACMP in DNR) O&M Operations and Maintenance PCE Power Cost Equalization PEP Provincial Emergency Program (BC) PG&E Pacific Gas and Electric PM&E Protection,Management &Enhancement (measures) PMPL Petersburg Municipal Power &Light PNW Pacific Northwest POW Prince of Wales Island PSE Puget Sound Energy PUD Public Utility District PWK Petersburg Wrangell Ketchikan RCA Regulatory Commission of Alaska REAP Resource Expenditure and Acquisition Plan (BC Hydro) RFP Request for Proposal RHA Rivers and Harbors Act ROD Record of Decision ROW Right-of-way RPS Renewable Portfolio Standard RRPM Regional Resource Planning Model SARA Species at Risk Act (CA) Hatch Acres Corporation PR324582.Rev.0,Page 16 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES SaRCO SE SE Alaska SEC SEIS SC STl SUA SUP TC TLRMP TTRA USC USDOE USFS USO WARS WMLP Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Species at Risk Coordination Office (CA) Southeast Refers to the portion of Southeast Alaska included in the AK-BC Intertie Feasibility Study Area (see Figure 1.1-1) Southeast Conference Supplemental Environmental Impact Statement Scheduling Coordinator Swan-Tyee Intertie Special Use Authorization Special Use Permit Transmission Cooperative Tongass Land and Resource Management Plan Tongass Timber Reform Act United States Code United States Department of Energy United States Forest Service Unified System Operator Wilderness Attribute Rating System Wrangell Municipal Light &Power Hatch Acres Corporation PR324582.Rev.0,Page 17 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report EXECUTIVE SUMMARY ISSUES SHAPING THE STUDY e If the State of Alaska provides funds to construct new transmission segments in Southeast (SE) Alaska,will development of the segments discussed in this report provide the incentive for the private sector to invest in new generation,including associated infrastructure to connect with the transmission grid? e Will the new generation projects'use of the State-funded transmission,including the proposed Alaska-British Columbia (AK-BC)Intertie,result in revenues sufficient to cover operations and maintenance (O&M)costs to maintain the new transmission systems over the long term? e While markets exist outside Alaska,it is not clear how the sum of generating costs plus delivery costs for Alaska electricity products will compare with existing prices in these markets. e The accuracy of the generation,transmission and market information used in analyses performed during Phase |of this study is,in most cases,below a "pre-feasibility”level and both confidence ratings and more accurate information should be developed during Phase II. BUSINESS STRUCTURES Business structure options were reviewed and recommended options meriting future consideration were developed with the primary purpose of managing a future interconnected transmission system within SE Alaska with potential to transmit power excess to needs within SE Alaska to BC and other potential export markets in the Lower 48 states.Entities that could be involved include: e Transmission Cooperative -own and operate the proposed AK-BC Intertie. e Unified System Operator -manage interconnected electric transmission system transactions and provide a planning function to define future additions to the system. e Power Marketing Oversight Unit -assist the private sector with making 50-year plus life projects financially viable in the first 15-20 years when debt payments are heavy and manage sales of power for export using the AK-BC Intertie. e State of Alaska Transmission Owner/Operator -fund,own,and operate the proposed AK-BC Intertie with the authority to acquire and operate other segments of the "backbone”for an interconnected electric transmission system. SOUTHEAST ALASKA MARKET The current SE Alaska electricity marketplace includes several geographically constrained sub markets: e Petersburg &Wrangell -interconnected by the Four Dam Pool Power Agency (FDPPA)-owned transmission line that delivers power from Tyee Lake Project. e Ketchikan &Ketchikan Gateway Borough -connected to generation at Swan Lake Project by an FDPPA-owned transmission line. Hatch Acres Corporation PR324582.Rev.O,Page 18 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGHA Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report e Southern Prince of Wales Island communities -interconnected by Alaska Power and Telephone (AP&T)-owned transmission segments to AP&T hydro generation. e Metlakatla on Annett Island and Kake on Kupreanof Island are currently isolated self-contained community systems. Significant disparities in cost of power in SE Alaska exist today,in part related to availability of low- cost hydropower.Many isolated load centers are currently served primarily by diesel generation. SE Alaska communities have experienced slow population growth for decades.The economy is in transition from a resource-based economy to one where the economy is mixed,with increasing development in service-oriented businesses including:government services,recreation and tourism. The electricity load forecast indicates average annual growth rates in electricity sales in the 1.5 - 2%range for the larger communities in SE Alaska. Completion of the Swan-Tyee Intertie (STI)and development of proposed transmission lines to interconnect submarkets,and a future interconnection with BC,will encourage new economic development in currently isolated load centers and improve quality of life for residents currently encumbered with high cost energy from diesel generation. EXTERNAL MARKETS AND MARKET STRUCTURES Power demands in BC and the Pacific Northwest (PNW)are expected to grow substantially over the next 10 -20 years and electricity policy changes related to reduction of greenhouse gas emissions (GHG)represent export opportunity for competitively priced power from SE Alaska projects. Principle Markets for SE Alaska hydro to meet load growth e BC Hydro and/or Powerex (the wholesale marketing arm of BC Hydro). e PNW investor owned and/or publicly owned utilities. Proposed Transmission Interconnections necessary to export SE Alaska hydropower to BC and/or the PNW e AK-BC Intertie System. e British Columbia Transmission Corporation (BCTC)Backbone Extension. Market Opportunities e¢To be competitive,SE Alaska hydro projects need to meet current delivered market price of approximately $70/MWh (which is equivalent to 7 cents per kilowatt/hour).Assuming power delivery costs of $10/MWh,generating costs would need to not exceed the $60/MWh range. e If generating costs exceed $60/MWh,competitiveness depends on GHG restrictions increasing future BC/PNW market prices. Market Oversight e State involvement would enhance the potential that new projects could produce power for 50 years substantially increasing marketability. Hatch Acres Corporation PR324582.Rev.0,Page 19 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACHES REGULATORY ISSUES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report No "fatal flaws”regarding development of proposed AK-BC Intertie to border with Canada. Further consultations required with BC regarding the line segment from the border to the nearest point of interconnection with the BCTC system. New hydropower projects with power that could be exported at Thomas Bay require FERC licenses. Potential cost of power is dependent on operating restrictions that may be imposed in any future issued FERC license terms and conditions.No "fatal flaw”identified with probability of FERC issuing licenses. Regulatory issues requiring further investigation include:determination of whether power export is determined to be "interstate commerce”involving FERC regulation. TRANSMISSION LINE COSTS AND ISSUES Swan-Tyee Intertie.Capital costs are assumed to be grant-funded.O&M costs would be recovered through use of the line.No further studies are required. Other SE Alaska Transmission Segment Projects new transmission segments to interconnect isolated communities in Metlakatla and Kake would be grant-funded and O&M costs would be recovered through use of the line.We have not seen studies for the Metlakatla to Ketchikan line.Studies on the Kake-Petersburg line are at the feasibility level. AK-BC Intertie to export surplus power for sale in BC/PNW would encourage development of new projects and provide additional reliability benefits.The outstanding unknowns regarding feasibility of this line segment is whether the Thomas Bay projects would produce power at a market-clearing cost and whether BCTC would construct adequate capacity to transmit power to the BC and PNW markets. POWER GENERATION COSTS AND ISSUES Proposed projects would provide low-cost power to meet load growth in SE Alaskan communities and could generate power surplus to needs in SE Alaska for export to BC and the PNW. e With completion of the STI,near term proposed projects will address load growth in Ketchikan and Petersburg e Successful licensing of proposed projects at Thomas Bay in combination with other proposed new projects could provide power for export under certain development scenarios.May require State support through power marketing oversight. POTENTIAL DEVELOPMENT SCENARIOS -WITH/WITHOUT EXPORT Basic Assumptions e SE Alaska requirements met first,surplus was considered for export e The proposed AK-BC Intertie would be grant funded e O&M cost of transmission facilities would be met by users Hatch Acres Corporation PR324582.Rev.0,Page 20 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Without Export Requirements in Petersburg/Wrangell/Ketchikan can be best met with completion of the STI Intertie and planned new hydro projects.These actions will reduce need for increased diesel generation and provide benefits to SE Alaska ratepayers. Connecting Metlakatla and Kake show positive benefits.Metlakatla has an opportunity to develop its next hydro resource if there is an electrical interconnection that would facilitate transmitting power excess to needs on Metlakatla to other communities in SE Alaska.Kake is currently served by high-cost diesel generation and interconnection would provide consumers with lower cost power and enable conversions from high cost oil-based heating to electric heating. Un-quantified benefits of interconnection include:reduction of GHG,through reduced use of diesel generation,increased conversion from oil to electric heat reducing GHG emissions,gains in energy through coordinated operation of hydro projects,and incentives to encourage new economic development. With Export The ability to export power would encourage early development of new hydro generation which, as well as providing revenue from exports,will help ensure future maintenance of the current overall status of a clean hydro-powered region,offer operating flexibility for the SE Alaska power system,and provide future benefits to the region under the proposed marketing oversight proposal. Power sales agreements for power generated at projects encouraged by the AK-BC Intertie could be structured to return payment to the state.Power sales agreements could be structured to include a call-back provision when load in SE Alaska grows and power is needed to serve native load. Potential development initiatives with BC are dependent on BCTC cooperation,particularly development of the Northwest Transmission Line (NTL),extension of the grid to the AK/BC border, and favorable market conditions for Alaskan-generated power. CONCLUSIONS Swan-Tyee Intertie (STI) e The STI is economic starting in 2010 and technically feasible and fully permitted e The STI would allow use of surplus energy from the Tyee hydro plant and provides a significant opportunity to support institutional,commercial &residential conversions to electric heating, displacing oil heat with clean,renewable hydropower e The STI as proposed demonstrates strong economic value to ratepayers of SE Alaska e When the STI is completed,coordinated operation of the existing hydro projects in Petersburg and Ketchikan with the combined Swan and Tyee project operations will result in less overall spill and a more uniform distribution of energy through each water year.Coordinated operation will provide more ability to operate units at maximum efficiency and provide more flexibility in timing of planned outages. Hatch Acres Corporation PR324582.Rev.O,Page 21 AK-BC Alaska Finat Report 18-09-07.Doc nATGT ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Other Line Segments in SE Alaska Transmission segments to interconnect Metlakatla with Ketchikan and Kake with Petersburg are technically feasible and would provide benefits to ratepayers of SE Alaska The Kake-Petersburg Transmission Intertie is economic starting in 2011 and would provide access for Kake ratepayers to low-cost hydropower,displacing diesel generation and facilitating conversion from oil heat to electric heat;and could spur new economic development The Metlakatla to Ketchikan Transmission Intertie is economic starting in 2013 and would provide enhanced reliability and may encourage development of a proposed new hydro project on Annette Island. AK-BC Intertie and Projects Developed for Export The AK-BC Intertie would provide a further opportunity to secure the energy future for SE Alaska Export of energy from 2015 onwards to BC and/or the PNW appears to be economic at discount rates of 6% The technical feasibility and market potential of the proposed future hydro facilities and related transmission features look promising but cannot be definitively determined at this time The regulatory process to approve the proposed AK-BC Intertie segment within SE Alaska is well defined and no fatal flaws were identified.The proposed segment in BC has not been studied and could face environmental and institutional challenges Licensing proposed hydro facilities faces significant,but not necessarily insurmountable, environmental and institutional challenges If the State can be assured that the projects are constructed so they will produce power for 50 years (the term of their FERC license),it may be possible to evaluate their economics over that longer timeframe,substantially increasing their marketability. Hatch Acres Corporation PR324582.Rev.0,Page 22 AK-BC Alaska Final Report 18-09-07.Doc Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 1.INTRODUCTION Hatch Acres Corporation PR324582.Rev.O,Page 23 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 1.INTRODUCTION 1.1.Study Area and Energy Sector of Economy The study area includes the Southern Southeast region in Alaska (SE Alaska)'and a section of Northwest British Columbia (BC)(see Figure 1.1 AK-BC Intertie Feasibility Study Area).SE Alaska includes Thomas Bay,the Tyee Lake Project and proposed AK-BC Intertie located on the mainland; a proposed project at Takatz Lake on Baranof Island;and communities and transmission infrastructure and generation projects on Kupreanof,Mitkof,Wrangell,Revilagigedo,Annette,and Prince of Wales Islands.The proposed AK-BC Intertie would extend from Tyee Lake along the Bradfield River to the AK/BC border and along the Craig River to a proposed substation at Forrest Kerr in BC.Two maps (Figures 1.1-1 and 1.1-2)showing the AK-BC Intertie Feasibility Study Area and the Southeast Alaska and BC Transmission System respectively are provided at the end of this Section 1. The region offers significant natural resources and a quality of life conducive to attracting proponents of new clean economic development to the area.With few exceptions,no roads or bridges connect islands.People travel between islands by boat,floatplane,and/or wheeled plane. Electricity is the universal energy form.Virtually every home,shop,and factory in the nation use electricity and all are directly affected by its price and availability.Utility rates and services affect the quality of life for residents,influence economic development in communities within the study area,and shape future opportunities in all sectors of the economy.Significant disparities in the cost of power for SE Alaska communities exist today. Most electric systems in SE Alaska are community-based and serve isolated load centers.With the exception of the existing transmission line from the Tyee Lake Hydroelectric Plant to Petersburg and Wrangell?and the line linking several communities on Prince of Wales Island (POW)to the Black Bear Lake and South Forks Hydroelectric projects there are no interconnections to import or export power among the communities and electric utilities.Lacking transmission interconnections to other electric systems,each utility must plan independently to provide full power requirements to meet customer needs.Current isolated load areas are identified Table 1.1-1. 'In this report,the geographic area covered by the study is referred to as "SE Alaska” ?Transmission line segment owned by the FDPPA between Petersburg and Wrangell transmits power from the FDPPA's Tyee Lake Project. Hatch Acres Corporation PR324582.Rev.0,Page 24 AK-BC Alaska Final Report 18-09-07.Doc nATGA AGH Table 1.1-1 Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report SE Alaska -Geographic Areas,Communities and Electric Utilities GEOGRAPHIC AREA COMMUNITIES ELECTRIC UTILITY Annette Island Metlakatla Metlakatla Power &Light Kupreanof Island Kake Inside Passage Electric Cooperative Mitkof Island Petersburg Petersburg Municipal Power &Light Prince of Wales Island Coffman Cove,Craig,Hollis, Hydaburg,Kalwock,Thorne Bay Alaska Power &Telephone Revillagigedo Island Ketchikan,Ketchikan Gateway Borough,City of Saxman Ketchikan Public Utilities Wrangell Island Wrangell Wrangell Municipal Light &Power The following tables present a snapshot view of the study area and existing and proposed transmission and hydropower generation resources. Table 1.1-2 SE Alaska -Existing (E)and Proposed (P)Transmission Line Segments TRANSMISSION LINE E|P OWNER /INTERCONNECTED AREAS /COMMUNITIES SEGMENTS OPERATOR PMPL/WMLP/Tyee Lake X The Four Dam Petersburg and Wrangell Transmits power from Tyee Pool Power Lake Project Agency Swan Lake/KPU X The Four Dam KPU serves Ketchikan,Ketchikan Gateway Transmits power from Swan Pool Power Borough,and City of Saxman Lake Project Agency Swan-Tyee Intertie (STI)X |The Four Dam Petersburg,Wrangell,Ketchikan,Ketchikan Interconnects generation at Pool Power Gateway Borough,and City of Saxman Tyee Lake and Swan Lake Agency Projects AK-BC Intertie X |To be Would provide path to export power from SE Tyee Lake to AK/BC Border determined Alaska to BC Kake-Petersburg X |To be With STI would connect Kake,Petersburg, Transmission Intertie (KPTI)determined Wrangell,Ketchikan,Ketchikan Gateway Would transmit power from Borough,and City of Saxman Tyee Lake Project Metlakatla-Ketchikan X |Metlakatla With STI would connect Metlakatla,Ketchikan, Intertie Power &Light Ketchikan Gateway Borough,City of Saxman, Wrangell,and Petersburg. Prince of Wales Island to X |AP&T With STI would connect communities on Prince sTl of Wales Island to Ketchikan,Ketchikan Gateway Borough,City of Saxman,Wrangell,and Petersburg Thomas Bay to X |To be Export line to the proposed AK-BC Intertie for PMPL/WMLP/Tyee Lake to determined export to BC. AK-BC Intertie Takatz Lake to KPT X |To be Export line to the proposed AK-BC Intertie for determined export to BC. AK-BC Alaska Final Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 25 nATGH AGHA Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 1.1-3 SE Alaska -Existing (E)and Proposed (P)Generation PROJECT EARLY START LOCATION CAPACITY ON-LINE LOAD SERVED /EXPORTNAMEDATE Tyee Lake Wrangell Island 22.53 MW Available |PMPL/WMLP Hydro Future with STI -KPU Tyee Lake Wrangell Island 10 MW 2012 |Serve growing loads in SE Hydro Alaska;potential export -AK- Expansion BC Intertie Mahoney Lake |Ketchikan 9.6 MW 2010 |Potential export -STI to AK-BC Hydro Gateway Borough Intertie Whitman Lake |Ketchikan 4.6 MW 2010 |Serve growing load in KPU Hydro Gateway Borough service area. Cascade Creek |Thomas Bay 80 MW 2015 |Potential export -requires line Hydro from Thomas Bay to Tyee to AK-BC Intertie Ruth Lake Thomas Bay 20 MW 2015 |Potential export -requires line Hydro from Thomas Bay to Tyee to AK-BC Intertie Scenery Creek |Thomas Bay 40 --80 2015 |Potential export -requires line Hydro MW from Thomas Bay to Tyee to AK-BC Intertie Reynolds Prince of Wales 5.0 MW To be |Potential export-POW to Creek Hydro Island determined |STI to AK-BC-Intertie Near Hydaburg Soule River Hyder/Stewart 42 MW Not dependent on AK-BC Hydro Intertie Takatz Lake Baranoff Island 20 MW To be }Potential export -Takatz to Hydro determined |KPTI to Tyee to AK-BC Intertie Wrangell Wrangle Narrows 10 -100 To be |Potential export to AK-BC Narrows Tidal MW determined |Intertie Belle Island Belle Island NA To be |Potential export STI to AK-BCGeothermalRevillagigedodetermined|Intertie Island Table 1.1-4 Northwest BC -Proposed Transmission Line Segments TRANSMISSION LINE SRGMENTS LOCATION PURPOSE Northwest Transmission Line (NTL) Skeena to Bob Quinn substation Serve growing load in NW BC Provide transmission for IPP Projects under development in NW BC BC-AK Transmission Line Bob Quinn substation to BC/AK Border Provide interconnection with State of Alaska import SE Alaskan-generated power ?Current surplus at Tyee Lake -10 MW AK-BC Alaska Final Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 26 nATGH ACRES Table 1.1-5 Northwest BC -Proposed Generation Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report PROJECT NAME LOCATION |CAPACITY EARLY START ON- LINE DATE Forrest Kerr Hydro Iskut 115 MW 2009 More Creek Hydro Iskut 55 MW 2011 McLymount Creek Hydro Iskkut 60 MW 2011 Anyox Hydro Hyder/Stewart 30 MW 2010 Kitsault &Homestake Hydro Hyder/Stewart 26 MW 2010 Mount Hays Wind Farm Hydro |Hyder/Stewart 25 MW 2010 1.2 Purpose of this Report AEA states on its website that the purpose of the proposed AK-BC Intertie Project is: "The purpose of the project is to facilitate the development of the Southeast electrical intertie through the development of the Alaska-BC intertie for energy export.The export of energy through the Alaska-BC intertie will enable the completion of interties throughout Southeast Alaska including completion of the Swan-Tyee connection.Energy export could lead to the development of a number of hydro-electric projects in many locations in Southeast Alaska meeting domestic power needs and providing a surplus for export.The goal is to provide the energy needed for economic development in southeast Alaska resulting in jobs for Alaskans and providing reliable, less costly alternatives to diesel generated electricity for Alaskan communities.” The purpose of the AK-BC Intertie Feasibility Study is to conduct investigations and prepare a report for use by decision-makers in reviewing and evaluating proposals for funding and related state action on proposed transmission segments and related issues.This Final Report (report)presents the results of our investigations and analyses and includes: Potential options for the proposed future business structure e Potential markets for Alaskan-generated power e Regulatory requirements that will govern transactions in the export market;and the application and approval procedures to site,construct and operate proposed transmission lines and generation projects e Information and analyses regarding potential future electrical transmission segments that would form an interconnected system in SE Alaska e Information regarding existing and future generation projects e Least-cost plans to supply the electrical demand in SE Alaska with/without export e Potential future development scenarios. Analyses include with/without development of the proposed AK-BC Intertie export line to the AK/BC border.The primary purpose of the export line is to encourage development of Alaskan- generated power for sales to BC,and potentially the Pacific Northwest (PNW). Hatch Acres Corporation PR324582.Rev.0,Page 27 AK-BC Alaska Final Report 18-09-07.Doc nT AGRE The purpose of the within SE Alaska transmission segments discussed in this report (identified above in Table 1.1-2)is to provide surplus energy from Tyee to offset diesel generation in Ketchikan via the STI;to offset diesel generation in Kake via the KPT];and interconnect other areas within SE Alaska.We also investigated potential un-quantified benefits including:reduction of greenhouse gas (GHG)from diesel generation,increased heat conversions from oil to electric heat reducing GHG,gains in energy through complementary operation of hydro plants,and more economic development throughout the region. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report We developed an economic model,the "Regional Resource Planning Model”(RRPM)to assist in our analyses and this model has been provided to AEA. Two key inter-related questions posed by AEA'are addressed: e "If the State of Alaska provides funds to construct new transmission segments,will development of the segments discussed in this report provide the incentive for the private sector to invest in new generation,including associated infrastructure to connect with the transmission grid;and e Will the new generation projects use of the state-funded transmission,including the proposed AK-BC Intertie,result in revenues sufficient to cover O&M costs to maintain the transmission system over the long term?” This report includes reference to and excerpts from existing documents and information publicly available as of the time of submission of our Draft Final Report on April 5,2007°,and acquired through independent investigations and consultations by our project team®with individuals, government agencies,electric utilities and organizations. The accuracy of the generation,transmission and market information used in performing analyses during Phase|of this study is,in most cases,below a "pre-feasibility”level and both confidence ratings and more accurate information should be developed during Phase II. Our contract with AEA calls for this report to have been submitted by Apri!30",2007.As agreed with AEA,submission of the report was deferred to allow the AEA to assemble internal and stakeholder comments on our Draft Final Report dated April 5,2007.In preparing this Final Report,we have incorporated our responses to the AEA's comments of August 14"in our Draft Final Report.We would like to make specific note of the fact that in accordance with our scope of work we have not updated the Draft Final Report to reflect information on any new developments in the electricity sectors of SE Alaska ,British Columbia or the Lower 48 States during the period April 6",2007 to the present. We would also like to note that new information on the potential hydro projects continued to be received as we completed the Draft Final Report.This information was included in Section 7 of the report as it was received but it was not possible to include all the late arriving information in the preparation of the Development Scenarios of Section 8.We do not consider that any resulting "Often stated as "If we build it,will they come?”Questions were developed in consultation with AEA. >See Section 10 Bibliography for a listing of reports and other documents used in preparing this report.®See Section 11 List of Preparers Hatch Acres Corporation PR324582.Rev.O,Page 28 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES discrepancies between the information presented in Sections 7 and 8 have material impacts on the overall results presented in the report. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 1.3 Policy Issues 1.3.1 Joint Planning and Operations SE Alaska decision-makers have an opportunity to engage in joint planning to develop an interconnected electric transmission system within SE Alaska and the potential to expand that concept to include an interconnection with BC to enable export of clean hydropower. Joint planning and system operation will facilitate open access to regional system facilities at just and reasonable non-discriminatory rates.Entities that could be involved include: e Transmission Cooperative -own and operate the proposed AK-BC Intertie;potentially own and operate other interconnected line segments required for integrated system operations e.g.line from Thomas Bay to Petersburg and upgraded line and cables from Petersburg to Tyee currently owned and operated by the FDPPA e Unified System Operator -manage interconnected electric transmission system transactions and provide a planning function to define future additions.Consider future dispatch of generation on an integrated basis and address overall power quality to ensure reliable service throughout the interconnected grid system.High power quality and reliability are two essential elements to attract new economic investment in the region e Power Marketing Oversight Unit -assist the private sector with making 50-year plus life projects financially viable in the first 15-20 years when debt payments are heavy and manage sales of power for export using the AK-BC Intertie e State of Alaska Transmission Owner/Operator -fund,own,and operate the proposed AK- BC Intertie and the proposed line segment from Thomas Bay to a point of interconnection; potential to own and operate other segments,presently owned by other entities,that may be determined to be part of the "backbone”for an interconnected electric transmission system. Participation in the options presented for Business Structures in this Report would be open to all interested parties. 1.3.2.Markets and Market Structure The challenge to SE Alaska of competing in an ever increasing sophisticated marketplace for sales of products demands a more efficient production and delivery system and related infrastructure to support SE Alaska products and services.Increasing dependence on computer-based technology demands reliable power quality and integrated telecommunications /internet access services. To fully address the challenge inherent in determining future economic viability of the proposed AK-BC Intertie,Alaskan leaders representing the private sector,electric utilities,the state legislature and government agencies will need to participate in discussions with the decision-makers in the BC government and potential future power purchasers in the Lower 48. Hatch Acres Corporation PR324582.Rev.0,Page 29 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES 1.3.3 Regulatory Issues Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Future regulatory oversight of an interconnected electric transmission system that includes an interconnection with the BCTC system may be determined to constitute interstate commerce.The strategy to address this issue requires consideration by all members of the business structure that will own and operate the export intertie.Addressing this complex issue will involve filing a request for Declaratory Order with the FERC. 1.3.4 Generation Resources A central policy question is whether it is better to continue to develop many load-specific small hydropower projects and add diesel generation to back up isolated load centers,or to develop a long-term collective solution to meet future energy demand with larger regional hydropower plant reducing overall cumulative environmental impacts and avoiding future adverse air quality impacts that would result with continued reliance on diesel generation.In any case,some diesel generation will be required to address planned and forced outages and major repair and replacement given the terrain and weather challenges in the region. 1.3.5 Load Management The Four Dam Pool Power Agency (FDPPA)encourages conversion from oil heat to electric heat as the primary method of heating in the government,institutional,and residential sectors in Ketchikan, Petersburg and Wrangell to reduce costs and emissions associated with use of oil.Adoption of a policy to encourage conversion throughout the region and to add commercial entities may be of interest throughout the region to the extent that clean low cost hydropower is available as the interconnected electric transmission system develops. 1.4 Contractual Background Authorization On November 1,2006,Hatch Acres Corporation and the Alaska Energy Authority (AEA)entered into a Contract for AK-BC Intertie Feasibility Study SE Alaska,Contract #AEA-07-008 (Contract). Under the terms of this Contract Hatch Acres Corporation will "evaluate engineering,economic and political factors for development of a transmission interconnection from Southeast Alaska to British Columbia (AK-BC Intertie).””Funds for the study were provided by the State of Alaska. Schedule and Primary Activities and Deliverables DATE PRIMARY ACTIVITIES &DELIVERABLES November AK-BC Intertie Work Group briefing 14,2006 Meeting in Ketchikan to discuss the project December 19,|AK-BC Intertie Work Group briefing 2006 Working session in Ketchikan regarding the project 7 Appendix C -Scope of Work,C.1 Contract Intent Hatch Acres Corporation PR324582.Rev.0,Page 30 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACRES Alaska Energy Authority -AK-BC tntertie Feasibility Study SE Alaska Final Report January 7,December 2006 Draft Report provided to AEA and posted on AEA website 2007 March 27 -Southeast Conference and AK-BC Intertie Work Group meeting in Juneau 29,2007 Briefing for Governor's office and other decision-makers in Juneau April 5,2007 |Electronic copy of the Draft Final Report submitted to AEA and posted on AEA website May 8,2007 |Meeting of the AK-BC Work Group in Craig for which the agenda included discussion of the Draft Final Report August 14,Comments on Draft Final Report received by Hatch Acres from AEA 2007 September Final Report provided to AEA based on information available to Hatch Acres as of 18,2007 April 5,2007 supplemented by information provided in AEA's comments of August 14,2007 on the Draft Final Report 1.5.Overview of Phase I The Contract states that "The project concept is to develop hydroelectric projects and other renewable electricity generating facilities in SE Alaska along with building the necessary transmission links in Southeast Alaska to move the power to Alaskan Communities for in-state use and for the export of surplus power to Canada and the Lower 48 markets.® Phase |began with project initiation on November 1,2006.The first report was provided to AEA on January 7,2007.The Draft Final Report was provided on April 5,2007 A Bibliography of referenced sources is presented at Section 10 of this report. This Final Report addresses the feasibility of the proposed AK-BC Intertie under a reasonable range of market and ownership scenarios and other considerations defined in the contract. It must be noted that while it is clear that there are markets outside Alaska,it is not clear how the sum of generating costs plus delivery costs for the Alaska electricity product(s)will compare with the existing prices in these markets.The accuracy of the generation,transmission,and market information used in analyses performed during Phase |of this study is,in most cases,below a "pre- feasibility”level and both confidence ratings and more accurate information should be developed during Phase Il. 1.6 Study Approach and Assumptions We understand that the overall AK-BC Intertie Project concept is to: e Construct transmission segments within SE Alaska to interconnect currently isolated load centers,and provide access to clean hydropower generation to isolated communities presently solely dependent on diesel generation Ibid. Hatch Acres Corporation PR324582.Rev.0,Page 31 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES Alaska Energy Authority -AK-BC intertie Feasibility Study SE Alaska Final Report e Construct the Alaska Segment of the AK-BC Intertie from the Tyee Lake Project to an interconnection point at the AK/BC border to provide a path for export of surplus power to Canada and the Lower 48 states e Encourage upgrades at existing hydropower projects e Encourage development of new hydropower and renewable electricity generating facilities to serve loads SE Alaska and generate power for export to BC and the PNW. The multidisciplinary project team includes individuals with expertise in each of the discipline areas relevant to accomplishing the tasks identified in this contract.A list of preparers is provided in Section 11 of this report. The primary tasks identified in the contract include: e Consideration of Previous Feasibility Studies e Analysis of Business Structures e Regulatory considerations e Scenario Development and Computer Modeling e Development Schedule e Power Generation -Preliminary Engineering,Scoping and Project Budgets e Existing Transmission Systems and Power sales Agreements e Methods of Implementation e Power Generation -Development and Capacity Considerations e Transmission Line Considerations e Market Analysis Considerations for Sale of AK-BC Power. 1.7.Phase II -Development Assistance for AK-BC Intertie Project One element of this study is to investigate and present options for a business structure that would operate and maintain the state-funded proposed AK-BC Intertie that would interconnect with transmission in BC to provide a path for export of Alaskan-generated power. Primary factors shaping the business structure that would own and operate the proposed AK-BC Intertie include:inclusiveness of utilities,protection from excessive liability and undue risk,income tax exemption,ability to assume long-term debt,and ability to instil confidence in developers of new generation dependent on the export line.Options are presented and discussed in detail at Section 2 of this Report. We considered how future operation of a system comprised of existing and proposed transmission line segments might be structured given the current isolated current operations and range of ownership of existing line segments.We discussed system operations with current transmission line owners. We reviewed potential new generation projects and considered the uncertainties inherent given that the large new projects proposed for development at Thomas Bay have not proceeded to the point of applying to the FERC for licenses to construct and operate the projects. Hatch Acres Corporation PR324582.Rev.0,Page 32 AK-BC Alaska Final Report 18-09-07.Doc nATGt ACHES We discussed how to address uncertainties with the future costs of power produced by these projects.The concept emerged of a business structure to provide for state oversight over how the projects are constructed.If the state can be assured that the projects are constructed so they will produce power for 50 years (the term of their FERC licenses),it may be possible to evaluate their economics over that longer timeframe,substantially increasing their marketability. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 1.8 SE Alaska Market The current SE Alaska electricity marketplace includes several geographically constrained sub markets: e Petersburg and Wrangell -interconnected by the FDPPA-owned transmission line that delivers power generated at the Tyee Lake Project to PMPL &WMLP e Southern sector of Prince of Wales Island -Hydaburg,Hollis,Craig.Klawock,Kasaan,and Thorne Bay are interconnected by AP&T-owned transmission to hydro plant e Ketchikan and the Ketchikan Gateway Borough -connected by the FDPPA-owned transmission line to the Swan Lake Project and served by KPU e Metlakatla on Annette Island -currently isolated and served by a mix of hydro and diesel generated power e Kake on Kupreanof Island -currently isolated and solely reliant on diesel-generated power. Significant disparities in the cost of power in SE Alaska communities exist today,in part related to availability of low cost hydropower.Many isolated load centers are currently served solely by diesel generation.Utility rates and services affect the quality of life for residents,influence economic development in communities within the study area,and shape future opportunities in all sectors of the economy.Decisions to locate new commercial and industrial development is influenced by the availability of reliable and low-cost power. We assembled data regarding historic and projected loads and resources for each of the areas identified above.We considered the effects of developing the proposed transmission line segments to interconnect isolated market areas and present a proposed least cost approach to future supply within SE Alaska in this report. 1.9 External Market and Market Structures The primary purpose of the proposed AK-BC Intertie is to encourage development of Alaskan- generated power for export sales to BC and the PNW.In Section 4 of this Report we provide detailed information regarding the market and market structures. Power demands in both BC and the PNW are expected to grow substantially over the next 10 to 20 years.This growth plus electricity policy changes in BC and the PNW represent a potential export opportunity for competitively priced hydropower exports from SE Alaska. The 2007 BC Energy Plan issued by the BC Ministry of Energy,Mines and Petroleum Reserves will shape energy acquisition and transmission line development in BC for the foreseeable future.The BC government is holding meetings with representatives from the states of Washington,Oregon, Hatch Acres Corporation PR324582.Rev.0,Page 33 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report and Alaska to discuss how implementation of elements of the BC Energy Plan will affect accomplishment of goals to reduce greenhouse gas (GHG)levels and encourage development of renewable generation throughout the region. The Bonneville Power Administration (BPA)is modifying its long-term power marketing program. Major changes will occur in the PNW region post 2010 when BPA significantly reduces its obligation to meet load growth of its customers by acquiring new generation resources. Power demand within SE Alaska communities is expected to increase in some areas and to hold relatively steady in other areas. With development of the proposed AK-BC Intertie that will provide a transmission interconnection, it is feasible to export SE Alaska power to either BC or the PNW.If SE Alaska hydro projects can produce electricity to meet the current market clearing price of $60/megawatt hour (MWh)or less, they will be economically viable to export.If project prices exceed $60/MWh they may still be economic to export,but their competitiveness will likely depend on GHG restrictions increasing future BC/PNW market prices. If the State can be assured that projects are constructed so they will produce power for 50 years (term of their FERC license)it may be possible to evaluate project economics over that longer timeframe,substantially increasing their marketability.Consideration of long-term project operation would probably require more direct involvement by the State. The principal markets for SE Alaskan-generated power would be BC Hydro or Powerex,the wholesale marketing arm of BC Hydro,or PNW investor-owned and/or publicly-owned utilities.All of these entities will need power to meet their load growth in the post-2010 timeframe. 1.10 Regulatory Issues Federal and state regulatory requirements will shape future development of transmission segments and new generation in SE Alaska,and how the sales of Alaskan-generated power will be regulated. Section 5 of this report presents discussions of regulatory requirements that will shape development and operations of the proposed interconnected electrical system in SE Alaska. Discussions and analyses include consideration of whether export sales from Alaskan hydro projects constitute interstate commerce and present potential jurisdictional authority at the Regulatory Commission of Alaska (RCA)and the FERC (Section 5.2.1). Requirements that will affect development of the proposed AK-BC Intertie from the Tyee Lake Project to the AK/BC border,including provisions to site,construct,and operate a transmission line within the Tongass National Forest and requirements related to export of electric power including the Presidential Permit and Export Authorization are presented in Section 5.3.1.A brief discussion of requirements in BC is presented in 5.3.2. We present a detailed discussion of the regulatory proceedings governing new hydropower projects,including a discussion of the FERC hydropower licensing process that will shape how the proposed Thomas Bay projects might be constructed and operated in Section 5.4.1.The cost of power from these projects will be shaped by terms and conditions of licenses that may be issued by the FERC in the future. Hatch Acres Corporation PR324582.Rev.0,Page 34 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Regulatory requirements at the state and federal level discussed in this section of the report will influence how the business structures discussed in Section 2 of this report will function and how transactions involving export of Alaskan-generated power to BC might be regulated. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Regulatory issues that will require further consideration include:clarification of whether export of power across the proposed AK-BC Intertie will be determined "interstate commerce”and involve regulation by the FERC,and how that determination might shape the organizational structure of the entity that will own and operate the AK-BC Intertie. 1.11.Transmission Line Costs and Issues Section 6 of this report presents descriptions of potential future electrical transmission segments and related estimated capital and O&M costs;and,provides an analysis of the role an integrated electric transmission system may play in improving economic conditions within SE Alaska and facilitating export of Alaskan hydro power to BC and the PNW. Specific segments and groups of potential future segments addressed in this report include: Swan-Tyee Intertie (STI).The Four Dam Pool Power Agency (FDPPA)currently has a request pending before the State decision-makers to authorize funds to complete the 57-mile STI that will interconnect power generated at the FDPPA's Tyee Lake and Swan Lake Projects.Interconnection will enable the FDPPA to optimize generation at Tyee Lake as approximately 50%of the potential power is currently constrained by lack of a transmission segment that would deliver current surplus power to load.Tyee Lake currently serves loads in Wrangell and Petersburg;with the STI, Ketchikan would be served. The STI would interconnect existing FDPPA-owned line segments between Tyee Lake,Wrangell, and Petersburg;and between Swan Lake and Ketchikan. Future SE Alaska Transmission Segment Projects.A proposal to construct a transmission segment between Petersburg and Kake would deliver relatively low-cost clean hydroelectric power to offset diesel generation.Proposed segments between Metlakatla and Ketchikan;Coffman Cove on Prince of Wales Island and Ketchikan;and Kake and the proposed Takatz Lake project on Baranoff Island would provide a path to export surplus power over the proposed AK-BC Intertie. AK-BC Intertie.Interconnect SE Alaska with BC by constructing the proposed AK-BC Intertie to provide a path to export electric power surplus to the region for sale in BC and/or the Pacific Northwest (PNW);and to encourage development of new hydropower and renewable resource generation for the purpose of export . Proposed Line to Transmit Power from Proposed Projects at Thomas Bay to the AK-BC Intertie. Development of the three hydro projects at Thomas Bay is dependent on construction of a submarine transmission line from a proposed new substation at Thomas Bay to a new substation at Scow Bay on Mitkof Island where power would then be transmitted across the FDPPA transmission line from Petersburg to a new substation at Tyee Lake and the AK-BC Intertie. Hatch Acres Corporation PR324582.Rev.O,Page 35 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACHES 1.12 Power Generation Costs and Issues Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Section 7 of this Report presents information regarding existing and potential new generation projects in the AK-BC Intertie Study Area.New projects include proposals to provide relatively low-cost hydropower to SE Alaskan communities and those that will be developed for the purpose of exporting power to BC and the PNW. The ten (10)existing hydro projects in the study area have a total combined installed capacity of 70.7 MW.The potential estimated capacity from new hydropower generation could total an additional 183.7 MW in the SE Alaska region,with approximately 10%of that available in the near term (by 2010)and the remaining 90%would be developed in the far term (after 2015).In addition to not coming on-line until 2015 at the earliest,the final design,purpose,capacity and output are preliminary estimates at the time of this study.Potential new hydro projects considered in this study vary in their development status.Going forward,these projects will need to be further defined. Because of the limited project definition for new hydro within the study area,estimated development costs can range greatly.We used cost data from the most recent studies performed for projects and applied escalation on the basis of hydropower cost indices published by the US Bureau of Reclamation.In addition,standard cost assumptions were applied to the parameters of the projects to make comparison between projects consistent.A detailed description of the formula applied and the resulting "order of magnitude”costs is presented in Section 7.2. Diesel plants provide backup power to communities with hydropower generating capabilities but diesel is still the primary or only source of generation in several communities within SE Alaska and within our study area.Diesel capacity totals 56.65 MW in SE Alaska and retirement of ageing units is only possible with the replacement by lower cost clean hydropower.It is likely,however,that a significant amount of the diesel capacity in the region will be maintained for backup purposes even as more hydro and renewable energy projects are developed.Section 8 contains a discussion of the treatment of diesel power in this study and in the model. Potential for renewable energy generation in the study area consists of on-shore and off-shore wind, geothermal and tidal power.Definition and design of these types of projects has yet to reach a maturity appropriate for inclusion in this study.However,the interest,understanding and investment in these technologies in SE Alaska will continue to grow.These types of projects are likely on a longer development term than the potential hydro projects referenced above as each would be the first of its kind in the region.As such,the development costs are not available for analysis,confirmation or inclusion in this report. 1.13 Development Scenarios Evaluated Section 8 of the report describes the work carried out to prepare alternative development scenarios and assess their economic attractiveness.This work is based on the load forecasts prepared for the major load centers of SE Alaska (Section 3),the market price analyses for external markets (Section 4),the cost estimates for new transmission line segments to connect load centers in SE Alaska and to connect SE Alaska with external markets (Section 6)and estimates of the outputs of existing hydro plants and capital and O&M costs of potential hydro plant developments (Section 7). Hatch Acres Corporation PR324582.Rev.0,Page 36 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES The approach followed was to first identify the development scenario that would serve the SE Alaska electricity load forecast requirements at the least cost in economic terms.This involved defining three currently non-connected regions within SE Alaska and in a step-wise fashion assessing the economics of connecting load centers within each region,connecting the regions and adding alternative types and sizes of new generation.This process resulted in identification of the least cost development scenario for the study area as a whole identifying the transmission segments and hydro plant developments that would be economic to implement,by year of the planning period.Starting with this scenario,additional hydro plants (the Thomas Bay plants)and the transmission segments needed to export power were assessed to identify the economic benefits of exports based on the projected market prices in the external markets.The analysis was carried out using levelized costs calculated by assuming that hydro plants would have operating lives of 50 years and that their estimated capital costs would be recovered over 50 years of output with the estimated levels of production held constant over the operating period. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report A computer-based model in Microsoft Excel was developed to assist with the analysis described above.This model has been provided for future use by the AEA and interested stakeholders. 1.14 Phase Il -Development Assistance for AK-BC Intertie Project The Contract with AEA states that "Phase II may occur if a scenario is identified that involves a reasonable amount of public contribution of infrastructure,and reasonable expectations that Alaskan power production businesses will produce and sell power at low cost in Southeast Alaska and be able to export the excess over the long term. If the feasibility findings are positive,the contract may be extended and amended so the Contractor can provide assistance to AEA in bringing a development plan forward..”? Conclusions and Recommendations that may be pursued during Phase Il are discussed at Section 9 of this Report. °Contract with AEA -C.3 Phase {I Summary -Development Assistance for AK-BC Intertie Project Hatch Acres Corporation PR324582.Rev.0,Page 37 AK-BC Alaska Finai Report 18-09-07.Doc A \ S@Angoon -_\Proposed Generating Stations 4 :fa]Forrest Kerr Power Project -115 MW (2009) More Creek Power Project -55 MW (2011+)\Pen .. McLymount Creek Power Project -60 MW (2011+) -)Galore Creek , i [DB]Anyox Power Project -30 MW (2008)Sitka :Substations a,.. Blue Lake ran ;7 .138 kkv --..ey El Kitsault and Homestake Power Projects -26 MW (2008) "i)fan oo?”inl Mount Hays Wind Farm -25 MW (2008)Green Lake *::.oe .'af ep ain::ubstationSsPetersburg¢,AXx¢* :¢Se me . * 't .Y 2:Sos«" . * by f) ' wee ”LJ\"Meziadin Junction138kVSubstation Proposed Generating Stations Stewart " |Mahoney Lake -9.6 MW (2010+)Substation [2]Scenery Creek -30 Mw (2015+) Ruth Lake -20 MW (2015+) [4]Cascade Creek -45 Mw (2015+)Swan Lake 'Kitsault[5]Whitman Lake-4.6 Mw (2010+).=={Substation [B]Reynolds Creek-5.0 Mw (2010+)Ketchikan J ao \bbe ;en, ; : 4 ?;"&Aiyansh -Potential Future Generating Stations 4 2 eo!/-Substation [2]Scule River -42 Mw (2015+)@Metlakata .a [B]Wrangell Narrows Tidal -10-100 MW (2018+) &Takatz -20 MW (2) EJ Geothermal ames Area of Study e Cities and Load Centers BCTC Transmission Lines [|Major Hydroelectric Projects =aa Proposed Transmission Lines ®Existing Substation -Proposed Intertie AA Proposed Substations AK-BC Intertie Feasibility Study Area Z HATCH energy TENAKEE 1 SPRINGS HYDRO LEGEND EXISTING 138 KV,ALASKA PROPOSED ALASKA EXISTING 500 KV,BRITISH COLUMBIA EXISTING 287 KV,BRITISH COLUMBIA EXISTING 138 KV,BRITISH COLUMBIA PROPOSED 138 KV,BRITISH COLUMBIA SNETTISHAM 4 HYDRO (oon GREEN LK m=2SSane CREEK <.THOMAS BAYeeHYDRO yct>anSALTCHUCK .og pond pd aie!:7v4 me RECREATION AREAveganfs :°wy a RED CHRIS. \\(SPATS ities PLATEAL }i Me yf PARKPoeaai a &a KLAPPAN vy t ros a a v anGALORE.;. "CREEK :< CRAIGvenders **"AX,nest KER % ane HYDRO os4 A 4 '7 Po t,8 -MEZIADIN JUNCTION 8 EXISTING HYDROELECTRIC FACILITY 5 iste 7TsPROPOSEDHYDROELECTRICFACILITY,Le A MINERAL DEPOSIT °city .s 0 50 100 kmEEeev)30 60 mites io FIGURE 1.1-2 Southeast Alaska and BC Transmission System ZHATCH energy HATH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 2.BUSINESS STRUCTURES Hatch Acres Corporation PR324582.Rev.0,Page 40 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 2.BUSINESS STRUCTURES 2.1 Overview In this section of the report we discuss business structure options initially identified during preparation of the December 2006 Draft Report and the pros and cons of each.We present information for consideration to implement business structures to operate and maintain the proposed AK-BC Intertie,manage future operations of an interconnected electric transmission system,and manage sales of power generated for export. The business structure options presented in this report include:a Transmission Cooperative that would own and operate the proposed AK-BC Intertie;a Unified System Operator that would manage transactions across a future interconnected electric transmission system and provide a forum for consideration of future additions to the system;a state-sponsored authority to manage sales of power generated for export using the AK-BC Intertie,a Power Marketing Oversight Unit ; and a State-owned Transmission Owner/Operator. Potential Business Structure Options Potential business structure options identified in the December 2006 Draft Report: e Transmission Cooperative e For-profit Corporation e Non-Profit Corporation e Limited Liability Company (LLC) e Unified System Operator e Joint Action Agency e State Ownership. We acquired and reviewed available reports regarding each of the above-listed potential business structure options and engaged in conversations with a number of individuals with experience in operating transmission systems in British Columbia and the Lower 48 states.We also reviewed documents developed by legal counsel for the Southeast Conference in March 2004 during their consideration of options for ownership and/or operation of segments of the Southeast Alaska Intertie Project.Copies of these documents are included in Appendix B of this Report..We understand that the primary factors for the proposed business structure are: e =Inclusiveness of all utilities and power purchasers who are located near the future intertie segments e Protection of members from excessive liability and undue risk e Exemption from income taxation e Management stability e Ability to capitalize using long-term debt Hatch Acres Corporation PR324582.Rev.0,Page 41 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGES e Appropriate governance by shareholders and users Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report e Isolation from political forces e Financial accountability e Regulatory considerations e Ability to instil confidence in the potential investors in new generation capacity that would depend on the line to deliver the output of their plants to market. The following potential business structures address each of the above listed factors and were selected for further consideration: e Transmission Cooperative e Unified System Operator e State-sponsored authority to manage sales of power generated for export e State of Alaska Transmission Owner/Operator. Section 2.1.1 briefly describes other options considered and the rationale for removing them from further consideration. Section 2.1.2 presents options for further investigation. 2.1.1 Options Removed from Further Consideration Business structures not considered further in this report and the rationale for removing them from further consideration include: For Profit Corporation.This structure would not provide equal voting rights within the entity and may exclude some potential members.Under Alaska law (AS 10.06.420)voting rights are vested in the number of shares owned as opposed to a one member-one vote basis.In addition AS 10.06.338 requires payment of consideration (contributions)for shares. Non-Profit Corporation.Under Alaska law,a non-profit could provide limited liability and accommodate new members when planning for a new segment is imminent.However,a non- profit corporation would not be able to obtain a federal tax exemption under IRC 501(c)(3)or (4). The non-profit status could also not provide for participation by certain potential members,for example an Investor-Owned-Utility such as AP&T. Limited Liability Company (LLC).LLCs as defined in AS 10.55 would not restrict membership and could provide limited fiability to its members.One potential drawback is that LLCs are relatively new entities,and there is not a well-established body of law regarding the standards for piercing an LLC's "corporate veil.”An LLC could structure its articles and operating agreement to allow future users to become members as planning for additional intertie segments becomes imminent. However,the main disadvantage of a LLC is the difficulty it would likely face in obtaining exemption from federal income taxation.Another disadvantage of a LLC is that though a LLC may Hatch Acres Corporation PR324582.Rev.O,Page 42 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report technically be able to qualify for some types of grant funding,it is probably less politically attractive for a funding entity to issue such funds to a LLC." Joint Agency Regional Operator.In 2002 the Southeast Conference prepared proposals for and engaged in significant discussion with SE Alaska utilities regarding the concept of forming a joint action agency ("JAA”)pursuant to AS 42.45.300.This met with considerable opposition for various reasons.Among the most significant was that in order for the JAA to be tax exempt under federal income tax law,investor owned utilities ("IOUs”)could not be members,thereby excluding potential participants.In addition,AS 42.45.300 would have to be amended to ensure the requisite sovereign powers to obtain a federal income tax exemption.Finally,in contrast to AS 42.45.310, the statute for special JAAs like the FDPPA,AS 42.45.300 is very brief and lacks any detailed provisions regarding the governance and operation,let alone limited liability,for such a JAA. 2.1.2 Business Structures Selected for Further Analysis This section discusses options for further consideration:Transmission Cooperative,Unified System Operator,State of Alaska Transmission Owner/Operator;and a Power Marketing Oversight Unit. These options address all of the primary factors listed above in Section 2.2. 2.1.2.1 Transmission Cooperative Business Structure for SE Alaska The Transmission Cooperative Business Structure for SE Alaska is similar to the organizational structure adopted by the Kwaan Electric Transmission Intertie Cooperative,Inc (KWETICO),a Generation and Transmission (G&T)Cooperative that was recently formed by Alaska Electric Light &Power (AEL&P)and the Inside Passage Cooperative Inc."'(IPEC). AEL&P and IPEC formed KWETICO and received their Certificate of Public Convenience and Necessity (CPCN)from the RCA.AEL&P's service area includes Juneau and surrounding areas. IPEC has service areas in the Klukwan Valley north of Haines,Hoonah,Angoon,Kake,and other locations. KWETICO proposes to develop six grant-funded electric intertie segments,including the proposed interconnection from Petersburg to Kake'*that would extend the existing transmission network owned and operated by the FDPPA.The Petersburg to Kake segment is included in the AK-BC Intertie feasibility study area and discussed in this report. A future interconnection with KWETICO may be realized with full development of the interconnected Southeast Alaska Intertie System.Figure 1.1 -1 AK-BC Intertie Feasibility Study Area depicts the SE Alaska interconnected system and shows a proposed transmission interconnection with Angoon and proceeding north to Hoonah.Combining the proposed SE '©The perception is that most LLC's are for-profit,taxable entities.In addition,although LLCs have significant flexibility,that flexibility exists at the cost of certainty and experience regarding what is required,allowed, and discretionary under AS 10.50.That adds a level of complexity in drafting,revising,and abiding by governing documents.(Memorandum from Dean Thompson to Dave Carlson,March 16,2004.) "'[PEC was formerly known as the Tlingit-Haida Regional Electrical Authority (THREA). '2 KWETICO's organization is discussed in filings with the Regulatory Commission of Alaska in Docket U-05- 100. Hatch Acres Corporation PR324582.Rev.O,Page 43 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska interconnected electric transmission system with KWETICO would provide a transmission system interconnection from Juneau to the proposed AK-BC Intertie and connection to BC. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The following subsections discuss elements of the proposed Transmission Cooperative (TC)for southern SE Alaska. Membership Generation and transmission cooperatives have operated for decades.'?Membership includes investor-owned,rural-electric,municipal and state utilities;direct-service industries;and individuals.Under Alaska law (AS 10.25)there are no restrictions for membership by utilities or power purchasers in a TC." AS 10.25.080 states that as a condition of membership,new members must agree to "use the services furnished by the cooperative when they are made available through its facilities.”"*A TC may establish a standard in the articles or bylaws regarding how imminent the planning of a segment should be prior to having a future customer formally join as a member. Limited Liability Under provisions of AS 10.25.410 members of a TC are not liable or responsible for any debts of the corporation.Further,directors,officers,employees,and agents of a TC are not individually liable for conduct performed within the scope of the person's duties for the cooperative. Tax Exemption Internal Revenue Code ("IRC”)Section 501(a)and (c)(12)exempt a mutual or cooperative electric company from federal income taxation if it derives at least 85 percent of its income from its members.The basic requirements for satisfying "cooperative principles”are (1)democratic control-one member-one vote;(2)operating at cost;and (3)subordination of capital." Operating at cost means that the TC will not collect income from members greater or less than what is required to meet current losses and expenses,including recovery of reasonable margins'”. The limit is that those funds cannot be accumulated beyond the "reasonable needs of the organization's business”'®The IRS'recognition of the need for a TC to earn and retain reasonable "3 There are at least two transmission-only cooperatives currently operating in Georgia and the Southwestern United States '4 AS 10.25.010 and 10.25.020 provide electric and telephone cooperative utilities with broad powers to perform different types of activities.In several provisions,these statutes expressly allow a cooperative to construct,operate,and maintain "electric lines”and "transmission lines”and to "transmit electric energy.”(AS 10.25.010(a)(4)and (a){7);AS 10.25.020(1).) AS 10.25.020(1)states,in relevant part: "An electric cooperative may ...generate,manufacture,purchase,acquire,accumulate,and transmit electric energy,and distribute,sell,supply,and dispose of electric energy to its members,to governmental agencies and political subdivisions,and to other persons not exceeding 10 percent of the number of its members ...” 1S March 16,2004,memorandum from Dean Thompson to Dave Carlson ©Puget Sound Plywood v.Commissioner,44 T.C.305,307-08 (1965). '7 In Revenue Ruling72-36,the IRS held that operating at cost allows the cooperative to retain margins to expand the services of the cooperative and to maintain reserves for necessary purposes. 18 ID Hatch Acres Corporation PR324582.Rev.0,Page 44 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES reserves for current and future operations fits well with the overall plan for the long-term development of the intertie project. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Subordination of capital refers to the fact that cooperatives operate for the benefit of their member customers,not for equity investors.This means that over time,excess margins are returned to members and former members based on their patronage in the cooperative.'? Within the structure of a TC,different intertie segments may be operated on a stand-alone basis with respect to wheeling rates,O&M,and reserves.” The general cooperative principle of serving members at cost implies that a cooperative may charge different classes of members different rates based on differences in costs and allocations and circumstances of the service. One of the distinct benefits of a TC over other potential legal entities is that the IRS has routinely granted tax exempt status to electric cooperatives under IRC 501(c)(12).In addition,the IRS has routinely granted those exemptions to G&T electric cooperatives,not just distribution cooperatives. Nothing in the IRC or IRS regulations preclude a TC from qualifying for tax exemption under IRC 501(c)(12).?" The primary disadvantages of a TC structure are its 10%non-member service limit and the administrative burden of keeping records of member patronage and capital credits.The 10%non- member service limit is a state law requirement (AS 10.25.020(1)),not an IRS rule. The other primary disadvantage of a TC is the requirement for rigorous record-keeping of past and current patronage capital.However,to the extent entities seek to obtain their IRS tax exemption through IRC 501(c)(12),they would have the same type of record-keeping requirements. 2.1.2.2 Unified System Operator A unified system operator (USO)business structure would enable creation of an umbrella organization comprised of electric utilities and producers,and by coordinating resources of participating utilities,be in a position to undertake the financial obligation of constructing new and upgrading existing facilities.This is an important consideration as the State-funded transmission elements that provide a "kick-start”to the concept of an interconnected SE Alaska with provision for export via the proposed AK-BC Intertie cannot be relied upon to provide future expansion of the system,nor should it be required to finance upgrades to existing State-funded segments. There are many variations of a USO,including the California State Independent System Operator (CAISO).The following discussion addresses how a USO could operate an interconnected electrical transmission system in SE Alaska,and the proposed interconnection with BC. 19 ID 20 AS 10.25 and IRS rules allow this 2"The IRS granted Southwestern Transmission Electric Cooperative,Inc.a 501(c)(12)exemption as recently as January 4, 1999 Hatch Acres Corporation PR324582.Rev.0,Page 45 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACHES Segment Ownership Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report A USO could accommodate future ownership of the AK-BC Intertie by a TC as discussed above (Section 2.2.2.1)and include segments currently owned other members,for example the lines owned and operated by the Four Dam Pool Power Agency (FDPPA)”and other transmission segment owners,in an overall system operation without requiring divesture by current owners. Governance and Core Functions The USO organizational structure could be modeled on the not-for-profit public benefits corporation brought on line in 1998 when the State of California restructured its electricity industry. Although utilities still own transmission lines,the USO would ensure equal access to the overall interconnected system. The core functions of the USO could include: e Provide open and non-discriminatory transmission service e Ensure safe and reliable operation of the grid. Membership Membership is open to any entity that buys,sells,trades,transmits or distributes electricity in the interconnected system.This includes utilities,generating companies,transmission owners,and other entities.Currently the emerging market in SE Alaska does not include energy traders, however,development of a link to markets in BC and the PNW could result in new participants in the market. Markets As a function of operating the interconnected electric transmission system,the USO could address system reliability requirements.The USO could serve as a clearinghouse for energy transactions. Ancillary Services Market The Ancillary Services Market creates operating reserves where standby power is bought and sold on an agreed-to basis..This market helps adjust the flow of electricity when the unexpected happens,such as a power plant failure or a sharp rise in demand for power.The capacity that is bought and sold can be dispatched within the time frame adopted.Four types of energy may be offered for sale in the Ancillary Services Market: e Regulation -Generation that is already up and running (synchronized with the power grid) and can be increased or decreased instantly to keep energy supply and energy use in balance e Spinning Reserve -Generation that is running,with additional capacity that can be dispatched within minutes 22 The FDPPA currently owns and operates lines to deliver power from Tyee Lake to Wrangell and Petersburg and from Swan Lake to Ketchikan.The FDPPA would also own and operate the Swan-Tyee Intertie between Tyee Lake and Swan Lake and thereby connecting Petersburg,Wrangell and Ketchikan. Hatch Acres Corporation PR324582.Rev.0,Page 46 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report e Non-Spinning Reserves -Generation that is not running,but can be brought up to speed, within ten minutes e Replacement Reserves -Generation that can begin contributing to the grid within an hour. Transmission Market The transmission market allocates space on the transmission lines and is conducted for the day- ahead and the hour-ahead of when electricity is delivered.. 2.1.2.3 Power Marketing Oversight Unit As noted above,Phase|of this feasibility addresses business structures that would own and operate the proposed AK-BC Intertie and the future interconnected electric transmission system in SE Alaska.If the State can be assured that the projects are constructed so they will produce power for 50 years (the term of the FERC licenses),it may be possible to evaluate their economics over that longer timeframe,substantially increasing their marketability.A third potential business structure could provide power marketing oversight to assist the private sector with making 50-year plus life projects financially viable in the first 15 -20 years when debt payments are heavy and manage sales of Alaskan-generated power for export to markets outside the state. The Power Marketing Oversight Unit could be formed as a separate State government entity,or added to the existing AEA program,to oversee and facilitate power marketing aspect of projects encouraged by State commitment to the proposed AK-BC Intertie.For example,the Power Marketing Oversight Unit could negotiate agreements with Powerex,the power marketing subsidiary of B.C.Hydro (see Section 4.2.3),or other potential purchasers,for sale of Alaskan- generated power to the Lower 48. 2.1.2.4 State Ownership Background The AEA was created in 1976 by the Alaska Legislature.The AEA is a public corporation of the state with a separate and independent legal existence.AEA's original mission was to construct, acquire,finance,and operate power projects and facilities that utilize Alaska's natural resources to produce electricity and heat.Throughout the 1980s AEA worked to develop the state's energy resources as a key element in diversifying Alaska's economy.A number of large scale projects were constructed. In 1993 the Alaska Legislature enacted comprehensive energy legislation and oversight of AEA's existing state hydroelectric projects and the Alaska Intertie in the Railbelt Region was transferred to the Alaska Industrial Development and Export Authority (AIDEA).Programs addressing the energy needs of rural communities were transferred to a newly-created Division of Energy within the Department of Community and Regional Affairs.In 1999 the rural energy programs were integrated into AEA with AIDEA oversight and management.Department of Energy staff were transferred to AIDEA. The AEA's mission is to "Reduce the cost of energy in Alaska.”AEA projects and programs support its mission by 1)providing for the operation and maintenance of existing Authority-owned projects Hatch Acres Corporation PR324582.Rev.0,Page 47 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGES with maximum utility control,2)assisting in the development of safe,reliable,and efficient energy systems throughout Alaska,which are sustainable and environmentally sound,3)reducing the cost of electricity for residential customers and community facilities in rural Alaska,and 4)responding quickly and effectively to electrical emergencies. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report AEA continues to manage and provide oversight to state-owned energy assets,including the 126 MW Bradley Lake Project located in south central Alaska,the 475 KW Larsen Bay Hydroelectric Project on Kodiak Island,and the Anchorage-Fairbanks Intertie.The Anchorage-Fairbanks Intertie is a 170-mile,345 kV transmission line between Willow and Healy.The Intertie allows Golden Valley Electric Association in Fairbanks to purchase electricity produced less expensively with lower cost energy,natural gas and hydro,from the Anchorage and Kenai Peninsula utilities.The Intertie Operating Committee oversees operations and maintenance duties. Potential options for State ownership: e The State of Alaska could own,operate,and maintain the proposed AK-BC Intertie and the proposed transmission segment that would transmit power developed for export from proposed projects at Thomas Bay to the existing transmission line between Petersburg and the Tyee Lake Hydro Project owned and operated by the FDPPA.The State could participate in the Transmission cooperative (see 2.2.2.1)and the Unified System Operator structure (see 2.2.2.2).The State could also manage the Power Marketing Oversight Unit (see 2.2.2.3) e The State of Alaska could own,operate,and maintain the proposed AK-BC Intertie and the proposed transmission connection from Thomas Bay to Petersburg;and,could purchase the transmission assets of the FDPPA including:the existing line from Petersburg/Wrangell to the Tyee Lake Hydro Project,the existing connection from Swan Lake to Ketchikan,and the Swan-Tyee Intertie currently under construction to connect the Tyee Lake and Swan Lake hydro projects.This would provide the nucleus of an interconnected system within southern SE Alaska.Other segments that could be considered include the proposed connection between Kake and Petersburg;the connection from Annette Island to Ketchikan; and the proposed connection from Coffman Cove to the FDPPA transmission line near Wrangell,or to an interconnection with KPU e The State of Alaska could own certain transmission line segments that form the interconnected transmission system and export line to BC.The State could contract with third parties to operate and maintain the system.System operation could be accomplished through the Transmission Cooperative (see 2.2.2.1)and the Unified System Operator (2.2.2.2). Steps to Develop a State Ownership Business Structure The southern SE Alaska region could prepare a request to the Governor and the State Legislature that it is in the public interest for the State to assume a leadership role in developing essential transmission segments to ensure completion of an interconnected system in SE Alaska and to actively engage the BC Government in consultations and eventual negotiations to accomplish the proposed AK-BC Intertie export line. Hatch Acres Corporation PR324582.Rev.0,Page 48 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Benefits of State ownership could include:State financing to develop essential segments of the interconnected electric system;State representation as an owner in the forum to export power to BC;ability to assume debt on behalf of the State;direct State representation in regulatory proceedings at the State,BC,and,if required,at the Federal Energy Regulatory Commission should the export line be found to be "interstate commerce.” As there would be a need to change existing statutes that currently restrict State development of new energy projects,the timeframe for decision-making is unknown. 2.2 Regulatory Considerations 2.2.1 Overview The Transmission Cooperative(TC),the Unified System Operator (USO),and/or the State of Alaska Transmission Owner/Operator may be regulated by the Regulatory Commission of Alaska (RCA)for transactions within SE Alaska as discussed in Section 5.2.1.2.;and may be regulated by the Federal Energy Regulatory Commission (FERC)should export sales across the proposed AK-BC Intertie to BC constitute interstate commerce.Filing of rates for sale of export power could also be affected. Whether FERC would have jurisdiction over power transmitted to BC would be determined by the FERC.The process to determine jurisdiction is to prepare and file a petition for Declaratory Order with the FERC.FERC would review the petition and issue a determination regarding whether export of Alaskan-generated power is determined to be interstate commerce requiring Federal regulation (see 5.2.1.3 and 5.2.1.4). If Alaska constructs an intertie to connect its electric transmission system with the BCTC transmission system,Alaska could elect to voluntarily comply with the FERC open access transmission protocol as implemented by BCTC. As noted above at 2.2.3.4,changes in current State statutes would be required to accommodate the State Ownership model. 2.3.Transmission Element of Business Structure 2.3.1 Transmission System Segments -Alaska The Transmission Cooperative (TC)would own and operate the proposed AK-BC Intertie.The line from the proposed Thomas Bay Projects has been identified as a potential line to be owned by the TC,however,to date no firm decision has been made regarding this line segment.The alternative option for the State to own and operate these line segments would require change in current State law (see 2.2.3.4). The existing line segment from Petersburg to Tyee Lake Project owned and operated by the FDPPA would require an upgrade to transmit power from the proposed Thomas Bay Projects for export. The proposed Unified System Operator (USO)would manage the interconnected electric transmission system and provide a planning function to define future additions and negotiate the financial obligation of constructing new and upgrading existing facilities. Hatch Acres Corporation PR324582.Rev.0,Page 49 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Transmission segments that comprise a potential future SE Alaska interconnected electric transmission system include: e Line segments owned and operated by the FDPPA including:the partially constructed Swan-Tyee Intertie (ST1),and existing line segments connecting Petersburg/Wrangell with Tyee Lake Project and Ketchikan with Swan Lake Project e Line segment connecting Petersburg and Kake e Line segment connecting Annette Island to Ketchikan -proposed by Metlakatla Power & Light e Line segment connecting Prince of Wales Island to Wrangell and the FDPPA system - proposed by Alaska Power &Telephone e Line segment connecting Kake to the Takatz Lake Project on Baranof Island -currently no owner/operator is proposed. Maps depicting SE Alaska transmission lines are shown in Figure 1.1-2 Southeast Alaska and BC Transmission System (Section 1 of this Report).Detailed maps showing the proposed ST]and the AK-BC Intertie are included in Appendix A.Detailed discussions regarding these transmission line segments is presented in Section 6.Transmission Line Costs and Issues. 2.3.2 Interconnection and Future Arrangements with BCTC BCTC has proposed to extend its transmission backbone from Skeena to a new substation at Bob Quinn (see maps -Figure 1.1-2 Southeast Alaska and BC Transmission System and the proposed NTL in Appendix A).The design and final routing of this segment are under consideration. BCTC performed a "very preliminary”investigation of a line from Bob Quinn to the AK/BC border and issued a report in March 2006”.However,there is no projected date for a decision regarding this segment and the range of costs was estimated in that report as between $30 million and $120 million,and no supporting information was provided for these estimates.BCTC stated in its posting issuing the March report that "Before initiating any project to serve loads or undertake an intertie in this area,more robust planning and consultation would need to be completed.” A discussion of the BCTC Segments and potential interconnection to the AK/BC border.based on information available to date,is presented at Section 6.6 British Columbia Segments. 2.4 Generation Element of Business Structure 2.4.1.Generation Resources Identified for Export Dispatch of power generated for purposes of export could be subject to approval by the potential USO element of the business structure discussed above at 2.2.2.2. The proposed new hydro projects at Thomas Bay would be largely surplus to current and projected near-term needs to serve loads in SE Alaska.Please see Section 3 for description of the SE Alaska *3 Alaska-BC Inter-Tie Study,March 3,2006. Hatch Acres Corporation PR324582.Rev.0,Page 50 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Market and 3.2 for detailed information regarding SE Alaska loads and resources analysis.Section 4 presents the External Markets and Market Structures.Section 7 Power Generation Costs and Issues includes discussion of the Thomas Bay projects currently being studied under Preliminary Permits issued by the FERC.The future owner/operator of the Thomas Bay projects is dependent on successful applications for license at the FERC.The applications for license will include identification of the proposed transmission facilities to interconnect the projects. Near-term development of the Thomas Bay Projects will be dependent on:issuance of licenses by the FERC”to construct,operate,and maintain the projects;construction of the proposed AK-BC Intertie and related interconnection with the BCTC system;and,construction of the line from Thomas Bay to the FDPPA system at Petersburg.The line segment that would interconnect the Thomas Bay projects could be included in the licenses for the hydro projects as a primary line,or the license applicant could identify a line segment owned by a third party that would transmit power.. Additional generation projects for purposes of export could include: e Mahoney Lake Project located in Ketchikan Gateway Borough -licensed and under Congressionally authorized stay -licensee is City of Saxman e Triangle Lake Project -proposed for development by Metlakatla Power &Light e Takatz Lake Project --may be under consideration for development by the City and Borough of Sitka. The City of Wrangell is currently considering development of Sunrise Lake,however there is no detailed information at this date.Several other smaller hydro projects?'have been identified, however based on earlier studies these projects do not appear to meet the criteria of delivering power at the 6 to 7-cent market-clearing price discussed in Section 4.External Markets and Market Structures.See Section 7 of this report for information regarding existing and proposed generation projects. 4 While preliminary permits have been issued for the three projects,no applications for license have been filed with the FERC. 5 Projects include:Virginia Lake,Thoms Lake,Anita &Kunk lakes,Connell,and Carlanna -See additional information in Section 6. Hatch Acres Corporation PR324582.Rev.0,Page 51 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 3.SOUTHEAST ALASKA MARKET Hatch Acres Corporation PR324582.Rev.0,Page 52 AK-BC Alaska Final Report 18-09-07.Doc HATH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 3.SOUTHEAST ALASKA MARKET 3.1 Overview The current SE Alaska electricity marketplace includes several geographically constrained sub- markets: e Petersburg and Wrangell -interconnected by the FDPPA-owned transmission line that delivers power generated at the Tyee Lake Project to PMPL &WMLP e Southern sector of Prince of Wales Island -Hydaburg,Hollis,Craig.Klawock,Kasaan,and Thorne Bay are interconnected by AP&T-owned transmission to hydro plant e Ketchikan and the Ketchikan Gateway Borough -connected by the FDPPA-owned transmission line to the Swan Lake Project and served by KPU e Metlakatla on Annette Island -currently isolated and served by a mix of hydro and diesel generated power e Kake on Kupreanof Island -currently isolated and solely reliant on diesel-generated power. Significant disparities in the cost of power in SE Alaska communities exist today,in part related to availability of low cost hydropower.Many isolated load centers are currently served solely by diesel generation.Utility rates and services affect the quality of life for residents,influence economic development in communities within the study area,and shape future opportunities in all sectors of the economy.Decisions to locate new commercial and industrial development is influenced by the availability of reliable and low-cost power. The economy of SE Alaska has experienced broad-based transition from a commodity resource- based economy to one where the economy is mixed,with increasing development of general service-oriented businesses including government services recreation and tourism.This transition reflects national trends over the past decade where rapid employment growth is occurring in the services,retail trade,and government sectors.It is also a reflection of the decline in the wood products sector along with a substantial growth in the number of visitors to SE Alaska.Average annual employment in SE Alaska grew over the past decade,but at a slower rate than the national average.Changes in employment varied by community and by economic sector.In some communities in SE Alaska,employment has reduced in part due to the high cost of energy from diesel generation in isolated communities.As SE Alaska communities respond to transitions in the economy,the need to have an interconnected electric system becomes even more apparent. Development of proposed transmission lines to interconnect these sub-markets and provide an interconnection with BC will enable new economic development in many of the currently isolated load centers and improve quality of life for residents currently encumbered with high cost energy service from diesel generation. Hatch Acres Corporation PR324582.Rev.0,Page 53 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES 3.2 Loads and Resources Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The following sections outline the status of data collection for the load forecast task aspect of the study. 3.2.1.Current Loads and Resources Ketchikan Ketchikan is an industrial center based on fishing,fish processing,tourism and timber.The Census 2000 population figure for Ketchikan is 7922 plus an additional 431 for Saxman.The estimated populations for July 2005 are 7685 and 405,respectively.Population growth has averaged less then 0.4 per year percent over the past 35 years. Ketchikan Public Utilities (KPU)buys,generates and resells all of the electricity consumed in the City of Ketchikan/Ketchikan Gateway Borough area.KPU owns Ketchikan Lakes Hydro and Beaver Falls Hydro (including the Silvis Plant)totaling 11.5 MW,and operates Swan Lake Hydro (22.5MW)which is owned by the Four Dam Pool Power Agency (FDPPA).KPU also owns and operates a four-unit diesel plant with a capacity of 23 MW. Monthly sales and generation data were available for Ketchikan for the years 2000 to 2006.The data are summarized on an annual basis below.The detailed monthly data are presented in Appendix H01.Although some growth is evident into 2006,total sales and generation are lower for 2006 than in either 2000 or 2001.Monthly sales display consistent seasonal patterns over the years.Residential sales are markedly lower in the summer,particularly August and September and peak in December and January.The seasonal pattern for non-residential sales,however,is less well defined displaying only slightly lower consumption in the summer and slightly higher in the winter. The monthly consumption patterns are presented in Appendix HO1. Table 3.2-1 Ketchikan -Annual Sales and Generation Residential Non-Residential Total Net Peak Customers |Consumption |Customers |Consumption |Consumption |Generation |Demand (#)(kWh)(#)(kWh)(kWh)(kWh)(kW) 2000 5,612 56,769,397 1,909 102,635,997 159,405,394 166,375,424 28,100 2001 5,662 58,008,912 1,846 100,594,515 158,603,427 166,133,715 27,400 2002 5,643 56,913,013 1,828 87,226,943 144,139,956 151,502,672 26,300 2003 5,577 56,723,524 1,914 88,277,148 145,000,672 153,472,585 25,900 2004 5,597 57,332,811 1,842 88,063,078 145,395,889 150,586,782 27,600 2005 5,584 56,815,618 1,859 88,428,512 145,244,130 153,306,333 27,000 2006 5,630 59,870,257 1,882 92,289,675 152,159,932 159,543,140 28,900 Petersburg Since its beginning in the 1890s,Petersburg's economy has been based on commercial fishing and timber harvests.Several processors operate cold storage,canneries and custom packing services. Unlike Ketchikan and Wrangell,Petersburg does not have a deep water dock suitable for cruise ships.The Census 2000 population figure for Petersburg is 3224;the estimated population at July 2005 is 3010.The current population is approximately 7 percent larger than the population in 1980. Hatch Acres Corporation PR324582.Rev.0,Page 54 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES Petersburg Municipal Power &Light buys the vast majority of its electrical requirements from the Tyee Lake Hydro Plant (20 MW)owned by the FDPPA.!n addition the city owns a hydro facility at Blind Slough (Crystal Lake)which has a capacity of 2.2 MW and a small diesel plant. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Generation and sales data currently available for Petersburg includes monthly net generation,sales by tariff category and number of customers from 2000 to 2006.The data are summarized on an annual basis below.The detailed monthly data are presented in Appendix HO2. Like Ketchikan the monthly sales data displays a low in the summer and a peak in the winter. Unlike Ketchikan the non-resident sales has a well defined summer peak based on the operations of the large commercial sector associated with the fishing industry.The monthly consumption patterns are presented in Appendix H02. Table 3.2-2 Petersburg --Annual Sales and Generation Residential Non-Residential Total Net Peak Customers |Consumption |Customers |Consumption |Consumption |Generation |Demand (#)(kWh)(#)(kWh)(kWh)(kWh)(kW) 2000 1,316 13,027,144 666 22,229,387 35,256,531 39,120,307 6,860 2001 1,321 13,084,396 666 23,661,263 36,745,659 40,841,874 9,080 2002 1,327 12,825,151 651 22,529,651 35,354,802 39,442,490 8,180 2003 1,347 13,247,992 655 22,814,913 36,062,905 39,627,828 8,010 2004 1,363 13,132,812 663 23,470,133 36,602,945 39,929,252 8,380 2005 1,365 13,463,651 690 24,131,183 37,594,834 41,708,013 7,880 2006 1,376 14,600,288 704 24,348,294 38,948,582 44,843,573 8,810 Wrangell Wrangell's economy is based on commercial fishing and timber from the Tongass National Forest. Fishing and fish processing represent a significant portion of the economy.Although Wrangell has a deep-water port it caters only to small cruise ships.The nearby Stikine River attracts independent travelers for sportfishing.The Census 2000 population figure for Wrangell is 2308 while the estimated population at July 2005 is 2117.This is barely 4 percent larger than the population in 1970. Wrangell Municipal Light &Power buys the vast majority of its electrical requirements from the Lake Tyee Hydro Plant (20 MW)owned by the FDPPA.WMLP also owns a 5 MW diesel plant which is used for backup. Generation and sales data currently available for Wrangell includes monthly net generation and sales by tariff category for 2000 to 2006.The data are summarized on an annual basis below.The detailed monthly data are presented in Appendix H03. Monthly sales display consistent seasonal patterns over the years.Like Ketchikan,residential sales are markedly lower in the summer,particularly August and September and peak in December and January.Also like Ketchikan,the seasonal pattern for non-residential sales displays only slightly lower consumption in the summer and slightly higher in the winter.The monthly consumption patterns are presented in Appendix HO3. Hatch Acres Corporation PR324582.Rev.0,Page 55 AK-BC Alaska Final Report 18-09-07.Doc HAUGH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 3.2-3 Wrangell -Annual Sales and Generation Residential Non-Residential Total Net Peak Customers |Consumption |Customers |Consumption |Consumption |Generation |Demand (#)(kWh)(#)(kWh)(kWh)(kWh)(kW) 2000 1,049 8,059,451 486 17,688,705 25,748,156 21,211,028 - 2001 1,050 8,176,301 487 12,323,052 20,499,353 20,650,274 - 2002 1,055 7,454,245 474 11,986,928 19,441,173 20,691,304 - 2003 1,037 7,355,292 469 11,943,332 19,298,624 20,372,554 - 2004 1,033 7,384,010 468 12,499,331 19,883,341 21,079,459 - 2005 1,039 7,558,321 477 13,109,814 20,668,135 21,598,602 - 2006 1,037 7,935,625 474 12,635,433 20,571,058 22,382,718 - Kake Kake is a Tlingit community with a fishing,logging and subsistence lifestyle.The City,School District and Kake Tribal Corp are the largest employers.The Census 2000 population figure for Kake is 710,the estimated population at July 2005 is 667.Population growth from 1970 has averaged 1.1 percent per annum. The City of Kake is supplied by the Inside Passage Electric Cooperative through a local diesel plant of approximately 3.4 MW.Customers in Kake are eligible for the PCE subsidy but high electricity costs place industries and the community in general at a competitive disadvantage compared to communities with hydro-based supplies. The goal of the PCE program is to provide economic assistance to customers in rural areas of Alaska where the kilowatt-hour charge for electricity can be substantially higher than the charge in more urban areas of the state.The RCA determines the PCE level for each eligible utility based on reported fuel and non-fuel expenses.The AEA issues payment to the utility based on documentation of the eligible power sold to cover the PCE credits that the utility has already provided to its eligible customers.Individual customers can receive credits for consumption up to 500 kWh per month.The PCE level per kWh is calculated as 95 percent of the eligible costs between 12 cents per kWh and 52.5 cents per kWh.The maximum PCE level is 38.48 cents per kWh. The currently available statistics for Kake include monthly sales and number of customers by tariff category for 2000 to 2003 as well as for 2006.Monthly consumption in Kake is similar to the patterns observed in Petersburg.That is,the residential seasonal consumption pattern has distinct winter peaks and the non-residential pattern has distinct summer peaks.However,average monthly consumption per residential consumer is lower and below the 500 kWh per month limit for PCE subsidy.The data are summarized on an annual basis below.The detailed monthly data are presented in Appendix H04.The monthly consumption patterns are also charted in Appendix H04. Hatch Acres Corporation PR324582.Rev.0,Page 56 AK-BC Alaska Final Report 18-09-07.Doc HATH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 3.2-4 Kake -Annual Sales and Generation Residential Non-Residential Total Net Peak Customers Consumption |Customers |Consumption {|Consumption |Generation |Demand (#)(kWh)(#)(kWh)(kWh)(kWh)(kW) 2000 287 1,599,883 79 2,006,533 3,606,416 -- 2001 284 1,588,409 74 2,207,608 3,796,017 -- 2002 272 1,498,186 71 2,465,530 3,963,716 -- 2003 276 1,486,738 73 2,227,138 3,713,876 -- 2004 ------ 2005 ------ 2006 238 1,149,995 72 1,824,006 2,974,001 -- Metlakatla Metlakatla is a traditional Tsimshian native community on the federal Annette Island Reserve;the only Indian reservation in Alaska.The economy is based primarily on fishing and fish processing. The largest employer is the Metlakatla Indian Community which operates a hatchery,the tribal court and all local services.Annette Island Packing Co.is a cold storage facility owned by the community.A cannery and two sawmills are no longer in operation.The Census 2000 population figure for Metlakatla is 1375,the estimate for 2005 is 1397.The annual population growth is 0.3 percent per year from 1970 to 2005. Metlakatla Power &Light generates at two nearby hydro sites;Purple Lake (3.9 MW)and Chester Lake (1.0MW).They also have the 3.3 MW Centennial Diesel Plant. The currently available statistics for Metlakatla include monthly generation,sales and number of customers by tariff category for 2000 to 2005.The seasonality of consumption in Metlakatla is similar to that in Ketchikan -winter peak for residential consumption but no distinct peak in the non-residential sales.The data are summarized on an annual basis below.The detailed monthly data are presented in Appendix HO5.The monthly consumption patterns are also charted in the appendix. Table 3.2-5 Metlakatla -Annual Sales and Generation Residential Non-Residential Total Net Peak Customers |Consumption |Customers |Consumption |Consumption |Generation |Demand (#)(kWh)(#)(kWh)(kWh)(kWh)(kW) 2000 549 5,673,097 275 9,208,041 14,881,138 16,372,245 - 2001 556 5,608,302 264 8,544,195 14,152,498 15,327,234 - 2002 569 5,602,555 263 7,939,954 13,542,509 14,820,061 - 2003 528 5,608,157 261 8,394,246 14,002,403 15,122,842 - 2004 556 5,672,531 261 8,049,878 13,722,409 14,761,380 - 2005 555 5,809,401 255 8,488,425 14,297,826 15,316,636 - Craig,Thorne Bay,Klawock and Hollis There are a number of small communities on Prince of Wales Island which could potentially be connected to the Wrangell -Tyee transmission line through a future submarine cable to the island. The towns of Thorne Bay,Klawock,Hollis and Craig already share a distribution system based on hydro generation at Black Bear Lake.This system has recently been extended to Hydaburg. AK-BC Alaska Final Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 57 HATCH ACRES Expansion within the system or extensions to supply towns currently on diesel generators on the island would require additional supplies to supplement those from Black Bear Lake. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The economies of both Craig and Klawock are based on the fishing industry,logging support and sawmill operations.A paved road joins the communities such that Hollis,on the east coast,is a major transshipment point for supplies to the communities on the west coast of Prince of Wales Island.The total Census population for the four communities in 2000 was 2947.The current estimate for 2005 is approximately 2500,with 50 percent living in Craig and 30 percent in Klawock.The population has been largely unchanged since 1990. Alaska Power &Telephone (AP&T)owns and operates hydropower facilities at Black Bear Lake (4.5 MW)and South Fork (2 MW)which supply power to the four communities.Statistics for sales, generation and number of customers are readily available from APC from 1998 to 2006. Seasonality in the data displays a winter peak for residential sales and a summer peak for non- residential consumption.When combined there is no distinct peak for total sales.The data for 2000 to 2006 are summarized on an annual basis below.The detailed monthly data are presented in Appendix H06.The monthly consumption patterns are also charted in the appendix. Table 3.2-6 Craig,Thorne Bay,Klawock and Hollis -Annual Sales and Generation Residential Non-Residential Total Net Peak Customers |Consumption |Customers |Consumption |Consumption |Generation |Demand (#)(kWh)(#)(kWh)(kWh)(kWh)(kW) 1998 790 7,548,198 323 11,310,316 18,858,514 20,458,900 - 1999 1,120 8,696,778 458 13,108,340 21,805,118 23,425,600 - 2000 1,180 9,074,803 483 13,569,933 22,644,736 24,578,545 - 2001 1,202 8,714,074 492 13,067,158 21,781,232 23,950,055 - 2002 1,350 8,761,265 553 13,100,190 21,861,455 23,843,940 - 2003 1,366 8,847,406 559 13,254,446 22,101,852 24,597,722 - 2004 1,371 8,866,519 561 13,299,736 22,166,255 24,427,712 - 2005 1,390 8,859,241 569 13,321,024 22,180,265 24,468,785 - 2006 1,391 9,026,688 570 13,522,770 22,549,458 24,957,325 - Hydaburg Hydaburg is the largest Haida native village in Alaska.The economy is based on fishing and timber.The Census population in 2000 was 382 while the 2005 estimate is 351.The population level is incredibly stable;the 2005 estimate is only five (5)greater than the 1920 Census value of 346. AP&T supplies power to Hydaburg from the Black Bear Lake and South Fork Hydro facilities through the Craig,Thorne Bay,Klawock and Hollis distribution system.Statistics for sales, generation and number of customers at Hydaburg are readily available from APC from 1998 to 2006.Residential sales have a winter peak while non-residential sales show no distinct peak in the monthly data.The data for 2000 to 2006 are summarized on an annual basis below.The detailed monthly data are presented in Appendix HO7.The monthly consumption patterns are also charted in the appendix. Hatch Acres Corporation PR324582.Rev.O,Page 58 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 3.2-7 Hydaburg -Annual Sales and Generation Residential Non-Residential Total Net Peak Customers |Consumption |Customers |Consumption |Consumption |Generation |Demand (#)(kWh)(#)(kWh)(kWh)(kWh)(kW) 1998 143 588,143 58 869,613 1,457,756 1,549,400 - 1999 138 568,463 56 832,791 1,401,254 1,491,200 - 2000 134 555,172 55 818,029 1,373,201 1,458,400 - 2001 133 581,162 55 856,560 1,437,722 1,506,582 - 2002 130 585,978 53 863,240 1,449,218 1,540,853 - 2003 133 542,756 55 800,883 1,343,639 1,413,800 - 2004 128 557,494 53 824,393 1,381,887 1,450,734 - 2005 123 577,837 50 858,523 1,436,360 1,503,515 - 2006 124 605,239 51 894,199 1,499,438 1,588,843 - Coffman Cove Coffman Cove is one of the major log transfer sites on Prince of Wales Island.Logging support services and the local schoo!provide the majority of the employment.The estimated population for 2005 is 180,which is slightly lower than the 1990 population. AP&T supplies power to Coffman Cove from a local diesel plant.Statistics for sales,generation and number of customers are readily available from APC from 1998 to 2006.Residential sales have a winter peak while non-residential sales show a small summer peak in the monthly data.The data for 2000 to 2006 are summarized on an annual basis below.The detailed monthly data are presented in Appendix HO8.The monthly consumption patterns are also charted in the appendix. Table 3.2-8 Coffman Cove -Annual Sales and Generation Residential Non-Residential Total Net Peak Customers |Consumption |Customers |Consumption |Consumption |Generation |Demand (#)(kWh)(#)(kWh)(kWh)(kWh)(kW) 1998 TI 453,441 46 668,581 1,122,022 1,243,167 - 1999 118 446,162 49 655,996 1,102,158 1,238,157 - 2000 106 333,802 43 489,690 823,492 953,822 - 2001 105 266,636 43 396,392 663,028 763,631 - 2002 109 269,339 45 404,321 673,660 732,630 - 2003 111 281,279 46 419,975 701,254 758,930 - 2004 116 291,989 47 436,773 728,762 786,010 - 2005 115 288,254 47 433,248 721,502 791,330 - 2006 121 330,576 49 502,723 833,299 903,428 - Naukati Bay Small sawmills and related logging and lumber services are the sole income sources in Naukati Bay.Employment is seasonal.Naukati Bay is a log transfer site for several smaller camps on the Island.The estimated population for 2005 is 106. AP&T supplies power to Naukati Bay from a local diesel plant.Statistics for sales,generation and number of customers are readily available from APC from 1998 to 2006.Residential sales have a winter peak while non-residential sales show no distinct peak in the monthly data.The data for Hatch Acres Corporation PR324582.Rev.0,Page 59 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACHES 2000 to 2006 are summarized on an annual basis below.The detailed monthly data are presented in Appendix HO9.The monthly consumption patterns are also charted in the appendix. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 3.2-9 Naukati Bay -Annual Sales and Generation Residential Non-Residential Total Net Peak Customers |Consumption |Customers |Consumption |Consumption |Generation |Demand (#)(kWh)(#)(kWh)(kWh)(kWh)(kW) 1998 27 403,593 11 589,909 993,502 1,019,440 - 1999 34 413,076 14 601,579 1,014,655 1,085,040 - 2000 42 311,073 17 450,063 761,136 836,928 - 2001 42 161,640 17 237,046 398,686 455,904 - 2002 43 153,649 18 227,852 381,501 455,748 - 2003 46 164,936 19 243,494 408,430 462,886 - 2004 49 186,744 20 275,798 462,542 517,593 - 2005 46 201,883 19 299,296 501,179 568,255 - 2006 45 179,363 19 264,490 443,853 501,608 - Whale Pass Logging operations and related services plus the school provide the only steady employment in Whale Pass.The estimated population in 2005 was 76. AP&T supplies power to Whale Pass from a local diesel plant.Statistics for sales,generation and number of customers are readily available from APC from 1998 to 2006.Both residential and non- residential sales show a summer peak in the monthly data.The data for 2000 to 2006 are summarized on an annual basis below.The detailed monthly data are presented in Appendix H10. The monthly consumption patterns are also charted in the appendix. Table 3.2-10 Whale Pass -Annual Sales and Generation Residential Non-Residential Total Net Peak Customers |Consumption |Customers {Consumption |Consumption |Generation |Demand (#)(kWh)(#)(kWh)(kWh)(kWh)(kW) 1998 26 95,061 11 146,043 241,104 275,040 - 1999 32 108,355 13 169,611 277,966 313,280 - 2000 36 100,386 15 159,364 259,750 296,400 - 2001 37 71,317 15 107,426 178,743 220,320 - 2002 40 84,904 17 128,341 213,245 273,984 - 2003 45 92,701 19 139,481 232,182 288,960 - 2004 48 121,332 19 185,347 306,679 370,560 - 2005 48 121,010 19 188,477 309,487 379,200 - 2006 50 108,681 21 171,317 279,998 340,320 - 3.2.2 Projected Loads Forecast Approach The communities of SE Alaska have experienced slow population growth for decades,their economies based traditionally on the natural resources of fishing and timber.The gain or loss of a single cannery or sawmill can mean the difference between prosperity and negative growth.The increase of tourist activities,including the arrival of cruise ships,is beginning to change the Hatch Acres Corporation PR324582.Rev.0,Page 60 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES economic base,especially in the larger communities in the region.Electricity consumption has and will continue to increase but at a slow rate,more in line with general population growth. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The principal exception to this population-based growth approach is the observed trend in heating loads.The utilities are currently experiencing a large number of conversions from oil space heating to electric heat.This trend is explicitly addressed in the forecasts. In the absence of official forecasts of population and/or economic growth for these communities the power market forecast has been developed on the basis of a range of low general population growth expectations plus the power requirements of specific anticipated and announced loads.A reference forecast as well as a low and a high forecast are produced. Residential Sector Sales to the residential sector account for roughly 40 percent of total electrical sales in the communities of SE Alaska.For purposes of the forecast residential sales are projected on the basis of number of customers and consumption per customer.For the reference forecast the number of residential customers is projected to increase at 0.75 percent per annum.This is the average growth rate observed in the Census population figures for the period from 1970 to 2005.The average consumption level per customer is also projected at 0.75 percent growth per year.This is the observed average per customer growth from 2000 to 2006.Implicit in the growth rate of consumption per customer is that each customer will use electrical appliances more intensely, either using existing appliances more or purchasing new appliances.This is balanced somewhat by the fact that many of the new appliances will be more efficient than those that are replaced,such as LCD monitors for computers. Non-Residential Sector The forecast for non-residential sales is also projected on the basis of number of customers and consumption per customer.For the reference forecast the number of non-residential customers is projected to increase at 0.50 percent per annum.This is somewhat larger than the average growth rate observed in utility statistics for the period from 2000 to 2005,but is a reflection of the optimism expressed by the utilities at the December 19,2006 AK-BC Intertie Meeting in Ketchikan. No annual growth is projected for the average consumption level per non-residential customer. This assumes that electricity use by new non-residential customers will not vary significantly from the current use. Spot Loads A number of specific spot loads were noted by the utilities at the December 19,2006 AK BC Intertie Meeting in Ketchikan.Subsequent discussions have removed several of these developments from the list of spot loads as the loads have already been connected to the system and are included in the base data. The remaining spot loads are a Ship and Dry Dock Facility in Ketchikan which has been included in 2 phases -350 kW at 65%load factor in 2008 and 175 kW also at 65%load factor in 2010 and a 500 kW kiln in Wrangell starting in 2008. Hatch Acres Corporation PR324582.Rev.O,Page 61 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES Heating Load Conversions Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Information available in the 2000 Census indicates that approximately 10%of residential dwellings used at least some electric heating at that time.The utilities are currently experiencing a significantly large number of conversions from oil space heating to electric heat.These conversions are currently concentrated in those communities where lower cost hydro-based electricity offers a reasonable alternative to rising oil prices.As the hydro-based systems expand,the demand for electricity for heating can also be expected to expand. These conversions,however,will ultimately only be installed and operated when the cost of oil is relatively high compared to that of electricity.If we assume that the average oil-based system is 60 percent efficient in the conversion of oil to heat and the price of oil is $2.60 per gallon;the threshold electricity price is $0.106 per kilowatt-hour.That is,electricity is more cost effective than oil if it is below $0.106 per kilowatt-hour.The greater the efficiency of the oil heater the lower the required electricity price -90 percent efficiency at $2.60 per gallon requires $0.07/kWh electricity. The following chart shows the comparative prices at various efficiencies and over a range of possible oil prices. Figure 3.2-1 Electricity Price Threshold for Conversion Electricity Price Threshold for Conversion (eg.at 60%oil heating efficiency and Oil Price of $2.60 per US gal,electricity price must be less than $0.1056/kWh for conversion)0.25 Po ee Oil Heating |pot ttt ttt tt rt rst te He rrrtrrrt +>---Efficiency-4 0.20 = ==<#0.15 o2 = alz'3 0.10 $[*]Oo ii 0.05 0.00 Tt 7 --T .T :.r >7 mame T 1.00 1.20 1.40 1.60 180 2.00 2.20 2.40 2.60 2.80 3.00 3.20 3.40 3.60 3.80 400 4.20 440 460 480 5.00 Oil Price ($/USgal) In the residential sector of SE Alaska the recent trend has been that many new houses are built with all electric heating,while older homes will have electric heating added without removing the oil- heating equipment.The former would require uninterruptible electricity supply while the latter could tolerate interruptions.It is understood that a large number of portable heaters have been purchased and added to the heating mix. One concept that does not appear to have been investigated is the addition of plenum heaters in existing oil furnaces.These heaters are typically in the range of 3 to 5 kW and are not intended to supply the total heating requirement.They would,however,be capable of supplying all required heat during the shoulder seasons and often during the day even in mid-winter.Their principal advantage is control.Plenum heaters can be connected in such a way as to be controlled centrally by the utility such that they can be turned off at times of critical supply and left on during surplus. Hatch Acres Corporation PR324582.Rev.0,Page 62 AK-BC Alaska Final Report 18-09-07.Doc nATGH AGEN Electronic controls are available which would seamlessly use the oil furnace during those times when the plenum heater is turned off or insufficient to supply all of the required heat.In return for this potential interruption the customer could be supplied at a special lower rate which would encourage the use of the plenum heater over a portable unit at regular rates. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The reference forecast assumes that 50 percent of new customers will install electric heating and that 5 percent of the existing customers will undertake partial conversions through the use of portable heaters or the addition of one or two baseboard heaters to supplement their oil system.It is assumed that conversions will stop when 35 percent of the customers have full conversions. The estimated heating load at various locations was compared to the heating degree days at those same locations to determine a relationship which could be adapted in Southeast Alaska.A relationship was observed for both old detached houses as well as new detached houses,where old houses are assumed to have been built before 1990.Both housing types are approximately 2000 square feet. Figure 3.2-2 Relationship Between Heating Load and Heating Degree Days 200 @ Old Detached y @ 0.0115x +13.188aa180R?=0.8809- 160 @ New Detached140-¥=0.0088x-+-4,4596 120 100 80 HeatingLoad(GJ)60 |--»_ 5,000 7,000 9,000 11,000 13,000 15,000 17,000 Heating Degree Days (deg F) On the basis of this relationship for new detached housing (the lower curve in Fig 3.2-2)the following annual electricity requirements have been assumed for this forecast: Hatch Acres Corporation PR324582.Rev.0,Page 63 AK-BC Alaska Final Report 18-09-07.Doc nATGH AGE Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 3.2-11 Annual Electric Heating Requirements Heating Degree Heating Electricity Days(F°)Requirement Requirement (kWh) (G)) Ketchikan 7,207 67.9 18,861 Petersburg 8,176 76.4 21,222 Wrangell 7,706 72.3 20,100 Elsewhere 7,700 72.3 20,100 Partial conversions have been assumed to require 5,000 kWh per year in all locations. There are plans to convert a number of the government and institutional buildings in Ketchikan, Petersburg and Wrangell from oil to electric heating.It is anticipated that these conversions will be undertaken over a number of years and that once implemented that they will be an interruptible load.No information was available on the potential for conversion from oil to heating in the private business sector. Table 3.2-12 Anticipated Commercial Electric Heating Conversions LOCATION NAME STARTING POWER L.FACTOR GROWTH (Kw) Ketchikan State Bldgs |2010 257 100%0.0% Ketchikan State Bldgs II 2012 257 100%0.0% Ketchikan City Bldgs |2012 1313 100%0.0% Ketchikan City Bldgs II 2014 1313 100%0.0% Petersburg City Bldgs 2011 650 100%0.0% Wrangell City Bldgs 2011 385 100%0.0% 3.2.3 Forecast Parameters -Reference Case Table 3.2-13 lists the principal forecast parameters used in the Reference Forecast.All load centers on Prince of Wales Island are all assigned the same parameters.In addition,a 50 percent factor has been assigned to the commercial conversions to electric heating.This factor can be viewed as a probability that the forecast values will either not be achieved as planned or that there will be interruptions in the supply of electricity due to short falls in supply from hydroelectric plants. Hatch Acres Corporation PR324582.Rev.0,Page 64 AK-BC Alaska Final Report 18-09-07.Doc nATGH AGRE Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 3.2-13 Principal Forecast Parameters -Reference Case REFERENCE FORECAST Prince of Ketchikan Petersburg §Wrangell Kake Metlakatla Wales Island Residential Customer Growth 0.75%0.75%0.75%0.75%0.75%0.75% Unit Consumption Growth 0.75%0.75%0.75%0.75%0.75%0.75% Non-Residential Customer Growth 0.50%0.50%0.50%0.50%0.50%0.50% Unit Consumption Growth 0.00%0.00%0.00%0.00%0.00%0.00% Heating Conversions Start Year 2000 2000 2000 2015 2000 2020 New Customers Full Conversions 50.0%50.0%50.0%50.0%50.0%50.0% Partial Conversions 0.0%0.0%0.0%0.0%0.0%0.0% Existing Customers Full Conversions 0.0%0.0%0.0%0.0%0.0%0.0% Partial Conversions 5.0%5.0%5.0%5.0%5.0%5.0% Maximum Full Conversions 35.0%35.0%35.0%35.0%35.0%35.0% Unit Consumption (kWh) Full Conversions 18,861 21,222 20,100 20,100 20,100 20,100 Partial Conversions 5,000 5,000 5,000 5,000 5,000 5,000 3.2.4 Monthly Sales Patterns The nature of generation in Alaska necessitates a forecast on a monthly basis.The monthly sales patterns of the existing loads are introduced in Section 3.2.1.1 above.The patterns derived for each load center based on the historic data are applied to each year's forecast to produce the corresponding monthly forecast.The existing patterns are also applied to the annual spot load forecasts.These patterns are detailed for each load center below. The heating conversion forecasts require a somewhat different approach.The heating degree day data used to determine the total energy requirement above is available on a daily basis.This information is aggregated by month to determine a monthly pattern of required heating which is applied to each of the annual conversion values for each of Ketchikan,Petersburg and Wrangell. An average derived from these three communities is used in the other load centers.Figure 3.2-3 presents the heating degree day pattern over the year for each community.These curves are based on climate data for 1971 to 2000 from the National Oceanic and Atmospheric Administration. AK-BC Alaska Final Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 65 nATGH AUER Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Figure 3.2-3 Heating Degree Days -Southeast Alaska Heating Degree-Days -Monthly Values 1200 a +, ry 1000 |---ns g WKetchikan (7,207dd/yr) lL Petersburg (8,176dd/yr)Py @|ie OWrangell (7,706dd/yr)- 800 i-+r -|a + 5.a :ain LL&soo }4 }-J |__J }_|_||__|| fs] &.i Th :400 +|}+-_-f{|--[-}- 200 +/-4 +t-}L--_=}-| 9 -- Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Ketchikan Forecast The power market forecast for Ketchikan consists of growth in both the residential and non- residential sectors,a number of full and partial electric heating conversions as well as new spot industrial loads and commercial electric heating conversions. Based on the reference case parameters listed in Table 3.2-13 for Ketchikan the annual forecast is presented in Table 3.2-29 at the end of this report section.The table also includes historic values from 2000.The overall growth rate for net generation over the 25-year planning horizon is 1.9 percent per year.Clearly,the majority of the consumption growth occurs early in the forecast period in response to the spot loads and commercial electric heating conversions. The monthly forecast is based on the monthly consumption patterns for the residential and non- residential sectors displayed in Figure 3.2-4 while the electric heating conversions are distributed on the basis of the heating degree day values for Ketchikan.The three sets of monthly distribution values are listed in Table 3.2-14.The detailed annual and monthly forecasts are presented in Appendix H-1. Note:Figures 3.2-4 to 3.2-13 display the seasonal consumption patterns for each community.Each smoothed curve is based on 12 monthly observations.While monthly values might normally be best displayed in a bargraph,the intent of these figures is to highlight the relative levels between the residential and non-residential sales categories.These relative levels are best observed from smoothed curves. Hatch Acres Corporation PR324582.Rev.0,Page 66 AK-BC Alaska Final Report 18-09-07.Doc nATGH AGH Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Figure 3.2-4 Seasonal Consumption Patterns -Ketchikan Ketchikan -Seasonal Sales Patterns 12% o | -_a10%= Residential Sales ->_- .--™.Mee Se ontial Sales 8%os es=,-_-a 6%-Sait -- 4%ao - 2%+---- ---- 0%u U T v T T r T T Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Table 3.2-14 Monthly Sales Distribution -Ketchikan Monthly Distribution -Ketchikan Non-Ketchikan Residential Residential Heating Existing Existing Deg-Days Jan 10.25%8.93%13.50% Feb 10.03%8.92%11.17% Mar 9.08%8.16%11.29% Apr 8.95%8.14%9.17% May 8.19%7.95%7.13% Jun 7.53%7.54%4.69% Jul 7.23%8.00%3.16% Aug 6.80%8.73%3.01% Sep 6.98%8.98%4.97% Oct 7.57%8.32%8.28% Nov 7.94%7.87%10.91% Dec 9.45%8.46%12.71% Petersburg The annual forecast for Petersburg Municipal Power and Light includes residential and non- residential growth as well as residential and commercial electric heating conversions. Based on the reference case parameters listed in Table 3.2-13 for Petersburg the annual forecast is presented in Table 3.2-30 at the end of this report section.The table also includes historic values from 2000.The overall growth rate for net generation over the 25-year planning horizon is 1.4 percent per year. The monthly forecast is based on the monthly consumption patterns for the residential and non- residential sectors displayed in Figure 3.2-5 while the electric heating conversions are distributed on the basis of the heating degree day values for Petersburg.The three sets of monthly distribution Hatch Acres Corporation AK-BC Alaska Final Report 18-09-07.Doc PR324582.Rev.0,Page 67 HATGH AUER values are listed in Table 3.2-15.The detailed annual and monthly forecasts are presented in Appendix H-2. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Figure 3.2-5 Seasonal Consumption Patterns -Petersburg , Petersburg -Seasonal Sales Patterns 16% 14%--oo 1 | 12%y_™| \Vi . 10%+-a Residential Sates -------- 8%+ -_-Totat Sates-- ae |ee -«Non-Residential Sales 6% 4%Se ae --- 2%+ee -woe -- 0%T T ,,r Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Table 3.2-15 Monthly Sales Distribution -Petersburg Monthly Sales Distribution -Petersburg Non-Petersburg Residential Residential Heating Existing Existing Deg-Days Jan 11.34%7.51%13.59% Feb 9.27%7.32%11.08% Mar 9.26%7.15%10.81% Apr 8.71%8.10%8.41% May 7.29%7.19%6.48% Jun 7.24%7.27%4.28% Jul 6.65%11.49%3.44% Aug 6.65%13.33%3.89% Sep 7.14%9.13%5.71% Oct 7.83%7.62%8.51% Nov 8.68%7.25%10.97% Dec 9.94%6.63%12.82% There is also the possibility of future mining expansion on Mitkoff Island as well as a new mining development on Woewodski Island.Both developments are in the range of 5 to 7 MW load and would require a dedicated transmission extension from the Petersburg to Kake line.These potential loads have not currently been included in this forecast. Wrangell Wrangell Municipal Light &Power (WMLP)sees development that mirrors that of Petersburg.They are currently adding 2 meters per week for electric heating,which they meter separately.At the Hatch Acres Corporation PR324582.Rev.0,Page 68 AK-BC Alaska Final Report 18-09-07.Doc nATGA AGE December project meeting in Ketchikan the development of a cannery (3 MW from May to Sept),a cold storage facility and the conversion of the hospital to electric heat were discussed.They are also pursuing port development,a regional solid waste facility as a possible energy plant and are looking for more development at the saw mill if it is sold.These are all longer term development opportunities.Without specific information as to load,load factor,timing and operating characteristics these potential developments could not be added to the load forecast. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report A spot load for a new kiln has been added to the forecast as has the conversion of the Wrangell Municipal offices to electric heat. Based on the reference case parameters listed in Table 3.2-13 for Wrangell the annual forecast is presented in Table 3.2-31 at the end of this report section.The table also includes historic values from 2000.The overall growth rate for net generation over the 25-year planning horizon is 2.2 percent per year based on the new kiln and the commercial conversion to electric heating early in the forecast. The monthly forecast is based on the monthly consumption patterns for the residential and non- residential sectors displayed in Figure 3.2-6 while the electric heating conversions are distributed on the basis of the heating degree day values for Wrangell.The three sets of monthly distribution values are listed in Table 3.2-16.The detailed annual and monthly forecasts are presented in Appendix H-3. Figure 3.2-6 Seasonal Consumption Patterns -Wrangell Wrangell -Seasonal Sales Patterns 12% .ro Residential Sales |10%oN o_s --- Total Sales 8%|-"=.»Non-Residential Sales___ 6%- 4%--- 2%{--ae 4 0%r 7 ;-;-T Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov'Dec Hatch Acres Corporation PR324582.Rev.0,Page 69 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 3.2-16 Monthly Sales Distribution -Wrangell Monthly Sales Distribution -Wrangell Non-Wrangell Residential _Residential Heating Existing Existing Deg-Days Jan 10.48%8.17%14.14% Feb 9.89%8.26%11.60% Mar 8.58%7.90%11.13% Apr 8.26%8.35%8.64% May 7.57%7.49%6.46% Jun 7.22%7.93%4.19% jul 6.55%8.49%3.09% Aug 7.26%10.20%3.24% Sep 7.57%9.05%5.05% Oct 7.67%7.69%8.18% Nov 8.70%8.33%11.06% Dec 10.23%8.14%13.21% Kake The City of Kake is seeing the loss of the logging industry and no new industrial development in its future.Currently all electricity is generated at the diesel plant;it is expensive and is a serious deterrent to new industry.The community struggles due to a lack of new jobs.With a connection to Petersburg and access to less expensive power the development a fish meal plant may move forward as well as expansion in other areas of the fish processing industry.For this forecast, residential conversions to electric heating have been delayed until 2015 to ensure that hydro supplies from Petersburg are well established.No commercial conversions are assumed. Based on the reference case parameters listed in Table 3.2-13 for Kake the annual forecast is presented in Table 3.2-32 at the end of this report section.The table also includes historic values from 2000.The overall growth rate for net generation over the 25-year planning horizon is approximately 1.8 percent per year based on the residential conversion to electric heating included in the forecast.A connection between Kake and Petersburg would enable the supply of hydro power at a cost very significantly below that of diesel power could result in higher growth as the lower cost of power spurs development of the economy. The monthly forecast is based on the monthly consumption patterns for the residential and non- residential sectors displayed in Figure 3.2-7 while the electric heating conversions are distributed on the basis of the average heating degree day values for Ketchikan,Petersburg and Wrangell.The three sets of monthly distribution values are listed in Table 3.2-17.The detailed annual and monthly forecasts are presented in Appendix H-4. Hatch Acres Corporation PR324582.Rev.0,Page 70 AK-BC Alaska Final Report 18-09-07.Doc nATGA AGH Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Figure 3.2-7 Seasonal Consumption Patterns -Kake Kake -Seasonal Sales Patterns 16% sd =,14%7 '-- rs + 10% 8% 6% 4%oo _ S.-:oe _=«Non-Residential Sales Residential Sales Total Sales 2% 0 %T T T Jan Feb Mar =Apr May Jun Oct NovJulAugSep Dec Table 3.2-17 Monthly Sales Distribution -Kake Monthly Sales Distribution -Kake Non-Kake Residential -_'Residential HeatingExistingExistingDeg-Days Jan 9.86%5.59%13.59% Feb 8.81%6.08 %11.08% Mar 8.48%5.82%10.81% Apr 8.07%5.85%8.41% May 7.73%5.35%6.48% Jun 7.90%6.73%4.28% Jul 7.53%12.99%3.44% Aug 7.46%14.98%3.89% Sep 8.16%13.29%5.71% Oct 8.07%9.06%8.51% Nov 8.84%7.47%10.97% Dec 9.09%6.81%12.82% Metlakatla Metlakatla Light &Power sees expansion at the Baldridge Aggregate mine as well as the fish processing plant although no specific details were available to this forecast.For this forecast residential conversions to electric heating have been included based on the existing hydro supplies. There are,however,no commercial conversions. Based on the reference case parameters listed in Table 3.2-13 for Metlakatla the annual forecast is presented in Table 3.2-33 at the end of this report section.The table also includes historic values from 2000.The overall growth rate for net generation over the 25-year planning horizon is 1.5 percent per year. AK-BC Alaska Final Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 71 nATGH ACRES Craig/Klawock/Thorne Bay/Hollis Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report There were no new developments discussed for the Prince of Wales Island communities nor is there any information on conversions to electric heating.This is understandable in that the hydro system,which now includes service to Hydaburg,has no surplus and requires some diesel generation to maintain supply. Based on the reference case parameters listed in Table 3.2-13 for Prince of Wales Island the annual forecast is presented in Table 3.2-34 at the end of this report section.The table also includes historic values from 1998.The overall growth rate for net generation over the 25-year planning horizon is 1.4 percent per year based on residential conversions to electric heating starting in 2020 when power from the development of additional on-island hydro power or an interconnection with the Swan-Tyee system is feasible. The monthly forecast is based on the monthly consumption patterns for the residential and non- residential sectors displayed in Figure 3.2-9 while the electric heating conversions are distributed on the basis of the average heating degree day values for Ketchikan,Petersburg and Wrangell.The three sets of monthly distribution values are listed in Table 3.2-19.The detailed annual and monthly forecasts are presented in Appendix H-6. Figure 3.2-9 Seasonal Consumption Patterns -Craig/Klawock/Thorne Bay/Hollis oy Craig/Klawock/Thorne Bay/Hollis -Seasonal Sales Patterns 12% 10%--,«Residential Sales -¢= -Total Sales8%|==-eomen ss .mawem__s Non-Residential Sales '-- 6% 4% 2% 0%r r +;., Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov'Dec Hatch Acres Corporation PR324582.Rev.0,Page 73 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Table 3.2-19 Monthly Sales Distribuion -Craig/Klawock/Thorne Bay/Hollis Monthly Sales Distribution Craig/Klawock/Thorne Bay/Hollis Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Non-Average Residential Residential Heating Existing Existing Deg-Days Jan 9.04%7.65%13.75% Feb 9.03%8.09%11.28% Mar 8.17%7.63%11.07% Apr 8.77%8.36%8.73% May 8.14%7.53%6.68% Jun 8.13%7.88%4.38% Jul 7.01%9.17%3.24% Aug 7.25%9.71%3.40% Sep 7.28%9.24%5.26% Oct 7.96%8.44%8.33% Nov 9.44%8.26%10.98% Dec 9.78%8.04%12.91% Hydaburg There were no new developments discussed for Hydaburg nor is there any specific information on spot loads or conversions to electric heating.Based on the reference case parameters listed in Table 3.2-13 for Prince of Wales Island the annual forecast for Hydaburg is presented in Table 3.2- 35 at the end of this report section.The table also includes historic values from 1998.The overall growth rate for net generation over the 25-year planning horizon is 1.8 percent per year based on residential conversions to electric heating starting in 2020 when power from the development of additional on-island hydro power or an interconnection with the Swan-Tyee system is feasible. The monthly forecast is based on the monthly consumption patterns for the residential and non- residential sectors displayed in Figure 3.2-10 while the electric heating conversions are distributed on the basis of the average heating degree day values for Ketchikan,Petersburg and Wrangell.The three sets of monthly distribution values are listed in Table 3.2-20.The detailed annual and monthly forecasts are presented in Appendix HO7. Hatch Acres Corporation PR324582.Rev.0,Page 74 AK-BC Alaska Final Report 18-09-07.Doc nATGA AGE Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Figure 3.2-10 Seasonal Consumption Patterns -Hydaburg Hydaburg -Seasonal Sales Patterns 12% 10%|N a ___©Residential Sales | -SS Total Sales »Non-Residential Sales 8% ” 6%fe oe 4 -_-_-_-He 4%|-=we 2%ee Soo 0%T T T T T | Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov'Dec | Table 3.2-20 Montly Sales Distribution -Hydaburg Monthly Sales Distribution Hydaburg Non-Average Residential Residential Heating Existing Existing Deg-Days Jan 10.58%9.10%13.75% Feb 10.16%9.25%11.28% Mar 8.74%8.30%11.07% Apr 8.87%8.59%8.73% May 8.63%8.11%6.68% Jun 7.62%7.51%4.38% Jul 5.66%7.51%3.24% Aug 5.96%8.11%3.40% Sep 6.50%8.39%5.26% Oct 7.62%8.22%8.33% Nov 9.37%8.33%10.98% Dec 10.29%8.59%12.91% Hatch Acres Corporation PR324582.Rev.0,Page 75 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGRES Coffman Cove Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report There were no new developments discussed for Coffman Cove nor is there any specific information on spot loads or conversions to electric heating.Based on the reference case parameters listed in Table 3.2-13 for Prince of Wales Island the annual forecast for Coffman Cove is presented in Table 3.2-36 at the end of this report section.The table also includes historic values from 1998.The overall growth rate for net generation over the 25-year planning horizon is 2.4 percent per year based on residential conversions to electric heating starting in 2020 when connection to the AP&T hydro system is assumed to be complete. The monthly forecast is based on the monthly consumption patterns for the residential and non- residential sectors displayed in Figure 3.2-11 while the electric heating conversions are distributed on the basis of the average heating degree day values for Ketchikan,Petersburg and Wrangell.The three sets of monthly distribution values are listed in Table 3.2-21.The detailed annual and monthly forecasts are presented in Appendix H-8. Figure 3.2-11 Seasonal Consumption Patterns -Coffman Cove Coffman Cove -Seasonal Sales Patterns 10%+---e Residential SalesfoTotalSales weems =s Non-Residential Sales Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov'Dec Hatch Acres Corporation PR324582.Rev.0,Page 76 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES Table 3.2-21 Monthly Sales Distribution -Coffman Cove Monthly Sales Distribution Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Coffman Cove Non-Average Residential -_Residential Heating Existing Existing Deg-Days Jan 10.61%9.05%13.75% Feb 9.78%8.83%11.28% Mar 8.41%7.92%11.07% Apr 8.41%8.08 %8.73% May 8.09%7.54%6.68% Jun 7.77%7.59%4.38% Jul 6.41%8.44%3.24% Aug 6.88%9.27%3.40% Sep 7.02%8.98%5.26% Oct 7.33%7.84%8.33% Nov 9.33%8.22%10.98% Dec 9.96%8.25%12.91% Naukati Bay There were no new developments discussed for Naukati Bay nor is there any specific information on spot loads or conversions to electric heating.Based on the reference case parameters listed in Table 3.2-13 for Prince of Wales Island the annual forecast for Naukati Bay is presented in Table 3.2-37 at the end of this report section.The table also includes historic values from 1998.The overall growth rate for net generation over the 25-year planning horizon is 0.9 percent per year based on residential conversions to electric heating starting in 2020 when connection to the AP&T hydro system is assumed to be complete. The monthly forecast is based on the monthly consumption patterns for the residential and non- residential sectors displayed in Figure 3.2-12 while the electric heating conversions are distributed on the basis of the average heating degree day values for Ketchikan,Petersburg and Wrangell.The three sets of monthly distribution values are listed in Table 3.2-22.The detailed annual and monthly forecasts are presented in Appendix H-9. Hatch Acres Corporation PR324582.Rev.0,Page 77 AK-BC Alaska Final Report 18-09-07.Doc BATU AGES Figure 3.2-12 Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Seasonal Consumption Patterns -Naukati Bay 14% 12% 8% 6% 4% 2% 0% Naukati Bay -Seasonal Sales Patterns 10%+ oN s Residential Sales 7 Total Sales Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov'Dec Table 3.2-22 Monthly Sales Distribution -Naukati Bay Monthly Sales Distribution Naukati Bay Non-Average Residential -_Residential Heating Existing Existing Deg-Days Jan 10.80%9.35%13.75% Feb 11.43%10.47%11.28% Mar 9.75%9.32%11.07% Apr 9.52%9.28%8.73% May 8.63%8.17%6.68% Jun 7.48%7.42%4.38% Jul 5.24%7.01%3.24% Aug 5.44%7.45%3.40% Sep 5.85%7.60%5.26% Oct 6.94%7.54%8.33% Nov 9.12%8.16%10.98% Dec 9.81%8.25%12.91% Hatch Acres Corporation PR324582.Rev.0,Page 78 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES Whale Pass Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report There were no new developments discussed for Whale Pass nor is there any specific information on spot loads or conversions to electric heating.Based on the reference case parameters listed in Table 3.2-13 for Prince of Wales Island the annual forecast for Whale Pass is presented in Table 3.2-38 at the end of this report section.The table also includes historic values from 1998.The overall growth rate for net generation over the 25-year planning horizon is 1.1 percent per year based on residential conversions to electric heating starting in 2020 when the community could possibly connect to the AP&T system. The monthly forecast is based on the monthly consumption patterns for the residential and non- residential sectors displayed in Figure 3.2-13 while the electric heating conversions are distributed on the basis of the average heating degree day values for Ketchikan,Petersburg and Wrangell.The three sets of monthly distribution values are listed in Table 3.2-23.The detailed annual and monthly forecasts are presented in Appendix H-10. Figure 3.2-13 Seasonal Consumption Patterns -Whale Pass ¥ Whale Pass -Seasonal Sales Patterns 16% 14%aoe oe t 12% 10% 8%|-mmm .ae a #Residential Sales_° Total Sales -s Non-Residential Sales 6%-------- 4%oe aaa 2% 0%7 r T T r r Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Hatch Acres Corporation PR324582.Rev.0,Page 79 AK-BC Alaska Final Report 18-09-07.Doc HATH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 3.2-23 Monthly Sales Distribution -Whale Pass Monthly Sales Distribution Whale Pass Non-Average Residential -_Residential Heating Existing Existing Deg-Days Jan 7.85%6.45%13.75% Feb 7.37%6.41%11.28% Mar 6.41%5.82%11.07% Apr 6.86%6.36%8.73% May 9.39%8.43%6.68% Jun 11.26%10.60%4.38% Jul 9.45%11.99%3.24% Aug 10.50%13.65%3.40% Sep 8.63%10.64%5.26% Oct 6.32%6.52%8.33% Nov 7.65%6.50%10.98% Dec 8.30%6.62%12.91% Hatch Acres Corporation PR324582.Rev.0,Page 80 AK-BC Alaska Final Report 18-09-07.Doc HATO AUER Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 3.2.5 Forecast Summary Table 3.2-24 summarizes the net generation forecast for the reference case by load center. Table 3.2-24 Net Generation -Reference Case NET GENERATION -REFERENCE YEAR Ketchikan Petersburg Wrangell Kake Metlakatla Prince of Wales System Prince of Wales Remote 1998 22,008,300 2,537,647 1999 24,916,800 2,636,477 2000 166,375,424 39,120,307 21,211,028 16,372,245 26,036,945 2,087,150 2001 166,133,715 40,841,874 20,650,274 15,327,234 25,456,637 1,439,855 2002 151,502,672 39,442,490 20,691,304 14,820,061 25,384,793 1,462,362 2003 153,472,585 39,627,828 20,372,554 15,122,842 26,011,522 1,510,776 2004 150,586,782 39,929,252 21,079,459 14,761,380 25,878,446 1,674,163 2005 153,306,333 41,708,013 21,598,602 15,316,636 25,972,300 1,738,785 2006 159,543,140 44,843,573 22,382,718 15,316,636 26,546,168 1,745,356 2007 164,195,077 42,037,124 22,300,166 3,166,174 15,434,358 25,685,497 1,676,440 2008 169,479,267 42,850,032 25,832,352 3,185,824 15,730,835 25,920,324 1,684,390 2009 172,659,475 43,649,659 26,343,055 3,205,700 16,023,047 26,156,961 1,692,422 2010 178,037,955 44,475,346 26,844,657 3,225,804 16,311,004 26,395,427 1,700,536 2011 181,141,042 48,300,345 29,121,423 3,246,137 16,594,717 26,635,740 1,708,733 2012 191,484,034 49,105,241 29,604,869 3,266,702 16,874,196 26,877,918 1,717,015 2013 194,514,993 49,897,139 30,084,551 3,287,502 17,149,451 27,121,980 1,725,381 2014 203,595,043 50,681,359 30,555,192 3,308,539 17,425,783 27,367,946 1,733,833 2015 206,591,619 51,457,929 31,016,808 3,414,567 17,697,913 27,615,833 1,742,371 2016 209,558,011 52,226,879 31,474,706 3,520,837 17,965,852 27,865,661 1,750,997 2017 212,511,846 52,988,239 31,923,610 3,622,061 18,229,611 28,117,450 1,759,711 2018 215,441,214 53,747,329 32,368,826 3,723,531 18,494,490 28,371,220 1,768,513 2019 218,346,242 54,498,888 32,810,371 3,819,960 18,788,683 28,626,989 1,777,406 2020 221,264,797 55,242,947 33,301,433 3,916,640 19,078,912 29,475,088 1,871,142 2021 224,164,744 55,984,828 33,788,992 4,008,283 19,370,481 30,309,470 1,954,388 2022 227,046,215 56,737,214 34,273,064 4,100,183 19,658,113 31,119,576 2,037,727 2023 229,927,409 57,482,383 34,753,668 4,192,342 19,947,112 31,916,009 2,121,159 2024 232,795,877 58,225,660 35,230,822 4,279,473 20,232,200 32,698,791 2,204,686 2025 235,651,755 58,967,077 35,704,545 4,366,867 20,518,683 33,467,943 2,283,017 2026 238,528,204 59,706,671 36,174,855 4,454,529 20,801,285 34,223,489 2,361,444 2027 241,397,828 60,444,475 36,641,772 4,537,170 21,085,308 34,965,450 2,439,967 2028 244,260,772 61,180,525 37,110,604 4,620,083 21,365,479 35,699,142 2,513,298 2029 247,182,428 61,914,856 37,576,080 4,703,271 21,647,100 36,424,585 2,581,438 2030 250,097,894 62,647,503 38,038,220 4,781,446 21,930,188 37,131,224 2,649,677 2031 253,046,131 63,378,503 38,497,043 4,859,902 22,209,466 37,829,661 2,712,726 AK-BC Alaska Final Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 81 HATGH AUER 3.2.6 Sensitivity Analysis Alaska Energy Authority -AK-BC Intertie Feasibility Study SE AlaskaFinalReport In addition to the reference forecast,low and high forecasts have also been developed.Theforecastsaredefinedbylower(or higher)basic growth rates in the residential and non-residential sectors as well as less (or more)aggressive conversions to electric heat. in the low case,a 50 percent factor has been assigned to the commercial conversions to electricheating.This factor can be viewed as a probability that the forecast values will either not beachievedasplannedorthattherewillbeinterruptionsinthepowersupplyunderinterruptibletariffsforelectricheating..Table 3.2-25 lists the principal forecast parameters for the low case. Table 3.2-25 Principal Forecast Parameters -Low Case LOW FORECAST Prince of Ketchikan Petersburg Wrangell Kake Metlakatla Wales Island Residential Customer Growth 0.50%0.50%0.50%0.50%0.50%0.50% Unit Consumption Growth 0.50%0.50%0.50%0.50%0.50%0.50% Non-Residential Customer Growth 0.25%0.25%0.25%0.25%0.25%0.25% Unit Consumption Growth 0.00%0.00%0.00%0.00%0.00%0.00% Heating Conversions Start Year |2000 2000 2000 2015 2000 2020 New Customers Full Conversions 40.0%40.0%40.0%40.0%40.0%40.0% Partial Conversions 0.0%0.0%0.0%.0.0%0.0%0.0% Existing Customers Full Conversions 0.0%0.0%0.0%0.0%0.0%0.0% Partial Conversions 5.0%5.0%5.0%5.0%5.0%5.0% Maximum Full Conversions 30.0%30.0%30.0%30.0%30.0%30.0% Unit Consumption (kWh) Full Conversions 16,975 19,100 18,090 18,090 18,090 18,090 Partial Conversions 5,000 5,000 5,000 5,000 5,000 5,000 Hatch Acres Corporation PR324582.Rev.0,Page 82 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES In the high case,a 100 percent factor has been assigned to the commercial conversions to electric heating.This factor can be viewed as a probability that the forecast values will be achieved as planned.Table 3.2-26 lists the principal forecast parameters for the high case. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 3.2-26 Principal Forecast Parameters -High Case HIGH FORECAST Prince of Ketchikan Petersburg Wrangell Kake Metlakatla Wales Island Residential Customer Growth 0.75%0.75%0.75%0.75%0.75%0.75% Unit Consumption 1.00%1.00%1.00%1.00%1.00%1.00% Growth Non-Residential Customer Growth 0.50%0.50%0.50%0.50%0.50%0.50% Unit Consumption 0.00%0.00%0.00%0.00%0.00%0.00% Growth Heating Conversions Start Year |2000 2000 2000 2015 2000 2020 New Customers Full Conversions 60.0%60.0%60.0%60.0%60.0%60.0% Partial Conversions 0.0%0.0%0.0%0.0%0.0%0.0% Existing Customers Full Conversions 0.0%0.0%0.0%0.0%0.0%0.0% Partial Conversions 5.0%5.0%5.0%5.0%5.0%5.0% Maximum Full 40.0%40.0%40.0%40.0%40.0%40.0% Conversions Unit Consumption (kWh) Full Conversions 20,747 23,344 22,110 22,110 22,110 22,110 Partial Conversions 5,000 5,000 5,000 5,000 5,000 5,000 Table 3.2-27 summarizes the net generation forecast for the low case by load center. Table 3.2-28 summarizes the net generation forecast for the high case by load center. The year by year values for the low,reference and high forecasts are shown graphically in Figure 3.2-14. The annual reference forecast data for each of the SE Alaska communities is contained in Tables H- 1 through H-10 which are located in Appendix H. Hatch Acres Corporation PR324582.Rev.0,Page 83 AK-BC Alaska Final Report 18-09-07.Doc nATGH AGES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 3.2-27 Net Generation -Low Case NET GENERATION -LOW Prince of Prince of YEAR Ketchikan 'Petersburg ==Wrangell Kake Metlakatla Wales Wales System Remote 1998 22,008,300 |2,537,647 1999 24,916,800 |2,636,4772000|166,375,424 |39,120,307 |21,211,028 16,372,245 |26,036,945 |2,087,150 2001 |166,133,715 |40,841,874 |20,650,274 15,327,234 |25,456,637 |1,439,855 2002 |151,502,672 |39,442,490 |20,691,304 14,820,061 |25,384,793 |1,462,362 2003 |153,472,585 |39,627,828 |20,372,554 15,122,842 |26,011,522 |1,510,776 2004 |150,586,782 |39,929,252 |21,079,459 14,761,380 |25,878,446 |1,674,163 2005 |153,306,333 |41,708,013 |21,598,602 15,316,636 |25,972,300 {1,738,785 2006 |159,543,140 |44,843,573 |22,382,718 15,316,636 |26,546,168 |1,745,356 2007 |163,448,149 |41,839,538 |22,179,606 |3,157,968 |15,384,355 |25,581,999 |1,671,870 2008 |167,948,079 |42,453,470 |25,590,398 |3,169,272 |15,630,302 |25,712,325 |1,678,1132009|170,285,938 |43,052,715 |25,978,862 |3,180,658 |15,871,449 |25,843,447 |1,684,4032010|174,249,705 |43,637,281 |26,357,370 |3,192,127 |16,107,799 |25,975,368 |1,690,7392011|176,515,679 |45,718,649 |27,618,051 |3,203,680 |16,339,357 |26,108,095 |1,697,1212012|182,371,755 |46,279,170 |27,976,660 |3,215,316 |16,566,125 |26,241,633 |1,703,550 2013 |184,547,230 |46,830,326 |28,325,325 |3,227,037 |16,788,107 |26,375,987 |1,710,0262014|189,722,643 |47,372,125 |28,669,342 |3,238,843 |17,010,596 |26,511,162 |1,716,549 2015 |191,813,046 |47,904,575 |29,003,424 |3,314,220 |17,228,306 |26,647,165 |1,723,121 2016 |193,866,252 |48,427,684 |29,327,576 |3,384,393 |17,441,240 |26,784,001 |1,729,740 2017 |195,899,475 |48,941,461 |29,647,091 |3,454,652 |17,649,401 |26,921,675 |1,736,407 2018 |197,900,979 |49,445,914 |29,961,976 |3,519,709 |17,852,793 |27,060,193 |1,743,124 2019 |199,870,802 |49,941,052 |30,266,943 |3,584,853 |18,056,710 |27,199,560 |1,749,8892020|201,814,269 |50,432,172 |30,575,969 |3,644,795 |18,255,865 |27,820,439 |1,820,188 2021 |203,726,126 |50,913,994 |30,880,464 |3,704,826 |18,450,261 |28,421,017 |1,879,957 2022 |205,616,989 |51,391,816 |31,180,433 |3,764,947 |18,645,192 |29,001,299 |1,939,775 2023 |207,481,605 |51,860,356 |31,475,881 |3,819,868 |18,835,372 |29,574,056 |1,999,6442024|209,337,609 |52,324,914 |31,766,812 |3,874,879 |19,026,094 |30,131,894 |2,059,5632025|211,172,853 |52,797,840 |32,053,233 |3,924,692 |19,212,072 |30,669,529 |2,114,242 2026 |212,987,374 |53,266,925 |32,335,148 |3,974,596 |19,398,600 |31,197,550 |2,168,973 2027 |214,786,502 |53,732,177 |32,612,563 |4,024,593 |19,580,391 |31,710,671 |2,223,756 2028 |216,564,984 |54,193,608 |32,885,482 |4,074,684 |19,762,738 |32,214,190 |2,273,300 2029 |218,328,149 |54,651,225 |33,153,912 |4,119,578 |19,945,647 |32,708,114 |2,317,606 2030 |220,111,971 |55,105,040 |33,423,148 |4,164,566 |20,123,830 |33,181,868 |2,361,9652031|221,880,681 |55,555,063 |33,687,904 |4,209,649 |20,302,581 |33,646,039 |2,401,086 AK-BC Alaska Final Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 84 ATG ACRES Table 3.2-28 Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Net Generation -High Case Final Report YEAR Ketchikan Petersburg NET GENERATION HIGH Wrangell Kake Metlakatla Prince of Wales System Prince of Wales Remote 1998 22,008,300 2,537,647 1999 24,916,800 2,636,477 2000 166,375,424 39,120,307 21,211,028 16,372,245 26,036,945 2,087,150 2001 166,133,715 40,841,874 20,650,274 15,327,234 25,456,637 1,439,855 2002 151,502,672 39,442,490 20,691,304 14,820,061 25,384,793 1,462,362 2003 153,472,585 39,627,828 20,372,554 15,122,842 26,011,522 1,510,776 2004 150,586,782 39,929,252 21,079,459 14,761,380 25,878,446 1,674,163 2005 153,306,333 41,708,013 21,598,602 15,316,636 25,972,300 1,738,785 2006 159,543,140 44,843,573 22,382,718 15,316,636 26,546,168 1,745,356 2007 164,484,346 42,111,953 22,353,221 3,169,241 15,454,089 25,711,171 1,678,097 2008 170,065,032 43,000,937 25,939,158 3,192,065 15,770,792 25,972,528 1,687,746 2009 173,547,070 43,877,911 26,504,323 3,215,221 16,083,733 26,236,568 1,697,522 2010 180,423,860 44,779,310 27,061,111 3,238,714 16,392,933 26,503,326 1,707,426 2011 183,839,898 51,699,061 31,178,050 3,262,548 16,698,412 26,772,839 1,717,458 2012 201,772,287 52,582,455 31,718,172 3,286,728 17,000,189 27,045,140 1,727,622 2013 205,122,429 53,459,576 32,250,005 3,311,259 17,298,286 27,320,268 1,737,918 2014 220,612,574 54,330,478 32,778,869 3,336,144 17,592,723 27,598,259 1,748,348 2015 223,937,277 55,195,220 33,299,504 3,448,269 17,883,522 27,879,149 1,758,913 2016 227,243,304 56,053,859 33,811,941 3,560,757 18,175,993 28,162,978 1,769,616 2017 230,560,109 56,906,452 34,321,500 3,668,324 18,464,869 28,449,782 1,780,459 2018 233,858,972 57,753,059 34,828,213 3,776,266 18,750,171 28,739,601 1,791,441 2019 237,140,140 58,599,031 35,326,822 3,879,295 19,073,210 29,032,474 1,802,567 2020 240,422,089 59,439,136 35,860,161 3,982,708 19,392,972 29,957,301 1,900,716 2021 243,692,400 60,273,437 36,390,936 4,081,220 19,709,483 30,869,548 1,988,430 2022 246,951,333 61,120,451 36,919,183 4,180,125 20,028,060 31,758,677 2,076,292 2023 250,234,431 61,967,337 37,444,938 4,279,429 20,343,440 32,635,313 2,164,304 2024 253,512,243 62,808,875 37,968,238 4,373,846 20,660,941 33,499,499 2,252,467 2025 256,785,044 63,650,422 38,489,119 4,468,673 20,975,300 34,345,990 2,335,493 2026 260,066,842 64,492,048 39,007,620 4,558,624 21,291,835 35,185,412 2,418,674 2027 263,349,755 65,333,822 39,523,777 4,648,995 21,605,285 36,012,520 2,502,012 2028 266,634,073 66,175,815 40,037,630 4,739,792 21,920,969 36,832,651 2,580,219 2029 270,008,075 67,018,100 40,549,216 4,825,729 22,238,916 37,640,561 2,653,297 2030 273,384,355 67,860,748 41,063,867 4,912,103 22,553,865 38,436,297 2,726,537 2031 276,799,601 68,703,833 41,576,330 4,998,919 22,871,137 39,225,199 2,794,652 AK-BC Alaska Fina!Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 85 HATA AGEN Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Figure 3.2-14 Net Generation Forecast -All Sensitivities Net Generation -Ketchikan,Petersburg,Wrangell,Kake &Metlakatla 450 High 400 - Reference 350 a tow300 Net Generation (GWh) 250 - 200 150 100 ; 50 | 0 T qt r q iu q a T u T T qT t T tT T T T T T 1998 2001 2004 2007 +2010 2013 2016 2019 2022 2025 2028 2031 T T T r T T T T T T T Hatch Acres Corporation PR324582.Rev.0,Page 86 AK-BC Alaska Final Report 18-09-07.Doc navi ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 4.EXTERNAL MARKETS AND MARKET STRUCTURE Hatch Acres Corporation PR324582.Rev.0,Page 87 HATGH AGES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 4.EXTERNAL MARKETS AND MARKET STRUCTURES 4.1 Overview Power demands in both British Columbia (BC)and the Pacific Northwest (PNW)are expected to grow substantially over the next 10 -20 years.This growth plus electricity policy changes in BC and the PNW represent a potential export opportunity for competitively priced hydropower exports from SE Alaska. The 2007 BC Energy Plan issued by the BC Ministry of Energy,Mines and Petroleum Reserves will shape energy acquisition and transmission line development in BC for the foreseeable future. The Bonneville Power Administration (BPA)is modifying its long-term power marketing program. Major changes will occur in the PNW region post 2011 when BPA significantly reduces its obligation to meet load growth of its customers by acquiring new generation resources. This section provides a snapshot view based on information available to date regarding market realities and potential opportunities to sell Alaskan-generated power into markets in BC and the PNW. 4.1.1 Wholesale Market Prices The D.Hittle Report of March 2006 posited a range of competitive delivered prices at $60 - $72/MWh.Delivered prices include transmission charges and ancillary service costs,as well as the cost of generating the electricity.We believe this range of delivered prices represents a reasonable proxy for competitive out-year power prices in both BC and the PNW expressed in 2006$(i.e.with no allowance for general price level increases).If project prices exceed $60 /MWh they may be economic to export,but competitiveness will depend on greenhouse gas (GHG)restrictions increasing future BC/PNW market prices. Recent resource acquisition trends in both BC and the PNW support this projected price level.For example,BC Hydro's 2005 resource solicitation reportedly yielded prices in the $70/MWh range. Similarly,Puget Sound Energy's 2006 resources request produced bid prices averaging $70 - 100/MWh.These prices represented an increase of nearly 50 percent from Puget Sound Energy's 2004 resources request. 4.1.2.Global Power Prices Rapidly increasing power prices in BC and the PNW mirror worldwide pricing trends.Since 2003/04,out-year electricity prices in both regions have risen from roughly $40/MWh to $60/MWh.These trends fundamentally track dramatic recent increases in world oil prices from $30/barrel (bbl)a few years ago,to $55 -75/bbl today.Unlike past oil price increases,which were caused by temporary supply interruptions,recent increases are driven by energy demands of China and other Asian countries and are likely to remain at high levels for the foreseeable future. Hatch Acres Corporation PR324582.Rev.0,Page 88 AK-BC Alaska Final Report 18-09-07.Doc HATCH AGRE 4.1.3 Implications for British Columbia &Pacific Northwest Markets Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Oil and natural gas prices are loosely linked,since the two fuels often substitute for each other in non transportation end uses.Since natural gas fired combined cycle combustion turbines (CCCTs) have been the predominant new power resource for the last 15 years,and since natural gas fuel costs represent most of the CCCT power cost,the marginal cost of power has steadily increased as oil and natural gas costs have risen in recent years.With CCCTs representing the resource of choice at the margin,it seems likely that this $60 -70/MWh market price range will continue,and perhaps even increase,in the 2010 -2020 timeframe.Coal,the only other potential generation substitute,will likely have higher delivered costs resulting from expected costly GHG restrictions in the next 3 -5 years and significant transmission costs to transport coal generated power to the consuming loads in the PNW. 4.1.4 Recent Policy Changes While Alaskan projects with delivered costs in the $60-$70/MWh range seem assured of being competitive,projects with higher delivered costs may still be viable in light of recent policy changes in both the U.S.and British Columbia.First,several western states and British Columbia have recently announced policies to significantly limit GHG and encourage renewable resource development.These policies will likely merge with legislation on GHG by the U.S.federal government,probably in the form of a cap and trade system.Second,the proliferation of Renewable Portfolio Standards (RPS),plus the transmission and shaping costs (for wind)to integrate these resources,will probably increase overall acquisition costs for renewable resources. This combination of factors,if they materialize as recently predicted,will essentially preclude any coal resources,other than (possibly)Integrated Gasification Combined Cycle (IGCC)”®,and will result in substantially higher prices for coal based resources and other comparable alternatives.It, therefore,seems possible for clean resources above $70/MWh to be viable.While far from certain, these recent developments could well push market prices significantly higher in the 2010-2020 timeframe.Although significant imports of liquefied natural gas (LNG)might moderate these projected increases,the slow pace of LNG development to date (driven primarily by capital investment requirements and siting concerns)makes such market price moderation seem unlikely. 4.1.5 Levelized Hydro Costs Another framework for considering the value,and ultimate competitiveness,of SE Alaskan hydro projects would be to spread the development and construction costs over the entire 50-year life of their FERC license.This approach would levelize the cost over that period,rather than expressing the cost in 2007 (or some other base year)nominal dollars and only spreading costs over the 20- year duration of the anticipated power purchase agreement.For capital-intensive resources such as new hydro projects,the levelized cost is typically 50 to 60 percent of the first year nominal cost. Therefore,a hydro project whose nominal cost would be $90/MWh would have a levelized cost of $45/MWh to $50/MWh. 26 Integrated Gasification Combined Cycle is a clean coal technology that turns coal into a gas,and then removes impurities from the coal gas before it is combusted. Hatch Acres Corporation PR324582.Rev.0,Page 89 AK-8C Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report To use this approach,however,the State of Alaska would require the projects to produce power as designed for the full 50-year license term.Whether the private sector development model currently assumed for the proposed new hydro projects at Thomas Bay would,in fact,produce such long- term benefits would thus become a key issue for the State to evaluate. Such an evaluation requires both project development and legal expertise and should be pursued in Phase 11 of this feasibility study. 4.1.6 Power Marketing Oversight Unit A Power Marketing Oversight Unit could be formed to manage marketing surplus power for export. The concept of a Power Market Oversight Unit surfaced in conjunction with using levelized cost (as opposed to nominal costs)for evaluating the long-term marketability of proposed new projects as discussed in Section 4.1.5 above.The Power Market Oversight Unit could be formed as a separate State government entity,or simply as an added set of responsibilities for AEA,to provide power marketing oversight for export of surplus power from new hydro projects that might be encouraged if the State finances the proposed AK-BC Intertie segment (see discussion in Section 2.2.2.3). 4.2 British Columbia Market Nearly all of British Columbia is served by the provincial electric utility,BC Hydro and delivered on the transmission grid operated by the British Columbia Transmission Corporation (BCTC).Like the PNW !OUs,BC Hydro has been actively soliciting new resources since 2003.This aggressive resource acquisition plan is driven by both the need to meet provincial load growth and by BC's recently articulated policy,as stated in the BC Energy Plan,of resource self sufficiency since BC is currently a net importer of electricity.Given its proximity to Northwest BC and the nature of its resources,SE Alaska hydropower would be well positioned to meet BC electricity needs.Such exports could be directed either to BC Hydro for retail load service,or to Powerex (the wholesale marketing subsidiary of BC Hydro)for resale to PNW or California markets. 4.2.1.BC Energy Plan The future energy market in BC will be shaped by a policy statement delivered on February 13, 2007 to the Parliament in the Speech from the Throne”'and the announcement and release of the BC Energy Plan”by the Ministry of Energy,Mines,and Petroleum Resources on February 27,2007. BC's evolving energy policy as addressed in the Speech from the Throne and the BC Energy Plan are of interest to State of Alaska and may shape future development of the energy sector in SE Alaska. 27 British Columbia Speech from the Throne presented by lona Campagnolo,Lieutenant-Governor,at the Opening of the Third Session,Thirty-Eighth Parliament of the Province of British Columbia,February 13, 2007. 8 The BC Energy Plan:A Vision for Clean Energy Leadership was issued by the Premier Gordon Campbell and Richard Neufeld,Minister of Energy,Mines and Petroleum Resources on February 27,2007. Documents regarding The BC Energy Plan are available on the web at www.gov.bc.ca -Ministry of Energy Mines and Petroleum Resources Hatch Acres Corporation PR324582.Rev.0,Page 90 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The BC Energy Plan:A Vision for Clean Energy Leadership is designed to achieve energy self- sufficiency while taking responsibility for stewardship of BC's natural environment and climate.BC is currently dependent on other jurisdictions for up to 10%of its electricity supply.BC Hydro estimates demand for electricity to grow by up to 45%over the next 20 years.The BC Energy Plan includes a goal of achieving electricity self-sufficiency by 2016.Through the BC Energy Plan,the government will set policies to guide BC Hydro in producing and acquiring enough electricity in advance of future need. Of interest to the State of Alaska,Powerex”?will continue to market power to the Lower 48.This may provide market incentive to Alaska notwithstanding the BC Hydro goal to reduce electricity imports as set forth in the recently issued BC Energy Plan®'. The following sections present a snapshot view of emerging energy policy in BC and identify potential constraints and opportunities that could shape successful sales of electricity from Alaskan generation projects*': 4.2.1.1 Energy Conservation and Efficiency The BC Energy Plan sets an ambitious conservation target to acquire 50%of BC Hydro's incremental resource needs through conservation by 2020.The government will work closely with BC Hydro and other utilities to research,develop,and implement best practices in conservation and energy efficiency and to increase public awareness.Utilities are also encouraged to explore and develop rate designs to encourage efficiency,conservation and development of renewable energy. 4.2.1.2 Electricity Policies The BC Energy Plan establishes a goal to reduce dependence on other jurisdictions for electricity. BC currently imports up to 10%of its electricity supply.BC Hydro estimates demand for electricity to increase up to 45%over the next 20 years.The Energy Plan states that "The Province wants to ensure that British Columbia has the reliable made-in-BC supply it needs to meet the growing demand for electricity,and that new resource acquisition is planned in a way that recognizes the long lead time and implementation risks associated with new power projects,and the challenges of forecasting future needs.” Energy Self-Sufficiency The BC Energy Plan establishes a goal to ensure self-sufficiency to meet electricity needs by 2016, including acquiring an additional supply of "insurance power”beyond the projected increases in demand to minimize the risk and implications of having to rely on electricity imports.Ensure that 9 Powerex is the wholly-owned power marketing subsidiary of BC Hydro,Canada's third largest electric utility.Established in 1988. 3°Statement by Premier Gordon Campbell on February 27,2007:"Our plan will make B.C.energy self- sufficient by 2016.” 31 Sales of Alaskan-generated electric power could occur with completion of the proposed international transmission interconnection via the AK-BC Intertie and/or direct sale from Alaska to BC (e.g.potential to sell generation from AP&T's proposed Soule River Project to Stewart BC.) Hatch Acres Corporation PR324582.Rev.0,Page 91 AK-BC Alaska Final Report 18-09-07.Doc nAvGH ACHES BC Hydro has enough BC-based power at all times,even in low water years,to meet its customers' electricity needs. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Under the Plan,by 2026,BC Hydro is projected to acquire 3,000 gigawatt hours of supply on top of their firm energy requirements (energy required to meet customer needs under critical water conditions)and capacity resources needed to effectively integrate this energy in a cost-effective manner. Standing Offer for Clean Electricity Projects Up to 10 MW BC Hydro is directed to establish a Standing Offer Program with no quota to encourage small (less than 10 MW)and clean electricity producers.Under the Standing Offer Program,BC Hydro will purchase directly from suppliers at a fixed price with standard terms and conditions based on prices paid in the most recent BC Hydro energy call.The program design will be subject to the review and approval of the British Columbia Utilities Commission (BCUC).Specific design guidelines include: e Except for local safety and security reasons,there should be no quota initially for the Standing Offer program e The product should be contractually non-firm energy e Transmission or distribution connected projects of 10 MW or less,and either clean, renewable or co-generation with an overall efficiency (heat and electricity production)in excess of 80%will be eligible for the program e BC Hydro will absorb transmission/distribution network upgrade costs for individual projects subject to a cap established in consultation with stakeholders and approval from the BCUC,after which project proponents may be required to pay for additional network upgrade costs e BC Hydro will retain any rights and incentives associated with the green attributes,as well as any credits associated with greenhouse gas emissions (GHG). Electric Transmission Technology and Infrastructure The Energy Plan directs BCTC to move from its current contract-driven practice of planning system upgrades and new transmission projects in response to a customer's request to adopt an approach that builds infrastructure in advance of need.BCTC will study and propose,where appropriate, system upgrades or expansions based,in part,on its own assessment of future market needs.Three types of transmission projects will benefit from this approach: e A planned system upgrade for a Network Customer already identified in the BCTC Capital Plan that can be beneficially advanced in time e Asystem upgrade required for a customer that can beneficially be made larger than the immediate requirement e A project that BCTC identifies as having future benefits,but which has not been triggered by a customer request. Hatch Acres Corporation PR324582.Rev.0,Page 92 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES BCTC will identify the third type of project through an annual project review designed to identify possible projects that would be viable as a BCTC led investment. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report BCTC will only proceed with an upgrade or expansion project after completion of a strong business case that identifies the costs and benefits of the proposed project,completion of stakeholder and First Nation consultations,and receipt of all necessary regulatory approvals. Generation Projects Currently in BC,approximately 90%of electricity is from clean or renewable resources.The government will issue guidelines to define what sources qualify as clean or renewable,and will provide additional policy guidance and directions,as needed,to ensure BC continues to meet this standard. Under the BC Energy Plan all new electricity generation projects will have zero net greenhouse gas emissions.Currently,electricity accounts for only a small portion (around 3%in 2004)of the province's overall GHG emissions. e All new natural gas or oil-fired electricity generation projects developed in BC and connected to the integrated grid are required to have zero net GHG emissions.Proponents of these generation projects will be required to invest in other initiatives to completely offset the GHG emissions generated by these projects,unless available technology can eliminate or capture and store emissions from the plant e Existing thermal generation power plants will be required to achieve zero net GHG by 2016 e The BC Energy Plan continues the Province's commitment that nuclear power is not a part of BC's energy future e The BC Energy Plan recognizes that low cost means more than least financial costs. Environmental,social,and economic development objectives of the province are also values that need to considered. Procurement of Aggregated Intermittent Resources?” BC has substantial potential to develop green resources such as wind and small hydro,and doing so is an objective of the BC Energy Plan.BC Hydro,with stakeholder input,will develop an approach to allow for recognition of any additional value associated with intermittent clean or renewable energy projects,including portfolio benefits,for the purposes of evaluating these generators'capacity and firm energy output in its energy calls and acquisition processes. 4.2.2 BC Hydro BC Hydro is the largest electric utility in British Columbia and a provincial Crown corporation reporting to the Minister of Energy and Mines. 32 Intermittent resources are those for which the 'fuel'supply to the generator (e.g.wind or water flow)is not always available and cannot be 'ordered'when needed. Hatch Acres Corporation PR324582.Rev.0,Page 93 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES BC Hydro serves more than 1.7 million customers in an area containing over 94%of British Columbia's population.BC Hydro's policy is "to provide energy solutions to its customers in an environmentally and socially responsible way by balancing British Columbians'energy needs with the concerns of the environment.BC Hydro has constructed a world-class integrated hydroelectric system of close to 11,500 MW of generating capacity with over 10,000 MW of hydroelectric power.BC Hydro customers enjoy some of the lowest electricity rates in the world.”® Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report BC Hydro's primary business activities are the generation and distribution of electricity.BC Hydro operates 30 hydroelectric facilities and three natural gas-fuelled thermal power plants.About 80 per cent of the province's electricity is produced by major hydroelectric generating stations on the Columbia and Peace rivers.BC Hydro's various facilities generate between 43,000 and 54,000 GWh of electricity annually,depending on prevailing water levels. e For fiscal 2006,domestic electric sales volume reached 52,440 GWh e For fiscal 2006,net income was $266 million,which resulted in a return on equity of 9.26 per cent. Electricity is delivered to customers through an interconnected system of about 18,280 kilometres of transmission lines and 56,000 kilometres of distribution lines.BC Hydro's backbone electric system is interconnected with the western US by two 500 kV transmission lines on the west coast between BC and Washington State.The transmission assets are owned by BC Hydro;the management and operation of the transmission system is the responsibility of the British Columbia Transmission Corporation (BCTC). The recently issued BC Energy Plan includes directives that will shape the future market into which Alaskan-generated power could be sold.In the plan,BC Hydro is required to produce and/or acquire electricity to ensure delivery within the province during the most critical water year and achieve electricity self sufficiency by 2016.Recognizing that development of new electricity generation and transmission infrastructure require long lead times,BC Hydro must acquire an additional supply of "insurance power”beyond the projected increases in demand to minimize the risk and implications of having to rely on electricity imports. The BC Energy Plan states that "Achieving electricity self-sufficiency in British Columbia will require a range of new power sources to be brought on line.BC Hydro will establish a Standing Offer Program with no quota to encourage small and clean electricity producers.”Qualifying criteria include that eligible projects must be less than 10 MW and be clean electricity or high efficiency electricity cogeneration.The standard offer price will be based on the prices paid in the most recent BC Hydro energy call. 4.2.2.1 BC Hydro Call for Tenders -Electricity Purchase Agreements BC Hydro contracts with Independent Power Producers (IPPs)to ensure new additional resources for energy are secured to meet customer's needs.BC Hydro does this through competitive procurement processes.On March 7,2005 BC Hydro filed its 2005 Resource Expenditure and Acquisition Plan ("2005 REAP”)with the British Columbia Utilities Commission (BCUC).The 2005 33 Source -BC Hydro Website -www.bchydro.com Hatch Acres Corporation PR324582.Rev.0,Page 94 AK-BC Alaska Final Report 18-09-07.Doc ATG AGEN REAP included a request for approval of the need for the F2006 Call for Tenders ("F2006 Call”).BC Hydro's 2006 Open Call for Power attracted 37 bidders who submitted 53 projects which represented approximately 1800 MW of potential capacity (not including alternate versions of different projects.) Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 4.2.2.2 Load/Resource Gap Currently BC imports approximately 10%of its electricity.In the recently issued BC Energy Plan, BC Hydro estimates demand for electricity to grow by up to 45%over the next 20 years.The BC government envisions that BC Hydro will acquire electric generation resources sufficient to meet customer needs at all times,even in low water years. The BC Energy Plan forecasts that by 2026 BC Hydro will acquire 3,000 gigawatt hours of supply on top of their firm energy requirements (energy to meet customer needs under critical water conditions)and capacity resources needed to effectively integrate this energy in a cost effective manner. The load forecast used by BC Hydro for the F2006 Call was based on its December 2004 forecast. The increase in the load forecast in the February 2006 update over the December 2004 forecast was**: YEAR HIGH (GWh)MID (GWh)LOW (GWh) F2007 1,640 1,771 1,857 F2008 1,940 2,193 2,421 F2009 1,831 2,205 2,532 F2010 2,243 2,701 3,146 F2011 2,133 2,713 3,232 F2012 2,724 3,340 3,945 BC Hydro filed a revised "2006 System Energy Supply-Demand Outlook”*(Report,p.38),which identified the following deficits from the Mid-Load Forecast: 34 BC Hydro's Annual Report 2006,Table 7,p.33 3 1D,page 38 Hatch Acres Corporation PR324582.Rev.0,Page 95 AK-8C Alaska Final Report 18-09-07.Doc ATG AUER YEAR DEFICIT*EXISTING DSM NET F2007 1,300 1,200 100 F2008 1,600 1,600 - F2009 4,400 1,900 2,500 F2010 5,700 2,200 3,500 F2011 7,900 2,500 5,400 F2012 9,000 2,700 6,300 Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report *Before BC Hydro's non-firm energy/market allowance of 2500 GWh/year. In FY 2012 (the first full year of all awarded projects)BC Hydro forecasts that it will have the following firm sources of new supply: SOURCE FIRM ENERGY (GWh) Revelstoke 5 100 Alcan Inc 1,000 Brilliant Expansion 200 F2006 Call (net of attrition and outages)4,000 Total 5,300 Based on the mid-load forecast before demand side management (DSM)of 65,000 GWh, committed supply of 56,000 GWh and existing DSM of 2,700 GWh BC Hydro projects a deficit of 1,000 GWh in FY 2012 after taking into account the new sources of supply set out in the table above.Both Revelstoke 5 and the Alcan LTEPA require Commission approval. BC Hydro presents a capacity forecast for F2012 showing a deficit of 700 MW after existing DSM programs which BC Hydro proposes to meet as follows: SOURCE MW Revelstoke 5 500 Alcan Inc 100 Brilliant Expansion 100 F2006 Call (net)600 Total 1,200 AK-BC Alaska Final Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 96 HATH AGHED 4.2.3 Powerex Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Powerex is a wholly-owned power marketing subsidiary of BC Hydro for sales outside the province.Established in 1988,Powerex is a separate Crown Corporation with its own Board of Directors.Powerex holds all necessary trade permits including export permits from the Canadian National Energy Board;export permits from the US Department of Energy and holds Power Marketing Authorization from FERC,enabling Powerex to buy and sell power anywhere in the US and to deliver power directly from BC to its US customers. Powerex is very active in both the PNW and California wholesale electricity markets.Since its creation in 1988,Powerex has focused principally on short term transactions (daily,weekly, monthly and/or seasonal sales or exchanges).More recently,it has entered into multi year sales, but none for longer than five years.A sale of AK hydro project output to Powerex for resale to PNW markets is a distinct possibility if AK hydro output can be priced competitively with other generation alternatives.This sale/resale alternative would certainly by feasible for short term transactions.Longer than five years sales might also be possible,but those would require a change in present Powerex policy for exports. 4.3 Lower 48 Market Roughly 60 percent of Northwest electricity is provided by investor owned utilities (IOUs)such as Puget Sound Energy (PSE)and Portland General Electric.The remaining 40 percent comes from publicly owned utilities,such as Seattle City Light and Snohomish County PUD,who in turn receive most of their electricity from the Bonneville Power Administration (BPA).All six PNW lOUs are actively acquiring new generation resources to meet their growing loads.Northwest publicly owned utilities will start to need new resources in the 2012 -2014 time-frame,shortly after they sign new 20 year power contracts with BPA. As BPA drafts these new contracts,however,it intends to implement a major change in resource policy.Instead of blending the cost of new resources into its basic embedded cost hydro rate (roughly $30/MWh),BPA will implement a tiered rate system.This will make PNW public utilities responsible for acquiring their own generating resources (at a market or marginal cost)to meet their load growth.Therefore,post -2011,both PNW IOUs and public utilities will be acquiring new resources at market rates,representing a feasible export opportunity for SE Alaska hydropower 4.3.1 Pacific Northwest The PNW market in the 2010 -2020 timeframe will be characterized by two main features:(1)the increasing number of publicly owned utilities who are acquiring their own resources;and,(2)the required acquisition of renewable (principally wind)resources driven by Renewable Portfolio Standards (RPS)in both Washington and (likely)Oregon.Washington RPS requires most utilities in the state to meet 15 percent of their load with renewable resources by 2020.Legislation recently introduced by Oregon Governor Kulongoski would require that state's utilities to meet 25 percent of their load with renewable by 2025.Additional hydro would not count,and most new renewables acquired to meet these RPS will be wind.The regulation and load following capability necessary to successfully integrate these new wind resources could represent an additional marketing opportunity for Alaska hydro projects. Hatch Acres Corporation PR324582.Rev.0,Page 97 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACHES 4.3.2 California Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report While somewhat more speculative,interregional transmission alternatives currently being studied (under the Western Electricity Coordinating Council planning process)might also represent an opportunity for Alaskan hydro.Specifically,a study sponsored by Pacific Gas and Electric (PG&E) is examining several different routes from British Columbia to northern California.Much of the impetus for examining these routes comes from the California RPS,and California's parallel restrictions on greenhouse gas emissions.Taken together,these requirements are prompting PG&E, and other California utilities,to investigate constructing major new transmission to potentially tap renewable resources in British Columbia (primarily wind and small hydro).Should such transmission be constructed,it might also provide an export opportunity for Alaska hydro. 4.4 Market Opportunities 4.4.1.Marketing Choices Two types of marketing choices potentially exist for SE Alaskan hydro projects.While they are not mutually exclusive,they each represent different types of hydro based products.In addition,they all depend on the Alaskan projects,meeting the basic economic viability threshold described in Section 3.1.They also assume the feasible quantity of developable Alaskan hydro is roughly 70 average megawatts or 200 megawatts Capacity. 4.4.1.1 Energy Export This alternative involves export of project energy output (shaped according to project capability and contractual requirements)along with the associated capacity.It is the simplest type of transaction and,given the storage and consequent shaping capability of the proposed projects, should be quite feasible.This conclusion assumes that project economics are competitive with other market alternatives and that the requisite transmission interconnections occur. 4.4.1.2 Firming for BC Wind A final market opportunity would involve using Alaskan hydro (given its storage/shaping capability) to firm up BC wind resources.This choice could involve providing both within hour regulation and next hour load following for BC wind projects.Given their proximity,it would be most valuable for proposed wind developments in Northwest BC.However,given dynamic scheduling and appropriate transmission interconnection,Alaskan hydro could be used to firm other BC wind projects as well.As mentioned,in Section 4.4.1,it theoretically could be used for firming of PNW wind projects,but the requirements for additional dynamic scheduling into BPA's system and pancaked transmission tariffs make this opportunity more problematic. 4.4.2 Market Projections Based on the foregoing discussion,three basic market projections seem warranted: e Out-year markets for SE Alaska hydro exist,or soon will exist,in both BC and the Pacific Northwest Hatch Acres Corporation PR324582.Rev.0,Page 98 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACRES e Given the competitive range of delivered power costs,and the roughly $10/MWh of transmission charges to wheel Alaskan power to the PNW ($8/MWh for deliveries to BC), SE Alaska hydro projects will need to generate power,at the plant,for a cost of $60/MWh or less to assure their competitiveness Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report e If SE AK hydro project prices exceed $60/MWh they may be economic to export,but competitiveness will depend on GHG restrictions increasing future BC/PNW market prices. Hatch Acres Corporation PR324582.Rev.0,Page 99 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 5.REGULATORY ISSUES Hatch Acres Corporation PR324582.Rev.0,Page 100 AK-BC Alaska Final Report 18-09-07.Doc nATGA AGH Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 5.REGULATORY ISSUES 5.1 Overview In this section of the report,we identify and assesses regulatory requirements that will shape future development of transmission segments and new generation in SE Alaska.We include a brief discussion of the requirements that will affect development of the line segment in BC that will extend the proposed AK-BC Intertie to the nearest point of interconnection in Canada,including provisions to site,construct,and operate a transmission line within the Tongass National Forest and requirements related to export of electric power including the Presidential Permit and Export Authorization. We present a detailed discussion of the regulatory proceedings governing new hydropower projects,including a discussion of the FERC hydropower licensing process that will shape how the proposed Thomas Bay projects might be constructed and operated.The cost of power from these projects will be shaped by terms and conditions of licenses that may be issued by the FERC in the future. Regulatory requirements at the state and federal levels discussed in this section of the report will influence how the business structures discussed in Section 2 of this report will function and how transactions involving export of Alaskan-generated power to BC might be regulated. Regulatory issues that will require further consideration include:clarification of whether export of power across the proposed AK-BC Intertie will be determined "interstate commerce”and involve regulation by the FERC,and how that determination might shape the organizational structure of the entity that will own and operate the AK-BC Intertie. Table 5.1-1 provides a list of typical licensing and permitting requirements for transmission lines and hydropower projects. Table 5.1-1 Typical Licensing and Permitting Requirements Transmission Lines and Hydropower Projects LEGEND T Transmission requirements H Hydropower project facilities requirements Cl Coordination of review/approvals is accomplished under the August 8,2006 MOU on Early Coordination of Federal Authorizations and Related Environmental Reviews Required in Order to Site Electric Transmission Facilities -Lead is US Department of Energy C2 Coordination of review/approvals is accomplished during the FERC Hydropower Licensing Process Hatch Acres Corporation PR324582.Rev.0,Page 101 AK-BC Alaska Final Report 18-09-07.Doc Table 5.1-1 -_Licensing and Permitting Requirements -Transmission Lines and Hydropower Projects T H LICENSES,PERMITS AND APPROVALS C1 C2 X |X |X |X_|Alaska Coastal Management Program (ACMP)Certificate of Consistency issued by Alaska Department of Natural Resources (ADNR) X X Clean Air Act,EPA &ADEC -regulatory requirements to address construction-related activities that may result in pollutants and/or particulates emitted. X X Clean Water Act,EPA &ADEC -regulatory requirements to address construction-related activities that may result in discharge and/or contribute to turbidity.At present,the State of Alaska does not impose Section 401 Certification requirements on hydropower developers. X|X Corps of Engineers Section 10 Permit for each crossing of navigable waters X}|X |X Corps of Engineers Section 404 Permit where facilities affect wetlands or involve dredge and fill xX]X |X |X |Endangered Species Act,Section 7 Consultation regarding potential effects on candidate and listed species and related habitat.USFWS &NMFS are agencies with management authority. X |X_|FERC Hydropower License!to construct and operate hydropower facilities jurisdictional under the Federal Power Act (includes primary lines transmitting power from project to first point of use/interconnection) X|X |X |X |Fish and Wildlife Coordination Act,authority given to state and federal fish and wildlife agencies to recommend protection,mitigation,and enhancement measures to address potential project-related effects on species and habitat. X|X |X |X |Forest Service Special Use Permit (SUP)to construct and operate facilities on National Forest Lands.Wrangell District,USFS,reviews and approves the SUP. X |X National Energy Board Permit (Canada)required to construct and operate a part of an international power line. X |X |X |X_|National Environmental Policy Act (NEPA)Environmental Assessment or Environmental Impact Statement.X |X |X {|X |National Historic Preservation Act -Section 106 -Federal agencies are obligated to consider how actions may affect properties included in or eligible for inclusion in the National Register of Historic Places.State Historic Preservation Officer (SHPO),ADNR,and the Advisory Council on Historic Preservation administer Section 106 review and approval procedures. X|X Presidential Permit and Export Authorization to construct and operate transmission facilities for purpose of exporting energy to a foreign country. US Department of Energy (USDOE)Office of Electricity Delivery and Energy Reliability is responsible to coordinate Federal Agency environmental review under an MOU to Site Transmission.?,USDOE grants Presidential Permits and related Export Authorization.USDOE consults with the Department of Defense and the State Department as part of this process. X}|X |X |X |Spill Prevention Containment and Counter Measure (SPCC)Design/Plan required by EPA to comply with the Federal Clean Water Act.Addresses construction and long-term operation activities. x?State of Alaska Hydropower Licensing Program for Projects 5MW or Less.The Regulatory Commission of Alaska (RCA)is currently preparing a final set of regulations to submit to FERC for approval. X X Local government building permits and zoning requirements 'FERC's Hydropower Licensing Process requires Applicants to consult with Federal and State agencies with jurisdiction over resources that may be affected by a licensing action.During the application process resource agencies may require permits to perform field studies. *The Energy Policy Act of 2005 set forth policies in subsection 216(h)of the Federal Power Act to require coordination among agencies with authority to issue Federal authorizations affecting siting electric transmission facilities (Federal MOU to Site Transmission) 3 Program currently under development. nATGn ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 5.2 SE Alaska Transmission System This section of the report discusses the regulatory requirements and related decisions that will shape development and operations of the proposed interconnected electrical transmission system in SE Alaska including: e AK-BC Intertie -transmission segment between Tyee Lake Project and the AK/BC border for purposes of exporting Alaska-generated power to BC and the PNW e Swan-Tyee Intertie -transmission segment between Tyee Lake Project and Swan Lake Project e Kake -Petersburg -transmission segment to enable delivery of power from Tyee Lake to currently isolated load at Kake.This link would eventually extend to Takatz Lake on Baranoff Island e Metlakatla -Ketchikan e Thomas Bay to Petersburg -transmission segment between proposed new generation at Thomas Bay to interconnected system between Petersburg and Wrangell to the AK-BC Intertie e Coffman Cove to Wrangell -transmission segment from Prince of Wales to a point of interconnection at Wrangell. Discussions regarding the potential Business Structure(s)that would own and operate the proposed AK-BC Intertie and manage operations of a region-wide SE Alaska Transmission System are discussed in Section 2 of this Report.A snapshot of the SE and external markets is provided in Sections 3 and 4.Discussion of the physical facilities that will comprise the System are addressed in Section 6 Transmission Costs and Issues.A discussion of future generation projects that could be developed with completion of transmission lines to interconnect load centers currently isolated within SE Alaska and,to export power to BC and the PNW with completion of the AK-BC Intertie is presented in Section 7 Power Generation Costs and Issues. 5.2.1 Jurisdiction and Regulation 5.2.1.1 Overview The ultimate decision regarding jurisdiction over the operation of the proposed integrated electric transmission system is not addressed in this report.That decision will depend,in large part, whether the interconnection with the BC electric transmission system at the AK/BC border is determined to constitute interstate commerce. e If the system is determined to be solely of an intrastate nature,all regulatory proceedings governing operations and ratemaking of the system would lie with the Regulatory Commission of Alaska e If,on the other hand,the determination is that the international interconnection of the AK- BC Intertie results in interstate commerce,the Federal Energy Regulatory Commission Hatch Acres Corporation PR324582.Rev.0,Page 103 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report would become involved in matters relating to rate-making and open-access requirements under the Federal Power Act e Neither option would impose additional state or federal regulation over municipal and state owned and operated electric utilities. In either case,a Certificate of Public Convenience and Necessity issued by the RCA will be required for new transmission segments. A "snapshot”discussion of the respective roles and authorities of the RCA and the Federal Energy Regulatory Commission are presented in the following sections. 5.2.1.2.Regulatory Commission of Alaska The Alaska Legislature created the RCA in 1999,authorizing it to regulate utilities and pipeline carriers.Alaska Statutes 42.04 -42.06 and other statutes authorize the RCA to regulate public utilities by certifying providers of public utility and pipeline services and to ensure that services provided are safe and adequate and that rates are just and reasonable.The RCA also determines the per kilowatt-hour support for eligible customers of electric utilities under the Power Cost Equalization (PCE)program”®. The RCA includes five Commissioners appointed by the Governor and confirmed by the Legislature.The RCA exercises a delegated legislative power and each decision is reached quasi- judicially,based on evidence of record gathered in docketed proceedings.Decisions may be appealed to state or federal court and must be supported by the evidentiary record and applicable laws and regulations. The RCA regulates the rates,services and practices of utilities that meet the criteria for a certificate of public convenience and necessity (CPCN)to provide service to the public.However,there are utilities that are not economically regulated,including:local,government owned-utilities,very small utilities,and cooperatives whose members have voted to become deregulated.Requests by utilities to the RCA for approval are publicly noticed with a thirty day period to provide comments. Certificated economically regulated electric utilities serving customers in the study area include: e Alaska Power Company serves customers on Prince of Wales Island. Certificated electric utilities exempt from economic regulation in the study area include: e Thomas Bay Power Authority e City of Kake e City of Ketchikan d.b.a.Ketchikan Public Utilities e City of Petersburg d.b.a Petersburg Municipal Power &Light e City of Thorne Bay e City of Wrangell d.b.a Wrangell Municipal Light &Power 36 AS 42.45 Hatch Acres Corporation PR324582.Rev.0,Page 104 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES we Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report e Inside Passage Electric Cooperative. Of interest to utilities in the study area addressed in this report,the RCA approved an application by Alaska Electric Light and Power Company (AEL&P)to expand its service area to include a portion of Admiralty Island on which the Kennicott Greens Creek Mine is located.*”The undersea transmission line from Juneau to Admiralty Island was grant-funded by the Denali Commission*® and is the first segment of the proposed Southeast Alaska Intertie.AEL&P provides hydro power to Kennicott Greens Creek Mine which previously used petroleum distillate to self-generate. AEL&P and the Inland Passage Electric Cooperative formed a non-profit cooperative corporation in 2004,Kwaan Electric Transmission Intertie Cooperative (KWETICO”)to provide electric transmission service between Juneau and Hoonah.KWETICO is one of the models we reviewed in analyzing potential business structures to own and operate the proposed AK-BC Intertie.*° Construction of the line is proceeding in two phases;Phase 1 is complete and Phase 2 is projected to be in service in 2008.*' The recent experience of KWETICO's application with the RCA for a CPCN®and ongoing proceedings before the RCA are of interest to proponents of the AK-BC Intertie.The following discussion presents a snapshot view of the proceeding and major milestones that may mirror a future request for CPCN as the SE Alaska interconnected system proceeds. As part of their application,KWETICO requested exemption from economic regulation®. KWETICO supported this request by pointing out to the RCA that traditional ratemaking methodologies would not allow KWETICO adequate margins to generate reserves for contingencies or eventual repair and replacements.This situation will also exist for future filings with the RCA by a Business Structure comprised of mixed ownership"for CPCN for grant-funded transmission segments in the study area.KWETICO's filing refers to grant-funded transmission infrastructure resulting in debt-free capital structure that will not incur depreciation expense. 37 RCA Docket U-05-073 issued October 3,2005 38 Construction of Phase1 is complete and was financed by $14.7 million in federal grant funds. 3?KWETICO was formed to serve as the holding company for transmission assets,allowing investor-owned, cooperative,and municipal utilities within SE Alaska to participate together in the management of the assets and to obtain electric power in their service areas.To date KWETICO infrastructure has been principally funded by the federal government with financial grants administered by the Denali Commission. "°See also discussion of KWETICO in Section 2.Business Structures at 2.2.2.1. "'Phase |extends from AEL&P's transmission facilities on North Douglas Island to the Greens Creek Mine on Admiralty Island.This phase consists of 9.5 miles of submarine cable between Douglas and Admiralty Islands and 8.5 miles of overhead transmission line on Admiralty Island.Phase 2 will extend from Admiralty Island to Hoonah and will consist of 25.5 miles of submarine cable between Admiralty and Chichagof Islands and 3.5 miles of overhead transmission line on Chichagof Island.This segment is scheduled for completion in 2008 provided that $28 million in federal grant funds is obtained. *U-05-100 Application for New Certificate of Public Convenience and Necessity;and Request for Public Interest Exemption.December 21,2005 "3 Request filed under AS 42.05711(d).The RCA may exempt a utility,a class of utilities,or a utility service from all or a portion of this chapter if the RCA finds that the exemption is in the public interest. "4 Municipal systems and the Four Dam Poo!Power Agency are exempt from economic regulation by the RCA. Hatch Acres Corporation PR324582.Rev.0,Page 105 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report On February 28,2006,the RCA issued an Order Granting Temporary Operating Authority, Establishing Interim Rates,and Requiring Filings*®.On March 24,2006,KWETICO filed information in response.On September 25,2006,the RCA issued an Order Approving Application,Requiring Filing,and Denying Request for Exemption from Economic Regulation (Order re KWETICO)granting the CPCN and requesting KWETICOto file a tariff reflecting the interim rates established by the Order issued on February 28,2006.KWETICO filed a petition for partial reconsideration of the requirement to file a tariff on October 10,2006.KWETICO on November 9,2006,the RCA denied the request for reconsideration and ordered KWETICOto file a tariff reflecting the transmission rates approved on an interim basis as originally ordered. Of interest to this study,the RCA's policy appears to be that a Cooperative entity like KWETICO applying for a CPCN for new transmission,like the AK-BC Intertie,will be subjected to economic regulation by the RCA. As the Business Structure for the future segments is firmed up,it will be important to engage the RCA in consultation prior to filing the Application for CPCN. 5.2.1.3 Federal Energy Regulatory Commission If the international interconnection of the AK-BC Intertie results in interstate commerce,the Federal Energy Regulatory Commission (FERC)would become involved in matters relating to rate-making and open-access requirements under the Federal Power Act. The FERC was created through the Department of Energy (DOE)Organization Act on October 1, 1977.At that time the Federal Power Commission (FPC),established in 1920 was abolished and FERC inherited most of the FPC's regulatory mission.FERC is an independent regulatory agency within DOE and is headed by a bi-partisan five-member Commission,comprised of the Chairman and four Commissioners who are appointed by the President and confirmed by the Senate.The Chairman serves as the Chief Executive Officer.The FERC headquarters office is located in Washington,D.C.Staff offices of the Office of Market Oversight and Investigations and the Office of Markets,Tariffs and Rates review applications for approval in the electric sector of FERC's jurisdiction. FERC's authority to regulate the electric utility industry was established in 1935 amendments to the Federal Power Act (FPA)adding sections 205 and 206 authorizing the FPA,now FERC,to oversee rates,terms and conditions of sales for resale of electric energy and transmission service in interstate commerce by public utilities including investor-owned utilities and independent power producers.Government-owned utilities,(e.g.state and municipal utilities)and generally,most cooperatively-owned utilities are not subject to regulation at the FERC.FERC does not regulate retail sales or local distribution of electricity as the FPA leaves these matters to the states. "The RCA required KWETICO to file a copy of its contract with AEL&P for transmission of electricity from AEL&P to the Kensington Mines and to file copies of any executed joint use of facilities agreement. KWETICO filed the required information and stated that no joint use of facilities agreements had been negotiated or executed. Hatch Acres Corporation PR324582.Rev.0,Page 106 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Under the Energy Policy Act of 2005*°(EPAct 2005)FERC now has,if certain conditions are met, the authority to permit the construction or modification of transmission facilities located in "national interest electric transmission corridors”that are designated by the Secretary of the Department of Energy. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report EPAct 2005 directed FERC to develop incentive-based rate treatments for transmission of electric energy in interstate commerce,to provide regulatory certainty,and to support expanded and improved transmission infrastructure while ensuring that transmission rates remain just and reasonable.FERC issued Final Rules*”amending its regulations to establish incentive-based (including performance-based)rate treatments for the transmission of electric energy in interstate commerce by public utilities for the purpose of benefiting consumers by ensuring reliability and reducing the cost of delivered power.The Final Rule identifies specific incentives that FERC will allow and requires that an applicant for incentive-based rate treatment demonstrate a nexus between the incentive being sought and the investment being made.Rates under this incentive- based treatment must still meet the requirement of "just and reasonable under FPA Section 205.” FERC developed a pro forma Open Access Transmission Tariff (OATT)in 1996 and has modified its approach and issued a Final Rule on open access regulations on February 15,2007. Of interest to this study,FERC requires that each public utility”transmission provider submit information regarding its planning process in support of the requested tariff.Transmission providers are required to meet with transmission customers and interconnected neighbors in developing their transmission plan.This study includes information in support of the requirement to describe the planning process for the AK-BC Intertie,including consultations held with BCTC regarding the future interconnection. Transmission providers are required to disclose to all customers and other stakeholders the basic criteria,assumptions,and data that underlie their planning. As with the process before the RCA,filings regarding grant-funded transmission assets will require consultation with the FERC prior to filing.Calculation of return on equity (ROE)for purposes of recovering adequate margins to generate reserves for contingencies or eventual repair and replacement of transmission infrastructure will require consultation with the FERC prior to filing applications.FERC requires applicants for incentive rate treatment to justify a higher ROE under the nexus test and to justify where in the "zone of reasonableness”that return should lie.FERC's traditional ratemaking practice typically determines ROE in a hearing only after the investment is made and a facility is constructed.Regarding the proposed AK-BC Intertie,the selected Business Structure to own and operate the line may elect to file in advance of construction a request for clarification by filing a petition for declaratory order*'. 46 Energy Policy Act of 2005,Public Law No.1099-58,119 Stat 594,315 and 1283 (2005) 47 Order on Rehearing -Promoting Transmission Investment through Pricing Reform,Docket No.RM06-4- 001,Order No.679-A,issued December 22,2006.Order No.679 issued July 31,2006. 8 "Public utility”is defined as "°Petitions for Declaratory Order are filed under 18 CFR 385.207 of the FERC regulations;a filing fee of $19,800 is required to accompany the petition. Hatch Acres Corporation PR324582.Rev.0,Page 107 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES The BCTC transmission system operates under FERC rules regarding open access and related rate structure for use of the system. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 5.2.1.4 Determination of Jurisdiction over the AK-BC Intertie In order to determine the jurisdictional structure over the export line,the organization that will own and operate the AK-BC Intertie wil!need to file petitions with the FERC and the RCA in order to determine the level of State and Federal jurisdiction. 5.3.Permitting and Related Approvals -Transmission 5.3.1 Federal and State of Alaska Most transmission lines in SE Alaska,including the proposed AK-BC Intertie,would be constructed on lands within the Tongass National Forest managed by the U.S.Forest Service (USFS or Forest Service),thereby requiring federal approval to site,construct,and operate proposed facilities. Project developers applying for federal permits and other approvals are required to comply with the National Environmental Policy Act (NEPA).The NEPA process provides the overarching forum for review and consideration by federal agencies,state agencies with delegated authority under federal statute,and other entities authorized to review and issue permits and other approvals required to develop proposed energy facilities,including transmission lines.The NEPA process is discussed in Section 5.3.1.1 below. Project developers are required to consult with federal and state agencies to identify potential project-related environmental effects associated with siting,construction,and operation of proposed facilities;perform environmental studies and analyses to assess such project-related effects;and document study results.The study results are used to prepare the Environmental Assessment (EA)or Environmental Impact Statement (EIS),funded by the developer,that presents an assessment of expected project-related effects and presents proposed measures to protect affected resources,to mitigate any project-related adverse effects on natural and human environmental resources,and,in some cases to provide enhancement to the existing resources in the vicinity of the project.(PM&E measures)The EA or EIS is used by federal agencies in their review of applications for and provides support for decisions to issue permits and other approvals. Because the proposed AK-BC Intertie involves interconnection at the border with BC transmission lines for the purpose of exporting Alaska-generated power,the developer is required to apply for and receive a Presidential Permit that authorizes construction and operation of the transmission facilities and Export Authorization for the international sale of Alaskan-generated power.These approvals are discussed in Sections 5.3.1.2 and 5.3.1.3 below. A developer proposing to occupy and use lands within the Tongass National Forest to site, construct,and operate transmission facilities over the life of the facilities must consult with the USFS and other federal agencies regarding potential environmental effects and secure necessary approvals,including the Special Use Authorization (SUA)issued by the US Forest Service.The application process for the SUP and the Presidential Permit trigger compliance with a number of other federal resource agency requirements including the Endangered Species Act (ESA).The requirements and process to apply for a SUP are discussed in section 5.3.1.4 below. Hatch Acres Corporation PR324582.Rev.0,Page 108 AK-BC Alaska Final Report 18-09-07.Doc HATA AGRE State agency approvals are discussed within the context of the Special Use Authorization,the primary federal authority triggering state agency approvals. Alaska Energy Authority -AK-BC tntertie Feasibility Study SE Alaska Final Report 5.3.1.1 National Environmental Policy Act (NEPA)Process Potential developers of projects that require approval by federal agencies,including issuance of permits and other approvals,are required to comply with the requirements established in NEPA. NEPA identified environmental protection as a major national policy objective and requires Federal agencies involved in issuing permits and licenses for proposed projects affecting the environment to evaluate environmental impacts and the significance of these impacts.The NEPA process is used to identify and assess environmental effects associated with a proposed project;identify reasonable alternatives to proposed actions;and develop practical means to avoid or minimize any possible adverse effects of their actions upon the quality of the human environment. Relevant to the proposed AK-BC Intertie,issuance of the required Presidential Permit,Export Authorization and the Special Use Authorization (see subsections below)will trigger the requirement to comply with NEPA.The applicant for these approvals will be required to fund preparation of an Environmental Assessment (EA)or Environmental Impact Statement (EIS) depending on the determination of the federal agencies involved whether siting,construction and operation of the proposed AK-BC intertie would result in a "significant affect on the human environment.” Coordination of federal agency approvals for electric transmission facilities is established in the August 8,2006 "Memorandum of Understanding on Early Coordination of Federal Authorizations and Related Environmental Reviews Required in Order to Site Electric Transmission Facilities” (MOU)”*signed by the departments of Energy (DOE),Agriculture (USDA -includes the Forest Service),Defense (DOD -includes the Corps of Engineers (COE)),Interior (DOI -includes the Fish and Wildlife Service (FWS)),Commerce (includes the National Marine Fisheries Service (NMFS)); and the FERC,the Environmental Protection Agency (EPA),the Council on Environmental Quality (CEQ),and the Advisory Council of Historic Preservation with the commitment to work together to meet each Agency's obligations.The purpose of the MOU is to establish a framework for early cooperation and participation that will enhance coordination of all applicable land use authorizations,related environmental,cultural,and historic preservation reviews,and any other approvals that may be required under Federal law in order to site an electric transmission facility. Central to this MOU is compliance with NEPA and preparation of related environmental documents,including the EA or EIS. 5.3.1.2 Presidential Permit The Presidential Permit is required to site,construct,and operate electric transmission line segments that cross International borders.The authority to grant Presidential permits is derived from the constitutional power of the President to protect the territorial integrity of the United States.US Department of Energy (USDOE)is the federal agency authorized to review and approve applications for Presidential Permit. °°The MOU was developed in response to requirements of the Energy Policy Act of 2005 that amended the Federal Power Act;codified at USC 824p. Hatch Acres Corporation PR324582.Rev.0,Page 109 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACRES In preparing this report,we consulted with Ellen Russell®'and Tony Como”in the Office of Electricity Delivery and Energy Reliability,U.S.Department of Energy regarding current requirements for the Presidential Permit and the related Energy Export Authorization.Ms.Russell and Mr.Como were involved in review and approval of the previous application for Presidential Permit submitted by Bradfield Electric,Inc.in the 1987 proposal for the proposed "Bradfield Electric Powerline”also referred to as the "Tyee /Johnny Mountain Transmission Line.”We reviewed documents prepared in 1987 and 1988 in support of the "Bradfield Electric Powerline, including the Presidential Permit PP-87 issued on May 8,1989,by USDOE and the Special Use Permit and related Decision Notice and Finding of No Significant Impact (FONSI)issued by the Forest Service on June 7,1988.We also reviewed reports prepared for the Alaska Power Authority®and Bradfield Electric™issued in 1988 that were used to support the Applications for Presidential Permit and the Special Use Authorization.The proposed AK-BC Intertie segment between Tyee Lake Project and the AK/BC border would follow the same route as the proposed, but not constructed 69-kV line. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The narrative in this section reflects consultations with USDOE and guidance documents from the USDOE website. Executive Order 12038 states that,before a Presidential permit may be issued,the action must be found to be consistent with the public interest.The two criteria used by USDOE to determine if a proposed project is consistent with the public interest are: Impact on Electric Reliability -USDOE considers the effect that the proposed project would have on the operating reliability of the US electric power supply system;i.e.the ability of the existing generation and transmission system to remain within acceptable voltage,loading and stability limits during normal and emergency conditions.The standards USDOE applies include the standards of the North American Electric Reliability Council (NERC)and the standards of the member regional councils that are formulated by the utilities themselves.Because the proposed AK-BC Intertie would not be directly interconnected with transmission systems in the Lower 48,this review may more appropriately be conducted by British Columbia regulatory authorities. Environmental Consequences of Proposed Projects -Under NEPA,USDOE is required to determine the environmental impacts associated with issuing or denying a Presidential permit.** Environmental review will be accomplished under the MOU signed on August 8,2006,described above at 4.3.1.1.Review under NEPA where lands of the United States would be occupied is usually led by the management agency.The proposed AK-BC Intertie would occupy lands within the Tongass National Forest..The NEPA review of the earlier proposed Tyee/Johnny Mountain was 5'Fllen Russell serves as Senior Project Manager and was involved with the 1988-89 proceeding regarding the proposed Bradfield Intertie. 52 Tony Como serves as Office Director and was the decision-maker at USDOE who signed the Presidential Permit issued in 1989 for the Bradfield Intertie 53 Southeast Alaska Transmission Intertie Study,Addendum 1,Tyee/Johnny Mountain Transmission Line Study,Prepared for the Alaska Power Authority,Harza Engineering Company,July 1988. 54 Proposed Johnny Mountain 69-kV Transmission Line,Project Concept Summary,Prepared for Bradfield Electric,Inc,by R.W.Beck and Associates,August 26,1988. °>USDOE published NEPA regulations implementing NEPA on April 24,1992 (57 FR 15122).These rules are codified at 10 CFR 1021. Hatch Acres Corporation PR324582.Rev.O,Page 110 AK-BC Alaska Final Report 18-09-07.Doc HATH ACRES conducted by the USFS in 1988°°Contact was made with the Wrangell Ranger District to discuss the proposed AK-BC Intertie.At this time,the USFS expressed interest in serving as a Cooperating Agency,but declined to serve as Lead Agency due to the level of other activities ongoing at this time.°” Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Other Approvals -After addressing compliance with NEPA and satisfaction of the electric reliability criteria,EO 12038 requires USDOE to obtain concurrence from the Secretary of the Department of State and the Secretary of the Department of Defense before a permit may be issued. Time Frame to Process a Presidential Permit -The overall schedule for application of the Presidential permit is driven by the extent of environmental analysis required to address NEPA and other federal statutes associated with siting project infrastructure on lands of the United States and potentially affecting protected natural and/or cultural resources.If an Environmental Impact Statement is required,the time for processing the permit application could take 18 months or longer. Filing Fee -A filing fee,currently $150,must be submitted with the application.In addition to this nominal fee,the applicant is also required to pay the cost of USDOE's environmental review if an EA or EIS is required. 5.3.1.3.Export Authorizations The Export Authorization is closely associated with the Presidential Permit discussed above.Part Il, Section 202(e)of the Federal Power Act (FPA)states that exports of electric energy should be allowed unless the proposed export would impair the sufficiency of electric power supply within the US,or would impede or tend to impede the coordinated use of the U.S.power supply network. The USDOE is authorized to grant permission to export electric energy if it is determined that: e Sufficient generating resources exist such that the exporter could sustain the export while still maintaining adequate generating resources to meet all firm supply obligations e The export would not cause operating parameters on regional transmission systems to fall outside of established industry criteria. USDOE is required to comply with NEPA before granting authorization to export electric energy. In the case of the proposed AK-BC Intertie,USDOE would participate in preparation of required NEPA documents to authorize construction and operation of the AK-BC Intertie through the Presidential Permit application and review process. 5.3.1.4.Special Use Authorization for Occupation and Use of Federal Lands The proposed AK-BC Intertie and several other proposed transmission segments for SE Alaska are located within the Tongass National Forest managed by the USFS.The Tongass Land and Resource 56 USDA,US Forest Service Special Use Permit issued to Bradfield Electric,Inc.,June 7,1988 and Decision Notice and Finding of No Significant Impact Environmental Assessment. >?E-mail communication with Frank W.Roberts,Wrangell Ranger District,Tongass National Forest on January 19,2007. Hatch Acres Corporation PR324582.Rev.0,Page 111 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Management Plan (TLRMP)°*?includes maps and descriptions of allowed use of National Forest System (NFS)lands including specific Land Use Designations (LUDs).The proposed AK-BC Intertie route would be located on lands classified LUD II°?(11.5 miles)and LUD IV®(13 miles).The TLRMP includes power transmission lines as an allowed use within both designations. Alaska Energy Authority -AK-BC tntertie Feasibility Study SE Alaska Final Report Developers wishing to site,construct,and operate electric transmission lines within the NFS are required to apply for and secure a Special Use Authorization (SUA)as set forth by the Federal Land Management and Policy Act of 1976 (FLPMA)and USFS regulations.The SUA is a legal document and may be issued in the form of a permit,term permit,lease,or easement,which allows occupancy,use,rights,or privileges of NFS land.The SUA is granted for a specific use of the land for a specific period of time.Fees associated with the SUA include: e Cost Recovery Fees -fees to recover agency processing costs for SUA and monitoring costs for occupancy and use under the SUA.Agency processing costs include costs incurred by the USFS and other federal agencies who participate in the review and approval process. These fees are separate from land use fees.Cost to prepare documents under NEPA, including the EA or EIS e Land Use Fees -annual rental fee based on the fair market value for the uses authorized and payable in advance.Fees are established by appraisal or other sound business management principles e Other Associated Costs -additional information and reports necessary to determine the feasibility and environmental impacts of the proposed use;compliance with applicable laws and regulations;and terms and conditions to be included in the SUA. Steps in the SUA process include: Proposal Stage e Contact the USFS office responsible for management of affected land as early as possible in advance of the proposed use e Review and provide information noted on the Application for Transportation and Utility Systems and Facilities on Federal Lands Standard Form 229.A copy of this form is provided in Appendix D -Regulatory e Arrange a pre-application meeting with the USFS office responsible for managing lands where the use is being requested.Discuss the proposed use and receive guidance regarding:application procedures and qualifications,probable time frames,fees,bonding requirements,additional coordination with other agencies,environmental reports,and field reviews 58 The USFS is currently revising the 1997 Tongass Land and Resource Management Plan. 5°?LUD Il areas are to be managed in a roadless state to retain their wildland character except that water and power developments are permitted if they can be designed to retain the overall primitive characteristics of the allocated area. ©LUD IV areas provide for intensive resource development and use. Hatch Acres Corporation PR324582.Rev.0,Page 112 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Provide supporting information including:alternatives considered,complete project description including maps,design drawings,proposed construction and operating schedule and plans;proposed environmental protection plan;liability insurance,and other documents as requested by the USFS Prepare and submit the application form,including supporting documents to the USFS office responsible for managing lands to be occupied and used under the SUA The proposal to obtain an SUA does not grant any right of privilege to use or occupy NFS lands.Rights are only conveyed through issuance of the SUA. Pre-Review Stage The USFS and relevant state and federal agencies participate in the review of the application and may require additional information Discussion of all approvals required to support a decision to issue the SUA,including:an EA or EIS prepared under NEPA and related applications for approval by state and federal agencies Applicant is advised of additional information necessary to begin processing of the application. Processing Stage®" Initial screening -USFS screens proposal to ensure that the proposed use meets minimum requirements Results of initial screening -USFS advises applicant whether proposal meets minimum requirements and may request supplementary information.Applicant must provide requested information to proceed with processing Second-level screening of proposed uses -USFS advises applicant of schedule and related costs to proceed NEPA compliance for second-level screening process.Compliance with NEPA is required prior to issuance.The official responsible for making a decision is the Stikine Area Forest Supervisor.In the case of the proposed AK-BC Intertie,the NEPA process for the SUA would be coordinated with USDOE and the application for Presidential Permit and Export Authorization discussed above.The Presidential Permit discussed above is required to cross the International Boundary with Canada.Approval by the International Boundary Commission may also required Applicant submits NEPA document and completed Application (Standard Form 299)62 to the local USFS office for review and approval ®'Regulations covering the processing of applications for SUA are presented in 36 CFR 251 Subpart B - Special Uses 62 Standard Form 299 -Application for Transportation and Utility Systems and Facilities on Federal Lands prescribed by DOI/USDA/DOT under PL-96-487 -form included in Appendix D. Hatch Acres Corporation PR324582.Rev.0,Page 113 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES e USFS advises applicant that proposal is complete and instructs applicant to file application with the USFS and provide simultaneously to each federal department or agency requiring authorization to establish and operate the proposed project. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report A Decision Notice including a description of the decision,the rationale for reaching it,and the major environmental considerations behind the Decision (Record of Decision)will be prepared by the USFS and published. The proposed AK-BC Intertie will be subject to Cost Recovery regulations where the proponent is responsible for processing and monitoring costs incurred by the Forest Service. Discussions with the USFS indicated that the annual charge to occupy and use lands within the Tongass National Forest would be equivalent to 5%of the estimated land value.The estimated total land area required for the AK-BC Intertie within the Forest is estimated at 320 acres. In issuing the SUA,the USFS will review the proposed line to ensure no adverse effects on subsistence uses or needs in the affected area as required by the Alaska National Interest Lands Conservation Act (ANILCA). The USFS requires that following agencies be consulted during the SUA application process: e US Fish and Wildlife Service(USFWS) e National Marine Fisheries Service (NMFS) e Environmental Protection Agency (EPA) e US Coast Guard (USCG) e Alaska Department of Fish and Game (ADFG) e Alaska Department of Natural Resources (ADNR) e State Historical Preservation Officer (SHPO) e local City and Borough Governments that may be affected. The following are typical permitting requirements from other government agencies for Transmission lines: e US Army Corps of Engineers (USACE)-Section 404 permit e Alaska Department of Environmental Conservation (ADEC)-Section 401,Water Quality Certification (part of USACE permitting) e Alaska Department of Natural Resources (ADNR):Habitat Division for activities affecting fish &wildlife and associated habitat,Division of Lands Right of Way(if the is work involving submerged lands) e ADNR-Alaska Coastal Management Plan and related Coastal Zone Consistency Determination. §3 E-mail communication with Erik P.Spillman,Lands and Special Uses Forester,Tongass National Forest on December 29,2006. Hatch Acres Corporation PR324582.Rev.0,Page 114 AK-BC Alaska Final Report 18-09-07.Doc HATH ACHES In preparing this report,we consulted with the Wrangell District Office of the USFS,Tongass National Forest and reviewed guidance documents and regulations™for the SUA process.We reviewed the USFS NEPA document prepared for the Application for Special Use Permit (SUP)for the Bradfield Intertie and the SUP and Presidential Permit issued in 1988. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Issues associated with the proposed AK-BC Intertie®include: e Floodplain crossing -1.7 miles e Floodplain/wetland habitat -6 miles e Helicopter/Aircraft use and related landing pads e Recreational use e Salmon spawning habitat e Stream crossings (total -15)affecting anadromous fish (13 identified) e Timber clearing within clearing limits of the proposed ROW e Waterfowl use area -spring/fall waterfowl concentration area and trumpeter swan wintering area -2.0 miles e Wildlife area -black/brown bear spring concentration area -15 miles. 5.3.1.5 |Other Federal Review &Approvals The following paragraphs describe review and approval requirements under federal law that may occur during the preparation of the NEPA document to support all federal approvals.Compliance with these requirements will be "triggered”by application for the Special Use Authorization from the USFS and the Presidential Permit and Export Authorization from USDOE (see subsections above). Clean Water Act The Clean Water Act (CWA)prohibits the discharge of pollutants or fill into most waterways of the US without a permit issued under the Environmental Protection Agency's (EPA)National Pollutants Discharge Elimination System (NPDES)or Corps of Engineers (COE)Section 404 permit.The COE has issued a nation wide permit for construction of utilities.The USFS in issuing the Special Use Authorization,may require the applicant to prepare an Erosion and Sediment Control Plan and a Revegetation Mitigation and Monitoring Plan that demonstrate compliance with the CWA. Applicants for federal permits and other approvals are also required to comply with the water quality management and state water quality standards under Section 401 of the CWA.Currently the Alaska Department of Environmental Conservation (ADEC)issues Certificates of Reasonable Assurance in accordance with Section 401.Requests for these approvals may be prepared as an integral part of NEPA compliance. ®36 CFR 251.50 et seq -Subpart B Special Uses and Standard Form 299 -Application for Transportation and Utility Systems and Facilities on Federal Lands. §5 Southeast Alaska Transmission Intertie Study,Addendum 1,Tyee /Johnny Mountain Transmission Line Study,July 1988 Hatch Acres Corporation PR324582.Rev.0,Page 115 AK-BC Alaska Final Report 18-09-07.Doc nT ACHES Coastal Zone Management Act Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The Coastal Zone Management Act (CZMA)authorizes states to prepare and implement management plans under the CZMA.The State of Alaska prepared and received approval for the Alaska Coastal Management Plan (ACMP).Applicants for federal permits are required to complete and submit a Coastal Project Questionnaire and Certification Statement describing the proposed project for review and approval under the ACMP.The Office of Project Management and Permitting (OPMP)®coordinates the State's review of proposed projects for consistency with the ACMP. Endangered Species Act The Endangered Species Act (ESA)requires the federal government to comply with consultation and review requirements under the ESA in issuing permits and other approvals.Under the ESA various species are categorized by regulation as threatened or endangered species,and their related critical habitat is also designated for protection.The USFS is required to consult with the US Fish and Wildlife Service (FWS)and/or the National Marine Fisheries Service (NMFS)to determine whether the agency action is likely to jeopardize the continued existence of any endangered or threatened species or result in critical habitat destruction.Where these species and/or habitat are present in the area of a proposed transmission line segment,the USFS may be required to conduct a Biological Assessment (BA)for the purposes of identifying any project-related effects on protected species and/or habitat.The BA may be prepared as an integral part of NEPA compliance. Fish and Wildlife Coordination Act The Fish and Wildlife Coordination Act (FWCA)requires federal agencies granting a permit for a project that affects streams and water bodies to consult with the FWS and the appropriate state fish and wildlife agency,the Alaska Department of Fish and Game (ADFG)and the Office of Habitat Management and Permitting (OHMP)located in the Alaska Department of Natural Resources (ADNR),regarding conservation of these resources.This review is an integral part of NEPA compliance. National Historic Preservation Act The National Historic Preservation Act (NHPA)requires the federal government to comply with consultation and review requirements under Section 106 of the NHPA.Federal agencies in issuing permits and other approvals are required to take into account the effect of the action on any district, site,building,structure,or object that is included in or eligible for inclusion in the National Register of Historic Places (eligible or listed properties).Applicants for federal permits are required to prepare a Historic Properties Management Plan (HPMP)before starting any land-clearing or land- disturbing activities within the proposed right-of-way for the proposed transmission segments in consultation with the USFS and the State Historic Preservation Officer ((SHPO)®”.The USFS archeologist assigned to the Tongass National Forest and the SHPO will be involved in review and ®€The Office of Project Management and Permitting (OCMP)is located within the State of Alaska Department of Natural Resources. °7 In the State of Alaska,the SHPO is located within the Alaska Department of Natural Resources. Hatch Acres Corporation PR324582.Rev.0,Page 116 AK-BC Alaska Final Report 18-09-07.Doc HATH ACHES approval of any requested permit or approval that may affect eligible or listed properties as an integral part of NEPA compliance. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 5.3.2 British Columbia 5.3.2.1 The National Energy Board The National Energy Board Act (NEB Act)was initially promulgated in 1959 and amended by the Canadian Electricity Policy Act in 1988.One of the key strategies in the NEB's Strategic Plan for 2007 -2010 is to improve the regulatory process.Applicants for permits are advised to contact the NEB to receive the most current guidance. The NEB regulates construction and operation of international power lines and electricity exports from Canada.The NEB reviews environmental effects associated with a proposed line and would be consulted during scoping and preparation of the required NEPA documents to support the applications for USFS Special Use Authorization and approvals from the US Department of Energy (discussed in Section 4.3.1 of this Report).During this consultation clarification regarding filings with the NEB would be requested. International Power Line Permit The NEB Act requires persons constructing or operating a section of an international power line (IPL)to apply for and receive a certificate or permit issued by the NEB.A permit means an authorization for the construction and operation of an IPL issued under III.]of the NEB Act if a federal approval is required,or NEB Act 58.11 if a provincial approval is determined adequate. The NEB is in the process of developing an electricity filing manual which outlines the information applicants need to provide to the NEB when filing an electricity facility application for an IPL. Prospective applicants may arrange pre-application meetings with the NEB to discuss procedural and non-substantive matters.NEB guidelines provide information on the process and filing requirements (www.neb-one.gc.ca). Applicants are required to publish notification of application in the Canada Gazette and in some cases local newspapers. The NEB issues a permit to construct and operate an IPL if it is satisfied that the information provided conforms with its requirements and all concerns have been addressed.Permits may contain terms and conditions. Timing -a 30-day comment period is provided following the date of filing,applicants have 15 days to respond to comments and interested parties have 10 days to assess and comment on the applicant's response.The NEB may then issue a permit or refer the matter for public hearing. Electricity Import Reporting Procedures The NEB does not regulate imports of electricity that is consumed in BC.The NEB does however collect data that is provided to Statistics Canada.The NEB is modifying its procedures and will have published reporting forms in the future. Hatch Acres Corporation PR324582.Rev.0,Page 117 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACHES Electricity Export Permit and Reporting Requirements Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The NEB regulates electricity wheeled through BC for sale to the Lower 48 and a permit is required. Powerex holds a permit for electricity sold to Powerex for delivery to the Lower 48.Requirements for the Electricity Export Permit are described in Sections 8 and 9 of the National Energy Board Electricity Regulations (Electricity Regulations)Three categories of electricity export applications are established in the Electricity Regulations.At this time there is no straightforward application form. Applicants for permit need to contact the NEB and discuss which category applies and the expected decision date for the proposed permit.Section 8 of the Electricity Regulations requires every permit holder to submit a report to the NEB on or before the 15"day of each month that contains the following information:(a)the quantities and dollar value,in Canadian currency,of electricity exported by customer,by type (firm or interruptible)and by class of electricity transfer;and (b)the name and telephone number of the person who prepared the return. 5.3.2.2 System Planning,Interconnection and Operations BCTC is the Crown corporation responsible for the planning,operation and maintenance of the province's publicly-owned transmission system.BCTC has developed a 10-year $3.2 billion Capital Plan that addresses the growing demand for electricity driven by unprecedented growth in BC's economy and population. BCTC falls under the regulatory jurisdiction of the British Columbia Utilities Commission (BCUC). BCTC files an annual Transmission Revenue Requirements Application with the BCUC that includes three components:the BC Hydro Owner's Revenue Requirement,the BCTC Revenue Requirement,and the Asset Management/Maintenance Revenue Requirement.BCTC files for a Certificate of Public Convenience and Necessity (CPCN)with the BCUC for new projects. The BC Energy Plan provides policy direction to BCTC to ensure that there is adequate transmission capacity.BCTC is introducing technology innovations to improve performance of the system and allow greater utilization of existing assets. The Energy Plan directs BCTC to move from its current contract-driven practice of planning system upgrades and new transmission projects in response to a customer's request to adopt an approach that builds infrastructure in advance of need.BCTC will study and propose,where appropriate, system upgrades or expansions based,in part,on its own assessment of future market needs.Three types of transmission projects will benefit from this approach: e Aplanned system upgrade fro a Network Customer already identified in the BCTC Capital Plan that can be beneficially advanced in time e Asystem upgrade required for a customer that can beneficially be made larger than the immediate requirement e A project that BCTC identifies as having future benefits,but which has not been triggered by a customer request. BCTC will identify the third type of project through an annual project review designed to identify possible projects that would be viable as a BCTC led investment.Interconnection with the State of Alaska would fall in this third type of project. Hatch Acres Corporation PR324582.Rev.0,Page 118 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES BCTC will only proceed with an upgrade or expansion project after completion of a strong business case that identifies the costs and benefits of the proposed project,completion of stakeholder and First Nation consultations,and receipt of all necessary regulatory approvals. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Consultations with BCTC will need to continue regarding the potential extension of the BCTC backbone from Skeena to Bob Quinn Lake in Northwest BC and the link from Bob Quinn to Forrest Kerr and the AK/BC Border for interconnection with the proposed AK-BC Intertie. 5.3.2.3 Siting Requirements The siting of a transmission lines in BC requires reviews and approvals at the Federal and Provincial levels and well as from First Nations.The following paragraphs provide a brief overview of the review and approval requirements under federal and provincial law that may occur.A more thorough description is located at Appendix D. National Energy Board -As authorized by the National Energy Board Act,the NEB requires a permit or certificate to construct and operate international power lines,which are defined as facilities constructed or operated for the purpose of transmitting electricity from or to a place in Canada to or from a place outside Canada.Transmitting power through Canada falls under this permit or certification requirement.Details of the NEB requirement are further described above. Canadian Environmental Assessment Act (CEAA)-Under the CEAA,the Canadian Environmental Assessment Agency (CEA Agency)is directed to coordinate involvement of the Federal Responsible Authorities,First Nations and the public during the federal assessment process.The Federal Responsible Authorities are listed below.Instigation of the federal review requires the submission of a Screening Level Environmental Assessment (EA)Report and for a harmonized provincial/federal review process,an EAC Application is considered equivalent to the Screening Level EA Report. The Minister of the Environment reviews the EA Report prepared by the CEA Agency and determines whether or not the project will receive federal government approval. Federal Responsible Authorities -Projects that trigger CEAA involve the following federal agencies as authorized under the referenced legislative mandates.The agencies listed below are those believed to have a stake in the proposed AK/BC Intertie from the point where it crosses the AK/BC border to the substation connecting the line to the BC grid. e Environment Canada:Canadian Wildlife Service (CWA)under the Species At Risk Act (SARA) e Environment Canada:Environmental Protection Branch under the Canadian Environmental Protection Act,1999 (CEPA) e Fisheries and Oceans Canada (DFO):Habitat &Enhancement Branch under the Fisheries Act,Section 53(2) e Health Canada under the Health Act e Indian and Northern Affairs Canada under the Indian Act e Natural Resources:Legal Surveys Division,Geomantics Canada and the International Boundary Commission under the International Boundary Commission Act Hatch Acres Corporation PR324582.Rev.0,Page 119 AK-BC Alaska Final Report 18-09-07.Doc nATGh ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Transport Canada:Canadian Coast Guard and Navigable Waters Protection Division under the Navigable Waters Protection Act National Energy Board under the National Energy Board Act Provincial Agencies that have authority to consult on,review and approve aspects of the proposed AK/BC Intertie project are listed below: Ministry of Agriculture and Lands:Crown Land Administration Division under the Land Act and the Land Titles Act.A variety of permits may be required to secure Crown Land tenures from construction and occupation permits to rights-of-way and easements Ministry of Energy,Mines and Petroleum Reserves:Chief Gold Commissioner under the Mineral Tenures Act Under SARA at the Provincial level,the Species at Risk Coordination Office (SaRCO)is responsible for Provincial Coordination and the BC Ministry of Environment (MoE):BC Biodiversity Branch and BC Conservation Data Centre are involved in site-specific information and recovery planning. Ministry of Attorney General:Provincial Emergency Program (PEP)under the Environmental Management Act (EMA),Spill Reporting Regulation Also authorized under the EMA is involvement from the MoE Kitimat-Stikine Regional District regarding discharges under the Waste Discharge Regulation and smoke control under the Open Burning Smoke Control Regulation and approval from the MoE Regional Director of a Soil Relocation Permit under the Contaminated Sites Regulation The BC MoE's authority also involves the Permit and Authorization and Service Bureau under the Wildlife Act to approve works and permit adverse effects to wildlife,wildlife habitat or resident fish habitat.Under the Water Act,Section 9,a MoE Habitat Officer approves proposed works and changes in and about a stream MoE:BC Parks permitting authority under the Protected Areas of British Columbia Act and the Park Act requires a park use permit or resource use permit any may include payment for use.The current transmission line layout between the AK/BC border and the substation at Forrest Kerr crosses through the Craig River Headwaters Protected Area.The siting of a transmission line through this protected area falls under the authority of BC Parks Ministry of Forests and Range:North Coast Region,Skeena-Stikine Forest District under the Forest Act requires a license to harvest on Crown land.The Forest and Range Practices Act requires a Forest Stewardship Plan before authorization to build roads or harvest Ministry of Public Safety and Solicitor General:Office of the Fire Commissioner under the Fire Services Act Ministry of Tourism,Sport and the Arts:Archaeology Permitting and Assessment Section under the Heritage Conservation Act Ministry of Transportation:Northern Region,Bulkley-Stikine District under the Transportation Act Hatch Acres Corporation PR324582.Rev.0,Page 120 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report e BC Oil and Gas Commission:Operations Division under the Pipeline Act. First Nations -The Talhtan Nation (Talhtan Indian Band and Iskut First Nation)under Provincial law are required to be consulted and engaged.Allows for facilitation of First Nations'input to formal environmental impact assessment process,project-related decisions regarding issues affecting First Nations interests,environmental management plans,and terms and conditions of project approval. 5.4 Permitting and Licensing -Hydro &Tidal Energy Generation Projects 5.4.1.Federal Agencies One of the specified tasks important to this Study is consideration of new generation that could be encouraged by State development of the proposed AK-BC Intertie.We identified several new projects that might be developed for the purpose of generating power to be transmitted across the proposed AK-BC Intertie for sale in BC and/or the PNW.Information available at this time for proposed projects is schematic at best.This is due to the nature of the FERC licensing process.For example,the three identified projects at Thomas Bay -Cascade Creek,Ruth Lake,and Scenery Creek -are currently proceeding under FERC Preliminary Permits,the sole purpose of which is to secure a future priority to file an application license and to perform studies necessary to support a license application.The holder of these permits has not,to date,conducted any detailed studies and therefore,there is no detailed information available on the proposals to develop these projects. FERC Preliminary Permits,unlike the Presidential Permit and Special Use Authorization discussed in Section 5.3 above,do not authorize the holder of the permit to construct the proposed projects. Applicants interested in developing new hydropower projects found jurisdictional to the FERC are required to prepare and file an Application for License (Applicant)with the FERC.Applicants develop narrative description and drawings depicting a proposal for the project and engage ina lengthy regulated consultation process that includes participation by state and federal agencies; local governments;non-governmental organizations (NGO);Native Tribes;and other interested persons and organizations.Through this consultation process,potential environmental effects are identified and the Applicant develops study plans and conducts in-depth field and office environmental,engineering,and economic studies to develop information sufficient to support the application for license.The Applicant's proposal includes a pre-reconnaissance level description and layout of proposed project facilities,and proposed mode of project operation,including proposed reservoir operation and expected annual generation.The application includes detailed information regarding anticipated effects on natural and human resources associated with the proposed project.Detailed information regarding the final design and operation for licensed projects is developed post license issuance prior to commencement of construction. This section of the Report provides a brief overview of agencies and their respective roles in reviewing applications for hydropower license. Hatch Acres Corporation PR324582.Rev.O,Page 121 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES 5.4.1.1 Federal Energy Regulatory Commission Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Part |of the Federal Power Act (FPA)®,as amended,authorizes the FERC to issue licenses to nonfederal water power projects located on navigable waterways,occupying federal lands,using the power generation potential at existing federal dams,and projects interconnected in interstate commerce and affecting "commerce clause waterways.”©*.Projects located within the Annette Island Indian Reservation or on lands selected by Alaska Native Corporations under the Alaska Native Claims Settlement Act (ANCSA)are not jurisdictional to the FERC. The FERC issues licenses for up to 50 years.Upon expiration of a license,there are provisions for federal takeover or the FERC can issue a new license to either the existing licensee or a new licensee.New licenses are issued for terms of 30 to 50 years. The FERC Commission is composed of five members appointed by the President with the advice and consent of the Senate.One member is designated by the President as Chairman and serves as the administrative head.FERC staff are organized into several offices,including the Office of Energy Projects (OEP)where the hydropower licensing program is located.Regulations implementing the FERC hydropower licensing program and codified in 18 CFR Subchapter B - Regulations Under the Federal Power Act.”° Hydropower Licensing Program Three divisions within OEP are assigned responsibility to implement the FERC licensing program 1.Division of Hydropower Licensing (DHL)receives and reviews applications for license for conventional and pumped storage hydro projects and has recently added tidal projects.FERC hydropower licenses include all project facilities:dam,reservoir,spillway,penstocks, powerhouses,switchyards,primary power lines,and other structures proposed to be included as part of the project;and lands occupied by project facilities.Licenses include numerous terms and conditions recommended and/or mandated by state and federal agencies with jurisdiction over natural and cultural resources that may be affected by project construction and operation.Staff in DHL develop the recommendation for consideration by the Director of OEP or the full Commission depending on the level of complexity and/or controversy associated with a specific project.Staff in DHL,with a few exceptions of biologists assigned to FERC Regional Offices,are located in Washington,D.C. 2.Division of Hydropower Administration &Compliance (DHAC)receives and reviews applications for Preliminary Permit and the 6-month reports prepared by the Permittee during the term of the permit.Preliminary Permits are issued for a three-year term.The purpose of a Preliminary Permit is to secure a priority position (first one filed)before filing a license application.The three-year term provides time for a prospective developer to evaluate the feasibility of the proposed project and perform studies necessary to support a license application.If at the expiration of the permit a potential Applicant has not completed preparing the application,the Permittee may apply for a second permit.DHAC also receives filings post- ®8 16 USC 791a -823c 69 Section 23(b)(1)of the FPA ”°The FERC website includes a section on the hydropower industry with a link at "General Information” "Regulation”to the US Code and the Code of Federal Regulations (www.ferc.gov/industries/hydropower.asp) Hatch Acres Corporation PR324582.Rev.O,Page 122 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES license issuance as required by terms and conditions of the expressed in license articles. Failure to comply with terms and conditions of a license can subject a licensee to civil penalties.Staff in DHAC,with a few exceptions of environmental specialists assigned to FERC Regional Offices,are located in Washington,D.C. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 3.Division of Dam Safety &Inspection (DDSI)includes an office in Washington,D.C.,however most DDS!personnel are located in the five regional offices.Staff in the Portland Regional Office are assigned to projects located in Alaska.Staff perform annual inspections of licensed projects and participate in the five-year reviews performed by Independent Consultants. Overview of the FERC Licensing Process Hydro licensing is a complex and lengthy regulatory process that takes,on average,10 years from start to finish.A number of federal laws and regulations,as well as some state laws and regulations,govern the way in which decisions are made and establish the procedures that must be followed. A license from the FERC is required to construct,operate,and maintain a non-federal hydro project that is or would be a)located on navigable waters of the United States,b)occupy U.S.lands,c) utilize surplus water or water power from a U.S.government dam,or d)be located on a stream over which Congress has commerce clause jurisdiction.”' Preliminary Permit A preliminary permit secures priority of an application for license,and it provides the prospective developer with time to evaluate the feasibility of the proposed project and to complete the studies required to support a development application.A preliminary permit,issued for up to three years, does not authorize construction;rather,it maintains priority of application for license (i.e., guaranteed first-to-file status)while the permittee studies the site and prepares to apply for a license. The permittee must submit periodic reports on the status of its studies.However,it is not necessary to obtain a permit in order to apply for or receive a license. Once a prospective applicant identifies a proposed project,the project must be characterized in sufficient detail to prepare a preliminary permit application. If a permittee fails to file an acceptable license application during the term of the permit,the permittee's priority of application for a license is lost,but the permittee can still file a license application. Project Licensing Original licenses are restricted to newly constructed projects or existing projects that come under the Commission's jurisdiction for the first time.A license conveys the right of eminent domain and a potential developer must file an application for license or exemption from licensing if the project will be: e located on a navigable waterway of the U.S 71 Where project construction or expansion occurred on or after August 26,1935,and the project affects the interests of interstate or foreign commerce. Hatch Acres Corporation PR324582.Rev.0,Page 123 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES e occupying U.S.lands Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report e utilizing surplus water or water power from a U.S.government dam e located on a body of water over which Congress has Commerce Clause jurisdiction,project construction occurred on or after August 26,1935,and the project affects the interests of interstate or foreign commerce. Several of the undeveloped hydropower projects identified in Section 7 (see Table 7.2-3)would fall under FERC jurisdiction until such time the State of Alaska promulgates regulations for a State Licensing Process as discussed below in Section 5.4.2.5. The current default Federal licensing process that an as-yet-undeveloped hydropower project will follow is called the Integrated Licensing Process (ILP)and is intended to streamline the previous Commission's licensing processes by providing a more predictable,efficient,and timely licensing process that continues to ensure adequate resource protections.The efficiencies expected to be achieved through the ILP are founded in three fundamental principles: e Early issue identification and resolution of studies needed to fill information gaps,avoiding studies post-filing e Integration of other stakeholder permitting process needs e Established time frames to complete process steps for all stakeholders,including the Commission. The steps and schedule to be followed through the ILP is shown in Figure 5.4-1. Hatch Acres Corporation PR324582.Rev.0,Page 124 AK-BC Alaska Final Report 18-09-07.Doc 5.5-5 years before expiration for relicense Pre-ApplicationActivity30 a |...-jra._..Lidertsin_ (Section 241 of the Energy Policy Act of 2005) 'oc Post-FilingActivityral *Qantian 944 vf tha Enarens Dalian Ant af ONDE in nink (Applicant files NOI and 60 /Commission notices \30 Commission holds Comments on PAD,45 Applicant Files 90 Comments Pre-Application NOIWPAD and issues Scoping Meetings/SD1 and Proposed Study Plan i on Document (PAD)(initial Tribal Consultation)Scoping Document 1 Site Visit Study Requests Study Plan Proposed 30 Meeting (SD1)Discuss issues,mgmt §5.11 Meeting(s)Study Plan Applicant may request \§5.7 2a)obj,existing info,info Commission issues (informal use of TLP or ALP "oC Commission acts on needs,process plan,SD2,if necessary resolution ofXQommentsonuseof|study issues)>,»|TLP or ALP requests and scheduleTLPorALP,if requested >30\$5.3,§5.5,§5.6 1 J 30 (65.3 2b )\5.8 3)\g5.10 6 /\§5.11 §5.12 (;{Applicant files revised \30 /Commissionissues \22 No disputes {First season studies \Second season Study Plan for Study Plan >>)and Study Review:1)studies,if needed,and Commission approval Determination L tla J Applicant files initial Study Review »study report 2)Study >(same as first season) File reply comments (Mandatory conditioning)meeting 3)Requests we .:Study Dispute Determination onwithin15daysagenciesfilenoticeof;for study plan >,Resolution Process Study Dispute ificati study disputes modification\§5.13 9 /§5.13 10 20 ($5.14 )§5.14 12)70 \§5.14 13 5.15 14 Applicant's Preliminary 90/Comments on \ Licensing Proposal Applicant's Preliminary (not later than 150 Licensing Proposal days before ,application)Additional Information Requests,if needed §5.16 5.16 17 2 years before expiration for relicense 14 ()60.60.45 (' _ License Application Tendering Notice Notice of Acceptance id Comments,"1 Reply comments id §5.19 19a Interventions,Parties submit ia /Notice of Ready for preliminary terms and 30 alternatives 15 > ("Environmental Analysis conditions EPAct-1a 55.23 21ayy, .Commission decision on .r >!any outstanding pre->Parties request trial-Interventions and Agency response to trial-30 filing AIR type hearing responses type hearing 5.19 19b §5.22 20 §5.23 21/7 30 EPAct-1b }15 EPAct-2 )30 EPAct-33).7, 75.{Commission issues _)30-45 (Comments on EA 60 Modified terms and q 55.24 non-draft EA 22a)|§5.24 23a|55.24 conditions 5 Commission issues r license order135CommissionissuesDraft30-60 {a 60 (Modified terms and \90 oo. >EA or EIS ©Comments on Draft EA conditions based on any Commission issues ($5.25 22b )or ElS hearing decision,Final EA or EIS """comments,and proposedAgencyhearingTrial-type hearing alternativesreferralEpact-4 |90 decision EPAct-5 \§5.25 236)\$5.2 24b)§5.25 25 §5.25 26 (FERC may refer conditions to FERC's Dispute Resolution Service EPAct-6 | nATGA AGE Agency Authority Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 5.4-1 below contains a list of the Federal laws governing the permitting and licensing processes for hydropower projects Table 5.4-1 List of Public Laws LAW YEAR AGENCY KEY POINTS AUTHORIZED Federal Power Act {|1920 and US Forest Service,|Agencies can issue mandatory conditions to ensure Section 4(e)amended Bureau of Land the project operations do not interfere with the Met.intended public use of the land. Federal Power Act |1920 and |FERC FERC must give equal consideration to power and Section 10(a)amended non-power values,known as "balancing.” Federal Power Act |1920 and_|State and Federal |Agencies recommended terms and conditions to Section 10(j)amended |fish and wildlife protect fish and wildlife must be consistent with the agencies FPA, Federal Power Act |1920 and |US Fish &Agency imposed mandatory construction,operation Section 18 amended |Wildlife Service,and maintenance of fishways.Agency fishway National Marine prescriptions cannot be rejected or altered by the Fisheries Service |FERC. National 1969 FERC,US Forest FERC or the applicant must conduct a "scoping” Environmental Service process and prepare an environmental assessment Policy Act (NEPA)(EA)describing the existing environment and the applicant's proposal to operate the project and to provide environmental enhancements.FERC analyzes and determines how to "balance”power and non-power values.An environmental impact statement (EIS)may also be required. Clean Water Act 1977 EPA,US Army Prohibits the discharge of pollutants or fill into most Section 404 Corps of US waterways without a permit.Permit may be Engineers issued by the EPA (NPDES)or the COE (Section 404). Clean Water Act 1977 State water quality |Requires that the project secure a water quality Section 401 agencies certificate (401 Certification)from the state(s).Studies may be required.FERC must incorporate conditions of the 401 Cert.into license conditions. Fish and Wildlife 1934 State and Federal |FERC must consult with the USFWS and state Coordination Act fish and wildlife agencies before granting a license. agencies National Historic 1966 State Historic FERC must take into account the effect of issuing a AK-BC Alaska Fina!Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 126 nATGH AGH Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report LAW YEAR AGENCY KEY POINTS AUTHORIZED Preservation Act Preservation license on any district,site,building or structure Officer eligible for inclusion in the National Register of Historic Places.Advisory council must have opportunity to comment on effect.Meeting Historic American Engineering Records documentation standards may allow for approval. Wild and Scenic 1968 National Park Prohibits FERC from issuing license for construction Rivers Act Section Service of any project on or directly affecting a wild and 7(a)scenic river as designated by the National Park Service. Endangered 1973 US Fish &FERC must consult with agencies to determine Species Act Wildlife Service,_|whether the relicensing is likely to jeopardize the National Marine existence of any endangered or threatened species or Fisheries Service |result in the destruction of critical habitat.FERC's biological assessment (BA)identifies species and project affects.The agencies biological opinion (BO) analyzes the FERC's recommended measures for protection the species. Coastal Zone 1972 State Coastal If a project is located in a coastal zone,the licensee Management Act Management must submit a CZMA federal consistency certification Program agency to the FERC and the CMP agency (the license application,or parts of,usually suffice for the certification).The licensee must provide the state with data showing the project's effects,if any,on coastal resources.The CMP agency reviews and determines if the project is consistent with the CMP. Americans with 1990 Department of This law requires public and private entities that have Disabilities Act Justice "public accommodations",such as recreation facilities at hydro projects,to be accessible to persons with disabilities.FERC requires new facilities and access areas to comply with the requirements of the ADA. 5.4.1.2 U.S.Forest Service Applicants for license for projects that would occupy lands included in the National Forest System are required to consult with the U.S.Forest Service ... The Federal Land Management and Policy Act of 1976 (FLPMA)requires federal agencies, including FERC,in deciding whether to issue a license or permit for a project that would occupy lands within the National Forest System to include terms and conditions prepared under AK-BC Alaska Final Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 127 nATGn ACHES requirements of FLPMA and Section 4(e)of the FPA in any issued license.Projects in SE Alaska are located on lands within the Tongass National Forest,with few exceptions”. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 5.4.1.3 U.S.Fish and Wildlife Service and National Marine Fisheries Service Applicants for license are required to consult with the US Fish and Wildlife Service,the National Marine Fisheries Service,and the state agency with delegated authority under federal statutes. The Fish and Wildlife Coordination Act (FWCA)requires federal agencies,including FERC,in deciding whether to issue a license or permit for a project that would control,impound,or modify streams and water bodies to consult with the Fish and Wildlife Service (FWS),the National Marine Fisheries Service (NMFS)and the appropriate state fish agencies regarding conservation of these resources.In the State of Alaska the authorities under the FWCA are split between the Alaska Department of Fish &Game (ADFG)and the Alaska Department of Natural Resources (ADNR)”'. FERC is required under the FPA,as amended”to include recommendations from these agencies regarding measures to protect,mitigate,and enhance fish and wildlife species and related habitat that may be affected by a proposed project construction and long-term operation. Section 18 of the Federal Power Act requires FERC to include recommendations for fishways at licensed projects. The FWS and the NMFS are authorized under the Endangered Species Act (ESA)to mandate terms and conditions in licenses issued by the FERC to protect candidate and listed species that may be affected by a proposed project construction and long-term operation.FERC engages in consultation with the FWS and NMFS under Section 7 of the ESA to determine whether a proposed license issuance is likely to jeopardize the continued existence of any listed or candidate species,or result in damage to critical habitat.The FERC may be required to conduct a biological assessment for the purpose of identifying any ESA species likely to be affected by licensing. 5.4.1.4 U.S.Army Corps of Engineers Applicants for license are required to consult with the US Army Corps of Engineers (COE)regarding proposed facilities that would require construction in wetlands and floodplains,including removal of materials and/or placement of fill in wetlands,streams,and other waterbodies.The COE is authorized to issue permits under Section 404 of the Clean Water Act governing the above noted activities. 72 Projects located on Annette Island are within a federal reservation,not the National Forest.Certain hydro projects in SE Alaska are sited on Jands selected by Native Corporations under the Alaska Native Interest Lands C Act (ANILCA)that have been transferred from federal ownership.Certain hydro projects in SE Alaska are sited on lands selected by the State of Alaska under the Statehood Act that have been transferred from federal ownership.These projects do not require a Special Use Permit. 73 Former Alaska Governor Murkowski transferred certain responsibilities regarding permitting from the Alaska Department of Fish and Wildlife (ADFG)to the Alaska Department of Natural Resources (ADNR).The Alaska State Legislature is considering a proposal to return the permitting authorities to ADFG. 74 The Federal Power Act was amended in 1986 by the Electric Consumers Protection Act (ECPA)to not only consult with the FWS and the state agencies,but also to include in each license conditions for the protection, mitigation,and enhancement of fish and wildlife. Hatch Acres Corporation PR324582.Rev.0,Page 128 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES 5.4.1.5.Advisory Council on Historic Preservation Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Section 106 of the National Historic Preservation Act (NHPA)requires the FERC and applicants for license to consult with the State Historic Preservation Officer and,where projects are proposed to be located on lands within the National Forest System,the US Forest Service Archaeologist and to perform studies required by those agencies.Consultation includes consideration of properties that may be eligible for listing and/or listed in the National Register of Historic Places.The FERC enters into a Programmatic Agreement (PA)with the State Historic Preservation Officer,the Advisory Council on Historic Preservation,federal land management agencies where applicable,and the Applicant.The PA includes stipulations governing protection and management of properties eligible for listing;establishes requirements for preparation of the Historic Properties Management Plan (HPMP);and interim treatment of historic properties.The PA provides evidence that the FERC has satisfied its responsibilities pursuant to the NHPA and is incorporated into any license issued by the FERC 5.4.2 State of Alaska 5.4.2.1 Alaska Department of Environmental Conservation The Alaska Department of Environmental Conservation is delegated authority by the US Environmental Protection Agency (EPA)through its authority under the Clean Water Act (CWA)to set water quality standards,issue Water Quality Certifications ,and oversee the state's National Pollutant Discharge Elimination System (NPDES)program.Under this delegated authority the Division of Water accomplishes the following: e Establishes standards for water cleanliness e Regulates discharges to waters and wetlands e Provides financial assistance for water and wastewater facility construction,and waterbody assessment and remediation e Trains,certifies and assists water and wastewater system operators e Monitors and reports on water quality. Section 401(a)(1)of the CWA requires an applicant for a federal license or permit for any activity that may result in a discharge into navigable waters of the United States to provide to the licensing or permitting agency a certification from the state in which the discharge originates that such discharge will comply with certain sections of the CWA.Thus,in order for the FERC to issue a license to as hydropower project,that project must first obtain a Water Quality Certification from the ADEC. 5.4.2.2 Alaska Department of Fish and Game and Department of Natural Resources The Fish and Wildlife Coordination Act (FWCA)requires federal agencies,including FERC,to consult with the appropriate federal and state fish agencies regarding conservation of these resources as discussed in Section 5.4.1.3.The state authority is split between the Alaska Department of Fish &Game (ADFG)and the Alaska Department of Natural Resources (ADNR). Hatch Acres Corporation PR324582.Rev.0,Page 129 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES FERC is required under the FPA,as amended to include recommendations from these agencies regarding measures to protect,mitigate,and enhance fish and wildlife species and related habitat that may be affected by a proposed project construction and long-term operation. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report In addition,ADFG permits construction activities in and or across streams.ADNR While state agencies do not have Section 18 fishway prescription authority,the federal agencies (FWS and NMFS)do consider the issues raised by ADNR and ADFG in the NEPA process. 5.4.2.3 State Historic Preservation Officer The Alaska State Historic Preservation Officer (SHPO)is appointed by the Governor and is responsible for consultation in FERC proceedings under Section 106 of the NHPA as described in Section 5.4.1.5.The Alaska SHPO is an office of the Department of Natural Resources,under the Division of Parks and Outdoor Recreation.The SHPO,along with the USFS where applicable, require studies to consider and identify properties that may be eligible for listing and/or listed in the National Register of Historic Places and development of an Historic Properties Management Plan becomes an condition of the FERC-issued license. 5.4.2.4 Proposed State of Alaska Hydro Licensing Program On November 9,2000,the Federal Power Act was amended”by adding section 32”entitled "Alaska State Jurisdiction over Small Hydroelectric Projects.”Section 32 of the Federal Power Act (FPA)provides that the FERC "...shall discontinue exercising licensing and regulatory authority under this subchapter over qualifying project works in the State of Alaska,effective on the date on which the Commission certifies that the State of Alaska has in place a regulatory program for water- power development that - (1)protects the public interest,the purposes listed in paragraph (2),and the environment to the same extent provided by licensing and regulation by the Commission under this subchapter and other applicable Federal laws,including the Endangered Species Act (16 USC 1531 et seq.)and the Fish and Wildlife Coordination Act (16 USC 661 et seq.); (2)gives equal consideration to the purposes of - (A)energy conservation; (B)the protection,mitigation of damage to,and enhancement of,fish and wildlife (including related spawning grounds and habitat); (C)the protection of recreational opportunities; (D)the preservation of other aspects of environmental quality; (E)the interests of Alaska Natives;and 7°§.422 entitled "A bill to provide for Alaska state jurisdiction over small hydroelectric projects”,introduced on February 11,1999,by Sen.Frank Murkowski. 76 16 USC 823(c) Hatch Acres Corporation PR324582.Rev.0,Page 130 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE AlaskaFinalReport (F)other beneficial public uses,including irrigation,flood control,water supply,and navigation; and (3)requires,as a condition of license for any project works -...” Other requirements address fishways prescribed by the FWS or NMFS,operation of navigation facilities as required by the COE,and conditions for protection,mitigation,and enhancement of fish and wildlife based on agency recommendations. In short,the RCA program is required to be equal to the standards established in the Federal Power Act governing the FERC hydropower program. On March 13,2001,SB 140 was introduced”in the Alaska Legislature entitled "An Act relating to regulation and licensing of certain water-power development projects;and providing for an effective date.”On January 31,2003,AS 42.45.350 became effective requiring the RCA to adopt regulations to establish a regulatory program for small (5 MW or less)water-power development projects. The RCA convened a Stakeholder Advisory Committee,held public meetings and workshops and developed draft regulations to establish a state licensing program under 3 AAC proposed Chapter 46 Hydropower licensing program.”The proposed regulations were issued for public comment.” The RCA received comments and worked with FERC representatives to address various issues.The statutory timeline in the rulemaking proceeding was extended to April 3,2006."At a public meeting held on March 22,2006,the RCA discussed "the enormous effort undertaken thus far by the public,stakeholders,Staff,and our legal counsel in producing draft regulations.”On March 31, 2006,the RCA determined that the statutory timeline did not anticipate "an unusually complex regulations proceeding such as this.”The RCA issued an Order Closing Docket R-03-5 and stated its intent to finish review of the issues remaining in a new regulations docket and closed the proceeding without having adopted final regulations.*' On January 27,2007,the RCA entered into a contract with a consultant to provide assistance to develop a set of draft state hydropower licensing regulations.RCA proposes to issue a draft regulations by the end of April with a 30-day public comment period.The RCA will hold a public meeting to present public comments sometime in May.The final revised regulations would be scheduled for a public meeting in June.Following RCA approval,the State will apply to the FERC for approval in accordance with the federal legislation.” 77 Senators Torgerson,Taylor,Austerman,and Cowdery sponsored the legislation 78 R-03-5(2)Order Issuing Proposed Regulations for Comment and Setting Public Hearings,dated March 25, 2005.: 79 Order R-03-5(3)Order Granting Requests to Extend Comment Period,dated Apri!20,2005. 8°Order R-03-5(4),Order Extending Statutory Timeline,dated December 16,2005. 8"Order R-03-5(5),Order Closing Docket,dated March 31,2006.The record from this Docket will be subsumed into a new docket. ®16 USC Sec.823c. Hatch Acres Corporation PR324582.Rev.0,Page 131 AK-BC Alaska Final Report 18-09-07.Doc nATGA AGE 5.5 Permitting and Licensing -Other Renewable Energy Generation Projects Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 5.5-1 summarizes the Federal and State agencies that may be involved in the reviewing and approving various other renewable energy generation projects.At the time of this study,specific projects have not been identified.At such time as specific projects are defined and designed,the agencies listed below may have authority over issuing permits,licenses and/or approvals for the projects. Table 5.5-1 Renewable Energy Project Requirements RESOURCE FEDERAL STATE OTHER TYPE APPROVALS APPROVALS REQUIREMENTS Geothermal Interior AK DNR Native Corporation(s) USFS ADF&G Municipalities/Boroughs FWS SHPO SSRAA COE AK DEC NGOs USGS AIDEA Public EPA AK PUC BLM AK DOT&PF NPS Onshore Wind Interior AK DNR Native Corporation(s) USFS ADF&G Municipalities/Boroughs FWS SHPO SSRAA COE AK DEC NGOs USGS AIDEA Public EPA AK PUC BLM AK DOT&PF NPS Offshore Wind MMS AK DNR Native Corporation(s) Coast Guard ADF&G Municipalities/Boroughs COE SHPO SSRAA NMFS AK DEC NGOs EPA AIDEA Public AK PUC AK DOT&PF Tidal FERC AK DNR Native Corporation(s) MMS ADF&G Municipalities/Boroughs Coast Guard SHPO SSRAA COE AK DEC NGOs NMFS AIDEA Public EPA AK PUC AK DOT&PF AK-BC Alaska Final Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 132 WATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska 6.TRANSMISSION LINE COSTS AND ISSUES AK-BC Alaska Final Report 18-09-07.Doc HATGH AGES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 6.TRANSMISSION LINE COSTS AND ISSUES 6.1 Overview This report presents descriptions of potential future electrical transmission segments and provides an analysis of the role an integrated electric transmission system may play in improving economic conditions within SE Alaska and facilitating export of Alaskan hydro power to BC and the PNW. Specific segments and groups of potential future segments addressed in this report are listed in Table 6.1-1 below and include: Swan-Tyee Intertie (STI).The FDPPA currently has a request pending before the State decision- makers to authorize funds to complete the 57-mile STI that will interconnect power generated at the FDPPA's Tyee Lake and Swan Lake Projects.Interconnection will enable the FDPPA to optimize generation at Tyee Lake as approximately 50%of the potential power is currently constrained by lack of a transmission segment that would deliver current surplus power to load. Tyee Lake currently serves loads in Wrangell and Petersburg;with the STI,Ketchikan would be served. The STI would interconnect existing FDPPA-owned line segments between Tyee Lake,Wrangell, and Petersburg;and between Swan Lake and Ketchikan. Future SE Alaska Transmission Segment Projects.A proposal to construct a transmission segment between Petersburg and Kake would deliver relatively low-cost clean hydroelectric power to offset diesel generation.Proposed segments between Metlakatla and Ketchikan;Coffman Cove on Prince of Wales Island and Wrangell;and Kake and the proposed Takatz Lake project on Baranoff Island would provide a path to export surplus power over the proposed AK-BC Intertie. AK-BC Intertie.Interconnect SE Alaska with BC by constructing the proposed AK-BC Intertie to provide a path to export electric power surplus to the region for sale in BC and/or the PNW;and to encourage development of new hydropower and renewable resource generation for the purpose of export.. Proposed Line to Transmit Power from Proposed Projects at Thomas Bay to the AK-BC Intertie. Development of the three hydro projects at Thomas Bay is dependent on construction of a submarine transmission line from a proposed new substation at Thomas Bay to a new substation at Scow Bay on Mitkof Island where power would then be transmitted across the FDPPA transmission line from Petersburg to a new substation at Tyee Lake and the AK-BC Intertie. 6.1.1 Cost Estimates The development of,or source of,the transmission line cost estimates used in this report depended on the particular project.Table 6.1-2 identifies the cost estimates and their sources.Construction cost estimates were developed for AK-BC Intertie and the STI and rough order of magnitude cost estimates were prepared for the Coffman Cove-Wrangell and Kake -Takatz connections.All other cost estimates were taken directly from studies by others and escalated to 2007 dollars.For example,the 2005 Kake-Petersburg Transmission Intertie Study by D.Hittle &Associates is an in- Hatch Acres Corporation PR324582.Rev.0,Page 134 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES depth review of the line.It includes six alternative routings,various voltages,and even different conductor sizes.This is a comprehensive study including field reconnaissance and we do not have any reason to modify their cost estimates. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report In 2001,AP&T commissioned the consulting firm Teshmont to prepare a report on the possible use of new HVDC technologies in SE Alaska.This report concludes that a Ketchikan -Thorne Bay - Wrangell HVDC system could be built at less cost than that for the proposed AC line for the STI. The conclusion is apparently based on using the latest technology for:valves (IGBT),converters (VSC)and submarine cable (either extruded polymer or MIND).All of these state-of-the-art technologies have been brought together and installed in a less than a hand-full of projects around the world.In 2006,the Estlink project between Finland and Estonia is one of the latest installations:350 MW,150 kV DC,31 kM land cable,74 kM submarine cable.The stated reason for selecting the HVDC system was "Length of land cable,sea crossing and non-synchronous AC systems”. This combination of conversion along with the economical XLPE cable may well be the wave of the future.However,the projects that are being contemplated in SE Alaska do not necessarily fit the same conditions.The Alaskan projects are very small compared to the 2,000 GWh that are expected on the Estlink.The demands for most of the projects are not close to the 350 MW capacity of Estlink.The submarine cable lengths in Southeast for the proposed line would be longer than the 74 Km crossing of Estlink.The final comparison is reliability.The Estlink is a tie between two very large systems that can function on their own. The application of state-of-the-art technology to small Alaskan communities is impractical.In our opinion,none of these new systems has sufficient track-record to yet be called conventional. Alaska is not the environment to be proving technology.The electrical systems are too small to be dealing in any form of R&D especially if they will be dependent on the system as their primary supply.The use of polymer insulation for a DC submarine cable is pushing a technology that was developed from lower AC voltages for installations in soils.This could be the future of submarine cables,but it is early in terms of proven cable life.The possibility of a cable failure would be a major impact to a community in SE Alaska and the impact could be very different from that on an Intertie between two major electrical grids. To fit with Alaska,we have utilized in our DC cost estimates the more conventional,and granted more expensive,converter and submarine cable systems. Hatch Acres Carporation PR324582.Rev.0,Page 135 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGE Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 6.1-1 SE Alaska --Existing (E)and Proposed (P)Transmission Segments TRANSMISSION LINE E|P OWNER /INTERCONNECTED AREAS /COMMUNITIES SEGMENT OPERATOR PMPL/WMLP'/Tyee Lake X The Four Dam Petersburg and Wrangell Transmits power from Tyee Pool Power Lake Project Agency Swan Lake/KPU X The Four Dam KPU serves Ketchikan,Ketchikan Gateway Transmits power from Swan Pool Power Borough,and City of Saxman Lake Project Agency Swan-Tyee Intertie (STI)X |The Four Dam Petersburg,Wrangell,Ketchikan,Ketchikan Interconnects generation at Pool Power Gateway Borough,and City of Saxman Tyee Lake and Swan Lake Agency Projects AK-BC Intertie X |To be Would provide path to export power from SE Tyee Lake to AK/BC Border determined Alaska to BC Kake-Petersburg X |Tobe With STI would connect Kake,Petersburg, Transmission Intertie (KPTI determined Wrangell,Ketchikan,Ketchikan Gateway Would transmit power from Borough,and City of Saxman Tyee Lake Project Metlakatla-Ketchikan X |Metlakatla Light |With ST!would connect Metlakatla,Ketchikan, Intertie &Power Ketchikan Gateway Borough,City of Saxman, Wrangell,and Petersburg. Prince of Wales Island to X |AP&T With STI would connect communities on Prince STI of Wales Island to Ketchikan,Ketchikan Gateway Borough,City of Saxman,Wrangell,and Petersburg Thomas Bay to X |Tobe Export line to the proposed AK-BC Intertie for PMPL/WMLP/Tyee Lake to determined export to BC. AK-BC Intertie Takatz Lake to KPT!X |To be Export line to the proposed AK-BC Intertie for determined export to BC. AK-BC Alaska Final Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 136 Table 6.1-2 Transmission Segments with Estimated Costs Estimated Capital |Estimated O&M|Estimated Construction Segment Cost Cost Time Source Notes Route and O&M Costs from 2006 Southeast AK-BC Intertie Alaska'$31,950,000 $360,000 Alaska Energy Export Study Swan-Tyee Intertie'$57,000,000 $500,000 Partially completed construction Transmission Segments with Rough Order of Magnitude (ROM)Costs -Basis in Studies/Reports ROM Capital ROM O&M_|Estimated Construction Segment Costs Cost Time Source Notes Costs escalated from 2005 Kake-Petersburg Transmission Intertie Study -Center-South 3 Petersburg to Kake?$31,350,000 $210,000 Route Transmission Segments with Rough Order of Magnitude (ROM)Costs -Limited or No Studies/Reports ROM Capital ROM O&M_|Estimated Construction Segment Costs Cost Time Source Notes Estimated 30 mile distance from border to Forrest Kerr;extrapolated cost from Alaska 4 _AK-BC Intertie British Columbia'$36,000,000 $450,000 portion of AK-BC Intertie Only route identified from 1985 Thomas Bay Hydroelectric Project Pre-feasiblity Study.138 5 Thomas Bay to Petersburg $66,000,000 $810,000 kV,100 MW capacity Identified in 1987 Souteast Alaska Intertie Study;Capital costs escalated from same study. 6 Metlakatla to Ketchikan $14,900,000 $125,000 7MW estimated load,34.5 kV No route identified;costs based upon approximately 50 mile distance of submarine 7 Coffman Cove to Wrangell (HVDC)$170,000,000 $1,300,000 line.138 kV,30 MW capacityNorouteidentified;costs based upon approximately 45 mile distance of submarine 8 Kake to Takatz (HVDC)$160,000,000 $1,200,000 line.138kV,50 MW capacity 'Capital costs for this project include indirect costs such as permitting,engineering,etc. ?Capital costs for this project include indirect costs such as permitting,engineering,etc.Capital and O&M costs are based upon using road access entire length of the line. 3 Costs for all submarine cables are based upon 30 year service life and no cable replacement. HATGH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 6.2.Swan-Tyee Intertie 6.2.1 Overview Ketchikan Public Utilities (KPU)transferred its ownership and management of the Swan -Tyee Intertie (STI)to the FDPPA in 2004.The STI is an important element of the proposed interconnected electric transmission system within SE Alaska and the proposed AK-BC Intertie.The State of Alaska has been requested to provide supplemental funding in the amount of $46.2 million to complete construction of the STI.The STI will be constructed with public funds (i.e.a grant that would not require a return of or on the capital to the State).O&M,replacements,and reconstruction in the event of catastrophic failure are the responsibility of the FDPPA. Approximately 18 miles of the right-of-way was cleared in 2002 and nearly all of the clearing was completed in 2004.Initiation of structure foundation installation also began in 2004.In the fall of 2004,funding sources for the STI were depleted and the FDPPA stopped construction.The STI is approximately 57 miles long with no submarine crossings.It will be constructed for 138-kV nominal voltage but will be operated initially at 69-kV. The ST!would facilitate use of current excess power at Lake Tyee in Ketchikan and further encourage fuel switching from oil to electric heat among other benefits. 6.2.2 Corridor and Facilities:Swan-Tyee Intertie (STI) The purpose of the partially constructed STI is to connect the FDPPA's existing Tyee Lake Hydroelectric Project (Tyee Lake or Tyee),located approximately 40 miles southeast of Wrangell, Alaska,with the FDPPA's existing Swan Lake Hydroelectric Project (Swan Lake or Swan),located about 22 miles northeast of Ketchikan,Alaska.The STI will interconnect with two existing FDPPA- owned lines:the line from Tyee to Wrangell to Petersburg;and the line from Swan to Ketchikan. The Tyee Lake Project located at the north end of the STI currently serves the loads of the Wrangell- Petersburg area.However,absent interconnection with other potential load centers,the Tyee generating plant typically operates at significantly below its capacity and excess water is spilt. The Swan Lake Project located at the south end of the STI serves the loads in the Ketchikan area. Existing loads periodically require diesel generation to supplement the output of Swan Lake and the KPU owned hydro projects.Power flow from Tyee to Ketchikan across the STI will depend on the relative load/resource balance positions of the Wrangell/Petersburg area and the Ketchikan area. Power from Tyee would offset the current and projected increasing need for KPU to use diesel generation to meet load. 183MapsdepictingtheSTI®are included in Appendix A Maps. Project design based on revised criteria is nearly complete,however construction specifications and drawings are currently on hold pending additional funding. 83 Maps from the CAI STI Analysis -"Ketchikan-Swan Lake-Tyee-Petersburg,115/138 kV Transmission Line, Four Dam Poo!Power Agency,February 13,2006;and a detail showing the Tyee Lake Hydro Site nad Swan Lake Hydro Site and the STI. Hatch Acres Corporation PR324582.Rev.0,Page 138 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska 6.2.3.Construction Cost and Schedule Final Report To date,approximately $55 million has been spent of the estimated total construction cost of $110 million (2006 dollars).Work completed to date on the STI includes:USFS NEPA document and permits complete -permits expire in 2009;Line routing,line layout and design,and initiation of structure purchase;and right-or-way clearing and installation of a portion of the foundations. Completion of construction is on hold awaiting additional funding.The FDPPA has approximately $9.8 million in available funding for the project and has requested an appropriation in the amount of $46.2 million in the State of Alaska Budget. Tables 6.2-1 and 6.2-2 below provides a detailed cost estimate and schedule for the STI. Table 6.2-1 STI Construction Cost TASK NAME START DURATION |FINISH COST Tower Materials 10/02/07 |357 days |02/11/09 |$7,500,000 e Complete design 10/02/07 61 days 02/25/07 50,000 e Bidding 12/26/07 28 days 02/01/08 10,000 e Fabrication 02/04/08 |251 days |01/19/09 7,440,000 e Material delivery 1/22/09 15 days 02/11/09 0 Hardware Materials 11/01/07 143 days |05/19/08 $3,800,000 e Design 11/01/07 27 days 12/07/07 20,000 e Bidding 12/10/07 16 days 12/31/07 10,000 e Material Delivery 01/01/08 5 months 05/19/08 3,770,000 Substation Material &Assembly |12/07/07 |475.8 days |10/05/09 |$3,500,000 e Design 12/10/07 61 days 03/03/08 150,000 e Bidding 03/04/08 24 days 04/04/08 10,000 e Fabrication 04/07/08 |14 months |05/01/08 1,300,000 e Materia!delivery 05/04/09 0.54 months 05/1 8/09 0 Construction Mobilization 02/25/08 15 days 03/1/08 $1,000,000 Clearing 03/10/08 63 days 06/04/08 |$1,700,000 e General 03/10/08 48 days 05/14/08 700,000 e Klam Creek Reroute 03/31/08 48 days 06/04/08 1,000,000 Complete Foundations 06/05/08 88 days 10/06/08 |$9,000,000 ®Micropiles/anchors 06/05/08 48 days 08/11/08 6,000,000 e Pile caps 08/12/08 24 days 09/12/08 1,000,000 e Stove pipes 09/15/08 16 days 10/06/08 2,000,000 Tower Assembly 02/12/09 |110days |07/15/09 |$10,000,000®Receive and assemble |02/12/09 48 days 04/20/09 4,000,000 e Load barges 04/21/09 16 days 05/12/09 1,000,000 e Set towers 05/13/09 46 days 07/15/09 5,000,000 Conductor 09/01/09 46 days 11/03/09 |$10,000,000 e String wire 09/01/09 46 days 11/03/09 7,000,000 e Clipping 09/29/09 26 days 11/03/09 3,000,000 e Energize 10/30/09 3 days 11/03/09 AK-BC Alaska Final Report 18-09-07.Doc Hatch Acres Corporation PR324582.Rev.0,Page 139 BATU AGEN Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Online 11/03/09 0 days 11/03/09 0 Design,Inspect,Helicopter 10/02/07 |546days |11/03/09 |$3,000,000 Contingency 10/01/07 |557 days |11/03/09 |$7,500,000 TOTAL $57,000,000 Assuming that the State provides funding,the FDPPA would complete the STI on the following schedule. Table 6.2-2 STI Construction Schedule TIMEFRAME ACTIVITIES /ACTIONS 2007 -2008 Final design and construction documents;order towers 2008 -2009 Additional!ROW clearing and removal of danger trees and maintenance of ROW cleared in 2002-2004;install remaining foundations. 2009 Install towers and conductors,construct substation and transformers -complete construction in November 2009 -2010 Test and energize line 6.2.4 Annual O&M Costs 6.2.4.1 General The proposed O&M program for the STI line is similar in scope to the program implemented for the existing Swan®*and Tyee®transmission lines.While the STI Analysis presumes a stand-alone contract,economies of scale may be realized if a single O&M contract covering the three segments of line were to be awarded.Costs assume that O&M contracts will be multi-year (2 -3 years minimum)and that a two to three week line outage period will be available in the May through July period.The STI Analysis recommends and assumes that the work will be completed under three separate contracts to make maximum use of specialized labor,while at the same time use local expertise and labor to accomplish: e Facility inspection and maintenance e Thermographic inspection e Right-or-way maintenance and clearing. 6.2.4.2 Line Access Due to remote location and steep terrain,access is generally limited to helicopters.The STI Analysis assumes permanent landing sites along the line route will be developed during the construction phase to provide access to all structures within a one-half mile travel distance.These 84 FDPPA-owned line segment that connects generation at Swan to the KPU system in Ketchikan 85 FDPPA-owned line segment that connects generation at Tyee to the WML&P system in Wrangell and the PMP&L system in Petersburg Hatch Acres Corporation PR324582.Rev.0,Page 140 AK-BC Alaska Final Report 18-09-07.Doc nATGA AGE sites will be maintained for the life of the project.Portions of the ST!located near water may be accessed from an offshore barge. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 6.2.4.3 Facility Inspection and Maintenance Program Climbing Inspections -assumes inspection of 15 structure sites annually.Sites will be selected to include a minimum of one of each type.15-site rotation will result in all structure types inspected every year and all structures being climbed once every 20 years. Visual (on ground)Inspection -inspections of 40 structure sites each year,including minimum of one from each type.40-site rotation combined with climbing inspections ensures that all structure types will undergo inspection every 5 years.Inspections include correcting minor items that can be accessed from the ground and use of binoculars to inspect towers and appurtenances not accessible from ground. Helicopter Survey -assumes minimum of once each year conducted by an experienced lineman to include review of the conductor,insulators,structures,structure sites,helicopter landing sites,and right-or-way conditions. Maintenance materials -STI Analysis assumes sufficient spare materials for routine maintenance and any catastrophic failures that may occur be purchased and stockpiled. 6.2.4.4 Annual O&M Table 6.2-3 STI Estimated Annual O&M Costs (2006$)** ITEM YEARS 1-7 |YEARS 8+|5-YEAR PERIOD Maintenance Materials $20,000 Climbing Inspections $132,000 |$145,000 Visual (on ground)Inspection |$60,000 Helicopter Survey $15,000 Thermographic Survey (1)$18,000 Right-of-Way Clearing (2)$140,000 (1)ST Analysis states that this survey should be done prior to climbing inspections and every 5 years thereafter. (2)STt Analysis states that clearing cost starts In year 3 86 Information in these tables derived from the March 2006 Swan-Tyee Economic Analysis Prepared for the Four Dam Pool Power Agency by Commonwealth Associates,Inc.,dated March 2006. Hatch Acres Corporation PR324582.Rev.0,Page 141 AK-BC Alaska Final Report 18-09-07.Doc nATGH AGEN 6.2.4.5 Catastrophic Failures Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 6.2-4 STI Estimated Catastrophic Failure Costs (2006$) FAILURE TYPE COST RANGE -ASSUMPTION Long-Span Conductor Drop $250,000 -$400,000 A tl in 30-life oflissumesatleastoncein30-year life of line Assume in Year 15 -$325,000 Mudslide/Landslide/Avalanche $350,000 -$1,000,000 Assumes t 10-int Is starting in year5 .occurrence a year interva ing in y Assumption -$675,000 Tree Strikes $50,000 -$250,000 Assumes occ 4to6sumesoccurevery4to6 years Assumption-$150,000 6.2.5 Regulatory Considerations The Forest Service issued a Special Use Permit (SUP)to KPU on September 7,2001.Right of way timber was sold to KPU under a settlement agreement May 20,2002,and clearing began soon thereafter.Wood from the right of way was processed at the Silver Bay sawmill in Wrangell.In April 2004,KPU requested the Forest Service revoke its SUP and grant the FDPPA an SUP to construct the intertie.The Forest Service granted a SUP to the FDPPA in May 2004.This permit expires December 31,2009. 6.2.6 Map Maps depicting the Ketchikan -Swan Lake -Tyee -Petersburg 115/138 kV Transmission Line (Commonwealth Associates Inc,p 11,12)are included in Appendix A. 6.3.AK-BC Intertie The purpose of the proposed AK-BC Intertie is to interconnect with the proposed extension of the BCTC grid to Northwest British Columbia.This interconnection would provide access to export markets in British Columbia and the "Lower 48.”for sale of Alaskan-generated electric power. Electricity for export potentially includes production from existing projects surplus to the future needs of Southeast Alaska (e.g.surplus power currently available at Tyee);and production from development of new hydropower and renewable resource projects. The May 1,2006,Southeast Alaska Energy Export Report Final Report prepared by D Hittle & Associates Inc.(Hittle)for the Southeast Conference (SEC)(Energy Export Report)is one of two reports reviewed under this Contract .The Energy Export Report presents a reconnaissance level analysis of the proposed AK-BC Intertie based on the revenue that would be produced from power sales as compared to the costs of operation and maintenance of the infrastructure. The basis for preparing an economic analysis assumes that the cost of constructing the Alaska Segment of the AK-BC Intertie will be funded with federal or State grants.A yet-to-be determined Hatch Acres Corporation PR324582.Rev.0,Page 142 AK-BC Alaska Final Report 18-09-07.Doc HATCH AGRE regional organization would be responsible for O&M,replacements,and reconstruction in the event of catastrophic failure (see Section 2.2.2.1). Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report This Report presents an update to information presented in the Energy Export Report;identifies essential information not presently available;and presents a proposed plan to address outstanding issues and develop a next level pre-feasibility study during Phase II of this study. 6.3.1.Description of Proposed Corridor and Facilities AK-BC Intertie 6.3.1.1 Overview of Information Presented in the Energy Export Report The proposed Alaska AK-BC Intertie Segment from the Energy Export Report is a 26.5 mile transmission line from the existing Tyee Lake Project to the AK/BC border.The discussion of this segment only includes the Alaska portion of the AK-BC Intertie.A brief description of the BC segment is provided in Section 6.3.2.3. Access to construct and conduct O&M for the lower segments may be accomplished from an offshore barge using existing logging roads;helicopters will be required to access upper segments. The proposed line would be comprised of single wood poles for typical structures with A-frame structures utilized to support long spans;single circuit 138-kV®'line operated at 69-kV until increase in load requires changing operation of the existing Tyee Grid "to 138 kV. Designed to allow export of approximately 105 MW.®The final selection of the conductor for the line would be dependent on the "expected power flow requirement”. Location of line segments and general description as identified in the Energy Export Report are provided Table 6.3-1 below. Table 6.3-1 AK-BC Intertie Segments -Location and Length SEGMENT /LENGTH NOTES LOCATION (MILES) A.Tyee Lake 2.2 Parallels an existing road switchyard to Bradfield Below 100 foot elevation River East Fork Has been clear-cut logged in past -Alder B.Crossing of East 11.6 Located near river bottom above flood stage 87 "The export of energy via the Bradfield Intertie was studied as a 69-kV and 138-kV line.A 230-kV line was discounted early in this study as there is no plan for a grid on either side of the border in the near future to support such a consideration.However,BCTC has recently completed a study evaluating system transfer capabilities on the Canadian side of the border if a 287-kV transmission line were constructed.If sucha voltage were to be a serious consideration in BC,it would be necessary to reconsider the voltage on the Alaska side of the border.”Energy Export Study Final Report at page 2-7. 88 FDPPA-owned line segment that transmits power from Tyee Lake Project to Wrangell and Petersburg.The power flow from Tyee to Wrangell &Petersburg is via an existing 69-kV /138-kV overhead transmission line with 138-kV submarine cable crossings.The step-down transformers at Petersburg and Wrangell are dual rated on the high side for 69-kV /138-kV.There are no current plans to upgrade this existing line from 69-kV to 138-kV operation.(Energy Export Study Final Report at page 2-6) 8?Energy Export Study Final Report at page 2-7. Hatch Acres Corporation PR324582.Rev.0,Page 143 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGEN Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report SEGMENT /LENGTH NOTES LOCATION (MILES) Fork Bradfield River to Abandoned logging roads could be re-established crossing of North Fork Has been clear-cut -Alder &Hemlock Bradfield River Hillside -danger trees Low altitude construction C.Crossing of North 4.7 High altitude construction Fork Bradfield River to Helicopter access -No evidence of logging or roads confluence of E &W Moderate rugged branches of river Dense spruce headwaters.Challenges for construction -steep valley slopes and granitic rock;some glacial till D.East branch of 3.3 Climbs from 800 to 2,600 feet elevation Bradfield River Exposed slopes vulnerable to possible avalanche,granitic rock, headwaters.Crosses some shallow glacial till. pass between Bradfield Helicopter access to construct &Craig River Valleys Sparsely forested E,Extends from pass 4.7 Helicopter access from Alaska unless access can be provided between Bradfield and from Forrest Kerr area on the Canadian side of the border. Craig River Valleys Side slopes,ridges,or small areas of land jutting into river along Craig River to bottom AK/BC border Some high altitude construction Sparse to dense Spruce 6.3.1.2 |Review of Proposed Corridor and Facilities and Recommendations for Further Investigation The proposed corridor of the existing Energy Export Study is based upon previous transmission and road studies,and recommends a corridor similar to a 1986 proposed road alignment”and the route proposed by Bradfield Electric,Inc,in1988 for the Johnny Mountain 69 kV Transmission Line®'. At our current level of analysis,a review of the proposed corridor shows this to be a reasonable route selection.As the project moves forward into design,additional reconnaissance and surveying would be required to refine the route selection in certain areas,such as alignment along the north fork river valley,and the routing through the pass between the north fork of the Bradfield River and the Craig River. The route description provided in the Energy Export Study notes that in the section along the North Fork Bradfield between the crossing of the East Fork Bradfield and the crossing of the North Fork Bradfield there are existing logging roads in the area;it indicates that these roads may be restored and utilized to provide access for construction of the AK-BC Intertie in that area.The Export Study »°Energy Export Study Report,pages 2-2 through 2-4. *"Proposed Johnny Mountain Transmission Line,Project Concept Summary,August 26,1988.Presidential Permit PP-87 Authorizing Bradfield Electric,Inc.,and the Alaska Power Authority to construct and operate facilities,May 8,1988 Hatch Acres Corporation PR324582.Rev.0,Page 144 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report notes that the alignment in this section is generally located at the foot of the eastern slope.??Our recommendation would be to locate this line in the river bottom far enough away from the foot of the slope to mitigate the potential impacts of landslides and avalanches on the line.Additional research and reconnaissance will need to be performed in order to determine if the proximity of the old logging roads to the selected alignment along the river valley bottom will make them feasible for use in construction access of the line.Without this reconnaissance,our best estimate is that this section of the line will need to be constructed using helicopter access like the northern sections of the line. Although the existing study utilizes single pole structures,we have selected wood pole H-frame structures as they allow for longer spans that are typically desired for remote transmission lines in inaccessible terrain.These structures could be installed using culvert caisson type foundations as indicated in the Energy Export Study. The Energy Report Study considers several options for conductors and voltage levels from 69 kV to 138 kV,from 336 ACSR to 954 ACSR.It recommends that the line be constructed at 138 kV and operated at 69 kV until load demands necessitate the upgrade to 138 kV,matching the existing Tyee Grid.®It further goes on to select 556 ACSR conductor as the preferred alternative. We have assumed that the AK-BC Intertie would be constructed and operated at 138 kV.We have utilized the 556 ACSR conductor that the Energy Export Study recommends as the preferred alternative.Additional load flow analysis should be performed to determine if this conductor and voltage selection is adequate to serve the expected energy to be exported via this intertie. 6.3.2 Construction Cost and Schedule 6.3.2.1 Overview of Information Presented in the Energy Export Report The cost estimate provided in the Energy Export Report represents a preliminary reconnaissance level analysis and is based on the assumption that the line from Tyee to the AK/BC border would transmit approximately 105 MW of exported power and therefore would not exceed the capacity of a 138 kV line.A 230 kV line was discounted early in the study as "there is no plan for a grid on either side of the border in the near future to support such a consideration.”®The Energy Export Study anticipated interconnecting with a 138 kV line to be constructed by Coast Mountain”.Costs were based on recent construction of 138 kV transmission infrastructure”. The Energy Export Report includes a cost estimate of $26.8 million (2006 dollars),based on construction of a 138 kV line limited to transmit approximately 105 MW of exported power from Tyee Lake to the AK/BC border.The cost estimate does not include consideration of the potential 180 -310 MW that could be exported from identified Alaskan projects. *Energy Export Study Report,page 2-4. %3 Energy Export Study Report,page 2-7 %Energy Export Study Report,page 4-2. %Energy Export Study Report at page 2-7. ©Coast Mountain was acquired by NovaGold in 2006. 7 The Energy Export Report does not include detailed supporting information Hatch Acres Corporation PR324582.Rev.0,Page 145 AK-BC Alaska Final Report 18-09-07.Doc HATCH AGRE Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report A table presenting details regarding the estimated cost of construction for the preferred alternative investigated in the Energy Export Report is presented in Appendix E,Table E-1 "AK-BC Intertie Segment -Estimated Cost of Construction”(Energy Export Report). The Energy Export Report does not include a proposed construction schedule. 6.3.2.2 Update Cost Estimate and Schedule Assumptions Employed in Developing Updated Cost Estimate and Schedule Our development of an updated cost estimate and schedule is based upon our estimate of the material quantities and labor to construct the line,utilizing the rough conceptual design that we have selected.Our costs for materials,labor,and other indirect costs of the construction are based upon our own experience in construction in Southeast Alaska.It also includes information gathered with discussions with other individuals familiar with various aspects of high voltage electric facilities,from design to construction,and from transmission lines to substations and switchyards. We have assumed that the AK-BC Intertie will be constructed as a 138 kV line,using 556 ASCR conductor.Our conceptual design utilizes wood H-frame structures,with span lengths averaging approximately 750 feet.Shorter spans would be utilized in the higher elevation areas where heavier loadings on the structures are expected.Foundations would be culvert caisson type foundations with wood poles directly embedded in the culverts;in higher elevations areas outside of the river valleys,the poles could be direct embedded without the use of the culvert caisson. The estimate includes adding an additional transformer with associated breakers and switches at the existing Tyee switchyard.The transformer size we have selected is a 30 MVA transformer,sized to accommodate the generated power of the Tyee Project.We have assumed that any additional power that would be transmitted through the AK-BC Intertie would be sourced from the Tyee transmission line or Swan-Tyee Intertie,and these lines would be operating at 138 kV,therefore not requiring additional transformation. Although the route selected in the Energy Export Study notes that the existing logging roads could be utilized for access through the first 13.8 miles of construction,without more detailed reconnaissance of the condition of the existing logging roads and determination of their proximity to the new AK-BC Intertie route,it is difficult to confidently assume that the effort involved in utilizing those roads would be more cost effective than helicopter construction.Therefore we have assumed that the line will be entirely constructed utilizing helicopter access,with the exception of the first 2.2 miles that the Export Study states generally parallels an existing road.Our estimate therefore includes a line item for the additional cost of helicopter construction. Clearing costs are based upon using helicopter access rather the old logging roads for clearing,and includes the assumption that felled timber will not need to be hauled off the right-of-way,except for the first mile back from tidewater. Our estimate also includes a 20%factor for indirect costs such as engineering and design, surveying,and permitting,and a 30%contingency factor.As project design commences and the design becomes more detailed,this contingency factor could probably be reduced. Hatch Acres Corporation PR324582.Rev.0,Page 146 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES Update to Cost Estimate Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The cost estimate from the Energy Export Study is based upon the use of single pole structures instead of H-frame structures for typical spans.From the breakdown provided,it is difficult to determine how the estimate accounts for items such as helicopter access and weather difficulties that are a factor in transmission line construction in Southeast Alaska.Therefore we have developed a revised cost estimate that is based upon the conceptual!design that we have selected, shown below. Table 6.3-2 Estimated Cost of AK-BC Intertie -Tyee Lake to Border Tine tem ga Transmission Structures (H-Structures)==$_ -2,800,000 Insulators and Hardware "$600,000 Guys and Anchors $$)900,000 Conductor -oo OO "$--2,500,000 Foundations rr Se 3,200,000WeatherDays-$-_200,000Miscellaneous_"$500,000 Subtotal.$10,700,000 Mob/Demob oO :$1,000,000Clearing; $2,600,000 Helicoptor/Access Costs $5,700,000 Tyee Switchyard/Substation =+$800,000 Communications 'Systems _nS «B00,000 'Subtotal $21,300,000 Indirect Costs (Permitting,Engineering,etc)(20%)$4,260,000 Contingency (30%)$6,390,000 Total $31,950,000 Estimated Development Schedule The proposed schedule for construction of the AK-BC Intertie will be highly dependent on a decision by the British Columbia government,anticipated in 2007,to construct a new 287-kV transmission segment that will extend the existing BCTC transmission system north from Skeena to a proposed substation at Bob Quinn,the proposed Northwest Transmission Line (NTL).For purposes of this discussion,we use an in-service date of 2010 for completion of the segment to Bob Quinn. Hatch Acres Corporation PR324582.Rev.0,Page 147 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Notwithstanding this uncertainty,tasks necessary to develop a realistic proposed development schedule would include: e Decision by State of Alaska to proceed with development of the AK-BC Intertie to the Border e Consultations with BCTC and other entities in BC regarding timing of development of line from the new substation at Bob Quinn Lake to the AK/BC Border e Consultations with BCTC and other entities in BC regarding the facilities at the border to interconnect the AK-BC Intertie to the BCTC line from the border to Bob Quinn substation, Following achievement of the above tasks,the anticipated activities and timeframe for developing the proposed 26-mile 138 kV AK-BC Intertie segment within Alaska and the potential 30-mile segment in BC from the border to Forrest Kerr would include: Proposed AK-BC Intertie ACTIVITY POTENTIAL TIMEFRAME Permitting 18 -24 months Design &Material Procurement 12 months Construction 12 months Proposed Within BC Transmission Line -Forrest Kerr to AK/BC Border ACTIVITY POTENTIAL TIMEFRAME Permitting 18 -24 months Design &Material Procurement 12 months Construction 12 months 6.3.2.3 British Columbia Segment Our cost estimate for the AK-BC Intertie stops at the AK-BC border and does not contain any line item for transmission line construction of the British Columbia side of the Intertie from the AK-BC border to the Forrest Kerr Project,not does it include any switchyard upgrade or transformer installation at the Forrest Kerr Project.The Energy Export Study does provide a rough estimate of construction cost of the transmission line through British Columbia as 17.4 million (in U.S.dollars) based upon information obtained from Canadian contractors and CMP. The route of the British Columbia segment of the AK-BC Intertie will roughly follow the Craig River Valley and Iskut River Valley to the Forrest Kerr Project.Based upon available maps and other information,our estimate of the length of the segment from the AK-BC border to Forrest Kerr is approximately 30 miles.Since the remoteness and terrain for this portion of the line is similar to 8 Energy Export Study Report at page 4-3. Hatch Acres Corporation PR324582.Rev.0,Page 148 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES the Alaskan side,we assume that it will also need to be constructed using similar concepts and methodology.If we extrapolate our estimate for the Alaska portion of the AK-BC Intertie to the approximate length of the British Columbia segment of the Intertie,the rough order of magnitude cost of this segment is estimated at 36 million dollars (U.S.). Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 6.3.3 Annual O&M Costs 6.3.3.1 Overview of O&M Costs Presented in the Energy Export Report The proposed O&M program for the Alaska Segment of the AK-BC Intertie is similar in scope to the ongoing program on the existing Swan-Ketchikan and Tyee-Wrangell/Petersburg transmission lines owned and operated by the FDPPA. Access to the upper segments of the line is a major cost item due to the extent of helicopter access. Permanent helicopter landing sites are proposed to be developed along the line route during the construction phase.The lower segments are assumed to be accessed from an offshore barge and logging roads. The projected annual O&M cost estimate in 2006 dollars is approximately $318,850 for the first year and $281,000 for years where activities are for routine inspections,ROW clearing,and regular repairs.In years when catastrophic failures are predicted to occur,projected annual O&M costs plus catastrophic failure costs range from $419,250 to $694,250. The estimate assumes a stand-alone O&M contract.Catastrophic failures were predicted to occur at 5 year intervals.The following tables present a summary of information presented in the Energy Export Report”. °°Energy Export Report,Table 4-3 Bradfield Intertie Estimated Costs of Operation and Maintenance. Hatch Acres Corporation PR324582.Rev.O,Page 149 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGES Table 6.3-3 Summary of AK-BC Intertie Estimated O&M Costs Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Annually Years 1,5,10,15, Annual O&M -Item Year 1 Years 1-30 20,25 &30 Visual/Climbing Inspections $161,250 Spare Materials $10,000 First Year Helicopter Survey -All $19,600 Towers Thermographic Survey $18,000 Right-of-Way Clearing $120,000 Years 10 and Catastrophic Failure -Item Years 5,15,and 25 20 Year 30 Long-Span Conductor Drop $125,000 Landslide/Avalanche $275,000 Tree Strike $110,000 $110,000 $100,000 6.3.3.2 |Review and Update to the Energy Export Study O&M costs The information presented in the Energy Export Study for O&M is based upon programs that have been implemented on the Swan'™and Tyee™'transmission lines,which have similar construction types and remoteness of location.The activities proposed for O&M include clearing,helicopter survey,ground and climbing inspections,and catastrophic failure repair.The O&M program described in the Energy Export Study is well developed;although we have modified the line construction concept,we believe that the O&M methodology and schedule will apply equally well to the conceptual line design that we have utilized.The number of structure climbing and visual inspections called for in the Energy Export Study would equate to climbing each structure every 20 years,and a visual ground inspection of each structure every 5 years.Although the Energy Export Study indicates that structures in the southern portion of the line could be accessed via the logging roads and barges,we anticipate that this will not be the case,and the majority of the O&M work will need to be performed with helicopter access.As noted in the Energy Export Study,helicopter sites will need to be established during construction for use in O&M activities. The average annual cost of the O&M program outlined in the Energy Export Report is approximately $350,000 annually in 2006 dollars,and we believe that this cost is as accurate as possible when forecasting O&M costs,and falls within the one to two percent of construction costs 109 "Swan”refers to the FDPPA line between the Swan Lake Project and KPU's system 101 "Tyee”refers to the FDPPA line from the Tyee Lake Project to delivery points in Wrangell and Petersburg. Hatch Acres Corporation PR324582.Rev.0,Page 150 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES 6.3.4 Wheeling Tariff Costs Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The wheeling tariff will be established through a proceeding either at the RCA or the FERC depending on whether Interstate Commerce results from the AK-BC Intertie.Please see a discussion regarding potential jurisdiction over the line segment in Section 5.2.1.Determination of the regulatory structure and related cost of the wheeling tariff requires legal assistance and will be developed during Phase II of this study. 6.3.5 Regulatory Approval Costs and Schedule The AK-BC Intertie would be constructed on !ands within the Tongass National Forest managed by the US Forest Service thereby requiring federal approval to site,construct,and operate proposed facilities.Because the AK-BC Intertie is located on lands of the US and requires federal permits and other approvals,an Environmental Assessment (EA)and/or an Environmental Impact Statement (EIS) will be prepared under the requirements of the National Environmental Policy Act (NEPA).The EA/EIS will include information necessary to support the Special Use Authorization (SUA)required to occupy federal lands,the Presidential Permit and Export Authorization required to export energy across an international border,and a number of other permits and approvals required to site, construct,and operate the proposed transmission line. A detailed discussion of the regulatory process and required permits and approvals is provided in Section 5.3 Permitting and Related Approvals -Transmission.Major approvals and related estimates regarding schedule and cost are listed in the following table. Hatch Acres Corporation PR324582.Rev.O,Page 151 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGEN Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 6.3-4 Regulatory Approvals,Schedule and Cost REQUIRED JURISDICTIONAL SCHEDULE COST PERMITS &APPROVALS AGENCY NEPA Process including consultation with Lead Agencies:18 months -2.|NEPA EA/EIS agencies with jurisdiction over resources US Forest Service (USFS);|years $500,000 - affected by construction and operation of US Department of Energy $1.5 million the AK-BC Intertie;and preparation of an EA |(USDOE);and cooperating (+or-) and/or EIS.agencies' Presidential Permit USDOE During NEPA Filing fee - Secretary of State Dept.process $150 Secretary of Defense Dept. Export Authorization USDOE During NEPA process National Energy Board Permit (CA)CA National Energy Board |60 days post filing application Special Use Authorization USFS During NEPA Processing fee process TBD Annual Charge to occupy US lands USFS Annual 5%of payment'"™estimated land value CWA Section 404 Permit -dredge &fill COE During NEPA Processing fee Nationwide Permit process TBD CWA NPDES Permit COE /EPA Required at Processing fee start of TBD construction CWA Section 401 Certificate of Reasonable |ADEC During NEPA NA Assurance to comply with State Water process Quality Standards CZMA/ACMP Office of Project During NEPA NA Coastal Project Questionnaire and Management and process Certification Statement Permitting in ADNR ESA Biological Assessment FWS and/or NMFS During NEPA NA process Historic Properties Management Plan USFS &SHPO During NEPA NA process State permits to construct in and/or cross ADFG During NEPA NA streams process Fish and Wildlife Protection Plans FWS and/or NMFS &During NEPA NA ADFG and/or ADNR process 6.3.6 Map A map depicting the AK-BC Proposed Route is include in Appendix A. '2 Cooperating agencies may include:US Army Corps of Engineers and US Fish and Wildlife Service '03 Annual payment begins when construction period starts and continues through life of the transmission line. Hatch Acres Corporation AK-BC Alaska Final Report 18-09-07.Doc PR324582.Rev.0,Page 152 WATCH ACRES 6.4 Other Potential Segments Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Information presented in this section of the Report is provided to give the reader a snapshot view of other potential segments that could be developed in the future.The scope of the Contract with AEA for this study does not include an in-depth review of these segments.Should the proposed AK-BC Intertie proceed,these other potential segments would need to be investigated further. 6.4.1.Thomas Bay Transmission The purpose of this future segment of transmission would be to connect the three potential hydro projects at Thomas Bay to the Petersburg substation,tying these sources into the Tyee transmission system.There are three potential projects located in Thomas Bay:Cascade Creek,Scenery Creek, and Ruth Lake.This transmission line would originate at the power house of the closest project, the Cascade Creek powerhouse and substation,located near tidewater.It is assumed that the other projects would include infrastructure to connect and transmit their generated energy to the substation at Cascade Creek.Any substations associated with these power plants,including the Cascade Creek plant,are assumed to be included in the costs for the power plants.We are basing our estimate on the route proposed in the Thomas Bay Hydroelectric Project,Pre-Feasibility Assessment Report prepared in 1985 by Hosey &Associates.'"**This route may not be the best or least costly,but without actual field reconnaissance and more specific data it was considered to represent the best information available and was used in this analysis.A routing that avoids all or part of Kupreanof Island and a single submarine cable may be more economical,but was not investigated. The route proposed in the Hosey report has 6 basic segments.The first segment consists of the submarine cable crossing of Thomas Bay,and is approximately 3 miles in length.The next segment is an overhead portion that crosses the Agassiz Peninsula from Thomas Bay to Frederick Sound.This segment is approximately 3.5 miles.From there,another submarine cable segment of approximately 3.5 miles would cross Frederick Sound to Kupreanof Island.The fourth segment would be an overhead line along the east coast of Kupreanof Island to the Wrangell Narrows;this segment is approximately 6.5 miles.The next segment would be another submarine crossing,this one of approximately 2.5 miles,crossing the entrance of the Wrangell Narrows to land southwest of Petersburg.The last segment would be an overhead line of approximately 3 miles from the submarine cable landing point to the Petersburg Substation.This transmission line would have a total length of approximately 22 miles,9 miles of submarine cable crossings and 13 miles of overhead line.'® Both submarine and overhead portions of this transmission line would be constructed at 138 kV to match the Tyee Project transmission line.The cable and conductor would be sized to transmit the potential generation capability of the Thomas Bay projects.The route that was selected (i.e.based on the Hosey report)is currently at the feasibility level for the purposes of cost estimation and has not been thoroughly reviewed for the purposes of route finalization or constructability. '04 Thomas Bay Hydroelectric Project Pre-Feasibility Assessment Report,Page V-3 105 All distances stated here are scaled from the Vicinity Map of the Thomas Bay Hydroelectric Project Pre- Feasibility Assessment Report,Exhibit V-1. Hatch Acres Corporation PR324582.Rev.O,Page 153 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACHES The estimated cost for connection of the Thomas Bay hydro projects to the Tyee Lake transmission line was developed as part of this study as described below.We estimate submarine cable costs to be approximately $5,000,000 per mile,based upon utilizing 4 single conductor cables with three cables in use and one spare.Submarine cable costs tend to fluctuate with the bidding climate,the actual costs for these crossings could vary greatly depending on the market at the time of installation.We also have estimated the cost of the overhead segments to be approximately $600,000 per mile.Multiplying these costs times the length of the line and adding in a 25% contingency factor gives a rough estimate of the cost of the Thomas Bay Transmission Line of $66 million dollars. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 6.4.2 Petersburg to Kake The proposed Kake-Petersburg Transmission Line ("KPTL”)would interconnect the community of Kake on Kupreanof Island to the interconnected electric systems of Petersburg and Wrangell. Petersburg and Wrangell are connected to and purchase most of their respective power supplies from the Lake Tyee hydroelectric project owned by the FDPPA.The KPTL will be used to transmit surplus hydroelectric power purchased from the FDPPA to IPEC's electric system in Kake,thereby offsetting diesel generation in Kake.'*° As with other proposed segments of the SE Alaska Intertie System,the capital costs are expected to be mostly grant funded.The annual costs of operating and maintaining the KPTL as well as funding a reserve for long-term renewals and replacements is to be borne by the users of the KPTL. Several routes were investigated in the KPTL Intertie Study Final Report,July 2005'°”.The Report also considered a future connection to a proposed mining facility on Woewodski Island.Future transmission interconnection could also accommodate estimated power loadings between Kake and Sitka. The Center-South Alternative'™®was selected as the preferred alternative: e 51.7 miles total length e Two marine crossings totalling 1.6 miles e Forest Service roads exist along the majority of the proposed route.Construction adjacent to these roads should provide for lower costs of construction and maintenance e Single wood pole structures e Recommended voltage is 69 kV. The estimated cost of developing and constructing the KPTL,including all direct and indirect costs, is stated in the KPTL Report at $30.3 million for the Center-South Alternative.The estimated cost to 1 Kake-Petersburg Intertie Study,Final Report,Prepared for the Southeast conference by D Hittle & Associates,July 2005 (Kake-Petersburg Intertie Study,July 2005) 1°”Ibid '8 This route was defined in previous studies as the Southern Alternative and is also referred to as the Tonka- Duncan Canal!route. Hatch Acres Corporation PR324582.Rev.0,Page 154 AK-BC Alaska Final Report 18-09-07.Doc nT ACHES construct the connection to Woewodski Island if the future mining operation goes forward is estimated at $8.3 million.'” Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The Kake-Peterburg Intertie Study construction concept is based upon utilizing road access to construct the entire overhead portion of the line.The report proposes to utilize existing forest service roads for most of the length of the project,however there are approximately 13 miles of access road that will need to be constructed.The costs developed for transmission line construction and O&M are dependant on utilization of that access road,and we find the costs indicated for the overhead transmission line construction portion of the center-south route are consistent with typical costs for this method of construction.However,the cost of this access road is included in the project cost and is a significant portion;variations in the actual cost of that access road construction will significantly impact the total project cost. 6.4.3 Metlakatla to Ketchikan The potential to construct a line from Metlakatla to Ketchikan was briefly discussed during the December 29,2006,meeting in Ketchikan.To date no detailed information has been provided. Metlakatla is located on Annette Island approximately 15 miles southwest of Ketchikan within the Annette Islands Indian Reservation.An interconnection was identified in the Southeast Alaska Intertie Study prepared in 1987 for the Alaska Power Authority.The line was described as a 15- mile 34.5 kV line with 14 miles of overhead line and 1 mile of submarine cable connecting KPU's Mountain Point Substation with Metlakatla's Race Point Substation.Estimated cost in 2007 dollars would be $14,900,000.''° 6.4.4 6.4.4 Other Transmission Segments In addition to the segments listed above,two other segments were proposed for connecting potential generation sources to the interconnected transmission system for the purposes of exporting surplus power.These two segments are a connection from Kake to a future generation site at Takatz Lake on Baranoff Island,and a connection from Coffman Cove on Prince of Wales Island to the Tyee transmission line near Wrangell.There are not currently any studies or proposed routes for these segments.For inclusion in this study,we have developed very rough order of magnitude costs for these segments,using assumed submarine routes.Those costs are included in table 6.1-2. 6.5 Load Flow Studies in SE Alaska Load flow studies were carried out for peak load conditions in the years 2011,2021 and 2031 for the SE Alaska system for the least cost without exports development scenario as described in Section 8 and for the year 2021 for the least cost with exports scenario.The objective of these studies was to provide information on the loading of individual transmission circuits,allow the reactive power balances to be correctly adjusted,identify any additional reactive compensation 109 Kake-Petersburg Intertie Study,July 2005 "9 Cost cited in the1987 Southeast Alaska Intertie Study was $8,785,000.Cost was escalated using the Bureau of Reclamation Cost Trend Tables. Hatch Acres Corporation PR324582.Rev.0,Page 155 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report equipment that would be required,determine the loading levels of each major substation and provide voltage profiles for the system. The load flow results also provide an indication of the transmission losses under the expected generation dispatch for each of these development scenarios in the years indicated. It should be noted that as detailed studies have not been carried out for most of the potential new transmission lines there is incomplete information available on the characteristics and parameters of these lines.In view of this,all the new transmission lines were assumed to use Dove conductor. The transmission capability of 138 kV,69 kV and 34 kV transmission lines was assumed to be 130 MVA,65 MVA and 34 MVA,respectively.All the new transformers were assumed to have an impedance of 8%. 6.5.1 New Transmission and Generation Facilities As of 2007 the study area includes the three isolated regions as described in Section 8:Tyee,Swan and Prince of Wales Island.Within these regions there are several load centers that are isolated from each other.Due to geography and the expected level of demand,it is unlikely that Prince of Wales Island will be connected with the other two regions during the planning period and thus this region was not considered in the load flow analysis. The principal load centers studied include: e Kake in the Tyee region and presently isolated from the other centers e Petersburg and Wrangell supplied from local hydro and diesel plants and the Tyee Lake hydro plant via a transmission line designed and built at the 138 kV voltage level but operated at 69 kV e Ketchikan,supplied from local hydro generation,local diesel and from the Swan Lake hydro plant via a 115 kV transmission line and 34 kV lines from the local hydro generation e Metlakatla,supplied from local hydro generation and local diesel generation. The analysis of Section 8 indicates that the operation and maintenance costs of the transmission lines to connect the above load centers could be recovered from the operating savings that these connections could bring.Thus for purposes of the load flow studies it is assumed that these lines will be in service by 2011 and all the above load centers will be connected to form a single system. It is considered that by 2011 some load transformers will need to be reinforced due to the load growth.Including these new transformers the new generation and transmission facilities that would be expected to be in-service by 201 lare as follows: e Whitman Lake Hydro plant -4.6 MW e Petersburg -Kake 69 kV line (58 miles) e Tyee Lake -Swan Lake 138 kV line (57 miles,operating at 69 kV) e Ketchikan -Metlakatla 34 kV line (15 miles) e Whitman -Ketchikan 34 kV line (6 miles,generation connection for Whitman Lake hydro plant) Hatch Acres Corporation PR324582.Rev.0,Page 156 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES e Mahoney Lake hydro plant -9.6 MW e 138/115/69 kV,50 MVA,three winding transformer at Swan Lake e 2nd 115/34 kV,20 MVA,Transformer at Bailey e 2nd 34/4.16 kV,10 MVA,Transformer at Bethe e 2nd 34/12.47 kV,5 MVA,Transformer at Port West e 2nd 34/12.47 kV,5 MVA,Transformer at North Point e 5 MVAR Shunt capacitor at North Point. It should be noted that Section 8 mentions that the connection between Ketchikan and Metlakatla should be in place by 2013 and the parameters above consider it to be in place by 2011.The earlier date used in this section was selected in order to verify network performance with the connection at an early in-service date. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The high voltage transformers shown above are included in the capita!cost for the STl and the lower voltage transformers required in the Ketchikan area for power distribution,are common to all alternatives and their costs should be taken into account by the distribution entity in Ketchikan. The 5 MVAR shunt capacitor at North Point is also considered part of the distribution network costs. It was envisaged that by 2021,the Swan Lake -Tyee Lake -Wrangell -Petersburg transmission lines would be switched to the 138 kV voltage level and the following additional generation and transmission facilities would be in place: e Connell Hydro plant -1.7 MW e Carlanna Hydro plant -0.8 MW e Generation connections (34 kV lines)for Connell and Carlanna hydro plants e 138/69 kV,20 MVA,transformer at Petersburg e 15 MVAR shunt reactor at Petersburg (15 MVAR of shunt reactors are needed for minimum load conditions). The cost associated with the 15 MVAR shunt reactor was not taken into account explicitly in the cost estimate for the overall project but is considered to be part of the contingency allowances. For the development scenario that would provide for exports to the British Columbia border,a 26.5 mile transmission line between the Tyee hydro plant and BC operating at 138 kV would be required.Under the power export scenario,the following additional generation and transmission installations would be required: e Cascade Creek Hydro plant -45 MW e Scenery Lake Hydro plant -30 MW e 138 kV generation connection circuit from Cascade Creek to Petersburg comprised of a mix of overhead line (13 miles)and submarine cable (9 miles) e 138 kV Tyee Hydro Plant -BC border single circuit line (27 miles) Hatch Acres Corporation PR324582.Rev.0,Page 157 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES e A25 MVAR switched shunt capacitor at the BC border (This compensation is required under current simplified modeling;it may not be necessary or its size may be reduced depending on the way in which this circuit is connected to the BC transmission system). Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report It appears that some sections of the Petersburg to Wrangell transmission line use the 37#8 Alumoweld conductor.The thermal current carrying capability for this conductor depends upon several factors including ambient temperature and final conductor temperature.For an ambient temperature of 75 F and a final conductor temperature of 195 F,the current carrying capability of the 37#8 Alumoweld conductor would be approximately 90 MVA and since only two Thomas Bay projects are considered to be developed within the timeframe studied,it is considered that there would be no need to reconductor line sections between Petersburg and Wrangell. By 2031 for the scenario without exports,the following new generation and transmission facilities would be in place: e Triangle Hydro plant -3.5 MW e 34 kV generation connection circuit for Triangle (2 miles) e Upgrading of the existing Port West -Ketchikan 34 kV transmission circuit from 6.2 MVA to 34 MVA e 2nd 34/12.47 kV,5 MVA,transformer at Wards Cove. It should be noted that some of the distances used to connect future hydro plants in the Swan region to the respective load centers are approximate as no information on the exact plant locations was available. 6.5.2 Load Flow for Year 2011 A load flow analysis was carried out for the peak demand conditions of 2011 assuming maximum hydro dispatch.In this case,the peak demand was about 55 MW.Most of diesel units are not in service.In view of the limited energy production capability of the Swan Lake hydroelectric plant (capacity factor of 37%under average hydrological conditions)the plant's generation was taken as 13 MW and in order to balance the system total demand and generation resources it was decided to bring on line two diesel units at Petersburg (2x2.3 MW).Should the dispatch from Swan Lake be greater,then the output from the Petersburg diesel units would be decreased. The load flow results are presented Figure 6.5-1 in at the end of this section and major observations include: e All the system voltages are within normal operating ranges e No overloading is observed.The loading for most major circuits is less than 50%of Capacity e There are no large angular differences between adjacent buses,there is a 7 degree difference between Tyee Lake and Swan Lake e With the Tyee Lake -Swan Lake connection,about 12 MW of power is supplied from Tyee Lake to Swan Lake.This would change with a different dispatch Hatch Acres Corporation PR324582.Rev.0,Page 158 AK-BC Alaska Final Report 18-09-07,Doc HATCH ACRES e Total transmission and distribution losses are 2.4 MW,accounting for 4%of total operating generation. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 6.5.3 Load Flow for Year 2021 The peak demand in 2021 is forecast to be 66 MW,20%higher than in 2011.The transmission lines from Tyee Lake were assumed to be operating at 138 kV.The hydro dispatch has been maximized and the diesels at Petersburg were in operation to supply local loads in order to balance the system total demand and generation resources. The load flow results are presented in Figure 6.5-2 at the end of this section and major observations include: e With adequate control by generators,transformers and shunt reactors the system voltage profile is satisfactory e The 138 kV transmission lines are lightly loaded,no overloading is observed e Tyee Lake is supplying about 10 MW to Swan Lake via the 138 kV transmission line e Total transmission losses are 2 MW which is slightly less than those in 2011 and this reduction is due to the higher operating voltage on the Swan Lake -Lake Tyee -Wrangell -Petersburg transmission line. 6.5.4 Load Flow for Year 2021 with Exports For the export case it was considered that two new hydro plants,Cascade Creek and Scenery Lake would be in-service and that about 75 MW would need to be delivered to the BC border for export. The generation considered assumed maximum hydro generation at most buses and no diesel generation. The load flow results are presented in Figure 6.5-3 at the end of this section and major observations include: e No voltage violations are observed e Loading of the138 kV transmission lines is greater than in the case without exports. However,no circuits are overloaded e Export to British Columbia (75 MW)is mainly is supplied from new hydro units at Cascade Creek and Scenery Lake e Total transmission losses are 7.8 MW,about 5.2%of total operating generation.Thus the incremental loss associated with the export sale is approximately 5.8 MW. 6.5.5 Load Flow for Year 2031 without Exports A load flow study was carried out for peak demand conditions in 2031 which reached 74 MW or an increase of 12 %when compared to 2021.For this load flow,maximum hydro generation was used. Hatch Acres Corporation PR324582.Rev.O,Page 159 AK-BC Alaska Final Report 18-09-07.Doc HATH ACRES e The load flow results are presented in Figure 6.5-4 at the end of this section and major observations include: Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report o Satisfactory system operation with all voltages within reasonable levels and all loadings within accepted values o Relatively small angular differences between adjacent buses and this is a result of the switchover from 69 kV operation to 138 kV operation of some of the transmission lines o Total transmission losses are 2.3 MW,representing about 3%of total generation. 6.5.6 Conclusions The load flow studies indicate that,once the STI is in place,it will be feasible to operate in a connected way the load centers from Kake to Metlakatla. Due to load growth,additional step down transformers and re-conductoring of low voltage feeders is required.Depending on the load's power factor,a 5 MVAR shunt capacitor bank is likely to be required at North Point. With the switching of the transmission voltage of the Petersburg -Wrangell -Tyee -Swan line from 69 kV to 138 kV,a 15 MVAR reactor will be required at Petersburg. Should conditions be favorable for power to be exported to the BC border,it is likely that shunt compensation will be required at that point or some other point.Once more details of the connection point in the BCTC network are known,this requirement needs to be investigated further. Further studies are required to determine the appropriate timing for changing the operation voltage from 69 kV to 138 kV of the transmission line evacuating the Tyee Lake generation. Additional studies are required to assess the operation of the STI under various load conditions. 6.6 British Columbia Segments 6.6.1 Overview BCTC,a provincial Crown corporation incorporated May 2,2003,is responsible for operating, managing,and maintaining BC Hydro's transmission system.Since its inception,BCTC has planned system upgrades and new transmission projects in response to a customer's request. The recently issued BC Energy Plan envisions a modification in how new transmission projects are planned and provides direction to BCTC to move beyond the contract-driven approach to an approach where infrastructure is added in advance of need.The proposed Northwest Transmission Line (NTL)discussed below is included in BCTC's potential future line segments as it responds to a customer request for service;the potential interconnection with SE Alaska would fall within a new category introduced in the BC Energy Plan:"a project that BCTC identifies as having future benefits, but which has not been triggered by a customer request.” Hatch Acres Corporation PR324582.Rev.0,Page 160 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACHES Under a Master Agreement between BCTC and BC Hydro,dated November 12,2003,BCTC is responsible for planning,constructing,and obtaining all regulatory approvals for enhancements, reinforcement,and sustaining and growth investments to BC Hydro's transmission system,and for entering into commitments and incurring expenditures for capital expenditures on the transmission system. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report BC Hydro continues to own the core transmission assets and is required to make capital expenditures to support these investments in accordance with Article 19 of the Master Agreement. Other capital assets,including control centers,system operation assets,and business support systems are funded directly and owned by BCTC. Upon receiving approval from the British Columbia Utilities Commission (BCUC),BCTC directs new transmission infrastructure investment.The BCUC regulates terms and rates for transmission services. BCTC currently manages 18,000 km of high-voltage lines,underground and submarine cables and operates six System Control Centers all over BC,which are responsible for maintaining the reliability of the "backbone”of BC's transmission grid (see map of the BCTC system at Appendix A) BCTC's corporate offices are located in Vancouver. BCTC is the transmission services scheduling agent,the control area operator,the bulk transmission system operator,and the real time generation dispatch group for the BC integrated transmission system. BCTC operates under an open access transmission tariff that meets FERC regulations,allowing non- discriminatory access to all requesters to use the system.Presently the BC transmission system is interconnected to Alberta by two 138 kV lines and one 500 kV line;and to the "Lower 48”United States by two 500 kV and two 230 kV lines. BCTC reports discuss an interconnection with Alaska to BCTC's transmission system through the proposed AK-BC Intertie'''.However,the current Northwest Transmission Line proposal does not include this link. 6.6.2 Description of Segments and Potential Interconnection Locations 6.6.2.1 Northwest Transmission Line BCTC,BC Hydro Corporation and the other representatives from the Government of British Columbia are currently exploring options for the Highway 37-BC Northwest Transmission Line from Skeena to Bob Quinn in northwest BC (NTL).A decision is anticipated in 2007. Proposed NTL Corridor Route The corridor would follow the existing BCTC circuits from Skeena to Aiyansh and Aiyansh to Meziadin/Stewart.A map showing the proposed NTL is included in Appendix A.From Meziadin the corridor would follow several major river valleys and generally parallels roads and highways. "1 Alaska-BC Inter-tie Study Report,Powertech,March 3,2006 Hatch Acres Corporation PR324582.Rev.0,Page 161 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES The route between the existing Skeena Substation,located 12-km south-west of Terrace and Iskut would be approximately 440 km/273 miles in length and includes four segments: Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report e Skeena Substation to Aiyansh e Aiyansh to Meziadian e Meziadin to Bob Quinn e Bob Quinn to Iskut. A new 287KV line termination and associated facilities would be added at the existing Skeena Substation and two new substations would be constructed at Bob Quinn and Iskut. Currently identified challenges and issues that BCTC will address include: e Confirm the right-of-way location for the line within Canada,and the potential link to interconnect with Alaska (AK-BC Intertie).Secure all required approvals to construct and operate the transmission segments e Energize the line to deliver energy to meet mining development schedules -e.g.a stated requirement by NovaGold to deliver energy to the Galore Creek Mine in third quarter of 2008 to support construction e Address the disconnect between the estimated cost of the transmission segment against the current allowed funding through BCTC tariff structure and avoid future significantly higher costs for BC ratepayers.This concern may be reduced given the proposed modifications to current practices in the recently issued BC Energy Plan e Address potential risk of capital cost/schedule uncertainties given volatility of mining industry development e Consider interests expressed by the State of Alaska in securing an interconnected transmission system with Canada for the purposes of exporting power (AK-BC Intertie). Note that current statements regarding the proposed line north from Meziadin Junction do not include the potential interconnection with Alaska e Develop a long-term coordinated approach to address energy needs within northwest BC and proposed interconnection with Alaska that would provide additional opportunities for hydropower with seasonal storage benefits,as opposed to run-of-river project operations in BC;and provide voltage support during forced outages on BCTC's 500 kV system south of Skeena. Summary and Analysis of BCTC Facilities Construction Cost and Schedule As of the date of this report,detailed information is not available.The following section contains information presented in the BCTC September 8,2006,report posted on the BCTC website.'”” "2 North West Area Transmission Options,BCTC Report No.SPA 2005-24 Hatch Acres Corporation PR324582.Rev.0,Page 162 AK-BC Alaska Final Report 18-09-07.Doc WATCH ARES Construction Cost Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Estimated costs are accurate to a level of +/-20%.The project estimates assume a commitment to proceed in early 2007 with completion by fall 2010. The following table presents the cost estimate from that report. Table 6.6-1 Estimated Cost -Skeena to Iskut (September 8,2006) CATEGORY ITEM TOTAL COST Direct Costs -Transmission Skeena-Aiyansh (101 km)$36,503,000 Aiyansh-Meziadin (108 km)46,064,000 Meziadin-Bob Quinn (126 km)64,037,000 Bob Quinn-Iskut (105 km)48,688,000 Subtotal -Transmission $195,292,000 Direct Costs -Stations Skeena Upgrade Sub-station 7,139,000 Bob Quinn New 287 kV Sub-station 33,604,000 Iskut New 287 kV Sub-station 13,374,000 Subtotal -Stations $54,117,000 Telecommunications 13,348,000 Indirect Costs 32,780,000 Contingencies @15%44,331,000 OH &IDC 45,748,000 Total ($2006)$385,616,000 Total (Low Inflation)$449,301,000 Total (High Inflation)$490,034,000 Table 6.6-2 Project Schedule --Development Milestones DATE ITEM June 8,2006 Initial Working Group Meeting June 22,2006 Initial!BCTC/BC Hydro engineering team meeting June 26,2006 Initial Tahltan meeting September 2006 Conceptual design &preliminary (+/-20%)cost estimates =$330 Hatch Acres Corporation PR324582.Rev.0,Page 163 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report million September 2006 Environmental overview assessment October -December 2006 __First Nations /Mines /Government discussions and alternatives assessment. May 2007 Agreement in Principal to Proceed with Selected Project Summer /Fall 2007 File for regulatory approvals Spring /Summer 2008 Begin clearing and access work Spring 2009 Begin construction Fall 2009 Complete Meziadin to Bob Quinn segment and temporarily energize at 138 kV to serve mine construction loads Fall 2010 In service date 6.6.2.2 Interconnection to AK/BC Border While the link to SE Alaska is not under active consideration at this date a report issued by BCTC on March 3,2006,Alaska BC Intertie-Study''',reviewed a potential line from Terrace,BC,to Tyee Lake in SE Alaska.The route generally follows Highway 37 to the Iskut River,then west to the Craig River,and then southwest to the Bradfield Canal.The study identified potential benefits for parties in both SE Alaska and British Columbia of interconnecting various Alaskan loads and generators to the BC grid including: e Improved continuity of service to customers due to redistribution of power flows following a contingency or during a planned maintenance outage e Improved frequency stability as a result of the increased inertia of the combined power system e Improved voltage stability as a result of higher short circuit capability e Trade opportunities. The limited study addressed the likely transfer capabilities for a range of net area loads and generation.The studied case,based on BCTC's 2009 heavy winter condition modified as follows: e A 287-kV line from Skeena to Bob Quinn Lake (335 km) e A 287-kV line tap from Bob Quinn to the AK/BC border (approximately same length. 6.6.3 Maps Maps depicting the BC Hydro-Transmission System and the Proposed Northwest Transmission Line are included in Appendix A. "3 Alaska-BC Inter-tie Study,Project 16239-21-00;Report #16239-21-00-3,Powertech Labs,Inc.prepared for BCTC,March 3,2006 Hatch Acres Corporation PR324582.Rev.0,Page 164 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report SECTION 6 FIGURES Hatch Acres Corporation PR324582.Rev.0,Page 165 AK-BC Alaska Final Report 18-09-07.Doc 124 PTRSBURG 23©OOR 48 C27 3 aes ED O Fan 20300.0 -1s JE PTRSBURG 3©ss 1.5 a6R CRYSTAL ra)20 2.0 ff -2.0 2 02 ot Dor y a ©aQ: 3.6 5.1 290 43 2020fo)PTRSBURG 1050 07 32 2 (0)110 1051 pT POINT FALLS©-70 [a8 y 5 100 A MT POINT O)1.010 2l2 iON 26 26 25.1 SWAN LK}<or27.0 1.030 oo 's 'e 2010 wr sls 212 1041 04,0.0 gWRANGELL 5 999 WRANGELL 27:2 gWRANGELL 77 1190 ale 12.5 |mw i 2000 SWAN LK -_390 2 6 bo 40 38 TYEE 2002 1030 wi |oeSEsET)30 ff -124 2 TYEE 2 50 142 1040 i 1180 -Oe HERRING720WANLK1.013 8 80 69.9 a1 6R°980 297 "133 2Et2013ur ti;WRANGELL . 44 1290-98 10.1 8 -10.9%S$S$5.0 0 69 #5 7 = 12 2 07 [Lo 33ff25 ¢ 0 H 2 ed "28 P28 2697 26 06 1140BAIL-SWN°?BAILEY 43 4.000 1.015 1181 2,7120 10 249 70.0 SWAN LK ;--4{f-_-1,003 AS 29.8 >"6 |©46 ns -1L4 Keene a "241 2 120 101s 17 1060 1900 350 :34.5 -16 1s |%174999 10.9 3 46 wt 719 pra 0997 1.030 © =|s 248 710 1130165DETHE 43 43 45 Pa 1120 09 f 09 2 68 PORTWESTnen123112301211>{>995POINTPOINTPKGEN148ed: 5 343 Dt sw s 28 1220 -73 77 13 Da 28 2 4 rr (06 4 "ad >56 56 $28 ff 56 $7]-57 93 $mae FF z 33 > 34 333306Pt"il Le ars 6)10-12 14 904 18 $1070 973 7 337 981 983 rd ea 1100 12.1 334 110.1 33.8 339 .23 23 fF -KETCHT243.4 "110 96 3 .: 10.9<j}65 1170 . 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MT POINT 32 $32 Ls <16 17 127 398 1040 HERRING 10 0.2K 69 69 20 $5.0 ff 70 69'on as OS O4R kd 09 906 "OS uw? 20 "12 OAR 020 352 1060 ors 2021 2030 2031p97PTRSBURG(."RYSTAL 24 |-19 off -21O-|ss 2 Fr27>or ,O5R5597 o-0.0 3 27 (6)33°2.0 3 io)38.7 po22 PTRSBURG © 55 9°56 -®bo22733ETRSBURG4 430106065 08 2<}n 2040 2036 ofroa€TR 2020 wo F/2 els 050©PTRSBURG 4010 1081of0808osfosole0.969 2 133.8 4 PFALLS MT POINTO--6 oI i 6]e47es >1.026 ale 235 S15 19 32 32256=|_SWANLK1 <q41014-_-18 z 16©zo 709 AA M2794 ©1.030 a fo 10 144 129 x F/?wo201223"2004 9.0 gWRANGELL 2000 040 Q|s 127WRANGELL36GgVRANGELL78TYEE13sSWANLK=a2a<ssf Pa 36 |ss 56 9 594 608 764 Pe oat |34 ee Er]"15.5 a7 7180 2 M2 ose RING"037 SWAN LK 7102k143.1 56 .0988BS EE?23 m2 10082013Wa11.2 24 s -:WRANGELL :36 OAR 69 91.29)526 05g °°ay 20 $8070 Bad or 012207§105 a Me Met 4,930 ©Oar 2 os poz roe ae : 06 ]+a4 :42 BAL-SWN25 -_BALEY 20 27 1.007 022 $0 61R 1181 %34 QuikaR 16 25.41 441.0 1.040 WAN LIK >62 ---@ 1024 26 339 14 "029 3534060 1.022nrSIE "°a7 22 37 Kd 37 9 186 18.3 2 91 4g?227 483WePsMil?28 "27 tC -27fi21 -135 >62 48 22.9 "004 1.045 --@ "a?38 26.0 9 991 1.047 116.8 =4430rye 35 437.2 1376 1204 276 Aa 376 ;7.8 8.3 286 1200 en a 1231 57 N POINT 30 1220 06NPOINT=sw s 34$1 ae Be 7.0)70 87885454A3B130633<07 . 1.014 eo”126 1,004 3340.4 34.6 73 2016 WFPSMILL, 1114 0s 68.4 y .. 1170FIGURE6.5.3 -2021 -PEAK DEMAND-export LEYS at 20212x6ELTRSBURG 2030©00 0 FO "RYSTAL °+2)022 20 20 20 Pa bIRSBURG ©02 70.1 for > 63 fir i--©1028<j ibe 1 010 286 bs m4]-8.0 10.5 82 2016 _WEPSMILL |Barc Os 68.4 yoo FIGURE 6.5.4 -2031 -PEAK DEMAND.NYae1120 PORTWEST 4g 1080 ost MT POINT MT POINT $36 ka 19 1o1t 126 389 1040 HERRING 1 {notSWAN LKI 1030 v.|v .az eft20104020081.042 0.0 gWRANGELL 00 LAKE a 3201243OQ08|.+Sis3920117iosOOO190slspVRANGELL.229 WRANGELL 82 WAN LK 65 2 6s J 63 65 972 12 1030 es 4 a2 os 3d y 37 37 37 P27 "9.1 1180 "78 os 7oO1.046 SWAN LK 2514441.046 >1.007 144.4 44 :2013 49a3WRANGELL 2001 12 9-150 182109 ¢Jus 12 2 07 for Erxu Bred 032206i>44 1.033 1047 uM 287 1445 249 67 a2 1.047 14d 267 BETHE 6.2 3aaNyn 1211 P 1230 LPK GEN 2 Ww 0937 15 129 3.0 =oA nATGH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 7.POWER GENERATION COSTS AND ISSUES Q Hatch Acres Corporation PR324582.Rev.0,Page 170 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGE Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 7.POWER GENERATION COSTS AND ISSUES 7.1.Overview This report identifies and describes potential new generation project development to: e provide low-cost power to SE Alaskan communities e encourage new projects that would generate power surplus to needs in SE Alaska for export to BC and the PNW. 7.2 Potential Power Project Development 7.2.1 Existing,potential retirements,and planned new projects (capital and O&M costs) 7.2.1.1 Existing Hydropower Projects Hydropower projects exist throughout the study area with owners including Alaska Power and Telephone (APT),the Four Dam Power Pool Agency (FDPPA),Ketchikan Public Utilities (KPU), Metlakatla Power and Light (MP&L),and Petersburg Municipal Power &Light (PMP&L).A listing of the projects that relate to the current study is included in Table 7.2-1 below.In general,these projects are operated with very little spill and the resulting capacity and energy values can be taken directly from the generation records for each site.The well known exception to this is Tyee Lake project which has generation capability in excess of the combined load of Wrangell and Petersburg. The generation values shown for this project are based on previous studies as summarized in the referenced report. Table 7.2-1 Existing Hydropower Projects Average --'Firm NearestLoad Licensee/Installed Energy Energy Project Name Center Permittee Capacity (GWh)(GWh)Source -Comments A_South Fork Prince of Wales APT 2.0 6.7 5.5 APT generation records B Black BearLake Prince of Wales APT 45 21.4 19.2 APT generation records C__Swan Lake Ketchikan FDPPA 22.5 72.0 59.0 KPU generation records Wrangell /Commonwealth Associates,Inc.,"SoutheastDTyeeLakePetersburgFDPPA22.5 116.8 67.2 Alaska Energy Export Study”,2006 E_Silvis Ketchikan KPU 2.1 11.4 9.6 KPU generation records F Ketchikan Lakes Ketchikan KPU 42 19.8 15.0 _KPU generation records G_Beaver Falls Ketchikan KPU 6.0 38.4 33.0 __KPU generation records H_Purple Lake Metlakatla MP&L 3.9 12.6 10.7__MP&L generation records |_ChesterLake _Metlakatla MP&L 1.0 3.5 2.1 __MP&L generation records J Blind Slough Petersburg PMP&L 20 40.4 40.0 Acres International Inc.,"Flow Studies andHydrologyReport”,2002 Figure 7.2-1 shows the existing and potential hydropower projects within the project study area of SE Alaska. Hatch Acres Corporation PR324582.Rev.0,Page 171 AK-BC Alaska Final Report 18-09-07.Doc Sitka ]EY South Fork -2 MW Blue Lake woes [EJ Black Bear Lake -4.5 MW Green Lake venee ake [Gl swan Lake -22.5 MW a |D|Tyee Lake -22.5 MW *i sivis -2.1 mw en dal :[i Ketchikan Lakes -4.2 MW |G |Beaver Falls -6 MW EE]Purple Lake -3.9 Mw [OW Chester Lake -1 MW EI]Blind Stough -2 Mw \... \ Coffman Cove \ [4]Mahoney Lake -9.6 MW (2010)Naukati e J [2]Scenery Lake -30 MW (2015)*/[3]Delta Creek (Ruth Lake)-20 MW (2015).: [4]Cascade Lake (Swan Lake)-45 MW (2015)Klawock ) [5]Whitman Lake -4.6 MW (2010)Crai : raig \[6]Connell Lake -1.7 MW (2016) Carlanna Lake -0.8 MW (2016) Triangle (Hassler)Lake -3.5 MW (2016) ¢€Ketchikan Bao 'GIIZ)[9]Takatz Lake -20 MW (2016)os "a Fi]©toad Conter Virginia Lake -12 MW (2016)@Metlakatia --Existing Transmission Line[14]Thoms Lake -7.5 MW (2016)===Proposed Transmission Line Sunrise Lake -4 MW (2016) .El Existing Projects Anita &Kunk Lakes -8.6 MW (2016) . ;oO Proposed Projects Tyee Lake -34.0 MW (incr.)==Other Features [15]Reynolds Creek -5 MW (2012);N FIGURE 7.2-1 Zz HATCHAK-BC Intertie Feasibility Study Features:Z- Load Centers,Transmission and Generation Facilities energy WATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 7.2.1.2 Existing Diesel Facilities Diesel plants ranging from a few kWs to 10.5 MW supply communities in SE Alaska with firm power,as backup in some communities and as primary in others.The total capacity of in-service diesel plants in SE Alaska totals 56.65 MW.Fuel prices vary by community or load center and range from $2.20/gallon in Ketchikan to $2.68/gallon in Wrangell.Compared to the cost of existing hydro power in the range of $10/MWh to $20/MWh,and the lowest cost proposed hydro power in the $55/MWh to $87/MWh range,diesel is both costly to the communities and a contributor to greenhouse gas emissions in the region.A more in-depth discussion of existing diesel facilities including O&M costs,consumption,and condition is contained in Section 8.3, Existing Generation and Transmission Infrastructure. 7.2.1.3 Potential Retirements As stated above,the strategy over recent years for the utilities that have the good fortune to have nearby viable hydropower sites has been to replace diesel generation with hydropower to the greatest extent possible.Within this framework,no retirements have recently occurred or are planned for the hydropower family of resources.On the other hand,this strategy has enabled and will continue to enable the retirement of aging diesel units.For the present study all existing and in-use units are considered to remain in service throughout the study period.Future decisions to retire individual units will be based on economics and other operating factors as determined by the individual utilities,which requires a level of planning that is considered beyond the scope of this study. 7.2.1.4 Potential New Hydropower Projects In 1947 the Federal Power Commission (forerunner to the FERC)and the USFS published a document entitled "Water Powers of Southeast Alaska”.The forward to the document includes the following statement: "There are 200 potential which it is estimated could develop 1,008,370 average horsepower.Of these,27 range in size from 10,000 to 51,000 average horsepower.In developing a power system, many of these projects could logically be interconnected with high voltage transmission.The remaining projects and some of less capacity,but susceptible to automatic control and operation, could be interconnected through the principal stations at lower voltage transmission.This would permit the advantages of economy to extend throughout the system and keep the installation cost to a minimum.” The FPC/USFS report includes a description of the physical characteristics and development potential of the referenced 200 projects.Of these,some have been developed as included in Section 6.2.1.1 above.Many others have been studied and proposed for development several times over but still remain as undeveloped.The projects selected for serious consideration in this study are those that have been studied at one time or another within the last 30 years.It is from this remaining family of potential projects that the fifteen (15)sites listed in Table 7.2-2 have been selected for further consideration as future resources for SE Alaska as well as export through the proposed AK-BC Intertie. Hatch Acres Corporation PR324582.Rev.0,Page 173 AK-BC Alaska Final Report 18-09-07.Doc HATA AGED Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 7.2-2 Potential Hydropower Projects Project Name Nearest Load Center Licensee Earliest On-Line 1 Mahoney Lake Ketchikan Saxman 2010 2 Scenery Lake Export cc,LLC 2015 3 Delta Creek (Ruth Lake)Export CC,LLC 2015 4 Cascade Creek (Swan Lake)Export CC,LLC 2015 5 Whitman Lake Ketchikan KPU 2010 6 Connell Lake Ketchikan None 2016 7 Carlanna Lake Ketchikan None 2016 8 Triangle (Hassler)Lake Metlakatla None 2016 9 Takatz Lake Sitka /Export None 2016 10 Virginia Lake Wrangell None 2016 11 Thoms Lake Wrangell None 2016 12 Sunrise Lake Wrangell None 2016 13 Anita &Kunk Lakes Wrangell None 2016 14 Tyee -34.0 MW Wrgl/Ptsbg None 2012 15 Reynolds Creek POW Haida Corp 2010 All of the above listed projects have been considered for development several times and pursued to differing levels by various entities.Accordingly,considerable variation exists amongst these studies in the proposed project purpose,project layout,capacity and energy characteristics and the cost of power production.The project capacity and energy characteristics are discussed in paragraphs below and a general description of each project as proposed is included in Appendix F. 7.2.1.5.Potential Wind,Tidal and Geothermal Projects The potential for development of alternate energy projects in SE Alaska exists but is much further behind in identification,study,definition,evaluation,and implementation than the viable hydroelectric projects described above.However,the region is assumed to be blessed with potential for additional projects from as-yet-unidentified renewable power projects. Each type considered suitable for SE Alaska is described below.Because individual sites or projects have neither been studied in any detail nor defined for development we can only describe the energy sources in general terms.For these same reasons,potential generation and development cost information does not exist. Wind Power Both small utility-grade wind energy projects as well as large-scale wind farms in both onshore and offshore developments may be feasible in the SE Alaska region,yet no projects have been identified or defined at a level that would warrant inclusion in this study. The State of Alaska's Wind Energy Program is managed by the Alaska Energy Authority (AEA)and "provides information and technical assistance wind monitoring equipment,and educational Hatch Acres Corporation PR324582.Rev.0,Page 174 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRESEeeneeneevasenenaeenenans Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report opportunities for Alaskans interested in wind as a viable energy source.”Through this program that focuses mainly on small wind,AEA provides basic technical information and assistance,access to relevant reports and publications,and links to additional educational information.The key technical aspect of the wind program is the effort to loan anemometer equipment to communities for onsite monitoring of wind resources to communities and the compilation of the resource assessment data into accessible formats.In addition,data from the National Climatic Data Center (NCDC)for each airport weather station is also made available.Many communities in Western Alaska have gathered wind resource data through the AEA's anemometer loan program while the SE Alaska region has yet to produce more site-specific assessments other than at local airports. However,wind resources in SE Alaska do exist and the potential for large scale development is potentially feasible offshore,rather than on land. Tidal Power In February 2007,FERC issued a Notice of Inquiry (NOI)and Interim Statement Policy to invite comments with respect to a preliminary permitting process for potential tidal,wave and instream new technologies slightly different than for traditional hydropower projects.Until such time that the comment period is closed,FERC reviews the comments and issues a guidance document,no preliminary permits pending with the FERC are being processed.'* Currently in SE Alaska,the only project within our study area with a pending preliminary permit is at the Wrangell Narrows.Other projects in the vicinity are at Icy Straight and Gastineau Channel, both to the north of but outside of our study area. As described in Section 5.4.1.1 the only presently identified potential project has not arrived at a state where either generation or cost is estimable.Until that time,this project is simply noted and its progress will continue to be monitored with great interest. Geothermal Power Geothermal energy refers to naturally occurring "earth heat"underground,such as hot rocks or hot water,often in active volcanic areas.Geothermal energy potential is high in much of Alaska, including in the SE Alaska region,which is dotted with hot springs on the mainland and on several islands.SE Alaska geothermal activity is as fault-related rather than volcanic as is the rest of the state.There are currently 14 known hot springs in SE Alaska.Current estimates assign the potential for geothermal energy from the identified hot springs a very small scale,in the kW to MW range. As an interconnected SE Alaska becomes a reality,the remotely located hot springs may become attractive developments of geothermal power.'” 7.2.2 Generation Potential at New Projects 7.2.2.1 New Hydropower Generation As stated above,the potential new hydropower facilities considered for this study vary in their development status.Two projects in the group,Mahoney Lake and Whitman Lake,have "4 Docket No.RMO7-08-000.Comment period closes April 15,2007. "5 "Geothermal Resources in Alaska”presentation by Amanda Kolker,UAF. Hatch Acres Corporation PR324582.Rev.0,Page 175 AK-BC Alaska Fina!Report 18-09-07.Doc nATGH ARES completed their environmental reviews.Accordingly,their capacity and energy estimates reflect final resolution with resource agencies on such matters and reservoir operation,instream flows and ramping rates.In the case of the remaining projects,however,The required future consultation with the agencies will heavily influence project operational constraints and at this time it is not possible to include their potential impact on the generation potential of these future projects. Accordingly,their generation values as estimated by past and current proponents and as shown in Table 7.2-3 are based on physical site conditions including drainage area,runoff patterns,reservoir storage potential and reservoir elevation. Alaska Energy Authority-AK-BC Intertie Feasibility Study SE Alaska Final Report Table 7.2-3 New Hydropower Generation Average -'Firm Installed Energy Energy Project Name Capacity (GWh)(GWh)Source -Comments 1 Mahoney Lake 9.6 39.6 34.3.FERC License,Project No.11393 2 Scenery Lake 30.0 128.7 102.8 Cascade Creek,LLC 3 Delta Creek (Ruth Lake)20.0 70.7 57.6 Cascade Creek,LLC 4 Cascade Creek (Swan Lake)45.0 202.3 159.1 Cascade Creek,LLC WESCORP,"Whitman Lake -Hydroelectric5WhitmanLake4619.6 17.0 project Reasibility Study”,1998 R.W.Beck &Assocoates,Inc.,"KPU Power Supply6ConnellLake1.7 10.8 93 Planning Study",1996 R.W.Beck &Assocoates,Inc.,"KPU Power Supply7CarlannaLake0.8 42 3.6 Planning Study",1996 .Federal Power Commission &Forest Service,"Water8Triangle(Hassler)Lake 3.5 13.1 11.4 Powers of Southeast Alaska",1947 9 Takatz Lake 20.0 406.9 97.4 Alaska Power Administration,"Takatz Creek Project-Alaska”,1968 oe R.W.Beck &Assocoates,Inc.,"Appraisal Report,10 Virginia Lake 12.0 43.8 37.9 Virginia Lake Project”,1977. R.W.Beck &Assocoates,Inc.,"Appraisal Report,11 Thoms Lake 75 24.2 20.9 Virginia Lake Project”,1977. .R.W.Beck &Assocoates,Inc.,"Appraisal Report,12 Sunrise Lake 4.0 13.5 11.7 Virginia Lake Project”,1977. 43.Anita &Kunk Lakes 86 28.4 243 R.W.Beck &Assocoates,Inc.,"Appraisal Report,Virginia Lake Project",1977. 14 Tyee -34.0 MW (incremental}11.5 20.3 6.0 -Prorated from existing project 15 Reynolds Creek 5.0 6.1 5.5.FERC License,Project No.11480 Hatch Acres Corporation PR324582.Rev.0,Page 176 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACHES 7.2.3 Cost of Power Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 7.2.3.1 New Hydropower Costs The evaluation of the cost of power from the above list of future hydropower projects requires careful consideration of the variability of the level of data that is currently available.With the exception of Triangle Lake,earlier studies have been done and cost estimates have been developed.However,these studies vary widely in purpose,philosophy of development ,extent of analysis and the year in which they have been performed.For the purposes of this study and to the extent possible,however,it is necessary to bring the estimates to a common basis.To that end,the approach taken herein is as follows: e When available,estimates for the major elements of construction of the Direct Construction Costs (DCC)have been taken as published in the most recent study for each project e Acommon percentage each for Contingencies and for Environmental,Engineering and Owner Administration have been applied to the DCC to develop the Total Construction Cost (TCC) e Acommon percentage has been applied to the TCC to develop an estimate for the Total Capital Requirements (TCR)in terms of the year in which the estimate for the DCC was prepared e "Composite Trend Indices”from the "Bureau of Reclamation Construction Cost Trends” table were used to escalate the TCR to 2007 dollars e Annual Costs were developed using a common set of financial terms and assumptions for variable costs such as Operation and Maintenance. The values used to arrive at the TCR and the Annual Costs are summarized in Table 7.2-4 and the resulting comparative costs,expressed as "Order of Magnitude Costs”in nominal 2007 dollars,are included in Table 7.2-5. It is noted that the "Cost of Power”derived in this section (as shown in Table 7.2-5)is defined on a different basis from the "Levelized Unit Cost of Energy”shown in Section 8.5.1.The two calculations each use the same assumptions on the total estimated capital investment and annual operating and maintenance costs for each of the potential new hydropower developments.The calculation methods used for each calculation are described in the respective sections. Hatch Acres Corporation PR324582.Rev.O,Page 177 AK-BC Alaska Final Report 18-09-07.Doc nATGH AGE Table 7.2-4 New Hydropower Cost Assumptions Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Item Value Total Capital Requirements Contingencies 15%of Direct Construction Cost Engineering &Owner Administration 15%of Direct Construction Cost Interest During Construction 4%of Total Construction Cost 2007 USBR Cost Index 305 Fixed Costs Annual Interest on Bonds 6% Bond Term 20 years Financing Expenses 2.5%of Total Capital Requirments Working Capital Reserve 6 months of O&M costs Variable Costs Operation and Maintenance $32 /kW Administrative and General $8 /kW FERC Compliance $15,000 /yr Interim Replacements $4./kW Insurance $12 /kW With regard to the values shown in Table 7.2-4,it is clearly understood that the actual cost of development of any of these sites could vary significantly from the amounts shown as the result of factors as: e Yet to be determined geotechnical site conditions e Market structure for which the project is developed e =Institutional requirements unique to the business structure of the project proponent with regard to factors such as contracting for engineering and construction services,necessary arrangements for project financing and staffing requirements of operation and maintenance activities during the life of the project e Environmental constraints imposed on project features as well as project construction activities as may be contained in a future FERC license. Accordingly,these costs must solely be considered in the context of the present study as they may influence the conclusions and recommendations included herein. Hatch Acres Corporation PR324582.Rev.0,Page 178 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 7.2-5 Comparative Costs -New Hydropower Order of Magnitude Costs (2007 Dollarg Cost of Capital Cost Variable Cot Power Project Name ($1,000)($1,000)($/MWh)Source-Comments 1 Mahoney Lake $34,073 $553 $85 FERC License,Project No.11393,1998 2 Scenery Lake $84,442 $1,695 $67 Cascade Creek,LLC 3 Delta Creek (Ruth Lake)$60,517 $1,135 $86 Cascade Creek,LLC 4 Cascade Creek (Swan Lake)$144,959 $2,535 $71 Cascade Creek,LLC ;Hatch Acres,"Updated Cost Estimate and5WhitmanLake$9,738 $273 $55 fe”,2006 RW.Beck &Assocoates,Inc.,"KPU Power Supply Planning Study”,1996RW.Beck &Assocoates,Inc.,"KPU Power Supply Planning Study”,1996 8 Triange (Hasder)Lake $15,613 $211 $114 HatchAcres,present study RW.Beck,"Sitka-Analyss of Bectric System Requirements",1974 RW.Beck &Assocoates,Inc.,"Appraisal Report,VirginiaLakeProject”,1977.RW.Beck &Assocoates Inc.,""Apprajsal Report,Virginia Lake Project”,1977.RW.Beck &Assocoates Inc.,"Apprafsal Report,Virginia Lake Project",1977. RW.Beck &Assocoates,Inc.,"Appraisal Report,Virginia Lake Project”,1977.Harza,"Risk Assnent of the FourDam Pool Power Projects”,1996 15 Reynolds Creek $19,166 $295 $307 FERC License,Project No.11480,1998 6 Connell Lake $7,779 $110 $69 7 Carlanna Lake $3,735 $60 $87 9 Takatz Lake $134,204 $1,566 $117 10 Virginia Lake $127,575 $687 $255 11 Thoms Lake $136,108 $435 $481 12 Sunrise Lake $16,252 $239 $117 13 Anita&Kunk Lakes $111,922 $497 $345 14 Tyee-34.0 MW(incr.)$10,114 $659 $73 On the basis of the assumptions as stated above,the annual costs include the cost of financing the capital cost of each project over an initial financing period of 20-years.Please note that the costs as shown in the following section represent an annualized or levelized cost of each project over a life of 50 years,which results in a considerably lower number. Hatch Acres Corporation PR324582.Rev.0,Page 179 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACRES 7.3.Potential Power Project Not Proposed For Interconnection Within SE Alaska Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Soule River Project Alaska Power &Telephone Company (AP&T)is pursuing development of the proposed 50 MW''® Soule River Water Project,FERC P-12615''”,that would be located on the Soule River near Hyder, Alaska.""®The proposed project would be connected by a 9.72 mile-long 35 kV submarine cable transmission segment from the powerhouse,located at the mouth of the Soule River extending along the Portland Canal,a 70-mile-long fjord which forms a portion of the AK/BC border,to an interconnection with the existing BC Hydro-owned transmission system in Hyder,Alaska.Hyder is located at the head of the Portland Canal 2 miles from Steward,BC. Hyder and Stewart are served by BC Hydro.Currently generation is provided by propane and diesel-generation.The proposed Soule River Project would have an estimated annual generation of approximately 155 GWh hours.AP&T has prepared an Interconnection with BCTC and expect to file it during March 2007 to determine feasibility and location of connecting Soule River.AP&T plans to submit a proposal to BC Hydro during their next call for power expected to occur in fall 2007. "6 Storage project with a 150-foot-high dam,and with capacity of about 50 MW (42 MW in a main power plant at tidewater and 8 MW in a power plant at the dam using instream releases).AP&T is also considering an alternate ROR project with a low diversion further downstream than the storage dam,and with a capacity of 21 MW. "7 AP&T received a Preliminary Permit from the FERC on July 13,2006,to reserve the site during a three- year study period. "8 Soule River Project is identified on Figure 1.1 AK-BC Intertie Feasibility Study Area Hatch Acres Corporation PR324582.Rev.0,Page 180 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska 8.COMPARATIVE ANALYSIS OF DEVELOPMENT AK-BC Alaska Final Report 18-09-07.Doc nA ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 8.COMPARATIVE ANALYSIS OF DEVELOPMENT 8.1 Overview This section of the report identifies and describes a range of potential development scenarios to supply the increasing demand in SE Alaska in a least cost way and examines the effects on the overall economics of developing projects for export power to British Columbia or the Lower 48. The section provides a brief overview of the methodology used including the approach of dividing the study area into three regions and addressing the individual requirements of each region as well connecting the individual regions.As part of the approach used,a brief description of the special purpose model (referred to as a Regional Resource Planning Model -RRPM)developed for the present study is given. A brief outlook of the existing generation and transmission facilities is presented together with the planning parameters used in the evaluation to arrive at the least cost plans.The planning parameters include both technical and economic criteria and address such items as generating reserve and fuel costs. To meet the increased system requirements,the system can count on hydroelectric resources, diesel plants and transmission facilities to bring these resources to the load centres.Several individual projects were identified and included in the overall analysis. Studies were carried out to determine the capacity and energy balance for each of the load centers in SE Alaska under study to obtain the system needs under a range of conditions regarding existing and committed generation. Generation expansion plans were formulated,developed,analyzed and evaluation with the assistance of the RRPM in order to arrive at a least cost plan to supply SE Alaska with electrical energy.These plans included scenarios without exports and with exports. Finally,sensitivity studies were carried out to determine the sensitivity of the generation expansion sequences results to changes in the parameters used in the analysis. 8.2.Description of the Economic Analysis Methodology The SE part of the State of Alaska is composed of several load centers with few of these being connected to each other which would allow sharing of resources and participating in economies of scale.One of the key objectives of this study is to determine the least cost and environmentally sustainable way to provide energy to meet the region's requirements. Electricity is presently being generated by hydro plants and diesel generating units.With increasing cost of fuels,the supply cost of diesel generation in SE Alaska is not conducive to economic development but the region has hydro resources that could be developed to supply its own load and possibly for export to the Lower 48 or to British Columbia.The principal obstacle,at this time, to the development of the hydro resources is the lack of a transmission system between the major load centers as well as stagnant load growth in the region.In order to determine the most Hatch Acres Corporation PR324582.Rev.0,Page 182 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report appropriate way of supplying these load centers,an integrated generation/transmission plan is required. For study purposes SE Alaska was divided into three main regions,namely: e Tyee Region composed of the load centers of Petersburg,Wrangell and Kake e Swan Region composed of the load centers of Ketchikan and Metlakatla e Prince of Wales (POW)Region composed of the load centers of Craig,Klawock,Thorne Bay,Kassan,Hollis,Hydaburg,Coffman Cove,Naukati and Whale Pass. At this time the regions remain isolated from each other and load centers within the regions are also isolated,except for Petersburg and Wrangell in the Tyee Region and in the POW Region where only Coffman Cove,Naukati and Whale Pass remain isolated.For the present study,and due to the distances from the other load centres and its relatively small electrical energy requirements,the community of Whale Pass was considered to be supplied in an isolated mode throughout the study period and as such was not considered in the analytical studies. Keeping the above background in perspective and the fact that the electricity demand requirements are likely to increase in the near future,a study to determine the least cost integrated system (generation and transmission)expansion for SE Alaska was carried out in order to best allocate the resources available to the power sector. Given the physical structure and topology of the power system,and the fact that the Terms of Reference require that "in-state”(meaning SE Alaska)requirements for energy supply and delivery be met first,this part of the work was carried out in two steps: e The first step determined the least cost plan to supply the electrical demand in the Southeast part of Alaska without exports e The second step determined the least cost plan to supply the electrical demand in the Southeast part of Alaska taking into account possible export of electricity under long term commitments. The approach used in each of these two steps is described below. 8.2.1 Least Cost Plan without Exports The development of the least cost plan without exports followed a series of coordinated steps which included: e Review of existing studies e Review of the existing system e Definition of candidates for future installation e Analysis of capacity and energy balances for individual load centres e Formulation of generation alternatives e Estimation of costs for transmission segments e Modeling of generation alternatives Hatch Acres Corporation PR324582.Rev.0,Page 183 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACHES e Evaluation of generation alternatives. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The first task undertaken was to review the existing studies for both the supply of SE Alaska and for the export cases.Valuable lessons were learned from these reports which also assisted in providing input to the criteria to the used in this final report. The second step was to obtain data for the existing generation and transmission facilities for each of the three regions.A list of diesel units and hydro plants along with their respective technical and cost characteristics was developed based on the information received.Of particular importance within the data received for the existing diesel units was the price of diesel oil which allowed the delivery cost and other costs to be determined for each diesel plant in SE Alaska. Hydro plant generation by month was also received from other project team members for three hydrological conditions:minimum,average and maximum.The variation of the hydro generation capability throughout the year plays an important role in the supply of the demand and as such one has to ensure that the appropriate values are utilized. Candidate projects for future installation were analyzed.These consisted of thermal and hydroelectric projects.No project-specific information regarding other renewable energy facilities is available at this time.Therefore,other renewable energy sources were not included in Phase |of this study,but should be considered when project-specific information is made available in following phases. For new thermal generation only diesel technology was considered suitable for the load centers of SE Alaska using diesel oil (No.2)as fuel.The use of heavy fuel oil (HFO)was not considered for large units because it is not presently being used and its use could probably require especial handling facilities.Should generation by diesel units be significant at a particular load centre to warrant possible use of HFO,then the proper studies should be undertaken to verify the overall economics of switching to that fuel. For the hydroelectric candidates capital cost estimates were developed and the unit price of energy determined taking into account an annuity to pay off the capital investment (determined at an agreed upon discount rate and project life),the annual operation and maintenance costs and the expected energy to be produced by the plant (on an average basis).The unit price of energy at the plant's capacity factor was compared to that of equivalent diesel plant to determine its cost advantage and care was exercised in the interpretation of these values since many times the hydroelectric plants produce energy that could not be absorbed immediately by the load.In order to avoid this issue,an amount of generation from a particular new project was determined that could be sufficient to offset its costs by replacing diesel generation (break even amount of generation). Capacity and energy balances based on annual values were carried out for each individual load center to assist in determining the need for system additions.This simple exercise provided input as to when and how much new capacity and/or energy additions are required in a particular load center. Once the above steps were carried out,generation alternatives were formulated as described below. Hatch Acres Corporation PR324582.Rev.0,Page 184 AK-BC Alaska Final Report 18-09-07.Doc HATGH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 8.2.1.1 Formulation of Generation Alternatives For the least cost plan to supply the electrical demand in SE Alaska without exports,two main scenarios for generation alternatives were examined. The first considered the development of the generation requirements for each of the three regions without taking into account possible future connections between regions.Also within this scenario,the economics of connecting isolated load centres within a region was examined and this entailed the analysis of such connections such as Kake with Petersburg and Metlakatla with Ketchikan. The second generation alternative scenario considered the connection of the three regions to each other to form a SE Alaska electrical system.It should be noted that the connection of the POW Region could pose some technical challenges due to its relatively small demand and distance from the two other regions. 8.2.1.2 Modeling of Generation Alternatives Once the generation alternatives were formulated they were developed,analyzed and costed using a specially built model in MS Excel described in the next section.Basically,the model considers the load's peak demand and energy requirements as well as the existing and committed generation. From these it determines the reserve and when this reserve falls below a certain level new generation has to be added manually.The model determines the overall cost of supplying a given number of load centers with the supply entered by the user. In order to capture the variations throughout the year in the capacity and energy components of the demand and the fluctuation of capacity and energy generation by the hydroelectric plants,the model used monthly simulations of all supply and demand components. The model can simulate various load centers connected through a series of "transmission lines”and determine the costs for the various generation sources and transmission lines required to meet the overall demand. Should the generation within a load centre or within a region not be sufficient to meet the demand, the model treats the unsupplied energy as unserved energy and costs this energy at a value specified by the user. 8.2.1.3 Evaluation of Generation Alternatives By comparing the total annual supply costs of the alternatives examined one can determine the most economic way to supply a given load center or a region.One can also determine the most appropriate year for a load center to be supplied from outside its own boundaries or the most appropriate timing for a given diesel or hydro plant. 8.2.2 Least Cost Plan with Exports The approach used to determine the least cost plan to supply the electrical demand in SE Alaska taking into account exports of electricity under long term commitments is described herein. The studies carried out for the case without exports developed a comprehensive list of resources available for power generation,and since thermal generation is expected to be more expensive in Hatch Acres Corporation PR324582.Rev.O,Page 185 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES SE Alaska then anywhere else in the Lower 48 or in BC,this type of generation was not be considered to support exports. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The export case could allow for faster resource development as large hydroelectric projects can be considered earlier since the deemed load to be met will be much larger. The potential energy available for export was determined by considering the existing and future reasonably priced hydro projects and the total energy requirements in SE Alaska. Once the energy available for export was known,one followed with formulating generation alternatives and modeling these generation alternatives using an approach similar to that outlined for the case without exports.However,the modeling of these alternatives required some interaction between the analyst and the model since the energy available for export was available only in blocks through times that increase through time as new hydro projects are built and decreases as the SE Alaska load increases. In the model,the exports were considered as the surplus hydro energy that was not required to serve the demand in SE Alaska.The exports generate revenues which were subtracted from the overall costs.In this case the capital costs of building the transmission facilities to allow export of power were considered to be funded through a grant and only the O&M costs of the transmission facilities were considered in the economic analysis. 8.2.3 Sensitivity Analysis Sensitivity analyses were carried out to determine the least cost expansion plan's robustness to changes of principal parameters used in the analysis.Meaningful variations of these parameters were selected to demonstrate the robustness of the planning results under conditions that could be reasonably expected.This analysis investigated the following parameters: e Fuel prices e Capital cost of thermal and hydro projects e Operation and maintenance costs of transmission projects e Dtscount rate. 8.2.4 Outline of the Planning Tool Used A special purpose model was developed to analyze the development alternatives in SE Alaska for generation alternatives without exports and generation alternatives with exports.This model was developed on an MS Excel platform and makes uses of several macros programmed using Basic. The model has been named the Regional Resource Planning Model (RRPM). RRPM was designed to accommodate up to 20 load centers,30 buses (a bus can either be a load center or a generating plant),30 hydro plants,20 diesel plants with up to 10 units at each plant and AO transmission lines to interconnect any of the buses.The model divides a year into 12 months and three of the months (June,July and August)are further subdivided into 4 weekly intervals to allow the model to be able to represent transmission line maintenance or generating unit maintenance.Up to 35 years can be simulated individually and up to 15 years of extended Hatch Acres Corporation PR324582.Rev.0,Page 186 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report simulation can be carried out (load,generation and expenditures are kept constant during this period). The model was designed to determine system costs under any one of up to three hydrological conditions and for the present study these include the minimum,average and maximum hydro generation conditions. The model consists of 5 input pages,1 information page and 3 output pages.There are 11 macros written in Basic which read each of the input pages and carry out data validation,deal with the availability of transmission between the individual load centres,dispatch the hydro and diesel generation,calculate the annual costs and write the respective output of the calculations. Figure 8.2-1 provides a snapshot of the scenario input page in the program.In this definition page, the load centres are defined and they are linked with the data provided in the "load page”,the reserves for individual load centres can be entered in either percentage of the peak demand or absolute MWs.The next columns identify the supply priority for each load centre.Each load centre dispatches hydro resources connected to itself first and taking Ketchikan as an example,the hydro plants connected to the Ketchikan bus would be dispatched first.The exhibit shows that for Ketchikan (bus 1000),the first priority,after its own hydro,is the Swan Lake Hydro (bus 1100) followed by new hydro plants in Ketchikan (bus 1200)and then by hydro plants connected to the Metlakatla bus(1500).In this case,the Swan-Tyee Intertie (STI)was assumed to not be in place,and thus its bus (bus 2000)does not appear in the priority list for Ketchikan.However,should the STI be in place,then the priority list would contain bus 2000 after bus 1100 in order for the dispatch to comply with the "Long-Term Power Sales Agreement Four Dam Pool -Initial Project of the Alaska Power Authority”. Continuing with Figure 8.2-1,the next block of information addresses the "Renewable Generation Resources”where the proposed on line date is defined for each project.Data for each project is given in the "renewable page”.The project Numbers,Names,Bus ID and Earliest On-Line are linked with the values in the "renewable page”.The block to the right addresses "Transmission Links”and contains similar information to the previous block and in this case it is linked with the "transmission page”.The input page also shows information for diesel units that is similar to that contained in the previous blocks. The scenario input page also contains information dealing with escalation of several inputs,the discount rate and the price for exports. The renewable energy page is used to enter information related to each hydro project either existing or future.This information is comprised of capacity and energy capability for each simulation interval in a year (21 composed of 9 months plus 12 intervals for June,July and August), the capital cost,the project life,the earliest in-service year,the variable and fixed operation and maintenance (O&M).Maintenance of individual units is easily simulated by manually adjusting a particular unit's interval capacity value. On the diesel information page one can provide the information for individual diesel plants with up to 10 units each.If more units exist,an additional bus can be created and connected to the load bus through a transmission line.The input required includes the on-line year,the year of retirement (if known),the capital cost,plant life,heat rate,fuel cost,variable O&M cost,fixed Hatch Acres Corporation PR324582.Rev.0,Page 187 AK-BC Alaska Final Report 18-09-07.Doc HATCH ARES O&M cost and monthly capability.Once again maintenance can easily be simulated by derating individual unit capability in an appropriate month or interval. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The transmission page provides information relative to the transmission lines between the different buses.The input required includes the buses to which the line is to connect,the capacity of the line in terms of MW,the capital cost,the life,the fixed costs,the expected losses and the monthly capability.Maintenance is simulated during one or more of the 21 annual intervals by forcing the capacity of the line to 0 MW. Once given the request to start calculations,in the scenario page,RRPM reads,verifies and validates the data.RRPM then determines how the load at each load centre should be supplied under the hydrological condition being simulated.As previously mentioned,the hydro generated energy is dispatched first from its own generation (the load centre being studied)and then from the hydro plants in the priority list as well as those beyond the priority list if such generation exists and the transmission links allow it to be brought into the load centre.After all hydro energy is exhausted,the model considers diesel generation in a similar way as it considered hydro generation.Should the supply be less than the demand,the model considers the difference as unserved energy. RRPM considers capital,fuel and operation and maintenance costs for each of the hydrological conditions.The capital costs are based on annuities for each new generation addition with existing and committed units assumed to have sunk costs.The fuel costs are calculated for each thermal unit by multiplying the respective heat rates by the fuel cost and energy generated at particular locations while the operation and maintenance (O&M)costs considered both fixed and variable costs for all units.The transmission line costs can include annuities for the capital costs (these would be zero if grant funding is assumed),as determined by the model,as well as fixed O&M costs. RRPM also determines,on an interval basis,the amount of energy available for export and this can be valued using a selling price entered by the user.This can be treated as potential revenue and subtracted from the overall costs of supply.Figure 8.2-2 presents a sample output from RRPM under average hydrological conditions and only one load,one hydro plant and one diesel plant are shown as this is for illustrative purposes only and the total costs do not match those presented.In this case the simulation was carried out up to 2031 but this is not shown due to limited space on the page. RRPM presents three pages summarizing the results of the simulations:Minimum,Average and Maximum (see Figure 8.2-2 for an example).These refer to hydrological conditions.Each page provides a summary of the load requirements for each load center as well as calculating the reserve and the unserved energy.The page also provides information on hydro generation,diesel generation,transmission lines and gives a system summary.Under the hydro and diesel heading, information is provided for each plant on available and used capacity and energy,capital charges and O&M charges and for the diesel plants the fuel charges are shown as a separate item.For the transmission heading,the capital charges and O&M charges for each line are provided. The system summary provides a sum of the total charges by year and cumulative to a particular year as well as the respective present values at the discount rate being investigated..There is a Hatch Acres Corporation PR324582.Rev.0,Page 188 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report facility to determine revenues from power sales to outside sources and for determining the total system costs taking into account the value of these sales. When dealing with systems having a significant hydro component it is difficult to forecast future energy production by any of the plants since it is difficult to forecast future hydrological conditions ona year by year basis.One way to mitigate against this unknown is to assign probabilities of occurrence to certain hydrological conditions and the most used hydro conditions are the minimum,average and maximum with others being possible such wet.As mentioned,the model determines the costs for each of the three hydrological conditions and as can be seen from the values shown in the "minimum”page this minimum hydrological condition provides the higher costs because there is less hydro energy thus obliging the diesel units to generate more than would be the case under other hydrological conditions. The probabilities of occurrence of hydrological conditions are also difficult to determine given the lack of hydrological data and in this case it was decided not to consider the maximum hydro generation and assign a probability of occurrence of 20%to the minimum hydro condition and 80%to the average hydro condition. To obtain the values shown in the tables shown below for the costs of the different generation scenarios,the values shown in the "minimum”page are multiplied by 0.2 and added to the value shown in the "average”page multiplied by 0.8. Hatch Acres Corporation PR324582.Rev.0,Page 189 AK-BC Alaska Final Report 18-09-07.Doc Figure 8.2-1 Exhibit 8A -Scenario Definition Page Load Center Renewable Generation Resources Transmission Link Reserve Supply Priority No.Name Bus ID (%)|(MW)1st 2nd |3rd 1 Wrangell 2100 0.0%0.10 2000 2600 2 Petersburg 2200 0.0%0.10 2000 2600 3 Kake 2500 0.0%0.10 2000 2600 4 Ketchikan 1000 0.0%0.10 1100 4200 1500 5 Metlakatla 1500 0.0%0.10 2000 4100 0 POW South 3000 0.0%0.10 0 Coffman Cove}3500 0.0%0.10 0 Naukati 3400 0.0%0.10 6 Unknown 0 0.0%0.10 7 New 0 0.0%0.01 14 New 0 0.0%0.01 15 New 0 0.0%0.01 16 New 0 0.0%0.01 17 New 0 0.0%0.01 Diesel Generation Earliest |Proposed No.Name Bus ID Unit ID On-Line |On-Line 1 Ketchikan 1000 1 2000 2000 2 2040 2050 3 2000 2000 4 2000 2000 5 2007 2007 6 2007 2007 7 2040 2050 8 2040 2050 9 2040 2050 10 2040 2050 2 Wrangell 2100 1 2004 2001 2 2000 2000 3 2000 2000 4 1981 2000 5 2050 2051 6 2050 2051 7 2050 2051 8 2050 2051 9 2050 2054 10 0 Q Earliest |Proposed Circuit |Earliest |Proposed No.Name Bus ID |On-Line |On-Line No.Name ID On-line On-line 1 BlackBear+S.Fq 3000 2000 2000 1 Ketchikan-Metiakatia 4 2011 2014 2 Triangle Lake 1500 2022 2022 2 Ketchikan-SwanLake 1 2000 2000 3 Purple +Chestq 1500 2000 2000 3 Swan-Tyee 1 2041 2011 4 Takatz 2700 2050 2051 4 Tyee-Wrangell 1 2000 2000 5 Ketchikan 1000 2000 2000 5 Wrangell-Petersburg 1 2000 2000 6 Silvis 1000 2000 2000 6 Petersburg-Kake 1 2011 2011 7 BeaverFails 1000 2000 2000 7 Petersburg-Thomas 4 2050 2051 8 Swan Lake 4100 2000 2000 8 Coffman-Naukati i 2050 2051 9 Tyee Lake 2000 2000 2000 9 Coffman-Wrangell 1 2050 2051 10 __{BlindSlough 2200 2000 2000 10 _|Naukati -POW South 1 2050 2051 11 SceneryCreek-}2600 2050 2051 11__|Tyee-BC 1 2000 2000 12 Cascade (Swary 2600 2050 2051 12 Tyee-Wrangell 2 2050 2051 13 |Delta(RuthLakq 2600 2050 2051 13__{Wrangell-Petersburg 2 2050 2051 14 |MahoneyLake 4200 2014 2011 14 |Takatz -Kake 1 2050 2050 15 |WhitmanLake 4200 2010 2010 15 -|Ketgen-Ketchikan 1 2010 2010 46 {Connell Lake 1200 2014 2014 16 [Unknown 1 0 6 17 Cariana Lake 1200 2016 2016 7 New 1 0 0 18 _|SunriseLake 2100 2050 2051 18 jNew 1 0 0 19 _|Anita-Kunk 2100 2050 2051 19 |New 1 0 0 20 {Virginia 2100 2050 2051 20 |New 1 0 0 21 Thoms Lake 2100 2050 2051 21 New 1 0 0 22 {Tyee Inc.Lake¥2000 2050 2051 22 _|New 1 0 0 23 [Reynolds Lake |3000 2050 2051 23.{New i 0 0 24 {Unknown 0 0 0 24 New 1 0 0 25 |New 0 0 0 25 |New 1 0 0 26 New 0 0 0 26 New 1 0 0 27 |New 0 0 0 27 [New 1 0 0 28 |New 0 0 0 28 |New 1 0 0 29 |New 0 0 0 29 {New 1 0 0 30.|New 0 0 0 30 |New 1 0 0 31 New 1 0 0 32 New 1 0 0 33 New 4 0 0 34 [New i 0 9 35 _|New 1 0 0 36___|New 1 0 0 37 New 1 0 0 38 |New 4 0 0 39 New 1 0 0 Page 190 Figure 8.2-2 Sample Output Under Average Hydrological Conditions 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 WRANGELL Peak Demand (MW)4 5 5 5 6 6 6 6 6 6 6 6 7 Load Energy Demand (MWh)22,300 25,832 26,343 26,845 29,121 29,605 30,085 30,555 31,017 31,475 31,924 32,369 32,810 Capacity Reserve (MW)4 3 3 3 3 2 2 2 2 2 2 2 2 Energy Reserve(MWh)0 0 0 0 0 0 0 0 0 0 0 0 0 Unsupplied Capacity (MW)0 0 0 0 0 0 0 0 0 0 0 0 0 Unsupplied Energy (MWh)0 0 0 0 0 0 0 0 0 0 0 0 0 Costs of Unsupplied Energy ($M)0 0 0 0 0 0 0 0 0 0 0 0 0 TYEE LAKE Available Capacity (MW)23 23 23 23 23 23 23 23 23 23 23 23 23 HYDRO Available Energy (MWh)116,750 116,750 116,750 116,750 116,750 116,750 116,750 116,750 116,750 116,750 116,750 116,750 116,750 Capacity Used (MW)11 12 12 12 14 14 14 14 14 15 15 15 15 Energy Used (MWh)45,940 48,733 49,424 50,053 54,859 55,577 56,291 57,009 57,762 58,522 59,295 60,210 61,012 Capacity Losses (MW)0 0 0 0 0 0 0 0 0 0 1 1 1 Energy Losses (MWh)1,382 1,431 1,450 1,467 1,664 1,687 1,710 1,733 1,759 1,785 1,812 1,846 1,873 Capital Charges (M$)0 0 0 0 0 0 0 0 0 0 0 0 0 Fixed Costs (M$)0 0 0 0 0 0 0 0 0 0 0 0 0 Variable Costs (M$)3 3 3 3 4 4 4 4 4 4 4 4 4 Subtotal Costs (M$)3 3 3 3 4 4 4 4 4 4 4 4 4 WRANGELL Available Capacity (MW)9 9 9 9 9 9 9 9 9 9 9 9 9 Diesel Capacity Used (MW)3 4 4 4 4 4 4 4 4 4 4 4 4 Energy Used (MWh)424 873 987 1,098 529 536 543 549 556 562 568 575 581 Capacity Losses (MW)0 0 0 0 0 0 0 0 0 0 0 0 0 Energy Losses (MWh)0 0 0 0 0 0 0 0 0 0 0 0 0 Capital Charges (M$)0 0 0 0 0 0 0 0 0 0 0 0 0 Fixed Costs (M$)0 0 0 0 0 ie]0 0 0 0 0 0 0 Variable Costs (M$)0 0 0 0 0 0 0 0 0 0 0 0 0 Fuel Costs (M$)0 0 0 0 0 0 0 0 0 0 0 0 0 Subtotal Costs (M$)0 1 1 1 1 1 1 1 1 1 1 1 1 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 System Summary Grand Total Costs (M$)17.3 18.9 19.9 19.1 19.4 20.8 21.6 23.1 24.0 25.0 26.3 27.3 28.3) Cumulative Costs (M$)17.3 36.1 56.0 75.1 94.5 115.3 136.8 160.0 184.0 209.0 235.3 262.6 290.9) Grand Total Costs in PV(M$)16.8 17.3 17.2 15.6 14.9 15.1 14.8 14.9 14.6 14.4 14.3 14.0 13.7 Cumulative Costs in PV(M$)16.8 34.0 §1.2 66.8 81.7 96.8 111.6 126.5 141.2 155.5 169.8 183.8 197.4 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Revenue Summary -Export Energy (MWh)65,244 62,642 61,995 61,408 78,210 72,771 70,856 72,895 70,967 71,492 69,590 67,686 65,794 Export Revenue (M$)0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000; Cumulative Revenue (M$)0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Export Revenue in PV(M$)0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Cumulative Revenue in PV(M$)0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000) 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Net Costs Summary Net Costs (M$)17.3 18.9 19.9 19.1 19.4 20.8 21.6 23.1 24.0 25.0 26.3 27.3 28.3 Cumulative Net Costs (M$)17.3 36.1 56.0 75.1 94.5 115.3 136.8 160.0 184.0 209.0 235.3 262.6 290.9) Net Costs in PV(M$)16.8 17.3 17.2 15.6 14.9 15.1 14.8 14.9 14.6 14.4 14.3 14.0 13.7 Cumulative Net Costs in PV(M$)|16.8 34.0 51.2 66.8 81.7 96.8 111.6 126.5 141.2 155.5 169.8 183.8 197.4 Page 191 HATGH AGEN Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 8.3.Existing Generation and Transmission Infrastructure SE Alaska has a number of existing hydroelectric plants and diesel plants.Each load center has enough local generation to meet the peak load with its own local generation and some load centers are served by energy generated at remote hydro plants that is delivered by a transmission line.The existing hydro,diesel and transmission facilities are described below. 8.3.1 Hydro Generation In SE Alaska there are 10 hydroelectric plants.The power plants in each of the regions outlined in Section 8.2 can be summarized as: REGION |PLANT CAPACITY (MW) Tyee Tyee Lake 22.5 Blind Slough 2.0 Swan Swan Lake 22.5 Ketchikan 4.2 Beaver Falls 6.0 Silvis 2.1 Purple Lake 3.9 Chester 1.0 POW*Black Bear 4.5 South Fork 2.0 Total 70.7 *POW -Prince of Wales The total hydro capability in SE Alaska amounts to 70.7 MW with 39.7 MW in the Swan Region, 24.5 MW in the Tyee Region,and 6.5 MW in the POW region. Table 8-1 (reproduced with all other tables at the end of this section)presents the capability of each of the hydro plants on a monthly and annual basis for three hydrological conditions;average, minimum and maximum.Under the average condition the hydro plants annual energy capability amounts to 326.7 GWh.The largest monthly capability is in December and January while the smallest is in April and May (for the three regions as a whole the lowest monthly amount is over 80%of that for the maximum month)but it should be noted that these values do not necessarily reflect the monthly inflows as storage capability at some of the plants was used to derive the monthly energy capability. Under average hydro conditions the annual capacity factors range from 36.6%for Swan to 73.1% for Beaver Falls.The overall system capacity factor is close to 53%. Table 8-1 also presents the annual operation and maintenance costs for each hydroelectric plant and these range from $127,000 for Blind Slough to $1,275,000 for Tyee Lake and the same amount for Swan Lake. Hatch Acres Corporation PR324582.Rev.0,Page 192 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGE 8.3.2 Diesel Generation Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report In SE Alaska there are many diesel plants with units ranging in size from a few kWs to 10.5 MW. The total capability of these units amounts to 56.65 MW of which 26.0 MW are available in the Swan region,23.19 MW in the Tyee region and 10.76 MW in the POW region.In Ketchikan one of the Worthington units is out of service and it has not been included in the total capability. The capability of the existing units by load center is: REGION |LOAD CENTER |CAPACITY (MW) Tyee Wrangell 8.50 Petersburg 8.80 Kake 2.59 Swan Ketchikan 22.70 Metlakatla 3.30 POW POW South*2.10 Coffman Cove 0.74 Naukati 0.48 Whale Pass 0.30 Total 56.65 *POW South includes the communities of Craig,Hollis,Hydaburg,Klawock,Kasaan and Thorne Bay Table 8-2 (at the end of this section)presents information relative to the characteristics of all the diesel units in SE Alaska.Most of the information presented in Table 8-2 was obtained directly from the utilities in Southeast Alaska.The present study defined the values for fixed and variable O&M based on information available in our databank.The annual fixed O&M for the larger plants was taken as 40 $/kW while for the smaller plants the fixed O&M was taken at 60 $/kW and the variable O&M was taken as 20 $/MWh for the larger plants and 25 $/MWh for the smaller plants. For the Swan and Tyee Regions,the units presented in the table were commissioned between 1971 and 2001 and this represents a wide range in the age of the units.The earliest commissioned units have been in operation over 35 years but also of importance is the hours of operation of each of the units and as can be seen from the values presented in Table 8-2 these are somewhat low for the age of the units.It should be noted that the duty cycle of most of these units is of the back up and emergency type (with exception of units at Kake and isolate load centers on POW)and therefore these units operated very few hours in the past. The condition of the units in the Swan and Tyee Regions ranges from fair to excellent with most units being reported as being in good condition.The fuel consumption ranges from 8.8 kWh per gallon to 150 kWh per gallon of Diesel Oil (No.2)fuel with the best efficiency being obtained by the largest unit in the system (10.5 MW)located in Ketchikan. Table 8-2 presents information by plant for the POW units.Table 8-3 presents individual unit information for afl the units in POW.The total diesel capability in POW amounts to 10.73 MW with individual unit sizes ranging from 70 kW to 1,285 kW for a unit at Craig.The Craig diesel plant accounts for over 53%of the total diesel capability in POW.The second largest plant is the Thorne Bay plant with 1,075 kW.The information received did not include the commissioning year for several of the units but it included the operating hours for each of the plants and six of the Hatch Acres Corporation PR324582.Rev.0,Page 193 AK-BC Alaska Final Report 18-09-07.Doc nav ACHES units have already reached at least 50,000 operating hours with a unit in Hydaburg having operated more than 100,000 hours. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Since all of the communities in POW South are now connected,it is expected that diesel operation will be reduced from that in the past as hydro energy is now available to meet the demand.The fuel consumption ranges from 10.00 kWh per gallon to 15.79 kWh per gallon with the highest value being achieved by the largest diesel unit in POW. It is recognized that several diesel units in SE Alaska have been service close to 30 years and in some cases longer and that some time in the future some of the units will be taken out of service and probably be replaced by larger more efficient units.For the present study it was decided to keep all units throughout the study period since the decision to retire individual units is based on economics and several operating factors and requires an in depth study that is considered beyond the scope of this study. 8.3.3 Existing Transmission There are only two high voltages transmission lines in SE Alaska.One high voltage transmission line (115kV)connects the output of the Swan Lake hydroelectric plant to the Ketchikan load center at the Bailey Substation. The other high voltage transmission line is used to supply the communities of Wrangell and Petersburg with electricity generated at the Tyee Lake hydroelectric plant.This line is presently operated at 69 kV.However,the transmission line was designed and built with a capability of operating at 138 kV.The step up transformers at Tyee Lake and the step down transformers at Wrangell and Petersburg are dual voltage (69 and 138 kV)and the switchgear is rated at 138 kV. Switchover to the higher voltage can be carried out with a minimum cost and disruption of supply. Lower voltages are used in the regions to connect the hydro and diesel plants to the load centers. In POW,the principal communities in the southern part are all interconnected via 34.5 kV transmission lines. 8.4 Planning Parameters The planning parameters used in the analysis are presented and discussed in this subsection.These parameters include technical and economic parameters such as discount rate,escalation rates,fuel prices and O&M costs of transmission lines. 8.4.1 Planning Horizon The planning horizon covers a period of 25 years from 2007 to 2031. At the end of the Planning horizon,the various expansion scenarios could have different plant mixes with different remaining lives and different operation and maintenance costs as well as different investment costs. In order to measure all substantive benefits of the plants that are commissioned during the planning horizon and take into account different plant lives,it is a common practice to extend the period of analysis by 10 to 15 or more years.For the extended period,demand and supply are maintained at Hatch Acres Corporation PR324582.Rev.0,Page 194 AK-BC Alaska Final Report 18-09-07.Doc HATCH AGRE the same level as at the end of the simulation period.An extended period of analysis of 15 years was used in this study. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 8.4.2 Reserve A deterministic criteria was selected to determine the generation reserve that should be in place at each load center.For the present study,the reserve criterion adopted was that each load center should have sufficient local generation to be able to meet the expected peak demand.For the purposes of the study,local generation is defined as the diesel and hydroelectric generation connected directly to each load centre.Thus the generation available at the Swan Lake and Tyee Lake hydroelectric plants is not included in the capability of any load center.However,for example,the output of the Silvis and Beaver Falls hydroelectric plants is taken into account when determining the local generation for Ketchikan. 8.4.3 Unserved Energy It is possible that during some time periods some of the load centers may not have sufficient supply available to meet the entire demand requirement.In this case,the deficit is referred to as "unserved”energy.To evaluate the impact of the unserved energy on the overall cost of the generation alternative being evaluated it is customary to place a relatively high value on this type of energy to reflect the deemed cost to society of the shortfall.For this study a value of 1,000 $/MWh was assumed as the cost of unserved energy. 8.4.4 Energy Losses The transmission lines connecting the various generating centers with the load centers have inherent losses that are dependent upon the power being transmitted.For this study,a simplified approach has been taken by assuming that all transmission segments would encounter losses of the order of 2%.This value can be refined once detailed load flow studies are carried out. 8.4.5 Discount Rate Following the practice in previous power sector studies performed for SE Alaska,a discount rate of 6%was used in the study.For the sensitivity analysis,discount rates of 8%and 10%were used to test the robustness of selected generation alternatives to the discount rate. 8.4.6 Escalation An assumed annual inflation rate of 2.5%was used on all items except the energy being generated and sold by the Swan Lake and Tyee Lake hydroelectric plants. 8.4.7 Reference Year for Present Value Analysis The reference point for the present value analysis is January 1,2007.This implies that all costs are discounted to the beginning of 2007.It should be noted that the model used for the analysis assumes that all costs are incurred at the middle of the year. Hatch Acres Corporation PR324582.Rev.O,Page 195 AK-BC Alaska Final Report 18-09-07.Doc nATGH AGH 8.4.8 Capital and O&M Costs of Transmission Lines Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Capital costs of the future transmission lines required to connect the various load centers and regions and to export surplus power were assumed to be grant funded implying that there will be no Capital recovery to be considered in the financial analysis of these projects.The costs of transmission lines to connect new generation projects to the system are generally assumed to be included in the projects'capital cost and usually form a small portion of the overall project cost. The Thomas Bay projects would require the construction of transmission lines and submarine cable connections from the project sites to Petersburg and,as shown in Section 6.4.1,the cost of these facilities would be significant.The capital costs for these connections are not included in the studies to evaluate the generation options to meet SE Alaska requirements and for export as it was assumed that state grand-funding would be provided. For the transmission line to connect the Coffman Cove and Naukati load centers to the other load centers in POW South,two alternatives were considered;one with grant funds and another with a capital recovery component for the $5.1 million which corresponds to the estimated cost to build the transmission lines. The annual O&M cost for the existing lines was not used in the study as they were considered to be common to all alternatives.The annual O&M costs for the new transmission segments considered in the analysis are: TRANSMISSION SEGMENT O&M COST ($) Tyee -BC Border 360,000 AK-BC Border to Connection in BC 450,000 Swan -Tyee 500,000 Thomas Bay -Petersburg 810,000 Petersburg -Kake 210,000 Kake -Takatz 1,200,000 Ketchikan -Metlakatla 125,000 Coffman Cove -Wrangell 1,300,000 Coffman Cove -Naukati -POW South [*]40,000 *Assumed value 8.4.9 Fuel Prices The present fuel prices at each load center were obtained from the respective utilities and are presented in Table 8-4.The fuel prices vary by load center and they range from $2.20/gallon (Ketchikan)to $2.68/gallon (Wrangell).These fuel prices were assumed to reflect a crude price in the NIMEX market of the order to 61.00 $per barrel which could be translated to a base value (reference price)for diesel Oil (No.2)of $1.76/gallon.This base value was used to calculate the additional costs to bring the fuel to each community. The future price of fuel is an important determinant of the overall outcome of the economic analysis.Thus the fuel price forecast is of significant importance.For this study,several sources were consulted regarding fuel forecasts and the forecast produced by the Energy Information Administration (EIA)of the U.S.Department of Energy in its Annual Energy Outlook dated March 2007 was selected. Hatch Acres Corporation PR324582.Rev.0,Page 196 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES When the values shown in the EIA forecast are converted to 2007 prices,the average price for low sulphur light sweet crude oil amounts to 57.12 $per barrel.By using the appropriate conversion factors this is equivalent to $1.65/gallon for diesel oil (No.2).To this value,the additional costs calculated with the existing prices were added to arrive at the future delivered price for diesel oil (No.2). Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 8-4 also presents the future price at each load center for diesel oil (No.2). 8.4.10 Cost of Energy from Swan Lake and Tyee Lake Hydros Energy sales from Swan Lake and Tyee Lake were attributed an average cost of 64.00 $/MWh for the scenarios where the STI would not be commissioned.In the scenario where the STI would be commissioned early during the study period,an average cost of 53.00 $/MWh was used in the study.It should be noted that annual revenues for the two scenarios would be the same but since in the case of the STI the current surplus energy at Tyee Lake could be delivered to the loads,the unit cost of energy would decrease. 8.4.11 Cost to Society of Greenhouse Gas and Other Emissions No cost was included although it is recognized that some of the alternatives include significant amounts of generation by diesel plants using No.2 fuel oil.Section 8.11 presents estimates of the avoided emissions for selected generation expansion cases.However,those avoided emissions have not been assigned a monetary value in the economic analysis. 8.4.12 Ownership The analysis of this section is based on economic costs rather than financial costs.This implies that the analysis is based on economic values that do not take into account such factors as the imposition of taxes or royalties by government or any risk premium that might be charged by private sector investors.Government taxes and royalties are not included in the calculation of economic costs,as these are a transfer payment between one group in the economy and another, rather than a cost to the economy as a whole.Economic costs are used to determine what the appropriate choices would be from the point of view of the Alaskan economy and society as a whole. Thus in the economic analysis that has been carried out,the ownership of a project does not have an impact on the costs of transmission lines,hydroelectric and thermal generation projects. 8.5 Development Projects Considered As shown in Section 3 of this Report,the load in SE Alaska is expected to grow during the study period.To meet the increased requirements,the system will rely on hydroelectric projects,diesel plants and transmission facilities to serve these load centers.Only diesel plants were considered as thermal resources since they were considered to be the most appropriate technology to supply the demand given its requirements and the resources available at each load center. Hatch Acres Corporation PR324582.Rev.0,Page 197 AK-BC Alaska Final Report 18-09-07.Doc HATH AGEN 8.5.1 Hydro Projects Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report There are several hydroelectric projects that could be developed to meet the growing demand in SE Alaska and possibly to export energy to BC and the Lower 48 states.This phase of the study considers the 15 projects listed in Table 8-5 as candidates projects.These candidate projects are located in the 3 regions under study:1 project located in POW,5 projects in the Swan region,and the remaining 9 in the Tyee region. The candidate hydroelectric projects range in capability from 0.8 MW to 45 MW and their capacity factors range,under average hydrological conditions,from 13.9%to 71.5%.Table 8-5 also presents the monthly energy distribution for each candidate hydroelectric project as well as the corresponding annual values.It should be noted that the values shown for the Tyee project are for the total project but when this project was considered in the study only the incremental values were used, The monthly energy values presented in Table 8-5 indicate that most projects are run of river without storage facilities,the exception being the Takatz and Tyee projects. Table 8-6 presents cost data for the candidate hydroelectric projects including capital costs and O&M cost.Assuming a discount rate of 6%and an economic life of 50 years,the annual capital charges were determined and are presented in Table 8-6.The unit cost of energy was determined taking into account the annual capital charges plus the annual O&M charges divided by the annual average energy.For purposes of this analysis,we used levelized as opposed to nominal costs. Levelized costs spread the costs over the 50-year term of the FERC license as opposed to nominal costs that reflect the initial term of financing for a project developed in the private sector. As can be seen from the values presented in Table 8-6,the levelized unit cost of energy varies between 45.42 $/MWh and 374.80 $/MWh.The levelized unit cost of energy for the most promising projects is summarized below: LEVELIZED PROJECT UNIT COST OF ENERGY ($/MWh) Whitman Lake 45.42 Mahoney Lake 54.02 Scenery Lake 54.80 Connell Lake 56.63 Cascade (Swan)58.01 Carlanna Lake 70.71 Delta (Ruth)70.36 Tyee Lake Extension 90.96 Triangle 91.44 Triangle 91.44 Table 8-6 also presents the earliest in-service date for each project.Whitman Lake and Mahoney Lake could be in-service by 2010 whereas the Tyee extension project could be in-service by 2012. Hatch Acres Corporation PR324582.Rev.0,Page 198 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Absent current information regarding the development schedule,all other projects were considered have the potential to be in-service by 2015. The Tyee Lake Extension project mentioned in the above table refers to the addition of a third generation unit at the Tyee Lake hydroelectric plant. It is noted that the "Levelized Unit Cost of Energy”derived in this section (as shown in the above table)is defined on a different basis from the "Cost of Power”shown in Section 7.2.3.The two calculations each use the same assumptions on the total estimated capital investment and annual operating and maintenance costs for each of the potential new hydropower developments.The calculation methods used for each calculation are described in the respective sections. 8.5.2 Diesel Units Table 8-7 presents the characteristics of candidate diesel units to meet the increasing demand in South Southeast Alaska.Several unit sizes were selected since there are several unit sizes in operation and each load center would have its own size requirements. The technical and cost data were obtained from our in-house data base.High speed diesel technology was selected for the smaller sizes.The fuel consumption values shown are typical and reflect life cycle values and are for mid range duty which implies that these could be higher when operating only a few hours per week. The capital costs consider North American supply with units to be installed within a building with all controls and required equipment. 8.5.3 Transmission The transmission lines to be considered for the present study can be divided into two groups:those required to connect new generation to the load centers and those to connect load centers. In the first group one finds only two transmission lines.The first would be necessary to connect the output of the Thomas Bay projects to Petersburg and the timing of this line should coincide with the in-service date of those projects.The second transmission line would be necessary to connect the Takatz hydroelectric project to Kake and due to the distances between the two locations,geography and topology,this connection would require a submarine cable as well the use of HVDC technology. The second group includes several transmission lines.The proposed Swan-Tyee Intertie (STI) would connect the Tyee Lake Project near Wrangell with the Swan Lake Project near Ketchikan. The STI is partially constructed and a proposal to secure grant funds to complete this segment is pending.The STI would transfer power between Tyee and Swan in both directions. The Kake to Petersburg transmission line (KPTL)has been recommended by several studies to be built as a 69 kV transmission line,however,this voltage could limit or hinder a future connection with other electrical systems in the northern sector of SE Alaska.This voltage is used in this study, but serious consideration should be given to higher voltages for the KPTL. Hatch Acres Corporation PR324582.Rev.0,Page 199 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES The Metlakatla to Ketchikan 34.5 kV transmission line could allow the transfer of power between these two load centers and encourage development of hydro projects in both load centers for mutual assistance. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report A proposed 34.5 kV transmission line would connect the load centers of Coffman Cove and Naukati with POW South.This line segment would transmit lower cost power generated by the hydro plants in POW South to supply Coffman Cove and Naukati. A connection between POW and the Tyee region in SE Alaska via a submarine cable connecting Coffman Cove and Wrangell is under consideration.This would be an HVDC connection. The final transmission line under consideration is the AK-BC Intertie,a line from the Tyee Lake plant to the BC border to transmit power generated by hydroelectric facilities in SE Alaska to BC and the Lower 48. 8.6 Capacity and Energy Balances Studies were performed to determine the capacity and energy balance for each of the SE Alaska load centers under study to obtain the system needs under a range of conditions regarding existing and committed generation.Since many load centers in SE Alaska are heavily dependant on energy produced by hydroelectric plants,the balance for the energy component was calculated using the minimum generation capability of the hydro plants. In carrying out the capacity and energy balances,the only resources taken into account were the deemed local generation and as such the Swan and Tyee hydro plants capabilities were not considered.The capacity and energy balances were carried out based on annual values.The Capacity reserve required for different load centers was based on the loss of the largest diesel unit if the load center was not connected to any major hydro plant or the capacity reserve was neglected if the load center was connected to a major hydro plant. 8.6.1 Kake Table 8-8 presents the capacity and energy balance for Kake as if this load center was to remain isolated from Petersburg and Wrangell.As can be seen,there is a capacity excess up to 2020 and further investigation showed this capacity excess to occur until the end of the study period. The current generation in Kake is capable of meeting the load center's projected energy needs well past 2020. 8.6.2 Petersburg and Wrangell Table 8-9 presents the capacity and energy balance for Petersburg.Under the reference load growth forecast,there could be a capacity deficit by 2017 and this deficit could increase to about 2.1 MW by 2031.There are no energy deficits during the study period. Table 8-9 also shows the capacity and energy balance for Wrangell.There are no capacity or energy deficits during the study period. Hatch Acres Corporation PR324582.Rev.0,Page 200 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGES 8.6.3 Ketchikan and Metlakatla Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Table 8-10 presents the capacity and energy balance for Ketchikan.As can be seen,under the reference growth load forecast,a capacity deficit is expected by 2010.This deficit is expected to grow to 9 MW by 2020 and could reach 15.5 MW by 2031.Thus the Ketchikan load center requires generation capacity additions amounting to at least 15.5 MW during the study period and should some of the existing diesel generation be retired during the study period then additional units would have to be commissioned. As shown in Table 8-10,the Ketchikan load center is expected to have an energy deficit by 2019 and this deficit could increase to about 35,000 MWh by the end of the study period but as new units are commissioned to meet the capacity deficit,this energy deficit is expected to be reduced significantly. Table 8-10 also shows the capacity and energy balance for Metlakatla.There are no capacity or energy deficits during the study period. 8.6.4 POW Table 8-11 presents the capacity and energy balance for the POW South communities as well as Coffman Cove and Naukati.Under the reference growth load forecast,there are capacity and energy excesses up to 2020.The excesses continue during the study period. 8.6.5 SE Intertie Development Scenarios Considered to Date Proposals and investigations with the goal of interconnecting the communities of SE Alaska with an electrical transmission grid (SE Intertie)have been considered for decades.In 1997 a group of utilities and communities formed a committee under the leadership of the Southeast Conference and engaged Acres International to perform a study and propose a long-term plan,including phased development and estimated costs in support of a proposed electrical intertie system to interconnect isolated load centers;increase system reliability;reduce or avoid diesel dependence;encourage economic development;and stabilize and equalize rates.The Acres study provided recommendations for implementing a reliable Intertie system in five phases.The Southeast Conference and its members,working closely with the Alaskan Congressional delegation in Washington,D.C.,secured passage in 2000 of a bill authorizing the intertie project that included Federal expenditures in the amount of $384,000,000,equal to 80 percent of the system cost,and requiring a 20 percent local match requirement.. The Five Phases investigated in 1997 included potential development scenarios presented in this report.Since 2000 two segments of the SE Intertie have received federal funding as authorized by §.2439. 8.6.6 SE Intertie Segments Currently Under Development with Federal Funds to Date The Swan-Tyee Intertie (STI)segment has been designed,permits secured,and the project is partially constructed.Completion of the STI is dependent on funding by the State of Alaska.The STI is an integral element to the Development Scenarios discussed in this section of the report. Hatch Acres Corporation PR324582.Rev.0,Page 201 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The Juneau to Hoonah Intertie segment is under construction by the Kwaan Electric Transmission Intertie Cooperative,Inc.(KWETICO).This segment will connect Alaska Electric Light &Power Company's (AEL&P)transmission infrastructure to Inside Passage Electric Cooperative,Inc.'s (IPEC) distribution system serving Hoonah on Chichagof Island,replacing current high-cost diesel generation with low-cost hydro-generated power The second proposed segment under consideration by KWETICO is the Kake-Petersburg transmission segment that would interconnect IPEC's system on Kupreanof Island with the FDPPA existing transmission segment between Petersburg/Wrangell and the Tyee Lake Project and provide low-cost hydro power to an area solely dependent on high-cost diesel-generated power'”'. 8.7.Development Scenarios in SE Alaska without Exports As mentioned in Section 8.2 SE Alaska was divided into three main regions and generation expansion scenarios for each of these regions were formulated,developed,analyzed and evaluated. In addition,scenarios considering regional connections were also investigated. 8.7.1.Generation Expansion Scenarios for the Tyee Region The Tyee region is composed of the Petersburg,Wrangell and Kake load centers.Kake's demand is being supplied by local diesel generation.Petersburg's demand is supplied by local hydro,local diesel and electrical energy from the Tyee Lake hydro plant.Wrangell's demand is supplied by local diesel and electrical energy from the Tyee Lake hydro plant.A transmission line operated at 69 kV but designed and constructed for 138 kV operation connects the Tyee Lake hydro plant to Wrangell and from there to Petersburg. As identified in the previous section,Petersburg is the only load center in the Tyee region that requires capacity additions during the study period and in order to meet the reserve criterion it was decided to install a 2 MW diesel unit by 2017 at that load center. The RRPM was used to determine the costs associated with supplying the Tyee region load centers demand assuming continuing supply from existing resources. The next step taken was to estimate the year that a connection between Kake and Petersburg could be economic.This was done by dividing the estimated annual O&M cost of the transmission line to connect these load centers by the variable cost of diesel generation minus the cost of Tyee Lake energy.The resulting value indicated that if about 1,450 MWh of diesel generation could be displaced by Tyee Lake generated energy,the connection would be economic and since the load at Kake is greater that that value,such a connection would be economic as soon as it would be operational.However,considering the lead time to place this line in operation,it was decided that the first in service date would be January 1,2011. The RRPM was rerun considering a transmission line between Kake and Petersburg starting in 2011.The present value of costs of supplying the Tyee region demand,from 2007 to 2031 and a "?KWETICO included the Kake-Petersburg Transmission Intertie in its Application for New Certificate of Public Convenience and Necessity;and Request for Public Interest Exemption filed with the RCA under U-05- 100 on December 21,2005. Hatch Acres Corporation PR324582.Rev.0,Page 202 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report further evaluation period of 15 years,under the two alternatives described above can be summarized as: Table 8.7-1:Cost of Expansion for the Tyee Region C.P.V.of Costs to January 2007 ($,million) Scenario Discount Rate 6%8%10% Wrangell +Petersburg &Kake 117.0 90.1 72.1 Isolated Wrangell +Petersburg +Kake 109.4 84.9 68.3 Connected in 2011 Benefits of Connection of Kake 7.5 5.2 3.8 Note:C.P.V.stands for Cumulative Present Value The above results indicate that the connection of Kake to Petersburg is economic from its first possible in service year,delay in the connection would decrease the benefits. The transmission voltage for this connection is being mentioned elsewhere in the report as being 69 kV.Serious consideration has to be given to this voltage level for this transmission segment as this voltage could jeopardize future development in Southeast Alaska,namely the connection of the Tyee region to regions to the North. 8.7.2.Generation Expansion Scenarios for the Swan Region The Swan region is composed of the Ketchikan and Metlakatla load centers.Ketchikan's demand is being supplied by local hydro,local diesel and electrical energy from the Swan Lake hydro plant. Metlakatla's demand is supplied by local hydro and local diesel.A transmission line operated at 115 kV connects the Swan Lake hydro plant to Ketchikan. As identified in the previous section,Ketchikan requires capacity additions by 2010 and this rises to a need for new capacity of 15.5 MW by 2031.This new capacity could be obtained either from diesel generation or the hydro resources available in the region.As diesel generation is relatively more expensive than hydro generation and the hydro projects available to be brought into service are not much larger than the load requirements it was decided to meet Ketchikan capacity and energy requirements with new hydroelectric resources. Item 3 in Table 8-12 presents the development sequence of new hydro projects to meet Ketchikan's capacity and energy requirements when supplied in an isolated fashion.Four hydro projects were considered to be developed during the study period to meet both capacity and energy requirements.Even though only one hydro plant would be needed in the earlier years,it was decided to have both Whitman Lake and Mahoney Lake on line in order to displace expensive diesel generation.With both Whitman Lake and Mahoney Lake in place,further capacity additions would only be required by 2029 but since the diesel generators at Ketchikan would be producing close to 20,000 MWh by 2015 it was decided to advance Connell Lake to its earliest in service date.The in service date of Carlanna Lake was determined by its costs and capability to displace diesel generation. Hatch Acres Corporation PR324582.Rev.0,Page 203 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Item 4 in Table 8-12 presents the generation additions to meet Metlakatla's capacity and energy requirements when supplied in an isolated way.According to the capacity and energy balances, Metlakatla does not need generation additions to meet capacity and energy requirements. However,when carrying out preliminary system simulations it was noticed that significant amounts of diesel generation were required past 2020.In order to curtail diesel generation and decrease cost,the Triangle hydro project was assumed to be commissioned by 2022. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report A generation expansion scenario was developed whereby the load centers of Ketchikan and Metlakatla would be connected.The resulting expansion scenario is shown in item 5 of Table 8-12 and as can be seen the Triangle hydro project was advanced because it could supply energy to Ketchikan that would compensate for its advancement. The most economic in-service date for the connection of Ketchikan and Metlakatla was 2013.This connection was beneficial to both load centers in terms of displaced diesel energy.From 2013 to 2031 some 21,600 MWh of diesel energy was displaced in Ketchikan when compared to the isolated scenario and some 7,800 MWh in Metlakatla. The present value of costs for supplying the Swan region's demand,from 2007 to 2031 and a further evaluation period of 15 years,under the two alternatives described above can be summarized as: Table 8.7-2:Cost of Expansion for the Swan Region C.P.V.of Costs to January 2007 ($,million) Scenario Discount Rate 6%8%10% Ketchikan Isolated 271.9 212.9 173.2 Metlakatla Isolated 25.3 19.8 15.8 Ketchikan +Metlakatla Connected 294.0 230.9 188.2 in 2013 Benefits of Connecting Ketchikan &3.2 1.8 0.8 Metlakatla The above results indicate that the connection of Ketchikan and Metlakatla is economic from 2013 and delay in the connection would decrease the benefits. 8.7.3 Generation Expansion Scenarios for the POW Region The energy and capacity balance section shows that during the study period there are no deficits in the POW region.For study purposes,the region has been divided into POW South and the load centers of Coffman Cove and Naukati.The POW South load centers are all connected via 34.5 transmission lines and are supplied from the Black Bear and South Fork hydro plants as well as from diesel units located at each load center.Coffman Cove and Naukati are relatively small load centers supplied by local diesel generation. During preliminary system simulations with the RRPM it was noticed that the load centers in POW South during certain periods of the year were absorbing all the hydro generation and producing Hatch Acres Corporation PR324582.Rev.0,Page 204 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGEN some diesel generation.To reduce costs and displace the diesel generation,it was decided to include the Reynolds Creek hydro project and the most economic in-service date for this project was found to be 2021.Based on new data received for the capital cost of Reynolds Creek,just before the Draft Final Report was issued,an in service date outside the planning period may be more suitable for this project. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Following the development of the generation expansion scenarios for the case where the load centers would continue to be isolated,two additional generation expansion scenarios were evaluated;one considering the capital cost and O&M cost of a 34.5 kV transmission line to connect Coffman Cove and Naukati to the POW South load centers and another considering only the O&M cost of the transmission line.The transmission line would be in service by 2011. The present value of costs for supplying the POW region's demand,from 2007 to 2031 anda further evaluation period of 15 years,under the three scenarios described above can be summarized as: Table 8.7-3:Cost of Expansion for the POW Region C.P.V.of Costs to January 2007 ($,million) Scenario Discount Rate 6%8%10% POW South +Coffman Cove &58.3 44.4 35.1 Naukati POW Connected in 2011 &with 60.5 46.9 37.7 Capital &O&M POW Connected in 2011 &with 55.8 42.6 33.8 O&M Costs Only Benefit of Connecting 2 centers 2.5 1.8 1.4 with O&M Costs Only The above results indicate that the connection of the Coffman Cove and Naukati load centers to the load centers of POW South is not economic if both the capital cost and O&M cost of the transmission line required for the connection is included in the calculations.However,the connection is economic if only the O&M of the transmission line is included in the costs. 8.7.4 Connection of the Swan and Tyee Regions The connection of the Swan and Tyee regions requires that a transmission line be in place between the Tyee Lake hydro plant and the Swan Lake hydro plant,the Swan Tyee Intertie (STI).Significant work has been already done on the STI (see Section 6.2 of this Report for a detailed discussion). The Four Dam Pool Power Agency (FDPPA)has a request pending before the State decision-makers to authorize funds to complete the STI.The Governor's budget proposal includes some of the requested additional funding.The STI will enable the FDPPA to optimize generation at Tyee Lake and decrease spilling as the existing surplus could be used to meet Ketchikan's energy needs. The STI is approximately 57 miles long with no submarine crossings.It would be constructed for 138-kV nominal voltage but would be operated initially at 69-kV. Hatch Acres Corporation PR324582.Rev.O,Page 205 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Generation expansion plans were developed for the Swan and Tyee regions considering that the STI would be in place by 2010.Item 6 in Table 8-12 presents the generation additions as well as their timing.It should be noted that since the STI would be bringing energy into the Ketchikan area,some of the local hydro plant additions should be delayed as utilization of their generation would be curtailed.The analysis indicated that Mahoney Lake should be delayed 4 years,Triangle Lake should be delayed by 6 years and the Carlanna Lake hydro project should be delayed beyond the study period. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The present value of costs for supplying the Swan and Tyee regions'demand,from 2007 to 2031 and a further evaluation period of 15 years,either individually or in a connected way can be summarized as: Table 8.7-4:Cost of Expansion for the Swan Tyee Regions C.P.V.of Costs to January 2007 ($,million) Scenario Discount Rate 6%8%10% Isolated Supply of Swan and Tyee 403.4 315.8 256.5 Demand Swan and Tyee Connected in 2010 370.2 288.8 233.7 Benefit of STI 33.2 27.0 22.8 The above results indicate that the STI is economic from its first possible in service year.Delay in the connection would decrease the benefits. The utilization of the energy that could be produced by individual hydro plants in the scenario without the STI and in the scenario with the STI is shown in Figures 8-1 and 8-2 respectively.The figures are provided at the end of this Section 8. 8.7.5 Connection of the POW Region to Other Regions Studies were undertaken to verify the economic viability of connecting the POW load centers to the Wrangell substation.The connection of the POW load centers would involve the construction of a submarine cable link,50 miles long utilizing HVDC technology.The capital cost of this link is quite high and the annual O&M charges have been estimated at $1,300,000. In order for the link to be economically viable,the annual O&M charges would have to be offset with gains from displaced diesel energy.The diesel generation is expected to cost about 164 $/MWh and hydro energy from either Swan Lake or Tyee Lake would cost about 53 $/MWh and this would result in an overall net savings of 111 $/MWh. Dividing the annual O&M cost of the connection between POW and Wrangell by the overall net savings ($1,300,000 /111$/MWh)provides the amount of energy that would have to imported into POW for the connection to be economic and in this case this energy amounts to about 11,700 MWh. Hatch Acres Corporation PR324582.Rev.0,Page 206 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACHES The diesel energy generated in POW by 2031 amounts to only 7,000 MWh and in this case the connection would not be economic. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 8.8 Development Scenarios in SE Alaska with Exports Generation expansion scenarios considering sales of energy generated within SE Alaska to entities either in BC or in the Lower 48 states were developed.Under this arrangement hydro projects would be developed in SE Alaska and their energy would be able to meet the demand in SE Alaska first with the remaining surplus available for sale to entities outside SE Alaska. Under this scenario,a transmission line (AK-BC Intertie)would be built from the Tyee Lake hydro plant to the AK/BC border to make the sales of the surplus energy possible.Losses on this line were assumed to be 2%with a further 6%to be encountered from the border to the final buyer.The sales at the border were valued at 60 $/MWh. From the list of projects presented in Section 8.5 it was determined that the most economic projects available for export were the Thomas Bay projects.The transmission line would originate at the power house of the closest project,the Cascade Creek powerhouse and substation,located near tidewater.The other two projects at Thomas Bay would include infrastructure to connect and transmit their generated energy to the substation at Cascade Creek.Power from Thomas Bay projects would be transmitted from Thomas Bay across Frederick Sound to a new substation southwest of Petersburg.From there the power would be transmitted on the existing transmission line that connects Petersburg to Wrangell and the Tyee Lake hydro plant.Losses were assumed at 2%for each transmission segment between the collection point and Tyee Lake. For the generation expansion plan it was decided to start with the plan for the STI scenario and make revisions to it as required.The development of the Thomas Bay plants was considered to be staged.Cascade Creek would be the first plant to be commissioned,followed 2 years later by Scenery Lake and 2 years after that the Delta Creek plant would be commissioned.The Cascade Creek hydro plant was considered to be in service at its earliest possible date,2015,followed by Scenery Lake in 2017 and Delta Creek in 2019.Study results indicated that Delta Creek would not provide sufficient revenue to cover its costs (capital and O&M)and thus was not considered to be part of the system.Other hydro projects were considered for export but were found to be uneconomical.In addition,under this scenario it was shown to be more economical to delay the Triangle Lake hydro project beyond the study period. Item 7 in Table 8-12 presents the expansion plan considered for the scenario with exports. The present value of costs for supplying the Swan and Tyee regions'demand,from 2007 to 2031 and a further evaluation period of 15 years,either in a connected way or in an export mode can be summarized as: Hatch Acres Corporation PR324582.Rev.0,Page 207 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACHES Table 8.8-1:Benefits of Power Exports Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report C.P.V.of Costs to January 2007 ($,million) Scenario Discount Rate 6%8%10% Swan Lake and Tyee Lake 370.2 288.8 233.7 Connected in 2010 Swan Lake and Tyee Lake 337.7 298.4 264.4 Connected in 2010 &Power Exports Benefit of Power Exports 32.5 -9.6 -30.7 The above results indicate that power exports are economic under the base case discount rate but uneconomic at higher discount rates. Figure 8-3 presents the potential energy for export by month for three selected years. 8.9 Items Not Included in Economic Analysis As noted in an earlier section,the economic analysis has been carried out under the assumption that the transmission segments needed to connect load centers and bring power to the BC border for export would be funded through government grants.However,the economic analysis includes the full estimated costs of the annual operation and maintenance costs associated with each transmission segment..The operation and maintenance cost estimates have been prepared to recognize the challenges of the Alaskan climate and terrain and the resulting impacts on costs. On the other hand,there are a number of benefits to the residents of the region and the State of Alaska as a whole that would likely result from the projects for SE Alaska that have not been quantified as part of the Phase 1 work and thus have not been counted in the economic analysis. These include benefits such as: e Reduction of GHG from diesel generation e Reduction in the total amount of spinning reserve e More conversions from oil heat to electric heat and the resulting economic and GHG reduction benefits e Increased total output from hydro plants by the ability to exploit hydro complementarities through coordinated operation of the plants e Assistance during maintenance outages e Reduction in PCE subsidy payments e The multiplier effects of increased economic development and increased disposable income resulting from lower energy prices. Hatch Acres Corporation PR324582.Rev.0,Page 208 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES Similar un-quantified benefits would generally also result from the investments made to allow the export of power.In this case there would be further un-quantified benefits associated with: Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report e Earlier development of larger hydro projects allowing further reduction in diesel generation in SE Alaska e Increased flexibility of power system operations by virtue of being connected to a larger system e Opportunity for further optimization of system resources. 8.10 Sensitivity Analysis Sensitivity studies were carried out to determine the sensitivity of the generation/transmission expansion sequences results to changes in the parameters used in the analysis.Meaningful variations of these parameters were selected to demonstrate the robustness of the planning results under conditions that could reasonably be expected.Sensitivity was investigated to variations in the following parameters. e Low and high load growth e Capital and O&M Costs e Fuel prices e Export price and repayment period e Discount rate. 8.10.1 Low and High Load Growth The generation expansion scenarios developed for the reference load forecast were examined to obtain indications on how the generating plants added during the study period would be either delayed or advanced depending on the load growth scenario under study;low or high.The capacity and energy balances were also taken into account when developing generation expansion sequences for the load growth under study. For the low growth load forecast,Petersburg could experience a capacity deficit by 2026 and Ketchikan has a capacity deficit by 2011 with the remaining load centers not encountering capacity deficits.With the assistance of the RRPM,studies were performed to determine the best timing of the hydro plants considered under the reference growth load forecast.The resulting plant addition plan is presented in Table 8-13 and when compared to Table 8-12 it can be seen that for the Swan region expansion plans,the Carlanna Lake and Triangle Lake hydro projects were delayed from 2 to 8 years depending upon the case being studied.For the STI and exports cases Connell Lake was delayed 6 years and Triangle Lake was delayed beyond the study period. For the high growth load forecast,Petersburg would see a capacity deficit by 2013 and Ketchikan would have a capacity deficit by 2010 with the remaining load centers not encountering capacity deficits.With the assistance of the RRPM,studies were performed to determine the best timing of the hydro plants considered under the reference growth load forecast. Hatch Acres Corporation PR324582.Rev.0,Page 209 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACRES The resulting plant addition plan is presented in Table 8-14 and when compared to Table 8-12 it can be seen that for the Tyee region,diesel additions were commissioned by 2013 and 2017 in Petersburg with a nominal size of 2 MW for each addition.For the Swan region expansion plans, there was a need for a 5 MW diesel unit at Ketchikan to mitigate the capacity deficit in 2026,the Triangle Lake hydro projects was advanced either 3 or 4 years depending upon the scenario being investigated and the Carlanna Lake plant was advanced 4 years in the case of a connection between Ketchikan and Metlakatla.For the high growth load forecast,the Tyee extension hydro project was included in the generation expansion plans,other hydro projects were found to be uneconomical. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report The ST!and export cases required the advance of all plants when compared to the reference growth load forecast with Cascade Creek and Scenery Lake remaining with the same in-service date as in previous cases. Table 8-15 summarizes the costs associated with supplying the demand in SE Alaska under the three different load growth forecasts.Generally,the costs associated with supplying the demand of the three regions under study in SE Alaska increase with the high growth load forecast and decrease with the low growth load forecast.The benefits associated with the various connections also increase with load growth and generally have their smallest values under the low load growth case. The exception being the loads in the POW region where the benefits of connecting the Coffman Cove and Naukati load centers decrease with increasing load growth and this may be due to the fact of limited hydro energy availability. 8.10.2 Capital and O&M Costs Increase Studies were performed to determine the sensitivity of the economic analysis to variations in the capital costs and O&M costs of projects.In this analysis,a 20%increase was assumed in the capital cost and O&M cost estimates for all projects.The results of these studies are presented in Table 8-16 and these results indicate that a 20%increase in capital and O&M costs would not result in significant impacts on the benefits of the connection of Kake to Petersburg,the connection of Ketchikan and Metlakatla and the connection of Swan Lake and Tyee Lake (the STI).However, the economics of the export case would be significantly and adversely affected by a 20%increase in capital and O&M costs of the Thomas Bay projects. 8.10.3 Fuel Prices Studies were performed to determine the sensitivity of the generation sequences to variations of fuel prices.Studies were performed for a +15 %variation in all fuels prices which would correspond to crude price varying from 48 $per barrel to 65 $per barrel.The results of these studies are presented in Table 8-17 and these results indicate that the higher the fuel price the more costly to supply the load centers and the more benefits one would obtain from the various connection alternatives including the STI and the export cases. 8.10.4 Export Price and Capital Repayment Period Studies were performed to determine the sensitivity of the generation sequences for the export cases to variations of export price,capital cost of plants for export and numbers of years for capital Hatch Acres Corporation PR324582.Rev.0,Page 210 AK-BC Alaska Final Report 18-09-07.Doc HATH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report cost repayment.The results are shown in Table 8-18 and indicate that for a 20 years capital repayment period and an export price of 60 $/MWh,increases in capital cost of the plants built for export would result in negative benefits.However,for export prices of 70 and 80 $/MWh the benefits of exports would remain positive for the range of capital cost increases examined. Table 8-18 also shows that for a capital repayment period of 50 years,one would encounter negative benefits if the export price was 60 $/MWh and the capital cost of the plants built for export was increased by 20%.The other export prices and capital cost increases tested resulted in positive benefits. 8.10.5 Discount Rate The cumulative present value of costs,at different discount rates,of supplying the load centers under study are presented in Sections 8.7 and 8.8.Generally the results show that the higher the discount rate the lower the overall benefits of connecting the load centers.The STI benefits are reduced from $33.2 million for a 6%discount rate to $22.8 million for a 10%discount rate. The benefits associated with the export case are significantly adversely affected by increases in the discount rate.At 6%discount rate,the export case has a positive benefit of $32.5 million whereas for a discount rate of 10%,the benefit is negative $35.9 million. 8.11.Estimated Avoided Emissions An analysis was prepared of the emissions that could be avoided when individual load centers and systems are interconnected in southern Alaska.Two load growth scenarios were investigated: e Include conversion of a portion of heating supplied by oil fired heating furnaces to loads supplied by electrical heaters (case with conversion) e Consider that heating would continue to be supplied by oil fired heating furnaces (case without conversion). This section of the report provides results of this analysis which was carried out with the assistance of RRPM. In the case with conversion of oil fired heating furnaces,the annual expected displaced oil consumption of these furnaces was estimated and the expected amount is discussed in this section. For each of the two load growth scenarios,the generation for three system development cases was determined in order to calculate the avoided emissions.These cases are: 1)Isolated -Swan-Tyee Intertie is not implemented and both Kake and Metlakatla remain isolated; 2)Isolated With STI -Swan-Tyee Intertie is commissioned in 2010 but both Kate and Metlakatla remain isolated; 3)Interconnected With ST!-Swan-Tyee Intertie is commissioned in 2010,Kate is interconnected with Petersburg and Metlakatla is interconnected with Ketchikan. Hatch Acres Corporation PR324582.Rev.O,Page 211 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 8.11.1 Emission Factors Four emission pollutants -CO2,SOx,CO and NOx -were examined in this study.The emission factors used were obtained from AP 42,Volume I,Fifth Edition published by the Environmental Protection Agency (EPA)of the USA in 1995.These factors are summarized as follows: Pollutant |Diesel Engine |Furnace Emission Factors in Pounds Per Horsepower-Hour (b/hp-hr) CO2 1.16 SOx 0.00809 CO 0.0055 NOx 0.024 Emission Factors in Pounds Per Thousand Gallons of Fuel (lb/1000-gal) CO2 22,548 22,300 SOx 157 144 CO 107 5 NOx 467 18 It is important to note that the emission factors in Ib/hp-hr for diesel engines shown in the table above are the average values for large diesel engines (greater than 600 hp).The factors in Ib/1000- gal for the diesel engines are calculated based on the values in Ib/hp-hr,heat rate of 7,000 Btu/hp- hr,diesel heating value of 19,300 Btu/Ib and diesel density 7.05 Ib/gal.It is also assumed that the diesel fuel contains 1%of sulfur. It can be seen from these emission factors that for the same amount of liquid fuel consumed by the diesel engines and furnaces,the two types of facilities emit similar amounts of CO2 and SOx but diesel engines emit much more CO and NOx than furnaces.CO and NOx emissions from diesel engines are about 21 times and 26 times of those from furnaces. 8.11.2 Electricity Required for Conversion of Oil Fired Heating Furnaces In this analysis,five load centres were considered -Ketchikan,Metlakatla,Wrangell,Petersburg and Kake.The estimated additional annual electrical energy required to supply the loads that would be converted from oil fired heating furnaces as well as the displaced oil consumption (in the case with conversion)are summarized as follows: Year Additional Electricity Displaced Oil Required (MWh)Consumption (US Gallon) 2007 2,759 108,375 2008 5,433 213,377 2009 8,016 314,846 2010 11,728 453,163 2011 18,962 707,095 2012 28,600 1,039,909 2013 30,889 1,129,792 Hatch Acres Corporation PR324582.Rev.0,Page 212 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 2014 39,194 1,417,705 2015 41,449 1,506,298 2016 43,641 1,592,398 2017 45,765 1,675,796 2018 47,841 1,757,324 2019 49,874 1,837,193 2020 51,891 1,916,396 2021 53,860 1,993,728 2022 55,781 2,069,190 2023 57,660 2,142,990 2024 59,492 2,214,920 2025 61,286 2,285,395 2026 63,058 2,354,991 2027 64,793 2,423,133 2028 66,496 2,490,028 2029 68,168 2,555,676 2030 69,802 2,619,869 2031 71,425 2,683,600 Total 1,117,863 41,503,183 With conversion of each MWh of furnace load to electrical load,about 37 gallons of heating oil can be displaced.Based on a heat rate of 7,000 Btu/hp-hr,a heating value of 19,300 Btu/lb and a density of 7.05 |lb/gal as mentioned earlier,diesel engines would use about 69 gallons of diesel to generate one MWh.This implies that diesel engines have lower efficiency than heating furnaces.If the additional load for heating was produced by diesel engines,there would be more oil consumption and more pollution than in the case of supply from heating furnaces.It is important to note that most of the additional or displaced heating furnace load is expected to be provided by unused hydro generation. 8.11.3 Estimated Avoided Emissions The following tables present total and avoided emissions over the periods from 2007 to 2041 and from 2007 to 2031.Tables 8.19 and 8.20 present the detailed information from which these summary tables were developed. Hatch Acres Corporation PR324582.Rev.0,Page 213 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Total Emissions Theme Case co2 SOx co NOx (ton)(ton)(ton)(ton) 2007-2046 Isolated 1,667,754 11,160 3,790 16,381 No-Conversion |isolated-STI 1,485,993 9,892 2,928 12,620 IC-STI 1,383,714 9,179 2,443 10,504 Isolated 1,424,535 9,935 6,754 29,473 Conversion |Isotated-STI 956,242 6,669 4,534 19,784 IC-STI 872,599 6,086 4,137 18,054 2007-2031 Isolated 912,198 6,123 2,235 9,672 No-Conversion |Isolated-STI 829,041 5,543 1,840 7,952 IC-STI 770,639 5,135 1,564 6,743 Isolated 754,157 5,260 3,576 15,603 Conversion __|Isolated-STI 471,672 3,290 2,236 9,759 IC-STI 426,202 2,972 2,021 8,818 Avoided Emissions Theme Case co2 SOx co NOx (ton)(ton)(ton)(ton) 2007-2046 Isolated ------- No-Conversion |Isolated-STI 181,762 1,268 862 3,761 IC-STI 284,040 1,981 1,347 5,877 Isolated 243,219 1,225 -2,965 -13,093 Conversion |lsolated-STl 711,513 4,491 -744 -3,404 IC-STI 795,155 5,074 -348 -1,673 2007-2031 Isolated -------- No-Conversion |Isolated-STI 83,156 580 394 1,720 IC-STI 141,559 987 671 2,929 Isolated 158,041 863 -1,341 -5,931 Conversion |lsolated-STI 440,525 2,833 -2 -87 IC-STI 485,996 3,150 214 854 It can be seen from the above table that in the interconnected case with the Swan-Tyee interconnection commissioned in 2010,conversion of a portion of oil fired furnace load could reduce CO2 and SOx emissions by 795,155 and 5,074 tons or some 47.7%and 45.5% respectively over the period from 2007 to 2046 or 485,996 and 3,150 tons or some 53.3%and 51.5%respectively over the period from 2007 to 2031 when compared with the isolated case without conversion.Over the period from 2007 to 2046,emissions of CO and NOx would be Hatch Acres Corporation PR324582.Rev.0,Page 214 AK-8C Alaska Final Report 18-09-07.Doc Table 8.1:Generation Capability of Existing Hydro Plants Monthly Energy (MWh) Capacity O&M Cost Hydro Totals Capacity Plant (MW)($1.000)Condition Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec (GWh)Factor Avg 6,930 5,479 5,154 4,824 5168 4886 6211 6,368 6,143 6,058 7,022 7,800 72.0 37%Swan 22.5 1275 Min 5,272 1,854 2983 4,151 4,680 5485 6995 4821 2606 4069 7,527 8,556 59.0 30% Max 8,647 6697 3,007 6,388 6,383 5,889 7,313 8191 6659 6,895 7,053 8,539 81.7 41% Avg 1,895 1,577 1,646 1,361 1,461 1,622 1,262 1,178 1,585 2,011 2,083 2,079 19.8 54% Ketchikan 4.2 250 Min 2,719 2,100 2,260 33 0 0 0 138 1670 2021 1,981 2,036 15.0 41% Max 1,743 1,235 982 2,141 2320 1914 1,906 2244 2311 2281 2,154 2,094 23.3 63% Avg 3424 3,078 3,345 3,228 3164 2,873 3,241 3,110 3,087 3,275 3,290 3,323 38.4 73% Beaver Falls 6 351 Min 2546 3,301 3,366 3,057 2119 2500 3320 411 1,770 3,480 3425 3,722 33.0 63% Max 3,517 3,294 3845 3,708 3,732 3,141 3395 3596 3605 3317 3497 3,639 42.3 80% Avg 1,147 981 1,113 944 840 906 1,059 849 661 794 1,091 1,055 114 62% Silvis 2.1 133 Min 1,222 507 1,006 1,064 844 1105 1,008 1,024 590 291 457 478 9.6 52% Max 1,331 1,280 --'1,423=-«1,244 «1,047,1,015 1,220,1,268 =213,154 1,393 1,447 14.0 76% Avg 924 879 895 912 975 1,042 722 «29736 «#4+799 «#2972 «#29789 ° =«(771 10.4 59% Blind Slough 2 127 Min 1,152 821 14,060 1,063 791 808 «6=s«8833.-'i'<'éz wd «=SC77s-"'iTKQ”S SCé«iTNCi'7Az:10.0 57% Max 1,262 1,000 840 967 1,291 1,236 1143 793 517 952 788 578 11.4 65% Black Beart Avg 2,173 2,261 1,746 2,387 2,349 2,906 2,293 2,390 2,191 2599 2,415 2,485 28.2 50% 6.5 394 Min 2307 2263 1972 1,050 1,699 2119 2168 2,396 2,129 2134 2,198 2,241 24,7 43%South Fork Max 2369 2,468 1881 3443 2689 3053 2573 2562 1,809 2768 2617 2,614 30.8 54% +Avg 1,621 1,383 1,445 «1,438 1,214 «1,097 «1,292 «1,256 «=1,253 «1,362 «1,294 -«*1,476 16.1 38%Purple 4.9 304 Min 1033 931 1,156 1,141 739 894 886 1,306 1,212 1,204 1,014 1,256 12.8 30%Chester Max 2135 1,735 1829 1654 1,462 1,236 1,522 1,714 1583 1,762 1,754 1,905 20.3 47% Avg 11,900 11,100 12,100 10,800 10,000 10,800 10,400 10,800 10,400 10,800 10,800 10,400 130.3 66% Tyee 22.5 22.5 1275 Min 10,800 10,400 10,800 10,800 9,700 10800 10,400 10,800 10,400 10,800 10,800 10,400 126.9 64% Max 16,700 10,400 10,800 10,800 9,700 10,800 10,400 10,800 10,400 10,800 16,700 16,200 144.5 73% Totals 70.7 Avg 30,013 26,737 27,444 25,894 25,171 26,131 26,479 26,687 26,118 27,870 28,783 29,389 326.7 HATGH ACRES increased by 348 and 1673 tons or about 9.2%and 10.2%respectively and this is due to the higher emission factors of diesel engines. The Tables 8.19 and 8.20 present detailed information regarding the estimated annual emissions in short tons (2000lb/short ton)for each of the two load growths studied. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report PR324582.Rev.0,Page 215HatchAcresCorporation AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report SECTION 8 TABLES AND FIGURES Hatch Acres Corporation PR324582.Rev.O,Page 216 AK-BC Alaska Final Report 18-09-07.Doc Table 8.1:Generation Capability of Existing Hydro Plants Monthly Energy (MWh) Capacity O&M Cost Hydro Totals Capacity Plant (MW)($1.000)Condition Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec (GWh)Factor Avg 6930 5,479 5,154 4824 5168 4886 6211 6,368 6,143 6,058 7,022 7,800 72.0 37%Swan 22.5 1275 Min 5,272 1,854 2983 4,151 4,680 5,485 6995 4821 2606 4069 7,527 8556 59.0 30% Max 8647 6,697 3,007 6,388 +-6,383.«45,889 7,313 «8.191 6,659 6895 7,053 8,539 81.7 41% Avg 1,895 1,577 1646 1,361 1,461 1,622 1,262 1178 1,585 2011 2,083 2,79 19.8 54% Ketchikan 4.2 250 Min 2719 2100 2,260 33 0 0 0 138 1,670 2021 1,981 2,036 15.0 41% Max 1,743 1,235.--982,-s«2141 «2,320 1,914 1906 2,244 «2.311 -2.281 «2,154 2,094 23.3 63% Avg 3424 3,078 3,345 «3,228 «3,164.S-2,873 «3,241 3,110 «3,087 3,275 =3,290 «3,323 38.4 73% Beaver Falls 6 351 Min 2,546 3,301 3,366 3,057 2119 2500 3320 411 1,770 3480 3,425 3,722 33.0 63%Max 3,517 3,294 3.845 =«3,708 =«3,732,«3,141 «3,305 «3.596 ©=«3,605 3.317 «3,497 «3,639 423 80% Avg 1,147 981 1,113 944 840 906 1,059 849 661 794 1,091 1,055 11.4 62%Silvis 2.1 133 Min 1,222 507 1,006 1,064 844 1,105 1,008 1,024 590 291 457 478 9.6 52% Max 1,331 1,280 1,423 1,244 1,047 1,015 «1,220.-1,268 =243 1,154 1,393 1,447 14.0 76% Avg 924 879 895 912 975 1,042 722 «49736 «4799 «972 2 #©6©789 =«(771 10.4 59% Blind Slough 2 127 Min 1,152 821 1,060 1,063 791 808 833 580 772 719 670 743 10.0 57% Max 1,262 1,000 840 967 1,291 1,236 1,143 793 S17 952 788 578 114 65% Black Beart Avg 2,173 2,261 1,746 2,387 2349 2906 2,293 2390 2,191 2599 2415 2,485 28.2 50% South Fork 6.5 394 Min 2,307 2,263 1,972 1,050 1699 2,119 2168 2396 2129 2134 2,198 2,241 247 43% Max 2,369 2468 1,881 3443 2689 3,053 2573 2,562 1809 2768 2617 2614 30.8 54% Purple +Avg 1,621 1,383 1,445 1,438 1,214 1,097 1,292 1,256 1,253 1,362 1,294 1,476 16.1 38%Chester 49 304 Min 1,033 931 1,156 1,141 739 894 886 1,306 1,212 1,204 1,014 1,256 12.8 30% Max 2,135 1,735 1,829 1,654 «1,462,-«1,236 «1,522 1,714 1,583 1,762 1,754 1,905 20.3 47% Avg 11,900 11,100 12,100 10,800 10,000 10,800 10,400 10,800 10,400 10,800 10,800 10,400 130.3 66% Tyee 22.5 22.5 1275 Min 10,800 10,400 10,800 10,800 9,700 10,800 10,400 10,800 10,400 10,800 10,800 10,400 126.9 64% Max 16,700 10,400 10,800 10,800 9,700 10,800 10,400 10,800 10,400 10,800 16,700 16,200 144.5 73% Totals 70.7 Avg 30,013 26,737 27,444 25,894 25,171 26,131 26,479 26,687 26,118 27,870 28,783 29,389 326.7 Page 217 Table 8.2:Characteristics of Existing and Committed Diesel Units Capacity (MW)Fuel Consumption 0 &M Costs Unit Net Sent Year Fixed Variable General Operating Plant Number Manufacturer Installed Out FuelType Installed (kWh/Gal)(Gal/MWh)(k$/Yr) ($/MWh)-Condition Hours Ketchikan Bailey 1 Worthington 3.5 3.50 #2 Diesel 1971 14.8 67.6 140.00 20.00 good 40,765 Bailey 2 Worthington 3.5 0.00 #2 Diesel 1971 14.8 67.6 140.00 20.00 Out of service 39,797 Bailey 3 Colt Pielstick 5.5 5.50 #2 Diesel 1976 14.2 70.4 220.00 20.00 good 37,352 Bailey 4 Wartsilla 10.5 10.50 #2 Diesel 1998 15.0 66.7 420.00 20.00 good 5,642 Pt Higgins 1 Cat 1.8 1.60 #2 Diesel 2007 14.2 70.4 108.00 25.00 good 23 Pt Higgins 2 Cat 1.8 160 #2 Diesel 2007 14.2 70.4 108.00 25.00 good 24 Subtotal 22.70 Metlakatla Centennial 6 3.30 _'#2 Diesel 1987 8.8 113.6 132.00 20.00 Excellent Wrangell WMLP #2 EMD 2.0 2.00 #2 Diesel 2001 12.7 78.9 80.00 25.00 Good 33 WMLP #3 EMD 2.0 2.00 #2 Diesel 2000 12.7 78.9 80.00 25.00 Good 207 WMLP #4 EMD 2.0 2.00 #2 Diesel 2000 12.7 78.9 80.00 25.00 Good 179 WMLP #5 EMD 2.5 2.50 #2 Diesel 1981 12.7 78.9 100.00 25.00 Good 3 SubTotal 8.50 Petersburg 1 Detroit 0.35 0.20 ULSDF2 1972 10.0 99.9 8.00 20.00 Good 9,000 2 Cat 0.6 0.60 ULSDF2 1979 17.6 57.0 24.00 20.00 Fair 21,042 3 Cat 0.8 0.70 ULSDF2 1979 12.6 79.3 28.00 20.00 Good 22,957 4 White Superior 1.25 1.00 ULSDF2 1965 14.6 68.7 40.00 20.00 Good 19,525 5 EMD 2.3 1.70 ULSDF2 1972 13.5 74.3 68.00 20.00 Good 10,908 6 EMD 2.6 2.30 ULSDF2 1993 13.0 76.8 92.00 20.00 Good 4,141 7 EMD 2.6 2.30 ULSDF2 2001 13.9 718 92.00 20.00 Good 744 Subtotal 8.80 Page 218 Table 8.2:Characteristics of Existing and Committed Diesel Units Capacity (MW)Fuel Consumption 0 &M Costs Unit Net Sent Year Fixed Variable General Operating Plant Number Manufacturer Installed Out FuelType Installed (kWh/Gal)(Gal/MWh)(k$/Yr)-($/MWh)-Condition Hours Kake Kake 1 Cat/Kato 630 KW 0.63 #2 Diesel 1984 13.2 75.5 37.80 25.00 Fair 5,871 Kake 2 Cat/Kato 1100 KW 1.10 #2 Diesel 1992 13.2 75.5 66.00 25.00 Fair 931 Kake 3 Cat/Kato 855 KW 0.86 #2 Diesel 1997 13.2 75.5 51.30 25.00 Good 2,863 Subtotal 2.59 POW [*] Coffman Cove 0.74 -«#2 Diesel 13.2 76.0 44.40 25.00 Naukati 0.48 #2 Diese!12.7 78.7 28.68 25.00 Whale Pass 0.30 #2 Diesel 12.3 81.1 17.70 25.00 Craig 1.29 #2 Diesel 15.8 63.3 77.10 25.00 Craig 4.50 #2 Diesel 12.5 80.8 270.00 25.00 Hollis 0.25 #2 Diesel 10.0 100.0 15.00 25.00 Hydaburg 0.96 #2 Diesel 12.4 80.9 57.60 25.00 Klawock 1.00 #2 Diesel 12.3 81.6 60.00 25.00 Kasaan 0.18 #2 Diesel 12.5 80.0 10.80 25.00 Thorne Bay 1.08 #2 Diesel 13.5 74.1 64.50 25.00 Subtotal 10.76 Total South Southeast Alaska 56.65 Page 219 Table 8.3:Characteristics of Existing Diesel Units in Prince of Wales Capacity (MW)Fuel Consumption 0&M Costs Unit Net Sent Year Fixed Variable General Operating Plant Number Manufacturer Out FuelType 'Installed (kWh/Gal)(Gal/MWh)(k$/Yr) ($/MWh)-Condition Hours Coffman Cove 1 Caterpillar 175 #2 Diesel 13.2 76.0 10.50 25.00 Good 67,771 2 Caterpillar 330 #2 Diesel 13.2 76.0 19.80 25.00 Good 39,535 3 Cummins 235 #2 Diesel 13.2 76.0 14.10 25.00 Fair 59,203 Subtotal 740 Naukati Bay Fair 41,375 1 John Deere 138 #2 Diesel 12.7 78.7 8.28 25.00 Fair 37,571 2 John Deere 165 #2 Diesel 12.7 78.7 9.9 25 Good 36,254 3 John Deere 475 #2 Diesel 12.7 78.7 10.5 25 Subtotal 478 Whale Pass 1 John Deere 70 #2 Diesel 12.3 81.1 4.20 25.00 Poor 33,511 2 Cummins 100 #2 Diesel 12.3 81.4 6.00 25.00 Good 5,553 3 Caterpillar 125 #2 Diesel 12.3 81.1 7.50 25.00 Fair 11,645 Subtotal 295 Craig 1 Caterpillar 630 #2 Diesel 1984 12.4 80.8 37.8 25 Good 60,615 3 Caterpillar 1,600 #2 Diesel 12.4 80.8 96.00 25.00 Good 6,297 5 Caterpillar 1,135 #2 Diesel 12.4 80.8 68.10 25.00 Good 3,379 6 Caterpillar 1,135 #2 Diesel 1989 12.4 80.8 68.10 25.00 Good 50,069 Craig Sub 1 Caterpillar 1,285 #2 Diesel 15.8 63.3 77.10 25.00 New 14,584 Subtotal 5,785 Page 220 Table 8.3:Characteristics of Existing Diesel Units in Prince of Wales Capacity (MW)Fuel Consumption 0 &M Costs Unit Net Sent Year Fixed Variable General Operating Plant Number Manufacturer _Installed Out FuelType Installed (kWh/Gal)(Gal/MWh)(k$/Yr)=($/MWh) -Condition Hours Viking 1 Cummins 1,000 #2 Diesel 12.3 81.6 60.00 25.00 Excellent 2,075 Hollis 1 Caterpillar Caterpillar 250 #2 Diesel 10.0 100.0 15.00 25.00 Poor 1,226 Hydaburg 1 Caterpillar 330 #2 Diesel 12.4 80.9 19.8 25 Good 70,987 3 Caterpillar 300 #2 Diesel 12.4 80.9 18.00 25.00 Good 54 5 Caterpillar 330 #2 Diesel 12.4 80.9 19.80 25.00 Good 104,184 Subtotal 960 Kasaan Caterpillar 90 #2 Diesel 1976 12.5 80.0 54 25 Poor 13442 Caterpillar 90 #2 Diesel 1976 12.5 80.0 5.40 25.00 Poor 14630 Subtotal 180 Thorne Bay Caterpillar 425 #2 Diesel 13.5 74.1 25.50 25.00 Good 14799 Caterpillar 650 #2 Diesel 13.5 74.1 39.00 25.00 Good 29411 Subtotal 1,075 Total POW 10,763 Page 221 Table 8.4:Determination of Fuel Prices Current Prices Future Prices Total Price Reference Other Costs Reference OtherCosts Total Price Plant (c/Gal)Price(c/Gal)(c/Gal}Price (c/Gal)-_(c/Gall)(c/Gal) Ketchikan 220.00 176.2 43.80 165.25 43.80 209.05 Metlakatla 220.52 176.2 44.32 165.25 44.32 209.57 Wrangell 268.00 176.2 91.80 165.25 91.80 257.05 Petersburg 235.10 176.2 58.90 165.25 58.90 224.15 Kake 252.80 176.2 76.60 165.25 76.60 241,85 POW South Craig 230.54 176.2 54.34 165.25 54.34 219.59 Thorne Bay 233.50 176.2 57.30 165.25 57.30 222.55 Hydaburg 233.44 176.2 57.24 165.25 57.24 222.49 Klawock 231.54 176.2 55.34 165.25 55.34 220.59 Holis 243.00 176.2 66.80 165.25 66.80 232.05 Kassan 234.50 176.2 58.30 165.25 58.30 223.55 Whale Pass 237.04 176.2 60.84 165.25 60.84 226.09 Coffman Cove 236.50 176.2 60.30 165.25 60.30 225.55 Naukati 238.50 176.2 62.30 165.25 62.30 227,55 Current price of crude (NYMEX)($/bbl)=61.00 Current price of Diesel =176.2 (c/Gal)conversion as per EIA Forecast Long Term Forecast ($/bbl)=57.21 Source:EIA 2007 Enrgy Outlook multiplier Diesel/crude =1.213 Future Reference price of Diesel (c/Gal.)=165.3 Page 222 Table 8.5:Generation Capability of Candidate Hydro Plants Monthly Energy (MWh) Capacity Hydro Totals Capacity Plant (MW)Condition Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec (GWh)Factor Avg 807 632 567 758 1,703 1,467 1,360 693 1,276 1,560 1,280 1,037 13.1 43% Triangle 3.5 Min 698 547 490 656 1473 1,269 1,177 600 1,104 1,349 1,107 897 11.4 37% Max 1,028 805 722 965 2168 1,868 1,731 883 1,625 1,985 1629 1,320 16.7 55% Avg 8800 7,900 8,200 7,700 7,600 7,200 7,400 8989 11,632 13,400 8816 9,300 106.9 61% Takatz 20.0 Min 8800 7,900 8200 7,700 7,600 7,200 7,400 7,700 8100 8500 8700 9,300 97.1 55% Max 8800 7,900 8200 7,700 7,600 7,200 7,400 14880 14,000 14,880 8700 9,300 116.6 67% Avg 5,220 4,482 4420 4,643 10,430 17,602 19683 19,816 17,629 14,540 6,737 3,483 128.7 49% Scenery Lake 30.0 Min 6,503 3,669 4,048 3125 8,061 17,192 13,743 12,989 11,009 12,965 6,286 3,254 102.8 39% Max 4874 5,117 5613 6,171 13,487 20,426 21,120 21,209 20,670 21,400 7,868 4,868 152.8 58% Cascade Avg 10,752 9,554 9,472 8,909 12,229 24,253 30,719 30,775 27,288 21,807 9,900 6,595 202.3 51% Creek 45.0 Min 9,881 9,790 12,714 12,185 8677 17,039 17,770 20,610 17,296 18,702 10,509 3,954 159.1 40% Max 9,866 11,524 12641 8412 17,177 28,786 32,627 32,792 31,897 32,950 12,431 7,895 239.0 61% Avg 2,221 1,575 1,547 1,307 «45,256 11,587 12,718 11,332 9,967 7,634 3361 2,198 70.7 40% Delta (Ruth)20.0 Min 3823 1,379 1,898 1,094 3,573 9,245 10,066 7,835 5,898 7,965 2,953 1,919 57.6 33% Max 1,919 1,733 1,900 1,826 6649 12,985 13344 13,751 10,873 12,885 3,335 3,056 84.3 48% Avg 2,433 1,906 1,708 2,283 5,132 4,422 4,099 2,090 3,846 4,700 3856 3,125 39.6 47% Mahoney 9.6 Min 2105 1649 1,478 1,976 4,440 3,826 3546 1,808 3,328 4,067 3336 2,704 34.3 M% Max 3,097 2426 2174 2907 6534 5629 5,218 2660 4896 5,984 4909 3,979 50.4 60% Avg 1,205 944 846 1,131 2,542 2190 2,030 1,035 1,905 2,328 1910 1,548 19.6 49% Whitman 4.6 Min 1,043 817 732 979 2199 1,895 1,756 895 1,648 2,014 1,653 1,339 17.0 42% Max 1,534 1,202 1,077 1440 3,236 2788 2584 1,318 2425 2964 2432 1,971 25.0 62% Avg 664 «520s 46G-(its«iBes«*4«2GH_-"'<'i«QOG:SC'd1,418-=s«5'7--«*1,049 1,265 «1,052.85 10.6 72% Connell 1.7 Min 574 450 403 539 1,211 1043 967 +493 908 1,109 910 737 93 63% Max 845 662 593 793 1,265 1,224 1,265 726 1,224 1,265 1,224 1,085 12.2 82% Avg 258 202 181 242 +544 «+469 £435 «9222 «408 #499 409 331 42 60% Carlanna 0.8 Min 223 175 157 «210 471 #«+406 376 «©1922 353 431 354 287 3.6 52% Max 328 «=o 257 -s«23 308 46595 +«576 =553-Ss282s-iéNDs-S"siHC «DD 52 74% Page 223 Table 8.5:Generation Capability of Candidate Hydro Plants Monthly Energy (MWh) Capacity Hydro Totals Capacity Plant (MW)Condition Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec (GWh)Factor Avg 829 650 582 778 1,750 1,507 1,397 712 1,311 1,602 1,315 1,065 13.5 39% Sunrise 4.0 Min 718 562 504 674 1,514 1,304 1,209 616 1,134 1,386 1,137 922 11.7 33% Max 1,056 827 741 991 2227 1,919 1,779 907 1,669 2,040 1,674 1,356 17.2 49% Avg 1,726 1,352 1,212 1,620 3,642 3,138 2,908 1,483 2,729 3,335 2,736 2,218 28.1 37% Anita-Kunk 8.6 Min 1,494 1,170 1,049 1,402 3,151 2,715 2516 1,283 2,361 2886 2367 41,919 24.3 32% Max 2,198 1,722 1,543 2063 4636 3994 3,702 1,888 3474 4246 3484 2,823 35.8 47% a Avg 2,691 2,108 1,889 2,526 5677 4890 4,533 2,311 4,254 5,199 4,265 3,457 43.8 42% Virginia 12.0 Min 2,328 1,824 1,635 2,185 4911 4231 3,922 2,000 3681 4,498 3690 2,991 37.9 36% Max 3,426 2684 2405 3215 7,227 6,226 5771 2,942 5416 6618 5430 4,401 55.8 53% Avg 1,487 1,165 1,044 1,395 3,136 2,702 2,505 1,277 2,350 2,872 2357 1,910 24.2 37% Thoms Kake 75 Min 1,286 1,008 903 1,207 2,714 2338 2167 1,105 2,034 2,485 2,039 1,652 20.9 32% Max 1,893 1,483 1,329 1,776 3,993 3,440 3,189 1,626 2,992 3657 3,000 2,431 30.8 47% Tyee 34 MW Avg 15,300 13,000 15,500 11,800 10,800 11,300 11,000 11,300 11,000 11,300 11,300 11,000 144.6 49% Total 33.8 Min 11,300 11,000 11,300 11,300 10,300 11,300 11,000 11,300 11,000 11,300 11,300 11,000 133.4 45% Max 25,300 11,000 11,300 11,300 10,300 11,300 11,000 11,300 11,000 11,300 25,300 24,500 174.9 59% Reynolds Avg 526 556 486 418 443 492 516 515 494 517 571 567 6.1 14% Creek 5.0 Min 471 498 435 375 397 «+440 462 462 £443 463 512 508 55 12% Max 571 604 528 454 482 534 564 560 537 561 620 616 66 15% Page 224 Table 8.6:Comparison of Candidate Hydro Project Unit Cost Annual Costs ($1,000,000) Average Unit Cost Capacity Energy Earliest Total of Energy Plant (MW)(GWh)On-Line Cost [1]Capital [2]O&M Total ($/MWh) Triangle 3.5 13.1 2015 15.61 0.99 0.21 4.20 91.44 Takatz 20 106.9 2015 134.20 8.51 1.57 10.08 94.27 Scenery Lake 30 128.7 2015 84.44 5.36 1.70 7.05 54.80 Cascade (Swan)45 202.3 2015 144.96 9.20 2.54 11.73 58.01 Delta (Ruth)20 70.7 2015 60.52 3.84 1.14 4.97 70.36 Mahoney 9.6 39.6 2010 25.00 1.59 0.55 2.14 54.02 Whitman 46 19.6 2010 9.74 0.62 0.27 0.89 45.42 Connell 1.7 10.6 2016 7.77 0.49 0.11 0.60 56.63 Carlanna 0.8 4.2 2016 3.74 0.24 0.06 0.30 70.71 Sunrise 4.0 13.5 2016 20.57 1.31 0.24 1.54 114.38 Anita-Kunk 8.6 28.1 2016 111.92 7.10 0.50 7.60 270.38 Nirginia 12.0 43.8 2016 127.58 8.09 0.69 8.78 200.48 Thoms Lake 7.5 24.2 2016 136.11 8.64 0.44 9.07 374.80 Tyee Lake 34 MW [3]11.3 14.3 2016 10.11 0.64 0.66 1.30 90.96 Reynolds Creek 5.0 6.1 2010 4.27 0.27 0.30 0.57 92.77 Notes; 1.Includes interest during construction 2.Plant Life =50 yr,Discount Rate =6%.Capital Recovery Factor =0.0634 3.Incremental values Page 225 Table 8.7:Characteristics of Candidate Diesel Units Fuel Consumption O&M Capital CostNet Economic Output ([HHV]Fixed Variable Total Unit Life Plant/Unit Fuel (MW)(Btu/kWh)(kWh/Gal)(Gal/MWh)($/kWiyr)=($/MWh)($1,000,000)($/kW)(years) HS Diesel #2 Diesel 0.5 10,715 12.91 77.46 60.0 25.0 0.3 600 15 HS Diesel #2 Diesel 1.0 9,880 14.00 71.42 60.0 25.0 0.6 550 15 MS Diesel #2 Diese!2.0 9,100 15.20 65.78 40.0 20.0 2.6 1,300 20 MS Diesel #2 Diesel 3.0 8,950 15.46 64.70 40.0 20.0 3.5 1,150 20 MS Diesel #2 Diesel 5.0 8,700 15.90 62.89 40.0 20.0 5.3 1,050 20 MS Diesel #2 Diesel 10.0 8,550 16.18 61.81 40.0 20.0 10.0 1,000 20 Page 226 Table 8.8:Capacity and Energy Balance with only Local Resources -Reference Forecast -Kake 2007.2008 =2009)Ss 2010 =.2011 2012,2013,2014)=2015 =2016 =2017 =2018 2019 2020 CAPACITY BALANCE [1] 1,Existing and Committed Supply,kW Hydroelectric [2]0 0 0 0 0 0 0 0 0 0 0 0 0 0 Thermal 2,590 2,690 2,590 2,590 2590 2590 2590 2,590 2,590 2590 2,590 2590 2,590 2,590 Total 2,590 2,590 2,590 2590 2590 2,590 2590 2590 2590 2590 2590 2590 2,590 2,590 2.Forecasted Peak Demand,kW 6313 635.3 639.2 643.2 647.3 6514 6555 659.7 6809 7021 7223 7425 761.7 781.0 3.Reserve,MW [4]1,400 1,100 1,100 1,100 1,100 1,100 1,100 1,100 1,100 1,100 1,100 1,100 1,100 1,100 4.Required Capacity,MW {5}1,731 1,735 1,739 1,743 1,747 1,751 1,756 ==1,760 1,781 1,802 1822 1,842 1,862 1,881 5.Capacity Excess (Deficit),kW [6]859 855 851 847 843 839 834 830 809 788 768 748 728 709 ENERGY BALANCE [1] 1.Existing and Committed Supply,MWh Hydroelectric [3]0 0 0 0 0 0 0 0 0 0 0 0 0 0 Thermal [7]10,442 10,442 10,442 10,442 10,442 10,442 10,442 10,442 10,442 10,442 10,442 10,442 10,442 10,442 Total 10,442 10,442 10,442 10,442 10,442 10,442 10,442 10,442 10,442 10,442 10,442 10,442 10442 10,442 2.Forecasted Energy Demand,MWh 3,166 3,186 =3,206 =3,226 =3,246 =3,267 3,288 =3,309 3.415 =3,21 36223724 =3,820 =3,917 3.Energy Excess (Deficit),MW [8]7,276 7,256 =67,236 =7,216 =7,196 =7,175 7,154 7,133 7,027,6,921 6,820 6718 6622 6,525 Notes (1] [2] [3] [4] [5] [6] [7] [8] The capacity and energy balances are based on annual values The hydroelectric plant's capacities are based on installed capacity The hydroelectric energy is based on annual minimum values The reserve is equal to the largest unit The required capacity is the peak demand plus the reserve Capacity excess is the total capacity minus the required capacity Thermal energy is based on 80%plant factor of available units minus reserve Energy excess is the total energy minus the forecasted energy Page 227 Table 8.9 Capacity and Energy Balance with only Local Resources -Reference Forecast -Petersburg and Wrangell A)Petersburg 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 CAPACITY BALANCE (1] 1.Existing and Committed Supply,MW Hydroelectric [2]2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 Thermal 88 85 8.5 85 8.5 8.5 8.5 8.5 8.5 8.5 8.5 85 85 8.5 Total 10.8 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 2.Forecasted Peak Demand,MW 8.4 85 87 8.9 9.6 9.8 9.9 10.1 10.3 10.4 10.6 10.7 10.9 11.0 3.Reserve,MW [4]0 0 0 0 0 0 0 0 0 0 0 0 0 0 4.Required Capacity,MW [5]8.4 85 8.7 8.9 9.6 9.8 9.9 10.1 10.3 10.4 10.6 10.7 10.9 11.0 5.Capacity Excess (Deficit),MW [6]2.4 2.0 18 1.6 0.9 0.7 0.6 0.4 0.2 0.1 -0.1 -0.2 -0.4 0.5 ENERGY BALANCE (1] 1.Existing and Committed Supply,MWh Hydroelectric [3]10,000 10,000 40,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 Thermal [7]61,670 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 Total 71,670 69,568 69,568 69,568 69,568 69,568 69,568 69,568 69,568 69,568 69,568 69,568 69,568 69,568 2.Forecasted Energy Demand,MWh 42,037 42,850 43,650 44,475 48,300 49,105 49,897 50,681 51,458 52,227 52,988 §3,747 54,499 55,243 3.Energy Excess (Deficit),MW [8]29,633 26,718 25,918 25,093 21,268 20,463 19,671 18,887 18,110 17,344 16,580 15,821 15,069 14,325 B)Wrangell 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 CAPACITY BALANCE [1] 1.Existing and Committed Supply,MW Hydroelectric [2]0 0 0 0 0 0 0 0 (°)0 ie)0 0 0 Thermal 8.5 85 8.5)8.5 8.5 8.5 8.5 85 8.5 8.5 8.5 8.5 8.5 8.5 Total 8.5 8.5 8.5 8.5 8.5 8.5 8.5 85 8.5 8.5 85 8.5 8.5 8.5 2.Forecasted Peak Demand,MW 44 5.2 §.3 5.4 5.8 5.9 6.0 6.1 6.2 6.3 6.4 6.5 6.5 66 3.Reserve,MW [4]0 0 0 0 0 0 0 0 0 0 0 0 0 0 4.Required Capacity,MW [5]44 5.2 5.3 5.4 5.8 5.9 6.0 6.1 6.2 6.3 6.4 6.5 6.5 6.6 5.Capacity Excess (Deficit),MW [6]44 3.3 3.2 3.1 2.7 2.6 2.5 2.4 2.3 2.2 2.1 2.0 2.0 1.9 ENERGY BALANCE [1] 1.Existing and Committed Supply,MWh Hydroelectric [3]0 0 0 0 0 0 0 0 0 0 0 0 0 0 Thermal [7]59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 Total 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 59,568 2.Forecasted Energy Demand,MWh 22,300 25,832 26,343 26,845 29,121 29,605.30,085 30,555 31,017 31,475 31,924 32,369 32,810 33,301 3.Energy Excess (Deficit),MW[8]37,268 33,736 33,225 32,723 30,447 29,963 29,483 29,013 28,551 28,093 27,644 27,199 26,758 26,267 Notes (1]The capacity and energy balances are based on annual values (2]The hydroelectric plant's capacities are based on installed capacity [3]The hydroelectric energy is based on annual minimum values [4]The reserve is 0%of peak demand since Wrangell can obtain additional capacity from the Tyee hydroelectric plant (5]The required capacity is the peak demand plus the reserve (6]Capacity excess is the total capacity minus the required capacity (7]Thermal energy is based on 80%plant factor for ail units (8]Energy excess is the total energy minus the forecasted energy Page 228 Table 8.10:Capacity and Energy Balance with only Local Resources -Reference Forecast -Ketchikan and Metlakatla A)Ketchikan 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 CAPACITY BALANCE [1] 1.Existing and Committed Supply,MW Hydroelectric (2]12.3 12.3 12.3 12.3 12.3 12.3 12.3 12.3 12.3 12.3 12.3 12.3 12.3 12.3 Thermal 22.7 22.7 22.7 22.7 22.7 22.7 22.7 22.7 22.7 22.7 22.7 22.7 22.7 22.7 Total 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 2.Forecasted Peak Demand,MW 32.7 33.8 34.4 35.5 36.1 38.2 38.8 40.6 41.2 41.8 42.4 43.0 43.5 44.1 3.Reserve,MW [4]0 0 0 0 0 0 0 0 0 0 0 0 0 0 4.Required Capacity,MW [5]32.7 33.8 34.4 35.5 36.1 38.2 38.8 40.6 41.2 41.8 42.4 43.0 43.5 44.1 5.Capacity Excess (Deficit),MW [6]2.3 1.2 0.6 -0.5 -1.1 3.2 -3.8 -5.6 6.2 6.8 7.4 8.0 -8.5 -9.1 ENERGY BALANCE [1] 1.Existing and Committed Supply,MWh Hydroelectric [3]57,600 57,600 57,600 57,600 57,600 57,600 57,600 57,600 57,600 57,600 57,600 57,600 §7,600 57,600 Thermal [7]159,082 159,082 159,082 159,082 159,082 159,082 159,082 159,082 159,082 159,082 159,082 159,082 159,082 159,082 Total 216,682 216,682 216,682 216,682 216,682 216,682 216,682 216,682 216,682 216,682 216,682 216,682 216,682 216,682 2.Forecasted Energy Demand,MWh 164,195 169,479 172,659 178,038 181,141 191,484 194,515 203,595 206,592 209,558 212,512 215,441 218,346 221,265 3.Energy Excess (Deficit),MW [8]52,487 47,202 44,022 38,644 35,541 25,198 22,167 13,087 10,090 7,124 4,170 1,240 -1,665 -4,583 B)Metlakatia 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 CAPACITY BALANCE [1] 1.Existing and Committed Supply,MW Hydroelectric [2]49 49 49 49 49 49 49 49 49 49 49 49 49 49 Thermal 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 Total 8.2 8.2 8.2 82 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 2.Forecasted Peak Demand,MW 3.1 3.1 3.2 3.3 3.3 3.4 3.4 3.5 3.5 3.6 3.6 3.7 3.7 3.8 3.Reserve,MW [4]0.9 0.9 1.0 1.0 1.0 1.0 1.0 4.0 11 1.1 11 11 1.1 14 4.Required Capacity,MW [5]4.0 41 4.2 4.2 43 44 44 45 46 47 47 48 49 49 §.Capacity Excess (Deficit),MW [6]4.2 41 4.0 40 3.9 3.8 3.8 3.7 3.6 3.5 3.5 3.4 3.3 3.3 ENERGY BALANCE [1] 1.Existing and Committed Supply,MWh Hydroelectric (3)12,800 12,800 12,800 12,800 12,800 12,800 12,800 12,800 12,800 12,800 12,800 12,800 12,800 12,800 Thermal [7]23,126 23,126 23,126 23,126 23,126 23,126 23,126 23,126 23,126 23,126 23,126 23,126 23,126 23,126 Total 35,926 35,926 35,926 35,926 35,926 35,926 35,926 35,926 35,926 35,926 35,926 35,926 35,926 35,926 2.Forecasted Energy Demand,MWh 15,434 15,731 16,023 16,311 16,595 16,874 17,149 17,426 17,698 17,966 18,230 18,494 18,789 19,079 3.Energy Excess (Deficit),MW [8]20,492 20,196 19,903 19,615 49,332 19,052 18,777 18,501 18,228 17,961 17,697 17,432 17,138 16,847 Notes [(1]The capacity and energy balances are based on annual values {2]The hydroelectric plant's capacities are based on installed capacity [3]The hydroelectric energy is based on annual minimum values [4]The reserve is 0%of peak demand since Ketchikan can obtain additional capacity from the Swan hydroelectric plant.For Metlakatla the reserve was set at 30%of peak demand [5]The required capacity is the peak demand plus the reserve [6]Capacity excess is the total capacity minus the required capacity (7]Thermal energy is based on 80%plant factor for all units [8]Energy excess is the total energy minus the forecasted energy Page 229 Table 8.11;Capacity and Energy Balance with only Local Resources -Reference Forecast -POW A)POW South 2007 2008]2009 2010)2011 2012 2013)2014)2015]2016)2017|2018)2019 2020] CAPACITY BALANCE [1] 1.Existing and Committed Supply,MW Hydroelectric [2]6.5 65 6.5 6.5 6.5 65 6.5)6.5)6.5 6.5 6.5 6.5 6.5 65 Thermal 9.3 9.3 9.3 9.3 9.3 9.3)9.3 9.3 9.3 9.3)9.3 9.3 9.3 9.3 Total 15.8 15.8)15.8)16.8)15.8)15.3)15.8 15.8 15.8)15.8 15.8 15.8 15.8)15.8) 2.Forecasted Peak Demand,MW 5.1 5.2|5.2|5.3 5.3 5.4]5.4]5.5|5.5]5.6 5.6 5.7 5.7 59 3.Reserve,MW [4]16 1.6)1.6]1.6]16 16]1.6]1.6 1.6 16 1.6 1.6]1.6 1.6) 4.Required Capacity,MW [5]6.7 6.8 6.8)6.9)69)7.0)7.0)7.4 7.4 7.2)7.2 73)re)75 §.Capacity Excess (Deficit),MW [6]9.0 9.0 8.9 8.9 8.8 8.8 8.7 8.7 8.6 8.6 85 85 8.4)83 ENERGY BALANCE (1) 1.Existing and Committed Supply,MWh Hydroelectric [3]24,700}24,700;24,700 24,700}24,700)24,700)24,700)24,700)24,700]24,700)24,700)24,700)24,700 24,700] Thermal [7]64,824)64,824)64,824)64,824)64,824)64,824 64,824 64,824)64,824)64,824)64,824]64,824 64,824)64,824 Total 89,524]89,524)89,524]89,524)89,524)89,524)89,524 89,524 89,524 89,524]89,524]89,524!89,524 89,524 2.Forecasted Energy Demand,MWh 25,685)25,920)26,157 26,395)26,636)26,878)27,122)27,368)27,616)27,866)28,117]28,371 28,627 29,475) 3.Energy Excess (Deficit),MW [8]63,839]63,604!63,367 63,129]62,889}62,646)62,402)62,156 61,908]61,658)61,407 61,153}60,897 60,049 B)Coffman Cove 2007)2008 2009;2010)2011 2012 2013)2014 2015 2016 2017 2018 2019)2020] CAPACITY BALANCE [1] 1.Existing and Committed Supply,kW Hydroelectric [2]0 ie)0 [e)it)i)iy)0 0 0 it)0 Q 0 Thermal 740 740 740 740 740 740 740 740)740 740 740 740 740 740 Total 740)740 740 740 740)740)740)740 740)740 740 740 740 740 2.Forecasted Peak Demand,kW 178.5 179.6)180.7,181.9)183.0)184.2]185.4)186.6)187.8 189.0 190.2 191.5)192.8)205.7 3.Reserve,MW [4]330 330 330 330 330 330 330 330 330 330!330 330 330)330 4.Required Capacity,MW [5]508 510 541 512 513)514 515)517]518)§19 520 §22 523 536 5.Capacity Excess (Deficit),kW [6]232 230)229 228 227 226)225)223 222 221 220 218 217 204 ENERGY BALANCE [1] 1.Existing and Committed Supply,MWh Hydroelectric (3]0 0 0 0 0 0 0 [¢)0 0 0 0 0]0 Thermal [7]5,186 5,186 5,186 5,186 5,186 5,186 5,186 5,186 §,186 5,186]5,186)5,186 5,186 §,186 Total 5,186)5,186]5,186 5,186)5,186)5,186 5,186 5,186 §,186 5,186)5,186)5,186 5,186)5,186 2.Forecasted Energy Demand,MWh 895]901 906 912 918 924 930 936 942)948 954 960 967 1,031 3.Energy Excess (Deficit),MW [8]4,291 4,285)4,280)4,274 4,268;4,262)4,256]4,250 4,244 4,238 4,232)4,226 4,219)4,154 C)Naukatl 2007'2008]2009)2010)2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 CAPACITY BALANCE {1} 1.Existing and Committed Supply,KW Hydroelectric [2]Le)0 0 0}fe)0 0 0 Le)iv)ie)0 ty)0 Thermai 478)478 478 478)478 478 478 478)478)478)478 478)478)478 Total 478 478 478 478 478)478)478)478)478 478 478 478)478 478 2.Forecasted Peak Demand,kW 95.6 95.9 96.2 96.5)96.8)97.1 97.4 97.7 98.0)98.3 98.6]99.0)99.3]101.7 3.Reserve,MW [4]175 175 175)175 175 175:175 175)175 175 175)175 175 175 4.Required Capacity,MW [5]271 271 271 272 272]272 272 273)273 273 274 274 274 277 5.Capacity Excess (Deficit),kW [6]207 207 207 206 206 206 206 205 205 205)204|204 204 201 ENERGY BALANCE [1] 14.Existing and Committed Supply,MWh Hydroelectric [3]0 0 ie)it]0}0 i)0 q 0 it)0 tt)0 Thermal [7}3,350!3,350 3,350)3,350)3,350)3,350 3,350)3,350)3,350 3,350 3,350]3,350 3,350}3,350) Total 3,350 3,350)3,350 3,350)3,350)3,350 3,350)3,350]3,350)3,350 3,350 3,350)3,350 3,350] 2.Forecasted Energy Demand,MWh 480)481 483)484 486 487 489 490)492 493 495)496 498 510 3.Energy Excess (Deficit),MW [8]2,870 2,869 2,867 2,866 2,864 2,863 2,861 2,860]2,858 2,857 2,855 2,854 2,852]2,840 Notes [1]The capacity and energy balances are based on annual values (2]The hydroelectric plant's capacities are based on installed capacity [3]The hydroelectric energy is based on annual minimum values [4]The reserve is equal to the largest unit [5]The required capacity is the peak demand plus the reserve [6]Capacity excess is the total capacity minus the required capacity [7]Thermal energy is based on 80%plant factor of available units minus reserve [8]Energy excess is the total energy minus the forecasted energy Page 230 Table 8.12:Unit Additions -Reference Forecast Unit Additions Supply Scenario Diesel Units |Whitman]!Mahoney|Connell |Carlana |Triangle |Cascade |Scenery Lake Lake Lake Lake Lake Creek Lake Region:Tyee 1 Wrangell +Petersburg &2MW @ ------- Kake Isolated Petersburg 2017 2 Wrangell +Petersburg &2 MW @ ------- Kake connected in 2011 Petersburg 2017 Region:Swan 3 Ketchikan Isolated -2010 2011 2015 2020 --- 4 Metlakatla Isolated -----2022 -- 5 Ketchikan +Metlakatla -2010 2011 2015 2020 2018 -- Interconnected in 2013 Region:Tyee and Swan 6 STlin 2010 2MW @ 2010 2014 2018 -2024 -- Petersburg 2017 Export Case 7 Exports Start in 2015 2MW @ 2010 2014 2018 --2015 2017 Petersburg 2017 Unit Additions Supply Scenario Diesel Units |Reynolds Creek Region:POW 8 POW South +Coffman Cove &-2021 Naukati Page 231 Table 8.13:Unit Additions -Low Load Forecast Unit Additions Supply Scenario Diesel Units |Whitman |Mahoney]Connell |Carlana |Triangle |Cascade |Scenery Lake Lake Lake Lake Lake Creek Lake Region:Tyee 1 Wrangell +Petersburg &2MW @ ------ Kake Isolated Petersburg 2026 2 Wrangell +Petersburg &2MW @ ------ Kake Interconnected in 2011 Petersburg 2026 Region:Swan 3 Ketchikan Isolated -2010 2011 2015 2028 --- 4 Metlakatla Isolated ----2024 -- 5 Ketchikan +Metlakatla -2010 2011 2015 2028 2024 -- Interconnected in 2013 Region:Tyee and Swan 7 STlin 2010 2 MW @ 2010 2020 2024 --- Petersburg 2026 Export Case 8 Exports Start in 2015 2MW @ 2010 2020 2024 -2015 2017 Petersburg 2026 Unit Additions Supply Scenario Diesel Units |Reynolds Creek Region:POW 9 POW South +Coffman Cove &2025 Naukati Table 8.14:Unit Additions -High Load Forecast Unit Additions Supply Scenario Diesel Units {Whitman |Mahoney]Connell |Carlana |Triangle Tyee Cascade |Scenery Lake Lake Lake Lake Lake |Extension|Creek Lake Region:Tyee 1 Wrangell +Petersburg &2 MW @ 20138 -------- Kake Isolated 2025 Petersburg 2 Wrangell +Petersburg &2 MW @ 2013&-------- Kake Interconnected in 2011 2025 Petersburg Region:Swan 3 Ketchikan Isolated 5 MW 2026 2010 2011 2015 2020 ---- 4 Metlakatia Isolated -----2018 --- 5 Ketchikan +Metlakatla 5 MW 2026 2010 2011 2015 2016 2015 --- Interconnected in 2011 Region:Tyee and Swan 6 STI in 2010 2 MW @ 2013&2010 2012 2015 2016 2018 2017 -- 2025+SMW 2026 Export Case 7 Exports Start in 2015 2 MW @ 20138 2010 2012 2015 2016 --2015 2017 2025+SMW 2026 Unit Additions Supply Scenario Diesel Units |Reynolds Creek Region:POW 8 POW South +Coffman Cove &2021 Naukati Page 233 Table 8.15:Summary of Results -Load Growth Sensitivity Cumulative Present Value of Costs Scenario to January 2007 @ 6%($,millions) Load Growth Low Reference High Region:Tyee 1 Wrangell +Petersburg &107.6 117.0 125.3 Kake !solated 2 Wrangell +Petersburg &101.1 109.4 117.7 Kake Interconnected in 2011 3 Benefits of Connecting Kake (1-2)6.5 75 7.6 Region:Swan 4 Ketchikan Isolated 234.0 271.9 316.1 5 Metlakatla Isolated 23.7 25.3 25.9 6 Ketchikan +Metlakatla 254.7 294.0 335.3 Interconnected in 2013 7 Benefits of Connecting Ketchikan &Metlakatla (4+5-6)3.1 3.2 6.7 Region:POW 8 POW South +Coffman Cove &53.1 58.3 60.2 Naukati 9 POW South +Coffman Cove &54.8 60.6 64.6 Naukati connected with Capital Cost 10 POW South +Coffman Cove &50.1 55.8 59.9 Naukati connected with Capital Cost 11 Benefit of Connecting Coffman Cove 3.0 2.5 0.3 &Naukati Without Capital Cost (8-10) Region:Tyee and Swan 12 Isolated (2+6)355.8 403.4 453.0 13 Interconnected in 2010 320.8 370.2 417.4 14 Benefits of STI in 2010 (12-13)35.0 33.2 35.6 Export Case 15 Exports Start in 2015,No Triangle 311.9 337.7 371.0 Cascade &Scenery Only 19 Benefits of Exports in 2015 (13-15)8.9 32.5 46.4 Page 234 Table 8.16:Summary of Results -Capital and O&M Costs Sensitivity Scenario Cumulative Present Value of Costs @ 6%to January 2007 ($,million) 0%Increase 20%Increase Region:Tyee 1 Wrangell +Petersburg & Kake Interconnected in 2011 Region:Swan 2 Ketchikan +Metlakatla Interconnected in 2013 Region:Tyee and Swan 3 Isolated (1+2) 4 Interconnected in 2010 5 Benefits of STI in 2010 (3-4) Region:POW 6 POW South +Coffman Cove & Naukati connected without Capital Cost Export Case 7 Exports Start in 2015,No Triangle Cascade &Scenery Only 8 Benefits of Exports in 2015 (4-7) 109.4 294.0 403.4 370.2 33.2 55.8 337.7 32.5 110.8 307.2 418.0 384.3 33.7 57.0 395.2 -10.9 Page 235 Table 8.17:Summary of Results -Sensitivity to Changes in Fuel Price Cumulative Present Value of Costs Scenario @ 6%to January 2007 ($,million) Change in Fuel Price -15%0%15% Region:Tyee 1 Wrangell +Petersburg &107.8 109.4 111.1 Kake Interconnected in 2011 Region:Swan 2 Ketchikan +Metlakatla 279.2 294.0 308.7 Interconnected in 2013 Region:Tyee and Swan 3 Isolated (1+2)387.0 403.4 419.8 4 Interconnected in 2010 358.7 370.2 381.7 5 Benefits of STI in 2010 (3-4)28.4 33.2 38.1 Region:POW 6 POW South +Coffman Cove &54.2 55.8 57.5 Naukati connected without Capital Cost Export Case 7 Exports Start in 2015,No Triangle 332.9 337.7 342.5 Cascade &Scenery Only 8 Benefits of Exports in 2015 (4-7)25.7 32.5 39.2 Page 236 Table 8.19:Estimated Emissions for Cases Without Conversion of Oil Fired Heating Furnaces Isolated Case Isolated Case With STI Interconnected Case With STI Year co2 SOx co NOx Year co2 SOx co NOx Year co2 SOx co NOx (ton)(ton)(ton)(ton)___(ton)(ton)(ton)(ton)(ton)(ton)(ton)(ton) 2007 28,036 195 127 556 2007 28,036 195 127 556 2007 28,036 195 127 556 2008 31,890 221 140 612 2008 31,890 221 140 612 2008 31,890 221 140 612 2009 34,217 237 146 638 2009 34,217 237 146 638 2009 34,217 237 146 638 2010 26,217 180 101 442 2010 13,592 92 42 181 2010 13,592 92 42 181 2011 18,520 4125 52 226 2011 17,134 115 46 198 2011 15,153 102 36 157 2012 22,891 154 56 243 2012 22,221 149 53 229 2012 20,228 135 44 188 2013 24,458 164 59 256 2013 23,907 160 56 244 2013 21,715 145 46 199 2014 28,625 191 64 278 2014 28,900 193 66 284 2014 23,336 155 39 169 2015 30,262 202 68 292 2015 27,377 182 54 232 2015 24,900 165 42 181 2016 31,898 213 71 307 2016 28,969 193 57 246 2016 26,431 175 45 194 2017 33,551 224 75 323 2017 30,532 203 60 260 2017 27,930 185 48 206 2018 35,193 235 78 339 2018 32,075 214 64 274 2018 29,548 196 52 222 2019 36,829 246 82 355 2019 33,606 224 67 288 2019 31,402 208 56 242 2020 38,466 257 86 371 2020 35,377 236 71 307 2020 33,416 222 62 267 2021 40,087 268 90 387 2021 37,279 249 76 329 2021 35,414 235 67 291 2022 40,288 269 87 375 2022 37,777 252 75 323 2022 37,396 249 73 315 2023 41,910 280 91 392 2023 39,664 264 80 346 2023 35,394 234 60 257 2024 43,693 292 96 413 2024 41,528 277 85 368 2024 37,314 247 65 281 2025 42,179 281 85 366 2025 43,375 289 91 391 2025 39,230 260 71 305 2026 43,638 291 88 381 2026 36,848 243 56 240 2026 33,952 223 42 180 2027 45,128 301 92 397 2027 38,154 252 59 252 2027 35,250 232 45 192 2028 46,731 312 96 415 2028 39,488 261 62 265 2028 36,568 241 48 205 2029 48,418 323 101 435 2029 40,935 271 65 280 2029 38,014 250 52 220 2030 48,704 325 99 427 2030 42,365 280 69 296 2030 39,443 260 55 235 2031 50,370 336 104 447 2031 43,797 290 72 311 2031 40,872 270 59 251 Total |912,198 |6,123 |2,235 |9,672 Total |829,041 {5,543 |1,840 {7,952 Total |770,639 {|5,135 |1,564 |6,743 Page 238 Table 8.20:Estimated Emissions for Cases With Conversion of Oil Fired Heating Furnaces Isolated Case Isolated Case With STI Interconnected Case With STI Year co2 SOx co NOx Year co2 SOx co NOx Year Cco2 SOx co NOx (ton)(ton)(ton)(ton)(ton)(ton)(ton)(ton)(ton)(ton)(ton)(ton) 2007 27,962 195 133 579 2007 27,962 195 133 579 2007 27,962 195 133 579 2008 31,980 223 152 662 2008 31,980 223 152 662 2008 31,980 223 152 662 2009 34,618 241 164 716 2009 34,618 241 164 716 2009 34,618 241 164 716 2010 25,086 175 119 519 2010 7,369 51 35 152 2010 7,369 51 35 152 2011 14,202 99 67 294 2011 8,514 59 40 176 2011 6,616 46 31 137 2012 18,331 128 87 379 2012 10,939 76 52 226 2012 9,168 64 43 190 2013 19,657 137 93 407 2013 12,161 85 58 252 2013 9,885 69 47 205 2014 23,868 166 113 494 2014 9,154 64 43 189 2014 6,120 43 29 127 2015 22,343 156 106 462 2015 10,102 70 48 209 2015 6,867 48 33 142 2016 23,893 167 113 494 2016 11,068 77 52 229 2016 8,080 56 38 167 2017 25,625 179 121 530 2017 12,432 87 59 257 2017 9,653 67 46 200 2018 27,362 191 130 566 2018 42,006 84 57 248 2018 9,026 63 43 187 2019 29,106 203 138 602 2019 13,646 95 65 282 2019 10,590 74 50 219 2020 29,481 206 140 610 2020 15,383 107 73 318 2020 12,175 85 58 252 2021 31,215 218 148 646 2021 17,112 119 81 354 2021 13,789 96 65 285 2022 29,803 208 141 617 2022 15,702 110 74 325 2022 15,595 109 74 323 2023 31,323 218 149 648 2023 17,233 420 82 357 2023 17,571 123 83 364 2024 32,858 229 156 680 2024 18,999 133 90 393 2024 19,542 136 93 404 2025 34,413 240 163 712 2025 20,824 145 99 431 2025 21,505 150 102 445 2026 35,980 251 171 744 2026 22,680 158 108 469 2026 19,778 138 94 409 2027 37,540 262 178 777 2027 24,551 171 116 508 2027 21,701 151 103 449 2028 39,127 273 186 810 2028 26,418 184 125 547 2028 23,648 165 112 489 2029 40,906 285 194 846 2029 28,310 197 134 586 2029 25,615 179 121 530 2030 42,787 298 203 885 2030 30,207 211 143 625 2030 27,588 192 131 571 2031 44,692 312 212 925 2031 32,305 225 153 668 2031 29,760 208 141 616 Total |754,157 |5,260 |3,576 |15,603 Total |471,672 {3,290 |2,236 |9,759 Total |426,202 |2,972 }2,021 |8,818 Page 239 450.0 ---___-__,-- Total System Load w/Heat Conversion T 7 (I 400.0 4 |- g 350.0 |--__]: O ..300.0 |Spill c "Whitman 5 250.0 77|Purple /Chester 5 re&200.0 +Tyee Sh c 150.0< 100.0 Blind Slough Swan 30.0 Beaver Falls 0.0 Se A OO NSN GM oOaa Figure 8.1 Annual Energy Generation Without STI 450.0 | 400.0 Total System 1 4 350.0 300.0 | Load w/Heat Conversion Whitman©) I =250.0=)i Tyee 3 =|Purple /Chester§200.0 | Yoa.150.0<7 100.0 Blind Slough FF Swan 50.0 |Beaver Falls aK etchi kan:0.0 ''' "A Se)o "Vv hel we)'o A ©Oo ke)Vv 4 we 'o "A &O STSNSPerereerIiJFMIMIMIPMMMISsMSCOSEESETEEEEESESESEEEEESEESS Figure 8.2 ZHATCH Annual Energy Generation With STI ExportEnergy(GWh5.0 |----=]0.0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Figure 8.3 Z HATCH Export Energy Under Average Hydrologic Conditions energy HATH AGES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska 9.CONCLUSIONS AND RECOMMENDATIONS AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 9.CONCLUSIONS AND RECOMMENDATIONS 9.1 Overview This section of the Report presents the conclusions and recommendations based on the analysis performed with the information available as of April 5,2007.This information is for consideration by the AEA as they consider whether the scenarios identified in this Report "involve a reasonable amount of public contribution of infrastructure,and reasonable expectations that Alaskan power production businesses will produce and sell power at low cost in Southeast Alaska and be able to export the excess over the long term.” Potential future work may include activities described in three categories: e Phase II AK-BC Intertie Feasibility Study Tasks e Actions for AEA with Assistance by Contractor e Monitor Actions by 3%Parties and Consider Need for Additional Independent Analyses. 9.2 Conclusions 9.2.1 Proposed Transmission and Generation Projects Transmission line segments are assumed to be grant-financed,new hydro projects would be developed and financed by utilities or private developers.Transmission lines to connect hydro resources to load centers,connect load centers to each other in order to share resources and connect regions to share resources and decrease hydro surplus were judged economic for SE Alaska. 9.2.1.1 Swan-Tyee Intertie (STI) e The STl as proposed demonstrates strong economic value to ratepayers of SE Alaska e The STI is economic starting in 2010,the year it is proposed to be in service,and is technically feasible and fully permitted.Delay in the timing could decrease the overall benefits e The STI would transmit current surplus hydro energy from the Tyee Lake hydro plant to Ketchikan and,to Metlakatla when the proposed future transmission segment between Ketchikan and Metlakatla is completed e Delivery of power from Tyee Lake to Ketchikan will offset diesel generation and encourage additional institutional,commercial &residential conversions to electric heating,displacing oil heat with clean,renewable hydropower e Asa result of the sensitivity analysis,it can be stated that load growth changes,increases in capital and O&M costs as well as changes in fuel prices have no significant impact on the overall economic viability of the STI. Hatch Acres Corporation PR324582.Rev.0,Page 244 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACHES 9.2.1.2 9.2.1.3 9.2.1.4 Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Other Line Segments in SE Alaska Transmission segments to interconnect Metlakatla with Ketchikan and Kake with Petersburg are technically feasible and would provide benefits to the ratepayers of SE Alaska The Kake-Petersburg Transmission Intertie (KPTI)is economic beginning in 2011 and possibly earlier.The KPT!would provide access for Kake ratepayers to relatively low-cost hydropower,displacing diesel generation and facilitating conversion from oil heat to electric heat;and could spur new economic development The Metlakatla to Ketchikan Transmission Intertie is economic starting in 2013 and possibly earlier.This segment would provide enhanced reliability and may encourage development of a proposed new hydro project on Annette Island Connection of the Coffman Cove and Naukati load centers to the rest of the load centers already connected in POW is economic starting in 2011 Connection of POW to Wrangell was found to be uneconomic as the load forecast indicates demand on POW will remain relatively low and given the necessary design and routing for the transmission line,its annual O&M costs would be relatively high. AK-BC Intertie The AK-BC Intertie would provide a further opportunity to secure the energy future for SE Alaska The technical feasibility and market potential of the proposed future hydro facilities and related transmission features look promising but cannot be definitively determined at this time The regulatory process to approve the proposed AK-BC Intertie segment within SE Alaska is well defined and no fatal flaws were identified.The proposed segment in BC has not been studied and could face environmental &institutional challenges. Power Generation SE Alaska communities'future electricity needs as estimated in the load forecasting task can be met by a combination of power generated by hydro projects and diesel plants delivered on an interconnected electric transmission system The levelized unit costs of energy from hydro projects identified as potential candidates to meet demand in SE Alaska range between 45 and 374 $/MWh.Hydro resources retained for further analysis would generate power at costs ranging from 45 to 91 $/MWh (levelized dollars) Diesel units ranging in size from 500 kW to 10 MW were considered to meet capacity requirements.However,due to high fuel costs diesel units were considered only for reserve duty and no significant amount of generation is expected from this source Hatch Acres Corporation PR324582.Rev.0,Page 245 AK-BC Alaska Final Report 18-09-07.Doc HAG AGRA e When the STI is completed,coordinated operation of the existing hydro projects in Petersburg and Ketchikan with the combined Swan Lake and Tyee Lake hydro project operations would result in the following: Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report o The coordinated operation of the reservoir system will result in less overall spill as well as a more uniform distribution of energy through each water year o More ability to operate units within each plant at their respective points of maximum efficiency o More flexibility in the timing of planned outages. e If the State can be assured that proposed new generation projects intended primarily for the export of power are constructed so they will be able to produce power for 50 years (the term of their FERC license),this would have a positive impact on the marketability of their outputs e Licensing proposed hydro facilities faces significant,but not necessarily insurmountable, environmental &institutional challenges. 9.2.1.5 Un-quantified Benefits Resulting From Interconnected Electric Transmission System Several benefits to the SE Alaska ratepayers and communities would likely result from an interconnected electric transmission system.They are not quantified in the economic analysis performed to date.These include: e Reduction of current levels of GHG from diesel generation e Reduction in total spinning reserve requirements e More conversions from oil to electric heat and resulting economic and GHG reduction benefits e Gains in energy through coordinated operation of hydro plants e Assistance during maintenance outages e Possible reduction in PCE subsidy payments e Multiplier effects of increased economic development and increased disposable income resulting from lower energy prices. 9.2.2 Business Structures,Southeast Alaska Market,External Market,and Regulatory Issues 9.2.2.1 Business Structures Section 2 of this Report discusses options for the Business Structure that would provide a comprehensive organization to manage a future interconnected transmission system within SE Alaska and expand to the export market when further clarification regarding the interests of BC to interconnect and determination of feasibility as regards cost of power for new generation are confirmed. Hatch Acres Corporation PR324582.Rev.0,Page 246 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES 9.2.2.2 9.2.2.3 Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report In the near-term,SE Alaska could benefit from implementing the proposed Unified System Operator to manage integrated operation of the future interconnected transmission lines within the region. Southeast Alaska Market SE Alaska communities future electricity needs can be met by a combination of power generated by hydro projects and diesel plants delivered on an interconnected electric transmission system. The capacity and energy balances for the individual load centers indicated that for the reference growth load forecast only Petersburg and Ketchikan would encounter a capacity deficit during the study period.In addition,Ketchikan would also encounter an energy deficit.Due to the lack of potential future small cost effective hydro projects in Petersburg, a diesel unit was assumed to be in-service to mitigate the capacity deficit.The deficits in Ketchikan were resolved with the introduction of 4 new hydro projects. External Markets Power demands in BC and the PNW are expected to grow substantially over the next 10 -20 years and electricity policy changes related to reduction of greenhouse gas emissions (GHG)represent export opportunity for competitively priced power from SE Alaska projects.The economics of exports of power are directly impacted by the capital costs of the projects supplying the power,the export price,the period of capital repayment,capital cost increases in the projects supplying the power and the discount rate. 9.2.2.4 e Export of energy from 2015 onwards to BC and/or the PNW from the proposed Thomas Bay projects and other projects developed for purpose of export appears to be economic at a discount rate of 6%.Higher discount rates generate overall negative benefits SE Alaska hydro projects need to meet the current delivered market price of approximately $70/MWh.Assuming power delivery costs of $10/MWh,generating costs would need to not exceed the $60/MWh range If generating costs exceed $60/MWh,competitiveness depends on GHG restrictions increasing future BC/PNW market prices State involvement in a power marketing oversight role as presented in the discussion of Business Structures in this Report would enhance the potential that new projects could produce power for 50 years substantially increasing marketability. Regulatory Issues No "fatal flaws”regarding development of proposed AK-BC Intertie to border with Canada Further consultations required with BC regarding the line segment from the border to the nearest point of interconnection with the BCTC system Hatch Acres Corporation PR324582.Rev.0,Page 247 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACRES e New export projects at Thomas Bay require FERC licenses.Potential cost of power is dependent on operating restrictions that may be imposed in any future issued FERC license terms and conditions.No "fatal flaw”identified with probability of FERC issuing licenses. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 9.3.Recommendations 9.3.1 Phase Il AK-BC Intertie Feasibility Study Tasks The Contract with AEA states: "Phase Il may occur if a scenario is identified that involves a reasonable amount of public contribution of infrastructure,and reasonable expectations that Alaskan power production businesses will produce and sell power at low cost in Southeast Alaska and be able to export the excess over the long term. If the feasibility findings are positive,the contract may be extended and amended so the Contractor can provide assistance to AEA in bringing a development plan forward.”!”° Based on the conclusions presented in 9.2 above,the following tasks are presented for consideration by AEA. 9.3.1.1 Overarching Issues and Tasks e Assist in developing a SE Alaska Energy Policy e Assist State of Alaska in consultations with BC government and utilities in BC and PNW e Assist AEA in developing and negotiating agreements between Governments,utilities,and private sector developers e Assist AEA in obtaining additional expertise or resources as needed by AEA to oversee the project e Provide Project Management for a steering committee as may be requested by AEA. 9.3.1.2 Business Structure e Assist AEA in future considerations regarding alternative Business Structures. 9.3.1.3 Southeast Alaska Market e Refine load forecast for SE Alaska utilities with focus on the potential for conversions from oil-based heating to electric heat.Customer surveys could be considered in order to obtain better information on the current heating infrastructure and customer intentions for the future. 0 Contract with AEA -C.3 Phase Il Summary -Development Assistance for AK-BC Intertie Project Hatch Acres Corporation PR324582.Rev.0,Page 248 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRESTeereentnrenenntenneORRRHNNENDRIER Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 9.3.1.4 External Markets e Monitor implementation of policies set forth in BC Energy Plan to identify potential for projects in SE Alaska to provide energy to BC and the PNW.(See Section 3.6 of Report) e Monitor emerging market opportunities in BC &PNW and advise AEA e.g.future BC Hydro &PNW utility RFPs for power. 9.3.1.5.Regulatory Issues e Consult with RCA and FERC regarding regulatory structure for AK-BC Intertie.Note that legal counsel will be required to file the request for Declaratory Order with the FERC to determine interstate commerce jurisdiction e Monitor progress of RCA rulemaking to implement a State Small Hydro Licensing Program (5 MW or less). 9.3.1.6 Transmission Line Costs and Issues e Extend studies to develop more accurate capital and O&M cost estimates for planned transmission segments e Continue to monitor progress and consult with BCTC regarding the proposed NTL line and the segment from the NTL to the AK/BC border e Consult with BCTC regarding contractual terms and related costs to achieve interconnection e Monitor developments in SE Alaska and BC and propose a critical path for development of the transmission segments required to export power generated in Alaska to BC/PNW:AK- BC Intertie from Tyee Lake to AK/BC border;segment from border to interconnection with BCTC;and proposed line to connect potential new hydro projects at Thomas Bay to the FDPPA line segment from Petersburg to Tyee Lake e Develop and/or manage a process for choosing developers of state-sponsored transmission segments. 9.3.1.7 Power Generation Costs and Issues e The decision to proceed with a transmission system and institutional mechanism to enable the export of power from SE Alaska is heavily dependent upon the development costs for the Thomas Bay projects including the Scenery Lake,Delta Creek,and Cascade Creek projects.Accordingly,it is recommended that an independent evaluation of the energy potential and development cost of these projects be performed in a manner similar to a "Due Diligence Review”as generally required by banking institutions prior to approval of financing construction or acquisition of a major project e Monitor development of renewable resource projects including tidal energy,geothermal, and offshore wind energy.As proposals come forward,consider the "fit”of these projects to an overall energy portfolio for SE Alaska Hatch Acres Corporation PR324582.Rev.0,Page 249 AK-BC Alaska Final Report 18-09-07.Doc WATCH ACHES e Conduct studies to identify the potential benefits of coordinated operation of the existing hydro projects to maximize power operation and related reservoir operations Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report e Develop more accurate cost estimates for candidate generation projects e Develop more accurate calculation of monthly generation from existing and candidate hydro projects e Advise State of Alaska in opportunities to shape future hydro projects by active involvement in FERC license proceedings e Assist the FDPPA and municipal utilities in identifying the benefits of integrated operation of existing hydro projects with the STI in place e Assist AEA in participating in proceedings before the FERC for proposed Applications for License proposed to use the state-sponsored transmission segments (e.g.Current proceedings for Thomas Bay Projects under FERC Preliminary Permit)to ensure that State interests are addressed and measures included in the license to ensure that projects will be constructed and operated to deliver power over a 50-year period. 9.3.1.8 |Computer Model e Enhance the Regional Resource Planning Model (RRPM)developed during Phase I to include constraints of transmission line capacity e Develop and provide detailed user manual and conduct training seminars on the use of the RRPM e Develop a method to quantify other benefits not included in the present analysis e Rerun the RRPM as updated energy and cost data becomes available from project proponents e Investigate additional scenarios and update the economic analysis performed on the scenarios developed in Phase II. 9.3.2 Actions for AEA with Assistance by Contractor 9.3.2.1 Proposed Business Structure Review options presented for the proposed Business Structure:Transmission Cooperative,Unified System Operator,Power Marketing Oversight,and/or State of Alaska Transmission Owner/Operator.This could include the following: e Continue consultations with all potential members regarding adoption and the management and operations structure e Discuss how to integrate transmission segments owned by third parties essential to successful future operations. Hatch Acres Corporation PR324582.Rev.O,Page 250 AK-BC Alaska Final Report 18-09-07.Doc HATGH AGHA 9.3.2.2 Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Continue to monitor developments in BC and Alaska as regards the development schedule for the interconnection with BC Continue to monitor potential development of Alaska projects where the stated objective is to generate power for export to BC and/or the Lower 48;discuss options for future ownership/operation of transmission segments connecting projects to the proposed interconnected transmission system Continue consultations with all potential users of the proposed interconnected electric transmission system regarding adoption ofa USO,its roles and responsibilities,and_its future management and operations protocols Consult with current project owners and potential future project developers to develop proposed future structure and management of the proposed Power Marketing Oversight Unit.Investigate potential future market opportunities and engage in consultation with potential future purchasers. Determine Level of State/Federal Jurisdiction Consult with the RCA,the FERC,and any appropriate agencies within BC to discuss how,and at what level,the future operations would be regulated.Develop a schedule and engage legal counsel to prepare necessary filings to confirm regulatory jurisdiction. 9.3.3 Monitor Actions by 3 Parties and Consider Need for Additional Independent Analyses: Market developments in BC and PNW e.g.future BC Hydro &PNW utility RFPs for power Applications filed with FERC for license for proposed projects (e.g.Thomas Bay) Decisions to construct licensed projects currently stayed by Congressional action (e.g. Mahoney Lake and Reynolds Creek) Proposals to develop other renewable resource projects:tidal energy,geothermal,and offshore wind Economic development and potential new loads in SE Alaska State of Alaska decisions regarding proposed AK-BC Intertie and related segments of export transmission system BCTC decision regarding NTL and proposed extension to AK/BC border Monitor implementation of policies set forth in BC Energy Plan Decisions to construct new transmission lines:Kake to Petersburg;Metlakatla to Ketchikan; Coffman Cove to FDPPA system;Takatz Lake to Kake Technical improvements to transmission construction Market prices affecting construction. Hatch Acres Corporation PR324582.Rev.0,Page 251 AK-BC Alaska Final Report 18-09-07.Doc 10 HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 10.BIBLIOGRAPHY Hatch Acres Corporation PR324582.Rev.0,Page 252 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACHES -oe Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 10.BIBLIOGRAPHY AIDEA and AEA Responses to Questions from DCCED Finance Subcommittee;2/28/2007 Alaska Community Database Community Information Summaries (CIS),Department of Commerce, Community,and Economic Development,Division of Community Advocacy,11/17/2006, http://www.commerce.state.ak.us/dca/commdb/CF_CliS.htm Alaska Division of Community Advocacy,Department of Commerce,State of Alaska,Community Database information www.commerce.state.ak.us/dca Alaska Economic Information System,a joint project of the Alaska Department of Community and Economic Development and the US Department of Commerce,Economic Development Administration,11/17/2006,http:/(www.commerce.state.ak.us/dca/AEIS/AEIS Home.htm Alaska Economic Performance Report 2004,Division of Community Advocacy,State of Alaska Department of Commerce,Community and Economic Development,May 2005 Alaska Economic Performance Report 2005,Division of Community Advocacy,State of Alaska Department of Commerce,Community and Economic Development,June 2006 Alaska Electric Power Statistics (with Alaska Energy Balance),1960 -2001,Prepared by Institute of Social and Economic Research,University of Alaska Anchorage,November 2003 Alaska Energy Authority;Alaska Intertie Project;Public Hearing Meeting Minutes;3/13/2007 Alaska Industrial Development and Export Authority Power Revenue Bonds,First Series (Snettisham Hydroelectric Project.8/6/1998 Alaska-BC Inter-tie Study,Report #16239-21-00-3,Prepared for BCTC by Powertech Labs,Inc, March 3,2006 Alaska Intertie Agreement Among Alaska Power Authority;Municipality of Anchorage,Alaska d.b.a.Municipal Light and Power;Chugach Electric Association,Inc.;City of Fairbanks,Alaska; Municipal Utilities System;and Golden Valley Electric Association,Inc.;and Alaska Electric Generation and Transmission Cooperative.Many signature pages with dates in 1985 -1991. Alaska Power Authority,Anchorage Alaska,Chacachamna Hydroelectric Project,Interim Feasibility Assessment Report;March 1983. An Assessment of Growth and Development Paths for Southeast Alaska,USDA,USFS,Pete Tsournos and Richard W.Haynes,October 2004 BC Hydro Annual Report 2006 BC Hydro F2006 Call for Tenders,Electricity Purchase Agreements,Reasons for Decision, Appendix B,September 21,2006 BC Hydro Green Criteria,June 5,2003 (BC Hydro website) BC Hydro Green Power News,November 2006 Hatch Acres Corporation PR324582.Rev.O,Page 253 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES BC Hydro 2006 Integrated Electricity Plan Application Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report BC Hydro Powering the Province for Generations -publication listing proposed new generation projects (BC Hydro website) Bradley Lake Hydroelectric Project,Agreement for the Sale and Purchase of Electric Power (Power Sales Agreement);no date. Bradley Lake Hydroelectric Project;Transmission Facilities Maintenance Agreement between Alaska Energy Authority and Homer Electric Association,Inc.;August 1996 British Columbia Transmission Corporation Transmission System Capital Plan F 2006 to F 2015, March 23,2005 BCTC updates to the Northwest Transmission Line:August 14,2006;August 30,2006;September 8,2006;September 28,2006.Posted on BCTC website. BCTC responses to Iskut First Nation Information Request,August 3,2005,submitted as part of BCUC written public hearing with respect to Project No.3698387 California Independent System Operator (CAISO),miscellaneous brochures and documents Canada's Impact on Alaska,prepared for the Consulate of Canada,September 2005 Canada-Northwest-California Transmission Options Study,Northwest Power Pool,May 16,2006. Comprehensive Renewable Energy Feasibility Study for Sealaska Corporation,Final Report, Springtyme Company LLC,December 31,2005 Current Community Conditions:Fuel Prices Across Alaska,prepared by Research and Analysis Section,Division of Community Advocacy,Department of Commerce,Community,and Economic Development,State of Alaska,December 2005 Economic Assessment of the Bradfield/Iskut Transportation Corridor,prepared for the Alaska Department of Commerce,Community &Economic Development,McDowell Group,Inc, November 2004 Economic Development Resource Guide,Division of Community Advocacy,Department of Commerce,Community,and Economic Development,October 2005,17"Edition Economic Impact of Alaska's Mining Industry,prepared for the Alaska Miners Association by McDowell Group,February 2006 FERC docketed filings for proposed hydropower and tidal energy projects,www.ferc.gov Forrest Kerr Northern Mine Stage 1 Feasibility Study Report -Report No:SPA2006-089,Regional System Planning,BCTC,June 15,2006 Kake-Petersburg Transmission Intertie Study Final Report prepared for the Southeast Conference,D. Hittle &Associates,July 2005 Hatch Acres Corporation PR324582.Rev.O,Page 254 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES KWETICO Application for New Certificate of Public Convenience and Necessity;and Request for Public Interest Exemption,U-05-100,filing before the Regulatory Commission of Alaska,December21,2005. KWETICO Articles of Incorporation,July 2004 Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Legal Entity Options for SE Alaska Intertie Project and Matrix of Entity Options prepared for the Southeast Conference,Dean Thompson,March 16,2004 Long-Term Power Sales Agreement.Four Dam Pool -Initial Project of the Alaska Power Authority, Number 85-493,November 12,1985 NonRailbelt Report -Findings and Recommendations of the Alaska Energy Policy Task force,2003 North West Area Transmission Options -Report No.SPPA 2005-24,BCTC,July 8,2005 Northwest Wind Integration Action Plan,Working Draft,January 17,2007. City of Petersburg,Alaska,Petersburg Municipal Power and Light,2005 Revenue Requirement Study,D.Hittle &Associates,Inc.,March 10,2005 NovaGold -documents describing proposed new hydropower generation projects and related proposed transmission line segment in Northwest BC,www.coastmountainpower.com and www.novagold.net Petersburg Municipal Power &Light 20 Year Plan,Power Engineers,April 1997 Presidential Permit PP-87 Authorizing Bradfield Electric,Inc,and the Alaska Power Authority to construct,connect,operate and maintain electric transmission facilities across the International Border between the US and Canada,US Department of Energy,May 8,1989. Project Fact Sheet:Snettisham Hydroelectric Project;Alaska Energy Authority;Reviewed:August10,2006. Project Review of the North West Transmission Extension in Northwest British Columbia, Chesterman Consulting Inc,for BCTC,June 22,2005 Proposed Johnny Mountain 69-kV Transmission Line,Project Concept Summary,R.W.Beck and Associates,August 26,1988. Railbelt Energy Study;Final Report;Ater Wynne LLP and RW Beck;1/15/2004. Regulatory Commission of Alaska,Order Accepting Settlement Agreement,Subject to Conditions; Approving Amendatory Agreement;Vacating Suspension of TA203-8;and Dismissing TA203-8. Investigation into Effect of Nonfirm Energy Agreement,U-97-188,Order No.6;2/25/2000 Regulatory Commission of Alaska,Order Tabling Electric Market Structure Issues and Closing Docket,R-97-10;Order No.8;9/28/2001 Regulatory Commission of Alaska,Railbelt Contract Summary:Fuel,Wholesale Electric,and Transmission,no date. Renewable Energy Atlas of Alaska,Alaska Energy Authority,2006 Hatch Acres Corporation PR324582.Rev.O,Page 255 AK-BC Alaska Final Report 18-09-07.Doc nATGH ACRES Review of the Status of Development of HVDC Voltage Sourced Converters and Extruded Submarine Cable Technology for HVDC in Southeast Alaska,Report No:322-10000-2,Teshmont, October 16,2001 Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Rural Energy Action Council,Findings and Action Recommendations,April 15,2005 Snettisham Hydroelectric Project;Agreement for the Sale and Purchase of the Electric Capability of the Snettisham Hydroelectric Project (Power Sales Agreement)between Alaska Electric Light and Power Company (Purchaser)and Alaska Industrial Development Export Authority (Authority).No date. Southeast Alaska Electrical Intertie System Plan,Report #97-01,prepared for the Southeast Conference,Acres International Corporation,January 1998 Southeast Alaska Comprehensive Development Strategy,prepared for the US Department of Commerce,Economic Development Administration by Southeast Conference and Central Council Tlingit and Haida Indian Tribes of Alaska,April 2001 Southeast Alaska Energy Export Report,Final Report,Prepared for the Southeast Conference,D. Hittle &Associates,May 1,2006 Southeast Alaska Intertie Study,Phase 1 Final Report,Prepared for the Southeast Conference,D. Hittle &Associates,December 2003 Southeast Alaska Transmission Intertie Study,Prepared for the Alaska Power Authority,Harza Engineering Company,October 1987 Southeast Alaska Transmission Intertie Study,Addendum 1,Tyee/Johnny Mountain Transmission Line Study,Prepared for the Alaska Power Authority,Harza Engineering Company,July 1988 Southeast Intertie Study Presentation,D.Hittle &Associates,September 19,2003 Special Use Permit and Record of Decision/Finding of No Significant Impact,USDA Forest Service, Issued to Bradfield Electric,Inc.,June 7,1988. State of Alaska Seafood Economic Strategies Draft Report,prepared for State of Alaska Office of the Governor by McDowell Group,December 2006. Statistical Report of the Power Cost Equalization Program,Fiscal Year 2005 -July 1,2004 -June 30,2005 prepared by the Alaska Energy Authority,January 2006 Survey of the Reliability of HVDC Systems Throughout the World During 2001 -2002,Teshmont Consultants LP,September 23,2005 Swan-Tyee Intertie Economic Analysis Prepared for the Four Dam Pool Power Agency, Commonwealth Associates,Inc.,March 2006 Thomas Bay Hydroelectric Project,Pre-Feasibility Assessment Report,Hosey &Associates, December 1985 Timber Markets Update an Analysis of an Integrated SE Alaska Forest Products Industry,slide presentation prepared for Southeast Conference by McDowell Group,Inc.,September 21,2004 Hatch Acres Corporation PR324582.Rev.0,Page 256 AK-BC Alaska Final Report 18-09-07.Doc nATGh ACRES Tongass Land Management Plan Revision -Supplemental Environmental Impact Statement, Roadless Area Evaluation for Wilderness Recommendations,Record of Decision,USFS,February 2003. Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report Water Powers Southeast Alaska 1947,Federal Power Commission and Forest Service Hatch Acres Corporation PR324582.Rev.0,Page 257 AK-BC Alaska Final Report 18-09-07.Doc 11 HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska Final Report 11.LIST OF PREPARERS Hatch Acres Corporation PR324582.Rev.0,Page 258 AK-BC Alaska Final Report 18-09-07.Doc HATCH ACRES Alaska Energy Authority -AK-BC Intertie Feasibility Study SE Alaska 11.LIST OF PREPARERS Robert Griesbach,P.Eng.,CMC Project Director Nan Nalder,MPA Project Manager Anibal Carias,P.Eng. Development Scenarios and Model A.Richard Griffith,PE Power Generation Randy Hardy Markets and Market Structures,Transmission Del LaRue Transmission Guangbin Lian,PhD,P.Eng. Development Scenarios and Model Patricia Miller,BS,MS Regulatory Clark Smith,MA Loads and Resources Heidi Wahto,MPA Regulatory Matt Williams Transmission Final Report Hatch Acres Corporation AK-BC Alaska Final Report 18-09-07.Doc PR324582.Rev.0,Page 259