Appendix D REC Pricing Model Description...The REC Pricing Model uses a modified version of National...

February27,2018Update

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AppendixD‐RECPricingModelDescription

RECPricingApproach

The objective of the REC Pricing Model is to calculate the revenue and incentive levelsrequired for a typical distributed solar or community solarproject tomeet its thresholdinvestment requirements and the associated price in $/REC (“the REC price”).1 ThecalculatedRECpriceshouldberepresentativeofapricethatwouldbesufficienttoallowadeveloperofatypicalsystemtomeetaproject’sexpensesanddebtserviceobligations,aswellastheequityinvestors’minimumrequiredafter‐taxrateofreturn.

The calculated REC price is net of (i) revenues received through net metering, (ii) anyassumedincentivessuchasfederaltaxcredits,and(iii)theDistributedGenerationRebate2value(“SmartInverterRebate”),ifapplicable.

Under Section16‐107.5(j) of thePublicUtilitiesAct (“PUA”), netmetering is a credit forenergy,3 transmission, and distribution charges for the net generation produced bydistributedgenerationprojectsuntilnetmeteringaccountsfor5%ofthetotalpeakdemandof theelectricityprovider’seligible customers.For systems that receiveaSmart InverterRebate, thenetmetering credit doesnot includedistribution charge credits, pursuant toSection16‐107.6(c)(3)ofthePUA.Forcommunitysolar,netmeteringisforenergysupplychargesonly.(Oncethe5%levelisreached,netmeteringforallnewinstallations,includingdistributedgeneration,willbeforenergyonly.)

AsfurtherdescribedinthesectionontheRECpricecalculation,theRECPricingModelissetupusingthefollowingsixcapacity‐basedbinsforblockpricing:

upto10kWAC

greaterthan10to25kWAC




greaterthan500to2,000kWAC

Thereisonepriceforallsystemswithinabin.Thebinswerechosenbasedontheavailablepricingdatapointsasdescribedinthesectiononinstallationcostdataandstakeholderinputreceived on the draft Long TermRenewable Resources Procurement Plan (“LTRRPP” or

1Themodelusesinputsfromcurrentlyavailableinformation,includingcurrentutilityratesandtariffs.AsdiscussedinSection6.4ofthePlan,inputswillbeupdatedafterthePlanisapprovedbytheCommissionin2018.2See,generally,220ILCS5/16‐107.6.3 For residential customers, the utility’s energy supply charge generally includes capacity charges billed by the relevant RegionalTransmissionOrganization(“RTO”).

AppendixD February27,2018Update

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“Plan”).4Abaseprice iscalculated for themosteconomicblocksize(greater than500to2,000kW),andthepricesfortheotherbinsaredeterminedthroughtheuseofadjustments,asfurtherdescribedinthesectionontheRECpricingcalculation. Theadjustmentsweredeterminedusingamidpointapproachandusingthesamemodelthatwasrunforthebaseprice,asfurtherdescribedinthesectionondistributedgenerationRECmodeladjustments.CommunitySolarprojectsfaceadditionalcostsandlessrevenuethandistributedgenerationsystems.Ontherevenueside,theyareeligibleonlyforenergy‐onlynetmetering,5whileonthecostside,theremaybethecostofacquiring,maintaining,andmanagingsubscribers.Theinitialblockpriceforcommunitysolarreflectsabaselineforthoseadditionalcostsandlowerrevenue.ToensurethatthebenefitsofsolarenergyarewidelysharedbyIllinoisresidents,theAdjustableBlockProgram(“ABP”)willofferanadditionalincentiveforcommunitysolarprojectswithahigherlevelofparticipationbysmallsubscribers.Therewill,therefore,beanadder to incentivize small subscriber participation. Projectsmeeting a small subscriberparticipation requirement of 25% to 50%, over 50% to 75%, or greater than 75%willreceivetheadditionaladder.

ThisAppendixDreflectsthesuggestedchangesthatweremadeintheLTRRPP’sdocketedproceedingandadoptedbytheProposedOrder,aswellasrecentlyimplementedlegalandregulatorychanges.6

TheIPAalsonotesthattheRECpricespresentedinthisAppendixDmaychangebasedon comments received and any other updates to the input assumptions as theybecomeavailable.

ModelSelectionandDescription

TheRECPricingModelusesamodifiedversionofNationalRenewableEnergyLaboratory’s(“NREL”)publiclyavailableCostofRenewableEnergySpreadsheetTool(“CREST”).7CRESTiswidelyknownandrespectedintherenewableenergyindustry.ForthepurposeofsettingRECpricesfortheABP,modifications(asdescribedinthefollowingsections)tothemodelinputsandformatoftheoutputsweremadesoastorefinetheresultsforuseindeterminingRECpricesfortheblocks.8

TheCRESTmodelwasdevelopedbyNRELtoaidpolicymakers,regulatorsandrenewableenergy developers with estimating renewable energy costs for various public policypurposes, such as establishing cost‐based or performance‐based incentives. The modelcalculatesthetotalincentivenecessaryforarenewableprojecttocoveritscostsandachieveanecessaryeconomicreturntotheprojectdeveloperand/orinvestors.

4TheAgencyissuedthedraftLTRRPPonSeptember29,2017.ThedeadlineforthesubmissionofstakeholdercommentswasNovember13,2017.TheAgencyfiledthePlanwiththeIllinoisCommerceCommissiononDecember4,2017inDocketNo.17‐0838. 5220ILCS5/16‐107.5(l)(2).6ThesechangesaredetailedintheRECPricingModelUpdateaccompanyingthisFebruary27,2018updatetoAppendixD.

7TheCRESTmodelisavailableonNREL’swebsite:https://financere.nrel.gov/finance/content/crest‐cost‐energy‐models.8Asdescribedintheprevioussection,theCRESTmodeloutputisnotthefinalRECprice,asrevenuesreceivedfromnetmeteringmustbenettedoutfromthepresent‐valueCostofEnergy(“COE”).


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AsdescribedintheUserManualpublishedwiththeCRESTmodel,CRESTatitscoreisaneconomic cash flow model designed to assess project economics, design cost‐basedincentives(e.g.,feed‐intariffs(“FITs”)),andevaluatetheimpactofvariousstateandfederalsupportstructures.9CRESTisasuiteoffouranalytictools,oneeachforsolar(photovoltaicandsolarthermal),wind,geothermal,andanaerobicdigestiontechnologies.

TheCRESTUserManualprovidesasummaryoftheprimaryandsecondarymodeloutputs:10

Theprimaryoutputisthemodeledproject’sCOE.TheCOEistheyear‐onepriceincentsperkilowatthour(¢/kWh)necessaryfortheprojecttomeetallexpensesand debt service obligations (if applicable), aswell as the equity investors’minimumrequiredafter‐taxrateofreturn.Atthemodeluser’sdiscretion,theCOEcanbecalculatedtoassumeanescalationrate(appliedtoalloraportionoftheinitialrate)overtime.IncalculatingtheCOE,theCRESTmodelincludestheoptiontospecifybothapercentageofthetariffsubjecttoescalationandtheassociatedtariffescalationrate.Theresultscanbeused to informarangeofcost‐basedincentives,includingFITrates.

Thesecondaryoutputisthemodeledproject’slevelizedcostofenergy(LCOE)11.TheLCOE isasingle, fixed,non‐escalatingvalueover the incentive’spaymentduration. The escalating stream of payments generated by the COE and theconstantstreamofpaymentsgeneratedbytheLCOEhavethesameNetPresentValue (NPV) when discounted at the same required rate of equity return.PolicymakerscanrefertotheLCOEoutputifpolicyobjectivesfavorasingle,fixedpriceperkWh for the lifeof thecost‐based tariff. If the tariff rateescalationfactorissettozero,thenthecalculatedCOEandLCOEvalueswillbeequal.

CRESTprovidestheinterfacefortheinputassumptionsnecessaryforthecalculationofaREC price for a solar photovoltaic project including, but not limited to (i) capital costs(moduleandinvertercosts,balanceofplantcosts,interconnectioncosts,developmentcostsand fees, reserves and financing costs), (ii) operations andmaintenance costs, (iii) cost‐basedtariffratestructure,and(iv)federalandstateincentives/rebates/taxcredits,etc.TheRECPricingModelusesinputassumptionsmodifiedfromthedefaultCRESTvaluesthatare based on more current and granular installation cost data, input from stakeholderresponses to both the Request for Comments 12 and the draft LTRRPP, and conclusionsdrawnfromintervenorcommentsinICCDocketNo.17‐0838.

9Gifford,JasonS.&Grace,RobertC.“CRESTCostofRenewableEnergySpreadsheetTool:AModelforDevelopingCost‐BasedIncentivesintheUnitedStates.”UserManualVersion4.July2013.https://financere.nrel.gov/finance/files/crest_user_manual_v‐4.pdf.10Ibid,pages3‐4. 11The“levelizedcost‐of‐energy”ispresentedeitherasaconstantpriceineachyear(nominallevelized)orasaconstantpriceadjustedforinflation(reallevelized).RealLCOEisoftenusedforcomparativestudies,whereasthenominalLCOEistypicallyusedinsetting,describing,orestablishingactualprices.TheCRESTmodelcalculatesanominalLCOE.12TheRequestforCommentswassentoutfollowingtheAgency’sMay17,2017andMay18,2017workshopsheldinChicagotodiscussthe Renewable Portfolio Standard, Adjustable Block Program, Community Renewable Generation Program, and Illinois Solar for AllProgram.TheRequestforCommentswassentouttostakeholdersonJune6,2017.StakeholderresponseswerereceivedbyJune27,2017.


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InstallationCostData

RegardingtheinputstotheCRESTmodel,inparticularinstallationcostdata,anumberofstakeholders suggested that the IPA issue a survey to stakeholders involved in thedevelopmentofsolarprojectstodeterminetheinputstothemodel.Therewasasuggestionto use the survey issued by the Massachusetts Department of Energy Resources (“MADOER”) as part of the SolarMassachusetts Renewable Target (“SMART”) program. TheAgency reviewed theMADOERTask1Report13whichhighlighteddataquality concernsarisingfromthestakeholdersurvey.Inparticular,thereportnotedthatself‐reportedsystemcostsfortwoofthelargestresidentialinstallersinthedatasetweresignificantlyabovethecosts reported by other firms.14 The report deemed the self‐reported data from theseinstallers as questionable and removed them from the dataset. Because of concernsregardingdataquality,basedontheMassachusettsexperience,theAgencydecidedagainstissuingasimilarsurvey.Asaresult,theIPAmadeadecisiontousepubliclyavailabledatafortheRECPricingModel.

Todevelop theRECPricingModel, severaldata sources forpopulating theCRESTModelwerereviewedandanalyzed—includingbutnotlimitedto(i)NRELQ12017BenchmarkingReport,15 (ii) LBNL Tracking the Sun Report – September 2017,16 (iii) NREL Open PVReport,17 and (iv) SEIA/GTMResearch (US SolarMarket Insight –Q22017).18 While allreviewedreportsprovidenationalaveragedata,duetotheimmaturityoftheIllinoissolarmarket,thereportsdonotprovidedetailedIllinois‐specificinstallationcostdata.

TheRECPricingModelusestheNRELQ12017BenchmarkingReport,whichprovidesthemostdetailintermsofcostcategoriesnecessaryforpopulatingtheCRESTModel.Thereportpublishesthefollowinginstallationcostcategories:

Module Inverter BalanceofSystem(“BOS”) InstallationLabor&Equipment Permitting,InspectionandInterconnection EPC19Overhead DeveloperOverhead

TheNRELQ12017BenchmarkingReportmodelsandprovidesnationalcostaveragesforaResidentialSolarProject,aCommercialSolarProject,andaUtilityScaleProject.TheaverageResidential Systemmodeled in theNREL report is 5.7 kWDC. The averageCommercial 13 Task 1 Report: Evaluation of Current Solar Costs and Needed Incentive Levels Across Market Segments. Seehttp://www.mass.gov/eea/docs/doer/rps‐aps/doer‐post‐400‐task‐1.pdf.14Ibidatsection4.2.1. 15https://www.nrel.gov/docs/fy17osti/68925.pdf.16https://emp.lbl.gov/publications/tracking‐sun‐10‐installed‐price.17https://openpv.nrel.gov.18Reportavailablethroughsubscription.19EPCstandsforengineering,procurement,andconstruction.


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Systemmodeledis200kWDC.Thereport,however,alsomodelsandprovidesthecostsfor100kWDC,500kWDC,and1,000kWDCsystems.

Table D‐1 throughTableD‐6provideananalysisoftheinstallationcostsbasedontheNRELReport.Theprojectcosts reflect the total installation costs of building the DC system equivalent of an ACsystem.20ToconvertanACsystemtoaDCsystemanAC‐DCconversionlossfactorof25%wasused.21Forexamplea2,000kWACsystemtranslatestoa2,667kWDCsystem.Theproject costsalso include the impactof thesolar import tariffs thatwere imposedbyUSPresidentDonaldTrumpon crystalline siliconphotovoltaic cells andmodules in January2018.ThischangeisimplementedintheRECpricingmodelbyassuminganincreaseinthecostofgenerationequipmentequalto8centsperwattDC.

TableD‐1‐ResidentialSolarPVInstalledCosts(Scaledfrom5.7kWSystem)

TotalProjectCost($) 10kWAC

$/WDC $/kWDC 13kWDCModule 0.43 430 $5,733Inverter 0.19 193 $2,580

HardwareBOS‐StructuralComponents 0.11 113 $1,512HardwareBOS‐ElectricalComponents 0.24 244 $3,257

SupplyChainCosts 0.42 419 $5,582SalesTax 0.09 89 $1,186

InstallationLabor 0.30 304 $4,052Permitting,InspectionandInterconnection(PII) 0.10 96 $1,275

TotalEPCCost 1.89 Sales&Marketing(CustomerAcquisition) 0.34 343 $4,570

Overhead(General&Admin.) 0.31 308 $4,105NetProfit 0.35 346 $4,613

TotalInstallationCost 2.88 2,885 $38,465

NRELModelCategories GenerationEquipment $12,418

BalanceofPlant $14,404Interconnection $1,275

DevelopmentCostsandFee $10,369Total $38,465

20JointSolarParties(“JSP”)Replyat23‐24.21JSPResponseat31.


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TableD‐2‐InstalledCosts(25kWSystem)22

TotalProjectCost($)

25kWAC 33kWDC




TableD‐3‐CommercialPVInstalledCosts(100kWSystem)

TotalProjectCost($)

100kWAC $/WDC $/kWDC 133kWDC

Module 0.43 430 $57,333Inverter 0.10 104 $13,913


InstallationLabor&Equipment 0.23 231 $30,851Permitting,InspectionandInterconnection(PII) 0.15 154 $20,534

EPCOverhead 0.22 216 $28,848SalesTax 0.05 55 $7,283

TotalEPCCost 1.53 Contingency(4%) 0.05 51 $6,841

DeveloperOverhead 0.40 397 $52,898EPC/DeveloperNetProfit 0.13 133 $17,686TotalInstallationCost 2.11 2,108 $281,005




22Costs for the25kWsystemreflectanaverageof the installedcosts fora systemscaledupwards from5.7kWanda systemscaleddownwardsfrom100kW.The25kWsystemsizewasincorporatedinresponsetovariousstakeholdercommentsontheDraftLTRRPP.


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TotalProjectCost($)

200kWAC $/WDC $/kWDC 267kWDC

Module 0.43 430 $114,667Inverter 0.10 104 $27,826





DeveloperOverhead 0.40 397 $105,796EPC/DeveloperNetProfit 0.12 121 $32,277TotalInstallationCost 1.93 1,930 $514,706





TotalProjectCost($) 500kWAC

$/WDC $/kWDC 667kWDCModule 0.43 430 $286,667Inverter 0.10 104 $69,565





DeveloperOverhead 0.40 397 $264,490EPC/DeveloperNetProfit 0.12 116 $77,276TotalInstallationCost 1.85 1,852 $1,234,557



DevelopmentCostsandFee $264,490Total $1,234,557


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TableD‐6‐CommercialPVInstalledCosts(Scaledfrom1,000kWSystem)

TotalProjectCost($) 2,000kWAC

$/WDC $/kWDC 2,667kWDCModule 0.43 430 $1,146,667Inverter 0.10 104 $278,261





DeveloperOverhead 0.40 397 $1,057,962EPC/DeveloperNetProfit 0.11 114 $303,732TotalInstallationCost 1.82 1,821 $4,856,101

NRELModelCategories GenerationEquipment $2,422,452

BalanceofPlant $1,096,642Interconnection $279,045

DevelopmentCostsandFee $1,057,962Total $4,856,101

Because theprogramsareexpected to launch in2019, theNRELQ12017BenchmarkingReportcostswererolledforwardtwoyearsbyreducingpricesby4%peryear,reflectingrecenthistoricaltrendsinsolarpricedeclines.23

OtherCostData

The REC Pricing Model also relies on the following sources for data on the other costsrequiredtopopulatetheCRESTmodel.

Financing and operating cost data was obtained from the following sources – (i)CRESTmodeldefaultassumptions, (ii)ElevateEnergy’sCommunitySolarmodel,24and(iii)variousstakeholdercommentsontheDraftLTRRPP.

Inresponsetostakeholdercommentsandusingdataprovidedbystakeholders,theIntermediatecategoryofdetailwasutilizedforoperationsandmaintenancecost.

Netmeteringandelectricitypricingdatawasobtainedfromtheutilities’filedtariffs.

23BasedonstakeholderresponsestotheDraftPlan,interconnectioncostswerenotrolledforward.24https://www.illinois.gov/sites/ipa/Documents/Elevate‐Energy‐L‐RRPP‐Request‐Comments‐20170714‐Updated.pdf.


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ThefederalInvestmentTaxCreditwasextendedin2016toprovidea30percenttaxcreditthatwouldrampdownincrementallythrough2021andremainat10percentfrom2022forward.

LocationalMarginalPrices(“LMPs”)providedbytheJSP.25

TheAC‐DCconversionfactorof25%wasprovidedbytheJSP.26

The14%DCCapacityFactorfordistributedgeneration,andthe15.5%DCcapacityfactorforcommunitysolarsystemswereprovidedbytheJSP.27

RECPriceCalculation

DistributedGenerationModel28

Asnotedbefore,theRECPricingModeladaptsandmodifiestheNRELCRESTmodelforthepurposesofcalculatingRECpricesforthisPlan.TheCRESTmodelisaneconomiccashflowmodelthatestimatesthecostofenergyassociatedwithspecificinputassumptionsregardingtechnologytype,location,systemcapitalandoperatingcosts,expectedproduction,projectusefullife,thedurationofthecost‐basedtariff,andvariousprojectfinancingvariables.Thedistributedgenerationmodelwasrunwithmodificationsmadetocertaininputassumptionstoreflectcurrentpubliclyavailabledataandinputfromstakeholdercommentsinresponseto the draft Plan. Modified assumptions are annotated with a source document andhighlighted in yellow in the accompanying REC Pricing Model Excel spreadsheets (seeAppendicesE‐1throughE‐5). Asnotedearlier, theapproachforRECpricing isbasedoncalculatingabaseprice for themosteconomicblocksize (500 ‐2,000kWAC),and thendeterminingthepricesoftheotherprojectsizesthroughadjustments.ThebaseRECpriceisbasedonthecostsfora2,000kWACprojectandisthepriceforthefirstAdjustableBlockProgramblock.TheRECpricedeclinesby4%foreachsuccessiveblockafterBlock1,asitisanticipatedthatnecessaryincentiveswilldeclinewiththedecliningcostofsolar.The4%isbasedontheaverageannualdropinsolar installationcostsasestimatedintheNRELQ12017BenchmarkingReport.29Theblocksandpriceshavebeenstructuredwiththegoalofmeetingtheprocurementtargetsbytheendofthedeliveryyear2020.Thepricesalsotakeintoaccount(i)thechangeinthefederalcorporateincometaxrate,whichonDecember22,2017wasreducedfrom35%to21%,and(ii)theauthorizationof100%bonusdepreciationforfederalincometaxpurposeforpropertyplacedinserviceafterSeptember27,2017andbeforeJanuary1,2023.

Thedistributedgenerationmodelprovidesresultsundertwoscenarios.Forsystemsover10kWto2,000kWAC,themodelincludesanassumptionthatthesystemisnon‐residentialandelectstotaketheSmartInverterRebateandthus,understatelaw,doesnotreceivenet

25https://www.illinois.gov/sites/ipa/Documents/2018ProcurementPlan/2018‐LTRenewable‐Joint‐Solar‐Parties‐Comments.pdf.26JSPResponseat31.

27JSPObjectionsat31‐33.28PresentedinAppendixE‐1‐AdjustableBlockProgramDistributedGenerationPricingModel.29https://www.nrel.gov/docs/fy17osti/68925.pdf.


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meteringdistributioncredits.30Forsystemsupto10kWAC,themodelassumesthesystemis residential and thus does not receive the Smart InverterRebate, instead receivingnetmeteringdistributioncredits.

TheSmartInverterRebateof$250perkWDC,asdiscussedinSection6.8.2ofthedraftPlan,accountsforanafter‐taxcreditof$603,333forthe2,000kWACsystem.(Itisassumedthatiftheprojectisover10kWAC,itelectstotaketherebateunderSection16‐107.6(c)(1)ofthePublicUtilitiesAct.)TheSmartInverterRebateisappliedasanadditionalstaterebateintheCRESTmodelonadollarperwattbasisat$0.25perwattDC,applicableonlytotheprojectsizeslargerthan10kWACinthedistributedgenerationmodelandtreatedastaxableincome.

Fortheup‐to‐10kWACprojectsizeinthedistributedgenerationmodel,theIPAconsideredtheimpactofthefederaltaxlawchangesregardingbonusdepreciation.Inthisregard,itistheIPA’sviewthathavingbonusdepreciationat100%maymakethird‐partyownershipofsmallsystemsmorelikely,comparedtoownershipbyahomeowner,becausebeingabletocapture bonus depreciation will be more attractive. For this reason, the 100% bonusdepreciationisnowalsoappliedtotheup‐to‐10kWACprojectsize.

The present‐value cost of energy (“PV COE”) for each project size is calculated over theprojectusefullife,25years,bytakingthepresentvalueofthefifteenyeartariffprice(i.e.thetotaldollarvalueincentivenecessaryforaprojecttocoveritscostsandachieveanecessaryeconomicreturntotheprojectdeveloperand/orsubscribers)andtenyearsofpresentvalueexpectedpost‐tariffmarketrevenues.

TherawPVCOEoutputcalculatedusing thecash flows fromthemodifiedversionof theCRESTmodelforthe2,000kWACsystemsizeisnotthefinalbaseRECprice.Thepresentvalueoftheexpectednetmeteringrevenues(adjustedto80%ofthemarketvaluetoaccountfor20%subscribersavings)over25yearsbyutilitymustthereforebesubtractedfromthePVCOEtogettherevenueshortfall–which,afterdividingbytheexpectedproductionoverthefirst15years,isequivalenttothenetPVCOEorthefinalbaseRECprice.TherearethreebillchargecategoriesthatmayfallunderthenetmeteringtariffthatareassumedcreditstoABP participants, including the energy supply, transmission, and distribution volumetriccredits.31 For the distributed generation model pricing bins, it is assumed that eligiblecustomerswillreceivethenetmeteringtariffincluding,asapplicablebycustomertype,thecreditsfortheenergysupply,transmission,anddistributioncharges,asspecifiedbyeach

30See220ILCS5/16‐107.6(c)(1),(3).31Itisassumedthataresidentialcustomerwithasolarsystemwillreceivefullretailnetmeteringwithallthreeofthesecredits.220ILCS5/16‐107.5(d),(d‐5).Anon‐residentialcustomerthatelectedthe$250/kWrebateunderSection16‐107.6(c)(1)ofthePublicUtilitiesActwouldnolongerbeeligibletoreceivethedistributionservicerateportionofthenetmeteringcredit,butwouldstillreceivecreditsforenergyandtransmissioncharges.220ILCS5/16‐107.6(c)(3).Moreover,itisassumedthatresidentialcustomers’existingenergysupplyrateisthetariffed,bundledrateprovidedbytheutility(RateBESforComEdorRateBGS‐1forAmerenIllinois),whilenon‐residentialcustomers’existingenergysupplyrate isanhourlyrate thatcanbeapproximatedbytheapplicableRTO’sLocationalMarginalPrices(“LMPs”)fortheapplicablegeographicareaofIllinois.

ThecommunityrenewablenetmeteringtariffforComEdapprovedbytheCommissiononSeptember27,2017includescreditsforonly theenergysupplyrate(which includescapacity),butnot transmissionordistributionrates. Ameren Illinois’netmetering tariffapprovedbytheCommissiononthesamedatecreditscommunityrenewablenetgenerationattheenergysupplyrate.


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utilityforthecorrespondingcustomerclass.Thepresentvalueofthenetmeteringcreditovertheprojectusefullifeforeachprojectsizewascalculatedonatotaldollarbasisthataccountsfortheexpectedproductionforeachsystemsize.Forthedistributedgenerationmodel,thenetmeteringcreditappliedtothepricingbinsincludingprojectsizesbetween10and2,000kWACassumessubscriberswillbeinthecommercialandindustrial(“C&I”)rateclasses. The net metering credit applied to the up‐to‐10 kW AC pricing bin assumessubscriberswillbeintheresidentialrateclass.

For thedistributedgenerationpricingbins thatassumeC&Isubscribers,only theenergysupply and transmission credits were applied as part of the expected net meteringrevenues.32TheenergysupplycreditforeachutilitywascalculatedbyaveragingtheannualaverageLMPs for the last five fullcalendaryears for2018,escalatedat2%toreflect theassumedinflationrate.33Transmissioncreditsforthe2017‐2018deliveryyearweretakenfrom the utility tariffs. For Ameren Illinois, the transmission credit was calculated byconvertingthetransmissionchargeasprovidedintheutilitytariffin$/kW‐daytoa$/kW‐Monthvalue,whichwasfurtheradjustedbytheestimatedpeakloadcontribution(“PLC”)andcapacityfactortoarriveata$/kWhvalue.ForComEd,thetransmissioncreditfromthetariffwassimplyconvertedfroma¢/kWhvaluetoa$/kWhvalue.

For systems up to 10 kW, the energy supply credit for each utility was calculated as aweightedaverageofretailpurchasedelectricitycharges($/kWh)forthefoursummerandeightnon‐summermonthsforthe2017‐2018deliveryyear;furtheryearsareextrapolatedfromthe2017‐2018deliveryyearpriceassuminga2%annualinflationrate.TransmissioncreditswerecalculatedinthesamemannerastheywerefortheC&Iclassbutinsteadusingtheresidentialclasstariffrates.Thedistributioncredit fortheAmerenIllinoisresidentialclasswascalculatedbytakingtheweightedaveragedistributionchargein$/kWhoffourmonthsofsummerandeightmonthsofnon‐summertariffrates(forcalendaryear2017),34while the residential class ComEd customer distribution credits were calculated bymultiplyingthevolumetricdistributionchargeforcalendaryear2017bytheIncrementalDistribution Uncollectible Cost Factor (“IDUF”) for the residential single family withoutelectricspaceheatcustomerclass.35

Various stakeholders suggested that a measure of subscriber (for community solar) orpropertyowner(fordistributedsolar)savingsbeapplied to thenetmeteringcredit; thissavingswouldbe excluded fromcontributing to the assumed rate of returnon the solargeneration investment. In the distributed generationmodel, 20%customer savingswassuggestedandapplied,thusreducingthenetmeteringcreditvalueto80%.TableD‐7shows

32See220ILCS5/16‐107.6(c)(1),(3). TheModelassumesaC&Isubscriberwillelect theSmart InverterRebateandthereby losenetmeteringcreditsfordistributioncharges.33Ibid.34AmerenIllinois’volumetricdistributionchargesdifferinsummervs.non‐summer.35TheAgencyupdatedthese figuresafter the IllinoisCommerceCommissionapprovednewcalendar‐year2018distributionrates forComEdandAmerenIllinoisinordersissuedinDecember2017throughFebruary2018,inDocketNos.17‐0196and18‐0034(ComEd)and17‐0197and18‐0210(AmerenIllinois),respectively.


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the25‐yearpresentvaluenetmeteringcreditforeachprojectsizeat80%forbothAmerenIllinoisandComEdforthedistributedgenerationmodel.

TableD‐7‐25‐yearPresentValueNetMeteringCreditat80%($)36

SystemSize AmerenIllinois ComEd10kWAC $14,406 $15,11225kWAC $18,546 $18,402100kWAC $75,174 $74,590200kWAC $151,556 $150,380500kWAC $380,432 $377,4792000kWAC $1,524,304 $1,512,472

ThemodifiedCRESTmodel,includingtheSmartInverterRebateasdescribedabove,wasruntocalculatethePVCOEforthe2,000kWACsystemsizeinordertosetthebaseRECpricetowhichpricingbinadjustmentsareapplied.Fortheup‐to‐10kWACcategory,themodeldidnotincludetheSmartInverterRebate,asresidentialsystemsarenotcurrentlyeligibleforthat rebate under Section 16‐107.6(c)(1) of the PUA, but did include net meteringdistributioncredits.

AmerenIllinoisandComEdRECpricesarenotderivedfromonlythePVCOEoutputfromthemodelastheRECpriceissetbysubtractinganynetmeteringcredits,whichdifferbyutility,fromthePVCOEtoarriveatthefinalbaseRECpriceasshownbelow.

BaseRECPrice($/REC)37=25‐yearPVCOEfor2,000kW($)–25‐yearPVUtilityNetMeteringCreditsat80%($)/15‐yearRECproduction(MWh)

AftercalculatingthebaseRECpricefora2000kWACsystem,pricingbinadjustmentswerecalculatedfortheotherdistributedgenerationbins,i.e.,(i)upto10kWAC,(ii)greaterthan10to25kWAC,(iii)greaterthan25to100kWAC,(iv)greaterthan100to200kWAC,and(v)greaterthan200to500kWAC,basedonamidpointapproachusingtheIPA’smodifiedCRESTmodeloutputforthebinsizebookends.ThepricingbinadjustmentswerecalculatedusingthenetPVCOEoutputfromthemodifiedCRESTmodelforeachofthesystemsizesthatbookendapricingbinasshownin

TableD‐8.ThenetPVCOEforeachsystemsizeiscalculatedbysubtractingtherelevantnetmetering credits after accounting for subscriber savings for the system size from themodeledPVCOEoutputforthatsystemsize.Tocalculatetheadjustmentforeachsize‐basedbin,themidpointbetweenthenetPVCOEforthetwobookendsystemsizeswascalculated.TheadjustmentforeachpricingbinisontopofthebaseRECprice.Eachadjustmentisthedifferencebetween(i)themidpointofthecalculatedNetPVCOEforthetwobookendsystemsizesforthatbin,and(ii)thebaseRECprice.Adjustmentsdifferbyutilitybecausethenet

36Referencesto“AmerenIllinois”and“ComEd”inthisTableD‐7aswellassubsequenttablesinthisAppendixD,denote“GroupA”and“GroupB”describedinChapter6ofthePlan.37OneRECisequaltoonemegawatt‐hour(“MWh”)ofelectricitygeneratedsuchthat$/RECareequivalentto$/MWh.


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meteringtariffsdifferbetweenthetwolargestutilities.Theresultingadjustmentforeachutilityandpricingbin isshown inTableD‐9. Bywayofexample, the100to200kWACadjustmentwascalculatedasshownbelow:

[greaterthan100to200kWACAdjustment]=[averageof100kWACNetPVCOE&200kWACNetPVCOE])–[BaseRECPrice]

The smallest system size incorporates any systemup to 10 kWAC. As noted above, fordistributedgeneration,thisisassumedtobearesidentialsystem.Theadjustmentfortheupto10kWsizeisthedifferencebetweentheNetPVCOEfora10kWACsystemandthebaseRECpricefordistributedgeneration.

TableD‐8‐ModifiedCRESTModelResults38

SystemSize

AmerenIllinoisNetPVCOE($/MWh)

ComEdNetPVCOE($/MWh)

10kWAC $80.23 $77.2525kWAC $73.81 $74.06100kWAC $57.45 $57.70200kWAC $49.50 $49.75500kWAC $46.09 $46.342000kWAC $44.37 $44.62

TableD‐9showsthedistributedgenerationpricingbinadjustmentsforeachutilityand

TableD‐10showsthedistributedgenerationABPRECpriceforeachutilityandpricingbin.Forexample,the100to200kWbinRECpriceiscalculatedbyaddingthatbin’sadjustment($9.11)tothebaseRECpriceof$44.62forComEdor$44.37forAmerenIllinois.

TableD‐9–DistributedGenerationPricingBinAdjustmentsforEachUtility39

Bin

AmerenIllinoisAdjustment($/REC)

ComEdAdjustment($/REC)

≤10kWAC $35.87 $32.63>10to25kWAC $32.66 $31.04>25to100kWAC $21.27 $21.26>100to200kWAC $9.11 $9.11>200to500kWAC $3.43 $3.43>500to2,000kWAC $0.00 $0.00

38TheresultsinthistablearethePVCOEoutputfromtheCRESTmodelpriortosubtractingthenetmeteringcreditsshowninTableD‐7fromthePVCOEanddividingbytheexpectedRECproductionover15years.39Pricingbinadjustmentsfortheup‐to‐10kWsystemsizeandthe10‐25kWACsystemsize(i.e.thetwosmallestpricingbins)areunequalacrossthetwoutilitiesbecausethechangeinnetmeteringcreditsfromC&Itoresidentialdiffersacrossthetwoutilities’tariffswhilethePVCOEdoesnot.


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TableD‐10–DistributedGenerationABPRECPrices

BinAmerenIllinoisRECPrice($/REC)

ComEdRECPrice($/REC)


CommunitySolarModel40

Communitysolarprojectsweremodeledundervariousassumptionsthatdifferedfromthedistributed generation projects. As noted above, community solar projects receive apricingbinadjustmentcalculatedinthesamemannerasdescribedforthedistributedgeneration adjustment, and an adder to incentivize small subscriber participation.Projects thatmeetorexceeda25%,50%,or75%requirement forsmallsubscriber41participation will receive the additional adder (“the Small Subscriber ParticipationAdder”).Thecalculationofthecommunitysolarpricingbinadjustmentsandaddersisbasedonchangingtheassumptionstothenetmeteringcreditandchangingsomeofthemodelinputassumptions.ForComEd,asapprovedbytheCommissiononSeptember27,2017inDocketNo.17‐0350,thenetmeteringcreditincludesenergysupplychargesbutdoesnotincludetransmissionordistributioncharges.ForAmerenIllinois,asapprovedbytheCommissiononSeptember27,2017intariffno.ERM17‐144,thetariffcreditstheenergyservicebillsofsubscribersatthe“tariffedorcontractrateforelectricitysupplyas appropriate.” The tariffed or contract rate does not include transmission ordistributioncharges. Forcommunitysolarprojects,allprojectsizeswereassumedtoreceiveenergy‐onlyC&Inetmeteringcreditsbasedonthefive‐yearaverageLMPafteraccountingfor20%subscribersavings.Additionally,allcommunitysolarprojectsizeswere assumed to take the Smart Inverter Rebate applied to the project in the samemannerasitwasappliedtodistributedgenerationprojects10kWACorlarger.42

40PresentedinAppendixE‐2‐AdjustableBlockProgramCommunitySolarPricingModel.41“Smallsubscriber”isusedtomeanresidentialorsmallcommercialcustomersubscribers,asreferencedinSection1‐75(c)(1)(N)oftheIPAAct.Theseareidentifiedusingtheirsubscriptionsizes:anysubscriptionbelow25kWACisassumedtobebya“smallsubscriber.”42Acommunitysolarproject,oritssubscribers,areentitledtoreceivetheSmartInverterRebate.220ILCS5/16‐107.6(f).


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TableD‐11showsthe25‐yearpresentvaluenetmeteringcreditforeachprojectsizeat80%forbothAmerenIllinoisandComEdforthecommunitysolarmodel.


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TableD‐11‐25‐yearPresentValueNetMeteringCreditat80%($)

CustomerClass AmerenIllinois ComEd

10kW AC $4,888 $5,99725kWAC $12,344 $15,145100kWAC $50,070 $61,430200kWAC $100,988 $123,900500kWAC $253,553 $311,0782000kWAC $1,016,022 $1,246,532

Input assumptions changed for community solar projects, aside from those noted aboverelatedtothenetmeteringcredit,reflectstakeholdercommentsandincludeanincreasedinternalrateofreturn,43theinclusionofMACRSbonusdepreciationinfederaltaxationforallproject sizes (including theup‐to‐10kWACsize), andadditionaldataoncostsfacing a community solar project (i.e., land lease, property taxes). REC prices forcommunity solar projects for each utility were calculated in the same manner asdistributed generation REC prices where a base community solar REC price wascalculated and calculated pricing bin adjustments applied to the successively smallerprojectsizebins.Bywayofexample,thecommunitysolarpriceforthegreaterthan100to200kWACisthedifferencebetweenthegreaterthan100to200kWACadjustmentand thebase community solarRECprice. The resulting community solarpricingbinadjustments are shown in Table D‐12Error! Reference source not found.44 andcommunitysolarRECpricesareshownin

43Theassumedinternalrateofreturnis14%inthecommunitysolarmodelinsteadof12%inthedistributedgenerationmodel.44Duetothesamenetmeteringcreditbeingappliedtoallsystemsizes,thecommunitysolarpricingbinadjustmentsdonotvarybyutilityinpricingbinsthatincludethe10kWprojectsize.


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TableD‐13below.

TableD‐12–CommunitySolarPricingBinAdjustments($)

BinAmerenIllinoisREC

Price($/REC)ComEdRECPrice

($/REC)≤10kWAC $43.84 $44.01

>10to25kWAC $34.79 $34.94>25to100kWAC $18.67 $18.77>100to200kWAC $8.19 $8.23>200to500kWAC $3.19 $3.20>500to2,000kWAC $0.00 $0.00


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TableD‐13–CommunitySolarRECPrices($/REC)

BinAmerenIllinoisRECPrice($/REC)


≤10kWAC $96.12 $91.89>10to25kW $87.07 $82.82

>25to100kWAC $70.95 $66.65>100to200kWAC $60.47 $56.12>200to500kWAC $55.46 $51.09>500to2,000kWAC $52.28 $47.88

The IPA received comments from several stakeholders related to the ResidentialParticipationAdderspublishedinthedraftPlan.Toaddressthosecomments(andnotethattheAgencyalsoupdated theAdders toreflect “small subscribers” rather thanresidentialparticipation), the IPA utilized a recommendation by the Coalition for Community SolarAccess45 touse theresultsofananalysisby theRhode IslandOfficeofEnergyResources(“RIOER”)oncostassumptionsforcommunitysolar.RIOERconductedanindustrysurveyoncommunitysolaradministrativecostsrelatedtoprojectsthatallocateatleast50%oftheircapacity to subscription sizesof25kWor less. TheRIOERsurvey resultswere that theupfront (one time) subscriber acquisition costs associated with these projects are$0.25/Watt,andthattheongoing(annual)costsassociatedwithsubscriberreplacementis$0.02/Watt/year,and theongoing (annual)costof subscribermanagementandbilling isabout$0.01/Watt/year.46

InordertodeterminetheSmallSubscriberParticipationAdders,theIPAalsoreliedondataonprojectsize,andprojectenergyproductionprovidedbyElevateEnergyintheircommentsonthedraftPlan.47Intheircomments,ElevateEnergymodelleda1,250kWsystemwithanenergyproductionof33,794MWhover25years.First,todeterminetheincrementallifetimesubscribercostsfor50%SmallSubscriberParticipation,theIPAcalculatedthetotal$/Wattcostsfor50%smallsubscriberparticipationasdeterminedbyRIOER,byaddingtheupfrontcoststothepresentvalueoftheongoingcosts,discountedovera25‐yearperiodusinga6%discountrate.Thetotalcostis$0.76/Watt.Second,theIPAcalculatedthetotalprojectcostsbymultiplyingthetotalcostin$/Wattandtheprojectsizeof1,250kW.Thetotalprojectcost is$944,898. Third, the IPAcalculated theGross50%SmallSubscriberParticipationAdderbydividingthetotalprojectcostbytheproject’senergyproductionover25years.Theresultantadderis$27.96/REC.Fourth,theIPAadjustedtheaddertoaccountforthenetmeteringrevenueasubscriberwouldreceive.Inthisregard,usingtheRECPricingModel,theIPAdeterminedthedifferencebetweentheresidentialandC&InetmeteringvaluesforbothComEdandAmeren,totakeintoaccountthedifferencebetweenthebundledenergysupplyrateandtheLMPforeachofthetwoutilities.TheIPAthenapplieda2%escalation

45https://www.illinois.gov/sites/ipa/Documents/2018ProcurementPlan/2018‐LTRenewable‐Coalition‐for‐Community‐Solar‐Access‐Comments.pdf.46SEA.(2016)RhodeIslandRenewableEnergyGrowthProgram:20172ndDraftCeilingPriceRecommendations.Availableat:http://sos.ri.gov/documents/publicinfo/omdocs/minutes/6154/2016/49211.pdf. 47https://www.illinois.gov/sites/ipa/Documents/2018ProcurementPlan/2018‐LTRenewable‐Elevate‐Energy‐Comments.pdf.


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factortothenetmeteringcreditvaluesforthetwoutilitiesfor25years,andsubsequentlycalculatedthenetpresentvalueofalltheannualdifferencesusingthe6%discountrate.

Through extrapolation, the values were scaled down accordingly tomatch a 50% smallsubscriberparticipationlevel.TheIPAthendividedthepresentvaluesby25todetermineannualvaluesof$6.19/RECforComEdand$5.62/RECforAmeren(“theAnnualNetMeteringValues”).Next,theIPAsubtractedtheAnnualNetMeteringValuesfromtheGross50%SmallSubscriber Participation Adder to determine the net adders (“the 50% Small SubscriberParticipation Adders”). The 50% Small Subscriber Participation Adder for ComEd is$21.77/RECandforAmerenis$22.34/REC.Finally,theIPAdeterminedtheaddersforsmallsubscriberparticipation levelsof25%and75%, throughextrapolation. TheCommunitySolarSmallSubscriberParticipationAddersarepresentedinTableD‐14.

TableD‐14–CommunitySolarSmallSubscriberParticipationAdders

SmallSubscriberParticipation(%)

AmerenIllinoisAdder($/REC)

ComEdAdder($/REC)

Lessthan25% NoAdder NoAdder≥25‐50% $11.17 $10.88≥50‐75% $22.34 $21.77≥75% $33.51 $32.65

IllinoisSolarforAllModels48

TherearethreegroupsundertheIllinoisSolar forAllProgramthatreceive incentivesasdescribed in Chapter 8 of the Plan: Low‐Income Distributed Generation Initiative, Low‐Income Community Solar Project Initiative, and Incentives for Non‐Profits and PublicFacilities. There isaseparateapproachused forsettingRECprices foreachof the threeIllinoisSolarforAllgroups.TheIncentivesforIllinoisSolarforAllbuildonthemodelsusedfor theAdjustableBlockProgram. Forall threegroups, it isassumed that thecustomersavingsvalueallocatedfromthenetmeteringcreditisincreasedfrom20%to50%.

Section1‐56(b)(2)oftheActrequiresthattheIllinoisSolarForAllincentivesdelivertangibleeconomicbenefitsforeligiblelow‐incomesubscribers.Theincentivepaymentsforthelow‐incomesubscribersare intendedtobesufficienttoprovidetangibleeconomicbenefitstoparticipants through enabling project developers to eliminate upfront costs to theparticipants for the installationofphotovoltaicprojects.The incentivewillbea standardincentiveandnotcustomizedforeachproject.

TheCRESTmodelwasusedtodeterminethePVCOEforlow‐incomedistributedgenerationparticipantsbysettingthedebtfinancingparametertozeropercent,assumingtheywouldhavedifficultyaccessingcreditmarkets,andusingtheotherinputassumptionsmirroringthose used to calculate non‐low income distributed generation prices. Pricing bin

48PresentedinAppendicesE‐3‐aandE‐3‐b‐IllinoisSolarforAllDistributedGenerationIncentivePricingModel,E‐4:IllinoisSolarforAllCommunitySolarPricingModel,andE‐5:IllinoisSolarforAllNon‐profitandPublicFacilityPricingModel.


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adjustments were calculated in the same manner as for non‐low income distributedgeneration.TableD‐15providestheRECpricesforthelow‐incomedistributedgenerationparticipantsinlargerbuildings,whoareassumedtoreceive50%ofthenetmeteringvalue.TableD‐16providestheRECpricesforthelow‐incomedistributedgenerationparticipantsinsmaller(1‐4unit)buildings,whoareassumedtoreceive100%ofthenetmeteringvalue.

TableD‐15–Low‐IncomeDistributedGenerationInitiativeRECPrices(Multi‐FamilyBuildings)

Bin

AmerenIllinoisRECPrice($/REC)



TableD‐16–Low‐IncomeDistributedGenerationInitiativeRECPrices(1‐4UnitPropertyOwner)

Bin

AmerenIllinoisRECPrice($/REC)


≤10kWAC $143.09 $143.09>10to25kW $127.55 $127.55

>25to100kWAC $103.28 $103.28>100to200kWAC $90.40 $90.40>200to500kWAC $84.41 $84.41>500to2,000kWAC $80.69 $80.69

AsdescribedinChapter8ofthePlan,theLow‐IncomeCommunitySolarProjectInitiativeisintended tosupportparticipation incommunitysolarby low‐incomesubscribers.ForLow‐IncomeCommunitySolarProjectInitiativeparticipants,adifferentapproachwasused than the zero percent debt financing used for the Low‐Income DistributedGeneration Initiative. While the non‐low income community solar REC price wascalculated using the assumption of a 15‐year paybackperiod, theRECprices for thisgroupwas calculatedusinga shortened,5‐yearpaybackperiodanda lowerassumed35%debtfinancing.RECpricesforparticipantsofLow‐IncomeCommunitySolarProjectInitiativeareshowninTableD‐17.Low‐IncomeCommunitySolarvaluesinTableD‐17builduponthenon‐lowincomecommunitysolarRECpricesin


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TableD‐13underalteredassumptionsdiscussedabove.

TableD‐17–Low‐IncomeCommunitySolarProjectInitiativeRECPrices



($/REC)≤10kWAC $121.99 $119.55


Section1‐56(b)(2)(C)oftheActalsospecifiesthat“non‐profitsandpublicfacilities”willbeeligible to receive incentives for on‐site photovoltaic generation. These incentives aredesignedto“supporton‐sitephotovoltaicdistributedrenewableenergygenerationdevicesto serve the load associatedwith not‐for‐profit subscribers and to support photovoltaicdistributedrenewableenergygenerationthatusesphotovoltaictechnologytoservetheloadassociatedwithpublicsectorsubscriberstakingserviceatpublicbuildings.”49Tocalculatethe Incentives for Non‐Profits and Public Facilities participants, the input assumptionsremained the same as those used for low‐income distributed generation in all but twocategories. The owner was not considered to be a taxable entity for the purposes ofcalculating the Incentives for Non‐Profits and Public Facilities, and the up‐to‐10 kW ACproject sizewas considered to be a C&I subscriber, reflected in the netmetering creditappliedaswellastheinclusionoftheSmartInverterRebateforallprojectsizes.RECpricesfortheIncentivesforNon‐ProfitsandPublicFacilitiesareprovidedinTableD‐18.

TableD‐18–IncentivesforNon‐ProfitsandPublicFacilitiesRECPrices



($/REC)≤10kWAC $144.15 $142.38


4920ILCS3855/1‐56(b)(2)(C).

Appendix D REC Pricing Model Description...The REC Pricing Model uses a modified version of National...

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