Appendix D REC Pricing Model Description...2018/06/04 · Appendix D June 4, 2018 Update 3 incentives (e.g., feed‐in tariffs (“FITs”)), and evaluate the impact of various state

June4,2018Update

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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,theRECPricingModelissetupusingthefollowingsevencapacity‐basedbinsforblockpricing:

upto10kWAC greaterthan10to25kWAC greaterthan25to100kWAC greaterthan100to200kWAC greaterthan200to500kWAC greaterthan500to2,000kWAC Forco‐locatedcommunitysolarsystemsonly,greaterthan2,000kWAC(inaggregate

size)Thereisonepriceforallsystemswithinabin.Thebinswerechosenbasedontheavailablepricingdatapointsasdescribedinthesectiononinstallationcostdataandstakeholderinput 1Themodelusesinputsfromcurrentlyavailableinformation,includingcurrentutilityratesandtariffs.AsdiscussedinSection6.4ofthePlan,inputswereupdatedafterthePlanwasapprovedbytheCommission.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 June4,2018Update

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received on the draft Long TermRenewable Resources Procurement Plan (“LTRRPP” or“Plan”).4Abaseprice iscalculated for themosteconomicblocksize(greater than500to2,000kW),andthepricesfortheotherbinsaredeterminedthroughtheuseofadjustments,asfurtherdescribedinthesectionontheRECpricingcalculation. Theadjustmentsweredeterminedusingamidpointapproachandusingthesamemodelthatwasrunforthebaseprice,asfurtherdescribedinthesectionondistributedgenerationRECmodeladjustments.CommunitySolarprojectsfaceadditionalcostsandlessrevenuethandistributedgenerationsystems.Ontherevenueside,theyareeligibleonlyforenergy‐onlynetmetering,5whileonthecostside,theremaybethecostofacquiring,maintaining,andmanagingsubscribers.Theinitialblockpriceforcommunitysolarreflectsabaselineforthoseadditionalcostsandlowerrevenue.ToensurethatthebenefitsofsolarenergyarewidelysharedbyIllinoisresidents,the Adjustable Block Program (“ABP”) and Illinois Solar for All Program will offer anadditional incentive for community solar projectswith a higher level of participation bysmall subscribers. There will, therefore, be an adder to incentivize small subscriberparticipation.Projectsmeetingasmallsubscriberparticipationrequirementof25%to50%,over50%to75%,orgreaterthan75%willreceivetheadditionaladder.ThisAppendixDreflectsthesuggestedchangesthatweremadeintheLTRRPP’sdocketedproceeding, ICC Docket No. 17‐0838, and adopted by the Final Order and AmendatoryOrder.6

ModelSelectionandDescription

TheRECPricingModelusesamodifiedversionofNationalRenewableEnergyLaboratory’s(“NREL”)publiclyavailableCostofRenewableEnergySpreadsheetTool(“CREST”).7CRESTiswidelyknownandrespectedintherenewableenergyindustry.ForthepurposeofsettingRECpricesfortheABP,modifications(asdescribedinthefollowingsections)tothemodelinputsandformatoftheoutputsweremadesoastorefinetheresultsforuseindeterminingRECpricesfortheblocks.8TheCRESTmodelwasdevelopedbyNRELtoaidpolicymakers,regulatorsandrenewableenergy developers with estimating renewable energy costs for various public policypurposes, such as establishing cost‐based or performance‐based incentives. The modelcalculatesthetotalincentivenecessaryforarenewableprojecttocoveritscostsandachieveanecessaryeconomicreturntotheprojectdeveloperand/orinvestors.AsdescribedintheUserManualpublishedwiththeCRESTmodel,CRESTatitscoreisaneconomic cash flow model designed to assess project economics, design cost‐based 4TheAgencyissuedthedraftLTRRPPonSeptember29,2017.ThedeadlineforthesubmissionofstakeholdercommentswasNovember13,2017.TheAgencyfiledthePlanwiththeIllinoisCommerceCommissiononDecember4,2017inDocketNo.17‐0838. 5220ILCS5/16‐107.5(l)(2).6ThesechangesaredetailedintheComplianceFilingaccompanyingthisAppendixD.TheIllinoisCommerceCommissionissueditsFinalOrderapprovingthePlanonApril3,2018,anditsAmendatoryOrderonMay2,2018.7TheCRESTmodelisavailableonNREL’swebsite:https://financere.nrel.gov/finance/content/crest‐cost‐energy‐models.8Asdescribedintheprevioussection,theCRESTmodeloutputisnotthefinalRECprice,asrevenuesreceivedfromnetmeteringmustbenettedoutfromthepresent‐valueCostofEnergy(“COE”).


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incentives(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.

InstallationCostData

RegardingtheinputstotheCRESTmodel,inparticularinstallationcostdata,anumberofstakeholders suggested that the IPA issue a survey to stakeholders involved in the 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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developmentofsolarprojectstodeterminetheinputstothemodel.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,andaUtility‐ScaleProject.TheaverageResidential Systemmodeled in theNREL report is 5.7 kWDC. The averageCommercialSystemmodeledis200kWDC.Thereport,however,alsomodelsandprovidesthecostsfor100kWDC,500kWDC,and1,000kWDCsystems.

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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TableD‐1throughTableD‐7provideananalysisoftheinstallationcostsbasedontheNRELReport.TheprojectcostsreflectthetotalinstallationcostsofbuildingtheDCsystemequivalentofanACsystem.20ToconvertanACsystemtoaDCsystem,anAC‐DCconversionlossfactorof25%wasused.21Forexamplea2,000kWACsystemtranslatestoa2,667kWDCsystem.TheprojectcostsalsoincludetheimpactofthesolarimporttariffsthatwereimposedbyUSPresidentDonaldTrumponcrystallinesiliconphotovoltaiccellsandmodulesinJanuary2018.ThischangeisimplementedintheRECpricingmodelbyassuminganincreaseinthecostofgenerationequipmentequalto8centsperwattDC.TheAgencydeterminednottomakeanyadditionaladjustmentsatthistimetoreflecttariffsimposedearlierthisyearbytheUnitedStatesgovernmentonimportedsteelandaluminumfromcertaincountries22duetothelackofreliablecostimpactestimates.TableD‐1‐ResidentialSolarPVInstalledCosts(10kW,scaledfrom5.7kWSystem)

TotalProjectCost($) 10kWAC $/WDC $/kWDC 13kWDC

Module 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. 22 See, e.g., https://www.whitehouse.gov/presidential‐actions/presidential‐proclamation‐adjusting‐imports‐steel‐united‐states‐4 (May31,2018).


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TableD‐2‐InstalledCosts(25kWSystem)23

TotalProjectCost($) 25kWAC

33kWDCNRELModelCategories GenerationEquipment $32,010



TableD‐3‐CommercialPVInstalledCosts(100kWSystem)


$/WDC $/kWDC 133kWDCModule 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




23Costs for the25kWsystemreflectanaverageof the installedcosts fora systemscaledupwards from5.7kWanda systemscaleddownwardsfrom100kW.The25kWsystemsizewasincorporatedinresponsetovariousstakeholdercommentsontheDraftLTRRPP.


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$/WDC $/kWDC 267kWDCModule 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 667kWDC

Module 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(2,000kW,scaledfrom1,000kWSystem)

TotalProjectCost($) 2,000kWAC $/WDC $/kWDC 2,667kWDC

Module 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

TableD‐7‐CommercialPVInstalledCosts(4,000kW,scaledfrom5,000kWSystem)

TotalProjectCost($) 4,000kWAC

5,333kWDCNRELModelCategories GenerationEquipment $3,998,868

BalanceofPlant $2,496,209Interconnection $470,684

DevelopmentCostsandFee $829,031Total $7,794,792

Because theprogramsareexpected to launch in2019, theNRELQ12017BenchmarkingReportcostswererolledforwardtwoyearsata4%reductionperyear(comparedtothe2017costfiguresshownabove),reflectingrecenthistoricaltrendsinsolarpricedeclines.24

24BasedonstakeholderresponsestotheDraftPlan,interconnectioncostswerenotrolledforward.


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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,25and(iii)variousstakeholdercommentsontheDraftLTRRPP.

Inresponsetostakeholdercommentsandusingdataprovidedbystakeholders,theIntermediatecategoryofdetailwasutilizedforoperationsandmaintenancecost.

Netmeteringandelectricitypricingdatawasobtainedfromtheutilities’filedtariffs. ThefederalInvestmentTaxCreditwasextendedin2016toprovidea30percenttax

creditthatwouldrampdownincrementallythrough2021andremainat10percentfrom2022forward.

LocationalMarginalPrices(“LMPs”)providedbytheJSP.26 TheAC‐DCconversionfactorof25%wasprovidedbytheJSP.27 The14%DCCapacityFactorfordistributedgeneration,andthe15.5%DCcapacity

factorforcommunitysolarsystemswereprovidedbytheJSP.28RECPriceCalculation

DistributedGenerationModel29

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.ThebaseRECprice 25https://www.illinois.gov/sites/ipa/Documents/Elevate‐Energy‐L‐RRPP‐Request‐Comments‐20170714‐Updated.pdf.26https://www.illinois.gov/sites/ipa/Documents/2018ProcurementPlan/2018‐LTRenewable‐Joint‐Solar‐Parties‐Comments.pdf.27JSPResponseat31.28JSPObjectionsat31‐33.29PresentedinAppendixE‐1:AdjustableBlockProgramDistributedGenerationPricingModel.


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isbasedonthecostsfora2,000kWACprojectandisthepriceforthefirstAdjustableBlockProgramblock.TheRECpricedeclinesby4%foreachsuccessiveblockafterBlock1,asitisanticipatedthatnecessaryincentiveswilldeclinewiththedecliningcostofsolar.The4%isbasedontheaverageannualdropinsolar installationcostsasestimatedintheNRELQ12017BenchmarkingReport.30Theblocksandpriceshavebeenstructuredwiththegoalofmeetingtheprocurementtargetsbytheendofthedeliveryyear2020.Thepricesalsotakeinto account (i) the recent change31 in the federal corporate income tax rate, which onDecember22,2017wasreducedfrom35%to21%effectivewithtaxyear2018,and(ii)theauthorization32of100%bonusdepreciation for federal income taxpurpose forpropertyplacedinserviceafterSeptember27,2017andbeforeJanuary1,2023.Thedistributedgenerationmodelprovidesresultsundertwoscenarios.Forsystemsover10kWto2,000kWAC,themodelincludesanassumptionthatthesystemisnon‐residentialandelectstotaketheSmartInverterRebateandthus,understatelaw,doesnotreceivenetmeteringdistributioncredits.33Forsystemsupto10kWAC,themodelassumesthesystemis residential and thusdoesnot receive the Smart InverterRebate, instead receiving fullretailnetmeteringcreditsincludingdistribution.TheSmartInverterRebateof$250perkWDC,asdiscussedinSection6.8.2ofthePlan,accountsforanafter‐taxcreditof$603,333forthe2,000kWACsystem.(Itisassumedthatiftheprojectisover10kWAC,itelectstotakethe rebate under Section 16‐107.6(c)(1) of the Public Utilities Act.) The Smart InverterRebateisappliedasanadditionalstaterebateintheCRESTmodelonadollarperwattbasisat $0.25 per watt DC, applicable only to the project sizes larger than 10 kW AC in thedistributedgenerationmodelandtreatedastaxableincome.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.Thepresentvalueoftheexpectedproductionvalueand/ornetmeteringrevenues(adjustedto80%of 30https://www.nrel.gov/docs/fy17osti/68925.pdf.31SeePub.Law115‐97(Dec.22,2017),https://www.congress.gov/115/bills/hr1/BILLS‐115hr1enr.pdf,at§13001(modifying26U.S.C.§11(b)andotherprovisionsoftheInternalRevenueCode).32Ibid.at§13201(modifying26U.S.C.§168(k)(6)).33See220ILCS5/16‐107.6(c)(1),(3).


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themarketvaluetoaccountfor20%savingsallocatedtothecustomer/subscriber)over25yearsbyutilitymustthereforebesubtractedfromthePVCOEtogettherevenueshortfall–which,afterdividingbytheexpectedproductionoverthefirst15years,isequivalenttothenetPVCOEorthefinalbaseRECprice.Therearethreebillchargecategoriesthatmayfallunder thenetmetering tariff that areassumedcredits toABPparticipants, including theenergy supply, transmission, and distribution volumetric credits.34 For the distributedgenerationmodel pricing bins, it is assumed that eligible customerswill receive the netmeteringtariffincluding,asapplicablebycustomertype,thecreditsfortheenergysupply,transmission, anddistribution charges, as specifiedbyeachutility for the correspondingcustomerclass.Thepresentvalueofthenetmeteringcreditovertheprojectusefullifeforeach project size was calculated on a total dollar basis that accounts for the expectedproduction foreachsystemsize. For thedistributedgenerationmodel, thenetmeteringcredit applied to the pricing bins including project sizes between 10 and 2,000 kW ACassumessubscriberswillbeinthecommercialandindustrial(“C&I”)rateclasses.Thenetmeteringcreditappliedtotheup‐to‐10kWACpricingbinassumessubscriberswillbeintheresidentialrateclass.For thedistributedgenerationpricingbins thatassumeC&Isubscribers,only theenergysupply and transmission credits were applied as part of the expected net meteringrevenues.35TheenergysupplycreditforeachutilitywascalculatedbyaveragingtheannualaverageLMPs for the last five fullcalendaryears for2018,escalatedat2%toreflect theassumedinflationrate.36Transmissioncreditsforthe2018‐2019deliveryyearweretakenfrom 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‐summermonthsforthe2018‐2019deliveryyear;furtheryearsareextrapolatedfromthe2018‐2019deliveryyearpriceassuminga2%annualinflationrate.TransmissioncreditswerecalculatedinthesamemannerastheywerefortheC&Iclassbutinsteadusingtheresidentialclasstariffrates.Thedistributioncredit fortheAmerenIllinoisresidential 34Itisassumedthataresidentialcustomerwithasolarsystemwillreceivefullretailnetmeteringwithallthreeofthesecredits.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.35See220ILCS5/16‐107.6(c)(1),(3). TheModelassumesaC&Isubscriberwillelect theSmart InverterRebateandthereby losenetmeteringcreditsfordistributioncharges.36Ibid.


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classwascalculatedbytakingtheweightedaveragedistributionchargein$/kWhoffourmonthsofsummerandeightmonthsofnon‐summertariffrates(forcalendaryear2018),37while the residential class ComEd customer distribution credits were calculated bymultiplyingthevolumetricdistributionchargeforcalendaryear2018bytheIncrementalDistribution Uncollectible Cost Factor (“IDUF”) for the residential single family withoutelectricspaceheatcustomerclass.38Various stakeholders suggested that a measure of subscriber (for community solar) orpropertyowner(fordistributedsolar)savingsbeappliedtothevalueofthenetmeteringcredit and/or avoidedconsumption froma solar system; this savingswouldbeexcludedfromcontributingtotheassumedrateofreturnonthesolargenerationinvestment.Inthedistributed generation model, 20% customer savings was suggested and applied, thusreducingthenetmeteringcreditvalueto80%forthedeveloper.TableD‐8showsthe25‐yearpresentvaluenetmeteringcreditforeachprojectsizeat80%forbothAmerenIllinoisandComEdforthedistributedgenerationmodel.

TableD‐8‐25‐yearPresentValueNetMeteringCreditat80%($)39

SystemSize AmerenIllinois ComEd10kWAC $13,234 $16,10825kWAC $19,179 $18,474100kWAC $77,737 $74,882200kWAC $156,724 $150,968500kWAC $393,403 $378,9542,000kWAC $1,576,277 $1,518,383

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.

37AmerenIllinois’volumetricdistributionchargesdifferinsummervs.non‐summer.38TheAgencyupdatedthese figuresafter the IllinoisCommerceCommissionapprovednewcalendar‐year2018distributionrates forComEdandAmerenIllinoisinordersissuedinDecember2017throughFebruary2018,inDocketNos.17‐0196and18‐0034(ComEd)and17‐0197and18‐0210(AmerenIllinois),respectively.TheAgencyalsoupdatedAmerenIllinoisandComEdtransmissionandsupplyrates,basedonrecentlyfiledtariffseffectiveasofJune2018.39Referencesto“AmerenIllinois”and“ComEd”inthisTableD‐8aswellassubsequenttablesinthisAppendixD,denote“GroupA”and“GroupB”describedinChapter6ofthePlan.


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BaseRECPrice($/REC)40=25‐yearPVCOEfor2,000kW($)–25‐yearPVUtilityNetMeteringCreditsat80%($)/15‐yearRECproduction(MWh)

AftercalculatingthebaseRECpricefora2000kWACsystem,pricingbinadjustmentswerecalculatedfortheotherdistributedgenerationbins,i.e.,(i)upto10kWAC,(ii)greaterthan10to25kWAC,(iii)greaterthan25to100kWAC,(iv)greaterthan100to200kWAC,and(v)greaterthan200to500kWAC,basedonamidpointapproachusingtheIPA’smodifiedCRESTmodeloutputforthebinsizebookends.ThepricingbinadjustmentswerecalculatedusingthenetPVCOEoutputfromthemodifiedCRESTmodelforeachofthesystemsizesthatbookendapricingbinasshowninTableD‐9.ThenetPVCOEforeachsystemsizeiscalculatedbysubtractingtherelevantnetmetering credits after accounting for subscriber savings for the system size from themodeledPVCOEoutputforthatsystemsize.Tocalculatetheadjustmentforeachsize‐basedbin,themidpointbetweenthenetPVCOEforthetwobookendsystemsizeswascalculated.TheadjustmentforeachpricingbinisontopofthebaseRECprice.Eachadjustmentisthedifferencebetween(i)themidpointofthecalculatedNetPVCOEforthetwobookendsystemsizesforthatbin,and(ii)thebaseRECprice.Adjustmentsdifferbyutilitybecausethenetmeteringtariffsdifferbetweenthetwolargestutilities.TheresultingadjustmentforeachutilityandpricingbinisshowninTableD‐10.Bywayofexample,the100to200kWACadjustmentwascalculatedasshownbelow:

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

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

TableD‐9‐ModifiedCRESTModelResults41

SystemSize

AmerenIllinoisNetPVCOE($/MWh)

ComEdNetPVCOE($/MWh)

10kWAC $85.10 $72.9725kWAC $72.30 $73.49100kWAC $56.51 $57.72200kWAC $48.56 $49.77500kWAC $45.14 $46.362,000kWAC $43.42 $44.64

40OneRECisequaltoonemegawatt‐hour(“MWh”)ofelectricitygeneratedsuchthat$/RECareequivalentto$/MWh.41TheresultsinthistablearethePVCOEoutputfromtheCRESTmodelpriortosubtractingthenetmeteringcreditsshowninTableD‐8fromthePVCOEanddividingbytheexpectedRECproductionover15years.


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TableD‐10showsthedistributedgenerationpricingbinadjustmentsforeachutility,andTableD‐11showsthedistributedgenerationABPRECpriceforeachutilityandpricingbin.Forexample,the100to200kWbinRECpriceiscalculatedbyaddingthatbin’sadjustment($9.11)tothebaseRECpriceof$44.64forComEdor$43.42forAmerenIllinois.

TableD‐10–DistributedGenerationPricingBinAdjustmentsforEachUtility42

Bin

AmerenIllinoisAdjustment($/REC)

ComEdAdjustment($/REC)

≤10kWAC $41.68 $28.33>10to25kWAC $35.29 $28.59>25to100kWAC $20.99 $20.97>100to200kWAC $9.12 $9.11>200to500kWAC $3.43 $3.43>500to2,000kWAC $0.00 $0.00

TableD‐11–DistributedGenerationABPRECPrices

BinAmerenIllinoisRECPrice($/REC)

ComEdRECPrice($/REC)


CommunitySolarModel43

Communitysolarprojectsweremodeledundervariousassumptionsthatdifferedfromthedistributedgenerationprojects.Asnotedabove,communitysolarprojectsreceiveapricingbinadjustmentcalculatedinthesamemannerasdescribedforthedistributedgenerationadjustment,andanaddertoincentivizesmallsubscriberparticipation.Projectsthatmeetorexceeda25%,50%,or75%requirementforsmallsubscriber44participationwillreceivetheadditionaladder (“theSmall SubscriberParticipationAdder”). Thecalculationof thecommunitysolarpricingbinadjustmentsandaddersisbasedonchangingtheassumptionstothenetmeteringcreditandchangingsomeofthemodelinputassumptions.ForComEd,as approved by the Commission on September 27, 2017 in DocketNo. 17‐0350, the net 42Pricingbinadjustmentsfortheup‐to‐10kWACsystemsizeandthe10‐25kWACsystemsize(i.e.thetwosmallestpricingbins)areunequalacrossthetwoutilitiesbecausethechangeinnetmeteringcreditsfromC&Itoresidentialdiffersacrossthetwoutilities’tariffswhilethesize‐basedvariationinthePVCOEdoesnot.43PresentedinAppendicesE‐2‐aandE‐2‐b‐AdjustableBlockProgramCommunitySolarPricingModel.44“Smallsubscriber”isusedtomeanresidentialorsmallcommercialcustomersubscribers,asreferencedinSection1‐75(c)(1)(N)oftheIPAAct.Theseareidentifiedusingtheirsubscriptionsizes:anysubscriptionbelow25kWACisassumedtobebya“smallsubscriber.”


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metering credit includes energy supply charges but does not include transmission ordistributioncharges.ForAmerenIllinois,asapprovedbytheCommissiononSeptember27,2017intariffno.ERM17‐144,thetariffcreditstheenergyservicebillsofsubscribersatthe“tariffedorcontractrateforelectricitysupplyasappropriate.”Thetariffedorcontractratedoesnot include transmissionordistribution charges. For community solarprojects, allprojectsizeswereassumedtoreceiveenergy‐onlyC&Inetmeteringcreditsbasedonthefive‐year average LMP after accounting for 20% subscriber savings. Additionally, allcommunitysolarprojectsizeswereassumedtotaketheSmartInverterRebateappliedtotheprojectinthesamemannerasitwasappliedtodistributedgenerationprojects10kWACor larger.45 TableD‐12showsthe25‐yearpresentvaluenetmeteringcredit foreachprojectsizeat80%forbothAmerenIllinoisandComEdforthecommunitysolarmodel.

TableD‐12‐25‐yearPresentValueNetMeteringCreditat80%($)

CustomerClass AmerenIllinois ComEd

10kW AC $4,888 $5,99725kWAC $12,344 $15,145100kWAC $50,070 $61,430200kWAC $100,988 $123,900500kWAC $253,553 $311,0782,000kWAC $1,016,022 $1,246,532

Input assumptions changed for community solar projects, aside from those noted aboverelatedtothenetmeteringcredit,reflectstakeholdercommentsandincludeanincreasedinternalrateofreturn,46theinclusionofMACRSbonusdepreciationinfederaltaxationforallprojectsizes(includingtheup‐to‐10kWACsize),andadditionaldataoncostsfacingacommunitysolarproject(i.e., landlease,propertytaxes).RECpricesforcommunitysolarprojectsforeachutilitywerecalculatedinthesamemannerasdistributedgenerationRECpriceswhereabasecommunitysolarRECpricewascalculatedandcalculatedpricingbinadjustmentsappliedtothesuccessivelysmallerprojectsizebins. Bywayofexample,thecommunitysolarpriceforthegreaterthan100to200kWACisthedifferencebetweenthegreaterthan100to200kWACadjustmentandthebasecommunitysolarRECprice.Theresulting community solar pricing bin adjustments are shown in Table D‐1347 andcommunitysolarRECpricesareshowninTableD‐14below.

45Acommunitysolarproject,oritssubscribers,areentitledtoreceivetheSmartInverterRebate.220ILCS5/16‐107.6(f).46Theassumedinternalrateofreturnis14%inthecommunitysolarmodelinsteadof12%inthedistributedgenerationmodel.47Duetothesamenetmeteringcreditbeingappliedtoallsystemsizes,thecommunitysolarpricingbinadjustmentsdonotvarybyutilityinpricingbinsthatincludethe10kWprojectsize.


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TableD‐13–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

TableD‐14–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 $47.88Co‐locatedsystemsexceeding2MWinaggregatesize $47.03 $42.59

Co‐locatedSystemsExceeding2MWinAggregateSize

TableD‐14includesanewpricingtierforco‐locatedsystems.InitsFinalOrderapprovingtheLong‐TermRenewableResourcesProcurementPlan, theCommissionapproved a co‐locationstandardforcommunitysolarprojectsasfollows:“noApprovedVendormayapplytotheAdjustableBlockProgramformorethan4MWofCommunitySolarprojectsonthesameorcontiguousparcels.Theseprojectsmaybeco‐locatedinoneoftwoways:a)two2‐MWprojectsononeparcel,orb)one2‐MWprojectoneachoftwocontiguousparcels.”48The Agency filed aMotion for Clarification or Other Relief on April 16, 2018,which theCommissiongrantedonMay2,2018.ThatclarificationaddedthefollowingparagraphtotheCommission’sOrder:

Additionally,consistentwiththeOrder’sconclusionpermittingco‐location forsystemsindividuallyofnomorethan2MWinsizeandinaggregateofnomorethan4MW in sizeon the sameoradjacentparcels, the IPA isauthorized toinvestigateoutsideofthisdockettheprobabilityofcostsavings(ifany)forco‐locatedprojectsthatputstheiraveragecostsbelowthosemodeledintheIPA’s

48FinalOrderat131.


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RECpricingmodel,andifwarrantedbasedontheresultsofthatinvestigation,establish a tier in its REC pricing model applicable to co‐located systemsexceeding2MWinaggregatesize.49

TheAgencyhas investigated those costs anddetermined that theprimary areas for costsavings due to the larger scale of co‐located projects are: (1) interconnection costs; (2)componentsofthebalanceofplantcosts;and(3)developmentcostsandfees.TheAgencythereforeisaddinganewpricetierforcommunitysolarco‐locatedsystemsexceeding2MWACinaggregatesize.ThispricingtierwillapplytosuchcommunitysolarsystemsinboththeAdjustableBlockProgramandIllinoisSolarforAllProgram.Theimpactofincreasedaggregatesystemsizefromco‐locationonprojectinterconnectioncostswasderivedbymodelingtwoadjacent2MWACcommunitysolarsystemsashavingthesametotalinterconnectioncostsasa4MWACphotovoltaicsystem.Inthedevelopmentof the REC Pricing Model, the Agency used cost data from the NREL Study, U.S. SolarPhotovoltaic System Cost Benchmark: Q1 2017.50 Using the same approach, theinterconnectioncostfora4MWACsystemisbasedonscalingthecostsreportedbyNRELfor a 5 MW utility‐scale fixed‐tilt system. This reduced interconnection costs by 15.7%($235,342foraco‐located2MWACsystemversus$279,045forastand‐alone2MWACsystem).Todeterminetheimpactsforthebalanceofplantcostsanddevelopmentcostsandfees,apercentageofthecostsforeachwasestimatedbasedonareviewofthecomponentsthatcomprisethesecostcategoriesthatwouldbeimpactedbyoperatingscale.51ThebalanceofplantcostinputsconsideredintheCRESTmodel(whichisthebasisfortheRECPricingModel)include:infrastructuresitepreparationandrelatedlaborcostsincludingthe cost of access roads; site survey and related costs; balance of facility electrical costsoutsideoftheelectricalcostsdirectlyassociatedwithsolarmodulesandinterconnection;costsfortheconstructionofmaintenancebuildingsandrelatedinfrastructure;spareparts;andplantcommissioningcosts.Notallofthesecostsbenefit fromincreasingprojectsize.Only11%ofthebalanceofplantcosts,reflectingthecostsforsitesurveyandpreparationandforconstructingaccessroads,wouldresultinco‐locationrelatedcostsavings.Thecostreductionforthesecomponentsinherentina5MWutility‐scalesystemwasappliedto11%ofthebalanceofplantcostsfora4MWsystemandsplitevenlyforeachofthe2MWco‐locatedsystems.TheotherbalanceofplantcostcomponentsoftheNREL5MWsystemwerehigherthanforthoseforastand‐alone2MWsystem.Theresultingadjustmenttobalanceofplantcostsresultedina1.5%increaseofcostfortheco‐located2MWsystem($1,024,239versus$1,008,911forastand‐alone2MWsystem).

49AmendatoryOrderat1‐2.50See:https://www.nrel.gov/docs/fy17osti/68925.pdfat29,39.Costfigures(exceptinginterconnection)inthisdiscussionofco‐locatedsystemsarereducedby2years’worthof4%annualcostreductions(i.e.,atotalof8%)fromthe2017figuresintheNRELstudy,duetoanassumptionthatprojectswillbeginconstructionin2019.51See:https://financere.nrel.gov/finance/files/NREL_CREST_Solar_version1.4.xlsx,at“ComplexInputs”worksheet.


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Using a similar analysis of theNREL costs for a 5MWutility‐scale system subsequentlyscaledto4MW,itwasdeterminedthatapproximately60%ofthedevelopmentcostsandfeeswouldbesubjecttoco‐locationrelatedcostbenefits. NREL’sdevelopmentcostsandfeesincludethefollowingcomponents:siteselectionandevaluationcosts;siteacquisitioncosts; permitting costs; engineering/design costs; resource analysis costs; and otherdevelopmentcosts.Allthesecomponentsexceptengineering/designwereconsideredtobesubject to scale benefits. This adjustment would reduce development costs by 36.5%($618,142versus$973,325forastand‐alone2MWsystem52).Accounting for these cost savings fromcommunity solarproject co‐location results inanAdjustableBlockProgramRECpriceforBlock1of$47.03forGroupA,and$42.59forGroupB.Anyco‐locatedcommunitysolarprojectsexceeding2MWACinaggregatesize,upto4MWtotal,willbeclassified in thisnewprice tier, shown inAppendixE‐2‐b.Thesepricesconstituteareductionof$5.25(10%)and$5.29(11%),respectively,fromtheBlock1pricesforprojectsinthe500kWto2MWsizerange.Thesamecostsavingsassumptions informthenewco‐locatedpricingtier fortheIllinoisSolarforAllLow‐IncomeCommunitySolarProjectInitiative,foundinAppendixE‐4‐b.Here,thepricesforco‐locatedprojectsofover2MWinsizeare$64.88and$62.30inGroupAandGroupB,respectively,areductionofapproximately9%,inbothcases,fromthepricesforthe500kWto2MWsizerange.SmallSubscriberAdder

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 SolarAccess53 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.54InordertodeterminetheSmallSubscriberParticipationAdders,theIPAalsoreliedondataonprojectsize,andprojectenergyproductionprovidedbyElevateEnergyintheircommentsonthedraftPlan.55Intheircomments,ElevateEnergymodelleda1,250kWsystemwithan 52Ibid. 53https://www.illinois.gov/sites/ipa/Documents/2018ProcurementPlan/2018‐LTRenewable‐Coalition‐for‐Community‐Solar‐Access‐Comments.pdf.54SEA.(2016)RhodeIslandRenewableEnergyGrowthProgram:20172ndDraftCeilingPriceRecommendations.Availableat:http://sos.ri.gov/documents/publicinfo/omdocs/minutes/6154/2016/49211.pdf. 55https://www.illinois.gov/sites/ipa/Documents/2018ProcurementPlan/2018‐LTRenewable‐Elevate‐Energy‐Comments.pdf.


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energyproductionof33,794MWhover25years.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%escalationfactortothenetmeteringcreditvaluesforthetwoutilitiesfor25years,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. TheCommunitySolarSmallSubscriberParticipationAddersarepresented inTableD‐15. Theseapplytocommunity solar projectRECprices in both theAdjustableBlockProgramand the Low‐IncomeCommunitySolarProjectInitiativesub‐programofIllinoisSolarforAll.56

TableD‐15–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

IllinoisSolarforAllModels57

Therearethreesub‐programsundertheIllinoisSolarforAllProgramthatreceiveincentivesasdescribedinChapter8ofthePlan:Low‐IncomeDistributedGenerationInitiative,Low‐Income Community Solar Project Initiative, and Incentives for Non‐Profits and Public 56FinalOrderat155.57PresentedinAppendicesE‐3‐aandE‐3‐b:IllinoisSolarforAllDistributedGenerationIncentivePricingModel,E‐4‐aandE‐4‐b:IllinoisSolarforAllCommunitySolarPricingModel,andE‐5:IllinoisSolarforAllNon‐profitandPublicFacilityPricingModel.


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Facilities. There isaseparateapproachused forsettingRECprices foreachof the threeIllinoisSolarforAllsub‐programs.TheIncentivesforIllinoisSolarforAllbuildonthemodelsusedfortheAdjustableBlockProgram.Forallthreesub‐programs,it isassumedthatthecustomersavingsvalueallocatedfromthenetmeteringcreditand/orproductionvalueisincreasedfrom20%to50%(but100%in1‐4unitbuildingsintheLow‐IncomeDistributedGenerationInitiativesub‐program,discussedbelow).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 binadjustments were calculated in the same manner as for non‐low income distributedgeneration.TableD‐16providestheRECpricesforthelow‐incomedistributedgenerationparticipantsinlargerbuildings,whoareassumedtoreceive50%ofthenetmeteringvalue.TableD‐17providestheRECpricesforthelow‐incomedistributedgenerationparticipantsinsmaller(1‐4unit)buildings,whoareassumedtoreceive100%ofthenetmeteringvalue.58

TableD‐16–Low‐IncomeDistributedGenerationInitiativeRECPrices(Multi‐FamilyBuildings)

Bin

AmerenIllinoisRECPrice($/REC)



58Forthe1‐4unitmodel,systemsofupto10kWareassumedtobeonasingle‐familyorduplexhomeandthusineligiblefortheSmartInverterRebateunderstatelaw,whilesystemsof10kWandaboveareassumedtobeonlarger,multi‐familyresidentialbuildingswherethephotovoltaicgeneratingsystemislinkedtothebuilding’scentralelectricaccount,whichisnon‐residentialfromtheutility’sperspectiveandthuseligiblefortheSmartInverterRebate.Forthe5+unitmodel,anyPVsystemofanysizeisassumedtobelinkedtothebuilding’scentralelectricaccount,whichiseligiblefortheSmartInverterRebate.


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TableD‐17–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‐IncomeCommunitySolarProjectInitiativeisintendedtosupportparticipationincommunitysolarbylow‐incomesubscribers.ForLow‐IncomeCommunitySolarProjectInitiativeparticipants,adifferentapproachwasusedthanthezeropercentdebtfinancingusedfortheLow‐IncomeDistributedGenerationInitiative.Whilethenon‐lowincomecommunitysolarRECpricewascalculatedusingtheassumptionofa15‐yearpaybackperiod,theRECpricesforthisgroupwascalculatedusingashortened,5‐yearpaybackperiodandalowerassumed35%debtfinancing.RECpricesforparticipantsofLow‐IncomeCommunitySolarProjectInitiativeareshowninTableD‐18. Low‐IncomeCommunitySolarvaluesinTableD‐18builduponthenon‐lowincomecommunitysolarRECpricesinTableD‐14underalteredassumptionsdiscussedabove.Asdiscussedabove,SmallSubscriber Participation Adders (Table D‐15) also apply to the Low‐Income CommunitySolarProjectInitiative.

TableD‐18–Low‐IncomeCommunitySolarProjectInitiativeRECPrices



($/REC)≤10kWAC $121.99 $119.55


Co‐locatedsystemsexceeding2MWinaggregatesize59 $64.88 $62.30

59Section1‐56oftheIPAAct(20ILCS3855/1‐56(b)(2)(B))doesnotexpresslycreateasizelimitforcommunitysolarprojectsparticipatingintheIllinoisSolarforAllLow‐IncomeCommunitySolarProjectInitiativesub‐program,buttheproposednewRECpricingtierforco‐locatedcommunitysolarprojectseachof2MWwillalsoapply to IllinoisSolar forAllProgramlow‐incomecommunitysolarprojectsexceeding2MWeitherasasingleprojectorthroughco‐location.


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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.”60Tocalculatethe 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‐19.

TableD‐19–IncentivesforNon‐ProfitsandPublicFacilitiesRECPrices



($/REC)≤10kWAC $155.87 $156.57


6020ILCS3855/1‐56(b)(2)(C).