Anthony Star Director - Illinois.gov...Draft 2016 Procurement Plan for Public Comments August 14, 2015 Illinois Power Agency 2016 Electricity Procurement Plan Prepared in accordance

2016

Anthony Star

Director

ELECTRICITYPROCUREMENTPLANDraftPlanforPublicComments August14,2015

Draft2016ProcurementPlanforPublicComments August14,2015

IllinoisPowerAgency

2016ElectricityProcurementPlanPreparedinaccordancewiththe

IllinoisPowerAgencyandIllinoisPublicUtilitiesActs

DraftPlanforPublicComments


TableofContents

1 ExecutiveSummary......................................................................................................................................................1 1.1 PowerProcurementStrategy.........................................................................................................................................................1 1.2 RenewableEnergyResources........................................................................................................................................................3 1.3 IncrementalEnergyEfficiency......................................................................................................................................................5 1.4 TheActionPlan....................................................................................................................................................................................5

2 Legislative/RegulatoryRequirementsofthePlan.............................................................................................7 2.1 IPAAuthority.........................................................................................................................................................................................7 2.2 ProcurementPlanDevelopmentandApprovalProcess....................................................................................................7 2.3 ProcurementPlanRequirements.................................................................................................................................................8 2.4 StandardProductProcurementandLoad‐FollowingProducts.....................................................................................9 2.5 RenewableEnergyResources......................................................................................................................................................10 2.5.1 RenewablePortfolioStandard................................................................................................................................................10 2.5.2 DistributedGenerationResourcesStandard....................................................................................................................12 2.5.3 RenewableEnergyResourcesFund......................................................................................................................................12 2.6 EnergyEfficiencyResources........................................................................................................................................................13 2.7 DemandResponseProducts.........................................................................................................................................................15 2.8 CleanCoalPortfolioStandard......................................................................................................................................................16 2.9 2015LegislativeProposals...........................................................................................................................................................16

3 LoadForecasts.............................................................................................................................................................18 3.1 StatutoryRequirements.................................................................................................................................................................18 3.2 SummaryofInformationProvidedbyAmerenIllinois....................................................................................................19 3.2.1 Macroeconomics............................................................................................................................................................................22 3.2.2 Weather.............................................................................................................................................................................................23 3.2.3 Switching...........................................................................................................................................................................................23 3.2.4 LoadShapeandLoadFactor....................................................................................................................................................25 3.3 SummaryofInformationProvidedbyComEd.....................................................................................................................27 3.3.1 Macroeconomics............................................................................................................................................................................30 3.3.2 Weather.............................................................................................................................................................................................30 3.3.3 Switching...........................................................................................................................................................................................30 3.3.4 LoadShapeandLoadFactor....................................................................................................................................................31 3.4 SummaryofInformationProvidedbyMidAmerican........................................................................................................33 3.4.1 Macroeconomics............................................................................................................................................................................36 3.4.2 Weather.............................................................................................................................................................................................36 3.4.3 Switching...........................................................................................................................................................................................37 3.4.4 LoadShapeandLoadFactor....................................................................................................................................................37 3.5 SourcesofUncertaintyintheLoadForecasts......................................................................................................................39 3.5.1 OverallLoadGrowth....................................................................................................................................................................39 3.5.2 Weather.............................................................................................................................................................................................40 3.5.3 LoadProfiles....................................................................................................................................................................................40 3.5.4 MunicipalAggregation................................................................................................................................................................42 3.5.5 IndividualSwitching....................................................................................................................................................................43 3.5.6 HourlyBilledCustomers............................................................................................................................................................43 3.5.7 EnergyEfficiency...........................................................................................................................................................................43 3.5.8 DemandResponse........................................................................................................................................................................44 3.5.9 EmergingTechnologies..............................................................................................................................................................44 3.6 RecommendedLoadForecasts...................................................................................................................................................44 3.6.1 BaseCases........................................................................................................................................................................................44 3.6.2 HighandLowExcursionCases...............................................................................................................................................44

4 ExistingResourcePortfolioandSupplyGap.....................................................................................................46 4.1 AmerenIllinoisResourcePortfolio...........................................................................................................................................47


4.2 ComEdResourcePortfolio............................................................................................................................................................48 4.3 MidAmericanResourcePortfolio...............................................................................................................................................48 4.4 AllocationofSupplyVolumesAssociatedwithAmerenIllinoisandComEdLTPPAs........................................49

5 MISOandPJMResourceAdequacyOutlookandUncertainty......................................................................51 5.1 ResourceAdequacyProjections.................................................................................................................................................51 5.2 LocationalResourceAdequacyNeeds.....................................................................................................................................55

6 ManagingSupplyRisks.............................................................................................................................................60 6.1 Risks........................................................................................................................................................................................................60 6.1.1 VolumeRisk.....................................................................................................................................................................................60 6.1.2 PriceRisk..........................................................................................................................................................................................61 6.1.3 HedgingImperfections...............................................................................................................................................................61 6.2 ToolsforManagingSupplyRisk.................................................................................................................................................61 6.2.1 TypesofSupplyHedges.............................................................................................................................................................62 6.2.1.1 Unit‐SpecificHedges.................................................................................................................................................................62 6.2.1.2 Unit‐IndependentHedges......................................................................................................................................................62 6.2.2 SuitabilityofSupplyHedges.....................................................................................................................................................63 6.2.3 OptionsasaHedgeonLoadVariability..............................................................................................................................64 6.3 ToolsforManagingSurplusesandPortfolioRebalancing..............................................................................................65 6.4 PurchasedElectricityAdjustmentOverview........................................................................................................................65 6.5 EstimatingSupplyRisksintheIPA’sHistoricApproachtoPortfolioManagement............................................66 6.5.1 HistoricStrategiesoftheIPA...................................................................................................................................................66 6.5.2 MeasuringtheCostandUncertaintyImpactsofSupplyRiskFactors...................................................................67 6.5.2.1 MonthlyPriceFluctuation......................................................................................................................................................68 6.5.2.2 ProcurementSchedulesandPortfolioVolatility..........................................................................................................72 6.5.2.3 ForwardPriceCurveAnalysis..............................................................................................................................................73 6.6 DemandResponseasaRiskManagementTool...................................................................................................................77

7 ResourceChoicesforthe2015ProcurementPlan..........................................................................................79 7.1 IncrementalEnergyEfficiency....................................................................................................................................................79 7.1.1 IncrementalEnergyEfficiencyinPreviousPlans...........................................................................................................80 7.1.2 2015Workshops...........................................................................................................................................................................81 7.1.2.1 EnergyEfficiencyasaSupplyResourceWorkshops..................................................................................................81 7.1.2.2 StakeholderAdvisoryGroupTRCSubcommitteeWorkshops...............................................................................82 7.1.2.2.1UseofMarginalLineLosses..................................................................................................................................................847.1.2.2.2DemandReductionInducedPriceEffects(“DRIPE”).................................................................................................847.1.2.2.3UseofNon‐EnergyBenefitsinTRCTests.......................................................................................................................857.1.2.2.4ApplicationofAdministrativeCostsinTRCTests.......................................................................................................867.1.2.2.5 IndependentTRCTestsbyIPA............................................................................................................................................877.1.3 PriorYearConsensusItems.....................................................................................................................................................87 7.1.4 PolicyIssuesforConsiderationinthe2017Plan...........................................................................................................88 7.1.5 AmerenIllinois...............................................................................................................................................................................89 7.1.5.1 AmerenIllinoisBidReviewProcess..................................................................................................................................89 7.1.5.2 ReviewofAmerenIllinoisTRCAnalysis..........................................................................................................................90 7.1.5.3 ProgramsforwhichAmerenIllinoisassertsthecostexceedsthecostofsupply.........................................91 7.1.5.4 ReviewofDuplicativePrograms.........................................................................................................................................92 7.1.5.5 AmerenIllinoisProgramsRecommendedforApproval..........................................................................................93 7.1.5.6 AmerenIllinoisRequestedDeterminations...................................................................................................................94 7.1.6 ComEd................................................................................................................................................................................................94 7.1.6.1 ComEdBidReviewProcess...................................................................................................................................................95 7.1.6.2 ReviewoftheComEdTRCAnalysis...................................................................................................................................95 7.1.6.3 ReviewofDuplicativePrograms.........................................................................................................................................96 7.1.6.4 ComEdIdentificationof“PerformanceRisk”.................................................................................................................96 7.1.6.5 ComEdProgramsRecommendedforApproval...........................................................................................................97 7.1.7 MidAmerican...................................................................................................................................................................................98


7.2 ProcurementStrategy.....................................................................................................................................................................99 7.3 IndicativeQuantitiesandTypesofProductstobeProcured.....................................................................................102 7.3.1 AmerenIllinois.............................................................................................................................................................................103 7.3.1.1 AmerenIllinoisProcurementDeliveryYears2016‐2021..................................................................................103 7.3.1.2 DeliveryYear+3andDeliveryYear+4(2019‐2020and2020‐2021)..........................................................106 7.3.2 ComEd.............................................................................................................................................................................................107 7.3.2.1 ComEdProcurementDeliveryYears2016–2021..................................................................................................107 7.3.2.2 DeliveryYear+3andDeliveryYear+4(2019‐2020and2020‐2021)..........................................................110 7.3.3 MidAmerican................................................................................................................................................................................111 7.3.3.1 MidAmericanProcurementDeliveryYears2016–2021.....................................................................................111 7.3.3.2 DeliveryYear+3andDeliveryYear+4(2019‐2020and2020‐2021)..........................................................114 7.4 AncillaryServices,TransmissionServiceandCapacityPurchases..........................................................................114 7.4.1 AncillaryServicesandTransmissionService................................................................................................................114 7.4.2 CapacityPurchases....................................................................................................................................................................115 7.5 DemandResponseProducts..................................................................................................................................................115 7.6 CleanCoal......................................................................................................................................................................................117 7.6.1 FutureGen2.0..............................................................................................................................................................................117 7.6.2 Sargas..............................................................................................................................................................................................117 7.7 SummaryofStrategyforthe2015ProcurementPlan...................................................................................................118

8 RenewableResourcesAvailabilityandProcurement.................................................................................120 8.1 CurrentUtilityRenewableResourceSupplyandProcurement................................................................................123 8.1.1 AmerenIllinois............................................................................................................................................................................123 8.1.1.1 AmerenIllinoisSRECProcurementfor2015‐16DeliveryYear........................................................................124 8.1.2 ComEd.............................................................................................................................................................................................124 8.1.2.1 ComEdSRECProcurementfor2015‐16DeliveryYear..........................................................................................125 8.1.3 MidAmerican................................................................................................................................................................................125 8.2 AvailableRenewableResourcesBudgetandLTPPACurtailment............................................................................126 8.2.1 ImpactofBudgetCap...............................................................................................................................................................126 8.3 UseofHourlyAlternativeCompliancePaymentsHeldbytheUtilities..................................................................128 8.4 DistributedGenerationProcurement...................................................................................................................................128 8.4.1 ProcurementProcess...............................................................................................................................................................129 8.4.2 KeyContractTerms...................................................................................................................................................................131 8.4.3 CreditRequirementsandBidder/SupplierFees..........................................................................................................131 8.4.4 Aggregators...................................................................................................................................................................................131 8.5 AlternativeCompliancePaymentsHeldbytheIPAintheRenewableEnergyResourcesFund................132

9 ProcurementProcessDesign...............................................................................................................................133 9.1 ContractForms................................................................................................................................................................................134 9.2 IPARecoveryofProcurementExpenses..............................................................................................................................135 9.3 SecondProcurementEvent........................................................................................................................................................136 9.4 InformalHearing............................................................................................................................................................................136

Appendices........................................................................................................................................................................138 AppendixA. RegulatoryComplianceIndex................................................................................................................................138 AppendixB. AmerenIllinoisLoadForecast..............................................................................................................................138 AppendixC. ComEdLoadForecast................................................................................................................................................138 AppendixD. MidAmericanLoadForecast..................................................................................................................................138 AppendixE. AmerenIllinoisLoadForecastandSupplyPortfoliobyScenario.........................................................139 AppendixF. ComEdLoadForecastandSupplyPortfoliobyScenario..........................................................................139 AppendixG. MidAmericanLoadForecastandSupplyPortfoliobyScenario.............................................................140 Appendicesareavailableseparatelyat:www2.illinois.gov/ipa/Pages/Plans_Under_Development.aspx


TablesTable1‐1:SummaryofEnergyHedgingStrategy.............................................................................................................................2 Table1‐2:SummaryofCapacityProcurementStrategyforComEd........................................................................................3 Table1‐3:SummaryofCapacityHedgingStrategyforAmerenIllinois.................................................................................3 Table1‐4:SummaryofCapacityHedgingStrategyforMidAmerican.....................................................................................3 Table1‐5:SummaryofProcurementPlanRecommendationsBasedonJuly15,2015UtilityLoadForecast

(QuantitiestobeAdjustedBasedontheMarchandJuly2016LoadForecast):..........................................4 Table3‐1:LoadMultipliersinAmerenIllinoisExcursionCases.............................................................................................22 Table3‐2:RepresentativeARESFixedPriceOffers(Offerswithoutanexplicitpremiumrenewable

component)andUtilityPricetoCompare..................................................................................................................43 Table4‐1:AmerenIllinoisLTPPAsMonthlyPeakandOff‐PeakAllocations(June2015throughMay2016)...50 Table4‐2:ComEdLTPPAsMonthlyPeakandOff‐PeakAllocations(June2015throughMay2016).....................50 Table7‐1:ProjectedSavings(MWH)fromSection16‐111.5BProgramsFromPriorIPAProcurementPlans

andProposedinthisPlan...................................................................................................................................................80 Table7‐2:AmerenIllinoisDuplicativeProgramScreening.......................................................................................................93 Table7‐3:AmerenIllinoisProgramsDuplicativeofDCEOPrograms...................................................................................93 Table7‐4:AmerenIllinoisEnergyEfficiencyOfferings...............................................................................................................94 Table7‐5:ComEdDuplicativeProgramScreening........................................................................................................................96 Table7‐6:ComEdEnergyEfficiencyOfferings................................................................................................................................97 Table7‐7:SummaryofEnergyHedgingStrategy...........................................................................................................................99 Table7‐8:SummaryofCapacityProcurementStrategyforComEd......................................................................................99 Table7‐9:SummaryofCapacityHedgingStrategyforAmerenIllinois............................................................................101 Table7‐10:SummaryofMidAmericanLoadandCapability..................................................................................................102 Table7‐11:SummaryofCapacityHedgingStrategyforMidAmerican.............................................................................102 Table7‐12:AmerenIllinoisSpringProcurement,DeliveryYear2016‐2017PreliminaryVolumes*.................103 Table7‐13:AmerenIllinoisFallProcurement,October‐MayofDeliveryYear2016‐2017,Preliminary

Volumes*.................................................................................................................................................................................104 Table7‐14:AmerenIllinoisSpringProcurement,DeliveryYear+1(2017‐2018),PreliminaryVolumes*......105 Table7‐15:AmerenIllinoisSpringProcurement,DeliveryYear+2(2018‐2019),PreliminaryVolumes*.....106 Table7‐16:ComEdSpringProcurement,DeliveryYear2016‐2017,PreliminaryVolumes*..................................107 Table7‐17:ComEdFallProcurement,October‐MayofDeliveryYear2016‐2017,PreliminaryVolumes*......108 Table7‐18:ComEdSpringProcurement,DeliveryYear+1(2017‐2018),PreliminaryVolumes*.......................109 Table7‐19:ComEdSpringProcurement,DeliveryYear+2(2018‐2019),PreliminaryVolumes*......................110 Table7‐20:MidAmericanSpringProcurement,DeliveryYear2016‐2017,PreliminaryVolumes*....................111 Table7‐21:MidAmericanFallProcurement,October‐MayofDeliveryYear2016‐2017,PreliminaryVolumes*

.....................................................................................................................................................................................................112 Table7‐22:MidAmericanSpringProcurement,DeliveryYear+1(2017‐2018),PreliminaryVolumes*..........113 Table7‐23:MidAmericanSpringProcurement,DeliveryYear+2(2018‐2019),PreliminaryVolumes*.........114 Table7‐24:SummaryofCapacityHedgingStrategyforAmerenIllinois.........................................................................115 Table7‐25:SummaryofCapacityHedgingStrategyforMidAmerican.............................................................................115 Table7‐26:SummaryofProcurementPlanRecommendationsBasedonJuly15,2015UtilityLoadForecast

(QuantitiestobeAdjustedBasedontheMarchandJuly2016LoadForecast):.....................................118 Table8‐1:AmerenIllinoisExistingRPSContractsvs.RPSRequirements.......................................................................124 Table8‐2:ComEdExistingRPSContractsvs.RPSRequirements........................................................................................125 Table8‐3:MidAmericanExistingRPSContractsvs.RPSRequirements...........................................................................126 Table8‐4:AvailableRenewableResourcesBudgetFundsandForecastReductions(Curtailments)ofLong‐

termRenewableContracts(LTPPAs),AmerenIllinois......................................................................................127 Table8‐5:AvailableRenewableResourcesBudgetFundsandForecastReductions(Curtailments)ofLong‐

termRenewableContracts(LTPPAs),ComEd........................................................................................................127 Table8‐6:AvailableRenewableResourcesBudgetFunds,MidAmerican.......................................................................128


FiguresFigure3‐1:AmerenIllinois’ForecastRetailCustomerLoadBreakdown,DeliveryYear2016‐2017.....................20 Figure3‐2:AmerenIllinois’ForecastRetailCustomerLoadbyDeliveryYear.................................................................21 Figure3‐3:AmerenIllinois’ForecastEligibleLoad*byMonth................................................................................................22 Figure3‐4:AmerenIllinois’RetailCustomerLoadbeforeSwitchinginAmerenIllinois’Forecasts.......................23 Figure3‐5:UtilityLoadRetentioninAmerenIllinois’Forecasts............................................................................................24 Figure3‐6:SupplyObligationinAmerenIllinois’Forecasts.....................................................................................................25 Figure3‐7:SampleDailyLoadShape,SummerDayinAmerenIllinois’Forecasts.........................................................25 Figure3‐8:SampleDailyLoadShape,SpringDayinAmerenIllinois’Forecasts.............................................................26 Figure3‐9:LoadFactorinAmerenIllinois’Forecasts..................................................................................................................27 Figure3‐10:ComEd’sForecastRetailCustomerLoadBreakdown,DeliveryYear2016‐2017.................................28 Figure3‐11:ComEd’sForecastRetailCustomerLoadbyDeliveryYear.............................................................................29 Figure3‐12:ComEd’sForecastEligibleLoadbyMonth..............................................................................................................29 Figure3‐13:WeatherImpactsinComEd’sForecasts...................................................................................................................30 Figure3‐14:SupplyObligationinComEd’sForecasts..................................................................................................................31 Figure3‐15:SampleDailyLoadShape,SummerDayinComEd’sForecasts......................................................................32 Figure3‐16:SampleDailyLoadShape,SpringDayinComEd’sForecasts..........................................................................32 Figure3‐17:LoadFactorinComEd’sForecasts..............................................................................................................................33 Figure3‐18:MidAmerican’sForecastRetailCustomerLoadBreakdown,DeliveryYear2016‐2017....................34 Figure3‐19:MidAmerican’sForecastRetailCustomerLoadbyDeliveryYear................................................................35 Figure3‐20:MidAmerican’sForecastEligibleLoadbyMonth.................................................................................................36 Figure3‐21:SupplyObligationinMidAmerican’sForecasts....................................................................................................37 Figure3‐22:SampleDailyLoadShape,SummerDayinMidAmerican’sForecasts........................................................38 Figure3‐23:SampleDailyLoadShape,SpringDayinMidAmerican’sForecasts............................................................38 Figure3‐24:LoadFactorinMidAmerican’sForecasts.................................................................................................................39 Figure3‐25:CoefficientofVariationofDailyPeak‐PeriodLoads...........................................................................................41 Figure3‐26:ExampleofOver‐andUnder‐HedgingofHourlyLoad......................................................................................41 Figure3‐27:DistributionofMunicipalAggregationContractExpirations(ComEd).....................................................42 Figure3‐28:ComparisonofAmerenIllinois’,ComEd’s,andMidAmerican’sHighandLowForecastsfor

DeliveryYear2016‐2017...................................................................................................................................................45 Figure4‐1:AmerenIllinois'On‐PeakSupplyGap‐June2016‐May2021Period‐ExpectedLoadForecast......47 Figure4‐2:ComEd'sOn‐PeakSupplyGap‐June2016‐May2021period‐ExpectedLoadForecast......................48 Figure4‐3:MidAmerican’sOn‐PeakSupplyGap‐June2016‐May2021period‐ExpectedLoadForecast........49 Figure5‐1:PJMRPMCapacityPriceforDeliveryYears2012‐2017......................................................................................52 Figure5‐2:PJMNERCProjectedCapacitySupplyandDemandforDeliveryYears2015‐2020................................52 Figure5‐3:MISONERCProjectedCapacitySupplyandDemandforthePlanningYears2015‐2020....................54 Figure5‐4:MISOPRAResultsforPlanningYears2014‐2015and2015‐2016................................................................56 Figure6‐1:PurchasedElectricityAdjustmentsinCents/kWh,June2011–August2015..........................................66 Figure6‐2:MonthlyDistributionMeans...........................................................................................................................................69 Figure6‐3.MonthlyDistributionStandardDeviations................................................................................................................69 Figure6‐4:MonthlyStandardDeviationsforJuly2014Delivery...........................................................................................70 Figure6‐5:MonthlyStandardDeviationsforOctober2014Delivery..................................................................................70 Figure6‐6:MonthlyStandardDeviationsforJanuary2015Delivery...................................................................................71 Figure6‐7.MonthlyStandardDeviationsforApril2015Delivery.........................................................................................71 Figure6‐8:PortfolioPriceMeans..........................................................................................................................................................73 Figure6‐9.PortfolioPriceStandardDeviations..............................................................................................................................73 Figure6‐10:PJMOn‐PeakDe‐seasonalizedAverageLogofPricesfor24Maturities....................................................74 Figure6‐11:MISOOn‐PeakDe‐seasonalizedAverageLogofPricesfor24Maturities.................................................75 Figure6‐12:PJMOn‐PeakSeasonalPremia......................................................................................................................................75 Figure6‐13:MISOOn‐PeakSeasonalPremia...................................................................................................................................76 Figure6‐14:PJMOn‐PeakConvenienceYieldVolatility..............................................................................................................77 Figure6‐15:MISOOn‐PeakConvenienceYieldVolatility...........................................................................................................77


IllinoisPowerAgency

2016ElectricityProcurementPlan

DraftPlanforPublicComments


1

1 ExecutiveSummary

This is theeighthelectricityandrenewableresourceprocurementplan(the“Plan,” “ProcurementPlan,”or“2016ProcurementPlan”)preparedby the Illinois PowerAgency (“IPA”or “Agency”) under the authoritygrantedto itundertheIllinoisPowerAgencyAct(“IPAAct”)andasfurtherregulatedbytheIllinoisPublicUtilitiesAct(“PUA”).Chapter2ofthisPlandescribesthespecificlegislativeauthorityandrequirementstobeincluded in any such plan including from previous orders of the Illinois Commerce Commission("Commission"or"ICC").

The Plan addresses the provision of electricity and renewable resource supply for the “eligible retailcustomers”ofAmeren IllinoisCompany(“Ameren Illinois”),CommonwealthEdison(“ComEd”), and for thefirst time in an IPA Procurement Plan, MidAmerican Energy (“MidAmerican”). As defined in Section 16‐111.5(a)ofthePUA,“eligibleretailcustomers”areforAmerenIllinoisandComEdgenerallyresidentialandsmall commercial fixed price customers who have not chosen service from an alternate supplier. ForMidAmerican, eligible customers include residential, commercial, industrial, street lighting, and publicauthoritycustomersthatpurchasepowerandenergyfromMidAmericanunder fixed‐pricebundledservicetariffs.ThePlan considersa5‐yearplanninghorizon thatbeginswith the2016‐2017energydeliveryyearandlaststhroughthe2020‐2021deliveryyear.

The2015ProcurementPlanwas approvedby theCommission inDocketNo. 14‐0588.TheAgency’s 2015Plan, as approved by the Commission called for continuing the use (first adopted in 2014) of two energyprocurementeventseachyear,tobeheldinthespringandfall.The2015Plancalledatleast50%ofAmerenIllinois’ capacity requirements be procured in a fall procurement event. Finally, the 2015 Plan called forprocurementsofSolarRenewableEnergyCredits(“SRECs”),andaprocurementorRenewableEnergyCreditsfromdistributedgenerationdevices.

The2016ProcurementPlanrecommendsthattheenergyandrenewableresourcesrequirementsforAmerenIllinois,ComEd,andMidAmericanbeprocuredbythe IPA through twoblockenergyprocurements (springand fall),aspringrenewablesprocurement,anda falldistributedgenerationprocurement. Inaddition, thePlan calls for capacity procurements for Ameren Illinois and MidAmerican to be held as a Fall 2016procurement event. The IPA recommends a minor change to the energy hedging strategy in which theOctoberrequirementswillbehedgedto75%inthespringprocurementandto100%inthefallprocurementevent. The IPA also recommends that the load forecasts prepared by Ameren Illinois, ComEd andMidAmerican,whichformthebasisforthe2016Plan,beadoptedbytheCommission.

1.1 PowerProcurementStrategy

The Plan proposes to continue using the risk management and procurement strategy that the IPA hashistorically utilized: hedging load by procuring on and off‐peak blocks of forward energy in a three‐yearladderedapproach.WhiletheIPAagainthisyearinvestigatedalternativeriskmanagementstrategies,theIPAbelievesthecontinuationofitsprevious(testedandproven)riskmanagementstrategyisthemostprudent,most reasonable, and the most likely to meet its statutorily mandated objective to “[d]evelop electricityprocurementplanstoensureadequate,reliable,affordable,efficient,andenvironmentallysustainableelectricserviceatthelowesttotalcostovertime,takingintoaccountanybenefitsofpricestability.”1

Theproposedhedgingstrategy, intheshortterm(promptdeliveryyear), isdesignedtomanagetheriskofload uncertainty resulting from the possibility of large blocks of load returning to the utilities because ofmunicipalities choosing not to continue their aggregation programs.2As described in detail in Chapter 7,basedontheanalysisofthecostsofprocurementinChapter6andsupplyshortfallsidentifiedinChapter4,

120ILCS3855/1‐20(a)(1).2Thelargestsingleblockofloadthatcouldreturn,customersintheCityofChicago,isreturningduringthelatesummer/earlyfallof2015andthusisalreadyaccountedforinthe2016Plan.


2

the IPA recommends a refinement of the procurement approach adopted in the 2015 Plan for use in theprocurementofpowerfordeliveryyear2016‐2017andbeyond.

Consistentwith the 2015 Plan, the IPA also continues to recommend procurement of energy in blocks of25MW. The riskmanagement strategy will continue to bifurcate the first delivery year into periods withdifferent hedging levels—with June hedged at 100% of average load, July and August hedged to 106% ofaverage on‐peak load and 100% of average off‐peak load, fall hedged to 100% of average load, and thebalance of the year hedged to 75%of average load at the time of the spring procurement event. The IPArecommends that the Commission pre‐approve a fall energy procurement event, which would bring thehedginglevelforthebalanceofthefirstdeliveryyear(OctoberthroughMay)tothefullyhedgedlevel(100%ofload).

Consistentwiththe2015Planandyearsprior,theIPArecommendshedging50%oftheexpectedloadforthesecond delivery year, and 25% of the expected load for the third delivery year. The IPA, for this Plan,recommendstheprocurementofhalfofthesevolumesinthespring2016procurementeventandthebalanceinthefall2016procurementevent.

Additionally,forAmerenIllinois,theIPArecommendspurchasingcapacityinbilateralprocurementeventstosatisfyaportionofthecapacityrequirementsforthesecondandthirddeliveryyears.ForMidAmerican,theIPArecommendspurchasingalloftheforecastcapacityshortfallforthefirstdeliveryyear(2016‐2017)intheMISO capacity auction,which is known as the Planning Resource Auction (“PRA”)3. For the following fivedeliveryyears(June2017throughMay2022),theIPArecommendspurchasingallofMidAmerican’sforecastcapacityshortfallinabilateralprocurementeventinthefallof2016basedonMidAmerican’sJuly2016loadforecast which will be pre‐approved by the ICC in this docket, subject to the review of the IPA and theconsensus among the IPA, ICC Staff, MidAmerican and the Procurement Monitor. The IPA recommendsconsensus because the capacity requirements for the 2021‐2022 delivery year will not be known untilMidAmericanproducestheJuly2016loadforecast.

Asidefromtheproposalabove,theIPArecommendsthatcapacity,ancillaryservices,loadbalancingservices,andtransmissionservicesbepurchasedbyAmerenIllinoisandMidAmericanfromtheMISOmarketplaceandbyComEdfromPJM’s.

ThefollowingtablessummarizetheIPA’sproposedprocurementandhedgingstrategy:

Table1‐1:SummaryofEnergyHedgingStrategy

3ThePRAisanannualcapacityauctionthatdeterminesclearingpricesonazonalbasis.ThePRAprovidesloadservingentitiesinMISOwithanoptionformeetingtheircapacityobligationsbybuyingcapacityfromtheauction.

Spring2016Procurement Fall2016Procurement

June2016‐May2017(UpcomingDeliveryYear)

UpcomingDeliveryYear+1


October2016‐May2017



June100%peakandoffpeakJulyandAug.106%peak,100%offpeakandSep.100%peakandoffpeakOct.‐May75%peakandoffpeak

25% 12.5% 100% 25% 12.5%


3

Table1‐2:SummaryofCapacityProcurementStrategyforComEd*PJMRPMBaseResidualAuctionsfor2016‐17and2017‐18havealreadycleared.PJM’sinitialCapacityPerformanceResourceauctionwillbecompletedbymid‐September2015.

Table1‐3:SummaryofCapacityHedgingStrategyforAmerenIllinois*MISOAuctionisexpectedtoclearinApril2016.**MISOAuctionisexpectedtoclearinApril2017.***MISOAuctionisexpectedtoclearinApril2018.

Table1‐4:SummaryofCapacityHedgingStrategyforMidAmerican

*MISOAuctionisexpectedtoclearinApril2016.

1.2 RenewableEnergyResources

The load forecasts provided by the utilities on July 15, 2015 indicate that existing renewable energyresources under contract for Ameren Illinois and ComEd do notmeet or exceed the Renewable PortfolioStandardobligations for solarphotovoltaicsor fordistributedgeneration.MidAmericanhasnotpreviouslybeen a part of the IPA procurement process, or subject to its provisions, and thus it does not have anyresources previously procured to meet its overall obligations or its specific obligations for wind,photovoltaics,ordistributedgeneration.Accordingly,theIPArecommendsconductingaspringprocurementeventforgeneralRECs(MidAmericanonly),wind(MidAmericanonly),andsolarRECs(allutilities)usingtheRenewable Resources Budget. The IPA also proposes a fall procurement for distributed generation RECsusing hourly ACP funds for Ameren Illinois and ComEd, and using the Renewable Resources Budget forMidAmerican.

Table1‐5summarizestheIPA’sproposedsupply‐sideprocurementsasdescribedinthisPlan:


June2017‐May2018

June2018‐May2019

100%PJMRPMAuctions* 100%PJMRPMAuctions*

100%PJMRPMAuctions


June2017‐May2018

June2018‐May2019

50%RFPinSep.201550%MISOPRA*

25%RFPinSep.201550%RFPinFall201625%MISOPRA**

25%RFPinFall201650%RFPinFall201725%MISOPRA***


June2017‐May2022

100%MISOPRA* 100%RFPinFall2016


4

Table1‐5:SummaryofProcurementPlanRecommendationsBasedonJuly15,2015UtilityLoadForecast(QuantitiestobeAdjustedBasedontheMarchandJuly2016LoadForecast):

DeliveryYear

Energy Capacity RenewableResourcesAncillaryServices

2016‐2017 Upto675MWforecastedrequirement(Spring

Procurement)

Upto250MWadditionalforecastedrequirement(FallProcurement)

50%RFPinSep.201550%MISOPRA

One‐yearSRECsprocurementupto34.2GWh

Five‐yearDGRECprocurement

upto7.8GWh*

NoRPSprocurementorsalesforotherresources,targetexceeded

Willbepurchasedfrom

MISO


Procurement)Upto125MWforecasted

requirement(FallProcurement)

25%RFPinSep.201550%RFPinFall2016

25%MISOPRA

NoRPSprocurement:shortageof52.8GWh,revisitnextyear

Willbepurchasedfrom

MISO

2018‐2019 Upto125MWforecastedrequirement

(SpringProcurement)Upto150MWforecasted


25%RFPinFall201650%RFPinFall2017

25%MISOPRA


Willbepurchasedfrom

MISO

2019‐2020 Noenergyprocurementrequired

Nofurtheractionatthistime


Willbepurchasedfrom

MISO


Nofurtheractionatthistime.


Willbepurchasedfrom

MISO

2016‐2017 Upto1,925MWforecastedrequirement(Spring

Procurement)


100%PJMRPMAuctions



upto16.3GWh*

Totalrenewablesare68GWhshortoftarget

Willbepurchasedfrom

PJM




100%PJMRPMAuctions


Willbepurchasedfrom

PJM




100%PJMRPMAuctions

NoRPSprocurement:shortageof1,616.6GWh,revisitnextyear

Willbepurchasedfrom

PJM




Willbepurchasedfrom

PJM




Willbepurchasedfrom

PJM

AMERENILLINOIS

COMED


5


Procurement)


100%MISOPRA One‐yearSRECsprocurementupto13.2GWh


upto2.2GWh

Totalrenewablesare220.4GWhshortoftarget.Includes

165.3GWhofwind,13.2GWhofsolarand2.2GWhofDG

Willbepurchasedfrom

MISO


100%RFPinFall2016**


Willbepurchasedfrom

MISO


100%RFPinFall2016**


Willbepurchasedfrom

MISO


100%RFPinFall2016**


Willbepurchasedfrom

MISO


100%RFPinFall2016**


Willbepurchasedfrom

MISO

*ThetotalDGRECstobeprocuredwillbeadjustedbasedontheresultsoftheFall2015DGprocurementevent.**Thefall2016capacityprocurementwillcoverfiveplanningyears,startingwiththe2017‐18PlanningYearandendingwiththe2021‐2022PlanningYear.

1.3 IncrementalEnergyEfficiency

ThisplanisthefourthyearforinclusionofincrementalenergyefficiencyprogramspursuanttoSection16‐111.5BofthePublicUtilitiesAct.TheIPArecommendsinclusionoftheprogramssubmittedbytheutilitiesthathavepassedtheTotalResourceCostandhavenotbeendeterminedtobeduplicativeofotherprograms.

1.4 TheActionPlan

Inthisplan,theIPArecommendsthefollowingitemsforICCaction:

1. ApprovethebasecaseloadforecastsofComEd,AmerenIllinoisandMidAmericanassubmittedinJuly2015.

2. Requiretheutilitiestoprovideanupdated loadforecastbyMarch15,2016whichwillbepre‐approvedby the ICCaspartof theapprovalof thisPlan, subject to the reviewof the IPA.Theconsensusofeachutility,theIPA,theICCStaff,andtheProcurementMonitorwillberequiredifautilityloadforecasttriggersthecurtailmentoftheLong‐TermPowerPurchaseAgreements.

3. Approvetwoenergyprocurementeventsscheduled forspring2016and fall2016.TheenergyamountstobeprocuredinspringwillbebasedontheupdatedMarch2016loadforecastandinaccordancewiththehedginglevelsstatedinthisPlanandasultimatelyapprovedbytheICCaspart of the approval of this Plan. The energy amounts (and capacity for Ameren Illinois andMidAmerican) tobeprocured in the fallwillbebasedon the July2016expected load forecastdevelopedbyeachofAmerenIllinois,MidAmericanandComEd,andsubjecttothereviewoftheIPA.

4. Approve procurement by ComEd, Ameren Illinois, and MidAmerican of capacity, networktransmissionserviceandancillaryservicesfromtheirrespectiveRTOforthe2016‐2017deliveryyear.

5. Approve a fall capacity procurement for Ameren Illinois in a quantity of 50% of its forecastrequirements for the second delivery year (2017‐2018) and 25% for the third delivery year

MIDAMERICAN


6

(2018‐2019).Ameren Illinoiswillprocure25%of itscapacity requirements through theMISOPRAforthesecondandthirddeliveryyears.

6. Approve theprocurement of capacity byMidAmerican tomeet the quantity ofMidAmerican’sforecastcapacityshortfallforthefirstdeliveryyear(2016‐2017)throughtheMISOPRA.

7. Approveacapacityprocurement forMidAmerican insufficientquantities tomeet100%of theforecastcapacityshortfallforthe2017‐2018throughthe2021‐2022deliveryyearsinabilateralprocurementeventinthefallof2016basedonMidAmerican’sJuly2016expectedloadforecastwhichwillbepre‐approvedbytheICCaspartoftheapprovalofthisPlan,subjecttothereviewoftheIPAandconsensusamongtheIPA,ICCStaff,MidAmericanandtheProcurementMonitor.The IPA recommends consensus among the IPA, ICC Staff,MidAmerican and theProcurementMonitorbecausethecapacityrequirementsforthe2021‐2022deliveryyearwillnotbeknownuntilMidAmericanproducestheJuly2016loadforecast.

8. Approve pro‐rata curtailment of ComEd and Ameren Illinois’ Long‐Term Power PurchaseAgreements forrenewableenergy intheunlikelyeventthattheupdatedMarch2016expectedloadforecastindicatesthatsuchacurtailmentisnecessary.Thisforecastwillformthebasisforpro‐ratacurtailmentoflongtermrenewablecontractsassumingconsensusisreachedamongtheparties identified in Item 2 above. Otherwise, the July 2015 forecast will form the basis forcurtailment.

9. Approve a spring 2016 procurement of RECs using the renewable resources budget for theprompt delivery year to allow the utilities to meet their RPS requirements other than fordistributedgeneration(solarphotovoltaiconlyforAmerenIllinoisandComEd,allcategoriesforMidAmerican).Thevolumefortheprocurementwillbedeterminedbaseduponthe“RemainingTarget” quantities resulting from the utilities’ March, 2016 load forecasts and limited to thefundsavailableaccordingtotheutilities’updatedbudgets.

10. Approveafall2016procurementofdistributedgenerationRECsusingalreadycollectedhourlyACP funds for Ameren Illinois and ComEd, and the Renewable Resources Budget forMidAmerican.

11. Approve consensus items from the 2015 energy efficiency stakeholder workshops and prioryears’ energy efficiency stakeholder workshops related to the implementation of Section 16‐111.5BoftheIPAAct.

12. ApprovetheSection16‐111.5BincrementalenergyefficiencyprogramsidentifiedbytheAgencyforapprovalinChapter7.

TheIllinoisPowerAgencyrespectfullypoststhisdraftProcurementPlan,whichtheIPAbelievesiscompliantwithallapplicablelaw,forpubliccommentwithaduedateforcommentsofSeptember14,2015.


7

2 Legislative/RegulatoryRequirementsofthePlan

ThisSectionofthe2016ProcurementPlandescribesthelegislativeandregulatoryrequirementsapplicableto the Agency’s annual Procurement Plan, including compliance with previous Commission Orders. ARegulatory Compliance Index, Appendix A, provides a complete cross‐index of regulatory/legislativerequirementsandthespecificsectionsofthisplanthataddresseachrequirementidentified.

2.1 IPAAuthority

The IllinoisPowerAgency (“IPA”, or “Agency”)wasestablished in2007byPublicAct95‐0481 inorder toensurethatratepayers,specificallycustomersinserviceclassesthathavenotbeendeclaredcompetitiveandwho take service from the utility’s bundled rate (“eligible retail customers”),4benefit from retail andwholesalecompetition.Theobjectiveof theActwasto improvetheprocesstoprocureelectricityforthosecustomers.5In creating the IPA, the General Assembly found that Illinois citizens should be provided“adequate,reliable,affordable,efficient,andenvironmentally‐sustainableelectricserviceat the lowesttotalcost over time, taking into account benefits of price stability.”6The General Assembly also articulated“investmentinenergyefficiencyanddemand‐responsemeasures,andtosupportdevelopmentofcleancoaltechnologiesandrenewableresources”asadditionalgoals.7

Each year, the IPA must develop a “power procurement plan” and conduct a competitive procurementprocess to procure supply resources as identified in the final procurement plan, as approved pursuant toSection16‐111.5ofthePublicUtilitiesAct(“PUA”).8ThepurposeofthepowerprocurementplanistosecuretheelectricitycommodityandassociatedtransmissionservicestomeettheneedsofeligibleretailcustomersintheserviceareasofCommonwealthEdisonCompany(“ComEd”)andAmerenIllinoisCompany(“AmerenIllinois”),aswellas“smallmulti‐jurisdictionalutilities”shouldtheyrequesttoparticipate.9TheIllinoisPowerAgency Act (“IPA Act”) directs that the procurement plan be developed and the competitive procurementprocess be conducted by “experts or expert consulting firms,” respectively known as the “ProcurementPlanning Consultant” 10 and “Procurement Administrator.” 11 The Illinois Commerce Commission(“Commission”) is taskedwith approval of the plan andmonitoring of the procurement events through aCommission‐hired“ProcurementMonitor.”12

2.2 ProcurementPlanDevelopmentandApprovalProcess

Although the elements of procurement planning process are ongoing, with the Agency incorporatingstakeholder input and lessons from past proceedings, the formal process for composing the 2016ProcurementPlanbeganonJuly15,2015.Bythatdate,eachIllinoisutilitythatprocureselectricitythroughthe IPA (ComEd,Ameren Illinois, and for2016,MidAmerican)had submitted load forecasts to theAgency.Theseforecasts–whichformthebackboneoftheProcurementPlanandwhicharecoveredinSections3.2,3.3,and3.4ingreaterdetail–coverafive‐yearplanninghorizonandincludehourlydatarepresentinghigh,low,andexpectedscenariosfortheloadoftheeligibleretailcustomers.

4220ILCS5/16‐111.5(a).520ILCS3855/1‐5(2);3855/1‐5(3);3855/1‐5(4).620ILCS3855/1‐5(1).720ILCS3855/1‐5(4).820ILCS3855/1‐20(a)(2),3855/1‐75(a).920ILCS3855/1‐20(a)(1).AsindicatedinChapter1,throughalettertotheIPAdatedApril9,2015,MidAmericanhaselectedtoparticipateinthe2016ProcurementPlan.Seealso220ILCS5/16‐111.5(a).(“ThisSectionshallnotapplytoasmallmulti‐jurisdictionalutilityuntilsuchtimeasasmallmulti‐jurisdictionalutilityrequeststheIllinoisPowerAgencytoprepareaprocurementplanforitseligibleretailcustomers.”)1020ILCS3855/1‐75(a)(1).1120ILCS3855/1‐75(a)(2).12220ILCS5/16‐111.5(b),(c)(2).


8

Next, the IPApreparedadraftProcurementPlan.ThisdocumentconstitutesthatdraftPlan.OnAugust14,2015,thatPlanwasmadeavailableforpublicreviewandcomment.ThePublicUtilitiesActprovidesfora30‐day comment period starting on the day the IPA releases its draft plan. The 2016 Plan comment periodconcludesonMondaySeptember14,2015.Duringthe30‐daycommentperiod,theAgencyisrequiredtoholdone public hearing within each utility’s service area for the purpose of receiving public comment on theprocurement plan;13those public hearings are scheduled for September 4th in Moline, September 9th inSpringfield, and September 10th in Chicago. After the receipt of public comment andwithin fourteen daysfollowingtheendofthe30‐dayreviewperiod(i.e.,nolaterthanSeptember28,2015),theIPAmustfile itsrevisedProcurementPlanwiththeCommissionforapproval.14ObjectionstothisPlanmustbefiledwiththeCommissionwithin five days after the filing of the Plan;15typically, the Administrative Law Judge sets thedatesforResponsesandRepliestoObjectionsbyRulingshortlyafterthedocketopens.TheCommissionmustenteranorder confirmingormodifying thePlanwithin90daysafter it is filedby the IPA;16assuming theAgency files its2016PlanonSeptember28,2015, thisyear’sdeadlinewillbeSunday,December27,2015(leading toaMonday,December28,2015deadline).Thecurrent ICCcalendar indicates the last scheduledmeetingpriortothatdeadlineisonTuesday,December22,2015.

The Commission approves the Procurement Plan, including the load forecasts used in the Plan, if theCommission determines that “it will ensure adequate, reliable, affordable, efficient, and environmentallysustainable electric service at the lowest total cost over time, taking into account any benefits of pricestability.”17

2.3 ProcurementPlanRequirements

At itscore, theProcurementPlanconsistsofthreepieces:(1)aforecastofhowmuchenergy(andinsomecasescapacity)isrequiredbyeligibleretailcustomers;(2)thesupplycurrentlyundercontract;and(3)whattype andhowmuch supplymust beprocured tomeet load requirements and all other legal requirements(suchasrenewable/cleancoalpurchaserequirementsormandates frompreviousCommissionOrders).Tothat end, theProcurementPlanmust containanhourly loadanalysis,which includes:multi‐yearhistoricalanalysis of hourly loads; switching trends and competitive retail market analysis; known or projectedchanges to future loads;andgrowth forecastsbycustomerclass.18Inaddition, theProcurementPlanmustanalyze the impact of demand side and renewable energy initiatives, including the impact of demandresponseprogramsandenergyefficiencyprograms,bothcurrentandprojected.19Basedonthehourly loadanalysis, theProcurementPlanmustdetail the IPA’splan formeeting theexpected loadrequirements thatwillnotbemetthroughpreexistingcontracts,20andindoingsomust:

Define the different Illinois retail customer classes for which supply is being purchased, andinclude monthly forecasted system supply requirements, including expected minimum,maximum,andaveragevaluesfortheplanningperiod.21

Includetheproposedmixandselectionofstandardwholesaleproductsforwhichcontractswillbeexecutedduringthenextyearthat,separatelyorincombination,willmeettheportionoftheloadrequirementsnotmet throughpre‐existingcontracts.22Suchstandardwholesaleproductsinclude,butarenotlimitedto,monthly5x16peakperiodblockenergy,monthlyoff‐peakwrap

13220ILCS5/16‐111.5(d)(2).14Id.15220ILCS5/16‐111.5(d)(3).16Id.17220ILCS5/16‐111.5(d)(4).18220ILCS5/16‐111.5(b)(1)(i)‐(iv).19220ILCS5/16‐111.5(b)(2),(b)(2)(i).20220ILCS5/16‐111.5(b)(3).21220ILCS5/16‐111.5(b)(i),(b)(iii).22220ILCS5/16‐111.5(b)(3)(iv).


9

energy,monthly7x24energy,annual5x16energy,annualoff‐peakwrapenergy,annual7x24energy, monthly capacity, annual capacity, peak load capacity obligations, capacity purchaseplan,andancillaryservices.23

Detailtheproposedtermstructuresforeachwholesaleproducttypeincludedintheportfolioofproducts.24

Assessthepricerisk,loaduncertainty,andotherfactorsassociatedwiththeproposedportfoliomeasures,including,totheextentpossible,thefollowingfactors:contractterms;timeframesforsecurity products or services; fuel costs; weather patterns; transmission costs; marketconditions; and thegovernmental regulatory environment.25For thoseportfoliomeasures thatare identified as having significant price risk, the Plan shall identify alternatives to thosemeasures.

ForloadrequirementsincludedinthePlan,thePlanshouldincludetheproposedproceduresforbalancingloads, includingtheprocessforhourly loadbalancingofsupplyanddemandandthecriteriaforportfoliore‐balancingintheeventofsignificantshiftsinload.26

Includerenewableresourceanddemand‐responseproducts,asdiscussedbelow.

2.4 StandardProductProcurementandLoad‐FollowingProducts

Asnoted inSection2.3, the IPAActprovidesexamplesof “standardwholesaleproducts.”27This listinghasbeen understood by the Commission to be non‐exhaustive and non‐static.28Instead, as articulated by theCommissioninapprovingthe2015Plan,“[w]henevertheCommissionisconfrontedwithauniqueproduct...theremustbeanexaminationof theattributesof theproductandwhetherthoseareconsistentwithothercommonlytradedproductsinthewholesalemarket”andsuchproducts“mustberoutinelytradedinaliquidmarketandhavetransparentpricesthatallowparticipantsadegreeofassurancethattheyarereceivingfairmarketprices.”29

Reading Subsection 16‐111.5(b)(3)(vi) in conjunction with Subsection 16‐111.5(e) and the ICC’s OrderapprovingtheIPA’s2014ProcurementPlan,30theIPAunderstandsthatthedefinitionof“standardproduct”to also include wholesale load‐following products (including “full requirements” products) so long as theproductdefinition isstandardizedsuchthatbidsmaybe judgedsolelyonprice.31Withrespecttodemand‐side products, in approving the 2015 Plan the Commission determined that block super‐peak energyefficiencyproductsproposedforprocurementbytheAgency“shouldnotbeprocuredatthistime,”but leftopen the possibility that “as demand‐side markets evolve and energy efficiency products become more

23Id.24220ILCS5/16‐111.5(b)(3)(v).25220ILCS5/16‐111.5(b)(3)(vi).26220ILCS5/16‐111.5(b)(4).27220ILCS5/16‐111.5(b)(3)(iv).28SeeDocketNo.14‐0588,FinalOrderdatedDecember17,2014at156(“thelistenumeratedin16‐111.5(b)(3)(iv)containsthephrase‘includingbutnotlimitedto’whichexpandsthelistratherthanlimitsit;”“thephrase‘standardwholesaleproducts’cannotbestaticanditdependsontheproductsthatmaybetradedinwholesalemarketsatagiventime”).29DocketNo.14‐0588,FinalOrderdatedDecember17,2014at156.30WhilenotadoptingICEA’sfullrequirementsproposal,theCommission’sFinalOrderapprovingtheIPA’s2014Planmadeclearthatwholesaleload‐followingproducts,includingfullrequirementsproducts,mayqualifyasa“standardproduct.”SeeDocketNo.13‐0546,FinalOrderdatedDecember18,2013at94(“theCommissionagreeswithStaffandtheIPAthatfullrequirementsproductsshouldbeconsidereda‘standardproduct’underSection16‐111.5”).31See,e.g.,220ILCS5/16‐111.5(e)(2)(requiringdevelopmentofstandardized“contractformsandcreditterms”foraprocurement);16‐111.5(e)(3)‐(4)(creationofaprice‐basedbenchmarkandselectionofbids“onthebasisofprice”);DocketNo.09‐0373,FinalOrderdatedDecember28,2009at115‐116(Commissionapprovaloflong‐termrenewableresourcePPAprojectselectionbasedonpricealone).NotealsothattheCommission’sOrderapprovingthe2015ProcurementPlanindicatesthat“asdemand‐sidemarketsevolveandenergyefficiencyproductsbecomemorestandardized,theCommissioncouldenvisionatimeinwhichtheseproductsmightsatisfySection16‐111.5ofthePUA.”DocketNo.14‐0588,FinalOrderdatedDecember17,2014at156.


10

standardized,theCommissioncouldenvisionatimeinwhichtheseproductsmightsatisfySection16‐111.5ofthePUA.”32

2.5 RenewableEnergyResources

2.5.1 RenewablePortfolioStandard

TheGeneralAssemblyhasacknowledgedtheimportanceofincludingcost‐effectiverenewableresourcesinadiverseelectricityportfolio.33“Renewableenergyresources”isdefinedintheIllinoisPowerAgencyAct,andmeans (1) energy and its associated renewable energy credit or (2) renewable energy credits alone fromqualifyingsourcessuchaswind,solarthermalenergy,photovoltaiccellsandpanels,biodiesel,andothersasidentified in the IPAAct.34Aminimumpercentageofeachutility’s total supply to serve the loadofeligibleretailcustomersshallbegeneratedfromcost‐effectiverenewableenergyresources;byJune1,2016,atleast11.5%ofeachutility’stotalsupplyshouldbegeneratedfromrenewableenergyresources.35

Section 1‐75(c)(1) of the IPA Act also features sub‐target goals for the procurement of renewable energyresourcesbyspecificgeneratingtechnologies.Forthecurrent(2016)ProcurementPlan,totheextentcost‐effective resources are available, the IPA is directed to procure at least 75% of the renewable energyresources from wind generation, 6% from photovoltaics, and 1% from distributed renewable energygenerationdevices.36Renewableenergyresourcesprocuredfromdistributedgenerationdevicestomeetthisrequirementmayalsocount towards the requiredpercentages forwindandsolarphotovoltaics.37Inotherwords, if the IPA procures the required 1% distributed generation renewable energy resources and theresourcesusedtomeetthatstandardareallgeneratedfromphotovoltaics,thoseresourcesalsocounttowardthe6%solarphotovoltaicssub‐target,leaving5%solarphotovoltaicstobeprocuredfromothersources.InDocketNo.14‐0588approvingtheAgency’s2015Plan,theCommissionconfrontedthequestionofwhether,should the overall renewable energy resource requirements for the upcoming delivery year be met (viaexisting long‐term contracts), procurements may be conducted to satisfy the sub‐target percentage goalsspecifictogeneratingtechnologies.38Inthatproceeding,theCommissionapprovedtheAgency’sproposaltoconductaprocurementofrenewableenergycreditsfromphotovoltaicsystemsovertheobjectionsofComEdandAmerenIllinois(whoviewedtheprocurementas“unnecessary”),statingthat itwas“clearlysupportedbytherecord.”39

Section 1‐75(c)(1) sets renewables targets and technology‐specific sub‐targets based on “a minimumpercentageofeachutility'stotalsupplytoservetheloadofeligibleretailcustomers,asdefinedinSection16‐111.5(a)ofthePublicUtilitiesAct.”40ThiscanbeappliedsomewhatcleanlytoComEdandAmerenIllinois,as“each utility’s total supply to serve the load of eligible retail customers” is addressed through the IPA’sprocurementplanningprocess.Alternatively,MidAmerican“mayelecttoprocurepowerandenergyforalloraportionofitseligibleIllinoisretailcustomersinaccordancewiththeapplicableprovisionssetforthinthis

32DocketNo.14‐0588,FinalOrderdatedDecember17,2014at156.3320ILCS3855/1‐5(5),1‐5(6).3420ILCS3855/1‐10.SeealsoDocketNo.10‐0563,FinalOrderdatedDecember21,2010at83(“Section1‐10defines‘renewableenergyresources’aseitherenergyanditsassociatedrenewableenergycreditorrenewableenergycreditsfromrenewableenergy,suchaswindorsolarthermalenergy.AsnotedinSection1‐10aRECisarenewableenergyresourceandthereforefullymeetstherequirementofSection1‐20oftheIPAActrequiringtheprocurementofrenewableenergy.”)3520ILCS3855/1‐75(c)(1).36Id.37Id.38SeegenerallyDocketNo.14‐0588,FinalOrderdatedDecember17,2014at286(andassociateddiscussion).39Id.However,inpastprocurementplanproceedings,theCommissionhasalsoapprovedAgencyproposalsnottoconductrenewableresourceprocurementsdespitesub‐targetsnotscheduledtobemetduetoconcernsabouttheavailabilityofrenewableresourcebudgetfundsortheamountofresourcestobeprocuredrelativetotheprocurement’sadministrativecosts.(SeegenerallyDocketNos.12‐0544,13‐0546).4020ILCS3855/1‐75(c)(1).


11

Section and Section 1‐75 of the Illinois Power Agency Act.”41This raises the question of whether therenewablestargetsenumeratedinSection1‐75(c)automaticallyapplytoMidAmerican’sentireeligibleretailcustomer load, or only to that portion of its eligible retail customer load for which the IPA develops itsprocurementplan.FurtherdiscussiononthissubjectcanbefoundinChapter8.

All renewable energy resources procured, including those to meet sub‐target requirements, must still be“cost‐effective” under the law. The IPA Act’s definition of “cost‐effective” has two key features: first, fordifferent renewable resources, the Procurement Administrator creates a “benchmarks” “based on marketpricesforrenewableenergyresourcesintheregion”againstwhichallbidsaremeasured.42Nobidexceedingtheestablishedconfidentialbenchmarkpricemayberecommendedforprocurement.Second,andinadditiontothebenchmarks,thetotalcostofrenewableenergyresourcesprocuredforanysingleyearshallbereducedbyanamountnecessarytolimittheannualestimatedaveragenetincreaseduetothecostsoftheseresourcestonomorethanthegreaterof:

2.015%oftheamountpaidperkilowatt‐hourbyeligibleretailcustomersduringtheyearendingMay31,2007;or

Theincrementalamountperkilowatt‐hourpaidfortheseresourcesin2011.43

ThesevaluesarenowfixedforAmerenIllinoisandComEd,andthegreaterofthetwois0.18054¢/kWhforAmeren Illinois, and 0.18917 ¢/kWh for ComEd. For MidAmerican, the value is expected to be 0.12415¢/kWh.

Cost‐effectiverenewableenergyresourcesaresubjecttogeographicrestrictions;theIPAmustfirstprocurefrom resources located in Illinois or in states that adjoin Illinois.44If cost‐effective renewable energyresourcesarenotavailableinIllinoisoradjoiningstates,theIPAmustseekcost‐effectiverenewableenergyresourcesfrom“elsewhere.”45

The IPA’s 2015 Plan called for the pre‐authorization from the Commission of a curtailment of long‐termrenewablePPAs,pursuanttothelanguageofthecontract,shouldthespring2015loadforecastsindicatethattheeligibleretailcustomerratecapwouldbeexceededundertheexpected loadforecast.46Asdiscussed inlater chapters,with significant amountsof loadhaving switchedback to utility service, the likelihood thatexistinglong‐termpowerpurchaseagreementsmayneedtobecurtailedforthe2016‐2017deliveryyearisverylow.

Inadditionto fundsfromeligibleretailcustomers,alternativecompliancepaymentscollectedbytheutilityfrom customers taking service under the utility’s hourly pricing tariff “increase [IPA] spending on thepurchaseofrenewableenergyresourcestobeprocuredbytheelectricutilityforthenextplanyear.”47Aspartof the 2015 Plan, the existing balances of these funds were committed to procure distributed generationrenewableenergyresourcesunder5‐yearcontracts,with thebalanceof fundsavailable for thedistributedgenerationprocurementreducedbyanyamountsnecessarytobespentonRECsfromlong‐termrenewablePPA holders that could not be purchased by eligible retail customers due to Commission‐authorizedcurtailmentsnecessitatedbythestatutory2.015%rateimpactcap.48

41220ILCS5/16‐111.5(a)(emphasisadded).4220ILCS3855/1‐75(c)(1).4320ILCS3855/1‐75(c)(2)(E).4420ILCS3855/1‐75(c)(3).45Id.46SeeDocketNo.14‐0588,FinalOrderdatedDecember17,2014at6(authorizationofcurtailmentifnecessitatedbyrateimpactcapwasnotadisputedissue).Ultimately,theSpring2015loadforecastsdidnotdemonstratethatacurtailmentwasrequired.4720ILCS3855/1‐75(c)(5).48DocketNo.14‐0588,FinalOrderdatedDecember17,2014at6.Ascurtailmentswereultimatelynotnecessary,nofundswillbespentoncurtailedRECs.


12

2.5.2 DistributedGenerationResourcesStandard

Asnotedabove,withintheRenewablePortfolioStandardaresub‐targetsfortheprocurementofwind(75%),photovoltaics (6%), and distributed generation (1%). Procurement of renewable energy resources fromdistributedrenewableenergygenerationdevices is tobeconductedonanannualbasis throughmulti‐yearcontractsofnolessthanfiveyears,andshallconsistsolelyofrenewableenergycredits.49

Agenerationsourceisconsidereda“distributedrenewableenergygenerationdevice”undertheIPAActifitis:

Powered by wind, solar thermal energy, photovoltaic cells and panels, biodiesel, crops anduntreatedandunadulteratedorganicwastebiomass,treewaste,andhydropowerthatdoesnotinvolvenewconstructionorsignificantexpansionofhydropowerdams;

Interconnected at the distribution system level of either an electric utility, alternative retailelectricsupplier,municipalutility,oraruralelectriccooperative;

Locatedonthecustomersideofthecustomer’selectricmeterandisprimarilyusedtooffsetthatcustomer’selectricityload;andis

Limitedinnameplatecapacitytonomorethan2,000kW.50

Totheextentavailable,halfoftherenewableenergyresourcesprocuredfromdistributedrenewableenergygenerationshallcomefromdevicesoflessthan25kWinnameplatecapacity.51

The IPA’s 2015 Plan featured the first distributed generation‐specific procurement approved by theCommission. That procurement process is scheduled to begin in September 2015, with bid selection andcontractexecutionsettooccurinOctober.52Resultingcontractswillbefor5yearsbeginningwiththe2015‐2016deliveryyearandmaybefromanyqualifyingdistributedgenerationtechnology.Asrenewableenergyresourcesprocuredfromdistributedgenerationdevicesmayalsocounttowardstherequiredpercentagesforwindandsolarphotovoltaics, theAgencywill tracktheattributesofsystemsundercontractforfutureRECdeliveriesasaresultoftheFall2015DGprocurementandusethatinformationtoinformtheamounttobeprocured in future renewables, wind, photovoltaics, and distributed generation procurements (includingprocurements for the 2016‐2017 delivery year). Chapter 8 contains additional information on how theAgencyplanstoaddressthedistributedgenerationandothertechnology‐specificsub‐targetgoals.

2.5.3 RenewableEnergyResourcesFund

Separate from the renewable energy procurements approved as part of the Agency’s annual procurementplan are procurements made by the IPA from the Renewable Energy Resources Fund (“RERF”). CreatedthroughSection1‐56oftheIllinoisPowerAgencyAct,theRERFisaspecialfundintheIllinoisStateTreasuryadministered by the Illinois Power Agency to procure renewable energy resources.53 Unlike withprocurementsmadetosatisfytherequirementsofSection1‐75(c)oftheIPAAct,procurementsmadefromtheRERFarenotproposedaspartoftheAgency’sannualplananddonotrequireCommissionapproval,andthe resulting counterparty for such procurements is the State of Illinois (and not utilities).54Resourcesprocured using the RERF thus cannot be used to meet the utilities’ Section 1‐75(c) renewable energyresourcesprocurementtargets.

4920ILCS3855/1‐75(c)(1).5020ILCS3855/1‐10.5120ILCS3855/1‐56(b).52AsMidAmericanhadnotelectedtoparticipateinthe2015ProcurementPlan,thisprocurementisbeingconductedonlyforComEdandAmerenIllinois.5320ILCS3855/1‐56(a).54SeegenerallyDocketNo.12‐0544,FinalOrderdatedDecember19,2012at112‐113.


13

The RERF is funded through payments made by Alternative Retail Electric Suppliers (“ARES”) to satisfystatutory renewable energy resource procurement obligations manifest in Section 16‐115D of the PublicUtilitiesAct.55TheRERFdoesnotconsistofpaymentsmadebycustomerstakingsupply fromtheirelectricutility.Instead,forcustomerstakingsupplyfromanARES,theARESisresponsibleformakinganalternativecompliancepaymentfornolessthan50%ofitscomplianceobligation,56withitspaymentratedeterminedbyresultsfromtheprocurementofrenewableenergyresourcesusingtherenewableresourcesbudget.57Thesealternative compliance payments (“ACPs”) are generally made in conjunction with an ARES’s self‐procurementof theremainderof itsrenewableenergyresourceobligationtomeetcompliancewithstate’srenewableenergyportfoliostandard.58

InrecognitionoftheconstraintspresentinattemptingtoconductprocurementsfromtheRERFwithoutmoreexpressstatutoryauthorization,59PublicAct98‐0672creatednewsubsection1‐56(i)oftheIPAActrequiringtheIllinoisPowerAgencytodevelopaplanforconductingasupplementalprocurementofrenewableenergycreditsfromsolarphotovoltaics(“SRECs”)usingupto$30millionfromtheRERF.60TheIPA’sSupplementalPhotovoltaicProcurementPlanwasfiledwiththeCommissiononOctober28,2014andapprovedonJanuary21, 2015. The IPA conducted its first procurement pursuant to its Supplemental Plan inMay 2015with abudgetof$5million.61SubsequentprocurementsarescheduledforNovember2015($10million)andMarch2016($15million),withapotentialcontingencyprocurementtentativelyscheduledforspring2017shouldtherebeunspentfunds.

2.6 EnergyEfficiencyResources

Section 16‐111.5B of the PUA outlines requirements related to including new or expanded cost‐effectiveenergyefficiencyprogramsintheProcurementPlan.TheProcurementPlanmust includeanassessmentofopportunitiestoexpandprogramsundertheutilities’existingCommission‐approvedenergyefficiencyplansor to implementadditional cost‐effectiveenergyefficiencyprogramsormeasures.62Toassist in thiseffort,theutilitiesarerequiredtoprovide,alongwiththeirloadforecasts,an“assessmentofcost‐effectiveenergyefficiency programs or measures that could be included in the Procurement Plan.”63This assessment isrequiredtoincludethefollowing:

A comprehensive energy efficiency potential study for the utility's service territory that wascompletedwithinthepast3years.64

Beginning in2014, themostrecentanalysissubmittedpursuanttoSection8‐103Aof thePUAandapprovedbytheCommissionundersubsection(f)ofSection8‐103ofthePUA.65

Identification of new or expanded cost‐effective energy efficiency programs ormeasures that areincremental to those included in energy efficiency and demand‐response plans approved by theCommission pursuant to Section 8‐103 and that would be offered to all retail customers whoseelectric service has not been declared competitive under Section 16‐113 of the PUA andwho are

55220ILCS5/16‐115D(d)(4).56220ILCS5/16‐115D(b).57220ILCS5/16‐115D(d)(1).58Inpastyears,thevastmajorityofAREShavechosentopaynomorethantheminimumpercentage(50%)inalternativecompliancepayments,relyingonself‐procurementfortheremainder.59Foradiscussionoftheseconstraints,seetheIPA’sSupplementalPhotovoltaicProcurementPlanat3‐4.60http://ilga.gov/legislation/publicacts/fulltext.asp?Name=098‐067261Informationabouttheresultsofthatprocurementmaybefoundathttp://www.illinois.gov/ipa/Documents/IPA‐June‐2015‐SPV‐announcement.pdf.62See220ILCS5/16‐111.5B(a)(2).Additionally,pursuanttoSection16‐111.5B(a)(1),theAgency’sanalysisrequiredunderSection16‐111.5(b)(2)mustprovide“theimpactofenergyefficiencybuildingcodesorappliancestandards,bothcurrentandprojected.”ThisinformationiscontainedinAppendicestothePlan.63220ILCS5/16‐111.5B(a)(3).64220ILCS5/16‐111.5B(a)(3)(A).65220ILCS5/16‐111.5B(a)(3)(B).


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eligible to purchase power and energy from the utility under fixed‐price bundled service tariffs,regardlessofwhethersuchcustomersactuallydopurchasesuchpowerandenergyfromtheutility.66

Analysisshowing that theneworexpandedcost‐effectiveenergyefficiencyprogramsormeasureswouldleadtoareductionintheoverallcostofelectricservice.67

Analysisofhowthecostofprocuringadditionalcost‐effectiveenergyefficiencymeasurescomparesoverthelifeofthemeasurestotheprevailingcostofcomparablesupply.68

An energy savings goal, expressed inmegawatt‐hours, for the year inwhich themeasureswill beimplemented.69

Foreachexpandedornewprogram,theestimatedamountthattheprogrammayreducetheagency'sneedtoprocuresupply.70

BothAmerenIllinoisandComEdhaveprovidedthisinformation,whichisincludedintheAppendicestothisProcurementPlanalongwiththeir loadforecast information;MidAmericanassertsthatbecauseitdoesnotfallunderthepurviewofSection8‐103ofthePUA,71manyoftherequirementsofSection16‐111.5Barenotapplicable to it (while also providing substantive responses and accompanying information whereappropriate).72FurtherdiscussionoftheapplicabilityofSection16‐111.5BtoMidAmericancanbefoundinChapter7.

TheseassessmentsweredeliveredtotheIPAonJuly15thtoaidtheAgencyinthedevelopmentof its2016ProcurementPlan.ThePUArequirestheAgencyto include in itsProcurementPlanthoseenergyefficiencyprograms and measures that it determines are cost‐effective; the utilities are directed to factor in theassociated energy savings to the load forecast.73If the Commission approves the procurement of thisadditional efficiency, it shall reduce theamountofpower tobeprocuredunder theProcurementPlanandshalldirecttheutilitytoundertaketheprocurementoftheefficiencyresources.74

Forpurposesofmeetingthisstatutoryrequirement,“cost‐effective”meansthattheassessedmeasurespassthetotalresourcecosttestasdefinedintheIPAAct:75

“Totalresourcecosttest"or"TRCtest"meansastandardthat ismet if, foran investment inenergyefficiencyordemand‐responsemeasures,thebenefit‐costratioisgreaterthanone.Thebenefit‐costratioistheratioofthenetpresentvalueofthetotalbenefitsoftheprogramtothenet present value of the total costs as calculated over the lifetime of themeasures.A totalresourcecosttestcomparesthesumofavoidedelectricutilitycosts,representingthebenefitsthataccrue to the systemand theparticipant in thedeliveryof thoseefficiencymeasures,aswellasotherquantifiable societalbenefits, includingavoidednaturalgasutilitycosts, to thesumofall incremental costsof end‐usemeasures thatare implementeddue to theprogram(including both utility and participant contributions), plus costs to administer, deliver, andevaluateeachdemand‐sideprogram,toquantifythenetsavingsobtainedbysubstitutingthedemand‐sideprogramor supply resources. Incalculatingavoidedcostsofpowerandenergythat an electric utilitywould otherwise have had to acquire, reasonable estimates shall be

66220ILCS5/16‐111.5B(a)(3)(C).67220ILCS5/16‐111.5B(a)(3)(D).68220ILCS5/16‐111.5B(a)(3)(E).69220ILCS5/16‐111.5B(a)(3)(F).70220ILCS5/16‐111.5B(a)(3)(G).71See220ILCS5/8‐103(h)(“ThisSectiondoesnotapplytoanelectricutilitythatonDecember31,2005providedelectricservicetofewerthan100,000customersinIllinois.”).72SeeAppendixD,MidAmericanEnergyCompany’sElectiontoProcurePowerandEnergyforaPortionofitsEligibleIllinoisRetailCustomers.73220ILCS5/16‐111.5B(a)(4).74220ILCS5/16‐111.5B(a)(5).75See220ILCS5/16‐111.5B(b)(“ForpurposesofthisSection,theterm‘energyefficiency’shallhavethemeaningsetforthinSection1‐10oftheIllinoisPowerAgencyAct,andtheterm‘cost‐effective’shallhavethemeaningsetforthinsubsection(a)ofSection8‐103ofthisAct.);220ILCS5/8‐103(a)(“AsusedinthisSection,‘cost‐effective’meansthatthemeasuressatisfythetotalresourcecosttest.”).


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included of financial costs likely to be imposed by future regulations and legislation onemissionsofgreenhousegases.76

Each year, new issues relating to the implementation of Section 16‐111.5B are raised in the Commissionproceedings approving the IPA’s annual plan. Resolution (or at least further discussion) of these issues isoftendeferredtoworkshopprocessesorderedbytheCommissionforthemonthsimmediatelyfollowingtheconclusionofthedocket.AstheCommissionrecognizedinitsOrderapprovingthe2015Plan,“[a]significantproblemwithprocurementproceedingsistheexpeditedschedulecombinedwitharelativelylargenumberofcontestedissuesandparties,”makingit“difficultfortheCommissiontodealwithcomplexeconomicissues”suchas those related toTRCmethodology.77Furtherdiscussionof theenergyefficiency‐relatedworkshopsrequiredfromtheOrderapprovingthe2015Planandthecontestedissuestobeaddressedtherein,aswellasthe “energy efficiency programs and measures [the IPA] determines are cost‐effective” and thus fit forinclusioninthisPlan,maybefoundinChapter7.

Additionally,past years’disputeshave resulted in a seriesofCommission‐mandatedworkshops leading toconsensuslanguagebeingreachedamongstakeholders.Assomepartieshavequestionedtheapplicabilityofpast Commission‐approved consensus language to future solicitations and contracts, all such consensuslanguagereachedinprioryearsisincludedthisyearinAppendixB‐2andtheIPAisexpresslyrequestingthatsuchlanguagebeapprovedbytheCommissionwiththeintentionthatitbeappliedprospectively,informingtherequestsforproposalsdevelopedbytheutilitiespursuanttoSection16‐111.5B(a)(3)forthesolicitationofprogramstobeincludedinthe2017ProcurementPlan.

2.7 DemandResponseProducts

The IPAmay include cost‐effective demand response products in its Procurement Plan. The ProcurementPlanmustincludetheparticular“mixofcost‐effective,demand‐responseproductsforwhichcontractswillbeexecuted during the next year, to meet the expected load requirements that will not be met throughpreexisting contracts.”78Under the PUA, cost‐effective demand‐response measures may be procuredwhenever the cost is lower than procuring comparable capacity products, if the product and companyofferingtheproductmeetminimumstandards.79Specifically:

Thedemand‐responsemeasuresmustbeprocuredbyademand‐responseproviderfromeligibleretailcustomers;

The products must at least satisfy the demand‐response requirements of the regionaltransmissionorganizationmarketinwhichtheutility’sserviceterritoryislocated,including,butnotlimitedto,anyapplicablecapacityordispatchrequirements;80

Theproductsmustprovide for customers’participation in the streamofbenefitsproducedbythedemand‐responseproducts;

Theprovidermusthaveaplanforthereimbursementof theutility foranycosts incurredasaresultofthefailureoftheprovidertoperformitsobligations;81;and

Demand‐responsemeasures included in the plan shall meet the same credit requirements asapplytosuppliersofcapacityintheapplicableregionaltransmissionorganizationmarket.82

Public Act 97‐0616, the Energy Infrastructure Modernization Act (“EIMA”), required ComEd and AmerenIllinois to file tariffs instituting an opt‐in market‐based peak time rebate (“PTR”) program with the

7620ILCS3855/1‐10.77DocketNo.14‐0588,FinalOrderdatedDecember17,2014at224.78220ILCS5/16‐111.5(b)(3)(ii).79220ILCS5/16‐111.5(b)(3)(ii).80220ILCS5/16‐111.5(b)(3)(ii)(A);16‐111.5(b)(3)(ii)(B).81220ILCS5/16‐111.5(b)(3)(ii)(C);16‐111.5(b)(3)(ii)(D).82220ILCS5/16‐111.5(b)(3)(ii)(E).


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Commission within 60 days after the Commission has approved the utility’s AMI Plan.83ComEd’s PTRprogramwasprovisionallyapprovedinDocketNo.12‐0484andAmerenIllinois’PTRprogramwaslikewiseprovisionallyapprovedinDocketNo.13‐0105.84TheseprogramsarediscussedfurtherinSection7.5,wheredemandresponseresourcechoicesareexamined.

OnMay23,2014,apaneloftheU.S.CourtofAppealsfortheD.C.Circuitvoted2‐1toinvalidateFERCOrder745,whichcreatedauniformcompensationstructurefordemandresponseparticipationinwholesaleenergymarkets.85TherulingcreatesnonewobligationsfortheIPA,butcouldimpactthedegreetowhichdemandresponseproviderslooktostatepolicyasamechanismtomonetizedemandresponse.InearlyMay,theU.S.SupremeCourtgrantedpetitions forwritsofcertiorari in thematter, and thecase isexpected tobeheardduringtheCourt’sOctoberterm.86FurtherdiscussionofthisrulingcanbefoundinSection7.5.

2.8 CleanCoalPortfolioStandard

TheIPAActcontainsanaspirationalgoalthatcost‐effectivecleancoalresourceswillaccountfor25%oftheelectricityused in Illinoisby January1,2025.87Asapartof thegoal, thePlanmustalso includeelectricitygeneratedfromcleancoalfacilities.88Whilethereisabroaderdefinitionof“cleancoalfacility”containedinthe definition section of the IPA Act,89Section 1‐75(d) describes two special cases: the “initial clean coalfacility”90and“electricitygeneratedbypowerplantsthatwerepreviouslyownedbyIllinoisutilitiesandthathavebeenorwillbeconvertedintocleancoalfacilities(“retrofitcleancoalfacility”).91Currently,thereisnofacilitymeetingthedefinitionofan“initialcleancoal facility,” that the IPA isawareof, thathasannouncedplanstobeginoperationswithinthenextfiveyears.InDocketNo.12‐0544,theCommissionapprovedinclusionofFutureGen2.0asa“retrofitcleancoalfacility”starting in the 2017delivery year.While the IllinoisAppellateCourt upheld the cost recoverymechanismusedinthatdocket’sOrder,92thematteriscurrentlybeforetheIllinoisSupremeCourtanditsstatushasbeenthrown into question by a February 2015 announcement by the U.S. Department of Energy that federalfunding for theprojectwouldbesuspended.93Additionaldiscussionof theCleanCoalPortfolioStandard islocatedinSection7.6ofthePlan.

2.9 2015LegislativeProposals

The Spring 2015 session of the Illinois General Assembly saw the introduction of a number of legislativeproposalsthatwouldsignificantlychangethescopeordirectionoftheIllinoisPowerAgency’splanningandprocurementprocesses.94Amongtheproposalsarethefollowing:

83220ILCS5/16‐108.6(g).84SeeDocketNo.12‐0484,InterimOrderdatedFebruary21,2013at32;DocketNo.13‐0105,InterimOrderdatedJanuary7,2014at19.85SeeElectricPowerSupplyAss’nvs.FERC,753F.3d216,225(D.C.Cir.2014).86http://www.supremecourt.gov/orders/courtorders/050415zor_7648.pdf8720ILCS3855/1‐75(d).8820ILCS3855/1‐75(d)(1).8920ILCS3855/1‐10.90Id.9120ILCS3855/1‐75(d)(5).92SeeDocketNo.12‐0544,FinalOrderdatedDecember19,2012at228‐237;DocketNo.13‐0034,FinalOrderdatedJune26,2013(“PhaseII”approvingsourcingagreementasrequiredinDocketNo.12‐0544);CommonwealthEdisonCo.v.IllinoisCommerceCommission,etal.,2014ILApp(1st)130544,July22,2014.AsofthedateofthePlanbeingpublished,thismatterremainedunderconsiderationbytheIllinoisSupremeCourt.93http://www.chicagobusiness.com/article/20150203/NEWS11/150209921/futuregen‐clean‐coal‐plant‐is‐dead.94ElementsoftheseproposalsalsoaddressotheraspectsoftheIPA’swork,suchastheuseoftheRenewableEnergyResourcesFund;totheextentthatthoseelementsarenotpartoftheAgency’splanningandprocurementprocess,theyarenotaddressedhere.


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SB 1585/HB 3293 would require the Agency include the procurement of low carbon energyresources in itsannualprocurementplansandcompetitiveprocurementprocessesbeginningwiththepartialplanningyearcommencingonJanuary1,2016throughMay31,2021.

SB1879/HB3328wouldrequire theprocurementofphotovoltaicRECs frombrownfieldsites, thedevelopment of a “renewable energy resources plan,” andwould terminate the Section 16‐111.5Bpathwayfortheinclusionofenergyefficiencyprogramsinannualplans.

SB1485/HB2607wouldrequirethedevelopmentofa“long‐termrenewableresourcesprocurement

plan”(includinga“low‐incomesolarprogram,”a“decliningblockprogram,”anda“communitysolarprogram”) andwould conditionally terminate the Section 16‐111.5B pathway for the inclusion ofenergyefficiencyprogramsinannualplans.

SB1480wouldrequiretheinclusionofsourcingagreementsbetween“cleancoalfacilities”andboth

utilitiesandalternativeretailelectricsuppliersaspartofeachannualprocurementplan.TheAgencyisactivelytrackingthestatusofthesebillsandanyotherlegislationthatcouldchangeitspowers,duties,andobjectives.Inaddition,onAugust3,2015,theU.S.EnvironmentalProtectionAgencyreleaseditsfinalCleanPowerPlanrulespromulgatedpursuanttoSection111(d)oftheCleanAirAct.Theserulesrequirestatestodevelopstrategiesintendedtoreducecarbondioxideemissionsfrompowerplants.UndertheCleanPowerPlan,initialstatecomplianceplansareduetotheU.S.EPAbySeptember6,2016,andthedevelopmentoftheIllinoisstatecomplianceplanmaygenerateadditionallegislationofrelevancetotheAgency. SenateResolution623,adoptedMay31,2015,urgestheIllinoisPowerAgencytodothefollowing:

Independently review the PJM Interconnection LLC and Midwest Independent System OperatorcapacityauctionrulesandmarketdesignanddeterminewhytherulesandmarketdesignhavenotprotectedIllinoisratepayersfromsignificantincreases;

Independently investigate whether market power was exercised by any auction participants,

including thewithholdingof certaingenerationassets intended todriveup theclearingprice, andwhetherthemarketdesignforcapacityauctionsallowsfortheexerciseofmarketpower;and

Participate inFederalEnergyRegulatoryCommissionproceedingsthatwilladdressthedesignandoperationofthecapacitymarketplanningprocessesandauctionpracticesutilizedbyPJMandMISOand to promote policies in those proceedings that will ensure greater transparency, prevent theexerciseofmarketpowerbybidders,andtodelivercapacityresourcestoIllinoisconsumersatthelowestandmoststableprices.

A review of PJM and MISO capacity auction rules and market design can be found in Chapter 5, while adiscussionoftheIPA’sproposedstrategyforhedgingcapacityforComEd,AmerenIllinois,andMidAmericancanbefoundinChapter7.


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3 LoadForecasts

3.1 StatutoryRequirements

UnderIllinoislaw,aprocurementplanmustbepreparedannuallyforeach“electricutilitythatonDecember31,2005servedat least100,000customers in Illinois.”95Section16‐115(a)of thePUAallows smallmulti‐jurisdictional electricutilities to elect tohave the IPAprocurepower andenergy forall or aportionof itseligibleloadinIllinois.MidAmericanhaselectedtohavetheIPAprocureincrementalamountsofelectricity96,aswellasstatutorilymandatedrenewableresources for itseligiblecustomers in Illinois, startingwith thisplan.97Theplanmust includea loadforecastbasedonananalysisofhourly loads.Thestatuterequirestheanalysistoinclude:

Multi‐yearhistoricalanalysisofhourlyloads;

Switchingtrendsandcompetitiveretailmarketanalysis;

Knownorprojectedchangestofutureloads;and

Growthforecastsbycustomerclass.98

The statute also defines the process by which the procurement plan is developed. The load forecaststhemselvesaredevelopedbytheutilitiesasstatedinthestatute:

EachutilityshallannuallyprovidearangeofloadforecaststotheIllinoisPowerAgencybyJuly15ofeachyear,orsuchotherdateasmayberequiredbytheCommissionorAgency.Theloadforecastsshallcoverthe 5‐year procurement planning period for thenext procurement plan and shall include hourly datarepresentingahigh‐load,low‐loadandexpected‐loadscenariofortheloadoftheeligibleretailcustomers.Theutilityshallprovidesupportingdataandassumptionsforeachofthescenarios.99

The forecastsarepreparedbytheutilities,but theProcurementPlan isultimately theresponsibilityof theIllinois Power Agency. The Illinois Commerce Commission is required to approve the plan, including theforecastsonwhichitisbased.Therefore,theAgencymustreviewandevaluatetheloadforecaststoensurethey are sufficient for thepurposeofprocurementplanning.ThisChapter contains a summaryof the loadforecastsforAmerenIllinois,ComEd,andMidAmerican,theAgency’sevaluationoftheloadforecasts,andarecommendationontheforecaststhattheCommissionshouldapproveforprocurementplanning.

Note:Throughoutthisreport,exceptwherenoted,theretailloadistakentoincludeanallowanceforlosses.In otherwords, it represents the volume of energy that each utilitymust schedule tomeet the loadof itseligibleretailcustomersattheRTOlevel(MISOforAmerenIllinoisandMidAmerican,andPJMforComEd).

95220ILCS5/16‐111.5(a).96MidAmericanregisterswithMISOitsgenerationresourcesallocatedtoserveitsIllinoiscustomers,ashistoricalresources.Incrementalamountsofelectricityrefertothecapacityandenergythatwouldbeneededinadditiontothehistoricalresourcestomeettheprojectedloads.97MidAmericanservesfewerthan100,000electriccustomersinIllinoisand,asasmallmulti‐jurisdictionalelectricutility,isnotobligatedto,but“mayelecttoprocurepowerandenergyforalloraportionofitseligibleIllinoisretailcustomers”usingtheIPAprocess.220ILCS5/16‐111.5(a).ThisisthefirstprocurementprocessinwhichMidAmericanelectedtohavetheIPAprocurepowerandenergyforaportionofitsIllinoisjurisdictionalload.98220ILCS5/16‐111.5(b)(1).99220ILCS5/16‐111.5(d)(1).


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3.2 SummaryofInformationProvidedbyAmerenIllinois

IncompliancewithSection16‐111‐5(d)(1)ofthePublicUtilitiesAct,AmerenIllinoisprovidedtheIPAwiththefollowingdocumentsforuseinpreparationofthisplan:

AmerenIllinoisCompany(“AIC”)LoadForecastfortheperiodJune1,2016–May31,2021(SeeAppendixB)

ElectricEnergyEfficiencyCompliancewith220ILCS5/16‐111.5B.ThisdocumentalsocontainedsevenAppendices.(SeeAppendixB.Note,AmerenIllinoisAppendix6[BidReviewInformation],8[ThirdPartyBids],and9[DetailedAnalysis]weremarkedconfidentialandarenotincludedinAppendixB.)

Spreadsheetsoftheexpected,high,andlowloadforecasts.

Supplementalspreadsheetsdetailedtherenewableportfoliostandardtargetsandbudgetsundereachscenario,capacityneedsundereachscenario,andtheimpactontheexpectedloadforecastofincrementalenergyefficiencyprograms.(SummarizedinAppendixE)

Ameren Illinois uses a combination of statistical and econometric modeling approaches to develop itscustomer class specific load forecast models. A Statistically Adjusted End‐use approach is used for theresidential and commercial customer classes. This approach combines the econometric model’s ability toidentifyhistorictrendsandprojectfuturetrendswiththeend‐usemodel’sabilitytoidentifyfactorsdrivingcustomerenergyuse.

Industrialandpublicauthorityclassesaremodeledusingatraditionaleconometricapproachthatcorrelatesmonthlysales,weather,seasonalvariables,andeconomicconditions.TheLightingloadclassismodeledusingeitherexponentialsmoothingoreconometricmodels.

Figure3‐1showstheforecastedannualpercentageofusagebyeligibleretailcustomerloadandnon‐retainedretailcustomerload.100

100AmerenIllinoisassignsloadprofileclassificationsatthepointofservicelevelandonlytopointsofservicethataremetered.Theclassificationsareasfollows:DS1–Residential,DS2–Non‐TimeofUseCommercial&Industrialwithdemandslessthan150kW,DS3–TimeofUseCommercial&Industrialwithdemandsbetween150kWand1,000kW,DS4–TimeofUseCommercial&Industrialwithdemandsabove1,000kW,andDS5–Lighting.TheDS3andDS4classesarefullycompetitivemeaningcustomersintheseclassesmustreceivesupplyfromARESorAmerenIllinoisrealtimepricing.CustomersintheDS1,DS2andDS5classesareeligibletotakefixed‐priceservicefromAmerenIllinoisoranARES.


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Figure3‐1:AmerenIllinois’ForecastRetailCustomerLoadBreakdown,DeliveryYear2016‐2017

AmerenIllinois’forecastsareperformedonthetotalAmerenIllinoisdeliveryserviceloadusingaregressionmodelappliedtohistoricalloadandweatherdata.Aseparateanalysisisperformedforeachcustomerclasstoaccountforthedifferingimpactsofweatheronthedifferentcustomerclasses.Figure3‐2showstheAmerenIllinois5‐yearforecastbyretained/notretainedcustomergroup.

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Figure3‐2:AmerenIllinois’ForecastRetailCustomerLoadbyDeliveryYear

AmerenIllinoisappliesassumed“switchingrates”tothetotalsystemloadforecasttoremovetheloadtobeserved by bundled hourly pricing (Power Smart Pricing or Rider HSS), municipal aggregation, or otherAlternative Retail Electric Suppliers (“ARES”). Ameren Illinois establishes the current customer switchingtrend line utilizing actual switching data by customer class. Qualitative judgment is used to makeadjustments.TheportionoftheforecastloadattributedtoRiderHSS,municipalaggregation,andotherAREScustomers,issubtractedfromthetotalsystemloadforecast.TheresultistheforecastedloadtobesuppliedbyAmerenIllinois.

Figure3‐3providesamonthlybreakdownof theexpectedorbase‐case forecastofAmeren Illinoiseligibleretail load, that is, the load of customers who are eligible for bundled supply procured under thisProcurementPlan.

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Figure3‐3:AmerenIllinois’ForecastEligibleLoad*byMonth

*Totalload,priortonettingQFsupply.

AmerenIllinoisprovidesabasecaseandtwocompleteexcursioncases:a lowforecastandahighforecast.Eachexcursioncaseaddressesthreedifferentuncertaintiesthatsimultaneouslymoveinthesamedirection:macroeconomics,weather,andswitching.Thismeans,forexample,thatahighloadcaseshouldrepresentthecombination of stronger‐than‐expected economic growth (which increases load), extremeweather (whichincreasesload)andareducedlevelofswitching(whichincreasesthe“eligible”fractionofretailload,thatis,thefractionforwhichtheutilityretainsthesupplyobligation).Similarly,alowloadcaseshouldrepresentthecombinationofweaker‐than‐expectedeconomicgrowth,mildweatherandanincreaselevelofswitching.

3.2.1 Macroeconomics

The Ameren Illinois base case load forecast is based on a Statistically Adjusted End‐use forecast thatcombines technological coefficients (efficiencies of various end‐use equipment) and econometric variables(income levels and energy prices). Ameren Illinois did not define “high” and “low” cases by varying theeconometric (or other) variables. Instead, Ameren Illinois looked at the statistics of the residual from themodelfitandthehighandlowcasesarebasedona95%confidenceinterval.

Ameren Illinois’ “high” and “low” forecasts are uniform modifications of the expected case, excludingincrementalenergyefficiency,byrateclass.Specifically,ineachcase,asinglemultiplierisdefinedforeachofthe three non‐fully competitive delivery service rate classes, and the “before switching” load forecast foreveryhourismultipliedbytherateclassmultiplier.

Table3‐1:LoadMultipliersinAmerenIllinoisExcursionCasesRateClass LowCase HighCase

DS1 0.920 1.080DS2 0.883 1.117DS5 0.920 1.080

In regressionmodels, residuals indicate the difference between the predicted and actual values. Patternsassociatedwithresidualsmayindicatetheimpactofnon‐specifiedvariables.Becausetheexcursioncasesarebasedon thestatisticsof theresiduals, theyreflect the influenceofvariablesnotmodeled.The forecasting

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modelappearstobedominatedbytechnologicalandweathereffects.Theeconometricvariablesarerelatedtoshort‐termdecisionmaking.Uncertaintyaroundlong‐termeconomicgrowthwillappearintheresiduals.

3.2.2 Weather

AmerenIllinoisincludes“highweather”and“lowweather”initscharacterizationofthehighandlowcases.Ameren Illinois did not re‐compute its load forecasting models with different values for the weathervariables. The high and low scenarios only account for an averaged impact of weather, as well asmacroeconomics,whichisproportionallythesameineachhour.

Figure 3‐4 shows the base, high, and low case forecasts of Ameren Illinois eligible load, assuming noswitching.Thedifferencebetweenthehigh,lowandbasecasesshowthevariationAmerenIllinoisattributestomacroeconomics andweather. The low case is about 9% lower than thebase case and thehigh case isabout9%higherthanthebasecase.

Figure3‐4:AmerenIllinois’RetailCustomerLoadbeforeSwitchinginAmerenIllinois’Forecasts

3.2.3 Switching

According to Ameren Illinois, customer switching to alternative suppliers, in particular throughmunicipalaggregation, is the greatest driver of load uncertainty. Switching through April 2015 has resulted inapproximately58‐64%ofresidentialandsmallcommercial loadseekingservicefromalternativesuppliers.Ameren Illinois expects the amountof load suppliedbyARESwill remain flat across theplanninghorizonbasedonindicationsfrommunicipalitiesthathavecontractsexpiring.Additionally,AmerenIllinois’currentyear tariff price is similar to comparableARESprices.While according to Table 3‐2 presented in the nextSection,ARESofferings to the individualcustomers, ingeneral,appear tobehigher than thedefaultutilityrate, the rates offered by ARES to the aggregated loads may be lower and thus more comparable to theAmerenIllinoisdefaultservicerate.

Ahighloadscenarioenvisionsasituationwhereanevenlargerreturnofresidentialand,toalesserextent,commercialcustomers,isrealized,especiallyinJune2016whenapproximately30%ofresidentialloadwillseecontractsundergovernmentaggregationexpire.Residentialandcommercial switching ratesunder thehighloadscenarioareforecastedtobe24%and54%,respectively,inMay2017,23%and51%,respectively,inMay2018,and19%and42%,respectively,bytheendoftheplanninghorizon.

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24

Conversely,shouldfutureAmerenIllinoistariffpriceexceedcustomers’perceivedvalueofAREScontracts,ahigherswitchingscenario ispossible.ThusAmerenIllinois’ low loadscenarioassumesthatresidentialandsmallcommercialwillapproach71%and76%,respectively,inMay2017,77%and82%,respectively,inMay2018,and95%and94%,respectively,bytheendoftheplanninghorizon.

The difference in the amount of switching among the three cases is significant. Figure 3‐5 shows theretention,thatis,thefractionofdeliveryloadinclassesDS1,DS2andDS5thatremainsonutilityservice,forthebase,highandlowcases.

Figure3‐5:UtilityLoadRetentioninAmerenIllinois’Forecasts

As the figure shows, the difference in switching rates among the scenarios grows through the projectionhorizon. The difference in switching rates is themost significant factor driving the differences among thescenarios.

Figure3‐6showstheforecastedAmerenIllinoissupplyobligationineachcase.

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Figure3‐6:SupplyObligationinAmerenIllinois’Forecasts

3.2.4 LoadShapeandLoadFactor

Figure3‐7andFigure3‐8displaythehourlyprofileofAmerenIllinoissupplyobligationineachcase(relativetothedailymaximumload).Figure3‐7illustratesahigh‐loadsummerdayandFigure3‐8alow‐loadspringday.Inthesefiguresthecurvesarenormalizedsothatthehighestvalueineachis1.Thereislittledifferencebetweentheprofilesofthehigh,lowandbasecases.

Figure3‐7:SampleDailyLoadShape,SummerDayinAmerenIllinois’Forecasts

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Figure3‐8:SampleDailyLoadShape,SpringDayinAmerenIllinois’Forecasts

Onecallsa loadshape“peaky” if there isa lotofvariation in it– forexample, if there isa largedifferencebetweenthelowestandhighestloadvaluesor,inthesenormalizedcurves,ifthelowestpointiswellbelow1.Aloadshapethatisnotpeakyisoneinwhichtheloadisnearlyconstant.Thepeakinessofacaseisusuallyborneoutbytheloadfactors.Theloadfactor inanytimeperiod,suchasayear, istheratiooftheaverageloadtothemaximumload.Ingeneral,peakyloadcurveshavelowloadfactors.Figure3‐9showsthatthelowcasehasthe lowest loadfactors,whileFigure3‐7andFigure3‐8showthatthe lowcase loadprofile isnotpickier than the other two cases aswould be expected. This can be attributed to a difference inweatherassumptionsbetweenthelowcaseandtheothertwocases.

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Figure3‐9:LoadFactorinAmerenIllinois’Forecasts

3.3 SummaryofInformationProvidedbyComEd

IncompliancewithSection16‐111‐5(d)(1)ofthePublicUtilitiesAct,ComEdprovidedtheIPAthefollowingdocumentsforuseinpreparationofthisplan:

LoadForecastforFive‐YearPlanningPeriodJune2016–May2021.ThisdocumentalsocontainedAppendicesA‐D.FouroftheAppendicesareincludedinthemaindocument,whileone(ComEdAppendixC)withsupplemental informationonSection16‐111.B incrementalenergyefficiencyprogramswas includedas fouradditional separatedocuments. (SeeAppendixC.Note, ComEdalsoprovidedanadditionaldocumententitled,ThirdPartyEfficiencyProgramResultsof2015BidReviewwhichwasmarkedconfidentialandisnotincludedinAppendixC.)

Information supporting the load forecasts including spreadsheets of load profiles, hourly loadstrips, model inputs, procurement blocks, and scenario models for the base, high and lowforecasts.(SummarizedinAppendixF)

ComEd forecasts load by applying hourly load profiles for each of themajor customer groups to the totalserviceterritoryannual loadforecastandsubtractingloadsprojectedtobeservedbyhourlypricing,ARES,andmunicipalaggregation.HourlyloadprofilesaredevelopedbasedonstatisticallysignificantsamplesfromComEd’sresidential,non‐residentialwatt‐hour,and0to100kWdeliverycustomerclasses.Theprofilesshowclearandstableweather‐relatedusagepatterns.Usingtheprofilesandactualcustomerusagedata,ComEddevelopshourly loadmodels that determine the averagepercentage ofmonthlyusage that each customergroupusesineachhourofthemonth.

ComEddidnotsupplyitsforecastsformediumandlargecommercialandindustrialcustomers,whoseservicehasbeendeemedtobecompetitiveandwhothereforecannotbeeligibleretailcustomers.Figure3‐10showstheforecastedannualpercentageofusagebyeligibleretailcustomerloadandnon‐retainedretailcustomerload.

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Figure3‐10:ComEd’sForecastRetailCustomerLoadBreakdown,DeliveryYear2016‐2017

Asnotedabove, ComEdprovidesa forecastof total usage for the entire service territoryandallocates theusage to various customer classes using themodels specific to each class. A suite of econometricmodels,adjusted forotherconsiderations suchas customer switching, isused toproducemonthlyusage forecasts.Thehourlycustomerloadmodelsareappliedtocreatehourlyforecastsbycustomerclass.

Indeterminingtheexpectedloadrequirementsforwhichstandardwholesaleproductswillbeprocured,theComEd forecast must be adjusted for the volume served by municipal aggregation and other ARES. TheComEd5‐yearannualloadforecast,showninFigure3‐11,isbasedontherateofcustomerswitchinginthepast,expectedincreasesinresidentialARESservice,andtheanticipatedadditionalmigrationof0to100kWcustomers toARESandmunicipal aggregation.The figuredecomposes the total forecastof residential andsmallcommercialcustomerloadinthesamewayasFigure3‐10doesforasingleyear.


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Figure3‐11:ComEd’sForecastRetailCustomerLoadbyDeliveryYear

Figure3‐12providesamonthlybreakdownof theexpectedorbase‐case forecastofComEd’seligibleretailload,thatis,theloadofcustomerswhoareeligibleforbundledsupplyprocuredunderthisProcurementPlan.

Figure3‐12:ComEd’sForecastEligibleLoadbyMonth

ComEdprovidesabasecaseandtwoexcursioncases:alowforecastandahighforecast.Eachexcursioncaseaddresses three different uncertainties, simultaneously moving in the same direction: macroeconomics,weather,andswitching.

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ComEd’s base case load forecast is driven by a Zone Model that includes both macroeconomic variables(Gross Metropolitan Product for Chicago and other metropolitan areas within ComEd’s service territory,householdincome)anddemographics(householdcounts).ComEddidnotusethismodeltodefine“high”and“low”cases.ComEdmodifiedtheservicearealoadgrowthrates,increasingthemby2%inthehighcaseandreducingthemby2%inthelowload(becausethegrowthrateintheexpectedcaseisbelow2%,presumablythisimpliesnegativeloadgrowthinthelowcasethroughouttheprojectionhorizon).

3.3.2 Weather

ComEdincludes“highweather”and“lowweather”initscharacterizationofthehighandlowcases.Underthesampleyearapproach, thehigh loadforecastassumesthatthesummerweatherishotterthannormal,andthelowloadforecastassumesthatthesummerweatheriscoolerthannormal.

ComEdhasnotprovidedthespecificimpactsoftheloadgrowthassumption(loadforecastsintheabsenceofswitching). ComEddidprovide the impacts of theweather case on residential and small commercial load,relativetothebasecaseforecast.Theyareprovidedaspercentagesthatsummarizethehourlyimpactsofafiner‐scalemodeloftheeffectoftemperatureonload.Figure3‐13showstheimpactofweatheronloadbymonth.Thehighandlowyearsarenothighandlowineverymonth.Therearesomemonths,forexample,wheretheimpactofthe“highweather”yearislessthan1.

Figure3‐13:WeatherImpactsinComEd’sForecasts

3.3.3 Switching

The high switching (low load) case assumes residential ARES usage to be at 85% (vs. the 60% base caseassumption)intheyears2016and2017asthecommunitiesthatareoptingoutfromComEdservicerenewtheirmunicipalaggregationprograms.MunicipalaggregationhashistoricallybeenamajorfactorintherapidexpansionofresidentialARESsupply.Intotal,thereare357communitiesthathadapprovedaggregationasofAprilof2015.Thatisanincreasefromthe345communitiesreportedlastyear.Inaddition,itisassumedthatsmallcommercialswitchingincreasesinitiallyby1.2%andthenbyanother2.4%overthenext2years.

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Thelowswitching(highload)caseassumesadditionalcommunitiesoptforComEdserviceintheyears2016and2017suchthatresidentialARESusagedeclinestoapproximately35%intheyears2016and2017.Thiscoincideswithaninitial1.2%decreaseandafurtherdeclinebyanother2.4%insmallcommercialswitchingoverthenext2years.Figure3‐14showstheforecastedComEdsupplyobligationineachcase.

Figure3‐14:SupplyObligationinComEd’sForecasts


Figure3‐15andFigure3‐16displaythehourlyprofileoftheutilitysupplyobligationineachcase(relativetothedailymaximumload).Figure3‐15illustratesahigh‐loadsummerday,andFigure3‐16alow‐loadspringday.Thehighcaseisdefinitelypeakieronasummerdaythanthebasecase,andthelowcaseisflatter.Duringthesamplesummerday,boththebasecaseandlowcaseare lesspeakythanthehighcase;andduringthesamplespringday,thereisnosignificantdifferencebetweentheprofilesofthehighandbasecases,butthelowcaseisaslightlypeakier.

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Figure3‐15:SampleDailyLoadShape,SummerDayinComEd’sForecasts

Figure3‐16:SampleDailyLoadShape,SpringDayinComEd’sForecasts

TheannualloadfactorsareshowninFigure3‐17.Asexpected,thehighloadcasehasalowerloadfactorthanthebasecase.Unexpectedly,thebasecaseloadfactor ismuchhigherthanboththehigh‐caseandlow‐caseload factors. This may indicate that the base case forecast was based on an over‐averaged temperaturepattern(normaleveryday).

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Figure3‐17:LoadFactorinComEd’sForecasts

3.4 SummaryofInformationProvidedbyMidAmerican

In compliance with Section 16‐111‐5(d)(1) of the Public Utilities Act, MidAmerican provided the IPA thefollowingdocumentsforuseinpreparationofthisplan:

Methodology for Illinois Electric Customers and Sales Forecasts: 2016‐2025. This documentcontained a discussion of load forecast methodology for all MidAmerican scenarios andsupportingdataforthebasescenarioforecast.Theloadforecastincludedamulti‐yearhistoricalanalysisofhourlyloaddata,forecastedloadandcapabilityalongwiththeimpactofdemandsideand renewable energy initiatives. MidAmerican’s load forecast was further broken down byrevenue class, projected kWh usage and sales, which factored in economic and demographicvariables alongwithweather variables based onweather data. Additionally, the load forecastaccounted for sales forecasts based on variables and model statistics along with the non‐coincident electric gross peak demand forecast and represents all of the eligible customerclasses, except the customer accounted for being served by an ARES. Pursuant to Section 16‐111.5(d)(1),MidAmerican’sloadforecastcoveredafive‐yearprocurementplanningperiod.

MidAmerican’sElectiontoProcurePowerandEnergyforaPortionof itsEligibleIllinoisRetailCustomers Procurement Year – 2016 (Supplemental Procurement Plan Information). Thisdocument,with6attachments, furtheraddressedtheloadforecastapproach,switchingtrends,andenergyefficiency.

Spreadsheetsofloadprofiles,hourlyloadstrips,modelinputs,procurementblocks,andscenariomodelsforthebase,highandlowforecasts.(SummarizedinAppendixG)

MidAmericanforecastsloadbyusingeconometricmodelsonamonthlybasis.Fortheresidential,commercialandpublic authority classes, sales aredetermined bymultiplying customers byuse per customer. For theindustrialclass,salesaremodeleddirectly.Forthestreetlightingclass,salesareforecastusingtrending.

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Thegrosspeaknumbersusedintheanalysisarethehistoricalgrosspeaks,whichtakeintoaccountdemandsidemanagementimpacts.Sincethereareplannedlargeloadadditions,101usingthemodelresultsaloneforthe peak demand forecast would result in a forecast that is too low. Therefore, the planned large loadadditionsareaddedtothemodelresultstoachievethefinalpeakdemandforecast.

MidAmericanhasone active alternative retail supplier in its Illinois service territory.MidAmericanhasnocustomerclassesthathavebeendeclaredcompetitive.Figure3‐18showstheforecastedannualpercentageofusage by eligible retail customer load and non‐retained retail customer load.. The low level of switchingamongMidAmerican’seligiblecustomersrelativetothemuchhigherswitchinglevelsforAmerenIllinoisandComEd is likely due to a combination of market conditions in MidAmerican’s service area including: arelativelylowcostofMidAmerican‐ownedresourcesallocatedtoitsIllinoisloadwhichwouldleadtolittleornomunicipalaggregationactivity,andlittleprofitopportunityforARES.

Figure3‐18:MidAmerican’sForecastRetailCustomerLoadBreakdown,DeliveryYear2016‐2017

MidAmerican provided a forecast of total usage for the entire service territory combining the projectedcustomersandsalesnumbersmodeledusingdataspecifictotheareabeingforecast.Asuiteofeconometricmodels, adjusted for other considerations such as customer switching, is used to producemonthly usageforecasts.Thehourlycustomer loadmodelsareappliedtocreatehourly forecastsbycustomerclass.Somevariables, suchas customernumbers,price, sales, revenueclass, jurisdiction,etc.,wereobtained internallyfrom the companydatabase,whileotherdata, suchas economic,demographicandweatherwere receivedfromexternalsources.

101The3MplantlocatedinCordova,ILadded10MWofloadin2015Q1.Sincethisloadadditionwasnotpickedupinthedatausedtoestimatethemodel,usingthemodelresultsaloneforthepeakdemandforecastwouldresultinaforecastthatistoolow.Therefore,the10MWloadadditionwasaddedtothemodelresultstoachievethefinalpeakdemandforecast.

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Indeterminingtheexpectedloadrequirementsforwhichstandardwholesaleproductswillbeprocured,theMidAmericanforecast isadjustedforthevolumeservedbytheARES.TheMidAmerican5‐yearannual loadforecast, shown in Figure 3‐19, incorporates the rate of customer switching in the past, and expectedincreasesintheARESservice.Theretailchoiceswitchingforecastwasderivedbyreviewingrecentswitchingactivityandprojectingforwardrecenttrends.Thefiguredecomposesthetotalforecastofthetotalcustomerload,inthesamewayasFigure3‐18doesforasingleyear.

Figure3‐19:MidAmerican’sForecastRetailCustomerLoadbyDeliveryYear

Figure3‐20providesamonthlybreakdownof theexpectedorbasecase forecastofMidAmericanretainedretailload,thatis,theloadofcustomersonbundledsupplytobeconsideredunderthisProcurementPlan.

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Figure3‐20:MidAmerican’sForecastEligibleLoadbyMonth

MidAmericanprovidesabasecaseandtwoexcursioncases:alowforecastandahighforecast.Therequiredlowandhighhourlyloadforecastscenarioswerecreatedbytakingthe95%confidenceintervalaroundeachclass‐levelsales,customerandusepercustomerforecastandthe95%confidenceintervalaroundthenon‐coincidentgrosspeakdemandforecast.Theloadforecastingsoftwareusedforthesales,customersusepercustomer and non‐coincident peak demand forecasts, provided the upper and lower bounds of a 95%confidence interval aroundeachmonthly forecast value.This software feature allowed the constructionofupper and lower bound forecasts for the residential, commercial, industrial and public authority salesforecasts.Thestreetlightingsalesforecastwasmultipliedby0.99and1.01togenerate,respectively,alowerandupperboundstreetlightingsalesforecast.


MidAmerican’sreferencecaseloadforecastisbasedonthemodelutilizingeconomicanddemographicdatathatwereobtainedfromanexternalsourcedatabase.ForMidAmerican’sIllinoisserviceterritory,economicanddemographicvariablesspecifictotheQuadCitiesmetropolitanareawereusedintheforecastingprocess.The Quad Cities area encompasses MidAmerican’s Illinois service territory. The list of economic anddemographic variables considered for the forecast includes real gross metropolitan area product,manufacturing,population,households,employment,etc.Asmentionedabove,MidAmericanusedthismodelto define “high” and “low” cases applying the 95% confidence interval to arrive at the lower and upperbounds.

3.4.2 Weather

The reference case temperature assumptions in the hourly load forecastmodelwere not changed for thescenarios.Thereferencecaseweather‐relatedassumptions inthesales, theusepercustomerandthenon‐coincidentpeakdemandforecastmodelsforMidAmerican’sIllinoisserviceterritorywerenotchangedinthescenarios.

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3.4.3 Switching

The reference case forecasts for retail switching sales, customers, and demand in MidAmerican Illinoisserviceterritorywerenotchangedinthescenarios.Figure3‐21showstheforecastedMidAmericanIllinoissupplyobligationineachcase.

Figure3‐21:SupplyObligationinMidAmerican’sForecasts


Figure3‐22andFigure3‐23displaythehourlyprofileoftheutilitysupplyobligationineachcase(relativetothedailymaximumload).Figure3‐22illustratesahigh‐loadsummerday,andFigure3‐23showsalow‐loadspringday.Thereisnodifferencebetweenthebase,lowandhighloadshapesonasummerday,andthereisaslightdifferencebetweentheloadshapesonasamplespringday.

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Figure3‐22:SampleDailyLoadShape,SummerDayinMidAmerican’sForecasts

Figure3‐23:SampleDailyLoadShape,SpringDayinMidAmerican’sForecasts

The annual load factors are shown in Figure 3‐24. As expected, the base, the high and the low case loadfactorsareconsistentbeingwithinthe52‐56%range.

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Figure3‐24:LoadFactorinMidAmerican’sForecasts

3.5 SourcesofUncertaintyintheLoadForecasts

Inthepast,theAgencyhasprocuredpowerfortheutilitiestomeetamonthlyforecastoftheaveragehourlyloadineachoftheon‐peakandoff‐peakperiods.TheAgencyhasaddressedthevolatilityinpowerpricesby“laddering”itspurchases:hedgingafractionoftheforecasttwoyearsahead,anotherfractiononeyearahead,andathirdfractionshortlybeforethebeginningofthedeliveryyear.Evenifpricingtwoyearsaheadwereextremelyadvantageous,theAgencydoesnotpurchaseitsentireforecastthatfaraheadbecausetheforecastisitselfuncertain.Itisthereforeimportanttounderstandthesourcesofuncertaintyintheforecasts.

Furthermore,eveniftheAgencycouldperfectlyforecasttheaveragehourlyloadineachperiod,andperfectlyhedgethatforecast,itwouldstillbeexposedtopowercostrisk.Loadvariesfromhourtohour.Energyinonehour isnotaperfect substitute forenergy inanotherhourbecause thehourly spotpricesdiffer.Aperfecthedgewouldcoverdifferingamountsofloadindifferenthours,andwouldhavetobebasedonaforecastofthe different hourly loads. The “expected hourly load” is not an accurate forecast of each hour’s load (seeSection3.5.3).This isnotan issueofuncertainty: itwouldbe trueeven if theexpectedhourly loadwereaperfectforecastoftheaverageload,andthehourlyprofile(theratioofeachhour’sloadtotheaverage)wereknownwithcertainty.Soitistreatedheretogetherwiththeotheruncertainties.

3.5.1 OverallLoadGrowth

AmerenIllinoisandComEd,constructtheirloadforecastsbyforecastingloadfortheirentiredeliveryservicearea, then forecasting the load for each customer class or rate classwithin the service territory, and thenapplying multipliers to eliminate load that has switched to municipal aggregation or other ARES service.Customer groups that have been declared competitive – medium and large commercial and industrialcustomers–areremovedentirely,astheutilitieshavenosupplyorplanningobligationforthem.Incontrast,MidAmerican,autilityservingamuchsmallernumberofelectriccustomersinIllinoisterritory,doesnothaveanycustomergroupsthathavebeendeclaredcompetitive.ThereisonlyoneentityprovidingARESserviceinthe MidAmerican Illinois service territory serving a relatively small segment of customers. Similar to theothertwoutilities,MidAmericanconstructsitsloadforecastbyusingatop‐downapproach.

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Ameren Illinois doesnot explicitly address uncertainty in load growth. In otherwords, theydonotdefine“loadgrowthscenarios”andexaminetheconsequencesofhighorlowloadgrowth.Theyaddressbothloadandweatheruncertaintybydefininghighandlowscenariosatparticularconfidencelevelsofthemodelfit,that is,oftheresidualsof theireconometricmodel.Thehighand lowcases,whichrepresentthecombinedandcorrelatedimpactofweatherandloadgrowthuncertainties,representavariationofonly±9%inserviceareaload.However,AmerenIllinois’highandlowcasesalsoincludeextremecustomermigrationuncertainty.

ComEddefineshighand lowloadgrowthscenariosas2%aboveorbelowthe loadgrowth intheirbaseorexpectedcase forecast.Thechanges in loadgrowthare imposedupon themodel rather thanderived fromeconomicscenariossoitishardtodeterminehowtheyrelatetoeconomicuncertainty.Giventhestabilityofutility loads in recent years, differences of ±2% in load growth should represent an appropriatelyrepresentativerangeofuncertainty.

Like Ameren Illinois, MidAmerican addresses the load andweather uncertainty by defining high and lowscenariosatparticularconfidencelevels,i.e.,byapplyingthe95%confidenceintervalaroundreferencesales,customer and use per customer forecast, and the non‐coincident gross peak demand forecast. The streetlightingsalesforecast,however,wasmultipliedby0.99and1.01togenerate,respectively,alowerandupperboundofstreetlightingsalesforecast,whichismoresimilartotheComEd’sapproach.

3.5.2 Weather

Onashort‐termbasis,weatherfluctuationsareakeydriveroftheuncertainty in loadforecasts,and inthedailyvariationof load forecastsaroundanaverage‐day forecast.Thediscussionofhighand lowscenarios,Sections 3.2.2, 3.3.2, and 3.4.2 notes the way that Ameren Illinois, ComEd, and MidAmerican haveincorporated weather variation into their high and low load forecasts. Ameren Illinois treats weatheruncertainty togetherwith load growth uncertainty. ComEd’s forecasts are built around two sample years.Muchoftheimpactofweatherisonloadvariabilitywithintheyear.MidAmerican’sreferencecaseweather‐relatedassumptionsarenotchangedforthehighandlowloadforecasts.Thereferencecaseloadforecastisbasedonthe“weathernormalized”historicalsales.

3.5.3 LoadProfiles

Asnotedabove,the“averagehour” loadforecast isnotanaccurateforecastofeachhour’s load.Withinthesixteen‐hourdailypeakperiod,mid‐afternoonhourswouldbeexpectedtohavehigher loadsthanaverage,andearlymorningoreveninghourswouldbeexpectedtohavelowerloads.Moreimportantly,multiplyingtheaveragehourlyloadbythecostofa“strip”contract(equaldeliveryineachhouroftheperiod)givesaninaccurate forecast of the cost of energy. This is because hourly energy prices are correlatedwith hourlyloads(energycostsmorewhendemandishigh).Technically,thisisreferredtoasa“biased”forecast,becausetheexpectedcostwillpredictablydifferfromtheproductofexpectedhourlyloadandexpectedhourlycost.

Figure3‐25illustratesthisdisconnectbyshowing,foreachmonth,theaveragehistorical“dailycoefficientofvariation” for peakperiod loads. This figure is basedon historical ComEd loads from2009 through2014,normalizedtothemonthlybasecaseforecastsinthefirstdeliveryyear.Tocalculatethedailycoefficientofvariation, the variancesof loadswithin eachday’speakperiod are averaged toproduce an expecteddailyvariance.Thatvarianceisthenscaledtoloadbyfirsttakingthesquarerootandthendividingbytheaveragepeak‐period hourly load forecasted for themonth. As the figure shows, there is significant load variationduringthedayinthehigh‐pricedsummermonths.


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Figure3‐25:CoefficientofVariationofDailyPeak‐PeriodLoads

Becauseofthisvariation,eveniftheaveragepeakandoff‐peakmonthlyloadisperfectlyhedged,theactualhourly loadwill still be imperfectly hedged. In otherwords, if the Agencywere to buy peak and off‐peakhedgeswhosevolumesequaledrespectivelytheaveragepeakperiodloadandaverageoff‐peakperiodload,therewouldstillbeunhedgedloadbecausetheactualloadisusuallygreaterorlessthantheaverage.ThisisillustratedinFigure3‐26,below.

Figure3‐26:ExampleofOver‐andUnder‐HedgingofHourlyLoad

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3.5.4 MunicipalAggregation

In theirbasecases,Ameren Illinoisprojects60.8%switchingbyeligibleretail customersby theendof the2016‐2017deliveryyearandComEdprojectsabout46.2%.Theselevelsrepresentadeclineintheswitchingstatistics assumed in the July 2014 forecasts and are informed by lower than forecasted actual switchingthroughApril 2015driven in part by communities deciding to suspend and/ornot renew theirmunicipalaggregationprogramsandreturntoutilityservice.Savingsopportunitiesthatexistedpriorto2014drovethegrowth in residential switching, but since 2014 these savings have been diminishing and in some caseseliminated.

Atthispoint,theuncertaintyaroundmunicipalaggregationandswitchingmaybemorerelatedtothechancethatutility loadwill increaseduetocustomersreturntodefaultservice.Toa lesserextentbutthesame istruewithregardstotheuncertaintyaroundtheextenttowhichasaggregationlevelsdeclineindividualretailswitchingmayormaynotincrease.

As shown in Figure 3‐27, approximately one quarter of the current supply contracts for municipalaggregationwillexpireinthe2015‐2016deliveryyear.However,asshowninFigure3‐27,themajorityofthesupplycontractsarescheduledtoexpirebytheendofthesummerperiodof2017.Itispossiblethatmanyoftherenewaloffersmadebythesuppliers tomunicipalaggregationsmaybehighrelative toutilitybundledsupplyprices, so theremaybe a considerable amount of return toutility service. This is especially true ifmarketpricesrisebetweennowandtheexpirationofmunicipalaggregationcontracts.On theotherhand,switchingcouldbehigherthanexpected,resultinginanover‐hedgedposition.Expandingonthehypothetical,assumingthattheutilities’hedgesareabovemarketprices,theremainingloadtakingbundledutilityservicewouldbe subject tohigherbundled rates.BothAmeren Illinois andComEdhaveassumedawide rangeofswitching fractions in their low and high scenarios (return to utility service would be represented as adecreaseintheswitchingfractionovertime).

Figure3‐27:DistributionofMunicipalAggregationContractExpirations(ComEd)

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3.5.5 IndividualSwitching

ARESofferavarietyofproductstocustomers–someofwhichhaveasimilarstructuretotheutilitybundledservice, and some vary significantly in structure. These include offers with pass‐through capacity prices,“green” energy above themandated RPS level,month tomonth variable pricing, longer‐term fixed prices,options to match prices in the future, options to extended contract terms, and options to adjust pricesretroactively.102Individualcustomerswhochooseoneoftheseotherratestructurespresumablyhavemadeanaffirmativechoicetotakeonthosealternativeservices.

AlthoughswitchingfromdefaultservicetoanARESbyindividualcustomershassomeimpact,AmerenIllinoisandComEdswitchingforecastshavebeendominatedbymunicipalaggregation.WhiletheIPArecognizesthatmany ARES focus on individual residential switching, the IPA is not aware of a significant number ofresidential customers leaving default service to take ARES service outside of a municipal aggregationprogram.AsshowninTable3‐2,thisiscurrentlythecasebecauseoftheappreciabledifferencethatcurrentlyexistsbetween theutilityprice to compare103and representativeARESprices104available to eligibleutilitycustomers.Itappearsthat,atthecurrenttime,ARESfixedpriceoffersforasimilartermtotheutilitypricedonotoffer savings or benefits to individual residential customers. It is reasonable to assume that switchingbehaviorbyindividualcustomers(otherthanthosewhochoseanARESratethatisnotan“applestoapples”comparisontotheutilityrate,oronethatoffersadditionalperceivedvalue)willnotbeasignificantfactorinthe load forecast, except for transition tomunicipal aggregation, opt‐out frommunicipal aggregation, andreturnfrommunicipalaggregation.

Table3‐2:RepresentativeARESFixedPriceOffers(Offerswithoutanexplicitpremiumrenewablecomponent)andUtilityPricetoCompare

UtilityTerritoryUtilityPriceto

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Price(¢/kWh)

AmerenIllinois(ZoneI) 5.97 7.12AmerenIllinois(ZoneII) 5.91 7.18AmerenIllinois(ZoneIII) 5.97 7.12ComEd 7.03 8.04

3.5.6 HourlyBilledCustomers

Customers who could have elected bundled utility service but take electric supply pursuant to an hourlypricing tariff arenot “eligible retail customers.”Therefore, thesehourly ratecustomersarenotpartof theutilities’supplyportfolioandtheIPAdoesnothavetoprocureenergyforthem.AmerenIllinoisandComEddid not include customers on hourly pricing in their load forecasts; they appropriately considered thesecustomers to have switched. The amount of load on hourly pricing is small and unlikely to undergo largechanges that would introduce significant uncertainty into the load forecasts. MidAmerican does not havehourlybilledcustomers.

3.5.7 EnergyEfficiency

PublicAct95‐0481alsocreatedarequirementforComEdandAmerenIllinoistooffercost‐effectiveenergyefficiency and demand response measures to all customers.105Both Ameren Illinois and ComEd haveincorporatedtheimpactsofthesestatutoryandspending‐cappedefficiencygoals,asappliedtoeligibleretailcustomers,aswellasachievedandprojectedsavingsintheforecaststhatareincludedwiththisProcurement

102FormoreinformationonchoicesofferedbyARES,seethe2015AnnualReportoftheICCOfficeofRetailMarketDevelopmentathttp://www.icc.illinois.gov/downloads/public/2015%20ORMD%20Section%2020‐110%20report.pdf.103July2015utilitycosttocomparefromhttp://www.pluginillinois.org/MunicipalAggregation.aspx.104RepresentativeARESpricesareanaverageof12‐monthfixedpriceoffersfromARESavailableathttp://www.pluginillinois.org/OffersBegin.aspxasofJuly23,2015.105SeeP.A.95‐0481(Sectionoriginallycodifiedas220ILCS5/12‐103).


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Plan.Section7.1ofthisplandiscussestheproposedincrementalenergyefficiencyprogramsthathavebeensubmittedpursuanttoSection16‐111.5B.Theseprogramsarereflectedintheloadforecasts.PursuanttoaseparateprovisioninthePublicUtilitiesAct,106MidAmericanalsohasenergyefficiencyprogramsoperatingin its Illinois service territory. MidAmerican expects that the projected energy efficiency program impactwouldbeconsistentwiththehistoricallevels;therefore,noadjustmentwasmadetotheforecastingmodels.

3.5.8 DemandResponse

Asnotedbytheutilitiesintheirloadforecastdocumentation,demandresponsedoesnotimpacttheweather‐normalizedloadforecasts.Assuch,theIPAnotesthattheyaremorelikesupplyresources.Section7.5ofthePlancontainstheIPA’sdiscussionandrecommendationsfordemandresponseresources.

3.5.9 EmergingTechnologies

The Agency’s 2015 AnnualReport:The Costs andBenefits ofRenewableResource Procurement included asectionontheimpactofenergystorageonrenewableresourceprocurement.107Recentannouncementssuchas Tesla’s Powerwall home energy storage system suggest that energy storage is now an emergingtechnology.However,itistooearlytoforecasttheimpactonloadforecasts,andtheAgencynotesthatthereare not clear provisions in Illinois law to encourage the adoption of these technologies. The Agency willcontinuemonitorthedevelopmentoftheenergystoragemarketinthecomingyears.

3.6 RecommendedLoadForecasts

3.6.1 BaseCases

The IPA recommends adoption of the Ameren Illinois, ComEd, andMidAmerican base case load forecasts.Ameren Illinois and ComEd forecasts include already approved energy efficiency programs, andMidAmerican’s forecast includes verified energy efficiency program impacts as well. The IPA alsorecommends that the Commission approve the additional incremental energy efficiency programs andmeasuresaspresentedinChapter7.TheMarch2016loadforecastsshouldalsoreflectthosenewlyapprovedprograms.

3.6.2 HighandLowExcursionCases

Thehighandlowcasesrepresentusefulexamplesofpotential loadvariability.Althoughtheyareprimarilydriven by variation in switching, Ameren Illinois correctly notes that this is the major uncertainty in itsoutlook.Theswitchingvariability,especiallyinAmerenIllinois’highandlowforecasts,isextremeandthusthesemaybecharacterizedas “stresscases.”TheAgency’sprocurementstrategy todatehasbeenbuiltonhedging theaveragehourly load ineachof thepeakandoff‐peaksub‐periods,andthehighand loadcasesrepresentsignificantvariationinthoseaverages.

AsillustratedinFigure3‐28,theAmerenIllinoislowandhighloadforecastsareonaverageequalto68%and176% of the base case forecast, respectively, during the 2016‐2017 delivery year. Comparatively, for thesame period, ComEd’s low and high load forecasts are on average equal to 91% and 111% of the baseforecast, respectively. This reflects the differences in switching assumptions used by the two utilities.MidAmerican’slowandhighloadforecastdeviationsfromthebasecaseareflatandsymmetricalbeingequalto86%and114%,respectively.SwitchingassumptionsplaynoexplicitroleintheMidAmericanhighandlowload forecasts. Instead, theMidAmericanhighand lowload forecastsareaproductofapuremathematicalconstruct.

106See220ILCS5/8‐408.107Thatreportcanbefoundhere:http://www.illinois.gov/ipa/Documents/IPA‐2015‐Cost‐Benefits‐Renewables‐Report‐4‐1‐15.pdf


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Figure3‐28:ComparisonofAmerenIllinois’,ComEd’s,andMidAmerican’sHighandLowForecastsforDeliveryYear2016‐2017

Anotheruseofthehighandlowcaseswillbetoestimatetherisksofdifferentsupplystrategies.Akeydriverof that risk is the cost of meeting unhedged load on the spot market. One of the main reasons load isunhedgedisthatoneattemptstohedgeavariable,orshaped,loadwithaproductwhosedeliveryisconstant.Thespotpriceatwhichtheunhedgedvolumesarecoveredispositivelycorrelatedwithload.Thehighandlowcasesarelesssuitableforsuchariskanalysis.

TherelativelyhighloadfactoroftheComEdbasecaseforecastimpliesthatthehourlyprofileofthatcaseisnot representative of a typical year. This means that the base case hourly forecast would understate theamountbywhichhourlyloadsvaryfromtheaveragehourlyloadsinthepeakandoff‐peaksub‐periods.Usingthathourlyprofileforariskanalysiscouldleadtounderestimatingthecostofunhedgedsupply.

The Ameren Illinois and MidAmerican load scenarios have identical monthly load shapes (differing byuniform scaling factors). These shapes will not provide much information about the cost of meetingfluctuatingloads,exceptfortheinformationcontainedintheexpectedloadshape.TheexpectedloadshapemayhaveanoverstatedloadfactorlikethatofComEd,andnootherforecastcaseisavailableforcomparison.

The extreme nature of the Ameren Illinois low and high load forecasts can influence the results of aprobabilistic risk analysis. With almost any assignment of weights to the Ameren Illinois cases, loaduncertaintywilldominatepriceuncertainty.ThisdoesnotapplytoComEdandMidAmerican,whichmustbetakenintoaccountwhenevaluatinganysimulationofprocurementrisk.

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4 ExistingResourcePortfolioandSupplyGap

Startingwiththe2014ProcurementPlan,theIPAhaspurchasedenergysupplyinstandard25MWon‐peak,andoff‐peakblocks.Theenergyblocksizewasreducedfrom50MWpriortothe2014Planinordertomoreaccuratelymatchsupplywith load.108ThehistoryoftheIPAadministeredprocurements isavailableontheIPA website.109The 2016 Procurement Plan includes procurement of energy supply to meet the needs ofMidAmerican’seligiblecustomersaswellasthoseofComEdandAmerenIllinois.Thesepurchasesaredrivenby the supply requirements outlined in the current year procurement plan and are executed through acompetitive procurement process by the IPA’s Procurement Administrator. This procurement process ismonitoredfortheCommissionbytheindependentProcurementMonitor.

Inadditiontopurchasingenergyblockcontractsintheforwardmarkets,AmerenIllinois,MidAmerican,andComEdrelyontheoperationoftheirRTOs(MISOandPJM)tobalancetheirloadsandconsequentlymayincuradditionalcostsorcredits.Purchasedenergyblocksmaynotperfectlycovertheload,thereforetriggeringtheneed for spot energypurchasesor sales fromor to theRTO.The IPA’s procurementplans are basedonasupplystrategydesigned,amongotherthings,tobalancepriceriskandcost.Theunderlyingprincipleofthissupplystrategyistoprocureenergyproductsthatwillcoverallormostofthenear‐termloadrequirementsandthengraduallydecreasetheamountofenergypurchasedrelativetoloadforthefollowingyears.

The current IPA procurement strategy involves procurement of hedges to meet a portion of the hedgingrequirementsovera threeyearperiodand includes twoprocurementevents inwhich the JulyandAugustpeak requirements will be hedged at 106%, while the remaining peak and off‐peak requirements will behedgedat100%.Inthespringprocurementevent,106%oftheJulyandAugustexpectedpeak,100%oftheJuly and August off‐peak, 100% of the June and September peak and off‐peak, and 75% of the Octoberthrough May peak and off‐peak requirements for the 2016‐2017 delivery year will be targeted forprocurement.Thefallprocurementeventwillbringthetargetedhedgelevelsto100%forOctoberthroughMayofthe2016‐2017deliveryyear.Aportionofthetargetedhedgelevelsforthe2017‐2018andthe2018‐2019deliveryyearsof50%and25%,respectively,willbeacquiredspreadonanequalbasisinthespringandfallprocurementevents.

Becauseof theuncertainty in the amountof eligible retail load in future years, the IPAhasnotpurchasedenergybeyonda3‐yearhorizon,exceptinafewcircumstances.Theseinclude:

A 20‐year bundled REC and energy purchase (also known as the long‐term power purchaseagreementsor“LTPPAs”),starting in June2012,madebyAmeren IllinoisandComEd inDecember2010pursuanttotheFinalOrderinDocketNo.09‐0373.

TheFebruary2012“RateStability”procurementsmandatedbyPublicAct97‐0616forblockenergyproductscoveringtheperiodJune2013throughDecember2017.110

Duetotheforecastedreturnofsomeloadtotheutilities,curtailmentoftheLTPPAsishighlyunlikelyforthe2016‐2017deliveryyear forComEdandAmeren Illinois.MidAmerican isnotcoveredbyeitherLTPPAsorRateStabilityprocurements.

Twenty‐yearpowerpurchaseagreementsbetweenAmerenIllinoisandComEdandtheFutureGenIndustrialAlliance, Inc., although not procured by the IPA, were directed by the Commission order approving the

108IPA2014ProcurementPlanat93.109http://www2.illinois.gov/ipa/Pages/Prior_Approved_Plans.aspx.110P.A.97‐0616alsomandatedassociatedRECprocurements,buttheseRECprocurementsdonotimpactthe(energy)resourceportfolio.


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Agency’s 2013 Procurement Plan.111In February 2015, DOE funding support for Future Gen 2.0 wassuspended,potentiallyeliminatingtheprojectasasourceofsupply.

Thediscussionbelowexplores inmoredetail the supply gapbetween theupdatedutility loadprojectionsdescribedinChapter3andthesupplyalreadyundercontractfortheplanninghorizon.TheIPA’sapproachtoaddressingthesegapsisdescribedinChapter7.

4.1 AmerenIllinoisResourcePortfolio

Figure4‐1showsthecurrentsupplygapintheAmerenIllinoissupplyportfolioforthefive‐year,June2016throughMay2021,planningperiod,usingtheexpectedon‐peakforecastdescribedinChapter3.

AmerenIllinois’existingsupplyportfolio,includinglong‐termrenewableresourcecontracts,isnotsufficienttocovertheprojectedloadforthe2016‐2017deliveryyear.Additionalenergysupplywillberequiredfortheentire 5‐year planning period. Approximately 58%of the Ameren Illinois residential load has switched toARESsuppliers.TheAmerenIllinoisexpectedscenarioloadforecastassumesthatswitchingwillbeflatacrossthecurrentplanninghorizon.

QuantitiesshownareaveragepeakperiodMWforbothloadsandhistoricpurchases.

Figure4‐1:AmerenIllinois'On‐PeakSupplyGap‐June2016‐May2021Period‐ExpectedLoadForecast

Undertheexpectedloadforecastscenario,theaveragesupplygapforpeakhoursofthe2016‐2017deliveryyear is estimated to be 456MW, the peak period average supply gap for the 2017‐2018 delivery year isestimated to be 686 MW, and the average peak period supply gap for the 2018‐2019 delivery year isestimated tobe857MW.While theplanningperiod is five‐years, the IPA’shedging strategy is focusedonprocuringelectricitysuppliesfortheimmediatethreedeliveryyears.

111DocketNo.12‐0544,FinalOrderdatedDecember19,2012at228‐237;seealsoDocketNo.13‐0034,FinalOrderdatedJune26,2013(“PhaseII”approvingsourcingagreementasrequiredinDocketNo.12‐0544).

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4.2 ComEdResourcePortfolio

Figure4‐2showsthecurrentgapintheComEdsupplyportfoliofortheJune2016‐May2021planningperiod,usingtheexpectedloadon‐peakforecastdescribedinChapter3.

ComEd’scurrentenergyresourceswillnotcoverloadstartinginJune2016.Theaveragesupplygapduringpeakhoursforthe2016‐2017deliveryyearundertheexpectedloadforecastisestimatedtobe1,350MW.Theaveragesupplygapduringpeakhoursforthe2017‐2018and2018‐2019deliveryyearsareestimatedtobe2,189MWand2,789MWrespectively.

Figure4‐2:ComEd'sOn‐PeakSupplyGap‐June2016‐May2021period‐ExpectedLoadForecast

4.3 MidAmericanResourcePortfolio

Figure 4‐3 shows the current supply gap in the MidAmerican supply portfolio for the five‐year planningperiod, using MidAmerican’s expected on‐peak load forecast. MidAmerican has requested that the IPAprocureelectricityfortheincrementalloadthatisnotforecastedtobesuppliedinIllinoisbyMidAmerican’sIllinois jurisdictional generation. MidAmerican’s existing eligible load is served by a 10.86% allocation ofcapacityfromMidAmerican’shistoricalIllinoisresources.Theaveragesupplygapduringpeakhoursforthe2016‐2017deliveryyearundertheexpectedloadforecastisestimatedtobe41MW.Theaveragesupplygapduringpeakhoursforthe2017‐2018deliveryyearis43MWandforthe2018‐2019deliveryyearthesupplygapis49MW.

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Figure4‐3:MidAmerican’sOn‐PeakSupplyGap‐June2016‐May2021period‐ExpectedLoadForecast

4.4 AllocationofSupplyVolumesAssociatedwithAmerenIllinoisandComEdLTPPAs

The IPA’s approved 2012 Procurement Plan prescribed for each utility an averagemonthly peak and off‐allocationoftheLTPPAs’annualcontractenergyvolume.TheIPA’sprescribedallocationcoveredtheperiodof June2012 throughMay2015. In2016ProcurementPlan,again forprocurementplanningpurposes, theIPAproposesanextensionofthemonthlyallocationthroughMay2032.Forillustrationpurposes,Table4‐1andTable4‐2showtheproposedallocationforthe2015‐2016PlanningYearforAmerenIllinoisandComEdrespectively.AppendicesEandFshowtheentireproposedallocations.Themethodologyforestablishingtheproposedallocationsisthesamethatwasusedinthe2012ProcurementPlan.

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Table4‐1:AmerenIllinoisLTPPAsMonthlyPeakandOff‐PeakAllocations(June2015throughMay2016)

Month

MonthlyPeakHours

PeakRenewableEnergyVolumes(MWh)

AverageMonthlyPeakLoad(MW)

MonthlyOffPeakHours

OffPeakRenewableEnergyVolumes(MWh)

AverageMonthlyOffPeakLoad(MW)

June‐16 352 15,084 43 368 19,369 53

July‐16 320 9,802 31 424 15,538 37

August‐16 368 10,605 29 376 19,550 52

September‐16 336 13,957 42 384 19,209 50

October‐16 336 26,207 78 408 32,150 79

November‐16 336 28,412 85 384 37,229 97

December‐16 336 24,720 74 408 28,286 69

January‐17 336 27,529 82 408 33,620 82

February‐17 320 23,116 72 352 27,944 79

March‐17 368 27,862 76 376 37,611 100

April‐17 320 31,530 99 400 35,950 90

May‐17 352 23,352 66 392 31,368 80

Table4‐2:ComEdLTPPAsMonthlyPeakandOff‐PeakAllocations(June2015throughMay2016)

Month

MonthlyPeakHours

PeakRenewableEnergyVolumes(MWh)

AverageMonthlyPeakLoad(MW)

MonthlyOffPeakHours

OffPeakRenewableEnergyVolumes(MWh)

AverageMonthlyOffPeakLoad(MW)

June‐16 352 31,720 90 368 40,731 111

July‐16 320 20,613 64 424 32,675 77

August‐16 368 22,301 61 376 41,112 109

September‐16 336 29,350 87 384 40,394 105

October‐16 336 55,110 164 408 67,607 166

November‐16 336 59,747 178 384 78,287 204

December‐16 336 51,982 155 408 59,481 146

January‐17 336 57,891 172 408 70,699 173

February‐17 320 48,610 152 352 58,762 167

March‐17 368 58,588 159 376 79,093 210

April‐17 320 66,303 207 400 75,599 189

May‐17 352 49,107 140 392 65,962 168


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5 MISOandPJMResourceAdequacyOutlookandUncertainty

As a result of retail choice in Illinois, resource adequacy (the load/resource balance) can be viewed as afunctionofdeterminingwhatlevelofresourcestopurchasefromwhichmarketsovertime.However,fortheIllinois market to function properly, the RTOmarkets and operations (e.g., MISO and PJM)must providesufficientresourcestosatisfytheloadofallcustomersreliably.ThisSectionreviewsthelikelyload/resourceoutcomes over the planning horizon to determine if the current system is likely to provide the necessaryresourcessuchthatcustomerswillbeservedwithreliablepower.

In reviewing the load/resource outcomes over the planning horizon, this Section analyzes several outsidestudiesofresourceadequacythatarepubliclyavailablefromdifferentplanningandreliabilityentities.Theseinclude:

North American Electric Reliability Corporation (“NERC”), the entity certified by the FederalEnergy Regulatory Commission to establish and enforce reliability standardswith the goal ofensuringthereliabilityoftheAmericanbulkpowersystem.

MidcontinentISO(“MISO”),whichoperatesthetransmissiongridinmostofcentralandsouthernIllinois.

PJMInterconnection(“PJM”),whichoperatesthetransmissiongridinNorthernIllinois.

Fromreviewoftheseentities’mostrecentdocumentation,itisapparentthatovertheplanninghorizonPJMwillmaintainadequateresources tomeet thecollectiveneedsofcustomers in thoseregions.MISOmaybeshortresourcesstartinginthe2016‐2017timeframe.

5.1 ResourceAdequacyProjections

In PJM, capacity is largely procured through PJM’s capacitymarket, the Reliability PricingModel (“RPM”),which was approved by FERC in December 2006.112RPM is a forward capacity auction through whichgeneratorsoffercapacitytoservetheobligationsofload‐servingentities.Theprimarycapacityauctions,BaseResidual Auctions (“BRAs”), are held each May, three years prior to the commitment period.113ThecommitmentperiodisalsoreferredtoasaDeliveryYear.114InadditiontotheBRAs,uptothreeincrementalauctionsareheld,atintervals20,10,and3monthspriortotheDeliveryYear.The1st,2nd,and3rdIncrementalAuctionsareconductedtoallowforreplacementresourceprocurement,increasesanddecreasesinresourcecommitmentsduetoreliabilityrequirementadjustments,anddeferredshort‐termresourceprocurement.AConditional Incremental Auction may be conducted, if and when necessary, to secure commitments ofadditionalcapacitytoaddressreliabilitycriteriaviolationsarisingfromthedelayofaBackboneTransmissionupgradethatwasmodeledintheBRAforsuchDeliveryYear.

JustpriortothebeginningofeachDeliveryYear,theFinalZonalNetLoadPrice,whichisthepricepaidbyLoad Serving Entities (“LSEs”) for capacity procured as part of RPM in PJM, is calculated. This price isdeterminedbasedontheresultsoftheBRAandsubsequentincrementalauctionsforagivenDeliveryYear.AstheprocurementofthemajorityofthecapacityviatheRPMisdoneduringtheBRA,thereislittlevariation

112OnJune9,2015FERCacceptedPJM’sproposaltoestablishanewcapacityproduct,aCapacityPerformanceResource,onaphased‐inbasis,toensurethatPJM’scapacitymarketprovidesadequateincentivesforresourceperformanceduringemergencyconditions(“theCapacityPerformanceFiling”). Resourcesthatarecommittedascapacityperformanceresourceswillbepaidincentivestoensurethattheydeliver thepromisedenergyandreserveswhencalledupon inemergencies. CapacityPerformancewillbe implemented for the2018‐2019deliveryyear,witha transitionmechanism for the2016‐2017and2017‐2018deliveryyears thatwill facilitate improvedresourceperformanceduringthoseyearsbyallowingaportionofcapacitytoberebidinanewprocurement.Thecapacityperformanceincentiveswillmostlikelyresultinincreasesinthecapacityprices.113NotethattheBRAforthe2018‐2019deliveryyearwasdelayedfromMay,2015toAugust,2015.114ADeliveryYearisJune1throughMay31ofthefollowingyear.


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between the BRA clearing price and the Final ZonalNet LoadPrice as shown in Figure 5‐1. However, theresultsof the incrementalCapacityPerformanceauctionsexpectedout in lateAugustandearlySeptembermaysignificantlychangethenetpriceofcapacityforthe2016‐2017and2017‐2018deliveryyears.

Figure5‐1:PJMRPMCapacityPriceforDeliveryYears2012‐2017115

As shown in Figure 5‐2, PJM is projected to have sufficient resources tomeet load plus required reservemargins for theDeliveryYears2015‐2020,withprojectedreservemarginsabovethe15.7%targetreservemargin.Forthe2015‐2016DeliveryYear,thereservemarginisapproximately10%abovethetargetreservemargin,droppingtoapproximately3%abovethetargetreservemarginforthe2020‐2021DeliveryYear.

Figure5‐2:PJMNERCProjectedCapacitySupplyandDemandforDeliveryYears2015‐2020

Source:NERC2014LongTermReliabilityAssessment(“NERC2014LTRA”)116

1152015‐2016isthelatestDeliveryYearforwhichtheFinalZonalNetLoadPricehasbeencalculated.ItwillbecalculatedforfutureDeliveryYearsasthestartoftheyearapproaches.The2018‐2019PJMBRAwaspostponedduetothedelayedFERCdecisiononPJM’sCapacityPerformanceFiling.OnJune9,2015FERCissuedanOrderaccepting,subjecttocompliancefiling,PJM’sCapacityPerformanceFiling.PJMsubmittedthecompliancefilingonJuly9,2015.TheBRAresultsarenowexpectedtobepostedonAugust21,2015.


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MISO’sResourceAdequacyconstruct,specifiedinModuleE‐1ofitsTariff,117containstheResourceAdequacyRequirements(“RAR”)thatrequireLSEsintheMISOregiontoprocuresufficientPlanningResourcestomeettheiranticipatedpeakdemand,plusaplanningreservemargin(“PRM”)118forthePlanningYear.119AnLSE’stotalresourceadequacyobligationisreferredtoasthePlanningReserveMarginRequirement(“PRMR”).OnJune11,2012theFederalEnergyRegulatoryCommission(“FERC”)conditionallyapprovedMISO’sproposalto enhance its RAR by establishing an annual construct based uponmeeting reliability requirements on alocationalbasis, including theuseofanannualPlanningResourceAuction (“PRA”).MISO implemented theModuleE‐1RAR,whichbecamefullyeffectiveonJune1,2013.MoredetailsonthelocationalconstructoftheMISORARandMISO’sthirdPRAareprovidedinSection5.2.

AsshowninFigure5‐3,basedupontheNERC2014LTRA,onaregion‐widebasisMISOisexpectedtohavesufficient resources to meet load plus required reserve margin for the 2015‐2016 Planning Year with areservemargin slightly above17%which is approximately 2%above the reservemargin target of 14.8%.However,startingwiththe2016‐2017PlanningYearthroughthe2020‐2021PlanningYearMISOisprojectedto have insufficient resources to meet load plus required reserve margin. The 2016/17 shortfall isapproximately2%and increases toapproximately5% in2020‐2021.As also shown inFigure5‐3,NERC’sanalysismirrorsMISO’s analysis presented in the 2014MISO Transmission Expansion Planning (“MTEP”)report,whichaddressesresourceadequacy.TheMISOreservemarginestimatesareslightlyhigherthantheNERCestimates.IntheresourceadequacySectionofthe2014MISOMTEP,MISOexplainsthedifferenceasfollows: “Whencomparing reservemarginsbetweenTable6.2‐1and theNERCLTRA, thepercent for eachplanningyearwillbeslightlylowerintheNERCLTRAbecauseofthedifferencesinhowthereservemarginpercent is calculated. MISOs Resource Adequacy construct counts DR as a resource while the NERCcalculationhastheDRcalculatedonthedemandside.Whilethepercentwillbeslightlydifferent,theabsoluteGWshortfall/surplusisthesamebetweenthetwo.”

BothNERCandMISOexplainthedropinreservemarginbeginningin2016insimilarterms.Inthisregardtheprimarycontributingfactorsdrivingtheprojectedshortfallare:

IncreasedretirementsandsuspensionsduetoEnvironmentalProtectionAgency(“EPA”)regulationsandmarketforces(i.e.lownaturalgasprices);

ExclusionoflowcertaintyresourcesthatwereidentifiedintheResourceAdequacysurvey;120 IncreasedexportstoPJMandtheremovalofnon‐Firmimports;121 ExclusionofsurpluscapacityinMISOSouthabovethe1,000MWtransferlimit;122 Notenoughcertaintyofresourcesplanned;91percentoftheloadintheMISOfootprintisservedby

utilitieswithanobligationtoservecustomersreliablyandatareasonablecost.ResourceplanningandinvestmentinresourcesarepartofstateandlocallyjurisdictionalintegratedresourceplansthatonlybecomecertainuponthereceiptofaCertificateofPublicConvenienceandNeed(“CPCN”).

116PriorProcurementPlanshavereliedonthedatafromtheElectricitySupply&DemandDatabase(“ESD”).IndiscussionswithaNERCrepresentativeregardingdatafromtheESD,therepresentativerecommendedusingdatafromtherecentlypublishedNERC2014LTRAwhichprovidesthepertinentdataonPeakDemand,ReserveMarginandReserveMarginTarget.117UndertheMISOTariffModuleE‐2outlinestheRARcomplianceobligationsforanewLSEduringatransitionalperioduntilthenewLSE’sassetscanbeincludedinthefullannualRARprocessinaccordancewithModuleE‐1.118ThePRM(ortargetreservemargin)isdeterminedbyMISO,basedonaLossofLoadExpectation(“LOLE”)ofonedayintenyears,orstate‐specificstandards.IfastateregulatorybodyestablishesaminimumPRMfortheLSEsundertheirjurisdiction,thenthatstate‐setPRMwouldbeadoptedbyMISOforjurisdictionalLSEsinsuchstate.119APlanningYearisJune1throughMay31ofthefollowingyear.120TheResourceAdequacysurveyofLSEswasconductedbyMISOandtheOrganizationofMISOStates(“OMS”)withthegoalofprovidinganupdatedviewintothelong‐termresourcesituation.Resourcesthatwereidentifiedtohavealowcertaintyofservingloadwerenotincludedintheassessment.121Capacitysales(importsandexports)inMISOdependonthedecisionsoftherespectiveresourceowners,assumingthatthetariffrequirementsaremet.Regardingtheremovalofnon‐Firmimports,theMISOmarketmonitornotesthatMISOwasdouble‐countingnon‐firmimportsbecausethePRMRalreadyincludestheuseofnon‐firmimports.122Forthisassessment1,000MWofcapacityistransferredfromtheMISOSouthtotheMISONorth/CentralRegionpendingtheoutcomeoftheregulatoryissuescurrentlyunderFERCreview.


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In light of the projected reserve margin deterioration, MISO is studying ways to better utilize existingtransmissionandgenerationtohelpalleviatetheexpectednear‐termshortages.OnestrategytoalleviatethepotentialcapacityshortfallsistoconvertgenerationcapacitythatiscurrentlyineligibletoqualifyasPlanningResourcesintheannualPRA.Inthisregard,MISOisconductingtheUnusedGenerationCapacityStudythatseeks to identify and inform Market Participants of potential opportunities to participate in the capacitymarket by connecting to the grid as Network Resources. Preliminary results from the study indicate thatapproximately 806 to 938 MW of generation have the potential to become Network Resources with norequired network upgrades after progressing through the MISO Generation Interconnection Process. Anadditional273to404MWwillrequirenetworkupgradestounlocktheconstrainedunusedgeneration.Withthe completion of the study, projects will be identified that would allow resources to qualify as PlanningResources,eligible forparticipation inthePRA.Similarly,MISOhasundertakentheSouthtoNorth/CentralCapacityTransferAnalysis,whichexploreswaysto improvethetransfercapacitybetweentheregions.Thetransfer analysis identified the full capability of the transmission system to be in the3 to 4GW range; anincreaseof2 to3GWfromthe levelof capacity thatwascounted fromMISOSouth in the2014‐2015and2015‐2016 PRAs.123As noted earlier the current assessment assumes a maximum of 1,000 MW of MISORegioncapacity isavailable toMISONorth/CentralRegion.TheUnusedGenerationCapacityStudyandtheSouth to North/Central Capacity Transfer Analysis help to inform areas where additional capacity couldpotentiallyclearandhelpmitigatepotentialResourceAdequacyshortfalls.

TheNERCanalysisnotesthatalthoughthereservemarginisprojectedtofallbelowthereservemargintargetin 2016, MISO fully expects that the shortfall will change significantly once LSEs and state commissionswithinthefootprintsolidifyfuturecapacityplans.Inthisregard,inthe2014MTEPreport,MISOstatesthat“By Planning Year 2016‐17MISOprojects that its regionwill operate at an approximately two‐days‐in‐10reliabilitylevelunlessanduntilLoadServingEntitiesandStatecommissionssolidifyfuturecapacityplans.”AssuchtheMISOcapacityprojectionmayneedtobeupdatedwhenmorereliabledataisavailable.

Figure5‐3:MISONERCProjectedCapacitySupplyandDemandforthePlanningYears2015‐2020

Source:NERC2014LongTermReliabilityAssessment,MISO2014MTEPBook2ResourceAdequacy

123OnMarch28,2014,FERCacceptedforfiling,andsuspendedforanominalperiodtobeeffectiveJanuary29,2014,subjecttorefundandhearingandsettlementjudgeprocedures,aTransmissionServiceAgreementfiledbySouthwestPowerPool(“SPP”),requiringMISOtopaySPPforanyflowonSPP’stransmissionsystemabovetheexisting1,000MWcontractpathbetweenMISONorth/CentralandMISOSouth.ThiscontractpathlimitationiscurrentlybeinglitigatedbeforeFERC.


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5.2 LocationalResourceAdequacyNeeds

Akeycomponentof theModuleE‐1RAR is theestablishmentofLocalResourceZones (“LRZs”).TheMISOregion currently has 9 LRZs. Local ReliabilityRequirements (“LRRs”) are set for each LRZ to establish theminimum amount of Planning Resources needed to maintain MISO’s LOLE within each LRZ, withoutconsideration of Planning Resources outside of the LRZ that could be accessed through transmission ties.MISOalsoestablishesaLocalClearingRequirement(“LCR”)foreachLRZ,whichistheminimumamountofPlanning Resources required to be sourcedwithin the LRZwhile fully utilizing the Capacity Import Limit(“CIL”)fortheLRZ.CapacityExportLimits(“CEL”)arealsoestablishedforeachLRZ.AmarketparticipantcanqualifyaPlanningResource,andconverttheUnforcedCapacityofthePlanningResourceintoZonalResourceCredits(“ZRCs”).ZRCsareMWunitsofPlanningResourcesthathavebeenconvertedintoacreditthatcanbeusedtomeetPRMRdirectlythroughoffersorself‐schedulesinthePRA,orcommitmentsinaFixedResourceAdequacy Plan (“FRAP”). Market participants can also buy and sell ZRCs through bilateral arrangements.MISOwillimposeaCapacityDeficiencyCharge(“CDC”)124onanLSEthathasnotdemonstratedatthecloseofthePRA,thatithassufficientcapacityresourcestomeetitsPRMR.MISOheldthethirdPRAinApril2015.

TheRTO‐basedreliabilityassessmentsexaminedinthepreviousSectionareimportantmeasuresofresourcereliabilityinIllinoisbecausetheIllinoiselectricgridoperateswithinthecontrolofthesetwoRTOs.WhiletheIPAconcludesthatitdoesnotneedtoincludeanyextraordinarymeasuresinthe2016ProcurementPlantoassurereliabilityover theplanninghorizon, the IPAacknowledges theresultsof the2015‐2016MISOPRAwhich cleared substantially higher for the IllinoisRegion (Zone4) than in prior years.Adiscussionof theresultsfollows.

Inthe2014‐2015PRA,Zone1clearedat$3.29/MW‐Day,Zones2‐7clearedat$16.75/MW‐Day,andZones8‐9clearedat$16.44/MW‐Day.125Inthe2015‐2016PRA,Zones1,2,3,5,6,and7allclearedat$3.48/MW‐Dayand Zones 8‐9 cleared at $3‐29/MW‐Day. Zone 4 (IL) on the other hand cleared substantially higher at$150/MW‐Day.126AsshowninFigure5‐4theZone4priceis9timesgreaterthanthepreviousPlanningYear,andmorethan40timesgreaterthantheotherzones,whichhasraisedquestionsfromconsumeradvocates,theIllinoisAttorneyGeneral,and industrialcustomers. In itseffortstobetterunderstandtheresultsofthe2015‐2016PRA,inparticularastheyrelatetoZone4,theIPAreviewedpresentationsandstatementsmadebyMISOandMISO’sIndependentMarketMonitor(“MISOIMM”)ontheauction.

InapresentationthatwasmadetotheMISO’sSupplyAdequacyWorkingGroup(“SAWG”),127MISOnotedthatthe 2015‐2016 PRA results indicate adequate resources in the region for the Planning Year.MISO furtherexplained thatZone4clearedatahigherpricebecauseofhigher incremental costof capacity in the zone,notingthattomeetthelocalresourcerequirementinthezone,128thishigherpricedcapacitywasneededandthereforesetthepriceforthezone.Intheirpresentation,MISOalsonotedthattheMISOIMMreviewedtheauctionresultsforphysicalandeconomicwithholdingandconcludedthatthesubmittedoffersrepresentedacompetitivemarketoutcome.

InresponsetoquestionsraisedbytheIllinoisAttorneyGeneral,129MISOnotedthat:

124ThevalueoftheCDCiscurrentlysetat2.748*CostofNewEntry(“CONE”).125TheMISOLRZsencompassthefollowingstates:Zone1(MN,ND,WesternWI),Zone2(EasternWI,UpperMI),Zone3(IA),Zone4(IL),Zone5(MO),Zone6(IN,KY),Zone7(MI),Zone8(AR),Zone9(LA,MS,TX).In2013MISOintegratedEntergyintoMISOcreatingtheMISOSouthRegion(Zones8‐9).126MISOalsocalculatedtheZonalDeliverabilityBenefit(“ZDB”).ZDBsoccurwhenconstraintscausepriceseparationresultinginover‐collectionofauctionrevenuesinimportingzonesorgroupsofzones.PertheMISOTariff,theZDBfor2015‐2016willbeacreditof$23.47/MW‐DaytoloadinZone4.127Thepresentationcanbefoundat:https://www.misoenergy.org/Library/Repository/Meeting%20Material/Stakeholder/SAWG/2015/20150430/20150430%20SAWG%20Item%2002%20ab%202015‐16%20PRA%20Summary.pdf.128ThezonalcapacityrequirementmustbemetwithResourceslocatedwithinthezone.129Theresponsecanbefoundat:http://www.rtoinsider.com/wp‐content/uploads/MISO‐response‐to‐IL‐OAG‐4‐24‐15.pdf


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(i) IncrementalchangeswhichhadbeenmadetotheTariffeffective for the2015‐2016PlanningYeareitherdidnot impactZone4,orthey impactedZone4nomoreor less thanotherLRZswithin theMISOregion.

(ii) TherewerenospecificdesignorPRArulechangesthatspecificallyaddressedconditionsuniquetoZone4.

(iii) WhileZone4wasabletoimport1,568MW130oflowercostcapacityfromotherzones,thebalanceofthecapacityforthezoneneededtocomefromresourcesinternaltoZone4(theLCR).

(iv) Theruleswerefollowedinthe2015‐2016PRA.InZone4,higherpricedlocalresourceswereneededtomeettheLCR.Additionally,morecapacitywasprocuredthroughthe2015/16PRAratherthanbydirect contracts betweenparties as compared to theprevious year, resulting inmore exposure topricesensitivecapacityoffersinthe2015‐2016PRA.

(v) Somedifferences in offers and bidding strategies occurred in the 2015‐2016PRA as compared topreviousyears.TheMISO IMMreviewed theoffersanddetermined that the final resultswerenotimpactedbyphysicaloreconomicwithholdingorotherconductprohibitedbytheMISO’sTariff.

Figure5‐4:MISOPRAResultsforPlanningYears2014‐2015and2015‐2016

InapresentationthatwasmadetotheMISO’sSAWG,131theMISOIMMnotedthat:

(i) The2015‐2016PRAwasconductedandclearedinaccordancewiththeTariff.(ii) Nomarketpowermitigationwaswarranted.(iii) TherewerenoconductfailuresforeconomicwithholdinginZone4basedontheReferenceLevel.132

a. TheReferenceLevelmustreflectsuppliers’competitiveoptions,includingretiring/mothballingandexportingcapacitytoneighboringregions.

i. Theopportunitytoretireisbasedonasupplier’s“goingforwardcosts”.ii. Theopportunitytoexportisbasedonpricesinneighboringmarkets.

b. ThebestopportunityforexportingcapacityisthePJMmarket.c. TheInitialReferenceLevelforZonalResourceOfferswas$155.79/MW‐Day.

130MISO’spresentationofthe2015‐2016PRAexplainingtheZRCclearingshowsthat568MWwereimportedfromZones1‐3&5‐7(netZRCsurplus)andtheremaining1,000MWwasimportedfromZones8&9(MISOSouth).131Thepresentationcanbefoundat:https://www.misoenergy.org/Library/Repository/Meeting%20Material/Stakeholder/SAWG/2015/20150430/20150430%20SAWG%20Item%2002c%20IMM%20on%202015‐16%20PRA%20Results.pdf.132ReferenceLevelsserveasBenchmarksusedinperformingConductTests.


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i. ThisiscalculatedasthePJMpenaltyprice(basedonclearingpricesinPJM)minusthetransmissionexpensestodelivertoPJM.

d. ThelatestmarketdataintheIMM’spossessionpriortothePRAvalidatedtheReferenceLevel.i. The PJM RPM 3rd Incremental Auction cleared almost exactly at the penalty price

calculatedbytheIMM($163.20vs.$163.41)/MW‐Dayii. Subtracting $7.63/MW‐Day in transmission costs yields $155.57/MW‐Day, nearly

matchingtheIMM’sInitialReferenceLevel.e. If the IMM does not find bilateral data and uses the samemethodology next year, the Initial

ReferenceLevelwillberoughly$71/MW‐Day.

The IPAalsonotes that four complaintshavebeen filedatFERCagainstMISO regarding the resultsof the2015‐2016MISOPRAinZone4.ThecomplaintswerefiledbytheIllinoisAttorneyGeneral(“ILAG”)133,PublicCitizen, Inc (“Public Citizen”)134, Southwestern Electric Cooperative (“SWEC”)135and the Illinois IndustrialEnergyConsumers(“IIEC”)136.Thecomplaintscanbesummarizedasfollows:

TheILAGtakesissuewiththesubstantialincreaseintheZone4clearingpricefrom$16.75/MW‐Dayto$150/MW‐Day,anincreaseofcloseto900%fromthe2014‐2015auctionresult.TheILAGalsoallegesthatDynegyisaPivotalSupplier inZone4becauseitsparticipationinthePRAisrequiredtomeetthereliabilitystandardsetbyMISO.TheILAGfurtherallegesthatDynegywasabletostructureitsbidssuchthattheywouldsetthezone’sclearingpricebasedontherequirementtomeettheLCR.TheILAGalsofurtherallegesthatthe2015‐2016MISOPRAforZone4failedtoaddressthemarketpowerofthePivotalSupplier in the Zone, resulting in the pivotal supplier exercising anti‐competitive market power anddriving thecapacityprice inZone4toa level that isnot justandreasonableandabovethatsupplier’sinternal cost. In their requested relief the ILAG asks FERC to (i) find that the rate resulting from the2015‐2016 PRA for Zone 4, effective June 1, 2015 is not just and reasonable, (ii) suspend the rateresultingfromthe2015‐2016MISOPRAforZone4,effectiveJune1,2015,(iii)instituteaproceedingtoinvestigate the allegations raised in the complaint, and if it does not suspend the rates as requested,establisharefunddate,(iv)setnewrates forthe2015‐2016PRAforZone4,(v)assignthe issuestoasettlementprocesswithadeadlineforresolutionof60daysifFERCdeclinestofindtheratestobeunjustand unreasonable, and if settlement is not successful, set the matter for discovery and evidentiaryhearing,(vi)directMISOtoamenditsTariffgoverningthePRAtoprotectconsumersfromtheexerciseofmarketpowerbypivotal suppliers, (vii) assess civil penalties if it concludes in thisproceedingorandother proceeding or investigation that market manipulation by any party led to the unjust andunreasonableratesresultingfromthe2015‐2016PRAforZone4,and(viii)enteraSupplementalOrderinDocketEC13‐93‐000,imposingappropriateconditionsonDynegywithregardtobiddingbehaviorbytheAmerenGenerators(nowcontrolledbyDynegy)intheannualMISOZone4PRAs.

Public Citizen alleges that the highly excessive, unjust, unreasonable, and unduly discriminatory rateincreasesforMISO’sZone4,maybetheresultofillegalmanipulationandgamingoftheauctionbiddingprocess, specifically capacity withholding. Public Citizen alleges that Dynegy may have engaged inintentional capacity withholding to drive auction prices from $16.75/MW‐Day to $150.00/MW‐Day.Public Citizen further alleges that utilities like Dynegy use the threat of “ISO Shopping” as a lever toinfluencethedevelopmentofmarketrulesthatprotect theirprofitability(ortopreventchanges intherules thatwould limit their ability to exercisemarket power) andMISO, acting out of a sense of self‐preservation, has incentive to acquiesce to such threats in order to retainmembership. Public Citizenrequests that (i) FERC exercise its authority under FPA Section 206 to institute an emergencyinvestigationintowhetherPRAwasmanipulatedbyillegalpracticesunderFPASection222sothattherates resulting therefrom, especially as to MISO Zone 4, are unjust and unreasonable, or unduly

133FERCDocketEL15‐71‐000.134FERCDocketEL15‐70‐000.135FERCDocketEL15‐72‐000.136FERCDocketEL15‐82‐000.


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discriminatory,andtosetarefundeffectivedateasoftheeffectivedateofthisComplaint;andthat(ii)FERCexerciseitsauthorityunderFPASections205(d)and309torequirethattheMISOfileassoonaspossibletheresultsofthePRAasaSection205filingofincreasedratesforMISOZone4,andanyotherMISOZoneinwhichchangedchargesareproposed,andtosetsuchratesforhearingunderFPASection205(e)withtheburdenofproofonMISOtojustifytheincreases,andtosuspendsuchratesforatleastonedayandmakethemsubjecttorefund.

SWECallegesthatthe2015‐2016PRAfailedtoproducejustandreasonableratesinZone4asaresultofanon‐competitiveauction,noting(i)thestaggeringincreasefromthe2014‐2015auctionclearingpriceof$16.75/MW‐Daytothe2015‐2016auctionclearingpriceof$150.00/MW‐Dayand(ii) the incredibledisparitybetweentheresultsofZone4(at$150.00/MW‐Day)andtheotherMISOZones(withthenexthighestzoneclearingat$3.48/MW‐Day).SWECseeksanorderthat(i)findstheresultsoftheMISO2015‐2016PRAforZone4tobeunjust,unreasonable,andundulydiscriminatory;(ii)setsajust,reasonable,andnon‐discriminatorypricefortheprocurementofcapacityinZone4;(iii)directsMISOtosubmitforFERCapprovaltariffrevisionsthatwillpreventasinglemarketparticipantfromexercisingmarketpowerinfutureMISOZone4PRAs;and(iv)initiatesaninvestigationintowhetherDynegy’sactionsleadingupto the2015‐2016PRAresulted inmarketmanipulation in contraventionofFederalPowerAct Section222andFERCregulations.

IIEC’scomplaintisthatcertaintermsandconditionsoftheMISOTariffrelatingtothePRAarenolongerjustandreasonableinlightoftheMISO2015‐2016auctionresultsforMISOZone4.IIECrequestsFERCacceptanceofspecifictariffmodificationstoensurethesedeficienciesarefullyaddressedpriortoMISOconducting its 2016‐2017 Auction. IIEC also takes issue with the fact that MISO’s 2015‐2016 auctionresultedinanauctionclearingpriceof$150.00perMW‐dayforZone4whichisa655%increasefromthe2014‐2015price forcapacityof$16.75perMW‐day forZone4afteradjusting for theMISO2015‐2016PRAZonalDeliveryBenefit credit forZone4of $23.47perMW‐day. IIEC seeksaFERCorder (i)findingthatMISO’scalculationofLCRsinitsPRAandtheMISOIMM’scalculationoflostopportunitycostfor Reference Level Prices for theMISO PRA are unjust and unreasonable; and (ii) directingMISO tomodifytheLCRandPRAReferenceLevelcalculationsundertheMISOTariffpriortoconductingtheMISO2016‐2017 PRA to ensure that LCRs, Reference Levels, and Conduct Threshold Levels are justly andreasonablycalculatedforthe2016‐2017andfutureMISOPRAs.

The ICC submitted comments in the respective dockets. In their comments the ICC notes that if the PRAresultsarefoundtoresultinratesthatareunjustandunreasonable,FERCshouldorderappropriaterefunds.Regardless, theICCsuggeststhatFERCshoulddirectMISOtoworkwith itsstakeholders, inanexpeditiousmanner, to re‐examine certain design elements of theMISOPRA and to submit tariff changesprior to the2016PRAtoensurethatthe2016PRA,andfuturePRAs,producejustandreasonablecapacityprices.TheICCnotes that the design elements at issue include: (1) reference levels; (2) LCRs; and (3) LRZ configuration.Specifically,FERCshouldreexaminetheeffectivenessofMISO’scurrentmethodforcalculatingthereferencelevel as a means to mitigate market power, particularly in the presence of a pivotal supplier. The ICCacknowledgestherolethatLRZsplaywithrespecttoreliability.However,theICCnotesthatLRZ4boundontheLCRratherthanthecapacityimport,whichdirectlyimpactedtheclearingpricebylimitingthevolumeoflower cost generation that could be imported into LRZ 4 to meet its reliability requirement. Such anoccurrencesuggeststhatthereisaninconsistencyintherelationshipbetweentheLCR,theCILandtheroletheseparametersplayinachievingMISO’sstatedreliabilitygoalswithineachLRZ.Accordingly,theICCnotesthat FERC should reexamine how MISO develops these zonal auction parameters, how MISO implementstheminthePRA,howtheyimpactthePRAclearingpricesforeachLRZandorderMISOtocorrectanyexistingdesign flaws. Finally, given the results of the 2015‐2016 PRA, and the increasing strength of theinterconnectionbetweenLRZs4and5,FERCshoulddirectMISOtoconsolidateLRZs4and5.ConsolidatingthetwoLRZs,notestheICC,woulddilutetheabilityofapivotalsuppliertoexercisemarketpower.

Inresponsetothecomplaints,MISOnotesthatitfolloweditsFERC‐accepted,Tariff‐basedrulesanditsIMMconfirmed that the PRA both compliedwith the Tariff and produced the results it should have produced.AlthoughMISOfolloweditsTariff,theauctionproducedhigherpricesthanpreviouslyexperiencedinZone4.


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MISOstatesthatthefactthelatestZone4PRAclearingpriceishigherthanthePRAZone4resultsinpriorauctionsdoesnotestablishthatthepriceisunjustandunreasonable;orthatthepricewastheproductofanylackofoversightoradministrationonMISO’spart;orthatthepricewastheproductofmarketmanipulation,allasallegedbyComplainants.ThatthepriceishigheralsodoesnotestablishthatMISOviolatedanyrulesconcerning the conductof theauction,andnoneof the complaintsmakes suchanallegation.MISO furthernotesthatitconductedtheauctionexactlyasrequiredunderitsTariff,andnoneoftheComplainantsprovideany evidence to the contrary. Accordingly, MISO notes that these complaints should be dismissed withprejudice.

MISOandIMMclaimthatthe2015‐2016PRAworkedasexpectedandthefinalresultswerenotimpactedbyphysicaloreconomicwithholdingandotherconductprohibitedbyMISO’sTariff.The reviewalsosuggeststhatforthe2016‐2017and2017‐2018PRAs,Zone4willclearinasimilarfashiontothe2015‐2016PRAwiththeZone4pricemost likely tracking the InitialReferencePrice.With the IMM forecastinga$71/MW‐DayInitial Reference Price for 2016‐2017 and a Preliminary Initial Reference Price of $136.37/MW‐Day137for2017‐2018itisconceivablethattheZone4pricewillclearatclosetotheseprices,i.e.droppingin2016‐2017then rising again in 2017‐2018.While the PJM Base Residual Auction (BRA) for 2018‐2019 has not beenconducted yet due to the delayed FERC decision on PJM’s Capacity Performance Filing, the capacityperformance incentiveswillmost likely result in an increase in the BRA price for 2018‐2019.138With theMISOIMMusingtheopportunitycostofsellingtoPJMasabasisforderivingtheInitialReferencePriceitissafetoassumethattheInitialReferencePricefor2018‐2019willbehigher.Inlightofthecomplaintsandthefactssurroundingthe2015‐2016PRA,theIPAexpectsmuchuncertaintyinfutureMISOPRAZone4clearingprices. IntheinterestofhedgingpriceriskandmaintainingratestabilityfortheIllinoiscustomers,theIPArecommendshedgingaportionofAmeren’s capacitymarket exposure for theupcomingplanningyearsasdescribedinSection7.4.

137ForecastbasedonRPMBRAresultsfor2017‐2018andpresentedatFebruary5,2015SAWG.138OnJune9,2015FERCissuedanOrderaccepting,subjecttocompliancefiling,PJM’sCapacityPerformanceFiling.PJMsubmittedthecompliancefilingonJuly9,2015.TheBRAresultsarenowexpectedtobepostedonAugust21st,2015.


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6 ManagingSupplyRisks

TheIllinoisPowerAgencyActliststheprioritiesapplicabletotheIPA’sportfoliodesign,whichare“toensureadequate, reliable, affordable, efficient, andenvironmentally sustainable electric service at the lowest totalcostovertime,takingintoaccountanybenefitsofpricestability.”139

Atthesametime,theLegislaturerecognizedthatachievementoftheseprioritiesrequiresacarefulbalancingofrisksandcosts,whenitrequiredthattheProcurementPlaninclude:

anassessmentofthepricerisk,loaduncertainty,andotherfactorsthatareassociatedwiththeproposedprocurementplan;thisassessment,totheextentpossible,shallincludeananalysisofthefollowingfactors:contractterms,timeframesforsecuringproductsorservices,fuelcosts,weather patterns, transmission costs, market conditions, and the governmental regulatoryenvironment;theproposedprocurementplanshallalsoidentifyalternativesforthoseportfoliomeasuresthatareidentifiedashavingsignificantpricerisk.140

ThisChapterdiscussesandassessesriskinthesupplyportfolio,aswellastoolsandstrategiesformitigatingthem.Developingariskmanagementstrategyrequiresknowledgeoftheriskfactorsassociatedwithenergyprocurementanddelivery,andofthetoolsavailabletomanagethoserisks.Section6.1describestherelevantrisk factors. Section 6.2 describes types of contracts and hedges that can be used tomanage supply risk.Those products may be thought of as being used to build a supply portfolio. Section 6.3 addresses thecomplementaryissueofreducingorre‐balancingthesupplyportfoliowhenneeded,andthelegal,regulatoryandpolicy issues thatmayarise ifutilitieshave todo soby sellingpreviouslypurchasedhedgesover‐the‐counter.

Sections6.4through6.6addressthecostanduncertaintyimpactsoftheseriskfactors.Riskisoftentakentomean the amount bywhich costsdiffer from initial estimates.Utility energypricing in Illinois forAmerenIllinoisandComEdcustomersisbasedonestimatesandcostdifferencesaretruedupafterthefactthroughthePurchasedElectricityAdjustment(“PEA”).141TheenergypricingforMidAmericancustomersinIllinoisiscurrentlyregulatedbytheIllinoisCommerceCommission.Section6.4providesahistoricalsummaryofPEAratesasaguidetothehistoricalimpactofriskfactors.Section6.5discussestheIPA’shistoricalapproachtoriskandportfoliomanagement,andbrieflydiscussestheriskofwinterpricespikessuchasoccurredin2014.Finally,Section6.6addressesdemandmanagement.

6.1 Risks

Procurement risk factors can be divided into three broad categories: volume, price, and hedgingimperfections. Volume risk deals with risk factors associated with identifying the volume and timing ofenergydeliverytomeetdemandrequirements.Priceriskcoversnotonlytheuncertainty inthecostoftheenergybutalsothecostsassociatedwithenergydeliveryinrealtime.Hedgingimperfectionsaretheresultofmismatchesbetweenthetypesofavailablehedgeproductsandthenatureofcustomerdemand.

6.1.1 VolumeRisk

Theaccuracyof load forecastsdirectly impactsvolumerisk.Accurate customer consumptionprofiles, loadgrowthprojections, andweather forecasts impact both the total energy requirement and the shape of the

13920ILCS3855/1‐20(a)(1).140220ILCS5/16‐111.5(b)(3)(vi).141See220ILCS5/16‐111.5(l).Thispolicyismanifestthroughridersfiledbyeachutility–ComEd’sRiderPE(PurchasedElectricity),andAmerenIllinois’RiderPER(PurchasedElectricityRecovery).


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load curve. Chapter 3 describes the load forecasting processes utilized by Ameren Illinois, ComEd andMidAmerican.Theriskfactorsthatdetermineoverallvolumeriskinclude:changesincustomerloadprofilesand usage patterns, the uncertainties associated with load growth and short‐term weather fluctuations,technology changes such as smart meters and behind the meter generation and storage, and customerswitching. For the Illinoisutilities, akey factor in volume risk is theuncertainty associatedwith customerswitching which directly impacts the results of the utilities’ load forecasts. The opportunities for eligiblecustomerstotakeservicefromARESorthroughmunicipalaggregationresultedinsubstantialportionsoftheeligibleretailloadswitchingawayfromtheutilitiesfornon‐utilityretailcontractsthatrunthroughthe2014‐2015procurementyear.Morerecently,theprimaryuncertaintysurroundingcustomerswitchingappearstobethepotentialforsignificantretailloadmigrationbacktotheutilities.

6.1.2 PriceRisk

ThepricetheAmerenIllinoisandComEdsupplycustomerspayforelectricityconsistsprimarilyofthepriceof energy procured in the forward and spot markets, the cost of capacity to meet resource adequacyrequirements, and the cost of delivery, plus additional charges related to RPS compliance. MidAmericancustomers in Illinois pay the energy and capacity costs associated with the portion of the MidAmericanresourcesthatareallocatedtoservingitsIllinoisload.TherequirementsofMidAmerican’sIllinoiscustomersthatexceedthisresourceallocationwillbeobtainedthroughtheIPA’sprocurementprocessstartingwiththe2016procurement year.Theprimary risk factors that contribute toprice risk include the costs of electricenergy, real‐timebalancing, capacity, ancillary services, transmission including congestion, and correlationwithvolumeriskfactors.

Customer switching decisions are influenced by the difference between the utility and third party pricing.Customer switching behavior impacts volume risk and, in turn, variability in utility customer volumesimpacts price risks. The IPA’s historical procurement strategy involves buying power in a “laddered”approachwithalargefractionofthepowertoserveretailcustomersinthedeliveryyearprocuredthroughforwardpurchasesinthetwoprioryears.Inaperiodofrisingprices,thoseforwardpurchasesarelikelytobepricedbelowmarket.Therefore,theblendedpriceofutilitysupplymaybelessthatthecurrentpriceofanARESormunicipalaggregationoffer.Thispricedifferencecanresultinincreasedcustomermigrationbacktotheutility. The reverse canoccur aswell, higher utility supply costs relative to alternatives throughARESsuppliersormunicipalaggregationcanresultineligiblecustomersmigratingawayfromtheutilities.

6.1.3 HedgingImperfections

Hedging imperfection can contribute to supply risks through mismatches in procurement supply shape,supplydeliverypointsandcustomerloadlocations,ortheintermittentnatureofrenewableenergysources.Thestandardon‐peakandoff‐peakblockenergyproductsprocuredby the IPAdonotreflecthourly loads.Theseproductsprovideconstantvolumeandpricesacrossa fixednumberofhourswhilehourlypricesaswellasloadvaryacrossthedayandwithineachofthepeakandoff‐peakperiods.Becauseofthisvariation,iftheaveragepeakandoff‐peakmonthlyloadisperfectlyhedged,theactualhourlyloadwillstillbeimperfectlyhedged.Residualsupplyriskwill remainsincetheactual loadwillvarybetweenbeinggreaterthanor lessthantheaverage.LocationalmismatchesaregenerallynotasignificantriskfortheIPAprocurementssincethedeliverypointsforthehedgecontractsaretheLoadServingEntity’s(“LSE’s”)loadzone.Thecosttocovertheintermittentoutputfromrenewableresourcesinthesupplyportfoliomaynotbehedgeableandthereforecanresultinresidualsupplyriskaswell.

6.2 ToolsforManagingSupplyRisk

Traditionally,autility’selectricitysupplyplanincludesphysicalsupplyandfinancialhedges.Physicalsupplyincludes thepowerplants that theutilityownsor controls, aswell as transactions forphysicaldeliveryofelectricity.Financialhedgesareadditionalhedginginstrumentsusedtomanageresidualpriceriskandotherrisks,suchasweatherrisk.

ComEdandAmeren Illinoisdivested theirgeneratingplants tounregulatedaffiliatesor thirdparties.Theyhaveno contracts for unit‐specificphysical delivery, other than certainQF (Qualifying Facilities under the


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PublicUtilitiesRegulatoryPracticesAct(“PURPA”))contracts.Their long‐termrenewablesPowerPurchaseAgreements (“LTPPAs”) are structured as “Contracts forDifferences.” As the utilities do not purchase andtake title to electricity, the utilities’ supply positions, other than RTO spot energy, are exclusively pricehedges.MidAmericanhasretainedtheresourcesthatserveitsIllinoiscustomers,mostofwhicharelocatedoutsideofIllinois.MidAmericanallocatesaportionofthecapacityandenergyfromspecifiedresourcesunderitscontrolforitseligibleIllinoiscustomers.Underthe2016ProcurementPlan,theIPAwillprocurethenetrequirements between MidAmerican’s eligible customer retail load and the MidAmerican controlledgenerationallocatedtoitsIllinoiscustomers.

PhysicalelectricitysupplyandloadbalancingforComEd,AmerenIllinois,andMidAmericanarecoordinatedby the respectiveRTOs (PJM forComEdandMISO forAmeren Illinois andMidAmerican). ComEd,AmerenIllinois,andMidAmericanareconsideredtobeLSEsbytheRTOs.EachRTOprovidesday‐aheadandreal‐timeelectricity markets and clearing prices, That is, generators supply their energy to the RTO, and the RTOdeliversenergytoLSEsandcustomers.TheRTOensuresthephysicaldeliveryofpower.Thecostofmanagingthisdelivery, includingthecostofmanagingreliabilityrisks, ispassedonto theLSEs financially.TherisksfacedbyLSEs insupplyingenergytocustomersaremostly financial.TheLSEstillneedstomanagecertainoperational risks such as scheduling and settlement. There are other, non‐financial risks associated withelectricityretailing,suchascustomerbillingoraccountspayablerisks,butthosearenotassociatedwiththesupplyportfolio.

EachRTOchargesauniformday‐aheadpriceforallenergyscheduledinagivenhouranddeliveryzone.Totheextentthatreal‐timedemanddiffersfromtheday‐aheadschedule,loadisbalancedbytheRTOatareal‐timeprice:ifdemandexceedstheday‐aheadschedule,thentheLSEpaysthereal‐timeprice;andifdemandisless than theday‐aheadschedule, theLSE iscredited the real‐timeprice.Both theday‐aheadand the real‐time prices are referred to as Locational Marginal Prices (“LMPs”) because they depend on the deliverylocationorzone.

6.2.1 TypesofSupplyHedges

The2014ProcurementPlancontainedadetaileddescriptionofanumberofdifferenttypesofsupplyhedges,listed below.One pointmade in that plan is that hedges available in themarket are not perfect; the riskslistedinSection6.1cannotallbehedgedawayexceptperhapsthroughaspeciallytailored“fullrequirements”hedgecontract,whosepricepremiummaynotbeacceptableinreturnforthatdegreeofriskreduction.142

An important categoryof energy supplyhedges isaunit‐specific supply contract.Other supplyhedgesareforwardcontracts,futurescontracts,andoptions.

6.2.1.1 Unit‐SpecificHedges

As‐available

Baseload

Dispatchable

6.2.1.2 Unit‐IndependentHedges.

Standardforwardhedges(blockcontracts)

Shapedforwardhedges

142Evenafullrequirementshedgedoesnottrulyeliminateallrisk.Forexample,ifasupplierofafullrequirementstrancheweretodefault,additionalprocurementcoststomakeuptheshortfallcouldbepassedalongtoeligiblecustomers.


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Futurescontracts

Options

Fullrequirementshedges

6.2.2 SuitabilityofSupplyHedges

NotallofthetypesofhedgeslistedinSection6.2.1aresuitableforuseinthisProcurementPlan,andnotallmay be readily available in electricitymarkets.143Illinois law requires that “any procurement occurring inaccordancewiththisplanshallbecompetitivelybidthrougharequestforproposalsprocess,”providesasetofrequirementsthattheprocurementprocessmustsatisfy,andmandatesthattheresultsbeacceptedbytheICC.144Amongthespecificrequirements,theProcurementAdministratormustbeabletodevelopamarket‐basedpricebenchmarkfortheprocess;thebiddingmustbecompetitive;andtheICC’sProcurementMonitorisrequiredtoreportonbidderbehavior.145Themostnaturalevidenceofcompetitivenesswillbebreadthofparticipation,althoughotherevidencemaybepossibleaswell.

HedgesmostsuitableforusebytheAgencywouldbethosestandardizedproductsthatarewell‐understood,andpreferablywidely‐traded. If aproduct has liquid tradingmarkets, or is similar tootherproductswithliquidmarkets,abiddercancontrol itsriskexposure.Availabilityof informationoncurrentpricesandthepricehistoryofsimilarproductshelpbiddersprovidemorecompetitivepricing,andhelptheProcurementAdministrator produce a realistic benchmark. Prior to its 2014 Procurement Plan, the IPA had generallyrestricteditshedgingtotheuseofstandardforwardhedgesin50MWincrements.TheIPAbeganusing25MW increments and amid‐year procurementwith the 2014 Plan. TheAgency’s recommended plans havebeenstatedintermsofmonthlycontracts,althoughprocurementeventshavemetsomeoftheseneedswithmulti‐monthcontracts.

TheIPAhasinthepastpurchasedenergyproductsthatarenottypicallytraded,suchasthelong‐termPPAswith new build renewable generation that were authorized in the 2010 Procurement Plan. As noted inSection2,theseproductsstillmustbestandardizedinsuchawaythatthewinningbiddersmaybeselectedbasedonpricealone,andthepriceissubjecttoamarket‐basedbenchmark.AsdiscussedinChapter2,whilethe ICC clarified its understanding of the definition of “standard product” in its approval of the 2014Procurement Plan, the IPA’s authority to procure other products, including shaped forward contracts andoptioncontracts,couldbesubjecttofuturelitigation.Marketsforproductsthatarespecificallydesignedforthe IPA’s requirements, such as full requirements contracts or over‐the‐counter options, will likely havelimited transparency.The IPA’sprocurementstructurerequiresabenchmarkingandapprovalprocessandmaynotbecompatiblewithsuchalowleveloftransparency.

FuturescontractsatthePJMNorthernIllinoisHubandtheMISOIllinoisHubaretradedinreasonablyliquidmarkets,makingsuchcontractseasiertobenchmark.Themarketsfor long‐dated(i.e. furtherinthefuture)contractsarelessliquid,however.TheAgencywouldseektoobtaincompetitivepricingonsuchcontractsifitweretoincorporatetheminitsportfolio.However,itmaybedifficultorimpossibletoconductthestatutoryRFPprocess for exchange‐traded futures contracts: setting a price through anRFPprocess structured perlegislative mandates is incompatible with price‐setting either in an open outcry auction or by a market‐

143TherehasbeensubstantialdebateintheapprovalofpriorProcurementPlansrelatedtowhetherafullrequirementsapproachisamoresuitableapproachforeligibleretailcustomers.Inapprovingthe2015PlanandrejectingtheIllinoisCompetitiveEnergyAssociation’sfullrequirementsprocurementproposalas“notsupportedbytherecord,”theCommissionstatedthatit“wishe[d]tomakeclearthatitisnotinclinedtoconsiderfutureyears’fullrequirementsprocurementproposalsabsentnewargumentssupportedbyananalysisquantifyingbenefitstoeligibleretailcustomers.”ICCDocketNo.14‐0588,FinalOrderdatedDecember17,2014at114.TheIPAisnotawareofanynewargumentsinfavoroffullrequirements,letalonenewargumentssupportedbyanalysesquantifyingbenefitstoeligibleretailcustomers,andnotesthecontinuedsuccessofitsprocurementapproachinproducinghighlycompetitiveserviceratesforAmerenIllinoisandComEdeligibleretailcustomers.144220ILCS5/16‐111.5(b),(e),(f).145220ILCS5/16‐111.5(f).


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maker.Itisalsounclearhowthemarginrequirementswouldfitwithinthecurrentregulatoryframework,ifpricemovementsrequiretheutilitytopostmarginmanymonthsinadvanceofdelivery.Thesameconcernsareevenmoreapplicabletooptionscontracts,tradinginwhichismoreilliquid.

6.2.3 OptionsasaHedgeonLoadVariability

Anoptiongivesthebuyerarightbutnotanobligationtobuyorsellacommodityataspecifiedpriceonorbefore a certaindate.For example, a call optiongives thebuyer the right, butnot theobligation, tobuy aspecific contract. A put option gives the buyer the right, but not the obligation, to sell a specific contract.Optionsare“one‐way”hedges.Acalloption,forexample,canhelphedgeagainstpriceincreasesbutprovidesnohedgeagainstpricedecreases.Optionsonforwardorfuturescontractsaremuchlessexpensivethanthecontractsthemselves,becausetheyonlyconveytherighttospendthemoneytobuythecontract.

Somemayperceiveoptionsasattractivetoolstohedgeagainstcustomermigrationandotherformsofloadfluctuations.Accordingtooptionpricingtheory,optionsarenotanymoreusefulforhedgingpriceriskthanare forward contracts unlessone is exposed to other risks that correlatewith and enhanceprice risk (forexample, loss of load accompaniedwith declining prices). In theory, option prices are determined by thevalueoftheoptionasapricehedge.Ifanoptionhadadditionalvalueasahedgeagainstloadmigrationrisk,somemightconsideroptionstobeabargain.Itturnsoutthatoptionsareexpensivewhenusedashedgesforloadmigrationrisk.Thisisbecauseifacalloptionon1MWofloadhasapriceV,thenthatshouldbeitsvalueasapricehedge.Ifthe1MWisnotcurrentlyservedbytheutility,butmayreturnwithsomeprobabilityP,thenthevalueofthisoptionshouldbeonlyPtimesVwhichislessthanitsprice.Inotherwords,thevalueoftheoptionasahedgeagainstloadmigrationriskislessthanitsvalueasapricehedge.Butitisthevalueasapricehedgethatdeterminestheoption’sprice.

Therearealsoothercostsandlogisticalobstaclestousingoptions:

A large part of the volume of options on the market is traded on exchanges. They have aparticularadvantageinthatthetradingexchangebearsthecounterpartydefaultrisk.However,theAgency’sstructuredprocurementprocesspreventstheAgency’sfrombuyingoptionsontheexchanges.

Option contracts can be relatively illiquid, making it more difficult to assure fair pricing. Ifoptions purchased through the IPA procurement process required an affirmative exercisedecision, which most likely they would, the utilities would seek regulatory comfort on theirexercise decision‐making before agreeing to use options. For example, if an exercise decisionweredependentontheutility’sloadforecastorviewofmunicipalaggregation,theutilitywouldwanttobeable toshowithadactedprudently. If theutilityexercisedaputoption, tosell theunderlying hedge, itwouldwant to be sure that decision did notmake it awholesalemarketparticipant for purposes of FERC Order 717. If the option exercisewere purely financial andautomatic—resultedonlyinacashpaymentfromtheoptionholder–theseconcernsmightnotbeasimportant,butcounterpartycreditwouldbeanissue.

TheuseofoptionsissubjecttoregulationsundertheDodd‐FrankActof2010(specificallyTitleVII). Under this act, the trading of options (and other swaps)would be reported to a centraldatabaseforclearingpurposes.Tradedetails(price,volumes,timestampedtradeconfirmations,andcompleteaudittrails)wouldneedtobereported.Inaddition,traderecordsmustbekeptfor5yearsaftertheterminationoftrade(eitherthroughexerciseorexpiration),andmustbemadeavailablewithinfivebusinessdaysofrequest.Thiswouldaddtoeitherthepurchasecostortheownershipcostofoptions.


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6.3 ToolsforManagingSurplusesandPortfolioRebalancing

TheIllinoisPowerAgencyActspecifiesthattheProcurementPlan“shall include…thecriteriaforportfoliore‐balancingintheeventofsignificantshiftsinload.”146Itisthereforeappropriatetoconsiderwhattoolsareavailabletoconductsuchrebalancing,keepinginmindthattheutilities,nottheAgency,aretheownersoftheforward hedges and that selling of excess supply in the forwardmarkets may have unintended cost andaccountingconsequences.

To date, the only rebalancing of hedge portfolios prior to the delivery date has been thecurtailmentoflong‐termrenewablecontractsduetobudgetrestrictions.Spendingonthesecontractswassubjecttoalimitrelatedtoamandatedratecap.

Sales of excess supply by the utilities in the wholesale market to rebalance their supplyportfolio may create a de facto “wholesale marketing function” within the utilities. TheemployeesinvolvedinwholesalemarketingactivitieswouldbesubjecttotheseparationoffunctionsinaccordancetoFERCOrder717.147

Forthelastfewyears,theutilitieshavescheduledexcesssupplyintheirportfolios,ormadeup supply deficits, in the RTOs’ day‐aheadmarkets. This has been the dominantmode ofportfoliorebalancing.

Asanalternativeformofrebalancing,theAgencycouldconduct“reverseRFP”procurementevents, inwhichthebidsare tobuyrather thansell forwardhedges.TheAgencydoesnotbelievethat ithastheauthorityto“conductcompetitiveprocurementprocesses”under20ILCS3855/1‐20(a)(2)tosellexcesssupply.

The Agency could conceivably issue an RFP to purchase derivative products, such as putoptions on forward hedges, which would have a similar risk reduction effect to sellingforwards.Thismayavoid legal andcontractualdifficulties associatedwith selling forwardhedgecontracts.Thisapproachwouldalsorequiretheutilitiestoensuretheyhadregulatoryapprovaltoexercisetheoptionsafterpurchasingthem,andtheemployeeswhoexercisetheoption could become classified as part of a “marketing function.” The Agency does notenvisionenteringintoderivativecontractsforrebalancingpurposes.

TheAgency could conductmore than one procurement event in a year if the rebalancingrequiredistoincreasethesupplyundercontract.TheIPAconductedtwoprocurementsfor2014,andin2015afterconductingaspringprocurement,theAgencyisplanningasecondprocurementinSeptember2015.Thevolumesforthatprocurementhavebeenadjustedinthismanner.

6.4 PurchasedElectricityAdjustmentOverview

ThePurchasedElectricityAdjustment (“PEA”) functions as a financial balancingmechanism to assure thatelectricitysupplychargesmatchsupplycostsovertime.Thebalanceisreviewedmonthlyandthechargerateis adjusted accordingly. The PEA can be a debit or credit to address the difference between the revenuecollectedfromcustomersandthecostofelectricitysuppliedtothesesamecustomersinagivenperiod.Thesupply costs are tracked, and the PEA adjusted, for each customer group. The PEA is applicable to thepurchasedelectricitycostsofAmerenIllinoisandComEd.MidAmerican’schargeforpurchasedelectricityissetbytheICCunderaseparatecostrecoveryprocess.

ThePEAprovidessomeguidanceastotheamountbywhichthecompletesetofriskfactorscausedthecostofenergysupplytodifferfromtheestimate—inotherwords,theimpactofrisk.Figure6‐1showshowthePEAshave changedover the last fouryears.WhileAmeren Illinois’PEAshavebeengenerallynegative,ComEd’s

146220ILCS5/16‐111.5(b)(4).147125FERC¶61,064,Oct.16,2008.


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havebeenmoreoftenthannotpositive,andhavehadmorevolatility.ComEdhasvoluntarilylimiteditsPEAtomovebetween+0.5cents/kWhand‐0.5cents/kWh,andthefigureshowsthatComEd’sPEAhasoscillatedbetweenthoselimits.

InApril2014,theCommissionapprovedanadjustmenttoComEd’sPEAthatallowstheaccumulatedbalanceofdeferralsassociatedwiththecomputationofthePEAeachJunetoberolledintothebasedefaultservicerateforthenextyearandtheassociatedbalancetoberesettozero.TheComEdPEAincreasedfromacredittoachargefortwomonthsinthespringof2015.ThiswasduetohowtheICCinstructedComEdtorecovercustomer care costs from eligible retail customers, and not due to costs related to energy procurement.Absentthatcostrecovery,thePEAwouldhavebeenacreditinthosetwomonths.

InJuly2014,themagnitudeoftheAmerenIllinoisnegativePEAsincreasedsignificantly.TheIPAunderstandsthatthischangewasmostlikelytheresultofAmerenIllinoisover‐collectionduringthepreviouswinteranditsPEAsrepresentedthereturnoftheseproceedstocustomers.ThenegativevaluesoftheAmerenIllinoisPEAshavesubsequentlybeenmuchsmaller.

Figure6‐1:PurchasedElectricityAdjustmentsinCents/kWh,June2011–August2015

*‐UniformacrossAmerenIllinoisserviceterritorysinceOct.2013.Forprevious

months,valuesdifferedslightlybyZone.

6.5 EstimatingSupplyRisksintheIPA’sHistoricApproachtoPortfolioManagement

6.5.1 HistoricStrategiesoftheIPA

The utilities, pursuant to plans developed by the IPA, have historically used fixed‐price, fixed‐quantityforwardenergycontractsandfinancialhedges(suchastheLTPPAs),alongwithRTOloadbalancingservicestoserveload.EnergydeliverieshavebeencoordinatedbytheRTOsandtheAgencyarrangedaportfoliooflong‐termcontractsandstandardforwardhedges.These forwardhedgeswereprocured inmultiplesof50MW during the earlier procurements and in 25 MW blocks since 2014. Ancillary services have beenpurchased from the RTO spot markets. The utilities have used Auction Revenue Rights to mitigatetransmissioncongestioncost.

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Forwardhedgeshavebeenprocuredona “laddered”basis.TheAgencyoriginally sought tohedge35%ofenergy requirements on a three‐year‐ahead basis, another 35% on a two‐year‐ahead basis, and theremainderonayear‐aheadbasis.Priorto2014,procurementshadbeenannual,inAprilorMay,ratherthanonamorefrequentorratablebasis.Forexample,inthespringof2010,theAgencyprocuredforwardhedgevolumesascloseaspossibleto35%ofthemonthlyaveragepeakandoff‐peakloadforecastsforthe2012‐2013delivery year. In the spring of 2011, theAgency procured forward hedge volumes to bring the totalvolumeascloseaspossibleto70%ofthen‐currentmonthlyaveragepeakandoff‐peakloadforecastsforthe2012‐2013deliveryyear.Andinthespringof2012,theAgencyprocuredforwardhedgevolumestobringthetotalvolumeascloseaspossibleto100%ofthen‐currentmonthlyaveragepeakandoff‐peakloadforecastsfor the2012‐2013deliveryyear. In the2013ProcurementPlan, theAgency indicated itwasconsideringachange in hedging from100%/70%/35%of the expected load to75%/50%/25%.Because therewerenoprocurementsin2013,thathedgingstrategywasnotformallyadoptedorimplemented.

Inthe2014ProcurementPlan,theIPAproposedamodificationtothe75%/50%/25%strategy.TheAgencysuggested that the procurement goal for amid‐April procurement event should be to hedge 106% of theexpected load forecast for June‐October. These months would be close to the procurement date and nobenefitwasseenindeferring25%oftheprocurementtothespotmarket.Ontheotherhand,becauseofthecorrelationbetweenloadandpriceandbecausepricesinthehoursofhighusagearemorethan100%ofthetime‐weightedaverageprice,a$1/MWhmovementinthemonthlyaveragepricetranslatesintoanincreaseofmorethan$1/MWhintheaverageportfoliocost(theload‐weightedaverageprice)–infact,approximately$1.06.TheAgencycontinuedtorecommendhedginguptoonly75%oftheexpectedloadforNovember‐Mayof the prompt delivery year in the April procurement, but also recommended a second procurement inSeptembertobringthehedgedvolumeto100%.

Inthe2015ProcurementPlan,theIPAadoptedsomeminorchangesfromthe2014Plan.Thehedgeratiosforthe April procurement eventwere adjusted to 100% of the expected forecast for off‐peak hours for JunethroughOctoberdeliveryinthecurrentyearandforon‐peakhoursforJune,September,andOctoberdeliveryinthecurrentyear.Thehedgeratiowasleftat106%onlyfortheon‐peakhoursofJulyandAugust.Thetargethedge ratios for delivery in subsequent years were adjusted to 50% for all months (June‐May) of thefollowingyearfortheSeptemberprocurementevent,37.5%forallmonthsofthefollowingyearfortheAprilevent,25%forallmonthsofthesecondyearoutfortheSeptemberevent,and12.5%forallmonthsofthesecondyearoutfortheAprilevent.

Forthe2016ProcurementPlan,otherthanmovingOctoberfromthegroupofmonthscompletedintheAprilprocurement to the group of months completed in the Fall procurement, no substantial changes to thestrategyareproposed,butconsiderationisgiventoadjustingthecumulativehedgeratiosforvariousdeliverymonths,effectiveatthenexttolastscheduledeventpriortodelivery.

The procurement schedule balances procurement overhead costs, price risk, and load uncertainty. If theamountstobehedgedinanyyeararesmall,theAgencycoulddecidetoavoidtheprocurementoverheadandnot schedule a procurement event (as in 2013). The Agency has not used options, unit specific contracts(exceptfortheLTPPAsandtheFutureGenagreement),orotherformsofhedginginthepast.InadditiontheAgencyhasnotusedforwardsalesorputoptionstorebalanceitsportfolio.

6.5.2 MeasuringtheCostandUncertaintyImpactsofSupplyRiskFactors

Giventhevolatilityinforwardenergypricesfrommonthtomonthandwithinmonthsexperiencedinthelastseveralyears,theIPAinvestigatedthemeritofconsideringalternativeprocurementschedulestrategieswiththegoaloffurtherminimizingthevolatilityoftheresultingportfoliosofcontractsforeachdeliverymonth.

Anobjectiveoftheprocurementscheduleistomaximizestabilityoftheresultingrateforservicetoeligibleretailcustomers,whileminimizingcost.Ifpurchasesweredistributedclosetoevenlyover5or6eventsina2to3yearperiod,theresultingaveragepriceoftheportfolioofcontractsforanydeliverymonthwouldreflectanaverageof any long‐term (>1 year)price trendover theprocurementperiod.The inclusionof several,evenlyweightedprocurementdateswouldalsosmoothoutday‐to‐dayvolatilityinforwardprices.


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Concentratingahighpercentageofpurchasesforsomedeliverymonths inoneortwoprocurementeventsclosetothebeginningofthedeliveryperiod,however, increasesthepotential impactofday‐to‐daymarketvolatilityontheportfolioaverageprice.

Ingeneral,theIPAexpectedthatthevolatilityofportfoliopricewouldbereducedbyincreasingthenumberofprocurementeventsandallocatingpurchasetargetsevenlyamongthem.However,duetothepatternofhistorical monthly volatilities in the forward market over the time span analyzed, the schedule ofprocurementsprescribedinthe2015ProcurementPlan,whichpurchasessmallquantitiesupto3yearspriortodelivery,producesthelowestvolatilityofportfoliopriceasmeasuredbystandarddeviation.Areviewofmonthly forwardmarketvolatilitiesdoesnot supportastrongpreference foranyparticularmonthsof theyearasidealortobeavoidedforprocurementevents.Thisistobeexpectedbecausevolatilityisdrivenbymarketinformation,whichmaynothaveaseasonalprofile.TheIPAseesnoreason,basedonthisanalysis,tosignificantlychangetheenergyprocurementschedulefromthatestablishedinthe2015ProcurementPlan.

TheresultsoftheprocurementschedulingandvolatilityanalysisdescribedinmoredetaillaterinthisSectionindicatethattheclosertheprocurementeventsareheldtotheproductdeliverydatethegreatertheimpactofvolatilityontheproductsprocured.Theon‐peakconveniencevolatilitycurvesshowninFigures6‐12and6‐13 demonstrate these results. However, other factors also impact the scheduling of procurement eventsrelative to delivery timing and may result in reasonable decisions to hold procurement events in closeproximitytoproductdeliverydates.

6.5.2.1 MonthlyPriceFluctuation

The IPA used historical PJM Northern Illinois hub on peak energy forward prices for trading dates fromFebruary 1, 2011 through April 30, 2015 and delivery months from June 2014 through May 2015148toanalyze thedistributionsofdaily tradeprices for individualdeliverymonthsover the tradingdaysofeachtrademonth.Resultsofthisanalysisarepresentedinthefollowingcharts.Figure6‐2showsthemeandailyprices for the 12 deliverymonths for each trademonth of the sample period,while Figure 6‐3 shows thestandarddeviationofthedailypricesforthesamedistributions.Inbothcharts,thevaluesreportedfortrademonthsJanuary2011throughFebruary2012arethesameforall2014deliverymonths.Similarly,reportedpricesbegin inMarch2012for2015deliverymonths,but fullmonthlydifferentiation isnotavailableuntilJanuary2014.ForwardpricesforJuly2014andAugust2014deliveryclearlyroseinlate2012andagaininthefirstsixmonthsof2014,withcorrespondingspikesinstandarddeviationatthebeginningofthoserises.Forward prices for January 2015 and February 2015 delivery rose dramatically in January 2014 andsubsequentmonthswithcorrespondingspikesinstandarddeviation.

148Sourceofdata:BloombergLP.


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Figure6‐2:MonthlyDistributionMeans

Figure6‐3.MonthlyDistributionStandardDeviations

Itishelpfultopivotthedataforselecteddeliverymonthsinthesechartstoseehowstandarddeviationvariesbycalendartrademonthfortherelevantrangeofcalendaryears.Figure6‐4showsthestandarddeviationofdailypricesforeachmonthfortheJuly2014deliverymonth.Themonthlystandarddeviationisconfinedtoarelativelynarrowbandwithnostrongindicationsthatanycalendarmonthrepresentsparticularlyhighpricevariability.ThespikeinstandarddeviationforOctober2012,whichalsoappearsinFigure6‐3,appearstobean anomaly. Similar charts forOctober2014, January2015, andApril 2015delivery appearasFigure6‐5,Figure6‐6, andFigure6‐7.While theOctober andApril charts showverynarrow ranges of relatively low

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standarddeviations, the January chart shows a significant increase in standarddeviation for 2014 tradingmonths,relativetotheprioryears,attributabletotheshockofthePolarVortex.

Figure6‐4:MonthlyStandardDeviationsforJuly2014Delivery

Figure6‐5:MonthlyStandardDeviationsforOctober2014Delivery

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Figure6‐6:MonthlyStandardDeviationsforJanuary2015Delivery

Figure6‐7.MonthlyStandardDeviationsforApril2015Delivery

Theprecedingchartssuggest thatvolatility,asmeasuredbythestandarddeviationofdaily forwardpriceswithin a trade month, is not significantly different from trade month to trade month and is generallysomewhathigherinanytrademonthfordeliveryinasummermonth(e.g.,July)thanfordeliverythanothermonths.Highvolatilityforwinterdeliverymonths(e.g.,January)isarecentdevelopment.

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6.5.2.2 ProcurementSchedulesandPortfolioVolatility

Thecosttoeligibleretailcustomersforqualifiedserviceinagivenmonthisdrivenbytheaveragepricepaidforblocksofon‐peakandoff‐peakenergysecuredunderaprocurementplan.Thestabilityofthatcost isafunction of the long‐term trends (both predictable and random) in forward prices over the procurementperiodandthemorerandomdrawoftheforwardpriceonthedaysinwhichcomponentsoftheportfolioareprocured.TheIPAperformeda“backcast”analysistostudytheeffectsofdifferentprocurementschedulesfortheon‐peakenergycomponentofthemonthlyportfoliosforOctober2014throughSeptember2015deliveryusingthePJMNorthernIllinoisHubforwardpricedatadescribedabove.

Fourprocurement scheduleswere considered.Each schedule avoidsprocurement events in themonthsofJanuary,February, JulyandAugust.Thefirstschedulerepresentsabackcastof the2015procurementplanschedule(ignoringtheextrasixpercentofloadtobehedgedinthesummermonths)withprocurementsinAprilandSeptemberfrom2012through2014andinAprilof2015.

Thesecondscheduleconsideredalsohastwoannualprocurementevents,occurringinMarchorAprilandinSeptember or October. The cumulative procurement targets are adjusted somewhat so that, barringsignificant changes in load forecasts or failures to fill the targeted quantity in a given event, 25% of therequirementforeachdeliverymonthwouldbeprocuredineachoffoureventsover18months.

Thethirdprocurementscheduleconsidered incorporatesathirdannualevent inMayor June,slips the falleventouttoOctoberorNovember,andallocatesthetargetedprocurementsforeachdeliverymonthevenlyoverfiveeventsandroughly14to18months.

Thefourthprocurementscheduleconsideredaddsafourthevent,slidingtheOctober‐NovembereventbacktoSeptember‐OctoberandinsertinganeventinNovemberorDecember.Targetsaresetsothattheportfolioforeachdeliverymonthisacquiredinfiveequalpartsover13months.

AMonte‐Carlosimulationwasconductedwith10,000iterations.Ineachiteration,aforwardpricewasdrawnfrom a normal distribution for each delivery month from each designated event date range (one to twomonthsoftradedays)andcalculatedaweightedaverageportfoliocostforeachdeliverymonthundereachprocurement schedule, based on the designated target levels. The distributions over all iterations of theportfolioaveragecostswereanalyzedtodeterminemeansandstandarddeviations.Meanaverageportfolioprices are plotted for each procurement schedule in Figure 6‐8, while standard deviations are shown inFigure6‐9.Themeansaresimilarforalldeliverymonths,andnoplanhasthelowestcostorthehighestcostinall12deliverymonths.Contrarytooriginalexpectations,thestandarddeviationsforsixdeliverymonthsare lowest under the 2015 Procurement Plan schedule. Standard deviations are highest for six deliverymonthsundertheFour‐Eventschedule.


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Figure6‐8:PortfolioPriceMeans

Figure6‐9.PortfolioPriceStandardDeviations

6.5.2.3 ForwardPriceCurveAnalysis

Onlyonepossibleevolutionofforwardpricesisobservedinhistoricaldata,whichmakesitdifficulttodrawstrong conclusions or make hedging strategy recommendations based on a few years of data. The aboveanalysiswasconductedwithanapproachthathadlimitedabilitytoanalyzepossiblefutures.Inordernottohaveparticularrecenttrendsoreventsdrivetheconclusions,ananalysiswasalsoconductedthatfocusedonamodel‐baseddecompositionof thesourcesofseasonalandstochastic fluctuations.Thissecondapproach,

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moregroundedinfinancialeconomicswasusedtoassesskeyaspectsofelectricenergyforwardpricesthatareimportantconsiderationsforpricehedging.TheIPAanalyzedMISOIllinoishubandPJMNorthernIllinoishub futures prices with a general model for use with futures that have seasonally‐varying prices.149Thismodelingapproachhasthreebasicstepsforcharacterizingpricevolatilityofaparticularforwardorfuturesproduct.

First, for each tradingdate, thede‐seasonalizedaverageof the logarithmofprices for the current forwardcurve of Nmonths is calculated. Logarithms are used, as is standard in statistical price analysis becausecommoditypriceshaveprobabilisticdistributions that resemble the logdistributionmore than thenormaldistribution,whichsimplifiesstatisticalanalysis.Toinsurethatallseasonalityisremoved,a24monthseries(N=24)isusedbecauseitisamultipleof12.Figure6‐10andFigure6‐11showthede‐seasonalizedlogpricesforPJMandMISOon‐peak futures, respectively.Equal lengthsubsetsof the3.5yearsofdataused forPJMfuturesand the2yearsofdataavailable forMISO futures indicate that in themore recent sub‐period, thevolatility of de‐seasonalized futures prices has declined slightly. The de‐seasonalized log price series ismodeledasastochastic,oruncertain,variablethatrepresentsthetrajectoryofaveragepricesovertime.

Figure6‐10:PJMOn‐PeakDe‐seasonalizedAverageLogofPricesfor24Maturities

149S.BorovkovaandH.Geman,“Seasonalandstochasticeffectsincommodityforwardcurves,”ReviewofDerivativesResearch(2006)pp.167‐186.

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Figure6‐11:MISOOn‐PeakDe‐seasonalizedAverageLogofPricesfor24Maturities

Second, the seasonal premia by calendar month, expressed as percent of the de‐seasonalized price, arecalculated as the average difference between the daily prices for a product that expires (or physicallydelivers) in the specific calendarmonthand thedailyde‐seasonalizedprices.By construction, thepositiveand negative premia sum to zero over the 12 calendarmonths. For simplicity, these seasonal premia aremodeledasdeterministicshapingfactors,andarethesameregardlessofyear.TheshapesforPJMandMISOon‐peakfuturesareshowninFigure6‐12andFigure6‐13,respectively.

Figure6‐12:PJMOn‐PeakSeasonalPremia

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Figure6‐13:MISOOn‐PeakSeasonalPremia

Thethirdandfinalfactorinthedecompositionofforwardpricesiswhatisknownasthe“convenienceyield.”Theconvenienceyield is theresidualof the forwardpriceminusthedeseasonalized forwardpriceandtheseasonalpremium.Theconvenienceyield ismodeledasasecondstochasticfactor,whichvariesbytimetomaturity,accountingforthedynamicsofsupply‐demandimbalances.Theaverageconvenienceyieldinthismodel is zero. The volatility term structures of convenience yields for PJM andMISO on‐peak futures areshowninFigure6‐14andFigure6‐15,respectively.

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Figure6‐14:PJMOn‐PeakConvenienceYieldVolatility

Figure6‐15:MISOOn‐PeakConvenienceYieldVolatility

WhiletheIPAdidnot includemodelingofseasonal futuresprices intheMonteCarlosimulation, itappearsthatthefairlystablevolatilityofaveragefuturespricesandthematurity‐varyingprofileofconvenienceyieldsboth lend support toa strategyofusingmultipleprocurementswhichmaybe evenly spacedand sized. Inorder to avoid excessive uncertainty in procurement costs, the shape of the convenience yield curvesindicatesthatthelastprocurementshouldbemadeseveralmonthsinadvanceofcontractexpiry.

Basedonthisanalysis,theIPAseesnoreasontosignificantlychangetheenergyprocurementscheduleandapproach for its 2016 Plan from the approach established in the 2015 Procurement Plan. Additionalstatisticalandmodelinganalysiswouldbeneededtojustifyadditionalrevisionstotheprocurementschedule.TheIPAwillcontinuetoreviewandsuggest improvements(ifnecessary)to itsriskmanagementapproachandprocurementprocessinfutureprocurementplans.

6.6 DemandResponseasaRiskManagementTool

Demand response programs operated by ComEdare not used to offset the incremental demand, over andabovetheweather‐normalizedexpectedcasepeakload.Theprograms,however,aresupplyriskmanagementtoolsavailabletohelpassurethatsufficientresourcesareavailableunderextremeconditions.

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Under the currentPJM capacity construct, demand resourcesparticipate fully as a source of supply in thecapacityprocurementprocess,andtheRPMprovidescapacitycompensationfordemandresourcesthatclearinRPMauctionsinthesamemannerasclearedgenerationresourcesreceivecompensation.InlightoftheDCCourtofAppealsvacationofOrder745,PJMproposedchangespendingtheresolutionofOrder745 issuesthatwouldsignificantlyalter themanner inwhichdemandresourcescouldparticipate inRPM.Under thatproposal,thedemandcurveusedintheRPMwouldbealteredtoreflectoffersmadebywholesaleentitiestoreduceload.However,inMarch2015,FERCissuedanorderthatrejectedPJM’sfilingaspremature.

InthecaseofAmerenIllinoisandMidAmerican,MISOprovidestheabilityfordemandresponsemeasurestoreducesupplyrisk.OnMarch14,2014,FERCapprovedMISO’smodificationtoitsModuleE‐1tarifftotreatDRandEEresourcessimilarlytoothercapacityprovidingresourcesforoperationalplanningpurposes.

ThePJMandMISOcapacitymarketsareFERCjurisdictional,governedbytariffsfiledwithandapprovedbyFERC.TheDCCourtofAppealsvieweddemandresponsecompensationasinvolvingdirectregulationofretailmarketsandthusamatterexclusivelywithinstate jurisdiction.Thisdecision,whichiscurrentlybeforetheU.S. Supreme Court, could lead to a more comprehensive challenge to ISO‐supplied demand responsecompensation.Inthefuture, itmaynotbepossibletosimplyrelyonISOcapacitypaymentstocompensatedemand response providers. The role of states and state agencies in compensatingdemand responsemaybecome much more important. As this issue is resolved in the courts, the IPA will revisit it in futureprocurementplansasnecessary.

Chapter7ofthisplanprovidesdetailsandadditionaldiscussionregardingdemandresponseresources.


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7 ResourceChoicesforthe2015ProcurementPlan

ThisChapteroftheProcurementPlansetsoutrecommendationsfortheresourcestoprocurefortheforecasthorizon covered by this plan. These include: (1) incremental energy efficiency; (2) energy procurementstrategy; (3)balancingrecommendations;and(4)demandresponse.ProcurementofadditionalRenewableResources,includingwind,solaranddistributedgenerationisconsideredseparatelyinChapter8.

7.1 IncrementalEnergyEfficiency

As described in Section 2.6 of this Plan, Section 16‐111.5B of the Public Utilities Act requires the IPA toincludeinitsProcurementPlan,

[A]n assessment of opportunities to expand the programs promoting energy efficiencymeasuresthathavebeenofferedunderplansapprovedpursuanttoSection8‐103ofthisActortoimplementadditionalcost‐effectiveenergyefficiencyprogramsormeasures.150

TheIPAbasesitsassessmenton“anassessmentofcost‐effectiveenergyefficiencyprogramsormeasuresthatcould be included in the procurement plan” submitted to it by the utilities as part of their July 15th loadforecasts.151This annual assessment provided by the utilities is required to include the “[i]dentification ofcost‐effective energy efficiency programs or measures that are incremental to those included in energyefficiencyanddemand‐responseplansapprovedbytheCommissionpursuanttoSection8‐103ofthisAct,”152an “[a]nalysis showing that the new or expanded cost‐effective energy efficiency programs or measureswould lead to a reduction in the overall cost of electric service,”153and an “[a]nalysis of how the cost ofprocuringadditionalcost‐effectiveenergyefficiencymeasurescomparesoverthelifeofthemeasurestotheprevailingcostofcomparablesupply.”154

Section 16‐111.5B was originally enacted as part of Public Act 97‐0616, the Energy Infrastructure andModernization Act (“EIMA”), in 2011. Its provisions are meant to complement, enhance, and expand theutilities’ existing energy efficiencyprogramportfolios requiredby Section8‐103of thePublicUtilitiesActthroughtheinclusionintheIPA’sannualprocurementplansof“neworexpanded...incremental”programsthatwouldotherwisenotbeincludedintheSection8‐103portfoliosduetotheoperationofSection8‐103’s2.015%rateimpactcap.155Toidentifythese“incremental”programs,theutilitiesarerequiredto“conductanannual solicitation process for purposes of requesting proposals from third‐party vendors” developed“consistentwiththemannerinwhichitdevelopsrequestsforproposalsunderplansapprovedpursuanttoSection8‐103ofthisAct,whichconsidersinputfromtheAgencyandinterestedstakeholders.”156TheresultsofthatRFPprocessareprovidedtotheIPAaspartofeachutility’sassessment.Underthisstructure,theIPAthen “shall include” in its annual plan “energy efficiency programs and measures it determines are cost‐effective”157and the Commission “shall approve” those programs and measures “if the Commissiondeterminestheyfullycapturethepotentialforallachievablecost‐effectivesavings,totheextentpracticable,andotherwisesatisfytherequirementsofSection8‐103”ofthePUA.158

ThissectionincludesdiscussionrelatedtoprogramsandmeasureswhichtheIPArecommendsforinclusioninthe2016PlanaswellasdiscussionofotherissuesrelatedtotheoperationofSection16‐111.5B,includingthestatusofissuesdesignatedforworkshopdiscussionthroughpriorCommissionOrders.

150220ILCS5/16‐111.5B(a)(2).151220ILCS5/16‐111.5B(a)(3).152220ILCS5/16‐111.5B(a)(3)(C).153220ILCS5/16‐111.5B(a)(3)(D).154220ILCS5/16‐111.5B(a)(3)(E).155See220ILCS5/8‐103(d).156220ILCS5/16‐111.5B(a)(3).157220ILCS5/16‐111.5B(a)(4).158220ILCS5/16‐111.5B(a)(5).


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7.1.1 IncrementalEnergyEfficiencyinPreviousPlans

TheIPA’s2016ProcurementPlanisthefourthplantoincludeenergyefficiencyprogramsunderSection16‐111.5B.Table7‐1summarizesthetotalMWHofapprovedprogramsfromeachpreviousProcurementPlan.

Table7‐1:ProjectedSavings(MWH)fromSection16‐111.5BProgramsFromPriorIPAProcurementPlansandProposedinthisPlan

DeliveryYear AmerenIllinois ComEd

2013–2014(Approvedin2013Plan) 70,834 118,515

2014–2015(Approvedin2014Plan) 65,680 430,609

2015–2016 169,442 830,008

Approvedin2014Plan ‐ 547,904

Approvedin2015Plan 169,442 282,104

Movedfrom8‐103 88,203 247,648

Third‐PartyRFP 81,239 34,456

2016–2017 239,813 984,052

Approvedin2014Plan ‐ 611,958

Approvedin2015Plan 169,690 284,641

Movedfrom8‐103 93,569 241,541

Third‐PartyRFP 76,121 43,100

Proposedin2016Plan 70,123 87,453

The totalexpectedreductions listedaboveare thegross totals for theprogramsavailable toallpotentiallyeligible retail customers.159Please note, however, that the actual impact on IPA energy procurement eachyearisproratedtotheportionofthosecustomerswhoareactuallyeligibleretailcustomers(i.e.,takesupplyservice from ComEd or Ameren Illinois). See Sections 3.2.3 and 3.3.3 for a discussion of what portion ofpotentiallyeligibleretailcustomersareforecasttoactuallybeeligibleretailcustomers.

Asdemonstratedthroughthetableabove,prioryears’Planshavealsofeaturedcontractofferingsformorethan a single delivery year. For instance, for programs included in the 2014 Plan, ComEd allowed forcontracts for the upcoming three delivery years (2014‐15, 2015‐16, 2016‐17), resulting in the “projectedsavings” values for future years shown in Table 7‐1. Further discussion on the treatment of multi‐yearcontractsforthisyear’sPlancanbefoundinSection7.1.4.below.

The IPA’s 2015 Procurement Plan included the approval of eight expanded or new programs for AmerenIllinoisandtenforComEd.160Onesignificantaspectofthe2015Plan’s16‐111.5Bprogramportfoliowastheinclusion of residential lighting and behavioral programs. In a separate docket, the ICC ordered theseprogramsmoved from theSection8‐103EnergyEfficiencyportfolioofprograms to the Section16‐111.5Bprocess,thusallowingforadifferentportfolioofprogramsunderSection8‐103andcausinganexpansionof

159WhiletheIPAgenerallyprocuresonlyforthe“eligibleretailcustomers”ofparticipatingutilities,Section16‐111.5Bprogramsareavailableto“allretailcustomerswhoseelectricservicehasnotbeendeclaredcompetitiveunderSection16‐113ofthisActandwhoareeligibletopurchasepowerandenergyfromtheutilityunderfixed‐pricebundledservicetariffs,regardlessofwhethersuchcustomersactuallydopurchasesuchpowerandenergyfromtheutility.”(220ILCS5/16‐111.5B(a)(3)(C))160The2014ProcurementPlanincludedfiveexpandedornewprogramsforAmerenIllinois,andeightforComEd;the2013ProcurementPlanincludedeightexpandedornewprogramsforAmerenIllinoisandsevenexpandedornewprogramsforComEd.


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the budget and savings associated with the Section 16‐111.5B programs.161Similarly, for the 2014 Plan,ComEd significantly increased the size of its Section 8‐103 Small Business Direct Install program via theSection16‐111.5Bprocess,thusgrowingitsoverallSection16‐111.5Bportfolio.

The 2014 and 2015 Procurement Plans also discussed additional policy issues arising under Section 16‐111.5B. For instance, the2014Plan includeddiscussionof feedbackmechanisms, transition yearprogramexpansion, DCEO participation, and consideration of all third party bids.162In approving that Plan, theCommission’smostsignificantdecisionsweredeterminingthatDCEOisnotautilityforthepurposesoftheSection16‐111.5Bfilings,andtheapprovalofamethodologyfortheconsiderationofpotentiallyduplicativeandcompetingthird‐partyenergyefficiencyprograms.163

Initsdraftandfiled2015Plan,theIPAproposedprocuringanewsuper‐peakenergyefficiencyblockproductasasupplyresource(i.e.,asa“standardwholesaleproduct”procuredpursuanttoitsauthorityunderSection16‐111.5(b)(3)(iv) of the PUA).While the Commission declined to approve this proposal as a stand‐aloneprocurement strategy, it did approve the IPA’s alternative approach of allowing for modification of thesolicitationofthird‐partyprogramsunderSection16‐111.5Btotakeintoaccountthevalueofavoidingpeakenergyconsumption.164The2015Planalsorequestedtheapprovalofconsensuslanguagetakenfrom2014workshops and raised issues related to stakeholder participation in “duplicative” bid determinations forCommissionconsideration.

7.1.2 2015Workshops

In its Order approving the 2015 Plan, the Commission observed that “[a] significant problem withprocurementproceedings is the expedited schedule combinedwith a relatively largenumberof contestedissuesandparties,”makingit“difficultfortheCommissiontodealwithcomplexeconomicissues”suchastheSection16‐111.5Bissuesraisedbysomeparties.165Asaresult,theCommissionorderedthatmanycontestedissuesbefurtheraddressedthroughworkshopstobeheldin2015.Adiscussionofthestatusofthoseissues,andtheresultingworkshops,canbefoundbelow.

7.1.2.1 EnergyEfficiencyasaSupplyResourceWorkshops

As referenced above, the IPA included a primary and alternative proposal in its filed 2015 Plan for theprocurementofenergyefficiencyasasupplyresource. In itsFinalOrderapproving the2015ProcurementPlan,theCommissionconcludedthefollowing:

TheCommissionconcurswiththosepartiesthatsuggestenergyefficiencyisavaluabletoolandshouldbepursuedasamatterofpolicyandappreciatestheeffortsoftheIPAtopursueinnovative ideas. The Commission believes such efforts should be pursued pursuant toSection16‐111.5BofthePUAandherebyadoptstheIPA’salternativeproposaltoinformthedevelopment and evaluation of the RFPs for programs submitted for consideration in theIPA’s2016ProcurementPlan.

TheCommissiondirectsthepartiestocommenceworkshops,coordinatedbyStaff,topursuetheIPA’salternativeproposal,withsuchworkshopsbeginninginJanuaryandconcludingbymid‐February to allow the workshops to inform development of the RFPs. Among otherthings, thoseworkshops should considerwhether an additional RFP for energy efficiencyprogramswillbenecessary,thedurationofanysuchprograms,whethertheIL‐TRMshouldgovernthesetypesofprograms,andhowsuchprogramsshouldbeevaluated.Totheextent

161SeeDocketsNos.13‐0498(AmerenIllinois)and13‐0495(ComEd).162See2014IPAProcurementPlanat81‐86.163DocketNo.13‐0546,FinalOrderdatedDecember18,2013at149.164DocketNo.14‐0588,FinalOrderdatedDecember17,2014at157.165DocketNo.14‐0588,FinalOrderdatedDecember17,2014at224.


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practical,theCommissiondirectsComEdandAmerentoproposeenergyefficiencyprogramsconsistentwiththeIPA’sgoalswheneachprovidesitsenergyefficiencyproposalspursuanttoSection16‐111.5BofthePUAnextyear.166

ICC Staff coordinated workshops to pursue IPA's alternative proposal. While consensus was not reachedamong stakeholders on all issues related to the IPA’s alternative proposal,167the workshops did result inchangesmadetoAmeren’sandComEd’sRFPsissuedpursuanttoSection16‐111.5B(a)(3)andallowedforthereview of bid submissions using hourly energy values. Those changes also reflected consideration ofinterestedstakeholders'comments.

OnecontestedissueonwhichconsensuswasnotreachedwastheappropriatecontractlengthforSection16‐111.5B programs evaluated using hourly load profiles under the IPA’s alternative proposal. Duringworkshops some parties argued that the nature of programs available, and vendorswilling to participate,wouldbe limitedbyshortercontracts,especially theone‐yearcontractsbeingofferedthroughtheutilities’RFPs seekingprograms for the2016Plan.While the IPA tentativelyunderstands thatComEdandAmerenIllinoiswill likelybeofferingcontractsupto3yearsin lengthforSection16‐111.5Bprogramssolicitedforinclusion in the 2017 Plan (including peak‐hour oriented energy efficiency programs), the Agency wouldappreciatestakeholderperspectiveontheappropriatecontractlengthforprogramsfallingunderitsSection16‐111.5BalternativeproposalaspartofcommentsmadeonthisdraftPlan.

7.1.2.2 StakeholderAdvisoryGroupTRCSubcommitteeWorkshops

Section 16‐111.5B requires the IPA to include incremental “energy efficiency programs and measures itdeterminesarecost‐effective.”168UnderSection16‐111.5B,“theterm‘cost‐effective’shallhavethemeaningset forth in subsection (a) of Section 8‐103 of this Act,”169meaning “that the measures satisfy the totalresourcecosttest.”170Section1‐10oftheIPAActdefinesthe“totalresourcecosttest”asfollows:

"Totalresourcecosttest"or"TRCtest"meansastandardthatismetif,foraninvestmentinenergyefficiencyordemand‐responsemeasures, thebenefit‐costratio isgreaterthanone.Thebenefit‐costratioistheratioofthenetpresentvalueofthetotalbenefitsoftheprogramtothenetpresentvalueofthetotalcostsascalculatedoverthelifetimeofthemeasures.Atotalresourcecosttestcomparesthesumofavoidedelectricutilitycosts,representingthebenefits that accrue to the system and the participant in the delivery of those efficiencymeasures,aswellasotherquantifiablesocietalbenefits,includingavoidednaturalgasutilitycosts,tothesumofallincrementalcostsofend‐usemeasuresthatareimplementedduetotheprogram(includingbothutilityandparticipantcontributions),pluscoststoadminister,deliver, and evaluate each demand‐side program, to quantify the net savings obtained bysubstitutingthedemand‐sideprogramforsupplyresources. Incalculatingavoidedcostsofpowerandenergythatanelectricutilitywouldotherwisehavehadtoacquire, reasonableestimatesshallbeincludedoffinancialcostslikelytobeimposedbyfutureregulationsandlegislationonemissionsofgreenhousegases.

Since its introduction into the law in 2007, this definition has left many stakeholders grappling withquestionsaroundwhatcostsandbenefitsareappropriatetoincludeincost‐effectivenessdeterminationsandhow to appropriately quantify any such costs and benefits. In general, advocates for increased energy

166Ibid.167Amongtheissuesonwhichfullconsensuswasnotreachedincludethedefinitionof“super‐peak,”theappropriateprogram/contractlength,andthetreatment/definitionofdemandresponse.168220ILCS5/16‐111.5B(a)(4).169220ILCS5/16‐111.5B(b).170220ILCS5/8‐103(a).


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efficiency seek a more robust accounting of benefits and less for costs (increasing the number/scale ofprogramswhichhaveaTRCabove1.0),whilethose in favorof lessspendingonenergyefficiencyseektheinclusionofmoreorhighercostsandlessforbenefits(havingtheoppositeeffect).

In the docketed proceeding for the approval of the 2015 Plan, the Natural Resources Defense Council(“NRDC”)raisedanumberofissuesrelatedtohowTRCtestsareconducted,whatcostswerebeingincludedby theutilities,andwhetherallallowablebenefitswereproperlybeing taken intoaccount.171Inapprovingthe IPA’s 2015 Procurement Plan, the Commission directed SAG‐coordinated172workshops to considermultipleunresolvedissuesrelatedtothecalculationoftheTRC:

The Commission refers the three issues raised by NRDC to be addressed at workshopsconducted by the SAG. In the event the SAG is unable to conduct the workshops, forwhatever reason, the Commission directs the Staff to conduct theworkshops. Among thebroader issues to be explored in the workshops, the Commission specifically directs theparties toaddresswhyAmerendoesnotutilize itsbestestimateofmarginal line losses inplaceofaverage line losses,whichComEdalreadyutilizes.Additionally, thepartiesshouldaddress the possibly outdated literature relied upon by ComEd in its opposition to theinclusionofDRIPEintheTRCtest.TheCommissionalsofindstheAG’sargumentsregardingtheinclusionofDRIPEintriguing.Asnotedabove,procurementproceedingsarenottheidealforum for considering complex economic issues and the Commission urges the parties tomake serious efforts to reach consensus on at least some of these issues. While theCommission does not wish to open a proceeding for the purpose of addressing possiblechangesto theTRCtestat this time, itmaybenecessary if thepartiesareunable tomakeprogressintheworkshopforum.173

NRDCalsoarguesthatAmerenisoverstatingitsoverheadoradministrativecostsasusedinthe TRC test and notes that ComEd does not use a similar percentage adder whenperformingtheTRCtest.Amerendisagrees,whileStaffsuggestsAmerenshouldnotbeusinganygenericadderforallprogramsasadministrativecostsarelikelytovarybyprogramsizetypeandsize.TheCommissionfindsthequalityofevidencerelatingtothisissuelacking.Noparty presented evidence regarding Ameren specific overhead or administrative coststhough it isalmostcertain theyexist.Totheextent theutilitiesdonotexplicitlytrackthisinformation already, the Commission hereby directs Ameren and ComEd to trackadministrative costs by program in order to aid in future determinations of appropriateadministrative cost assumptions to use in the TRC analysis of the Section 16‐111.5Bprograms.TheCommissionrejectsStaff’ssuggestionsthatAmerenshoulduseavalueofzerofor a cost that almost certainly exists and could probably be estimated with reasonablecertainty.Asa result,while theCommissionmust rejectNRDC’s recommendationson thisissuebecause theyarenotsupportedbytherecord, theCommissiondirects theparties toaddressthisissueintheworkshopsdiscussedabove.174

AccordingtoStaff,theIPAindicatesitappreciatesthatSection16‐111.5B(a)(4)inisolationcould be understood to demand a more rigorous evaluation, even justifying the use ofevaluative criteria separate from criteria used to evaluate programs under Section 8‐103.StaffsaystheIPAsuggests intheprocurementplanthataworkshopcouldalsoconsider iftheIPAshoulddevelopandperformanindependentTRCcalculationwithdistinctinputsand

171Furtherdiscussionofthespecificissuesraisedinlastyear’sPlanlitigationcanbefoundinDocketNo.14‐0588andintheCommission’sFinalOrderinthatDocket,datedDecember17,2014at164‐179.172The“SAG”istheStakeholderAdvisoryGroupformedin2008tooverseetheimplementationofenergyefficiencyprogramsinIllinois.Formoreinformation,seewww.ilsag.info.173DocketNo.15‐0588,FinalOrderdatedDecember17,2014at224.174Id.at225‐226.


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assumptionsratherthanrelyingoninputsprovidedbytheutilities.(StaffBOEAttachmentAat 222) The Commission agrees that this would be a reasonable topic to address in theworkshopsdiscussedabove.175

To this end, the SAG established a Total Resource Cost (“TRC”) Test Subcommittee and led a series ofworkshopsovertheperiodofJanuary‐August2015,withplanstocontinueintoSeptember(andpotentiallybeyond). The workshops were held as a series of meetings, conference calls, and written requests forresponsestoquestions.Whileparticipantswerenotabletoreachagreementonall issues,someconsensusitemsdidemergefromtheworkshops.176

The IPAappreciates theeffortsof theSAGfacilitatorsandSubcommitteemembers toaddress these issues.Whiletherewasapronounced lackofagreementonkey issues,allparticipantsengagedfullyonthe issuesandprovidedsubstantialanddetailedinformationandarguments.Abriefdiscussionofeachofthoseissuesisincludedbelow.

7.1.2.2.1 UseofMarginalLineLosses

Thelinelossesavoidedbyenergyefficiencymeasuresareamongthe“avoidedelectricutilitycosts”includedinaTRCcalculation.Linelossesmaybecalculatedintwoways:averagelinelosses,whichareameasuredandpublishedfigure;ormarginallinelosses,whicharegenerallydeterminedbyusingactualsysteminformationand more detailed calculations. In Docket No. 14‐0588, NRDC argued that because line losses growexponentially with load and are most pronounced during peak hours, marginal line loss calculations arebetterabletoaccountforlinelossesasasquareoftheload.

ComEdhashistoricallyusedmarginallinelossesintheirTRCtests;thiswasComEd’sapproachforprogramssubmitted for the 2015Plan, and the sameheld true for the 2016 Plan. Alternatively, Ameren Illinois hashistorically incorporated average line losses in its TRC calculations. Through the TRC sub‐committeeworkshop process, parties agreed that for 2016 Plan program submissions, Ameren Illinois would useComEd’smarginal line loss information intheabsenceofmarginal line loss informationspecific toAmerenIllinois.TheTRCcalculationsprovidedbyAmerenIllinoisforthe2016Planthusreflectmarginallinelosses.

7.1.2.2.2 DemandReductionInducedPriceEffects(“DRIPE”)

Market energy prices are driven in large part by load levels, and reducing electric loads should lead to areduction in market prices. Energy efficiency programs and measures reduce consumption and, as aconsequence, reduce electric loads. In turn, these load reductions should lead to price reductions ingenerationratespaidbyelectricityconsumers(independentofdirectsavingsfrominstallationoftheenergyefficiency measures themselves), with reduced demand now operating in an environment of unchangedsupply.

Thatreducingconsumptionreducesmarketprices isnotanovelconcept(althoughquestionspersistaboutthemagnitude andpersistence of suchprice effects), nor is the concept that consumers achieve economicbenefit from reduced prices. In Docket No. 14‐0588, NRDC argued that those price effects from reduceddemand created by energy efficiency programs—known as demand reduction induced price effects, or“DRIPE”—shouldbeincludedasabenefitinutilityTRCcalculations.Citingthecomplexityofresolvingsuchissuesina90daydocket,theCommissiondirectedthattheissuebeaddressedthroughworkshops.

175Id.at226.176DraftTRCSubcommitteeReportdated6/11/2015,availableathttp://www.ilsag.info/subcommittees.html


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TheTRCsubcommitteereviewedtworeportsonDRIPE:onewasfromResourceInsightInc.;177anotherwasfrom Exeter Associates, Inc.178The subcommittee also heard commentary from, and asked questions of,technicalexpertsofferedbyeachsideoftheDRIPEdebate.

Despiteallparties’bestefforts,noconsensusonthe impactofDRIPEwasreached.Openquestions includewhetherorhowsuchpriceeffectsfitintothedefinitionof“benefits”foundinthestatutoryTRCtestdefinition(andwhetherDRIPEbenefits are, or needbe, reliably “quantifiable”), thepersistence ofprice effects fromdemandreduction,andwhetherempiricallyobservedpriceeffectsshowcausalityversusmerecorrelation.

TheTRCsubcommitteealsoreviewedinformationonotherstates’practices.Ofthetwelveotherrestructuredstates, seven (Connecticut,Rhode Island,Massachusetts,Maryland, theDistrictofColumbia,Delaware, andMaine) include DRIPE in their cost‐effectiveness screening of efficiency measures.179Though not arestructuredstate,VermontregulatorsalsoincludetheimpactsofDRIPEinneighboringrestructuredstatesintheirscreeningofthebenefitsofefficiencymeasuresinstalledintheirstate.

NeitherutilityincludedDRIPEbenefitsinitsassessmentofenergyefficiencyprogramsandmeasuresofferedforthe2016Plan.

7.1.2.2.3 UseofNon‐EnergyBenefitsinTRCTests

ThestatutorydefinitionoftheTRCtestdescribesacceptablebenefitsas“thesumofavoidedelectricutilitycosts, representing the benefits that accrue to the system and the participant in the delivery of thoseefficiencymeasures,aswellasotherquantifiablesocietalbenefits,includingavoidednaturalgasutilitycosts.”SomepartiesarguethatsomelessobviousbenefitsofenergyefficiencyprogramsmaybeaccountedforintheTRCevenifnotdirectlyrelatedtothesupplyofenergy(andareindeedenvisionedbylawtobeincorporatedthroughlanguagedirectingtheinclusionof“otherquantifiablesocietalbenefits”).

Such benefits are known as non‐energy benefits, or “NEBs.” NEBs may incorporate several differentcategoriesofbenefitsfromenergyefficiencyprograms:

Environmental adders – specifically, reductions in SOx,, NOx, and, other air pollutants andemissions180

Water–Resourcebenefit SocietalImpacts–health,safety,comfort,buildingdurability,etc. O&Mcostavoidance Economic–Jobcreation ParticipantPerspective –water and sewer savings, fewer shutoffs, fewer calls to theutility, fewer

reconnects,propertyvaluebenefits,fewerfires,reducedmovingcosts,fewerillnessesandlostdaysfromworkorschool,netbenefitsforcomfortandnoise,andnetbenefitsforadditionalhardship.

Positioned for consideration by the TRC subcommittee was which non‐energy benefits (NEBs) should beincludedintheIllinoisTRCcalculation,howtheyshouldbequantified,andwhethertheyshould—orcould—bequantifiedbyprogram/measuretype.181Areviewofotherstatepracticesshowedthatsomestateelectric

177“AnalysisofElectricEnergyDRIPEinIllinois”,ResourceInsight,Inc.,Sept3,2014.178“AssessmentoftheCostsAvoidedthroughEnergyEfficiencyandConservationMeasuresinMaryland,”ExeterAssociates,Inc.,April2014.179http://ilsagfiles.org/SAG_files/Subcommittees/IPA‐TRC_Subcommittee/6‐16‐2015_Meeting/DRIPE_Comparison_Exhibit_2015_Final_Draft.pdf180CarbondioxidesavingsareaddressedseparatelyandmoreexplicitlyunderIllinoislaw,astheTRCdefinitionrequiresthat“reasonableestimatesshallbeincludedoffinancialcostslikelytobeimposedbyfutureregulationsandlegislationonemissionsofgreenhousegases.”(20ILCS3855/1‐10)181Bywayofexample,NRDChasproposedusinga15%defaultnon‐lowincomebenefitsadderanda30%defaultlowincomebenefitsadder—demonstratingamarkedincreaseinnon‐energybenefitsassociatedwithprogramstargetedtowardlow‐incomehouseholds.


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efficiencyprogramsusevaryingcostsforNEBsrangingfrom10to30percent;182othersalsoincludeapriceforcarboninadditiontotheNEBspercentage.183

Noconsensuswasreachedontheappropriatetreatmentofnon‐energybenefitsforthe2016Plan,althoughagreementappearstohavebeenreachedthatnon‐energybenefitswillbeconsideredforinclusioninthenexteditionoftheTechnicalReferenceManual(“TRM”)onameasure‐specificbasis.

7.1.2.2.4 ApplicationofAdministrativeCostsinTRCTests

Turning to the cost side of the TRC ledger, an additional topic left to the TRC subcommittee concernedadministrative costs associated with Section 16‐111.5B incremental energy efficiency programadministration. In Docket No. 14‐0588, NRDC contested Ameren Illinois’ application of a blanket 15%administrativecostadderappliedtoallSection16‐111.5Bprograms,believingthatsuchcostswereinflatedandborelittleconnectiontotheactualcostsofadministeringtheprogramsbeingevaluated.TheCommissionresolvedtheissuewiththefollowingstatement:

NRDCalsoarguesthatAmerenisoverstatingitsoverheadoradministrativecostsasusedinthe TRC test and notes that ComEd does not use a similar percentage adder whenperformingtheTRCtest.Amerendisagrees,whileStaffsuggestsAmerenshouldnotbeusinganygenericadderforallprogramsasadministrativecostsarelikelytovarybyprogramsizetypeandsize.TheCommissionfindsthequalityofevidencerelatingtothisissuelacking.Noparty presented evidence regarding Ameren specific overhead or administrative coststhough it isalmostcertain theyexist.To theextent theutilitiesdonotexplicitly track thisinformation already, the Commission hereby directs Ameren and ComEd to trackadministrative costs by program in order to aid in future determinations of appropriateadministrative cost assumptions to use in the TRC analysis of the Section 16‐111.5Bprograms.184

While theutilities are beginning to take steps toward tracking administrative costs byprogram, program‐specificadministrativecost information forprogramssubmitted for inclusion in the2016Planhasnotyetbeendeveloped.Asaresult,someestimationofadministrativecostsmustonceagainbeapplied.

In addressing this issue, one proposed solution raised by TRC Sub‐committee identified the followingcategoriesofadministrativecosts:

Category1:EM&V–will add to each IPAprogram (3%).Utilitywill take3% fromeachprogramselected,lumptogether.

Category2:ProgramManagement–(3‐4%)Utilitywilltakeprogram‐specificandwillbeallocatedtoprogramsinscreening.Othermanagementadmincosts,invoicing,etc.willbeallocatedbasedonprogrambudget.

Category 3: Increase in other Admin: Marketing, General Admin, other non‐assignable –(Approximately4%)AssignablewillbeallocatedtoIPAprogramsbasedonprogrambudgets.Non‐assignable (RFP, regulatory approval, legal, potential studies, etc.) will be allocated across theportfolio.Utilitieswilltrackthesecosts.Therewasnon‐consensusonwhethertoincludethesecostswhenscreeningIPAprograms.

182SeetheSAGwebsiteathttp://www.ilsag.info/subcommittee_ipa‐trc.htmlformoreinformationonhowotherstatescalculateNEBs.183Again,asnotedabove,IllinoislawrequiresthatTRCtestsinclude“reasonableestimates...offinancialcostslikelytobeimposedbyfutureregulationsandlegislationonemissionsofgreenhousegases.”(20ILCS3855/1‐10)184DocketNo.14‐0588,FinalOrderdatedDecember17,2014at224.


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TheTRC Sub‐Committee discussed the idea that the utilities could screen bothwith 7%and11%blanketadministrativecostratesandreportthosenumberstotheIPAforprogramreview.185Theprogramsactuallysubmitted to the IPA for review featuredutility administrativecost screeningsusingdifferent, and slightlyhigher, values. The administrative costs used by Ameren and ComEd in TRC screenings can be found inSections7.2.3.7and7.2.4.4,respectively.

7.1.2.2.5 IndependentTRCTestsbyIPA

Section 16‐111.5B of the PUA requires that the IPA include in its procurement plan “energy efficiencyprogramsandmeasures itdeterminesarecost‐effective” (emphasisadded).186However,Section16‐111.5Benergyefficiencyprogramsandmeasuresareinitiallyidentifiedandreviewedbytheutilitiesandsubmittedto the IPA through an assessment process including initial determinations made as to cost‐effectiveness.Perhaps more importantly, Section 16‐111.5B(b) requires that “the term ‘cost‐effective’ shall have themeaningsetforthinsubsection(a)ofSection8‐103ofthisAct,”leavingquestionsastothedegreetowhichthe IPA could adopt an approach to cost‐effectiveness screening distinct from that already applied by theutilitiesunderSection8‐103.

TheissueofwhethertheIPAcan(andshould)performanindependentTRCcalculation,withdistinctinputsandassumptions(ratherthanrelyingoninputsprovidedbytheutilities),wasputtotheTRCsubcommitteefor further discussion and review. By consensus, the subcommittee determined that IPA does not need toperform independent cost‐effectiveness screening with truly independent inputs, assumptions, andmethodology,butmustindependentlyreviewassumptions.

Assuchareviewrequiresnecessary information fromtheutilities, theTRCsubcommitteealsodeterminedthattheutilitiesaretoprovideasummaryofthecontentoftheircost‐effectivenessscreeningmodelandthebasisforanycostandbenefitassumptions.

7.1.3 PriorYearConsensusItems

The2014Plan includedanumberofconsensus items from ICCstaff‐ledworkshopsand the IPArequested(andreceived)Commissionapprovalofthoseitems.187Theconsensusitemsincluded:

Bothnewandexpandedprogramsmaybeapprovedforuptothree‐yearincrements. DCEOmaybidprograms intotheutility‐runRFPsandshouldpass theTRCtestas indicated in the

legislation. AnyutilitysavingsgoalspursuanttoSection8‐103andcontractorperformance“goals”pursuantto

Section16‐111.5Bareseparateandnon‐transferrable.Budgetsshouldalsobekeptseparate. Utilities should provide the IPAwith all bids to the RFP (on a confidential basis) so the IPAmay

independentlyevaluatethebids. TheIPAalsobelievesthatpartiesshouldworkcollaborativelyoncontractprinciples forsuccessful

bidders,whichmayincludepay‐for‐performancelanguageandgranttheutility“flexibility”torewardsuccessfulprogramswhileminimizingresourcesspentonunsuccessfulprograms.

The2015Plan includedanumberofconsensus items fromthestaff ledworkshopsand the IPArequested(andreceived)Commissionapprovalofthoseitems.188Theconsensusitemsincluded:

DeemingandEvaluationforFutureSection16‐111.5BEnergyEfficiency(“EE”)Programs

185http://ilsagfiles.org/SAG_files/Subcommittees/IPA‐TRC_Subcommittee/6‐16‐2015_Meeting/SAG_TRC_Subcommittee_Attendees‐and‐Meeting‐Notes_6‐16‐2015_Final_Draft.pdf186220ILCS5/16‐111.5(a)(4).187SeeAppendixB‐2fortheICCStaffreportontheworkshops.188Ibid.


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Deeming and Evaluation for Previously Approved Section 16‐111.5B EE Programs, Program Year(“PY”)6andPY7

Responsibleentity Policy or Clarity on Status of Bid Accepted into IPA Procurement Plan and Approved by the

CommissionandFlexibility ContinuityforMulti‐YearEEPrograms EvaluationBudgetandProcessEvaluations

TheAgencyrequeststhattheCommissionreaffirmitspastapprovaloftheconsensusitemsfromprioryears’workshops.Further, theAgencyrequests thattheCommissionapprovesuch itemsprospectively,expresslyallowingfortheirapplicationtothe2016RFPsolicitationandbidevaluationprocess.

7.1.4 PolicyIssuesforConsiderationinthe2017Plan

In this draft 2016 Plan, the IPA seeks feedback from stakeholders on two items that could result in theCommissiongivingtheIPAandutilitiesusefuldirectionforthedevelopmentofthe2017Plan.

ThefirstissueistheprocessbywhichtheutilitiesscreenbidsreceivedintheRFPprocess.Initssubmittal,AmerenIllinoisappliedthescreeningforduplicativeprogramspriortotherunningoftheTRCanalysis,whileComEddidtheopposite.WhiletheIPAappreciatesthetimeandeffortrequiredtoconductaTRCanalysis,theIPA believes it is preferable to conduct the TRC screening on every bid that complies with the basicrequirementsof theRFP, and then conduct anyother screening (e.g., forduplicativeprograms) thereafter.WhileitcouldbearguedthattheRFPsrequirethebiddertoassessiftheirproposalisduplicativeofexistingprograms, that assessment is sufficiently subjective that it should be treated differently from other RFPrequirements. Having a complete record of TRC analyses submitted by the utilitieswill aid the IPA in itsreviewofprogramsforconsiderationforinclusioninthePlan.

ThesecondissueconcernshowSection16‐111.5Bprogramsmaybeusedto“expand”aportfolioofSection8‐103programs thathavenot yetbeenapprovedby theCommission. For the2017ProcurementPlan tobedevelopedduringthesummerof2016(incorporatinginformationfromutilityassessmentssubmittedtotheIPAonJuly15,2016),thisissuewillbefrontandcenter:theutilitieswillbefilingtheirnextsetofthree‐yearplans in the Fall of 2016 and therefore there will not be a set of existing (and approved) Section 8‐103programsagainstwhich the incrementalprogramswouldbe considered.Consequently, the2016Plan andassociatedcommentperiod (which informsanyprogramssubmitted for2017) is the idealopportunity forthisdiscussion.

IntheICCStaff‐ledworkshopconductedin2013aspartoftheprocessleadinguptothedevelopmentofthe2014Plan, the issueofmultiyearprogramswasextensivelydiscussed, includinghowitwouldrelatetothethree‐yearplanningcycleoftheSection8‐103energyefficiencyprograms.Noclearresolutionwasreachedandthe2014Planstatedthat“[i]nanticipationofthethistriennialissue,alegislativechangetoeitherSection16‐111.5Bor8‐103wouldlikelybenecessarytocreateamechanismforutilitiestoseekexpansionofSection8‐103programsthroughtheSection16‐111.5Bprocess,ratherthanseekingapprovalfornewprogramsonlywhen an 8‐103 three year plan is awaiting Commission approval.”189No such legislative change has beenenactedatthistime.

The IPA believes that an approach that will guarantee the inclusion of third‐party bids for multi‐yearprograms(three‐years,orperhapseven longer)wouldbedesirable. If strongthird‐partybidsarereceivednext year, they could have an opportunity to be included with fewer (or no) constraints related to thescreeningoutofduplicativeprograms.Byallowingthecompetitivemarkettosuggestcost‐effectiveprograms

1892014ProcurementPlanat84.


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throughtheRFPprocess,theopportunitiestogrowtheenergyefficiencysectorinIllinoiswillbeexpanded,leadingtoadditionaljobcreationandbenefitsforcustomers.

7.1.5 AmerenIllinois

Ameren Illinois’ submittal to the IPAprepared in compliancewith sections16‐111.5and16‐111.5Bof thePUAisincludedinAppendixBofthisPlan.Thesubmittal includesnineappendiceswhichmaybefoundontheIPAwebsitepostingofthe2016ProcurementPlanatwww.illinois.gov/ipa.ThreeoftheAppendices(6,8,and9)inAmerenIllinois’submittalcontainconfidentialdataandarenotincludedintheAppendicesofthisPlan.

TheIPAbelievesthatAmerenIllinois’submittalmeetstherequirementsofSection16‐111.5B(a)(1)‐(3)andthattheprogramsidentifiedas“cost‐effective”shouldbeapprovedpursuanttoSection16‐111.5B(a)(5).

7.1.5.1 AmerenIllinoisBidReviewProcess

AmerenIllinoisreceived32bids—10fortheresidentialsector,and22forthebusinesssector.Oneresidentialbidderwithdrewtheirbid,andthreebidders(oneresidential,twobusiness)didnotprovideinformationtoresolveincompleteaspectsoftheirbidsandthuswereremovedfromconsideration.

Of the 28 remaining bids, Ameren Illinois and a stakeholder review committee190determined that tworesidential bids andnine business bidswere duplicative of existingAmeren Illinois programs. Four of theduplicative bids were considered duplicative of existing DCEO programs and were included in the bidevaluation as discussed below. One of the business bids was withdrawn during the subsequent reviewprocess, leaving 19 bids for consideration. Additionally, one of the bids that was initially identified asduplicativeofDCEOprogramswassubsequentlydeterminedtobenotduplicative.

In conjunction with the bid analysis conducted by Ameren Illinois and stakeholders, Ameren Illinois’consultantAEGalsoperformedanalysisonthebids.Alldocumentssubmittedbythebidderswerereviewedincluding the program proposal, measure information spreadsheet, and any supporting documentation.AccordingtoAmerenIllinois, theconsultant’sworkoperatedasfollows:AEGreviewedthedetailedsavingscalculations provided by the bidders then independently calculated savings for each individual measurewhereaTechnicalReferenceManual(“TRM”)191equationisapplicabletoverifycompliancewiththeTRM.Iftheresultsmatched,compliancewasverified.IfAEGfoundminordiscrepanciesinthebidderequationsthatwerenotincompliancewithTRMVer.4.0,AEGadjustedthesavingssotheywereincompliance.Ifthereweremajordiscrepancies,AEGwentbacktothebiddertogathermoreinformationonassumptionstodeterminewhy thereweredifferences from thebidder savingsandTRMcalculations. In all but twocases, the issueswereresolvedandAEGwasabletoverifyTRMcompliantsavings.192 IntheinstanceswhereAEGcalculationsdifferedfromthebiddercalculations,theAEGindependentlycalculatedsavingsvalueswereutilized.

EightbidsdidnotpasstheTRCand11bidspassedtheTRC.Ofthe11thatpassed,twoweredeterminedtobeduplicativeofDCEOprogramsandwerenotincludedbyAmerenIllinoisinitslistofprogramsforinclusioninthePlan.FurtherdiscussionoftheprogramsthatwereduplicativeofDCEOprogramsisincludedbelow.

190TheCommitteeincludedEnvironmentalLawandPolicyCenter,NRDC,andDCEO.ICCStaffalsoparticipatedinthereviewprocess.TheIPAnotesthatAmerenIllinoisappearstohavemoreextensivelyengagedstakeholdersinthisyear’sreviewprocessthaninpastyears.191TheTRMisaguidancedocumentdevelopedthroughtheSAGprocessandapprovedbytheCommission.Itprovidesstandardvaluesandmethodologiesforcalculatingsavingsandimpactsfromenergyefficiencymeasuresandprograms.192OnebidderdidnotagreewiththeIL‐TRMIn‐ServiceRate(ISR)andanotherbidderdidnotagreewiththeIL‐TRMhoursofuseassumedintheanalysisthoughfurtherdiscussionsdidnotresolvethedisagreementasAmerenIllinoisnotedintheRFPthatallapplicableIL‐TRMvalueswouldbeusedintheanalysis.


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7.1.5.2 ReviewofAmerenIllinoisTRCAnalysis

The IPA reviewed theTRC analysis provided byAmeren Illinois (using theBENCOST tool) and, subject toexceptions described in the sections below, generally concurred with the inputs, assumptions, andmethodology.

AmerenIllinoisdoesnothaveamarginallinelossstudyapplicabletoitsserviceterritory,sofortheanalysesforthissubmission,AmerenIllinoismirroredComEd'smarginallossanalysisstudywhichshowedanannualmarginaldistributionlossthat is1.65timestheaveragedistributionloss.AmerenIllinoisappliedthisratiotimes their average distribution losses to arrive at estimatedmarginal line losses. Going forward, AmerenIllinoishasdemonstratedinterestincompletingamarginallinelossstudyinthefuturetomakesurethecostsare accurate. This approach is now consistent with the methodology used by ComEd and the approachadvocatedforbyNRDCduringconsiderationofthe2015Plan.

AmerenIllinoisemployedablanketadministrativecostadderof13.58%toallprograms,andprovidedonlyrudimentary information on how that 13.58% figure was reached.193In its submittal, Ameren Illinoisexplainedthecostsas“3.5%forEvaluation,Measurement&Verificationactivities("EM&V"),5%forprogramimplementation oversight; portion of the costs to conduct the potential study (estimated at $1.5million),~3%foreducationandawarenessactivitiesaswellasplanning,assessmentandtrackingoftheprograms,asrequiredunderSection5/16‐111.5B.”

Administrativecostswereacontestedissueinthelitigationofthe2015Plan.InresponsetoargumentsthatAmeren Illinois’ blanket administrative adder of 15% was both inflated and inadequately justified, theCommission directed the utilities “to track administrative costs by program in order to aid in futuredeterminationsofappropriateadministrativecostassumptions.“194Inlightofthisdirective,theIPAbelievesthat including fixed, non‐incremental, non‐program‐specific costs in the TRC calculation such as those forAmeren’s potential study (the development of which is a standalone requirement under Section 16‐111.5B(a)(3)(A), and must occur whether Ameren Illinois administers 10, 30, or zero energy efficiencyprograms) is inappropriateand inconsistentwiththedirection takenbytheCommission inDocketNo.14‐0588. If unidentified costs and costs associated with Ameren Illinois’ potential study are removed, theadministrative cost adder would then constitute 11.5% ‐‐ coincidentally, the same amount reported byComEdinitssubmittals.Section7.1.5.5liststheTRCresultsassubmittedbyAmerenIllinois,andtheTRCasadjustedbytheIPAtoreflectan11.5%administrativeadder.

Forits2016Plansubmittal,AmerenIllinoisremoveditsprior‐appliedblanketadderforNon‐EnergyBenefits(“NEBs”) from the TRC.195This is somewhat similar to ComEd’s approach, as ComEd does not include ablanket NEB adder (ComEd does, however, include somemeasure‐specific adders as described further inSection7.1.6.2).AccordingtoAmerenIllinois,theremovalofanon‐energybenefitsadderwasinresponsetofeedback during the bid review process from ICC staff. Ameren also did not include DRIPE (see Section7.1.2.2.2aboveforadiscussionofthisissue)initscalculations.

TheIPAconductedasensitivityanalysisoftheAmerenIllinois‐providedTRCresultslookingattheimpactoftheadministrativeaddersetat0%(asdonebyComEd),7%,and11.5%asdescribedabove,and13.58%asproposed by Ameren Illinois; and through including or excluding NEBs at Ameren Illinois’ prior‐appliedlevels. Various combinations of these adjustments only impacted the TRC results of three programs thatwouldhaveotherwisefailedtheTRC.Intwoofthecases,addinginNEBswouldhaveincreasedtheTRCtoabove1.0evenwitha13.58%administrativeadder(risingfrom0.97to1.06,andfrom0.93to1.02).Without

193AppendixB,AmerenIllinoisSection16‐111.5BSubmittalat9‐10.194DocketNo.14‐0588,FinalOrderdatedDecember17,2014at224.195TheIPAunderstandsAmerenIllinoisashavingpreviouslyuseda10%blanketadderforelectricsavingsanda7.5%adderforgassavings,includinginlastyear’sSection16‐111.5Bfiling.


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NEBs,bothofthoseprogramswouldfailtheTRCtestwithan11.5%ora7%administrativeadder,butwouldbothpasswitha0%administrativeadder(at1.0and1.05respectively).ThethirdprogramwouldonlypasstheTRCtestwithNEBsincludedanda0%administrateadder.

ForpurposesofthisdraftPlan,theIPAhaschosennottoincludethesethreeprogramsinitsrecommendedprograms for inclusion,but invites interestedparties to commentonwhatadministrativeadder shouldbeused,andifaNEBsaddershouldbeincluded(andifso,atwhatlevel).Basedoncommentsreceived,theIPAwillconsiderifitsrecommendationshouldchangeorremainthesame.

Asdescribedabove inSection7.1.5.2,AmerenIllinois(through itsconsultantAEG)adjustedcertainnet‐to‐gross ratios provided by bidders tomore accurately reflect values in the Illinois TRM. Those adjustmentsappeartobereasonabletotheIPA.

TheIPAobservesthatfewerprogramspassedtheAmerenIllinoisTRCscreeningthantheComEdscreening.While this couldbe a functionof thebids receivedor theTRCmethodologyapplied, it appears that lowerenergyandcapacitypricesintheAmerenIllinoisserviceterritorysimplymakethetestmoredifficulttopass.

7.1.5.3 ProgramsforwhichAmerenIllinoisassertsthecostexceedsthecostofsupply

As described in Section 7.1.2.2 of the Plan, Section 16‐111.5B of the PUA requires the IPA to includeincremental“energyefficiencyprogramsandmeasuresitdeterminesarecost‐effective.”196UnderSection16‐111.5B, “the term ‘cost‐effective’shallhavethemeaningset forth insubsection(a)ofSection8‐103of thisAct,”197meaning“thatthemeasuressatisfythetotalresourcecosttest.”198

Thetotalresourcecosttestisadistincttestfromthe“costofsupply.”Nevertheless,inits2016Plansubmittal,AmerenIllinoissuggeststhattwoprogramswhichpasstheTRC(evenusingAmeren’ssuggestedinputsandinput levels) should still be excluded “because the estimated costs of suchprogramsarenot less than theprevailingcostofsupply.”199

TheIPAdisagreeswiththisapproach.IllinoislawrequirestheinclusionofprogramsthattheIPAdeterminestobe“cost‐effective”throughapplicationof theTRCtest.AmerenIllinoisbasedtheirsuggestiononSection16‐111.5B(a)(3)(E), which requires the utilities to include an “analysis of how the cost of procuringadditionalcost‐effectiveenergyefficiencymeasurescomparesoverthelifeofthemeasurestotheprevailingcostofcomparablesupply”aspartoftheirSection16‐111.5Bsubmittal.However,thisrequirementdoesnotcreateindependentgroundsfortheexclusionofotherwisecost‐effectiveprogramsinanIPAPlan.Indeed,theCommission is likewisedirected to “approve theenergyefficiencyprogramsandmeasures included in theprocurementplan,includingtheannualenergysavingsgoal,iftheCommissiondeterminestheyfullycapturethe potential for all achievable cost‐effective savings, to the extent practicable, and otherwise satisfy therequirementsofSection8‐103ofthisAct.”Thisstatutorycost‐effectivenessthresholdcannotsimplybereadoutofthelawinfavorofautility’spreferredalternativeapproach.200

In addition, how to interpret “the prevailing cost of comparable supply” language found in Section111.5B(a)(3)(E)hasalreadybeenaddressedbypartiesthroughtheworkshopprocess.AscanbefoundintheStaffReportsummarizing the2013Section16‐111.5Bworkshops, this language“canbe interpretedas the

196220ILCS5/16‐111.5B(a)(4).197220ILCS5/16‐111.5B(b).198220ILCS5/8‐103(a).199AppendixB,AmerenIllinoisSection16‐111.5BSubmittalat22.200Initssubmittal,AmerenIllinoisreliesonthephrase“totheextentpracticable”asjustificationforfashioningnon‐statutorylimitationsonprograminclusion,andthenconflates“practicable”(usedonlyinitiallyintheirsubmittalwhenquotingthelaw)with“practical”(usedinsteadthroughoutitssubmittal).While“practicable”refersto“capableofbeingaccomplished,”“practical”meansto“beinglikelytobeeffective.”Acost‐effectiveprogramsubmittedincompliancewithRFPrequirementsisunquestionablypartofaportfoliointendedto“fullycapturethepotentialforallachievablecost‐effectivesavings,totheextentpracticable.”Theremaybe“practical”reasonsforautilitytoseekaprogram’sexclusion,butasSection16‐111.5Bfailstousetheterm“practical,”thosefindnosupportinthelaw.


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totalresourcecost test.”201Asthe“costofsupply”analysisconductedbyAmerenIllinoisdidnotfollowtheestablishedstricturesofthetotalresourcecosttest(forinstance,bynotincludingavoidedtransmissionanddistributioncostsfortheproposedcost‐effectiveenergyefficiencymeasures,despitesuchcostsclearlybeingavoided),itappearstobeinconsistentwiththeconsensusapproachdecideduponin2013.

Basedontheforegoing,theIPAdeclinestoadoptAmerenIllinois’recommendationregardingtheexclusionofcost‐effectiveenergyefficiencyprogramswhichexceedthe“costofsupply”butpassthetotalresourcecosttestrequiredforevaluationbythelaw.

7.1.5.4 ReviewofDuplicativePrograms

InthedocketapprovingtheAgency’s2014Plan,significantconsiderationwasgiventohowtoaddressthird‐partyprogrambidsthatmaybe“duplicative”ofexistingprogramsunderSection8‐103ofthePUA.Basedonprioryears’Plans, theIPAunderstandstheterm“duplicative”tomeanaprogramthatoverlapsanexistingprograminamanner inwhichgreatermarketparticipationbyvendorsdoesnotyieldsufficientadditionalvalue to consumers, “competing” programsmay benefit frommultiple delivery channels. The general goalwouldbethat“duplicative”programsaretobeavoided,while“competing”programswouldbeacceptabletotheextentthatthecompetitiondoesnotrenderoneorbothnon‐costeffective.

ThereviewprocessforduplicativeorcompetingbidsapprovedbytheCommissionworksasfollows:

First,theutilitiesreceiveandreviewthethirdpartyRFPresults,anddeterminewhichbidsare,intheutility’s estimation, duplicative or competing. The utilities are under no obligation to identify anyprogramsinthismanner.

Next,intheannualJuly15assessmentsubmittedtotheIPA,theutilitymayexcludeprogramsithasdetermined are duplicative or competing from the estimated savings calculation (and associatedadjustments to the load forecast). However, in their submittals to the IPA, the utilities must: (1)describetheduplicativeorcompetingprogram;(2)explainwhytheutilitybelievesitiscompetingorduplicative;and(3)providetheIPAwithalloftheunderlyingdocumentsasitwouldforanyotherbid.

Inpreparingitsannualprocurementplan,theIPAindependentlyreviewsallofthebidssubmittedbythe utilities and determine which bids the IPA believes are duplicative or competing. The IPAidentifies all proposed programs to the Commission in its Procurement Plan filing, along with arecommendationonwhich,ifany,programsshouldbeexcludedasduplicativeorcompeting.

AfterthePlanhasbeenfiled,thepartiestotheProcurementPlanapprovallitigation—includingtheIPA—mayopineonwhetheraparticularprogramisduplicativeorcompeting,andtheCommissionwill make the final determination. To the extent that a utility had previously determined that aprogram is duplicative or competing but the Commission disagrees, the utility will update theestimatedenergysavingsandloadforecasttoreflectthereadmissionoftheprogram.202

Inadditiontoaddressingtheprocessfordeterminingwhetheraprogramis“duplicative”or“competing,”theCommissionalsoapprovedamulti‐factorinquirytobeemployedinmakingsuchdeterminations:

(1)similarityinproduct/serviceoffered;(2)marketsegmenttargeted,includinggeographic,economic,andcustomerclassestargeted;(3)programdeliveryapproach;(4)compatibilitywith other programs (for instance, a program that created an incentive to accelerate the

201http://www.icc.illinois.gov/downloads/public/ICC%20Staff%20Report%20Summary%20of%20Section%2016‐111.5B%20EE%20Workshops%202013‐08‐02.pdf202DocketNo.13‐0546,FinalOrderdatedDecember18,2013at149.


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retirementofolderinefficientappliancescouldclashwithadifferentprogramthattunes‐upolder appliances ); (5) likelihood of program success (a proven provider versus anundercapitalizedorunderstaffedprovider,ifsuchevidenceisplacedintherecord);(6)theeffect(s) on utility joint program coordination, and (7) impact on Section 8‐103 EEPSportfolioperformance.203

The IPAconcurswith thedeterminationsofAmerenIllinoisand itsStakeholderreviewcommitteethatthefollowingprogramsmeet theduplicative standard setout inpreviousProcurementPlansandCommissionOrders.ThereforetheIPAdoesnotrecommendtheapprovaloftheseprograms.

Table7‐2:AmerenIllinoisDuplicativeProgramScreeningSector Program ReasonDuplicative

Residential DirectInstall–LEDandSmartStrips DuplicativewithAmerenIllinoisSection8‐103HomePerformanceand HVAC Programs, and DCEO Section 8‐103 Low IncomeProgram

Residential SchoolKits DuplicativewithAmerenIllinoisSection8‐103SchoolKitsProgramBusiness DirectInstall‐LEDOnly DuplicativewithAmerenIllinoisSection16‐111.5BSmallBusiness

DirectInstallProgramBusiness DirectInstall‐PrivateSchools DuplicativewithAmeren Illinois Section8‐103StandardProgram

andAmerenIllinoisSection16‐111.5BSmallBusinessDirectInstallProgram

Business DirectInstall‐Geo‐Targeted DuplicativewithAmeren IllinoisSection16‐111.5BSmallBusinessDirect Install Program and DCEO Section 8‐103 Direct InstallProgram

Business DirectInstall‐WholeBuilding DuplicativewithAmerenIllinoisSection16‐111.5BSmallBusinessDirect Install Program, Ameren Illinois Section 8‐103 StandardProgram,andDCEOSection8‐103STEPProgram

Business RuralEfficiencyKits DuplicativetoAmerenIllinois8‐103StandardProgram

TwoadditionalprogramswereconsideredduplicativeofcurrentDCEOprograms,forwhichfuturefundingisuncertain. Both programs target public buildings. The Direct Install – Public Facilities program was alsoconsideredtobepotentiallyduplicativeoftheexistingSmallBusinessdirectinstallprogram.

Table7‐3:AmerenIllinoisProgramsDuplicativeofDCEOPrograms

Program NetSavings(MWh)TotalUtility

CostTRC

DirectInstall‐PublicFacilities 29,314,681 $6,614,516 1.31SavingsthroughEfficientProducts 2,770,617 $776,553 1.09

Ifincluded,theseprogramswouldbeduetostartJune1,2016.TheStateFiscalYearrunsfromJuly1toJune30thofeachyear;thusthefirstmonth(andanyassociatedpreparationtime)ofDCEO’scurrentprograms(ofwhich the programs identified above may be duplicative) falls into the current Fiscal Year July 1, 2015throughJune30,2016.AtthetimeofthereleaseofthisdraftPlan,DCEO’sbudgetforthecurrentFiscalYearhasnotyetbeenenacted.Withoutthatbudgetinplace,itisunclearwhetheranyfundingisavailableforDCEOtorunenergyefficiencyprogramsinthecurrentFiscalYearorwhatthecascadingrepercussionsmaybeonfollowingFiscalYears.

7.1.5.5 AmerenIllinoisProgramsRecommendedforApproval

AmerenIllinois’submittalincludesidentificationofnineenergyefficiencyofferingsforthisProcurementPlanwithaTRCofabove1.0,whichwerenotdeterminedtobe“duplicative”ofexistingprograms,andwhichmet

203Id.


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therequirementsofAmerenIllinois.AllnineoftheseprogramspassedtheTRCtestatthetimeofassessment,evenwithoutadjustmentsmadetoAmerenIllinois’suggestedTRC.204TheseprogramsareexhibitedinTable7‐4.

Table7‐4:AmerenIllinoisEnergyEfficiencyOfferings

ProgramNetSavings(MWh)

TotalUtilityCost

TRC(Assubmitted)

TRC205(IPAAdjusted)

AgriculturalEnergyEfficiency 945 $380,615 1.09 1.11Community‐BasedCFLDistribution 9,330 $1,178,428 2.27 2.31DemandBasedVentilationFanControl 5,717 $1,227,357 3.38 3.44

ElectricOnlyBehaviorModification 8,640 $373,920 1.06 1.06HVACCheck‐Up 5,940 $1,160,182 1.35 1.38LEDLinearLightingforSmallFacilities 14,750 $3,168,882 1.16 1.19PrivateHVACOptimization 7,692 $1,135,800 1.29 1.31PublicHVACOptimization 7,692 $1,135,800 1.29 1.31SmallCommercialLitSignage 9,417 $2,271,599 1.31 1.34

The totalnet savings for theseprograms is estimatedas70,124MWhat thebusbar206.Theprogramsalsocontributetoapeakreductionofapproximately8.3MW.Theestimatedsavingsattributabletoeligibleretailcustomersis26,334MWh.

7.1.5.6 AmerenIllinoisRequestedDeterminations

Initsfiling,AmerenIllinoismadethefollowingrequests:

AIC207formally requests that annual updates to themeasure values in the TRM and NTGratiovaluesresultinchangestotheimplementer'ssavingsgoalsand/orthecoststructuresbetween AIC and the implementer and will be re‐negotiated for the savings calculationsbasedupontheannualIL‐TRMandNTGupdatesforoneprogramyear.

AICseeksexpressapprovalthatit ispermittedtorecovercoststhatexceedtheestimatedprogramcosts. In lieu of this express approval, AIC will be forced to prematurely discontinue approvedprogramspriortotheestimatedbudgetbeingexpended.208

The IPAdoesnotobject to theserequests,as theyappear tobeconsistentwithconsensus items frompastworkshops.

Inadditiontoadoptingthesedeterminations,theIPArequeststhattheICCapprovetheincrementalenergyefficiencyprogramsasdescribedabove.

7.1.6 ComEd

ComEd’s submittal to the IPAprepared in compliancewith sections16‐111.5and16‐111.5Bof thePUA isincluded in Appendix C of this Plan which may be found on the IPA’s website posting of the 2016ProcurementPlan atwww.illinois.gov/ipa.Note that thedocument entitled “ComEdThirdPartyEfficiency

204AmerenIllinoisalsoprovidedtheresultsoftheUCTtestandalltheproposedprogramspassedtheUCTtest.TheIPAconsidersthatinformationalonlyandhasnotusedtheUCTtestinitsconsiderationofprogramstoincludeinthisPlan.205Using11.5%administrativeadder,asdescribedinSection7.1.5.2.Notethattheadderisnotappliedtoprogramincentives,onlytodirectcostssotheimpactofthisadjustmentvariesbyprogram.Thisadjustmentdoesnotincludenon‐energybenefits.206NotethatinAmerenIllinois’submittaldocumentnetsavingsareprimarilylistedasatthemeter.Forconsistencynetsavingsinthisplanarelistedatthebusbar.207AmerenIllinoisCompany(“AIC”).208AmerenIllinoisSection16‐111.5BSubmittalat12.


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ProgramResultsof2015BidReview,July13,2015”containsconfidentialdataandisnotincludedwiththisPlan.

The IPA believes that ComEd’s filing meets the requirements of Section 16‐111.5B(a)(1)‐(3) and theprogramslistedinAppendixC‐2shouldbeapprovedpursuanttoSection16‐111.5B(a)(5).

7.1.6.1 ComEdBidReviewProcess

ComEd received 17 bids. One bid was withdrawn. The remaining programs included one multifamilyprogram, one agricultural program, 8 business programs, three public‐sector programs, and three low‐income programs. The public sector programs and the low‐income programs target customer segmentsnormallyservedbyDCEOSection8‐103programs.

InordertoprovidetheIPAwithabroadrangeoffeedbackonthebidsreceived,ComEdsolicitedinvolvementfrommembers of the SAG. In addition toDCEO, twoorganizationsparticipated in the review process: theNaturalResourcesDefenseCouncilandtheEnvironmentalLaw&PolicyCenter.

ComEdreleaseditsSection16‐111.5BRFPonMarch9,2015andconductedapre‐bidconferenceonMarch16.Thereviewteamparticipatedinconferencecallsduringtheprocesstodiscussbids,comparepreliminaryresults, and identify follow‐up information needed from bidders. ComEd’s review focused on programstargetingcustomersservedby theComEdportfolio,althoughComEdalso reviewed theaLowIncomeKitsprogram,sinceComEdSection8‐103EnergyEfficiencyportfolioincludesasimilarprogramthatwouldalsobeeligible to low incomecustomers.Similarly,DCEO’sreview focusedonprograms targetingpublicsectorand low income customers, althoughDCEO also reviewed the LEDLinear Lighting for Small Facilities bid,sincethatproposalincludedtargetingsomepublicsectorcustomerswithitsoffering.

Ofthe16bids, fourbidsweredeterminedtobeduplicativeofexistingComEdprogramsandonebidhadaTRCbelow1.0.Thisleft11programsforinclusioninthisPlan.

7.1.6.2 ReviewoftheComEdTRCAnalysis

ComEdusestheDSMoretooltoconductitsTRCanalysis.UnliketheBENCOSTtoolusedbyAmerenIllinois,DSMoreusesproprietaryanalyticalmodules.ComEdprovidedmoredetailedinputandoutputtablesfromtheanalysisthaninpreviousyears,butwhiletheIPAwasabletoreviewthosefixedinputsandoutputs,theIPAwasnotabletomodifyinputstoexaminetheimpactontheoutputs(thuslimitingthesensitivityanalysisthattheAgencycouldconduct).

As previously noted, ComEd has traditionally used marginal line losses when calculating TRCs, and thatpractice continued for its submittal this year. In previous years, ComEd also did not include an adder foradministrative costs. For this Plan, ComEd included an administrative adder of 11.5%; this number wasdevelopedoffof “an8.5percentadder to reflectComEd’sadministrativecostsandanadditional3percentadder to reflect costs required by ComEd’s independent evaluator.”209ComEd also calculated TRC valueswithout the inclusion of its administrative cost adder; for the one program that did not pass the TRC,removingtheadder(whichwouldincreasetheTRCvalue)didnotresultintheTRCbeingover1.0(instead,itwas0.93).

ComEd did not include DRIPE in its TRC calculations and does not include a blanket NEB adder at theportfolioorprogramlevel.ComEdinsteadconsidersNEBsatthemeasurelevel,addingthefollowingbenefitstomeasuresasappropriate:

209“ComEdtrackedcostsoverthepastyearanddeterminedthatadministrativecostswouldadd8.5%tothetypicalthirdpartyprogramcosts.Inaddition,stakeholdersagreedthatprogramsapprovedandrunpursuantto16‐111.5Bwouldincuranevaluationbudgetequalto3%ofapprovedprogrambudgets.Intotal,ComEdincreasedeachbidder’sbudgetby11.5%toaccommodateestimatedadministrativeandevaluationcosts.”ComEdLoadForecastat28.


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Maintenance savings (primarily the avoided customer cost to replace incandescent/halogen lampsevery1000‐2000hoursduetothelongerlifeofLEDorfluorescentlamps)

Watersavings(forthosemeasuresthatsavewater).210

Basedon the sensitivityanalysis conducted forAmeren Illinoisprograms (suchas the inclusionof aNEBsadderandtheobservedimpactsonTRCs),itdoesnotappearthattheadditionofablanketNEBsadder(suchaswhatwasusedbyAmerenIllinoisinpreviousyears)wouldhaveallowedtheoneprogramthatfailedtheComEdTRCscreeningtohavepassed.

7.1.6.3 ReviewofDuplicativePrograms

ComEdand its stakeholder review committeedetermined that the following four (outof the16 evaluatedproposals)wereduplicativeofexistingprograms.Theapproachusedwascomparable to thatdescribed inSection7.1.5.4above.

Table7‐5:ComEdDuplicativeProgramScreeningSector Program ReasonDuplicativeBusiness SuperTradeAlly DuplicativewithSection16‐111.5BSmallBusinessEnergyServices ProgramBusiness LinearLED DuplicativewithSection16‐111.5BSmallBusinessEnergyServices ProgramBusiness IntegratedEnergyControls DuplicativewithSection16‐111.5BSmallBusinessEnergyServices ProgramBusiness EnergyDashboard DuplicativewithSection16‐111.5BSmallBusinessEnergyServices Program

ThreeoftheproposalsdirectlyoverlappedtheComEdSmallBusinessEnergyServicesprograminwaysthatwouldnotofferadditionalconsumerbenefits.Thefourthprogramprovidedaweb‐baseddashboardforleadcreation, but failed to demonstrate how itwould sufficiently utilize that dashboard to reachunder‐servedmarketsandoffermeasures inways thatwouldnotbemerelyduplicativeof theexistingprogram.ComEdalsonotedthatthedashboardreplicatedmuchofthefunctionalityofitsBuildingEnergyAnalyzerdashboardthatisavailabletobusinesscustomerswithAMImeters.211

Thecommitteealsoconcludedthattwootherprogramswhilehavingsomeoverlapmoreappropriatelyfellinto the categoryof competingprograms inwhich theywouldnotdetract from theexistingprogramsandthuswereincluded.

TheIPAagreeswiththosedeterminations.

ThereviewcommitteealsodeterminedthatthefiveprogramsthattargetsectorsnormallyservedbyDCEOprograms could be structured so as not to be duplicative of existing programs (regardless of if thoseprogramscontinuetoreceivefundingasdiscussedinrelationtoAmerenIllinois’programsinSection7.1.5.4above.).However,thoseprogramsmayrequireadditionalcoordinationbetweenDCEOandComEd.

7.1.6.4 ComEdIdentificationof“PerformanceRisk”

ComEdidentifiedsixprogramsthatitconsidereda“performancerisk”baseduponthereviewofComEd,theStakeholderreviewcommittee,andDCEO(whereapplicable).Thisanalysisbaseduponanassessmentofthestrengthoftheproposedapproachandtheexperienceoftheprogramteam.OneofthoseprogramsdidnotpasstheTRC,andonewasdeterminedtobeduplicative.Oftheremainingfourprograms,ComEdexpressedconcerns that the sales cycle for the applicable products in twoof thebids is very slowand complex, oneprogramthatexpandsonanexistingprogramhascurrentlynotcurrentlyexpendeditsbudget,andanother

210ComEdalsoincludesacarboncostadderasrequiredbythestatutoryTRCdefinition.211TheBuildingAnalyzerDashboardisnotfundedthroughSection8‐103,sothisduplicationisnotdirectlyrelevanttothisdeterminationoftheprogrambeingduplicative.


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programmayrelyonlistsofcustomersreceivingLIHEAPformarketing,andthoselistsarenotavailableduetoconfidentialityprovisions.

ComEddoesnot,however,recommendthatsuchprogramsnotbeincludedintheIPA’sPlanornotapprovedby the Commission. The IPA agrees. Section 16‐111.5B requires the IPA to include incremental “energyefficiency programs andmeasures it determines are cost‐effective.”212Under Section 16‐111.5B, “the term‘cost‐effective’ shall have themeaning set forth in subsection (a) of Section 8‐103 of this Act,”213meaning“thatthemeasuressatisfythetotalresourcecosttest.”214Aseachofthesemeasurespassesthetotalresourcecosttest,theyshouldbeincludedintheIPA’sannualprocurementplan.

Further, as the IPAunderstands it, the “pay forperformance”natureof contractsunderSection16‐111.5Bshould insulateratepayers frompaying forprogramsthatcannotachievedexpectedsavings. If riskofnon‐performancerestedwithratepayersortheadministeringutility,thenqualitativeprogramfactorswouldneedtobeconsideredtoprotect thoseparties’ interests.Butunderapay forperformancearrangement, the IPAunderstands risk of underperformance to rest with the winning bidders, and flawed program designwillsimplymanifestitselfinlesspaymentforlessperformance.

However, while the IPA does not propose recommending exclusion or non‐approval of any “savings risk”programs, it invites stakeholder comments on how a qualitative assessment of a program’s proposedapproach and program teammay be considered andwhether the “pay for performance”model is indeedsufficientto insulateratepayersandutilitiesfromfinancialrisk.TheIPAhasinvitedfeedbackontheuseofqualitative factors for energy efficiency program review in the past,215and is again interested in any suchfeedbackthisyear.

7.1.6.5 ComEdProgramsRecommendedforApproval

ComEd’s submittal includes identification of eleven energy efficiency programs for inclusion in thisProcurementPlan.Allof theseprogramspassedtheTRCtestat the timeofassessment.216TheseprogramsareexhibitedinTable7‐6.

Table7‐6:ComEdEnergyEfficiencyOfferings

Program NetSavings(MWh)TotalUtility

CostTRC

AgriculturalEE 1,354 $366,613 1.64AssistedandSeniorHousing 1,319 $625,928 1.60Community‐basedCFLDistribution(DCEO) 17,566 $1,240,000 3.01EfficientProducts(DCEO) 3,711 $778,179 6.24EnhancedBuildingOptimization(DCEO) 12,274 $2,500,000 2.68LitSignage 16,236 $3,700,000 3.06Low‐incomeKits(DCEO) 4,555 1,439,246 1.85Low‐incomeMulti‐family(DCEO) 7,239 $2,167,622 4.44Luminaire‐LevelLightingControl 19,113 $5,101,484 4.39Monitoring‐basedCommissioning 3,008 $1553,800 1.67RuralSmallBizEEKits 1,078 $582,970 4.54

Thenetsavingsatthebusbaris87,453MWh.Theseprogramsareforecastedtodeliver13MWofreductioninpeakprocurement.Thesavingsattributabletoeligibleretailcustomersis35,812MWh.

212220ILCS5/16‐111.5B(a)(4).213220ILCS5/16‐111.5B(b).214220ILCS5/8‐103(a).215Mostrecently,aspartoftheAgency’sdraft2015Plan.216ComEdalsoprovidedtheresultsoftheUCTtestandeightofthetenproposedprogramspassedtheUCTtest.TheIPAconsidersthatinformationalonlyandhasnotusedtheUCTtestinitsconsiderationofprogramstoincludeinthisPlan.


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The IPA agreeswith this assessment and requests that the ICC approve the incremental energy efficiencyprogramsasdescribedabove.

7.1.7 MidAmerican

Section 16‐111.5B of the Public Utilities Act calls for each utility that participates in the procurementplanningprocesssetforthinSection16‐111.5toincludeadditionalinformationrelatedtoenergyefficiency.MidAmericanprovidedtotheIPAinformationrelatedtothoseprovisions,whichisincludedasAppendixDofthisPlan.

Section16‐111.5BofthePublicUtilitiesActalsoprovidesthat“eachIllinoisutilityprocuringpowerpursuantto[Section16‐111.5]shallannuallyprovidetotheIllinoisPowerAgencybyJuly15ofeachyear,orsuchotherdate asmay be required by the Commission or Agency, an assessment of cost‐effective energy efficiencyprograms or measures that could be included in the procurement plan.”217To satisfy this requirement,ComEdandAmerenIllinoisissuerequestsforproposalforthird‐partyenergyefficiencyprogramsearlyintheyear, receive detailed proposals from third‐party vendors in the spring, screen those programs for cost‐effectivenessandduplicitywithexistingprograms,anddisclosewhichprogramstheutilitydeemstobecost‐effectiveforinclusionintheIPA’sprocurementplanaspartofitsJuly15thdeliverables.

“[P]rocurement plans prepared pursuant to Section 16‐111.5 of this Act shall be subject to” Section 16‐111.5B’s “requirements,” and a procurement plan for MidAmerican would unquestionably be “preparedpursuanttoSection16‐111.5.”218However,Section16‐111.5B’scompliance“requirements”includerequiringthatautilitysubmitits“mostrecentanalysissubmittedpursuanttoSection8‐103AofthisActandapprovedby the Commission under subsection (f) of Section 8‐103 of this Act” and the “[i]dentification of new orexpanded cost‐effective energy efficiency programsormeasures that are incremental to those included inenergyefficiencyanddemand‐responseplansapprovedbytheCommissionpursuanttoSection8‐103ofthisAct.”219AsSection8‐103ofthePublicUtilitiesAct“doesnotapplytoanelectricutilitythatonDecember31,2005providedelectricservicetofewerthan100,000customersinIllinois”(i.e.,MidAmerican),220therearenoanalysesdevelopedbyMidAmericanandnounderlyingMidAmericanenergyefficiencyprogramsunderSection8‐103towhichany“neworexpanded”programscouldbeviewedas“incremental.”

Other provisions in Section 16‐111.5B also call into question its applicability toMidAmerican. Section 16‐111.5B(a)(3)requiresthatutilities“shalldeveloprequestsforproposalsconsistentwiththemannerinwhichitdevelopsrequestsforproposalsunderplansapprovedpursuanttoSection8‐103ofthisAct,”butagain,noplansarefiledandnorequestsforproposalsmaybeissuedbyasmallmulti‐jurisdictionalpursuanttoSection8‐103.221Likewise, theCommissionapproves included incremental efficiencyprograms “if theCommissiondeterminestheyfullycapturethepotentialforallachievablecost‐effectivesavings,totheextentpracticable,andotherwisesatisfytherequirementsofSection8‐103ofthisAct,”buta“requirement”ofSection8‐103isthatprogramsmaynotbeproposedbysmallmulti‐jurisdictionalutilities.222

Basedontheforegoing,theIPAbelievesthatMidAmerican’sJuly15,2015submittalmeetstherequirementsofSection16‐111.5Basitappliestothatutility.However,incommentsthisdraftPlan,theIPAinvitesfurtherfeedbackfrominterestedpartiesontheapplicabilityofSection16‐111.5BtoMidAmericanforthisPlan,andinthefuture.

217220ILCS5/16‐111.5B(a)(3).218220ILCS5/16‐111.5(a).219220ILCS5/16‐111.5(a)(3)(B),(a)(3)(C).220220ILCS5/8‐103(h).221220ILCS5/16‐111.5B(a)(3).222220ILCS5/8‐103(a)(5).


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7.2 ProcurementStrategy

TheIPArecommendsoneslightrefinementtothebasicstrategyforblockenergyprocurementfromthe2015ProcurementPlan.TheslightrefinementrelatestotheprocurementfortheNovembertoMaymonthswhichwillnowtakeplaceforOctoberthroughMayasexplainedbelow.

ThecurrentIPAprocurementstrategyinvolvestheprocurementofhedgestomeetaportionofthe hedging requirements over a three year period and includes two procurement events inwhichtheJulyandAugustpeakrequirementswillbehedgedat106%,whiletheremainingpeakandoff‐peakrequirementswillbehedgedat100%. In thespringprocurementevent,106%oftheJulyandAugustexpectedpeak,100%oftheJulyandAugustoff‐peak,100%oftheJuneandSeptember peak and off‐peak, and 75% of the October through May peak and off‐peakrequirements for the 2016‐2017 delivery year will be targeted for procurement. The fallprocurementeventwillbringthetargetedhedgelevelsto100%forOctoberthroughMayofthe2016‐2017deliveryyear.Aportionofthetargetedhedgelevelsforthe2017‐2018andthe2018‐2019deliveryyearsof50%and25%,respectively,willbeacquiredspreadonanequalbasisinthespringandfallprocurementevents.

Including October in the fall procurement event will better align the procurement with theutilities’non‐summerperiodand,moreimportantly,givestheutilitiestheopportunitytocoveranyshortpositioninthemonthofOctoberresultingfromloadreturningtotheutilitywhichwasnotanticipatedinthespringloadforecast.Forexample,aftertheMarch2015loadforecastwasproduced,theCityofChicagoannouncedtoreturnitsmunicipalaggregationloadtoComEd.Thisdecisionproducedashortposition inComEd’s supplyportfolio in themonthsof June throughOctober.HadthefallprocurementeventincludedthemonthofOctober,theshortpositionwouldhadbeensmaller.TheIPAisnotawareofanynegativefinancialconsequencesresultingfromthereturnof theChicago load toComEd;however, froma riskmanagementperspective, itwouldhavebeenpreferabletohavehadtheoptionofcoveringthemonthofOctoberintheSeptemberprocurementevent.

TherefinedstrategyissummarizedinTable7‐7.

Table7‐7:SummaryofEnergyHedgingStrategy

Priorprocurementplans,includingthe2015ProcurementPlan,haverecommendedthatComEdcontinuetoobtain its capacity needs through the PJM capacitymarket. In the current plan the IPA recommends thatComEdcontinuetoobtainitscapacityneedsfromthePJMcapacitymarketasshowninTable7.5.

Table7‐8:SummaryofCapacityProcurementStrategyforComEd*PJMRPMBaseResidualAuctionsfor2016‐17and2017‐18havealreadycleared.PJM’sinitialCapacityPerformanceResourceauctionwillbecompletedbymid‐September2015.

Spring2016Procurement Fall2016Procurement




October2016‐May2017



June100%peakandoffpeakJulyandAug.106%peak,100%offpeakandSep.100%peakandoffpeakOct.‐May75%peakandoffpeak

25% 12.5% 100% 25% 12.5%


June2017‐May2018

June2018‐May2019

100%PJMRPMAuctions* 100%PJMRPMAuctions*

100%PJMRPMAuctions


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For Ameren Illinois, the 2015 Procurement Plan recommended that for the 2015‐2016 Planning Year,AmerenIllinoispurchaseallofitscapacityrequirementsviaMISO’sPRA.ThiswasthefirstyearsincetheIPAwasformedthatAmerenIllinoishadnoforwardhedgingofcapacity.TheIPArecommendsaslightchangeinstrategywithrespecttohedgingcapacitypriceriskforAmerenIllinois.

The capacity prices resulting from the 2015‐2016 MISO PRA cleared substantially higher for the IllinoisRegion(Zone4)thaninprioryears.The2015‐2016Zone4priceof$150/MW‐Dayis9timesgreaterthanthepreviousPlanningYear,andmore than40 timesgreater thantheotherzones.MISO’s IndependentMarketMonitor (“IMM”) is forecasting a $71/MW‐Day Initial Reference Price for 2016‐2017223and a PreliminaryInitialReferencePriceof$136.37/MW‐Day224forthe20172018PlanningYear.ItisconceivablethattheZone4pricewillclearatclosetotheseprices,i.e.droppingin2016‐2017thenrisingagainin2017‐2018.WhilethePJM Base Residual Auction (BRA) for 2018/19 has not been conducted yet, the capacity performanceincentiveswillmostlikelyresultinanincreaseintheBRApricefor2018‐2019.225WiththeMISOIMMusingtheopportunitycostofsellingtoPJMasabasisforderivingtheInitialReferencePriceitissafetoassumethatthe InitialReferencePrice for2018‐2019willbehigher.Asmentioned inChapter5, the IPAexpectsmuchuncertaintyinfutureMISOPRAZone4clearingprices.Intheinterestofhedgingpriceriskandmaintainingrate stability for the Illinois customers, the IPA recommends hedging a portion of Ameren’s (andMidAmerican’s)capacitymarketexposure.

ThedifferencesbetweenthePJMandMISOcapacityconstructsindicatesthatacapacityhedgingstrategythatreliesonboththeMISOPRAaswellasbilateralcapacityprocurementsby the IPA isareasonablehedgingapproachformeetingtheAmerenIllinoiscapacityneeds.OneparticularlyimportantdifferenceisthatfortheMISO PRA, the clearing prices are not known until two months prior to the beginning of the respectivePlanning Year,whereas inPJM the primary capacity auctions, theBRAs, are forward looking and are heldthreeyearspriortotheDeliveryYear.TheMISOPRAthereforedoesnotprovideaforwardpricesignalandposespotentialriskstocustomerswhenpricesincreaseabruptlyandsurprisingly,asobservedinthe2015‐2016PRA.

In light of the short‐term nature of theMISO PRA, itmakes sense to utilize forward hedging of at least aportion of the Ameren Illinois capacity needs through bilateral capacity purchases. Given the potentialscheduling conflicts with the MISO PRA and a spring IPA capacity procurement event, the capacityprocurement for the upcoming Planning Year should take place well before the MISO PRA, during a fallprocurementevent.Itisalsoimportanttonotethatanargumentcouldbemadethat,giventheresultsofthemostrecentMISOPRA,Zone4customerscouldincurhigherpricesthroughthebilateralpurchases.Suppliersknow from theMISOPRA results that thepotential for higher capacityprices inZone4may exist givenahighercapacityclearingpriceinthePRA,suchasoccurredinthe2015‐2016PRA.BiddersintheIPAcapacityprocurementeventwouldbenefitfromknowingrecentMISOPRAclearingprices.InadditiontoPRAclearingpricesbeingpublicknowledge,bidderswouldbeawareoftheinputinformationutilizedbytheMISOIMMtodevelop thePRAReference including: InitialReferencePrices,ConductThresholds226, and theCostofNewEntry(CONE).However,giventhatanybidsabovethebenchmarkpricesinanIPAprocurementarerejectedandtheconfidentialnatureoftheinputs,methodologyandvaluesforthecapacitybenchmarks,thebiddingadvantage for thesuppliersprovidedbydetailedknowledgeof thePRAresultsandassumptionswouldbesomewhatdiluted.TheIPAcapacityprocurementsalsoofferflexibilityinthattheprocurementsprovidean

223The2016‐2017BRApriceis$59.37/MW‐Day.224ForecastbasedonRPMBRAresultsfor2017‐20/18andpresentedatFebruary5,2015SAWG.The2017‐2018BRApriceis$120/MW‐Day.225Theresultsofthe2018‐2019BRAareexpectedtobepostedonAugust21st,2015.226TheConductThreshold=InitialReferencePrice+10%CONE.


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optionandnotanobligation toexecutecontracts.Forexample, in theevent thesuppliersofferprices thatexceedthebenchmarks,itispossiblethatnocontractswouldbeexecuted.

Inlightoftheabovediscussion,Table7‐9providesacapacityhedgingstrategywhere:

For the2016‐2017PlanningYear,50%of theAmeren IllinoiscapacitywouldbeprocuredthroughanRFPinSeptember2015withtheremaining50%beingprocuredintheMISOPRA;

For the2017‐2018PlanningYear, 25%of theAmeren Illinois capacitywouldbeprocured throughanRFPinSeptember2015,50%wouldbeprocuredthroughanRFPinfall2016,withtheremaining25%beingprocuredintheMISOPRA;and

For the2018‐2019PlanningYear, 25%of theAmeren Illinois capacitywouldbeprocured throughanRFP in fall2016,50%wouldbeprocured throughanRFP in fall2017,with the remaining25%beingprocuredintheMISOPRA.

TheIPAwillreviewandanalyzetheresultsofthe2016‐2017MISOPRAandmakeanynecessaryadjustmentstotherecommendedcapacityhedgingstrategyinfutureprocurementplans.


MidAmericanmade a formal request to the IPA toprocure the incremental amount of capacity that is notcurrently served, or forecasted to be served in Illinois by MidAmerican‐owned Illinois jurisdictionalgeneration.Aspartof thatrequestMidAmericanprovided its forecasted loadandcapability,asummaryofwhichispresentedinTable7‐10.

TheIPAnotesthatthemagnitudeoftheproposedcapacityprocurementsforMidAmericanissmallrelativetoitscapacityrequirements (about15%).Also,while theMISOPRAbiddingandclearingdynamics thathavebeen discussed for the Ameren procurement are potentially valid for Zone 3, it is unlikely that biddingbehavior in thisZonewillcause the levelofpriceseparationexperienced inZone4 thisyear.ThedeliverypointforMidAmerican’scapacityisLRZ3(Zone3);itclearedat$3.48/MW‐Dayinthe2015‐2016MISOPRA.Inlightofthis,theIPArecommendsthatMidAmericanobtains100%ofitsforecastcapacityshortfallforthe2016‐2017PlanningYearintheupcomingMISOPRA.

Forfutureplanningyears,theIPArequeststhattheICCapprovetheprocurementof100%ofthe2017‐2018through 2020‐2022 (five planning years) forecast capacity shortfall for MidAmerican in the fall 2016procurementevent,asshowninTable7‐11.ThisprocurementwillusetheupdatedcapacityrequirementsinMidAmerican’sJuly2016loadforecast,andwillbesubjecttothereviewoftheIPAandtheconsensusamongtheIPA,ICCStaff,MidAmerican,theandtheProcurementMonitor.TheIPArecommendsconsensusbecausethecapacityrequirements for the2021‐2022deliveryyearwillnotbeknownuntilMidAmericanproducestheJuly2016loadforecast.

The IPA’s overarching supply risk management approach relies, in part, on the laddered procurementstrategy described in Chapter 6. However, in this specific case, the IPA recommends a five‐year capacityprocurement for MidAmerican for the following reasons. The capacity procurement volumes forMidAmericanarerelativelysmall,asdemonstrated inTable7‐10.Theprocurementcostof implementingaladdered procurement strategy for relatively small quantities each year would most likely outweigh the


June2017‐May2018

June2018‐May2019


25%RFPinSep.201550%RFPinfall201625%MISOPRA**

25%RFPinfall201650%RFPinfall201725%MISOPRA***


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benefits.On theotherhand,by combining theMidAmerican five‐year capacitypurchaseswith theAmerenIllinoiscapacitypurchaseinthefall2016procurementevent,theprocurementunitcostwillbesignificantlylowerastheresultofeconomiesofscale.ProcuringallofMidAmerican’sfive‐yearcapacityshortfallthroughthe 2021‐2022 delivery yearmay also result in lower capacity costs for MidAmerican over this planninghorizonduetodelaysincoalretirementsandtheuncertaintyassociatedwithlitigationoverEPAemissionsregulations.The recently finalizedCleanPowerPlan (“CPP”)delayed requiring complianceuntil 2022 (thepriordraftversionhadreferenced2020as the initialmandatedcompliancedate),whichcoulddelaysomecoalplantretirements.Further,likelylitigationovertheCPPmaycreateadditionaluncertaintyregardingthetimingofcoalplantretirements,potentiallyofferingtheopportunitytobuyreasonablypricedcapacityinthenearhorizon.Finally,insupportofafive‐yearbilateralcapacityprocurement,allowingfortheprocurementofcapacityforafive‐yearperiodmayprovideenoughrevenuecertaintyfordeveloperswhowouldbuildorrepowercapacityintheZoneandhelpmaintainreliabilitylevelswithinprescribedstandards.

Table7‐10:SummaryofMidAmericanLoadandCapability



TheIPAdoesnotrecommendconductingabilateralcapacityprocurementaspartofthespringprocurementevent given the relatively close timing with regard to the MISO PRA. Attempting to procure the AmerenIllinoisorMidAmericanforecastcapacityshortfallfortheupcomingyearinaspringprocurementwould,inall likelihood,notallowsufficient timetoparticipate in theMISOPRA,whichalso functionsas thecapacitysourceoflastresorttoavoidMISOpenalties.Inaddition,itistheIPA’sviewthatincreasingthetimeintervalbetweentheMISOPRAresultsbeingreleasedandthe IPAcapacityprocurementmayhavesomebeneficialimpactsonthepricesbidintotheIPAprocurement.

7.3 IndicativeQuantitiesandTypesofProductstobeProcured

The following tables were constructed using the July 2015 Expected Load Forecasts (which excludeincrementalenergyefficiencyprograms) toprovide indicativevalues for the2016‐2017deliveryyear.Theactual target procurement volumeswill be calculatedusing theMarch 2016 and July 2016Expected LoadForecasts for the spring and fall procurement events respectively. These forecasts are expected to includeApproved Energy Efficiency Programs for both Ameren Illinois and ComEd. The following tables arecalculatedassumingnoLTPPAscurtailmentsduringthedeliveryperiods,androundedsymmetricallytothenearest25MWblock.

2016‐2017 2017‐2018 2018‐2019 2019‐2020 2020‐2021

CoincidentPeakMWServedbyMidAmerican

440.2 442.9 445.9 448.9 451.8

MISOPRM 7.1% 7.1% 7.1% 7.1% 7.1%

TotalPRMRMW 471.7 474.4 477.5 480.7 483.9

TotalNetCapabilityMW 397.8 399.3 399.3 399.3 399.3

Surplus/Shortfall(UCAPMW) (73.7) (75.1) (78.3) (81.4) (84.7)


June2017‐May2022

100%MISOPRA* 100%RFPinfall2016


103


7.3.1.1 AmerenIllinoisProcurementDeliveryYears2016‐2021

Table7‐12:AmerenIllinoisSpringProcurement,DeliveryYear2016‐2017PreliminaryVolumes*

ExpectedLoad

(MW)

June100%peakandoffpeak

JulyandAug.106%peak,100%offpeak

Sep.100%peakand

offpeak

Oct.‐May75%peakand

offpeak

CurrentContractedSupply(MW)

AnticipatedSpring2016

Purchases(MW)

PeakOff‐Peak

Peak Off‐Peak Peak Off‐Peak PeakOff‐Peak

June‐16 1,000 822 1,000 822 493 403 500 425

July‐16 1,175 928 1,246 928 581 462 675 475

August‐16 1,116 857 1,183 857 554 427 625 425

September‐16 867 726 867 726 442 375 425 350

October‐16 750 640 562 480 378 329 175150

November‐16780

675 585 506 385 347 200 150

December‐16 1,019 899 765 674 499 444 275 225

January‐17 1,002 928 752 696 507 457 250 250

February‐17 928 858 696 643 472 429 225 225

March‐17 855 772 641 579 426 375 225 200

April‐17 720 624 540 468349

315 200 150

May‐17 686 654 515 491 341 330 175 150

*VolumestobeadjustedusingtheMarch2016expectedloadforecast,whichshallalsoincludenewlyapprovedenergyefficiencyprograms.


104

Table7‐13:AmerenIllinoisFallProcurement,October‐MayofDeliveryYear2016‐2017,PreliminaryVolumes*

ExpectedLoad

(MW)

100%ofExpectedLoad

(MW)

AnticipatedContracted

Supply(MW)**

AnticipatedFall2016

Purchases(MW) Peak Off‐

PeakPeak Off‐

PeakPeak Off‐Peak Peak Off‐Peak

October‐16 750 640 750 640 553 479 200 150

November‐16 780 675 780 675 585 497 200 175

December‐16 1,019 899 1,019 899 774 669 250 225

January‐17 1,002 928 1,002 928 757 707 250 225

February‐17 928 858 928 858 697 654 225 200

March‐17 855 772 855 772 651 575 200 200

April‐17 720 624 720 624 549 465 175 150

May‐17 686 654 686 654 516 480 175 175

*VolumestobeadjustedusingtheJuly2016expectedloadforecast,whichshallalsoincludenewlyapprovedenergyefficiencyprograms.**Includinganypurchasesmadeinspring.


105

Table7‐14:AmerenIllinoisSpringProcurement,DeliveryYear+1(2017‐2018),PreliminaryVolumes*

ExpectedLoad

(MW)

50%ofExpectedLoad

(MW)


AnticipatedSpring2016Purchases(MW)

AnticipatedFall2016Purchases(MW)

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

June‐17 1,010 819 505 410 243 203 125 100 125 100

July‐17 1,182 927 591 464 306 237 150 125 125 100

August‐17 1,122 858 561 429 279 227 150 100 125 100

September‐17 876 730 438 365 219 173 100 100 125 100

October‐17 754 637 377 319 199 157 100 75 75 75

November‐17 784 677 392 339 185 172 100 75 100 100

December‐17 1,019 909 510 455 252 217 125 125 125 125

January‐18 1,006 930 503 465 253 236 125 125 125 100

February‐18 939 856 469 428 222 204 125 100 125 125

March‐18 869 771 434 386 229 196 100 100 100 100

April‐18 728 621 364 310 194 144 75 75 100 100

May‐18 694 654 347 327 166 155 100 75 75100



106

Table7‐15:AmerenIllinoisSpringProcurement,DeliveryYear+2(2018‐2019),PreliminaryVolumes*

ExpectedLoad

(MW)

25%ofExpectedLoad

(MW)




PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

June‐18 1,015 830 254 208 45 50 100 75 100 75

July‐18 1,187 921 297 230 29 38 125 100 150 100

August‐18 1,128 860 282 215 29 52 125 75 125 100

September‐18 892 731 223 183 46 46 100 75 75 50

October‐18 761 633 190 158 71 86 50 25 75 50

November‐18 793 677 198 169 85 97 50 25 75 50

December‐18 1,029 910 257 228 77 67 100 75 75 75

January‐19 1,006 936 251 234 78 86 75 75 100 75

February‐19 939 861 235 215 72 79 75 75 100 50

March‐19 877 774 219 193 83 92 75 50 50 50

April‐19 732 617 183 154 90 98 50 25 50 25

May‐19 700 654 175 163 66 80 50 50 50 25

*Volumes to be adjusted using the March 2016 expected load forecast, which shall also include newly approved energy efficiencyprograms.

7.3.1.2 DeliveryYear+3andDeliveryYear+4(2019‐2020and2020‐2021)

Giventheabsenceofvisibleandliquidblockenergymarketsfourandfiveyearsout,itisnotrecommendedthatanyblockenergypurchasesbemadetosecuresupplyfortheseyearsinthisProcurementPlan.


107

7.3.2 ComEd

7.3.2.1 ComEdProcurementDeliveryYears2016–2021

Table7‐16:ComEdSpringProcurement,DeliveryYear2016‐2017,PreliminaryVolumes*

ExpectedLoad

(MW)

June100%peakandoffpeak

JulyandAug.106%peak,100%offpeak

Sep.100%peakand

offpeak

Oct.‐May75%peakand

offpeak



Purchases(MW)

PeakOff‐Peak

Peak Off‐Peak PeakOff‐Peak

PeakOff‐Peak

June‐16 2,921 2,331 2,921 2,331 1,465 1,161 1,450 1,175

July‐16 3,459 2,825 3,666 2,825 1,739 1,402 1,925 1,425

August‐16 3,299 2,620 3,496 2,620 1,661 1,309 1,825 1,300

September‐16 2,483 2,058 2,483 2,058 1,237 1,030 1,250 1,025

October‐16 2,209 1,825 1,657 1,369 1,114 916 550 450

November‐16 2,503 2,130 1,877 1,598 1,253 1,054 625 550

December‐16 2,844 2,459 2,133 1,844 1,430 1,221 700 625

January‐17 2,859 2,506 2,145 1,879 1,422 1,248 725 625

February‐17 2,659 2,322 1,994 1,742 1,327 1,167 675 575

March‐17 2,377 2,066 1,783 1,549 1,184 1,035 600 525

April‐17 2,141 1,831 1,606 1,373 1,082 914 525 450

May‐17 2,205 1,829 1,654 1,372 1,115 918 550 450



108

Table7‐17:ComEdFallProcurement,October‐MayofDeliveryYear2016‐2017,PreliminaryVolumes*

ExpectedLoad

(MW)

100%ofExpectedLoad

(MW)


Supply(MW)**


PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

October‐16 2,209 1,825 2,209 1,825 1,664 1,366 550 450

November‐16 2,503 2,130 2,503 2,130 1,878 1,604 625 525

December‐16 2,844 2,459 2,844 2,459 2,130 1,846 725 625

January‐17 2,859 2,506 2,859 2,506 2,147 1,873 700 625

February‐17 2,659 2,322 2,659 2,322 2,002 1,742 650 575

March‐17 2,377 2,066 2,377 2,066 1,784 1,560 600 500

April‐17 2,141 1,831 2,141 1,831 1,607 1,364 525 475

May‐17 2,205 1,829 2,205 1,829 1,665 1,368 550 450



109

Table7‐18:ComEdSpringProcurement,DeliveryYear+1(2017‐2018),PreliminaryVolumes*

ExpectedLoad

(MW)

50%ofExpectedLoad

(MW)




PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

June‐17 3,182 2,527 1,591 1,263 790 636 400 325 400 300

July‐17 3,766 3,079 1,883 1,539 939 777 475 375 475 375

August‐17 3,575 2,858 1,788 1,429 886 709 450 350 450 375

September‐17 2,686 2,242 1,343 1,121 667 551 350 275 325 300

October‐17 2,380 1,968 1,190 984 607 622 300 175 275 175

November‐17 2,708 2,306 1,354 1,153 678 654 350 250 325 250

December‐17 3,053 2,661 1,526 1,331 762 665 375 325 400 350

January‐18 3,109 2,726 1,554 1,363 789 680 375 350 400 325

February‐18 2,874 2,529 1,437 1,264 727 642 350 300 350 325

March‐18 2,564 2,240 1,282 1,120 641 552 325 275 325 300

April‐18 2,324 1,985 1,162 992 572 497 300 250 300 250

May‐18 2,392 1,984 1,196 992 590 493 300 250 300 250



110

Table7‐19:ComEdSpringProcurement,DeliveryYear+2(2018‐2019),PreliminaryVolumes*

ExpectedLoad

(MW)

25%ofExpectedLoad

(MW)



AnticipatedFall.2016Purchases(MW)

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

June‐18 3,182 2,564 795 641 94 106 350 275 350 250

July‐18 3,786 3,091 946 773 61 80 450 350 425 350

August‐18 3,586 2,884 897 721 61 109 425 300 400 300

September‐18 2,711 2,271 678 568 97 97 300 225 275 250

October‐18 2,401 1,981 600 495 150 180 225 150 225 175

November‐18 2,738 2,330 685 582 178 204 250 200 250 175

December‐18 3,075 2,678 769 670 162 140 300 275 300 250

January‐19 3,115 2,738 779 684 164 180 300 250 325 250

February‐19 2,878 2,543 719 636 152 167 275 225 300 250

March‐19 2,568 2,247 642 562 174 194 225 175 250 200

April‐19 2,341 1,991 585 498 188 205 200 150 200 150

May‐19 2,405 1,990 601 497 140 168 225 175 225 150





111

7.3.3 MidAmerican

7.3.3.1 MidAmericanProcurementDeliveryYears2016–2021

Table7‐20:MidAmericanSpringProcurement,DeliveryYear2016‐2017,PreliminaryVolumes*

ExpectedLoad

(MW)

June100%peakandoffpeakJulyandAug.106%peak,100%offpeakSep.100%peakandoffpeakOct.‐May75%peakandoffpeak



Purchases(MW)

PeakOff‐Peak

Peak Off‐Peak PeakOff‐Peak

PeakOff‐Peak

June‐16 303 233 303 233 243 175 50 50

July‐16 338 260 358 260 268 207 100 50

August‐16 317 241 336 241 257 182 75 50

September‐16 274 218 274 218 233 173 50 50

October‐16 253 193 189 145 219 160 ‐‐

November‐16244

188 183 141 219 173 ‐ ‐

December‐16 270 220 202 165 236 195 ‐ ‐

January‐17 276 225 207 168 267 221 ‐ ‐

February‐17 269 221 202 166 256 214 ‐ ‐

March‐17 253 205 190 153 236 182 ‐ ‐

April‐17 250 196 187 147175

150 ‐ ‐

May‐17 240 193 180 145 185 130 ‐ 25

*VolumestobeadjustedusingtheMarch2016expectedloadforecast.


112

Table7‐21:MidAmericanFallProcurement,October‐MayofDeliveryYear2016‐2017,PreliminaryVolumes*

ExpectedLoad

(MW)

100%ofExpectedLoad

(MW)


Supply(MW)**


PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

October‐16 253 193 253 193 219 160 25 25

November‐16 244 188 244 188 219 173 25 25

December‐16 270 220270

220 236 195 25 25

January‐17 276 225 276 225 267 221 ‐ ‐

February‐17 269 221 269 221 256 214 ‐ ‐

March‐17 253 205 253 205 236 182 25 25

April‐17 250 196 250 196 175 150 75 50

May‐17 240 193 240 193 185 155 50 50



113

Table7‐22:MidAmericanSpringProcurement,DeliveryYear+1(2017‐2018),PreliminaryVolumes*

ExpectedLoad

(MW)

50%ofExpectedLoad

(MW)




PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

June‐17 300 238 150 119 243 177 ‐ ‐ ‐ ‐

July‐17 341 259 170 130 259 195 ‐ ‐ ‐ ‐

August‐17 315 245 158 123 261 186 ‐ ‐ ‐ ‐

September‐17 276 221 138 111 235 176 ‐ ‐ ‐ ‐

October‐17 252 193 126 96 211 156 ‐ ‐ ‐ ‐

November‐17 249 186 124 93 215 170 ‐ ‐ ‐ ‐

December‐17 273 222 136 111 248 190 ‐ ‐ ‐ ‐

January‐18 276 224 138 112 266 215 ‐ ‐ ‐ ‐

February‐18 270221

135 111 249 198‐

‐ ‐ ‐

March‐18 255 206 127 103 231 179 ‐ ‐ ‐ ‐

April‐18 250 195 125 97 177 144 ‐ ‐ ‐ ‐

May‐18 241 193 120 97 185 131 ‐ ‐ ‐ ‐



114

Table7‐23:MidAmericanSpringProcurement,DeliveryYear+2(2018‐2019),PreliminaryVolumes*

ExpectedLoad

(MW)

25%ofExpectedLoad

(MW)




PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

PeakOff‐Peak

June‐18 304 239 76 60 245 180 ‐ ‐ ‐ ‐

July‐18 338 261 84 65 270 198 ‐ ‐ ‐ ‐

August‐18 317 245 79 61254

183 ‐ ‐ ‐‐

September‐18 279 222 70 55 236 176 ‐ ‐ ‐ ‐

October‐18 253 192 63 48 208 156 ‐ ‐ ‐ ‐

November‐18 250 187 62 47 213 170 ‐ ‐ ‐ ‐

December‐18 272 224 68 56 234 185 ‐ ‐ ‐ ‐

January‐19 279 223 70 56 266 214 ‐ ‐ ‐ ‐

February‐19 271 222 68 56 258 202 ‐ ‐ ‐ ‐

March‐19 257 209 64 52 168 137 ‐ ‐ ‐ ‐

April‐19 250 194 63 49 149 140 ‐ ‐ ‐ ‐

May‐19 242 195 60 49 217 164 ‐ ‐ ‐ ‐




7.4 AncillaryServices,TransmissionServiceandCapacityPurchases

7.4.1 AncillaryServicesandTransmissionService

AmerenIllinois,MidAmerican,andComEdpurchasetheirancillaryservicesandtransmissionservicesfromtheir respectiveRTOs,MISO andPJM. The utilities alsomanage their Financial TransmissionRights (FTR)processesandAuctionRevenueRights(ARR)processesintheirrespectiveRTOsconsistentwithICCordersinprior Plans. The IPA is not aware of any justification or reason to alter these practices and thereforerecommendstheyremainunchanged.


115

7.4.2 CapacityPurchases

For ComEd, the IPA concludes that it does not need to include any extraordinary measures in the 2016ProcurementPlantoassurereliabilityovertheplanninghorizon.TheIPArecommendsthatComEdcontinuetomeetallof its capacityobligations through thePJMcapacitymarket inwhichcapacity ispurchased inathree‐yearaheadforwardmarketthroughmandatorycapacityrules.

ForAmerenIllinois,theIPArecommendstheprocurementofpartofthecapacityneedsviaforwardhedgingofat leastaportionoftheAmerenIllinoiscapacityneedsthroughbilateralcapacitypurchases indicated inTable7‐9(specificquantitiestobefinalizedbasedonAmeren’sforecastofJuly2016).Theremainderofthecapacity needswill be procured from theMISOPRA.The CapacityHedging Strategy forAmeren Illinois isreproducedinTable7‐24below.


ForMidAmerican,theIPAconcludesthat,MidAmericanshouldobtain100%ofitsforecastcapacityshortfallfor the 2016‐2017Planning Year from theMISOPRA. The IPA also requests that the ICC pre‐approve theprocurementof100%ofthe2017‐2018through2021‐2022(fiveplanningyears)forecastcapacityshortfallforMidAmerican, inafall2016procurementevent,asshownintheTable7‐25usingtheupdatedcapacityrequirementsinMidAmerican’sJuly2016loadforecast,andsubjecttothereviewoftheIPAandconsensusamongtheIPA, ICCStaff,MidAmerican, theandtheProcurementMonitor.TheIPArecommendsconsensusbecause the capacity requirements for the 2021‐2022 delivery yearwill not be known untilMidAmericanproduces the July 2016 load forecast. The IPA recommends a five‐year capacity procurement forMidAmericanforthereasonspresentedinSection7.2.



7.5 DemandResponseProducts

Section8‐103(c)ofthePUAestablishesagoaltoimplementdemandresponsemeasures,providingthat:

Electricutilitiesshallimplementcost‐effectivedemandresponsemeasurestoreducepeakdemandby0.1%overtheprioryearforeligibleretailcustomers,asdefinedinSection16‐111.5ofthisAct,andforcustomers thatelecthourlyservice fromtheutilitypursuant toSection16‐107of thisAct,providedthosecustomershavenotbeendeclaredcompetitive.ThisrequirementcommencesJune1,2008andcontinuesfor10years.

ComEdprovidedinformationregardingitsexistingdemandresponseprogramsfor2015whichinclude:


June2017‐May2018

June2018‐May2019


25%RFPinSep.201550%RFPinfall201625%MISOPRA**

25%RFPinfall201650%RFPinfall201725%MISOPRA***


June2017‐May2022

100%MISOPRA* 100%RFPinfall2016


116

Direct LoadControl (“DLC”): ComEd’s residential central air conditioning cyclingprogram is aDLCprogramwith72,900 customerswitha load reductionpotentialof88MW(ComEdRiderAC).

VoluntaryLoadReduction(“VLR”)Program:VLRisanenergy‐baseddemandresponseprogram,providing compensation based on the value of energy as determined by the real‐time hourlymarket run by PJM. This program also provides for transmission and distribution (“T&D”)compensationbasedonthelocalconditionsoftheT&Dnetwork.Thisportionoftheportfoliohas1,171MWofpotentialloadreduction(ComEdRiderVLR).

Residential Real‐Time Pricing (RRTP) Program: All of ComEd’s residential customers have anoptiontoelectanhourly,wholesalemarket‐basedrate.TheprogramusesComEd’sRateBESHtodetermine themonthlyelectricitybills for eachRRTPparticipant.Thisprogramhas roughly5MWofpriceresponsepotential.

PeakTimeSavings(PTS)Program:ThisprogramisrequiredbySection16‐108.6(g)ofthePUAandwasapprovedbytheICCinDocketNo.12‐0484.ThePTSprogramisanopt‐in,market‐baseddemand response program for customers with smart meters. Under the program, customersreceive bill credits for kWh usage reduction during curtailment periods. The programcommenceswiththe2015PlanningYear.ComEdsold48MWofcapacityfromtheprogramintothePJMcapacityauctionforthe2017PlanningYearand10MWforthesummerof2015.

AmerenIllinoishasimplementedVoltageOptimizationProgramincluding,forexample,ConservationVoltageReduction (“CVR”)Program, aswell asReal TimePricing (“RTP”) and the associated Power Smart Pricing(“PSP”)Program.Also,AmerenIllinoisoffersrealtimepricingoptionsthroughitstariff(AmerenRiderRTP),and,pursuanttotheCommission’sInterimOrderinDocketNo.13‐0105,AmerenIllinoisoffersaPeakTimeRebateprogram(RiderPTR).This tariffpertains toanoptionalprogramavailable toDS‐1customersasofJune 1, 2016,whereby a customerwould receive a billing credit if they curtail electric energy use duringspecificpeakusageperiods.

MidAmericanadministersaprogramcalled“SummerSaverProgram,”aresidentialDirectLoadControl(DLC)program. In addition, there is a potential for load displacement due to curtailment of customers on aninterruptiblerate.Basedonthecustomerenrollment,MidAmericanestimates itspotential totalcapacityofDemandResponse(DR)at19.5MW.

TheIPAdoesnotproposeanyprocurementofdemandresponseprogramsforthe2016‐2017deliveryyear.Undercurrentmarketandregulatoryconditions,227anewdemandresponseprocurementbytheIPAwouldnotmeetthestandardssetforthinSection16‐111.5(b)(3)ofthePublicUtilitiesActincluding,butnotlimitedto, not being “cost effective,” “satisfy[ing] thedemand‐response requirements of the regional transmissionorganization market in which the utility's service territory is located,” or “provid[ing] for customers'participation in thestreamofbenefitsproducedby thedemand‐responseproducts.”PeakTimeRebate (orSavings) programs as offered by Ameren Illinois and ComEd create value through reduction in capacitychargesandthetechnologiesutilizedforcapacityreductionsalsohavethepotentialtoprovidelongertermdemand response that could operate over more peak hours than those used for calculations of capacityobligations.

Goingforward,theIPAwillcontinuetoassessthedemandresponsemarket,andcontinueitsinvolvementinstakeholderdiscussionsregardingIllinoisstatepolicyondemandresponse.Asthemarketchangesandlegalandregulatorybarriersareaddressed,theAgencymaychoosetoproposeademandresponseprocurementinafutureprocurementplan.

227InparticularthependingSupremeCourtcasereferencedinSection2.7.


117

7.6 CleanCoal

TheIPAActcontainsanaspirationalgoalthatcost‐effectivecleancoalresourceswillaccountfor25%oftheelectricityused in Illinoisby January1,2025.228Asapartof thegoal, thePlanmustalso includeelectricitygeneratedfromcleancoalfacilities.229Whilethereisabroaderdefinitionof“cleancoalfacility”containedinthe definition section of the IPA Act230, Section 1‐75(d) describes two special cases: the “initial clean coalfacility”231and“electricitygeneratedbypowerplantsthatwerepreviouslyownedbyIllinoisutilitiesandthathavebeenorwillbeconvertedintocleancoalfacilities(“retrofitcleancoalfacility”).232Currently,theIPAisunawareofany facilitymeeting thedefinitionofan “initial cleancoal facility” thathasannouncedplans tobeginoperationswithinthenextfiveyears.

7.6.1 FutureGen2.0

InDocketNo.12‐0544,theCommissionapprovedinclusionofFutureGen2.0asaretrofitcleancoalresourcestarting in the2017deliveryyear.233On July22,2014, an Illinois appellate courtupheld theCommission’sdecision to require ComEd andAmeren Illinois to recover FutureGen sourcing agreement costs through acompetitively‐neutral retail distribution charge applicable to all utility distribution customers (includingAREScustomers).234

However,inearlyFebruary2015,theU.S.DepartmentofEnergy(DOE)announcedthesuspensionoffederalfunding,$1billion in fundingunder theAmericanRecoveryandReinvestmentActof2009(ARRA), for theFutureGen2.0project,indicatingthattheprojecthadinsufficienttimetobecompletedbytheARRAfundingexpirationinSeptember2015.OnMay26,2015theIllinoisSenateadoptedSR232whichurgestheU.S.DOEtocontinuefundingFutureGen2.0andtoextendtheARRAdeadlineforfunding.AtthetimethisdraftPlanisbeingpublishedforcomment,theAgencyisunawareofanychangeinstatusoftheFutureGen2.0project,itsunderlyingfinancing,andperformanceundertheFutureGen2.0sourcingagreements.

7.6.2 Sargas

In preparation for its 2015 Plan, the Agency was approached by a team representing Sargas, Inc., a USsubsidiaryofSargasAS,aNorwegiantechnologycompany,aboutitsplanstodevelopacoal‐firedpowerplantinMattoondesignedtoburn Illinoiscoalwith90%post‐combustioncarboncapture,withcapturedcarbonthenusedforlocalenhancedoilrecovery.SargasproposedthattheIPAconductacompetitiveprocurementforcleancoalfacilitysourcingagreementspursuanttoitsauthorityunderSection1‐75(d)(1)oftheIPAActasameanstofacilitatetheproject’sdevelopment.

ForreasonsexplainedbytheAgencyinits2015Plan,235theIPAdeclinedtoadoptthatproposal.InapprovingtheIPA’s2015ProcurementPlan,theCommissionapprovedthatdecision,statingthatitwas“notconvincedthataproposalofthetypepresentedbySargaswascontemplatedbytheIllinoisGeneralAssemblyorisinthepublicinterest.”236

BasedonarecentmeetingwithrepresentativesfromSargas,theAgencyunderstandsthatSargasmaymakeasimilarproposalincommentsontheIPA’sdraft2016Plan.TheIPAwillprovidearesponsetotheproposalsmadebySargas,andanyotherpartiesprovidingcommentontheAgency’sdraftPlan,throughtheAgency’s2016ProcurementPlanfiledwiththeIllinoisCommerceCommission.

22820ILCS3855/1‐75(d).22920ILCS3855/1‐75(d)(1).23020ILCS3855/1‐10.231Id.23220ILCS3855/1‐75(d)(5).233SeeDocketNo.12‐0544,FinalOrderdatedDecember19,2012at228‐237;seealsoDocketNo.13‐0034,FinalOrderdatedJune26,2013(“PhaseII”approvingsourcingagreementasrequiredinDocketNo.12‐0544).234CommonwealthEdisonCo.v.IllinoisCommerceCommission,etal.,2014ILApp(1st)130544,July22,2014.235See2015IPAProcurementPlanat93‐95.236SeeDocketNo.14‐0588,FinalOrderdatedDecember17,2014at315.


118

7.7 SummaryofStrategyforthe2015ProcurementPlan

Table7‐26summarizestherecommendationsofthisChapter.

Table7‐26:SummaryofProcurementPlanRecommendationsBasedonJuly15,2015UtilityLoadForecast(QuantitiestobeAdjustedBasedontheMarchandJuly2016LoadForecast):

DeliveryYear

Energy Capacity RenewableResourcesAncillaryServices


Procurement)


50%RFPinSep.201550%MISOPRA



upto7.8GWh*

NoRPSprocurementorsalesforotherresources,targetexceeded

Willbepurchasedfrom

MISO


Procurement)Upto125MWforecasted


25%RFPinSep.201550%RFPinFall2016

25%MISOPRA


Willbepurchasedfrom

MISO




25%RFPinFall201650%RFPinFall2017

25%MISOPRA


Willbepurchasedfrom

MISO




Willbepurchasedfrom

MISO


Nofurtheractionatthistime.


Willbepurchasedfrom

MISO

2016‐2017 Upto1,925MWforecastedrequirement(Spring

Procurement)


100%PJMRPMAuctions



upto16.3GWh*

Totalrenewablesare68GWhshortoftarget

Willbepurchasedfrom

PJM




100%PJMRPMAuctions


Willbepurchasedfrom

PJM




100%PJMRPMAuctions


Willbepurchasedfrom

PJM




Willbepurchasedfrom

PJM




Willbepurchasedfrom

PJM

AMERENILLINOIS

COMED


119


Procurement)


100%MISOPRA One‐yearSRECsprocurementupto13.2GWh


upto2.2GWh

Totalrenewablesare220.4GWhshortoftarget.Includes

165.3GWhofwind,13.2GWhofsolarand2.2GWhofDG

Willbepurchasedfrom

MISO


100%RFPinFall2016**


Willbepurchasedfrom

MISO


100%RFPinFall2016**


Willbepurchasedfrom

MISO


100%RFPinFall2016**


Willbepurchasedfrom

MISO


100%RFPinFall2016**


Willbepurchasedfrom

MISO

*ThetotalDGRECstobeprocuredwillbeadjustedbasedontheresultsoftheFall2015DGprocurementevent.**Thefall2016capacityprocurementwillcoverfiveplanningyears,startingwiththe2017‐18PlanningYearandendingwiththe2021‐2022PlanningYear.

MIDAMERICAN


120

8 RenewableResourcesAvailabilityandProcurement

ThisChapterfocusesontheprocurementofrenewableresourcesonbehalfofeligibleretailcustomersandalso provides informational guidance on the IPA’s considerations for the use of the Renewable EnergyResources Fund (“RERF”) which contains payments made by ARES as part of their RPS complianceobligations.Procurementonbehalfofeligibleretailcustomersissubjecttotargetsforpurchasevolumesandupperlimitsoncustomerbillimpacts,which,basedontheloadforecast,createsacapontheavailablebudgetforeachutility.

From 2009 through 2012, the IPA’s annual electricity procurement plans included purchase of renewableenergyresourcessufficienttomeettheRenewablePortfolioStandard(“RPS”)requirementsapplicabletotheeligible load of ComEd and Ameren Illinois. In 2013 and 2014, the IPA determined that resources undercontract were sufficient to meet the reduced eligible load, while in 2015 the IPA procured only SolarRenewableEnergyCredits,andplanstoprocureresourcesfromDistributedGenerationthisfall.Forthe2016Plan, inadditiontoanyrenewableenergycreditprocurements tomeet theRPStargets forAmerenIllinoisandComEd,theIPAwillseektoprocuresufficientrenewableenergycreditstomeettherenewableresourcestargetforMidAmericanbasedonMidAmerican’stotalIllinoisjurisdictionalload.

MidAmerican’s involvement in the 2016 Plan raises new questions about how to calculate the renewableresourcetargetappropriatetoit.Specifically,itisunclearwhetherrenewableenergyresourcesprocurementtargetsshouldbecalculatedforallofMid‐American’seligibleretailcustomerload,oronlyforthatportionofeligibleretailcustomerloadforwhichtheutilityspecificallyrequestsprocurement.Section1‐75(c)(1)oftheIPA Act references procurement percentages applicable to “each utility's total supply to serve the load ofeligible retail customers, as defined in Section16‐111.5(a)of thePublicUtilitiesAct.”237While Section16‐111.5(a)defines“eligibleretailcustomer”bycustomerstatusthatwouldappearto includeMid‐American’sentire eligible retail customer load, this same section also expressly contemplates thatMid‐Americanmayseekprocurementforonly“aportionofitseligibleIllinoisretailcustomersinaccordancewiththeapplicableprovisionssetforthinthisSectionandSection1‐75oftheIllinoisPowerAgencyAct.”238

IncommunicationswiththeAgency,MidAmericanhasstatedthatitsinterpretationofSection16‐111ofthePUAis thattheamountofRECstobeprocuredbytheIPAshouldbedeterminedbasedontheincrementalamountof energy and capacity planned to beprocuredby the IPA to serveMidAmerican’s eligible Illinoiscustomers, rather than the load forallof itseligible customers in Illinois.UnderMidAmerican’sviewpoint,becauseasmalljurisdictionalutilitymayelectfortheIPAtoprocureonlyaportionoftheenergyandcapacityrequired for itseligible customers, the IPAwould likewiseprocureRECs tomatch theprocurementof thisincrementalenergyandcapacity.

Alternatively, the IPAbelieves that the strongerargumentmaybe thatMidAmerican’s renewable resourcetargetsaredeterminedbaseduponMidAmerican’s“totalsupplytoserveeligibleretailcustomers”—inotherwords, its entire eligible retail customer load. While procurement may be requested by a small, multi‐jurisdictional utility for only a portion of that load, the renewable energy procurement target itself is setthroughthemoredirectlanguagecontainedinSection1‐75(c)(1)oftheIPAAct(“aminimumpercentageofeach utility's total supply to serve the load of eligible retail customers”), and that language remainscontrolling regardlessofwhether thebroaderprocurement is foronlyaportionofeligible retail customerload.BecausetheIPAbelievesthatthismaybetheappropriatereadingofthelaw,renewableenergyresourceprocurementtargetsreportedinthisChapterarecalculatedconsistentwiththisapproach.However,astheseprovisionsareopentomultipleinterpretations,theIPAinvitescommentsfrominterestedstakeholderstoaidwithmakingitsrecommendationforitsfiled2016ProcurementPlan.

23720ILCS3855/1‐75(c)(1)(emphasisadded).238220ILCS5/16‐111.5(a).


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After thePlan is filed, the IllinoisCommerceCommissionwillmakethe finaldeterminationofwhether theIPA’s proposed procurement plan meets the requirements of Illinois law—including proposed renewableenergy resourcesprocurementproposals and targets. If theCommissiondetermines that theMidAmericanrenewableenergyresourceprocurementshouldcoveronlytheincrementalportionofMidAmerican’seligiblecustomerload,thequantityofRECstobeprocuredwillbeapproximately14%ofthequantitythatwouldbeneededtocovertheutility’stotaleligiblecustomerload(asreportedinthisChapter).

Section1‐75(c)oftheIPAActrequirestheprocurementofat leastaminimumpercentageof“eachutility'stotalsupplytoservetheloadofeligibleretailcustomers”from“cost‐effectiverenewableenergyresources.”Under that provision, the following are the percentages of renewable energy resources required to beprocured.239The renewable energy resources obligation for the utilities in the 2016‐2017 delivery year is11.5%tomeettheJune1,2016target.Thisobligationincreasesbyat least1.5%eachyearthereaftertoatleast25%byJune1,2025.240

The obligation of each electric utility—i.e., the amount of renewable energy resources that have to beprocured tomeet these statutoryminimums—”shall bemeasured as apercentage of the actual amountofelectricity(megawatt‐hours)suppliedbytheelectricutilitytoeligibleretailcustomersintheplanningyearendingimmediatelypriortotheprocurement.”241Underthisstandard,ifaprocurementofRECsisscheduledtotakeplaceinSpring2016fordeliveryinthe2016‐2017deliveryyear,themostrecentlycompletedyear(i.e., theyear“endingimmediatelypriortotheprocurement”) isthe2014‐2015deliveryyear,asthe2015‐2016deliveryyearwouldnothaveendedpriortotheprocurement.Asaresult,customerswitchingtakingplace in the fall of 2015may notmanifest itself in significant changes to renewable energy procurementtargetsuntilprocurementstakeplaceinthespringof2017forthe2017‐2018deliveryyear.However,thatswitchingwillbereflectedintheactual2015‐2016deliveryyearload.242

Inaddition,theRPSmandateincludestargetsforspecificresourcetypes:75%wind,6%(byJune1,2015andthereafter)photovoltaics(“PV”)and1%(byJune1,2015andthereafter)distributedgeneration(“DG”)whichcanbeincludedwithinthePVandwindrequirements.243

ThespendingcapontheavailableRenewableResourcesBudget(“RRB”)isdefinedasfollows:

Theamountofrenewableenergyresourcesprocuredpursuanttotheprocurementplanforanysingleyearshallbereducedbyanamountnecessaryto limittheestimatedaveragenet increaseduetothecostof theseresources included in theamountspaidbyeligible retail customers inconnectionwithelectricservicetonomorethanthegreaterof2.015%oftheamountpaidperkilowatthourbythosecustomersduringtheyearendingMay31,2007ortheincrementalamountperkilowatthourpaidfortheseresourcesin2011.244

The estimated renewable resource volumes and dollar budgets available for use by each utility and theassumptions that provide the basis for these estimates reflect the utilities’ expected load forecasts as

239Renewableenergyresourcesaredefinedas:“energyanditsassociatedrenewableenergycreditorrenewableenergycreditsfromwind,solarthermalenergy,photovoltaiccellsandpanels,biodiesel,anaerobicdigestion,cropsanduntreatedandunadulteratedorganicwastebiomass,treewaste,hydropowerthatdoesnotinvolvenewconstructionorsignificantexpansionofhydropowerdams,andotheralternativesourcesofenvironmentallypreferableenergy.Forpurposesof[theIPAAct],landfillgasproducedintheStateisconsideredarenewableenergyresource.”20ILCS3855/1‐10.24020ILCS3855/1‐75(c)(1).24120ILCS3855/1‐75(c)(2).242ThesequantitiesareupdatedwitheachPlan’sloadforecastandwillchangeasthoseforecastsareupdated.Forexample,comparingtheComEdtotalRECtargetforthe2016‐2017deliveryyearinthe2015PlantothisPlanshowslittlechange,butforthe2017‐2018deliveryyearthetargetis20%higher,andforthefollowingyear34%higher.Thisreflectstheimpactofrevisingtheloadforecasttoaccountforthedecreaseinswitchingduetotheexpirationofmunicipalaggregationcontracts.ThechangesaremuchlesssignificantforAmerenIllinois.24320ILCS3855/1‐75(c)(1).24420ILCS3855/1‐75(c)(2)(E).


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described inChapter3and recommendedby the IPA tobeadoptedby the ICC. If the ICCwere toadoptadifferentloadforecast,thentheanalysiswhichfollowsinthisChapterwouldhavetoberevisedaccordingly.In futureprocurementplans, load forecastswill beupdatedbasedonnewdata (particularlyeligible retailcustomer switching rates). Therefore the renewable resource and related budget estimates presented infutureplanscoulddiffersignificantlyfromwhatispresentedinthisPlan.

In recent years, Ameren Illinois and ComEd have generally met their overall RECs procurement targets.However,someyearssince2012haveseentheutilitiesfallshortoftheirtechnology‐specificsub‐targets.Inthe 2012 plan, the IPA included a one‐year REC procurement to procure the minimum unbundled RECsrequiredtomeetthesolarandwindtargets(inadditiontoRECsseparatelyprocuredthroughthelegislativelymandated2012“ratestability”procurements).Dueto thevolumeof long‐term(20year)bundledRECandenergycontractsprocuredin2010,anddecliningeligibleretailcustomerload,therewerenoprocurementsofrenewableresourcesproposed(orsubsequentlyconducted)inthe2013or2014Plans.Forthe2015–2016deliveryyear (2015Plan),Ameren Illinois andComEdhadmet their overallRECs targets, butneitherhadprocuredsufficientSRECstomeetthesolarPVrequirements.TheCommissionapprovedtheIPA’sproposed1‐yearSRECsprocurementforComEdandAmerenIllinoistomeettheshortfalls.ThatSRECprocurementwasheldinthespringof2015.

Ameren Illinois and ComEd will be short SRECs and DG RECs for the 2016‐2017 delivery year, andMidAmerican is shortRECs for overall renewable energy resource compliance,windRECs, SRECs, andDGRECs due to not having previously participated in the IPA procurement process. ComEd is short RECs foroverallrenewableenergyresourcecompliance,butprocuringitsrequiredSRECvolumewouldbesufficienttofillthatgap.Toachievestatutorycompliance,theIPArecommendsaspring2016procurementofRECstomeet each utility’s requirements (other than tomeet the Distributed Generation sub‐targets, as discussedbelow) for the2016‐2017deliveryyear.Thequantities tobeprocuredwillbebasedupon the “RemainingTargets”ascalculatedfromtheupdatedMarch2016loadforecastsandwillbelimitedtothefundsavailablein the Renewable Resources Budget as reported at that time. As described elsewhere in the Plan, shouldconsensus on theMarch 2016 load forecasts be needed and not be reached, the quantities of RECs to beprocuredforthe2016‐2017deliveryyearwillbebaseduponthe“RemainingTarget”rowsofTable8‐1,Table8‐2,andTable8‐3forthatdeliveryyearfoundinthePlan.Totheextentpracticable, thestructure,processandcontractsfortheprocurementwillbebaseduponthoseusedfortheSRECprocurementconductedbytheIPAin2015.

Section1‐75(c)oftheIPAActalsorequirestheutilitiestoacquireRECsfromdistributedgeneration(“DG”)devicesamountingtoatleast1%ofeachutilitiestotalRECstarget.Dependingontheresultsoftheplannedfall2015DGprocurement, the IPAproposes toscheduleat leastoneDGprocurement in2016 tomeet theutilities’ remaining 2016‐2017 delivery year DG REC targets. Details related to the structure of thisprocurementarediscussedinSection8.4.

Underthelaw,theprocurementofDGresourcestomeetthoserequirementswillrequirecontractsofatleast5 years.245Because of continued volatility in the available Renewable Resources Budget present due tocustomerswitchingmanifestingitselfinthepotentialcurtailmentoftheexistingAmerenIllinoisandComEdLTPPAs from 2010, newmulti‐year contracts were entered into using funds collected from eligible retailcustomers carry a significant risk of future curtailments (and the resolution of competing curtailmentprovisionsbetweendistinctsetsoflong‐termcontracts).Asaresult,theIPAdoesnotrecommenduseoftheRenewable Resources Budget for Ameren Illinois or ComEd for contracts more than 1 year in length orextendingbeyondthe2016‐2017deliveryyear.ForAmerenIllinoisandComEd,thismayunfortunatelylimitthe use of Renewable Resources Budget funds tomeeting the technical requirements of the utilities’ RPSmandates rather thanachievingbroaderpolicygoals suchas fostering thedevelopmentofnewrenewable

24520ILCS3855/1‐75(c)(1)


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resourcesinIllinois.AbsentlegislativechangestotheIPAActandthePUA,thisisthelimittowhattheIPAcanproposeforuseoftheRenewableResourcesBudget

Because MidAmerican’s service territory does not feature the same load volume volatility created bycustomer switching, andbecauseMidAmerican isnot aparty to long‐termcontracts for renewable energyresources, the risk of needing to curtail contracts longer than 1 year appears to be very small forMidAmerican. As a result, the IPA believes that the use of the Renewable Resources Budget would beappropriateforcontractswithMidAmericanextendingbeyondthedeliveryyear.

TheIPAnotesthatSection1‐56(i)of theIPAActrequiredthedevelopmentofasupplementalphotovoltaic(“SPV") procurement plan for the procurement of RECs from photovoltaic systems. The IPA’s initial SPVprocurementwasheldinJune2015withtwoadditionalSPVprocurementsplannedforNovember2015andMarch2016.AstheseRECsarepurchasedbytheAgencyoutoftheRenewableEnergyResourcesFundandnotby theutilities, theSRECsprocuredunder theSPVplandonotcount towards theutilities’DGRECsorSRECstargets.

8.1 CurrentUtilityRenewableResourceSupplyandProcurement


AsshowninTable8‐1,AmerenIllinois’currentrenewableresourcecontractswillcoveritstotalrenewablestargets for the 2016‐2017 delivery year.246Assuming that no additional purchases of renewable energyresourcesaremade,AmerenIllinois isprojectedto fallshortofmeeting itsRPSrequirements in the2017‐2018deliveryyearby6%.Inthe2018‐2019,2019‐2020and2020‐2021deliveryyears,theshortfallfortotalrenewablesisprojectedtoreach41%,47%and51%,respectively.

Table8‐1alsoshowsthetargetsandpurchasingrequirementsforAmerenIllinoistomeetthegoalssetbytheIllinois Power Agency Act for wind, photovoltaics, and distributed generation based on the currentlyestablished fractions of the total renewables requirement.247Ameren Illinois is projected tomeet itswindgenerationgoalsforthe2016‐2017andthe2017‐2018deliveryyears.Assumingthatnoadditionalpurchasesaremade,AmerenIllinoisisprojectedtofallshortofthewindgoalby22%,29%and35%inthe2018‐2019,2019‐2020,and2020‐2021deliveryyears,respectively.AssumingthatnoadditionalpurchasesofPVandDGaremade,Ameren Illinois is projected to fall short of thephotovoltaic anddistributedgeneration goals ineachdeliveryyear.

Additionally, Ameren Illinois is projected to have Renewable Resources Budget funds248with which topurchaserenewables(Table8‐4).249

246ThisTabledoesnotincludetheresultsoftheupcomingDGprocurement;asthatprocurementwillfeature5‐yearcontracts,itmayimpactthesevolumes.24720ILCS3855/1‐75(c)(1).248Availablerenewableresourcesbudgetfundsfortheupcomingyeararearesultofthehigherloadforecastrelativetothatutilizedinlastyear’sprocurementplan.TheRPSbudgetisafunctionof,amongotherthings,forecastedeligibleretailload.Relativetolastyear,forecastedeligibleretailloadissignificantlyhigherasofthisprocurementplanduetotherecentobservationofcommunitiesoptingtosuspendtheirmunicipalaggregationprogramsandtakesupplyfromAmerenIllinois.249InitscommentsontheAgency’sdraft2015Plan,AmerenaskedtheIPAtoaffirmativelystatethatAmerenIllinois’excesswindRECsnotbesoldbacktothemarket,andinsteadrecommendedthattheseRECsberetiredconsistentwithcontractualprocedures.TheIPAhasnoplanorintentiontoselltheRECsfromanyexistingutilitycontractbacktothemarket,andthushasaskedfornoauthoritytothiseffectinits2016ProcurementPlan.


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Table8‐1:AmerenIllinoisExistingRPSContractsvs.RPSRequirements250DeliveryYear

TotalRenewables

Wind Photo‐voltaics

DistributedGeneration

2016‐2017

Target(MWh) 776,681 582,510 46,601 7.767PurchasedMWh 1,029,245 976,851 12,394 0RemainingTarget(MWh) ‐‐ ‐‐ 34,207 7,767

2017‐2018

Target(MWh) 907,169 680,377 54,430 9,072PurchasedMWh 854,396 848,338 6,058 0RemainingTarget(MWh) 52,773 ‐‐ 48,372 9,072

2018‐2019

Target(MWh) 1,013,368 760,026 60,802 10,134PurchasedMWh 600,000 596,571 3,429 0RemainingTarget(MWh) 413,368 163,455 57,373 10,134

2019‐2020


2020‐2021


8.1.1.1 AmerenIllinoisSRECProcurementfor2015‐16DeliveryYear

OnApril 16, 2015, the IPAheld anSRECprocurementpursuant to theprocurementplan approvedby theCommission in Docket No. 14‐0588. A total of 30,212 SRECs were acquired to meet Ameren Illinois’procurementtargetforthe2015‐16deliveryyear.NoSRECswereprocuredforsubsequentdeliveryyears.Aprocurementeventforupto6,518DGRECs/yearisplannedforthefallof2015;pursuanttotheprovisionsofSection 1‐75(c) of the IPA Act, this procurement will feature five‐year contracts (extending into futuredeliveryyears).

8.1.2 ComEd

Table 8‐2 shows ComEd’s current RPS contracts relative to its renewables requirements and includesconsiderationofComEd’s statutory targets established for total renewable energy resourcesaswell as forwind, photovoltaics, and distributed generation over the five‐year forecast horizon.251ComEd’s forecastindicates that for the2016‐2017deliveryyear total renewables are67,960RECs short of the targetwhileenough renewables have been procured tomeet itswind targets. In subsequent delivery years, ComEd isforecastedtofallshortofitstotalrenewablestargetby35%in2017‐2018,56%in2018‐2019,63%in2019‐2020, and 67% in 2020‐2021. ComEd is also forecasted to fall short of the photovoltaic and distributedgenerationtargetsineachofthefivedeliveryyearsconsideredinthisPlanandtofallshortofthewindtargetinthe2017‐2018deliveryyearandbeyond.

AswithAmerenIllinois,ComEdisalsoprojectedtohaveRenewableResourcesBudgetfunds252withwhichtopurchaserenewables(Table8‐5).

250VolumesarebasedontheJuly2015expectedloadforecast.TheMarch2016loadforecastwillupdatethe2016‐2017volumesandthequantityofDGRECspurchasedinthefall2015procurement,andfutureyears’actualprocurementtargetswillbebasedoffofthosefutureyears’loadforecasts..251ThisTabledoesnotincludetheresultsoftheupcomingDGprocurementwhichwillfeature5‐yearcontractsandthusimpactthesevolumes252Seepriorfootnotere:loadmigration.


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Table8‐2:ComEdExistingRPSContractsvs.RPSRequirements253DeliveryYear

TotalRenewables

Wind254 Photo‐voltaics255

DistributedGeneration256

2016‐2017

Target(MWh) 1,629,357 1,222,018 97,761 16,294PurchasedMWh 1,561,397 1,340,016 27,895 0RemainingTarget(MWh) 67,960 ‐‐ 69,866 16,294

2017‐2018

Target(MWh) 2,360,934 1,770,700 141,656 23,609PurchasedMWh 1,533,198 1,233,838 27,887 0RemainingTarget(MWh) 827,736 536,862 113,769 23,609

2018‐2019

Target(MWh) 2,878,296 2,158,722 172,698 28,783PurchasedMWh 1,261,725 1,233,838 27,887 0RemainingTarget(MWh) 1,616,571 924,884 144,811 28,783

2019‐2020

Target(MWh) 3,444,117 2,583,087 206,647 34,441PurchasedMWh 1,261,725 1,233,838 27,887 0RemainingTarget(MWh) 2,182,392 1,349,249 178,760 34,441

2020‐2021

Target(MWh) 3,789,473 2,842,105 227,368 37,895PurchasedMWh 1,261,725 1,233,838 27,887 0RemainingTarget(MWh) 2,527,748 1,608,267 199,481 37,895

8.1.2.1 ComEdSRECProcurementfor2015‐16DeliveryYear

OnApril 16, 2015, the IPAheld anSRECprocurementpursuant to theprocurementplan approvedby theCommission inDocketNo.14‐0588.A totalof49,700SRECswereacquired tomeetComEd’sprocurementtargetforthe2015‐16deliveryyear.NoSRECswereprocuredforsubsequentdeliveryyears.Aprocurementeventforupto13,194DGRECs/yearisplannedforthefallof2015;pursuanttotheprovisionsofSection1‐75(c)oftheIPAAct,thisprocurementwillfeaturefive‐yearcontracts(extendingintofuturedeliveryyears).

8.1.3 MidAmerican

Table 8‐3 shows the forecast of the statutory targets for MidAmerican’s procurement of total renewableenergy resources, wind, photovoltaics, and distributed generation over the five‐year forecast horizon.MidAmerican does not currently have any existing purchased RECs to meet these targets. If the IPA isdirectedtoprocureRECsbasedononlyMidAmerican’sincremental loadinIllinois,thentheRECquantitiesrequiredwouldbeapproximately14%ofthequantitiesshowninthetable

253VolumesarebasedontheJuly2015expectedloadforecast.TheMarch2016loadforecastwillupdatethe2016‐2017volumesandthequantityofDGRECspurchasedinthefall2015procurement,andfutureyears’actualprocurementtargetswillbebasedoffofthosefutureyears’loadforecasts.254WindRPSrequirementis75%oftheannualRPSrequirement.See20ILCS3855/1‐75(c)(1).255PVRPSrequirementis6%oftheannualRPSrequirement.See20ILCS3855/1‐75(c)(1).256DistributedGenerationRPSrequirementis1%oftheannualRPSrequirement.See20ILCS3855/1‐75(c)(1).


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Table8‐3:MidAmericanExistingRPSContractsvs.RPSRequirementsDeliveryYear

TotalRenewables

Wind257 Photo‐voltaics258

DistributedGeneration259

2016‐2017

Target(MWh) 220,418 165,313 13,225 2,204PurchasedMWh 0 0 0 0RemainingTarget(MWh) 220,418 165,313 13,225 2,204

2017‐2018


2018‐2019


2019‐2020


2020‐2021


8.2 AvailableRenewableResourcesBudgetandLTPPACurtailment

In2010,pursuanttoanIPAprocurement,ComEdandAmerenenteredintolong‐term(20‐year)contractsforrenewableenergyresources(“LTPPAs”)fromaseriesofwindandphotovoltaicfacilities.Inpastproceedings,theIPAhassoughtexpressauthorizationforthosecontractstobe“curtailed”(amandatedreductionintheamount which need be purchased under the contract) should the payments required under the contractexceedtheexpectedRenewableResourcesBudget.Acurtailmentofthesecontractsrisksbeingtriggeredbycustomers switching to alternative suppliers and consequently load shifting away from the utilities, thusreducingtheavailablebudget.

8.2.1 ImpactofBudgetCap

Section1‐75(c)(2)oftheIPAActrequirestheIPAtoreducetheamountofrenewableenergyresourcestobeprocured for anyparticular year in order to keep the “estimated”net increase in charges to eligible retailcustomersbelowthestatutory2.015%rateimpactcap.Forthe2013‐2014and2014‐15deliveryyears,inanefforttokeepthecostofrenewableenergyresourcesbelowthestatutoryrate impactcap,theCommissionpre‐approved the curtailment of the 2010 LTPPAs based on the information contained in that subsequentMarch’s updated load forecasts. Curtailment has been required of ComEd’s LTPPAs, but has not yet beenrequired for theAmeren Illinois contracts.Curtailmentswerenot required in the2015‐2016deliveryyearand, based on the load forecasts supplied by the utilities, are not currently anticipated over the five‐yearforecasthorizonofthe2016ProcurementPlan.

For the 2016‐2017 delivery year, the Ameren Illinois and ComEd load forecasts have grown significantlybasedlargelyonasignificantnumberofmunicipalitiessuspendingtheirmunicipalaggregationprogramsandreturningtoutilitysuppliedservice.BecausethedeliveryyearRenewableResourceBudget isa functionoftheamountofeligibleutility load,whichhas increasedrelative to lastyear’s loadforecasts, it is forecastedthat the delivery year Renewable Resource Budgets will exceed the Contractual Cost for RECs alreadyprocured in each delivery year. Therefore, both Ameren Illinois (Table 8‐4) and ComEd (Table 8‐5) are

257WindRPSrequirementis75%oftheannualRPSrequirement.See20ILCS3855/1‐75(c)(1).258PVRPSrequirementis6%oftheannualRPSrequirement.See20ILCS3855/1‐75(c)(1).259DistributedGenerationRPSrequirementis1%oftheannualRPSrequirement.See20ILCS3855/1‐75(c)(1).


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forecasted to have sufficient funds available in each of the five delivery years covered by this plan.MidAmericandoesnotholdanyLTPPAs.

Table8‐4:AvailableRenewableResourcesBudgetFundsandForecastReductions(Curtailments)ofLong‐termRenewableContracts(LTPPAs),AmerenIllinois

DeliveryYear

ContractualRECCost($)

DeliveryYearRPSBudget

($)

AvailableRPSFunds

($)

LTPPAQuantity

Reduction(%)2016‐2017 10,403,861 12,617,481 2,213,620 0.0%2017‐2018 9,412,155 12,668,038 3,255,883 0.0%2018‐2019 8,000,000 12,721,183 4,721,183 0.0%2019‐2020 7,999,000 12,768,585 4,769,585 0.0%2020‐2021 7,753,000 12,768,585 5,015,585 0.0%

Table8‐5:AvailableRenewableResourcesBudgetFundsandForecastReductions(Curtailments)ofLong‐termRenewableContracts(LTPPAs),ComEd

DeliveryYear

ContractualRECCost

($)

DeliveryYearRPSBudget($)

AvailableRPSFunds

($)

LTPPAQuantity

Reduction(%)2016‐2017 23,502,192 37,550,843 14,048,651 0.0%2017‐2018 23,803,641 40,720,222 16,916,581 0.0%2018‐2019 23,438,590 40,963,118 17,524,528 0.0%2019‐2020 23,566,909 41,254,513 17,687,604 0.0%2020‐2021 23,178,932 41,280,076 18,101,144 0.0%

ThecontractedRECcostsforthe2016‐17deliveryyearforAmerenIllinoisandComEdarerespectively82%and 63% of the current estimates of their respective 2016‐17 RPS budget caps. Those budgets dependdirectlyoneligibleretailload,soitappearsthataslongasComEd’sMarch2016forecastfor2016‐2017loadiscloseto63%ofitsJuly2015forecastvalue,andaslongasAmerenIllinois’isMarch2016forecastfor2016‐2017loadisinturncloseto82%ofitsJuly2015forecastvalue,neitherutilitywillhavetocurtailitsLTPPAs.Underthetwoutilities’ lowloadforecastscenarios,ComEdwouldnothavetocurtail itsLTPPAs;however,AmerenIllinoisforecaststhattheRenewableResourcesBudgetwouldbeexceededandapartialcurtailmentofLTPPAswouldbeneeded.

WhileitappearshighlyunlikelythatcurtailmentoftheLTPPAswouldberequiredinthe2016‐2017deliveryyear,theIPAstillrecommendsthatafinaldeterminationbebasedupontheMarch2016loadforecasts.Intheeventthatcurtailmentsarerequired,theIPArecommendsthatthemethodologyadoptedintheICC’sOrderonRehearingofthe2014ProcurementPlanbeemployedforthecalculationofRECpricesforcurtailedRECs(including theuse ofAnnual ContractValues).260While it is againhighly unlikely that curtailmentswill berequired, as hourly ACP funds are proposed for procurement of DG RECs, the IPA proposes to address apotentialcurtailmentthroughcontinuingitsprioroffertopurchasecurtailedRECsattheimputedRECpricesfromthe2010contractsusingtheRenewableEnergyResourcesFund.

Table8‐6showsthebudgetavailableforMidAmerican.IftheIPAisdirectedtoprocureRECsbasedononlyMidAmerican’s incremental load in Illinois, then the available budgetwould be approximately 14%of thequantitiesshowninthetable

260InitsOrderonRehearing,theCommissionrequestedthat,“whatallocationmethodshouldbeusedwillbereviewedagainanddeterminedintheIPAProcurementPlancaseforthe2015‐2016year.”(DocketNo.13‐0546,OrderonRehearingat56)duetothelowprobabilityofneedingtocurtailtheLTPPAcontractsinthe2015‐16deliveryyear,theIPAhasdeterminedthatthecurtailmentmethodologydoesnotneedtobeupdatedatthistimeandconsiderationofthisissuedeferredtoafutureyearwhereitismorerelevant.


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Table8‐6:AvailableRenewableResourcesBudgetFunds,MidAmerican

DeliveryYear

DeliveryYearRPSBudget($)

AvailableRPSFunds

($)2016‐2017 2,477,311 2,477,3112017‐2018 2,486,717 2,486,7172018‐2019 2,496,201 2,496,2012019‐2020 2,507,235 2,507,2352020‐2021 2,518,768 2,518,768

8.3 UseofHourlyAlternativeCompliancePaymentsHeldbytheUtilities

Ameren Illinois andComEdalso collectAlternativeCompliancePayments (“ACPs”) onbehalf of customerstakinghourlyservicefromtheutility.261UnliketheACPfundspaidbyARESintotheRERF,whichareheldandadministeredbytheIPA,utilityhourlycustomerACPfundsareheldbytheutilities.262AsrequiredbytheIPAAct,eachutilityhasdisclosedtheamountofhourlycustomerACPfundsbeingheldasofMay31,2015:forAmerenIllinois,thebalanceis$10,040,276;forComEd,thebalanceis$19,039,957.

TheIPAActrequiresthatACPfundsfromutilityhourlycustomersbeusedto“increase[theutility’s]spendingonthepurchaseofrenewableenergyresourcestobeprocuredbytheelectricutilityforthenextplanyearbyanamountequal to theamountscollectedby theutilityunder thealternative compliancepayment rateorrates in the prior year ending May 31.”263Starting with the 2013‐2014 delivery year, the CommissionapprovedtheuseofhourlyACPfundstopurchaseRECsfromanycurtailedLTPPAs,andtheIPArecommendsacontinuationofthatpolicy.

Aspreviouslydiscussed,theutilitieshaveacurrentshortfallinmeetingtheirstatutoryDGtargets(althoughthe extent of that shortfall will not be known until the completion of the Fall 2015 DG procurement). Ittherefore appears that utilizing the already collected, and otherwise unspent, hourly ACP funds to allowAmerenIllinoisandComEdtomeettheirDGtargetswouldbeappropriatetofurtheranaspectoftheutilities’RPS obligations. Additionally, as contracts for DG resources must be “no less than 5 years” in length,264entering into5yearcontractsusingexistingACPfundsalreadycollectedfromhourlycustomerseliminatestheloadmigrationriskpresentwiththerenewableresourcesbudget(fromwhichlong‐termcontractshavebeen subject to curtailments in the past, as detailed above) while ensuring that there are no impacts oncustomer rates. Although distributed generation systems were eligible to participate in the IPA’s priorrenewableenergyresourceprocurements,theFall2015procurementspecificallytargetingDGresourcesisthefirstofitskindconductedbytheIPA.

8.4 DistributedGenerationProcurement

Aspartofthedevelopmentofthe2015Plan,afteranalysisandreviewofcommentsfromstakeholdersandadditional consideration (includingcoordination,wherepossible,with theSPVprocurementplan), the IPAsettledonadistributedgenerationprocurementmodelforthefall2015procurement.Thismodelwasbasedon the Agency’s traditional procurement process involving the block procurement of renewable energycredits with competitive bids selected on the basis of price. As the Agency is proposing a distributedgenerationprocurementtomeetstatutoryDGtargets,andnotsimplyasolarphotovoltaicRECprocurement,

261See20ILCS3855/1‐75(c)(5).262Seeid.263Id.26420ILCS3855/1‐75(c)(1).


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theAgencyalsobelievesthatthismodelleftitbestabletoaccommodateRECsfromgeneratingtechnologiesbeyondsolarphotovoltaics.

TheIPAisproposingthemodelas implementedforthe2015procurementasthestartingpointfora2016procurement of DG RECs beginning in the 2016‐2017 delivery year. While the final results of thisprocurementeventwillstillnotbeknownbythefilingofthisPlanonSeptember28,2015,moreinformationwillbeavailableontheresponsetotheprocurementevent.Asaresult,theIPAmaymakeadditionalchangestothismodelinitsSeptemberfiledPlan,andspecificallyseekscommentsonthisDGprocurementproposalfrompartiesengagedinthedevelopmentofandparticipationinthatprocurementprocess.

UnlikewiththeIPA’sSPVprocurementunderSection1‐56(i)oftheIPAAct,nothinginthelawgoverningthisDG procurement distinguishes between “new” or “existing” systems. As a result, the Agency’s solerequirement regarding the system completion date is that all participating DG systemsmust successfullybegindeliveryofRECsgeneratedinthe2016‐2017deliveryyear.Contractswillbeforthefivedeliveryyearsstartingwith2016‐2017deliveryyear.

The IPA recognizes that given the limited amount of distributed generation currently in Illinois, thisapproach’ssuccesshingesontheabilityoftheIllinoisDGmarketbothtoself‐organizeandtogrow.ThereforetheAgencywillallowbidstocontainDGsystemsofallqualifyingsizesandresourcetypes.Systemsmustbenolargerthan2,000kW.ThetechnologytypeseligibletoparticipatearedefinedbytheIPAActandincludeDG“poweredbywind,solarthermalenergy,photovoltaiccellsandpanels,biodiesel,cropsanduntreatedandunadulteratedorganicwastebiomass,treewaste,andhydropowerthatdoesnotinvolvenewconstructionorsignificant expansion of hydropower dams.”265Benchmarks used by the Procurement Administrator toevaluatebidsmaydependonsystemsizeand/ortechnology.Bidsthatmeetorbeatthebenchmarkswillbeevaluatedfirstonthebasisofprice,andthenonthebasisofachievinga50‐50balanceofRECsprocuredfromeachof the two categories of systems, namely systems below25 kWand systems of 25‐2,000 kW in size,whilemaintainingwinningbidsizesataonemegawattthreshold.

The IPA’splannedDG renewable resourceprocurementwillusehourlyACP funds forAmeren Illinois andComEd,anduse theRenewableResourcesBudget forMidAmerican.OnlyhourlyACP funds thathavebeencollectedasofMay30,2016andnotallocatedtothepurchaseofeitherDGRECsfromthefive‐year2015DGprocurementcontractsorcurtailedRECsforthe2016‐2017deliveryyearmaybeused.TheIPAwillprocureDGRECsuntilfundsarefullyallocatedortheutilities’DGgoalsaremet,whichevercomesfirst.Theproductsto be procured are RECs from DG systems that are interconnected with Ameren Illinois, ComEd,MidAmerican,amunicipalutilityinIllinois,oraruralelectriccooperativeinIllinois.DGsystemsneednotbeintheserviceterritoryoftheutilitypurchasingtheRECs.

8.4.1 ProcurementProcess

TheAgency’sapproachwillbetoprocureDGRECsthroughasingleprocurementeventinacompetitivebidprocess in the Fall of 2016with two categories of systems participating. The first category is for systemsunder25kW,thesecondforsystemsbetween25kWand2MW.

Bidsmustbeatleastonemegawattinsize,butmayfeatureanumberofDGsystemsofallqualifyingsizesandresource types. The bidder must identify the specific system(s) that will provide the RECs; “speculativebidding” of RECs from systems not specifically identified will not be permitted. Evidence regarding thesystemsmayinclude,butisnotlimitedto,lettersofintent,signedcontracts,interconnectionornetmeteringapplications,localpermits,etc.

26520ILCS3855/1‐10.


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Section 1‐75(c)(1) of the IPA Act requires that aggregators “aggregate distributed renewable energy intogroupsofnolessthanonemegawattininstalledcapacity.”Consistentwiththisprovision,thefirstblockofDGsystemsbidbyeachbiddermustbeatleastonemegawattinsizeofferedatasingleblendedpriceperREC.SubsequentblocksofDGsystemsmustbebidathigherpricesandmustbeatleast100kW.BiddersmaynotdesignatedifferentRECpricesfortheRECsgeneratedfromasingledistributedgenerationsystemorforRECsassociatedwithagivenblock.Whileblockpricesmaydiffer, eachbidder’s resultingRECcontractwith thepurchasing utility will be at a single blended price, encompassing all successful bids which have beenassignedtothatutility.Apre‐determinedcapacityfactorforeacheligibletechnologywillbeusedtocalculateanannualnumberofRECsforeachblocktobedeliveredineachyearofthecontractexceptthefirst.ThebidforablockmayincludeadifferentnumberofRECsforthefirstyearofthecontracttotheextentthatsomeofthesystemsincludedintheblockarenotyet inoperation.Forthe2016‐2017deliveryyearRECsfromanymonthinthedeliveryyearwillbeeligible.

Asrequiredbylaw,theAgencymustendeavortoensurethat,totheextentavailable,halfofthetotalDGRECsprocured by the Agency are from “devices of less than 25 kilowatts in nameplate capacity.” Section 16‐111.5(e) of the PUA requires that the Agency’s procurement process be conducted through selectingcompetingbids“solelyonthebasisofprice.”TheIPAbelievestheserequirementscanbeproperlybalancedbyprocuringonthebasisofpricewithineachcategory(<25kW,and25kWto2MW)whileensuringthatthewinningbidsizeremainsatleastonemegawatt.Ifthetargetismetunderthebudgetandonecategoryislessthan50%of the target, then thenextmost competitive bid in that categorywouldbe selected andwouldreplaceDGRECsfromasystemintheothercategory(totheextentsuchabidisavailable).Thismeansthat,forexample,asub‐25kWsystemcanbeselectedaheadofanabove‐25kWsystemwithalowerprice,butonlyifthatselectionisrequiredtoreachthetarget50%ofDGRECsfromsub‐25kWsystems.ThemarginalbidderintheevaluationofbidscouldreceiveacontractthatincludesaportionofRECsfromaparticularsystemandthebidderwillhavetheoptionofwhetherornottoacceptthecontract.AsinotherprocurementsconductedbytheIPA,allwinningbidsmustalsobebelow“benchmarks”developed“foreachproductprocured.”

Whileeachoftheutilitieshasseparatecompliancetargetsandbudgets,winningbidswillbeassignedtotheutilitiesusingasa guideeachutility’spro‐rata shareof totalRECsandminimizing thenumberofwinningbiddersthathavecontractswithmorethanoneutility.266Eachsystemcoveredbyacontractawardedinthisprocurementmustbeginaccumulatingmetereddeliveriesofrenewableenergypriortotheendofthe2016‐2017deliveryyear(May31,2017).Supplierswillberequiredtodemonstratethateachsystemhasgeneratedelectricity that was tracked by GATS orM‐RETS byMay 31, 2017. Should a system not comply with thisrequirement, the bidder’s contract volume will be reduced accordingly by the amount allocated to thatsystem.

Within2daysafteraprocurementeventfeaturing“sealed,bindingcommitmentbidding”withbidsselected“on the basis of price,” reports on the procurement event are to be submitted by the procurementadministratorandtheCommission’sprocurementmonitortotheCommissionforreview.Thesereportsaretocontainbiddingresults,arecommendationfortherejectionoracceptanceofbids,andtheassignmentofwinningbids toeachutility.TheCommissionwill then issueadecisiononwhether toacceptor reject theprocurementresultswithin2daysafterreceivingthereports.

Within3daysaftertheCommission’sdecision,“theutilityshallenterintobindingcontractualarrangementswiththewinningsuppliersusingthestandardformcontracts.”

266TheProcurementAdministratormayuseitsdiscretioninassigningbids(includingproratedsharesofbids)toeachutilitytoaccommodatethefactthattheprorationofthetotalvolumeofselectedbidsthatwouldbeallocatedtoeachutility’sprocurementtargetmaynotevenlybedividedduetothesizeofthebids.


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8.4.2 KeyContractTerms

Contracts under the DG procurements are between winning bidders and Ameren Illinois, ComEd, orMidAmerican; the IPA is not a contract party as it is for the procurements of solar photovoltaic RECsconductedpursuanttotheSupplementalPhotovoltaicProcurementPlan.ContractswillprovidepaymentforRECs generatedover a five year delivery years startingwith thedelivery year that commences on June1,2016.UtilitycontractswillnotfeaturepaymentspriortoRECdelivery,suchaspre‐paymentattheexecutionofacontractorwhenasystembecomesenergized.Thecontractmaybetransferredorassignedwithconsentfromtheutility.Suchconsentwillbeautomaticiftheownershipofthesystemchanges,iftheassignmentistoanaffiliateofthecounterparty,orisforfinancingpurposes.Thecounterpartywillberequiredtoeffectsuchassignmentortransferintheeventofbankruptcyordissolution.

8.4.3 CreditRequirementsandBidder/SupplierFees

TheIPAisrequiredtorecoverthecostofconductingthisprocurementthroughbidderfees267andtodevelop“standardcredittermsandinstruments.”268Forthisprocurement,thoseareasfollows:

Allbidderswillpaya$500non‐refundablebidparticipationfee.Thisfeeisnon‐refundableandwillbeassessedevenlyacrossallbidders.

Bidderswillprovideadeposit(intheformofapre‐bidletterofcredittotheIPA)of$8/RECaspartofthebidderregistrationprocess.Bidderswhosebidsarenotselectedwillhavetheirpre‐bidletterofcreditreturned.Forabidderwhoonlyissuccessfulforaportionoftheirbids,thereturnwillbeproratedbasedupontheirwinningbids.

WinningbidderswillbeassessedaSupplierFeethatreflectsthebalanceofthecostofconductingtheprocurement less the totalof thebidparticipationfees.AnestimatedSupplierFeeperRECwillbeannouncedprior to the opening of bidder registration, and the final Supplier Fee perRECwill beannouncedafterbidderregistrationiscompletedbutpriortothebidduedate.WinningbidderswillhavesevendaysaftertheapprovaloftheprocurementresultsbytheCommissiontopaytheSupplierFeeduetotheIPA(andupondoingsowillhavetheirdeposit–thepre‐bidletterofcredit‐released).

AllwinningbidderswillalsohavesevendaysaftertheapprovaloftheprocurementresultsbytheCommissiontoprovideapost‐bidletterofcredittotheIPAintheamountof10%ofthetotalvalueofthecontract(s)awarded.

The IPA will return an adjusted letter of credit back to the winning bidder upon the bidderdemonstratingtotheIPAthateachspecificprojecthasbegundeliveryofRECsfromthe2016‐2017deliveryyeartotheapplicableutility.

AnysystemthatisnotsuccessfullydevelopedwillforfeititsdepositforthoseRECs.

Inadditiontothecreditrequirementsdescribedinthissession,theRECdeliverycontractwiththeutilitymayalsoincludeanongoingperformanceassurancecreditrequirementthatbeginswiththestartofRECdelivery.REC delivery contract terms and conditions will be developed consistent with the contract developmentprocessandrequirementssetforthinSection16‐111.5(e)(2)ofthePUA.

8.4.4 Aggregators

UnlikewiththeIPA’sSupplementalPhotovoltaicProcurementPlandevelopedpursuanttoSection1‐56(i)ofthe IPAAct,whichdoesnotdefineaggregatorsize,Section1‐75(c)(1)requiresthataggregators“aggregate

26720ILCS3855/1‐75(h).268220ILCS5/16‐111.5(e)(2).


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distributedrenewableenergyintogroupsofnolessthanonemegawatt in installedcapacity.” TheIPAwillallowfor“self‐aggregation”fromsystemowners,solongasthosebidsareatleastonemegawatt.ThebidderwillserveasthecounterpartywiththeutilityincontractsforthedeliveryofRECs;inthecaseofnon‐systemowners(third‐partyaggregators),thebiddermusthaveownershipovertheRECsorthecontractualrighttotransferorassignRECstotheutilitylegally.

Giventhenumberofsystemsrequiredtoconstituteafullmegawatt,meetingaonemegawattthresholdmaybechallengingforaggregatorsorganizingbidsofsmallersystems.ItmaybealsoespeciallychallenginggiventherelativelysmalluniverseofexistingDGsystemsinIllinois.Anyparticipatingsystemwouldbothneedto1)haveRECsavailableforprocurement(i.e.,notalreadyundercontract)andbewillingtotransferavailableRECs;269and2)havetheknowledgeandunderstandingnecessarytoparticipatethroughanaggregatorinanIPAprocurementevent.Inits2015Plan,inanattempttoallowthemarketsufficienttimetoorganize,theIPAscheduleditsDGprocurementfortheFallof2015.Whilethislaterprocurementdateriskedmoretimespentout of compliance with statutory DG procurement goals during the 2015‐16 delivery year, the IPA felt itnecessarytoallowaggregatorsandotherinterestedpartiessufficienttimetoorganizesystemsandbidsforitsfirstDGprocurement.

Keepingwith that schedule, and in recognition of the proposed and scheduled SRECprocurements due totakeplaceundertheSPVandthe2016ProcurementPlanduringtheSpringof2016,theIPAagainproposesthat its DGprocurement be held later in the year, in the Fall of 2016. The IPAwill allow for the contractdeliveryofallRECsgeneratedduringthe2016‐17deliveryyear fromwinningbidders(andnotonly thoseRECsgeneratedaftertheexecutionofcontracts).

8.5 AlternativeCompliancePaymentsHeldbytheIPAintheRenewableEnergyResourcesFund

TheRERFbalanceasofApril1,2015equals$30,550,341.21,thetotalamountreceivedintheIPA’sRERFattributabletoARESACPpaymentslessthecostofRECspurchasedpertheIPA’soffertouseRERFfundstopurchasecurtailedRECsfromthe2010LTPPAsthatwerenotpurchasedbyComEdusinghourlyACPfunds,anda$98milliontransfertotheIllinoisGeneralRevenueFundpursuanttoPublicAct99‐0002.Priorto2015theICChasheldthatitdidnothavejurisdictionovertheRERF,andasaresulttheIPAdidnotseekapprovalforprocurementusingtheRERFinpreviousplanyears.270Section1‐56(i)oftheIPAActrequiredtheIPAtodevelopasupplementalphotovoltaic(“SPV”)procurementplantospendupto$30milliononRECsfromphotovoltaicresourcesusingtheRERF.TheAgency’sSPVprocurementplanwasapprovedbytheCommissioninDocketNo.14‐0651.ThefirstprocurementeventunderthatplanwasheldinJune2015andsuccessfullyallocatedthefull$5millionbudgetforthatevent.WhiletheSPVprocurementplandoesnotdirecttheIPAtoutilizethefullRERFbalance(whichwillincreaseasARESmakefuturecompliancepayments),itisanimportantfirststepforwardinallowingthosefundstobeusedfortheirintendedpurpose.TheIPAhopesthatfuturelegislativechangeswilladdtotheeasethroughwhichtheIPAcanusetheremainingfundbalancetofurthertheRERF’spurposes.

269Basedonindustryfeedback,theIPAunderstandsthismaybeachallengefortheoperatorsofsomeexistingcommercialsystemswhoalreadyclaimthattheirenergyissourcedfromrenewablesbecausethesale,transfer,orassignmentoftheenvironmentalattributes(i.e.,theRECs)isinconsistentFederalTradeCommissionguidelines.(seehttp://www.business.ftc.gov/documents/environmental‐claims‐summary‐green‐guidesformoreinformation).Whilethisfactorisunlikelytopresentachallengewithaggregatingsmallerresidentialsystems,participationfromlargersystemsmaybenecessaryfora1MWthresholdtobemet.270DocketNo.12‐0544,FinalOrderdatedDecember19,2012at112‐114.


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9 ProcurementProcessDesign

Theproceduralrequirements fortheprocurementprocessaredetailed in the IllinoisPublicUtilitiesActatSection16‐111.5.271TheProcurementAdministrator,retainedbytheIPAinaccordancewith20ILCS3855/1‐75(a)(2), conducts thecompetitiveprocurementeventsonbehalfof the IPA.Thecostsof theProcurementAdministrator incurred by the IPA are recovered from the bidders and suppliers that participate in thecompetitive solicitations, throughbothBidParticipationFeesandSupplierFeeswhichareassessedby theIPA.The“eligibleretailcustomers” foreachoftheparticipatingutilitiesultimately incurthesecostsas it isassumed that suppliers’bidprices reflecta recoveryof these fees.As requiredby thePUAand inorder tooperate in the best interests of consumers, the IPA and the Procurement Administrator review theprocurementprocesseachyearinordertoidentifypotentialimprovements.

Section 16‐111.5(e) of the Public Utilities Act specifies that the procurement process must include thefollowingcomponents:

(1)Solicitation,pre‐qualification,andregistrationofbidders.

Theprocurementadministratorshalldisseminateinformationtopotentialbidderstopromoteaprocurementevent,notifypotentialbidders thattheprocurementadministratormayenterintoapost‐bidpricenegotiationwithbiddersthatmeettheapplicablebenchmarks272,providesupplyrequirements,andotherwiseexplainthecompetitiveprocurementprocess. Inadditionto such other publication as the procurement administrator determines is appropriate, thisinformationshallbepostedontheIllinoisPowerAgency'sandtheCommission'swebsites.Theprocurement administrator shall also administer the prequalification process, includingevaluation of creditworthiness, compliancewith procurement rules, and agreement to thestandard form contract developed pursuant to paragraph (2) of this subsection (e). Theprocurement administrator shall then identify and register bidders to participate in theprocurementevent.

(2)Standardcontractformsandcredittermsandinstruments.

Theprocurementadministrator, inconsultationwith theutilities, theCommission,andotherinterested parties and subject to Commission oversight, shall develop and provide standardcontract forms for the supplier contracts thatmeet generally accepted industry practices.Standardcredittermsandinstrumentsthatmeetgenerallyacceptedindustrypracticesshallbesimilarlydeveloped.TheprocurementadministratorshallmakeavailabletotheCommissionallwritten comments it receives on the contract forms, credit terms, or instruments. If theprocurementadministratorcannotreachagreementwith theapplicableelectricutilityas tothecontracttermsandconditions,theprocurementadministratormustnotifytheCommissionofanydisputedtermsandtheCommissionshallresolvethedispute.Thetermsofthecontractsshallnotbesubjecttonegotiationbywinningbidders,andthebiddersmustagreetothetermsofthecontractinadvancesothatwinningbidsareselectedsolelyonthebasisofprice.

(3)Establishmentofamarket‐basedpricebenchmark.

271Seegenerally220ILCS5/16‐111.5.272TheActrequirestheprocurementadministratortonotifybiddersthattheprocurementadministratormay,initsdiscretion,enterintopost‐bidpricenegotiationswithbidders.Inordertoencouragebestandfinalbidsfromthebiddersandtakingintoconsiderationthemandateduseofconfidentialbenchmarks,theprocurementadministratorsinpreviousprocurementshavedecidednottoengageinpost‐bidnegotiations.


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Aspartof thedevelopmentof theprocurementprocess, theprocurementadministrator, inconsultationwith the Commission staff, Agency staff, and the procurementmonitor, shallestablishbenchmarksforevaluatingthefinalpricesinthecontractsforeachoftheproductsthatwillbeprocured through theprocurementprocess.Thebenchmarks shallbebasedonpricedataforsimilarproducts forthesamedeliveryperiodandsamedeliveryhub,orotherdeliveryhubsafteradjustingforthatdifference.Thepricebenchmarksmayalsobeadjustedto take into account differences between the information reflected in the underlying datasourcesandthespecificproductsandprocurementprocessbeingusedtoprocurepower fortheIllinoisutilities.Thebenchmarksshallbeconfidentialbutshallbeprovidedto,andwillbesubjecttoCommissionreviewandapproval,priortoaprocurementevent.

(4)Requestforproposalscompetitiveprocurementprocess.

The procurement administrator shall design and issue a request for proposals to supplyelectricityinaccordancewitheachutility'sprocurementplan,asapprovedbytheCommission.Therequest forproposalsshallset forthaprocedure forsealed,bindingcommitmentbiddingwithpay‐as‐bidsettlement,andprovisionforselectionofbidsonthebasisofprice.

(5)Aplanforimplementingcontingencies

[i]n the event of supplier default or failure of the procurement process to fully meet theexpected loadrequirementsdueto insufficientsupplierparticipation,commissionrejectionofresults,oranyothercause.

9.1 ContractForms

Of these five process components, the IPA has implemented changes related to item (2): development ofstandard contract forms and credit terms and instruments in order to achieve process efficiencyimprovementsdesignedto lowertheoverallcoststoratepayers.TheIPAbelievesthattheformshavenowbecomelargelystandardizedandshouldremainacceptabletofuturepotentialbidders.Aswasthecasewiththe 2014 and 2015 procurement events, the process to receive comments from potential bidders can berestrictedtochangestotheforms,thusreducingProcurementAdministratortimeandbillablehours,whileshorteningthecriticalpathtimeneededtoconductaprocurementevent.Thisisbecause,priortothe2014procurementevents, the forms, termsand instrumentshadbecomerelativelystable,with fewercommentsbeingreceivedfrompotentialbiddersrequestingrevisionoroptionaltermsforeachsucceedingprocurementevent.Anyprocurementeventtobeconductedundertheauspicesofthe2016ProcurementPlanwouldbethe tenth iterationof IPA‐runprocurement events,when including theApril 2015procurement event, theSupplemental Photovoltaic Procurement, and the planned September 2015 procurement event. In eachiterationpriorto2014,potentialbiddershadanopportunitytocommentondocumentsandthosecommentshave been, where appropriate, incorporated into the documents or provided as acceptable alternativelanguage.Inthe2014and2015procurementevents,potentialbidderssubmittedonlylimitedcommentsontheproposedchangestotheforms.

IntheprocurementeventsconductedforenergyblocksandRECssince2012(theRateStabilityProcurementand the standard Spring Procurement including the RPS Procurement) comments have been few, withvirtually no new modifications being accepted or made (in part because some comments made by newparticipants have been handled in prior procurement events). The documents used for the 2012 IPA‐runprocurement events illustrate both the breadth and depth of bidder input to the current state of thedocumentsandthematurityofthedocumentsthemselves.

On the opposite side of this discussion, the IPA also understands thatmarkets are dynamic and periodicreview of contract terms is necessary to ensure proper protection for the utilities, utility customers andsuppliers. The IPA therefore recommends that the last used forms, namely the energy, capacity and RPScontracts used in the2015procurement events be the startingpoint for the contracts used in the energy,


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capacity and SREC procurements associated with this plan. The IPA also recommends that the IPA,CommissionStaff,ProcurementAdministrator,ProcurementMonitor,andutilitiesundertakeajointreviewofsuchcontractsinordertoidentifywhatterms,ifany,needtobemodified.

9.2 IPARecoveryofProcurementExpenses

Section1‐75(h)oftheIPAActstatesthat,“[t]heAgencyshallassessfeestoeachbiddertorecoverthecostsincurred in connection with a competitive procurement process.”273Additionally in April, 2014 the IPAadopted new administrative rules related to fee assessments that codify past practices including defining“bidders”and“suppliers”inprocurementeventsaswellastheprocessfordeterminingthosefees.274

TheIPAhashistoricallyrecoveredthecostofprocurementeventsthroughtwotypesoffees:

A“BidParticipationFee”,whichisaflatfeepaidbyallbiddersasaconditionofqualification;and

“SupplierFees”,whicharepaidonlybythewinningbiddersasafeeperblockwonattheconclusionoftheprocurementevent.

Forthelastseveralprocurements,theBidParticipationFeehasbeennominal($500),whichmeansthatthebulk of the costs of the procurement event (which are typically several hundred thousand dollars) arerecoveredfromwinningbiddersthroughSupplierFees.TherearetworisksfortheIPAfromrecoveringcostsinthismanner:

1. If not all the blocks are procured (andno additional procurement event is held), the IPAwill notrecoverthefullcostoftheprocurementthroughthecombinationoftheBidParticipationFeesandthe Supplier Fees. The Supplier Fees are collected from the “winning bidders” based on therecommendedblocksapprovedbytheCommission;theSupplierFeesassociatedwiththeblocksthatarenotprocuredarenotcollected.

2. SuppliersmaynotnecessarilypaytheSupplierFeesontime(orpaythematall).SuppliersthathavebidsthatareapprovedbytheCommissionproceedtothecontractexecutionprocesswiththeutilityandwill get paid under that contractwhether or not they have paid the Supplier Fees.When thestructure of fees was first introduced, non‐payment of the Supplier Fees was an event of defaultunderthecontractwiththeutility.SuppliershadaverystrongincentivetopaytheSupplierFeesasfailuretodosomeantthattheywouldnotbeabletogetthecompensatedunderthecontractfromwinning thebid.Asprocurement events came tobe IPA‐run, this structurewasabandonedas theresponsibility for assessing fees to bidders is the IPA’s and not the utility’s. The incentives forsupplierstopaytheSupplierFeeswerereducedasaresult.

The IPA considered a number of approaches for addressing these risks involving two broad categories ofsolutions:

a. Maintain the current fee structure and use the pre‐bid letter of credit provided by bidders as bidassurancecollateraltoensurecompliancewiththepaymentobligationoftheSupplierFees.

b. Change thecurrent feestructure tohave thecostof theprocurement largelypaidupfrontandbarsuppliersthatfailtopayallfeesduefromparticipationinIPA‐runeventsforaperiodoftime.

Untilthe2014procurementevents,thepre‐bidletterofcredithadbeenstrictlyacreditinstrumentheldforthebenefitoftheutilityanditscustomers.Theutilitywasabletodrawuponthepre‐bidletterofcreditifthesupplier failed to complete the contract executionprocess.At thatpoint, theutility that had filed its ratesbasedonthewinningbidswouldhavetobuyreplacementsupply,forwhichitcouldusefundsunderthepre‐bid letter of credit to mitigate any impact of the default by a supplier on rates. Starting with the 2014procurement events, the function of the pre‐bid letter of credit was expanded to ensure payment of the

27320ILCS3855/1‐75(h).27483Ill.Admin.Code.1200.110,1200.220.


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SupplierFeesbyaddingacondition to theutilitypre‐bid letterofcreditallowing theutility todraw if theSupplierFeesarenotpaidbyadatecertain(andhavinganagreementbetweentheIPAandtheutilityonhowfundswouldflowbacktotheIPAforpaymentoftheSupplierFees).Thisistheapproachthatwasusedinthe2014and2015procurementevents.

TheIPAhaspreviouslyreceivedcommentsonthesepossibleapproachesandhowtheIPAcouldensurethatinconductingprocurementeventsitcomplieswithSection1‐75(h)oftheIPAActandPart1200.220ofTitle83oftheIllinoisAdministrativeCode.Basedonthosecommentsandsubsequentreviewofthealternatives,the IPA recommends that the approach used in the 2014 and 2015 procurement events be continued tosupporttheprocurementeventsrecommendedinthisPlan.Thatapproachistomaintaintheconditionintheutilitypre‐bidletterofcreditallowingtheutilitytodrawiftheSupplierFeesarenotpaidbyadatecertain.Likewise,asusedinthe2014and2015procurementevents,therewillalsobeanagreementbetweentheIPAand each utility on how funds would flow back to the IPA for payment of the Supplier Fees under thiscircumstance.

9.3 SecondProcurementEvent

TheIPArecommendsthatprocurementeventsbeheldinthespringandfallof2016forpurchaseofenergyblocks,capacityandRECsunderthe2016ProcurementPlan.AllofthecomponentsoftheenergyandRECsprocurementprocessdetailedabovewouldbeconductedinthespringevent.Forthefallprocurementevent,for energy blocks under the Procurement Plan, certain activitieswould not occur as the fall procurementeventcouldrelyonthedocumentsorprocessesestablishedforthespringprocurementevent,asfollows:

The procurement administrator will rely on the contract and credit forms established in thespringprocurementeventandsupplierswouldnotcommentanewonthesedocuments;

TheprocurementadministratorwillrelyontheRFPdesignandupdatedbenchmarksusingthebenchmarkmethodologyestablishedinthespringprocurementevent;and

Suppliers that participate in the springprocurement eventwill have access to an abbreviatedqualificationandregistrationprocessiftheyalsoparticipateinthefallprocurementevent;

TheIPArecommendsthatthefallprocurementeventincludestheprocurementofstandardenergyproductsfor MidAmerican, AIC and ComEd as well as a portion of the AIC capacity requirements and all ofMidAmericanforecastcapacityshortfallforthefollowingfive‐planningyears.

9.4 InformalHearing

Section16‐111.5(o)ofthePUAstates,

OnorbeforeJune1ofeachyear,theCommissionshallholdaninformalhearingforthepurposeofreceivingcommentsontheprioryear'sprocurementprocessandanyrecommendationsforchange.

OnMay22,2015 the ICCStaffpostedapublicnotice for the informalhearing for thepurposeof receivingcomments regarding on the procurement process for the procurement events that were held during thesummerandfallof2014andthespringof2015.Thesummer2014event involvedtherepurchaseofRECsfollowingComEd’spartial curtailmentofRECpurchasesunder the termsof the20‐year renewable energycontractsthatwereexecutedinDecember2010.Atotalof85,891RECswererepurchasedforComEdinthesummerevent,whichtookplacefollowingtheCommission’sJune17,2014OrderonRehearinginDocketNo.13‐0546. The fall 2014 procurement involved the procurement of standard energy products to meet therequirements of ComEd’s andAIC’s eligible customers forNovember 2014 throughMay 2015. The spring2015procurement events included thepurchaseof aportionof theutilities’ energy requirements tomeeteligible customers’ needs for the 2015‐2016, 2016‐2017 and 2017‐2018 delivery years. The spring 2015procurementeventsalsoincludedthepurchaseofSRECsforComEdandAIC.


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Initial comments,whichweredue to theCommissionby June29,2015,were received fromBostonPacificCompany,Inc.(“BostonPacific”).275BostonPacific’scommentsfocusedon:asummaryoftheresultsoftheseprocurementevents;theeffectivenessofholdingspringandfallprocurementevents;observationsregardingthelocationalpreferenceandpre‐bidsecurityoptionsfortheSRECprocurements;and,thepotentialimpactthattheintroductionofa“LowCarbonPortfolioStandard”tosupportexistingnucleargenerationinthestatewouldhaveontheIPA’sprocurementprocess.BostonPacificsuggestedthat, fortheSRECprocurementsinparticular,tomeetpre‐bidsecurityrequirementscashshouldbeacceptedinlieuofapre‐bidletterofcreditwhichcouldalleviatetheadministrativeproblemsthatsomesmallbidderscanencounterinsecuringaletterofcredit.Whilethismayhelpsomeofthepotentialbidders,postingcashinlieuofaletterofcreditdoesnoteasily fit the current procurement administrative process and the IPA does not recommend making thischange. A reply comment was received on July 27, 2015 from Exelon Generation. It reiterated their pastpositioninfavorofaFullRequirementsprocurementapproach.

ThecommentsreceivedintheinformalhearingsareavailableontheCommission’swebsite.

275BostonPacificservedastheCommission’sprocurementmonitorforalloftheseprocurementevents.


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Appendices

Appendicesareavailableseparatelyat:

www2.illinois.gov/ipa/Pages/Plans_Under_Development.aspx

AppendixA. RegulatoryComplianceIndex

AppendixB. AmerenIllinoisLoadForecast

SupplementalDocuments Appendix1:Section16.111.5B Appendix2:WorkshopSummaries Appendix3:NTGRecommendations Appendix4:AICPotentialStudy(6volumes) Appendix5:AICThirdPartyRFP Appendix6:BidReviewInformation(marked“Confidential”) Appendix7:ProgramDescriptions Appendix8:Third‐partyBids(marked“Confidential”) Appendix9:DetailedAnalysis(marked“Confidential”) AICForecastingMethodology AICEECompliance AICLetterTransmittingFinalData

AppendixC. ComEdLoadForecast

SupplementalDocuments AppendixC‐1:PotentialStudy AppendixC‐2:EnergyEfficiencyAnalysisSummary AppendixC‐3:MonthlySavingsCurves AppendixC‐4:ProgramDescriptions AppendixC‐5:DSMoreModelInputs ComEd 2015 Third Party Efficiency Program Summary of Bid Review Process, July 13, 2015

(marked“Confidential”) ComEdLoadForecastforFive‐YearPlanningPeriodJun2016–May2021,July15,2015

AppendixD. MidAmericanLoadForecast

SupplementalDocuments MethodologyForIllinoisElectricCustomersandSalesForecasts:2016‐2025 RiderPE–PurchasedElectricity MECPotentialStudy AppendixA3:MECMeasures ElectiontoProcurePowerandEnergyforaPortionofitsEligibleIllinoisRetailCustomers,July

15,2015 AssessmentofEnergyandCapacitySavingsPotentialinIowa:Appendices(Attachments1and2) IPALetterTransmittingFinalDataandMethodology


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AppendixE. AmerenIllinoisLoadForecastandSupplyPortfoliobyScenario

E.1TotalDeliveryServiceAreaLoad TableE‐1AmerenIllinoisDeliveryServiceAreaLoadForecast–ExpectedCasewithIncremental

EnergyEfficiency TableE‐2AmerenIllinoisDeliveryServiceAreaLoadForecast–ExpectedCase(NoIncremental

EnergyEfficiency) TableE‐3AmerenIllinoisDeliveryServiceAreaLoadForecast–HighCase TableE‐4AmerenIllinoisDeliveryServiceAreaLoadForecast–LowCase

E.2AmerenIllinoisBundledServiceLoadForecast Table E‐5 Ameren Illinois Bundled Service Load Forecast – Expected Case with Incremental

EnergyEfficiency Table E‐6 Ameren Illinois Bundled Service Load Forecast – Expected Case (No Incremental

EnergyEfficiency) TableE‐7AmerenIllinoisBundledServiceLoadForecast–HighCase TableE‐8AmerenIllinoisBundledServiceLoadForecast–LowCase

E.3AmerenIllinoisPeak/OffPeakDistributionofEnergyandAverageLoad Table E‐9Ameren Illinois Peak/Off peakDistribution of Energy andAverage Load – Expected

CasewithIncrementalEnergyEfficiency TableE‐10AmerenIllinoisPeak/OffPeakDistributionofEnergyandAverageLoad–Expected

Case(NoIncrementalEnergyEfficiency) TableE‐11AmerenIllinoisPeak/OffPeakDistributionofEnergyandAverageLoad–HighCase TableE‐12AmerenIllinoisPeak/OffPeakDistributionofEnergyandAverageLoad–LowCase

E.4AmerenIllinoisNetPeakPositionbyScenario Table E‐13 Ameren Illinois Net Peak Position – Expected Case with Incremental Energy

Efficiency Table E‐14 Ameren Illinois Net Peak Position – Expected Case (No Incremental Energy

Efficiency) TableE‐15AmerenIllinoisNetPeakPosition–HighCase TableE‐16AmerenIllinoisNetPeakPosition–LowCase

E.5AmerenIllinoisNetOff‐PeakPositionbyScenario Table E‐17 Ameren Illinois Net Off Peak Position – Expected Case with Incremental Energy

Efficiency Table E‐18 Ameren Illinois Net Off Peak Position – Expected Case (No Incremental Energy

Efficiency) TableE‐19AmerenIllinoisNetOffPeakPosition–HighCase TableE‐20AmerenIllinoisNetOffPeakPosition–LowCase

E.6AmerenIllinoisLTPPAAllocation TableE‐21AmerenIllinoisLTPPAAllocation

AppendixF. ComEdLoadForecastandSupplyPortfoliobyScenario

F.1ComEdResidentialBundledServiceLoadForecast TableF‐1ComEdResidentialBundledServiceLoadForecast–ExpectedCase TableF‐2ComEdResidentialBundledServiceLoadForecast–HighCase TableF‐3ComEdResidentialBundledServiceLoadForecast–LowCase

F.2ComEdCommercialBundledServiceLoadForecast TableF‐4ComEdCommercialBundledServiceLoadForecast–ExpectedCase TableF‐5ComEdCommercialBundledServiceLoadForecast–HighCase TableF‐6ComEdCommercialBundledServiceLoadForecast–LowCase

F.3Peak/OffPeakDistributionofEnergyandAverageLoad


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TableF‐7ComEdPeak/OffPeakDistributionofEnergyandAverageLoad–ExpectedCase TableF‐8ComEdPeak/OffPeakDistributionofEnergyandAverageLoad–HighCase TableF‐9ComEdPeak/OffPeakDistributionofEnergyandAverageLoad–LowCase

F.4ComEdNetPeakPositionbyScenario TableF‐10ComEdNetPeakPosition–ExpectedCase

F.5ComEdNetOffPeakPositionbyScenario TableF‐11ComEdNetOffPeakPosition–ExpectedCase

F.6ComEdLTPPAAllocation TableF‐12ComEdLTPPAAllocation

AppendixG. MidAmericanLoadForecastandSupplyPortfoliobyScenario

G.1.MidAmericanLoadForecast TableG‐1MidAmericanLoadForecast–Expected,HighandLowCases

G.2Peak/OffPeakDistributionofEnergyandAverageLoad TableG‐2MidAmericanPeak/OffPeakDistributionofEnergyandAverageLoad–ExpectedCase TableG‐3MidAmericanPeak/OffPeakDistributionofEnergyandAverageLoad–HighCase TableG‐4MidAmericanPeak/OffPeakDistributionofEnergyandAverageLoad–LowCase

G.3MidAmericanNetPeakPositionbyScenario TableG‐5MidAmericanNetPeakPosition–ExpectedCase

G.4MidAmericanNetOffPeakPositionbyScenario TableG‐6MidAmericanNetOffPeakPosition–ExpectedCase