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Page2of2chargestomakeitdeliverable.However,aremotewindresourcemayrequireSPPpointtopointtransmissionservicetotheMISOborderandMISOpointtopointtransmissionservicetoELL/EGSL'sload.BasedoncurrentMISOandSPPtariffrates,thecombinedcostoftransmissionservicecouldbeapproximately$$5/MWhforoffpeakhours4,$10/MWhforonpeakhours4,orwhenadjustedtoawindgenerationprofile,aweightedaverageof$7.11/MWh.Thistransmissionservicecostandriskisnotincurredbyalocalwindresource.
Page2of2chargestomakeitdeliverable.However,aremotewindresourcemayrequireSPPpointtopointtransmissionservicetotheMISOborderandMISOpointtopointtransmissionservicetoELL/EGSL'sload.BasedoncurrentMISOandSPPtariffrates,thecombinedcostoftransmissionservicecouldbeapproximately$$5/MWhforoffpeakhours4,$10/MWhforonpeakhours4,orwhenadjustedtoawindgenerationprofile,aweightedaverageof$7.11/MWh.Thistransmissionservicecostandriskisnotincurredbyalocalwindresource.
WindgenerationispaidthehourlyLMPatthegeneratorbuswhilecustomerspayforenergybasedonthehourlyloadweightedaverageLMPfortheloadzone.ThedifferencebetweentheloadLMPandgeneratorLMPisanestimateoftheriskthatcustomersareexposedtobyhavingaremoteresourceasopposedtoalocalresource.ToestimatethepotentialLMPdifferentialrisk,threerepresentativeSPPwindresources3for2014wereassessed,assumingagenericSPPwindprofile.TheLMPdifferentialsin2014betweenthesethreenodesandELL/EGSL'sload(loadweightedaverageofEES.ELILDandEES.EGILD)are$12.92/MWh,$13.84/MWh,and$17.07/MWhrespectively,orapproximately$14.60/MWhonaverage.AlocalwindresourceisnotsubjecttothispotentialLMPdifferentialrisk.
WindgenerationispaidthehourlyLMPatthegeneratorbuswhilecustomerspayforenergybasedonthehourlyloadweightedaverageLMPfortheloadzone.ThedifferencebetweentheloadLMPandgeneratorLMPisanestimateoftheriskthatcustomersareexposedtobyhavingaremoteresourceasopposedtoalocalresource.ToestimatethepotentialLMPdifferentialrisk,threerepresentativeSPPwindresources3for2014wereassessed,assumingagenericSPPwindprofile.TheLMPdifferentialsin2014betweenthesethreenodesandELL/EGSL'sload(loadweightedaverageofEES.ELILDandEES.EGILD)are$12.92/MWh,$13.84/MWh,and$17.07/MWhrespectively,orapproximately$14.60/MWhonaverage.AlocalwindresourceisnotsubjecttothispotentialLMPdifferentialrisk.
Insummary,thetablebelowshowsacomparisonofthecostofelectricityofalocalwindresourcewitharemoteresourcetakingthedifferencesincapacityfactor,transmissioncost,andLMPintoconsideration.Inthisexample,thecapacityfactoradvantageofaremotewindresourceisalmostcompletelyoffsetbyadditionaltransmissionservicecostsandLMPdifferentialrisk,whichresultsinsimilarLevelizedCostofElectricity("LCOE")estimatesforbothremoteandlocalwindresources.LocationInstalledCost($/kW)FixedChargeRate(%)CapacityFactor(%)TransmissionCost($/MWh)LMPDifferential($/MWh)LCOE($/MWh)Local$200010.5%34%$0$0$70.51Remote$200010.5%50%$7.11$14.60$69.65=[A]=[B]=[C]=[D]=[E]=[F][F]=[A]x[B]x(1/([C]x8760))x1000(kW/MW)+[D]+[E]Fromthisassessment,theexpectedcostdifferenceisapproximately1%betweenmodelingpotentialwindresourceswithlocalassumptionsascomparedwithremoteassumptions.IfinflationinthetransmissionservicecostandLMPdifferentialweretakenintoconsideration,thelocalwindresourcewouldhavealowerLCOEascomparedtotheremotewindresource.3KeenanWindFarm(OklahomaGas&Electric,OKGEWDWRDEHVUNKEENAN_WIND_RA),CentennialWindFarm(OklahomaGas&Electric,OKGECENTWINDUNCENTWIND_RA),SpearvilleWindFarm(KansasCityPower&Light,KCPLSPEARVILUNWINDFARM_RA).HistoricalLMPsbylocationobtainedfromSPPIntegratedMarketplace(https://marketplace.spp.org/web/guest/lmpbylocation).4MISOtransmissioncostestimatescalculatedbasedonMISOOATTSchedule7year2015rates,asofJuly2015.SPPtransmissioncostestimatescalculatedbasedonSPPOATTSchedule7AttachmentT,asofJuly2015.  
Insummary,thetablebelowshowsacomparisonofthecostofelectricityofalocalwindresourcewitharemoteresourcetakingthedifferencesincapacityfactor,transmissioncost,andLMPintoconsideration.Inthisexample,thecapacityfactoradvantageofaremotewindresourceisalmostcompletelyoffsetbyadditionaltransmissionservicecostsandLMPdifferentialrisk,whichresultsinsimilarLevelizedCostofElectricity("LCOE")estimatesforbothremoteandlocalwindresources.LocationInstalledCost($/kW)FixedChargeRate(%)CapacityFactor(%)TransmissionCost($/MWh)LMPDifferential($/MWh)LCOE($/MWh)Local$200010.5%34%$0$0$70.51Remote$200010.5%50%$7.11$14.60$69.65=[A]=[B]=[C]=[D]=[E]=[F][F]=[A]x[B]x(1/([C]x8760))x1000(kW/MW)+[D]+[E]Fromthisassessment,theexpectedcostdifferenceisapproximately1%betweenmodelingpotentialwindresourceswithlocalassumptionsascomparedwithremoteassumptions.IfinflationinthetransmissionservicecostandLMPdifferentialweretakenintoconsideration,thelocalwindresourcewouldhavealowerLCOEascomparedtotheremotewindresource.3KeenanWindFarm(OklahomaGas&Electric,OKGEWDWRDEHVUNKEENAN_WIND_RA),CentennialWindFarm(OklahomaGas&Electric,OKGECENTWINDUNCENTWIND_RA),SpearvilleWindFarm(KansasCityPower&Light,KCPLSPEARVILUNWINDFARM_RA).HistoricalLMPsbylocationobtainedfromSPPIntegratedMarketplace(https://marketplace.spp.org/web/guest/lmpbylocation).4MISOtransmissioncostestimatescalculatedbasedonMISOOATTSchedule7year2015rates,asofJuly2015.SPPtransmissioncostestimatescalculatedbasedonSPPOATTSchedule7AttachmentT,asofJuly2015.}}
}}

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Alternatives RAI AL-3 - Entergy 2015g_Integrated Resource Plan 2015--Final Report
ML17024A218
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  • Via Hand Delivery Ms. Terri Lemoine Bordelon Records and Recording Division Louisiana Public Service Commission Galvez Building, lih Floor 602 North Fifth Street Baton Rouge, Louisiana 70802 August 3, 2015 Entergy Services, Inc. 639 Loyola Avenue (70113} P.O. Box 61000 New Orleans, LA 70161-1000 Tel 504 576 3101 Fax 504 576 5579 Edward R. Wicker, Jr. Senior Counsel Legal Sel'Vices -Regulatory Re: 2015 Integrated Resource Planning ("IRP") Process for Entergy Louisiana, LLC and Entergy Gulf States Louisiana, L.L.C. Pursuant to the General Order No. R-30021, Dated April 20, 2012 LPSC Docket No. 1-33014

Dear Ms. Bordelon:

On behalf of Entergy Louisiana, LLC and Entergy Gulf States Louisiana, L.L.C. (collectively, the "Companies"), enclosed please find the Companies' 2015 Integrated Resource Plan (the "2015 IRP"). Also enclosed is a red-lined version that reflects certain changes to the previously-filed draft report. Please retain an original and two copies for your files and return a date-stamped copy to our by-hand courier. Appendix B submitted with the 2015 Draft IRP contains information that is designated Highly Sensitive Protected Materials ("HSPM"), which are being provided to you under seal pursuant to the provisions of the LPSC General Order dated August 31, 1992, and Rules 12.1 and 26 of the Commission's Rules of Practice and Procedure. The confidential materials included in the filing consist of confidential and market-sensitive financial information. Please retain the original HSPM materials for your files and return a date-stamped copy to our by-hand courier. The HSPM materials are being produced only to the appropriate Reviewing Representatives in accordance with the Confidentiality Agreement in effect in this docket.

Ms. Bordelon August 3, 2015 Page2 If you have any questions, please do not hesitate to call me. Thank you for your courtesy and assistance with this matter. ERW/ttm Enclosures Sincerely, Edward R. Wicker, Jr. cc: Official Service List (via electronic and U.S. mail)

CERTIFICATE OF SERVICE LPSC Docket No. I-33014 I, the undersigned counsel, hereby certify that a copy of the above and foregoing has been served on the persons listed below by facsimile, electronic mail, hand delivery and/or by mailing said copy through the United States Postal Service, postage prepaid, and addressed as follows: Melanie A. V erzwyvelt Staff Attorney Louisiana Public Service Commission P.O. Box 91154 Baton Rouge, LA 70821-9154 Donnie Marks LPSC Utilities Division Louisiana Public Service Commission P.O. Box 91154 Baton Rouge, LA 70821 Katherine W. King J. Randy Young Carrie R. Tournillon Kean Miller LLP P.O. Box 3513 Baton Rouge, LA 70821 Kathryn J. Lichtenberg Karen H. Freese Edward R. Wicker, Jr. Entergy Services, Inc. 639 Loyola A venue, 26th Floor P.O. Box 61000 Mail Unit L-ENT-26E New Orleans, LA 70161-1000 Chairman Eric F. Skrmetta Office of the Commissioner District I -Metairie 433 Metairie Road, Suite 406 Metairie, LA 70005 Commissioner Lambert C. Boissiere, III Office of the Commissioner District III -New Orleans 1450 Poydras Street, Suite 1402 New Orleans, LA 70112 Tulin Koray Economics Division Louisiana Public Service Conunission P.O. Box 91154 Baton Rouge, LA 70821-9154 James M. Ellerbe Marathon Petroleum Company LP 539 South Main Street Findlay, Ohio 45840-3295 Kimberly A. Fontan Entergy Services, Inc. 4809 Jefferson Highway Mail Unit L-JEF-357 Jefferson, LA 70121 John H. Chavanne Chavanne Enterprises 111 West Main Street, Suite 2B P.O. Box 807 New Roads, LA 70760-0807 Conunissioner Scott A. Angelle Office of the Commissioner District II -Baton Rouge Post Office Box 2681 Baton Rouge, LA 70821 Vice-Chairman Clyde C. Holloway Office of the Conunissioner District IV -Forest Hill 11098 Hwy. 165 South Forest Hill, LA 71430 Conunissioner Foster L. Campbell Office of the Commissioner District V -Shreveport Post Office Drawer E Shreveport, LA 71161 Rebecca E. Turner Vice President Regulatory Affairs & Market Design Entegra Power Group LLC 100 South Ashley Drive, Suite 1400 Tampa, FL 33602 Casey DeMoss Roberts Executive Director Alliance for Affordable Energy 2372 St. Claude Ave., #300A New Orleans, LA 70117 Gordon D. Polozola NRG Energy, Inc. General Counsel-South Central Region 112 Telly Street New Roads, LA 70760 Joshua Smith, Staff Attorney Casey Austin Roberts Sierra Club Environmental Law Program 85 Second St., Second Floor San Francisco, CA 94104 C. Tucker Crawford President, GSREIA 643 Magazine Street Suite 102 New Orleans, LA 70130 Mr. Simon A. Mahan Southern Wind Energy Association C/O SACE P .0. Box 1842 Knoxville, TN 37901 Philip Hayet Lane Kollen Randy A. Futral J. Kennedy and Associates, Inc. 570 Colonial Park Drive, Suite 305 Roswell, GA 30075 Thomas W. Milliner Anzelmo, Milliner & Burke, LLC 3636 S. l 0 Serv. Rd., Suite 206 Metairie, LA 70001 Michelle Bloodworth Senior Director, Power Generation America's Natural Gas Alliance 710 8th Street NW, Suite 800 Washington, DC 20001 Robert P. Larson Douglas A. Spaulding Manager Nelson Energy LLC 8441 Wayzata Blvd., Suite 101 Golden Valley, MN 55426 Haywood Martin Sierra Club Delta Chapter Chair P.O. Box 52503 Lafayette, LA 70505 Mandy Mahoney Abby Schwimmer Southeast Energy Efficiency Alliance 50 Hurt Plaza SE, Suite 1250 Atlanta, GA 30303 New Orleans, Louisiana, this 3rd day of August, 2015.

20015IDrafntegEntergyELPDraftReftReporFinalRgrateyGulfStaEntergyLPSCDockeport:FirtRevisioReport:FedRatesLouandLouisianketNo.IiledJanuon1:FilFiledAug esouuisiana,na,LLCI33014uary30,edAprilgust3,2urceL.L.C.2015l15,2012015ePla15n LouisianatheeconoAttractedfriendlycfacilitiesaresidents.Entergy'spartneringtremendoLouisianaandreliabABlueprinThisIntegalsosustaprocess,evaluatedprogramsthosereqBecauseo1,600MWleastanomodernizAddingnexpandingwithotheinthecoustandsattheomicfuturesobylowcostlimate,energandcreatingt.Louisianacgwiththeouseconomhasanampblepower.WntForLouisiagratedResouainingcompetweconducteddifferentfu,andanalyzeuirementsinofthisunprecWofincreasedther8,000Mingourgenerew,highlyegeconomywerfactorsminuntry.ecenterofanoftheirfamilinaturalgas,lgyintensiveinthousandsofcompaniesastatetocmicopportunplesupplyofecallourplaana'sBrightFurcePlanrefletitiveenergyedanextensuelsandtecedavarietythisrapidlyccedentedgrodindustrialloMWofgenerrationfleet.efficientgenewillallowthosimizestheranindustrialreiesandcommowelectricityndustriesarefjobsforLouarecommittecapitalizeonnitybyensfclean,afforn"Powertouture."ectsthatcompricesandcosivestudyochnologies,iofeconomicchangingenviowth,Entergyoadthrough2ratingcapaciterationrequisecoststobeateeffecttocenaissancethamunitiesforgyprices,existeinvestingbiluisianaedtonthissuringrdableGrow,mmitmenttoontinuingtosofourcustomncludingrencscenariostoronment.y'sLouisianac2019.Beyondtyby2034tiressignificanspreadacroscustomersanatoffersresidenerationstotinginfrastruclionstobuildhelpingoursserveallcustomers'needsnewableresoohelpdetercompaniesmdindustrialgrtomeetgrowntcapitalinvssagrowingvdhelpskeepdentsanoppocome.cture,andLodnewplantsstatecreateomersreliablovertheneourcesandaminehowwmustbepreparowth,weprwingdemandvestment.Hvolumeofsaingourratesortunitytochuisiana'sbusorexpandexneededjobsy.Throughthext20yearsalternativeewecanbestsaredtoserveojectaneeddandtoconowever,aqles,whichcoamongthelo1hangeinessxistingwhileheIRPs.Weenergysatisfyuptoforatntinueuicklyoupledowest 2TheIRPincludesafiveyearactionplanthatwillallowustoensureweareabletoprovidesafe,reliableandeconomicservicetoallcustomers,existingandnew.Theactionplanincludes: ObtainingregulatoryapprovalsforEntergyGulfStatesLouisianatopurchasetwounitsoftheUnionPowerStationnearElDorado,Arkansas. Addingpotentialnewresources:o SeekingcertificationofselfbuildCCGTthatwasmarkettestedinthe2014AmiteSouthRFP.o Issuingthe2015WOTABRFPtosolicitproposalsforanewCCGTunitintheLakeCharlesareainthe202021timeframe.o DeterminingwhetherapairofCTunitsisneededintheLakeCharlesareaby2020tomeetindustrialloadgrowth.o ContinuingtoassessdevelopmentofotherCTunitsinAmiteSouthandWOTABareasforquickdeploymentifloadgrowthexceedsprojectionsand/orothersupplyoptionsarenotcompletedasplanned. StudyingdistributedsolarandstoragepilotprojectstodeterminetheviabilityandperformanceofthetechnologiesinLouisiana. Assessingpowercontractsasviablealternativesformeetinglongtermneeds. Exploringopportunitiesforlongtermgassuppliestomitigatepricevolatilityandhedgeagainstfuturepriceincreases. EvaluatingtheresultsoftheQuickStartphaseofEntergySolutions:ALouisianaProgram;and WorkingwithregulatorstodeveloprulesforcosteffectiveenergyefficiencyprogramsbeyondtheQuickStartphase.ThisisanexcitingtimeforLouisiana.Entergy'sLouisianacompanieshaveaplanandarecommittedtomeetingthepowerneedsofourcustomersatareasonablecost.

3CONTENTSContents........................................................................................................................................................3Introduction..................................................................................................................................................5IndustrialRenaissanceinLouisiana.................................................................................................6MISOIntegration..............................................................................................................................6BusinessCombinationofELLandEGSL...........................................................................................7SystemAgreement...........................................................................................................................7Part1:PlanningFramework..........................................................................................................................8ResourceAdequacyRequirements..................................................................................................9TransmissionPlanning.....................................................................................................................9AreaPlanning.................................................................................................................................11Part2:Assumptions....................................................................................................................................13TechnologyAssessment.................................................................................................................13DemandSideAlternatives.............................................................................................................16NaturalGasPriceForecast.............................................................................................................17CO2Assumptions...........................................................................................................................18MarketModeling...........................................................................................................................18Part3CurrentFleet&ProjectedNeeds.....................................................................................................20CurrentFleet.................................................................................................................................20LoadForecast.................................................................................................................................21ResourceNeeds.............................................................................................................................23TypesofResourcesNeeded...........................................................................................................27Part4:PortfolioDesignAnalytics................................................................................................................28MarketModeling...........................................................................................................................28PortfolioDesign&RiskAssessment..............................................................................................29SummaryofFindingsandConclusions..........................................................................................37Part5:FinalReferenceResourcePlan&ActionPlan.................................................................................38FinalReferenceResourcePlan.......................................................................................................38ActionPlan.....................................................................................................................................42 4APPENDICESAppendixAELLandEGSLGenerationResourcesAppendixBActualHistoricLoadandLoadForecastAppendixCResponsetoStakeholderCommentsAppendixDEntergyLongTermTransmissionPlan(ELLandEGSLProjects)AppendixE1stStakeholderMeetingChartsAppendixFAuroraDSMPortfoliosbyScenarioAppendixGWindModelingAssumptions 5INTRODUCTIONThisreport,preparedinaccordancewiththeIntegratedResourcePlanningrulespromulgatedbytheLouisianaPublicServiceCommission("LPSC"),1describesthelongtermintegratedresourceplan("IRP")ofEntergyGulfStatesLouisiana,L.L.C.("EGSL")andEntergyLouisiana,LLC("ELL")(collectivelyreferredtoasthe"Companies")fortheperiod2015-2034.TheplanreflectsimportantchangesintheCompanies'planningandoperationsandgivesconsiderationtothecurrentandexpectedeconomicenvironmentinLouisiana.ItshouldbenotedthatthedataandassumptionsreflectedinthisIRPlargelyreflectthebestinformationavailableduringtheinitialdevelopmentoftheDataAssumptionsforthedraftreportinlate2013early2014.Duringthe18monthsoverwhichthisreportwasdeveloped,someinformation,forecasts,andassumptionsmayhavechanged.Whilethisreportdoesnotattempttoaddressallsuchchanges,keychangeshavebeennotedthroughoutthedocument.Asalongtermplanningdocument,theIRPisintendedtoprovideguidelinesforresourceplanninganddecisions,butactualdecisionswillbemadebasedonthebestinformationavailableatthetimesuchdecisionismade.Inadditiontotheeconomicoutlookforthestate,threerecentlycompletedorforthcominginitiativestheCompanies'participationintheMidcontinentIndependentSystemOperator("MISO")marketbeginningDecember19,2013,theCompanies'JointApplicationtocombinetheirrespectiveassetsandliabilitiesintoasingleoperatingcompany,andtheproposedterminationoftheCompanies'participationintheEntergySystemAgreementonFebruary14,2019haveimplicationsfortheCompanies'resourceneedsandsupplystrategy.GiventhesignificanceofthesechangesontheCompanies'longtermcapacityandresourceneeds,thisIRPaddresseshowtheCompaniesplantomeettheircustomers'powerneeds,botheconomicallyandreliably.Asdiscussedinthisreport,residential,commercial,andindustrialloadgrowth,unitdeactivations,andpurchasedpoweragreement("PPA")expirations,willrequiretheCompaniestoaddsignificanttransmissionandgenerationresourcesduringtheplanningperiod,includingmultiplegeneratorsinthe20192021timeframe.WhileadditionalgenerationwillrequiresubstantialcapitalcommitmentsfromtheCompanies,theCompaniesdonotexpectthatthegenerationadditionswillcausecustomerratestoincreasematerially.Thisisaresultofincreasedconsumption(i.e.,greaterkWhsalesoverwhichtospreadfixedcosts),improvedportfolioefficiency,andexpirationofothercustomercharges,amongotherfactors.1See,LPSCCorrectedGeneralOrderNo.R30021,Inre:DevelopmentandImplementationofRuleforIntegratedResourcePlanningforElectricUtilities,datedApril20,2012.

6IndustrialRenaissanceinLouisianaAuniquesetofcircumstanceshasconvergedtogiveLouisianatheopportunitytodevelopandgrowitseconomyinwaysthatcanbenefititscitizensforgenerationstocome.Acombinationoffactors,includinglownaturalgaspricesresultingfromthedevelopmentofshalenaturalgas,lowelectricityprices,accesstoworldclassenergyinfrastructure,includingdeepwaterports,anextensiveinterstatepipelinenetworkandrelatedinfrastructure,anexperiencedworkforce,andaprobusinessenvironmenthaveresultedinanindustrialrenaissanceinLouisianathathasseenmorethan$50billioninnewcapitalinvestmentandthecreationofover83,000newdirectandindirectjobssince2008.Thisindustrialrenaissanceisresultingin-andisprojectedtocontinuetoresultin-neworexpandedindustrialfacilitiesconcentratedintheAmiteSouth2andtheWestoftheAtchafalayaBasin("WOTAB")3planningareas,wheretherecurrentlyaresubstantialsupplyrequirementsthatrequirelocalgenerationyetlimitedavailableinregionpowersources.Morespecifically,theCompaniesexpectupto1,600megawatts("MW")ofindustrialloadgrowthintheirserviceareasthrough2019,andby2034,afteraccountingforthedeactivationofexisting,oldergenerationtheCompaniesexpecttorequireatleast8,000MWofadditionalcapacitytomeetdemand.Thisindustrialloadgrowthisinadditiontoexpectedloadgrowthintheresidentialandcommercialsectors.ThroughthePowertoGrowinitiative,theCompaniesaredemonstratingtheircommitmenttomeetingtoday'sneedsandanticipatingthepowerdemandsofthefuturesoLouisianahastheamplesupplyofclean,affordableandreliablepowerneededtocapitalizeonthistremendouseconomicopportunity.MISOIntegrationTheCompanies,alongwiththeiraffiliateEntergyOperatingCompanies("EOC"),becamemarketparticipantsinMISOonDecember19,2013.MISOisaregionaltransmissionorganization("RTO")allowingtheCompaniesaccesstoalargestructuredmarketthatenhancestheresourcealternativesavailabletomeetcustomers'powerneeds.TheavailabilityandpriceofpowerintheMISOmarketaffectstheCompanies'resourcestrategyandportfoliodesign.DespitethesignificanceofthemovetoMISOfortheCompaniesandtheircustomers,theCompaniesretainresponsibilityforplanningtomeettheircustomers'longtermpowerneeds.MISOconsiderationsareanelementofthisIRP.2AmiteSouthistheareagenerallyeastoftheBatonRouge,Louisiana,metropolitanareatotheMississippistatelineandsouthtotheGulfofMexico.3WOTABistheareagenerallywestoftheBatonRouge,Louisiana,metropolitanareatothewesternmostportionofEGSL'sserviceterritory.

7BusinessCombinationofELLandEGSLOnSeptember30,2014,theCompaniesfiledanapplication4withtheLPSCseekingapprovalofaproposaltocombinetheirrespectiveassetsandliabilitiesintoasingleoperatingcompany.ThisIRPassumesthattheproposedcombinationwillbeapprovedandcompleted;5assuch,theIRPanalysiswasconducted,andtheresultsarereportedherein,onacombinedentitybasis.However,becausetheCompaniescurrentlyusesubstantiallyidenticalplanningcriteriatooneanotherandtothoseusedforthecombinedentity,resultsoftheIRPanalysiswouldnotbemateriallydifferenthadtheanalysisbeenperformedseparatelyforeachoperatingcompany.AseparatelyperformedanalysisforEGSLandELLwouldresult,overthelongterm,intwoportfoliosthatincombinationwouldincludesimilarelementstothefinalreferenceresourceplanforthecombinedentity.SystemAgreementTheelectricgenerationandbulktransmissionfacilitiesoftheEOCsparticipatingintheEntergySystemAgreementareoperatedonanintegrated,coordinatedbasisasasingleelectricsystemandarereferredtocollectivelyasthe"EntergySystem."TheEOCsparticipatingtodayintheSystemAgreementareEGSL,ELL,EntergyMississippi,Inc.("EMI"),EntergyTexas,Inc.("ETI"),andEntergyNewOrleans,Inc.("ENO").6OnFebruary14,2014,EGSLandELLprovidedwrittennoticetotheotherEOCsoftheterminationoftheirparticipationintheSystemAgreement.7Inlightofthedecisiontoterminateparticipation,thisIRPwaspreparedundertheassumptionthatEGSLandELLwillnolongerparticipateintheSystemAgreementasofFebruary14,20198.AlthoughtheeffectivedateoftheCompanies'terminationofparticipationisuncertain,itisappropriatethatcurrentresourceplanningeffortsacknowledgethatstandaloneoperationsareonthehorizon.ThisIRPisanassessmentofthelongtermresourceneedsoftheCompaniesthatmaybeusedtodevelopstrategicdirectionandguidethedevelopmentofthefuturelongtermresourceportfolio.4ExParte:PotentialBusinessCombinationofEntergyLouisiana,LLCandEntergyGulfStatesLouisiana,L.L.C.,DocketNo.U33244.5AnuncontestedstipulationrecommendingapprovaloftheBusinessCombinationwasfiledwiththeCommissiononJuly13,2015,andasettlementhearingwasheldonJuly24,2015.TheCommissionisexpectedtoconsiderthestipulationattheAugust2015BusinessandExecutiveSession.6EntergyArkansas,Inc.("EAI"),alsoanEOC,terminateditsparticipationintheSystemAgreementeffectiveDecember18,2013.7EMIprovidednoticetotheEOCsthatitwouldterminateitsparticipationeffectiveNovember7,2015.ETIhasprovidednoticethatitwouldterminateitsparticipationonOctober1,2018(subjecttotheFERC'srulinginDocketNo.ER1475000whichistheFERCproceedingfiledtoamendthenoticeprovisionsofSection1.01oftheSystemAgreement).8EGSL'sandELL'snoticewouldbeeffectiveFebruary14,2019orsuchotherdateconsistentwiththeFERC'srulinginDocketNo.ER1475000.However,anearlierterminationmaybepossibleifagreeduponbytheparticipatingEOCs.

8PART1:PLANNINGFRAMEWORKTheCompanies'planningprocessseekstoaccomplishthreebroadobjectives: Toservecustomers'powerneedsreliably; Toreliablyprovidepoweratthelowestreasonablesupplycost;and Tomitigatetheeffectsandtheriskofproductioncostvolatilityresultingfromfuelpriceandpurchasedpowercostuncertainty,RTOrelatedchargessuchascongestioncosts,andpossiblesupplydisruptions.Objectivesaremeasuredfromacustomerperspective.Thatis,theCompanies'planningprocessseekstodesignaportfolioofresourcesthatreliablymeetscustomerpowerneedsatthelowestreasonablesupplycostwhileconsideringrisk.Indesigningaportfoliotoachievetheplanningobjectives,theprocessisguidedbythefollowingprinciples: Reliability-adequateresourcestomeetcustomerpeakdemandswithadequatereliability. BaseLoadProductionCosts-lowcostbaseloadresourcestoservebaseloadrequirements,whicharedefinedasthefirmloadlevelthatisexpectedtobeexceededforatleast85%ofallhoursperyear. LoadFollowingProductionCostandFlexibleCapability-efficient,dispatchable,loadfollowingresourcestoservethetimevaryingloadshapelevelsthatareabovethebaseloadsupplyrequirement,andalsosufficientflexiblecapabilitytorespondtofactorssuchasloadvolatilitycausedbychangesinweatherorbyinherentcharacteristicsofindustrialoperations. GenerationPortfolioEnhancement-agenerationportfoliothatavoidsanoverrelianceonagingresourcesbyaccountingforfactorssuchascurrentoperatingrole,unitage,unitcondition,historicandprojectedinvestmentlevels,anduniteconomics,andtakingintoconsiderationthemannerinwhichMISOdispatchesunits. PriceStabilityRiskMitigation-mitigationoftheexposuretopricevolatilityassociatedwithuncertaintiesinfuelandpurchasedpowercosts.

9 SupplyDiversityRiskMitigation-mitigationoftheexposuretomajorsupplydisruptionsthatcouldoccurfromspecificriskssuchasoutagesatasinglegenerationfacility.ResourceAdequacyRequirementsAsaloadservingentity("LSE")withinMISO,theCompaniesareandcontinuetoberesponsibleformaintainingsufficientgenerationcapacitytomeettheminimumreliabilityrequirementsoftheircustomers.UndertheMISOOpenAccessTransmission,Energy,andOperatingReserveMarketsTariff("MISOTariff"),theCompaniesmeetresourceadequacyrequirementsbyprovidingresourcesnecessarytomeetorexceedaminimumplanningreservemarginestablishedfortheCompaniesbyMISO.ResourceAdequacyistheprocessbywhichMISOensuresthatparticipatingLSEsmaintainsufficientreliableanddeliverableresourcestomeettheiranticipatedpeakdemandplusanappropriatereservemargin.UnderMISO'sResourceAdequacyprocess,MISOannuallydetermines(byNovember1eachyear)theplanningreservemarginapplicabletoeachLocalResourceZone("LRZ")forthenextplanningyear(June-May).LSEsarerequiredtoprovideplanningresourcecreditsforgenerationordemandsidecapacityresourcestomeettheirforecastedpeakloadcoincidentwiththeMISOpeakloadplustheplanningreservemarginestablishedbyMISO.Generationplanningresourcecreditsaremeasuredbyunforcedcapacity(installedcapacitymultipliedbyappropriateforcedoutagerate).TheannualplanningreservemarginfortheLRZwhichencompassesELLandEGSL,asdeterminedbyMISO,setstheminimumrequiredplanningreservemargin9theCompaniesmustprovide.Forpurposesoflongtermplanning,theCompanieshavedeterminedthata12%reservemarginbasedoninstalledcapacityratingsandforecasted(noncoincident)firmpeakloadshouldbeadequatetocoverMISO'sResourceAdequacyrequirementsanduncertaintiessuchasMISO'sfuturerequiredreservemargins,generatorunitforcedoutagerates,andforecastedpeakloadcoincidencefactors.Also,afterthebusinesscombination,a12%reservemarginprovidesenoughcapacitytocoverlossoftheCompanies'largestgeneratingunitcontingency.TransmissionPlanningTheCompanies'transmissionplanningensuresthatthetransmissionsystem(1)remainscompliantwithapplicableNERCReliabilityStandardsandrelatedSERCandlocalplanningcriteria,and(2)isdesignedtoefficientlydeliverenergytoendusecustomersatareasonablecost.SincejoiningMISO,theCompaniesplantheirtransmissionsysteminaccordancewiththeMISOTariff.Expansionof,andenhancementsto,transmissionfacilitiesmustbeplannedwellin9InMISO,ResourceAdequacyreservemarginrequirementsareexpressedbasedonunforcedcapacityratingsandMISOSystemcoincidentpeakload.Traditionally,theCompaniesandotherLSEshavestatedplanningreserverequirementsbasedoninstalledcapacityratingsandforecasted(noncoincident)peakload.

10advanceoftheneedforsuchimprovementsgiventhatregulatorypermittingprocessesandconstructioncantakeyearstocomplete.Advancedplanningrequiresthatcomputermodelsbeusedtoevaluatethetransmissionsysteminfutureyearstakingintoaccounttheplannedusesofthesystem,generationandloadforecasts,andplannedtransmissionfacilities.Onanannualbasis,theCompanies'TransmissionPlanningGroupperformsanalysestodeterminethereliabilityandeconomicperformanceneedsoftheCompanies'portionoftheinterconnectedtransmissionsystem.TheprojectsdevelopedareincludedintheLongTermTransmissionPlan10("LTTP")forsubmissiontotheMISOTransmissionExpansionPlanning("MTEP")processaspartofabottomupplanningprocessforMISO'sconsiderationandreview.TheLTTPconsistsoftransmissionprojectsplannedtobeinserviceinanensuing10yearplanningperiod.TheprojectsincludedintheLTTPserveseveralpurposes:toservespecificcustomerneeds,toprovideeconomicbenefittocustomers,tomeetNERCTPLreliabilitystandards,tofacilitateincrementalblockloadadditions,andtoenabletransmissionservicetobesoldandgeneratorstointerconnecttotheelectricgrid.Withregardtotransmissionplanningaimedatprovidingeconomicbenefittocustomers,theCompanieshaveplayed,andwillcontinuetoplay,anintegralroleinMISO'stopdownregionaleconomicplanningprocessreferredtoastheMarketCongestionPlanningStudy("MCPS"),whichisapartoftheMTEPprocess.MISO'sMCPSreliesontheinputoftransmissionownersandotherstakeholders,bothwithregardtotheassumptionsandscenariosutilizedintheanalysisandtheproposedprojectsintendedtobringeconomicvaluetocustomers.Basedonthisstakeholderinput,MISOevaluatestheeconomicbenefitsofthesubmittedtransmissionprojects,whileensuringcontinuedreliabilityofthesystem.TheintendedresultoftheMCPSisaprojectorsetofprojectsdeterminedtobeeconomicallybeneficialtocustomersandthatisthereforesubmittedtotheMISOBoardofDirectorsforapproval.TheCompanies'continuedinvolvementintheMCPSbeganwiththe2014processandtheCompanies'submissionofacollectionofprojectsforMISO'sreview.Theresultofthe2014MCPSincludedtheapprovalofaportfoliooffourprojectsinsoutheastLouisiana,calledtheLouisianaEconomicTransmissionProject("LETP").11TheLETPwasidentifiedfollowingasubstantialamountofeconomicanalysesperformedbytheCompaniesandMISOandisanexampleofthetypeofeconomicplanningtheCompaniesanticipatewillcontinueasapartofMISOparticipation.TheLETP,whichtheCompaniespresentedtotheCommissioninacertificationfilingpursuanttoLPSCGeneralOrderNo.R26018,isanticipatedtoprovide10TheCompanies'mostrecentLTTPisincludedinAppendixD.11TheMCPSalsoresultedintheidentificationoftwoeconomicallybeneficialprojectsinEAI'sserviceterritory,whichwereapprovedbytheMISOBoardofDirectors.

11customerswithbenefitsexceedingsixtimesitsestimatedcostof$56.3million-benefitsthataredirectlyrelatedtotheCompanies'participationintheMISOmarket.12Additionally,EGSLrecentlyfiledanApplicationforcertificationpursuanttoLPSCGeneralOrderNo.R26018foraportfoliooffourtransmissionprojectsreferredtoastheLakeCharlesTransmissionProject("LCTP").13EntergyServices,Inc.("ESI")andMISOhavedeterminedthattheLCTPisthemosteffectiveprojecttomeetthereliabilityneedsoftheLakeCharlesareaandwillbenecessarytoservetheforecastedloadgrowththerebythesummerof2018.TheportfoliooftransmissionprojectsthatcomprisetheLCTPiscurrentlyestimatedtocostupto$187millionandwillprovidetheinjectionofanew500kilovolt("kV")transmissionsourceintothearea.Thereareapproximately200projectsinthecurrentLTTP,locatedthroughoutthefourstatesoftheEntergyservicefootprint,withapproximately80projectsplannedforthestateofLouisiana.AreaPlanningAlthoughresourceplanningisperformedwiththegoalofmeetingtheplanningobjectivesattheoveralllowestreasonablesupplycost,physicalandoperationalfactorsdictatethatregionalreliabilityneedsmustbeconsideredwhenplanningforthereliableoperationwithinthearea.Thus,oneaspectoftheplanningprocessisthedevelopmentofplanningstudiestoidentifysupplyneedswithinspecificgeographicareas,andtoevaluatesupplyoptionstomeetthoseneeds.12JointApplicationOfEntergyGulfStatesLouisiana,L.L.C.AndEntergyLouisiana,LLCForCertificationOfTheLouisianaEconomicTransmissionProjectInAccordanceWithLouisianaPublicServiceCommissionGeneralOrderDatedOctober10,2013,filedApril21,2015,LPSCDocketNo.U33605.13ApplicationOfEntergyGulfStatesLouisiana,L.L.C.ForCertificationOfTheLakeCharlesTransmissionProjectInAccordanceWithLouisianaPublicServiceCommissionGeneralOrderDatedOctober10,2013,filedJune16,2015,LPSCDocketNo.U33645.

12Figure1:MapofLouisianaPlanningAreasForplanningpurposes,theregionservedbytheCompaniesisdividedintothreemajorplanningareasandonesubarea.Theseareasaredeterminedbasedoncharacteristicsoftheelectricsystemincludingtheabilitytotransferpowerbetweenareasasdefinedbytheavailabletransfercapability,thelocationandamountofload,andthelocationandamountofgeneration.Thethreemajorplanningareasandsubareaarelistedbelow:* WestoftheAtchafalayaBasin("WOTAB")-theareagenerallywestoftheBatonRougemetropolitanarea.* AmiteSouth-theareagenerallyeastoftheBatonRougemetropolitanareatotheMississippistateline,andtheareasouthtotheGulfofMexico.* DownstreamofGypsy("DSG")-asubareaencompassingtheSoutheastportionofAmiteSouth,generallyincludingtheareadownriveroftheLittleGypsyplantincludingmetropolitanNewOrleanssouthtotheGulfofMexico.* Central-theremainderofLouisiananorthoftheWOTABandAmiteSouthareas,includingtheBatonRougemetropolitanarea.Asdescribedlaterinthisreport,separateassessmentsoftheAmiteSouthandWOTABplanningareasindicateaneedforadditionalresourcesinthoseplanningareasearlyinthenextdecade.TheneartermneedsarelargelydrivenbytheincreaseinloadresultingfromtheLouisiana 13industrialrenaissanceandexpiringPPAs,butresourceneedsovertheplanninghorizonarealsosignificantlyinfluencedbyunitdeactivations.PART2:ASSUMPTIONSTechnologyAssessmentAspartofthisIRPprocess,a2014TechnologyAssessmentwaspreparedtoidentifypotentialsupplysideresourcealternativesthatmaybetechnologicallyandeconomicallysuitedtomeetcustomerneeds.TheinitialscreeningphaseoftheTechnologyAssessmentreviewedthesupplysidegenerationtechnologylandscapetoidentifyresourcealternativesthatmeritedmoredetailedanalysis.Duringtheinitialphase,anumberofresourcealternativeswereeliminatedfromfurtherconsiderationbasedonarangeoffactorsincludingtechnicalmaturity,stageofcommercialdevelopment,andeconomics.Theseresourcealternativeswillcontinuetobemonitoredforpossiblefuturedevelopment.Thefollowingresourcealternativeswerefoundappropriateforfurtheranalysis: PulverizedCoal-SupercriticalPulverizedCoalwithcarboncapture("PC"with"CC") NaturalGasFiredalternativeso SimpleCycleCombustionTurbines("CT")o CombinedCycleGasTurbines("CCGT")o SmallScaleAeroderivativeso LargeScaleAeroderivatives Nuclear-(GenerationIIITechnology) Renewableso Biomasso OnshoreWindPowero SolarPhotovoltaic("PV")Uponcompletionofthescreeninglevelanalysis,moredetailedanalysis(includingrevenuerequirementsmodelingofremainingresourcealternatives)wasconductedacrossarangeofoperatingrolesandunderarangeofinputassumptions.Theanalysisresultedinthefollowingconclusions:

14 Amongconventionalgenerationresourcealternatives,CCGTandCTtechnologiesarethemostattractive.Thegasfiredalternativesareeconomicallyattractiveacrossarangeofassumptionsconcerningoperationsandinputcosts. Newnuclearandnewcoalalternativesarenoteconomicallyattractiveneartermoptionsrelativetogasfiredtechnology.Thelowpriceofgasandtheuncertaintiesaroundemissionsregulationmakecoaltechnologiesunattractive.Nucleariscurrentlyunattractiveduetobothcapitalandregulatoryrequirements. Despiterecentdeclinesinthecapitalcostandimprovementsofrenewablegenerationalternatives,theyarestilllesseconomicallyattractivecomparedtoCCGTandCTalternativesdueto:o Declinesinthelongtermoutlookfornaturalgaspricesbroughtonbytheshalegasboom;o Uncertaintyabouttherenewalofproductiontaxcreditsandinvestmenttaxcreditsthatareapplicabletoresourcescompletedbeforetheendof2016;ando Theuncertainneartermoutlookforemissionsregulation. Amongrenewablegenerationalternatives,windandsolararethemostlikelytobecomecostcompetitive.However,uncertaintieswithrespecttovariousrenewablegenerationtaxcreditextensions,capacitycreditsallowedfortheseresourcesbyMISO,andimplementationandtimingofCO2regulationsforfossilfuelresourcealternativeslikelywillaffectthecompetitivenessofrenewableresourcealternatives.MISOdeterminesthecapacityvalueforwindgenerationbasedonaprobabilisticanalyticalapproach.Theapplicationofthisapproachresultedinacapacityvalueofapproximately14.1%forthe201415planningyear.Furthermore,thefootprintoftheCompaniesisnotfavorableforwindgeneration.Thetransmissioncosttoserveloadwithwindpowerfromremoteresourceswillfurtherworsentheeconomicsofwindcomparedtoconventionalresources.InMISO,solarresourcesreceivenocapacitycreditwithinthefirstyearofoperation.Solarpoweredresourcesmustsubmitalloperatingdataforthepriorsummerwithaminimumof30consecutivedaystohavetheircapacityregisteredwithMISO.Table1summarizestheresultsoftheTechnologyAssessmentforanumberofresourcealternatives.

15Table1:2014TechnologySensitivityAssessmentBasedonGenericCostofCapital14NoCO2($/MWh)CO2Beginning2023($/MWh)TechnologyCapacityFactor15ReferenceFuelHighFuelLowFuelReferenceFuelHighFuelLowFuelFFrameCT10%$198$224$179$204$230$184FFrameCTw/SelectiveCatalyticReduction20%$141$167$121$146$173$126EFrameCT10%$240$274$215$247$281$222LargeAeroderivativeCT40%$108$131$91$113$136$95SmallAeroderivativeCT40%$125$150$106$130$156$112InternalCombustion40%$115$137$99$120$141$1042x1FFrameCCGT65%$79$97$67$83$100$702x1FFrameCCGTw/Supplemental65%$75$93$61$78$97$652x1GFrameCCGT65%$76$93$63$79$96$672x1GFrameCCGTw/Supplemental65%$72$90$59$76$94$631x1FFrameCCGT65%$82$100$69$86$104$731x1JFrameCCGT65%$73$90$61$77$93$651x1JFrameCCGTw/Supplemental65%$72$132$59$76$136$63PulverizedCoalw/CarbonCapturingSequestration85%$163$230$94$165$232$96Biomass85%$175$321$142$175$321$142Nuclear90%$157$169$157$157$169$157Wind1634%$109$109$109$109$109$109Windw/ProductionTaxCredit34%$102$102$102$102$102$102SolarPV(fixedtilt)1718%$190$190$190$190$190$190SolarPV(tracking)1821%$179$179$179$179$179$179BatteryStorage1920%$217$217$217$217$217$21714Ageneraldiscountrate(7.656%)wasusedinordertoaccuratelymodeltheseresourcesintheMarketModelingstageoftheIRP.15Assumptionusedtocalculatelifecycleresourcecost.16Includescapacitymatchupcostof$18.76/MWhduetowind's14.1%capacitycreditinMISO.17Includescapacitymatchupcostof$30.93/MWhassuminga25.0%capacitycreditinMISO.18Includescapacitymatchupcostof$26.51/MWhassuminga25.0%capacitycreditinMISO.19Includescostof$25/MWhrequiredtochargebatteries.

16DemandSideAlternativesTheCompaniesengagedtheservicesofICFInternationaltoassessthemarketachievablepotentialforDemandSideManagement("DSM")programsthatcouldbedeployedovertheplanninghorizon.Intotal,1,097measureswereevaluated,ofwhich896wereconsideredcosteffectivewithaTotalResourcesCost("TRC")testresultof1.0orbetter.Thesemeasureswerethencollectedinto24DSMprogramstobeassessedintheIRPprocess.ThePotentialStudyestimatedthepeakload,annualenergyreduction,andprogramcoststhatresultfromalow,reference,andhighlevelofspendingonprogramincentives.ThereferencecaseestimateofDSMpotentialindicatesapproximately673MWofpeakdemandreductioncouldbeachievedby2034iftheCompanies'investmentinDSMwassustainedfora20yearperiod.ThemethodologyofthePotentialStudywasconsistentwithaprimaryobjectivetoidentifyawiderangeofDSMalternativesavailabletomeetcustomers'needs.Inthisway,thestudyresultshelpedensurethatmoreDSMprogramswouldbeidentifiedforfurtherevaluationintheIRP.DSMprogramcostsutilizedintheIRPincludeincentivespaidtoparticipantsandprogramdeliverycostssuchasmarketing,training,andprogramadministration.Programdeliverycostswereestimatedtoreflectaverageannualcostsoverthe20yearplanninghorizonoftheDSMPotentialStudy.Thecostsreflectanassumptionthatovertheplanninghorizon,programefficiencieswillbeachievedresultinginlowerexpectedcosts.Thatis,asexperienceisgainedwithcurrentandfutureprograms,actualcostmaydecreaseovertime.Assuch,actualneartermcostsassociatedwithcurrentandfutureprogramsmaybehigherthantheassumptionsusedtodeterminetheoptimalcosteffectivelevelidentifiedintheCompanies'FinalReferenceResourcePortfolioPlan.Therefore,futureDSMprogramgoalsandimplementationplansshouldreflectthisuncertainty.TheIRPassumptionsfortheDSMprogramcostestimatesascomparedtothecostoftypicalsupplysidealternativesareincludedintheDSMTechnicalSupplementtotheIRP.

17NaturalGasPriceForecastSystemPlanningandOperations20("SPO")preparedthenaturalgaspriceforecast21usedinthe2015IRP.TheneartermportionofthenaturalgasforecastisbasedonNYMEXHenryHubforwardprices,whichserveasanindicatorofmarketexpectationsoffutureprices.BecausetheNYMEXfuturesmarketbecomesincreasinglyilliquidasthetimehorizonincreases,NYMEXforwardpricesarenotareliablepredictoroffuturepricesinthelongterm.Duetothisuncertainty,SPOpreparesalongtermpointofview("POV")regardingfuturenaturalgaspricesutilizinganumberofexpertconsultantforecaststodetermineanindustryconsensusregardinglongtermprices.ThelongtermnaturalgasforecastusedintheIRPincludessensitivitiesforhighandlowgaspricestosupportanalysisacrossarangeoffuturescenarios.IndevelopinghighandlowgaspricePOVs,SPOutilizesseveralconsultantforecaststodeterminelongtermpriceconsensus.TheseforecastsareshownintheTablebelow.Table2:HenryHubNaturalGasPriceForecastsHenryHubNaturalGasPricesNominal$/MMBtuReal2014$/MMBtuLowReferenceHighLowReferenceHighRealLevelized,22(20152034)$4.57$5.77$9.72$3.84$4.87$8.17Average(20152034)$4.82$6.28$10.79$3.66$5.00$8.0820YearCAGR2.5%3.1%6.2%0.4%1.0%4.1%20SystemPlanningandOperationsisadepartmentwithinESItaskedwith:(1)theprocurementoffossilfuelandpurchasedpower,and(2)theplanningandprocuringofadditionalresourcesrequiredtoprovidereliableandeconomicelectricservicetotheEOCs'customers.SPOalsoisresponsibleforcarryingoutthedirectivesoftheOperatingCommitteeandthedailyadministrationofaspectsoftheEntergySystemAgreementnotrelatedtotransmission.21TheforecastwaspreparedfromtheJuly2014gaspriceforecastwhichistheCompanies'latestofficialforecastandwasincludedintheCompanies'November3,2014UpdatedIRPInputsfiling.22"Reallevelized"pricesrefertothepricein2014$wheretheNPVofthatpricegrownwithinflationoverthe20152034periodwouldequaltheNPVoflevelizednominalpricesoverthe20152034period.

18ThenaturalgasforecastsabovedonotattempttoforecasttheeffectsoftheshorttermnaturalgashedgingprogramscurrentlyemployedbytheCompanies.Thecurrentgashedgingprogramattemptstomitigateshorttermgaspricevolatility.However,giventheshorttermnatureofthegashedgingprogram,thereisnoeffectonthelongtermgaspricesexperiencedbytheCompanies.TheCompanieshaveevaluatedandcontinuetoevaluateopportunitiesthatwould,onalongertermbasis,helpstabilizegaspricesandofferthepotentialforsavingsrelativetogaspricesthatmayexistinthefuture.TheCompaniesalsonotethattheCommissionhasapprovedalongtermgashedgingpilotprograminGeneralOrderNo.R32975.However,noadjustmentsarewarrantedtotheCompanies'longtermnaturalgasforecastsatthistime.IftheCommissionapprovesanylongtermgastransactionsfortheCompanies,theexpectedpricefromsuchtransactionswillbeconsideredintheCompanies'futureresourceplanningdecisions.CO2AssumptionsAtthistime,itisnotpossibletopredictwithanydegreeofcertaintywhethernationalCO2legislationwilleventuallybeenacted,andifitisenacted,whenitwouldbecomeeffective,orwhatformitwouldtake.Inordertoconsidertheeffectsofcarbonregulationuncertaintyonresourcechoiceandportfoliodesign,theIRPprocessreliedonarangeofprojectedCO2costoutcomes.ThelowcaseassumesthatCO2legislationdoesnotoccuroverthe20yearplanninghorizon.Thereferencecaseassumesthatacapandtradeprogramstartsin2023withanemissionallowancecostof$7.54/U.S.tonanda20152034levelizedcostin2014$of$6.83/U.S.ton.23Thehighcaseassumesthatacapandtradeprogramstartsin2023at$22.84/U.S.tonwitha20152034levelizedcostin2014$of$14.61/U.S.ton.MarketModelingAuroraModelThedevelopmentoftheIRPreliedontheAURORAxmpElectricMarketModel("AURORA")tosimulatemarketoperationsandproducealongtermforecastoftherevenuesandcostofenergyprocurementfortheCompanies.24AURORA25isaproductioncostmodelandresourcecapacityexpansionoptimizationtoolthatusesprojectedmarketeconomicstodeterminetheoptimallongtermresourceportfoliounder23Includesadiscountrateof7.656%.24TheAURORAmodelreplacesthePROMODIVandPROSYMmodelsthattheCompaniespreviouslyused.25TheAURORAmodelwasselectedfortheIRPandotheranalyticworkafteranextensiveanalysisofelectricitysimulationtoolsavailableinthemarketplace.AURORAiscapableofsupportingavarietyofresourceplanning 19varyingfutureconditionsincludingfuelprices,availablegenerationtechnologies,environmentalconstraints,andfuturedemandforecasts.AURORAestimatespriceanddispatchusinghourlydemandsandindividualresourceoperatingcharacteristicsinatransmissionconstrained,chronologicaldispatchalgorithm.TheoptimizationprocesswithinAURORAidentifiesthesetofresourcesamongexistingandpotentialfuturedemandandsupplysideresourceswiththehighestandlowestmarketvaluestoproduceeconomicallyconsistentcapacityexpansion.AURORAchoosesfromnewresourcealternativesbasedonthenetreallevelizedvaluesperMW("RLV/MW")ofhourlymarketvaluesandcomparesthosevaluestoexistingresourcesinaniterativeprocesstooptimizethesetofresources.Scenarios26IRPanalyticsreliedonfourscenariosdesignedtoassessalternativeportfoliosacrossarangeofoutcomes.Thefourscenariosare:* IndustrialRenaissance(Reference)-AssumestheU.S.energymarket(particularlyasitaffectstheGulfCoastregionandLouisiana)continueswithreferencefuelprices.Currentfuelpricesdriveconsiderableloadgrowthandeconomicopportunityespeciallyintheindustrialclass.TheIndustrialRenaissancescenarioassumesreferenceload,referencegas,andnoCO2costs.* BusinessBoom-AssumestheU.S.energyboomcontinueswithlowgasandcoalprices.Lowfuelpricesdrivehighloadgrowthespeciallyintheindustrialclass,butwithresidentialandcommercialclassspilloverbenefits.Asaresultoftheindustrialloadgrowthandlowfuelprices,powersalesincreasesignificantly.AmodestCO2taxorcapandtradeprogramisimplementedandiseffectivein2023.* DistributedDisruption-Assumesstatescontinuetosupportdistributedgeneration.Consumersandbusinesseshaveagreaterinterestininstallingdistributedgeneration,whichleadstoadecreaseinenergydemand.OveralleconomicconditionsaresteadywithmoderateGDPgrowth,whichenablesinvestmentinenergyinfrastructure.However,naturalgaspricesaredrivenhigherbyEPAregulationofhydraulicfracturing.CongressortheEPAalsoimplementsamoderateCO2taxorcapandtradeprogram.activitiesandiswellsuitedforscenariomodelingandriskassessmentmodeling.Itiswidelyusedbyloadservingentities,consultants,andindependentpowerproducers.26ThefourscenariosandtheirgeneralassumptionshaveremainedconstantthroughouttheIRPprocess.However,intheNovember2014filing,twoofthescenarioswererenamedfromtheMay2014filing."ScenarioOne"wasrenamed"IndustrialRenaissance."The"IndustrialRenaissance"ScenariointheMay2014wasrenamed"BusinessBoom"intheNovember2014filing.

20* GenerationShift-AssumesgovernmentpolicyandpublicinterestdrivesupportforgovernmentsubsidiesforrenewablegenerationandstrictrulesonCO2emissions.Highnaturalgasexportsandmorecoalexportsleadtohigherfuelprices.EachscenariowasmodeledinAurora.Theresultingmarketmodeling,whichincludedprojectedpowerprices,providedabasisforassessingtheeconomicsoflongterm(here,twentyyears)resourceportfolioalternatives.Table3:SummaryofKeyScenarioAssumptionsSummaryofKeyScenarioAssumptionsIndustrialRenaissance(Ref.Case)BusinessBoomDistributedDisruptionGenerationShiftElectricityCAGR(EnergyGWh)27~1.45%~1.70%~0.90%~1.20%PeakLoadGrowthCAGR~1.05%~1.10%~0.75%~0.85%HenryHubNaturalGasPrice($/MMBtu)ReferenceCase($4.87levelized2014$)LowCase($3.84levelized2014$)ReferenceCase($4.87levelized2014$)HighCase($8.17levelized2014$)CO2Price($/shortton)LowCase:NoneReferenceCase:Capandtradestartsin2023$6.83levelized2014$Capandtradestartsin2023$6.83levelized2014$Capandtradestartsin2023$14.61levelized2014$PART3:CURRENTFLEET&PROJECTEDNEEDSCurrentFleetCurrently,theCompaniestogethercontrolapproximately10,561MWofgeneratingcapacityeitherthroughownershiporlongtermpowerpurchasecontract.AppendixAprovidesanoverviewoftheCompanies'currentactivegenerationportfolio.Table4showsthesupplyresourcesbyfueltypemeasuredininstalledMWwithpercentagesforELLandEGSLseparatelyandforthecombinedcompany.ItisimportanttonotethatsomeoftheamountsbelowrepresentresourcesthatarenotownedbytheCompaniesbutinsteadareundercontractthroughPPAs.AsreflectedonTable4andAppendixA,roughlyonehalfofthecurrentcombinedresourceportfoliosarefromlegacygasgenerationwhichhasbeeninservicefor4027Allcompoundannualgrowthrates("CAGRs")inthistable:20152034(20Years)forthemarketmodeledinAURORA.

2160years.WhiletheCompanieshavemadeandwillcontinuetomakeeconomicinvestmentstoextendtheservicelifeofthesegenerators,manyofthesegeneratorsareassumedtodeactivateovertheplanninghorizonandtheseunitdeactivationsareasignificantdriveroftheCompanies'needforadditionalgenerationregardlessofanyassumedloadgrowth.Table4:2014EGSLandELLCombinedResourcePortfolioInaddition,theCompaniesaddedanewCCGTfacility,Ninemile6,totheportfolioinDecember2014.Ninemile6isa561MWCCGTresourcelocatedinWestwego,LouisianaattheNinemilePointStationinJeffersonParish.TheCompaniesreceivedCommissionapprovaltoconstructthisnewCCGTgeneratingfacility,thecurrentlyestimatedcostofwhichis$655million.29LoadForecastAwiderangeoffactorslikelywillaffectelectricloadinthelongterm,including:* Levelsofeconomicactivityandgrowth;* Thepotentialfortechnologicalchangetoaffecttheefficiencyofelectricconsumption;* Potentialchangesinthepurposesforwhichcustomersuseelectricity(e.g.,theadoptionofelectricvehicles);28TotalresourcesincludetheadditionofNinemile6.29ExParte:JointApplicationofEntergyLouisiana,LLCforApprovaltoConstructUnit6atNinemilePointStationandofEntergyGulfStatesLouisiana,L.L.C.forApprovaltoParticipateinaRelatedContractforthePurchaseofCapacityandElectricEnergy,forCostRecoveryandRequestforTimelyRelief,OrderNo.U31971(April5,2012).2014EGSLandELLCombinedResourcePortfolioELLEGSLCombinedMW%MW%MW%Coal32136793994Nuclear1,6092439091,99919CombinedCycleGasTurbine(CCGT)1,289201,036262,32522OtherGas3,479532,173545,65254Hydro&Other12526121862Total6,5344,02710,56128 22* Thepotentialadoptionofenduse(behindthemeter)selfgenerationtechnologies(e.g.,rooftopsolarpanels);and* Thelevelofenergyefficiency,conservationmeasures,anddistributedgeneration(e.g.,rooftopsolarpanels)adoptedbycustomers.Suchfactorsmayaffectboththelevelandshapeofloadinthefuture.Peakloadsmaybehigherorlowerthanprojectedlevels.Similarly,industrialcustomerloadfactorsmaybehigherorlowerthancurrentlyprojected.Uncertaintiesinloadmayaffectboththeamountandtypeofresourcesrequiredtoefficientlymeetcustomerneedsinthefuture.Inordertoconsiderthepotentialimplicationsofloaduncertaintiesonlongtermresourceneeds,fourloadforecastscenarioswerepreparedfortheIRP,whicharedescribedbelow:IndustrialRenaissance-ReferenceloadAssumesIndustrialRenaissancewillhaveamultipliereffectthatwillspurloadgrowthinresidential,commercial,andgovernmentclasses(referredtoasan"economicmultiplier")andincludesadditionalindustrialgrowthstemmingfromtheregionalIndustrialRenaissance.BusinessBoomAssumeshighereconomicmultipliereffect,alowerriskadjustmenttofutureindustrialprojects,andanincreaseinthenumberofindustrialprojectsthatareincludedinforecast.DistributedDisruptionDecrementstheReferenceloadscenarioforCombinedHeatandPower("CHP")impactanddistributedsolarphotovoltaicsystem("PV")impact.GenerationShiftAssumesnoeconomicmultipliereffect,nocommercialconversions,andfewerindustrialprojects.MethodologySPOusedthesameloadforecastingprocessasdescribedinpreviousIRPsdevelopedfortheCompanies.ThatprocessusescomputersoftwarefromItrontodevelopa20year,hourbyhourloadforecast.TheMetrixND30andtheMetrixLTŽ31programsareusedwidelyinthe30MetrixNDbyITronisanadvancedstatisticsprogramforanalysisandforecastingoftimeseriesdata.

23utilityindustry,tothepointwheretheymaybeconsideredanindustrystandardforenergyforecasting,weathernormalization,andhourlyloadandpeakloadforecasting.Todeveloptheloadforecast,SPOallocatestheRetailEnergyForecast(bymonth)andtheWholesaleEnergyForecast(bymonth)toeachhourofa20yearperiodbasedonhistoricalloadshapesdevelopedbyESI'sLoadResearchDepartment.Fifteenyear"typicalweather"isusedtoconverthistoricloadshapesinto"typicalloadshapes."Forexample,iftheactualsalesforanEOC'sresidentialcustomersoccurredduringveryhotweatherconditions,thetypicalloadshapewouldflattenthehistoricloadshape.Iftheactualweatherweremild,thetypicalloadshapewouldraisethehistoricloadshape.EachcustomerclassineachEOCrespondsdifferentlytoweather,soeachhasitsownweatherresponsefunction.MetrixNDisusedtoadjustthehistoricalloadshapesbytypicalweather,andMetrixLTŽisusedtocreatethe20year,hourlyloadforecast.Theloadforecastisgrosseduptoincludeaveragetransmissionanddistributionlinelosses.TheCompanieshaveuniquelossfactorsthatareappliedtoeachrevenueclassaftertheforecastisdevelopedandafteraccountingforenergyefficiency.Forexample,whenlinelossesareaddedintotheCompanies'forecastsELL'sresidentialclassisgrossedupbyadifferentamountthanEGSL'sresidentialclass.CogenerationloadsareincludedintheIndustrialrevenueclassandaseparatepeakisnotdevelopedforthesecustomersastheirloadscanbeirregular.EconometricmodelsareusedtodeveloptheenergyforecastforcogenerationloadswhicharethencombinedwithbothlargeandsmallindustrialcustomerstocreatetheIndustrialenergyforecast.Interruptionsareinhistoricaldatathattheforecastmodelsuse,butcustomerspecificinterruptionsarenotforecastedastheinterruptionsareirregular.EnergysavingsfromcompanysponsoredDSMprogramsaredecrementedfromtheRetailenergyforecast.Theloadforecastusesthedecrementedenergyforecasttodevelopannualpeaksthatreflectthesavingsfromsuchprograms.ResourceNeedsOvertheIRPperiod,theCompanieswillneedtoaddresources.Thelongtermresourceneedsareprimarilydrivenbyloadgrowthexpectations,unitdeactivationassumptions,andexistingPPAcontractterminationsandexpirations.ForthepurposeofdevelopingthisIRP,assumptionsmustbemadeaboutthefutureofgeneratingunitscurrentlyintheportfolio.31MetrixLTŽbyITronisaspecializedtoolfordevelopingmediumandlongrunloadshapesthatareconsistentwithmonthlysalesandpeakforecasts.

24AssumptionsmadefortheIRParenotfinaldecisionsregardingthefutureinvestmentinresources.Unitspecificportfoliodecisions,suchassustainabilityinvestments,environmentalcomplianceinvestments,orunitretirements,arebasedoneconomicandtechnicalevaluationsconsideringsuchfactorsasprojectedforwardcosts,anticipatedoperatingroles,andthecostofsupplyalternatives.Thesefactorsaredynamic,andasaresult,actualdecisionsmaydifferfromplanningassumptionsasgreatercertaintyisgainedregardingrequirementsoflegislation,regulation,andrelativeeconomics.Basedoncurrentassumptions,anumberoftheCompanies'existingfossilgeneratingunitsmaybedeactivatedduringtheIRPplanningperiod.Inaddition,variousPPAsthattheCompanieshavepreviouslyenteredintowillexpire.Intheyears20152034,thetotalnetreductionintheCompanies'generatingcapacityfromtheseassumedunitdeactivationsandPPAterminationsandexpirationsisapproximately6,859MWrelativetotheCompanies'currentcombinedresourcesofapproximately10,561MW.IncludedinthisamountistheeffectoftheterminationofthePPAsenteredbetweenEGSLandETIpursuanttotheJurisdictionalSeparationPlan("JSP")thatledtotheseparationofEntergyGulfStates,Inc.intoEGSLandETI.ThosePPAsarereferredtohereinasthe"JSPPPAs."32ThisIRPassumesthattheJSPPPAswillterminatewhenETIorEGSLterminatesparticipationintheSystemAgreement,asprovidedforintheLPSC'sorderregardingtheJSP.33TheoverallneteffectwouldreduceEGSL'sportfoliopositionbyroughly700MWin2018basedonETI'sterminatingparticipation34intheSystemAgreementonOctober18,2018.Moreover,inthecomingyears,theCompanieswillfacetheneedforadditionalresourcestomeetloadgrowth.Theloadforecastnecessarilyhaschangedduringthe18monthperiodinwhichthisIRPwasdevelopedandcanbeexpectedtochangeinthefuture.Ascontemplated32AsaresultoftheimplementationoftheJSPtoseparateEntergyGulfStates,Inc.("EGSI")intoseparateTexasandLouisianacompanies,ETIandEGSL(successorsininteresttoEGSI)currentlysharecertaincapacityinTexasandLouisiana.ThiscapacityissharedthroughcostbasedpurchasesandsalesmadepursuanttopurchasedpoweragreementsunderServiceScheduleMSS4oftheEntergySystemAgreement.Specifically,EGSLsellstoETI42.5%ofthecapacityandrelatedenergyofthefollowingresources:(1)WillowGlenandNelson;(2)Calcasieu;(3)Perryville;and(4)RiverBend.ETIsellstoEGSL:(1)57.5%ofthecapacityandrelatedenergyassociatedwithitsLewisCreekandSabineresources;and(2)50%ofthecapacityandrelatedenergyassociatedwiththeCarvilleresource.AsubsetofthesePPAs,referredtoasthe"JSPPPAs,"willterminateuponETI'sterminationofitsparticipationintheSystemAgreement.TheseJSPPPAsincludetheMSS4PPAsassociatedwiththeWillowGlen,Nelsongas,LewisCreek,Sabine,andCalcasieugeneratingunits.SeealsoLPSCOrderNos.U21453,U20925,andU22092SubdocketJ,Inre:RequestfortheApprovaloftheJurisdictionalSeparationPlanforEntergyGulfStates,Inc.,datedJanuary31,2007,at20.33Inre:RequestfortheApprovaloftheJurisdictionalSeparationPlanforEntergyGulfStates,Inc.,OrderNos.U21453,U20925andU22092(SubdocketJ),Orderatp.20(Jan.31,2007).34ETIprovidednoticetotheEOCsofitsintenttoterminateitsparticipationintheSystemAgreementeffectiveOctober18,2018.

25bytheIndustrialRenaissanceScenario(referencecase),theareasservedbytheCompaniesareexperiencingaheightenedlevelofeconomicdevelopmentactivitystemmingfromtheavailabilityoflowcostnaturalgasandeffortsbytheStateofLouisianatoaddjobsandgrowtheeconomythroughattractingnewandexpandedindustrialfacilities.Assuch,inthereferencecase,theCompanies'loadsareprojectedtoreachapproximately11,200MWby2019(a15%increaseoverthecurrentcombinedlevelofapproximately9,600MW),whichreflectstheadditionofapproximately1,600MWofindustrialfacilitiesby2019.By2025,theCompanies'totalreferenceloadisprojectedtoincreaseapproximately1,760to2,200MWfromthepresentcombinedlevel.ThefollowingTablesummarizestheprojectedpeakforecastincreasefortheCompaniesoverthenext20years(20152034)byscenario.Table5:ELLandEGSLProjectedPeakForecastIncreasefrom2015IndustrialRenaissance(MWs)BusinessBoom(MWs)DistributedDisruption(MWs)GenerationShift(MWs)By20342,2262,6261,5071,751InbothAmiteSouthandWOTAB,currentsupplyneedsrequirelocalgeneration,yettherearelimitedavailablepowersourcesthatexistwithineachoftheregions.AmiteSouthisasupplyconstrainedregionthat,basedonprojectedloadgrowth,unitretirements,andPPAexpirations,mayrequirenewresourceseveryfiveyearsinordertocontinuemeetingreliabilityneedswithinitsloadpocket.35Theindustrialloadgrowthintheregionfurtherincreasesthisneed.IntheIndustrialRenaissanceScenario,theAmiteSouthregion'speakloadisexpectedtogrowbyapproximately10%(500MW)toatotalofapproximately6,000MWby2019.Inotherwords,resourcesneedtobeplannedandbroughtonlineinanorderlysequencetomaintainadequatecapacityandstabilityandsupporttheregion'sgrowingload.

SeparatefromtheAmiteSouthregion,theWOTABregionisexpectedtoexperiencesignificantindustrialloadgrowthundertheIndustrialRenaissanceScenario.EGSL'sloadinWOTABisanticipatedtoincreasebyapproximately70%(800MW)toatotalofapproximately1,900MWby2019.AsubstantialportionoftheexpectedgrowthinloadwillbecenteredaroundLakeCharles.TheconcentrationofloadwithintheLakeCharlesareaisexpectedtoresultinthecreationofaloadpocketwithintheplanningregion,whichwillrequireadditionalresourcesasloadcontinuestogrow.35Loadpocketsareareasofthesystemwherelocalgenerationalongwithtransmissionimportcapabilityisneededtoservetheloadreliablywithinthearea.

26Asdiscussedlaterinthisreport,theseincreasesinresidential,commercial,andindustrialload,andunitdeactivationsandPPAexpirationswillrequiretheCompaniestoaddresourcestomeettheloadandmaintainreliability.Thereisexpectedtobealimitedeffectoncustomerrates,however,becauseoftheincreaseincustomerkWhusageoverwhichthefixedcostsofthenewresourcesarespread,portfolioefficiencyimprovements,andexpirationofothercustomerchargesamongotherfactors.AsshowninTables6and7below,by2034,thecombinationofloadgrowth,resourcedeactivationsandPPAcontractexpirationsmayresultinapproximately9.5GWofcapacityneededfortheIndustrialRenaissanceScenario.By2024,thecapacitydeficitcouldbeashighas3.6GWunderthecurrentloadforecastsandresourcedeactivationandexpirationassumptions.Table6:ResourceNeedsbyScenario(MWs)*Includes12%planningreservemarginCapacitySurplus/(Need)(BeforeIRPAdditions)IndustrialRenaissanceBusinessBoomDistributedDisruptionGenerationShiftBy2024(3,601)(4,039)(3,173)(2,980)By2034(9,536)(9,999)(8,695)(8,913)

Table7:InThereare In D StrTypesoInorderCompaniandtypesufficientdescribedndustrialReneanumberncrementallo SelfSo Acquio LongDemandSidehorttermcransactions.ofResourcetoreliablyiesmustmaesofcapacittgeneratingdabove,thenaissance20ofalternativongtermreupplyalternsitionsTermPPAsaealternativescapacitypuesNeededmeetthepaintainapoty.WithresgcapacityteCompaniesYearProjectevestoaddreesourceaddinativesandrenewasurchasesindpowerneedsrtfolioofgespecttotheomeetthesneedtoplaedCapacityNsstheresouitionsincludlsMISOPlasofcustomenerationreamountofirpeakloadanforresouNeed(GW)urceneeds,iing:nningResomersattheesourcesthacapacity,thdsplusapurcestomeencluding:ourceAuctiolowestreasatincludestheCompanielanningreseettheannuaonorbilasonablecosttherightamesmustmaiervemarginalreservem27ateralt,themountntainn.Asmargin 28mandatedbyMISO,whichisassumedtobe12%forlongtermplanning.Ingeneral,theCompanies'supplyroleneedsinclude: BaseLoad-expectedtooperateinmosthours. LoadFollowing-capableofrespondingtothetimevaryingneedsofcustomers. PeakingandReserve-expectedtooperaterelativelyfewhours,ifatall.Table8:ProjectedResourceNeedsin2034bySupplyRoles(withoutPlannedAdditions)inIndustrialRenaissanceScenarioNeedResourcesSurplus/(Deficit)BaseLoad(MW)7,9482,399(5,549)LoadFollowing(MW)2,2571,270(987)Peaking&Reserve(MW)3,341341(3,000)Totals13,5464,010(9,536)Table8showsthatforbothCompanies,thesupplyrolewiththegreatestneedisbaseload.Peakingresourceswillalsobeneededwithinthe20yearplanninghorizon.PART4:PORTFOLIODESIGNANALYTICSTheIRPutilizedatwostepapproachtoconstructandassessalternativeresourceportfoliostomeetthecustomerneeds:1. MarketModeling2. PortfolioDesign&RiskAssessmentMarketModelingThefirststeptodevelopwithintheAURORAmodelisaprojectionofthefuturepowermarketforeachofthefourscenarios.ThisprojectionlooksatthepowermarketfortheentireMISOfootprintexcludingLouisianatogainperspectiveonthebroadermarketoutsidethestate.Thepurposeofthisstepwastoprovideprojectedpowerpricestoassesspotentialportfoliostrategieswithineachscenario.Inordertoachievethis,assumptionswererequiredaboutthefuturesupplyofpower.TheprocessfordevelopingthoseassumptionsreliedontheAURORA 29CapacityExpansionModeltoidentifytheoptimalsetofresourceadditionsinthemarkettomeetreliabilityandeconomicconstraints.ResultingassumptionsregardingnewcapacityadditionsineachscenarioaresummarizedinTable9.Table9:ResultsofMISOMarketModelingResultsofMISOMarketModeling(MISOFootprint,excludingLouisiana)IncrementalCapacityMixbyScenarioIndustrialRenaissance(Ref.Case)BusinessBoomDistributedDisruptionGenerationShiftCCGT52%91%98%53%CT48%9%2%1%Wind0%0%0%31%Solar0%0%0%0%YearofFirstAddition2020202020202020TotalGWsAdded(through2034)11712773226ResultsoftheCapacityExpansionModelingthatsupportedconclusionsfromtheTechnologyAssessment,asdiscussedearlier,werereasonablyconsistentacrossscenarios.Theseresults,assummarizedbelow,aretheoutputofthemodelbasedonthemarketconditionsthatthemodelanalyzed: Ingeneral,newbuildcapacityisrequiredtomeetoverallreliabilityneeds. Gasfired,CTsandCCGTs,arethepreferredtechnologiesfornewbuildresourcesinmostoutcomes. Themodeldidnotselectnewnuclearornewcoalforanyscenario. ThemodeldidnotselectsolarPVorbiomassforanyscenario. Windgenerationhasasignificantroleinonlyoneofthescenariosthatinvolveshighgasandcarbonprices.PortfolioDesign&RiskAssessmentTheAURORACapacityExpansionModelanalyzesleastcostportfoliostomeettheCompanies'resourceneedsusingthescreeneddemandandsupplysideresourcealternatives.Throughthis 30analysis,theCompaniessoughttoassesstherelativeperformanceofthehighestrankingresourcealternativesfromthescreeningassessmentswhenincludedwiththeCompanies'existingresourcesandtotesttheirperformanceacrossarangeofoutcomesasprovidedbythescenarios.Thisanalysisseekstoidentifytheportfoliothatproducesthelowesttotalsupplycosttomeettheidentifiedneeds,butdoesnottakeintoaccountratedesignorrateeffects.Intotal,fourportfolios(describedbelow)wereconstructedandassessed.TheAURORACapacityExpansionModelwasusedtodevelopaportfolioforeachofthescenariosinatwostepprocess,whichfirstassessedDSMprograms,andthensupplysidealternatives.DSMprogramswereevaluatedfirstwithoutconsiderationofsupplysidealternativesbyallowingtheAURORACapacityExpansionModeltodeterminewhichoftheDSMprogramsmaybeabletoprovidecapacityandenergybenefitsinexcessoftheircosts.AlleconomicDSMprogramswereincludedineachportfolio.36OncethelevelofeconomicDSMwasdeterminedwithineachscenario/portfoliocombination,theAURORACapacityExpansionModelwasusedtoidentifythemosteconomiclevelandtypeofsupplysideresourcesneededtomeetreliabilityrequirements.TheresultofthisprocesswasanoptimalportfolioforeachscenarioconsistingofbothDSMandsupplysidealternatives.Table10:PortfolioDesignMixPortfolioDesignMixIRPortfolioBBPortfolioDDPortfolioGSPortfolioDSMPrograms18Programs14Programs16Programs20ProgramsDSMMaximum(MWs)37497407539467CTs/CCGTs(MWs)7,3488,4046,8766,512Wind(MWs)0004,0003836InevaluatingtheeconomicsofDSMprograms,themodelevaluatesthecostandbenefitoftheDSMprograms,butdoesnottakeintoconsiderationratemakingandpolicyissuesimplicatedbyDSMprograms,whichmustbeappropriatelyaddressedaspartofDSMimplementation.37DemandSideManagement(DSM)totalisgrossedupforPlanningReserveMargin(12%)andtransmissionlosses(2.4%).38Windwaslimitedto20resourcesannuallyat200MWseach,whichprovides564MWofcapacitycreditbasedonMISOdeterminedwindcapacitycreditof14.1%.

31EachportfoliowasmodeledinAURORAandtestedinthefourscenariosdescribedearlierforatotalof16cases.TheresultsoftheAURORAsimulationswerecombinedwiththefixedcostsoftheincrementalresourceadditionstoyieldthetotalforwardrevenuerequirementsexcludingsunkcostsoftheportfolio.Thetotalforwardrevenuerequirementresultsandrankingsbyscenarioareprovidedinthefollowingtables.Table11:PVofForwardRevenueRequirementsbyScenario3940PVofForwardRevenueRequirements($B)(20152034)IRScenarioBBScenarioDDScenarioGSScenarioIndustrialRenaissancePortfolio$36.0$32.5$36.1$46.4BusinessBoomPortfolio$36.2$32.2$36.3$46.3DistributedDisruptionPortfolio$36.0$32.2$36.2$46.3GenerationShiftPortfolio$37.9$35.1$37.4$43.1Therevenuerequirementsshownaboveincludethetotalcosttoservetotalloadoverthe20yearplanningperiod.Itisimportanttonotethattherevenuerequirementsshownarereflectiveofthetotalfuelcostsandtheincrementalresourcecosttodelivertheportfoliosunderdifferentscenariosandarenotreflectiveofcustomerrateeffectsastheydonotconsiderchangesinloadandotherfactorsaffectingrates.Table12,below,breaksdowntheforwardrevenuerequirementsforeachportfoliointheIndustrialRenaissanceScenario(thefirstcolumnofTable11)intothecomponentcosts.Thepiechartsshowthepercentagesofincrementalfixed,variable,andDSMcostsofthetotalPVforwardrevenuerequirementsshowninTable11.39TheforwardrevenuerequirementsareintendedtoprovidethebestavailableestimateofoverallportfoliocostgiventhelongtermnatureoftheIRPprocessandthefactthatcustomerclassbillandrateeffectswillbedeterminedthroughcertificationproceedingsassociatedwithparticularresources.40ThetablereflectsthecorrectinputofnominalDSMprogramcostsasopposedtolevelizedDSMprogramcosts.

Table12:Thecolueachoft41Variable42Incremeeachportf43ThetablPortfoliosbymnsinTablhescenarioscostrepresenntalfixedcostolio.ereflectsthecyCostCompoe13,belows.tstheloadpayisthefixedcocorrectinputoonentsinthew,showtheymentnetofgostrevenuereqofnominalDSMIndustrialRerankingsofgenerationenequirementofthMprogramcostenaissanceScfeachoftheergymargins.heincrementatsasopposedcenario(2015efourmodealsupplysidertolevelizedDS52034)414243eledportfoliresourceadditiSMprogramco323iosinionsinosts.

33Table13:PortfolioRankingbyScenarioPortfolioRankingbyScenario(20152034)IRScenarioBBScenarioDDScenarioGSScenarioIndustrialRenaissancePortfolio131444BusinessBoomPortfolio314533DistributedDisruptionPortfolio2222GenerationShiftPortfolio4441Thenextstepwastoperformsensitivityanalysesoneachportfoliobyadjustingonevariableatatime46andcomputingthePVofforwardrevenuerequirements.Eachportfoliowastestedacrosstherangeofassumptionsfor: NaturalGasPrices CoalPrices CapitalCostforNewGeneration GeneralInflationandResultingCostofCapital CO2Costs NaturalGasPricesandCO2CostsCombinations44TotalsupplycostfortheIndustrialRenaissancePortfoliowaslowerthantheDistributedDisruptionPortfolio;however,thedifferencewasnotsignificant(0.3%)andthevariablesupplycostoftheDistributedDisruptionPortfoliowaslower.45AswithTables11and12above,thistablereflectsthecorrectinputofnominalDSMprogramcostsasopposedtolevelizedDSMprogramcosts.ThiscorrectionresultedintheBusinessBoomPortfoliohavingthelowesttotalsupplycostintheBusinessBoomScenario.46AcombinationofnaturalgaspricesandCO2costsinvolvedadjustmentoftwovariablesatthesametime.

TherangRenaissaTable14:geoftotalnceScenarioNaturalGasforwardroisprovidedSensitivityinrevenuereqdinthefollontheIndustriquirementsowingfivetaalRenaissancresultsbyables.ceScenarioportfoliointheIndu34ustrial Table15:Table16:CO2PriceSeNaturalGasensitivityinthandCO2ComheIndustrialmbinationSenRenaissancensitivityinthScenarioeIndustrialRRenaissanceSScenario35 Table17:Table18:CostofCapitInstalledCostalSensitivitystSensitivityyintheIndusintheInduststrialRenaisstrialRenaissasanceScenarianceScenarioioo36 37Resultsofthesensitivityassessmentsindicatethattheinstalledcost,costofcapital,andcoalprices47havelessofanimpactonthevariabilityoftotalforwardrevenuerequirementsresultsacrossallportfoliosincomparisontonaturalgasprices,CO2prices,andthecombinationofnaturalgaspriceandCO2price.TheIndustrialRenaissance,BusinessBoom,andDistributedDisruptionportfoliosaresimilarlysensitivetonaturalgasprices,CO2prices,andthecombinationofnaturalgasandCO2prices,whereastheGenerationShiftportfolioisrelativelylesssensitivetothesevariables.Conversely,theGenerationShiftportfolioismoresensitivetoinstalledcostandcostofcapitalascomparedtotheIndustrialRenaissance,BusinessBoom,andDistributedDisruptionportfolios.ThisisaresultoftheGenerationShiftportfolio'shigherincrementalfixedcostsrelativetotheotherthreeportfolios,whichisindicatedintheaccompanyingTable.Resultsofthesensitivityanalysisareconsistentwiththeresourcetypeandamountthatcompriseeachoftheportfolios.SummaryofFindingsandConclusionsResultsofthescenarioassessmentindicate: Supplysideeconomicswereconsistentwithtechnologyscreeninganalysis. SomelevelofDSMwaseconomic48ineveryscenario. Renewablesarenoteconomicundermostassumptions.RenewableresourcesdependonhighgasandcarbonpricestobeeconomicrelativetoCTandCCGTresources. CTandCCGTresourcesperformwellacrossmostscenarios.ThechoicebetweenCCGTandCTtechnologiesissensitivetoexternalfactorsasdemonstratedbythenarrowrangeofoutcomesfortheportfolioscomprisedprimarilyoftheseresources.47Coalpricesensitivityresultsarenotshowninthesensitivitychartsbecausecoalresourcesarenotaddedasanewresourcetoanyoftheportfoliosandtheexistingresourceportfolioonlyhasapproximately4%ofcoalresources.48Seenote32,supra.

38PART5:FINALREFERENCERESOURCEPLAN&ACTIONPLANFinalReferenceResourcePlanTheIRPprocessresultedintheidentificationofaFinalReferenceResourcePlanthatrepresentstheCompanies'bestavailablestrategyformeetingcustomers'longtermpowerneedsatthelowestreasonablesupplycost,whileconsideringreliabilityandrisk.TheFinalReferenceResourcePlanisbasedonthefollowingassumptions: TheindustrialrenaissanceunderwayinLouisiana,coupledwithresidentialandcommercialloadgrowth,isdrivingsignificantgrowthinutilityloadwithupto1,600MWofindustrialloadgrowthexpectedintheCompanies'serviceareasthrough2019.By2034,theCompaniesexpecttorequireatleast8,000MWofadditionalcapacitytomeetdemand. Forpurposesofplanningcapacity,theCompanieshaveassumptionsregardingthedeactivationofapproximately5,950MWofoldergasfiredsteamgeneratorsovertheplanningperiod.Thisagingfleetisincreasinglysusceptibletoaccelerateddeactivationasdecisionsaremaderegardinguniteconomicsassociatedwithunexpectedmaintenancecostsandongoingevaluationofunitavailability.Actualdecisionstocontinuetoinvestinandoperatetheseunitshavenotbeenmadeandwillbesubjecttoongoingassessmentsofeconomicsandtechnicalfeasibility. Inordertoreliablymeetthepowerneedsoftheirrespectivecustomersatthelowestreasonablecost,theCompanieswillmaintainaportfolioofgenerationresourcesthatincludestherightamountandtypesofcapacity.o Withrespecttotheamountofcapacity,theCompaniesmustmaintainsufficientgeneratingcapacitytomeettheirpeakloadsplusaplanningreservemargin.TheCompanieswillplanresourcestoa12%reservemargin.TheCompanieswillneedtoaddcapacityforthreereasons:1)tomeetloadgrowth;2)toreplaceexistingresourcesthatwillreachtheendoftheirusefullives(unitdeactivations);and3)toreplacePPAsthatwillexpire.o Withrespecttothetypeofcapacity,theCompaniesseektoaddmodern,efficientgeneratingcapacity,whichwillpredominantlybeCCGTSandCTs.

39 TheCompanieswillcontinuetomeetthebulkoftheirreliabilityrequirementswitheitherownedassetsorlongtermPPAs.Theemphasisonlongtermresourcesmitigatesexposuretocapacitypricevolatilityandensurestheavailabilityofresourcessufficienttomeetlongtermreliabilityneeds. Aportionofreliabilityrequirementsmaybemetthroughareasonablerelianceonlimitedtermpowerpurchaseproductsincludingzonalresourcecredits,totheextenttheseareeconomicallyavailablewhenconsideringrisk. SomelevelofDSMisconsideredeconomicallyattractivebutpresentsratemakingandpolicyissuesthatmustbeaddressedinconnectionwithadoptionsofsuchprograms.Avarietyoffactors,manyofwhicharehighlyuncertain,willaffecttheamountofDSMthatcanandwillbeachievedovertheplanninghorizon. Allexistingcoalandnuclearunitswillcontinueoperatingthroughouttheplanninghorizon.AllnuclearunitsareassumedtoreceivelicenseextensionsfromtheNuclearRegulatoryCommission("NRC")tooperateupto60years. Newbuildcapacity,whenneededin2020andbeyond,comesfromacombinationofCTandCCGTresources.Newbuildcapacitymaybeobtainedthroughownedresourcesorlongtermpowerpurchasecontracts.ForthepurposeofpreparingtheIRP,theeconomicswereassumedtobeequivalent. Nonewsolidfuelcapacityisadded,andnewnucleardevelopmentremainsinthemonitoringphase. Renewableresourcesarenoteconomicallyattractiverelativetoconventionalgasturbinetechnology(whetherinsimpleorcombinedcycle)assolelyacapacityresource.However,renewablecostandperformance-inparticular,solar-continuestoimproveasasourceofzeroemissiongeneration.Duetopotentialstateandfederalincentives,potentialenvironmentalrequirements,andasgeneralcostandtechnologyperformanceimprove,itisconceivablethattheCompaniesandtheircustomerscouldincorporatesolarorotherintermittent,renewableresourcesatdistributedorutilityscalemagnitude.Thesepossibilitieswarrantfurtheranalysis.TheFinalReferenceResourcePlanshowninTable19includesassumptionsregardingfuturemajorresourceadditions,suchastheUnionPoweracquisition,the2020AmiteSouthCCGT, 402020WOTABCTs,andthe202021WOTABCCGT,aswellasassumptionsregardingimplementationofcosteffectiveDSMprograms.Theactualresourcesdeployed(includingtheamountandtimingoftechnologyandpowerpurchaseproducts)andDSMimplemented,willdependonfactorswhichmaydifferfromassumptionsusedinthedevelopmentoftheIRP.Suchlongtermuncertaintiesinclude,butarenotlimitedto: Loadgrowth(magnitudeandtiming),whichwilldetermineactualresourceneeds Therelativeeconomicsofalternativetechnologies,whichmaychangeovertime Environmentalcompliancerequirements Practicalconsiderationsthatmayconstraintheabilitytodeployresourcealternativessuchastheavailabilityofadequatesourcesofcapitalatreasonablecost ConditionofexistingunitsandongoingassessmentsofthoseunitsTherearetwoimportantpointstoconsiderwhenreviewingtheFinalReferenceResourcePlan.First,thedecisiontoprocureagivenresourcewillbecontingentuponareviewofavailablealternativesatthattime,includingtheeconomicsofanyviabletransmissionalternativesavailablethatwouldbecoupledwithapurchaseofcapacityand/orenergy.Inaddition,thedecisiontoprocureaspecificresourceinaspecificlocationmustreflectthespecificleadtimeforthattypeofresource,whichwillvarybyresourcetype,andthetimerequiredforobtainingregulatoryapprovals.Bydeferringspecificresourcedecisionsuntildeploymentisneeded,theCompaniesretaintheflexibilitytorespondtochangesincircumstanceuptothetimethatacommitmentismade.Second,avarietyoffactors,manyofwhicharehighlyuncertain,willaffecttheamountofDSMthatcanandwillbeimplementedovertheplanninghorizon.DSMassumptions,includingthelevelofcosteffectiveDSMidentifiedthroughtheIRPprocess,arenotintendedasdefinitivecommitmentstoparticularprograms,programlevelsorprogramtiming.TheimplementationofcosteffectiveDSMrequiresconsistent,sustainedregulatorysupportandapproval.TheCompanies'investmentinDSMmustbesupportedbyareasonableopportunitytotimelyrecoverallofthecosts,includinglostcontributiontofixedcost,associatedwiththoseprograms.ItisimportantthatappropriatemechanismsbeputintoplacetoensuretheDSMpotentialactuallyaccruestothebenefitofcustomersandthatutilityinvestorsareadequatelycompensatedfortheirinvestmentthroughopportunitytoearnperformancebasedincentives.

41Table19:FinalReferenceResourcePlanLoad&Capability20152034(AllvaluesinMW)Load&Capability2015-203420152016201720182019202020212022202320242025202620272028202920302031203220332034RequirementsPeakLoad9,86910,08110,49510,89611,17211,09011,16211,23111,30311,37611,45211,52611,59911,67211,74311,81111,88211,95212,02412,095ReserveMargin(12%)1,1841,2101,2591,3071,3411,3311,3391,3481,3561,3651,3741,3831,3921,4011,4091,4171,4261,4341,4431,451TotalRequirements4911,05311,29011,75412,20312,51312,42112,50212,57812,65912,74112,82612,90912,99113,07313,15213,22913,30813,38713,46613,546ResourcesExistingResourcesOwnedResources5096529549954988268826881488148688868886888688827776167616709565285571441937023702PPAContracts909909866386386386386144144144144144144144144144399LMRs308308308308308308308308308308308308308308308308308308308308IdentifiedPlannedResourcesUnion51816816816816816816816816816816816816816816816816816816816AmiteSouthCCGT52560560560560560560560560560560560560560560560OtherPlannedResourcesDSM53194477105151220266299329334403413414471457532539423456538CTs(2)388388388388388388388388388388388388388388388CCGT1764764764764764764764764764764764764764764764CCGT2764764764764764764764764CCGT3764764764764764764764CCGT4764764764764764764CCGT5764764764764764CCGT6764764764764CCGT7764764CCGT8764MarketPurchase1651381,7622,0261652006116637397551,2391,2184783281335031,8811,8891,122TotalResources11,05311,62511,75412,20312,51312,42112,50212,57812,65912,74112,82612,90912,99113,07313,15213,22913,30813,38713,46613,54649Totalloadrequirementadjustsforthepeakloaddiversitybetweenthetwocompanies.50TheJSPPPAsareincludedintheOwnedResourcesrow.51Unionplantacquisitioniscompletedpendingregulatoryapprovals.816MWistwotrainsofthefacilityless20%allocationtoENO.Givenchangestotheownershipoftheothertrains,itisexpectedthatEGSLwillretain100%ofitstwotrains.52ELL/EGSLshareofAmiteSouthRFPispresentlyestimatedat560MW.RFPresponsesarecurrentlybeingevaluated;actualcapacityofselectedresourcecouldrangebetween650to1,000MWandaportionofthatcapacitymaybesharedwithanotherEntergyoperatingcompany.Asaresult,actualcapacitymayexceed560MW.Givenchangestotheownershipoftheothertrains,itisexpectedthatELL/EGSLwillretain100%oftheresourceselectedthroughthisRFP.53DemandSideManagement(DSM)totalisgrossedupforPlanningReserveMargin(12%)andtransmissionlosses(2.4%).

42ActionPlanTheCompanieshavedevelopedthefollowingActionPlanforpursuingtheFinalReferenceResourcePlandescribedaboveoverthefirstfiveyearsoftheplanningperiod.TheActionPlanrecognizesthattherearenumerousuncertaintiesthatwillbeencounteredoverthe20yearIRPperiod,theoutcomeofwhichwillsignificantlyinfluencetheresultingsupplyportfolio.Table20:ActionPlanCategoryItemActiontobetakenSupplySideAlternativesUnionAcquisition ObtainregulatoryapprovalandcompletetheacquisitionofPowerBlocks3and4oftheUnionPlantnearElDorado,Arkansas.Netofa20%PPAtoENO,UnionPlantwouldaddapproximately816MWstotheCompanies'currentcapacityin2016;however,givenchangestotheownershipoftheotherUnionPowerunits,itisexpectedthatEGSLwillretain100%ofitstwotrains.Renewables Theenergyandcapacityperformanceofutilityscaleintermittentresourcesandlocationalimpactsondistributionfeedersofdistributedrenewablesattheresidentialorsmallutilityscalewillneedtobedeterminedtoreliablyandeconomicallyincorporatetheseresourcesovertime.Longterminvestmentsinthesystemoperationsandutilitydistributioninfrastructuremightberequiredtoreliablyinterconnectthesetechnologiesatalargescale.TheCompanieswillevaluatedistributedpilotprojects(<5MW)forsolarandstoragetechnologyinordertoassessenergyandcapacitybasedplantperformance,verifyforecastintegrationofintermittentrenewablesforsystemreliability,andevaluatedistributedsolarPVlocationalimpactsandeconomicsondistributionfeeders.LegacyFleet Evaluatecostsandbenefitsofinvestinginexistingresourcesinordertosupportsafe,reliableoperationbeyondthecurrentlyassumeddeactivationdates.

43PPAs EvaluatecostsandbenefitsofPPAsasviablealternativestomeetlongtermneeds.NewResources ContinuetoassessthedevelopmentofaCToption(approximately380MWs)thatcouldbedeployedintheLakeCharlesareain2020tomeettheindustrialloadgrowthexpectedinthatarea;however,thetimingofthisresourceisuncertainandsubjecttochangebasedonchangesinloadadditions,implementationofothersupplyadditions,andchangesintransmissiontopography. InQ32015,fileanapplicationandsupportingtestimonywiththeCommissionseekingcertificationfortheSt.CharlesPowerStationselfbuildCCGTresourceselectedthroughthe2014AmiteSouthRFP.Completethecertificationprocessinordertosupportaninservicedateby2020. InSeptember2015,issuetheWOTABRFPtosolicitproposalsforanewCCGTfacility(approximately8001000MWs)intheLakeCharlesareaby2020tomaintainreliableandeconomicservicetocustomersgiventheindustrialloadgrowth,PPAexpirationsandterminations,andanticipatedunitdeactivationsexpectedinthatarea.ObtaincertificationforanyresourceselectedthroughtheRFPinordertofacilitateaninservicedateby2020. ContinuetoassessdevelopmentofadditionaloptionsforCTadditionsintheAmiteSouthandWOTABareasthatcouldbedeployedquicklyifloadgrowthishigherthanexpectedand/orsupplyalternativesarenotcompletedasplanned.GasSupply Exploreopportunitiesforlongtermgassuppliesthatcouldmitigatepricevolatilityand/orreducethecostofgasrelativetofuturemarketconditions.DemandSideDSMandEnergyEfficiency EvaluatetheresultsoftheQuickStartEnergyEfficiencyprogramsinLouisiana.

44AlternativesPrograms WorkwithregulatorstodeveloprulesthatwouldprovideaframeworkforimplementingcosteffectiveDSMprogramsbeyondtheQuickStartphaseandprovideappropriatecostrecovery.

Rev.1-April2015APPENDIXA:ELL&EGSLGENERATIONRESOURCESGeneratingAssetsOwnedorControlledbyELLasof1/1/15PlantUnitMegawattCapabilityFuelCODRegionANO123Nuclear12/19/1974NorthANO227Nuclear3/25/1980NorthAcadia2367Gas7/3/2002WOTABBuras812Gas1/30/1971DSGGrandGulf209Nuclear7/1/1985CentralIndependence17Coal1/18/1983NorthLittleGypsy2411Gas4/18/1966AmiteSouthLittleGypsy3520Gas3/21/1969AmiteSouthNinemilePoint3103Gas11/5/1955DSGNinemilePoint4699Gas5/1/1971DSGNinemilePoint5717Gas6/12/1973DSGNinemilePoint6308Gas12/24/2014DSGPerryville1133Gas7/1/2002CentralPerryville236Gas7/1/2001CentralSterlington7126Gas1/1/1986CentralRiverbend1195Nuclear1/1/1986CentralWaterford1411Gas6/27/1974AmiteSouthWaterford2411Gas9/13/1975AmiteSouthWaterford31,156Nuclear9/24/1985AmiteSouthWaterford433Oil9/24/1985AmiteSouthWhiteBluff113Coal8/22/1980NorthWhiteBluff212Coal7/23/1981NorthTotalOwned5,929UnaffiliatedPPAs605TotalCapacity6,534

Rev.1-April2015GeneratingAssetsOwnedorControlledbyEGSLasof1/1/15PlantUnitMegawattCapabilityFuelCODRegionAcadia2184Gas7/3/2002WOTABBigCajun23146Coal1/1/1983CentralCalcasieu182Gas5/30/2000WOTABCalcasieu291Gas5/1/2001WOTABLewisCreek1133Gas12/1/1970WOTABLewisCreek2132Gas5/1/1971WOTABNinemilePoint6140Gas12/24/2014DSGOuachita3241Gas8/1/2002CentralPerryville1228Gas7/1/2002CentralPerryville263Gas7/1/2001CentralRoyNelson4244Gas7/1/1970WOTABRoyNelson6222Coal5/1/1982WOTABRiverbend1389Nuclear1/1/1986CentralSabine1122Gas3/1/1962WOTABSabine2122Gas12/1/1962WOTABSabine3228Gas11/1/1964WOTABSabine4306Gas8/1/1974WOTABSabine5270Gas12/1/1979WOTABWillowGlen2104Gas1/1/1962CentralWillowGlen4276Gas7/1/1973CentralTotalOwned3,723UnaffiliatedPPAs304TotalCapacity4,027

1APPENDIXB:ACTUALHISTORICLOADANDLOADFORECASTHistoricPeakDemandandEnergy1Table1:HistoricTotalAnnualEnergy(MWh)ELLEGSL200429,718,03121,149,604200528,303,40520,541,702200629,080,98720,732,221200729,773,35420,964,467200829,198,10721,537,359200929,894,16921,395,660201032,085,69222,224,858201133,164,85921,531,721201232,989,32721,074,484201333,456,57821,400,699201433,859,48222,460,701Table2:HistoricTotalMonthlyEnergy(MWh)2Month/YearELLEGSL01/20042,311,5371,601,02802/20042,136,7171,524,44203/20042,164,8321,577,64504/20042,176,8311,593,90305/20042,596,8351,781,54806/20042,741,2391,864,53107/20042,932,7802,024,93908/20042,881,2982,012,44609/20042,593,5131,862,49110/20042,624,0311,996,07511/20042,168,0181,596,35512/20042,390,4001,714,20101/20052,255,8831,672,99702/20052,031,0111,453,53003/20052,235,8181,548,04504/20052,261,1621,553,19705/20052,559,3311,784,56906/20052,769,7851,904,1941Actualsarenotavailableforrevenueclasses.2DataforNovemberandDecember2014ispreliminaryandsubjecttochange.

207/20052,906,9552,008,77708/20052,834,5342,037,84909/20052,087,8421,806,26310/20052,211,1311,597,88311/20052,001,8501,554,43012/20052,148,1031,619,96801/20062,033,1441,556,82102/20061,980,6521,385,55403/20062,117,9341,571,04304/20062,221,6531,653,72605/20062,537,2311,816,74006/20062,789,7371,940,44307/20062,875,9962,023,79508/20062,997,5002,097,95509/20062,646,6581,873,17610/20062,398,8571,677,93411/20062,169,8481,527,10212/20062,311,7771,607,93201/20072,371,6781,703,01202/20072,162,6701,500,58803/20072,221,5301,601,05704/20072,190,6941,608,71505/20072,492,5261,913,33006/20072,734,5521,902,83007/20072,816,8531,938,45108/20073,099,3292,107,73709/20072,697,9471,876,64210/20072,455,8561,687,02011/20072,170,8031,521,49012/20072,358,9171,603,59501/20082,432,1391,852,72002/20082,118,9601,603,29503/20082,236,8311,690,72804/20082,291,8411,668,17705/20082,626,7171,954,25306/20082,786,2552,080,00707/20082,995,9362,259,71408/20082,842,5962,158,30809/20082,078,5461,467,91710/20082,350,7521,750,56411/20082,144,4271,474,22212/20082,293,1081,577,453 301/20092,343,8831,690,18402/20091,985,9911,411,60103/20092,172,2801,587,72704/20092,298,9411,572,65805/20092,616,1821,823,80006/20092,837,2462,124,41007/20092,963,5902,173,59008/20092,891,4592,215,59709/20092,685,8991,907,62910/20092,461,3161,735,89011/20092,201,4311,478,59912/20092,435,9511,673,97501/20102,623,1871,759,16402/20102,276,5651,646,24803/20102,342,8631,666,68104/20102,336,7781,679,50905/20102,832,8782,025,87206/20103,032,2882,129,33407/20103,106,0972,091,79908/20103,161,0692,140,42909/20102,921,6621,993,04610/20102,554,8471,760,97311/20102,300,9711,596,12112/20102,596,4861,735,68201/20112,653,7981,740,26102/20112,412,0601,562,61903/20112,407,8981,614,15804/20112,508,9471,740,57905/20112,794,6261,909,37306/20113,089,5842,021,02207/20113,248,0032,079,77408/20113,488,0512,185,17109/20112,874,9911,793,41010/20112,579,2221,649,35111/20112,410,0481,600,38612/20112,697,6291,635,61601/20122,531,1351,608,97702/20122,412,0941,454,68703/20122,593,0421,631,73804/20122,574,4521,696,10505/20122,982,0021,957,034 406/20123,111,3401,922,59007/20123,245,9962,024,52508/20122,991,9512,024,34309/20122,841,4001,832,74310/20122,639,3421,735,54711/20122,404,1111,525,23412/20122,662,4631,660,96101/20132,746,1761,615,50402/20132,340,0101,461,94503/20132,549,9991,631,89804/20132,510,5501,673,46505/20132,846,7031,817,89606/20133,105,0512,006,77807/20133,111,8862,049,35708/20133,307,4592,106,36609/20133,056,7611,938,44810/20132,539,6171,741,51311/20132,513,9831,609,73212/20132,828,3811,747,79501/20142,918,3731,861,03202/20142,457,1011,626,95603/20142,558,3741,752,51404/20142,533,2371,707,60005/20142,810,8571,892,23706/20143,067,2302,073,05407/20143,237,3042,077,90908/20143,265,7192,170,38309/20143,008,2221,997,18310/20142,745,6331,841,00011/20142,567,0311,721,72712/20142,690,4011,739,106

5Table3:HistoricTotalSummer&WinterPeaks(MW)3ELLEGSLWinter200444,6363,119Summer20045,0913,555Winter20054,9433,314Summer20055,2363,583Winter20064,5503,311Summer20065,2573,639Winter20074,3953,383Summer20075,3413,676Winter20084,6533,609Summer20085,2343,912Winter20094,5583,256Summer20095,2524,046Winter20105,0603,496Summer20105,4923,747Winter20115,1743,400Summer20115,7663,787Winter20125,3433,412Summer20125,7063,694Winter20135,0453,386Summer20135,7733,776Winter20145,3823,459Summer20145,5183,752

3SummerisdefinedasJuneNovember.WinterisdefinedasDecemberMay.4Winter2004isdefinedasJanuary2004May2004.

6LoadForecastTable4:EGSLMonthlyEnergyForecast(GWh),IndustrialRenaissanceCase 7

8 9

10 11 12Table5:ELLRetailMonthlyEnergyForecast(GWh),IndustrialRenaissanceCase 13 14 15 16 17 18Table6:ForecastedRetailSummer&WinterPeaks(MWs)5ELLEGSLWinter20155,2943,666Summer20155,8633,861Winter20165,3823,766Summer20165,9503,983Winter20175,5483,933Summer20176,1154,232Winter20185,6194,345Summer20186,1744,567Winter20195,7524,501Summer20196,2924,723Winter20205,7844,372Summer20206,3324,601Winter20215,8284,402Summer20216,3724,630Winter20225,8694,428Summer20226,4134,658Winter20235,9094,455Summer20236,4564,688Winter20245,9504,484Summer20246,4924,719Winter20255,9904,515Summer20256,5324,752Winter20266,0294,544Summer20266,5744,785Winter20276,0694,573Summer20276,6144,816Winter20286,1084,601Summer20286,6594,847Winter20296,1464,628Summer20296,6934,877Winter20306,1854,655Summer20306,7324,905Winter20316,2234,683Summer20316,7714,935Winter20326,2614,710Summer20326,8104,965Winter20336,2994,738Summer20336,8514,9955Summerandwintercoincidentpeakdemandsforeachcustomerclassarenotdeveloped.

19Winter20346,3374,766Summer20346,8935,026Table7:ForecastedLoadFactorsELLEGSL201569%69%201670%70%201770%72%201870%76%201971%78%202071%76%202171%76%202271%77%202371%77%202471%77%202571%77%202671%77%202771%77%202871%77%202971%77%203071%77%203171%77%203271%77%203371%77%203471%77%

Page1of16APPENDIXC:RESPONSETOSTAKEHOLDERCOMMENTSGeneralCommentResponse(January2015)StaffProviderationaleforselectionoftheproxygeneratingunitusedfortheprojectedlongtermcapacitypricesanddescribehowthatcomparestoothermarketcapacitypricesforMISORTOMISOdoesnothaveprojectedlongtermcapacityprices;onlyannualmarketcapacitypricesaredeveloped.Forlongtermplanning,aCTisusedastheproxygeneratingunitforprojectedlongtermcapacitypricesasitisthelowestcostsourceofcapacity.StaffIdentifyunitsselectedfordeactivationandreasonfordeactivationandwhenForthepurposeofdevelopingthisIRP,assumptionsmustbemadeaboutthefutureofgeneratingunitscurrentlyintheCompanies'portfolio.AssumptionsmadefortheIRParenotfinaldecisionsregardingthefutureinvestmentinresources.Unitspecificportfoliodecisionssuchas,sustainabilityinvestments,environmentalcomplianceinvestments,orunitretirements,arebasedoneconomicandtechnicalevaluationsconsideringsuchfactorsasprojectedforwardcosts,anticipatedoperatingroles,andthecostofsupplyalternatives.Thesefactorsaredynamic,andasaresult,actualdecisionsmaydifferfromplanningassumptionsasgreatercertaintyisgainedregardingrequirementsoflegislation,regulation,andrelativeeconomics.Basedoncurrentassumptions,anumberoftheCompanies'existingfossilgeneratingunitsmaybedeactivatedduringtheIRPplanningperiod.Intheyears20152034,thetotalassumedreductionintheCompanies'generatingcapacityfromtheseunitdeactivationsandPPAterminationsisapproximately6,100MW,whichconsiderstheadditionofNinemilePoint6,relativetotheCompanies'currentcombinedresourcesofapproximately10,915MW.SierraClubNotclear"howtheCompanywillmodelthepossibleretirementofexistingcoalresources.Moreover,itappearsEntergyhasignoredthepossibilityofretiringanyofitscoalfiredfacilities."ThroughouttheplanningperiodallEntergycoalunitsareassumedtocontinuetooperate.Theseunitswillcontinuetooperateaslongasitiseconomictodoso.

Page2of16StaffIdentifyanddescribefutureknownand/orplannedchangesincapacity,availability,etc.Therearenoknownfutureand/orplannedchangesinthecapacityandtheavailabilityofexistingresources.StaffIdentifyanddescribenewresourcesthecompanyplanstobuildoracquire,includingthoseplannedforWOTABtransmissionregion.AsdescribedintheActionPlan,EGSLisintheprocessofobtainingregulatoryapprovaltoacquiretwounitsoftheUnionPlantnearElDorado,Arkansas.Thisacquisitionwouldaddapproximately816MWsnetofa20%PPAtoENOtotheCompanies'currentcapacity.Similarly,theCompaniesarecurrentlyconductingtheAmiteSouthRFPtoobtainanewCCGTby2020.StaffIdentifyanddescribefutureknownand/orplannedchangesintransmissioncapacity,includingnewlinesandupgrades,andeffectonnewresources.ThisinformationisavailableundertheTransmissionPlanningSectionintheIRP.SpecificdetailsaboutfuturechangesintransmissionisinAppendixA.SierraClubDisclosehowELLandEGSLwillaffectresourceplansAspartoftheIRP,anActionPlanwasdevelopedthatdescribestheCompaniesplanforspecificresourcesatcertaintimes.SWEARecommendsthatdataassumptionsregardingO&MonlyusefixedO&Mcosts,insteadoffixedandvariableO&Mcoststogether.AllrelevantcostsareincludedintheIRP,whichincludesbothfixedandvariableO&M.TheIRPisdevelopedfromacustomerperspective.Thatis,theCompanies'planningprocessseekstodesignaportfolioofresourcesthatreliablymeetscustomerpowerneedsatareasonablecostwhileconsideringrisk,whichiswhyitisnecessarytoincludevariableO&Mcosts.SWEADataassumptionsshouldincludegreatertransparencyandcitationsoallstakeholderscanconductdataqualitycontrol.AllinputassumptionswerefiledwiththeLPSCthroughaseriesoffilingsin2014,withthemostrecentinOctober.SierraClubEntergyshould"treatdistributedgenerationlikeanyotheravailableresourceandpursuingprogramsthatareavailableandbeneficialtoratepayers."Theeffectofdistributedgenerationisaccountedforintheloadforecast.Currently,thisisthebestavailablemethodtoaccountfordistributedgenerationgivenitsnondispatchablenature.

Page3of16CommentonDraftIRPReportResponse(August2015)AllianceforAffordableEnergy-WereupgradecostsfornuclearmodeledinAURORAorwerenewnuclearcostsmodeled?Upgradecostsfornuclearwerenotmodeled.NewnuclearwasevaluatedinthescreeninglevelanalysisphaseoftheTechnologyAssessmentandfoundtobeaviabletechnology,butwasnotselectedbyAURORAasacostcompetitiveresourceinthedetailedanalysisphase.AllianceforAffordableEnergy-WasgenerationfromtheUnionPowerStationincludedinthemodelingorafterthemodelingwascomplete?UnionPowerStationwasincludedintheAURORAmodelingasaresource.AllianceforAffordableEnergy-Pleaseexplainthematchupfeeusedinconnectionwithwindresources.The"matchup"reflectsthefactthatwindreceivespartialcapacityvalueinMISOduetowind'sintermittentnature.Thecapacitymatchupfeewasonlyappliedintheinitialscreeninganalysisphaseofsupplysideresourcesinthetechnologyassessment.OnceitwasselectedforfurtheranalysisandmodelinginAURORA,windwasevaluatedrelativetootherresourceswithoutthecapacitymatchupfeeadded.LEUG-Explaintheprocessbywhichthecompaniescontinuetoevaluateunitdeactivations.ForthepurposeofdevelopingtheIRP,assumptionsaremadeaboutthefutureoftheunitsinthecurrentportfolio.Unitspecificportfoliodecisionssuchassustainabilityinvestments,environmentalcomplianceinvestments,orunitretirementsarebasedoneconomicandtechnicalevaluationsconsideringsuchfactorsasprojectedforwardcosts,anticipatedoperatingroles,andthecostofsupplyalternatives.IntheIRP,atotalassumednetreductionintheCompanies'generatingcapacityfromunitdeactivationsandPPAterminationsisapproximately6,100MWovertheplanninghorizon.ThisassumptionhasnotchangedsincetheNovember3,2014Inputsfiling.LEUG-Provideadditionalinformationontheprocessforevaluationofnewtransmissionoptionstoensurelowestreasonablecosts.Transmissionaloneisnotanalternativetogeneration,butrathertransmissioninconjunctionwithgenerationallowscustomerstobeservedreliablyandeconomically.TheCompaniesandotherloadservingentitiesinMISOarerequiredtoprovidegenerationcapacityequaltotheirloadobligationplusaMISOdeterminedreservemargintocomplywithMISOResourceAdequacyrequirements.Therefore,whentheCompaniesneedtoaddanewgeneratingunit,thelocationischosentobestmeettheplanningobjectives Page4of16basedonconsiderationoffactorsneededtosupportnewgenerationincluding,butnotlimitedtofuelsupply,transmission,watersupply,environmentalpermitting,andproximitytoload.ThisprocessconsidersbothgenerationandtransmissionandallowstheCompaniestomeettheplanningobjectivesofservingitscustomersreliablyatthelowestreasonablecostwhileconsideringrisk.Staff-DiscusswhetherthereareanyeconomicopportunitiestoincludeCHPintheportfolioandreduceneedforothercapacityrelatedcapitalexpendituresTheCompanies'favorablecommercialandindustrialratesmakesCHPdeploymentuneconomicformostexistingcustomersexceptthosewithover20MWofloadthatalsohaveanoperationalneedforprocesssteam.EvenifCHPiseconomic,manyindustrialcustomersprefertoutilizetheCompanies'reliableandcompetitivelypricedelectricalpowerratherthancommittheirlimitedcapitalresourcestoconstructingtheirownpowergenerationprojectsthathaveamidtolongtermpaybackandareanoncorebusiness.Thisisverymuchthecasewhentheindustrialcustomer'scostofelectricityissmallcomparedtoitstotalcostofdoingbusiness.TheconsiderableamountofindustrialCHPalreadyconnectedtotheCompanies'electricalgridindicatesthatthebaseofexistingindustrialcustomersforwhomthattechnologymakeseconomicsensehavealreadyelectedtodeployCHP.Staff-RegardingActionPlan,provideinformationontimelinesforacquiringtheNewResourcesdiscussedaswellasanyreasonswhycompetitivesolicitationmightnotbeused.AdditionalinformationregardingtimelineshasbeenprovidedintheActionPlaninthereport.Staff-ExplainwhetheranalysishasbeenperformedtodetermineifitwouldbebeneficialtoEGSLcustomersforJSPPPAstoremainineffectandhowthatwouldaffecttheReferencePlan.BecauseLPSCConsolidatedOrderNos.U21453,U20925andU22092(SubdocketJ)requirestheterminationofthesePPAsuponremovaloftheJSPPPAresourcesfromEntergySystemdispatch,suchanalysishasnotbeenperformedindevelopingtheCompanies'IRP.Ingeneral,theterminationoftheJSPPPAswouldcauseEGSL,onanetbasis,toloseapproximately700MWofcapacityfromlegacygasgenerationresources.ThisassumptionisreflectedintheReferencePlan.ThereisnobasistoassumeadifferentoutcomegiventheLPSCOrder.

Page5of16LoadCommentResponse(January2015)StaffIdentifyanddescribeknownoranticipatedmajorloadadditionsLoadadditionsincludeindividualcustomerinformation,whichisconfidential.StaffAddresshowpriceelasticityincorporatedinprojectedpeakloadsandenergy,andhowthiseffectsresourceportfolioPriceelasticityisaninputintotheenergyforecastingmodels.Thepeakloadforecastusestheoutputfromtheenergymodelsasaninputsotheimpactsofpriceelasticityindirectlyinfluencethepeakload.Resourceportfoliosarethendevelopedaftertheloadforecastiscomplete.CommentonDraftIRPReportResponse(August2015)StaffHowdidactualloadcomparetotheloadforecastintheCompanies'2012IRPfilings?Thefollowingtableprovidesacomparisonofactualannualenergysales,orcumulativehourlyload,tothe2012IRPforecast.Staff-Addamoredetaileddescriptionoftheassumptionsusedtodeveloptheloadforecastanddistributedgeneration.Rooftopsolar'sforecastedgrowthisbasedona12monthaverageofinstallationratesandaveragesystemsize.Nospecificadditionalgrowthisassumedafter2017duetotheexpirationofinvestmenttaxcredits;however,growthinsolaralongwithotheritemsisembeddedinthereductionofsaleswithinorganicenergyefficiencyassumptions.Staff-AddamoreInanefforttoavoidlongtermresourceshortages,projectswithintheCompanies'EconomicDevelopmentpipelinewereaddedtotheforecast.InAmountsinGWh201220132014201220132014IRPForecast119,29819,65919,92531,37332,13032,482WeatherAdjustment1244887178142275NonWeatherAdjustedActuals19,58119,66320,82331,71032,22032,905ForecastError%1.5%0.0%4.5%1.1%0.3%1.3%WeatherAdjustedError%2.1%0.3%4.1%1.6%0.7%0.5%1FinalRetailForecastfromthe2012IRPBaseCase;AssumesnormalweatherEGSLELL Page6of16detaileddescriptionoftheassumptionsusedtodeveloptheloadforecast,includingmajorloadadditions.recognitionoftheuncertaintyinherentinforecastingnewload,theaddedprojectswereriskadjustedtoreflectaninternallyassignedprobabilityofthenewcustomercompletingthependingproject.Forexample,assumethatcustomerABChasinformedEntergyofanew80MWprojectbeingconsideredinEntergy'sserviceterritory.Baseduponconversationswiththecustomerandpreviousexperiences,theCompanies'AccountManagerassignedaprobabilityof50%tothisprojectbeingcompleted.Thus,theloadforecastwouldassumea40MW(80MWx50%=40MW)projectisadded.ProjectsforwhichthecustomerhasexecutedanelectricserviceagreementarenotriskadjustedandwouldbeincludedintheloadforecastatthefullprojectedMWload.Alargeindustrialadditionofapproximately10MWwasalsoincludedinLouisianatoaccountforprojectsthathadnotbeenexplicitlyidentified.

Thecapacityofthelargeindustrialloadadditionsassumedintheforecastisidentifiedinthechartbelow.AllianceforAffordableEnergy-DoesweatherforecastingusedbySPOandMetrixusehistoricdataorclimateimpactedprojections?Historicdataisusedintheweatherforecasting.

Page7of16FuelInputsCommentResponse(January2015)StaffUseconsistentassumptionsforcoalpriceinput.Iftherearediscrepanciesbetweenplants,explain.TheDeliveredPlantCoalPricesweredevelopedusingtwodifferentmethodologies:EntergyOperatingCompany("EOC")andMarketPlants.TheSPODeliveredtoEOCUnitsCoalPriceForecastisalongtermdeliveredpriceforecastcreatedfromconsultantcommoditypriceforecast,forecastedburn,transportationcosts,andcontractinformation.ThedeliveredpricesforMarketResourceswerederivedfromaconsultantforecast.DifferentplantsmayhaveDeliveredCoalPriceForecastsbecauseofdifferencesinthetimingandvolumesforcommodityandtransportationcontracts.Moreover,itisexpectedthatvariousscenarioshavedifferentcoalpriceinputsasaresultofdifferentfuelassumptions(e.g.,low,reference,andhigh).SierraClubAssumptionsarebiasedtowardsnaturalgas,insteadoflowercostoptions;Entergyshouldconsidera"gaspricevolatilityadder"toreflectriskofpricefluctuationThesensitivityanalysisconductedintheIRPevaluatedarangeofnaturalgaspricesacrosseachscenariotocapturetheriskrelatedtofluctuatingnaturalgasprices.MISOCommentResponse(January2015)EntegraCoordinatewithMISOongenerationunitretirementassumptionsandtransmissionstudies(e.g.forAmiteSouthandWOTABareas)

ThereareestablishedproceduresfortheCompanies'workwithMISO,whichisbeyondthescopeoftheIRPprocess.EntegraPerformatransmissiontopologysensitivityanalysisofitspreliminaryIRPresultsonceMISOmakesrecommendationsLouisianaEnergyUsersGroupCoordinatewithMISOongenerationunitretirementassumptionsand Page8of16transmissionprojects(e.g.,AmiteSouthandWOTAB)LouisianaEnergyUsersGroupCompareAURORAmodelingtoMISOrecommendations;performatransmissiontopologysensitivityanalysisEnergyEfficiencyCommentResponse(January2015)AllianceforAffordableEnergyDSMbenefitsshouldincludeindirectutilitysystembenefitsresultingfromlowercapacityandenergyloads,reducedreserverequirements,marginallinelossesinsteadofaverage,andavoidedT&Dexpenses.

AspartoftheIRPprocess,theCompaniesengagedICFtoprepareademandsidemanagementpotentialstudyforuseintheIRP.ThestudywasfiledinOctober.AllprogramsthathadaTRCratioof1.0orgreaterwereevaluatedintheAURORAMarketModelbeforeconsiderationofsupplysideresourceoptions.SoutheastEnergyEfficiencyAlliance("SEEA")NeedtodiscloseassumptionsforcostandavailabilityofenergyefficiencyforDSM("DemandSideManagement")study-suchasdirectsavingsfrominstalledmeasuresandsystembenefits,lowercapacityandenergyloads,reducedreservesrequirements,reductioninmarginallinelosses,andavoidedtransmissionanddistributionexpensesSEEAEnergyefficiency"isnotonlyaleastcostresource,butalsoamechanismfordeferringadditionalsupplysidegeneration,avoidingnewtransmissionanddistributioninfrastructure,andbufferingagainstcompliancecostsfromfutureenvironmentalregulations."

Page9of16SierraClubTreatenergyefficiencyasaresource,orparwithsupplysideresources.SierraClub-EnergyEfficiencyshouldbeaccountedasaresource.SierraClubModeldistributedgenerationandenergyefficiencyassupplyrideresources.IntheIRP,distributedgenerationisaccountedforintheloadforecastfortheCompanies.Moreover,energyefficiencyisevaluatedasaresourcealternativeintheIRP.CommentsontheDraftIRPReportResponse(August2015)AllianceforAffordableEnergy-ICFmodeledthreecasesbasedonincentivelevel.WhichoneofthesecaseswasmodeledinAURORA?Theincentivelevelvariedbyprogram.TheincentivelevelwiththehighestTRCratioforeachprogramwasselectedtobemodeledinAURORA.Assuch,theincentivelevelvariedforeachprogram.However,thereferenceprogramtendedtohavethehighestTRCratioformostprograms.AllianceforAffordableEnergy-Whydidn'tICFincludeENOinthebenchmarkingdata?ENOandtheELL/EGSLserviceterritorieshavesignificantlydifferentcustomerbases.ELL/EGSLareheavilyindustrial,whileENOhasverylittleindustry.Assuch,comparingperformanceattheportfoliolevelbetweenENOandELL/EGSLisproblematic.AllianceforAffordableEnergy-WhyarethepaybackacceptancecurvesdifferentfromtheNewOrleansdata?ThesamesetofpaybackacceptancecurveswasusedtoestimateparticipationforELL/EGSLaswasusedforENOfortheEntergyStudy.AllianceforAffordableEnergy-WhyarethenettogrossratiosdifferentfromENO?ThesamesetofprogramnettogrossratioswereusedforELL/EGSLaswereusedfortheENOstudy.AllianceforAffordableEnergy-InAppendixF[oftheNovember3,2014InputsFiling],itlookslikeavoidedcostsdonotincludefuel.Yes,fuelisincludedintheavoidedcostsinAppendixF.

Page10of16EnvironmentalRegulationCommentResponse(January2015)Staff-Addresshow[CSAPR]affectsamountandtimingofplanneddeactivations.TheCompaniescontinuetoevaluatetherecentSupremeCourtdecisiontoallowtheEPAtoenforceCSAPR,buttodate,noneoftheCompanies'unitshavebeenidentifiedfordeactivationbecauseofthisrule.However,therearedifferentassumptionsforotherloadservingentitiesinthemarketbaseduponthedifferentscenarios.IndustrialRenaissanceandDistributedDisruptionassumenonEntergyunitsretireattheageof60years;BusinessBoomassumes70years;andGenerationShiftassumes50years.SierraClub-Unclearhowenvironmentalcompliancecostsregardingcarbonpollutionandotherenvironmentalregulationswillbeincorporated.TheIRPdoesevaluatearangeofenvironmentalcompliancecostsinregardstoCO2,SO2,andNOx.GulfStatesRenewableEnergyIndustriesAssociation("GSREIA")Failsto"recognizeinherentproblemswithtraditionalsourcessuchaspricevolatilityandreducedcapacityoflife";"sustainability"andenvironmentalimpactareotherissues.TheIRPdoesconsiderallknownandexpectedenvironmentalcostofresourcesincludingcarbon.AllianceforAffordableEnergyUseonerobustreferencecasethatincludesCO2andSection111(d)compliancewithmorefocusonsensitivitiesinsteadofmultiplescenarios.

ArangeofCO2priceassumptionsareincludedintheIRPacrossthefourscenarios.Moreover,thesensitivityanalysisevaluatestheeffectsofdifferentCO2pricesforeachscenario.SEEA-AssumptionsregardingCO2policyareunrealistic.SierraClub-"Ignores"thecostsofnewEPAregulationsinSection111(d)regardingcarbonpollutionstandardscominginJune2014.SierraClub-Use"nonzeroCO2price" Page11of16CommentResponse(August2015)StaffIncludeanevaluationoftheeffectsofenvironmentalregulationsorfutureregulationsontheoperationoftheCompanies'existingUnits.ESIcoordinatesinternallytoidentify,assess,andrespondtoenvironmentalissuesarisingfromfederalregulatoryandlegislativeproceedings.ESItracksissuesandanalyzesimpactsusingacombinationofinternalcorporateandbusinessfunctionstaffandexternalorganizations.Subjectmatterexpertsparticipateinindustryassociationsandorganizations,interactwithfederalandstateagencystaff,andmonitorthetradepressregardingenvironmentalissues.InformationgatheredissharedthroughtechnicalpeergroupsandtheEnvironmentalLeadTeam,andaconsolidatedpointofviewisformedbasedonEntergy'soverallbusinessstrategy,asneeded.Unlessotherwisenotedbelow,expectedcapitalexpendituresandincreasestoO&Mcostsfrommanyoftheseproposalsarenotyetfullydevelopedduetouncertaintyregardingtheoutcomeofregulatory,legislative,andlitigationproceedings.AbriefsummaryofissueswhichpotentiallyhavethehighestoperationalimpactontheCompaniesfollows:CleanAirActRegulations-ConsistentwiththePresident'sCleanPowerPlanannouncedinJune2013,EPAisexpectedtofinalizeinAugust2015regulationsfornew,existing,andmodified/reconstructedsourcesofCO2undertheCleanAirAct.ESIdevelopedanengagementplanandisactivelyengagedwithindustrygroups,regulatoryagencystaff,andotherexternalpartiestoanalyzetheimpactoftheseproposedrules,commentonpolicyandtechnicalissues,andadvocateforreasonableapproaches.Performancestandardsforexistingsources,oncefinal,willinitiatestateplansforcompliancewhichcouldbedueasearlyasSeptember2016.Regulationstoaddresstraditionalpollutantshaveevolvedduetocourtrulings,stateimplementationplanning,andEPAactions.EGSLinstalledcontrolsattheR.S.NelsonpowerplantpursuanttoEPAregulationsregardingmercuryandotherairtoxics,butarecentSupremeCourtrulingremandingthisrulemayresultinadifferentcompliancerequirement.ESIalsoisimplementingcompliancemeasuresfortheCrossStateAirPollutionRule(CSAPR)andcontinuestomonitorissues Page12of16regardingregionalhazeandNationalAmbientAirQualityStandard(NAAQS)development.Solid/HazardousWasteRegulations-EPAfinalizedregulationsforcoalashandmanagementstructuresinDecember2014.Theruleregulatescoalashdisposalandimpoundments/landfillsunderthenonhazardoussectionofthesolidwasteregulations.TheR.S.NelsonpowerplantistheonlyEGSLownedfacilityaffectedbytherule.ESIcontinuestoparticipatewithindustrygroupstoadvocateforreasonableimplementationapproachesinordertominimizecompliancecosts.Litigationonthisrulemayresultinadifferentcompliancestrategy.

AquaticProtectionRegulations-EPAfinalizedthe316(b)ruleinMay2014.ThefinalruleaffectsseveralEGSL/ELLfacilitiesandprovidesflexibilityonboththescheduleandtechnologyapproachesforcomplyingwiththestandardsforimpingementandentrainment.ESI'sEnvironmentalStrategy&PolicygrouphascoordinatedbetweentheEntergyFossilandNuclearorganizationstoassessplantneedsforrespondingtothenewregulation.Consultantshavebeenretainedandcomplianceactivitiesareunderwaytoconductthenecessarytechnicalstudiesandcompiletheexistingtechnicaldataforsubmissiontotheappropriateregulatoryagencies.EPAalsohasproposedneweffluent(discharge)guidelinesforelectricgeneratingunitsthatmayrequiremodifiedwastewatertreatmentprocedures;theseguidelinesarenotexpectedtobefinalizeduntillate2015.StaffIncludemoreclarificationonthemethodologyoftheCO2forecast,particularlyaroundwhythecarboncostsstartin2023.Includesupportingstudiesfromotherorganizations.Thereferencecasepricestreamisbasedonaprobabilityweightedforecastofautilityonlysectorcapandtradeprogrambeingimplementedstartingin2023.TheutilityprogramisbasedonthereductionsrequiredundertheKerryLiebermanlegislativeproposal,andproratedtothepowersectoremissionslevels.Offsetsarealsoallowed.Theassumedprobabilityofanational,utilityonlyprogramis33percentin2023and66percentby2040.TheforecastisupdatedannuallybytheESIEnvironmentalStrategyandPolicygroup,ormore Page13of16oftenasconditionswarrant.TheupdatedforecastisreviewedbytheCompanies'EnvironmentalLeadTeamwiththeirrecommendationbeingusedastheCompanies'CO2PointofView.TheforecastisbasedontheQ12014StrategicOutlook(formerlytheIntegratedEnergyOutlook)datedJanuary2013byICFInternational.RenewableResourcesCommentResponse(January2015)SierraClub-Solarandwindinstallationcostswilldecrease.

TheTechnologyAssessmentindicatesthatsolarcostarelikelytodeclineoverthenextfiveyears,however,windcostandperformancearenotexpectedtomateriallyimproveordeclineoverthistimeperiod.IfwindandsolarcostandperformanceimprovemorethanexpectedinthisIRP,thenfutureIRPswillcapturethat.LAIRPcycletimeiseveryfouryears.GSREIACommonexpectationforsolarandwindenergyleveledcoststoreachgridparityinmanyareaswithin510years.AlackofearlyfirsthandexperiencebyEGSLandELLwithintegration,thesetechnologieswillbealiabilitytoratepayers,keepingcostsandvolatilityhighunnecessarily.Decliningpriceofrenewableenergysourcesmustbeincludedinthemodelingofanyforwardlookingresourceplan.AllianceforAffordableEnergyWindresources:modelLouisianacoastal,upland,andoutofregionprojectsseparatelyanduse40%+capacityfactor.

TheCompaniesprefertechnologiesthatareprovenonacommercialscale.Sometechnologieslackthecommercialtrackrecordtodemonstratetheirtechnicalandoperationfeasibility.AcautiousapproachtotechnologydevelopmentanddeploymentisthereforereasonableandappropriateinordertoAllianceforAffordableEnergy-Renewableresource:instateandoutofstateandabroadrangeofprojectsizesshouldbeconsidered.

Page14of16SWEAConsider"importingSouthwestPowerPool[SPP]wind"atlowcost.

Recommends"MISOWestwindenergyresourcesbemodeledinIRPprocessasaseparateresource.Ifpossible,EGSL/ELLshouldmodeltransmissioninterconnectionsandupgradesthatmaygrantgreaterflexibilityinaccessinglowcostenergyresources,likeSPPorMISOwindenergy."Entergycouldalso"procurewindresourcesinNorthernMISO."

WithinLouisiana,windfarmscanbeconstructedinthecoastalzoneoffshoreandcanbeconsideredresourcesforMISOSouthPricepointsandcapacityfactorsaredifferentforLouisianabasedresourcesandmustbemodeledasaseparateresourceinthisIRPprocess.EncourageaclearerexplanationofhowEGSL/ELLplanstoconductcapacityvalueanalysesforallgenerationresources.Currently,thecapacityvalueprovidedtowindenergyintheMISOsystemis14.1%,andbecauseEGSL/ELLisnowamemberofMISO,thisisareasonablefigureforinclusionintheIRPprocess.Evenso,thisvaluemaybeconservative.AnalysisofwindresourcesavailableinSPPandforHVDCtransmissionsuggestsacapacityvalueof40%basedonTVA'scapacityvaluemethodology.

Usedwindcoststhataretoohigh:"AmajorreasonforEGSL/ELL'sunrealisticallyhighLCOE[LevelizedCostofEnergy]forwindenergyisamaintainSystemreliabilityandtoprotectOperatingCompanycustomersfromunduerisks.TheEntergyOperatingCompaniesgenerallydonotplantobethe"firstmovers"foremerging,unproventechnologies.TheIRPseekstoidentifygenerationtechnologiesthataretechnologicallymatureandcouldreasonablybeexpectedtobeoperationalinoraroundtheCompanies'regulatedserviceterritory.TheCompaniesusea34%capacityfactorassumptionforwindresourcesthatcouldbedevelopedinoraroundtheEntergyregulatedserviceterritory.

AspartofMISO,theCompaniesarerequiredtoadheretoMISO'scapacityvaluesforwind,whichis14.1%asoutlinedinMISO'sResourceAdequacyTariff(ModuleE)andResourceAdequacyBusinessPracticeManual.

TheCompanies'useofacapacity"matchup"reflectsthefactthatwindreceivespartialcapacityvalueinMISOduetowind'sintermittentnature.Thecapacitymatchupisonlyusedinthescreeninganalysisofsupplysideresourcesinthetechnologyassessment.WhenmodeledinAURORA,windisevaluatedwithoutthecapacitymatchuprelativetootherresources.

Page15of16spurioususeofa'matchup'fee-"Itisrecommendedthatthetotalallin,deliveredcostsofwindenergyforoutofstateresourcesberoughly$4050/MWhandapproximately$44/MWhforresourceswithinLouisianaCommentonDraftIRPReportResponse(August2015)StaffConcernedaboutlackoffueldiversityintheReferenceCase.Shoulddiscussfueldiversityandcommentsfromthe2009SRPregardingappropriatenessofincludingrenewablesintheSystemportfolio.The2009SystemSRPincludedthestatementonpage110that"renewablegenerationhasaplaceintheportfolio.InclusionofmodestlevelsofthemosteconomicallypricedrenewablegenerationalternativescanreducecostandminimizetotalsupplycostriskespeciallyinlightofthepotentialRPSandcarbonlegislation.However,theamountofrenewablegenerationthatcanbecosteffectivelyaddedislimited."The"expected"gasforecastshownonFigure4:3ofthatSRPoverthe20yearhorizon(ending2030)inreal2008$was$8.66/MMBTU,significantlyabovetheReferenceCaseRealLevelizedforecastof$4.87inthis2015IRP.

Basedonthatpointofview,itwaspossibletoforesee2GWofcosteffectiverenewablesbeingaddedtotheEntergySystemportfolio(asstatedonpage111)andaSystemrenewablesRFPbeingissuedinthe20092010timeframe(infact,theRFPissuedin2010waslimitedtoELL/EGSL).Whilerenewableswouldincreasefueldiversityintheportfolio,theanalysisconductedforthe2015IRPshowsthatthecostofrenewablescomparedtonaturalgasgenerationissuchthattheyarenotcompetitiveintheabsenceofaRPS.Likewise,thecostsassociatedwithnewnuclearandcoalrenderthemuncompetitivewithnaturalgasatthistime.WhilefueldiversityisaconcernoftheIRPprocess,naturalgasgenerationoffersthebestwaytoprovidethelowestreasonablecostportfoliothatcanreliablyservethecustomers'needs.

Page16of16HydroelectricCommentResponse(January2015)NelsonFailstorecognize-thatconventionalhydroelectricgenerationisanoptionforEntergy,fromnewhydroelectricprojectsthatwouldbelocatedinorneartheCompanies'serviceareas."HydroelectricgenerationresourcesarewellbelowcostsofotherrenewableoptionsShouldstudyhydroelectricgenerationaspartofIRP

HydroelectricisasitespecificresourcethathaslimiteddevelopmentopportunitiesinLouisiana.Asaresult,itisnotappropriatetoassessconventionalhydroelectricresources(oranyotherspecificresource)inthecontextoftheIRP.SuchanalysiswouldbeconductedaspartoftheevaluationofresponsestoaRequestforProposals("RFP")orofanunsolicitedofferforaparticularresource.SierraClub-Entergyshouldincludehydroelectricprojects.

Report Date:January 19, 2015Entergy Project IDMTEP Project IDMTEP DesignationProject DriverProject NameOperating CompanyProposed ISD (Planning)Project Funding StatusProject StatusProject Status CommentsCurrent Projected ISDActual ISDMitigation Plan if requiredIncluded in Model? (Yes/No)11-EGL-0074602Appendix BTransmission Reliability - Meeting Planning CriteriaMoril to Delcambre 138 kV line: Upgrade station equipmentEGSLSummer 2016Proposed & In TargetScopingScoping to begin 3rd Quarter 2014Summer 2016N/A11-EGL-016-02N/APre-PlannedTransmission Reliability - Meeting Planning CriteriaMossville to Canal - Phase 2: Upgrade 69 kV LineEGSLWinter 2014ApprovedConstructionConstruction started 12/15/14. Outages have been approved2/14/15N/A11-EGL-0174608Appendix BTransmission Reliability - Meeting Planning CriteriaFive Points to Line 281 Tap to Line 247 Tap- Upgrade 69 kV lineEGSLSummer 2019Proposed & In TargetScopingSummer 2019N/A11-EGL-0184630Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaFrancis to Marydale: Upgrade 69 kV lineEGSLSummer 2017Proposed & In TargetScopingAccelerated Need By Date from 2023 to Summer 2017Summer 2017N/A12-EGL-0044603Appendix BTransmission Reliability - Meeting Planning CriteriaMcManus to Brady Heights - Upgrade 69 kV lineEGSLWinter 2023ConceptualConceptualConceptualMoved out from 2016 to 2023Winter 2023N/A12-EGL-010N/APre-PlannedTransmission Reliability - Meeting Planning CriteriaKirk Substation: Construct new 138-69 kV substation near St. Martinville (Formerly New Iberia: Add 138-69 kV substation)EGSLSummer 2015Proposed & In TargetScopingPEP is under review to evaluate a proposed change in the station configuration.Spring 2016NCLL14-EGL-0024611Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaConstruct new Waddill 230-69 kV Substation (formerly referred to as Flannery Area Project)

Also reconfigure 69 kV lines 340 and 749EGSLSummer 2017Proposed & In TargetScopingAccelerated Need By Date from 2020 to 2017Summer 2017N/A14-EGL-003N/APre-PlannedTransmission Reliability - Meeting Planning CriteriaWillow Glenn: Upgrade 500-230 kV single phase transformer bank with 1200 MVA single phase bankEGSLSummer 2016ApprovedDesign/ConstructionAutotransformer and breakers have been ordered and are scheduled to be delivered to support EGSL Construction; January 2016 (Auto) and March 2015 (breakers).Summer 2016Planned NCLL until project completed14-EGL-0044606Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaFancy Point: Add 2nd 500-230 kV, 1200 MVA transformerEGSLSummer 2017Proposed & In TargetScopingDetailed scoping to begin 3rd Quarter 2014Summer 2017Planned NCLL until project completed14-EGL-0054625A in MTEP14Transmission Reliability - Meeting Planning CriteriaNelson: Upgrade 500-230 kV single phase transformer bank with 1200 MVA transformer bankEGSLWinter 2015ApprovedDesignAutotransformer has been ordered. Design completeSpring 2015N/A14-EGL-006N/APre-PlannedTransmission Reliability - Meeting Planning CriteriaLeBlanc - New Cap Bank #1EGSLSummer 2015Proposed & In TargetConstructionPermanent and Temporary Servitudes are being finalizedSummer 2015N/A14-EGL-0074610Appendix BTransmission Reliability - Meeting Planning CriteriaChlomal to Lacassine - Upgrade LineEGSLWinter 2023ConceptualConceptualConceptualMoved out from 2019 to 2023Winter 2023N/A14-EGL-0084609Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaKrotz Springs - New Cap BankEGSLSummer 2016Proposed & In TargetScopingAlternative locations for the capacitor bank are being evaluated based on constructability issues.Summer 2016N/A14-EGL-0104626Appendix BTransmission Reliability - Meeting Planning CriteriaMeaux to Abbeville - Upgrade Meaux Line bay busEGSLSummer 2024ConceptualConceptualConceptualProject need date moved out from 2020 to 2024Summer 2024N/A14-EGL-0124628Appendix BTransmission Reliability - Meeting Planning CriteriaLeBlanc - New Cap Bank #2EGSLSummer 2021ConceptualConceptualConceptualAccelerated one year from 2022 to 2021Summer 2021N/AAPPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)Long Term ProjectsPage 1 of 7 Report Date:January 19, 2015Entergy Project IDMTEP Project IDMTEP DesignationProject DriverProject NameOperating CompanyProposed ISD (Planning)Project Funding StatusProject StatusProject Status CommentsCurrent Projected ISDActual ISDMitigation Plan if requiredIncluded in Model? (Yes/No)APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)14-EGL-0164604Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaPort Hudson to Zachary REA 69 kV Line ReconductorEGSLSummer 2016Proposed & In TargetScopingAccelerated Need By Date to Summer 2016Summer 2016N/A14-EGL-0174605A in MTEP14Transmission Reliability - Meeting Planning CriteriaHorseshoe Substation (Crown Zellerbach Area): Construct new 230-138 kV substation on the Fancy Point to Enjay 230 kV lineEGSLSummer 2017Proposed & In TargetScopingChanged name to reflect new substation name and line connection in titleSummer 2017N/A14-EGL-019N/APre-PlannedTransmission Reliability - Meeting Planning CriteriaMud Lake 230 kV Substation: Loop Sabine to Big 3 230 kV Line into new Mud Lake 230 kV substation and add (2) 230 kV capacitor banks at Mud LakeEGSLFall 2016ApprovedScopingDetailed scoping in progress. Currently projected to be complete in the Summer 2016.Summer 2016N/A14-EGL-0204719A in MTEP14Transmission ServicePPG to Rosebluff 230 kV Line: Upgrade line to increase capacityEGSLSummer 2015ApprovedDesignScoping complete. Design has begun. Current project schedule is targeting a 7/1/15 ISD.7/1/15N/A14-EGL-022-14761A in MTEP14Transmission Reliability - Meeting Planning CriteriaEGSL SPOF Projects: Modify relaying at Willow Glen 500 kVEGSLSummer 2015Proposed & In TargetScopingDefinition Phase underway. Site visits completed. Review and updating of drawings by PCS will be completed by March 2015. PEP will also be completed by the end of February 2015. Due to the need to change 21 panels, add new relay room, replacement of transformer under another capital project, etc. and uncertainty in availability of outages, ISD would likely be by December 2016 or beyond this date. After PEP and outage planning is done, a schedule will be developed and ISD identified.12/31/2016N/AN/A14-EGL-022-24762A in MTEP14Transmission Reliability - Meeting Planning CriteriaEGSL SPOF Projects: Modify relaying at Fancy Point 500kVEGSLSummer 2015Proposed & In TargetScopingScope to be determinedSummer 2015N/AN/A14-EGL-0234720A in MTEP14Customer DrivenMichigan 230 kV substation: Construct new Michigan 230 kV substation and cut in to the Nelson to Verdine 230 kV lineEGSLSummer 2015ApprovedDesignDesign complete. Material has been ordered. Awaiting customer to prep the site. Expected mobilization is 01/05/2015.Fall 2015N/A14-EGL-024-14763A in MTEP14Transmission Reliability - Meeting Planning CriteriaEGSL Underrated Breaker Project: Jaguar 69 kV 20940-COEGSLWinter 2016Proposed & In TargetScopingUnder ReviewWinter 2016N/AN/A14-EGL-024-24764A in MTEP14Transmission Reliability - Meeting Planning CriteriaEGSL Underrated Breaker Project: Jaguar 69 kV 20905-COEGSLWinter 2016Proposed & In TargetScopingUnder ReviewWinter 2016N/AN/A14-EGL-024-34765A in MTEP14Transmission Reliability - Meeting Planning CriteriaEGSL Underrated Breaker Project: Blount 69 kV 14105-TCEGSLWinter 2016Proposed & In TargetScopingUnder ReviewWinter 2016N/AN/A14-EGL-024-44766A in MTEP14Transmission Reliability - Meeting Planning CriteriaEGSL Underrated Breaker Project: Coly 230 kV 21825-CEGSLWinter 2016Proposed & In TargetScopingUnder ReviewWinter 2016N/AN/A14-EGL-024-54767A in MTEP14Transmission Reliability - Meeting Planning CriteriaEGSL Underrated Breaker Project: Coly 230 kV 21830-CEGSLWinter 2016Proposed & In TargetScopingUnder ReviewWinter 2016N/AN/A14-EGL-0268284A in MTEP14EconomicLETP: Coly - Add 2nd 500-230 kV, 1200 MVA AutotransformerEGSLSummer 2018ApprovedScopingNew project (Economic MTEP 14)Summer 2018N/AN/ALong Term ProjectsPage 2 of 7 Report Date:January 19, 2015Entergy Project IDMTEP Project IDMTEP DesignationProject DriverProject NameOperating CompanyProposed ISD (Planning)Project Funding StatusProject StatusProject Status CommentsCurrent Projected ISDActual ISDMitigation Plan if requiredIncluded in Model? (Yes/No)APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)15-EGL-0017917Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaGillis 230 kV Substation: Add 61 MVAR capacitor bankEGSLSummer 2016Proposed & In TargetScopingNew ProjectSummer 201615-EGL-0027919Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaPecan Grove 230 kV Substation: Add 61 MVAR capacitor bankEGSLSummer 2016Proposed & In TargetScopingNew ProjectSummer 201615-EGL-0037920Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaCarlyss to Boudoin 230 kV Line: Upgrade station equipment at CarlyssEGSLSummer 2016Proposed & In TargetScopingNew ProjectSummer 201615-EGL-0047921Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaNelson to Michigan 230 kV line: Upgrade line to minimum of 2000AEGSLSummer 2016Proposed & In TargetScopingNew ProjectSummer 201615-EGL-0057923Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaLake Charles Bulk to Chlomal 69 kV Line: Reconductor lineEGSLSummer 2017Proposed & In TargetScopingNew ProjectSummer 201715-EGL-0067924Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaGoosport Substation: Install 138-69 kV autotransformerEGSLSummer 2017Proposed & In TargetScopingNew ProjectSummer 201715-EGL-0087929Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaSolac: Upgrade 69 kV switch on AutotransformerEGSLSummer 2016Proposed & In TargetScopingNew ProjectSummer 201615-EGL-0097948Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaScott to Carencro 69 kV line: Reconductor LineEGSLSummer 2017Proposed & In TargetScopingNew ProjectSummer 201715-EGL-0107949Appendix BTransmission Reliability - Meeting Planning CriteriaSolac: Add 3rd AutotransformerEGSLSummer 2023ConceptualConceptualNew ProjectSummer 202315-EGL-0117950Appendix BTransmission Reliability - Meeting Planning CriteriaEast Broad to Ford 69 kV line: Reconductor lineEGSLSummer 2020Proposed & In TargetScopingNew ProjectSummer 202015-EGL-0127952Appendix BTransmission Reliability - Meeting Planning CriteriaContraband to Solac 69 kV line: Reconductor lineEGSLSummer 2023ConceptualConceptualNew ProjectSummer 202315-EGL-0137954Appendix BTransmission Reliability - Meeting Planning CriteriaMossville to Alfol 69 kV line: Reconductor lineEGSLSummer 2023ConceptualConceptualNew ProjectSummer 202315-EGL-0147960Appendix BTransmission Reliability - Meeting Planning CriteriaChlomal to Iowa 69 kV line: Reconductor lineEGSLSummer 2024ConceptualConceptualNew ProjectSummer 202415-EGL-0157965Appendix BTransmission Reliability - Meeting Planning CriteriaLake Charles Bulk to L673 TP 69 kV line: Reconductor lineEGSLSummer 2025ConceptualConceptualNew ProjectSummer 202515-EGL-0168585Target Appendix A in MTEP15 (OOC)Transmission Reliability - Meeting Planning CriteriaLCTP: Construct new Sulphur Lane 500 kV switching stationEGSLSummer 2018ApprovedScopingNew Project to address reliability needs in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycleSummer 201815-EGL-017-018586Target Appendix A in MTEP15 (OOC)Transmission Reliability - Meeting Planning CriteriaLCTP: Construct new 500-230 kV Bulk Substation west of Carlyss. Install new 500-230 kV, 1200 MVA autotransformer composed of three single phase units.EGSLSummer 2018ApprovedScopingNew Project to address reliability needs in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycleSummer 2018Long Term ProjectsPage 3 of 7 Report Date:January 19, 2015Entergy Project IDMTEP Project IDMTEP DesignationProject DriverProject NameOperating CompanyProposed ISD (Planning)Project Funding StatusProject StatusProject Status CommentsCurrent Projected ISDActual ISDMitigation Plan if requiredIncluded in Model? (Yes/No)APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)15-EGL-017-028587Target Appendix A in MTEP15 (OOC)Transmission Reliability - Meeting Planning CriteriaLCTP: Construct new 500 kV transmission line from Sulphur Lane to new 500/230 kV Bulk Substation west of CarlyssEGSLSummer 2018ApprovedScopingNew Project to address reliability needs in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycleSummer 201815-EGL-017-038588Target Appendix A in MTEP15 (OOC)Transmission Reliability - Meeting Planning CriteriaLCTP: Construct new 230 kV line from new Bulk Substation to Carlyss 230 kV substationEGSLSummer 2018ApprovedScopingNew Project to address reliability needs in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycleSummer 201815-EGL-0188589Target Appendix A in MTEP15 (OOC)Transmission Reliability - Meeting Planning CriteriaLCTP: Reconfigure Carlyss 230 kV substation into a breaker and a half configurationEGSLSummer 2018ApprovedScopingNew Project to address reliability needs in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycleSummer 201815-EGL-0198590Target Appendix A in MTEP15 (OOC)Transmission Reliability - Meeting Planning CriteriaLCTP: Construct new 12 mile 230 kV line from Carlyss to new 230 kV substation adjacent to Graywood.EGSLSummer 2018ApprovedScopingNew Project to address reliability needs in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycleSummer 201815-EGL-020TBDTarget Appendix A in MTEP15 (OOC)Customer DrivenIntracoastal 69 kV Substation: Install 150 MVA, 230-69 kV autotransformer at Intracoastal and connect to Mud Lake 230 kV substationEGSLSummer 2016ApprovedScopingNew customer requested project to provide an additional source into the Intracoastal 69 kV substationSummer 2016N/A15-EGL-021TBDTarget Appendix A in MTEP15 (OOC)Transmission Reliability - Meeting Planning CriteriaCarlyss to Sweet Crude Tap (L-238): Reconductor 69 kV line (0.94 miles) to a minimum of 1200A.EGSLSummer 2016ApprovedScopingNew customer requested project to provide an additional source into the Intracoastal 69 kV substationSummer 2016N/A14-EGL-0278284A in MTEP14EconomicLETP: Richardson to Iberville - Construct new Richardson 230 kV substation new Dow Meter and construct new 230 kV line from Richardson to Iberville 230 kV substation. (EGSL Portion of project)EGSL/ELLWinter 2018ApprovedScopingNew project (Economic MTEP 14)Winter 2018N/AN/A14-ELL-0198284A in MTEP14EconomicLETP - Richardson to Iberville - Construct new Richardson 230 kV substation new Dow Meter and construct new 230 kV line from Richardson to Iberville 230 kV substation. (ELL Portion of project)EGSL/ELLWinter 2018ApprovedScopingNew project (Economic MTEP 14)Winter 2018N/AN/ALong Term ProjectsPage 4 of 7 Report Date:January 19, 2015Entergy Project IDMTEP Project IDMTEP DesignationProject DriverProject NameOperating CompanyProposed ISD (Planning)Project Funding StatusProject StatusProject Status CommentsCurrent Projected ISDActual ISDMitigation Plan if requiredIncluded in Model? (Yes/No)APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)10-ELL-008N/APre-PlannedTransmission Reliability - Meeting Planning CriteriaSoutheast LA Coastal Improvement Plan: Phase 3 Construct Oakville to Alliance 230kV Line Add 230 - 115 kV Autotransformer at Alliance SubstationELLSummer 2013ApprovedScopingOakville Substation expansion placed into service 9/3/12. Alliance Substation expansion and 230/115kV Auto placed into service 1/16/14. T-Line routing challenges continue to delay start of ROW acquisition. Projected ISD delayed from 6/1/15 to 6/1/18. Awaiting conditional permit approval from LADOTD to construct line within their ROW for Hwy 23. Identifying location of two Parish water lines along west side of Hwy, continue discussions on tifltili6/1/18Planned NCLL until project completed11-ELL-001N/APre-PlannedEnhanced Transmission ReliabilityGolden Meadow to Leeville 115 kV - Rebuild/relocate 115 kV transmission line ELLSpring 2014ApprovedConstructionT-Line ROW acquisition completed Dec-2013. The DNR-OCM permit was received in Nov-2013, and the USACE permit was received in Feb-2014. Construction of driveway pads needed for the T-Line structures completed Oct-2014.T-Lineconstructionisin3/31/15N/A11-ELL-004N/APre-PlannedTransmission Reliability - Meeting Planning CriteriaNortheast LA Improvement Project Phase 3 Upgrade Sterlington to Oakridge to Dunn 115 kV LineELLSummer 2015ApprovedConstructionPre-Construction meeting held on 1/09/15. Construction to start 1/15/201512/30/15Planned NCLL until project completed11-ELL-012N/APre-PlannedTransmission Reliability - Meeting Planning CriteriaValentine to Clovelly 115 kV upgradeELLSummer 2015ApprovedConstructionDesign, material procurement, permitting, and ROW access improvements complete. T-Line 5/1/15Planned NCLL until project completed12-ELL-0044769A in MTEP14Load GrowthSchriever: Construct new 230 kV substationELL2017Proposed & In TargetScopingUnder Review3/31/17N/A13-ELL-004N/APre-PlannedTransmission Reliability - Meeting Planning CriteriaMinden Improvement Project Ph. 1-Place cap bank at Minden REAELLSummer 2015Proposed & In TargetScopingWill require co-ordination with Lagen on final design and operationSummer 2015N/A13-ELL-0064634Appendix BTransmission Reliability - Meeting Planning CriteriaNinemile to Westwego 115 kV: Reconductor LineELLSummer 2020ConceptualConceptualConceptualSummer 2020N/A14-ELL-0024635Appendix BTransmission Reliability - Meeting Planning CriteriaSterlington 115 kV Substation: Upgrade jumpers on the Sterlington to Walnut Grove 115 kV line (line 107)ELLSummer 2024ConceptualConceptualConceptualSummer 2024N/A14-ELL-0064639Appendix BTransmission Reliability - Meeting Planning CriteriaNinemile to Harvey2 115 kV: Reconductor line and change station limiting elementsELLSummer 2025ConceptualConceptualConceptualMoved ISD back to from 2022 to 2025Summer 2025N/A14-ELL-008-14770A in MTEP14Transmission Reliability - Meeting Planning CriteriaELL Underrated Breaker Project: Waterford 230 kV S7145-COELLWinter 2016Proposed & In TargetScopingUnder ReviewWinter 2016N/AN/A14-ELL-008-24771A in MTEP14Transmission Reliability - Meeting Planning CriteriaELL Underrated Breaker Project: Waterford 230 kV S7154-COELLWinter 2016Proposed & In TargetScopingUnder ReviewWinter 2016N/AN/A14-ELL-009-14773A in MTEP14Transmission Reliability - Meeting Planning CriteriaELL SPOF Projects: Modify relaying at Ninemile 230 kVELLSummer 2015Proposed & In TargetDesignProject is in Design Phase - Kickoff meeting to commence project has been held and schedule developed. Currently scheduled to be completed by Summer 2016 barring availability of outages.Summer 2016N/AN/ALong Term ProjectsPage 5 of 7 Report Date:January 19, 2015Entergy Project IDMTEP Project IDMTEP DesignationProject DriverProject NameOperating CompanyProposed ISD (Planning)Project Funding StatusProject StatusProject Status CommentsCurrent Projected ISDActual ISDMitigation Plan if requiredIncluded in Model? (Yes/No)APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)14-ELL-009-24774A in MTEP14Transmission Reliability - Meeting Planning CriteriaELL SPOF Projects: Modify relaying at Southport 230 kVELLSummer 2015Proposed & In TargetDesignProject is in Design Phase - Kickoff meeting to commence project has been held and schedule developed. Currently scheduled to be completed by Summer 2016 barring availability of outages.Summer 2016N/AN/A14-ELL-009-34775A in MTEP14Transmission Reliability - Meeting Planning CriteriaELL SPOF Projects: Modify relaying at Labarre 230 kVELLSummer 2015Proposed & In TargetDesignProject is in Design Phase - Kickoff meeting to commence project has been held and schedule developed. Currently scheduled to be completed by Summer 2016 barring availability of outages.Summer 2016N/AN/A14-ELL-009-44776A in MTEP14Transmission Reliability - Meeting Planning CriteriaELL SPOF Projects: Modify relaying at Harahan 230 kVELLSummer 2015Proposed & In TargetDesignProject is in Design Phase - Kickoff meeting to commence project has been held and schedule developed. Currently scheduled to be completed by Summer 2016 barring availability of outages.Summer 2016N/AN/A14-ELL-009-54777A in MTEP14Transmission Reliability - Meeting Planning CriteriaELL SPOF Projects: Modify relaying at Paris 230 kVELLSummer 2015Proposed & In TargetDesignProject is in Design Phase - Kickoff meeting to commence project has been held and schedule developed. Currently scheduled to be completed by Summer 2016 barring availability of outagesSummer 2016N/AN/A14-ELL-0164783A in MTEP14Customer DrivenHaute 115 kV Substation: Construct new substation and cut into existing Lutcher to Belle Point 115 kV lineELLSummer 2014ApprovedConstructionThe Haute Substation is complete. Project team has accelerate schedule to complete by 12/18/14 . Energization pending legal transfer of ownership.4/1/2015N/AN/A14-ELL-0187841A in MTEP14Customer DrivenReese Substation: Construct new 115 kV substationsELLSpring 2015ApprovedCompleteIn-ServiceSpring 201512/17/14N/AYes14-ELL-0208284A in MTEP14EconomicLETP: Panama Substation: Cut-in Bagatelle to Sorrento 230 kV lineELLWinter 2018ApprovedScopingNew project (Economic MTEP 14)Winter 2018N/AN/A14-ELL-0218284A in MTEP14EconomicLETP: Romeville Substation: Upgrade line bay bus.ELLWinter 2017ApprovedScopingNew project (Economic MTEP 14)Winter 2017N/AN/A15-ELL-0017988Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaTerrebonne to Gibson: Construct new 230 kV line and operate at 115 kVELLSummer 2018Proposed & In TargetScopingNew ProjectSummer 201815-ELL-0027970Appendix BTransmission Reliability - Meeting Planning CriteriaMinden Area Improvement Ph. 2: Construct new 115 kV substation east of Minden REA and cut-in Minden REA to Arcadia 115 kV line and construct new 115 kV lines to cut the Minden to Sailes 115 kV line in and out ofthenewsubstationELLSummer 2020Proposed & In TargetScopingNew ProjectSummer 2020Long Term ProjectsPage 6 of 7 Report Date:January 19, 2015Entergy Project IDMTEP Project IDMTEP DesignationProject DriverProject NameOperating CompanyProposed ISD (Planning)Project Funding StatusProject StatusProject Status CommentsCurrent Projected ISDActual ISDMitigation Plan if requiredIncluded in Model? (Yes/No)APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)15-ELL-0037990Appendix BLoad GrowthLuna: Construct new 115 kV substationELLWinter 2017Proposed & In TargetScopingNew ProjectWinter 201714-ELL-0124779A in MTEP15 (OOC)Transmission Reliability - Meeting Planning CriteriaNinemile to Derbigny: Upgrade 230 kV lineELL/ENOISummer 2016Proposed & In TargetScopingProject currently accelerated and targeted for June 1, 2016 ISD. Lattice structure inspections to take place Spring 2015. Team meeting with conductor vendor, 3M, on 01.14.15 to determine installation logistics. Project may require funding out of process to support ISD.6/1/2016N/A14-ELL-0134780Appendix BTransmission Reliability - Meeting Planning CriteriaNinemile to Napoleon: Upgrade 230 kV lineELL/ENOISummer 2017Proposed & In TargetScopingNew Project. Project currently accelerated for targeted for June 1, 2017 ISD. Lattice structure inspections to take place Spring 2015. Team meeting with conductor vendor, 3M, on 01.14.15 to determine installation logistics. 6/1/2017N/A15-EMI-0037904Target Appendix A in MTEP15Transmission Reliability - Meeting Planning CriteriaNatchez SES - Redgum: Rebuild 115 kV lineEMI/ELLSummer 2018Proposed & In TargetScopingUnder ReviewSummer 2018N/ALong Term ProjectsPage 7 of 7 APPE

1AsrequeSincethesRenaissanENDIXE:1SestedbyStaffinthsechartswerepronce"scenariofromSTSTAKEHOheircommentsontoducedtheScenariotheMay2014filinOLDERMEtheDraftIRPReporonameshavebeenng(ScenarioTwo)wETINGCHArt,thefollowingthnmodified."Scenawasrenamedto"BTable1:ScenaARTS1hreechartsfromtharioOne"wasrenaBusinessBoom."arioStorylinesefirstIRPstakehomedto"IndustrialldermeetingheldlRenaissance"inthJanuary22,2014,heNovember2014havebeenprovide4filing.The"Industed.trial Table2:20YearMarketModelingInputs(20152034)Scenario1IndustrialRenaissance DistributedDisruptionResourceShiftElectricityCAGR(EnergyGWh) ~0.8%~TBD%~TBD%~TBD%PeakLoadGrowthCAGR ~0.8%~TBD%~TBD%~TBD%HenryHubNaturalGasPrices($/MMBtu) $4.89levelized2013$ LowCase$3.84levelized2013$ SameasReferenceCase($4.89levelized2013$) HighCase($8.18levelized2013$) WTICrudeOil($/Barrel) $73.99levelized2013$LowCase$69.00levelized2013$ MediumHigh($109.12levelized2013$)HighCase($173.71levelized2013$)CO2($/shortton) None Capandtradestartsin2023 $6.70levelized2013$ Capandtradestartsin2023$6.70levelized2013$Capandtradestartsin2023$14.32levelized2013$ ConventionalEmissionsAllowanceMarkets CAIR&MATSCAIR&MATSCAIR&MATSCAIR&MATSDeliveredCoalPrices-EntergyOwnedPlants(PlantSpecificIncludesCurrentContracts) $/MMBtu ReferenceCase(Vol.WeightedAvg. $2.69levelized2013$)LowCase(Vol.WeightedAvg. $TBDlevelized2013$) SameasReferenceCase(Vol.WeightedAvg. $2.69levelized2013$)HighCase(Vol.WeightedAvg. $TBDlevelized2013$) DeliveredCoalPrices-NonEntergyPlantsInEntergyRegion MappedtosimilarEntergyPlantMappedtoSimilarEntergyPlantMappedtoSimilarEntergyPlantMappedtoSimilarEntergyPlantDeliveredCoalPrices-NonEntergyRegions ReferenceCaseVariesByRegionLowCaseVariesByRegion SameAsReferenceCase-VariesByRegionHighCase-VariesByRegion CoalRetirementsCapacity(GW)* TBDTBDTBDTBDNewNuclearCapacity(GW)* TBDTBDTBDTBDNewBiomass(GW)* TBDTBDTBDTBDNewWindCapacity(GW)* TBDTBDTBDTBDNewSolarCapacity(GW)* TBDTBDTBDTBD Table3:ProposeddSensitivitiesfoortheLAIRP APPENDIXF:AURORADSMPORTFOLIOSBYSCENARIOAURORADSMPortfoliosbyScenario IndustrialRenaissance BusinessBoomDistributedDisruptionGenerationShiftDSM1-ResidentialLighting&Appliances DSM1-ResidentialLighting&AppliancesDSM1-ResidentialLighting&AppliancesDSM1-ResidentialLighting&AppliancesDSM3-ENERGYSTARAirConditioning DSM3-ENERGYSTARAirConditioningDSM3-ENERGYSTARAirConditioningDSM3-ENERGYSTARAirConditioningDSM4-ApplianceRecycling DSM4-ApplianceRecyclingDSM4-ApplianceRecyclingDSM5-HomeEnergyUseBenchmarking DSM5-HomeEnergyUseBenchmarkingDSM5-HomeEnergyUseBenchmarkingDSM8-Multifamily DSM8-MultifamilyDSM8-Multifamily DSM8-MultifamilyDSM9-WaterHeatingDSM10-PoolPumpDSM12-DynamicPricing DSM12-DynamicPricingDSM12-DynamicPricingDSM13-CommercialPrescriptive&Custom DSM13-CommercialPrescriptive&CustomDSM13-CommercialPrescriptive&CustomDSM13-CommercialPrescriptive&Custom DSM14-SmallBusinessSolutions DSM14-SmallBusinessSolutionsDSM14-SmallBusinessSolutionsDSM14-SmallBusinessSolutionsDSM15-NonResidentialDynamicPricing DSM15-NonResidentialDynamicPricingDSM15-NonResidentialDynamicPricingDSM15-NonResidentialDynamicPricingDSM16-RetroCommissioning DSM16-RetroCommissioningDSM16-RetroCommissioningDSM17-CommercialNewConstruction DSM17-CommercialNewConstructionDSM17-CommercialNewConstructionDSM17-CommercialNewConstructionDSM18-DataCenter DSM18-DataCenter DSM18-DataCenterDSM19-MachineDrive DSM19-MachineDriveDSM19-MachineDrive DSM19-MachineDriveDSM20-ProcessHeating DSM20-ProcessHeatingDSM20-ProcessHeating DSM20-ProcessHeatingDSM21-ProcessCoolingandRefrigeration DSM21-ProcessCoolingandRefrigerationDSM21-ProcessCoolingandRefrigerationDSM21-ProcessCoolingandRefrigerationDSM22-FacilityHVAC DSM22-FacilityHVACDSM22-FacilityHVAC DSM22-FacilityHVACDSM23-FacilityLighting DSM23-FacilityLightingDSM23-FacilityLighting DSM23-FacilityLightingDSM24-OtherProcess/NonProcessUseDSM24-OtherProcess/NonProcessUseDSM24-OtherProcess/NonProcessUseDSM24-OtherProcess/NonProcessUse Page1of2APPENDIXG:WINDMODELINGASSUMPTIONSInresponsetostakeholdercommentsregardingtheassumptionsusedtoevaluatewindresourcesintheIRP,theCompanieshavepreparedthisAppendix.Forpurposesofthe2015ELL/EGSLIRP,thedeliveredcostofenergyfromawindresourcedevelopedinornearELLorEGSL'sservicearea("local")isjudgedtobecomparabletothecostofenergyfromaremote1windresource("remote").Whilethecapacityfactorsofremoteresourcesaregenerallyhigher,theadditionalcostsassociatedwithtransmissionserviceandthedifferencesinLocationalMarginalPrices("LMPs")combinetogenerallyequalizeenergypricesbetweenlocalandremoteresources.Additionally,allremoteresourceslocatedoutsideofMISOcarryanincreasedriskofunavailabilitycomparedtoresourceslocatedinMISOduetoMISO'semergencycurtailmentproceduresofexternalsystems.Riskassociatedwithpotentialchangesinrules,transmission,andmarketstructuresareinherentlygreaterforaremoteresourcerelativetoalocalresourcebasedoninterveningentitiesthatwouldbeinvolvedinconjunctionwiththelongtermnatureoftheseresources.

Forsomefactors,itisreasonabletoapplythesameassumptionsforlocalandremotewindresourcesbecausetheyarenotexpectedtobemateriallydifferent.Forinstance,theinstalledcostisassumedtobethesame.Inaddition,thenondispatchable,intermittentnatureisexpectedtobesimilarandisexpectedtoresultinsimilarcapacitycreditawardedbyMISO.Thetransmissioninterconnectioncosttoconnecttheresourcetoanearbysubstationisunknownandwouldbedependentonthespecificlocationregardlessofwhetherthewindresourceislocalorremote;therefore,itisreasonabletoignorethatcostbecauseitisunknown,butexpectedtobecomparable.Otherfactorsareexpectedtobedifferentforlocalascomparedwithremotewindresources.Keydifferencesincludecapacityfactor,transmissionservicecost,andLMPs.Assessmentofeachofthesefactorsisdiscussedinturn.

Windqualityandspeedinthemidwestisexpectedtoyieldhighercapacityfactorsascomparedtolocalwindresources.BasedonaNationalRenewableEnergyLaboratory("NREL")costandperformancestudypublishedin20102,thecapacityfactorforawindresourceinthemidwestisassumedtobe50%;whereas,basedonthesamestudy,alocalwindresourceisonlyexpectedtobe34%.Thus,remotewindresourceshaveanadvantageoverlocalwindresourceswithrespecttoenergyproductionpotential.ItisimportanttodrawadistinctionbetweentransmissioninterconnectioncostsasdescribedaboveandthetransmissionservicecostnecessarytomakethewindresourcedeliverabletotheCompanies'load.Alocalresourceisnotexpectedtorequireadditionaltransmissionservice1Forexample,awindresourcelocatedinKansasorOklahomaorothermidwestlocation.2http://www.nrel.gov/docs/fy11osti/48595.pdf(Figure96)

Page2of2chargestomakeitdeliverable.However,aremotewindresourcemayrequireSPPpointtopointtransmissionservicetotheMISOborderandMISOpointtopointtransmissionservicetoELL/EGSL'sload.BasedoncurrentMISOandSPPtariffrates,thecombinedcostoftransmissionservicecouldbeapproximately$$5/MWhforoffpeakhours4,$10/MWhforonpeakhours4,orwhenadjustedtoawindgenerationprofile,aweightedaverageof$7.11/MWh.Thistransmissionservicecostandriskisnotincurredbyalocalwindresource.

WindgenerationispaidthehourlyLMPatthegeneratorbuswhilecustomerspayforenergybasedonthehourlyloadweightedaverageLMPfortheloadzone.ThedifferencebetweentheloadLMPandgeneratorLMPisanestimateoftheriskthatcustomersareexposedtobyhavingaremoteresourceasopposedtoalocalresource.ToestimatethepotentialLMPdifferentialrisk,threerepresentativeSPPwindresources3for2014wereassessed,assumingagenericSPPwindprofile.TheLMPdifferentialsin2014betweenthesethreenodesandELL/EGSL'sload(loadweightedaverageofEES.ELILDandEES.EGILD)are$12.92/MWh,$13.84/MWh,and$17.07/MWhrespectively,orapproximately$14.60/MWhonaverage.AlocalwindresourceisnotsubjecttothispotentialLMPdifferentialrisk.

Insummary,thetablebelowshowsacomparisonofthecostofelectricityofalocalwindresourcewitharemoteresourcetakingthedifferencesincapacityfactor,transmissioncost,andLMPintoconsideration.Inthisexample,thecapacityfactoradvantageofaremotewindresourceisalmostcompletelyoffsetbyadditionaltransmissionservicecostsandLMPdifferentialrisk,whichresultsinsimilarLevelizedCostofElectricity("LCOE")estimatesforbothremoteandlocalwindresources.LocationInstalledCost($/kW)FixedChargeRate(%)CapacityFactor(%)TransmissionCost($/MWh)LMPDifferential($/MWh)LCOE($/MWh)Local$200010.5%34%$0$0$70.51Remote$200010.5%50%$7.11$14.60$69.65=[A]=[B]=[C]=[D]=[E]=[F][F]=[A]x[B]x(1/([C]x8760))x1000(kW/MW)+[D]+[E]Fromthisassessment,theexpectedcostdifferenceisapproximately1%betweenmodelingpotentialwindresourceswithlocalassumptionsascomparedwithremoteassumptions.IfinflationinthetransmissionservicecostandLMPdifferentialweretakenintoconsideration,thelocalwindresourcewouldhavealowerLCOEascomparedtotheremotewindresource.3KeenanWindFarm(OklahomaGas&Electric,OKGEWDWRDEHVUNKEENAN_WIND_RA),CentennialWindFarm(OklahomaGas&Electric,OKGECENTWINDUNCENTWIND_RA),SpearvilleWindFarm(KansasCityPower&Light,KCPLSPEARVILUNWINDFARM_RA).HistoricalLMPsbylocationobtainedfromSPPIntegratedMarketplace(https://marketplace.spp.org/web/guest/lmpbylocation).4MISOtransmissioncostestimatescalculatedbasedonMISOOATTSchedule7year2015rates,asofJuly2015.SPPtransmissioncostestimatescalculatedbasedonSPPOATTSchedule7AttachmentT,asofJuly2015.

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