Portland General Electric Company
10-K on 02/19/2021   Download
SEC Document
SEC Filing
0000784977false2020FY--12-3130,000,00030,000,00030,000,000160,000,000160,000,000160,000,00089,537,33189,537,33189,387,12489,387,12489,537,33189,387,1241663.63.6459.5P1YP2YP3YP6M1.849.311.37211us-gaap:OtherLiabilitiesCurrentus-gaap:OtherLiabilitiesCurrentus-gaap:OtherLiabilitiesNoncurrentus-gaap:OtherLiabilitiesNoncurrent00007849772020-01-012020-12-310000784977us-gaap:CommonStockMember2020-01-012020-12-310000784977us-gaap:MediumTermNotesMember2020-01-012020-12-31iso4217:USD00007849772020-06-30xbrli:shares00007849772021-02-1000007849772020-12-3100007849772019-01-012019-12-3100007849772018-01-012018-12-31iso4217:USDxbrli:shares00007849772019-12-310000784977us-gaap:CommonStockMember2017-12-310000784977us-gaap:CommonStockIncludingAdditionalPaidInCapitalMember2017-12-310000784977us-gaap:AccumulatedOtherComprehensiveIncomeMember2017-12-310000784977us-gaap:RetainedEarningsMember2017-12-3100007849772017-12-310000784977us-gaap:CommonStockMember2018-01-012018-12-310000784977us-gaap:CommonStockIncludingAdditionalPaidInCapitalMember2018-01-012018-12-310000784977us-gaap:AccumulatedOtherComprehensiveIncomeMember2018-01-012018-12-310000784977us-gaap:RetainedEarningsMember2018-01-012018-12-310000784977us-gaap:CommonStockMember2018-12-310000784977us-gaap:CommonStockIncludingAdditionalPaidInCapitalMember2018-12-310000784977us-gaap:AccumulatedOtherComprehensiveIncomeMember2018-12-310000784977us-gaap:RetainedEarningsMember2018-12-3100007849772018-12-310000784977us-gaap:CommonStockMember2019-01-012019-12-310000784977us-gaap:CommonStockIncludingAdditionalPaidInCapitalMember2019-01-012019-12-310000784977us-gaap:AccumulatedOtherComprehensiveIncomeMember2019-01-012019-12-310000784977us-gaap:RetainedEarningsMember2019-01-012019-12-310000784977us-gaap:CommonStockMember2019-12-310000784977us-gaap:CommonStockIncludingAdditionalPaidInCapitalMember2019-12-310000784977us-gaap:AccumulatedOtherComprehensiveIncomeMember2019-12-310000784977us-gaap:RetainedEarningsMember2019-12-310000784977us-gaap:CommonStockMember2020-01-012020-12-310000784977us-gaap:CommonStockIncludingAdditionalPaidInCapitalMember2020-01-012020-12-310000784977us-gaap:AccumulatedOtherComprehensiveIncomeMember2020-01-012020-12-310000784977us-gaap:RetainedEarningsMember2020-01-012020-12-310000784977us-gaap:CommonStockMember2020-12-310000784977us-gaap:CommonStockIncludingAdditionalPaidInCapitalMember2020-12-310000784977us-gaap:AccumulatedOtherComprehensiveIncomeMember2020-12-310000784977us-gaap:RetainedEarningsMember2020-12-31utr:sqmixbrli:purepor:retail_customers00007849772020-07-012020-09-300000784977us-gaap:AssetRetirementObligationCostsMember2020-12-310000784977por:TrojandecommissioningMember2020-12-310000784977us-gaap:AssetRetirementObligationCostsMember2019-12-310000784977por:TrojandecommissioningMember2019-12-310000784977us-gaap:DeferredIncomeTaxChargesMember2020-12-310000784977us-gaap:DeferredIncomeTaxChargesMember2019-12-310000784977por:ResidentialMember2020-01-012020-12-310000784977por:ResidentialMember2019-01-012019-12-310000784977por:CommercialMember2020-01-012020-12-310000784977por:CommercialMember2019-01-012019-12-310000784977por:IndustrialMember2020-01-012020-12-310000784977por:IndustrialMember2019-01-012019-12-310000784977por:DirectAccesscustomersMember2020-01-012020-12-310000784977por:DirectAccesscustomersMember2019-01-012019-12-310000784977us-gaap:RevenueSubjectToRefundMember2020-01-012020-12-310000784977us-gaap:RevenueSubjectToRefundMember2019-01-012019-12-310000784977por:PublicUtilityCommissionOfOregonMember2020-01-012020-12-310000784977us-gaap:FairValueInputsLevel1Member2020-12-310000784977us-gaap:FairValueInputsLevel2Member2020-12-310000784977us-gaap:FairValueInputsLevel3Member2020-12-310000784977por:NonQualifiedBenefitPlansMember2020-12-310000784977us-gaap:FairValueInputsLevel1Member2019-12-310000784977us-gaap:FairValueInputsLevel2Member2019-12-310000784977us-gaap:FairValueInputsLevel3Member2019-12-310000784977por:NonQualifiedBenefitPlansMember2019-12-310000784977us-gaap:AvailableforsaleSecuritiesMember2020-12-310000784977us-gaap:DerivativeFinancialInstrumentsLiabilitiesMember2020-12-310000784977srt:MinimumMember2020-12-310000784977srt:MaximumMember2020-12-310000784977srt:WeightedAverageMember2020-12-310000784977us-gaap:AvailableforsaleSecuritiesMember2019-12-310000784977us-gaap:DerivativeFinancialInstrumentsLiabilitiesMember2019-12-310000784977srt:MinimumMember2019-12-310000784977srt:MaximumMember2019-12-310000784977srt:WeightedAverageMember2019-12-310000784977us-gaap:NotesPayableToBanksMember2020-12-310000784977us-gaap:NotesPayableToBanksMember2019-12-31utr:MWhutr:MMBTUiso4217:CAD0000784977us-gaap:ElectricityMember2019-12-310000784977srt:NaturalGasReservesMember2019-12-310000784977us-gaap:ElectricityMember2020-12-310000784977srt:NaturalGasReservesMember2020-12-310000784977por:UnrealizedGainLossOnDerivativesMember2020-12-310000784977us-gaap:CreditRiskContractMember2020-12-310000784977us-gaap:LetterOfCreditMemberus-gaap:CreditRiskContractMember2020-01-012020-12-310000784977por:CounterpartyAMember2020-01-012020-12-310000784977por:CounterpartyAMember2019-01-012019-12-310000784977por:CounterpartyBMember2020-01-012020-12-310000784977por:CounterpartyBMember2019-01-012019-12-310000784977por:CounterpartyCMember2020-01-012020-12-310000784977por:CounterpartyCMember2019-01-012019-12-310000784977por:CounterpartyDMember2020-01-012020-12-310000784977por:CounterpartyDMember2019-01-012019-12-310000784977por:CounterpartyFMember2020-01-012020-12-310000784977por:CounterpartyFMember2019-01-012019-12-310000784977us-gaap:DeferredDerivativeGainLossMember2020-01-012020-12-310000784977us-gaap:DeferredDerivativeGainLossMember2020-12-310000784977us-gaap:DeferredDerivativeGainLossMember2019-12-310000784977us-gaap:PensionAndOtherPostretirementPlansCostsMember2020-12-310000784977us-gaap:PensionAndOtherPostretirementPlansCostsMember2019-12-310000784977us-gaap:LossOnReacquiredDebtMember2020-01-012020-12-310000784977us-gaap:LossOnReacquiredDebtMember2020-12-310000784977us-gaap:LossOnReacquiredDebtMember2019-12-310000784977us-gaap:EnvironmentalRestorationCostsMember2020-01-012020-12-310000784977us-gaap:EnvironmentalRestorationCostsMember2020-12-310000784977us-gaap:EnvironmentalRestorationCostsMember2019-12-310000784977por:OtherRegulatoryAssetsEarningaReturnMember2020-12-310000784977us-gaap:OtherRegulatoryAssetsLiabilitiesMember2020-12-310000784977us-gaap:OtherRegulatoryAssetsLiabilitiesMember2019-12-310000784977por:EarningareturnMember2020-12-310000784977us-gaap:RemovalCostsMember2020-12-310000784977us-gaap:RemovalCostsMember2019-12-310000784977us-gaap:RevenueSubjectToRefundMember2020-12-310000784977us-gaap:RevenueSubjectToRefundMember2019-12-310000784977us-gaap:DeferredDerivativeGainLossMember2020-12-310000784977us-gaap:DeferredDerivativeGainLossMember2019-12-310000784977us-gaap:OtherRegulatoryAssetsLiabilitiesMember2020-12-310000784977us-gaap:OtherRegulatoryAssetsLiabilitiesMember2019-12-310000784977por:EarningareturnMember2020-12-310000784977us-gaap:UtilityPlantDomain2020-01-012020-12-310000784977por:NonUtilityMemberMember2020-07-012020-09-300000784977por:TermLoanMember2020-04-0900007849772020-04-272020-04-2700007849772020-12-102020-12-100000784977us-gaap:DebtInstrumentRedemptionPeriodTwoMember2020-12-102020-12-100000784977us-gaap:DebtInstrumentRedemptionPeriodOneMember2020-12-102020-12-1000007849772020-03-110000784977us-gaap:OtherPensionPlansPostretirementOrSupplementalPlansDefinedBenefitMember2020-12-310000784977us-gaap:OtherPensionPlansDefinedBenefitMember2020-12-310000784977us-gaap:OtherPensionPlansPostretirementOrSupplementalPlansDefinedBenefitMember2019-12-310000784977us-gaap:OtherPensionPlansDefinedBenefitMember2019-12-310000784977us-gaap:OtherPensionPlansDefinedBenefitMemberus-gaap:EquitySecuritiesMember2020-12-310000784977us-gaap:OtherPensionPlansDefinedBenefitMemberus-gaap:EquitySecuritiesMember2019-12-310000784977us-gaap:OtherPensionPlansDefinedBenefitMemberus-gaap:DebtSecuritiesMember2020-12-310000784977us-gaap:OtherPensionPlansDefinedBenefitMemberus-gaap:DebtSecuritiesMember2019-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:EquitySecuritiesMember2020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:EquitySecuritiesMember2019-12-310000784977us-gaap:DebtSecuritiesMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310000784977us-gaap:DebtSecuritiesMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-12-310000784977us-gaap:EquitySecuritiesMemberus-gaap:OtherPensionPlansPostretirementOrSupplementalPlansDefinedBenefitMember2020-12-310000784977us-gaap:EquitySecuritiesMemberus-gaap:OtherPensionPlansPostretirementOrSupplementalPlansDefinedBenefitMember2019-12-310000784977us-gaap:DebtSecuritiesMemberus-gaap:OtherPensionPlansPostretirementOrSupplementalPlansDefinedBenefitMember2020-12-310000784977us-gaap:DebtSecuritiesMemberus-gaap:OtherPensionPlansPostretirementOrSupplementalPlansDefinedBenefitMember2019-12-310000784977us-gaap:OtherContractMemberus-gaap:OtherPensionPlansPostretirementOrSupplementalPlansDefinedBenefitMember2020-12-310000784977us-gaap:OtherContractMemberus-gaap:OtherPensionPlansPostretirementOrSupplementalPlansDefinedBenefitMember2019-12-310000784977us-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310000784977us-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:PensionPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel3Member2020-12-310000784977us-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:PrivateEquityFundsMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310000784977us-gaap:PrivateEquityFundsMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:EquitySecuritiesMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310000784977us-gaap:PensionPlansDefinedBenefitMemberus-gaap:EquitySecuritiesMember2020-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:PrivateEquityFundsDomesticMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310000784977us-gaap:PrivateEquityFundsDomesticMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310000784977us-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310000784977us-gaap:PensionPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel3Member2020-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310000784977us-gaap:PensionPlansDefinedBenefitMember2020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:MoneyMarketFundsMemberus-gaap:FairValueInputsLevel1Member2020-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:MoneyMarketFundsMember2020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:MoneyMarketFundsMemberus-gaap:FairValueInputsLevel3Member2020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:MoneyMarketFundsMember2020-12-310000784977us-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel1Member2020-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310000784977us-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel3Member2020-12-310000784977us-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMemberus-gaap:FairValueInputsLevel1Member2020-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember2020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMemberus-gaap:FairValueInputsLevel3Member2020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember2020-12-310000784977us-gaap:USGovernmentAgenciesDebtSecuritiesMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel1Member2020-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:USGovernmentAgenciesDebtSecuritiesMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310000784977us-gaap:USGovernmentAgenciesDebtSecuritiesMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel3Member2020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:USGovernmentAgenciesDebtSecuritiesMember2020-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:PrivateEquityFundsMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310000784977us-gaap:PrivateEquityFundsMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:EquitySecuritiesMember2020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel1Member2020-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel3Member2020-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310000784977us-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310000784977us-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:PensionPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel3Member2019-12-310000784977us-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:PrivateEquityFundsMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310000784977us-gaap:PrivateEquityFundsMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:EquitySecuritiesMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310000784977us-gaap:PensionPlansDefinedBenefitMemberus-gaap:EquitySecuritiesMember2019-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:PrivateEquityFundsDomesticMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310000784977us-gaap:PrivateEquityFundsDomesticMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310000784977us-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310000784977us-gaap:PensionPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel3Member2019-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310000784977us-gaap:PensionPlansDefinedBenefitMember2019-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:MoneyMarketFundsMemberus-gaap:FairValueInputsLevel1Member2019-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:MoneyMarketFundsMember2019-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:MoneyMarketFundsMemberus-gaap:FairValueInputsLevel3Member2019-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:MoneyMarketFundsMember2019-12-310000784977us-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel1Member2019-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-12-310000784977us-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel3Member2019-12-310000784977us-gaap:DefinedBenefitPlanEquitySecuritiesUsMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMemberus-gaap:FairValueInputsLevel1Member2019-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember2019-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMemberus-gaap:FairValueInputsLevel3Member2019-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember2019-12-310000784977us-gaap:USGovernmentAgenciesDebtSecuritiesMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel1Member2019-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:USGovernmentAgenciesDebtSecuritiesMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-12-310000784977us-gaap:USGovernmentAgenciesDebtSecuritiesMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel3Member2019-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:USGovernmentAgenciesDebtSecuritiesMember2019-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:PrivateEquityFundsMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-12-310000784977us-gaap:PrivateEquityFundsMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:EquitySecuritiesMember2019-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel1Member2019-12-310000784977us-gaap:FairValueInputsLevel2Memberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel3Member2019-12-310000784977us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-12-310000784977us-gaap:PensionPlansDefinedBenefitMember2018-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2018-12-310000784977us-gaap:OtherPensionPlansPostretirementOrSupplementalPlansDefinedBenefitMember2018-12-310000784977us-gaap:PensionPlansDefinedBenefitMember2020-01-012020-12-310000784977us-gaap:PensionPlansDefinedBenefitMember2019-01-012019-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-01-012020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-01-012019-12-310000784977us-gaap:OtherPensionPlansPostretirementOrSupplementalPlansDefinedBenefitMember2020-01-012020-12-310000784977us-gaap:OtherPensionPlansPostretirementOrSupplementalPlansDefinedBenefitMember2019-01-012019-12-310000784977us-gaap:PensionPlansDefinedBenefitMember2018-01-012018-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2018-01-012018-12-310000784977us-gaap:OtherPensionPlansPostretirementOrSupplementalPlansDefinedBenefitMember2018-01-012018-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMembersrt:MinimumMember2020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMembersrt:MinimumMember2019-12-310000784977srt:MaximumMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310000784977srt:MaximumMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMembersrt:MinimumMember2020-01-012020-12-310000784977us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMembersrt:MinimumMember2019-01-012019-12-310000784977srt:MaximumMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-01-012020-12-310000784977srt:MaximumMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-01-012019-12-310000784977us-gaap:CapitalAdditionsMember2020-12-310000784977us-gaap:LongTermContractForPurchaseOfElectricPowerDomain2020-12-310000784977us-gaap:ElectricTransmissionMember2020-12-310000784977por:PublicUtilityDistrictsMember2020-12-310000784977us-gaap:PublicUtilitiesInventoryFuelMember2020-12-310000784977us-gaap:CoalSupplyAgreementsMember2020-12-310000784977us-gaap:CommitmentsMember2020-12-310000784977por:PriestRapidsAndWanapumMember2020-12-31utr:MW0000784977por:PriestRapidsAndWanapumMember2020-01-012020-12-310000784977por:PriestRapidsAndWanapumMember2019-01-012019-12-310000784977por:PriestRapidsAndWanapumMember2018-01-012018-12-310000784977por:WellsMember2020-12-310000784977por:WellsMember2020-01-012020-12-310000784977por:WellsMember2019-01-012019-12-310000784977por:WellsMember2018-01-012018-12-310000784977por:ColstripMember2020-12-310000784977por:PeltonRoundButteMemberMember2020-12-31por:name0000784977por:EPAInvestigationOfPortlandHarborMember2020-01-012020-12-310000784977por:PutativeShareholderDerivativeLawsuitMember2020-01-012020-12-31

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020

OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition period from              to             

Commission File Number 001-05532-99
 
PORTLAND GENERAL ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Oregon93-0256820
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
121 S.W. Salmon Street
Portland, Oregon 97204
(503) 464-8000
(Address of principal executive offices, including zip code,
and Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
(Title of class)(Trading symbol)(Name of exchange on which registered)
Common Stock, no par valuePORNew York Stock Exchange
9.31% Medium-Term Notes due 2021POR 21New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None.


Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes      No  

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes      No  




Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No  

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes      No  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filerAccelerated filer
Non-accelerated filerSmaller reporting company
Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes      No  

As of June 30, 2020, the aggregate market value of voting common stock held by non-affiliates of the Registrant was $3,725,882,304. For purposes of this calculation, executive officers and directors are considered affiliates.

As of February 10, 2021, there were 89,539,034 shares of common stock outstanding.

Documents Incorporated by Reference

Part III, Items 10 - 14Portions of Portland General Electric Company’s definitive proxy statement to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on April 28, 2021.



PORTLAND GENERAL ELECTRIC COMPANY
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2020

TABLE OF CONTENTS

Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
3

Table of Contents

DEFINITIONS

The abbreviations or acronyms defined below are used throughout this Form 10-K:
 
Abbreviation or AcronymDefinition
AFDCAllowance for funds used during construction
AROAsset retirement obligation
AUTAnnual Power Cost Update Tariff
BeaverBeaver natural gas-fired generating plant
Biglow CanyonBiglow Canyon Wind Farm
BoardmanBoardman coal-fired generating plant
BPABonneville Power Administration
CartyCarty natural gas-fired generating plant
ColstripColstrip Units 3 and 4 coal-fired generating plant
Coyote SpringsCoyote Springs Unit 1 natural gas-fired generating plant
DthDecatherm = 10 therms = 1,000 cubic feet of natural gas
EIMEnergy Imbalance Market
EPAUnited States Environmental Protection Agency
ESSElectricity Service Supplier
FERCFederal Energy Regulatory Commission
FMBFirst Mortgage Bond
FPAFederal Power Act
GRCGeneral Rate Case for a specified test year
IRPIntegrated Resource Plan
ISFSIIndependent Spent Fuel Storage Installation
kVKilovolt = one thousand volts of electricity
Moody’sMoody’s Investors Service
MWMegawatts
MWaAverage megawatts
MWhMegawatt hours
NRCNuclear Regulatory Commission
NVPCNet Variable Power Costs
OATTOpen Access Transmission Tariff
OPUCPublic Utility Commission of Oregon
PCAMPower Cost Adjustment Mechanism
PTCFederal production tax credit
PW1Port Westward Unit 1 natural gas-fired generating plant
PW2Port Westward Unit 2 natural gas-fired flexible capacity generating plant
QFPURPA qualifying facility
RACRenewable Adjustment Clause
RPSRenewable Portfolio Standard
S&PS&P Global Ratings
SECUnited States Securities and Exchange Commission
TrojanTrojan nuclear power plant
Tucannon RiverTucannon River Wind Farm
USDOEUnited States Department of Energy
4

Table of Contents

PART I
 
ITEM 1.     BUSINESS.

General

Portland General Electric Company (PGE or the Company), a vertically-integrated electric utility with corporate headquarters located in Portland, Oregon, is engaged in the generation, wholesale purchase, transmission, distribution, and retail sale of electricity in the state of Oregon. The Company operates as a cost-based, regulated electric utility with revenue requirements and customer prices determined based on the forecasted cost to serve retail customers and a reasonable rate of return as determined by the Public Utility Commission of Oregon (OPUC). PGE meets its retail load requirement with both Company-owned generation and power purchased in the wholesale market. The Company participates in the wholesale market through the purchase and sale of electricity and natural gas in an effort to obtain reasonably-priced power to serve its retail customers. PGE, incorporated in 1930, is publicly-owned, with its common stock listed on the New York Stock Exchange (NYSE). The Company operates as a single business segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis.

PGE’s state-approved service area allocation of four thousand square miles is located entirely within Oregon and includes 51 incorporated cities. During 2020, the Company added 13 thousand customers, and as of December 31, 2020, served a total of 908 thousand retail customers.    

Available Information

PGE’s periodic and current reports, and amendments to those reports, are available and may be accessed free of charge through the Investors section of the Company’s website at PortlandGeneral.com as soon as reasonably practicable after the reports are electronically filed with, or furnished to, the United States Securities and Exchange Commission (SEC). It is not intended that PGE’s website and the information contained therein or connected thereto be incorporated into this Annual Report on Form 10-K.

Regulation

Federal and state of Oregon (State) regulation each have a significant impact on the operations of PGE. In addition to the agencies and activities discussed below, the Company is subject to regulation by certain environmental agencies, as described in the Environmental Matters section in this Item 1.

Federal Regulation

Several federal agencies, including the Federal Energy Regulatory Commission (FERC), the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA), and the Nuclear Regulatory Commission (NRC), have regulatory authority over certain of PGE’s operations and activities, as described in the discussion that follows.

PGE is a “licensee,” a “public utility,” and a “user, owner, and operator of the bulk power system,” as defined in the Federal Power Act (FPA). As such, the Company is subject to regulation by the FERC in matters related to wholesale energy activities, transmission services, reliability and cybersecurity standards, natural gas pipelines, hydroelectric projects, accounting policies and practices, short-term debt issuances, and certain other matters.

Wholesale Energy—PGE has authority under its FERC Market-Based Rates tariff to charge market-based rates for wholesale energy sales in all markets in which it sells electricity except in its own Balancing Authority Area (BAA). The BAA is the area in which PGE is responsible for balancing customer demand with electricity supply, in real time, and the tariff exception within PGE’s BAA does not have a material impact on the Company.

5

Table of Contents

Transmission—PGE offers wholesale electricity transmission service pursuant to its Open Access Transmission Tariff (OATT), which contains rates, terms, and conditions of service, as filed with, and approved by, the FERC.

Reliability and Cybersecurity Standards—The FERC has adopted mandatory reliability standards for owners, users, and operators of the bulk power system. Such standards, which are applicable to PGE, were developed by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC), which have responsibility for compliance and enforcement of these standards, and are intended to help protect critical cyber assets used to support reliable operations.

Natural Gas Pipelines—The FERC has authority in matters related to the construction, operation, extension, enlargement, safety, and abandonment of jurisdictional interstate natural gas pipeline facilities, as well as transportation rates and accounting for interstate natural gas commerce. PGE is subject to such authority as the Company has a 79.5% ownership interest in the Kelso-Beaver (KB) Pipeline, a 17-mile interstate pipeline that provides natural gas to Port Westward Unit 1 (PW1), Port Westward Unit 2 (PW2), and Beaver, the Company’s natural gas-fired generating plants located near Clatskanie, Oregon, and to the North Mist storage facility. As the operator of record of the KB Pipeline, PGE is subject to the requirements and regulations enacted under the Pipeline Safety Laws administered by the PHMSA, which include safety standards, operator qualification standards, and public awareness requirements.

Hydroelectric Licensing—As required under the FPA, PGE holds FERC licenses for all Company-owned hydroelectric generating plants. The FERC license process includes an extensive public review process that involves the consideration of numerous natural resource issues and environmental conditions. For additional information, see the Environmental Matters section in this Item 1. and the Generating Facilities section in Item 2.—“Properties.”

Accounting Policies and Practices—PGE prepares periodic and current reports in accordance with accounting principles generally accepted in the United States of America (GAAP). In addition, the Company prepares, pursuant to applicable provisions of the FPA, financial statements in accordance with the accounting requirements of the FERC, as set forth in its applicable Uniform System of Accounts and published accounting releases. Such financial statements are included in annual and quarterly reports filed with the FERC.

Short-term Debt—Pursuant to applicable provisions of the FPA and FERC regulations, regulated public utilities are required to obtain FERC approval to issue certain securities. For additional information on the Company’s Short-term Debt, see Short-term Debt in the Debt and Equity section of Liquidity and Capital Resources in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Spent Fuel Storage—The NRC regulates the licensing and decommissioning of nuclear power plants, including PGE’s decommissioned Trojan nuclear power plant (Trojan), which was closed in 1993. For additional information on spent nuclear fuel storage activities, see Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data” and “Hazardous Material” in the Environmental Matters section of this Item 1.

State of Oregon Regulation

PGE is subject to the jurisdiction of the OPUC, which reviews and approves the Company’s retail prices and reviews the Company’s generation and transmission resource acquisition plans, pursuant to a biennial integrated resource planning process. The OPUC regulates the issuance of securities, prescribes accounting policies and practices, regulates the sale of utility assets, reviews transactions with affiliated companies, and has jurisdiction over the acquisition of, or exertion of substantial influence over, public utilities.

Retail customer prices are determined through formal proceedings that generally include testimony by participating parties, discovery, public hearings, and the issuance of a final order. Participants in such proceedings may include PGE, OPUC staff, and intervenors representing PGE customer groups, as well as other interested parties. The
6

Table of Contents

following are the more significant regulatory mechanisms and proceedings under which customer prices are determined:
General Rate Cases. PGE periodically evaluates the need to change its retail electric price structure as part of a comprehensive general rate case process that reflects revenue requirements based on a forecasted test year. The OPUC authorizes the Company’s debt-to-equity capital structure, return on equity, overall rate of return, and customer prices.
Annual Power Cost Updates. The OPUC has approved an Annual Power Cost Update Tariff (AUT) by which PGE can adjust retail customer prices annually to reflect forecasted changes in the Company’s net variable power costs (NVPC). NVPC consists of the cost of power purchased and fuel used to generate electricity, as well as the cost of settled electric and natural gas financial contracts (all classified as Purchased power and fuel expense in the Company’s consolidated statements of income) and is net of wholesale revenues, which are classified in the consolidated statements of income as Revenues, net. The OPUC has also authorized a Power Cost Adjustment Mechanism (PCAM), under which PGE may share with customers a portion of actual cost variances associated with NVPC.
Renewable Energy. The State maintains a Renewable Portfolio Standard (RPS) that requires PGE to serve a portion of its retail load with renewable resources. In conjunction with the RPS, the State established a Renewable Adjustment Clause (RAC) mechanism that allows for the recovery in retail customer prices, outside of a general rate case, of prudently incurred costs to comply with the RPS. The State also passed a law referred to as the Oregon Clean Electricity and Coal Transition Plan (SB 1547), which, among its provisions, increased the RPS percentages in certain future years. For further information on SB 1547, see “Carbon Legislation and Administrative Actions” in the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Retail Customer Choice Program—Under cost of service pricing, residential and small commercial customers may select portfolio options from PGE that include time-of-use and renewable resource pricing.

Pricing options other than cost of service are available to certain commercial and industrial customers for a one-year period, including daily market index-based pricing under which the Company provides the electricity, and Direct Access, whereby customers purchase electricity directly from an Electricity Service Supplier (ESS).

PGE receives revenue from Direct Access customers only for the transmission and delivery of the volume of electricity delivered, along with fixed transition adjustments intended to mitigate the shifting of excess charges to the Company’s cost of service customers. Certain large commercial and industrial customers may elect a fixed three-year or a minimum five-year term, to be served either by an ESS, or by the Company under the daily market index-based price option. Participation in the fixed three-year and minimum five-year opt-out programs for existing and planned load is capped at 300 average megawatts (MWa) in aggregate.

In 2018, the OPUC created and approved rules for a New Large Load Direct Access (NLDA) program, which is capped at 119 MWa, for unplanned, large, new loads and large load growth at existing sites. In January 2020, the OPUC issued an order that required PGE to begin offering enrollment in the NLDA program to eligible customers in early February 2020.

For further information regarding Direct Access deliveries, see “Customers and Demand” in the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Regulatory Accounting

PGE prepares financial statements in accordance with GAAP and, as a regulated public utility, the effects of rate regulation are reflected in its financial statements. GAAP provides for the deferral, as regulatory assets, of certain actual or estimated costs that would otherwise be charged to expense, based on expected recovery from customers in future prices. Likewise, certain actual or anticipated credits that would otherwise be recognized as revenue or reduce expense can be deferred as regulatory liabilities, based on expected future credits or refunds to customers. PGE
7

Table of Contents

records regulatory assets or liabilities if it is probable that they will be reflected in future prices, based on regulatory orders or other available evidence.

The Company periodically assesses the applicability of regulatory accounting to its business, considering both the current and anticipated future regulatory environment and related accounting guidance. For additional information, see “Regulatory Assets and Liabilities” in Note 2, Summary of Significant Accounting Policies, and Note 7, Regulatory Assets and Liabilities, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Customers and Revenues

PGE generates revenue primarily through the sale and delivery of electricity to retail customers located exclusively in Oregon. In addition, the Company distributes power to commercial and industrial customers that choose to purchase their energy from an ESS. Although the Company includes such Direct Access customers in its customer counts and energy delivered to such customers in its total retail energy deliveries, retail revenues include only delivery charges and applicable transition adjustments for these Direct Access customers. The Company conducts retail electric operations within its service territory and competes with: i) the local natural gas distribution company for the energy needs of residential and commercial space heating, water heating, and appliances; and ii) ESSs. Energy efficiency, conservation measures and distributed solar generation also have an increasing influence on customer demand.

Retail Revenues

Retail customers are classified as residential, commercial, or industrial, with no single customer representing more than 8% of PGE’s total retail revenues or 12% of total retail deliveries.

PGE’s Retail revenues, retail energy deliveries, and average number of retail customers consist of the following:
Years Ended December 31,
202020192018
Retail revenues (1) (dollars in millions):
Residential$1,030 53 %$981 52 %$948 53 %
Commercial634 33 654 35 665 37 
Industrial246 13 222 12 210 12 
Subtotal1,910 99 1,857 99 1,823 102 
Alternative revenue programs, net of amortization(6)— — — 
Other accrued (deferred) revenues, net (2)
28 22 (45)(2)
Total retail revenues$1,932 100 %$1,881 100 %$1,781 100 %
Retail energy deliveries (3) (MWh in thousands):
Residential7,756 40 %7,471 38 %7,416 39 %
Commercial6,855 35 7,318 38 7,430 39 
Industrial4,932 25 4,671 24 4,376 22 
Total retail energy deliveries19,543 100 %19,460 100 %19,222 100 %
Average number of retail customers:
Residential791,119 88 %779,673 88 %772,389 88 %
Commercial110,851 12 110,084 12 109,107 12 
Industrial267 — 262 — 270 — 
Total902,237 100 %890,019 100 %881,766 100 %
8

Table of Contents

(1)Includes both revenues from customers who purchase their energy supplies from the Company and revenues from the delivery of energy to those commercial and industrial customers that purchase their energy from ESSs.
(2)Amounts for the years ended December 31, 2020 and 2019 are primarily comprised of $24 million and $23 million of amortization, respectively, including interest, related to the $45 million deferral reflected in 2018 for the net tax benefits due to the change in corporate tax rate under the United States Tax Cuts and Jobs Act of 2017 (TCJA).
(3)Includes both energy sold to retail customers and energy deliveries to those commercial and industrial customers that purchase their energy from ESSs.

The following table presents additional averages for retail customers. Certain supplemental tariff collections are excluded from revenues as they are not considered a part of the Company’s base retail prices for these calculations.
Years Ended December 31,
 202020192018
Residential
Revenue per customer (in dollars):$1,226 $1,177 $1,153 
Usage per customer (in kilowatt hours):9,804 9,582 9,601 
Revenue per kilowatt hour (in cents):12.50 ¢12.28 ¢12.01 ¢
Commercial
Revenue per customer (in dollars):$5,684 $5,901 $6,051 
Usage per customer (in kilowatt hours):61,837 66,481 68,096 
Revenue per kilowatt hour (in cents):9.19 ¢8.88 ¢8.89 ¢
Industrial
Revenue per customer (in dollars):$921,540 $847,079 $776,245 
Usage per customer (in kilowatt hours):18,472,161 17,827,115 16,207,263 
Revenue per kilowatt hour (in cents):4.99 ¢4.75 ¢4.79 ¢

For additional information, see the Results of Operations section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

In addition to standard cost of service pricing, the Company offers different pricing options including a daily market price option, various time-of-use options, and several renewable energy options, which are offered to residential and small commercial customers. For additional information on customer options, see “Retail Customer Choice Program” within the Regulation section of this Item 1.

Residential customers include single family housing, multiple family housing (such as apartments, duplexes, and town homes), mobile homes, and small farms. Residential demand is sensitive to the effects of weather, with demand historically highest during the winter heating season. Increased use of air conditioning in PGE’s service territory has caused the summer peaks to increase in recent years, while the historical winter peak has not increased in over 20 years. In the past few years, summer peaks have exceeded winter peaks and long-term load forecasts expect that trend to continue. Economic conditions can also affect residential demand as job growth and population growth in PGE’s service territory have led to increased customer growth rates. Residential demand is also impacted by energy efficiency measures; however, the Company’s decoupling mechanism is intended to mitigate the financial effects of such measures.

Commercial customers consist of non-residential customers who accept energy deliveries at voltages equivalent to those delivered to residential customers. This customer class includes most businesses, small industrial companies, and public street and highway lighting accounts. The Company’s commercial customer demand is somewhat less susceptible to weather conditions than residential customer demand. Economic conditions and fluctuations in total employment in the region can also lead to changes in energy demand from commercial customers. Energy efficiency measures also impact commercial demand, although the Company’s decoupling mechanism partially mitigates the financial effects of such measures.

9

Table of Contents

Industrial customers consist of non-residential customers who accept delivery at higher voltages than commercial customers, with pricing based on the amount of electricity delivered under the applicable tariff. Demand from industrial customers is primarily driven by economic conditions, with weather having little impact on this customer class.

Wholesale Revenues

PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity, largely through bi-lateral agreements, within the region to serve retail demand, depending upon the relative price and availability of power, hydro and wind conditions, and daily and seasonal retail demand. PGE also participates in the California Independent System Operator’s western Energy Imbalance Market (western EIM), which allows for load balancing with other western EIM participants in five-minute intervals. Wholesale revenues represented 8% of total revenues in 2020, 2019, and 2018.

Other Operating Revenues

Other operating revenues consist primarily of gains and losses on the sale of natural gas volumes purchased that exceeded what was needed to fuel the Company’s generating facilities, as well as revenues from transmission services, excess transmission capacity resales, pole attachment rentals, and other electric services provided to customers. Other operating revenues represented 2% of total revenues in 2020, and 3% in 2019 and 2018.

Seasonality

Demand for electricity by PGE’s residential and, to a lesser extent, commercial customers, is affected by seasonal weather conditions. The Company uses heating and cooling degree-days to determine the effect of weather on the demand for electricity. Heating and cooling degree-days, determined by taking the difference between the average daily temperature and a baseline of 65 degrees, provide cumulative variances over a period of time, to indicate the extent to which customers are likely to have used electricity for heating or cooling. The higher the number of degree-days, the greater the expected demand for electricity.

The following table presents the heating and cooling degree-days for the most recent three-year period, along with 15-year averages for the most recent year provided by the National Weather Service, as measured at Portland International Airport:
 Heating
Degree-Days
Cooling
Degree-Days
20203,836600
20194,165564
20183,702692
15-year average4,145538
PGE’s all-time high net system load peak of 4,073 megawatts (MW) occurred in December 1998. The Company’s all-time summer peak of 3,976 MW occurred in August 2017. The following table presents PGE’s average winter (defined as January, February, and December) and summer (defined as June through September) loads for the periods presented, along with the corresponding peak load (in MWs) and month in which such peak occurred. As the table below illustrates, although the average winter loads continue to run higher than average summer loads, the Company continues to experience its highest annual peak loads during the summer months:

10

Table of Contents

Winter LoadsSummer Loads
AveragePeakMonthAveragePeakMonth
20202,5663,367December2,2893,771July
20192,6093,422February2,2633,765June
20182,5193,399February2,3013,816August

The Company tracks and evaluates both load growth and peak load requirements for purposes of long-term load forecasting, integrated resource planning, and preparing general rate case (GRC) assumptions. Behavior patterns, conservation, energy efficiency initiatives and measures, weather effects, economic conditions, and demographic changes all play a role in determining expected future customer demand and the resulting resources the Company will need to adequately meet those loads and maintain adequate capacity reserves.

Power Supply

PGE utilizes its generating resources, as well as wholesale power purchases from third parties to meet the needs of its retail customers. The volume of electricity the Company generates is dependent upon, among other factors, the capacity and availability of its generating resources and the price and availability of wholesale power and natural gas. As part of its power supply operations, the Company enters into short- and long-term power and fuel purchase and sale agreements. PGE executes economic dispatch decisions concerning its own generation and participates in the wholesale market in an effort to obtain reasonably-priced power for its retail customers, manage risk, and administer its long-term wholesale contracts. The Company also encourages energy efficiency measures to help meet its energy requirements and promotes the use of various demand side management products to reduce load during peak time usage.

11

Table of Contents

PGE’s resource and contracted capacity (in MW) was as follows:

 As of December 31,
 20202019
 Capacity%Capacity%
Generation:
Thermal (1):
Natural gas1,831 34 %1,830 35 %
Coal296 814 15 
Total thermal2,127 40 2,644 50 
Wind (2)
817 16 717 14 
Hydro (3)
495 495 
Total generation3,439 65 3,856 73 
Purchased power:
Long-term contracts:
Hydro (3)
512 10 462 
PURPA qualifying facilities (4)
279 133 
Dispatchable standby generation123 125 
Capacity100 100 
Wind (2)
300 100 
Solar— — 
Biomass10 — 10 — 
Total long-term contracts1,331 25 937 18 
Short-term contracts538 10 471 
Total purchased power1,869 35 1,408 27 
Total resource capacity5,308 100 %5,264 100 %
(1)Capacity represents the MW the plants are capable of generating under normal operating conditions, which is affected by ambient temperatures, net of electricity used in the operation of the plant. PGE’s Boardman coal-fired generating plant (Boardman) ceased coal-fired operations during the fourth quarter of 2020.
(2)Capacity represents nameplate and differs from expected energy to be generated, which is expected to have a capacity factor range from 30 to 40%, dependent upon wind conditions.
(3)Capacity represents net capacity and differs from expected energy to be generated, which is expected to have a capacity factor range from 40 to 50%, dependent upon river flows.
(4)Capacity represents contracted capacity under the Public Utility Regulatory Policies Act of 1978 (PURPA).
For information regarding actual generating output and purchases for the years ended December 31, 2020 and 2019, see the Results of Operations section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Generation

PGE’s generating resources consist of six thermal plants (natural gas- and coal-fired), three wind farms, and seven hydroelectric facilities. The portion of PGE’s retail load requirements generated by its plants varies from year to year and is determined by various factors, including planned and unplanned outages, availability and price of coal and natural gas, precipitation and snow-pack levels, the market price of electricity, and wind variability. For a complete listing of these facilities, see “Generating Facilities” in Item 2.—“Properties.”

Thermal    The Company has five natural gas-fired generating facilities: PW1, PW2, Beaver, Coyote Springs Unit 1 (Coyote Springs), and Carty Generating Station (Carty).
12

Table of Contents


The Company operated, and continues to have a 90% ownership interest in, Boardman, which ceased coal-fired operations during the fourth quarter of 2020. The Company has begun the initial steps toward decommissioning the facility. The Company also has a 20% ownership interest in the Colstrip Units 3 and 4 coal-fired generating plant (Colstrip), which is operated by a third party. Pursuant to SB 1547, PGE’s portion of Colstrip is scheduled to be fully depreciated by 2030, with the potential to utilize the output of the facility, in Oregon, until 2035. For additional information on SB 1547, see “Carbon Legislation and Administrative Actions” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Wind     PGE owns and operates two wind farms, Biglow Canyon Wind Farm (Biglow Canyon) and Tucannon River Wind Farm (Tucannon River). Biglow Canyon, located in Sherman County, Oregon, is PGE’s largest renewable energy resource consisting of 217 turbines with a total nameplate capacity of 450 MW. Tucannon River, located in southeastern Washington, consists of 116 turbines with a total nameplate capacity of 267 MW. During 2020, the wind component of the Wheatridge Renewable Energy Facility (Wheatridge), located in Morrow County, Oregon, was placed into service. Although PGE does not operate Wheatridge, it now owns 40 turbines with a total nameplate capacity of 100 MW and purchases the output of the remaining turbines, with a capacity of 200 MWs through power purchase agreements. For additional information on Wheatridge, see “The Resource Planning Process” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Hydro    The Company’s FERC-licensed hydroelectric projects consist of Pelton/Round Butte on the Deschutes River near Madras, Oregon (discussed below), four plants on the Clackamas River, and one on the Willamette River.

PGE has a 66.67% ownership interest in the 455 MW Pelton/Round Butte hydroelectric project on the Deschutes River, with the remaining interest held by the Confederated Tribes of the Warm Springs Reservation of Oregon (CTWS). A 50-year joint license for the project, which is operated by PGE, was issued by the FERC in 2005. The CTWS has an option to purchase an additional undivided 16.66% interest in Pelton/Round Butte at their discretion on December 31, 2021. CTWS has a second option in 2036 to purchase an undivided 0.02% interest in Pelton/Round Butte. If both options are exercised, CTWS’s ownership percentage would exceed 50%.

Fuel Supply—PGE contracts for natural gas and coal supplies required to fuel the Company’s thermal generating plants, with certain plants also able to operate on fuel oil, if needed. In addition, the Company uses forward, future, swap, and option contracts to manage its exposure to volatility in natural gas prices.

Natural Gas    Physical supplies of natural gas are generally purchased up to twelve months in advance of delivery and based on anticipated operation of the plants. PGE manages the price risk of natural gas supply through the use of financial contracts up to 60 months in advance of expected need of energy.

PGE owns 79.5%, and is the operator of record, of the KB Pipeline, which directly connects PW1, PW2, and Beaver to the Northwest Pipeline, an interstate natural gas pipeline operating between British Columbia and New Mexico. Currently, PGE transports natural gas on the KB Pipeline for its own use under a firm transportation service agreement, with capacity offered to others on an interruptible basis to the extent not utilized by the Company. PGE has access to 103,305 Dth per day of firm natural gas transportation capacity on the Northwest Pipeline to serve the three plants.

PGE has access to 4.1 billion cubic feet of natural gas storage in Mist, Oregon from which it can draw when economic factors favor its use or in the event that natural gas supplies are interrupted.
13

Table of Contents

The storage facility is owned and operated by NW Natural, and may be utilized to provide fuel to PW1, PW2, and Beaver.

To serve Coyote Springs and Carty, PGE has access to 120,000 Dth per day of firm natural gas transportation capacity on three pipeline systems accessing gas fields in Alberta, Canada.

Coal     The Colstrip co-owners obtain coal to fuel the plant via conveyor belt from a mine that lies adjacent to the facility and is the sole source of coal supply for the plant. The coal supply contract with the owner of the mine is scheduled to expire at the end of 2025. The terms of contracts and the quality of coal are expected to be in alignment with required emissions limits.

    Purchased Power
PGE supplements its own generation with power purchased in the wholesale market to meet its retail load requirements. The Company utilizes short- and long-term wholesale power purchase contracts in an effort to provide the most favorable economic mix on a variable cost basis.

PGE’s medium-term power cost strategy helps mitigate the effect of price volatility on its customers due to changing energy market conditions. The strategy allows the Company to take positions in power and fuel markets up to five years in advance of physical delivery. By purchasing a portion of anticipated energy needs for future years over an extended period, PGE mitigates a portion of the potential future volatility in the average cost of purchased power and fuel.
The Company’s major power purchase contracts consist of the following (also see the preceding table which summarizes the average resource capabilities related to these contracts):

Hydro—During 2020, the Company had the following agreements:

Public Utility Districts—PGE has long-term power purchase contracts with certain public utility districts in the state of Washington for a portion of the output of two hydroelectric projects on the mid-Columbia River. Although the projects currently provide a total of 313 MW of capacity, actual energy received is dependent upon river flows and capacity amounts may decline over time:

one contract, with Grant County PUD, representing 165 MW of capacity that expires in 2052;

one contract, with Douglas County PUD, representing 148 MW of capacity that expires in 2028; and

another contract with Douglas County PUD that is a five-year agreement starting January 1, 2021 to supply the Company with additional capacity between 100 and 160 MW, which is not reflected in the table above.

CTWS—PGE has a long-term agreement under which the Company purchases, at index prices, CTWS’ interest in the output of the Pelton/Round Butte hydroelectric project. Although the agreement provides approximately 162 MW of net capacity, actual energy received is dependent upon river flows. The term of the agreement coincides with the term of the FERC license for this project, which expires in 2055. In 2014, PGE entered into an agreement with CTWS under which CTWS has agreed to sell, on modified payment terms, its share of the energy generated from the Pelton/Round Butte hydroelectric project exclusively to the Company through 2024.

Other—PGE has two additional contracts that provide for the purchase of power generated from hydroelectric projects in Oregon with capacity of 37 MW in total. One contract for 36 MW expires in 2032 while the second has no expiration date.

14

Table of Contents

PURPA qualifying facilities—PGE is required to purchase power from PURPA qualifying facilities (QFs), as mandated by federal law. QFs are generating facilities that fall within the following two categories: i) qualifying generation facilities with a capacity of 80 MW or less and whose primary energy source is renewable (hydro, wind, solar, biomass, waste, or geothermal); or ii) qualifying cogeneration facilities that sequentially produce electricity and another form of useful thermal energy (e.g., heat, steam) in a way that is more efficient than the separate production of each form of energy. As of December 31, 2020, PGE had contracts with 60 on-line PURPA qualifying facilities, providing a total of 279 MW of capacity. As of December 31, 2020, PGE has 36 contracts with PURPA QFs representing 164 MW of capacity that are not yet operational, of which 34 of the QF power purchase agreements (PPAs) are in default because the QF has failed to complete construction and become operational by the date required by the PPA. The PPAs provide that the QF has one year to cure its default. If the QF has failed to cure, PGE is permitted to immediately terminate the QF PPA upon expiration of the cure period. The term of a QF PPA generally ranges from 15 to 23 years, measured from the date of execution.

The expense and volume of purchases from QFs for the years ended December 31, 2020 and 2019 were as follows:
20202019
PURPA contract expense (in millions)$43 $
MWh purchased under PURPA contracts (in thousands)498 152 
Average cost per MWh from PURPA contracts$85.31 $38.69 

Expenses incurred related to PURPA contracts are included in PGE’s AUT.

Dispatchable Standby Generation (DSG)—PGE has a DSG program under which the Company can start, operate, and monitor customer-owned diesel-fueled standby generators when needed to provide NERC-required operating reserves. As of December 31, 2020, there were 53 customer-owned sites with a total DSG capacity of 123 MW. PGE continues to pursue expansion of the program with the goal of having an additional 3 MW of customer-owned DSG projects online by the end of 2022.

Capacity—PGE’s capacity contracts are primarily comprised of the following agreements to help meet peak loads:

Seasonal peaking capacity up to 100 MW during the summer and winter peak periods obtained from a natural gas-fired resource, which expires in 2024; and

Starting in January 2021, an additional 200 MW of annual capacity will be added, with a five-year term, primarily obtained from hydroelectric resources.

Wind—PGE has three contracts representing 300 MW of capacity to purchase power generated from renewable wind resources that extend to 2028, 2035, and 2050. The expected energy from these wind resources will vary from the nameplate capacity due to varying wind conditions.

Solar—PGE has three contracts representing 7 MW of capacity to purchase power generated from photovoltaic solar projects that extend to 2036 and 2037. The expected energy from these solar resources will vary from the nameplate capacity due to varying solar conditions.

Biomass—PGE has one contract to purchase biomass energy that is set to expire in 2021.

Short-term contracts—These contracts are for delivery periods of one month up to one year in length. They are entered into with various counterparties to provide additional firm energy to help meet the Company’s load requirements.

PGE also utilizes spot purchases of power in the open market to secure the energy required to serve its retail customers. Such purchases are made under contracts that range in duration from 15 minutes to less than one month.
15

Table of Contents

As of 2017, PGE became a market participant in the western EIM, which allows certain of the Company’s generating plants to receive automated dispatch signals from the California Independent System Operator (CAISO) for load balancing with other western EIM participants in five-minute intervals.

For additional information regarding PGE’s power purchase contracts, see Note 16, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Future Energy Resource Strategy

PGE’s Integrated Resource Plan (IRP) outlines the Company’s plan to meet future customer demand and describes PGE’s future energy supply strategy. For a detailed discussion of the IRPs, see “The Resource Planning Process” within the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Transmission and Distribution

Transmission systems deliver energy from generating facilities to distribution systems for final delivery to customers. PGE schedules energy deliveries over its transmission system in accordance with FERC requirements and operates one balancing authority area (an electric system bounded by interchange metering) in its service territory. In 2020, PGE delivered approximately 25 million megawatt hours (MWh) in its balancing authority area through 1,269 circuit miles of transmission lines operating at or above 115 kilovolts (kV).

PGE’s transmission system is part of the Western Interconnection, the regional grid in the western United States. The Western Interconnection includes the interconnected transmission systems of 11 western states, two Canadian provinces and parts of Mexico, and is subject to the reliability rules of the WECC and the NERC. PGE relies on transmission contracts with Bonneville Power Administration (BPA) to transmit a significant amount of the Company’s generation to serve its distribution system. PGE’s transmission system, together with contractual rights on other transmission systems, enables the Company to integrate and access generation resources to meet its customers’ energy requirements. PGE’s generation is managed on a coordinated basis to obtain maximum load-carrying capability and efficiency.

The Company’s wholesale transmission activities are regulated by the FERC and are offered on a non-discriminatory basis, with all potential customers provided equal access to PGE’s transmission system through PGE’s OATT. In accordance with its OATT, PGE offers several transmission services to wholesale customers, including:

Network integration transmission service, a service that integrates generating resources to serve retail loads;

Short- and long-term firm point-to-point transmission service, a service with fixed delivery and receipt points; and

Non-firm point-to-point service, an “as available” service with fixed delivery and receipt points.

For additional information regarding the Company’s transmission and distribution facilities, see “Transmission and Distribution” in Item 2.—“Properties.”

Environmental Matters

PGE’s operations are subject to a wide range of environmental protection laws and regulations, which pertain to air and water quality, endangered species and wildlife protection, and hazardous material. Various state and federal agencies regulate environmental matters that relate to the siting, construction, and operation of generation, transmission, and substation facilities and the handling, accumulation, clean-up, and disposal of toxic and hazardous substances. In addition, certain of the Company’s hydroelectric projects and transmission facilities are located on property under the jurisdiction of federal and state agencies, and/or tribal entities that have authority in
16

Table of Contents

environmental protection matters. The following discussion provides further information on certain regulations that affect the Company’s operations and facilities.

Air Quality

Clean Air Act—PGE’s operations, primarily its thermal generating plants, are subject to regulation under the federal Clean Air Act (CAA), which addresses particulate matter, hazardous air pollutants, and greenhouse gas (GHG) emissions, among other things. Oregon and Montana, the states in which PGE’s thermal facilities are located, also implement and administer certain portions of the CAA and have set standards that are at least as stringent as federal standards. PGE manages its air emissions at its thermal generating plants by the use of low sulfur fuel, emissions and combustion controls and monitoring, and sulfur dioxide allowances awarded under the CAA.

Climate Change—In 2015, the United States Environmental Protection Agency (EPA) released the Clean Power Plan (CPP), under which each state would have to reduce carbon dioxide emissions from its power sector on a state-wide basis. In 2016, the United States Supreme Court halted implementation and enforcement of the CPP.

In 2018, the EPA proposed the Affordable Clean Energy (ACE) rule, to repeal and replace the CPP and, in 2019, finalized the ACE rule, which established guidelines for states to develop plans to address GHG emissions from existing coal-fired plants, such as Colstrip in the case of PGE. With the finalization of the ACE rule, the CPP was repealed. However, on January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE rule and remanded it, in full, back to the EPA, the impact of which casts uncertainty on the status of the CPP, as the court did not say whether it viewed its decision on the ACE rule as reinstatement of the CPP.

The EPA has now been directed to review all climate and environmental rules promulgated over the past four years, including the ACE rule. The Company will continue to monitor any challenges to the recent ACE rule decision, and how the EPA will replace the ACE rule, and potentially the CPP, for impacts on Colstrip and its existing natural gas fleet.

Any laws that would impose taxes or mandatory reductions in GHG emissions may have a material impact on PGE’s operations, as the Company utilizes fossil fuels in its own power generation and other companies use such fuels to generate power that PGE purchases in the wholesale market. If incremental costs were incurred as a result of changes in the regulations regarding GHGs, the Company would seek recovery in customer prices.

PGE’s carbon-emitting facilities provided 62% of the Company’s net generating capacity at December 31, 2020.

For more information regarding GHGs and related environmental regulation, see “Carbon Legislation and Administrative Actions” in the Overview section of Item 7.—”Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Water Quality

The federal Clean Water Act requires that any federal license or permit to conduct an activity that may result in a discharge to waters of the United States must first receive a water quality certification from the state in which the activity will occur. In Oregon, Montana, and Washington, the Departments of Environmental Quality are responsible for reviewing proposed projects under this requirement to ensure that federally approved activities will meet water quality standards and policies established by the respective state. PGE has obtained permits where required and has certificates of compliance for its hydroelectric operations under the FERC licenses. The Company is currently subject to litigation with regard to water quality conditions on the Deschutes River. For additional information on this litigation see “Deschutes River Alliance Clean Water Act Claims” in Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”


17

Table of Contents

Threatened and Endangered Species and Wildlife

Fish Protection—The federal Endangered Species Act (ESA) has granted protection to many populations of migratory fish species in the Pacific Northwest. Long-term recovery plans for these species continue to have operational impacts on many of the region’s hydroelectric projects. PGE continues to implement fish protection measures at its hydroelectric projects that were prescribed by the U.S. Fish and Wildlife Service and the National Marine Fisheries Service under their authority granted in the ESA and the FPA. Conditions required with the operating licenses are expected to result in a minor reduction in power production and continued capital spending to modify the facilities to enhance fish passage and survival.

Avian Protection—Various statutes, including the Migratory Bird Treaty Act and Bald and Golden Eagle Protection Act, contain provisions for civil, criminal, and administrative penalties resulting from the unauthorized take of migratory birds and eagles. Because PGE operates facilities that can pose risks to a variety of such birds, the Company developed an Avian Protection Plan to help address and reduce risks to bird species that may be affected by Company operations. PGE has implemented such a plan for its transmission, distribution, and thermal generation facilities and continues to finalize additional plans for its wind generation facilities.

Hazardous Material

PGE has a comprehensive program to comply with requirements of both federal and state regulations related to the storage, handling, and disposal of hazardous materials. The handling and disposal of hazardous materials from Company facilities is subject to regulation under the federal Resource Conservation and Recovery Act. In addition, the use, disposal, and clean-up of polychlorinated biphenyls, contained in certain electrical equipment, are regulated under the federal Toxic Substances Control Act.

PGE is also subject to regulation under the Comprehensive Environmental Response Compensation and Liability Act, commonly referred to as Superfund, which provides authority to the EPA to assert joint and several liability for investigation and remediation costs for designated Superfund sites.

An investigation by the EPA that began in 1997 of a segment of the Willamette River in Oregon known as Portland Harbor, revealed significant contamination of river sediments and prompted the EPA to designate Portland Harbor as a Superfund site. The EPA has listed PGE among the more than one hundred Potentially Responsible Parties (PRPs) in this matter, as PGE historically owned or operated property near the river. For additional information regarding the EPA action on Portland Harbor, see Note 19, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

PGE is subject to regulation by the United States Department of Energy (USDOE), which, under the Nuclear Waste Policy Act of 1982, is responsible for the permanent storage and disposal of spent nuclear fuel. PGE has contracted with the USDOE for permanent disposal of spent nuclear fuel from Trojan that is stored in the Independent Spent Fuel Storage Installation (ISFSI), an NRC-licensed interim dry storage facility that houses the fuel at the former plant site. The NRC approved the transfer of spent nuclear fuel from a spent fuel pool to the ISFSI where it is expected to remain until permanent off-site storage is available. Shipment of the spent nuclear fuel from the ISFSI to off-site storage is not expected to be completed prior to 2059. For additional information regarding this matter, see “Trojan decommissioning activities” in Note 8, Asset Retirement Obligations, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Human Capital Management

PGE’s talent and culture are vital to its ability to execute its business strategy and realize continued success. Accordingly, the Company seeks to attract and retain a talented, motivated, and diverse workforce and maintain a culture that reflects PGE’s core values, drive for performance, and commitment to acting with the highest levels of honesty, integrity, and compliance.

18

Table of Contents

Employees and Collective Bargaining AgreementsPGE had 3,639 members in its workforce (769 of which are contingent workers) as of December 31, 2020, with 721 employees covered under one of two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers (IBEW). The agreements cover 660 and 61 employees and expire March 2022 and August 2022, respectively. The partnership with IBEW is key to a holistic labor relations approach.

Competitive Pay and BenefitsPGE is committed to ensuring pay equity among its employees and offers a wide range of market-competitive benefits, including comprehensive health and welfare benefits and a 401(k) retirement plan, designed to support the physical, mental, and financial well-being of its employees.

Talent development PGE provides a variety of training and development programs for employees, as well as tuition reimbursement for job-related coursework. The Board oversees executive talent development with the assistance of the Governance Committee and the Compensation Committee in an effort to maximize the pool of internal candidates. In addition, the Compensation Committee regularly conducts more in-depth reviews of development plans for promising management talent for promotion and advancement.

Health and safetyPGE is committed to providing a safe and healthy place of business for employees, customers, and the public. Management has established an Executive Safety Council that has oversight of the Company’s efforts to create a safe workplace. In addition, PGE provides various safety resources to its employees, such as safety manuals, trainings, and incident reporting tools that are all designed to incorporate safe practices into all daily activities and promote in all employees a sense of personal commitment, responsibility, and obligation regarding safety.

Diversity, Equity and InclusionPGE promotes an inclusive workforce through pay equity practices, racial equity training, and development opportunities for women and people of color to advance into management. Black, Indigenous, and People of Color comprise over 22% of its employees and nearly 19% of management. Nearly one third of its employees and over 31% of its management, including its CEO, are female. PGE also promotes diversity and economic development through its suppliers. The Company’s supplier diversity program ensures opportunity in all competitive bid events for qualified minority-owned, women-owned, disabled veteran-owned, and emerging small business suppliers.

COVID-19 In response to the COVID-19 pandemic, PGE took immediate steps to protect employees by making changes to work schedules, work locations, cleaning practices, work protocols, and information services—including encouraging employees to take advantage of its comprehensive health, wellness, family, and leave programs.


Information about Our Executive Officers

The following are PGE’s current executive officers:
19

Table of Contents

NameAgeCurrent Position and Previous ExperienceYear Appointed Officer
James A. Ajello67Senior Vice President, Finance, Chief Financial Officer and Treasurer (January 2021 to present), Senior Advisor (November 2020 to December 2020), Executive Vice President and Chief Financial Officer at Hawaiian Electric Industries (January 2009 to April 2017 - retired), Senior Vice President, Business Development at Reliant Energy (January 2000 to January 2009), Managing Director, UBS Securities (January 1984 to August 1998).2021
Larry N. Bekkedahl59Vice President, Grid Architecture, Integration and Systems Operations (January 2019 to present), Vice President Transmission and Distribution (August 2014 to January 2019). Senior Vice President of Transmission Services at BPA (June 2012 to August 2014), Vice President of Engineering and Technical Services at BPA (2008 to June 2012).2014
Bradley Y. Jenkins57Vice President, Utility Operations (January 2019 to present), Vice President, Generation and Power Operations (October 2017 to January 2019), Vice President, Power Supply Generation (September 2015 to October 2017), General Manager, Diversified Plant Operations, (November 2013 to August 2015), Plant General Manager, Boardman (September 2012 to November 2013), Operations Manager, Boardman (March 2012 to September 2012).2015
Lisa A. Kaner60Vice President, General Counsel and Corporate Compliance Officer (July 2017 to present), trial attorney and shareholder at Markowitz Herbold PC (1994 to June 2017).2017
John T. Kochavatr47Vice President, Information Technology and Chief Information Officer (February 2018 to present). Senior Vice President and Chief Information Officer at SUEZ Water Technologies & Solutions (formerly General Electric Water and Process Technologies) (October 2017 to January 2018), Chief Information Officer and Chief Digital Officer at General Electric Water and Process Technologies (November 2012 to September 2017).2018
John C. McFarland40Vice President, Chief Customer Officer (April 2019 to present). Director, Global Digital Experience at General Motors (February 2016 to March 2019), Chief Marketing Officer at OnStar (a subsidiary of General Motors, October 2012 to January 2016), Senior Manager of Strategy at General Motors (September 2010 to September 2012), Brand Management and Finance at Procter & Gamble (August 2002 to August 2010).2019
Anne F. Mersereau58Vice President, Human Resources, Diversity, Equity and Inclusion (January 2016 to present), Employee Services Manager (January 2014 to January 2016), Change Management Consultant (January 2012 to January 2014), Human Resources Business Partner (July 2009 to December 2011).2016
Maria M. Pope55President (October 2017 to present) and Chief Executive Officer (January 2018 to present), Senior Vice President, Power Supply, Operations and Resource Strategy (March 2013 to December 2017), Senior Vice President, Finance, Chief Financial Officer and Treasurer (January 2009 to February 2013). Board director (January 2006 to December 2008). Vice President and Chief Financial Officer for Mentor Graphics Corporation (July 2007 to December 2008).2009
W. David Robertson53Vice President, Public Affairs (August 2009 to present), Director of Government Affairs (June 2004 to August 2009).2009
Brett M. Sims52Vice President, Strategy, Regulation and Energy Supply (October 2020 to present), Senior Director of Strategy, Commercial and Regulatory Affairs (September 2017 to October 2020), Director of Origination, Structuring & Resource Strategy (May 2001 to September 2017).2020
Kristin A. Stathis57Vice President, Operations Services (May 2019 to present), Vice President, Customer Solutions (January 2019 to May 2019), Vice President, Customer Service Operations (June 2011 to December 2018), General Manager of Revenue Operations (August 2009 to May 2011), Assistant Treasurer and Manager of Corporate Finance (October 2005 to July 2009), General Manager of Power Supply Risk Management (August 2003 to September 2005).2011
20

Table of Contents


ITEM 1A.     RISK FACTORS.

Certain risks and uncertainties that could have a material impact on PGE’s business, financial condition, results of operations, or cash flows, or that may cause the Company’s actual results to vary materially from the forward-looking statements contained in this Annual Report on Form 10-K, include those set forth below.

REGULATORY, LEGAL, AND COMPLIANCE RISKS

PGE is subject to extensive regulation that affects the Company’s operations and costs.

PGE is subject to regulation by the FERC, the OPUC, and by certain federal, state, and local authorities under environmental and other laws. Such regulation significantly influences the Company’s operating environment and can have an effect on many aspects of its business. Changes to regulations are ongoing, and the Company cannot predict with certainty the future course of such changes or the ultimate effect that they might have on its business. However, changes in regulations could delay or adversely affect business planning and transactions, and substantially increase the Company’s costs.

Recovery of PGE’s costs is subject to regulatory review and approval, and the inability to recover costs may adversely affect the Company’s results of operations.

The prices that PGE charges for its retail services, as authorized by the OPUC, are a major factor in determining the Company’s operating income, financial position, liquidity, and credit ratings. As a general matter, PGE seeks to recover in customer prices most of the costs incurred in connection with the operation of its business, including, among other things, costs related to capital projects (such as the construction of new facilities or the modification of existing facilities), the costs of compliance with legislative and regulatory requirements, and the costs of damage from storms and other natural disasters. However, there can be no assurance that such recovery will be granted. The OPUC has the authority to disallow the recovery of any costs that it considers imprudently incurred. Although the OPUC is required to establish customer prices that are fair, just and reasonable, it has significant discretion in the interpretation of this standard.

PGE attempts to manage its costs at levels consistent with the OPUC approved prices. However, if the Company is unable to do so, or if such cost management results in increased operational risk, the Company’s financial and operating results could be adversely affected.

PGE is subject to various legal and regulatory proceedings, the outcome of which is uncertain, and resolution unfavorable to PGE could adversely affect the Company’s results of operations, financial condition, or cash flows.

In the normal course of its business, PGE is subject to various regulatory proceedings, lawsuits, claims, and other matters, which could result in adverse judgments, settlements, fines, penalties, injunctions, or other relief. These matters are subject to many uncertainties, the ultimate outcome of which management cannot predict. The final resolution of certain matters in which PGE is involved could require that the Company incur expenditures over an extended period of time and in a range of amounts that could have an adverse effect on its cash flows and results of operations. Similarly, the terms of resolution could require the Company to change its business practices and procedures, which could also have an adverse effect on its cash flows, financial position, or results of operations.

There are certain pending legal and regulatory proceedings that may have an adverse effect on results of operations and cash flows for future reporting periods. For additional information, see Item 3.—“Legal Proceedings” and Note 19, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”


21

Table of Contents

Legislative or regulatory efforts to reduce GHG emissions could lead to increased capital and operating costs and have an adverse impact on the Company’s results of operations.

Future legislation or regulations could result in limitations on GHG emissions from the Company’s fossil fuel-fired generation facilities. Compliance with any GHG emissions reduction requirements could require PGE to incur significant expenditures, including those related to carbon capture and sequestration technology, purchase of emission allowances and offsets, fuel switching, and the replacement of high-emitting generation facilities with lower-emitting facilities.

The cost to comply with potential GHG emissions reduction requirements is subject to significant uncertainties, including those related to: i) the timing of the implementation of emissions reduction rules; ii) required levels of emissions reductions; iii) requirements with respect to the allocation of emissions allowances; iv) the maturation, regulation, and commercialization of carbon capture and sequestration technology; and v) PGE’s compliance alternatives. Although the Company cannot currently estimate the effect of future legislation or regulations on its results of operations, financial condition, or cash flows, the costs of compliance with such legislation or regulations could be material.

Operational changes required to comply with both existing and new environmental laws related to fish and wildlife could adversely affect PGE’s results of operations.

A portion of PGE’s total system load is supplied with power generated from hydroelectric and wind generating resources. Operation of these facilities is subject to regulation related to the protection of fish and wildlife. The listing of various plants and species of fish, birds, and other wildlife as threatened or endangered has resulted in significant operational changes to these projects. Salmon recovery plans could include further major operational changes to the region’s hydroelectric projects, including those owned by PGE and those from which the Company purchases power under long-term contracts. In addition, laws relating to the protection of migratory birds and other wildlife could impact the development and operation of transmission and distribution lines and wind projects. Also, new interpretations of existing laws and regulations could be adopted or become applicable to such facilities, which could further increase required expenditures for salmon recovery and endangered species protection and reduce the availability of hydroelectric or wind generating resources to meet the Company’s energy requirements.

The construction of new facilities, or modifications to existing facilities, is subject to risks that could result in the disallowance of certain costs for recovery in customer prices or higher operating costs.

PGE supplements its own generation with wholesale power purchases to meet its retail load requirement. In addition, long-term increases in both the number of customers and demand for energy will require continued expansion and upgrade of PGE’s generation, transmission, and distribution systems. Construction of new facilities and modifications to existing facilities could be affected by various factors, including unanticipated delays and cost increases and the failure to obtain, or delay in obtaining, necessary permits from state or federal agencies or tribal entities, which could result in failure to complete the projects and the disallowance of certain costs in the rate determination process. In addition, failure to complete construction projects according to specifications could result in reduced plant efficiency, equipment failure, and plant performance that falls below expected levels, which could increase operating costs.

ECONOMIC, FINANCIAL, AND MARKET RISKS

Economic conditions that result in reduced demand for electricity and impair the financial stability of some of PGEs customers could affect the Companys results of operations.

Unfavorable economic conditions in Oregon may result in reduced demand for electricity. Such reductions in demand could adversely affect PGE’s results of operations and cash flows. Economic conditions could also result in an increased level of uncollectible customer accounts and cause the Company’s vendors and service providers to experience cash flow problems and be unable to perform under existing or future contracts.
22

Table of Contents


Capital and credit market conditions could adversely affect the Company’s access to capital, cost of capital, and ability to execute its strategic plan as currently envisioned.

Access to capital and credit markets is important to PGE’s ability to operate. The Company expects to issue debt and equity securities, as necessary, to fund its future capital requirements. In addition, contractual commitments and regulatory requirements may limit the Company’s ability to delay or terminate certain projects.

If the capital and credit market conditions in the United States and other parts of the world deteriorate, the Company’s future cost of debt and equity capital, as well as access to capital markets, could be adversely affected. In addition, restrictions on PGE’s ability to access capital markets could affect its ability to execute its strategic plan.

Adverse changes in PGE’s credit ratings could negatively affect its access to the capital markets and its cost of borrowed funds.

Access to capital markets is important to PGE’s ability to operate its business and complete its capital projects. Credit rating agencies evaluate the Company’s credit ratings on a periodic basis and when certain events occur. A ratings downgrade could increase fees on PGE’s revolving credit facilities and letter of credit facilities, increasing the cost of funding day-to-day working capital requirements, and could also result in higher interest rates on future long-term debt. A ratings downgrade could also restrict the Company’s access to the commercial paper market, a principal source of short-term financing, or result in higher interest costs.

In addition, if Moody’s Investors Service (Moody’s) and/or S&P Global Ratings (S&P) reduce their rating on PGE’s unsecured debt to below investment grade, the Company could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, which could have an adverse effect on the Company’s liquidity.

Under certain circumstances, banks participating in PGE’s credit facilities could decline to fund advances requested by the Company or could withdraw from participation in the credit facilities.

PGE currently has a syndicated unsecured revolving credit facility with several banks for an aggregate amount of $500 million. The revolving credit facility provides a primary source of liquidity and may be used to supplement operating cash flow and as backup for commercial paper borrowings. The revolving credit facility represents commitments by the participating banks to make loans and, in certain cases, to issue letters of credit. The Company is required to make certain representations to the banks each time it requests an advance under the credit facility. However, in the event certain circumstances occur that could result in a material adverse change in the business, financial condition, or results of operations of PGE, the Company may not be able to make such representations, in which case the banks would not be required to lend. PGE is also subject to the risk that one or more of the participating banks may default on their obligation to make loans under the credit facility.

Adverse capital market performance could result in reductions in the fair value of benefit plan assets and increase the Company’s liabilities related to such plans. Sustained declines in the fair value of the plans’ assets could result in significant increases in funding requirements, which could adversely affect PGE’s liquidity and results of operations.

Performance of the capital markets affects the value of assets that are held in trust to satisfy future obligations under PGE’s defined benefit pension and other postretirement plans. Sustained adverse market performance could result in lower rates of return for these assets than projected by the Company and could increase PGE’s funding requirements related to the plans. Additionally, changes in interest rates affect PGE’s liabilities under the plans. As interest rates decrease, the Company’s liabilities increase, potentially requiring additional funding.

23

Table of Contents

Performance of the capital markets also affects the fair value of assets that are held in trust to satisfy future obligations under the Company’s non-qualified employee benefit plans, which include deferred compensation plans. As changes in the fair value of these assets are recorded in current earnings, decreases can adversely affect the Company’s operating results. In addition, such decreases can require that PGE make additional payments to satisfy its obligations under these plans.

Market prices for power and natural gas are subject to forces that are often not predictable and that can result in price volatility and general market disruption, adversely affecting PGE’s costs and ability to manage its energy portfolio and procure required energy supply, which ultimately could have an adverse effect on the Company’s liquidity and results of operations.

As part of its normal business operations, PGE purchases and sells power and natural gas in the open market under short- and long-term contracts, which may specify variable prices or volumes. Market prices for power and natural gas are influenced primarily by factors related to supply and demand. These factors generally include the adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric and wind generation levels, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth, and changes in technology.

Volatility in these markets can affect the availability, price, and demand for power and natural gas. Disruption in power and natural gas markets could result in a deterioration of market liquidity, increase the risk of counterparty default, affect regulatory and legislative processes in unpredictable ways, affect wholesale power prices, and impair PGE’s ability to manage its energy portfolio. Changes in power and natural gas prices can also affect the fair value of derivative instruments and cash requirements to purchase power and natural gas. If power and natural gas prices decrease from those contained in the Company’s existing purchased power and natural gas agreements, PGE may be required to provide increased collateral, which could adversely affect the Company’s liquidity. Conversely, if power and natural gas prices rise, especially during periods when the Company requires greater-than-expected volumes that must be purchased at market or short-term prices, PGE could incur greater costs than originally estimated.

The risk of volatility in power costs is partially mitigated through the AUT and the PCAM. Application of the PCAM requires that PGE absorb certain power cost increases before the Company is allowed to recover any amount from customers. Accordingly, the PCAM is expected to only partially mitigate the potentially adverse financial impacts of forced generating plant outages, reduced hydro and wind availability, interruptions in fuel supplies, and volatile wholesale energy prices.

BUSINESS AND OPERATIONAL RISKS

The spread of COVID-19 could have a material adverse effect on PGE’s business.

The COVID-19 pandemic has adversely impacted economic activity and conditions worldwide. Measures to control the spread of COVID-19 have affected the demand for the products and services of many businesses in PGE’s service territory and disrupted supply chains around the world. Due to COVID-19, PGE has observed an increase in past due accounts and late customer payments resulting in incremental bad debt expense of $8 million in 2020 that has been deferred pursuant to the OPUC’s COVID-19 deferral. PGE has also observed a change in the trend of customer demand with an increase in residential usage as customers stay at home and a decrease in commercial usage due to COVID-19 related closures and economic conditions. Although these trends have not had a material impact on the Company to date, management believes that these trends will continue and the full scope and extent of the impacts of COVID-19 on the Company’s operations remains uncertain and depends on multiple variables. PGE continues to monitor the impacts of the COVID-19 pandemic on its workforce, liquidity, capital markets, reliability, cybersecurity, customers, and suppliers, along with overall macroeconomic conditions. Although the Company cannot predict with certainty the full extent of the COVID-19 pandemic’s impact on its business, a protracted slowdown of broad sectors of the economy, changes in demand for commodities, or significant changes in legislation or regulatory policy to address the COVID-19 pandemic could ultimately result in a significant reduction in demand for electricity in PGE’s service territory, increased late customer payments or uncollectible
24

Table of Contents

accounts, and the inability of the Company’s contractors, suppliers, and other business partners to fulfill their contractual obligations, any of which could have, or continue to have, a material adverse effect on the Company’s results of operations, financial condition and cash flows.

Changes in tax laws may have an adverse impact on the Company’s financial position, results of operations, and cash flows.

PGE makes judgments and interpretations about the application of tax law when determining the provision for taxes. Such judgments include the timing and probability of recognition of income, deductions, and tax credits, which are subject to challenge by taxing authorities. Additionally, treatment of tax benefits and costs for ratemaking purposes could be different than what the Company anticipates or requests from the state regulatory commission, which could have a negative effect on the Company’s financial condition and results of operations.
PGE owns and operates wind generating facilities, which generate federal production tax credits (PTCs) that PGE uses to reduce its federal tax obligations. The amount of PTCs earned depends on the level of electricity output generated and the applicable tax credit rate. A variety of operating and economic parameters, including adverse weather conditions and equipment reliability, could significantly reduce the PTCs generated by the Company’s wind facilities resulting in a material adverse impact on PGE’s financial condition and results of operations. These PTCs generate tax credit carryforwards that the Company plans to utilize in the future to reduce income tax obligations. If PGE cannot generate enough taxable income in the future to utilize all of the tax credit carryforwards before the credits expire, the Company may incur material charges to earnings.
The effects of weather on electricity usage can adversely affect results of operations.

Weather conditions can adversely affect PGE’s revenues and costs, impacting the Company’s results of operations. Variations in temperatures can affect customer demand for electricity, with warmer-than-normal winter seasons or cooler-than-normal summer seasons reducing the demand for energy. Weather conditions are the dominant cause of usage variations from normal seasonal patterns, particularly for residential customers. Severe weather can also disrupt energy delivery and damage the Company’s transmission and distribution system.

Rapid increases in load requirements resulting from unexpected weather changes, particularly if coupled with transmission constraints, could adversely impact PGE’s cost and ability to meet the energy needs of its customers. Conversely, rapid decreases in load requirements could result in the sale of excess energy at depressed market prices.

Reduced river flows can adversely affect generation from hydroelectric resources and unfavorable wind conditions can similarly affect wind generating resources. The Company could be required to replace energy expected from these sources with higher cost power from other facilities or with wholesale market purchases, which could have an adverse effect on results of operations.

PGE derives a significant portion of its power supply from its own hydroelectric facilities and through long-term purchase contracts with certain public utility districts in the state of Washington. Regional rainfall and snowpack levels affect river flows and the resulting amount of energy generated by these facilities. Shortfalls in energy expected from lower cost hydroelectric generating resources would require increased energy from the Company’s other generating resources and/or power purchases in the wholesale market, which could have an adverse effect on results of operations.

PGE also derives a portion of its power supply from wind generating resources, for which the output is dependent upon wind conditions. Unfavorable wind conditions could require increased reliance on power from the Company’s thermal generating resources or power purchases in the wholesale market, both of which could have an adverse effect on results of operations.

Although the application of the PCAM could help mitigate adverse financial effects from any decrease in power provided by hydroelectric and wind generating resources, full recovery of any increase in power costs is not
25

Table of Contents

assured. Inability to fully recover such costs in future prices could have a negative impact on the Company’s results of operations, as well as a reduction in renewable energy credits and loss of PTCs related to wind generating resources.

Storms, earthquakes, wildfires, and other natural disasters could damage the Company’s facilities and disrupt delivery of electricity resulting in significant property loss, repair costs, and reduced customer satisfaction.

PGE has exposure to natural disasters that can cause significant damage to its generation, transmission, and distribution facilities. Such events can interrupt the delivery of electricity, increase repair and service restoration expenses, and reduce revenues. Such events, if repeated or prolonged, can also affect customer satisfaction and the level of regulatory oversight. As a regulated utility, the Company is required to provide service to all customers within its service territory and generally has been afforded liability protection against customer claims related to service failures beyond the Company’s reasonable control.

PGE could be vulnerable to cybersecurity attacks, data security breaches, acts of terrorism, or other similar events that could disrupt its operations, require significant expenditures, or result in claims against the Company.

In the normal course of business, PGE collects, processes, and retains sensitive and confidential customer and employee information, as well as proprietary business information, and operates systems that directly impact the availability of electric power and the transmission of electric power in its service territory. Despite the security measures in place, the Company’s systems, and those of third-party service providers, could be vulnerable to cybersecurity attacks, data security breaches, acts of terrorism, or other similar events that could disrupt operations or result in the release of sensitive or confidential information. Such events could cause a shutdown of service or expose PGE to liability. In addition, the Company may be required to expend significant capital and other resources to protect against security breaches or to alleviate problems caused by security breaches. PGE maintains insurance coverage against some, but not all, potential losses resulting from these risks. However, insurance may not be adequate to protect the Company against liability in all cases. In addition, PGE is subject to the risk that insurers will dispute or be unable to perform their obligations to the Company.

Forced outages at PGE’s generating plants can increase the cost of power required to serve customers because the cost of replacement power purchased in the wholesale market generally exceeds the Company’s cost of generation.

Forced outages at the Company’s generating plants could result in power costs greater than those included in customer prices. As indicated above, application of the Company’s PCAM could help mitigate adverse financial impacts of such outages; however, the cost sharing features of the mechanism do not provide full recovery in customer prices. Inability to recover such costs in future prices could have a negative impact on the Company’s results of operations.

Development of alternative technologies may negatively impact the value of PGE’s generation facilities.
A basic premise of PGE’s business is the ability to produce electricity at competitive prices due to economies of scale. Many companies and organizations conduct research and development activities to seek improvements in alternative technologies and distributed generation. It is possible that advances in such technologies, or other current technologies, will reduce the cost of alternative methods of electricity production to a level that is equal to or below that of existing generation facilities. Such a development could limit the Company’s future growth opportunities and limit growth in demand for PGE’s electric service.

The inability to attract and retain a qualified workforce, including senior management talent, and to maintain satisfactory collective bargaining agreements without prolonged labor disruptions, may adversely affect PGE’s results of operations.

26

Table of Contents

PGE’s workforce includes a diverse mix of skilled professional, managerial and technical employees, including employees represented under collective bargaining agreements. Workforce management risks include the risk of turnover due to demographic challenges as employees approach retirement age. PGE also faces competition from other employers for key skills and experience within the industry or local geography. The Company also faces the risk of labor disruption due to the outcomes of labor negotiations or the possibility that employees not currently subject to collective bargaining agreements may organize.

PGE business activities are concentrated in one region and future performance may be affected by events and factors unique to Oregon.

The Company’s industry and geographic concentrations may increase exposure to risks arising from regional regulation or legislation, such as legislative action related to carbon emissions. These concentrations may also increase exposure to credit and operational risks due to counterparties, suppliers, and customers being similarly affected by changing conditions.

ITEM 1B.     UNRESOLVED STAFF COMMENTS.

None.

ITEM 2.     PROPERTIES.

PGE’s principal property, plant, and equipment are generally located on land owned by the Company or land under the control of the Company pursuant to existing leases, federal or state licenses, easements, or other agreements. In some cases, meters and transformers are located on customer property. The Indenture securing the Company’s First Mortgage Bonds (FMBs) constitutes a direct first mortgage lien on substantially all utility property and franchises, other than expressly excepted property.

Generating Facilities

The following are generating facilities owned by PGE as of December 31, 2020 (in MW):
27

Table of Contents

FacilityLocation
Net
Capacity (1)
Wholly-owned:
Natural Gas or Oil:
BeaverClatskanie, Oregon508 
CartyBoardman, Oregon438 
Port Westward Unit 1 (PW1)Clatskanie, Oregon411 
Coyote SpringsBoardman, Oregon249 
Port Westward Unit 2 (PW2)Clatskanie, Oregon225 
Wind:
Biglow CanyonSherman County, Oregon450 
Tucannon River Columbia County, Washington267 
Wheatridge
Morrow County, Oregon100 
Hydro:
North ForkClackamas River58 
FaradayClackamas River46 
Oak GroveClackamas River45 
River MillClackamas River25 
T.W. SullivanWillamette River18 
Jointly-owned (2):
Coal:
Colstrip (3)
Colstrip, Montana296 
Hydro:
Round Butte (4)
Deschutes River230 
Pelton (4)
Deschutes River73 
Net capacity3,439 
(1)Represents net capacity of generating unit as demonstrated by actual operating or test experience, net of electricity used in the operation of a given facility. For wind-powered generating facilities, nameplate ratings are used in place of net capacity. A generator’s nameplate rating is its full-load capacity under normal operating conditions as defined by the manufacturer.
(2)Net capacity reflects PGE’s ownership share.
(3)PGE has a 20% ownership interest in the facility, which is operated by Talen Montana, LLC. The Company operated, and continues to have a 90% ownership interest in, Boardman, which ceased coal-fired operations during the fourth quarter of 2020.
(4)PGE operates Pelton and Round Butte and has a 66.67% ownership interest.

PGE’s hydroelectric projects are operated pursuant to FERC licenses issued under the FPA. The licenses for the hydroelectric projects on the three different rivers expire as follows: Clackamas River, 2055; Willamette River, 2035; and Deschutes River, 2055.

Transmission and Distribution

PGE owns or has contractual rights associated with transmission lines that deliver electricity from its generation facilities to its distribution system in its service territory and also to the Western Interconnection. As of December 31, 2020, PGE-owned electric transmission system consisted of 1,269 circuit miles as follows: 287 circuit miles of 500 kV line; 414 circuit miles of 230 kV line; and 568 miles of 115 kV line. The Company also has 27,939 circuit miles of distribution lines that deliver electricity to its customers. The Company also has an ownership interest in, and capacity on, the following:
15% of the Colstrip Transmission facilities from Colstrip to BPA’s transmission system; and
28

Table of Contents

20% of the Pacific Northwest Intertie, a 4,800 MW transmission facility between the John Day Substation near the Columbia River in northern Oregon, and Malin, Oregon, near the California border. The Pacific Northwest Intertie is used primarily for the transmission of interstate purchases and sales of electricity among utilities, including PGE.

In addition, the Company has contractual rights to the following transmission capacity:
4,045 MW of firm BPA transmission on BPA’s system to PGE’s service territory in Oregon; and
150 MW of firm BPA transmission from the Mid-Columbia projects in Washington to the northern end of the Pacific Northwest AC Intertie, near John Day, Oregon, 5 MW to Tucannon River, and 5 MW to Biglow Canyon.

ITEM 3.     LEGAL PROCEEDINGS.

See Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data,” for information regarding legal proceedings.

ITEM 4.     MINE SAFETY DISCLOSURES.

Not applicable.

PART II

ITEM 5.     MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

PGE’s common stock is traded on the NYSE under the ticker symbol “POR”. As of February 10, 2021, there were 653 holders of record of PGE’s common stock.

While the Company expects to pay regular quarterly dividends on its common stock, the declaration of any dividends is at the discretion of the Company’s Board of Directors. The amount of any dividend declaration will depend upon factors that the Board of Directors deems relevant and may include, but are not limited to, PGE’s results of operations and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.

For information with respect to securities authorized for issuance under equity compensation plans, see Note 14, Stock-Based Compensation in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Share repurchase program

On February 17, 2021, the Company’s Board of Directors authorized a share repurchase program, under which the Company is authorized to repurchase up to $17.5 million of its outstanding common stock through 2022. The share repurchase program may be limited or terminated at any time without prior notice. Under the share repurchase program, the Company may repurchase shares of common stock from time to time in open market transactions or in privately negotiated transactions as permitted under applicable rules and regulations. The extent to which the Company repurchases its shares of common stock and the timing of such purchases will depend upon market conditions and other considerations as may be determined in the Company’s sole discretion. Repurchases may also be made pursuant to a trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended, which would permit shares to be repurchased when the Company might otherwise be precluded from doing so because of self-imposed trading blackout periods or other regulatory restrictions. The Company intends to finance any repurchases under the share repurchase program using cash on hand.

ITEM 6.     [REMOVED AND RESERVED]
29

Table of Contents


ITEM 7.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions and objectives concerning future results of operations, business prospects, loads, outcome of litigation and regulatory proceedings, capital expenditures, market conditions, future events or performance, and other matters. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” “should,” or similar expressions are intended to identify such forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and data contained either in internal records or available from third parties, but there can be no assurance that PGE’s expectations, beliefs, or projections will be achieved or accomplished.

In addition to any assumptions and other factors and matters referred to specifically in connection with forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in such forward-looking statements include:
governmental policies, legislative action, and regulatory audits, investigations and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs and capital investments, and current or prospective wholesale and retail competition;

economic conditions that result in decreased demand for electricity, reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial stability of vendors and service providers and elevated levels of uncollectible customer accounts;
changing customer expectations and choices that may reduce customer demand for its services may impact PGE’s ability to make and recover its investments through rates and earn its authorized return on equity, including the impact of growing distributed and renewable generation resources, changing customer demand for enhanced electric services, and an increasing risk that customers procure electricity from registered ESSs or community choice aggregators;
the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 19, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.— “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K;
unseasonable or extreme weather and other natural phenomena, which could affect customers’ demand for power and PGE’s ability and cost to procure adequate power and fuel supplies to serve its customers, and could increase the Company’s costs to maintain its generating facilities and transmission and distribution systems;
operational factors affecting PGE’s power generating facilities, including forced outages, hydro and wind conditions, and disruption of fuel supply, any of which may cause the Company to incur repair costs or purchase replacement power at increased costs;
30

Table of Contents

complications arising from PGE’s jointly-owned generating facilities, including changes in ownership, adverse regulatory outcomes or legislative actions, or operational failures that result in legal or environmental liabilities or unanticipated costs related to replacement power or repair costs;
failure to complete capital projects on schedule and within budget or the abandonment of capital projects, either of which could result in the Company’s inability to recover project costs;
volatility in wholesale power and natural gas prices that could require PGE to post additional collateral or issue additional letters of credit pursuant to power and natural gas purchase agreements;
changes in the availability and price of wholesale power and fuels, including natural gas and coal, and the impact of such changes on the Company’s power costs;
capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, as well as changes in PGE’s credit ratings, any of which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction of capital projects, and the repayments of maturing debt;
future laws, regulations, and proceedings that could increase the Company’s costs of operating its thermal generating plants, or affect the operations of such plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generating facilities, in order to mitigate carbon dioxide, mercury and other gas emissions;
changes in, and compliance with, environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife;
the effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;
changes in residential, commercial, or industrial customer growth, or demographic patterns, in PGE’s service territory;
the effectiveness of PGE’s risk management policies and procedures;
cybersecurity attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation, transmission, or distribution facilities, information technology systems, or result in the release of confidential customer, employee, or Company information;
employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and the ability to recruit and retain appropriate talent;
new federal, state, and local laws that could have adverse effects on operating results;
political and economic conditions;
natural disasters and other risks, such as pandemic, earthquake, flood, drought, lightning, wind, and fire;
the impact of widespread health developments, including the global coronavirus (COVID–19) pandemic, and responses to such developments (such as voluntary and mandatory quarantines, including government stay at home orders, as well as shut downs and other restrictions on travel, commercial, social, and other activities), which could materially and adversely affect, among other things, demand for electric services, customers’ ability to pay, supply chains, personnel, contract counterparties, liquidity and financial markets;
changes in financial or regulatory accounting principles or policies imposed by governing bodies;
acts of war or terrorism; and
the impact of the recommendations on the Company and its operations based on the review conducted by the Special Committee relating to energy trading losses, the time and expense incurred in implementing the recommendations of the Special Committee, and any reputational damage to the Company relating to the matters underlying the Special Committee’s review.

31

Table of Contents

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors or assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company’s consolidated financial statements contained in this report, and other periodic and current reports filed with the SEC.

PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity in the state of Oregon, as well as the wholesale purchase and sale of electricity and natural gas in order to meet the needs of its retail customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory. In addition, the Company participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to obtain reasonably-priced power for its retail customers.

Energy Trading

PGE is exposed to commodity price risk as its primary business is to provide electricity to its retail customers. The Company expects to manage commodity price volatility within net variable power costs by engaging in energy trading activities. The Company does not intend to engage in trading activities for non-retail purposes.

PGE personnel entered into a number of energy trades during 2020, with increasing volume accumulating late in the second quarter and into the third quarter, resulting in significant exposure to the Company. In August 2020, a portion of energy trading positions in PGE’s energy portfolio experienced significant losses as wholesale electricity prices increased substantially at various market hubs due to extreme weather conditions, constraints to regional transmission facilities, and changes in power supply in the West. During this time period, the CAISO declared a Stage 3 Electrical Emergency and ordered the first rolling blackouts in the state of California since 2001.

As a result of the convergence of these conditions, the Company’s energy portfolio experienced realized losses of $127 million on these positions in 2020. PGE determined the energy trading positions that led to the losses were outside the Company’s acceptable risk tolerances, and the Company will not pursue regulatory recovery of the associated losses. PGE will also exclude the impacts of the realized losses from its regulatory earnings tests. The increase in net variable power costs due to this trading activity has been recognized in PGE’s results of operations. PGE no longer has net market exposure from the energy trading positions that led to these losses.

PGE and its external consultants have performed a full operational review of the Company’s energy supply risk management policies, procedures and personnel. In addition, the PGE Board of Directors formed a Special Committee comprising five independent Board members to review the energy trading that led to the losses and the Company’s procedures and controls related to the trading, and to make recommendations to the Board for appropriate action. The Special Committee retained independent legal advisors. On December 18, 2020, PGE announced that the Special Committee concluded its independent review of the energy trading activity that led to the losses incurred in the third quarter of 2020. The Special Committee concluded that the trades were ill-conceived and revealed opportunities for improving the Company’s energy trading policies and practices. Additionally, the Board of Directors concluded that the actions the Company began taking in August to enhance oversight of energy trading and associated risk management reporting, policies, and practices were consistent with the Special Committee’s recommendations and will be monitored by the Board of Directors through enhanced reporting. These actions are expected to strengthen the Company and include:
32

Table of Contents

Added expertise: PGE brought in additional experienced risk management personnel and replaced the Power Operations general manager with a new leader;
Strengthened trading policies: Power Operations personnel are operating under revised policies designed to prevent positions of the type that led to the losses. The improved policies place controls on the ability of personnel to enter into wholesale energy transactions to the extent that PGE does not have physical or financial delivery capability;
Enhanced risk reporting: Energy trading activity reporting has been improved to ensure greater visibility into portfolio risk;
Changed reporting structures: Energy Trading Risk Management now reports through a Risk and Compliance team that reports to the Chief Executive Officer. Effective January 1, 2021, Power Operations reports to the Vice President of Strategy, Regulation and Energy Supply; and
Changed personnel: The individuals who previously were placed on leave are no longer with the Company.

For further information regarding legal proceedings associated with this matter, see “Shareholder Lawsuits” in Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

COVID-19 Impacts

The COVID-19 pandemic has adversely impacted economic activity and conditions worldwide, including workforces, liquidity, capital markets, consumer behavior, supply chains, and macroeconomic conditions. In the state of Oregon, the Governor issued an executive order on March 23, 2020 directing Oregon residents to stay at home except for essential activity and mandating closure of businesses for which close personal contact was difficult or impossible to avoid. This order was rescinded May 14, 2020 in a new executive order announcing a phased approach for reopening Oregon’s economy. The subsequent phased reopening approach has not allowed all businesses to reopen, or has allowed reopening only at reduced capacity to meet requirements for social distancing. The continued loosening of restrictions is contingent upon the successful reduction of cases.

Retail loads—The slowdown in certain sectors of the economy due to COVID-19 and the initial stay-at-home order and subsequent phased reopening plans has resulted in changes in retail load patterns. See “Customers and Demand” and “Decoupling” in this Overview section and “Revenues” of the Results of Operations section for more information related to COVID-19 impacts on retail loads and Revenues, net.

Bad debt expense—The Company has responded to the hardships many customers are facing and has taken steps to support its customers and communities, including temporarily suspending disconnections and late fees during the crisis, developing time payment arrangements, and partnering with local non-profits to soften the impacts on small businesses and low-income residential customers. PGE’s bad debt expense was $15 million for the full-year 2020, compared to an original $6 million forecast, subject to deferral. See “Administrative and other” of the Results of Operations section for more information related to COVID-19 impacts on bad debt expense, and see “Legislative and regulatory developments” within this Overview section for more information regarding regulatory deferrals of incremental costs associated with the COVID-19 pandemic.

Financial condition and liquidity—Global capital markets have experienced significant volatility in response to COVID-19 and PGE continues to assess the impact of this volatility on its liquidity position and capital investment plans. The Company believes the combination of its revolver capacity, proceeds of a $150 million, 364-day term loan, issued in April 2020, and proceeds from $200 million and $230 million FMB issuances, in April and November 2020, respectively, will continue to provide adequate liquidity for the Company’s operational needs. The Company continues to evaluate its five-year capital plan. A detailed discussion of capital market and capital investment responses is included in the Liquidity and Capital Resources section of this Item 7.

The COVID-19 pandemic did not have a material impact on PGE’s financial condition and cash flows in 2020 and the Company continues to have sufficient liquidity to meet the Company’s anticipated capital and operating
33

Table of Contents

requirements going forward. It is reasonably possible, however, that disruption and volatility in the global capital markets may materially increase the cost of capital.

Supply chain—The global nature of the COVID-19 pandemic has resulted in supply chain disruptions and in some instances construction interruptions, although PGE has not experienced significant supply chain disruptions or construction interruptions to date. The Company’s business continuity plans have included an assessment of critical operational supply chain linkages and an assessment of potential interruptions to its capital project execution. The Company will continue to monitor supply chain issues, including possible force majeure notices, for any material impacts to its operations.

Business continuity plans—In February 2020, as more information about the potential impacts of COVID-19 became available, the Company activated its business continuity plans. These plans are designed to ensure the safety of the public and employees while the Company continues to provide critical service to its customers. In addition to directing employees to work from home when appropriate, the Company has implemented safeguards for employees who play critical roles to ensure operational reliability and established protocols for employees who interact directly with the public. The Company has enacted extra physical security and cybersecurity measures to safeguard systems to serve operational needs, including those of its remote workforce, and to ensure uninterrupted service to customers. The Company will continue to evolve its business continuity plans to follow guidance from the Centers for Disease Control and the Oregon Health Authority. Although PGE has plans in place to address workforce availability, including sequestration of key employees if necessary, the Company has not experienced workforce availability issues to date. Implementation of PGE’s business continuity plans have not had a material impact on PGE’s results of operation.

Legislative and regulatory developments—The Company has analyzed available relief for the economic effects of COVID-19 under the following:
FERC WaiverOn June 30, 2020 the FERC issued a waiver that provides that, for the 12-month period starting March 2020, jurisdictional utilities may apply an alternative allowance for funds used during construction (AFDC) calculation formula that excludes the actual outstanding short-term debt balance and replaces it with the simple average of the actual 2019 short-term debt balance. The purpose of the waiver is to allow relief from the detrimental impacts of issuing short-term debt on the allowance for equity funds used during construction. PGE adopted the waiver in the second quarter of 2020 and retrospectively applied its provisions as of March 2020, resulting in a $1 million increase to AFDC. The Company continues to monitor for potential extensions of the waiver beyond the original 12-month period.
Coronavirus Aid, Relief, and Economic Security (CARES) ActOn March 27, 2020, the U.S. Government enacted the CARES Act, which provides economic relief and stimulus to support the national economy during the COVID-19 pandemic and includes support for individuals, large corporations, small business, and health care entities, among other affected groups. The Company has not experienced direct material benefits from the CARES Act.
COVID-19 DeferralPGE filed an application for deferral of certain incremental costs and lost revenue related to COVID-19 on March 20, 2020 with the OPUC. The application requested the ability to defer incremental costs associated with the COVID-19 pandemic but did not specify the precise scope of the deferral, or the means by which PGE would recover deferred amounts. PGE, other utilities under the OPUC’s jurisdiction, intervenors, and OPUC staff held discussions regarding the scope of costs incurred by utilities that may qualify for deferral under Docket UM 2114, Investigation into the Effects of the COVID-19 Pandemic on Utility Customers. The result of such discussions was an Energy Term Sheet (Term Sheet), which dictates costs in scope for deferral, but is silent to the timing of recovery of such costs. On September 24, 2020, the Commission adopted OPUC Staff’s motion to execute stipulations incorporating the terms of the Term Sheet. PGE’s deferral application was approved by the Commission on October 20, 2020 with final stipulations for the Term Sheet approved on November 3, 2020. As of December 31, 2020, PGE has deferred $8 million related to bad debt expense, and $2 million for other incremental costs associated with COVID-19 under the Term Sheet. All other incremental expenses will be recognized in the results of operations, until a determination is made that cost recovery is probable.
34

Table of Contents

Amortization of any deferred costs will remain subject to OPUC review prior to amortization and inclusion in customer prices. Although PGE expects its 2020 regulated ROE, after adjusting for certain energy trading losses, to exceed its authorized ROE of 9.5%, PGE believes the full amount of the 2020 deferral is probable of recovery as the Company’s prudently incurred costs were in response to the unique nature of the COVID-19 pandemic health emergency. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE’s 2020 deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.

Company Strategy

PGE is committed to continuing to achieve steady growth and returns as the Company transforms to meet the challenges of climate change and an ever-evolving energy grid. Customers, policy makers, and other stakeholders expect PGE to reduce GHG emissions, keep the power grid reliable and secure, and ensure prices are affordable, especially for the most vulnerable customers. The Company’s strategy strives to balance these interests. PGE plans to:
Reduce GHG emissions associated with the power served to customers by 80% by 2030 (2010 baseline year), and setting an aspirational goal for zero GHG emissions associated with the power served to customers by 2040;
Electrify sectors of the economy like transportation and buildings that are also transforming to reduce GHG emissions; and
Perform as a business, driving improvements to work efficiency, safety of our coworkers, and reliability of our systems and equipment all while adhering to the Company’s earnings per diluted share growth guidance of 4-6% on average.

Decarbonize the power supply—PGE partners with customers and local and state governments to advance a clean energy future. PGE continues to leverage these partnerships to pursue emission reductions using a diverse portfolio of clean and renewable energy resources, and promote economy-wide emission reductions through electrification and smart energy use to help the state meet its GHG emission reduction goals. In addition to state greenhouse gas reduction goals, PGE announced in 2020 a new company wide goal of achieving net zero GHG emissions by 2040. PGE also announced a new goal to meet customer expectations for clean energy, pledging to reduce GHG emissions associated with the power served to customers by 80% by 2030 (2010 baseline year).

To reach these goals, PGE will focus on the following areas:

Customer Choice Programs—PGE’s customers continue to express a commitment to purchasing clean energy, as over 230,000 customers voluntarily participate in PGE’s Green Future Program, the largest renewable power program by participation in the nation. In 2017, Oregon’s most populous city, Portland, and most populous county, Multnomah, each passed resolutions to achieve 100 percent clean and renewable electricity by 2035 and 100 percent economy-wide clean and renewable energy by 2050. Other jurisdictions in PGE’s service area continue to consider similar goals.

In response, the Company has implemented a new customer product option, the Green Future Impact program, which allows for 100 MW of PGE-provided power purchase agreements for renewable resources and up to 200 MW of customer-provided renewable resources. Approved by the OPUC in the first quarter 2019, the program will provide business customers access to bundled renewable attributes from those resources. Through this voluntary program, the Company seeks to align sustainability goals, cost and risk management, reliable integrated power, and a cleaner energy system.

Pursuant to the OPUC order approving the Green Future Impact tariff, program subscribers remain cost of service customers, and pay both the cost of service tariff price and the price under the renewable energy option tariff. This structure is intended to avoid stranded costs and cost shifting.

35

Table of Contents

Carbon Legislation and Administrative Actions—In 2016, SB 1547 set a benchmark for how much electricity must come from renewable sources like wind and solar and requires the elimination of coal from Oregon utility customers’ energy supply no later than 2030 (subject to an exception that allows extension of this date until 2035 for PGE’s output from Colstrip).

Other provisions of the law include:
An increase in RPS thresholds to 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;
A limitation on the life of Renewable Energy Credits (RECs) generated from facilities that become operational after 2022 to five years, but continued unlimited lifespan for all existing RECs and allowance for the generation of additional unlimited RECs for a period of five years for projects online before December 31, 2022; and
An allowance for energy storage costs related to renewable energy in the Company’s RAC filings.

In response to SB 1547, the Company filed a tariff request in 2016 to accelerate recovery of PGE’s investment in the Colstrip facility from 2042 to 2030. In January 2020, the owners of Colstrip Units 1 and 2 permanently retired those two units. Although PGE has no direct ownership interest in Units 1 and 2, the Company does have a 20% ownership share in Colstrip Units 3 and 4, which utilize certain common facilities with Units 1 and 2.

Although PGE is currently scheduled to recover the costs of Colstrip by 2030, some co-owners of Units 3 and 4 have sought approval to recover their costs sooner in their respective jurisdictions. In its most recent depreciation study filed with the OPUC in January 2021, PGE proposed to accelerate depreciation on Colstrip generation assets through 2027. The Company continues to evaluate its ongoing investment in Colstrip, including the possibility of earlier closure of these facilities.

Any reduction in generation from Colstrip has the potential to provide capacity on the Colstrip transmission facilities, which stretches from eastern Montana to near the western end of the state to serve markets in the Pacific Northwest and beyond. PGE has a 15% ownership interest in, and capacity on, the Colstrip Transmission facilities. Renewable energy development in the state of Montana could benefit from any excess transmission capacity that may become available.

As previously planned, in October 2020, PGE ceased coal-fired operation at Boardman and has begun decommissioning activities.

During the 2019 Oregon legislative session, House Bill (HB) 2020 was introduced, which would have authorized a comprehensive cap and trade package in Oregon and would have granted the OPUC direct authority to address climate change. Although HB 2020 was not enacted in 2019, an amended version was reintroduced in the 35-day legislative session, which began in February 2020. This new proposal, SB 1530, was also a cap and trade package that included changes made to address concerns raised by various parties. Prior to the legislative session, the OPUC stated that it would continue to collaborate with the legislature and stakeholders to make progress on climate change, noting that their authority was limited to that of an economic regulator.

The short 2020 legislative session adjourned without action on SB 1530 and, as a result, in March 2020, the Governor of Oregon issued an executive order directing state agencies to seek to reduce and regulate GHG emissions. Many of the direct agency actions are on an aggressive timeline with due dates in 2020 and 2021. As the Governor is limited by current statutory authority, the executive order does not include a market-based mechanism as envisioned by the cap and trade legislation introduced in the 2019 and 2020 legislative sessions.

Among other things, the executive order:
Modified the statewide GHG emissions reduction goals to at least 45% below 1990 emission levels by 2035 and at least 80% below 1990 emission levels by 2050;
36

Table of Contents

Directed state agencies to integrate climate change and the State’s GHG emissions reduction goals into their planning, budgets, investments, and decisions to the extent allowed by law;
Directed the OPUC to—
determine whether utility portfolios and customer programs reduce risks and costs to utility customers by making rapid progress towards reducing GHG emissions consistent with Oregon’s reduction goals;
encourage electric companies to support transportation electrification infrastructure that supports GHG emission reductions and zero emission vehicle goals; and
prioritize proceedings and activities that advance decarbonization in the utility sector and exercise its broad statutory authority to reduce GHG emissions, mitigate energy burden on utility customers, and ensure reliability and resource adequacy;
Directed the Oregon Department of Environmental Quality to adopt a program to cap and reduce GHG emissions from large stationary sources, transportation fuels, and other liquid or gaseous fuels including natural gas; and
More than doubled the reduction goals of the state’s Clean Fuels Program and extended the program, from the previous rule that required a 10 percent reduction in average carbon intensity of fuels from 2015 levels by 2025, to a 25 percent reduction below 2015 levels by 2035.

The Resource Planning Process—PGE’s planning process includes working with customers, stakeholders, and regulators to chart the course toward a clean, affordable, and reliable energy future. This process includes consideration of customer expectations and legislative mandates to move away from fossil fuel generation and toward renewable sources of energy.

In May 2018, the Company issued a request for proposals seeking to procure approximately 100 MWa of qualifying renewable resources. The prevailing bid was Wheatridge, an energy facility in eastern Oregon that will combine 300 MW of wind generation and 50 MW of solar generation with 30 MW of battery storage.

PGE now owns 100 MW of the wind resource, which was placed into service in the fourth quarter of 2020 at a cost of $149 million and qualified for PTCs at the 100 percent level. Subsidiaries of NextEra Energy Resources, LLC own the balance of the 300 MW wind resource, along with the solar and battery components, and will sell their portion of the output to PGE under 30-year power purchase agreements. PGE has the option to increase its ownership to include the entire facility in 2032.

Construction of the solar and battery components is planned for 2021 and is also expected to qualify for federal investment tax credits. PGE did not experience any supply chain disruptions due to the COVID-19 pandemic related to the construction of Wheatridge, and the solar and battery portions of the project are proceeding as planned. PGE continues to work closely with the contractor to actively monitor for supply chain issues. See “COVID-19 Impacts” within this Overview section for further information on COVID-19.

On May 6, 2020, the OPUC issued an order that acknowledged the Company’s 2019 IRP and the following Action Plan for PGE to undertake over the next four years to acquire the resources identified:
Customer actions—
Seek to acquire all cost-effective energy efficiency; and
Seek to acquire all cost-effective and reasonable distributed flexibility.
Renewable actions—Conduct a Renewables Request for Proposals (RFP) seeking up to approximately 150 MWa of new RPS-eligible resources that contribute to meeting PGE’s capacity needs by the end of 2024, with the following conditions, among others:
Resources must qualify for PTC or the federal Investment Tax Credit;
37

Table of Contents

Resources must pass the cost-containment screen; and
The value of RECs generated prior to 2030 must be returned to customers.
Capacity actions—Pursue dispatchable capacity through the following concurrent processes:
Pursue cost-competitive, bilateral contract agreements for existing capacity in the region; and
Conduct an RFP for non-emitting dispatchable resources that contribute to meeting PGE’s capacity needs.

The order also requires that PGE consider resources in the Renewable and Capacity RFPs in a co-optimized manner. PGE had requested authorization to pursue up to approximately 700 MW of capacity contribution by 2025 from a combination of renewables, existing resources, and new non-emitting dispatchable capacity resources, such as energy storage. As PGE implements the Action Plan, the Company will continue to evaluate present and ongoing resource needs and timing of any related RFP in light of the economic disruption related to COVID-19. PGE expects to issue an RFP for both renewable energy and capacity resources.

PGE and Douglas County Public Utility District entered an agreement during 2020 to supply the Company additional capacity from facilities including the Wells Hydroelectric Project, located on the Columbia River in central Washington. The agreement also provides Douglas County PUD with PGE load management and wholesale market sales services. With a start date of January 1, 2021, the five-year agreement is expected to contribute between 100 and 160 MWs toward a capacity need that PGE identified in its 2019 IRP. The agreement is a further step toward the Company’s stated goal of providing customers with a clean energy future.

PGE filed an IRP Update with the OPUC in January 2021 seeking acknowledgement so that it may incorporate the updated resource cost and value information in PURPA QF avoided cost pricing. No changes were proposed to the 2019 IRP Action Plan in the IRP Update. However, based on the updated capacity need forecast reflecting the addition of the agreement with the Douglas County PUD and more sophisticated modeling, the updated capacity need in 2025 is 511 MW.

Renewable Recovery Framework—As previously authorized by the OPUC, the RAC allows PGE to recover prudently incurred costs of renewable resources through filings made by April 1st each year. In the 2019 GRC Order, the OPUC authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings to be made to the OPUC, under certain conditions. Although no significant filings were made under the RAC during 2020, the Company did submit a RAC filing for Wheatridge in the fourth quarter of 2019. On September 29, 2020, the OPUC issued an order in response to PGE’s RAC filing that stated PGE’s decision to proceed with Wheatridge was prudent and authorized cost recovery of, and return on, the facility in customer prices once service to PGE's customers began, in the fourth quarter 2020.

Electrify other sectors of the economy—PGE is working toward an equitable, safe, and clean energy future. Recent and future enhancements to the grid to enable a seamless platform include:
The use of electricity in more applications such as electric vehicles and heat pumps;
The integration of new, geographically-diverse energy markets;
The deployment of new technologies like energy storage, communications networks, automation and control systems for flexible loads, and distributed generation;
The development of connected neighborhood microgrids and smart communities; and
The use of data and analytics to better predict demand and support energy saving customer programs.

In July 2019, PGE’s Board approved plans to construct an Integrated Operations Center (IOC) as a key step to supporting this strategy, at an estimated total cost of $200 million, excluding AFDC. The IOC will centralize mission-critical operations, including those that are planned as part of the integrated grid strategy. This secure, resilient facility will include infrastructure to support and enhance grid operations and co-locate primary support
38

Table of Contents

functions. As of December 31, 2020, the Company has recorded $109 million, including AFDC, in construction work-in-progress related to the IOC.

The Company is also working to advance transportation electrification, with projects aimed at improving accessibility to electric vehicle charging stations and partnering with local mass transit agencies to transition to a greater use of electric vehicles. In June 2019, the Oregon Legislature enacted SB 1044, which establishes Oregon's zero emissions vehicle goals in statute at 250 thousand vehicle sales by 2025 and 90% of all vehicle sales by 2035. In September 2019, PGE filed with the OPUC its first Transportation Electrification plan, which considers current and planned activities, along with both existing and potential system impacts, in relation to the State’s carbon reduction goals.

In 2018, PGE filed an energy storage proposal that called for 39 MW of storage to be developed over the next several years at various locations across the grid. In August 2018, the OPUC issued an order that outlined an agreed approach to the development of five energy storage projects by PGE with an expected capital cost of approximately $45 million.

Perform as a business—PGE focuses on providing reliable, clean power to customers at affordable prices while providing a fair return to investors. To achieve this goal the Company must execute effectively within its regulatory framework and maintain prudent management of key financial, regulatory, and environmental matters that may affect customer prices and investor returns. The following discussion provides detail on several such material matters.

Wildfire—In 2020, Oregon experienced one of the most destructive wildfire seasons on record, with over one million acres of land burned. PGE’s wildfire mitigation planning includes regular risk assessment. On September 7, 2020 PGE proactively initiated a public safety power shutoff (PSPS) in a zone near Mt. Hood that was identified as the region at highest risk of wildfire. In addition to the PSPS region, PGE cut power to eight different high-risk fire areas. These actions were coordinated with emergency responders and helped clear the path for them to fight wildfires. During this time, PGE also established a community resource center within the PSPS zone to help support the residents affected. The Oregon Department of Forestry has opened an investigation into the causes of wildfires in Clackamas County. The Company has received a subpoena and is fully cooperating. The Company is not aware of any wildfires caused by PGE equipment. PGE will incur costs to replace and rebuild PGE facilities damaged by the fires, as well as addressing fire-damaged vegetation and other resulting debris and hazards both in and outside of PGE’s property and right-of-way. On October 20, 2020, the OPUC formally approved PGE’s request for deferral of such costs. As of December 31, 2020, PGE deferred $15 million in costs related to wildfire response. PGE continues to assess the damage to its infrastructure and expects regulatory recovery of prudently incurred restoration costs. Although PGE expects its 2020 regulated ROE, after adjusting for certain energy trading losses, to exceed its authorized ROE of 9.5%, PGE believes the full amount of the 2020 deferral is probable of recovery as the Company’s prudently incurred costs were in response to the unique and unprecedented nature of the wildfire events leading to the deferral. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE’s 2020 deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.

Power Costs—Pursuant to the AUT process, PGE annually files an estimate of power costs for the following year. As approved by the OPUC, the 2020 AUT included a final increase in power costs for 2020, and a corresponding increase in annual revenue requirement, of $27 million from 2019 levels, which were reflected in customer prices effective January 1, 2020. See “Power Operations” within this Overview section of Item 7 for more information regarding the PCAM.

Portland Harbor Environmental Remediation Account (PHERA) Mechanism—The EPA has listed PGE as one of over one hundred PRPs related to the remediation of the Portland Harbor Superfund site. As of December 31, 2020, significant uncertainties still remained concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. In a Record of Decision issued in 2017, the EPA outlined its selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion. However, the Company does not currently have sufficient information to
39

Table of Contents

reasonably estimate the amount, or range, of its potential costs for investigation or remediation of Portland Harbor, although such costs could be material to PGE’s financial position. The impact of such costs to the Company’s results of operations is mitigated by the PHERA mechanism. As approved by the OPUC, the Company’s environmental recovery mechanism allows the Company to defer and recover incurred environmental expenditures related to the Portland Harbor Superfund Site through a combination of third-party proceeds, such as insurance recoveries, and customer prices, as necessary. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds, and annual expenditures in excess of $6 million, excluding contingent liabilities, are subject to an annual earnings test. Under the PHERA mechanism in 2020, PGE incurred and deferred $6 million related to defense costs, net an estimated refund of less than $1 million as a result of the regulated earnings test. PGE’s results of operations may be impacted to the extent such expenditures are deemed imprudent by the OPUC or disallowed per the prescribed earnings test. For further information regarding the PHERA mechanism, see “EPA Investigation of Portland Harbor” in Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

City of Portland Audit—In 2019, the city of Portland (the “City”), which is the largest city within PGE’s service territory, completed its audit of PGE’s and the City’s mutual License Fees agreement for the 2012 through 2015 periods. The preliminary claim by the City is that PGE improperly excluded certain items from the calculation of gross revenues, which resulted in underpayment of franchise taxes of $7 million, including interest and penalties. PGE disagreed with the preliminary findings as they were not consistent with previous audit conclusions, which found that the Company had appropriately calculated gross revenues in determining franchise fees. In December 2020, PGE and the City reached a settlement for less than $1 million that covered the audit periods from 2012 to 2018.

Capital Project Deferral—In the second quarter of 2018, PGE placed into service a new customer information system at a total cost of $152 million. In accordance with agreements reached with stakeholders in the Company’s 2019 GRC, the Company’s capital cost of the asset was included in rate base and customer prices as of January 1, 2019.

Consistent with past regulatory precedent, in May 2018, the Company submitted an application to the OPUC to defer the revenue requirement associated with this new customer information system from the time the system went into service through the end of 2018. As a result, PGE began deferring its incurred expenses, primarily related to depreciation and amortization, of the new customer information system once it was placed in service.

In 2017, the OPUC had opened docket UM 1909 to conduct an investigation of the scope of its authority under Oregon law to allow the deferral of costs related to capital investments for later inclusion in customer prices. In October 2018, the OPUC issued Order 18-423 (1909 Order) concluding that the OPUC lacked authority under Oregon law to allow deferrals of any costs related to capital investments. In the 1909 Order, the OPUC acknowledged that this decision was contrary to its past limited practice of allowing deferrals related to capital investments and would require adjustments to its regulatory practices. The OPUC directed its Staff to meet with the utilities and stakeholders to address the full implications of this decision, and to propose recommendations needed to implement this decision consistent with the OPUC’s legal authority and the public interest.

During 2018, PGE deferred a total of $12 million of expenses related to the customer information system. However, the 1909 Order impacted the probability of recovery of deferred expenses and, as such, the Company recorded a reserve for the full amount of the costs related to the customer information system. The reserve was established with an offsetting charge to the results of operations in 2018.

In response to the 1909 Order, PGE and other utilities filed a motion for reconsideration and clarification, which was denied. On April 19, 2019, PGE and the other utilities filed a petition for judicial review of the 1909 Order with the Oregon Court of Appeals, although the Court has indicated that the case would be dismissed given the lack of recent action in the case.

On April 30, 2020, the OPUC issued a final order affirming its authority to defer all cost components related to a utility’s capital projects, including both depreciation expense and the cost of financing capital projects. PGE
40

Table of Contents

believes that the costs incurred to date associated with the customer information system were prudently incurred; however, PGE intends to file to close the deferral proceeding related to the customer information system without further action at the OPUC.

Decoupling—The decoupling mechanism, authorized by the OPUC through 2022, is intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency, customer-owned generation, and conservation efforts by residential and certain commercial customers. The mechanism provides for collection from (or refund to) customers if weather-adjusted use per customer is less (or more) than that projected in the Company’s most recent general rate case.

The Company recorded an estimated refund of $15 million and a collection of $9 million from residential and commercial customers, respectively for the year ended December 31, 2020, which resulted from variances between actual weather-adjusted use per customer and that projected in the 2019 GRC. The Company continues to see higher weather-adjusted use per customer from residential customers that are spending more time at home and lower use per customer from commercial customers that are adversely affected by COVID-19.

Collections under the decoupling mechanism are subject to an annual limitation of 2% of revenues for each eligible customer class, based on the net prices in effect for the applicable tariff schedule at the time of collection. For collections recorded in 2020, the 2% limit will be applied to the net prices for the applicable tariff schedules that will be in effect on January 1, 2022. The Company reached its 2020 annual cap for collection from commercial customers during the third quarter of 2020. No cap exists for any potential refunds under the decoupling mechanism, thus increased demand from residential customers since the onset of the COVID-19 pandemic has resulted in larger estimated refunds under the decoupling mechanism, which have largely offset the revenue increases that have resulted from higher residential demand. Any collection from customers for the 2020 year is expected to occur over a one-year period, which would begin January 1, 2022.

At December 31, 2019, PGE had recorded a total collection of $14 million that will be collected over a one-year period, which began January 1, 2021.

Corporate Activity Tax—In 2019, the state of Oregon enacted HB 3427, which imposes a new gross receipts tax on companies with annual revenues in excess of $1 million and applies to tax years beginning on or after January 1, 2020. The tax applies to commercial activities sourced in Oregon, less a deduction for 35% of the greater of “cost inputs” or “labor costs.” The resulting amount is taxed at 0.57%.

In January 2020, at PGE’s request, the OPUC issued an order approving a tariff and related deferral and balancing account to provide for an estimated recovery of $7 million in customer prices in 2020. The Company will revisit the expected tax consequences annually and revise the annual tariff accordingly. Pursuant to the order, PGE started collections in customer prices February 1, 2020. For the year ended December 31, 2020, PGE incurred $8 million under the tax.

Non-utility Asset Retirement Obligation (ARO)—PGE’s Non-utility ARO represents the liability that has been recognized for portions of unregulated properties that are currently or previously leased to third parties and located adjacent to PGE’s T.W. Sullivan hydro generating facility. In 2020, PGE performed a decommissioning study to update its ARO liability which resulted in a $21 million increase to non-utility property AROs. Additions in non-utility AROs related to assets that are no longer in service are charged directly to Depreciation and amortization on the consolidated statements of income in the period in which the revisions are probable and reasonably estimable. As a part of this study, the Company also established an additional ARO liability of $3 million related to utility properties that was charged to Depreciation and amortization expense. PGE plans to pursue regulatory recovery for the utility portion of the ARO update, however, as of December 31, 2020, no amounts have been deferred as a regulatory asset. For further information regarding the Company’s AROs, see Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Deferral of Boardman Revenue Requirement—In October 2020, intervenors filed a deferral application with the OPUC that would require PGE to defer and refund the revenue requirement associated with Boardman currently
41

Table of Contents

included in customer prices as established in the Company’s last general rate case. The application states a deferral is required for customers to adequately capture the reduction in revenue requirement beginning on October 15, 2020, the date Boardman ceased operations. PGE estimates this amount could be up to $14 million for the period ended December 31, 2020. As of December 31, 2020, PGE has not recorded a regulatory liability pursuant to this deferral application as the Company believes its current prices are just and reasonable in light of PGE’s continued substantial investments in utility plant. The costs of these investments, which are not currently reflected in customer prices, more than offsets the revenue requirement for Boardman. If the OPUC authorizes the deferral, PGE would record a regulatory liability with a corresponding charge to earnings.

2021 Storm— Beginning on February 11, 2021, an historic set of storms involving heavy snow, winds, and ice impacted the United States, including PGE’s service territory. Significant damage across the State of Oregon led Oregon’s Governor to call a state of emergency on February 13, 2021. PGE’s restoration efforts in response to this historic set of storms are ongoing and the total costs of the storm cannot be reasonably estimated, although such costs could be material to its results of operations in 2021. Given the magnitude of the impacts to PGE’s transmission and distribution system, on February 15, 2021 PGE filed a deferral application with the OPUC for potential recovery of restoration costs, however, there is no assurance that such recovery would be granted by the OPUC.
42

Table of Contents

Operating Activities

In combination with electricity provided by its own generation portfolio, to meet its retail load requirements and balance its energy supply with customer demand, PGE purchases and sells electricity in the wholesale market. PGE also participates in the CAISO western EIM, which allows the Company to, among other things, integrate more renewable energy into the grid by better matching the variable output of renewable resources. PGE also purchases natural gas in the United States and Canada to fuel its generation portfolio and sells excess gas back into the wholesale market.

The Company generates revenues and cash flows primarily from the sale and distribution of electricity to its retail customers. The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues, cash flows, and income from operations to fluctuate from period to period. Historically, PGE has experienced its highest MWa deliveries and retail energy sales during the winter heating season, although instances of peak deliveries have increased during the summer months, generally resulting from air conditioning demand. See “Seasonality” in the Customers and Revenues section in Item 1.—“Business.” for further information regarding seasonal fluctuations. Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues. Wholesale power availability and price, hydro and wind generation, and fuel costs for thermal and gas plants can also affect income from operations.

Customers and Demand—The following tables present total energy deliveries and the average number of retail customers by customer type for 2020 and 2019.
Energy deliveries (MWh in thousands)20202019% Increase/
(Decrease)
Retail:
     Residential7,756 7,471 3.8 %
     Commercial (PGE sales only)6,222 6,653 (6.5)
          Direct Access633 665 (4.8)
     Total Commercial6,855 7,318 (6.3)
     Industrial (PGE sales only)3,446 3,181 8.3 
          Direct Access1,486 1,490 (0.3)
     Total Industrial4,932 4,671 5.6 
     Total (PGE sales only)17,424 17,305 0.7 
          Total Direct Access2,119 2,155 (1.7)
     Total retail energy deliveries19,543 19,460 0.4 %
Wholesale energy deliveries5,794 4,669 24.1 
     Total energy deliveries25,337 24,129 5.0 %

Average number of retail customers20202019% Increase
Residential791,119 88 %779,673 88 %1.5 %
Commercial110,290 12 109,521 12 0.7 
Industrial194 — 193 — 0.5 
Direct access634 — 632 — 0.3 
Total902,237 100 %890,019 100 %1.4 %

In 2020, retail energy deliveries increased 0.4% from 2019. While results for the first quarter largely reflected conditions prior to the COVID-19 pandemic, the remainder of the year was influenced by customer behavioral response to the pandemic.
43

Table of Contents


On March 23, 2020, the Governor of Oregon issued an order directing residents to stay at home except for essential activity and mandating closure of businesses for which close personal contact would be difficult or impossible to avoid. The Company saw a shift in retail demand in response, beginning with the second quarter of 2020. In particular, residential loads increased as a larger percentage of the population spent more time at home, whether working from home, providing child-care due to school closures, or lacking employment as commercial activity slowed. Conversely, commercial energy deliveries declined as many businesses were disrupted in an attempt to maintain social distancing or have closed as a result of the lack of business as residents followed directives from state and federal authorities. Although the industrial class as a whole experienced an increase in energy deliveries for 2020, this was due primarily to continued growth in the high-tech and digital services sectors, which saw lesser impacts from noted closures than other sectors.

Residential energy deliveries, which are most sensitive to fluctuations in temperatures, were 3.8% higher in 2020 than 2019, due to a 2.3% increase in average usage per customer and a 1.5% increase in the average number of customers. Residential deliveries, down 6% in the first quarter driven by mild temperatures, were up 9% in the second quarter of 2020 due largely to the impact of the COVID-19 pandemic and have remained strong through the balance of the year.

Commercial energy deliveries declined 6.3% overall with widespread decreases across PGE’s customer base led by several sectors most impacted by COVID-19 related closures and economic conditions, including: government and education; offices, finance, insurance, and real estate; and restaurants and lodging.

The 5.6% increase during 2020 in industrial energy deliveries is due to continued strength in the high-tech manufacturing sector as well as a full-year of demand from a large paper facility that reopened during 2019, after having closed in late 2017.

In 2020, the Company’s service territory experienced warmer temperatures during the heating season than in 2019, indicating lower demand for heating, the effect of which was partially offset by having slightly warmer temperatures during the summer cooling season and increased demand for cooling.

Total heating degree-days, an indication of electricity use for heating, in 2020 were 7% below the 15-year average and down 8% from total heating degree-days in 2019. Total cooling degree-days, a similar indication of the extent to which customers are likely to have used electricity for cooling, in 2020, exceeded the 15-year average by 12% and were 6% above the 2019 total. The following table presents the number of heating and cooling degree-days in 2020 and 2019, along with the current 15-year averages, reflecting that weather had a considerable influence on comparative energy deliveries:

 Heating Degree-DaysCooling Degree-Days   
 2020201915-Year Average2020201915-Year Average
1st quarter1,761 1,992 1,848 — — — 
2nd quarter554 467 636 99 102 89 
3rd quarter47 83 78 492 462 447 
4th quarter1,474 1,623 1,583 — 
Total3,836 4,165 4,145 600 564 538 
Increase (decrease) from the 15-year average(7)%— %12 %%

On a weather-adjusted basis, total retail deliveries increased 1.5% from 2019. The increase was driven by 6.3% growth in residential deliveries and 5.6% growth in industrial energy deliveries, which were somewhat offset by a decrease in commercial energy deliveries of 6.0%. Retail energy deliveries for 2021 will continue to be impacted by COVID-19 related behavioral changes. PGE projects that retail energy deliveries for 2021 will be approximately
44

Table of Contents

1.0% - 1.5% above 2020 weather-adjusted levels, reflecting strength in industrial deliveries, and impacts associated with COVID-19 early in the year, and unwinding of such impacts later in the year.

ESSs supplied Direct Access customers with energy representing 11% of the Company’s total retail energy deliveries during 2020 and 2019. The maximum retail load allowed to be supplied under the fixed three-year and minimum five-year opt-out programs represent 13% of the Company’s total retail energy deliveries for 2020, and 2019. With the adoption of the New Large Load Direct Access program in 2020, as much as 19% of the Company’s energy deliveries could have been supplied by ESSs.

Energy efficiency and conservation efforts by retail customers influence demand, although the financial effects of such efforts by residential and certain commercial customers are mitigated by the decoupling mechanism, which is intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency and conservation efforts. The mechanism provides for collection from (or refund to) customers if weather-adjusted use per customer is less (or more) than the projected baseline set in the Company’s most recent approved general rate case. See “Decoupling” in this Overview section of Item 7, for further information on the decoupling mechanism.

Power Operations—PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of its retail customers. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, the Company continuously makes economic dispatch decisions in an effort to obtain reasonably-priced power for its retail customers. PGE also purchases wholesale natural gas in the United States and Canada to fuel its generating portfolio and sells excess gas back into the wholesale market. As a result, the amount of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period and impacts NVPC and income from operations.

The following table provides information regarding the performance of the Company’s generation portfolio.
 
Plant availability (1)
Actual energy provided compared to projected levels (2)
Actual energy provided as a percentage of total retail load
 202020192020201920202019
Thermal:
Natural gas92 %92 %74 %86 %43 %45 %
Coal (3)
99 87 83 104 17 24 
Wind 94 96 117 90 11 
Hydro 86 93 71 81 
(1)Plant availability represents the percentage of the year plants were available for operations, which is impacted by planned maintenance and forced, or unplanned, outages.
(2)Projected levels of energy are included as part of PGE’s AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources.
(3)Plant availability excludes Colstrip, which PGE does not operate. Colstrip availability was 74% in 2020, compared with 85% in 2019. Boardman ceased coal-fired generation on October 15, 2020.

Energy received from PGE-owned and jointly-owned thermal plants decreased 12% in 2020 compared to 2019, primarily as a result of a 27% reduction in generation from coal-fired generation, which produced only 13% of the Company’s total system load in 2020. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs to run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year.

45

Table of Contents

Total energy received from hydroelectric generation sources, both PGE-owned generation and purchased, increased 12% in 2020 compared to 2019. While energy received from mid-Columbia hydroelectric projects increased 46% in 2020, the energy generated by the Company-owned facilities decreased 14%. Energy expected to be received from hydroelectric resources is projected annually in the AUT based on a modified hydro study, which utilizes 80 years of historical stream flow data. See “Purchased power and fuel” in the Results of Operations section in this Item 7, for further detail on regional hydro results.

Energy received from PGE-owned wind resources and under contracts increased 28% in 2020 compared to 2019, due to more favorable wind conditions in 2020 and the addition of Wheatridge during the fourth quarter 2020. Energy expected to be received from Biglow Canyon and Tucannon River is projected annually in the AUT based on historical generation. Wind generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available. As a result of the generation increase, a larger amount of PTCs were produced in 2020 than in 2019 and exceeded what was contemplated in the Company’s prices.

For Wheatridge, wind generation studies were used to develop NVPC cost forecasts, which were included in the RAC filing for the facility, and included in customer prices when the facility went into service. The RAC tariff included NVPC in 2020 along with all other aspects of the revenue requirement. Beginning January 1, 2021, the NVPCs were included in the Company’s AUT, although the other aspects of the RAC tariff will remain in effect until they are included in customer prices as a result of a future general rate case.

Under the PCAM, PGE may share with customers a portion of cost variances associated with NVPC. Customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year, if such differences exceed a prescribed “deadband” limit, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. The following is a summary of the results of the Company’s PCAM as calculated for regulatory purposes for 2020, and 2019:

For 2020, actual NVPC, excluding certain trading losses totaling $127 million, was below baseline NVPC by $13 million, which was within the established deadband range, so no estimated refund to customers was recorded as of December 31, 2020. A final determination regarding the 2020 PCAM results will be made by the OPUC through a public filing and review in 2021. If actual NVPC for 2020 included the certain trading losses, it would have been $114 million above the baseline. See “Energy Trading” in the Overview section of this Item 7. for further information regarding certain trading losses.

For 2019, actual NVPC was above baseline NVPC by $5 million, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded as of December 31, 2019. A final determination regarding the 2019 PCAM results was made by the OPUC through a public filing and review in 2020, which confirmed no refund to customers pursuant to the PCAM for 2019.

The AUT filing, which serves to reset the baseline NVPC for PCAM purposes, indicated that a $27 million increase was expected in 2020 over 2019. The 2021 AUT anticipates a $79 million increase in NVPCs that will be recovered in customer prices beginning January 1, 2021.

Results of Operations

The following tables provide financial and operational information to be considered in conjunction with management’s discussion and analysis of results of operations.

PGE defines Gross margin as Total revenues less Purchased power and fuel. Gross margin is considered a non-GAAP measure as it excludes depreciation and amortization and other operation and maintenance expenses. The presentation of Gross margin is intended to supplement an understanding of PGE’s operating performance in
46

Table of Contents

relation to changes in customer prices, fuel costs, impacts of weather, customer counts and usage patterns, and impact from regulatory mechanisms such as decoupling. The Company’s definition of Gross margin may be different from similar terms used by other companies and may not be comparable to their measures.

The results of operations are as follows for the years presented (dollars in millions):
 Years Ended December 31,% Increase (Decrease)
 20202019
 AmountAmount
Total revenues (1)
$2,145 $2,123 %
Purchased power and fuel (1)
708 614 15 
Gross margin1,437 1,509 (5)
Other operating expenses:
Generation, transmission and distribution293 323 (9)
Administrative and other283 290 (2)
Depreciation and amortization454 409 11 
Taxes other than income taxes138 134 
Total other operating expenses1,168 1,156 
Income from operations269 353 (24)
Interest expense, net (2)
136 128 
Other income:
Allowance for equity funds used during construction16 10 60 
Miscellaneous income, net— 
Other income, net22 16 38 
Income before income taxes155 241 (36)
Income tax (benefit) expense— 27 (100)
Net income$155 $214 (28)%
(1) Gross margin agrees to Total revenues less Purchased power and fuel as reported on PGE’s Consolidated Statements of Income.
(2) Includes an allowance for borrowed funds used during construction of $8 million in 2020 and $5 million in 2019.



47

Table of Contents

2020 Compared to 2019

Net income - The following items contributed to the change in Net income for the year ended December 31, 2020 compared to the year ended December 31, 2019 (dollars in millions):

Year ended December 31, 2019$214 
Purchased power and fuel expense related to certain trading losses*(127)
Purchased power and fuel expense, excluding certain trading losses*43 
Other operating revenues primarily from the resale of excess natural gas used for fuel in 2019 that did not recur in 2020(17)
Average retail price predominately due to increase under the AUT for NVPC37 
Retail deliveries, net of decoupling deferral (11)
Wholesale revenues driven by lower average sale prices(8)
Late fee revenue due largely to COVID-19 related curtailments(6)
Generation, transmission and distribution expenses driven by lower plant maintenance30 
Administrative and general expenses due largely to lower wages and benefits
Non-utility ARO due to revised estimates(21)
Depreciation and amortization resulting largely from capital additions(11)
Income taxes resulting primarily from lower pre-tax income27 
Other(4)
Year ended December 31, 2020155 
Change in Net income$(59)
*See “Energy Trading” in the Overview section of this Item 7.—”Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information regarding certain trading losses.

Total revenues consist of the following for the years presented (in millions):
20202019% Increase (Decrease)
Retail: (1)
Residential$1,030 $981 %
Commercial616 636 (3)
Industrial218 196 11 
Direct Access46 44 
Subtotal1,910 1,857 
Alternative revenue programs, net of amortization(6)(400)
Other accrued revenues, net (2)
28 22 27 
Total retail revenues1,932 1,881 
Wholesale revenues162 170 (5)
Other operating revenues51 72 (29)
Total revenues$2,145 $2,123 %