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Alternatives RAI AL-3 - Entergy 2015g_Integrated Resource Plan 2015--Final Report
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~Entergy 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.

Accessed at http://www.entergy-louisiana.com/content/irp/2015_0803_Louisiana_Final_IRP_Public.pdf

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. I~ 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.

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2

TheIRPincludesafiveyearactionplanthatwillallowustoensureweareabletoprovidesafe,reliable andeconomicservicetoallcustomers,existingandnew.Theactionplanincludes:

ObtainingregulatoryapprovalsforEntergyGulfStatesLouisianatopurchasetwounitsofthe UnionPowerStationnearElDorado,Arkansas.

Addingpotentialnewresources:

o SeekingcertificationofselfbuildCCGTthatwasmarkettestedinthe2014AmiteSouth RFP.

o Issuingthe2015WOTABRFPtosolicitproposalsforanewCCGTunitintheLakeCharles areainthe202021timeframe.

o DeterminingwhetherapairofCTunitsisneededintheLakeCharlesareaby2020to meetindustrialloadgrowth.

o ContinuingtoassessdevelopmentofotherCTunitsinAmiteSouthandWOTABareas forquickdeploymentifloadgrowthexceedsprojectionsand/orothersupplyoptions arenotcompletedasplanned.

Studyingdistributedsolarandstoragepilotprojectstodeterminetheviabilityandperformance ofthetechnologiesinLouisiana.

Assessingpowercontractsasviablealternativesformeetinglongtermneeds.

Exploringopportunitiesforlongtermgassuppliestomitigatepricevolatilityandhedgeagainst futurepriceincreases.

EvaluatingtheresultsoftheQuickStartphaseofEntergySolutions:ALouisianaProgram;and Workingwithregulatorstodeveloprulesforcosteffectiveenergyefficiencyprogramsbeyond theQuickStartphase.

ThisisanexcitingtimeforLouisiana.EntergysLouisianacompanieshaveaplanandarecommittedto meetingthepowerneedsofourcustomersatareasonablecost.

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CONTENTS Contents........................................................................................................................................................3 Introduction..................................................................................................................................................5 IndustrialRenaissanceinLouisiana.................................................................................................6 MISOIntegration..............................................................................................................................6 BusinessCombinationofELLandEGSL...........................................................................................7 SystemAgreement...........................................................................................................................7 Part1:PlanningFramework..........................................................................................................................8 ResourceAdequacyRequirements..................................................................................................9 TransmissionPlanning.....................................................................................................................9 AreaPlanning.................................................................................................................................11 Part2:Assumptions....................................................................................................................................13 TechnologyAssessment.................................................................................................................13 DemandSideAlternatives.............................................................................................................16 NaturalGasPriceForecast.............................................................................................................17 CO2Assumptions...........................................................................................................................18 MarketModeling...........................................................................................................................18 Part3CurrentFleet&ProjectedNeeds.....................................................................................................20 CurrentFleet.................................................................................................................................20 LoadForecast.................................................................................................................................21 ResourceNeeds.............................................................................................................................23 TypesofResourcesNeeded...........................................................................................................27 Part4:PortfolioDesignAnalytics................................................................................................................28 MarketModeling...........................................................................................................................28 PortfolioDesign&RiskAssessment..............................................................................................29 SummaryofFindingsandConclusions..........................................................................................37 Part5:FinalReferenceResourcePlan&ActionPlan.................................................................................38 FinalReferenceResourcePlan.......................................................................................................38 ActionPlan.....................................................................................................................................42

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APPENDICES AppendixA ELLandEGSLGenerationResources AppendixB ActualHistoricLoadandLoadForecast AppendixC ResponsetoStakeholderComments AppendixD EntergyLongTermTransmissionPlan(ELLandEGSLProjects)

AppendixE 1stStakeholderMeetingCharts AppendixF AuroraDSMPortfoliosbyScenario AppendixG WindModelingAssumptions

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INTRODUCTION Thisreport,preparedinaccordancewiththeIntegratedResourcePlanningrulespromulgated by the Louisiana Public Service Commission (LPSC),1 describes the longterm integrated resourceplan(IRP)ofEntergyGulfStatesLouisiana,L.L.C.(EGSL)andEntergyLouisiana,LLC (ELL) (collectively referred to as the Companies) for the period 2015 - 2034. The plan reflectsimportantchangesintheCompaniesplanningandoperationsandgivesconsideration tothecurrentandexpectedeconomicenvironmentinLouisiana.Itshouldbenotedthatthe dataandassumptionsreflectedinthisIRPlargelyreflectthebestinformationavailableduring theinitialdevelopmentoftheDataAssumptionsforthedraftreportinlate2013early2014.

Duringthe18monthsoverwhichthisreportwasdeveloped,someinformation,forecasts,and assumptions may have changed. While this report does not attempt to address all such changes,keychangeshavebeennotedthroughoutthedocument.Asalongtermplanning document,theIRPisintendedtoprovideguidelinesforresourceplanninganddecisions,but actualdecisionswillbemadebasedonthebestinformationavailableatthetimesuchdecision ismade.

In addition to the economic outlook for the state, three recently completed or forthcoming initiativestheCompaniesparticipationintheMidcontinentIndependentSystemOperator (MISO)marketbeginningDecember19,2013,theCompaniesJointApplicationtocombine their respective assets and liabilities into a single operating company, and the proposed terminationoftheCompaniesparticipationintheEntergySystemAgreementonFebruary14, 2019haveimplicationsfortheCompaniesresourceneedsandsupplystrategy.Giventhe significanceofthesechangesontheCompanieslongtermcapacityandresourceneeds,this IRP addresses how the Companies plan to meet their customers power needs, both economicallyandreliably.

As discussed in this report, residential, commercial, and industrial load growth, unit deactivations,andpurchasedpoweragreement(PPA)expirations,willrequiretheCompanies toaddsignificanttransmissionandgenerationresourcesduringtheplanningperiod,including multiple generators in the 20192021 time frame. While additional generation will require substantialcapitalcommitmentsfromtheCompanies,theCompaniesdonotexpectthatthe generation additions will cause customer rates to increase materially. This is a result of increased consumption (i.e., greater kWh sales over which to spread fixed costs), improved portfolioefficiency,andexpirationofothercustomercharges,amongotherfactors.

1See,LPSCCorrectedGeneralOrderNo.R30021,Inre:DevelopmentandImplementationofRuleforIntegrated ResourcePlanningforElectricUtilities,datedApril20,2012.

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IndustrialRenaissanceinLouisiana AuniquesetofcircumstanceshasconvergedtogiveLouisianatheopportunitytodevelopand growitseconomyinwaysthatcanbenefititscitizensforgenerationstocome.Acombination offactors,includinglownaturalgaspricesresultingfromthedevelopmentofshalenaturalgas, lowelectricityprices,accesstoworldclassenergyinfrastructure,includingdeepwaterports, anextensiveinterstatepipelinenetworkandrelatedinfrastructure,anexperiencedworkforce, andaprobusinessenvironmenthaveresultedinanindustrialrenaissanceinLouisianathathas seen more than $50 billion in new capital investment and the creation of over 83,000 new directandindirectjobssince2008.

Thisindustrialrenaissanceisresultingin-andisprojectedtocontinuetoresultin-newor expandedindustrialfacilitiesconcentratedintheAmiteSouth2andtheWestoftheAtchafalaya Basin(WOTAB)3planningareas,wheretherecurrentlyaresubstantialsupplyrequirements thatrequirelocalgenerationyetlimitedavailableinregionpowersources.Morespecifically, theCompaniesexpectupto1,600megawatts(MW)ofindustrialloadgrowthintheirservice areas through 2019, and by 2034, after accounting for the deactivation of existing, older generationtheCompaniesexpecttorequireatleast8,000MWofadditionalcapacitytomeet demand.Thisindustrialloadgrowthisinadditiontoexpectedloadgrowthintheresidential and commercial sectors. Through the Power to Grow initiative, the Companies are demonstrating their commitment to meeting todays needs and anticipating the power demands of the future so Louisiana has the ample supply of clean, affordable and reliable powerneededtocapitalizeonthistremendouseconomicopportunity.

MISOIntegration The Companies, along with their affiliate Entergy Operating Companies (EOC), became market participants in MISO on December 19, 2013. MISO is a regional transmission organization(RTO)allowingtheCompaniesaccesstoalargestructuredmarketthatenhances theresourcealternativesavailabletomeetcustomerspowerneeds.Theavailabilityandprice ofpowerintheMISOmarketaffectstheCompaniesresourcestrategyandportfoliodesign.

Despite the significance of the move to MISO for the Companies and their customers, the Companiesretainresponsibilityforplanningtomeettheircustomerslongtermpowerneeds.

MISOconsiderationsareanelementofthisIRP.

2AmiteSouthistheareagenerallyeastoftheBatonRouge,Louisiana,metropolitanareatotheMississippistate lineandsouthtotheGulfofMexico.

3WOTABistheareagenerallywestoftheBatonRouge,Louisiana,metropolitanareatothewesternmostportion ofEGSLsserviceterritory.

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BusinessCombinationofELLandEGSL OnSeptember30,2014,theCompaniesfiledanapplication4withtheLPSCseekingapprovalof aproposaltocombinetheirrespectiveassetsandliabilitiesintoasingleoperatingcompany.

ThisIRPassumesthattheproposedcombinationwillbeapprovedandcompleted;5assuch,the IRPanalysiswasconducted,andtheresultsarereportedherein,onacombinedentitybasis.

However,becausetheCompaniescurrentlyusesubstantiallyidenticalplanningcriteriatoone anotherandtothoseusedforthecombinedentity,resultsoftheIRPanalysiswouldnotbe materiallydifferenthadtheanalysisbeenperformedseparatelyforeachoperatingcompany.A separately performed analysis for EGSL and ELL would result, over the longterm, in two portfoliosthatincombinationwouldincludesimilarelementstothefinalreferenceresource planforthecombinedentity.

SystemAgreement TheelectricgenerationandbulktransmissionfacilitiesoftheEOCsparticipatingintheEntergy SystemAgreementareoperatedonanintegrated,coordinatedbasisasasingleelectricsystem andarereferredtocollectivelyastheEntergySystem.

TheEOCsparticipatingtodayintheSystemAgreementareEGSL,ELL,EntergyMississippi,Inc.

(EMI),EntergyTexas,Inc.(ETI),andEntergyNewOrleans,Inc.(ENO).6OnFebruary14, 2014, EGSL and ELL provided written notice to the other EOCs of the termination of their participationintheSystemAgreement.7Inlightofthedecisiontoterminateparticipation,this IRP was prepared under the assumption that EGSL and ELL will no longer participate in the SystemAgreementasofFebruary14,20198.AlthoughtheeffectivedateoftheCompanies terminationofparticipationisuncertain,itisappropriatethatcurrentresourceplanningefforts acknowledgethatstandaloneoperationsareonthehorizon.ThisIRPisanassessmentofthe longtermresourceneedsoftheCompaniesthatmaybeusedtodevelopstrategicdirection andguidethedevelopmentofthefuturelongtermresourceportfolio.

4 Ex Parte: Potential Business Combination of Entergy Louisiana, LLC and Entergy Gulf States Louisiana, L.L.C.,

DocketNo.U33244.

5AnuncontestedstipulationrecommendingapprovaloftheBusinessCombinationwasfiledwiththeCommission onJuly13,2015,andasettlementhearingwasheldonJuly24,2015.TheCommissionisexpectedtoconsiderthe stipulationattheAugust2015BusinessandExecutiveSession.

6 Entergy Arkansas, Inc. (EAI), also an EOC, terminated its participation in the System Agreement effective December18,2013.

7EMIprovidednoticetotheEOCsthatitwouldterminateitsparticipationeffectiveNovember7,2015.ETIhas providednoticethatitwouldterminateitsparticipationonOctober1,2018(subjecttotheFERCsrulinginDocket No.ER1475000whichistheFERCproceedingfiledtoamendthenoticeprovisionsofSection1.01oftheSystem Agreement).

8EGSLsandELLsnoticewouldbeeffectiveFebruary14,2019orsuchotherdateconsistentwiththeFERCsruling inDocketNo.ER1475000.However,anearlierterminationmaybepossibleifagreeduponbytheparticipating EOCs.

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PART1:PLANNINGFRAMEWORK TheCompaniesplanningprocessseekstoaccomplishthreebroadobjectives:

Toservecustomerspowerneedsreliably; Toreliablyprovidepoweratthelowestreasonablesupplycost;and Tomitigatetheeffectsandtheriskofproductioncostvolatilityresultingfromfuelprice andpurchasedpowercostuncertainty,RTOrelatedchargessuchascongestioncosts, andpossiblesupplydisruptions.

Objectives are measured from a customer perspective. That is, the Companies planning processseekstodesignaportfolioofresourcesthatreliablymeetscustomerpowerneedsat thelowestreasonablesupplycostwhileconsideringrisk.

In designing a portfolio to achieve the planning objectives, the process is guided by the followingprinciples:

Reliability - adequate resources to meet customer peak demands with adequate reliability.

Base Load Production Costs - lowcost base load resources to serve base load requirements,whicharedefinedasthefirmloadlevelthatisexpectedtobeexceeded foratleast85%ofallhoursperyear.

LoadFollowingProductionCostandFlexibleCapability-efficient,dispatchable,load followingresourcestoservethetimevaryingloadshapelevelsthatareabovethebase load supply requirement, and also sufficient flexible capability to respond to factors suchasloadvolatilitycausedbychangesinweatherorbyinherentcharacteristicsof industrialoperations.

GenerationPortfolioEnhancement-agenerationportfoliothatavoidsanoverreliance onagingresourcesbyaccountingforfactorssuchascurrentoperatingrole,unitage, unitcondition,historicandprojectedinvestmentlevels,anduniteconomics,andtaking intoconsiderationthemannerinwhichMISOdispatchesunits.

PriceStabilityRiskMitigation-mitigationoftheexposuretopricevolatilityassociated withuncertaintiesinfuelandpurchasedpowercosts.

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SupplyDiversityRiskMitigation-mitigationoftheexposuretomajorsupplydisruptions thatcouldoccurfromspecificriskssuchasoutagesatasinglegenerationfacility.

ResourceAdequacyRequirements Asaloadservingentity(LSE)withinMISO,theCompaniesareandcontinuetoberesponsible formaintainingsufficientgenerationcapacitytomeettheminimumreliabilityrequirementsof theircustomers.UndertheMISOOpenAccessTransmission,Energy,andOperatingReserve Markets Tariff (MISO Tariff), the Companies meet resource adequacy requirements by providing resources necessary to meet or exceed a minimum planning reserve margin established for the Companies by MISO. Resource Adequacy is the process by which MISO ensuresthatparticipatingLSEsmaintainsufficientreliableanddeliverableresourcestomeet theiranticipatedpeakdemandplusanappropriatereservemargin.

UnderMISOsResourceAdequacyprocess,MISOannuallydetermines(byNovember1each year)theplanningreservemarginapplicabletoeachLocalResourceZone(LRZ)forthenext planning year (June - May). LSEs are required to provide planning resource credits for generationordemandsidecapacityresourcestomeettheirforecastedpeakloadcoincident withtheMISOpeakloadplustheplanningreservemarginestablishedbyMISO.Generation planningresourcecreditsaremeasuredbyunforcedcapacity(installedcapacitymultipliedby appropriate forced outage rate). The annual planning reserve margin for the LRZ which encompasses ELL and EGSL, as determined by MISO, sets the minimum required planning reserve margin9 the Companies must provide. For purposes of longterm planning, the Companieshavedeterminedthata12%reservemarginbasedoninstalledcapacityratingsand forecasted (noncoincident) firm peak load should be adequate to cover MISOs Resource Adequacy requirements and uncertainties such as MISOs future required reserve margins, generatorunitforcedoutagerates,andforecastedpeakloadcoincidencefactors.Also,after thebusinesscombination,a12%reservemarginprovidesenoughcapacitytocoverlossofthe Companieslargestgeneratingunitcontingency.

TransmissionPlanning The Companies transmission planning ensures that the transmission system (1) remains compliant with applicable NERC Reliability Standards and related SERC and local planning criteria,and(2)isdesignedtoefficientlydeliverenergytoendusecustomersatareasonable cost.SincejoiningMISO,theCompaniesplantheirtransmissionsysteminaccordancewiththe MISOTariff.Expansionof,andenhancementsto,transmissionfacilitiesmustbeplannedwellin

9InMISO,ResourceAdequacyreservemarginrequirementsareexpressedbasedonunforcedcapacityratingsand MISO System coincident peak load. Traditionally, the Companies and other LSEs have stated planning reserve requirementsbasedoninstalledcapacityratingsandforecasted(noncoincident)peakload.

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advanceof theneedforsuchimprovementsgiventhatregulatorypermittingprocessesand constructioncantakeyearstocomplete.Advancedplanningrequiresthatcomputermodelsbe usedtoevaluatethetransmissionsysteminfutureyearstakingintoaccounttheplanneduses ofthesystem,generationandloadforecasts,andplannedtransmissionfacilities.Onanannual basis, the Companies Transmission Planning Group performs analyses to determine the reliabilityandeconomicperformanceneedsoftheCompaniesportionoftheinterconnected transmissionsystem.TheprojectsdevelopedareincludedintheLongTermTransmissionPlan10 (LTTP)forsubmissiontotheMISOTransmissionExpansionPlanning(MTEP)processaspart of a bottomup planning process for MISOs consideration and review. The LTTP consists of transmission projects planned to be inservice in an ensuing 10year planning period. The projects included in the LTTP serve several purposes: to serve specific customer needs, to provide economic benefit to customers, to meet NERC TPL reliability standards, to facilitate incrementalblockloadadditions,andtoenabletransmissionservicetobesoldandgenerators tointerconnecttotheelectricgrid.

Withregardtotransmissionplanningaimedatprovidingeconomicbenefittocustomers,the Companieshaveplayed,andwillcontinuetoplay,anintegralroleinMISOstopdownregional economic planning process referred to as the Market Congestion Planning Study (MCPS),

whichisapartoftheMTEPprocess.MISOsMCPSreliesontheinputoftransmissionowners and other stakeholders, both with regard to the assumptions and scenarios utilized in the analysisandtheproposedprojectsintendedtobringeconomicvaluetocustomers.Basedon thisstakeholderinput,MISOevaluatestheeconomicbenefitsofthesubmittedtransmission projects,whileensuringcontinuedreliabilityofthesystem.TheintendedresultoftheMCPSisa projectorsetofprojectsdeterminedtobeeconomicallybeneficialtocustomersandthatis thereforesubmittedtotheMISOBoardofDirectorsforapproval.

The Companies continued involvement in the MCPS began with the 2014 process and the CompaniessubmissionofacollectionofprojectsforMISOsreview.Theresultofthe2014 MCPSincludedtheapprovalofaportfoliooffourprojectsinsoutheastLouisiana,calledthe Louisiana Economic Transmission Project (LETP).11 The LETP was identified following a substantial amount of economic analyses performed by the Companies and MISO and is an exampleofthetypeofeconomicplanningtheCompaniesanticipatewillcontinueasapartof MISO participation. The LETP, which the Companies presented to the Commission in a certification filing pursuant to LPSC General Order No. R26018, is anticipated to provide

10TheCompaniesmostrecentLTTPisincludedinAppendixD.

11TheMCPSalsoresultedintheidentificationoftwoeconomicallybeneficialprojectsinEAIsserviceterritory, whichwereapprovedbytheMISOBoardofDirectors.

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customerswithbenefitsexceedingsixtimesitsestimatedcostof$56.3million-benefitsthat aredirectlyrelatedtotheCompaniesparticipationintheMISOmarket.12 Additionally,EGSLrecentlyfiledanApplicationforcertificationpursuanttoLPSCGeneralOrder No. R26018 for a portfolio of four transmission projects referred to as the Lake Charles TransmissionProject(LCTP).13EntergyServices,Inc.(ESI)andMISOhavedeterminedthat theLCTPisthemosteffectiveprojecttomeetthereliabilityneedsoftheLakeCharlesareaand will be necessary to serve the forecasted load growth there by the summer of 2018. The portfoliooftransmissionprojectsthatcomprisetheLCTPiscurrentlyestimatedtocostupto

$187millionandwillprovidetheinjectionofanew500kilovolt(kV)transmissionsourceinto thearea.

Thereareapproximately200projectsinthecurrentLTTP,locatedthroughoutthefourstatesof theEntergyservicefootprint,withapproximately80projectsplannedforthestateofLouisiana.

AreaPlanning Althoughresourceplanningisperformedwiththegoalofmeetingtheplanningobjectivesat theoveralllowestreasonablesupplycost,physicalandoperationalfactorsdictatethatregional reliabilityneedsmustbeconsideredwhenplanningforthereliableoperationwithinthearea.

Thus,oneaspectoftheplanningprocessisthedevelopmentofplanningstudiestoidentify supplyneedswithinspecificgeographicareas,andtoevaluatesupplyoptionstomeetthose needs.

12 Joint Application Of Entergy Gulf States Louisiana, L.L.C. And Entergy Louisiana, LLC For Certification Of The LouisianaEconomicTransmissionProjectInAccordanceWithLouisianaPublicServiceCommissionGeneralOrder DatedOctober10,2013,filedApril21,2015,LPSCDocketNo.U33605.

13ApplicationOfEntergyGulfStatesLouisiana,L.L.C.ForCertificationOfTheLakeCharlesTransmissionProject In Accordance With Louisiana Public Service CommissionGeneral Order Dated October 10, 2013, filed June 16, 2015,LPSCDocketNo.U33645.

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Figure1:MapofLouisianaPlanningAreas

Forplanningpurposes,theregionservedbytheCompaniesisdividedintothreemajorplanning areasandonesubarea.Theseareasaredeterminedbasedoncharacteristicsoftheelectric system including the ability to transfer power between areas as defined by the available transfer capability, the location and amount of load, and the location and amount of generation.Thethreemajorplanningareasandsubareaarelistedbelow:

WestoftheAtchafalayaBasin(WOTAB)-theareagenerallywestoftheBatonRouge metropolitanarea.

Amite South - the area generally east of the Baton Rouge metropolitan area to the Mississippistateline,andtheareasouthtotheGulfofMexico.

DownstreamofGypsy(DSG)-asubareaencompassingtheSoutheastportion ofAmiteSouth,generallyincludingtheareadownriveroftheLittleGypsyplant includingmetropolitanNewOrleanssouthtotheGulfofMexico.

Central - the remainder of Louisiana north of the WOTAB and Amite South areas, includingtheBatonRougemetropolitanarea.

Asdescribedlaterinthisreport,separateassessmentsoftheAmiteSouthandWOTABplanning areasindicateaneedforadditionalresourcesinthoseplanningareasearlyinthenextdecade.

The near term needs are largely driven by the increase in load resulting from the Louisiana

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industrialrenaissanceandexpiringPPAs,butresourceneedsovertheplanninghorizonarealso significantlyinfluencedbyunitdeactivations.

PART2:ASSUMPTIONS TechnologyAssessment AspartofthisIRPprocess,a2014TechnologyAssessmentwaspreparedtoidentifypotential supplysideresourcealternativesthatmaybetechnologicallyandeconomicallysuitedtomeet customer needs. The initial screening phase of the Technology Assessment reviewed the supplyside generation technology landscape to identify resource alternatives that merited more detailed analysis. During the initial phase, a number of resource alternatives were eliminatedfromfurtherconsiderationbasedonarangeoffactorsincludingtechnicalmaturity, stageofcommercialdevelopment,andeconomics.Theseresourcealternativeswillcontinueto bemonitoredforpossiblefuturedevelopment.Thefollowingresourcealternativeswerefound appropriateforfurtheranalysis:

PulverizedCoalSupercriticalPulverizedCoalwithcarboncapture(PCwithCC)

NaturalGasFiredalternatives o SimpleCycleCombustionTurbines(CT) o CombinedCycleGasTurbines(CCGT) o SmallScaleAeroderivatives o LargeScaleAeroderivatives Nuclear-(GenerationIIITechnology)

Renewables o Biomass o OnshoreWindPower o SolarPhotovoltaic(PV)

Upon completion of the screening level analysis, more detailed analysis (including revenue requirementsmodelingofremainingresourcealternatives)wasconductedacrossarangeof operatingrolesandunderarangeofinputassumptions.Theanalysisresultedinthefollowing conclusions:

14

Among conventional generation resource alternatives, CCGT and CT technologies are the most attractive. The gasfired alternatives are economically attractive across a rangeofassumptionsconcerningoperationsandinputcosts.

New nuclear and new coal alternatives are not economically attractive nearterm options relative to gasfired technology. The low price of gas and the uncertainties aroundemissionsregulationmakecoaltechnologiesunattractive.Nucleariscurrently unattractiveduetobothcapitalandregulatoryrequirements.

Despiterecentdeclinesinthecapitalcostandimprovementsofrenewablegeneration alternatives, they are still less economically attractive compared to CCGT and CT alternativesdueto:

o Declinesinthelongtermoutlookfornaturalgaspricesbroughtonbytheshale gasboom; o Uncertainty about the renewal of production tax credits and investment tax creditsthatareapplicabletoresourcescompletedbeforetheendof2016;and o Theuncertainneartermoutlookforemissionsregulation.

Amongrenewablegenerationalternatives,windandsolararethemostlikelytobecome costcompetitive.However,uncertaintieswithrespecttovariousrenewablegeneration tax credit extensions, capacity credits allowed for these resources by MISO, and implementationandtimingofCO2regulationsforfossilfuelresourcealternativeslikely will affect the competitiveness of renewable resource alternatives. MISO determines thecapacityvalueforwindgenerationbasedonaprobabilisticanalyticalapproach.The applicationofthisapproachresultedinacapacityvalueofapproximately14.1%forthe 201415planningyear.Furthermore,thefootprintoftheCompaniesisnotfavorable forwindgeneration.Thetransmissioncosttoserveloadwithwindpowerfromremote resources will further worsen the economics of wind compared to conventional resources.InMISO,solarresourcesreceivenocapacitycreditwithinthefirstyearof operation. Solarpowered resources must submit all operating data for the prior summerwithaminimumof30consecutivedaystohavetheircapacityregisteredwith MISO.

Table 1 summarizes the results of the Technology Assessment for a number of resource alternatives.

15

Table1:2014TechnologySensitivityAssessment BasedonGenericCostofCapital14

NoCO2($/MWh)

CO2Beginning2023($/MWh)

Technology Capacity Factor15 Reference Fuel HighFuel LowFuel Reference Fuel HighFuel LowFuel FFrameCT 10%

$198

$224

$179

$204

$230

$184 FFrameCTw/SelectiveCatalyticReduction 20%

$141

$167

$121

$146

$173

$126 EFrameCT 10%

$240

$274

$215

$247

$281

$222 LargeAeroderivativeCT 40%

$108

$131

$91

$113

$136

$95 SmallAeroderivativeCT 40%

$125

$150

$106

$130

$156

$112 InternalCombustion 40%

$115

$137

$99

$120

$141

$104 2x1FFrameCCGT 65%

$79

$97

$67

$83

$100

$70 2x1FFrameCCGTw/Supplemental 65%

$75

$93

$61

$78

$97

$65 2x1GFrameCCGT 65%

$76

$93

$63

$79

$96

$67 2x1GFrameCCGTw/Supplemental 65%

$72

$90

$59

$76

$94

$63 1x1FFrameCCGT 65%

$82

$100

$69

$86

$104

$73 1x1JFrameCCGT 65%

$73

$90

$61

$77

$93

$65 1x1JFrameCCGTw/Supplemental 65%

$72

$132

$59

$76

$136

$63 PulverizedCoalw/CarbonCapturingSequestration 85%

$163

$230

$94

$165

$232

$96 Biomass 85%

$175

$321

$142

$175

$321

$142 Nuclear 90%

$157

$169

$157

$169

$157 Wind16 34%

$109

$109 Windw/ProductionTaxCredit 34%

$102

$102 SolarPV(fixedtilt)17 18%

$190

$190 SolarPV(tracking)18 21%

$179

$179 BatteryStorage19 20%

$217

14Ageneraldiscountrate(7.656%)wasusedinordertoaccuratelymodeltheseresourcesintheMarketModelingstageoftheIRP.

15Assumptionusedtocalculatelifecycleresourcecost.

16Includescapacitymatchupcostof$18.76/MWhduetowinds14.1%capacitycreditinMISO.

17Includescapacitymatchupcostof$30.93/MWhassuminga25.0%capacitycreditinMISO.

18Includescapacitymatchupcostof$26.51/MWhassuminga25.0%capacitycreditinMISO.

19Includescostof$25/MWhrequiredtochargebatteries.

16

DemandSideAlternatives The Companies engaged the services of ICF International to assess the marketachievable potentialforDemandSideManagement(DSM)programsthatcouldbedeployedoverthe planninghorizon.Intotal,1,097measureswereevaluated,ofwhich896wereconsideredcost effectivewithaTotalResourcesCost(TRC)testresultof1.0orbetter.Thesemeasureswere thencollectedinto24DSMprogramstobeassessedintheIRPprocess.ThePotentialStudy estimatedthepeakload,annualenergyreduction,andprogramcoststhatresultfromalow, reference,andhighlevelofspendingonprogramincentives.Thereferencecaseestimateof DSMpotentialindicatesapproximately673MWofpeakdemandreductioncouldbeachieved by2034iftheCompaniesinvestmentinDSMwassustainedfora20yearperiod.

ThemethodologyofthePotentialStudywasconsistentwithaprimaryobjectivetoidentifya wide range of DSM alternatives available to meet customers needs. In this way, the study resultshelpedensurethatmoreDSMprogramswouldbeidentifiedforfurtherevaluationin theIRP.

DSM program costs utilized in the IRP include incentives paid to participants and program deliverycostssuchasmarketing,training,andprogramadministration.Programdeliverycosts wereestimatedtoreflectaverageannualcostsoverthe20yearplanninghorizonoftheDSM Potential Study. The costs reflect an assumption that over the planning horizon, program efficiencieswillbeachievedresultinginlowerexpectedcosts.Thatis,asexperienceisgained withcurrentandfutureprograms,actualcostmaydecreaseovertime.Assuch,actualnear termcostsassociatedwithcurrentandfutureprogramsmaybehigherthantheassumptions usedtodeterminetheoptimalcosteffectivelevelidentifiedintheCompaniesFinalReference Resource Portfolio Plan. Therefore, future DSM program goals and implementation plans shouldreflectthisuncertainty.TheIRPassumptionsfortheDSMprogramcostestimatesas compared to the cost of typical supplyside alternatives are included in the DSM Technical SupplementtotheIRP.

17

NaturalGasPriceForecast SystemPlanningandOperations20(SPO)preparedthenaturalgaspriceforecast21usedinthe 2015IRP.TheneartermportionofthenaturalgasforecastisbasedonNYMEXHenryHub forwardprices,whichserveasanindicatorofmarketexpectationsoffutureprices.Because theNYMEXfuturesmarketbecomesincreasinglyilliquidasthetimehorizonincreases,NYMEX forward prices are not a reliable predictor of future prices in the longterm. Due to this uncertainty,SPOpreparesalongtermpointofview(POV)regardingfuturenaturalgasprices utilizinganumberofexpertconsultantforecaststodetermineanindustryconsensusregarding longtermprices.

ThelongtermnaturalgasforecastusedintheIRPincludessensitivitiesforhighandlowgas pricestosupportanalysisacrossarangeoffuturescenarios.Indevelopinghighandlowgas pricePOVs,SPOutilizesseveralconsultantforecaststodeterminelongtermpriceconsensus.

TheseforecastsareshownintheTablebelow.

Table2:HenryHubNaturalGasPriceForecasts HenryHubNaturalGasPrices

Nominal$/MMBtu Real2014$/MMBtu

Low Reference High Low Reference High RealLevelized,22 (20152034)

$4.57

$5.77

$9.72

$3.84

$4.87

$8.17 Average(2015 2034)

$4.82

$6.28

$10.79

$3.66

$5.00

$8.08 20YearCAGR 2.5%

3.1%

6.2%

0.4%

1.0%

4.1%

20SystemPlanningandOperationsisadepartmentwithinESItaskedwith:(1)theprocurementoffossilfueland purchased power, and (2) the planning and procuring of additional resources required to provide reliable and economicelectricservicetotheEOCscustomers.SPOalsoisresponsibleforcarryingoutthedirectivesofthe OperatingCommitteeandthedailyadministrationofaspectsoftheEntergySystemAgreementnotrelatedto transmission.

21TheforecastwaspreparedfromtheJuly2014gaspriceforecastwhichistheCompanieslatestofficialforecast andwasincludedintheCompaniesNovember3,2014UpdatedIRPInputsfiling.

22Reallevelizedpricesrefertothepricein2014$wheretheNPVofthatpricegrownwithinflationoverthe 20152034periodwouldequaltheNPVoflevelizednominalpricesoverthe20152034period.

18

Thenaturalgasforecastsabovedonotattempttoforecasttheeffectsoftheshorttermnatural gashedgingprogramscurrentlyemployedbytheCompanies.Thecurrentgashedgingprogram attemptstomitigateshorttermgaspricevolatility.However,giventheshorttermnatureof thegashedgingprogram,thereisnoeffectonthelongtermgaspricesexperiencedbythe Companies.TheCompanieshaveevaluatedandcontinuetoevaluateopportunitiesthatwould, onalongertermbasis,helpstabilizegaspricesandofferthepotentialforsavingsrelativeto gas prices that may exist in the future. The Companies also note that the Commission has approvedalongtermgashedgingpilotprograminGeneralOrderNo.R32975.However,no adjustmentsarewarrantedtotheCompanieslongtermnaturalgasforecastsatthistime.If the Commission approves any longterm gas transactions for the Companies, the expected price from such transactions will be considered in the Companies future resource planning decisions.

CO2Assumptions Atthistime,itisnotpossibletopredictwithanydegreeofcertaintywhethernationalCO2 legislationwilleventuallybeenacted,andifitisenacted,whenitwouldbecomeeffective,or whatformitwouldtake.Inordertoconsidertheeffectsofcarbonregulationuncertaintyon resourcechoiceandportfoliodesign,theIRPprocessreliedonarangeofprojectedCO2cost outcomes.ThelowcaseassumesthatCO2legislationdoesnotoccuroverthe20yearplanning horizon. The reference case assumes that a cap and trade program starts in 2023 with an emission allowance cost of $7.54/U.S. ton and a 20152034 levelized cost in 2014$ of

$6.83/U.S. ton.23 The high case assumes that a cap and trade program starts in 2023 at

$22.84/U.S.tonwitha20152034levelizedcostin2014$of$14.61/U.S.ton.

MarketModeling AuroraModel ThedevelopmentoftheIRPreliedontheAURORAxmpElectricMarketModel(AURORA)to simulate market operations and produce a longterm forecast of the revenues and cost of energyprocurementfortheCompanies.24 AURORA25isaproductioncostmodelandresourcecapacityexpansionoptimizationtoolthat usesprojectedmarketeconomicstodeterminetheoptimallongtermresourceportfoliounder

23Includesadiscountrateof7.656%.

24TheAURORAmodelreplacesthePROMODIVandPROSYMmodelsthattheCompaniespreviouslyused.

25TheAURORAmodelwasselectedfortheIRPandotheranalyticworkafteranextensiveanalysisofelectricity simulationtoolsavailableinthemarketplace.AURORAiscapableofsupportingavarietyofresourceplanning

19

varying future conditions including fuel prices, available generation technologies, environmental constraints, and future demand forecasts. AURORA estimates price and dispatch using hourly demands and individual resourceoperating characteristics in a transmissionconstrained, chronological dispatch algorithm. The optimization process within AURORA identifies the set of resources among existing and potential future demand and supplyside resources with the highest and lowest market values to produce economically consistentcapacityexpansion.AURORAchoosesfromnewresourcealternativesbasedonthe net real levelized values per MW (RLV/MW) of hourly market values and compares those valuestoexistingresourcesinaniterativeprocesstooptimizethesetofresources.

Scenarios26 IRPanalyticsreliedonfourscenariosdesignedtoassessalternativeportfoliosacrossarangeof outcomes.Thefourscenariosare:

IndustrialRenaissance(Reference)-AssumestheU.S.energymarket(particularlyasit affects the Gulf Coast region and Louisiana) continues with reference fuel prices.

Currentfuelpricesdriveconsiderableloadgrowthandeconomicopportunityespecially in the industrial class. The Industrial Renaissance scenario assumes reference load, referencegas,andnoCO2costs.

BusinessBoom-AssumestheU.S.energyboomcontinueswithlowgasandcoalprices.

Low fuel prices drive high load growth especially in the industrial class, but with residential and commercial class spillover benefits. As a result of the industrial load growthandlowfuelprices,powersalesincreasesignificantly.AmodestCO2taxorcap andtradeprogramisimplementedandiseffectivein2023.

Distributed Disruption - Assumes states continue to support distributed generation.

Consumersandbusinesseshaveagreaterinterestininstallingdistributedgeneration, whichleadstoadecreaseinenergydemand.Overalleconomicconditionsaresteady with moderate GDP growth, which enables investment in energy infrastructure.

However,naturalgaspricesaredrivenhigherbyEPAregulationofhydraulicfracturing.

CongressortheEPAalsoimplementsamoderateCO2taxorcapandtradeprogram.

activitiesandiswellsuitedforscenariomodelingandriskassessmentmodeling.Itiswidelyusedbyloadserving entities,consultants,andindependentpowerproducers.

26ThefourscenariosandtheirgeneralassumptionshaveremainedconstantthroughouttheIRPprocess.However, intheNovember2014filing,twoofthescenarioswererenamedfromtheMay2014filing.ScenarioOnewas renamedIndustrialRenaissance.TheIndustrialRenaissanceScenariointheMay2014wasrenamedBusiness BoomintheNovember2014filing.

20

Generation Shift - Assumes government policy and public interest drive support for governmentsubsidiesforrenewablegenerationandstrictrulesonCO2emissions.High naturalgasexportsandmorecoalexportsleadtohigherfuelprices.

Each scenario was modeled in Aurora. The resulting market modeling, which included projected power prices, provided a basis for assessing the economics of longterm (here, twentyyears)resourceportfolioalternatives.

Table3:SummaryofKeyScenarioAssumptions SummaryofKeyScenarioAssumptions

Industrial Renaissance (Ref.Case)

BusinessBoom Distributed Disruption Generation Shift ElectricityCAGR (EnergyGWh)27

~1.45%

~1.70%

~0.90%

~1.20%

PeakLoadGrowth CAGR

~1.05%

~1.10%

~0.75%

~0.85%

HenryHubNatural GasPrice($/MMBtu)

ReferenceCase

($4.87levelized 2014$)

LowCase

($3.84levelized 2014$)

ReferenceCase

($4.87levelized 2014$)

HighCase

($8.17levelized 2014$)

CO2Price($/short ton)

LowCase:

None ReferenceCase:

Capandtrade startsin2023

$6.83levelized 2014$

Capandtrade startsin2023

$6.83levelized 2014$

Capandtrade startsin2023

$14.61levelized 2014$

PART3:CURRENTFLEET&PROJECTEDNEEDS CurrentFleet Currently,theCompaniestogethercontrolapproximately10,561MWofgeneratingcapacity either through ownership or longterm power purchase contract. Appendix A provides an overview of the Companies current active generation portfolio. Table 4 shows the supply resourcesbyfueltypemeasuredininstalledMWwithpercentagesforELLandEGSLseparately and for the combined company. It is important to note that some of the amounts below represent resources that are not owned by the Companies but instead are under contract through PPAs. As reflected on Table 4 and Appendix A, roughly onehalf of the current combinedresourceportfoliosarefromlegacygasgenerationwhichhasbeeninservicefor40

27Allcompoundannualgrowthrates(CAGRs)inthistable:20152034(20Years)forthemarketmodeledin AURORA.

21

60years.WhiletheCompanieshavemadeandwillcontinuetomakeeconomicinvestmentsto extendtheservicelifeofthesegenerators,manyofthesegeneratorsareassumedtodeactivate over the planning horizon and these unit deactivations are a significant driver of the Companiesneedforadditionalgenerationregardlessofanyassumedloadgrowth.

Table4:2014EGSLandELLCombinedResourcePortfolio

Inaddition,theCompaniesaddedanewCCGTfacility,Ninemile6,totheportfolioinDecember 2014.Ninemile6isa561MWCCGTresourcelocatedinWestwego,LouisianaattheNinemile PointStationinJeffersonParish.TheCompaniesreceivedCommissionapprovaltoconstruct thisnewCCGTgeneratingfacility,thecurrentlyestimatedcostofwhichis$655million.29

LoadForecast Awiderangeoffactorslikelywillaffectelectricloadinthelongterm,including:

Levelsofeconomicactivityandgrowth; The potential for technological change to affect the efficiency of electric consumption; Potential changes in the purposes for which customers use electricity (e.g., the adoptionofelectricvehicles);

28TotalresourcesincludetheadditionofNinemile6.

29ExParte:JointApplicationofEntergyLouisiana,LLCforApprovaltoConstructUnit6atNinemilePointStation andofEntergyGulfStatesLouisiana,L.L.C.forApprovaltoParticipateinaRelatedContractforthePurchaseof CapacityandElectricEnergy,forCostRecoveryandRequestforTimelyRelief,OrderNo.U31971(April5,2012).

2014EGSLandELLCombinedResourcePortfolio

ELL

EGSL

Combined

MW MW MW Coal 32 1

367 9

399 4

Nuclear 1,609 24 390 9

1,999 19 Combined CycleGas Turbine(CCGT) 1,289 20 1,036 26 2,325 22 OtherGas 3,479 53 2,173 54 5,652 54 Hydro&Other 125 2

61 2

186 2

Total 6,534

4,027

10,56128

22

The potential adoption of enduse (behindthemeter) selfgeneration technologies(e.g.,rooftopsolarpanels);and Thelevelofenergyefficiency,conservationmeasures,anddistributedgeneration (e.g.,rooftopsolarpanels)adoptedbycustomers.

Suchfactorsmayaffectboththelevelandshapeofloadinthefuture.Peakloadsmaybe higherorlowerthanprojectedlevels.Similarly,industrialcustomerloadfactorsmaybehigher orlowerthancurrentlyprojected.Uncertaintiesinloadmayaffectboththeamountandtype ofresourcesrequiredtoefficientlymeetcustomerneedsinthefuture.

In order to consider the potential implications of load uncertainties on longterm resource needs,fourloadforecastscenarioswerepreparedfortheIRP,whicharedescribedbelow:

IndustrialRenaissance-Referenceload AssumesIndustrialRenaissancewillhaveamultipliereffectthatwillspurloadgrowthin residential,commercial,andgovernmentclasses(referredtoasaneconomicmultiplier)and includesadditionalindustrialgrowthstemmingfromtheregionalIndustrialRenaissance.

BusinessBoom Assumes higher economic multiplier effect, a lower risk adjustment to future industrial projects,andanincreaseinthenumberofindustrialprojectsthatareincludedinforecast.

DistributedDisruption Decrements the Reference load scenario for Combined Heat and Power (CHP) impactand distributedsolarphotovoltaicsystem(PV)impact.

GenerationShift Assumes no economic multiplier effect, no commercial conversions, and fewer industrial projects.

Methodology SPOusedthesameloadforecastingprocessasdescribedinpreviousIRPsdevelopedforthe Companies.ThatprocessusescomputersoftwarefromItrontodevelopa20year,hourby hour load forecast. The MetrixND30 and the MetrixLT'31 programs are used widely in the

30MetrixNDbyITronisanadvancedstatisticsprogramforanalysisandforecastingoftimeseriesdata.

23

utilityindustry,tothepointwheretheymaybeconsideredanindustrystandardforenergy forecasting,weathernormalization,andhourlyloadandpeakloadforecasting.

To develop the load forecast, SPO allocates the Retail Energy Forecast (by month) and the WholesaleEnergyForecast(bymonth)toeachhourofa20yearperiodbasedonhistoricalload shapesdevelopedbyESIsLoadResearchDepartment.Fifteenyeartypicalweatherisusedto converthistoricloadshapesintotypicalloadshapes.Forexample,iftheactualsalesforan EOCs residential customers occurred during very hot weather conditions, the typical load shapewouldflattenthehistoricloadshape.Iftheactualweatherweremild,thetypicalload shapewouldraisethehistoricloadshape.EachcustomerclassineachEOCrespondsdifferently toweather,soeachhasitsownweatherresponsefunction.MetrixNDisusedtoadjustthe historicalloadshapesbytypicalweather,andMetrixLT'isusedtocreatethe20year,hourly loadforecast.

Theloadforecastisgrosseduptoincludeaveragetransmissionanddistributionlinelosses.The Companieshaveuniquelossfactorsthatareappliedtoeachrevenueclassaftertheforecastis developedandafteraccountingforenergyefficiency.Forexample,whenlinelossesareadded intotheCompaniesforecastsELLsresidentialclassisgrossedupbyadifferentamountthan EGSLsresidentialclass.

Cogeneration loads are included in the Industrial revenue class and a separate peak is not developedforthesecustomersastheirloadscanbeirregular.Econometricmodelsareusedto developtheenergyforecastforcogenerationloadswhicharethencombinedwithbothlarge andsmallindustrialcustomerstocreatetheIndustrialenergyforecast.Interruptionsarein historical data that the forecast models use, but customer specific interruptions are not forecastedastheinterruptionsareirregular.

Energy savings from companysponsored DSM programs are decremented from the Retail energyforecast.Theloadforecastusesthedecrementedenergyforecasttodevelopannual peaksthatreflectthesavingsfromsuchprograms.

ResourceNeeds OvertheIRPperiod,theCompanieswillneedtoaddresources.Thelongtermresourceneeds areprimarilydrivenbyloadgrowthexpectations,unitdeactivationassumptions,andexisting PPAcontractterminationsandexpirations.ForthepurposeofdevelopingthisIRP,assumptions mustbemadeaboutthefutureofgeneratingunitscurrentlyintheportfolio.

31MetrixLT'byITronisaspecializedtoolfordevelopingmediumandlongrunloadshapesthatareconsistentwith monthlysalesandpeakforecasts.

24

Assumptions made for the IRP are not final decisions regarding the future investment in resources.Unitspecificportfoliodecisions,suchassustainabilityinvestments,environmental complianceinvestments,orunitretirements,arebasedoneconomicandtechnicalevaluations consideringsuchfactorsasprojectedforwardcosts,anticipatedoperatingroles,andthecostof supplyalternatives.Thesefactorsaredynamic,andasaresult,actualdecisionsmaydifferfrom planning assumptions as greater certainty is gained regarding requirements of legislation, regulation,andrelativeeconomics.

Basedoncurrentassumptions,anumberoftheCompaniesexistingfossilgeneratingunitsmay bedeactivatedduringtheIRPplanningperiod.Inaddition,variousPPAsthattheCompanies havepreviouslyenteredintowillexpire.Intheyears20152034,thetotalnetreductioninthe CompaniesgeneratingcapacityfromtheseassumedunitdeactivationsandPPAterminations and expirations is approximately 6,859 MW relative to the Companies current combined resourcesofapproximately10,561MW.

IncludedinthisamountistheeffectoftheterminationofthePPAsenteredbetweenEGSLand ETIpursuanttotheJurisdictionalSeparationPlan(JSP)thatledtotheseparationofEntergy GulfStates,Inc.intoEGSLandETI.ThosePPAsarereferredtohereinastheJSPPPAs.32This IRPassumesthattheJSPPPAswillterminatewhenETIorEGSLterminatesparticipationinthe SystemAgreement,asprovidedforintheLPSCsorderregardingtheJSP.33Theoverallnet effect would reduce EGSLs portfolio position by roughly 700MW in 2018 based on ETIs terminatingparticipation34intheSystemAgreementonOctober18,2018.

Moreover,inthecomingyears,theCompanieswillfacetheneedforadditionalresourcesto meetloadgrowth.Theloadforecastnecessarilyhaschangedduringthe18monthperiodin whichthisIRPwasdevelopedandcanbeexpectedtochangeinthefuture.Ascontemplated

32AsaresultoftheimplementationoftheJSPtoseparateEntergyGulfStates,Inc.(EGSI)intoseparateTexas andLouisianacompanies,ETIandEGSL(successorsininteresttoEGSI)currentlysharecertaincapacityinTexas andLouisiana.Thiscapacityissharedthroughcostbasedpurchasesandsalesmadepursuanttopurchasedpower agreementsunderServiceScheduleMSS4oftheEntergySystemAgreement.Specifically,EGSLsellstoETI42.5%

of the capacity and related energy of the following resources: (1) Willow Glen and Nelson; (2) Calcasieu; (3)

Perryville;and(4)RiverBend.ETIsellstoEGSL:(1)57.5%ofthecapacityandrelatedenergyassociatedwithits LewisCreekandSabineresources;and(2)50%ofthecapacityandrelatedenergyassociatedwiththeCarville resource. A subset of these PPAs, referred to as the JSP PPAs, will terminate upon ETIs termination of its participationintheSystemAgreement.TheseJSPPPAsincludetheMSS4PPAsassociatedwiththeWillowGlen, Nelsongas,LewisCreek,Sabine,andCalcasieugeneratingunits.SeealsoLPSCOrderNos.U21453,U20925,and U22092SubdocketJ,Inre:RequestfortheApprovaloftheJurisdictionalSeparationPlanforEntergyGulfStates, Inc.,datedJanuary31,2007,at20.

33Inre:RequestfortheApprovaloftheJurisdictionalSeparationPlanforEntergyGulfStates,Inc.,OrderNos.U 21453,U20925andU22092(SubdocketJ),Orderatp.20(Jan.31,2007).

34ETIprovidednoticetotheEOCsofitsintenttoterminateitsparticipationintheSystemAgreementeffective October18,2018.

25

bytheIndustrialRenaissanceScenario(referencecase),theareasservedbytheCompaniesare experiencing a heightened level of economic development activity stemming from the availabilityoflowcostnaturalgasandeffortsbytheStateofLouisianatoaddjobsandgrow the economy through attracting new and expanded industrial facilities. As such, in the referencecase,theCompaniesloadsareprojectedtoreachapproximately11,200MWby2019 (a15%increaseoverthecurrentcombinedlevelofapproximately9,600MW),whichreflects the addition of approximately 1,600 MW of industrial facilities by 2019. By 2025, the Companies total reference load is projected to increase approximately 1,760 to 2,200 MW fromthepresentcombinedlevel.ThefollowingTablesummarizestheprojectedpeakforecast increasefortheCompaniesoverthenext20years(20152034)byscenario.

Table5:ELLandEGSLProjectedPeakForecastIncreasefrom2015

Industrial Renaissance (MWs)

BusinessBoom (MWs)

Distributed Disruption(MWs)

GenerationShift (MWs)

By2034 2,226 2,626 1,507 1,751

InbothAmiteSouthandWOTAB,currentsupplyneedsrequirelocalgeneration,yetthereare limitedavailablepowersourcesthatexistwithineachoftheregions.AmiteSouthisasupply constrainedregionthat,basedonprojectedloadgrowth,unitretirements,andPPAexpirations, may require new resources every five years in order to continue meeting reliability needs withinitsloadpocket.35Theindustrialloadgrowthintheregionfurtherincreasesthisneed.In theIndustrialRenaissanceScenario,theAmiteSouthregionspeakloadisexpectedtogrowby approximately10%(500MW)toatotalofapproximately6,000MWby2019.Inotherwords, resourcesneedtobeplannedandbroughtonlineinanorderlysequencetomaintainadequate capacityandstabilityandsupporttheregionsgrowingload.

SeparatefromtheAmiteSouthregion,theWOTABregionisexpectedtoexperiencesignificant industrial load growth under the Industrial Renaissance Scenario. EGSLs load in WOTAB is anticipatedtoincreasebyapproximately70%(800MW)toatotalofapproximately1,900MW by2019.AsubstantialportionoftheexpectedgrowthinloadwillbecenteredaroundLake Charles. The concentration of load within the Lake Charles area is expected to result in the creationofaloadpocketwithintheplanningregion,whichwillrequireadditionalresourcesas loadcontinuestogrow.

35Loadpocketsareareasofthesystemwherelocalgenerationalongwithtransmissionimportcapabilityisneeded toservetheloadreliablywithinthearea.

26

Asdiscussedlaterinthisreport,theseincreasesinresidential,commercial,andindustrialload, andunitdeactivationsandPPAexpirationswillrequiretheCompaniestoaddresourcestomeet theloadandmaintainreliability.Thereisexpectedtobealimitedeffectoncustomerrates, however,becauseoftheincreaseincustomerkWhusageoverwhichthefixedcostsofthenew resources are spread, portfolio efficiency improvements, and expiration of other customer chargesamongotherfactors.

As shown in Tables 6 and 7 below, by 2034, the combination of load growth, resource deactivations and PPA contract expirations may result in approximately 9.5 GW of capacity neededfortheIndustrialRenaissanceScenario.By2024,thecapacitydeficitcouldbeashighas 3.6GWunderthecurrentloadforecastsandresourcedeactivationandexpirationassumptions.

Table6:ResourceNeedsbyScenario(MWs)

Includes12%planningreservemargin CapacitySurplus/(Need)(BeforeIRPAdditions)

Industrial Renaissance BusinessBoom Distributed Disruption Generation Shift By2024 (3,601)

(4,039)

(3,173)

(2,980)

By2034 (9,536)

(9,999)

(8,695)

(8,913)

Table7:In

Thereare In D

S tr

Typeso In order Compani andtype sufficient described ndustrialRen eanumber ncrementall o SelfS o Acqui o Long

DemandSide hortterm c ransactions.

ofResource to reliably iesmustma esofcapacit t generating dabove,the naissance20 ofalternativ ongtermre upplyaltern sitions TermPPAsa ealternatives capacity pu esNeeded meet the p aintainapo ty.Withres g capacity t eCompanies YearProjecte vestoaddre esourceaddi natives andrenewa s

urchases in d

power needs rtfolioofge specttothe o meet the sneedtopla

edCapacityN sstheresou itionsinclud ls MISO Pla s of custom enerationre amountof ir peak load anforresou Need(GW) urceneeds,i ing:

nning Reso mers at the esourcestha capacity,th ds plus a p urcestomee ncluding:

ource Auctio lowest reas atincludest heCompanie lanning rese ettheannua on or bila sonable cost therightam esmustmai erve margin alreservem

27

ateral t, the mount ntain

n. As margin

28

mandated by MISO, which is assumed to be 12% for longterm planning. In general, the Companiessupplyroleneedsinclude:

BaseLoadexpectedtooperateinmosthours.

LoadFollowingcapableofrespondingtothetimevaryingneedsofcustomers.

PeakingandReserveexpectedtooperaterelativelyfewhours,ifatall.

Table8:ProjectedResourceNeedsin2034bySupplyRoles(withoutPlannedAdditions)inIndustrial RenaissanceScenario

Need Resources Surplus/

(Deficit)

BaseLoad(MW) 7,948 2,399 (5,549)

LoadFollowing(MW) 2,257 1,270 (987)

Peaking&Reserve(MW) 3,341 341 (3,000)

Totals 13,546 4,010 (9,536)

Table8showsthatforbothCompanies,thesupplyrolewiththegreatestneedisbaseload.

Peakingresourceswillalsobeneededwithinthe20yearplanninghorizon.

PART4:PORTFOLIODESIGNANALYTICS TheIRPutilizedatwostepapproachtoconstructandassessalternativeresourceportfoliosto meetthecustomerneeds:

1. MarketModeling

2. PortfolioDesign&RiskAssessment MarketModeling ThefirststeptodevelopwithintheAURORAmodelisaprojectionofthefuturepowermarket foreachofthefourscenarios.ThisprojectionlooksatthepowermarketfortheentireMISO footprintexcludingLouisianatogainperspectiveonthebroadermarketoutsidethestate.The purpose of this step was to provide projected power prices to assess potential portfolio strategieswithineachscenario.Inordertoachievethis,assumptionswererequiredaboutthe futuresupplyofpower.TheprocessfordevelopingthoseassumptionsreliedontheAURORA

29

CapacityExpansionModeltoidentifytheoptimalsetofresourceadditionsinthemarketto meet reliability and economic constraints. Resulting assumptions regarding new capacity additionsineachscenarioaresummarizedinTable9.

Table9:ResultsofMISOMarketModeling ResultsofMISOMarketModeling(MISOFootprint,excludingLouisiana)

IncrementalCapacityMixbyScenario

Industrial Renaissance (Ref.Case)

Business Boom Distributed Disruption Generation Shift CCGT 52%

91%

98%

53%

CT 48%

9%

2%

1%

Wind 0%

0%

31%

Solar 0%

0%

YearofFirstAddition 2020 2020 2020 2020 TotalGWsAdded (through2034)

117

127

73

226

ResultsoftheCapacityExpansionModelingthatsupportedconclusionsfromtheTechnology Assessment,asdiscussedearlier,werereasonablyconsistentacrossscenarios.Theseresults,as summarizedbelow,aretheoutputofthemodelbasedonthemarketconditionsthatthemodel analyzed:

Ingeneral,newbuildcapacityisrequiredtomeetoverallreliabilityneeds.

Gasfired, CTs and CCGTs, are the preferred technologies for new build resources in mostoutcomes.

Themodeldidnotselectnewnuclearornewcoalforanyscenario.

ThemodeldidnotselectsolarPVorbiomassforanyscenario.

Windgenerationhasasignificantroleinonlyoneofthescenariosthatinvolveshighgas andcarbonprices.

PortfolioDesign&RiskAssessment TheAURORACapacityExpansionModelanalyzesleastcostportfoliostomeettheCompanies resourceneedsusingthescreeneddemandandsupplysideresourcealternatives.Throughthis

30

analysis, the Companies sought to assess the relative performance of the highest ranking resource alternatives from the screening assessments when included with the Companies existingresourcesandtotesttheirperformanceacrossarangeofoutcomesasprovidedbythe scenarios.Thisanalysisseekstoidentifytheportfoliothatproducesthelowesttotalsupplycost tomeettheidentifiedneeds,butdoesnottakeintoaccountratedesignorrateeffects.

In total, four portfolios (described below) were constructed and assessed. The AURORA CapacityExpansionModelwasusedtodevelopaportfolioforeachofthescenariosinatwo step process, which first assessed DSM programs, and then supplyside alternatives. DSM programswereevaluatedfirstwithoutconsiderationofsupplysidealternativesbyallowingthe AURORACapacityExpansionModeltodeterminewhichoftheDSMprogramsmaybeableto providecapacityandenergybenefitsinexcessoftheircosts.AlleconomicDSMprogramswere included in each portfolio.36 Once the level of economic DSM was determined within each scenario/portfoliocombination,theAURORACapacityExpansionModelwasusedtoidentify the most economic level and type of supplyside resources needed to meet reliability requirements.Theresultofthisprocesswasanoptimalportfolioforeachscenarioconsistingof bothDSMandsupplysidealternatives.

Table10:PortfolioDesignMix PortfolioDesignMix

IRPortfolio BBPortfolio DDPortfolio GSPortfolio DSMPrograms 18Programs 14Programs 16Programs 20Programs DSM Maximum (MWs)37 497 407 539 467 CTs/CCGTs (MWs) 7,348 8,404 6,876 6,512 Wind(MWs) 0 0

0 4,00038

36InevaluatingtheeconomicsofDSMprograms,themodelevaluatesthecostandbenefitoftheDSMprograms, butdoesnottakeintoconsiderationratemakingandpolicyissuesimplicatedbyDSMprograms,whichmustbe appropriatelyaddressedaspartofDSMimplementation.

37DemandSideManagement(DSM)totalisgrossedupforPlanningReserveMargin(12%)andtransmissionlosses (2.4%).

38Windwaslimitedto20resourcesannuallyat200MWseach,whichprovides564MWofcapacitycreditbased onMISOdeterminedwindcapacitycreditof14.1%.

31

EachportfoliowasmodeledinAURORAandtestedinthefourscenariosdescribedearlierfora totalof16cases.TheresultsoftheAURORAsimulationswerecombinedwiththefixedcostsof theincrementalresourceadditionstoyieldthetotalforwardrevenuerequirementsexcluding sunk costs of the portfolio. The total forward revenue requirement results and rankings by scenarioareprovidedinthefollowingtables.

Table11:PVofForwardRevenueRequirementsbyScenario3940 PVofForwardRevenueRequirements($B)(20152034)

IRScenario BBScenario DDScenario GSScenario Industrial Renaissance Portfolio

$36.0

$32.5

$36.1

$46.4 BusinessBoom Portfolio

$36.2

$32.2

$36.3

$46.3 Distributed Disruption Portfolio

$36.0

$32.2

$36.2

$46.3 GenerationShift Portfolio

$37.9

$35.1

$37.4

$43.1

Therevenuerequirementsshownaboveincludethetotalcosttoservetotalloadoverthe20 year planning period. It is important to note that the revenue requirements shown are reflective of the total fuel costs and the incremental resource cost to deliver the portfolios underdifferentscenariosandarenotreflectiveofcustomerrateeffectsastheydonotconsider changesinloadandotherfactorsaffectingrates.

Table 12, below, breaks down the forward revenue requirements for each portfolio in the IndustrialRenaissanceScenario(thefirstcolumnofTable11)intothecomponentcosts.The piechartsshowthepercentagesofincrementalfixed,variable,andDSMcostsofthetotalPV forwardrevenuerequirementsshowninTable11.

39Theforwardrevenuerequirementsareintendedtoprovidethebestavailableestimateofoverallportfoliocost given the long term nature of the IRP process and the fact that customer class bill and rate effects will be determinedthroughcertificationproceedingsassociatedwithparticularresources.

40ThetablereflectsthecorrectinputofnominalDSMprogramcostsasopposedtolevelizedDSMprogramcosts.

Table12:

Thecolu eachoft

41Variable 42Increme eachportf 43Thetabl Portfoliosby mnsinTabl hescenarios

costrepresen ntalfixedcost olio.

ereflectsthec yCostCompo e13,below s.

tstheloadpay isthefixedco correctinputo onentsinthe w,showthe ymentnetofg ostrevenuereq ofnominalDSM

IndustrialRe rankingsof generationene quirementofth Mprogramcost enaissanceSc feachofthe ergymargins.

heincrementa tsasopposed cenario(2015 efourmode alsupplysider tolevelizedDS 52034)414243

eledportfoli resourceadditi SMprogramco

32 3

iosin ionsin osts.

33

Table13:PortfolioRankingbyScenario PortfolioRankingbyScenario(20152034)

IRScenario BBScenario DDScenario GSScenario Industrial Renaissance Portfolio

1

3

144

4 BusinessBoom Portfolio

3

145

3

3 Distributed Disruption Portfolio

2

2 GenerationShift Portfolio

4

1

Thenextstepwastoperformsensitivityanalysesoneachportfoliobyadjustingonevariableat atime46andcomputingthePVofforwardrevenuerequirements.Eachportfoliowastested acrosstherangeofassumptionsfor:

NaturalGasPrices

CoalPrices

CapitalCostforNewGeneration

GeneralInflationandResultingCostofCapital

CO2Costs

NaturalGasPricesandCO2CostsCombinations

44TotalsupplycostfortheIndustrialRenaissancePortfoliowaslowerthantheDistributedDisruptionPortfolio; however, the difference was not significant (0.3%) and the variable supply cost of the Distributed Disruption Portfoliowaslower.

45AswithTables11and12above,thistablereflectsthecorrectinputofnominalDSMprogramcostsasopposed tolevelizedDSMprogramcosts.ThiscorrectionresultedintheBusinessBoomPortfoliohavingthelowesttotal supplycostintheBusinessBoomScenario.

46AcombinationofnaturalgaspricesandCO2costsinvolvedadjustmentoftwovariablesatthesametime.

The rang Renaissa Table14:

ge of total nceScenario NaturalGas forward r oisprovided Sensitivityin revenue req dinthefollo ntheIndustri

quirements owingfiveta alRenaissanc results by ables.

ceScenario portfolio in the Indu

34 ustrial

Table15:

Table16:

CO2PriceSe NaturalGas ensitivityinth andCO2Com heIndustrial mbinationSen

Renaissance nsitivityinth Scenario eIndustrialRRenaissanceS

Scenario

35

Table17:

Table18:

CostofCapit InstalledCos talSensitivity stSensitivity yintheIndus intheIndust

strialRenaiss trialRenaissa sanceScenari anceScenario io o

36

37

Resultsofthesensitivityassessmentsindicatethattheinstalledcost,costofcapital,andcoal prices47havelessofanimpactonthevariabilityoftotalforwardrevenuerequirementsresults acrossallportfoliosincomparisontonaturalgasprices,CO2prices,andthecombinationof natural gas price andCO2 price. The Industrial Renaissance, Business Boom, and Distributed Disruption portfolios are similarly sensitive to natural gas prices, CO2 prices, and the combinationofnaturalgasandCO2prices,whereastheGenerationShiftportfolioisrelatively lesssensitivetothesevariables.Conversely,theGenerationShiftportfolioismoresensitiveto installedcostandcostofcapitalascomparedtotheIndustrialRenaissance,BusinessBoom,and Distributed Disruption portfolios. This is a result of the Generation Shift portfolios higher incremental fixed costs relative to the other three portfolios, which is indicated in the accompanyingTable.Resultsofthesensitivityanalysisareconsistentwiththeresourcetype andamountthatcompriseeachoftheportfolios.

SummaryofFindingsandConclusions Resultsofthescenarioassessmentindicate:

Supplysideeconomicswereconsistentwithtechnologyscreeninganalysis.

SomelevelofDSMwaseconomic48ineveryscenario.

Renewablesarenoteconomicundermostassumptions.Renewableresourcesdepend onhighgasandcarbonpricestobeeconomicrelativetoCTandCCGTresources.

CTandCCGTresourcesperformwellacrossmostscenarios.ThechoicebetweenCCGT and CT technologies is sensitive to external factors as demonstrated by the narrow rangeofoutcomesfortheportfolioscomprisedprimarilyoftheseresources.

47Coalpricesensitivityresultsarenotshowninthesensitivitychartsbecausecoalresourcesarenotaddedasa new resource to any of the portfolios and the existing resource portfolio only has approximately 4% of coal resources.

48Seenote32,supra.

38

PART5:FINALREFERENCERESOURCEPLAN&ACTIONPLAN FinalReferenceResourcePlan TheIRPprocessresultedintheidentificationofaFinalReferenceResourcePlanthatrepresents theCompaniesbestavailablestrategyformeetingcustomerslongtermpowerneedsatthe lowest reasonable supply cost, while considering reliability and risk. The Final Reference ResourcePlanisbasedonthefollowingassumptions:

The industrial renaissance underway in Louisiana, coupled with residential and commercialloadgrowth,isdrivingsignificantgrowthinutilityloadwithupto1,600MW ofindustrialloadgrowthexpectedintheCompaniesserviceareasthrough2019.By 2034,theCompaniesexpecttorequireatleast8,000MWofadditionalcapacitytomeet demand.

For purposes of planning capacity, the Companies have assumptions regarding the deactivationofapproximately5,950MWofoldergasfiredsteamgeneratorsoverthe planningperiod.Thisagingfleetisincreasinglysusceptibletoaccelerateddeactivation as decisions are made regarding unit economics associated with unexpected maintenance costs and ongoing evaluation of unit availability. Actual decisions to continuetoinvestinandoperatetheseunitshavenotbeenmadeandwillbesubjectto ongoingassessmentsofeconomicsandtechnicalfeasibility.

Inordertoreliablymeetthepowerneedsoftheirrespectivecustomersatthelowest reasonablecost,theCompanieswillmaintainaportfolioofgenerationresourcesthat includestherightamountandtypesofcapacity.

o Withrespecttotheamountofcapacity,theCompaniesmustmaintainsufficient generatingcapacitytomeettheirpeakloadsplusaplanningreservemargin.The Companies will plan resources to a 12% reserve margin. The Companies will needtoaddcapacityforthreereasons:1)tomeetloadgrowth;2)toreplace existingresourcesthatwillreachtheendoftheirusefullives(unitdeactivations);

and3)toreplacePPAsthatwillexpire.

o With respect to the type of capacity, the Companies seek to add modern, efficientgeneratingcapacity,whichwillpredominantlybeCCGTSandCTs.

39

The Companies will continue to meet the bulk of their reliability requirements with eitherownedassetsorlongtermPPAs.Theemphasisonlongtermresourcesmitigates exposuretocapacitypricevolatilityandensurestheavailabilityofresourcessufficient tomeetlongtermreliabilityneeds.

A portion of reliability requirements may be met through a reasonable reliance on limitedtermpowerpurchaseproductsincludingzonalresourcecredits,totheextent theseareeconomicallyavailablewhenconsideringrisk.

SomelevelofDSMisconsideredeconomicallyattractivebutpresentsratemakingand policyissuesthatmustbeaddressedinconnectionwithadoptionsofsuchprograms.A varietyoffactors,manyofwhicharehighlyuncertain,willaffecttheamountofDSM thatcanandwillbeachievedovertheplanninghorizon.

All existing coal and nuclear units will continue operating throughout the planning horizon.AllnuclearunitsareassumedtoreceivelicenseextensionsfromtheNuclear RegulatoryCommission(NRC)tooperateupto60years.

Newbuildcapacity,whenneededin2020andbeyond,comesfromacombinationofCT andCCGTresources.Newbuildcapacitymaybeobtainedthroughownedresourcesor longterm power purchase contracts. For the purpose of preparing the IRP, the economicswereassumedtobeequivalent.

No new solid fuel capacity is added, and new nuclear development remains in the monitoringphase.

Renewable resources are not economically attractive relative to conventional gas turbinetechnology(whetherinsimpleorcombinedcycle)assolelyacapacityresource.

However,renewablecostandperformance-inparticular,solar-continuestoimprove asasourceofzeroemissiongeneration.Duetopotentialstateandfederalincentives, potentialenvironmentalrequirements,andasgeneralcostandtechnologyperformance improve,itisconceivablethattheCompaniesandtheircustomerscouldincorporate solar or other intermittent, renewable resources at distributed or utility scale magnitude.Thesepossibilitieswarrantfurtheranalysis.

TheFinalReferenceResourcePlanshowninTable19includesassumptionsregardingfuture majorresourceadditions,suchastheUnionPoweracquisition,the2020AmiteSouthCCGT,

40

2020 WOTAB CTs, and the 202021 WOTAB CCGT, as well as assumptions regarding implementationofcosteffectiveDSMprograms.Theactualresourcesdeployed(includingthe amountandtimingoftechnologyandpowerpurchaseproducts)andDSMimplemented,will dependonfactorswhichmaydifferfromassumptionsusedinthedevelopmentoftheIRP.Such longtermuncertaintiesinclude,butarenotlimitedto:

Loadgrowth(magnitudeandtiming),whichwilldetermineactualresourceneeds

Therelativeeconomicsofalternativetechnologies,whichmaychangeovertime

Environmentalcompliancerequirements

Practical considerations that may constrain the ability to deploy resource alternativessuchastheavailabilityofadequatesourcesofcapitalatreasonablecost

Conditionofexistingunitsandongoingassessmentsofthoseunits TherearetwoimportantpointstoconsiderwhenreviewingtheFinalReferenceResourcePlan.

First,thedecisiontoprocureagivenresourcewillbecontingentuponareviewofavailable alternatives at that time, including the economics of any viable transmission alternatives availablethatwouldbecoupledwithapurchaseofcapacityand/orenergy.Inaddition,the decisiontoprocureaspecificresourceinaspecificlocationmustreflectthespecificleadtime forthattypeofresource,whichwillvarybyresourcetype,andthetimerequiredforobtaining regulatoryapprovals.Bydeferringspecificresourcedecisionsuntildeploymentisneeded,the Companiesretaintheflexibilitytorespondtochangesincircumstanceuptothetimethata commitmentismade.

Second,avarietyoffactors,manyofwhicharehighlyuncertain,willaffecttheamountofDSM thatcanandwillbeimplementedovertheplanninghorizon.DSMassumptions,includingthe levelofcosteffectiveDSMidentifiedthroughtheIRPprocess,arenotintendedasdefinitive commitmentstoparticularprograms,programlevelsorprogramtiming.Theimplementation of costeffective DSM requires consistent, sustained regulatory support and approval. The Companies investment in DSM must be supported by a reasonable opportunity to timely recover all of the costs, including lost contribution to fixed cost, associated with those programs.ItisimportantthatappropriatemechanismsbeputintoplacetoensuretheDSM potentialactuallyaccruestothebenefitofcustomersandthatutilityinvestorsareadequately compensatedfortheirinvestmentthroughopportunitytoearnperformancebasedincentives.

41

Table19:FinalReferenceResourcePlanLoad&Capability20152034(AllvaluesinMW)

Load&Capability20152034

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 Requirements

PeakLoad 9,869 10,081 10,495 10,896 11,172 11,090 11,162 11,231 11,303 11,376 11,452 11,526 11,599 11,672 11,743 11,811 11,882 11,952 12,024 12,095 ReserveMargin(12%) 1,184 1,210 1,259 1,307 1,341 1,331 1,339 1,348 1,356 1,365 1,374 1,383 1,392 1,401 1,409 1,417 1,426 1,434 1,443 1,451 TotalRequirements 49 11,053 11,290 11,754 12,203 12,513 12,421 12,502 12,578 12,659 12,741 12,826 12,909 12,991 13,073 13,152 13,229 13,308 13,387 13,466 13,546 Resources ExistingResources OwnedResources 50 9652 9549 9549 8826 8826 8814 8814 8688 8688 8688 8688 8277 7616 7616 7095 6528 5571 4419 3702 3702 PPAContracts 909 909 866 386 386 386 386 144 144 144 144 144 144 144 144 144 39 9

LMRs 308 308 308 308 308 308 308 308 308 308 308 308 308 308 308 308 308 308 308 308 IdentifiedPlanned Resources Union 51

816 816 816 816 816 816 816 816 816 816 816 816 816 816 816 816 816 816 816 AmiteSouthCCGT 52

560 560 560 560 560 560 560 560 560 560 560 560 560 560 560 OtherPlanned Resources DSM 53 19 44 77 105 151 220 266 299 329 334 403 413 414 471 457 532 539 423 456 538 CTs(2)

388 388 388 388 388 388 388 388 388 388 388 388 388 388 388 CCGT1

764 764 764 764 764 764 764 764 764 764 764 764 764 764 764 CCGT2

764 764 764 764 764 764 764 764 CCGT3

764 764 764 764 764 764 764 CCGT4

764 764 764 764 764 764 CCGT5

764 764 764 764 764 CCGT6

764 764 764 764 CCGT7

764 764 CCGT8

764 MarketPurchase 165

138 1,762 2,026 165 200 611 663 739 755 1,239 1,218 478 328 133 503 1,881 1,889 1,122 TotalResources 11,053 11,625 11,754 12,203 12,513 12,421 12,502 12,578 12,659 12,741 12,826 12,909 12,991 13,073 13,152 13,229 13,308 13,387 13,466 13,546

49Totalloadrequirementadjustsforthepeakloaddiversitybetweenthetwocompanies.

50TheJSPPPAsareincludedintheOwnedResourcesrow.

51Unionplantacquisitioniscompletedpendingregulatoryapprovals.816MWistwotrainsofthefacilityless20%allocationtoENO.Givenchangestotheownershipofthe othertrains,itisexpectedthatEGSLwillretain100%ofitstwotrains.

52ELL/EGSLshareofAmiteSouthRFPispresentlyestimatedat560MW.RFPresponsesarecurrentlybeingevaluated;actualcapacityofselectedresourcecouldrangebetween 650to1,000MWandaportionofthatcapacitymaybesharedwithanotherEntergyoperatingcompany.Asaresult,actualcapacitymayexceed560MW.Givenchangestothe ownershipoftheothertrains,itisexpectedthatELL/EGSLwillretain100%oftheresourceselectedthroughthisRFP.

53DemandSideManagement(DSM)totalisgrossedupforPlanningReserveMargin(12%)andtransmissionlosses(2.4%).

42

ActionPlan The Companies have developed the following Action Plan for pursuing the Final Reference ResourcePlandescribedaboveoverthefirstfiveyearsoftheplanningperiod.TheActionPlan recognizesthattherearenumerousuncertaintiesthatwillbeencounteredoverthe20yearIRP period,theoutcomeofwhichwillsignificantlyinfluencetheresultingsupplyportfolio.

Table20:ActionPlan Category Item Actiontobetaken SupplySide Alternatives Union Acquisition Obtainregulatoryapprovalandcompletetheacquisitionof PowerBlocks3and4oftheUnionPlantnearElDorado, Arkansas.Netofa20%PPAtoENO,UnionPlantwouldadd approximately816MWstotheCompaniescurrent capacityin2016;however,givenchangestotheownership oftheotherUnionPowerunits,itisexpectedthatEGSLwill retain100%ofitstwotrains.

Renewables Theenergyandcapacityperformanceofutilityscale intermittentresourcesandlocationalimpactson distributionfeedersofdistributedrenewablesatthe residentialorsmallutilityscalewillneedtobedetermined toreliablyandeconomicallyincorporatetheseresources overtime.Longterminvestmentsinthesystem operationsandutilitydistributioninfrastructuremightbe requiredtoreliablyinterconnectthesetechnologiesata largescale.TheCompanieswillevaluatedistributedpilot projects(<5MW)forsolarandstoragetechnologyinorder toassessenergyandcapacitybasedplantperformance, verifyforecastintegrationofintermittentrenewablesfor systemreliability,andevaluatedistributedsolarPV locationalimpactsandeconomicsondistributionfeeders.

LegacyFleet Evaluatecostsandbenefitsofinvestinginexisting resourcesinordertosupportsafe,reliableoperation beyondthecurrentlyassumeddeactivationdates.

43

PPAs EvaluatecostsandbenefitsofPPAsasviablealternatives tomeetlongtermneeds.

NewResources ContinuetoassessthedevelopmentofaCToption (approximately380MWs)thatcouldbedeployedinthe LakeCharlesareain2020tomeettheindustrialload growthexpectedinthatarea;however,thetimingofthis resourceisuncertainandsubjecttochangebasedon changesinloadadditions,implementationofothersupply additions,andchangesintransmissiontopography.

InQ32015,fileanapplicationandsupportingtestimony withtheCommissionseekingcertificationfortheSt.

CharlesPowerStationselfbuildCCGTresourceselected throughthe2014AmiteSouthRFP.Completethe certificationprocessinordertosupportaninservicedate by2020.

InSeptember2015,issuetheWOTABRFPtosolicit proposalsforanewCCGTfacility(approximately8001000 MWs)intheLakeCharlesareaby2020tomaintain reliableandeconomicservicetocustomersgiventhe industrialloadgrowth,PPAexpirationsandterminations, andanticipatedunitdeactivationsexpectedinthatarea.

Obtaincertificationforanyresourceselectedthroughthe RFPinordertofacilitateaninservicedateby2020.

Continuetoassessdevelopmentofadditionaloptionsfor CTadditionsintheAmiteSouthandWOTABareasthat couldbedeployedquicklyifloadgrowthishigherthan expectedand/orsupplyalternativesarenotcompletedas planned.

GasSupply Exploreopportunitiesforlongtermgassuppliesthat couldmitigatepricevolatilityand/orreducethecostof gasrelativetofuturemarketconditions.

Demand Side DSMandEnergy Efficiency EvaluatetheresultsoftheQuickStartEnergyEfficiency programsinLouisiana.

44

Alternatives Programs

Workwithregulatorstodeveloprulesthatwouldprovide aframeworkforimplementingcosteffectiveDSM programsbeyondtheQuickStartphaseandprovide appropriatecostrecovery.

Rev.1April2015 APPENDIXA:ELL&EGSLGENERATIONRESOURCES GeneratingAssetsOwnedorControlledbyELLasof1/1/15 Plant Unit Megawatt Capability Fuel COD Region ANO 1

23 Nuclear 12/19/1974 North ANO 2

27 Nuclear 3/25/1980 North Acadia 2

367 Gas 7/3/2002 WOTAB Buras 8

12 Gas 1/30/1971 DSG GrandGulf

209 Nuclear 7/1/1985 Central Independence1

7 Coal 1/18/1983 North LittleGypsy 2

411 Gas 4/18/1966 AmiteSouth LittleGypsy 3

520 Gas 3/21/1969 AmiteSouth NinemilePoint 3

103 Gas 11/5/1955 DSG NinemilePoint 4

699 Gas 5/1/1971 DSG NinemilePoint 5

717 Gas 6/12/1973 DSG NinemilePoint 6

308 Gas 12/24/2014 DSG Perryville 1

133 Gas 7/1/2002 Central Perryville 2

36 Gas 7/1/2001 Central Sterlington 7

126 Gas 1/1/1986 Central Riverbend 1

195 Nuclear 1/1/1986 Central Waterford 1

411 Gas 6/27/1974 AmiteSouth Waterford 2

411 Gas 9/13/1975 AmiteSouth Waterford 3

1,156 Nuclear 9/24/1985 AmiteSouth Waterford 4

33 Oil 9/24/1985 AmiteSouth WhiteBluff 1

13 Coal 8/22/1980 North WhiteBluff 2

12 Coal 7/23/1981 North TotalOwned

5,929

UnaffiliatedPPAs

605

TotalCapacity

6,534

Rev.1April2015 GeneratingAssetsOwnedorControlledbyEGSLasof1/1/15 Plant Unit Megawatt Capability Fuel COD Region Acadia 2

184 Gas 7/3/2002 WOTAB BigCajun2 3

146 Coal 1/1/1983 Central Calcasieu 1

82 Gas 5/30/2000 WOTAB Calcasieu 2

91 Gas 5/1/2001 WOTAB LewisCreek 1

133 Gas 12/1/1970 WOTAB LewisCreek 2

132 Gas 5/1/1971 WOTAB NinemilePoint 6

140 Gas 12/24/2014 DSG Ouachita 3

241 Gas 8/1/2002 Central Perryville 1

228 Gas 7/1/2002 Central Perryville 2

63 Gas 7/1/2001 Central RoyNelson 4

244 Gas 7/1/1970 WOTAB RoyNelson 6

222 Coal 5/1/1982 WOTAB Riverbend 1

389 Nuclear 1/1/1986 Central Sabine 1

122 Gas 3/1/1962 WOTAB Sabine 2

122 Gas 12/1/1962 WOTAB Sabine 3

228 Gas 11/1/1964 WOTAB Sabine 4

306 Gas 8/1/1974 WOTAB Sabine 5

270 Gas 12/1/1979 WOTAB WillowGlen 2

104 Gas 1/1/1962 Central WillowGlen 4

276 Gas 7/1/1973 Central TotalOwned

3,723

UnaffiliatedPPAs

304

TotalCapacity

4,027

1

APPENDIXB:ACTUALHISTORICLOADANDLOADFORECAST Historic Peak Demand and Energy1 Table1:HistoricTotalAnnualEnergy(MWh)

ELL EGSL 2004 29,718,031 21,149,604 2005 28,303,405 20,541,702 2006 29,080,987 20,732,221 2007 29,773,354 20,964,467 2008 29,198,107 21,537,359 2009 29,894,169 21,395,660 2010 32,085,692 22,224,858 2011 33,164,859 21,531,721 2012 32,989,327 21,074,484 2013 33,456,578 21,400,699 2014 33,859,482 22,460,701

Table2:HistoricTotalMonthlyEnergy(MWh)2 Month/Year ELL EGSL 01/2004 2,311,537 1,601,028 02/2004 2,136,717 1,524,442 03/2004 2,164,832 1,577,645 04/2004 2,176,831 1,593,903 05/2004 2,596,835 1,781,548 06/2004 2,741,239 1,864,531 07/2004 2,932,780 2,024,939 08/2004 2,881,298 2,012,446 09/2004 2,593,513 1,862,491 10/2004 2,624,031 1,996,075 11/2004 2,168,018 1,596,355 12/2004 2,390,400 1,714,201 01/2005 2,255,883 1,672,997 02/2005 2,031,011 1,453,530 03/2005 2,235,818 1,548,045 04/2005 2,261,162 1,553,197 05/2005 2,559,331 1,784,569 06/2005 2,769,785 1,904,194

1Actualsarenotavailableforrevenueclasses.

2DataforNovemberandDecember2014ispreliminaryandsubjecttochange.

2

07/2005 2,906,955 2,008,777 08/2005 2,834,534 2,037,849 09/2005 2,087,842 1,806,263 10/2005 2,211,131 1,597,883 11/2005 2,001,850 1,554,430 12/2005 2,148,103 1,619,968 01/2006 2,033,144 1,556,821 02/2006 1,980,652 1,385,554 03/2006 2,117,934 1,571,043 04/2006 2,221,653 1,653,726 05/2006 2,537,231 1,816,740 06/2006 2,789,737 1,940,443 07/2006 2,875,996 2,023,795 08/2006 2,997,500 2,097,955 09/2006 2,646,658 1,873,176 10/2006 2,398,857 1,677,934 11/2006 2,169,848 1,527,102 12/2006 2,311,777 1,607,932 01/2007 2,371,678 1,703,012 02/2007 2,162,670 1,500,588 03/2007 2,221,530 1,601,057 04/2007 2,190,694 1,608,715 05/2007 2,492,526 1,913,330 06/2007 2,734,552 1,902,830 07/2007 2,816,853 1,938,451 08/2007 3,099,329 2,107,737 09/2007 2,697,947 1,876,642 10/2007 2,455,856 1,687,020 11/2007 2,170,803 1,521,490 12/2007 2,358,917 1,603,595 01/2008 2,432,139 1,852,720 02/2008 2,118,960 1,603,295 03/2008 2,236,831 1,690,728 04/2008 2,291,841 1,668,177 05/2008 2,626,717 1,954,253 06/2008 2,786,255 2,080,007 07/2008 2,995,936 2,259,714 08/2008 2,842,596 2,158,308 09/2008 2,078,546 1,467,917 10/2008 2,350,752 1,750,564 11/2008 2,144,427 1,474,222 12/2008 2,293,108 1,577,453

3

01/2009 2,343,883 1,690,184 02/2009 1,985,991 1,411,601 03/2009 2,172,280 1,587,727 04/2009 2,298,941 1,572,658 05/2009 2,616,182 1,823,800 06/2009 2,837,246 2,124,410 07/2009 2,963,590 2,173,590 08/2009 2,891,459 2,215,597 09/2009 2,685,899 1,907,629 10/2009 2,461,316 1,735,890 11/2009 2,201,431 1,478,599 12/2009 2,435,951 1,673,975 01/2010 2,623,187 1,759,164 02/2010 2,276,565 1,646,248 03/2010 2,342,863 1,666,681 04/2010 2,336,778 1,679,509 05/2010 2,832,878 2,025,872 06/2010 3,032,288 2,129,334 07/2010 3,106,097 2,091,799 08/2010 3,161,069 2,140,429 09/2010 2,921,662 1,993,046 10/2010 2,554,847 1,760,973 11/2010 2,300,971 1,596,121 12/2010 2,596,486 1,735,682 01/2011 2,653,798 1,740,261 02/2011 2,412,060 1,562,619 03/2011 2,407,898 1,614,158 04/2011 2,508,947 1,740,579 05/2011 2,794,626 1,909,373 06/2011 3,089,584 2,021,022 07/2011 3,248,003 2,079,774 08/2011 3,488,051 2,185,171 09/2011 2,874,991 1,793,410 10/2011 2,579,222 1,649,351 11/2011 2,410,048 1,600,386 12/2011 2,697,629 1,635,616 01/2012 2,531,135 1,608,977 02/2012 2,412,094 1,454,687 03/2012 2,593,042 1,631,738 04/2012 2,574,452 1,696,105 05/2012 2,982,002 1,957,034

4

06/2012 3,111,340 1,922,590 07/2012 3,245,996 2,024,525 08/2012 2,991,951 2,024,343 09/2012 2,841,400 1,832,743 10/2012 2,639,342 1,735,547 11/2012 2,404,111 1,525,234 12/2012 2,662,463 1,660,961 01/2013 2,746,176 1,615,504 02/2013 2,340,010 1,461,945 03/2013 2,549,999 1,631,898 04/2013 2,510,550 1,673,465 05/2013 2,846,703 1,817,896 06/2013 3,105,051 2,006,778 07/2013 3,111,886 2,049,357 08/2013 3,307,459 2,106,366 09/2013 3,056,761 1,938,448 10/2013 2,539,617 1,741,513 11/2013 2,513,983 1,609,732 12/2013 2,828,381 1,747,795 01/2014 2,918,373 1,861,032 02/2014 2,457,101 1,626,956 03/2014 2,558,374 1,752,514 04/2014 2,533,237 1,707,600 05/2014 2,810,857 1,892,237 06/2014 3,067,230 2,073,054 07/2014 3,237,304 2,077,909 08/2014 3,265,719 2,170,383 09/2014 3,008,222 1,997,183 10/2014 2,745,633 1,841,000 11/2014 2,567,031 1,721,727 12/2014 2,690,401 1,739,106

5

Table3:HistoricTotalSummer&WinterPeaks(MW)3

ELL EGSL Winter20044 4,636 3,119 Summer2004 5,091 3,555 Winter2005 4,943 3,314 Summer2005 5,236 3,583 Winter2006 4,550 3,311 Summer2006 5,257 3,639 Winter2007 4,395 3,383 Summer2007 5,341 3,676 Winter2008 4,653 3,609 Summer2008 5,234 3,912 Winter2009 4,558 3,256 Summer2009 5,252 4,046 Winter2010 5,060 3,496 Summer2010 5,492 3,747 Winter2011 5,174 3,400 Summer2011 5,766 3,787 Winter2012 5,343 3,412 Summer2012 5,706 3,694 Winter2013 5,045 3,386 Summer2013 5,773 3,776 Winter2014 5,382 3,459 Summer2014 5,518 3,752

3SummerisdefinedasJuneNovember.WinterisdefinedasDecemberMay.

4Winter2004isdefinedasJanuary2004May2004.

6

Load Forecast Table4:EGSLMonthlyEnergyForecast(GWh),IndustrialRenaissanceCase REDACTED MATERIAL

7

REDACTED MATERIAL

8

REDACTED MATERIAL

9

REDACTED MATERIAL

10

REDACTED MATERIAL

11

REDACTED MATERIAL

12

Table5:ELLRetailMonthlyEnergyForecast(GWh),IndustrialRenaissanceCase REDACTED MATERIAL

13

REDACTED MATERIAL

14

REDACTED MATERIAL

15

REDACTED MATERIAL

16

REDACTED MATERIAL

17

REDACTED MATERIAL

18

Table6:ForecastedRetailSummer&WinterPeaks(MWs)5

ELL EGSL Winter2015 5,294 3,666 Summer2015 5,863 3,861 Winter2016 5,382 3,766 Summer2016 5,950 3,983 Winter2017 5,548 3,933 Summer2017 6,115 4,232 Winter2018 5,619 4,345 Summer2018 6,174 4,567 Winter2019 5,752 4,501 Summer2019 6,292 4,723 Winter2020 5,784 4,372 Summer2020 6,332 4,601 Winter2021 5,828 4,402 Summer2021 6,372 4,630 Winter2022 5,869 4,428 Summer2022 6,413 4,658 Winter2023 5,909 4,455 Summer2023 6,456 4,688 Winter2024 5,950 4,484 Summer2024 6,492 4,719 Winter2025 5,990 4,515 Summer2025 6,532 4,752 Winter2026 6,029 4,544 Summer2026 6,574 4,785 Winter2027 6,069 4,573 Summer2027 6,614 4,816 Winter2028 6,108 4,601 Summer2028 6,659 4,847 Winter2029 6,146 4,628 Summer2029 6,693 4,877 Winter2030 6,185 4,655 Summer2030 6,732 4,905 Winter2031 6,223 4,683 Summer2031 6,771 4,935 Winter2032 6,261 4,710 Summer2032 6,810 4,965 Winter2033 6,299 4,738 Summer2033 6,851 4,995

5Summerandwintercoincidentpeakdemandsforeachcustomerclassarenotdeveloped.

19

Winter2034 6,337 4,766 Summer2034 6,893 5,026

Table7:ForecastedLoadFactors

ELL EGSL 2015 69%

69%

2016 70%

70%

2017 70%

72%

2018 70%

76%

2019 71%

78%

2020 71%

76%

2021 71%

76%

2022 71%

77%

2023 71%

77%

2024 71%

77%

2025 71%

77%

2026 71%

77%

2027 71%

77%

2028 71%

77%

2029 71%

77%

2030 71%

77%

2031 71%

77%

2032 71%

77%

2033 71%

77%

2034 71%

77%

Page1of16

APPENDIXC:RESPONSETOSTAKEHOLDERCOMMENTS General Comment Response(January2015)

StaffProviderationaleforselection oftheproxygeneratingunitusedfor theprojectedlongtermcapacity pricesanddescribehowthat comparestoothermarketcapacity pricesforMISORTO

MISOdoesnothaveprojectedlongtermcapacity prices;onlyannualmarketcapacitypricesare developed.Forlongtermplanning,aCTisusedasthe proxygeneratingunitforprojectedlongtermcapacity pricesasitisthelowestcostsourceofcapacity.

StaffIdentifyunitsselectedfor deactivationandreasonfor deactivationandwhen

ForthepurposeofdevelopingthisIRP,assumptions mustbemadeaboutthefutureofgeneratingunits currentlyintheCompaniesportfolio.Assumptions madefortheIRParenotfinaldecisionsregardingthe futureinvestmentinresources.Unitspecificportfolio decisionssuchas,sustainabilityinvestments, environmentalcomplianceinvestments,orunit retirements,arebasedoneconomicandtechnical evaluationsconsideringsuchfactorsasprojected forwardcosts,anticipatedoperatingroles,andthe costofsupplyalternatives.Thesefactorsaredynamic, andasaresult,actualdecisionsmaydifferfrom planningassumptionsasgreatercertaintyisgained regardingrequirementsoflegislation,regulation,and relativeeconomics.Basedoncurrentassumptions,a numberoftheCompaniesexistingfossilgenerating unitsmaybedeactivatedduringtheIRPplanning period.Intheyears20152034,thetotalassumed reductionintheCompaniesgeneratingcapacityfrom theseunitdeactivationsandPPAterminationsis approximately6,100MW,whichconsidersthe additionofNinemilePoint6,relativetothe Companiescurrentcombinedresourcesof approximately10,915MW.

SierraClubNotclearhowthe Companywillmodelthepossible retirementofexistingcoalresources.

Moreover,itappearsEntergyhas ignoredthepossibilityofretiringany ofitscoalfiredfacilities.

ThroughouttheplanningperiodallEntergycoalunits areassumedtocontinuetooperate.Theseunitswill continuetooperateaslongasitiseconomictodoso.

Page2of16

StaffIdentifyanddescribefuture knownand/orplannedchangesin capacity,availability,etc.

Therearenoknownfutureand/orplannedchangesin thecapacityandtheavailabilityofexistingresources.

StaffIdentifyanddescribenew resourcesthecompanyplanstobuild oracquire,includingthoseplanned forWOTABtransmissionregion.

AsdescribedintheActionPlan,EGSLisintheprocess ofobtainingregulatoryapprovaltoacquiretwounits oftheUnionPlantnearElDorado,Arkansas.This acquisitionwouldaddapproximately816MWsnetof a20%PPAtoENOtotheCompaniescurrentcapacity.

Similarly,theCompaniesarecurrentlyconductingthe AmiteSouthRFPtoobtainanewCCGTby2020.

StaffIdentifyanddescribefuture knownand/orplannedchangesin transmissioncapacity,includingnew linesandupgrades,andeffectonnew resources.

ThisinformationisavailableundertheTransmission PlanningSectionintheIRP.Specificdetailsabout futurechangesintransmissionisinAppendixA.

SierraClubDisclosehowELLand EGSLwillaffectresourceplans

AspartoftheIRP,anActionPlanwasdevelopedthat describestheCompaniesplanforspecificresourcesat certaintimes.

SWEARecommendsthatdata assumptionsregardingO&Monlyuse fixedO&Mcosts,insteadoffixedand variableO&Mcoststogether.

AllrelevantcostsareincludedintheIRP,which includesbothfixedandvariableO&M.TheIRPis developedfromacustomerperspective.Thatis,the Companiesplanningprocessseekstodesigna portfolioofresourcesthatreliablymeetscustomer powerneedsatareasonablecostwhileconsidering risk,whichiswhyitisnecessarytoincludevariable O&Mcosts.

SWEADataassumptionsshould includegreatertransparencyand citationsoallstakeholderscan conductdataqualitycontrol.

AllinputassumptionswerefiledwiththeLPSCthrough aseriesoffilingsin2014,withthemostrecentin October.

SierraClubEntergyshouldtreat distributedgenerationlikeanyother availableresourceandpursuing programsthatareavailableand beneficialtoratepayers.

Theeffectofdistributedgenerationisaccountedforin theloadforecast.Currently,thisisthebestavailable methodtoaccountfordistributedgenerationgivenits nondispatchablenature.

Page3of16

CommentonDraftIRPReport Response(August2015)

AllianceforAffordableEnergy-Were upgradecostsfornuclearmodeledin AURORAorwerenewnuclearcosts modeled?

Upgradecostsfornuclearwerenotmodeled.New nuclearwasevaluatedinthescreeninglevelanalysis phaseoftheTechnologyAssessmentandfoundtobea viabletechnology,butwasnotselectedbyAURORAas acostcompetitiveresourceinthedetailedanalysis phase.

AllianceforAffordableEnergy-Was generationfromtheUnionPower Stationincludedinthemodelingor afterthemodelingwascomplete?

UnionPowerStationwasincludedintheAURORA modelingasaresource.

AllianceforAffordableEnergy-Pleaseexplainthematchupfeeused inconnectionwithwindresources.

Thematchupreflectsthefactthatwindreceives partialcapacityvalueinMISOduetowinds intermittentnature.Thecapacitymatchupfeewas onlyappliedintheinitialscreeninganalysisphaseof supplysideresourcesinthetechnologyassessment.

Onceitwasselectedforfurtheranalysisandmodeling inAURORA,windwasevaluatedrelativetoother resourceswithoutthecapacitymatchupfeeadded.

LEUG-Explaintheprocessbywhich thecompaniescontinuetoevaluate unitdeactivations.

ForthepurposeofdevelopingtheIRP,assumptions aremadeaboutthefutureoftheunitsinthecurrent portfolio.Unitspecificportfoliodecisionssuchas sustainabilityinvestments,environmentalcompliance investments,orunitretirementsarebasedon economicandtechnicalevaluationsconsideringsuch factorsasprojectedforwardcosts,anticipated operatingroles,andthecostofsupplyalternatives.In theIRP,atotalassumednetreductioninthe Companiesgeneratingcapacityfromunit deactivationsandPPAterminationsisapproximately 6,100MWovertheplanninghorizon.Thisassumption hasnotchangedsincetheNovember3,2014Inputs filing.

LEUG-Provideadditionalinformation ontheprocessforevaluationofnew transmissionoptionstoensurelowest reasonablecosts.

Transmissionaloneisnotanalternativetogeneration, butrathertransmissioninconjunctionwithgeneration allowscustomerstobeservedreliablyand economically.TheCompaniesandotherloadserving entitiesinMISOarerequiredtoprovidegeneration capacityequaltotheirloadobligationplusaMISO determinedreservemargintocomplywithMISO ResourceAdequacyrequirements.Therefore,when theCompaniesneedtoaddanewgeneratingunit,the locationischosentobestmeettheplanningobjectives

Page4of16

basedonconsiderationoffactorsneededtosupport newgenerationincluding,butnotlimitedtofuel supply,transmission,watersupply,environmental permitting,andproximitytoload.Thisprocess considersbothgenerationandtransmissionandallows theCompaniestomeettheplanningobjectivesof servingitscustomersreliablyatthelowestreasonable costwhileconsideringrisk.

StaffDiscusswhetherthereareany economicopportunitiestoinclude CHPintheportfolioandreduceneed forothercapacityrelatedcapital expenditures TheCompaniesfavorablecommercialandindustrial ratesmakesCHPdeploymentuneconomicformost existingcustomersexceptthosewithover20MWof loadthatalsohaveanoperationalneedforprocess steam.EvenifCHPiseconomic,manyindustrial customersprefertoutilizetheCompaniesreliableand competitivelypricedelectricalpowerratherthan committheirlimitedcapitalresourcestoconstructing theirownpowergenerationprojectsthathaveamid tolongtermpaybackandareanoncorebusiness.

Thisisverymuchthecasewhentheindustrial customerscostofelectricityissmallcomparedtoits totalcostofdoingbusiness.Theconsiderableamount ofindustrialCHPalreadyconnectedtotheCompanies electricalgridindicatesthatthebaseofexisting industrialcustomersforwhomthattechnologymakes economicsensehavealreadyelectedtodeployCHP.

StaffRegardingActionPlan,provide informationontimelinesforacquiring theNewResourcesdiscussedaswell asanyreasonswhycompetitive solicitationmightnotbeused.

Additionalinformationregardingtimelineshasbeen providedintheActionPlaninthereport.

StaffExplainwhetheranalysishas beenperformedtodetermineifit wouldbebeneficialtoEGSL customersforJSPPPAstoremainin effectandhowthatwouldaffectthe ReferencePlan.

BecauseLPSCConsolidatedOrderNos.U21453, U20925andU22092(SubdocketJ)requiresthe terminationofthesePPAsuponremovaloftheJSP PPAresourcesfromEntergySystemdispatch,such analysishasnotbeenperformedindevelopingthe CompaniesIRP.Ingeneral,theterminationoftheJSP PPAswouldcauseEGSL,onanetbasis,tolose approximately700MWofcapacityfromlegacygas generationresources.Thisassumptionisreflectedin theReferencePlan.Thereisnobasistoassumea differentoutcomegiventheLPSCOrder.

Page5of16

Load Comment Response(January2015)

StaffIdentifyanddescribeknownor anticipatedmajorloadadditions Loadadditionsincludeindividualcustomer information,whichisconfidential.

StaffAddresshowpriceelasticity incorporatedinprojectedpeakloads andenergy,andhowthiseffects resourceportfolio Priceelasticityisaninputintotheenergyforecasting models.Thepeakloadforecastusestheoutputfrom theenergymodelsasaninputsotheimpactsofprice elasticityindirectlyinfluencethepeakload.Resource portfoliosarethendevelopedaftertheloadforecastis complete.

Comment onDraftIRP Report Response(August2015)

StaffHow didactual load compareto theload forecastin the Companies 2012IRP filings?

Thefollowingtableprovidesacomparisonofactualannualenergysales,or cumulativehourlyload,tothe2012IRPforecast.

Staff-Adda more detailed description ofthe assumptions usedto developthe loadforecast and distributed generation.

Rooftopsolarsforecastedgrowthisbasedona12monthaverageofinstallation ratesandaveragesystemsize.Nospecificadditionalgrowthisassumedafter 2017duetotheexpirationofinvestmenttaxcredits;however,growthinsolar alongwithotheritemsisembeddedinthereductionofsaleswithinorganic energyefficiencyassumptions.

Staff-Adda more Inanefforttoavoidlongtermresourceshortages,projectswithinthe CompaniesEconomicDevelopmentpipelinewereaddedtotheforecast.In AmountsinGWh 2012 2013 2014 2012 2013 2014 IRPForecast1 19,298

19,659

19,925

31,373

32,130

32,482

WeatherAdjustment 124 48 87 178 142 275 NonWeatherAdjustedActuals 19,581

19,663

20,823

31,710

32,220

32,905

ForecastError%

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;Assumesnormalweather EGSL ELL

Page6of16

detailed description ofthe assumptions usedto developthe load

forecast, including majorload additions.

recognitionoftheuncertaintyinherentinforecastingnewload,theadded projectswereriskadjustedtoreflectaninternallyassignedprobabilityofthe newcustomercompletingthependingproject.Forexample,assumethat customerABChasinformedEntergyofanew80MWprojectbeingconsidered inEntergysserviceterritory.Baseduponconversationswiththecustomerand previousexperiences,theCompaniesAccountManagerassignedaprobability of50%tothisprojectbeingcompleted.Thus,theloadforecastwouldassumea 40MW(80MWx50%=40MW)projectisadded.Projectsforwhichthe customerhasexecutedanelectricserviceagreementarenotriskadjustedand wouldbeincludedintheloadforecastatthefullprojectedMWload.Alarge industrialadditionofapproximately10MWwasalsoincludedinLouisianato accountforprojectsthathadnotbeenexplicitlyidentified.

Thecapacityofthelargeindustrialloadadditionsassumedintheforecastis identifiedinthechartbelow.

Alliancefor Affordable Energy-Does weather forecasting usedbySPO andMetrix usehistoric dataor climate impacted projections?

Historicdataisusedintheweatherforecasting.

Page7of16

FuelInputs Comment Response(January2015)

StaffUseconsistentassumptionsfor coalpriceinput.Ifthereare discrepanciesbetweenplants,explain.

TheDeliveredPlantCoalPricesweredevelopedusing twodifferentmethodologies:EntergyOperating Company(EOC)andMarketPlants.TheSPO DeliveredtoEOCUnitsCoalPriceForecastisalong termdeliveredpriceforecastcreatedfromconsultant commoditypriceforecast,forecastedburn, transportationcosts,andcontractinformation.The deliveredpricesforMarketResourceswerederived fromaconsultantforecast.Differentplantsmayhave DeliveredCoalPriceForecastsbecauseofdifferences inthetimingandvolumesforcommodityand transportationcontracts.Moreover,itisexpectedthat variousscenarioshavedifferentcoalpriceinputsasa resultofdifferentfuelassumptions(e.g.,low, reference,andhigh).

SierraClubAssumptionsarebiased towardsnaturalgas,insteadoflower costoptions;Entergyshouldconsider agaspricevolatilityaddertoreflect riskofpricefluctuation

ThesensitivityanalysisconductedintheIRPevaluated arangeofnaturalgaspricesacrosseachscenarioto capturetheriskrelatedtofluctuatingnaturalgas prices.

MISO Comment Response(January2015)

EntegraCoordinatewithMISOon generationunitretirement assumptionsandtransmissionstudies (e.g.forAmiteSouthandWOTAB areas)

ThereareestablishedproceduresfortheCompanies workwithMISO,whichisbeyondthescopeoftheIRP process.

EntegraPerformatransmission topologysensitivityanalysisofits preliminaryIRPresultsonceMISO makesrecommendations

LouisianaEnergyUsersGroup CoordinatewithMISOongeneration unitretirementassumptionsand

Page8of16

transmissionprojects(e.g.,Amite SouthandWOTAB)

LouisianaEnergyUsersGroup CompareAURORAmodelingtoMISO recommendations;performa transmissiontopologysensitivity analysis

EnergyEfficiency Comment Response(January2015)

AllianceforAffordableEnergyDSM benefitsshouldincludeindirectutility systembenefitsresultingfromlower capacityandenergyloads,reduced reserverequirements,marginalline lossesinsteadofaverage,andavoided T&Dexpenses.

AspartoftheIRPprocess,theCompaniesengagedICF toprepareademandsidemanagementpotential studyforuseintheIRP.Thestudywasfiledin October.AllprogramsthathadaTRCratioof1.0or greaterwereevaluatedintheAURORAMarketModel beforeconsiderationofsupplysideresourceoptions.

SoutheastEnergyEfficiencyAlliance (SEEA)Needtodisclose assumptionsforcostandavailability ofenergyefficiencyforDSM (DemandSideManagement)study

-suchasdirectsavingsfrominstalled measuresandsystembenefits,lower capacityandenergyloads,reduced reservesrequirements,reductionin marginallinelosses,andavoided transmissionanddistribution expenses

SEEAEnergyefficiencyisnotonlya leastcostresource,butalsoa mechanismfordeferringadditional supplysidegeneration,avoidingnew transmissionanddistribution infrastructure,andbufferingagainst compliancecostsfromfuture environmentalregulations.

Page9of16

SierraClubTreatenergyefficiencyas aresource,orparwithsupplyside resources.

SierraClub-EnergyEfficiencyshould beaccountedasaresource.

SierraClubModeldistributed generationandenergyefficiencyas supplyrideresources.

IntheIRP,distributedgenerationisaccountedforin theloadforecastfortheCompanies.Moreover,energy efficiencyisevaluatedasaresourcealternativeinthe IRP.

CommentsontheDraftIRPReport Response(August2015)

AllianceforAffordableEnergy-ICF modeledthreecasesbasedon incentivelevel.Whichoneofthese caseswasmodeledinAURORA?

Theincentivelevelvariedbyprogram.Theincentive levelwiththehighestTRCratioforeachprogramwas selectedtobemodeledinAURORA.Assuch,the incentivelevelvariedforeachprogram.However,the referenceprogramtendedtohavethehighestTRC ratioformostprograms.

AllianceforAffordableEnergy-Why didntICFincludeENOinthe benchmarkingdata?

ENOandtheELL/EGSLserviceterritorieshave significantlydifferentcustomerbases.ELL/EGSLare heavilyindustrial,whileENOhasverylittleindustry.As such,comparingperformanceattheportfoliolevel betweenENOandELL/EGSLisproblematic.

AllianceforAffordableEnergy-Why arethepaybackacceptancecurves differentfromtheNewOrleansdata?

Thesamesetofpaybackacceptancecurveswasused toestimateparticipationforELL/EGSLaswasusedfor ENOfortheEntergyStudy.

AllianceforAffordableEnergy-Why arethenettogrossratiosdifferent fromENO?

Thesamesetofprogramnettogrossratioswereused forELL/EGSLaswereusedfortheENOstudy.

AllianceforAffordableEnergy-In AppendixF[oftheNovember3,2014 InputsFiling],itlookslikeavoided costsdonotincludefuel.

Yes,fuelisincludedintheavoidedcostsinAppendixF.

Page10of16

EnvironmentalRegulation Comment Response(January2015)

Staff-Addresshow[CSAPR]affects amountandtimingofplanned deactivations.

TheCompaniescontinuetoevaluatetherecent SupremeCourtdecisiontoallowtheEPAtoenforce CSAPR,buttodate,noneoftheCompaniesunitshave beenidentifiedfordeactivationbecauseofthisrule.

However,therearedifferentassumptionsforother loadservingentitiesinthemarketbaseduponthe differentscenarios.IndustrialRenaissanceand DistributedDisruptionassumenonEntergyunitsretire attheageof60years;BusinessBoomassumes70 years;andGenerationShiftassumes50years.

SierraClub-Unclearhow environmentalcompliancecosts regardingcarbonpollutionandother environmentalregulationswillbe incorporated.

TheIRPdoesevaluatearangeofenvironmental compliancecostsinregardstoCO2,SO2,andNOx.

GulfStatesRenewableEnergy IndustriesAssociation(GSREIA)

Failstorecognizeinherentproblems withtraditionalsourcessuchasprice volatilityandreducedcapacityoflife; sustainabilityandenvironmental impactareotherissues.

TheIRPdoesconsiderallknownandexpected environmentalcostofresourcesincludingcarbon.

AllianceforAffordableEnergyUse onerobustreferencecasethat includesCO2andSection111(d) compliancewithmorefocuson sensitivitiesinsteadofmultiple scenarios.

ArangeofCO2priceassumptionsareincludedinthe IRPacrossthefourscenarios.Moreover,thesensitivity analysisevaluatestheeffectsofdifferentCO2prices foreachscenario.

SEEA-AssumptionsregardingCO2 policyareunrealistic.

SierraClub-Ignoresthecostsof newEPAregulationsinSection111(d) regardingcarbonpollutionstandards cominginJune2014.

SierraClub-UsenonzeroCO2price

Page11of16

Comment Response(August2015)

StaffIncludeanevaluationofthe effectsofenvironmentalregulations orfutureregulationsontheoperation oftheCompaniesexistingUnits.

ESI coordinates internally to identify, assess, and respond to environmental issues arising from federal regulatory and legislative proceedings. ESI tracks issues and analyzes impacts using a combination of internal corporate and business function staff and external organizations.

Subject matter experts participateinindustryassociationsandorganizations, interact with federal and state agency staff, and monitor the trade press regarding environmental issues. Information gathered is shared through technical peer groups and the Environmental Lead Team, and a consolidated pointofview is formed based on Entergys overall business strategy, as needed. Unless otherwise noted below, expected capitalexpendituresandincreasestoO&Mcostsfrom many of these proposals are not yet fully developed due to uncertainty regarding the outcome of regulatory, legislative, and litigation proceedings. A brief summary of issues which potentially have the highestoperationalimpactontheCompaniesfollows:

Clean Air Act Regulations - Consistent with the PresidentsCleanPowerPlanannouncedinJune2013, EPAisexpectedtofinalizeinAugust2015regulations fornew,existing,andmodified/reconstructedsources of CO2 under the Clean Air Act. ESI developed an engagementplanandisactivelyengagedwithindustry groups, regulatory agency staff, and other external partiestoanalyzetheimpactoftheseproposedrules, commentonpolicyandtechnicalissues,andadvocate for reasonable approaches. Performance standards forexistingsources,oncefinal,willinitiatestateplans for compliance which could be due as early as September 2016. Regulations to address traditional pollutants have evolved due to court rulings, state implementation planning, and EPA actions. EGSL installed controls at the R.S. Nelson power plant pursuant to EPA regulations regarding mercury and other air toxics, but a recent Supreme Court ruling remanding this rule may result in a different compliance requirement. ESI also is implementing compliancemeasuresfortheCrossStateAirPollution Rule (CSAPR) and continues to monitor issues

Page12of16

regarding regional haze and National Ambient Air QualityStandard(NAAQS)development.

Solid/Hazardous Waste Regulations - EPA finalized regulationsforcoalashandmanagementstructuresin December2014.Theruleregulatescoalashdisposal andimpoundments/landfillsunderthenonhazardous sectionofthesolidwasteregulations.TheR.S.Nelson powerplantistheonlyEGSLownedfacilityaffectedby the rule. ESI continues to participate with industry groups to advocate for reasonable implementation approaches in order to minimize compliance costs.Litigationonthisrulemayresultinadifferent compliancestrategy.

AquaticProtectionRegulations-EPAfinalizedthe 316(b)ruleinMay2014.Thefinalruleaffectsseveral EGSL/ELLfacilitiesandprovidesflexibilityonboththe scheduleandtechnologyapproachesforcomplying withthestandardsforimpingementand entrainment.ESIsEnvironmentalStrategy&Policy grouphascoordinatedbetweentheEntergyFossiland Nuclearorganizationstoassessplantneedsfor respondingtothenewregulation.Consultantshave beenretainedandcomplianceactivitiesareunderway toconductthenecessarytechnicalstudiesandcompile theexistingtechnicaldataforsubmissiontothe appropriateregulatoryagencies.EPAalsohas proposedneweffluent(discharge)guidelinesfor electricgeneratingunitsthatmayrequiremodified wastewatertreatmentprocedures;theseguidelines arenotexpectedtobefinalizeduntillate2015.

StaffIncludemoreclarificationon themethodologyoftheCO2forecast, particularlyaroundwhythecarbon costsstartin2023.Includesupporting studiesfromotherorganizations.

The reference case price stream is based on a probabilityweighted forecast of a utilityonly sector capandtradeprogrambeingimplementedstartingin 2023. The utility program is basedon the reductions required under the KerryLieberman legislative proposal,andproratedtothepowersectoremissions levels. Offsets are also allowed. The assumed probability of a national, utilityonly program is 33 percentin2023and66percentby2040.

The forecast is updated annually by the ESI Environmental Strategy and Policy group, or more

Page13of16

often as conditions warrant. The updated forecast is reviewedbytheCompaniesEnvironmentalLeadTeam with their recommendation being used as the CompaniesCO2PointofView.

TheforecastisbasedontheQ12014StrategicOutlook (formerly the Integrated Energy Outlook) dated January2013byICFInternational.

RenewableResources Comment Response(January2015)

SierraClub-Solarandwind installationcostswilldecrease.

TheTechnologyAssessmentindicatesthatsolarcost arelikelytodeclineoverthenextfiveyears,however, windcostandperformancearenotexpectedto materiallyimproveordeclineoverthistimeperiod.If windandsolarcostandperformanceimprovemore thanexpectedinthisIRP,thenfutureIRPswillcapture that.LAIRPcycletimeiseveryfouryears.

GSREIACommonexpectationfor solarandwindenergyleveledcoststo reachgridparityinmanyareaswithin 510years.Alackofearlyfirsthand experiencebyEGSLandELLwith integration,thesetechnologieswillbe aliabilitytoratepayers,keepingcosts andvolatilityhighunnecessarily.

Decliningpriceofrenewableenergy sourcesmustbeincludedinthe modelingofanyforwardlooking resourceplan.

AllianceforAffordableEnergyWind resources:modelLouisianacoastal, upland,andoutofregionprojects separatelyanduse40%+capacity factor.

TheCompaniesprefertechnologiesthatareprovenon acommercialscale.Sometechnologieslackthe commercialtrackrecordtodemonstratetheir technicalandoperationfeasibility.Acautious approachtotechnologydevelopmentanddeployment isthereforereasonableandappropriateinorderto AllianceforAffordableEnergy-Renewableresource:instateandout ofstateandabroadrangeofproject sizesshouldbeconsidered.

Page14of16

SWEAConsiderimporting SouthwestPowerPool[SPP]windat lowcost.

RecommendsMISOWestwind energyresourcesbemodeledinIRP processasaseparateresource.If possible,EGSL/ELLshouldmodel transmissioninterconnectionsand upgradesthatmaygrantgreater flexibilityinaccessinglowcostenergy resources,likeSPPorMISOwind energy.Entergycouldalsoprocure windresourcesinNorthernMISO.

WithinLouisiana,windfarmscanbe constructedinthecoastalzone offshoreandcanbeconsidered resourcesforMISOSouthPricepoints andcapacityfactorsaredifferentfor Louisianabasedresourcesandmust bemodeledasaseparateresourcein thisIRPprocess.

Encourageaclearerexplanationof howEGSL/ELLplanstoconduct capacityvalueanalysesforall generationresources.Currently,the capacityvalueprovidedtowind energyintheMISOsystemis14.1%,

andbecauseEGSL/ELLisnowa memberofMISO,thisisareasonable figureforinclusionintheIRPprocess.

Evenso,thisvaluemaybe conservative.Analysisofwind resourcesavailableinSPPandfor HVDCtransmissionsuggestsa capacityvalueof40%basedonTVAs capacityvaluemethodology.

Usedwindcoststhataretoohigh:A majorreasonforEGSL/ELLs unrealisticallyhighLCOE[Levelized CostofEnergy]forwindenergyisa maintainSystemreliabilityandtoprotectOperating Companycustomersfromunduerisks.TheEntergy OperatingCompaniesgenerallydonotplantobethe firstmoversforemerging,unproventechnologies.

TheIRPseekstoidentifygenerationtechnologiesthat aretechnologicallymatureandcouldreasonablybe expectedtobeoperationalinoraroundthe Companiesregulatedserviceterritory.TheCompanies usea34%capacityfactorassumptionforwind resourcesthatcouldbedevelopedinoraroundthe Entergyregulatedserviceterritory.

AspartofMISO,theCompaniesarerequiredto adheretoMISOscapacityvaluesforwind,whichis 14.1%asoutlinedinMISOsResourceAdequacyTariff (ModuleE)andResourceAdequacyBusinessPractice Manual.

TheCompaniesuseofacapacitymatchupreflects thefactthatwindreceivespartialcapacityvaluein MISOduetowindsintermittentnature.Thecapacity matchupisonlyusedinthescreeninganalysisof supplysideresourcesinthetechnologyassessment.

WhenmodeledinAURORA,windisevaluatedwithout thecapacitymatchuprelativetootherresources.

Page15of16

spurioususeofamatchupfee

Itisrecommendedthatthetotalall in,deliveredcostsofwindenergyfor outofstateresourcesberoughly$40 50/MWhandapproximately

$44/MWhforresourceswithin Louisiana

CommentonDraftIRPReport Response(August2015)

StaffConcernedaboutlackoffuel diversityintheReferenceCase.

Shoulddiscussfueldiversityand commentsfromthe2009SRP regardingappropriatenessof includingrenewablesintheSystem portfolio.

The2009SystemSRPincludedthestatementonpage 110thatrenewablegenerationhasaplaceinthe portfolio.Inclusionofmodestlevelsofthemost economicallypricedrenewablegenerationalternatives canreducecostandminimizetotalsupplycostrisk especiallyinlightofthepotentialRPSandcarbon legislation.However,theamountofrenewable generationthatcanbecosteffectivelyaddedis limited.TheexpectedgasforecastshownonFigure 4:3ofthatSRPoverthe20yearhorizon(ending2030) inreal2008$was$8.66/MMBTU,significantlyabove theReferenceCaseRealLevelizedforecastof$4.87in this2015IRP.

Basedonthatpointofview,itwaspossibletoforesee 2GWofcosteffectiverenewablesbeingaddedtothe EntergySystemportfolio(asstatedonpage111)and aSystemrenewablesRFPbeingissuedinthe2009 2010timeframe(infact,theRFPissuedin2010was limitedtoELL/EGSL).

Whilerenewableswouldincreasefueldiversityinthe portfolio,theanalysisconductedforthe2015IRP showsthatthecostofrenewablescomparedto naturalgasgenerationissuchthattheyarenot competitiveintheabsenceofaRPS.Likewise,the costsassociatedwithnewnuclearandcoalrender themuncompetitivewithnaturalgasatthistime.

WhilefueldiversityisaconcernoftheIRPprocess, naturalgasgenerationoffersthebestwaytoprovide thelowestreasonablecostportfoliothatcanreliably servethecustomersneeds.

Page16of16

Hydroelectric Comment Response(January2015)

NelsonFailstorecognizethat conventionalhydroelectricgeneration isanoptionforEntergy,fromnew hydroelectricprojectsthatwouldbe locatedinorneartheCompanies serviceareas.

Hydroelectricgenerationresources arewellbelowcostsofother renewableoptions

Shouldstudyhydroelectricgeneration aspartofIRP

Hydroelectricisasitespecificresourcethathaslimited developmentopportunitiesinLouisiana.Asaresult,it isnotappropriatetoassessconventionalhydroelectric resources(oranyotherspecificresource)inthe contextoftheIRP.Suchanalysiswouldbeconducted aspartoftheevaluationofresponsestoaRequestfor Proposals(RFP)orofanunsolicitedofferfora particularresource.

SierraClub-Entergyshouldinclude hydroelectricprojects.

Report Date:

January 19, 2015 Entergy Project ID MTEP Project ID MTEP Designation Project Driver Project Name Operating Company Proposed ISD (Planning)

Project Funding Status Project Status Project Status Comments Current Projected ISD Actual ISD Mitigation Plan if required Included in Model?

(Yes/No) 11-EGL-007 4602 Appendix B Transmission Reliability - Meeting Planning Criteria Moril to Delcambre 138 kV line: Upgrade station equipment EGSL Summer 2016 Proposed &

In Target Scoping Scoping to begin 3rd Quarter 2014 Summer 2016 N/A 11-EGL-016-02 N/A Pre-Planned Transmission Reliability - Meeting Planning Criteria Mossville to Canal - Phase 2: Upgrade 69 kV Line EGSL Winter 2014 Approved Construction Construction started 12/15/14.

Outages have been approved 2/14/15 N/A 11-EGL-017 4608 Appendix B Transmission Reliability - Meeting Planning Criteria Five Points to Line 281 Tap to Line 247 Tap-Upgrade 69 kV line EGSL Summer 2019 Proposed &

In Target Scoping Summer 2019 N/A 11-EGL-018 4630 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Francis to Marydale: Upgrade 69 kV line EGSL Summer 2017 Proposed &

In Target Scoping Accelerated Need By Date from 2023 to Summer 2017 Summer 2017 N/A 12-EGL-004 4603 Appendix B Transmission Reliability - Meeting Planning Criteria McManus to Brady Heights - Upgrade 69 kV line EGSL Winter 2023 Conceptual Conceptual Conceptual Moved out from 2016 to 2023 Winter 2023 N/A 12-EGL-010 N/A Pre-Planned Transmission Reliability - Meeting Planning Criteria Kirk Substation: Construct new 138-69 kV substation near St. Martinville (Formerly New Iberia: Add 138-69 kV substation)

EGSL Summer 2015 Proposed &

In Target Scoping PEP is under review to evaluate a proposed change in the station configuration.

Spring 2016 NCLL 14-EGL-002 4611 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Construct new Waddill 230-69 kV Substation (formerly referred to as Flannery Area Project)

Also reconfigure 69 kV lines 340 and 749 EGSL Summer 2017 Proposed &

In Target Scoping Accelerated Need By Date from 2020 to 2017 Summer 2017 N/A 14-EGL-003 N/A Pre-Planned Transmission Reliability - Meeting Planning Criteria Willow Glenn: Upgrade 500-230 kV single phase transformer bank with 1200 MVA single phase bank EGSL Summer 2016 Approved Design/Construction Autotransformer and breakers have been ordered and are scheduled to be delivered to support EGSL Construction; January 2016 (Auto) and March 2015 (breakers).

Summer 2016 Planned NCLL until project completed 14-EGL-004 4606 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Fancy Point: Add 2nd 500-230 kV, 1200 MVA transformer EGSL Summer 2017 Proposed &

In Target Scoping Detailed scoping to begin 3rd Quarter 2014 Summer 2017 Planned NCLL until project completed 14-EGL-005 4625 A in MTEP14 Transmission Reliability - Meeting Planning Criteria Nelson: Upgrade 500-230 kV single phase transformer bank with 1200 MVA transformer bank EGSL Winter 2015 Approved Design Autotransformer has been ordered.

Design complete Spring 2015 N/A 14-EGL-006 N/A Pre-Planned Transmission Reliability - Meeting Planning Criteria LeBlanc - New Cap Bank #1 EGSL Summer 2015 Proposed &

In Target Construction Permanent and Temporary Servitudes are being finalized Summer 2015 N/A 14-EGL-007 4610 Appendix B Transmission Reliability - Meeting Planning Criteria Chlomal to Lacassine - Upgrade Line EGSL Winter 2023 Conceptual Conceptual Conceptual Moved out from 2019 to 2023 Winter 2023 N/A 14-EGL-008 4609 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Krotz Springs - New Cap Bank EGSL Summer 2016 Proposed &

In Target Scoping Alternative locations for the capacitor bank are being evaluated based on constructability issues.

Summer 2016 N/A 14-EGL-010 4626 Appendix B Transmission Reliability - Meeting Planning Criteria Meaux to Abbeville - Upgrade Meaux Line bay bus EGSL Summer 2024 Conceptual Conceptual Conceptual Project need date moved out from 2020 to 2024 Summer 2024 N/A 14-EGL-012 4628 Appendix B Transmission Reliability - Meeting Planning Criteria LeBlanc - New Cap Bank #2 EGSL Summer 2021 Conceptual Conceptual Conceptual Accelerated one year from 2022 to 2021 Summer 2021 N/A APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)

Long Term Projects Page 1 of 7

Report Date:

January 19, 2015 Entergy Project ID MTEP Project ID MTEP Designation Project Driver Project Name Operating Company Proposed ISD (Planning)

Project Funding Status Project Status Project Status Comments Current Projected ISD Actual ISD Mitigation Plan if required Included in Model?

(Yes/No)

APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects) 14-EGL-016 4604 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Port Hudson to Zachary REA 69 kV Line Reconductor EGSL Summer 2016 Proposed &

In Target Scoping Accelerated Need By Date to Summer 2016 Summer 2016 N/A 14-EGL-017 4605 A in MTEP14 Transmission Reliability - Meeting Planning Criteria Horseshoe Substation (Crown Zellerbach Area):

Construct new 230-138 kV substation on the Fancy Point to Enjay 230 kV line EGSL Summer 2017 Proposed &

In Target Scoping Changed name to reflect new substation name and line connection in title Summer 2017 N/A 14-EGL-019 N/A Pre-Planned Transmission Reliability - Meeting Planning Criteria Mud 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 Lake EGSL Fall 2016 Approved Scoping Detailed scoping in progress. Currently projected to be complete in the Summer 2016.

Summer 2016 N/A 14-EGL-020 4719 A in MTEP14 Transmission Service PPG to Rosebluff 230 kV Line: Upgrade line to increase capacity EGSL Summer 2015 Approved Design Scoping complete. Design has begun.

Current project schedule is targeting a 7/1/15 ISD.

7/1/15 N/A 14-EGL-022-1 4761 A in MTEP14 Transmission Reliability - Meeting Planning Criteria EGSL SPOF Projects: Modify relaying at Willow Glen 500 kV EGSL Summer 2015 Proposed &

In Target Scoping Definition 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.

12/31/2016 N/A N/A 14-EGL-022-2 4762 A in MTEP14 Transmission Reliability - Meeting Planning Criteria EGSL SPOF Projects: Modify relaying at Fancy Point 500kV EGSL Summer 2015 Proposed &

In Target Scoping Scope to be determined Summer 2015 N/A N/A 14-EGL-023 4720 A in MTEP14 Customer Driven Michigan 230 kV substation: Construct new Michigan 230 kV substation and cut in to the Nelson to Verdine 230 kV line EGSL Summer 2015 Approved Design Design complete. Material has been ordered. Awaiting customer to prep the site. Expected mobilization is 01/05/2015.

Fall 2015 N/A 14-EGL-024-1 4763 A in MTEP14 Transmission Reliability - Meeting Planning Criteria EGSL Underrated Breaker Project: Jaguar 69 kV 20940-CO EGSL Winter 2016 Proposed &

In Target Scoping Under Review Winter 2016 N/A N/A 14-EGL-024-2 4764 A in MTEP14 Transmission Reliability - Meeting Planning Criteria EGSL Underrated Breaker Project: Jaguar 69 kV 20905-CO EGSL Winter 2016 Proposed &

In Target Scoping Under Review Winter 2016 N/A N/A 14-EGL-024-3 4765 A in MTEP14 Transmission Reliability - Meeting Planning Criteria EGSL Underrated Breaker Project: Blount 69 kV 14105-TC EGSL Winter 2016 Proposed &

In Target Scoping Under Review Winter 2016 N/A N/A 14-EGL-024-4 4766 A in MTEP14 Transmission Reliability - Meeting Planning Criteria EGSL Underrated Breaker Project: Coly 230 kV 21825-C EGSL Winter 2016 Proposed &

In Target Scoping Under Review Winter 2016 N/A N/A 14-EGL-024-5 4767 A in MTEP14 Transmission Reliability - Meeting Planning Criteria EGSL Underrated Breaker Project: Coly 230 kV 21830-C EGSL Winter 2016 Proposed &

In Target Scoping Under Review Winter 2016 N/A N/A 14-EGL-026 8284 A in MTEP14 Economic LETP: Coly - Add 2nd 500-230 kV, 1200 MVA Autotransformer EGSL Summer 2018 Approved Scoping New project (Economic MTEP 14)

Summer 2018 N/A N/A Long Term Projects Page 2 of 7

Report Date:

January 19, 2015 Entergy Project ID MTEP Project ID MTEP Designation Project Driver Project Name Operating Company Proposed ISD (Planning)

Project Funding Status Project Status Project Status Comments Current Projected ISD Actual ISD Mitigation Plan if required Included in Model?

(Yes/No)

APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects) 15-EGL-001 7917 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Gillis 230 kV Substation: Add 61 MVAR capacitor bank EGSL Summer 2016 Proposed &

In Target Scoping New Project Summer 2016 15-EGL-002 7919 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Pecan Grove 230 kV Substation: Add 61 MVAR capacitor bank EGSL Summer 2016 Proposed &

In Target Scoping New Project Summer 2016 15-EGL-003 7920 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Carlyss to Boudoin 230 kV Line: Upgrade station equipment at Carlyss EGSL Summer 2016 Proposed &

In Target Scoping New Project Summer 2016 15-EGL-004 7921 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Nelson to Michigan 230 kV line: Upgrade line to minimum of 2000A EGSL Summer 2016 Proposed &

In Target Scoping New Project Summer 2016 15-EGL-005 7923 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Lake Charles Bulk to Chlomal 69 kV Line: Reconductor line EGSL Summer 2017 Proposed &

In Target Scoping New Project Summer 2017 15-EGL-006 7924 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Goosport Substation: Install 138-69 kV autotransformer EGSL Summer 2017 Proposed &

In Target Scoping New Project Summer 2017 15-EGL-008 7929 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Solac: Upgrade 69 kV switch on Autotransformer EGSL Summer 2016 Proposed &

In Target Scoping New Project Summer 2016 15-EGL-009 7948 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Scott to Carencro 69 kV line: Reconductor Line EGSL Summer 2017 Proposed &

In Target Scoping New Project Summer 2017 15-EGL-010 7949 Appendix B Transmission Reliability - Meeting Planning Criteria Solac: Add 3rd Autotransformer EGSL Summer 2023 Conceptual Conceptual New Project Summer 2023 15-EGL-011 7950 Appendix B Transmission Reliability - Meeting Planning Criteria East Broad to Ford 69 kV line: Reconductor line EGSL Summer 2020 Proposed &

In Target Scoping New Project Summer 2020 15-EGL-012 7952 Appendix B Transmission Reliability - Meeting Planning Criteria Contraband to Solac 69 kV line: Reconductor line EGSL Summer 2023 Conceptual Conceptual New Project Summer 2023 15-EGL-013 7954 Appendix B Transmission Reliability - Meeting Planning Criteria Mossville to Alfol 69 kV line: Reconductor line EGSL Summer 2023 Conceptual Conceptual New Project Summer 2023 15-EGL-014 7960 Appendix B Transmission Reliability - Meeting Planning Criteria Chlomal to Iowa 69 kV line: Reconductor line EGSL Summer 2024 Conceptual Conceptual New Project Summer 2024 15-EGL-015 7965 Appendix B Transmission Reliability - Meeting Planning Criteria Lake Charles Bulk to L673 TP 69 kV line: Reconductor line EGSL Summer 2025 Conceptual Conceptual New Project Summer 2025 15-EGL-016 8585 Target Appendix A in MTEP15 (OOC)

Transmission Reliability - Meeting Planning Criteria LCTP: Construct new Sulphur Lane 500 kV switching station EGSL Summer 2018 Approved Scoping New Project to address reliability needs in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycle Summer 2018 15-EGL-017-01 8586 Target Appendix A in MTEP15 (OOC)

Transmission Reliability - Meeting Planning Criteria LCTP: Construct new 500-230 kV Bulk Substation west of Carlyss. Install new 500-230 kV, 1200 MVA autotransformer composed of three single phase units.

EGSL Summer 2018 Approved Scoping New Project to address reliability needs in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycle Summer 2018 Long Term Projects Page 3 of 7

Report Date:

January 19, 2015 Entergy Project ID MTEP Project ID MTEP Designation Project Driver Project Name Operating Company Proposed ISD (Planning)

Project Funding Status Project Status Project Status Comments Current Projected ISD Actual ISD Mitigation Plan if required Included in Model?

(Yes/No)

APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects) 15-EGL-017-02 8587 Target Appendix A in MTEP15 (OOC)

Transmission Reliability - Meeting Planning Criteria LCTP: Construct new 500 kV transmission line from Sulphur Lane to new 500/230 kV Bulk Substation west of Carlyss EGSL Summer 2018 Approved Scoping New Project to address reliability needs in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycle Summer 2018 15-EGL-017-03 8588 Target Appendix A in MTEP15 (OOC)

Transmission Reliability - Meeting Planning Criteria LCTP: Construct new 230 kV line from new Bulk Substation to Carlyss 230 kV substation EGSL Summer 2018 Approved Scoping New Project to address reliability needs in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycle Summer 2018 15-EGL-018 8589 Target Appendix A in MTEP15 (OOC)

Transmission Reliability - Meeting Planning Criteria LCTP: Reconfigure Carlyss 230 kV substation into a breaker and a half configuration EGSL Summer 2018 Approved Scoping New Project to address reliability needs in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycle Summer 2018 15-EGL-019 8590 Target Appendix A in MTEP15 (OOC)

Transmission Reliability - Meeting Planning Criteria LCTP: Construct new 12 mile 230 kV line from Carlyss to new 230 kV substation adjacent to Graywood.

EGSL Summer 2018 Approved Scoping New Project to address reliability needs in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycle Summer 2018 15-EGL-020 TBD Target Appendix A in MTEP15 (OOC)

Customer Driven Intracoastal 69 kV Substation: Install 150 MVA, 230-69 kV autotransformer at Intracoastal and connect to Mud Lake 230 kV substation EGSL Summer 2016 Approved Scoping New customer requested project to provide an additional source into the Intracoastal 69 kV substation Summer 2016 N/A 15-EGL-021 TBD Target Appendix A in MTEP15 (OOC)

Transmission Reliability - Meeting Planning Criteria Carlyss to Sweet Crude Tap (L-238): Reconductor 69 kV line (0.94 miles) to a minimum of 1200A.

EGSL Summer 2016 Approved Scoping New customer requested project to provide an additional source into the Intracoastal 69 kV substation Summer 2016 N/A 14-EGL-027 8284 A in MTEP14 Economic LETP: 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/ELL Winter 2018 Approved Scoping New project (Economic MTEP 14)

Winter 2018 N/A N/A 14-ELL-019 8284 A in MTEP14 Economic LETP - 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/ELL Winter 2018 Approved Scoping New project (Economic MTEP 14)

Winter 2018 N/A N/A Long Term Projects Page 4 of 7

Report Date:

January 19, 2015 Entergy Project ID MTEP Project ID MTEP Designation Project Driver Project Name Operating Company Proposed ISD (Planning)

Project Funding Status Project Status Project Status Comments Current Projected ISD Actual ISD Mitigation Plan if required Included in Model?

(Yes/No)

APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects) 10-ELL-008 N/A Pre-Planned Transmission Reliability - Meeting Planning Criteria Southeast LA Coastal Improvement Plan: Phase 3 Construct Oakville to Alliance 230kV Line Add 230 - 115 kV Autotransformer at Alliance Substation ELL Summer 2013 Approved Scoping Oakville 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 ti f

l ti li 6/1/18 Planned NCLL until project completed 11-ELL-001 N/A Pre-Planned Enhanced Transmission Reliability Golden Meadow to Leeville 115 kV - Rebuild/relocate 115 kV transmission line ELL Spring 2014 Approved Construction T-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-Line construction is in 3/31/15 N/A 11-ELL-004 N/A Pre-Planned Transmission Reliability - Meeting Planning Criteria Northeast LA Improvement Project Phase 3 Upgrade Sterlington to Oakridge to Dunn 115 kV Line ELL Summer 2015 Approved Construction Pre-Construction meeting held on 1/09/15. Construction to start 1/15/2015 12/30/15 Planned NCLL until project completed 11-ELL-012 N/A Pre-Planned Transmission Reliability - Meeting Planning Criteria Valentine to Clovelly 115 kV upgrade ELL Summer 2015 Approved Construction Design, material procurement, permitting, and ROW access improvements complete. T-Line 5/1/15 Planned NCLL until project completed 12-ELL-004 4769 A in MTEP14 Load Growth Schriever: Construct new 230 kV substation ELL 2017 Proposed &

In Target Scoping Under Review 3/31/17 N/A 13-ELL-004 N/A Pre-Planned Transmission Reliability - Meeting Planning Criteria Minden Improvement Project Ph. 1-Place cap bank at Minden REA ELL Summer 2015 Proposed &

In Target Scoping Will require co-ordination with Lagen on final design and operation Summer 2015 N/A 13-ELL-006 4634 Appendix B Transmission Reliability - Meeting Planning Criteria Ninemile to Westwego 115 kV: Reconductor Line ELL Summer 2020 Conceptual Conceptual Conceptual Summer 2020 N/A 14-ELL-002 4635 Appendix B Transmission Reliability - Meeting Planning Criteria Sterlington 115 kV Substation: Upgrade jumpers on the Sterlington to Walnut Grove 115 kV line (line 107)

ELL Summer 2024 Conceptual Conceptual Conceptual Summer 2024 N/A 14-ELL-006 4639 Appendix B Transmission Reliability - Meeting Planning Criteria Ninemile to Harvey2 115 kV: Reconductor line and change station limiting elements ELL Summer 2025 Conceptual Conceptual Conceptual Moved ISD back to from 2022 to 2025 Summer 2025 N/A 14-ELL-008-1 4770 A in MTEP14 Transmission Reliability - Meeting Planning Criteria ELL Underrated Breaker Project: Waterford 230 kV S7145-CO ELL Winter 2016 Proposed &

In Target Scoping Under Review Winter 2016 N/A N/A 14-ELL-008-2 4771 A in MTEP14 Transmission Reliability - Meeting Planning Criteria ELL Underrated Breaker Project: Waterford 230 kV S7154-CO ELL Winter 2016 Proposed &

In Target Scoping Under Review Winter 2016 N/A N/A 14-ELL-009-1 4773 A in MTEP14 Transmission Reliability - Meeting Planning Criteria ELL SPOF Projects: Modify relaying at Ninemile 230 kV ELL Summer 2015 Proposed &

In Target Design Project 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 2016 N/A N/A Long Term Projects Page 5 of 7

Report Date:

January 19, 2015 Entergy Project ID MTEP Project ID MTEP Designation Project Driver Project Name Operating Company Proposed ISD (Planning)

Project Funding Status Project Status Project Status Comments Current Projected ISD Actual ISD Mitigation Plan if required Included in Model?

(Yes/No)

APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects) 14-ELL-009-2 4774 A in MTEP14 Transmission Reliability - Meeting Planning Criteria ELL SPOF Projects: Modify relaying at Southport 230 kV ELL Summer 2015 Proposed &

In Target Design Project 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 2016 N/A N/A 14-ELL-009-3 4775 A in MTEP14 Transmission Reliability - Meeting Planning Criteria ELL SPOF Projects: Modify relaying at Labarre 230 kV ELL Summer 2015 Proposed &

In Target Design Project 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 2016 N/A N/A 14-ELL-009-4 4776 A in MTEP14 Transmission Reliability - Meeting Planning Criteria ELL SPOF Projects: Modify relaying at Harahan 230 kV ELL Summer 2015 Proposed &

In Target Design Project 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 2016 N/A N/A 14-ELL-009-5 4777 A in MTEP14 Transmission Reliability - Meeting Planning Criteria ELL SPOF Projects: Modify relaying at Paris 230 kV ELL Summer 2015 Proposed &

In Target Design Project 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 2016 N/A N/A 14-ELL-016 4783 A in MTEP14 Customer Driven Haute 115 kV Substation: Construct new substation and cut into existing Lutcher to Belle Point 115 kV line ELL Summer 2014 Approved Construction The Haute Substation is complete.

Project team has accelerate schedule to complete by 12/18/14. Energization pending legal transfer of ownership.

4/1/2015 N/A N/A 14-ELL-018 7841 A in MTEP14 Customer Driven Reese Substation: Construct new 115 kV substations ELL Spring 2015 Approved Complete In-Service Spring 2015 12/17/14 N/A Yes 14-ELL-020 8284 A in MTEP14 Economic LETP: Panama Substation: Cut-in Bagatelle to Sorrento 230 kV line ELL Winter 2018 Approved Scoping New project (Economic MTEP 14)

Winter 2018 N/A N/A 14-ELL-021 8284 A in MTEP14 Economic LETP: Romeville Substation: Upgrade line bay bus.

ELL Winter 2017 Approved Scoping New project (Economic MTEP 14)

Winter 2017 N/A N/A 15-ELL-001 7988 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Terrebonne to Gibson: Construct new 230 kV line and operate at 115 kV ELL Summer 2018 Proposed &

In Target Scoping New Project Summer 2018 15-ELL-002 7970 Appendix B Transmission Reliability - Meeting Planning Criteria Minden 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 of the new substation ELL Summer 2020 Proposed &

In Target Scoping New Project Summer 2020 Long Term Projects Page 6 of 7

Report Date:

January 19, 2015 Entergy Project ID MTEP Project ID MTEP Designation Project Driver Project Name Operating Company Proposed ISD (Planning)

Project Funding Status Project Status Project Status Comments Current Projected ISD Actual ISD Mitigation Plan if required Included in Model?

(Yes/No)

APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects) 15-ELL-003 7990 Appendix B Load Growth Luna: Construct new 115 kV substation ELL Winter 2017 Proposed &

In Target Scoping New Project Winter 2017 14-ELL-012 4779 A in MTEP15 (OOC)

Transmission Reliability - Meeting Planning Criteria Ninemile to Derbigny: Upgrade 230 kV line ELL/ENOI Summer 2016 Proposed &

In Target Scoping Project 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.

6/1/2016 N/A 14-ELL-013 4780 Appendix B Transmission Reliability - Meeting Planning Criteria Ninemile to Napoleon: Upgrade 230 kV line ELL/ENOI Summer 2017 Proposed &

In Target Scoping New 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.

6/1/2017 N/A 15-EMI-003 7904 Target Appendix A in MTEP15 Transmission Reliability - Meeting Planning Criteria Natchez SES - Redgum: Rebuild 115 kV line EMI/ELL Summer 2018 Proposed &

In Target Scoping Under Review Summer 2018 N/A Long Term Projects Page 7 of 7

APPE

1Asreque Sincethes Renaissan ENDIXE:1S

estedbyStaffinth sechartswerepro ncescenariofrom STSTAKEHO

heircommentsont oducedtheScenario theMay2014filin OLDERME theDraftIRPRepor onameshavebeen ng(ScenarioTwo)w ETINGCHA rt,thefollowingth nmodified.Scena wasrenamedtoB Table1:Scena ARTS1 hreechartsfromth arioOnewasrena BusinessBoom.

arioStorylines efirstIRPstakeho medtoIndustrial ldermeetingheld lRenaissanceinth January22,2014, heNovember2014 havebeenprovide 4filing.TheIndust ed.

trial

Table2:20YearMarketModelingInputs(20152034)

Scenario1 IndustrialRenaissance DistributedDisruption ResourceShift ElectricityCAGR(EnergyGWh)

~0.8%

~TBD%

PeakLoadGrowthCAGR

~0.8%

~TBD%

HenryHubNaturalGasPrices($/MMBtu)

$4.89levelized2013$

LowCase

$3.84levelized2013$

SameasReferenceCase

($4.89levelized2013$)

HighCase($8.18levelized 2013$)

WTICrudeOil($/Barrel)

$73.99levelized2013$

LowCase

$69.00levelized2013$

MediumHigh($109.12 levelized2013$)

HighCase($173.71levelized 2013$)

CO2($/shortton)

None Capandtradestartsin2023

$6.70levelized2013$

Capandtradestartsin2023

$6.70levelized2013$

Capandtradestartsin2023

$14.32levelized2013$

ConventionalEmissionsAllowanceMarkets CAIR&MATS CAIR&MATS CAIR&MATS CAIR&MATS DeliveredCoalPrices-EntergyOwnedPlants (PlantSpecificIncludesCurrentContracts)

$/MMBtu ReferenceCase (Vol.WeightedAvg.

$2.69levelized2013$)

LowCase (Vol.WeightedAvg.

$TBDlevelized2013$)

SameasReferenceCase(Vol.

WeightedAvg.

$2.69levelized2013$)

HighCase (Vol.WeightedAvg.

$TBDlevelized2013$)

DeliveredCoalPrices-NonEntergyPlantsIn EntergyRegion Mappedtosimilar EntergyPlant MappedtoSimilarEntergyPlant MappedtoSimilarEntergy Plant MappedtoSimilarEntergy Plant DeliveredCoalPrices-NonEntergyRegions ReferenceCaseVaries ByRegion LowCase VariesByRegion SameAsReferenceCase-VariesByRegion HighCase-VariesByRegion CoalRetirementsCapacity(GW)*

TBD TBD TBD TBD NewNuclearCapacity(GW)*

TBD TBD TBD TBD NewBiomass(GW)*

TBD TBD TBD TBD NewWindCapacity(GW)*

TBD TBD TBD TBD NewSolarCapacity(GW)*

TBD TBD TBD TBD

Table3:ProposeddSensitivitiesfortheLAIRP

APPENDIXF:AURORADSMPORTFOLIOSBYSCENARIO

AURORADSMPortfoliosbyScenario IndustrialRenaissance BusinessBoom DistributedDisruption GenerationShift DSM1-ResidentialLighting&Appliances DSM1-ResidentialLighting&Appliances DSM1-ResidentialLighting&Appliances DSM1-ResidentialLighting&Appliances DSM3-ENERGYSTARAirConditioning DSM3-ENERGYSTARAirConditioning DSM3-ENERGYSTARAirConditioning DSM3-ENERGYSTARAirConditioning DSM4-ApplianceRecycling DSM4-ApplianceRecycling DSM4-ApplianceRecycling DSM5-HomeEnergyUseBenchmarking DSM5-HomeEnergyUseBenchmarking DSM5-HomeEnergyUseBenchmarking DSM8-Multifamily DSM8-Multifamily DSM8-Multifamily DSM8-Multifamily

DSM9-WaterHeating

DSM10-PoolPump DSM12-DynamicPricing DSM12-DynamicPricing DSM12-DynamicPricing DSM13-CommercialPrescriptive&Custom DSM13-CommercialPrescriptive&Custom DSM13-CommercialPrescriptive&Custom DSM13-CommercialPrescriptive&Custom DSM14-SmallBusinessSolutions DSM14-SmallBusinessSolutions DSM14-SmallBusinessSolutions DSM14-SmallBusinessSolutions DSM15-NonResidentialDynamicPricing DSM15-NonResidentialDynamicPricing DSM15-NonResidentialDynamicPricing DSM15-NonResidentialDynamicPricing DSM16-RetroCommissioning DSM16-RetroCommissioning DSM16-RetroCommissioning DSM17-CommercialNewConstruction DSM17-CommercialNewConstruction DSM17-CommercialNewConstruction DSM17-CommercialNewConstruction DSM18-DataCenter DSM18-DataCenter DSM18-DataCenter DSM19-MachineDrive DSM19-MachineDrive DSM19-MachineDrive DSM19-MachineDrive DSM20-ProcessHeating DSM20-ProcessHeating DSM20-ProcessHeating DSM20-ProcessHeating DSM21-ProcessCoolingandRefrigeration DSM21-ProcessCoolingandRefrigeration DSM21-ProcessCoolingandRefrigeration DSM21-ProcessCoolingandRefrigeration DSM22-FacilityHVAC DSM22-FacilityHVAC DSM22-FacilityHVAC DSM22-FacilityHVAC DSM23-FacilityLighting DSM23-FacilityLighting DSM23-FacilityLighting DSM23-FacilityLighting DSM24-OtherProcess/NonProcessUse DSM24-OtherProcess/NonProcessUse DSM24-OtherProcess/NonProcessUse DSM24-OtherProcess/NonProcessUse

Page1of2

APPENDIXG:WINDMODELINGASSUMPTIONS

In response to stakeholder comments regarding the assumptions used to evaluate wind resourcesintheIRP,theCompanieshavepreparedthisAppendix.

For purposes of the 2015 ELL/EGSL IRP, the delivered cost of energy from a wind resource developedinornearELLorEGSLsservicearea(local)isjudgedtobecomparabletothecost of energy from a remote1 wind resource (remote). While the capacity factors of remote resourcesaregenerallyhigher,theadditionalcostsassociatedwithtransmissionserviceand the differences in Locational Marginal Prices (LMPs) combine to generally equalize energy pricesbetweenlocalandremoteresources.Additionally,allremoteresourceslocatedoutside ofMISOcarryanincreasedriskofunavailabilitycomparedtoresourceslocatedinMISOdueto MISOsemergencycurtailmentproceduresofexternalsystems.Riskassociatedwithpotential changes in rules, transmission, and market structures are inherently greater for a remote resourcerelativetoalocalresourcebasedoninterveningentitiesthatwouldbeinvolvedin conjunctionwiththelongtermnatureoftheseresources.

Forsomefactors,itisreasonabletoapplythesameassumptionsforlocalandremotewind resourcesbecausetheyarenotexpectedtobemateriallydifferent.Forinstance,theinstalled cost is assumed to be the same. In addition, the nondispatchable, intermittent nature is expectedtobesimilarandisexpectedtoresultinsimilarcapacitycreditawardedbyMISO.The transmissioninterconnectioncosttoconnecttheresourcetoanearbysubstationisunknown andwouldbedependentonthespecificlocationregardlessofwhetherthewindresourceis local or remote; therefore, it is reasonable to ignore that cost because it is unknown, but expectedtobecomparable.

Otherfactorsareexpectedtobedifferentforlocalascomparedwithremotewindresources.

Keydifferencesincludecapacityfactor,transmissionservicecost,andLMPs.Assessmentof eachofthesefactorsisdiscussedinturn.

Wind quality and speed in the midwest is expected to yield higher capacity factors as comparedtolocalwindresources.BasedonaNationalRenewableEnergyLaboratory(NREL) costandperformancestudypublishedin20102,thecapacityfactorforawindresourceinthe midwestisassumedtobe50%;whereas,basedonthesamestudy,alocalwindresourceis onlyexpectedtobe34%.Thus,remotewindresourceshaveanadvantageoverlocalwind resourceswithrespecttoenergyproductionpotential.

Itisimportanttodrawadistinctionbetweentransmissioninterconnectioncostsasdescribed aboveandthetransmissionservicecostnecessarytomakethewindresourcedeliverabletothe Companiesload.Alocalresourceisnotexpectedtorequireadditionaltransmissionservice

1Forexample,awindresourcelocatedinKansasorOklahomaorothermidwestlocation.

2http://www.nrel.gov/docs/fy11osti/48595.pdf(Figure96)

Page2of2

chargestomakeitdeliverable.However,aremotewindresourcemayrequireSPPpointto pointtransmissionservicetotheMISOborderandMISOpointtopointtransmissionserviceto ELL / EGSLs load. Based on current MISO and SPP tariff rates, the combined cost of transmissionservicecouldbeapproximately$$5/MWhforoffpeakhours4,$10/MWhforon peakhours4,orwhenadjustedtoawindgenerationprofile,aweightedaverageof$7.11/MWh.

Thistransmissionservicecostandriskisnotincurredbyalocalwindresource.

WindgenerationispaidthehourlyLMPatthegeneratorbuswhilecustomerspayforenergy basedonthehourlyloadweightedaverageLMPfortheloadzone.Thedifferencebetweenthe loadLMPandgeneratorLMPisanestimateoftheriskthatcustomersareexposedtobyhaving aremoteresourceasopposedtoalocalresource.ToestimatethepotentialLMPdifferential risk,threerepresentativeSPPwindresources3for2014wereassessed,assumingagenericSPP windprofile.TheLMPdifferentialsin2014betweenthesethreenodesandELL/EGSLsload (loadweighted average of EES.ELILD and EES.EGILD) are $12.92/MWh, $13.84/MWh, and

$17.07/MWhrespectively,orapproximately$14.60/MWhonaverage.Alocalwindresourceis notsubjecttothispotentialLMPdifferentialrisk.

In summary, the table below shows a comparison of the cost of electricity of a local wind resourcewitharemoteresourcetakingthedifferencesincapacityfactor,transmissioncost, andLMPintoconsideration.Inthisexample,thecapacityfactoradvantageofaremotewind resource is almost completely offset by additional transmission service costs and LMP differentialrisk,whichresultsinsimilarLevelizedCostofElectricity(LCOE)estimatesforboth remoteandlocalwindresources.

Location

Installed Cost($/kW)

FixedCharge Rate(%)

Capacity Factor(%)

Transmission Cost($/MWh)

LMPDifferential

($/MWh)

LCOE($/MWh)

Local

$2000 10.5%

34%

$0

$70.51 Remote

$2000 10.5%

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]

From this assessment, the expected cost difference is approximately 1% between modeling potential wind resources with local assumptions as compared with remote assumptions. If inflationinthetransmissionservicecostandLMPdifferentialweretakenintoconsideration, thelocalwindresourcewouldhavealowerLCOEascomparedtotheremotewindresource.

3KeenanWindFarm(OklahomaGas&Electric,OKGEWDWRDEHVUNKEENAN_WIND_RA),CentennialWindFarm(Oklahoma Gas&Electric,OKGECENTWINDUNCENTWIND_RA),SpearvilleWindFarm(KansasCityPower&Light, KCPLSPEARVILUNWINDFARM_RA).HistoricalLMPsbylocationobtainedfromSPPIntegratedMarketplace (https://marketplace.spp.org/web/guest/lmpbylocation).

4MISOtransmissioncostestimatescalculatedbasedonMISOOATTSchedule7year2015rates,asofJuly2015.SPP transmissioncostestimatescalculatedbasedonSPPOATTSchedule7AttachmentT,asofJuly2015.

ML17024A218

Text

Dear Ms. Bordelon:

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